REGULATORY ASSISTANCE PROJECT  RESEARCHBRIEF AUGUST 2010  WWW.RAPONLINE.ORG

An Emissions Performance Standard (EPS) 

establishes a maximum level of carbon 

dioxide (CO2) emissions, or CO2 equivalent,

per unit of output from an electricitygenerating power plant. An EPS has been

described as analogous to an energy 

efficiency standard for appliances such as 

refrigerators, in which minimum 

performance standards are set. Beyond that,

it is up to the market to compete, so long as 

each of the manufactured appliances can

meet or exceed the minimum standard.

California, Washington and Oregon 

have each adopted an EPS that applies to 

new and existing baseload generation for 

which electric utilities enter into long-term 

commitments (e.g., new construction and 

long-term contracts), with certain 

exceptions. Other states have adopted 

related emission performance conditions 

that are incorporated into policies designed 

to reduce CO2 emissions specifically from 

coal-fired plants or encourage the 

development and deployment of carbon 

capture and sequestration. In Montana, the 

approval of new coal-fired plants is 

conditioned upon emissions reductions 

achieved through carbon capture and 

storage. In New Mexico, tax and cost 

recovery incentives are available to coalfired plants that can meet an emissions 

performance standard. And in Illinois, 

emissions reduction requirements are 

incorporated into a clean-coal portfolio

standard that obligates utilities to procure a 

certain percentage of electricity from new 

coal-fired plants that reduce emissions by at 

least 50% through carbon capture and 

sequestration. An overview of these 

policies is presented below. 

California

California’s EPS statute, Senate Bill 

1368, was enacted in September 2006 and 

detailed regulations were adopted in January 

2007. In adopting SB 1368, the California 

Legislature concluded that an EPS was 

ResearchBrief Regulatory Assistance Project

 August 2010

Emissions Performance Standards

In Selected States

T

The Regulatory Assistance Project research staff prepared this summary of Emissions 

Performance Standards (EPS) that have been adopted by various states in the United 

States. It is designed to provide a comparative summary of key EPS components for the 

interested reader rather than attempt to evaluate the relative merits of the alternative 

policies discussed in the summary. Each of the state summaries includes links to 

applicable laws and rules. 

Research Staff 

Authors:

Chris Simpson

Brenda Hausauer

Ajith Rao
 PAGE 2 REGULATORY ASSISTANCE PROJECT  RESEARCHBRIEF AUGUST 2010  WWW.RAPONLINE.ORG

necessary to protect ratepayers and the 

economy from certain risks and costs and as 

a complement to other key policies that 

encouraged investment in cost-effective 

energy efficiency and renewable energy 

resources.1

SB 1368 set out a process by which the 

California Public Utilities Commission 

(CPUC) would issue EPS implementation 

rules for the investor-owned utilities (IOUs) 

it regulated, with the California Energy 

Commission following shortly thereafter 

with a set of consistent EPS rules for 

California’s publically-owned utilities. 

Covered Procurements

The California EPS establishes a 

facility threshold based on the power plant’s 

capacity factor.2 More specifically, the EPS 

applies to any and all long-term financial 

commitments 3 with ―baseload‖ facilities,

defined as power plants that are designed 

and intended to provide electricity at an 

annualized plant capacity factor of at least 

60%.4 These are facilities that essentially 

operate ―24/7‖ and are not able to ramp up 

and down quickly, provide spinning 

reserves, or exhibit other operating 

characteristics that are associated with loadfollowing or peaking resources. 

With some exceptions, California 

utilities must comply with the EPS for all 

new or renewed contracts of 5 years or 

longer that they enter into with baseload 

facilities, for all new plant investments--

including upgrades under certain 

circumstances, or when acquiring a new or 

increased ownership interest in baseload 

facilities. Offsets or averaging of plant 

performance is not permitted. However, the 

CPUC may provide a case-by-base 

exemption from the EPS to address 1) 

unanticipated electric system reliability 

needs, or 2) catastrophic events or threat of 

significant financial harm that may arise 

from unforeseen circumstances.

Some facilities are grandfathered, or do 

not need to comply with the EPS: 1) 

existing baseload facilities owned by the 

IOUs or public utilities, unless they become 

subject to new long-term commitments; 2) 

existing combined-cycle gas turbine 

(CCGT) power plants in operation or 

permitted in California before June 30,2007. 

The CPUC’s Decision 07-01-039 further 

describes the long-term commitments, both 

new ownership investments and new 

contract commitments that are covered by 

the California EPS.5

Level of Emissions Performance 

Standard

Pursuant to SB 1368, the performance 

level of the EPS must be no higher than the 

emissions rate of a CCGT power plant but 

does not specify the emissions rate for a 

CCGT.6 Based on its review of emissions 

rates associated with various CCGT power

plants, the CPUC adopted an EPS emissions 

rate of 1100 lbs CO2/MWh.

 

Treatment of Renewables 

The CPUC made an up-front 

determination that the following renewable 

resources and technologies are EPScompliant: solar thermal electric (with up to 

25% gas heat input), wind, geothermal (with 

or without reinjection) and generating 

facilities using biomass (e.g., agricultural 

and wood waste, landfill gas) that would 

otherwise be disposed of utilizing open 

burning, forest accumulation, landfill, 

spreading or composting.7

 

Calculation of Net Emissions for 

Combined Heat and Power

SB 1368 directed the CPUC to adopt a 

methodology for calculating the emissions 

rate associated with cogeneration facilities 

that recognizes both the thermal output (heat 

or steam) and the electrical output 

associated with cogeneration.8 The CPUC 

discusses its calculation of emissions 
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associated with cogeneration in Decision 

07-01-039.

Consideration of Carbon Capture and 

Storage

Carbon capture and storage (CCS) 

–also referred to as ―carbon sequestration‖ 9

–is an approach to mitigating Greenhouse 

Gas (GHG) emissions based on capturing 

CO2 from large point sources such as coal 

generation plants and storing it (e.g., by 

injecting the CO2 into geological 

formations) instead of releasing it into the 

atmosphere. California’s EPS statute 

provides that ―[c]arbon dioxide that is 

injected in geographical formations, so as to 

prevent releases into the atmosphere, in 

compliance with applicable laws and 

regulations shall not be counted as 

emissions of the power plant in determining 

compliance‖ with the EPS.10 In 

implementing this directive, the CPUC 

determined that any facility that proposes to 

use CCS to meet the standard must present a 

―reasonable and economically and 

technically feasible plan that will result in a 

permanent sequestration of CO2 once the 

injection project [i.e., injection of CO2 into 

permanent geological storage] is operational 

and that the CO2 injection project complies 

with applicable laws and regulations.‖ 11

The CPUC recently clarified that the plan 

must comply with federal and/or state 

monitoring, verification and reporting 

requirements applicable to projects designed 

to permanently sequester CO2 and prevent 

its release from the subsurface, and further 

specified how a plan may meet monitoring, 

verification and reporting requirements if 

federal and/or state requirements do not 

exist or have not been finalized.

12

The plan is reviewed in a formal CPUC 

proceeding, with stakeholder participation, 

and subject to full Commission vote of 

approval or denial. 

Improvements to Existing Plants that 

Trigger EPS Compliance

Improvements to existing baseload 

plants that will trigger the EPS (as a new,

long-term financial commitment) are 

defined under the California rules as those 

that: 13

(a) For combined-cycle, natural gas power 

plants in operation or permitted before June 

30, 2007, increase the generation capacity 

by 50 megawatts (MW) or more.

(b) For other power plants, are intended to 

extend the life of one or more units by five 

years or more.

(c) Are intended to increase the rated 

capacity of the power plant.

(d) Are intended to convert a non-baseload 

power plant into a baseload power plant.

 

Citations

Senate Bill 1368 (Stats 2006, ch. 598):

http://www.energy.ca.gov/emission_standar

ds/index.html

CPUC Decision 07-01-039 issued on 

January 25, 2007 in Rulemaking 06-04-009: 

http://www.cpuc.ca.gov/PUBLISHED/FIN

AL_DECISION/64072.htm.

Washington

Washington’s EPS law, SB 6001, 

became effective July 22, 2007, and specific 

rules were adopted on June 24, 2008. 

Washington’s EPS is modeled on 

California’s law and it applies to both IOUs

and consumer-owned utilities (COUs). The 

key features are summarized below.

Covered Procurements

Like the California standard, 

Washington’s EPS covers baseload electric 

generation for which electric utilities enter 

into long-term financial commitments (on or 

after July 1, 2008.) The definition of a 

baseload facility is identical to the one used 

in California—and the definitions of what 

constitutes a long-term commitment are 

very similar. (See above.) 
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Under SB 6001, the following facilities 

are grandfathered or do not need to comply 

with the EPS: 1) baseload generation 

facilities in operation as of June 30, 2008, 

until they are the subject of long-term 

financial commitments; 2) all electric 

generation facilities or power plants 

powered exclusively by renewable 

resources; and 3) cogeneration facilities 

fueled by natural gas or waste gas in 

operation as of June 30, 2008, until they are 

the subject of a new ownership interest or 

are upgraded.14 As in California, the 

Commission may provide a case-by-case 

exemption from the EPS to address: 1) 

unanticipated electric system reliability 

needs; 2) catastrophic events or threat of 

significant financial harm that may arise 

from unforeseen circumstances.

It appears to be an open question 

whether the law covers out-of-state 

generation. The issue is likely to be 

resolved by court decision or the 

commission’s interpretation when an actual 

case tests the issue.15

Level of the Emissions Performance 

Standard

The standard is the lower of 1) 1,100 

pounds of GHG per MWh; or 2) the average 

available GHG emissions output as 

determined and updated by the Washington 

Department of Community, Trade & 

Economic Development (CTED). 

Washington’s statute defines net emissions 

from combined heat and power on an output 

basis, similar to California. 

To update the standard, CTED will 

conduct a survey every 5 years of new 

CCGTs commercially available and offered 

for sale by manufacturers and purchased in 

the US. CTED must use the survey results 

to adopt by rule the average available GHG 

emissions output. The survey results must 

be reported to the legislature every five

years, beginning June 30, 2013. The CTED 

must also consult with specified groups 

(such as the Bonneville Power Authority) 

and consider the effects of the standard on 

system reliability and the overall costs to 

electricity consumers.

Treatment of Renewables

As discussed under ―Covered 

Procurements‖ above, electric generation 

facilities or power plants powered 

exclusively by renewable resources do not 

have to comply with the EPS. ―Renewable 

resources‖ are defined as electricity 

generation facilities fueled by: (a) water; (b) 

wind; (c) solar energy; (d) geothermal 

energy; (e) landfill gas; (f) biomass energy 

utilizing animal waste, solid organic fuels 

from wood, forest, or field residues or 

dedicated energy crops that do not include 

wood pieces that have been treated with 

chemical preservatives such as creosote, 

pentachlorophenol, or copper-chromearsenic; (g) byproducts of pulping or wood 

manufacturing processes, including but not 

limited to bark, wood chips, sawdust, and 

lignin in spent pulping liquors; (h) ocean 

thermal, wave, or tidal power; or (i) gas 

from sewage treatment facilities.16

Consideration of Carbon Capture and 

Storage 

In calculating compliance with the EPS, 

the Washington statute excludes emissions 

that are injected permanently in geological 

formations or other CO2 storage methods/ 

mitigation plans approved by the 

Washington Department of Ecology and

Energy Facility Site Evaluation Council.

SB6001 permits utilities to apply for preapproval of a plan to sequester carbon for 

purposes of meeting the EPS, and are under

obligation to demonstrate financial, 

technical and economic feasibility in their 

submittal—similar to the implementing 

rules adopted for California. However, the 

Washington statute includes additional 

provisions not currently included in the 
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California rules or statute: 1) a requirement 

that carbon sequestration must begin within 

5 years of plant operation, and 2) penalty 

provisions for failure to achieve the 

implementation plan on schedule.17

Improvements to Existing Plants that 

Trigger EPS Compliance

Under Washington’s EPS, the 

following conditions will trigger EPS 

compliance for an existing plant:18

(a) The unmodified station generating 

capability is 350 MWh or greater;

(b) The increase to the facility or units is the 

greater of the following measures:

 (i) An increase in station-generating 

capability of more than 25 MWh; or

 (ii) An increase in CO2 emissions output 

by fifteen percent or more.

Other Information 

The Washington EPS is enforced as 

follows: For IOUs, the Washington Utilities 

and Transportation Commission (WUTC) 

must review a long-term financial 

commitment in a general rate case. WUTC 

must also review an IOU’s proposed 

decision to acquire electric generation or 

enter into a power purchase agreement for 

electricity. WUTC must consult with the 

Washington Department of Ecology when 

verifying compliance with the EPS. For 

COU’s, the utility’s governing board must 

review a long-term financial commitment in 

consultation with the Washington 

Department of Ecology, after which the 

State Auditor is responsible for auditing 

compliance with the EPS and the Attorney 

General is responsible for enforcing 

compliance. 

The EPS must be reviewed at least 

every five years or upon implementation of 

a federal or state law or rule regulating 

carbon dioxide emissions of electric 

utilities.

Citations 

SB 6001: 

http://apps.leg.wa.gov/billinfo/summary.asp

x?year=2007&bill=6001

Washington Administrative Code rules to 

implement the law: 

http://www.efsec.wa.gov/rulerev.shtml#CO

2

Oregon 

Oregon’s EPS law, SB 101, was 

enacted on July 22, 2009, and all sections of 

the bill became operative on July 1, 2010.19

SB 101 expands the 1997 standards 

established by HB 3283, which specified 

that baseload gas power plants, nonbaseload power plants, and non-generating 

energy facilities must reduce their net 

carbon dioxide emissions 17% below the 

most efficient baseload gas plant in the 

United States.

As indicated below, SB 101 

incorporated many of the key features of the 

California and Washington EPS laws.

 

Covered Procurements

Covered procurements under SB 101 

are new, long-term financial commitments 

to baseload facilities entered into by the

utility. Long-term commitments includes 

contracts (or contract renewals) of more 

than five years with a baseload facility. 

Oregon’s statute explicitly excludes 

renewable (as defined below) from the EPS, 

as well as any generating source that uses 

natural gas or petroleum distillates as a fuel 

source and is primarily used to serve either 

peak demand or to integrate energy from a 

renewable energy source. 

SB 101 also exempts certain facilities, 

including co-generation facilities in 

operation prior to July 1, 2010 unless 

subject to a new long-term financial 

commitment. The statute permits the 

governing board of a COU to exempt longterm financial commitments between the 

COU and a joint operating entity recognized 
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under federal law where the COU had an 

ownership interest prior to July 1, 2010.

20

In addition, an exemption for an 

individual generating facility from the EPS

may be considered to address unanticipated 

electricity system reliability needs or 

catastrophic events or threat of significant 

financial harm that may arise from 

unforeseen circumstances.

Level of the Emissions Performance 

Standard 

The performance standard is also set at 

the same level of the California and 

Washington EPS (1,100 pounds of CO2 per 

megawatt-hour) and emissions from 

combined heat and power are determined 

using an output-based methodology. SB 

101 defines ―total emissions‖ as excluding

emissions associated with transportation, 

fuel extraction or other life-cycle emissions 

associated with obtaining the fuel for the 

facility. 

Treatment of Renewables

As indicated above, a facility that is 

powered exclusively by renewable energy 

sources is exempt from Oregon’s EPS 

requirement. ―Renewable energy sources‖

include wind energy; solar photovoltaic and 

solar thermal energy; wave, tidal and ocean 

thermal energy, as well as geothermal 

energy.21

Consideration of Carbon Capture and 

Storage

The Oregon EPS does not apply to 

emissions from a generating facility that has 

―in place a plan, as determined by the Public 

Utility Commission, to be a low-carbon 

emissions resource, pursuant to sufficient 

technical documentation, within seven years 

of commencing plant operations.‖ An 

OPUC staff person familiar with SB 101 

indicated that this language is intended to 

include coal plants with a plan to capture 

and sequester carbon emissions within a 

designated period of time. However, there 

are no explicit references to CCS in SB 101.

 

Improvements to Existing Plants that 

Trigger EPS Compliance

 The Oregon statute describes what 

improvements to existing plants will trigger 

the EPS in the form of ―exclusions‖ to 

covered procurements, as follows:22

(a) Routine or necessary maintenance;

(b) Installation of emission control 

equipment;

(c) Installation, replacement or modification 

of equipment that improves the heat rate of 

the facility or reduces a generating facility’s

pounds of greenhouse gases per MWh of 

electricity;

(d) Installation, replacement or modification 

of equipment where the primary purpose is 

to maintain reliable generation output 

capability and not to extend the life of the 

generating facility, and that does not 

increase the heat input or fuel usage as 

specified in existing generation air quality 

permits, but that may result in incidental 

increases in generation capacity;

(e) Repairs necessitated by sudden and 

unexpected equipment failure; or

(f) An acquisition of an additional interest.

Other Information

SB 101directs the Oregon Public 

Utilities Commission (OPUC) to review the 

EPS once every three years. After review, 

the OPUC may modify the EPS by rule and 

may also modify the GHGs included under 

the EPS.23

OPUC is also required to revoke the 

certificate of an electricity service supplier 

if it serves customers in the state with 

baseload electricity from a facility that does 

not comply with the EPS. It does not 

include specific enforcement language 

relating to COUs.
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Citations

SB 101: 

http://www.leg.state.or.us/09reg/measpdf/sb

0100.dir/sb0101.en.pdf

Montana

Montana’s law regarding constraints on 

unabated coal plants, House Bill 25, was 

passed in May 2007. HB 25 prohibits the 

utility from acquiring an equity interest or 

leasing/contracting with a new coal plant 

(constructed after January 1, 2007), unless 

the facility or equipment captures and 

sequesters a minimum of 50% of the carbon 

dioxide produced by the facility. It permits 

sequestration offsite from the facility.

HB 25 only applies to formerly 

restructured utilities in Montana, which by 

definition is a single utility (Northwest 

Energy). The provisions of HB 25 apply 

when Northwest Energy seeks pre-approval 

of an electricity supply resource that it has 

not previously procured. The law does not 

apply to entities that are outside the

Commission’s jurisdiction, such as rural 

electric cooperatives which serve about 1/3 

of the state.

24

HB 25 is currently untested. The 

Commission updated existing rules to adopt 

the law, but the rules simply refer to the 

law.25

Citations

Montana Code Annotated 69-8-421: 

http://data.opi.mt.gov/bills/mca/69/8/69-8-

421.htm;

HB 25: 

http://data.opi.mt.gov/bills/2007/billhtml/H

B0025.htm

New Mexico

New Mexico has adopted what can be 

characterized as a ―first mover‖ incentive 

for carbon capture and storage at coal-fired 

plants by authorizing tax credits and cost 

recovery incentives for qualifying 

investments. The New Mexico statute, SB 

994, was signed into law on April 3, 2007 

and took effect on July 1, 2007.

SB 994 provides that a taxpayer holding

an interest in a qualified generating facility 

located in New Mexico is eligible for an 

―advanced energy combined reporting tax 

credit.‖26 A ―qualified generating facility‖ is 

defined as a facility that begins construction 

no later than December 31, 2015 and is 

either a solar thermal generating facility, 

solar photovoltaic generating facility, 

geothermal generating facility, recycled 

energy project27 or a new or re-powered 

coal-based electric generating facility and 

associated coal gasification facility.28 The 

tax credit equals six percent of the eligible 

generation plant costs of the qualified 

generating facility up to a maximum amount 

of $60,000,000.29 The new and re-powered 

coal-based and association coal gasification 

facilities are also eligible for the cost 

recovery incentives, described later in this 

section.

SB 994 requires the ―qualified 

generating facility‖ to meet the following 

specifications:30

(a) Emits the lesser of: i) what is

achievable with the best available control 

technology; or ii) thirty-five thousandths 

pound per million Btu’s of SO2, twenty-five 

thousandths pound per million Btu’s of NOX 

and one hundredth pound per million Btu’s 

of total particulates in the flue gas;

(b) Removes the greater of: i) what is 

achievable with the best available control 

technology; or ii) 90% or more of the 

mercury from the input fuel;

(c) Captures and sequesters or controls 

CO2 emissions such that by the later of 

January 1, 2017, or eighteen months after 

the commercial operation date, no more than 

1,100 lbs per MWh of CO2 is emitted into 

the atmosphere; 

(d) All infrastructure required for 
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sequestration is in place by the later of 

January 1, 2017, or eighteen months after 

the commercial operation date of the 

qualified generating facility;

(e) Includes methods and procedures to 

monitor the disposition of the CO2 captured 

and sequestered from the facility; and

(f) Does not exceed 700 net MW 

nameplate capacity.

SB 994 also directs the New Mexico

Public Regulation Commission to adopt 

rules to allow the utility a reasonable 

opportunity to recover costs incurred for the 

development and ongoing construction of a 

―clean energy project.‖

31 The law defines a

―clean energy project‖ as the construction or 

modification of a new or existing electric 

generation facility in a manner that employs 

a technology that has additional financial 

risk because it is not commercially 

established or because it employs an 

established technology that is not 

commercially proven under the altitude, 

geographic or resource availability 

conditions under which it is proposed to 

operate. This may include associated 

renewable energy storage facilities, recycled 

energy and advanced coal technology, or 

other technology as deemed appropriate by 

the commission. 

In addition, the ―clean energy project‖ 

should achieve emission levels no greater 

than those specified for advanced coal 

technology and cannot include nuclear 

power. SB 994 defines ―advanced coal 

technology‖ as new coal-based generation, 

coal gasification or other technology using 

coal as a fuel source that is certified by the 

department of environment to meet the same 

specifications as listed for the qualified 

generating facility.32

Citations

SB 994: 

http://legis.state.nm.us/lcs/_session.aspx?Ch

amber=S&LegType=B&LegNo=994&year

=07

3.13.8.7 NMAC – Definitions: Advanced 

Energy Tax Credit Defined

http://www.tax.newmexico.gov/SiteCollecti

onDocuments/Tax-Library/Statutes-andDepartment-Directives/Recent-RegulationChanges/Other_Tax_Credits.pdf

Illinois

Illinois recently passed a law that 

implements a clean coal portfolio standard. 

While this law does not limit coal power, it 

does create a preference for coal resources 

that utilize CCS. The Illinois statute, SB 

1987, was signed into law on January 12, 

2009 and took effect on June 1, 2009. 

SB 1987 requires each Illinois electric 

utility to enter into one or more sourcing 

agreements with an ―initial clean coal 

facility‖ that represents at least 5% of each 

utility’s total supply to serve the load of 

eligible retail customers in 2015.33 An 

―initial clean coal facility‖ is defined as a 

proposed facility with a nameplate capacity 

of at least 500 MW when commercial 

operation commences, having a final Clean 

Air Act permit on the effective date of the 

act, and meeting the definition of ―clean 

coal facility‖ described below. 

The new law further provides that ―[i]t 

is the goal of the State that by January 1, 

2025, 25% of the electricity used in the 

State shall be generated by cost-effective 

clean coal facilities.‖34 The provisions limit 

the total amount paid under the clean coal 

sourcing agreements, however, in order to 

keep annual average cost increases to 

customers due to the cost of these resources 

to under 0.5%. 

Eligible clean coal procurement under 

this portfolio standard is defined by the 

level of emission reductions achieved 

through carbon capture and sequestration. 

A clean coal facility scheduled to 
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commence operation before 2016 must 

capture and sequester at least 50% of the 

total carbon emissions that the facility 

would emit. If the facility is scheduled to 

commence operation during 2016 or 2017, 

at least 70% of the total carbon emissions 

that the facility would emit must be 

captured and sequestered. The applicable 

percentage for facilities scheduled to 

commence operations after 2017 is 90%. 

For the purpose of establishing these 

thresholds, the scheduled commencement 

date is established at the time that 

construction commences.35

SB 1987 includes provisions for 

repowering and retrofitting coal-fired plants 

previously owned by Illinois utilities to 

qualify as clean coal facilities. No specific 

definitions of these terms are provided in 

the statute and rules have not been adopted 

to date to clarify how the Commission 

intends to define them.36

The state Attorney General may 

specifically enforce the initial clean coal 

facility’s sequestration requirement.37 The

Commission may reduce the allowable 

return-on-equity for the facility reflected in 

the sourcing agreement if the facility 

willfully fails to comply with its capture and 

sequestration requirements.38

Citations

SB 1987: 

www.ilga.gov/legislation/publicacts/95/PDF

/095-1027.pdf.

 

1

Both the California Legislature and the California Public 

Utilities Commission (CPUC) concluded that if utilities or 

other load-serving entities were allowed to enter into new 

long-term commitments with high-greenhouse gas (GHG) 

emitting power plants, California ratepayers would be 

exposed to high costs of retrofits (or the need to purchase 

expensive offsets) under future emission control 

regulations. California ratepayers would also be exposed 

to potential supply disruptions when these high-emitting 

facilities are taken off line for retrofits, or retired early, in 

order to comply with future regulations. 

SB 1368, Section 1(f)-(m) at 

http://www.leginfo.ca.gov/pub/05-06/bill/sen/sb_1351-

1400/sb_1368_bill_20060929_chaptered.pdf

CPUC Decision 07-01-039 issued on January 25, 2007 in 

Rulemaking 06-04-009, at page 3. 

http://www.cpuc.ca.gov/PUBLISHED/FINAL_DECISION

/64072.htm

2

―Capacity factor‖ is defined as the ratio of the annual 

amount of electricity produced by the power plant divided 

by the annual amount of electricity the plant could have 

produced based on maximum rated capacity (or maximum 

―permitted‖ capacity, if the permit limits maximum plant 

operation below the facility’s rated capacity.)

3

The California EPS is codified at Public Utilities Code 

section 8340-8341. ―Long-term financial commitment‖ is 

defined at subsection 8340(j).

4

―Baseload generation‖ is defined at subsection 8340(a).

5

CPUC Decision 07-01-039 at page 6. 

6

Subsection 8341(d).

7

CPUC Decision 07-01-039 at page 6.

8

CPUC Decision 07-01-039 at page 10.

9 We use these terms interchangeably here.

10 Subsection 8341 (d)(3).

11 CPUC Decision 07-01-039, Attachment 7, page 5. 

http://www.cpuc.ca.gov/PUBLISHED/FINAL_DECISION

/64072.htm

12 D.10-07-046, issued July 29, 2010.

13

http://www.energy.ca.gov/emission_standards/index.html

14 ―Renewable resources‖ are defined below under the 

heading ―Treatment of Renewable Resources.‖

15 E-mail with Dick Byers, Senior Policy Advisor, 

Washington Utilities and Transportation Commission, 10-

10-08.

16 In RCW 19.280.020 of SB 6001

17 Section 5, Subsections (11)-(13) of SB 6001

18 Chapter 463-85 WAC
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19 Section 13 of SB 101. Since the implementing rules 

have not been developed yet, our description of OPUC’s 

EPS necessarily relies on the plain reading of the statute.

20 SB 101, Section 5(2)(b) and (3)(c)

21 These are listed in ORS 469A.025 which can be found 

at http://www.leg.state.or.us/ors/469a.html

22 Section 1(10)(b) of SB 101

23 Subsection 2(4)(b) provides that the OPUC may 

―[m]odify the emissions standard based upon current 

information on the rate of greenhouse gas emissions from a 

commercially available combined-cycle natural gas 

generating facility that:

(A) Employs a combination of one or more gas turbines 

and one or more steam turbines and produces electricity in 

the steam turbines from waste heat produced by the gas 

turbines;

(B) Has a heat rate at high elevation within the boundaries 

of the Western Electricity Coordinating Council; and

(C) Has a heat rate at ambient temperatures when operating 

during the hottest day of the year.‖

24 Interview with Will Rosquist, Rate Analyst, MT PSC, 

10-10-08.

25 Ibid.

26 Section 7-9G-2 (A) of 3.13.8.7 NMAC

27 The statute defines a ―recycled energy project‖ as 

energy produced by a generation unit with a name-plate 

capacity of not more than fifteen megawatts that converts 

the otherwise lost energy from exhaust stacks or pipes to 

electricity without combustion of additional fossil fuel.

28 Section 7-9G-2 (B) (10) (e) of 3.13.8.7 NMAC

29 Section 7-9G-2 (J) of 3.13.8.7 NMAC

30 Section 7-9G-2 (B) (2) (a-f) of 3.13.8.7 NMAC

31 Section 2 (D) (2) of SB 994

32 Section 2 (D) (1) (a-f) of SB 994

33 20 ILCS 3855/1-75 (d) (1) of SB 1987

34 20 ILCS 3855/1-75 (d) (1) of SB 1987

35 20 ILCS 3855/1-10) Sec. 1-10 of SB 1987

36 20 ILCS 3855/1-75 (d) (5) of SB 1987

37 20 ILCS 3855/1-75 (d) (3) (D) (v) of SB 1987

38 20 ILCS 3855/1-75 (d) (3) (D) (vi) of SB 1987