Energy Management Handbook [6th ed] 9780881735420, 0-88173-542-6, 0849382343, 9780849382345, 0881735434, 9780881735437

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ENERGY MANAGEMENT HANDBOOK SIXTH EDITION

EDITORIAL BOARD EDITOR Wayne C. Turner School of Industrial Engineering and Management Oklahoma State University Stillwater, Oklahoma

ASSOCIATE EDITOR Steve Doty Colorado Springs Utilities Colorado Springs, Colorado

CONTRIBUTORS Eric Angevine School of Architecture Oklahoma State University Stillwater, OK

Jeff Haberl Energy Systems Laboratory Texas A&M University College Station, Texas

Bradley Bracher Oklahoma City, OK

Michael R. Harrison, Manager Engineering & Technical Services Johns-Mansfield Corporation Denver, CO

Barney Burroughs Indoor Air Quality Consultant Alpharetta, GA Barney L. Capehart Industrial Engineering University of Florida Gainesville, FL Clint Christenson Industrial Engineering Oklahoma State University Stillwater, OK David E. Claridge Mechanical Engineering Department Texas A&M University College Station, Texas William E. Cratty Ventana Corporation Bethal, CT Charles Culp Energy Systems Laboratory Texas A&M University College Station, Texas Steve Doty Colorado Springs Utilities Colorado Springs, CO Keith Elder Coffman Engineers, Inc. Seattle, WA John L. Fetters, CEM, CLEP Effective Lighting Solutions, Inc. Columbus, Ohio Carol Freedenthal, CEO Jofree Corporation, Houston, TX GSA Energy Consultants Arlington, VA Richard Wakefield Lynda White Jairo Gutiemez Dale A. Gustavson Consultant Orange, CA

Russell L. Heiserman School of Technology Oklahoma State University Stillwater, OK William J. Kennedy, Jr. Industrial Engineering Clemson University Clemson, SC

S.A. Parker Pacific Northwest National Laboratory Richland, WA David Pratt Industrial Enginneering and Management Oklahoma State University Stillwater, OK Wesley M. Rohrer Mechanical Engineering University of Pittsburgh Pittsburgh, PA Philip S. Schmidt Department of Mechanical Engineering University of Texas Austin, TX

John M. Kovacik, Retired GE Industrial & Power System Sales Schenectady, NY

R. B. Scollon Manager, Energy Conservation Allied Chemical Corporation Morristown, NJ

Mingsheng Liu Architectural Engineering University of Nebraska Lincoln, NB

R. D. Smith Manager, Energy Generation & Feed Stocks Allied Chemical Corporation Morristown, NJ

Konstantin Lobodovsky Motor Manager Penn Valley, CA

Mark B. Spiller Gainesville Regional Utilities Gainesville, FL

Tom Lunneberg CTG Energetics, Inc. Irvine, CA

Nick Stecky NJS Associates, LLC

William Mashburn Virginia Polytechnic Institute and State University Blacksburg, VA Javier Mont Johnson Controls Chesterfield, MO George Owens Energy and Engineering Solutions Columbia, MD Les Pace Lektron Lighting Tulsa, OK Jerald D. Parker, Retired Mechanical & Aerospace Engineering Oklahoma State University Stillwater, OK

Albert Thumann Association of Energy Engineers Atlanta, GA W.D. Turner Mechanical Engineering Department Texas A&M University College Station, Texas Alfred R. Williams Ventana Corporation Bethel, CT Larry C. Witte Department of Mechanical Engineering University of Houston Houston, TX Jorge Wong Kcomt General Electric, Evansville, IN Eric Woodroof Johnson Controls, Santa Barbara, CA

ENERGY MANAGEMENT HANDBOOK SIXTH EDITION BY

WAYNE C. TURNER SCHOOL OF INDUSTRIAL ENGINEERING AND MANAGEMENT OKLAHOMA STATE UNIVERSITY AND

STEVE DOTY COLORADO SPRINGS UTILITIES COLORADO SPRINGS, COLORADO

Library of Congress Cataloging-in-Publication Data Turner, Wayne C., 1942Energy management handbook / by Wayne C. Turner & Steve Doty. -- 6th ed. p. cm. Includes bibliographical references and index. ISBN: 0-88173-542-6 (print) — 0-88173-543-4 (electronic) 1. Power resources--Handbooks, manuals, etc. 2. Energy conservation-Handbooks, manuals, etc. I. Doty, Steve. II. Title. TJ163.2.T87 2006 658.2'6--dc22 2006041263 Energy management handbook / by Wayne C. Turner & Steve Doty ©2007 by The Fairmont Press, Inc. All rights reserved. No part of this publication may be reproduced or transmitted in any form or by any means, electronic or mechanical, including photocopy, recording, or any information storage and retrieval system, without permission in writing from the publisher. Published by The Fairmont Press, Inc. 700 Indian Trail Lilburn, GA 30047 tel: 770-925-9388; fax: 770-381-9865 http://www.fairmontpress.com Distributed by Taylor & Francis Ltd. 6000 Broken Sound Parkway NW, Suite 300 Boca Raton, FL 33487, USA E-mail: [email protected] Distributed by Taylor & Francis Ltd. 23-25 Blades Court Deodar Road London SW15 2NU, UK E-mail: [email protected] Printed in the United States of America 10 9 8 7 6 5 4 3 2 1 0-88173-542-6 (The Fairmont Press, Inc.) 0-8493-8234-3 (Taylor & Francis Ltd.)

While every effort is made to provide dependable information, the publisher, authors, and editors cannot be held responsible for any errors or omissions.

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CONTENTS Chapter

Page

1

Introduction ................................................................................................................................. 1 Background .......................................................................................................................... 1 The Value of Energy Management ................................................................................... 2 The Energy Management Profession ............................................................................... 3 Some Suggested Principles of Energy Management ..................................................... 5

2

Effective Energy Management .................................................................................................. 9 Introduction ......................................................................................................................... 9 Energy Management Program .......................................................................................... 9 Organizational Structure.................................................................................................. 10 Energy Policy ..................................................................................................................... 13 Planning ............................................................................................................................. 13 Audit Planning .................................................................................................................. 14 Educational Planning ....................................................................................................... 15 Strategic Planning ............................................................................................................. 16 Reporting............................................................................................................................ 16 Ownership ......................................................................................................................... 17 Summary ............................................................................................................................ 17

3

Energy Auditing ........................................................................................................................ 23 Introduction ....................................................................................................................... 23 Energy Auditing Services ................................................................................................ 23 Basic Components of an Energy Audit .......................................................................... 23 Specialized Audit Tools .................................................................................................... 33 Industrial Audits ............................................................................................................... 34 Commercial Audits ........................................................................................................... 36 Residential Audits............................................................................................................. 37 Indoor Air Quality ............................................................................................................ 37

4

Economic Analysis .................................................................................................................... 41 Objective ............................................................................................................................. 41 Introduction ....................................................................................................................... 41 General Characteristics of Capital Investments ........................................................... 42 Sources of Funds ............................................................................................................... 43 Tax Considerations ........................................................................................................... 44 Time Value of Money Concepts ...................................................................................... 46 Project Measures of Worth ............................................................................................... 54 Economic Analysis ............................................................................................................ 58 Special Problems ............................................................................................................... 64 Summary and Additional Example Applications ........................................................ 69 v

5

Boilers and Fired Systems ....................................................................................................... 87 Introduction ....................................................................................................................... 87 Analysis of Boilers and Fired Systems ........................................................................... 87 Key Elements for Maximum Efficiency ......................................................................... 89 Fuel Considerations ........................................................................................................ 116 Direct Contact Technology for Hot Water Production .............................................. 122

6

Steam and Condensate Systems ........................................................................................... 125 Introduction ..................................................................................................................... 125 Thermal Properties of Steam ......................................................................................... 126 Estimating Steam Usage and its Value ........................................................................ 133 Steam Traps and Their Application.............................................................................. 139 Condensate Recovery ..................................................................................................... 147

7

Cogeneration ............................................................................................................................ 155 Introduction ..................................................................................................................... 155 Cogeneration System Design and Analysis ................................................................ 157 Computer Programs ....................................................................................................... 174 U.S. Cogeneration Legislation: PURPA ....................................................................... 176 Evaluating Cogeneration Opportunities: Case Examples ........................................ 178

8

Waste-Heat Recovery .............................................................................................................. 193 Introduction ..................................................................................................................... 193 Waste-Heat Survey ......................................................................................................... 201 Waste-Heat Exchangers.................................................................................................. 207 Commercial Options in Waste-Heat-Recovery Equipment ...................................... 211 Economics of Waste-Heat Recovery ............................................................................. 218

9

Building Envelope................................................................................................................... 221 Introduction ..................................................................................................................... 221 Principles of Envelope Analysis ................................................................................... 223 Metal Elements in Envelope Components .................................................................. 225 Roofs ................................................................................................................................. 230 Floors ................................................................................................................................ 233 Fenestration ..................................................................................................................... 234 Infiltration ........................................................................................................................ 237 Summarizing Envelope Performance with the Building Load Coefficient ......... ...239 Thermal “Weight” ........................................................................................................... 240 Envelope Analysis for Existing Buildings ................................................................... 240 Envelope Analysis for New Buildings ......................................................................... 245 Updated Envelope Standards for New and Existing Construction ........................ 245 Additional Reading ........................................................................................................ 246

10

HVAC Systems ......................................................................................................................... 247 Introduction ..................................................................................................................... 247 Surveying Existing Conditions ..................................................................................... 247 Human Thermal Comfort .............................................................................................. 248 HVAC System Types ...................................................................................................... 249 Energy Conservation Opportunities ............................................................................ 259 Cooling Equipment ........................................................................................................ 269 Domestic Hot Water ....................................................................................................... 271 Estimating HVAC Energy Consumption .................................................................... 272 vi

11

Electric Energy Management ................................................................................................ 273 Introduction ..................................................................................................................... 273 Power Supply .................................................................................................................. 273 Effects of Unbalanced Voltages on the Performance of Motors ............................... 274 Effect of Performance-General ...................................................................................... 274 Motor ................................................................................................................................ 275 Glossary of Frequently Occurring Motor Terms ........................................................ 275 Power Factor .................................................................................................................... 279 Handy Electrical Formulas & Rules of Thumb .......................................................... 281 Electric motor Operating Loads.................................................................................... 281 Determining Electric Motor Operating Loads ............................................................ 282 Power Meter .................................................................................................................... 282 Slip Measurement ........................................................................................................... 282 Amperage Readings ....................................................................................................... 284 Electric Motor Efficiency ................................................................................................ 284 Comparing Motors ......................................................................................................... 286 Sensitivity of Load to Motor RPM ................................................................................ 290 Theoretical Power Consumption .................................................................................. 291 Motor Efficiency Management...................................................................................... 294 Motors Are Like People ................................................................................................. 294 Motor Performance Management Process .................................................................. 294 How to Start MPMP ....................................................................................................... 295 Nameplate Glossary ....................................................................................................... 298

12

Energy Management Control Systems ................................................................................ 315 Energy Management Systems ....................................................................................... 315 Justification of EMCSs .................................................................................................... 321 Systems Integration ........................................................................................................ 326

13

Lighting ..................................................................................................................................... 353 Introduction ..................................................................................................................... 353 Lighting Fundamentals .................................................................................................. 353 Process to Improve Lighting Efficiency ....................................................................... 367 Maintenance .................................................................................................................... 368 New Technologies & Products ...................................................................................... 370 Special Considerations ................................................................................................... 379 Daylighting ...................................................................................................................... 383 Common Retrofits ........................................................................................................... 385 Schematics ........................................................................................................................ 390 Glossary ............................................................................................................................ 397

14

Energy Systems Maintenance ........................................................................................... ....401 Developing the Maintenance Program ........................................................................ 401 Detailed Maintenance Procedures ................................................................................ 413 Materials Handling Maintenance ................................................................................ .421 Truck Operation and Maintenance............................................................................... 423 Measuring Instruments .................................................................................................. 426 Saving Energy Dollars in Materials Handling and Storage...................................... 430 Recent Developments ..................................................................................................... 433

15

Industrial Insulation .............................................................................................................. .437 Fundamentals of Thermal Insulation Design Theory ....................................... ........437 vii

Insulation Materials ....................................................................................................... .439 Insulation Selection........................................................................................................ .443 Insulation Thickness Determination ............................................................................ 448 Insulation Economics ..................................................................................................... 461 16

Use of Alternative Energy ...................................................................................................... 471 Introduction ..................................................................................................................... 471 Solar Energy ..................................................................................................................... 471 Wind Energy .................................................................................................................... 484 Refuse-Derived Fuel ...................................................................................................... .489 Fuel Cells .................................................................................................................. ........493

17

Indoor Air Quality .................................................................................................................. 497 Introduction and Background ............................................................................... ........497 What is the Current Situation ....................................................................................... 499 Solutions and Prevention of IAQ Problems ............................................................... .500

18

Electric and Gas Utility Rates for Commercial and Industrial Consumers ................. 507 Introduction ..................................................................................................................... 507 Utility Costs .................................................................................................................... .507 Rate Structures ................................................................................................................ 508 Innovative Rate Type ...................................................................................................... 509 Calculation of a Monthly Bill ........................................................................................ 510 Conducting a Load Study .............................................................................................. 513 Effects of Deregulation on Customer Rates ................................................................ 516

19

Thermal Energy Storage ......................................................................................................... 519 Introduction ..................................................................................................................... 519 Storage Systems............................................................................................................... 521 Storage Mediums ............................................................................................................ 523 System Capacity .............................................................................................................. 526 Economic Summary........................................................................................................ 532

20

Codes Standards & Legislation ............................................................................................ 539 The Energy Policy Act of 1992 ...................................................................................... 539 State Codes....................................................................................................................... 540 Model Energy Code ........................................................................................................ 541 Federal Energy Efficiency Requirements .................................................................... 541 Indoor Air Quality Standards ....................................................................................... 542 Regulations & Standards Impacting CFCs .................................................................. 543 Regulatory and Legislative Issues Impacting Air Quality ........................................ 544 Regulatory and Legislative Issues Impacting Cogeneration & Power ................... 545 Opportunities in the Spot Market ................................................................................ 546 The Climatic Change Action Plan ................................................................................ 547

21

Natural Gas Purchasing ......................................................................................................... 549 Preface .............................................................................................................................. 549 Introduction ..................................................................................................................... 550 Natural Gas as a Fuel ..................................................................................................... 553 Buying Natural Gas ........................................................................................................ 566 New Frontiers for the Gas Industry ............................................................................. 575 viii

22

Control Systems ....................................................................................................................... 577 Introduction ..................................................................................................................... 577 Why Automatic Control? ............................................................................................... 577 Why Optimization? ........................................................................................................ 578 Technology Classifications ............................................................................................ 578 Control Modes ................................................................................................................. 580 Input/Output Devices ................................................................................................... 584 Valves and Dampers ....................................................................................................... 586 Instrument Accuracy, Repeatability, and Drift ........................................................... 588 Basic Control Block Diagrams ....................................................................................... 589 Key Fundamentals of Successfully Applied Automataic Controls ......................... 590 Operations and Maintenance ........................................................................................ 592 Expected Life of Control Equipment ........................................................................... 592 Basic Energy-saving Control Applications.................................................................. 594 Advanced Energy-saving Control Applications ........................................................ 594 Facilities Operations Control Applications ................................................................. 594 Control System Application Pitfalls to Avoid ............................................................. 601 Costs and Benefits of Automataic Control .................................................................. 601 Estimating Savings from Applied Automatic Control Systems ............................... 601 Conclusion and Further Study ...................................................................................... 605 Glossary of Terms ........................................................................................................... 616

23

Energy Security and Reliability ........................................................................................... 621 Introduction ..................................................................................................................... 621 Risk Analysis Methods ................................................................................................... 624 Countermeasures ............................................................................................................ 630 Economics of Energy Security and Reliability ............................................................ 632 Links to Energy Management ....................................................................................... 633 Impact of Utility Deregulation ...................................................................................... 634

24

Utility Deregulation and Energy System Outsourcing .................................................... 637 Introduction ..................................................................................................................... 637 An Historical Perspective of the Electric Power Industry ........................................ 637 The Transmission System and The Federal Regulatory Commission's (FERC) Role in Promoting Competition in Wholesale Power ........................ 638 Stranded Costs ................................................................................................................ 639 Status of State Electric Industry Restructuring Activity ........................................... 640 Trading Energy—Marketers and Brokers ................................................................... 640 The Impact of Retail Wheeling ..................................................................................... 640 The Ten-Step Program to Successful Utility Deregulation ....................................... 641 Aggregation ..................................................................................................................... 643 In-house vs. Outsourcing Energy Services.................................................................. 643

25

Financing Energy Management Projects ............................................................................ 649 Introduction ..................................................................................................................... 649 Financial Arrangements: A Simple Example .............................................................. 649 Financial Arrangements: Details and Terminology ................................................... 652 Applying Financial Arrangements: A Case Study ..................................................... 653 "Pros" & "Cons" of Each Financial Arrangement........................................................ 664 Characteristics that Influence which Financial Arrangement is Best ...................... 665 Incorporating Strategic Issues when Selecting Financial Arrangements ............... 666 ix

Glossary ............................................................................................................................ 666 26

Commissioning for Energy Management........................................................................... 671 Introduction to Commissioning for Energy Management ....................................... 671 Commissioning Definitions ........................................................................................... 671 The Commissioning Process in Existing Buildings ................................................... 672 Commissioning Measures ............................................................................................. 680 Ensuring Optimum Building Performance ................................................................. 695 Commissioning New Buildings for Energy Management........................................ 702 Additional Information .................................................................................................. 704

27

Measurement and Verification of Energy Savings ............................................................ 707 Introduction ..................................................................................................................... 707 Overview of Measurement and Verification Methods .............................................. 711

28

Ground-source Heat Pumps Applied to Commercial Buildings ................................... 755 Abstract ............................................................................................................................ 755 Background ...................................................................................................................... 755 Introduction to Ground-source Heat Pumps .............................................................. 756 About the Technology .................................................................................................... 757 Application ...................................................................................................................... 767 Technology Performance ............................................................................................... 771 Hypothetical Case Studies ............................................................................................. 774 The Technology in Perspective ..................................................................................... 781 Manufacturers ................................................................................................................. 783 For Further Information ................................................................................................. 785

29

Sustainability and High Performance Green Buildings ................................................. 793 Beginnings ....................................................................................................................... 793 Sustainability Gives Rise to the Green Building Movement .................................... 794 Introducing the LEED NC Rating System: A Technical Review .............................. 798 LEED for Existing Building Rating System (LEED-EB) Adopted in 2004 .............. 801 Summary Discussion of Two New LEED Programs ................................................. 804 The LEED Process ........................................................................................................... 805 ASHRAE Guides Developed to Support LEED ......................................................... 808

Appendix I—Thermal Sciences Review ....................................................................................... 815 Appendix II—Conversion Factors and Property Tables ............................................................ 837 Appendix III—Review of Electrical Science ............................................................................... 887 Index .................................................................................................................................................... 901

x

FOREWORD TO THE SIXTH EDITION Since its first edition was published more than two decades ago, Energy Management Handbook has remained the leading reference of choice used by thousands of energy management professionals for one fundamental reason. With this new edition, Dr. Turner and Mr. Doty continue to bring readers both the cutting-edge developments they need to know about, as well as the broad scope of practical information they must have to accomplish real and significant energy cost reduction goals. No other single publication has been as influential in defining and guiding the energy management profession. This new sixth edition builds upon and is no less essential than its predecessors. Comprehensive in scope, it provides today’s energy managers with the tools they will require to meet the challenges of a new era of predicted rising energy costs and supply uncertainties—ongoing developments which seem certain to impact virtually every aspect of the cost of doing business in the decades ahead. The new edition also examines the impact of the passage and implementation of the Energy Policy Act of 2005, which puts in place new energy efficiency requirements for government facilities, as well as energy-efficiency-related tax incentives for commercial buildings. As evidence continues to lend credence to the reality of global climate change, a growing number of businesses are seeing the “good business sense” of reducing greenhouse emissions and developing sustainable, green facilities. The sixth edition of Energy Management Handbook includes substantial new material on sustainability, high performance facilities and related technologies. In many ways the evolution of Energy Management Handbook has paralleled that of the Association of Energy Engineers (AEE) in meeting the needs of and setting the standards for the modern energy management profession which has emerged since the 1970s. Therefore, it seems very appropriate that the publication of this important new sixth edition officially kicks off AEE’s 30th anniversary celebration. As our organization completes its third decade of serving more than 8,000 members in 77 countries, it would be nearly impossible to overstate the impact that Energy Management Handbook has had for those we serve. The book is an official reference and preparatory text for AEE’s Certified Energy Manager (CEM) program, the most widely recognized professional credential in the energy management field, having certified more than 6,000 professionals since its inception in 1981. In addition numerous large corporations have selected Energy Management Handbook as their official corporate energy management reference. There is no doubt that Energy Management Handbook will continue its role as the indispensable reference for all energy managers who must meet the daunting energy supply and cost control challenges which lie ahead. Albert Thumann, P.E., C.E.M. Executive Director, The Association of Energy Engineers April 2006

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PREFACE TO THE SIXTH EDITION When the first introduction to Energy Management Handbook was written in 1982, I was in college, worried more about how to repay student loans than anything else. But this is now. This book lives to serve its readers. In helping to edit the book, it has been my goal to keep the material fresh, pertinent and useful. My approach has been to view it from the reader’s perspective, and to assure that the book provides good value. I look forward to further improvements, over time, as technologies continue to change and refine, since it will keep me current in the process. As I see it, the core intentions of this book are these: •

To address an audience of practicing energy managers and persons entering this trade. It is a tool for energy managers to get their questions answered, and get things accomplished.

•

To provide a resource of current, accurate, useful information in a readable format.

•

To emphasize applications, and include practical examples to clarify key topics, especially savings calculations. Background development and derivations should be limited to just what is needed to support the application messages.

For this edition, there are some significant changes, including a rewrite of the automatic controls chapter, and all-new chapters on ground source heat pumps, and green building design. As I have learned, editors check for errors and adjust grammar or format, but do not change the author’s message. The primary strategy for quality in this book is to choose the very best authors, so I’ll extend my personal thanks to each of them for their contributions. And I owe Wayne Turner a debt of thanks for the opportunity to contribute. I can only hope to do as well. I am excited about contributing to the long-running success of this book, because of its potential to influence other energy professionals, and therefore the public at large. Writing is just writing, until it changes a behavior or helps someone get something accomplished—then it becomes golden! Steve Doty Colorado Springs, CO April 2006

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CHAPTER 1

INTRODUCTION DR. WAYNE C. TURNER, REGENTS PROFESSOR Oklahoma State University Stillwater, Ok.

the opportunity of purchasing electricity from wherever the best deal could be found and to wheel the electric energy through the grid. Several states moved toward electrical deregulation, with some successes. But there were also some failures that made the energy industry pause and reflect. The prospect of electric deregulation and sharing grid infrastructure caused utilities to change their business view of their portion of the grid. Investment in expanding or upgrading this infrastructure became risky business for individual utilities, and so most chose to maintain the existing grid systems they owned, with a wait-and-see approach. Through electricity trading that manipulated pricing, problems with implementation changed the electric deregulation movement trend from slow to stop. Since good business relationships are good for all, some revisions to the EPACT-92 deregulation provisions may be necessary to see greater acceptance, and to sustain the concept in practice. To regain the confidence of the consumers, a greater degree of oversight of the business practices and the sharing of the vital US grid infrastructure may be necessary. This need is further accentuated by concerns of security and reliability of our nation's electrical grid, spurred by national events in September 2001 (9-11) and August 2003 (Blackout). Even with the bumps as electricity deregulation was first tried, wider scale electric deregulation remains an exciting concept and energy managers are watching with anticipation. As new skills are learned and beneficial industry relationships are created, the prospects of larger scale deregulation will improve. However, EPACT-1992's impact is further reaching. If utilities must compete with other producers of electricity, then they must be “lean and mean.” As Mr. Thumann mentions in the Foreword, this means many of the Demand Side Management (DSM) and other conservation activities of the utilities are being cut or eliminated. The roller coaster ride goes on. In 2005, the Bush Administration enacted the Energy Policy Act of 2005. This Act provides new opportunities and incentives for energy improvements in the country, including strong incentives for renewable energy sources and net metering. It is hoped that the tax incentives provided under this Act will become tools for the private sector to spur change with the free enterprise system. Similar in style to individual utility incentive programs, the Act's success will depend largely on the ability of private firms, such as consultants, ESCOs and

DR. BARNEY L. CAPEHART, PROFESSOR University of Florida Gainesville, Fla. STEPHEN A. PARKER Pacific Northwest National Laboratory Richland, WA STEVE DOTY Colorado Springs Utilities Colorado Springs, CO 1.1

BACKGROUND

Mr. Al Thumann, Executive Director of the Association of Energy Engineers, said it well in the Foreword. “The energy ‘roller coaster’ never ceases with new turns and spirals which make for a challenging ride.” Those professionals who boarded the ride in the late 70’s and stayed on board have experienced several ups and downs. First, being an energy manager was like being a mother, John Wayne, and a slice of apple pie all in one. Everyone supported the concept and success was around every bend. Then, the mid-80’s plunge in energy prices caused some to wonder “Do we really need to continue energy management?” Sometime in the late 80’s, the decision was made. Energy management is good business but it needs to be run by professionals. The Certified Energy Manager Program of the Association of Energy Engineers became popular and started a very steep growth curve. AEE continues to grow in membership and stature. About the same time (late 80’s), the impact of the Natural Gas Policy Act began to be felt. Now, energy managers found they could sometimes save significant amounts of money by buying “spot market” natural gas and arranging transportation. About the only thing that could be done in purchasing electricity was to choose the appropriate rate schedule and optimize parameters (power factor, demand, ratchet clauses, time of use, etc.—see Chapter 18 on energy rate schedules). With the arrival of the Energy Policy Act of 1992, electricity deregulation moved closer to reality, creating 1

2

Performance Contractors, to find partnering solutions to connect the program funding mechanism and the customer points of use. EPACT-2005 also updates the federal energy improvement mandates with a newer, stricter, baseline year (2003) and a new timeline for energy reduction requirements. The federal building segment remains an excellent target for large-scale improvement, as well as setting the all-important high visibility example for private industry to follow. The Presidential Executive Orders mentioned in Chapter 20 created the Federal Energy Management Program (FEMP) to aid the federal sector in meeting federal energy management goals. The potential FEMP savings are mammoth and new professionals affiliated with federal, as well as state and local governments have joined the energy manager ranks. However, as Congress changes complexion, the FEMP and even DOE itself may face uncertain futures. The roller coaster ride continues. FEMP efforts are showing results. Figure 1.3 outlines the goals that have been established for FEMP and reports show that the savings are apparently on schedule to meet all these goals. As with all such programs, reporting and measuring is difficult and critical. However, that energy and money is being saved is undeniable. More important, however, to most of this book's readers are the Technology Demonstration Programs and Technology Alerts being published by the Pacific Northwest Laboratories of Battelle in cooperation with the US DOE. Both of these programs are dramatically speeding the incorporation of new technology and the Alerts are a great source of information for all energy managers. (Information is available on the WEB). As utility DSM programs shrink, while private sector businesses and the federal government expand their needs for energy management programs, the door is opening for the ESCOs (Energy Service Companies), Shared Savings Providers, Performance Contractors, and other similar organizations. These groups are providing the auditing, energy and economic analyses, capital and monitoring to help other organizations reduce their energy consumption and reduce their expenditures for energy services. By guaranteeing and sharing the savings from improved energy efficiency and improved productivity, both groups benefit and prosper. Throughout it all, energy managers have proven time and time again, that energy management is cost effective. Furthermore, energy management is vital to our national security, environmental welfare, and economic productivity. This will be discussed in the next section.

ENERGY MANAGEMENT HANDBOOK

1.2

THE VALUE OF ENERGY MANAGEMENT

Business, industry and government organizations have all been under tremendous economic and environmental pressures in the last few years. Being economically competitive in the global marketplace and meeting increasing environmental standards to reduce air and water pollution have been the major driving factors in most of the recent operational cost and capital cost investment decisions for all organizations. Energy management has been an important tool to help organizations meet these critical objectives for their short term survival and long-term success. The problems that organizations face from both their individual and national perspectives include: •

Meeting more stringent environmental quality standards, primarily related to reducing global warming and reducing acid rain.

Energy management helps improve environmental quality. For example, the primary culprit in global warming is carbon dioxide, CO2. Equation 1.1, a balanced chemistry equation involving the combustion of methane (natural gas is mostly methane), shows that 2.75 pounds of carbon dioxide is produced for every pound of methane combusted. Thus, energy management, by reducing the combustion of methane can dramatically reduce the amount of carbon dioxide in the atmosphere and help reduce global warming. Commercial and industrial energy use accounts for about 45 percent of the carbon dioxide released from the burning of fossil fuels, and about 70 percent of the sulfur dioxide emissions from stationary sources. CH4 + 2 O2 = CO2 + 2 H2O (12 + 4*1) +2(2*16) = (12 + 2*16) + 2(2*1 +16)

(1.1)

Thus, 16 pounds of methane produces 44 pounds of carbon dioxide; or 2.75 pounds of carbon dioxide is produced for each pound of methane burned. Energy management reduces the load on power plants as fewer kilowatt hours of electricity are needed. If a plant burns coal or fuel oil, then a significant amount of acid rain is produced from the sulphur dioxide emitted by the power plant. Acid rain problems then are reduced through energy management, as are NOx problems. Less energy consumption means less petroleum field development and subsequent on-site pollution.

INTRODUCTION

3

Less energy consumption means less thermal pollution at power plants and less cooling water discharge. Reduced cooling requirements or more efficient satisfaction of those needs means less CFC usage and reduced ozone depletion in the stratosphere. The list could go on almost indefinitely, but the bottom line is that energy management helps improve environmental quality. Becoming—or continuing to be—economically competitive in the global marketplace, which requires reducing the cost of production or services, reducing industrial energy intensiveness, and meeting customer service needs for quality and delivery times.

•

companies and organizations to implement these new technologies. Total Quality Management (TQM) is another emphasis that many businesses and other organizations have developed over the last decade. TQM is an integrated approach to operating a facility, and energy cost control should be included in the overall TQM program. TQM is based on the principle that front-line employees should have the authority to make changes and other decisions at the lowest operating levels of a facility. If employees have energy management training, they can make informed decisions and recommendations about energy operating costs. •

Significant energy and dollar savings are available through energy management. Most facilities (manufacturing plants, schools, hospitals, office buildings, etc) can save according to the profile shown in Figure 1.1. Even more savings have been accomplished by some programs.

√

Low cost activities first year or two: 5 to 15%

√

Moderate cost, significant effort, three to five years: 15 to 30%

√

Long-term potential, higher cost, more engineering: 30 to 50% Figure 1.1

Typical Savings Through Energy Management

Once again, the country is becoming dependent on imported oil. During the time of the 1979 oil price crisis, the U.S. was importing almost 50% of our total oil consumption. By 1995, the U.S. was again importing 50% of our consumption. Today (2003) we are importing even more (approximately 54%), and the price has dramatically increased. Thus, the U.S. is once again vulnerable to an oil embargo or other disruption of supply. The major difference is that there is a better balance of oil supply among countries friendly to the U.S. Nonetheless, much of the oil used in this country is not produced in this country. The trade balance would be much more favorable if we imported less oil. •

Thus, large savings can be accomplished often with high returns on investments and rapid paybacks. Energy management can make the difference between profit and loss and can establish real competitive enhancements for most companies. Energy management in the form of implementing new energy efficiency technologies, new materials and new manufacturing processes and the use of new technologies in equipment and materials for business and industry is also helping companies improve their productivity and increase their product or service quality. Often, the energy savings is not the main driving factor when companies decide to purchase new equipment, use new processes, and use new high-tech materials. However, the combination of increased productivity, increased quality, reduced environmental emissions, and reduced energy costs provides a powerful incentive for

Maintaining energy supplies that are: — Available without significant interruption, and — Available at costs that do not fluctuate too rapidly.

Helping solve other national concerns which include: — Need to create new jobs — Need to improve the balance of payments by reducing costs of imported energy — Need to minimize the effects of a potential limited energy supply interruption

None of these concerns can be satisfactorily met without having an energy efficient economy. Energy management plays a key role in helping move toward this energy efficient economy.

1.3

THE ENERGY MANAGEMENT PROFESSION

Energy management skills are important to people in many organizations, and certainly to people who

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ENERGY MANAGEMENT HANDBOOK

perform duties such as energy auditing, facility or building management, energy and economic analysis, and maintenance. The number of companies employing professionally trained energy managers is large and growing. A partial list of job titles is given in Figure 1.2. Even though this is only a partial list, the breadth shows the robustness of the profession. For some of these people, energy management will be their primary duty, and they will need to acquire in-depth skills in energy analysis as well as knowledge about existing and new energy using equipment and technologies. For others—such as maintenance managers—energy management skills are simply one more area to cover in an already full plate of duties and expectations. The authors are writing this Energy Management Handbook for both of these groups of readers and users. Twenty years ago, few university faculty members would have stated their primary interest was energy management, yet today there are numerous faculty who prominently list energy management as their principal specialty. In 2003, there were 26 universities throughout the country listed by DOE as Industrial Assessment Centers or Energy Analysis and Diagnostic Centers. Other Universities offer coursework and/or do research in energy management but do not have one of the above centers. Finally, several professional Journals and Magazines now publish exclusively for energy managers while we know of none that existed 15 years ago. The need for energy management in federal facilities predates the U.S. Department of Energy. Since 1973, the President and Congress have called on federal agencies to lead by example in energy conservation and management in its own facilities, vehicles and operations. Both the President and the Congress have addressed the issue of improving energy efficiency in federal facilities several times since the mid- 1970’s. Each new piece of legislation and executive order has combined past experiences with new approaches in12 an effort to promote further efficiency gains in federal agencies . The Federal Energy Management Program (FEMP) was established

• • • • •

Plant Energy Manager Utility Energy Auditor State Agency Energy Analyst Consulting Energy Manager DSM Auditor/Manager

in the early 1970’s to coordinate federal agency reporting, analysis of energy use and to encourage energy conservation and still leads that effort today. Executive Order 13123, Greening the Government Through Efficient Energy Management, signed by President Clinton in June 1999, is the most recent directive for federal agencies. A brief summary of the goals of that executive order is given in Figure 1.3. In addition to the goals, Executive Order 13123 outlined several other requirements for federal agencies aimed at improving energy efficiency, reducing greenhouse gases and other emissions, increasing the use of renewable energy, and promoting federal leadership in energy management. Like energy management itself, utility DSM programs have had their ups and downs. DSM efforts peaked in the late 80s and early 90s, and have since retrenched significantly as utility deregulation and the movement to retail wheeling have caused utilities to reduce staff and cut costs as much as possible. This short-term cost cutting is seen by many utilities as their only way to become a competitive low-cost supplier of electric power. Once their large customers have the choice of their power supplier, they want to be able to hold on to these customers by offering rates that are competitive with other producers around the country. In the meantime, the other energy services provided by the utility are being reduced or eliminated in this corporate downsizing effort. This reduction in electric utility incentive and rebate programs, as well as the reduction in customer support, has produced a gap in energy service assistance that is being met by a growing sector of equipment supply companies and energy service consulting firms that are willing and able to provide the technical and financial assistance that many organizations previously got from their local electric utility. New business opportunities and many new jobs are being created in this shift away from utility support to energy service company support. Energy management skills are extremely important in this rapidly expanding field, and even critical to those companies that are in the business of identifying energy savings and providing a guarantee of the savings results.

• • • •

Building/Facility Energy Manager Utility Energy Analyst Federal Energy Analyst Consulting Energy Engineer

Figure 1.2 Typical Energy Management Job Titles

INTRODUCTION

√

Sec. 201. Greenhouse Gases Reduction Goal. Reduce greenhouse gas emissions attributed to facility energy use by 30% by 2010 compared to 1990.

√

Sec. 202. Energy Efficiency Improvement Goals. Reduce energy consumption per gross square foot of facilities by 30% by 2005 and by 35% by 2010 relative to 1985.

√

Sec. 203. Industrial and Laboratory Facilities. Reduce energy consumption per square foot, per unit of production, or per other unit as applicable by 20% by 2005 and 25% by 2010 relative to 1990.

√

Sec. 204. Renewable Energy. Strive to expand use of renewable energy. The federal government shall strive to install 2,000 solar energy systems at federal facilities by the end of 2000, and 20,000 solar energy systems at federal facilities by 2010.

√

Sec. 205. Petroleum. Each agency shall reduce the use of petroleum within its facilities. [Although no specific goal is identified.]

√

Sec. 206. Source Energy. The federal government shall strive to reduce total energy use as measured at the source. [Although agency reporting requirements for energy consumption are based on site energy, this section allows for an agency to receive a credit for activities where source energy decreases but site energy increase, such as in cogeneration systems.]

√

Sec. 207. Water Conservation. Reduce water consumption and associated energy use in their facilities to reach the goals (subsequently) set by the Secretary of Energy. [The Secretary of Energy, through the DOE Federal Energy Management Program, issued guidance to establish water efficiency improvement goal for federal agencies in May 2000. See www.eere.energy.gov/femp/ resources/waterguide.html for details.

Figure 1.3. Federal Agency Goals as Established by Executive Order 13123. Thus, the future for energy management is extremely promising. It is cost effective, it improves environmental quality, it helps reduce the trade deficit, and it helps reduce dependence on foreign fuel supplies. Energy management will continue to grow in size and importance.

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1.4

SOME SUGGESTED PRINCIPLES OF ENERGY MANAGEMENT

(The material in this section is repeated verbatim from the first and second editions of this handbook. Mr. Roger Sant who was then director of the Energy Productivity Center of the Carnegie-Mellon Institute of Research in Arlington, VA, wrote this section for the first edition. It was unchanged for the second edition. Now, the fourth edition is being printed. The principles developed in this section are still sound. Some of the number quoted may now be a little old; but the principles are still sound. Amazing, but what was right 18 years ago for energy management is still right today. The game has changed, the playing field has moved; but the principles stay the same). If energy productivity is an important opportunity for the nation as a whole, it is a necessity for the individual company. It represents a real chance for creative management to reduce that component of product cost that has risen the most since 1973. Those who have taken advantage of these opportunities have done so because of the clear intent and commitment of the top executive. Once that commitment is understood, managers at all levels of the organization can and do respond seriously to the opportunities at hand. Without that leadership, the best designed energy management programs produce few results. In addition, we would like to suggest four basic principles which, if adopted, may expand the effectiveness of existing energy management programs or provide the starting point of new efforts. The first of these is to control the costs of the energy function or service provided, but not the Btu of energy. As most operating people have noticed, energy is just a means of providing some service or benefit. With the possible exception of feedstocks for petrochemical production, energy is not consumed directly. It is always converted into some useful function. The existing data are not as complete as one would like, but they do indicate some surprises. In 1978, for instance, the aggregate industrial expenditure for energy was $55 billion. Thirty-five percent of that was spent for machine drive from electric motors, 29% for feedstocks, 27% for process heat, 7% for electrolytic functions, and 2% for space conditioning and light. As shown in Table 1.1, this is in blunt contrast to measuring these functions in Btu. Machine drive, for example, instead of 35% of the dollars, required only 12% of the Btu. In most organizations it will pay to be even more specific about the function provided. For instance, evaporation, distillation, drying, and reheat are all typical of

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ENERGY MANAGEMENT HANDBOOK

Table 1.1 Industrial Energy Functions by Expenditure and Btu, 1978 ————————————————————————— Dollar Expenditure Percent of Percent of Function (billions) Expenditure Total Btu ————————————————————————— Machine drive 19 35 12 Feedstocks 16 29 35 Process steam 7 13 23 Direct heat 4 7 13 Indirect heat 4 7 13 Electrolysis 4 7 3 Space conditioning and lighting 1 1 1 ––– ––– ––– Total 55 100 100 ————————————————————————— Source: Technical Appendix, The Least-Cost Energy Strategy, Carnegie-Mellon University Press, Pittsburgh, Pa., 1979, Tables 1.2.1 and 11.3.2.

the uses to which process heat is put. In some cases it has also been useful to break down the heat in terms of temperature so that the opportunities for matching the heat source to the work requirement can be utilized. In addition to energy costs, it is useful to measure the depreciation, maintenance, labor, and other operating costs involved in providing the conversion equipment necessary to deliver required services. These costs add as much as 50% to the fuel cost. It is the total cost of these functions that must be managed and controlled, not the Btu of energy. The large difference in cost of the various Btu of energy can make the commonly used Btu measure extremely misleading. In November 1979, the cost of 1 Btu of electricity was nine times that of 1 Btu of steam coal. Table 1.2 shows how these values and ratios compare in 2005.

One of the most desirable and least reliable skills for an energy manager is to predict the future cost of energy. To the extent that energy costs escalate in price beyond the rate of general inflation, investment paybacks will be shortened, but of course the reverse is also true. A quick glance at Table 1.2 shows the inconsistency in overall energy price changes over this period in time. Even the popular conception that energy prices always go up was not true for this period, when normalized to constant dollars. This volatility in energy pricing may account for some business decisions that appear overly conservative in establishing rate of return or payback period hurdles. Availabilities also differ and the cost of maintaining fuel flexibility can affect the cost of the product. And as shown before, the average annual price increase of natural gas has been almost three times that of electricity. Therefore, an energy management system that controls Btu per unit of product may completely miss the effect of the changing economics and availabilities of energy alternatives and the major differences in usability of each fuel. Controlling the total cost of energy functions is much more closely attuned to one of the principal interests of the executives of an organization—controlling costs. NOTE: The recommendation to control energy dollars and not Btus does not always apply. For example, tracking building energy use per year for comparison to prior years is best done with Btus since doing so negates the effect of energy price volatility. Similarly, comparing the heating use of a commercial facility against an industry segment benchmark using cost alone can yield wild results if, for example, one building uses natural gas to heat while another uses electric resistance; this is another case where using Btus yields more meaningful results.

Table 1.2 Cost of Industrial Energy per Million Btu, 1979 and 2005

INTRODUCTION

A second principle of energy management is to control energy functions as a product cost, not as a part of manufacturing or general overhead. It is surprising how many companies still lump all energy costs into one general or manufacturing overhead account without identifying those products with the highest energy function cost. In most cases, energy functions must become part of the standard cost system so that each function can be assessed as to its specific impact on the product cost. The minimum theoretical energy expenditure to produce a given product can usually be determined en route to establishing a standard energy cost for that product. The seconds of 25-hp motor drive, the minutes necessary in a 2200°F furnace to heat a steel part for fabrication, or the minutes of 5-V electricity needed to make an electrolytic separation, for example, can be determined as theoretical minimums and compared with the actual figures. As in all production cost functions, the minimum standard is often difficult to meet, but it can serve as an indicator of the size of the opportunity. In comparing actual values with minimum values, four possible approaches can be taken to reduce the variance, usually in this order: 1.

An hourly or daily control system can be installed to keep the function cost at the desired level.

2.

Fuel requirements can be switched to a cheaper and more available form.

3.

A change can be made to the process methodology to reduce the need for the function.

4.

New equipment can be installed to reduce the cost of the function.

The starting point for reducing costs should be in achieving the minimum cost possible with the present equipment and processes. Installing management control systems can indicate what the lowest possible energy use is in a well-controlled situation. It is only at that point when a change in process or equipment configuration should be considered. An equipment change prior to actually minimizing the expenditure under the present system may lead to oversizing new equipment or replacing equipment for unnecessary functions. The third principle is to control and meter only the main energy functions—the roughly 20% that make up 80% of the costs. As Peter Drucker pointed out some time ago, a few functions usually account for a majority of the costs. It is important to focus controls on those that represent the meaningful costs and aggregate the

7

remaining items in a general category. Many manufacturing plants in the United States have only one meter, that leading from the gas main or electric main into the plant from the outside source. Regardless of the reasonableness of the standard cost established, the inability to measure actual consumption against that standard will render such a system useless. Submetering the main functions can provide the information not only to measure but to control costs in a short time interval. The cost of metering and submetering is usually incidental to the potential for realizing significant cost improvements in the main energy functions of a production system. The fourth principle is to put the major effort of an energy management program into installing controls and achieving results. It is common to find general knowledge about how large amounts of energy could be saved in a plant. The missing ingredient is the discipline necessary to achieve these potential savings. Each step in saving energy needs to be monitored frequently enough by the manager or first-line supervisor to see noticeable changes. Logging of important fuel usage or behavioral observations are almost always necessary before any particular savings results can be realized. Therefore, it is critical that an energy director or committee have the authority from the chief executive to install controls, not just advise line management. Those energy managers who have achieved the largest cost reductions actually install systems and controls; they do not just provide good advice. As suggested earlier, the overall potential for increasing energy productivity and reducing the cost of energy services is substantial. The 20% or so improvement in industrial energy productivity since 1972 is just the beginning. To quote the energy director of a large chemical company: “Long-term results will be much greater.” Although no one knows exactly how much we can improve productivity in practice, the American Physical Society indicated in their 1974 energy conservation study that it is theoretically possible to achieve an eightfold improvement of the 1972 energy/production ratio.9 Most certainly, we are a long way from an economic saturation of the opportunities (see, e.g., Ref. 10). The common argument that not much can be done after a 15 or 20% improvement has been realized ought to be dismissed as baseless. Energy productivity provides an expanding opportunity, not a last resort. The chapters in this book provide the information that is necessary to make the most of that opportunity in each organization. References 1. Statistical Abstract of the United States, U.S. Government Printing Office, Washington, D.C., 1999. 2. Energy User News, Jan. 14, 1980. 3. JOHN G. WINGER et al., Outlook for Energy in the United States

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ENERGY MANAGEMENT HANDBOOK

to 1985, The Chase Manhattan Bank, New York, 1972, p 52. 4. DONELLA H. MEADOWS et al., The Limits to Growth, Universe Books, New York, 1972, pp. 153-154. 5. JIMMY E. CARTER, July 15, 1979, “Address to the Nation,” Washington Post, July 16, 1979, p. A14. 6. Monthly Energy Review, Jan. 1980, U.S. Department of Energy, Washington, D.C., p. 16. 7. Monthly Energy Review, Jan. 1980, U.S. Department of Energy, Washington D.C., p. 8; Statistical Abstract of the United States, U.S. Government Printing Office, Washington, D.C., 1979, Table 1409; Energy User News, Jan. 20, 1980, p. 14. 8. American Association for the Advancement of Science, “U.S. Energy Demand: Some Low Energy Futures,” Science, Apr. 14, 1978, p. 143.

9. American Physical Society Summer Study on Technical Aspects of Efficient Energy Utilization, 1974. Available as W.H. CARNAHAN et al., Efficient Use of Energy, a Physics Perspective, from NTIS PB242-773, or in Efficient Energy Use, Vol. 25 of the American Institute of Physics Conference Proceedings. 10. R.W. SANT, The Least-Cost Energy Strategy, Carnegie-Mellon University Press, Pittsburgh, Pa., 1979 11. U.S. Congress Office of Technology Assessment (OTA). Energy Efficiency in the Federal Government: Government by Good Example? OTA-E-492, U.S. Government Printing Office, Washington D.C., May 1991. 12. U.S. Air Force. DOD Energy Manager’s Handbook Volume 1: Installation Energy Management. Washington D.C., April 1993.

CHAPTER 2

EFFECTIVE ENERGY MANAGEMENT WILLIAM H. MASHBURN, P.E., CEM

•

Most manufacturing companies are looking for a competitive edge. A reduction in energy costs to manufacture the product can be immediate and permanent. In addition, products that use energy, such as motor driven machinery, are being evaluated to make them more energy efficient, and therefore more marketable. Many foreign countries where energy is more critical, now want to know the maximum power required to operate a piece of equipment.

•

Energy technology is changing so rapidly that state-of-the-art techniques have a half life of ten years at the most. Someone in the organization must be in a position to constantly evaluate and update this technology.

•

Energy security is a part of energy management. Without a contingency plan for temporary shortages or outages, and a strategic plan for long range plans, organizations run a risk of major problems without immediate solutions.

•

Future price shocks will occur. When world energy markets swing wildly with only a five percent decrease in supply, as they did in 1979, it is reasonable to expect that such occurrences will happen again.

Professor Emeritus Mechanical Engineering Department Virginia Polytechnic Institute & State University Blacksburg, Virginia

2.1

INTRODUCTION

Some years ago, a newspaper headline stated, “Lower energy use leaves experts pleased but puzzled.” The article went on to state “Although the data are preliminary, experts are baffled that the country appears to have broken the decades-old link between economic growth and energy consumption.” For those involved in energy management, this comes as no surprise. We have seen companies becoming more efficient in their use of energy, and that’s showing in the data. Those that have extracted all possible savings from downsizing, are now looking for other ways to become more competitive. Better management of energy is a viable way, so there is an upward trend in the number of companies that are establishing an energy management program. Management is now beginning to realize they are leaving a lot of money on the table when they do not instigate a good energy management plan. With the new technologies and alternative energy sources now available, this country could possibly reduce its energy consumption by 50%—if there were no barriers to the implementation. But of course, there are barriers, mostly economic. Therefore, we might conclude that managing energy is not a just technical challenge, but one of how to best implement those technical changes within economic limits, and with a minimum of disruption. Unlike other management fads that have come and gone, such as value analysis and quality circles, the need to manage energy will be permanent within our society. There are several reasons for this: •

Those people then who choose—or in many cases are drafted—to manage energy will do well to recognize this continuing need, and exert the extra effort to become skilled in this emerging and dynamic profession. The purpose of this chapter is to provide the fundamentals of an energy management program that can be, and have been, adapted to organizations large and small. Developing a working organizational structure may be the most important thing an energy manager can do.

2.2

ENERGY MANAGEMENT PROGRAM

All the components of a comprehensive energy management program are depicted in Figure 2-1. These components are the organizational structure, a policy, and plans for audits, education, reporting, and strategy. It is hoped that by understanding the fundamentals of managing energy, the energy manager can then adapt a good

There is a direct economic return. Most opportunities found in an energy survey have less than a two year payback. Some are immediate, such as load shifting or going to a new electric rate schedule. 9

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ENERGY MANAGEMENT HANDBOOK

The organizational chart for energy management shown in Figure 2-1 is generic. It must be adapted to fit into an existing structure for each organization. For example, the presidential block may be the general manager, and VP blocks may be division managers, but the fundamental principles are the same. The main feature of the chart is the location of the energy manager. This position should be high enough in the organizational structure to have access to key players in management, and to have a knowledge of current events within the company. For example, the timing for presenting energy projects can be critical. Funding availability and other management priorities should be known and understood. The organizational level of the energy manager is also indicative of the support management is willing to give to the position.

pany. Every successful program has had this one thing in common—one person who is a shaker and mover that makes things happen. The program is then built around this person. There is a great tendency for the energy manager to become an energy engineer, or a prima donna, and attempt to conduct the whole effort alone. Much has been accomplished in the past with such individuals working alone, but for the long haul, managing the program by involving everyone at the facility is much more productive and permanent. Developing a working organizational structure may be the most important thing an energy manager can do. The role and qualifications of the energy manager have changed substantially in the past few years, caused mostly by EPACT-1992 requiring certification of federal energy managers, deregulation of the electric utility industry bringing both opportunity and uncertainty, and by performance contracting requiring more business skills than engineering. In her book titled “Performance Contracting: Expanded Horizons,” Shirley Hansen give the following requirements for an energy management:

2.3.1 Energy Manager One very important part of an energy management program is to have top management support. More important, however, is the selection of the energy manager, who can among other things secure this support. The person selected for this position should be one with a vision of what managing energy can do for the com-

• • • • • • •

working program to the existing organizational structure. Each component is discussed in detail below.

2.3

ORGANIZATIONAL STRUCTURE

Set up an Energy Management Plan Establish energy records Identify outside assistance Assess future energy needs Identify financing sources Make energy recommendations Implement recommendations

ENERGY MANAGEMENT PROGRAM President Policy VP

Coordinator

VP

VP

Coordinator

Audit Plan

Energy Manager

Educational Plan

Coordinator

Reporting System

Employees

Figure 2.1

Strategic Plan

EFFECTIVE ENERGY MANAGEMENT

• • •

Provide liaison for the energy committee Plan communication strategies Evaluate program effectiveness

Energy management programs can, and have, originated within one division of a large corporation. The division, by example and savings, motivates people at corporate level to pick up on the program and make energy management corporate wide. Many also originate at corporate level with people who have facilities responsibility, and have implemented a good corporate facilities program. They then see the importance and potential of an energy management program, and take a leadership role in implementing one. In every case observed by the author, good programs have been instigated by one individual who has recognized the potential, is willing to put forth the effort—in addition to regular duties—will take the risk of pushing new concepts, and is motivated by a seemingly higher calling to save energy. If initiated at corporate level, there are some advantages and some precautions. Some advantages are: •

More resources are available to implement the program, such as budget, staff, and facilities.

•

If top management support is secured at corporate level, getting management support at division level is easier.

•

Total personnel expertise throughout the corporation is better known and can be identified and made known to division energy managers.

•

Expensive test equipment can be purchased and maintained at corporate level for use by divisions as needed.

•

A unified reporting system can be put in place.

•

Creative financing may be the most needed and the most important assistance to be provided from corporate level.

•

Impacts of energy and environmental legislation can best be determined at corporate level.

•

Electrical utility rates and structures, as well as effects of unbundling of electric utilities, can be evaluated at corporate level.

Some precautions are: •

11

Many people at division level may have already done a good job of saving energy, and are cautious

about corporate level staff coming in and taking credit for their work. •

All divisions don’t progress at the same speed. Work with those who are most interested first, then through the reporting system to top management give them credit. Others will then request assistance.

2.3.2 Energy Team The coordinators shown in Figure 2-1 represent the energy management team within one given organizational structure, such as one company within a corporation. This group is the core of the program. The main criteria for membership should be an indication of interest. There should be a representative from the administrative group such as accounting or purchasing, someone from facilities and/or maintenance, and a representative from each major department. This energy team of coordinators should be appointed for a specific time period, such as one year. Rotation can then bring new people with new ideas, can provide a mechanism for tactfully removing nonperformers, and involve greater numbers of people in the program in a meaningful way. Coordinators should be selected to supplement skills lacking in the energy manager since, as pointed out above, it is unrealistic to think one energy manager can have all the qualifications outlined. So, total skills needed for the team, including the energy manager may be defined as follows: •

Have enough technical knowledge within the group to either understand the technology used by the organization, or be trainable in that technology.

•

Have a knowledge of potential new technology that may be applicable to the program.

•

Have planning skills that will help establish the organizational structure, plan energy surveys, determine educational needs, and develop a strategic energy management plan.

•

Understand the economic evaluation system used by the organization, particularly payback and life cycle cost analysis.

•

Have good communication and motivational skills since energy management involves everyone within the organization.

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ENERGY MANAGEMENT HANDBOOK

The strengths of each team member should be evaluated in light of the above desired skills, and their assignments made accordingly. 2.3.3 Employees Employees are shown as a part of the organizational structure, and are perhaps the greatest untapped resource in an energy management program. A structured method of soliciting their ideas for more efficient use of energy will prove to be the most productive effort of the energy management program. A good energy manager will devote 20% of total time working with employees. Too many times employee involvement is limited to posters that say “Save Energy.” Employees in manufacturing plants generally know more about the equipment than anyone else in the facility because they operate it. They know how to make it run more efficiently, but because there is no mechanism in place for them to have an input, their ideas go unsolicited. An understanding of the psychology of motivation is necessary before an employee involvement program can be successfully conducted. Motivation may be defined as the amount of physical and mental energy that a worker is willing to invest in his or her job. Three key factors of motivation are listed below:

may be sources of releasing motivation, A study done by Heresy and Blanchard [1] in 1977 asked workers to rank job related factors listed below. The results were as follows: 1. 2. 3. 4. 5. 6. 7. 8. 9.

Full appreciation for work done Feeling “in” on things Understanding of personal problems Job security Good wages Interesting work Promoting and growth in the company Management loyalty to workers Good working conditions

10. Tactful discipline of workers This priority list would no doubt change with time and with individual companies, but the rankings of what supervisors thought employees wanted were almost diametrically opposed. They ranked good wages as first. It becomes obvious from this that job enrichment is a key to motivation. Knowing this, the energy manager can plan a program involving employees that can provide job enrichment by some simple and inexpensive recognitions. Some things to consider in employee motivation are as follows:

•

Motivation is already within people. The task of the supervisor is not to provide motivation, but to know how to release it.

•

•

The amount of energy and enthusiasm people are willing to invest in their work varies with the individual. Not all are over-achievers, but not all are lazy either.

There appears to be a positive relationship between fear arousal and persuasion if the fear appeals deal with topics primarily of significance to the individual; e.g., personal well being.

•

The success of persuasive communication is directly related to the credibility of the source of communication and may be reduced if recommended changes deviate too far from existing beliefs and practices.

•

When directing attention to conservation, display the reminder at the point of action at the appropriate time for action, and specify who is responsible for taking the action and when it should occur. Generic posters located in the work area are not effective.

•

Studies have shown that pro-conservation attitudes and actions will be enhanced through associations with others with similar attitudes, such as being part of an energy committee.

•

Positive effects are achieved with financial incentives if the reward is in proportion to the savings,

•

The amount of personal satisfaction to be derived determines the amount of energy an employee will invest in the job.

Achieving personal satisfaction has been the subject of much research by industrial psychologists, and they have emerged with some revealing facts. For example. They have learned that most actions taken by people are done to satisfy a physical need—such as the need for food—or an emotional need—such as the need for acceptance, recognition, or achievement. Research has also shown that many efforts to motivate employees deal almost exclusively with trying to satisfy physical needs, such as raises, bonuses, or fringe benefits. These methods are effective only for the short term, so we must look beyond these to other needs that

EFFECTIVE ENERGY MANAGEMENT

13

and represents respectable increments of spendable income. •

Consumers place considerable importance on the potential discomfort in reducing their consumption of energy. Changing thermostat settings from the comfort zone should be the last desperate act for an energy manager.

•

Social recognition and approval is important, and can occur through such things as the award of medals, designation of employee of the month, and selection to membership in elite sub-groups. Note that the dollar cost of such recognitions is minimal.

•

The potentially most powerful source of social incentives for conservation behavior—but the least used—is the commitment to others that occurs in the course of group decisions.

manager, coordinators, and any committees or task groups. •

Reporting—Without authority from top management, it is often difficult for the energy manager to require others within the organization to comply with reporting requirements necessary to properly manage energy. The policy is the place to establish this. It also provides a legitimate reason for requesting funds for instrumentation to measure energy usage.

•

Training—If training requirements are established in the policy, it is again easier to include this in budgets. It should include training at all levels within the organization.

Before entering seriously into a program involving employees, be prepared to give a heavy commitment of time and resources. In particular, have the resources to respond quickly to their suggestions.

Many companies, rather that a comprehensive policy encompassing all the features described above, choose to go with a simpler policy statement. Appendices A and B give two sample energy policies. Appendix A is generic and covers the items discussed above. Appendix B is a policy statement of a multinational corporation.

2.4. ENERGY POLICY

2.5 PLANNING

A well written energy policy that has been authorized by management is as good as the proverbial license to steal. It provides the energy manager with the authority to be involved in business planning, new facility location and planning, the selection of production equipment, purchase of measuring equipment, energy reporting, and training—things that are sometimes difficult to do. If you already have an energy policy, chances are that it is too long and cumbersome. To be effective, the policy should be short—two pages at most. Many people confuse the policy with a procedures manual. It should be bare bones, but contain the following items as a minimum:

Planning is one of the most important parts of the energy management program, and for most technical people is the least desirable. It has two major functions in the program. First, a good plan can be a shield from disruptions. Second, by scheduling events throughout the year, continuous emphasis can be applied to the energy management program, and will play a major role in keeping the program active. Almost everyone from top management to the custodial level will be happy to give an opinion on what can be done to save energy. Most suggestions are worthless. It is not always wise from a job security standpoint to say this to top management. However, if you inform people— especially top management—that you will evaluate their suggestion, and assign a priority to it in your plan, not only will you not be disrupted, but may be considered effective because you do have a plan. Many programs were started when the fear of energy shortages was greater, but they have declined into oblivion. By planning to have events periodically through the year, a continued emphasis will be placed on energy management. Such events can be training programs, audits, planning sessions, demonstrations, research projects, lectures, etc.

•

Objectives—this can contain the standard motherhood and flag statements about energy, but the most important is that the organization will incorporate energy efficiency into facilities and new equipment, with emphasis on life cycle cost analysis rather than lowest initial cost.

•

Accountability—This should establish the organizational structure and the authority for the energy

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The secret to a workable plan is to have people who are required to implement the plan involved in the planning process. People feel a commitment to making things work if they have been a part of the design. This is fundamental to any management planning, but more often that not is overlooked. However, in order to prevent the most outspoken members of a committee from dominating with their ideas, and rejecting ideas from less outspoken members, a technique for managing committees must be used. A favorite of the author is the Nominal Group Technique developed at the University of Wisconsin in the late 1980’s by Andre Delbecq and Andrea Van de Ven [2]. This technique consists of the following basic steps: 1. Problem definition—The problem is clearly defined to members of the group. 2. Grouping—Divide large groups into smaller groups of seven to ten, then have the group elect a recording secretary. 3. Silent generation of ideas—Each person silently and independently writes as many answers to the problem as can be generated within a specified time.

• • • • • •

Motors Lighting Steam system Water Controls HVAC

•

Employee suggestions

By defining individual audits in this manner, it is easy to identify the proper team for the audit. Don’t neglect to bring in outside people such as electric utility and natural gas representatives to be team members. Scheduling the audits, then, can contribute to the events that will keep the program active. With the maturing of performance contracting, energy managers have two choices for the energy audit process. They may go through the contracting process to select and define the work of a performance contractor, or they can set up their own team and conduct audits, or in some cases such as a corporate energy manager, performance contracting may be selected for one facility, and energy auditing for another. Each has advantages and disadvantages. Advantages of performance contracting are:

4. Round-robin listing—Secretary lists each idea individually on an easel until all have been recorded.

•

No investment is required of the company—other than that involved in the contracting process, which can be very time consuming.

5. Discussion—Ideas are discussed for clarification, elaboration, evaluation and combining.

•

A minimum of in-house people are involved, namely the energy manager and financial people.

6. Ranking—Each person ranks the five most important items. The total number of points received for each idea will determine the first choice of the group.

Disadvantages are: •

Technical resources are generally limited to the contracting organization.

•

Performance contracting is still maturing, and many firms underestimate the work required

•

The contractor may not have the full spectrum of skills needed.

•

The contractor may not have an interest in low/ cost no/cost projects.

2.6 AUDIT PLANNING The details of conducting audits are discussed in a comprehensive manner in Chapter 4, but planning should be conducted prior to the actual audits. The planning should include types of audits to be performed, team makeup, and dates. By making the audits specific rather than general in nature, much more energy can be saved. Examples of some types of audits that might be considered are: • •

Tuning-Operation-Maintenance (TOM) Compressed air

Advantages of setting up an audit team are: •

The team can be selected to match equipment to be audited, and can be made up of in-house personnel, outside specialists, or best, a combination of both.

EFFECTIVE ENERGY MANAGEMENT

•

They can identify all potential energy conservation projects, both low-cost/no-cost as well as large capital investments.

•

The audit can be an excellent training tool by involving others in the process, and by adding a training component as a part of the audit.

Disadvantages of an audit team approach: •

Financing identified projects becomes a separate issue for the energy manager.

•

It takes a well organized energy management structure to take full advantage of the work of the audit team.

2.7 EDUCATIONAL PLANNING A major part of the energy manager’s job is to provide some energy education to persons within the organization. In spite of the fact that we have been concerned with it for the past two decades, there is still a sea of ignorance concerning energy. Raising the energy education level throughout the organization can have big dividends. The program will operate much more effectively if management understands the complexities of energy, and particularly the potential for economic benefit; the coordinators will be more effective is they are able to prioritize energy conservation measures, and are aware of the latest technology; the quality and quantity of employee suggestions will improve significantly with training. Educational training should be considered for three distinct groups—management, the energy team, and employees. 2.7.1 Management Training It is difficult to gain much of management’s time, so subtle ways must be developed to get them up to speed. Getting time on a regular meeting to provide updates on the program is one way. When the momentum of the program gets going, it may be advantageous to have a half or one day presentation for management. A good concise report periodically can be a tool to educate management. Short articles that are pertinent to your educational goals, taken from magazines and newspapers can be attached to reports and sent selectively. Having management be a part of a training program for either the energy team or employees, or

15

both, can be an educational experience since we learn best when we have to make a presentation. Ultimately, the energy manager should aspire to be a part of business planning for the organization. A strategic plan for energy should be a part of every business plan. This puts the energy manager into a position for more contact with management people, and thus the opportunity to inform and teach. 2.7.2 Energy Team Training Since the energy team is the core group of the energy management program, proper and thorough training for them should have the highest priority. Training is available from many sources and in many forms. •

Self study—this necessitates having a good library of energy related materials from which coordinators can select.

•

In-house training—may be done by a qualified member of the team—usually the energy manager, or someone from outside.

•

Short courses offered by associations such as the Association of Energy Engineers [3], by individual consultants, by corporations, and by colleges and universities.

•

Comprehensive courses of one to four weeks duration offered by universities, such the one at the University of Wisconsin, and the one being run cooperatively by Virginia Tech and N.C. State University.

For large decentralized organizations with perhaps ten or more regional energy managers, an annual two or three-day seminar can be the base for the educational program. Such a program should be planned carefully. The following suggestions should be incorporated into such a program: •

Select quality speakers from both inside and outside the organization.

•

This is an opportunity to get top management support. Invite a top level executive from the organization to give opening remarks. It may be wise to offer to write the remarks, or at least to provide some material for inclusion.

•

Involve the participants in workshop activities so they have an opportunity to have an input into the program. Also, provide some practical tips

16

ENERGY MANAGEMENT HANDBOOK

on energy savings that they might go back and implement immediately. One or two good ideas can sometimes pay for their time in the seminar. •

Make the seminar first class with professional speakers; a banquet with an entertaining—not technical—after dinner speaker; a manual that includes a schedule of events, biosketches of speakers, list of attendees, information on each topic presented, and other things that will help pull the whole seminar together. Vendors will contribute things for door prizes.

•

You may wish to develop a logo for the program, and include it on small favors such as cups, carrying cases, etc.

2.7.3 Employee Training A systematic approach for involving employees should start with some basic training in energy. This will produce a much higher quality of ideas from them. Employees place a high value on training, so a side benefit is that morale goes up. Simply teaching the difference between electrical demand and kilowatt hours of energy, and that compressed air is very expensive is a start. Short training sessions on energy can be injected into other ongoing training for employees, such as safety. A more comprehensive training program should include: •

Energy conservation in the home

•

Fundamentals of electric energy

•

Fundamentals of energy systems

•

How energy surveys are conducted and what to look for

2.8 STRATEGIC PLANNING Developing an objective, strategies, programs, and action items constitutes strategic planning for the energy management program. It is the last but perhaps the most important step in the process of developing the program, and unfortunately is where many stop. The very name “Strategic Planning” has an ominous sound for those who are more technically inclined. However, by using a simplified approach and involving the energy management team in the process, a plan can be developed using a flow chart that will define the program for the next five years. If the team is involved in developing each of the

components of objective, strategies, programs, and action items—using the Nominal Group Technique—the result will be a simplified flow chart that can be used for many purposes. First, it is a protective plan that discourages intrusion into the program, once it is established and approved. It provides the basis for resources such as funding and personnel for implementation. It projects strategic planning into overall planning by the organization, and hence legitimizes the program at top management level. By involving the implementers in the planning process, there is a strong commitment to make it work. Appendix C contains flow charts depicting a strategic plan developed in a workshop conducted by the author by a large defense organization. It is a model plan in that it deals not only with the technical aspects of energy management but also the funding, communications, education, and behavior modification.

2.9 REPORTING There is no generic form to that can be used for reporting. There are too many variables such as organization size, product, project requirements, and procedures already in existence. The ultimate reporting system is one used by a chemical company making a textile product. The Btu/lb of product is calculated on a computer system that gives an instantaneous reading. This is not only a reporting system, but one that detects maintenance problems. Very few companies are set up to do this, but many do have some type of energy index for monthly reporting. When energy prices fluctuate wildly, the best energy index is usually based on Btus; but, when energy prices are stable, the best index is dollars. However, there are still many factors that will influence any index, such as weather, production, expansion or contraction of facilities, new technologies, etc. The bottom line is that any reporting system has to be customized to suit individual circumstances. And, while reporting is not always the most glamorous part of managing energy, it can make a contribution to the program by providing the bottom line on its effectiveness. It is also a straight pipeline into management, and can be a tool for promoting the program. The report is probably of most value to the one who prepares it. It is a forcing function that requires all information to be pulled together in a coherent manner. This requires much thought and analysis that might not otherwise take place. By making reporting a requirement of the energy

EFFECTIVE ENERGY MANAGEMENT

policy, getting the necessary support can be easier. In many cases, the data may already be collected on a periodic basis and put into a computer. It may simply require combining production data and energy data to develop an energy index. Keep the reporting requirements as simple as possible. The monthly report could be something as simple as adding to an ongoing graph that compares present usage to some baseline year. Any narrative should be short, with data kept in a file that can be provided for any supporting in-depth information. With all the above considered, the best way to report is to do it against an audit that has been performed at the facility. One large corporation has its facilities report in this manner, and then has an award for those that complete all energy conservation measures listed on the audit.

17

within the company. Too many management decisions are made with a meager knowledge of the effects on energy. •

Use proven technology. Many programs get bogged down trying to make a new technology work, and lose sight of the easy projects with good payback. Don’t buy serial number one. In spite of price breaks and promise of vendor support, it can be all consuming to make the system work.

•

Go with the winners. Not every department within a company will be enthused about the energy program. Make those who are look good through the reporting system to top management, and all will follow.

•

A final major tip—ask the machine operator what should be done to reduce energy. Then make sure they get proper recognition for ideas.

2.10 OWNERSHIP The key to a successful energy management program is within this one word—ownership. This extends to everyone within the organization. Employees that operate a machine “own” that machine. Any attempt to modify their “baby” without their participation will not succeed. They have the knowledge to make or break the attempt. Members of the energy team are not going to be interested in seeing one person—the energy manger—get all the fame and glory for their efforts. Management people that invest in energy projects want to share in the recognition for their risk taking. A corporate energy team that goes into a division for an energy audit must help put a person from the division in the energy management position, then make sure the audit belongs to the division. Below are more tips for success that have been compiled from observing successful energy management programs.

2.11 SUMMARY

•

Have a plan. A plan dealing with organization, surveys, training, and strategic planning—with events scheduled—has two advantages. It prevents disruptions by non-productive ideas, and it sets up scheduled events that keeps the program active.

2.11.2 Policy Develop some kind of acceptable policy that gives authority to the program. This will help later on with such things as reporting requirements, and need for measurement instrumentation.

•

Give away—or at least share—ideas for saving energy. The surest way to kill a project is to be possessive. If others have a vested interest they will help make it work.

2.11.3 Organization Set up the energy committee and/or coordinators.

•

Be aggressive. The energy team—after some training—will be the most energy knowledgeable group

Let’s now summarize by assuming you have just been appointed energy manager of a fairly large company. What are the steps you might consider in setting up an energy management program? Here is a suggested procedure. 2.11.1 Situation Analysis Determine what has been done before. Was there a previous attempt to establish an energy management program? What were the results of this effort? Next, plot the energy usage for all fuels for the past two—or more—years, then project the usage, and cost, for the next five years at the present rate. This will not only help you sell your program, but will identify areas of concentration for reducing energy.

2.11.4 Training With the committee involvement, develop a training plan for the first year.

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2.11.5 Audits Again with the committee involvement, develop an auditing plan for the first year.

I.

2.11.6 Reporting Develop a simple reporting system.

II.

2.11.7 Schedule From the above information develop a schedule of events for the next year, timing them so as to give periodic actions from the program, which will help keep the program active and visible.

Policy Energy Management shall be practiced in all areas of the Company’s operation. Energy Management Program Objectives It is the Company’s objective to use energy efficiently and provide energy security for the organization for both immediate and long range by: •

Utilizing energy efficiently throughout the Company’s operations.

•

Incorporating energy efficiency into existing equipment and facilities, and in the selection and purchase of new equipment.

•

Complying with government regulations—federal, state, and local.

•

Putting in place an Energy Management Program to accomplish the above objectives.

2.11.8 Implement the program

2.12 CONCLUSION Energy management has now matured to the point that it offers outstanding opportunities for those willing to invest time and effort to learn the fundamentals. It requires technical and management skills which broadens educational needs for both technical and management people desiring to enter this field. Because of the economic return of energy management, it is attractive to top management, so exposure of the energy manager at this level brings added opportunity for recognition and advancement. Managing energy will be a continuous need, so persons with this skill will have personal job security as we are caught up in the down sizing fad now permeating our society. References 1. Hersey, Paul and Kenneth H. Blanchard, Management of Organizational Behavior: Utilizing Human Resources, Harper and Row, 1970 2. Delbecq, Andre L., Andrew H. Van de Ven, and David H. Gustafson, Group Techniques for Program Planning, Green Briar Press, 1986. 3. Mashburn, William H., Managing Energy Resources in Times of Dynamic Change, Fairmont Press, 1992 4. Turner, Wayne, Energy Management Handbook, 2nd edition, Chapter 2, Fairmont Press, 1993.

III. Implementation A. Organization The Company’s Energy Management Program shall be administered through the Facilities Department. 1.

Energy Manager The Energy Manager shall report directly to the Vice President of Facilities, and shall have overall responsibility for carrying out the Energy Management Program. 2.

Energy Committee The Energy Manager may appoint and Energy Committee to be comprised of representatives from various departments. Members will serve for a specified period of time. The purpose of the Energy Committee is to advise the Energy Manager on the operation of the Energy Management Program, and to provide assistance on specific tasks when needed. 3.

Appendix A ENERGY POLICY Acme Manufacturing Company Policy and Procedures Manual Subject: Energy Management Program

Energy Coordinators Energy Coordinators shall be appointed to represent a specific department or division. The Energy Manager shall establish minimum qualification standards for Coordinators, and shall have joint approval authority for each Coordinator appointed. Coordinators shall be responsible for maintaining an ongoing awareness of energy consumption and expenditures in their assigned areas. They shall recommend and implement energy conservation projects and energy management practices.

EFFECTIVE ENERGY MANAGEMENT

19

Coordinators shall provide necessary information for reporting from their specific areas. They may be assigned on a full-time or part-time basis; as required to implement programs in their areas.

cost-effective programs that will maintain or improve the quality of the work environment, optimize service reliability, increase productivity, and enhance the safety of our workplace.

B.

Appendix C

Reporting The energy Coordinator shall keep the Energy Office advised of all efforts to increase energy efficiency in their areas. A summary of energy cost savings shall be submitted each quarter to the Energy Office. The Energy Manager shall be responsible for consolidating these reports for top management. C. Training The Energy Manager shall provide energy training at all levels of the Company. IV.

Policy Updating The Energy Manager and the Energy Advisory Committee shall review this policy annually and make recommendations for updating or changes.

Appendix B POLICY STATEMENT Acme International Corporation is committed to the efficient, cost effective, and environmentally responsible use of energy throughout its worldwide operations. Acme will promote energy efficiency by implementing

Figure 2.2

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Figure 2.4 Figure 2.3

EFFECTIVE ENERGY MANAGEMENT

Figure 2.6 Figure 2.5

21

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ENERGY MANAGEMENT HANDBOOK

Figure 2.7

CHAPTER 3

ENERGY AUDITING BARNEY L. CAPEHART AND MARK B. SPILLER University of Florida — Gainesville Regional Utilities Gainesville, FL

energy-consuming appliances in a house or an apartment. Ceiling and wall insulation is measured, ducts are inspected, appliances such as heaters, air conditioners, water heaters, refrigerators, and freezers are examined, and the lighting system is checked. Some utilities also perform audits for their industrial and commercial customers. They have professional engineers on their staff to perform the detailed audits needed by companies with complex process equipment and operations. When utilities offer free or low-cost energy audits for commercial customers, they usually only provide walk-through audits rather than detailed audits. Even so, they generally consider lighting, HVAC systems, water heating, insulation and some motors. Large commercial or industrial customers may hire an engineering consulting firm to perform a complete energy audit. Other companies may elect to hire an energy manager or set up an energy management team whose job is to conduct periodic audits and to keep up with the available energy efficiency technology. The U.S. Department of Energy (U.S. DOE) funds a program where universities around the country operate Industrial Assessment Centers which perform free energy audits for small and medium sized manufacturing companies. There are currently 30 IACs funded by the Industrial Division of the U.S. DOE. The Institutional Conservation Program (ICP) is another energy audit service funded by the U.S. Department of Energy. It is usually administered through state energy offices. This program pays for audits of schools, hospitals, and other institutions, and has some funding assistance for energy conservation improvements.

SCOTT FRAZIER Oklahoma State University

3.1 INTRODUCTION Saving money on energy bills is attractive to businesses, industries, and individuals alike. Customers whose energy bills use up a large part of their income, and especially those customers whose energy bills represent a substantial fraction of their company’s operating costs, have a strong motivation to initiate and continue an ongoing energy cost-control program. No-cost or very lowcost operational changes can often save a customer or an industry 10-20% on utility bills; capital cost programs with payback times of two years or less can often save an additional 20-30%. In many cases these energy cost control programs will also result in both reduced energy consumption and reduced emissions of environmental pollutants. The energy audit is one of the first tasks to be performed in the accomplishment of an effective energy cost control program. An energy audit consists of a detailed examination of how a facility uses energy, what the facility pays for that energy, and finally, a recommended program for changes in operating practices or energy-consuming equipment that will cost-effectively save dollars on energy bills. The energy audit is sometimes called an energy survey or an energy analysis, so that it is not hampered with the negative connotation of an audit in the sense of an IRS audit. The energy audit is a positive experience with significant benefits to the business or individual, and the term “audit” should be avoided if it clearly produces a negative image in the mind of a particular business or individual.

3.3 BASIC COMPONENTS OF AN ENERGY AUDIT An initial summary of the basic steps involved in conducting a successful energy audit is provided here, and these steps are explained more fully in the sections that follow. This audit description primarily addresses the steps in an industrial or large-scale commercial audit, and not all of the procedures described in this section are required for every type of audit. The audit process starts by collecting information about a facility’s operation and about its past record of utility bills. This data is then analyzed to get a picture of how the facility uses—and possibly wastes—energy, as well as to help the auditor learn what areas to examine

3.2 ENERGY AUDITING SERVICES Energy audits are performed by several different groups. Electric and gas utilities throughout the country offer free residential energy audits. A utility’s residential energy auditors analyze the monthly bills, inspect the construction of the dwelling unit, and inspect all of the 23

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to reduce energy costs. Specific changes—called Energy Conservation Opportunities (ECOs)—are identified and evaluated to determine their benefits and their cost-effectiveness. These ECOs are assessed in terms of their costs and benefits, and an economic comparison is made to rank the various ECOs. Finally, an Action Plan is created where certain ECOs are selected for implementation, and the actual process of saving energy and saving money begins. 3.3.1 The Auditor’s Toolbox To obtain the best information for a successful energy cost control program, the auditor must make some measurements during the audit visit. The amount of equipment needed depends on the type of energyconsuming equipment used at the facility, and on the range of potential ECOs that might be considered. For example, if waste heat recovery is being considered, then the auditor must take substantial temperature measurement data from potential heat sources. Tools commonly needed for energy audits are listed below: Tape Measures The most basic measuring device needed is the tape measure. A 25-foot tape measure l" wide and a 100foot tape measure are used to check the dimensions of walls, ceilings, windows and distances between pieces of equipment for purposes such as determining the length of a pipe for transferring waste heat from one piece of equipment to the other. Lightmeter One simple and useful instrument is the lightmeter which is used to measure illumination levels in facilities. A lightmeter that reads in footcandles allows direct analysis of lighting systems and comparison with recommended light levels specified by the Illuminating Engineering Society. A small lightmeter that is portable and can fit into a pocket is the most useful. Many areas in buildings and plants are still significantly overlighted, and measuring this excess illumination then allows the auditor to recommend a reduction in lighting levels through lamp removal programs or by replacing inefficient lamps with high efficiency lamps that may not supply the same amount of illumination as the old inefficient lamps. Thermometers Several thermometers are generally needed to measure temperatures in offices and other worker areas, and to measure the temperature of operating equipment. Knowing process temperatures allows the auditor to

ENERGY MANAGEMENT HANDBOOK

determine process equipment efficiencies, and also to identify waste heat sources for potential heat recovery programs. Inexpensive electronic thermometers with interchangeable probes are now available to measure temperatures in both these areas. Some common types include an immersion probe, a surface temperature probe, and a radiation shielded probe for measuring true air temperature. Other types of infra-red thermometers and thermographic equipment are also available. An infra-red “gun” is valuable for measuring temperatures of steam lines that are not readily reached without a ladder. Infrared Cameras Infrared cameras are still rather expensive pieces of equipment. An investment of at least $25,000 is needed to have a quality infrared camera. However, these are very versatile pieces of equipment and can be used to find overheated electrical wires, connections, neutrals, circuit breakers, transformers, motors and other pieces of electrical equipment. They can also be used to find wet insulation, missing insulation, roof leaks, and cold spots. Thus, infrared cameras are excellent tools for both safety related diagnostics and energy savings diagnostics. A good rule of thumb is that if one safety hazard is found during an infrared scan of a facility, then that has paid for the cost of the scan for the entire facility. Many insurers require infrared scans of buildings for facilities once a year. Voltmeter An inexpensive voltmeter is useful for determining operating voltages on electrical equipment, and especially useful when the nameplate has worn off of a piece of equipment or is otherwise unreadable or missing. The most versatile instrument is a combined volt-ohm-ammeter with a clamp-on feature for measuring currents in conductors that are easily accessible. This type of multimeter is convenient and relatively inexpensive. Any newly purchased voltmeter, or multimeter, should be a true RMS meter for greatest accuracy where harmonics might be involved. Clamp On Ammeter These are very useful instruments for measuring current in a wire without having to make any live electrical connections. The clamp is opened up and put around one insulated conductor, and the meter reads the current in that conductor. New clamp on ammeters can be purchased rather inexpensively that read true RMS values. This is important because of the level of harmonics in many of our facilities. An idea of the level

ENERGY AUDITING

of harmonics in a load can be estimated from using an old non-RMS ammeter, and then a true RMS ammeter to measure the current. If there is more than a five to ten percent difference between the two readings, there is a significant harmonic content to that load. Wattmeter/Power Factor Meter A portable hand-held wattmeter and power factor meter is very handy for determining the power consumption and power factor of individual motors and other inductive devices. This meter typically has a clamp-on feature which allows an easy connection to the current-carrying conductor, and has probes for voltage connections. Any newly purchased wattmeter or power factor meter, should be a true RMS meter for greatest accuracy where harmonics might be involved Combustion Analyzer Combustion analyzers are portable devices capable of estimating the combustion efficiency of furnaces, boilers, or other fossil fuel burning machines. Two types are available: digital analyzers and manual combustion analysis kits. Digital combustion analysis equipment performs the measurements and reads out in percent combustion efficiency. These instruments are fairly complex and expensive. The manual combustion analysis kits typically require multiple measurements including exhaust stack temperature, oxygen content, and carbon dioxide content. The efficiency of the combustion process can be calculated after determining these parameters. The manual process is lengthy and is frequently subject to human error. Airflow Measurement Devices Measuring air flow from heating, air conditioning or ventilating ducts, or from other sources of air flow is one of the energy auditor’s tasks. Airflow measurement devices can be used to identify problems with air flows, such as whether the combustion air flow into a gas heater is correct. Typical airflow measuring devices include a velometer, an anemometer, or an airflow hood. See section 3.4.3 for more detail on airflow measurement devices. Blower Door Attachment Building or structure tightness can be measured with a blower door attachment. This device is frequently used in residences and in office buildings to determine the air leakage rate or the number of air changes per hour in the facility. This is often helps determine whether the facility has substantial structural or duct

25

leaks that need to be found and sealed. See section 3.4.2 for additional information on blower doors. Smoke Generator A simple smoke generator can also be used in residences, offices and other buildings to find air infiltration and leakage around doors, windows, ducts and other structural features. Care must be taken in using this device, since the chemical “smoke” produced may be hazardous, and breathing protection masks may be needed. See section 3.4.1 for additional information on the smoke generation process, and use of smoke generators. Safety Equipment The use of safety equipment is a vital precaution for any energy auditor. A good pair of safety glasses is an absolute necessity for almost any audit visit. Hearing protectors may also be required on audit visits to noisy plants or areas with high horsepower motors driving fans and pumps. Electrical insulated gloves should be used if electrical measurements will be taken, and asbestos gloves should be used for working around boilers and heaters. Breathing masks may also be needed when hazardous fumes are present from processes or materials used. Steel-toe and steel-shank safety shoes may be needed on audits of plants where heavy materials, hot or sharp materials or hazardous materials are being used. (See section 3.3.3 for an additional discussion of safety procedures.) Miniature Data Loggers Miniature—or mini—data loggers have appeared in low cost models in the last five years. These are often devices that can be held in the palm of the hand, and are electronic instruments that record measurements of temperature, relative humidity, light intensity, light on/ off, and motor on/off. If they have an external sensor input jack, these little boxes are actually general purpose data loggers. With external sensors they can record measurements of current, voltage, apparent power (kVA), pressure, and CO2. These data loggers have a microcomputer control chip and a memory chip, so they can be initialized and then can record data for periods of time from days to weeks. They can record data on a 24 hour a day basis, without any attention or intervention on the part of the energy auditor. Most of these data loggers interface with a digital computer PC, and can transfer data into a spreadsheet of the user’s choice, or can use the software provided by the suppliers of the loggers. Collecting audit data with these small data loggers

26

gives a more complete and accurate picture of an energy system’s overall performance because some conditions may change over long periods of time, or when no one is present. Vibration Analysis Gear Relatively new in the energy manager’s tool box is vibration analysis equipment. The correlation between machine condition (bearings, pulley alignment, etc.) and energy consumption is related and this equipment monitors such machine health. This equipment comes in various levels of sophistication and price. At the lower end of the spectrum are vibration pens (or probes) that simply give real-time amplitude readings of vibrating equipment in in/sec or mm/sec. This type of equipment can cost under $1,000. The engineer compares the measured vibration amplitude to a list of vibration levels (ISO2372) and is able to determine if the vibration is excessive for that particular piece of equipment. The more typical type of vibration equipment will measure and log the vibration into a database (on-board and downloadable). In addition to simply measuring vibration amplitude, the machine vibration can be displayed in time or frequency domains. The graphs of vibration in the frequency domain will normally exhibit spikes at certain frequencies. These spikes can be interpreted by a trained individual to determine the relative health of the machine monitored. The more sophisticated machines are capable of trend analysis so that facility equipment can be monitored on a schedule and changes in vibration (amplitudes and frequencies) can be noted. Such trending can be used to schedule maintenance based on observations of change. This type of equipment starts at about $3,000 and goes up depending on features desired. 3.3.2 Preparing for the Audit Visit Some preliminary work must be done before the auditor makes the actual energy audit visit to a facility. Data should be collected on the facility’s use of energy through examination of utility bills, and some preliminary information should be compiled on the physical description and operation of the facility. This data should then be analyzed so that the auditor can do the most complete job of identifying Energy Conservation Opportunities during the actual site visit to the facility. Energy Use Data The energy auditor should start by collecting data on energy use, power demand and cost for at least the previous 12 months. Twenty-four months of data might be necessary to adequately understand some types of

ENERGY MANAGEMENT HANDBOOK

billing methods. Bills for gas, oil, coal, electricity, etc. should be compiled and examined to determine both the amount of energy used and the cost of that energy. This data should then be put into tabular and graphic form to see what kind of patterns or problems appear from the tables or graphs. Any anomaly in the pattern of energy use raises the possibility for some significant energy or cost savings by identifying and controlling that anomalous behavior. Sometimes an anomaly on the graph or in the table reflects an error in billing, but generally the deviation shows that some activity is going on that has not been noticed, or is not completely understood by the customer. Rate Structures To fully understand the cost of energy, the auditor must determine the rate structure under which that energy use is billed. Energy rate structures may go from the extremely simple ones—for example, $1.00 per gallon of Number 2 fuel oil, to very complex ones—for example, electricity consumption which may have a customer charge, energy charge, demand charge, power factor charge, and other miscellaneous charges that vary from month to month. Few customers or businesses really understand the various rate structures that control the cost of the energy they consume. The auditor can help here because the customer must know the basis for the costs in order to control them successfully. •

Electrical Demand Charges: The demand charge is based on a reading of the maximum power in kW that a customer demands in one month. Power is the rate at which energy is used, and it varies quite rapidly for many facilities. Electric utilities average the power reading over intervals from fifteen minutes to one hour, so that very short fluctuations do not adversely affect customers. Thus, a customer might be billed for demand for a month based on a maximum value of a fifteen minute integrated average of their power use.

•

Ratchet Clauses: Some utilities have a ratchet clause in their rate structure which stipulates that the minimum power demand charge will be the highest demand recorded in the last billing period or some percentage (i.e., typically 70%) of the highest power demand recorded in the last year. The ratchet clause can increase utility charges for facilities during periods of low activity or where power demand is tied to extreme weather.

•

Discounts/Penalties: Utilities generally provide

ENERGY AUDITING

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discounts on their energy and power rates for customers who accept power at high voltage and provide transformers on site. They also commonly assess penalties when a customer has a power factor less than 0.9. Inductive loads (e.g., lightly loaded electric motors, old fluorescent lighting ballasts, etc.) reduce the power factor. Improvement can be made by adding capacitance to correct for lagging power factor, and variable capacitor banks are most useful for improving the power factor at the service drop. Capacitance added near the loads can effectively increase the electrical system capacity. Turning off idling or lightly loaded motors can also help. •

Wastewater charges: The energy auditor also frequently looks at water and wastewater use and costs as part of the audit visit. These costs are often related to the energy costs at a facility. Wastewater charges are usually based on some proportion of the metered water use since the solids are difficult to meter. This can needlessly result in substantial increases in the utility bill for processes which do not contribute to the wastewater stream (e.g., makeup water for cooling towers and other evapo-

rative devices, irrigation, etc.). A water meter can be installed at the service main to supply the loads not returning water to the sewer system. This can reduce the charges by up to two-thirds. Energy bills should be broken down into the components that can be controlled by the facility. These cost components can be listed individually in tables and then plotted. For example, electricity bills should be broken down into power demand costs per kW per month, and energy costs per kWh. The following example illustrates the parts of a rate structure for an industry in Florida. Example: A company that fabricates metal products gets electricity from its electric utility at the following general service demand rate structure. Rate structure: Customer cost Energy cost Demand cost Taxes Fuel adjustment

= = = = =

$21.00 per month $0.051 per kWh $6.50 per kW per month Total of 8% A variable amount per kWh each month

The energy use and costs for that company for a year are summarized below:

Summary of Energy Usage and Costs

kWh Used (kWh)

kWh Cost ($)

Demand (kW)

Demand Cost ($)

Total Cost ($)

Mar

44960

1581.35

213

1495.26

3076.61

Apr

47920

1859.68

213

1495.26

3354.94

May

56000

2318.11

231

1621.62

3939.73

Jun

56320

2423.28

222

1558.44

3981.72

Jul

45120

1908.16

222

1558.44

3466.60

Aug

54240

2410.49

231

1621.62

4032.11

Sept

50720

2260.88

222

1558.44

3819.32

Oct

52080

2312.19

231

1621.62

3933.81

Nov

44480

1954.01

213

1495.26

3449.27

Dec

38640

1715.60

213

1495.26

3210.86

Jan

36000

1591.01

204

1432.08

3023.09

Feb

42880

1908.37

204

1432.08

3340.45

569,360

24,243.13

2,619

18,385.38

42,628.51

47,447

2,020.26

218

1,532.12

3,552.38

Month

Totals Monthly Averages

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ENERGY MANAGEMENT HANDBOOK

The auditor must be sure to account for all the taxes, the fuel adjustment costs, the fixed charges, and any other costs so that the true cost of the controllable energy cost components can be determined. In the electric rate structure described above, the quoted costs for a kW of demand and a kWh of energy are not complete until all these additional costs are added. Although the rate structure says that there is a basic charge of $6.50 per kW per month, the actual cost including all taxes is $7.02 per kW per month. The average cost per kWh is most easily obtained by taking the data for the twelve month period and calculating the cost over this period of time. Using the numbers from the table, one can see that this company has an average energy cost of $0.075 per kWh. These data are used initially to analyze potential ECOs and will ultimately influence which ECOs are recommended. For example, an ECO that reduces peak demand during a month would save $7.02 per kW per month. Therefore, the auditor should consider ECOs that would involve using certain equipment during the night shift when the peak load is significantly less than the first shift peak load. ECOs that save both energy and demand on the first shift would save costs at a rate of $0.075 per kWh. Finally, ECOs that save electrical energy during the off-peak shift should be examined too, but they may not be as advantageous; they would only save at the rate of $0.043 per kWh because they are already used off-peak and there would not be any additional demand cost savings. Physical and Operational Data for the Facility The auditor must gather information on factors likely to affect energy use in the facility. Geographic location, weather data, facility layout and construction, operating hours, and equipment can all influence energy use. •

Geographic Location/Weather Data: The geographic location of the facility should be noted, together with the weather data for that location. Contact the local weather station, the local utility or the state energy office to obtain the average degree days for heating and cooling for that location for the past twelve months. This degree-day data will be very useful in analyzing the need for energy for heating or cooling the facility. Bin weather data would also be useful if a thermal envelope simulation of the facility were going to be performed as part of the audit.

•

Facility Layout: Next the facility layout or plan should be obtained, and reviewed to determine

the facility size, floor plan, and construction features such as wall and roof material and insulation levels, as well as door and window sizes and construction. A set of building plans could supply this information in sufficient detail. It is important to make sure the plans reflect the “as-built” features of the facility, since many original building plans do not get updated after building alterations. •

Operating Hours: Operating hours for the facility should also be obtained. Is there only a single shift? Are there two shifts? Three? Knowing the operating hours in advance allows some determination as to whether some loads could be shifted to off-peak times. Adding a second shift can often be cost effective from an energy cost view, since the demand charge can then be spread over a greater amount of kWh.

•

Equipment List: Finally, the auditor should get an equipment list for the facility and review it before conducting the audit. All large pieces of energy-consuming equipment such as heaters, air conditioners, water heaters, and specific process-related equipment should be identified. This list, together with data on operational uses of the equipment allows a good understanding of the major energy-consuming tasks or equipment at the facility. As a general rule, the largest energy and cost activities should be examined first to see what savings could be achieved. The greatest effort should be devoted to the ECOs which show the greatest savings, and the least effort to those with the smallest savings potential.

The equipment found at an audit location will depend greatly on the type of facility involved. Residential audits for single-family dwellings generally involve smaller-sized lighting, heating, air conditioning and refrigeration systems. Commercial operations such as grocery stores, office buildings and shopping centers usually have equipment similar to residences, but much larger in size and in energy use. However, large residential structures such as apartment buildings have heating, air conditioning and lighting that is very similar to many commercial facilities. Business operations is the area where commercial audits begin to involve equipment substantially different from that found in residences. Industrial auditors encounter the most complex equipment. Commercial-scale lighting, heating, air conditioning and refrigeration, as well as office business equipment, is generally used at most industrial facilities. The major difference is in the highly specialized equip-

ENERGY AUDITING

ment used for the industrial production processes. This can include equipment for chemical mixing and blending, metal plating and treatment, welding, plastic injection molding, paper making and printing, metal refining, electronic assembly, and making glass, for example. 3.3.3 Safety Considerations Safety is a critical part of any energy audit. The audit person or team should be thoroughly briefed on safety equipment and procedures, and should never place themselves in a position where they could injure themselves or other people at the facility. Adequate safety equipment should be worn at all appropriate times. Auditors should be extremely careful making any measurements on electrical systems, or on high temperature devices such as boilers, heaters, cookers, etc. Electrical gloves or asbestos gloves should be worn as appropriate. The auditor should be careful when examining any operating piece of equipment, especially those with open drive shafts, belts or gears, or any form of rotating machinery. The equipment operator or supervisor should be notified that the auditor is going to look at that piece of equipment and might need to get information from some part of the device. If necessary, the auditor may need to come back when the machine or device is idle in order to safely get the data. The auditor should never approach a piece of equipment and inspect it without the operator or supervisor being notified first. Safety Checklist 1. Electrical: a. Avoid working on live circuits, if possible. b. Securely lock off circuits and switches before working on a piece of equipment. c. Always keep one hand in your pocket while making measurements on live circuits to help prevent cardiac arrest. 2. Respiratory: a. When necessary, wear a full face respirator mask with adequate filtration particle size. b. Use activated carbon cartridges in the mask when working around low concentrations of noxious gases. Change the cartridges on a regular basis. c. Use a self-contained breathing apparatus for work in toxic environments. 3. Hearing: a. Use foam insert plugs while working around loud machinery to reduce sound levels up to 30 decibels.

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3.3.4 Conducting the Audit Visit Once the information on energy bills, facility equipment and facility operation has been obtained, the audit equipment can be gathered up, and the actual visit to the facility can be made. Introductory Meeting The audit person—or team—should meet with the facility manager and the maintenance supervisor and briefly discuss the purpose of the audit and indicate the kind of information that is to be obtained during the visit to the facility. If possible, a facility employee who is in a position to authorize expenditures or make operating policy decisions should also be at this initial meeting. Audit Interviews Getting the correct information on facility equipment and operation is important if the audit is going to be most successful in identifying ways to save money on energy bills. The company philosophy towards investments, the impetus behind requesting the audit, and the expectations from the audit can be determined by interviewing the general manager, chief operating officer, or other executives. The facility manager or plant manager is one person that should have access to much of the operational data on the facility, and a file of data on facility equipment. The finance officer can provide any necessary financial records (e.g., utility bills for electric, gas, oil, other fuels, water and wastewater, expenditures for maintenance and repair, etc.). The auditor must also interview the floor supervisors and equipment operators to understand the building and process problems. Line or area supervisors usually have the best information on times their equipment is used. The maintenance supervisor is often the primary person to talk to about types of lighting and lamps, sizes of motors, sizes of air conditioners and space heaters, and electrical loads of specialized process equipment. Finally, the maintenance staff must be interviewed to find the equipment and performance problems. The auditor should write down these people’s names, job functions and telephone numbers, since it is frequently necessary to get additional information after the initial audit visit. Walk-through Tour A walk-through tour of the facility or plant tour should be conducted by the facility/plant manager, and should be arranged so the auditor or audit team can see the major operational and equipment features of the facility. The main purpose of the walk-through tour is to obtain general information. More specific information

30

ENERGY MANAGEMENT HANDBOOK

should be obtained from the maintenance and operational people after the tour. Getting Detailed Data Following the facility or plant tour, the auditor or audit team should acquire the detailed data on facility equipment and operation that will lead to identifying the significant Energy Conservation Opportunities (ECOs) that may be appropriate for this facility. This includes data on lighting, HVAC equipment, motors, water heating, and specialized equipment such as refrigerators, ovens, mixers, boilers, heaters, etc. This data is most easily recorded on individualized data sheets that have been prepared in advance.

currents, and power factors may be appropriate for some motors. Notes should be taken on the use of motors, particularly recording those that are infrequently used and might be candidates for peak load control or shifting use to off-peak times. All motors over 1 hp and with times of use of 2000 hours per year or greater, are likely candidates for replacement by high efficiency motors—at least when they fail and must be replaced. •

Water Heaters: All water heaters should be examined, and data recorded on their type, size, age, model number, electrical characteristics or fuel use. What the hot water is used for, how much is used, and what time it is used should all be noted. Temperature of the hot water should be measured.

•

Waste Heat Sources: Most facilities have many sources of waste heat, providing possible opportunities for waste heat recovery to be used as the substantial or total source of needed hot water. Waste heat sources are air conditioners, air compressors, heaters and boilers, process cooling systems, ovens, furnaces, cookers, and many others. Temperature measurements for these waste heat sources are necessary to analyze them for replacing the operation of the existing water heaters.

•

Peak Equipment Loads: The auditor should particularly look for any piece of electrically powered equipment that is used infrequently or whose use could be controlled and shifted to off-peak times. Examples of infrequently used equipment include trash compactors, fire sprinkler system pumps (testing), certain types of welders, drying ovens, or any type of back-up machine. Some production machines might be able to be scheduled for offpeak. Water heating could be done off-peak if a storage system is available, and off-peak thermal storage can be accomplished for on-peak heating or cooling of buildings. Electrical measurements of voltages, currents, and wattages may be helpful. Any information which leads to a piece of equipment being used off-peak is valuable, and could result in substantial savings on electric bills. The auditor should be especially alert for those infrequent on-peak uses that might help explain anomalies on the energy demand bills.

•

Other Energy-Consuming Equipment: Finally, an inventory of all other equipment that consumes a substantial amount of energy should be taken. Commercial facilities may have extensive computer

What to Look for •

Lighting: Making a detailed inventory of all lighting is important. Data should be recorded on numbers of each type of light fixtures and lamps, wattages of lamps, and hours of operation of groups of lights. A lighting inventory data sheet should be used to record this data. Using a lightmeter, the auditor should also record light intensity readings for each area. Taking notes on types of tasks performed in each area will help the auditor select alternative lighting technologies that might be more energy efficient. Other items to note are the areas that may be infrequently used and may be candidates for occupancy sensor controls of lighting, or areas where daylighting may be feasible.

•

HVAC Equipment: All heating, air conditioning and ventilating equipment should be inventoried. Prepared data sheets can be used to record type, size, model numbers, age, electrical specifications or fuel use specifications, and estimated hours of operation. The equipment should be inspected to determine the condition of the evaporator and condenser coils, the air filters, and the insulation on the refrigerant lines. Air velocity measurement may also be made and recorded to assess operating efficiencies or to discover conditioned air leaks. This data will allow later analysis to examine alternative equipment and operations that would reduce energy costs for heating, ventilating, and air conditioning.

•

Electric Motors: An inventory of all electric motors over 1 horsepower should also be taken. Prepared data sheets can be used to record motor size, use, age, model number, estimated hours of operation, other electrical characteristics, and possibly the operating power factor. Measurement of voltages,

ENERGY AUDITING

and copying equipment, refrigeration and cooling equipment, cooking devices, printing equipment, water heaters, etc. Industrial facilities will have many highly specialized process and production operations and machines. Data on types, sizes, capacities, fuel use, electrical characteristics, age, and operating hours should be recorded for all of this equipment. Preliminary Identification of ECOs As the audit is being conducted, the auditor should take notes on potential ECOs that are evident. Identifying ECOs requires a good knowledge of the available energy efficiency technologies that can accomplish the same job with less energy and less cost. For example, overlighting indicates a potential lamp removal or lamp change ECO, and inefficient lamps indicates a potential lamp technology change. Motors with high use times are potential ECOs for high efficiency replacements. Notes on waste heat sources should indicate what other heating sources they might replace, and how far away they are from the end use point. Identifying any potential ECOs during the walk-through will make it easier later on to analyze the data and to determine the final ECO recommendations. 3.3.5 Post-Audit Analysis Following the audit visit to the facility, the data collected should be examined, organized and reviewed for completeness. Any missing data items should be obtained from the facility personnel or from a re-visit to the facility. The preliminary ECOs identified during the audit visit should now be reviewed, and the actual analysis of the equipment or operational change should be conducted. This involves determining the costs and the benefits of the potential ECO, and making a judgment on the cost-effectiveness of that potential ECO. Cost-effectiveness involves a judgment decision that is viewed differently by different people and different companies. Often, Simple Payback Period (SPP) is used to measure cost-effectiveness, and most facilities want a SPP of two years or less. The SPP for an ECO is found by taking the initial cost and dividing it by the annual savings. This results in finding a period of time for the savings to repay the initial investment, without using the time value of money. One other common measure of cost-effectiveness is the discounted benefit-cost ratio. In this method, the annual savings are discounted when they occur in future years, and are added together to find the present value of the annual savings over a specified period of time.

31

The benefit-cost ratio is then calculated by dividing the present value of the savings by the initial cost. A ratio greater than one means that the investment will more than repay itself, even when the discounted future savings are taken into account. Several ECO examples are given here in order to illustrate the relationship between the audit information obtained and the technology and operational changes recommended to save on energy bills. Lighting ECO First, an ECO technology is selected—such as replacing an existing 400 watt mercury vapor lamp with a 325 watt multi-vapor lamp when it burns out. The cost of the replacement lamp must be determined. Product catalogs can be used to get typical prices for the new lamp—about $10 more than the 400 watt mercury vapor lamp. The new lamp is a direct screw-in replacement, and no change is needed in the fixture or ballast. Labor cost is assumed to be the same to install either lamp. The benefits—or cost savings—must be calculated next. The power savings is 400-325 = 75 watts. If the lamp operates for 4000 hours per year and electric energy costs $0.075/kWh, then the savings is (.075 kW)(4000 hr/year)($0.075/kWh) = $22.50/year. This gives a SPP = $10/$22.50/yr =.4 years, or about 5 months. This would be considered an extremely costeffective ECO. (For illustration purposes, ballast wattage has been ignored.) Motor ECO A ventilating fan at a fiberglass boat manufacturing company has a standard efficiency 5 hp motor that runs at full load two shifts a day, or 4160 hours per year. When this motor wears out, the company will have an ECO of using a high efficiency motor. A high efficiency 5 hp motor costs around $80 more to purchase than the standard efficiency motor. The standard motor is 83% efficient and the high efficiency model is 88.5% efficient. The cost savings is found by calculating (5 hp)(4160 hr/yr)(.746 kW/hp)[(1/.83) –( 1/.885)]($.075/kWh) = (1162 kWh)*($0.075) = $87.15/ year. The SPP = $80/$87.15/yr =.9 years, or about 11 months. This is also a very attractive ECO when evaluated by this economic measure. The discounted benefit-cost ratio can be found once a motor life is determined, and a discount rate is selected. Companies generally have a corporate standard for the discount rate used in determining their measures used to make investment decisions. For a 10 year assumed life, and a 10% discount rate, the present worth factor is found as 6.144 (see Chapter 4, Ap-

32

pendix 4A). The benefit-cost ratio is found as B/C = ($87.15)(6.144)/$80 = 6.7. This is an extremely attractive benefit-cost ratio. Peak Load Control ECO A metals fabrication plant has a large shot-blast cleaner that is used to remove the rust from heavy steel blocks before they are machined and welded. The cleaner shoots out a stream of small metal balls—like shotgun pellets—to clean the metal blocks. A 150 hp motor provides the primary motive force for this cleaner. If turned on during the first shift, this machine requires a total electrical load of about 180 kW which adds directly to the peak load billed by the electric utility. At $7.02/kW/month, this costs (180 kW)*($7.02/ kW/month) = $1263.60/month. Discussions with line operating people resulted in the information that the need for the metal blocks was known well in advance, and that the cleaning could easily be done on the evening shift before the blocks were needed. Based on this information, the recommended ECO is to restrict the shot-blast cleaner use to the evening shift, saving the company $15,163.20 per year. Since there is no cost to implement this ECO, the SPP = O; that is, the payback is immediate. 3.3.6 The Energy Audit Report The next step in the energy audit process is to prepare a report which details the final results and recommendations. The length and detail of this report will vary depending on the type of facility audited. A residential audit may result in a computer printout from the utility. An industrial audit is more likely to have a detailed explanation of the ECOs and benefit-cost analyses. The following discussion covers the more detailed audit reports. The report should begin with an executive summary that provides the owners/managers of the audited facility with a brief synopsis of the total savings available and the highlights of each ECO. The report should then describe the facility that has been audited, and provide information on the operation of the facility that relates to its energy costs. The energy bills should be presented, with tables and plots showing the costs and consumption. Following the energy cost analysis, the recommended ECOs should be presented, along with the calculations for the costs and benefits, and the costeffectiveness criterion. Regardless of the audience for the audit report, it should be written in a clear, concise and easy-to understand format and style. The executive summary should be tailored to non-technical personnel, and technical

ENERGY MANAGEMENT HANDBOOK

jargon should be minimized. A client who understands the report is more likely to implement the recommended ECOs. An outline for a complete energy audit report is shown below. Energy Audit Report Format Executive Summary A brief summary of the recommendations and cost savings Table of Contents Introduction Purpose of the energy audit Need for a continuing energy cost control program Facility Description Product or service, and materials flow Size, construction, facility layout, and hours of operation Equipment list, with specifications Energy Bill Analysis Utility rate structures Tables and graphs of energy consumptions and costs Discussion of energy costs and energy bills Energy Conservation Opportunities Listing of potential ECOs Cost and savings analysis Economic evaluation Action Plan Recommended ECOs and an implementation schedule Designation of an energy monitor and ongoing program Conclusion Additional comments not otherwise covered 3.3.7 The Energy Action Plan The last step in the energy audit process is to recommend an action plan for the facility. Some companies will have an energy audit conducted by their electric utility or by an independent consulting firm, and will then make changes to reduce their energy bills. They may not spend any further effort in the energy cost control area until several years in the future when another energy audit is conducted. In contrast to this is the company which establishes a permanent energy cost control program, and assigns one person—or a team of people—to continually monitor and improve the energy efficiency and energy productivity of the company. Similar to a Total Quality Management program where a company seeks to continually improve

ENERGY AUDITING

the quality of its products, services and operation, an energy cost control program seeks continual improvement in the amount of product produced for a given expenditure for energy. The energy action plan lists the ECOs which should be implemented first, and suggests an overall implementation schedule. Often, one or more of the recommended ECOs provides an immediate or very short payback period, so savings from that ECO—or those ECOs can be used to generate capital to pay for implementing the other ECOs. In addition, the action plan also suggests that a company designate one person as the energy monitor for the facility. This person can look at the monthly energy bills and see whether any unusual costs are occurring, and can verify that the energy savings from ECOs is really being seen. Finally, this person can continue to look for other ways the company can save on energy costs, and can be seen as evidence that the company is interested in a future program of energy cost control.

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3.4 SPECIALIZED AUDIT TOOLS

This bottle should yield over a year of service with regular use. The neck will clog with debris but can be cleaned with a paper clip. Some smoke generators are designed for short time use. These bottles are inexpensive and useful for a day of smoke generation, but will quickly degrade. Smoke bombs are incendiary devices designed to emit a large volume of smoke over a short period of time. The smoke is available in various colors to provide good visibility. These are useful in determining airflow capabilities of exhaust air systems and large-scale ventilation systems. A crude smoke bomb can be constructed by placing a stick of elemental phosphorus in a metal pan and igniting it. A large volume of white smoke will be released. This is an inexpensive way of testing laboratory exhaust hoods since many labs have phosphorus in stock. More accurate results can be obtained by measuring the chemical composition of the airstream after injecting a known quantity of tracer gas such as sulphur hexafluoride into an area. The efficiency of an exhaust system can be determined by measuring the rate of tracer gas removal. Building infiltration/exfiltration rates can also be estimated with tracer gas.

3.4.1 Smoke Sources Smoke is useful in determining airflow characteristics in buildings, air distribution systems, exhaust hoods and systems, cooling towers, and air intakes. There are several ways to produce smoke. Ideally, the smoke should be neutrally buoyant with the air mass around it so that no motion will be detected unless a force is applied. Cigarette and incense stick smoke, although inexpensive, do not meet this requirement. Smoke generators using titanium tetrachloride (TiCl4) provide an inexpensive and convenient way to produce and apply smoke. The smoke is a combination of hydrochloric acid (HCl) fumes and titanium oxides produced by the reaction of TiCl4 and atmospheric water vapor. This smoke is both corrosive and toxic so the use of a respirator mask utilizing activated carbon is strongly recommended. Commercial units typically use either glass or plastic cases. Glass has excellent longevity but is subject to breakage since smoke generators are often used in difficult-to-reach areas. Most types of plastic containers will quickly degrade from the action of hydrochloric acid. Small Teflon® squeeze bottles (i.e., 30 ml) with attached caps designed for laboratory reagent use resist degradation and are easy to use. The bottle should be stuffed with 2-3 real cotton balls then filled with about 0.15 fluid ounces of liquid TiCl4. Synthetic cotton balls typically disintegrate if used with titanium tetrachloride.

3.4.2 Blower Door The blower door is a device containing a fan, controller, several pressure gauges, and a frame which fits in the doorway of a building. It is used to study the pressurization and leakage rates of a building and its air distribution system under varying pressure conditions. The units currently available are designed for use in residences although they can be used in small commercial buildings as well. The large quantities of ventilation air limit blower door use in large commercial and industrial buildings. An air leakage/pressure curve can be developed for the building by measuring the fan flow rate necessary to achieve a pressure differential between the building interior and the ambient atmospheric pressure over a range of values. The natural air infiltration rate of the building under the prevailing pressure conditions can be estimated from the leakage/pressure curve and local air pressure data. Measurements made before and after sealing identified leaks can indicate the effectiveness of the work. The blower door can help to locate the source of air leaks in the building by depressurizing to 30 Pascals and searching potential leakage areas with a smoke source. The air distribution system typically leaks on both the supply and return air sides. If the duct system is located outside the conditioned space (e.g., attic, under floor, etc.), supply leaks will depressurize the building

34

and increase the air infiltration rate; return air leaks will pressurize the building, causing air to exfiltrate. A combination of supply and return air leaks is difficult to detect without sealing off the duct system at the registers and measuring the leakage rate of the building compared to that of the unsealed duct system. The difference between the two conditions is a measure of the leakage attributable to the air distribution system. 3.4.3 Airflow Measurement Devices Two types of anemometers are available for measuring airflow: vane and hot-wire. The volume of air moving through an orifice can be determined by estimating the free area of the opening (e.g., supply air register, exhaust hood face, etc.) and multiplying by the air speed. This result is approximate due to the difficulty in determining the average air speed and the free vent area. Regular calibrations are necessary to assure the accuracy of the instrument. The anemometer can also be used to optimize the face velocity of exhaust hoods by adjusting the door opening until the anemometer indicates the desired airspeed. Airflow hoods also measure airflow. They contain an airspeed integrating manifold which averages the velocity across the opening and reads out the airflow volume. The hoods are typically made of nylon fabric supported by an aluminum frame. The instrument is lightweight and easy to hold up against an air vent. The lip of the hood must fit snugly around the opening to assure that all the air volume is measured. Both supply and exhaust airflow can be measured. The result must be adjusted if test conditions fall outside the design range.

3.5 INDUSTRIAL AUDITS 3.5.1 Introduction Industrial audits are some of the most complex and most interesting audits because of the tremendous variety of equipment found in these facilities. Much of the industrial equipment can be found during commercial audits too. Large chillers, boilers, ventilating fans, water heaters, coolers and freezers, and extensive lighting systems are often the same in most industrial operations as those found in large office buildings or shopping centers. Small cogeneration systems are often found in both commercial and industrial facilities. The highly specialized equipment that is used in industrial processes is what differentiates these facilities from large commercial operations. The challenge for the auditor and energy management specialist is to learn how this complex—and often unique—industrial equip-

ENERGY MANAGEMENT HANDBOOK

ment operates, and to come up with improvements to the processes and the equipment that can save energy and money. The sheer scope of the problem is so great that industrial firms often hire specialized consulting engineers to examine their processes and recommend operational and equipment changes that result in greater energy productivity. 3.5.2 Audit Services A few electric and gas utilities are large enough, and well-enough staffed, that they can offer industrial audits to their customers. These utilities have a trained staff of engineers and process specialists with extensive experience who can recommend operational changes or new equipment to reduce the energy costs in a particular production environment. Many gas and electric utilities, even if they do not offer audits, do offer financial incentives for facilities to install high efficiency lighting, motors, chillers, and other equipment. These incentives can make many ECOs very attractive. Small and medium-sized industries that fall into the Manufacturing Sector—SIC 2000 to 3999, and are in the service area of one of the Industrial Assessment Centers funded by the U.S. Department of Energy, can receive free energy audits throughout this program. There are presently 30 IACs operating primarily in the eastern and mid-western areas of the U.S. These IACs are administered by the U.S. Department of Energy. A search vehicle using "Industrial Assessment Centers" will yield updated locations. 3.5.3 Industrial Energy Rate Structures Except for the smallest industries, facilities will be billed for energy services through a large commercial or industrial rate category. It is important to get this rate structure information for all sources of energy—electricity, gas, oil, coal, steam, etc. Gas, oil and coal are usually billed on a straight cost per unit basis—e.g. $0.90 per gallon of #2 fuel oil. Electricity and steam most often have complex rate structures with components for a fixed customer charge, a demand charge, and an energy charge. Gas, steam, and electric energy are often available with a time of day rate, or an interruptible rate that provides much cheaper energy service with the understanding that the customer may have his supply interrupted (stopped) for periods of several hours at a time. Advance notice of the interruption is almost always given, and the number of times a customer can be interrupted in a given period of time is limited. 3.5.4 Process and Technology Data Sources For the industrial audit, it is critical to get in ad-

ENERGY AUDITING

vance as much information as possible on the specialized process equipment so that study and research can be performed to understand the particular processes being used, and what improvements in operation or technology are available. Data sources are extremely valuable here; auditors should maintain a library of information on processes and technology and should know where to find additional information from research organizations, government facilities, equipment suppliers and other organizations. EPRI/GRI The Electric Power Research Institute (EPRI) and the Gas Research Institute (GRI) are both excellent sources of information on the latest technologies of using electric energy or gas. EPRI has a large number of on-going projects to show the cost-effectiveness of electro-technologies using new processes for heating, drying, cooling, etc. GRI also has a large number of projects underway to help promote the use of new cost-effective gas technologies for heating, drying, cooling, etc. Both of these organizations provide extensive documentation of their processes and technologies; they also have computer data bases to aid customer inquiries. U.S. DOE Industrial Division The U.S. Department of Energy has an Industrial Division that provides a rich source of information on new technologies and new processes. This division funds research into new processes and technologies, and also funds many demonstration projects to help insure that promising improvements get implemented in appropriate industries. The Industrial Division of USDOE also maintains a wide network of contacts with government-related research laboratories such as Oak Ridge National Laboratory, Brookhaven National Laboratory, Lawrence Berkeley National Laboratory, Sandia National Laboratory, and Battelle National Laboratory. These laboratories have many of their own research, development and demonstration programs for improved industrial and commercial technologies. State Energy Offices State energy offices are also good sources of information, as well as good contacts to see what kind of incentive programs might be available in the state. Many states offer programs of free boiler tune-ups, free air conditioning system checks, seminars on energy efficiency for various facilities, and other services. Most state energy offices have well-stocked energy libraries, and are also tied into other state energy research organizations, and to national laboratories and the USDOE.

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Equipment Suppliers Equipment suppliers provide additional sources for data on energy efficiency improvements to processes. Marketing new, cost-effective processes and technologies provides sales for the companies as well as helping industries to be more productive and more economically competitive. The energy auditor should compare the information from all of the sources described above. 3.5.5 Conducting the Audit Safety Considerations Safety is the primary consideration in any industrial audit. The possibility of injury from hot objects, hazardous materials, slippery surfaces, drive belts, and electric shocks is far greater than when conducting residential and commercial audits. Safety glasses, safety shoes, durable clothing and possibly a safety hat and breathing mask might be needed during some audits. Gloves should be worn while making any electrical measurements, and also while making any measurements around boilers, heaters, furnaces, steam lines, or other very hot pieces of equipment. In all cases, adequate attention to personal safety is a significant feature of any industrial audit. Lighting Lighting is not as great a percent of total industrial use as it is in the commercial sector on the average, but lighting is still a big energy use and cost area for many industrial facilities. A complete inventory of all lighting should be taken during the audit visit. Hours of operation of lights are also necessary, since lights are commonly left on when they are not needed. Timers, Energy Management Systems, and occupancy sensors are all valuable approaches to insuring that lights that are not needed are not turned on. It is also important to look at the facility’s outside lighting for parking and for storage areas. During the lighting inventory, types of tasks being performed should also be noted, since light replacement with more efficient lamps often involves changing the color of the resultant light. For example, high pressure sodium lamps are much more efficient than mercury vapor lamps or even metal halide lamps, but they produce a yellowish light that makes fine color distinction difficult. However, many assembly tasks can still be performed adequately under high pressure sodium lighting. These typically include metal fabrication, wood product fabrication, plastic extrusion, and many others. Electric Motors A common characteristic of many industries is their extensive use of electric motors. A complete inven-

36

ENERGY MANAGEMENT HANDBOOK

tory of all motors over 1 hp should be taken, as well as recording data on how long each motor operates during a day. For motors with substantial usage times, replacement with high-efficiency models is almost always cost effective. In addition, consideration should be given to replacement of standard drive belts with synchronous belts which transmit the motor energy more efficiently. For motors which are used infrequently, it may be possible to shift the use to off-peak times, and to achieve a kW demand reduction which would reduce energy cost.

equipment should all be examined and operational data taken, as well as noting hours and periods of use. All heat sources should be considered carefully as to whether they could be replaced with sources using waste heat, or whether a particular heat source could serve as a provider of waste heat to another application. Operations where both heating and cooling occur periodically—such as a plastic extrusion machine—are good candidates for reclaiming waste heat, or in sharing heat from a machine needing cooling with another machine needing heat.

HVAC Systems An inventory of all space heaters and air conditioners should be taken. Btu per hour ratings and efficiencies of all units should be recorded, as well as usage patterns. Although many industries do not heat or air condition the production floor area, they almost always have office areas, cafeterias, and other areas that are normally heated and air conditioned. For these conditioned areas, the construction of the facility should be noted—how much insulation, what are the walls and ceilings made of, how high are the ceilings. Adding additional insulation might be a cost effective ECO. Production floors that are not air conditioned often have large numbers of ventilating fans that operate anywhere from one shift per day to 24 hours a day. Plants with high heat loads and plants in the mild climate areas often leave these ventilating fans running all year long. These are good candidates for high efficiency motor replacements. Timers or an Energy Management System might be used to turn off these ventilating fans when the plant is shut down.

Air Compressors Air compressors should be examined for size, operating pressures, and type (reciprocating or screw), and whether they use outside cool air for intake. Large air compressors are typically operated at night when much smaller units are sufficient. Also, screw-type air compressors use a large fraction of their rated power when they are idling, so control valves should be installed to prevent this loss. Efficiency is improved with intake air that is cool, so outside air should be used in most cases—except in extremely cold temperature areas. The auditor should determine whether there are significant air leaks in air hoses, fittings, and in machines. Air leaks are a major source of energy loss in many facilities, and should be corrected by maintenance action. Finally, air compressors are a good source of waste heat. Nearly 90% of the energy used by an air compressor shows up as waste heat, so this is a large source of low temperature waste heat for heating input air to a heater or boiler, or for heating hot water for process use.

Boilers All boilers should be checked for efficient operation using a stack gas combustion analyzer. Boiler specifications on Btu per hour ratings, pressures and temperatures should be recorded. The boiler should be varied between low-fire, normal-fire, and high-fire, with combustion gas and temperature readings taken at each level. Boiler tune-up is one of the most common, and most energy-saving operations available to many facilities. The auditor should check to see whether any waste heat from the boiler is being recovered for use in a heat recuperator or for some other use such as water heating. If not, this should be noted as a potential ECO. Specialized Equipment Most of the remaining equipment encountered during the industrial audit will be the highly specialized process production equipment and machines. This

3.6 COMMERCIAL AUDITS 3.6.1 Introduction Commercial audits span the range from very simple audits for small offices to very complex audits for multi-story office buildings or large shopping centers. Complex commercial audits are performed in substantially the same manner as industrial audits. The following discussion highlights those areas where commercial audits are likely to differ from industrial audits. Commercial audits generally involve substantial consideration of the structural envelope features of the facility, as well as significant amounts of large or specialized equipment at the facility. Office buildings, shopping centers and malls all have complex building envelopes that should be examined and evaluated. Building materials, insulation levels, door and window construction,

ENERGY AUDITING

skylights, and many other envelope features must be considered in order to identify candidate ECOs. Commercial facilities also have large capacity equipment, such as chillers, space heaters, water heaters, refrigerators, heaters, cookers, and office equipment such as computers and copy machines. Small cogeneration systems are also commonly found in commercial facilities and institutions such as schools and hospitals. Much of the equipment in commercial facilities is the same type and size as that found in manufacturing or industrial facilities. Potential ECOs would look at more efficient equipment, use of waste heat, or operational changes to use less expensive energy. 3.6.2 Commercial Audit Services Electric and gas utilities, as well as many engineering consulting firms, perform audits for commercial facilities. Some utilities offer free walk-through audits for commercial customers, and also offer financial incentives for customers who change to more energy efficient equipment. Schools, hospitals and some other government institutions can qualify for free audits under the ICP program described in the first part of this chapter. Whoever conducts the commercial audit must initiate the ICP process by collecting information on the rate energy rate structures, the equipment in use at the facility, and the operational procedures used there. 3.6.3 Commercial Energy Rate Structures Small commercial customers are usually billed for energy on a per energy unit basis, while large commercial customers are billed under complex rate structures containing components related to energy, rate of energy use (power), time of day or season of year, power factor, and numerous other elements. One of the first steps in a commercial audit is to obtain the rate structures for all sources of energy, and to analyze at least one to two year’s worth of energy bills. This information should be put into a table and also plotted. 3.6.4 Conducting the Audit A significant difference in industrial and commercial audits arises in the area of lighting. Lighting in commercial facilities is one of the largest energy costs—sometimes accounting for half or more of the entire electric bill. Lighting levels and lighting quality are extremely important to many commercial operations. Retail sales operations, in particular, want light levels that are far in excess of standard office values. Quality of light in terms of color is also a big concern in retail sales, so finding acceptable ECOs for reducing lighting costs is much more difficult for retail facilities than for

37

office buildings. The challenge is to find new lighting technologies that allow high light levels and warm color while reducing the wattage required. New T8 and T10 fluorescent lamps, and metal halide lamp replacements for mercury vapor lamps offer these features, and usually represent cost-effective ECOs for retail sales and other facilities.

3.7 RESIDENTIAL AUDITS Audits for large, multi-story apartment buildings can be very similar to commercial audits. (See section 3.6.) Audits of single-family residences, however, are generally fairly simple. For single-family structures, the energy audit focuses on the thermal envelope and the appliances such as the heater, air conditioner, water heater, and “plug loads.” The residential auditor should start by obtaining past energy bills and analyzing them to determine any patterns or anomalies. During the audit visit, the structure is examined to determine the levels of insulation, the conditions of and seals for windows and doors, and the integrity of the ducts. The space heater and/or air conditioner is inspected, along with the water heater. Equipment model numbers, age, size, and efficiencies are recorded. The post-audit analysis then evaluates potential ECOs such as adding insulation, adding doublepane windows, window shading or insulated doors, and changing to higher efficiency heaters, air conditioners, and water heaters. The auditor calculates costs, benefits, and Simple Payback Periods and presents them to the owner or occupant. A simple audit report—often in the form of a computer printout is given to the owner or occupant.

3.8 INDOOR AIR QUALITY 3.8.1 Introduction Implementation of new energy-related standards and practices has contributed to a degradation of indoor air quality. In fact, the quality of indoor air has been found to exceed the Environmental Protection Agency (EPA) standards for outdoor air in many homes, businesses, and factories. Thus, testing for air quality problems is done in some energy audits both to prevent exacerbating any existing problems and to recommend ECOs that might improve air quality. Air quality standards for the industrial environment have been published by the American Council of Governmental Industrial Hygienists (ACGIH) in their booklet “Threshold Limit Values.”

38

No such standards currently exist for the residential and commercial environments although the ACGIH standards are typically and perhaps inappropriately used. The EPA has been working to develop residential and commercial standards for quite some time. 3.8.2 Symptoms of Air Quality Problems Symptoms of poor indoor air quality include, but are not limited to: headaches; irritation of mucous membranes such as the nose, mouth, throat, lungs; tearing, redness and irritation of the eyes; numbness of the lips, mouth, throat; mood swings; fatigue; allergies; coughing; nasal and throat discharge; and irritability. Chronic exposure to some compounds can lead to damage to internal organs such as the liver, kidney, lungs, and brain; cancer; and death. 3.8.3 Testing Testing is required to determine if the air quality is acceptable. Many dangerous compounds, like carbon monoxide and methane without odorant added, are odorless and colorless. Some dangerous particulates such as asbestos fibers do not give any indication of a problem for up to twenty years after inhalation. Testing must be conducted in conjunction with pollution-producing processes to ensure capture of the contaminants. Testing is usually performed by a Certified Industrial Hygienist (CIH). 3.8.4 Types of Pollutants Airstreams have three types of contaminants: particulates like dust and asbestos; gases like carbon monoxide, ozone, carbon dioxide, volatile organic compounds, anhydrous ammonia, radon, outgassing from urea-formaldehyde insulation, low oxygen levels; and biologicals like mold, mildew, fungus, bacteria, and viruses. 3.8.5 Pollutant Control Measures Particulates Particulates are controlled with adequate filtration near the source and in the air handling system. Mechanical filters are frequently used in return air streams, and baghouses are used for particulate capture. The coarse filters used in most residential air conditioners typically have filtration efficiencies below twenty percent. Mechanical filters called high efficiency particulate apparatus (HEPA) are capable of filtering particles as small as 0.3 microns at up to 99% efficiency. Electrostatic precipitators remove particulates by placing a positive charge on the walls of collection plates and allowing negatively charged particulates to attach to the surface. Periodic cleaning of

ENERGY MANAGEMENT HANDBOOK

the plates is necessary to maintain high filtration efficiency. Loose or friable asbestos fibers should be removed from the building or permanently encapsulated to prevent entry into the respirable airstream. While conducting an audit, it is important to determine exactly what type of insulation is in use before disturbing an area to make temperature measurements. Problem Gases Problem gases are typically removed by ventilating with outside air. Dilution with outside air is effective, but tempering the temperature and relative humidity of the outdoor air mass can be expensive in extreme conditions. Heat exchangers such as heat wheels, heat pipes, or other devices can accomplish this task with reduced energy use. Many gases can be removed from the airstream by using absorbent/adsorbent media such as activated carbon or zeolite. This strategy works well for spaces with limited ventilation or where contaminants are present in low concentrations. The media must be checked and periodically replaced to maintain effectiveness. Radon gas—Ra 222—cannot be effectively filtered due to its short half life and the tendency for its Polonium daughters to plate out on surfaces. Low oxygen levels are a sign of inadequate outside ventilation air. A high level of carbon dioxide (e.g., 1000-10,000 ppm) is not a problem in itself but levels above 1000 ppm indicate concentrated human or combustion activity or a lack of ventilation air. Carbon dioxide is useful as an indicator compound because it is easy and inexpensive to measure. Microbiological Contaminants Microbiological contaminants generally require particular conditions of temperature and relative humidity on a suitable substrate to grow. Mold and mildew are inhibited by relative humidity levels less than 50%. Air distribution systems often harbor colonies of microbial growth. Many people are allergic to microscopic dust mites. Cooling towers without properly adjusted automated chemical feed systems are an excellent breeding ground for all types of microbial growth. Ventilation Rates Recommended ventilation quantities are published by the American Society of Heating, Refrigerating, and Air-Conditioning Engineers (ASHRAE) in Standard 62, “Ventilation for Acceptable Air Quality.” These ventilation rates are for effective systems. Many existing systems fail in entraining the air mass efficiently. The density of the contaminants relative to air must be con-

ENERGY AUDITING

sidered in locating the exhaust air intakes and ventilation supply air registers. Liability Liability related to indoor air problems appears to be a growing but uncertain issue because few cases have made it through the court system. However, in retrospect, the asbestos and ureaformaldehyde pollution problems discovered in the last two decades suggest proceeding with caution and a proactive approach.

3.9 CONCLUSION Energy audits are an important first step in the overall process of reducing energy costs for any building, company, or industry. A thorough audit identifies and analyzes the changes in equipment and operations that will result in cost-effective energy cost reduction. The energy auditor plays a key role in the successful conduct of an audit, and also in the implementation of the audit recommendations.

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Bibliography Instructions For Energy Auditors, Volumes I and II, U.S. Department of Energy, DOE/CS-0041/12&13, September, 1978. Available through National Technical Information Service, Springfield, VA. Energy Conservation Guide for Industry and Commerce, National Bureau of Standards Handbook 115 and Supplement, 1978. Available through U.S. Government Printing Office, Washington, DC. Guide to Energy Management, Third Edition, Capehart, B.L., Turner, W.C., and Kennedy, W.J., The Fairmont Press, Atlanta, GA, 2000. Illuminating Engineering Society, IES Lighting Handbook, Ninth Edition, New York, NY, 2000. Total Energy Management, A Handbook prepared by the National Electrical Contractors Association and the National Electrical Manufacturers Association, Washington, DC. Handbook of Energy Audits, Thumann, Albert, Fifth Edition, The Fairmont Press, Atlanta, GA. Industrial Energy Management and Utilization, Witte, Larry C., Schmidt, Philip S., and Brown, David R., Hemisphere Publishing Corporation, Washington, DC, 1988. Threshold Limit Values for Chemical Substances and Physical Agents and Biological Exposure Indices, 1990-91 American Conference of Governmental Industrial Hygienists. Ventilation for Acceptable Indoor Air Quality, ASHRAE 62-1999, American Society of Heating, Refrigerating and Air-Conditioning Engineers, Inc., 1999. Facility Design and Planning Engineering Weather Data, Departments of the Air Force, the Army, and the Navy, 1978. Handbook of Energy Engineering, Fourth Edition, Thumann, A., and Mehta, D.P., The Fairmont Press, Atlanta, GA.

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CHAPTER 4

ECONOMIC ANALYSIS DR. DAVID PRATT Industrial Engineering and Management Oklahoma State University Stillwater, OK

4.1

the costs incurred. The number of years over which the revenues accumulate and the comparative importance of future dollars (revenues or costs) relative to present dollars are important factors in making sound investment decisions. This consideration of costs over the entire life cycle of the investments gives rise to the name life cycle cost analysis which is commonly used to refer to the economic analysis approach presented in this chapter. An example of the importance of life cycle costs is shown in Figure 4.1 which depicts the estimated costs of owning and operating an oil-fired furnace to heat a 2,000-squarefoot house in the northeast United States. Of particular note is that the initial costs represent only 23% of the total costs incurred over the life of the furnace. The life cycle cost approach provides a significantly better evaluation of long term implications of an investment than methods which focus on first cost or near term results.

OBJECTIVE

The objective of this chapter is to present a coherent, consistent approach to economic analysis of capital investments (energy related or other). Adherence to the concepts and methods presented will lead to sound investment decisions with respect to time value of money principles. The chapter opens with material designed to motivate the importance of life cycle cost concepts in the economic analysis of projects. The next three sections provide foundational material necessary to fully develop time value of money concepts and techniques. These sections present general characteristics of capital investments, sources of funds for capital investment, and a brief summary of tax considerations which are important for economic analysis. The next two sections introduce time value of money calculations and several approaches for calculating project measures of worth based on time value of money concepts. Next the measures of worth are applied to the process of making decisions when a set of potential projects are to be evaluated. The final concept and technique section of the chapter presents material to address several special problems that may be encountered in economic analysis. This material includes, among other things, discussions of inflation, non-annual compounding of interest, and sensitivity analysis. The chapter closes with a brief summary and a list of references which can provide additional depth in many of the areas covered in the chapter.

4.2

Figure 4.1 15-Year life cycle costs of a heating system Life cycle cost analysis methods can be applied to virtually any public or private business sector investment decision as well as to personal financial planning decisions. Energy related decisions provide excellent examples for the application of this approach. Such decisions include: evaluation of alternative building designs which have different initial costs, operating and maintenance costs, and perhaps different lives; evaluation of investments to improve the thermal performance of an existing building (wall or roof insulation, window glazing); or evaluation of alternative heating, ventilating, or air conditioning systems. For federal buildings, Congress and the President have mandated, through legislation and executive order, energy conservation goals that must be met using cost-effective measures. The life cycle cost approach is mandated as the means of evaluating cost effectiveness.

INTRODUCTION

Capital investment decisions arise in many circumstances. The circumstances range from evaluating business opportunities to personal retirement planning. Regardless of circumstances, the basic criterion for evaluating any investment decision is that the revenues (savings) generated by the investment must be greater than 41

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4.3

ENERGY MANAGEMENT HANDBOOK

GENERAL CHARACTERISTICS OF CAPITAL INVESTMENTS

4.3.1 Capital Investment Characteristics When companies spend money, the outlay of cash can be broadly categorized into one of two classifications; expenses or capital investments. Expenses are generally those cash expenditures that are routine, ongoing, and necessary for the ordinary operation of the business. Capital investments, on the other hand, are generally more strategic and have long term effects. Decisions made regarding capital investments are usually made at higher levels within the organizational hierarchy and carry with them additional tax consequences as compared to expenses. Three characteristics of capital investments are of concern when performing life cycle cost analysis. First, capital investments usually require a relatively large initial cost. “Relatively large” may mean several hundred dollars to a small company or many millions of dollars to a large company. The initial cost may occur as a single expenditure such as purchasing a new heating system or occur over a period of several years such as designing and constructing a new building. It is not uncommon that the funds available for capital investments projects are limited. In other words, the sum of the initial costs of all the viable and attractive projects exceeds the total available funds. This creates a situation known as capital rationing which imposes special requirements on the investment analysis. This topic will be discussed in Section 4.8.3. The second important characteristic of a capital investment is that the benefits (revenues or savings) resulting from the initial cost occur in the future, normally over a period of years. The period between the initial cost and the last future cash flow is the life cycle or life of the investment. It is the fact that cash flows occur over the investment’s life that requires the introduction of time value of money concepts to properly evaluate investments. If multiple investments are being evaluated and if the lives of the investments are not equal, special consideration must be given to the issue of selecting an appropriate planning horizon for the analysis. Planning horizon issues are introduced in Section 4.8.5. The last important characteristic of capital investments is that they are relatively irreversible. Frequently, after the initial investment has been made, terminating or significantly altering the nature of a capital investment has substantial (usually negative) cost consequences. This is one of the reasons that capital investment decisions are usually evaluated at higher levels of the organizational hierarchy than operating expense decisions.

4.3.2 Capital Investment Cost Categories In almost every case, the costs which occur over the life of a capital investment can be classified into one of the following categories: • • • •

Initial Cost, Annual Expenses and Revenues, Periodic Replacement and Maintenance, or Salvage Value.

As a simplifying assumption, the cash flows which occur during a year are generally summed and regarded as a single end-of-year cash flow. While this approach does introduce some inaccuracy in the evaluation, it is generally not regarded as significant relative to the level of estimation associated with projecting future cash flows. Initial costs include all costs associated with preparing the investment for service. This includes purchase cost as well as installation and preparation costs. Initial costs are usually nonrecurring during the life of an investment. Annual expenses and revenues are the recurring costs and benefits generated throughout the life of the investment. Periodic replacement and maintenance costs are similar to annual expenses and revenues except that they do not (or are not expected to) occur annually. The salvage (or residual) value of an investment is the revenue (or expense) attributed to disposing of the investment at the end of its useful life. 4.3.3 Cash Flow Diagrams A convenient way to display the revenues (savings) and costs associated with an investment is a cash flow diagram. By using a cash flow diagram, the timing of the cash flows are more apparent and the chances of properly applying time value of money concepts are increased. With practice, different cash flow patterns can be recognized and they, in turn, may suggest the most direct approach for analysis. It is usually advantageous to determine the time frame over which the cash flows occur first. This establishes the horizontal scale of the cash flow diagram. This scale is divided into time periods which are frequently, but not always, years. Receipts and disbursements are then located on the time scale in accordance with the problem specifications. Individual outlays or receipts are indicated by drawing vertical lines appropriately placed along the time scale. The relative magnitudes can be suggested by the heights, but exact scaling generally does not enhance the meaningfulness of the diagram. Upward directed lines indicate cash inflow (revenues or savings) while downward directed lines indicate cash

ECONOMIC ANALYSIS

43

outflow (costs). Figure 4.2 illustrates a cash flow diagram. The cash flows depicted represent an economic evaluation of whether to choose a baseboard heating and window air conditioning system or a heat pump for a ranger’s house in a national park [Fuller and Petersen, 1994]. The differential costs associated with the decision are: •

The heat pump costs (cash outflow) $1500 more than the baseboard system,

•

The heat pump saves (cash inflow) $380 annually in electricity costs,

•

The heat pump has a $50 higher annual maintenance costs (cash outflow),

•

The heat pump has a $150 higher salvage value (cash inflow) at the end of 15 years,

•

The heat pump requires $200 more in replacement maintenance (cash outflow) at the end of year 8.

Although cash flow diagrams are simply graphical representations of income and outlay, they should exhibit as much information as possible. During the analysis phase, it is useful to show the Minimum Attractive Rate of Return (an interest rate used to account for the time value of money within the problem) on the cash flow diagram, although this has been omitted in Figure 4.2. The requirements for a good cash flow diagram are completeness, accuracy, and legibility. The measure of a successful diagram is that someone else can understand the problem fully from it.

4.4

SOURCES OF FUNDS

Capital investing requires a source of funds. For large companies multiple sources may be employed.

The process of obtaining funds for capital investment is called financing. There are two broad sources of financial funding; debt financing and equity financing. Debt financing involves borrowing and utilizing money which is to be repaid at a later point in time. Interest is paid to the lending party for the privilege of using the money. Debt financing does not create an ownership position for the lender within the borrowing organization. The borrower is simply obligated to repay the borrowed funds plus accrued interest according to a repayment schedule. Car loans and mortgage loans are two examples of this type of financing. The two primary sources of debt capital are loans and bonds. The cost of capital associated with debt financing is relatively easy to calculate since interest rates and repayment schedules are usually clearly documented in the legal instruments controlling the financing arrangements. An added benefit to debt financing under current U.S. tax law (as of April 2000) is that the interest payments made by corporations on debt capital are tax deductible. This effectively lowers the cost of debt financing since for debt financing with deductible interest payments, the after-tax cost of capital is given by: Cost of CapitalAFTERTAX = Cost of CapitalBEFORETAX * (1 - TaxRate) where the tax rate is determine by applicable tax law. The second broad source of funding is equity financing. Under equity financing the lender acquires an ownership (or equity) position within the borrower’s organization. As a result of this ownership position, the lender has the right to participate in the financial success of the organization as a whole. The two primary sources of equity financing are stocks and retained earnings. The cost of capital associated with shares of stock is much debated within the financial community. A detailed presentation of the issues and approaches is beyond the

Figure 4.2. Heat pump and baseboard system differential life cycle costs

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scope of this chapter. Additional reference material can be found in Park and Sharp-Bette [1990]. One issue over which there is general agreement is that the cost of capital for stocks is higher than the cost of capital for debt financing. This is at least partially attributable to the fact that interest payments are tax deductible while stock dividend payments are not. If any subject is more widely debated in the financial community than the cost of capital for stocks, it is the cost of capital for retained earnings. Retained earnings are the accumulation of annual earnings surpluses that a company retains within the company’s coffers rather than pays out to the stockholders as dividends. Although these earnings are held by the company, they truly belong to the stockholders. In essence the company is establishing the position that by retaining the earnings and investing them in capital projects, stockholders will achieve at least as high a return through future financial successes as they would have earned if the earnings had been paid out as dividends. Hence, one common approach to valuing the cost of capital for retained earnings is to apply the same cost of capital as for stock. This, therefore, leads to the same generally agreed result. The cost of capital for financing through retained earnings generally exceeds the cost of capital for debt financing. In many cases the financing for a set of capital investments is obtained by packaging a combination of the above sources to achieve a desired level of available funds. When this approach is taken, the overall cost of capital is generally taken to be the weighted average cost of capital across all sources. The cost of each individual source’s funds is weighted by the source’s fraction of the total dollar amount available. By summing across all sources, a weighted average cost of capital is calculated. Example 1 Determine the weighted average cost of capital for financing which is composed of: 25% loans with a before tax cost of capital of 12%/ yr and 75% retained earnings with a cost of capital of 10%/yr. The company’s effective tax rate is 34%.

ENERGY MANAGEMENT HANDBOOK

4.5

TAX CONSIDERATIONS

4.5.1 After Tax Cash Flows Taxes are a fact of life in both personal and business decision making. Taxes occur in many forms and are primarily designed to generate revenues for governmental entities ranging from local authorities to the Federal government. A few of the most common forms of taxes are income taxes, ad valorem taxes, sales taxes, and excise taxes. Cash flows used for economic analysis should always be adjusted for the combined impact of all relevant taxes. To do otherwise, ignores the significant impact that taxes have on economic decision making. Tax laws and regulations are complex and intricate. A detailed treatment of tax considerations as they apply to economic analysis is beyond the scope of this chapter and generally requires the assistance of a professional with specialized training in the subject. A high level summary of concepts and techniques that concentrate on Federal income taxes are presented in the material which follows. The focus is on Federal income taxes since they impact most decisions and have relatively wide and general application. The amount of Federal taxes due are determined based on a tax rate multiplied by a taxable income. The rates (as of April 2000) are determined based on tables of rates published under the Omnibus Reconciliation Act of 1993 as shown in Table 4.1. Depending on income range, the marginal tax rates vary from 15% of taxable income to 39% of taxable income. Taxable income is calculated by subtracting allowable deductions from gross income. Gross income is generated when a company sells its product or service. Allowable deductions include salaries and wages, materials, interest payments, and depreciation as well as other costs of doing business as detailed in the tax regulations. The calculation of taxes owed and after tax cash flows (ATCF) requires knowledge of: •

Before Tax Cash Flows (BTCF), the net project cash flows before the consideration of taxes due, loan payments, and bond payments;

•

Total loan payments attributable to the project, including a breakdown of principal and interest components of the payments;

•

Total bond payments attributable to the project, including a breakdown of the redemption and interest components of the payments; and

•

Depreciation allowances attributable to the project.

Cost of CapitalLOANS = 12% * (1 - 0.34) = 7.92% Cost of CapitalRETAINED EARNINGS = 10% Weighted Average Cost of Capital = (0.25)*7.92% + (0.75)*10.00% = 9.48%

ECONOMIC ANALYSIS

45

Table 4.1 Federal tax rates based on the Omnibus Reconciliation Act of 1993 Taxable Income (TI)

Taxes Due

Marginal Tax Rate

$0 < TI ≤ $50,000

0.15*TI

0.15

$50,000 < TI ≤ $75,000

$7,500+0.25(TI-$50,000)

0.25

$75,000 < TI ≤ $100,000

$13,750+0.34(TI-$75,000)

0.34

$100,000 < TI ≤ $335,000

$22,250+0.39(TI-$100,000)

0.39

$335,000 < TI ≤ $10,000,000

$113,900+0.34(TI-$335,000)

0.34

$10,000,000 < TI ≤ $15,000,000

$3,400,000+0.35(TI-$10,000,000)

0.35

$15,000,000 < TI ≤ $18,333,333

$5,150,000+0.38(TI-$15,000,000)

0.38

$18,333,333 < TI

$6,416,667+0.35(TI-$18,333,333)

0.35

Given the availability of the above information, the procedure to determine the ATCF on a year-by-year basis proceeds using the following calculation for each year: •

Taxable Income = BTCF - Loan Interest - Bond Interest - Deprecation

•

Taxes = Taxable Income * Tax Rate

•

ATCF = BTCF - Total Loan Payments - Total Bond Payments - Taxes

An important observation is that Depreciation reduces Taxable Income (hence, taxes) but does not directly enter into the calculation of ATCF since it is not a true cash flow. It is not a true cash flow because no cash changes hands. Depreciation is an accounting concept design to stimulate business by reducing taxes over the life of an asset. The next section provides additional information about depreciation.

4.5.2 Depreciation Most assets used in the course of a business decrease in value over time. U.S. Federal income tax law permits reasonable deductions from taxable income to allow for this. These deductions are called depreciation allowances. To be depreciable, an asset must meet three primary conditions: (1) it must be held by the business for the purpose of producing income, (2) it must wear out or be consumed in the course of its use, and (3) it must have a life longer than a year. Many methods of depreciation have been allowed under U.S. tax law over the years. Among these methods are straight line, sum-of-the-years digits, declining balance, and the accelerated cost recovery system. Descrip-

tions of these methods can be found in many references including economic analysis text books [White, et al., 1998]. The method currently used for depreciation of assets placed in service after 1986 is the Modified Accelerated Cost Recovery System (MACRS). Determination of the allowable MACRS depreciation deduction for an asset is a function of (1) the asset’s property class, (2) the asset’s basis, and (3) the year within the asset’s recovery period for which the deduction is calculated. Eight property classes are defined for assets which are depreciable under MACRS. The property classes and several examples of property that fall into each class are shown in Table 4.2. Professional tax guidance is recommended to determine the MACRS property class for a specific asset. The basis of an asset is the cost of placing the asset in service. In most cases, the basis includes the purchase cost of the asset plus the costs necessary to place the asset in service (e.g., installation charges). Given an asset’s property class and its depreciable basis the depreciation allowance for each year of the asset’s life can be determined from tabled values of MACRS percentages. The MACRS percentages specify the percentage of an asset’s basis that are allowable as deductions during each year of an asset’s recovery period. The MACRS percentages by recovery year (age of the asset) and property class are shown in Table 4.3. Example 2 Determine depreciation allowances during each recovery year for a MACRS 5-year property with a basis of $10,000. Year 1 deduction: $10,000 * 20.00% = $2,000 Year 2 deduction: $10,000 * 32.00% = $3,200

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Table 4.2 MACRS property classes Property Class Example Assets ——————————————————————————————————————————— 3-Year Property special handling devices for food special tools for motor vehicle manufacturing ——————————————————————————————————————————— 5-Year Property computers and office machines general purpose trucks ——————————————————————————————————————————— 7-Year Property office furniture most manufacturing machine tools ——————————————————————————————————————————— 10-Year Property tugs & water transport equipment petroleum refining assets ——————————————————————————————————————————— 15-Year Property fencing and landscaping cement manufacturing assets ——————————————————————————————————————————— 20-Year Property farm buildings utility transmission lines and poles ——————————————————————————————————————————— 27.5-Year Residential Rental Property rental houses and apartments ——————————————————————————————————————————— 31.5-Year Nonresidential Real Property business buildings Year 3 deduction: $10,000 * 19.20% = $1,920 Year 4 deduction: $10,000 * 11.52% = $1,152 Year 5 deduction: $10,000 * 11.52% = $1,152 Year 6 deduction: $10,000 * 5.76% = $576 The sum of the deductions calculated in Example 2 is $10,000 which means that the asset is “fully depreciated” after six years. Though not shown here, tables similar to Table 4.3 are available for the 27.5-Year and 31.5-Year property classes. Their usage is similar to that outlined above except that depreciation is calculated monthly rather than annually.

4.6

TIME VALUE OF MONEY CONCEPTS

4.6.1 Introduction Most people have an intuitive sense of the time value of money. Given a choice between $100 today and $100 one year from today, almost everyone would prefer the $100 today. Why is this the case? Two primary factors lead to this time preference associated with money; interest and inflation. Interest is the ability to earn a return on money which is loaned rather than consumed. By taking the $100 today and placing it in an interest bearing bank account (i.e., loaning it to the bank), one year from today an amount greater than $100 would be available for withdrawal. Thus, taking the $100 today

and loaning it to earn interest, generates a sum greater than $100 one year from today and thus is preferred. The amount in excess of $100 that would be available depends upon the interest rate being paid by the bank. The next section develops the mathematics of the relationship between interest rates and the timing of cash flows. The second factor which leads to the time preference associated with money is inflation. Inflation is a complex subject but in general can be described as a decrease in the purchasing power of money. The impact of inflation is that the “basket of goods” a consumer can buy today with $100 contains more than the “basket” the consumer could buy one year from today. This decrease in purchasing power is the result of inflation. The subject of inflation is addressed in Section 4.9.4. 4.6.2 The Mathematics of Interest The mathematics of interest must account for the amount and timing of cash flows. The basic formula for studying and understanding interest calculations is: Fn = P + I n where:

Fn =

a future amount of money at the end of the nth year;

P=

a present amount of money at the beginning of the year which is n years prior to Fn;

ECONOMIC ANALYSIS

47

Table 4.3 MACRS percentages by recovery year and property class Recovery 3-Year Year Property

5-Year Property

7-Year Property

10-Year Property

15-Year Property

20-Year Property

———————————————————————————————————— 1 33.33% 20.00% 14.29% 10.00% 5.00% 3.750% ———————————————————————————————————— 2 44.45% 32.00% 24.49% 18.00% 9.50% 7.219% ———————————————————————————————————— 3 14.81% 19.20% 17.49% 14.40% 8.55% 6.677% ———————————————————————————————————— 4 7.41% 11.52% 12.49% 11.52% 7.70% 6.177% ———————————————————————————————————— 5 11.52% 8.93% 9.22% 6.93% 5.713% ———————————————————————————————————— 6 5.76% 8.92% 7.37% 6.23% 5.285% ———————————————————————————————————— 7 8.93% 6.55% 5.90% 4.888% ———————————————————————————————————— 8 4.46% 6.55% 5.90% 4.522% ———————————————————————————————————— 9 6.56% 5.91% 4.462% ———————————————————————————————————— 10 6.55% 5.90% 4.461% ———————————————————————————————————— 11 3.28% 5.91% 4.462% ———————————————————————————————————— 12 5.90% 4.461% ———————————————————————————————————— 13 5.91% 4.462% ———————————————————————————————————— 14 5.90% 4.461% ———————————————————————————————————— 15 5.91% 4.462% ———————————————————————————————————— 16 2.95% 4.461% ———————————————————————————————————— 17 4.462% ———————————————————————————————————— 18 4.461% ———————————————————————————————————— 19 4.462% ———————————————————————————————————— 20 4.461% ———————————————————————————————————— 21 2.231%

In =

the amount of accumulated interest over n years; and

n=

the number of years between P and F.

The goal of studying the mathematics of interest is to develop a formula for Fn which is expressed only in terms of the present amount P, the annual interest rate i, and the number of years n. There are two major approaches for determining the value of In; simple interest and compound interest. Under simple interest, interest is earned (charged) only on the original amount loaned (borrowed). Under compound interest, interest is earned (charged) on the original amount loaned (borrowed) plus any interest accumulated from previous periods. 4.6.3 Simple Interest For simple interest, interest is earned (charged) only on the original principal amount at the rate of i%

per year (expressed as i%/yr). Table 4.4 illustrates the annual calculation of simple interest. In Table 4.4 and the formulas which follow, the interest rate i is to be expressed as a decimal amount (e.g., 8% interest is expressed as 0.08). At the beginning of year 1 (end of year 0), P dollars (e.g., $100) are deposited in an account earning i%/yr (e.g., 8%/yr or 0.08) simple interest. Under simple compounding, during year 1 the P dollars ($100) earn P*i dollars ($100*0.08 = $8) of interest. At the end of the year 1 the balance in the account is obtained by adding P dollars (the original principal, $100) plus P*i (the interest earned during year 1, $8) to obtain P+P*i ($100+$8=$108). Through algebraic manipulation, the end of year 1 balance can be expressed mathematically as P*(1+i) dollars ($100*1.08=$108). The beginning of year 2 is the same point in time as the end of year 1 so the balance in the account is P*(1+i) dollars ($108). During year 2 the account again

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Table 4.4 The mathematics of simple interest Year

Amount At Interest Earned Amount At End Beginning Of During Year Of Year (t) Year (Ft) ————————————————————————————————— 0 P 1

P

Pi

P + Pi = P (1 + i)

2

P (1 + i)

Pi

P (1+ i) + Pi = P (1 + 2i)

3

P (1 + 2i)

Pi

P (1+ 2i) + Pi = P (1 + 3i)

n

P (1 + (n-1)i)

Pi

P (1+ (n-1)i) + Pi = P (1 + ni)

earns P*i dollars ($8) of interest since under simple compounding, interest is paid only on the original principal amount P ($100). Thus at the end of year 2, the balance in the account is obtained by adding P dollars (the original principal) plus P*i (the interest from year 1) plus P*i (the interest from year 2) to obtain P+P*i+P*i ($100+$8+$8=$116). After some algebraic manipulation, this can be written conveniently mathematically as P*(1+2*i) dollars ($100*1.16=$116). Table 4.4 extends the above logic to year 3 and then generalizes the approach for year n. If we return our attention to our original goal of developing a formula for Fn which is expressed only in terms of the present amount P, the annual interest rate i, and the number of years n, the above development and Table 4.4 results can be summarized as follows: For Simple Interest Fn = P (1+n*i) Example 3 Determine the balance which will accumulate at the end of year 4 in an account which pays 10%/yr simple interest if a deposit of $500 is made today. Fn = P * (1 + n*i) F4 = 500 * (1 + 4*0.10) F4 = 500 * (1 + 0.40) F4 = 500 * (1.40) F4 = $700 4.6.4 Compound Interest For compound interest, interest is earned (charged) on the original principal amount plus any accumulated

interest from previous years at the rate of i% per year (i%/ yr). Table 4.5 illustrates the annual calculation of compound interest. In the Table 4.5 and the formulas which follow, i is expressed as a decimal amount (i.e., 8% interest is expressed as 0.08). At the beginning of year 1 (end of year 0), P dollars (e.g., $100) are deposited in an account earning i%/yr (e.g., 8%/yr or 0.08) compound interest. Under compound interest, during year 1 the P dollars ($100) earn P*i dollars ($100*0.08 = $8) of interest. Notice that this the same as the amount earned under simple compounding. This result is expected since the interest earned in previous years is zero for year 1. At the end of the year 1 the balance in the account is obtain by adding P dollars (the original principal, $100) plus P*i (the interest earned during year 1, $8) to obtain P+P*i ($100+$8=$108). Through algebraic manipulation, the end of year 1 balance can be expressed mathematically as P*(1+i) dollars ($100*1.08=$108). During year 2 and subsequent years, we begin to see the power (if you are a lender) or penalty (if you are a borrower) of compound interest over simple interest. The beginning of year 2 is the same point in time as the end of year 1 so the balance in the account is P*(1+i) dollars ($108). During year 2 the account earns i% interest on the original principal, P dollars ($100), and it earns i% interest on the accumulated interest from year 1, P*i dollars ($8). Thus the interest earned in year 2 is [P+P*i]*i dollars ([$100+$8]*0.08=$8.64). The balance at the end of year 2 is obtained by adding P dollars (the original principal) plus P*i (the interest from year 1) plus [P+P*i]*i (the interest from year 2) to obtain P+P*i+[P+P*i]*i dollars ($100+$8+$8.64=$116.64). After some algebraic ma-

ECONOMIC ANALYSIS

49

Table 4.5 The Mathematics of Compound Interest ——————————————————————————————————————— Year Amount At Interest Earned Amount At End Beginning Of During Year Of Year (t) Year (Ft) ——————————————————————————————————————— 0 P ——————————————————————————————————————— 1 P Pi P + Pi = P (1 + i) ——————————————————————————————————————— 2 P (1 + i) P (1 + i) i P (1+ i) + P (1 + i) i = P (1 + i) (1 + i) = P (1+i)2 ——————————————————————————————————————— 3 P (1+i)2 P (1+i)2 i P (1+ i)2 + P (1 + i)2 i = P (1 + i)2 (1 + i) = P (1+i)3 ——————————————————————————————————————— n P (1+i)n-1 P (1+i)n-1 i P (1+ i)n-1 + P (1 + i)n-1 i = P (1 + i)n-1 (1 + i) = P (1+i)n ———————————————————————————————————————

nipulation, this can be written conveniently mathematically as P*(1+i)n dollars ($100*1.082 =$116.64). Table 4.5 extends the above logic to year 3 and then generalizes the approach for year n. If we return our attention to our original goal of developing a formula for Fn which is expressed only in terms of the present amount P, the annual interest rate i, and the number of years n, the above development and Table 4.5 results can be summarized as follows: For Compound Interest Fn = P (1+i)n Example 4 Repeat Example 3 using compound interest rather than simple interest. Fn = P * (1 + i)n F4 = 500 * (1 + 0.10)4 F4 = 500 * (1.10)4 F4 = 500 * (1.4641) F4 = $732.05 Notice that the balance available for withdrawal is higher under compound interest ($732.05 > $700.00). This is due to earning interest on principal plus interest rather than earning interest on just original principal. Since compound interest is by far more common in prac-

tice than simple interest, the remainder of this chapter is based on compound interest unless explicitly stated otherwise. 4.6.5 Single Sum Cash Flows Time value of money problems involving compound interest are common. Because of this frequent need, tables of compound interest time value of money factors can be found in most books and reference manuals that deal with economic analysis. The factor (1+i)n is known as the single sum, future worth factor or the single payment, compound amount factor. This factor is denoted (F|P,i,n) where F denotes a future amount, P denotes a present amount, i is an interest rate (expressed as a percentage amount), and n denotes a number of years. The factor (F|P,i,n) is read “to find F given P at i% for n years.” Tables of values of (F|P,i,n) for selected values of i and n are provided in Appendix 4A. The tables of values in Appendix 4A are organized such that the annual interest rate (i) determines the appropriate page, the time value of money factor (F|P) determines the appropriate column, and the number of years (n) determines the appropriate row. Example 5 Repeat Example 4 using the single sum, future worth factor.

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ENERGY MANAGEMENT HANDBOOK

Fn = P * (1 + i)n

sum of the present worths of the individual cash flows.

Fn = P * (F|P,i,n)

Example 7 Determine the future worth (accumulated total) at the end of seven years in an account that earns 5%/yr if a $600 deposit is made today and a $1000 deposit is made at the end of year two?

F4 = 500 * (F|P,10%,4) F4 = 500 * (1.4641) F4 = 732.05 The above formulas for compound interest allow us to solve for an unknown F given P, i, and n. What if we want to determine P with known values of F, i, and n? We can derive this relationship from the compound interest formula above: Fn = P (1+i)n dividing both sides by (1+i)n yields P=

Fn ———— (1 + i)n

which can be rewritten as P = Fn (1+i)-n The factor (1+i)-n is known as the single sum, present worth factor or the single payment, present worth factor. This factor is denoted (P|F,i,n) and is read “to find P given F at i% for n years.” Tables of (P|F,i,n) are provided in Appendix 4A.

for the $600 deposit, n=7 (years between today and end of year 7) for the $1000 deposit, n=5 (years between end of year 2 and end of year 7) F7 = 600 * (F|P,5%,7) + 1000 * (F|P,5%,5) F7 = 600 * (1.4071) + 1000 * (1.2763) F7 = 844.26 + 1276.30 = $2120.56 Example 8 Determine the amount that would have to be deposited today (present worth) in an account paying 6%/ yr interest if you want to withdraw $500 four years from today and $600 eight years from today (leaving zero in the account after the $600 withdrawal). for the $500 deposit n=4, for the $600 deposit n=8

Example 6 To accumulate $1000 five years from today in an account earning 8%/yr compound interest, how much must be deposited today? P= P= P= P= P=

Fn * (1 + i)-n F5 * (P|F,i,n) 1000 * (P|F,8%,5) 1000 * (0.6806) 680.60

To verify your solution, try multiplying 680.60 * (F|P,8%,5). What would expect for a result? (Answer: $1000) If you're still not convinced, try building a table like Table 4.5 to calculate the year end balances each year for five years. 4.6.6 Series Cash Flows Having considered the transformation of a single sum to a future worth when given a present amount and vice versa, let us generalize to a series of cash flows. The future worth of a series of cash flows is simply the sum of the future worths of each individual cash flow. Similarly, the present worth of a series of cash flows is the

P = 500 * (P|F,6%,4) + 600 * (P|F,6%,8) P = 500 * (0.7921) + 600 * (0.6274) P = 396.05 + 376.44 = $772.49 4.6.7 Uniform Series Cash Flows A uniform series of cash flows exists when the cash flows in a series occur every year and are all equal in value. Figure 4.3 shows the cash flow diagram of a uniform series of withdrawals. The uniform series has length 4 and amount 2000. If we want to determine the amount of money that would have to be deposited today to support this series of withdrawals starting one year from today, we could use the approach illustrated in Example 8 above to determine a present worth component for each individual cash flow. This approach would require us to sum the following series of factors (assuming the interest rate is 9%/yr): P = 2000*(P|F,9%,1) + 2000*(P|F,9%,2) + 2000*(P|F,9%,3) + 2000*(P|F,9%,4) After some algebraic manipulation, this expression can be restated as:

ECONOMIC ANALYSIS

51

P = 2000*[(P|F,9%,1) + (P|F,9%,2) + (P|F,9%,3) + (P|F,9%,4)] P = 2000*[(0.9174) + (0.8417) + (0.7722) + (0.7084)] P = 2000*[3.2397] = $6479.40 2000

0

1

2000

2

2000

3

2000

4

Figure 4.3. Uniform series cash flow Fortunately, uniform series occur frequently enough in practice to justify tabulating values to eliminate the need to repeatedly sum a series of (P|F,i,n) factors. To accommodate uniform series factors, we need to add a new symbol to our time value of money terminology in addition to the single sum symbols P and F. The symbol “A” is used to designate a uniform series of cash flows. When dealing with uniform series cash flows, the symbol A represents the amount of each annual cash flow and the n represents the number of cash flows in the series. The factor (P|A,i,n) is known as the uniform series, present worth factor and is read “to find P given A at i% for n years.” Tables of (P|A,i,n) are provided in Appendix 4A. An algebraic expression can also be derived for the (P|A,i,n) factor which expresses P in terms of A, i, and n. The derivation of this formula is omitted here, but the resulting expression is shown in the summary table (Table 4.6) at the end of this section. An important observation when using a (P|A,i,n) factor is that the “P” resulting from the calculation occurs one period prior to the first “A” cash flow. In our example the first withdrawal (the first “A”) occurred one year after the deposit (the “P”). Restating the example problem above using a (P|A,i,n) factor, it becomes:

provided in Appendix 4A and the algebraic expression for (A|P,i,n) is shown in Table 4.6 at the end of this section. This factor enables us to determine the amount of the equal annual withdrawals “A” (starting one year after the deposit) that can be made from an initial deposit of “P.” Example 9 Determine the equal annual withdrawals that can be made for 8 years from an initial deposit of $9000 in an account that pays 12%/yr. The first withdrawal is to be made one year after the initial deposit. A = P * (A|P,12%,8) A = 9000 * (0.2013) A = $1811.70 Factors are also available for the relationships between a future worth (accumulated amount) and a uniform series. The factor (F|A,i,n) is known as the uniform series future worth factor and is read “to find F given A at i% for n years.” The reciprocal factor, (A|F,i,n), is known as the uniform series sinking fund factor and is read “to find A given F at i% for n years.” An important observation when using an (F|A,i,n) factor or an (A|F,i,n) factor is that the “F” resulting from the calculation occurs at the same point in time as to the last “A” cash flow. The algebraic expressions for (A|F,i,n) and (F|A,i,n) are shown in Table 4.6 at the end of this section. Example 10 If you deposit $2000 per year into an individual retirement account starting on your 24th birthday, how much will have accumulated in the account at the time of your deposit on your 65th birthday? The account pays 6%/yr.

P = A * (P|A,i,n)

n = 42 (birthdays between 24th and 65th, inclusive)

P = 2000 * (P|A,9%,4)

F = A * (F|A,6%,42)

P = 2000 * (3.2397) = $6479.40

F = 2000 * (175.9505) = $351,901

This result is identical (as expected) to the result using the (P|F,i,n) factors. In both cases the interpretation of the result is as follows: if we deposit $6479.40 in an account paying 9%/yr interest, we could make withdrawals of $2000 per year for four years starting one year after the initial deposit to deplete the account at the end of 4 years. The reciprocal relationship between P and A is symbolized by the factor (A|P,i,n) and is called the uniform series, capital recovery factor. Tables of (A|P,i,n) are

Example 11 If you want to be a millionaire on your 65th birthday, what equal annual deposits must be made in an account starting on your 24th birthday? The account pays 10%/yr. n = 42 (birthdays between 24th and 65th, inclusive) A = F * (A|F,10%,42) A = 1000000 * (0.001860) = $1860

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4.6.8 Gradient Series A gradient series of cash flows occurs when the value of a given cash flow is greater than the value of the previous period’s cash flow by a constant amount. The symbol used to represent the constant increment is G. The factor (P|G,i,n) is known as the gradient series, present worth factor. Tables of (P|G,i,n) are provided in Appendix 4A. An algebraic expression can also be derived for the (P|G,i,n) factor which expresses P in terms of G, i, and n. The derivation of this formula is omitted here, but the resulting expression is shown in the summary table (Table 4.6) at the end of this section. It is not uncommon to encounter a cash flow series that is the sum of a uniform series and a gradient series. Figure 4.4 illustrates such a series. The uniform component of this series has a value of 1000 and the gradient series has a value of 500. By convention the first element of a gradient series has a zero value. Therefore, in Figure 4.4, both the uniform series and the gradient series have length four (n=4). Like the uniform series factor, the “P” calculated by a (P|G,i,n) factor is located one period before the first element of the series (which is the zero element for a gradient series). Example 12 Assume you wish to make the series of withdrawals illustrated in Figure 4.4 from an account which pays 15%/yr. How much money would you have to deposit today such that the account is depleted at the time of the last withdrawal? This problem is best solved by recognizing that the cash flows are a combination of a uniform series of value 1000 and length 4 (starting at time=1) plus a gradient series of size 500 and length 4 (starting at time=1). P = A * (P|A,15%,4) + G * (P|G,15%,4) P = 1000 * (2.8550) + 500 * (3.7864) P = 2855.00 + 1893.20 = $4748.20 Occasionally it is useful to convert a gradient series to an equivalent uniform series of the same length. Equivalence in this context means that the present value (P) calculated from the gradient series is numerically equal to the present value (P) calculated from the uniform series. One way to accomplish this task with the time value of money factors we have already considered is to convert the gradient series to a present value using a (P|G,i,n) factor and then convert this present value to a uniform series using an (A|P,i,n) factor. In other words:

2000

2000

2000

2000

1

2

3

4

Figure 4.4. Combined uniform series and gradient series cash flow

A = [G * (P|G,i,n)] * (A|P,i,n) An alternative approach is to use a factor known as the gradient-to-uniform series conversion factor, symbolized by (A|G,i,n). Tables of (A|G,i,n) are provided in Appendix 4A. An algebraic expression can also be derived for the (A|G,i,n) factor which expresses A in terms of G, i, and n. The derivation of this formula is omitted here, but the resulting expression is shown in the summary table (Table 4.6) at the end of this section. 4.6.9 Summary of Time Value of Money Factors Table 4.6 summarizes the time value of money factors introduced in this section. Time value of money factors are useful in economic analysis because they provide a mechanism to accomplish two primary functions: (1) they allow us to replace a cash flow at one point in time with an equivalent cash flow (in a time value of money sense) at a different point in time and (2) they allow us to convert one cash flow pattern to another (e.g., convert a single sum of money to an equivalent cash flow series or convert a cash flow series to an equivalent single sum). The usefulness of these two functions when performing economic analysis of alternatives will become apparent in Sections 4.7 and 4.8 which follow. 4.6.10 The Concepts of Equivalence and Indifference Up to this point the term “equivalence” has been used several times but never fully defined. It is appropriate at this point to formally define equivalence as well as a related term, indifference. In economic analysis, “equivalence” means “the state of being equal in value.” The concept is primarily applied to the comparison of two or more cash flow profiles. Specifically, two (or more) cash flow profiles are equivalent if their time value of money worths at a common point in time are equal. Question: Are the following two cash flows equivalent at 15%/yr? Cash Flow 1: Receive $1,322.50 two years from today Cash Flow 2: Receive $1,000.00 today

ECONOMIC ANALYSIS

53

Table 4.6 Summary of discrete compounding time value of money factors To Find

Given

Factor

Symbol

Name

P

F

(1+i)-n

(P|F,i,n)

Single Payment, Present Worth Factor

F

P

(1+i)n

(F|P,i,n)

Single Payment, Compound Amount Factor

P

A

(1+i)n – 1 ———— i(1 + i)n

(P|A,i,n)

Uniform Series, Present Worth Factor

A

P

i(1+i)n ———— (1+i)n – 1

(A|P,i,n)

Uniform Series, Capital Recovery Factor

F

A

(1+i)n – 1 ———— i

(F|A,i,n)

Uniform Series, Compound Amount Factor

(A|F,i,n)

Uniform Series, Sinking Fund Factor

(P|G,i,n)

Gradient Series, Present Worth Factor

(A|G,i,n)

Gradient Series, Uniform Series Factor

A

F

P

G

i n 1+i –1 1 – 1 + ni 1 + i

–n

i2 A

G

–n

1 + i – 1 + ni –n i 1+i –1

Analysis Approach 1: Compare worths at t=0 (present worth) PW(1) = 1,322.50*(P|F,15,2) = 1322.50*0.756147 = 1,000 PW(2) = 1,000 Answer: Cash Flow 1 and Cash Flow 2 are equivalent Analysis Approach 2: Compare worths at t=2 (future worth) FW(1) = 1,322.50 FW(2) = 1,000*(F|P,15,2) = 1,000*1.3225 = 1,322.50 Answer: Cash Flow 1 and Cash Flow 2 are equivalent Generally the comparison (hence the determination of equivalence) for the two cash flow series in this example would be made as present worths (t=0) or future worths (t=2), but the equivalence definition holds regardless of the point in time chosen. For example: Analysis Approach 3: Compare worths at t=1 W1(1) = 1,322.50*(P|F,15,1) = 1,322.50*0.869565 = 1,150.00 W1(2) = 1,000*(F|P,15,1) = 1,000*1.15 = 1,150.00

Answer: Cash Flow 1 and Cash Flow 2 are equivalent Thus, the selection of the point in time, t, at which to make the comparison is completely arbitrary. Clearly however, some choices are more intuitively appealing than others (t= 0 and t=2 in the above example). In economic analysis, “indifference” means “to have no preference” The concept is primarily applied in the comparison of two or more cash flow profiles. Specifically, a potential investor is indifferent between two (or more) cash flow profiles if they are equivalent. Question: Given the following two cash flows at 15%/yr which do you prefer? Cash Flow 1: Receive $1,322.50 two years from today Cash Flow 2: Receive $1,000.00 today Answer: Based on the equivalence calculations above, given these two choices, an investor is indifferent. The concept of equivalence can be used to break a large, complex problem into a series of smaller more manageable ones. This is done by taking advantage of

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the fact that, in calculating the economic worth of a cash flow profile, any part of the profile can be replaced by an equivalent representation without altering the worth of the profile at an arbitrary point in time. Question: You are given a choice between (1) receiving P dollars today or (2) receiving the cash flow series illustrated in Figure 4.5. What must the value of P be for you to be indifferent between the two choices if i=12%/yr? 2000

0

1

2

3

2000

2000

2000

4

5

6

2000

7

Figure 4.5 A cash flow series Analysis Approach: To be indifferent between the choices, P must have a value such that the two alternatives are equivalent at 12%/yr. If we select t=0 as the common point in time upon which to base the analysis (present worth approach), then the analysis proceeds as follows. PW(Alt 1) = P Because P is already at t=0 (today), no time value of money factors are involved. PW(Alt 2) Step 1 - Replace the uniform series (t=3 to 7) with an equivalent single sum, V2, at t=2 (one period before the first element of the series). V2 = 2,000 * (P|A,12%,5) = 2,000 * 3.6048 = 7,209.60 Step 2 - Replace the single sum V2, with an equivalent value V0 at t=0: PW(Alt 2) = V 0 =V 2 * (P|F,12,2) = 7,209.60 * 0.7972 = 5,747.49 Answer: To be indifferent between the two alternatives, they must be equivalent at t=0. To be equivalent, P must have a value of $5,747.49

4.7

PROJECT MEASURES OF WORTH

4.7.1 Introduction In this section measures of worth for investment projects are introduced. The measures are used to evaluate the attractiveness of a single investment opportunity. The measures to be presented are (1) present worth, (2) annual worth, (3) internal rate of return, (4) savings investment ratio, and (5) payback period. All but one of these measures of worth require an interest rate to calculate the worth of an investment. This interest rate is commonly referred to as the Minimum Attractive Rate of Return (MARR). There are many ways to determine a

value of MARR for investment analysis and no one way is proper for all applications. One principle is, however, generally accepted. MARR should always exceed the cost of capital as described in Section 4.4, Sources of Funds, presented earlier in this chapter. In all of the measures of worth below, the following conventions are used for defining cash flows. At any given point in time (t = 0, 1, 2,..., n), there may exist both revenue (positive) cash flows, Rt, and cost (negative) cash flows, Ct. The net cash flow at t, At, is defined as Rt - Ct. 4.7.2 Present Worth Consider again the cash flow series illustrated in Figure 4.5. If you were given the opportunity to “buy” that cash flow series for $5,747.49, would you be interested in purchasing it? If you expected to earn a 12%/yr return on your money (MARR=12%), based on the analysis in the previous section, your conclusion would be (should be) that you are indifferent between (1) retaining your $5,747.49 and (2) giving up your $5,747.49 in favor of the cash flow series. Figure 4.6 illustrates the net cash flows of this second investment opportunity. What value would you expect if we calculated the present worth (equivalent value of all cash flows at t=0) of Figure 4.6? We must be careful with the signs (directions) of the cash flows in this analysis since some represent cash outflows (downward) and some represent cash inflows (upward). PW = -5747.49 + 2000*(P|A,12%,5)*(P|F,12%,2) PW = -5747.49 + 2000*(3.6048)*(0.7972) PW = -5747.49 + 5747.49 = $0.00 The value of zero for present worth indicates indifference regarding the investment opportunity. We would just as soon do nothing (i.e., retain our $5747.49) as invest in the opportunity. What if the same returns (future cash inflows) where offered for a $5000 investment (t=0 outflow),

Figure 4.6 An investment opportunity

ECONOMIC ANALYSIS

55

would this be more or less attractive? Hopefully, after a little reflection, it is apparent that this would be a more attractive investment because you are getting the same returns but paying less than the indifference amount for them. What happens if calculate the present worth of this new opportunity? PW = -5000 + 2000*(P|A,12%,5)*(P|F,12%,2) PW = -5000 + 2000*(3.6048)*(0.7972)

The cash flow diagram for the thermal windows is shown in Figure 4.7. PW = –10000+2525*(P|F,15%,1)+2525*(P|F,15%,2) +2525*(P|F,15%,3)+3840*(P|F,15%,4)+ 3840*(P|F,15%,5)+3840*(P|F,15%,6) PW = –10000+2525*(0.8696)+2525*(0.7561) +2525*(0.6575)+3840*(0.5718)+3840*(0.4972)+ 3840*(0.4323)

PW = -5000.00 + 5747.49 = $747.49 The positive value of present worth indicates an attractive investment. If we repeat the process with an initial cost greater than $5747.49, it should come as no surprise that the present worth will be negative indicating an unattractive investment. The concept of present worth as a measure of investment worth can be generalized as follows: Measure of Worth: Present Worth Description: All cash flows are converted to a single sum equivalent at time zero using i=MARR. n

Calculation Approach:

PW =

Σ At t=0

P|F,i,t

Decision Rule: If PW≥0, then the investment is attractive. Example 13 Installing thermal windows on a small office building is estimated to cost $10,000. The windows are expected to last six years and have no salvage value at that time. The energy savings from the windows are expected to be $2525 each year for the first three years and $3840 for each of the remaining three years. If MARR is 15%/yr and the present worth measure of worth is to be used, is this an attractive investment?

Figure 4.7 Thermal windows investment

PW = –10000+2195.74+1909.15+1660.19+2195.71 +1909.25+1660.03 PW =

$1530.07

Decision: PW≥0 ($1530.07≥0.0), therefore the window investment is attractive. An alternative (and simpler) approach to calculating PW is obtained by recognizing that the savings cash flows are two uniform series; one of value $2525 and length 3 starting at t=1 and one of value $3840 and length 3 starting at t=4. PW =

-10000+2525*(P|A,15%,3)+3840* (P|A,15%,3)*(P|F,15%,3)

PW =

-10000+2525*(2.2832)+3840*(2.2832)* (0.6575) = $1529.70

Decision: PW≥0 ($1529.70>0.0), therefore the window investment is attractive. The slight difference in the PW values is caused by the accumulation of round off errors as the various factors are rounded to four places to the right of the decimal point. 4.7.3 Annual Worth An alternative to present worth is annual worth (AW). The annual worth measure converts all cash flows to an equivalent uniform annual series of cash flows over the investment life using i=MARR. The annual worth measure is generally calculated by first calculating the present worth measure and then multiplying this by the appropriate (A|P,i,n) factor. A thorough review of the tables in Appendix 4A or the equations in Table 4.6 leads to the conclusion that for all values of i (i>0) and n (n>0), the value of (A|P,i,n) is greater than zero. Hence,

56

ENERGY MANAGEMENT HANDBOOK

if PW>0, then AW>0; if PW MARR, the project is attractive, if IRR < MARR, the project is unattractive, if IRR = MARR, indifferent. Thus, if MARR changes, no new calculations are required. We simply compare the calculated IRR for the project to the new value of MARR and we have our decision. The value of IRR is typically determined through a trial and error process. An expression for the present worth of an investment is written without specifying a value for i in the time value of money factors. Then, various values of i are substituted until a value is found that sets the present worth (PW) equal to zero. The value of i found in this way is the IRR. As appealing as the flexibility of this approach is, their are two major drawbacks. First, the iterations required to solve using the trial and error approach to solution can be time consuming. This factor is mitigated by the fact that most spreadsheets and financial calculators are pre-programmed to solve for an IRR value given a cash flow series. The second, and more serious, drawback to the IRR approach is that some cash flow series have more than one value of IRR (i.e., more than one value of i sets the PW expression to zero). A detailed discussion of this multiple solution issue is beyond the scope of this chapter, but can be found in White, et al. [1998], as well as most other economic analysis references. However, it can be shown that, if a cash flow series consists of an initial investment (negative cash flow at t=0) followed by a series of future returns (positive or zero cash flows for all t>0) then a unique IRR exists. If these conditions are not satisfied a unique IRR is not guaranteed and caution should be exercised in making decisions based on IRR. The concept of internal rate of return as a measure of investment worth can be generalized as follows: Measure of Worth: Internal Rate of Return Description: An interest rate, IRR, is determined which yields a present worth of zero. IRR implicitly assumes the reinvestment of recovered funds at IRR. Calculation Approach:

find IRR such that PW =

n

Σ A t P|F,IRR,t t=0

=0

Important Note: Depending upon the cash flow series, multiple IRRs may exist! If the cash flow series consists of an initial investment (net negative cash flow) followed by a series of future returns (net non-negative cash flows), then a unique IRR exists.

ECONOMIC ANALYSIS

Decision Rule: If IRR is unique and IRR ≥MARR, then the investment is attractive.

57

from the present worth decision rule as follows: Starting with the PW decision rule

Example 15 Reconsider the thermal window data of Example 13. If the internal rate of return measure of worth is to be used, is this an attractive investment?

PW ≥0 replacing PW with its calculation expression n

First we note that the cash flow series has a single negative investment followed by all positive returns, therefore, it has a unique value for IRR. For such a cash flow series it can also be shown that as i increases PW decreases.

Σ A t P|F,i,t t=0

which, using the relationship At = Rt - Ct, can be restated n

Σ t=0

From example 11, we know that for i=15%: PW =

-10000+2525*(P|A,15%,3)+3840*(P|A,15%,3)* (P|F,15%,3)

R t – C t P|F,i,t ≥ 0

which can be algebraically separated into n

PW =

-10000+2525*(2.2832)+3840*(2.2832)* (0.6575) = $1529.70

Because PW>0, we must increase i to decrease PW toward zero for i=18%: PW =

PW =

-10000+2525*(P|A,18%,3)+3840* (P|A,18%,3)*(P|F,18%,3) -10000+2525*(2.1743)+3840*(2.1743)* (0.6086) = $571.50

Since PW>0, we must increase i to decrease PW toward zero for i=20%: PW =

-10000+2525*(P|A,20%,3)+3840* (P|A,20%,3)*(P|F,20%,3)

PW =

-10000+2525*(2.1065)+3840*(2.1065)* (0.5787) = -$0.01

Although we could interpolate for a value of i for which PW=0 (rather than -0.01), for practical purposes PW=0 at i=20%, therefore IRR=20%.

≤0

n

C t P|F,i,t Σ R t P|F,i,t – tΣ =0 t=0

≥0

adding the second term to both sides of the inequality n

n

C 1 P|F,i,t Σ R t P|F,i,t ≥ tΣ =0 t=0

≥0

dividing both sides of the inequality by the right side term n

Σ R 1 P|F,i,t

t=0 n

≥1

Σ C 1 P|F,i,t

t=0

which is the decision rule for SIR. The SIR represents the ratio of the present worth of the revenues to the present worth of the costs. If this ratio exceeds one, the investment is attractive. The concept of savings investment ratio as a measure of investment worth can be generalized as follows: Measure of Worth: Savings Investment Ratio

Decision: IRR≥MARR (20%>15%), therefore the window investment is attractive. 4.7.5 Saving Investment Ratio Many companies are accustomed to working with benefit cost ratios. An investment measure of worth which is consistent with the present worth measure and has the form of a benefit cost ratio is the savings investment ratio (SIR). The SIR decision rule can be derived

Description: The ratio of the present worth of positive cash flows to the present worth of (the absolute value of) negative cash flows is formed using i=MARR. n

Calculation Approach : SIR =

Σ R t P|F,i,t

t=0 n

Σ C t P|F,i,t

t=0

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ENERGY MANAGEMENT HANDBOOK

Decision Rule: If SIR ≥1, then the investment is attractive. Example 16 Reconsider the thermal window data of Example 13. If the savings investment ratio measure of worth is to be used, is this an attractive investment?

Measure of Worth: Payback Period Description: The number of years required to recover the initial investment by accumulating net project returns is determined. Calculation Approach: m

From example 13, we know that for i=15%: n

SIR =

Σ R t P|F,i,t t=0 n

Σ C t P|F,i,t t=0 2525*(P|A,15%,3)+3840*(P|A,15%,3)*(P|F,15%,3) SIR = ————————————————————— 1000 11529.70 SIR = ————— = 1.15297 10000.00 Decision: SIR≥1.0 (1.15297>1.0), therefore the window investment is attractive. An important observation regarding the four measures of worth presented to this point (PW, AW, IRR, and SIR) is that they are all consistent and equivalent. In other words, an investment that is attractive under one measure of worth will be attractive under each of the other measures of worth. A review of the decisions determined in Examples 13 through 16 will confirm the observation. Because of their consistency, it is not necessary to calculate more than one measure of investment worth to determine the attractiveness of a project. The rationale for presenting multiple measures which are essentially identical for decision making is that various individuals and companies may have a preference for one approach over another. 4.7.6 Payback Period The payback period of an investment is generally taken to mean the number of years required to recover the initial investment through net project returns. The payback period is a popular measure of investment worth and appears in many forms in economic analysis literature and company procedure manuals. Unfortunately, all too frequently, payback period is used inappropriately and leads to decisions which focus exclusively on short term results and ignore time value of money concepts. After presenting a common form of payback period these shortcomings will be discussed.

PBP = the smallest m such that

Σ A t ≥ C0

t=1

Decision Rule: If PBP is less than or equal to a predetermined limit (often called a hurdle rate), then the investment is attractive. Important Note: This form of payback period ignores the time value of money and ignores returns beyond the predetermined limit. The fact that this approach ignores time value of money concepts is apparent by the fact that no time value of money factors are included in the determination of m. This implicitly assumes that the applicable interest rate to convert future amounts to present amounts is zero. This implies that people are indifferent between $100 today and $100 one year from today, which is an implication that is highly inconsistent with observable behavior. The short-term focus of the payback period measure of worth can be illustrated using the cash flow diagrams of Figure 4.8. Applying the PBP approach above yields a payback period for investment (a) of PBP=2 (1200>1000 @ t=2) and a payback period for investment (b) of PBP=4 (1000300>1000) @ t=4). If the decision hurdle rate is 3 years (a very common rate), then investment (a) is attractive but investment (b) is not. Hopefully, it is obvious that judging (b) unattractive is not good decision making since a $1,000,000 return four years after a $1,000 investment is attractive under almost any value of MARR. In point of fact, the IRR for (b) is 465% so for any value of MARR less than 465%, investment (b) is attractive.

4.8

ECONOMIC ANALYSIS

4.8.1 Introduction The general scenario for economic analysis is that a set of investment alternatives are available and a decision must be made regarding which ones (if any) to accept and which ones (if any) to reject. If the analysis is deterministic, then an assumption is made that cash flow amounts, cash flow timing, and MARR are known with

ECONOMIC ANALYSIS

0

59 600

600

600

600

1

2

3

4

1000

(a)

1,000,000

0

100

100

100

1

2

3

4

1,000 (b)

Figure 4.8 Two investments evaluated using payback period certainty. Frequently, although this assumption does not hold exactly, it is not considered restrictive in terms of potential investment decisions. If however the lack of certainty is a significant issue then the analysis is stochastic and the assumptions of certainty are relaxed using probability distributions and statistical techniques to conduct the analysis. The remainder of this section deals with deterministic economic analysis so the assumption of certainty will be assumed to hold. Stochastic techniques are introduced in Section 4.9.5. 4.8.2 Deterministic Unconstrained Analysis Deterministic economic analysis can be further classified into unconstrained deterministic analysis and constrained deterministic analysis. Under unconstrained analysis, all projects within the set available are assumed to be independent. The practical implication of this independence assumption is that an accept/reject decision can be made on each project without regard to the decisions made on other projects. In general this requires that (1) there are sufficient funds available to undertake all proposed projects, (2) there are no mutually exclusive projects, and (3) there are no contingent projects. A funds restriction creates dependency since, before deciding on a project being evaluated, the evaluator would have to know what decisions had been made on other projects to determine whether sufficient funds were available to undertake the current project. Mutual exclusion creates dependency since acceptance of one of the mutually exclusive projects precludes acceptance of

the others. Contingency creates dependence since prior to accepting a project, all projects on which it is contingent must be accepted. If none of the above dependency situations are present and the projects are otherwise independent, then the evaluation of the set of projects is done by evaluating each individual project in turn and accepting the set of projects which were individually judged acceptable. This accept or reject judgment can be made using either the PW, AW, IRR, or SIR measure of worth. The unconstrained decision rules for each or these measures of worth are restated below for convenience. Unconstrained PW Decision Rule: If PW ≥0, then the project is attractive. Unconstrained AW Decision Rule: If AW ≥0, then the project is attractive. Unconstrained IRR Decision Rule: If IRR is unique and IRR ≥MARR, then the project is attractive. Unconstrained SIR Decision Rule: If SIR ≥1, then the project is attractive. Example 17 Consider the set of four investment projects whose cash flow diagrams are illustrated in Figure 4.9. If MARR is 12%/yr and the analysis is unconstrained, which projects should be accepted? Using present worth as the measure of worth: PWA = -1000+600*(P|A,12%,4) = -1000+600(3.0373) = $822.38 ⇒ Accept A PWB = -1300+800*(P|A,12%,4) = -1300+800(3.0373) = $1129.88 ⇒ Accept B PWC = -400+120*(P|A,12%,4) = -400+120(3.0373) = -$35.52 ⇒ Reject C PWD = -500+290*(P|A,12%,4) = -500+290(3.0373) = $380.83 ⇒ Accept D Therefore, Accept Projects A, B, and D and Reject Project C 4.8.3 Deterministic Constrained Analysis Constrained analysis is required any time a dependency relationship exists between any of the projects

60

ENERGY MANAGEMENT HANDBOOK

within the set to be analyzed. In general dependency exists any time (1) there are insufficient funds available to undertake all proposed projects (this is commonly referred to as capital rationing), (2) there are mutually exclusive projects, or (3) there are contingent projects. Several approaches have been proposed for selecting the best set of projects from a set of potential projects under constraints. Many of these approaches will select the optimal set of acceptable projects under some conditions or will select a set that is near optimal. However, only a few approaches are guaranteed to select the optimal set of projects under all conditions. One of these approaches is presented below by way of a continuation of Example 17. The first steps in the selection process are to specify the cash flow amounts and cash flow timings for each project in the potential project set. Additionally, a value of MARR to be used in the analysis must be specified. These issues have been addressed in previous sections so further discussion will be omitted here. The next step is to form the set of all possible decision alternatives from the projects. A single decision alternative is a collection of zero, one, or more projects which could be accepted (all others not specified are to be rejected). As an illustration, the possible decision alternatives for the set of projects illustrated in Figure 4.9 are listed in Table 4.7. As a general rule, there will be 2n possible decision alternatives generated from a set of n projects. Thus, for the projects of Figure 4.9, there are 24 = 16 possible decision alternatives. Since this set represents all possible decisions that could be made, one, and only one, will be selected as the best (optimal) decision. The set of decision alternatives developed in this way has the properties of being collectively exhaustive (all possible choices are listed) and mutually exclusive (only one will be selected).

0

600

600

1

2

1000

3

1

120 2

Project B is contingent on Project C, and A budget limit of $1500 exists on capital expenditures at t=0. Based on these constraints the following decision alternatives must be removed from the collectively exhaustive, mutually exclusive set: any combination that includes B but not C (B only; A&B; B&D; A&B&D), any combination not already eliminated whose t=0 costs exceed $1500 (B&C, A&B&C, A&C&D, B&C&D, A&B&C&D). Thus, from the original set of 16 possible decision alternatives, 9 have been eliminated and need not be evaluated. These results are illustrated in Table 4.8. It is frequently the case in practice that a significant percentage of the original collectively exhaustive, mutually exclusive set will be eliminated before measures of worth are calculated. The next step is to create the cash flow series for the remaining (feasible) decision alternatives. This is a straight forward process and is accomplished by setting a decision alternative’s annual cash flow equal to the sum of the annual cash flows (on a year by year basis) of all projects contained in the decision alternative. Table 4.9 illustrates the results of this process for the feasible decision alternatives from Table 4.8. The next step is to calculate a measure of worth for each decision alternative. Any of the four consistent measures of worth presented above (PW, AW, IRR, 800

600

4

0

1

1,300

Project A

120 0

600

The next step in the process is to eliminate decisions from the collectively exhaustive, mutually exclusive set that represent choices which would violate one (or more) of the constraints on the projects. For the projects of Figure 4.9, assume the following two constraints exist:

120 3

120 4

0

800

800

2

3

500

Figure 4.9 Four investments projects

4

Project B

290

290

290

290

1

2

3

4

400 Project C

800

Project D

ECONOMIC ANALYSIS

61

or SIR but NOT PBP) can be used. The measures are entirely consistent and will lead to the same decision alternative being selected. For illustrative purposes, PW will be calculated for the decision alternatives of Table 4.9 assuming MARR=12%. PWA =

-1000 + 600*(P|A,12%,4) = 1000 + 600 (3.0373) = $822.38

PWC =

-400 + 120*(P|A,12%,4) = 400 + 120 (3.0373) = -$35.52

PWD =

-500 + 290*(P|A,12%,4) = 500 + 290 (3.0373) = $380.83

PWA&C = -1400 + 720*(P|A,12%,4) = 1400 + 720 (3.0373) = $786.86 PWA&D = -1500 + 890*(P|A,12%,4) = -1500 + 890 (3.0373) = $1203.21 PWC&D = -900 + 410*(P|A,12%,4) = 900 + 410 (3.0373) = $345.31

Table 4.7 The decision alternatives from four projects ———————————————————————— Accept A only Accept B only Accept C only Accept D only ———————————————————————— Accept A and B only Accept A and C only Accept A and D only Accept B and C only Accept B and D only Accept C and D only ———————————————————————— Accept A, B, and C only Accept A, B, and D only Accept A, C, and D only Accept B, C, and D only ———————————————————————— Accept A, B, C, and D (frequently called the do everything alternative) ———————————————————————— Accept none (frequently called the do nothing or null alternative) ————————————————————————

PWnull = -0 + 0*(P|A,12%,4) = -0 + 0 (3.0373) = $0.00

Table 4.8 The decision alternatives with constraints imposed ———————————————————————————————————— Accept A only OK Accept B only infeasible, B contingent on C Accept C only OK Accept D only OK ———————————————————————————————————— Accept A and B only infeasible, B contingent on C Accept A and C only OK Accept A and D only OK Accept B and C only infeasible, capital rationing Accept B and D only infeasible, B contingent on C Accept C and D only OK ———————————————————————————————————— Accept A, B, and C only infeasible, capital rationing Accept A, B, and D only infeasible, B contingent on C Accept A, C, and D only infeasible, capital rationing Accept B, C, and D only infeasible, capital rationing ———————————————————————————————————— Do Everything infeasible, capital rationing ———————————————————————————————————— null OK ————————————————————————————————————

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ENERGY MANAGEMENT HANDBOOK

The decision rules for the various measures of worth under constrained analysis are list below.

•

The internal rate of return of a decision alternative is NOT the sum of internal rates of returns of the projects contained within the alternative. The IRR for the decision alternative must be calculated by the trial and error process of finding the value of i that sets the PW of the decision alternative to zero.

•

The savings investment ratio of a decision alternative is NOT the sum of the savings investment ratios of the projects contained within the alternative. The SIR for the decision alternative must be calculated from the cash flows of the decision alternative.

•

A common, but flawed, procedure for selecting the projects to accept from the set of potential projects involves ranking the projects (not decision alternatives) in preferred order based on a measure of worth calculated for the project (e.g., decreasing project PW) and then accepting projects as far down the list as funds allow. While this procedure will select the optimal set under some conditions (e.g., it works well if the initial investments of all projects are small relative to the capital budget limit), it is not guaranteed to select the optimal set under all conditions. The procedure outlined above will select the optimal set under all conditions.

•

Table 4.10 illustrates that the number of decision alternatives in the collectively exhaustive, mutually exclusive set can grow prohibitively large as the number of potential projects increases. The mitigating factor in this combinatorial growth problem is that in most practical situations a high percentage of the possible decision alternatives are infeasible and do not require evaluation.

Constrained PW Decision Rule: Accept the decision alternative with the highest PW. Constrained AW Decision Rule: Accept the decision alternative with the highest AW. Constrained IRR Decision Rule: Accept the decision alternative with the highest IRR. Constrained SIR Decision Rule: Accept the decision alternative with the highest SIR. For the example problem, the highest present worth ($1203.21) is associated with accepting projects A and D (rejecting all others). This decision is guaranteed to be optimal (i.e., no feasible combination of projects has a higher PW, AW, IRR, or SIR). 4.8.4 Some Interesting Observations Regarding Constrained Analysis Several interesting observations can be made regarding the approach, measures of worth, and decisions associated with constrained analysis. Detailed development of these observations is omitted here but may be found in many engineering economic analysis texts [White, et al., 1998]. •

The present worth of a decision alternative is the sum of the present worths of the projects contained within the alternative. (From above PWA&D = PWA + PWD).

•

The annual worth of a decision alternative is the sum of the annual worths of the projects contained within the alternative.

Table 4.9 The decision alternatives cash flows yr \ Alt A only C only D only A&C A&D C&D null —————————————————————————————————————————— 0 -1000 -400 -500 -1400 -1500 -900 0 —————————————————————————————————————————— 1 600 120 290 720 890 410 0 —————————————————————————————————————————— 2 600 120 290 720 890 410 0 —————————————————————————————————————————— 3 600 120 290 720 890 410 0 —————————————————————————————————————————— 4 600 120 290 720 890 410 0

ECONOMIC ANALYSIS

63

Table 4.10 The number of decision alternatives as a function of the number of projects

Number of Projects

Number of Decision Alternatives

1

2

2

4

3

8

4

16

5

32

6

64

7

128

8

256

9

512

10

1,024

15

32,768

20

1,048,576

25

33,554,432

4.8.5 The Planning Horizon Issue When comparing projects, it is important to compare the costs and benefits over a common period of time. The intuitive sense of fairness here is based upon the recognition that most consumers expect an investment that generates savings over a longer period of time to cost more than an investment that generates savings over a shorter period of time. To facilitate a fair, comparable evaluation a common period of time over which to conduct the evaluation is required. This period of time is referred to as the planning horizon. The planning horizon issue arises when at least one project has cash flows defined over a life which is greater than or less than the life of at least one other project. This situation did not occur in Example 17 of the previous section since all projects had 4 year lives. There are four common approaches to establishing a planning horizon for evaluating decision alternatives. These are (1) shortest life, (2) longest life, (3) least common multiple of lives, and (4) standard. The shortest life planning horizon is established by selecting the project with the shortest life and setting this life as the planning horizon. A significant issue in this approach is how to value the remaining cash flows for projects whose lives are truncated. The typical approach to this valuation is to estimate the value of the remaining cash flows as the salvage value (market value) of the investment at that point in its life.

Example 18 Determine the shortest life planning horizon for projects A, B, C with lives 3, 5, and 6 years, respectively. The shortest life planning horizon is 3 years based on Project A. A salvage value must be established at t=3 for B’s cash flows in years 4 and 5. A salvage value must be established at t=3 for C’s cash flows in years 4, 5, and 6. The longest life planning horizon is established by selecting the project with the longest life and setting this life as the planning horizon. The significant issue in this approach is how to handle projects whose cash flows don’t extend this long. The typical resolution for this problem is to assume that shorter projects are repeated consecutively (end-to-end) until one of the repetitions extends at least as far as the planning horizon. The assumption of project repeatability deserves careful consideration since in some cases it is reasonable and in others it may be quite unreasonable. The reasonableness of the assumption is largely a function of the type of investment and the rate of innovation occurring within the investment’s field (e.g., assuming repeatability of investments in high technology equipment is frequently ill advised since the field is advancing rapidly). If in repeating a project’s cash flows, the last repetition’s cash flows extend beyond the planning horizon, then the truncated cash flows (those that extend beyond the planning horizon) must be assigned a salvage value as above. Example 19 Determine the longest life planning horizon for projects A, B, C with lives 3, 5, and 6 years, respectively. The longest life planning horizon is 6 years based on Project C. Project A must be repeated twice, the second repetition ends at year 6, so no termination of cash flows is required. Project B’s second repetition extends to year 10, therefore, a salvage value at t=6 must be established for B’s repeated cash flows in years 7, 8, 9, and 10. An approach that eliminates the truncation salvage value issue from the planning horizon question is the least common multiple approach. The least common multiple planning horizon is set by determining the smallest number of years at which repetitions of all projects would terminate simultaneously. The least common multiple for a set of numbers (lives) can be determined mathematically using algebra. Discussion of this ap-

64

proach is beyond the scope of this chapter. For a small number of projects, the value can be determined by trial and error by examining multiples of the longest life project. Example 20 Determine the least common multiple planning horizon for projects A, B, C with lives 3, 5, and 6 years, respectively. The least common multiple of 3, 5, and 6 is 30. This can be obtained by trial and error starting with the longest project life (6) as follows: 1st trial: 6*1=6; 6 is a multiple of 3 but not 5; reject 6 and proceed 2nd trial: 6*2=12; 12 is a multiple of 3 but not 5; reject 12 and proceed 3rd trial: 6*3=18; 18 is a multiple of 3 but not 5; reject 18 and proceed 4th trial: 6*4=24; 24 is a multiple of 3 but not 5; reject 24 and proceed 5th trial: 6*5=30; 30 is a multiple of 3 and 5; accept 30 and stop Under a 30-year planning horizon, A’s cash flows are repeated 10 times, B’s 6 times, and C’s 5 times. No truncation is required. The standard planning horizon approach uses a planning horizon which is independent of the projects being evaluated. Typically, this type of planning horizon is based on company policies or practices. The standard horizon may require repetition and/or truncation depending upon the set of projects being evaluated. Example 21 Determine the impact of a 5 year standard planning horizon on projects A, B, C with lives 3, 5, and 6 years, respectively. With a 5-year planning horizon: Project A must be repeated one time with the second repetition truncated by one year. Project B is a 5 year project and does not require repetition or truncation. Project C must be truncated by one year.

ENERGY MANAGEMENT HANDBOOK

There is no single accepted approach to resolving the planning horizon issue. Companies and individuals generally use one of the approaches outlined above. The decision of which to use in a particular analysis is generally a function of company practice and consideration of the reasonableness of the project repeatability assumption and the availability of salvage value estimates at truncation points. 4.9

SPECIAL PROBLEMS

4.9.1 Introduction The preceding sections of this chapter outline an approach for conducting deterministic economic analysis of investment opportunities. Adherence to the concepts and methods presented will lead to sound investment decisions with respect to time value of money principles. This section addresses several topics that are of special interest in some analysis situations. 4.9.2 Interpolating Interest Tables All of the examples previously presented in this chapter conveniently used interest rates whose time value of money factors were tabulated in Appendix 4A. How does one proceed if non-tabulated time value of money factors are needed? There are two viable approaches; calculation of the exact values and interpolation. The best and theoretically correct approach is to calculate the exact values of needed factors based on the formulas in Table 4.6. Example 22 Determine the exact value for (F|P,13%,7). From Table 4.6, (F|P,i,n) = (1+i)n = (1+.13)7 = 2.3526 Interpolation is often used instead of calculation of exact values because, with practice, interpolated values can be calculated quickly. Interpolated values are not “exact” but for most practical problems they are “close enough,” particularly if the range of interpolation is kept as narrow as possible. Interpolation of some factors, for instance (P|A,i,n), also tends to be less error prone than the exact calculation due simpler mathematical operations. Interpolation involves determining an unknown time value of money factor using two known values which bracket the value of interest. An assumption is made that the values of the time value of money factor vary linearly between the known values. Ratios are then

ECONOMIC ANALYSIS

65

used to estimate the unknown value. The example below illustrates the process. Example 23 Determine an interpolated value for (F|P,13%,7). The narrowest range of interest rates which bracket 13% and for which time value of money factor tables are provided in Appendix 4A is 12% to 15%. The values necessary for this interpolation are

i values

(F|P,i%,7)

12%

2.2107

13%

(F|P,13%,7)

15%

2.6600

12% per year compounded monthly or 12%/yr/mo. When expressed in this form, 12%/yr/mo is known as the nominal annual interest rate The techniques covered in this chapter up to this point can not be used directly to solve an economic analysis problem of this type because the interest period (per year) and compounding period (monthly) are not the same. Two approaches can be used to solve problems of this type. One approach involves determining a period interest rate, the other involves determining an effective interest rate. To solve this type of problem using a period interest rate approach, we must define the period interest rate: Nominal Annual Interest Rate Period Interest Rate = ——————————————— Number of Interest Periods per Year In our example,

The interpolation proceeds by setting up ratios and solving for the unknown value, (F|P,13%,7), as follows: change between rows 2 & 1 of left column ——————————————————— = change between rows 3 & 1 of left column 0.13 – 0.12 ————— 0.15 – 0.12 0.01 —— 0.03

=

=

(F|P,13%,7) – 2.2107 ————————— 2.6600 – 2.2107

(F|P,13%,7) – 2.2107 ————————— 0.4493

0.1498 = (F|P,13%,7) – 2.2107 (F|P,13%,7) = 2.3605 The interpolated value for (F|P,13%,7), 2.3605, differs from the exact value, 2.3526, by 0.0079. This would imply a $7.90 difference in present worth for every thousand dollars of return at t=7. The relative importance of this interpolation error can be judged only in the context of a specific problem. 4.9.3 Non-Annual Interest Compounding Many practical economic analysis problems involve interest that is not compounded annually. It is common practice to express a non-annually compounded interest rate as follows:

12%/yr/mo Period Interest Rate = ——————— = 1%/mo/mo 12 mo/yr Because the interest period and the compounding period are now the same, the time value of money factors in Appendix 4A can be applied directly. Note however, that the number of interest periods (n) must be adjusted to match the new frequency. Example 24 $2,000 is invested in an account which pays 12% per year compounded monthly. What is the balance in the account after 3 years? Nominal Annual Interest Rate = 12%/yr/mo 12%/yr/mo Period Interest Rate = ——————— = 1%/mo/mo 12 mo/yr Number of Interest Periods = 3 years × 12 mo/yr = 36 interest periods (months) F = P (F|P,i,n) = $2,000 (F|P,1,36) = $2,000 (1.4308) = $2,861.60 Example 25 What are the monthly payments on a 5-year car loan of $12,500 at 6% per year compounded monthly? Nominal Annual Interest Rate = 6%/yr/mo Period Interest Rate

6%/yr/mo = ————— 12 mo/yr

= 0.5%/mo/mo

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Number of Interest Periods = 5 years × 12 mo/yr = 60 interest periods A = P (A|P,i,n) = $12,500 (A|P,0.5,60) = $12,500 (0.0193) = $241.25 To solve this type of problem using an effective interest rate approach, we must define the effective interest rate. The effective annual interest rate is the annualized interest rate that would yield results equivalent to the period interest rate as previously calculated. Note however that the effective annual interest rate approach should not be used if the cash flows are more frequent than annual (e.g., monthly). In general, the interest rate for time value of money factors should match the frequency of the cash flows (e.g., if the cash flows are monthly, use the period interest rate approach with monthly periods). As an example of the calculation of an effective interest rate, assume that the nominal interest rate is 12%/ yr/qtr, therefore the period interest rate is 3%/qtr/qtr. One dollar invested for 1 year at 3%/qtr/qtr would have a future worth of: F = P (F|P,i,n) = $1 (F|P,3,4) = $1 (1.03)4 = $1 (1.1255) = $1.1255 To get this same value in 1 year with an annual rate the annual rate would have to be of 12.55%/yr/yr. This value is called the effective annual interest rate. The effective annual interest rate is given by (1.03)4 - 1 = 0.1255 or 12.55%. The general equation for the Effective Annual Interest Rate is: Effective Annual Interest Rate = (1 + (r/m))m–1 where: r = nominal annual interest rate m = number of interest periods per year Example 26 What is the effective annual interest rate if the nominal rate is 12%/yr compounded monthly? nominal annual interest rate = 12%/yr/mo period interest rate = 1%/mo/mo effective annual interest rate = (1+0.12/12)12 -1 = 0.1268 or 12.68% 4.9.4 Economic Analysis Under Inflation Inflation is characterized by a decrease in the purchasing power of money caused by an increase in general price levels of goods and services without an

accompanying increase the value of the goods and services. Inflationary pressure is created when more dollars are put into an economy without an accompanying increase in goods and services. In other words, printing more money without an increase in economic output generates inflation. A complete treatment of inflation is beyond the scope of this chapter. A good summary can be found in Sullivan and Bontadelli [1980]. When consideration of inflation is introduced into economic analysis, future cash flows can be stated in terms of either constant-worth dollars or then-current dollars. Then-current cash flows are expressed in terms of the face amount of dollars (actual number of dollars) that will change hands when the cash flow occurs. Alternatively, constant-worth cash flows are expressed in terms of the purchasing power of dollars relative to a fixed point in time known as the base period. Example 27 For the next 4 years, a family anticipates buying $1000 worth of groceries each year. If inflation is expected to be 3%/yr what are the then-current cash flows required to purchase the groceries. To buy the groceries, the family will need to take the following face amount of dollars to the store. We will somewhat artificially assume that the family only shops once per year, buys the same set of items each year, and that the first trip to the store will be one year from today. Year Year Year Year

1: 2: 3: 4:

dollars dollars dollars dollars

required required required required

$1000.00*(1.03)=$1030.00 $1030.00*(1.03)=$1060.90 $1060.90*(1.03)=$1092.73 $1092.73*(1.03)=$1125.51

What are the constant-worth cash flows, if today’s dollars are used as the base year. The constant worth dollars are inflation free dollars, therefore the $1000 of groceries costs $1000 each year. Year Year Year Year

1: 2: 3: 4:

$1000.00 $1000.00 $1000.00 $1000.00

The key to proper economic analysis under inflation is to base the value of MARR on the types of cash flows. If the cash flows contain inflation, then the

ECONOMIC ANALYSIS

value of MARR should also be adjusted for inflation. Alternatively, if the cash flows do not contain inflation, then the value of MARR should be inflation free. When MARR does not contain an adjustment for inflation, it is referred to as a real value for MARR. If it contains an inflation adjustment, it is referred to as a combined value for MARR. The relationship between inflation rate, the real value of MARR, and the combined value of MARR is given by: 1 + MARRCOMBINED= (1 + inflation rate) * (1 + MARRREAL) Example 28 If the inflation rate is 3%/yr and the real value of MARR is 15%/yr, what is the combined value of MARR? 1 + MARRCOMBINED = (1 + inflation rate) * (1 + MARRREAL) 1 + MARRCOMBINED= (1 + 0.03) * (1 + 0.15) 1 + MARRCOMBINED= (1.03) * (1.15) 1 + MARRCOMBINED= 1.1845 MARRCOMBINED= 1.1845 - 1 = 0.1845 = 18.45% If the cash flows of a project are stated in terms of then-current dollars, the appropriate value of MARR is the combined value of MARR. Analysis done in this way is referred to as then-current analysis. If the cash flows of a project are stated in terms of constant-worth dollars, the appropriate value of MARR is the real value of MARR. Analysis done in this way is referred to as then constant worth analysis. Example 29 Using the cash flows of Examples 27 and interest rates of Example 28, determine the present worth of the grocery purchases using a constant worth analysis. Constant worth analysis requires constant worth cash flows and the real value of MARR. PW = 1000 * (P|A,15%,4) = 1000 * (2.8550) = $2855.00

67

PW =

1030.00 * (P|F,18.45%,1) + 1060.90 * (P|F,18.45%,2) + 1092.73 * (P|F,18.45%,3) +1125.51 * (P|F,18.45%,4)

PW =

1030.00 * (0.8442) + 1060.90 * (0.7127) + 1092.73 * (0.6017) +1125.51 * (0.5080)

PW =

869.53 + 756.10 + 657.50 + 571.76 = 2854.89

The notable result of Examples 29 and 30 is that the present worths determined by the constant-worth approach ($2855.00) and the then-current approach ($2854.89) are equal (the $0.11 difference is due to rounding). This result is often unexpected but it is mathematically sound. The important conclusion is that if care is taken to appropriately match the cash flows and value of MARR, the level of general price inflation is not a determining factor in the acceptability of projects. To make this important result hold, inflation must either (1) be included in both the cash flows and MARR (the then-current approach) or (2) be included in neither the cash flows nor MARR (the constantworth approach). 4.9.5 Sensitivity Analysis and Risk Analysis Often times the certainty assumptions associated with deterministic analysis are questionable. These certainty assumptions include certain knowledge regarding amounts and timing of cash flows as well as certain knowledge of MARR. Relaxing these assumptions requires the use of sensitivity analysis and risk analysis techniques. Initial sensitivity analyses are usually conducted on the optimal decision alternative (or top two or three) on a single factor basis. Single factor sensitivity analysis involves holding all cost factors except one constant while varying the remaining cost factor through a range of percentage changes. The effect of cost factor changes on the measure of worth is observed to determine whether the alternative remains attractive under the evaluated changes and to determine which cost factor affects the measure of worth the most.

Example 30 Using the cash flows of Examples 27 and interest rates of Example 28, determine the present worth of the grocery purchases using a then-current analysis.

Example 31 Conduct a sensitivity analysis of the optimal decision resulting from the constrained analysis of the data in Example 17. The sensitivity analysis should explore the sensitivity of present worth to changes in annual revenue over the range -10% to +10%.

Then-current analysis requires then current cash flows and the combined value of MARR.

The PW of the optimal decision (Accept A & D only) was determined in Section 4.8.3 to be:

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PWA&D = -1500 + 890*(P|A,12%,4) = -1500 + 890 (3.0373) = $1203.21 If annual revenue decreases 10%, it becomes 890 - 0.10*890 = 801 and PW becomes PWA&D = -1500 + 801*(P|A,12%,4) = -1500 + 801 (3.0373) = $932.88 If annual revenue increases 10%, it becomes 890 + 0.10*890 = 979 and PW becomes PWA&D = -1500 + 979*(P|A,12%,4) = -1500 + 979 (3.0373) = $1473.52 The sensitivity of PW to changes in annual revenue over the range -10% to +10% is +$540.64 from $932.88 to $1473.52. Example 32 Repeat Example 31 exploring of the sensitivity of present worth to changes in initial cost over the range -10% to +10%. The PW of the optimal decision (Accept A & D only) was determined in Section 4.8.3 to be: PWA&D = -1500 + 890*(P|A,12%,4) = -1500 + 890 (3.0373) = $1203.21 If initial cost decreases 10% it becomes 1500 0.10*1500 = 1350 and PW becomes PWA&D = -1350 + 890*(P|A,12%,4) = -1350 + 890 (3.0373) = $1353.20 If initial cost increases 10% it becomes 1500 + 0.10*1500 = 1650 and PW becomes PWA&D = -1650 + 890*(P|A,12%,4) = -1500 + 890 (3.0373) = $1053.20 The sensitivity of PW to changes in initial cost over the range -10% to +10% is -$300.00 from $1353.20 to $1053.20. Example 33 Repeat Example 31 exploring the sensitivity of the present worth to changes in MARR over the range -10% to +10%. The PW of the optimal decision (Accept A & D only) was determined in Section 4.8.3 to be:

PWA&D = -1500 + 890*(P|A,12%,4) = -1500 + 890 (3.0373) = $1203.21 If MARR decreases 10% it becomes 12% - 0.10*12% = 10.8% and PW becomes PWA&D = -1500 + 890*(P|A,10.8%,4) = -1500 + 890 (3.1157) = $1272.97 If MARR increases 10% it becomes 12% + 0.10*12% = 13.2% and PW becomes PWA&D = -1500 + 890*(P|A,13.2%,4) = -1500 + 890 (2.9622) = $1136.36 The sensitivity of PW to changes in MARR over the range -10% to +10% is -$136.61 from $1272.97 to $1136.36. The sensitivity data from Examples 31, 32, and 33 are summarized in Table 4.11. A review of the table reveals that the decision alternative A&D remains attractive (PW ≥0) within the range of 10% changes in annual revenues, initial cost, and MARR. An appealing way to summarize single factor sensitivity data is using a “spider” graph. A spider graph plots the PW values determined in the examples and connects them with lines, one line for each factor evaluated. Figure 4.10 illustrates the spider graph for the data of Table 4.11. On this graph, lines with large positive or negative slopes (angle relative to horizontal regardless of whether it is increasing or decreasing) indicate factors to which the present value measure of worth is sensitive. Figure 4.10 shows that PW is least sensitive to changes in MARR (the MARR line is the most nearly horizontal) and most sensitivity to changes in annual revenue (the annual revenue line has the steepest slope). Additional sensitivities could be explored in a similar manner. Table 4.11 Sensitivity analysis data table Factor \ Percent Change

- 10%

Base

+ 10%

1st Cost

1353.20

1203.21

1053.20

Annual Revenue

932.88

1203.21

1473.52

MARR

1272.97

1203.21

1136.36

When single factor sensitivity analysis is inadequate to assess the questions which surround the certainty assumptions of a deterministic analysis, risk

ECONOMIC ANALYSIS

69

Figure 4.10. Sensitivity analysis “spider” graph analysis techniques can be employed. One approach to risk analysis is the application of probabilistic and statistical concepts to economic analysis. These techniques require information regarding the possible values that uncertain quantities may take on as well as estimates of the probability that the various values will occur. A detailed treatment of this topic is beyond the scope of this chapter. A good discussion of this subject can be found in Park and Sharp-Bette [1990]. A second approach to risk analysis in economic analysis is through the use of simulation techniques and simulation software. Simulation involves using a computer simulation program to sample possible values for the uncertain quantities in an economic analysis and calculating the measure of worth. This process is repeated many times using different samples each time. After many samples have been taken, probability statements regarding the measure of worth may be made. A good discussion of this subject can be found in Park and Sharp-Bette [1990].

4.10 SUMMARY AND ADDITIONAL EXAMPLE APPLICATIONS In this chapter a coherent, consistent approach to economic analysis of capital investments (energy related or other) has been presented. To conclude the chapter, this section provides several additional examples to illustrate the use of time value of money concepts for energy related problems. Additional example applications

as well as a more in depth presentation of conceptual details can be found in the references listed at the end of the chapter. These references are by no means exclusive; many other excellent presentations of the subject matter are also available. Adherence to the concepts and methods presented here and in the references will lead to sound investment decisions with respect to time value of money principles. Example 34 In Section 4.3.3 an example involving the evaluation of a baseboard heating and window air conditioner versus a heat pump was introduced to illustrate cash flow diagramming (Figure 4.2). A summary of the differential costs is repeat here for convenience. •

The heat pump costs $1500 more than the baseboard system,

•

The heat pump saves $380 annually in electricity costs,

•

The heat pump has a $50 higher annual maintenance costs,

•

The heat pump has a $150 higher salvage value at the end of 15 years,

•

The heat pump requires $200 more in replacement maintenance at the end of year 8.

If MARR is 18%, is the additional investment in the heat pump attractive?

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Using present worth as the measure of worth: PW =

-1500 + 380*(P|A,18%,15) - 50*(P|A,18%,15) + 150*(P|F,18%,15) - 200*(P|F,18%,8)

PW =

-1500 + 380*(5.0916) - 50*(5.0916) + 150*(0.0835) - 200*(0.2660)

PW =

-1500.00 + 1934.81 - 254.58 + 12.53 - 53.20 = $139.56

Decision: PW≥0 ($139.56>0.0), therefore the additional investment for the heat pump is attractive. Example 35 A homeowner needs to decide whether to install R-11 or R-19 insulation in the attic of her home. The R-19 insulation costs $150 more to install and will save approximately 400 kWh per year. If the planning horizon is 20 years and electricity costs $0.08/kWh is the additional investment attractive at MARR of 10%? At $0.08/kWh, the annual savings are: 400 kWh * $0.08/kWh = $32.00

Example 37 An economizer costs $20,000 and will last 10 years. It will generate savings of $3,500 per year with maintenance costs of $500 per year. If MARR is 10%, is the economizer an attractive investment? Using present worth as the measure of worth: PW = -20000 + 3500*(P|A,10%,10) - 500*(P|A,10%,10) PW = -20000 + 3500*(6.1446) - 500*(6.1446) PW = -20000.00 + 21506.10 - 3072.30 = -$1566.20 Decision: PW 0 > 0 Block 1 Energy Charge: $0.09444 $0.09444 No. of Demand Blocks: 2 2 Block 1 Size: 1 1 Block 2 Size: > 1 > 1 Block 1 Demand Charge: $4.53 $4.53 Block 2 Demand Charge: $7.84 $8.89 ———————————————————————————————— BILLING DEMAND: Estimated by dividing kWh usage by 100 or, if metered, greatest average 30-minute demand in the month. ————————————————————————————————

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Block 2 - (150 kWh × 32 kW), or 4,800 kWh @ $0.02712 = Block 3 - (all remaining kWh), or 6,403 kWh @ $0.01173 = Energy Cost Adjustment: (16,003 × $0.01418) Demand Charge: (32 kW × $5.023) Subtotal: Tax Rate: 25% of first $50 of subtotal 12% on remainder of subtotal Total Monthly Charge:

the price signal and has relatively little on-peak usage. $130.18 $75.11 $226.92 $160.74 $846.44 $12.50 $95.57 $954.51

Time-of-Use Rates Time-of-use rates are calculated very differently from general service rates. The customer’s use must be recorded on a time-of-use meter, so that billing can be calculated on the use in each time period. In the following sample calculation from Long Island Lighting Company (Table 18.4), we assume the customer has responded to

Energy Usage - 1,200 kWh; Season - Summer; On-Peak Period - 10:00 AM-8:00 PM, Monday-Friday; On-Peak Usage - 12.5% Customer Charge: $9.79 Energy Charge: $176.53 150 on-peak kWh @ $0.3739 = $56.09 1050 off-peak kWh @ $0.1147 = $120.44 Energy Cost Adjustment: $2.88 Tax: $10.02 Total Monthly Charge: $199.22 18.5.2 Gas General Service Rates Gas general service rates are calculated in a similar manner to the electric general service rates. Gas rates are priced in dollars per MMBtu, or in dollars per MCF, depending upon the individual utility’s unit of measurement.

Table 18.3 Energy usage measured in kWh per kW of demand. —————————————————————————————————————————————— Company: Virginia Electric & Power Company Rate Class: Commercial Rate Type: General Service Rate Name: Schedule GS-2 - Intermediate Effective Date: 1/01/94 Qualifications: Non-residential use with at least three billing demands => 30 kW in the current and previous 11 billing months; but not more than two billing months of 500 kW or more. —————————————————————————————————————————————— OCT-MAY JUN-SEP Customer Charge: $21.17 $21.17 Minimum Charge: See Note See Note Energy Cost Adjustment: $0.01418 $0.01418 Tax Rate: See Note See Note No. of Energy Blocks: 3 3 Block 1 Size: 150 kWh/kW demand 150 kWh/kW demand Block 2 Size: 150 kWh/kW demand 150 kWh/kW demand Block 3 Size: > 300 kWh/kW demand > 300 kWh/kW demand Block 1 Energy Charge: $0.0484 $0.0484 Block 2 Energy Charge: $0.02712 $0.02712 Block 3 Energy Charge: $0.01173 $0.01173 No. of Demand Blocks: 1 1 Block 1 Size: >0 >0 Block 1 Demand Charge: $5.023 $6.531 —————————————————————————————————————————————— MINIMUM CHARGE: Greater of: 1) contract amount; or 2) sum of customer charge, energy charge and adjustments, plus $1.604 times the maximum average 30-minute demand measured in the month. TAX: Tax is 25% of the first $50, and 12% of the excess. BILLING DEMAND: Maximum average 30-minute demand measured in the month, but not less than the maximum demand determined in the current and previous 11 months when measured demand has reached 500 kW or more. ——————————————————————————————————————————————

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513

Table 18.4 Electric time-of-use rate. ———————————————————————————————— Company: Long Island Lighting Company Rate Class: Residential Rate Type: Time-of-Use Rate Name: Schedule SC 1-VMRP, Rate 2 Effective Date: 04/11/95 Qualifications: Use for all residential purposes where consumption is 39,000 kWh or less for year ending September 30, or under 12,600 kWh for June through September. ———————————————————————————————— OCT-MAY JUN-SEP Customer Charge: $9.79 $9.79 Minimum Charge: $16.53 $16.53 Energy Cost Adjustment: $0.0024 $0.0024 Tax Rate: 5.29389% 5.29389% No. of Energy Blocks: 1 1 Block 1 Size: > 0 > 0 Block 1 Energy Charge: On-Peak: $0.1519 $0.3739 Off-Peak: $0.0978 $0.1147 ———————————————————————————————— TAX: applied to total bill PEAK PERIOD: On-Peak Hours: 10 a.m.-8 p.m., MON-FRI. Off-Peak Hours: All remaining hours. ————————————————————————————————

Commercial General Service Rate with Demand Component Gas rates for the commercial or industrial customer may involve a demand charge. The method for calculating this type of bill is done in the same manner as an electric rate with a demand charge. The example in Table 18.5 comes from Northern Illinois Gas Company. Energy Usage - 11,500 MMBtu; Billing Demand - 400 MMBtu; Season - Winter Customer Charge: $325.00 Energy Charge: $4,899.00 Purchased Gas Adjustment (Energy Cost Adjustment): $28,221.00 Demand Charge: $2,828.00 Tax: $1,849.92 Total Charge: $38,122.92 18.6 CONDUCTING A LOAD STUDY Once a customer understands how utility rates are implemented, he/she can perform a simple load study

to make use of this information. A load study will help the energy user to identify his load patterns, amount and time of occurrence of maximum load, and the load factor. This information can be used to modify use in ways that can lower electric or gas bills. It can also help the customer to determine the most appropriate rate to use. The basic steps of a utility load study are shown in Table 18.6. The first step is to collect historical load data. Past bills are one source for this information. One year of data is necessary to identify seasonal patterns; two or more years of data is preferable. Select a study period that is fairly representative of normal consumption conditions. The next step is to organize the data so that use patterns are evident. One way to analyze the data is to plot the kWh usage, the maximum demand, and the load factor. The load factor is the ratio of the average demand to the maximum demand. The average demand is determined by the usage in kWh divided by the total number of hours (24 × number of days) in the billing period. The number of days in the billing period may vary depending on how often the meter is read. (See Table 18.7.)

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Table 18.5 Commercial gas rate with demand component. ——————————————————————————————————————— Company: Northern Illinois Gas Company Rate Class: Commercial/Industrial Large Rate Type: General Service Rate Name: Schedule 6 Effective Date: 09/01/89 Qualifications: General commercial use. All charges are shown per MMBtu. ——————————————————————————————————————— Winter Summer Customer Charge: $325.00 $325.00 Minimum Charge: $3,000.00 $3,000.00 Purchased Gas Adjustment: $2.454 $2.61 Tax Rate: 5.1% 5.1% No. of Energy Blocks: 1 1 Block 1 Size: > 0 > 0 Block 1 Energy Charge: $0.426 $0.426 No. of Demand Blocks: 1 1 Block 1 Size: > 0 > 0 Block 1 Demand Charge: $7.07 $5.388 ——————————————————————————————————————— TAX: applied to the total bill and is the lower of 5% of revenues or $0.24 per MMBtu, plus 0.10%. BILLING DEMAND: per MMBtu of customer’s Maximum Daily Contract Quantity. The PGA and Demand charges shown here change monthly. Winter charges applied in January 1994; and Summer charges applied in July 1993. ———————————————————————————————————————

1) 2)

3)

4) 5)

Table 18.6 Basic steps for conducting a load analysis. Collect historical load data • compile data for at least one year Organize data by month for • kWh consumption • maximum kW demand • load factor Review data for • seasonal patterns of use • peak demands Determine what demand or use can be eliminated or reduced Review load data with utility

Next, review the data. Seasonal variations will be easily pinpointed. For example, most buildings will show a seasonal trend with two peaks. One will occur in winter and another during summer, reflecting seasonal heating and cooling periods. There may be other peaks due to some aspect of some industrial process, such as a cannery where crops are processed when they are harvested. In Figure 18.1, kWh, maximum kW, and average kW are plotted from the data in Table 18.1 for the shopping

Table 18.7 Load factor calculation. ————————————————————————— average demand (kW) Load Factor = ———————————, where maximum demand (kW) Average Demand =

kWh usage ——————— (24) × (number of days)

Example: December office building load from Table 18.1 172,500 kWh Average Demand = ————————— = 231.9 kW (24) × (31) 231.9 kW Load Factor = ——————— = 0.39 600 kW ————————————————————————— center and the office building. Note that the shopping center has a dominant winter peak—it is in the winter that the maximum kWh and kW are used for the year. The load factor ranges between 0.54 and 0.70. Overall, the average demand for this customer is about 60% of the peak demand. The office building shows a different pattern. The load factor ranges between 0.35 and 0.52. This reflects the fact that the office building is really used less than half

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Figure 18.1 Monthly load profile. the time. Generally, working hours span from 8 a.m. to 6 p.m. Although some electrical load continues during the night hours, it is not as intense as during the normal office hours. If the load factor were 1, this would imply uniform levels of use—in effect, a system that was turned on and left running continuously. This may be the case with some manufacturing processes such as steel mills and refineries. The fourth step is to determine what demand or use can be eliminated, reduced, or redirected. How can the shopping center reduce its energy costs? By reducing or shifting the peak demand it can shave demand costs. Although overall consumption is not necessarily reduced, the demand charge is reduced. Where demand ratchets are in place, shaving peak demand may result in savings over a period of several months, not just the month of use. One way to shift peak demand is to install thermal storage units for space cooling purposes; this will shift day time load to night time, giving the customer an overall higher load factor. This may qualify the customer for special rates from the utility as well. Where there may not be much that can be done about the peak demand, (in a high load factor situation)

more emphasis should be placed on methods to reduce usage. Some examples: turn up the thermostat at night during the summer, down during the winter; install motion detectors to turn off unnecessary lights; turn off other equipment that is not in use. Where the customer is charged for electric service on a time-of-use basis, a more sophisticated load study should be performed. The data collected should consist of hourly load data over at least one year. This data can be obtained through the use of recording meters. Once acquired, the data should be organized to show use patterns on a monthly basis with Monday through Friday (or Saturday, depending on the customer’s uses) use plotted separately from weekend use. Review of this data should show where shaving or shifting energy or demand can lower overall electricity bills. Once the customer has obtained a better understanding of his energy usage patterns, he can discuss with his utility how to best benefit from them. The utility most likely will be interested because it will also receive some benefits. The customer can consider implementing certain specific measures to better fit in the utility’s load pattern, and at the same time improve his energy use. The customer’s benefit will generally be associated with less

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energy-related costs. Table 18.8 contains some examples of options that can be taken by commercial and industrial customers and the effect of those options on the utility.

18.7 EFFECTS OF DEREGULATION ON CUSTOMER RATES 18.7.1 Gas and Electric Supply Deregulation In the period since 1980, many changes have either occurred or begun to occur in the structure of the nation’s electric and gas supply industries. These changes have already begun to affect the rate types and structures for U.S. gas and electricity consumers. In the natural gas industry, well-head prices were deregulated as a result of the Natural Gas Policy Act of 1978 and the subsequent Natural Gas Well-Head Decontrol Act of 1989. Subsequently, FERC introduced a number of restructuring rules (Order Nos. 436, 500, and 636) that dramatically change the regulation of the nation’s pipelines and provide access for end-users to transport gas purchased at the well-head. In the electric industry, supply deregulation commenced with passage of the Public Utility Regulatory Policies Act of 1978, which encouraged electric power generation by certain non-utility producers. The Energy Policy Act of 1992 further deregulated production and mandated open transmission access for wholesale transfers of electricity between qualified suppliers and wholesale customers. These legal and regulatory changes will have a significant and lasting effect on the rate types and rate structures experienced by end-users. In the past, most gas and electric customers paid a single bundled rate that reflected all costs for capacity and energy, storage, delivery, and administration. Once customers are given the opportunity to purchase their gas and electric resources directly from producers, it then becomes necessary to unbundle the costs associated with production from the costs associated with transportation and delivery to end users. This

unbundling process has already resulted in separate rates for many services whose costs were previously combined in the single unit price for either gas or electricity. 18.7.2 Effect on Gas Rates Much of the discussion in Section 18.3 of this chapter pertains to bundled rates for gas. However, as a result of unbundling, many utilities are now offering customers four separate services, including balancing, procurement, storage, and transportation of gas. Gas balancing rates provide charges for over- or under-use of customerowned gas over a specified period of time. When the customer has the utility procure gas for transportation to the customer, gas procurement rates are charged. Gas storage rates are offered to customers for the storage of customer-owned gas. Gas transportation rates are offered to commercial, industrial and non-utility generator customers for the transportation and delivery of customerowned gas. In addition to these rates, there is the actual cost of purchasing the gas to be transported. Gas procurement, balancing, storage and transportation rates have increased in usage as the structure of the gas industry has evolved. Two other types of gas rates also are evolving as a result of industry deregulation. These include negotiated gas rates and variable gas rates. The former refers to rates that are negotiated between individual customers and the utility. Such rates are often subject to market conditions. The latter, variable gas service rates, refer to rates that vary from month to month. A review of all of the gas service rates collected by the Gas Research Institute (GRI) in 1994 indicated that 52% of the gas utilities surveyed offered at least one type of variable pricing. Such rates are often indexed to an outside factor, such as the price of gasoline or the price of an alternative fuel, and they usually vary between established floor and ceiling prices. The most common types of variable rates are those offered for transportation services.

Table 18.8 Customer options and their effects on utility. ——————————————————————————————————————————— OPTIONS ——————————————————————————————————————————— Commercial Industrial Utility Effect ——————————————————————————————————————————— Accept direct control of Subscribe to interruptible Reduction of load during water heaters rates peak periods ——————————————————————————————————————————— Store hot water to Add nighttime operations Builds load during off-peak increase space heating periods ———————————————————————————————————————————

ELECTRIC AND GAS UTILITY RATES FOR COMMERCIAL AND INDUSTRIAL CUSTOMERS

18.7.3 Effect on Electric Rates In the past, most U.S. electric customers have paid a single bundled rate for electricity. Many of these customers purchased from a utility that produced, transmitted, and delivered the electricity to their premises. In other cases, customers purchased from a distribution utility that had itself purchased the electricity at wholesale from a generating and transmitting utility. In both of these cases, the customer paid for electricity at a single rate that did not distinguish between the various services required to produce and deliver the power. In the future, as a result of the deregulation process already underway, there is a far greater likelihood that initially large customers, and later many smaller customers, will have the ability to select among a number of different suppliers. In most of these cases, however, the transmission and delivery of the purchased electricity will continue to be a regulated monopoly service. Consequently, future electricity consumers are likely to receive separate bills for: • • •

electric capacity and energy; transmission; and distribution.

In some cases, a separate charge may also be made for system control and administrative services, depending on exact industry structure in the given locality. For each such charge, a separate rate structure will apply. At present, it appears likely that there will be significant regional and local differences in the way these rates evolve and are implemented.

GLOSSARY There are a few terms that the user of this document needs to be familiar with. Below is a listing of common terms and their definitions. Billing Demand: The billing demand is the demand that is billed to the customer. The electric billing demand is generally the maximum demand or maximum average measured demand in any 15-, 30-, or 60minute period in the billing month. The gas billing demand is determined over an hour or a day and is usually the greatest total use in the stated time period. British Thermal Unit (Btu): Quantity of heat needed to bring one pound of water from 58.5 to 59.5 degrees Fahrenheit under standard pressure of 30 inches of mercury. Btu Value: The heat content of natural gas is in Btu per cubic foot. Conversion factors for natural gas are:

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• Therm = 100,000 Btu; • 1 MMBtu = 1,000,000 Btu = 1 Decatherm. Contract Demand: The demand level specified in a contractual agreement between the customer and the utility. This level of demand is often the minimum demand on which bills will be determined. Controllable Demand: A portion or all of the customer’s demand that is subject to curtailment or interruption directly by the utility. Cubic Foot: Common unit of measurement of gas volume; the amount of gas required to fill one cubic foot. Curtailable Demand: A portion of the customer’s demand that may be reduced at the utility’s direction. The customer, not the utility, normally implements the reduction. Customer Charge: The monthly charge to a customer for the provision of the connection to the utility and the metering of energy and/or demand usage. Demand Charge: The charge levied by a utility for metered demand of the customer. The measurement of demand may be either in kW or kVA. Dual-Fuel Capability: Some interruptible gas rates require the customer to have the ability to use a fuel other than gas to operate their equipment. Energy Blocks: Energy block sizes for gas utilities are either in MCFs or in MMBtus. The standard measures of energy block sizes for electric utilities are kWhs. However, several electric utilities also use an energy block size based on the customers’ demand level (i.e. kWh per kW). Additionally, some electric utilities combine the standard kWh value with the kWh per kW value. Energy Cost Adjustment (ECA): A fuel cost factor charged for energy usage. This charge usually varies on a periodic basis, such as monthly or quarterly. It reflects the utilities’ need to recover energy related costs in a volatile market. It is often referred to as the fuel cost adjustment, purchased power adjustment or purchased gas adjustment. Excess or Non-Coincidental Demand: Some utilities charge for demands in addition to the on- or offpeak demands in time-of-use rates. An excess demand is demand used in off-peak time periods that exceeds usage during on-peak hours. Non-coincidental demand is the maximum demand measured any time in a billing period. This charge is usually in addition to the on- or off-peak demand charges. Firm Demand: The demand level that the customer can rely on for uninterrupted use. Interruptible Demand: All of the customer’s demand may be completely interrupted at the utility’s direc-

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tion. Either the customer or the utility may implement the interruption. MCF: Thousand (1000) cubic feet. MMCF: Million (1,000,000) cubic feet. Minimum Charge: The minimum monthly bill that will be charged to a customer. This generally is equal to the customer charge, but may include a minimum demand charge as well. Off-Peak Demand: Greatest demand measured in the off-peak time period. On-Peak Demand: Greatest demand measured in the onpeak time period. Ratchet: A ratchet clause sets a minimum billing demand that applies during peak and/or non-peak months. It is usually applied as a percentage of the peak demand for the preceding season or year. Reactive Demand: In electric service, some utilities have a special charge for the demand level in kilovoltamperes reactive (kVAR) that is added to the standard demand charge. This value is a measure of the customer’s power factor. Surcharge: A charge levied by utilities to recover fees or imposts other than taxes. Therm: A unit of heating value equal to 100,000 Btu. Transportation Rates: Rates for the transportation of customer-owned gas. These rates do not include purchase or procurement of gas. Voltage Discounts: Most electric utilities offer discounted rates to customers who will take service at voltages

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other than the general distribution voltages. The voltages for which discounts are generally offered are Secondary, Primary, Sub-transmission and Transmission. The actual voltage of each of these levels vary from utility to utility. References 1. Acton, J.P., Gelbard, E.H., Hosek, J.R., & Mckay, D.J. (1980, February). British Industrial Response to the Peak-Load Pricing of Electricity. The Rand Corporation, R-2508-DOE/DWP. 2. David, A.K., & Li, Y.Z. (1991, November). A Comparison of System Response For Different Types of Real-Time Pricing. IEEE International Conference on Advances In Power System Control, Operation and Management. Hong Kong, p. 385-390. 3. Anonymous (1997, August). Energy User News. Chilton Co., p. 32. 4. EPRI (1980, October). Industrial Response To Time Of Day Pricing—A Technical and Economic Assessment Of Specific Load Management Strategies. Gordian Associates, EA-1573, Research Project 1212-2. 5. Hanser, P., Wharton, J., & Fox-Penner, P. (March 1, 1997). Realtime Pricing—Restructuring’s Big Bang? Public Utilities Fortnightly, 135 (5), p. 22-30. 6. Kirsch, L. D., Sullivan, R.L., & Flaim, T.A. (1988, August). Developing Marginal Costs For Real-Time Pricing. IEEE Transactions on Power Systems, 3 (3), p. 1133-1138. 7. Mykytyn Consulting group, Inc. (1997). Electric Utilities and Tariffs. PowerRates [Online]. Available: http://www.mcgi.com/ pr/samples/utility_list.html [November 4, 1997]. 8. O’Sheasy, M. ([email protected]). (1998, March 12). RTP. E-mail to Mont, J. ([email protected]). 9. Tabors, R.D., Schweppe, F.C., & Caraminis, M.C. (1989, May). Utility Experience with Real-Time Rates. Transactions on Power Systems, 4(2), p. 463-471. 10. Tolley, D.L. (1988, January). Industrial Electricity Tariffs. Power Engineering Journal. p. 27-34.

CHAPTER 19

THERMAL ENERGY STORAGE CLINT CHRISTENSON Johnson Controls, Inc.

19.1 INTRODUCTION A majority of the technology developed for energy management has dealt with the more efficient consumption of electricity, rather than timing the demand for it. Variable frequency drives, energy efficient lights, electronic ballasts and energy efficient motors are a few of these consumption management devices. These techniques often only impact a small portion of the facilities demand (when compared to say the mechanical cooling equipment), which is normally a major portion of the facilities overall annual electric bill. The management of demand charges deals very little with conservation of energy, but mainly with the ability of a generator to supply power when needed. It is this timing of consumption that is the basis of demand management and the focus of thermal energy storage (TES). Experts agree that demand management is actually not a form of energy conservation but a form of cost management. Throughout the 1980’s and most of the 1990’s, Demand Side Management (DSM) was done by utilities in order to manage generating capacity and costs by promoting demand reduction though incentives (financial rewards) and disincentives (rate structures). Most of the incentive programs have ceased due to surplus generation capacity and the approach of retail electrical deregulation. A deregulated market place will surely impact the cost of energy for many customers and if the commodity pricing experiments of the recent past are any indication of the future, demand costs, and thus demand management, will remain as an important cost control strategy for utilities and the energy users. Utilities often charge more for energy and demand during certain periods in the form of on-peak rates and ratchet clauses. The process of managing the generation capacity that a particular utility has “on-line” involves the utilization of those generating units that produce power most efficiently first since these units would have the lowest avoided costs (ultimately the actual cost of energy). When the loads are approaching the connected generation capacity of the utility, additional generating 519

Figure 19.1 Typical office building chiller consumption profile. units must be brought on line. Each additional unit has an incrementally higher avoided cost since these “peaking units” units are less efficient and used less often. This has prompted many organizations to implement some form of demand management. Thermal energy storage (TES) is the concept of generating and storing energy in the form of heat or cold for use during peak periods. For the profile in Figure 19.1, a cooling storage system could be implemented to reduce or eliminate the need to run the chillers during the on-peak rate period. By running the chillers during off-peak hours and storing this capacity for use during the onpeak hours, a reduction in energy costs can be realized. If this type of system is implemented during new construction or when equipment is being replaced, smaller capacity chillers can be installed, since the chiller can spread the production of the total load over the entire day, rather than being sized for peak loads.

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Thermal energy storage has been used for centuries, but only recently have large electrical users taken advantage of the technique for cost management. The process involves storing Btu’s (or lack of Btu’s) for use when either a heat source or a heat sink is required. The use of eaves, root cellars, ground coupled heat pump systems, and adobe type thermal mass could all be considered forms of thermal storage. Today, the ability to take advantage of a source of inexpensive energy (whether waste heat source or time based rate structure) for use during a later time of more expensive energy has extended the applications of TES. For this particular chapter, the focus of discussion will concentrate on the storage of cooling capacity and the storage of heat will not be considered. The two main driving forces behind the storage of cooling capacity, rate structure and cooling system management, will be discussed in the following paragraphs. Often the chiller load and efficiency follow the chiller consumption profile, in that the chiller is running at high load, i.e. high efficiency, only a small portion of the day. This is due to the HVAC system having to produce cooling when it is needed as well as to be able to handle instantaneous peak loads. With smaller chiller systems designed to handle the base and peak loads during offpeak hours, the chillers can run at higher average loads and thus higher efficiencies. Appendix A following this chapter lists several manufacturers of thermal energy storage systems. Thermal energy storage also has the ability to balance the daily loads on a cooling system. Conventional air conditioning system must employ a chiller large enough to handle the peak cooling demand as it occurs. This mandates that the cooling system will be required to operate in a load following mode, varying the output of the system in response to changes in the cooling requirements. In systems that operate within a one or two shift operation or those that are much more climatically based, can benefit from the smoothing characteristics of TES. A school for example that adds a new wing, could utilize the existing refrigeration system during the evening to generate cooling capacity to be stored for use during the day. Although additional piping and pumping capacity would need to be added to the addition, new chiller capacity may not have to be added. A new construction project that would have similar single shift cooling demand profile could utilize a smaller chiller in combination with storage to better balance the chiller operation. This could significantly reduce the capital cost of the renovation in addition to any rate based savings as discussed above. Companies often control the demand of electricity by utilizing some of the techniques listed above and other consumption management actions which also reduce

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demand. More recently the ability to shift the time when electricity is needed has provided a means of balancing or shifting the demand for electricity to “off-peak” hours. This technique is often called demand balancing or demand shifting. This demand balancing may best be seen with the use of an example 24-hour chiller consumption plot during the peak day, Figure 19.1 and Table 19.1. This facility exhibits a typical single shift building load profile. Note that the load listed in this table for the end of hour 1 identifies the average load between midnight and 1:00 a.m., and that for end of hour 2 is the average load between 1 and 2 a.m., and so on. This example will employ a utility rate schedule with a summer on-peak demand period from 10 am to 5:59 p.m., an 8-hour period. Moving load from the on-peak rate period to the off-peak period can both balance the demand and reduce residual ratchTable 19.1 Example chiller consumption profile Chiller Consumption Profile ———————————————————————— Chiller Load End of Hour (Tons) Rate ———————————————————————— 1 100 Reg 2 120 Reg 3 125 Reg 4 130 Reg 5 130 Reg 6 153 Reg 7 165 Reg 8 230 Reg 9 270 Reg 10 290 Reg 11 340 On-Peak 12 380 On-Peak 13 450 On-Peak 14 490 On-Peak 15 510 On-Peak 16 480 On-Peak 17 410 On-Peak 18 360 On-Peak 19 250 Reg 20 210 Reg 21 160 Reg 22 130 Reg 23 125 Reg 24 115 Reg ———————————————————————— Daily Total 6123 Ton-Hrs Daily Avg. 255.13 Tons ———————————————————————— Peak Total 3420 Ton-Hrs Peak Demand 510 Tons ————————————————————————

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eted peak charges. Thermal energy storage is one method available to accomplish just that.

19.2 STORAGE SYSTEMS There are two general types of storage systems, ones that shut the chiller down during on-peak times and run completely off the storage system during that time are known as “full storage systems.” Those designed to have the chiller run during the on-peak period supplementing the storage system are known as “partial storage systems.” The full storage systems have a higher first cost since the chiller is off during peaking times and the cooling load must be satisfied by a larger chiller running fewer hours and a larger storage system storing the excess. The full storage systems do realize greater savings than the partial system since the chillers are completely turned off during on-peak periods. Full storage systems are often implemented in retrofit projects since a large chiller system may already be in place. A partial storage system provides attractive savings with less initial cost and size requirements. New construction projects will often implement a partial storage system so that the size of both the chiller and the storage system can be reduced. Figures 19.2 and 19.3 and Tables 19.2 and 19.3 demonstrate the chiller load required to satisfy the cooling needs of the office building presented in Figure 19.1 for the full and partial systems, respectively. Column 2 in these tables represents the building cooling load each hour, and column 3 represents the chiller output for each hour. Discussion of the actual calculations that are required for sizing these different systems is included in a subsequent section. For simplicity sake, these numbers do not provide for any system losses, which will also be discussed in a later section. The full storage system has been designed so that the total daily chiller load is produced during the offpeak hours. This eliminates the need to run the chillers during the on-peak hours, saving the increased rates for demand charges during this period and as well as any future penalties due to ratchet clauses. The partial storage system produces 255.13 tons per hour during the entire day, storing excess capacity for use when the building demand exceeds the chiller production. This provides the ability to control the chiller load, limit the peak chiller demand to 255.13 kW,* and still take advantage of the offpeak rates for a portion of the on-peak chiller load.

3.517 *assuming COP = 3.5, then kW/ton = ——— = 1.0 kW/ton COP

Table 19.2 Full storage chiller consumption profile. Chiller Consumption Profile—Full Storage System 1 2 3 4 ————————————————————————— End of Cooling Chiller Rate Hour (Tons) Load (Tons) Load2 ————————————————————————— 1 100 382.69 Reg 2 120 382.69 Reg 3 125 382.69 Reg 4 130 382.69 Reg 5 130 382.69 Reg 6 153 382.69 Reg 7 165 382.69 Reg 8 230 382.69 Reg 9 270 382.69 Reg 10 290 382.69 Reg 11 340 0 On-Peak 12 380 0 On-Peak 13 450 0 On-Peak 14 490 0 On-Peak 15 510 0 On-Peak 16 480 0 On-Peak 17 410 0 On-Peak 18 360 0 On-Peak 19 250 382.69 Reg 20 210 382.69 Reg 21 160 382.69 Reg 22 130 382.69 Reg 23 125 382.69 Reg 24 115 382.69 Reg ————————————————————————— Without storage With storage Daily Total (Ton-Hrs) 6123 6123 1 Daily Avg (Tons): 255.13 255.13 ————————————————————————— Peak Total (Ton-Hrs) 34203 04 3 Peak Demand (Tons) 510 04 ————————————————————————— 1

2

6123 Ton-Hr —————— 24 Hours

= 255.13 Avg Tons

6123 Ton-Hr —————— 16 Hours

= 382.69 Avg Tons

3This peak load is supplied by the TES, not the chiller 4This is the chiller load and peak during on-peak periods

An advantage of partial load systems is that they can provide a means of improving the performance of a system that can handle the cumulative cooling load, but not the instantaneous peak demands of the building. In such a system, the chiller could be run nearer optimal load continuously throughout the day, with the excess cooling tonnage being stored for use during the peak

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Table 19.3 Partial storage chiller consumption profile. Chiller Consumption Profile Partial Storage System ————————————————————————— 1 2 3 4 ————————————————————————— Hour of Cooling Chiller Rate 1 Day Load (Tons) Load (Tons) —————————————————————————

Figure 19.2 Full storage chiller consumption profile.

1 100 255.13 Reg 2 120 255.13 Reg 3 125 255.13 Reg 4 130 255.13 Reg 5 130 255.13 Reg 6 153 255.13 Reg 7 165 255.13 Reg 8 230 255.13 Reg 8 270 255.13 Reg 10 290 255.13 Reg 11 340 255.13 On-Peak 12 380 255.13 On-Peak 13 450 255.13 On-Peak 14 490 255.13 On-Peak 15 510 255.13 On-Peak 16 480 255.13 On-Peak 17 410 255.13 On-Peak 18 360 255.13 On-Peak 19 250 255.13 Reg 20 210 255.13 Reg 21 160 255.13 Reg 22 130 255.13 Reg 23 125 255.13 Reg 24 115 255.13 Reg ————————————————————————— Without storage With storage Daily Total (Ton-Hrs) 6123 6123 Daily Avg (Tons): 255.13 255.13 ————————————————————————— Peak Total (Ton-Hrs): 34202 20413 Peak Demand (Tons): 5102 255.133 ————————————————————————— 1

6123 Ton-Hr —————— 24 Hours

= 255.13 Avg Tons

2This peak load is supplied by the TES, supplemented by the chiller 3This is the chiller load and peak during on-peak period.

Figure 19.3 Partial storage chiller consumption profile.

periods. An optional method for utilizing partial storage is a system that already utilizes two chillers. The daily cooling load could be satisfied by running both chillers during the off-peak hours, storing any excess cooling capacity, and running only one chiller during the on-peak period, to supplement the discharge of the storage system. This also has the important advantage of offering a reserve chiller during peak load times. Figure 19.4 shows

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the chiller consumption profile for this optional partial storage arrangement and Table 19.4 lists the consumption values. Early and late in the cooling season, the partial load system could approach the full load system characteristics. As the cooling loads and peaks begin to decline, the storage system will be able to handle more of the on-peak requirement, and eventually the on-peak chiller could also be turned off. A system such as this can be designed to run the chillers at optimum load, increasing efficiency of the system.

19.3 STORAGE MEDIUMS There are several methods currently in use to store cold in thermal energy storage systems. These are water, ice, and phase change materials. The water systems simply store chilled water for use during on-peak periods. Ice systems produce ice that can be used to cool the actual chilling water, utilizing the high latent heat of fusion. Phase change materials are those materials that exhibit properties, melting points for example, that lend themselves to thermal energy storage. Figure 19.5a represents the configuration of the cooling system with either a water or phase change material thermal storage system and Figure 19.5b represents a general configuration of a TES utilizing ice as the storage medium The next few sections will discuss these different mediums. 19.3.1 Chilled Water Storage Chilled water storage is simply a method of storing chilled water generated during off-peak periods in a large tank or series of tanks. These tanks are the most commonly used method of thermal storage. One factor to this popularity is the ease to which these water tanks can be interfaced with the existing HVAC system. The chillers are not required to produce chilled water any colder than presently used in the system so the system efficiency is not sacrificed. The chiller system draws warmer water from one end of the system and this is replaced with chilled water in the other. During the off-peak charge cycle, the temperature of the water in the storage will decline until the output temperature of the chiller system is approached or reached This chilled water is then withdrawn during the on-peak discharge cycle, supplementing or replacing the chiller(s) output. Facilities that have a system size constraint such as lack of space often install a series of small insulated tanks that are plumbed in series. Other facilities have installed a single, large volume tank either above or below ground. The material and shape of these tanks vary greatly from installation to installation. These large tanks are often de-

Figure 19.4 Optional partial storage chiller profile. signed very similar to municipal water storage tanks. The main performance factors in the design of these tank systems, either large or multiple, is location and insulation. An Electric Power Research Institute’s (EPRI) Commercial Cool Storage Field Performance Monitoring Project (RP-2732-05) Report states that the storage efficiencies of tanks significantly decrease if tank walls were exposed to sunlight and outdoor ambient conditions and/or had long hold times prior to discharging7. To minimize heat gain, tanks should be out of the direct sun whenever possible. The storage efficiency of these tanks is also decreased significantly if the water is stored for extended periods. One advantage to using a single large tank rather than the series of smaller ones is that the temperature differential between the warm water intake and the chilled water outlet can be maintained. This is achieved utilizing the property of thermal stratification where the warmer water will migrate to the top of the tank and the colder to the bottom. Proper thermal stratification can only be maintained if the intake and outlet diffusers are located at the top and bottom of the tank and the flow rates of the water during charge and discharge cycles is kept low This will reduce a majority of the mixing of the two temperature waters. Another method used to assure that the two temperature flows remain separated is the use of a movable bladder, creating a physical partition. One top/bottom diffuser tank studied in the EPRI study used

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Table 19.4 Partial storage chiller consumption profile. 1 2 3 4 Hour of Day Cooling Load Chiller Load1,2 Rate (Tons) (Tons) ————————————————————————— 1 100 306 Reg 2 120 306 Reg 3 125 306 Reg 4 130 306 Reg 5 130 306 Reg 6 153 306 Reg 7 165 306 Reg 8 230 306 Reg 9 270 306 Reg 10 290 306 Reg 11 340 153 On-Peak 12 380 153 On-Peak 13 450 153 On-Peak 14 490 153 On-Peak 15 510 153 On-Peak 16 480 153 On-Peak 17 410 153 On-Peak 18 360 153 On-Peak 19 250 306 Reg 20 210 306 Reg 21 160 306 Reg 22 130 306 Reg 23 125 306 Reg 24 115 306 Reg —————————————————————————

Figure 19.5a Water & eutectic storage system configuration.

Without storage With storage Daily Total (Ton-Hrs): 6123 6123 Daily Avg (Tons): 255.13 255.13 ————————————————————————— On-Peak (Ton-Hrs): 34203 12254 3 Peak Demand (Tons): 510 1534 ————————————————————————— 1

(6123 Ton-Hr) (2 Chillers Operating) ———————————————————— = 306 Tons (16 Hours)(2 Chillers) + (8 Hours)(1 Chiller)

2

(6123 Ton-Hr) (1 Chiller Operating) ———————————————————— = 153 Tons (16 Hours)(2 Chillers) + (8 Hours)(1 Chiller)

3This peak load is supplied by the TES, supplemented by the chiller. 4This is the chiller load and peak during the on-peak period.

————————————————————————— a thermocouple array, installed to measure the chilled water temperature at one foot intervals from top to bottom of the tank. This tank had a capacity of 550,000 gallons and was 20 feet deep but had only a 2.5 foot blend zone over which the temperature differential was almost 20 degrees7. The advantages of using water as the thermal storage medium are:

Figure 19.5b Ice storage system configuration.

THERMAL ENERGY STORAGE

1.

Retrofitting the storage system with the existing HVAC system is very easy,

2.

Water systems utilize normal evaporator temperatures,

3.

With proper design, the water tanks have good thermal storage efficiencies,

4.

Full thermal stratification maintains chilled water temperature differential, maintaining chiller loading and efficiencies, and

5.

Water systems have lower auxiliary energy consumption than both ice and phase change materials since the water has unrestricted flow through the storage system.

19.3.2 Ice Storage Ice storage utilizes water’s high latent heat of fusion to store cooling energy. One pound of ice stores 144 Btu’s of cooling energy while chilled water only contains 1 Btu per pound –°F7,8. This reduces the required storage volume approximately 75%7 if ice systems are used rather than water. Ice storage systems form ice with the chiller system during off-peak periods and this ice is used to generate chilled water during on-peak periods. There are two main methods in use to utilize ice for on-peak cooling. The first is considered a static system in which serpentine expansion coils are fitted within a insulated tank of cooling water. During the charging cycle, the cooling water forms ice around the direct expansion coil as the cold gases pass through it (see Figure 19.5b). The thickness of the ice varies with the ice building time (charge time) and heat transfer area. During the discharge cycle, the cooling water contained in the tank is used to cool the building and the warmer water returned from the building is circulated through the tank, melting the ice, and using its latent heat of fusion for cooling. The second major category of thermal energy storage systems utilizing ice can be considered a dynamic system. This system has also been labeled a plate ice maker or ice harvester. During the charging cycle the cooling water is pumped over evaporator “plates” where ice is actually produced. These thin sheets of ice are fed into the cooling water tank, dropping the temperature. During on-peak periods, this chilled water is circulated through the building for cooling. This technology is considered dynamic due to the fact that the ice is removed from the evaporator rather than simply remaining on it. Static ice storage systems are currently available in factory-assembled packaged units which provide ease

525

of installation and can provide a lower initial capital cost. When compared to water storage systems, the size and weight reduction associated with ice systems makes them very attractive to facilities with space constraints One main disadvantage to ice systems is the fact that the evaporator must be cold enough to produce ice. These evaporator temperatures usually range from 10° to 25° while most chiller evaporator temperatures range from 42° to 47°9. This required decrease in evaporator temperature results in a higher energy demand per ton causing some penalty in cooling efficiency. The EPRI Project reported that chillers operating in chilled water or eutectic salt (phase change material) used approximately 20% less energy than chillers operating in ice systems (0.9 vs. 1.1 kW/ton)7. The advantages of using ice as the thermal storage medium are: 1.

Retrofitting the storage system with the existing HVAC chilled water system is feasible,

2.

Ice systems require less space than that required by the water systems,

3.

Ice systems have higher storage but lower refrigeration efficiencies than those of water, and

4.

Ice systems are available in packaged units, due to smaller size requirements

19.3.3 Phase Change Materials The benefit of capturing latent heat of fusion while maintaining evaporating temperatures of existing chiller systems can be realized with the use of phase change materials. There are materials that have melting points higher than that of water that have been successfully used in thermal energy storage systems. Several of these materials fall into the general category called “eutectic salts” and are salt hydrates which are mixtures of inorganic salts and water. Some eutectic salts have melting (solidifying) points of 47°7, providing the opportunity for a direct retrofit using the existing chiller system since this is at or above the existing evaporator temperatures. In a thermal storage system, these salts are placed in plastic containers, which are immersed within an insulated chilled water tank. During the charging cycle, the chilled water flows through the gaps between the containers, freezing the salts within them. During the on-peak discharge, the warmer building return water circulates through the tank, melting the salts and utilizing the latent heat of fusion to cool the building. These salt solutions have latent heat of fusion around 40 Btu/lb9. This additional latent heat reduces the storage vol-

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ume by 66% of that required for an equivalent capacity water storage system9. Another obvious benefit of using eutectic salts is that the efficiency of the chillers is not sacrificed, as stated earlier, since the phase change occurs around normal evaporator suction temperatures. One problem with the eutectic salt systems is that the auxiliary energy consumption is higher since the chilled water must be pumped through the array of eutectic blocks. The auxiliary energy consumption of the ice systems is higher than both the water and eutectic salt systems since the chilled water must be pumped through the ice system coils, nozzles, and heat exchangers. The EPRI study found that the chilled water systems had an average auxiliary energy use of 0.43 kWh/Ton-Hr compared to the phase change systems (eutectic and ice) average auxiliary energy use of 0.56 kWh/Ton-Hr5. The advantages of using eutectic salts as the thermal storage medium are that they: 1.

can utilize the existing chiller system for generating storage due to evaporator temperature similarity,

2.

require less space than that required by the water systems, and

3.

have higher storage and equivalent refrigeration efficiencies to those of water.

19.4 SYSTEM CAPACITY The performance of thermal storage systems depends upon proper design. If it is sized too small or too large, the entire system performance will suffer. The following section will explain this sizing procedure for the example office building presented earlier. The facility has a maximum load of 510 tons, a total cooling requirement of 6,123 Ton-Hours, and a on-peak cooling requirement of 3,420 Ton-Hours. This information will be analyzed to size a conventional chiller system, a partial storage system, a full storage system, and the optional partial storage system. These results will then be used to determine the actual capacity needed to satisfy the cooling requirements utilizing either a chilled water, a eutectic salt, or an ice thermal storage system. Obviously some greatly simplifying assumptions are made. 19.4.1 Chiller System Capacity The conventional system would need to be able to handle the peak load independently, as seen in Figure 19.1. A chiller or series of chillers would be needed to produce the peak cooling load of 510 tons. Unfortunately,

packaged chiller units usually are available in increments that mandate excess capacity but for simplicity one 600ton chiller will be used for this comparison. The conventional chiller system will provide cooling as it is needed and will follow the load presented in Figure 19.1 and Table 19.1. To determine the chiller system requirement of a cooling system utilizing partial load storage, further analysis is needed. Table 19.1 showed that the average cooling load of the office building was 255.13 tons per hour. The ideal partial load storage system will run at this load (see Figure 19.3 and Table 19.3). The chiller system would need to be sized to supply the 255.13 tons per hour, so one 300-ton chiller will be used for comparison purposes. Table 19.5 shows how the chiller system would operate at 255.13 tons per hour, providing cooling required for the building directly and charging the storage system with the excess. Although the storage system supplements the cooling system for 2 hours before the peak period, the cooling load is always satisfied. Comparing the peak demand from the bottoms of columns 2 and 3 of Table 19.5 shows that the partial storage system reduced this peak load almost 50% (510 – 255.13 = 254.87 Tons). Column 4 shows the tonnage that is supplied to the storage system and column 5 shows the amount of cooling contained in the storage system at the end of each hour of operation. This system was design so that there would be zero capacity remaining in the thermal storage tanks after the on-peak period. The values contained at the bottom of Table 19.5 are the total storage required to assure that there is no capacity remaining and the maximum output required from storage. These values will be utilized in the next section to determine the storage capacity required for each of the different storage mediums. The full storage system also requires some calculations to determine the chiller system size. Since the chillers will not be used during the on-peak period, the entire daily cooling requirement must be generated during the off-peak periods. Table 19.1 listed the total cooling load as 6,123 Ton-Hours for the peak day. Dividing this load over the 16 off-peak hours yields that the chillers must generate 383 tons of cooling per hour (6,123 Ton-Hours/16 hours). A 450-ton chiller will be utilized in this situation for comparison purposes. Table 19.6 shows how the chiller system would operate at 383 tons per hour, providing cooling required for the building directly and charging the storage system with the excess. Comparing the peak demand with and without storage in Table 19.6 shows that the full storage system eliminated all load from the on-peak period. Column 4 shows the tonnage that is supplied to the storage system

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527

Table 19.5 Partial storage operation profile. Thermal Storage Operation Profile Partial Storage System ——————————————————————————————————————————— 1 2 3 4 5 6 End of Cooling Chiller Capacity to Capacity Storage Hour Load Load Storage In Storage Cycle (Tons) (Tons) (Ton-Hrs) (Ton-Hrs) ——————————————————————————————————————————— 1 100 255.13 155 696 Charge 2 120 255.13 135 831 Charge 3 125 255.13 130 961 Charge 4 130 255.13 125 1086 Charge 5 130 255.13 125 1211 Charge 6 153 255.13 102 1314 Charge 7 165 255.13 90 1404 Charge 8 230 255.13 25 1429 Charge 9 270 255.13 -15 1414 Discharge 10 290 255.13 -35 1379 Discharge 11 340 255.13 -85 1294 Discharge 12 380 255.13 -125 1169 Discharge 13 450 255.13 -195 974 Discharge 14 490 255.13 -235 740 Discharge 15 510 255.13 -255 485 Discharge 16 480 255.13 -225 260 Discharge 17 410 255.13 -155 105 Discharge 18 360 255.13 -105 0 Discharge 19 250 255.13 5 5 Charge 20 210 255.13 45 50 Charge 21 160 255.13 95 145 Charge 22 130 255.13 125 271 Charge 23 125 255.13 130 401 Charge 24 115 255.13 140 541 Charge ——————————————————————————————————————————— Daily Total (Ton-Hrs): Daily Avg (Tons):

Without storage 6123 255.13

With storage 6123 255.13

——————————————————————————————————————————— Peak Total (Ton-Hrs): Peak Demand (Tons):

3420 510

2041 255.13

Storage Total = Peak Storage Output =

1429 255

——————————————————————————————————————————— Column 4 = Column 3 – Column 2 Column 5(n) = Column 5(n–1) + Column 4(n)

and column 5 shows the amount of cooling contained in the storage system at the end of each hour of operation. This system was designed so that there would be 0 capacity remaining in the thermal storage tanks after the on-peak period, as shown at the bottom of Table 19.6. The values in Table 19.6 will be utilized in the next section to determine the storage capacity required for each of the different storage mediums. The optional partial storage system is a blend of the two systems presented earlier. Values given in Table 19.7 and Figure 19.4 are one combination of several possibili-

ties that would drop the consumption and peak demand during the on-peak period. Once again this system has been designed to run both chillers during off-peak hours and run only one during on-peak hours. Benefits of this arrangement are that the current chiller system could be used in combination with the storage system and that the storage system does not require as much capacity as the full storage system. Also, a reserve chiller is available during peak-load times. Comparing the peak demand with and without storage in Table 19.7 shows that the optional partial stor-

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Table 19.6 Full storage operation profile. ——————————————————————————————————————————— Thermal Storage Operation Profile Full Storage System ——————————————————————————————————————————— 1 Hour of Day

2 3 4 5 6 Cooling Chiller Capacity to Capacity Storage Load Load Storage In Storage Cycle (Tons) (Tons) (Ton-Hrs) (Ton-Hrs) ——————————————————————————————————————————— 1 100 383 283 1589 Charge 2 120 383 263 1852 Charge 3 125 383 258 2109 Charge 4 130 383 253 2362 Charge 5 130 383 253 2615 Charge 6 153 383 230 2844 Charge 7 165 383 218 3062 Charge 8 230 383 153 3215 Charge 9 270 383 113 3327 Charge 10 290 383 93 3420 Charge 11 340 0 -340 3080 Discharge 12 380 0 -380 2700 Discharge 13 450 0 -450 2250 Discharge 14 490 0 -490 1760 Discharge 15 510 0 -510 1250 Discharge 16 480 0 -480 770 Discharge 17 410 0 -410 360 Discharge 18 360 0 -360 0 Discharge 19 250 383 133 133 Charge 20 210 383 173 305 Charge 21 160 383 223 528 Charge 22 130 383 253 781 Charge 23 125 383 258 1038 Charge 24 115 383 268 1306 Charge ——————————————————————————————————————————— Without storage With storage Daily Total (Ton-Hrs): 6123 6123 Daily Avg (Tons): 255.13 255.13 ——————————————————————————————————————————— Peak Total (Ton-Hrs): 3420 0 Storage Total = 3420 Peak Demand (Tons): 510 0 Peak Storage Output = 510 ——————————————————————————————————————————— Column 4 = Column 3 – Column 2 Column 5(n) = Column 5(n–1) + Column 4(n) age system reduces the peak load from 510 tons to 153 tons, or approximately 70% during the on-peak period. Column 4 shows the tonnage that is supplied to the storage system and column 5 shows the amount of cooling contained in the storage system at the end of each hour of operation. This system was designed so that there would be zero capacity remaining in the thermal storage tanks after the on-peak period. The values contained at the bottom of Table 19.7 are the total storage capacity required and the maximum output required from storage. These values will be utilized in the next section to determine the

storage capacity required for each of the different storage mediums. Table 19.8 summarizes the performance parameters for the three configurations discussed above. The next section summarizes the procedure used to determine the size of the storage systems required to handle the office building. 19.4.2 Storage System Capacity Each of the storage mediums has different size requirements to satisfy the needs of the cooling load. This section will describe the procedure to find the actual

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529

Table 19.7 Optional partial storage operation profile. ——————————————————————————————————————————— Thermal Storage Operation Profile—Optional Partial Storage System ——————————————————————————————————————————— 1 2 3 4 5 6 End of Cooling Chiller Capacity to Capacity Storage Hour Load Load Storage In Storage Cycle (Tons) (Tons) (Ton-Hrs) (Ton-Hrs) ——————————————————————————————————————————— 1 100 306 206 1053 Charge 2 120 306 186 1239 Charge 3 125 306 181 1420 Charge 4 130 306 176 1597 Charge 5 130 306 176 1773 Charge 6 153 306 153 1926 Charge 7 165 306 141 2067 Charge 8 230 306 76 2143 Charge 9 270 306 36 2179 Charge 10 290 306 16 2195 Charge 11 340 153 -187 2008 Discharge 12 380 153 -227 1782 Discharge 13 450 153 -297 1485 Discharge 14 490 153 -337 1148 Discharge 15 510 153 -357 791 Discharge 16 480 153 -327 464 Discharge 17 410 153 -257 207 Discharge 18 360 153 -207 0 Discharge 19 250 306 56 56 Charge 20 210 306 96 152 Charge 21 160 306 146 298 Charge 22 130 306 176 475 Charge 23 125 306 181 656 Charge 24 115 306 191 847 Charge ——————————————————————————————————————————— Without storage With storage Daily Total (Ton-Hrs): 6123 6123 Daily Avg (Tons): 255.13 255.12 ——————————————————————————————————————————— Peak Total (Ton-Hrs): 3420 1225 Storage Total = 2195 Peak Demand (Tons): 510 153 Peak Storage Output = 357 ——————————————————————————————————————————— Column 4 = Column 3 - Column 2 Column 5(n) = Column 5(n-1) + Column 4(n) volume or size of the storage system for the partial load system for each of the different storage mediums. The design of the chiller and thermal storage system must provide enough chilled water to the system to satisfy the peak load, so particular attention should be paid to the pumping and piping. Table 19.9 summarizes the size requirement of each of the three different storage options. To calculate the capacity of the partial load storage system, the relationship between capacity (C), mass (M), specific heat of material (Cp), and the coil temperature differential (T2–T1) shown in Figure 19.5a will be used:

C where: M Cp (T2–T1)

= M Cp (T2–T1) = lbm = Btu/lbm °R = °R

The partial load system required that 1,429 Ton-Hrs be stored to supplement the output of the chiller during onpeak periods. This value does not allow for any thermal loss which normally occurs. For this discussion, a conservative value of 20% is used, which is an average suggested in the EPRI report7. This will increase the storage

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Table 19.8 System performance comparison. ——————————————————————————————————————————— SYSTEM ————————————————————————— Conventional Partial Full Optional PERFORMANCE PARAMETERS No Storage Storage Storage Partial ——————————————————————————————————————————— Overall Peak Demand (Tons) 510 255.13 383 306 On-Peak, Peak Demand (Tons)

510

255.13

0

153

On-Peak Chiller Consumption (Ton-Hrs)

3,420

2,041

0

1,225

Required Storage Capacity1 (Ton-Hrs)

—

1,379

3,420

2,195

MAXIMUM STORAGE OUTPUT1 — 255 510 357 (Tons) ——————————————————————————————————————————— 1Values from Table 19.5, 19.6, and 19.7. Represent the capacity required to be supplied by the TES.

requirements to 1,715 Ton-Hrs and chilled water storage systems in this size range cost approximately $200/TonHr including piping and installation5. Assuming that there are 12,000 Btu’s per Ton-Hr, this yields:

C = (1,715 Ton-Hrs)*(12,000 Btu/Ton-Hr) = 20.58 × 106 Btu’s. Assuming (T2–T1) = 12° and Cp = 1 Btu/lbm °R, the relation becomes: C M = —————— = Cp(T2 – T1)

20.58 × 106 Btus —————————— = 1.72 x 106 lbm H2O 1 Btu/lbm –°R)(12°R)

1.72 x 106 lbm Volume of Water = Mass/Density = ———————— 62.5 lbm/Ft3 1.72 × 106 lbm ——————— 8.34 lbm/gal

= 27,520 Ft3 or = 206,235 gal.

Sizing the storage system utilizing ice is completed in a very similar fashion. The EPRI study states that the ice storage tanks had average daily heat gains 3.5 times greater than the chilled water and eutectic systems due to the higher coil temperature differential (T2–T1) To allow for these heat gains a conservative value of 50% will be added to the actual storage capacity, which is an

average suggested in the EPRI report7 This will increase the storage requirements to 2,144 Ton-Hrs. Assuming that there are 12,000 Btu’s per Ton-Hr, this yields: (2,144 Ton-Hrs)*(12,000 Btu’s/Ton-Hr) = 25.73 × 106 Btu’s. The ice systems utilize the latent heat of fusion so the C1 now becomes C1 = Latent Heat = 144 Btu/lbm. Because the latent heat of fusion, which occurs at 32°F, is so large compared to the sensible heat, the sensible heat (Cp) is not included in the calculation. The mass of water required to be frozen becomes: 25.73 × 106 Btus M = C/C1 = ———————— = 1.79 × 105 lbm H2O (144 Btu/lbm) Mass 1.79 × 105 lbm Volume of Ice = ———— = —————— Density 62.5 lbm/Ft3 =

2,864 Ft3

This figure is conservative since the sensible heat has been ignored but calculates the volume of ice needed to be generated. The actual volume of ice needed will vary and the total amount of water contained in the tank around the ice coils will vary greatly. The ability to purchase pre-packaged ice storage systems makes their sizing quite easy For this situation, two 1,080 Ton-Hr ice storage units will be purchased for approximately $150/

THERMAL ENERGY STORAGE

531

Table 19.9 Complete system comparison. ——————————————————————————————————————————— SYSTEM ——————————————————————————— Conventional Partial Full Optional Performance Parameters No Storage Storage Storage Partial ——————————————————————————————————————————— CHILLER SIZE (# and Tons) 1 @ 600 1 @ 300 1 @ 450 2 @ 175 COST($) 180,000 90,000 135,000 105,000 WATER STORAGE Capacity (Ton-Hrs) Volume (cubic feet) Volume (gallons) Cost per Ton-Hr ($) Storage cost ($)

— — — — —

1,715 27,484 205,635 200 343,000

4,104 65,769 492,086 135 554,040

2,634 42,212 315,827 165 434,610

ICE STORAGE Capacity (Ton-Hrs) # and size (Ton-Hrs) Ice volume (cubic feet) Cost per Ton-Hr (S) Storage cost ($)1

— — — —

2,144 2 @ 1,080 2,859 150 324,000

5,130 4 @ 1,440 6,840 150 864,000

3,293 3 @ 1,220 4,391 150 549,000

EUTECTIC STORAGE Capacity (Ton-Hrs) 1,715 4,104 2,634 Eutectic vol (cubic feet) — 8,232 19,699 12,643 Cost per Ton-Hr ($) — 250 200 230 Storage cost ($) — 428,750 820,000 605,820 ——————————————————————————————————————————— 1(2 units)(1,080 Ton-Hrs/units)($150/Ton-Hr) = $324,000 Note: The values in this table vary slightly from those in the text from additional significant digits.

Ton-Hr including piping and installation4 (note that this provides 2,160 Ton-Hrs compared to the needed 2,144 Ton-Hrs). Sizing the storage system utilizing the phase change materials or eutectic salts is completed just as the ice storage system. The EPRI study states that the eutectic salt storage tanks had average daily heat gains approximately the same as that of the chilled water systems. To allow for these heat gains a conservative value of 20% is added to the actual storage capacity5. This increases storage requirements to 1,715 Ton-Hrs. Assuming there are 12,000 Btu’s per Ton-Hr, this yields: (1,715 Ton-Hrs)*(12,000 Btu’s/Ton-Hr) = 20.58 × 106 Btu’s. The eutectic system also utilizes the latent heat of fusion like the ice system and the temperature differential shown in Figure 19.5a is not used in the calculation. The C1 now becomes:

C1 = Latent Heat = 40 Btu/lbm 20.58 × 106 Btus M = C/C1 = ———————— = 5.15 × 105 lbm (40 Btu/lmb) Volume of Mass 5.15 × 105 lbm Eutectic Salts (assuming = ———– = ——————— density = water) Density 62.5 lbm/ft3 = 8,232 ft3 The actual volume of eutectic salts needed would need to be adjusted for density differences in the various combinations of the salts. Eutectic systems have not been studied in great detail and factory sized units are not yet readily available. The EPRI report7 studied a system that required 1,600 Ton-Hrs of storage which utilized approximately 45,000 eutectic “bricks” contained in an

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80,600 gallon tank of water. For this situation, a similar eutectic storage unit will be purchased for approximately $250/Ton-Hr including piping and installation. The ratio of Ton-Hrs required for partial storage and the required tank size will be utilized for sizing the full and optional partial storage systems. Table 19.9 summarizes the sizes and costs of the different storage systems and the actual chiller systems for each of the three storage arrangements. The values presented in this example are for a specific case and each application should be analyzed thoroughly. The cost per ton hour of a water system dropped significantly as the size of the tanks rises as will the eutectic systems since the engineering and installation costs are spread over more capacity. Also we ignored the sensible heat of the ice and eutectic systems.

19.5 ECONOMIC SUMMARY Table 19.9 covered the approximate costs of each of the three system configurations utilizing each of the three different storage mediums. Table 19.8 listed the various peak day performance parameters of each of the systems presented. To this point, the peak day chiller consumption has been used to size the system. To analyze the savings potential of the thermal storage systems, much more information is needed to determine daily cooling and chiller loads and the respective storage system performance. To calculate the savings accurately, a daily chiller consumption plot is needed for at least the summer peak period. These values can then be used to determine the chiller load required to satisfy the cooling demands. Only the summer months may be used since most of the cooling takes place and a majority of the utilities “time of use” charges (on-peak rates) are in effect during that time. There are several methods available to estimate or

simulate building cooling load. Some of these methods are available in a computer simulation format or can also be calculated by hand. For the office building presented earlier, an alternative method will be used to estimate cooling savings. An estimate of a monthly, average day cooling load will be used to compare the operating costs of the respective cooling configurations. For simplicity, it is assumed that the peak month is July and that the average cooling day is 90% of the cooling load of the peak day. The average cooling day for each of the months that make up the summer cooling period are estimated based upon July’s average cooling load. These factors are presented in Table 19.10 for June through October11. These factors are applied to the hourly chiller load of the average July day to determine the season chiller/TES operation loads. The monthly average day, hourly chiller loads for each of the three systems are presented in Table 19.11. The first column for each month in Table 19.11 lists the hourly cooling demand. The chiller consumption required to satisfy this load utilizing each of the storage systems is also listed. This table does not account for the thermal efficiencies used to size the systems but for simplicity, these values will be used to determine the rate and demand savings that will be achieved after implementing the system. The formulas presented for the peak day thermal storage systems operations have been used for simplicity. These chiller loads do not represent the optimum chiller load since some of partial systems approach full storage systems during the early and late cooling months. The bottom of the table contains the totals for the chiller systems. These totaled average day values will now be used to calculate the savings. The difference between the actual cooling load and the chiller load is the approximate daily savings for each day of that month. A hypothetical southwest utility rate schedule will be used to apply economic terms to these savings. The electricity consumption rate is $0.04/kWh and the de-

Table 19.10 Average summer day cooling load factors. ——————————————————————————————————————————— MONTH kW FACTOR1 PEAK TONS2 kWh FACTOR1 Ton-Hrs/day3 ——————————————————————————————————————————— JUNE 0.8 360 0.8 4,322 JULY 1 450 1 5,403 AUGUST 0.9 405 0.9 4,863 SEPT 0.7 315 0.7 3,782 OCT 0.5 225 0.5 2,702 ———————————————————————————————————————————

1kW and kWh factors were estimated to determine utility cost savings. 2The average day peak load is estimated to be 90% of the peak day. The kW factor for each month is multiplied by the peak months average tonnage. For JUNE: PEAK TONS = (0.8)*(450) = 360 3The average day consumption is estimated to be 90% of the peak day. The kWh factor for each month is multiplied by the peak months average consumption. For JUNE: CONSUMPTION = (0.8)*(5,403) = 4,322

THERMAL ENERGY STORAGE

533

Table 19.11 Monthly average day chiller load profiles.

mand rate during the summer is $3.50/kW per month for the peak demand during the off-peak hours and $5.00/ kW per month for the peak demand during the on-peak hours. These summer demand rates are in effect from June through October. This rate schedule only provides savings from balancing the demand, although utilities often have cheaper off-peak consumption rates. It can be seen that the off-peak demand charge assures that the demand is leveled and not merely shifted. This rate schedule will be applied to the total values in Table 19.11 and multiplied by the number of days in each month to determine the summer savings. These savings are contained in Table 19.12. The monthly average day loads in Table 19.11 are assumed to be 90% of the actual monthly peak billing demand, and are adjusted accordingly in Table 19.12. The total monthly savings for each of the chiller/TES systems is determined at the bottom of each monthly column. These cost savings are not the only monetary justification for implementing TES systems. Utilities often ex-

tend rebates and incentives to companies installing thermal energy storage systems to shorten their respective payback period. This helps the utility reduce the need to build new generation plants. The southwest utility serving the office building studied here offers $200 per design day peak kW shifted to off-peak hours up to $200,000.

19.6 CONCLUSIONS Thermal energy storage will play a large role in the future of demand side management programs of both private organizations and utilities. An organization that wishes to employ a system wide energy management strategy will need to be able to track, predict and control their load profile in order to minimize utility costs. This management strategy will only become more critical as electricity costs become more variable in a deregulated market. Real time pricing and multi-facility contracts will

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further enhance the savings potential of demand management, within which thermal energy storage should become a valuable tool. The success of the thermal storage system and the HVAC system as a whole depend on many factors:

to reduce the initial costs of the chiller system as well as savings in operation. Storage systems will become easier to justify in the future with increased mass production, technical advances, and as more companies switch to storage. References

•

The chiller load profile,

•

The utility rate schedules and incentive programs,

•

The condition of the current chiller system,

•

The space available for the various systems,

•

The selection of the proper storage medium, and

•

The proper design of the system and integration of this system into the current system.

Thermal storage is a very attractive method for an organization to reduce electric costs and improve system management. New installation projects can utilize storage

1. Cottone, Anthony M., “Featured Performer: Thermal Storage,” in Heating Piping and Air Conditioning, August 1990, pp. 51-55. 2. Hopkins, Kenneth J., and James W. Schettler, “Thermal Storage Enhances Heat Recovery,” in Heating Piping and Air Conditioning,, March 1990, pp. 45-50. 3. Keeler, Russell M., “Scrap DX for CW with Ice Storage,” in Heating Piping and Air Conditioning,, August 1990, pp. 59-62. 4. Lindemann, Russell, Baltimore Aircoil Company, Personnel Phone Interview, January 7, 1992. 5. Mankivsky, Daniel K., Chicago Bridge and Iron Company, Personnel Phone Interview, January 7, 1992. 6. Pandya, Dilip A., “Retrofit Unitary Cool Storage System,” in Heating Piping and Air Conditioning,, July 1990, pp. 35-37. 7. Science Applications International Corporation, Operation Performance of Commercial Cool Storage Systems Vols. 1 & 2, Electric Power Research Institute (EPRI) Palo Alto, September 1989. 8. Tamblyn, Robert T., “Optimizing Storage Savings,” in Heating Piping and Air Conditioning,, August 1990 pp. 43-46.

Table 19.12 Summer monthly system utility costs and TES savings.

Table 19.13 Available demand management incentives. ——————————————————————————————————————————— System Conventional Partial Full Optional Performance Parameters No Storage Storage Storage Partial ——————————————————————————————————————————— Actual On-Peak Demand1 (kW) 510 255 0 153 On-Peak Demand Shifted2 (kW)

255

510

357

Utility Subsidy3 ($) 51,000 102,000 71,400 ——————————————————————————————————————————— 1Yearly design peak demand from Table 19.8. 2Demand shifted from design day on-peak period. For partial: 510 kW - 255 kW = 255 kW. 3Based upon $200/kW shifted from design day on-peak period. For partial: 255 kW * $200/kW = $51,000.

THERMAL ENERGY STORAGE

Appendix 19-A Partial list of manufacturers of thermal storage systems. Source: Energy User News, Vol. 22, No. 12, December 1997. Manufacturer Storage Type Capacity (ton-hours) —————————————————————————————————————————————— Applied Thermal Technologies Ice, Ice coil 450 —————————————————————————————————————————————— Baltimore Aircoil Co. Ice, gylcol solid ice, ice coil 237-761 —————————————————————————————————————————————— Berg Chilling Systems Ltd. ice coil 100-10,000+ —————————————————————————————————————————————— Calmac Manufacturing Corp ice, glycol solid ice, eutectic 570 —————————————————————————————————————————————— CBI Walker Inc. water, hot water 2,000 -120,000+ —————————————————————————————————————————————— Chester-Jensen Co. Inc. ice coil 12-1,200 —————————————————————————————————————————————— Chicago Bridge & Iron Co. water 500+ —————————————————————————————————————————————— Cryogel ice, encapsulated ice 100-40,000 —————————————————————————————————————————————— Delta-Therm Corp. unlimited —————————————————————————————————————————————— Dunham-Bush Inc. ice 120, 180, 240 —————————————————————————————————————————————— FAFCO Inc. Ice, gylcol solid ice 125, 250, 375, 500 —————————————————————————————————————————————— Group Thermo Inc. water, hot water to 1,800 GPH —————————————————————————————————————————————— Henry Vogt Machine Co. ice unlimited —————————————————————————————————————————————— Morris & Associates ice 50 - 200 tons/day —————————————————————————————————————————————— Natgun Corp. ice, water 2,000 and up —————————————————————————————————————————————— Paul Mueller Co. ice slurry 3-1000+ —————————————————————————————————————————————— Perma Pipe water —————————————————————————————————————————————— Phoenix Thermal Storage ice, hot water 3 to 5 —————————————————————————————————————————————— Precision Parts Corp. hot water 440-17,800 gallons —————————————————————————————————————————————— Reaction Thermal Systems ice 242-4,244 —————————————————————————————————————————————— Steffes ETS Inc. ceramic brick 1.32-9 kW —————————————————————————————————————————————— Steibel Eltron Inc. ceramic brick —————————————————————————————————————————————— Store-More ice coil 270-20,000 ice, water, encapsulated ice, —————————————————————————————————————————————— The Trane Co. glycol solid ice, ice coil 60-145,000 —————————————————————————————————————————————— Turbo Refrigeration ice 10-340 —————————————————————————————————————————————— Vogt Tube Ice ice unlimited —————————————————————————————————————————————— York international Corp. ice 200 - 60,000 —————————————————————————————————————————————— 9. Thumann, Albert, Optimizing HVAC Systems The Fairmont Press, Inc., 1988. 10. Thumann, Albert and D. Paul Mehta, Handbook of Energy Engineering, The Fairmont Press, Inc., 1991. 11. Wong, Jorge-Kcomt, Dr. Wayne C. Turner, Hemanta Agarwala, and Alpesh Dharia, A Feasibility Study to Evaluate Different Options for Installation of a New Chiller With/Without Thermal Energy Storage System, study conducted for the Oklahoma State Office Buildings Energy Cost Reduction Project, Revised 1990.

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Appendix 19-B Partial list of Utility Cash Incentive Programs. Source: Dan Mankivsky, Chicago Bridge & Iron, August 1991. STATE CASH INCENTIVE - Electric Utility $/kW Shifted Maximum ——————————————————————————————————————————— ARIZONA - Arizona Public Service 75-125 no limit - Salt River Project 60-250 no limit CALIFORNIA - American Public Utilities Dept. - L.A. Dept of Water & Power - Pacific Gas & Electric - Pasadena Public Utility - Riverside Public Utility - Sacramento Municipal Util Dist. - San Diego Gas & Electric - Southern California Edison

60 250 300 300 200 200 50-200 100

50,000 40% cost 50%-70% no limit no limit no limit no limit 300,000

DISTRICT OF COLUMBIA - Patomac Electric Power Co.

200-250

no limit

FLORIDA - Florida Power & Light Co. - Florida Power Corp. - Tampa Electric Co.

250/ton 160-180 200

no limit 25% no limit

INDIANA - Indianapolis Power & Light - Northern Indiana Public Service

200 200/ton

no limit

MARYLAND - Baltimore Gas & Electric - Patomac Electric Power Co.

200 200-250

no limit no limit

MINNESOTA - Northern States Power

400/ton

no limit

NEVADA - Nevada Power

100-150

no limit

NEW JERSEY - Atlantic Electric - Jersey Central Power & Light - Orange & Rockland Utilities - Public Service Electric & Gas

150 300 250 125-250

200,000 250,000 no limit no limit

(Continued)

THERMAL ENERGY STORAGE

537

STATE CASH INCENTIVE - Electric Utility $/kW Shifted Maximum ——————————————————————————————————————————— NEW YORK - Central Edison Gas & Electric 25/Ton-Hr equip cost - Consolidated Edison Co. 600 no limit - Long Island Lighting Co. 300-500 no limit - New York State Electric & Gas 113 no limit - Orange & Rockland Utilities 250 no limit - Rochester Gas & Electric 200-300 70,000 NORTH DAKOTA - Northern States Power

400/ton

no limit

OHIO - Cincinnati Gas L Electric - Toledo Edison

150 200-250

no limit —

OKLAHOMA - Oklahoma Gas & Electric

125-200

225,000

PENNSYLVANIA - Metropolitan Edison - Orange & Rockland Utilities - Pennsylvania Electric - Pennsylvania Power & Light - Philadelphia Electric

100-250 250 250 100 100-200

40,000 no limit no limit no limit 25,000

SOUTH DAKOTA - Northern States Power

400/ton

no limit

300 200 250 350 125-250

150,000 no limit — — no limit

60 - 80 175 350

no limit no limit no limit

TEXAS - Austin Electric Department - El Paso Electric Company - Gulf States Utilities - Houston Lighting & Power - Texas Utilities (Dallas Power, Texas Electric Service, and Texas Power & Light) WISCONSIN - Madison Gas & Electric - Northern States Power - Wisconsin Electric Power

*Note: Some states have additional programs not listed here and some of the listed programs have additional limitations.

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CHAPTER 20

CODES, STANDARDS & LEGISLATION ALBERT THUMANN, P.E., CEM Association of Energy Engineers Atlanta, GA

resource planning; allow efficiency programs to be at least as profitable as new supply options; and encourage improvements in supply system efficiency.

CLINT CHRISTENSON Johnson Controls, Inc. Editor's Note: EPACT-2005 was just being made federal law as this edition was being finalized. Look for details of EPACT-2005 legislation in future editions. ————————————————————————— This chapter presents an historical perspective on key codes, standards, and regulations which have impacted energy policy and are still playing a major role in shaping energy usage. The Energy Policy Act of 1992 is far reaching and its implementation is impacting electric power deregulation, building codes and new energy efficient products. Sometimes policy makers do not see the far reaching impact of their legislation. The Energy Policy Act for example has created an environment for retail competition. Electric utilities will drastically change the way they operate in order to provide power and lowest cost. This in turn will drastically reduce utility sponsored incentive and rebate programs which have influenced energy conservation adoption.

20.1 THE ENERGY POLICY ACT OF 1992 This comprehensive legislation is far reaching and impacts energy conservation, power generation, and alternative fuel vehicles as well as energy production. The federal as well as private sectors are impacted by this comprehensive energy act. Highlights are described below: Energy Efficiency Provisions Buildings • Requires states to establish minimum commercial building energy codes and to consider minimum residential codes based on current voluntary codes. Utilities • Requires states to consider new regulatory standards that would: require utilities to undertake integrated

Equipment Standards • Establishes efficiency standards for: commercial heating and air-conditioning equipment; electric motors; and lamps. •

Gives the private sector an opportunity to establish voluntary efficiency information/labeling programs for windows, office equipment and luminaires, or the Dept. of Energy will establish such programs.

Renewable Energy • Establishes a program for providing federal support on a competitive basis for renewable energy technologies. Expands program to promote export of these renewable energy technologies to emerging markets in developing countries. Alternative Fuels • Gives Dept. of Energy authority to require a private and municipal alternative fuel fleet program starting in 1998. Provides a federal alternative fuel fleet program with phased-in acquisition schedule; also provides state fleet program for large fleets in large cities. Electric Vehicles • Establishes comprehensive program for the research and development, infrastructure promotion, and vehicle demonstration for electric motor vehicles. Electricity • Removes obstacles to wholesale power competition in the Public Utilities Holding Company Act by allowing both utilities and non-utilities to form exempt wholesale generators without triggering the PUHCA restrictions. Global Climate Change • Directs the Energy Information Administration to establish a baseline inventory of greenhouse gas emissions and establishes a program for the voluntary reporting of those emissions. Directs the Dept. of Energy to prepare a report analyzing the strategies

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for mitigating global climate change and to develop a least-cost energy strategy for reducing the generation of greenhouse gases. Research and Development • Directs the Dept. of Energy to undertake research and development on a wide range of energy technologies, including: energy efficiency technologies, natural gas end-use products, renewable energy resources, heating and cooling products, and electric vehicles.

20.2 STATE CODES The Energy Policy Act of 1992 called for states to establish minimum commercial building energy codes and to consider the same for residential codes. Prior to this regulation, many states had some level of energy efficiency included in building codes (ASHRAE 90-80, CA Title 24, etc.), but most did not address the advances in equipment, materials or designs that would impact energy usage. A 1991 study by the Alliance to Save Energy found that most states employed codes that were very outdated, which may have initiated that portion of EPACT-1992. The development of efficiency standards normally is undertaken by a consortium of interested parties in order to assure that the performance level is economically attainable. The groups for building efficiency standards are made up of building designers, equipment suppliers, construction professionals, efficiency experts, and others. There are several trade groups and research institutions that have developed standards as well as some states that developed their own. The approved standards are merely words on paper until a state or local agency adopts these standards into a particular building code. Once this occurs, officials (state or local) have the authority to inspect and assure that the applicable codes are enforced during design and construction. The main organization responsible for developing building systems and equipment standards, at least in the commercial sector is the American Society of Heating, Refrigeration, and Air-conditioning Engineers (ASHRAE). More than three quarters of the states have adopted ASHRAE Standard 90-80 as a basis for their energy efficiency standard for new building design. The ASHRAE Standard 90-80 is essentially “prescriptive” in nature. For example, the energy engineer using this standard would compute the average conductive

value for the building walls and compare it against the value in the standard. If the computed value is above the recommendation, the amount of glass or building construction materials would need to be changed to meet the standard. Most states have initiated “Model Energy Codes” for efficiency standards in lighting and HVAC. Probably one of the most comprehensive building efficiency standards is California Title 24. Title 24 established lighting and HVAC efficiency standards for new construction, alterations and additions of commercial and non-commercial buildings. ASHRAE Standard 90-80 has been updated into two new standards: ASHRAE 90.1-1999 Energy Efficient Design of New Buildings Except New Low-Rise Residential Buildings ASHRAE 90.2-1993 Energy Efficient Design of New Low Rise Residential Building The purposes of ASHRAE Standard 90.1-1999 are: (a)

set minimum requirement for the energy efficient design of new buildings so that they may be constructed, operated, and maintained in a manner that minimizes the use of energy without constraining the building function nor the comfort or productivity of the occupants.

(b)

provide criteria for energy efficient design and methods for determining compliance with these criteria.

(c)

provide sound guidance for energy efficient design.

In addition to recognizing advances in the performance of various components and equipment, the Standard encourages innovative energy conserving designs. This has been accomplished by allowing the building designer to take into consideration the dynamics that exist between the many components of a building through use of the System Performance Method or the Building Energy Cost Budget Method compliance paths. The standard, which is cosponsored by the Illuminating Engineering Society of North America, includes an extensive section on lighting efficiency, utilizing the Unit Power Allowance Method. The standard also addresses the design of the following building systems:

CODES, STANDARDS & LEGISLATION

• • • • • • •

Electrical power, Auxiliary systems including elevators and retail refrigeration, Building envelope, HVAC systems, HVAC equipment, Service water heating and equipment, and Energy Management.

ASHRAE has placed 90.1 and 90.2 under continuous maintenance procedures by a Standing Standard Project Committee, which allows corrections and interpretations to be adopted through addenda.

20.3 MODEL ENERGY CODE In 1994, the nation’s model code organizations, Council of American Building Officials (CABO), Building Officials and Code Administrators International (BOCA), International Conference of Building Officials (ICBO), and Southern Building Codes Congress International (SBCCI), created the International Code Council (ICC). The purpose of the new coalition was to develop a single set of comprehensive building codes for new residential and commercial buildings, and additions to such buildings. The 2000 International Energy Conservation Code (IECC) was published in February of 2000 along with ten other codes, collectively creating the 2000 Family of International codes. These codes are the successor to the 1998 IECC and the 1995 Model Energy Code (MEC) as well as all of the previous MECs. The IECC establishes minimum design and construction parameters for energy-efficient buildings through the use of prescriptive and performance based provisions. The 2000 IECC has been refined and simplified in response to the needs of the numerous users of the model energy code. It establishes minimum thermal performance requirements for building ceilings, walls, floors/foundations, and windows, and sets minimum efficiencies for lighting, mechanical and power systems in buildings. Currently EPACT-1992 references MEC 95 as the recommended building efficiency code. The Department of Energy is considering certifying the 2000 IECC as the most cost-effective residential energy-efficiency standard available. Once this determination is announced, EPACT-1992 requires states to determine the appropriateness of revising their residential energy codes to meet or exceed the 2000 IECC. The publication of the 2000 IECC offers states and local jurisdictions the opportunity to apply for financial

541

and technical assistance offered by DOE’s Building Standards and Guidelines Program. If the standards are codified by these entities, their code enforcement agencies will have opportunities to utilize the support infrastructure already established by the national model code organizations. More information can be obtained at the building Codes Assistance Projects web site: www. crest. org/efficiency/.

20.4 FEDERAL ENERGY EFFICIENCY REQUIREMENTS The federal sector is a very large consumer of energy in the United States. There are actually over 500,000 federal buildings with a combined energy cost of $10 billion per year. Managers and operators of these installations (mostly Department of Defense and Postal Service) have very little incentive to conserve energy or improve efficiency. Any work that is accomplished toward these goals would have normally been kept in the coffers and consumed by other functions as unencumbered funds. The OPEC oil embargo brought into focus the impact of energy costs and the US dependence on foreign sources of energy upon our economy. In 1975, the Energy Policy and Conservation Act directed the federal government to develop mandatory standards for agency procurement policies with respect to energy efficiency; and, develop and implement a 10-year plan for energy conservation in federal buildings, including mandatory lighting, thermal and insulation standards. This act was formalized with the Energy Conservation and Production Act in 1977, which established a 10% savings goal by 1985 over a 1975 baseline. The National Energy Conservation Policy Act of 1978 further defined the federal energy initiative with the following stipulations: •

Establishes the use of Life-cycle-cost (LCC) method of project analysis,

•

Establishes publication of Energy Performance Targets,

•

Requires LCC audits and retrofits of federal buildings by 1990,

•

Establishes Federal Photovoltaic Program,

•

Buildings exceeding 1000 square feet are subject to energy audits, and

•

Establishes a Federal Solar Program.

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In 1988 the Federal Energy Management Implementation Act (FEMIA 1988) amended the Federal Energy Initiative by removing the requirements to perform the LCC audits by 1990 and extended the deadline of 10 percent savings goals to 1995. FEMIA also allowed the Secretary of Energy to set the discount rate used in LCC analysis and directed the various federal agencies to establish incentive for energy conservation. The National Defense Authorization Acts for FY 89, 90, and 91 added the following provisions: •

Establishes incentive for shared energy savings contracts in DOD, allowing half of first year savings to be used for welfare, morale, and recreation activities at the facility. The other half to be used for additional conservation measures.

•

Expands DOD’s shared energy savings incentive to include half of first 5 years of savings.

•

Requires the Secretary of Defense to develop plan for maximizing Cost effective energy savings, develop simplified contracting method for shared energy savings, and report annually to congress on progress.

•

Expands DOD incentives to participate in utility rebate programs and to retain two-thirds of funds saved.

The President has power to invoke their own standards, in the form of Executive Orders, under which, agencies of the federal government must adhere. Presidents Bush and Clinton have both further increased and extended the efficiency improvements required to be undertaken by the federal sector. On June 3, 1999, President Clinton signed the order titled, “Greening the Government Through Efficient Energy Management.” The order required federal agencies to achieve by 2010: •

35% greater energy efficiency in buildings relative to 1985 levels, and

•

30% cut in greenhouse gas emissions from building-related energy use relative to 1990.

The order also directs agencies to maximize the use of energy savings performance contracts and utility contracts, in which private companies make energy improvements on federal facilities at their own expense and receive a portion of the resulting savings. Life cycle cost analysis must be used so agencies see the long term savings from energy

investments rather than merely the low bidder selection criteria. The order requires that everything from light bulbs to boilers be energy efficient as well as the use of renewable energy technologies and sources such as solar, wind, geothermal and biomass. This order also mandated that the DOE, DOD and GSA provide relevant training or training materials for those programs that they make available to all federal agencies relating to energy management strategies contained in this order. A complete text of E.O. 13123 can be found on the FEMP Web site www.greeninginterior.doi. gov/13123.html.

20.5 INDOOR AIR QUALITY (IAQ) STANDARDS1 Indoor Air Quality (IAQ) is an emerging issue of concern to building managers, operators, and designers. Recent research has shown that indoor air is often less clean than outdoor air and federal legislation has been proposed to establish programs to deal with this issue on a national level. This, like the asbestos issue, will have an impact on building design and operations. Americans today spend long hours inside buildings, and building operators, managers and designers must be aware of potential IAQ problems and how they can be avoided. IAQ problems, sometimes termed “Sick Building Syndrome,” have become an acknowledged health and comfort problem. Buildings are characterized as sick when occupants complain of acute symptoms such as headache, eye, nose and throat irritation, dizziness, nausea, sensitivity to odors and difficulty in concentrating. The complaints may become more clinically defined so that an occupant may develop an actual building-related illness that is believed to be related to IAQ problems. The most effective means to deal with an IAQ problem is to remove or minimize the pollutant source, when feasible. If not, dilution and filtration may be effective. Dilution (increased ventilation) is to admit more outside air to the building, ASHRAE’s 1981 standard recommended 5 CFM/person outside air in an office environment. The new ASHRAE ventilation standard, 62-1989, now requires 20 CFM/person for offices if the prescriptive approach is used. Incidentally, it was the energy cost of treating outside air that led to the 1981 standard. The superseded 1973 standard recommended 15-25 CFM/person. 1Source:

Indoor Air Quality: Problems & Cures, M. Black & W. Robertson, Presented at 13th World Energy Engineering Congress.

CODES, STANDARDS & LEGISLATION

Increased ventilation will have an impact on building energy consumption However, this cost need not be severe. If an airside economizer cycle is employed and the HVAC system is controlled to respond to IAQ loads as well as thermal loads, 20 CFM/person need not be adhered to and the economizer hours will help attain air quality goals with energy savings at the same time. In the fall of 1999 ASHRAE Standard 62-1999 was issued, “Ventilation for Acceptable Indoor Air Quality.” The new standard contained the entire 1989 version, which remains unchanged, along with four new addenda. The reference in the 89 standard that the ventilation levels could accommodate a moderate amount of smoking was removed, due to troubles with secondhand tobacco smoke. The new standard also removed reference to thermal comfort, which is covered by other ASHRAE Standards. Attempts were made to clarify the confusion concerning how carbon dioxide can be used to determine air contamination. A statement was also added to assure that designers understand that merely following the prescribed ventilation rates does not ensure acceptable indoor air quality. The Standard was added to the continuous review process, which will mandate firms keep up with the perpetual changes, corrections and clarifications. There are many issues that are still under review as addendums to the standard. The types of buildings that are covered were limited to commercial and institutional, and the methods of calculation of the occupancy levels have been clarified. ASHRAE offers a subscription service that updates all addendum and interpretations. One of the main issues that should be considered during design of HVAC systems is that the outdoor air ventilation is required to be delivered cfm, which may be impacted with new variable volume air handling systems. Energy savings can be realized by the use of improved filtration in lieu of the prescriptive 20 CFM/ person approach. Improved filtration can occur at the air handler, in the supply and return ductwork, or in the spaces via self-contained units. Improved filtration can include enhancements such as ionization devices to neutralize airborne biological matter and to electrically charge fine particles, causing them to agglomerate and be more easily filtered. The Occupational Safety and Health Administration (OSHA) announced a proposed rule on March 25, 1994 that would regulate indoor air quality (IAQ) in workplaces across the nation. The proposed rule addresses all indoor contaminants but a significant step would ban all smoking in the workplace or restrict it to specially designed lounges exhausted directly

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to the outside. The smoking rule would apply to all workplaces while the IAQ provisions would impact “non-industrial” indoor facilities. There is growing consensus that the most promising way to achieve good indoor air quality is through contaminant source control. Source control is more cost effective than trying to remove a contaminant once it has disseminated into the environment. Source control options include chemical substitution or product reformulating, product substitution, product encapsulation, banning some substances or implementing material emission standards. Source control methods except emission standards are incorporated in the proposed rule.

20.6 REGULATIONS & STANDARDS IMPACTING CFCs For years, chlorofluorocarbons (CFCs) were used in air-conditioning and refrigeration systems. However, because CFCs are implicated in the depletion of the earth’s ozone layer, regulations required the complete phaseout of the production of new CFCs by the turn of the century. Many companies, like DuPont, developed alternative refrigerants to replace CFCs. The need for alternatives will become even greater as regulatory cutbacks cause continuing CFC shortages. Air-conditioning and refrigeration systems designed to operate with CFCs will need to be retrofitted (where possible) to operate with alternative refrigerants so that these systems can remain in use for their intended service life. DuPont and other companies are commercializing their series of alternatives—hydrochlorofluorocarbon (HCFC) and hydrofluorocarbon (HFC) compounds. See Table 20.1. The Montreal Protocol which is being implemented by the United Nations Environment Program (UNEP) is a worldwide approach to the phaseout of CFCs. A major revision to the Montreal Protocol was implemented at the 1992 meeting in Copenhagen which accelerated the phaseout schedule. The reader is advised to carefully consider both the “alternate” refrigerants entering the market place and the alternate technologies available. Alternate refrigerants come in the form of HCFCs and HFCs. HFCs have the attractive attribute of having no impact on the ozone layer (and correspondingly are not named in the Clean Air Act). Alternative technologies include absorption and ammonia refrigeration (established technologies since the early 1900’s), as well as desiccant cooling. Taxes on CFCs originally took effect January 1,

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Table 20.1 Candidate Alternatives for CFCs in Existing Cooling Systems ——————————————————————————————————————————————————— CFC Alternative Potential Retrofit Applications CFC-11

HCFC-123

Water and brine chillers; process cooling

CFC-12

HFC-134a or Ternary Blends

Auto air conditioning; medium temperature commercial food display and transportation equipment; refrigerators/freezers; dehumidifiers; ice makers; water fountains

CFC-114

HCFC-124

Water and brine chillers

R-502 HFC-125 Low-temperature commercial food equipment ——————————————————————————————————————————————————— 1990. The Energy Policy Act of 1992 revised and further increased the excise tax effective January 1, 1993. Another factor to consider in ASHRAE Guidelines 3-1990—Reducing Emission of Fully Halogenated Chlorofluorocarbon (CFC) Refrigerants in Refrigeration and Air-Conditioning Equipment and Applications: The purpose of this guideline is to recommend practices and procedures that will reduce inadvertent release of fully halogenated chlorofluorocarbon (CFC) refrigerants during manufacture, installation, testing, operation, maintenance, and disposal of refrigeration and air-conditioning equipment and systems. The guideline is divided into 13 sections. Highlights are as follows: The Design Section deals with air-conditioning and refrigeration systems and components and identifies possible sources of loss of refrigerants to atmosphere. Another section outlines refrigerant recovery reuse and disposal. The Alternative Refrigerant section discusses replacing R11, R12, R113, R114, R115 and azeotropic mixtures R500 and R502 with HCFCs such as R22.

20.7 REGULATORY AND LEGISLATIVE ISSUES IMPACTING AIR QUALITY 20.7.1 Clean Air Act Amendment On November 15, 1990, the new Clean Air Act (CAA) was signed by President Bush. The legislation includes a section entitled Stratospheric Ozone Protection (Title VI). This section contains extraordinarily comprehensive regulations for the production and use of CFCs, halons, carbon tetrachloride, methyl

chloroform, and HCFC and HFC substitutes. These regulations will be phased in over the next 40 years, and they will impact every industry that currently uses CFCs. The seriousness of the ozone depletion is such that as new findings are obtained, there is tremendous political and scientific pressure placed on CFC end-users to phase out use of CFCs. This has resulted in the U.S., under the signature of President Bush in February 1992, to have accelerated the phaseout of CFCs. 20.7.2 Kyoto Protocol The United States ratified the United Nations’ Framework Convention on Climate Change, which is also known as the Climate Change Convention, on December, 4, 1992. The treaty is the first binding international legal instrument to deal directly with climate change. The goal is to stabilize green house gases in the atmosphere that would prevent human impact on global climate change, The nations that signed the treaty come together to make decisions at meetings call Conferences of the Parties. The 38 parties are grouped into two groups, developed industrialized nations (Annex I countries) and developing countries (Annex 11). The Kyoto Protocol, an international agreement reached in Kyoto in 1997 by the third Conference of the Parties (COP-3), aims to lower emissions from two groups of three greenhouse gases: Carbon dioxide, methane, and nitrous oxide and the second group of hydrofluorocarbon (HFCs), sulfur hexafluoride and perfluorocarbons. Emissions are meant to be reduced and limited to levels found in 1990 or 1995, depending upon the gases considered. The requirements will impact future clean air amendments, particularly for point sources. These requirements will further impact the implementation of distributed generation sources, which are discussed in the following section.

CODES, STANDARDS & LEGISLATION

20.8 REGULATORY AND LEGISLATIVE ISSUES IMPACTING COGENERATION & INDEPENDENT POWER PRODUCTION2 Federal, state and local regulations must be addressed when considering any cogeneration project. This section will provide an overview of the federal regulations that have the most significant impact on cogeneration facilities. 20.8.1 Federal Power Act The Federal Power Act asserts the federal government’s policy toward competition and anticompetitive activities in the electric power industry. It identifies the Federal Energy Regulatory Commission (FERC) as the agency with primary jurisdiction to prevent undesirable anti-competitive behavior with respect to electric power generation. Also, it provides cogenerators and small power producers with a judicial means to overcome obstacles put in place by electric utilities. 20.8.2 Public Utility Regulatory Policies Act (PURPA) This legislation was part of the 1978 National Energy Act and has had perhaps the most significant effect on the development of cogeneration and other forms of alternative energy production in the past decade. Certain provisions of PURPA also apply to the exchange of electric power between utilities and cogenerators. PURPA provides a number of benefits to those cogenerators who can become Qualifying Facilities (QFs) under the act. Specifically, PURPA •

Requires utilities to purchase the power made available by cogenerators at reasonable buy-back rates. These rates are typically based on the utilities’ cost.

•

Guarantees the cogenerator or small power producer interconnection with the electric grid and the availability of backup service from the utility.

•

Dictates that supplemental power requirements of cogenerator must be provided at a reasonable cost.

•

Exempts cogenerators and small power producers from federal and state utility regulations and associated reporting requirements of these bodies.

In order to assure a facility the benefits of PURPA, a cogenerator must become a Qualifying 2Source:

Georgia Cogeneration Handbook, published by the Governor’s Office of Energy Resources.

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Facility. To achieve Qualifying Status, a cogenerator must generate electricity and useful thermal energy from a single fuel source. In addition, a cogeneration facility must be less than 50% owned by an electric utility or an electric utility holding company. Finally, the plant must meet the minimum annual operating efficiency standard established by FERC when using oil or natural gas as the principal fuel source. The standard is that the useful electric power output plus one half of the useful thermal output of the facility must be no less than 42.5% of the total oil or natural gas energy input. The minimum efficiency standard increases to 45% if the useful thermal energy is less than 15% of the total energy output of the plant. 20.8.3 Natural Gas Policy Act (NGPA) The major objective of this legislation was to create a deregulated national market for natural gas. It provides for incremental pricing of higher cost natural gas supplies to industrial customers who use gas, and it allows the cost of natural gas to fluctuate with the cost of fuel oil. Cogenerators classified as Qualifying Facilities under PURPA are exempt from the incremental pricing schedule established for industrial customers. 20.8.4 Resource Conservation and Recovery Act of 1976 (RCRA) This act requires that disposal of non-hazardous solid waste be handled in a sanitary landfill instead of an open dump. It affects only cogenerators with biomass and coal-fired plants. This legislation has had little, if any, impact on oil and natural gas cogeneration projects. 20.8.5 Public Utility Holding Company Act of 1935 The Public Utility Holding Company Act of 1935 (the 35 Act) authorizes the Securities and Exchange Commission (SEC) to regulate certain utility “holding companies” and their subsidiaries in a wide range of corporate transactions. The Energy Policy Act of 1992 creates a new class of wholesale-only electric generators—“exempt wholesale generators” (EWGs)—which are exempt from the Public Utility Holding Company Act (PUHCA). The Act dramatically enhances competition in U.S. wholesale electric generation markets, including broader participation by subsidiaries of electric utilities and holding companies. It also opens up foreign markets by exempting companies from PUHCA with respect to retail sales as well as wholesale sales.

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20.8.6 Moving towards a deregulated electric power marketplace EPACT-1992 set into motion a widespread movement for utilities to become more competitive. Retail wheeling proposals were set into motion in states such as California, Wisconsin, Michigan, New Mexico, Illinois and New Jersey. There are many issues involved in a deregulated power marketplace and public service commission rulings and litigation will certainly play a major role in the power marketplace of the future. Deregulation has already brought about several important developments: •

Utilities will need to become more competitive. Downsizing and minimization of costs including elimination of rebates are the current trend. This translates into lower costs for consumers. For example Southern California Edison announced that the system average price will be reduced from 10.7 cents/kWh to lower than 10 cents by the year 2000. This would be a 25% reduction after adjusting for inflation.

•

Utilities will merge to gain a bigger market share. For example, Wisconsin Electric Power Company merged with Northern States Power; this merger of two utilities resulted in a savings of $2 billion over 10 years.

•

Utilities are forming new companies to broaden their services. Energy service companies, financial loan programs and purchasing of related companies are all part of the new utility strategy.

•

In 1995 one hundred power marketing companies have submitted applicants to FERC. Power marketing companies will play a key role in brokering power between end users and utilities in different states and in purchasing of new power generation facilities.

•

Utilities will need to restructure to take advantage of deregulation. Generation Companies may be split away from other operating divisions such as transmission and distribution. Vertical disintegration will be part of the new utility structure.

•

Utilities will weigh the cost of repowering and upgrading existing plants against purchasing power from a third party.

Chapter 24 discusses many more issues on the topic of electrical deregulation.

20.9 OPPORTUNITIES IN THE SPOT MARKET3 Basics of the Spot Market A whole new method of contracting has emerged in the natural gas industry through the spot market. The market has developed because the Natural Gas Policy Act of 1978 (NGPA) guaranteed some rights for end-users and marketers in the purchasing and transporting of natural gas. It also put natural gas supplies into a more competitive position with deregulation of several categories. The Federal Energy Regulatory Commission (FERC) provided additional rulings that facilitated the growth of the spot market. These rulings included provisions for the Special Marketing Programs in 1983 (Order 2346) and Order 436 in 1985, which encouraged the natural gas pipelines to transport gas for end-users through blanket certificates. The change in the structure of markets in the natural gas industry has been immense in terms of both volumes and the participants in the market. By year-end 1986, almost 40% of the interstate gas supply was being transported on a carriage basis. Not only were end-users participating in contract carriage, but local distribution companies (LDCs) were accounting for about one half of the spot volumes on interstate pipelines. The “spot market” or “direct purchase” market refers to the purchase of gas supplies directly from the producer by a marketer, end-user or LDC. (The term “spot gas” is often used synonymously with “best efforts gas,” “interruptible gas,” “direct purchase gas” and “self-help gas.”) This type of arrangement cannot be called new because the pipelines have always sold some supplies directly to end-users. The new market differs from the past arrangements in terms of the frequency in contracting and the volumes involved in such contracts. Another characteristic of the spot market is that contracts are short-term, usually only 30 days, and on an interruptible basis. The interruptible nature of spot market supplies is an important key to understanding the operation of the spot market and the costs of dealing in it. On both the production and transportation sides, all activities in transportation or purchasing supplies are on a “best efforts” basis. This means that when a cold snap comes the direct purchaser may not get delivery on his contracts because of producer shutdowns, pipeline capacity and operational problems or a combination of these problems. The “best efforts” approach to dealing can also lead to problems in transporting supplies

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when demand is high and capacity limited. FERC’s Order No. 436 The impetus for interstate pipeline carriage came with FERC’s Order No. 436, later slightly changed and renumbered No. 500, which provided more flexibility in pricing and transporting natural gas. In passing the 1986 ruling, FERC was attempting to get out of the day-to-day operations of the market and into more generic rule making. More significantly, FERC was trying to get interstate pipelines out of the merchant business into the transportation business—a step requiring a major restructuring of contracting in the gas industry. FERC has expressed an intent to create a more competitive market so that prices would signal adjustments in the markets. The belief is that direct sales ties between producers and end-users will facilitate market adjustments without regulatory requirements clouding the market. As more gas is deregulated, FERC reasoned that natural gas prices will respond to the demand: Lower prices would assist in clearing excess supplies; then as markets tightened, prices would rise drawing further investment into supply development. FERC Order No. 636 Order 636 required significant “Restructuring” in interstate pipeline services, starting in the fall of 1993. The original Order 636: •

Separates (unbundles) pipeline gas sales from transportation

•

Provides open access to pipeline storage

•

Allows for “no notice” transportation service

•

Requires access to upstream pipeline capacity

•

Uses bulletin boards to disseminate information

•

Provides for a “capacity release” program to temporarily sell firm transportation capacity

•

Pregrants a pipeline the right to abandon gas sales

•

Bases rates on straight fixed variable (SFV) design

•

Passes through 100% of transition costs in fixed monthly charges to firm transport customers

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FERC Order No. 636A Order 636A makes several relatively minor changes in the original order and provides a great deal of written defense of the original order’s terms. The key changes are: •

Concessions on transport and sales rates for a pipeline’s traditional “small sales” customers (like municipalities).

•

The option to “release” (sell) firm capacity for less than one month—without posting it on a bulletin board system or bidding.

•

Greater flexibility in designing special transportation rates (i.e., off-peak service) while still requiring overall adherence to the straight fixed variable rate design.

•

Recovery of 10% of the transition costs from the interruptible transportation customers (Part 284).

Court action is still likely on the Order. Further, each pipeline will submit its own unique tariff to comply with the Order. As a result, additional changes and variations are likely to occur.

20.10 THE CLIMATIC CHANGE ACTION PLAN The Climatic Change Action Plan was established April 21, 1993 and includes the following: •

Returns U.S. greenhouse gas emissions to 1990 levels by the year 2000 with cost effective domestic actions.

•

Includes measures to reduce all significant greenhouse gases, carbon dioxide, methane, nitrous oxide, hydrofluorocarbons and other gases.

20.11 SUMMARY The dynamic process of revisions to existing codes plus the introduction of new legislation will impact the energy industry and bring a dramatic change. Energy conservation and creating new power generation supply options will be required to meet the energy demands of the twenty-first century.

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CHAPTER 21

NATURAL GAS PURCHASING CAROL FREEDENTHAL JOFREEnergy Consulting Houston, Texas

21.1 PREFACE This is the second full revision for this chapter, Natural Gas Purchasing. Chapter 21 was originally written when the book was published in 1993. Rewrite for the first revision was a completely new effort done in 1996. As of 2000, the industry has continued to change and is still in the conversion from a federally regulated, price-controlled business to an economically dynamic, open industry, and this is a completely revised writing. Changes are continuing to shape the industry differently, especially when coupled with the changes coming from the potential decontrol of the electric power industry. To make even more changes, the impact of ECommerce business-to-business is beginning to play a role in this industry. When this revision was started, only one company offered the web for gas marketing. As of 2000, five additional companies had launched ECommerce business-to-business natural gas trading. The old natural gas business is really a new business. Its structure goes back 150 years but it is more like a new industry. It has the typical growth and turmoil of a new business. Energy products, especially natural gas and electricity, are new businesses as the country goes into the new millennium. Newly “reformed” companies, new marketing organizations, new systems affecting gas marketing, and even, a new industry structure makes it necessary to start from scratch in writing the revision for this chapter. Like the new millennium, the natural gas industry and equally as important, the total energy business is going through its own transition. Change will continue as companies and businesses try different strategies. ECommerce will play a major role in the industry’s transition. This phase of the transition is amorphous and makes it difficult to predict the exact course of events for the future. Things that appeared far-out years ago are becoming closer to reality. The newest buzzwords, “distributive electricity” includes the use of fuel cells and small dual cycle turbine driven generators by residential 549

and small commercial users. Both of these are becoming economically feasible. The impact on the gas and electric industries is unknown. This is a time of change for the new energy business. Marketing and supplying energy products like natural gas and electricity will go through many changes before optimum conditions are found. A few things are for sure. Natural gas is becoming the major fuel for stationary power uses in the United States. Long dominated by oil products for this use, now gas is becoming the leader. Coal continues as a major fuel source for electric generation. Consumption of coal for power generation has reached record levels in recent years but environmental concerns and the required high capital for new coal burning generating plants will reduce coal’s market share. The public’s dislike of nuclear power and the high costs to build plants with the safety desired means no growth for this industry. A new philosophy will have to be developed by society recognizing safety and environmental benefits of atomic power before new nuclear facilities will be built. The natural gas industry, just like the power industry, which is going through its own decontrol activities, change will be a way of life always. Companies in the energy field and in associated areas such as communications, financial, systems, etc. will continue to merge, acquire, spin off, and change their structure and goals. As the country goes into the new millennium, these are industries in transition and will change along with the growth industries in cyberspace. A big difference from the old, staid and conservative electric and gas utilities of the prior century! Change and growth are the way. Regardless of this, one factor continues to dominate. The profit motive is still the driving force of the industry today. It will not change but will continue into the future. Economics will govern change and be the basis for decision making. All the transformations—buying and selling of companies, new marketing companies, new systems for handling the merged assets, etc. will all be subject to one metric; is it profitable? Already, some acquisitions made by large electric and gas companies to bring together various parts of the energy industry have come apart because the final economics did not pass muster. The purpose of this chapter is to give the fuel buyer, for any operations or industry, the knowledge and infor-

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mation needed to buy natural gas for fuel. The buyer may be in a large petrochemical plant where natural gas is a major raw material or may be the commercial user having hundreds of apartments needing gas for heat and hot water or plant operator where the gas is used for process steam. It might be a first time experience or an on-going job for the buyer. This chapter will give the background and information to find natural gas supplies for any need at the lowest cost and highest service and security. The chapter will include information on history of the industry, sources of supply, transportation, distribution, storage, contracts, regulatory, and financial considerations needed to buy natural gas.

21.2 INTRODUCTION Natural gas is predominately the compound “methane,” CH4. It has the chemical structure of one carbon atom and four hydrogen atoms. It is the simplest of the carbon based chemicals and has been a fuel for industry, for illumination, and for heating and some cooling of homes, offices, schools, and factories. Natural gas is also, a major fuel for generating electricity. In addition to fuel uses, gas is a major feedstock for the chemical industry in making such products and their derivatives as ammonia and methanol. Natural gas is used in refining and chemical plants as a source for hydrogen needed by these processing businesses. Through the reforming process, hydrogen is stripped from the methane leaving carbon dioxide, which has its usefulness in chemical manufacturing or use, by itself in cooling, carbonated drinks, or crude oil recovery. The term “natural gas industry” includes the people, equipment, and systems starting in the fields where the wells are located and the natural gas is produced. It includes other field tasks as gathering, treating, and processing. Transportation to storage or to interstate or intrastate pipelines for further transportation to the market area storage, or to the distribution system for delivery to the consumer and the burner tip, are part of the system. The burner tip might be in a boiler, hot water heater, combustion engine, or a chemical reactor to name a few of the many uses for natural gas. Natural gas is produced in the field by drilling into the earth’s crust anywhere from a couple of thousand feet to five miles in depth. Once the gas is found and the well completed to bring the gas to the earth’s surface, it is treated if necessary to remove acid impurities and again, if necessary, processed to take out liquid hydrocarbons of longer carbon chains than methane, which has a single carbon atom. After processing, the gas is transported in

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pipelines to consuming areas where distribution companies handle the delivery to the specific consumer. In addition to the people and companies directly involved in the production, transportation, storage, and marketing of natural gas, there are countless other businesses and people involved in assisting the gas industry to complete its tasks. There are systems companies, regulatory and legal professionals, financial houses, banks, and a host of other businesses assisting the natural gas industry. Figure 21.1 shows the many parts of the industry as it is known today. The money flowing through the major sections of the industry are shown in Figure 21.2. The $85 billion industry shown in the diagram only represents the functions in getting natural gas, the commodity, to market and consumption. Not included in the overall industrial revenues are the moneys generated by the sales and resale of gas before its consumption, the processing and marketing of natural gas liquids coming from the gas, and the financial markets where gas futures and other financial instruments are sold and traded. These are big businesses also. Estimates are that the physical gas is traded three to four times before consumption. In the financial markets, gas volumes 10 to 12 times the amount of gas consumed on an average day are traded daily. Figure 21.3 should be of most interest to the natural gas buyer as it depicts the various sales points, stages, and handling the gas goes through in getting from the wellhead to the burner tip—from the wellhead to the consumer. As one can see in the diagram, there are many alternate paths the gas can travel before coming to its end use as a fuel or feedstock for chemical manufacturing. Each one of the stages on the flowsheet represents an added value point in the travel to consumption. Raw gas coming from the wellhead many times has sufficient quality to go directly into a transporting pipeline for delivery to the consuming area. Sometimes the gas needs field treating and/or processing to meet pipeline specifications for acceptance into the pipeline. The gas industry is the oldest utility except for water and sanitation. In the middle of the 19th century, many large cities used a synthetic gas made from passing steam over coal to light downtown areas and provide central heating systems. Big cities like Baltimore, New York, Boston, and many more cities and municipalities used gas for illumination. Many utilities from that period exist today and are still gas and electric suppliers to the areas they serve. In the early days of the gas business, there was no natural gas, as known today. Instead, these utilities produced a synthetic gas for both the illumination and the central heating systems. The synthetic gas, sometimes called “water gas” because of the method of producing it,

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Figure 21.1 Natural Gas Industry Flowsheet.

Figure 21.2 Gas Industry Money Flow for Business Activities.

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Figure 21.3 Wellhead to Consumer Flowsheet had bad attributes—it contained a high content of hydrogen and carbon monoxide, two bad actors for a gas used in homes, businesses, and factories. People died when exposed to it because of the carbon monoxide, and buildings blew-up because of the hydrogen when free gas from leaks or pipe ruptures was ignited. When natural gas came on the scene in the early 1900s, where it was available, it quickly replaced the old manufactured gas. About the same time, advances were made in electricity so that cities and municipalities changed to electricity for lighting and illumination. Natural gas quickly lost its market for municipal lighting. Natural gas was originally an unwanted by-product from the oil fields. Problem was getting rid of it. Flaring was used, but this was a waste of good natural resources. Around the beginning of the century, associated gas from Ohio oil fields was shipped to Cleveland in wooden pipes to replace the then used synthetic gas. In the early days of the industry, the limitations to greater uses of natural gas were that gas was produced in only certain parts of the country and transportation was available for only very short distances. Market penetration was thwarted by the ability to ship it. There were no long distance pipelines in the early days of the industry. Natural gas made a great replacement for the synthetic counterpart—methane is essentially safe as far as toxicity and is much safer as far as explosion. Gas’ growth was dependent on building long distance pipelines. Not until the 1930s did the industry have the capability of making strong enough, large steel piping needed for the long-distance pipelines. Completion of major interstate pipelines to carry gas from producing regions to consumers was the highlight of the 1930s to the start of World War II in the early 1940s. Pipeline construction came to a halt and was dormant until the war’s end. Construction went full force

after the war to insure delivering the most economical and easiest fuel to America’s homes, commercial facilities and industrial players. Even today with the start of the new millennium, some areas of the U.S. still do not have a fully developed natural gas distribution and delivery system. Areas in the West where population is sparse, parts of the Northeast where oil prices were too competitive to delivered gas prices, and other parts of the country lacking distribution systems for the same reasons are still without natural gas. Many of these use what is called “bottled gas,” a mixture of propane and butane or propane only for home heating and other critical uses. Just recently, new supplies and pipelines were developed to bring natural gas to the Northeast U.S. from Canada. Additional distribution systems will bring more gas to more customers through the country from the tip of Florida to the North Central and West Northern states. Ever since natural gas became available for fuel, it was under some form of government economic control. Through the tariff mechanism for pricing natural gas, the government had the power to make gas prices more or less attractive to competing fuels. Further, with the government controlling wellhead prices and slow to make changes in prices as conditions changed, it became difficult and economically undesirable to expand natural gas production. Government price controls hampered the growth of the U.S. natural gas business. The gas shortages of the mid-1970s are an example of government control stifling expansion and growth. There was no shortage of gas reserves, only a shortage of incentives for producers to develop and supply the gas. The free market builds its own controls to foster competition and growth. Congress passed the Natural Gas Policy Act of 1978 to change the policy of government economic control. A few years of transition were needed before significant changes began in the industry. Real impact started in 1985. Even today, the industry is still in transition. The federal decontrol changed interstate marketing and movement of natural gas. Gas at the local levels where the state Public Utility Commission or similar local government has control, is still heavily regulated. Decontrol at the federal level is slowly filtering down to local agencies. As of 2002, some states began moving to “open transportation” rules. A current obstacle to the swifter implementation of rules at the state and local levels is the tie of gas and electricity as utilities within state regulatory control. With the electric industry going through its own “decontrol,” many wanted to see the much larger electric industry work out the utility problems. Then gas could follow with less negotiating and discussion. The electric timetable is now years behind its planned evolution and this has slowed gas local control further.

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With the price of gas changing each year, the total industry value changes. The industry in nominal annual terms is roughly a $100 Billion business. Electricity is around $230 Billion. Many electric companies that were both gas and electricity utilities even before deregulation, have bought major natural gas pipelines or gas distributors. Large electric companies bought into the natural gas industry whether they purchased transporters, distributors, or marketing companies. Interestingly, in a relatively few years, some of these combinations have come apart because of poor profitability. Electric and gas utility companies have gone after transportation and marketing companies. Surprisingly, none of the expanding companies have sought to buy, at the beginning of the gas business, the oil and gas exploration and production companies (E&P companies). These are the companies looking for natural gas and then producing it. While all of the transporting companies, whether long distance or distribution in nature and, further, whether electric and/or natural gas in business, have shied away from the production companies, other E&P companies have merged or acquired smaller operations to add to the total capability of the company. The significant changes during the 1990's saw major E&P companies acquire even major and independent E&P assets. 21.3 NATURAL GAS AS A FUEL Why has natural gas grown in popularity? What makes it a fuel of choice in so many industries as the new millennium begins? What shortcomings does it have? Figure 21.4 shows the change in basic fuels mix used in the U.S. in 1985 and 1999. Nuclear, which started in 1960, enjoyed a period of rapid growth. The high costs for all the safety engineered into the plants had made it an uneconomical system towards the end of the century. There are no nuclear plants scheduled for construction. Even some of those completed and running and some with the initial construction still in progress were shut down or converted

into natural gas fired units. The only change that will be seen in nuclear generation of electricity is plant efficiencies will be improved for the units continuing to operate. Coal usage in the U.S. has grown in recent years with record coal production in the late 1990s. Coal is by far the major fuel used for electric generation, commanding a 56% market share. It has many negative properties like the need for railroads for transportation, high pollution from the burner after-products, and poor handling characteristics including being dirty, losses on storage, and the difficulties of moving a solid material, including the disposal of the remaining ash. Still, coal has a number of things going for it which will keep coal in use for many years to come. The ready availability and abundance are major merits. The stability of coal prices will always give coal a place in the market. Figure 21.5 shows the comparison in prices among coal, natural gas, and oil products for the period 1985 through 1999. Coal at about a dollar per million British units (MMBtu) is not only much cheaper per unit of energy, but also has the advantages of availability and abundance. Coal will slowly lose position because of its disadvantages of pollution and higher costs to meet changing standards and high capital costs for building new generating plants. Petroleum products have lost market share in the later years because of their costs and the dependence of the U.S. on foreign suppliers for crude and crude oil products. Oil products used for electric generation include distillate fuel oil, a relatively lightweight oil, which during the refining process can have most of the sulfur removed during that process. Low sulfur fuels are desirable to keep emissions low for environmental reasons. The other major oil product used is residual fuel oil, the bottom of the barrel from the refining process. This is a heavy, hard to transport fuel with many undesirable ingredients that become environmental problems after combustion. Many states have put costly tariffs on using residual fuel oil because of its environmental harm when used.

Figure 21.4 U.S. Basic Fuels 1985 & 1999 (Quadrillion Btu)

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Natural gas is the nation’s second largest source of fuel and a major source of feedstock for chemical production. Plentiful supplies at economically satisfactory prices, a well developed delivery system of pipelines to bring gas from the wellhead to the consumer, and its environmental attractiveness has made natural gas the choice of fuel for many applications. Going into the new millennium, natural gas will be a popular fuel. As a fuel for industry for heating and generating electricity and as a feedstock for chemicals, natural gas is very attractive. For residential and commercial applications, the security of supply and efficiency in supplying makes it an ideal fuel. Even though natural gas is a fossil fuel, it has the lowest ratio of combustion-produced carbon dioxide to energy released. Carbon dioxide is the biggest culprit in the concern for global warming. Natural gas consumption data are followed in four major areas by the Federal Energy Information Agency in addition to its listing the data for natural gas used in the fields for lease and plant fuel and as fuel for natural gas pipelines; residential, commercial, industrial, and electric generation. Natural gas demand has always, in modern times led the amount of gas produced except for the mid1970s when the country experienced a severe natural gas supply shortage. In those years, while there were more than sufficient reserves in the ground to meet demand, the control of gas pricing by the federal government stymied the initiative of producers to meet demand. Potential supply was available but the lack of profit incentive prevented meeting demand in those years. Demand increased because of changes and shortages in crude oil supplies. Early 1970s were the start of the change in

crude pricing and the country was faced with decreased supplies from foreign producers. Crude prices doubled almost overnight, but because natural gas was price controlled and could not meet the rising prices, supplies in the interstate market suffered. The major market for natural gas is the industrial sector. Residential is next and commercial and electric generating take about the same amount. Figure 21.6 graphically depicts the share each market took for 1999. The residential market is basically for home heating and hot water fuel. The commercial market is for space heating. Use of natural gas in industrial plants when used for space heating is included in this category. The industrial category covers all other uses of natural gas in industry and includes gas used by industrial locations for power generation until earlier 2000. All power generation is now included in the category of electric generation. The major demand factor in all categories is weather. Residential and commercial consumption are most affected by weather since these two categories reflect space heating. Electric generation is weather sensitive also since the summer electric load is responsive to the air conditioning load needed for the hot weather. Even though the industrial load is not as sensitive to weather as are other categories, it does reflect the additional heating load needed for the process industries when temperatures fall and raw materials including process air and/or water are much colder. Natural gas has tremendous potential to gain even greater use in the generation of electricity in several ways. First, it could be the choice fuel to replace aging nuclear plants that will not be re-certified as they age. Further

Figure 21.5 Fuel Prices for Generating Electricity 1995-1999

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NOTE: INDUSTRIAL INCLUDES INDEPENDENT POWER PRODUCTION JOFREE HOUSTON, TX 77002 CF 20 JUN 2000

Figure 21.6 Natural Gas Markets 1999 as coal plants age and need replacement or need to be replaced because of environmental causes, natural gas is the ideal fuel. It is easier to get to the plant and handle in the plant, the environmental needs are much smaller, and the capital required for the generating plant and facilities is much lower. Natural gas is the fuel of choice among the fuels currently available. Even if the electric systems in effect now were to change to more “distributive” in nature, such as fuel cells or small, dual cycle gas turbines, natural gas would be the ideal fuel. Some planners see fuel cells or turbines being used by residential units so that each household could have its own source of electricity. When houses needed additional power, they would draw it from the utility lines. When the fuel cell produces more than needed, the utility would take the excess. Most fuel cell work today involves hydrogen and oxygen as the combined fuels for operation. Natural gas could be the source of hydrogen. Since many homes already have natural gas piped to the house, it would be easy to handle this new fuel to make electric power locally. In addition, distributive power generation could use small, gas turbines for power supply. Commercial users would be possible users of these systems also. 21.3.1 Supply Natural gas is a product coming from the earth. As discussed previously, the major component of natural gas is the chemical compound methane, CH4. Methane is the product formed when organic matter like trees and foliage decays without sufficient oxygen available to completely transform the carbon in these materials to carbon dioxide. Theory is natural gas deep in the ground is a product of decaying material from past millions of years of the earth’s history. Chemical elements available as the matter decayed gives the methane such contaminants as hydrogen sulfide, carbon dioxide, nitrogen, and many more compounds and elements. Natural gas comes from shallow depths as little as a few thousand feet into the

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earth and as deep as 20 to 25 thousand feet. Natural gas wells are drilled on dry land and on water covered land. Current drilling in the Gulf of Mexico deep waters is in water depths up to around 3,000 feet. Natural gas quantities are measured in two sets of units. The volume of the gas at standard conditions is one measure. Basically, at standard conditions of temperature and pressure, the amount of natural gas in a volume of a cubic foot is a standard measure. Since a cubic foot is a relatively small volume when talking of natural gas, the usual term is a thousand cubic feet (Mcf). Still as a volume measurement, the next largest unit would be a million cubic feet (MMcf) which is a thousand, thousand cubic feet. A billion cubic feet is expressed as Bcf and a trillion is Tcf. Since natural gas is not a pure compound but a mixture of many products formed from the decaying organic matter, the energy content of each cubic foot at standard conditions is another method of measuring natural gas quantities. The energy units used in the U.S. are British thermal units (Btu), the amount of heat needed to raise a pound of water one degree Fahrenheit at standard conditions of pressure and at 60 degrees Fahrenheit. A typical cubic foot of gas, if of pure methane, would have about 1000 Btu per cubic foot (Btu/cf). Gas coming from wells can range from very low heat contents (200 to 300 Btu/cf) because of non-combustible contaminants like oxygen, carbon dioxide, nitrogen, water, etc. to energy contents of 1500 to 1800 Btu/cf. The additional heat comes from liquid hydrocarbons of higher carbon contents entrained in the gas. The higher carbon content molecules are known as “natural gas liquids” (NGLs). Also, other combustible gases like hydrogen sulfide contained in natural gas can raise the heat content of the gas produced. Data from the Federal Energy Information Agency (EIA) show an “average” cubic foot of gas produced in the U.S. as dry natural gas in recent years would have had an average of 1,028 Btu/cf. Gas is treated and/or processed to remove the contaminants lowering or raising the Btu quantity per cubic foot to meet pipeline specifications for handling and shipping and the gas. Pipeline quality natural gas is 950 to 1150 Btu per cubic foot. A frequently used term to describe the energy content of natural gas when sold at the local distribution level, such as residential, commercial or small industrial users, is the “therm.” A therm is equivalent to 100,000 Btu. Ten therms would make a “dekatherm” (Dt) and would be equivalent to a million Btu (MMBtu). The therm makes it easier when discussing smaller quantities of natural gas. When exploration and production companies search for gas in the ground, they refer to the quantities located

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as reserves. This is a measure of the gas the companies expect to be able to produce from the fields where the gas was found. Through various exploration methods—basic geophysical studies of the ground and surrounding areas to the final steps of development wells are used for more accurately pin-pointing reserve volumes. Reserves are the inventory these companies hold and from which gas is produced to fill market needs. In 1997, the U.S. government’s Department of Energy showed U.S. natural gas reserves in the order of magnitude of 170 trillion cubic feet (Tcf) of economically recoverable reserves. Without any replacement, this would be a 5- to 7-year life of existing reserves at current consumption rates. U.S. exploration and production companies are continuously looking for new reserves to replace the gas taken from the ground for current consumption. From 1994 to 1997, producers found reserves equal or more in volume to gas produced during that year. The reserve volumes are from areas where gas is already being produced and represent a very secure number for the amount of gas thought to be in the ground and economically feasible to produce. These are called recoverable reserves based on produced and flowing gas. The next level of measuring reserves is gas held behind these recoverable producing reserves. A little less secure and a little more speculative but, still a good chance of producing as designated. Using this category, just for the U.S., there are enough gas reserves for 25 to 35 years depending on the amount consumed each year. There are abundant gas reserves in North America to assure a steady supply for the near term and future. In addition to the U.S. reserves, gas in Mexico and Canada are considered a part of the U.S. supply or the total North American supply. Mexico contributes very little to the US supply at this time because its gas production and transportation systems are limited. As gas demand and prices increase, Mexico could play an important role as an U.S. supplier. As already noted, considerable amounts of gas come from Canada. In addition to these two levels of gas reserves, there are additional categories “possible” or potential of reserves. These become more speculative but are still an important potential supply for the future. Some of these may become more important sooner than expected. A good example is the gas supplies coming from coal seam sources. Considerable gas is produced in New Mexico from these sources which were not expected to be such large suppliers until much later in time. Additional potential supplies but with long lead times for further development is gas from hydrates and gas from sources deeper in the Gulf Coast. Natural gas produced from wells where crude oil

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is the major product is termed “associated gas.” Roughly 40% of the gas produced in the U.S. comes from associated wells while the rest comes from wells drilled specifically for natural gas. Only differences between the gas produced from the two types of wells are the associated wells gas might contain greater amounts of what has been mentioned previously as “natural gas liquids” (NGL). These liquids are organic compounds with a higher number of carbon elements in each of the molecules making up that compound and are entrained in the gas as minute liquid droplets. Methane, which is the predominant compound in natural gas, has one carbon and four hydrogens in the molecule. The two-carbon molecule is called ethane, the three-carbon molecule is propane, four-carbon molecule is butane, and the fifth, is pentane. All molecules with more than five carbons are collected with the pentanes and the product is called “pentane plus.” It is also known as “natural gasoline” which must be further refined before it can be used as motor fuel. The NGL are removed by physical means either through absorption in an organic solvent or through cryogenically cooling the gas stream so that the liquids can be separated from the methane and each other. There are markets for the individual NGL products. The ethane is used by the chemical industry for making plastics. Propane is also used in the chemical industry but finds a significant market as fuel. Butanes go to the chemical and fuels market and the pentanes plus are basically feedstock for the motor fuels production from refineries. The overall NGL market is about a $10 to 15 Billion a year business depending on the product prices. Prices for NGL vary as the demand varies for each of the specific products and bear little relationship to the price paid for the natural gas. When gas prices are high and NGL prices are low, profitability on the NGL is very poor. At the times, when the profitability is poor, the ethane will be re-injected back into the natural gas stream and sold with the gas to boost the heat content of the gas. A second difference between associated and gas well gas is strictly of a regulatory nature. Gas from associated wells is produced with no quantity regulations so that the maximum amount of crude oil can be produced from the well. Gas from “gas only” wells depending on the state where produced, may be subject to production restrictions because of market, conservation, or other conditions. Major natural gas producing areas in the U.S. are Texas, Louisiana, Oklahoma, and New Mexico. These states, including the offshore areas along the Gulf Coast stretching from Alabama to the southern tip of Texas, account for over 80% of the gas produced in the country. Figure 21.7, North American Gas Producing Areas, shows the gas producing states in the United States and the im-

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port locations for Canadian gas and for LNG receiving terminals. Other states with significant gas production are California, Wyoming, Colorado, New York, Pennsylvania, Alabama, Mississippi, and Michigan. A total of 18 states supply commercial quantities of natural gas according to the Federal EIA. A major supplier of gas for the U.S. is Canada. While imports do come from other countries, Canada by far, is the major supplier to the lower 48 states. Natural gas coming from Canada is transported by pipeline into the U.S. The small amounts of gas coming from Mexico also travel by pipeline. Imports from other countries into the U.S. are transported as liquefied natural gas (LNG). Here natural gas at the producing country is cooled and compressed until it is liquid. The reduction in volume is roughly 20 times the original volume. The liquefied gas with its reduced volume is now economically sized for shipping. The liquefied gas is transported between

U.S. PRODUCTION IMPORTS TOTAL

countries in large vessels, which are essentially very large cryogenically insulated, floating containers. The LNG is received at terminals in the U.S. where it is re-vaporized to gas. During this step, large quantities of refrigeration are available from the expanding liquid to gas. The cooling “energy” is sold and used in commercial applications to recoup some of the costs in making the gas into LNG. There are currently four terminals in the U.S. for receiving and handling LNG. These are in Boston, Lake Charles, LA, Baltimore, MD, and off the coast of Georgia at Elba Island. The Baltimore and Georgia locations were shut down years ago when natural gas prices would not justify LNG sales. Current plans are to reopen both facilities shortly. Overall imports into the U.S. have grown considerably since the mid-1980s when only 843 Bcf were imported in 1985. Natural gas imports in 1999 increased for the 13th consecutive year to 3,548 Bcf, 16.0 percent of

18,659 Bcf 3,538 Bcf 22,197 Bcf

Figure 21.7 North American Gas Producing Areas in 1999

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total U.S. gas supply. Canada supplied 93.9 percent of the total imports in 1999. Of the total imports, only 4.5 percent were received as LNG. Canada did much in the late 1990s to expand the pipeline systems bringing gas to the U.S. Additional pipelines are scheduled for completion early in the new millennium. Most Canadian production is in the provinces of Alberta and British Columbia. New production did come on from the Eastern Coast late in the last century and was imported into the U.S. from the Maritime Provinces. Since 1985, Canadian imports have more than quadrupled and Canada plays a major role in the expected additional supply needed to meet the demand for the years to come. Estimates are Canadian gas volumes will increase insuring the supply of gas for U.S. demand in future years. The Alliance Pipeline was completed in late 2000 and added 1.3 Bcf/day of supply to the U.S. Already, Canadian gas makes up a significant portion of the gas going to the U.S. Northeast. Figure 21.7 shows the major importing locations for gas coming into the U.S. from Canada. While natural gas imports into the U.S. as LNG were small in comparison to the total gas imported in 1999, the amount coming in 1999 was roughly three times that received the prior year. Equally important, the number of countries supplying LNG to the U.S. increased from three to six. Algeria continued to be the major supplier with 75 Bcf in 1999 but recently completed production facilities in Trinidad supplied 49 Bcf in the same year. Plans are to make all the terminals in the U.S. operative so that additional LNG supplies can be expected. Locations of all terminals are shown in Figure 21.7 21.3.2 Transportation Natural gas in the United States is transported almost exclusively by pipeline. From the time the natural gas leaves the wellhead, whatever route it takes in getting to the burner tip, it is through a pipe! Short or long distance, regardless, natural gas is transported in pipe. Only exceptions are the few times compressed natural gas is transported by truck for short distances. And, in some locations where gas is liquefied (LNG) for storage for use during peak demand times, the LNG is moved by truck also. Movement of gas through these two means is insignificant in the overall picture of transporting natural gas. When talking of transporting natural gas through pipelines, there are three main groups of pipelines to be considered: Gathering System: These are the pipelines in the field for collecting the gas from the individual wells and bringing it to either a central point for pick up by the long-haul pipeline or to a central treating and/or processing facility.

ENERGY MANAGEMENT HANDBOOK

Long-haul transportation: This is the pipeline picking up the gas at the gathering point, or if a highly productive well near a pipeline, from the well itself and moving the gas to a city-gate for delivery to the distribution company or to a sales point for a large user where the gas is delivered directly to the consumer. The long-haul pipeline can be either an interstate pipeline that crosses from one state into another or an intrastate pipeline where the transportation is only within the state where the gas was produced. The interstate pipelines are economically controlled by the Federal Energy Regulatory Commission (FERC). The operating regulations fall under the Department of Transportation (DOT). The Environmental Regulatory Agency has jurisdiction regardless of the type of pipeline in regard to environmental matters. The interstate pipelines are still economically regulated by the Federal Energy Regulatory Commission (FERC) since these are utilities engaged in interstate commerce. Intrastate pipelines are economically regulated by state agencies. Utilities are granted a license to operate in certain areas and are allowed to make a rate of return on their invested capital. This is different from the non-regulated businesses where they compete to make profits from the operations. As utilities, the rates for transportation are set through regulatory procedures. The pipeline makes a rate case for presentation to the FERC for authorization to charge the rates shown in the case. The pipeline is allowed to recover all of its costs for transporting the gas and make a return on the invested capital of the pipeline. Natural gas pipelines offer essentially two basic types of rates for transporting natural gas: firm and interruptible. With firm transportation, the transportation buyer is guaranteed a certain volume capacity daily for the gas it wants transported. The buyer is obligated to pay a portion of the transportation charge regardless whether its uses the volume or not on a daily basis. This is called a “demand charge” and is a part of the transportation tariff. The second part of the tariff is the commodity charge and is a variable charge depending on how much gas is transported by the pipeline. Pipelines also offer an “interruptible” tariff where space is on a “first come-first served” basis. Interruptible transportation carries no guarantee to the party buying the transportation that space in the pipeline will be available when needed. The tariff here is usually very close to the commodity rate under the firm transportation. The methodology of the ratemaking procedure used to recover the pipeline’s costs and rate of return is such that when a pipeline sells all of its firm transportation, it will make its allowed rate of return. A pipeline can legally exceed its accepted rate of return based on its handling of the firm and interruptible transportation. Typically,

NATURAL GAS PURCHASING

the pipeline has about 80% of its volume contracted in firm transportation. When a firm transporter does not use its full capacity, the pipeline can mitigate the costs to that pipeline by selling its firm transportation to another transporter as interruptible transportation. Many of the transportation contracts for firm transportation are terminating in the 2000 period. With the changes in the marketing system and the shift in the merchant role, some pipelines may have difficulty in filling their firm transportation sufficiently, This may bring some reduction in transportation costs which the gas buyer may be able to exploit. Further, the gas buyer at times can use what is called “back hauling” to get a lower rate for gas transportation. An example of this might be gas coming from Canada through the North Central U.S. area such as Chicago. A buyer for this gas might be located in the Southwest, say in Texas. Rather than ship gas from Chicago to Texas and have to pay the full tariff, a shipper might exchange gas in Texas for the gas to come from Chicago to Texas. In turn, the gas coming from Canada would be sold in the Chicago area as “Texas” gas. Here the shipper would pay the much lower fee for the “paper transportation” of the gas volumes. This would be a back haul arrangement. The interstate pipeline community is relatively small. Many of the pipelines have merged or were acquired by other utilities since the regulatory changes in the industry took the merchant function from them and made them strictly transporters. There are 25 major interstate pipelines moving gas from the production areas of the country to the consumer. These are owned or controlled by only 13 companies. Table 21.1, U.S. Interstate Natural Gas Pipelines, lists the major U.S. interstate pipelines, and the parent company having ownership. In all likelihood, even more mergers and acquisitions will occur to bring the number of separate companies even lower. Intrastate pipeline companies are within the state where the gas is produced. Many of these have miles of pipeline comparable to the interstate systems but, do not cross state lines. Within the state, these pipelines serve the same mission as the interstate pipelines; bringing the gas from the field whether the well or gathering point to the city gate for distribution by the local distributor or directly to a large consumer. Some of the larger ones for the gas producing states are listed in Table 21.2. While the pipelines themselves are no longer sellers of natural gas, the buyer should review the pipelines’ systems to see if there is a close connection possible so a direct supply might be made from the pipeline to the consumer. In cases where a pipeline is close to a plant or other large user, a marketer or the buyer itself can make arrangements for the short-

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haul pipeline to bring gas from the transporting pipeline to the facility. Pipeline transportation might include more than one pipeline to complete the shipment from well to burner tip. Who pays for the transportation at each step is open to negotiation between the gas supplier and the buyer. Usually, the producers are responsible for the gathering and field costs of getting the gas to the transportation pipeline’s inlet, which may be on the pipeline or at a terminal point, sometimes designated as a “hub.” Many times when the transporting pipeline goes through a producing field, the producer will only be responsible for gathering charges to get the gas from the wellhead to the field’s central point for discharge into the pipeline’s inlet. The gathering and field charges along with the transportation to the transporting pipeline inlet is what makes the difference between wellhead gas prices and “into pipe” gas prices. Table 21.1 U.S. Major Interstate Natural Gas Pipelines

——————————————————————————————— PARENT

PIPELINE

PIPELINE COMPANY HEADQUARTERS ——————————————————————————————— Panhandle Pipeline CMS Energy Houston, TX Trunkline Pipeline Houston, TX ANR Pipeline Coastal Corp. Houston, TX Detroit, MI CIG Pipeline Colorado Springs, CO Columbia Gas Tran’n Columbia Energy Co. Charleston, WV Columbia Gulf Trans’n Houston, TX CNG Pipeline Dominican Energy Pittsburgh, PA Algonquin Gas Trans’n Duke Energy Boston, MA Texas Eastern Pipeline Houston, TX El Paso Pipeline El Paso Energy Houston, TX Sonat Gas Houston, TX Tennessee Pipeline Houston, TX Florida Gas (50%) Enron Corporation Houston, TX Northern Natural Gas Omaha, NE Transwestern Pipeline Houston, TX NGPL Kinder Morgan Houston, TX Gateway United Koch Industries Houston, TX Wiliston Basin MDU Resources Bismarck, ND National Fuel Gas National Fuel Gas Buffalo, NY Northern Border Northern Border Omaha, NE PCT Pacific Gas & Electric San Francisco, CA Questar Pipeline Questar Energy Salt Lake City, UT Mississippi River Reliant Industries St. Louis, MO Noram Pipeline Houston, TX Northwest Pipeline Williams Companies Salt Lake City, UT Texas Gas Pipeline Owensboro, KY Transco Pipeline Houston, TX Williams Gas Pipeline Tulsa, OK ——————————————————————————————— JOFREEHOUSTON, TX CF 20JUN2000

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Who pays for the transportation charges from the transporting pipeline’s pick-up to the city gate or distribution company’s inlet, even if it includes more than one transporting pipeline, is negotiable between the seller or marketing company and the buyer. The marketing company selling the gas might quote a delivered price to the buyer, especially, if the seller is holding transportation rights with the pipeline handling the transportation. If the buyer has transportation rights, he might take the gas FOB (Free on Board, the point where title transfers and where transportation charges to that point are included in the sales price) at the transportation pipeline’s inlet. These are all part of the marketing and negotiating in moving gas from the field to the city gate and/or the consumer. What are typical prices for transporting natural gas from producing area to consumers in various parts of the country where there is no intrastate gas? The buyer can

get detailed information from the pipeline tariffs which can be gotten from the FERC and other sources like trade letters and magazines. Pipeline rates or tariffs are set by the regulatory agencies involved. There is some negotiation possible. Still, the gas in different locations will have a value based on market conditions regardless of transportation rates. This is called "basis differential." Some typical basis differentials between hubs and major markets are shown in Figure 21.8. These were developed from published prices given in trade publications for a several month period to get representative values. For natural gas to be carried in transportation pipelines, it must meet certain conditions of quality and composition. This was previously referred to as "pipeline specifications." These standards include the heating content of the gas per unit volume; i.e. British thermal units per cubic feet (Btu/cf). Typically, pipeline quality gas will

Table 21.2 U.S. Major Natural Gas Intrastate Pipelines—Summer 2000 ——————————————————————————————————————————————————— STATE

PIPELINE

PARENT

HEADQUARTERS

——————————————————————————————————————————————————— ALABAMA

Southeast Alabama Gas

Southeast Alabama Gas

Andalusia, Al

Pacific Gas Trans’n

Pacific Gas & Electric Co.

San Francisco, CA

Southern California Gas

Sempr Energy

Los Angeles, CA

——————————————————————————————————————————————————— CALIFORNIA

——————————————————————————————————————————

——————————————————————————————————————————————————— LOUISIANA

Chandeleur Pipeline Co.

Chandeleur Pipeline Co.

Woodlands, TX

Louisiana Interstate Pln

AEP Corp.

Alexandria, LA

Mid Louisiana. Gas Co.

Midcoast Energy Resources

Houston, TX

Gas Company of New Mexico

Public Service Co. of New Mexico

Albuquerque, NM

Enogex, Inc.

Enogex, Inc.

Oklahoma City, OK

Oneoak Gas Tran’n

Oneoak Inc.

Tulsa, OK

Aquilia Gas Pipeline

Utilicorp

Omaha, NE

Ferguson-Burleson County Gas

Mitchell Energy & Dev’t Corp.

Woodlands, TX

Houston Gas Pipeline

Enron Energy

Houston, TX

Lone Star Gas Pipeline

Ensearch

Dallas, TX

Midcon Texas Pipeline

Midcon Texas

Houston, TX

PG&E Texas Pipeline

PG&E

Houston, TX

Westar Transmission

Kinder-Morgan

Houston, TX

Winnie Pipeline Co.

Mitchell Energy & Dev’t Corp.

Woodlands, TX

—————————————————————————————————————————— —————————————————————————————————————————— ——————————————————————————————————————————

NEW MEXICO

——————————————————————————————————————————————————— OKLAHOMA

——————————————————————————————————————————

——————————————————————————————————————————————————— TEXAS

—————————————————————————————————————————— —————————————————————————————————————————— —————————————————————————————————————————— —————————————————————————————————————————— —————————————————————————————————————————— —————————————————————————————————————————— ——————————————————————————————————————————

——————————————————————————————————————————————————— JOFREEHOUSTON, TX CF 20JUN2000

NATURAL GAS PURCHASING

be around 1,000 Btu/cf. Gas coming out of the well, can range from very low values to over 1,500 to 1,600 Btu/cf. The lower values come from gas having contaminants like carbon dioxide or nitrogen in the stream while the higher values come from the gas containing entrained liquid hydrocarbons or hydrogen sulfide. The contaminants are removed in treating, for the hydrogen sulfide and other acid impurities, and processing facilities for the liquid hydrocarbons such as ethane, propane, etc. Typically, pipeline quality gas will run around 1,000 Btu/cf with a range of from 950 to 1150 Btu/cf. The exact amount is measured in the stream as the gas is sold on a Btu basis. Typical other specifications for pipeline transmission of natural gas are given in Table 21.3. Distribution: Once the natural gas is moved from the producing area it can travel from a few miles to thousands of miles in getting to its destination. The usual terminating point for the gas is at a city gate where the local distribution company (LDC) delivers it to the individual

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user whether it is a commercial, residential, or industrial consumer. In some cases where the consumer is a large industrial or an electric generating plant, the gas might go Table 21.3 Natural Gas Interstate Pipeline Specifications. ————————————————————————— Contaminants may not exceed the following levels: ————————————————————————— 20 grains of elemental sulfur per 100 cubic feet 1 grain of hydrogen sulfide per 100 cubic feet 7 pounds of water per million cubic feet 3 percent of carbon dioxide by volume Other impurity (i.e. oxygen, nitrogen, dirt, gum, etc.) if their levels exceed amounts that the buyer must incur costs to make the gas meet pipeline specifications. ————————————————————————— Source: Handbook on Gas Contracts, Thomas G. Johnson, IED Press, Inc. Oklahoma City, OK. 1982, page 63

Figure 21.8 Typical Natural Gas Basis Differentials between Hubs and Major Market Points.

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directly from the long haul transporter to the consumer. There are hundreds of distribution companies in the country. Some are investor owned utilities while many are municipality owned and operated. Some are co-ops formed for distributing the gas. The trade association representing this group of gas companies almost exclusively is the American Gas Association, headquartered outside of Washington, DC. Information and data on the industry as a whole, and on distribution companies can be obtained from this organization. Its address and web site are listed in Table 21.4. The local distribution company is usually regulated by the state regulatory agency such as the Public Service Commission. It may also be under local regulation by the city or municipality it serves. This group of natural gas transporters is yet to be deregulated throughout the country. Some states, Georgia the most notable, have passed new regulations much like the decontrol of the national pipelines. In these locations, the transporter is strictly a mover of gas and has no merchant function. It may have a subsidiary or affiliated company doing the merchant function or marketing of the gas. The eventual result of deregulation at this level will be for local distribution companies to offer open access to their transportation facilities. Each state will have to make its decision as to whether the LDC is freed from the merchant role or retains it if only in part along with offering open transportation for other merchants to move gas to the final consumer.

The odorizing of natural gas so that its presence can be detected easily since natural gas as such is an odorless gas, is usually done by the local distribution company before distributing the gas. The odorant is a sulfur containing hydrocarbon with an obnoxious odor that can be detected by human smell even when used in very small, minute quantities in the gas. While it is commonly thought all natural gas must be odorized when it is sold to the user, this is not necessarily correct. Gas going to industrial uses where the sulfur containing material giving the odor could be harmful to the process need not be odorized. There are both federal and state regulations governing the odorization. In buying natural gas, the buyer should insure the contract includes provision for adding the odorant and whose responsibility it is for proper addition and monitoring. 21.3.3 Economics Natural gas prices were originally set by the federal regulatory agency having jurisdiction over natural gas. The original methodology for price setting was much like the rate of return methodology for pipeline transportation tariffs. This was a direct function of the believed costs of finding, developing and producing natural gas. As discussed previously, the low prices paid at the wellhead prevented the natural gas industry from maintaining the necessary supply and caused the dire gas shortages of the mid-1970s. After natural gas prices were decontrolled, and natural gas became a true commodity, prices are a

Table 21.4 Federal Agencies & Natural Gas Trade Associations ORGANIZATION INFORMATION & SERVICES WEBSITE ———————————————————————————————————————————————————————— FEDERAL & MAJOR STATE AGENCIES FOR NATURAL GAS & ENERGY REGULATION 1 2 3 4 5 6 7 8

Department of Commerce Department of Energy (DOE) Energy Information Agency Department of Transportation Federal Energy Regulatory Commission Louisiana Office of Conservation New Mexico Public Regulation Commission Oklahoma Conservation Commission Texas Railroad Commission

Information on offshore production of gas and oil Information on energy products; supply, demand, consumption, prices, Regulates the safety of pipelines used in transporting natural gas. Regulates natural gas pipeline tariffs and facilities.

www.doc.gov. www.eia.doe.gov www.dot.gov

www.ferc.fed.us Regulatory board for Louisiana natural gas operations. www.dnr. state.la.us Regulatory board for New Mexico. www.nmprc.state.nm.us Regulatory board for Oklahoma. Regulatory board for Texas.

www. okcc. state. ok. us www.rrc.state.tx.us

(Continued)

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ORGANIZATION INFORMATION & SERVICES WEBSITE ———————————————————————————————————————————————————————— NATURAL GAS & RELATED ENERGY TRADE ASSOCIATIONS 1

2

3

4

5

6

7

8

9

10

11

12

13

14

American Gas Association (AGA)

Trade organization on natural gas; major source of information on gas local distribution companies.

American Petroleum Institute (API)

Represents the nations oil and gas industries

Association of Energy Engineers

Organization supplying information and services for energy efficiency, energy services, deregulation, facilities, management, etc.

www.aeecenter.org

Canadian Energy Research Institute (CERI)

Responsible for Canadian energy research.

www.ceri.ca

Edison Electric Institute

Represents electric industry; major area is investor -owned electric companies.

www.eei.org

Industry forum for development of natural gas measurement methods and standards for gas transmission.

www.gisb.org

Trade association for natural gas processors, a group of companies extracting gas liquids from natural gas streams and marketing the products.

www.gasprocessors.com

Annual marketing meeting for natural gas suppliers, transporters, customers, and marketers.

www.gasmart.com

Develops technical solutions for natural gas and related energy markets.

www.gri.org

Voice of the interstate natural gas system including the pipelines and companies supplying natural gas.

www.ingaa.org

National Energy Marketers Association

National non-profit trade association representing all facets of the energy business.

www.energymarketers.com

Natural Gas Information & Education Resources

Sweb-site dedicated to natural gas education and history.

www.naturalgas.org

Natural Gas Supply Association (NGSA)

Represents independent and integrated producers and marketers of natural gas.

www.ngsa.org

Gas Industry Standards Board (GISB)

Gas Processors Association

GasMart

Gas Research Institute

Interstate Natural Gas Association of America

Southern Gas Association (SFA )

www.aga.org

www.api.org

Links people, ideas, and information for transmission, distribution, and marketing of natural gas to all customers served by member companies. www.southerngas.org ————————————————————————————————————————————————————————— JOFREE HOUSTON, TX 77002 CF 21JUN2000

564

reflection of the normal economic factors impacting commodity pricing. The price for natural gas at the burner tip is dependent on many things—market conditions, supply/demand balances, economic conditions, and many more including the activity of natural gas financial markets, prices for competing fuels, etc. In the early stages of the industry, because natural gas was considered a burdensome by product of the crude oil industry, it was sold for very low prices. When crude oil was around $2/barrel (B) or about 30 cents per million British thermal units (MMBtu), natural gas under federal price control sold for a penny or two per thousand cubic feet or roughly the same per MMBtu. In actual heating value, a thousand cubic feet of natural gas has close to a million Btu. A barrel of fuel oil is 42 gallons of oil and about six million Btu depending on the grade of fuel oil. On an economic basis of energy content, natural gas prices for a thousand cubic feet compared to a 42 gallon barrel of oil, should be close to one-sixth the value of the oil, i.e. an $18 barrel of oil would be equivalent to $3/ Mcf or $3/MMBtu natural gas. Very seldom has the price, even after decontrol, reached this ratio. Instead, the value of gas has run about half or about one-twelfth or one-tenth the value of the oil product. In 2000, oil prices (West Texas Intermediate, WTI) were around $35/B. At the same time natural gas prices were over $5.00/MMBtu. Gas prices were about one-sixth the value of oil in dollars per barrel, very close to the energy equivalent of competing fuel, residual fuel oil. For the first time gas at the wellhead was at parity with crude oil in $/Btu. The fear in 2000 was gas supplies would not meet demand. Gas demand is increasing as more and more power plants are being completed that will use natural gas as fuel. This will do much to balance the gas demand between summer and winter. In summer the gas will go as fuel for electric generation to meet the hot weather requirements for power for air-conditioning, and in winter it will go as fuel for heating. Many buyers fear the high summer demand will prevent storage filling believed necessary for the winter heating season. Pricing is not a logical phenomenon. Data and basic considerations can help in predicting prices but the final price is very dependent on perception—market perception at the time. Too many of the variables are unknown precisely enough for pricing to be a scientific conclusion. Forecasting prices is art. Perception of the value based on supply/demand parameters sets the price. The market itself will do a lot to raise or lower the price. Further, the large financial market compared to the physical market for natural gas has an immense impact on the prevailing price. Gas prices can “spike” for many reasons—real or perceived. Hurricanes, hot weather spells, changes in the

ENERGY MANAGEMENT HANDBOOK

economy, etc. can make prices go up or down quickly and significantly. Short-term changes are always a possibility. Seasonality at times has little bearing on the current price. Natural gas prices have dropped precipitously in the middle of January and reached highs for the year in “shoulder months.” Eventually, prices come back to reality but in the time they are moving large dollar gains or losses can occur. In looking at gas prices, it is necessary to know where the gas is sold as prices vary according to where the sale is made in the wellhead to consumer path. Unlike crude oil, which is transformed into various commercial products, each with its own value, natural gas is essentially the same once it enters the transportation portion of the journey to the burner tip. Its value does increase as it moves through the system going from the wellhead to the consumer because of the added value of the transportation and services bringing the gas to market. The simplest place for pricing natural gas is gas sold at the wellhead. Gas priced on a Btu value at the wellhead will accurately reflect the value of the gas further down the chain even though wellhead gas might need to be gathered, treated, and/or processed. Once the gas is pipeline quality, its price reflects where in the transportation line from sales point to ending sales point it is at the time. Anywhere in the chain, the wellhead price can be determined by net backing the price to the wellhead by subtracting the additional costs to get to the point of pricing. The value of the gas, since it is a commodity, is open to supply/demand forces on the pricing. In addition, since at times pipeline capacity for moving the gas is susceptible to supply/demand restraints for capacity, the price differentials based on location can be affected also. This is how the basis differential of gas prices between different locations occurs. This is reflected in Figure 21.8. Gas purchased at the wellhead is done so on a wellhead price. Gas purchased further downstream might be termed “into pipe price” or “hub price” if coming from a central point where gas supplies come together for distribution to pipelines for long-haul transportation. The New York Mercantile in making a futures market for natural gas, has its main contract, at the Henry Hub, in Louisiana because of the hub’s central locality and easy accessibility. The difference between prices for major hubs or selling locations is termed the “basis” pricing and can vary much depending on the current supply/ demand factors. The first of the typical major pricing points for natural gas would be the wellhead or field price. This might include actual sales at the wellhead, at a central location after the gas is gathered in the field, or at the tailgate of a treating and/or processing plant depending on the plant

NATURAL GAS PURCHASING

565

location in relation to the transporting pipeline. The next major pricing point would be the “into pipe” price where the gas goes into a pipeline for transportation to the marketing area or to a “hub” for further redirection and transportation to the consuming area. The hub has the ability to dispatch the gas coming in on one pipeline to another in the variety of pipelines coming into and leaving the hub. From the hub pricing, gas would then be priced at the city gate where it is transferred to a local distribution company for delivery to the consumer. The pricing for the consumer would be based on the “sales point” price, which would be a total price for the gas including all the transportation and services required to get the gas to the user's receipt point. The individual price paid by the buyer is dependent on many factors starting from the wellhead pricing to the price at the meter coming onto the buyer’s property. In generalities, the government and other reporting services report the prices at the major pricing points and at the consumers’ location. The major consuming sectors where prices are reported are the residential, commercial, industrial, and electric generating markets. Since the progression from each of the stages from production to market carries a cost factor, it is important to know where in the delivery chain the price quoted applies. Figure 21.9 is a comparison of prices at each of these major market points for 1998. 21.3.4 Environmental Environmentally, natural gas is the preferred fuel. Even though it is a fossil fuel, the amount of carbon dioxide released is the lowest per unit of energy received of the major fossil fuels. Natural gas is ideal for its handling

and transportation qualities. Its environmental advantages makes it the most popular fuel and fuel of choice for many applications. It presents no unique environmental concerns to the user and as long as the supply is pipeline quality, the fuel source is of no concern in regard to environmental purposes. 21.3.5 Regulatory Changes To the average gas buyer, the new natural gas industry presents few regulatory problems or concerns other than those imposed by local or state authorities. The federal regulations from prior years on natural gas have been reduced. While natural gas pricing is no longer under federal regulations, it is still tied to some of the original federal natural gas laws. In today’s markets, these are essentially of no interference to commerce. It does mean that under certain extreme conditions, federal regulations could again be imposed on natural gas and certain uses could be restricted. For the current conditions, the buyer mainly has to be concerned with local and state rules and regulations. Transportation, storage and handling regulations are again local and state but here, federal agencies do play a role. The Department of Transportation and the Environmental Protection Agency have jurisdiction in the areas of pipeline safety and environment, respectively. Buyers should insure in their negotiations and contracts with sellers, transporters, and providers that all regulations are covered and the responsibility for meeting these rules are a part of the transaction. The contracts for buying and transporting should speak directly to whose responsibility meeting the requirements will fall and which parties will be responsible for the consequences if failure occurs.

POWER INDUSTRIAL COMMERCIAL RESIDENTIAL CITYGATE WELLHEAD 0

5

10

Source: U.S. EIA & Natural Gas WEEK

15

20

EXCLUDES ALASKA & HAWAII

$MMBtu

Figure 21.9 Natural Gas Prices by Sales Points for 1998

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Agencies having responsibility for natural gas regulations at the federal and state levels are easily accessible. Table 21.4 lists the major federal agencies including the web sites. State Public Utility Commissions (PUC) can easily be located if information is necessary. Further, many law firms and consultants specialize in the regulatory aspects and should be contacted if necessary.

21.4 BUYING NATURAL GAS To buy natural gas for either small or large operations, a thorough knowledge of the structure of the natural gas marketing system is essential. Again, this is the big change from the days when the industry was under price regulation by the federal government. Gas sales to consumers were through only one route—producers to pipeline transporter and merchant to local distributor to consumer. In the beginning of the transition to open marketing, this was referred to as "system gas." In localities where LDC are still the merchants, this is still the case. In a very small number of occasions, the chain was shortened to producer to pipeline to major consumer. Now—even with states in general still having control over the local distribution, the chain can be as short as producers to consumer or more generally, producers to marketers to consumers for relatively large users and producers to marketers to distributors for residential and most commercial and small industrial applications. This is the free market for natural gas. Buyers are free to pick any marketer or seller to supply gas. Open transportation is available to everyone—at least it should be! 21.4.1 Physical and Financial Markets Since natural gas is a commodity—it is fungible— and its supply is at times at the mercy of many factors including weather, demand, economics, etc., there is a market for buying gas supplies in the future. Commonly, this is called the “futures market” as opposed to the physical market where the actual commodity goes to the buyer either for resale or consumption. Many users of natural gas buy or “hedge” on the commodity market to take advantage of prices offered in the future. The New York Commodity Exchange (NYMEX) offers contracts for up to 36 months and several banks and operators do an over the counter market offering prices even further out. The consumers or sellers (producers, marketers, users, etc.) using the futures market are usually hedging as a means of price risk protection. As an example, a fertilizer manufacturer is a large user of natural gas for making ammonia and derivatives for use in fertilizers and industrial chemicals. If it takes

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the ammonia manufacturer an average of 60 to 90 days from the time he buys the raw material natural gas to be ready to sell it as ammonia, he has to worry about the price of both the ammonia and the price of the replacement natural gas changing during the period. If he uses $2 per MMBtu gas for the ammonia and then after selling the ammonia has to buy $3 per MMBtu gas to make new ammonia, he could be at a price disadvantage in the ammonia market. To “hedge” against these kinds of price changes, the manufacturer can buy “futures” when he starts making ammonia with the $2 raw material. He can protect his future-buying price for the raw material, which represent 70-80 percent of the manufactured cost of the ammonia, by hedging his future purchases. Since the prices on the futures market move constantly, almost daily for the near term market and less as time goes out, the futures market makes an ideal medium of wagering what the price will be in the future. The “speculators” who come into the market have no need for the commodity nor will they most likely ever take actual physical ownership of it. Their purpose is strictly to wager on where the price will be on a certain date. It can be either up or down from the price on the day they buy “futures.” This is not a small market but one in billions of dollars. In 1999, it was estimated that for every billion cubic feet of gas consumed in an average day, 10 to 12 billion cubic feet were traded on the NYMEX exchange and other markets. Of course, some of this 12-fold excess of consumption went to hedging, but roughly speculators traded 90 percent. The average amount of gas consumed per day in 1999 without regard to seasonality was about 60 billion cubic feet. Using the wellhead price of around $3.00/MMBtu, about $180 million was traded each average day for the consumption of gas. In the financial trading markets, almost two billion dollars per day were traded! Other than to have mentioned the financial market and show its significance in the natural gas industry, this chapter is devoted to physical gas buying. The buyers and sellers both need to know about the financial markets and evaluate their own need to participate or not in this type of gas transactions. There are many marketing companies, financial houses, and consultants well versed in the financial markets and how trading in these can lower the over all purchase costs of the commodity. Many books are written on this aspect. Buyers and sellers should become familiar with all sources of information in this area in helping to either maximize the return for the product for the sellers or minimize the purchase costs for the consumers. The comments on buying gas for use does not negate the financial market but, leaves it to other sources for the users to learn how to work within the financial framework including its benefits and risks. Knowledge

NATURAL GAS PURCHASING

of the financial markets are necessary because of the impact the financial market has on the physical market and prices for natural gas. 21.4.2 Actually Buying the Gas So—how does the gas user get down to the basics of buying natural gas? Do they call the local distributor, if the consuming facility is in an area served by the local distributor, or does the buyer shop around for the best price and service? Again, information and knowledge are the secret to success. The buyer must know what is needed to determine what path to follow in buying natural gas. If the buyer is looking for a source of gas for a new operations, one never before using natural gas as the fuel, then they must estimate the necessary parameters to know how much is needed to fill the requirements of that operation. If the buyer is replacing an expiring contract or having to change vendors, then they have the historical record to help in knowing what is needed to renew the supply sources. They can use the existing information and records to predict with greater accuracy what volume of gas will be needed, the changes on a daily or other time basis that will be needed and what were the prior costs for the gas supply. With this information, the fuel buyer can look for new sources to meet the needs more efficiently and cheaply. The very first question to be answered is how much natural gas will be consumed on a daily basis and what will be the range of use on a daily, weekly, monthly and annual basis. The information could even be a question of an hourly rate as to how large a swing does the user anticipate. These are the big questions to answer in making the first step in trying to select a supplier or seller. Knowing the quantity and conditions of where the rate will vary are crucial to starting the buying process. Whether the consumer is a large or small user of gas will play a major role in what selections are open to it for purchasing gas. The physical conditions prevailing in the area of the location using the gas will play a role because of regulations of the area and the actual physical availability of pipes for transporting the gas to the consumer. Typically, the break from a small user to a large one is a rate of about one thousand cubic feet per day or in energy units, about a million Btu per day. Most local gas distribution companies will talk in “therms” and “dekatherms” rather than Btu or cubic feet. The dekatherm is ten therms. Each therm is 100,000 Btu. Each dekatherm is one million Btu. The line between large and small users is not rigid. Applications coming close to this approximation may still meet the criteria for going the large user route. If the user is on the small side, depending on the state or location of the use, it still may have an

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alternative of buying from the local distribution company or using the LDC for transportation only and buying the commodity from a marketing entity. Making contact with marketing companies, which will be discussed later, and getting information on the local regulatory rules will help in making this decision. Many local distribution companies have set up their own non-regulated marketing companies to help consumers buy gas at the lowest price with the required service criteria of their own operations. One should not forget the potential of ECommerce, the newest way to buy and sell natural gas. A smart buyer will look at all possible sources for meeting his requirements at the lowest price but with reliability and service. In buying a commodity like natural gas, price alone should not be the only criteria. Service (security of service, emergency additional supplies, etc.) equally impacts the buyer’s bottom line as does price in meeting fuel requirements. Having a cheap supply of gas where its availability is so uncertain as to disrupt plant or business operations is really an expensive supply when looked at in the total picture. Security of supply or additional supplies, etc. is a valuable consideration to be included in pricing natural gas sources. The large users—those over the thousand cubic feet level or close to it, should investigate all possible sources for supply and transportation. Their sources may go all the way back to the wellhead or producer marketing companies. Depending on how large a supply is needed at a given location, the buyer may include dealing with pipelines and distribution companies for transportation and delivery of the gas. Once the buyer knows in general which direction to go, the big issues then become finding a marketer, transportation, and contracts for the services and commodity. 21.4.3 Natural Gas Marketers Marketers come in varying forms, sizes, and descriptions. One can look at it much like purchasing gasoline at the local filling station—”Full-Service” or “Self-Serve.” To add a little more variety or confusion, gas buying and selling is moving to ECommerce and the business-to-business Internet capabilities. When the start of marketing companies began in the mid-1980s to take the place of the merchant function performed by the pipelines, it was almost anyone with a telephone and a pencil could be called a natural gas marketer. Through the years, with a number of the marketing companies taking on added scope and abilities, the ”fly-by-night,“ less reliable marketers were pushed out of the business. Even some of the more reputable, better financed groups have gone because of the inability to be profitable in a fast moving, sometimes, irrational market place. With financial trad-

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ing exceeding high volumes of trading each day, risk becomes an even more important element of consideration. Marketing natural gas is more than just selling and delivering gas to the consumer. The gas business is big business running into revenues of around $100 Billion per year depending on the exact price for the commodity that year. The $100 Billion is only a measure of the actual commodity trading on an idealized basis of direct trades from producers to marketers to consumers. Actually, an average cubic foot of gas most likely gets traded three to four times before coming to the consumer, the entity with the burner tip that will consume the gas and put it out of the market. This is only for the physical side of the trading—the place where the commodity actually is moved to a final destination for consumption. The total natural gas consumption in 1999 was 22 trillion cubic feet (Tcf). This pales in comparison to the financial markets where 10 to 12 time the volume traded each day in the physical market of consumed gas is traded in the financial sector. The money moved in this arena is beyond the $100 Billion discussed previously. At times, the market is responding more to the financial than to the physical drives. The speculators are doing more to move the market than the actual users who need the natural gas for fuel or feedstock. Like all commodities, natural gas makes an ideal medium for financial trading. There are those who need to make a play in the market for the protection or risk-adverse properties the market gives. Those who produce the gas and those using large quantities can buy some protection of the future price by buying futures. This is “hedging.” The futures buyer is taking a position for a given month in the future where the price he pays will be the price for the quantity of gas he purchased futures for on that given month. He/she has locked in the price for gas anywhere from a month forward to 36 months forward. Whether buying or selling gas, hedging is a tool to relieve some of the risk in buying or selling a relatively volatile commodity. The volatility of natural gas prices (no pun intended) makes it an ideal commodity for speculators to make a market in it for the sheer purpose of making money. The speculator is betting the price will be higher or lower on a given date and is willing to take a position by buying the commodity for trading at that time. Much of the trading in natural gas is for speculation and this can only add to the volatility of the market place. While most of the hedgers bring a relatively simple mentality to the market place based on supply/demand parameters, the economy, and other pertinent factors, the speculators have a “statistics” of their own for playing the market. Basically, the speculators are “market technicians” and play a statistical analysis of the market itself for buying and selling the

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commodities. The mentality of the speculator is basically, “who needs to know all the details of the commodity, the market place itself shows the results and following the market place with its own statistical tools is the way to go.” Of course, many of these speculators are very large in the amount of money they control. When the signals show its time to buy or sell, very large sums of money can come into or leave the market. Easy to see how this can make the price of the commodity very volatile. Figure 21.5 shows the prices for natural gas, coal, and crude oil for the last five years to give a comparison among these three major fuels for electric generation as to the market volatility of each one. 21.4.4 Finding the Seller Now, to whom one goes for buying natural gas is a question of the degree of service expected and needed. A large user wanting to hedge prices to insure a stronger control in the price paid for the commodity might go to a “full-service” marketer while someone needing a relatively small amount of gas at a reasonable price can call the local distribution company or a more “self-service” marketing company. The selection is difficult because there are so many choices. There are roughly 30 major marketing companies handling natural gas and any where up to a couple of hundred smaller groups. There are the local distribution companies in the area. Most of them, in addition to selling “system gas” will have an affiliate or subsidiary selling market sensitive priced natural gas also. System gas is natural gas the LDC has purchased for resale to its local customers. Since this customer base includes residential and commercial customers as well as the industrial sector, the average price will be higher usually. Most local distribution companies have made available open access transportation so that large industrial user can bring in its own gas supply and let the local company transport it to the buyer’s facility. As part of its tariff, the LDC will set a minimum amount of gas the buyer uses as a criteria for allowing the buyer to purchase its own gas and use the LDC for transportation. The tariff will set the cost for transportation by the LDC. In addition to the transportation costs, rate of return, and other pipeline costs in the charge, in many tariffs a provision includes any local taxes or fees made by local governments for transporting natural gas. The LDC or pipeline affiliate will only sell the commodity. The buyer might also have a choice of buying from other marketers and can “shop” its purchase needs to get the best package of prices, services, and other options. The local distribution company would most likely be the transporter for the customer. In some locations, this may not be the case depending on the location of the buyer and

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accessibility to other pipelines for transportation. Remember, price alone should not be the only consideration in purchasing natural gas. Dependability and service have a definite value. One should always keep this in mind when buying gas supplies. It might be wonderful to buy the cheapest gas only to be unable to get it when weather or other problems make the supply scarce! After the prospective buyer has determined what its needs are and what alternatives it can live with, then the buyer should find the best source for buying the supply that meets those necessities. Looking for a good supplier can be a big part of the purchasing decision. But, it is an important element in the total economics that the buyer succeeds in selecting the right source or sources. The buying could include the transportation of the gas to the consumer or, again, depending on the sophistication of the buyers, they might purchase transportation separately from buying the commodity. These are all part of the difficulties of purchasing a gas supply. Because of the many parameters to be covered and the need to know the players and the system, many companies seek consultants to help either initially or continually to make better decisions in gas purchases. The difficulty is unless the buyer is in the buying sector almost continuously, he or she will be at a distinct disadvantage in seeking the

optimum natural gas sources. The expense of using a marketing company or a consultant can be a very small price in finding the most effective and efficient source of supply. Table 21.5 lists the largest marketing companies whether “full-service” or “self-service” in style. Looking at Table 21.5, one can see that many of the major marketing companies listed are a subsidiary or partner of natural gas pipeline companies, either the long-distance movers or the local distribution ones. Other big marketing companies are a subsidiary of the natural gas producer. Companies like Shell Oil (subsidiary Coral Energy), Texaco, and Exxon-Mobil all have marketing companies. Most of these are more to the “Self-Serve” type where selling the gas they produce or gas from their associates or partners in the field is the purpose for their marketing operations. The buyer should sample a large enough group of marketers to insure getting the best price, reliability, and service. Selecting a gas supply source is not an overnight task. The work needed should be in proportion to the value of the gas to the operation. If large supplies of gas are needed, differences of a penny or two or reliability are very important. The new area touched upon only lightly because of its newness is buying gas using ECommerce and the business-to-business Internet. Many of the major gas

Table 21.5 Natural Gas Marketing Companies

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marketers, either singularly or joining into a consortium, are making markets buying and selling gas through the Internet. Table 21.5 lists the marketing companies currently, summer of 2000, ready to trade using cyberspace and Table 21.6 lists all ECommerce companies doing business in the energy sector. The list will grow and players will change with time. The Internet marketers make it easy for the knowledgeable trader to buy or sell gas without having to use a marketer or broker. How much additional effort the buyer will need to complete the sale and transportation will depend on how this system of marketing grows and prospers. After only a short time of this method of marketing being in existence, large enough volumes have been traded to see the value and potential for ECommerce business in the natural gas industry. 21.4.5 Natural Gas Pricing Natural gas is a commodity. There are many suppliers and the commodity is fungible. Its price is a function of its availability. Simple, but true. When supply is perceived sufficient, gas prices based on current conditions would be in the $2-3/MMBtu range. Over-supply will see the price drop significantly sometimes coming down 40 to 50 percent of this price. Tight supplies can do the same with the cap sometimes on a short-term basis, being almost unlimited. Early summer 2000 prices teetered around the $4/MMBtu range and went above $5/MMBtu by early fall because of fears of short supplies caused by the summer electric generating high demand, gas storage filling requirements, and winter gas supply. While the movement is based on supply/demand parameters, the problem is two-fold: no one knows the supply/demand picture with accuracy and secondly, fact and perception play unequal roles. In the end, each buyer and seller must make its own decision on where the price will go in the short and long term futures. Historically, natural gas prices in the beginning were cents per thousand cubic feet. After crude oil prices became market sensitive in the early 1970s, it was not until natural gas prices were decontrolled that gas in interstate commerce came up to realistic prices ranging from over a dollar to $5-6/MMBtu. Gas prices during the 1970s, before decontrol, for the intrastate market quickly came to market sensitive levels of $3 to $6/MMBtu. The Natural Gas Policy Act of 1978 ended the difference between interstate and intrastate pricing. The high price for natural gas after decontrol was an affect of the legislation, which set up about a dozen pricing categories. When the gas surpluses of the mid-1980s started, where the legislation had set the “maximum lawful price,” it did nothing for a minimum price. The gas merchants of that time, the pipelines, brought the prices down to the $2/MMBtu

ENERGY MANAGEMENT HANDBOOK

range quickly. Since 1985, natural gas prices have varied from around a $1/MMBtu to current highs above $5/ MMBtu. Figure 21.5 shows natural gas price history during the period 1995 through 1999. There are tools to help in price analysis and forecasting. In addition to the sources for tracking the current gas prices, there are tools for helping in projections of future prices. Services that can supply forecasts based on their interpretation of the future are available. Many of the financial houses making a market in natural gas and other energy futures have current material on their analysis of gas markets. The federal government has many publications and resources for tracking and estimating gas supply, demand, and pricing. And, of course, there are many consultants offering pricing, supply, and demand forecasts. Many of the sources are free. Two things to keep in mind regardless of the source of information. First, forecasting is an art. There are statistical methods and programs to help in making predictions but many of the assumptions are based on the forecasters’ ability and experience. It is still art not fact or science. Who can predict with accuracy and precision the weather for a week or six months out? Hurricanes come, blizzards come and sometimes little is known before hand. There is even a difference if the extremely cold weather comes during the week or only on the weekend. During the week, schools and business facilities need gas for heating; weekends they are closed. The second point is simple. If the forecaster has an ax to grind, be careful of the conclusions! Since it is an art, the forecaster who has a specific purpose can be prejudiced whether conscious of it or not. Some of the trade sources for natural gas price reporting and forecasting are listed in Table 21.7. Since gas is a commodity and depends more on the factors of supply/demand for pricing than actual costs, gas prices vary significantly over a short time period. Each month, some of the gas trade publications (see Table 21.7) give what is called the “gas price index.” This number is based on the price sellers and buyers are using at the end of the month and it becomes the index for the next month. The index changes each month and many contracts use the index from a given publication as the price gas will be bought or sold for that month. Sometimes the contract will call for a penny or two per million Btu above or below the index. The major index used at this time is based on natural gas sold at the Henry Hub in Louisiana, a very common place for gas sales and trades. There are many more places where gas is traded and each of these will have an index of its own or a “basis price,” a method for converting from the Henry Hub price to that location’s price. It is usually based on the value of the gas at that location versus Henry Hub and the added cost

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Table 21.6 Commerce & Energy ——————————————————————————————————————————————————— Number

Internet Address

Activities & Purpose

——————————————————————————————————————————————————— 1

icapenergy.com

ICAP Energy, Inc. is an over-the-counter broker of natural gas, electricity and weather derivatives.

2

www.apx.com

Is International. APX leverages the Internet to trade all electricity products—the electricity commodity itself, the transmission rights needed for delivery, and the ancillary services that support and reliability. All integrated.

3

www.buyenergyonline.com

Buy and sell energy—Great Britain.

4

www.capacitycenter.com

Alerts to find capacity on natural gas pipelines.

5

www.coralconnect.com

Lots of information. Allows one to buy and trade gas and electricity with Coral Energy.

6

www.energy.com

Deregulation Status, Consumer Education, Links to energy suppliers, etc.

7

www.energycrossroads.com

“The e-partner of choice for small to mid-sized utilities.”

8

www.energyon.com

Buy energy on retail basis.

9

www.greenmountain.com

Green power focus.

10

www.houstonstreet.com

Electronic trading.

11

www.oilexchange.com

Oil property sales.

12

www.onlinechoice.com.

Gives customers access to buying pools. Also allows you to state your needs and receive a bid back.

13

www.powerchoice.com

Pepco offering to help in gas and electricity choice and to provide other electricity services such as power surge protection.

14

www. redmeteor.com

Energy Trading system.

15

www.scana.com

SCANA Online is an Internet-based energy auction.

16

www.itron.com

Provides interactive energy e-business solutions for optimizing energy usage and energy procurement processes.

17

www.tradecapture.com

TradeCapture.com is an innovation which will give you one stop shopping for multiple commodities and locations in the physical and financial commodity markets. Has offices in Canada, Mexico and Great Britain.

18

www.trueadvantage.com

TrueAdvantage is a leading provider of private-label sales leads and RFP services to the online B2B marketplace including energy.

19

www.truequote.com

Provides Price Discovery.

20

www.utilisave.com

Utility cost management, cost recovery, and e-commerce procurement solutions.

of transportation between the two locations. The basis does not always vary as the value of gas transportation changes. When gas prices are rising, the basis value can increase and vice-versa. Examples of these differences can be found in the trade publications listing natural gas prices, see Table 21.7. 21.4.6 Contracts for Purchasing Natural Gas As has been said previously, the major change to buying natural gas in the new millennium is the ability to

buy from many sources. This can mean buying from the actual producer regardless of where the consumer is located, to buying from local or national marketers or the local distribution company. A consumer might buy from the local distribution company in its area either directly from the utility or from a non-regulated marketing subsidiary of the utility. Another major difference today is the consumer can buy the commodity and the transportation separately or together depending on the source of the gas, the quantity, the service required, and/or the location of the consumer

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Table 21.7 Natural Gas Price Reporting Sources ——————————————————————————————————————————————————— SOURCE

MEDIA

TIMING

TELEPHONE

WEBSITE

——————————————————————————————————————————————————— 1

ACEO/NGX

Internet

Same day & near month

www.naturalgas.com

2

Bloomberg Energy

Internet

Spot Market Current less 20

3

CNN The Financial Network

Internet

minutes

www.CNNfn.com

4

ENERFAX

Internet

Daily

www.enerfax.com

5

GAS DAILY

Printed, Fax, & Electronic

Daily

800/424-2908 Crutchfield Energy Data

www.ftenergyusa.com/gasdaily

6

GASearch

Internet

Market intelligence

972/247-2968

www.gasearch.com

7

Platts

Printed, Fax, & Electronic

Biweekly & Current A/C 800/752-8878

www.mhenergy.com

8

Natural Gas

Internet

Various

www.naturalgas.com

9

NATURAL GAS MONTH, EIA

Internet & Printed

Monthly

www.eia.doe.gov/oil_gas

10

NATURAL GAS WEEK

Printed, Fax, & Electronic

Weekly & Current 800/621-0050

www.energyintel.com

11

NATURAL GAS INTELLIGENCE

Printed, Fax, & Electronic

Current futures A/C 703/318-8848 Weekly & Current

www.intelligencepress.com

12

NYMEX

Internet

delayed 30 min

www.nymex.com

13

Reuters

Fax & Electronic

Current delayed

A/C 609/279-4261

A/C 800/438-6992

www.bloomberg.com/energy

www.reuters.com

——————————————————————————————————————————————————— both for physical and/or regulatory reasons. These changes in how gas can be purchased have brought changes in how contracts are written between the supplier and the consumer. If the buyer is responsible for its own transportation, it would mean having to contract for this transportation as well as contracting for the gas supply. It also opens up new considerations. The buyer wants to make sure they are well protected in getting the gas they pay for from the vendor and if the case is such, the transporter as well. In addition, the buyer must be concerned he is protected from any liability that might occur because of damage caused by the gas in the sale and delivery to the user. Contracts are legal documents covering these elements and need to be clear and accurate. After something happens—such as being charged for gas not received or for someone hurt in an accident involving the gas in question—is not the time to start looking at the contract. Who is responsible, or what limits there are for the difference between paying for a volume of gas and receiving a smaller amount, and any other conditions and situations differing from what was expected should be stated in the contract. Recourse and responsibilities should be spelled out in the contract. With contracts being legal documents, the expense

and time to insure proper legal resources are used in negotiating and drawing up the contracts for buying and delivering natural gas are well worth the effort. Even in very short times of delivery or for very small quantities of gas to be purchased and delivered, contracts must accurately and legally cover protection of all parties involved in the transaction. This is where an “ounce of prevention is worth a pound of cure!” A contract or contracts between the two or more parties will spell out the details of the transactions needed to purchase and deliver the gas from the source to the consumer. Many of today’s gas deals are done over the telephone based upon agreed-to basic terms. Some are being done through computer and cyberspace. Whenever there is an on going relationship of supplying natural gas over a period of time regardless of the length of the time of delivery, there will be a contract or contracts covering buying and selling conditions including transportation, delivery, metering, payment, ownership, etc. There might be a contract to supply natural gas for as little as an hour or as long as a year or two and up to as long as 10 to 20 years. The long-term contracts of the controlled period when the transporting company marketed gas are no longer in use. Typically today, regard-

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less of the term of the contract, provisions are included for price adjustments and for security of supply. Also, typically today, contracts longer than six months or a year are considered long-term contracts. Contracts up to three to four years can be for a fixed price or a market based price depending on the whims of the buyer and seller. Most fixed priced contracts today will be based on the financial market for futures contracts to protect the buyer and seller from catastrophe due to sudden market peaks where the seller would be obligated to supply gas at a fixed price when prices are rising for the commodity. Further, the contract will protect the seller from the buyer ending the contract prematurely. Likewise, the buyer will want protection should prices drop significantly to reopen the pricing provisions. A contract is an allocation of risks between the buyer and seller. It is the same between the party buying the transportation and the transporter. Every business deal involves risks and the contract sets the responsibilities of the parties so that there should be little argument if something does not go according to plan. The seller is taking the risk of supplying gas and the risk of getting its payment for the gas and services supplied. The buyer is taking the risk of having a reliable, secure source of gas for its business needs. These are the major risks each party is taking and the contract is a written document to insure both are protected as much as possible. Contracts are written documents to help in allocating these risks. But, even the best contract, written by the best lawyers and negotiators, is really, no better than the people offering the commodity and services and the people buying the services and commodity. No contract will help if the party involved is not honorable, trustworthy and capable of doing what it claims it can do in the contract. Further, signing a contract and then planning on going to court to enforce it is a waste of good time and assets of either party. Contracts are like locks on doors—they are for the benefit of good people to insure no one gets confused or forgets the details of the arrangement. Contracts do little to protect from dishonest or untrustworthy business associates. Of course, even with good contracts and good intentions of the parties, things go wrong and contract disputes arise. These disputes can involve large loses of management time and company assets. Well-written and negotiated contracts can keep the disputes to a minimum in happening and to minimum losses when the unexpected does occur. Since one or more contracts may be needed to purchase and deliver natural gas, the buyer should be careful in his actions. Contracts for the purchase of natural gas will usually have the following major areas of consideration as listed below. Many of these will apply to the

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transportation contracts as well unless the purchase of the gas includes the transportation. Since today, sellers and buyers will vary considerably in their position in the respective industries, the contract needs to be tailored specifically between the two or more parties involved in the transactions. A contract for buying natural gas from a local distribution company will be different in many aspects from the contract between a marketing company and the buyer. The local distribution company is a regulated entity and many elements that will be in a contract are part of the regulatory aspect. Most of the specific items the utility will have to abide by are given in its tariffs, which are filed with local or state regulatory agencies. Some of the major elements of the gas purchase contracts are outlined in the following: 1. Purpose & Scope of the Agreement—What is to be accomplished by the contract. Who will be supplying gas, how will it be transported, and who will receive the gas. Additional comments as to the potential use, whether a sole supplier, etc. might also be included in this section. 2. Definitions—Lists the standard and special terms used in the contract. Especially important in natural gas contracts because of the uniqueness of the commodity, the industry ways of doing business, and the specific parameters of the operations the gas is being purchased for by this contract. 3. Term of the Agreement—A statement giving how long the agreement will be in force and what conditions will terminate the agreement. Some contracts will include information on methods and options of extending the contract past the initial terms of the agreement. 4. Quantity—Here, the details of the total quantity of natural gas to be sold and delivered by the seller and received by the buyer will be stated. Information on the daily contract quantity (DCQ) or even hourly contract quantity will be stated. Any specific deviations from the regular amount such as swing quantities needed during high production or other causes are listed here. Penalties the seller is willing to accept for the buyer’s failure to take the quantity of gas set in the contract will be listed in this section. Also, the converse, penalties the buyer is willing to accept for the seller’s nonperformance according to the contract will be stated in this section. If there is any take-or-pay language, this is the section for it. Take-or-pay

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is an agreement for the buyer to pay for gas if contracted but not taken. The Buyer usually has a period to make up the deficiency. The section will also state whether the gas is being sold on a firm basis with the buyer and seller obligated as stated to perform or if the gas is being made available or will be taken on a “best efforts” basis. Very important in this section could be the ways the buyer “nominates” takes for certain periods. The section will include means for balancing the account and give additional penalties for under- or over-quantities of gas taken by the Buyer. Other subjects that play a role in the quantity of gas to be supplied such as well or reserve measurements if buying directly from a producer or other supply considerations if buying from a marketer can be in this section. 5. Price—Price to be paid for the natural gas to be delivered by this contract as well as any statements regarding price escalators and/or means to renegotiate the price will be stated in this section. Omissions of statements to this effect can be construed as a statement of the contract so care must be exercised on what is said and what is left out. Any language needed for agreement on price indexing or other means of adjusting the price to current market conditions will be included. The writing should include provisions for both price increases as well as decreases if this is the desired purpose of the statements regarding changes for market or other conditions. The Price Section will cover any additional expenses or costs the buyer is willing to undertake in addition to the direct cost of the gas. If the contract is with the producer or an interest owner in a gas well, the section will state who is responsible for any gathering, treating, or processing costs. Again, for a contract with the seller being a producer, provisions will be in this section for who has responsibility for severance and other taxes, royalties or other charges the producer might be liable for payment. Pricing units most commonly used today will be energy units such as British thermal units (Btu). The dollar value per thousand Btu is typical such as gas at $0.003/MBtu. Since a typical volume measurement of natural gas is a thousand cubic feet (Mcf) and typical pipeline quality gas of this volume would have about a million Btu in energy units, the typical unit for gas sales is a million Btu or MMBtu. The above example would be $ 3.00/ MMBtu. The Pricing Section will also include

language in today’s contracts protecting both the buyer and the seller from the vagaries of the natural gas markets today. While these in effect reduce the coverage of the contract and change some of the allocations of risks set by the contract, often both parties are willing to have a contract with legal means of changing the pricing conditions of the contract. The long-term, fixed price contracts went out with decontrol. There are still fixed price contracts but, the seller will protect its position by going to the financial market and buying futures to protect his position of supplying long-term, fixed price natural gas. Since the seller is taking steps to insure supplying the gas at a fixed price by buying futures, the seller will protect his actions by putting clauses in the contract to protect this position should the buyer fail to take the gas as contracted. 6. Transportation—Transportation details as to who has responsibility, the transporter, costs, etc. to deliver the gas to the buyer must be included in the contract. Crucial items are who is responsible for arranging the transportation, who will pay for the transportation, and whether the transportation will be on a firm or interruptible basis. The transportation must cover the full course of bringing the natural gas from the source to the buyer’s location including bringing it to the accepted delivery point(s) as stated in the next paragraph. The buyer must insure they are covered in case transportation is unobtainable or ceases after delivery has started. The contract will include any special conditions on either the buyer’s or seller’s part to take into account any special situations either party could have to interfere with transporting the gas from the source to the delivery point(s). Further, any regulatory matters pertaining to the gas transportation should be referred to in this section and in more detail in the regulatory section discussed further in this chapter. This section should cover who has responsibility for overages and balancing of the account, measurement, disagreements on quantities, and payments of transportation and associated charges. 7. Delivery Point(s)—Since the delivery point or points are different in each situation, the contract needs to state delivery or alternate delivery points in very specific language. This clause can become a very crucial one in times where there is a dispute over quantities of gas sold or received. There is

NATURAL GAS PURCHASING

also a slightly different interpretation of this clause in light of the new sales methods where there is a separate contract for the sale of the natural gas and one for the transportation. To the gas buyer, the only real delivery point is when the natural gas crosses the meter and valve where the gas comes directly into the buyer’s system. The buyer wants to be responsible only for the gas received in his system. What gas is presumed sold or dispatched at some other location such as where the gas might come off of an interstate pipeline into the pipe of the local pipeline delivering the gas to the consumer is really not the concern of the buyer. This is an argument between the two pipelines or between the pipeline and the seller depending on the contract for transportation between the significant parties. Delivery point is also crucial in assessing responsibility for problems that might arise from the gas in question. An explosion or fire resulting from the improper handling of the gas and the ensuing legal action by one or more party could be influenced by the delivery point as to who had responsibility for the gas at the time and location of the accident. At times, delivery points may need to be changed to meet requirements of either parties and the need to change should be included in this section to insure that changing the locations according to the contract do not in any way negate the contract or the terms in the contract.

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party seeking protection from the responsibilities of the contract. Many times, this is referred to as an “act of God” and includes severe weather, acts of war or insurrection, strikes, etc. 11. Warranty of Title—The clause guarantees the seller has title to the gas and can sell it. Included are allowances for the buyer to recover damages if there is a failure of title should another party make claim to ownership of the gas. 12. Regulatory—All necessary permits, licenses, etc. must be obtained according to FERC regulations and any state or local authorities having jurisdiction over the selling and transportation of the natural gas. The party or parties having the responsibility for obtaining these and payments required should be fully covered. 13. Assignments—Specifications for the transfer of rights under the contract are covered in this section. This could be an important item in light of the various changes occurring in the gas industry today. The buyer should insure coverage includes changes that might impact gas transportation as well as the commodity if the seller was responsible for transportation as well as for the natural gas.

21.5 NEW FRONTIERS FOR THE GAS INDUSTRY

8. Measurement & Quality—Methods, conditions, timing, and authority for the measurement of the gas volume and quality are given in this section. Usually, a trade association or other organization's methods and requirements for measurement are called for in this section to insure the proper measurement of the quantity of gas sold or bought and the quality of the gas under the contract. Remedies or alternatives should be included in this section for those cases where the gas fails to meet the quality requirements of the contract whether on a short-time, unexpected rare or single occurrence or a continuing failure to meet the specifications.

A number of challenges face the natural gas industry going into the new millennium. Each of these will have an impact on the future buying and trading of the commodity. A summary of these follows:

9. Billing—Terms for the billing, who is responsible for payment, manner and methods of payment, etc. are included in this section. 10. Force Majeure—This the clause in the contract to protect both parties affected by a totally unforeseeable occurrence which is beyond the control of the

1.

Complete the natural gas decontrol to the final level—local markets in each state.

2.

Complete the development of an energy industry that incorporates other energy sources like power, fuel oil, etc.

3.

Develop the delivery system to insure secure supply of the larger quantities of natural gas demand forecast for future years.

4.

Develop new supply sources to meet the forecasted demand through the 2015 period forward.

Each one of these will play an important role in the gas industry of the future. More important, each one will require capital flows into the industry to make them possible.

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CHAPTER 22

CONTROL SYSTEMS

STEVE DOTY, PE, CEM

22.1 INTRODUCTION Control systems are an integral part of many energy related processes. Control systems can be as simple as a residential thermostat, to very complex computer controlled systems for multiple buildings, to industrial process control. Their diligence and repeatability can also serve to maintain the savings of the project improvements for years, further justifying their existence by providing economic return to the customer. This chapter will introduce the reader to some concepts of automatic control theory, followed by practical applications useful to the field of the Energy Professional. Upon completing this chapter the reader will gain a basic understanding of common terms, control technology and control mode categories, basic input and output instrumentation, and the practical need to temper ‘things possible’ with the skill level of the operators who will inherit it. The importance of system controllability and user-friendliness, as primary design parameters, will be stressed. Basic control strategies will be discussed. Estimating savings from the use of Automatic Controls will be discussed. Finally, there will be an introduction to some complex optimization methods, and suggested topics for further study. Examples are used throughout. The intent of this chapter is to focus on the application of Automatic Controls as a tool to achieve energy savings. Some background information on controls is obviously a necessary prerequisite; however this chapter does not attempt to cover all aspects of automatic control theory or application or to make the reader a controls expert. Less emphasis will be placed on hardware and theory, and more emphasis will be placed on practical applications and tangible benefits. A basic background in energy-related subject matter, common energy units, common energy-consuming machinery and systems, HVAC concepts, and the general field of energy engineering is assumed. The field of Automatic Controls is a busy technology with lots of jargon, hardware and software variations and details, and the sheer volume of it can create an air of mystery and awe. If this chapter 577

is successful, the reader will be able to separate the fundamental control concepts from the technical details, and effectively apply Automatic Controls to achieve energy savings. Many of the examples given are for commercial building HVAC and lighting systems, since these examples are common and should be familiar to the reader. Similar concepts and considerations apply equally to other fields of endeavor where energy savings are a driving force. A Glossary of Terms provides clarification of common terms used in the field of Automatic Controls.

22.2 WHY AUTOMATIC CONTROL? •

•

•

Regulation: Many things need attention and adjustment to compensate for changing conditions, or varying demands. Examples of this are common in living organisms, such as body temperature, blood pressure, etc. Process control regulation is really just emulating the concepts of such natural processes. The field of automatic control is similar in that we ‘continually adjust some device to cause a particular measured variable to remain at a desired state.’ Examples: The need to throttle heating and cooling equipment sized for maximum load that is effectively oversized at part load conditions. Varying occupancy, and systems attendant to the occupants (lighting, ventilation). Varying product throughput rate through manufacturing facilities. Varying demands, and the need to maintain level or full state for water or fuel reservoirs, feed or coal bins, etc. Coordination: Organizing or sequencing multiple processes in a logical and efficient manner is an important aspect of automatic control applications. Automation: Human beings can make very good manual controllers because we can think on our feet and consider many variables together, but most control tasks are repetitive and suitable for mechanization. Automatic operation allows people to provide oversight of system operations and more

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effectively utilize their time. Consistency: Manual control by people can be effective, although we are not all that repeatable and are sometimes forgetful. Using machinery for automatic control adds the improvement of consistent, repeatable operations. The repeatability and consistency feature of automatic control is very important in manufacturing. Conservation: Supplemental enhancement control routines can be incorporated to reduce energy use while still maintaining good control. It is important to note that control systems do not necessarily reduce energy consumption, unless specifically applied and designed for that purpose.

nature, and frequently it is also the simplest and most elegant method of control.” [1: pp xi] To summarize, the desires for maximum simplicity and maximum efficiency are at odds with each other. A system that is perceived as being too complex will likely fall into disrepair and be bypassed or unplugged. If the customer is committed to squeezing their energy costs through optimization, they will need to also embrace the technology and be willing to adapt and change along with the process. It is almost a given that pushing the envelope of optimization requires the operations personnel to accept additional complication and raise the bar of required operational skill. This concept should be discussed in advance to be sure the project isn’t set up to fail by being unacceptably complex.

22.3 WHY OPTIMIZATION? 22.4 TECHNOLOGY CLASSIFICATIONS The 80-20 Rule reminds us that we can usually hope to achieve 80 percent of the measure’s potential with 20 percent of the difficulty, but the remaining portion requires much more effort. For this text, Optimizing refers to reducing energy consumption as much as possible, often approaching the barrier of diminishing returns. Optimization can be characterized as taking over where the basic controls left off and working on the remaining opportunities—the ones that aren’t as easy to attain. The appropriate use of optimization depends upon the customer’s priorities, and these should be tested before the decision to optimize is made. Of course, from an energy conservation or ecology standpoint, we should all press for that last 20 percent. But if maximum simplicity controls that require only basic skills are a main focus of the customer, optimization may not be a good application. Similarly, projects where reliability is priority #1 may be better served with basic control routines, allowing the extra 20 percent potential to slip away to gain the advantages of simplicity. Economics always comes into play, and some optimization projects (chasing the last 20 percent) may not have the attractive payback periods of their 80 percent counterparts. Most projects represent some balance of these interests, depending upon the needs of the customer. It is important to understand that optimization for maximum benefit will not be for everyone. A case in point for optimization is the subject of fixed set points, which are often a matter of convenience or approximation, and usually represent a compromise in optimal energy use. The more factors we can take into account, the closer to optimal will be the result, as stated by Liptak: “…multivariable optimization is the approach of common sense. It is the control technique applied by

22.4.1 Introduction The following is a very important first statement before any discussion about control hardware: “The type of hardware used in optimization is less important than the understanding of the process and of the control concepts that are to be implemented.” [1: pp 42] The main goal should be to become clear about the process fundamentals and what should happen—then the parts and pieces are just details. This discussion of different available hardware types is a familiar but sometimes laborious and dull part of any controls text. Remember that Automatic Controls are really nothing more than machines that do for us what we would do ourselves if we had nothing better to do; they do work for us like any other tool, and are only as clever as the people who craft them. 22.4.2 Conventional Electric (also On-Off or Two-State) Electricity is used as the power source. Control is discrete (on-off, high-low, cut-in/cut-out, etc.). Contact closures are used to implement control logic. This principle of control has widespread use, varying from simple and familiar control to complex interlocks and Boolean Logic. Examples: • A basic home heating thermostat cuts in at 67 degrees F and cuts out at 69 degrees F, thereby maintaining a room temperature of approximately 68 degrees F. • A well pump controller cuts in when the storage tank pressure is 50 psig and cuts out when the storage tank pressure is 70 psig, thereby

CONTROL SYSTEMS

•

maintaining a system pressure of approximately 60 psig. An interlock circuit that prevents an exhaust fan from starting until the associated make-up air damper is first proven open.

The differentiator between Conventional Electric controls and Analog Electronic Controls is the discrete (two-state) nature of the inputs and outputs; analog controls have varying rate inputs and outputs. 22.4.2.1 Floating Control. A variation of this two-state control is “floating control.” Technically still “on-off,” this unique control method has a system control action similar to analog (modulating) control. With floating control, whenever the signal is sufficiently off set point, the motor actuator (moving a valve or damper) is energized, providing correction to the process. What makes floating control different is that once the feedback measurement indicates the process has returned to set point, the actuator is de-energized but the device (valve or damper) holds its last position—which may be 1/4 open, 1/2 open, or any midrange point. Because of this, floating control can achieve tighter control than simple on-off control, approaching that of true modulating control. Floating control is less expensive to implement than modulating control, and is used for small terminal HVAC control valves and dampers, as well as large machinery like chiller inlet vanes. See also Control Modes for a diagram that illustrates floating control action. 22.4.3 Analog Electronic Electricity is used as the power source. The key difference between analog and conventional electric control is modulation. Analog controls have variable inputs and outputs, not just two states. Minor changes in output positioning of controlled devices make tighter control possible than with two-state (on-off) electric controls. The hardware for analog electronic controls may include resistors, rheostats, Wheatstone bridges, operational amplifiers, or may use solid state components to measure the process and modulate the output devices. Some considerations of analog electronic controls: • Unless a control dead band is built into the controller, it is likely that the controlled device will be activated by even the most minute deviation from set point. The action may be nearly imperceptible, but if this occurs the repeated hovering about the ideal set point may over work the actuators and cause reduced device lifespan.

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•

Analog electronic technology “connectibility” options are generally limited to remote adjustments, remote alarm panels, etc. This, and modest cost, make them a popular choice for basic HVAC manufactured systems that come with factoryinstalled controls.

22.4.4 Pneumatic This is the general term for controls that use compressed air as the motive force for control inputs and output, instead of electricity. Analog pneumatic pressures are alternately coded and de-coded into control units; for example: 3-15 psig = 0-100 degF. Discrete pneumatic pressures are also coded; for example, 0 psig = off, 20 psig = on. Pneumatic devices can be two-state or modulating, but are most commonly modulating. Pneumatic controls often have interface devices that communicate pneumatic signals to and from their electric counterparts, such as Pressure-to-Electric switches (PE switches), and various Electric-to-Pneumatic solenoids and transducers. Some considerations for pneumatic controls: • Air supply quality is critical. No oil or water allowed at the instruments! • Contamination in the main air system represents a potential single point of failure for many or all pneumatic controls. 22.4.5 Digital Control (also called Direct Digital Control or DDC) This control technology uses microprocessors to provide control. A big advantage to DDC controls is the fact that changes to the system are often made with software and do not automatically require physical changes and cost like other technologies. Discrete (onoff) information is readily absorbed as a “1” or “0.” For analog processing, interface equipment called digital-toanalog converters (D/A) and analog-to-digital converters (A/D) are used. The higher the resolution of the A/D and D/A conversion, the closer the digital signals resemble true analog signals, allowing smoother control. One of the great enhancements of digital controls over the last 30 years has been the concept of distributed control. This technology shift occurred in response to customer complaints of excessive dependence on single hardware or software points, and widespread loss of control after a single item failure. Current best practice uses multiple smaller controllers at the points of control. These communicate upstream to a supervisory operator workstation, but each single failure point now affects a much smaller area, increasing overall process reliability. •

DDC Graphics: A Graphical User Interface (GUI) is an overlay onto most DDC control systems. While

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labor-intensive to create, these are useful for gaining acceptance of the control system, and can reduce the skill level needed for digital control system navigation. The GUI uses easily recognized icons and symbols, color-coded messages and alarms, and other visual methods, to increase the user-friendliness of the system. The GUI is analogous to the labeled display boards of traditional pneumatics. •

•

•

Field User Interface: For effective operations and maintenance, the user interface should not be limited to operator workstation graphics. Like the pressure gages or test ports of a pneumatic system, some form of user interface should be provided at the point of control to invite personnel to interact. This may be a fixed display-adjusting device that can scroll through a few points, to a portable operator workstation that can be connected at will. Without some provision for user interface in the field, the DDC system can introduce a frustration to the operations personnel who cannot “see” what is going on at the equipment locations. DDC Controller Hardware: Today’s digital controls come in a variety of styles, to suit the application. For common applications, mass produced and low cost definite purpose controllers are available. These use factory programming, also called ‘canned’ software, which speeds application and start-up, but may limit the opportunities to create special instructions or for optimization, unless sufficient programming is available from the supervisory controller to achieve the intended result. Multi-purpose generic controllers are also available that utilize custom programming. These generally come with a fixed number of input and output points, but the point capacity can often be expanded with multiplexers or other point expander cards. Since the programming is custom, these controllers are the natural choice for optimization routines that require dynamic calculations and adaptability. For control processes with a large number of points, point expander boards are usually preferable to multiple linked controllers because having a single processor brain eliminates some unpredictable operations modes that come from partial failures, e.g. if just one of the controllers fails. Conversely, too many expander boards can turn this application into a large-effect single point of failure. Proprietary vs. Open DDC Controls: The topic of proprietary controls, captive customers, open

protocols, hybrid systems, gateways, etc. is a hot topic in the control industry today. While the concept is not difficult to grasp, details and implications are very numerous and complex, and beyond the scope of this text. The basic argument FOR proprietary systems is the one-stop-shopping ease of purchasing, and security of all-encompassing technical resources for system maintenance and system integration; for large or complex systems this can be an important benefit. The basic argument AGAINST proprietary systems is the proprietary lock on the customer, and how the lack of competition almost certainly results higher replacement costs that escalate during the ownership life cycle. Current state of the industry includes both proprietary systems and “open protocol” systems, and both are viable, requiring a customer choice where new systems are proposed. Gateways and translator offerings are hardware go-between solutions that offer limited connectivity between proprietary systems. These are common solutions, but can create new problems even as they solve others—and many retain the proprietary nature they are intended to solve. •

DDC Information Technology (IT) System Maintenance: Systems that share communication infrastructure with other, more sensitive, systems require careful attention to information configuration and maintenance. The ideal approach is to have computer Information Technology (IT) capabilities on staff; devoting their time to control system integration activities as an in-house expense; however this may be cost prohibitive for all but the largest systems. The more common ‘drop-in’ approach is to select an industry partner to provide this technical service, although this can gravitate back toward proprietary solutions unless the person maintains an independent status from any equipment manufacturer.

22.5 CONTROL MODES 22.5.1 Introduction Deciding which control mode to apply is important, regardless of the technology used. It is important to understand that these modes can be implemented using many of the available technology types. In many cases, simple on-off control is adequate, and very appropriate. In other cases, the desired effect can only be achieved with modulating controls. The following are basic control

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——————————————————————————————————————————————————— TECHNOLOGY

PROS

CONS

Conventional Electric

• • • • •

Simple Proven Easy to understand and troubleshoot Inexpensive Accommodates “and-or” logic with simple series-parallel circuits (relay logic). • Floating control variation approaches analog control quality with reduced cost.

• Definite purpose controls are not flexible without hardware change. • Limited capabilities for optimization.

• Lowest cost stand-alone modulating control option. • Often standard equipment on packaged HVAC equipment.

• Long term drift unless properly maintained. • Short-lived components. • Definite purpose controls are not flexible without hardware change. • Often not user-friendly. • Limited capabilities for optimization. • Input/Output hardware items, especially actuators, are more expensive than conventional on-off devices.

———————————————————————————————————————————————————

——————————————————————————————————————————————————— Analog Electronic

——————————————————————————————————————————————————— Pneumatic

• • • •

Simple Proven End devices extremely durable Can be long lived if designed and maintained properly.

• Long term drift unless properly maintained. • Temperature dependent drift. • Definite purpose controls are not flexible without hardware change. • Limited capabilities for optimization. • Susceptible to system-wide failure if compressed air system is contaminated. • Complicated adjustments for pneumatic controllers • First cost includes infrastructure cost (tubing). • Future operator work force may have a reduction in skill level for this technology.

——————————————————————————————————————————————————— Digital Control (DDC)

• Excellent flexibility, using software changes with existing hardware. • Best option for optimization due to computing power. • Opportunities for communication linkage to other, compatible equipment for large data gathering/workstation benefit. • Convenient method of recording key measurements, baseline information, historical data, trends, run-times, etc. • Convenient remote monitoring.

• Highest first cost. • First cost includes infrastructure cost (cabling). • Often outdated before physically worn out, due to rapid technology advances. • Tendency for proprietary equipment manufacturers to create captive customers and high life cycle costs for repair parts and software upgrades.

——————————————————————————————————————————————————— Figure 22.1 Pros and Cons of Different Control Technologies modes. The accompanying diagrams will illustrate typical system performance. The term “system capacitance” refers to the rate of response of a system to a stimulus. Systems with a large capacitance tend to resist change and the effects of control are felt more slowly than systems with smaller capacitance. Comparing the effect to a flywheel or relative mass is a good way to describe this concept. Another useful example to illustrate system capacitance is an instantaneous electric water heater (small volume of water) compared to a standard residential tank-type water heater—upon energizing the heater elements, the

water temperature in the tank unit changes much more slowly because it has more mass, and we say it has greater system capacitance. The term “gain” is a control term synonymous with sensitivity, and is usually an adjustable value used to tune the controls. If a quicker response is desired for a small input change, the gain is increased. This makes the input change more noticeable, and results in a stronger output reaction from the controller. 22.5.2 On-Off Control Also called “two position control” this rudimentary

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mode is used with equipment that is either on or off. A nominal set point exists but is rarely actually achieved, except in passing. A range of control values must be tolerated to avoid short-cycling the equipment, and temperature ranges are often fairly wide for this reason. In the case of equipment that cannot be modulated, this is often the only choice. The smoothness of control depends strongly upon the system capacitance; systems with very low capacitance can experience short cycling problems using two position control. 22.5.3 Floating Control A hybrid combination of on-off control and modulating control, also called incremental control. As with on-off control, there is a control range (cut-in/ cut-out). However, unlike on-off control, floating control systems have the ability to maintain a mid-position of the controlled device, instead of full-on or fulloff. Between the cut-in and cut-out thresholds the controlled device merely holds its last position. The process variable is not actually under control within this range, and is seen to float with the load until it crosses a threshold to get another incremental nudge in the correcting direction. This control is not as tight as true modulating control, but is inexpensive and reliable. Equipment items from terminal units to 1000 HP Water Chillers are controlled in this manner with good success. Note that floating control is limited to processes that change slowly and do not require very tight control. ProportionalOnly Control (P) This is the basic modulating control, and what most commercial pneumatic and analog electronic systems utilize. It is essentially an error-sensing device with a fixed gain or amplification. A control

output is issued to regulate a process, and the magnitude of the output is directly proportional to the size of the error. This type of control is economical and reliable. A characteristic offset (residual error) is natural with this type of controller, and the size of the offset will increase with load. This offset is due to the inherent fixed-gain of

Figure 22.2 On-Off Control Mode Diagram

22.5.4

Figure 22.3 Floating Control Mode Diagram

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the controller. If the proportional control action is too sensitive (gain set too high), the controller’s response will be excessive, and oscillation or hunting will occur. When this occurs, the controller output (and the equipment connected to it) oscillate up-and-down, open-and-closed, etc. and don’t settle out. ProportionalPlus-Integral Control (PI) An integral function is added to a proportional-only controller to eliminate the residual error. This control action adjusts the gain to a stronger and stronger value until the error is eliminated. In theory, the integral controller will not rest as long as any error exists, however it is common to allow a small acceptable error band around the nominal set point to prevent incessant low-level hunting as the controller seeks the perfect “zero” error condition. In practice this has the appearance of slowly but surely building up the output to taper off the error. Since the “wind up” effect is slow, but also relentless, integral control problems can occur in processes that change rapidly. Also, if the controller is left active for long periods while the controlled equipment has been turned off, the integral controller will “wind up” to a 100% output. Upon startup after a long period of windup, the integral function can be strong enough to “stick” at full output for long periods of time with complete loss of control. Therefore, whenever integral control is used, some form of hardware or software interlock

must be used as an anti-wind-up measure. The most common approach to preventing wind-up is to simply turn off the controller when the process is stopped. 22.5.6 Proportional-Integral–Derivative Control (PID) PID Control is used to accommodate rapid changes in process and minimize overshoot. This is done by reacting to the rate of change of error (derivative) instead of the

22.5.5

Figure 22.4 Proportional Control Mode Diagram

Figure 22.5 Proportional-integral Control Mode Diagram

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magnitude of the error (proportional) or the duration of the error (integral). In reviewing the characteristic response curves, PID control looks like the absolute best and, in fact, does provide the tightest control of all the control modes. However, the derivative gain is very touchy to set up properly and can easily cause instability of control, especially at the beginning of a batch process or after a large step change. In HVAC work, the derivative term is seldom used to avoid the potential for instability, and since most HVAC processes are relatively slow acting and are tolerant of temporary overshoot of PI control. In many process control applications, PID control is essential since close control is often tied to product quality.

• • • •

Normal offset from proportional control. Normal time lag from Integral control. Independent, but sequenced, modulating controllers. Adjacent processes, such as two comfort zones in an open bay with widely different user set points.

Where the process does not require absolute tight control, building in some blank spaces or dead band between sequenced elements is a simple way to achieving and sustaining energy savings.

22.6 INPUT/OUTPUT DEVICES

22.5.7 Sequencing 22.6.1 Introduction While not actually a separate control mode, this There are many available input and output devices, topic deserves special attention since it has great potential for energy savings. A significant blight in many industry processes is the overlapping of adjacent and opposing processes. A common example is HVAC reheat, where air that has just been cooled with an energy source is now being heated. This is analogous to driving around with the accelerator fixed and controlling the vehicle speed with the brakes; even if the detriment to the brake system is neglected, the effect upon vehicle fuel economy is obvious. There are many examples of heating/cooling overlap, some deliberate but most inadvertent—but all make overall energy consumption higher than Figure 22.6 Proportional-Integral-Derivative Control Mode Diagram necessary. One very effective tool in combating or correcting this is effective equipment sequencing. Ignoring some of the imperfections of real-world control systems, some control systems that appear sequenced will actually overlap occasionally, or over time. Some things that contribute to inadvertent overlap are: • • •

Instrument drift. System influence upon actuator range of motion. Normal overshoot from on-off controls.

Figure 22.7 Sequencing with Dead Band

CONTROL SYSTEMS

serving many basic and specific needs, along with ranges of quality and other features as required for the job, and the Controls Application Engineer quickly becomes familiar with many of these in great detail. The Energy Professional may choose to delve into the sea of products, but can also be very effective by providing only performance-based generic requirements and managing the project from a more macro view. For input and output devices, there are basic distinctions between Transducers, Switches, Sensors, and Transmitters which are useful to understand. •

Transducers: These are the core of any instrument, and are used to convert the basic physical phenomena of interest into a form more useful to the instrument. Examples: — Temperature: bimetal coil, two-phase gas bellows, thermistor, RTD, etc. — Pressure: Bourdon tube, diaphragm, strain gage, etc. The term ‘transducer’ is also commonly applied to output signal form changing equipment, such as converting an analog electronic signal to a corresponding pneumatic signal for use by a pneumatic actuator.

•

Switches: Devices that can have two states (on-off, open-close) etc., used for regulating on-off electrical circuits as inputs or to actuate other equipment or devices in a two-position manner. Solenoid valves, relays, etc. are in this class of instruments.

•

Sensors: These are “passive” input devices that can be read directly by the controller with no signal conditioning. They are usually limited to short cable lengths and further limited to transducers with inherent linear outputs. Examples: — RTD (resistance temperature detector) that can be wired and read directly to the controller.

•

Transmitters: These are the typical analog input instrument. A transducer is coupled with some form of pneumatic or electronic signal conditioning. The transmitter output is a linear, standard value easily decoded as an input. Often, the signal conditioning allows for stable signal over a large distance to allow remote location of the device, hence the term ‘transmitter.’ Examples:

585

— — — —

0-100 degF 0-100 degF 0-100 degF 4-20mA output

‡ 3-15 psig ‡ 4-20 mA (milliamps) ‡ 0-10 VDC (Volts DC) ‡ 3-15 psig

22.6.2 Conventional Devices and Wiring Conventional wiring architecture consists of devices in the field; each wired back to the input or output terminals of the controller, with a dedicated set of wires (often a pair of wires). Thus, for 100 instruments there would be 100 sets of wires finding their way home to the controller. This type of wiring is very straight forward and is referred to as home run wiring. At the control panel the number of wires is the greatest and the system of wires fans out and disperses, the further it gets from the central point. 22.6.3 Addressable (‘Smart’) Devices and Wiring Also called ‘smart’ devices, these devices can be controlled directly by a digital control system, by giving the device a unique identification code or “address” to differentiate it from all other similar devices. Usually each addressable device has a means of setting up its own unique address or name, to permit uniqueness in communication. Addressable devices relay their information or accept their commands digitally, and do not rely on transmitters or the like. Addressable devices have the distinct advantage of reduced wiring, since a single loop of communication trunk wiring can be shared by multiple devices; on systems with large number of points, the difference can be remarkable. However, addressable devices cost more than conventional (nonaddressable) devices, since they include on-board communication hardware, as well as A/D and D/A converters for addressable analog devices. Since they cost more, their application requires balancing the cost vs. the benefits. Of the devices listed below, the ones currently most popular are the simple contact closure input/output devices used in large quantities for security, fire alarm, and lighting control systems, where the economies of scale show an advantage. The single loop communication can present new failure modes compared to conventional home run wiring methods; i.e. if a single cable is cut how many devices are affected? Common Addressable Devices: • Fire alarm devices—input and output • Lighting control devices—input and output • Security devices—input and output Other Addressable Devices: • Lighting ballast

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Actuators Transmitters and sensors Thermostats Relays

22.6.4 Linearization “For simplicity of design, a linear relationship between input and output is highly desirable.” [3: pp 28] Linearity is a high priority in instrumentation, for both inputs and outputs. This is because the controller’s algorithms or ratios are arithmetic in nature, comparing the input to a standard and producing a derived output. Linearization makes the effect of the controller’s decisions predictable and manageable. Understanding how linearization can affect the control system is important to assure project success. Input/Output instruments are considered linear when an incremental change of input value produces an equal increment of output value regardless of the value of the input or location of the device’s range. For example, a change of 1 degree F might produce a change of 0.16mA in transmitter output. If truly linear, the device would produce this 0.16mA change in current if reading 0 to 1 degF, or if reading 100 to 101 degF. To the extent that non-linearities exist in the control loop, errors and unpredictability will also exist and so should be identified and minimized. Many natural phenomena are linear, and many are not. Linear Examples include metal resistance with respect to temperature changes, static pressure with respect to depth of liquid, and volume of a vertical cylinder with respect to level. Non-Linear Examples include the volume of a conical container or a horizontal cylinder with respect to level, the change in flow with respect to butterfly valve or single blade damper position, and a heat exchanger heat transfer rate with respect to flow rate. Some natural phenomena behave in predictable, but non-linear fashion. These include thermocouples and differential pressure flow meters (head loss devices). Thermocouples are linearized by a look-up table or mathematical expression that defines the non-linearity, while head-loss meters are linearized with a square root extractor. Most common input measurements have already been linearized by the instrument manufacturers. Instead of hardware characterization, it is possible to linearize inputs and outputs through software. This “software linearization” is sometimes used with industrial controls, but seldom with commercial controls. A common control issue with linearization is control valves and dampers. These are notorious for having nonlinear response with respect to travel position. Control

valves are generally characterized as either linear, quick opening or equal percentage. For valves, the flow “character” is achieved by specially contouring the valve plug, to influence the flow rates at different valve stem positions. Characterized ball valves are also available, to greatly improve the inherent quick-opening flow pattern of these valve trim shapes. Control dampers and butterfly valves are either flat blade or flat disk shapes and do not have selectable characterized flow patterns like control valves do. In the case of control dampers, about all that can be done to reduce non-linear air flow through the damper is to down-size it to create a high pressure drop, which may create other complications or costs, especially in outside air ducts and large ducts without room for transitions. Where linear control of an air stream is important, air valves can be used which are available with characterized flow patterns. Modulation of a heat exchange process is a common automatic control application. The following example applies for most types of heat exchanges including shell and tube, tube and fin, etc., and includes all HVAC air coils. The heat transfer characteristics of a heat exchanger can be likened to a ‘quick opening valve’ since the incremental change in heat transfer for the first fraction of fluid input is much higher than the last fraction. Controlling flow linearly through a heat exchanger will yield a non-linear output with associated control problems, especially tuning issues. In this case, the non-linear flow characteristic of a control valve is deliberately used to improve process control. The standard approach to correct this is to use a control valve with a flow characteristic that is a mirror image of the inherent heat exchanger performance (equal percentage type), canceling this inherent phenomenon so the overall control effect is nearly linear. This example not only illustrates how linearity is important to a control system, but also points out that for heat exchanger applications, the control valve selected should almost always be the equal percentage type.

22.7 VALVES AND DAMPERS 22.7.1 Valve and Damper Selection Selection criteria usually includes a minimum pressure drop for proper authority and best linearity over the process. 22.7.1.1 Valve Sizing The typical sizing procedure for a hydronic control valve is 5 psig wide open pressure drop. The following explains the reason for this. The underlying principle for reasonable control of a heat transfer coil is for the control

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seated valves, undercut butterfly valves, and actuators without a positive seating mechanism to impart a residual tight seating force. Spring-return pneumatic actuators are forgiving in this sense because they inherently provide residual seating force. Some electronic actuators have mechanisms to provide ample seating force, but others rely on simple travel adjustments that define the open and closed positions—these are very undesirable since the opportunity for internal leak by, with subsequent heat/cool overlap, is high. Ball valves can be used for modulating service if they have characterized seats, and are inherently tight seating. Actuators that are only Figure 22.8 Control Valve Characteristics marginally strong enough to close off against system flow can rob the valve wide open pressure drop to be at least as high as system of efficiency over time as system pressures change, the coil it controls. So, if an air handler coil is sized for a valve stems bind, damper axles stiffen, etc. Determining 5 psig pressure drop at full flow, then the control valve at system needs and requiring close off ratings well in 5 psig full flow pressure drop would be appropriate. It is excess of this (e.g. at least 50% more) is good practice for common practice to select HVAC water coils at 10 ft. w.c. sustainable operation. or so wide open pressure drop, which equates to 10/2.31 = 4.3 psig. Thus the 5-psi valve pressure drop convention 22.7.1.3 Damper Sizing Just like valves, down-sizing dampers will improve is a reflection of the coil sizing convention. An extension of this logic would be that if the coil were selected at 1 control at the expense of raising system pressure. In psig wide open pressure drop, then the control valve practice, dampers are often left duct-sized, even though sizing criteria could also be reduced. This is in fact the resulting control is poor. There are several reasons for case, although seldom done in practice since coils selected this: at extremely low pressure drop have other, new issues, • Dampers are relatively cheap, compared to the namely reduced velocity and laminar flow heat transfer transition costs for a duct fabricator. degradation at reduced flows. • Dampers are often large, and transitions take up space that may not be available. Editorial Comment: The practice of adding system resistance to achieve good control is counterintuitive and definitely an opportunity for improvement in the industry, because adding circuit resistance to any fluid handling system increases the system energy requirements. 22.7.1.2 Leak-By and Close Off When specifying control actuators, specifications and close attention are important to achieve reliable closeoff performance. This is true for both valves and dampers, especially those with marginal actuator close-off ratings, excessive system pressure, large damper sections, metal-

•

At outside air intakes, a down-sized damper can cause rain or snow entrainment.

For air flows control by dampers, other than HVAC, proper sizing will yield more linear control and is recommended where practical. For control purposes, the opposed blade damper is normally used, since its aperture size and overall resistance varies the most directly with travel. Conversely, “parallel blade” or round dampers are highly non-linear in nature and hard to control unless drastically down-sized, or used for two position control only.

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22.7.1.4 Other Damper Considerations Large damper sections are often problematic. For cost reasons, there is often a desire to use fewer, larger actuators and link the dampers together so an adjacent actuator is driven by another damper, not an actuator. In practice, this can easily result in one end of a long section substantially open even as the actuator-end is closed. This is due to the fact that the damper blades and axles will twist and stretch. Methods to prevent this undesirable condition include multiple actuators or jack-shafting.

return actuators are more costly, so should be used prudently, where the added cost is justified. For large pneumatic cylinder actuators, a measure of fail-safe control can be provided without the expense of a spring system; using an air-to-open/airto-close actuator (no spring) and a small spring return air solenoid valve, the position of the actuator can be relatively assured on power loss, as long as compressed air remains available.

22.7.2 Valve and Damper Actuators Like other instruments, actuators come in a variety of styles and quality levels, and each has its pros and cons. Significant differences exist between manufacturers that make generalizations and rules of thumb difficult. One thing is certain about actuators: they are a moving part, with mechanical components, and will require maintenance; therefore consideration should be given to life cycle cost and maintainability. Some of the lower cost actuators are not intended to be serviced. For each of the types listed there are serviceable and throwaway variations, as well as spring-return/non-spring return types. Types of actuators include:

22.8 INSTRUMENT ACCURACY, REPEATABILITY, AND DRIFT

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Pneumatic spring return Pneumatic air-to-open/air-to-close Electric motor/gear reduction in oil bath Electric motor/gear reduction-open air Electric hysterisis/stalling motor Hydraulic Wax motors (thermal expansion) System powered actuators/using air or water system pressure as the motive force Self-powered actuators/using a capillary bulb and bellows

22.7.2.1 Actuator “Normal” (spring return) Position For valves and dampers, the phrases normally open or (N.O.) and normally closed (N.C.) refer to the device position with no power applied, where a spring-returning mechanism exists to drive it to one position or another. Valves required to have a “fail position” are necessary in many applications to provide an increased measure of reliability if control power is lost. In the case of comfort heating and cooling, the choice is made by asking “upon a loss of power, control signal or air pressure, would I rather have full heat, full cool, or don’t care?” In other cases, there are other operational issues like overheating, over-humidifying, etc. that should be considered. Without the spring return feature, the actuator will simply remain at its last position prior to the power interruption. Spring-

22.8.1 Introduction Like anything else, there are different grades of instruments with corresponding costs, so the task of the specifier is to separate the needs from the wants, and to balance the performance with the costs. With an awareness of some of the basic considerations and of instrument grades and selection criteria, good decisions are usually evident. Leaving the instrument selection entirely up to the vendor may or may not be the best approach. To the extent that the ‘standard offering’ instrument portfolio has good performance, this can save money, however a review of the proposed instruments is advised just to be sure. When reviewing product literature for instrumentation, like any other equipment, it is often as important what is not said, as what is said on a component specification sheet. For example, if long term drift is not mentioned, ask yourself “why is that?” 22.8.2 Accuracy In the realm of instrument calibration and accuracy specifications, there are two important terms: “percent of reading” and “percent of span.” It is not enough to say “+/- 5%” when specifying a calibration tolerance or instrument accuracy rating. The tolerance should be stated as either +/- xx degF, +/- xx psi, etc., +/- xx% of reading, or +/- xx% of span. Usually the instruments that are rated in terms of +/-% of reading are the higher quality instruments. The following example illustrates the important difference between “% of reading” and “% of span” concepts. Consider a 0-100 psig (span) transmitter that is indicating 10 psig (reading). Accuracy Spec “+/- 5% of reading,” Acceptable Range 9.5-10.5 psig Accuracy Spec “+/- 5% of span,” Acceptable Range 5-15 psig

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Figure 22.9. Suggested Tolerances For Commercial Instruments. 22.8.3 Repeatability Repeatability is self-defining; it is the ability of an instrument or process to faithfully repeat itself, given identical conditions. For instrumentation, this is synonymous with precision, and the mark of better grade instruments. Regarding instrumentation, a general statement is that accuracy can be adjusted, but repeatability is a function of the instrument quality and cannot be changed. Repeatability is determined, in large part, by the stability of the output in the face of environmental changes, such as ambient temperature effect, voltage fluctuation, pressure fluctuation, etc. Instruments whose readings are susceptible to changes in ambient temperature can be very problematic if located in areas where the temperature is expected to change, however this specification (and the cost to mitigate it with higher quality instruments) is of much less concern if located in areas of constant temperature. Commercial grade pneumatic instruments are usually susceptible to problems from ambient temperature changes, since thermal expansion changes the volume of tubing, size of orifices, etc. Some lower grade electronic components are also affected by ambient temperature changes. 22.8.4 Drift Drift is an undesirable but inevitable quality for any instrument. Long-term drift is attributable to many factors including normal degradation from age. A general rule of thumb is that the long term drift, from all sources combined, leave the instrument reading within reason for a period of five (5) years, to reduce the need for O/M activities and constant maintenance of the device, leaving it to serve instead of being served by the facility. Auto-Zero Feature: Some devices, such as stack gas sensors and very-low range differential pressure transmitters, periodically re-establish the zero point of their output span by simultaneously providing a zero input condition and automatically adjusting the output to a zero value.

22.9 BASIC CONTROL BLOCK DIAGRAMS 22.9.1 Introduction Besides control technology and control mode choices, a basic consideration of control strategy is whether it is open or closed loop. 22.9.2 Closed Loop Control The controlled system impacts the measured variable, and process measurement provides feedback to the controller. Examples of Closed Loop Control: • Room thermostat controls a heating water valve, to regulate heat to that room. •

Leaving water temperature sensor for a heat exchanger controls the steam inlet valve to that heat exchanger.

22.9.3 Open Loop Control An open-loop control system is characterized as one whose output has no impact on the measured variable, and so any form of process feedback is impossible. Examples of Open Loop Control: •

Turning off the building heating boilers in April and leaving them off until September. A common control strategy, this follows the common sense notion that boilers should not be needed in summer, but does not address spring and fall vary well and can lead to both discomfort and energy loss when weather is unseasonably cold or warm, usually near the calendar cutoff dates. This is open-loop because the outside air temperature is unaffected by whether or not the boiler is on. This is also open-loop to the building itself, because call for heat feedback will not be heard.

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Figure 22.10 Closed Loop Control

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Automatic reset of hot water temperature from outside air. A common control strategy, this provides general compensation based on the common sense notion that ‘the colder it gets outside the more heat we’ll need,’ however is open-loop since the outside air temperature is unaffected by water temperature. Starting the building HVAC system one hour before occupancy. A common strategy, this follows the common sense notion that the building will need some time to warm up (or cool down) after being off all night, or all weekend. It provides general compensation for the thermal lag in the building mass, but is open-loop because variations in actual time required in different seasons is not considered. For example it may take (4) hours after a long and cold weekend but only a half-hour after a single night in spring, but the controller is blind to these facts. Thermostat in room 1 controls the hot water control valve serving room 2. In this example, closed loop feedback control is changed into open loop control due to a design or installation error.

Figure 22.11 Open Loop Control 22.10 KEY ELEMENTS OF SUCCESSFULLY APPLIED AUTOMATIC CONTROLS 22.10.1 Examples of Good and Bad Control Applications Example. • BAD. Two thermostats in an exterior room; one serving the perimeter heat and the other serving

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Figure 22.12 Controls Application Checklist

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the VAV cooling box overhead air distribution. GOOD. One thermostat in a perimeter room; sequencing the VAV box and perimeter heat, with a dead band in between to prevent overlap.

• • •

22.10.2 Examples of Good and Bad System Controllability Example. • BAD. A single step controller on a 50-ton HVAC package unit that has one compressor attempting to maintain a constant 55 degree discharge temperature. Excessive equipment cycling will result, regardless of controls, and the consequence of poor control and likely premature equipment failure. • GOOD. A four-step controller on a 50-ton HVAC package unit that has four compressors, where 12.5 tons represents a typical part load day for the building. Cut-in and cut-out set wider than the temperature change of each stage, to prevent short-cycling. Minimum on-off times further safeguard equipment from short-cycle damage. 22.10.3 Examples of User-Friendly Control Design Features • Match the system complexity to the user’s level of sophistication, or their willingness to learn. If it’s too complex, they’ll probably just unplug it 6-months after start-up. Training will help to raise skill levels and avoid over-simplification. Be patient, especially for anything complex. Any type of measurement that allows the user to see the savings created by the new control system will help spark interest and encourage ownership and buy-in. • Control diagrams at the control panel as a handy resource. • User adjustment for comfort control applications. • Devices located in accessible locations for repairs and calibration. • Redundant Visual Indicators by key inputs and outputs. • Valve position indicators that are visible from the floor. • Temperature and pressure gages adjacent to key measurement points. • Man machine interface provision at the process location. • Override Provisions for key output points to

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accommodateemergencieswithoutdisconnecting things. Standard parts that are readily available. Sensors and Transmitters with long-term stability for minimal need for calibration. Arrange control wiring/tubing with troubleshooting in mind. Power on-off switches and air shut-off valves, in key locations to assist the service person. 3-valve manifolds at flow meters to allow zerocalibration. Drain and Vent valves at fluid transmitters for routine calibration. Minimum on-times and off-times to prevent short cycling. Make normal-use operator parameters adjustable, and critical parameters non adjustable, to allow user interaction and reduce inadvertent changes for the worse. Plug-In relays for easy replacement. Relays with LED lights to indicate at a glance when the relay is on or off. Separate control loops that are interrelated in a process designed with coordinated and linked set points, to prevent adjustment of one controller setting from inadvertently impacting another one. Control system logic design to identify faulty sensor readings, to prevent faulty control action. In general, try to provide a control design that will be accepted, and will last.

22.11 OPERATIONS AND MAINTENANCE For the control design to stand the test of time (e.g. to be sustainable), it must be a good fit for the Owner.

22.12 EXPECTED LIFE OF CONTROL EQUIPMENT Be realistic about how long things will last. Nothing lasts forever. For example, a control project based on a 10year life will need to include cost of repairs to be realistic. Note for the table below that life spans shown vary by manufacturer and grade. This information is offered as a prompt for realistic life cycle cost estimating when controls are applied.

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Figure 22.13 User-Friendly Control System Checklist

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Figure 22.14 Typical Control Equipment Life Spans 22.13 BASIC ENERGY-SAVING CONTROL APPLICATIONS Common themes throughout the following list of applications: • Strive to satisfy most of the people most of the time, but not all the people all the time (80-20 Rule) • Try not to run any equipment continuously, or off-season • Avoid heating, cooling, and lighting areas that are unoccupied • “Just enough” air pressure, water pressure, etc. to satisfy the point of use • “Just enough” heating and cooling, as determined by the point of use • “Just enough” ventilation air for the people and to make up the exhaust needs

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22.14

Eliminate simultaneous heating and cooling wherever possible; minimize where unavoidable ADVANCED ENERGY-SAVING CONTROL APPLICATIONS

(See Figures 22.17 and 22.18.) 22.15 FACILITIES OPERATIONS CONTROL APPLICATIONS Automatic Controls, especially DDC controls, can be a very valuable tool for facilities personnel. Computerized maintenance management, early detection, remote servicing, automatic notification, trends and logs, and other features can be used to improve facility operational quality.

Figure 22.15 Basic Lighting Control Applications

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Figure 22.16 Basic HVAC Control Applications

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Figure 22.16 Basic HVAC Control Applications (Concluded)

Figure 22.17 Advanced Lighting Control Applications

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Figure 22.18 Advanced HVAC Control Applications (Continued)

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Figure 22.18 Advanced HVAC Control Applications (Continued)

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Figure 22.18 Advanced HVAC Control Applications (Concluded)

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Figure 22.19 Facilities Operations Control Applications

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22.16 CONTROL SYSTEM APPLICATION PITFALLS TO AVOID The following are some common pitfalls to avoid in applying Automatic Controls.

22.17 COSTS AND BENEFITS OF AUTOMATIC CONTROL Automatic Controls are unique in that they often provide both tangible and intangible costs and benefits. Tangible Benefits, like other energy-related projects, include energy savings and demand savings. Intangible benefits are those that are difficult to quantify or predict. Some of these only apply to Digital Control systems.

22.18 ESTIMATING SAVINGS FROM APPLIED AUTOMATIC CONTROL SYSTEMS 22.18.1 Introduction Economic barriers are among the greatest obstacle for the Energy Professional, and Automatic Controls are no exception. Acceptance of the cost of new technology almost always requires economic justification, and rightly so. Finding ways to predict and then demonstrate the savings is necessary should be the goal of any Automatic Controls project, since this will build momentum for subsequent projects. While it is often easy to visualize that savings will occur from Automatic Control improvements, estimating

them can be a very daunting and intimidating challenge. This presents a dilemma to the Energy Professional since cost justification is almost always an expectation. Projects that have merit but defy quantification may be overlooked. Done accurately, the cost saving calculations can be laborious and expensive, posing a barrier to otherwise viable projects. One approach is to produce reasonable estimates using abbreviated estimating methods or ‘rules of thumb’ where possible. As with all estimates, being conservative is a key to success so that project performance is seen to under-sell and over-deliver. Even when not a contract requirement to guarantee savings, there is always an expectation that the estimated costs and savings come to pass; further, the credibility of the energy professional is built largely on the accuracy of these estimates. Bearing in mind that there will always be uncertainties and uncontrolled variables at work, it is usually good practice to de-rate the calculated savings. By artificially reducing savings (de-rating) and artificially increasing projected costs (contingency allowance), two things happen. Effect of de-rating project estimated savings: • The odds of project performance exceeding expectations increases. • Projects with marginal Return on Investment (ROI) look worse and may be eliminated. The applied de-rate will depend on the level of uncertainty. A high degree of uncertainty suggests the need for a higher de-rate. A value between 20-30% is

Figure 22.20 Control System Pitfalls

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Figure 22.21 Control System Costs and Benefits suggested for most applications, although there are cases where no de-rate is needed. Examples: • Easy to Quantify. A lighting replacement project with 24-7 operation need not be de-rated at all since there are few, if any, uncertainties. This is easy to quantify, since only one parameter has changed (light fixture energy efficiency).

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Hard to Quantify. An Automatic Control project that includes multiple control system improvements implemented at the same time, such as variable pumping, free cooling modes, supply air reset, boiler lock-out, morning warmup, and new quarter-turn (no leak by) terminal unit control valves. This adds uncertainty for what savings comes from individual measures.

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From a pure simplicity standpoint, a project consisting of several control improvements could be implemented one at a time, with six months of post-project Measurement and Verification (M&V), therefore changing only one thing at a time. This would have the clear advantage of knowing what savings occurred from what measure, but would probably not be done in practice due to the protracted length of time for the entire project to be implemented, as well as lost savings from delayed implementation. 22.18.2 Replacement Costs A common practice for existing facilities is to propose equipment replacement using energy efficiency as justification. In general, it is easy to justify the differential cost of upgrades to higher efficiency equipment, but often impossible to justify the entire replacement project on energy savings alone. Burdening the project cost with unrelated expenses, such as equipment replacement that was due anyway, makes the payback look worse and creates an unfair perception of long paybacks. Whenever possible, energy improvement expenses should be fairly separated from normal replacement project costs. Equipment that is near the end of its useful life should be a planned replacement expense, regardless of the desire to reduce energy costs. If replaced early, the remaining value of the equipment may be appropriately ‘charged’ to the energy project, but not the entire project cost since this would need to be done anyway. 22.18.3 Barriers to quantifying savings from controls changes • Control parameters are almost always useradjustable and will usually be fine-tuned during the life of the project, including the post-project measurement period. • Control algorithms often include multiple variables which do not act independently. Consequently the effects on energy consumption often defy isolating and quantifying separately. An uncertainty is whether one measure will interact with another. In many cases, the aggregate savings may be less than the sum of the parts, in which case the savings would be over-stated if calculated independently. • Control system improvements that improve quality, comfort, ventilation, or other features from some deficient state may actually increase energy use in some ways, eroding the overall savings of the measure itself.

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22.18.4 Methodology Establish realistic baselines. Identify variables and their interactions. Identify competing or complementing processes that will subtract from measure savings. Reduce the number variables to simplify analysis. Treat uncertainties with contingencies, by either inflating the baseline or de-rating the savings. With the baseline established, use experience to evaluate calculated savings as percent of total expenses. Use all these indicators as sanity checks to avoid over-stating savings. After project completion, get after-the-fact measurements where possible to compare actual to estimated savings; collecting this real data will allow improved estimating and reduced contingencies over time. 22.18.5 Quantified Savings Examples. The following are some examples of how to generally quantify savings from Automatic Controls measures. Many of the methods use rules of thumb, and assumptions to simplify the work. More accurate results can be had by using a rigorous computer model, but since time is money the luxury of detailed models is not always available. Without an excessive investment in time, the methods shown below will yield results close enough to identify probable savings and to tell if the measure is worthwhile or not. While this is by no means a complete listing, it is hoped to convey the general method of abbreviated energy accounting for multi-faceted processes when improvements are proposed. Some of the examples show straight forward benefits, and others show benefits with parasitic losses or competing processes. The first example below is Condenser Water Reset, and is discussed in detail. Other abbreviated solutions are provided in the table that follows. 22.18.6 Detailed Example: Condenser Water Reset. Note: The cooling tower term “approach” is the difference between leaving condenser water temperature and ambient wet bulb temperature. The variables: The chiller kW/ton varies according to load, and the cooling tower kW/ton varies according to wet bulb temperature and approach. The cooling tower fan energy varies according to chiller ton hours, tower capacity, and condenser temperature set point with respect to ambient wet bulb. Overall savings varies with annual ton-hours, chiller efficiency, the ratio of chiller-to-tower efficiency (kW/ton), chiller low limit in accepting colder condenser water, and coincident wet bulb temperatures. The wet bulb variable means that any rules of thumb developed for annual savings would be area/climate specific.

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Although the chiller energy is reduced directly as the condenser temperature is lowered (1-1.5% per degree), the cooling tower efficiency decreases at lower approach temperatures, and eventually a point is reached where the savings in chiller energy are met by the added cooling tower horsepower. This break-even point varies with the cooling tower sizing, and towers with high hp/ton (small box, big fan) will hit the wall sooner than more generously sized cooling towers. The cooling tower energy penalty varies depending upon the approach temperature and rises sharply for each degree below 7 degrees F approach. Some common values of the energy penalty, in percent increase per degree lowered, are as follows: 12 degF Approach 7.3% 11 degF Approach 7.8% 10 degF Approach 8.3% 9 degF Approach 8.9% 8 degF Approach 9.7% 7 degF Approach 10.6% 8.9% Average cooling tower fan energy penalty per degree lowered. The chillers place a physical limit on this control process; some can take colder condenser water than others. Centrifugal chillers can accept from 55 to 70 degrees F entering condenser water, depending upon the manufacturer. Screw chillers are generally limited to 70 degF entering condenser water. Many reciprocating chillers are limited to 70 degrees F, but some can operate at lower temperatures. IMPORTANT: For each application, the limits of the machinery need to be identified and the control system must stay within those limits to assure no damage or detriment is done to the chillers. Refer to the table below. For a chiller with 0.5kW/ ton efficiency, paired with a 0.07 kW/ton cooling tower, a proposed 5 degree reduction (from 12 to 7 degrees F approach), would yield worse energy consumption than leaving it at 12 degrees F, due to the high cooling tower fan energy penalty. This same example, with all things equal except a 0.04 kW/ton cooling tower, would save 0.35% per degree lower overall cooling energy. This example shows that during operation at or near design wet bulb conditions, most or all of the theoretical chiller savings from condenser water reset will usually be negated by the added cooling tower energy use, unless the cooling tower is very efficient (0.04 kW/ton or less). While the energy savings near design conditions may be marginal, most of the chiller hours will be at wet bulb conditions that are more favorable, and this is where the energy savings are attained. The control strategy capitalizes on this by continuously adjusting

the operating set point based on ambient wet bulb. For those chiller operating hours when the wet bulb is significantly lower than design and the cooling tower can easily produce colder water with little tower energy penalty, the savings will be much more pronounced and closer to the theoretical 1-1.5% per degree. Of course, the chiller load during these shoulder seasons or overnight periods are usually lower than maximum, so knowing the chiller load profile and coincident wet bulb is key to quantifying savings. Chillers that can accept very cold condenser water and have cooling needs coincident with reduced wet bulb temperatures such as in the Southwestern US, when it is easy to achieve colder condenser water temperatures, can achieve 10-15% annual overall cooling energy savings using condenser water reset, compared to a fixed temperature set point of 70 degrees F. The following diagram illustrates the pronounced effect the system cooling tower has upon the overall cooling savings of the condenser water reset control routine. Remember, without the cooling tower fan energy expense, the savings from the chiller would be 1-1.5% per degree lowered. The following diagram shows how the relative hp rating of the cooling tower (kW/ton) affects the optimal cooling tower leaving water temperature set point. The “approach” value is a parameter of the optimized condenser temperature calculation, and should be selected based on the cooling tower in use for best economy. The “approach” value is a parameter of the optimized condenser temperature calculation, and should be selected based on the cooling tower in use for best economy. Suggested values of cooling tower approach for best overall cooling efficiency (kW/ton) are shown below. By using the “Ratio” instead of specific combinations,

Figure 22.22 Cooling Tower Effect on Condenser Water Reset Savings

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Figure 22.23 Cooling Tower Effect on Optimum Condenser Water Temperature this information can be applied to any combination of chiller and cooling tower. This is the value inserted in the sequence “…optimum cooling tower set point shall be equal to the calculated wet bulb temperature plus approach…,” and provides further evidence of the importance of amply sized, low HP cooling towers.

EXAMPLES OF QUANTIFYING SAVINGS FROM AUTOMATIC CONTROL MEASURES (See Figure 22.24.)

22.19

CONCLUSION AND FURTHER STUDY

Automatic controls are useful for basic regulation, and quality control of processes and environments. They can also be leveraged for energy savings through optimization. Properly applied, these systems are reliable and cost effective. Let us now return to the Chapter Intent, so see if the objectives were met. The stated purpose of this chapter was to focus on the application of Automatic Controls as a tool to achieve energy savings. The reader should review the titles of each section, reflect on the key topics they have taken away, and decide if the stated objective was met. If you have gained insight into how automatic

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controls can help you achieve your energy goals, have increased your comfort level with the subject matter, know important questions to ask the vendors, and are eager to put these systems to work for you, then this chapter has been worthwhile. If you do not feel the objective was met for you, consider re-reading the material, seeking out supplemental material, or contacting the author for further discussion. Very often a second text on the same subject will amplify the effect of the first text, by reinforcing concepts with different examples and descriptions. This chapter was necessarily made brief, and does not pretend to be a complete treatment of the subject. The following advanced topics were not addressed, and are listed for the interested reader to pursue through additional study. • • • • • • • • • • • • • • • • • •

Addressable I/O devices, network communications, and equipment interfacing technologies. Boolean Logic. Cascade Control. Computerized Maintenance Management Systems (CMMS). Control Loop Interaction. Ergonomic Considerations. Trends, logs, reports, alarms, graphics. Failure Modes, Mitigation, and Fault Tolerance. Feed Forward Control. Fuzzy Logic. IT Security. Ladder Logic. Loop Tuning. Step changes, dead time, stability, response time. Measurement and Verification. Open Protocols, XML, Gateways, and Translators for DDC networking. SAMA logic diagrams, multi-element industrial control methods. SCADA systems. Self-Powered Controls. Wireless Controls.

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Figure 22.24 Quantifying Control System Savings

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Figure 22.24 Quantifying Control System Savings (Continued)

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Figure 22.24 Quantifying Control System Savings (Continued)

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Figure 22.24 Quantifying Control System Savings (Continued)

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Figure 22.24 Quantifying Control System Savings (Continued)

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Figure 22.24 Quantifying Control System Savings (Continued)

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Figure 22.24 Quantifying Control System Savings (Continued)

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Figure 22.24 Quantifying Control System Savings (Continued)

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Figure 22.24 Quantifying Control System Savings (Continued)

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Figure 22.24 Quantifying Control System Savings (Concluded)

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22.20

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GLOSSARY OF TERMS

Accuracy: A performance measurement of an instrument to produce a value equal to the actual value. Regarding instrumentation, a general statement is that accuracy can be adjusted, but repeatability is a function of the instrument. Addressable Devices: Also called smart devices. A term used to describe equipment that can be given a unique identifying address and controlled directly by a digital control system, often in reference to commodity-type equipment that exists in quantity in a facility. By having unique addresses, multiple devices can share a common communication bus and reduce the volume of wiring. Analog: Variable (input or output), contrasting to discrete. Bi-Metal: A basic temperature transducer formed by joining two metals with different thermal expansion properties. Common shapes are coiled ribbons (that turn upon a temperature change), bars (that bend upon a temperature change), and disks (that warp and ‘snap’ upon a temperature change). Movement is predictable and repeatable, and is integral to many temperature control instruments. Binary: Synonymous with on-off or discrete (input or output), contrasting to analog. Boolean Logic: A logical technique used to formulate precise queries using true-false connectors or ‘operators’ between concepts. The primary operators are AND, OR, and NOT. Words or concepts joined with these operators, and parentheses are used to organize the sequence groups of concepts. The truefalse nature of Boolean Logic makes it compatible with binary logic used in digital computers, since a TRUE or FALSE result can be easily represented by a 0 or 1. Named after George Boole. Building Automation System (BAS): BAS is the term given to a computerized automatic control system when the primary focus: “…is on automating as much as possible to save labor.” [7: pp 38.10]. Building Automation System (BAS) is currently the most common term used to describe computerized control in buildings that provide one or more of the functions: Energy Management System (EMS) Facility Management System (FMS) Energy Monitoring and Control (EMCS) Cascade Control: Also called Master-Sub Master. This is a combination of two controllers in series with a related measured variable. The output of the first controller becomes an input to the second controller which can

then amplify it. Often, the output of the first (master) becomes the set point of the second controller (submaster). Useful in improving modulating control of systems with very slow process response. Cavitation: A problem phenomenon with fluid flow, often with control valves or pumps, where the local pressure drop is sufficiently high to cause temporary boiling of the fluid. When the pressure is sufficiently regained, the vapor bubbles created by boiling collapse and create a shock. If this occurs within the vicinity of fluid handling apparatus it can damage the equipment. Closed Loop: A control system which includes related process feedback input(s) and controlled device output(s), collectively forming a regulating process. The defining characteristic is the feedback input point that senses changes in the process and the effect of the controlled device, to close the loop of communication. Control Loop: The general term for a collection of control system components used to regulate a process that includes as a minimum a Controller, Set Point, Control Element (Controlled Device), Associated Process, Process Measurement (Measured Variable). Controlled Device: The manipulated device responding to the controller output, that then impacts the process itself. The item being manipulated by the controller. Controller: A device that compares set point to measured values, and determines an appropriate output response. Cut In: A parameter of two-position control. The cut-in value is where the controlled variable is sufficiently beyond the set point for the controlled equipment to be turned on (cut-in). Cut Out: A parameter of two-position control. The cut-out value is where the controlled variable is sufficiently beyond the set point for the controlled equipment to be turned off (cut-out). Dead Band: Also called zero energy dead band. Refers to a deliberate gap in control span between sequenced, usually conflicting, processes, to avoid control overlap and subsequent operational or energy consumption issues. Example: A single temperature controller that sequences both heating and cooling equipment to a common duct or space may use a Dead Band to prevent simultaneous heating and cooling. Dead Time: The time between a change in the process input and when that change is felt in the downstream process measurement. Often a function of the time it

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takes material to flow from one point to another. De-Bouncing: A type of discrete input signal conditioning used for digital control systems. Mechanical snapacting contacts actually open and close many times and can trigger control output problems when monitored by a high speed digital circuit. The debouncing signal conditioning has, as its purpose, to filter out the bouncing ‘noise’ so the controller sees a simple open-or-closed state. Demand Limiting: A control strategy with the purpose of reducing electrical demand, not necessarily energy. This is applied to facilities with utility demand charges, and usually is designed to reduce peak (max) demand thereby reducing utility demand charges. Derivative Control Mode: Also called rate or anticipatory control, and is used to increase response time after a disturbance or step change. For a given rate of change of error, there is a unique value of controller output. This control mode reacts to the rate of change of error, not the magnitude of error. This mode cannot be used alone since there is no output when the error is zero. Direct Acting: Control Action that increases its output as the measured variable increases above set point. Discrete: Synonymous with on-off or binary (input or output). Characterized by having two possible states. Typical example is an open-close contact input, or relay output. Dry Contact: A discrete signal, output or input, that is made with a contact closure such as a mechanical relay or switch, that has no voltage at the terminals and depends upon voltage from the initiating circuit to read its two-state resistance. Contrasting, when the device has a voltage at the terminals (as if to light a light bulb when the contacts close) it is termed the wetting voltage. Duty Cycling: A demand-limiting strategy where multiple electric points of use, often motors, which otherwise run continuously, are controlled to run some fraction of time, e.g. 40 minutes on and 20 minutes off. By coordinating the run and off times of multiple items, the aggregate utility electric demand can be reduced, to generate demand savings. Energy Monitoring and Control System (EMCS): See Building Automation System Energy Management System (EMS): EMS is the term given to a computerized automatic control system when the primary focus: “…is on saving energy by specific automatic control programs.“ [7: pp 38.10,11]. See also Building Automation System. Facility Management System (FMS): FMS is the term given to a computerized automatic control system

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when the primary focus: “…goes beyond HVAC controls and/or beyond a single building, such as including fire, security, or manufacturing systems.” [7: pp 38.11]. See also See Building Automation System. Feedback: The measurement of the process output that is returned to the process controller that is also influenced by the controlled device. Feedback is the differentiating factor for a closed-loop control system, contrasted to an open-loop control system. Floating Control Mode: A form of discrete (on-off) control with a null position whereby the controller holds the last output when set point is achieved, rather than returning to zero output. Gain: A tuning constant that multiplies an input or output parameter, usually to increase sensitivity and improve control. GUI: Graphical User Interface. The software that overlays the machine coding, adding the user-friendliness look and feel to a digital control system work station. Hunting: Chronic, repeating oscillation (overshoot and undershoot) of a modulating control system, usually indicating a poorly tuned control loop. Hysteresis: A physical phenomenon best explained as inertia or a body’s tendency to stay at rest. In control systems this can affect input and output instruments, and controlled devices (valves and dampers). The hysteresis effect will require a different value of control to cause a change or movement, depending upon whether approaching the value from higher or lower values. Generally, hysteresis is an issue for heavier controlled devices or with minute I/O changes. Indicating Transmitter: A transmitter with an auxiliary display or meter to provide local indication of the measurement and/or output signal. Input/Output Points (I/O): The general term for the identifiable instruments (points) used to relay the control system information into (input points) and out from (output points) the controller, linking the controller to the actual process. Integral Control Mode: Also called reset control, and is used to return the process to zero error by producing an output any time the error is other than zero. Significant is that the output increases over time and is useful to return the process to a zero error state. Interlock: A control strategy that requires one process (discrete or analog) to depend upon the on-off state of a separate but related process. Examples: — A boiler firing interlocked with combustion air

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damper requires the damper to be proven open prior to firing. This interlock would be for safety and is normally “hard-wired,” so as not to depend upon any software intervention. — A cooling coil control routine interlocked with supply fan operation requires the supply fan to be proven running prior to engaging in control of the cooling coil. This interlock would be for normal control since the feedback measurement is downstream of the cooling coil and would not be sensed without air flow, and is usually a software interlock. Ladder Diagram: Also called an elementary wiring diagram. This is an electrical circuit representation where the high and low voltage terminals (120VAC, 24VAC, 24VDC, etc) are shown as vertical lines on opposite sides of the page. Each circuit sharing this power source, with its control contacts and load, becomes a “rung” on the ladder. M&V: Measurement and Verification Master-Sub Master Control: See “Cascade Control” Measured Variable: The measurement representative of the process that is the basis for controller action, relative to set point. Measurement and Verification (M&V): The after-thefact activities that are used to verify whether and to what extent energy savings have occurred, to gage the actual energy savings and cost savings benefit of a project. Often, these are compared to estimated savings. In some cases, M&V is part of a contract stipulation for guaranteed savings and may form the basis of payment from one party to another. Depth and rigor of these activities varies depending upon need for accuracy and available funds. Minimum Position: An adjustment parameter of controlled devices, referring to the lowest level of control action allowed, regardless of further reduction in controller signal. Examples: Minimum fan speed Minimum damper position Modulating: See also “Analog.” Varying position in response to need, contrasting to two-position. Most-open Valve: A control algorithm that senses damper or valve positions at the various points of use to determine demand. This strategy serves the most demanding area, but strives to provide just enough process media to satisfy it, thereby reducing overall system energy use. Similar control routine applies to “most open damper.” Open Loop Control: The controlled system has no impact on the measured variable. No amount of

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change in the controlled variable or in the output of the controller will cause a change in the measured variable. Optimization: Actively monitoring and controlling each of the pertinent parameters of a process to maximize productivity and/or to minimize energy use. Often requires control of multiple dynamic variables. Optimization can apply to single equipment items or large systems. Oscillation: Repeated over and over-shooting about the desired set point. For two-position control, this is normal. For modulating control, this is abnormal. See “Hunting.” Overshoot: A measure of control system response to changing loads. After a corrective action is taken, and before settling out at the new level, the controlled variable is usually driven beyond the set point as it tries to recover. The extent to which it temporarily goes beyond the mark is the overshoot. Point - Controls context: Usually used with Digital Control systems, each unique identifiable input or output item. The number of system points represents the size of the system, e.g. the number of connected instruments that can be individually controlled. Most commonly used in reference to hardware items, but also applies to software points. Proportional Band: The range of error (+/-) that will cause the proportional controller output to vary between 0-100%. As the proportional gain increases, the proportional band decreases. Proportional Control Mode: Produces a linear proportional output that is a direct response to the measured error, configured to counteract the error and provide basic regulation. A residual offset error is characteristic of this control mode, e.g. a true zero-error state can never be achieved using proportional-only control. Proportional Offset: The amount of residual error remaining in the process using proportional-only control. Pulse Width Modulation: An output signal conditioning strategy that converts a modulating 0-100% output to a percentage of on time output, to impose the proportional control onto a discrete device. Often used in the control of electric resistance heating or incremental control electric motor actuators. Real Time: (general context): A computer system that responds to inputs without delay. (Computer science context):Acomputer system that updates information at the same rate it receives information. Relay: A discrete output interface device, used to control a large current (via heavy contacts) with

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a small current (the relay coil current) and/or to isolate controller low voltage power (DC) from the controlled equipment. Relay Logic: The term given to discrete logical control (if-then, and, or) accomplished by arranging relay contact in series and/or parallel electrical circuits. Repeatability: A performance parameter that measures the ability of a process or instrument to produce the same value of output during repeated trials. Instrument repeatability is synonymous with instrument precision. Reset or Reset Schedule: A control algorithm whereby one set point is varied, usually linearly, between two values, as a function of another analog value. Example: Resetting hot water temperature set point (HW) from outside air temperature (OA): Reset Schedule OA HW 70 120 30 180 Resolution: The minimum measurable value of an input variable or the minimum incremental change of the output variable. In digital control systems, this is often a measurement criterion of the A/D or D/A transformation, e.g. the number of steps provided and how closely it emulates true analog control. Reverse Acting: Control Action that decreases its output as the measured variable increases above set point. RTD: Resistance Temperature Detector: A transducer that leverages the physical properties of certain materials that predictably change resistance as a function of temperature. RTD response is characterized as being nearly linear and stable over time. SCADA: Supervisory Control and Data Acquisition. These are industrial control systems with very large point counts, lots going on, often widespread and remote, and often critical in nature. Thousands of point systems are common. Example: Utility energy and water metering and control. SCR: Silicon Controlled Rectifier. A device used to proportionally control an electric load, often a resistance heater or motor. The rectifier is an electronic switch so is technically an on-off device. However, SCR’s are normally controlled at very high speeds in time-proportioning fashion to create a modulating effect. Sensor: The general name for a device whose purpose is to sense some media and translate the measurement into a convenient and predictable form, often electrical, pneumatic. Set Point: The desired steady state of a controlled process. The goal of the control activity.

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Settling Time: “…the time required to for the processcontrol loop to bring the dynamic variable back to within the allowable range,…” [3: pp 10] Short Cycling: A dysfunction of some two-position control applications where the cut-in and cut-out settings are too narrow or the process rate is to fast, with the result being in rapid cycling of equipment, often to the detriment of the equipment. Soft Start: Any of several methods or reducing start-up demand upon a motor, usually by reduced voltage or mechanically unloading the driven load. Step Change: Also known as a disturbance or bump, this describes a sudden and significant event process output change. In the context of control loop tuning, a step change is a valuable testing function that will demonstrate the ability of the tuned components to react properly to sudden process changes without undue loss of control, excess drift from set point, hunting, or other control anomalies. System Capacitance: A general term that describes the relative strength or capacity of the controlled equipment to effect a change to the process measured variable, and a good indicator of system controllability and control mode choice. In lay terms, a low system capacitance acts like the equipment is over-sized with the tendency to short-cycle as a result. In technical terms this is measured by the pct process change resulting from a step change in output. Systems with high capacitance can usually be controlled with any control mode. Systems with low capacitance are often troublesome. Systems with low capacitance may experience short-cycling and instability using on-off control unless excessively wide range is used. Modulated systems with low system capacitance may require careful tuning and complex proportional control (PI, PID) to maintain stable control. Thermistor: A semi-conductor device used to measure temperature. Lightweight and inexpensive, thermistors are popular for low cost or non-critical applications such as residential or light commercial temperature control, where minor errors and long term drift are acceptable. Thermistor outputs are not linear with respect to changes in temperature, and usually require some form of signal conditioning to avoid errors. Thermocouple: A basic transducer for temperature measurement that uses the physical principal of galvanic action between dissimilar materials. The galvanic response is a function of temperature and so, with proper signal conditioning, can be used to measure temperature.

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Throttling Range: “…the amount of change in the controlled variable that causes the controlled device to move from one extreme to the other, from fullopen to full-closed.” [2: pp 1:21] Transducer: A device that performs the initial input or output conversion of a dynamic variable into proportional electrical or pneumatic information, often a very low level signal requiring further signal conditioning. Examples include: Thermocouple, thermistor, RTD, variable capacitance dP cell, strain gage vibration transducer, flow element (orifice plate, etc) Transmitter: The general name for an input device that provides signal conditioning from a transducer or other basic measurement signal, transforming it into some proportional information in a useful form, often with the ability to send the information over long distance without loss of accuracy (transmit). Tuning: Adjustment of gains and various parameters of a dynamic control system to achieve acceptable and stable control. Two-position Control Mode: Also called On-Off control, this is the most elementary control mode. Output is either 100% if sufficiently below set point, or 0% if sufficiently above set point. Over and undershoot is normal for this control mode. The least costly of

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all control methods. Regarding two position control: “Generally, the two-position control mode is best adapted to large scale systems with relatively slow process rates.” [3: pp 290]. Wax Motor: A self-powered actuator whose motive force is thermal expansion of a wax pellet/bellows assembly. The expansion is translated into a linear movement to vary the position of another device. Common uses include small thermally compensated devices such as shower mixing valves, and thermally compensated air diffusers. Sources 1. 2. 3. 4. 5. 6.

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Optimization of Unit Operations, Bela Liptak, pub. Chilton Book Company, 1987. “Fundamentals of HVAC Control Systems,” Steven Taylor, PE, ASHRAE, Atlanta Georgia, 2004. Process Control Instrumentation Technology, second ed, Curtis D. Johnson, pub. John Wiley & Sons, 1982. “Hierarchy of HVAC Design Needs,” David Schwaller, PE, ASHRAE Journal August 2003. “Productivity Benefits Due to Improved Indoor Air Quality,” NEMI, National Energy Management Institute, August 1995. “Quantifying The Energy Benefits Of HVAC Maintenance Training and Preventive Maintenance,“ AEE, Energy Engineering; Vol. 96; Issue 2; 1999. “Computer Applications,” 1999 ASHRAE Applications Handbook, ASHRAE, Atlanta Georgia, 1999.

CHAPTER 23

ENERGY SECURITY AND RELIABILITY BRADLEY L. BRACHER, P.E., C.E.M. Great Plains Energy Consulting, Inc. Oklahoma City, OK

23.1 INTRODUCTION Reliable utility services are vital to all industrial, commercial and military installations. Loss of electricity, thermal fuels, water, environmental control, or communications systems can bring many operations to an immediate halt resulting in significant economic loss due to unscheduled downtime, loss of life, or threat to national security. These services are delivered by vast, complex networks with many components. A small number of damaged components is often sufficient to disable portions of these networks or halt operation of the entire system. These component failures can be caused by equipment failure, natural disaster, accidents, and sabotage. The need for security continues to grow in all areas. It has become increasingly apparent in recent years that law enforcement agencies cannot provide the needed resources and personnel to protect citizens, corporations, and private property. Theft and vandalism are ever present. Terrorism, shootings, and bombings continue at a level pace and increase in intensity. The transition from an industrial economy to an information economy is bound to be accompanied by political, social, and economic turmoil. Law enforcement does what it can to detect and prevent crime in advance but will of necessity be forever relegated to a primary role of investigating after the fact. Responsibility for security now, as it always has, falls upon individuals and private corporations to secure their own well-being. Many companies raised their awareness of energy security issues while preparing for anticipated problems associated with Year 2000 (Y2K) computer problems. Managers feared widespread utility outages initiated by computer malfunctions. Fortunately, business and industry took this threat seriously and acted in advance to prevent major problems. Not knowing the extent of problems that might occur on January 1, 2000, many facility managers critically examined the utility supply systems they rely on for the first time, installed back-up systems,

and developed contingency plans. With Y2K behind them without major incident, many managers have now directed their attention elsewhere. However, the reliability of utility systems is not a dead issue. Many analysts are watching the pending deregulation of the electric utility industry to see how that will affect system reliability. Some utilities have curtailed routine maintenance in anticipation of mandatory divestiture of assets. Work like tree trimming, system expansion, and replacement of aging equipment is deferred. This permits an increase of current profit and reduces future financial risk that could occur if regulators do not permit utilities to fully recover stranded system costs when they unbundle services. Wise managers are anticipating the risks now and preparing to take action to improve the energy security of their facilities. Only time will reveal the true extent of these threats. Energy security is the process of assessing the risk of loss from unscheduled utility outages and developing cost effective solutions to mitigate or minimize that risk. This chapter will explore the vulnerable network nature of utility systems and the events or threats that disrupt utility services. Methods will be presented to assess these threats and identify those most likely to result in serious problems. Actions to counter these threats will be introduced along with a methodology to evaluate the cost effectiveness of proposed actions. Finally, the links between energy security and energy management will be discussed. 23.1.1 Principles of Security General physical security involves four areas of concern: deterrence, delay, detection, and intervention. Deterrence is a way of making a potential target unattractive to those wishing to engage in mischief or mayhem. Properly implemented deterrence leads the would be attacker to believe their actions would not result in the desired outcome, require a level of effort not commensurate with the objective, or entail a high likelihood of capture. Examples of physical security include area lighting, physical barriers, visible intrusion detection systems, and the presence of guards. It is not cost effective to post guards at most utility installations like substations due to the large number of sites. Roving security patrols on an 621

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unpredictable schedule can be effective. Delay mechanisms increase the amount of time and effort required to accomplish an unauthorized entry and execute a criminal task. The increased effort requires additional planning and manpower on the part of the criminal and thus serves as a deterrent. Examples include fences, barbed wire, razor wire, secure doors and windows, locks, and channels that restrict the flow of people and vehicles. A delay mechanism must add enough time to the criminal’s task to permit security forces to arrive and intercept the intruder and is, therefore, most effective when combined with detection systems. Detection systems are intrusion alarms and video monitoring in both the visible and infrared spectrums. These systems alert security forces to the presence of intruders and allow them to respond in a manner that brings the intrusion to an end with a minimum of loss or damage. The time required to penetrate the facility, carry out the theft or assault, and exit the facility must be greater than the longest probable response time of security forces. The response time dictates the design and selection of delay mechanisms. Intervention is the final line of defense in physical security. It consists primarily of guards or security forces. Intruders must ultimately be confronted face-to-face if aggression is to be halted. Their physical presence serves as a deterrent. They can be permanently placed for critical facilities. They can be deployed on a full time basis to less critical facilities when intelligence information indicates a high threat environment. Roving patrols can be used for multiple facilities of a less critical nature. Security forces should be able to respond in mass to a detected intrusion to abort crimes in progress. All of these physical security fundamentals can be used to reduce the vulnerability of utility systems. Additional countermeasures specific to utility systems should be implemented. Actions such as improving component reliability, installing redundant systems, preparing for rapid recovery, and contingency planning are discussed at length later.

systems form networks. Any failed component in a network has the potential to disrupt or degrade the performance of the entire system. Some networks contain only a single path linking the site to the source of its utility supply. The loss of that single path results in total disruption at the site. Other networks have redundant paths. Alternate routes are available to serve the site at full or partial capacity should one of the routes be damaged. In a redundant system, loads normally carried by the damage portion of the system will be shifted to an operational part of the network. This places extra stress on the remaining portion of the system. Marginal components sometimes fail under this additional load, causing additional segments of the network to fail. Utility networks do not operate in isolation; they are linked to each other in a web of dependence. Each provides a vital service to the other. The impact of one failed utility network is felt in many other systems. The effects spread like ripples on a pond. More systems will fail if redundant or back-up systems are not in place. Often, the easiest way for a saboteur to disable a utility system is to damage another system on which it depends. Example. Figure 23.1 illustrates the mutual dependence utility systems share with each other at one facility. This facility generates some of its own electricity with natural gas engines, pumps a portion of its water from wells using electric pumps, utilizes steam absorption chillers, and produces compressed air from a mixture of electric and gas engine compressors. A disruption of natural gas will immediately halt the on-site generation of electricity and steam and curtail the production of compressed air since these systems depend directly on natural gas as their prime mover. Failure of one utility will cascade to other systems. The absorption chillers would also experience a forced outage since they are powered by steam which is experiencing a forced outage due to the lack of natural gas. All process equipment that requires any of these disrupted utilities will be idle until full utility service is restored.

23.1.2 Utility Systems As Interdependent Networks Modern industrial, institutional, and commercial facilities are dependent on many utility systems. The utility services supporting modern facilities include electricity, thermal fuels (natural gas, fuel oil, coal), water, steam, chilled water, compressed air, sanitary sewer, industrial waste, communication systems, and transportation systems. Some of these systems are restricted to the site. Others are a maze of distribution paths and processing stations connecting the site to distant generation or production facilities. The individual components of these

23.1.3 Threats to Utility Systems The individual components of a utility system can be damaged or disabled in many ways. The network itself may be wholly or partially disrupted depending on the criticality of the component or components damaged. The threats to network components can be segregated into four categories: equipment failure, natural disaster, accidents, and sabotage. Equipment failure is the normal loss of system components as they reach the end of their expected life. The reliability of most electrical and mechanical components

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Figure 23.1 Interdependence of utility networks.

follows a “bath-tub curve” illustrated in Figures 23.2 and 23.3. These curves begin with a high rate of failure early in the life cycle. This failure rate rapidly decreases until it reaches a minimum value that remains relatively stable throughout the normal operating period. The failure rate increases again once the component enters the wear-out phase. Natural disasters are the most common cause of widespread network failure. They include earthquake, hurricane, tornado, wind, lightning, fire, flood, ice, and animal damage. Utility companies are well versed in dealing with these situations and generally have the means to effect repairs rapidly. However, widespread damage can leave some customers without service for days resulting in substantial economic loss. Accidents are unintentional human actions such as traffic accidents, operator error, fires, and improper design or modification of the system. Operator error played a significant role in the failure of the Chernoble and Three Mile Island nuclear plants. It also contributed to both of the New York City blackouts. Once a failure sequence has begun, the system is in an abnormal state. Operators may lack the experience to know how the system will respond to a given corrective action or might fail to respond quickly enough to a dynamic and rapidly changing situation. Sabotage covers the realm of intentional human action. It includes the entire spectrum from a single disgruntled employee to acts of terrorism to military action. Terrorism has been a fact of life in many countries for a long time. Its use in the United States has increased great-

Figure 23.2 Typical “bath-tub curve” for electronic equipment showing failure rate per unit time.

Figure 23.3 Typical “bath-tub curve” for mechanical equipment showing failure rate per unit time.

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ly in recent years. Most terrorist organizations have social or political motivations that could lead them to target industrial or commercial operations. Military actions are beyond the scope of what most industrial or commercial facilities can handle. These types of threats are of interest only to the military itself.

23.2 RISK ANALYSIS METHODS Risk analysis is a necessary first step in the process of minimizing the losses associated with unscheduled utility outages. The purpose of risk analysis is to understand the system under study and establish a knowledge base from which resources can be optimally allocated to counter known threats. This understanding comes from a systematic evaluation that collects and organizes information about the failure modes of a utility system. Once these failure modes are understood decisions can be made that reduce the likelihood of a failure, facilitate operation under duress conditions, and facilitate rapid restoration to normal operating conditions. Two broad categories of risk analysis methods are available. The inductive methods make assumptions about the state of specific system components or some initiating event and then determine the impact on the entire system. They can be used to examine a system to any level of detail desired, but are generally only used to provide an overview. It is impractical and often unnecessary to examine every possible failure or combination of failures in a system. When the complexity or importance of a system merits more detailed analysis a deductive method is used. Deductive analysis makes an assumption about the condition of the entire system and then determines the state of specific components that lead to the assumed condition. Fault tree analysis is the most common and most useful deductive technique. The deductive method is preferred because it imposes a framework of order and objectivity in place of what is often a subjective and haphazard process. Probabilities can be incorporated into all of these methods to estimate the overall reliability of the system. Probabilistic techniques are best used when analyzing equipment failures but have also been used with some success in the evaluation of human error or accident. They are of less value when evaluating natural disasters and meaningless when applied to sabotage or other forms of organized hostility. The results would not only depend on the probability of a sabotage attempt occurring but also on the probability that all actions necessary to disable the system were successfully accomplished during the

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attack. This type of data is extremely difficult to obtain and is highly speculative. Therefore, the analysis is best conducted under the assumption that an adverse situation will definitely occur and proceed to determine what specific scenarios will result in system failure1. 23.2.1 Inductive Methods A number of analysis tools are available to examine the effects of single component failures of a system. Three common and well developed techniques are Failure Mode and Effect Analysis (FMEA), Failure Mode Effect and Criticality Analysis (FMECA) and Fault Hazard Analysis (FHA). These methods are very similar and build upon the previous technique by gradually increasing in scope. Most utilize failure probabilities of individual components to estimate the reliability of the entire system. Preprinted forms are generally used to help collect and organize the information. FMEA recognizes that components can fail in more than one way. All of the failure modes for each component are listed along with the probability of failure. These failure modes are then sorted into critical and non-critical failures. The non-critical failures are typically ignored in the name of economy. Any failure modes with unknown consequences should be considered critical. Figure 23.4 is a typical data sheet used in FMEA. Failure Mode Effect and Criticality Analysis (FMECA) is very similar to FMEA except that the criticality of the failure is analyzed in greater detail and assurances and controls are described for limiting the likelihood of such failures2. FMECA has four steps. The first identifies the faulted conditions. The second step explores the potential effects of the fault. Next, existing corrective actions or countermeasures are listed that minimize the risk of failure or mitigate the impact of a failure. Finally, the situation is evaluated to determine if adequate precautions have been made and if not to identify additional action items. This technique is of particular value when working with the system operators. It can lead to an excellent understanding of how a system is actually operated as opposed to how the designer intended for it to be operated. Figure 23.5 is a data sheet used with FMECA. Fault Hazard Analysis (FHA) is another permutation of Failure Mode and Effect Analysis (FMEA). Its value lies in an ability to detect faults that cross organizational boundaries. Figure 23.6 is a data collection form for use with FHA. It is the same data form used with FMEA with three addition columns. Faults in column five are traced up to an organizational boundary. Column six is added to list upstream components that could cause the fault in question. Factors that cause secondary failures are listed in column seven. These are things like operational

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conditions or environmental variables known to affect the component. A remarks column is generally included to summarize the situation. FHA is an excellent starting point if more detailed examination is anticipated since the data are collected in a format that is readily used in Fault Tree Analysis. These techniques concern themselves with the effects of single failures. Systems with single point failures tend to be highly vulnerable if special precautions are not taken and these methods will highlight those vital components. However, critical utility systems are normally designed to be redundant. The majority of forced outages in a redundant system will be caused by the simultaneous failure of multiple components. Techniques that only consider single point failures will significantly underestimate the vulnerability of a system. No matter how unlikely an event or combination of events may seem, experience has proven that improbable events do occur. The Double Failure Matrix (DFM) examines the effects of two simultaneous failures. A square grid is laid out with every failure mode of every component listed along the columns and also along the rows. The intersec-

tion of any two failure modes in the matrix represents a double failure in the system. The criticality of that double failure is listed at the intersection. Critical and catastrophic failures are explored further to identify corrective actions or alternative designs. The diagonal along the grid is the intersection of a component failure with itself. This is the set of single mode failures. It can be used as a first cut analysis and later expanded to encompass the entire set of two component failures if desired. This method becomes quite cumbersome or prohibitively difficult with large or complex systems. Event Tree Analysis is an exhaustive methodology that considers every possible combination of failed components. It is known as a tree because the pictorial illustration branches like a tree every time another component is included. The tree begins with a fully operational system that represents the trunk of the tree. The first component is added and the tree branches in two directions. One branch represents the normal operational state of the component and the other represents the failed state. The second component is considered next. A branch representing the operational and failed states is

Figure 23.4 Data collection sheet for Failure Mode and Effect Analysis (FMEA).

Figure 23.5 Data collection sheet for Failure Mode Effect and Criticality Analysis (FMECA).

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Figure 23.6 Data collection sheet for Failure Hazard Analysis (FHA). added to each of the existing branches, resulting in a total of four branches. Additional components are added in a like manner until the entire system has been included. The paths from the trunk to the tip of each branch are then evaluated to determine the state of the entire system for every combination of failed components. Complex systems can be in a state of total success, total failure, or some variant of partial success or failure. Example. Figure 23.7 is a simplified one-line diagram of an electric distribution system for a facility with critical loads. The main switch gear at the facility is a double-ended substation fed from two different commercial power sources. All critical loads are isolated on a single buss which can receive power from either commercial source or an on-site emergency generator. The facility engineer conducted a Failure Mode Effect and Criticality Analysis. His findings are listed in Figure 23.8. Three single point failures were identified that result in a forced outage of the critical loads if any one of these components fails: automatic transfer switch, main breaker at the critical load switch

gear, and the buss in the critical load switch gear. Action items were listed for all components to improve system reliability. Most of the breakers require on-site spares for maximum reliability, however, a number of these can be shared to minimize the expense. For example, the main breakers at switch gear “A” and “B” can share a spare since they are of the same size. The most important action items are those for the single point failures. FMECA identifies only single point failures and can significantly underestimate the risk of a forced outage since improbable events like double failures do occur. A Double Failure Matrix (DFM) was constructed in Figure 23.9 to identify the combinations of two failed components that would deprive the critical loads of electricity. Rules were defined to gauge the criticality of each double failure. Loss of any one of the three sources of electricity is a level 2 failure with marginal consequences. Loss of any two of the three sources is a level 3 failure with critical consequences and loss of all three sources is a level 4 failure with catastrophic consequences since all critical

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Figure 23.7 Simplified electric distribution system for example. loads are in an unscheduled forced outage. The upper portion of the matrix is left blank in this example since it is a mirror image of the lower portion. The highlighted diagonal is the intersection of a component with itself and represents the single point failures. The results of the FMECA are verified since the three components identified as single point failures are now shown to be level 4 failures along the diagonal. Since these components are single point failures their rows and columns are filled with 4’s denoting a catastrophic loss of power when they and any other component are simultaneously failed. Six additional level 4 failures appear on the chart that represent true double component failures. All of these involve the inability to transfer commercial power to the critical load buss and a simultaneous failure of the emergency generator or its support equipment. This could lead the facility manager to investigate alternate systems configurations that have more than one way of transferring commercial power to the critical loads. Additionally, the threats that can reasonably be expected to damage the components involved in level 4 failures should be carefully explored and countermeasures implemented to reduce the

likelihood of damage. The level 3 failures that occur along the diagonal also merit special attention. 23.2.2 Deductive Method Fault Tree Analysis is the most useful of the deductive methods and is preferred by the author above all the inductive methods. Benefits include an understanding of all system failure modes, identification of the most critical components in a complex network, and the ability to objectively compare alternate system configurations. Fault trees use a logic that is essentially the reverse of that used in event trees. In this method a particular failure condition is considered and a logic tree is constructed that identifies the various combinations and sequence of other failures that lead to the failure being considered. This method is frequently used as a qualitative evaluation method in order to assist the designer, planner or operator in deciding how a system may fail and what remedies may be used to overcome the cause of failure3. The fault tree is a graphical model of the various combinations of faults that will result in a predefined undesired condition. Examples of this undesired condi-

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Figure 23.8 Failure Mode Effect and Criticality Analysis (FMECA) for example.

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Figure 23.9 Double Failure Matrix (DFM) for electric distribution system in example. tion are: a) Total loss of electricity to surgical suite. b) Total loss of chilled water to computer facility. c) Steam boiler unable to generate steam. d) Loss of natural gas feedstock to fertilizer plant. e) Water supply to major metropolitan area curtailed to half of minimum requirement. f) Environmental conditioning of controlled experiment is interrupted for more than thirty minutes. The faults can be initiated by sabotage actions, software failures, component hardware failures, human errors, or other pertinent events. The relationship between these

events is depicted with logic gates. The most important event and logic symbols are shown in Figure 23.10. A basic event is an initiating fault that requires no further development or explanation. The basic event is normally associated with a specific component or subsystem failure. The undeveloped event is a failure that is not considered in further detail because it is not significant or sufficient information is not available. Logic gates are used to depict the relationship between two or more events and some higher level failure of the system. This higher level failure is known as the output of the gate. These higher level failures are combined using logic gates until they culminate in the top event of

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the tree, which is the previously defined undesired event. A simple fault tree is illustrated in Figure 23.11. The “OR” gate shows that the higher level failure will occur if at least one of the input events occurs. An “OR” gate could be used to model two circuit breakers in series on a radial underground feeder. If either circuit breaker is opened the circuit path will be broken and all loads served by that feeder will be deprived of electricity. The output event of an “AND” gate occurs only if all of the input events occur simultaneously. It would be used to model two redundant pumps in parallel. If one pump fails the other will continue to circulate fluid through the system and no higher order failure will occur. If both pumps fail at the same time for any reason the entire pumping subsystem fails. The logic of the fault tree is analyzed using boolean algebra to identify the minimal cut sets. A minimal cut set is a collection of system components which, when failed, cause the failure of the system. The system is not in a failed state if any one of the components in this set has not failed or is restored to operation. In fault tree terminology, a cut set is a combination of basic events that will result in the undesired top event of the tree. A computer is normally used to automate this tedious and error prone mathematical procedure. Cut sets are utilized because they directly correspond to the modes of system failure. In a simple case, the cut sets do not provide any insights that are not already quite obvious. In more complex systems, where the system failure modes are not so obvious, the minimal cut set computation provides the analyst with a thorough and systematic method to identify the combinations of component failures which culminate in the top event. Once an exhaustive list of cut sets is assembled, they can be analyzed to determine which components occur in failure modes with the highest frequency. These, along with the single point failures, are the most critical components of the entire system and merit special attention to keep them out of harm’s way.

23.3 COUNTERMEASURES Corrective actions, or countermeasures, are implemented to reduce the risk of an unscheduled outage. These measures should initially be focused on single component failures and those with the most catastrophic consequences when failed. The second priority are those components that occur in the largest number of cut sets. Countermeasures fall into three broad categories: protective measures, redundant systems, and rapid recovery.

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EVENT AND LOGIC SYMBOLS

Basic Event

Undeveloped Event

OR Gate

And Gate

Figure 23.10 Event and logic symbols loss of power to critical load

failure of UPS

circuit breaker manually opened

loss of power to UPS

loss of power to main buss

failure of main buss

loss of power to transfer switch

failure of transfer switch

failure of emergency generator

loss of commercial power

Figure 23.11 Sample fault tree for electric distribution system with uninterruptible power supply and emergency generator. Risk analysis contributes vital information to the countermeasure process by imparting an understanding of the system failure modes. By knowing how the system can fail and what components contribute the those failures, the facility manager can make informed decisions that allocate resources to those countermeasures that mitigate the most significant risks. Facilities and the utility systems that support them are complex. No single countermeasure is sufficient to mitigate all risk. A multi-faceted approach is required. Just as a three-legged stool will not stand on one leg, nei-

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ther will a facility be secure against disruption of utility support without a comprehensive approach. 23.3.1 Physical Security Protective countermeasures are actions taken before a crisis occurs to safeguard the components of a utility system against mechanical or electrical damage. Systems are normally constructed to withstand vandalism, severe weather, and other foreseeable events. Critical systems are normally designed with high reliability components. Physical barriers are the first protective action that should be considered. They establish a physical and psychological deterrent to unauthorized access. Their purpose is to define boundaries for both security and safety, detect entry, and delay and impede unauthorized entry. Fences are the most common barrier. They are used to secure the perimeter of a site. In high value sites, fencing should be supplemented with barbed wire or razor wire. Walls are another excellent barrier. They are routinely used to isolate electrical vaults and mechanical rooms within a building for safety reasons. Proper access control makes these areas more secure as well as safe. It should be remembered that physical barriers are not sufficient to deter a determined adversary intent on causing damage. When the situation warrants, physical barriers must be supplemented with surveillance systems and guards. Area lighting is used in combination with physical barriers to further deter intrusion and aid security personnel in the detection of unauthorized entry. Many components of utility systems are built in exposed locations that make them vulnerable to traffic accidents or tampering. Pipeline components such as valves and regulators can be buried in pits. Berms can protect many components like metering stations and regulators by sheltering them from vehicular traffic, deflecting blasts, and obscuring the line of sight necessary for firearm damage. Bollards offer excellent protection against delivery vehicles and lawn mowers. Creek and river crossing should be designed to withstand the full force of flooding. This includes any large debris that might be carried by the current. Site planning is an important aspect of energy security. Vital components should be located away from perimeter fences and shielded from view when possible. Dispersal of resources is another excellent strategy. When redundant system components like electrical transformers are co-located they can all be disabled by a single event. Hardening of components and the structures that house them is appropriate in some instances. Hardening makes a system tolerant to the blast, shock, and vibration caused by explosions or earthquakes.

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23.3.2 Component Reliability Reliability improvement of individual components can significantly reduce outages related to equipment failures. This is especially applicable to single point failures. Equipment brands and models known to have high a mean time between failure (MTBF) should be specified. Newly constructed systems should be thoroughly tested at load to insure they are beyond the known infant mortality period. An ongoing preventive maintenance program should be implemented for existing facilities to keep them in a state of high reliability. Such a program should include through inspection, adjusting, lubrication, and replacement of failed redundant components. Aging components should be replaced before they enter the wear out region. Standby systems, such as emergency electric generators, should be periodically tested at full load. These procedures require trained personnel, test equipment, and meticulous record keeping. 23.3.3 Redundant Systems Many actions can be taken to facilitate continued operation when a portion of the utility infrastructure is crippled or otherwise unavailable to the facility. The most important of these is redundancy. Critical facilities should be supported by multiple independent supply routes. Electrical feeders should follow different geographic routes and, ideally, come from different substations. Telephones lines can sometimes to routed to different switches. Backup generators and uninterruptible power supplies guard against disturbances and disruptions that occur off-site in the electric grid. Fuels subject to curtailment, such as natural gas, can be supplemented with alternate fuels such as fuel oil or propane-air mixing systems that can be stored on-site. Sites that burn coal should maintain a stockpile to guard against strikes or transportation uncertainties. Redundant systems should be sized with sufficient excess capacity to carry all critical loads and all support functions, such as lighting and environmental conditioning, that are required for continuous operation. 23.3.4 Rapid Recovery Once a crisis has developed, the overriding goal is to get the system operating in a normal state as rapidly as possible and resume full scale operations. Stockpiling critical or hard to get parts will reduce the recovery time more than any other action. These components should have been identified during the risk analysis. They must be stored separately from the components they are intended to replace to preclude the possibility of a single threat damaging both the primary component and the spare. Emergency response teams must be available to

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effect the repairs. If damage is expected to exceed the capabilities of in-house personnel, additional parts suppliers and alternate repair crews should be identified and contracts in place to facilitate their rapid deployment. Simulation of recovery actions is an excellent training tool to prepare crews for operation under adverse conditions. Realistic simulation also helps identify unexpected obstacles like limited communication capability, electronic locks that won’t open without electricity, and vehicles that can’t be refueled. Any number of things can and will go wrong once an emergency has been initiated. Operating with the lights off, both literally and figuratively, is a demanding task even for the prepared. Portable generators and lights are needed for twenty-four hour repair operations. Self contained battery-powered light carts should be available for use inside buildings. Clear lines of authority must be defined in advance. Crisis coordinators must be able to contact response teams even if the telephones don’t work. Crew members need to know where to report and to whom. These things must be thought out in advance and documented in contingency plans. 23.3.5 Contingency Planning Contingency planning is a vital follow-up to the countermeasure process. Plans give order to the chaos surrounding a catastrophic event. A manager’s thinking is not always clear in the fog of a crisis. Lines of communication break down. A plan provides the necessary framework of authority to implement restoration actions. The plan identifies the resources necessary to effect repairs and sets priorities to follow if the damage is extensive. Occasionally the planning process identifies critical components not previously identified or highlights bottlenecks such as communication systems that may become overloaded during the crisis. The goal of contingency planning is rapid recovery to a normal operating state. Risk analysis plays an important role in planning. It identifies those high-risk components or sub-systems that are most vulnerable or result in catastrophic situations when failed. Contingency plans must be developed to complement the implementation of countermeasures that reduce the likelihood of damage occurring. Risk analysis also identifies those components that only yield moderate consequences when damaged. These components are frequently not vital enough to merit the expense of constructing physical barriers or redundant systems. A solid contingency plan identifying sources of parts and labor to effect repairs may be the least cost option. The most important task performed in the plan is the designation of an emergency coordinator and delineation

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of authorities and responsibilities. A single coordinator is necessary to insure priorities are followed and to resolve conflicts that may develop. Each member of the response team should have a well defined role. Proper planning will insure no vital tasks “fall through the cracks” unnoticed. No plan can anticipate every contingency that may arise, but a well written plan provides a framework that can be adapted to any situation. An energy contingency plan should, as a minimum, contain the following items: • Definition of specific authorities and responsibilities • Priorities for plant functions and customers • Priorities for protection and restoration of resources • Curtailment actions • Recall of personnel (in-house, contract, and mutual aid) • Location of spares • Location and contacts for repair equipment • Equipment suppliers Each critical component identified during risk analysis should be addressed in detail. Contingency plans should be exercised on a regular basis. This familiarizes the staff with the specific roles they should assume during an emergency. Practicing these tasks allows them to become proficient and provides an opportunity to identify deficiencies in the plan. Exercising also creates an awareness that a crisis can occur. This gets personnel thinking about actions that reduce risk in existing and new systems. Exercises can range from a paper game or role playing to a full scale simulation that actually interrupts the power to portions of the facility. While full scale simulation is expensive in terms of both labor and productivity, many valuable lessons can be learned that would not otherwise be apparent until an actual disruption occurred. The most valuable product of repetitive gaming, for all of the people that truly participate, is the unfolding of a process of how to react to a real energy emergency, a process including a communications net, recall procedures, and information systems of all sorts. Repetitive gaming tends to fine-tune the contingency plan, exposing short comings, honing it down to an effective and working document. It is impossible to learn true energy emergency management in a totally calm, non-emergency atmosphere.4

23.4 ECONOMICS OF ENERGY SECURITY AND RELIABILITY The consequences of utility outages cover the spectrum from minor annoyances to catastrophic loss of life

ENERGY SECURITY AND RELIABILITY

or revenue. Financial losses can be grouped in several convenient categories. Loss of work in progress covers many things. A few examples include parts damaged during machining operations or by being stranded in cleaning vats, spoiled meats or produces in cold storage, interruption of time sensitive chemical process, and lost or corrupted data. Lost business opportunities are common in retail outlets that depend on computerized registers. Businesses that require continuous contact with customers such as reservation centers, data processing facilities, and communications infrastructure also experience lost business opportunities when utilities are disrupted. Many data processing and reservation centers estimate the cost of interruptions in the six figure range per hour of downtime. The cost of implementing countermeasures should be commensurate with the cost of an unscheduled outage. This requires a knowledge of the financial impact of an outage. If a probabilistic risk analysis technique was utilized, the frequency and duration of outages can be estimated using conventional reliability theory. Costs associated with recovery operations, damaged work in progress, and lost business opportunities are calculated for each type of outage under analysis. The expected annual loss can then be estimated for each scenario by multiplying the duration by the hourly cost and adding the cost of repairs and recovery operations. Countermeasure funding can be prioritized on the basis of expected financial loss, probability of occurrence, payback time, or other relevant measure. For non-probabilistic techniques, a more subjective approach must be utilized. The duration of most outages can be estimated based on known repair times. The accuracy of these estimates becomes questionable when widespread damage requires repair crews to service multiple sites or stocks of spare parts are exhausted. The absence of hard data on the frequency of such outages increases the subjective nature of the estimate. One technique is to simply assume that a crisis will occur and allocate resources to mitigate the risk on the basis of financial loss per occurrence or a cost/benefit ratio. Payback period and cost/benefit ratio are the most common economic analysis tools used to rank countermeasures competing for budget dollars. They can also be used to determine if a particular measure should be funded at all. Payback is calculated by dividing the cost to implement a countermeasure by the expected annual loss derived from a probabilistic risk analysis. The payback period can be evaluated using normal corporate policy. A payback of two years or less is usually sufficient to justify the expenditure. The cost/benefit ratio is calculated by dividing the cost to implement a

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countermeasure by the losses associated with a single forced outage. If the ratio is about one the expenditure will be paid back after a single incident. If the ratio is about one-half, the expenditure will be paid back after two incidents. Insurance should be considered to shift the risk of financial loss to another party. Business interruption policies are available to compensate firms for lost opportunities and help cover the cost of recovery operations. The cost of insurance policies should be treated as an alternate countermeasure and compared using payback or cost/benefit ratio.

23.5 LINKS TO ENERGY MANAGEMENT Many energy security projects can piggy-back on energy conservation projects at a nominal incremental cost. Purchased utility costs can be reduced while reliability is improved. This can dramatically alter the economics of implementing certain countermeasures. Fuel switching strategies let installations take advantage of interruptible natural gas tariffs or transportation contracts. Peak shaving with existing or proposed generators will reduce electric demand charges. Time-of-use rates and real-time pricing make self-generation very attractive during certain seasons or at particular times of the day. Many industrial facilities purchase utilities on interruptible supply contracts to reduce purchased utility costs. Curtailments are usually of short duration and are often contractually limited to a specified number of hours per year. Alternate fuel sources are normally installed prior to entering into an interruptible supply contract. An example would be to replace the natural gas supply to a steam plant with fuel oil or propane. This gives the facility the option of burning the least expensive fuel. Caution must be exercised when designing a dual-fuel system. Utility service is often curtailed at a time when it is most needed. Natural gas is typically curtailed during the coldest days of winter when demand is highest and supplies become limited due to freezing of wells. An extended curtailment could outlast the on-site supply of an alternate fuel. The same cold weather which caused the primary fuel to be curtailed may also result in shortages of the alternate fuel. An unscheduled plant shutdown could occur if the storage system is undersized or if proper alternate arrangement were not made in advance. Thermal energy storage systems are installed to reduce on-peak electric demand charges. They can also play a key role in facility reliability. Chillers are

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frequently considered non-critical loads and are not connected to emergency generators. When a disruption occurs, critical equipment that requires cooling must be shut-down until electricity is restored and the chilled water system is returned to operation. The time required to restart the chilled water system and critical equipment can last many hours longer than the electrical disruption that initiated the event. When a storage system is in place, only the chilled water circulating pumps need to be treated as critical loads powered by the generator. Chilled water can be continuously circulated from the storage system to the equipment, thus precluding the need for a shut-down in all but the longest of outages. When the chillers are removed from the emergency generator additional process equipment can be connected in its place and kept operating during outages or a smaller generator can be installed at a lower first cost. Energy conservation also has a direct impact on energy security. Conservation projects reduce the amount of energy required to perform at full capacity. By consuming less energy, an installation with a fixed quantity of alternate fuels stored on-site can remain in operation longer under adverse conditions. More efficient operations can also reduce the size of stand-by generators, uninterruptible power supplies, and similar systems. Smaller equipment usually means reduced construction costs and improved economics.

23.6 IMPACT OF UTILITY DEREGULATION Deregulation of the utility industry has the potential to impact energy security and reliability in a way the could greatly exceed the consequences of Year 2000 problems. Y2K problems such as forced outages of power plants or widespread blackouts failed to materialize even in countries that did little to prepare for the much anticipated century date rollover. This absence of Y2K problems has led many to conclude the threats never existed at all, which is not a correct perception. The potential for disruption did exist, it was just of unknown magnitude. Many energy managers will conclude that deregulation also carries with it no risk and will do nothing to prepare. The risk associated with utility deregulation is also of unknown magnitude but is of a different nature than Y2K. Deregulation is not a one-time event. It is a permanent structural change in an entire industry that will have long term effects which evolve over time. Some of the issues that can be predicted now include reduced reliability of transmission and distribution systems, reduced reliability of generation systems, higher potential

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for contract default, and market price risk. Many utilities have reduced scheduled maintenance of transmission and distribution systems and generation systems. This decision has two root causes. The first is the wave of downsizing that swept the industry during the 1990s. These attempts to reduce operating costs and improve the bottom line have resulted in extended maintenance cycles, fewer spare parts, and smaller crews responding to forced outages and natural disasters. While many of these companies are showing temporary profit increases, they are also reducing system reliability and extending mean time to repair. The long term consequences of these decisions are yet to be fully felt. A secondary motivation for deferred maintenance is the uncertainty associated with deregulation. Regulators will require utilities to unbundle the services offered. Integrated companies offering generation, transmission and distribution, billing, and other customer services will evolve into multiple, sometimes competing, companies in much the same way the telephone industry was broken up. Regulators may not permit full recovery of capital investments in infrastructure. The fear of not recovering these “stranded costs” has lead some utilities to reduce their investment in replacement or upgraded equipment. The consequences are the same: reduced reliability. While transmission and distribution is expected to remain a monopoly industry, many questions remain to be answered regarding system operation and reliability. Generation will become a competitive industry. Old, inefficient plants with high heat rates will not be able to compete on a cost basis in the new order but must continue to operate and fill the demand for electricity. New merchant plants and distributed generators with high efficiencies are being planned and constructed now. These, along with the old utility plants, will be unregulated plants competing for customers and operated for profit. Under the old, regulated structure, utilities had multiple generators that improved reliability. If one plant failed, the system had sufficient spinning reserve to immediately compensate. Many unregulated operators have only a single plant in the region with no spinning reserve to insure reliability. If a generation provider experiences a forced outage the customer may have no choice but to purchase power from a default provider or on the short term spot market at greatly increased costs. The only alternative would be an immediate curtailment of all operations. Recent system disruptions in the midwest and pacific northwest have seen spot market prices rise several orders of magnitude until failed plants were

ENERGY SECURITY AND RELIABILITY

returned to service. Experience with deregulated natural gas provides an indicator of future problems that might occur with electricity. Gas producers contract to provide gas. If the spot market price of gas increases before the completion of the contract term, then the producer’s profit is reduced. Unethical operators have defaulted on contract obligations by refusing to allocate the gas to the original contracted customer. They instead sell the gas on the spot market to the highest bidder. This forces the original customer to curtail load or obtain supplies on the spot market at current prices. The customer’s attempt to obtain stable commodity prices and minimize market risk through contractual instruments is nullified by the unethical acts of a supplier. Similar situations are bound to occur as the electric industry deregulates.

23.7 SUMMARY All facilities require a continuous and adequate supply of utility support to function. Energy security is the process of evaluating utility systems and implementing actions that minimize the impact of unscheduled outages that prevent a facility from operating at full capacity. Utility systems are networks with many components. Loss of a few, or in some cases one, critical components is sufficient to disable a network or leave it operating at partial capacity. Additionally, utility networks are not independent. They support each other in a symbiotic manner. The collapse of one network can lead to a domino effect that causes other networks to fail. The critical components of a utility network can be identified by using risk analysis techniques. The inductive methods make assumptions about the status of in-

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dividual components and then determine what impact is felt on the entire system. Deductive methods, notably fault tree analysis, use an opposite approach. Fault tree analysis assumes the system is in some undesired condition and proceeds to determine what combinations of failed components will result in that condition. The combinations of failed components are called cut sets. The component failures can be caused by equipment failure, natural disaster, accident, or sabotage. Countermeasures are actions that prevent or minimize the impact of utility disruptions. Three countermeasures that should not be neglected by any facility manager are physical protection, redundancy, and stockpiling of critical spare parts. Coupled with contingency planning, these counter measures will greatly enhance the energy security of any installation. Contingency plans should be exercised for maximum effectiveness. Utility disruptions can cause a wide range of impacts on the affected facility. In most cases, this impact can be expressed as a dollar value. This financial impact is useful in evaluating the economics of implementing countermeasures. The most common economic analysis tools are payback and cost/benefit ratio. Many countermeasures can be made more cost effective by linking them to energy conservation projects. References 1. 2. 3. 4.

Bracher, Bradley L., Utility Risk Analysis, Proceedings of the 8th World Energy Engineering Congress, 1989, p. 601. U.S. Nuclear Regulatory Commission, Fault Tree Handbook, p. II4. Billinton and Allan, Reliability Evaluation of Engineering Systems: Concepts and Techniques, p. 113. Broussard, Peter A., Energy Security for Industrial Facilities - Contingency Planning for Power Disruption, PennWell Publishing Company, 1994, pg. 111.

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CHAPTER 24

UTILITY DEREGULATION AND ENERGY SYSTEM OUTSOURCING GEORGE R. OWENS, P.E. C.E.M. Energy and Engineering Solutions, Inc.

24.0 INTRODUCTION “Utility Deregulation,” “Customer Choice,” “Unbundled Rates,” “Re-regulation,” “Universal Service Charge,” “Off Tariff Gas,” “Stranded Costs,” “Competitive Transition Charge (CTC),” “Caps and Floors,” “Load Profiles” and on and on are the new energy buzzwords. They are all the jargon are being used as customers, utilities and the new energy service suppliers become proficient in doing the business of utility deregulation. Add to that the California energy shortages and rolling blackouts, the Northeast and Midwest outages of 2003, scandal, rising energy prices, loss of price protection in deregulated states and you can see why utility deregulation is increasingly on the mind of utility customers throughout the United States and abroad. With individual state actions on deregulating natural gas in the late 80’s and then the passage of the Energy Policy Act (EPACT) of 1992, the process of deregulating the gas and electric industry was begun. Because of this historic change toward a competitive arena, the utilities, their customers, and the new energy service providers have begun to reexamine their relationships. How will utility customers, each with varying degrees of sophistication, choose their suppliers of these services? Who will supply them? What will it cost? How will it impact comfort, production, tenants and occupants? How will the successful new players bring forward the right product to the marketplace to stay profitable? And how will more and better energy purchases improve the bottom line? This chapter reviews the historic relationships between utilities, their customers, and the new energy service providers, and the tremendous possibilities for doing business in new and different ways. The following figure portrays how power is generated and how it is ultimately delivered to the end customer. 1. 2.

Generator – Undergoing deregulation Generator Substation – See 1

The Power Flow Diagram 3.

4. 5. 6.

Transmission System – Continues to be regulated by the Federal Energy Regulatory Commission (FERC) for interstate and by the individual states for in-state systems Distribution Substation – Continues to be regulated by individual states Distribution Lines – See 4 End Use Customer – As a result of deregulation, will be able to purchase power from a number of generators. Will still be served by the local “wires” distribution utility which is regulated by the state.

24.1 AN HISTORICAL PERSPECTIVE OF THE ELECTRIC POWER INDUSTRY At the turn of the century, vertically integrated electric utilities produced approximately two-fifths of the nation’s electricity. At the time, many businesses (nonutilities) generated their own electricity. When utilities began to install larger and more efficient generators and more transmission lines, the associated increase in convenience and economical service prompted many industrial consumers to shift to the utilities for their electricity needs. With the invention of the electric motor came the inevitable use of more and more home appliances. Consumption of electricity skyrocketed along with the utility share of the nation’s generation.

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The early structure of the electric utility industry was predicated on the concept that a central source of power supplied by efficient, low-cost utility generation, transmission, and distribution was a natural monopoly. In addition to its intrinsic design to protect consumers, regulation generally provided reliability and a fair rate of return to the utility. The result was traditional rate base regulation. For decades, utilities were able to meet increasing demand at decreasing prices. Economies of scale were achieved through capacity additions, technological advances, and declining costs, even during periods when the economy was suffering. Of course, the monopolistic environment in which they operated left them virtually unhindered by the worries that would have been created by competitors. This overall trend continued until the late 1960s, when the electric utility industry saw decreasing unit costs and rapid growth give way to increasing unit costs and slower growth. The passage of EPACT-1992 began the process of drastically changing the way that utilities, their customers, and the energy services sector deal (or do not deal) with each other. Regulated monopolies are out and customer choice is in. The future will require knowledge, flexibility, and maybe even size to parlay this changing environment into profit and cost saving opportunities. One of the provisions of EPACT-1992 mandates open access on the transmission system to “wholesale” customers. It also provides for open access to “exempt wholesale generators” to provide power in direct competition with the regulated utilities. This provision fostered bilateral contracts (those directly between a generator and a customer) in the wholesale power market. The regulated utilities then continue to transport the power over the transmission grid and ultimately, through the distribution grid, directly to the customer. What EPACT-1992 did not do was to allow for “retail” open access. Unless you are a wholesale customer, power can only be purchased from the regulated utility. However, EPACT-1992 made provisions for the states to investigate retail wheeling (“wheeling” and “open access” are other terms used to describe deregulation). Many states have held or are currently holding hearings. Several states either have or will soon have pilot programs for retail wheeling. The model being used is that the electric generation component (typically 60-70% of the total bill), will be deregulated and subject to full competition. The transmission and distribution systems will remain regulated and subject to FERC and state Public Service Commission (PSC) control. A new comprehensive energy bill, EPACT-2005, was signed into law in 2005, just as this edition was being

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finalized. Look for expanded discussion of EPACT-2005 in future editions of this chapter. This bill affects energy production, including renewables, energy conservation, regulations on the country’s transmission grids, utility deregulation as well as other energy sectors. Tax incentives to spur change are key facets of EPACT-2005. ELECTRIC INDUSTRY DEREGULATION TIME LINE

1992 - Passage of EPACT and the start of the debate. 1995 & 1996 - The first pilot projects and the start of special deals. Examples are: The automakers in Detroit, New Hampshire programs for direct purchase including industrial, commercial and residential, and large user pilots in Illinois and Massachusetts. 1997 - Continuation of more pilots in many states and almost every state has deregulation on the legislative and regulatory commission agenda. 1998 - Full deregulation in a few states for large users (i.e., California and Massachusetts). Many states have converged upon 1/1/98 as the start of their deregulation efforts with more pilots and the first 5% roll-in of users, such as Pennsylvania and New York. 2000 - Deregulation of electricity became common for most industrial and commercial users and began to penetrate the residential market in several states. These included Maryland, New Jersey, New York, and Pennsylvania among others. See figure 24.1. 2002/3- Customers have always had a “backstop” of regulated pricing. Now that the transition periods are nearing their end, customers are faced with the option of buying electricity on the open market without a regulated default price. 2003 - During the summer, parts of the northeast and upper Midwest experience a massive blackout that shuts down businesses and residential customers. The adequacy of the transmission system is blamed. 2005 - EPACT-2005 becomes law

24.2 THE TRANSMISSION SYSTEM AND THE FEDERAL ENERGY REGULATORY COMMISSION’S (FERC) ROLE IN PROMOTING COMPETITION IN WHOLESALE POWER Even before the passage of EPACT in 1992, FERC played a critical role in the competitive transformation of wholesale power generation in the electric power industry. Specific initiatives include notices of proposed

UTILITY DEREGULATION AND ENERGY SYSTEM OUTSOURCING

rulemaking that proposed steps toward the expansion of competitive wholesale electricity markets. FERC’s Order 888, which was issued in 1996, required public utilities that own, operate, or control transmission lines to file tariffs that were non-discriminatory at rates that are no higher than what the utility charges itself. These actions essentially opened up the national transmission grid to non-discretionary access on the wholesale level (public utilities, municipalities and rural cooperatives). This order did not give access to the transmission grid to retail customers. In an effort to ensure that the transmission grid is opened to competition on a non-discriminatory basis, Independent System Operators (ISO’s) are being formed in many regions of the country. An ISO is an independent operator of the transmission grid and is primarily responsible for reliability, maintenance (even if the day-to-day maintenance is performed by others) and security. In addition, ISO’s generally provide the following functions: congestion management, administering transmission and ancillary pricing, making transmission information publicly available, etc.

24.3 STRANDED COSTS Stranded costs are generally described as legitimate, prudent and verifiable costs incurred by a public utility or a transmitting utility to provide a service to a customer

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that subsequently are no longer used. Since the asset or capacity is generally paid for through rates, ceasing to use the service leaves the asset, and its cost, stranded. In the case of de-regulation, stranded costs are created when the utility service or asset is provided, in whole or in part, to a deregulated customer of another public utility or transmitting utility. Stranded costs emerge because new generating capacity can currently be built and operated at costs that are lower than many utilities’ embedded costs. Wholesale and retail customers have, therefore, an incentive to turn to lower cost producers. Such actions make it difficult for utilities to recover all their prudently incurred costs in generating facilities. Stranded costs can occur during the transition to a fully competitive wholesale power market as some wholesale customers leave a utility’s system to buy power from other sources. This may idle the utility’s existing generating plants, imperil its fuel contracts, and inhibit its capability to undertake planned system expansion leading to the creation of “stranded costs.” During the transition to a fully competitive wholesale power market, some utilities may incur stranded costs as customers switch to other suppliers. If power previously sold to a departing customer cannot be sold to an alternative buyer, or if other means of mitigating the stranded costs cannot be found, the options for recovering stranded costs are limited. The issue of stranded costs has become contentious in the state proceedings on electric deregulation. Utilities

Retail access is either currently available to all or some customers or will soon be available. Those states are Arizona, Connecticut, Delaware, District of Columbia, Illinois, Maine, Maryland, Massachusetts, Michigan, New Hampshire, New Jersey, New York, Ohio, Oregon, Pennsylvania, Rhode Island, Texas, and Virginia. In Oregon, no customers are currently participating in the State’s retail access program, but the law allows nonresidential customers access. Yellow colored states are not actively pursuing restructuring. Those states are Alabama, Alaska, Colorado, Florida, Georgia, Hawaii, Idaho, Indiana, Iowa, Kansas, Kentucky, Louisiana, Minnesota, Mississippi, Missouri, Nebraska, North Carolina, North Dakota, South Carolina, South Dakota, Tennessee, Utah, Vermont, Washington, West Virginia, Wisconsin, and Wyoming. In West Virginia, the Legislature and Governor have not approved the Public Service Commission’s restructuring plan, authorized by HB 4277. The Legislature has not passed a resolution resolving the tax issues of the PSC’s plan, and no activity has occurred since early in 2001. A green colored state signifies a delay in the restructuring process or the implementation of retail access. Those states are Arkansas, Montana, Nevada, New Mexico, and Oklahoma. California is the only blue colored state because direct retail access has been suspended. *As of January 30, 2003, Department of Energy, Energy Information Administration

Figure 24.1 Status of State Electric Industry Restructuring Activity*

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have argued vehemently that they are justified in recovering their stranded costs. Customer advocacy groups, on the other hand, have argued that the stranded costs proposed by the utilities are excessive. This is being worked out in the state utility commissions. Often, in exchange for recovering stranded costs, utilities are joining in settlement agreements that offer guaranteed rate reductions and opening up their territories to deregulation.

24.4 STATUS OF STATE ELECTRIC INDUSTRY RESTRUCTURING ACTIVITY Electric deregulation on the retail level is determined by state activity. Many states have or are in the process of enacting legislation and/or conducting proceedings. See Figure 24.1.

24.5 TRADING ENERGY MARKETERS AND BROKERS With the opening of retail electricity markets in several states, new suppliers of electricity have developed beyond the traditional vertically integrated electric utility. Energy marketers and brokers are the new companies that are being formed to fill this need. An energy marketer is one that buys electricity or gas commodity and transmission services from traditional utilities or other suppliers, then resells these products. An energy broker, like a real estate broker, arranges for sales but does not take title to the product. There are independent energy marketers and brokers as well as unregulated subsidiaries of the regulated utility. According to The Edison Electric Institute, the energy and energy services market was $360 billion in 1996 and was expected to grow to $425 billion in 2000. To help put these numbers in perspective, this market is over six times the telecommunications marketplace. As more states open for competition, the energy marketers and brokers are anticipating strong growth. Energy suppliers have been in a merger and consolidation mode for the past few years. This will probably continue at the same pace as the energy industry redefines itself even further. Guidance on how to choose the right supplier for your business or clients will be offered later on in this chapter The trading of electricity on the commodities market is a rather new phenomenon. It has been recognized that the marketers, brokers, utilities and end users need to have vehicles that are available for the managing of risk in the sometimes-volatile electricity

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market. The New York Mercantile Exchange (NYMEX) has instituted the trading of electricity along with its more traditional commodities. A standard model for an electricity futures contract has been established and is traded for delivery at several points around the country. As these contracts become more actively traded, their usefulness will increase as a means to mitigate risk. An example of a risk management play would be when a power supplier locks in a future price via a futures or options contract to protect its position at that point in time. Then if the prices rise dramatically, the supplier’s price will be protected.

24.6 THE IMPACT OF DEREGULATION Historically, electricity prices have varied by a factor of two to one or greater, depending upon where in the county the power is purchased. See Figure 24.2. These major differences even occur in utility jurisdictions that are joined. The cost of power has varied because of several factors, some of which are under the utilities control and some that are not, such as: • • • • •

Decisions on projected load growth The type of generation Fuel selections Cost of labor and taxes The regulatory climate

All of these factors contribute to the range of pricing. Customers have been clamoring for the right to choose the supplier and gain access to cheaper power for quite some time. This has driven regulators to impose utility deregulation, often with opposition from the incumbent utilities. Many believe that electric deregulation will even out this difference and bring down the total average price through competition. There are others that do not share that opinion. Most utilities are already taking actions to reduce costs. Consolidations, layoffs, and mergers are occurring with increased frequency. As part of the transition to deregulation, many utilities are requesting and receiving rate freezes and reductions in exchange for stranded costs. One factor has remained a constant until the early 2000’s. Customers have always had a “backstop” of regulated pricing until recently. Now that the transition periods are nearing their end, customers are faced with the option of buying electricity on the open market without a regulated default price. The risks to customers have increased dramatically. And, energy consultants

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Figure 24.2 Electricity Cost by State Average Revenue from Electric Sales to Industrial Consumers by State, 1995 (Cents per Kilowatt-hour)

and ESCOs are having a difficult time predicting the direction of electricity costs. All of this provides for interesting background and statistics, but what does it mean to energy managers interested in providing and procuring utilities, commissioning, O&M (operations and maintenance), and the other energy services required to build and operate buildings effectively? Just as almost every business enterprise has experienced changes in the way that they operate in the 90’s and 2000 and beyond, the electric utilities, their customers and the energy service sector must also transform. Only well-prepared companies will be in a position to take advantage of the opportunities that will present themselves after deregulation. Building owners and managers need to be in a position to actively participate in the early opening states. The following questions will have to be answered by each and every company if they are to be prepared: • •

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Will they participate in the deregulated electric market? Is it better to do a national account style supply arrangement or divide the properties by region and/or by building type? How will electric deregulation affect their relationships with tenants in commercial, governmental

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and institutional properties? Would there be a benefit for multi-site facilities to partake in purchasing power on their own? Should the analysis and operation of electric deregulation efforts be performed in-house or by consultants or a combination? What criteria should be used to select the energy suppliers when the future is uncertain?

24.7 THE TEN-STEP PROGRAM TO SUCCESSFUL UTILITY DEREGULATION In order for the building sector to get ready for the new order and answer the questions raised above, this ten-step program has been developed to ease the transition and take advantage of the new opportunities. This Ten Step program is ideally suited to building owners and managers as well as energy engineers that are in the process of developing their utility deregulation program. Step #1 - Know Thyself • When do you use the power • Distinguish between summer vs. winter, night vs. day

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• • • •

What load can you control/change What $$$ goal does your business have What is your 24 hr. load profile What are your in-house engineering, monitoring and financial strengths

Step • • • • • •

#2 - Keep Informed Read, read, read—network, network, network Interact with your professional organizations Talk to vendors, consultants, and contractors Subscribe to trade publications Attend seminars and conferences Utilize internet resources—news groups, WWW, E-mail Investigate buyer’s groups

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Step #3 - Talk to Your Utilities (all energy types) • Recognize customer relations are improving • Discuss alternate contract terms or other energy services • Find out if they are “for” or “agin” deregulation • Obtain improved service items (i.e., reliability) • Tell them your position and what you want. Now is not the time to be bashful • Renegotiate existing contracts Step • • • • •

#4 - Talk to Your Future Utility(ies) See Step #3 Find out who is actively pursuing your market Check the neighborhood, check the region, look nationally Develop your future relationships Partner with Energy Service Companies (ESCOs), power marketing, financial, vendor and other partners for your energy services needs

Step #5 - Explore Energy Services Now (Why wait for deregulation?) • Implement “standard” energy projects such as lighting, HVAC, etc. • Investigate district cooling/heating • Explore selling your central plant • Calculate square foot pricing • Buy comfort, Btus or GPMs; not kWhs • Outsource your Operations and Maintenance • Consider other work on the customer side of the meter Step #6 - Understand the Risks • Realize that times will be more complicated in the future • Consider the length of a contract term in uncertain times

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Identify whether you want immediate reductions now, larger reductions later or prices tied to some other index Determine the value of a flat price for utilities Be wary of losing control of your destiny-turning over some of the operational controls of your energy systems Realize the possibility some companies will not be around in a few years Determine how much risk you are willing to take in order to achieve higher rewards

Step #7 - Solicit Proposals • Meet with the bidders prior to issuing the Request For Proposal (RFP) • Prepare the RFP for the services you need • Identify qualified players • Make commissioning a requirement to achieve the results Step #8 - Evaluate Options • Enlist the aid of internal resources and outside consultants • Narrow the playing field and interview the finalists prior to awarding • Prepare a financial analysis of the results over the life of the project—Return on Investment (ROI) and Net Present Value (NPV) • Remember that the least first cost may or may not be the best value • Pick someone that has the financial and technical strengths for the long term • Evaluate financial options such as leasing or shared Step #9 - Negotiate Contracts Remember the following guidelines when negotiating a contract: • The longer the contract, the more important the escalation clauses due to compounding • Since you may be losing some control, the contract document is your only protection • The supplying of energy is not regulated like the supplying of kWhs are now • The clauses that identify the party taking responsibility for an action, or “Who Struck John” clauses, are often the most difficult to negotiate • Include monitoring and evaluation of results • Understand how the contract can be terminated and what the penalties for early termination are Step #10 - Sit Back and Reap the Rewards • Monitor, measure, and compare

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• • •

Don’t forget Operations & Maintenance for the long term Keep looking, there are more opportunities out there Get off your duff and go to Step #1 for the next round of reductions

24.8 AGGREGATION Aggregation is the grouping of utility customers to jointly purchase commodities and/or other energy services. There are many aggregators already formed or being formed in the states where utility deregulation is occurring. There are two basic forms of aggregation: 1. Similar Customers with Similar Needs Similar customers may be better served via aggregation even if they have the same load profiles • Pricing and risk can be tailored to similar customers needs • Similar billing needs can be met • Cross subsidization would be eliminated • Trust in the aggregator; i.e. BOMA for office building managers membership 2.

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Complementary Customers that May Enhance the Total Different load profiles can benefit the aggregated group by combining different load profiles. • Match a manufacturing facility with a flat or inverted load profile to an office building that has a peaky load profile, etc. • Combining of load profiles is more attractive to a supplier than either would be individually Why Aggregate? Some potential advantages to aggregating are: • Reduction of internal administration expense • Shared consulting expenses More supplier attention resulting from a larger bid Lower rates may be the result of a larger bid Lower average rates resulting from combining dissimilar user profiles Why Not Aggregate? Some potential disadvantages from aggregating are: If you are big enough, you are your own aggregation Good load factor customers may subsidize poor load factor customers

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The average price of an aggregation may be lower than your unique price An aggregation cannot meet “unique” customer requirements

Factors that affect the decision on joining an aggregation Determine if an aggregation is right for your situation by considering the following factors. An understanding of how these factors apply to your operation will result in an informed decision. • Size of load • Load profile • Risk tolerance • Internal abilities (or via consulting) • Contract length flexibility • Contract terms and conditions flexibility • Regulatory restrictions

24.9 IN-HOUSE VS. OUTSOURCING ENERGY SERVICES The end user sector has always used a combination of in-house and outsourced energy services. Many large managers and owners have a talented and capable staff to analyze energy costs, develop capital programs, and operate and maintain the in-place energy systems. Others (particularly the smaller players who cannot justify an in-house staff) have outsourced these functions to a team of consultants, contractors, and utilities. These relationships have evolved recently due to downsizing and returning to the core businesses. In the new era of deregulation, the complexion of how energy services are delivered will evolve further. Customers and energy services companies are already getting into the utility business of generating and delivering power. Utilities are also getting into the act by going beyond the meter and supplying chilled/hot water, conditioned air, and comfort. In doing so, many utilities are setting up unregulated subsidiaries to provide commissioning, O&M, and many other energy services to customers located within their territory, and nationwide as well. A variety of terms are often used: Performance Contracting, Energy System Outsourcing, Utility Plant Outsourcing, Guaranteed Savings, Shared Savings, Sell/Leaseback of the central plant, Chauffage (used in Europe), Energy Services Performance Contract (ESPC), etc. Definitions are as follows: • Performance Contracting Is the process of providing a specific improvement

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such as a lighting retrofit or a chiller change-out, usually using the contractor’s capital and then paying for the project via the savings over a specific period of time. Often the contractor guarantees a level of savings. The contractor supplies capital, engineering, equipment, installation, commissioning and often the maintenance and repair. Energy System Outsourcing Is the process of divesting of the responsibilities and often the assets of the energy systems to a third party. The third party then supplies the commodity, whether it be chilled water, steam, hot water, electricity, etc., at a per unit cost. The third party supplier then is responsible for the improvement capital and operations and maintenance of the energy system for the duration of the contract.

the infusion of a major capital investment in the near future. These investments are often required to address end-of-life, regulatory and efficiency issues. Either the building owner or manager could provide the capital or a third party could supply it and then include the repayment in a commodity charge plus interest; (“there are no free lunches”). 4.

Advantages The advantages of a performance contract or an energy system outsourcing project revolves around four major areas: 1.

2.

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Core Business Issues Many industries and corporations have been reexamining all of their non-core functions to determine if they would be better served by outsourcing these functions. Performance contracting or outsourcing can make sense if someone can be found that can do it better and cheaper than what can be managed by an in-house staff. Then the building managers can oversee the contractor and not the complete operation. This may allow the building to devote additional time and resources to other core business issues such as increasing revenues and reducing health care costs. Monetization One of the unique features of a performance contract or an energy system outsourcing project is the opportunity to obtain an up front payment. There is an extreme amount of flexibility available depending upon the needs. The amount available can range from zero dollars to the approximate current value of the installation. The more value placed on the up front payment will necessarily cause the monthly payments to increase as well as the total amount of interest paid. Deferred Capital Costs Many electrical and HVAC energy systems are at an age or state of repair that would necessitate

Operating Costs The biggest incentive to a performance contract or an energy system outsourcing project is that if the right supplier is chosen with the right incentives, then the total cost to own and operate the central plant can be less. The supplier, having expertise and volume in their core area of energy services, brings this to reality. With this expertise and volume, the supplier should be able to purchase supplies at less cost, provide better-trained personnel and implement energy and maintenance saving programs. These programs can range from capital investment of energy saving equipment to optimizing operations, maintenance and control programs.

Disadvantages Potentially, there are several disadvantages to undertaking a performance contract or an outsourcing project. The items identified in this section need to be recognized and mitigated as indicated here and in the Risk Management section. 1.

Loss of Control As with any service, if it is outsourced, the service is more difficult to control. The building is left with depending upon the skill, reliability and dedication of the service supplier and the contract to obtain satisfactory results. Even with a solid contract; if the supplier does not perform or goes out of business, the customer will suffer (see the Risk Management section). Close coordination between the building and the supplier will be necessary over the long term of the contract to adjust to changing conditions.

2.

Loss of Flexibility Unless addressed adequately in the contract, changes that the building wants or needs to make can cause the economics of the project to be adversely affected. Some examples are: • Changes in hours of operation • New systems that require additional cooling or heating, such as an expansion or renova-

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3.

tion, conversion of office or storage space to other uses, additional equipment requiring additional cooling, etc. Scheduling outages for maintenance or repairs Using in house technicians for other services throughout the building. If this situation occurs in current operation, provisions for additional building staff or having the supplier make the technician available needs to be arranged. If additional costs are indicated, they should be included in the financial analysis.

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then energy system outsourcing may be a good choice. •

Is there a desire to obtain a payment up front? As stated previously, a performance contract or energy system outsourcing project presents the opportunity to obtain a payment up front for the assets of the HVAC and electrical systems. However, any up-front payment increases the monthly payment over the term of the contract and should be considered similar to a loan.

•

Does the capital infusion and better operations generate enough cash flow to pay the debt? This is the sixty-four dollar question. Only by performing a long-term evaluation of the economics of the project with a comparison to the in house plan can the financial benefits be fairly compared. A Net Present Value and Cash Flow analysis should be used for the evaluation of a performance contract or energy system outsourcing project. It shows the capital and operating impact of the owner continuing to own and operate a HVAC and electrical systems. This is compared to a third party outsourced option. The analysis should be for a long enough period to incorporate the effect of a major capital investment. This is often done for a 20-year period. This type of analysis would allow the building owner or manager to evaluate the financial impact of the project over the term of the contract. Included in the analysis should be a risk sensitivity assessment that would bracket and define the range of results based upon changing assumptions.

Cost Increases This only becomes a disadvantage if the contract does not adequately foresee and cover every contingency and changing situation adequately. To protect themselves, the suppliers will try to put as much cost risk onto the customer as possible. It is the customer and the customer’s consultants and attorneys responsibility to define the risks and include provisions in the contract.

Financial Issues The basis for success of a performance contract or an energy system outsourcing project is divided between the technical issues, contract terms, supplier’s performance and how the project will be financed. These types of projects are as much (if not more) about the financial deal than the actual supplying of a commodity or a service. (See Chapter 4 -Economic Analysis and Life Cycle Costing) The answers to some basic questions will help guide the decision making process. •

•

Is capital required during the term of the project? The question of the need for capital is one of the major driving factors of a performance contract or an energy outsourcing project. Capital invested into the HVAC and electrical systems for efficiency upgrades, end of life replacements, increased reliability or capacity and environmental improvements can be financed through the program. Who will supply the capital and at what rate? The answer to the question of who will be supplying the capital should be made based upon your ability to supply capital from internal operations, capital improvement funds, borrowing ability and any special financing options such as tax free bonds or other low interest sources. If capital is needed for other uses such as expansions and other revenue generating or cost reduction measures,

Other Issues 1. Management and Personnel Issues • Management - Usually, an in-house manager will need to be assigned to manage the supplier and the contract and to verify the accuracy of the billing. An in-house technical person or an outside consultant should have the responsibility to periodically review the condition of the equipment to protect the long-term value of the central plant. •

Personnel - Existing employees need to be considered. This may or may not have a monetary consequence due to severance or other policies. If there is an impact, it needs to be reflected in the analysis. It would usually be to the building’s benefit if the years of knowledge and experience represented by the current engineers could be transferred to the

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new supplier. Another personnel concern is the effect on the moral of the employees due to their fear of losing their jobs. 2.

Which services to outsource? Where there are other services located in the central plant that are not outsourced, these need to be identified in the documents. These could include compressed air for controls, domestic water, hot water, etc. A method of allocating costs for shared services will need to be established and managed through the duration of the contract.

3.

Product specifications The properties of the supplied service need to be adequately described to judge if the supplier is meeting the terms of the contract. Quantities like temperature, water treatment values, pressure, etc. needs to be well defined.

4.

Early Termination There should be several options in the contract for early termination. The most obvious is for lack of performance. In this case, lack of performance can range from total disruption of service to not meeting the defined values of the commodity to letting the equipment deteriorate. There should also be the ability to have the building owner terminate the contract if the building owner decides that they want to take the central plant in-house or find another contractor. If the supplier is in default, then a “make whole” payment would be required of the building to terminate the contract in this case.

Risk Management As with any long-term commitment, the most important task is to identify all of the potential risks, evaluate their consequences and probability and then to formulate strategies that will mitigate the risks. This could be in the form of the contract document language or other financial instruments for protection. One of the most important areas of risk management mitigation is to choose a supplier that will deliver what is promised over the entire contract period. 1.

How to Choose a Supplier In addition to price, the following factors are important to the success of a project and should be evaluated before selecting a supplier. • Track record • Knowledge of your business, priorities and risk tolerance • Size

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Financial backing Customer service and reporting “Staying Power”

2.

Long Term Contracts Because the potential supplier will be investing capital for increased life, reliability and efficiency, the contract needs to be long enough to recover the costs and provide a positive cash flow. The length of the project can vary from three to five years for a simple, small-scale project up to ten to twenty years for one of increased complexity. Cost impacts at the termination of the contract needs to be adequately addressed, such as: • Renewals • Buyouts • Equipment leases • Equipment condition at the end of the contract

3.

Changing Assumptions • Interest rates • Utility rates • Maintenance and repair costs • Areas served (i.e., expansions/renovations/ contractions) • Regulations; building specific, environmental, OSHA, local codes, etc. • Utility deregulation

4.

Other Risks • The impact of planned or unplanned outages of the central plant • The consequences of the supplier not being able to maintain chilled water temperature or steam pressure • “Take or Pay” This provision of a contract requires the customer to pay a certain amount even if they do not use the commodity • Defaults and Remedies

24.10 SUMMARY This chapter presented information on the changing world of the utility industry in the new millennium. Starting in the 80’s with gas deregulation and the passage of the Energy Policy Act of 1992 for electricity, the method of providing and purchasing energy was changed forever. Utilities began a slow change from vertically integrated monopolies to providers of regulated wires and transmission services. Some utilities

UTILITY DEREGULATION AND ENERGY SYSTEM OUTSOURCING

continued to supply generation services, through their unregulated enterprises and by independent power producers in the deregulated markets while others sold their generation assets and became “wires” companies. Customers became confused in the early stages of deregulation, but by the end of the 1990’s some became more knowledgeable and successful in buying deregulated natural gas and electricity. In the early 2000’s, difficulties have developed in the deregulated utility arena. California rescinded deregulation (except for existing contracts) after shortages, rolling blackouts and price increases sent the utilities into a tailspin. The great blackout of 2003 raises concerns about the reliability of the transmission system. And the loss of regulated rates provides more challenges to customers and their consultants. However, many customers continue to participate in the deregulated markets to obtain reduced (or stable) prices, reduce their risk of big price swings and incorporate energy reduction programs with energy procurement programs. Another result of deregulation has been a re-examination by customers of outsourcing their energy needs. Some customers have “sold” their energy systems to energy suppliers and are now purchasing Btus instead of kWhs. The energy industry responded with energy service business units to meet this new demand for outsourcing. Performance contracting and energy system outsourcing can be advantageous when the organization does not have internal expertise to execute these projects and when other sources of capital are needed. However, performance contracting and energy system outsourcing is not without peril if the risks are not understood and mitigated. Before undertaking a performance contract or energy system outsourcing project, the owner or manager first needs to define the financial, technical, legal and operational issues of importance. Next, the proper resources, whether internal or outsourced, need to be marshaled to define the project, prepare the Request

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for Proposal, evaluate the suppliers and bids, negotiate a contract and monitor the results, often over a long period. If these factors are properly considered and executed, the performance contract or energy system outsourcing often produce results that could not be obtained via other project methods. BIBLIOGRAPHY Power Shopping and Power Shopping II, A publication of the Building Owners and Managers Association (BOMA) International, 1201 New York Avenue, N.W., N.W., Suite 300, Washington, DC 20005. The Changing Structure of the Electric Power Industry: Historical Overview, United States Department of Energy, Energy Information Administration, Washington, DC. The Ten Step Program to Successful Utility Deregulation for Building Owners and Managers, George R Owens PE CEM, President Energy and Engineering Solutions, Inc. (EESI), 9449 Penfield Ct., Columbia, MD 21045. Performance Contracting and Energy System Outsourcing, George R Owens PE CEM, President Energy and Engineering Solutions, Inc. (EESI), 9449 Penfield Ct., Columbia, MD 21045. Generating Power and Getting It to The Consumer, Edison Electric Institute, 701 Pennsylvania Ave NW, Washington, DC, 20004. The Changing Structure of the Electric Power Industry: An Update, US Department of Energy, Energy Information Administration, DOE/EIA-0562(96) PJM Electricity Futures, New York Mercantile Exchange (NYMEX) web page, www.nymex.com

SOME USEFUL INTERNET RESOURCES 10 Step paper - www.eesienergy.com State activities - www.eia.doe.gov/cneaf/electricity/chg_str/ State regulatory commissions www.naruc.org Utilities - www.utilityconnection.com Maillist - [email protected]

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CHAPTER 25

FINANCING ENERGY MANAGEMENT PROJECTS ERIC A. WOODRUFF, PH.D., CEM, CEP, CLEP Johnson Controls, Inc.

25.1 INTRODUCTION Financing can be a key success factor for projects. This chapter ’s purpose is to help facility managers understand and apply the financial arrangements available to them. Hopefully, this approach will increase the implementation rate of good energy management projects, which would have otherwise been cancelled or postponed due to lack of funds. Most facility managers agree that energy management projects (EMPs) are good investments. Generally, EMPs reduce operational costs, have a low risk/reward ratio, usually improve productivity and even have been shown to improve a firm’s stock price.1 Despite these benefits, many cost-effective EMPs are not implemented due to financial constraints. A study of manufacturing facilities revealed that first-cost and capital constraints represented over 35% of the reasons cost-effective EMPs were not implemented.2 Often, the facility manager does not have enough cash to allocate funding, or can not get budget approval to cover initial costs. Financial arrangements can mitigate a facility’s funding constraints,3 allowing additional energy savings to be reaped. Alternative finance arrangements can overcome the “initial cost” obstacle, allowing firms to implement more EMPs. However, many facility managers are either unaware or have difficulty understanding the variety of financial arrangements available to them. Most facility managers use simple payback analyses to evaluate projects, which do not reveal the added value of after-tax benefits.4 Sometimes facility managers do not implement an EMP because financial terminology and contractual details intimidate them.5 To meet the growing demand, there has been a dramatic increase in the number of finance companies specializing in EMPs. At a recent World Energy Engineering Congress, finance companies represented the most common exhibitor type. These financiers are introducing new payment arrangements to implement EMPs. Often, the financier’s innovation will satisfy the unique customer needs of a large facility. This is a great service

however, most financiers are not attracted to small facilities with EMPs requiring less than $100,000. Thus, many facility managers remain unaware or confused about the common financial arrangements that could help them implement EMPs. Numerous papers and government programs have been developed to show facility managers how to use quantitative (economic) analysis to evaluate financial arrangements.4,5,6 (Refer to Chapter 4 of this book.) Quantitative analysis includes computing the simple payback, net present value (NPV), internal rate of return (IRR), or lifecycle cost of a project with or without financing. Although these books and programs show how to evaluate the economic aspects of projects, they do not incorporate qualitative factors like strategic company objectives, (which can impact the financial arrangement selection). Without incorporating a facility manager’s qualitative objectives, it is hard to select an arrangement that meets all of the facility’s needs. A recent paper showed that qualitative objectives can be at least as important as quantitative objectives.9 This chapter hopes to provide some valuable information, which can be used to overcome the previously mentioned issues. The chapter is divided into several sections to accomplish three objectives. Sections 2 and 3 introduce the basic financial arrangements via a simple example. In sections 4 and 5, financial terminology is defined and each arrangement is explained in greater detail while applied to a case study. The remaining sections show how to match financial arrangements to different projects and facilities.

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25.2 FINANCIAL ARRANGEMENTS: A SIMPLE EXAMPLE Consider a small company “PizzaCo” that makes frozen pizzas, and distributes them regionally. PizzaCo uses an old delivery truck that breaks down frequently and is inefficient. Assume the old truck has no salvage value and is fully depreciated. PizzaCo’s management would like to obtain a new and more efficient truck to reduce expenses and improve reliability. However, they do not have the cash on hand to purchase the truck. Thus, they consider their financing options.

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25.2.1 Purchase the Truck with a Loan or Bond Just like most car purchases, PizzaCo borrows money from a lender (a bank) and agrees to a monthly re-payment plan. Figure 25.1 shows PizzaCo’s annual cash flows for a loan. The solid arrows represent the financing cash flows between PizzaCo and the bank. Each year, PizzaCo makes payments (on the principal, plus interest based on the unpaid balance), until the balance owed is zero. The payments are the negative cash flows. Thus, at time zero when PizzaCo borrows the money, they receive a large sum of money from the bank, which is a positive cash flow (which will be used to purchase the truck). The dashed arrows represent the truck purchase as well as savings cash flows. Thus, at time zero, PizzaCo purchases the truck (a negative cash flow) with the money from the bank. Due to the new truck’s greater efficiency, PizzaCo’s annual expenses are reduced (which is a savings). The annual savings are the positive cash flows. The remaining cash flow diagrams in this chapter utilize the same format. PizzaCo could also purchase the truck by selling a bond. This arrangement is similar to a loan, except investors (not a bank) give PizzaCo a large sum of money (called the bond’s “par value”). Periodically, PizzaCo would pay the investors only the interest accumulated. As Figure 25.2 shows, when the bond reaches maturity, PizzaCo returns the par value to the investors. The equipment purchase and savings cash flows are the same as with the loan. 25.2.2 Sell Stock to Purchase the Truck In this arrangement, PizzaCo sells its stock to raise money to purchase the truck. In return, PizzaCo is expected to pay dividends back to shareholders. Selling stock has a similar cash flow pattern as a bond, with a few subtle differences. Instead of interest payments to bondholders, PizzaCo would pay dividends to share-

Figure 25.1 PizzaCo’s Cash Flows for a Loan.

holders until some future date when PizzaCo could buy the stock back. However, these dividend payments are not mandatory, and if PizzaCo is experiencing financial strain, it does not need to distribute dividends. On the other hand, if PizzaCo’s profits increase, this wealth will be shared with the new stockholders, because they now own a part of the company. 25.2.3 Rent the Truck Just like renting a car, PizzaCo could rent a truck for an annual fee. This would be equivalent to a true lease. The rental company (lessor) owns and maintains the truck for PizzaCo (the lessee). PizzaCo pays the rental fees (lease payments) which are considered taxdeductible business expenses. Figure 25.3 shows that the lease payments (solid arrows) start as soon as the equipment is leased (year zero) to account for lease payments paid in advance. Lease payments “in arrears” (starting at the end of the first year) could also be arranged. However, the leasing company may require a security deposit as collateral. Notice that the savings cash flows are essentially the same as the previous arrangements, except there is no equipment purchase, which is a large negative cash flow at year zero.

Figure 25.2 PizzaCo’s Cash Flows for a Bond.

Figure 25.3. PizzaCo’s Cash Flows for a True Lease.

FINANCING ENERGY MANAGEMENT PROJECTS

In a true lease, the contract period should be shorter than the equipment’s useful life. The lease is cancelable because the truck can be leased easily to someone else. At the end of the lease, PizzaCo can either return the truck or renew the lease. In a separate transaction, PizzaCo could also negotiate to buy the truck at the fair market value. If PizzaCo wanted to secure the option to buy the truck (for a bargain price) at the end of the lease, then they would use a capital lease. A capital lease can be structured like an installment loan, however ownership is not transferred until the end of the lease. The lessor retains ownership as security in case the lessee (PizzaCo) defaults on payments. Because the entire cost of the truck is eventually paid, the lease payments are larger than the payments in a true lease, (assuming similar lease periods). Figure 25.4 shows the cash flows for a capital lease with advance payments and a bargain purchase option at the end of year five. There are some additional scenarios for lease arrangements. A “vendor-financed” agreement is when the lessor (or lender) is the equipment manufacturer. Alternatively, a third party could serve as a financing source. With “third party financing,” a finance company would purchase a new truck and lease it to PizzaCo. In either case, there are two primary ways to repay the lessor. 1.

With a “fixed payment plan”; where payments are due whether or not the new truck actually saves money.

2.

With a “flexible payment plan”; where the savings from the new truck are shared with the third party, until the truck’s purchase cost is recouped with interest. This is basically a “shared savings” arrangement.

Figure 25.4 PizzaCo’s Cash Flows for a Capital Lease.

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25.2.4 Subcontract Pizza Delivery to a Third Party Since PizzaCo’s primary business is not delivery, it could subcontract that responsibility to another company. Let’s say that a delivery service company would provide a truck and deliver the pizzas at a reduced cost. Each month, PizzaCo would pay the delivery service company a fee. However, this fee is guaranteed to be less than what PizzaCo would have spent on delivery. Thus, PizzaCo would obtain savings without investing any money or risk in a new truck. This arrangement is analogous to a performance contract. This arrangement is very similar to a third-party lease and a shared savings agreement. However with a performance contract, the contractor assumes most of the risk, (because they supply the equipment, with little or no investment from PizzaCo). The contractor also is responsible for ensuring that the delivery fee is less than what PizzaCo would have spent. For the PizzaCo example, the arrangement would designed under the conditions below. •

The delivery company owns and maintains the truck. It also is responsible for all operations related to delivering the pizzas.

•

The monthly fee is related to the number of pizzas delivered. This is the performance aspect of the contract; if PizzaCo doesn’t sell many pizzas, the fee is reduced. A minimum amount of pizzas may be required by the delivery company (performance contractor) to cover costs. Thus, the delivery company assumes these risks: 1. PizzaCo will remain solvent, and 2. PizzaCo will sell enough pizzas to cover costs, and 3. the new truck will operate as expected and will actually reduce expenses per pizza, and 4. the external financial risk, such as inflation and interest rate changes, are acceptable.

•

Because the delivery company is financially strong and experienced, it can usually obtain loans at low interest rates.

•

The delivery company is an expert in delivery; it has specially skilled personnel and uses efficient equipment. Thus, the delivery company can deliver the pizzas at a lower cost (even after adding a profit) than PizzaCo.

Figure 25.5 shows the net cash flows according to PizzaCo. Since the delivery company simply reduces

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PizzaCo’s operational expenses, there is only a net savings. There are no negative financing cash flows. Unlike the other arrangements, the delivery company’s fee is a less expensive substitute for PizzaCo’s in-house delivery expenses. With the other arrangements, PizzaCo had to pay a specific financing cost (loan, bond or lease payments, or dividends) associated with the truck, whether or not the truck actually saved money. In addition, PizzaCo would have to spend time maintaining the truck, which would detract from its core focus: making pizzas. With a performance contract, the delivery company is paid from the operational savings it generates. Because the savings are greater than the fee, there is a net savings. Often, the contractor guarantees the savings.

Figure 25.5 PizzaCo’s Cash Flows for a Performance Contract. Supplementary Note: Combinations of the basic finance arrangements are possible. For example, a shared savings arrangement can be structured within a performance contract. Also, performance contracts are often designed so that the facility owner (PizzaCo) would own the asset at the end of the contract.

25.3 FINANCIAL ARRANGEMENTS: DETAILS AND TERMINOLOGY To explain the basic financial arrangements in more detail, each one is applied to an energy management-related case study. To understand the economics behind each arrangement, some finance terminology is presented below. 25.3.1 Finance Terminology Equipment can be purchased with cash on-hand (officially labeled “retained earnings”), a loan, a bond, a capital lease or by selling stock. Alternatively, equipment can be utilized with a true lease or with a performance contract. Note that with performance contracting, the building owner is not paying for the equipment itself, but

ENERGY MANAGEMENT HANDBOOK

the benefits provided by the equipment. In the Simple Example, the benefit was the pizza delivery. PizzaCo was not concerned with what type of truck was used. The decision to purchase or utilize equipment is partly dependent on the company’s strategic focus. If a company wants to delegate some or all of the responsibility of managing a project, it should use a true lease, or a performance contact.10 However, if the company wants to be intricately involved with the EMP, purchasing and self-managing the equipment could yield the greatest profits. When the building owner purchases equipment, he/she usually maintains the equipment, and lists it as an asset on the balance sheet so it can be depreciated. Financing for purchases has two categories: 1.

Debt Financing, which is borrowing money from someone else, or another firm. (using loans, bonds and capital leases)

2.

Equity Financing, which is using money from your company, or your stockholders. (using retained earnings, or issuing common stock)

In all cases, the borrower will pay an interest charge to borrow money. The interest rate is called the “cost of capital.” The cost of capital is essentially dependent on three factors: (1) the borrower’s credit rating, (2) project risk and (3) external risk. External risk can include energy price volatility, industry-specific economic performance as well as global economic conditions and trends. The cost of capital (or “cost of borrowing”) influences the return on investment. If the cost of capital increases, then the return on investment decreases. The “minimum attractive rate of return” (MARR) is a company’s “hurdle rate” for projects. Because many organizations have numerous projects “competing” for funding, the MARR can be much higher than interest earned from a bank, or other risk-free investment. Only projects with a return on investment greater than the MARR should be accepted. The MARR is also used as the discount rate to determine the “net present value” (NPV). 25.3.2 Explanation of Figures and Tables Throughout this chapter’s case study, figures are presented to illustrate the transactions of each arrangement. Tables are also presented to show how to perform the economic analyses of the different arrangements. The NPV is calculated for each arrangement. It is important to note that the NPV of a particular arrangement can change significantly if the cost of capital, MARR, equipment residual value, or project life is ad-

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justed. Thus, the examples within this chapter are provided only to illustrate how to perform the analyses. The cash flows and interest rates are estimates, which can vary from project to project. To keep the calculations simple, end-ofyear cash flows are used throughout this chapter. Within the tables, the following abbreviations and equations are used: EOY Savings Depr. Taxable Income

= = = =

End of Year pre-Tax Cash Flow Depreciation Savings - Depreciation - Interest Payment Tax = (Taxable Income)*(Tax Rate) ATCF = After Tax Cash Flow = Savings – Total Payments – Taxes

Table 25.1 shows the basic equations that are used to calculate the values under each column heading within the economic analysis tables.

been fully depreciated, he/she can claim the book value as a tax-deduction.*

25.4 APPLYING FINANCIAL ARRANGEMENTS: A CASE STUDY Suppose PizzaCo (the “host” facility) needs a new chilled water system for a specific process in its manufacturing plant. The installed cost of the new system is $2.5 million. The expected equipment life is 15 years, however the process will only be needed for 5 years, after which the chilled water system will be sold at an estimated market value of $1,200,000 (book value at year five = $669,375). The chilled water system should save PizzaCo about $1 million/year in energy savings. PizzaCo’s tax rate is 34%. The equipment’s annual maintenance and insurance cost is $50,000. PizzaCo’s MARR is 18%. Since at the end of year 5, PizzaCo expects to sell the asset for an amount greater than its book value, the

Table 25.1 Table of Sample Equations used in Economic Analyses. ——————————————————————————————————————————————————— A

B

C

D

E

F

G

H

I

J

——————————————————————————————————————————————————— Payments EOY Savings

Depreciation

Principal

Interest

Total

Principal

Taxable

Outstanding

Income

Tax

ATCF

——————————————————————————————————————————————————— n n+1

= (MACRS %)*

n+2

(Purchase Price)

=(D) +(E)

=(G at year n)

=(B)–(C)–(E)

=(H)*(tax rate)

=(B)–(F)–(I)

–(D at year n+1)

——————————————————————————————————————————————————— Regarding depreciation, the “modified accelerated cost recovery system” (MACRS) is used in the economic analyses. This system indicates the percent depreciation claimable year-by-year after the equipment is purchased. Table 25.2 shows the MACRS percentages for seven-year property. For example, after the first year, an owner could depreciate 14.29% of an equipment’s value. The equipment’s “book value” equals the remaining unrecovered depreciation. Thus, after the first year, the book value would be 100%-14.29%, which equals 85.71% of the original value. If the owner sells the property before it has *To be precise, the IRS uses a “half-year convention” for equipment that is sold before it has been completely depreciated. In the tax year that the equipment is sold, (say year “x”) the owner claims only Ω of the MACRS depreciation percent for that year. (This is because the owner has only used the equipment for a fraction of the final year.) Then on a separate line entry, (in the year “x*”), the remaining unclaimed depreciation is claimed as “book value.” The x* year is presented as a separate line item to show the book value treatment, however x* entries occur in the same tax year as “x.”

Table 25.2 MACRS Depreciation Percentages. ————————————————————————— EOY MACRS Depreciation Percentages for 7-Year Property ————————————————————————— 0 0 ————————————————————————— 1 14.29% ————————————————————————— 2 24.49% ————————————————————————— 3 17.49% ————————————————————————— 4 12.49% ————————————————————————— 5 8.93% ————————————————————————— 6 8.92% ————————————————————————— 7 8.93% ————————————————————————— 8 4.46% —————————————————————————

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additional revenues are called a “capital gain,” (which equals the market value – book value) and are taxed. If PizzaCo sells the asset for less than its book value, PizzaCo incurs a “capital loss.” PizzaCo does not have $2.5 million to pay for the new system, thus it considers its finance options. PizzaCo is a small company with an average credit rating, which means that it will pay a higher cost of capital than a larger company with an excellent credit rating. As with any borrowing arrangement, if investors believe that an investment is risky, they will demand a higher interest rate. 25.4.1 Purchase Equipment with Retained Earnings (Cash) If PizzaCo did have enough retained earnings (cash on-hand) available, it could purchase the equipment without external financing. Although external finance expenses would be zero, the benefit of tax-deductions (from interest expenses) is also zero. Also, any cash used to purchase the equipment would carry an “opportunity cost,” because that cash could have been used to earn a return somewhere else. This opportunity cost rate is usually set equal to the MARR. In other words, the company lost the opportunity to invest the cash and gain at least the MARR from another investment. Of all the arrangements described in this chapter, purchasing equipment with retained earnings is probably the simplest to understand. For this reason, it will serve as a brief example and introduction to the economic analysis tables that are used throughout this chapter. 25.4.1.1 Application to the Case Study Figure 25.6 illustrates the resource flows between the parties. In this arrangement, PizzaCo purchases the chilled water system directly from the equipment manufacturer. Once the equipment is installed, PizzaCo recovers the full $1 million/year in savings for the entire five

years, but must spend $50,000/year on maintenance and insurance. At the end of the five-year project, PizzaCo expects to sell the equipment for its market value of $1,200,000. Assume MARR is 18%, and the equipment is classified as 7-year property for MACRS depreciation. Table 25.3 shows the economic analysis for purchasing the equipment with retained earnings. Reading Table 25.3 from left to right, and top to bottom, at EOY 0, the single payment is entered into the table. Each year thereafter, the savings as well as the depreciation (which equals the equipment purchase price multiplied by the appropriate MACRS % for each year) are entered into the table. Year by year, the taxable income = savings – depreciation. The taxable income is then taxed at 34% to obtain the tax for each year. The after-tax cash flow = savings - tax for each year. At EOY 5, the equipment is sold before the entire value was depreciated. EOY 5* shows how the equipment sale and book value are claimed. In summary, the NPV of all the ATCFs would be $320,675. 25.4.2 Loans Loans have been the traditional financial arrangement for many types of equipment purchases. A bank’s willingness to loan depends on the borrower’s financial health, experience in energy management and number of years in business. Obtaining a bank loan can be difficult if the loan officer is unfamiliar with EMPs. Loan officers and financiers may not understand energyrelated terminology (demand charges, kVAR, etc.). In addition, facility managers may not be comfortable with the financier’s language. Thus, to save time, a bank that can understand EMPs should be chosen. Most banks will require a down payment and collateral to secure a loan. However, securing assets can be difficult with EMPs because the equipment often becomes part of the real estate of the plant. For example, it would be very difficult for a bank to repossess lighting fixtures from a retrofit. In these scenarios, lenders may be willing to secure other assets as collateral.

Bank Purchase Amount Chilled Water System Manufacturer

Loan Principal PizzaCo

Equipment

Chilled Water System Manufacturer

Purchase Amount PizzaCo Equipment

Figure 25.6 Resource Flows for Using Retained Earnings

25.7 Resource Flow Diagram for a Loan.

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Table 25.3 Economic Analysis for Using Retained Earnings. —————————————————————————————————————————————— EOY

Savings

Depr.

Payments Principal Interest

Total

Principal Taxable Outstanding Income

Tax

ATCF

—————————————————————————————————————————————— 0 1 2 3 4 5 5*

2,500,000 950,000 950,000 950,000 950,000 950,000 1,200,000

357,250 612,250 437,250 312,250 111,625 669,375

592,750 337,750 512,750 637,750 838,375 530,625

201,535 114,835 174,335 216,835 285,048 180,413

-2,500,000 748,465 835,165 775,665 733,165 664,953 1,019,588

—————————————————————————————————————————————— 2,500,000 Net Present Value at 18%:

$320,675

—————————————————————————————————————————————— Notes:

Loan Amount: Loan Finance Rate:

0 0%

MARR Tax Rate

18% 34%

MACRS Depreciation for 7-Year Property, with half-year convention at EOY 5 Accounting Book Value at end of year 5: 669,375 Estimated Market Value at end of year 5: 1,200,000 EOY 5* illustrates the Equipment Sale and Book Value Taxable Income: =(Market Value - Book Value) =(1,200,000 - 669,375) = $530,625

—————————————————————————————————————————————— 25.4.2.1 Application to the Case Study Figure 25.7 illustrates the resource flows between the parties. In this arrangement, PizzaCo purchases the chilled water system with a loan from a bank. PizzaCo makes equal payments (principal + interest) to the bank for five years to retire the debt. Due to PizzaCo’s small size, credibility, and inexperience in managing chilled water systems, PizzaCo is likely to pay a relatively high cost of capital. For example, let’s assume 15%. PizzaCo recovers the full $1 million/year in savings for the entire five years, but must spend $50,000/ year on maintenance and insurance. At the end of the five-year project, PizzaCo expects to sell the equipment for its market value of $1,200,000. Tables 25.4 and 25.5 show the economic analysis for loans with a zero down payment and a 20% down payment, respectively. Assume that the bank reduces the interest rate to 14% for the loan with the 20% down payment. Since the asset is listed on PizzaCo’s balance sheet, PizzaCo can use depreciation benefits to reduce the after-tax cost. In addition, all loan interest expenses are tax-deductible. 25.4.3 Bonds Bonds are very similar to loans; a sum of money is borrowed and repaid with interest over a period of time. The primary difference is that with a bond, the issuer

(PizzaCo) periodically pays the investors only the interest earned. This periodic payment is called the “coupon interest payment.” For example, a $1,000 bond with a 10% coupon will pay $100 per year. When the bond matures, the issuer returns the face value ($1,000) to the investors. Bonds are issued by corporations and government entities. Government bonds generate tax-free income for investors, thus these bonds can be issued at lower rates than corporate bonds. This benefit provides government facilities an economic advantage to use bonds to finance projects. 25.4.3.1 Application to the Case Study Although PizzaCo (a private company) would not be able to obtain the low rates of a government bond, they could issue bonds with coupon interest rates competitive with the loan interest rate of 15%. In this arrangement, PizzaCo receives the investors’ cash (bond par value) and purchases the equipment. PizzaCo uses part of the energy savings to pay the coupon interest payments to the investors. When the bond matures, PizzaCo must then return the par value to the investors. See Figure 25.8. As with a loan, PizzaCo owns, maintains and depreciates the equipment throughout the project’s life. All coupon interest payments are tax-deductible. At the end

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Table 25.4 Economic Analysis for a Loan with No Down Payment. —————————————————————————————————————————————— EOY

Savings

Depr. Principal

Payments Interest

Total

Principal Outstanding

Taxable Income

Tax

ATCF

—————————————————————————————————————————————— 0 1 2 3 4 5 5*

950,000 950,000 950,000 950,000 950,000 1,200,000

357,250 612,250 437,250 312,250 111,625 669,375 2,500,000

370,789 426,407 490,368 563,924 648,511

2,500,000 375,000 319,382 255,421 181,865 97,277

745,789 745,789 745,789 745,789 745,789 530,625

2,129,211 1,702,804 1,212,435 648,511 0 180,413

217,750 18,368 257,329 455,885 741,098 1,019,588

74,035 6,245 187,492 55,001 251,973

Net Present Value at 18%:

130,176 197,966 116,719 49,210 -47,761

$757,121

—————————————————————————————————————————————— Notes:

Loan Amount: Loan Finance Rate:

2,500,000 (used to purchase equipment at year 0) 15% MARR 18% Tax Rate 34% MACRS Depreciation for 7-Year Property, with half-year convention at EOY 5 Accounting Book Value at end of year 5: 669,375 Estimated Market Value at end of year 5: 1,200,000 EOY 5* illustrates the Equipment Sale and Book Value Taxable Income: =(Market Value - Book Value) =(1,200,000 - 669,375) = $530,625

——————————————————————————————————————————————

Table 25.5 Economic Analysis for a Loan with a 20% Down-Payment, —————————————————————————————————————————————— EOY

Savings

Depr.

Payments Principal Interest

Total

Principal Outstanding

Taxable Income

Tax

ATCF

—————————————————————————————————————————————— 0 1 2 3 4 5 5*

950,000 950,000 950,000 950,000 950,000 1,200,000

357,250 612,250 437,250 312,250 111,625 669,375

302,567 344,926 393,216 448,266 511,024

280,000 237,641 189,351 134,301 71,543

500,000 582,567 582,567 582,567 582,567 582,567

2,000,000 1,697,433 1,352,507 959,291 511,0241 0

312,750 100,109 323,399 503,449 766,832 530,625

106,335 34,037 109,956 171,173 260,723 180,413

–500,000 261,098 333,396 257,477 196,260 106,710 1,019,588

—————————————————————————————————————————————— 2,500,000 Net Present Value at 18%:

$710,962

—————————————————————————————————————————————— Notes:

Loan Amount: Loan Finance Rate:

2,000,000 (used to purchase equipment at year 0) 14% MARR 18% 500,000 Tax Rate 34% MACRS Depreciation for 7-Year Property, with half-year convention at EOY 5 Accounting Book Value at end of year 5: 669,375 Estimated Market Value at end of year 5: 1,200,000 EOY 5* illustrates the Equipment Sale and Book Value Taxable Income: =(Market Value - Book Value) =(1,200,000 - 669,375) = $530,625

——————————————————————————————————————————————

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Investors Payments

Bond Chilled Water System Manufacturer

Purchase Amount PizzaCo Equipment

condition. Under this belief, the company’s stock price could decrease. However, recent research indicates that when a firm announces an EMP, investors react favorably.11 On average, stock prices were shown to increase abnormally by 21.33%. By definition, the cost of capital (rate) for selling stock is: cost of capitalselling stock = D/P where D = annual dividend payment P = company stock price

Figure 25.8 Resource Flow Diagram for a Bond. of the five-year project, PizzaCo expects to sell the equipment for its market value of $1,200,000. Table 25.6 shows the economic analysis of this finance arrangement. 25.4.4 Selling Stock Although less popular, selling company stock is an equity financing option which can raise capital for projects. For the host, selling stock offers a flexible repayment schedule, because dividend payments to shareholders aren’t absolutely mandatory. Selling stock is also often used to help a company attain its desired capital structure. However, selling new shares of stock dilutes the power of existing shares and may send an inaccurate “signal” to investors about the company’s financial strength. If the company is selling stock, investors may think that it is desperate for cash and in a poor financial

However, in most cases, the after-tax cost of capital for selling stock is higher than the after-tax cost of debt financing (using loans, bonds and capital leases). This is because interest expenses (on debt) are tax deductible, but dividend payments to shareholders are not. In addition to tax considerations, there are other reasons why the cost of debt financing is less than the financing cost of selling stock. Lenders and bond buyers (creditors) will accept a lower rate of return because they are in a less risky position due to the reasons below. •

Creditors have a contract to receive money at a certain time and future value (stockholders have no such guarantee with dividends).

•

Creditors have first claim on earnings (interest is paid before shareholder dividends are allocated).

Table 25.6 Economic Analysis for a Bond. —————————————————————————————————————————————— EOY

Savings

Depr. Principal

Payments Interest

Total

Principal Taxable Outstanding Income

Tax

ATCF

—————————————————————————————————————————————— 0 1 2 3 4 5 5*

950,000 950,000 950,000 950,0 0 950,000 1,200,000

357,250 612,250 437,250 312,250 111,625 669,375 2,500,000

2,500,000

375,000 375,000 375,000 375,000 375,000

375,000 375,000 375,000 375,000 2,875,000

2,500,000 2,500,000 2,500,000 2,500,000 2,500,000 0

217,750 -37,250 137,750 262,750 463,375 530,625

Net Present Value at 18%:

74,035 -12,665 46,835 89,335 157,548 180,413

500,965 587,665 528,165 485,665 -2,082,548 1,019,588 953,927

—————————————————————————————————————————————— Notes:

Loan Amount: Loan Finance Rate:

2,500,000 (used to purchase equipment at year 0) 0% MARR 18% Tax Rate 34% MACRS Depreciation for 7-Year Property, with half-year convention at EOY 5 Accounting Book Value at end of year 5: 669,375 Estimated Market Value at end of year 5: 1,200,000 EOY 5* illustrates the Equipment Sale and Book Value Taxable Income: =(Market Value - Book Value) =(1,200,000 - 669,375) = $530,625

——————————————————————————————————————————————

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Creditors usually have secured assets as collateral and have first claim on assets in the event of bankruptcy.

Despite the high cost of capital, selling stock does have some advantages. This arrangement does not bind the host to a rigid payment plan (like debt financing agreements) because dividend payments are not mandatory. The host has control over when it will pay dividends. Thus, when selling stock, the host receives greater payment flexibility, but at a higher cost of capital. 25.4.4.1 Application to the Case Study As Figure 25.9 shows, the financial arrangement is very similar to a bond, at year zero the firm receives $2.5 million, except the funds come from the sale of stock. Instead of coupon interest payments, the firm distributes dividends. At the end of year five, PizzaCo repurchases the stock. Alternatively, PizzaCo could capitalize the dividend payments, which means setting aside enough money so that the dividends could be paid with the interest generated. Table 25.7 shows the economic analysis for issuing stock at a 16% cost of equity capital, and repurchasing the stock at the end of year five. (For consistency of comparison to the other arrangements, the stock price does not change during the contract.) Like a loan or

bond, PizzaCo owns and maintains the asset. Thus, the annual savings are only $950,000. PizzaCo pays annual dividends worth $400,000. At the end of year 5, PizzaCo expects to sell the asset for $1,200,000. Note that Table 25.7 is slightly different from the other tables in this chapter: Taxable Income = Savings – Depreciation, and ATCF = Savings – Stock Repurchases - Dividends - Tax 25.4.5 Leases Firms generally own assets, however it is the use of these assets that is important, not the ownership. Leasing is another way of obtaining the use of assets. There are numerous types of leasing arrangements, ranging

Investors Sell Stock

Cash Chilled Water System Manufacturer

Purchase Amount PizzaCo Equipment

Figure 25.9 Resource Flow Diagram for Selling Stock.

Table 25.7 Economic Analysis of Selling Stock. —————————————————————————————————————————————— EOY

Savings

Depr.

Stock Transactions Sale of Stock Repurchase

Dividend Payments

Taxable Income

Tax

ATCF

—————————————————————————————————————————————— 0 1 2 3 4 5 5*

950,000 950,000 950,000 950,000 950,000 1,200,000

$2,500,000 from Stock Sale is used to purchase equipment, thur 357,250 400,000 592,750 612,250 400,000 337,750 437,250 400,000 512,750 312,250 400,000 637,750 111,625 2,500,000 400,000 838,375 669,375 530,625 2,500,000

ATCF = 0 201,535 114,835 174,335 216,835 285,048 180,413

348,465 435,165 375,665 333,165 2,235,048 1,019,588

—————————————————————————————————————————————— Net Present Value at 18%:

477,033

—————————————————————————————————————————————— Notes:

Value of Stock Sold (which is repurchased after year 5 2,500,000 (used to purchase equipment at year 0) Cost of Capital = Annual Dividend Rate: 16% MARR = 18% Tax Rate = 34% MACRS Depreciation for 7-Year Property, with half-year convention at EOY 5 Accounting Book Value at end of year 5: 669,375 Estimated Market Value at end of year 5: 1,200,000 EOY 5* illustrates the Equipment Sale and Book Value Taxable Income: = (Market Value - Book Value) = (1,200,000 - 669,375) = $530,625

——————————————————————————————————————————————

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from basic rental agreements to extended payment plans for purchases. Leasing is used for nearly one-third of all equipment utilization.12 Leases can be structured and approved very quickly, even within 48 hours. Table 25.8 lists some additional reasons why leasing can be an attractive arrangement for the lessee.

Does the lessor have:

≥ 20% investment in asset at all times? yes

▼

no

yes

▼

≥20% residual value? ▼

lease period ≤ 80% asset’s life?

Risk Sharing • Leasing is good for short-term asset use, and reduces the risk of getting stuck with obsolete equipment • Leasing offers less risk and responsibility —————————————————————————

yes

no ▼

Table 25.8 Good Reasons to Lease. ————————————————————————— Financial Reasons • With some leases, the entire lease payment is taxdeductible. • Some leases allow “off-balance sheet” financing, preserving credit lines

no ▼

▼

▼

▼

yes

no

▼

a loan to the lessor? ▼

▼

Basically, there are two types of leases; the “true lease” (a.k.a. “operating” or “guideline lease”) and the “capital lease.” One of the primary differences between a true lease and a capital lease is the tax treatment. In a true lease, the lessor owns the equipment and receives the depreciation benefits. However, the lessee can claim the entire lease payment as a tax-deductible business expense. In a capital lease, the lessee (PizzaCo) owns and depreciates the equipment. However, only the interest portion of the lease payment is tax-deductible. In general, a true lease is effective for a short-term project, where the company does not plan to use the equipment when the project ends. A capital lease is effective for long-term equipment.

▼

Does lessee have:

▼

a bargain purchase option? ▼

▼

no

Capital Lease

True Lease Figure 25.10 Classification for a True Lease.

25.4.5.1 The True Lease Figure 25.10 illustrates the legal differences between a true lease and a capital lease.13 A true lease (or operating lease) is strictly a rental agreement. The word “strict” is appropriate because the Internal Revenue Service will only recognize a true lease if it satisfies the following criteria: 1.

the lease period must be less than 80% of the equipment’s life, and

2.

the equipment’s estimated residual value must be ≥20% of its value at the beginning of the lease, and

3.

there is no “bargain purchase option,” and

4.

there is no planned transfer of ownership, and

5.

the equipment must not be custom-made and only useful in a particular facility.

25.4.5.2 Application to the Case Study It is unlikely that PizzaCo could find a lessor that would be willing to lease a sophisticated chilled water system and after five years, move the system to another facility. Thus, obtaining a true lease would be unlikely. However, Figure 25.11 shows the basic relationship between the lessor and lessee in a true lease. A third-party leasing company could also be involved by purchasing

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Chilled Water System Manufacturer (Lessor)

Lease Payments PizzaCo (Lessee)

Leased Equipment

Figure 25.11 Resource Flow Diagram for a True Lease. the equipment and leasing to PizzaCo. Such a resource flow diagram is shown for the capital lease. Table 25.9 shows the economic analysis for a true lease. Notice that the lessor pays the maintenance and insurance costs, so PizzaCo saves the full $1 million per year. PizzaCo can deduct the entire lease payment of $400,000 as a business expense. However PizzaCo does not obtain ownership, so it can’t depreciate the asset. 25.4.5.3 The Capital Lease The capital lease has a much broader definition than a true lease. A capital lease fulfills any one of the following criteria: 1. 2. 3. 4.

the lease term ≥80% of the equipment’s life; the present value of the lease payments ≥80% of the initial value of the equipment; the lease transfers ownership; the lease contains a “bargain purchase option,” which is negotiated at the inception of the lease.

Most capital leases are basically extended payment plans, except ownership is usually not transferred

until the end of the contract. This arrangement is common for large EMPs because the equipment (such as a chilled water system) is usually difficult to reuse at another facility. With this arrangement, the lessee eventually pays for the entire asset (plus interest). In most capital leases, the lessee pays the maintenance and insurance costs. The capital lease has some interesting tax implications because the lessee must list the asset on its balance sheet from the beginning of the contract. Thus, like a loan, the lessee gets to depreciate the asset and only the interest portion of the lease payment is tax deductible. 25.4.5.4 Application to the Case Study Figure 25.12 shows the basic third-party financing relationship between the equipment manufacturer, lessor and lessee in a capital lease. The finance company (lessor) is shown as a third party, although it also could be a division of the equipment manufacturer. Because the finance company (with excellent credit) is involved, a lower cost of capital (12%) is possible due to reduced risk of payment default. Like an installment loan, PizzaCo’s lease payments cover the entire equipment cost. However, the lease payments are made in advance. Because PizzaCo is considered the owner, it pays the $50,000 annual maintenance expenses, which reduces the annual savings to $950,000. PizzaCo receives the benefits of depreciation and tax-deductible interest payments. To be consistent with the analyses of the other arrangements, PizzaCo would sell the equipment at the end of the lease for its market value. Table 25.10 shows the economic analysis for a capital lease.

Table 25-9 Economic Analysis for a True Lease —————————————————————————————————————————————— EOY

Savings

Depr.

Lease Payments

Total

Principal Taxable Outstanding Income

Tax

ATCF

—————————————————————————————————————————————— 0 1 2 3 4 5

1,000,000 1,000,000 1,000,000 1,000,000 1,000,000

0 0 0 0 0

400,000 400,000 400,000 400,000 400,000

400,000 400,000 400,000 400,000 400,000

-400,000 600,000 600,000 600,000 600,000 1,000,000

204,000 204,000 204,000 204,000 340,000

-400,000 396,000 396,000 396,000 396,000 660,000

—————————————————————————————————————————————— Net Present Value at 18%:

$953,757

—————————————————————————————————————————————— Notes:

Annual Lease Payment: MARR = 18% Tax Rate 34%

400,000

——————————————————————————————————————————————

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PizzaCo Lease Payments Chilled Water System Manufacturer

Purchase Amount

Leased Equipment

Finance Company

Equipment

Figure 25.12 Resource Flow Diagram for a Capital Lease. 25.4.5.5 The Synthetic Lease A synthetic lease is a “hybrid” lease that combines aspects of a true lease and a capital lease. Through careful structuring and planning, the synthetic lease appears as an operating lease for accounting purposes (enables the Host to have off-balance sheet financing), yet also appears as a capital lease for tax purposes (to obtain depreciation for tax benefits). Consult your local financing expert to learn more about synthetic leases; they must be carefully structured to maintain compliance with the associated tax laws. With most types of leases, loans and bonds the monthly payments are fixed, regardless of the equip-

ment’s utilization, or performance. However, shared savings agreements can be incorporated into certain types of leases. 25.4.6 Performance Contracting Performance contracting is a unique arrangement that allows the building owner to make necessary improvements while investing very little money upfront. The contractor usually assumes responsibility for purchasing and installing the equipment, as well as maintenance throughout the contract. But the unique aspect of performance contracting is that the contractor is paid based on the performance of the installed equipment. Only after the installed equipment actually reduces expenses does the contractor get paid. Energy service companies (ESCOs) typically serve as contractors within this line of business. Unlike most loans, leases and other fixed payment arrangements, the ESCO is paid based on the performance of the equipment. In other words, if the finished product doesn’t save energy or operational costs, the host doesn’t pay. This aspect removes the incentive to “cut corners” on construction or other phases of the project, as with bid/spec contracting. In fact, often there is an incentive to exceed savings estimates. For this reason, performance contracting usually entails a more “facility-

Table 25.10 Economic Analysis for a Capital Lease. —————————————————————————————————————————————— EOY

Savings

Depr.

Payments Principal Interest

Total

Principal Taxable Outstanding Income

Tax

ATCF

—————————————————————————————————————————————— 0 1 2 3 4 5 5*

950,000 950,000 950,000 950,000 950,000 1,200,000

357,250 612,250 437,250 312,250 111,625 669,375

619,218 393,524 440,747 493,637 552,874

0 225,694 178,471 125,581 66,345

619,218 619,218 619,218 619,218 619,218

1,880,782 1,487,258 1,046,511 552,874 0

367,056 159,279 387,169 571,405 838,375 530,625

-619,218 124,799 54,155 131,637 194,278 285,048 180,413

205,983 276,627 199,145 136,503 664,953 1,019,588

—————————————————————————————————————————————— 2,500,000 Net Present Value at 18%:

$681,953

—————————————————————————————————————————————— Notes:

Total Lease Amount: 2,500,000 However, Since the payments are in advance, the first payment is analogous to a Down-Payment Thus the actual amount borrowed is only = 2,500,000 - 619,218 = 1,880,782 Lease Finance Rate: 12% MARR 18% Tax Rate 34% MACRS Depreciation for 7-Year Property, with half-year convention at EOY 5 Accounting Book Value at end of year 5: 669,375 Estimated Market Value at end of year 5: 1,200,000 EOY 5* illustrates the Equipment Sale and Book Value Taxable Income: = (Market Value - Book Value) = (1,200,000 - 669,375) = $530,625

——————————————————————————————————————————————

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wide” scope of work (to find extra energy savings), than loans or leases on particular pieces of equipment. With a facility-wide scope, many improvements can occur at the same time. For example, lighting and air conditioning systems can be upgraded at the same time. In addition, the indoor air quality can be improved. With a comprehensive facility management approach, a “domino-effect” on cost reduction is possible. For example, if facility improvements create a safer and higher quality environment for workers, productivity could increase. As a result of decreased employee absenteeism, the workman’s compensation cost could also be reduced. These are additional benefits to the facility. Depending on the host’s capability to manage the risks (equipment performance, financing, etc.) the host will delegate some of these responsibilities to the ESCO. In general, the amount of risk assigned to the ESCO is directly related to the percent savings that must be shared with the ESCO. For facilities that are not in a good position to manage the risks of an energy project, performance contracting may be the only economically feasible implementation method. For example, the US Federal Government used performance contracting to upgrade facilities when budgets were being dramatically cut. In essence, they “sold” some of their future energy savings to an ESCO, in return for receiving new equipment and efficiency benefits. In general, performance contracting may be the best option for facilities that: •

are severely constrained by their cash flows;

•

have a high cost of capital;

•

don’t have sufficient resources, such as a lack of in-house energy management expertise or an inadequate maintenance capacity*;

•

are seeking to reduce in-house responsibilities and focus more on their core business objectives; or

•

are attempting a complex project with uncertain reliability or if the host is not fully capable of managing the project. For example, a lighting retrofit has a high probability of producing the expected cash flows, whereas a completely new process does not have

*Maintenance capacity represents the ability that the maintenance personnel will be able to maintain the new system. It has been shown that systems fail and are replaced when maintenance concerns are not incorporated into the planning process. See Woodroof, E. (1997) “Lighting Retrofits: Don’t Forget About Maintenance,” Energy Engineering, 94(1) pp. 59-68.

the same “time-tested” reliability. If the in-house energy management team cannot manage this risk, performance contracting may be an attractive alternative. Performance contracting does have some drawbacks. In addition to sharing the savings with an ESCO, the tax benefits of depreciation and other economic benefits must be negotiated. Whenever large contracts are involved, there is reason for concern. One study found that 11% of customers who were considering EMPs felt that dealing with an ESCO was too confusing or complicated.14 Another reference claims, “with complex contracts, there may be more options and more room for error.”15 Therefore, it is critical to choose an ESCO with a good reputation and experience within the types of facilities that are involved. There are a few common types of contracts. The ESCO will usually offer the following options: • • • •

guaranteed fixed dollar savings; guaranteed fixed energy (MMBtu) savings; a percent of energy savings; or a combination of the above.

Obviously, facility managers would prefer the options with “guaranteed savings.” However this extra security (and risk to the ESCO) usually costs more. The primary difference between the two guaranteed options is that guaranteed fixed dollar savings contracts ensure dollar savings, even if energy prices fall. For example, if energy prices drop and the equipment does not save as much money as predicted, the ESCO must pay (out of its own pocket) the contracted savings to the host. Percent energy savings contracts are agreements that basically share energy savings between the host and the ESCO. The more energy saved, the higher the revenues to both parties. However, the host has less predictable savings and must also periodically negotiate with the ESCO to determine “who saved what” when sharing savings. There are numerous hybrid contracts available that combine the positive aspects of the above options. 25.4.6.1 Application to the Case Study PizzaCo would enter into a hybrid contract; percent energy savings/guaranteed arrangement. The ESCO would purchase, install and operate a highly efficient chilled water system. The ESCO would guarantee that PizzaCo would save the $1,000,000 per year, but PizzaCo would pay the ESCO 80% of the savings. In this way, PizzaCo would not need to invest any money, and would simply collect the net savings of $200,000 each year. To avoid periodic negotiations associated with shared savings

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agreements, the contract could be worded such that the ESCO will provide guaranteed energy savings worth $200,000 each year. With this arrangement, there are no depreciation, interest payments or tax-benefits for PizzaCo. However, PizzaCo receives a positive cash flow with no investment and little risk. At the end of the contract, the ESCO removes the equipment. At the end of most performance contracts, the host usually acquires or purchases the equipment for fair market value. However, for this case study, the equipment was removed to make a consistent comparison with the other financial arrangements. Figure 25.13 illustrates the transactions between the parties. Table 25.11 presents the economic analysis for performance contracting. Note that Table 25.11 is slightly different from the other tables in this chapter: Taxable Income = Savings – Depreciation – ESCO Payments. 25.4.7 Summary Of Tax Benefits Table 25.12 summarizes the tax benefits of each financial arrangement presented in this chapter. 25.4.8 Additional Options Combinations of the basic financial arrangements can be created to enhance the value of a project. A sample of the possible combinations are described below. •

Third party financiers often cooperate with performance contracting firms to implement EMPs.

•

Utility rebates and government programs may provide additional benefits for particular projects.

•

Tax-exempt leases are available to government facilities.

PizzaCo ESCO Payments

Installs Equipment, Guarantees Savings

Equipment Chilled Water System Manufacturer

ESCO Purchase Amount Payments

Loan Bank/Finance Co.

Figure 25.13 Transactions for a Performance Contract.

•

Insurance can be purchased to protect against risks relating to equipment performance, energy savings, etc.

•

Some financial arrangements can be structured as non-recourse to the host. Thus, the ESCO or lessor would assume the risks of payment default. However, as mentioned before, profit sharing increases with risk sharing.

Attempting to identify the absolute best financial arrangement is a rewarding goal, unless it takes too long. As every minute passes, potential dollar savings are lost forever. When considering special grant funds, rebate programs or other unique opportunities, it is important to consider the lost savings due to delay.

Table 25.11 Economic Analysis of a Performance Contract. —————————————————————————————————————————————— EOY

Savings

Depr.

ESCO Payments

Total

Principal Outstanding

Taxable Income

Tax

ATCF

—————————————————————————————————————————————— 0 1 2 3 4 5

1,000,000 1,000,000 1,000,000 1,000,000 1,000,000

0 0 0 0 0

800,000 800,000 800,000 800,000 800,000

800,000 800,000 800,000 800,000 800,000

200,000 200,000 200,000 200,000 200,000 Net Present Value at 18%:

68,000 68,000 68,000 68,000 68,000

132,000 132,000 132,000 132,000 132,000 $412,787

—————————————————————————————————————————————— Notes:

ESCO purchases/operates equipment. Host pays ESCO 80% of the savings = $800,000. The contract could also be designed so that PizzaCo can buy the equipment at the end of year 5.

——————————————————————————————————————————————

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Table 25.12 Host’s Tax Benefits for each Arrangement. ————————————————————————————————————————— ARRANGEMENT

Depreciation Benefits

Interest Payments are Tax-Deductible

Total Payments are Tax-Deductible

————————————————————————————————————————— Retained Earnings Loan Bond Sell Stock Capital Lease True Lease Performance Contract

X X X X X

X X X X X

—————————————————————————————————————————

25.5 “PROS” & “CONS” OF EACH FINANCIAL ARRANGEMENT This section presents a brief summary of the “Pros” and “Cons” of each financial arrangement from the host’s perspective. Loan • • • •

•

“Pros”: host keeps all savings, depreciation & interest payments are tax-deductible, host owns the equipment, and the arrangement is good for long-term use of equipment “Cons”: host takes all the risk, and must install and manage project

Bond Has the same Pros/Cons as loan, and “Pro”: • good for government facilities, because they can offer a tax-free rate (that is lower, but considered favorable by investors) Sell Stock Has the same Pros/Cons as loan, and “Pro”: • selling stock could help the host achieve its target capital structure

• •

“Con”: dividend payments (unlike interest payments) are not tax-deductible, and dilutes company control

Use Retained Earnings Has the same Pros/Cons as loan, and “Pro”: • host pays no external interest charges. However retained earnings do carry an opportunity cost, because such funds could be invested somewhere at the MARR. •

“Con”: host loses tax-deductible benefits of interest charges

Capital Lease Has the same Pros/Cons as loan, and “Pro”: • Greater flexibility in financing, possible lower cost of capital with third-party participation True Lease “Pros”: • allows use of equipment, without ownership risks, • reduced risk of poor performance, service, equipment obsolescence, etc., • good for short-term use of equipment, an • entire lease payment is tax-deductible

• •

“Cons”: no ownership at end of lease contract, and no depreciation tax benefits

Performance Contract “Pros”: • allows use of equipment, with reduced installment/operational risks, and • reduced risk of poor performance, service, equipment obsolescence, etc., and

FINANCING ENERGY MANAGEMENT PROJECTS

•

• •

allows host to focus on its core business objectives “Cons”: potentially binding contracts, legal expenses, and increased administrative costs, and host must share project savings

25.5.1 Rules of Thumb When investigating financing options, consider the following generalities: Loans, bonds and other host-managed arrangements should be used when a customer has the resources (experience, financial support, and time) to handle the risks. Performance contracting (ESCO assumes most of the risk) is usually best when a customer doesn’t have the resources to properly manage the project. Remember that with any arrangement where the host delegates risk to another firm, the host must also share the savings. Leases are the “middle ground” between owning and delegating risks. Leases are very popular due to their tax benefits.

• • • •

• • •

True leases tend to be preferred when: the equipment is needed on a short-term basis; the equipment has unusual service problems that cannot be handled by the host; technological advances cause equipment to become obsolete quickly; or depreciation benefits are not useful to the lessee. Capital Leases are preferred when: the installation and removal of equipment is costly; the equipment is needed for a long time; or the equipment user desires to secure a “bargain purchase option.”

665

bol: ‹ Note that qualitative characteristics are generally “strategic” and are not associated with an exact dollar value.

‹

$

There are at least three types of characteristics that can influence which financial arrangement should be used for a particular EMP. These include facility characteristics, project characteristics and financial arrangement characteristics. In this section, quantitative characteristics are bulleted with this symbol: $. The qualitative characteristics are bulleted with this sym-

The facility’s current financial condition. Credit ratings and ability to obtain loans can determine whether certain financial arrangements are feasible.

‹ The experience and technical capabilities of inhouse personnel. Will additional resources (personnel, consultants, technologies, etc.) be needed to successfully implement the project? $

The facility’s ability to obtain rebates from the government, utilities, or other organizations. For example, there are Dept. of Energy subsidies available for DOE facilities.

$

The facility’s ability to obtain tax benefits. For example, government facilities can offer tax-exempt interest rates on bonds.

A few of the Project Characteristics include: $ The project’s economic benefits. Net Present Value, Internal Rate of Return and Simple Payback.

‹

The project’s complexity and overall risk. For example, a complex project that has never been done before has a different level of risk than a standard lighting retrofit.

‹ The project’s alignment with the facility’s longterm objectives. Will this project’s equipment be needed for long-term goals?

‹ 25.6 CHARACTERISTICS THAT INFLUENCE WHICH FINANCIAL ARRANGEMENT IS BEST

A few of the Facility Characteristics include: The long-term plans of facility. For example, is the facility trying to focus on core business objectives and outsourcing other tasks, such as EMPs?

The project’s cash flow schedule and the variance between cash flows. For example, there may be significant differences in the acceptability of a project based on when revenues are received.

A few of the Financial Arrangement Characteristics include: $ The economic benefit of a project using a particular financial arrangement. The Net Present Value and Internal Rate of Return can be influenced by the financial arrangement selected.

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‹ The impact on the corporate capital structure. For example, will additional debt be required to finance the project? Will additional liabilities appear on the firm’s balance sheet and impact the image of the company to investors?

‹

The flexibility of the financial arrangement. For example, can the facility manager alter the contract and payment terms in the event of revenue shortfall or changes in operational hours?

in the private sector, the facility manager should decide whether the project should be on or off the balance sheet. An off-balance sheet preference would lead back to the “true lease.” If the facility manager wants the project’s assets on the balance sheet, the Net Present Value (or other economic benefit indicator) can help determine which “host-managed” arrangement (loan, capital lease or cash) would be most lucrative.

25.8 CHAPTER SUMMARY 25.7 INCORPORATING STRATEGIC ISSUES WHEN SELECTING FINANCIAL ARRANGEMENTS Because strategic issues can be important when selecting financial arrangements, the facility manager should include them in the selection process. The following questions can help assess a facility manager’s needs. • • • • • •

Does the facility manager want to manage projects or outsource? Are net positive cash flows required? Will the equipment be needed for long-term needs? Is the facility government or private? If private, does the facility manager want the project’s assets on or off the balance sheet? Will operations be changing?

From the research experience, a Strategic Issues Financing Decision Tree was developed to guide facility managers to the financial arrangement which is most likely optimal. Figure 25.14 illustrates the decision tree, which is by no means a rule, but it embodies some general observations from the industry. Working the tree from the top to bottom, the facility manager should assess the project and facility characteristics to decide whether it is strategic to manage the project or outsource. If outsourced, the “performance contract” would be the logical choice.* If the facility manager wants to manage the project, the next step (moving down the tree) is to evaluate whether the project’s equipment will be needed for long or shortterm purposes. If short-term, the “true lease” is logical. If it is a long-term project, in a government facility, the “bond” is likely to be the best option. If the facility is *It should be noted that a performance contract could be structured using leases and bonds.

It is clear that knowing the strategic needs of the facility manager is critical to selecting the best arrangement. There are practically an infinite number of financial alternatives to consider. This chapter has provided some information on the basic financial arrangements. Combining these arrangements to construct the best contract for your facility is only limited by your creativity. 25.9 GLOSSARY Capitalize To convert a schedule of cash flows into a principal amount, called capitalized value, by dividing by a rate of interest. In other words, to set aside an amount large enough to generate (via interest) the desired cash flows forever. Capital or Financial Lease Lease that under Statement 13 of the Financial Accounting Standards Board must be reflected on a company’s balance sheet as an asset and corresponding liability. Generally, this applies to leases where the lessee acquires essentially all of the economic benefits and risks or the leased property. Depreciation The amortization of fixed assets, such as plant and equipment, so as to allocate the cost over their depreciable life. Depreciation reduces taxable income, but is not an actual cash flow. Energy Service Company (ESCO) Company that provides energy services (and possibly financial services) to an energy consumer. Host The building owner or facility that uses the equipment. Lender Individual or firm that extends money to a borrower

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EMP CHARACTERISTICS

FACILITY CHARACTERISTICS In-house Staff Experience

Proj. Complexity Proj. Reliability Long-term Equip.

Mgmt.’s Strategic Focus Capital Willing to Commit

Manage or Outsource

Cash Flow Schedule O

M

Perf. Conf.

Host-managed Arrangements

Time Frame long

short True Lease

Govt. or Private Govt.

Bond

Private

Off Balance Sheet

On or Off Balance Sheet

QUANTITATIVE FACTORS

On Balance Sheet Int. Rate NPV

Taxes Cash Flow Timing

Loan, Cap. Lease

Figure 25.14 Strategic Issues Financing Decision Tree. with the expectation of being repaid, usually with interest. Lenders create debt in the form of loans or bonds. If the borrower is liquidated, the lender is paid off before stockholders receive distributions. Lessee The renter. The party that buys the right to use equipment by making lease payments to the lessor. Lessor The owner of the leased equipment. Line of Credit An informal agreement between a bank and a borrower indicating the maximum credit the bank will extend.

A line of credit is popular because it allows numerous borrowing transactions to be approved without the reapplication paperwork. Liquidity Ability of a company to convert assets into cash or cash equivalents without significant loss. For example, investments in money market funds are much more liquid than investments in real estate. Leveraged Lease Lease that involves a lender in addition to the lessor and lessee. The lender, usually a bank or insurance company, puts up a percentage of the cash required to purchase the asset, usually more than half. The balance is put up

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by the lessor, who is both the equity participant and the borrower. With the cash the lessor acquires the asset, giving the lender (1) a mortgage on the asset and (2) an assignment of the lease and lease payments. The lessee then makes periodic payments to the lessor, who in turn pays the lender. As owner of the asset, the lessor is entitled to tax deductions for depreciation on the asset and interest on the loan. MARR (Minimum Attractive Rate of Return) MARR is the “hurdle rate” for projects within a company. MARR is used to determine the NPV; the annual after-tax cash flow is discounted at MARR (which represents the rate the company could have received with a different project). Net Present Value (NPV) As the saying goes, “a dollar received next year is not worth as much as a dollar today.” The NPV converts the worth of that future dollar into what is worth today. NPV converts future cash flows by using a given discount rate. For example, at 10%, $1,000 dollars received one year from now is worth only $909.09 dollars today. In other words, if you invested $909.09 dollars today at 10%, in one year it would be worth $1,000. NPV is useful because you can convert future savings cash flows back to “time zero” (present), and then compare to the cost of a project. If the NPV is positive, the investment is acceptable. In capital budgeting, the discount rate used is called the hurdle rate and is usually equal to the incremental cost of capital. “Off-Balance Sheet” Financing Typically refers to a True Lease, because the assets are not listed on the balance sheet. Because the liability is not on the balance sheet, the Host appears to be financially stronger. However, most large leases must be listed in the footnotes of financial statements, which reveals the “hidden assets.”

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the common stock dividends. Preferred stock doesn’t ordinarily carry voting rights. Project Financing A type of arrangement, typically meaning that a Single Purpose Entity (SPE) is constructed. The SPE serves as a special bank account. All funds are sent to the SPE, from which all construction costs are paid. Then all savings cash flows are also distributed from the SPE. The SPE is essentially a mini-company, with the sole purpose of funding a project. Secured Loan Loan that pledges assets as collateral. Thus, in the event that the borrower defaults on payments, the lender has the legal right to seize the collateral and sell it to pay off the loan. True Lease or Operating Lease or Tax-Oriented Lease Type of lease, normally involving equipment, whereby the contract is written for considerably less time than the equipment’s life and the lessor handles all maintenance and servicing; also called service lease. Operating leases are the opposite of capital leases, where the lessee acquires essentially all the economic benefits and risks of ownership. Common examples of equipment financed with operating leases are office copiers, computers, automobiles and trucks. Most operating leases are cancelable. WACC (Weighted Average Cost of Capital) The firm’s average cost of capital, as a function of the proportion of different sources of capital: Equity, Debt, Preferred Stock, etc. For example, a firm’s target capital structure is: Capital Source Debt Common Equity Preferred Stock

Weight (wi) 30% 60% 10%

Par Value or Face Value Equals the value of the bond at maturity. For example, a bond with a $1,000 dollar par value will pay $1,000 to the issuer at the maturity date.

and the firm’s costs of capital are: before tax cost of debt = kd cost of common equity = ks cost of preferred stock = kps

Preferred Stock A hybrid type of stock that pays dividends at a specified rate (like a bond), and has preference over common stock in the payment of dividends and liquidation of assets. However, if the firm is financially strained, it can avoid paying the preferred dividend as it would

Then the weighted average cost of capital will be: WACC= wdkd(1-T) + wsks +wpskps

= 10% = 15% = 12%

where wi = weight of Capital Sourcei T = tax rate = 34% After-tax cost of debt = kd(1-T)

FINANCING ENERGY MANAGEMENT PROJECTS

Thus, WACC= (.3)(.1)(1-.34) +(.6)(.15) + (.1)(.12) WACC= 12.18% References 1. Wingender, J. and Woodroof, E., (1997) “When Firms Publicize Energy Management Projects Their Stock Prices Go Up: How High?—As Much as 21.33% within 150 days of an Announcement,” Strategic Planning for Energy and the Environment, Vol. 17(1), pp. 38-51. 2. U.S. Department of Energy, (1996) “Analysis of Energy-Efficiency Investment Decisions by Small and Medium-Sized Manufacturers,” U.S. DOE, Office of Policy and Office of Energy Efficiency and Renewable Energy, pp. 37-38. 3. Woodroof, E. and Turner, W. (1998), “Financial Arrangements for Energy Management Projects,” Energy Engineering 95(3) pp. 23-71. 4. Sullivan, A. and Smith, K. (1993) “Investment Justification for U.S. Factory Automation Projects,” Journal of the Midwest Finance Association, Vol. 22, p. 24. 5. Fretty, J. (1996), “Financing Energy-Efficient Upgraded Equipment,” Proceedings of the 1996 International Energy and Environmental Congress, Chapter 10, Association of Energy Engineers.

669 6. Pennsylvania Energy Office, (1987) The Pennsylvania Life Cycle Costing Manual. 7. United States Environmental Protection Agency (1994). ProjectKalc, Green Lights Program, Washington DC 8. Tellus Institute, (1996), P2/Finance version 3.0 for Microsoft Excel Version 5, Boston MA. 9. Woodroof, E. And Turner, W. (1999) “Best Ways to Finance Your Energy Management Projects,” Strategic Planning for Energy and the Environment, Summer 1999, Vol. 19(1) pp. 65-79. 10. Cooke, G.W., and Bomeli, E.C., (1967), Business Financial Management, Houghton Mifflin Co., New York. 11. Wingender, J. and Woodroof, E., (1997) “When Firms Publicize Energy Management Projects: Their Stock Prices Go Up,” Strategic Planning for Energy and the Environment, 17 (1) pp. 38-51. 12. Sharpe, S. and Nguyen, H. (1995) “Capital Market Imperfections and the Incentive to Lease,” Journal of Financial Economics, 39(2), p. 271-294. 13. Schallheim, J. (1994), Lease or Buy?, Harvard Business School Press, Boston, p. 45. 14. Hines, V. (1996),”EUN Survey: 32% of Users Have Signed ESCO Contracts,” Energy User News 21(11), p.26. 15. Coates, D.F. and DelPonti, J.D. (1996), “Performance Contracting: a Financial Perspective” Energy Business and Technology Sourcebook, Proceedings of the 1996 World Energy Engineering Congress, Atlanta. p. 539-543.

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CHAPTER 26

COMMISSIONING FOR ENERGY MANAGEMENT DAVID E. CLARIDGE Professor Mechanical Engineering Department Texas A&M University MINGSHENG LIU Associate Professor Architectural Engineering University of Nebraska - Lincoln W.D. TURNER Professor Mechanical Engineering Department Texas A&M University

26.1 INTRODUCTION TO COMMISSIONING FOR ENERGY MANAGEMENT Commissioning an existing building has been shown to be a key energy management activity over the last decade, often resulting in energy savings of 10%, 20% or sometimes 30% without significant capital investment. Commissioning is more often applied to new buildings today than to existing buildings, but the energy manager will have more opportunities to apply the process to an existing building as part of the overall energy management program. Hence, this chapter emphasizes commissioning applied to existing buildings, but also provides some commissioning guidance for the energy manager who is involved in a construction project. Commissioning an existing building provides several benefits in addition to being an extremely effective energy management strategy. It typically provides an energy payback of one to three years. In addition, building comfort is improved, systems operate better and maintenance cost is reduced. Commissioning measures typically require no capital investment, though the process often identifies maintenance that is required before the commissioning can be completed. Potential capital upgrades or retrofits are often identified during the commissioning activities, and knowledge gained during the process permits more accurate quantification of benefits than is possible with a typical audit. Involve671

ment of facilities personnel in the process can also lead to improved staff technical skills. This chapter is intended to provide the energy manager with the information needed to make the decision to conduct an in-house commissioning program or to select and work with an outside commissioning provider. There is no single definition of commissioning for an existing building, or for new buildings, so several widely used commissioning definitions are given. The commissioning process used by the authors in existing buildings is described in some detail, and common commissioning measures and commissioning resources are described so the energy manager can choose how to implement a commissioning program. Monitoring and verification is very important to a successful commissioning program. Some commissioning specific M&V issues are discussed, particularly the role of M&V in identifying the need for follow-up commissioning activities. Commissioning a new building is described from the perspective of the energy manager. Three case studies illustrate different applications of the commissioning process as part of the overall energy management program.

26.2 COMMISSIONING DEFINITIONS To commission a navy ship refers to the order or process that makes it completely ready for active duty. Over the last two decades, the term has come to refer to the process that makes a building or some of its systems completely ready for use. In the case of existing buildings, it generally refers to a restoration or improvement in the operation or function of the building systems. 26.2.1 New Building Commissioning ASHRAE defines building commissioning as: “the process of ensuring systems are designed, installed, functionally tested, and operated in conformance with the design intent. Commissioning begins with planning and includes design, construction, start-up, acceptance, and training and can be applied throughout the life of the building. Furthermore, the commissioning process encompasses and coordinates the traditionally separate functions of systems documentation, equipment start-

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up, control system calibration, testing and balancing, and performance testing.”1 This guideline was restricted to new buildings, but it later became evident that while initial start-up problems were not an issue in older buildings, most of the other problems that commissioning resolved were even more prevalent in older systems. 26.2.2 Recommissioning Recommissioning refers to commissioning a building that has already been commissioned at least once. After a building has been commissioned during the construction process, recommissioning ensures that the building continues to operate effectively and efficiently. Buildings, even if perfectly commissioned, will normally drift away from optimum performance over time, due to system degradation, usage changes, or failure to correctly diagnose the root cause of comfort complaints. Therefore, recommissioning normally reapplies the original commissioning procedures in order to keep the building operating according to design intent or it may modify them for current operating needs. Optimally, recommissioning becomes part of a facility’s continuing O&M program. There is not yet a consensus on recommissioning frequency, but some consider that it should occur every 3 to 5 years. If there are frequent build-outs or changes in building use, recommissioning should be applied more often.2 26.2.3 Retrocommissioning Retrocommissioning is the first-time commissioning of an existing building. Many of the steps in the retrocommissioning process are similar to those for commissioning. Retrocommissioning, however, occurs after construction, as an independent process, and its focus is usually on energy-using equipment such as mechanical equipment and related controls. Retrocommissioning may or may not bring the building back to its original design intent, since the usage may have changed or the original design documentation may no longer exist.3 26.2.4 Continuous Commissioning®45 Continuous Commissioning (CCSM) is an ongoing process to resolve operating problems, improve comfort, optimize energy use, and identify retrofits for existing commercial and institutional buildings and central plant facilities. CC focuses on improving overall system control and operations for the building, as it is currently utilized, and on meeting existing facility needs. CC is much more than an operations and maintenance program. It is not intended to ensure that a building’s systems function as originally designed, but it ensures

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that the building and its systems operate optimally to meet the current uses of the building. As part of the CC process, a comprehensive engineering evaluation is conducted for both building functionality and system functions. Optimal operational parameters and schedules are developed based on actual building conditions and current occupancy requirements.

26.3 THE COMMISSIONING PROCESS IN EXISTING BUILDINGS There are multiple terms that describe the commissioning process for existing buildings as noted in the previous section. Likewise, there are many adaptations of the process itself. The same practitioner will implement the process differently in different buildings, based on the budget and the owner requirements. The process described here is the process used by the chapter authors when the owner wants a thorough commissioning job. The terminology used will refer to the continuous commissioning process, but many of the steps are the same for retrocommissioning or recommissioning. The model described assumes that a commissioning provider is involved, since that is normally the case. Some (or all) of the steps may be implemented by the facility staff if they have the expertise and adequate staffing levels to take on the work. CC focuses on improving overall system control and operations for the building, as it is currently utilized, and on meeting existing facility needs. It does not ensure that the systems function as originally designed, but ensures that the building and systems operate optimally to meet the current requirements. During the CC process, a comprehensive engineering evaluation is conducted for both building functionality and system functions. The optimal operational parameters and schedules are developed based on actual building conditions and current occupancy requirements. An integrated approach is used to implement these optimal schedules to ensure practical local and global system optimization and persistence of the improved operation schedules. 26.3.1 Commissioning Team The CC team consists of a project manager, one or more CC engineers and CC technicians, and one or more designated members of the facility operating team. The primary responsibilities of the team members are shown in Table 26.1. The project manager can be an owner representative or a CC provider representative. It is essential that the engineers have the qualifications and experience to perform the work specified in the

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table. The designated facility team members generally include at least one lead HVAC technician and an EMCS operator or engineer. It is essential that the designated members of the facility operating team actively participate in the process and be convinced of the value of the measures proposed and implemented, or operation will rapidly revert to old practices. 26.3.2 CC Process The CC process consists of two phases. The first phase is the project development phase that identifies the buildings and facilities to be included in the project and develops the project scope. At the end of this phase, the CC scope is clearly defined and a CC contract is signed as described in Section 26.3.2.1. The second phase implements CC and verifies project performance through the six steps outlined in Figure 26.1 and described in Section 26.3.2.2. 26.3.2.1 Phase 1: Project Development Step 1: Identify Buildings or Facilities Objective: Screen potential CC candidates with minimal effort to identify buildings or facilities that will receive a CC audit. The CC candidate can be a building, an

entire facility, or a piece of equipment. If the building is part of a complex or campus, it is desirable to select the entire facility as the CC candidate since one mechanical problem may be rooted in another part of the building or facility. Approach: The CC candidates can be selected based on one or more of the following criteria: • The candidate provides poor thermal comfort • The candidate consumes excessive energy, and/or • The design features of the facility HVAC systems are not fully used. If one or more of the above criteria fits the description of the facility, it is likely to be a good candidate for CC. CC can be effectively implemented in buildings that have received energy efficiency retrofits, in newer buildings, and in existing buildings that have not received energy efficiency upgrades. In other words, virtually any building can be a potential CC candidate. The CC candidates can be selected by the building owner or the CC provider. However, the building owner is usually in the best position to select the most promising candidates because of his or her knowledge of the facility operation and costs. The CC provider

Table 26.1 Commissioning team members and their primary responsibilities. —————————————————————————————————————————————— Team Member(s)

Primary Responsibilities

—————————————————————————————————————————————— Project Manager

1. 2.

Coordinate the activities of building personnel and the commissioning team Schedule project activities

—————————————————————————————————————————————— CC Engineer(s)

1. 2. 3. 4. 5. 6. 7. 8.

Develop metering and field measurement plans Develop improved operational and control schedules Work with building staff to develop mutually acceptable implementation plans Make necessary programming changes to the building automation system Supervise technicians implementing mechanical systems changes Project potential performance changes and energy savings Conduct an engineering analysis of the system changes Write the project report

—————————————————————————————————————————————— Designated Facility Staff

1. 2. 3. 4. 5.

Participate in the initial facility survey Provide information about problems with facility operation Suggest commissioning measures for evaluation Approve all CC measures before implementation Actively participate in the implementation process

—————————————————————————————————————————————— CC Technicians

1. 2.

Conduct field measurements Implement mechanical, electrical, and control system program modifications and changes, under the direction of the project engineer

——————————————————————————————————————————————

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An experienced engineer should review this information and determine the potential of the CC process to improve comfort and reduce energy cost. The CC projects often improve building comfort and reduce building energy consumption at the same time. However, some of the CC measures may increase building energy consumption in order to satisfy room comfort and indoor air requirements. For example, providing building minimum outside air will certainly increase the cooling energy consumption during summer and heating consumption during winter compared to operating the building with no outside air. If the potential justifies a CC audit, a list of preliminary commissioning measures for evaluation in a CC audit should be developed. If the owner is interested in proceeding at this point, a CC audit may be performed. Step 2: Perform CC Audit and Develop Project Scope Objectives: The objectives of this step are to: • Define owner’s requirements • Check the availability of in-house technical support such as CC technicians • Identify major CC measures • Estimate potential savings from CC measures and cost to implement

Figure 26.1 Outline of Phase II of the CC Process: Implementation & Verification

should then perform a preliminary analysis to check the feasibility of using the CC process on candidate facilities before performing a CC audit. The following information is needed for the preliminary assessment: • Monthly utility bills (both electricity and gas) for at least 12 months (actual bills preferable to a table of historic energy and demand data because meter reading dates are needed) • General building information: size, function, major equipment, and occupancy schedules • O&M records, if available • Description of any problems in the building, such as thermal comfort, indoor air quality, moisture, or mildew.

Approach: The owner’s representative, the CC project manager and the CC project engineer will meet. The expectations and interest of the building owner in comfort improvements, utility cost reductions, and maintenance cost reductions will be discussed and documented. The availability and technical skills of in-house technicians will be discussed. After this discussion, a walkthrough must be conducted to identify the feasibility of the owner expectations for comfort performance and improved energy performance. During the walkthrough, the CC engineer and project manager will identify major CC measures applicable to the building. An in-house technician should participate in this walk-through to provide a local operational perspective and input. The project engineer estimates the potential savings and the commissioning cost and together with the project manager prepares the CC audit report that documents these findings as well as the owner expectations. Special Considerations: • A complete set of mechanical and control system design documentation is needed •

The CC engineer and technician will make preliminary measurements of key equipment operating parameters during the walk-through

COMMISSIONING FOR ENERGY MANAGEMENT

•

Any available measured whole building level or sub-metered energy consumption data from standalone meters or the building automation system should be utilized while preparing the report.

A CC audit report must be completed that lists and describes preliminary CC measures, the estimated energy savings from implementation, and the cost of carrying out the CC process on the building(s) evaluated in the CC audit. There may be more than one iteration or variation at each step described here, but once a contract is signed, the process moves to Phase 2 as detailed below. 26.3.2.2 Phase 2: CC Implementation and Verification Step 1: Develop CC plan and form the project team Objectives: • Develop a detailed work plan •

Identify the entire project team

•

Clarify the duties of each team member

Approach: The CC project manager and project engineer develop a detailed work plan for the project, that includes major tasks, their sequence, time requirements, and technical requirements. The work plan is then presented to the building owner or representative(s) at a meeting attended by any additional CC engineers and/ or technicians on the project team. During the meeting, the owner contact personnel and in-house technicians who will work on the project should be identified. If in-house technicians are going to conduct measurements and system adjustments, additional time should be included in the schedule unless they are going to be dedicated full time to the CC project. Typically, in-house technicians must continue their existing duties and cannot devote full time to the CC effort, which results in project delays. In-house staff may also require additional training. The work plan may need to be modified, depending on the availability and skill levels of in-house staff utilized. Special Issues: • Availability of funding to replace/repair parts found broken • Time commitment of in-house staff • Training needs of in-house staff Deliverable: CC Report Part I—CC Plan that includes project scope and schedule, project team, and task duties of each team member.

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Step 2: Develop performance baselines Objectives: • Document existing comfort conditions • Document existing system conditions • Document existing energy performance Approach: Document all known comfort problems in individual rooms resulting from too much heating, cooling, noise, humidity, odors (especially from mold or mildew), or lack of outside air. Also, identify and document any HVAC system problems including: • Valve and damper hunting • Disabled systems or components • Operational problems • Frequently replaced parts An interview and walk-through may be required although most of this information is collected during the CC audit and Step 1. Room comfort problems should be quantified using hand held meters or portable data loggers. System and/or component problems should be documented based on interviews with occupants and technical staff in combination with field observations and measurements. Baseline energy models of building performance are necessary to document the energy savings after commissioning. The baseline energy models can be developed using one or more of the following types of data: • Short-term measured data obtained from data loggers or the EMCS system • Long-term hourly or 15-minute whole building energy data, such as whole-building electricity, cooling and heating consumption, and/or • Utility bills for electricity, gas, and/or chilled or hot water The whole-building energy baseline models normally include whole building electricity, cooling energy, and heating energy models. These models are generally expressed as functions of outside air temperature since both heating and cooling energy are normally weather dependent. Any component baseline models should be represented using the most relevant physical parameter(s) as the independent variable(s). For example, the fan motor power should be correlated with the fan airflow and pump motor energy consumption should be correlated with water flow. Short-term measured data are often the most cost effective and accurate if the potential savings of CC measures are independent of the weather. For example, a

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single true power measurement can be used to develop the baseline fan energy consumption if the pulley is to be changed in a constant air volume system. Short-term data are useful for determining the baseline for specific pieces of equipment, but are not reliable for baselining overall building energy use. They may be used with calibrated simulation to obtain plausible baselines when no longer term data is available. Long-term measurements are normally required since potential savings of CC measures are weather dependent. These measurements provide the most convincing evidence of the impact of CC projects. Longterm data also help in continuing to diagnose system faults during ongoing CC. Although more costly than short-term measured data, long-term data often produces additional savings making them the preferred data type. For example, unusual energy consumption patterns can be easily identified using long-term shortinterval measured data. “Fixing” these unusual patterns can result in significant energy savings. Generally speaking, long-term interval data for electricity, gas, and thermal usage are preferred. Utility bills may be used to develop the energy use baselines if the CC process will result in energy savings that are a significant fraction (>15%) of baseline use and if the building functions and use patterns will remain the same throughout the project. The CC engineers should provide the metering options(s) that meet the project requirements to the building owner or representative. A metering method should be selected from the options presented by the CC engineer, and a detailed metering implementation plan developed. It may be necessary to hire a metering subcontractor if an energy information system is installed prior to implementation of the CC measures. More detailed information on savings determination is in contained the measurement and verification chapter of this handbook (Chapter 27). Special Considerations: • Use the maintenance log to help identify major system problems • Select a metering plan that suits the CC goals and the facility needs • Always consider and measure or obtain weather data as part of the metering plan • Keep meters calibrated. When the EMCS system is used for metering, both sensors and transmitters should be calibrated using field measurements Deliverables: CC Report Part II: Report on Current Building Performance, that includes current energy

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performance, current comfort and system problems, and metering plans if new meters are to be installed. Alternatively, if utility bills are used to develop the baseline energy models, the report should include baseline energy models. Step 3: Conduct system measurements and develop proposed CC measures Objectives: • Identify current operational schedules and problems • Develop solutions to existing problems • Develop improved operation and control schedules and setpoints • Identify potential cost effective energy retrofit measures Approach: The CC engineer should develop a detailed measurement cut-sheet for each major system. The cutsheet should list all the parameters to be measured, and all mechanical and electrical parts to be checked. The CC engineer should also provide measurement training to the technician if a local technician is used to perform system measurements. The CC technicians should follow the procedures on the cut-sheets to obtain the measurements using appropriate equipment. The CC engineer conducts an engineering analysis to develop solutions for the existing problems; and develops improved operation and control schedules and setpoints for terminal boxes, air handling units (AHUs), exhaust systems, water and steam distribution systems, heat exchangers, chillers, boilers, and other components or systems as appropriate. Cost effective energy retrofit measures can also be identified and documented during this step, if desired by the building owner. Special Considerations: • Trend main operational parameters using the EMCS and compare with the measurements from hand meters • Print out EMCS control sequences and schedules • Verify system operation in the building and compare to EMCS schedules Deliverable: CC Report Part III: Existing System Conditions. This report includes: • Existing control sequences and setpoints for all major equipment, such as AHU supply air temperature, AHU supply static pressures, terminal box minimum airflow and maximum airflow values, water loop differential pressure setpoints, and

COMMISSIONING FOR ENERGY MANAGEMENT

• • • •

equipment on/off schedules List of disabled control sequences and schedules List of malfunctioning equipment and control devices Engineering solutions to the existing problems and a list of repairs required Proposed improved control and operation sequences and schedules

Step 4: Implement CC measures Objectives: • Obtain approval for each CC measure from the building owner’s representative prior to implementation • Implement solutions to existing operational and comfort problems • Implement and refine improved operation and control schedules Approach: The CC project manager and project engineer should present the engineering solutions to existing problems and the improved operational and control schedules to the building owner’s representative in one or more meetings. The in-house operating staff should be invited to this meeting(s). All critical questions should be answered. It is important at this point to get “buy-in” and approval from both the building owner’s representative and the operating staff. The meeting(s) will decide the following issues: • Approval, modification or disapproval of each CC measure • Implementation sequence of CC measures • Implementation schedules CC implementation should start by solving existing problems. The existing comfort and difficult control problems are the first priority of the occupants, operating staff, and facility owner. Solving these problems improves occupant comfort and increases productivity. The economic benefits from comfort improvements are sometimes higher than the energy cost savings, though less easily quantified. The successful resolution of existing problems can also earn trust in the CC engineer from facility operating staff, facility management and the occupants. Implementation of the improved operation and control schedules should start at the end of the comfort delivery system, such as at the terminal boxes, and end with the central plant. This procedure provides benefits to the building occupants as quickly as possible. It also reduces the overall load on the system. If the process

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is reversed, the chiller plant is commissioned first. The chiller sequences are developed based on the current load. After the rest of the commissioning is complete, the chiller load may decrease by 30%, resulting in a need to revise the chiller operating schedules. The CC engineers should develop a detailed implementation plan that lists each major activity. The CC technician should follow this plan in implementing the measures. The CC engineers should closely supervise the implementation and refine the operational and control schedules as necessary. The CC engineers should also be responsible for the key software changes as necessary. Following implementation, the new operation and control sequences must be documented in a way that helps the building staff understand why they were implemented. Maintenance procedures for these measures should be provided. If any measures have not been implemented due to temporary impediments such as an out of stock part, recommendations for their future implementation should be included. Special Considerations: • Ensure that the owner’s technical representative understands each major measure • Encourage in-house technician involvement in the implementation and/or have them implement as many measures as possible • Document improvements in a timely manner. Deliverable: CC Report Part IV: CC Implementation. This report includes detailed documentation of implemented operation and control sequences, maintenance procedures for these measures, and recommendations for measures to be implemented in the future. Step 5: Document comfort improvements and preliminary energy savings Objectives: • Document improved comfort conditions • Document improved system conditions • Document preliminary energy savings Approach: The comfort measurements taken in Step 2 (Phase 2) should be repeated at the same locations under comparable conditions to determine impact on room conditions. The measured parameters, such as temperature and humidity, should be compared with the measurements from Step 2. The M&V procedures adopted in Step 2 should be used to determine the early post-CC energy performance.

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Energy performance should be compared under the same occupancy conditions and weather normalized. Special Considerations: • Savings analyses should follow accepted measurement and verification protocols such as the IPMVP • Comfort conditions should conform to appropriate guidelines/design documents such as ASHRAE Standard 55.

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the facility semi-annually. One year after CC implementation is complete, the CC engineer should write a project follow-up report that documents the first-year savings, recommendations or changes resulting from any consultation or site visits provided, and any recommendations to further improve building operations. Special Considerations: Operating personnel often have a high turnover rate, and it is important to train new staff members in the CC process and make sure they are aware of the reasons the CC measures were implemented Ongoing follow-up is essential if the savings are to be maintained at high levels over time.

Deliverable: CC Report, Part 5: Preliminary Measurement and Verification Report. This report includes results of detailed measurements of room conditions and energy consumption after CC activities, and any retrofit recommendations that may be provided. The room conditions should be compared with those from the pre-CC period. The projected annual energy savings should be determined according to the M&V approach adopted in Step 2.

Deliverable: Special CC Report, that documents measured first-year energy savings, results from first-year follow-up, recommendations for ongoing staff training, and a schedule of follow-up CC activities.

Step 6: Keep the commissioning continuous

26.3.3

Objectives: • Maintain improved comfort and energy performance • Provide measured annual energy savings. Approach: The CC engineers should review the system operation periodically to identify any operating problems and develop improved operation and control schedules as described below. The CC engineers should provide follow-up phone consultation to the operating staff as needed, supplemented by site visits. This will allow the operating staff to make wise decisions and maintain the savings and comfort in years to come. If long term measured data are available, the CC engineers should review the energy data quarterly to evaluate the need for a site visit. If the building energy consumption has increased, the CC engineers determine possible reasons and verify with facility operating staff. Once the problem(s) is identified, the CC engineer should visit the site, develop measures to restore the building performance, and supervise the facility staff in implementing the measures. If the CC engineer can remotely log onto the EMCS system, the CC engineer can check the existing system operation quarterly using the EMCS system. When a large number of operation and control measures are disabled, a site visit is necessary. If the CC engineer cannot evaluate the facility using long-term measured energy data and EMCS system information, the CC engineer should visit

Uses of Commissioning in the Energy Management Process Commissioning can be used as a part of the energy management program in several different ways. It can be used; • As a stand-alone measure • As a follow-up to the retrofit process • As an Energy Conservation Measure (ECM) in a retrofit program • To ensure that a new building meets or exceeds its energy performance goals 26.3.3.1 A stand-alone measure Commissioning is probably most often implemented in existing buildings because it is the most cost-effective step the owner can take to increase the energy efficiency of the building, generally offering a pay-back under three years, and often 1-2 years6. The CC process also provides a high level of understanding of the building and its operation, enabling retrofit recommendations developed as part of the CC process to be made with a high level of certainty. The load reductions resulting from implementation of the CC process may also, for example, enable use of a smaller high efficiency chiller. 26.3.3.2 A follow-up to the retrofit process CC has often been used to provide additional savings after a successful retrofit7,8 and an illustrative case study is provided in Section 26.4.3. It has also been used numerous times to make an under-performing retrofit meet or exceed the original expectations. The process

COMMISSIONING FOR ENERGY MANAGEMENT

was initially developed for these purposes as part of the Texas LoanSTAR program. 26.3.3.3 As an Energy Conservation Measure (ECM) in a retrofit program The rapid pay-back that generally results from CC may be used to lower the pay-back of a package of measures to enable inclusion of a desired equipment replacement that has a longer pay-back in a retrofit package9. This is illustrated by a case study in Section 26.3.4. In this approach the CC engineers conduct the CC audit in parallel with the retrofit audit conducted by the design engineering firm. Because the two approaches are different and look at different opportunities, it is very important to closely coordinate these two audits. For example, the CC engineer may determine a need for a variable frequency drive on a chilled water pump. This is a retrofit opportunity for the audit engineer and should be written up as a retrofit ECM. Similarly, the audit engineer may encounter a CC opportunity during the building walk-through audit, which should be reported to the CC engineer. 26.3.3.4 To ensure that a new building meets or exceeds its energy performance goals Commissioning is generally used for a new building to ensure that the systems work and provide comfort for the occupants with minimum start-up problems. It also has been found to reduce expensive change orders and other construction problems. It may also be used to significantly improve the efficiency of a new building by optimizing operation to meet its actual loads and uses instead of working to design assumptions10,11. The commissioning process has been described using an outside provider. It is certainly possible to perform commissioning using internal personnel when the needed skills are available on staff and these engineers and technicians can be assigned to the commissioning process. This is directly analogous to the retrofit process. Most energy audits and retrofit designs are performed by external consultants, but they can and are provided by internal personnel on occasion. 26.3.4 Case Study With CC As An ECM12 Prairie View A&M University is a 1.7 million square foot campus, with most buildings served by a central thermal plant. Electricity is purchased from a local electric co-op. University staff identified the need for a major plant equipment replacements on campus. They wished to use the Texas LoanSTAR program to finance the project. The LoanSTAR program finances energy efficiency upgrades

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for public buildings, requiring that the aggregate energy payback of all energy conservation measures (ECMs) financed be ten years or less. The program requires that participating state agencies meter all buildings/plants receiving the ECMs and implement a comprehensive M&V program. The cost of the detailed investment grade audit and the mandatory M&V can be rolled into the loan, but the simple payback must still meet the ten-year criterion. This typically means that the aggregate payback of the ECMs must be 8 to 8-1/2 years (without the audit and M&V costs included). Replacement of items such as chillers, cooling towers, and building automation systems typically have paybacks of considerably more than 10 years. Hence, they can only be included in a loan if packaged with low payback measures that bring the aggregate payback below 10 years. The university administration wanted to maximize the loan amount to get as much equipment replacement as possible. They also wanted to ensure that the retrofits work properly after they are installed. To maximize their loan dollars, they chose to include CC as an ECM. They also chose to include the audit and M&V costs in the loan to minimize up front costs. The LoanSTAR Program provides a brief walkthrough audit of the candidate buildings and plants. This audit is performed to determine whether there is sufficient retrofit potential to justify a more thorough investment grade audit. The CC audit is conducted in parallel with the retrofit audit conducted by the engineering design firm, when CC is to be included as an ECM. The two approaches look at different opportunities, but there can be some overlap, so it is very important to closely coordinate both audits. For example, the CC engineer may determine a need for a variable frequency drive on a chilled water pump. This is a retrofit opportunity for the audit engineer and should be written up as a retrofit ECM. Similarly, the audit engineer may encounter a CC opportunity during the building audit, which should be reported to the CC engineer. It is particularly important that the savings estimated by the audit team are not “double counted.” The area of greatest overlap in this case was the building automation system. Considerable care was taken not to mix improved EMCS operation with operational improvements determined by the CC engineer, so both measures received proper credit. The same design engineering firm conducted both the initial walk-through audit and the detailed, investment grade audit. ESL CC engineers likewise conducted an initial CC walk-through audit as well as the detailed CC audit. The CC measures identified included:

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hot and cold deck temperature resets extensive EMCS programming to avoid simultaneous heating and cooling air and water balancing duct static pressure resets sensor calibration/repair improved start/stop/warm-up/shutdown schedules

The CC engineers took the measurements required and collected data on building operation during the CC audit to perform a calibrated simulation on the major buildings. Available metered data and building EMCS data were also used. The CC energy savings were then written as an ECM and discussed with the design engineer. Any potential overlaps were removed. The combined ECMs were then listed, and the total savings determined. Table 26.2 summarizes the ECMs identified from the two audits. The CC savings were calculated to be $204,563, as determined by conducting calibrated simulation of 16 campus buildings and by engineering calculations of savings from improved loop pumping. No CC savings were claimed for central plant optimization. Those savings were all applied to ECM #7, although it seems likely that additional CC savings will accrue from this measure. The simple payback from CC is slightly under three years, making it by far the most cost effective of the ECMs to be implemented. The CC savings represent nearly 30% of the total project savings. Perhaps more importantly, CC accounted for 2/3 of the “surplus” savings dollars available to buy down the payback of the chillers and EMCS upgrade. Without CC as an ECM, the University would have had to choose which ECMs to delete, one chiller and the EMCS upgrades; or some combination of chillers and limited building EMCS upgrades to meet the ten-year payback criteria. With CC, however, the university was able to include all these hardware items, and still meet the tenyear payback.

26.4. COMMISSIONING MEASURES CC measures can be placed in two basic categories. The first category includes a number of long-time energy management measures that eliminate operation when it isn’t needed, or simply “shut it off if it isn’t needed.” A number of these measures are a bit more complex than simply turning it off, but all are widely recognized and practiced. However, opportunities to

implement some of these measures are often found, even in well-run facilities. These are discussed in some detail since most facility personnel can implement these measures. The second category of measures can broadly be categorized as implementing control practices that are optimized to the facility. These measures require a relatively high level of knowledge and skill to analyze the operation of a building, develop the optimal control sequences, and then implement them. These measures are presented in less detail, but references are provided for the reader who wishes to learn more. Some measures include the implementation of retrofits or new hardware in ways that are relatively new and innovative to provide rapid pay-back comparable to the other CC measures. These measures are sometimes considered as a separate category, but are not discussed to that level of detail in this chapter. 26.4.1 Eliminating Unnecessary Operation Commissioning begins with simple measures that are included in any good energy management program. Simple rules like shut off any system that isn’t needed are the beginning point of a good commissioning program as well as a good energy management program. 26.4.1.1 Remove Foot Heaters and Turn Off Desk Fans The presence of foot heaters and desk fans indicates an unsuitable working environment and wastes energy as well. To turn off foot heaters and desk fans, the following actions should be taken: • Adjust the individual zone temperature setpoint according to the occupant’s desires; • Balance zone airflow if foot heaters are used in a portion of the zone; • Adjust AHU supply air temperature and static pressure if the entire building is too cold or too hot • Repair existing mechanical and control problems, such as replacing diffusers of the wrong type and relocate return air grilles, to maintain a comfortable zone temperature Different people require different temperatures to feel comfortable. Some organizations, however, mandate the zone temperature setpoint for both summer and winter. This often leads to comfort complaints and negatively impacts productivity. The operating staff must place comfort as a priority and adjust the room temperature setpoint as necessary. Workers should be asked to dress appropriately during the summer and winter to maintain their individual comfort if setpoints are centrally mandated for a facility. Most complaints can be eliminated when the room temperature is within the range of ASHRAE’s recommended comfort zone.

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Table 26.2: Summary of Energy Cost Measures (ECMs)13 —————————————————————————————————————————————— Annual Savings ECM #

Electric kWh/yr

Electric Demand kW/yr

Gas MCF/yr

1,565,342

5,221

(820)

$94,669

$ 561,301

6.0

596,891

1,250

-0-

$33,707

$ 668,549

19.8

-0-

-0-

13,251

$58,616

$ 422,693

7.2

81,616

-0-

(44.6)

$ 3,567

$ 26,087

7.3

ECM

Cost Savings

Cost to Implement

Simple Payback

—————————————————————————————————————————————— #1

Lighting

#2

Replace Chiller #3

#3

Repair Steam System

#4

Install Motion Sensors

#5

Add 2 Bldgs. to CW Loop

557,676

7,050

-0-

$ 60,903

$ 508,565

8.4

#6

Add Chiller #4

599,891

1,250

-0-

$33,707

$ 668,549

19.8

#7

Primary/Secondary Pumping

1,070,207

-0-

-0-

$49,230

$ 441,880

9.0

—————————————————————————————————————————————— —————————————————————————————————————————————— —————————————————————————————————————————————— —————————————————————————————————————————————— —————————————————————————————————————————————— —————————————————————————————————————————————— —————————————————————————————————————————————— #8

Replace DX Systems

38,237

233

-0-

$ 2,923

$ 37,929

13.0

#9

Replace DDC/EMCS

2,969,962

670

2,736

$151,488

$2,071,932

13.7

#10

Continuous Commissioning

2,129,855

-0-

25,318

$204,563

$ 605,000

3.0

—————————————————————————————————————————————— —————————————————————————————————————————————— —————————————————————————————————————————————— Assessment Reports

$ 102,775

Metering

$ 157,700

M&V

$ 197,500

—————————————————————————————————————————————— —————————————————————————————————————————————— —————————————————————————————————————————————— 9,606,677

15,674

40,440

$693,373

$6,470,460

9.3

—————————————————————————————————————————————— 26.4.1.2 Turn off Heating Systems During Summer Heating is not needed for most buildings during the summer. When the heating system is on, hot water or steam often leaks through control valves, causes thermal comfort problems, and consumes excessive cooling and heating energy. To improve building comfort and decrease heating and cooling energy consumption, the following actions should be taken: • Turn off boilers or heat exchangers if the entire building does not need heating • Manually valve off heating and preheating coils if the heating system has to be on for other systems • Reset differential pressure of the hot water loop to a lower value to prevent excessive pressure on control valves during the summer • Trouble-shoot individual zones or systems, that have too many cold complaints • Do not turn heating off too early in the spring to avoid having to turn the system back on repeatedly

This measure may be applied in constant air volume systems in dry climates. When the reheat system is shut off, room comfort may be maintained by increasing supply air temperature. This measure is not suitable for other climates where the cooling coil leaving air temperature has to be controlled below 57°F to control room humidity levels. This simple measure results in significant energy savings as well as improved comfort in most buildings. Figure 26.2 compares the measured heating energy consumption before and after manually shutting off AHU heating valves in a building in Austin, Texas. This building has a floor area of 147,000 square feet with two dual duct VAV systems. Before closing the heating coil manual valves, the average daily steam consumption varied from a low of 0.2 MMBtu/hr to a high of about 0.28 MMBtu/hr. After the manual valves were closed, steam leakage was eliminated through the heating coil. The steam consumption immediately dropped to slightly above 0.10 MMBtu/hr. Since the manual valves in this building can stay closed for

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Figure 26.2 Comparison of measured daily average steam consumption before and after manually shutting off heating coil valves in the Business Administration Building at the University of Texas at Austin14. more than seven months, the annual steam savings are 756 MMBtu/yr. The same amount of chilled water will also be saved if the building remains at the same temperature, so the cooling energy savings will be 756 MMBtu/yr as well. The annual energy cost savings is $7,560 at an energy price of $5/MMBtu. This savings is not particularly large, but the only action required was shutting two manual valves. 26.4.1.3 Turn Off Systems During Unoccupied Hours If a building is not occupied at nights or on weekends, the HVAC system may often be turned off completely during these periods. With a properly designed warm-up/cool-down, building comfort can be maintained with significant energy savings. In a commercial or institutional building, office equipment and lighting make up a large portion (often 50% or more) of the electrical requirements. However, a significant portion of a building (15% or more) is normally unoccupied during office hours due to travel, meetings, vacations, and sick leave. Turning off systems during unoccupied hours results in significant energy savings without degrading occupant comfort. This measure can be achieved by the following actions: • Turn off lights, computers, printers, fax machines, desk fans, and other office equipment when leaving the office • Turn off lights and set back room thermostats after cleaning • Turn off AHUs at nights and on weekends. A schedule needs to be developed for each zone or air handling unit. Turning off the system too early in the evening or turning the system on too late in

• •

the morning may cause comfort problems. Conversely turning off a system too late in the evening and turning the system on too early in the morning may lose considerable savings Turn off the boiler hot water pump at night during the summer when AHUs are turned off Turn off chillers and chilled water pumps when free cooling is available or when AHUs are turned off

Figure 26.3 presents the measured building electricity consumption, excluding chiller consumption, before and after implementation of AHU and office equipment turn-off on nights and weekends in the Stephen F. Austin Building (SFA) in Austin, Texas. The Stephen F. Austin Building has 470,000 square feet of floor area with 22 dual duct AHUs. During the first phase of implementation, 16 AHUs were turned off from midnight to 4 a.m. weekdays and weekends. During the second phase, 22 AHUs were turned off from 11:00 p.m. to 5 a.m. during weekdays and weekends. In addition, during the second phase, all occupants were asked to turn off office equipment when they leave their office. The measured results show that the nighttime whole building electricity use decreased from 1,250 kW to 900 kW during the first phase. During the second phase, the nighttime minimum electricity decreased to 800 kW. It was observed that the daily peak electricity consumption after night shutdowns began is significantly lower than the base peak. For example, the lowest peak during the second phase is 1,833 kW, which is 8% lower

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Figure 26.3 Hourly whole building electricity consumption at the SFA Building before and after night shut down of AHUs was initiated15. than the base peak. The lower electricity peak indicates that some office equipment remained off during the daytime or the employees were more conscientious in turning off lights and equipment when they left the office. The annual energy cost savings, including electricity, heating, and cooling, were determined to be $100,000/yr using measured hourly data. 26.4.1.4 Slow Down Systems During Unoccupied/Lightly-Occupied Hours Most large buildings are never completely unoccupied. It is not uncommon to find a few people working regardless of the time of day. The zones that may be used during the weekends or at night, are also unpredictable. System shut down often results in complaints. Substantial savings can be achieved while maintaining comfort conditions in a building by an appropriate combination of the following actions: • Reset outside air intake to a lower level (0.05 cfm/ ft2) during these hours during hot summer and cold winter weather. Outside air can be reduced since there will be very few people in the building. Check outside and exhaust air balance to maintain positive building pressure • Reset the minimum airflow to a lower value, possibly zero, for VAV terminal boxes • Program constant volume terminal boxes as VAV boxes, and reset the minimum flow from the maximum to a lower value, possibly zero during unoccupied hours • Reset AHU static pressure and water loop differential pressure to lower values • Set supply air fan at a lower speed

These measures maintain building comfort while minimizing energy consumption. The savings are often comparable with the shut down option. Figure 26.4 presents the measured hourly fan energy consumption in the Education Building at the University of Texas at Austin. The Education Building has 251,000 ft2 of floor area with eight 50-hp AHUs that are operated on VFDs. Prior to the introduction of this measure, the motor control center (MCC) energy consumption was almost constant. The CC measure implemented was to set the fan speed at 30% at night and on weekends. The nighttime slow roll decreased the fan power from approximately 50 kW to approximately 25 kW while maintaining building comfort. 26.4.1.5 Limit Fan Speed During Warm Up and Cool Down Periods If nighttime shut down is implemented, warm-up is necessary during the winter and cool down is required during the summer. During warm-up and cool down periods, fan systems are often run at maximum speed since all terminal boxes require either maximum heating or maximum cooling. A simple fan speed limit can reduce fan power significantly. This principle may also be used in other systems, such as pumps. The following actions should be taken to achieve the fan energy savings: • Determine the optimal start up time using 80% (adjustable) fan capacity if automatic optimal start up is used • Set the fan speed limit at 80% (adjustable) manually and extend the warm up or cool down period

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Figure 26.4 Measured Post-CC hourly supply fan electricity consumption in the Education Building16.

by 25%. If the speed limit is set at another fractional value (x), determine the warm up period using the following equation: Texist Tn = ——— x •

Keep outside air damper closed during warm-up and cool-down periods

The fan energy savings increase significantly as the fan speed limit decreases. Figure 26.5 shows the theoretical fan power savings. When the fan speed limit is 50% of design fan speed, the potential fan energy savings are 75% of the fan energy even if the fan runs twice as long. The theoretical model did not consider the variable speed drive loss. The actual energy savings will normally be somewhat lower than the model projected value. Note that if the outside air damper cannot be closed tightly, extra thermal energy may be required to cool or warm up outside air that leaks through the damper. This factor should be considered when this measure is used. 26.4.2 Operational Efficiency Measures for AHU Systems Air handler systems normally condition and distribute air inside buildings. A typical AHU system consists of some combination of heating and cooling coils, supply and return air fans, filters, humidifiers, dampers, ductwork, terminal boxes, and associated safety and control devices, and may include an economizer. As the building load changes, AHUs change one or more of the following parameters to maintain building com-

fort: outside air intake, total airflow, static pressure, and supply air temperature and humidity. Both operating schedules and initial system set up, such as total airflow and outside airflow, significantly impact building energy consumption and comfort. The following ten major CC measures should be used to optimize AHU operation and control schedules: • • • • • • • • • •

Adjust total airflow for constant air volume systems Set minimum outside air intake correctly Improve static pressure set-point and schedule Optimize supply air temperatures Improve economizer operation and control Improve coupled control AHU operation Valve off hot air flow for dual duct AHUs during summer Install VFD on constant air volume systems Install airflow control for VAV systems Improve terminal box operation

26.4.2.1. Adjust Total Air Flow and Fan Head for Constant Air Volume Systems Air flow rates are significantly higher than required in most buildings primarily due to system oversizing. In some large systems, an oversized fan causes over-pressurization in terminal boxes. This excessive pressurization is the primary cause of room noise. The excessive airflow often causes excessive fan energy consumption, excessive heating and cooling energy consumption, humidity control problems, and excessive noise in terminal boxes18.

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Figure 26.5 Potential fan energy savings using fan speed limiting16. 26.4.2.2. Set Minimum Outside Air Intake Correctly Outside air intake rates are often significantly higher than design values in existing buildings due to lack of accurate measurements, incorrect design calculations and balancing, and operation and maintenance problems. Excessive outside air intake is caused by the mixed air chamber pressure being lower than the design value, by significant outside air leakage through the maximum outside air damper on systems with an economizer, by the minimum outside air intake being set to use minimum total airflow for a VAV system, or by lower than expected/designed occupancy. 26.4.2.3. Improve Static Pressure Setpoint and Schedule The supply air static pressure is often used to control fan speed and ensure adequate airflow to each zone. If the static pressure setpoint is lower than required, some zones may experience comfort problems due to lack of airflow. If the static pressure setpoint is too high, fan power will be excessive. In most existing terminal boxes, proportional controllers are used to maintain the airflow setpoint. When the static pressure is too high, the actual airflow is higher than its setpoint. The additional airflow depends on the setting of the control band. Field measurements19 have found that the excessive airflow can be as high as 20%. Excessive airflow can also occur when terminal box controllers are malfunctioning. For pressure dependent terminal boxes, high static pressure causes significant excessive airflow. Consequently, high static pressure often causes unnecessary heating and cooling energy consumption. A higher than necessary static pressure setpoint is also the primary reason for noise problems in buildings.

26.4.2.4. Optimize Supply Air Temperatures Supply air temperatures (cooling coil discharge air temperature for single duct systems; cold deck and hot deck temperatures for dual duct systems) are the most important operation and control parameters for AHUs. If the cold air supply temperature is too low, the AHU may remove excessive moisture during the summer using mechanical cooling. The terminal boxes must then warm the over-cooled air before sending it to each individual diffuser for a single duct AHU. More hot air is required in dual duct air handlers. The lower air temperature consumes more thermal energy in either system. If the cold air supply temperature is too high, the building may lose comfort control. The fan must supply more air to the building during the cooling season, so fan power will be higher than necessary. The goal of optimal supply air temperature schedules is to minimize combined fan power and thermal energy consumption or cost. Although developing optimal reset schedules requires a comprehensive engineering analysis, improved (near optimal) schedules can be developed based on several simple rules. Guidelines for developing improved supply air temperature reset schedules are available for four major types of AHU systems20. 26.4.2.5. Improve Economizer Operation and Control An economizer is designed to eliminate mechanical cooling when the outside air temperature is lower than the supply air temperature setpoint and decrease mechanical cooling when the outside air temperature is between the cold deck temperature and a high temperature limit, which is typically less than 70°F. Economizer control is often implemented so it controls mixed air

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temperature at the cold deck temperature or simply 55°F. This control algorithm is far from optimum. It may, in fact, actually increase the building energy consumption. The economizer operation can be improved using the following steps: 1.

Integrate economizer control with optimal cold deck temperature reset. It is tempting to ignore cold deck reset when the economizer is operating, since the cooling is free. However, cold deck reset normally saves significant heating.

2.

For a draw-through AHU, set the mixed air temperature 1°F lower than the cold deck temperature setpoint. For a blow-through unit, set the mixed air temperature at least 2°F lower than the supply air temperature setpoint. This will eliminate chilled water valve hunting and unnecessary mechanical cooling.

3.

For a dual duct AHU, the economizer should be disabled if the hot air flow is higher than the cold air flow since the heating energy penalty is then typically higher than cooling energy savings.

4.

5.

Set the economizer operating range as wide as possible. For dry climates, the economizer should be activated when the outside air temperature is between 30°F and 75°F, between 30°F and 65°F for normal climates, and between 30°F and 60°F for humid climates. When proper return and outside air mixing can be achieved, the economizer can be activated even when the outside air temperature is below 30°F. Measure the true mixed air temperature. Most mixing chambers do not achieve complete mixing of the return air and outside air before reaching the cooling coil. It is particularly important that mixed air temperature be measured accurately when an economizer is being used. An averaging temperature sensor should be used for the mixed air temperature measurement.

26.4.2.6. Improve Coupled Control AHU Operation Coupled control is often used in single-zone singleduct, constant volume systems. Conceptually, this system provides cooling or heating as needed to maintain the setpoint temperature in the zone and uses simultaneous heating and cooling only when the humidistat indicates that additional cooling (followed by reheat) is needed to provide humidity control. However, the

humidistat is often disabled for a number of reasons. To control room relative humidity level, the control signals or spring ranges are overlapped. Simultaneous heating and cooling often occurs almost continuously. 26.4.2.7. Valve Off Hot Air Flow for Dual Duct AHUs During Summer During the summer, most commercial buildings do not need heating. Theoretically, hot air should be zero for dual duct VAV systems. However, hot air leakage through terminal boxes is often significant due to excessive static pressure on the hot air damper. For constant air volume systems, hot air flow is often up to 30% of the total airflow. During summer months, hot air temperatures as high as 140°F have been observed due to hot water leakage through valves. The excessively high hot air temperature often causes hot complaints in some locations. Eliminating this hot air flow can improve building thermal comfort, reduce fan power, cooling consumption, and heating consumption. 26.4.2.8. Install VFD on Constant Air Volume Systems The building heating load and cooling load varies significantly with both weather and internal occupancy conditions. In constant air volume systems, a significant amount of energy is consumed unnecessarily due to humidity control requirements. Most of this energy waste can be avoided by simply installing a VFD on the fan without a major retrofit effort. Guidelines for VFD installation are available for dual duct, multi-zone, and single duct systems21. 26.4.2.9. Airflow Control for VAV Systems Airflow control of VAV systems has been an important design and research subject since the VAV system was introduced. An airflow control method should: (1) ensure sufficient airflow to each space or zone; (2) control outside air intake properly; and (3) maintain a positive building pressure. These goals can be achieved using the variable speed drive volume tracking (VSDVT) method22,23. 26.4.2.10. Improve Terminal Box Operation The terminal box is the end device of the AHU system. It directly controls room temperature and airflow. Improving the set up and operation are critical for room comfort and energy efficiency. The following measures are suggested: • Set minimum air damper position properly for pressure dependent terminal boxes. • Use VAV control algorithm for constant air volume terminal boxes.

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• • • •

Use airflow reset. Integrate lighting and terminal box control. Integrate airflow and temperature reset. Improve terminal box control performance.

26.4.3

Case Study—AHU CC in a Previously Retrofit Building24

26.4.3.1 Case Study Building Description The building studied in this paper is the 295,000 gross ft2 (226,000 ft2 net) Zachry Engineering Center (ZEC), located on the Texas A&M University campus (30°N, 96°W) where the average January temperature is 50°F and average July temperature is 84°F, and pictured in Figure 26.6. The building has four-floors plus an unconditioned basement parking level. It was constructed in the early 1970s and is a heavy structure with 6 in. concrete floors and insulated exterior walls made of precast concrete and porcelain-plated steel panels. About 12% of the exterior wall area is covered with single-pane, bronze-tinted glazing. The windows are recessed approximately 24 in. from the exterior walls, which provides some shading. Approximately 2835 ft2 of northeast-facing clerestory windows admit daylight into the core of the building. The ZEC includes offices, classrooms, laboratories and computer rooms and is open 24 hours per day, 365 days per year with heaviest occupancy during normal working hours between 8 a.m. and 6 p.m. on weekdays. Occupancy, electrical consumption and chilled water consumption show marked weekday/weekend differences with peak weekend electrical consumption less than 10% above the nightly minimum; weekday holiday occupancy is similar to weekend usage with intermediate usage on weekdays between semesters when class

Figure 26.6 The Zachry Engineering Center on the Texas A&M campus25.

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rooms are not in use, but laboratories and offices are occupied. HVAC Systems. Twelve identical dual-duct systems with 40 hp fans rated at 35,000 cfm and eight smaller air handlers (3 hp average) supply air to the zones in the building. Supply and return air ducts are located around the perimeter of the building. These were operated with a constant outdoor air intake at a nominal value of 10% of design flow. The large dual-duct constant air volume (DDCAV) systems were converted to dual-duct variable-air volume (DDVAV) systems accompanied by connection to the campus energy management and control system (EMCS) in 1991. This retrofit successfully reduced fan power consumption by 44%, cooling consumption by 23%, and heating consumption by 84%. Monitoring of energy use. In the engineering center about 50 channels of hourly data have been recorded and collected each week since May 1989. The sensors are scanned every 4 seconds and the values are integrated to give hourly totals or averages as appropriate. The important channels for savings measurement are those for air handler electricity consumption and whole-building heating and cooling energy use. Air handler electricity consumption is measured at the building’s motor control center (MCC) and represents all of the air-handling units and most of the heating, ventilating, and air-conditioning (HVAC)-related pumps in the building. Cooling and heating energy use are determined by a Btu meter which integrates the monitored fluid flow rate and temperature difference across the supply and return lines of the chilled- and hot-water supply to the building. The majority of the 50 channels of monitored information come from one air handler that was highly instrumented. 4.3.2 Continuous Commissioning of the Zachry Engineering Center The Continuous Commissioning process was applied to the Zachry Engineering Center in 1996-97. In this case, the initial survey and specification of monitoring portions of the CC process were not performed since the university president had decided to implement CC on campus based on its success in numerous other locations rather than on the results of individual building surveys. Metering had been installed much earlier in the Zachry Engineering Center as part of the retrofit process, so performance baselines were already available. Conduct system measurements and develop proposed CC measures The facility survey found that the building control system set-up was far from optimum and found numerous other problems in the building as well. The basic

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Figure 26.7 ZEC daily motor control center (MCC) electric consumption in 1990 before the retrofit, in 1994 after the retrofit, and in 1997 after CC26. control strategies found in the building are summarized in Table 26.3 in the column labeled “Pre-CC Control Practice.” The ranges shown for constant parameters reflect different constant values for different individual air handlers. The control practices shown in the table are all widely used, but none are optimal for this building. The campus controls engineer worked closely with the CC engineers during the survey. The items shown in Table 26.3 could all be determined by examination of the control system in the building, but the facility survey also examines a great deal of the equipment throughout the building and found numerous cases of valves that let too much hot or cold water flow, control settings that caused continuous motion and unnecessary wear on valves, air ducts that had blown off of the terminal boxes, kinks in air ducts that led to rooms that could not be properly heated or cooled, etc. Following the survey, the building performance was analyzed and CC measures including optimum control schedules were developed for the building in cooperation with the campus controls engineer. Implement CC measures Following the survey, the building performance was analyzed and optimum control schedules were developed for the building in cooperation with the campus control engineer. The air handlers, pumps and terminal

boxes had major control parameters changed to values shown in the “Post-CC” column of Table 26.3. Most of the control parameters were optimized to vary as a function of outside air temperature, Toa, as indicated. In addition to optimizing the control settings for the heating and cooling systems in the building, numerous problems specific to individual rooms, ducts, or terminal boxes were diagnosed and resolved. These included items like damper motors that were disconnected, bent air ducts that could not supply enough air to properly control room temperature, leaking air dampers, dampers that indicated open when only partly open, etc. Problems of this sort often had led to occupant complaints that were partially resolved without fixing the real problem. For example, if a duct was constricted so inadequate flow reached a room, the pressure in the air handler might be increased to get additional flow into the room. “Fixes” like this typically improve room comfort, but sometimes lead to additional heating and cooling consumption in every other room on the same air handler. Document energy savings Implementation of these measures resulted in significant additional savings beyond the original savings from the VAV retrofit and controls upgrade as shown in Figures 26.7, 26.8 and 26.9. Figure 26.7 shows the motor control center power consumption as a func-

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Table 26.3. Major control settings in the Zachry Engineering Center before and after implementation of CC27. —————————————————————————————————————————————— Parameter Pre-CC Control Practice Post-CC Control Practice —————————————————————————————————————————————— Pressure in air ducts Constant at 2.5 - 3.5 in H2O 1- 2 inH2O as Toa increases —————————————————————————————————————————————— Cold air temperature Constant at 50°F - 55°F 60°F - 55°F as Toa increases —————————————————————————————————————————————— Hot air temperature Constant at 110°F - 120°F 90°F - 70°F as Toa increases —————————————————————————————————————————————— Air flow to rooms Variable - but inefficient Optimized min/max flow and damper operation —————————————————————————————————————————————— Heating pump control Operated continuously On when Toa>55°F —————————————————————————————————————————————— Cooling pump control Variable speed with shut-off Pressure depends on flow —————————————————————————————————————————————— tion of ambient temperature for 1990, 1994 and 1997. It is evident that the minimum fan power has been cut in half and there has been some reduction even at summer design conditions. Figure 26.9 shows the hot water consumption for 1990, 1994 and 1997, again as a function of daily average temperature. The retrofit reduced the annual hot water (HW) consumption for heating to only 16% of the baseline, so there is little room for further reduction. However, it can be seen that the CC measures further reduced HW consumption, particularly at low temperatures. The largest savings from the CC measures are seen in the chilled water consumption as shown in Figure 26.8. The largest fractional savings occur at low ambient temperatures, but the largest absolute savings occur at the highest ambient temperatures. The annualized consumption values for the baseline, post-retrofit and post-CC conditions are shown in Table 26.4. The MCC consumption for 1997 was 1,209,918 kWh, 74% of the 1994 consumption and only 41% of the 1990 consumption. On an annual basis, the

post-CC HW consumption normalized to 1994 weather was 1940 MMBtu, a reduction to only 10% of baseline consumption and a reduction of 34% from the 1994 consumption. The CC measures reduced the post-CC chilled water (CHW) consumption to 17,400 MMBtu, a reduction of 17,800 MMBtu which is noticeably larger than the 13,900 MMBtu savings produced by the retrofit. The CHW savings accounted for the largest portion of the CC savings in this cooling-dominated climate. Generalized application of case study and conclusions The major energy savings from the CC activities in the case study building resulted from five items. 1.

Optimization of duct static pressures at lower levels. This reduces fan power and also reduces damper leakage that increases both heating and cooling consumption.

2.

Optimization of cold air temperatures. Most buildings in our experience use a constant set-point for

Table 26.4. Consumption at the Zachry Engineering Center before and after retrofit and after implementation of CC measures28. —————————————————————————————————————————————— Baseline Consumption

Post-retrofit

Post-Retrofit

Post-CC

Post-CC

—————————————————————————————————————————————— Fan Power

2,950,000 kWh

1,640,000 kWh

56%

1,210,000 kWh

41%

—————————————————————————————————————————————— Chilled Water

45,800 MMBtu

35,300 MMBtu

77%

17,400 MMBtu

37%

—————————————————————————————————————————————— Heating Water

18,800 MMBtu

2940 MMBtu

16%

1940 MMBtu

10%

——————————————————————————————————————————————

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the cold air temperature which is very inefficient. Even if this set-point is changed, it is seldom optimized. 3.

Optimization of hot air temperatures. We find that most buildings modulate hot air temperature according to outside air temperature, but it is normally significantly higher than necessary.

retrofit. The measures implemented in the case study building are quite typical of CC measures implemented in other buildings. These results are better than average for the process, but are not one-of-a-kind.

4.

Optimize settings on VAV boxes. Most VAV terminal boxes have minimum flow set-points at night that are too high.

5.

Optimize pump control. Static pressure set-points on chilled water and hot water pumps are generally set higher than necessary.

26.4.4 CC Measures for Water/Steam Distribution Systems Distribution systems include central chilled water, hot water, and steam systems, that deliver thermal energy from central plants to buildings. In turn, the system distributes the chilled water, hot water and steam to AHU coils and terminal boxes. Distribution systems mainly consist of pumps, pipes, control valves, and variable speed pumping devices. This section focuses on the CC measures for optimal pressure control, water flow control, and general optimization.

The CC process has been illustrated by application to a large building which had earlier had a major retrofit performed. The post-CC consumption values represent 41% of the pre-retrofit fan and pump consumption, 10% of the pre-retrofit hot water consumption, and 38% of the pre-retrofit chilled water consumption. Using the baseline energy prices, the post-CC consumption reflects an HVAC energy cost that is only 36% of the baseline HVAC cost and is only 65% of the HVAC cost after the

26.4.4.1 Improve Building Chilled Water Pump Operation Most building chilled water pumping systems are equipped with variable speed devices (VSDs). If a VSD is not installed, retrofit of a VSD is generally recommended. The discussion here is limited to systems where a VSD is installed. The goal of pumping optimization is to avoid excessive differential pressures across the control valves, while providing enough water to

Figure 26.8. ZEC daily chilled water consumption for 1990 before the retrofit, 1994 after the retrofit, and 1997 after CC29.

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Figure 26.9. ZEC daily hot water consumption for 1990 before the retrofit, 1994 after the retrofit, and 1997 after CC30. each building, coil, or other end use. An optimal pump differential pressure schedule should be developed that provides adequate pressure across the hydraulically most remote coil in the system under all operating conditions, but does not provide excess head. 26.4.4.2 Improve Secondary Loop Operation For buildings supplied by a secondary loop from a central plant, building loop optimization should be performed before the secondary loop optimization. Source Distributed Systems: If there are no building pumps, the secondary pumps must provide the pressure head required to overcome both the secondary loop and the building loop pressure losses. In this case, the secondary loop is called a source distributed system. The secondary loop pumps should be controlled to provide enough pressure head for the most remote coil. If VFDs are installed, the differential pressure can be controlled by modulating pump speed. Otherwise, the differential pressure can be modulated by changing the number of pumps in operation. Source Distributed Systems With Building Pumps: In most campus settings, each building has a pump. The optimal differential pressure setpoint should then be determined by optimizing the secondary loop pressure

setpoint so the combined secondary pump and building pumping power is minimized. This can be done by developing a pressure reset schedule that requires maximum building pump power at the most hydraulically remote building on the secondary loop. This may occur with a negative differential pressure across the most remote building. 26.4.4.3 Improving Central Plant Water Loop Operation The central plant loop optimization should be performed after secondary loop optimization. Single Loop Systems: For most heating distribution systems and some chilled water systems, a single loop is used instead of primary and secondary systems. Under partial load conditions, fewer pumps can be used for both chillers and heat exchangers. This can result in less pump power consumption. Primary-secondary Loop Systems: Primary-secondary systems are the most common chilled water distribution systems used with central chiller plants. This design is based on the assumption that the chilled water flow through the chiller must be maintained at the design level. This is seldom needed. Due to this incorrect assumption, a significant amount of pumping power is wasted in numerous central plants. Design engineers

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may or may not include an isolation valve on the bypass line of the primary loop. Procedures are available to optimize pump operation for both cases31,32,33,34.

for newer chillers. It is also recommended that you consult the chiller manufacturer for specific limits on allowable condenser water temperature.

26.4.5 CC Measures for Central Chiller Plants The central chiller plant includes chillers, cooling towers, a chilled water distribution system, and the condenser water distribution system. Although a secondary pumping system may be physically located inside the central plant, commissioning issues dealing with secondary loops are discussed in the previous section. The central chiller plant produces chilled water using electricity, steam, hot water, or gas. The detailed commissioning measures vary with the type of chiller and this section gives general commissioning measures that apply to a typical central cooling plant and that can produce significant energy savings.

The cooling tower return water temperature reset can be implemented using the BAS. If it cannot be implemented using the BAS, operators can reset the setpoint daily using the daily maximum wet bulb or dry bulb temperature. Decreasing the cooling tower return temperature may increase fan power consumption. However, fan power may not necessarily increase with lower cooling tower return water temperature. The following tips can help. • Use all towers. For example, use all three towers when one of the three chillers is used. This may eliminate fan power consumption entirely. The pump power may actually stay the same. Be sure to keep the other two tower pumps off. • Never turn on the cooling tower fan before the bypass valve is totally closed. If the by-pass valve is not totally closed, the additional cooling provided by the fan is not needed and will not be used. Save the fan power! • Balance the water distribution to the towers and within the towers. Towers are often seen where water is flowing down only one side of the tower, or one tower may have twice the flow of another. This significantly increases the water return temperature from the towers.

Use the Most Efficient Chillers: Most central chiller plants have several chillers with different performance factors or efficiencies. The differences in performance may be due to the design, to performance degradation, age, or operational problems. One chiller may have a higher efficiency at a high load ratio while another may have a higher efficiency at a lower load ratio. Running chillers with the highest performance can result in significant energy savings because you will be providing the greatest output for the least input. Reset the Supply Water Temperature: Increasing the chilled water supply temperature can decrease chiller electricity consumption significantly. The general ruleof-thumb is that a one degree Fahrenheit increase corresponds to a decrease in compressor electricity consumption of 1.7%. The chilled water supply temperature can be reset based on either cooling load or ambient conditions. Reset Condenser Return Water Temperature: Decreasing cooling tower return water temperature has the same effect as increasing the chilled water supply temperature. The cooling tower return temperature should be reset based on weather conditions. The following provides general guidelines: • The cooling tower return water temperature setpoint should be at least 5°F (adjustable based on tower design “approach”) higher than the ambient wet bulb temperature. This prevents excessive cooling tower fan power consumption. • The cooling tower water return temperature should not be lower than 65°F for chillers made before 1999, and should not be lower than 55°F

Increase Chilled Water Return Temperature: Increasing chilled water return temperature has the same effect as increasing chilled water supply temperature. It can also significantly decrease the secondary pump power since the higher the return water temperature (for a given supply temperature), the lower the differential temperature, and the lower the chilled water flow. Maximizing chilled water return temperature is much more important than optimizing supply water temperature since it often provides much more savings potential. It is hard to increase supply temperature 5°F above the design setpoint. It is often easy to increase the return water temperature as much as 7°F by conducting water balance and shutting off by-pass of three-way valves. Use Variable Flow under Partial Load Conditions: Typical central plants use primary-secondary loops. A constant speed primary pump is often dedicated to a particular chiller. When the chiller is turned on, the pump is on. Chilled water flow through each chiller is maintained at the design flow rate by this operating schedule. When the building-loop flow is less than the

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chiller loop flow, part of the chiller flow by-passes the building and returns to the chiller. This practice causes excessive primary pump power consumption and excessively low entering water temperature to the chiller, which increases the compressor power consumption. It is generally perceived that chilled water flows must remain constant for chiller operational safety. Actually, most new chillers allow chilled water flow as low as 30% of the design value. The chilled water flow can be decreased to be as low as 50% for most existing chillers if the proper procedures are followed35. Varying chilled water flow through a chiller can result in significant pump power savings. Although the primary pumps are kept on all the time, the secondary pump power consumption is decreased significantly when compared to the conventional primary and secondary system operation. Varying chilled water flow through the chillers will also increase the chiller efficiency when compared to constant water flow with chilled water by-pass. More information can be found in a paper by Liu36. Optimize Chiller Staging: For most chillers, the kW/ton decreases (COP increases) as the load ratio increases from 40% to 80%. When the load ratio is too low, the capacity modulation device in the chiller lowers the chiller efficiency. When the chiller has a moderate load, the capacity modulation device has reasonable efficiency. The condenser and evaporator are oversized for the load under this condition so the chiller efficiency is higher. When the chiller is at maximum load, the evaporator and condenser are marginally sized, reducing the chiller efficiency below its maximum value. Running chillers in the high efficiency range can result in significant electrical energy savings and can improve the reliability of plant operation. Optimal chiller staging should be developed using the following procedures: • Determine and understand the optimal load range for each chiller. This information should be available from the chiller manufacturer. For example, chiller kW/ton typically has a minimum value (best efficiency) when the chiller load is somewhere between 50% and 70% of the design value. • Turn on the most efficient chiller first. Optimize the pump and fan operation accordingly. • Turn on more chillers to maintain the load ratio (chiller load over the design load) within the optimal efficiency range for each chiller. This assumes that the building by-pass is closed. If the building by-pass cannot be closed, the minimum chiller load ratio should be maintained at 50% or higher to limit primary pumping power increases

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Maintain Good Operating Practices: The operating procedures recommended by the manufacturer should be followed. It is important to calibrate the temperature, pressure, and current sensors and the flow switches periodically. The temperature sensors are especially important for maintaining efficient operation. Control parameters must be set properly, particularly the time delay relay. 26.4.6 CC Measures for Central Heating Plants Central heating plants produce hot water, steam, or both, typically using either natural gas, coal or oil as fuel. Steam, hot water, or both are distributed to buildings for HVAC systems and other end uses, such as cooking, cleaning, sterilization and experiments. Boiler plant operation involves complex chemical, mechanical and control processes. Energy performance and operational reliability can be improved through numerous measures. However, the CC measures discussed in this section are limited to those that can be implemented by an operating technician, operating engineers, and CC engineers. 26.4.6.1 Optimize Supply Water Temperature and Steam Pressure Steam pressure and hot water temperature are the most important safety parameters for a central heating plant. Reducing the boiler steam pressure and hot water temperature has the following advantages: • Improves plant safety • Increases boiler efficiency and decreases fuel consumption • Increases condensate return from buildings and improves building automation system performance • Reduces hot water and steam leakage through malfunctioning valves 26.4.6.2 Optimize Feed Water Pump Operation The feed water pump is sized based on boiler design pressure. Since most boilers operate below the design pressure, the feed water pump head is often significantly higher than required. This excessive pump head is often dropped across pressure reducing valves and manual valves. Installing a VSD on the feed water pump in such cases can decrease pump power consumption and improve control performance. Trimming the impeller or changing feed water pumps may also be feasible, and the cost may be lower. However, the VSD provides more flexibility, and it can be adjusted to any level. Consequently, it maximizes the savings and can be adjusted to future changes as well.

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26.4.6.3 Optimize Airside Operation The key issues are excessive airflow and flu gas temperature control. Some excess airflow is required to improve the combustion efficiency and avoid having insufficient combustion air during fluctuations in airflow. However, excessive airflow will consume more thermal energy since it has to be heated from the outside air temperature to the flue gas temperature. The boiler efficiency goes down as excessive airflow increases. The flue gas temperature should be controlled properly. If the flue gas temperature is too low, acid condensation can occur in the flue. If the flue gas temperature is too high, it carries out too much thermal energy. The airside optimization starts with a combustion analysis, that determines the combustion efficiency based on the flu gas composition, flu gas temperature, and fuel composition. The typical combustion efficiency should be higher than 80%. If the combustion efficiency is lower than this value, available procedures37,38 should be used to determine the reasons. 26.4.6.4 Optimize Boiler Staging Most central plants have more than one boiler. Using optimal staging can improve plant energy efficiency and reduce maintenance cost. The optimal staging should be developed using the following guidelines: • Measure boiler efficiency. • Run the higher efficiency boiler as the primary system and run the lower efficiency boiler as the back up system. • Avoid running any boiler at a load ratio less than 40% or higher than 90%. • If two boilers are running at average load ratios less than 60%, no stand-by boiler is necessary. If three boilers are running at loads of less than 80%, no stand by boiler is necessary. Boiler staging involves boiler shut off, start up, and standby. Realizing the large thermal inertial and the temperature changes between shut off, standby, and normal operation, precautions must be taken to prevent corrosion damage and expansion damage. Generally speaking, short-term (monthly) turn on/off should be avoided for steam boilers. Hot water boilers are sometimes operated to provide water temperatures as low as 80°F. This improves distribution efficiency, but may lead to acid condensate in the flue. The hot water temperature must be kept high enough to prevent this condensation. 26.4.6.5 Improve Multiple Heat Exchanger Operation Heat exchangers are often used in central plants or

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buildings to convert steam to hot water or high temperature hot water to lower temperature hot water. If more than one heat exchanger is installed, use as many heat exchangers as possible provided the average load ratio is 30% or higher. This approach provides the following benefits: • Lower pumping power. For example, if two heat exchangers are used instead of one under 100% load, the pressure loss through the heat exchanger system will be decreased by 75%. The pumping power will also be decreased by 75%. • Lower leaving temperature on the heat source. The condensate should be super-cooled when the heat exchangers are operated at low load ratio. The exit hot water temperature will be lower than the design value under the partial load condition. This will result in less water or steam flow and more energy extracted from each pound of water or steam. For example, the condensate water may be sub-cooled from 215°F to 150°F under low heat exchanger loads. Compared with leaving the heat exchanger at 215°F, each pound of steam delivers 65 Btu more thermal energy to the heat exchanger. Using more heat exchangers will result in more surface heat loss. If the load ratio is higher than 30%, the benefits mentioned above normally outweigh the heat loss. More information can be found in a paper by Liu et al.39 26.4.6.6 Maintain Good Operating Practices: Central plant operation involves both energy efficiency and safety issues. Proper safety and maintenance guidelines should be followed. The following maintenance issues should be carefully addressed: • Blowdown: check blowdown setup if a boiler is operating at partial load most of the time. The purpose of blowdown is to remove the mineral deposits in the drum. This deposit is proportional to the cumulative make-up water flow, which is then proportional to the steam or hot water production. The blowdown can often be set back significantly. If the load ratio is 40% or higher, the blowdown can be reset proportional to the load ratio. If the load ratio is less than 40%, keep the blowdown rate at 40% of the design blowdown rate. • Steam traps: check steam traps frequently. Steam traps have a tendency to fail, failed position is usually open, and leakage costs can be significant. A steam trap maintenance program is recommended. Consult the manufacturer and other manuals for proper procedures and methods.

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•

Condensate return: inspect the condensate return frequently. Make sure you are returning as much condensate as possible. This is very expensive water. It has high energy content and is treated water. When you lose condensate, you have to pay for the make-up water, chemicals, fuel, and, in some cases, sewage costs.

26.4.7 Continuous Commissioning Guidelines Guidelines can be used to assist in carrying the CC process out in an orderly manner. An abbreviated sample set is provided in Appendix A that provides a basic check list, procedures, and documentation requirements.

26.5 ENSURING OPTIMUM BUILDING PERFORMANCE The CC activities described in the previous sections will optimize building system operation and reduce energy consumption. To ensure excellent long-term performance, the following activities should be conducted. 1. Document CC activities, 2. Measure energy and maintenance cost savings, 3. Train operating and maintenance staff, 4. Measure energy data, and continuously measure energy performance, and 5. Obtain on-going assistance from CC engineers. This section discusses guidelines to perform these tasks. 26.5.1 Document the CC Project The documentation should be brief and accurate. The operating sequences should be documented accurately and carefully. This documentation should not repeat the existing building documentation. It should describe the procedures implemented, including control algorithms, and briefly give the reasons behind these procedures. The emphasis is on accurate and usable documentation. The documentation should be easily used by operating staff. For example, operating staff should be able to create operating manuals and procedures from the document. The CC project report should include accurate documentation of current energy performance, building data, AHUs and terminal boxes, water loops and pumps, control system, and performance improvements. 26.5.2 Measure Energy Savings Most building owners expect the CC project to pay for itself through energy savings. Measurement of en-

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ergy savings is one of the most important issues for CC projects. The measurements should follow the procedures described in Chapter 27 (Measurement and Verification) of this handbook. Chapter 27 describes procedures from the International Performance Measurement and Verification Protocol40 (IPMVP). This section will provide a very brief description of these procedures, emphasizing issues that are important in M&V for CC projects. The process for determining savings as adopted in the IPMVP defines energy savings, Esave, as: ESave = Ebase – Epost where Ebase is the “baseline” energy consumption before the CC measures were implemented, and Epost is the measured consumption following implementation of the CC measures. Figure 26.10 shows the daily electricity consumption of the air handlers in a large building in which the HVAC systems were converted from constant volume systems to VAV systems using variable frequency drives. Consumption is shown for slightly over a year before the VFDs were installed (Pre), for about three months of construction and for about two years after installation (Post). In this case, the base daily electricity consumption is 8,300 kWh/day. The post-retrofit electricity consumption is 4,000 kWh/day, corresponding to electricity savings of 4,300 kWh/day. During the construction period, the savings are slightly lower. However, in most cases, consumption shows more variation from day to day and month to month than that shown by the fan power for these constant speed fans. Hence, determination of the baseline must consider a number of factors, including weather changes, changes in occupancy schedule, changes in number of occupants, remodeling of the spaces, equipment changes, etc. In the IPMVP, the baseline energy use, Ebase, is determined either from direct measurements, utility bills, or from a model of the building operation before the retrofit (or commissioning). The post-installation energy use is generally simply the measured energy use, but it may be determined from a model if measured data are not available. Before and after comparisons are often normalized with factors such as weather, occupancy, etc. The IPMVP includes four different M&V techniques or options. These options, may be summarized as Option A—some measurements, but mostly stipulated savings, Option B: measurement at the system or device level, Option C—measurement at the whole-building or facility level, and Option D—determination from calibrated simulation. Each option has its advantages for some special applications. The cost savings must also consider changes in

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Figure 26.10 Daily electricity consumption for approximately one year before a retrofit and two years after the retrofit41. utility rates. It is generally recommended that the utility rates in place before the retrofit or CC measures were implemented be used if any savings projections were made, since those projections were made based on the rates in effect at that time. In general, the least expensive M&V method that will provide the accuracy required should be used. Utility billing data will be the least expensive data whenever it is available. It will sometimes provide the required accuracy for CC projects, but has the disadvantage that it may take considerable time before the improved performance is clearly evident. The discussion below generally assumes that higher frequency data is being used. 26.5.2.1 Option A - Stipulated Savings (Involving some measurements) The stipulated option determines savings by measuring the capacity or the efficiency of a system before and after retrofit or commissioning, and then multiplies the difference by an agreed upon or “stipulated” factor such as the hours of operation, or the load on the system. This option focuses on a physical determination of equipment changes to ensure that the installation meets contract specifications. Key performance factors (e.g. lighting wattage) are determined with spot or short-

term measurements and operational factors (e.g. lighting operating hours) are stipulated based on historical data or spot measurement. Performance factors are measured or checked yearly. This method provides reliable savings estimation for applications where the energy savings are independent of weather and occupancy conditions. For example, during the CC process, the fan pulley was decreased from 18” to 16” for a constant volume AHU. The fan power savings can be determined using the following method: • Measure the fan power consumption before changing the pulley and the power consumption after changing the pulley. • Determine the number of hours in operation. • Determine the fan power savings as the product of the hourly fan power energy savings and the number of hours in operation. If the energy consumption varies with occupancy and weather conditions, this option should not be used. For example, the minimum airflow setting was adjusted from 50% to 0% for 100 VAV terminal boxes at night and during weekends. Since the airflow depends on both internal and external loads, and the airflow may not be 0% even if the minimum flow setting is 0%, this method cannot be used to determine savings.

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If Option A can provide the required accuracy, it will generally be the second least expensive method, after utility data. 26.5.2.2 Option B - Device/System Level Measurement Within Option B, savings are determined by continuous measurements taken throughout the project term at the device or system level. Individual loads or end-uses are monitored continuously to determine performance and the long-term persistence of the measures installed. The base line model can be developed using the measured energy consumption and other parameters. The energy savings can be determined as the difference between baseline energy consumption and the measured energy consumption. This method provides the best saving estimation for an individual device or system. The data collected can also be used to improve or optimize the system operation, and as such is particularly valuable for continuous commissioning projects. Since measurements are taken throughout the project term, the cost is higher than option A. 26.5.2.3 Option C - Whole Building Level Measurement Determines savings by analyzing “whole-building” or facility level data measured during the baseline period and the post-installation period. This option is required when it is desired to measure interaction effects, e.g. the impact of a lighting retrofit on the cooling consumption as well as savings in lighting energy. The data used may be utility data, or sub-metered data. The minimum number of measurement channels recommended for performance assurance or savings measurement will be the number needed to separate heating, cooling and other electric uses. The actual number of channels will vary, depending on whether pulses are taken from utility meters, or if two or three current transformers are installed to measure the three phase power going into a chiller. Other channels may need to be added, depending on the specific measures that are being evaluated. Option C requires that installation of the proper systems/equipment and proper operating practices must be confirmed. It determines savings from metered data taken throughout the project term. The major limitation in the use of Option C for savings determination is that the size of the savings must be larger than the error in the baseline model. The major challenge is accounting for changes other than those associated with the ECMs or the commissioning changes implemented. Accurate determination of savings using Option C normally requires 12 months of continuous data before

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a retrofit and continuous data after retrofit. However, for commissioning applications, a shorter period of data during which daily average ambient conditions cover a large fraction of normal yearly variation is often adequate. 26.5.2.4 Option D - Calibrated Simulation Savings are determined through simulation of the facility components and/or the whole facility. The most powerful application of this approach calibrates a simulation model to baseline consumption data. For commissioning applications, it is recommended that calibration be to daily or hourly data. This type of calibration may be carried out most rapidly if simulated data is compared to measured data as a function of ambient temperature. Wei et al.42 have developed “energy signatures” that greatly aid this process. More information can be found in Liu and Claridge43 and a manual providing instructions on use of the method is available44. Just as for the other options, the implementation of proper operating practices should be confirmed. It is particularly important that personnel experienced in the use of the particular simulation tool conduct the analysis. The simulation analysis needs to be well documented, with electronic and hard copies of the simulation program input and output preserved. 26.5.2.5 Data Used to Determine Savings Note that monthly bills may be used to estimate the energy savings. This method is one version of Option C described above. It is typically the least expensive method of verification. It will work fine if the following conditions are met: 1. Significant savings are expected at the utility meter level 2. Savings are too small to cost-justify more data 3. There will be no changes in a. Equipment b. Schedules c. Occupancy d. Space utilization The case shown in Figure 26.11 is an example where monthly bills clearly show the savings. The savings were large and consistent following the retrofit until June. At this point, a major deviation occurred. The presence of other metering at this site showed that the utility bill was incorrect. Further investigation showed that the utility meter had been changed and this had not been considered in the bill sent. The consumption included in this bill was greater than the site would have used if it had used the peak demand recorded on the utility

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Figure 26.11 Comparison of monthly utility bills before (top line) and after (bottom line) a retrofit45. meter for every hour of the billing period! However, daily or hourly data will show the results of commissioning measures much more quickly and are an extremely valuable diagnostic tool when problems arise as described in Section 26.5.4. Hence it is recommended that such data be used for savings determination and follow-up tracking whenever possible.

or an operating change that makes such a small change in comfort or operating efficiency that it is not visible in metered consumption data, it generally isn’t worth worrying about. If it does show up as even a marginal increase in consumption, trouble-shooting should be initiated. 2.

Trend/measure energy consumption data. This continuing activity is the first line of defense against declining performance. The same procedures used to establish a pre-CC baseline can be used to establish a baseline for post-CC performance, and this post-CC baseline can be used as a standard against which future performance is compared. Consumption that exceeds this baseline for a few days, or even a month may not be significant, but if it persists much more than a month, troubleshooting should be used to find out what has led to the increase. If it is the result of a malfunctioning valve, you can fix it. If it is the result of 100 new computers added to the building, you will adjust the baseline accordingly.

3.

Trend and check major operating parameters. Parameters such as cold-deck temperatures, zone supply temperatures, etc. should be trended periodically for comparison with historic levels. This can be extremely valuable when trouble-shooting and

26.5.3 Trained Operating and Maintenance Staff Efficient building operation begins with a qualified and committed staff. Since the CC process generally makes changes in the way a building is operated to improve comfort and efficiency, it is essential that the operators be a part of the commissioning team. They need to work with the CC engineers, propose CC measures and implement or help implement them. In addition to actively participating in the CC process, formal technical training should be provided to ensure that the operating staff understands the procedures implemented so they can perform trouble-shooting properly. 26.5.4 Continuously Measure Energy Performance The measurement of energy consumption data is very important to maintain building performance and maintain CC savings. The metered data can be used to: 1. Identify and solve problems. Metered consumption data is needed to be sure that the building is still operating properly. If there is a component failure

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when investigating consumption above the postCC baseline. 4.

Find the real problems when the system needs to be repaired or fixed. It is essential that the same fundamental approach used to find and fix problems while the CC process is initiated be used whenever new hot calls or cold calls are received.

26.5.5 Utilize Expert Support as Needed It is inevitable that a problem will come up which, even after careful trouble-shooting points toward a problem with one or more of the CC measures that have been implemented. Ask the CC providers for help in solving such problems before undoing an implemented CC measure. Sometimes it will be necessary to modify a measure that has been implemented. The CC engineers will often be able to help with finding the most efficient solution, and they will sometimes be able to help you find another explanation, so the problem can be remedied without changing the measure. Ask help from the CC providers when you run into a new problem or situation. Problems occasionally crop up that defy logical explanation. These are the problems that generally get resolved by trying one of three things that seem like possible solutions, and playing

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with system settings until the problem goes away. This is one of the most important situations in which expert help is needed. Without the expert’s help, these kinds of problems—and the trial and error solutions—can undo the measure’s savings potential. 26.5.6 How Well Do Commissioning Savings Persist? The Energy Systems Laboratory at Texas A&M has conducted a study of 10 buildings on the Texas A&M campus that had CC measures implemented in 19969746,47. Table 26.5 shows the baseline cost of combined heating, cooling and electricity use of each building and the commissioning savings for 1998 and 2000. The baseline consumption and savings for each year were normalized to remove any differences due to weather. Looking at the totals for the group of 10 buildings, heating and cooling consumption increased by $207,258 (12.1%) from 1998 to 2000, but savings from the earlier commissioning work were still $985,626. However, it may also be observed that almost three-fourths of this consumption increase occurred in two buildings, the Kleberg Building, and G. Rollie White Coliseum. The increased consumption of the Kleberg Building was due to a combination of component failures and control problems as described in the case study in Section 26.5.6.1. The increased consumption in G. Rollie White Coliseum

Table 26.5. Commissioning savings in 1998 and 2000 for 10 buildings on the Texas A&M campus48. ——————————————————————————————————————————— Building Baseline Use 1998 Savings 2000 ($/Yr) ($/Yr) Savings($/yr) ——————————————————————————————————————————— Kleberg Building $484,899 $313,958 $247,415 ——————————————————————————————————————————— G.R. White Coliseum $229,881 $154,973 $71,809 ——————————————————————————————————————————— Blocker Building $283,407 $76,003 $56,738 ——————————————————————————————————————————— Eller O&M Building $315,404 $120,339 $89,934 ——————————————————————————————————————————— Harrington Tower $ 145,420 $64,498 $48,816 ——————————————————————————————————————————— Koldus Building $ 192,019 $57,076 $61,540 ——————————————————————————————————————————— Richardson Petroleum Building $273,687 $120,745 $120,666 ——————————————————————————————————————————— Veterinary Medical Center $324,624 $87,059 $92,942 Addition ——————————————————————————————————————————— Welmer Business Building $224,481 $47,834 $68,145 ——————————————————————————————————————————— Zachry Engineering Center $436,265 $150,400 $127,620 ——————————————————————————————————————————— Totals $2,910,087 $ 1,192,884 $985,626 ———————————————————————————————————————————

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was due to different specific failures and changes, but was qualitatively similar to Kleberg since it resulted from a combination of component failures and control changes. The five buildings that showed consumption changes of more than 5% from 1998 to 2000 were all found to have different control settings that appear to account for the changed consumption (including the decrease in the Wehner Business Building). These data suggest that commissioning savings generally persist, but tracking can subsequently uncover problems that did not cause comfort problems, but have increased consumption by $10,000-$100,000 per year in large buildings. 26.5.6.1 Commissioning persistence case study - Kleberg Building49 The Kleberg Building is a teaching/research facility on the Texas A&M campus consisting of classrooms, offices and laboratories, with a total floor area of approximately 165,030 ft2. Ninety percent of the building is heated and cooled by two (2) single duct variable air volume (VAV) air handling units (AHU) each having a pre-heat coil, a cooling coil, one supply air fan (100 hp), and a return air fan (25 hp). Two smaller constant volume units handle the teaching/lecture rooms in the building. The campus plant provides chilled water and hot water to the building. The two (2) parallel chilled water pumps (2 × 20 hp) have variable frequency drive control. There are 120 fan-powered VAV boxes with terminal reheat in 12 laboratory zones and 100 fan-powered VAV boxes with terminal reheat in the offices. There are six (6) exhaust fans (10-20 hp, total 90 hp) for fume hoods and laboratory general exhaust. The air handling units, chilled water pumps and 12 laboratory zones are controlled by a direct digital control (DDC) system. DDC

Figure 26.12 Pre-CC and post-CC heating water consumption at the Kleberg Building vs. daily average outdoor temperature50.

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controllers modulate dampers to control exhaust airflow from fume hoods and laboratory general exhaust. A CC investigation was initiated in the summer of 1996 due to the extremely high level of simultaneous heating and cooling observed in the building (Abbas, 1996). Figures 26.12 and 26.13 show daily heating and cooling consumption (expressed in average kBtu/hr) as functions of daily average temperature. The Pre-CC heating consumption data given in Figure 26.13 shows very little temperature dependence as indicted by the regression line derived from the data. Data values were typically between 5 and 6 MMBtu/hr with occasional lower values. The cooling data (Figure 26.12) shows more temperature dependence and the regression line indicates that average consumption on a design day would exceed 10 MMBtu/hr. This corresponds to only 198 sq.ft./ton based on average load, which is a high cooling density. It was soon found that the preheat was operating continuously, heating the mixed air entering the cooling coil to approximately 105˚F, instituted in response to a humidity problem in the building. The preheat was turned off and heating and cooling consumption both dropped by about 2 MMBtu/hour as shown by the middle clouds of data in Figures 26.12 and 26.13. Subsequently, the building was thoroughly examined and a comprehensive list of commissioning measures was developed and implemented. The principal measures implemented that led to reduced heating and cooling consumption were: • •

Preheat to 105˚F was changed to preheat to 40˚F Cold deck schedule changed from 55˚F fixed to vary from 62˚F to 57˚F as ambient temperature varies from 40˚F to 60˚F

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Figure 26.13 Pre-CC and post-CC chilled water consumption at the Kleberg Building vs. daily average outdoor temperature51.

• •

• •

Economizer—set to maintain mixed air at 57˚F whenever outside air below 60˚F Static pressure control—reduced from 1.5 inH2O to 1.0 inH2O and implemented night-time set back to 0.5 inH2O Replaced or repaired a number of broken VFD boxes Chilled water pump VFDs were turned on.

Additional measures implemented included changes in CHW pump control—changed so one pump modulates to full speed before the second pump comes on instead of operating both pumps in parallel at all times, building static pressure was reduced from 0.05 in. w.c. to 0.02 in. w.c., and control changes were made to eliminate hunting in several valves. It was also observed that there was a vibration at a particular frequency in the pump VFDs that influenced the operators to place these VFDs in the manual mode, so it was recommended that the mountings be modified to solve this problem. These changes further reduced chilled water and heating hot water use as shown in Figures 26.12 and 26.13 for a total annualized reduction of 63% in chilled water use and 84% in hot water use. Additional followup conducted from June 1998 through April 1999 focused on air balance in the 12 laboratory zones, general exhaust system rescheduling, VAV terminal box calibration, adjusting the actuators and dampers, and calibrating fume hoods and return bypass devices to remote DDC control52 (Lewis, et al. 1999). These changes reduced electricity consumption by about 7% or 30,000 kWh/mo. In 2001 it was observed that chilled water savings for 2000 had declined to 38% and hot water savings to

62% as shown in Table 26.6. Chilled water data for 2001 and the first three months of 2002 are shown in Figure 26.14. The two lines shown are the regression fits to the chilled water data before CC implementation and after implementation of CC measures in 1996 as shown in Figure 26.13. It is evident that consumption during 2001 is generally appreciably higher than immediately following implementation of CC measures. The CC group performed field tests and analyses that soon focused on two single-duct VAV AHU systems, two chilled water pumps, and the Energy Management Control System (EMCS) control algorithms as described in Chen et al.53 Several problems were observed as noted below. Problems Identified • The majority of the VFDs were running at a constant speed near 100% speed. •

VFD control on two chilled water pumps was again bypassed to run at full speed.

•

Two chilled water control valves were leaking badly. Combined with a failed electronic to pneumatic switch and the high water pressure noted above, this resulted in discharge air temperatures of 50°F and lower and activated preheat continuously.

•

A failed pressure sensor and two failed CO2 sensors put all outside air dampers to the full open position.

•

The damper actuators were leaking and unable to maintain pressure in some of the VAV boxes. This

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Table 26.6. Chilled water and heating water usage and saving in the Kleberg Building for three different years normalized to 1995 weather54. —————————————————————————————————————————————— Type

Pre-CC

Post-CC Use/Savings

2000 Use/Savings

Baseline Use Savings % Use Savings (%) (MMBtu/yr) (MMBtu/yr) (MMBtu/yr) —————————————————————————————————————————————— CHW 72935 26537 63.6% 45431 37.7% —————————————————————————————————————————————— HW 43296 6841 84.2% 16351 62.2% —————————————————————————————————————————————— caused cold air to flow through the boxes even when they were in the heating mode, resulting in simultaneous heating and cooling. Furthermore some of the reheat valves were malfunctioning. This caused the reheat to remain on continuously in some cases. •

Additional problems identified from the field survey included the following: 1) high air resistance from the filters and coils, 2) errors in a temperature sensor and static pressure sensor, 3) high static pressure setpoints in AHU1 and AHU2.

This combination of equipment failure compounded by control changes that returned several pumps and fans to constant speed operation had the consequence of increasing chilled water use by 18,894 MMBtu and hot water use by 9,510 MMBtu. This amounted to an increase of 71% in chilled water use and more than doubled hot water use from two years earlier These problems have now been corrected and building performance has returned to previously low levels as illustrated by the data for April-June 2002 in Figure 26.4. These data are all below the lower of the two regression lines and is comparable to the level achieved after additional CC measures were implemented in 1998-99.

26.6 COMMISSIONING NEW BUILDINGS FOR ENERGY MANAGEMENT The energy manager’s effort is generally directed toward the improving the efficiency of existing buildings. However, whenever the organization initiates design and construction of a new building that will become part of the energy manager’s portfolio of buildings, it is extremely important that the energy manager become an active part of the design and construction team to ensure that the building incorporates all appropriate energy efficiency technologies. It is just as

Figure 26.14 ChW data for the Kleberg Building for January 2001- June 200255. important that the perspective of operational personnel be included in the design process so it will be possible to effectively and efficiently operate the building. One of the best ways to accomplish these objectives is to commission the building as it is designed and built. The primary motivation for commissioning HVAC systems is generally to achieve HVAC systems that work properly to provide comfort to building occupants at low cost. In principle, all building systems should be designed, installed, documented, tested, and building staff trained in their use. In practice, competitive pressures and fee structures, and financial pressures to occupy new buildings as quickly as possible generally result in buildings that are handed over to the owners with minimal contact between designers and operators, minimal functional testing of systems, documentation that largely consists of manufacturers system component manuals, and little or no training for operators. This in turn leads to problems such as mold growth in walls of new buildings, rooms that never cool properly, air quality problems, etc. Such experiences were doubtless the motivation for the facility manager for a large university medical center who stated a few years ago that he didn’t want to get any new buildings. He only

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wanted three-year old buildings in which the problems had been fixed. Although commissioning provides higher quality buildings and results in fewer initial and subsequent operational problems, most owners will include commissioning in the design and construction process only if they believe they will benefit financially from commissioning. It is much more difficult to document the energy cost savings from commissioning a new building than an existing building. There is no historical use pattern to use as a baseline. However, it has been estimated that new building commissioning will save 8% in energy cost alone compared with the average building which is not commissioned56. This offers a payback for the cost of commissioning in just over four years from the energy savings alone and also provides improved comfort and air quality. Commissioning is often considered to be a punchlist process that ensures that the systems in a building function before the building is turned over to the owner. However, the process outlined in Table 26.7 shows the process beginning in the pre-design phase. It is most effective if allowed to influence both design and construction. It is essential that the energy manager be involved in the commissioning process on the owner’s team no later than the design phase of the construction process. This permits input into the design process that can have major impact on the efficiency of the building as built and can lead to a building that has far fewer operational problems.

26.7 SUMMARY Commissioning of existing buildings is emerging as one of the most cost effective ways for an energy manager to lower operating costs, and typically does so with no capital investment, or with a very minimal amount. It has been successfully implemented in several hundred buildings and provides typical paybacks of one to three years. It is much more than the typical O&M program. It does not ensure that the systems function as originally designed, but focuses on improving overall system control and operations for the building as it is currently utilized and on meeting existing facility needs. During the CC process, a comprehensive engineering evaluation is conducted for both building functionality and system functions. The optimal operational parameters and schedules are developed based on actual building conditions. An integrated approach is used to implement these optimal schedules to ensure practical local and

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Table 26.7. The commissioning process for new buildings57. ————————————————————————— 1. Conception or pre-design phase (a) Develop commissioning objectives (b) Hire commissioning provider (c) Develop design phase commissioning requirements (d) Choose the design team ————————————————————————— 2. Design phase (a) Commissioning review of design intent (b) Write commissioning specifications for bid documents (c) Award job to contractor (d) Develop commissioning plan ————————————————————————— 3. Construction/Installation phase (a) Gather and review documentation (b) Hold commissioning scoping meeting and finalize plan (c) Develop pre-test checklists (d) Start up equipment or perform pre-test checklists to ensure readiness for functional testing during acceptance ————————————————————————— 4. Acceptance phase (a) Execute functional test and diagnostics (b) Fix deficiencies (c) Retest and monitor as needed (d) Verify operator training (e) Review O&M manuals (f) Building accepted by owner ————————————————————————— 5. Post-acceptance phase (a) Prepare and submit final report (b) Perform deferred tests (if needed) (c) Develop recommissioning plan/schedule ————————————————————————— global system optimization and to ensure persistence of the improved operational schedules. The approach presented in this chapter begins by conducting a thorough examination of all problem areas or operating problems in the building, diagnoses these problems, and develops solutions that solve these problems while almost always reducing operating costs at the same time. Equipment upgrades or retrofits may be implemented as well, but have not been a factor in the case studies presented, except where the commissioning was used to finance equipment upgrades. This is in sharp contrast to the more usual approach to improving

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the efficiency of HVAC systems and cutting operating costs that primarily emphasizes system upgrades or retrofits to improve efficiency. Commissioning of new buildings is also an important option for the energy manager, offering an opportunity to help ensure that new buildings have the energy efficiency and operational features that are most needed.

26.8. FOR ADDITIONAL INFORMATION Two major sources of information on commissioning existing buildings are the Continuous Commissioning SM Guidebook: Maximizing Building Energy Efficiency and Comfort (Liu, M., Claridge, D.E. and Turner, W.D., Federal Energy Management Program, U.S. Dept. of Energy, 144 pp., 2002) and A Practical Guide for Commissioning Existing Buildings (Haasl, T. and Sharp, T., Portland Energy Conservation, Inc. and Oak Ridge National Laboratory for U.S. DOE, ORNL/TM-1999/34, 69 pp. + App., 1999). Much of this chapter has been abridged and adapted from the CC Guidebook. There are a much wider range of materials available that treat commissioning of new buildings. Two documents that provide a good starting point are ASHRAE Guideline 1-1996: The HVAC Commissioning Process (American Society of Heating, Refrigerating and Air-Conditioning Engineers, Atlanta, GA, 1996) and the Building Commissioning Guide—Version 2.2 (U.S. GSA and U.S. DOE, 1998 by McNeil Technologies, Inc. and Enviro-Management & Research, Inc. available at www. emrinc.com). The case studies in this chapter have been largely abridged and adapted from the following three papers: Claridge, D.E., Liu, M., Deng, S., Turner, W.D., Haberl, J.S., Lee, S.U., Abbas, M., Bruner, H., and Veteto, B., “Cutting Heating and Cooling Use Almost in Half Without Capital Expenditure in a Previously Retrofit Building,” Proc. of 2001 ECEEE Summer Study, Mandeliu, France, Vol. 2, pp. 74-85, June 11-16, 2001. Turner, W.D., Claridge, D.E., Deng, S. and Wei, G., “The Use of Continuous CommissioningSM As An Energy Conservation Measure (ECM) for Energy Efficiency Retrofits,” Proc. of 11th National Conference on Building Commissioning, Palm Springs, CA, CD, May 20-22, 2003. Claridge, D.E., Turner, W.D., Liu, M., Deng, S., Wei, G., Culp, C., Chen, H. and Cho, S.Y., “Is Commissioning Once Enough?,” Solutions for Energy Security & Facility Management Challenges: Proc. of the 25th WEEC, Atlanta, GA, pp. 29-36, Oct. 9-11, 2002.

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References 1. ASHRAE, ASHRAE Guideline 1-1996: The HVAC Commissioning Process, American Society of Heating, Refrigerating and AirConditioning Engineers, Atlanta, GA, 1996. 2. U.S. Department of Energy, Building Commissioning: The Key to Quality Assurance, Washington, DC. 1999. 3. ibid. 4. Continuous Commissioning is a registered trademark and CC is a service mark of the Texas Engineering Experiment Station (TEES). Contact TEES for further information. 5. Liu, M., Claridge, D.E. and Turner, W.D., Continuous CommissioningSM Guidebook: Maximizing Building Energy Efficiency and Comfort, Federal Energy Management Program, U.S. Dept. of Energy, 144 pp., 2002. 6. Claridge, D.E., Haberl, J., Liu, M., Houcek, J., and Athar, A., “Can You Achieve 150% of Predicted Retrofit Savings: Is It Time for Recommissioning?” A CEEE 1994 Summer Study on Energy Efficiency In Buildings Proceedings: Commissioning, Operation and Maintenance, Vol. 5, American Council for an Energy Efficient Economy, Washington, D.C., pp. 73-87, 1994. 7. Claridge, D.E., Liu, M., Deng, S., Turner, W.D., Haberl, J.S., Lee, S.U., Abbas, M., Bruner, H., and Veteto, B., “Cutting Heating and Cooling Use Almost in Half Without Capital Expenditure in a Previously Retrofit Building,” Proc. of 2001 ECEEE Summer Study, Mandeliu, France, Vol. 2, pp. 74-85, June 11-16, 2001. 8. Turner, W. D., Claridge, D. E., Deng, S. and Wei, G., “The Use of Continuous CommissioningSM As An Energy Conservation Measure (ECM) for Energy Efficiency Retrofits,” Proc. of 11th National Conference on Building Commissioning, Palm Springs, CA, CD, May 20-22, 2003. 9. Zhu, Y., Liu, M., Claridge, D.E., Feary, D. and Smith, T., “A Continuous Commissioning Case Study of a State-of-the-Art Building,” Proceedings of the 5th National Commissioning Conference, Huntington Beach, CA, pp. 13.1 - 13. 10, April, 1997. 10. Liu, M., Zhu, Y., Powell, T., and Claridge, D.E., “System Optimization Saves $195,000/yr. in a New Medical Facility,” Proceedings of the 6th National Conference on Building Commissioning, Lake Buena Vista, FL, pp. 14.2.1-14.2.11, May 18-20, 1998. 11. Turner, et al., op. cit. 12. Source: Adapted from Turner et al. op. cit. 13. Source: Liu, Claridge, and Turner, op. cit. 14. Source: ibid. 15. Source: ibid. 16. Source: ibid. 17. Liu, M., Zhu, Y., Park, B.Y., Claridge, D.E., Feary, D.K. and Gain, J., “Airflow Reduction to Improve Building Comfort and Reduce Building Energy Consumption - A Case Study,” ASHRAE Transactions-Research, Vol. 105, Part 1, pp. 3 84 - 3 90, 1999. 18. Liu, M., Zhu, Y., Claridge, D. and White, E., “Impacts of Static Pressure Set Level on the HVAC Energy Consumption and Indoor Conditions,” ASHRAE Transactions-Research. Volume 103, Part 2, pp. 221-228, 1997. 19. Liu, Claridge, and Turner, op. cit. 20. ibid. 21. ibid. 22. Liu, M., “Variable Speed Drive Volumetric Tracking (VSDVT) for Airflow Control in Variable Air Volume (VAV) Systems,” Proceedings of Thirteenth Symposium on Improving Building Systems in Hot and Humid Climates, San Antonio, TX, pp. 195-198, May 15-16, 2002. 23. Claridge, et al. 2001, op. cit. 24. Source: ibid. 25. Source: ibid. 26. Source: ibid. 27. Source: ibid. 28. Source: ibid. 29. Source: ibid.

COMMISSIONING FOR ENERGY MANAGEMENT 30. Liu, Claridge, and Turner, op. cit. 31. Liu, M., “Variable Water Flow Pumping for Central Chilled Water Systems,” ASME Journal of Solar Energy Engineering, Vol. 124, pp. 300-304, 2002. 32. Deng, S., Turner, W.D., Batten, T., and Liu, M., “Continuous ConumriissioningSM of a Central Chilled Water and Heating Hot Water System,” Proc. Twelfth Symposium on Improving Building Systems in Hot and Humid Climates, San Antonio, TX, pp. 199-206, May 15-16, 2000. 33. Deng, S. Turner, W. D., Claridge, D. E., Liu, M., Bruner, H., Chen, H. and Wei, G. “Retrocommissioning of Central Chilled/ Hot Water Systems,” ASHRAE Transactions-Research, Vol. 108, Part 2, pp. 75-81, 2002. 34. Liu, Claridge, and Turner, op. cit. 35. Liu, M., op. cit. 36. Liu, Claridge, and Turner, op. cit. 37. Wei, G., Liu, M., and Claridge, D.E., “In-situ Calibration of Boiler Instrumentation Using Analytic Redundancy,” International Journal of Energy Research, Vol. 25, pp. 375-387, 2001. 38. Liu, M. et al., 1998, op. cit. 39. IpMVp Committee, International Performance Measurement & Verification Protocol.- Concepts and Options for Determining Energy and Water Savings, Vol. 1, U.S. Dept. of Energy, DOE/GO102001-1187, January, 2001, 86 pp 40. Source: Liu, Claridge, and Turner, op. cit. 41. Wei, G., Liu, M., and Claridge, D.E., “Signatures of Heating and Cooling Energy Consumption for Typical AHUs,” The Eleventh Symposium on Improving Building Systems in Hot and Humid Climates Proceedings, Fort Worth, Texas, pp. 387-402, June 1-2, 1998. 42. Liu, M. and Claridge, D.E., “Use of Calibrated HVAC System Models to Optimize System Operation,” ASME Journal of Solar Energy Engineering, Vol. 120, pp. 131-138, 1998. 43. Claridge, D.E., Bensouda, N., Lee, S.U., Wei, G., Heinemeier, K.,

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44. 45.

46.

47. 48. 49. 50. 51. 52.

53. 54. 55. 56.

and Liu, M., Manual of Procedures for Calibrating Simulations of Building Systems, submitted to the Lawrence Berkeley National Laboratory under Sponsored Contract #66503346 as part of the California Energy Commission Public Interest Energy Research Program, 94 pp., October, 2003. Source: Liu, Claridge, and Turner, op. cit. Turner, W.D., Claridge, D.E., Deng, S., Cho, S., Liu, M., Hagge, T., Darnell, C., Jr., and Bruner, H., Jr., “Persistence of Savings Obtained from Continuous ConunissioningSM,” Proc. of 9th National Conference on Building Commissioning, Cherry Hill, NJ, pp. 20-1.1 - 20-1.13, May 9-11, 2001. Claridge, D.E., Turner, W.D., Liu, M., Deng, S., Wei, G., Culp, C., Chen, H. and Cho, S.Y., “Is Commissioning Once Enough?,” Solutions for Energy Security & Facility Management Challenges: Proc. of the 25 h WEEC, Atlanta, GA, pp. 29-36, Oct. 9-11, 2002. Source: ibid. ibid. Source: ibid. Source: ibid. Lewis, T., H. Chen, and M. Abbas, “CC summary for the Kleberg Building,” Internal ESL Report, July, 1999. Chen, H., Deng, S., Bruner, H., Claridge, D. and Turner, W.D., “Continuous CommissioningSM Results Verification And Follow-Up For An Institutional Building - A Case Study,” Proc. 13th Symposium on Improving Building Systems in Hot and Humid Climates, Houston, TX, pp. 87-95, May 20-23, 2002. Source: Claridge, D.E. et al. 2002, op. cit. Source: ibid. PECI, “National Strategy for Building Commissioning,” Portland Energy Conservation, Inc., Portland, OR, 1999. Adapted from Haasl, T. and Sharp, T., A Practical Guide for Commissioning Existing Buildings, Portland Energy Conservation, Inc. and Oak Ridge National Laboratory for U.S. DOE, ORNL/TM1999/34, 69 pp. + App., 1999.

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CHAPTER 27

MEASUREMENT AND VERIFICATION OF ENERGY SAVINGS JEFF S. HABERL, PH.D., P.E. CHARLES C. CULP, PH.D., P.E. Energy Systems Laboratory Texas A&M University

27.1 INTRODUCTION 27.1.1 M&V Method Selection Measurement and verification (M&V) has a dual role. First, M&V quantifies the savings being obtained. This applies to the initial savings and the long-term savings. Since the persistence of savings has been shown to decrease with time,1 long term M&V provides data to make these savings sustainable. Second, M&V must be cost effective so that the cost of measurement and the analysis does not consume the savings.2,3 The 1997 International Performance Measurement and Verification Protocol (IPMVP) set the target costs for M&V to be in the range of 1% to 10%, depending upon the Option selected, of the construction cost for the life of the ECM. Most approaches fall in the recommended range of 3% to 10% of the construction cost. The IPVMP 2001 removed this guidance on the recommended costs for M&V. Currently, a goal of about 5% of the savings per year has evolved as a preferred criterion for costing M&V, since the cost justification directly results from the calculation. A general procedure for selecting an approach can be summarized by the following five steps: a) In general one wants to try to... Perform Monthly Utility Bill Before/After Analysis. b) And if this does not work, then… Perform Daily or Hourly Before/After Analysis. c) And if this does not work, then… Perform Component Isolation Analysis. d) And if this does not work, then… Perform Calibrated Simulation Analysis. e) Then… Report savings and Finish Analysis. 27.1.2 History of M&V 27.1.2.1 History of Building Energy Measurement. The history of the measurement of building energy use can be traced back to the 19th century for electricity, and earlier for fuels such as coal and wood, which were used to heat buildings.4,5,6,7 By the 1890s, although electricity was common in many new commercial build-

ings, its use was primarily for incandescent lighting and, to a lesser extent, for the electric motors associated with ventilating buildings since most of the work in office buildings was carried out during daylight hours. The metering of electricity closely paralleled the spread of electricity into cities as its inventors needed to recover the cost of its production through the collection of payments from electric utility customers.8,9 Commercial meters for the measurement of flowing liquids in pipes can be traced back to the same period, beginning with the invention of the first commercial flow meter by Clemens Herschel in 1887, which used principles based on the pitot tube and venturi flow meter, invented in 1732 and 1797 by their respective namesakes.10 Commercial meters for the measurement of natural gas can likewise be traced to the sale and distribution of natural gas, which paralleled the development of the electric meters. 27.1.2.2 History of M&V in the U.S. 27.1.2.2.1 History of M&V The history of the measurement and verification of building energy use parallels the development and use of computerized energy calculations in the 1960s, with a much accelerated awareness in 1973, when the embargo on Mideast oil made energy a front page issue.11,12 During the 1950s and 1960s most engineering calculations were performed using slide rules, engineering tables and desktop calculators that could only add, subtract, multiply and divide. Since the public was led to believe energy was cheap and abundant,13 the measurement and verification of the energy use in a building was limited for the most part to simple, unadjusted comparisons of monthly utility bills. In the 1960s several efforts were initiated to formulate and codify equations that could predict dynamic heating and cooling loads, including efforts at the National Bureau of Standards to predict temperatures in fallout shelters,14 and the 1967 HCC program developed by a group of mechanical engineering consultants,15 which used the Total Equivalent Temperature Difference/Time Averaging (TETD/TA) method. The popularity of this program prompted the American Society of Heating, Refrigeration and Air-Conditioning Engineers (ASHRAE) to embark on a series of efforts that eventually delivered today’s modern, general purpose simulation programs16 (i.e., DOE-2, BLAST, EnergyPlus, etc.),

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which utilize thermal response factors,17,18 as well as algorithms for simulation of the quasi-steady-state performance of primary and secondary equipment.19 One of these efforts was to validate the hourly calculations with field measurements at the Legal Aid Building on the Ohio State University campus,20 which is probably the first application of a calibrated, building energy simulation program. Some of the earliest efforts to develop standardized methods for the M&V of building energy use began with efforts to normalize residential heating energy use in single-family and multi-family buildings,21 which include the Princeton Scorekeeping Method (PRISM),22 a forerunner to ASHRAE’s Variable-based Degree Day (VBDD) calculation method. In commercial buildings, numerous methods have been reported over the years23,24,25 varying from weather normalization using monthly utility billing data,26,27,28 daily and hourly methods,29 and even dynamic inverse models using resistance-capacitance (RC) networks.30 Procedures and methodologies to baseline energy use in commercial buildings began to appear in several publications in the 1980s31,32,33 and the early 1990s.34,35,36 Modeling toolkits and software have been developed that are useful in developing performance metrics for buildings, as well HVAC system components. These efforts include

the Princeton Scorekeeping Software (PRISM),37 which is useful for developing variable-based degree day models of monthly or daily data, ASHRAE’s HVAC01 software for modeling primary HVAC systems such as boilers, and chillers,38 ASHRAE’s HVAC02 software for modeling secondary HVAC systems including air-handlers, blowers, cooling coils and terminal boxes,39 and ASHRAE’s Research Projects 827-RP for in-situ measurement of chillers, pumps, and blowers,40 Research Project 1004-RP for in-situ measurement of thermal storage systems,41 Research Project 1050-RP Toolkit for Calculating Linear, Change-point Linear and Multiple-Linear Inverse Building Energy Analysis Models, and Research Project 1093-RP toolkit for calculating diversity factors for energy and cooling loads.43 In 1989, a report by Oak Ridge National Laboratory44 classified the diverse commercial building analysis methods into five categories, including: annual total energy and energy intensity comparisons, linear regression and component models, multiple linear regression, building simulation, and dynamic (inverse) thermal performance models. In 1997 a reorganized and expanded version of this classification appeared in the ASHRAE Handbook of Fundamentals, and is shown in Tables 27.1 and 27.2. In Table 27.1 different methods of analyzing building energy are presented, which have been clas-

Table 27.1 ASHRAE’s 1997 Classification of Methods for the Thermal Analysis of Buildings.57

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Table 27.2 ASHRAE’s 1997 Decision Diagram for Selection of Model.58

sified according to model type, including: forward, inverse, and hybrid models.45 In the first method, forward modeling, a thermodynamic model is created of a building using fundamental engineering principles to predict the hypothetical energy use of a building for 8,760 hours of the year given the location, and weather conditions. This requires a complete description of the building, system, or component of interest, as well as the physical description of the building geometry, geographical location, system type, wall insulation value, etc. Forward models are normally used to design and size HVAC systems, and have begun to be used to model existing building, using a technique referred to as calibrated simulation. In the second method, inverse modeling, an empirical analysis is conducted on the behavior of the building as it relates to one or more driving forces or parameters. This approach is referred to as a system identification, parameter identification or inverse modeling. To develop an inverse model, one must assume a physical configuration of the building or system, and then identify the parameter of interest using statistical analysis.46 Two primary types of inverse models have been reported in the literature, including: steady state inverse models and dynamic inverse models. A third category, hybrid models, consists of models that have characteristics of both forward and inverse models.47 The simplest steady-state inverse model regresses monthly utility consumption data against average bill-

ing period temperatures. More robust methods include multiple linear regression, change-point linear regression, and Variable-Based Degree Day regressions as indicated in Table 27.1. The advantage of steady-state inverse models is that their use can be automated and applied to large datasets where monthly utility billing data and average daily temperatures for the billing periods are available. Steady-state inverse models can also be applied to daily data which allows one to compensate for differences in weekday and weekend use.48 Unfortunately, steady state inverse models are insensitive to dynamic effects (i.e., thermal mass), and other variables (for example humidity and solar gain), and are difficult to apply to certain building types, for example buildings that have strong on/off schedule dependent loads, or buildings that display multiple change-points. Dynamic inverse models include: equivalent thermal network analysis,49 ARMA models,50,51 Fourier series models,52,53 machine learning,54 and artificial neural networks.55,56 Unlike steady-state, inverse models, dynamic models are capable of capturing dynamic effects such as thermal mass which traditionally have required the solution of a set of differential equations. The disadvantages of dynamic inverse models are that they are increasingly complex, and need more detailed measurements to “tune” the model. Hybrid models are models that contain forward and inverse properties. For example, when a traditional fixed-schematic simulation program such as DOE-2 or

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BLAST (or even a component-based simplified model) is used to simulate the energy use of an existing building then one has a forward analysis method that is being used in an inverse application, i.e., the forward simulation model is being calibrated or fit to the actual energy consumption data from a building in much the same way that one fits a linear regression of energy use to temperature. Table 27.2 presents information that is useful for selecting an inverse model where usage of the model (diagnostics - D, energy savings calculations - ES, design De, and control - C), degree of difficulty in understanding and applying the model, time scale for the data used by the model (hourly - H, daily - D, monthly - M, and sub-hourly - S), calculation time, and input variables used by the models (temperature - T, humidity - H, solar - S, wind - W, time - t, thermal mass - tm), and accuracy are used to determine the choice of a particular model. 27.1.2.2.2 History of M&V Protocols in the United States The history of measurement and verification protocols in the United States can be traced to independent M&V efforts in different regions of the country as shown in Table 27.3, with states such as New Jersey, California, and Texas developing protocols that contained varying procedures for measuring the energy and demand savings from retrofits to existing buildings. These efforts

culminated in the development of the USDOE’s 1996 North American Energy Measurement and Verification Protocol (NEMVP),59 which was accompanied by the USDOE’s 1996 FEMP Guidelines,60 both relying on analysis methods developed in the Texas LoanSTAR program.61 In 1997 the NEMVP was updated and republished as the International Performance Measurement and Verification Protocols (IPMVP). The IPMVP was then expanded in 2001 into two volumes: Volume I covering Energy and Water Savings,63 and Volume II covering Indoor Environmental Quality.64 In 2003 Volume III of the IPMVP was published, which covers protocols for new construction.65 Finally, in 2002 American Society of Heating Refrigeration Air-conditioning Engineers (ASHRAE) released Guideline 14-2002: Measurement of Energy and Demand Savings,66 which is intended to serve as the technical document for the IPMVP. 27.1.3 Performance Contracts In order to reduce costs and improve the HVAC and lighting systems in its buildings, the U.S. federal government has turned to the private energy efficiency sector to develop methods to finance and deliver energy efficiency to the government. One of these arrangements, the performance contract, often includes a guarantee of performance, which benefits from accurate, reliable measurement and verification. In such a contract

Table 27.3: History of M&V Protocols ———————————————————————————————————————— 2003 - IPMVP - 2003 Volume III (new construction) 2002 - ASHRAE Guideline 14 - 2002 2001 - IPMVP - 2001 Volume I & II (revised and expanded IPMVP) 1998 - Texas State Performance Contracting Guidelines 1997 - IPMVP (revised NEMVP) 1996 - FEMP Guidelines 1996 - NEMVP 1995 - ASHRAE Handbook - Ch. 37 “Building Energy Monitoring” 1994 - PG&E Power Saving Partner “Blue Book” 1993 - NAESCO M&V Protocols 1993 - New England AEE M&V Protocols 1992 - California CPUC M&V Protocols 1989 - Texas LoanSTAR Program 1988 - New Jersey M&V Protocols 1985 - First Utility Sponsored Large Scale Programs to Include M&V 1985 - ORNLs “Field Data Acq. For Bld & Eqp Energy Use Monitoring” 1983 - International Energy Agency “Guiding Principles for Measurement” 1980s - USDOE funds the End - Use Load and Consumer Assessment Program (ELCAP) 1980s - First Utility Sponsored Large Scale Programs to Include M&V 1970s - First Validation of Simulations 1960s - First Building Energy Simulations on Mainframe Computers ————————————————————————————————————————

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all costs of the project (i.e., administration, measurement and verification, overhead and profit) are paid for by the energy saved from the energy or water conservation projects. In principle, this is a very attractive option for the government, since it avoids paying the initial costs of the retrofits, which would have to come from shrinking taxpayer revenues. Instead, the costs are paid over a series of years because the government agrees to pay the Energy Service Company (ESCO) an annual fee that equals the annual normalized costs savings of the retrofit (plus other charges). This allows the government to finance the retrofits by paying a pre-determined annual utility bill over a series of years, which equals the utility bill during the base year had the retrofit not occurred. In reality, because the building has received an energy conservation retrofit, the actual utility bill is reduced, which allows funding the annual fee to the ESCO without realizing any increase in the total annual utility costs (i.e., utility costs plus the ESCO fee). Once the performance contract is paid off, the total annual utility bills for the government are reduced and the government receives the full savings amount of the retrofit. 27.1.3.1 Definitions, Roles and Participants There are many different types of performance contracts, which vary according to risk, and financing, including Guaranteed Savings, and Shared Savings.67 In a Guaranteed Savings performance contract a fixed payment is established that repays the ESCO’s debt financing of the energy conservation retrofit, and any fees associated with the project. In return, the ESCO guarantees that the energy savings will cover the fixed payment to the ESCO. Hence, in a Guaranteed Savings contract the ESCO is responsible for the majority of the project risks. In a Shared Savings performance contract payments to the ESCO are based on an agreed-upon portion of the estimated savings generated by the retrofit. In such contracts the M&V methods selected determine the level of risk, and the responsibilities of the ESCO, and building owner. In both types of contracts the measurement and verification of the energy savings plays a crucial role in determining payment amounts.

27.2 OVERVIEW OF MEASUREMENT AND VERIFICATION METHODS Nationally recognized protocols for measurement and verification have evolved since the publication of the 1996 NEMVP as shown in Table 27.4. This evolution reflects the consensus process that the Department of Energy has chosen as a basis for the protocols. This

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process was chosen to produce methods that all parties agree can be used by the industry to determine savings from performance contracts, varying in accuracy and cost from partial stipulation to complete measurement. In 1996 three M&V methods were included in the NEMVP: Option A: measured capacity with stipulated consumption; Option B: end-use retrofits, which utilized measured capacity and measured consumption; and Option C: whole-facility or main meter measurements, which utilize before after regression models. In 1997, Options A, B and C were modified and relabeled, and Option D: calibrated simulation was added. Also included in the 1997 IPMVP was a chapter on measuring the performance of new construction, which primarily utilized calibrated simulation, and a discussion of the measurement of savings due to water conservation efforts. In 2001 the IPMVP was published in two volumes: Volume I, which covers Options A, B, and C, which were redefined and relabeled from the 1997 IPMVP, and Volume II, which covers indoor environmental quality (IEQ), and includes five M&V approaches for IEQ, including: no IEQ M&V, M&V based on modeling, short-term measurements, long-term measurements, and a method based on occupant perceptions of IEQ. In 2003 the IPMVP released Volume III, which contains four M&V methods: Option A: partially measured Energy Conservation Measure (ECM) isolation, Option B: ECM isolation, Option C: whole-building comparisons, and Option D: whole-building calibrated simulation. In 2002 ASHRAE released Guideline 14-2002: Measurement of Energy and Demand Savings, which is intended to serve as the technical document for the IPMVP. As the name implies, Guideline 14 contains approaches for measuring energy and demand savings from energy conservation retrofits to buildings. This includes three methods: a retrofit isolation approach, which parallels Option B of the IPMVP, a whole-building approach, which parallels Option C of the IPMVP, and a whole-building calibrated simulation approach, which parallels Option D of the 1997 and 2001 IPMVP. ASHRAE’s Guideline 14 does not explicitly contain an approach that parallels Option A in the IPMVP, although several of the retrofit isolation approaches use partial measurement procedures, as will be discussed in a following section. 27.2.1 M&V Methods: Existing Buildings In general, a common theme between the NEMVP, IPMVP and ASHRAE’s Guideline 14-2002, is that M&V methods for measuring energy and demand savings in existing building are best represented by the following three approaches: retrofit isolation approach, a whole-

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building approach, and a whole-building calibrated simulation approach. Similarly, the measurement of the performance of new construction, renewables, and water use utilize one or more of these same methods. 27.2.1.1 Retrofit Isolation Approach The retrofit isolation approach is best used when end use capacity, demand or power can be measured during the baseline period, and after the retrofit for short-term period(s) or continuously over the life of the project. This approach can use continuous measurement of energy use both before and after the retrofit. Likewise, periodic, short-term measurements can be used during the baseline and after the retrofit to determine the retrofit savings. Often such short-term measurements are accompanied by periodic inspections of the equipment to assure that the equipment is operating as specified. In most cases energy use is calculated by developing representative models of the isolated component load (i.e., the kW or Btu/hr) and energy end-use (i.e., the kWh or Btu). 27.2.1.1.1 Classifications of Retrofits According to ASHRAE’s Guideline 14-2002 retrofit isolation approach, components or end-uses can be classified according to the following definitions:68 •

Constant Load, Constant use. Constant load, constant use systems consist of systems where the energy used by the system is constant (i.e., varies by less than 5%) and the use of the system is constant (i.e., varies by less than 5%) through both the baseline and post-retrofit period.

•

Constant Load, Variable use. Constant load, variable use systems consist of systems where the energy used by the system is constant (i.e., varies by less than 5%) but the use of the system is variable (i.e., varies by more than 5%) through either the baseline or post-retrofit period.

•

Variable Load, Constant use. Variable Load, constant use systems consist of systems where the energy used by the system is variable (i.e., varies by more than 5%) but the use of the system is constant (i.e., varies by less than 5%) through either the baseline or post-retrofit period.

•

Variable Load, Variable use. Variable Load, variable use systems consist of systems where the energy used by the system is variable (i.e., varies by more than 5%) and the use of the system is variable (i.e., varies by more than 5%) through either the baseline or post-retrofit period.

Use of these classifications then allows for a simplified decision table (Table 27.5) to be used in determining which type of retrofit-isolation procedure to use. For example, in the first row (i.e., a CL/TS-preretrofit to CL/TS-post-retrofit), if a constant load with a known or timed schedule is replaced with a new device that has a reduced constant load, and a known or constant schedule, then the pre-retrofit and postretrofit metering can be performed with one-time load measurement(s). Contrast this with the last row (i.e., a VL/VS-pre-retrofit to VL/VS-post-retrofit), if a variable load, with a timed or variable schedule is replaced with

Table 27.4: Evolution of M&V Protocols in the United States.

MEASUREMENT AND VERIFICATION OF ENERGY SAVINGS

a new device that has a reduced variable load, and a variable schedule, then the pre-retrofit and post-retrofit metering should use continuous or short-term measurement that are sufficient in length to allow for the characterization of the performance of the component to be accomplished with a model (e.g., regression, or engineering model). 27.2.1.1.2 Detailed Retrofit Isolation Measurement and Verification Procedures Appendix E of ASHRAE’s Guideline 14-2002 contains detailed retrofit isolation procedures for the

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measurement and verification of savings, including: pumps, fans, chillers, boilers and furnaces, lighting, and large and unitary HVAC systems. In general, the procedures were drawn from the previous literature, including ASHRAE’s Research Project 827-RP70 (i.e., pumps, fans, chillers), various published procedures for boilers and furnaces, 71,72,73,74,75,76,77 lighting procedures, and calibrated HVAC calibration simulations.78,79 A review of these procedures, which vary from simple one-time measurements, to complex, calibrated air-side psychrometric models, is described it the following sections.

Table 27.5: Metering Requirements to Calculate Energy and Demand Savings from the ASHRAE Guideline 14-2002.69

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A. Pumps Most large HVAC systems utilize electric pumps for moving heating/cooling water from the building’s primary systems (i.e., boiler or chiller) to the building’s secondary systems (i.e., air-handling units, radiators, etc.) where it can condition the building’s interior. Such pumping systems use different types of pumps, varying control strategies, and piping layouts. Therefore, the characterization of pumping electric power depends on the system design and control method used. Pumping

systems can be characterized by the three categories shown in Table 27.6.80 Table 27.7 shows the six pump testing methods, including the required measurements, applications and procedures steps. ASHRAE’s Research Project 827-RP81 developed six in-situ methods for measuring the performance of pumps of varying types and controls. To select a method the user needs to determine the pump system type and control, and the desired level of uncertainty, cost, and degree of intrusion. The user also needs to record

Table 27.6: Applicability of Test Methods to Common Pumping Systems from the ASHRAE Guideline 14-2002.82

Table 27.7: Pump Testing Methods from ASHRAE Guideline 14-2002.83

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Table 27.7 (Continued)

the pump and motor data (i.e., manufacturer, model and serial number), fluid characteristics and operating conditions. The first two methods (i.e., single-point and single-point with a manufacturer’s curve) involve testing at a single operating point. The third and fourth procedures involve testing at multiple operating points under imposed system loading. The fifth method also involves multiple operating points, in this case obtained through short term monitoring of the system without imposed loading. The sixth procedure operates the pump with the fluid flow path completely blocked. While the sixth procedure is not useful for generating a power versus load relationship, it can be used to confirm manufacturer’s data or to identify pump impeller diameter. A summary of the methods is provided below. Additional details can be found by consulting ASHRAE’s Guideline 14-2002. A-1. Constant Speed and Constant Volume Pumps Constant volume pumping systems use three way

valves and bypass loops at the end-use or at the pump. As the load varies in the system, pump pressure and flow are held relatively constant, and the pump input power remains nearly constant. Because pump motor speed is constant, constant volume pumping systems have a single operating point. Therefore, measuring the power use at the operating point (i.e., a single point measurement) and the total operating hours are enough to determine annual energy use. A-2. Constant Speed and Variable Volume Pumps Variable pumping systems with constant speed pumps use two-way control valves to modulate flow to the end-use as required. In constant speed variable volume pumping systems, the flow varies along the pump curve as the system pressure drop changes in response to the load. In some cases, a bypass valve may be modulated if system differential pressure becomes too large. Such systems have a single possible operating point for any given flow, as determined by the pump curve at that flow

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rate. In such systems the second and third testing methods can be used to characterize the pumps energy use at varying conditions. In the second procedure, measurements of in-situ power use is performed at one flow rate and manufacturer’s data on the pump, motor, and drive system are used to create a part load power use curve. In the third testing method in-situ measurements are made of the electricity use of the pump with varying loads imposed on the system using existing control, discharge, or balancing valves. The fourth and fifth methods can also be used to characterize the pump electricity use. Using one of these methods the part load power use curve and a representative flow load frequency distribution are used to determine annual energy use.

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the annual energy use can be calculated using the following procedures, depending upon whether the system is a constant volume or variable volume pumping system. Savings are then calculated by comparing the annual energy use of the baseline with the annual energy use of the post-retrofit period. Constant Volume Constant Speed Pumping Systems. In a constant volume constant speed pumping systems the volume of the water moving through the pump is almost constant, and therefore the power load of the pump is virtually constant. The annual energy calculation is therefore a constant times the frequency of the operating hours of the pump. Eannual = T * P

A-3. Variable Speed and Variable Volume Pumps Like the constant speed variable volume system, flow to the zone loads is typically modulated using two-way control valves. However, in variable speed variable volume pumping systems, a static pressure controller is used to adjust pump speed to match the flow load requirements. In such systems the operating point cannot be determined solely from the pump curve and flow load because a given flow can be provided at various pressures or speeds. Furthermore, the system design and control strategy place constraints on either the pressure or flow. Such systems have a range of system curves which call for the same flow rate, depending on the pumping load. 827-RP provides two options (i.e., multiple point with imposed loads and short term monitoring) for accurately determining the in-situ part load power use. In both cases, the characteristics of the in-situ test include the pump and piping system (piping, valves, and controllers), therefore the control strategy is included within the data set. In the fourth method (i.e., multiple point with imposed load at the zone), the pump power use is measured at a range of imposed loads. These imposed loads are done at the zone level to account for the in-situ control strategy and system design. In the fifth method (i.e., multiple point through short term monitoring), the pump system is monitored as the building experiences a range of thermal loads, with no artificial imposition of loads. If the monitored loads reflect the full range of loads, then an accurate part load power curve can be developed that represents the full range of annual load characteristics. For methods #4 and #5, the measured part load power use curves and flow load frequency distribution are used to determine annual energy use. A-4. Calculation of Annual Energy Use Once the pump performance has been measured

where: T = annual operating hours P = equipment power input Variable Volume Pumping Systems. For variable volume pumping systems the volume of water moving through the pump varies over time, hence the power demand of the pump and motor varies. The annual energy use then becomes a frequency distribution of the load times the power associated with each of the bins of operating hours. In-situ testing is used to determine the power associated with the part load power use.

E annual = Σ Ti * Pi i

where: i Ti Pi

= bin index, as defined by the load frequency distribution = number of hours in bin i = equipment power use at load bin I

B. Fans Most large HVAC systems utilize fans or airhandling units to deliver heating and cooling to the building’s interior. Such air-handling systems use different types of fans, varying control strategies, and duct layouts. Therefore, the characterization of fan electric power depends on the system design and control method used. Fan systems can be characterized by the three categories shown in Table 27.8.84 In a similar fashion as pumping systems, ASHRAE’s Research Project 827-RP developed five in-situ methods for measuring the performance of fans of varying types and controls. To select a method the user needs to determine the system type and control, and the desired

MEASUREMENT AND VERIFICATION OF ENERGY SAVINGS

level of uncertainty, cost, and degree of intrusion. The user also needs to record the fan and motor data (i.e., manufacturer, model and serial number), as well as the operating conditions (i.e., temperature, pressure and humidity of the air stream). The first two methods (i.e., single-point and single-point with a manufacturer ’s curve) involve testing at a single operating point. The third and fourth procedures involve testing at multiple operating points under imposed system loading. The fifth method also involves multiple operating points, in this case obtained through short term monitoring of the system without imposed loading. Additional details about fan testing procedures can be found by consulting ASHRAE’s Guideline 14-2002. B-1. Calculation of Annual Energy Use Once the fan performance has been measured the annual energy use can be calculated using the following procedures, depending upon whether the system is a constant volume or variable volume system. Savings are then calculated by comparing the annual energy use of the baseline with the annual energy use of the post-

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retrofit period. Constant Volume Fan Systems. In a constant volume system the volume of the air moving across the fan is almost constant, and therefore the power load of the fan is virtually constant. The annual energy calculation is therefore a constant times the frequency of the operating hours of the fan. Eannual = T * P where: T = annual operating hours P = equipment power input Variable Volume Systems. For variable volume systems the volume of the air being moved by the fan varies over time, hence the power demand of the fan and motor varies. The annual energy use then becomes a frequency distribution of the load times the power associated with each of the bins of operating hours. In-situ testing is used to determine the power associated with the part load power use.

Table 27.8: Applicability of Test Methods to Common Fan Systems from the ASHRAE Guideline 14-2002.85

Table 27.9: Fan Testing Methods from ASHRAE Guideline 14-2002.86

(Continued)

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Table 27.9: (Continued)

E annual = Σ Ti * Pi i

where: i

=

Ti = Pi =

bin index, as defined by the load frequency distribution number of hours in bin i equipment power use at load bin I

C. Chillers In a similar fashions as pumps and fans, in-situ chiller performance measurements have been also been developed as part of ASHRAE Research Project 827-RP. These models provide useful performance testing methods to evaluate annual energy use and peak demand characteristics for installed watercooled chillers and selected air-cooled chillers. These

procedures require short-term testing of the part load performance of an installed chiller system over a range of building thermal loads and coincident ambient conditions. The test methods determine chiller power use at varying thermal loads using thermodynamic models or statistical models with inputs from direct measurements, or manufacturer ’s data. With these models annual energy use can be determined using the resultant part load power use curve with a load frequency distribution. Such models are capable of calculating the chiller power use as a function of the building thermal load, evaporator and condenser fl ow rates, entering and leaving chilled water temperatures, entering condenser water temperatures, and internal chiller controls. ASHRAE’s Guideline 14-2002 describes two models for calculating the

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power input of a chiller, including simple and temperature dependent thermodynamic models.87,88,89 A third method, which uses a tri-quadratic regression model such as those found in the DOE-2 simulation program,90,91,92,93,94 also provides acceptable performance models, provided that measurements are made over the full operating range.

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Coefficient of Performance (COP):

COP =

Energy Efficiency Ratio (EER):

EER = C-1. Simple Thermodynamic Model Both the simple thermodynamic model and the temperature-dependent thermodynamic model express chiller efficiency as 1/COP because it has a linear relationship with 1/(evaporator load). The simpler version of the chiller model developed predicts a linear relationship between 1/COP and 1/ Qevap, which is independent of the evaporator supply temperature or condenser temperature returning to the chiller. The full form of simple thermodynamic model is shown in the equation below.

1 =–1+ T cwRT/TchwST COP +

1 Q evap

q evapTcwRT – q cond + f HX TchwST

where: TcwRT = Entering (return) condenser water temperature (Kelvin) TchwST

= Leaving (supply) evaporator water temperature (Kelvin)

Qevap = Evaporator load qevap = rate of internal losses in evaporator qcond = rate of internal losses in condenser fHX

= dimensionless term.95

This equation reduces to a simple form that allows for the determination of two coefficients using linear regression, which is shown in the following equation.

In this simplified form the coefficient c1 characterizes the internal chiller losses, while the coefficient c0 combines the other terms of the simple model. The COP fi gure of merit can be converted into conventional efficiency measures of COP or kW per ton using the following relationships:

Btu/hr refrigeration effect = 3.412 COP Watts input

Power per Ton (kW/ton):

kW/ton =

kW input = 12/EER tons refrigeration effect

The simple thermodynamic model can be determined with relatively few measurements of the chiller load (evaporator flow rate, entering and leaving chilled water temperatures) and coincident RMS power use. Unfortunately, variations in the chilled water supply (i.e., the temperature of the chilled water leaving the evaporator) and the condenser water return temperature are not considered. Hence, this model is best used with chiller systems that maintain constant temperature control of evaporator and condenser temperatures. In systems with varying temperatures a temperature-dependent thermodynamic model, or tri-quadratic model yield a more accurate performance prediction. C-2. Temperature-dependent Thermodynamic Model The temperature dependent thermodynamic model includes the losses in the heat exchangers of the evaporator and condenser, which are expressed as a function of the chilled water supply and condenser water return temperatures. The resulting expression uses three coefficients (A0, A1, A2), which are found with linear regression, as shown in the equation that follows.

1 =–1+ T cwRT/TchwST COP +

1 =–C 1 + C0 1 COP Q evap

kW refrigeration effect kW input

– A 0 + A 1 TcwRT – A 2 TcwRT/TchwST Q evap

Use of this temperature dependent thermodynamic model requires the measurement of the chiller load (i.e., evaporator flow rate, entering and leaving chilled water temperatures), coincident RMS power use, and condenser water return temperature. Since this model is sensitive to varying temperatures it is applicable to a wider range of chiller systems.

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To use the temperature dependent model, measured chiller thermal load, coincident RMS power use, chilled water supply temperature, and condenser water return temperatures are used to calculate the three coefficients (A0, A1, A2). To determine A2 the following equation is plotted against TcwRT/TchwST (Kelvin), with value of A2 being determined from the regression lines, which should resemble a series of straight parallel lines, one for each condenser temperature setting.

α=

1 +1– T cwRT/TchwST Q evap COP

The coefficients A 0 and A 1 are determined by plotting β from the next equation, using the already determined value of A2, versus the condenser water return temperature TcwRT (Kelvin). This should result in a group of data points forming a single straight line. The slope of the regression line determines the value of coefficient A1 while the intercept determines the value of coefficient A0.

β=

1 +1– T cwRT/TchwST Q evap COP

+ A 2 TcwRT/TchwST After A0, A1, and A2 have been determined using α and β and from the equations above, the 1/COP can be calculated and used to determine the chiller performance over a wide range of measured input parameters of chiller load, chilled water supply temperature, and condenser water return temperature. C-3. Quadratic Chiller Models Chiller performance models can also be calculated with quadratic models, which can include models that express the chiller power use as a function of the chiller load (quadratic), as a function of the chiller load and chilled water supply temperature (bi-quadratic), or as a function of the chiller load, evaporator supply temperature and condenser return temperature (tri-quadratic). Such models use the quadratic functional form used in the DOE-2 energy simulation program to model partload equipment and plant performance characteristics. Two examples of quadratic models are shown below, one for a monitoring project where chiller electricity use, chilled water production, chilled water supply temperature, and condenser water temperature returning to the chiller were available, which uses a tri-quadratic model as follows:

kW/ton = + + + +

a + b x Tons + c x Tcond + d x Tevap + e x Tons2 f x Tcond2 g x Tevap2 + h x Tons x Tcond I x Tevap x Tons j x Tcond x Tevap + k x Tons x Tcond x Tevap

In a second example, chiller electricity use is modeled with a bi-quadratic model that includes only the chilled water production, and chilled water supply temperature, which reduces to the following form. Either model can easily be calculated from field data in a spreadsheet using multiple linearized regression. kW/ton

= a + b x Tons + c x Tkevap + d x Tons2 + e x Tevap2 + f x Tevap x Tons

C-4. Example: Quadratic Chiller Models An example of a quadratic chiller performance analysis model is provided from hourly measurements that were taken at to determine the baseline model of a cooling plant at an Army base in Texas. Figure 27.1 shows the time series data that were recorded during June and August of 2002. The upper trace is the chiller thermal load (tons), and the lower trace is the ambient temperature during this period. Figure 27.2 shows a time series plot of the recorded temperatures of the condenser water returning to the chiller (upper trace), and the chilled water supply temperatures (lower trace). In Figures 27.3 and 27.4 the performance of the chiller is shown as the chiller efficiency (i.e., kW/ton) versus the chiller load (tons). In Figure 27.3 linear (R2 = 34.3%) and quadratic (R2 = 53.4%) models of the chiller are superimposed over the measured data from the chiller to illustrate how a quadratic model fits the chiller data. In Figure 27.4 a tri-quadratic model (R2 = 83.7%) is shown superimposed over the measured data. A quick inspection of the R2 goodness-of-fit indicators for the linear, quadratic and tri-quadratic models begins to shed some light on how well the models are fitting the data. However, one must also inspect how well the model is predicting the chiller performance at the intended operation points. For example, although a linear model has an inferior R2 when compared to a quadratic model, for this particular chiller, it gives similar performance values for cooling loads ranging from 200 to 450 tons. Choosing the quadratic model improves the prediction of the chiller performance for values below 200 tons. However, it significantly under predicts the kW/ton at 350 tons and over-predicts the kW/ton at values over 500 tons. Hence, both models should be used with caution.

MEASUREMENT AND VERIFICATION OF ENERGY SAVINGS

The tri-quadratic model has an improved R2 of 83.7% and does not seem to contain any ranges where the model’s bias is significant from the measured data (excluding the few stray points which are caused by transient data). Therefore, in the case of this chiller, the additional effort to gather and analyze the chiller load against the chilled water supply temperature and condenser water return temperature is well justified. C-5. Calculation of Annual Energy Use Once the chiller performance has been determined the annual energy use can be calculated using the simple or temperature dependent models to determine the power demand of the chiller at each bin of the cooling load distribution. For chillers with varying temperatures, a load frequency distribution, which contains the two water temperatures, provides the operating hours of the chiller at each bin level. The energy use Ei, and

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power level Pi are given by the equations below. The total annual energy use is then the sum of the product of the number of hours in each bin times the chiller power associated with that bin. Savings are then calculated by comparing the annual energy use of the baseline with the annual energy use of the post-retrofit period. Ei = Ti * Pi Pi = (1/Effi) (Qevap,i)

E annual = Σ Ti * Pi i

where: i = bin index, as defined by load frequency distribution

Figure 27.1: Example chiller analysis. Time series plot of chiller load (upper trace, tons) and ambient temperature (lower trace, degrees F).

Figure 27.3: Example chiller analysis. Chiller performance plot of chiller efficiency (kW/ton) versus the chiller cooling load. Comparisons of linear (R 2 = 34.3%) and quadratic (R2 = 53.4.3%) chiller models are shown.

Figure 27.2: Example chiller analysis. Time series plot of condenser water return temperature (upper trace, degrees F) and chilled water supply temperature (lower trace, degrees F).

Figure 27.4: Example chiller analysis. Chiller performance plot of chiller efficiency (kW/ton) versus the chiller cooling load. In this figure a tri-quadratic chiller model (R2 = 83.7%) is shown.

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Ti = number of hours in bin i Pi = equipment power use at load bin i Effi = chiller 1/COP in bin i Qevap,i = chiller load in bin i D. Boilers and Furnaces In-situ boiler and furnace performance measurements, for non-reheat boilers and furnaces, are listed in Appendix E of ASHRAE Guideline 14-2002. These procedures, which were obtained from the previously noted published literature on performance measurements of boilers and furnaces,96,97,98,99,100,101,102 are grouped into four methods (i.e., single-point, single-point with manufacturer’s data, multiple point with imposed loads, and multiple point tests using short term monitoring) that use three measurement techniques (i.e., direct method, direct heat loss method, and indirect combustion method), for a total of twelve methods. The choice of method depends on boiler type (i.e., constant fire boiler, or variable-fire boilers), and availability of measurements (i.e., fuel meters, steam meters, etc.). For constant fire boilers, the boiler load is virtually constant. Therefore, a single measurement or series of measurements a full load will characterize the boiler or furnace efficiency at a given set of ambient conditions. For variable fire boilers the fuel use and output of the boiler varies. Therefore, the efficiency of the boiler will vary depending upon the load of the boiler as described by the manufacturer ’s efficiency curve. Figure 27.5 shows an example of the measured performance of a variable-fire, low pressure steam boiler installed at an army base in Texas.103

Figure 27.5: Example Boiler Performance Curve from Short Term Monitoring.104

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D-1. Boiler Efficiency Measurements There are three principal methods for determining boiler efficiency, the direct method (i.e., Input-Output method), the direct heat loss method, also known as the indirect method, and the indirect combustion efficiency method. The first two are recognized by the American Society of Mechanical Engineers (ASME) and are mathematically equivalent. They give identical results if all the heat balance factors are considered and the boiler measurements performed without error. ASME has formed committees from members of the industry and developed the performance test codes105 that detail procedures of determining boiler efficiency by the first two methods mentioned above. The accuracy of boiler performance calculations is dependent on the quantities measured and the method used to determine the efficiency. In the direct efficiency method, these quantities are directly related to the overall efficiency. For example, if the measured boiler efficiency is 80%, then an error of 1% in one of the quantities measured will result in a 0.8% error in the efficiency. Conversely, in the direct heat loss method, the measured parameters are related to the boiler losses. Therefore, for the same boiler which had an efficiency of 80%, a measurement error of 1% in any quantity affects the overall efficiency by only 0.2% (i.e., 1% of the measured losses of 20%). As a result, the direct heat loss method is inherently more accurate than the direct method for boilers. However, the direct heat loss method requires more measurement and calculations. In general, boiler efficiencies range from 75% to 95% for utility boilers, and for industrial and commercial boilers, the average efficiency ranges from 76% to 83% on gas, 78% to 89% on oil and 85% to 88% for coal.106,107

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•

Direct Method The direct method (i.e., the input-output method) is the simplest method to determine boiler efficiency. In this method, the heat supplied to the boiler and the heat absorbed by the water in the boiler in a given time period are directly measured. Using the direct method, the efficiency of a nonreheat boiler is given by:108

ηb = where Qa moho

mihi

Qi

Vfuel

HHV Qc

•

Qa × 100 Qi

= heat absorbed (Btu/hr) = Σmoho – Σmihi = mass flow-enthalpy products of working fluid streams leaving boiler envelope, including main steam, blowdown, soot blowing steam, etc. = mass flow-enthalpy products of working fluid streams entering boiler envelope, including feedwater, desuperheating sprays, etc. = heat inputs (Btu/hr) = Vfuel x HHV+Qc = volumetric flow of fuel into boiler (SCF/ hr) = fuel higher heating value (Btu/SCF), and = heat credits (Btu/hr). Heat credits are defined as the heat added to the envelope of the steam generating unit other than the chemical heat in the fuel “as fired.” These credits include quantities such as sensible heat in the fuel, the entering air and the atomizing steam. Other credits include heat from power conversion in the pulverizer or crusher, circulating pump, primary air fan and recirculating gas fan.

Direct Heat Loss Method In the direct heat loss method the boiler efficiency equals 100% minus the boiler losses. The direct heat loss method tends to be more accurate than the direct method because the direct heat loss method focuses on determining the heat lost from the boiler, rather than on the heat absorbed by the working fluid. The direct heat loss method determines efficiency using the following:109

ηb =

Q – Q loss Qa × 100 = i × 100 Qi ?

= 100 – Ldf – Lfh – Lam – Lrad – Lconv – Lbd – Linc – Lunacct

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where Qloss Ldf Lfh Lam Lrad Lconv Linc Lbd Lunacct

= = = = = = = = =

heat losses (Btu/hr), dry flue gas heat loss (%), fuel hydrogen heat loss (%), combustion air moisture heat loss (%), radiation heat loss (%), convection heat loss (%), incombusted fuel loss (%), blowdown heat loss (%), unaccounted for heat losses (%).

Using this method the flue gas losses (sensible and latent heat) due to radiation and convection, incomplete combustion, and blowdown are accounted for. In most boilers the flue gas loss is the largest loss, which can be determined by a flue gas analysis. Flue gas losses vary with flue gas exit temperature, fuel composition and type of firing. 110 Radiation and convection loss can be obtained from the standard curves.111 Unaccounted for heat losses can also be obtained from published industry sources,112 which cite losses of 1.5% for solid fuels, and 1% for gaseous or liquid fuel boilers. Losses from boiler blowdown should also be measured. Typical values can be found in various sources.113,114 •

Indirect Combustion Method The indirect combustion method can also be used to measure boiler efficiency. The combustion efficiency is the measure of the fraction of fuel-air energy available during the combustion process, calculated from the folowing:115,116

ηc = where ηc hp hf ha Qi

= = = = =

hp – h f + ha × 100 Qi

combustion efficiency (%) enthalpy of products (Btu/lb) enthalpy of fuel (Btu/lb) enthalpy of combustion air, Btu/lb heat inputs (Btu/hr) = Vfuel * HHV+Qc

Indirect combustion efficiency can be related to direct efficiency or direct heat loss efficiency measurements using the following:117,118 ηb = ηc – Lrad – Lconv – Lunacct On the right side of the equation the loss terms are usually small for well insulated boilers. These

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terms must be accounted for when boilers are poorly insulated or operated poorly (i.e., excessive blowdown control, etc.). Table 27-10 provides a summary of the performance measurement methods (i.e., single-point, single-point with manufacturer’s data, multiple point with imposed loads, and multiple point tests using short term monitoring), which use three efficiency measurement techniques (i.e., direct method, direct heat loss method, and indirect combustion method) that are listed in Appendix E of ASHRAE Guideline 14-2002. For each method the pertinent measurements are listed along with the steps that should be taken to calculate the efficiency of the boiler or furnace being measured. D-2. Calculation of Annual Energy Use Once the boiler performance has been measured the annual energy use can be calculated using the following procedures, depending upon whether the system is a constant fire boiler or variable fire boiler. Savings are then calculated by comparing the annual energy use of the baseline with the annual energy use of the postretrofit period. •

Constant Fire Boilers In constant fire boilers the method assumes the load and fuel use are constant when the boiler is operating. Therefore, the annual fuel input is simply the full-load operating hours of the boiler times the fuel input. The total annual energy use is given by: Eannual = T * P

where: T = annual operating hours under full load P = equipment power use •

Variable Fire Boilers For variable fire boilers the output of the boiler and fuel input vary according to load. Hence a

frequency distribution of the load is needed that provides the operating hours of the boiler at each bin level. In-situ testing is then used to determine the efficiency of the boiler or furnace for each bin. The total annual energy use for variable fire boilers is given by:

E annual = Σ Ti * Pi i

where: i = bin index, as defined by load variable frequency distribution Ti = number of hours in bin i Pi = equipment fuel input (& efficiency) at load bin (i) E. Lighting One of the most common retrofits to commercial buildings is to replace inefficient T-12 fluorescents and magnetic ballasts with T-8 fluorescents and electronic ballasts. This type of retrofit saves electricity associated with the use of the more efficient lighting, and depending on system type, can reduce cooling energy use because of reduced internal loads from the removal of the inefficient lighting. In certain climates, depending on system type, this can also mean an increase in heating loads, which are required to offset the heat from the inefficient lighting. Previously published studies show the cooling interaction can increase savings by 10 to 20%. The increased heating requirements can reduce savings by 5 to 20%.120 Therefore, where the costs can be justified, accurate measurement of total energy savings can involve before/after measurements of the lighting loads, cooling loads, and heating loads. E-1. Lighting Methods ASHRAE Guideline 14-2002 (see Table 27.11) provides six measurement methods to account for the electricity and thermal savings, varying from methods that utilize sampled before/after measurements to methods

Table 27.10: Boiler and Furnace Performance Testing Methods from ASHRAE Guideline 14-2002.119

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Table 27.10 (Continued)

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Table 27.10 (Continued)

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Table 27.10 (Continued)

that use sub-metered before-after lighting measurement with measurements of increases or decreases to the heating and cooling systems from the removal of the internal lighting load. In general, the calculation of savings from lighting retrofits involves ascertaining the wattage or power reduction associated with the new fixtures, which is then multiplied times the hours per day (i.e., lighting usage profiles) that the lights are used. The lighting usage profiles can be calculated based on appropriate estimates of use, measured at the electrical distribution panel, or sampled with lighting loggers. Figure 27.6 shows an example of weekdayweekend profiles calculated with ASHRAE’s Diversity Factor Toolkit.121 Some lighting retrofits involve the installation of daylighting sensors to dim fixtures near the perimeter of the building or below skylights when lighting levels can be maintained with daylighting, thus reducing the electricity used for supplemental lighting. Measuring the savings from such daylighting retrofits usually involves before-after measurements of electrical power and lighting usage profiles. Any lighting retrofit should include an assessment of the existing lighting levels, which is measured during daytime and nighttime conditions. All lighting retrofits should achieve and maintain lighting levels recommended by the Illuminating Engineering Society of North America (IESNA).122 Any pre-retrofit lighting levels not maintaining IESNA lighting levels should be brought to the attention of the building owner or administrator. In the following section the six methods, which are described in the ASHRAE Guideline 142002 are summarized. Table 27.11 contains the lighting performance measurement methods from ASHRAE’s Guideline 14-2002.

•

Method #1: Baseline and post-retrofit measured lighting power levels and stipulated diversity profiles. In Method #1 before-after lighting power levels for a representative sample of lighting fixtures are measured using a Wattmeter, yielding an average Watt/fixture measurement for the pre-retrofit fixtures and post-retrofit fixtures. Lighting usage profiles are estimated or stipulated using the best available information, which represents the lighting usage profiles for the fixtures. This method works best for exterior lighting fixtures or lighting fixtures controlled by a timer or photocell. Lighting fixtures located in hallways, or any interior lighting fixtures that is operated 24 hours per day, 7 days per week or controlled by a timer is also suitable for this method. Savings benefits or penalties from thermal interactions are not included in this method.

Figure 27.6: Example Weekday-Weekend Lighting Profiles.

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•

Method #2: Baseline and post-retrofit measured lighting power levels and sampled baseline and post-retrofit diversity profiles. In Method #2 before-after lighting power levels for a representative sample of lighting fixtures are measured using a Wattmeter, yielding an average Watt/fixture measurement for the pre-retrofit fixtures and post-retrofit fixtures. Lighting usage profiles are measured with portable lighting loggers, or portable current meters attached to lighting circuits to determine the lighting usage profiles for the fixtures. This method is appropriate for any interior or exterior lighting circuit that has predictable usage profiles. Savings benefits or penalties from thermal interactions are not included in this method.

•

Method #3: Baseline measured lighting power levels with baseline sampled diversity profiles and post-retrofit power levels with post-retrofit continuous diversity profile measurements. In Method #3 pre-retrofit lighting power levels for a representative sample of lighting fixtures are measured using a Wattmeter, yielding an average Watt/fixture measurement for the pre-retrofit fixtures. Pre-retrofit lighting usage profiles are measured with portable lighting loggers, or portable current meters attached to lighting circuits to determine the lighting usage profiles for the fixtures. Post-retrofit lighting usage is measured continuously using either sub-metered lighting electricity measurements, or post-retrofit lighting power levels for a representative sample of lighting fixtures times a continuously measured diversity profile (i.e., using lighting loggers or current measurements on lighting circuits). This method is appropriate for any interior or exterior lighting circuit that has predictable usage profiles. Savings benefits or penalties from thermal interactions are not included in this method.

•

Method #4: Baseline measured lighting power levels with baseline sampled diversity profiles and post-retrofit continuous sub-metered lighting.

In Method #4 pre-retrofit lighting power levels for a representative sample of lighting fixtures are measured using a Wattmeter, yielding an average Watt/fixture measurement for the pre-retrofit fixtures. Pre-retrofit lighting usage profiles are measured with portable lighting loggers, or portable current meters attached to lighting circuits to determine the lighting usage profiles for the fixtures. Post-retrofit lighting usage is measured continuously using sub-metered lighting electricity measurements. This method is appropriate for any interior or exterior lighting circuit that has predictable usage profiles. Savings benefits or penalties from thermal interactions are not included in this method. •

Method #5: Includes methods #1, #2, or #3 with measured thermal effect (heating & cooling). In Method #5 pre-retrofit and post-retrofit lighting electricity use is measured with Methods #1, #2, #3 or #4, and the thermal effect is measured using the component isolation method for the cooling or heating system. This method is appropriate for any interior lighting circuit that has predictable usage profiles. Savings benefits or penalties from thermal interactions are included in this method.

•

Method #6: Baseline and post-retrofit sub-metered lighting measurements and thermal measurements. In Method #6 pre-retrofit and post-retrofit lighting electricity use is measured continuously using sub-metering, and the thermal effect is measured using whole-building cooling and heating sub-metered measurements. This method is appropriate for any interior lighting circuit. Savings benefits or penalties from thermal interactions are included in this method.

E-2. Calculation of Annual Energy Use The calculation of annual energy use varies according to lighting calculation method as shown in Table

Table 27.11: Lighting Performance Measurement Methods from ASHRAE Guideline 14-2002.123

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Table 27.11 (Continued)

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27.12. The savings are determined by comparing the annual lighting energy use during the baseline period to the annual lighting energy use during the post-retrofit period. In Methods #5 and #6 the thermal energy effect can either be calculated using the component efficiency methods or it can be measured using whole-building, before-after cooling and heating measurements. Electric demand savings can be calculated using Methods #5 and #6 using diversity factor profiles from the pre-retrofit period and continuous measurement in the post-retrofit period. Peak electric demand reductions attributable to reduced chiller loads can be calculated using the component efficiency tests for the chillers. Savings are then calculated by comparing the annual energy use of the baseline with the annual energy use of the post-retrofit period. F. HVAC Systems As mentioned previously, during the 1950s and 1960s most engineering calculations were performed using slide rules, engineering tables and desktop calculators that could only add, subtract, multiply and divide. In the 1960s efforts were initiated to formulate and codify equations that could predict dynamic heating

and cooling loads, including efforts to simulate HVAC systems. In 1965 ASHRAE recognized that there was a need to develop public-domain procedures for calculating the energy use of HVAC equipment and formed the Presidential Committee on Energy Consumption, which became the Task Group on Energy Requirements (TGER) for Heating and Cooling in 1969.125 TGER commissioned two reports that detailed the public domain procedures for calculating the dynamic heat transfer through the building envelopes,126 and procedures for simulating the performance and energy use of HVAC systems.127 These procedures became the basis for today’s publicdomain building energy simulation programs such as BLAST, DOE-2, and EnergyPlus.128,129 In addition, ASHRAE has produced several additional efforts to assist with the analysis of building energy use, including a modified bin method,130 the HVAC-01131 and HVAC-02 132 toolkits, and HVAC simulation accuracy tests133 which contain detailed algorithms and computer source code for simulating secondary and primary HVAC equipment. Studies have also demonstrated that properly calibrated simplified HVAC system models can be used for measuring the performance of commercial HVAC systems.134,135,136,137

Table 27.12: Lighting Calculations Methods from ASHRAE Guideline 14-2002.124

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F-1. HVAC System Types In order to facilitate the description of measurement methods that are applicable to a wide range of HVAC systems, it is necessary to categorize HVAC systems into groups, such as single zone, steady state systems to the more complex systems such a multi-zone systems with simultaneous heating and cooling. To accomplish this two layers of classification are proposed, in the first layer, systems are classified into two categories: systems that provide heating or cooling under separate thermostatic control, and systems that provide heating and cooling under a combined control. In the second classification, systems are grouped according to: systems that provide constant heating rates, systems that provide varying heating rates, systems that provide constant cooling rates, systems that provide varying cooling rates. •

•

HVAC systems that provide heating or cooling at a constant rate include: single zone, 2-pipe fan coil units, ventilating and heating units, window air conditioners, evaporative cooling. Systems that provide heating or cooling at a constant rate can be measured using: single-point tests, multi-point tests, short-term monitoring techniques, or in-situ measurement combined with calibrated, simplified simulation. HVAC systems that provide heating or cooling at varying rates include: 2-pipe induction units, single zone with variable speed fan and/or compressors, variable speed ventilating and heating units, variable speed, and selected window air conditioners. Systems that provide heating or cooling at varying rates can be measured using: single-point tests, multi-point tests, short-term monitoring techniques, or short-term monitoring combined with calibrated, simplified simulation.

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•

HVAC systems that provide simultaneous heating and cooling include: multi-zone, dual duct constant volume dual duct variable volume, single duct constant volume w/reheat, single duct variable volume w/reheat, dual path systems (i.e., with main and preconditioning coils), 4-pipe fan coil units, and 4-pipe induction units. Such systems can be measured using: in-situ measurement combined with calibrated, simplified simulation.

F-2. HVAC System Testing Methods In this section four methods are described for the in-situ performance testing of HVAC systems as shown in Table 27.14, including: a single point method that uses manufacturer’s performance data, a multiple point method that includes manufacturer’s performance data, a multiple point that uses short-term data and manufacturer’s performance data, and a short-term calibrated simulation. Each of these methods is explained in the sections that follow. •

Method #1: Single point with manufacturer’s performance data In this method the efficiency of the HVAC system is measured with a single-point (or a series) of field measurements at steady operating conditions. On-site measurements include: the energy input to system (e.g., electricity, natural gas, hot water or steam), the thermal output of system, and the temperature of surrounding environment. The efficiency is calculated as the measured output/input. This method can be used in the following constant systems: single zone systems, 2-pipe fan coil units, ventilating and heating units, single speed window air conditioners, and evaporative coolers.

Table 27.13: Relationship of HVAC Test Methods to Type of System.

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•

Method #2: Multiple point with manufacturer’s performance data In this method the efficiency of the HVAC system is measured with multiple points on the manufacturer’s performance curve. On-site measurements include: the energy input to system (e.g., electricity, natural gas, hot water or steam), the thermal output of system, the system temperatures, and the temperature of surrounding environment. The efficiency is calculated as the measured output/input, which varies according to the manufacturer ’s performance curve. This method can be used in the following systems: single zone (constant or varying), 2-pipe fan coil units, ventilating and heating units (constant or varying), window air conditioners (constant or varying), evaporative cooling (constant or varying) 2-pipe induction units (varying), single zone with variable speed fan and/or compressors, variable speed ventilating and heating units, and variable speed window air conditioners.

•

Method #3: Multiple point using short-term data and manufacturer’s performance data In this method the efficiency of the HVAC system is measured continuously over a short-term period, with data covering the manufacturer ’s performance curve. On-site measurements include: the energy input to system (e.g., electricity, natural gas, hot water or steam), the thermal output of system, the system temperatures, and the temperature of surrounding environment. The efficiency is calculated as the measured output/input, which varies according to the manufacturer’s performance curve. This method can be used in the following systems: single zone (constant or varying), 2-pipe fan coil units, ventilating and heating units (constant or varying), window air conditioners (constant or varying), evaporative cooling (constant or varying) 2-pipe induction units (varying), single zone with variable speed fan and/or compressors, variable speed ventilating and heating units, and variable speed window air conditioners.

•

Method #4: Short-term monitoring and calibrated, simplified simulation In this method the efficiency of the HVAC system is measured continuously over a short-term period, with data covering the manufacturer ’s performance curve. On-site measurements include: the energy input to system (e.g., electricity, natural gas, hot water or steam), the thermal output of system, the system temperatures, and the temperature of surrounding environment. The efficiency is calculated using a calibrated air-side simulation of the system, which can include manufacturer’s performance curves for various components. Similar measurements are repeated after the retrofit. This method can be used in the following systems: single zone (constant or varying), 2-pipe fan coil units, ventilating and heating units (constant or varying), window air conditioners (constant or varying), evaporative cooling (constant or varying), 2-pipe induction units (varying), single zone with variable speed fan and/or compressors, variable speed ventilating and heating units, variable speed window air conditioners, multi-zone, dual duct constant volume, dual duct variable volume, single duct constant volume w/reheat, single duct variable volume w/reheat, dual path systems (i.e., with main and preconditioning coils), 4-pipe fan coil units, 4-pipe induction units

F-3. Calculation of Annual Energy Use The calculation of annual energy use varies according to HVAC calculation method as shown in Table 27.15. The savings are determined by comparing the annual HVAC energy use and demand during the baseline period to the annual HVAC energy use and demand during the post-retrofit period. Whole-building or Main-meter Approach Overview The whole-building approach, also called the main-meter approach, includes procedures that measure the performance of retrofits for those projects where whole-building pre-retrofit and post-retrofit data are

Table 27.14: HVAC System Testing Methods.138,139

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Table 27.14 (Continued)

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Table 27.14 (Continued)

Table 27.15: HVAC Performance Measurement Methods from ASHRAE Guideline 14-2002.140

MEASUREMENT AND VERIFICATION OF ENERGY SAVINGS

available to determine the savings, and where the savings are expected to be significant enough that the difference between pre-retrofit and post-retrofit usage can be measured using a whole-building approach. Wholebuilding methods can use monthly utility billing data (i.e., demand or usage), or continuous measurements of the whole-building energy use after the retrofit on a more detailed measurement level (weekly, daily or hourly). Sub-metering measurements can also be used to develop the whole-building models, providing that the measurements are available for the pre-retrofit and post-retrofit period, and that meter(s) measures that portion of the building where the retrofit was applied. Each sub-metered measurement then requires a separate model. Whole-building measurements can also be used on stored energy sources, such as oil or coal inventories. In such cases, the energy used during a period needs to be calculated (i.e., any deliveries during the period minus measured reductions in stored fuel). In most cases, the energy use and/or electric demand are dependent on one or more independent variables. The most common independent variable is outdoor temperature, which affects the building’s heating and cooling energy use. Other independent variables can also affect a building’s energy use and peak electric demand, including: the building’s occupancy (i.e., often expressed as weekday or weekend models), parking or exterior lighting loads, special events (i.e., Friday night football games), etc. Whole-building Energy Use Models Whole-building models usually involve the use of a regression model that relates the energy use and peak demand to one or more independent variables. The most widely accepted technique uses linear or change-point

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linear regression to correlate energy use or peak demand as the dependent variable with weather data and/or other independent variables. In most cases the wholebuilding model has the form: E = C + B1V1 + B2V2 + B3V3 + … where E = the energy use or demand estimated by the equation, C = a constant term in energy units/day or demand units/billing period, Bn = the regression coefficient of an independent variable Vn, Vn = the independent driving variable. In general, when creating a whole-building model for a number of different regression models are tried for a particular building and the results are compared and the best model selected using R2 and CV (RMSE). Table 27.16 and Figure 27.7 contain models listed in ASHRAE’s Guideline 14-2002, which include steadystate constant or mean models, models adjusted for the days in the billing period, two-parameter models, threeparameter models or variable-based degree-day models, four-parameter models, five-parameter models, and multivariate models. All of these models can be calculated with ASHRAE Inverse Model Toolkit (IMT), which was developed from Research Project 1050-RP.141 The steady-state, linear, change-point linear, variable-based degree-day and multivariate inverse models contained in ASHRAE’s IMT have advantages over other types of models. First, since the models are simple, and their use with a given dataset requires no human intervention, the application of the models can be on can be automated and applied to large numbers of build-

Table 27.16: Sample Models for the Whole-Building Approach from ASHRAE Guideline 14-2002.152

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ings, such as those contained in utility databases. Such a procedure can assist a utility, or an owner of a large number of buildings, identify which buildings have abnormally high energy use. Second, several studies have shown that linear and change-point linear model coefficients have physical significance to operation of heating and cooling equipment that is controlled by a thermostat.142,143,144,145 Finally, numerous studies have reported the successful use of these models on a variety of different buildings.146,147,148,149,150,151 Steady-state models have disadvantages, including: an insensitivity to dynamic effects (e.g., thermal mass), insensitivity to variables other than temperature (e.g., humidity and solar), and inappropriateness for certain building types, for example building that have strong on/off schedule dependent loads, or buildings that display multiple change-points. If whole-building models are required in such applications, alternative models will need to be developed. A. One-parameter or Constant Model One-parameter, or constant models are models where the energy use is constant over a given period. Such models are appropriate for modeling buildings that consume electricity in a way that is independent of the outside weather conditions. For example, such models are appropriate for modeling electricity use in buildings which are on district heating and cooling systems, since the electricity use can be well represented by a constant weekday-weekend model. Constant models are often used to model sub-metered data on lighting use that is controlled by a predictable schedule. B. Day-adjusted Model Day-adjusted models are similar to one-parameter constant models, with the exception that the final coefficient of the model is expressed as an energy use per day, which is then multiplied by the number of days in the billing period to adjust for variations in the utility billing cycle. Such day-adjusted models are often used with one, two, three, four and five-parameter linear or change-point linear monthly utility models, where the energy use per period is divided by the days in the billing period before the linear or change-point linear regression is performed. C. Two-parameter Model Two-parameter models are appropriate for modeling building heating or cooling energy use in extreme climates where a building is exposed to heating or cooling year-around, and the building has an HVAC system with constant controls that operates continu-

Figure 27.7: Sample Models for the Whole-building Approach. Included in this figure is: (a) mean or oneparameter model, (b) two-parameter model, (c) threeparameter heating model (similar to a variable based degree-day model (VBDD) for heating), (d) three-parameter cooling model (VBDD for cooling), (e) fourparameter heating model, (f) four-parameter cooling model, and (g) five-parameter model.153 ously. Examples include outside air pre-heating systems in arctic conditions, or outside air pre-cooling systems in near-tropical climates. Dual-duct, single-fan, constantvolume systems, without economizers can also be modeled with two-parameter regression models. Constant use, domestic water heating loads can also be modeled with two-parameter models, which are based on the water supply temperature. D. Three-parameter Model Three-parameter models, which include changepoint linear models or variable-based, degree day

MEASUREMENT AND VERIFICATION OF ENERGY SAVINGS

models, can be used on a wide range of building types, including residential heating and cooling loads, small commercial buildings, and models that describe the gas used by boiler thermal plants that serve one or more buildings. In Table 27.16, three-parameter models have several formats, depending upon whether or not the model is a variable based degree-day model or threeparameter, change-point linear models for heating or cooling. The variable-based degree day model is defined as: E = C + B1 (DDBT) where C = the constant energy use below (or above) the change point, and B1 = the coefficient or slope that describes the linear dependency on degree-days, DDBT = the heating or cooling degree-days (or degree hours), which are based on the balance-point temperature.

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E. Four-parameter Model The four-parameter change-point linear heating model is typically applicable to heating usage in buildings with HVAC systems that have variable-air volume, or whose output varies with the ambient temperature. Four-parameter models have also been shown to be useful for modeling the whole-building electricity use of grocery stores that have large refrigeration loads, and significant cooling loads during the cooling season. Two types of four-parameter models are listed in Table 27.16, including a heating model and a cooling model. The four-parameter change-point linear heating model is given by E = C + B1 (B3 - T)+ - B2 (T - B3)+ where C = the energy use at the change point, B1 = the coefficient or slope that describes the linear dependency on temperature below the change point, B2 = the coefficient or slope that describes the linear dependency on temperature above the change point B3 = the change-point temperature, T = the temperature for the period of interest, + = positive values only for the parenthetical expression.

The three-parameter change-point linear model for heating is described by154 E = C + B1 (B2 – T)+ where C = the constant energy use above the change point, B1 = the coefficient or slope that describes the linear dependency on temperature, B2 = the heating change point temperature, T = the ambient temperature for the period corresponding to the energy use, + = positive values only inside the parenthesis. The three-parameter change-point linear model for cooling is described by E = C + B1 (T – B2)+ where C = the constant energy use below the change point, B1 = the coefficient or slope that describes the linear dependency on temperature, B2 = the cooling change point temperature, T = the ambient temperature for the period corresponding to the energy use, + = positive values only for the parenthetical expression.

The four-parameter change-point linear cooling model is given by E = C - B1 (B3 - T)+ + B2 (T - B3)+ where C = the energy use at the change point, B1 = the coefficient or slope that describes the linear dependency on temperature below the change point, B2 = the coefficient or slope that describes the linear dependency on temperature above the change point B3 = the change-point temperature, T = the temperature for the period of interest, + = positive values only for the parenthetical expression. F. Five-parameter Model Five-parameter change-point linear models are useful for modeling the whole-building energy use in buildings that contain air conditioning and electric heating. Such models are also useful for modeling the

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weather dependent performance of the electricity consumption of variable air volume air-handling units. The basic form for the weather dependency of either case is shown in Figure 27.7f, where there is an increase in electricity use below the change point associated with heating, an increase in the energy use above the change point associated with cooling, and constant energy use between the heating and cooling change points. Fiveparameter change-point linear models can be described using variable-based degree day models, or a five-parameter model. The equation for describing the energy use with variable-based degree days is E = C - B1 (DDTH) + B2 (DDTC) where C = the constant energy use between the heating and cooling change points, B1 = the coefficient or slope that describes the linear dependency on heating degree-days, B2 = the coefficient or slope that describes the linear dependency on cooling degree-days, DDTH = the heating degree-days (or degree hours), which are based on the balance-point temperature. DDTC = the cooling degree-days (or degree hours), which are based on the balance-point temperature. The five-parameter change-point linear model that is based on temperature is E = C + B1 (B3 - T)+ + B2 (T – B4)+ where C = the energy use between the heating and cooling change points, B1 = the coefficient or slope that describes the linear dependency on temperature below the heating change point, B2 = the coefficient or slope that describes the linear dependency on temperature above the cooling change point B3 = the heating change-point temperature, B4 = the cooling change-point temperature, T = the temperature for the period of interest, + = positive values only for the parenthetical expression. G. Whole-building Peak Demand Models Whole-building peak electric demand models differ from whole-building energy use models in several

respects. First, the models are not adjusted for the days in the billing period since the model is meant to represent the peak electric demand. Second, the models are usually analyzed against the maximum ambient temperature during the billing period. Models for whole-building peak electric demand can be classified according to weather-dependent and weather-independent models. G-1. Weather-dependent Whole-building Peak Demand Models Weather-dependent, whole-building peak demand models can be used to model the peak electricity use of a facility. Such models can be calculated with linear and change-point linear models regressed against maximum temperatures for the billing period, or calculated with an inverse bin model.155,156 G-2. Weather-independent Whole-building Peak Demand Models Weather-independent, whole-building peak demand models are used to measure the peak electric use in buildings or sub-metered data that do not show significant weather dependencies. ASHRAE has developed a diversity factor toolkit for calculating weather-independent whole-building peak demand models as part of Research Project 1093-RP. This toolkit calculates the 24-hour diversity factors using a quartile analysis. An example of the application of this approach is given in the following section. Example: Whole-building energy use models Figure 27.8 presents an example of the typical data requirements for a whole-building analysis, including one year of daily average ambient temperatures and twelve months of utility billing data. In this example of a residence, the daily average ambient temperatures were obtained from the National Weather Service (i.e., the average of the published min/max data), and the utility bill readings represent the actual readings from the customer’s utility bill. To analyze these data several calculations need to be performed. First, the monthly electricity use (kWh/month) needs to be divided by the days in the billing period to obtain the average daily electricity use for that month (kWh/day). Second, the average daily temperatures need to be calculated from the published NWS min/max data. From these average daily temperatures the average billing period temperature need to be calculated for each monthly utility bill. The data set containing average billing period temperatures and average daily electricity use is then analyzed with ASHRAE’s Inverse Model Toolkit (IMT)157 to determine a weather normalized consumption as shown

MEASUREMENT AND VERIFICATION OF ENERGY SAVINGS

in Figures 27.9 and 27.10. In Figure 27.9 the twelve monthly utility bills (kWh/period) are shown plotted against the average billing period temperature along with a three-parameter change-point model calculated with the IMT. In Figure 27.10 the twelve monthly utility bills, which were adjusted for days in the billing period (i.e., kWh/day) are shown plotted against the average billing period temperature along with a three-parameter change-point model calculated with the IMT. In the analysis for this house, the use of an average daily model improved the accuracy of the unadjusted model (i.e., Figure 27.9) from an R2 of 0.78 and CV (RMSE) of 24.0% to an R2 of 0.83 and a CV (RMSE) of 19.5% for the adjusted model (i.e., Figure 27.10), which indicates a significant improvement in the model. In another example the hourly steam use (Figure

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27.11) and hourly electricity use (Figure 27.13) for the U.S. DOE Forrestal Building is modeled with a daily weekday-weekend three-parameter, change-point model for the steam use (Figure 27.12), and an hourly weekdayweekend demand model for the electricity use (Figure 27.14). To develop the weather-normalized model for the steam use the hourly steam data and hourly weather data were first converted into average daily data, then a three-parameter, weekday-weekend model was calculated using the EModel software,158 which contains similar algorithms as ASHRAE’s IMT. The resultant model, which is shown in Figure 27.12 along with the daily steam, is well described with an R2 of 0.87 an RMSE of 50,085.95 kBtu/day and a CV (RMSE) of 37.1%. In Figure 27.14 hourly weather-independent 24hour weekday-weekend profiles have been created for

Figure 27.8: Example Data for Monthly Whole-building Analysis (upper trace, daily average temperature, F, lower points, monthly electricity use, kWh/day).

Figure 27.9 Example Unadjusted Monthly Wholebuilding Analysis (3P Model) for kWh/period (R2 = 0.78, CV (RMSE) = 24.0%).

Figure 27.10. Example Adjusted Whole-building Analysis (3P Model) for kWh/day (R2 = 0.83, CV (RMSE) = 19.5%).

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the whole-building electricity use using ASHRAE’s 1093-RP Diversity Factor Toolkit.159 These profiles can be used to calculate the baseline whole-building electricity use (i.e., using the mean hourly use) by multiplying times the expected weekdays and weekends in the year. The profiles can also be used to calculate the peak electricity use (i.e., using the 90th percentile). Calculation of Annual Energy Use Once the appropriate whole-building model has been chosen and applied to the baseline data, the annual energy use for the baseline period and the post-retrofit period are then calculated. Savings are then calculated by comparing the annual energy use of the baseline with the annual energy use of the post-retrofit period. Whole-building Calibrated Simulation Approach Whole-building calibrated simulation normally requires the hourly simulation of an entire building, including the thermal envelope, interior and occupant loads, secondary HVAC systems (i.e., air handling units), and the primary HVAC systems (i.e., chillers, boilers). This is usually accomplished with a general purpose simulation program such as BLAST, DOE-2 or EnergyPlus, or similar proprietary programs. Such programs require an hourly weather input file for the location in which the building is being simulated. Calibrating the simulation refers to the process whereby selected outputs from the simulation are compared and eventually matched with measurements taken from an actual building. A number of papers in the literature have addressed techniques for accomplishing these calibrations, and include results from case study buildings where calibrated simulations have been developed for various purposes. 160, 161, 162, 163, 164, 165, 166, 167, 168, 169, 170, 171,172,173,174,175

Applications of Calibrated Whole-building Simulation. Calibrated whole-building simulation can be a useful approach for measuring the savings from energy conservation retrofits to buildings. However, it is generally more expensive than other methods, and therefore it is best reserved for applications where other, less costly approaches cannot be used. For example, calibrated simulation is useful in projects where either pre-retrofit or post-retrofit whole-building metered electrical data are not available (i.e., new buildings or buildings without meters such as many college campuses with central facilities). Calibrated simulation is desired in projects where there are significant interactions between retrofits, for example lighting retrofits combined with changes to HVAC systems, or chiller retrofits. In such cases the whole-building simulation program can account for the interactions, and in certain cases, actually isolate interactions to allow for end-use energy allocations. It is useful in projects where there are significant changes in the facility’s energy use during or after a retrofit has been installed, where it may be necessary to account for additions to a building that add or subtract thermal loads from the HVAC system. In other cases, demand may change over time, where the changes are not related to the energy conservation measures. Therefore, adjustments to account for these changes will be also be needed. Finally, in many newer buildings, as-built design simulations are being delivered as a part of the building’s final documents. In cases where such simulations are properly documented they can be calibrated to the baseline conditions and then used to calculate and measure retrofit savings. Unfortunately, calibrated, whole-building simulation is not useful in all buildings. For example, if a building cannot be readily simulated with available simulation programs, significant costs may be incurred in

Figure 27.11: Example Heating Data for Daily Whole-building Analysis.

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Figure 27.12: Example Daily Weekday-weekend Whole-building Analysis (3P Model) for Steam Use (kBtu/ day, R2 = 0.87, RMSE = 50,085.95, CV (RMSE) = 37.1%). Weekday use (x), weekend use (฀ ).

Figure 27.13: Example Electricity Data for Hourly Whole-building Demand Analysis.

Figure 27.14: Example Weekday-weekend Hourly Whole-building Demand Analysis (1093-RP Model) for Electricity Use. modifying a program or developing a new program to simulate only one building (e.g., atriums, underground buildings, buildings with complex HVAC systems that are not included in a simulation program’s system library). Additional information about calibrated,

whole-building simulation can be found in ASHRAE’s Guideline 14-2002. Figure 27.15 provides an example of the use of calibrated simulation to measure retrofit savings in a project where pre-retrofit measurements were not avail-

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able. In this figure both the before-after whole-building approach and the calibrated simulation approach are illustrated. On the left side of the figure the traditional whole-building, before-after approach is shown for a building that had a dual-duct, constant volume system (DDCV) replaced with a variable air volume (VAV) system. In such a case where baseline data are available, the energy use for the building is regressed against the coincident weather conditions to obtain the representative baseline regression coefficients. After the retrofit is installed, the energy savings are calculated by comparing the projected pre-retrofit energy use against the measured post-retrofit energy use, where the projected pre-retrofit energy use calculated with the regression model (or empirical model), which was determined with the facility’s baseline DDCV data. In cases where the baseline data are not available (i.e., the right side of the figure), a simulation of the building can be developed and calibrated to the postretrofit conditions (i.e., the VAV system). Then, using the calibrated simulation program, the pre-retrofit energy use (i.e., DDCV system) can be calculated for conditions in the post-retrofit period, and the savings calculated by comparing the simulated pre-retrofit energy use against the measured post-retrofit energy use. In such a case the calibrated post-retrofit simulation can also be used to fill-in any missing post-retrofit energy use, which is

ENERGY MANAGEMENT HANDBOOK

a common occurrence in projects that measure hourly energy and environmental conditions. The accuracy of the post-retrofit model depends on numerous factors. Methodology for Calibrated Whole-building Simulation Calibrated simulation requires a systematic approach that includes the development of the wholebuilding simulation model, collection of data from the building being retrofitted and the coincident weather data. The calibration process then involves the comparison of selected simulation outputs against measured data from the systems being simulated, and the adjustment of the simulation model to improve the comparison of the simulated output against the corresponding measurements. The choice of simulation program is a critical step in the process, which must balance the model appropriateness, algorithmic complexity, user expertise, and degree of accuracy against the resources available to perform the modeling. Data collection from the building includes the collection of data from the baseline and post-retrofit periods, which can cover several years of time. Building data to be gathered includes such information as the building location, building geometry, materials characteristics, equipment nameplate data, operations schedules, temperature settings, and at a minimum whole-building utility billing data. If the budget allows, hourly whole-

Figure 27.15: Flow Diagram for Calibrated Simulation Analysis of Air-Side HVAC System.176

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building energy use and environmental data can be gathered to improve the calibration process, which can be done over short-term, or long-term period. Figure 27.16 provides an illustration of a calibration process that used hourly graphical and statistical comparisons of the simulated versus measured energy use and environmental conditions. In this example, the site-specific information was gathered and used to develop a simulation input file, including the use of measured weather data, which was then used by the DOE-2 program to simulate the case study building. Hourly data from the simulation program was then extracted and used in a series of special-purpose graphical plots to help guide the calibration process (i.e., time series, bin and 3-D plots). After changes were made to the input file, DOE-2 was then run again, and the output compared against the measured data for a specific period. This process was then repeated until the desired level of calibration was reached, at which point the simulation was proclaimed to be “calibrated.” The calibrated model was then used to evaluate how the new building was performing compared to the design intent. A number of different calibration tools have been

reported by various investigators, ranging from simple X-Y scatter plots to more elaborate statistical plots and indices. Figures 27.17, 27.18 and 27.19 provide examples of several of these calibration tools. In Figure 27.17 an example of an architectural rendering tool is shown that assists the simulator with viewing the exact placement of surfaces in the building, as well as shading from nearby buildings, and north-south orientation. In Figure 27.18 temperature binned calibration plots are shown comparing the weather dependency of an hourly simulation against measured data. In this figure the upper plots show the data as scatter plots against temperature. The lower plots are statistical, temperature-binned boxwhisker-mean plots, which include the super positioning of measured mean line onto the simulated mean line to facilitate a detailed evaluation. In Figure 27.19 comparative three-dimensional plots are shown that show measured data (top plot), simulated data (second plot from the top), simulated minus measured data (second plot from the bottom, and measured minus simulated data (bottom plot). In these plots the day-of-the-year is the scale across the page (y axis), the hour-of-the-day is the scale projecting into the page (x axis), and the hourly

Figure 27.16: Calibration Flowchart. This figure shows the sequence of processing routines that were used to develop graphical calibration procedures.178

Figure 27.17: Example Architecture Rendering of the Robert E. Johnson Building, Austin, Texas.179,180

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electricity use is the vertical scale of the surface above the x-y plane. These plots are useful for determining how well the hourly schedules of the simulation match the schedules of the real building, and can be used to identify other certain schedule-related features. For example, in the front of plot (b) the saw-toothed feature is indicating on/off cycling of the HVAC system, which is not occurring in the actual building. Table 27.17 contains a summary of the procedures used for developing a calibrated, whole-building simulation program, as defined in ASHRAE’s Guideline 14-2002. In general, to develop a calibrated simulation, detailed information is required for a building, including information about the building’s thermal envelope (i.e., the walls, windows, roof, etc.), information about the building’s operation, including temperature settings, HVAC systems, and heating-cooling equipment that existed both during the baseline and post-retrofit period. This information is input into two simulation files, one for the baseline and one for the post-retrofit conditions. Savings are then calculated by comparing the two simulations of the same building, one that represents the baseline building, and one that represents the building’s operations during the post-retrofit period.

ENERGY MANAGEMENT HANDBOOK

nately, in most projects, numerous variables exist so the assessments can be easily disputed. In general, the low risk (L)—reasonable payback ECMs exhibit steady performance characteristics that tend not to degrade or become easily noticed when savings degradation occurs. These include lighting, constant speed motors, two-speed motors and IR radiant heating. The high risk (H)—reasonable payback ECMs include EMCSs, variable speed drives and control retrofits. The savings from these ECMs can be overridden by building operators and not be noticed until years later. Most other ECMs fall in the category of “it depends.” The attention that the operations and maintenance directs at these dramatically impacts the sustainability of the operation and the savings. With an EMCS, operators can set up trend reports to measure and track occupancy schedule overrides, the various reset schedule overrides, variable speed drive controls and even monitor critical parameters which track mechanical systems performance. illustrates a “most likely” range of ratings for the various categories.183 Often, building envelope or mechanical systems need to be replaced. Building systems have finite life-

27.2.2 Role of M&V Each Energy Conservation Measure (ECM) presents particular requirements. These can be grouped in functional sections as shown in Table 27.18. Unfortu-

Figure 27.18: Temperature Bin Calibration Plots. This figure shows the measured and simulated hourly weekday data as scatter plots against temperature in the upper plots and as statistical binned box-whisker-mean plots in the lower plots.181

Figure 27.19: Comparative Three-dimensional Plots. (a) Measured Data. (b) Simulated Data. (c) Simulated-Measured Data. (d) Measured-Simulated Data.

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Table 27.17: Calibrated, whole-building Simulation Procedures from ASHRAE Guideline 14-2002.177

times, ranging from two to five years for most light bulbs to 10 to 20+ years for chillers and boilers. Building envelope replacements like insulation, siding, roof, windows and doors can have lifetimes from 10 to 50 years. In these instances, life cycle costing should be done to compare the total cost of upgrading to more efficient technology. Also, the cost of M&V should be considered when determining how to sustain the savings and performance of the replacement. In many cases, the upgraded efficiency will have a payback of less than 10 years when compared to the current efficiency of the existing equipment. Current technology high efficiency upgrades normally use controls to acquire the high efficiency. These controls often connect to standard interfaces so that they communicate with today’s state of the art Energy Management and Control Systems (EMCSs). 27.2.3 Cost/Benefit Analysis The target for work for the USAF has been 5% of the savings.184 The cost of the M&V can exceed 5%

if the risk of losing savings exceeds predefined limits. The Variable Speed Drive ECM illustrates these opportunities and risks. VSD equipment exhibits high reliability. Equipment type of failures normally happen when connection breaks occur with the control input, the remote sensor. Operator induced failures occur then the operator sets the unit to 100% speed and does not re-enable the control. Setting the unit to 100% can occur for legitimate reasons. These reasons include running a test, overriding a control program that does not provide adequate speed under specific, and typically unusual, circumstances, or requiring 100% operation for a limited time. The savings disappear if the VSD remains at 100% operating speed. For example, consider a VSD ECM with ten (10) motors with each motor on a different air handling unit. Each motor has fifty (50) horsepower (HP). The base case measured these motors running 8760 hours per year at full speed. Assume that the loads on the motors matched the nameplate 50 HP at peak loads.

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Table 27.18: Overview of Risks and Costs for ECMs.

Although the actual load on a AHU fan varies with the state of the terminal boxes, assume that the load average equates to 80% of the full load since the duct pressure will rise as the terminal boxes reduce flow at the higher speed. Table 27.19 contains the remaining assumptions. To correctly determine the average power load, the average power must either be integrated over the period of consumption or the bin method must be used. For the purposes of this example, the 14.4% value will be used. The equation below shows the relationship between the fan speed and the power consumed. The exponent has been observed to vary between 2.8 (at high flow) and 2.7 (at reduced flow) for most duct systems. This includes the loss term from pressure increases at a given fan speed. Changing the exponent from 2.8 to

2.7 reduces the savings by less than 5%.

Pwr = Pwr 0 ×

% Speed Full Speed

2.8

Demand savings will not be considered in this example. Demand savings will likely be very low if the utility has a 12-month ratchet clause and the summer load requires some full speed operation during peak times. Assuming a $12.00/kW per month demand charge, demand savings could be high for off-season months if the demand billing resets monthly. Without a ratchet clause, rough estimates have yearly demand savings ranging up to $17,000 if the fan speed stays under 70% for 6 months per year. Yearly demand savings jump to over $20,000 if the fan speed stays under 60% for 6 months per year.

Table 27.19: VSD Example Assumptions.

MEASUREMENT AND VERIFICATION OF ENERGY SAVINGS

Figure 27.20 illustrates the savings expected from the VSD ECM by hours of use per year. The 5% and 10% of Savings lines define the amount available for M&V expenditures at these levels. In this example, the ECM savings exceeds $253,000 per year. Five percent (5%) of savings over a 20-year project life makes $253K available for M&V and ten percent (10%) of the savings makes $506K available over the 20-year period. If the motors run less frequently than continuous, savings decrease as shown in Figure 27.20. Setting up the M&V program to monitor the VSDs on an hourly basis and report savings on a monthly report requires monitoring the VSD inverter with an EMCS to poll the data and create reports. To provide the impact of the potential losses from losing the savings, assume the savings degrades at a loss of 10% of the total yearly savings per year. Studies have shown that control ECMs like the VSD example can expect to see 20% to 30% degradation in savings in 2 to 3 years. Figure 27.21 illustrates what happens to the

Figure 27.20: Example VSD EMC Yearly Savings/M&V Cost.

Figure 27.21: Yearly Impact of Ongoing Losses.

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savings in 20 years with 10% of the savings spent on M&V. Note that the losses exceed the M&V cost during the first year, resulting in a net loss of almost $3,000,000 over the 20-year period. Figure 27.22 shows the savings per year with a 10% loss of savings. M&V costs remain at 10% of savings. At the end of the 20-year period, the savings drop to almost $30,000 per year out of a potential savings of over $250,000 per year. This example shows the cumulative impact of losing savings on a year by year basis. The actual savings amounts will vary depending upon the specific factors in an ECM and can be scaled to reflect a specific application. Increasing the M&V cost to reduce the loss of savings often makes sense and must be carefully thought through. 27.2.4 Cost Reduction Strategies M&V strategies can be cost reduced by lowering the requirements for M&V or by statistical sampling. Reducing requirements involves performing trade-offs with the risks and benefits of having reliable numbers to determine the savings and the costs for these measurements. 27.2.4.1 Constant Load ECMs Lighting ECMs can save 30% of the pre-ECM energy and have a payback in the range of 3 to 6 years. Assuming that the lighting ECM was designed and implemented per the specifications and the savings were verified to be occurring, just verifying that the storeroom has the correct ballasts and lamps may constitute acceptable M&V on a yearly basis. This costs far less than performing a yearly set of measurements, analyzing them and then creating reports. In this case, other safeguards should be implemented to assure that the bulb and ballast replacement occurs and meets the

Figure 27.22: Cumulative Impact of Savings Loss.

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requirements specified. High efficiency motor replacements provide another example of constant load ECMs. The key short term risks with motor replacements involve installing the right motor with all mechanical linkages and electrical components installed correctly. Once verified, the long term risks for maintaining savings occur when the motor fails. The replacement motor must be the correct motor or savings can be lost. A sampled inspection reduces this risk. Make sure to inspect all motors at least once every five (5) years. 27.2.4.2 Major Mechanical Systems Boilers, chillers, air handler units, cooling towers comprise the category of manor mechanical equipment in buildings. They need to be considered separately as each carry their own set of short-term and long-term risks. In general, measurements provide necessary risk reduction. The question becomes: What measurements reduce the risk of savings loss by an acceptable amount? First a risk assessment needs to be performed. The short-term risks for boilers involve installing the wrong size or installing the boiler improperly (not to specifications). Long-term savings sustainability risks tend to focus on the water side and the fire side. Water deposits (K+, Ca++, Mg+) will form on the inside of the tubes and add a thermal barrier to the heat flow. The fire side can add a layer of soot if the O2 level drops too low. Either of these reduce the efficiency of the boiler over the long haul. Generally this can take several years to impact the efficiency if regular tune-ups and water treatment occurs. Boilers come in a wide variety of shapes and sizes. Boiler size can be used as a defining criterion for measurements. Assume that natural gas or other boiler fuels cost about $5.00 per MMBtu. Although fuel price constantly changes, it provides a reference point for this analysis. Thus a boiler with 1MMBtu per hour output, an efficiency of 80% and operating at 50% load 3500 hours per year, consumes about $11,000 per year. If this boiler replaced a less efficient boiler, say at 65%, then the net savings amounts to about $2,500 per year, assuming the same load from the building. At 5% of the savings, $125 per year can be used for M&V. This does not allow much M&V. At 10% of the annual savings, $250 per year can be used. At this level of cost, a combustion efficiency measurement could be performed, either yearly or bi-yearly, depending on the local costs. In 2003 the ASME’s Power Test Code 4.1 (PTC-4.1)185 was replaced with PTC4. Either of these codes allows two methods to measuring boiler efficiency. The first method uses

ENERGY MANAGEMENT HANDBOOK

the energy in equals energy out—using the first law of thermodynamics. This requires measuring the Btu input via the gas flow and the Btu output via the steam (or water) flow and temperatures. The second method measures the energy loss due to the content and temperature of the exhausted gases, radiated energy from the shell and piping and other loss terms (like blowdown). The energy loss method can be performed in less than a couple of hours. The technician performing these measurements must be skilled or significant errors will result in the calculated efficiency. The equation below shows the calculations required. Efficiency = 100% – Losses + Credits The losses term includes the temperature of the exhaust gas and a measure of the unburned hydrocarbons by measuring CO2 or O2 levels, the loss due to excess CO and a radiated term. Credits seldom occur but could arise from solar heating the makeup water or similar contributions. The Greek letter “η” usually denotes efficiency. As with boilers, a risk assessment needs to be performed for chilers. The short term risks for chillers involve sizing or improper installation. Long term savings sustainability risks focus on the condenser water system, as circulation occurs in an open system. Water deposits (K+, Ca++, Mg+, organics) will form on the inside of the condenser tubes and add a barrier to the thermal flow. These reduce the efficiency of the chiller over the long haul. Generally this can take several years to impact the efficiency if proper water treatment occurs. Depending on the environmental conditions, the quality of the makeup water and the water treatment, condenser tube fouling should be checked every year or at least every other year. Chillers consume electricity in the case of most centrifugal, screw, scroll and reciprocating compressors. Direct-fired absorbers and engine driven compressors use a petroleum based fuel. As with boilers, chiller size and application sets the basic energy consumption levels. Assume, for the purpose of this example, that electricity provides the chiller energy. Older chillers with water towers often operate at the 0.8 to 1.3 kW per ton level of efficiency. New chillers with water towers can operate in the 0.55 to 0.7 range of efficiency. Note that the efficiency of any chiller depends upon the specific operating conditions. Also assume the following: 500 Tons centrifugal chiller with the specifications shown in Table 27.20. Under these conditions the chiller produces 400 Tons of chilled water and requires an expenditure of $ 38,000 per year, considering both energy use and

MEASUREMENT AND VERIFICATION OF ENERGY SAVINGS

demand charges. Some utilities only charge demand charges on the transmission and delivery (T&D) parts of the rate structure. In that case, the cost at $0.06/kWh would be closer to $28,000. Using the 5% (10%) guideline for M&V costs as a percentage of savings leaves almost $1,100 ($2,200) per year to spend on M&V. This creates an allowable expenditure over a 20-year project of $22,000 ($44,000) for M&V. If the utility has a ratchet clause in the rate structure, the amount for M&V increases to $1,700 ($3,400) per year. At $1,100 per year, trade-offs will need to be made to stay within that “budget.” The risks need to be weighed and decisions made as to what level of M&V costs will be allowed. To determine the actual efficiency of a chiller requires accurate measurements of the chilled water flow, the difference between the chilled water supply and return temperatures and the electrical power provided to the chiller. Costs can be reduced using an EMCS if only temperature, flow and power sensors need to be installed.

749

sustainability risks. When an operator overrides a strategy and forgets to re-enable it, the savings disappear. A common EMCS ECM requires the installation of equipment and programs used to set back temperatures or turn off equipment. Short term risks involve setting up the controls so that performance enhances, or at least does not degrade, the comfort of the occupants. When discomfort occurs, either occupants set up “portable electric reheat units” or operators override the control program. For example, when the night set-back control does not get the space to comfort by occupancy, operators typically override instead of adjusting the parameters in the program. These actions tend to occur during peak loading times and then not get re-enabled during milder times. Long term risks cover the same area as short term risks. A new operator or a failure in remote equipment that does not get fixed will likely cause the loss of savings. Estimating the savings cost for various projects can be done when the specifics are known.

Table 27.20: Example of Savings with a 500 Ton Chiller.

Cooling tower replacement requires knowledge of the risks and costs involved. As with boilers and chillers, the primary risks involve the water treatment. Controls can be used to improve the efficiency of a chiller/tower combination by as much as 15% to 20%. As has been previously stated, control ECMs often get overridden and the savings disappear. 27.2.4.3 Control Systems Control ECMs encompass a wide spectrum of capabilities and costs. Upgrading a pneumatic control system and installing EP (electronic to pneumatic) transducers involves the simple end. The complex side could span installing a complete EMCS with sophisticated controls, with various reset, pressurization and control strategies. Generally, EMCSs function as basic controls and do not get widely used in sophisticated applications. Savings due to EMCS controls bear high

Table 27.21: Sampling Requirements.

750

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Risk abatement can be as simple as requiring a trend report weekly or at least monthly. M&V costs can generally be easily held under 5% when using an EMCS and creating trend reports. 27.2.5 M&V Sampling Strategies M&V can be made significantly lower cost by sampling. Sampling also reduces the timeliness of obtaining specific data on specific equipment. The benefits of sampling arise when the population of items increases. Table 27.21 (M&V Guidelines: Measurement and Verification for Federal Energy Projects, Version 2.2, Appendix D) illustrates how confidence and precision impact the number of samples required in a given population of items. Lighting ECMs may involve thousands of fixtures. For example, to obtain a savings estimate for 1,000 or more fixtures, with a confidence of 80% and a precision of 20%, 11 fixtures would need to be sampled. If the requirements increased to a confidence of 90% and a precision of 10%, 68 fixtures would need to be sampled. The boiler ECM also represents opportunity for M&V cost reduction using sampling. Assume that the ECM included replacing 50 boilers. If a confidence of 80% and a precision of 20% satisfy the requirements, 10 boilers would need to be sampled. The cost is then reduced to 20% of the cost of measuring all boilers, a significant savings. A random sampling to select the sample set can easily be implemented. References 1. Claridge D.E., Turner, W.D., Liu, M., Deng, S., Wei, G., Culp, C., Chen, H., and Cho, S. 2002. “Is Commissioning Once Enough?” Solutions for Energy Security and Facility Management Challenges: Proceedings of the 25th WEEC, Atlanta, GA, October 19-11, 2002, pp. 29-36. 2. Haberl, J., Lynn, B., Underwood, D., Reasoner, J., Rury, K. 2003. “Development an M&V Plan and Baseline for the Ft. Hood ESPC Project,” ASHRAE Seminar Presentation, (June). 3. C. Culp, K.Q. Hart, B. Turner, S. Berry-Lewis, 2003. “Energy Consumption Baseline: Fairchild AFB’s Major Boiler Retrofit,” ASHRAE Seminar (January). 4. Arnold, D., 1999. “The Evolution of Modem Office Buildings and Air Conditioning,” ASHRAE Journal, American Society of Heating Refrigeration Air-conditioning Engineers, Atlanta, GA, pp. 40-54, (June). 5. Donaldson, B., Nagengast. 1994. Heat and Cold: Mastering the Great Indoors. American Society of Heating Refrigeration Air-conditioning Engineers, Atlanta, GA. 6. Cheney, M., Uth, R. 1999. Tesla: Master of Lightning. Barnes and Noble Books, New York, N,Y. 7. Will, H. 1999. The First Century of Air Conditioning. American Society of Heating Refrigeration Air-conditioning Engineers, Atlanta, GA. 8. Israel, P. 1998. Edison: A Life of Invention. John Wiley and Sons, New York, N.Y. 9. EEI 1981. Handbook for Electricity Metering, 8th Edition with Appendix, Edition Electric Institute, Washington D.C.

10. Miller, R. 1989. Flow Measurement Engineering Handbook. McGraw Hill, New York, N.Y. 11. American Institute of Physics, 1975. Efficient Use of Energy: The APS Studies on the Technical Aspects of the More Efficient Use of Energy, American Physical Society, New York, N.Y., (A report on the 1973 summer study at Princeton University). 12. National Geographic, February 1981. Special Report on Energy: Facing up to the Problem, Getting Down to Solutions, National Geographic Society, Washington, D.C. 13. Scientific American 1971. Energy and Power. W.H. Freeman and Company, San Francisco, CA. (A reprint of eleven articles that appeared in the September 1971 Scientific American). 14. Kusuda, T. 1999. “Early History and Future Prospects of Building System Simulation,” Proceedings of the Sixth International Building Performance Simulation Association (IBPSA BS’ 99), Kyoto, Japan, (September). 15. APEC 1967. HCC-heating/cooling load calculations program. Dayton, Ohio, Automated Procedures for Engineering Consultants. 16. Ayres, M., Stamper, E. 1995. “Historical Development of Building Energy Calculations,” ASHRAE Transactions, Vol. 101, Pt. 1. American Society of Heating Refrigeration Air-conditioning Engineers, Atlanta, GA. 17. Stephenson, D., and Mitalas, G. 1967. “Cooling Load Calculations by Thermal Response Factor Method,” ASHRAE Transactions, Vol. 73, pt. 1. 18. Mitalas, G. and Stephenson, D. 1967, “Room Thermal Response Factors,” ASHRAE Transactions, Vol. 73, pt. 2. 19. Stoecker, W. 1971. Proposed Procedures for Simulating the Performance of Components and Systems for Energy Calculations, 2 “d Edition, American Society of Heating Refrigeration Air-conditioning Engineers, Atlanta, GA. 20. Sepsy, C. 1969. “Energy Requirements for Heating, and Cooling Buildings (ASHRAE RP 66-OS), Ohio State University. 21. Socolow, R. 1978. Saving Energy in the Home: Princeton’s Experiments at Twin Rivers, Ballinger Publishing Company, Cambridge, Massachusetts, (This book contains a collection of papers that were also published in Energy and Buildings, Vol. 1, No. 3., (April)). 22. Fels, M. 1986. Special Issue Devoted to Measuring Energy Savings: The Scorekeeping Approach, Energy and Buildings, Vol. 9, Nos. 1 & 2, Elsevier Press, Lausanne, Switzerland, (February/May). 23. DOE 1985. Proceedings of the DOE/ORNL Data Acquisition Workshop, Oak Ridge National Laboratory, Oak Ridge, TN, (October). 24. Lyberg, M. 1987. Source Book for Energy Auditors: Vols. 1 & 2, International Energy Agency, Stockholm, Sweden, (Report on IEA Task XI). 25. IEA 1990. Field Monitoring For a Purpose. International Energy Agency Workshop, Chalmers University, Gothenburg, Sweden, (April). 26. Oninicomp 1984. Faser Software, Omnicomp, Inc., State College, PA, (monthly accounting software with VBDD capability). 27. Eto, J. 1988. “On Using Degree-days to Account for the Effects of Weather on Annual Energy Use in Office Buildings,” Energy and Buildings, Vol. 12, No. 2, pp. 113-127. 28. SRC Systems 1996. Metrix: Utility Accounting System, Berkeley, CA, (monthly accounting software with combined VBDD/ multiple regression capabilities). 29. Haberl, J. and Vajda. E. 1988. “Use of Metered Data Analysis to Improve Building Operation and Maintenance: Early Results From Two Federal Complexes,” Proceedings of the ACEEE 1988 Summer Study on Energy Efficient Buildings, Pacific Grove, CA, pp. 3.98 - 3.111, (August). 30. Sonderegger, R. 1977. Dynamic Models of House Heating Based on Equivalent Thermal Parameters, Ph.D. Thesis, Center

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751 49. Sonderegger, R. 1977, op.cit. 50. Subbarao, K., Burch, J., Hancock, C.E, 1990. “How to accurately measure the load coefficient of a residential building,” Journal of Solar Energy Engineering, in preparation. 51. Reddy, A. 1989. “Application of Dynamic Building Inverse Models to Three Occupied Residences Monitored Non-intrusively,” Proceedings of the Thermal Performance of Exterior Envelopes of Buildings IV, ASHRAE/DOE/BTECC/CIBSE. 52. Shurcliff, W.A. 1984. “Frequency Method of Analyzing a Building’s Dynamic Thermal Performance, W.A. Shurcliff, 19 Appleton St., Cambridge, MA. 53. Dhar, A. 1995, “Development of Fourier Series and Artificial Neural Networks Approaches to Model Hourly Energy Use in Commercial Buildings,” Ph.D. Dissertation, Mechanical Engineering Department, Texas A&M University, May. 54. Miller, R., and Seem, J. 199 1. “Comparison of Artificial Neural Networks with Traditional Methods of Predicting Return Time from Night Setback,” ASHRAE Transactions, Vol. 97, Pt.2, pp. 500-508. 55. J.F. Kreider and X.A. Wang, (199 1). “Artificial Neural Networks Demonstration for Automated Generation of Energy Use Predictors for Commercial Buildings.” ASHRAE Transactions, Vol. 97, part 1. 56. Kreider, J. and Haberl, J. 1994. “Predicting Hourly Building Energy Usage: The Great Energy Predictor Shootout: Overview and Discussion of Results,” ASHRAE Transactions-Research, Volume 100, Part 2, pp. 1104 - 1118, (June). 57. ASHRAE 1997. Handbook of Fundamentals, Chapter 30: Energy Estimating and Modeling Methods, American Society of Heating Refrigeration Air-conditioning Engineers, Atlanta, GA., p. 30.27 (Copied with perinission). 58. ASHRAE 1997. op.cit., p. 30.28 (Copied with permission). 59. USDOE 1996. North American Energy Measurement and Verification Protocol (NEMVP), United States Department of Energy DOE/EE-0081, (March). 60. FEMP 1996. Standard Procedures and Guidelines for Verification of Energy Savings Obtained Under Federal Savings Performance Contracting Programs, USDOE Federal Energy Management Program (FEMP). 61. Haberl, J., Claridge, D., Turner, D., O’Neal, D., Heffington, W., Verdict, M. 2002. “LoanSTAR After 11 Years: A Report on the Successes and Lessons Learned From the LoanSTAR Program,” Proceedings of the 2nd International Conference for Enhanced Building Operation,” Richardson, Texas, pp. 131-138, (October). 62. USDOE 1997. International Performance Measurement and Verification Protocol (IPMVP), United States Department of Energy DOE/EE-0157, (December). 63. USDOE 2001. International Performance Measurement and Verification Protocol (IPMVP): Volume 1: Concepts and Options for Determining Energy and Water Savings, United States Department of Energy DOE/GO-102001-1187 (January). 64. USDOE 2001. International Performance Measurement and Verification Protocol (IPMVP): Volume 11: Concepts and Practices for Improved Indoor Environrnental Quality, United States Department of Energy DOE/GO-102001-1188 (January). 65. USDOE 2003. International Performance Measurement and Verification Protocol (IPMVP): Volume 11: Concepts and Practices for Improved Indoor Environmental Quality, United States Department of Energy DOE/GO-102001-1188 (January). 66. ASHRAE 2002.Guideline 14: Measurement of Energy and Demand Savings, American Society of Heating Refrigeration Air-conditioning Engineers, Atlanta, GA (September). 67. Hansen, S. 1993. Performance Contracting for Energy and Environmental Systems, Fairmont Press, Lilbum, GA, pp. 99-100. 68. ASHRAE 2002. op.cit., pp. 27-30.

752 69. lbid, p. 30 (Copied with permission). 70. Brandemuehl et al. 1996. op.cit. 71. Wei, G. 1997. “A Methodology for In-situ Calibration of Steam Boiler Instrumentation,” MS Thesis, Mechanical Engineering Department, Texas A&M University, August. 72. Dukelow, S.G. 1991. The Control of Boilers. Research Triangle Park, NC: Instrument Society of America. 73. Dyer, F.D. and Maples, G. 1981. Boiler Efficiency Improvement. Boiler Efficiency Institute. Auburn: AL. 74. Garcia-Borras, T. 1983. Manual for Improving Boiler and Furnace Performance. Houston, TX: Gulf Publishing Company. 75. Aschner, F.S. 1977. Planning Fundamentals of Thermal Power Plants. Jerusalem, Israel: Israel Universities Press. 76. ASME 1974 Performance Test for Steam Units — PTC 4. 1 a 1974. 77. Babcock and Wilcox. 1992. “Steam: Its generation and Use,” Babcock and Wilcox, Barberton, Ohio, ISBN 0-9634570-0-4. 78. Katipamula, S., and Claridge, D. 1992. “Monitored Air Handler Performance and Comparison with a Simplified System Model,” ASHRAE Transactions, Vol. 98, Pt 2., pp. 341-35 1. 79. Liu, M., and Claridge, D. 1995 “Application of Calibrated HVAC Systems to Identify Component Malfunctions and to Optimize the Operation and Control Schedules,” ASME/JSME International Solar Energy Conference, pp. 209-217. 80. ASHRAE 2002. op.cit., p. 144. 81. Brandemuehl, et al. 1996. op. cit. 82. ASHRAE 2002, op cit., p. 144, (Copied with permission). 83. ASHRAE 2002. op.cit., pp. 144-147, (Copied with permission). 84. ASHRAE 2002. op.cit., p. 144. 85. Ibid, p. 148, (Copied with permission). 86. ASHRAE 2002. op.cit., pp. 147-149, (Copied with permission). 87. Gordon, J.M. and Ng, K.C. 1994. op.cit. 88. Gordon, J.M. and Ng, K.C., 1995. “Predictive and diagnostic aspects of a universal thermodynamic model for chillers,” International Journal of Heat Mass Transfer, 38(5), p.807. 89. Gordon, J.M., Ng, K.C., and Chua, H.T., 1995. “Centrifugal chillers: thermodynamic modeling and a diagnostic case study,” International Journal of Refrigeration, 18(4), p.253. 90. LBL. 1980. DOE-2 User Guide, Ver. 2. 1. Lawrence Berkeley Laboratory and Los Alamos National Laboratory, Rpt No. LBL8689 Rev. 2; DOE-2 User Coordination Office, LBL, Berkeley, CA. 91. LBL. 198 1. DOE-2 Engineers Manual, Ver. 2. 1 A, Lawrence Berkeley Laboratory and Los Alamos National Laboratory, Rpt No. LBL-1 1353; DOE-2 User Coordination Office, LBL, Berkeley, CA. 92. LBL. 1982. DOE-2.1 Reference Manual Rev. 2.1A. Lawrence Berkeley Laboratory and Los Alamos National Laboratory, Rpt No. LBL-8706 Rev. 2; DOE-2 User Coordination Office, LBL, Berkeley, CA. LBL. 93. LBL. 1989. DOE-2 Supplement, Ver 2. 1 D. Lawrence Berkeley Laboratory, Rpt No. LBL-8706 Rev. 5 Supplement. DOE-2 User Coordination Office, LBL, Berkeley, CA. 94. Haberl, J. S., Reddy, T. A., Figueroa, I., Medina, M. 1997. “Overview of LoanSTAR Chiller Monitoring and Analysis of In-Situ Chiller Diagnostics Using ASHRAE RP827 Test Method,” Proceedings of the PG&E Cool Sense National Integrated Chiller Retrofit Forum (September). 95. According to Gordon et al. 1995, fHx is a dimensionless term that is norrrially negligible. 96. Wei, G. 1997. op.cit. 97. Dukelow, S.G. 1991. op.cit. 9.8 Dyer, F.D. and Maples, G. 198 1. op.cit. 99. Garcia-Borras, T. 1983. op.cit. 100. Aschner, F.S. 1977. op.cit. 101. ASME 1974. op.cit.

ENERGY MANAGEMENT HANDBOOK 102. Babcock and Wilcox. 1992. op.cit. 103. Haberl, J., Lynn, B., Underwood, D., Reasoner, J., Rury, K. 2003. op.cit. 104. Haberl, et al. 2003. ibid. 105. ASME, 1974. Power Test Codes (PTC) 4. la, Steam Generating Units. New York: ASME. 106. Stallard, G.S. and Jonas, T.S. 1996. Power Plant Engineering: Combustion Processes. New York: Chapman & Hall. 107. Payne, F.W. 1985. Efficient Boiler Operations Sourcebook. Atlanta, GA: The Fairmont Press. 108. Wei 1997. op.cit. 109. Wei 1997. ibid. 110. Aschner 1977. op.cit. 111. Babcock and Wilcox 1992. op.cit. 112. Dukelow 1991. op.cit. 113. Witte, L.C., Schmidt, P.S., and Brown, DR. 1988. Industrial Energy Management and Utilization. New York: Hemisphere Publishing Corporation. 114. Aschner 1977. op.cit. 115. Thumann, A. 1988. Guide to Improving Efficiency of Combustion Systems. Lilburn, GA: The Fairmont Press. 116. Wei 1997. op.cit. 117. Garcia-Borras, T. 1983. Manual for Improving Boiler and Furnace Performance. Houston, TX: Gulf Publishing Company. 118. Wei 1997. op.cit. 119. ASHRAE 2002, op.cit., pp. 154-156, (Copied with permission). 120. Bou Saada, T., Haberl, J., Vajda, J., and Harris, L. 1996. “Total Utility Savings From the 37,000 Fixture Lighting Retrofit to the USDOE Forrestal Building,” Proceedings of the 1996 ACEEE Summery Study, (August). 121. Abushakra, B., Sreshthaputra, A., Haberl, J., and Claridge, D. 2001. “Compilation of Diversity Factors and Schedules for Energy and Cooling Load Calculations - Final Report,” submitted to ASHRAE under Research Project 1093-RP, Energy Systems Lab Report ESL-TR-01/04-01, Texas A&M University, (April). 122. IESNA 2003. Lighting Handbook, 9h Edition, Illuminating Engineering Society of North America, New York, N.Y. 123. ASHRAE 2002, op.cit., pp. 156-159, (Copied with permission). 124. ASHRAE 2002, op. cit., p. 160, (Copied with permission). 125. Ayres, M., Stamper, E. 1995, op.cit. 126. ASHRAE 1969. Procedures for Determining Heating and Cooling Loads for Computerized Energy Calculations: Algorithms for Building Heat Transfer Sub-routines. M. Lokmanhekim, Editor, American Society of Heating Refrigeration Air-conditioning Engineers, Atlanta, GA. 127. ASHRAE 1971. Procedures for Simulating the Performance of Components and Systems for Energy Calculations. Stoecker, W.F. Stoecker, editor, 2 nd edition, American Society of Heating Refrigeration Airconditioning Engineers, Atlanta, GA 128. BLAST. 1993. BLAST Users Manual. BLAST Support Office, University of Illinois Urbana-Champaign. 129. LBL 1980, 1981, 1982, 1989, op.cit. 130. Kriebel, D.E., 1983. Simplified Energy Analysis Using the Modified Bin Method, American Society of Heating, Refrigerating and Air-Conditioning Engineers, Inc., Atlanta, Georgia. 131. ASHRAE 1999. op.cit. 132. ASHRAE 1993. op.cit. 133. Yuill, G., K., Haberl, J.S. 2002. Development of Accuracy Tests For Mechanical System Simulation. Final Report for ASHRAE Research Project 865-RP, The University of Nebraska at Lincoln, (July). 134. Katipamula, S. and Claridge, D.E., 1993. “ Use of Simplified Systems Models to Measure Retrofit Savings,” ASME Journal of Solar Energy Engineering, Vol. 115, pp. 57-68, May. 135. Liu, M. and Claridge , D.E., 1995. “Application of Calibrated HVAC System Models to Identify Component Malfunctions

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156.

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and to Optimize the Operation and Control Schedules,” Solar Engineering 1995, W.B. Stine, T. Tanaka and D.E. Claridge (Eds.), ASME/JSME/JSES International Solar Energy Conference, Maui, Hawaii, March. Liu, M. and Claridge, D.E., 1998. “Use of Calibrated HVAC System Models to Optimize System Operation,” Journal of Solar Energy Engineering, May 1998, Vol. 120. Liu, M., Wei, G., Claridge, D., E., 1998, “Calibrating AHU Models Using Whole Building Cooling and Heating Energy Consumption Data,” Proceedings of 1998 ACEEE Surrurier Study on Energy Efficiency in Buildings. Vol. 3. Haberl, J., Claridge, D., Turner. D. 2000b. “Workshop on Energy Measurement, Verification and Analysis Technology,” Energy Conservation Task Force, Federal Reserve Bank, Dallas, Texas (April). This table contains material adapted from proposed HVAC System Testing Methods for ASHRAE Guideline 14-2002, which were not included in the published ASHRAE Guideline 14-2002. Haberl et al. 2000b, op. cit. Kissock et al. 2001. op.cit. Fels 1986. op.cit. Rabl 1988. op.cit. Rabl and Raihle 1992. op.cit. Claridge et al. 1992. op.cit. Reddy, T.A., Haberl, J.S., Saman, N.F., Turner, W.D., Claridge, D.E., Chalifoux, A.T. 1997. “Baselining Methodology for Facility-Level Monthly Energy Use - Part 1: Theoretical Aspects,” ASHRAE Transactions-Research, Volume 103, Part 2, pp. 336347, (June). Reddy, T.A., Haberl, J.S., Saman, N.F., Turner, W.D., Claridge, D.E., Chalifoux, A.T. 1997 “Baselining Methodology for Facility-Level Monthly Energy Use - Part 2: Application to Eight Army Installations,” ASHRAE Transactions-Research, Volume 103, Part 2, pp. 348-359, (June). Haberl, J., Thamilseran, S., Reddy, A., Claridge, D., O’Neal, D., Turner, D. 1998. “Baseline Calculations for Measuring and Verification of Energy and Demand Savings in a Revolving Loan Program in Texas,” ASHRAE Transactions-Research, Volume 104, Part 2, pp. 841-858, (June). Turner, D., Claridge, D., O’Neal, D., Haberl, J., Heffington, W., Taylor, D., Sifuentes, T. 2000. “Program Overview: The Texas LoanSTAR Program: 1989 - 1999 A 10-year Experience,” Proceedings of the 2000 ACEEE Summery Study on Energy Efficiency in Buildings, Volume 4, pp. 4.365-4.376, (August). Haberl, J., Sreshthatputra, A., Claridge, D., Turner, D. 2001. “Measured Energy Indices for 27 Office Buildings,” Proceedings of the 1st International Conference for Enhanced Building Operation,” Austin, Texas, pp. 185-200, (July). Beasley, R., Haberl, J. 2002. “Development of a Methodology for Baselining The Energy Use of Large Multi-building Central Plants,” ASHRAE Transactions-Research, Volume 108, Part 1, pp. 251-259, (January). ASHRAE 2002. op.cit. p. 25, (Copied with permission). Haberl et al. 2000b, op. cit. Temperatures below zero are calculated as positive increases away from the change point temperature. Thamilseran, S., Haberl, J. 1995. “A Bin Method for Calculating Energy Conservation Retrofits Savings in Commercial Buildings,” Proceedings of the 1995 ASME/JSME/JSES International Solar Energy Conference, Lahaina, Maui, Hawaii, pp. 111- 124 (March). . Thamilseran, S. 1999. “An Inverse Bin Methodology to Measure the Savings from Energy Conservation Retrofits in Commercial Buildings,” Ph.D. Thesis, Mechanical Engineering Department, Texas A&M University, (May). Kissock et al. 2001. op.cit. Kissock, J.K, Xun,W., Sparks, R., Claridge, D., Mahoney, J. and

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159. 160.

161.

162.

163.

164.

165.

166.

167.

168.

169.

170.

171.

172.

173.

174.

175.

Haberl, J., 1994. “EModel Version 1.4de,” Texas A&M University, Energy Systems Laboratory, Department of Mechanical Engineering, Texas A&M University, College Station, TX, December. Abushakra et al. 2001. op.cit. Haberl, J., Bou-Saada, T. 1998. “Procedures for Calibrating Hourly Simulation Models to Measured Building Energy and Environmental Data,” ASME Journal of Solar Energy Engineering, Volume 120, pp. 193-204, (August). Clarke, J.A, Strachan, P.A. and Pemot, C.. 1993. An Approach to the Calibration of Building Energy Simulation Models. ASHRAE Transactions. 99(2): 917-927. Diamond, S.C. and Hunn, B.D.. 1981. Comparison of DOE-2 Computer Program Simulations to Metered Data for Seven Commercial Buildings. ASHRAE Transactions. 87(l): 1222-123 1. Haberl, J., Bronson, D., Hinchey, S. and O’Neal, D. 1993. “Graphical Tools to Help Calibrate the DOE-2 Simulation Program to Non-weather Dependent Measured Loads,” 1993 ASHRAE Journal, Vol. 35, No. 1, pp. 27-32, (January). Haberl, J., Bronson, D. and O’Neal, D. 1995. “An Evaluation of the Impact of Using Measured Weather Data Versus TMY Weather Data in a DOE-2 Simulation of an Existing Building in Central Texas.” ASHRAE Transactions Technical Paper no. 3921, Vol. 101, Pt. 2, (June). Hinchey, S.B. 1991. Influence of Thermal Zone Assumptions on DOE-2 Energy Use Estimations of a Commercial Building. M.S. Thesis, Energy Systems Report No. ESL-TH-91/09-06, Texas A&M University, College Station, TX Hsieh, E.S. 1988, Calibrated Computer Models of Commercial Buildings and Their Role in Building Design and Operation. M.S. Thesis, PU/CEES Report No. 230, Princeton University, Princeton, NJ. Hunn, B.D., Banks, J.A. and Reddy, S.N. 1992. Energy Analysis of the Texas Capitol Restoration. The DOE-2 User News. 13 (4): 2- 10. Kaplan, M.B., Jones, B. and Jansen, J. 1990a. DOE-2. I C Model Calibration with Monitored End-use Data. Proceedings from the ACEEE 1990 Summer Study on Energy Efficiency in Buildings, Vol. 10, pp. 10. 11510.125. Kaplan, M.B., Caner, P. and Vincent, G.W. 1992. Guidelines for Energy Simulation of Commercial Buildings. Proceedings from the ACEEE 1992 Summer Study on Energy Efficiency in Buildings, Vol. 1, pp. 1.137-1.147. Katipamula, S. and Claridge, D.E., 1993. “ Use of Simplified Systems Models to Measure Retrofit Savings,” ASME Journal of Solar Energy Engineering, Vol. 115, pp.57-68, May. Liu, M. and Claridge, D.E., 1995. “Application of Calibrated HVAC System Models to Identify Component Malfunctions and to Optimize the Operation and Control Schedules,” Solar Engineering 1995, W.B. Stine, T. Tanaka and D.E. Claridge (Eds.), ASME/JSME/JSES International Solar Energy Conference, Maui, Hawaii, March. Liu, M. and Claridge, D. E., 1998. “Use of Calibrated HVAC System Models to Optimize System Operation,” Journal of Solar Energy Engineering, May 1998, Vol. 120. Liu, M., Wei, G., Claridge, D. E., 1998, “Calibrating AHU Models Using Whole Building Cooling and Heating Energy Consumption Data,” Proceedings of 1998 ACEEE Summer Study on Energy Efficiency in Buildings. Vol. 3. Manke, J., Hittle, D. and Hancock 1996. “Calibrating Building Energy Analysis Models Using Short Term Test Data,” Proceedings of the 1996 International ASME Solar Energy Conference, p. 369, San Antonio, TX McLain, H.A., Leigh, S.B., and MacDonald, J.M1993. Analysis of Savings Due to Multiple Energy Retrofits in a Large Office Building. Oak Ridge National Laboratory, ORNL Report No. ORNL/CON-363, Oak Ridge, TN.

754 176. Haberl et al. 2000b, op. cit. 177. ASHRAE 2002. op.cit. p. 35-43, (Copied with permission). 178. Bou-Saada, T. 1994. An Improved Procedure for Developing A Calibrated Hourly Simulation Model of an Electrically Heated and Cooled Commecial Building, Master’s Thesis, Mechanical Engineering Department, Texas A&M University, (December), p. 54. 179. Sylvester, K., Song, S., Haberl, J., and Turner, D. 2002. Case Study: Energy Savings Assessment for the Robert E. Johnson State Office Building in Austin, Texas,” IBPSA Newsletter, Vol. 12, Number 2, pp. 22-28, (Summer). 180. Huang & Associates. 1993. DrawBDL user ’s guide. 6720 Potrero Ave., El Cerrito, California, 94530. 181. Bou Saada, T. 1994. “An Improved Procedure for Developing A Calibrated Hourly Simulation Model of an Electrically Heated and Cooled Commercial Building,” Master’s Thesis, Mechanical Engineering Department, Texas A&M University, (December), p. 150. 182. Bou-Saada 1994. op. cit. p. 144. 183. C. Culp, K. Q. Hart, B. Turner, S. Berry-Lewis, 2003. “Cost Effective Measurement and Verification at Fairchild AFB, International Conference on Enhance Building Operation,” Energy Systems Laboratory Report, Texas A&M University, (October). 184. Culp et al. 2003, ibid. 185. ASME 1974 op cit.

ENERGY MANAGEMENT HANDBOOK

CHAPTER 28

GROUND-SOURCE HEAT PUMPS APPLIED TO COMMERCIAL BUILDINGS

STEVEN A. PARKER, P.E., C.E.M. DONALD L. HADLEY Energy Science and Technology Directorate Pacific Northwest National Laboratory1 Richland, WA

This chapter provides information and procedures that an energy manager can use to evaluate most groundsource heat pump applications. Ground-source heat pump operation, system types, design variations, energy savings, and other benefits are explained. Guidelines are provided for appropriate application and installation. Two case studies are presented to give the reader a sense of the actual costs and energy savings. A list of manufacturers and references for further reading are included for prospective users who have specific or highly technical questions not fully addressed in this chapter. Sample case spreadsheets are also provided.

28.1 ABSTRACT Ground-source heat pumps can provide an energy-efficient, cost-effective way to heat and cool commercial facilities. While ground-source heat pumps are well established in the residential sector, their application in larger, commercial-style, facilities is lagging, in part because of limited experience with the technology by those in decision-making positions. Through the use of a ground-coupling system, a conventional water-source heat pump design is transformed to a unique means of utilizing thermodynamic properties of earth and groundwater for efficient operation throughout the year in most climates. In essence, the ground (or groundwater) serves as a heat source during winter operation and a heat sink for summer cooling. Many varieties in design are available, so the technology can be adapted to almost any site. Ground-source heat pump systems can be used widely in commercial-building applications and, with proper installation, offer great potential for the commercial sector, where increased efficiency and reduced heating and cooling costs are important. Ground-source heat pump systems require less refrigerant than conventional airsource heat pumps or air-conditioning systems, with the exception of direct-expansion-type ground-source heat pump systems. Installation costs are relatively high but are offset by low maintenance and operating expenses and efficient energy use. The greatest barrier to effective use is improper design and installation; well-trained, experienced, and responsible designers and installers is of critical importance. 1Pacific Northwest National Laboratory is operated for the U.S. Department of Energy by Battelle Memorial Institute under contract DE-AC05-76RL01830.

28.2 BACKGROUND This chapter is based on a Federal Technology Alert sponsored by the U.S. Department of Energy (DOE), Federal Energy Management Program (FEMP). The original Federal Technology Alert was published in 1995 and updated in 2001. The material was updated in 2005 to develop this chapter. 28.2.1 The DOE Federal Energy Management Program The federal government is the largest energy consumer in the nation. Annually, in its 500,000 buildings and 8,000 locations worldwide, it uses nearly 1.4 quadrillion Btu (quads) of energy, costing approximately $8 billion. This represents 1.5% of all primary energy consumption in the United States2. The DOE Federal Energy Management Program was established in 1974 to provide direction, guidance, and assistance to federal agencies in planning and implementing energy management programs that will improve the energy efficiency and fuel flexibility of the federal infrastructure. Over the years several federal laws and Executive Orders have shaped FEMP’s mission. These include the Energy Policy and Conservation Act of 1975; the National Energy Conservation and Policy Act of 1978; the Federal 2DOE. 2001. Annual Report to Congress on Federal Government Energy

Management and Conservation programs, Fiscal Year 1999. DOE/EE0252. U.S. Department of Energy. Washington, DC. 755

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Energy Management Improvement Act of 1988; Executive Order 12759 in 1991; the National Energy Policy Act of 1992 (EPAct 1992); Executive Order 12902 in 1994; Executive Order 13123 in 1999; and the Energy Policy Act of 2005 (EPAct 2005). The DOE Federal Energy Management Program is currently involved in a wide range of energy-assessment activities, including conducting new technology demonstrations, to hasten the penetration of energy-efficient technologies into the federal marketplace. 28.2.2 The FEMP New Technology Demonstrations Activity The Energy Policy Act of 1992, and subsequent Executive Orders, mandated that energy consumption in federal buildings be reduced by 35% from 1985 levels by the year 2010. The Energy Policy Act of 2005 calls for even more energy reduction. To achieve this goal, the DOE Federal Energy Management Program sponsors a series of program activities to reduce energy consumption at federal installations nationwide. One of these program activities, new technology demonstrations, is tasked to accelerate the introduction of energy-efficient and renewable technologies into the federal sector and to improve the rate of technology transfer. In addition to technology demonstrations, FEMP sponsors a series of publications that are designed to disseminate information on new and emerging technologies. These publications include: Federal Technology Alerts—longer summary reports that provide details on energy-efficient, water-conserving, and renewable-energy technologies that have been selected for further study for possible implementation in the Federal sector. Additional information on Federal Technology Alerts is provided below. Technology Installation Reviews— concise reports describing a new technology and providing case study results, typically from another demonstration program or pilot project. Technology Focuses—brief information on new, energy-efficient, environmentally friendly technologies of potential interest to the Federal sector. 28.2.3 More on Federal Technology Alerts Federal Technology Alerts provide summary information on candidate energy-saving technologies developed and manufactured in the United States. The technologies featured in the Federal Technology Alerts have already entered the market and have some experience but are not in general use in the Federal sector. The goal of the Federal Technology Alerts is to improve the rate of technology transfer of new energy-sav-

ENERGY MANAGEMENT HANDBOOK

ing technologies within the Federal sector by providing the right people in the field with accurate, up-to-date information on the new technologies so that they can make informed decisions on whether the technologies are suitable for their sites. The information in the Federal Technology Alerts typically includes a description of the candidate technology; a description of its performance, applications and field experience to date; a list of manufacturers; and important sources for additional information. Appendixes provide supplemental information and example worksheets for the technology. FEMP sponsors publication of the Federal Technology Alerts to facilitate information sharing between manufacturers and government staff. While the technology featured promises potential Federal sector energy savings, the Federal Technology Alerts do not constitute FEMP’s endorsement of a particular product, because FEMP has not independently verified performance data provided by manufacturers. Readers should note the publication date and consider the Federal Technology Alerts as an accurate picture of the technology and its performance at the time of publication. Product innovations and the entrance of new manufacturers or suppliers should be anticipated since the date of publication. FEMP encourages interested energy and facility managers to contact the manufacturers and other sites directly, and to use the worksheets in the Federal Technology Alerts to aid in their purchasing decisions.

28.3 INTRODUCTION TO GROUND-SOURCE HEAT PUMPS Ground-source heat pumps are known by a variety of names: geoexchange heat pumps, ground-coupled heat pumps, geothermal heat pumps, earth-coupled heat pumps, ground-source systems, groundwater source heat pumps, well water heat pumps, solar energy heat pumps, and a few other variations. Some names are used to describe more accurately the specific application; however, most are the result of marketing efforts and the need to associate (or disassociate) the heat pump systems from other systems. This chapter refers to them as ground-source heat pumps except when it is necessary to distinguish a specific design or application of the technology. A typical groundsource heat pump system design applied to a commercial facility is illustrated in Figure 28.1. It is important to remember that the primary equipment used for ground-source heat pumps are watersource heat pumps. What makes a ground-source heat pump different (unique, efficient, and usually more expensive to install) is the ground-coupling system. In

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Figure 28.1. Typical ground-source heat pump system applied to a commercial facility addition, most manufacturers have developed extendedrange water-source heat pumps for use as ground-source heat pumps.3 A conventionally designed water-source heat pump system would incorporate a boiler as a heat source during the winter heating operation and a cooling tower to reject heat (heat sink) during the summer cooling operation. This system type is also sometimes called a boiler/tower water-loop heat pump system. The water loop circulates to all the water-source heat pumps connected to the system. The boiler (for winter operation) and the cooling tower (for summer operation) provide a fairly constant water-loop temperature, which allows the water-source heat pumps to operate at high efficiency. A conventional air-source heat pump uses the outdoor ambient air as a heat source during the winter heating operation and as a heat sink during the summer cooling operation. Air-source heat pumps are subject to higher temperature fluctuations of the heat source and heat sink. They become much less effective—and less efficient—at extreme ambient air temperatures. This is particularly true at low temperatures. In addition, heat transfer using air as a transfer medium is not as effective as water systems because of air’s lower thermal mass.

A ground-source heat pump uses the ground (or in some cases groundwater) as the heat source during the winter heating operation and as the heat sink during the summer cooling operation. Ground-source heat pumps may be subject to higher temperature fluctuations than conventional water-source heat pumps but not as high as air-source heat pumps. Consequently, most manufacturers have developed extended-range systems. The extended-range systems operate more efficiently while subject to the extended-temperature range of the water loop. Like water-source heat pumps, ground-source heat pumps use a water loop between the heat pumps and the heat source/heat sink (the earth). The primary exception is the direct-expansion ground-source heat pump, which is described in more detail later in this chapter. Ground-source heat pumps take advantage of the thermodynamic properties of the earth and groundwater. Temperatures below the ground surface do not fluctuate significantly through the day or the year as do ambient air temperatures. Ground temperatures a few feet below the surface stay relatively constant throughout the year. For this reason, ground-source heat pumps remain extremely efficient throughout the year in virtually any climate.

3The

28.4 ABOUT THE TECHNOLOGY

extended-range designation is important. Conventional watersource heat pumps are designed to operate with a water-loop as a heat sink that maintains a narrow temperature range. Ground-source heat pumps, however, are typically required to operate with a water-loop heat sink under a wider range of temperatures.

In 1999, an estimated 400,000 ground-source heat pumps were operating in residential and commercial ap-

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plications, up from 100,000 in 1990. In 1985, it was estimated that only around 14,000 ground-source heat pump systems were installed in the United States. Annual sales of approximately 45,000 units were reported in 1997. With a projected annual growth rate of 10%, 120,000 new units would be installed in 2010, for a total of 1.5 million units in 2010 (Lund and Boyd 2000). In Europe, the estimated total number of installed ground-source heat pumps at the end of 1998 was 100,000 to 120,000 (Rybach and Sanner 2000). Nearly 10,000 ground-source heat pumps have been installed in U.S. Federal buildings, over 400 schools and thousands of low-income houses and apartments (ORNL/SERDP, no date). Although ground-source heat pumps are used throughout the United States, the majority of new groundsource heat pump installations in the United States are in the southern and mid-western states (from North Dakota to Florida). Oklahoma, Texas, and the East Coast have been particularly active with new ground-source heat pump installations. Environmental concerns, particularly from the potential for groundwater contamination with a leaking ground loop, and a general lack of understanding of the technology by HVAC companies and installers have limited installations in the West (Lund and Boyd 2000). Usually the technology does well in an area where it has been actively promoted by a local utility or the manufacturer. Ground-source heat pumps are not a new idea. Patents on the technology date back to 1912 in Switzerland (Calm 1987). One of the oldest ground-source heat pump systems, in the United Illuminating headquarters building in New Haven, Connecticut, has been operating since the 1930s (Pratsch 1990). Although ground-source heat pump systems are probably better established today in rural and suburban residential areas because of the land area available for the ground loop, the market has expanded to urban and commercial applications. The vast majority of ground-source heat pump installations utilize unitary equipment consisting of multiple water-source heat pumps connected to a common ground-coupled loop. Most individual units range from 1 to 10 tons (3.5 to 35.2 kW), but some equipment is available in sizes up to 50 tons (176 kW). Large-tonnage commercial systems are achieved by using several unitary water-source heat pumps, each responsible for an individual control zone. One of the largest commercial ground-source heat pump systems is at Stockton College in Pomona, New Jersey, where 63 ground-source heat pumps totaling 1,655 tons (5,825 kW) are connected to a ground-coupled loop consisting of 400 wells, each 425 feet (129 m) deep (Gahran 1993).

ENERGY MANAGEMENT HANDBOOK

Public schools are another good application for the ground-source heat pump technology with over 400 installations nationwide. In 1995, the Lincoln, Nebraska, Public School District built four new 70,000 square foot elementary schools. Space conditioning loads are met by 54 ground-source heat pumps ranging in size from 1.4 to 15 tons, with a total cooling capacity of 204 tons. Gasfired boilers provided hot water for pre-heating of the outside air and for terminal re-heating. Compared with other similar new schools, these four ground-source heat pump conditioned facilities used approximately 26% less source energy per square foot of floor area (Shonder et al. 1999). Multiple unitary systems are not the only arrangement suitable for large commercial applications. It is also possible to design large centralized heat-pump system consisting of reciprocating and centrifugal compressors (up to 19.5 million Btu/h) and to use these systems to support central-air-handling units, variable air-volume systems, or distributive two-pipe fan coil units. 28.4.1 How the Technology Works Heat normally flows from a warmer medium to a colder one. This basic physical law can only be reversed with the addition of energy. A heat pump is a device that does so by essentially “pumping” heat up the temperature scale, then transferring it from a cold material to a warmer one by adding energy, usually in the form of electricity. A heat pump functions by using a refrigerant cycle similar to the household refrigerator. In the heating mode, a heat pump removes the heat from a low temperature source, such as the ground or air, and supplies that heat to a higher temperature sink, such as the heated interior of a building. In the cooling mode, the process is reversed and the heat is extracted from the cooler inside air and rejected to the warmer outdoor air or other heat sink. For space conditioning of buildings, heat pumps that remove heat from outdoor air in the heating mode and reject it to outdoor air in the cooling mode are common. These are normally called air-source or air-to-air heat pumps. Air-source heat pumps have the disadvantage that the greatest requirement for building heating or cooling is necessarily coincident with the times when the outdoor air is least effective as a heat source or sink. Below about 37ºF (2.8°C), supplemental heating is required to meet the heating load. For this reason, air-source heat pumps are essentially unfeasible in cold climates with outdoor temperatures below 37ºF (2.8°C) for extended periods of time. The efficiency of any heat pump is inversely proportional to the temperature difference between the conditioned space and the heat source (heating mode) or heat

GROUND-SOURCE HEAT PUMPS APPIED TO COMMERCIAL BUILDINGS

sink (cooling mode) as can be easily shown by a simple thermodynamic analysis (Reynolds and Perkins 1977). For this reason, air-source heat pumps are less efficient and have a lower heating capacity in the heating mode at low outdoor air temperatures. Conversely, air-source heat pumps are also less efficient and have a lower cooling capacity in the cooling mode at high outdoor air temperatures. Ground-source heat pumps, however, are not impacted directly by outdoor air temperatures. Groundsource heat pumps use the ground, groundwater, or surface water, which are more thermally stable and not subjected to large annual swings of temperature, as a heat source or sink. 28.4.2 Other benefits The primary benefit of ground-source heat pumps is the increase in operating efficiency, which translates to a reduction in heating and cooling costs, but there are additional advantages. One notable benefit is that ground-source heat pumps, although electrically driven, are classified as a renewable-energy technology. The justification for this classification is that the ground acts as an effective collector of solar energy. The renewable-energy classification can affect federal goals and potential federal funding opportunities. An environmental benefit is that ground-source heat pumps typically use 25% less refrigerant than split-system air-source heat pumps or air-conditioning systems. Ground-source heat pumps generally do not require tampering with the refrigerant during installation. Systems are generally sealed at the factory, reducing the potential for leaking refrigerant in the field during assembly. Ground-source heat pumps also require less space than conventional heating and cooling systems. While the requirements for the indoor unit are about the same as conventional systems, the exterior system (the ground coil) is underground, and there are no space requirements for cooling towers or air-cooled condensers. In addition, the ground-coupling system does not necessarily limit future use of the land area over the ground loop, with the exception of siting a building. Interior space requirements are also reduced. There are no floor space requirements for boilers or furnaces, just the unitary systems and circulation pumps. Furthermore, many distributed ground-source heat pump systems are designed to fit in ceiling plenums, reducing the floor space requirement of central mechanical rooms. Compared with air-source heat pumps that use outdoor air coils, ground-source heat pumps do not require defrost cycles or crankcase heaters and there is virtually no concern for coil freezing. Cooling tower systems require electric resistance heaters to prevent freezing in the

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tower basin, also not necessary with ground-source heat pumps. It is generally accepted that maintenance requirements are also reduced, although research continues directed toward verifying this claim. It is clear, however, that ground-source heat pumps eliminate the exterior fincoil condensers of air-cooled refrigeration systems and eliminate the need for cooling towers and their associated maintenance and chemical requirements. This is a primary benefit cited by facilities in highly corrosive areas such as near the ocean, where salt spray can significantly reduce outdoor equipment life. Ground-source heat pump technology offers further benefits: less need for supplemental resistance heaters, no exterior coil freezing (requiring defrost cycles) such as that associated with air-source heat pumps, improved comfort during the heating season (compared with air-source heat pumps, the supply air temperature does not drop when recovering from the defrost cycle), significantly reduced fire hazard over that associated with fossil fuel-fired systems, reduced space requirements and hazards by eliminating fossil-fuel storage, and reduced local emissions from those associated with other fossil fuel-fired heating systems. Another benefit is quieter operation, because ground-source heat pumps have no outside air fans. Finally, ground-source heat pumps are reliable and longlived, because the heat pumps are generally installed in climate-controlled environments and therefore are not subject to the stresses of extreme temperatures. Because of the materials and joining techniques, the ground-coupling systems are also typically reliable and long-lived. For these reasons, ground-source heat pumps are expected to have a longer life and require less maintenance than alternative (more conventional) technologies. 28.4.3 Ground-Coupled System Types The ground-coupling systems used in groundsource heat pumps fall under three main categories: closed-loop, open-loop and direct-expansion. These are illustrated in Figure 28.2 and discussed in the following sections. The type of ground coupling employed will affect heat pump system performance (therefore the heat pump energy consumption), auxiliary pumping energy requirements, and installation costs. Choice of the most appropriate type of ground coupling for a site is usually a function of specific geography, available land area, and life-cycle cost economics. Closed-loop Systems Closed-loop systems consist of an underground network of sealed, high-strength plastic pipe4 acting as a heat

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ENERGY MANAGEMENT HANDBOOK

exchanger. The loop is filled with a heat transfer fluid, typically water or a water-antifreeze5 solution, although other heat transfer fluids may be used.6 When cooling requirements cause the closed-loop liquid temperature to rise, heat is transferred to the cooler earth. Conversely, when heating requirements cause the closed-loop fluid temperature to drop, heat is absorbed from the warmer earth. Closed-loop systems use pumps to circulate the heat transfer fluid between the heat pump and the ground loop. Because the loops are closed and sealed, the heat pump heat exchanger is not subject to mineral buildup and there is no direct interaction (mixing) with groundwater. There are several varieties of closed-loop configurations including horizontal, spiral, vertical, and submerged. Horizontal Loops Horizontal loops, illustrated in Figure 28.2a, are often considered when adequate land surface is available. The pipes are placed in trenches, typically at a depth of 4 to 10 feet (1.2 to 3.0 m). Depending on the specific design, from one to six pipes may be installed in each trench. Although requiring more linear feet of pipe, multiple-pipe configurations conserve land space, require less trenching, and therefore frequently cost less to install than single-pipe configurations. Trench lengths can range from 100 to 400 feet per system cooling ton (8.7 to 34.6 m/kW), depending on soil characteristics and moisture content, and the number of pipes in the trench. Trenches are usually spaced from 6 to 12 feet (1.8 to 3.7 m) apart. These systems are common in residential applications but are not frequently applied to large-tonnage commercial applications because of the significant land area required for adequate heat transfer. The horizontal-loop systems can be buried beneath lawns, landscaping, and parking lots. Horizontal systems tend to be more popular where there is ample land area with a high water table.

Figure 28.2. Ground-coupling system types •

Advantages: Trenching costs typically lower than well-drilling costs; flexible installation options.

•

4Acceptable piping includes high quality polyethylene or polybutylene.

Disadvantages: Large ground area required; ground temperature subject to seasonal variance at shallow depths; thermal properties of soil fluctuate with season, rainfall, and burial depth; soil dryness must be properly accounted for in designing the required pipe length, especially in sandy soils and on hilltops that may dry out during the summer; pipe system could be damaged during backfill process; longer pipe lengths are required than for vertical wells; antifreeze solution viscosity increases pumping energy, decreases the heat transfer rate, and thus reduces overall efficiency; lower system efficiencies.

PVC is not acceptable in either heat transfer characteristics or strength. 5Common heat transfer fluids include water or water mixed with an antifreeze, such as: sodium chloride, calcium chloride, potassium carbonate, potassium acetate, ethylene glycol, propylene gycol, methyl alcohol, or ethyl alcohol. 6Note that various heat transfer fluids have different densities and thermodynamic properties. Therefore, the heat transfer fluid selected will affect the required pumping power and the amount of heat transfer pipe. Furthermore, some local regulations may limit the selection and use of certain antifreeze solutions.

Spiral Loops A variation on the multiple pipe horizontal-loop configuration is the spiral loop, commonly referred to as the “slinky.” The spiral loop, illustrated in Figure 28.2b, consists of pipe unrolled in circular loops in trenches; the horizontal configuration is shown.

GROUND-SOURCE HEAT PUMPS APPIED TO COMMERCIAL BUILDINGS

Another variation of the spiral-loop system involves placing the loops upright in narrow vertical trenches. The spiral-loop configuration generally requires more piping, typically 500 to 1,000 feet per system cooling ton (43.3 to 86.6 m/kW) but less total trenching than the multiple horizontal-loop systems described above. For the horizontal spiral-loop layout, trenches are generally 3 to 6 feet (0.9 to 1.8 m) wide; multiple trenches are typically spaced about 12 feet (3.7 m) apart. For the vertical spiral-loop layout, trenches are generally 6 inches (15.2 cm) wide; the pipe loops stand vertically in the narrow trenches. In cases where trenching is a large component of the overall installation costs, spiral-loop systems are a means of reducing the installation cost. As noted with horizontal systems, slinky systems are also generally associated with lower-tonnage systems where land area requirements are not a limiting factor. •

Advantages: Requires less ground area and less trenching than other horizontal loop designs; installation costs sometimes less than other horizontal loop designs.

•

Disadvantages: Requires more total pipe length than other ground-coupled designs; relatively large ground area required; ground temperature subject to seasonal variance; larger pumping energy requirements than other horizontal loops defined above; backfilling the trench can be difficult with certain soil types and the pipe system could be damaged during backfill process.

Vertical Loops Vertical loops, illustrated in Figure 28.2c, are generally considered when land surface is limited. Wells are bored to depths that typically range from 75 to 300 feet (22.9 to 91.4 m) deep. The closed-loop pipes are inserted into the vertical well. Typical piping requirements range from 200 to 600 feet per system cooling ton (17.4 to 52.2 m/kW), depending on soil and temperature conditions. Multiple wells are typically required with well spacing not less than 15 feet (4.6 m) in the northern climates and not less than 20 feet (6.1 m) in southern climates to achieve the total heat transfer requirements. A 300- to 500ton capacity system can be installed on one acre of land, depending on soil conditions and ground temperature. There are three basic types of vertical-system heat exchangers: U-tube, divided-tube, and concentric-tube (pipe-in-pipe) system configurations. •

Advantages: Requires less total pipe length than most closed-loop designs; requires the least pump-

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ing energy of closed-loop systems; requires least amount of surface ground area; ground temperature typically not subject to seasonal variation. •

Disadvantage: Requires drilling equipment; drilling costs frequently higher than horizontal trenching costs; some potential for long-term heat buildup underground with inadequately spaced bore holes.

Submerged Loops If a moderately sized pond or lake is available, the closed-loop piping system can be submerged, as illustrated in Figure 28.2d. Some companies have installed ponds on facility grounds to act as ground-coupled systems; ponds also serve to improve facility aesthetics. Submerged-loop applications require some special considerations, and it is best to discuss these directly with an engineer experienced in the design applications. This type of system requires adequate surface area and depth to function adequately in response to heating or cooling requirements under local weather conditions. In general, the submerged piping system is installed in loops attached to concrete anchors. Typical installations require around 300 feet of heat transfer piping per system cooling ton (26.0 m/kW) and around 3,000 square feet of pond surface area per ton (79.2 m2/kW) with a recommended minimum one-half acre total surface area. The concrete anchors act to secure the piping, restricting movement, but also hold the piping 9 to 18 inches (22.9 to 45.7 cm) above the pond floor, allowing for good convective flow of water around the heat transfer surface area. It is also recommended that the heat-transfer loops be at least 6 to 8 feet (1.8 to 2.4 m) below the pond surface, preferably deeper. This maintains adequate thermal mass even in times of extended drought or other low-water conditions. Rivers are typically not used because they are subject to drought and flooding, both of which may damage the system. •

Advantages: Can require the least total pipe length of closed-loop designs; can be less expensive than other closed-loop designs if body of water available.

•

Disadvantage: Requires a large body of water and may restrict lake use (i.e., boat anchors).

Open-Loop Systems Open-loop systems use local groundwater or surface water (i.e., lakes) as a direct heat transfer medium instead of the heat transfer fluid described for the closedloop systems. These systems are sometimes referred to specifically as “ground-water-source heat pumps” to

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distinguish them from other ground-source heat pumps. Open-loop systems consist primarily of extraction wells, extraction and reinjection wells, or surface water systems. These three types are illustrated in Figures 28.2e, 28.2f, and 28.2g, respectively. A variation on the extraction well system is the standing column well. This system reinjects the majority of the return water back into the source well, minimizing the need for a reinjection well and the amount of surface discharge water. There are several special factors to consider in open-loop systems. One major factor is water quality. In open-loop systems, the primary heat exchanger between the refrigerant and the groundwater is subject to fouling, corrosion, and blockage. A second major factor is the adequacy of available water. The required flow rate through the primary heat exchanger between the refrigerant and the groundwater is typically between 1.5 and 3.0 gallons per minute per system cooling ton (0.027 and 0.054 L/skW). This can add up to a significant amount of water and can be affected by local water resource regulations. A third major factor is what to do with the discharge stream. The groundwater must either be re-injected into the ground by separate wells or discharged to a surface system such as a river or lake. Local codes and regulations may affect the feasibility of open-loop systems. Depending on the well configuration, open-loop systems can have the highest pumping load requirements of any of the ground-coupled configurations. In ideal conditions, however, an open-loop application can be the most economical type of ground-coupling system. •

Advantages: Simple design; lower drilling requirements than closed-loop designs; subject to better thermodynamic performance than closed-loop systems because well(s) are used to deliver groundwater at ground temperature rather than as a heat exchanger delivering heat transfer fluid at temperatures other than ground temperature; typically lowest cost; can be combined with potable water supply well; low operating cost if water already pumped for other purposes, such as irrigation.

•

Disadvantages: Subject to various local, state, and Federal clean water and surface water codes and regulations; large water flow requirements; water availability may be limited or not always available; heat pump heat exchanger subject to suspended matter, corrosive agents, scaling, and bacterial contents; typically subject to highest pumping power requirements; pumping energy may be excessive if the pump is oversized or poorly controlled; may

require well permits or be restricted for extraction; water disposal can limit or preclude some installations; high cost if reinjection well required. Direct-Expansion Systems Each of the ground-coupling systems described above uses an intermediate heat transfer fluid to transfer heat between the earth and the refrigerant. Use of an intermediate heat transfer fluid necessitates a higher compression ratio in the heat pump to achieve sufficient temperature differences in the heat transfer chain (refrigerant to fluid to earth). Each also requires a pump to circulate water between the heat pump and the groundcouple. Direct-expansion systems, illustrated in Figure 28.2h, remove the need for an intermediate heat transfer fluid, the fluid-refrigerant heat exchanger, and the circulation pump. Copper coils are installed underground for a direct exchange of heat between refrigerant and earth. The result is improved heat transfer characteristics and thermodynamic performance. The coils can be buried either in deep vertical trenches or wide horizontal excavations. Vertical trenches typically require from 100 to 150 square feet of land surface area per system cooling ton (2.6 to 4.0 m2/kW) and are typically 9 to 12 feet (2.7 to 3.7 m) deep. Horizontal installations typically require from 450 to 550 square feet of land area per system cooling ton (11.9 to 14.5 m2/kW) and are typically 5 to 10 feet (1.5 to 3.0 m) deep. Vertical trenching is not recommended in sandy, clay or dry soils because of the poor heat transfer. Because the ground coil is metal, it is subject to corrosion (the pH level of the soil should be between 5.5 and 10, although this is normally not a problem). If the ground is subject to stray electric currents and/or galvanic action, a cathodic protection system may be required. Because the ground is subject to larger temperature extremes from the direct-expansion system, there are additional design considerations. In winter heating operation, the lower ground coil temperature may cause the ground moisture to freeze. Expansion of the ice buildup may cause the ground to buckle. Also, because of the freezing potential, the ground coil should not be located near water lines. In the summer cooling operation, the higher coil temperatures may drive moisture from the soil. Low moisture content will change soil heat transfer characteristics. At the time this chapter was initially drafted (1995), only one U.S. manufacturer offered direct-expansion ground-source heat pump systems. However, new companies have released similar direct-expansion systems. In November 2005, the Geothermal Heat Pump Consortium web site identified four manufacturers of direct exchange

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systems. Systems were available from 16,000 to 83,000 Btu/h (heating/cooling capacity) (4.7 to 24.3 kW). Larger commercial applications would require multiple units with individual ground coils.

ground-loop design. With horizontal ground-loop systems, the ground surface annual temperature variation (Figure 28.3b and Figure 28.4b) becomes an important design consideration.

•

Advantages: Higher system efficiency; no circulation pump required.

•

Disadvantages: Large trenching requirements for effective heat transfer area; ground around the coil subject to freezing (may cause surface ground to buckle and can freeze nearby water pipes); copper coil should not be buried near large trees where root system may damage the coil; compressor oil return can be complicated, particularly for vertical heat exchanger coils or when used for both heating and cooling; leaks can be catastrophic; higher skilled installation required; installation costs typically higher; this system type requires more refrigerant than most other systems; smaller infrastructure in the industry.

Soil and Rock Classification The most important factor in the design and successful operation of a closed-loop ground-source heat pump system is the rate of heat transfer between the closed-loop ground-coupling system and the surrounding soil and rock. The thermal conductivity of the soil and rock is the critical value that determines the length of pipe required. The pipe length, in turn, affects the installation cost as well as the operational effectiveness, which in turn affects the operating cost. Because of local variations in soil type and moisture conditions, economic designs may vary by location. Soil classifications include coarse-grained sands and gravels, fine-grained silts and clays, and loam (equal mixtures of sand, silt, and clay). Rock classifications are broken down into nine different petrologic groups. Thermal conductivity values vary significantly within each of the nine groups. Each of these classifications plays a role in determining the thermal conductivity and thereby affects the design of the ground-coupling system. For more information on the thermal properties of soils and rocks and how to identify the different types of soils and rocks, see Soil and Rock Classification for the Design of Ground-Coupled Heat Pump Systems (STS Consultants 1989).

28.4.4 Variables Affecting Design and Performance Among the variables that have a major impact on the sizing and effectiveness of a ground-coupling system, the importance of underground soil temperatures and soil type deserves special mention. Underground Soil Temperature The soil temperature is of major importance in the design and operation of a ground-source heat pump. In an open-loop system, the temperature of groundwater entering the heat pump has a direct impact on the efficiency of the system. In a closed-loop system and in the direct-expansion system, the underground temperature will affect the size of the required ground-coupling system and the resulting operational effectiveness of the underground heat exchanger. Therefore, it is important to determine the underground soil temperature before selecting a system design. Annual air temperatures, moisture content, soil type, and ground cover all have an impact on underground soil temperature. In addition, underground temperature varies annually as a function of the ambient surface air temperature swing, soil type, depth, and time lag. Figure 28.3 contains a map of the United States indicating mean annual underground soil temperatures and amplitudes of annual surface ground temperature swings. Figure 28.4, though for a specific location, illustrates how the annual soil temperature varies with depth, soil type, and season. For vertical ground-loop systems, the mean annual earth temperature (Figure 28.3a) is an important factor in the

Series versus Parallel Flow Closed-loop ground-coupled heat exchangers may be designed in series, parallel, or a combination of both. In series systems, the heat transfer fluid can take only one path through the loop, whereas in parallel systems the fluid can take two or more paths through the circuit. The selection will affect performance, pumping requirements, and cost. Small-scale ground-coupling systems can use either series or parallel-flow design, but most large ground-coupling systems use parallel-flow systems. The advantages and disadvantages of series and parallel systems are summarized below. In large systems, pressure drop and pumping costs need to be carefully considered or they will be very high. Variablespeed drives can be used to reduce pumping energy and costs during part-load conditions. Total life-cycle cost and design limitations should be used to design a specific system. •

Series-System Advantages: Single path flow and pipe size; easier air removal from the system; slightly higher thermal performance per linear foot of

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Figure 28.4. Soil temperature variation Source: OSU (1988)

•

Figure 28.3. Mean annual soil temperatures. Source: OSU (1988) • pipe because larger pipe size required in the series system. •

Series-System Disadvantages: Larger fluid volume of larger pipe in series requires greater antifreeze volumes; higher pipe cost per unit of performance; increased installed labor cost; limited capacity (length) caused by fluid pressure drop characteristics; larger pressure drop resulting in larger pumping load; requires larger purge system to remove air from the piping network.

Parallel-System Advantages: Smaller pipe diameter has lower unit cost; lower volume requires less antifreeze; smaller pressure drop resulting in smaller pumping load; lower installation labor cost.

Parallel-System Disadvantages: Special attention required to ensure air removal and flow balancing between each parallel path to result in equal length loops.

28.4.5 Variations The ground-coupling system is what makes the ground-source heat pump unique among heating and air-conditioning systems and, as described above, there are several types of ground-coupling systems. In addition, variations to ground-source heat pump design and installation can save additional energy or reduce installa-

GROUND-SOURCE HEAT PUMPS APPIED TO COMMERCIAL BUILDINGS

tion costs. Three notable variations are described below. Cooling-Tower-Supplemented System The ground-coupling system is typically the largest component of the total installation cost of a groundsource heat pump. In southern climates or in thermally heavy commercial applications where the cooling load is the driving design factor, supplementing the system with a cooling tower or other supplemental heat rejection system can reduce the required size of a closed-loop groundcoupling system. The supplemental heat rejection system is installed in the loop by means of a heat exchanger (typically a plate and frame heat exchanger) between the facility load and the ground couple. A cooling tower system is illustrated in Figure 28.5. The cooling tower acts to precool the loop’s heat transfer fluid upstream of the ground couple, which lowers the cooling-load requirement on the ground-coupling system. By significantly reducing the required size of the ground-coupling system, using a cooling tower can lower the overall installation cost. This type of system is operating successfully in several commercial facilities, including some mission-critical facilities at Fort Polk in Louisiana.

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required size of the ground-coupled system and increase heat pump efficiency by providing a higher temperature heat transfer fluid. Hot Water Recovery/Desuperheating The use of heat pumps to provide hot water is becoming common. Because of their high efficiency, this practice makes economic sense. Most manufacturers offer an option to include desuperheating heat exchangers to provide hot water from a heat pump. These dual-wall heat exchangers are installed in the refrigerant loop to recover high temperature heat from the superheated refrigerant gas. Hot-water recovery systems can supplement, or sometimes replace, conventional facility water-heating systems. With the heat pump in cooling mode, hot-water recovery systems increase system operating efficiency while acting as a waste-heat-recovery device—and provide essentially free hot water. When the load is increased during the heating mode, the heat pump still provides heating and hot water more efficiently and less expensively than other systems.

Solar-Assisted System In northern climates where the heating load is the driving design factor, supplementing the system with solar heat can reduce the required size of a closed-loop ground-coupling system. Solar panels, designed to heat water, can be installed into the ground-coupled loop (by means of a heat exchanger or directly), as illustrated in Figure 28.6. The panels provide additional heat to the heat transfer fluid. This type of variation can reduce the

28.4.6 System Design and Installation More is becoming known about the design and installation of ground-source heat pumps. Design-day cooling and heating loads are determined through traditional design practices such as those documented by the American Society of Heating, Refrigerating, and Air-Conditioning Engineers (ASHRAE). Systems are also zoned using commonly accepted design practices. The key issue that makes ground-source heat pumps unique is the design of the ground-coupling system. Most operational problems with ground-source heat pumps

Figure 28.5. Cooling-tower-supplemented system for cooling-dominated loads

Figure 28.6. Solar-assisted system for heating-dominated loads

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stem from the performance of the ground-coupling system. Today, software tools are available to support the design of the ground-coupling systems that meet the needs of designers and installers. These tools are available from several sources, including the International Ground-Source Heat Pump Association (IGSHPA). In addition, several manufacturers have designed their own proprietary tools more closely tuned to their particular system requirements. Ground loops can be placed just about anywhere— under landscaping, parking lots, or ponds. Selection of a particular ground-coupling system (vertical, horizontal, spiral, etc.) should be based on life-cycle cost of the entire system, in addition to practical constraints. Horizontal closed-loop ground-coupling systems can be installed using a chain-type trenching machine, horizontal boring machine, backhoe, bulldozer, or other earth-moving heavy equipment. Vertical applications (for both open and closed systems) require a drilling rig and qualified operators. Most applications of ground-source heat pumps to large facilities use vertical closed-loop groundcoupling systems primarily because of land constraints. Submerged-loop applications require some special considerations and, as noted earlier, it is best to discuss these directly with an experienced design engineer. It is important to assign overall responsibility for the entire ground-source heat pump system to a single individual or contractor. Installation of the system, however, will involve several trades and contractors, many of whom may not have worked together in previous efforts. In addition to refrigeration/air-conditioning and sheet metal contractors, installation involves plumbers, and (in the case of vertical systems) well drillers. Designating a singular responsible party and coordinating activities will significantly reduce the potential for problems with installation, startup, and proper operation. In heating-dominated climates, a mixture of antifreeze and water must be used in the ground-coupling loops if loop temperatures are expected to fall below about 41ºF (5ºC). A study by Heinonen (1997) establishes the important considerations for antifreeze solutions for ground-source heat pump systems and provides guidance on selection. One note of caution to the designer: some regulations, installation manuals, and/or local practices call for partial or full grouting of the borehole. The thermal conductivity of materials normally used for grouting is very low compared with the thermal conductivity of most native soil formations. Thus, grouting tends to act as insulation and hinders heat transfer to the ground. Some experimental work by Spilker (1998) has confirmed the negative impact of grout on borehole heat transfer. Under

ENERGY MANAGEMENT HANDBOOK

heat rejection loading, average water temperature was nearly 11°F (6ºC) higher for a 6.5-in. (16.5-cm) diameter borehole backfilled with standard bentonite grout than for a 4.75-in. (12.1-cm) diameter borehole backfilled with thermally enhanced bentonite grout. Using fine sand as backfill in a 6.5-in. (16.5-cm) diameter borehole lowered the average water temperature over 14°F (8ºC) compared with the same-diameter bore backfilled with standard bentonite grout. For a typical system (Spilker 1998) with a 6.5-in. (16.5-cm) diameter borehole, the use of standard bentonite grout would increase the required bore length by 49% over fine sand backfill in the same borehole. By using thermally enhanced grout in a smaller 4.75-in. (12.1-cm) borehole, the bore length is increased by only 10% over fine sand backfill in the larger 6.5-in. (16.5-cm) diameter borehole. Thus, the results of this study (Spilker 1998) suggest three steps that may be taken to reduce the impact of grout on vertical borehole system performance: •

Reduce the amount of grout used to the bare minimum. Sand or cuttings may be used where allowed, but take care to ensure that the entire interstitial space between the piping and the borehole diameter is filled.

•

Use thermally enhanced grout wherever possible. For information on thermally enhanced grout consult ASHRAE (1997) and Spilker (1998).

•

Reduce the borehole diameter as much as possible to mitigate the effects of the grout or backfill used. The regulatory requirements for vertical boreholes used for ground-coupling heat exchangers vary widely by state. Current state and federal regulations, as well as related building codes, are summarized at the Geothermal Heat Pump Consortium web site (www.geoexchange.org/publications/regs.htm).

28.4.7 Summary of Ground-Loop Design Software Because of the diversity in loads in multi-zone buildings, the design of the ground-coupling heat exchanger (the ground loop) must be based on peak block load rather than the installed capacity. This is of paramount importance because ground coupling is usually a major portion of the total ground-source heat pump system cost, and over-sizing will render a project economically unattractive. In the residential sector, many systems have been designed using rules-of-thumb and local experience, but for commercial-scale systems such practices are ill advised. For all but the most northern climates, commercial-scale

GROUND-SOURCE HEAT PUMPS APPIED TO COMMERCIAL BUILDINGS

buildings will have significantly more heat rejection than extraction. This imbalance in heat rejection/extraction can cause heat buildup in the ground to the point where heat pump performance is adversely affected and hence system efficiency and possibly occupant comfort suffer. (This is an important consideration in producintg accurate life-cycle cost estimates of energy use.) Proper design for commercial-scale systems almost always benefits from the use of design software. Software for commercial-scale ground-source heat pump system design should consider the interaction of adjacent loops and predict the potential for long-term heat buildup in the soil. Some sources of PC-based design software packages that address this need are: •

•

•

GchpCalc, Version 3.1, Energy Information Services, Tel: (205) 799-4591. This program includes built-in tables for heat pump equipment from most manufacturers. Input is in the form of heat loss/gain during a design day and the approximate equivalent full-load heating hours and equivalent full-load cooling hours. Primary output from the program is the ground loop length required. This program will also calculate the optimal size for a supplemental fluid cooler for hybrid systems, as discussed later. GLHEPRO, International Ground Source Heat Pump Association (IGSHPA), Tel: (800) 626-4747. Input required is monthly heating/cooling loads on heat pumps and monthly peak loads either entered directly by user or read from BLAST or Trane System Analyzer and Trane Trace output files. Output includes long-term soil temperature effect from rejection/extraction imbalance. The current configuration of the program has some constraints on selection of borehole spacing, depth, and overall layout that will be removed from a future version now being prepared. GS2000, Version 2.0, Caneta Research Inc., Tel: (905) 542-2890, email: [email protected]. Heating/cooling loads are input as monthly totals on heat pumps or, alternatively, monthly loads on the ground loop may be input. Equipment performance is input at ARI/ISO rating conditions. For operating conditions other than the rating conditions, the equipment performance is adjusted based on generic heat pump performance relationships.

Each of these programs requires input about the soil thermal properties, borehole resistance, type of piping and borehole arrangement, fluid to be used, and other

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design parameters. Many of the required inputs will be available from tables of default values. The designer should be careful to ensure that the values chosen are representative of the actual conditions to be encountered to ensure efficient and cost-effective designs. Test borings and in situ thermal conductivity analysis to determine the type of soil formations and aquifer locations will substantially improve design accuracy and may help reduce costs. Even with the information from test borings, some uncertainty will remain with respect to the soil thermal properties. These programs make it possible to vary design parameters easily within the range of anticipated values and determine the sensitivity of the design to a particular parameter (OTL 1999). In some instances, particularly very large projects, it may be advisable to obtain specific information on ground-loop performance by thermal testing of a sample borehole (Shonder and Beck 2000).

28.5 APPLICATION This section addresses technical aspects of applying ground-source heat pumps. The range of applications and climates in which the technology has been installed are discussed. The advantages, limitations, and benefits are enumerated. Design and integration considerations for ground-source heat pumps are highlighted, including energy savings estimates, equipment warranties, relevant codes and standards, equipment and installation costs, and utility incentives. 28.5.1 Application Screening A ground-source heat pump system is one of the most efficient technologies available for heating and cooling. It can be applied in virtually any climate or building category. Although local site conditions may dictate the type of ground-coupling system employed, the high first cost and its impact on the overall life-cycle cost are typically the constraining factors. The operating efficiency of ground-source heat pumps is very dependent on the entering water temperature, which, in turn, depends on ground temperature, system load, and size of ground loop. As with any HVAC system, the system load is a function of the facility, internal activities, and the local weather. Furthermore, with ground-source heat pumps, the load on the ground-coupling system may impact the underground temperature. Therefore, energy consumption will be closely tied to the relationship between the annual load distribution and the annual ground loop-temperature distribution (e.g., their joint frequency distribution).

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There are several techniques to estimate the annual energy consumption of ground-source heat pump systems. The most accurate methodologies use computer simulation, and several software systems now support the analysis of ground-source heat pumps. These methods, while more accurate than hand techniques, are also difficult and expensive to employ and are therefore more appropriate when additional detail is required rather than as an initial screening tool. The bin method is another analytical tool for screening technology applications. In general, a bin method is a simple computational procedure that is readily adaptable to a spreadsheet-type analysis and can be used to estimate the energy consumption of a given application and climate. Bin methods rely on load and ambient wet and dry bulb temperature distributions. This methodology is used in the case study presented later in this chapter. 28.5.2 Where to Apply Ground-Source Heat Pumps Ground-source heat pumps are generally applied to air-conditioning and heating systems, but may also be used in any refrigeration application. The decision whether to use a ground-source heat pump system is driven primarily by economics. Almost any HVAC system can be designed using a ground-source heat pump. The primary technical limitation is a suitable location for the ground-coupling system. The following list identifies some of the best applications of ground-source heat pumps. •

Ground-source heat pumps are probably least costprohibitive in new construction; the technology is relatively easy to incorporate.

•

Ground-source heat pumps can also be cost effective to replace an existing system at the end of its useful life, or as a retrofit, particularly if existing ductwork can be reused with minimal modification.

•

In climates with either cold winters or hot summers, ground-source heat pumps can operate much more efficiently than air-source heat pumps or other airconditioning systems. Ground-source heat pumps are also considerably more efficient than other electric heating systems and, depending on the heating fuel cost, may be less expensive to operate than other heating systems.

•

In climates with by high daily temperature swings, ground-source heat pumps show superior efficiency. In addition, in climates characterized by large daily temperature swings, the ground-coupling system also offers some thermal storage capability, which

may benefit the operational coefficient of performance. •

In areas where natural gas is not available or where the cost of natural gas or other fuel is high compared with electricity, ground-source heat pumps are economical. They operate with a heating coefficient of performance in the range of 3.0 to 4.5, compared with conventional heating efficiencies in the range of 80% to 97%. Therefore, when the cost of electricity (per Btu) is less than 3.5 times that of conventional heating fuels (per Btu), ground-source heat pumps have lower energy costs.

•

Areas of high natural gas (or fuel oil) costs will favor ground-source heat pumps over conventional gas (or fuel oil) heating systems. High electricity costs will favor ground-source heat pumps over airsource heat pumps.

•

In facilities where multiple temperature control zones or individual load control is beneficial, ground-source heat pumps provide tremendous capability for individual zone temperature control because they are primarily designed using multiple unitary systems.

•

In areas where drilling costs are low, vertical-loop systems may be especially attractive. The initial cost of the ground-source heat pump system is one of the prime barriers to the economics. In locations with a significant ground-source heat pump industry infrastructure (such as Oklahoma, Louisiana, Florida, Texas, and Indiana), installation costs may be lower and the contractors more experienced. This, however, is changing as the market for ground-source heat pumps grows.

28.5.3 What to Avoid The following precautions should be followed when the application of ground-source heat pump technology is considered: •

Avoid threaded plastic pipe connections in the ground loop. Specify thermal fusion welding. Unlike conventional water-source heat pump systems where the water loop temperature ranges from 60° to 90°F (15.6° to 32.2°C), ground-source systems are subject to wider temperature ranges (20° to 110°F [-6.7° to 43.3°C]), and the resulting expansion and contraction may result in leaks at the threaded connection. It is also generally recommended to

GROUND-SOURCE HEAT PUMPS APPIED TO COMMERCIAL BUILDINGS

specify piping and joining methods approved by International Ground-Source Heat Pump Association (IGSHPA). •

•

•

•

Check local water and well regulations. Regulations affecting open-loop systems are common, and local regulations can vary significantly. Some local regulations may require reinjection wells rather than surface drainage. Some states require permits to use even private ponds as a heat source/sink.

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The design of a ground-source heat pump system will generally follow the following sequence: 1. Determine local design conditions, climatic and soil thermal characteristics. 2. Determine local water, well, and grouting requirements. 3. Determine building heating and cooling loads at design conditions.

Have the ground-source heat pump system installed as a complete and balanced assemblage of components, each of which must be properly designed, sized, and installed (Giddings 1988). Also, have the system installed under the responsibility of a single party. If the entire system is installed by three different professionals, none of whom understands or appreciates the other two parts of the system, then the system may not perform satisfactorily.

4. Select the alternative HVAC system components, including the indoor air-distribution system type; size the alternatives as required; and select equipment that will meet the demands calculated in Step 2 (using the preliminary estimate of the entering water temperatures to determine the heat pump’s heating and cooling capacities and efficiencies).

One of the most frequent problems cited is improper sizing of the heat pump or the ground-coupling system. Approved calculation procedures should be used in the sizing process—as is the case with any heating or air-conditioning system regardless of technology. ASHRAE has established one of the most widely known and accepted standards for the determination of design heating and cooling loads. Sizing the ground-coupling system is just as critical. Because of the uncertainty of soil conditions, a site analysis to determine the thermal conductivity and other heat transfer properties of the local soil may be required. This should be the responsibility of the designing contractor because it can significantly affect the final design.

6. Make preliminary selection of a ground-coupling system type.

Avoid inexperienced designers and installers (see above). Check on the previous experience of potential designers and installers. It is also generally recommended to specify IGSHPA certified installers.

28.5.4 Design and Equipment Integration The purpose of this chapter is to familiarize the energy manager and facility engineer with the benefits and liabilities of ground-source heat pumps in their application to commercial buildings. It is beyond the scope of this chapter to fully explain the design requirements of a ground-source heat pump system. It is, however, important that the reader know the basic steps in the design process.

5. Determine the monthly and annual building heating and cooling energy requirements.

7. Determine a preliminary design of the groundcoupling system. 8. Determine the thermal resistance of the groundcoupling system. 9. Determine the required length of the ground-coupling system; recalculate the entering and exiting water temperatures on the basis of system loads and the ground-coupling system design. 10. Redesign the ground-coupling system, as required, to balance the requirements of the system load (heating and cooling) with the effectiveness of the ground-coupling system. Note that designing and sizing the ground-coupling system for one season (such as cooling) will impact its effectiveness and ability to meet system load requirements during the other season (such as heating). 11. Perform life-cycle cost analysis on the system design (or system design alternatives). Although the design procedure for the groundcoupling system is an iterative and sometimes difficult process, several sources are available to simplify the task. First, an experienced designer should be assigned responsibility for the heat pump and ground-coupling system

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designs. Several manufacturers of ground-source heat pump equipment have their own software tools to support the design of large, commercial-type systems. However, for those who typically design systems in-house, there are support tools available. Software programs are available to support the design of ground-source heat pump HVAC systems and the ground-coupling system. Several software tools are available through the IGSHPA, including an Earth-Coupled Analysis Program and a Ground-Loop Heat Exchanger Design Program. In addition, several technical design manuals also are available through IGSHPA, ASHRAE, and equipment manufacturers (refer to earlier section for an introduction to groundloop design software). There are several different approaches for incorporating ground-source heat pumps into the HVAC design. However, most applications in large facilities involve multiple smaller heat pump units ( 1 Refrigerator c.o.p. β ≡ QL/W ≤ βCarnot = TL/(TH – TL), 0 < β < ∞, (QH/QL)Carnot = TH – TL Process efficiencies ηad, turbine = wactual, adiabatic/wisentropic ηad, compressor = wisentropic/wactual, adiabatic ηad, nozzle = K.E.actual, adiabatic/K.E.isentropic

η nozzle = These represent the best possible performance of cyclic energy conversion devices operating between temperature extremes, TH and TL. The thermodynamic efficiency

Va2/2gc Vs2/2gc

ηcooled nozzle = wisentropic rev./wactual —————————————————————————

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The Rankine cycle is probably the most frequently encountered cycle in thermodynamics. It is used in almost all large-scale electric generation plants, regardless of the energy source (gas, coal, oil, or nuclear). Many modern steam-electric power plants operate at supercritical pressures and temperatures during the boiler heat addition process. This leads to the necessity of reheating between high- and lower-pressure turbines to prevent excess moisture in the latter stages of turbine expansion (prevents blade erosion). Feedwater heating is also extensively used to increase the efficiency of the basic Rankine cycle (see Ref. 1 for details). The vapor compression cycle is almost a reversed Rankine cycle. The major difference is that a simple expansion valve is used to reduce the pressure between the condensor and the evaporator rather than being a work-producing device. The reliability of operation of the expansion valve is a valuable trade-off compared to the small amount of work that could be reclaimed. The vapor compression cycle can be used for refrigeration or heating (heat pump). In the energy conservation area, applications of the heat pump are taking on added emphasis. The device is useful for heating from an electrical source (compressor) in situations where direct combustion is not available. Additionally, the device can be used to upgrade the temperature level of waste heat recovered at a lower temperature. Air-standard cycles, useful both for power generation and heating/cooling applications, are the thermodynamic approximations to the processes occurring in the actual devices. In the actual cases, a thermodynamic

cycle is not completed, necessitating the approximations. Air-standard cycles are analyzed by using the following approximations: 1.

Air is the working fluid and behaves as an ideal gas.

2.

Combustion and exhaust processes are replaced by heat exchangers.

Other devices must be analyzed component by component using property data for the working fluids (see Appendix II). Figure I.2 gives a listing of various power systems with their corresponding thermodynamic cycle and other pertinent information. I.2.6 Combustion Processes The combustion process continues to be the most prevalent means of energy conversion. Natural and manufactured gases, coal, liquid fuel/air mixtures, even wood and peat are examples of energy sources requiring combustion. There are two overriding principles of importance in analyzing combustion processes. They are the combustion equation and the first law for the combustion chamber. The combustion equation is simply a mass balance between reactants and products of the chemical reaction combustion process. The first law is the energy balance for the same process using the results of the combustion equation as input. In practice, we can restrict our discussion to hydrocarbon fuels, meaning that the combustion equation (chemical balance) is written as

Table I.6 Characteristics of Some of the Hydrocarbon Families Family

Formula

Structure

Saturated

Paraffin Olefin Diolefin Naphthene Aromatic Benzene Aromatic Naphthalene

CnH2n + 2 CnH2n CnH2n – 2 CnH2n CnH2n – 6 CnH2n – 12

Chain Chain Chain Ring Ring Ring

Yes No No Yes No No H

Molecular structure of some hydrocarbon fuels: H H

H

H

H

H—C —C—C—C—H H

H

H

H

Chain structure, saturated

H

H C

C H—C—C—C—C—H H

H

H

H

H

H

Chain structure, unsaturated

H

C C

H

H H Ring structure, saturated

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ticular application. Table I.6 gives the characteristics of some of the hydrocarbons. Table I.7 shows the volumetric analyses of several gaseous fuels. Once a combustion process is decided upon (i.e., the fuel to be used and the heat transfer/combustion chamber are selected), the relative amount of fuel and air become of prime importance. This is because the air/fuel ratio (AF) controls the temperature of the combustion zone and the energy available to be transferred to a working fluid or converted to work. Stoichiometric air is that quantity of air required such that no oxygen would appear in the products. Excess air occurs when more than enough air is provided to the combustion process. Ideal combustion implies perfect mixing and complete reactions. In this case theoretical air (TA) would yield no free oxygen in the products. Excess air then is actual air less theoretical air. Most industrial combustion processes conform closely to a steady-state, steady-flow case. The first law for an open control volume surrounding the combustion zone can then be written. If we assume that Q and W are zero and that ∆K.E. and ∆P.E. are negligible, then the following equation results:

Σ

H e – H ref =

Σ

H i – H ref + H comb

products

Fig. I.2 Air standard cycles. reactants

CxHy + α(O2 + 3.76N2)→ b CO2 + c CO2 + e H2O + d O2 + 3.76a N2 This equation neglects the minor components of air; that is, air is assumed to be 1 mol of O2 mixed with 3.76 mol of N2. The balance is based on 1 mol of fuel C x H y. The unknowns are determined for each par-

(I.3)

Subscripts i and e refer to inlet and exit conditions, respectively. Href is the enthalpy of each component at some reference temperature. ∆Hcomb represents the heat of combustion for the fuel and, in general, carries a negative value, meaning that heat would have to be transferred out of the system to maintain inlet and exit temperatures at the same level. The adiabatic flame temperature occurs when the

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Table I.7 Volumetric Analyses of Some Typical Gaseous Fuels Various Natural Gases

Constituent

A

B

C

Methane 93.9 Ethane 3.6 Propane 1.2 1.3 Butanes plusa Ethene Benzene Hydrogen Nitrogen Oxygen Carbon monoxide Carbon dioxide

60.1 14.8 13.4 4.2

67.4 16.8 15.8

7.5

D

Producer Gas from Bituminous Coal

Carbureted Water Gas

Coke Oven Gas

3.0

10.2

32.1

14.0 50.9 0.6 27.0 4.5

6.1 2.8 40.5 2.9 0.5 34.0 3.0

3.5 0.5 46.5 8.1 0.8 6.3 2.2

54.3 16. 16.2 7.4

5.8

aThis includes butane and all heavier hydrocarbons. combustion zone is perfectly insulated. The solution of equation I.3 would give the adiabatic flame temperature for any particular case. The maximum adiabatic flame temperature would occur when complete combustion occurs with a minimum of excess O2 appearing in the products. Appendix II gives tabulated values for the important thermophysical properties of substances important in combustion. Gas Analysis. During combustion in heaters and boilers, the information required for control of the burner settings is the amount of excess air in the fuel gas. This percentage can be a direct reflection of the efficiency of combustion. The most accurate technique for determining the volumetric makeup of combustion by-products is the Orsat analyzer. The Orsat analysis depends upon the fact that for hydrocarbon combustion the products may contain CO2, O2, CO, N2, and water vapor. If enough excess air is used to obtain complete combustion, no CO will be present. Further, if the water vapor is removed, only CO2, O2, and N2 remain. The Orsat analyzer operates on the following principles. A sample of fuel gas is first passed over a desiccant to remove the moisture. (The amount of water vapor can be found later from the combustion equation.) Then the sample is exposed in turn to materials that absorb first the CO2, then the O2, and finally the CO (if present). After each absorption the volumetric change is carefully measured in a graduated pipette system. The

remaining gas is assumed to be N2. Of course, it could contain some trace of gases and pollutants. I.2.7 Psychrometry Psychrometry is the science of air/water vapor mixtures. Knowledge of the behavior of such systems is important, both in meteorology and industrial processes, especially heating and air conditioning. The concepts can be applied to other ideal gas/water vapor mixtures. Air and water vapor mixed together at a total pressure of 1 atm is called atmospheric air. Usually, the amount of water vapor in atmospheric air is so minute that the vapor and air can be treated as an ideal gas. The air existing in the mixture is often called dry air, indicating that it is separate from the water vapor coexisting with it. Two terms frequently encountered in psychrometry are relative humidity and humidity ratio. Relative humidity, φ , is defined as the ratio of the water vapor pressure to the saturated vapor pressure at the temperature of the mixture. Figure I.3 shows the relation between points on the T–s diagram that yield the relative humidity. Relative humidity cannot be greater than unity or 100%, as is normally stated. The humidity ratio, ω, on the other hand, is defined as the ratio of the mass of water vapor to the mass of dry air in atmospheric air, ω = mv/ma. This can be shown to be ω = va/vv, and a relationship between ω and φ exists, ω = (va/vg)φ, where vg refers to the specific volume of saturated water vapor at the temperature of the mixture.

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P3

P1

3

T

1 2

s Fig. I.3 Behavior of water in air: φ = P1/P3; T2 = dew point. A convenient way of describing the condition of atmospheric air is to define four temperatures: dry-bulb, wet-bulb, dew-point, and adiabatic saturation temperatures. The dry-bulb temperature is simply that temperature which would be measured by any of several types of ordinary thermometers placed in atmospheric air. The dew-point temperature (point 2 on Figure I.3) is the saturation temperature of the water vapor at its existing partial pressure. In physical terms it is the mixture temperature where water vapor would begin to condense if cooled at constant pressure. If the relative humidity is 100% the dew-point and dry-bulb temperatures are identical. In atmospheric air with relative humidity less than 100%, the water vapor exists at a pressure lower than saturation pressure. Therefore, if the air is placed in contact with liquid water, some of the water would be evaporated into the mixture and the vapor pressure would be increased. If this evaporation were done in an insulated container, the air temperature would decrease, since part of the energy to vaporize the water must come from the sensible energy in the air. If the air is brought to the saturated condition, it is at the adiabatic saturation temperature. A psychrometric chart is a plot of the properties of atmospheric air at a fixed total pressure, usually 14.7 psia. The chart can be used to quickly determine the properties of atmospheric air in terms of two independent properties, for example, dry-bulb temperature and relative humidity. Also, certain types of processes can be described on the chart. Appendix II contains a psychrometric chart for 14.7-psia atmospheric air. Psychrometric charts can also be constructed for pressures other than 14.7 psia.

I.3

HEAT TRANSFER

Heat transfer is the branch of engineering science that deals with the prediction of energy transport caused

by temperature differences. Generally, the field is broken down into three basic categories: conduction, convection, and radiation heat transfer. Conduction is characterized by energy transfer by internal microscopic motion such as lattice vibration and electron movement. Conduction will occur in any region where mass is contained and across which a temperature difference exists. Convection is characterized by motion of a fluid region. In general, the effect of the convective motion is to augment the conductive effect caused by the existing temperature difference. Radiation is an electromagnetic wave transport phenomenon and requires no medium for transport. In fact, radiative transport is generally more effective in a vacuum, since there is attenuation in a medium. I.3.1 Conduction Heat Transfer The basic tenet of conduction is called Fourier’s law,

Q = – kA dT dx The heat flux is dependent upon the area across which energy flows and the temperature gradient at that plane. The coefficient of proportionality is a material property, called thermal conductivity k. This relationship always applies, both for steady and transient cases. If the gradient can be found at any point and time, the heat flux density, Q/A, can be calculated. Conduction Equation. The control volume approach from thermodynamics can be applied to give an energy balance which we call the conduction equation. For brevity we omit the details of this development; see Refs. 2 and 3 for these derivations. The result is

G + K∇ 2T = – ρC ∂T ∂τ

(I.4)

This equation gives the temperature distribution in space and time, G is a heat-generation term, caused by chemical, electrical, or nuclear effects in the control volume. Equation I.4 can be written

ρC ∂T ∇ 2T + G = K k ∂τ The ratio k/ρC is also a material property called thermal diffusivity u. Appendix II gives thermophysical properties of many common engineering materials. For steady, one-dimensional conduction with no heat generation,

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D 2T = 0 dx 2 This will give T = ax + b, a simple linear relationship between temperature and distance. Then the application of Fourier’s law gives

Q = kA T x a simple expression for heat transfer across the ∆x distance. If we apply this concept to insulation for example, we get the concept of the R value. R is just the resistance to conduction heat transfer per inch of insulation thickness (i.e., R = 1/k). Multilayered, One-Dimensional Systems. In practical applications, there are many systems that can be treated as one-dimensional, but they are composed of layers of materials with different conductivities. For example, building walls and pipes with outer insulation fit this category. This leads to the concept of overall heat-transfer coefficient, U. This concept is based on the definition of a convective heat-transfer coefficient,

Q = hA T This is a simplified way of handling convection at a boundary between solid and fluid regions. The heattransfer coefficient h represents the influence of flow conditions, geometry, and thermophysical properties on the heat transfer at a solid-fluid boundary. Further discussion of the concept of the h factor will be presented later. Figure I.4 represents a typical one-dimensional, multilayered application. We define an overall heattransfer coefficient U as

Fig. I.4 Multilayered wall with convection at the inner and outer surfaces. The U factor for a multilayered tube with convection at the inside and outside surfaces can be developed in the same manner as for the plane wall. The result is

U= 1 +Σ h0 j

1 r 0ln r j + 1/r j kj

+

1r 0 h ir i

where ri and ro are inside and outside radii. Caution: The value of U depends upon which radius you choose (i.e., the inner or outer surface). If the inner surface were chosen, we would get

U=

1 r ln r j + 1/r j 1r i i +Σ + 1 hi h 0r 0 kj j

However, there is no difference in heat-transfer rate; that is, Qo = UiAiToverall = UoAoToverall so it is apparent that

Q = UA (Ti – To) We find that the expression for U must be

U=

1 1 + x1 + x2 + x3 + 1 h1 k1 k2 k3 h0

This expression results from the application of the conduction equation across the wall components and the convection equation at the wall boundaries. Then, by noting that in steady state each expression for heat must be equal, we can write the expression for U, which contains both convection and conduction effects. The U factor is extremely useful to engineers and architects in a wide variety of applications.

UiAi = UoAo for cylindrical systems. Finned Surfaces. Many heat-exchange surfaces experience inadequate heat transfer because of low heat-transfer coefficients between the surface and the adjacent fluid. A remedy for this is to add material to the surface. The added material in some cases resembles a fish “fin,” thereby giving rise to the expression “a finned surface.” The performance of fins and arrays of fins is an important item in the analysis of many heat-exchange devices. Figure I.5 shows some possible shapes for fins.

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The analysis of fins is based on a simple energy balance between one-dimensional conduction down the length of the fin and the heat convected from the exposed surface to the surrounding fluid. The basic equation that applies to most fins is d2θ 1dA dθ h 1 dS —— + ———— – ——— θ dx2 A dx dx k A dx

=0

(I.5)

Surface effectiveness K is defined as the actual heat transfer from a finned surface to that which would occur if the surface were isothermal at the base temperature. Taking advantage of fin efficiency, we can write (A – Af)h θ0 + ηfAfθ0 K = —————————— Ahθ0

(I.6)

Equation I.6 reduces to when θ is (T – T∞), the temperature difference between fin and fluid at any point; A is the cross-sectional area of the fin; S is the exposed area; and x is the distance along the fin. Chapman2 gives an excellent discussion of the development of this equation. The application of equation I.5 to the myriad of possible fin shapes could consume a volume in itself. Several shapes are relatively easy to analyze; for example, fins of uniform cross section and annular fins can be treated so that the temperature distribution in the fin and the heat rate from the fin can be written. Of more utility, especially for fin arrays, are the concepts of fin efficiency and fin surface effectiveness (see Holman3). Fin efficiency ηƒ is defined as the ratio of actual heat loss from the fin to the ideal heat loss that would occur if the fin were isothermal at the base temperature. Using this concept, we could write

Q fin = A hfin Tb – TÜ η f ηƒ is the factor that is required for each case. Figure I.6 shows the fin efficiency for several cases.

Af K = 1 —— (1 – ηf) A which is a function only of geometry and single fin efficiency. To get the heat rate from a fin array, we write Qarray = Kh (Tb – T∞) A where A is the total area exposed. Transient Conduction. Heating and cooling problems involve the solution of the time-dependent conduction equation. Most problems of industrial significance occur when a body at a known initial temperature is suddenly exposed to a fluid at a different temperature. The temperature behavior for such unsteady problems can be characterized by two dimensionless quantities, the Biot number, Bi = hL/k, and the Fourier modulus, Fo = ατ/L2. The Biot number is a measure of the effectiveness of conduction within the body. The Fourier modulus is simply a dimensionless time. If Bi is a small, say Bi ≤ 0.1, the body undergoing the temperature change can be assumed to be at a uniform temperature at any time. For this case,

T – Tf = exp – hA τ ρCV Ti – T f

Fig. I.5 Fins of various shapes. (a) Rectangular, (b) Trapezoidal, (c) Arbitrary profile, (d ) Circumferential.

where Tƒ and Ti are the fluid temperature and initial body temperature, respectively. The term (ρCV/hA) takes on the characteristics of a time constant. If Bi ≥ 0.1, the conduction equation must be solved in terms of position and time. Heisler4 solved the equation for infinite slabs, infinite cylinders, and spheres. For convenience he plotted the results so that the temperature at any point within the body and the amount of heat transferred can be quickly found in terms of Bi and Fo. Figures I.7 to I.10 show the Heisler charts for slabs and cylinders. These can be used if h and the properties of the material are constant.

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I.3.2 Convection Heat Transfer Convective heat transfer is considerably more complicated than conduction because motion of the medium is involved. In contrast to conduction, where many geometrical configurations can be solved analytically, there are only limited cases where theory alone will give convective heat-transfer relationships. Consequently, convection is largely what we call a semi-empirical science. That is, actual equations for heat transfer are based strongly on the results of experimentation. Convection Modes. Convection can be split into several subcategories. For example, forced convection refers to the case where the velocity of the fluid is completely independent of the temperature of the fluid. On the other hand, natural (or free) convection occurs when the temperature field actually causes the fluid motion through buoyancy effects. We can further separate convection by geometry into external and internal flows. Internal refers to channel, duct, and pipe flow and external refers to unbounded fluid flow cases. There are other specialized forms of convection, for example the change-of-phase phenomena: boiling, condensation, melting, freezing, and so on. Change-of-phase heat transfer is difficult to predict analytically. Tongs5 gives many of the correlations for boiling and two-phase flow.

Cμ Prandtl number: Pr = —— k ratio of momentum transport to heat-transport characteristics for a fluid: it is important in all convective cases, and is a material property g β(T – T∞)L3 Grashof number: Gr = —————— υ2 serves in natural convection the same role as Re in forced convection: that is, it controls the character of the flow h Stanton number: St = ——— ρ uCp

Dimensional Heat-Transfer Parameters. Because experimentation has been required to develop appropriate correlations for convective heat transfer, the use of generalized dimensionless quantities in these correlations is preferred. In this way, the applicability of experimental data covers a wider range of conditions and fluids. Some of these parameters, which we generally call “numbers,” are given below: Nusselt number: Nu =

hL —— k

where k is the fluid conductivity and L is measured along the appropriate boundary between liquid and solid; the Nu is a nondimensional heat-transfer coefficient. Lu Reynolds number: Re = —— υ defined in Section I.4: it controls the character of the flow

Fig. I.6 (a) Efficiencies of rectangular and triangular fins, (b) Efficiencies of circumferential fins of rectangular profile.

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Fig. I.7 Midplane temperature for an infinite plate of thickness 2L. (From Ref. 4.)

Fig. I.8 Axis temperature for an infinite cylinder of radius ro. (From Ref. 4.)

also a nondimensional heat-transfer coefficient: it is very useful in pipe flow heat transfer. In general, we attempt to correlate data by using relationships between dimensionless numbers: for example, in many convection cases, we could write Nu = Nu(Re, Pr) as a functional relationship. Then it is possible either from analysis, experimentation, or both, to write an equation that can be used for design calculations. These are generally called working formulas.

Forced Convection Past Plane Surfaces. The average heat-transfer coefficient for a plate of length L may be calculated from NuL = 0.664 (ReL)1/2(Pr)1/3 if the flow is laminar (i.e., if ReL ≤ 4,000). For this case the fluid properties should be evaluated at the mean film temperature Tm, which is simply the arithmetic

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Fig. I.9 Temperature as a function of center temperature in an infinite plate of thickness 2L. (From Ref. 4.) average of the fluid and the surface temperature. For turbulent flow, there are several acceptable correlations. Perhaps the most useful includes both laminar leading edge effects and turbulent effects. It is Nu = 0.0036 (Pr)1/3 [(ReL)0.8 – 18.700] where the transition Re is 4,000. Forced Convection Inside Cylindrical Pipes or Tubes. This particular type of convective heat transfer is of special engineering significance. Fluid flows through pipes, tubes, and ducts are very prevalent, both in laminar and turbulent flow situations. For example, most heat exchangers involve the cooling or heating of fluids in tubes. Single pipes and/or tubes are also used to transport hot or cold liquids in industrial processes. Most of the formulas listed here are for the 0.5 ≤ Pr ≤ 100 range. Laminar Flow. For the case where ReD < 2300, Nusselt showed that NuD = 3.66 for long tubes at a constant tube-wall temperature. For forced convection cases (laminar and turbulent) the fluid properties are evaluated at the bulk temperature Tb. This temperature, also called the mixing-cup temperature, is defined by R

uTr dr Tb =

0 R

ur dr 0

Fig. I.10 Temperature as a function of axis temperature in an infinite cylinder of radius ro. (From Ref. 4.) if the properties of the flow are constant. Sieder and Tate developed the following more convenient empirical formula for short tubes:

Nu D = 1.86 Re D

1/3

Pr

1/3

D L

1/3

Ç Çs

0.14

The fluid properties are to be evaluated at Tb except for the quantity μs, which is the dynamic viscosity evaluated at the temperature of the wall. Turbulent Flow. McAdams suggests the empirical relation NuD = 0.023 (PrD)0.8(Pr)n

(I.7)

where n = 0.4 for heating and n = 0.3 for cooling. Equation I.7 applies as long as the difference between the pipe surface temperature and the bulk fluid temperature is not greater than 10°F for liquids or 100°F for gases. For temperature differences greater then the limits specified for equation I.7 or for fluids more viscous than water, the following expression from Sieder and Tate will give better results:

Ç 0.14 NU D = 0.027 Pr D 0.8 Pr 1/3 Ç s Note that the McAdams equation requires only a knowledge of the bulk temperature, whereas the Sieder-Tate expression also requires the wall temperature. Many people prefer equation I.7 for that reason.

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Nusselt found that short tubes could be represented by the expression

Nu D = 0.036 Pe D

0.8

Pr

1/3

Ç Çs

0.14

D L

1/18

For noncircular ducts, the concept of equivalent diameter can be employed, so that all the correlations for circular systems can be used. Forced Convection in Flow Normal to Single Tubes and Banks. This circumstance is encountered frequently, for example air flow over a tube or pipe carrying hot or cold fluid. Correlations of this phenomenon are called semi-empirical and take the form NuD = C(ReD)m. Hilpert, for example, recommends the values given in Table I.8. These values have been in use for many years and are considered accurate. Flows across arrays of tubes (tube banks) may be even more prevalent than single tubes. Care must be exercised in selecting the appropriate expression for the tube bank. For example, a staggered array and an in-line array could have considerably different heat-transfer characteristics. Kays and London6 have documented many of these cases for heat-exchanger applications. For a general estimate of order-of-magnitude heat-transfer coefficients, Colburn’s equation

complicated type of heat transfer. This is caused primarily by the electromagnetic wave nature of thermal radiation. However, in certain applications, primarily high-temperature, radiation is the dominant mode of heat transfer. So it is imperative that a basic understanding of radiative heat transport be available. Heat transfer in boiler and fired-heater enclosures is highly dependent upon the radiative characteristics of the surface and the hot combustion gases. It is known that for a body radiating to its surroundings, the heat rate is

Q = εσA T 4 – Ts4 where ε is the emissivity of the surface, σ is the StefanBoltzmann constant, σ = 0.1713 × 10– 8 Btu/hr ft2 R4. Temperature must be in absolute units, R or K. If ε = 1 for a surface, it is called a “blackbody,” a perfect emitter of thermal energy. Radiative properties of various surfaces are given in Appendix II. In many cases, the heat exchange between bodies when all the radiation emitted by one does not strike the other is of interest. In this case we employ a shape factor Fij to modify the basic transport equation. For two blackbodies we would write •

Q 12 = F12σA T14 – T24

NuD = 0.33 (ReD)0.6 (Pr)1/3 Table I.8 Values of C and m for Hilpert’s Equation

is acceptable. Free Convection Around Plates and Cylinders. In free convection phenomena, the basic relationships take on the functional form Nu = ƒ(Gr, Pr). The Grashof number replaces the Reynolds number as the driving function for flow. In all free convection correlations it is customary to evaluate the fluid properties at the mean film temperature Tm, except for the coefficient of volume expansion β, which is normally evaluated at the temperature of the undisturbed fluid far removed from the surface—namely, Tƒ. Unless otherwise noted, this convention should be used in the application of all relations quoted here. Table I.9 gives the recommended constants and exponents for correlations of natural convection for vertical plates and horizontal cylinders of the form Nu = C Ram. The product Gr Pr is called the Rayleigh number (Ra) and is clearly a dimensionless quantity associated with any specific free convective situation. •

Range of NReD 1-4 4-40 40-4000 4000-40,000 40,000-250,000

C

m

0.891 0.821 0.615 0.175 0.0239

0.330 0.385 0.466 0.618 0.805

Table I.9 Constants and Exponents for Natural Convection Correlations Vertical Platea

Ra

c

Horizontal Cylindersb

m

c

1/4 1/3

0.525 0.129

m

•

I.3.3 Radiation Heat Transfer Radiation heat transfer is the most mathematically

104 < Ra < 109 109 < Ra < 1012

0.59 0.129

aNu and Ra based on vertical height L. bNu and Ra based on diameter D.

1/4 1/3

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ENERGY MANAGEMENT HANDBOOK

for the heat transport from body 1 to body 2. Figures I.11 to I.14 show the shape factors for some commonly encountered cases. Note that the shape factor is a function of geometry only. Gaseous radiation that occurs in luminous combustion zones is difficult to treat theoretically. It is too complex to be treated here and the interested reader is referred to Siegel and Howell7 for a detailed discussion.

In words, this is simply a balance between mass entering and leaving a control volume and the rate of mass storage. The ρ(υ•n) terms are integrated over the control surface, whereas the ρ dV term is dependent upon an integration over the control volume. For a steady flow in a constant-area duct, the continuity equation simplifies to

I.4

That is, the mass flow rate m is constant and is equal to the product of the fluid density ρƒ, the duct cross section Ac, and the average fluid velocity u. If the fluid is compressible and the flow is steady, one gets m ρ f = constant = uΑ c uΑ c 2

FLUID MECHANICS

In industrial processes we deal with materials that can be made to flow in a conduit of some sort. The laws that govern the flow of materials form the science that is called fluid mechanics. The behavior of the flowing fluid controls pressure drop (pumping power), mixing efficiency, and in some cases the efficiency of heat transfer. So it is an integral portion of an energy conservation program. I.4.1 Fluid Dynamics When a fluid is caused to flow, certain governing laws must be used. For example, mass flows in and out of control volumes must always be balanced. In other words, conservation of mass must be satisfied. In its most basic form the continuity equation (conservation of mass) is

ρ υ•n dA + ∂ ÌÌÌ [ ρ dV = 0 ∂t c.s. c.v.

ÌÌ

m = ρ f Α cu = constant

where 1 and 2 refer to different points in a variable area duct. I.4.2 First Law—Fluid Dynamics The first law of thermodynamics can be directly applied to fluid dynamical systems, such as duct flows. If there is no heat transfer or chemical reaction and if the internal energy of the fluid stream remains unchanged, the first law is

p –p Vi2 _ Ve2 z i – z e + g g + i ρ e + wp – w f = 0 2g c c

Fig. I.11 Radiation shape factor for perpendicular rectangles with a common edge.

(I.8)

THERMAL SCIENCES REVIEW

Fig. I.12 Radiation shape factor for parallel, concentric disks.

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Fig. I.14 Radiation shape factor for parallel, directly opposed rectangles.

Fig. I.15 The first law applied to adiabatic flow system. In the English system, horsepower is

mw p 1 hp – sec ft • lb f lb m = × hp = m sec wp = 550 500 ft – lb lb m

Fig. I.13 Radiation shape factor for concentric cylinders of finite length. where the subscripts i and e refer to inlet and exit conditions and wp and wƒare pump work and work required to overcome friction in the duct. Figure I.15 shows schematically a system illustrating this equation. Any term in equation I.8 can be converted to a rate expression by simply multiplying by , the mass flow rate. Take, for example, the pump horsepower,

W

energy energy = mwp mass mass time time

Referring back to equation I.8, the most difficult term to determine is usually the frictional work term wƒ. This is a term that depends upon the fluid viscosity, the flow conditions, and the duct geometry. For simplicity, wƒ is generally represented as pf wf = —— ρ when ∆pƒ is the frictional pressure drop in the duct. Further, we say that

p f 2 f u 2L ρ = gD c in a duct of length L and diameter D. The friction factor ƒ is a convenient way to represent the differing influence of laminar and turbulent flows on the friction pressure drop.

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The character of the flow is determined through the Reynolds number, Re = ρuD/μ, where μ is the viscosity of the fluid. This nondimensional grouping represents the ratio of dynamic to viscous forces acting on the fluid. Experiments have shown that if Re ≤ 2300, the flow is laminar. For larger Re the flow is turbulent. Figure I.16 shows how the friction factor depends upon the Re of the flow. Note that for laminar flow the ƒ vs. Re curve is single-valued and is simply equal to 16/Re. In the turbulent regime, the wall roughness e can affect the friction factor because of its effect on the velocity profile near the duct surface. If a duct is not circular, the equivalent diameter De can be used so that all the relationships developed for circular systems can still be used. De is defined as 4Ac De = —— P P is the “wetted” perimeter, that part of the flow cross section that touches the duct surfaces. For a circular system De = 4(πD2/4πD) = D, as it should. For an annular duct, we get

De =

ÉD 2o ⁄ 4 – ÉD 2i ⁄ 4 4 É D o + D i D o + D i = ÉD o + ÉD i ÉD o + ÉD i

= Do + Di

Fig. I.16 Friction factors for straight pipes.

where ƒ is the friction factor for the tubes (a function of the Re), N the number of tube rows crossed by the flow, and Fd is the “depth factor.” Figures I.17 and I.18 show the ƒ factor and Fd relationship that can be used in pressure-drop calculations. If the fluid is air, the pressure drop can be calculated by the equation

G T p = N 30 B 1.73 × 10 5 10 3

2

where B is the atmospheric pressure (in. Hg), T is temperature (°R), and G is the mass velocity (lbm/ft2 hr). Bernoulli’s Equation. There are some cases where the equation

Pressure Drop in Ducts. In practical applications, the essential need is to predict pressure drops in piping and duct networks. The friction factor approach is adequate for straight runs of constant area ducts. But valves nozzles, elbows, and many other types of fittings are necessarily included in a network. This can be accounted for by defining an equivalent length Le for the fitting. Table I.10 shows Le/D values for many different fittings. Pressure Drop across Tube Banks. Another commonly encountered application of fluid dynamics is the pressure drop caused by transverse flow across arrays of heat-transfer tubes. One technique to calculate this effect is to find the velocity head loss through the tube bank: Nv = ƒNFd

p u2 — + — + gz = constant ρ 2 which is called Bernoulli’s equation, is useful. Strictly speaking, this equation applies for inviscid, incompressible, steady flow along a streamline. However, even in pipe flow where the flow is viscous, the equation can be applied because of the confined nature of the flow. That is, the flow is forced to behave in a streamlined manner. Note that the first law equation (I.8) yields Bernoulli’s equation if the friction drop exactly equals the pump work. I.4.3 Fluid-Handling Equipment For industrial processes, another prime application of fluid dynamics lies in fluid-handling equipment.

THERMAL SCIENCES REVIEW

Table I.10 Le/D for Screwed Fittings, Turbulent Flow Onlya ————————————————————————— Fitting Le/D ————————————————————————— 45° elbow 15 90° elbow, standard radius 31 90° elbow, medium radius 26 90° elbow, long sweep 20 90° square elbow 65 180° close return bend 75 Swing check valve, open 77 Tee (as el, entering run) 65 Tee (as el, entering branch) 90 Couplings, unions Negligible Gate valve, open 7 Gate valve, 1/4 closed 40 Gate valve, 1/2 closed 190 Gate valve, 3/4 closed 840 Globe valve, open 340 Angle valve, open 170 —————————————————————————

833

Fig. I.17 Depth factor for number of tube rows crossed in convection banks.

aCalculated from Crane Co. Tech. Paper 409, May 1942.

Pumps, compressors, fans, and blowers are extensively used to move gases and liquids through the process network and over heat-exchanger surfaces. The general constraint in equipment selection is a matching of fluid handler capacity to pressure drop in the circuit connected to the fluid handler. Pumps are used to transport liquids, whereas compressors, fans, and blowers apply to gases. There are features of performance common to all of them. For purposes of illustration, a centrifugal pump will be used to discuss performance characteristics. Centrifugal Machines. Centrifugal machines operate on the principle of centrifugal acceleration of a fluid element in a rotating impeller/housing system to achieve a pressure gain and circulation. The characteristics that are important are flow rate (capacity), head, efficiency, and durability. Qƒ (capacity), hp (head), and ηp (efficiency) are related quantities, dependent basically on the fluid behavior in the pump and the flow circuit. Durability is related to the wear, corrosion, and other factors that bear on a pump’s reliability and lifetime. Figure I.19 shows the relation between flow rate and related characteristics for a centrifugal pump at constant speed. Graphs of this type are called performance curves; fhp and bhp are fluid and brake horsepower, respectively. The primary design constraint is a matching

Fig. I.18 Friction factor ƒ as affected by Reynolds number for various in-line tube patterns, crossflow gas or air, do, tube diameter; l⊥, gap distance perpendicular to the flow; l||, gap distance parallel to the flow.

834

ENERGY MANAGEMENT HANDBOOK

of flow rate to head. Note that as the flow-rate requirement is increased, the allowable head must be reduced if other pump parameters are unchanged. Analysis and experience has shown that there are scaling laws for centrifugal pump performance that give the trends for a change in certain performance parameters. Basically, they are: Efficiency:

η p = ƒ1

Qf D 3n

Dimensionless head:

h pg D 2n 2

Qf = f2 3 D n

Fig. I.19 Performance curve for a centrifugal pump.

Dimensionless brake horsepower:

bhp • g γD 2n 3

Qf = f3 3 D n

where D is the impeller diameter, n is the rotary impeller speed, g is gravity, and γ is the specific weight of fluid. The basic relationships yield specific proportionali1 ties such as Qƒ ∝ n (rpm), hp ∝ n2, fhp ∝ n3, Q f ∝ 2 , D h p ∝ 14 , and fhp ∝ 14 . D D For pumps, density variations are generally negligible since liquids are incompressible. But for gas-handling equipment, density changes are very important. The scaling laws will give the following rules for changing density: hp∝ ρ fhp∝ ρ

n fhp Qf n Qf hp

(Qf, n constant)

∝ ρ – 1/2

! (hp constant

1 ∝ρ (m constant)

1 fhp ∝ —— ρ2 For centrifugal pumps, the following equations hold:

Qf ρghp fhp = ———— 550gc Qfρghp550gc ηpp = —————— bhp

fhp = —— bhp

system efficiency ηs = ηp × ηm

(motor efficiency)

It is important to select the motor and pump so that at nominal operating conditions, the pump and motor operate at near their maximum efficiency. For systems where two or more pumps are present, the following rules are helpful. To analyze pumps in parallel, add capacities at the same head. For pumps in series, simply add heads at the same capacity. There is one notable difference between blowers and pump performance. This is shown in Figure I.20. Note that the bhp continues to increase as permissible head goes to zero, in contrast to the pump curve when bhp approaches zero. This is because the kinetic energy imparted to the fluid at high flow rates is quite significant for blowers. Manufactures of fluid-handling equipment provide excellent performance data for all types of equipment. Anyone considering replacement or a new installation should take full advantage of these data. Fluid-handling equipment that operates on a principle other than centrifugal does not follow the centrifugal scaling laws. Evans8 gives a thorough treatment of most types of equipment that would be encountered in industrial application.

THERMAL SCIENCES REVIEW

Fig. I.20 Variation of head and bhp with flow rate for a typical blower at constant speed.

835

K.E. lbf lbm lb mol m m M n n P Pi P.E. Pr q, Q

Q QH, QL References 1. G.J. Van Wylen and R.E. Sonntag, Fundamentals of Classical Thermodynamics, 2nd ed., Wiley, New York, 1973. 2. A.S. Chapman, Heat Transfer, 3rd ed., Macmillan, New York, 1974. 3. J.P. Holman, Heat Transfer, 4th ed., McGraw-Hill, New York, 1976. 4. M.P. Heisler, Trans. ASME, Vol. 69 (1947), p. 227. 5. L.S. Tong, Boiling Heat Transfer and Two-Phase Flow, Wiley, New York, 1965. 6. W.M. Kays and A.L. London, Compact Heat Exchangers, 2nd ed., McGraw-Hill, New York, 1963. 7. R. Siegel and J.R. Howell, Thermal Radiation Heat Transfer, McGraw-Hill, New York, 1972. 8. FRANK L. Evans, JR., Equipment Design Handbook for Refineries and Chemical Plants, Vols. 1 and 2, Gulf Publishing, Houston, Tex., 1974.

SYMBOLS Thermodynamics AF air/fuel ratio Cp constant-pressure specific heat Cv constant-volume specific heat Cp0 zero-pressure constant-pressure specific heat Cv0 zero-pressure constant-volume specufic heat e, E specific energy and total energy g acceleration due to gravity g, G specific Gibbs function and total Gibbs function ge a constant that relates force, mass, length, and time h, H specific enthalpy and total enthalpy k specific heat ratio: Cp/Cv

R R s, S t T u, U v, V V Vr w, W W wrev x Z Z

kinetic energy pound force pound mass pound mole mass mass rate of flow molecular weight number of moles polytropic exponent pressure partial pressure of component i in a mixture potential energy relative pressure as used in gas tables heat transfer per unit mass and total heat transfer rate of heat transfer heat transfer from high- and low-temperature bodies gas constant universal gas constant specific entropy and total entropy time temperature specific internal energy and total internal energy specific volume and total volume velocity relative velocity work per unit mass and total work rate of work, or power reversible work between two states assuming heat transfer with surroundings mass fraction elevation compressibility factor

Greek Letters β coefficient of performance for a refrigerator β' coefficient of performance for a heat pump η efficiency ρ density φ relative humidity ω humidity ratio or specific humidity Subscripts c property at the critical point c.v. control volume e state of a substance leaving a control volume ƒ formation ƒ property of saturated liquid ƒg difference in property for saturated vapor

836

g r s

ENERGY MANAGEMENT HANDBOOK

and saturated liquid property of saturated vapor reduced property isentropic process

Superscripts bar over symbol denotes property on a molal basis (over V, H, S, U, A, G, the bar denotes partial molal property) ° property at standard-state condition * ideal gas L liquid phase S solid phase V vapor phase Heat Transfer—Fluid Flow A surface area Am profile area for a fin Bi Biot number, (hL/k) cp specific heat at constant pressure c specific heat D diameter De hydraulic diameter Fi-j shape factor of area i with respect to area j ƒ friction factor 3 2 Gr Grashof number, g βÄTL c/υ g acceleration due to gravity gc gravitational constant h convective heat-transfer coefficient k thermal conductivity m mass m mass rate of flow N number of rows Nu Nusselt number, hL/k Pr Prandtl number, μCp/k p pressure Q volumetric flow rate Q rate of heat flow 3 Ra Rayleigh number, g βÄTL c/υ ∝

Re r St T U u ux V V W

Reynolds number, ρuav Lc/μ radius Stanton number, h/Cp ρu∝ temperature overall heat-transfer coefficient velocity free-stream velocity volume velocity rate of work done

Greek Symbols α thermal diffusivity β coefficient of thermal expansion ∆ difference, change ε surface emissivity ηf fin effectiveness μ viscosity v kinematic viscosity ρ density σ Stefan-Boltzmann constant τ time Subscripts b bulk conditions cr critical condition c convection cond conduction conv convection e entrance, effective ƒ fin, fluid i inlet conditions o exterior condition 0 centerline conditions in a tube at r = 0 o outlet condition p pipe, pump s surface condition ∝ free-stream condition

APPENDIX II

CONVERSION FACTORS AND PROPERTY TABLES Compiled by L.C. WITTE Professor of Mechanical Engineering University of Houston Houston, Texas Table II.1 Conversion Factors To Obtain:

Multiply:

By:

Acres Atmospheres Atmospheres Atmospheres Atmospheres Atmospheres Atmospheres Atmospheres Btu Btu Btu Btu Btu Btu/(cu ft) (hr) Btu/hr Btu/hr Btu/hr Btu/hr Btu/kW hr Btu/(hr) (ft) (deg F) Btu/(hr) (ft) (deg F) Btu/(hr) (ft) (deg F) Btu/(hr) (sq ft) Btu/min Btu/min Btu/min Btu/lb Btu/lb Btu/(lb) (deg F) Btu/(lb) (deg F) Btu/sec Btu/sec Btu/sec Btu/sec Btu/sq ft

Sq miles Cm of Hg @ 0 deg C Ft of H2O @ 39.2 F. Grams/sq cm In. Hg @ 32 F In. H2O @ 39.2 F Pounds/sq ft Pounds/sq in. Ft-lb Hp-hr Kg-cal. kW-hr Watt-hr kW/liter Mech. hp kW Tons of refrigeration Watts Kg cal/kW hr Cal/(sec) (cm) (deg C) Joules/(sec) (cm) (deg C) Watts/(cm) (deg C) Cal/(sec) (sq cm) Ft-lb/min Mech. hp kW Cal/gram Kg cal/kg Cal/(gram) (deg C) Joules/(gram) (deg C) Mech. hp Mech. hp (metric) Kg-cal/hr kW Kg-cal/sq meter

640.0 0.013158 0.029499 0.00096784 0.033421 0.0024583 0.00047254 0.068046 0.0012854 2545.1 3.9685 3413 3.4130 96,650.6 2545.1 3413 12,000 3.4127 3.9685 241.90 57.803 57.803 13,273.0 0.0012854 42.418 56.896 1.8 1.8 1.0 0.23889 0.70696 0.6971 0.0011024 0.94827 0.36867

837

838

ENERGY MANAGEMENT HANDBOOK

Table II.1 Continued To Obtain:

Multiply:

By:

Calories Calories Calories Cal/(cu cm) (sec) Cal/gram Cal/(gram) (deg C) Cal/(sec) (cm) (deg C) Cal/(sec) (sq cm) Cal/(sec) (sq cm) (deg C) Centimeters Centimeters Centimeters Cm of Hg @ 0 deg C Cm of Hg @ 0 deg C Cm of Hg @ 0 deg C Cm of Hg @ 0 deg C Cm of Hg @ 0 deg C Cm of Hg @ 0 deg C Cm/deg C Cm/sec Cm/sec Cm/(sec) (sec) Cm of H2O @39.2 F Cm of H2O @39.2 F Centipoises Centistokes Cu cm Cu cm Cu cm Cu cm Cu cm Cu cm Cu cm/sec Cu ft Cu ft Cu ft Cu ft Cu ft Cu ft/min Cu ft/min Cu ft/lb Cu ft/lb Cu ft/sec Cu ft/sec Cu ft/sec Cu in. Cu in. Cu in. Cu in.

Ft-lb Joules Watt-hr kW/liter Btu/lb Btu/(lb) (deg F) Btu/(hr) (ft) (deg F) Btu/(hr) (sq ft) Btu/(hr) (sq ft) (deg F) Inches Microns Mils Atmospheres Ft of H2O @ 39.2 F Grams/sq cm In. of H2O @ 4 C Lb/sq in. Lb/sq ft In./deg F Ft/min Ft/sec Gravity Atmospheres Lb/sq in. Centistokes Centipoises Cu ft Cu in. Gal. (USA, liq.) Liters Ounces (USA, liq.) Quarts (USA, liq.) Cu ft/min Cords (wood) Cu meters Cu yards Gal. (USA, liq.) Liters Cu meters/sec Gal. (USA, liq./sec) Cu meters/kg Liters/kg Cu meters/min Gal. (USA, liq.)/min Liters/min Cu centimeters Gal. (USA, liq.) Liters Ounces (USA. liq.)

0.32389 0.23889 860.01 0.23888 0.55556 1.0 0.0041336 0.000075341 0.0001355 2.540 0.0001 0.002540 76.0 2.242 0.07356 0.1868 5.1715 0.035913 4.5720 0.508 30.48 980.665 1033.24 70.31 Density l/density 28,317 16.387 3785.43 1000 03 29.573730 946.358 472.0 128.0 35.314 27.0 0.13368 0.03532 2118.9 8.0192 16.02 0.01602 0.5886 0.0022280 0.0005886 0.061023 231.0 61.03 1.805

CONVERSION FACTORS AND PROPERTY TABLES

839

Table II.1 Continued To Obtain:

Multiply:

By:

Cu meters Cu meters Cu meters Cu meters Cu meters/hr Cu meters/kg Cu meters/min Cu meters/min Cu meters/sec Cu yards Dynes Dynes Dyne-centimeters Dynes/sq cm Ergs Feet Ft of H2O @ 39.2 F Ft of H2O @ 39.2 F Ft of H2O @ 39.2 F Ft of H2O @ 39.2 F Ft of H2O @ 39.2 F Ft/min Ft/min Ft/sec Ft/sec Ft/sec Ft/(sec) (sec) Ft/(sec) (sec) Ft-lb Ft-lb Ft-lb Ft-lb Ft-lb Ft-lb/min Ft-lb/min Ft-lb/min Ft-lb/min Ft-lb/sec Ft-lb/sec Ft-lb/sec Gal. (Imperial, liq.) Gal. (USA, liq.) Gal. (USA. liq.) Gal. (USA. liq.) Gal. (USA, liq.) Gal. (USA. liq.) Gal. (USA. liq.) Gal. (USA. liq.)/min Gal. (USA, liq.)/min

Cu ft Cu yards Gal. (USA. liq.) Liters Gal./min Cu ft/lb Cu ft/min Gal./sec Gal./min Cu meters Grams Pounds (avoir.) Ft-lb Lb/sq in. Joules Meters Atmospheres Cm of Hg @ 0 deg C In. of Hg @ 32 deg F Lb/sq ft Lb/sq in. Cm/sec Miles (USA. statute)/hr Knots Meters/sec Miles (USA, statute)/hr Gravity (sea level) Meters/(sec) (sec) Btu Joules Kg-calories kW-hr Mech. hp-hr Btu/min Kg cal/min kW Mech. hp Btu/min kW Mech. hp Gal. (USA. Liq.) Barrels (petroleum, USA) Cu ft Cu meters Cu yards Gal. (Imperial, liq.) Liters Cu ft/sec Cu meters/hr

0.028317 0.7646 0.0037854 0.001000028 0.22712 0.062428 0.02832 0.22712 0.000063088 1.3079 980.66 444820.0 13 ,558,000 68947 10,000,000 3.281 33.899 0.44604 1.1330 0.016018 2.3066 1.9685 88.0 1.6889 3.2808 1.4667 32.174 3.2808 778.0 0.73756 3087.4 2,655,200 1,980,000 778.0 3087.4 44,254.0 33,000 12.96 737.56 550.0 0.83268 42 7.4805 264.173 202.2 1.2010 0.2642 448.83 4.4029

840

ENERGY MANAGEMENT HANDBOOK

Table II.1 Continued To Obtain:

Multiply:

By:

Gal. (USA. liq.)/sec Gal. (USA. liq.)/sec Grains Grains Grains Grains/gal. (USA. liq.) Grams Grams Grams Grams/cm Grams/(cm) (sec) Grams/cu cm Grams/cu cm Grams/cu cm Gravity (at sea level) Inches Inches Inches of Hg @ 32 F Inches of Hg @ 32 F Inches of Hg @ 32 F Inches of Hg @ 32 F Inches of H2O@ 4 C Inches of H2O @ 39.2 F Inches/deg F Joules Joules Joules Joules Joules Joules Kg Kg-cal Kg-cal Kg-cal Kg-cal Kg-cal Kg-cal/kg Kg-cal/kW hr Kg-cal/min Kg-cal/min Kg-cal/min Kg-cal/sq meter Kg/cu meter Kg/(hr) (meter) Kg/liter Kg/meter Kg/sq cm Kg sq cm Kg/sq meter

Cu ft/min Liters/min Grams Ounces (avoir.) Pounds (avoir.) Parts/million Grains Ounces (avoir.) Pounds (avoir.) Pounds/in. Centipoises Lb/cu ft Lb/cu in. Lb/gal. Ft/(sec) (sec) Centimeters Microns Atmospheres Ft of H2O @ 39.2 F Lb/sq in. In. of H2O @ 4 C In. of Hg @ 32 F Lb/sq in. Cm/deg C Btu Calories Ft-lb Kg-meters kW-hr Mech. hp-hr Pounds (avoir.) Btu Ft-lb Joules kW-hr Mech. hp-hr Btu/lb Btu/kW hr Ft-lb/min kW Mech. hp Btu/sq ft Lb/cu ft Centipoises Lb/gal. (USA, liq.) Lbm Atmospheres Lb/sq in . Lb/sq ft

0.12468 0.0044028 15.432 437.5 7000 0.0584 0.0648 28.350 453.5924 178.579 0.01 0 .016018 27.680 0.119826 0.03108 0.3937 0.00003937 29.921 0.88265 2.0360 0.07355 13.60 27.673 0.21872 1054.8 4.186 1.35582 9.807 3,600,000 2,684,500 0.45359 0.2520 0.00032389 0.0002389 860.01 641.3 0.5556 0.2520 0.0003239 14,33 10.70 2.712 16.018 3.60 0.11983 1.488 1.0332 0.0703 4.8824

CONVERSION FACTORS AND PROPERTY TABLES

841

Table II.1 Continued To Obtain:

Multiply:

By:

Kg/sq meter Km kW kW kW kW kW kW kW-hr kW-hr kW-hr kW-hr Knots Knots Liters Liters Liters Liters Liters Liters/kg Liters/min Liters/min Liters/sec Liters/sec Mech. hp Mech. hp Mech. hp Mech. hp Mech. hp Mech. hp-hr Mech. hp-hr Mech. hp-hr Mech. hp-hr Meters Meters Meters Meters Meters/min Meters/min Meters/sec Meters/sec Meters/sec Meters/sec Meters/(sec) (sec) Microns Microns Miles (Int., nautical) Miles (Int., nautical) Miles (Int., nautical)/hr

Lb/sq in. Miles (USA, statute) Btu/min Ft-lb/min Ft-lb/sec Kg-cal/hr Kg-cal/min Mech. hp Btu Ft-lb Kg-cal Mech. hp-hr Ft/sec Miles/hr Cu ft Cu in. Cu centimeters Gal. (Imperial. liq.) Gal. (USA, liq.) Cu ft/lb Cu ft/sec Gal. (USA. liq.)/min Cu ft/min Gal./min Btu/hr Btu/min Ft-lb/sec Kg-cal/min kW Btu Ft-lb Kg-calories kW-hr Feet Inches Miles (Int., nautical) Miles (USA, statute) Ft/min Miles (USA. statute)/hr Ft/sec Km/hr Knots Miles (USA, statute)/hr Ft/(sec) (sec) Inches Mils Km Miles (USA, statute) Knots

703.07 1.6093 0.01758 0.00002259 0.00135582 0.0011628 0.069767 0.7457 0.000293 0.0000003766 0.0011628 0.7457 0.5921 0.8684 28 . 316 0.01639 999.973 4.546 3.78533 62.42621 1699.3 3.785 0.47193 0.063088 0.0003929 0.023575 0.0018182 0.093557 1.3410 0.00039292 0.00000050505 0.0015593 1.3410 0.3048 0.0254 1852.0 1609.344 0.3048 26.82 0.3048 0.2778 0.5148 0.44704 0.3048 25,400 25.4 0.54 0.8690 1.0

842

ENERGY MANAGEMENT HANDBOOK

Table II.1 Continued To Obtain:

Multiply:

By:

Miles (USA, statute) Miles (USA, statute) Miles (USA, statute) Miles (USA, statute)/hr Miles (USA, statute)/hr Miles (USA, statute)/hr Miles (USA, statute)/hr Miles (USA, statute)/hr Milliliters/gram Millimeters Mils Mils Mils Minutes Ounces (avoir. ) Ounces (avoir.) Ounces (USA, liq.) Parts/million Percent grade Pounds (avoir.) Pounds (avoir.) Pounds (avoir.) Pounds (avoir.) Pounds (avoir.) Pounds (avoir.) Pounds/cu ft Pounds/cu ft Pounds/cu ft Pounds/cu in . Pounds/ft Pounds/hr Pounds/(hr) (ft) Pounds/inch Pounds/(sec) (ft) Pounds/sq inch Pounds/sq inch Pounds/sq inch Pounds/sq inch Pounds/sq inch Pounds/sq inch Pounds/sq inch Pounds/gal. (USA, liq.) Pounds/gal. (USA, liq.) Pounds/gal. (USA, liq.) Quarts (USA, liq.) Quarts (USA, liq.) Quarts (USA, liq.) Sq centimeters Sq centimeters

Km Meters Miles (Int., nautical) Knots Ft/min Ft/sec Meters/min Meters/sec Cu ft/lb Microns Centimeters Inches Microns Radians Grains (avoir. ) Grams Gal. (USA, liq.) Gr/gal. (USA, liq.) Ft/100 ft Grains Grams Kg Tons, long Tons, metric Tons, short Grams/cu cm Kg/cu meter Pounds/gal. Grams/cu cm Kg/meter Kg/min Centipoises Grams/cm Centipoises Atmospheres Cm of Hg @ 0 deg C Ft of H2O @ 39.2 F In. Hg @ l 32 F In. H2O @ 39.2 F Kg/sq cm Kg/sq meter Kg/liter Pounds/cu ft Pounds/cu inch Cu cm Cu in. Liters Sq ft Sq inches

0.6214 0.0006214 1.151 1.151 0.011364 0.68182 0.03728 2.2369 62.42621 0.001 393.7 1000 0.03937 3437.75 0.0022857 0.035274 128.0 17.118 1.0 0.0001429 0.0022046 2.2046 2240 2204.6 2000 62.428 0.062428 7.48 0.036127 0.67197 132.28 2.42 0.0056 0.000672 14.696 0.19337 0.43352 0.491 0.0361 14 . 223 0.0014223 8.3452 0.1337 231 0.0010567 0.01732 1.057 929.0 6.4516

CONVERSION FACTORS AND PROPERTY TABLES

843

Table II.1 Continued To Obtain:

Multiply:

By:

Sq ft Sq ft Sq inches Sq meters Sq meters Sq mlles (USA. statute) Sq mils Sq mils Tons (metric ) Tons (short) Watts Yards

Acres Sq meters Sq centimeters Acres Sq ft Acres Sq cm Sq inches Tons (short) Tons (metric) Btu/sec Meters

43,560 10.764 0.155 4046.9 0.0929 0.001562 155.000 1,000.000 0.9072 1.1023 1054.8 1.0936

844

ENERGY MANAGEMENT HANDBOOK

CONVERSION FACTORS AND PROPERTY TABLES

845

846

ENERGY MANAGEMENT HANDBOOK

CONVERSION FACTORS AND PROPERTY TABLES

847

848

Table 11.2-1

ENERGY MANAGEMENT HANDBOOK

Continued

———————————————————————————————————————————————————— Abs. Press. p (psi)

Specific Volume Temp. t (°F)

Sat. Liquid vf

Evap vfx

Enthalpy Sat. Vapor vx

Sat. Liquid hf

Evap hfx

Entropy Sat. Vapor hx

Sat. Liquid sf

Evap sfx

Sat. Vapor sf

Temp. t (°F)

————————————————————————————————————————————————————

CONVERSION FACTORS AND PROPERTY TABLES

849

850

ENERGY MANAGEMENT HANDBOOK

CONVERSION FACTORS AND PROPERTY TABLES

851

852

ENERGY MANAGEMENT HANDBOOK

CONVERSION FACTORS AND PROPERTY TABLES

853

854

ENERGY MANAGEMENT HANDBOOK

CONVERSION FACTORS AND PROPERTY TABLES

855

856

ENERGY MANAGEMENT HANDBOOK

CONVERSION FACTORS AND PROPERTY TABLES

857

Mollier Diagram for Steam Source: Modified and greatly reduced from J.H. Keenan and F.G. Keyes, Thermodynamic Properties of Steam, John Wiley & Sons Inc., New York, 1936; reproduced by permission of the publishers.

858

ENERGY MANAGEMENT HANDBOOK

CONVERSION FACTORS AND PROPERTY TABLES

859

860

ENERGY MANAGEMENT HANDBOOK

CONVERSION FACTORS AND PROPERTY TABLES

861

862

ENERGY MANAGEMENT HANDBOOK

CONVERSION FACTORS AND PROPERTY TABLES

863

864

ENERGY MANAGEMENT HANDBOOK

CONVERSION FACTORS AND PROPERTY TABLES

865

866

ENERGY MANAGEMENT HANDBOOK

CONVERSION FACTORS AND PROPERTY TABLES

867

868

ENERGY MANAGEMENT HANDBOOK

CONVERSION FACTORS AND PROPERTY TABLES

869

870

ENERGY MANAGEMENT HANDBOOK

CONVERSION FACTORS AND PROPERTY TABLES

871

872

ENERGY MANAGEMENT HANDBOOK

CONVERSION FACTORS AND PROPERTY TABLES

873

874

ENERGY MANAGEMENT HANDBOOK

Table II.5-1, Continued —————————————————————————————————————————————————————— Properties at 68°F

k(Btu/hr-ft-.F)

—————————————————————————————————————————————————————— ρ (lbm/ft3)

Metal

CP

α

–148°F

32°F

212°F

392°F

572°F

752°F

1112°F

1472°F 1832°F

(ft2/hr)

–100°C

0°C

100°C

200°C

300°C

400°C

600°C

800°C

216

—

210

204

k

(Btu/lbm•°F) (Btu/hr • ft • °F)

2192°F

1000°C 1200°C

—————————————————————————————————————————————————————— Copper Pure Aluminum bronze: 95 Cu, 5 Al Bronze: 75 Cu. 25 Sn Red brass: 85 Cu. 9 Sn. 6 Zn Brass: 70 Cu. 30 Zn German silver 62 Cu, 15 Ni. 22 Zn Constantan: 60 Cu, 40 Ni Magnesium Pure Mg-Al (electrolytic) 6-8% Al, 1-2% Zn Mg-Mn: 2% Mn Molybdenum Nickel Pure (99.9%) Impure (99.2%) Ni-Cr: 90 Ni. 10 Cr 80 Ni, 20 Cr Silver Purest Pure (99.9%) Tungsten Zinc. Pure Tin. pure

559 541

0.0915 0.098

223 48

4.353 0.903

235

223

219

541 544

0.082 0.092

15 35

0.333 0.699

—

34

41

532

0.092

64

1.322

51

—

74

83

85

85

538

0.094

14.4

0.290

11.1

—

18

23

26

28

557

0.098

13.1

0.237

12

—

12.8

15

109 113

0.242 0.24

99 38

3.762 1.397

103 —

99 30

97 36

94 43

111 638

0.24 0.060

66 79

2.473 2.074

54 80

64 79

72 79

75

556 556 541 519

0.1065 0.106 0.106 0.106

52 40 10 7.3

0.882 0.677 0.172 0.129

60 — — —

54 40 9.9 7.1

48 37 10.9 8.0

42 34 12.1 9.0

37 32 13.2 9.9

34 30 14.2 10.9

657 657

0.0559 0.0559 1208 0.0918 0.0541

242 235 0.0321 64.8 37

6.601 6.418 94 1.591 1.505

242 242 2.430 66 43

241 237 — 65 38.1

240 240 96 63 34

238 216 87 61 33

209 82 58

208 77 54

446 456

91 48

32

36

39

65

44

40

13.0

73.

—————————————————————————————————————————————————————— Source: From E.R.G. Eckert and R.M. Drake, Heat and Mass Transfer-, copyright 1959 McGraw-Hill; used with the permission of McGraw-Hill Book Company.

Table II.5-2 Thermal Properties of Some Nonmetals

—————————————————————————————————————————————————————— Substance

ρ lbm/°F3

CP (Btu/lbm • °F)

t (°F)

α (ft2/hr)

k (Btu/hr • ft2 • °F)

—————————————————————————————————————————————————————— Structural Asphalt Bakelite 0.38 Bricks Common Face

b

79.5

b

68 68

0.43 0.134

a b

0.20

d 128

100 d

d 68

68 0.76

0.40 a

a

1110 2550

10.7 6.4

a a

392 1022 1652

1.34 1.43 1.15

a a a

400 1600

0.14 0.18

a a

Carborundum brick

Chrome brick

0.20

d

188

d

Diatomaceous earth (fired)

0.0044 0.02

0.036 0.038 0.031

0.23

d

128

d

932 1472 2012

0.60 0.62 0.63

a a a

0.020 0.021 0.021

Fire clay brick (burnt 2642 F)

0.23

d

145

d

912 1472 2012

0.74 0.79 0.81

a a a

0.022 0.024 0.024

Fire clay brick (Missouri)

0.23

d

165

f

392 1112 2552

0.58 0.85 1.02

a a a

0.015 0.022 0.027

Magnesite

0.27

d

400 1200 2200

2.2 1.6 1.1

a a a

75 68 75

0.17 0.67 0.47-0.81 0.44

a a b a

Fire clay brick (burnt 2426 F)

Cement, portland Cement, mortar Concrete 0.21 Concrete, cinder

94 b

119-144

b

0.019-0.027

——————————————————————————————————————————————————————

CONVERSION FACTORS AND PROPERTY TABLES

875

876

ENERGY MANAGEMENT HANDBOOK

CONVERSION FACTORS AND PROPERTY TABLES

877

878

ENERGY MANAGEMENT HANDBOOK

CONVERSION FACTORS AND PROPERTY TABLES

879

880

ENERGY MANAGEMENT HANDBOOK

CONVERSION FACTORS AND PROPERTY TABLES

881

882

ENERGY MANAGEMENT HANDBOOK

CONVERSION FACTORS AND PROPERTY TABLES

883

884

ENERGY MANAGEMENT HANDBOOK

CONVERSION FACTORS AND PROPERTY TABLES

885

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APPENDIX III

REVIEW OF ELECTRICAL SCIENCE

RUSSELL L. HEISERMAN, Ed.D. School of Technology Oklahoma State University Stillwater, Oklahoma III. 1 INTRODUCTION This brief review of electrical science is intended for those readers who may use electrical principles only on occasion and is intended to be supportive of the material found in those chapters of the handbook based on electrical science. The review consists of selected topics in basic ac circuit theory presented at a nominal analytical level. Much of the material deals with power in ac circuits and principles of power-factor improvement.

Fig. III.1 The generalized vector Aejθ shown in the complex plane. If j is positive, it is referenced to the positive real axis with a counterclockwise displacement. If j is negative, it is referenced to the positive real axis with a clockwise displacement.

III.2 REVIEW OF VECTOR ALGEBRA Vector algebra is the mathematics most appropriate for ac circuit problems. Most often electric quantities, voltage and current, are not in phase in ac circuits, so phase relationships as well as magnitude have to be considered. This brief review will cover the basic idea of a vector quantity and then refresh the process of adding, subtracting, multiplying, and dividing vectors. III.2.1 Review A vector is a quantity having both direction and magnitude. Familiar vector quantities are velocity and force. Other familiar quantities, such as speed, volume, area, and mass, have magnitude only. A vector quantity is expressed as having both magnitude and direction, such as Ae

± j θ

Fig. III.2 The vector A ∠θ shown in the polar coordinate system. A vector expressed as A ∠θ is said to be in polar form.

where A is the magnitude and e ± j θ expresses the direction in the complex plane (Figure III.1). The important feature of this vector notation is to note that the angle of displacement is in fact an exponent. This feature is significant, since it will allow the use of the law of exponents when multiplying, dividing, or raising to a power.

Common practice has created a shorthand for expressing vectors. This method is quicker to write and for many, more clearly expresses the idea of a vector: AÂ θ 887

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ENERGY MANAGEMENT HANDBOOK

This shorthand is read as a vector magnitude A operating or pointing in the direction θ. It is termed the polar representation of a vector as shown in Figure III.2. Now the function e j θ may be expressed or resolved into its horizontal and vertical components in the complex plane:

20∠30° = 20 cos 30° + j20 sin 30° = 17.3 + j10 25∠–45° = 25 cos 45° – j25 sin 45° = 17.7 – j17.7

e

j θ

= cos θ + j sin θ

The vector has been resolved and expressed in rectangular form. Using the shorthand notation

A calculator is a handy tool for resolving vectors. Many calculators have automatic programs for converting vectors from one form to another. Now adding we obtain

A ∠θ = A cos θ + jA sin θ

where A cos θ is the vector projection on the real axis and jA sin θ is the vector projection on the imaginary axis, as shown in Figure III.3. Both rectangular and polar expressions of a vector quantity are useful when performing mathematical operations.

(+)

17.3 + j10 17.7 – j17.7 35.0 – j7.7

By inspection, this vector is seen to be slightly greater in magnitude than 35.0 and at a small angle below the positive real axis. Again using a calculator to express the vector in polar form: 35.8∠–12.4°, an answer in agreement with what was anticipated. Figure III.4 shows roughly the same result using a graphical technique. Subtraction is accomplished in much the same way. Suppose that the vector 25∠–45° is to be subtracted from the vector 20∠30°. 20∠30°

= 17.3 + j10

25∠–45° = 17.7 - j17.7 To subtract 17.3 + j10 17.7 – j17.7 first change sign of the subtrahend and then add:

Fig. III.3 The vector A ∠θ shown together with its rectangular components.

III.2.2 Addition and Subtraction of Vectors When adding or subtracting vectors, it is most convenient to use the rectangular form. This is best demonstrated through an example. Suppose that we have two vectors, 20∠30° and 25∠–45°, and these vectors are to be added. The quickest way to accomplish this is to resolve each vector into its rectangular components, add the real components, then add the imaginary components, and, if needed, express the results in polar form:

17.3 + j10 – 17.7 + j17.7 – 0.4 + j27.7 The effect of changing the sign of the subtrahend is to push the vector back through the origin. as shown in Figure III.5. The resulting vector appears to be about 28 units long and barely in the second quadrant. The calculator gives 27.7∠90.8°. III.2.3 Multiplication and Division of Vectors Vectors are expressed in polar form for multiplication and division. The magnitudes are multiplied or divided and the angles follow the rules governing

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889

(20∠30)3 = 8000∠90° or consider (20∠30°)l/2 = 4.47/15° III.2.4 Summary Vector manipulation is straightforward and easy to do. This presentation is intended to refresh those techniques most commonly used by those working at a practical level with ac electrical circuits. It has been the author’s intent to exclude material on dot and cross products in favor of techniques that tend to allow the user more of a feeling for what is going on.

Fig. III.4 Use of the graphical parallelogram method for adding two vectors. The result or sum is the diagonal originating at the origin of the coordinate system.

III.3 RESISTANCE, INDUCTANCE, AND CAPACITANCE The three types of electric circuit elements having distinct characteristics are resistance, inductance, and capacitance. This brief review will focus on the characteristics of these circuit elements in ac circuits to support later discussions on circuit impedance and power-factorimprovement principles.

Fig. III.5 Graphical solution to subtraction of vectors. exponents, added when multiplying, subtracted when dividing. Consider 20∠30° × 25∠–45° = 500∠–15° The magnitudes are multiplied and the angles are added. Consider 20 ∠30° ——— = 0.8 ∠75° 25∠–45° The magnitudes are divided and the angle of the divisor is subtracted from the angle of dividend. Raising to powers is a special case of multiplication. The magnitude is raised to the power and the angle is multiplied by the power. Consider

III.3. 1 Resistance Resistance R in an ac circuit is the name given to circuit elements that consume real power in the form of heat, light. mechanical work, and so on. Resistance is a physical property of the wire used in a distribution system that results in power loss commonly called I 2R loss. Resistance can be thought of as a name given that portion of a circuit load that performs real work, that is, the portion of the power fed to a motor that results in measurable mechanical work being accomplished. If resistance is the only circuit element in an ac circuit, the physical properties of that circuit are easily summarized, as shown in Figure III.6. The important property is that the voltage and current are in phase. Since the current and voltage are in phase and the ac source is a sine wave, the power used by the resistor is easily computed from root-mean-square (rms) (effective) voltage and current readings taken with a typical multimeter. The power is computed by taking the product of the measured voltage in volts or kilovolts and the measured current in amperes: P(watts) = V(volts) × I (amperes) where V is the voltage measured in volts and I is the current measured in amps. Both quantities are measured with an rms reading meter. In many industrial settings the voltage may be

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ENERGY MANAGEMENT HANDBOOK

Fig. III.6 Circuit showing an ac source with radian frequency ω. The current through the resistor is in phase with the voltage across the resistor. measured in kilovolts and current in amperes. The power is computed as the product of current and voltage and expressed as kilowatts: P (kilowatts) = V (kilovolts) × I (amps) If it is unhandy to measure both voltage and current, one can compute power using only voltage or current if the resistance R is known: P (watts) = I 2(amps) × R (ohms) or V2(volts) P(watts) = ———— R(ohms) III.3.2 Inductance Inductance L in an ac circuit is usually formed as coils of wire, such as those found in motor windings, solenoids, or inductors. In a real circuit it is impossible to have only pure inductance, but for purposes of establishing background we will take the theoretical case of a pure inductance so that its circuit properties can be isolated and presented. An inductor is a circuit element that uses no real power; it simply stores energy in the form of a magnetic field and will give up this stored energy, alternately storing energy and giving it up every half-cycle. The result of this storing and giving up energy when an inductor is driven by a sine-wave source is to put the measured magnetizing current (i c.) 90° out of phase with the driving voltage. The magnetizing current lags behind the driving voltage by 90°. If pure inductance were the load of a sine-wave generator, we could summarize its characteristics as in Figure III.7. An inductor limits the current flowing through it by reacting with the voltage change across it. This property is called inductive reactance XL. The inductive

Fig. III.7 (a) Ac circuit with pure inductance. (b) Plot of the voltage across the inductor vL, and the current iL through it. The plot shows a 90° displacement between the current and the voltage. reactance of a coil whose inductance is known in henrys (H) may be computed using the expression XL = 2πƒL where ƒ is the frequency in hertz and L is the coil’s inductance in henrys. III.3.3 Capacitance Capacitance C, like inductance, only stores and gives up energy. However, the voltage and current phasing is exactly opposite that of a inductor in an ac circuit. The current in an ac circuit containing only capacitance leads the voltage by ∠90°. Figure III.8 summarizes the characteristics of an ac circuit with a pure capacity load. A capacitor also reacts to changes. This property is called capacitive reactance Xc. The capacity reactance may be computed by using the expression 1 Xc = ——— 2πfC

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891

tention will be given to the notation used to describe such circuits since vector algebra must be used exclusively.

Fig. III.8 (a) Ac circuit with pure capacitance. (b) Plot of the voltage across the capacitor vc, and the current ic through it. The plot shows a 90° displacement between the current and the voltage.

III.4.1 Circuits with Resistance and Inductive Reactance Figure III.9 shows a circuit that has both resistive and inductive elements. Such a circuit might represent a real inductor with the resistance representing the wire resistance, or such a circuit might be a simple model of a motor, with the inductance reflecting the inductive characteristics of the motor’s windings and the resistance representing both the wire resistance and the real power consumed and converted to mechanical work performed by the motor. In Figure III.9 the current is common to both circuit elements. Recall that the voltage across the resistor is in phase with this current while the voltage across the inductor leads the current. This idea is shown by plotting these quantities in the complex plane. Since i is the reference, it is plotted on the positive real axis as shown in Figure III.10. The voltage across the resistor is in phase with the current, so it is also on the positive real axis. whereas the voltage across the inductor is on the positive j axis

where ƒ is the frequency in hertz and C is the capacity in farads. III.3.4 Summary Circuit elements are resistance that consumes real power and two reactive elements that only store and give up energy. These two reactive elements, capacitors and inductors, have opposite effects on the phase displacement between the current and voltage in ac circuits. These opposite effects are the key to adding capacitors in an otherwise inductive circuit for purposes of reducing the current-voltage phase displacement. Reducing the phase displacement improves the power factor of the circuit. (Power factor is defined and discussed later.)

Fig. III.9 Circuit with both resistance and inductance. The circuit current i is common to both elements.

III.4 IMPEDANCE In the preceding section it was mentioned that pure inductance does not occur in a real-world circuit. This is because the wire that is used to form the most carefully made coil still has resistance. This section considers circuits containing resistance and inductive reactance and circuits containing resistance and capacity reactance. At-

Fig. III.10 Circuit voltages and current plotted in the complex plane. Both i and VR are on the positive real axis since they are in phase, VL is on the positive j axis since it leads the current by 90°.

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ENERGY MANAGEMENT HANDBOOK

since it leads the current by 90°. However, the sum of the voltages must be the source voltage e. Figure III.10 shows that the two voltages must be added as vectors: e = vr + jvL e = iR + jiXL If we call the ratio of voltage to current the circuit impedance, then e Z = — = R + jXL i Z, the circuit impedance, is a complex quantity and may be expressed in either polar or rectangular form: Z = R + jXL or Z = |Z |

θ

In circuits with resistance and inductance the complex impedance will have a positive phase angle and if R and XL are plotted in the complex plane, XL is plotted on the positive j axis, as shown in Figure III.11. III.4.2 Circuits with Resistance and Capacity Reactance Circuits containing resistance and capacitance are approached about the same way. Going through a similar analysis and looking at the relationship among R, Xc, and Z would show that Xc is plotted on the negative j axis, as shown in Figure III.12. III.4.3 Summary

Fig. III.11 Plot in the complex plane showing the complex relationship of R, XL, and Z.

Fig. III.12 Summary of the relationship among R, Xc, and Z shown in the complex plane.

In circuits containing both resistive and reactive elements, the resistance is plotted on the positive real axis while the reactances are plotted on the imaginary axis. The fact that inductive and capacitive reactance causes opposite phase displacements (has opposite effects in ac circuits) is further emphasized by plotting their reactance effects in opposite directions on the imaginary axis of the complex plane. The case is building for why capacitors might be used in an ac circuit with inductive loading to improve the circuit’s power factor.

III.5 POWER IN AC CIRCUITS This section considers three aspects of power in ac circuits. First, the case of a circuit containing resistance and inductance is discussed, followed by the introduction of the power triangle for circuits containing resistance and inductance. Finally, power-factor improvement by the use of capacitors is presented. III.5.1 Power in a Circuit Containing Both Resistance and Inductance Figure III.13 reviews this situation through a circuit drawing and the voltages and currents shown in the complex plane. Meters are in place that read the effective or rms voltage V across the complex load and the effective or rms line current I. Power is usually thought of as the product of voltage and the current in a circuit. The question is: The current I times which voltage will yield the correct or true power? This is an important question, since Figure III.13b shows three voltages in the complex plane. Each of the three products may be taken, and each

REVIEW OF ELECTRICAL SCIENCE

893

This is the power that is alternately stored and given up by the inductor to maintain its magnetic field. None of this reactive power is actually used. If the voltages in the foregoing examples were measured in kilovolts, the three values computed would be the more familiar: P(apparent) = kVA P(real) = kW P(imaginary) = kVAR This discussion, together with Figure III.13b, leads to the power triangle.

Fig. III.13 (a) Circuit having resistance and inductance; meters are in place to measure the line current I and the voltage V. (b) Relationship between the various voltages and the line current for this circuit.

has a name and a meaning. Taking the ammeter reading I times the voltmeter reading yields the apparent power. The apparent power is the load current-load voltage product without regard to the phase relationship of the current and voltage. This figure by itself is meaningless: P(apparent) = IV If the voltmeter could be connected across the resistor only, to measure vR, then the line current-voltage product would yield the true power, since the current and voltage are in phase. P(true) = IvR Usually, this connection cannot be made, so the true power of a load is measured with a special meter called a wattmeter that automatically performs the following calculation.

III.5.2 The Power Triangle The power triangle consists of three values, kVA, kW, and kVAR, arranged in a right triangle. The angle between the line current and voltage, Θ, becomes an important factor in this triangle. Figure III.14 shows the power triangle. To emphasize the relationship between these three quantities, an example may be helpful. Suppose that we have a circuit with inductive characteristics and using a voltmeter, ammeter, and wattmeter the following values are measured: watts = 1.5 kW line current = 10 A line voltage = 240 V From this information we should be able to determine the kVA, Θ, and the kVAR. The kVA can be computed directly from the voltmeter and ammeter readings: kVA = (10 A)(0.24) kV = 2.4 kVA

P(true) = IV cos θ Note that in Figure III.13b, the circuit voltage V and the resistance voltage VR are related through the cosine of θ. The third product that could be taken is called imaginary power or VAR, the voltampere reactive product. P(imaginary) = IvL

Fig. III.14 Power triangle for an inductive load. The angle θ is the angle of displacement between the line voltage and the line current.

894

ENERGY MANAGEMENT HANDBOOK

Looking at the triangle in Figure III.14 and recalling some basic trigonometry, we have

and θ is the angle whose cosine equals 0.625. This can be looked up in a table or calculated using a hand calculator that computes trig functions: θ = cos–1 0.625 = 51.3° Again referring to the power triangle and a little trig, we see that kVAR = kVA sin θ = 2.4 kVA sin 51.3° = 1.87 kVAR Figure III.15 puts all these measured and calculated data together in a power triangle. Of particular interest is the ratio kW/kVA. This ratio is called the power factor (PF) of the circuit. So the power factor is the ratio of true power to apparent power in a circuit. This is also the cosine of the angle θ, the angle of displacement between the line voltage and the line current. To improve the power factor, the angle θ must be reduced. This could be accomplished by reducing the kVAR side of the triangle.

Fig. III.15 Organization of the measured and computed data of the example into a power triangle.

III.5.3 Power-Factor Improvement Recall that inductive reactance and capacity reactance are plotted in opposite directions on the imaginary axis, j. Thus it should be no surprise to consider that kVAR produced by a capacitive load behave in an opposite way to kVAR produced by inductive loads. This is the case and is the reason capacitors are commonly added to circuits having inductive loads to improve power factor (reduce the angle θ). Suppose in the example being considered that enough capacity is added across the load to offset the effects of 90% of the inductive load. That is, we will try

Fig. III.16 (a) Inductive circuit with capacity added to correct power factor. (b) Power vectors showing the relationship among kW, kVAR inductive, and kVAR capacitive. to improve the power factor by better than 90%. Figure III.16 shows the circuit arrangement with the kW and kVAR vectors drawn to show their relationship. Following the example through, consider Figure III.17, where 90% of the kVAR inductive load has been neutralized by adding the capacitor. Working with the modified triangle in Figure III.17, we can compute the new θ, call it θ2.

θ2

0.19 = tan–1 —— 1.5 = 7.2

Again, a calculator comes in handy. Since the new power factor is the cosine of θ2, we compute PF new = cosine 7.2 = 0.99 certainly an improvement. Recall that the power factor can be expressed as a ratio of kW to kVA. From this idea we can compute a new kVA value: 1.5 kW PF = 0.99 = ————— kVA new or

REVIEW OF ELECTRICAL SCIENCE

895

Fig. III.17 Resulting net power triangle when the capacitor is added. A new kVA can be calculated as well as a new θ. kVA new =

1.5 kW ——— 0.99

= 1.52 kVA The line voltage did not change, so the line current must be lower. 1.52 kVA new = 0.24 kV × I new 1.52 kVA I new = ————— = 6.3 A 0.24 Comparing the original circuit to the circuit after adding capacity, we have: Inductive Circuit Improved Circuit ————————————————————————— Line voltage

240 V

Line current

10 A

PF

62.5%

240 V 6.3 A 99%

kVA

2.4 kVA

1.52 kVA

kW

1.5 kW

1.5 kW

kVAR

1.87 kVAR

0.19 kVAR

The big improvement noted is the reduction of line current by 37% with no decrease in real power, kW, used by the load. Also note the big change in kVA; less generating capacity is used to meet the same real power demand (generator input power is determined by KVA output). III.5.4 Summary Through an example it has been demonstrated how the addition of a capacitor across an inductive load can improve power factor, reduce line current, and reduce the amount of generating capacity required to supply the load. The way this comes about is by having the capacitor supply the inductive magnetizing current locally. Since inductive and capacitive elements store and release power at different times in each cycle, this reactive current simply flows back and forth between the capacitor and inductor of the load. This idea is

Fig. III.18 (a) Pictorial showing the inductive load of the example in this section. (b) The load with a capacitor added. With the exchange of the kVAR current between the capacitor and inductive load, very little kVAR current is supplied by the generator. reinforced by Figure III.18. Adding capacitors to inductive loads can free generating capacity, reduce line loss, improve power factor, and in general be cost effective in controlling energy bills.

III.6 THREE-PHASE POWER Three-phase power is the form of power most often distributed to industrial users. This form of transmission has three advantages over single-phase systems: (1) less copper is required to supply a given power at given voltage; (2) if the load of each phase of the three-phase source is identical, the instantaneous output of the alternator is constant; and (3) a three-phase system produces a magnetic field of constant density that rotates at the line frequency—this greatly reduces the complexity of motor construction. The author realizes that both delta systems and wye systems exist, but will concentrate on four-wire wye systems as being representative of internal distribution systems. This type of internal distribution system allows the customer both single-phase and three-phase service. Our focus will be on measuring power and determining power factor in four-wire three-phase wye-connected systems. III.6.1 The Four-Wire Wye-Connected System Figure III.19 shows a generalized four-wire wyeconnected system. The coils represent the secondary windings of the transformers at the site substation while the generalized loads represent phase loads that are the

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ENERGY MANAGEMENT HANDBOOK

Table III.1 How to Select Capacitor Ratings for Induction Motors/Source: 1.

Fig. III.19 Generalized four-wire wyeconnected system. The coils A, B, and C represent the three transformer secondaries at the site substation; while ZA, ZB. and ZC are the generalized loads seen by each phase.

REVIEW OF ELECTRICAL SCIENCE

sum loads on each phase. These loads may be composites of single-phase services and three-phase motors being fed by the distribution system. N is the neutral or return. To determine the power and power factor of any phase A, B, or C, consider that phase as if it were a single-phase system. Measure the real power, kW, delivered by the phase by use of a wattmeter and measure and compute the volt-ampere product, apparent power, kVA, using a voltmeter and ammeter. The power factor of the phase can then be determined and corrected as needed. Each phase can be

897

treated independently in turn. The only caution to note is to make the measurements during nominal load periods, this will allow power-factor correction for the most common loading. If heavy motors are subject to intermittent duty, additional power and power-factor information can be gathered while they are operating. Capacitors used to correct power factor for these intermittent loads should be connected to relays so that they are across the motors and on phase only when the motor is on; otherwise, overcorrection can occur.

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ENERGY MANAGEMENT HANDBOOK

Table III.2 How to Select Capacitor Ratings for Induction Motors/Source: 2.

In the special case of a four-wire wye-connected system with balanced loading, two wattmeters may be used to monitor the power consumed on the service and also allow computation of the power factor from the two wattmeter readings. III.6.1.1 Balanced Four-Wire Wye-Connected System Figure III.20 shows a balanced system containing two wattmeters. The sum of these two wattmeter readings are the total real power being used by the service:

PT = P1 + P2 Further, the angle of displacement between each line current and voltage can be computed from P1 and P2:

θ = tan –1 3

P2 – P1 P2 + P1

and the power factor PF = cos θ.

REVIEW OF ELECTRICAL SCIENCE

This quick method for monitoring power and power factor is useful in determining both fixed capacitors to be tied across each phase for the nominal load, and the capacitors that are switched in only when intermittent loads come on-line. The two-wattmeter method is useful for determining real power consumed in either wye- or delta-connected systems with or without balanced loads: PT = P1 + P2 However, the use of these readings for determining

899

phase power factor as well is restricted to the case of balanced loads. III.6.2 Summary This brief coverage of power and power-factor determination in three-phase systems covers only the very basic ideas in this important area. It is the aim of this brief coverage to recall or refresh ideas once learned but seldom used. Tables III.1 and III.2 were supplied by General Electric. who gave permission for the reproduction of their materials in this handbook.

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ENERGY MANAGEMENT HANDBOOK

Fig. III.20 Four-wire wye-connected system with wattmeter connections detailed. Solid circle voltage connections to wattmeter; open circle, current connections to wattmeter.

INDEX Symbols 1995 Model Energy Code (MEC) 541 2000 International Energy Conservation Code (IECC) 541 A absolute pressure 126 absorber plate 475 absorptance 476 absorption chillers 272 abuse 445 acceptable indoor air quality 499 accidents 623 accuracy 588 active power 279 actuator 588 adaptive control 318 adjustable speed drive 291 administrative sequence logic 333 AEE (Association of Energy Engineers) xi, 1, 501 after-tax cost of capital 43 AFUE 789, 791 AGA 172 aggregation 643 AHU 339 systems 684 air-handling units 716 air-source heat pump 757 airflow measurement devices 25 air change method 238 air collectors 477 air compressors 406 maintenance for 407 air conditioning optimization 345 air handler 748 systems 684 air velocity and airflow 260 alarms 346 monitoring and reporting 321 all-air systems 250 all-water systems 255 alternative energy source 471 ambient temperature 299, 449 American Boiler Manufacturers Association (ABMA) 415

American Council for an Energy Efficient Economy 379 American Physical Society 7 American Society of Heating, Refrigeration, and Air Conditioning (ASHRAE) 397, 499, 540 American Society of Testing Materials 437 ammeters clamp on 24 amperage 284 ampere 397 amps 275, 298 anaerobic digestion processes 492 analog 616 input 342, 349 output (AO) 342, 349 to digital A/D converter 349 annual cost 468 annual energy review 193 annual energy use 716 annual expenses 42 annual worth 55 anode 493 ANSI 397 anti-wind-up 583 application requirements 443 approach 604 arc tube 397 ASHRAE 397, 499, 540 ASHRAE “Zone Method” 227 ASHRAE 90.1-1999 540 ASHRAE 90.2-1993 540 ASHRAE Equipment Handbook 407 ASHRAE Guidelines 3-1990 Reducing Emission of Fully Halogenated Chlorofluorocarbon (CFC) 544 ASHRAE Handbook of Fundamentals 237, 246, 460, 473 ASHRAE Standard 501 ASHRAE Standard 62-1999 543 ASHRAE Standard 90-80 540 ASHRAE Standard 90.1 226, 229 ASHRAE ventilation standard, 621989 543 901

Association of Energy Engineers (AEE) xi, 1, 501 ASTM 450 as built drawings 348 auditor’s toolbox 24 audits commercial 36 industrial 34 planning 14 residential 37 available forms 440 average rated life 397 avoided costs 177 B baffle 397 ballast 360, 397 cycling 397 efficiency factor 397 factor 360, 397 bare-surface heat loss 461 base 222 bath-tub curve 623 bearings 407 before tax cash flows (BTCF) 44 Betz coefficient 485 bin 775, 777 method 246, 768 blower door attachment 25 boiler 338, 402, 722, 748 economizer 216 efficiency 128, 414 maintenance 413 measurements 722 optimization 320 boiling point 126 BOMA 797 bonds 655 borehole 766 bottoming cycle 157 Bourdon gauge 428 British thermal unit (Btu) 126 building automation system 616 building balance temperature 245 building envelope 221, 402 building load coefficient (BLC) 239, 242

902

Building Officials and Code Administrators International (BOCA) 541 building related illness 499 causes 499 by-pass 291 C calcium silicate 441 calibration 615 California Title 24 540 candela 397 distribution 397 candle power 397 capacitive switching HID fixtures 361 capacitor 279 capitalize 666 capital investments 41, 42 cost categories 42 capital or financial lease 666 capital rationing 42 cash flow diagrams 42 cathode 493 CELCAP 174 cellular glass 441 cell structure 440 central chiller plants 693 ceramic metal halide lamps (CMH) 376 ceramic recuperator 213 Certified Energy Manager 1 CFC 793, 802 CFL 393 chilled water reset 320 chilled water storage 523 chiller 271, 339, 531, 693, 718, 720, 748 consumption profile 522 demand limiting 321 optimization 321 system capacity 526 chlorofluorocarbons (CFCs) 543 circulators 338 Clean Air Act Amendment 544 Climatic Change Action Plan 547 closed loop 589, 616 heat pumps 257 closed heat exchangers 200 code 299 coefficient of heat transmission 439 coefficient of performance (COP)

ENERGY MANAGEMENT HANDBOOK

198, 719, 776, 790, 791 coefficient of utilization (CU) 362, 397 cogeneration 545 facility 176 COGENMASTER 175 collectively exhaustive 60 collector 478 efficiency 475 color 356 color rendering index (CRI) 356, 397 color temperature 397 combined cycle 157 combustion analyzers 25 combustion or gas turbines 169 commissioning 329, 799 a new building 704 for energy management 671 measures 680 compact fluorescent 397 lamps (CFLs) 358 compound interest 47, 48 comprehensive, explicit, and relevant training and support (CERTs) 331 compression of insulation 224 compressive strength 440 computer programs 468 concentrating collectors 478 condensate systems 125, 147 condensation 125 control 454 conduction 437 constant-worth dollars 66 constant fire boilers 724 constant volume dual duct 254 constrained deterministic analysis 59 contaminants 38, 39 contaminant amplification 499 contingency 59 planning 632 contingent 60 continuous commissioning 672, 687 contrast 356, 397 controls 503 control drawings 347 control loop 349, 616 control relays 343 control systems 264, 404, 481 control valves 337, 339

convection 437 convective recuperator 212 converter 300 conveyor systems 423 cooling systems 271 cooling towers 272, 339, 693, 748 cool white lamps 359 coordinated color temperature (CCT) 356 COP 198, 719, 776, 790, 791 correlation coefficient, R 243 corrosion 492 control 209 costs 41 cost effectiveness 41 cost factors 446 cost of capital 44 Council of American Building Officials (CABO) 541 countermeasures 630, 633 criteria for selection 208 cross-contamination 214 cubic feet per minute (CFM) 290 current transformers 343 cut-in 578, 616 cut-out 578, 616 cut set 630 D daily scheduling 319 daisy chain 349 dampers 300, 337, 338 daylighting 383, 804 daylight harvesting 364 DDC 579, 580, 581 DDC EMCS 317, 319, 324 dead band 345, 349, 595, 616 deal time 349 debt financing 43 dedicated outdoor air systems 810 deductive analysis 624 deductive method 627 deferred maintenance 634 Degree Days 240 demand controlled ventilation (DCV) 598, 612 demand limiting or load shedding 320 demand management 261 demand shedding 345 demand side management (DSM) 1 depreciation 44, 666

INDEX

accelerated cost recovery system 45 clining balance 45 straight line 45 sum-of-the-years digits 45 Dept. of Energy 539 deregulation 634, 640, 641 derivative control 349 desiccant 811 design 298 life 447 of the waste-heat-recovery system 206 desuperheating 765 deterministic analysis constrained 59 economic 64 deterministic dew-point determination 454 dew-point temperature 449 DG economics 168 diaphragm gauge 428 differential temperature controller 481 diffuser 397 digital communication bus 349 digital inputs 342 digital outputs (DO) 342 digital to analog D/A converter 349 dilution 501, 543 dimmable CFLs 375 direct digital control 315, 579 direct glare 397 discounted cash flow (DCF) 466 discounted payback 465 disk traps 421 distributed control 349 distributed generation 167 distribution energy 270 distribution systems 690 DOAS 810 domestic hot water (DHW) 272, 339 doors 237 double failure matrix (DFM) 625, 626, 627 downlight 397 downsizing 634 drift 584, 588, 589 drive system efficiency 273 dry contact 617 dual-technology sensors (DT) 366 dual duct systems 254

903

dual duct VAV 254 dumping waste heat 199 duplex steels 210 duty 299 cycling 320, 345 logs 321 dynamic system 525 E E.O. 13123 542 economics 481 economic analysis 41, 58 economic calculations 464 economic thickness (ETI) 466, 468 economizers 263 eddy-current clutch 300 educational planning 15 EER 776, 790, 791 efficacy 354, 398 efficiency 276 index 299 elastomeric cellular plastic 442 electric/pneumatic relays 317, 341 electrical measurements 427 electrical system 404 electric energy management 273 electric industry deregulation 638 electric lift trucks 422 electric motor efficiency 275 electric power industry historical perspective 637 Electric Power Research Institute (EPRI) 35, 368 electronic ballast 398 electronic ballasts 361 EMCS application 322 EMCS installation 339 EMCS Retrofit 324 EMCS software specifications 333 emissivity 235 emittance 451, 476 end-of-year cash flow 42 energy-saving ballast 398 energy-saving lamp 398 energy analysis and diagnostic centers 4 energy audit 23, 32, 247 energy audit format 32 energy broker 640 energy conservation 634 analyzing 138 Energy Conservation and Produc-

tion Act in 1977 541 energy conservation opportunities (ECOs) 24 energy consumption 222 energy efficiency provisions 539 energy flux 202 Energy Information Administration 539 energy maintenance 403 energy management 9, 315, 633 control system 315 functions 344 in materials handling 430 program 7, 247 energy management systems 315, 617 energy manager 10 energy marketer 640 energy monitoring and control system 617 energy policy 13, 18 Energy Policy Act of 1992 237, 539, 544, 546 Energy Policy and Conservation Act 541 Energy Productivity Center of the Carnegie-Mellon Institute of Research 5 energy savings 707 calculations 463 measurement of 696 energy security 621 energy services in-house vs. outsourced 643 energy service company (ESCO) 666 energy systems maintenance 401 energy team 11 enthalpy 128 envelope analysis 223, 242 Environmental Protection Agency 416 equal percentage 586 equipment efficiency 267 equipment failure 622 equipment list 326 equity financing 43 equivalence 52 equivalent thickness 450 ESCOs (energy service companies) 2 eutectic salts 525, 531 eutectic storage 531

904

evaporative-condensing cycle 216 evaporative cooling 597, 811 event tree analysis 625 excess CO 415 excess O2 413 executive orders 542 exempt wholesale generators (EWGs) 546 exhaust fans 339 exit signs 363 expenses 42 extraction 501 F facility appraisal 326 facility layout 28 facility specific instructions 331 failure mode and effect analysis (FMEA) 624 failure mode effect and criticality analysis (FMECA) 624 fan-coils 256 fan law 290 fans 716 faradaic or current efficiency 494 fault hazard analysis (FHA) 624 fault tree 627, 630 analysis 627 FCU 349 Federal Energy Administration 467 Federal Energy Management Implementation Act (FEMIA) 542 Federal Energy Management Program (FEMP) 2 Federal Energy Regulatory Commission (FERC) 546, 638 Federal Power Act 545 feedback 617 fenestration 234 FERC 177 FERC Order No. 436 547 FERC Order No. 636 547 FERC Order No. 636A 547 FHA 625 fiber optics 378 fill factor 483 filtration 498, 502, 503, 543 finance terminology 652 financial analysis 464 financing 43, 649 finned tube 215, 218 fireproofing 444

ENERGY MANAGEMENT HANDBOOK

fire hazard classification 440 first cost 41 fixture 399 dirt depreciation (LDD) 369 efficiency 399 flash steam 128, 149, 420 flash tanks 148 flat-plate collector 473, 477 floating control 579, 582, 617 float and thermostatic traps 420 floors 233 below grade 234 on grade 234 flow hoods 429 flow meters 343 fluorescent lamps 358, 398 follow-up 412 foot-candles 353, 398 footlambert 398 form required 446 fouling 415, 492 frame 298 size 276 freeze protection 346, 459 free cooling 321, 336 frequency 276 fuel cells 170, 493 molten carbonate (MCFC) 495 full-load speed 274 full storage systems 521, 526, 528 functions 319 furnaces 722 future cash flows 66 constant-worth dollars 66 then-current dollars 66 G gain 581, 617 gas or Liquid-to-Liquid Regenerators 216 Gas Research Institute (GRI) 35 gauge pressure 126 general test form 282 geographic location 28 Gibbs free energy 493 glare 356, 398 glass fiber 441 glazed flat-plate collectors 476 global data exchange 342 gradient series 52 graphics 579 greenhouse effect 475

green buildings 795, 796 green power 799 ground-source heat pumps 755, 756, 757, 783 group relamping 370 grout 766 guidevanes 300 H harmonic 281, 380, 398 distortion 361 health effect consequences 499 heat-balance diagram 203 heat/power ratio 157 heating, ventilating, air conditioning (HVAC) 315 systems 402 heat exchangers concentric-tube 217 shell-and tube 217 heat flow 449, 450 heat flux 449 heat gain 221 heat loss 221 from a floor to a crawl space 234 heat pipe 216 array 215 heat plant 447 heat pumps 198 heat recovery systems 263 heat transfer 438 heat wheel 208, 213 HID 398 high-bay 398 high-intensity discharge (HID) 359 high-temperature controller 481 higher heating value 203 high inertia load 276 high output (HO) 398 high pressure sodium 359 high pressure sodium lamp 398 holiday programming 319 host 666 hot deck/cold deck temperature reset 321 hot water distribution 405 hot water reset 320 HP 298, 349 HSPF 790 human dimension 317, 331 hunting 583

INDEX

hurdle rate 58 HVAC 398 HVAC systems 247, 448, 497, 730 types 249 HZ 298

IEQ (indoor environmental quality) 500 ice storage 525, 531 ideal heat pump 198 IES (Illuminating Engineering Society) 353, 405, 428 IFMA 797 IGSHPA 769 illuminance 398 Illuminating Engineering Society (IES) 353, 405, 428 improper drainage 419 incandescent 358 income 43 indifference 53 indirect glare 398 indoor air quality (IAQ) 38, 260, 497, 498, 501, 542 manager 501 problems, solutions and prevention of 500 induction lighting 377 induction motors 274, 279, 285, 286 induction systems 257 inductive methods 624 industrial assessment centers 4 industrial light meter 428 infiltration 237 air flow 237 commercial buildings 238 residential buildings 237 inflation 41, 46, 66 infrared cameras 24 infrared equipment 429 initial costs 41, 42 input/output point 326 input/output units 342 inputs 342 insolation 473 installation 340 instant start 398 insulation class 276, 299 cost considerations 461 economics 461

905

equivalent thickness 449 flexible 441 formed-in-place 441 materials 439 nonrigid 445 penetrations 224 properties 439 removable-reusable 441 selection 443 thickness determination 448 integral control 350 integrated solid waste management 489 intelligent building 350 interest 46 interest rate effective 65 nominal 65 period 65 interface temperature 450 interlock 583, 596 internal rate of return 56 International Code Council (ICC) 541 International Conference of Building Officials (ICBO) 541 inverted bucket traps 420 inverter 300, 301 investment 41 investment analysis 42 IPLV 790, 791 isotherms 225 J Justification of EMCSs 321 K Kyoto protocol 544 L LAG 350 laminar wheel 214 lamp lumen depreciation (LLD) 369 factor 398 latent heat 128 of fusion 525, 530 transfer 224 lay-in troffer 398 leasing 659 least cost 497 LED 393, 398 LEED 795, 796, 798

lender 667 lens 398 lessee 667 lessor 667 leveraged lease 667 liability 39 life-cycle cost 503, 778, 780 analysis 41, 42 lift trucks, non-electric 422 lighting 724 fundamentals 353 quality 355 quantity 353 lightmeter 24 light color 355 light generated current 483 light loss factor (LLF) 398 light measurements 428 light meter 353 limitations of metal recuperators 212 line of credit 667 liquidity 667 litigation, risk of 500 load 282 diversity factor 304 factor 431 limiting 596 profile 303, 637 types 277 loans 654 local distribution companies (LDCs) 546 location 444 loose-fill insulation 440 louver 398 low-pressure sodium 359, 399 low-temperature controller 481 lumen 353, 399 depreciation compensation 365 luminaires 361 M magnetic ballasts 360 maintainability 211 maintenance 42, 424, 503 actions 416 for air compressors 407 manual 347 of the lighting 405 procedures 413 program 401

906

schedule 411 management control systems 7 management decisions 423 manifold 478 manometer 428 manual override 321, 346 Markey Bill 294 MARR (minimum attractive rate of return) 668 mass flow rate 202, 449 mass resistances 438 materials and construction 209 materials handling energy savings 432 materials handling maintenance 421 maximum theoretical COP 198 MCS (multiple-chemical-sensitivity) 497, 499 mean light output 399 mean temperature 440, 449, 450 mean time between failure 631 measurement and verification (M&V) 707, 711 measuring instruments 426 mechanical equipment 748 mercury vapor 359 lamp 399 metallic radiation recuperator 211 metal building roofs 232 metal building walls 228 metal elements envelope 225 metal halide 359, 399 microturbines 170 mineral Fiber/Rock Wool 441 miniature data loggers 25 minimum annual cost analysis 465 minimum attractive rate of return (MARR) 43, 54 minimum on-minimum off times 320 model energy code 541 Model Energy Codes 540 modified accelerated cost recovery system (MACRS) 45 modulation 579, 618 molten carbonate fuel cell (MCFC) 170 monitoring 346, 431 Montreal protocol 543 most-open valve 618 motor-generator sets 300 motor 407

ENERGY MANAGEMENT HANDBOOK

code letters 275 efficiency 284, 294 manager 294 operating loads 281, 282 performance management process 294 record form 295, 296 rpm 290 speed control 321 multimeters 427 multizone systems 253 mutually exclusive 59, 60 set 60 N National Electrical Code 279 National Electrical Manufacturers Association (NEM) 273, 285, 379 National Fenestration Rating Council 237 natural convection 256 natural disasters 623 natural gas 550 environmental advantages 565 purchase of 567 consumption 554 interstate pipeline specifications 561 marketers 567 markets 566 pricing 570 purchasing 549 supply 555 transportation 558 Natural Gas Policy Act (NGPA) 1, 545 of 1978 546 near term results 41 NEBs 322 negative-sequence voltage 274 NERTs 322 net present value (NPV) 668 new construction EMCS 326 night set-back 262, 320 non-annual compounding of interest 41, 65 non-energy benefit 322 non-energy related tasks (NERTs) 316 North American Insulation Manufacturers Association 467

O occupancy sensor 365, 366, 393, 399 Occupational Safety and Health Administration (OSHA) 543 off-balance sheet financing 668 Omnibus Reconciliation Act of 1993 44 opaque envelope components 223 open-circuit voltage 483 open bucket traps 419 open loop 589, 618 open protocol 580 open waste-heat exchangers 199 operating and maintenance costs 41 operating conditions 460 operating hours 28 operating practices 425 operating temperature 443 operator’s terminal 350 optimal start/stop 595 optimization 578, 618 optimum start/stop 320, 337, 345 organic binders 444 orifice plates 430 Orsat apparatus 428 outlay 43 outputs 342 ovens maintenance 407 over-the-Purlin 230 ownership 17 P p-n junction diodes 482 package boilers 416, 418 parabolic 478 partial load storage 526 partial load system 529 partial storage systems 521, 529 par value or face value 668 passive air preheaters 215 passive infrared sensors (PIR) 365, 366 payback period 58, 468 PCB ballasts 383 peer-to-peer network 318 performance contracting 661, 710 performance contractors 2 periodic replacement 42 personnel protection 450 phase 277, 299 phase-change materials 480, 525

INDEX

phosphoric acid (PAFC) 494 phosphoric acid fuel cell (PAFC) 170 photocells 364, 399 photographic light meter 428 photovoltaics 170 PID control 350 pipelines 558 Pitot tubes 429 PI control 350 planning 13 horizon 42, 63 plastic foams 442 plate-type 215 pneumatic 579, 581 pocket thermometers 429 poles 277 poll/response system 318 polyimide foams 442 potential 193 transformers 343 power coefficient 486 power factor 277, 279, 281, 399, 405 controller 291 meter 25, 427 power meter 282 power survey 281, 282 preferred stock 668 present-value cost analysis 466 present dollars 41 present worth 54 factor 50 savings investment ratio 54 pressure measurements 428 pressure sensors 343 pressure switches 343 proactive monitoring 501 process control 456 process wastes 489 process work 448 programmable logic controllers 315 project financing 668 project measures of worth 54 annual worth 54 internal rate of return 54 payback period 54 proton exchange membrane (PEM) 495 properties of thermal storage materials 197 proportional-integral (PI) control 316, 583 proportional control 350, 583

907

proportional output 618 protective coatings and jackets 442 protective countermeasures 631 proton exchange membrane (PEM) 170 public awareness 498 Public Utility Holding Company Act (PUHCA) 539, 546 of 1935 545 Public Utility Regulatory Policies Act (PURPA) 177, 545 pulse accumulators 342 pulse width modulation 301, 350 pumps 714 purge section 214 purlin 230 PURPA 177, 545 pyrolysis 492 Q qualifying facilities (QFs) 545 quantifying 194 R rachet clause 26 radiant heating 256 radiation 438 radon gas 39 rapid recovery 631 rapid start (RS) 399 rate structure 26 reactive power 279, 399 recessed 399 reciprocating engines 169 recirculation 321 recommended light levels 354, 355 recommissioning 672 recording ammeter 427 recuperators 211 reducing heat loss 228, 232 redundant systems 631 reed relays 343 reflectors 362 refractories 442 refuse-derived fuel (RDF) 489, 490 refuse combustion 492 refuse preparation 490 regenerators 207 reheat 610 systems 252 relative humidity 449 repeatability 589

reporting 16 reset 599, 603, 606, 607, 609, 812 resistance 445 Resource Conservation and Recovery Act of 1976 (RCRA) 545 retained earnings 44 retrocommissioning 672 retrofit 399 revenues 41, 42 risk analysis 67, 624 risk management 646 rock-bed storage system 480 roll-runner 232 room surface dirt depreciation (RSDD) 369 root-mean-square (rms) 399 routine maintenance 408 rpm (revolutions per minute) 290, 298 runaround systems 200 S sabotage 623 safety checklist 29 safety equipment 25, 29 salvage value 42 saturated steam 128 savings 533, 707 saving investment ratio 57 secured loan 668 Securities and Exchange Commission (SEC) 545 SEER 791 selectivity 476 selling stock 657 sensible heat 128, 133 sensitivity analysis 41, 67 sequencing 584 serial use 200 series cash flows 50 service factor 277, 298 setpoint 350 shared savings providers 2 short-circuit current 483 sick building syndrome 498, 499, 542 silicon controlled rectifier 301 simple interest 47 simulation 69 single-duct VAV systems 251 single duct systems 250 single factor sensitivity analysis 67

908

single point failures 625 single sum 50 cash flows 49 sizing 481 slip 278, 282 smart windows 237 smoke detectors 429 smoke generator 25 smoke sources 33 software 318 routines 319 specifications 327 soil temperature 763, 764 solar arrays 484 solar cells 482, 483 solar collecting systems 472, 473 solar constant 472 solar energy 471, 472 solar thermal energy 471 solid fuel pellets 492 solid oxide fuel cell (SOFC) 170 solid state relays (SSRs) 343 source control 501, 503, 543 Southern Building Codes Congress International (SBCCI) 541 spacers 236 space criterion 399 specific heat 449 specified heat loss 457 specular 399 speed ratio correction factor 290 spot market 1, 546 stack-gas analysis 428 stack-gas stream 206 stack-gas temperature 415 stagnation 475 state codes 540 static system 525 steady-state heat exchangers 208 steam systems 125, 133 steam traps 139, 145, 402, 418, 421 failure 418 stethoscope 430 stochastic techniques 59 storage 196 mediums 523 systems 521 capacity 528 stored heat 196 stranded costs 637, 639 strategic planning 16 stroboscope 430

ENERGY MANAGEMENT HANDBOOK

summary 635 superheated steam 128 super insulations 443 surface air film coefficient 449 surface film coefficient 449 surface resistance 438, 449, 450, 451 surface temperature 449 surge protection 343 sustainability 793, 794, 806, 808 synchronous speed 278 system capacitance 526, 581 system controllers 317 system manual 346 system modifications 270 system performance method 540 system programming 347 systems checkout 348 systems configuration 327 systems integration 326, 329 T T12 lamp 399 T2 lamps 371 T5 lamps 372 T8 lamps 373 tandem wiring 399 task lighting 368 tax benefits 663 tax considerations 44 tax effects 466 TCLP compliant fluorescent lamps 373 temperature 278 control 345 difference 438 drop 458 inputs 342 measurement 429 rise 299 use range 440 terminal unit 350 TES systems 533 then-current dollars 66 thermal-break 235 thermally heavy building 240, 244 thermally light buildings 240 thermal break 229 thermal comfort 248, 260 thermal conductivity 196, 437, 440, 449 thermal energy storage systems 633 thermal equilibrium 449

thermal insulation 437 Thermal Insulation Manufacturers Association 231 thermal mass 221 thermal performance 41 of roof 230 thermal pollution 193 thermal resistance 223, 438, 449 thermal spacers 233 thermal storage 272 systems 479, 526 thermal stratification 523 thermal weight 240 thermocouples 429 thermodynamic model 719 temperature dependent 719 thermal girts 228 thermometers 24 thermostatic traps 421 thermowells 342 The National Energy Conservation Policy Act of 1978 541 throttling 291 tight building syndrome 497, 498 time clocks 364, 408 time rating 278 time standards 408 time value of money 42, 46, 465 calculations 41 factors 52 principles 64 tires 492 topping cycles 157 torque 278 torque 279 total harmonic distortion (THD) 399 total quality management (TQM) 3 trading of electricity 640 training 15, 346 transducers 350, 585, 620 transformers, potential 343 transmittance 476 transmitters 585, 620 tri-phosphor lamps 359 truck operation and maintenance 423 true lease 668 trusses 230 tube-and-shell heat exchanger 211 twisted pair 350 two-position 350, 620

INDEX

control 581 type 299 typical Applications 447 U U-factor 223 ultrasonic (US) 365 sensors 365 unbalanced voltages 274 unbundled rates 637 unconstrained deterministic analysis 59 uniformity 356 uniform series cash flows 50 United Nations Environment Program 543 unit heaters 339 USGBC 794, 795, 796 utility billings 241 utility deregulation 637 utility network 622 utility outages 632 utility systems 622 V variable-speed drive 214 variable air volume (VAV) 250 variable consumption 222 variable fire boilers 724 variable frequency drives 300, 302, 304 variable inlet vanes (VIV) 304 variable pitch pulleys drive 300 variable speed drive 291

909

variable speed loads 302 VAV (Variable Air Volume) 350, 498 VCP 399 velocity and flow-rate measurement 429 ventilation 498, 543 rate procedure 501 vertical-axis wind turbine (VAWT) 486 very high output (VHO) 400 vibration 444 analysis equipment 26 measurement 430 viscosity 760 visual comfort probability 356 VOC 800 volatile organic compounds 497 voltage 279, 281 voltmeter 24 volts 298 volumetric flow rate 202 W WACC (weighted average cost of capital) 668 walk-through audit 431 waste heat 193 and load diagrams 205 boilers 218 exchangers 207 quality 194 source 194 survey 201 waterwall steam generator 491

water storage 531 tank 479 water treatment 272 watt-hour meters 343 transducers 343 wattmeter 25, 428 watt (W) 400 WECS 489 wet-side economizer 272 WHAT IF motor comparison form 297 whole-building approach 732 wind characteristics 486 wind devices 485 wind energy 484 aerodynamic efficiency 485 availability 484 conversion system 488 loadings and acoustics 489 power coefficient Cp. 485 power density 484 systems 471 wind speed 488 wind Systems 486 wind up 583 workplane 400 X xpanded perlite 441 Y yearly scheduling 319