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Appendix for State Plan Considerations

Technical Support Document (TSD)  

Survey of Existing State Policies and Programs that  

Reduce Power Sector CO2 Emissions

DRAFT

April 3, 2014

For Carbon Pollution Guidelines for Existing Power Plants:  

Emission Guidelines for Greenhouse Gas Emissions from Existing Stationary

Sources: Electric Utility Generating Units

Docket ID No. EPA‐HQ‐OAR‐2013‐0602
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Contents

I. Overview of state climate and energy policies and programs that reduce power sector CO2.............5

II. Existing state and utility policies, programs, and measures that affect EGU CO2 emissions ...............7

a. Actions that reduce EGU CO2 Directly............................................................................................... 8

i. Market‐based Emission Limits...................................................................................................... 8

ii. CO2 emission performance standards........................................................................................ 15

b. Energy Efficiency Policies, Programs and Measures....................................................................... 19

i. Energy Efficiency Resource Standards........................................................................................ 20

ii. Demand‐side Energy Efficiency Programs.................................................................................. 23

iii. Building codes............................................................................................................................. 26

iv. Appliance and equipment efficiency standards......................................................................... 28

v. Incentives and Finance Mechanisms for Energy Efficiency ........................................................ 30

c. Renewable Energy Policies and Programs...................................................................................... 32

i. Renewable Portfolio Standards.................................................................................................. 32

ii. Performance‐Based Incentives and Finance Mechanisms For Renewable Energy ....................35

d. Utility Planning Approaches and Requirements............................................................................. 37

    
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List of Acronyms

ACEEE ‐ American Council for an Energy Efficient Economy

ACP ‐ Alternative Compliance Payment

BSER – Best System of Emission Reduction

CACJA ‐ Clean Air Clean Jobs Act

CCR – Cost Containment Reserve

CHP – Combined Heat and Power

CEMS – Continuous Emissions Monitoring System

CO2 – Carbon Dioxide

CO2e – Carbon Dioxide Equivalent

CDPHE – Colorado Department of Public Health and Environment

DOE – Department of Energy

DSIRE ‐ Database of State Incentives for Renewable Energy

EERS – Energy Efficiency Resource Standard

EGU – Electricity Generating Unit

EIA – Energy Information Administration

EM&V – Evaluation, Measurement, and Verification

EPA – Environmental Protection Agency

ERP – Electric Resource Plan

ESCO – Energy Service Company

GDP – Gross Domestic Product

GHG – Greenhouse Gas

GW – Gigawatt (1 GW = 1,000 MW)

GWh – Gigawatt‐hour (1 GWh = 1,000 MWh)

IECC ‐ International Energy Conservation Code

IOU – Investor‐Owned Utility

IRP – Integrated Resource Planning

kWh – Kilowatt‐hour

LBNL – Lawrence Berkeley National Laboratory

LDC – Local Distribution Company

MERP ‐ Metropolitan Reduction Proposal

MMBTU – Million British Thermal Units

MW – Megawatt

MWh – Megawatt‐hour (1 MWh = 1,000 kWh)

NOx – Nitrogen Oxides

PBF – Public Benefit Funds

PBI – Performance‐based Incentives

RGGI – Regional Greenhouse Gas Initiative

REC – Renewable Energy Certificate

RES – Renewable Energy Standard
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RPS – Renewable Portfolio Standard

PUC – Public Utility Commission

SO2 – Sulfur Dioxide

VEIC – Vermont Energy Investment Corporation

WAP – Weatherization Assistance Program
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Survey of Existing State Policies and Programs that  

Reduce Power Sector CO2 Emissions

I. Overview of state climate and energy policies and programs that reduce

power sector CO2

Across the nation, many states and regions have shown strong leadership in creating and

implementing policies, programs and measures that reduce greenhouse gas (GHG) emissions

from the power sector, while achieving other economic, environmental, and energy benefits.

These policies and programs can serve as a strong foundation as states develop plans to meet

goals under the Carbon Pollution Standards for existing sources.  

This document provides a survey of many of these activities. Policies and programs range from

market‐based programs and GHG performance standards that require direct GHG emission

reductions from EGUs, to others, such as renewable portfolio standards (RPS) and energy

efficiency resource standards (EERS), that reduce GHG emissions by altering the mix of energy

supply and reducing energy demand. States have developed their policies and programs with

stakeholder input and tailored them to their own circumstances and priorities. Their leadership

and experiences provided the EPA with important information about best practices to build

upon in this proposed rule.

States vary in their regulatory structures, electricity generation and consumption patterns,

while geography affects factors such as the availability of fuels, transmission networks, and

seasonal energy demand. States have tailored their climate and energy policies and programs

accordingly. For example, in some states, utilities are vertically integrated, meaning that the

one company is responsible for electricity generation, transmission, and distribution over a

given service territory.  The state utility regulators have authority over these utilities.  In other

states, where the electric power industry has been restructured, generation has been

decoupled from distribution, and retail customers have their choice of electricity suppliers. In

actively restructured states (see Figure 1), the utility regulators do not have authority or control

over the utilities responsible for generation, only over the distribution utilities. States rely upon

and have access to different fuel types and house a variety of EGU types within state borders.  

States are part of regional electricity grids that do not align with state boundaries.  Electricity is

imported and exported by utilities across states throughout each regional grid.     
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Figure 1: Status of Electricity Restructuring by State (September 2010)1

States also have different economic considerations, drivers and approaches when

implementing climate change, energy efficiency and/or renewable energy policies, programs or

measures.  Actions can be motivated by state environmental, energy and/or economic concerns.  

For example, ten states have passed legislation requiring GHG emission reductions are using a

combination of climate change, energy efficiency and renewable energy strategies to achieve

these targets.2 Other state policies are motivated by public utility commission (PUC)

requirements to achieve all cost‐effective energy efficiency improvements and still others by

renewable energy generation requirements.  Policies, programs and measures vary from state

to state in their implementation levels and administration, some run by state agencies and

others by utilities with varying mechanisms for ensuring compliance.  

This appendix is not exhaustive and is only intended to provide information about strategies

states have used to achieve GHG emission reductions, advance energy efficiency and/or

increase the use of renewable resources.   Policies and programs included in this appendix are

not necessarily approvable in the context of a 111(d) state plan.  In order to be approvable,

                                                            

1 U.S. DOE, Energy Information Administration,

http://www.eia.gov/electricity/policies/restructuring/restructure_elect.html 2 States include California, Connecticut, Hawaii, Maine, Maryland, Massachusetts, Minnesota, New Jersey, Oregon,

and Washington. Targets are typically defined on a 1990 base year, aiming to achieve reductions of between 0 and

10 percent by 2020, although Maryland and Minnesota have chosen targets of 25 percent below 2006 levels by

2020, and 15 percent below 2005 levels by 2015 respectively.
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they must meet criteria laid out in this proposed rule, as described in the earlier part of this

Technical Support Document, State Plans Considerations.

II. Existing state and utility policies, programs, and measures that affect EGU

CO2 emissions

Some state and utility policies, programs and measures directly target CO2 emissions by

creating specific limits or standards for CO2 in the power sector. Other policies and programs,

such as those that advance energy efficiency and renewable energy, are designed to reduce

energy demand or promote an increase of supply from low or non‐GHG emitting sources which

reduces CO2 emissions.  While states often enact energy efficiency and renewable energy

programs for economic or reliability purposes, such as for reducing electricity rates or avoiding

the need to build new generation, many of the states aggressively pursuing climate change

mitigation look to both energy efficiency and renewable energy for the bulk of their reductions.   

For example, according to California, “the integrated nature of the grid means that policies

which displace the need for fossil generation can often cut emissions from covered sources

more deeply, and more cost‐effectively than can engineering changes at the plants alone,

though these source‐level control efforts are a vital starting point.”3 In working to meet its

statewide goal of reducing GHG emissions to 1990 levels by 2020 and 80 percent below 1990

levels by 2050, the state calls their energy efficiency standards “the bedrock upon which

climate policies are built” and uses renewable energy to fill any remaining energy needs.”4  

Compared to the costs of other climate policies, they find that “energy efficiency provides

substantial emissions reductions and should be an essential element of the BSER CO2 reduction

target.”5  Another state, Connecticut, has a law that requires the state to reduce GHG emissions

to 10 percent below 1990 emissions levels by 2020 and 80 percent from 2001 levels by 2050.6

  

They consider energy efficiency investments, expanded renewable energy and participation in

the Regional Greenhouse Gas Initiative among its top ten strategies to reduce GHGs when

considering cost‐effectiveness and GHG‐reduction potential.7

   

                                                            

3 December 27, 2013 Letter from Mary D. Nichols, Chairman of California Air Resources Board, to EPA

Administrator Gina McCarthy.   4 Ibid.

5 Ibid.

6 Connecticut Global Warming Solutions Act, http://www.env‐

ne.org/public/resources/pdf/CT_Global_Warming_Bill_Summary.pdf   7 States’ §111(d) Implementation Group Input to EPA on Carbon Pollution Standards for Existing Power Plants,

Joint comments from 15 states on Carbon Pollution Standards for Existing Power Plants sent to USEPA

Administrator McCarthy on December 16, 2013. Signatories include: Mary D. Nichols, Chairman of California Air

Resources Board, Robert B. Weisenmiller, California Energy Commission, Michael R. Peevey, Chair of California

Public Utilities Commission, Larry Wolk, MD, MSPH, Executive Director and Chief Medical Offices of Colorado
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Beyond these specific policies and programs, some states implement planning requirements

that can affect emissions both directly and indirectly.  This section describes a range of existing

state actions that fall into all of these categories.

a. Actions that reduce EGU CO2 Directly

Existing state actions that directly reduce EGU CO2 emissions tend to fall in one of two

categories: market‐based emission limits or emission performance standards.   

i. Market‐based Emission Limits  

Description

An emissions budget trading program (or “cap‐and‐trade” program) is a market‐based tool for

reducing pollution. The basic approach, which involves the allocation and trade of

environmental permits, has been used across environmental media, including air pollution

control, clean water regulation, and land‐use applications.   

Ten states have implemented emissions budget trading programs addressing CO2 and other

GHG emissions. These include California’s cap and trade program and the nine northeast and

mid‐Atlantic states participating in the Regional Greenhouse Gas Initiative (RGGI), consisting of

Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode

Island, and Vermont. .

89

                                                                                                                                                                                               

Department of Public Health and Environment, Dan Esty, Commissioner of Connecticut Department of

Environmental Protection, Collin O’Mara, Secretary of Delaware Department of Natural Resources and

Environmental Control, Dallas Winslow, Chairman of Delaware Public Service Commission, Douglas Scott, Chair of

Illinois Commerce Commission, David Littell, Commissioner of Maine Public Utilities Commission, Robert M.

Summers, Secretary of Maryland Department of the Environment, Kelly Speakes‐Backman, Commissioner of

Maryland Public Service Commission, Ken Kimmell,  Commissioner of Massachusetts Department of Environmental

Protection, Mark Sylvia, Commissioner of Massachusetts Department of Energy resources, John Linc Stine,

Commissioner of Minnesota Pollution Control Agency, Mike Rothman, Commissioner of Minnesota Department of

Commerce, Thomas S. Burack, Commissioner of New Hampshire Department of Environmental Service, Joseph

Martens, Commissioner of New York State Department of Environmental Conservation, Audrey Zibelman, Chief of

New York State Public Commission, Dick Pederson, Director Oregon department of Environmental Quality, Janet

Coit, Director of Rhode Island Department of Environmental Management, Marion Gold, Commissioner of Rhode

Island Office of Energy resources, Deborah Markowitz, Secretary of Vermont Agency of Natural Resources, James

Volz, Chairman of Vermont Public Service Board, Maia Bellon, Director of Washington State Department of Ecology.    8 RGGI website: http://www.rggi.org/rggi   9 California Air Resources Board: http://www.arb.ca.gov/cc/capandtrade/capandtrade.htm  

Greenhouse Gas Cap and Trade

Last updated 3/24/2014
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Policy Mechanics

Design

An emissions budget trading program establishes an aggregate limit on pollution through an

emissions cap that specifies the total allowable emissions for all of the sources subject to the

program. To comply with the program, each source must acquire allowances, through

purchases or by allocation from the state, equal to their emissions and surrender them at the

end of each compliance period.

Allowances may be traded among both regulated and non‐regulated parties, creating a market

for emission allowances. In turn, the allowance market establishes a price signal for emissions

(a market price for emitting a unit of pollution), which triggers broad economic incentives for

reducing emissions across the covered sector(s) and encourages innovation in developing

emissions control strategies and new pollution control technologies.

There are several key design elements that can vary from program to program:

 Scope of coverage (e.g., sectors and types of facilities covered)

 Applicability (criteria for inclusion of emitting facilities and units in the program)

 Emissions budget (i.e., “cap”) and emissions reduction schedule

 Flexibility provisions in addition to ability to trade emission allowances, including:  

o Multi‐year compliance periods,  

o Allowance banking,  

o Offsets (e.g., project‐based emissions reductions occurring outside the capped

sector/sources)

 Additional provisions to mitigate price volatility and overall costs  

o Auction reserve price  

o Cost containment reserve of allowances provided for sale at set price thresholds.

Once the allowance price hits a threshold, an extra supply of allowances are made

available

Table 1 summarizes some of the key design elements of the RGGI and California programs.
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Table 1: Comparison of RGGI and California Emissions Budget Trading Programs  

Element RGGI California

Applicability  All fossil fuel fired power plants with a

capacity of 25 MW or greater. 10

 All facilities in covered sectors emitting at

least 25,000 metric tons CO2 equivalent

(CO2e) or greater.11

Scope  Facilities in electric utility sector.12  Facilities in utility and large industrial sectors

(plus fuel distributors in 2015)13

Emissions

budget  Recently reduced 45 percent to 91

million tons CO2 in 2014.  Beginning in

2014, cap was reduced a further 2.5

percent per year to 2020.14

 Emissions cap was set at 2 percent below

expected 2012 emissions, declining by 2

percent in 2014 and 3 percent annually from

2015 to 2020. 15

Compliance

period  Must demonstrate compliance every

three years and hold at least 50 percent

of their obligations during first two

years of each period. 16

 Facilities must demonstrate full compliance

every three years, but the must surrender

allowances and offsets to cover 30 percent

of their compliance obligations during the

first two years of each three year cycle.17

Allowance

allocation

method

 Each state distributes their share of

allowances in an amount determined by

their applicable statute or regulation.  

Approximately 90 percent of CO2

allowances are auctioned off to EGUs or

the secondary market.18

 Large industrial facilities and electric utilities

are allocated the majority of their

allowances for free, set at 90 percent of the

average efficiency of a given sector. The

remaining allowances are auctioned off. The

share of allowances allocated for free

declines over time.19

Cost

containment

provisions

 An additional five million allowances

became available March 2014 when

market price exceeded $4 per ton.20  

 Trigger price increases until 2020 when

10 million allowances become available

if price per ton exceeds $10.7521

 A strategic reserve is starting at 1 percent of

allowances, rising over the years to 7

percent.  Shares of allowances held in the

reserve will be released at three price trigger

points; $40, $45, and $50 per ton and rise by

5 percent per year including inflation.22

                                                            

10 RGGI – Overview of RGGI CO2 Budget Trading Program:

http://www.rggi.org/docs/program_summary_10_07.pdf 11 CARB ‐ Cap and Trade Regulaiton Instructional Guidance, Chapter 2:

http://www.arb.ca.gov/cc/capandtrade/guidance/chapter2.pdf 12 RGGI Fact Sheet – Regional Greenhouse Gas Initiative; http://www.rggi.org/docs/RGGI_Fact_Sheet.pdf 13 CARB: ARB Emissions Trading Program Fact Sheet:

http://www.arb.ca.gov/newsrel/2011/cap_trade_overview.pdf

14 RGGI Press Release, January 13, 2014, http://www.rggi.org/docs/PressReleases/PR011314_AuctionNotice23.pdf 15 CARB: ARB Emissions Trading Program Fact Sheet:

http://www.arb.ca.gov/newsrel/2011/cap_trade_overview.pdf

16 Regional Greenhouse Gas Initiative  http://www.rggi.org/market/offsets 17 CARB: ARB Emissions Trading Program Fact Sheet:

http://www.arb.ca.gov/newsrel/2011/cap_trade_overview.pdf

18 Regional Greenhouse Gas Initiative 2013 Allowance Allocation http://rggi.org/design/overview/allowance‐

allocation/2013‐allocation.    19 CARB: ARB Emissions Trading Program Fact Sheet:

http://www.arb.ca.gov/newsrel/2011/cap_trade_overview.pdf

20 Reuters Point Carbon article

http://www.pointcarbon.com/research/promo/research/1.4523252?&ref=searchlist
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Banking  Allows unlimited allowance banking23  Allows unlimited banking of allowances.24

Offsets  Power plants covered under RGGI are

allowed to use offsets within the RGGI

region25 to meet 3.3 percent of their

compliance obligation.26.

 Facilities may use domestic offsets for up to

8 percent of their compliance obligations.27

A framework has been established to include

international offsets but these are currently

not allowed in the program. 28

Authority

State and regional GHG emissions budget trading programs are authorized through individual

state legislation and implemented through state regulations. For example, California

implemented their emissions trading program under the authority of its 2006 Global Warming

Solutions Act, which requires the state to reduce its 2020 GHG emissions to 1990 levels.29   Each

RGGI state has separate authorizing legislation, and in some cases their legislation specifically

directs the use of auction proceeds. For example, Maine authorized its participation in RGGI

through Stature 580‐A. Title 38 Chapter 3B: Regional Greenhouse Gas Initiative. This statute

also requires that 100 percent of auction proceeds to go towards carbon reduction and energy

conservation efforts.30  

The regulatory authority issues individual authorizations to emit a specific quantity of emissions

(“allowances”), which typically represent one ton of a pollutant, in an amount that equals the

emissions cap.

                                                                                                                                                                                                21 Regional Greenhouse Gas Initiative, Summary of RGGI Model Rule Changes: February 2013

http://www.rggi.org/docs/ProgramReview/_FinalProgramReviewMaterials/Model_Rule_Summary.pdf   22 CARB: Proposed Regulation to Implement the California Cap and Trade Program:

http://www.arb.ca.gov/regact/2010/capandtrade10/capisor.pdf   23 RGGI – Overview of RGGI CO2 Budget Trading Program http://www.rggi.org/docs/program_summary_10_07.pdf 24 CARB: Proposed Regulation to Implement the California Cap and Trade Program:

http://www.arb.ca.gov/regact/2010/capandtrade10/capisor.pdf 25 http://www.rggi.org/market/offsets   26 Eligible offsets under RGGI include: landfill methane capture and destruction, sulfur hexafluoride (SF6) reduction

from power transmission, afforestation, end use energy efficiency, and agricultural manure management;

http://www.rggi.org/market/offsets

27 CARB: ARB Emissions Trading Program Fact Sheet:

http://www.arb.ca.gov/newsrel/2011/cap_trade_overview.pdf;   Offsets are initially limited to forestry, urban

forestry, livestock methane capture and destruction, and destruction of ozone depleting substances. However, rice

cultivation and coal mine methane are proposed for inclusion in the program. See: CARB – Potential New

Compliance Offset Projects: http://www.arb.ca.gov/cc/capandtrade/offsets/offsets.htm for more information. 28 CARB: ARB Emissions Trading Program Fact Sheet:

http://www.arb.ca.gov/newsrel/2011/cap_trade_overview.pdf

29 State of California Global Warming Solutions Act of 2006, Assembly Bill 32, Chapter

http://www.leginfo.ca.gov/pub/05‐06/bill/asm/ab_0001‐0050/ab_32_bill_20060927_chaptered.pdf   30 Maine revised statutes: http://www.mainelegislature.org/legis/statutes/38/title38sec580‐B.html
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Obligated Parties

Obligated parties in trading programs are generally the covered facilities. It is the facilities that

are responsible for acquiring enough emission allowances to cover their emissions at the end of

each compliance period. For example, as stated above, RGGI covers fossil fuel fired power

plants 25 megawatts or greater in size.31 The California cap and trade program covers electricity

generators, importers of electricity, and industrial facilities whose annual emissions exceed

25,000 metric tons CO2e. Starting in 2015, the California trading program will cover distributors

of transportation, natural gas, and other fuels with emissions greater than 25,000 metric tons

CO2e as well as electricity imports from all sources.32

Measurement and Verification

Emissions budget trading programs include requirements for emissions monitoring and

reporting, holding and transfer of allowances, and surrender of allowances (and offsets) in an

amount equal to reported emissions.  This is often referred to, generally, as the program

“compliance obligation”).   

For example, facilities obligated under the RGGI program must report emissions quarterly to

environmental agencies in their respective state as well as annually to the U.S. EPA Greenhouse

Gas Reporting Program.33 They must provide verification of emissions as well as third party

verification of emission reductions from CO2 offsets. GHG emissions reporting for affected

sources in California is addressed through the California mandatory GHG reporting regulations,

using a modified version of the reporting platform administered through the EPA Greenhouse

Gas Reporting Program.34

Penalties for Non‐compliance

Failure to submit allowances in an amount equal to reported emissions can result in emissions

penalties. Penalties can come in the form of additional allowance submission requirements (e.g.,

three‐to‐one submission requirements to account for any shortfall), as well as other

administrative fines and penalties.  For example, if facilities are found to be short of the

allowances necessary to meet their obligation under the RGGI program, they can be fined for

                                                            

31 RGGI Fact Sheet – Regional Greenhouse Gas Initiative http://www.rggi.org/docs/RGGI_Fact_Sheet.pdf

California Environmental Protection Agency  Air Resources Board, Overview of Air Resources Board Emissions

Trading Program, 10/20/11,  http://www.arb.ca.gov/newsrel/2011/cap_trade_overview.pdf   33 Regional Greenhouse Gas Initiative  ‐ Overview of RGGI CO2 Budget Trading Program

http://www.rggi.org/docs/program_summary_10_07.pdf   34California Environmental Protection Agency  Air Resources Board, Overview of Air Resources Board Emissions

Trading Program, 10/20/11,  http://www.arb.ca.gov/newsrel/2011/cap_trade_overview.pdf.  
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up to three times the price of the value of the allowances they lack. Additional penalties may

also be applied at the state level.35 If facilities under the California program are unable to meet

their compliance obligations in time, they must surrender four allowances for every one

allowance they lack.36

Implementation Status

The RGGI program was established in 2009. From 2009 through 2012, the nine RGGI states

invested auction proceeds of more than $700 million in programs that lower costs for energy

consumers and reduce CO2 emissions, including approximately $460 million into energy

efficiency programs.37,38 The participating RGGI states estimate that those investments are

providing benefits of more than $1.8 billion in lifetime energy savings to energy consumers in

the region.39

                                                            

35 Regional Greenhouse Gas Initiative  ‐ Center for Climate and Energy Solutions

http://www.c2es.org/docUploads/rggi‐brief‐12‐18‐13‐updated.pdf 36 C2ES; available at http://www.c2es.org/docUploads/California‐Cap‐Trade‐Summary.pdf 37 Programs include residential, commercial, and industrial programs; Regional Investments of RGGI CO2 Allowance

Proceeds, 2012 (2014), available at http://www.rggi.org/docs/Documents/2012‐Investment‐Report.pdf   38 Of the $707 million in auction proceeds invested by RGGI participating states through 2012, 65 percent

supported end‐use energy efficiency programs. See Regional Greenhouse Gas Initiative, “Regional Investments of

RGGI CO2 Allowance Proceeds, 2012” (2014), available at) http://www.rggi.org/docs/Documents/2012‐

Investment‐Report.pdf   39 Ibid.
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Between 2005, when RGGI was first announced, and 2012, power sector CO2 emissions

in the RGGI participating states fell by more than 40 percent while GDP in the region grew.4041

By contrast, total U.S. power sector CO2 emissions fell by 16 percent during the same period of

time.42 In January 2014, the participating states lowered the overall allowable CO2 emission

level in 2014 by 45 percent, setting a multi‐state CO2 emission limit for affected EGUs of 91

million short tons of CO2 in 2014 and 78 million short tons of CO2 in 2020, more than 50 percent

below 2008 levels.43  

The California economy‐wide market‐based GHG emissions trading program, which addresses

GHG emissions from multiple sectors, was implemented in 2012 with emissions limitations

beginning in 2013. 44,45 While California’s emission trading program, like its state emission limit,

is multi‐sector in scope, the state projects that the emissions trading program and related

complementary measures will reduce power sector GHG emissions to less than 80 million

metric tons of CO2 equivalent by 2025, a 25 percent reduction from 2005 power sector

                                                            

40 Regional Greenhouse Gas Initiative, Report on Emission Reduction Efforts of the States Participating in the

Regional Greenhouse Gas Initiative and Recommendations for Guidelines under Section 111(d) of the Clean Air Act

(2013).http://www.rggi.org/docs/RGGI_States_111d_Letter_Comments.pdf 41 The first three‐year control period under RGGI, establishing CO2 emission limits for EGUs, began on January 1,

2009.

42 2014 U.S. Greenhouse Gas Inventory http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.html 43 RGGI Press Release, January 13, 2014, http://www.rggi.org/docs/PressReleases/PR011314_AuctionNotice23.pdf.   44 California Air Resources Board: http://www.arb.ca.gov/cc/capandtrade/capandtrade.htm   45 The California program was developed in coordination with U.S. state and Canadian province WCI partners.
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emission levels. 46 Prior to the implementation of the emission trading program, California

reports that it reduced CO2 power sector emissions by 16 percent from 2005 to a 2010‐2012

averaging period, a reduction of 16 million metric tons of CO2 equivalent.47    

ii. CO2 emission performance standards

Description

CO2 emission performance standards can apply either directly to EGUs or to the local

distribution company (LDC) that sells electricity to the customers. (For more information about

electricity is generated and distributed, see Chapter 2 of the Regulatory Impact Analysis).

As of March 2014, four states ‐ California, New York, Oregon and Washington ‐ have enacted

mandatory GHG emission

standards that impose

enforceable emission limits on

new and/or expanded electric

generating units. Three states ‐ 

California, Oregon and

Washington ‐ have enacted

mandatory GHG emission

performance standards that

set an emission rate for

electricity purchased by

electric utilities. 48 In addition

to these states, Illinois and

Montana have requirements

that new coal plants capture at

least 50 percent of their CO2 emissions. 49

                                                            

46 Preliminary California Air Resources Board analyses, based in part on CARB 2008 to 2012 Emissions for

Mandatory GHG reporting Summary (2013), cited in Letter to the EPA Administrator, “States' Roadmap on

Reducing Carbon Pollution,” December 16, 2013,

http://www.georgetownclimate.org/sites/default/files/EPA_Submission_from_States‐FinalCompl.pdf   47Ibid.

48 C2ES: http://www.c2es.org/us‐states‐regions/policy‐maps/electricity‐emissions‐caps 49 C2ES: http://www.c2es.org/us‐states‐regions/policy‐maps/electricity‐emissions‐caps

Greenhouse Gas Performance Standards

Applies to new units and power purchase agreements

Last updated 8/8/2013 Requires carbon capture and storage at new coal-fired power 

Applies only to new units
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Policy Mechanics

Design  

States have implemented three different types of CO2 performance standards that affect EGUs

and/or LDCs differently.  The first requires power plant emissions per electricity generated to

be less than or equivalent to an established standard and is directly applicable to EGUs. The

second type places conditions on the emissions attributes of electricity procured by electric

utilities.  It consists of standards that are applicable to LDCs that provide electricity to retail

customers. A third type requires that new coal‐fired power plants must capture and store a

specific percentage of CO2 emissions. Table 2 provides state examples for each of the types of

CO2 performance standards.  

Authority  

In some states, programs are regulated through the Public Utilities Commission (California,

Oregon). New York’s program is regulated through the Department of Environmental

Conservation. Washington’s program is regulated through two different sets of entities

depending on the ownership of the utilities.  The Washington Utilities and Transportation

Commission regulate investor owned utilities, and the utility's governing board, Washington

Department of Ecology, and the State Auditor oversees consumer owned utilities.

Obligated Parties

The emission performance standard can apply either directly to EGUs or to the local distribution

company (LDC) that sells electricity to the customer.

Measurement and Verification

Obligated parties must measure and report on electricity generation and CO2 emissions on a

regular basis to verify their compliance with the standard. The reporting requirements and

timing varies from state to state and are typically set by the agency that oversees the program

as described under authority above. Table 3 provides examples regarding measurement and

verification requirements across California, New York, Oregon, and Washington
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Table 2: Examples of State CO2 Performance Standards

                                                            

50 NY Department of Environmental Conservation, Part 251: CO2 Performance Standards for Major Electric

Generating Facilities http://www.dec.ny.gov/regs/83094.html#83097 51 Oregon Department of Energy ‐ Oregon’s Carbon Dioxide Emission Standards For New Energy

Facilitieshttp://www.oregon.gov/energy/Siting/docs/Reports/CO2Standard.pdf. 52 Washington State Legislature ‐ Chapter 80.70 RCW: Carbon Dioxide Mitigation

http://apps.leg.wa.gov/rcw/default.aspx?cite=80.70&full=true. 53 California bill SB 1368: http://www.energy.ca.gov/emission_standards/ 54 eGRID 2010 data files ‐ http://www.epa.gov/cleanenergy/energy‐resources/egrid/index.html#   55 Oregon Department of Energy ‐ Oregon’s Carbon Dioxide Emission Standards For New Energy

Facilitieshttp://www.oregon.gov/energy/Siting/docs/Reports/CO2Standard.pdf 56 Washington State Legislature ‐ Chapter 80.70 RCW: Carbon Dioxide Mitigation

http://apps.leg.wa.gov/rcw/default.aspx?cite=80.70&full=true 57 Illinois General Assembly Clean Coal Portfolio Standard Law. http://ilga.gov/legislation/publicacts/95/PDF/095‐

1027.pdf  

What It Does State Examples

Requires power

plant emissions

per electricity

generated to be

less than or

equivalent to the

established

standard; Applies

to EGUs

 New York (Part 251, 2012) ‐ New or expanded baseload plants (25 MW and larger)

must meet an emission rate of either 925 lb CO2/MWh (output based) or 120 lbs

CO2/MMBTU (input based).  Non‐baseload plants (25 MW and larger) must meet an

emission rate of either 1450 lbs CO2/MWh (output based) or 160 lbs CO2/MMBTU

(input based).50  

 Oregon (HB 3283; 1997, 2007) ‐ New natural gas‐fired power plants (baseload and

non‐baseload) must meet an emission rate of 675 lb CO2/MWh.  Cogeneration and

offsets may be used to comply with the emission standard.51

 Washington (RCW 80‐70‐010; 2004) ‐ New EGUs 25 MW and larger must have an

approved CO2 mitigation plan that results in mitigation of 20 percent of the total CO2

emissions over the life of the facility.  Includes modifications to existing EGUs that

result in an increase in CO2 emissions of 15 percent or more.  The CO2 mitigation plan

may include one or more of a list of eligible measures (includes indirect measures,

such as EE/RE and offsets). 52

Places conditions

on the emissions

attributes of

electricity

procured by

electric utilities;

Applies to LDCs

 California (SB 1368; 2006) ‐ Electric utilities may only enter into long‐term power

purchase agreements for baseload power if the electric generator supplying the power

has a CO2 emission rate that does not exceed that of a natural gas combined cycle

plant.  The California Energy Commission promulgated regulations establishing an

emission rate of 1,100 lb CO2/MWh.53 By comparison, the average emissions rate of

gas plants in the U.S. is 945 lb CO2/MWh, while the average emissions rate of

pulverized coal plants is 2,154 lb CO2/MWh.54

 Oregon (HB 101; 2009) and Washington (SB 6001; 2007) ‐ Electric utilities may only

enter into long‐term power purchase agreements for baseload power if the electric

generator supplying the power has a CO2 emission rate of 1,100 lb CO2/MWh or

less.5556

Requires that new

coal‐fired power

plants must

capture and store

a specific

percentage of CO2

 Illinois (SB 1987; 2009) Illinois utilities and retailers must purchase at least 5 percent of

their electricity from Clean Coal Facilities in 2015 and beyond. To be designated a

Clean Coal Facility, new coal‐fired power plants must capture and store 50 percent of

carbon emissions from 2009‐2015, 70 percent for 2016‐2017, and 90 percent after

2017.57

 Montana (HB 25; 2007). The Public Service Commission may not approve new plants
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Table 3: Examples of Measurement and Verification Requirements for CO2 Performance

Standards

State Measurement and Verification Details

California  The California PUC is responsible for approving any long term financial commitment by

an electric utility and must adopt rules to enforce these requirements as well as

verification procedures.59

New York  CO2 emission regulations require recordkeeping, monitoring and reporting consistent

with existing state and federal regulations.  

 Each applicable emissions source must install Continuous Emissions Monitoring Systems

(CEMS) subject to Federal CO2 reporting requirements for 40 CFR part 75, successfully

complete certification tests, and record, report, and quality assure the data from the

CEMS.  

 The owner or operator must report the CO2 mass emissions data and heat input data on

a semi‐annual basis to the Department of Environmental Conservation.  

 On a quarterly basis, the owner or operator must report all of the data and information

required in either 40 CFR part 60 or subpart H of 40 CFR part 75.60

Washington  Mitigation projects must be approved by the appropriate council, department, or

authority, and made a condition of the proposed and final site certification agreement

or order of approval.  

 Direct investment projects are approved if they provide reasonable certainty that the

performance requirements of the projects will be achieved and that they were

implemented after July 1, 2004.  

 For facilities under the jurisdiction of a council, the implementation of a carbon dioxide

mitigation project, other than purchase of carbon credits, is monitored by an

independent entity for conformance with the performance requirements of the carbon

dioxide mitigation plan.  The independent entity shares the project monitoring results

with the council.  

 For facilities under jurisdiction of the department or authority, the implementation of a

carbon dioxide mitigation project, other than a purchase of carbon credits, is monitored

by the department or authority issuing the order of approval.61

Oregon  It is up to the Council during the certificate application phase to determine the gross

CO2 emissions over a 30 year lifetime of the proposed facility to determine whether it

meets the CO2 performance standard.  

 During the operation phase of approved facilities, there are CO2 reporting requirements

to the Oregon Department of Environmental Quality and US EPA.  

 New facilities must pass a 100 hour test in their first year of operation to show they

meet the performance standards.62

                                                            

58 Montana State Legislature – H.B.25, 2007. http://leg.mt.gov/bills/2007/billpdf/HB0025.pdf 59 California bill SB 1368: http://www.energy.ca.gov/emission_standards/ 60 NY Department of Environmental Conservation, Part 251: CO2 Performance Standards for Major Electric

Generating Facilities http://www.dec.ny.gov/regs/83094.html#83097 61 Washington State Legislature ‐ Chapter 80.70 RCW: Carbon Dioxide Mitigation

http://apps.leg.wa.gov/rcw/default.aspx?cite=80.70&full=true 62 Oregon Department of Energy ‐ Oregon’s Carbon Dioxide Emission Standards For New Energy Facilities

emissions constructed after January 2007 that are primarily coal‐fired unless at least 50 percent

of the plant’s CO2 emissions are captured and stored.58
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Penalties for Noncompliance

For policies that affect target new electric generating units, utilities must prove any proposed

units are in compliance at the time of permitting. In Oregon, if facilities do not meet the

performance standard in their first year of operation during a 100 hour test63, they must

purchase offsets to account for any excess emissions.64

Implementation Status

Since enacting the performance standard, California’s carbon emissions rates have fallen from

approximately 1,245 lbs CO2e/MWh for fossil generation (considering both in‐state and

imported power) and 875 lbs CO2e/MWh for all power in 2005 to an average of approximately

1,090 lbs CO2e/MWh and 775 lbs CO2e/MWh in the three years before 2012.65  

b. Energy Efficiency Policies, Programs and Measures

Demand‐side energy efficiency policies and programs reduce utilization of EGUs and avoid

greenhouse gas emissions associated with electricity generation.  These electricity demand

reductions can be achieved through enabling policies that incentivize investment in demand‐

side energy efficiency improvements by overcoming market barriers that otherwise prevent

these investments, such as lack of information on energy efficient options, high transaction

costs, split‐incentives, lack of product availability, and perceptions of organizational risks.

Reducing electricity demand also enhances system efficiency by reducing the transmission and

distribution losses that occur across the grid between the sites of electricity generation and the

end use.  

Demand‐side energy efficiency is considered a central part of climate change mitigation in

states that currently have mandatory GHG targets, accounting for roughly 35 percent to 70

percent of expected reductions of state's power sector emissions.66 For example, California

expects to achieve reductions of 21.9 MMTCO2e in 2020 from energy efficiency programs

targeting electricity reductions. Taking into account expected reductions of 21.3 MMTCO2e

expected from California's RPS and 2.1 MMTCO2e from the million solar roofs program, energy

efficiency makes up 48 percent of power sector reductions based on California's Climate

                                                                                                                                                                                               

http://www.oregon.gov/energy/Siting/docs/Reports/CO2Standard.pdf 63 During the first year of operation new power plants test their equipment to ensure compliance with standards

for commercial equipment. Initial CO2 performance requirements can be validated during this test. 64 Oregon Department of Energy ‐ Oregon’s Carbon Dioxide Emission Standards For New Energy

Facilitieshttp://www.oregon.gov/energy/Siting/docs/Reports/CO2Standard.pdf 65 States’ §111(d) Implementation Group Input to EPA on Carbon Pollution Standards for Existing Power Plants 66 These reduction target ranges are based on a review of state GHG reduction laws in California, Connecticut,

Hawaii, Maine, Maryland, Massachusetts, Minnesota, New Jersey, Oregon, and Washington.
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Change Scoping Plan.67 Another state, Washington, expects to reduce 9.7 MMTCO2e from

energy efficiency measures in 2020. Taking into account expected reductions of 4.1 MMTCO2e

from Washington's RPS, energy efficiency makes up 70 percent of expected emission reductions

from stationary energy within the state.68

States have employed a variety of strategies to increase investment in demand‐side energy

efficiency technologies and practices, including (1) energy efficiency resource standards, (2)

demand‐side energy efficiency programs, (3) building energy codes, (4) appliance standards and

(5) tax credits.  Each of these strategies are described below.  

i. Energy Efficiency Resource Standards  

Description

Energy Efficiency Resource Standards (EERS) set multiyear targets for energy savings that

utilities or third‐party program administrators typically meet through customer energy

efficiency programs but also through other approaches, such as peak demand reductions,

building codes and combined heat and power (CHP). An EERS can apply to retail distributors of

either electricity or natural gas, or both, depending on the state.  To date, at least 29 states

have some type of EE requirement or goal.69   

Policy Mechanics

Design

EERS design and implementation details vary by state, and may be expressed as a percentage

reduction in annual retail electricity sales, as a percentage reduction in retail electricity sales

growth, or as a specific electricity savings amount over a long‐term period.  A typical EERS sets

multiyear targets for energy savings that drive investment in EE programs implemented by

utilities or third party administrators.  Over the compliance period, an EERS reduces electricity

demand by a target amount that utilities must meet.  As a result, an EERS indirectly affects

utility CO2 emissions by reducing the use of fossil‐fuel‐fired EGUs.

Authority

Most state EERS policies are established through legislation.  However, there are several

instances in which they have been established by PUC orders under broader statutory authority,

                                                            

67 CA Climate Change Scoping Plan http://www.arb.ca.gov/cc/scopingplan/document/adopted_scoping_plan.pdf 68 Growing Washington's Economy in a Carbon‐Constrained World:

https://fortress.wa.gov/ecy/publications/publications/0801025.pdf   69 State Energy Efficiency Resource Standards: Policy Design, Status, and Impacts, D.C. Steinberg, O. Zinaman, NREL

Technical Report NREL/TP‐6A20‐61023, April 2014.
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such as by setting quantitative targets consistent with the achievement of ‘all cost‐effective

energy efficiency.70   

Obligated Parties

Retail electricity suppliers, which are utilities that sell electricity to customers for end‐use

purposes, are the obligated parties under an EERS.

Measurement and Verification

PUCs generally oversee EERS.  Retail electricity suppliers comply with EERS requirements by

developing a portfolio of end‐use energy efficiency programs that encourage electric utility

customers to invest in more energy efficient technologies and practices as described below.  

PUCs typically rely on independent program evaluators to perform evaluation, measurement

and verification (EM&V) activities that estimate the incremental annual and cumulative energy

savings attributable to the programs.71  These estimates are typically the basis for compliance

reports submitted by retail electricity suppliers. For more information about measurement and

verification of energy efficiency policies or programs, see earlier in the State Plan

Considerations Technical Support Document.

                                                            

70 An important policy driver for EE programs in six states is a statutory requirement for utilities to acquire 

"all cost-effective energy efficiency". This policy typically requires utilities and other program 

administrators to pursue energy efficiency up to the point at which it is no longer cost effective, as defined 

by cost-benefit tests and procedures REQUIRED by state PUCs. States with all-cost effective energy 

efficiency policies include: CA, CT, MA, RI, VT, WA. For MA, this goals has translated into achieving 

annual electric energy savings equivalent to a 2.4% reduction in retail sales from energy efficiency 

programs in 2012. (Cite: http://emp.lbl.gov/sites/all/files/REPORT%20lbnl-3833e.pdf)

71 Evaluation, measurement, and verification (EM&V) refers to set of techniques and approaches used to estimate

the quantity of energy savings from an EE program or policy.  Since energy savings cannot be directly measured,

efficiency program impacts are estimated by taking the difference between: (a) actual energy consumption after

efficiency measures are installed, and (b) the energy consumption that would have occurred during the same

period had the efficiency measures not been installed (i.e., the baseline). 72 DSIREUSA, http://www.dsireusa.org/incentives/incentive.cfm?Incentive_Code=PA14R&re=0&ee=0.  

State Direct Financial Penalties

Pennsylvania Failure to achieve the requisite reductions in electricity

consumption and peak demand during Phase 1 results in one‐time

fines from $1 million to $20 million. Failure to file a plan with the

public utilities commission is also punishable by a fine of $100,000

per day. Costs associated with any such fines may not be passed

on to ratepayers.72

Table 3: Examples of Penalties for Noncompliance 
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Penalties for

Noncompliance

If the obligated parties

do not demonstrate

compliance with the

EERS, they may face

financial penalties. The

existence and amount of

penalties varies across

the states.   Table 3

provides examples of financial penalties in three states, Pennsylvania, Ohio and Illinois.

Implementation Status

As of January 2014, more than 20 states had an active EERS in place, while at least four have EE

targets or goals that are voluntary, underfunded or uncertain at this time. In addition, two

states have renewable portfolio standard that allow the option for energy efficiency to meet

requirements.76  

                                                            

73 RECs represent the non‐energy attributes, including all the environmental attributes, of electricity generation

from renewable energy sources. RECs are typically issued in single MWh increments. See the section on Renewable

Portfolio Standards for more detail. 74 DSIREUSA http://www.dsireusa.org/incentives/incentive.cfm?Incentive_Code=OH16R&re=0&ee=0 .

75 DSIREUSA http://www.dsireusa.org/incentives/incentive.cfm?Incentive_Code=IL19R&re=0&ee=0. 76 State Energy Efficiency Resource Standards: Policy Design, Status, and Impacts, D.C. Steinberg, O. Zinaman, NREL

Technical Report NREL/TP‐6A20‐61023, April 2014.  

Ohio Failure to comply with energy efficiency or peak demand reduction

requirements results in the state public utilities commission

assessing a forfeiture upon the utility, to be credited to the

Advanced Energy Fund. The amount of the forfeiture is either: an

amount, per day per under‐compliance or non‐compliance, not

greater than $10,000 per violation; or an amount equal to the then

existing market value of one renewable energy credit (REC)73 per

megawatt hour of under‐compliance or noncompliance. 74

Illinois For both natural gas and electric utilities, failure to submit an

energy reduction plan will result in a fine of $100,000 per day until

the plan is filed. This penalty is deposited in the Energy Efficiency

Trust Fund and may not be recovered by rate payers. 75

Status of State EERS, as of January 2014
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Most states are meeting or on track to meet their incremental savings goals, which typically

range from an annual reduction in electricity of about 0.25 ‐ 2.5 percent. 77 In 2011, across the

50 states, incremental savings were equivalent to 0.62 percent of retail electricity sales.78 For

those states with EERS policies in place for more than two years, thirteen of twenty states are

achieving 100 percent or more of their goals, three states are achieving over 90 percent of their

goals, and only three states are realizing savings below 80 percent of their goals.79  

ii. Demand‐side Energy Efficiency Programs  

Description  

Demand‐side energy efficiency programs are programs designed to advance energy efficiency

improvements within a state or utility service area.  They are typically implemented to help

meet state policies, standards or objectives, such as energy efficiency resource standards (EERS),

‘all cost effective’ energy efficiency goals, integrated resource planning, and other demand‐side

management program and budget processes. As of January 2013, utilities in 48 states

implement demand‐side energy efficiency programs.80

Policy Mechanics

Design

Demand‐side energy efficiency programs include financial incentives to use energy efficient

products, make energy efficiency upgrades to residential and commercial buildings, and

technical assistance and information programs to address market and information barriers.  

Funding for these programs typically comes from charges added to customer utility bills and

                                                            

77 State Policy Table – Internal estimate drawing on multiple sources 78 2013 Scorecard

79 Sciortino, M., Nowak, S., White, P., York, D., Kushler, M. (2011). “Energy Efficiency Resource 

Standards: A Progress Report on Sate Experience.” American Council for an Energy Efficient Economy, 

Washington, DC.

80 2013 State Energy Efficiency Scorecard, ACEEE, November 2013. http://www.aceee.org/researchreport/e13k 
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from revenues raised through emission allowance auctions, such as under RGGI. The RGGI

auction proceeds go to a variety of sources with the authority to run demand‐side energy

efficiency programs, including those also funded via independent trusts, DOE’s Weatherization

Assistance Program (WAP), and state‐run energy efficiency grant programs for municipalities.81

Funding may also come from “forward capacity markets” operated by regional electricity

operators. Forward capacity markets allow energy suppliers to bid against each other for the

amount of capacity they can supply into the electricity market in a future year. Demand‐side

management programs have been allowed to bid into these markets as an energy source,

demonstrating that energy efficiency programs can compete with more traditional forms of

electricity supply in meeting the needs of the power grid.  

Authority

Demand‐side programs that are a part of EERS programs and integrated resource planning are

established through legislation or PUC authority. Additional demand‐side management

program and budget processes also exist via utility planning, as well as state and local

government efforts to ensure all cost‐effective energy efficiency and other policy goals are met.  

Obligated Parties

Energy efficiency programs can be administered by investor‐owned, municipal or cooperative

utilities; third party administrators; or state and local government agencies.    

Measurement and Verification

PUCs generally oversee demand‐side energy efficiency programs.  Program administrators

typically rely on independent evaluators to perform evaluation, measurement and verification

(EM&V) activities that estimate the incremental annual and cumulative energy savings

attributable to the programs.  These estimates are typically the basis for annual performance

reports submitted by retail electricity suppliers or third party administrators to the PUCs. In the

case of state and local government agency run programs that are not overseen by the PUC,

energy savings are typically estimated to assure proper use of grants or other funds.  For more

information about the evaluation, measurement and verification of energy efficiency policies

and programs, see earlier in the State Plan Considerations Technical Support Document.

                                                            

81 RGGI - Regional Investment of RGGI CO2 Allowance Proceeds, 2012 

http://www.rggi.org/docs/Documents/2012-Investment-Report.pdf
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Penalties for Noncompliance

As discussed above, some states with an EERS levy direct fines for missing energy efficiency

targets or failure to submit an energy efficiency plan. For some programs under PUC oversight,

failure to reach certain performance levels may result in an inability to receive an incentive

payment or recover all incurred costs. Demand‐side programs funded by RGGI proceeds or

grants typically do not have penalties for noncompliance. However, state agencies play a role in

evaluating these programs and deciding whether funding should continue to flow to them.

Implementation Status

Well‐established state demand‐side energy efficiency programs have demonstrated their ability

to reduce electricity demand.82  For example, data reported to the U.S. Energy Information

Administration (EIA) show that in 2012 California avoided 35,482 GWh of electricity

consumption through its demand‐side efficiency programs, while Illinois avoided 3,084 GWh

and Maryland avoided 1,528 GWh, .

83 These reductions are equivalent to 13.7 percent, 2.1

percent, and 2.5 percent of total 2012 retail electricity sales in those states, respectively.84  

According to data and analyses from sources including Lawrence Berkeley National Lab (LBNL),

the U.S. Department of Energy’s Energy Information Administration, and the American Council

for an Energy Efficient Economy (ACEEE), as well as the EPA’s own analysis, ten leading states

have either achieved – or have established requirements that will lead them to achieve ‐ annual

incremental savings rates of at least 1.5 percent of the electricity consumption that would

otherwise have occurred.85

In 2011, state demand‐side energy efficiency programs are estimated to have reduced

CO2 emissions by 75 million metric tons, or 3.5 percent of national power sector emissions.8687

                                                            

82 LBNL The Future of Utility Customer‐Funded Energy Efficiency Programs in the United States

http://emp.lbl.gov/publications/future‐utility‐customer‐funded‐energy‐efficiency‐programs‐united‐states‐

projected‐spend 83 Energy Information Administration Form 861, 2012, available at http://www.eia.gov/electricity/data/eia861/ . 84 EIA: EIA Form 861: http://www.eia.gov/electricity/data/state/ 85 See the Greenhouse Gas Abatement Measures TSD for more information. 86 Innovation, Electricity, Efficiency (an Institute of the Edison Foundation), Summary of Customer‐Funded Electric

Efficiency Savings, Expenditures, and Budgets (2011‐2012) (March 2013), available at

http://www.edisonfoundation.net/iei/ourwork/Pages/issuebriefs.aspx.   87 2011 National GHG Inventory: http://www.epa.gov/climatechange/Downloads/ghgemissions/US‐GHG‐

Inventory‐2013‐ES.pdf
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iii. Building codes

Description

Energy codes establish minimum efficiency requirements for new and renovated residential

and commercial buildings.  These measures are intended to eliminate inefficient technologies

with minimal impact on up‐front project costs.  This can reduce the need for energy generation

capacity and new infrastructure while reducing energy bills. Energy codes lock in future energy

savings during the building design and construction phase, rather than through a renovation.  

Policy Mechanics

Design

Codes specify “thermal resistance” improvements to the building shell and windows, minimum

air leakage, and minimum efficiency for heating and cooling equipment.

Mandatory building energy codes establish minimum efficiency requirements for residential

and commercial construction.  The International Energy Conservation Code (IECC) is the

prevailing model code for the residential sector.  ASHRAE 90.1‐2010 is the model commercial

code.   

By locking in efficiency measures at the time of construction, codes are intended to capture

energy savings that are more cost‐effective than retrofit opportunities available after a building

has been constructed.  Energy code requirements are also intended to overcome market

barriers to efficient construction in both the commercial and residential sectors, such as the

complexity of advanced codes, lack of local‐level implementation resources, and a shortage of

empirical data on the costs and benefits of codes.   

Authority

Model building codes are typically developed at the national or international level, adopted at

the state and/or local level, and implemented and enforced locally.

Obligated Parties

Local parties, such as developers and property owners requiring building permits, are the most

common obligated parties.
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Measurement and Verification

Program implementation steps, including builder training, compliance assurance, and

enforcement, are typically the responsibility of state and local governments. These steps,

however, are often not fully or uniformly implemented for numerous reasons, including an

emphasis on health and safety issues over the proper functioning of mechanical equipment, a

lack of trained staff to review building plans and conduct onsite inspections, and limited

funding to carry out key implementation activities. As a result, most jurisdictions do not have

the capacity to analyze code compliance and to identify the measures and strategies that

should be targeted for improved implementation. For more information about measurement

and verification of energy efficiency, see earlier in the State Plan Considerations Technical

Support Document.

Penalties for Noncompliance

In order to get building permits approved, the relevant developer or property owners must

show they are in compliance with standards. Since permitting is done at the local level, the use

of penalties and the ability to enforce standards vary significantly by region. DOE has been

working with states and localities to improve compliance practice

Implementation Status

To date, 28 states have adopted IECC 2009 while four states have gone further by adopting the IECC

2012.  In the commercial sector, 33 states have adopted ASHRAE 90.1‐2007 and five states have

adopted ASHRAE 90.1‐2010.   Currently, 11 states have outdated or no state‐wide residential energy

code, and 9 states have outdated or no state‐wide energy codes for commercial construction.88 The

State of Oregon, which has adopted residential and commercial codes based on the IECC 2009,

estimated total savings in 2009 from building energy codes of 1.17 GWh and 2.3 GWh in the residential

and commercial sectors, respectively.89 This was equivalent to more than 7 percent of total retail

electricity sales in Oregon in 2009.90

                                                            

88 Online Code Environment & Advocacy Network http://energycodesocean.org/code‐status

89 2011‐2013 State of Oregon Energy Plan, Oregon Department of Energy,

http://www.oregon.gov/energy/docs/reports/legislature/2011/energy_plan_2011‐13.pdf 90 EIA, State Electricity Profiles. http://www.eia.gov/electricity/state/oregon/  
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iv. A

pplian

ce and

equip

ment

efficie

ncy

standa

rds

Descrip

tion

State

applian

ce

standa

rds
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establish minimum energy‐efficiency levels for those appliances and other energy‐consuming

products that are not already covered by the federal government. These standards typically

prohibit the sale of less efficient models within a state. States are finding that appliance

standards offer a cost‐effective strategy for improving energy efficiency and lowering energy

costs for businesses and consumers, though these standards are superseded when Federal

standards are enacted for new product categories,.

While state appliance standards can be useful in testing and exploring the effectiveness of

standards for new products, states cannot preempt or supersede existing Federal standards.

States may apply to DOE for a waiver to implement more stringent standards.  This is

sometimes granted if a certain period of time has passed since the federal standard has been

updated.

Policy Mechanics

Design

When states implement appliance and equipment standards, they are establishing a minimum

efficiency for products, such as refrigerators or air conditioners, thereby reducing the energy

associated with using the product. Standards prohibit the production and sale of products less

efficient than the minimum requirements, encouraging manufacturers to focus on how to

incorporate energy‐efficient technologies into their products at the least cost and hastening the

development of innovations that bring improved performance.

Authority

State energy offices, which typically administer the federal state energy program funds, have

generally acted as the administrative lead for standards implementation. In contrast, inspection

and enforcement of appliance standards regulations has typically involved self‐policing.

Industry competition is such that competitive manufacturers usually report violations.

Obligated Parties

Manufacturers of products being sold in a given state are typically obligated to ensure their

appliances meet the appropriate energy efficiency standards.

Measurement and Verification

Evaluating the benefits and costs of the standards is important during the standards‐setting

process. Once enacted, however, little field evaluation is performed. For more information

about measurement and verification of energy efficiency, see earlier in the State Plan

Considerations Technical Support Document.
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Penalties for Noncompliance

Appliances and equipment found in violation of the minimum energy performance standards

are not allowed to be sold or manufactured in the state.

Implementation Status

Currently, fifteen states and the District of Columbia have enacted appliance efficiency

standards. However, most of these standards have been superseded by federal standards. Still,

nine states (AZ, CA, CT, MD, NV, NY, OR, RI, WA) and the District of Columbia have either

enacted standards for equipment not covered federally or obtained waivers to enact tougher

appliance standards where the federal regulations have become outdated. California currently

leads all states in active state standards, covering 13 products, including consumer audio and

video products, pool pumps and hot tubs, vending machines, televisions, battery chargers, and

various lighting applications.91

v. Incentives and Finance Mechanisms for Energy Efficiency  

Description

States offer a diverse portfolio of financing and incentive approaches that are designed to

address specific financing challenges and barriers and help specific markets and customer

groups invest in energy efficiency. These programs include revolving loan funds, energy

performance contracting, tax incentives, rebates, grants, and other incentives.   

Policy Mechanics  

Design

Revolving loan funds provide low‐interest loans for energy efficiency improvements.  The funds

are designed to be self‐supporting. States create a pool of capital that “revolves” over a multi‐

year period, as payments from borrowers are returned to the capital pool and are subsequently

lent to other borrowers. Revolving loan funds can be created from several sources, including

public benefits funds (PBFs),92 utility program funds, general state revenues, or federal funding

sources. Revolving funds can grow in size over time, depending on repayment interest rates and

program administrative costs.  

                                                            

91 DSIREUSA, http://www.dsireusa.org/incentives/incentive.cfm?Incentive_Code=CA48R&re=0&ee=0 . 92 Public benefit funds (PBFs) are dedicated funds used for supporting research and development of energy

efficiency and renewable energy projects. Funds are normally collected either through a small charge for every

electric customer or through specified contributions from utilities.  
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Energy performance contracting allows the public sector to contract with private energy service

companies (ESCOs) to provide building owners with energy‐related efficiency improvements

that are guaranteed to save more than they cost over the course of the contracting period.

ESCOs provide energy auditing, engineering design, general contracting, and installation

services, and help arrange project financing.93 The contracts are privately funded and do not

involve state funding or financial incentives.

State tax incentives for energy efficiency are available as personal or corporate income tax

credits, tax exemptions (e.g., sales tax exemptions on energy‐efficient appliances), and tax

deductions (e.g., for construction programs). Tax incentives aim to spur private sector

innovation to develop more energy efficient technologies and practices and increase consumer

choice of energy‐efficient products.94  

Rebates (also known as “buy‐downs”) are used to promote demand‐side energy efficiency

reductions by providing direct incentives to customers who purchase or make upgrades to

approved efficient appliances or retrofit their homes (e.g., a utility may refund part of the cost

for a homeowner to improve attic insulation or purchase a high‐efficiency furnace). Funding for

rebates may come from PBFs, direct grants, or utility generation incentives.  

Grants from the federal government, state government, regional agency, or private source may

be used to start or finance energy efficiency programs. A grant may be used to provide funding

for a specific construction project (e.g., retrofit of a school), finance a rebate program, initiate a

revolving fund, conduct a behavior change campaign (e.g., educate public about the benefits of

off‐peak energy use), or any other type of program that meets the specific grant requirements.  

Authority

Financial mechanisms and incentives for energy efficiency are run by utilities and state and local

governments. Utilities primarily offer rebates, grants, and loans. Personal, corporate, sales, and

property tax incentives are mainly offered by state and local governments.95  

Implementation Status

Financial mechanisms and incentives for energy efficiency exist in all 50 states, with the most

prevalent financial mechanisms and incentives for energy efficiency are rebates and loan

programs. There are 43 tax incentives and over one‐thousand rebate, grant, and loan

                                                            

93 EPA. 2004. Integrating State and Local Environmental and Energy Goals: Energy Performance Contracting. Fact

Sheet. EPA. September. 94 Brown, E., P. Quinlan, H.M. Sachs, and D. Williams. 2002. Tax Credits for Energy Efficiency and Green Buildings:

Opportunities for State Action. Report #E021. ACEEE. March. 95 http://www.dsireusa.org/summarytables/finee.cfm  
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programs.96 In the first 3 years of Alaska’s Home Energy Rebate Program, the State provided an

estimated $110 million to help finance energy efficiency retrofits for 16,500 homeowners.

Retrofitted housed are currently saving an estimated 1.6 trillion BTUs of energy annually, or 5

percent of the Alaska’s total annual energy demand for residential space heating.97

c. Renewable Energy Policies and Programs

States have adopted a range of requirements and programs to advance the deployment of

renewable energy technologies, including renewable portfolio standards, performance‐based

incentives and public benefit funds.98 These renewable energy policies and programs reduce

GHG emissions by increasing the use of renewable energy and altering the mix of energy supply.

i. Renewable Portfolio Standards

Description

                                                            

96 http://www.dsireusa.org/summarytables/finee.cfm   97 Cold Climate Housing Research Center, http://cchrc.org/docs/snapshots/HERP_snapshot.pdf 98 Feed‐in tariffs offer long‐term purchase agreements to renewable energy electricity generators. Public benefit

funds are typically created by levying a small fee as a part of retail electricity rates and are used to support rebate,

loan, and other programs that support renewable energy deployment. For more information, see Database of

State Incentives for Renewables and Efficiency, available at http://www.dsireusa.org/.
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Renewable Portfolio Standards

Mandatory -

Voluntary -

29

9

Last updated 8/8/2013

A renewable portfolio standard (RPS), also known as a renewable electricity standard (RES), is a

mandatory requirement for retail electricity suppliers to supply a minimum percentage or

amount of their retail electricity load with electricity generated from eligible sources of

renewable energy.  An RPS indirectly affects EGU CO2 emissions by reducing the utilization of

fossil‐fuel‐fired EGUs. As of June 2013, 29 states and Washington, DC have adopted a

mandatory RPS, although designs vary (e.g., applicability, targets and timetables, geographic

and resource eligibility, alternative compliance payments) and an additional nine have

voluntary renewable goals.99

Policy Mechanics

Design  

RPS requirements typically start at modest levels and ramp up over a period of several years.

An RPS relies on market mechanisms to increase electricity generation from eligible sources of

                                                            

99 Ibid.
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renewable energy.  

Retail electricity suppliers can comply with RPS requirements through several mechanisms,

which vary by state, including:

 Ownership of a qualifying renewable energy facility and its electric generation output,  

 Purchasing electricity bundled with renewable energy certificates (RECs)100 from a

qualifying renewable energy facility, and  

 Purchasing RECs separately from electricity generators.  Unlike bundled renewable

energy, which is dependent on physical delivery via the power grid, renewable energy

certificates (RECs) can be traded between any two parties, regardless of their location.

However, state RPS rules typically condition the use of RECs based on either location of

the associated generation facility or whether it sells power into the state or to the

regional grid.

Authority

Most state RPS are established through legislation and administered by state PUCs.  

Obligated Parties

RPS applicability varies by state. All state RPS apply to investor‐owned utilities, while some

state RPS obligate municipal utilities, rural cooperatives, and/or other retail providers, often

depending on a minimum number of customers served.   

Measurement and Verification

Some state RPS include an alternative compliance payment (ACP) option, where a retail

electricity supplier may purchase compliance credits from the state at a known price, which

acts as a de facto price cap, if it has not procured sufficient electricity from renewable energy

sources or RECs to meet the RPS compliance requirement.  State PUCs typically require annual

compliance reports from retail electricity suppliers subject to a RPS. Most states use regional

tracking systems (e.g., Western Renewable Energy Generation Information System, PJM

Generation Attribute Tracking System) to issue, track, and retire RECs for RPS compliance

                                                            

100 RECs represent the non‐energy attributes, including all the environmental attributes, of electricity generation

from renewable energy sources. RECs are typically issued in single MWh increments.  
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purposes.101  For more information about measurement and verification of renewable energy,

see earlier in the State Plan Considerations Technical Support Document.

Penalties for Noncompliance

States have developed a range of compliance enforcement and flexibility mechanisms. As of

2007, despite the fact that several states had not achieved the RPS targets, only Connecticut

and Texas had levied fines. A $5.6 million penalty was incurred in Connecticut in 2006. In 2003

and 2005, two competitive electricity service providers in Texas were penalized a total of

$4,000 and $28,000 respectively. Flexible enforcement and opportunities to “make‐up”

shortfalls in subsequent years or ACPs that are recycled to support other renewable and

efficiency measures have helped other states avoid penalties for noncompliance.102      

Implementation Status

States with RPS policies have demonstrated higher levels of renewable energy capacity

development. From 1998‐2012, 67 percent (46 GW) of all non‐hydro renewable capacity

additions occurred in states with active or impending RPS requirements, although other factors

may contribute to the growth in renewable capacity.103

ii. Performance‐Based Incentives and Finance Mechanisms For Renewable

Energy  

Description

States offer a diverse portfolio of financing and performance based incentive approaches that

are designed to address specific financial challenges and barriers and help specific markets and

customer groups produce clean energy.  

Policy Mechanics

Design

States support the advancement of clean generation technologies through performance‐based

incentives, including feed‐in tariffs and other payments, or tax incentives.  Performance‐based

                                                            

101 For a summary of REC tracking systems, see Federal Energy Regulatory Commission, “Renewable Power &

Energy Efficiency Market: Renewable Certificate Tracking” (September 2010); available at

http://www.ferc.gov/market‐oversight/othr‐mkts/renew/othr‐rnw‐rec‐trk.pdf. 102 Ryan Wiser and Galen Barbose, Renewables Portfolio Standards in the United States – A Status Report with Data

Through 2007 (April 2008). http://emp.lbl.gov/sites/all/files/REPORT%20lbnl‐154e‐revised.pdf 103 Barbose, Galen. (2013). Renewables Portfolio Standards in the United States: A Status Update. Lawrence

Berkeley National Laboratory.

http://www.renewableenergymarkets.com/docs/presentations/2013/REM_Sept2013_Barbose.pdf
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incentives are paid based on the actual energy production of a system. Feed‐in tariffs establish

temporarily elevated price per kWh in order to encourage renewable energy innovation using

high cost technologies. Tax incentives are used to lower financial barriers to renewable energy

production.  

A major source of funding for renewable energy activities comes from PBFs, but states also

fund these activities through alternative sources including direct grants, rebates and generation

incentives provided by utilities.  

State tax incentives for renewable energy and Combined Heat and Power (CHP) take the form

of personal or corporate income tax credits and tax exemptions. State tax incentives for

renewable energy are a common policy tool, mainly using credits on personal or corporate

income tax and exemptions from sales tax, excise tax, and property tax.  

Authority

Financial mechanisms and incentives for renewables are run by utilities, non‐profits, and state

and local government. Personal, corporate, sales, and property tax incentives are mainly

offered by state and local government.104  

Implementation Status

Financial mechanisms and incentives for renewable energy of some form exist in most states.

According to the Database of State Incentives for Renewable Energy (DSIRE), there are over 200

tax incentives. In addition, nearly a hundred performance based incentives are offered from

state and local governments, as well as utilities and non‐profits.105  

There are currently 18 states that have state‐wide performance‐based policies, and in several

other states utilities have adopted programs based on performance‐based incentives, including

feed‐in tariffs, standard offer payments, and payments in exchange for RECs.106 In many cases,

however, PBI is limited to customer‐sited projects or limited by size eligibility.

Financial incentives, working in concert with a strong RPS and net metering policies, have

contributed to the rapid growth in solar power deployment in New Jersey. The state’s RPS

includes a minimum carve‐out for solar sources, and allows solar energy generators to earn

Solar Renewable Energy Certificates (SRECs) that can then be sold to electricity suppliers trying

to meet the minimum solar production and/or purchase requirement. As a result of these

interdependent policies, solar photovoltaic facilities are increasing, with installations more than

                                                            

104 http://www.dsireusa.org/summarytables/finre.cfm 105 http://www.dsireusa.org/summarytables/finre.cfm    106 http://www.dsireusa.org/summarytables/finre.cfm.
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doubling from 2010 through 2011.107 New Jersey ranks second only to California in terms of

total installed capacity.108  

d. Utility Planning Approaches and Requirements

Description

Some public utility commissions require utilities to conduct portfolio management or

integrated resource planning to provide least cost and stable electric service to customers over

the long term.  Portfolio management refers to energy resource planning that incorporates a

variety of energy resources, including supply‐side (e.g., traditional and renewable energy

sources) and demand‐side (e.g., energy efficiency) options. The term "portfolio management"

typically describes resource planning and procurement in states that have restructured their

electric industry. However, it can also include the more traditional integrated resource planning

(IRP) approaches applied to vertically integrated utilities.   

In addition to energy resource planning, two states have policies or requirements for utilities to

specifically factor pollution reduction requirements into their planning.  In Colorado, the Clean

Air Clean Jobs Act (CACJA), signed into law on April 19, 2010, required utilities to submit a plan

to the PUC showing how they would meet EPA standards for a variety of pollutants. The law

was passed because the state was out of compliance with the national Ambient Air Quality

Standard for Ozone, and the EPA threatened to propose more stringent standards for the state.  

In 2001, Minnesota enacted Minnesota Statute 216B.1692, which encourages utilities to make

voluntary emission reductions and provides them with a mechanism to recover the costs

through customer rate increases outside of the normal rate review cycle.109  

Policy Mechanics

Design

 Portfolio Management ‐ Portfolio management involves deliberately choosing among a

variety of electricity products and contracts. The approach emphasizes diversity—fuels,

technologies, and power supply contract durations. In its fullest form, energy efficiency

and renewable generation are key strategic components. Portfolio management

typically involves a multi‐step process of forecasting, resource identification, scenario

                                                            

107 Solar New Jersey, http://www.solar‐new‐jersey.org/2012/08/15/why‐has‐new‐jersey‐become‐a‐leader‐in‐solar‐

in‐the‐us/   108 NREL Open PV Project, https://openpv.nrel.gov/rankings 109 Minnesota PUC ‐ Report To The Legislature On Emissions Reduction Projects Under Minnesota Statutes

216B.1692 http://www.puc.state.mn.us/portal/groups/public/documents/pdf_files/000661.pdf
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analysis, and resource procurement. Several states as well as vertically integrated

utilities use IRP, a specialized form of portfolio management. Since these utilities own

their own generation assets, they use their IRPs to weigh the benefits of building their

own generation plants against procuring energy from other entities. The plans also

evaluate how best to balance peak versus off‐peak electric load requirements. In

addition, they compare various supply‐ and demand‐side options and contract and

financial hedging options. Companies achieve these goals simultaneously by analyzing

different scenarios. The IRPs detail fuel and electricity price information, customer

demand forecasts, existing plant performance, other plant additions in the region, and

legislative decisions. The following examples show how various states have designed

their programs:

o Montana is a deregulated state that has established least cost planning rules and

policy guidelines for default electricity suppliers. These rules and guidelines

target long‐term electricity supply and require utilities to submit electric supply

resource plans every two years with the aim of providing a balanced,

environmentally responsible electricity portfolio. These plans must include

supply‐side and demand‐side resources, and they must address the need to

supply power in a way that minimizes the environmental cost by estimating the

cost to the environment of alternatives. In addition, utilities must account for the

costs of complying with existing and future environmental regulations. When

considering various resource options, Montana requires a competitive

solicitation process, allowing resource operators and developers to submit their

proposals to the default electricity supplier for consideration. Montana also

requires the portfolio management plans to be subject to an advisory committee

review and a public review.110

o Oregon electric utilities, submit IRPs every two years, covering a 20 year

timeframe. The goal of these plans is to consider the acquisition of resources at

least cost while keeping the public interest in mind. Potential risk factors must be

considered, including price volatility, weather, the cost of meeting existing and

future federal environmental regulations. Quantifiable environmental

externalities are included, as are less quantifiable developments such as changes

in market structure and the establishment of a renewable portfolio standard. As

for energy efficiency requirements during the planning process, Oregon

determines these on a utility by utility basis. 111

                                                            

110 EPA – Clean Energy Guide to Action: http://epa.gov/statelocalclimate/resources/action‐guide.html 111 EPA – Clean Energy Guide to Action: http://epa.gov/statelocalclimate/resources/action‐guide.html
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 Multi‐Pollutant Utility Planning – Two states, Minnesota and Colorado, have worked

collaboratively with their investor‐owned utilities to develop multi‐pollutant emission

reduction plans on a utility‐wide basis. This multi‐pollutant, collaborative approach

enables utilities to determine the least cost way to meet long term and comprehensive

energy and environmental goals.

o The Colorado CACJA required investor‐owned utilities (IOUs) with coal plants to

submit a multi‐pollutant plan to the PUC to meet the EPA standards for NOx, SO2,

particulates, mercury, and CO2. Utilities were not required to adopt a specific

plan set by the state, but had to meet with Colorado Department of Public

Health and Environment (CDPHE) and PUC approval. Xcel Energy’s plan was

submitted and approved in 2010.112

o The Minnesota Emission Reductions Rider allows utilities to submit plans for

projects that reduce emissions and go beyond federal requirements outside of a

general rate case.  It allows them to recover the costs of those actions as an

incentive.113  The specific design and process of the projects vary by utility, but

typically involve installing additional pollution control equipment at coal‐fired

power plants, or repowering them with natural gas.  

Authority

State utility commissioners oversee utilities’ and default service providers’ procurement

practices in their states. Typically, the commissions solicit comments and input as they develop

portfolio management practices from a wide variety of stakeholders. The utility regulator may

also play a role in reviewing and approving utilities’ planning procedures, selection criteria,

and/or their competition solicitation processes.

Obligated Parties

Vertically integrated utilities are obligated under integrated resource planning, while in

restructured markets, the default utility service provider is obligated to conduct portfolio

management.

For multi‐pollutant planning, Colorado IOUs, Xcel Energy and Black Hills Energy, were required

to file plans with the Department of Public Health and Environment and the PUC in order to be

                                                            

112 The Regulatory Assistance Project (RAP). (2013). “Addressing the Effects of Environmental Regulations: Market

Factors, Integrated Analyses, and Administrative Processes.” The Regulatory Assistance Project, Montpelier, VT.   113 Minn. Stat.§216B.1692 (2013)
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compliant with the CACJA. Plans needed to meet the National Ambient Air Quality Standards

for a number of air pollutants.

As the Minnesota multi‐pollutant legislation is voluntary for state utilities, there is neither

compliance nor reporting requirements.

Measurement and Verification

Regulatory oversight aims to ensure utilities are following through with their plans. Regulators

sometimes require utilities to submit portfolio management plans and progress reports at

regular intervals. These plans and reports describe in detail the assumptions used, the

opportunities assessed, and the decisions made when developing resource portfolios.

Regulators then carefully review these plans and either approve them or reject them and

recommend changes needed for approval. California, for example, requires utilities to submit

biennial IRPs and quarterly reports on their plans.

Penalties for Noncompliance

There are no penalties for noncompliance, however there is usually significant interaction with

the regulator during the planning and implementation process as is described above.  

Implementation Status

Currently more than half of the states have integrated resource or other long‐term planning

requirements, 114 while Minnesota and Colorado have multi‐pollutant planning policies or

requirements.

In Montana, for example, the 2011 Electric Supply Resource Plan for NorthWestern Energy calls

for:

 Shortening the length of power supply contracts from seven years to a more

competitive, staged process of between three to five years.

 Diversifying Montana’s resource mix with the recent addition of a 150MW gas‐fired

power plant.

 Improving the integration of intermittent power sources into the power supply as new

wind turbines play a larger role in the state’s resource mix.

 Meet state RPS requirements.

 Acquire cost‐effective demand side management resources, targeting 6MW of

additional energy conservation per year.

                                                            

114 Wilson, Rachel and  Bruce Biewald, Best Practices in Electric Utility Integrated Resource Planning Examples of

State Regulations and Recent Utility Plans, June 2013, www.raponline.org.
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 Monitor market, regulatory, and technology changes to better manage risks and

opportunities.115

In Oregon, PacifiCorp has filed its 2013 integrated resource plan. Key highlights from the report

include:

 Demand–side energy efficiency efforts are expected to meet 67 percent of electricity

load growth from 2013 to 2022

 Market analyses for integrating Wind resources into the grid, and pursuing

opportunities for combined heat and power resources.

 Goals to obtain 1,425 – 1,876 GWh of energy efficiency resources by 2015 and 2,034 –

3,180 GWh by 2017.

 Permitting and development efforts to convert a unit of the Naughton power plant from

coal to gas.116

                                                            

115 Northwestern Energy Electric Supply Resource Plan: https://www.northwesternenergy.com/our‐

company/tariffs‐and‐rates/montana‐tariffs‐and‐rates/electric‐supply‐resource‐procurement‐plan   116 PacifiCorp 2013 Integrated Resource Plan:

http://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Integrated_Resource_Plan/2013IRP/Pac

ifiCorp‐2013IRP_Vol1‐Main_4‐30‐13.pdf
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To meet Colorado’s multi‐pollutant planning requirement, Xcel Energy submitted a plan that

was approved by the Colorado PUC on December 9, 2010. Implementation of the plan will

reduce NOx levels 88% and CO2 levels 28% relative to 2008 levels by 2018. 117   Black Hills Energy

has also filed its electric resource plan (ERP). This plan includes the retirement of a coal‐fired

power plant and two older natural gas‐fired gas units, as well as a proposal to build a 40 MW

natural gas turbine. It plans to add 100 MW of capacity by 2017, Black Hills Energy will use

competitive bidding to meet the remaining 60 MW.118

In Minnesota, projects currently implemented under the multi pollutant legislation include the

Minnesota Power’s Arrowhead Regional Emissions Abatement (AREA) Project, Minnesota

Power’s Boswell 3 Emissions Reduction Plan, Xcel Energy’s Mercury Reduction Plan, and Xcel

Energy’s Metropolitan Reduction Proposal (MERP). MERP, authorized in 2002, has shown a 93%

reduction in SO2, 91% reduction in NOx, 81% reduction in mercury, 55% reduction in

particulates, and 21% reduction in CO2 from 2007‐2009.119

                                                            

117 Public Service Company of Colorado, an Xcel Energy Company , Xcel Energy‐Emissions Reduction Plan, 11‐06‐

325_6E_FS, 2011. https://www.xcelenergy.com/staticfiles/xe/Corporate/Environment/10‐12‐303_CACJ‐6E_FS.pdf   118 Black Hill Energy files plan for ongoing reliable, cost‐effective energy for years to come in Colorado:

http://www.blackhillsenergy.com/node/34671#.UzHkuIXYhIt   119 Update/add citation