ENVIRONMENTAL REVENUE STREAMS FOR 

COMBINED HEAT AND POWER

U.S. Environmental Protection Agency 

Combined Heat and Power Partnership 

December 2008 
FOREWORD

The U.S. Environmental Protection Agency (EPA) established the 

Combined Heat and Power (CHP) Partnership as a voluntary 

program that seeks to reduce the environmental impact of power 

generation by promoting the use of CHP. CHP is an efficient, 

clean, and reliable approach to generating power and thermal 

energy from a single fuel source. CHP can increase operational 

efficiency and decrease energy costs, while reducing the emissions 

of greenhouse gases that contribute to global climate change. The 

CHP Partnership works closely with energy users, the CHP 

industry, state and local governments, and other stakeholders to 

support the development of new CHP projects and promote their 

energy, environmental, and economic benefits. 

The CHP Partnership provides resources about CHP technologies, 

incentives, emissions profiles, and other information on its Web 

site at <www.epa.gov/chp>. 

ii
CONTENTS

Executive Summary....................................................................................................................... iv 

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

Key Programs and Policies............................................................................................................. 1 

Cap and Trade Programs............................................................................................................. 1 

Regional Greenhouse Gas Initiative (RGGI).......................................................................... 2 

The Western Climate Initiative (WCI) ................................................................................... 4 

The NOX Budget Trading Program (NBP)............................................................................ 5 

Offset Programs.......................................................................................................................... 6 

New Source Review................................................................................................................ 6 

CO2 Offset Programs.............................................................................................................. 8 

Renewable Energy Certificate (REC) Programs....................................................................... 10 

Renewable Portfolio Standards (RPSs) ................................................................................ 10 

Voluntary Green Power Programs........................................................................................ 13 

CHP Project Example ................................................................................................................... 14 

Appendix: Calculating Environmental Revenue Streams............................................................. 17 

iii
iv

EXECUTIVE SUMMARY

Federal and state policymakers have created numerous incentives to encourage the deployment 

of clean distributed generation (DG), such as combined heat and power (CHP). Increasingly, 

governments have also created incentives intended to monetize the environmental attributes of 

clean, onsite power generation. These types of incentives are helping developers capture the full 

benefits of DG/CHP and overcome some of the financial hurdles created by market 

inefficiencies. 

CHP, also known as cogeneration, is the simultaneous production of electricity and thermal 

energy from a single fuel source, such as natural gas, biomass, biogas, coal, or waste heat. By 

using waste heat recovery technology to capture a significant proportion of the heat created as a 

byproduct in electricity generation, CHP systems typically achieve total system efficiencies of 60 

to 80 percent for producing electricity and thermal energy. Because CHP uses less fuel than 

conventional generation, it reduces emissions of greenhouse gases (GHGs) and air pollutants. 

Environmental revenue streams (ERSs) are one-time or ongoing payments by an entity (such as a 

state) to the developer or owner of an energy-generation project. ERSs reward the use of highly 

efficient and/or renewable energy generation technologies. Programs established to monetize the 

environmental benefits of clean DG offer the possibility of improving project economics and 

increasing the acceptance of CHP by energy users who are committed to reducing GHG 

emissions. Similar to CHP project development, every project will have unique attributes and be 

sited in an area that has a unique set of policies and programs in place. With the exception of 

companies that specialize in biomass or biogas projects, participation in programs such as 

emissions trading, offsets, or renewable energy credit (REC) programs has not been part of the 

typical CHP project development process to date. Many in the CHP industry are unfamiliar with 

the nuances of these programs, where and how they could be applicable to their projects, what 

the potential value of the ERS could be, and how to access the ERS to improve project 

economics and success. 

This paper discusses three key types of programs or policies (i.e., cap and trade, offset, and REC 

programs). It can also help project developers determine what ERS programs are available in 

their state, if CHP systems qualify, and if a project might be eligible for more than one program. 

The paper also provides a case study example of a CHP project in which potential ERS payments 

under several of the policies/programs discussed are calculated. An appendix contains guidance 

on how to estimate the monetary impacts of an ERS on a specific project. 
INTRODUCTION

By improving project economics, environmental revenue stream (ERS) payments encourage both 

the deployment of combined heat and power (CHP) or renewable energy projects and reductions 

in emissions of greenhouse gases (GHGs) and air pollutants. 

What Is CHP? 

CHP, also known as cogeneration, is the simultaneous 

production of electricity and thermal energy from a single 

fuel source, such as natural gas, biomass, biogas, coal, or 

waste heat. By using waste heat recovery technology to 

capture a significant portion of the heat created as a 

byproduct in electricity generation, CHP systems typically 

achieve total system efficiencies of 60 to 80 percent. 

Because CHP uses less fuel than conventional generation, it 

reduces emissions of GHGs and air pollutants. More 

information about CHP can be found at 

<www.epa.gov/chp/basic>. 

thermal energy from a single 

Specifically, ERSs provide 

revenue through the sale of 

credits for achieving emission 

reductions of nitrogen oxides 

(NOX) or carbon dioxide 

(CO2), or credits for the 

electricity generation from 

renewable energy sources or 

waste energy (e.g., CHP). The 

following three types of 

programs or policies offer 

ERSs for which CHP projects 

might qualify: 

• Cap and trade programs 

• Offset programs 

• Renewable energy certificate (REC) programs 

The monetary value of ERS varies. CHP projects possess unique energy and environmental 

attributes, and states have different environmental and energy policy goals that place different 

emphases on ERS. As such, the value of an ERS for a specific project is determined by that 

project’s emission profile and local market and policy conditions. 

This paper discusses the three types of programs or policies listed above to help project 

developers determine what ERS programs are available in their states, if a project might be 

eligible for more than one ERS program, and whether CHP projects qualify. Following the 

discussion of these policies and programs, the paper presents potential ERS payments for a 

sample CHP project. The appendix includes guidance for estimating the monetary impacts of an 

ERS on a specific project. 

KEY PROGRAMS AND POLICIES

Calculating the monetary impact of ERS on a specific project requires understanding the ERS 

program requirements, the energy and environmental profile of the project, and the market value 

of the credits. The key characteristics of the three types of programs and policies that offer ERS 

are described as follows. 

Cap and Trade Programs 

A cap and trade program is a market-based regulatory approach to reducing emissions across 

specific industry sectors (e.g., the electricity sector) in a specified geographic region. An 

emission cap is established for the sector, and tradable emission allowances are distributed to 

1
affected sources. Allowances are allocated either at no cost to the regulated entities or for a fee 

(usually through an auction). Each allowance represents the right to emit one unit of the 

regulated pollutant—typically 1 ton—in one year. To comply with the cap, an affected source 

must surrender allowances equal to its actual emissions during each compliance period. Because 

fewer allowances are issued than tons of emission released at the start of the program, the 

program ultimately results in emission reductions. A source can comply with the cap by 

installing pollution controls, implementing efficiency measures, or purchasing additional 

allowances from the market.1

 

Cap and trade programs historically have been an effective means for reducing emissions of NOX

and sulfur dioxide (SO2), which contribute to the formation of acid rain and smog. Because CHP 

projects reduce the emissions of these pollutants, some states encourage these projects by 

allowing them to participate in allowance trading. States that want to encourage clean energy 

projects typically set aside a portion of their tradable allowances and allocate them to projects 

that reduce or displace electricity generation. A clean energy project developer or owner can then 

sell the allowances to generate a revenue stream. Other states permit clean energy projects to 

participate directly in the cap and trade program, comparable to all other participants. In these 

cases, CHP projects can benefit from participation because their emission profiles can create 

extra allowances that may be sold. 

Several cap and trade programs that provide allowance allocations to CHP systems are in place 

or under development: 

$ The Regional Greenhouse Gas Initiative (RGGI) is a CO2 cap and trade program in the 

Northeast. Implementation rules in participating states vary in the extent to which they 

will use the program to promote CHP. 

$ The Western Climate Initiative (WCI) is developing a CO2 cap and trade program that 

could include CHP facilities. The design of the program is under development, and 

implementation is scheduled to begin in 2012. 

The NOX Budget Trading Program (previously called the NOX SIP Call) provides 

allocations to CHP facilities in several states; however, this program ends in 2008. 

Each of these programs is described in more detail below. 

Regional Greenhouse Gas Initiative (RGGI) 

RGGI is a cooperative effort by several northeastern and mid-Atlantic states to reduce CO2

emissions. RGGI is being implemented through a multistate cap and trade program for electric 

power generators larger than 25 MW. As of November 2008, 10 states were participating in 

RGGI (see Table 1). The CO2 cap will take effect in 2009 and will be reduced after 2014, thus 

requiring additional emission reductions. 

On August 16, 2006, RGGI released a model rule, subsequently updated on January 5, 2007, that 

has served as the basis for individual state rules. Each state was required to determine how to 

allocate allowances, track emissions and allowances, incorporate emission offsets, and address 

 

1

 Learn more about cap and trade programs from EPA’s Clean Air Markets Division Web site at 

<www.epa.gov/airmarkets/cap-trade/index.html>. 

2
the issue of leakage.2

 Each participating RGGI state must propose a state plan based on the 

model rule by December 31, 2008. 

The states agreed that at least 25 percent of each state’s allowances must be held for a consumer 

benefit set-aside to promote renewables and energy efficiency. As of November 2008, five states 

have proposed to auction 95 percent or more of their allowances, with the proceeds to be used to 

support energy efficiency and renewable energy. Two of the states that are auctioning a lower 

percentage of allowances—Connecticut and Maine—have established specific allowance setasides that will be used to support CHP. In addition, New Jersey has established regulations that 

will explicitly promote the development of CHP. Other states may choose to support CHP as part 

of their efficiency and renewable energy programs, the details for which have not yet been 

established. The specifics on the three state efforts to date are: 

• Connecticut has set aside up to 21.5 percent of allowances to benefit CHP across three 

set-aside accounts.3

 The customer-side distributed resources (CDR) set-aside account 

will include 3.5 percent of allowances, for which CHP is eligible. The CHP useful 

thermal energy set-aside account contains 5 percent of allowances. The CHP long-term

Power Purchase Agreement (PPA) set-aside account includes 13 percent of allowances. 

 

• Maine is setting aside allowances to benefit CHP units that are located at integrated 

manufacturing facilities.4

 Such facilities are eligible to receive allowances free-of-charge 

equal to their behind-the-meter CO2 emissions.5

 

• New Jersey provides direct allocation of CO2 allowances to affected cogeneration 

facilities that meet certain thermal efficiency criteria.6 Additionally, the New Jersey 

Economic Development Authority, which will receive 60 percent of the state’s auction 

revenue, is required to provide grants and other forms of financial assistance to support 

end-use energy efficiency projects and new, efficient electric generation facilities, 

including CHP.7

 

The first RGGI auction of allowances occurred on September 25, 2008. The 12,565,387 

allowances offered for sale reached an auction clearing price of $3.07 per ton, generating more 

than $38.5 million. The proceeds from the auction will be distributed to Connecticut, Maine, 

Maryland, Massachusetts, Rhode Island, and Vermont, the six RGGI states that offered 

allowances for sale during the first auction. The schedule for subsequent auctions has been set 

through 2009 as occurring each quarter (i.e., in December, March, June, and September).8

2

 Leakage refers to the idea that to meet the cap, an activity (such as electric generation) could be shifted to a region 

outside the cap (e.g., by purchasing electricity from a company outside the cap region). If such shifts occur, 

emissions would be reduced within the cap region, but overall emissions would not be reduced.

3

 www.ct.gov/dep/lib/dep/air/regulations/mainregs/22a-174-31.pdf 4

 “Integrated manufacturing facilities” are defined as a facility that (1) received an air emissions license from the 

Department of Environmental Protection prior to June 2007, (2) produces electricity from one or more carbon 

dioxide budget units, including one or more combined heat and power units, for transmission over the facilities of a 

transmission and distribution utility, and (3) routinely produces one or more other products for sale. 

5 www.maine.gov/dep/air/greenhouse/rggi.htm

6 www.nj.gov/dep/rules/adoptions/adopt_081117a.pdf 7

 www.njleg.state.nj.us/2006/Bills/PL07/340_.pdf 8 http://www.rggi.org/docs/Submission_Schedule_July_11_2008.pdf 

3
Table 1. RGGI State CO2 Budgets 

State CO2 Budget 

(short tons) 

Auction Proportion 

Connecticut 10,695,036 77% 

Delaware 

7,559,787 

60% in 2009, 

increasing by 8% 

each year until 2014 

Maine 5,948,902 85-90% 

Maryland 37,503,983 85% 

Massachusetts 26,660,204 99% 

New Hampshire* 

8,620,460 

at least 70% (up to 

2011); at least 83% 

thereafter 

New Jersey 22,892,730 99% 

New York 64,310,805 100% 

Rhode Island 2,659,239 100% 

Vermont 1,225,830 100% 

Total 188,076,976 

* Proposed auction proportions; regulations and rulemakings are not yet final. 

Source: Regional Greenhouse Gas Initiative. (2008, September 24). www.rggi.org/home; EPA. (2008, September 

24). State and Regional Climate Policy Maps–Power Sector GHG Cap and Trade. 

www.epa.gov/climatechange/wycd/stateandlocalgov/state_power_sec.html#four. 

The Western Climate Initiative (WCI) 

Launched in February 2007, WCI is a collaboration among seven U.S. governors and four 

Canadian Premiers to develop regional strategies to address climate change. WCI is identifying, 

evaluating, and implementing cooperative ways to reduce GHGs in the region. Other U.S. and 

Mexican states and Canadian provinces have joined as observers. Figure 1 shows WCI partners 

and observers as of November 2008. 

Figure 1. Western Climate Initiative Partners and Observers 

4
In August 2007, WCI partners set an overall regional goal to reduce aggregate GHG emissions 

15 percent below 2005 levels by 2020 through the use of a market-based mechanism (cap-andtrade). On September 23, 2008, WCI released its “Design Recommendations for the WCI 

Regional Cap and Trade Program,”9

 which presents an initial set of guidelines for designing the 

regional cap and trade program. Partner states and provinces still need to formally adopt design 

principles. The cap and trade system will most likely provide allowance allocations to CHP 

systems. 

The NOX Budget Trading Program (NBP) 

The NBP, previously called the NOX SIP Call, was promulgated by EPA in 1998. The NBP/NOX

SIP Call applies to 22 eastern states (see Figure 2) and was implemented in two phases. The first 

phase began in 2003 or 2004, depending on the state; the second phase began in 2007. The 

program is set to expire at the end of 2008. The NBP/NOX SIP Call was created to reduce 

emissions of NOX—a primary component in smog formation—from power plants and other large 

combustion sources. It is a cap and trade program and applies to NOX emissions from fossil-fuel 

power plants and large industrial boilers during the ozone season (from May through 

September). 

Figure 2. NOX Budget Trading Program Map 

Not under 

NOx SIP Call 

 NOx SIP 

Call states, no 

set-aside 

 SIP Call 

states with setaside

Source: EPA Clean Air Markets Division. www.epa.gov/airmarkets/index.html. 

Although EPA mandated emission reductions, the Agency gave states some flexibility in overall 

program design—in particular, with regard to the allocation of allowances to affected sources. 

 

9 www.westernclimateinitiative.org/ewebeditpro/items/O104F19865.pdf 

5
As part of this flexibility, some states decided to reward clean energy projects by establishing 

energy efficiency and renewable energy (EE/RE) set-asides in their allocation systems. Under 

the set-aside, clean energy projects such as biomass, CHP, wind, solar, hydro, and other 

electricity generation projects may be eligible to receive allowances that could be sold to other 

facilities. The seven states with set-asides include Indiana, Maryland, Massachusetts, Missouri, 

New Jersey, New York, and Ohio. These states allocate from 1 percent to 5 percent of their NOX

allowance budget to the EE/RE set-aside. Additionally, the Massachusetts allowance allocation 

is an output-based allocation10 that includes credit for the thermal output of CHP facilities. 

Allowances received from the EE/RE set-aside or CHP allocation can provide an additional 

revenue stream for existing projects, encouraging the deployment of new renewable and CHP 

projects. The value of the revenue stream is determined by: 

• How many allowances are allocated to each project 

• The price of allowances in the market 

Most states use a similar approach to identify facilities eligible for the set-aside and to allocate 

allowances to those units. Typically, energy efficiency projects including demand-side 

management (DSM) and renewables such as wind, hydro, biomass, landfill methane generation, 

and solar are eligible. For states that include CHP, a minimum overall efficiency requirement of 

60 percent is typically present. 

Allowances are often allocated at a rate of 1.5 lbs NOX/MWh generated; however, states might 

have different methodologies depending on the technology. Additionally, if the set-aside pools 

are oversubscribed or undersubscribed, then allowances often will be allocated on a pro rata 

basis. Allowances typically are awarded for one year, and applicants may reapply for a period 

ranging from 3 to 7 years. 

The price of allowances varies based on the conditions of the allowance market throughout the 

NBP/NOX SIP Call region. Historically, prices have ranged from $500 to $7,000 per ton.11 

Offset Programs 

Offsets counteract emissions that would have been emitted into the atmosphere. Acting as a 

compensating equivalent for reductions made at a specific source of emissions, offsets are 

generated by the reduction, avoidance, or sequestration of GHG emissions from a specific 

project. Discussed below are the two primary offset programs in which CHP projects can 

participate. 

New Source Review 

The new source review offset program applies in all areas of the country that are not in 

attainment with the National Ambient Air Quality Standard (NAAQS).12 The program requires 

 

10 Output allocations are based on the productive electric (and thermal) output of the unit versus the heat input. More 

information on structure of output-based regulations can be found in EPA’s Handbook on Output-Based Regulations 

for Air Regulators at <www.epa.gov/chp/publications>. 11 Ozone Transport Commission. (2003, March). NOX Budget Program, 1999-2002 Progress Report. 

www.epa.gov/airmarkets/progress/docs/otcreport.pdf. 12 The NAAQS has been established for lead, nitrogen dioxide (NO2), carbon monoxide (CO), particulate matter 

(PM), ground-level ozone (smog), and SO2. Air quality is monitored throughout the United States, and areas are 

6
major new or expanded emission sources to offset more than 100 percent of their increased 

emissions by making emission reductions within the local airshed. The offsets must be obtained 

as part of the air permitting process. 

To satisfy emission reduction requirements, industries may purchase emission reduction credits 

(ERCs) from other sources that have reduced equivalent emissions. ERCs are a commodity that 

can be traded among facilities within a limited geographic area. This trading market can provide 

a one-time payment to the source generating the emission reductions. CHP projects that replace 

more highly emitting combustion sources can create ERCs, most commonly for NOX emissions. 

NOX ERCs currently can be marketed in states with nonattainment areas for ozone (Figure 3). 

Figure 3. 8-Hour Ozone Standard Nonattainment and Maintenance Areas 

in the United States (2007) 

Source: EPA. (2007, March). Green Book Nonattainment Areas for Criteria Pollutants.

www.epa.gov/oar/oaqps/greenbk/map8hrnm.html. 

Each ERC represents 1 ton per year of reduced emissions. ERCs can only be created through 

strictly defined emission control actions, although specific ERC creation requirements vary 

widely by state. In general, ERCs can only be used in the state in which they are created, or in 

some cases within a limited interstate region. The reductions must be permanent, measurable, 

surplus to any emission limits that would otherwise apply, and enforceable. Typically, the source 

creating the reductions must take an enforceable permit condition for the reductions. 

Creation of ERCs usually entails a quantification process, negotiation with the state air 

permitting agency, and air permit modifications. This process can be time-consuming and costly. 

To be worthwhile, the project must create a significant emission reduction in an area where a 

 designated as “nonattainment” for any pollutants that exceed the standard. The new source review offset program 

applies to the nonattaining pollutants in each nonattainment and maintenance area. 

7
high demand for ERCs creates a favorable price. To learn about the local market for ERCs, 

contact the appropriate state environmental agency or an emission broker who is familiar with 

e market.13

$120,000 

er ton.14 More commonly, however, prices are in the $3,000 to $7,000 per ton range. 

lar 

2

 be sold to offset emissions at another location. CHP projects can be 

sed to create these offsets. 

 to 

 and is rarely defined quantitatively.15

ffsets also may need to be validated by a third party. 

tion 

al programs become available, the price of CO2 offsets 

ould change, perhaps substantially. 

th

The market for ERCs depends on the level of new construction activity in the region, as well as 

the local supply of ERCs. In California, prices for NOX ERCs can sometimes approach 

p

CO2 Offset Programs 

Separate from CO2 cap and trade programs, several states regulate CO2 emissions from particu

sources. To help regulated sources comply cost effectively, these states allow the sale of CO

emission offset credits. Projects that reduce CO2 emissions or other GHGs at one location 

generate CO2 credits that can

u

States or program administrators specify the criteria for projects that are eligible to earn CO2 

offsets. One common criterion is the “additionality” of an offset project. Additionality refers

the requirement that a project be one that would not have existed under a business-as-usual 

scenario without the incentive, funding, or other policy-related intervention being offered. The

exact means of proving additionality varies by program

O

Existing state offset programs in Oregon and Washington are summarized in the following 

sections. Because many of the programs are relatively new, rules and methods of implementa

are continually evolving. As addition

c

Oregon CO2 Emission Standards

Oregon has established CO2 emission standards for certain types of new facilities. Affected 

facilities include baseload power plants fueled by natural gas, non-baseload power plants (all 

fuels), and non-generating energy facilities (all fuels). The emission lim

16

its require new facilities 

 offset a portion of their GHG emissions before construction begins. 

n 

ets 

 

to

Given the limitations of current technologies, power plants cannot meet the established emissio

rate through efficiency alone. Thus, regulated facilities have two options for meeting the CO2

limits: 1) implement offset projects, either directly or through a third party; or 2) contribute to a 

monetary fund that is used to fund offset projects. CHP projects can be used to generate offs

13 The California South Coast Air Quality Management District posts a list of ERC brokers at 

<www.aqmd.gov/permit/ERCbrokers.html>. A recent report on the opportunities related to ERC creation from CHP 

facilities in New York provides background on this topic. See PACE Energy Project for The New York State Energy 

Research and Development Authority. (2006, January). Guidebook for Small Combined Heat and Power Systems 

Seeking to Obtain Emissions Reduction Credits in New York State. 14 Evolution Markets (2002, April 17). An Overview of NOx Emission Credit Markets in the U.S.

www.evomarkets.com/assets/presentations/pres_2-1019219509.pdf. 15 EPA’s Climate Leaders program has released guidelines on using offsets to help Partners achieve their GHG 

reduction goals. These guidelines use a “performance standard” methodology to quantitatively define additionality 

and selection and setting of the baseline. For more information see <www.epa.gov/climateleaders>. 16 Oregon Energy Facility Siting. (n.d.). Oregon Carbon Dioxide Emission Standards for New Energy Facilities.

www.oregon.gov/ENERGY/SITING/docs/ccnewst.pdf. 

8
to displace CO2 emissions. Only new projects qualify, but the Oregon regulations place no 

rized 

nding. In 2005, The Climate Trust paid $4.80 per 

etric ton of CO2. The expected price for 2007-2008 is $5.00 per metric ton. To date, the trust 

n turbine 

enerator, a heat recovery steam generator, and two auxiliary boilers. The second round of 

tion of the facility. 

limitations on the geographic location of offset projects. 

The Climate Trust, an Oregon nonprofit organization, is the only organization that is autho

to generate offsets from the monetary fund.17 In practice, power plant developers pay a fixed fee 

per metric ton of excess CO2 to the Climate Trust. The Climate Trust issues a request for 

proposal that specifies the criteria for eligible offset projects.18 These criteria always include an

additionality requirement. Selected offset projects are paid a fee per metric ton of CO2 offset 

produced. Both the fee and the method of payment are negotiated on a case-by-case basis. The 

fee has been increasing with each round of fu

m

has invested $8.8 million in offset projects. 

To date, only one CHP project, a CHP plant at Oregon State University, has received funding

through The Climate Trust. Currently under construction, the university’s CHP plant is expected 

to receive two separate rounds of offset funding from The Climate Trust. The Climate Trust

awarded the first round of funding in 2007, providing funding for a 5.5 MW combustio

g

funding is contingent on the delivery of proof of commercial opera

Washington State CO2 Offset Program

Washington first established regulations to limit CO2 emissions from new fossil fuel-fired po

plants in 2004. The limits apply to plants constructed after July 1, 2004, and modified facilitie

that increase production by more than 15 perc

wer 

s 

ent or 25 MW. These facilities must offset 20 

ercent of their new CO2 emissions. Because facilities with CHP systems receive a credit, they 

pt 

ements 

on by the energy facility site 

valuation council.” The regulations also apply to facilities that increase production by more than 

ays to comply: 

 

19

p

are not required to offset the full 20 percent. 

SB 6001, passed in May 2007, revised the 2004 statute and requires Washington to ado

California’s emission performance standard of 1,100 lbs of CO2/MWh for all new, long-term 

baseload electric power generation contracts, starting July 1, 2008.20 The Washington 

Department of Ecology developed the final rule and it was adopted on June 19, 2008.21 The CO2

mitigation requirements under Part I remain relatively unchanged from the original requir

passed in 2004. The regulations apply to fossil-fueled thermal generating facilities that submit an 

application to the Department of Ecology on or after July 1, 2004, and have a generating 

capability that is above 25 MWe, but less than 350 MWe, and are not considered a “fossil-fueled 

floating thermal electric generation facility subject to regulati

e

15 percent or 25 MW. Facilities have three w

17 For more information, see <www.climatetrust.org>. 18 The Climate Trust. (n.d.). The Climate Trust’s Criteria for Offset Projects.

www.climatetrust.org/pdfs/CT%20offset%20criteria.pdf. 19 Washington State Statute. (2004, December 22). Chapter 173-407 WAC, Carbon Dioxide Mitigation Program for 

Fossil-Fueled Thermal Electric Generating Facilities. www.ecy.wa.gov/pubs/wac173407.pdf. 20 SB 6001. (2007, May). www.leg.wa.gov/pub/billinfo/2007-08/Pdf/Bills/Senate%20Passed%20Legislature/6001-

S.PL.pdf. 21 Chapter 173-407 WAC. (2008, June 19). Carbon Dioxide Mitigation Program, Greenhouse Gases Emissions 

Performance Standard and Sequestration Plans and Programs for Thermal Electric Generating Facilities. 

www.ecy.wa.gov/laws-rules/wac173407_218/x0711a.pdf. 

9
$ Invest in CO2 offset projects directly 

$ Purchase carbon credits (verified by a recognized trading authority) 

s. For facilities that choose to make payments to a 

ird-party organization, the minimum payment is $1.60 per metric ton of CO2. The actual cost 

or 

g 

sued a notice of construction approval 

r site certification agreement; if the existing facility is upgraded; or if the existing facility or 

acilities can meet the standard through the 

se of nongeologic and geologic sequestration methods. 

ote the development of clean and renewable power 

eneration, including: 1) renewable portfolio standards (RPS) and 2) the voluntary green power 

y 

tificates. 

ECs usually are sold in units of 1 megawatt-hour (MWh) each. The certificates can be sold 

 they are associated. This flexibility enables purchasers 

e energy technologies. Many state RPSs have 

stablished a market for RECs on either a state or regional basis. Eligible sources receive a 

certain number of RECs each year based on their electricity generation. Electricity providers then 

purchase RECs to help meet their RPS targets. 

 

$ Make payments to a third party to implement offsets 

Eligible offset projects include alternative energy resources, energy efficiency measures, and 

CHP. Either the Washington Department of Ecology or the Energy Facility Site Evaluation 

Council approves all proposed offsets project

22 th

of the reductions acquired by the third party could exceed $1.60 per metric ton, for example, if 

acquired through the Oregon Climate Trust. 

Part II of the regulations concerns the new emissions performance standard. The new standard 

will apply to all new baseload generation and cogeneration facilities that are permitted for 

construction and operation after June 30, 2008, and that use fossil fuel or nonrenewable fuels f

all or part of their fuel requirements. The emissions performance standard also applies to existin

facilities if a new baseload generation facility or unit is is

o

unit enters into a new long-term financial contract. F

u

Renewable Energy Certificate (REC) Programs 

Several vehicles have emerged to prom

g

market. An RPS is typically mandated by law, while the green power market is a voluntary 

market guided by consumer choices. 

Both programs work, in part, through a trading program of RECs. A REC represents the propert

rights to the environmental, social, and other nonpower qualities of renewable electricity 

generation. A REC, and its associated attributes and benefits, can be sold separately from the 

underlying physical electricity associated with a renewable-based generation source. RECs are 

sometimes referred to as green tags, green energy certificates, or tradable renewable cer

R

separately from the electricity with which

to offset their conventional electricity use with renewable energy generated elsewhere. 

Renewable Portfolio Standards (RPSs) 

An RPS requires that electric power providers supply a specified percentage of customer load 

with electricity generated from eligible renewabl 23

e

22 The Energy Site Evaluation Council maintains a list of qualified third-party organizations for generating emission 

offsets. 

23 Some states have energy portfolio standards (EPS). An EPS is similar to an RPS but includes broader energy 

resources such as energy efficiency, waste energy, and CHP. 

10
Through November 2008, 33 states plus the District of Columbia had established RPS 

requirements or goals (see Table 2).24 The eligibility of projects to qualify for RECs varies 

widely by state. Nonemitting renewables, such as solar and wind power, are almost always 

included. All states currently include biomass as eligible under their standard; most states include 

landfill gas; and 12 states include CHP or waste heat recovery as eligible resources. The types of 

CHP energy that are eligible and the vintage date for projects that qualify vary greatly. For 

example, some RPS programs specify that CHP systems must meet a certain efficiency threshold 

to qualify (e.g., 50 percent total efficiency in Connecticut). In some states (e.g., Connecticut, 

Pennsylvania), CHP is in a separate tier from other renewables and has separate goals.25

 

24 EPA. (2007, June). Energy Portfolio Standards and the Promotion of Combined Heat and Power; EPA. (2008, 

October). State Clean Energy Policy Maps–Energy Supply Actions. www.epa.gov/cleanenergy/energyprograms/state-and-local/supply_actions.html#rps. 25 Additional information about state EPS/RPS programs, including expanded descriptions of those that include 

CHP, can be found in Energy Portfolio Standards and the Promotion of Combined Heat and Power. 

www.epa.gov/chp/documents/eps_and_promotion.pdf. 

11
Table 2. Eligibility of Technologies Under State Energy Portfolio Standards Biofuels Biomass CHP/Waste Heat Energy Efficiency Fuel Cells‡ Geothermal Hydro Landfill Gas Municipal Waste Ocean Thermal Photovoltaics Solar Thermal Electric Tidal Waste Tire Wave 

Wind 

AZ z z* z z z z z z

CA z z z z z z z z z z z z

CO z z** z z z z z

CT z z z z z z z z z z z z z

DE z z z z z z z z z z

DC z z z z z z z z z z z

HI z z z z z z z z z z z z z z

IA z z z z z z

IL z z z z z z z

MA z z z z z z z z

MD z z z z z z z z z z z

ME z z z z z z z z z z z

MI z z z z z z z z z z z

MN z z*** z z z z z z

MO z z z z z z

MT z z z z z z z

NC z z z z z z z z z z z

ND z z** z z z z z

NH z z z z z z z z z z z

NJ z z z z z z z z z z

NM z z z z z z z

NV z z z** z z z z z z z z z

NY z z z z z z z z z z

OH z z z z z z z z z z z

OR z z z z z z z z z z

PA z z z z z z z z z z z

RI z z z z z z z z z z

SD z z** z z z z z z z

TX z z z z z z z z z z

UT z z z z z z z z z z z z

VA z z z z z z z z

VT z z z z z z

WA z z z z z z z z z z z z z

WI z z z z z z z z z

 States with RPS goals, not mandatory requirements. 

* Renewable CHP systems are eligible; fossil-fuel CHP systems are not eligible. 

** Waste heat only. 

*** After January 1, 2010, hydrogen must be generated by renewable energy sources. 

‡ Includes only those states that allow fuel cells using nonrenewable energy sources of hydrogen. Some states (i.e., 

Arizona, California, Colorado, Delaware, Massachusetts, Maryland, Missouri, New Mexico, New York, Rhode 

Island, and Wisconsin) allow only renewable fuel cells as eligible technologies. 

Source: Database of State Incentives for Renewable Energy (DSIRE). Last accessed October 2008. 

www.dsireusa.org. 

12
Table 3. REC Prices as of July 

2008 

(1 REC = 1MWh) 

Connecticut 

Class I* 

2008 $25.00 

Class II* 

2008 $0.65 

Class III* 

2008 $26.75 

Maine 

2008 $0.15 

Massachusetts 

2008 $45.50 

Texas 

Q3-Q4 2007 $5.25 

Q1-Q2 2008 $4.00 

Delaware 

2007 Existing $0.65 

2007 New $13.75 

Rhode Island 

2008 $48.00 

New Jersey 

Solar 

2007/2008 $265.00 

Class I * 

2007/2008 $6.00 

2008/2009 $17.50 

Class II * 

2007/2008 $0.60 

Maryland 

Tier I * 

2006 $0.70 

2007 $0.75 

2008 $1.00 

Tier II * 

2006 $0.40 

2007 $0.55 

2008 $0.60 

DC 

Tier I * 

2007 $0.65 

2008 $1.15 

Tier II * 

2007 $0.75 

Pennsylvania 

Tier I * 

2007/2008 $8.50 

*For more information on the resources included 

under various classes and tiers for a state, visit the 

RPS description for each state available on the 

One significant variable in RPS program design is whether 

generators are eligible for both RECs and emission 

allowances under an applicable cap and trade program. 

Some states consider earning RECs and emission 

allowances from the same project to be “double counting” 

and prohibit it; others do not. For example, in New York, 

qualifying RPS facilities that receive RECs must transfer 

ownership of environmental attributes to the New York 

State Research and Development Authority. 

REC prices vary by state. Prices are influenced primarily 

by renewable energy supply, geographic limitations, 

resource eligibility, and vintage restrictions. States with 

stricter RPS eligibility generally have higher REC prices 

(see Table 3). Furthermore, RECs from zero-emitting 

renewables often garner the highest prices. For example, 

in New Jersey, the price of a solar REC for the 2007 and 

2008 calendar years was $265.26, 27

Voluntary Green Power Programs 

Voluntary green power programs offer electricity 

customers a way to reduce the environmental impacts of 

their electricity use. Participants can purchase green power 

by paying a higher price to their electricity provider for 

renewably produced electricity, or they can buy RECs 

through a REC marketer.28 

Green power is a subset of renewable energy and 

represents those renewable energy resources and 

technologies that provide the highest environmental 

benefit. EPA defines green power as electricity produced 

from solar, wind, geothermal, biogas, biomass, and lowimpact small hydroelectric sources. Customers often 

purchase green power for avoided environmental impacts 

and GHG reduction benefits 

In general, eligibility for voluntary RECs is limited to 

zero-emitting resources, with the exception of certain 

biomass fuels.29,30 Fossil fuel-fired CHP is ineligible 

 

26 RECs in these markets represent 1 MWh. RECs in some western states represent 1 kWh. 27 Evolution Markets (2008, July). REC Markets, Monthly Market Update. www.evomarkets.com. 28 EPA provides numerous resources to members of the public interested in purchasing green power, or developers 

seeking access to green power markets. EPA’s Green Power Partnership is a voluntary EPA program that seeks to 

increase the use of green power among leading U.S. organizations, providing educational and technical assistance to 

those seeking to purchase green power. More information on green power purchase requirements and green power 

can be found at <www.epa.gov/greenpower>. 

29 Green-E. Green-E National Standard. www.green-e.org/getcert_re_stan.shtml. 30Revised Uniform National Standard for EcoPower® Renewable Energy Certificates.

www.ert.net/ecopower/index.html. 

13
under both Green-E and Environmental Resource Trust (ERT) requirements. 

The voluntary market functions, in part, through the use of third-party certifiers. Third-party 

certifiers ensure that RECs come from the type of renewable resource claimed and that RECs 

have been sold only once. As in the mandatory RPS market, each certifier specifies the 

environmental attributes that transfer with the REC. For example, a Green-E REC includes all 

environmental attributes except cap and trade pollutants. An ERT REC includes indirect GHG 

emission reductions but no other emission reductions (e.g., NOX). In July 2008, prices paid for 

RECs on the voluntary market ranged from $3 to $12 for new facilities.31

CHP PROJECT EXAMPLE

To demonstrate the ERS that a CHP project might earn, the following highlights a 10-MW gasturbine-based CHP system located in Massachusetts and the ERS possible through three of the 

policies or programs discussed in this paper. Table 4 shows the performance and emissions 

characteristics for the gas turbine system. Table 5 presents a summary of the ERS payments 

under each program. 

Table 4. Performance and Emissions Characteristics for Gas Turbine CHP System 

Gas Turbine 

CHP System 

Performance 

Net Capacity (kW) 10,146 

Fuel Use (MMBtu/hr, HHV) 123.6 

Heat Rate (Btu/kW) 12,178 

Electric Efficiency (%) 28.0% 

Steam Output (lbs/Hr) 48,150 

Steam Pressure (psig) 150 

Steam Temperature (°F) 365.9 

Recoverable Thermal Energy (Btu/kWh) 5,220 

Electric /Thermal Output Ratio 0.65 

CHP Efficiency (%) 70.9% 

Emissions* 

NOX Emissions (lb/MWh) 0.672 

NOX Emissions (tons/year) 28.2 

Net CO2 Emissions CHP Basis (lbs/MWh) 738 

CO2 Emissions (metric tons/year) 28,195 

* Capacity factor assumed at 95 percent. Thermal utilization factor of 90 percent. 

 

31 Evolution Markets. (2008, July). REC Markets, Monthly Market Update. www.evomarkets.com. 

14
Table 5. Summary of ERS Payments for Sample Project 

New Source Review 

Program 

CO2 Offset 

Program 

($5/metric ton) 

CO2 Offset 

Program 

($10/metric ton) 

REC Program 

ERS Payment $275,100* $100,085** $200,170** $168,104** 

* This is a one-time payment made at the beginning of the project. 

** These are annual payments made over the life of the project. 

New Source Review 

Calculating the impact of an offset project under the NOX new source review offset program is 

somewhat more complicated than other potential revenue streams because the emission reduction 

value depends on the emission reduction relative to the equipment that is being replaced. The 

program applies only to CHP projects that can show that they will result in the permanent 

retirement of NOX emissions from boilers. Using the sample 10-MW CHP facility, it is assumed 

that the CHP system replaces a relatively high-emitting residual oil-fired boiler. The estimate of 

the offset program’s impact on the CHP project is based on the following assumptions: 

• The thermal output of the CHP system contributes to the retirement of a 53 MMBtu/hour 

residual (#6) fuel oil boiler that emits NOX at 0.367 lb/MMBtu. 

• The annual boiler capacity factor is 85.5 percent, equivalent to a CHP system with a 95 

percent electric capacity factor and 90 percent utilization of recovered thermal energy. 

• The payment for permanent NOX removal is assumed to be $4,500 per ton. This payment 

is a one-time payment made at the beginning of the project. There is an assumed $7,500 

transaction cost for the developer to participate in this project (based on typical 

permitting costs for a small project). 

Based on these assumptions, the sample 10-MW CHP project could expect a one-time payment 

of $275,100. Table 6 shows the results. 

Table 6. ERS Payment for Sample Project Under NOX New Source Review Offset Program 

Gas Turbine 

CHP System 

NOX Emissions from CHP (tons/year) 28.2 

NOX Emissions from Retired Unit (tons/year) 91.0 

Total NOX Credits (tons/year) 62.8 

Transaction Cost ($) $7,500 

Initial One-time Payment* ($) $275,100 

* Based on NOX payment of $4,500 per ton.

CO2 Offset Programs

The potential ERS payment for the sample project under a CO2 offset program in Massachusetts 

is based on two scenarios: offset payments valued at either $5 per metric ton or $10 per metric 

ton. The $5 per metric ton payment is in line with past Oregon Climate Trust solicitations, and 

the $10 per metric ton payment is used to show the potential impacts on project economics from 

an increased value of offsets due to competition from other programs. The Oregon Climate Trust 

bases the CO2 emission offsets on regional marginal electric grid CO2 emission factors. The 

2005 eGRID subregion CO2 emission factor for Massachusetts is 0.571 metric tons CO2/MWh. 

15
16

Table 7. ERS Payment for Sample Project Under CO2 Offset Program 

Gas Turbine 

CHP System 

NERC Subregion CO2 Emission Rate for 

Massachusetts (metric ton/MWh)* 0.571 

CHP System CO2 Emissions (metric tons/year) 28,195 

CO2 Credits (metric tons/year) 20,017 

Value of CO2 Credits at $5/metric ton ($) $100,085 

Value of CO2 Credits at $10/metric ton ($) $200,170 

*Obtained from eGRID 2007 subregion GHG output emission rates for 2005. 

www.epa.gov/cleanenergy/documents/egridzips/eGRID2007V1_0_year05_GHGOutputRates.pdf

Renewable Energy Certificate Programs 

Eligibility for an RPS can have a significant effect on project economics. As of July 2008, the 

Massachusetts REC price was approximately $45.50. RECs in Massachusetts are reserved for 

renewable energy projects; CHP projects can generate RECs as well, but the values are much 

lower because they are based only on the increased efficiency of CHP heat recovery. Currently, 

the REC value for CHP is approximately $2/MWh. Table 8 shows the potential ERS. 

Table 8. ERS Payment for Sample Project Under REC Program 

Gas Turbine 

CHP System 

RECs Generated 84,052 

Market Value of RECs ($/MWh) $2 

Total ERS $168,104 
Appendix: Calculating Environmental Revenue Streams 

The following table provides guidance for estimating the potential revenue from the sale of emission 

allowances, emission offset credits, and RECs. Be aware that the calculation methodologies presented 

might not be applicable in every situation because not all state programs operate in the same way. The 

table provides a framework, however, for comparing the monetary value of different environmental 

revenue streams to assist in estimating the economic benefits for your project. 

Code Information Needed Project 

Data 

Notes 

A Generator nameplate capacity, MW 

B Annual capacity factor, % 

C NOX emissions, tons/year 

D CO2 emissions, tons/year 

NOX New Source Offsets for CHP

J NOX emissions from retired unit, 

tons/year 

 Actual historical emissions from recent period 

for existing unit to be retired. 

K Offset transaction cost, $ One-time payment. Fees can range from 

$5,000 to $15,000. 

L NOX credits, tons/year L = J – C 

M Market value of NOX credits, $/ton Obtain latest price from local emission credit 

brokers. 

N Environmental revenue stream, $ 

(one-time payment) 

 N = (L × M) – K 

CO2 Offsets 

O CO2 regional emission rate, tons 

CO2/MWh 

 Obtain from eGRID 2007 or other stateapproved source for your region of the 

electrical grid. 

P Cost of monitoring and verification, 

$/yr 

 Typical costs could be $2,500 per year. 

Q CO2 credits, tons/year Q = (A × B × O × 8760) - D 

R Market value of CO2 credits, $/ton Obtain latest price from local emission credit 

brokers. 

S Environmental revenue stream,32

$/year 

 S = (Q × R) - P 

REC Market 

T RECs generated, MWh T = A × B × 8760 

U Market value of REC, $/kWh Obtain latest price from local emission credit 

brokers. 

V Environmental revenue stream, 

$/year 

 V = T × U 

 

32 One-time costs might apply for due diligence negotiations, legal fees, and development of a monitoring and verification 

plan. 

17