Cutting Power Sector
Carbon Pollution:
State Policies arid Programs
This document provides updated information that reflects existing state policies and
programs as of June 13, 2016. It builds on information presented in the Appendix to
the State Plan Considerations Technical Support Document developed for U.S.
Environmental Protection Agency Clean Power Plan proposal in June 2, 2014 (Docket
ID No. EPA-HQ-OAR-2013-0602). This update does not modify that record in any way
but provides, for informational purposes only, updated details about existing state
policies and programs that reduce CO2 emissions from the power sector.
v>EPA
U.S. ENVIRONMENTAL PROTECTION AGENCY
JUNE 2016
WWW.EPA.GOV/STATELOCALCLIMATE
eMIbmiiL
State and Local
Climate and Energy Program
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Contents
I. Overview of State Climate and Energy Policies and Programs That Reduce Power Sector C02
Emissions 6
II. Existing State and Utility Policies, Programs, and Measures That Affect EGU C02 Emissions 8
A. Actions That Directly Reduce EGU C02 Emissions 9
i. Market-based Emissions Limits 10
ii. C02 Emissions Performance Standards 18
B. Energy Efficiency Policies, Programs, and Measures 25
i. Energy Efficiency Resource Standards 26
ii. Demand-side Energy Efficiency Programs 30
iii. Building Energy Codes 32
iv. Appliance and Equipment Efficiency Standards 36
v. Incentives and Finance Mechanisms for Energy Efficiency 37
C. Renewable Energy Policies and Programs 39
i. Renewable Portfolio Standards 39
ii. Performance-based Incentives and Finance Mechanisms for Renewable Energy 43
D. Utility Planning Approaches and Requirements 44
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List of Figures
Figure 1: Status of Electricity Restructuring by State 7
Figure 2: States with Active Greenhouse Gas Emissions Budget Trading Programs 10
Figure 3: Historical GDP and Greenhouse Gas Emissions in the RGGI Region 17
Figure 4: States with Greenhouse Gas Performance Standards 19
Figure 5: Status of Energy Efficiency Resource Standards by State 29
Figure 6: Residential State Energy Code Status 35
Figure 7: Commercial State Energy Code Status 35
Figure 8: States with Renewable Portfolio Standards 40
Figure 9: States with Integrated Resource Planning or Similar Processes 49
List of Tables
Table 1: Comparison of RGGI and California Emissions Budget Trading Programs 12
Table 2: Examples of State C02 Performance Standards 22
Table 3: Examples of Measurement and Verification Requirements for C02 Performance Standards 23
Table 4: Examples of Penalties for Noncompliance 28
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List of Acronyms
ACEEE - American Council for an Energy Efficient Economy
ACP - Alternative Compliance Payment
BSER - Best System of Emissions Reduction
CAGA - Clean Air Clean Jobs Act
CCR - Cost Containment Reserve
CHP - Combined Heat and Power
CEMS - Continuous Emissions Monitoring System
CO2 - Carbon Dioxide
CChe - 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 - Electric Generating Unit
EIA - Energy Information Administration
EM&V - Evaluation, Measurement, and Verification
EPA - Environmental Protection Agency
ERP - Electricity 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
MMTC02e - Million Metric Tons of Carbon Dioxide Equivalent
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 5
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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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I. Overview of State Climate and Energy Policies and Programs That Reduce
Power Sector CO2 Emissions
Across the nation, many states and regions have shown strong leadership in creating and
implementing policies, programs, and measures that reduce CO2 emissions from the power
sector, while achieving other economic, environmental, and energy benefits. These policies and
programs can serve as a strong foundation for states developing strategies to reduce
greenhouse gas (GHG) emissions and for those that voluntarily choose to continue exploring
options to address requirements for affected electric generating units (EGUs) under the final
"Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating
Units," also known as the Clean Power Plan.1
This document provides an overview of existing state activities that reduce CO2 emissions from
the power sector. Policies and programs range from market-based programs and CO2 emissions
performance standards that require CO2 emissions reductions from EGUs, to others, such as
renewable portfolio standards (RPS) and energy efficiency resource standards (EERS), that
reduce CO2 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.
States vary in their regulatory structures, electricity generation, and usage 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. State public utility regulators have authority over these utilities. In other
states, where the electric power industry has been restructured, ownership of electric
generation assets has been decoupled from transmission and distribution assets, and retail
customers have their choice of electricity suppliers. In states where restructuring is active (see
Figure 1), state public utility regulators do not have authority to regulate the companies
responsible for electricity generation, but they can regulate the electricity distribution utilities.
States rely upon and have access to different fuel types and have a variety of EGU types within
state borders. States are part of regional electricity grids that usually do not align with state
1 On February 9, 2016, the Supreme Court stayed the Clean Power Plan. EPA is not implementing or enforcing the
requirements of the rule accordingly at this time. EPA is providing technical assistance for states who choose to
move forward on a voluntary basis to address the requirements of the Clean Power Plan. Available at
https://www.gpo.gov/fdsvs/pkg/FR-2015-10-23/pdf/2015-22842.pdf.
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borders. Electricity is imported arid exported by utilities across states throughout each regional
grid.
Figure 1: Status of Electricity Restructuring by State
Source: "Status of Restructuring by State as of September 2010" (U.S. Energy information Administration),
accessed March 10, 2016. Available at:
http://www.eia.gov/electricitv/policies/restructuring/restructure elect.html.
States also have different economic considerations, drivers, and approaches when
implementing climate change, energy efficiency, and renewable energy policies, programs, and
measures. State actions may be motivated by state environmental, energy and/or economic
concerns. For example, as of March 2016, 12 states and Washington, D.C., have passed
legislation establishing GHG reduction goals and are using a combination of emissions limits,
performance standards, energy efficiency, and renewable energy measures to achieve these
goals.2 Other state measures are motivated by public utility commission (PUC) requirements to
achieve all cost-effective end-use energy efficiency improvements or by renewable energy
generation requirements. Policies, programs, and measures vary from state to state in their
2 States include California, Connecticut, Hawaii, Maine, Maryland, Massachusetts, Minnesota, New Jersey, Oregon,
Rhode Island, Vermont 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. "Greenhouse Gas
Emissions Targets," Center for Climate and Energy Solutions, accessed March 10, 2016. Available at:
http://www.c2es.org/us-states-regions/policv-maps/emissions-targets.
Electricity Restructuring by State
I I Not Active
D Active
I I Suspended
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implementation levels and administration. Some are administered by state agencies and others
by utilities, with varying mechanisms for ensuring compliance with applicable requirements.
This document is not exhaustive and is only intended to provide background information about
strategies states have used to achieve CO2 emissions reductions in the power sector, advance
end-use energy efficiency, and increase the use of renewable energy resources. For example,
states may consider measures that other states have used to support other low- or zero-
emitting generating technologies beyond what is addressed here. This document in no way
purports to indicate or evaluate whether the state policies and programs described meet the
requirements of the Clean Power Plan or a CAA section 111(d) state plan more generally.
II. Existing State and Utility Policies, Programs, and Measures That Affect
EGU CO2 Emissions
Some state and utility policies, programs, and measures directly target EGU CO2 emissions by
creating specific limits or standards for CO2 emissions in the power sector. Other policies and
programs, such as those that advance deployment of end-use energy efficiency or renewable
energy, are designed to reduce energy demand or promote an increase of supply from low- or
non-GHG-emitting generating sources, which reduces CO2 emissions from fossil fuel-fired
EGUs. Many states that are aggressively pursuing climate change mitigation look to end-use
energy efficiency and renewable energy first, recognizing the potential for low-cost GHG
emissions reductions and the economic, reliability, and fuel diversity benefits these resources
provide.
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,
although these source-level control efforts are a vital starting point."3 California calls its energy
efficiency standards "the bedrock upon which climate policies are built" and uses renewable
energy to fill any remaining energy needs.3 On October 7, 2015, California Governor Jerry
Brown signed The Clean Energy and Pollution Reduction Act of 2015, requiring California to
generate half of its electricity from renewable sources by 2030 and double energy efficiency in
homes, offices and factories.4 The policies will assist California in meeting its statewide goal of
reducing GHG emissions to 1990 levels by 2020, 40 percent below 1990 levels by 2030 and 80
3 Mary Nichols (Chairman of California Air Resources Board), letter to EPA Administrator Gina McCarthy, December
27, 2013.
4 Gov. Brown signs climate change bill to spur renewable energy, efficiency standards. October 7, 2015. LA Times.
Available at: http://www.latimes.com/politics/la-pol-sac-ierrv-brown-climate-change-renewable-energy-
20151007-storv.html.
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percent below 1990 levels by 2050.5 As another example, 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 Connecticut considers energy efficiency investments,
expanded renewable energy generation, and participation in the Regional Greenhouse Gas
Initiative (RGGI) among its top ten strategies to reduce GHG emissions when considering cost-
effectiveness and GHG emissions reduction potential.7
Beyond these specific policies and programs, some states implement utility 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 Directly Reduce EGU CO2 Emissions
Existing state actions that directly reduce EGU CO2 emissions tend to fall in one of two
categories: market-based emissions limits or emissions performance standards.
5 Office of Governor Edmund G. Brown Jr. Governor Brown Establishes Most Ambitious Greenhouse Gas Reduction
Target in North America, April 29, 2015. Available at: http://gov.ca.gov/news.php?id=18938.
6 State of Connecticut, Connecticut House Bill No. 5600: An Act Concerning Connecticut Global Warming Solutions.
Available at: http://www.cga.ct.gov/2008/ACT/PA/2008PA-00098-R00HB-0560Q-PA.htm.
7 States' Section 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
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 Line 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. Letter hereafter referred to as "State environmental agency leaders from CA, CO, DE, IL, ME, MD, MA,
MN, NH, NY, OR, Rl, VT, WA, Open Letter to the EPA Administrator Gina McCarthy on Emission Standards Under
Clean Air Act Section 111(d), December 16, 2013."
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i. Market-based Emissions Limits
Description
An emissions budget trading program is a market-based tool for reducing pollution. The basic
approach, which involves the allocation and trade of a limited number of environmental
permits, has been used across environmental media, including air pollution control, clean water
regulation, and land-use applications.
As of March 2016, ten states have implemented emissions budget trading programs addressing
CO2 and other GHG emissions. As shown in Figure 2 below, these include California's emissions
budget trading 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.8,9
Figure 2: States with Active Greenhouse Gas Emissions Budget Trading Programs
GHG Emission Budget Trading Programs
Last updated 3/14/2016
8 Regional Greenhouse Gas Initiative Inc. Website Homepage, accessed March 10, 2016. Available at:
http://www.rggi.org/.
9 "Cap-and-Trade Program," California Air Resources Board, accessed March 10, 2016. Available at:
http://www.arb.ca.gov/cc/capandtrade/capandtrade.htm.
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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 over a specified time period for all of
the emissions sources subject to the program. To comply with the emissions limitation, each
emissions source must surrender emissions allowances equal to its reported emissions at the
end of each compliance period.
Allowances may be traded among both regulated and non-regulated parties, creating a market
for emissions 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 may 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)
• Initial emissions budget (i.e., the aggregate emissions limitation for covered emissions
sources) and emissions reduction schedule
• Flexibility provisions, in addition to ability to trade emissions 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 EGUs with a
capacity of 25 MW or greater.10
• All facilities in covered sectors, either directly
emitting or distributing fossil fuels with
potential combustion emissions, of at least
25,000 metric tons C02-equivalent (C02e) or
greater (with no minimum11 for emissions from
imported electricity).12
Scope
• Facilities in electric power sector.13
• Facilities in electric power, large industrial
sectors, and distributors of gasoline, certain
diesel fuels, liquefied petroleum gas, and
natural gas.1415
Emissions
budget
• Recently reduced 45 percent to 91
million tons of CO2 in 2014. Beginning
in 2015, the budget will decline 2.5
percent per year to 2020.16
• Set at 2 percent below expected 2012
emissions in 2013 (162.8 million tons of CO2),
declining by 2 percent in 2014 and 3 percent
annually from 2015 (394.5 million tons of
CO2)17 to 2020 (334.2 million tons of CO2).14,18
Compliance
period
• EGUs must demonstrate compliance
every three years and hold allowances
equal to 50 percent of reported CO2
emissions at the end of the first two
years of every three-year compliance
period.19
• Facilities must demonstrate compliance every
three years. On an annual basis, facilities must
also hold allowances and offsets covering 30
percent of the previous year's emissions.14
10 Regional Greenhouse Gas Initiative Inc., Overview of RGGI CO2 Budget Trading Program (RGGI Inc., October,
2007). Available at: http://www.rggi.org/docs/program summary 10 07.pdf.
11 As of January 1, 2015, all electricity imports, regardless of the size of the generating station of origin, are covered
under the emissions trading system.
12 California Air Resources Board, Cap and Trade Regulation Instructional Guidance, Chapter 2: Is My Company
Subject to the Cap-and-Trade Regulation (CARB, September, 2012). Available at:
http://www.arb.ca.gov/cc/capandtrade/guidance/chapter2.pdf.
13 "Regulated Sources," Regional Greenhouse Gas Initiative Inc., accessed March 10, 2016. Available at:
http://www.rggi.org/design/overview/regulated sources.
14 California Air Resources Board, Overview of ARB Emissions Trading Program (CARB, October, 2011). Available at:
http://www.arb.ca.gov/newsrel/2011/cap trade overview.pdf.
15 California Air Resources Board, Information for Entities That Take Delivery of Fuel for Fuels Phased into the Cap-
and-Trade Program Beginning on January 1, 2015 (CARB, 2015). Available at:
http://www.arb.ca.gov/cc/capandtrade/guidance/faq fuel purchasers.pdf.
16 Regional Greenhouse Gas Initiative Inc., "RGGI States Make Major Cuts to Greenhouse Gas Emissions from
Power Plants," Regional Greenhouse Gas Initiative Press Release (January 13, 2014). Available at:
http://www.rggi.org/docs/PressReleases/PR011314 AuctionNotice23.pdf.
17 The large cap increase in 2015 is due to the inclusion of transportation, natural gas, and other fossil fuel
distributors in the emissions trading program.
18 Center for Climate and Energy Solutions (C2ES), California Cap and Trade (C2ES, 2015) accessed March 10, 2016.
Available at: http://www.c2es.org/us-states-regions/kev-legislation/california-cap-trade.
19 "Compliance" Regional Greenhouse Gas Initiative Inc., accessed March 10, 2016. Available at:
http://www.rggi.org/market/tracking/compliance.
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Element
RGGI
California
Allowance
allocation
method
• Each state distributes allowances from
its established budget in an amount
and manner determined by its
applicable statutes and regulations.
Approximately 90 percent of CO2
allowances are distributed through
auction.20
• Allowances are both allocated and auctioned
off according to provisions established by the
program. More information is available from
CARB (see footnote).14
Cost
containment
provisions
• A Cost Containment Reserve (CCR) of
CO2 allowances provides a fixed
additional supply of allowances that
are only available if the auction price
exceeds a set threshold ($4 in 2014
rising to $10 in 2017 and 2.5 percent
per year to 2020).21
• An additional five million allowances
became available March 2014 when
market price exceeded the current
price trigger of $4 per ton.22
• CCR allowances increase from five
million in 2014 to 10 million in 2015
and beyond.23
• A strategic reserve is included, providing an
Allowance Price Containment Reserve of 1
percent of allowances for 2013-2014, 4 percent
of allowances for 2015-2017, and 7 percent of
allowances for 2018-2020. 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.24
Banking
• Allows unlimited allowance banking.10
• Allows unlimited allowance banking, but
regulated entities are subject to holding limits,
which are a function of the entity's annual
allowance budget.2518
20 Regional Greenhouse Gas Initiative Inc., "2015 Allowance Allocation." Available at:
www.rggi.org/design/overview/allowance-allocation.
21 Regional Greenhouse Gas Initiative Inc., "The RGGI CO2 Cap,"accessed March 10, 2016. Available at:
http://www.rggi.org/design/overview/cap.
22 Regional Greenhouse Gas Initiative Inc., "CO2 Allowances Sold at $4.00 at 23rd RGGI Auction," Regional
Greenhouse Gas Initiative Press Release (March 7, 2014). Available at:
http://www.rggi.org/docs/Auctions/23/PR030714 Auction23.pdf.
23 Regional Greenhouse Gas Initiative Inc., Summary of RGGI Model Rule Changes (Regional Greenhouse Gas
Initiative, Inc., 2013). Available at:
http://www.rggi.org/docs/ProgramReview/ FinalProgramReviewMaterials/Model Rule Summarv.pdf.
24 "California Cap on Greenhouse Gas Emissions and Market-Based Compliance Mechanisms to Allow for the Use of
Compliance Instruments Issued by Linked Jurisdictions," California Code of Regulations, Title 17, §95800-96023,
July 2013. Available at: http://www.arb.ca.gov/cc/capandtrade/ctlinkqc.pdf.
25 CARB Proposed Regulation to Implement the California Cap-and-Trade Program (California Air Resources Board,
2010). Available at: http://www.arb.ca.gov/regact/2010/capandtradel0/capisor.pdf.
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Element
RGGI
California
Offsets
• EGUs subject to RGGI are allowed to
use offsets within the RGGI region to
meet 3.3 percent of their compliance
obligation, increasing to 5 and 10
percent if allowance prices exceed
price thresholds of $7 and $10 per
allowance, respectively.26,27,28
• Facilities may use domestic offsets for up to 8
percent of their compliance obligation.29 A
framework has been established to include
international offsets but these are currently
not allowed in the program.30
Authority
State and regional GHG emissions budget trading programs are authorized through individual
state legislation and implemented through state regulations. For example, California
implemented its emissions budget 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.31 Each RGGI state has separate authorizing legislation, and in some cases, its legislation
specifically directs the use of auction proceeds. For example, Maine authorized its participation
in RGGI through Statute 580-A, Title 38 Chapter 3B: Regional Greenhouse Gas Initiative. This
statute also requires that 100 percent of auction proceeds go toward carbon reduction and
energy conservation efforts.32 RGGI is implemented through individual state CO2 budget trading
program regulations.33
26 Regional Greenhouse Gas Initiative Inc., "CO2 Offsets," accessed March 10, 2016. Available at:
http://www.rggi.org/market/offsets.
27 Eligible offsets under RGGI include: landfill methane capture and destruction, sulfur hexafluoride (SFs) reduction
from power transmission, U.S. forest projects (reforestation, improved forest management, and avoided
conversion) or afforestation (in Connecticut and New York only), end use energy efficiency, and agricultural
manure management. "Offset Categories" Regional Greenhouse Gas Initiative, Inc., accessed March 10, 2016.
Available at: http://www.rggi.org/market/offsets/categories.
28 Regional Greenhouse Gas Initiative Inc., Fact Sheet: RGGI Offsets. Available at:
http://www.rggi.org/docs/Documents/RGGI Offsets FactSheet.pdf.
29 California Air Resources Board, Overview of ARB Emissions Trading Program (CARB, October, 2011). Available at:
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 at: http://www.arb.ca.gov/cc/capandtrade/offsets/offsets.htm for more information;
accessed March 10, 2016.
30 California Air Resources Board, Overview of ARB Emissions Trading Program (CARB, 2011). Available at:
http://www.arb.ca.gov/newsrel/2011/cap trade overview.pdf.
31 Assembly Bill 32, California Global Warming Solutions Act of 2006, Division 25.5 (September 27, 2006). Available
at: http://www.leginfo.ca.gov/pub/05-06/bill/asm/ab 0001-0050/ab 32 bill 20060927 chaptered.pdf.
32 Maine revised statutes, Title 38, Chapter 3-B, section 580-B, the Regional Greenhouse Gas Initiative Act of 2007,
accessed March 10, 2016. Available at: http://www.mainelegislature.org/legis/statutes/38/title38sec580-B.html.
33 Regional Greenhouse Gas Initiative Inc., "State Statutes and Regulations," accessed March 10, 2016. Available at:
http://www.rggi.org/design/regulations.
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The state regulatory authority issues individual authorizations to emit a specific quantity of
emissions ("allowances"), which represent one (metric or short) ton of a pollutant, in an
amount no greater than the established emissions budget.
Obligated Parties
Obligated parties in emissions budget trading programs are generally the covered emissions
sources. The emissions sources are responsible for surrendering emissions allowances equal to
their reported emissions at the end of each compliance period. For example, as stated above,
RGGI covers fossil fuel-fired EGUs 25 megawatts or larger in size.34 The California emissions
budget trading program covers electricity generators, distributors of transportation, natural
gas, and other fuels, and industrial facilities with emissions35 greater than 25,000 metric tons
C02-e. The program also covers all importers of electricity.36
Measurement and Verification
Emissions budget trading programs include requirements for emissions monitoring and
reporting by affected emissions sources, holding and transfer of allowances, and surrender of
allowances (and offset allowances or credits) in an amount equal to reported emissions.
Allowance surrender in an amount equal to reported emissions is often referred to, generally,
as the program "compliance obligation."
For example, EGUs subject to the RGGI program must report CO2 emissions quarterly pursuant
to state regulations, which are generally consistent with EPA regulations for reporting of CO2
emissions from EGUs under 40 CFR 75.37 Emissions are reported quarterly to EPA, using the
Emissions Collection and Monitoring Plan System (ECMPS), and data is transferred to the RGGI
CO2 Allowance Tracking System (RGGI COATS). GHG emissions reporting for affected sources
under the California program 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.38 Affected emissions sources must report emissions
annually and provide third party verification of reported emissions.
34 "Regulated Sources," Regional Greenhouse Gas Initiative Inc., accessed March 10, 2016. Available at:
http://www.rggi.org/design/overview/regulated sources.
35 Fossil fuel distributors are liable for combustion emissions that occur downstream of their operations.
36 California Air Resources Board, Overview of ARB Emissions Trading Program (CARB, 2011). Available at:
http://www.arb.ca.gov/newsrel/2011/cap trade overview.pdf.
37 Regional Greenhouse Gas Initiative Inc., Overview of RGGI CO2 Budget Trading Program (RGGI Inc., 2007).
Available at: http://www.rggi.org/docs/program summary 10 07.pdf.
38 California Air Resources Board, Overview of ARB Emissions Trading Program (CARB, 2011). Available at:
http://www.arb.ca.gov/newsrel/2011/cap trade overview.pdf.
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Penalties for Non-compliance
Failure to submit allowances in an amount equal to reported emissions result in automatic
emissions penalties in the form of additional allowance submission requirements (e.g., three-
to-one submission requirements to account for any shortfall in RGGI, and a four-to-one
submission requirement for any shortfall under the California program). States may also apply
other administrative fines and penalties, pursuant to their implementing regulations.
Implementation Status
The RGGI program was established in 2009. From 2009 through 2013, the nine current RGGI
participating states invested auction proceeds of more than $1 billion in programs that lower
costs for energy consumers and reduce CO2 emissions, including approximately $630 million in
energy efficiency programs.39 The participating RGGI states estimate that those investments are
providing benefits of more than $2.9 billion in lifetime energy savings to energy consumers in
the region.39
Between 2005, when agreement to implement RGGI was first announced, and 2013, power
sector CO2 emissions in the RGGI participating states fell by more than 40 percent while GDP in
the region grew by more than 8 percent (see Figure 3).40
39 Regional Greenhouse Gas Initiative Inc., Investment of RGGI Proceeds Through 2013 (RGGI Inc., 2015). Available
at: http://www.rggi.org/docs/ProceedsReport/lnvestment-RGGI-Proceeds-Through-2013.pdf. Programs include
residential, commercial, and industrial programs. Of the $1 billion in auction proceeds invested by RGGI
participating states through 2012, 62 percent supported end-use energy efficiency programs.
40 Regional Greenhouse Gas Initiative Inc., Investment of RGGI Proceeds Through 2013 (RGGI Inc., 2015). Available
at: http://www.rggi.org/docs/ProceedsReport/lnvestment-RGGI-Proceeds-Through-2013.pdf.
By contrast, total U.S. power sector CO2 emissions fell by 15 percent during the same period of time. See 2015 U.S.
Greenhouse Gas Inventory for more detail: U.S. EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-
2013 (U.S. Environmental Protection Agency, 2015), Available at:
https://www3.epa.gov/climatechange/ghgemissions/usinventorvreport/archive.html.
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Figure 3: Historical GDP and Greenhouse Gas Emissions in the RGGI Region
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The California economy-wide market-based GHG emissions budget trading program, which
addresses GHG emissions from multiple sectors, was implemented in 2012 with emissions limits
beginning in 20 13.45,46 While California's emissions budget trading program, like its state
emissions 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 CCh-e by 2025, a 25 percent reduction from 2005 power sector emissions
levels.47 Prior to the implementation of the emissions trading program, California reports that it
reduced power sector CO2 emissions by 16 percent from 2005 to a 2011-2013 averaging period,
a reduction of 16 million metric tons of CCh-e.48
ii. CO2 Emissions Performance Standards
Description
CO2 emissions 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
how electricity is generated and distributed, see Chapter 2 of the Regulatory Impact Analysis).
45 "Cap-and-Trade Program," California Air Resources Board, accessed March 10, 2016. Available at:
http://www.arb.ca.gov/cc/capandtrade/capandtrade.htm.
46 The California program was developed in coordination with U.S. state and Canadian province WCI partners.
47 State environmental agency leaders from CA, CO, DE, IL, ME, MD, MA, MN, NH, NY, OR, Rl, VT, WA, Open Letter
to the EPA Administrator Gina McCarthy on Emission Standards under Clean Air Act Section 111(d), December 16,
2013. Available at: http://www.eenews.net/assets/2013/12/16/document gw 06.pdf.
Preliminary California Air Resources Board analyses, based in part on CARB 2008 to 2012 Emissions for Mandatory
GHG reporting Summary (2013), cited in this letter.
48 California Greenhouse Gas Inventory. 2000-2013 Inventory by Economic Sector - Full Detail. Available at:
http://www.arb.ca.gov/cc/inventorv/data/tables/ghg inventory sector all 2000-13 20150831.pdf.
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Figure 4: States with Greenhouse Gas Performance Standards
Greenhouse Gas Performance Standards
| Applies lo new units and power purchase agreements
Applies only to new units
Requires or incentivizes carbon capture and storage at new coal-
Last Updated 3/14/16
fired power plants
As shown above in Figure 4,, as of March 2016, four states—California, New York, Oregon, and
Washington—have enacted mandatory GHG emissions standards that impose enforceable
emissions limits on new and/or expanded electric generating units.49 Three states—California,
Oregon, and Washington—have enacted mandatory GHG emissions performance standards
that set an emissions rate for electricity purchased by electric utilities/'9 In addition to these
states, Illinois and Montana have policies to incentivize or require new coal plants to capture at
least 50 percent of their CO? emissions.49
49 California Energy Commission, California SB 1368, Chapter 598: Emission Performance Standards, September 29,
2006. Available at: http://www.energy.ca.gov/emission standards/. New York Department of Environmental
Conservation, Part 251: CO2 Performance Standards for Major Electric Generating Facilities, June 12, 2012.
Available at:
https://govt.westlaw.com/nycrr/Browse/Home/NewYork/NewYorkCodesRulesandRegulations?guid=l5d3c9d90eaf
bile 19f380000845b8d3e&originationContext=documenttoc&transitionType=Default&contextData=(sc, Default).
Oregon Department of Energy, Oregon's Carbon Dioxide Emission Standards for New Energy Facilities (Oregon
Department of Energy, 2010). Available at: http://www.oregon.gov/energv/Siting/docs/Reports/C02Standard.pdf.
Washington State Legislature, Chapter 80.70 RCW: Carbon Dioxide Mitigation. Available at:
http://apps.leg.wa.gov/rcw/default.aspx?cite=80.70&full=true. Illinois General Assembly, Public Act 095-1027,
SB1987, Clean Coal Portfolio Standard Law, January 12, 2009. Available at:
http://ilga.gov/legislation/publicacts/95/PDF/095-1027.pdf. Montana State Legislature, H.B.0Q25.05, An Act
Generally Revising the Electric Utility Industry and Customer Choice Laws, May 14, 2007. Available at:
http://leg.mt.gov/bills/2007/bilipdf/HB0Q25.pdf.
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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,
Montana).50'51 Oregon's program is regulated through the Oregon Energy Facility Siting
Council.52 New York's program is regulated through the Department of Environmental
Conservation.53 Washington's program is regulated through two different sets of entities
depending on the ownership of the utilities. The Washington Department of Community, Trade
& Economic Development (CTED) is responsible for updating the emissions performance
standard every five years.54 In addition, the Washington Energy Facility Site Evaluation Council
(EFSEC) is in charge of evaluating and licensing state power plants.55 Illinois's program is
regulated by the Illinois Commerce Commission.56
50 California Energy Commission, "California SB 1368, Chapter 598: Emission Performance Standards" (September
29, 2006). Available at: http://www.energy.ca.gov/emission standards/.
51 Center for Climate and Energy Solutions (C2ES), "Standards and Caps for Electricity GHG Emissions" (C2ES, 2015)
accessed March 10, 2016. Available at: http://www.c2es.org/us-states-regions/policv-maps/electricitv-emissions-
caps.
52 Oregon Department of Energy, Oregon's Carbon Dioxide Emission Standards for New Energy Facilities (Oregon
Department of Energy, 2010). Available at: http://www.oregon.gov/energy/Siting/docs/Reports/C02Standard.pdf.
53 New York Department of Environmental Conservation, "DEC Adopts Ground-Breaking Power Sector Regulations
to Analyze Possible Environmental Impacts and Limit CO2 Emissions from Power Plants," (NY DEC, 2012). Available
at: http://www.dec.nv.gov/press/83269.html.
54 Regulatory Assistance Project, "Emissions Performance Standards in Selected States" (RAP, 2009). Available at:
http://www.raponline.org/docs/RAP Simpson EPSResearchBrief 2009 11 13.pdf.
55 State of Washington, "Energy Facility Site Evaluation Council" (State of Washington, 2015), accessed March 10,
2016. Available at: http://www.efsec.wa.gov/default.shtm.
56 State of Illinois, "Illinois SB 1987: Clean Coal Portfolio Standard Law" (January 12, 2009). Available at:
http://www.c2es.org/docUploads/IL%20SB1987%20Coal.pdf.
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Obligated Parties
The emissions 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 2 provides an overview of different CO2 performance standards, while 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
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 emissions rate of either 925 lbs. C02/MWh (output based) or 120 lbs
CO2/MMBTU (input based). Non-baseload plants (25 MW and larger) must meet an
emissions rate of either 1450 lbs. C02/MWh (output based) or 160 lbs. CO2/MMBTU
(input based).57
• Oregon (HB 3283; 1997, 2007) - New natural gas-fired power plants (baseload and non-
baseload) must meet an emissions rate of 675 lbs. C02/MWh. Cogeneration and offsets
may be used to comply with the emissions standard.58 Baseload power plants must
meet an emissions rate of 1,100 lbs. C02/MWh.59
• Washington (RCW 80-70-010; 2004, SB 6001) - 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).60 Baseload power plants must meet an emissions rate of 1,100 lbs.
C02/MWh.61
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 emissions rate that does not exceed that of a natural gas combined cycle
plant. The California Energy Commission promulgated regulations establishing an
emissions rate of 1,100 lbs. C02/MWh.62 By comparison, the average emissions rate of
gas plants in the U.S. is 945 lbs. C02/MWh, while the average emissions rate of
pulverized coal plants is 2,154 lbs. C02/MWh.63
• Oregon (HB SB 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 emissions rate of 1,100 lbs. C02/MWh or less.
57 New York Department of Environmental Conservation, "DEC Adopts Ground-Breaking Power Sector Regulations
to Analyze Possible Environmental Impacts and Limit CO2 Emissions from Power Plants," (NY DEC, 2012). Available
at: http://www.dec.nv.gov/press/83269.html.
58 Oregon Department of Energy, Oregon's Carbon Dioxide Emission Standards for New Energy Facilities (Oregon
Department of Energy, 2010). Available at: http://www.oregon.gov/energy/Siting/docs/Reports/C02Standard.pdf.
59 Center for Climate and Energy Solutions (C2ES), Standards and Caps for Electricity GHG Emissions (C2ES, 2015),
accessed March 10, 2016. Available at: http://www.c2es.org/us-states-regions/policv-maps/electricitv-emissions-
caps.
60 Washington State Legislature, Chapter 80.70 RCW: Carbon Dioxide Mitigation. Available at:
http://apps.leg.wa.gov/rcw/default.aspx?cite=80.70&full=true.
61 Center for Climate and Energy Solutions (C2ES), Standards and Caps for Electricity GHG Emissions (C2ES, 2015),
accessed March 10, 2016. Available at: http://www.c2es.org/us-states-regions/policv-maps/electricitv-emissions-
caps.
62 California Energy Commission, California SB 1368, Chapter 598: Emission Performance Standards, September 29,
2006, accessed March 10, 2016. Available at: http://www.energy.ca.gov/emission standards/.
63 U.S. EPA, eGRID 2010 data files (U.S. Environmental Protection Agency, 2014), accessed March 10, 2016.
Available at: https://www.epa.gov/energy/egrid. See "Download all eGRID files (1996-2012) (ZIP)" link.
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What It Does
State Examples
Requires that
new coal-fired
power plants
must capture
and store a
specific
percentage of
CO2 emissions
• 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
2017.64
• Montana (HB 25; 2007) - The Public Service Commission mav not approve new plants
constructed after January 2007 that are primarily coal-fired unless at least 50 percent of
the plant's CO2 emissions are captured and stored. These requirements apply to
formerly restructured utilities in the state. Northwest Energy is the only utility subject
to this requirement, which serves about two-thirds of Montana.
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.65
New York
• CO2 emissions 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 75.66
64 Illinois General Assembly, Public Act 095-1027, SB1987, Clean Coal Portfolio Standard Law, January 12, 2009.
Available at: http://ilga.gov/legislation/publicacts/95/PDF/095-1027.pdf.
65 "SB 1368 Emission Performance Standards," California Energy Commission, accessed March 10, 2016. Available
at: http://www.energy.ca.gov/emission standards/.
66 New York Department of Environmental Conservation, "DEC Adopts Ground-Breaking Power Sector Regulations
to Analyze Possible Environmental Impacts and Limit CO2 Emissions from Power Plants" (NY DEC, 2012). Available
at: http://www.dec.nv.gov/press/83269.html.
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State
Measurement and Verification Details
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.67
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.68
Penalties for Noncompliance
For policies that affect 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 test,69 they must purchase offsets to
account for any excess emissions.70
67 Washington State Legislature, Chapter 80.70 RCW: Carbon Dioxide Mitigation. Available at:
http://apps.leg.wa.gov/rcw/default.aspx?cite=80.70&full=true.
68 Oregon Department of Energy, Oregon's Carbon Dioxide Emission Standards for New Energy Facilities (Oregon
Department of Energy, 2010). Available at: http://www.oregon.gov/energy/Siting/docs/Reports/C02Standard.pdf.
69 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.
70 Oregon Department of Energy, Oregon's Carbon Dioxide Emission Standards for New Energy Facilities. Available
at: http://www.oregon.gov/energy/Siting/docs/Reports/C02Standard.pdf.
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Implementation Status
Between 2007, when California enacted the performance standard and 2013, California's
carbon emissions rates fell from approximately 860 lbs. CChe/MWh for all generation
(considering both in-state and imported power) to approximately 710 lbs. CChe/MWh.71
B. Energy Efficiency Policies, Programs, and Measures
Demand-side energy efficiency policies and programs reduce utilization of EGUs and avoid GHG
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. Barriers include a 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 reduces the associated 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 legislated GHG targets,72 accounting for roughly 35 percent to 70
percent of expected reductions of these states' power sector emissions.73 For example, under
California's Climate Change Scoping Plan, the state projects reductions of 21.9 million metric
tons of carbon dioxide equivalent (MMTCChe) in 2020 from energy efficiency programs
targeting electricity reductions. Taking into account projected reductions of 21.3 MMTCChe
from California's RPS and the expected 2.1 MMTCChe reduction from the Million Solar Roofs
program, energy efficiency makes up 48 percent of power sector reductions based on
California's Climate Change Scoping Plan.74 Another state, Washington, projects to reduce 9.7
MMTCChe from energy efficiency measures in 2020 through a mix of new and existing
programs. Taking into account expected reductions of 4.1 MMTCChe from Washington's RPS,
energy efficiency makes up 70 percent of expected emissions reductions from stationary energy
within the state.75
71 California Air Resources Board, California Greenhouse Gas Emissions for 2000 to 2013 - Trends of Emissions and
Other Indicators (June 2015). Available at:
http://www.arb.ca.gov/cc/inventorv/pubs/reports/ghg inventory trends 00-13%20 10sep2015.pdf.
72 States with legislated GHG targets include California, Connecticut, Hawaii, Maine, Maryland, Massachusetts,
Minnesota, New Jersey, Oregon, Vermont, and Washington.
73 These reduction target ranges are based on a review of state GHG reduction laws in states with legislated GHG
targets.
74 California Air Resources Board, Climate Change Scoping Plan (December 2009). Available at:
http://www.arb.ca.gov/cc/scopingplan/document/adopted scoping plan.pdf.
75 Washington Department of Ecology, Growing Washington's Economy in a Carbon-Constrained World (December
2008). Available at: https://fortress.wa.gov/ecv/publications/publications/0801025.pdf.
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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 is 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, 23 states have
mandatory EE requirements in place, two states have voluntary targets, and two more states
allow EE to be used to meet part of a mandatory RPS, for a total of at least 27 states with some
type of EE requirement or goal.76'77
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.
76 "State Energy Efficiency Resource Standards (EERS)" (American Council for an Energy-Efficient Economy, April
2014). Available at: http://www.aceee.org/files/pdf/policv-brief/eers-04-2014.pdf.
77 Delaware and Florida were not included in the totals. Delaware has enacted legislation to create an EERS, but
final regulations have not yet been promulgated (Database of State Incentives for Renewables & Efficiency,
January 2015). Available at: http://programs.dsireusa.org/svstem/program/detail/4510. Florida has enacted an
EERS, but program funding to date is considered to be "...far below what is necessary to meet targets" ("State
Energy Efficiency Resource Standards [EERS]," American Council for an Energy-Efficient Economy, April 2014).
Available at: http://www.aceee.org/files/pdf/policv-brief/eers-04-2014.pdf. Ohio's EERS, while included in the
total, was frozen for two years beginning in 2015. Cumulative targets will increase again from 2017 (Database of
States Incentives for Renewables & Efficiency, December 2014). Available at:
http://programs.dsireusa.org/svstem/program/detail/4542.
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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, such as by setting quantitative targets consistent with the achievement of "all cost-
effective energy efficiency."78
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.
Transmission and distribution infrastructure improvements may also count toward EERS
programs in some states.79 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.80 These estimates are
typically the basis for compliance reports submitted by retail electricity suppliers. See Table 4
for examples of penalties for program noncompliance.
78 Ernest Orlando, Benefits and Costs of Aggressive Energy Efficiency Programs and the Impacts of Alternative
Sources of Funding: Case Study of Massachusetts (Lawrence Berkeley National Laboratory, August 2010). Available
at: http://emp.lbl.gov/sites/all/files/REPQRT%20lbnl-3833e.pdf. 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, Rl, VT, WA. For MA, this goals has translated into achieving
annual electric energy savings equivalent to a 2.4 percent reduction in retail sales from energy efficiency programs
in 2012.
79 For example, Ohio allows transmission and distribution infrastructure improvements to count toward its EERS
(Database of State Incentives for Renewables & Efficiency, December 2014). Available at:
http://programs.dsireusa.org/svstem/program/detail/4542.
80 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).
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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 4 provides
examples of financial penalties in three states, Pennsylvania, Ohio and Illinois.
Table 4: Examples of Penalties for Noncompliance
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.81
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)82 per megawatt hour of under-compliance or noncompliance.83
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 ratepayers. If an electric utility
fails to comply with its plan after two years, it must make a contribution to the Low-
Income Home Energy Assistance Program (LIHEAP). Large utilities (those with more than
2,000,000 customers on December 31, 2005) must contribute $665,000, and medium
utilities (those with between 100,000 and 2,000,000 customers) must contribute
$335,000. Utilities that fail to meet their plans again after the third year must make
another contribution to the fund ($665,000 for large utilities and $335,000 for medium
utilities). After three years of non-compliance, the Illinois Power Agency shall assume
control over energy efficiency incentive programs. For natural gas utilities that fail to
meet their efficiency plans after three years, large utilities (those with more than
1,500,000 customers on December 31, 2008) must pay $600,000 into LIHEAP, medium
utilities (those with 500,000-1,500,000 customers on December 31, 2008) must pay
$400,000, and small utilities (those with 100,000-500,000 customers on December 31,
2008) must pay $200,000. If a utility fails to meet the standard for two consecutive
three-year planning periods, the Illinois Commerce Commission will transfer
responsibility of the utility's energy efficiency programs to an independent
administrator.84
81 "Energy Efficiency and Conservation Requirements for Utilities: Pennsylvania" (Database of State Incentives for
Renewables & Efficiency, June 2015). Available at: http://programs.dsireusa.org/svstem/program/detail/4514.
82 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.
83 "Energy Efficiency Portfolio Standard: Ohio" (Database of State Incentives for Renewables & Efficiency,
December 2014). Available at: http://programs.dsireusa.org/svstem/program/detail/4542.
84 "Energy Efficiency Standard: Illinois" (Database of State Incentives for Renewables & Efficiency, February 2016).
Available at: http://programs.dsireusa.org/svstem/program/detail/4501.
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Implementation Status
As of March 2016, 23 states have an active EERS, while at least two have EE targets or goals
that are voluntary at this time (see Figure 5). In addition, two states have renewable portfolio
standard that allow the option for energy efficiency to meet requirements.85
Figure 5: Status of Energy Efficiency Resource Standards by State86
Energy Efficiency Resource Standards
Mandatory -23
Eligible Under RPS - 2
Voluntary - 2
Last updated 3/14/2016
Most states are meeting or on track to meet their incremental savings goals, which typically
range from an annual reduction in electricity of about 0.1-2.5 percent. 86 In 2014, incremental
savings across the 50 states were equivalent to 0.69 percent of retail electricity sales.87 In 2012,
85 See footnotes 76 and 77.
86 States with voluntary EERS: Virginia and Missouri. States eligible under RPS: Nevada, North Carolina. For Nevada,
energy efficiency may meet a quarter of the standard through 2014, but is phased out of the RPS by 2025. For
North Carolina, its Renewable Energy and Energy Efficiency Portfolio Standard requires renewable generation
and/or energy savings of 6 percent by 2015,10 percent by 2018, and 12.5 percent by 2021 and thereafter. Energy
efficiency is capped at 25 percent of target, increasing to 40 percent in 2021 and thereafter. Information from:
http://aceee.org/files/pdf/policv-brief/eers-04-2014.pdf.
87 'The 2015 State Energy Efficiency Scorecard" (American Council for an Energy-Efficient Economy, October 2015;
uses data from 2014). Available at: http://aceee.org/research-report/ul509.
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15 of 26 states achieved 100 percent or more of their goals, six states met over 90 percent of
their goals, five states achieved over 80 percent of their goals, and only one state realized
savings below 80 percent of its goal.88
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 EERS programs, "all cost effective" energy
efficiency goals, integrated resource planning, and other demand-side management program
and budget processes.
Policy Mechanics
Design
Demand-side energy efficiency programs include financial incentives to use energy efficient
products, make energy efficiency upgrades to improve the performance of residential,
commercial, and industrial buildings, and provide 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 from revenues raised through emissions
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.89
States are also funding energy efficiency programs using revenues 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.
88 Annie Downs and Celia Cui. "Energy Efficiency Resource Standards: A New Progress Report on State Experience."
American Council for an Energy Efficient Economy (April 2014). Available at: http://aceee.org/research-
report/ul403.
89 RGGI Inc., Investment of RGGI Proceeds Through 2013 (Regional Greenhouse Gas Initiative Inc., April 2015).
Available at: http://www.rggi.org/docs/ProceedsReport/lnvestment-RGGI-Proceeds-Through-2013.pdf.
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Authority
Demand-side programs that are a part of EERS programs are typically established through
legislation or PUC authority. Other demand-side management programs can arise as a result of
utility planning processes and 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 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.
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.90 For example, data reported to the U.S. Energy Information
Administration (EIA) show that in 2014, incremental annual savings91 in electricity consumption
through demand-side efficiency programs were 268 GWh in Rhode Island, 1,201 GWh in
90 'The Future of Utility Customer-Funded Energy Efficiency Programs in the United States" (Lawrence Berkeley
National Laboratory, January 2013). Available at: https://emp.lbl.gov/sites/all/files/lbnl-5803e.pdf.
91 EIA defines incremental annual savings for a given year as annualized savings caused by new program
participants to existing energy efficiency programs, or program participants to new energy efficiency programs.
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Arizona, and 599 GWh in Iowa.92 These reductions are equivalent to 3.5 percent, 1.6 percent,
and 1.3 percent of total 2014 retail electricity sales in those states, respectively.93 According to
data and analyses from sources including Lawrence Berkeley National Lab (LBNL), the DOE
Energy Information Administration, and the American Council for an Energy Efficient Economy
(ACEEE), as well as the EPA's own analysis for the Clean Power Plan, at least 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.94
In 2014, utilities and administrators in all 50 states and the District of Columbia implemented
electricity demand-side energy efficiency programs, and savings from these programs are
increasing. State demand-side energy efficiency programs are estimated to have reduced
electricity demand by 25.7 million MWh in 2014, or 0.7 percent of national retail electricity
sales. These savings are an increase of 5.8 percent over the previous year.95
iii. Building Energy Codes
Description
Building 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.
Based on provisions of the Energy Policy Act of 1992, the International Energy Conservation
Code (IECC) is the prevailing national model code for residential buildings. Similarly, American
92 "Electric Power Sales, Revenue, and Energy Efficiency Form EIA-861 Detailed Data Files" (Energy Information
Administration, January 2016). Available at: http://www.eia.gov/electricitv/data/eia861/.
93 "Electricity: Detailed State Data" (Energy Information Administration, October 2015). Available at:
http://www.eia.gov/electricitv/data/state/.
94 See EPA's Demand-Side Energy Efficiency Technical Support Document (August 2015) for more information.
Available at: https://www.epa.gov/sites/production/files/2015-ll/documents/tsd-cpp-demand-side-ee.pdf.
95 'The 2015 State Energy Efficiency Scorecard" (American Council for an Energy-Efficient Economy, October 2015;
uses data from 2014). Available at: http://aceee.org/research-report/ul509.
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Society of Heating, Refrigerating and Air-Conditioning Engineers (ASHRAE) Standard 90.1 serves
as the national model commercial code. The most current codes are ASHRAE Standard 90.1-
2013 and 2015 IECC.96
Building code standards are revised every three years. The IECC codes are updated every 18
months using a prescribed process, and new editions are published every three years. The
ASHRAE Standard 90.1 revision process occurs on a three-year cycle, but proposals for revisions
are accepted at any time.97 The Energy Policy Act of 1992 requires DOE to conduct
determinations on each successive version of the IECC residential code provisions and ASHRAE
Standard 90.1. For residential buildings, each state must consider adoption of each successive
version of the IECC for which DOE makes a positive determination on energy savings, and
report to DOE within two years on whether they have adopted the new version. For commercial
buildings, state adoption of each successive version of ASHRAE Standard 90.1 is mandatory
subject to the same DOE determination process; however there are no penalties for states that
do not comply.98
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.
96 "Code Adoption Status: February 2016," Building Codes Assistance Project. Available at: http://bcap-
energy.org/wp-content/uploads/2015/ll/code status februarv 20161.pdf.
97 "Code Development," Online Code Environment & Advocacy Network, accessed March 11, 2016. Available at:
http://energvcodesocean.Org/research-topic/code-development#.
98 "Regulations & Rulemaking," Building Energy Codes Program, U.S. Department of Energy, Energy Efficiency &
Renewable Energy, accessed March 11, 2016. Available at: https://www.energycodes.gov/regulations.
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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.
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
As of September 2015, 25 states have adopted IECC 2009 residential energy codes, 10 states
and Washington, D.C., have adopted the IECC 2012, while two states have gone further by
adopting the IECC 2015. In the commercial sector, 21 states have adopted ASHRAE 90.1-2007,
18 states and Washington, D.C., have adopted ASHRAE 90.1-2010, and two states have adopted
ASHRAE 90.1-2013. Currently, 12 states have outdated or no statewide residential energy code,
and 11 states have outdated or no state-wide energy codes for commercial construction." The
current status of state residential and commercial energy codes are shown below in Figure 6
and Figure 7, respectively." Illinois is notable as a state that adopted the 2012 IECC on January
1, 2013, and has set up an aggressive system for implementing future updates to energy
building codes. A provision in past legislation to adopt 2009 IECC and ASHRAE 90.1-2007
directed the state's Capital Development Board to adopt subsequent versions of the IECC
within 9 months of publication. DOE expects lllinois's energy cost savings to reach $270 million
annually by 2030.100
99 Building Codes Assistance Project, Code Adoption Status, September 2015. Available at:
http://energycodesocean.org/sites/default/files/code%20status%201%20pgr%20new.pdf.
11111 U.S. EPA, Clean Energy-Environment Guide to Action (U.S. Environmental Protection Agency, 2015), accessed
March 10, 2016. Available at: http://epa.gov/statelocalclimate/resources/action-guide.html.
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Figure 6: Residential State Energy Code Status
RESIDENTIAL
¦
Meets or exceeds the 2015
IECC or equivalent (2)
Meets or exceeds the 2012
IECC or equivalent (11)
Meets or exceeds the 2009
IECC or equivalent (25)
Meets or exceeds the 2006
IECC or equivalent (6)
No statewide code or pre-
dates the 2006 IECC (12)
Source: Building Codes Assistance Project. Code Adoption Status (September 2015). Available at:
http://energycodesocean.org/sites/default/files/code%20status%201%20pgr%20new.pdf.
Figure 7: Commercial State Energy Code Status
COMMERCIAL
IVT Mk
pw At
I
m
¦
Meets or exceeds ASHRAE
Standard 90.1-2013 or
equivalent (2)
Meets or exceeds ASHRAE
Standard 90.1-2010 or
equivalent (19)
Meets or exceeds ASHRAE
Standard 90.1-2007 or
equivalent (21)
Meets or exceeds ASHRAE
Standard 90.1-2004 or
equivalent (3)
No statewide code or
predates ASHRAE Standard
90.1-2004 (11)
Source: Building Codes Assistance Project. Code Adoption Status (September 2015). Available at:
http://energvcodesocean.org/sites/default/files/code%20status%201%20pgr%20new.pdf.
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iv. Appliance and Equipment Efficiency Standards
Description
State appliance standards 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, although 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.
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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
As of March 2016, 16 states and Washington, D.C., have enacted appliance efficiency standards
since 2001. However, most of these standards have been superseded by federal standards. Still,
11 states (AZ, CA, CO, CT, NH, MD, OR, GA, TX, Rl, WA) and Washington, D.C., 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 17 products, including pool pumps and hot
tubs, vending machines, televisions, battery chargers, toilets and urinals, bottle-type water
dispensers, faucets, CD and DVD equipment, and various lighting applications.101
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 incentivize specific markets and customer
groups to invest in energy efficiency. These programs include revolving loan funds, energy
performance contracting, green banks, 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),102 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.
101 Appliance Standards Awareness Project, State Standards, accessed March 10, 2016. Available at:
http://www.appliance-standards.org/states.
102 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.103The contracts are privately funded and do not
involve state funding or financial incentives.
Green banks offer an emerging approach used by an increasing number of states to evolve
away from traditional state funded incentive programs. They use creative financing to bring and
leverage private capital to develop projects and markets. Green banks can be self-sufficient and
manage their seed capital in perpetuity. They do not require ongoing funding from the
legislative and state budget process once they are capitalized. Because green banks are
effectively nonprofit organizations, they can offer a capital cost far lower than any other source
of capital available in the market. States can consolidate their existing incentive programs and
resources under a green bank framework.104
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.105
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 program funds.
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.
103 U.S. EPA, Integrating State and Local Environmental and Energy Goals: Energy Performance Contracting - Fact
Sheet (U.S. Environmental Protection Agency, September 2004).
104 U.S. EPA, Clean Energy-Environment Guide to Action (U.S. Environmental Protection Agency, 2015), accessed
March 10, 2016. Available at: http://epa.gov/statelocalclimate/resources/action-guide.html.
105 Elizabeth Brown, Harvey Sachs, Patrick Quinlan, and Daniel Williams. 'Tax Credits for Energy Efficiency and
Green Buildings: Opportunities for State Action." American Council for an Energy Efficient Economy (2002).
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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.106
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 being rebates and loan
programs in place. There are 50 tax incentives and over a thousand rebate, grant, and loan
programs that help finance and deliver electricity savings.107 Texas LoanSTAR, also known as the
Loans to Save Taxes and Resources program, began in 1988 as a $98.6 million retrofit program
for energy efficiency in buildings (primarily public buildings such as state agencies, local
governments, and school districts). As of January 2014, the program has funded over 237 loans,
totaling more than $395 million. The program has also saved over $419 million and reduced
CO2 emissions by 3.7 million tons.108
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.109 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
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
106 "Programs," Database of State Incentives for Renewables & Efficiency, accessed March 10, 2016. Available at:
http://programs.dsireusa.org/svstem/program.
107 Ibid.
108 Texas State Energy Conservation Office, "LoanSTAR Revolving Loan Program," accessed March 24, 2016.
Available at: http://www.seco.cpa.state.tx.us/ls/.
109 Feed-in tariffs, a performance-based incentive, 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 energy.110 An RPS indirectly affects EGU CO2 emissions by reducing the utilization of
fossil fuel-fired EGUs. As of March 2016, 29 states and Washington, D.C., have adopted a
mandatory RPS (see Figure 8), although designs vary (e.g., applicability, targets and timetables,
geographic and resource eligibility, alternative compliance payments) and an additional eight
states have voluntary renewable goals.111,112
Figure 8: States with Renewable Portfolio Standards
Renewable Portfolio Standards
| Mandatory - 29
Voluntary - 8
Last updated 3/14/2016
110 In some state Renewable Portfolio Standards (alternatively called "Alternative and Renewable Energy Portfolio
Standards"), selected non-renewable sources such as coal bed methane or gasification are eligible for credit.
111 Database of State Incentives for Renewables and Efficiency (June 2015), accessed March 10, 2016. Available at:
http://www.dsireusa.org/.
112 Alaska House Bill 306, Signed by Governor Sean Parnell June 16, 2010. Available at:
http://www.legis.state.ak.us/basis/get bill text.asp?hsid=HB0306Z&session=26.
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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
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)113 from a
qualifying renewable energy facility.
• Purchasing RECs separately from electricity generators. Unlike bundled renewable
energy, which is dependent on physical delivery via the power grid, 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 RPSs are established through legislation and administered by state PUCs.
Obligated Parties
RPS applicability varies by state. All state RPSs 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 RPSs 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
113 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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Generation Attribute Tracking System) to issue, track, and retire RECs for RPS compliance
purposes.114
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.115 More recently the vast majority of states have met their
RPS requirements, and for those that have not, utilities have been allowed to "make-up"
shortfalls in subsequent years.116
ACPs that are recycled to support other renewable and efficiency measures have helped other
states avoid penalties for noncompliance.115 The reported compliance cost for the entire RPS in
the District of Columbia was $2.6 million in 2011, of which ACPs made up $229,500. Electricity
suppliers in Maryland submitted more than 4.6 million RECs for compliance in 2011 for a total
cost of $14.6 million, of which $98,520 came from ACPs.117
Implementation Status
States with RPS policies have demonstrated higher levels of renewable energy capacity
development. From 1998 to 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.118
114 For a summary of REC tracking systems, see: U.S. Department of Energy Renewable Energy Certificates,
National REC Tracking Systems, accessed March 10, 2016. Available at:
http://apps3.eere.energy.gov/greenpower/markets/certificates.shtml?page=3.
115 Ryan Wiser and Galen Barbose, Renewables Portfolio Standards in the United States - A Status Report with Data
Through 2007 (Lawrence Berkeley National Laboratory, April 2008). Available at:
http://emp.lbl.gov/sites/all/files/REPQRT%20lbnl-154e-revised.pdf.
116 Personal communication with Galen Barbrose of Lawrence Berkeley National Lab, March, 2016.
117 J. Heeter, G. Barbose, L. Bird, S. Weaver, F. Flores-Espino, K. Kuskova-Burns, and R. Wiser, "A Survey of State-
Level Cost and Benefit Estimates of Renewable Portfolio Standards" (NREL, May 2014). Available at:
http://www.nrel.gOv/docs/fvl4osti/61042.pdf.
118 Galen Barbose, Renewables Portfolio Standards in the United States: A Status Update (Lawrence Berkeley
National Laboratory, November 2013). Available at: http://emp.lbl.gov/sites/all/files/rps summit nov 2013.pdf.
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ii. Performance-based Incentives and Finance Mechanisms for Renewable Energy
Description
States offer a diverse portfolio of financing mechanisms, performance-based incentives, and
state utility ratemaking 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
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.119
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 more
119 "Summary Tables" (Database of State Incentives for Renewables & Efficiency), accessed March 10, 2016.
Available at: http://programs.dsireusa.org/svstem/program/tables.
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than 200 tax incentives. In addition, over 50 performance-based incentives are offered from
state and local governments, as well as utilities and non-profits.120
There are currently 26 states that offer some form of performance-based incentive, 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.121 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,122 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, the number of solar photovoltaic facilities grew, with total capacity in
New Jersey increasing by 20 percent from 2013 to 2014.123 New Jersey ranks second only to
California in terms of total installed PV capacity.124
D. Utility Planning Approaches and Requirements
Description
Some public utility commissions require utilities to conduct portfolio management or
integrated resource planning (IRP) to ensure the supply of 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 and may be required for default service providers (the
backup electric service provider in areas open to competition). IRP is generally used by
vertically integrated utilities and is a long-range planning process to meet forecasted demand
for energy within a defined geographic area through a combination of supply-side resources
and demand-side resources and considering a broad range of perspectives. The goal of an IRP is
120 "Summary Tables" (Database of State Incentives for Renewables & Efficiency), accessed March 10, 2016.
Available at: http://programs.dsireusa.org/svstem/program/tables.
121 "Summary Tables" (Database of State Incentives for Renewables & Efficiency), accessed March 10, 2016.
Available at: http://programs.dsireusa.org/svstem/program?type=13&.
122 Net metering policies allow solar installation owners to receive a credit on their utility bill for the excess
electricity generated by solar panels that is fed back into the grid.
123 Solar Energy Industries Association, "New Jersey Ranks 3rd in U.S. in Total Solar Capacity" (seia.org, March 17,
2015). Available at: http://www.seia.org/news/new-iersev-ranks-3rd-us-total-solar-capacitv.
124 "Open PV State Rankings," National Renewable Energy Laboratory, accessed March 10, 2016. Available at:
https://openpv.nrel.gov/rankings.
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to identify the mix of resources that will minimize future energy system costs while ensuring
safe and reliable operation of the system.
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, requires utilities to submit a plan
to the PUC showing how they would meet EPA standards for a variety of pollutants.125 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 emissions reductions and provides them with a mechanism to recover the costs
through customer rate increases outside of the normal rate review cycle.126
Policy Mechanics
Design
• Portfolio Management and IRP - Portfolio management emphasizes diversity in fuels,
technologies, and power supply contract durations. Portfolio management includes
energy efficiency and renewable generation as key strategic components. Portfolio
management typically involves a multi-step process of forecasting, resource
identification, scenario analysis, and resource procurement.
Several states and vertically integrated utilities rely on an IRP process for long-term
planning. Since these utilities own generation assets, they use their IRPs to evaluate a
broad range of options for meeting electricity demand over a 20- or 30-year time frame.
The IRP considers new supply-side options (including renewable resources) and
demand-side options, and purchased power (including transmission considerations). A
broad range of plans are considered, reflecting a range of objectives and capturing key
uncertainties. Plans are evaluated against established criteria (e.g., costs, rate impacts,
emissions, diversity, etc.) and are ranked. 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:
125 Regulatory Assistance Project, Addressing the Effects of Environmental Regulations: Market Factors, Integrated
Analyses, and Administrative Processes (RAP, 2013). Available at:
www.raponline.org/document/download/id/6455.
126 Minnesota PUC, Report To The Legislature On Emissions Reduction Projects Under Minnesota Statutes
216B.1692 (Minnesota Public Utilities Commission, March 2008). Available at:
http://mn.gov/puc/documents/pdf files/000661.pdf.
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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 are slightly different for vertically
integrated utilities and restructured utilities. Vertically integrated utilities are
required to submit electric supply resource plans every two years with the aim of
providing a balanced, environmentally responsible electricity portfolio.
Meanwhile, restructured utilities must file updates to their portfolio action plans
every three years.127 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.128
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, and 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.129
• Multi-Pollutant Utility Planning -Two states, Minnesota and Colorado, have worked
collaboratively with their investor-owned utilities to develop multi-pollutant emissions
reduction plans on a utility-wide basis. This multi-pollutant, collaborative approach
127 Rachel Wilson and Bruce Biewald, Best Practices in Electric Utility Integrated Resource Planning (RAP, 2013).
Available at: http://www.raponline.org/document/download/id/6608.
128 U.S. EPA, Clean Energy-Environment Guide to Action (U.S. Environmental Protection Agency, 2015), accessed
March 10, 2016. Available at: http://epa.gov/statelocalclimate/resources/action-guide.html.
129 Ibid.
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enables utilities to determine the least cost way to meet long-term and comprehensive
energy and environmental goals.
o The Colorado CAGA requires investor-owned utilities (lOUs) 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 2010.130
o The Minnesota Emissions-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.131 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 often obligated under integrated resource planning, while in
restructured markets, the default utility service provider may be obligated to conduct portfolio
management.
For multi-pollutant planning, Colorado lOUs, 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
compliant with the CACJA. Plans needed to meet the National Ambient Air Quality Standards
for a number of air pollutants.
130 Regulatory Assistance Project, Addressing the Effects of Environmental Regulations: Market Factors, Integrated
Analyses, and Administrative Processes (RAP, 2013). Available at:
www.raponline.org/document/download/id/6455.
131 Minnesota Office of Revisor of Statutes, 2013 Minnesota Statutes, §216B,1692 Emissions-Reduction Rider,
2013, accessed March 10, 2016. Available at: https://www.revisor.mn.gov/statutes/?id=216B. 1692.
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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
often 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
As of 2015, more than two-thirds of the states have integrated resource or other long-term planning
requirements,132 while Minnesota and Colorado have multi-pollutant planning policies or requirements
(see Figure 9).
132 Wilson, Rachel and Bruce Biewald, Best Practices in Electric Utility Integrated Resource Planning (RAP, June
2013). Available at: http://www.raponline.org/document/download/id/6608.
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Figure 9: States with Integrated Resource Planning or Similar Processes
Utility Planning Requirements
Integrated Resource / Multi-
pollutant Planning -
Other Long-term Utility Planning - 3
Last updated 5/20/2016
Primary source: Clean Energy-Environment Guide to Action (U.S. Environmental Protection Agency, 2015), accessed
May 20, 2016. Available at: http://epa.gov/statelocalclimate/resources/action-guide.html.133
In Missouri, for example, Ameren's 2014 Integrated Resource Plan Update calls for:
• Spending $148 million from 2016-2018 to achieve 426 GWh of energy savings and 114
MW of peak demand savings.
• Installing 400 MW of wind power, 45 MW of solar power, 20 MW of hydroelectric
power, and 5 MW of landfill gas capacity by 2034.
• Installing 600 MW of combined-cycle natural gas capacity by 2034.
• Retiring one-third of coal-fired generating capacity by 2034.
• Planning for a 12 percent increase in energy consumption, 8 percent increase in peak
demand, and 0.59 percent annual retail sales increase by 2034.
• Incorporating a carbon price of between $23 and $53/ton beginning in 2025.
133 Additional sources for other long-term planning requirements include: California Office of Ratepayer Advocates,
Long Term Procurement Planning: 2014 - 2024, accessed May 20, 2016. Available at:
http://www.ora.ca.gov/ltpp.aspx. Florida Public Service Commission, Ten-Year Site Plans, accessed May 20, 2016.
Available at: http://www.psc.state.fl.us/ElectricNaturalGas/TenYearSitePlans. LAWriter Ohio Laws and Rules,
4901:5-5-06 Resource plans, accessed May 20, 2016. Available at: http://codes.ohio.gov/oac/4901%3A5-5-06.
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• Planning for a natural gas price increase of between $4-6/MMBtu by 2034.134
In Virginia and North Carolina, Dominion Resources filed an updated integrated resource plan in
April 2016. Key highlights from the report include:
• Five detailed "Study Plans" (including solar, co-fire, nuclear, and wind). The company's
integrated resource plans prior to 2015 included either a preferred plan or a
recommended path forward. The 2016 integrated resource plan does not have a
preferred plan or a recommended path forward, as Dominion did not have enough time
to analyze a future in which either the Clean Power Plan implementation is delayed or a
different form of carbon dioxide regulation is promulgated. Instead, Dominion intends
to study these five plans that represent plausible future paths for meeting electricity
needs while responding to changing regulatory requirements.
• All of the studied plans include:
o 400 MW of utility-scale solar phased in from 2016-2020.
o 600 MW of solar generation from non-utility generators by 2017.
o 7 MW of solar from its "Solar Partnership Program."
o 12 MW from the Virginia Offshore Wind Technology Advancement Project
(VOWTAP) as early as 2018.
o Demand-side resources of 304 MW by 2031.
o 20-year extensions of four nuclear reactors by 2038.
o 1,585 MW of additional natural gas combined cycle capacity by 2019.
• To show how the various plans can diverge from the previous year's plan, if Dominion
were to adopt the most solar-focused plan, this plan projects 7,000 MW of additional
solar resources by 2029, an increase of 3,500 MW over the solar-focused 2015 plan.135
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 86 percent and CO2 levels 28 percent relative to 2008 levels by 2018.136 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, and use competitive
134 Ameren Missouri, 2014 Integrated Resource Plan (Ameren Missouri, 2014). Available at:
https://www.ameren.com/missouri/environment/renewables/ameren-missouri-irp.
135 Dominion, Dominion Virginia Power's and Dominion North Carolina Power's Report of its Integrated Resource
Plan (Dominion, April 2016). Available at: https://www.dom.com/corporate/what-we-
do/electricitv/generation/2016-integrated-resource-planning.
136 Xcel Energy, Xcel Energy-Emissions Reduction Plan, (Xcel Energy, 2011). Available at:
https://www.xcelenergv.com/staticfiles/xe/Corporate/Environment/10-12-303 CACJ-6E FS.pdf.
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bidding to meet the remaining 60 MW.137 Work is well underway to implement Xcel Energy's
emissions reduction plan under Colorado's Clean Air-Clean Jobs Act. Three coal units have been
retired and new emissions controls finished in August 2014 have kept emissions rates below
new permit levels.138
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 Emissions Reduction Proposal (MERP). MERP, authorized in 2002, has
shown an annual 93 percent reduction in SO2, 91 percent reduction in NOx, 81 percent
reduction in mercury, 55 percent reduction in particulates, and 21 percent reduction in CO2
from 2002 levels during the 2007 to 2009 time period.139
137 Black Hills Energy, "Black Hills Energy Files Plan for Ongoing Reliable, Cost-effective Energy for Years to Come in
Colorado." Available at: http://www.blackhillsenergv.eom/node/34671#.UzHkulXYhlt.
138 Xcel Energy, Colorado Clean Air-Clean Jobs Plan. Available at:
http://www.xcelenergy.com/Environment/Programs/Colorado Clean Air-Clean Jobs Plan.
139 Xcel Energy, "Minnesota Metro Emissions Reduction Project - Environmental Benefits." Available at:
http://www.xcelenergy.com/Environment/Programs/Minnesota Metro Emissions Reduction Project.
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EPA 430-S-16-001
JUNE 2016
WWW.EPA.GOV/STATEL0CALCLIIVIATE
£EPA
State and Local
Climate and Energy Program
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