the opportunity for chp in the united states€¦ · the opportunity for chp in the united states...

The Opportunity for CHP in the United States

May 2013 Prepared for: American Gas Association Washington, DC

Prepared by: ICF International Bruce Hedman Anne Hampson Ken Darrow

NOTICE

In funding, issuing or making this publication available,neither ICF nor AGA is undertaking to render professional or other services for or on behalf of any person or entity. Nor is either undertaking to perform any duty owed by any person or entity to someone else. Anyone using this document should rely on his or her own independent judgment or, as appropriate, seek the advice of a competent professional in determining the exercise of reasonable care in any given circumstances. The statements in this publication are for general information and represent an unaudited compilation of statistical information that could contain coding or processing errors. Neither ICF nor AGA makes any warranties, express or implied, nor representations about the accuracy of the information in the publication or its appropriateness for any given purpose or situation. This publication shall not be construed as including, advice, guidance, or recommendations to take, or not to take, any actions or decisions in relation to any matter, including without limitation, relating to investments or the purchase or sale of any securities, shares or other assets of any kinds. Should you take any such action or decision, you do so at your own risk. Information on the topics covered by this publication may be available from other sources, which the user may wish to consult for additional views or information not covered by this publication.

Joint Copyright © 2013 ICF International, LLC. and American Gas Association. All Rights Reserved.

i

Table of Contents Executive Summary .................................................................................................................................. ES-1

Introduction .................................................................................................................................................. 1

History of CHP Development in U.S. ............................................................................................................. 4

Characteristics of Existing CHP in the U.S. .................................................................................................... 8

Emerging Drivers for CHP ............................................................................................................................ 17

Recent CHP Market Trends ......................................................................................................................... 25

Market Environment ................................................................................................................................... 26

Primary CHP Market Participants ............................................................................................................... 28

Market Opportunities for CHP .................................................................................................................... 29

Economic Potential for CHP ........................................................................................................................ 35

Natural Gas and Electric Utility Participation in CHP .................................................................................. 42

Conclusions & Recommendations .............................................................................................................. 46

Appendix A: Existing CHP in the United States ........................................................................................ A-1

Appendix B: CHP Technical Potential Methodology ................................................................................. B-1

Appendix C: CHP Economic Potential Methodology ................................................................................. C-1

Appendix D: CHP Potential Tables by Payback Category, Market, and Scenarios ................................... D-1


ES-1

Executive Summary

Combined Heat and Power (CHP) or cogeneration, which is the generation of electricity or mechanical power and useful thermal energy from a single source of energy at the point of use, provides a number of potential benefits for the United States in terms of increased energy efficiency, lower greenhouse gas and other emissions, economic competitiveness, and energy resiliency. CHP has been in use in the United States in some form or another for more than 100 years. Currently, 82 gigawatts (GW) of CHP capacity is in use at more than 4,100 sites across the United States. Seventy-one percent of existing CHP capacity is fueled by natural gas, resulting in approximately 4.5 Tcf of annual consumption accounting for approximately 18% of annual natural gas demand. Estimates on the untapped potential of CHP in the United States vary considerably depending on how “potential” is defined and calculated. While investment in CHP applications has remained low since 2005, recent market activity suggests the potential for a rebound in CHP development powered by three critical drivers:

1. the changing outlook for natural gas supply and price 2. environmental regulatory pressures on power plants and industrial boilers, and 3. growing federal and state policymaker support.

The American Gas Association engaged ICF International to conduct a market assessment of CHP potential with a focus on the impact it could have on the natural gas utility industry. This report provides a fresh look at historical CHP activity, the current market environment, and the potential for future CHP. It is intended to provide high level, directional information that can be used to help the industry and individual companies evaluate the resources and areas of focus that should be directed towards CHP market development. The process for evaluating the potential for new CHP begins with identifying facilities or sites that possess the energy load characteristics and requirements that are technically conducive for CHP applications. The technical potential for additional CHP applications at existing industrial, commercial, and institutional facilities is large, at approximately 130 GW. However, this represents an upper bound and does not consider capital costs, regulatory barriers, policy uncertainty, market conditions, and other factors impacting the feasibility of CHP system investments that can affect the market potential for CHP. Consumer perceptions and tolerance for risk is another critical element. Past analysis has shown that potential industrial CHP candidates have low risk tolerance – less than 50% of potential CHP candidates view a two year payback as acceptable for a CHP project. This report includes an analysis of the impact of economic considerations on the technical potential of the CHP market, but does not estimate the impacts of consumer acceptance rates on market potential. The analysis in this report focused on CHP systems below 100 megawatts (MW) in the industrial, commercial, institutional, and multi-family residential market sectors. It was assumed that systems below this capacity would most likely be connected to the local natural gas distribution company. The technical potential for the CHP systems below the 100 MW threshold is approximately 56 GW of additional industrial CHP installations, and 68 GW of commercial or institutional CHP potential, for a total of 124.7 GW of additional capacity. Therefore, system sizes examined in this report represent approximately 95% of the total technical potential for CHP systems.


ES-2

In order to gain a clearer picture of the market potential of CHP systems that could achieve a realistic economic feasibility threshold, a high-level economic analysis for each CHP system size range (< 1 MW, 1 to 5 MW, 5 to 20 MW, 20 to 50 MW, 50 to 100 MW) was developed using state average electricity and natural gas rates and typical CHP equipment cost and performance characteristics. Simple paybacks were calculated for the five CHP system size categories and three CHP system categories

CHP with heating only - High load factor applications

CHP with heating and cooling - Incremental high load factor applications

CHP with heating and cooling - Low load factor applications

The payback calculation was conducted for each state and the potential in terms of MWs was categorized into three payback categories representing the degree of economic potential:

Strong potential – simple payback less than 5 years

Moderate potential – simple payback 5 to 10 years

Minimal potential – simple payback more than 10 years

Table ES-1 presents the results of the economic potential analysis described above based on current state electricity and natural gas prices and equipment cost and performance. As shown, 6,355 MW of the technical potential that was modeled of 123,3001 MW had paybacks less than 5 years located in twelve states: Alaska, California, Connecticut, Florida, Hawaii, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, Texas and Vermont. Thirty six states had 41,612 MW with paybacks less than 10 years. Fourteen states and the District of Columbia had little or no potential, having paybacks greater than 10 years.

1 The total technical potential for CHP <100 MW as shown in Tables 7 and 8 is 124.7 GW, however 1,420.5 MW of

low load factor CHP applications was not included in the economic modeling because of their low likelihood of appearing economic. Therefore, the amount of CHP technical potential that was modeled for economics was 123.3 GW.


ES-3

Table ES-1 Economic Potential for CHP Units Less than 100 MW – Base Case

Using the above analysis as a base case, several scenarios were then developed and analyzed to evaluate the effect of changes in capital costs, electricity prices, and natural gas prices on the paybacks and resulting levels of economic potential.

The first scenario modeled a 25 percent reduction in CHP equipment costs from the base case. This scenario could be reflective of capital cost incentives similar to those implemented in states such as New Jersey, California, Maryland and New York. In this case, the strong potential category increased to 16,467 MW with Louisiana, Tennessee, Georgia, Maryland, Alabama, Mississippi and Delaware added to this category. Thirty nine states had 37,878 MW with paybacks in the 5 to 10 years range. Ten states and the District of Columbia continued to have little or no economic potential under this scenario.

The second scenario modeled a 15 percent increase in average electricity prices. This scenario could represent the impact of coal plant closings and planned electricity transmission and distribution investments in certain regions of the country. In this case, the strong potential category increased to 17,419 MW with Nebraska added to this category compared to the capital cost reduction case. Forty three states had 45,278 MW of potential with paybacks in the 5 to 10

Minimal

Potential,

Payback

>10 yrs

Moderate

Potential,

Payback

5-10 yrs

Strong

Potential,

Payback

<5yrs

Minimal

Potential,

Payback

>10 yrs

Moderate

Potential,

Payback

5-10 yrs

Strong

Potential,

Payback

<5yrs

Alabama 1,512 416 0 1,928 Missouri 2,532 0 0 2,532

Alaska 0 52 130 181 Montana 343 0 0 343

Arizona 1,561 134 0 1,695 Nebraska 718 26 0 744

Arkansas 1,384 0 0 1,384 Nevada 999 0 0 999

California 2,807 8,283 735 11,826 New Hampshire 0 497 74 571

Colorado 1,211 208 0 1,419 New Jersey 1,159 2,301 341 3,801

Connecticut 0 796 621 1,417 New Mexico 493 76 0 569

Delaware 254 144 0 398 New York 0 5,993 3,367 9,360

Dist of Columbia 321 0 0 321 North Carolina 3,726 632 0 4,358

Florida 2,541 2,098 104 4,744 North Dakota 324 0 0 324

Georgia 3,256 555 0 3,811 Ohio 5,951 0 0 5,951

Hawaii 77 212 86 376 Oklahoma 1,295 0 0 1,295

Idaho 469 0 0 469 Oregon 1,472 0 0 1,472

Ill inois 4,626 727 0 5,354 Pennsylvania 4,972 1,143 0 6,115

Indiana 2,705 0 0 2,705 Rhode Island 203 198 35 436

Iowa 1,573 0 0 1,573 South Carolina 1,962 386 0 2,348

Kansas 1,126 96 0 1,222 South Dakota 332 0 0 332

Kentucky 1,607 932 0 2,539 Tennessee 2,143 594 0 2,737

Louisiana 1,864 658 0 2,523 Texas 5,716 1,836 384 7,935

Maine 582 237 0 820 Utah 881 0 0 881

Maryland 1,450 306 0 1,756 Vermont 0 282 12 293

Massachusetts 282 2,078 466 2,826 Virginia 2,570 490 0 3,060

Michigan 3,605 803 0 4,408 Washington 2,201 0 0 2,201

Minnesota 2,230 327 0 2,557 West Virginia 545 244 0 789

Mississippi 1,086 274 0 1,360 Wisconsin 2,859 1,114 0 3,973

Wyoming 166 110 0 275

U.S. Total 81,691 35,257 6,355 123,303

Total

Technical

Potential

State

Technical Potential by Payback

Range, MWTotal

Technical

Potential

State


Range, MW


ES-4

years range. Six states and the District of Columbia continued to have little or no economic potential under this scenario.

The third scenario modeled a 10 percent decrease in natural gas prices. This scenario could represent the impact of further increases in the supply of North American natural gas. In this case, the strong potential category increased to 8,694 MW, and the moderate potential category increased to 37,622 MW.

The results of the base case analysis and the three scenarios were converted from potential expressed in MW capacity to potential expressed in gross natural gas demand and incremental natural gas demand. Gross natural gas demand was based on the total amount of natural gas consumed for the CHP systems. Incremental natural gas demand was calculated using the assumption that the thermal energy captured from the CHP system displaced natural gas demand from natural gas boilers. Figure ES-1 shows the annual and incremental natural gas consumption potential for the CHP systems achieving less than a 10 year payback for the four cases.

Figure ES-1: Impact of Scenarios on Potential Gas Consumption for CHP Units Less than 100 MW (Gas Consumption for Strong and Moderate Economic Potential combined)

The analysis and findings presented are intended to create a better informational foundation for the natural gas industry, and in particular for local distribution companies, to understand CHP opportunities and to inform the level and nature of industry involvement in developing this market. Proactive involvement in CHP market development by the natural gas industry could serve to reduce project risks, increase market acceptance, and promote the deployment of efficient cost-effective CHP. Potential support the industry could provide for CHP market development includes:

Customer Outreach – Lack of awareness of CHP and the savings it can provide to a user continues to be a significant barrier to CHP development, particularly with emerging CHP


ES-5

markets in the commercial and institutional sectors. LDCs can leverage their access to and relationship with potential CHP users to increase their understanding of CHP and its potential to help their bottom lines.

Feasibility Studies – LDCs could conduct or support initial feasibility studies to further reduce the risks to potential customers. Many users unfamiliar with CHP need assistance in taking the initial steps in determining whether CHP makes economic sense in their facility. LDCs could supply the technical guidance or initial analysis to start them on the evaluation process, and provide technical support as they proceed through project development.

Financing – Providing low cost financing or facilitating access to financing can help increase market acceptance by improving economic feasibility and lowering perceived risks by the user. Financing support can range from on-bill financing of capital cost to leasing of CHP equipment or to direct asset ownership by the LDC. Industrial customers, in particular, have indicated that they are interested in mechanisms that would keep CHP project investments off of the balance sheet.

CHP Policy Advocacy – the gas industry should stay closely involved in monitoring, intervening, and commenting on regulatory proceedings that will affect CHP, including advocacy at the national and state levels.

Targeted CHP Project Development – LDCs could seek to develop and financially support the development of CHP projects to the extent allowed by state regulatory rules.


1

Introduction

Combined heat and power (CHP), also known as cogeneration, is an efficient and clean approach to generating electricity or mechanical power and useful thermal energy from a single fuel source at the point of use. Instead of purchasing electricity and then burning fuel in an on-site furnace or boiler to produce thermal energy, an industrial or commercial facility can use CHP to provide these energy services in one energy-efficient step. As a result, CHP can provide significant energy efficiency and environmental advantages over separate heat and power. For optimal efficiency, CHP systems typically are designed and sized to meet the users’ thermal baseload demand. CHP technology can be deployed quickly, cost-effectively, and with few geographic limitations. CHP systems are located at or near end-users, and therefore defer or reduce construction of new transmission and distribution (T&D) infrastructure. While the traditional method of producing separate heat and power has a typical combined efficiency of 45 percent, CHP systems can operate at efficiency levels as high as 80 percent (see Figure 1 for an example). CHP’s high efficiency results in less fuel use and lower levels of greenhouse gases emissions. CHP in the United States today avoids more than 1.9 Quadrillion Btus of fuel consumption and 248 million metric tons of CO2 emissions when compared to traditional separate production of electricity and heat2. This CO2 reduction is the equivalent of removing more than 45 million cars from the road.

The efficinecy of a CHP system varies based on its application and other factors. In the example below of a typical CHP system, to produce 75 units of useful energy, the separate heat and power systems use 154 units of energy—98 for electricity production and 56 to produce heat—resulting in an overall efficiency of 49 percent. However, the CHP system needs only 100 units of energy to produce the 75 units of useful energy from a single fuel source, resulting in a total system efficiency of 75 percent.

2 Oak Ridge National Laboratory. “Combined Heat and Power: Effective Energy Solutions for a Sustainable Future.”

December 2008.


2

Figure 1: Increased Efficiency of CHP Results in Carbon Emissions Savings

Source: ICF data. Graphic created by AGA

The size of CHP systems can range from 1 kW (the demand of a single-family home) to several hundred MW (the demand of a large petroleum-refining complex). Due to this size flexibility, CHP can be utilized in a variety of applications. Eighty-seven percent of current U.S. CHP capacity is found in industrial applications, providing power and steam to large industries such as chemicals, paper, refining, food processing, and metals manufacturing. CHP in commercial and institutional applications is currently 13 percent of existing capacity, providing power, heating, and cooling to hospitals, schools, campuses, nursing homes, hotels, and office and apartment complexes3. CHP can be configured either as a topping or bottoming cycle. In a typical topping cycle system, fuel is combusted in a prime mover such as a gas turbine or reciprocating engine to generate electricity. Energy normally lost in the prime mover’s hot exhaust and cooling systems is instead recovered to provide heat for industrial processes (such as petroleum refining or food processing), hot water (e.g., for laundry or dishwashing), or for space heating, cooling, and dehumidification. In a bottoming cycle system, also referred to as “waste heat to power,” fuel is combusted to provide thermal input to a furnace or other industrial process and heat rejected from the process is then used for producing power. CHP is a commercially available clean energy solution that directly addresses a number of national priorities including improving the competitiveness of U.S. manufacturing, increasing energy efficiency, reducing emissions, enhancing energy infrastructure, improving energy security and growing the economy. While CHP has been in use in the United States in some form or another for more than 100 years, it remains an underutilized resource today. As shown in Figure 2, CHP currently represents approximately 8 percent of U.S. generating capacity compared to over 30 percent in countries such as Denmark, Finland and the Netherlands. Its use in the U.S. has been limited, particularly in recent years, by a host of market and non-market barriers. Nevertheless, the outlook for increased use of CHP is bright -- policymakers at the federal and state level are beginning to recognize the potential benefits of CHP and

3 CHP Installation Database. Maintained by ICF International for Oak Ridge National Laboratory and the US

Department of Energy. 2010. http://www.eea-inc.com/chpdata/index.html

http://www.eea-inc.com/chpdata/index.html


3

the role it could play in providing clean, reliable, cost-effective energy services to industry and businesses. CHP can provide a cost-effective source of highly-efficient new generating capacity, and the economics of CHP are further improving as a result of the changing outlook in the long-term supply and price of North American natural gas – a preferred fuel for many CHP applications.

Figure 2: CHP as a Percentage of National Generating Capacity


4

History of CHP Development in U.S.

Decentralized CHP systems located at industrial and municipal sites were the foundation of the early electric power industry in the United States. However, as power generation technologies advanced, the power industry began to build larger central station facilities to take advantage of increasing economies of scale. CHP became a limited practice utilized by a handful of industries (paper, chemicals, refining and steel) which had high and relatively constant steam and electric demands and access to low-cost fuels. By the 1970s, the U.S. electricity market was dominated by mature, regulated electric utilities using large, power-only central station generating plants. As a result of this competitive position, utilities had little incentive to encourage customer-sited generation, including CHP. Further, a host of regulatory barriers at the state and federal level served to further discourage broad CHP development4.

Public Utilities Regulatory Act Partly in response to the oil crisis, in 1978, Congress passed the Public Utilities Regulatory Policies Act (PURPA) to encourage greater energy efficiency. PURPA provisions encouraged energy efficient cogeneration5 and small power production from renewables by requiring electric utilities to interconnect with "qualified facilities" (QFs). Cogeneration or CHP facilities had to meet minimum fuel-specific efficiency standards6 in order to become a QF. PURPA required utilities to provide QFs with reasonable standby and back-up charges, and to purchase excess electricity from these facilities at the utilities’ avoided costs.7 PURPA also exempted QFs from regulatory oversight under the Public Utilities Holding Company Act and from constraints on natural gas use imposed by the Fuel Use Act. Shortly after enacting PURPA, Congress also provided tax credits for investments in cogeneration equipment under the Energy Tax Act of 1978 (P.L. 95-618; 96-223) and the Crude Oil Windfall Profits Tax Act of 1980 (P.L. 96-223; 96-471). The Energy Tax Act included a 10 percent tax credit on waste-heat boilers and related equipment, and the Windfall Profits Tax Act extended the 10 percent credit to remaining CHP equipment for qualified projects8. The Windfall Profits Act limited the amount of oil or natural gas that a qualifying facility could use9. The implementation of PURPA and the tax incentives were successful in dramatically expanding CHP development; installed capacity increased from about 12,000 MW in 1980 to over 66,000 MW in 200010. While PURPA promoted CHP development, it also had unforeseen consequences. PURPA was enacted at the same time that larger, more efficient, lower-cost combustion turbines and combined cycle systems became widely available. These technologies were capable of producing greater amounts of power in proportion to useful thermal output compared to traditional boiler/steam turbine CHP systems. Therefore, the power purchase provisions of PURPA, combined with the availability of these new

4 “Combined Heat and Power: Effective Energy Solutions for a Sustainable Future”, Oak Ridge National Laboratory,

ORNL/TM-2008/224, December 2008. 5 The terms “cogeneration” and “combined heat and power” both refer to the simultaneous generation of

electricity or mechanical power and useful thermal from a single source and are used interchangeably in this report. 6 Efficiency hurdles were higher for natural gas CHP.

7 Avoided cost is the cost an electric utility would otherwise incur to generate power if it did not purchase

electricity from another source. 8 “Energy Tax Policy: Historical Perspectives on the Current Status of Energy Tax Expenditures” Congressional

Research Service, May 2011. 9 Gary Fowler, Albert Baugher and Steven Jansen, “Cogeneration”, Illinois Issues, Northern Illinois University,

December 1981. 10

CHP Installation Database developed by ICF International for Oak Ridge National Laboratory and the U.S. DOE; 2012. Available at http://www.eea-inc.com/chpdata/index.html.


5

technologies, resulted in the development of very large merchant plants designed for high electricity production.

For the first time since the inception of the power industry, non-utility participation was allowed in the U.S. power market, triggering the development of third-party CHP developers who had greater interest in electric markets than thermal markets. As a result, the development of large CHP facilities paired with industrial facilities increased dramatically; today almost 65 percent of existing U.S. CHP capacity—53,000 MW—is concentrated in plants over 100 MW in size11. Figure 4 shows the cumulative growth of CHP capacity in the U.S. since 1950, highlighting the rapid increase in growth starting in the late 1980s. This data is broken down further in Figure 3, which shows the annual capacity additions between 1960 and 2011. Figure 4 highlights the large amount of CHP capacity installed in systems greater than 100 MW beginning in the late 1980s and continuing through the mid-2000s. A preliminary analysis of the approximately 900 CHP systems in the ICF installation database larger than 10 MW indicates that 40 to 50 percent of the CHP systems that are 100 MW or larger are connected directly to inter or intrastate pipelines; only 20 to 30 percent of systems between 50 to 100 MW are directly connected to inter or intrastate pipelines, and less than 15 percent of systems between 10 and 50 MW are directly connected to pipelines.

Figure 3: CHP Cumulative Capacity Growth by Application Type in the U.S.

Source: ICF CHP Installation Database, 2012

11

Ibid.


6

Figure 4: Annual CHP Capacity Additions from 1960 to 2011


Competitive Power Markets The environment for CHP changed again in the early 2000s with the advent of restructured wholesale markets for electricity in several regions of the country. Independent power producers (IPP) could now sell directly to the market without the need for QF status. CHP capacity increased rapidly from 2000 to 2005 as shown in Figure 3 as many of these large IPP projects relied on thermal sales to adjacent industrials to enhance project economics in the wholesale market.

At the same time, utilities continued to oppose the mandatory purchase requirements of PURPA which, they claimed, forced them to buy power they did not need or could not use. Further, they argued that developments in the industry, such as standardized interconnection procedures, open access tariffs and established energy markets, have removed the obstacles that PURPA was originally designed to eliminate. Congress responded to these complaints in the Energy Policy Act of 2005 (EPAct 2005) by adding a new PURPA Section 210(m) which allows utilities to terminate their obligation to purchase power from any QF over 20 MW that has nondiscriminatory access to certain wholesale markets. Section 210(m) applies only to new contracts or obligations, leaving existing contracts intact. In 2006, FERC issued a Final Rule (Order No. 688) establishing the process by which utilities could apply for termination approval. FERC found that that the six existing Regional Transportation Organizations (RTOs) and the Electric Reliability Council of Texas provided the necessary access to wholesale energy markets described in Section 210(m)12. In their applications to FERC, utilities located in those designated regions

12

RTOs and Independent System Operators (ISO) grew out of FERC Orders Nos. 888/889 where the Commission suggested the concept of an Independent System Operator as one way for existing tight power pools to satisfy the requirement of providing non-discriminatory access to transmission. The seven RTO/ISOs in the United States include the California ISO (CASIO), the Southwest Power Pool (SPP), the Midwest ISO (MISO), the PJM


7

can rely on a rebuttable presumption that QFs greater than 20 MW have nondiscriminatory access to wholesale markets. FERC gave QFs the opportunity to rebut this presumption and illustrated the kind of evidence needed to make this showing. For example, a QF could present evidence that its highly variable thermal or electric demand prevents it from effectively participating in the market. Alternatively, the QF may lack access to the scheduling mechanisms necessary to make advanced sales on a consistent basis, or transmission constraints may prevent the QF from being able to deliver energy to the market. FERC determines on a case-by-case basis whether the QF presented sufficient evidence to demonstrate a lack of market access.

Market Uncertainty The movement toward restructuring (deregulation) of power markets in individual states also caused market uncertainty, resulting in delayed energy investments. These changes also coincided with rising and increasingly volatile natural gas prices as the supply and demand balance in the U.S. tightened. As a result, CHP development slowed precipitously in the 2004/2005 timeframe (see Figure 5). At that point, a combination of highly volatile natural gas prices, continuing market barriers and an uncertain economic outlook led to a steep decline in CHP installations that persisted through 2011.

Figure 5: CHP Capacity Additions Since 2000


While recent investment in CHP has declined, CHP’s potential role as a clean energy source for the future may be much greater than recent market trends would indicate. Like other forms of energy efficiency, efficient on-site CHP represents a largely untapped resource that exists in a variety of energy-intensive industries and businesses. Recent estimates indicate the technical potential13 for additional

Interconnection (PJM), the New York ISO (NYISO), the New England ISO (ISO-NE) and the Electricity Reliability Council of Texas (ERCOT) 13

The technical market potential is an estimation of market size constrained only by technological limits—the ability of CHP technologies to fit existing customer energy needs. The technical potential includes sites that have the energy consumption characteristics that could apply CHP. The technical market potential does not consider screening for other factors such as ability to retrofit, owner interest in applying CHP, capital availability, fuel availability, and variation of energy consumption within customer application/size classes. All of these factors


8

CHP at existing industrial facilities is just below 65 GW, with the corresponding technical potential for CHP at commercial and institutional facilities at just over 65 GW14, for a total of about 130 GW. A 2009 study by McKinsey and Company estimated that 50 GW of CHP in industrial and large commercial/institutional applications could be deployable at reasonable returns with then current equipment and energy prices15. These estimates of both technical and economic potential are likely greater today given the improving outlook in natural gas supply and prices.

Characteristics of Existing CHP in the U.S.

CHP is an important electric generating resource in the United States; about 82 gigawatts (GW) of existing CHP generation capacity at over 4,100 facilities represents over 8 percent of total U.S. power generation capacity.16 CHP represents over 12 percent of annual U.S. power generation, reflecting the longer operating hours of CHP assets. CHP can be utilized in a variety of applications that have significant and coincident, power and thermal loads. Figure 6 shows the sectors currently using CHP - eighty seven percent of existing CHP capacity is found in industrial applications, providing power and steam to energy intensive industries such as chemicals, paper, refining, food processing, and metals manufacturing. CHP in commercial and institutional applications is currently 13 percent of existing capacity, providing power, heating and cooling to hospitals, schools, university campuses, hotels, nursing homes, office buildings and apartment complexes.

Figure 6: Existing CHP Capacity in the United States


affect the feasibility, cost and ultimate acceptance of CHP at a site and are critical in the actual economic implementation of CHP 14

Based on ICF International internal estimates as detailed in “Effect of a 30 Percent Investment Tax Credit on the Economic Market Potential for Combined Heat and Power”, report prepared for WADE and USCHPA, October 2010. These estimates are on the same order as recent estimates developed by McKinsey and Company in “Unlocking Energy Efficiency in the U.S. Economy”, July 2009 15

McKinsey and Company, “Unlocking Energy Efficiency in the U.S. Economy”, July 2009 16




9

CHP installations in the U.S. use a diverse mix of fuels, with natural gas being the most common fuel. Seventy one percent of existing CHP capacity is fueled by natural gas, representing approximately 4.5 Tcf of annual gas demand (an estimated 2.2 Tcf of incremental gas demand over the gas that would have been consumed by onsite boilers or furnaces in the absence of CHP). Coal and process wastes make up the remaining fuel mix (15 and 9 percent respectively), followed by biomass, wood, oil, and other waste fuels. There has been increased interest in biomass and waste fuels in recent years as policymakers and consumers seek to use more renewable fuel sources. Figure 7 shows the breakdown of existing CHP capacity by fuel type.

Figure 7: Existing CHP Capacity by Fuel Type


The prominent use of natural gas as a fuel for CHP in the United States is driven by the extensive use of gas turbine and combined cycle (gas turbine/steam turbine) systems. Figure 8 shows that combined cycles and simple cycle gas turbines represent 50 and 13 percent of existing CHP capacity respectively. Boiler/steam turbine systems represent 34 percent of total CHP capacity and are primarily fueled by solid fuels such as coal and wood waste. Reciprocating engines, fueled by natural gas, represent 3 percent of CHP capacity in the United States. Together, microturbines (small, recuperated gas turbines in the 60 to 250 kW size range), fuel cells and other technologies such as organic Rankine cycles represent less than one percent of installed CHP capacity. Figure 9 shows the market share of CHP technologies based on the number of installations. Reciprocating engines are the primary technology of choice, used in 51 percent of existing CHP systems in the United States. Emerging technologies such as fuel cells and microturbines are used in 11 percent of existing CHP systems in the United States.


10

Figure 8: U.S. CHP Capacity by Technology Figure 9: U.S. CHP Sites by Technology

(81,800 MW) (4,100 Sites)


There are significant regional differences in the distribution of CHP sites and capacity due to economic activity, relative electric and fuel rates, and the prevailing market and regulatory environment. Some states are far ahead of others in terms of adopting policies that encourage CHP growth, most notably New York, Massachusetts, California, Rhode Island, and Connecticut, which offer financial and other incentives to CHP. Other regional variations can be traced to industrial development. For example, chemicals and refining are common in the Gulf Coast states and paper production in the Southeast. The map in Figure 10 illustrates the states with the highest amount of CHP capacity, with dark blue states each having more than 2 GW of installed CHP capacity.

Figure 10: Existing CHP Capacity by State17


17




11

Figures 11 and 12 profile existing CHP capacity below 100 MW in size. As noted earlier, this segment of the market is more likely to remain directly connected to local distribution companies. Commercial applications represent 28 percent of the 28,200 MW of existing CHP capacity in this size range. As shown in Figure 14, natural gas is used by 50 percent of the capacity in this size range, representing an annual natural gas load of approximately 1.1 Tcf. Figure 11: CHP Systems < 100 MW in Size Figure 12: CHP Systems < 100 MW in Size

(Sectors) (Fuels)


Industrial CHP Applications The industrial sector includes manufacturing industries (food, paper, chemicals, refining, iron and steel, nonferrous metals, and nonmetallic minerals, among others) and nonmanufacturing industries (agriculture, mining, and construction). Chemicals and refining, iron and steel, nonmetallic minerals, paper, and nonferrous metal manufacturing account for the majority of U.S. industrial energy consumption. Industrial energy demand varies across states depending on industry mix and economic activity. Energy is consumed in the industrial sector for a wide range of activities, such as processing and assembly, space conditioning, and lighting. Industrial CHP installations in the U.S. are typically large (average system size is 52.5 MW) and represent 87 percent of total installed national capacity (Figure 6). As shown in Figures 13 and 14, existing CHP in the industrial sector is concentrated in energy intensive industries such as chemicals, refining, paper, primary metals, and food processing, that have large and coincident electric and steam demands. Installation of large (greater than 20 MW) CHP systems in this sector has been limited in recent years, but market activity is increasing as natural gas rates have declined in many regions. There is also increasing interest in biomass and other alternative fuels.


12

Figure 13: Industrial CHP Sites Figure 14: Industrial CHP Capacity

(1,800 Sites) (70,800 MW)


Tables 1 and 2 and the discussion below profile existing CHP in key industrial markets18:

Chemicals – The chemicals industry is comprised of a wide variety of plants and processes providing a diverse array of commodity and specialty chemical products. CHP is extensively used in certain segments of the chemicals industry such as plastic materials and resins, basic inorganic and organic products and commodity chemicals such as alkali and chlorine. These segments are highly energy intensive with large steam process loads. CHP systems in these applications tend to be based on large gas turbine or combined cycle systems, many owned and/or operated by third party entities that sell steam and power to the industrial facility and excess power to the grid. Growth opportunities appear in smaller CHP systems based on gas turbine and reciprocating engines that can be used in less energy intensive segments such as ethanol, pharmaceuticals and consumer products (soaps, detergents, etc.). Existing CHP in this market is heavily based on natural gas (80 percent of CHP capacity). Coal and process wastes are secondary CHP fuels used primarily in boiler/steam turbine systems.

Refining – Most large refineries in the U.S. currently utilize CHP to provide a portion of their process steam and power needs and to enhance energy reliability. Ninety percent of existing CHP in the refining sector is natural gas, and like chemicals, is dominated by large combined cycle and simple cycle gas turbine systems. Growth opportunities may exist in refineries planning expansions and upgrades.

Paper – The paper industry has long used CHP to supply its extensive steam and power demands. Large pulp and paper mills tend to be self-sufficient in energy, utilizing wood waste and black liquor recovery, sometimes supplemented with coal in boiler/steam turbine CHP systems. Smaller plants and recycled pulp mills have installed natural gas CHP systems based on gas turbine technology.

Food Processing – Food processing comprises a wide variety of plants and process ranging from local dairies to large wet mill corn processing facilities that resemble chemical plants. Natural gas is the preferred fuel for CHP in this sector (68 percent of existing capacity) unless the plant has processing waste available or is used to handling large amounts of solids in their operations. Expanding markets for

18

Detailed tables of existing CHP can be found in Appendix A


13

CHP include animal/poultry slaughtering, flour and rice milling, breweries, soft drink manufacturing, animal food manufacturing, fruit and vegetable canning, fluid milk, beet sugar, soybean processing and cereal manufacturing.

Primary Metals – While natural gas represents 51 percent of existing CHP capacity in the iron and steel industry, this segment also uses a variety of process waste (blast furnace gas, coke oven gas, waste heat) to provide steam and power at its facilities. Natural gas is used more frequently in non-integrated mills where process wastes are not as available.

Transportation – Automobile and truck manufacturers and their suppliers have started to utilize CHP more frequently to provide steam and power needs. Natural gas currently accounts for 88 percent of existing CHP capacity in this segment.

Table 1: Key Industrial CHP Markets

Market Total CHP

MW Number of CHP Sites

Percentage Capacity

Natural Gas

Primary Fuel Other than Natural Gas

Primary Technology in Terms of MW

Primary Technology in Terms of Sites

Chemicals 24,321 274 80% Coal Combined

Cycle Boiler/Steam

Turbine

Refining 15,015 107 90% Process Gas Combined

Cycle Gas Turbine

Paper 11,352 231 41% Coal/Black

Liquor Boiler/Steam

Turbine Boiler/Steam

Turbine

Food Processing 6,267 246 68% Coal/Biomass Combined

Cycle Reciprocating

Engine

Primary Metals 3,923 52 51% Process Gas Boiler/Steam

Turbine Boiler/Steam

Turbine

Enhanced Oil Recovery

2,735 100 95% N/A Gas Turbine Gas Turbine

Transportation Manufacturing

1,218 22 88% Process Waste Combined

Cycle Gas Turbine

Table 2: Key Industrial CHP Markets

Market < 5 MW 5 – 20 MW 20 – 100 MW >100 MW

Sites MW Sites MW Sites MW Sites MW

Chemicals 102 209 43 412 64 2,986 65 20,715

Refining 18 44 20 174 37 1,841 32 12,956

Paper 33 89 41 438 116 6,038 31 4,787

Food Processing 134 193 66 599 27 1,304 19 4,170

Primary Metals 19 26 9 76 18 1,008 6 2,813

Enhanced Oil Recovery 38 74 27 263 29 1,201 6 1,196

Transportation Manufacturing 9 18 6 62 5 194 2 944

Commercial CHP Applications CHP installations in commercial and institutional facilities make up 55 percent of CHP sites in the U.S., but account for only 13 percent of capacity (see Figure 6). This is due to the relative size of commercial facilities which are typically much smaller than industrial facilities (the average capacity of an industrial CHP system is 52.5 MW compared to 4.8 MW for commercial/institutional CHP). Commercial and


14

institutional applications (and light industrial) are seen as potential growth markets for CHP in the U.S. The U.S. Department of Energy and developers have both invested in technology improvements for these applications, focusing on increasing efficiency, incorporating new thermally activated technologies to provide both heating and cooling services, and integrating components and controls into cost effective packages. As shown in Figures 15 and 16, approximately 60 percent of existing commercial CHP capacity is used in colleges, hospitals, government facilities such as prisons, campuses and military bases, and in downtown district energy systems. Close to 40 percent of existing CHP is used in a wide variety of other commercial applications including hotels, schools, multi-family buildings, office buildings greater than 100,000 square feet in size, laundries, country clubs, health clubs, nursing homes, and other commercial facilities that use CHP to provide heating, cooling and power.

Figure 15: Commercial CHP Sites Figure 16: Commercial CHP Capacity

(2,300 Sites) (11,000 MW)


Tables 3 and 4 and the discussion below profile existing CHP in key commercial markets19: Colleges/Universities – Due to their large thermal loads and desire for reliable power, CHP is a good fit for colleges and universities. A number of college and universities use CHP to provide steam and some power to key campus facilities. Seventy-two percent of existing CHP for colleges and universities is natural gas-fired, and most institutions use a boiler/steam turbine or gas turbines. A number of college and university CHP systems have been designed to be able to run independepently of the grid. This has enabled colleges and universities to continue many of their normal operations during storm events, and has helped increase interest in the use of CHP in this market sector. District Energy (DE) – Due to the large need for thermal energy to deliver to adjacent buildings and facilities through a steam loop, district energy systems are a prime candidate for CHP. Most CHP systems used for district energy are boiler/steam turbine systems, or reciprocating engines. Seventy-four percent of existing CHP capacity for DE systems are natural gas fired. District energy systems make sense in areas with dense construction, where a steam loop can provide service to multiple cutomers, and in areas with space constraints where a central service provider makes more sense than individual boiler installations. Due to the efficiency and environmental benefits of CHP, some cities have begun to

19

Detailed tables of existing CHP can be found in Appendix A


15

encourage developers to consider the use of CHP as part of a district energy system in any new large-scale development plans. Hospitals/Health Care – hospitals, nursing homes and other healthcare facilities are good candidates for CHP based on their thermal loads and the need for reliable power. Most hospital CHP systems consist of gas turbines, and reciprocating engines, and 84 percent of existing hospital/healthcare CHP capacity is natural gas. Many healthcare CHP systems are designed so that they can operate independently of the grid, in case of weather events or other incidents that may cause grid outages. Interest in CHP at healthcare facilities, especially in densely populated areas that are more prone to natural disasters, has increased in recent years due mainly to CHP’s reliability benefits. Government Facilities – government complexes, prisons, waste water treatment, and criticial infrastructure facilities such as military bases are also good candidate sites for CHP systems. Most government CHP systems consist of combined cycle/gas turbine configurations or reciprocating engines. Natural gas is used to a lesser exent in these CHP applications as compared to other commercial markets, with 64 percent of capacity from natural gas-fired systems. CHP systems can help meet government objectives such as reducing greenhouse gas (GHG) emissions and can help operations remain up and running during emergency events, which is especially crucial at certain facilities such as military bases. Multi-Family – facilities are defined as those facilities with central hot water and space heating systems, and that have no submetering. Sized appropriately, CHP systems at multi-family residences such as co-op buildings and other residences, can meet all of the building’s steam and power needs. Ninety-nine percent of existing CHP capacity located at multi-family residences is natural gas. Most multi-family CHP systems are gas turbines and reciprocating engines. Office Buildings – CHP systems make sense at office buildings that are 100,000 sq ft and above in size, which have large enough thermal and power needs. Most CHP capacity at office buildings is natural gas-fired – 84 percent, and reciprocating engines are the primary technology being used. CHP systems are also commonly used in buildings that support business operations. For instance, a number of data centers now have CHP systems to ensure the continuity of business functions during grid outages. Hotels/Lodging – Most CHP systems located at hotels are smaller systems typically less than 5 MW and use natural gas-fired reciprocating engines. Ninety-six percent of hotel CHP capacity is from natural gas. Hotels commonly use CHP to provide hot water for guest use and laundry facilities. Larger hotels that have multiple restaurants, provide spa services and have heated swimming pools typically make the best candidates for CHP. Schools – CHP systems are increasingly common in schools. These CHP systems are small, less than 1 MW systems. Eighty-four precent of school CHP capacity is natural gas. Most schools use reciprocating engines. Since schools often serve as places of refuge for the community during storm events, CHP systems have become increasingly popular due to their ability to allow for the school to have lighting and other services during power outages.


16

Table 3: Key Existing Commercial CHP Markets

Market Total CHP

MW

Number of CHP Sites

Percentage Capacity Natural

Gas

Primary Fuel Other than Natural Gas

Primary Technology in Terms of MW

Primary Technology in Terms of Sites

Colleges/Universities 2,715 262 72% Coal Boiler/Steam

Turbine Gas Turbine

District Energy (downtown) 2,427 48 74% Coal Boiler/Steam

Turbine Reciprocating

Engine

Hospitals/Health Care 737 213 84% Waste Gas Turbine Reciprocating

Engine

Government 1,212 170 64% Coal/Waste Combined Cycle/

Gas Turbine Reciprocating

Engine

Multi-family 201 208 99% N/A Gas Turbine Reciprocating

Engine

Office Buildings 169 129 84% Waste Reciprocating

Engine Reciprocating

Engine

Hotels 125 130 96% Oil Reciprocating


Engine

Schools 72 248 84% Oil Reciprocating


Engine

Table 4: Key Existing Commercial CHP Markets

Market < 5 MW 5 – 20 MW 20 – 100 MW >100 MW

Sites MW Sites MW Sites MW Sites MW

Colleges/Universities 169 202 51 496 42 2,017 2 426

District Energy (downtown) 16 28 13 108 7 492 7 1,799

Hospitals/Health Care 180 224 27 235 6 278 0 0

Government 133 125 20 215 16 550 1 322

Multi-family 203 40 2 26 3 135 0 0

Office Buildings 122 97 6 44 1 28 0 0

Hotels 121 49 9 76 0 0 0 0

Schools 248 72 0 0 0 0 0 0


17

Emerging Drivers for CHP

While investment in CHP has remained low since 2005, recent market activity suggests the potential for a rebound in CHP development powered by three critical drivers:

CHANGING OUTLOOK FOR NATURAL GAS SUPPLY AND PRICE The United States is in the midst of a shale gas revolution that has been described as a “game changer” in terms of the near and long term supply outlook for natural gas. The revolution in recovering natural gas from shale formations is the result of large-scale application of horizontal drilling and hydraulic fracturing techniques in the shale development that began in the early 2000s.

The Barnett shale formation in Texas was one of the first to be tapped. Other large shale formations include the Haynesville shale in Louisiana, the Fayetteville shale in Arkansas, and (perhaps the largest) the Marcellus shale that extends southward from New York State, through Pennsylvania and into the Appalachian Mountains. As shown in Figure 17, the amount of shale gas supplied to the U.S. market has grown by a factor of 14 since 2005, displacing imports and more than offsetting declines in other North American production resources20. The development of shale gas has had a significant moderating effect on natural gas prices. Henry Hub prices in the five years prior to the recession averaged about $7.50/MMBtu; since 2008, Henry Hub gas prices have averaged about $4/MMBtu21. Continuing advancements in technology are driving reassessments of the long term gas outlook as analysts project more and more shale gas is economically recoverable at prices below $5 per MMBtu. Estimates of the natural gas resource base in North America that can be technically recovered using current exploration and production technologies now range from 2,000 to over 4,000 Tcf - enough natural gas to supply the United States and Canada for 100 to 150 years at current levels of consumption22. Henry Hub gas prices remain in the $4 to $7 range through 2030 in current EIA projections23; sufficient to support the levels of supply development in the projection, but not high enough to discourage market growth. Continuing moderate, and less volatile, gas prices will be a strong incentive for CHP market development. As detailed above, 72 percent of existing CHP capacity

20

ICF Internal estimates based on historical production data 21

See Figure 18 22

The lower limit is based on DOE’s natural gas resource estimate for the United States in EIA’s Annual Energy Outlook 2012; the upper limit is based on ICF International’s estimates of recoverable North American resources as of spring 2012 23

DOE Energy Information Administration, Annual Energy Outlook 2012

Figure 17: U.S. Natural Gas Supply

0

10

20

30

40

50

60

70

80

Ave

rage

Bcf

d

All Other Production Net Imports Shale Production


18

is fueled by natural gas, and the clean burning and low carbon aspects of natural gas will make it a preferred fuel for future CHP growth. Figure 18 shows ICF’s early-2013 natural gas price projection. While we believe robust growth in gas demand will eventually apply upward pressure on gas prices, we project prices to remain below $6 until post 2030. Our assessment is that $5 to $6 gas prices are sufficient to support the levels of supply development in an expanded consumption projection, but not so high as to discourage market growth.

Figure 18: Gas Prices at Henry Hub (2010 $/MMBtu)

ENVIRONMENTAL PRESSURES ON POWER PLANTS AND INDUSTRIAL BOILERS

Pressures on Utility Generation - There are a number of factors that have the potential to affect costs and investments in the power generation market. The changing economics of coal and natural gas generation over the past five years combined with an aging fleet and new United States Environmental Protection Agency (EPA) regulations that will require investments in pollution control technology at fossil-fired plants that currently are not controlled have put increased pressure on coal-fired electricity-generating plants. Recent projections of the total impact of an expected wave of coal plant retirements vary considerably, reflecting the variations in assumptions about commodity and energy markets; the decision-making behavior of the nation’s utilities; and the cost and stringency of new and future EPA regulations. Estimates of near-term nationwide closures range from 19 GW to 49 GW, which is about 2-5% of the total U.S. electric generating capacity24. While there is a fair amount of excess power generating capacity currently, in some regions the increase in power plant retirements may result in the need for new generation capacity sooner than would

24

DOE Energy Information Administration – 2012 Annual Energy Outlook


19

otherwise be required in order to maintain targeted reserve margins within regional electricity planning authorities. This could create upward pressure on electricity prices in regulated markets25. In addition, the retirement of individual units can require the need to assess more localized impacts on the grid in order to ensure continued maintenance of established reliability standards. These factors may create the need for new generation within regions most impacted by retirements, as well as to provide localized resources to ensure reliability over the coming years. This creates a significant opportunity for the development of new CHP to meet these needs, and could promote programs and policies that would promote customer-side investments in energy efficiency and CHP. As an example, ACEEE published a report in September 2012 that looked at the potential for increased energy efficiency that these retirements present, focusing especially on combined heat and power 26. The report evaluated twelve states that have high degrees of likely coal retirements and/or high degrees of CHP potential. For each of these states the report summarized the coal plant retirement situation as well as the technical and economic potential for new CHP. This report finds that while CHP will not be able to make up for all of the lost capacity due to coal retirements, it can meet a substantial amount of that capacity need in a highly cost-effective manner. This was especially true for states facing higher percentages of coal capacity retirements. The report concludes “though these retirements represent a small portion of the country’s electricity generation, they can be looked at as a unique opportunity to replace what were already rather inefficient and dirty electricity generation assets with cleaner, more cost-effective resources. The investment decisions made by utilities in the next few years will have ramifications for generations, because electricity generation assets tend to live long lives.” It should be noted, however, that in some cases it appears that the electric utility industry has been slow to acknowledge the benefits that customer-sited CHP represents in terms of resource planning and grid reliability. Pressures on End Users - Industrial and commercial boiler operators are also facing increasing environmental pressures. On December 20, 2012, the Environmental Protection Agency finalized rules setting air toxic standards for boilers, process heaters and certain solid waste incinerators (CIWSI) incinerators. EPA initially issued final rules for these units in March 2011, setting standards intended to cut emissions of hazardous air pollutants (HAPs) such as mercury, dioxin and lead. These pollutants can cause a range of dangerous health effects -- from developmental disabilities in children, to cancer, heart attacks and premature death. The final standards are expected to avoid up to 8,100 premature deaths, 5,100 heart attacks, and 52,000 asthma attacks. EPA estimates that less than one percent of the 1.5 million boilers in the United States would need to meet emissions limits under the final rules. About 183,000 of the boilers located at small sources of air emissions such as hotels, hospitals and commercial buildings would be covered by the Area Source Boiler Rule. Of these, over 99 percent would need to follow work practice rules such as periodic tune-ups. The remaining one percent (about 600 units) would have to meet specific emissions limits. EPA estimates that there are about 14,000 boilers at large sources of air emissions including refineries,

25

It should be noted that lower natural gas prices have resulted in lower electricity prices in many areas in the near term. However, many analysts believe the trend is for higher electricity prices over time. Central station power generation is no longer a declining cost industry – efficiencies have plateaued, equipment costs have increased, T&D costs are increasing and assets are more difficult to site. And any future national action on GHG emissions would seemingly increase the pressure on prices. 26 Anna Chittum, Coal Retirements and the CHP Investment Opportunity, ACEEE Report, September 2012, Report Number IE123 (ICF International provided the CHP market analysis for this report)

http://www.epa.gov/airquality/combustion/


20

chemical plants and some institutional facilities such as universities that would be covered by the Major Source Boiler MACT (maximum achievable control technology) Rule. Eighty-eight percent of these would need to follow work practice standards such as annual tune-ups. Twelve percent, about 1,750 boilers primarily fired by coal, oil and biomass, would need to meet specific emissions limits. See Table 1

for an overview of the new reconsidered proposals. Under the Commercial and Industrial Solid Waste

Incineration Unit MACT, the final rules affect 106 existing sources located at 6 facilities. While the final rule provides additional flexibility and expands the compliance options for many facilities with affected units, EPA is still estimating significant investment costs for affected coal and oil boilers. EPA estimates that for the December 2012 final rule, the capital costs for compliance for the existing 621 coal boilers will be $2.6 billion, at an average cost of $4.1 million per boiler. Annualized costs, including testing and monitoring, for the affected existing coal boilers are estimated at $904 million. Estimated capital costs for the 934 affected liquid fueled boilers are $1.5 billion, and average cost of $1.6 million. Annualized costs for the affected liquid units are $387 million. The EPA estimates the health benefits of these rules to range from $12 to $30 for every $1 spent to meet the proposed standards. To that end, DOE has joined EPA in an effort to help ensure that major sources burning coal and oil have information on alternative cost-effective clean energy strategies such as CHP for compliance with the Major Source Boiler MACT rule. DOE currently provides technical information on clean energy options to industry through its regional Clean Energy Application Centers27. DOE will supplement this effort to provide site-specific technical and cost information to the major source facilities that are currently burning coal or oil in their boilers when the reconsideration process is complete. This technical assistance effort is currently being piloted in Ohio and the program is about to be launched nationally based on the final rule.28 These impacted facilities may have opportunities to develop compliance strategies, such as natural gas CHP, which are cleaner, more energy efficient, and that can have a positive economic return for the plant over time. These opportunities can be considered alongside investment in pollution controls to comply with the standards in the rule. The ICI Boiler MACT represents a unique opportunity for natural gas CHP. Many of the facilities with affected coal and oil boilers are evaluating conversion to natural gas as an alternative to costly compliance investments. However, both options – investing in controls on the existing boilers or converting to natural gas - will result in increased steam costs for many facilities. Replacement of the affected boilers with a gas turbine CHP system can result in lower steam costs (when reduced purchases of power from the grid are credited) depending on the relative prices of purchased power and natural gas, albeit with an increase in capital expenditures compared to compliance or conversion. However, the overall investment in CHP can provide a return over time, while the investments in compliance or straight conversion will not. Table 5 presents an estimate of the total population of affected coal and oil boilers affected by the ICI Boiler MACT29. As shown, the units are located in a relatively concentrated population of facilities – 556 primarily industrial sites. The coal units specifically represent over 180,000 MMBtu/hr of input fuel capacity and a potential gas turbine CHP capacity of approximately 18,000 MW.

27

http://www1.eere.energy.gov/manufacturing/distributedenergy/ceacs.html 28

http://www.puco.ohio.gov/puco/index.cfm/industry-information/industry-topics/us-department-of-energy-pilot-program-for-combined-heat-and-power/ 29

Based on information from the Midwest Clean Energy Application Center

http://www1.eere.energy.gov/manufacturing/distributedenergy/ceacs.html

http://www.puco.ohio.gov/puco/index.cfm/industry-information/industry-topics/us-department-of-energy-pilot-program-for-combined-heat-and-power/

http://www.puco.ohio.gov/puco/index.cfm/industry-information/industry-topics/us-department-of-energy-pilot-program-for-combined-heat-and-power/


21

Table 5: Affected Coal and Oil Boilers (ICI Boiler MACT)

Fuel Type Number of

Affected Facilities

30

Number of Affected

Units

Boiler Capacity,

MMBtu/hr

CHP Capacity, MW

31

Coal 351 791 180,619 18,064

Heavy Oil 151 319 41,821 4,182

Light Oil 217 215 20,791 2,080

Total 717 1,325 243,231 24,326

GROWING FEDERAL AND STATE POLICYMAKER SUPPORT

Policymakers at the federal and state level are increasingly recognizing the benefits that CHP offers in terms of energy efficiency, reduced emissions, and economic growth. Some of the benefits that most resonate with policymakers include:

CHP is a distributed energy resource that is, by definition, strategically located at or near the point of energy use. Such on-site generation avoids the transmission and distribution (T&D) losses associated with electricity purchased via the grid from central stations and defers or eliminates the need for new T&D investment. CHP’s inherent higher efficiency and elimination of transmission and distribution losses from the central station generator results in reduced primary energy use and lower greenhouse gas (GHG) emissions.

CHP can provide lower energy costs for the user by displacing higher priced purchased electricity and boiler fuel with lower cost self-generated power and recovered thermal energy. The amount of savings that CHP represents depends on the difference in costs between displaced electricity purchases and fuel used by the CHP system. To be cost effective, the savings in power and fuel costs need to be compared to the added capital, fuel and other operating and maintenance costs associated with operating a combined heat and power system. In many parts of the country, CHP provides not only operating savings for the user, but may also represent a cost-effective supply of new power generation capacity for regions with declining reserve margins.

The increase in fuel use efficiency of CHP combined with the use of lower carbon fuels such as natural gas generally translates into reductions in greenhouse gas and criteria emissions compared to separate heat and power. Table 6 below compares the annual energy and CO2 savings of a 10 MW natural gas-fired CHP system over separate heat and power with the energy and CO2 savings from utility-scale renewable technologies producing power only and to a 10 MW portion of a new central station combined heat and power generator. The comparison is shown on a national basis and based on displacing EPA eGRID 2010 All Fossil Average Generation resources and an on-site natural gas boiler.

30

Some facilities are listed in multiple categories due to multiple fuel types; there are an estimated 556 ICI affected facilities 31

CHP potential based on average efficiency of affected boilers of 75%; average annual load factor of 65%, and simple cycle gas turbine CHP performance (power to heat ratio = 0.7)


22

Table 6: CHP Energy and CO2 Savings Potential

Category 10 MW CHP 10 MW PV 10 MW Wind 10 MW

Natural Gas Combined Cycle

Annual Capacity Factor 85% 25% 34% 70%

Annual Electricity 74,446 MWh 21,900 MWh 29,784 MWh 61,320 MWh

Annual Useful Heat Provided 103,417 MWht None None None

Footprint Required 6,000 sq ft 1,740,000 sq ft 76,000 sq ft N/A

Capital Cost $20 million $48 million $24 million $9.8 million

Annual National Energy Savings 343,787 MMBtu 225,640 MMBtu 306,871 MMBtu 163,724 MMBtu

Annual National CO2 Savings 44,114 Tons 20,254 Tons 27,546 Tons 28,233 Tons

Annual National NOX Savings 86.9 Tons 26.8 Tons 36.4 Tons 76.9 Tons

Following the terrorist attacks in 2001, the Northeast blackout in 2003, and natural disasters such as Hurricane Katrina in 2005, Hurricane Ike in 2008, and Superstorm Sandy in 2012, disaster preparedness planners have become increasingly aware of the need to protect critical infrastructure facilities and to better prepare for energy emergencies. Resilient critical infrastructures enable a faster response to disasters when they occur, mitigate the extent of damage that communities endure, and speed the recovery of critical functions. CHP helps answer this need while making energy more cost- and fuel-efficient for the user, as well as more environmentally friendly for society at large. The use of CHP systems for critical infrastructure facilities can also improve overall grid resiliency and performance by removing significant electrical load from key areas of the grid. This is possible when CHP is installed in areas where the local electricity distribution network is constrained or where load pockets exist. The use of CHP in these areas eases constraints and load pockets by reducing load on the grid.

The values in Table 6 are based on:

• 10 MW Gas Turbine CHP - 28% electric efficiency, 68% total CHP efficiency, 15 ppm NOx emissions

• Capacity factors and capital costs for PV and Wind based on utility systems in DOE’s Advanced Energy Outlook 2011Capacity factor, capital cost and efficiency for natural gas combined cycle system based on Advanced Energy Outlook 2011 (540 MW system proportioned to 10 MW of output), NGCC NOx emissions 9 ppm

• CHP, PV, Wind and NGCC electricity displaces National All Fossil Average Generation resources (eGRID 2010 ) - 9,720 Btu/kWh, 1,745 lbs CO

2/MWh, 2.3078 lbs NOx/MWh, 6% T&D losses;

CHP thermal output displaces 80% efficient on-site natural gas boiler with 0.1 lb/MMBtu NOx emissions

• CHP, PV, Wind and NGCC electricity displaces EPA eGRID 2010 California All Fossil Average Generation resources - 8.050 Btu/kWh, 1,076 lbs CO

2/MWh, 0.8724 lbs NOx/MWh, 6% T&D

losses; CHP thermal output displaces 80% efficient on-site natural gas boiler with 0.1 lb/MMBtu NOx emissions


23

There are a variety of examples of CHP systems in critical infrastructure facilities that have continued operating throughout grid failures and continuing to serving the community32:

South Oaks Hospital on Long Island originally installed their 1.3 MW CHP system to reduce energy costs; however reliability has been a large advantage of having CHP. The system is grid-connected but can operate off the grid during emergencies. During the major northeast blackout in August 2003, South Oaks never lost power, while the area around the hospital lost power for 14 hours. During the recent Superstorm Sandy, the hospital continued to operate as usual and was able to receive patients from other facilities that were without power due to the failure of backup generators. About 30 psychiatric patients from South Beach Psychiatric Center on Staten Island were shifted to South Oaks33.

Montefiore Medical Center in the Bronx, New York, has a 14 MW CHP system that generates almost all of the electric and thermal needs of the facility. In advance of Superstorm Sandy, a command center was set up and connected to the NYC Office of Emergency Management. Twenty patients were seamlessly transferred from NY Downtown Hospital, and as the storm and its effects worsened, additional patients were taken in from NYU Langone, Bellevue Hospital and nursing homes across the region. Montefiore was the only institution in the area that kept its outpatient services open on both days, and residents and faculty kept the teaching clinics fully staffed.

Salem Community College in Salem County, New Jersey is a Red Cross Disaster Relief Shelter. The site consists of three Capstone C65 microturbines that provide heating, cooling and emergency power to the critical facility. During Superstorm Sandy, the shelter was fully operational as it was continuously powered and heated by the CHP system. The shelter took in a peak of about 80 to 90 residents between Monday and Tuesday34.

New York University has a CHP system that allowed some of the campus facilities to remain in operation during a grid outage. During Superstorm Sandy, approximately 6,000 of New York University’s students found themselves in dorms without power. After 48 hours without power due to the storm, those who could not find refuge with friends in dorms with power or elsewhere in the city were ordered to evacuate on Wednesday and spend the night in the Kimmel Center, NYU’s student life building. The Kimmel Center’s CHP plant kept the lights on and the heat and water running for displaced students. The second floor of the building became a temporary health center, as NYU’s permanent health center was closed. The power provided by the CHP plant also allowed the university to distribute hot meals. Five NYU dorms (such as Goddard Hall, which also runs on power from NYU’s CHP system) that still had power also became centers of refuge, as displaced students were allowed in to sleep on floors and in hallways35.

Recognizing these benefits, a number of states have adopted supportive policies for CHP. These policies include recognizing CHP in state energy portfolio standards (renewable, clean energy, and energy efficiency) and addressing utility regulatory policies that unduly discourage new CHP project development. Twenty-four states recognize CHP in one form or another as part of their Renewable

32

Note that there are also several examples of CHP that did not operate as planned. 33

http://www.medicaldaily.com/articles/12942/20121030/hospitals-emergency-mode-hurricane-sandy-death-toll.htm#qePwdJUKkUWvTRtm.99 34

http://www.nj.com/salem/index.ssf/2012/10/salem_county_deals_with_afterm.html 35

http://www.thedailybeast.com/articles/2012/11/01/inside-the-nyu-refugee-camp-for-displaced-students.html

http://www.medicaldaily.com/articles/12942/20121030/hospitals-emergency-mode-hurricane-sandy-death-toll.htm#qePwdJUKkUWvTRtm.99

http://www.medicaldaily.com/articles/12942/20121030/hospitals-emergency-mode-hurricane-sandy-death-toll.htm#qePwdJUKkUWvTRtm.99

http://www.nj.com/salem/index.ssf/2012/10/salem_county_deals_with_afterm.html

http://www.thedailybeast.com/articles/2012/11/01/inside-the-nyu-refugee-camp-for-displaced-students.html


24

Portfolio Standards or Energy Efficiency Resource Standards36. A number of states, including California, New York, Massachusetts, Rhode Island, New Jersey, Maryland and North Carolina, have initiated specific incentive programs for CHP. An example is Massachusetts Green Communities Act – The Green Communities Act includes a rebate incentive for efficient CHP systems ($750/kW up to 50 percent of total installed costs). The incentive value is determined on a case-by-case basis considering the value of CHP in the participating utility’s overall energy efficiency portfolio, the project’s benefit to cost ratio, the project’s contribution to energy efficiency, project risk, and customer investment threshold. All of the kilowatt-hours from CHP installed under the program are credited to the servicing utility’s annual energy efficiency goals. Another example is Maryland’s CHP pilot program for investor-owned utilities implemented this year that offers $250/kW in upfront incentives and $0.07/kWh for the initial 18 months of operation. Systems must meet minimum efficiency requirements and pass each utility’s total resource cost test to qualify for the incentive. Yet another example is in Rhode Island. National Grid offers an upfront incentive to customers that wish to install CHP, the size of which rachets up if the system efficiency is higher. Incentives include $900 per KW for 55% efficiency up to 60%, and $1,000 per KW above 60% efficiency. A 25% bonus on either of these is offered if the company reduces electric load by 5%, in essence a right sizing bonus. NARUC, recognizing the potential benefits of CHP, passed a resolution on November 19, 2012 that recognized an investment in CHP “has the potential to improve the competitiveness of United States manufacturing, lower energy costs, free up future capital for businesses to invest, reduce air pollution, and create jobs” and encouraging “State public service commissions to work with stakeholders and other agencies, as needed, to encourage cost effective investment in CHP opportunities” and to “explore educational opportunities and forums on CHP” and to “evaluate regulatory mechanisms and consider and identify ways to best deploy cost-effective CHP technologies”. A similar resolution was passed on February 6, 2013 for waste heat to power (WHP) CHP. State efforts in promoting CHP received an additional boost on August 30 of 2012, the Administration signed an Executive Order to accelerate investments in industrial energy efficiency, including CHP. The Executive Order:

Sets a national goal of 40 gigawatts (GW) of new CHP installations over the next decade;

Directs agencies to foster a national dialogue through ongoing regional workshops to encourage the adoption of best practice policies and investment models that overcome the numerous barriers to investment, provide public information on the benefits of unlocking investment in industrial energy efficiency, and use existing Federal authorities that can support these investments;

Directs the Departments of Energy, Commerce, and Agriculture, and the Environmental Protection Agency, to coordinate actions at the Federal level while providing policy and technical assistance to states to promote investments in industrial energy efficiency.

The Executive Order highlighted a number of national benefits from increased CHP investment, including:

Improving U.S. manufacturing competitiveness: By accelerating these investments, manufacturers

could save at least $100 billion in energy costs over the next decade.

36

While a number of states have recognized CHP in RPS or EERS programs, many of the RPS programs limit qualified CHP systems to waste heat to power CHP (CHP bottoming cycles), and most EERS programs do not set

separate targets for CHP reducing the effectiveness of these programs in promoting CHP development.

http://www.whitehouse.gov/the-press-office/2012/08/30/executive-order-accelerating-investment-industrial-energy-efficiency


25

Creating jobs now through investments upgrading our manufacturing facilities: Meeting the

President's goal of 40 GW of new CHP over the next decade would mean $40 billion to $80 billion of

new capital investment in American manufacturing facilities.

Offering a low-cost approach to new electricity generation capacity to meet current and future

demand: Investments in industrial energy efficiency, including CHP, cost as much as 50% less than

traditional forms of delivered new baseload power.

Significantly lowering emissions: Improved efficiency can meaningfully reduce nationwide GHG

emissions and other criteria pollutants.

Enhancing grid security: Investments in industrial energy efficiency reduce the need for new

electricity infrastructure (transmission and distribution) and improve overall electric reliability.

Recent CHP Market Trends Market activity in CHP was increasing even before the issuance of the Executive Order due to the drivers highlighted above. Figure 19, based on the ICF Watch List37, shows that, while CHP capacity additions have been low on an annual basis since 2006, current activity is increasing with over 4,500 MW in development and planned for installation through 2016. This is undoubtedly a conservative estimate because many projects are not publically announced or publicized.

Figure 19: Annual CHP Installations Since 2000, With Projected Future Installations based on Announced Projects


37

As part of its support of the ORNL/DOE CHP program, ICF maintains a list of announced and under construction CHP projects for ultimate incorporation into the CHP Installation Database


26

Market Environment While the benefits of added CHP capacity are promising and policymakers are taking notice, existing market conditions and technical barriers continue to impede full realization of CHP’s potential. Policymakers are beginning to understand that a strategic approach is needed to encourage CHP where it can be applied today and address the challenges discouraging its wider deployment. A history of success in the US and abroad proves that a balanced set of policies, incentives, and technology investments can bring sustained CHP growth. The following figure summarizes some of the key drivers and restraints affecting the CHP market.

Figure 20: CHP Market Drivers and Restraints

Source: Frost and Sullivan

CHP Drivers As highlighted earlier, there are a variety of drivers for increased CHP deployment in the U.S. CHP has the potential to greatly reduce energy consumption, while also decreasing criteria and greenhouse gas emissions, increasing the competitiveness of businesses that use it, easing grid congestion, and enhancing reliability and ancillary electricity system benefits. CHP also provides economic development benefits, creates jobs, and increases overall energy security. Already used by many industrial facilities and a growing number of commercial and institutional entities, CHP is a commercially available clean energy resource that is immediately deployable, and that may help address current and future US energy needs.

Barriers to CHP Although much progress has been made in the last decade to remove technical and regulatory barriers to wider adoption of CHP, and significant new market drivers support an increase in CHP development, several major hurdles remain. Addressing these challenges will require a holistic approach involving regulatory, policy, and technical solutions. Grid interconnection: The key to the ultimate market success of CHP is the ability to safely, reliably, and economically interconnect with the utility grid system. The current lack of uniformity in interconnection


27

standards makes it difficult for equipment manufacturers to design and produce modular packages, and reduces the economic incentives for on-site generation. Limited CHP Supply Infrastructure: The downturn in CHP investment since 2005 has reduced the size and focus of the industry sales and service infrastructure. CHP is not currently a major emphasis for most energy developers and equipment suppliers. Increased use of CHP may help bring system costs down and develop service infrastructure for CHP. Standby/Back-up Charges: Facilities with CHP systems usually require supplemental and/or standby/back-up service from the utility to provide power needs over and above the output of the CHP system and during periods when the system is down due to routine maintenance or unplanned outages. Electric utilities often assess specific standby charges to cover the additional costs the utilities incur as they continue to provide generating, transmission, or distribution capacity (depending on the structure of the utility) to supply backup power when requested (sometimes on short notice). The level of these charges is often a point of contention between the utility and the consumer, and can, without proper oversight, create unintended and important barriers to CHP38. Market and Non-market Uncertainties: CHP requires a significant capital investment and the equipment has historically had a long life – 20+ years. It can be challenging to make investment decisions in a rapidly changing policy and economic environment. Uncertain factors affecting project economics include: fuel and electricity prices, regional/national economic conditions, market sector growth, utility and power market regulation, and environmental policy. Sizing the CHP system to maximize efficiency in many industrial facilities (i.e., thermal match) often produces power in excess of the host site’s needs, introducing the added market risk of power pricing to a consumer usually in a different core business. In addition, CHP may increase emissions on-site while reducing emissions regionally; CHP projects benefit from policies that recognize and account for these savings39. Lack of Recognition of CHP in Environmental Regulations: Higher efficiency generally means lower fuel consumption and lower emissions of all pollutants. Nevertheless, most U.S. environmental regulations have historically established emission limits based on heat input (lb/MMBtu) or exhaust concentration (parts per million [ppm]). These input-based limits do not recognize or encourage the higher efficiency offered by CHP. Nor do they account for the pollution prevention benefits of efficiency in ways that encourage the application of more efficient generation approaches. Moreover, since CHP generates both electricity and thermal energy on-site, it can potentially increase on-site emissions even while it reduces the total on-site and off-site emissions. Thus environmental permitting can be a barrier to CHP development, rather than an incentive and recognition of its benefits40. End-user Awareness and Economic Decision-making: CHP is not regarded as part of most end-users’ core business focus and, as such, is sometimes subject to higher investment hurdle rates than competing internal options. In addition, many potential industrial project hosts are not fully aware of the full array of benefits provided by CHP, or are overly sensitive to perceived CHP investment risks.

38

U.S. EPA Combined Heat and Power Partnership, http//www.epa.gov/chp/state-policy/utility.html 39

International Energy Agency, Combined Heat & Power: and Emissions Trading: Options for Policy Makers, July 2008, http://www.iea.org/papers/2008/chp_ets.pdf 40

While the 2007 California ARB emissions standards for small DG are output-based and include a CHP thermal credit, the required levels of the standard represent a barrier for many gas-fired CHP systems

http://www.iea.org/papers/2008/chp_ets.pdf


28

Primary CHP Market Participants

There are a variety of participants in the CHP market from the ultimate end-user of the technology to the government agencies trying to promote its use. Each participant has a unique role in the market, which is addressed below:

End-Users End-users are the industrial, commercial, or institutional facilities that use the output of the CHP system. Installing and operating an onsite generation unit is a difficult decision for many end-users, because it represents the addition of new lines of business – power plant operation and energy management. These new business lines require personnel and management with unique skills, present new risks, and consume already limited management attention41. Some end-users choose to enter these new lines of business themselves, while others opt to have a third party handle the construction, ownership, and operation of the CHP system. Sophisticated end-users can deal directly with their local grid operator or load-serving entity, and can package the output of these units to generate additional revenue streams through the sale of electricity, capacity, or ancillary services.

CHP Equipment Manufacturers There are many equipment manufacturers that supply reciprocating engines, gas turbines, steam turbines, fuel cells, microturbines, and other types of equipment to the CHP market. Some equipment suppliers work directly with end-users, while others work through CHP developers and engineering companies to get their equipment sold and installed. Major equipment manufacturers include, but are not limited to, Solar Turbines, General Electric, Caterpillar, Capstone Turbines, United Technologies, Flex Energy, Tecogen, Cummins, Siemens-Westinghouse, Elliot Turbines and Fairbanks Morse.

CHP Developers CHP developers consist of engineering companies that specialize in developing CHP projects for end-users. Developers typically deal with all aspects of installing a system including the system design and engineering specifications, construction details, permitting and interconnection requirements, and commissioning. Some CHP developers provide these services for a flat fee, while others will build, own, and operate the CHP system and sell the energy outputs back to the end-user. This path allows an end-user to benefit from on-site generation without actually taking on another line of business. A number of firms exist, usually with some degree of specialization in a certain technology platform that will install a turnkey system for the end-user or actually own and operate a CHP facility on behalf of the end-user.

Utilities Electric utilities, with some exceptions, have traditionally been reluctant participants in the CHP market. Some utilities may regard CHP as a threat to their revenue streams or a possible safety concern. However, a more progressive utility may recognize that utility owned CHP can provide a cost effective means to defer large capital investments in transmission and distribution infrastructure such as new substations, transformers, and line upgrades. Investor owned utilities have conventionally been more likely to oppose CHP while municipal utilities have taken a broader position on how to use CHP for its many benefits. Natural gas utilities can benefit from increased CHP development, however not all gas utilities actively market for or provide support for CHP development.

41

Pike Research. “Industrial Distributed Generation: Combined Heat and Power, Aggregated Generation, Opportunity Fuels, Data Centers, Fuel Cells, and Renewable Energy for Industrial Power Applications.” 2011.


29

Federal and State Government Government has played a significant role in attempting to increase the market for CHP as a prime energy efficiency technology. The Federal government has supported CHP technology development, demonstration, and deployment through the Department of Energy. The EPA CHP Partnership also serves as a program to promote CHP technologies by working with energy users and CHP industry stakeholders to facilitate the development of new CHP projects and to promote their environmental and economic benefits. Elimination of economic, regulatory and institutional barriers to CHP has been primarily focused at the state government level, where a patchwork of state incentives and regulations exists. These policies are controlled by public utility commissions, state energy offices, governors and state legislative bodies responsible for interconnection rules, renewable portfolio standards, and environmental permitting issues.

Non-Governmental Organizations There are a variety of non-governmental organizations that exist to promote the growth of CHP. The United States Combined Heat and Power Association (USCHPA) is a private, non-profit trade association, formed to promote the merits of CHP and to achieve public policy support for CHP. A sister organization, Heat is Power, promotes the merits of waste heat to power systems. The American Council for an Energy-Efficient Economy (ACEEE) is a nonprofit organization dedicated to advancing energy efficiency as a means of promoting economic prosperity, energy security, and environmental protection and has long supported expanded CHP development. The eight Clean Energy Application Centers around the country offer CHP technical assistance, training, educational opportunities, and outreach support.

Market Opportunities for CHP

U.S. CHP Technical Potential ICF evaluated CHP technical potential for the U.S. Department of Energy and estimated that there is approximately 56 GW of additional industrial CHP potential, and 69 GW of commercial/institutional CHP potential in the U.S., for a total of 124.7 GW of additional capacity in CHP systems below 100 MW in size at existing industrial and commercial facilities. Key additional features of this potential include:

Almost one-half of the technical potential is in commercial/institutional applications

Just over one-half of the technical potential is in systems below 5 MW in size

Much of the technical potential is in applications with limited experience with CHP Figure 21 profiles the total technical potential for additional CHP systems of all sizes at existing industrial and commercial facilities in comparison to the existing 82 GW of installed CHP capacity42. The 124.7 GW of technical potential represents approximately 8.4 Tcf of annual natural gas demand serving new technically feasible CHP; this CHP demand would result in an incremental annual load of 5.1 Tcf assuming displaced thermal loads were entirely natural gas based.

42

The technical market potential does not consider screening for economic rate of return, or other factors such as ability to retrofit, owner interest in applying CHP, capital availability, natural gas availability, and variation of energy consumption within customer application/size class. However, the technical potential as outlined is useful in understanding the potential size and distribution of the target CHP markets among the states.


30

Figure 21: Existing CHP and Technical Potential

LDC Addressable Technical Potential43 ICF evaluated the technical potential for CHP systems below 100 MW in the industrial, commercial/ institutional, and multi-family residential market sectors for this report. As noted earlier, it was assumed that systems below this capacity would most likely remain connected to the local distribution company. The CHP technical potential is an estimation of market size constrained only by technological limits – the ability of CHP technologies to fit customer energy needs. CHP technical potential is calculated in terms of CHP electrical capacity that could be installed at existing industrial, commercial and institutional facilities based on the estimated electric and thermal needs of the site. The technical market potential does not consider screening for economic rate of return, or other factors such as ability to retrofit, owner interest in applying CHP, capital availability, natural gas availability, and variation of energy consumption within customer application/size class. The technical potential as outlined is useful in understanding the potential size and distribution of the target CHP market in an area. Identifying the technical market potential is a preliminary step in the assessment of actual economic market size and ultimate market penetration. CHP is best applied at facilities that have significant and concurrent electric and thermal demands. In the industrial sector, CHP thermal output has traditionally been in the form of steam used for process heating and for space heating. For commercial and institutional users, thermal output has traditionally been steam or hot water for space heating and domestic hot water heating, and more recently, for providing space cooling through the use of absorption chillers. Two different types of CHP markets were included in this evaluation of technical potential: 1) traditional heating CHP, and 2) CHP with both cooling and heating as a thermal output. Both of these markets were further disaggregated by high load factor and low load factor applications resulting in the analysis of four distinct market segments.

43

A detailed discussion of the methodology used to estimate CHP technical potential is in Appendix B


31

CHP with Heating

This market represents CHP systems where the electrical output is produced to meet all or a portion of the base load for a facility and the thermal energy is used to provide steam or hot water. The most efficient sizing for CHP is to match thermal output to baseload thermal demand at the site. Depending on the type of facility, the appropriate sizing could be either electric or thermal limited. Industrial facilities often have “excess” thermal load compared to their on-site electric load (meaning the CHP system will generate more power than can be used on-site if sized to match the thermal load). In this case, potential CHP capacity was limited to on-site electric demand. Commercial facilities almost always have excess electric load compared to their thermal load. Two sub-categories were considered:

High load factor applications: This market provides for continuous or nearly continuous operation. It includes all industrial applications and round-the-clock commercial/institutional operations such colleges, hospitals, hotels, and prisons.

Low load factor applications: Some commercial and institutional markets provide an opportunity for coincident electric/thermal loads for a period of 3,500 to 5,000 hours per year. This sector includes applications such as office buildings, schools, and laundries.

CHP with Heating and Cooling

All or a portion of the thermal output of a CHP system can be converted to air conditioning or refrigeration with the addition of a thermally activated cooling system. This type of system can potentially open up the benefits of CHP to facilities that do not have the year-round heating load to support a traditional CHP system. A typical cooling, heating, and power system would provide the annual hot water load, a portion of the space heating load in the winter months and a portion of the cooling load during the summer months. Two sub-categories were considered:

Incremental high load factor applications: These markets represent round-the-clock commercial/institutional facilities that could support traditional CHP, but with consideration of cooling as an output, could support additional CHP capacity while maintaining a high level of utilization of the thermal energy from the CHP system.

Low load factor applications. These represent cooling and heating CHP markets that otherwise could not support traditional CHP due to a lack of thermal load.

The following tables present the detailed CHP technical potential estimates by application class (industrial and commercial/institutional) and size range (< 1 MW, 1 to 5 MW, 5 to 20 MW, 20 to 50 MW, 50 to 100 MW). The estimates of CHP technical potential are based on thermally loaded CHP systems sized to serve on-site electric demands at target facilities and do not include export capacity.


32

Table 7 Industrial CHP Technical Potential < 100 MW by State and Size Category

State 50 -1000 kW

(MW) 1 - 5 MW

(MW) 5 - 20 MW

(MW) 20 - 50 MW

(MW) 50 - 100 MW

(MW) Total

(MW)

Alabama 88 305 281 209 133 1,015

Alaska 5 42 13 0 0 60 Arizona 39 129 165 0 72 405

Arkansas 47 214 255 285 0 800

California 1,467 1,403 1,042 118 127 4,157

Colorado 37 143 129 70 83 463 Connecticut 54 126 140 163 84 567

Delaware 15 88 86 37 0 226

District of Columbia 2 9 0 0 0 11

Florida 127 394 256 28 0 806 Georgia 158 591 778 466 90 2,083

Hawaii 7 11 12 0 0 30

Idaho 20 82 50 78 0 230

Illinois 220 675 859 422 305 2,481 Indiana 156 419 374 216 140 1,305

Iowa 74 294 270 108 148 894

Kansas 105 206 172 96 0 579

Kentucky 195 217 444 416 516 1,787 Louisiana 158 286 599 476 95 1,613

Maine 76 64 123 112 125 501

Maryland 122 132 151 81 150 635

Massachusetts 223 290 295 142 185 1,135 Michigan 433 476 664 436 268 2,276

Minnesota 233 363 389 176 96 1,257

Mississippi 141 168 278 179 0 766

Missouri 224 362 276 233 51 1,147 Montana 38 33 70 29 0 170

Nebraska 80 126 53 26 0 284

Nevada 44 48 24 48 81 246

New Hampshire 49 57 92 74 0 272 New Jersey 371 443 466 314 0 1,593

New Mexico 40 81 27 76 0 223

New York 518 640 534 504 435 2,632

North Carolina 507 795 813 312 243 2,669 North Dakota 31 35 64 0 0 131

Ohio 570 877 1,030 559 249 3,286

Oklahoma 98 171 165 136 0 571

Oregon 141 271 143 206 64 827 Pennsylvania 386 714 914 598 361 2,975

Rhode Island 29 65 46 35 0 175

South Carolina 247 380 524 386 0 1,536

South Dakota 17 63 60 0 0 140 Tennessee 204 359 461 443 60 1,528

Texas 708 1,056 1,340 340 65 3,509

Utah 66 120 79 170 0 435

Vermont 26 51 58 0 0 135 Virginia 169 335 385 342 107 1,338

Washington 180 274 205 166 162 988

West Virginia 51 55 100 109 135 450

Wisconsin 279 534 649 465 649 2,578 Wyoming 12 38 9 0 110 169

Total 9,288 15,111 16,413 9,886 5,390 56,088


33

Table 8 Commercial CHP Technical Potential < 100 MW by State and Size Category

State 50 -1000 kW

(MW) 1 - 5 MW

(MW) 5 - 20 MW

(MW) 20 - 50 MW

(MW) 50 - 100 MW

(MW) Total

(MW)

Alabama 549 235 70 74 0 929 Alaska 84 32 8 0 0 123

Arizona 777 381 112 62 0 1,333

Arkansas 330 165 28 70 0 593 California 4,289 2,098 922 324 167 7,799

Colorado 591 271 70 0 54 987

Connecticut 475 313 78 0 0 866

Delaware 107 48 21 0 0 176 District of Columbia 134 84 94 0 0 312

Florida 2,546 1,192 267 21 54 4,081

Georgia 1,112 581 78 0 0 1,771

Hawaii 182 140 15 20 0 357 Idaho 160 71 16 0 0 247

Illinois 1,846 968 134 0 0 2,948

Indiana 874 462 91 0 0 1,427

Iowa 454 224 15 0 0 693 Kansas 408 186 63 0 0 656

Kentucky 485 233 47 0 0 765

Louisiana 539 272 117 0 0 928

Maine 184 89 44 6 0 323 Maryland 642 232 204 75 0 1,152

Massachusetts 920 464 203 140 0 1,727

Michigan 1,226 542 311 99 0 2,178

Minnesota 813 328 140 55 0 1,336 Mississippi 316 111 80 95 0 602

Missouri 779 333 180 117 0 1,408

Montana 114 31 17 15 0 178

Nebraska 273 131 63 0 0 467 Nevada 321 235 192 25 0 774

New Hampshire 197 99 9 0 0 305

New Jersey 1,225 771 226 28 0 2,250

New Mexico 249 88 16 0 0 352 New York 3,033 1,688 1,007 820 259 6,806

North Carolina 1,130 413 112 77 0 1,733

North Dakota 122 51 24 0 0 196

Ohio 1,635 888 192 0 0 2,716 Oklahoma 421 211 30 74 0 737

Oregon 423 194 48 0 0 665

Pennsylvania 1,616 1,158 241 116 67 3,198

Rhode Island 153 92 22 0 0 266 South Carolina 599 195 44 0 0 839

South Dakota 129 52 14 0 0 195

Tennessee 761 357 112 0 0 1,230

Texas 2,643 1,404 373 100 0 4,521 Utah 302 130 25 0 0 457

Vermont 94 47 19 0 0 161

Virginia 1,019 510 186 42 0 1,756

Washington 747 351 85 57 0 1,239 West Virginia 207 111 24 0 0 342

Wisconsin 854 467 103 0 0 1,424

Wyoming 81 21 7 0 0 109

Total 39,171 19,751 6,601 2,512 601 68,636


34

Table 9 Industrial CHP Technical Potential < 100 MW by Application and Size Category

SIC Application 50 -1000 kW

(MW) 1 - 5 MW

(MW) 5 - 20 MW

(MW) 20 – 50 MW

(MW) 50 - 100 MW

(MW) Total (MW)

20 Food 2,115 3,656 1,887 588 460 8,706

22 Textiles 446 801 863 195 0 2,306

24 Lumber and Wood 1,086 1,033 555 44 0 2,718

25 Furniture 18 0 0 0 0 18

26 Paper 1,014 2,064 4,204 4,129 2,151 13,562

27 Printing/Publishing 27 5 5 0 0 36

28 Chemicals 2,046 5,030 6,200 3,102 1,831 18,209

29 Petroleum Refining 349 951 880 840 350 3,370

30 Rubber/Misc Plastics 937 396 149 108 0 1,590

32 Stone/Clay/Glass 30 26 27 0 0 83

33 Primary Metals 347 486 951 615 523 2,922

34 Fabricated Metals 146 19 6 0 0 171

35 Machinery/Computer Equip 60 53 0 0 0 113

37 Transportation Equip. 585 533 668 264 0 2,050

38 Instruments 65 49 11 0 75 200

39 Misc Manufacturing 18 8 8 0 0 34

Total 9,288 15,111 16,413 9,886 5,390 56,088

Table 10 Commercial CHP Technical Potential < 100 MW by Application and Size Category

SIC Application 50 -1000 kW

(MW) 1 - 5 MW

(MW) 5 - 20 MW

(MW) 20 – 50 MW

(MW) 50 - 100 MW

(MW) Total (MW)

43 Post Offices 49 9 3 0 0 62

52 Retail 2,175 306 52 44 0 2,577

4222 Refrigerated Warehouses 122 16 4 7 0 149

4581 Airports 17 25 39 57 0 138

4952 Wastewater Treatment 234 55 24 0 0 313

5411 Food Stores 1,645 123 51 26 0 1,844

5812 Restaurants 1,722 67 23 6 0 1,819

6512 Commercial Buildings 15,779 9,799 0 0 0 25,577

6513 Multifamily Buildings 3,950 1,289 0 0 0 5,239

7011 Hotels 2,674 1,224 785 173 21 4,877

7211 Laundries 231 24 3 0 0 257

7374 Data Centers 382 258 226 35 0 902

7542 Car Washes 118 2 1 0 0 121

7832 Movie Theaters 8 1 0 0 0 9

7991 Health Clubs 306 27 8 8 0 349

7997 Country Clubs 646 30 17 0 0 693

8051 Nursing Homes 1,968 143 78 0 0 2,189

8062 Hospitals 1,250 2,608 1,544 321 0 5,722

8211 Schools 2,536 107 32 0 0 2,675

8221 College/Universities 970 1,313 1,885 1,204 472 5,843

8412 Museums 83 3 12 0 0 98

9100 Govt. Buildings 1,864 1,157 842 269 0 4,132

9223 Prisons 442 1,165 971 363 109 3,050

Total 39,171 19,751 6,601 2,512 601 68,636


35

Table 11 profiles the technical potential in terms of annual total and incremental natural gas demand assuming displaced thermal loads are entirely natural gas based.

Table 11 CHP Technical Potential and Annual Gas Load < 100 MW by Application

Segment Potential < 20 MW

Annual Gas Demand

Annual Incremental Gas Demand

Potential < 100 MW

Annual Gas Demand

Annual Incremental Gas Demand

Commercial 65,500 MW 3.9 Tcf 2.4 Tcf 68,600 MW 4.1 Tcf 2.5 Tcf

Industrial 40,800 MW 3.1 Tcf 1.9 Tcf 56,100 MW 4.3 Tcf 2.6 Tcf

Total 106,300 MW 7.0 Tcf 4.3 Tcf 124,700 MW 8.4 Tcf 5.1 Tcf

Economic Potential for CHP

The technical potential as outlined is useful in understanding the potential size and distribution of the target CHP market in an area. Identifying the technical market potential is a preliminary step in the assessment of actual economic market size. The main benefits of CHP for the user are reduced energy costs and increased energy reliability. CHP can provide lower energy costs by displacing higher priced purchased electricity and boiler fuel with lower cost self-generated power and recovered thermal energy. The amount of savings that CHP can provide depends on the difference in costs between displaced electricity purchases and fuel used by the CHP system. To be cost effective, the savings in power and fuel costs need to be compared to added capital, fuel and other operating and maintenance costs associated with operating a combined heat and power system. CHP project economics are extremely site specific, affected by specific electricity rates and tariff structures, natural gas prices, site specific conditions such as space availability and integration into existing thermal and electric systems, and permitting, siting and grid interconnection requirements. A high level estimate of economic potential by system size range (< 1 MW, 1 to 5 MW, 5 to 20 MW, 20 to 50 MW, 50 to 100 MW) was developed for this report using state average electricity and natural gas rates and typical CHP equipment cost and performance characteristics. Simple paybacks were calculated for the five CHP system size categories for each of the following three CHP market categories44:

CHP with heating only - High load factor applications: Continuous or nearly continuous operations with process or space conditioning heat loads. It includes all industrial applications and round-the-clock commercial/institutional operations such colleges, hospitals, hotels, and prisons.

CHP with heating and cooling - Incremental high load factor applications: Round-the-clock commercial/institutional facilities that could support traditional CHP, but with consideration of cooling as an output, could support additional CHP capacity while maintaining a high level of utilization of the thermal energy from the CHP system.

CHP with heating and cooling - Low load factor applications: These represent markets that otherwise could not support CHP due to a lack of thermal load. This sector includes applications such as commercial office buildings.

44

The fourth market category – low load factor cooling applications was not included in the economic potential analysis due to the typically moderate economics of such applications. This segment represents about 1,400 MW of the total potential below 100 MW


36

The payback calculation was conducted for each state and the potential in terms of MWs categorized into three payback categories representing the degree of economic potential:

Strong potential – simple payback < 5 years

Moderate potential – simple payback 5 to 10 years

Minimal potential – simple payback > 10 years

Scenario analysis were then conducted to evaluate the effect of changes in capital costs and electricity prices on the paybacks and resulting levels of economic potential. A detailed discussion of the methodology is included in Appendix C.

It is important to note that this analysis is a fairly high level estimate and has a number of important limiting factors:

The analysis was done based on state average electric and gas prices. Some states have wide variations in electric prices among utilities and state-wide averages most likely underestimate the potential (Ohio is an example)

The analysis was done without consideration of individual state financial incentives for CHP. As an example, Oregon showed no strong or moderate potential as a result of the analysis, but a high business energy tax credit and other initiatives have stimulated the market in this state.

State average energy prices were based on the most recent EIA data – 2011 and early 2012. Recent natural gas price reductions may not be fully reflected in the EIA data. As an example, the 2012 price for industrial natural gas in Ohio was $5.76/MMBtu; this rate is now at $5.06/MMBtu based on the Ohio PUC rate calculator. This change alone would move over 800 MW of CHP potential in Ohio from the minimal to the moderate payback range.


37

Table 12 presents the base case economic potential based on current state level electricity and natural gas prices, and equipment cost and performance as outlined in Appendix C. As shown, 6,355 MW of the total technical potential of 123,30045 MW had paybacks less than 5 years located in twelve states (Alaska, California, Connecticut, Florida, Hawaii, Massacussetts, New Hampshire, New Jersey, New York, Rhode Island, Texas and Vermont). Thirty six states had 35,257 MW with paybacks in the 5 to 10 years range. Fourteen states and the District of Columbia have little or no economic potential under the base case.

Table 12 Economic Potential for CHP Units Less than 100 MW – Base Case

45

The total technical potential for CHP <100 MW as shown in Tables 7 and 8 is 124.7 GW, however 1,420.5 MW

of low load factor CHP applications was not included in the economic modeling because of their low likelihood of

appearing economic. Therefore, the amount of CHP technical potential that was modeled for economics was 123.3

GW.

Minimal

Potential,

Payback

>10 yrs

Moderate

Potential,

Payback

5-10 yrs

Strong

Potential,

Payback

<5yrs

Minimal

Potential,

Payback

>10 yrs

Moderate

Potential,

Payback

5-10 yrs

Strong

Potential,

Payback

<5yrs


Alaska 0 52 130 181 Montana 343 0 0 343


Arkansas 1,384 0 0 1,384 Nevada 999 0 0 999

California 2,807 8,283 735 11,826 New Hampshire 0 497 74 571

Colorado 1,211 208 0 1,419 New Jersey 1,159 2,301 341 3,801





Georgia 3,256 555 0 3,811 Ohio 5,951 0 0 5,951

Hawaii 77 212 86 376 Oklahoma 1,295 0 0 1,295

Idaho 469 0 0 469 Oregon 1,472 0 0 1,472






Louisiana 1,864 658 0 2,523 Texas 5,716 1,836 384 7,935

Maine 582 237 0 820 Utah 881 0 0 881

Maryland 1,450 306 0 1,756 Vermont 0 282 12 293

Massachusetts 282 2,078 466 2,826 Virginia 2,570 490 0 3,060



Mississippi 1,086 274 0 1,360 Wisconsin 2,859 1,114 0 3,973

Wyoming 166 110 0 275

U.S. Total 81,691 35,257 6,355 123,303

Total

Technical

Potential

State


Range, MWTotal

Technical

Potential

State


Range, MW


38

Table 13 presents the economic potential based on current state level electricity and natural gas prices, and a 25 percent reduction in CHP equipment costs from the base case. This scenario could be reflective of state level capital cost incentives such as have been implemented in states such as New Jersey, California, Maryland and New York. In this case, the strong potential category increased to 16,467 MW with Louisianna, Tennessee, Georgia, Maryland, Alabama, Mississippi and Delaware added to this category. Thirty nine states had 37,878 MW with paybacks in the 5 to 10 years range. Ten states and the District of Columbia continued to have little or no economic potential under this scenario.

Table 13 Economic Potential for CHP Units Less than 100 MW – 25 Percent Reduction in CHP Capital Costs

Minimal

Potential,

Payback

>10 yrs

Moderate

Potential,

Payback

5-10 yrs

Strong

Potential,

Payback

<5yrs

Minimal

Potential,

Payback

>10 yrs

Moderate

Potential,

Payback

5-10 yrs

Strong

Potential,

Payback

<5yrs


Alaska 0 0 181 181 Montana 343 0 0 343


Arkansas 1,384 0 0 1,384 Nevada 999 0 0 999

California 0 7,688 4,138 11,826 New Hampshire 0 312 260 571

Colorado 1,211 208 0 1,419 New Jersey 364 3,095 341 3,801





Georgia 2,399 946 466 3,811 Ohio 5,142 809 0 5,951

Hawaii 77 201 97 376 Oklahoma 1,295 0 0 1,295

Idaho 469 0 0 469 Oregon 1,472 0 0 1,472






Louisiana 1,236 716 571 2,523 Texas 3,258 4,171 506 7,935

Maine 577 243 0 820 Utah 711 170 0 881

Maryland 790 660 306 1,756 Vermont 0 164 129 293

Massachusetts 0 1,569 1,257 2,826 Virginia 2,570 490 0 3,060



Mississippi 728 365 267 1,360 Wisconsin 2,106 1,867 0 3,973

Wyoming 166 110 0 275

U.S. Total 68,958 37,878 16,467 123,303

Total

Technical

Potential

State


Range, MWTotal

Technical

Potential

State


Range, MW


39

Table 14 presents the base case economic potential based on current state level natural gas prices, and base case equipment cost and performance, but with a 15 percent increase in average electricity prices. This scenario could represent the impact of coal plant closings and planned T&D investments in certain regions of the country. In this case, the strong potential category increased to 17,419 MW with Nebraska added to this category compared to the capital cost reduction case. Forty three states had 45,278 MW of potential with paybacks in the 5 to 10 years range. Six states and the District of Columbia continued to have little or no economic potential under this scenario.

Table 14 Economic Potential for CHP Units Less than 100 MW – 15 Percent Increase in Average Electricity Prices

On the following pages, Figure 22 presents a comparison of the strong and moderate potential in total MWs for four cases (base case 25 percent capital cost reduction, 15 percent increase in average electricity prices, and 10 percent decrease in average natural gas prices). Figure 23 shows the annual and incremental natural gas consumption for the combined strong and moderate economic potential for

Minimal

Potential,

Payback

>10 yrs

Moderate

Potential,

Payback

5-10 yrs

Strong

Potential,

Payback

<5yrs

Minimal

Potential,

Payback

>10 yrs

Moderate

Potential,

Payback

5-10 yrs

Strong

Potential,

Payback

<5yrs

Alabama 834 810 283 1,928 Missouri 2,532 0 0 2,532

Alaska 0 0 181 181 Montana 299 45 0 343


Arkansas 1,029 354 0 1,384 Nevada 999 0 0 999

California 0 7,882 3,944 11,826 New Hampshire 0 241 331 571

Colorado 1,013 406 0 1,419 New Jersey 0 2,801 1,000 3,801




Florida 0 4,478 265 4,744 North Dakota 236 88 0 324

Georgia 1,731 1,525 555 3,811 Ohio 5,142 809 0 5,951

Hawaii 0 77 298 376 Oklahoma 1,295 0 0 1,295

Idaho 469 0 0 469 Oregon 1,472 0 0 1,472




Kansas 892 330 0 1,222 South Dakota 258 74 0 332

Kentucky 1,607 932 0 2,539 Tennessee 945 1,290 503 2,737

Louisiana 927 1,025 571 2,523 Texas 3,258 4,171 506 7,935

Maine 577 243 0 820 Utah 711 170 0 881

Maryland 740 710 306 1,756 Vermont 0 153 141 293

Massachusetts 0 1,481 1,345 2,826 Virginia 1,999 1,061 0 3,060



Mississippi 558 534 267 1,360 Wisconsin 1,529 2,444 0 3,973

Wyoming 166 110 0 275

U.S. Total 60,606 45,278 17,419 123,303

Total

Technical

Potential

State


Range, MWTotal

Technical

Potential

State


Range, MW


40

the four cases46. Figure 24 shows a sensitivity analysis of the impact of rising electricity prices on strong and moderate economic potential estimates.

Figure 22: Impact of Scenarios on Economic Potential for CHP Units Less than 100 MW

46

CHP and avoided boiler fuel natural gas consumption values are based on the CHP technology and site conditions

shown in Table C2 of Appendix C. The equation for incremental gas consumption in MMBtu equals:

∑ (

)

CAPi = Capacity in size bin i in MW

EFLHi = Equivalent full load hours per year in size bin i

HtRatei = CHP generator heat rate for size bin i HHV, Btu,kWh

Thermali = CHP recoverable thermal energy for size bin i, Btu/kWh

TUFi = thermal use factor – share of Thermal that is used to avoid process heat requirements in size

bin i

BoilerEff = Avoided boiler efficiency – assumed to be 80% in all size bins

((5((5-10 Yr Payback)

((5((<5 Yr Payback)


41

Figure 23: Impact of Scenarios on Potential Gas Consumption for CHP Units Less than 100 MW (Gas Consumption for Strong and Moderate Economic Potential combined)

47

Figure 24: Impact of Rising Electric Prices on Economic Potential for CHP Units Less than 100 MW

47

CHP and avoided boiler fuel natural gas consumption figures are based on the CHP technology and site conditions

shown in Table C2 of Appendix C.

((5((5-10 Yr Payback)

((5((<5 Yr Payback)


42

Natural Gas and Electric Utility Participation in CHP

For a variety of reasons, including rebounding load growth, and state and local initiatives to decrease energy consumption and lower carbon emissions, there seems to be increased interest in combined heat and power (CHP) by gas and electric utilities across the United States48. CHP projects can yield numerous benefits to electric and gas utilities and to the public, including:

Reducing peak electrical demand on the grid. Yielding improvements to electric grid system efficiency by reducing grid congestion. Deferring or displacing more expensive transmission and distribution infrastructure

investments. Reducing the environmental impact of power generation. Helping to meet state mandated renewable portfolio standards in states where CHP constitutes

an eligible resource. Efficient use of natural gas resources.

Electric Utilities Some investor-owned electric utilities may still regard customer-sited CHP as revenue erosion due to traditional business models linking sales to cost recovery and revenues. Since most facilities that install CHP remain connected to the grid and need to rely on their servicing utility for supplemental power needs beyond their self-generation capacity and/or for standby and back-up service during outages or planned maintenance, utility policies, attitudes, and actions can make or break a CHP project’s economics. Utility tariff structures and standby rates impact the economics of on-site generation49. Similarly, interconnection processes can delay the project development process and add expenses by requiring costly studies, onerous technical requirements, or significant delays in the process. Given the central role that electric utilities play in the development of new CHP – through policies and tariffs that directly impact project economics – and the current modest level of utility ownership of or support for CHP, a number of federal and state policymakers believe that greater partnership between utilities, their industrial customers, project developers, and other stakeholders offers a significant opportunity for addressing obstacles that currently limit CHP project development. Utility recognition of CHP as an investment opportunity to retain large industrial customers, as well as a solution to needed investments in new generation and T&D infrastructure, could be a critical driver to future CHP development. Utilities can serve as important partners in the development of CHP projects in areas of the grid that are currently congested and in need of support. Financing difficulties can also be relieved by utilities that typically have a lower cost of capital and longer investment time horizons than many of their industrial customers. Overall, greater utility partnerships on CHP could be a win-win for the utility, the end-user/project developer, and other ratepayers. The utilities can get the generation and T&D infrastructure support they need, while providing the user with stable financing and risk management. Project benefits will need to be appropriately apportioned to stakeholders through well-crafted, fair policies and strategies to ensure broad support.

Gas Utilities Natural gas local distribution (LDCs) companies face a challenging business environment shaped by declining gas use per customer in some areas, loss of new market share in some traditional markets, and

48

EPA CHP Partnership. http://www.epa.gov/chp/markets/utilities.html. 49

Rate structures that recover the majority of the cost of service in non-bypassable fixed charges and/or ratcheted demand charges reduce the economic savings potential of CHP

http://www.epa.gov/chp/markets/utilities.html


43

difficulties adding new customers. At the same time, as discussed earlier, the North American natural gas outlook is changing radically, with increasing resources of low cost supply entering the market. CHP may offer new, sizable business opportunities for LDCs in their large commercial and industrial markets to provide these consumers with efficient energy solutions, creating value for the customer and generating new revenue for the utility. Direct LDC support could involve significant investments in equipment and infrastructure over a long investment horizon, a proposition that aligns with the utility business model. To promote CHP opportunities, natural gas utility companies could help address the local, state, and federal barriers that hinder combined heat and power deployment, and collaborate with other CHP stakeholders to develop regulatory approaches that properly incentivize customers while maintaining and creating utility shareholder value.

Examples of Utility Support for CHP

Utility Ownership of CHP Assets Although the experience is limited, direct utility involvement in customer-sited CHP projects has taken various forms, including utility ownership and operation of the CHP system with sales of thermal and/or power directly to the site, to joint ownership of generating and heat recovery assets and joint purchase of fuel:

Examples of joint ownership of CHP assets in the ethanol industry include Missouri Ethanol LLC in Laddonia, MO, a 45 million-gal/yr ethanol plant that began operation in September 2006. The plant uses approximately 5 MW of power and 100,000 lb/hr of steam. It is one of two ethanol plants in the state that employ gas turbine-based CHP through a utility-ethanol plant partnership. The CHP system is comprised of a 14.4 MW Solar Titan gas turbine and an unfired heat recovery steam generator (HRSG). The CHP system is jointly owned by Missouri Ethanol and the Missouri Joint Municipal Electric Utility Commission (MJMEUC) – a statewide joint action agency that supplies power and capacity services to 56 municipal Missouri utilities. The Missouri Ethanol project is patterned after an earlier CHP partnership between the City of Macon, MO, and the Northeast Missouri Grain LLC ethanol plant in Macon. In both Macon and Laddonia, the utilities own and are responsible for gas turbine operation. However, the ethanol plants own and are responsible for the heat recovery equipment, including the HRSGs and downstream steam systems. Natural gas costs are shared between the utilities and ethanol plants in both cases. The Missouri Public Utility Alliance MPUA views the Laddonia project as a ‘win-win-win’ effort, as it provides a cost-competitive power supply for MJMEUC, reduced steam costs for the ethanol plant and additional baseload gas demand for the Missouri Municipal Gas Commission. In addition to these benefits, the project directly supports a number of MPUA goals, including increasing the diversity of its supply portfolio, increasing local control of supply assets and promoting economic development for rural Missouri.

Austin Energy, a municipal electric utility in Texas, is sole owner and operator of a 4.5 MW CHP plant that is used to power, heat and cool a number of buildings, including IBM Research Labs, in the Domain industrial park in northwest Austin. Austin Energy has characterized this plant as a “mini-grid solution”, and a response to increasing demands on Austin’s power generation assets. Austin Energy also owns and operates a 4.4 MW CHP system at the Dell Children’s Medical Center; the system provides 100 percent of the hospital’s power, heating and cooling needs.

Gainesville Regional Utilities owns and operates the South Energy Center, a 4.3 MW natural gas fired CHP system that serves the Shands Cancer Hospital at the University of Florida with 100 percent of its energy needs.


44

Ameren owns and operates a 44 MW CHP facility in Mossville, Illinois, through a non-regulated subsidiary – Ameren Energy Medina Valley Cogen LLC. The system produces electricity, steam and chilled water for the adjacent Caterpillar engine manufacturing facility.

Duke Energy owns and operates a 46 MW combustion turbine (GE LM6000) CHP system sited at the University of Florida at Gainesville (formerly a Progress Energy asset). The Gator Power plant is run as a “regulated power plant with the power produced flowing into the grid”, and steam provided to the university.

Alabama Power owns and operates a number of cogeneration power plants sited at large industrial sites: o 97 MW combined cycle Burkville Cogeneration plant located at Sabic Plastics (formerly GE

Plastics), o 210 MW combined cycle Theodore Cogeneration plant located at INEOS-Phenol Chemicals, o 100 MW combined cycle Washington County Cogeneration plant located at Olin Chemicals in

McIntosh o 130 MW coal-biomass Gadsden Cogeneration plant located at Goodyear Tires and Rubber.

Beyond the potential for direct project involvement as described above, current utility initiatives to encourage CHP deployment have been limited, and have taken a variety of forms including financial incentives, feasibility analyses, project management assistance, design/engineering assistance, discounted gas rates, regulatory process advice, and in limited instances, some form of joint ownership. A 2008 report from the EPA CHP Partnership found that 41 utilities offered some type of incentive or program to support CHP50. Of these utility programs, the majority were part of state-mandated initiatives, however 18 utilities provided some type of support for CHP without a state mandate. Direct financial incentives were found to not be commonly offered unless part of state initiatives, while other types of CHP support activities were far more common. Some potential approaches to utility support of CHP are discussed below:

Innovative Financing for CHP Providing innovative financing is one way that electric and gas utilities could promote CHP development. One example is being pursued by Philadelphia Gas Works (PGW), a municipal utility. PGW has provided the upfront capital cost for small CHP systems (1MW) for commercial and industrial customers, recovering those costs plus PGW’s cost of capital over the first five years of CHP system operation through the facility’s gas bills. The site signs a promissory note for the full cost of the system, but the five year through-the-bill financing eliminates the site’s need for upfront capital.

Discounted Natural Gas Rates One way that gas utilities can support CHP is through offering reduced gas rates for distributed generation (DG) facilities. New Jersey Natural Gas (NJNG), a local gas distribution company in New Jersey, provides special pricing plans for commercial and residential customers that install DG. Under the plans residential customers can save up to 40 percent on their gas delivery charges and a commercial customer can save up to 50 percent on delivery charges. In addition to these favorable rates, NJNG also provides guidance and support on DG equipment, manufacturers, distributors, and other resources.

50

U.S. Environmental Protection Agency, Combined Heat and Power Partnership. “Utility Incentives for Combined Heat and Power.” October 2008.


45

California and New York both allow CHP facilities to qualify for electric generator distribution rates.

CHP Outreach and Project Development Several electric and gas utilities provide education and outreach materials to promote CHP in their region. South Jersey Gas Company a provider of natural gas to residential, commercial, and industrial customers in southern New Jersey, has worked with developers to initiate several projects in its service territory. It also promotes CHP through a subsidiary company, Marina Energy, an energy project developer that provides a full range of services to facilitate CHP. Marina Energy provides project management services during the design and construction phases of CHP projects, as well as operations and maintenance service once the projects are installed. Southwest Gas is an investor-owned gas utility that serves nearly 940,000 customers in Arizona, along with customers in Nevada and California. Along with providing incentives for CHP projects (see below), Southwest Gas Key Account Management group has Industrial Gas Engineers who will work with customers or customer consultants to determine the feasibility of a CHP project, and prepare economic studies. In addition Southwest Gas can assist prospective customers in understanding local air quality issues and permitting requirements. Southwest Gas also agreed to partner with the Intermountain CHP Application Center (ICHPC) to promote CHP regionally.

PPL Corporation, an investor-owned energy company headquartered in Allentown, Pennsylvania, has created a subsidiary called PPL Energy Services, that provides onsite thermal and electric energy solutions using DG and CHP technologies. The company provides capital and project development resources to businesses for developing and building CHP systems. PPL Energy Services helps design, install, and finance DG/CHP systems. They also operate and maintain DG/CHP systems to supply businesses with all of their electric and thermal needs.

CHP Incentives In addition to the CHP project development and outreach that Southwest Gas engages in, they have also designed an incentive program to support CHP development. Southwest Gas’s Arizona DG incentive program is one of seven DSM programs they currently provide. Under this program, Southwest Gas provides incentives to Arizona customers installing onsite power generation, with a focus on CHP technologies. The program currently targets commercial and industrial customers and has an annual budget of $400,000 ($350,000 per year for incentives; $50,000 for marketing, administration, and implementation). A project must achieve an overall fuel efficiency of 60 percent or greater to earn utility incentives, which are payable up to a maximum of 50 percent of the installed cost of any project. The incentives include:

$400/kW for projects that attain fuel efficiencies from 60 to 64 percent.

$450/kW for projects that attain fuel efficiencies from 65 to 69 percent.

$500/kW for projects that attain fuel efficiencies of 70 percent and above. Customers seeking incentive payments are required to submit 12 months of gas and electric utility bills, and a copy of the CHP project engineering study signed and stamped by an Arizona registered professional engineer. The utility will provide the first part of the incentive once the CHP equipment is purchased following the submission of the project application and the engineering study. The utility will then verify the installation and operation of the equipment and energy savings prior paying the incentive to the customer.


46

Conclusions & Recommendations As described in this report, CHP represents important benefits for the United States in terms of increased energy efficiency, lower greenhouse gas emissions, and economic competitiveness. While the potential for additional CHP in the U.S. is large, development in recent years has stalled due to regulatory barriers, policy uncertainty and market conditions all of which increase risk to potential CHP users. Active participation by the natural gas industry in this market could help reduce perceptions of market risk by users and stimulate CHP development. The main benefits of CHP for the user are reduced energy costs and increased energy reliability. CHP provides lower energy costs by displacing higher priced purchased electricity and boiler fuel with lower cost self-generated power and recovered thermal energy. The amount of savings that CHP can provide depends on the difference in costs between displaced electricity purchases and fuel used by the CHP system. To be cost effective, the savings in power and fuel costs need to be compared to added capital, fuel and other operating and maintenance costs associated with operating a combined heat and power system. While the economic case for CHP for a potential user would seem fairly straightforward, the actual decision is often impacted by the barriers described previously and is affected by the user’s perception of risks. Intolerance of risk can be an important element in derailing the decision to move forward with CHP and centers on perceived risks in technology performance, future energy prices, economic conditions, etc. Figure 25 is based on a 2003 survey conducted by Primen of California business facilities that could potentially implement CHP51. The figure shows the percentage of the market that would accept a given payback period and move forward with a CHP investment based on the survey results. As can be seen from the figure, more than 40 percent of customers would reject a project that promised to return their initial investment in just one year, an indication that there is considerable perceived risk in making CHP investments. A little more than half would reject a project with a payback of 2 years. The figure shows that less than 50% of potential CHP users view a two year payback as acceptable for a CHP project – a reflection of their perceptions of risk inherent in CHP.

51

Assessment of CHP Market and Policy Options for Increased Penetration, April 2005. EPRI, CEC-500-2005-060-D.


47

Figure 25: CHP Market Acceptance Curve

The aversion to longer payback projects has had a significant impact on CHP project development, especially in the industrial sector which faces greater competition for capital funds. Institutional customers, such as educational and healthcare facilities, can accept longer payback periods, as they take more long-term approaches to their capital budgeting processes52. While the potential for additional CHP development is significant, the likelihood of extensive new market development is limited in the current market and regulatory environment. However, proactive involvement in CHP market development by the natural gas industry could serve to reduce the many risks perceived by potential users and increase market acceptance and promote the deployment of efficient, cost-effective CHP. Potential support the industry could provide for CHP development include:

Customer Outreach – Lack of awareness of CHP and the savings it can provide to a user continues to be a significant barrier to CHP development, particularly with emerging CHP markets in the commercial and institutional sectors. Gas LDCs can leverage their access to and relationship with potential CHP users to increase understanding of CHP and its potential to help their bottom lines.

Feasibility Studies – LDCs could conduct or support initial feasibility studies to further reduce the risks to potential customers. Many users unfamiliar with CHP need assistance in taking the initial steps in determining whether CHP makes economic sense in their facility. LDCs could supply the technical guidance or initial analysis to start them on the evaluation process, and provide technical support as they proceed through project development.

Financing – Providing low cost financing or facilitating access to financing can help increase market acceptance by improving project economics and lowering perceived risks by the user. Financing support can range from on-bill financing of capital cost similar to the PGW program, to leasing of CHP equipment, to direct asset ownership by the LDC. Industrial customers, in

52

Challenges Facing Combined Heat and Power Today, September 2011. ACEEE, IE111.

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

6 mos. 1 yr. 2 yrs. 3 yrs. 4 yrs. 5 yrs. 6 to 10

yrs.

11+

yrs.

Source: Primen’s 2003 Distributed Energy Market Survey

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

6 mos. 1 yr. 2 yrs. 3 yrs. 4 yrs. 5 yrs. 6 to 10

yrs.

11+

yrs.

Source: Primen’s 2003 Distributed Energy Market Survey


48

particular, are interested in mechanisms that would keep CHP project investments off of the balance sheet.

CHP Policy Advocacy – the gas industry should stay closely involved in monitoring, intervening, and commenting on regulatory proceedings that will affect CHP including advocacy at the national and state levels.

Targeted CHP Project Development – LDCs could seek to develop and/or financially support the development of CHP projects to the extent allowed by state regulatory rules.


A-1

Appendix A: Existing CHP in the United States


A-1


A-2


A-3

Source: ICF CHP Installation Database


A-4



A-5


A-6



A-7



C-1

Appendix B: CHP Technical Potential Methodology


C-2

CHP Technical Potential Methodology This section describes the methodology for estimating the technical market potential for combined heat and power (CHP) in the industrial and commercial/institutional market sectors. Two different types of CHP markets (traditional CHP and combined cooling heating and power) were included in the evaluation of technical potential. Both of these markets were evaluated for high load factor (80% and above) and low load factor (51%) applications resulting in four distinct market segments that are analyzed.

Traditional CHP – Heating Only

Traditional CHP electrical output is produced to meet all or a portion of the base load for a facility and the thermal energy is used to provide steam or hot water. Depending on the type of facility, the appropriate sizing could be either electric or thermal limited. Industrial facilities often have “excess” thermal load compared to their on-site electric load. Commercial facilities almost always have excess electric load compared to their thermal load. Two sub-categories were considered:

High load factor applications: This market provides for continuous or nearly continuous operation. It includes all industrial applications and round-the-clock commercial/institutional operations such colleges, hospitals, hotels, and prisons. Low load factor applications: Some commercial and institutional markets provide an opportunity for coincident electric/thermal loads for a period of 3,500 to 5,000 hours per year. This sector includes applications such as schools, and laundries.

CHP with Heating and Cooling

All or a portion of the thermal output of a CHP system can be converted to air conditioning or refrigeration with the addition of a thermally activated cooling system. This type of system can potentially open up the benefits of CHP to facilities that do not have the year-round thermal load to support a traditional CHP system. A typical system would provide the annual hot water load, a portion of the space heating load in the winter months and a portion of the cooling load in during the summer months. Two sub-categories were considered:

Low load factor applications. These represent markets that otherwise could not support CHP due to a lack of thermal load. This sector includes applications such as commercial office buildings. Incremental high load factor applications: These markets represent round-the-clock commercial/institutional facilities that could support traditional CHP, but with cooling, incremental capacity could be added while maintaining a high level of utilization of the thermal energy from the CHP system. All of the market segments in this category are also included in the high load factor traditional market segment, so only the incremental capacity for these markets is added to the overall totals.

The estimation of technical market potential consists of the following elements:

Identification of applications where CHP provides a reasonable fit to the electric and thermal needs of the user. Target applications were identified based on reviewing the electric and thermal energy consumption data for various building types and industrial facilities.


C-3

Quantification of the number and size distribution of target applications. Several data sources were used to identify the number of applications by sector that meet the thermal and electric load requirements for CHP.

Estimation of CHP potential in terms of megawatt (MW) capacity. Total CHP potential is then derived for each target application based on the number of target facilities in each size category and sizing criteria appropriate for each sector.

Subtraction of existing CHP from the identified sites to determine the remaining technical market potential.

The technical market potential does not consider screening for economic rate of return, or other factors such as ability to retrofit, owner interest in applying CHP, capital availability, natural gas availability, and variation of energy consumption within customer application/size class. The technical potential as outlined is useful in understanding the potential size and size distribution of the target CHP markets in the state. Identifying technical market potential is a preliminary step in the assessment of market penetration.

The basic approach to developing the technical potential is described below:

Identify existing CHP in the state. The analysis of CHP potential starts with the identification of existing CHP. The U.S. currently has 4,100 CHP sites totaling 81.8 GW of capacity. Of this existing CHP capacity, 31% of the sites and 80% of the capacity are in the industrial sector. This existing CHP capacity is deducted from any identified technical potential.

Identify applications where CHP provides a reasonable fit to the electric and thermal needs of the user. Target applications were identified based on reviewing the electric and thermal energy (heating and cooling) consumption data for various building types and industrial facilities. Data sources include the DOE EIA Commercial Buildings Energy Consumption Survey (CBECS), the DOE Manufacturing Energy Consumption Survey (MECS) and various market summaries developed by DOE, Gas Technology Institute (GRI), and the American Gas Association. Existing CHP installations in the commercial/institutional and industrial sectors were also reviewed to understand the required profile for CHP applications and to identify target applications.

Quantify the number and size distribution of target applications. Once applications that could technically support CHP were identified, the Hoovers database from Dun & Bradstreet and the Major Industrial Plant Database (MIPD) from IHS were utilized to identify potential CHP sites by SIC code or application, and location. The Hoovers database is based on the Dun & Bradstreet financial listings and includes information on economic activity (8 digit SIC), location (metropolitan area, county, electric utility service area, state) and size (employees) for commercial, institutional and industrial facilities. In addition, for select SICs limited energy consumption information (electric and gas consumption, electric and gas expenditures) is provided based on data from Wharton Econometric Forecasting (WEFA). MIPD has detailed energy and process data for 16,000 of the largest energy consuming industrial plants in the United States. The Hoovers database and MIPD were used to identify the number of facilities in target CHP applications and to group them into size categories based on average electric demand in kilowatt-hours.

Estimate CHP potential in terms of MW capacity. Total CHP potential is then derived for each target application based on the number of target facilities in each size category. It was assumed that the CHP system would be sized to meet the average site electric demand for the target applications unless


C-4

thermal loads (heating and cooling) limited electric capacity. There are two distinct applications and two levels of annual load making for four market segments in all. In traditional CHP, the thermal energy is recovered and used for heating, process steam, or hot water. In cooling CHP, the system provides both heating and cooling needs for the facility. High load factor applications are assumed to operate at 80% load factor and above; low load factor applications operate at an assumed average of 4500 hours per year (51%) load factor. The high load factor cooling applications are also applications for traditional CHP, though the cooling applications have 25-30% more capacity than traditional.

CHP Target Applications

In general, the most efficient and economic CHP operation is achieved when:

1. the system operates at full-load most of the time (high load factor application),

2. the thermal output can be fully utilized by the site, and 3) the recovered heat displaces fuel or electricity purchases.

There are a number of commercial and industrial applications that characteristically have sufficient and coincident thermal and electric loads for CHP. Examples of these applications include food processing, pulp and paper plants, laundries and health clubs. Most commercial and light industrial applications have low base thermal loads relative to the electric load, but have high thermal loads in the cooler months for heating. Such applications include hotels, hospitals, nursing homes, college campuses, correctional facilities, and light manufacturing. In order to identify a complete list of applications where CHP provides a reasonable fit to the electric and thermal needs of the user, ICF reviewed electric and thermal energy (heating and cooling) consumption data for various building types and industrial facilities. Data sources included the DOE EIA Commercial Buildings Energy Consumption Survey (CBECS), the DOE Manufacturing Energy Consumption Survey (MECS) and various market summaries developed by DOE, Gas Technology Institute (GRI), and the American Gas Association. Existing CHP installations in the commercial/institutional and industrial sectors were also reviewed to understand the required profile for CHP applications and to identify target applications. There are two fundamental approaches to sizing CHP systems for a given application based on what the thermal energy will be used for:

Traditional Power and Heat CHP - Size the CHP system for the base thermal load (process steam, domestic hot water, pool heating, showers, laundries, kitchens).

Cooling, Heating and Power CHP - Size the CHP system to include thermally activated cooling to create additional thermal use during the cooling months that when combined with space heating justifies a larger CHP system that better matches the electric demand.

The following two tables show the target applications identified in these two categories as well as their assumed load profiles. Applications with a high load factor were assumed to operate for 7,000 hours a year, whereas applications with a low load factor were assumed to operate for 4,500 hours a year. The category and load profile combinations comprise the markets that were defined at the beginning of this section.


C-5

Table B-1 Traditional Combined Heat and Power Target Applications

Sector SIC Application Load Factor

Industrial 20 Food & Beverage High

Industrial 22 Textiles High

Industrial 24 Lumber and Wood High

Industrial 25 Furniture High

Industrial 26 Paper High

Industrial 27 Printing/Publishing High

Industrial 28 Chemicals High

Industrial 29 Petroleum Refining High

Industrial 30 Rubber/Misc Plastics High

Industrial 32 Stone/Clay/Glass High

Industrial 33 Primary Metals High

Industrial 34 Fabricated Metals High

Industrial 35 Machinery/Cptr Equip High

Industrial 37 Transportation Equip. High

Industrial 38 Instruments High

Industrial 39 Misc Manufacturing High

Commercial/Institutional 4952 Waste Water Treatment High

Commercial/Institutional 9223 Prisons High

Commercial/Institutional 7211 Laundries Low

Commercial/Institutional 7991 Health Clubs Low

Commercial/Institutional 7997 Golf/Country Clubs Low

Commercial/Institutional 7542 Carwashes Low

Table B-2 Cooling. Heating and Power Target Applications

Sector SIC Application Load Factor

Commercial/Institutional 43 Post Offices Low

Commercial/Institutional 52,53,56,57 Big Box Retail Low

Commercial/Institutional 4222 Refrig Warehouses High

Commercial/Institutional 4581 Airports Low

Commercial/Institutional 5411 Food Food Sales Low

Commercial/Institutional 5812 Restaurants Low

Commercial/Institutional 6512 Commercial Buildings Low

Commercial/Institutional 6513 Multi-Family Buildings High

Commercial/Institutional 7011 Hotels High

Commercial/Institutional 7374 Data Centers High

Commercial/Institutional 7832 Movie Theaters Low

Commercial/Institutional 8051 Nursing Homes High

Commercial/Institutional 8062 Hospitals High

Commercial/Institutional 8211 Schools Low

Commercial/Institutional 8221 Colleges/Universities High

Commercial/Institutional 8412 Museums Low

Commercial/Institutional 9100 Government Facilities Low


C-1

Appendix C: CHP Economic Potential Methodology


C-2

Energy Price Projections and CHP Performance Characteristics The expected future relationship between purchased natural gas and electricity prices, called the spark spread in this context, is one major determinant of the ability of a facility with electric and thermal energy requirements to cost-effectively utilize CHP. For this screening analysis, a fairly simple methodology was used:

Electric Price Estimates Industrial retail electric prices from EIA were used as the starting point for the analysis. The annual 2011 rate was used as it is the latest annual average rate available. These prices are shown in Table B-1. Price adjustments for customer load factor were defined as follows:

- High load factor – 100% of the estimated value

- Low load factor – 120% of the estimated value

- Peak cooling load – 150% of the estimated value

Since this analysis is based on state average prices, it does not reflect variations in price within a state, as is common for states with multiple large electric utilities (e.g. Ohio). The use of state average electric prices may lead to underestimation of the CHP economic potential.

For a customer generating a portion of his own power with CHP, standby charges are estimated at 15% of the defined average electric rate. Therefore, when considering CHP, only 85% of a customer’s rate can be avoided.

Natural Gas Price Estimates Delivered natural gas prices depend, among other factors, on the cost of gas at the wellhead and the cost of transportation to the customer. The natural gas price assumptions are based on the 2011 annual industrial retail prices from EIA, however that rate was replaced with the city gate rate plus $1 if it was lower than the industrial rate. The final rates used in the analysis are shown in the Table C-1.


C-3

Table C-1: Natural Gas and Electricity Prices

State

Natural Gas Price,

$/MMBtu53

Avg. Ind. Electric

Rate ($/kWh)

54 State

Natural Gas Price, $/MMBtu

Avg. Ind. Electric

Rate ($/kWh)

Alabama $4.36 $0.063 Montana $5.04 $0.053

Alaska $3.71 $0.157 Nebraska $4.34 $0.064

Arizona $5.65 $0.066 Nevada $7.73 $0.067

Arkansas $5.94 $0.056 New Hampshire $7.48 $0.123

California $4.54 $0.101 New Jersey $7.42 $0.114

Colorado $5.93 $0.071 New Mexico $4.70 $0.061

Connecticut $6.33 $0.132 New York $6.06 $0.122

Delaware $6.58 $0.089 North Carolina $5.20 $0.060

District of Columbia $6.07 $0.069 North Dakota $4.55 $0.062

Florida $4.98 $0.086 Ohio $5.76 $0.061

Georgia $4.90 $0.066 Oklahoma $6.41 $0.055

Hawaii $29.30 $0.284 Oregon $6.58 $0.055

Idaho $5.57 $0.051 Pennsylvania $6.74 $0.077

Illinois $5.18 $0.064 Rhode Island $8.67 $0.113

Indiana $5.69 $0.062 South Carolina $4.42 $0.059

Iowa $4.93 $0.052 South Dakota $4.62 $0.062

Kansas $5.14 $0.067 Tennessee $5.13 $0.072

Kentucky $4.06 $0.053 Texas $3.12 $0.062

Louisiana $3.07 $0.057 Utah $4.73 $0.051

Maine $9.49 $0.089 Vermont $4.98 $0.098

Maryland $7.00 $0.088 Virginia $5.14 $0.065

Massachusetts $8.91 $0.134 Washington $6.16 $0.041

Michigan $6.50 $0.073 West Virginia $4.99 $0.062

Minnesota $4.15 $0.065 Wisconsin $5.43 $0.073

Mississippi $4.57 $0.065 Wyoming $4.08 $0.054

Missouri $6.47 $0.059 US Average $6.05 $0.079

The rates listed in Table C-1 are plotted on the graph below to show the spark spread by state. States with low natural gas prices and high electric prices have the most attractive economic conditions for CHP.

53

Energy Information Administration. Natural Gas Price Tables. Industrial and City Gate Rates 2011. http://www.eia.gov/dnav/ng/ng_pri_sum_dcu_nus_m.htm. 54

Energy Information Administration. Industrial Electricity Prices 2011. http://www.eia.gov/electricity/data.cfm

http://www.eia.gov/dnav/ng/ng_pri_sum_dcu_nus_m.htm

http://www.eia.gov/electricity/data.cfm


C-4

Figure C-1: 2011 State Average Prices

CHP Technology Cost and Performance The CHP system itself is the engine that drives the economic savings. The cost and performance characteristics of CHP systems determine the economics of meeting the site’s electric and thermal loads. A sample of commercially available CHP systems was selected to profile performance and cost characteristics in CHP applications. The selected systems range in capacity from approximately 100 – 40,000 kW. The technologies include gas-fired reciprocating engines and gas turbines, and represent the most cost-effective technologies in each size range.

The cost and performance estimates for the CHP systems are based on work done for the EPA.55 These estimates were updated for this study based on contacts with manufacturers and developers active in the CHP market. Data is presented for a range of sizes that include basic electrical performance characteristics, CHP performance characteristics (power to heat ratio), equipment cost estimates, maintenance cost estimates, emission profiles with and without after-treatment control, and emissions control cost estimates. The estimates include the following:

Unit installed capital cost estimates based on an average U.S. site installation. These costs include any required exhaust aftertreatmentand appropriately sized absorption cooling for market applications that include cooling. The capital costs are reduced by the 10% federal investment tax credit.

Estimated non-fuel operating and maintenance costs are shown.

The CHP performance is based on the heat rate defined as the the quantity of natural gas needed to generate one kilowatt-hour on a higher heating value basis in Btu/kWh.

The thermal output is the recoverable waste heat from the prime mover in Btu/kWh

55

EPA CHP Partnership Program, Technology Characterizations, December 2007.

$0.00

$0.02

$0.04

$0.06

$0.08

$0.10

$0.12

$0.14

$0.16

$0.18

$0.00 $2.00 $4.00 $6.00 $8.00 $10.00

Ind

ust

rial

Ele

ctri

c P

rice

, $/k

Wh

Industrial Natural Gas Price, $/MMBtu

State Average Electric and Gas Prices


C-5

The heat rate and thermal output determine both the electrical generation efficiency (electric output (3412 Btu/kWh) divided by fuel input (heat rate0 and the overall CHP efficiency (the sum of electric and thermal output divided by the heat rate.)

Absorption cooling heat rates represent the thermal energy needed to produce one ton of cooling. The small reciprocating engines would utilize a single-effect absorption chiller requiring 17,000 Btu/ton and the gas turbines producing steam would require 10,438 Btu/ton in a double-effect absorption chiller.

The avoided boiler and electric air conditioning efficiencies are also shown. These values determine the site energy savings from the system thermal output.

Table C-2: CHP System Cost and Performance Characteristics

Market Size Bin 100 kW-

1 MW 1-5 MW

5-20 MW

20-50 MW

50-100 MW

Technology

Average of

100/800 kW

Recip Engine

3 MW Recip

Engine

10 MW Gas

Turbine

40 MW Gas

Turbine

40 MW Gas

Turbine

Capacity, kW 500 3,000 12,500 40,000 80,000

U.S. Average Capital Cost $2,325 $1,700 $1,750 $1,350 $1,350

After-treatment Cost, $/kW $150 $200 $180 $80 $80

Federal CHP Investment Tax Credit $248 $190 $193 $54 $0

Total Capital Cost, $/kW $2,228 $1,710 $1,737 $1,376 $1,430

Cooling Cost Adder, $/kW $596 $325 $258 $148 $127

Cooling Investment Tax Credit $60 $33 $26 $15 $13

Net Total Capital Cost w Cooling, $/kW $2,764 $2,003 $1,969 $1,510 $1,544

O&M Costs, $/kWh $0.020 $0.016 $0.009 $0.005 $0.005

Economic Life, years 10 15 20 20 20

Heat Rate, Btu/kWh 11,199 9,800 11,765 9,220 9,220

Thermal Output, Btu/kWh 5,500 4,200 4,674 3,189 3,189

Electric Efficiency, % 30.5% 34.8% 29.0% 37.0% 37.0%

CHP Efficiency 79.6% 77.7% 68.7% 71.6% 71.6%

Absorption AC Heat Rate, Btu/ton 17,000 17,000 10,435 10,435 10,435

Avoided Electric AC Eff., kW/ton 0.68 0.68 0.68 0.68 0.68

Avoided AC Electricity, kW/kW gen 0.220 0.168 0.305 0.208 0.208

Avoided Boiler Efficiency 80% 80% 80% 80% 80%

In the cooling markets, an additional cost was added to reflect the costs of adding chiller capacity to the CHP system. These costs depend on the sizing of the absorption chiller which in turn depends on the amount of usable waste heat that the CHP system produces. Figure C-2 shows this cost approximation.


C-6

Figure C-2. Absorption Chiller Capital Costs

The capital cost assumptions for CHP systems and cooling equipment stated above are national average cost figures. These costs can change significantly based on the region of the country due to differences in labor costs for installation as well as permitting and engineering costs. Table C-3 shows the capital cost adjustment factors that were used in the analysis to modify cost estimates by state to take into account these regional differences.

Table C-3: CHP System Capital Cost Adjustment Factors by State56

State Capital Cost

Adjustment Factor State

Capital Cost Adjustment Factor

Alabama 90% Montana 97%

Alaska 121% Nebraska 98%

Arizona 96% Nevada 108%

Arkansas 88% New Hampshire 104%

California 118% New Jersey 120%

Colorado 99% New Mexico 95%

Connecticut 118% New York 116%

Delaware 111% North Carolina 83%

District of Columbia 105% North Dakota 92%

Florida 94% Ohio 102%

Georgia 90% Oklahoma 86%

Hawaii 118% Oregon 107%

Idaho 95% Pennsylvania 109%

Illinois 114% Rhode Island 115%

Indiana 100% South Carolina 84%

Iowa 99% South Dakota 89%

Kansas 95% Tennessee 90%

Kentucky 98% Texas 87%

Louisiana 89% Utah 95%

Maine 100% Vermont 94%

Maryland 99% Virginia 94%

Massachusetts 119% Washington 107%

Michigan 105% West Virginia 103%

Minnesota 116% Wisconsin 107%

Mississippi 90% Wyoming 90%

Missouri 104% US Average 100%

56

Army Corps of Engineers, Construction Cost Index

Absorption Chiller Costs

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

$1,800

$2,000

0 1,000 2,000 3,000

Tons of Cooling

Ch

ille

r C

ap

ita

l C

os

t ($

/to

n)


C-7

CHP Payback Calculations The technical potential figures by state for industrial and commercial applications were evaluated based on the state average energy price assumptions (shown in Table C-1) and the CHP cost and performance characteristics (shown in Table C-2) to estimate simple payback of the CHP potential size and market categories the amount of CHP potential by simple payback period. The simple payback of a CHP system is the number of years that it will take for the annual operating cost savings from CHP to pay back the upfront costs of installing the CHP system. The higher the annual operating savings with CHP, the lower the simple payback will be and the more economically beneficial the CHP project.

For this analysis the CHP potential by payback is presented in three payback ranges:

<5 Years – Strong Potential

5-10 Years – Moderate Potential

>10 Years – Minimal Potential

For each state, the amount of CHP technical potential that falls into each of these payback ranges is Three alternative scenarios were also evaluated to assess the impact that changes in energy prices or CHP system costs would have on the amount of potential in the payback ranges. The alternative scenarios are:

25% reduction in the capital costs of the CHP system – this scenario would replicate an incentive for the installation of CHP. Some states currently have, or have had in the past, incentives to reduce the capital cost of CHP systems or to provide generation payments.

15% increase in electricity prices – this scenario replicates an improvement in the spark spread for a state. Spark spread is a critical factor in economic competitiveness for CHP and would be positively affected by increased electricity prices.

10% decrease in natural gas prices - this scenario replicates an improvement in the spark spread for a state. Spark spread is a critical factor in economic competitiveness for CHP and would be positively affected by decreased natural gas prices.

It is important to note that this analysis was done without consideration of individual state CHP financial incentives (e.g., Oregon shows little or no economic potential due to a very low spark spread, but a 35-50% business energy tax credit has stimulated the market), or individual site drivers such as reliability needs or emissions reductions.


D-1

Appendix D: CHP Potential Tables by Payback Category, Market, and Scenarios


D-2

Table D-1 Economic Potential for Industrial (Plus Wastewater Treatement and Prisons) CHP Units Less than 100 MW – Base Case

57

57

The ICF CHP market model separates CHP applications out into four categories, high load traditional, high load

cooling, low load traditional, and low load cooling. Table D-1 shows the high load traditional applictions which

include all industrial applications as well as wastewater treatment and prisons.

State

No

Potential,

Payback

>10

Marginal

Potential,

Payback 5-

10

Strong

Potential,

Payback <5

Total

Technical

Potential

(MW)

State

No

Potential,

Payback

>10

Marginal

Potential,

Payback 5-

10

Strong

Potential,

Payback <5

Total

Technical

Potential

(MW)

Alabama 721 342 0 1,063 Montana 173 0 0 173

Alaska 0 0 66 66 Nebraska 273 26 0 298

Arizona 405 114 0 519 Nevada 285 0 0 285

Arkansas 820 0 0 820 New Hampshire 0 212 74 286

California 0 4,014 245 4,258 New Jersey 0 1,392 314 1,706

Colorado 387 208 0 595 New Mexico 160 76 0 236

Connecticut 0 57 575 632 New York 0 1,198 1,502 2,701

Delaware 116 133 0 249 North Carolina 2,143 555 0 2,698

District of Columbia 60 0 0 60 North Dakota 139 0 0 139

Florida 173 861 83 1,117 Ohio 3,414 0 0 3,414

Georgia 1,661 555 0 2,217 Oklahoma 652 0 0 652

Hawaii 0 12 25 36 Oregon 861 0 0 861

Idaho 244 0 0 244 Pennsylvania 2,163 1,033 0 3,196

Illinois 1,849 727 0 2,576 Rhode Island 30 115 35 180

Indiana 1,375 0 0 1,375 South Carolina 1,175 386 0 1,561

Iowa 922 0 0 922 South Dakota 149 0 0 149

Kansas 508 96 0 603 Tennessee 1,092 503 0 1,595

Kentucky 902 932 0 1,834 Texas 1,977 1,554 340 3,871

Louisiana 1,117 571 0 1,688 Utah 458 0 0 458

Maine 273 237 0 510 Vermont 0 148 0 148

Maryland 457 252 0 709 Virginia 995 490 0 1,486

Massachusetts 0 832 337 1,169 Washington 1,078 0 0 1,078

Michigan 1,646 759 0 2,404 West Virginia 236 244 0 481

Minnesota 1,017 287 0 1,304 Wisconsin 1,523 1,114 0 2,638

Mississippi 608 188 0 796 Wyoming 64 110 0 174

Missouri 1,219 0 0 1,219 U.S. Total 35,521 20,333 3,596 59,451

Industrial Technical Potential Industrial Technical Potential


D-3

Table D-2 Economic Potential for Most Commercial CHP Units Less than 100 MW – Base Case

58

58

Table D-2 shows the high load traditional applictions which include all industrial applications as well as

wastewater treatment and prisons.

State

No

Potential,

Payback

>10

Marginal

Potential,

Payback 5-

10

Strong

Potential,

Payback <5

Total

Technical

Potential

(MW)

State

No

Potential,

Payback

>10

Marginal

Potential,

Payback 5-

10

Strong

Potential,

Payback <5

Total

Technical

Potential

(MW)

Alabama 790 74 0 865 Montana 170 0 0 170

Alaska 0 52 63 115 Nebraska 446 0 0 446

Arizona 1,156 20 0 1,176 Nevada 714 0 0 714


California 2,807 4,270 490 7,567 New Jersey 1,159 908 28 2,095





Florida 2,368 1,237 21 3,627 Ohio 2,536 0 0 2,536


Hawaii 77 201 61 339 Oregon 611 0 0 611

Idaho 225 0 0 225 Pennsylvania 2,810 109 0 2,919


Indiana 1,330 0 0 1,330 South Carolina 787 0 0 787



Kentucky 705 0 0 705 Texas 3,739 282 44 4,065

Louisiana 747 88 0 835 Utah 423 0 0 423

Maine 309 0 0 309 Vermont 0 133 12 145

Maryland 993 54 0 1,047 Virginia 1,575 0 0 1,575

Massachusetts 282 1,246 129 1,657 Washington 1,123 0 0 1,123


Minnesota 1,213 39 0 1,252 Wisconsin 1,335 0 0 1,335



Commercial Technical Potential Commercial Technical Potential


D-4

Table D-3 Economic Potential for Industrial (Plus Wastewater Treatement and Prisons) CHP Units Less than 100 MW – 25 Percent Reduction in CHP Capital Costs

59

59




State

No

Potential,

Payback

>10

Marginal

Potential,

Payback 5-

10

Strong

Potential,

Payback <5

Total

Technical

Potential

(MW)

State

No

Potential,

Payback

>10

Marginal

Potential,

Payback 5-

10

Strong

Potential,

Payback <5

Total

Technical

Potential

(MW)

Alabama 428 426 209 1,063 Montana 173 0 0 173

Alaska 0 0 66 66 Nebraska 220 78 0 298

Arizona 405 114 0 519 Nevada 285 0 0 285


California 0 1,518 2,740 4,258 New Jersey 0 1,392 314 1,706


Connecticut 0 0 632 632 New York 0 537 2,164 2,701



Florida 0 1,034 83 1,117 Ohio 2,606 809 0 3,414

Georgia 862 889 466 2,217 Oklahoma 652 0 0 652

Hawaii 0 0 36 36 Oregon 861 0 0 861



Indiana 1,019 356 0 1,375 South Carolina 1,175 386 0 1,561


Kansas 508 96 0 603 Tennessee 220 872 503 1,595

Kentucky 902 932 0 1,834 Texas 761 2,705 405 3,871

Louisiana 489 628 571 1,688 Utah 287 170 0 458

Maine 273 237 0 510 Vermont 0 31 117 148




Minnesota 1,017 287 0 1,304 Wisconsin 874 1,764 0 2,638





D-5

Table D-4 Economic Potential for Most Commercial CHP Units Less than 100 MW – 25 Percent Reduction in CHP Capital Costs

60

60



State

No

Potential,

Payback

>10

Marginal

Potential,

Payback 5-

10

Strong

Potential,

Payback <5

Total

Technical

Potential

(MW)

State

No

Potential,

Payback

>10

Marginal

Potential,

Payback 5-

10

Strong

Potential,

Payback <5

Total

Technical

Potential

(MW)

Alabama 732 58 74 865 Montana 170 0 0 170

Alaska 0 0 115 115 Nebraska 383 63 0 446

Arizona 1,156 20 0 1,176 Nevada 714 0 0 714







Florida 2,368 1,076 182 3,627 Ohio 2,536 0 0 2,536


Hawaii 77 201 61 339 Oregon 611 0 0 611






Kentucky 705 0 0 705 Texas 2,497 1,467 100 4,065

Louisiana 747 88 0 835 Utah 423 0 0 423

Maine 304 6 0 309 Vermont 0 133 12 145









D-6

Table D-5 Economic Potential for Industrial (Plus Wastewater Treatement and Prisons) CHP Units Less than 100 MW – 15 Percent Increase in Electric Prices

61

61




State

No

Potential,

Payback

>10

Marginal

Potential,

Payback 5-

10

Strong

Potential,

Payback <5

Total

Technical

Potential

(MW)

State

No

Potential,

Payback

>10

Marginal

Potential,

Payback 5-

10

Strong

Potential,

Payback <5

Total

Technical

Potential

(MW)

Alabama 102 752 209 1,063 Montana 144 29 0 173

Alaska 0 0 66 66 Nebraska 85 188 26 298

Arizona 405 114 0 519 Nevada 285 0 0 285


California 0 1,518 2,740 4,258 New Jersey 0 880 826 1,706


Connecticut 0 0 632 632 New York 0 537 2,164 2,701



Florida 0 1,034 83 1,117 Ohio 2,606 809 0 3,414

Georgia 193 1,468 555 2,217 Oklahoma 652 0 0 652

Hawaii 0 0 36 36 Oregon 861 0 0 861



Indiana 1,019 356 0 1,375 South Carolina 651 910 0 1,561



Kentucky 902 932 0 1,834 Texas 761 2,705 405 3,871

Louisiana 180 938 571 1,688 Utah 287 170 0 458

Maine 273 237 0 510 Vermont 0 31 117 148




Minnesota 604 700 0 1,304 Wisconsin 297 2,341 0 2,638





D-7

Table D-6 Economic Potential for Most Commercial CHP Units Less than 100 MW – 15 Percent Increase in Electric Prices

62

62



State

No

Potential,

Payback

>10

Marginal

Potential,

Payback 5-

10

Strong

Potential,

Payback <5

Total

Technical

Potential

(MW)

State

No

Potential,

Payback

>10

Marginal

Potential,

Payback 5-

10

Strong

Potential,

Payback <5

Total

Technical

Potential

(MW)

Alabama 732 58 74 865 Montana 155 15 0 170

Alaska 0 0 115 115 Nebraska 383 63 0 446

Arizona 1,156 20 0 1,176 Nevada 714 0 0 714







Florida 0 3,444 182 3,627 Ohio 2,536 0 0 2,536


Hawaii 0 77 262 339 Oregon 611 0 0 611






Kentucky 705 0 0 705 Texas 2,497 1,467 100 4,065

Louisiana 747 88 0 835 Utah 423 0 0 423

Maine 304 6 0 309 Vermont 0 122 23 145








the opportunity for chp in the united states€¦ · the opportunity for chp in the united states...

Documents