Thu May 08 09:12:25 EDT 2014

Moritz.Brigette@epamail.epa.gov

FW: new report: Clean Air Act - Section 111(d) and electric reliability

To: CMS.OEX@epamail.epa.gov

_____________________________________________________________________________________________________

From: Tierney, Susan [mailto:STierney@analysisgroup.com]

Sent: Wednesday, May 07, 2014 6:41 PM

To: Mccarthy, Gina; McCabe, Janet; Goffman, Joseph; Tsirigotis, Peter; Beauvais, Joel; Kurlansky, Ellen; Culligan, Kevin

Subject: new report: Clean Air Act - Section 111(d) and electric reliability

Dear Madame Administrator, Madame Air Administrator, Senior Advisor, and other key EPA advisors on CAA Section 111(d):

I wanted to send you a copy of the paper that Ive just written on the electric system reliability issues associated with EPAs guidance

under the CAA 111(d). The bottom line of my report is that the inherent flexibility of the Clean Air Acts Section 111(d) will provide useful

ways for EPA and the states to assure reliability while the system transitions to a lower GHG footprint.

Please let me know if any of you would like to discuss any of this. Hope all of you are doing very well.

Best 

Sue

Sue Tierney | Senior Advisor

Analysis Group, Inc. | Economic, Financial, and Strategy Consulting

111 Huntington Avenue, Tenth Floor, Boston, MA 02199

617-425-8114 (direct) | 617-425-8000 (main) | 617-901-6921 (mobile)

www.analysisgroup.com

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i

Greenhouse Gas Emission Reductions 

From Existing Power Plants Under 

Section 111(d) of the Clean Air Act: 

Options to Ensure Electric System Reliability

Susan F. Tierney, Ph.D.

Analysis Group, Inc. 

May 8, 2014
Analysis Group, Inc. Page | 2

Table of Contents

Introduction and Executive Summary...........................................................................................................1

Regulating GHG Emissions from Existing Power Plants under Section 111(d) of the Clean Air Act.............7

How does Section 111(d) of the CAA work?..............................................................................................9

The likely character of EPA’s guidance under CAA Section 111(d)..........................................................13

Section 111(d) Differs from Other Recent EPA Regulations Affecting Power Plants ..............................16

The MATS Rule....................................................................................................................................16

How Section 111(d)’s Framework Differs from the MATS Rule..........................................................18

Power plants that are subject to CAA Section 111(d).............................................................................20

Context for Industry Compliance with CAA Section 111(d) Requirements................................................23

Natural gas, coal and existing power plants...........................................................................................23

Outlook for electricity demand ...............................................................................................................28

Availability of zero-carbon supply from nuclear generators...................................................................34

Responses to EPA MATS regulations.......................................................................................................38

New Generating Capacity Proposals.......................................................................................................43

Implications of the Changing Electricity Resource Mix ...........................................................................44

Planning for Compliance with EPA Guidance Under Section 111(d) of the CAA........................................46

Breadth of Options Available to the States in Developing Section111(d) SIPs .......................................46

Inside the Fence Options ....................................................................................................................47

Outside the Fence Options .................................................................................................................49

Outside-the-Fence Models Approaches: Examples to ensure reliable and economic compliance in 

states with different electric industry structures...............................................................................56

Outside-the-Fence Models Approaches: Collateral policies...............................................................65

Conclusions.................................................................................................................................................66
Electric System Reliability and GHG Emission Reductions Under CAA Section 111(d) – May 2014

Analysis Group, Inc. Page | 1

Electric system reliability:

“The degree to which the performance of the 

elements of the electrical system results in power 

being delivered to consumers within accepted 

standards and in the amount desired. Reliability 

encompasses two concepts, adequacy and security. 

Adequacy implies that there are sufficient 

generation and transmission resources installed 

and available to meet projected electrical demand 

plus reserves for contingencies. Security implies 

that the system will remain intact operationally 

(i.e., will have sufficient available operating 

capacity) even after outages or other equipment 

failure. The degree of reliability may be measured 

by the frequency, duration, and magnitude of 

adverse effects on consumer service.”

Energy Information Administration.

Introduction and Executive Summary

In June 2014, the U.S. Environmental Protection Agency (“EPA”) is expected to propose 

guidance to the states for reducing greenhouse gas (“GHG”) emissions from existing fossil-fuel 

power plants. Final guidance is expected a year later, with requirements that each state develop 

and submit a state implementation plan (“SIP”) for how the state would prefer to achieve such 

emissions reductions at the power plants in its state. While the Clean Air Act’s Section 111 

identifies many criteria for setting the emissions standard and for states’ development of SIPs to 

achieve it, an important additional objective not 

mentioned in the Act but still important for the 

nation is assuring that such plans will not 

jeopardize electric system reliability.

This paper addresses whether EPA’s actions to 

regulate GHG emissions from existing power 

plants will give rise to electric system reliability 

problems,1 and explains why it will not. 

Industry participants have often raised concerns 

about potential electric system reliability impacts 

from major new EPA regulations affecting power 

plants. This was a major issue in 2010 to 2012, for 

example, in many parties’ comments on EPA’s 

proposals to control mercury and air toxic emissions (the “MATS” rule). Reliability concerns 

have already been raised in relation to EPA’s upcoming regulation of GHG emissions from 

existing power plants.2 

 1 The North American Electric Reliability Corporation (“NERC”) further explains the adequacy component of reliability: “The 

ability of the electric system to supply the aggregate electrical demand and energy requirements of the end-use customers at all 

times, taking into account scheduled and reasonably expected unscheduled outages of system elements.” In this paper, I focus on 

reliability in the bulk-power system, which NERC defines as: “(A) facilities and control systems necessary for operating an 

interconnected electric energy transmission network (or any portion thereof); and (B) electric energy from generation facilities 

needed to maintain transmission system reliability. The term does not include facilities used in the local distribution of electric 

energy....The bulk power electric system is routinely planned and operated so as to perform reliably under normal and abnormal 

conditions.” http://www.nerc.com/files/glossary_of_terms.pdf. 

2 See, for example, hearings held on November 14, 2013, before the House Energy and Commerce Subcommittee on Energy and 

Power, and comments made by panelists at the February 12, 2014 meeting of the National Association of Regulatory Utility 

Commissioners (“NARUC”).
Electric System Reliability and GHG Emission Reductions Under CAA Section 111(d) – May 2014

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Historically, the reliability red flag3 has tended to be raised with regard to concerns that 

compliance with a new environmental rule would require a large portion of generating capacity 

to be simultaneously out of service to add control equipment, to retire permanently, or 

otherwise to become unavailable to produce power.4 To date, implementation of new 

environmental rules has not produced reliability problems, in large part because the industry 

has proven itself capable of responding effectively. A very mission-oriented industry, 

composed of electric utilities, other grid operators, non-utility energy companies, federal and 

state regulators, and others, has taken a wide variety of steps to ensure reliability.5 

Regarding the upcoming EPA regulations of GHG emissions from existing power plants, 

reliability concerns are misplaced. It is broadly understood – including by President Obama6

 3 In recent years, many Congressional hearings have addressed the implications of EPA regulations for electric system reliability. 

For example: hearings before the House Energy and Commerce Subcommittee on Energy and Power (December 5, 2013; May 9, 

2012; and September 14, 2011); the November 1, 2011 hearing before the House Oversight and Government Reform Committee; and 

the June 30, 211 hearing before the Senate Environment and Public Works Subcommittee on Clean Air and Nuclear Safety. In 

2010/2011, NERC published major assessments of electric system reliability and EPA regulations. . 

4 This, for example, was how the issue came up in discussions of EPA’s acid rain regulations in the early 1990s and in proposals for 

how Northeast states would reduce sulfur dioxide (“SO2”), and nitrogen oxides (“NOx”) emissions from existing power plants. In 

such cases, key questions were whether the electric industry (and its supply chains) could respond in a timely way to regulatory 

requirements while also ensuring that the lights stay on at all times in every part of the affected regions of the U.S. This was the 

framing of reliability concerns in recent years when EPA agency proposed the combination of regulations affecting cross-state 

transport of NOx (e.g., the “Cross-State Air Pollution Rule” (“CSAPR”) and toxic air pollution (e.g., the MATS rule)). 

5 For example, the Federal Energy Regulatory Commission (“FERC”) has authority under the Energy Policy Act of 2005 to 

ensure reliability in the bulk power systems, and has delegated to the NERC (as the National Reliability Organization) the 

responsibility for setting reliability standards. For decades, states have supervised – and continue to do so – utilities and 

others’ planning for long-term resource adequacy. I previously described these processes, norms, requirements, and 

other elements of the mission-oriented culture of the industry: “The U.S. electric industry has a proven track record of 

doing what it takes to provide the reliable power supplies. Regulated electric utilities, competitive electric companies, 

grid operators, and regulators have a strong mission orientation, along with regulatory requirements, which together 

ensure that reliable electricity supply is a priority. For many decides, the U.S. electric industry has developed institutions,

operating and planning requirements, system plans, operating approaches, emergency response protocols, and billions of 

dollars of investment to assure reliable electricity supply. The industry is keenly aware that the American economy and 

standard of living depend upon reliable power supplies.... With some notable exceptions, utilities and other electric 

companies and their workers, investors, and suppliers, have provided what Americans take for granted and what public 

officials insist upon: that electricity be reliably available around the clock, with increasing levels of environmental 

performance to assure worker and community safety and public health. ....The electric industry has responded well in 

prior periods (such as the mid-1990s) when Clean Air Act requirements led to investments in new pollution-control 

equipment and new additions to generating capacity. There were no reliability problems arising from those actions, in 

spite of concerns raised that there would be equipment shortages and difficulties adding control equipment on so many 

power plants in a constrained period of time.” Testimony of Susan Tierney, Before the U.S. Senate Environment and 

Public Works Committee. Subcommittee on Clean Air and Nuclear Safety, June 30, 2011 (Oversight Hearing: Review of 

EPA Regulations Replacing the Clean Air Interstate Rule (CAIR) and the Clean Air Mercury Rule (CAMR)).

6 The June 35, 2013 “Presidential Memorandum -- Power Sector Carbon Pollution Standards” states that “In developing standards, 

regulations, or guidelines ... {EPA] shall ensure, to the greatest extent possible, that you: ...(v) ensure that the standards are 

developed and implemented in a manner consistent with the continued provision of reliable and affordable electric power for 

consumers and businesses...” 
Electric System Reliability and GHG Emission Reductions Under CAA Section 111(d) – May 2014

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and the EPA’s Administrator7 – that regulatory actions to reduce threats to public health and 

the environment from power generation cannot occur at the expense of reliable power supply.

Moreover, EPA will be relying on a portion of the Clean Air Act (“CAA”) – Section 111(d) – to 

regulate GHG emissions from existing power plants. Section 111(d)’s regulatory framework 

creates an entirely different and potentially much wider set of compliance and implementation 

options compared to other recent federal regulatory initiatives applicable to the electric 

industry. Section 111(d)’s ‘cooperative federalism’ model provides for much more compliance 

flexibility and creativity than was possible for the many unit-specific regulations issued by EPA 

in the past two decades. This is core to understanding why EPA’s regulation of GHG emissions 

from existing power plants will not jeopardize electric system reliability. 

In the recent MATS rule, for example, EPA set uniform national standards to reduce emissions 

from different categories of existing coal- and oil-fired power plants. No trading or averaging is 

allowed across different generating stations. There is no possibility of purchasing credits 

resulting from over-compliance at other sources, or to credit emissions reductions resulting 

from end-use efficiency or zero-carbon energy sources.

By contrast with MATS, Section 111(d) inherently allows greater opportunities for different 

pathways to compliance. Section 111(d) relies on the SIP process. This means that EPA will 

provide states with guidance allowing considerable and wide-ranging latitude in how they plan 

to meet EPA’s requirements. EPA’s guidance will not likely impose a standard that must be 

met solely by actions taken at each affected unit. Rather, EPA is likely to establish standards 

specific to each state, based on the “degree of emission limitation achievable through the 

application of the best system of emission reduction,” which may vary across states in light of 

their own particular circumstances. And in its SIP, each state will have flexibility to propose its 

own preferred actions to accomplish the targeted reductions, as long as the plan provides 

reductions across the facilities in the state that are at least as effective as EPA’s approach.8 This 

language “supports the use of market-based mechanisms” and other alternatives in ways that 

 7 See, for example: Statement of Gina McCarthy, Nominee for the Position of Administrator of the EPA, Before the Environment 

and Public Works Committee, U.S. Senate, April 11, 2013; Testimony of Gina McCarthy before the FERC, Reliability Technical 

Conference, Docket Number AD12-1-000, November 30, 2011. 

8 Section 111(d) directs EPA to “prescribe regulations which shall establish a procedure similar to that provided by section 110 

under which each State shall submit to the Administrator a plan....” As explained in Section 110 (a)(2)(A) of the Act, a SIP shall 

(among other things), “(A) include enforceable emission limitations and other control measures, means, or techniques (including 

economic incentives such as fees, marketable permits, and auctions of emissions rights), as well as schedules and timetables for 

compliance, as may be necessary or appropriate to meet the applicable requirements of this chapter.”
Electric System Reliability and GHG Emission Reductions Under CAA Section 111(d) – May 2014

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are not possible under the statutory language governing MATs, which required each affected 

generating station to have emissions at or below the allowed emissions rates. 

If a state has concerns about the reliability implications of compliance with EPA guidance, the 

state can take that fact into account as it designs its SIP and its schedule/timetable for individual 

units’ compliance so long as the overall emission reduction required by the guideline has a firm 

deadline and is achieved. For example, a state could propose plan elements that enable early 

action/compliance at some Section 111(d) generating units in exchange for allowing more time 

for others, or that allow for deeper reductions at one unit in exchange for lighter reductions at 

another. Thus, the inherent authority within Section 111(d) removes the reliability red flag in 

this case, as long as the EPA, the states, and the industry take appropriate and timely steps. 

States may consider diverse options as they plan for cost-effective emissions reductions while 

also ensuring electric system reliability. Some of the options may take place “inside the fence” 

of generating units covered by Section 111(d), while others might focus more on interactions of 

those plants’ emissions in light of changes in power demand, transmission and generation:

 Inside the fence: Examples include: heat-rate improvements; fuel switching; averaging of 

emissions within a single station; and changes to the operating permit of existing power 

plants to limit emissions over some averaging period.

 Outside the fence: Examples include: emission reductions achieved through changes in 

the overall dispatch of existing generating resources and/or level of demand on the 

system: emission-averaging among multiple power plants; state carbon budgets with an 

emissions cap-and-trade program; multi-state electric-system dispatch practices of grid 

operators; demand-side reductions; adoption of clean energy standards; and/or 

transmission upgrades to open up access to underutilized, low-carbon facilities.

Other factors also allow for cost-effective emissions reductions at Section 111(d) units in ways 

that do not adversely affect system reliability. A significant amount of existing generating 

capacity is underutilized. For example, output at natural-gas fired combined-cycle power 

plants averaged approximately 50 percent in 2012. There is the potential to reduce overall 

demand through energy efficiency, thus reducing the need to dispatch plants with relatively 

high emission rates. There is potential to add additional low or zero-carbon electricity supply 

(e.g., wind and solar; combined heat and power; nuclear uprates). Actions also can be taken to 

extend the life of, or increase the output from, well-performing generating units that produce no 

emissions at the facility (e.g., hydroelectric resources, nuclear plants). These various resources 
Electric System Reliability and GHG Emission Reductions Under CAA Section 111(d) – May 2014

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offer significant flexibility and optionality to states as they prepare a SIP suited to their own 

circumstances and conditions (including reliability concerns).

As they develop SIPs in response to the EPA’s Section 111(d) guidance, the states start from a 

position of great diversity in their electric power industries. These differences show up in the 

character of the power plants located in each state, the electric industry structure, the CO2

emissions from existing power plants, renewable energy potential, reliance on in-state versus 

out-of-state power resources, the outlook for demand growth, mix of public policies affecting 

power plants, and many other differences. This will likely lead to varied approaches in SIP 

designs. (See the Appendix 2 for the generating units in each state that are directly affected by 

Section 111(d) requirements, along with information about other generating resources and their 

capacity factors in 2012.)

To envision how differently situated states might shape their compliance strategies to assure 

both electric system reliability and compliance with upcoming EPA guidance, this paper 

concludes with a handful of examples representing ways that states could consider shaping 

their SIPs to suit their own conditions. The examples address options for states with 

traditionally regulated electric industries, and for states whose electric companies participate in 

an organized interstate wholesale electric market managed by a regional transmission 

organization (“RTO”). The GHG control options include: inter-facility emissions trading for 

plants owned by a common owner in a single state or in multiple states with traditional electric 

industry structure; inter-state trading among plants owned by multiple owners in traditionally 

regulated states; reliance on a state-wide emissions budget combined with other mechanisms to 

allow emissions averaging across plants located within a single-state or multi-state RTO; and 

use of collateral programs to support cost-effective emissions reductions (such as clean energy 

standards, renewable portfolio standards, energy efficiency programs, transmission 

enhancements, and others). All of these provide extensive opportunities for innovative SIP 

elements that can accommodate cost-effective environmental compliance, alignment with 

economic principles underpinning electric industry structure and market design, while 

maintenance of electric system reliability.

The bottom line: there is no reasonable basis to anticipate that EPA’s guidance, the states’ SIPs 

and the electric industry’s compliance with them will create reliability problems for the power 

system, as long as EPA and the states plan appropriately and take timely actions to assure 

electric-system reliability in their plans. Section 111(d) affords states considerable latitude to 

mitigate and otherwise resolve reliability concerns. 
Electric System Reliability and GHG Emission Reductions Under CAA Section 111(d) – May 2014

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To explain how I reached this conclusion, this paper covers the following topics: 

 the federal/state regulatory framework under Section 111(d) of the CAA; 

 how Section 111(d)’s reliance on the preparation of SIPs makes this regulatory 

framework inherently different from other recent environmental regulations affecting 

existing power plants, and provides more compliance options and greater flexibility; 

 the types of power plants directly affected by the GHG reduction policies, with 

differences among fleets in various regions of the country; 

 conditions in the electric industry (such as the outlook for demand, fuel prices, plant 

additions and retirements) that set the stage for the 

industry’s future compliance with GHG regulations for 

existing plants; 

 the breadth of tools that may be available to the states 

as they consider what to include in their SIPs;

 the factors that states may take into account to assure 

electric system reliability as part of their compliance 

strategies; 

 examples of ways to design compliance strategies in 

different industry contexts; and 

 the overall implications of Section 111(d) compliance for maintaining electric system 

reliability.
Electric System Reliability and GHG Emission Reductions Under CAA Section 111(d) – May 2014

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Regulating GHG Emissions from Existing Power Plants under Section 111(d) of 

the Clean Air Act 

Under the CAA, the control of GHG emissions from existing power plants fits within a larger 

framework in which EPA regulates air pollution from mobile and stationary sources. Section 

111(d) sets forth the process through which EPA will regulate GHG emissions from existing 

power plants, which account for 40 percent of total CO2 emissions in the U.S.,9 and one out of 

every 15 tons of CO2 emitted anywhere in the world.10

Much has been written about the overall framework under which GHG emissions may be 

regulated under the CAA.11 These analyses depict the process now underway: 

 9 Based on 2011 data, the most recent available in the EPA’s “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2011,” 

April 12 2013, Table 2-3 (Recent Trends in U.S. Greenhouse Gas Emissions and Sinks) and Table 2-4 (Emissions from Energy). 

10 The U.S. emitted 5,433,056 kt of CO2, out of the total 33,615,389 kt of CO2 emitted globally in 2010. The U.S.’s CO2 emissions were 

16 percent of the global amount. http://data.worldbank.org/topic/climate-change. Assuming electric power accounts for 40 percent 

of U.S. CO2 emissions (from the EPA GHG Inventory data), then electric power production in the U.S. accounted for 6.5 percent of 

global CO2 emissions in 2010. 

11 For example, see: Dan Lashof, et. al., “Cleaner and Cheaper: Using the Clean Air Act to Sharply Reduce Carbon Pollution from 

Existing Power Plants, Delivering Health, Environmental, and Economic Benefits,” NRDC, March 2014; Clean Air Task Force, 

“Power Switch: An Effective, Affordable Approach to Reducing Carbon Pollution from Existing Fossil-Fueled Power Plants,” 

February 2014, with accompanying analysis (Bruce Phillips, The Northbridge Group,“ Alternative Approaches for Regulating 

Greenhouse Gas Emissions from Existing Power Plants under the Clean Air Act: Practical Pathways to Meaningful Reductions,” 

February 27, 2014); Comments of the Attorneys General of New York, California, Massachusetts, Connecticut, Delaware, Maine, 

Maryland, New Mexico, Oregon, Rhode Island, Vermont, Washington, and the District of Columbia on the Design of a Program to 

Reduce Carbon Pollution from Existing Power Plants, December 16, 2013; White Paper to EPA from 18 State Attorneys General, 

“Perspective of 18 States on Greenhouse Gas Emission Performance Standards for Existing Sources under § 111(d) of the Clean Air 

Act,” November 2013; Megan Ceronsky and Tomas Carbonell, “Section 111(d) of the Clean Air Act: The Legal Foundation for 

Strong, Flexible & Cost-Effective Carbon Pollution Standards for Existing Power Plants,” Environmental Defense Fund, October 

2013; Christopher Van Atten, “Structuring Power Plant Emissions Standards Under Section 111(d) of the Clean Air Act – Standards 

for Existing Plants,” MJ Bradley & Associates, October 2013; James McCarthy, “EPA Standards for Greenhouse Gas Emissions from 

Power Plants: Many Questions, Some Answers,” Congressional Research Service, September 30, 2013; National Climate Coalition, 

“Using EPA Clear Air Act Authority to Build a Federal Framework for State Greenhouse Gas Reduction Programs,” September 

2013; Scott Schang, ed., Old Laws, New Tricks: Using the Clean Air Act to Curb Climate Change (Environmental Law Institute, August 

19, 2013); Kyle Danish, Stephen Fotis, Doug Smith, Ilan Gutherz, “EPA Regulation of Greenhouse Gas Emissions from Existing 

Power Plants: Issues and Options,” Van Ness Feldman, June 27, 2013; Daniel A. Lashof, et. al., “Closing the Power Plant Carbon 

Pollution Loophole: Smart Ways the Clean Air Act Can Clean Up America’s Biggest Climate Polluters,” March 2013; Nicholas 

Bianco and Franz Litz, “Reducing Greenhouse Gas Emissions in the United States: Using Existing Federal Authorities and State 

Action,” World Resources Institute, February 2013; Jeremy Tarr, Jonas Monast and Tim Profeta, “Regulating Carbon Dioxide under 

Section 111(d) of the Clean Air Act: Options, Limits, and Impacts,” Nicholas Institute, Duke University, January 2013; Georgetown 

Climate Center, “Issue Brief for the States: EPA’s Forthcoming Performance Standards for Regulating Greenhouse Gas Pollution 

from Power Plants (Clean Air Action Section 111),” September 2011; Gregory E. Wannier, Jason A. Schwartz, Nathan Richardson, 

Michael A. Livermore, Michael B. Gerrard, and Dallas Burtraw, “Prevailing Academic View on Compliance Flexibility under § 111 

of the Clean Air Act,” Resources for the Future, July 2011; Pew Center on Global Climate Change, “GHG New Source Performance 

Standards for the Power Sector: Options for EPA and the States,” March 17, 2011. 
Electric System Reliability and GHG Emission Reductions Under CAA Section 111(d) – May 2014

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 The U.S. Supreme Court’s 2007 holding that “greenhouse gases fit well within the [Clean 

Air] Act’s capacious definition of ‘air pollutant’.”12

 The EPA Administrator’s finding in 2009 that current and projected concentrations of 

GHGs “in the atmosphere threaten the public health and welfare of current and future 

generations.”13 

 The President’s 2009 pledge at the United Nations Climate Change Conference that by 

2020, America would reduce its GHG “emissions in the range of 17 per cent by 2020” 

compared with 2005 levels.14 

 The President’s 2013 Climate Action Plan and Presidential Memorandum directing the 

EPA to take steps under Section 111(d) authority to reduce carbon pollution from 

existing power plants,15 and to do so through engaging directly with the states (“as 

they will play a central role in establishing and implementing standards for 

existing power plants”) and other stakeholders.

16 

 12 549 U.S. 497 (2007). 

13 74 Fed. Reg. 66496 (December 15, 2009) (Environmental Protection Agency, Endangerment and Cause or Contribute Findings for 

Greenhouse Gases Under Section 202(a) of the Clean Air Act).

14 White House Press Release, Remarks by the President in the Morning Plenary Session of the United Nations Climate Change 

Conference, Copenhagen, December 18, 2009. 

15 The President’s Climate Action Plan, June 2013; White House, Presidential Memorandum -- Power Sector Carbon Pollution 

Standards, June 25, 2013. 

16 “Carbon Pollution Regulation for Modified, Reconstructed, and Existing Power Plants. To ensure continued progress in reducing 

harmful carbon pollution, I direct you to use your authority under sections 111(b) and 111(d) of the Clean Air Act to issue 

standards, regulations, or guidelines, as appropriate, that address carbon pollution from modified, reconstructed, and existing 

power plants and build on State efforts to move toward a cleaner power sector.” White House, Presidential Memorandum -- Power 

Sector Carbon Pollution Standards, June 25, 2013. The Memorandum also directs that EPA “(ii) consistent with achieving 

regulatory objectives and taking into account other relevant environmental regulations and policies that affect the power sector, 

tailor regulations and guidelines to reduce costs; (iii) develop approaches that allow the use of market-based instruments, 

performance standards, and other regulatory flexibilities; (iv) ensure that the standards enable continued reliance on a range of 

energy sources and technologies; (v) ensure that the standards are developed and implemented in a manner consistent with the 

continued provision of reliable and affordable electric power for consumers and businesses; and (vi) work with the Department of 

Energy and other Federal and State agencies to promote the reliable and affordable provision of electric power through the 

continued development and deployment of cleaner technologies and by increasing energy efficiency, including through stronger 

appliance efficiency standards and other measures.”
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Clean Air Act:

Section 111(d) Standards of performance for existing sources; 

remaining useful life of source [excerpts]

(1) The Administrator shall prescribe regulations which shall 

establish a procedure similar to that provided by section 110 

under which each State shall submit to the Administrator a 

plan which (A) establishes standards of performance for any 

existing source for any air pollutant (i) for which air quality 

criteria have not been issued ..., and (B) provides for the 

implementation and enforcement of such standards of 

performance. Regulations of the Administrator under this 

paragraph shall permit the State in applying a standard of 

performance to any particular source under a plan submitted 

under this paragraph to take into consideration, among other 

factors, the remaining useful life of the existing source to 

which such standard applies. 

Section 111(a) Definitions [excerpts] For the purposes of this 

section:

(1) The term “standard of performance” means a standard for 

emissions of air pollutants which reflects the degree of 

emission limitation achievable through the application of the 

best system of emission reduction which (taking into account 

the cost of achieving such reduction and any non air quality 

health and environmental impact and energy requirements) 

the Administrator determines has been adequately 

demonstrated..... 

(See Appendix 1 for additional statutory language from Section 111 

of the CAA)

How does Section 111(d) of the CAA work?

Regulation of one third of the nation’s GHG emissions (i.e., from existing fossil power plants) 

will take place through a portion of the CAA that is used infrequently. Section 111(d) only 

applies to pollutants (like GHGs) not regulated elsewhere in the law. Most air pollutants 

emitted from power production –

including emissions of sulfur 

dioxide (“SO2”), nitrogen oxides 

(“NOx”), and air toxics like 

mercury – are specifically covered 

by other parts of the CAA. The 

electric industry, the states and 

many other stakeholders have 

become familiar with regulatory 

approaches related to those other 

pollutants over several decades. 

Section 111(d) has only been used 

to control emissions for five 

categories of existing sources of 

emissions17 and never for a 

pollutant that is so pervasive (as 

CO2) in the U.S. and globally. Thus 

it is thus relatively ‘new’ to the 

EPA, as well as to the regulated 

industry and the states. 

That said, the upcoming regulatory 

process is not entirely unfamiliar to the states. Section 111(d) calls for EPA to use “a procedure 

similar to that provided by section 110.” Section 110 is a well-established “cooperative 

federalism” framework that has been relied upon for decades to ensure that EPA’s National 

 17 Section 111(d) has been used previously for regulating: landfill gases from municipal solid waste landfills; acid mist from sulfuric 

acid plants; flourides from phosphate fertilizer plants; flourides from primary aluminum plants; and total reduced sulfur from kraft 

pulp plants. Source: “Overview presentation of Clean Air Act Section 111,” http://www2.epa.gov/carbon-pollutionstandards/what-epa-doing. 
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Ambient Air Quality Standards (“NAAQS”) are met and maintained for six common air 

pollutants (known as ‘criteria pollutants’). Under Section 110, “EPA uses its expertise to 

determine what the NAAQS should be, and the states are delegated the authority to determine 

how the NAAQS will be achieved.”18 In essence, the ‘cooperative federalism’ framework of 

Section 111(d) can be thought of one in which EPA identifies the destination (e.g., ambient air 

quality), and states determine what route they want to take to get there.19 In the past, the states 

(typically through their state air regulatory agency) have developed SIPs to demonstrate how 

they will address ground-level ozone (smog), particulate emissions, SO2, NOx, and other criteria 

pollutants to meet the national air standards.20 Thus, state air regulators have considerable 

experience with such SIP processes.21 

In various presentations, statements and other documents, EPA has provided strong indications 

of how it intends to move forward under the Section 111(d) framework. The process is expected 

to involve the following steps and elements:22 

- EPA Guidance: EPA issues guidance to the states with respect to the “best system of 

emissions reductions” (“BSER”) from existing power plants. This guidance will likely 

establish the target CO2 tonnage reductions, or reductions in CO2 emission rates per 

megawatt-hour (“MWh”), that each individual state must achieve at affected generating 

units through its SIP.

 18 Jonas Monast, Tim Profesta, Brooks Rainey Pearson, and John Doyle, “Regulating Greenhouse Gas Emissions from Existing 

Sources: Section 111(d) and State Equivalency,” 42 ELR 10206, March 2012 (hereinafter “Monast et. al. (2012)”). 

19 Susan Tierney, “Section 111(d) of the Clean Air Act: Drivers of Power Sector CO2 Reductions,” presentation to the Bipartisan 

Policy Center Workshop on GHG Regulation of Existing Power Plants under the Clean Air Act: Policy Design and Impacts, 

December 6, 2013. 

20 The States “develop a general plan to attain and maintain the NAAQS in all areas of the country and a specific plan to attain the 

standards for each area designated nonattainment for a NAAQS. These plans, known as State Implementation Plans or SIPs, are 

developed by state and local air quality management agencies and submitted to EPA for approval.” 

http://www.epa.gov/oar/urbanair/sipstatus/index.html

21 See, for example, EPA’s website that tracks the status of each state’s SIP for each criteria pollutant. As is apparent there, SIPs 

include elements that are added or changed over time. http://www.epa.gov/oar/urbanair/sipstatus/reports/map_s.html. 

22 This description is drawn from various documents, including from the EPA’s website and its “Overview presentation of Clean Air 

Act Section 111”( http://www2.epa.gov/carbon-pollution-standards/what-epa-doing); EPA Office of Air and Radiation, 

“Considerations in the Design of a Program to Reduce Carbon Pollution from Existing Power Plants,” September 23, 2013 version

(hereinafter “EPA Design Considerations 2013”); EPA, “Background on Establishing New Source Performance Standards (NSPS) 

Under the Clean Air Act,” October 2013, http://www.epa.gov/region9/air/listening/BackgroundEstablishingNewSourcePerformance 

Stds.pdf; EPA, Office of Air Quality Planning and Standards (“OAQPS”), “Rulemaking for Greenhouse Gas Emissions from Electric 

Utility Steam Generating Units,” Tribal Consultation, May 2011 (hereinafter “OAQPS GHG Presentation”).
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 Guidance will be developed through EPA’s normal rulemaking process with a noticeand-comment period (including a Regulatory Impact Assessment), and with “binding 

requirements that states are required to address when they develop plans to regulate

existing sources in their jurisdictions.”

 The guidance will come first in proposed form (by June 1, 2014), and then in final form 

(by June 1, 2015). 

 The Presidential Memorandum requests that EPA guidelines require that States submit 

to EPA their SIPs by no later than June 30, 2016.

 EPA’s guidance will likely set the target reductions for states to use in developing their 

implementation plans with performance standards that apply to the power plants 

subject to Section 111(d) (the “affected sources” of GHG emissions). Consistent with 

prior Section 111(d) rules, “EPA believes that its guidelines should identify for sources 

and states the required level(s) of performance prior to plan submittal.”23 Based on prior 

EPA guidance under Section 111(d), the GHG guidance is likely to contain:24

o A description of BSER that has been adequately demonstrated for a particular 

category of sources (taking into account feasibility, cost, emissions reductions, 

and technology development issues); 25 the degree of emission limitation 

achievable, costs and benefits, and environmental impacts of application; and a 

goal for reductions based on the BSER analysis. 

o No specific prescribed technologies that must be used to comply.

 23 EPA Design Considerations 2013.

24 Sources for these points: EPA, “Background on Establishing New Source Performance Standards (NSPS) Under the Clean Air 

Act,” October 2013, http://www.epa.gov/region9/air/listening/BackgroundEstablishingNewSourcePerformanceStds.pdf; “Overview 

presentation of Clean Air Act Section 111”(http://www2.epa.gov/carbon-pollution-standards/what-epa-doing); OAQPS GHG 

Presentation; Monast et. al. (2012).

25 Senior EPA officials have stated that the particular BSER the agency adopts for existing sources of GHG emissions will not be the 

same as the one it adopted for new power plants, although the BSER criteria EPA takes into account are similar. (See the statement 

of Acting Administrator for Air and Radiation Janet McCabe before the House Energy and Commerce Subcommittee on Energy and 

Power (November 14, 2013)). The application of the criteria to new versus existing power plants is what would lead to different 

BSER targets. In EPA’s proposed Standards of Performance for Greenhouse Gas Emissions from New Stationary Sources: Electric 

Utility Generating Units” (dated September 2013), EPA explains the factors that are to be considered in identifying the BSER: “For 

this rulemaking [under Section 111(b)], the following factors are key: feasibility, costs, size of emission reductions and technology. 

Feasibility ...whether the system of emission reduction is technically feasible. Costs...whether the costs of the system are 

reasonable. Size of emission reductions...the amount of emissions reductions that the system would generate. 

Technology...whether the system promotes the implementation and further development of technology.” Page 25 of the signed 

prepublication version of 40 CFR Part 60 [EPA-HQ-OAR-2013-0495; FRL-9839-4] RIN 2060-AQ91, EPA, Standards of Performance 

for Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating Units, September 20, 2013 (hereinafter 

“EPA 2013 Proposed GHG Standards for New EGUs”). 
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o A stated performance standard using a rate of allowed emissions that is met on a 

facility-by-facility basis (although EPA has discretion to set performance 

standards for classes of power plants based on an allowed rate of emissions (e.g., 

pounds of CO2 per MWh) or a total mass of emissions (e.g., a CO2 tonnage 

budget for a state)).26 

o Timelines for implementing its guidelines.

o “Different guidelines or compliance times (or both)...for different sizes, types, 

and classes of designated facilities when costs, physical limitations, geographical 

location, or other factors make sub-categorization appropriate.” 

o Proposed model rules or a “model approach” to facilitate development of SIPs, 

but the states need not adopt any particular approach.

- State SIPs: States prepare their plans and implement the elements of approved SIPs: 

 In parallel with EPA’s development and issuance of proposed and final guidelines, a 

state may begin to plan its SIP, informed by increasingly more concrete information 

provided through the process and adopted in the final EPA guidance. 

 A state’s SIP, due to be filed at EPA one year after EPA finalizes its guidance, will 

describe how the state proposes to satisfy the EPA guidance, either through adopting 

the EPA approach (if one is provided) or through a program that would provide 

equivalent emissions reductions achieved via elements preferred by the state.

 A SIP may need to contain,for example: 

o “Emission standards and compliance schedules ‘no less stringent than emission 

guidelines’,”27 with the regulations (under Section 110) allowing for equivalency 

where the resulting emission limit is quantifiable, accountable, and enforceable, 

and (based upon replicable procedures) is equivalent to the SIP limit.28 

o Methods and procedures for determining compliance.29

o Enforceable increments of progress for compliance schedules longer than 12 

months.30

 26 Megan Ceronsky and Tomas Carbonell, “Section 111(d) of the Clean Air Act: The Legal Foundation for Strong, Flexible & CostEffective Carbon Pollution Standards for Existing Power Plants,” Environmental Defense Fund, October 2013.

27 OAQPS GHG Presentation.

28 57 Fed. Reg. 13567-68.

29 OAQPS GHG Presentation.

30 OAQPS GHG Presentation.
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 A SIP may propose to “adopt less stringent emission standards or longer compliance 

schedules than those set out in the guidelines where the State demonstrates””:31

o “Unreasonable cost of control due to age, location or basic process design”

o “Physical impossibility of installing necessary control equipment”

o “Other factors specific to the facility or class of facility that make application of a 

less stringent standard or final compliance time significantly more reasonable.” 

 A SIP may adopt more stringent standards or shorter compliance schedules than those 

contained in the guidelines. 

 States will need to adopt laws, rules and/or other administrative mechanisms as part of 

their demonstration that their SIPs will be effective and enforceable. 

 If a state does not file a satisfactory SIP or fails to enforce an approved SIP, then EPA has 

the authority to issue and enforce a Federal Implementation Plan (“FIP”). 

The likely character of EPA’s guidance under CAA Section 111(d) 

Until the EPA publishes its proposed Section 111(d) guidance in June 2014 and finalizes it by the 

following year, observers cannot be sure what that final guidance will contain. There are clues, 

however, in statements from EPA, as well as analyses prepared by many observers. These clues 

provide a reasonable basis for states and the affected industry to begin their planning (as many 

states have already done).

In its September 2013 document posing “questions to the states,” for example, EPA identified 

two “different options available for addressing carbon pollution from existing power plants... A 

source-based approach evaluates emission reduction measures that could be taken directly at 

the affected sources—in this case, the power plants. A system-based approach evaluates a 

broader portfolio of measures including those that could be taken beyond the affected sources 

but still reduce emissions at the source.”32

EPA has typically adopted a source-based approach in other Section 111 regulations.33 In 

developing its proposed GHG emission standards for new fossil power plants under Section 

111(b), for example, EPA relied upon a source-based approach, expressed as a limit on pounds

 31 OAQPS GHG Presentation.

32 EPA Design Considerations 2013.

33 EPA, “Background on Establishing New Source Performance Standards (NSPS) Under the Clean Air Act,” October 2013, 

http://www.epa.gov/region9/air/listening/BackgroundEstablishingNewSourcePerformanceStds.pdf; 
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of CO2 emitted for each MWh of generation. The proposal has one CO2/MWh rate for new 

Electric Utility Steam Generating Units (“EGUs”) that propose to use a solid fossil fuel (e.g., 

coal-fired boilers) and integrated gasification combined cycle (“IGCC”) units,34 and another rate 

for natural-gas-fired combustion units.35,36 

Many parties outside of EPA have made recommendations and proposals for the form of 

regulations they prefer to see EPA adopt in its guidance. In terms of the design and stringency 

of the requirement, these proposals differ in two dimensions (as described recently by Bruce 

Phillips/Clean Air Task Force37): “(1) Whether the rule establishes separate emission standards 

for covered coal and natural gas-fired generation or a blended emission standard for all covered 

fossil generation (both coal and natural gas). (2) Whether the emission standards are expressed 

as an emission rate (in pounds of carbon emissions per unit of generating output) or a massbased standard (in tons of carbon emissions). As shown in the following table, these two basic 

design elements characterize the policy proposals and concepts offered to date.”

 34 EPA has proposed standards of performance for utility boilers and IGCC units based on partial implementation of carbon capture 

and storage (“CCS”) as the BSER. “There are two limits for fossil fuel-fired utility boilers and IGCC units, depending on the 

compliance period that best suits the unit. These limits require capture of only a portion of the CO2 from the new unit. These 

proposed limits are: (a) 1,100 lb CO2/MWh gross over a 12-operating month period, or (b) 1,000-1,050 lb CO2/MWh gross over an 

84-operating month (7-year) period. All standards are in pounds of CO2 per megawatt-hour (lb CO2/MWh gross).” EPA Fact 

Sheet, “Reducing Carbon Pollution From Power Plants Moving Forward On the Climate Action Plan,” September 20, 2013; EPA 

2013 Proposed GHG Standards for New EGUs, pages 15-16.

35 “EPA is proposing two standards for natural gas-fired stationary combustion units, depending on size. The proposed limits are 

based on the performance of modern natural gas combined cycle (NGCC) units. These proposed limits are: (a) 1,000 lb CO2/MWh 

gross for larger units (> 850 mmBtu/hr); and (b) 1,100 lb CO2/MWh gross for smaller units (≤ 850 mmBtu/hr).” All standards are in 

pounds of CO2 per megawatt-hour (lb CO2/MWh gross.” EPA Fact Sheet, “Reducing Carbon Pollution From Power Plants Moving 

Forward On the Climate Action Plan,” September 20, 2013; EPA 2013 Proposed GHG Standards for New EGUs, page 16.

36 I do not mean to suggest that the particular form or level of the CO2/MWh standards proposed in the Section 111(b) rulemaking for 

new power plants will be the same form or level of standards applicable to existing power plants. Indeed, EPA has stated that the 

particular CO2/MWh standards proposed in the rulemaking for new power plants will not be the same standards applicable to 

existing power plants: “In September [2013], the EPA announced its new proposal. The proposed standards would establish the 

first uniform national limits on carbon pollution from future power plants. They will not apply to existing power plants.” Opening 

Statement of Janet McCabe, Acting Assistant Administrator, Office of Air and Radiation, EPA, Hearing on EPA’s Proposed GHG 

Standards for New Power Plants and H.R. __, Whitfield-Manchin Legislation, Subcommittee on Energy and Power, Committee on 

Energy and Commerce, U.S. House of Representatives, November 14, 2013.

37 Bruce Phillips, The Northbridge Group, “Alternative Approaches for Regulating Greenhouse Gas Emissions from Existing Power 

Plants under the Clean Air Act: Practical Pathways to Meaningful Reductions,” prepared at the Request of the Clean Air Task Force, 

February 27, 2014 (hereafter, “Phillips/CATF 2014”).
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Table 1

TAXONOMY OF ALTERNATIVE POLICY DESIGNS38

Blended Fossil Standard Separate Coal and Gas Standards

RateBased

Blended Fossil Emission Rate [one rate for all fossil 

sources]

• NRDC [Natural Resources Defense Council] (trading 

with uncovered sources)39

Coal Emission Rate & Gas Emission Rate

• CATF [Clean Air Task Force] 1.0 

• NCC [National Climate Coalition] (trading 

with uncovered sources)40

MassBased

Fossil Budget (ceiling on total amount of emissions 

from covered fossil fuel units)

• RGGI [Regional Greenhouse Gas Initiative] 

• California AB 32 [Cap-and-Trade Program]

• CATF 2.0 Fossil Alternative

Coal Budget & Gas Emission Rate

• CATF 2.0 Coal Budget/Gas Rate 

Alternative (with an emission rate 

standard for natural gas)

EPA reports41 that commenters have suggested that Section 111(d) guidelines be drafted to 

accommodate multiple emission-reduction options for state SIPs,42 including:

 Averaging of emissions from covered units, through tradable credits. “Units would be 

given emission rate targets. If they emit below the targets, they would generate credits 

 38 I have reproduced the overall structure of the original table in Phillips/CATF 2014 (page 8), but have annotated it [in bracketed 

italics text] to provide full names for the acronyms in the original table, and with other information as provided in the explanatory 

text of Phillips/CATF 2014 regarding the table. Note the perspective of Phillips/CATF 2014 (page 8) that “Although the coal 

budget/gas rate approach is less familiar than the fossil budget approach, there are several advantages. It provides similar 

compliance flexibility and cost effectiveness to the fossil approach, and during the initial years of a 111(d) power plant policy results 

in lower emission credit prices, wholesale market prices and potentially lower retail rate impacts. Also, it is fundamentally quite 

similar to the sulfur dioxide (SO2) trading program established by the CAA Amendments of 1990 and successfully operated since

then. Coal plants produce virtually all of the electric sector’s SO2 emissions, while natural gas emits only trace amounts. 

Consequently, the SO2 trading program is effectively a type of mass-based coal regulation. Given these characteristics and 

advantages, the mass-based coal approach deserves close consideration.”

39 Footnote in the original: Dan Lashof et al., NRDC, “Closing The Power Plant Loophole: Smart Ways The Clean Air Act Can Clean 

Up America’s Climate Polluters, December 2012.

40 Footnotes in the original: “The NCC policy concept calls for renewable and demand side efficiency crediting to play a critical role 

in the rule.” National Climate Coalition, “Using EPA Clean Air Act Authority to Build a Federal Framework for State Greenhouse 

Gas Reduction Programs.” September 2013. Phillips/CATF 2014, page 7-8.

41 EPA Design Considerations 2013. 

42 EPA has also indicated that although it has historically issued a model rule, the agency is “exploring whether and how to develop 

a ‘toolbox’ of decision-making and implementation resources for states that might include information about state programs and 

measures that reduce electricity sector CO2 emissions. Examples of information in the decision-making toolbox might include 

criteria for demonstrating how system-wide actions can meet the level of performance in the emission guidelines; a compendium of 

existing state energy and GHG policies, programs, and measures that includes information about key design attributes and how the 

states are estimating energy savings and emission reductions; and links to tools that help quantify energy savings and emissions 

reductions from state programs and measures.” EPA Design Considerations 2013.
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for each MWh generated. If they emit above the targets, they would still be able to 

comply if they obtained credits to offset emissions above the target.”

 “Generation performance standards,” which EPA depicts as similar to emissions 

averaging “but would include all generating sources (e.g., renewables, nuclear, etc.).”

 “Intrastate emission trading programs with GHG limitations.”

 “Other programs that impact a State’s generation mix and could lead to reductions in 

emissions from covered sources such as renewable portfolio standards, clean energy 

standards,” or “increases in end-use efficiency and demand-side management.”

These clues provide a reasonable basis to expect that the final rule will give states many options 

to meet CO2 reductions cost-effectively and reliably and in ways tailored to the generation mix 

and policy preferences of the particular state. 

Section 111(d) Differs from Other Recent EPA Regulations Affecting Power 

Plants

The character of Section 111(d)’s regulatory framework creates an entirely different and 

potentially much-wider set of compliance and implementation options compared to other 

federal regulations that have affected the electric industry in recent memory. The ‘cooperative 

federalism’ model embedded in Section 111(d) provides for much more compliance flexibility 

and creativity than was possible for the many unit-specific regulations issued recently by EPA. 

This is core to the conclusion that EPA’s regulation of GHG emissions from existing power 

plants will not raise electric system reliability concerns. 

The MATS Rule

For example, one of the most recent EPA regulations affecting existing fossil-fuel power plants –

the MATS rule – differs in fundamental ways from Section 111(d). In the MATS rule, EPA set 

uniform, national standards to reduce emissions of mercury and other toxic air pollutants from 

approximately 1,100 coal-fired EGUs and 300 oil-fired EGUs located in the U.S.43, 44 The 

regulations set limits on allowable emissions that could occur at each affected unit by the 

compliance dates. 

 43 The 12-16-2011 MATS rule also adopted standards for new power plants, which were updated in March 2013.

44 EPA, “Reducing Toxic Pollution from Power Plants: Final Mercury and Air Toxics Standards (MATS),” December 2011 

presentation, page 11.
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EGUs generally have up to four years (and in a limited number of instances, a fifth year) to 

comply with MATS,45 through a range of compliance strategies to be undertaken at the specific 

generating units covered by the regulation. “Many existing sources will comply with the MATS 

by controlling their emissions, while others (typically older, smaller, less efficient units) may 

choose to cease operations rather than install control technologies.”46 No trading or averaging 

is allowed across different generating stations. There is no possibility of purchasing compliance 

credits from over-compliance at other generating stations. 

A vibrant public debate took place during the 2010-2012 period about the ability of the electric 

industry to maintain electric system reliability while also complying with MATS, because those 

EGUs not yet in compliance would either have to invest in pollution-control technology to 

comply with MATS, or shut down.47,48 Reliability concerns focused on the fact that such a large 

portion of the nation’s generating fleet would be affected, and on whether the systems in which 

they were located could respond appropriately (and reliably) given those regions’ heavy 

reliance on coal-fired generation. Other concerns focused on whether pollution-control 

equipment manufacturers and installers could absorb the simultaneous demand for work 

orders from the owners of so many affected units, and whether the rule would force coal units 

to retire and create shortages of generation capacity in some regions.

To address such concerns, the EPA took the unusual step in December 2011 (when it finalized 

its MATS regulation) of issuing a specific statement of enforcement policy to explain that,

“where there is a conflict between timely compliance with a particular requirement and electric 

reliability, the EPA intends to carefully exercise its authorities to ensure compliance with 

 45 MATS includes a 3-year compliance period, with an extension of the compliance deadline for a 4th year for units able to 

demonstrate to state permitting authorities that additional year is needed for installing technology. In some cases a 5th year may be 

allowed, in light of EPA intention to allow use of administrative orders “with respect to sources that must operate in noncompliance 

with the MATS for up to a year to address a specific and documented [electric] reliability concern.” EPA December 2011 MATS 

Enforcement Policy Letter. This would extend MATS compliance deadlines from April 2015 to April 2016 for certain units. 

46 EPA December 2011 MATS Enforcement Policy Letter.

47 Note that many generating units covered by the MATS rule were already compliant with the emissions limits as of the issuance of 

the MATS rule. See M. Bradley, S. Tierney, C. Van Atten, and A. Saha, “Ensuring a Clean, Modern Electric Generating Fleet while 

Maintaining Electric System Reliability,” Fall 2011 Update, November 2011.

48 During the two-year period of 2010 and 2011, countless industry reports and analyses, conference presentations, financial analyst 

calls, media articles, congressional hearings, and other public reviews focused on the question of whether the EPA’s adoption of the 

mercury and air toxics rules, either alone or in conjunction with other potential EPA regulations affecting existing power plants 

(including CSAPR, the coal-ash rule, and the cooling water intake structure rule (Section 316(b) of the Clean Water Act)) that were 

being considered at the time, would introduce local or regional electric system reliability issues. Note one of my own analyses on 

this topic from early 2011: S. Tierney, “Electric Reliability under New EPA Power Plant Regulations: A Field Guide,” January 18, 

2011. http://www.wri.org/stories/2011/01/electric-reliability-under-new-epa-power-plant-regulations-field-guide.
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environmental standards while addressing genuine risks to reliability in a manner that protect 

public health and welfare.”49

At present, the industry is proceeding with its planning in light of the final MATS regulation. 

(See further discussion, below, on how MATS compliance affects the conditions under which 

the states and the industry will develop their responses to EPA guidance under Section 111(d).)

How Section 111(d)’s Framework Differs from the MATS Rule

There several reasons why the types of reliability concerns raised during the discussions of the 

MATS rule in 2010-2011 are not relevant to the Section 111(d) regulations. First, Section 

111(d)’s reliance on the SIP process means that EPA will be able to provide states with guidance 

allowing considerable and wide-ranging latitude in how they plan to meet EPA’s requirements. 

EPA’s guidance will not likely impose a common emission standard that must be met solely by 

actions taken at each affected unit. Rather, EPA is likely to establish standards specific to each 

state, based on the “degree of emission limitation achievable through the application of the best 

system of emission reduction,” which may vary across states given their own particular 

circumstances. Each state will have flexibility to propose its preferred actions that accomplish 

the targeted reductions, as long as the SIP provides reductions across the facilities in the state 

that are at least as effective as EPA’s approach. As EPA Acting Administrator for Air and 

Radiation told state regulators recently, “We get it that states are in very different positions and 

that they’re thinking about these issues in their own context.”50

Second, if a state has concerns about the reliability implications of potential temporary or 

permanent outages of units needed to respond to EPA guidance, the state can take that fact 

 49 EPA December 2011 MATS Enforcement Policy Letter, pages 1, 4: “The EPA generally does not speak publicly to the intended 

scope of its enforcement efforts, particularly years in advance of the date when a violation may occur. The Agency is doing so now 

with respect to the MATS to provide confidence with respect to electric reliability. EGUs may be needed to operate to maintain the 

reliability of the electric grid when they would prefer, or could be required, to halt operations temporarily (until controls can be 

installed) or indefinitely (through deactivation of a unit). ...Some sources may take all steps necessary to comply with the MATS, 

but may nevertheless be needed to operate in noncompliance with the MATS to address concerns with electric reliability. In the 

event that such sources are interested in receiving a schedule to come into compliance while operating, the EPA intends, where 

necessary to avoid a serious risk to electric reliability, and provided the criteria set forth herein are met, to issue an expeditious casespecific AO [Administrative Order] to bring a source into compliance within one year....Any such AOs would be issued on or after 

(not before) the MATS Compliance Date and would be limit to units that are required to run for reliability purposes that (A) would 

otherwise be deactivated, or (B) due to factors beyond the control of the owner/operator, have a delay in installation of controls or 

need to operate because another units has had such a delay.”

50 Remarks of Janet McCabe, Acting Administrator for Air and Radiation, presented to the National Association of Regulatory 

Utility Commissioners, February 11, 2014.
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explicitly into account as it designs its SIP. For example, a state may propose plan elements that 

enable early action/compliance at some Section 111(d) generating units in exchange for allowing 

more time for others, or that allow emission averaging or emission-credit trading that achieve 

deeper reductions at one unit in exchange for lighter reductions at another. (The many options 

available to states in developing their SIPs are discussed below, in the section on “Planning for 

compliance with EPA guidance.”) 

Third, the Presidential Memorandum directing EPA to use its Section 111(d) authority explicitly 

calls for the agency to “develop approaches that allow the use of market-based instruments, 

performance standards, and other regulatory flexibilities” that are not possible under the 

statutory language governing MATS. The Presidential Memorandum further directs EPA to 

develop its standards, regulations or guidelines to:

identify and use the best, most innovative, and least burdensome tools for 

achieving regulatory ends...[and to] propose or adopt a regulation only upon a 

reasoned determination that its benefits justify its costs (recognizing that some 

benefits and costs are difficult to quantify); (2) tailor its regulations to impose the 

least burden on society, consistent with obtaining regulatory objectives, taking 

into account, among other things, and to the extent practicable, the costs of 

cumulative regulations; (3) select, in choosing among alternative regulatory 

approaches, those approaches that maximize net benefits (including potential 

economic, environmental, public health and safety, and other advantages; 

distributive impacts; and equity); (4) to the extent feasible, specify performance 

objectives, rather than specifying the behavior or manner of compliance that 

regulated entities must adopt; and (5) identify and assess available alternatives to 

direct regulation, including providing economic incentives to encourage the 

desired behavior, such as user fees or marketable permits, or providing 

information upon which choices can be made by the public.51

Thus, the inherent authority within 111(d), combined with these Presidential directives, invites 

(if not requires) EPA to implement a flexible framework that will allow states to propose SIPs

that take into account the need to assure electric system reliability. As such, the reliability red 

flag is mainly useful as a spur toward advanced planning, and to motivate states to prepare 

SIPs with elements addressing (and mitigating) such concerns. (See further discussion below.) 

 51 This language is from Executive Order 13563, reflecting the Presidential Memorandum direction that EPA develop its guidance in 

a manner “consistent with Executive Orders 12866 of September 30, 1993, as amended, and 13563 of January 18, 2011.” The latter 

Executive Order is “13563: Improving Regulation and Regulatory Review.” 
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Power plants that are subject to CAA Section 111(d) 

EPA has previously indicated that its Section 111(d) regulations will apply specifically to 

existing EGUs:52 all grid-connected steam generators that use fossil fuel and are over 25 

megawatts (“MW”) in size. It is sensible to presume, too, that Section 111(d) will also apply to 

natural-gas-fired combined-cycle (“NGCCs”) generating units, in light of the fact that the 

Section 111(b) proposal (affecting new power plants) applies to such units as well.53

Together, these categories represent a large subset of all of the nation’s power plants, and cover 

most but not all existing fossil-fuel generating units. It does not include either non-grid 

connected or very-small steam generating units, or simple-cycle peaking units. EGUs and 

NGCCs represent classes of technologies which may be owned by investor-owned utilities, 

publicly owned utilities, rural electric cooperatives, non-utility generating companies, and 

others. 

Based on current information about power plants from SNL Financial for 2013, I calculate that 

there are 3,084 EGUs and NGCC units likely to be directly affected by EPA’s upcoming 

regulations.54 (See Table 2.) These generating units represent approximately 532.4 GW of 

generating capacity,55 with 292.4 GW of coal-fired power plants (mainly EGU capacity), 216.6

 52 “The regulations would apply to each EGU capable of combusting more than 250 million British thermal units per hour 

(MMBtu/hr) heat input of fossil fuel: Electric utility steam generating unit means any steam electric generating unit that is constructed 

for the purpose of supplying more than one-third of its potential electric output capacity and more than 25 megawatts electric 

(MWe) output to any utility power distribution system for sale. Fossil fuel means natural gas, petroleum, coal, and any form of solid, 

liquid, or gaseous fuel derived from such material for the purpose of creating useful heat.“ OAQPS GHG Presentation.

53 This is based on two assumptions: First, CAA Section 111(d) will apply to EGUs as defined by the EPA (see, for example, the 

OAQPS GHG Presentation from 2011). Second, Section 111(d) will apply to any categories of existing emission sources that, if they 

were new sources, would be regulated under Section 111(b). Under EPA’s 2013 Proposed GHG Standards for New EGUs, Section 

111(b) includes not only fossil-fuel steam generating units but also natural-gas combined-cycle units: “Utility announcements about 

the status of coal projects, IRPs [integrated resources plans], and EIA projections suggest that, by far, the largest sources of new 

fossil fuel-fired electricity generation are likely to be NGCC units. The EPA believes, therefore, that it is also appropriate to set a 

standard for stationary combustion turbines used as EGUs. These units are currently covered under subpart KKKK (stationary 

combustion turbines). The EPA also proposes to maintain the definition of EGUs under the NSPS that differentiates between EGUs 

(sources used primarily for generating electricity for sale to the grid) and non-EGUs (turbines primarily used to generate steam 

and/or electricity for on-site use). That definition defines EGUs as units that sell more than one-third of their potential electric 

output to the grid. Under this definition, most simple cycle “peaking” stationary combustion turbines, which typically sell 

significantly less than one-third of their potential electric output to the grid, would not be affected by today’s proposal.” Page 24 of 

EPA 2013 Proposed GHG Standards for New EGUs.

54 The actual number of EGUs as of early 2014 is 1,929 units in light of data for grid-connected steam generating units over 25 MW in 

size and using coal, natural gas or oil for fuel. In early 2014, there were 1,176 generating units associated with combined cycle 

technologies, most of which burn natural gas. Source of data: SNL Financial.

55 Net summer capacity.
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GW of natural-gas-fired plants (mainly combined cycle units), and 23.7 GW of plants that burn 

oil (mainly EGUs).56 This represents approximately half of total generating capacity in the U.S. 

as of the first quarter of 2014 (with the rest being primarily nuclear, hydro and wind), and 70 

percent of U.S. fossil generating capacity. (See Appendix 2.)

Table 2

Existing Power Generation Capacity in the U.S. as of 3-2014:

All Power Plants and Power Plants Likely to be Subject to Clean Air Act 111(d)

Generating Units Likely to Be 

Directly Covered by Section 111(d)*

 (# Units) (GW of Capacity)

Total Grid-Connected 

Generating Capacity

in the U.S.

(GW) 

111(d) Capacity as 

a Share of Total 

Capacity (%)

Coal 1204 292.4 303.7 96%

Natural Gas 1,636 216.6 414.3 52%

Oil 244 23.7 38.2 61%

Nuclear 0 0 98.0 0

Hydro 0 0 99.0 0

Wind and Solar 0 0 68.9 0

Other** 0 0 21.7 0

Total 3,804 532.4 1042.4 51%

Source of data: SNL Financial, March 2014. “GW” reflects net summer capacity of the generating units.

* This reflects existing grid-connected EGUs over 25 MW and NGCCs.

** This includes biomass, geothermal, and generation from other fuels not listed above.

Figure 1 shows the location of all U.S. fossil power plants by fuel type. Given the different 

fuel/technology mixes of power plants across the states, Section 111(d) will impact the states in 

different ways: 

 States with half of their in-state generating capacity likely to be subject to Section 111(d) 

are (ranked by percentage of total capacity in the state): West Virginia (highest at 88 

percent), Utah, Wyoming, Kentucky, Indiana, Louisiana, Delaware, Ohio, New Mexico, 

Oklahoma, Texas, Missouri, North Dakota, Missouri, Arkansas, Rhode Island, 

Massachusetts, Maryland, Wisconsin, Florida, Nebraska, Michigan, Alabama, 

Pennsylvania, and Hawaii (with 50 percent). 

 56 These estimates are based on the primary fuel of plants, some of which may burn a second fuel.
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 States with a relatively high share of the nation’s total generating capacity affected by 

Section 111(d) are as follows (ranked by highest percentage of total capacity in the U.S.): 

Texas (12 percent), Florida, California, Pennsylvania, Ohio, Indiana, Georgia, Illinois, 

Louisiana, Alabama, New York, Michigan, Kentucky, Oklahoma, West Virginia, North 

Carolina, and Missouri (3 percent).

Appendix 2 provides state-specific information about power plant capacity and units likely to 

be directly subject to 111(d), along with other capacity in the each state’s electric generating 

fleet. Forty-nine of the 50 states will need to prepare a SIP to show how the state plans to bring 

its generating facilities into compliance with EPA guidance. 

Figure 1

Roughly one quarter of that Section 111(d) capacity (and 28 percent of the units) entered service 

prior to 1970, and is thus at least 43 years old. Approximately 352 EGUs (with a total capacity 

of 43.2 GW) are older than 53 years. Owners of 119 of the old (pre-1970) EGUs (with a capacity 

totaling 16.7 GW) have announced that they intend to retire the unit in a year prior to the end of 
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2016.57 These tend to be much smaller units, two-thirds of which are coal-fired EGUs and onefourth oil-fired EGUs.

Approximately three percent of the directly affected EGU and combined-cycle capacity (18.8 

GW) operating at the start of 2014 has a planned retirement occurring between 2013 and 2016 –

well before the compliance period for SIP implementation58 (and roughly consistent with the

date by which existing coal-fired and oil-fired EGUs will have had to comply with the EPA’s 

MATS rule59 or retire). Using this information as a proxy for upcoming retirements, 

approximately 523 GW of capacity nationwide would be subject to Section 111(d) after 2016. 

(See further discussion below regarding power plant retirements.)

Context for Industry Compliance with CAA Section 111(d) Requirements

Several trends affecting the electric industry set the stage for the roll-out of new regulations. 

Foremost among these trends are: the ‘shale gas’ revolution and its implications for coal plant 

economics (including the availability of higher levels of output from existing natural-gas power 

plants); relatively flat demand for electricity; growth in development of renewable energy; the 

availability of supply from zero-carbon nuclear generation; the announcements of retirements 

of coal-fired generating capacity that result from these factors and the EPA’s MATS rule; and 

proposals to build new power plants. These trends set the context for EPA and the states 

preparing to address GHG emission reductions. And they affect the factors that states will need 

to consider as they plan for electric-system reliability as part of that process.

Natural gas, coal and existing power plants 

Until the past few years, energy market fundamentals favored use of coal for power generation 

in many parts of the U.S. The recent shale gas revolution has fundamentally changed that 

 57 Analysis based on SNL Financial data.

58 The Presidential Memorandum requests that EPA’s 111(d) guidelines require states to submit their SIPs by no later than June 

2016. Assuming this optimistic time frame and taking into account time for EPA review and state implementation, compliance 

would actually likely begin no earlier than late 2017. (See, for example, the schedule showing an estimated compliance period for 

Section 111(d) spanning roughly late 2017 through 2020, as presented by Jennifer Macedonia, Bipartisan Policy Center, “Clean Air

Act Regulation of Power Plants: Greenhouse Gas Performance Standards,” September 2013, page 4.)

59 See December 16, 2011, letter of Cynthia Giles, Assistant Administrator of the Office of Enforcement and Compliance Assurance, 

EPA, re: the EPA’s “Enforcement Response Policy for Use of Clean Air Act Section 113(a) Administrative Orders in Relation to 

Electric Reliability and the Mercury and Air Toxics Standard” (hereafter, “EPA December 2011 MATS Enforcement Policy Letter”).
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situation. Low natural gas prices over the past few years60 have put economic pressure on coal 

facilities. Natural-gas-fired power plants increased their output (from 22 percent of U.S. power 

production in 2007, to 28 percent in 2013), while coal-fired generation decreased (from 49 

percent in 2007 to 39 percent 2013).61 Fuel-switching and re-dispatch of existing power plants 

was possible in light of the significant amount of gas-fired generating capacity that had been 

added in the U.S. since 2000 (Figure 2) and that had been underutilized for many years. 

Figure 2

Generating Capacity Additions by Year and by Fuel (GW): 1985-2013

Source: EIA, Annual Energy Outlook 2013, Figure 78.

Low gas prices resulted from a combination of lower demand for energy (from the U.S. 

economic downturn and other factors62), and generally lower production costs associated with 

unconventional gas production. (See Figure 3 for wellhead prices of natural gas and in Figure 4 

for prices of natural gas futures.) Market pressure resulting from low natural gas prices led to 

 60 Note that natural gas commodity prices spiked in many parts of the U.S. where extremely cold weather occurred in December 

2013 and mid-January 2014. See SNL Financial.

61 Source: EIA, Electric Power Monthly, Table 1.1. Net Generation by Energy Source: Total (All Sectors), 2003-November 2013. 

Information for 2013 is for the 11 months (January through November).

62 Including states’ promotion of increased funding for energy efficiency programs and stronger appliance efficiency standards.

 -

 10.00

 20.00

 30.00

 40.00

 50.00

 60.00

19851986198719881989199019911992199319941995199619971998199920002001200220032004200520062007200820092010201120122013

Other Renewables

Solar

Wind

Oil and Gas

Nuclear

Hydro/other

Coal
Electric System Reliability and GHG Emission Reductions Under CAA Section 111(d) – May 2014

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announcements of retirements of some of the oldest, smallest and least-efficient coal plants, as 

discussed previously.63 Figure 5 shows the cumulative amount of coal-fired generating capacity 

(a total of 25.4 GW) that retired without reliability problems in the 2008-2013 period, in various 

regions of the U.S. It also shows the amount of capacity (an additional 20 GW) that has been 

announced to retire between 2014 through 2018. Most of the retiring capacity is located in the 

RFC and SERC regions – areas with substantial coal-fired generation and underutilized natural 

gas capacity. 

 Figure 3 Figure 4

Source: EIA Source: SNL Financial

Given the significant amount of natural-gas-fired generating capacity added since 2000, these 

plants have not operated at full capacity, even as natural gas prices dropped in recent years and 

made it more economical to operate gas-fired plants.64 This underutilized gas-fired capacity 

represents existing capacity that could operate more and could supply consumers’ power 

requirements in the event of retirements of other power plants, operating restrictions on other 

high-emitting plants, and/or increased costs to run coal-fired power plants.

 63 A longer explanation of such market changes is in my February 2012 paper called “Why Coal Plants Retire: Power Market 

Fundamentals as of 2012.”

64 This is particularly true compared to prior years (e.g., during the period from roughly 2001 through 2008), when gas prices were 

relatively volatile and high (compared to most of the period since then, as shown in Figure 3). 
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Figure 5

Generating Capacity Associated Actual Coal-Plant Retirements (2009-2013) and 

Planned Coal Capacity Retirements (2014-2018) by NERC Region

(With Retirements as a Percentage of Each Region’s Total 2012 Generating Capacity)

Source of data: SNL Financial, March 25, 2014. “NERC Region” refers to NERC’s reliability regions (shown on 

the map). Note that there are no actual or planned retirements during the 2008-2018 period for TRE and FRCC.

The states and regions vary with respect to their reliance on natural gas capacity (e.g., NGCC 

capacity as a percentage of total capacity in the region) and their dispatch of NGCCs (i.e., their 

capacity factors, or the percentage actual output relative to their potential to produce power). 

Figure 6 shows the various regions, with shading indicating the extent to which there is 

significant under-utilized NGCC capacity that could be dispatched to meet power requirements 

in the event of restricted output at or retirement of coal plants. A lighter-shaded color indicates 

that the region’s electric mix has relatively low reliance on NGCC capacity, but operates them 

relatively frequently. A darker-shaded color indicates that that region has relatively high reliance 

on NGCC capacity but with low capacity factors at those plants. 
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Figure 6

Regional Reliance on Natural Gas-Fired Combined Cycle in 2012 as a Percentage of

Total Generating Capacity and in terms of Asset Utilization (Capacity Factor): 

Source of data: SNL data (on NGCC power plants and capacity factors) by NERC subregion as of 2012. NERC 

regions and subregions are shown in Appendix 3. Note: There were no regions with less than 3 percent or more than 

41 percent reliance on NGCC capacity (as a percentage of total summer capacity in 2012). No regions had an average 

NGCC capacity factor lower than 25 percent and higher than 65 percent in 2012. In all but one region (NWPP), the 

average 3-year capacity factor (2011-2013) was lower than the capacity factor in 2012, due to various factors including 

relative price of natural gas and coal, availability of hydro and/or wind, nuclear outages and/or retirements, coalplant retirements). The 3-year average was less than 5 percent lower for some regions (i.e., ERCOT, FRCC, ISO-NE, 

NYISO, RMPA, VACAR), between 5-10 percent lower for others (AZNM, DELTA, and SOUTHEAST), between 10-15 

percent lower (CAISO, CENTRAL, PJM, and SPP), and 15-30 percent lower (in GATEWAY and MISO). 

This under-utilized NGCC capacity provides an opportunity in most states to incorporate policies 

and actions in their SIPs that encourage redispatch of existing power plants. For example, the 

recent Phillips/CATF 2014 analysis indicates that a combination of 

approaches would reduce emissions through a mix of compliance actions: 

by reducing the heat rates (and consequently the emission rates) of coal 

units; displacing high emission rate coal generation with lower emission 

rate gas generation through an emission credit trading program; retiring 
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coal generating capacity; and reducing electric demand through customer 

response to higher electric prices. Of these, the emission reductions from

fossil dispatch represent the largest single source of reductions, in both 

cases approximately 70 percent of total compliance. This is due to the large 

size and intermediate capacity factors of the existing NGCC fleet (even 

under current and expected market conditions) and the relatively narrow 

spread between delivered coal and natural gas prices, especially in the 

eastern and central regions of the country.”65

This existing, under-utilized existing capacity provides grid operators with generating 

resources to dispatch to meet operating requirements reliably. As noted in Figure 6, every 

region has some existing under-utilized NGCC capacity, and there were no regions with 

average NGCC capacity factors lower than 25 percent and higher than 65 percent in 2012. 

As shown in the Appendix 2, a handful of states (Hawaii, Kansas, Kentucky, North Dakota, 

Vermont, West Virginia, and Wyoming) did not have any NGCC capacity operating in 2012; 

of these, most of them either have NGCC capacity under construction in their state as of 

March 2014 (as is the case for Kansas, Kentucky, North Dakota, and Wyoming) and/or are 

part of a region with significant under-utilized NGCC capacity (as is the case for all of these 

states besides Hawaii). 

Outlook for electricity demand 

GHG emissions from fossil fuel power plants are also strongly tied to overall electricity use. 

Electricity demand has been relatively flat in recent years, with a gradual return to 2007 levels 

anticipated by next year.66 Beyond then, EIA estimates that demand will grow approximately 

1.5 percent per year through the end of this decade.67 The current forecast for 2020 is 

approximately the level of demand anticipated for 2013 before the economic downturn. This 

provides a degree of breathing room for managing changes in the generation mix.

 65 Phillips/CATF 2014, page 21. See also the Appendix in that report.

66 EIA, Annual Energy Outlook 2014 (Early Release) (hereafter “EIA AEO 2014ER”), and AEO 2008, with actual data from Electric 

Power Monthly.

67 The EIA’s estimates of demand does not take into account the demand met by on-site renewable generation (e.g., roof-top 

photovoltaic systems). 
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Figure 7

Electricity Demand through 2025:

Projected (as of 2008 and 2014) and Actual (2005-2012)

Source of data: EIA, AEO (2008, 2014), and Electric Power Monthly

EIA projects different growth rates by region of the country.68 Regions anticipated to grow 

faster than the U.S. average are the Mountain states, the Plains states, Texas, and the 

Southeast.69 By contrast, EIA projects slower growth for the Pacific states, East North Central 

states, the Mid-Atlantic, and New England regions.70 (Figure 8.)

 68 EIA AEO 2014ER, Tables 1-30. http://www.eia.gov/forecasts/aeo/er/tables_ref.cfm, Tables.

69 West North Central (1.0%/year); South Atlantic (1.1%/year); West South Central (1.2%/year); Mountain (1.7%/year); East South

Central (1.7%/year). EIA, AEO 2014ER. 

70 Middle Atlantic states (0.3%/year); New England (0.6%/year); East North Central (0.8%/year); Pacific states (0.8%/year). EIA AEO 

2014ER. 
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Figure 8

Projected Growth in Demand for Electricity by Region:

Average Annual Growth Rate (2012-2020)

 Source of data: EIA, AEO 2014ER

States’ growth trends reflect not only different economic activity but also the effect of policy. 

Many states have adopted energy efficiency policies that enable greater energy productivity 

through policies such as utility-sponsored energy efficiency programs, building codes, 

ratemaking incentives for meeting efficiency targets, and an Energy Efficiency Resource 

Standard (“EERS”). According to the American Council for an Energy Efficiency Economy 

(“ACEEE”), 26 states “have adopted and adequately funded an EERS, which sets long-term 

energy savings targets and drives investments in utility-sector energy efficiency programs,”71

and which “aim explicitly for quantifiable energy savings.”72 Figure 9 shows states with an 

EERS and other programs promoting efficiency savings in electricity use.

 71 ACEEE, “The 2013 State Energy Efficiency Scorecard,” ACEEE Report E13K (hereafter “ACEEE 2013 Efficiency Scorecard”), page 

vi. The states with a “statewide EERS” as of 2013 are: Arizona, Arkansas, California, Connecticut, Illinois, Indiana, Maine, 

Maryland, Massachusetts, Michigan, Minnesota, New Mexico, New York, Ohio, Pennsylvania, Rhode Island, and Texas. The states 

with a version of an EERS that ACEEE calls a “tailored target” are Colorado, Iowa, Oregon, Vermont, Washington, and Wisconsin. 

And the states that combine a renewables and energy efficiency standard are Hawaii, Nevada and North Carolina. ACEEE 2013 

Efficiency Scorecard, page 19. 

72 “Twenty-six states now have fully funded EERS that establish specific energy savings targets through customer energy efficiency 

programs. These policies set multi-year targets for electricity..., such as 1% or 2% incremental savings per year or 20% cumulative 

savings by 2025.[fn in the original.] EERS policies aim explicitly for quantifiable energy savings, reinforcing the idea that energy

efficiency is a utility system resource on par with supply-side resources. These standards also help utility system planners more

clearly anticipate and project the impact of energy efficiency programs on utility system loads and resource needs. Energy savings 
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Figure 9

States with a Energy Efficiency Resource Standard or With Relatively

High Scores for Electricity Energy Efficiency Policies (as of 2013)

Source: Data from the ACEEE 2013 Efficiency Scorecard, Table 8. This table includes all states 

considered having an EERS (by ACEEE) and otherwise receiving at least 5 of 16 points for 

electricity energy efficiency (“EE”) or EE ratemaking incentives for utilities.

Even states with a strong history of pursuing cost-effective energy efficiency have further 

opportunities to improve energy productivity in the future.73 Tapping such opportunities can 

help states reduce some of the GHG emissions associated with electricity production.74

State policies relating to renewable energy 

Another factor affecting the outlook for GHG emissions at existing fossil units is the widespread 

adoption of policies by states to promote use of renewable generation. As shown in Figure 10, 

 

targets are generally set at levels that push efficiency programs to achieve higher savings than they otherwise would have, typically 

based on analysis for the energy efficiency savings potential in the state that ensures the targets are realistic and achievable. EERS 

policies maintain strict requirements for cost-effectiveness so that efficiency programs are guaranteed to provide overall benefits to 

consumers.” ACEEE 2013 Efficiency Scorecard, Page 18.

73 See, for example, the February 7, 2013 report of the Alliance Commission on National Energy Efficiency Policy, “Doubling U.S. 

Energy Productivity by 2030.”

74 Paul Hibbard and Andrea Okie, “Crediting Greenhouse Gas Emission Reductions from Energy Efficiency Investments: 

Recommended Framework for Proposed Guidance on Quantifying Energy Savings and Emission Reductions in Section 111(d) State 

Plans Implementing the Carbon Pollution Standards for Existing Power Plants,” March 2014. 

http://www.edf.org/sites/default/files/eemv-111d-recommended-framework.pdf.
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most states have either a Renewable Portfolio Standard (“RPS”) that requires that a certain 

percentage of electricity sold at retail be sourced from renewable energy generation, or a goal 

for development and use of renewable supplies. Some of these states’ RPS policies have been 

in place for many years, leading to growth in renewable generation in recent years. Figure 11 

shows the percentage of states’ 2012 generation that came from renewable energy (including 

wind, solar, geothermal, hydro, wood, wood waste, municipal waste, landfill gas, and other 

biomass). This output tends to displace output that would otherwise come from fossil 

generation with GHG emissions.75

Figure 10

States with a Renewable Portfolio Standard or Renewables Goals (as of 2013)

Source: Database of State Incentives for Renewables and Efficiency (“DSIRE”)

 75 In the U.S. overall in 2012, renewable generation accounted for 14 percent of total electricity supply. Of this renewable generation, 

the sources of power production were as follows: 

Renewable Generation in the U.S. – Percentage Shares by Fuel/Resource in 2012

Conventional Hydro 55%

Wind 28%

Wood and Other Biomass 7%

Municipal Wastes 4%

Geothermal 3%

Solar (not including off-grid PV systems) 2%

Total Renewables 100%

EIA, AEO 2014ER, ref2014.d102413a, Table 120. 
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Figure 11

Percentage of States’ Total Power Generation from Renewable Energy in 2012

Source of data: EIA, AEO 2014ER, ref2014.d102413a, Table 96. States’ output shown on the map 

above is based on their location within EIA’s Electricity Market Module Regions. For states in more 

than one region, a state has been assigned to the particular region in which the majority of the state 

is located (by land, not necessarily load). “Renewables” includes wind, solar, geothermal, 

conventional hydro, wood, wood waste, municipal waste, landfill gas, and other biomass.

EIA projects that in several parts of the country where renewable generation was a relatively 

small share of total power supply in 2012, there will be substantial growth in renewable output. 

Figure 12 shows information related to such growth, with the color indicating each state’s 

renewable generation in 2020, as a percentage increase from that state’s base of renewables in 

2012. The additional renewable supply will come from both utility-scale and distributed 

renewable energy projects (i.e., facilities located ‘behind the meter’ on customers’ premises). 

These projections, based on current policy assumptions, provide a reasonable basis for 

assuming that in the future, renewables will allow for displacement of some of the output from 

fossil generation in many regions of the country (e.g., the Southeast and Florida, Arizona and 

New Mexico, Virginia and the Carolinas, Michigan and other parts of the Midwest) in the years 

ahead. States may be able to plan for such as part of their SIPs, and will likely need to address 
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operational/integration issues that may become more urgent with higher penetration of 

renewables (although the availability of flexible NGCC will help with this integration).76

Figure 12

Projected Growth in States’ Renewable Generation 

by 2020, Relative to 2012 Percentage

Source of data: EIA, AEO, 2014ER, ref2014.d102413a, Table 96. The information in this chart is based 

on a comparison of the MWh of generation in 2012 with the projected generation in 2020, with the 

difference reflecting the percentage change in renewables generation over that period. States with a 

darker color represent a higher percentage growth in that state. States’ output shown on the map above 

is based on their location within EIA’s Electricity Market Module Regions. For states in more than one 

region, a state has been assigned to the particular region in which the majority of the state is located (by 

land, not necessarily load). “Renewables” includes wind, solar, geothermal, conventional hydro, wood, 

wood waste, municipal waste, landfill gas, and other biomass. 

Availability of zero-carbon supply from nuclear generators

For nearly two decades, one fifth of the nation’s electricity supply has been generated at nuclear 

power plants.77 The currently operating 100 nuclear reactors are located in 31 states, as shown 

in Figure 13.

 76 See, for example, the recent study performed to examine the operational, cost, emission, and other implications of a 40-percent 

and 50-percent RPS requirement in California: E3, “investigating a Higher Renewables Portfolio Standard in California, January 

2014; and Dan Arvizu, Severin Borenstein, Susan Tierney, and Stephen Wright, “Report of the Independent Advisory Panel 

Regarding the Five California Utilities’ Study of Integration of Renewable Energy into California’s Electric System: ‘Investigating a 

Higher Renewables Portfolio Standard in California’,” January 2014. 
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Figure 13

Location of Existing Nuclear Power Plants and Regional Transmission Organizations (RTOs) 

Source: World Nuclear Association, http://www.world-nuclear.org/info/Country-Profiles/Countries-TZ/USA--Nuclear-Power/. Overlay of RTOs (Analysis Group). Note that this map shows the San Onofre 

(California), Crystal River (Florida), and Kewaunee (Wisconsin) units – all of which were retired as of 2014.

In the past two years, owners of several existing nuclear units have either retired or announced 

an impending retirement of the plants. The actual retirements include units located in 

California, Wisconsin, and Florida. A unit retirement will occur in Vermont at the end of 2014. 

These particular retirements are due to a variety of reasons, including costly repairs and low 

wholesale power prices.78 

 77 EIA, Annual Review of Energy, 2013, Table 7.2b Electricity Net Generation: Electric Power Sector.

78 San Onofre Units 2 and 3 in California (and totaling 2150 MW) retired in 2013 after being shut down for an extended outage 

related to a damaged steam generator at the unit, with its owner reporting it would be uneconomic to repair and restart the units, in 

light of market conditions; Kawanee, a 566-MW unit in Wisconsin shut down in 2013 due to lower power prices in wholesale 

markets; Crystal River, a 860-MW unit in Florida that was shut down permanently in 2013 down after a decision not to repair the 

previously damaged station; and Vermont Yankee, a 604-MW unit announced to be retired at the end of 2014 due to unfavorable 

economics, in spite of a 90+ percent capacity factor. Sources: EIA Generator Y2012 data (860 database on power plants); EIA, 

“Lower power prices and high repair costs drive nuclear,” July 2, 2013; Matthew Bandyck, “UPDATE: Entergy says Vermont 

Yankee nuke closure shows 'design flaws' in wholesale markets,” August 27, 2013.
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Many of the nation’s best-performing nuclear units – including those that operate on a nonutility ‘merchant’ basis – are under significant economic pressure. Merchant nuclear plants 

operating in the ‘organized’ wholesale power markets (shown on Figure 13’s shaded regions) 

have suffered slim profit margins in recent years. This results from many factors, including low 

natural gas prices, wholesale power-market design flaws, flat electricity demand, rising capital 

costs, and public policies that favor some low-carbon resources but not others.79 

Figure 14 shows total nuclear generating capacity, taking into account the effect of recent 

nuclear retirements, new nuclear units under construction, new capacity uprates, and other 

nuclear plants retiring at the end of their currently approved operating licenses. 

Figure 14

Nuclear Generating Capacity: 2012-2030 

(Existing Units, Unit Retirements, Planned Uprates, and Units Under Construction in 2014

Source: EIA, AEO 2014ER.

Taking these retirements into account, along with the projected addition of the five nuclear 

generating units under construction in the Southeast, EIA projects that regions will continue to 

rely on nuclear plants to produce a considerable share of power supply by the year 2020 (as 

shown in Figure 15), with declining zero-carbon nuclear generating capacity beyond then (see 

Figure 14). 

 79 See my forthcoming paper: S. Tierney, “Today’s Nuclear Fleet: What Role in the Nation’s Clean, Affordable and Reliable Power 

Strategy?” 
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Figure 15

Projected Regional Reliance on Nuclear Energy 2020

(NERC Subregions80)

Source of data: EIA, AEO 2014ER, ref2014.d102413a, Table 96. Note that because these 

projections are based on NERC subregions rather than state-specific generation estimates for 

2020, there may be no nuclear units in some states with that show shading (rather than being 

a white color). Compare Figure 13 to this one, for the location of nuclear units by state. 

Note that NERC regions and subregions are shown in Appendix 3.

When a nuclear plant retires, its output tends to be replaced (at least in the near term) with 

generation from plants that burn natural gas, oil or coal. Loss of nuclear units leads, therefore,

to higher CO2 emissions. Reportedly, California’s CO2 emissions increased by 10 percent after 

the recent loss of the output from the two San Onofre units that shut down in early 2012.81 

The need to replace zero-carbon generation at any additional nuclear plants that shut down 

could increase the pressure on states to include Section 111(d) SIP elements addressing this 

 80 States’ output shown on the map above is based on their location within EIA’s Electricity Market Module Regions. For states in 

more than one region, a state has been assigned to the particular region in which the majority of the state is located (by land, not 

necessarily load). There may be no nuclear units in some states with a shading (i.e., not white color), in light of the market subregions used in EIA modeling. 

81 The California Air Resources Board has reported that CO2 emissions in the state increased from 2011 to 2012, “primarily due to 

emission increases from California electricity generation using natural gas as a fuel”, which in turn were tied to low hydro 

conditions, higher demand as a result of warmer weather and a recovery economy, and the shutdown of the San Onofre nuclear 

station in early 2012. World Nuclear News, “Greenhouse gas emissions from power plants in California increased by 35% in 2012, 

partly due to the early closure of the San Onofre nuclear power plant,” November 5, 2013. 
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situation. For example, EPA should consider requiring states with existing nuclear plants to 

demonstrate in their SIPs mechanisms to assure retention of such zero-carbon electricity supply 

and/or address the potential loss of resources with no GHG emissions. Additionally, the states 

located in regions with (a) deep reliance on nuclear generation (Figure 15), (b) merchant nuclear 

plants located in ERCOT, PJM, MISO, NYISO, ISO-NE (Figure 13), and (c) significant coal 

retirements (Figure 5, and discussion in the following section) should consider including 

elements in their SIPs to create incentives to retain safely operating zero-carbon generating 

capacity and/or to recognize the potential to generate electricity with no carbon emissions as a 

result of any planned nuclear capacity uprates. 

Responses to EPA MATS regulations 

Owners of many existing coal-fired power plants are planning for their future in light of the 

EPA’s MATS regulations issued at the end of 2011. EGUs affected by the MATS rule will need 

to be in compliance by 2016, with some exceptions as noted by EPA.82 

In anticipation of these regulations and in light of market fundamentals, many of the older and 

less-efficient coal plants may retire before the MATS compliance deadlines. (See Figure 5.) 

(Various observers have estimated the expected amounts of retirements, but comparisons 

among them are hard because they reflect different time periods for their baseline generating 

capacity and forward period for retirements.83) Some of the coal plant capacity has already 

retired (e.g., 25.4 GW from 2008 through 2013, as shown in Table 5), leaving 303.7 GW of coalfired capacity as of the beginning of 2014. Because owners of plants affected by the MATS rule 

have until roughly 2016 to comply with the rule’s requirements, the retirements occurring 

before then can be viewed as heavily affected by current power market pressures. In addition 

to the 25.4 GW already retired, another 18.4 GW has been announced to retired through 2016, 

with most of that retiring by the end of 2015 and located in the RFC (Midwest) and SERC 

(Southeast) regions (see Figure 5).

 82 See EPA December 2011 MATS Enforcement Policy Letter.

83 “Over 52 GW (about 16% of the existing coal fleet) of coal-fired electric generating capacity has been announced for retirement by 

2025. Of this, about 45 GW will retire by 2016.” Amlan Saha, “Review of Coal Retirements,” MJ Bradley Associates, April 2013. SNL 

has recently reported that owners of 47 GW (roughly 14.6 percent of the 323 GW of coal-fired generating capacity operating as of 

2012) have announced the retirement of such units before 2016. Jesse Gilbert and Andrew Gelbaugh, “Coal under fire: Assessing 

risk factors and market impacts for upcoming coal retirement decisions,” SNL Financial, December 2013 (hereafter “SNL 2013 Coal 

Retirement Study”), page 14.
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A December 2013 SNL study analyzed the combined economic pressures from MATS 

compliance and other factors (including low natural gas prices, wholesale power prices and 

demand forecasts). SNL estimates that an additional 16.9 GW is ‘at risk” of retirement, with 

that amount decreasing to 15 GW if average natural gas prices are 50 cents/MMBtu higher than 

the base case and increasing to 22.3 GW if average natural gas prices are 50 cents/MMBtu lower 

than in the base case [by 2016]. 84 Most of the coal-fired capacity identified as ‘at risk’ of 

retirement by SNL is located in parts of the Midwest and the Southeast, as shown in Figure 16, 

reproduced from the SNL study. These ‘at risk’ units are older, smaller and worse performing 

compared to the average coal fleet overall. This capacity has an average unit size of 102 MW,

an average age at retirement of 51 years old, and an average capacity factor of 51 percent.85

 84 SNL’s report identified 323 GW, but included the 9 GW that had been retired in 2012. As of the start of 2013, SNL identified 314 

GW of coal plants in operation as of the beginning of 2013. Of this capacity, 13 GW are not “EGUs,” and therefore are not subject to 

MATS regulations. SNL identified 113 GW of existing coal-fired capacity “which appear to need some retrofits for MATS 

compliance but have neither announced specific plans for major retrofits nor firm retirement plans.” SNL 2013 Coal Retirement

Study, page 12-16.

 SNL’s analysis of announced retirements plus capacity at-risk of retirement is generally consistent with February 2014 study 

published by the Brattle Group, which identifies additional announced retirements totaling 25 GW in 2014 through 2016, as a result 

of the combined effects of low wholesale electricity prices and the cost of compliance with pollution-control equipment. This report 

summarized coal-plant retirements by year: Actual retirements in 2012 (9.0 GW) and 2013 (6.0 GW), totaling 15 GW. Announced 

additional retirements in 2014 (3.5 GW), in 2015 (16.9 GW), and 2016 (4.6 GW, for a total of 25 GW between now and the end of 2016. 

Martin Celebi, Brattle Group, “Coal Plant Retirements and Market Impacts,” February 5, 2014.

85 SNL 2013 Coal Retirement Study, Figure 22.

Table 4

Operating Statistics for ‘At-Risk” Coal Retirements for Select Regions

2011 Capacity 

Factor

Average Heat 

Rate

Average Age at 

Retirement

Average size 

(MW)

MISO (Midcontinent) 52.29 11,598 51 75

PJM (MidAtlantic and Midwest) 40.51 11,414 53 67

Southeast 38.11 10,527 50 169

AZ/NM (Arizona and New Mexico) 65.15 10,953 39 192

SPP (Southwest) 61.44 11,065 48 97

Central 64.79 10,679 60 144

All regions 51.19 11,138 51 102

Source: SNL 2013 Coal Retirement Study, Figure 22.
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Figure 16

Source: SNL 2013 Coal Retirement Study. The note on the bottom of the chart reads: 

States are shaded by total at risk and announced retirements (2012-2021) as a percentage 

of the state’s total 2012 installed capacity (adjusted for availability), as of Nov. 15, 2013.

By now, electric companies and grid operators affected by these retirements have been planning 

to assure compliance as well as system reliability for many years.86 According to EIA, as of the 

end of 2012, “70% of the U.S. coal generating capacity already had the appropriate 

environmental control equipment to comply with the MATS and allow their operation past 

2016. Another 6% plan to add control equipment, while 8% have announced plans to retire. 

Owners of the remaining 16% are faced with the decision of upgrading or retiring their 

plants.”87

 86 See, for example, M. Bradley, S. Tierney, C. Van Atten, and A. Saha, “Ensuring a Clean, Modern Electric Generating Fleet while 

Maintaining Electric System Reliability,” Fall 2011 Update, November 2011; NERC, “2010 Special Reliability Scenario Assessment: 

Resource Adequacy Impacts of Potential U.S. Environmental Regulations,” October 2010.

87 EIA, “Coal-fired power plant operators consider emissions compliance strategies,” March 28, 2014.
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The most recent long-term reliability assessment published by NERC indicates that reserve 

margins will be adequate in upcoming years in all parts of the country, with two notable 

exceptions: ERCOT (the TRE reliability region in Texas) and the MISO region.88 

In ERCOT, for example, relatively near-term resource adequacy issues have been headline news 

for several years, with different parties expressing views about the need for changes in the 

wholesale power market design (which is an “energy-only” market) to assure new investment 

in generating capacity.89 This debate is separate from the state’s response to the MATS rule. In 

its recent analysis of at-risk generating assets, SNL found “no units in ERCOT were identified as 

at risk under the SNL base case...”90 ERCOT’s regulators, grid operator and stakeholders are 

working on solutions to address these low-reserve-margin issues, including instituting 

additional market-design changes, demand-response and other actions.

At the end of 2013, MISO issued a report summarizing power plant owners’ plans for unit 

retirements, and indicated that “25 coal-fired units, representing 8.2 GW of capacity, or about 

one-eighth of the MISO coal fleet capacity, have yet to determine whether they need an 

additional year to comply with MATS.”91 MISO’s summary indicated a potential shortfall of 

capacity by 2016 but only if all of that capacity retired and no significant steps end up being 

taken to increase additional demand-response, energy efficiency, incremental generating 

capacity, and/or transmission additions. The SNL analysis of ‘at risk’ capacity identifies 6 GW 

in MISO, with that capacity at small, old, and inefficient units.92 Some have offered suggestions 

 88 NERC, “2013 Long-Term Reliability Assessment,” December 2013, page 2 and Figure 2 (page 6).

89 For example, “ERCOT projects that reserve margins will fall to 9.8% by 2014, substantially below its current reliability target of 

13.75%. Reserve margins will decline even further thereafter unless new resources are added. Generation investors state that a lack 

of long-term contracting with buyers, low market heat rates, and low gas prices in ERCOT’s energy-only market make for a 

uniquely challenging investment environment. In response to these concerns, the Public Utility Commission of Texas (PUCT) has 

implemented a number of actions to ensure stronger price signals to add generation when market conditions become tight.... The 

key question is whether market prices will be high enough to support entry at an acceptably high reserve margin and associated 

reliability level.” Samuel Newell, Kathleen Spees, Johannes Pfeifenberger, Robert Mudge, Michael DeLucia, Robert Carlton, 

“ERCOT Investment Incentives and Resource Adequacy,” June 1, 2012.

90 SNL 2013 Coal Retirement Study, page 17. 

91 MISO's "3rd Quarter 2013 EPA Survey Update," November 13, 2013, as reported by Jonathan Crawford, “More than 8 GW of 

MISO coal capacity still undecided on compliance path for EPA mercury rule,” SNL Exclusive, November 18, 2013. “An additional 

24 coal-fired units in MISO, accounting for 4.1 GW, that were listed as needing a one-year extension to meet the MATS emissions 

limits were identified as not having submitted an extension request to regulators for approval. The survey had a participation rate 

of 98.5%, with 1 GW of MISO's total 66 GW of coal capacity not included in the results..... On the positive side, the survey showed 

that 35 coal-fired units in MISO, accounting for 11.7 GW, were approved for a one-year extension to comply with MATS. That is out 

of 84 coal units, representing 24 GW, which could possibly need a one-year extension....This is consistent with calls by the EPA that 

state regulators be liberal in granting approval of the compliance deadline extension requests.”

92 See prior table. SNL 2013 Coal Retirement Study, Figure 19. 
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about steps that could be undertaken by parties in the MISO region and states in the near term 

to ensure adequate reserve margins in 2016.93 These include: improving joint planning and 

coordination with neighboring regions with very-high reserve margins (e.g., SPP); increasing

the notice that generators must give of their intention to close temporarily or permanently

(beyond the current 6-months’ notice requirement); and encouraging states to coordinate their 

plans (e.g., for energy efficiency, demand response) with MISO’s. 

MISO is taking steps to assuring resource adequacy in light of MATS regulations. MISO is also 

actively planning for the cost and reliability implications of upcoming Section 111(d) 

regulations (e.g., for additional retirements beyond those likely to occur before Section 111(d)’s 

implementation). For example, MISO has recently refreshed its analysis of the impacts of 

region-wide versus more zonal approaches that MISO states might choose to take with respect 

to managing their future compliance with Section 111(d), and concluded that a more flexible, 

region-wide approach may lower the overall cost of compliance.94 This latter analysis does not 

specifically assess reliability implications of compliance strategies, but it nonetheless invites 

cooperative approaches to design compliance schedules and pathways in light of the realities of 

interstate electricity market operations and reliability considerations. 

In both MISO and ERCOT (as elsewhere in the nation), there are at least five years before the 

full effect of implementation of Section 111(d) will occur. States will have many tools and 

flexible approaches to use in planning for compliance with GHG emission limits, and 

addressing reliability and other concerns. For example, MISO and ERCOT have significant 

amounts of underutilized natural gas combined-cycle capacity whose more-frequent dispatch 

could absorb some of the generation needed in those regions to comply with Section 111(d). 

(See Figure 6.) Many states in the MISO region rely on integrated resource plans to assure 

resource adequacy, and these states can take steps in near-term planning cycles to assure both 

adequate capacity and generation that emits lower CO2 emissions. As a single state RTO, 

ERCOT and Texas regulators have demonstrated an ability to take aggressive action to 

implement policies deemed to be important for the state.95

 93 For example: John Moore, NRDC, “We Can Have Both a Reliable Grid and a Cleaner Environment,” December 9, 2013. 

http://switchboard.nrdc.org/blogs/jmoore/we_can_have_both_a_reliable_gr.html. 

94 MISO, “Refresh of MTEP-10 Carbon Analysis,” presentation to PAC Meeting, February 19, 2014.

95 Note that Texas/ERCOT undertook steps in the past decade to create incentives for investment in renewable energy and highvoltage transmission facilities. Today, Texas has the highest amount of wind power capacity (12,355 MW as of the 4th quarter of 

2013). It has more wind capacity than the combined amount in the two states with next-highest amount of wind generating capacity 
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New Generating Capacity Proposals 

Given the relatively low price of natural gas, the “fuel of choice” for new power generation 

capacity planned and under construction by electric utilities and independent power producers 

has shifted to natural gas and renewable power plants, and away from coal. Figure 17 shows 

the location of capacity under construction (by state). Half of the power plant capacity under 

construction is at gas-fired power plants, with another fifth at renewable facilities. There are 

five new nuclear reactors under construction in the Southeast. Of the other projects in 

advanced development (e.g., well along in permitting but not yet under construction), 

approximately one-third of the capacity is at gas-fired power plants, and another 42 percent is 

at renewable projects. Figure 18 shows the expected net changes in generating capacity from 

2013 through 2017, by fuel type and by NERC region. These data reflect the effect of new plants 

under construction or planned (especially natural gas-fired capacity and renewable projects), as 

well plant retirements (especially coal, oil, and nuclear retirements). 

Figure 17

Generating Capacity Under Construction by State as of March 2014

Source of data: SNL Financial

 

(California, with 5,830 MW, and Iowa, with 5,178 MW). American Wind Energy Association, “U.W. Wind Industry Fourth Quarter 

Market Report, 2013,” page 6. Since 1999, when Texas restructured its electric industry, there has been $14.3 billion investment in 

transmission, with 9,141 new circuit miles of transmission improvements, with another 2,558 circuit miles and $3.7 billion of 

planned transmission. ERCOT Quick Facts, 2014. Currently, Texas has 5,833 MW of power plants under construction, and another 

1,671 MW in advanced development, most of which is scheduled to come on line in 2014 and 2015. Of this, 3,940 MW is gas-fired 

capacity. Charlotte Cox, “Nearly 6 GW of capacity under construction in ERCOT, with 42 GW planned,” SNL Data Dispatch, 

February 26, 2014.
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Figure 18

Changes in Capacity by Fuel and by NERC Region from 2013 to 2017

(Showing Capacity Additions and Retirements)

Source of data: SNL Financial (as of March 2014)

Implications of the Changing Electricity Resource Mix

The significant changes underway in the electric industry (and described above) set the stage 

for states’ planning for compliance with Section 111(d). To a large degree, many of these 

changes create breathing room for compliance with upcoming GHG regulations while also 

maintaining electric system reliability. 

Around the country, the changing conditions reflect the combined effects of low natural gas 

prices, significant under-utilized capacity at existing gas-fired power plants around the country, 

relatively slow demand growth, continuing opportunities for cost-effective energy efficiency, 

retirements of older and less efficient coal-fired generating capacity, new natural-gas-fired and 
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renewable energy capacity under construction, and substantial progress toward compliance 

with MATS by 2016. 

The conditions create opportunities for states to maintain system reliability as they plan for

compliance with Section 111(d). For example, the presence of under-utilized capacity at 

existing gas-fired power plants and the outlook for relatively low natural gas prices allow for a 

relatively affordable pathway to lower GHG emissions, but doing so must be accompanied with 

advanced planning to assure that natural gas supplies can be delivered and/or stored reliably as 

electric systems increase their reliance on natural gas. (New England has already had to 

accelerate its planning to respond to this type of situation while assuring reliable system 

operations.96) Federal regulators and policy makers, grid operators, and many others are 

focusing on this question of gas-deliverability and harmonization of electric and gas markets.97 

Continued attention to this issue will be important for reliability, regardless of the 

implementation of Section 111(d).

Similarly, new gas-fired power plants, new renewable projects, and new nuclear capacity 

additions will further support reliable compliance with Section 111(d). That said, states (and 

the federal government) should not assume that zero-carbon generating capacity at existing 

nuclear stations will automatically be available in the future, especially at merchant nuclear 

plants located in organized markets which are facing significant financial pressure to remain in 

operation.98 Planning for reliable and affordable compliance with Section 111(d) should 

proactively address market reforms and other policies (including design of SIPs) to retain zerocarbon electricity supplies.99

In the parts of the country – like MISO and ERCOT – with pre-existing reliability challenges, 

Section 111(d) will only exacerbate that situation if nothing is done to address them. Clearly, 

 96 ISO-NE has for the past two years focused attention on ways to ensure winter reliability in an electric system with high reliance 

on natural gas, pipeline capacity constraints, and lack of incentives in the market design to ensure gas-fired generators have fuel to 

allow them to operate.

97 See, for example, NERC, “2013 Long-Term Reliability Assessment,” December 2013, page 2 and Figure 2 (page 6); Questions of the 

leadership of the House Energy and Commerce Committee to MISO, PJM, NYISO, and ISO-NE, March 27, 2014; FERC notice of 

proposed rulemaking on Coordination of the Scheduling Processes of Interstate Natural Gas Pipelines and Public Utilities, 

146FERC¶61,201, 18 CFR Part 284, Docket No. RM14-2-000, March 20, 2014; Testimony of Acting Chair Cheryl LaFleur and 

Commissioners Philip Moeller, John Norris and Tony Clark before the House Energy & Commerce, Subcommittee on Energy and 

Power, valuating the Role of FERC in a Changing Energy Landscape, December 5, 2013.

98 See my forthcoming paper: S. Tierney, “Today’s Nuclear Fleet: What Role in the Nation’s Clean, Affordable and Reliable Power 

Strategy?” 

99 See further discussion below on “outside the fence” actions to reduce GHG emissions. 
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the industry, state and federal regulators, grid operators, and many other stakeholders are 

working to address these pre-existing reliability challenges, through a wide range of solutions. 

These options include potential market reforms, new power plants, new power lines, new gas 

transmission, more efficient use of existing transmission and distribution systems for electricity 

and gas, increased investment in demand-side measures, and other things. 

Section 111(d)’s compliance period is far enough in the future that there will be time for states 

and regions to transition toward lower GHG emissions while retaining electric reliability. And, 

as described previously, Section 111(d) affords broad flexibility to the states to respond to 

upcoming GHG emissions requirements in a way that preserves electric system reliability.

Planning for Compliance with EPA Guidance Under Section 111(d) of the CAA 

Breadth of Options Available to the States in Developing Section111(d) 

SIPs 

Even in advance of EPA’s proposed guidelines (June, 2014), it is already clear that states will 

have discretion to consider and propose a wide range of options as part of their plans. EPA 

officials have signaled their intention to allow each state to submit a SIP that enables them to 

comply with EPA’s guidance and tailor their approach to meet multiple state-specific goals, 

including affordable and reliable electricity supplies.100

It is likely that as long as a state is able to demonstrate that its SIP is at least equivalent to EPA’s 

guidance (in terms of reducing GHG emissions from affected power plants), then that state will 

have significant flexibility in developing its preferred package of policies. For example, SIPs 

may create incentives for EGUs and NGCCs to reduce emissions “within the fence” line of the 

covered units themselves. SIPs may include elements that affect actions occurring “outside the 

fence,” where there is a strong connection between those actions and emission reductions at 

plants covered by Section 111(d). (See Figure 19.) This combination of options creates 

significant opportunities to plan for reliability while also planning for cost-effective GHG 

emissions reductions. 

 100 For example, remarks of Administrator Gina McCarthy, Acting Administrator for Air and Radiation Janet McCabe and Senior 

Air Advisor Joseph Goffman at the meeting of the National Association of Regulatory Utility Commissioners, February 7th and 11th, 

2014.
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Figure 19

Inside the Fence Options

“Inside the fence” actions differ in terms of engineering, cost and feasibility of potential GHG 

reductions. For example, Dr. James Staudt has identified two categories of actions that can 

accomplish GHG emissions reductions at existing coal plants: (a) heat rate improvements at the 

units, which improve the efficiency of the boiler and/or steam plant (in terms of the amount of 

fuel it needs to burn to generate a unit of electricity), or reduce auxiliary loads at the station;

and (b) conversion to a less carbon-intensive fuel, by fuel-switching, co-firing and/or reburn 

approaches.101 These engineering-based approaches all focus on reducing a plant’s rate of GHG 

emissions relative to its production of electricity. 

 101 Dr. James Staudt, “Reducing CO2 Emissions from Fossil Fuel Power Plants,” presented to the Bipartisan Policy Center workshop 

on Section 111(d), December 6, 2013. Dr. Staudt has identified the various engineering options for reducing CO2 emissions from 

existing coal plants: (1) “Potential Approaches for HR [heat rate] Improvement: Coal Drying (esp., lignite coals); Variable Speed 
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States seeking these types of engineering approaches could require each affected EGU or NGCC 

to reduce its emissions by a certain percentage, or meet a maximum emission rate for 

CO2/MWh. A state could impose a common standard to all plants in a category of EGUs, or it 

could tailor the requirements to particular conditions at different plants (reflecting, for example, 

their remaining useful life, or their role in providing local reliability).

The Department of Energy’s National Energy Technology Laboratory (“NETL”) has studied the 

opportunities for “inside the fence” power-production efficiency improvements, and has 

estimated that they could improve power plant performance (and thereby reduce coal 

combustion and GHG emissions) in the range of 1 percent to as high as 12 percent, depending 

upon the particular set of engineering actions taken at different coal-fired facilities.102

Other SIP approaches that could lead to “inside the fence” GHG reductions at EGUs and 

NGCCs would include modifications to the operating permit of particular plants so as to limit 

the dispatch and generation output of one or more units. It is not uncommon for power plants 

to have certain operational limits. Sometimes these limit the unit’s overall annual output to an 

amount equivalent to 30 days of output at full power.103 Or the unit may be dispatched only 

when local system reliability requirements demand operation of the generating unit (such as 

shortage events in the summer or winter period).104 Such inside-the-fence operating constraints 

 

Drives; Centrifugal to Axial fan conversion; Steam turbine modifications; Intelligent soot-blowing system; New APH seals; Repair 

boiler casing and duct in-leakage; Condenser cleaning. [2] Using less Carbon-Intensive Fuels: Conversion (convert to 100% gas), 

with a capital cost of ~$80/kW (with gas on site); Cofiring/Reburning (10-15% gas) Modest cost (somewhat higher for reburn), 

assuming gas is on site, with co-benefits from reducing NOx emissions as well.” 

102 A recent study by the NETL evaluated four efficiency improvement projects, the three of which are ‘off-the-shelf’ technologies: 1. 

Coal Pulverizer Improvement; 2. Condenser Improvement; 3. Steam Turbine Upgrade; and 4. Solar Assisted Feedwater Heaters. 

NETL’s analysis found opportunities to reduce GHG emissions in the range of 1.7 to 6.9 percent, with the highest reduction 

potential at less-efficient power plants. NETL, “Options for Improving the Efficiency of Existing Coal-Fired Power Plants,” 

DOE/NETL-2013/1611, Final Report, April 1, 2014, pages 1-4. Prior NETL studies examined the effect of efficiency improvements: 

NETL, “Reducing CO2 Emissions by Improving the Efficiency of the Existing Coal-fired Power Plant Fleet,” DOE/NETL-2008/1329, 

July 23, 2008. By examining the efficiency of the top performing coal-fired power plants relative to the efficiency level of the fleet on 

average, NETL calculates that if changes could be made across the fleet to bring all of the plants up to the top 10 percent 

performance level, then the CO2 emissions associated with a constant level of MWh generated could be reduced by approximately

12 percent. This conclusion was further examined in NETL, “Improving the Efficiency of Coal-Fired Power Plants for Near Term 

Greenhouse Gas Emissions Reductions” (DOE/NETL-2010/1411), April 16, 2010. NETL concluded that the use of a combination of 

aggressive refurbishment and improved operation and maintenance at existing coal plants could improve the average fleet’s overall 

efficiency.

103 This approach was used in the air permit approvals issued in 1999/2000 by the Massachusetts Department of Environmental 

Protection for capacity expansion at Mystic Station, in which a new 1500-MW NGCC was permitted to operate in conjunction with 

imposition of 30-day operating limits on several other older generating units that also existed at the same station. 

104 For example: Several years ago, Exelon Corporation decided to retire units at two generating stations in Pennsylvania (the 

Eddystone and Cromby units) due primarily to economic factors. In its analysis to determine whether such retirements would lead 

to system reliability problems, the grid operator (PJM) determined that in the absence of transmission upgrades, retirements of 
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would affect the terms and conditions of plant dispatch, causing the grid operator (e.g., the local 

vertically integrated utility, or the RTO) to dispatch other power plants to make up for power it 

might otherwise have wanted to generate at the restricted unit. A state (or an owner of multiple 

power plants within the state) might find it economically preferable to impose operating limits 

on Unit A (with relatively high GHG emissions per MWh) and to dispatch Unit B (with higher 

operating costs but lower GHG emissions per MWh), than to require both Unit A and Unit B to 

invest in engineering actions leading to heat rate improvements at both. The permit limitation 

on Unit A would be the action inside the fence of that plant, and the electricity requirements for 

the system could be satisfied by electricity generation at Unit A and B. 

In theory, a state could identify plants that provide some form of important functionality to the 

system but produce GHG emissions that are relatively expensive to control through one of the 

types of actions above. The state could introduce a limitation on that unit’s output over an 

annual period of time such that its MWh and GHG emissions would be capped, while retaining 

its availability during high load periods, and with its MWh replaced at cleaner unit(s) during 

periods of low or medium electric demand. The latter approach would be one type of tool that 

states could use to assure that the compliance pathways demonstrated in their SIPs take into 

account both GHG emissions reductions and reliability concerns. 

Outside the Fence Options

A much wider set of cost-effective emissions reductions could result from SIP elements 

involving actions in the electric system occurring outside the fence of a specific unit 

subject to Section 111(d).105 

 

those units would lead to violations of security standards. Exelon entered into agreements with PJM and with the state air 

regulatory office so that the plant could remain on line pending those transmission upgrades, but allowing the units to be 

dispatched by PJM only when needed for reliability purposes. Prepared Testimony of Kathleen L. Barrón, Vice President, Federal 

Regulatory Affairs and Policy Exelon Corporation, before the FERC, Reliability Technical Conference Docket No. AD12-1-000 (etc.), 

November 11, 2011. This agreement was referenced by CATF in its 2011 proposal for “reliability-only dispatch”: “to minimize 

health risks, we propose limiting the operation of any such units to the brief periods when required to preserve reliability, i.e., when 

no other resource is available to meet the electricity need. Such a targeted “Reliability---Only Dispatch” approach can serve the 

goals of both the Federal Power Act’s reliability framework and the Clean Air Act’s express concern for near term reductions of air 

toxics and maximum protections for public health and the environment.... Through such customized solutions to identified 

reliability issues and tailored to specific, local circumstances, the Cromby---Eddystone example demonstrates that when a plant 

must continue to operate for some period due to reliability needs, it can be limited to running only to meet those reliability needs.” 

John Hanger, “Reliability Only Dispatch: Protecting Lives & Human Health While Ensuring System Reliability,” Clean Air Task 

Force, pages 5, 23. 105 In the example above, Unit B’s redispatch to replace power that would otherwise have come from Unit A is an example of an 

outside-the-fence counterpart action to the inside-the-fence action at Unit A.
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Emission Averaging and Carbon Budgets 

Many observers have examined the economic and emissions trade-offs associated with 

engineering-approaches versus more market-based compliance approaches. For 

example, Dallas Burtraw and Matt Woerman compared the cost to achieve a ton of CO2

emission reduction through inside-the-fence actions versus outside-the-fence options 

enabled through a ‘tradable performance standard.’ Starting with estimates of the cost 

to accomplish the types of inside-the-fence options, they determined that with the 

money it would take to accomplish 4 percent reductions in GHG emissions inside the 

fence, it would be possible to achieve four times the amount of total emissions 

reductions if power plants were allowed the flexibility to trade emissions reduction 

opportunities.106 

They and others107 have analyzed variations on this approach of allowing a state to 

comply with EPA guidance by creating a rate-based or mass-based tradable currency, 

either of which could allow units with a higher level of GHG emissions per MWh to 

trade with those having a lower-than-average level of GHG emissions per MWh. 

The Philips/CATF 2014 study explains how the use of a mass-based standard (converted

from an original rate-based standard) has numerous benefits because it overcomes 

certain market distortions that might arise with use of a rate-based standard alone. 

“First, the positive price on carbon emissions and lack of production incentives means 

they would diminish or avoid the previously described emission rebound, seams and 

longer term regulatory transition concerns associated with most rate-based approaches. 

Also, they would give states another proven, practical compliance pathway and greater 

flexibility than if every state were restricted to complying through a mandatory emission 

rate standard. ...Further, the accounting rules required to reflect the impact of new 

 106 A “specific emissions rate improvement averaged over a larger set of generators reduces the actual emissions change. A marginal 

abatement cost criterion to compare policy designs suggests cost-effectiveness across sources. This criterion can quadruple the 

emissions reductions that are achieved, with net social benefits exceeding $25 billion in 2020, with a 1.3 percent electricity price 

increase.” Dallas Burtraw and Matt Woerman, “Technology Flexibility and Stringency for Greenhouse Gas Regulations,” Resources 

for the Future, July 2013, executive summary.

107 For example, Phillips/CATF 2014; Christopher Van Atten, “Structuring Power Plant Emissions Standards Under Section 111(d) of 

the Clean Air Act – Standards for Existing Plants,” MJ Bradley & Associates, October 2013; National Climate Coalition, “Using EPA 

Clear Air Act Authority to Build a Federal Framework for State Greenhouse Gas Reduction Programs,” September 2013.
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renewable facilities, energy efficiency programs and nuclear uprates, would be much 

more straightforward under a mass-based system than a rate-based system.”108

More generally, mass-based standards can be translated into a total amount of GHG 

emissions “budgeted” or allowed to occur in a state. A budget could apply to all units 

collectively within a state, or to groups of units within a state, or to the units in multiple 

states that have compacted with each other. Chris Van Atten has described how a state 

budget approach might work: “In proposing a state budget approach, EPA could still 

develop a rate-based performance standard and then translate that performance standard 

into state budgets, giving each individual state the choice in terms of whether to impose a 

rate-based performance standard or state-wide emissions budget. In guidance to states, 

EPA could: define the appropriate baseline period (i.e., the MWh data used in converting 

the lbs./MWh standards to tons); determine whether and how future economic growth 

should be factored into the calculation of the budgets; and define trading rules for states 

that elect to allow trading as a compliance mechanism.”109

Demand-side and non-carbon emitting options

States could take action to create incentives specifically aimed at adding and/or retaining zerocarbon electricity supply through adoption of a tradable emission standard (“TES”) or clean 

 108 Also, “Rate-based approaches...are typically established so that some covered generating sources have emission rates 

above the standard and others have rates below the standard. Generating sources with emission rates above the standard 

must undertake actions to come into compliance. Generating sources with emission rates below the standard have a 

financial incentive to increase their production, assuming an emission credit trading program, because every additional 

unit of generating output “earns” that generator additional emission credits which have a financial value under the 

trading program. In the case of a single blended fossil rate standard covering both coal and gas generation, NGCC units 

would typically be awarded emission credits whenever they generate output. This would allow gas units to sell power 

for less than their direct variable fuel and O&M costs. The value of the credits earned by generating additional output

partially offsets the unit’s variable cost of production, reducing the marginal cost of dispatch and making the unit more 

competitive with other sources of generation in that power market without comparable production incentives. Such 

production incentives can lead to unintended adverse consequences..... create what often are referred to as “seams” 

conflicts at the borders of mass-based trading programs such as RGGI and other mass-based programs, emissions 

“rebound”, and greater difficulty in transitioning to longer term national carbon policies.” Phillips/CATF 2014 (pages 8-9, 

18).

109 Also: “States would ... have the flexibility to determine their preferred method for meeting their assigned budget, including the 

option of relying on a system of transferable emissions permits. If states elected to implement a trading program, power plant 

operators would track their CO2 emissions and surrender an emissions permit for each ton of CO2 released to the atmosphere.....

For example, a state could propose to give each company operating in the state a set number of emission permits. Under such a 

scenario, a regulated utility might advocate for a company-wide emission budget that it could reflect in its integrated resource 

plan.” Christopher Van Atten, “Structuring Power Plant Emissions Standards Under Section 111(d) of the Clean Air Act – Standards 

for Existing Plants,” M. J. Bradley & Associates, October 2013, pages 17-18. 
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energy standard (“CES”). When applied to owners of generating units in an area, the TES could 

be a mechanism through which generation of zero- and low-carbon electricity by suppliers (old 

and new) would create carbon-free electricity credits, for sale to others. For example, a state (or 

a group of states) could set assign a common target CO2/MWh to all generating units in the 

state, and then allow generators with different CO2/MWh emissions rates to buy/sell their CO2-

emission permits. A provider of energy efficiency or demand-side measures could similarly 

generate CO2-emission permits. It would be important that such a standard be at or below the 

emissions rate achievable by NGCCs so as to avoid potential wholesale price distortions that 

would result from natural gas units generating rate credits by offering a price below their 

variable cost of generation (as could arise as described above by Phillips/CATF 2014). 

By contrast, a state could apply the CES to sellers of retail power supply (e.g., load serving 

entities (“LSEs”)) to demonstrate that their overall supply portfolio satisfies a standard 

emissions amount (in much the same way that an RPS requires LSEs to include renewables as a 

percentage of their supply portfolios). A CES could cover all existing and new generation, thus 

allowing sellers of zero-carbon supply to find revenue streams to remain in and/or enter the 

market.

Allowing zero-carbon resources to capture the economic value of that attribute through 

efficient market-based transactions with other generators provides the state with the ability to 

arrive at a least-cost, reliable pathway toward overall electric system compliance. 

RTO Dispatch Constraint

Another recent variation on the outside-the-fence approach has been suggested for one multistate RTO (or Independent System Operator (“ISO”)) region. In this approach, the RTO would 

expand the criteria it uses to determine the dispatch of power plants so that in addition to 

security-constrained economic dispatch, it would also use a total system-wide constraint on CO2

emissions. As described by its authors, this concept includes the following elements: 

Translate EPA requirements into ISO-level targets on CO2 emissions, ideally with 

a single long-term target (e.g. X% reduction over 2000 level, by 2030). Short/

intermediate term targets may be necessary to guide the “emissions path,” but 

could limit flexibility of meeting the targets and possibly be less cost effective. 

ISO sets an initial path of “carbon values,” that are used in dispatching (based on 
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emissions profiles and bid offers) to reach the expected regional target. Plant 

dispatch minimizes total cost while meeting reliability and CO2 constraints. The 

resulting power market prices, paid by load, reflect the emission constraints. 

Generators are charged the per-unit carbon value for their CO2 emissions. 

Revenues collected are returned to load on a non-variable basis (maintaining 

proper price signals for demand-side resources). ISO adjusts carbon value path 

carefully when updated projections of emissions deviate significantly from 

original assumptions.110 

These various mass-based approaches allow for cost-effective and administratively efficient 

means to reduce GHG emissions across the power plants dispatched in a system. And they 

allow for system conditions, such as reliability considerations, to factor into the manner in 

which the grid operator dispatches its plants to meet system requirements in regions with 

organized wholesale electricity markets. 

Figure 20 shows (with color shading) the parts of the U.S. where an RTO (or ISO) is the grid 

operator and administrator of an organized wholesale market.111 In these areas, the RTO has

responsibility for centrally dispatching power plants that are owned or controlled by market 

participants (e.g., utilities (including investor-owned, coops, publicly owned utilities) and IPPs) 

in that region.112 In states (or parts of states) which are not part of an RTO, the utility typically 

is responsible for centrally dispatching the power plants it owns or controls. In some states 

with a traditional vertically integrated electric industry structure, most if not all of the 

generating capacity is owned by utilities. The states with more than two-thirds of their 

generation produced at utility-owned power plants are shown with a pattern (dotted) on Figure 

 110 Judy Chang, Jurgen Weiss, Yingxia Yang, Jon Brekke, and Will Kaul, “A Market-based Regional Approach to Implementing 

EPA’s GHG Emissions Regulation,” Brattle Group and Great River Energy, January 2014.

111 “Presently, RTOs/ISOs geographic footprint covers approximately 2/3rds of the nation, encompassing regions that cover all or 

parts of 38 of the 50 states plus the District of Columbia. ISOs/RTOs serve approximately 75% of national demand.” ISO/RTO 

Council, “EPA CO2 Rule – ISO/RTO Council Reliability Safety Valve and Regional Compliance Measurement and Proposals,” 

January 31, 2014.

112 “ISOs/RTOs centrally dispatch power plants within their footprint based on the marginal cost of operation of each individual 

unit as reflected in bids submitted to the ISO/RTO on a day ahead basis.[fn] By dispatching generation resources across the I 

ISO/RTO footprint based on the marginal cost to produce the next MW of electricity, the economic efficiencies of the generation fleet 

is maximized for each hour of the operating day across the entire RTO footprint.[fn] Supply bids submitted by generators 

effectively internalize environmental compliance costs while still ensuring least cost compliance with environmental 

requirements.[fn] The regional centralized dispatch undertaken by ISOs/RTOs is known as Security Constrained Economic 

Dispatch (SCED).” ISO/RTO Council, “EPA CO2 Rule – ISO/RTO Council Reliability Safety Valve and Regional Compliance 

Measurement and Proposals,” January 31, 2014.
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20. Figure 21 shows the ranking of states according to their reliance of utility-owned (and not 

IPP-owned) generation. 

Figure 20

Footprint of RTOs and States’ Reliance on Utility versus Non-Utility Power Generation

 Source: EIA Generation by Type of Producer and by State, 2012.

Figure 21

States’ Reliance on Utility-Owned Generation as a 

Percent of Total Power Generation in the State (2012)

Source: EIA, EIA Generation by Type of Producer and by State, 2012.
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Recent modeling by Bruce Phillips for the CATF examines how two alternative policy designs 

for an emissions standard would work in a regional dispatch. As shown previously in Table 1, 

the “CATF 2.0” options that they modeled were: (a) a single mass-based standard applicable to 

all fossil power plants, and (b) an alternative that has a mass-based budget for emissions from 

coal-fired power plants and a rate-based standard for emissions from gas-fired power plants 

(which they have called the “Mass-Based Coal” budget as a short hand name).113 Phillips’ 

analysis found that both “approaches would reduce emissions through a mix of compliance 

actions: by reducing the heat rates (and consequently the emission rates) of coal units; 

displacing high emission rate coal generation with lower emission rate gas generation through 

an emission credit trading program; retiring coal generating capacity, and reducing electric 

demand through customer response to higher electric prices. Of these, the emission reductions 

from fossil dispatch represent the largest single source of reductions, in both cases 

approximately 70 percent of total compliance.....Heat rate improvements, coal retirements and 

electric price response comprise the remainder, with approximately 10 percent, 15 percent and 5 

percent respectively.”114 The analysis also concluded that these policies would lead to 

relatively similar changes in generation and capacity mix: “Under the mass-based coal case, 42 

GWs of coal capacity retire due to the policy (that is, relative to what would otherwise be 

expected in 2020), average national coal capacity factors decline from 67 to 58 percent and 

average national NGCC capacity factors increase from 48 to about 65 percent. Under the massbased fossil case, 37 GWs of coal capacity retire, average national coal capacity factors decline to 

58 percent and average national NGCC capacity factors increase to 63 percent.”115 

 113 Phillips/CATF 2014, page 17.

114 Phillips/CATF 2014, page 21.

115 Phillips/CATF 2014, page 21.
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Figure 22

Modeled Changes in Generation Output, Capacity Retirements and Capacity Factors of CoalFired and Gas-Fired Power Plants under Two Alternative CATF Policy Designs

Phillips/CATF 2014, page 22.

This analysis suggests that there will be capacity retirements that are manageable, especially in 

light of the existence of underutilized NGCC capacity in all regions of the country, along with 

inherent flexibility in the Section 111(d) framework that will allow states to tailor their SIPs to 

local conditions and reliability requirements. , 

Outside-the-Fence Models Approaches: Examples to ensure reliable and 

economic compliance in states with different electric industry structures

Because states have different electric industry structures that affect how groups of power plants 

are dispatched to supply electricity at different times during the year, states will likely seek to 

take this factor into account as they consider different options for and inside-the-fence and 

outside-the-fence compliance approaches.

For example, there are two key features of industry structure: (1) presence or absence of an 

RTO; and (2) the extent to which utilities versus merchant generators (IPPs) dominate the 

power generation – seem relevant for how a state might consider structuring its SIP to include 

relatively cost-effective outside-the-fence policy elements. These two features essentially are 

proxies for the extent to which power plants owned by different entities participate in a 

common system for generation dispatch within a state (or across a region). 
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Consider the following examples as ways that a state could develop an economically efficient 

tradable compliance mechanism and in so doing, support more cost-effective, reliable 

compliance with GHG reduction targets. All of these examples are based on an assumption that 

EPA will issue state-specific guidance that reflects either a blended target emissions rate for all 

fossil-fuel generation (EGUs and NGCCs) or a separate one for each fuel, with a multi-year 

period over which a state needs to make reasonable progress toward compliance. The examples 

also assume that the state may use a variety of tools to achieve the targeted emissions 

reductions, many of which accommodate planning to mitigate electric system reliability 

concerns.

Example 1: Trading Among Power Plants Owned by Common Owner within a Single State: 

In this example, the state has a traditional electric industry structure, with several vertically 

integrated utility companies owning power plants in that state. These utilities do not belong to 

an RTO. Several of the utilities have 

more than one generating unit 

subject to Section 111(d) and these 

units have different emissions rates 

(CO2/MWh). A simple trading 

approach the state could adopt in its 

SIP would be to allow emission 

trading across all of the units owned 

by a single utility. Each owner 

could determine the set of actions 

through which it would maintain 

reliability and bring its fleet into overall compliance with the target. These approaches could 

include redispatch of existing fossil plants to find the optimal mix of production, investment in 

a zero-carbon generating source, and/or other actions to produce a blended lbs of CO2/MWh 

rate consistent with the state target. 

Let’s assume further that one of these utilities had recently made investments in one of its coalfired power plants to enable it to comply with MATS. To retain the economic and reliability 

value of that investment, the utility would be allowed (through the state’s SIP) to operate that 

plant for more years into the future, as long as these emissions are offset somewhere else in the 

system. Perhaps this could be accomplished by relatively aggressive investment in energy 

efficiency to reduce the utility’s MWh requirements that would otherwise have been met by its 
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marginal and high-emitting generating unit(s) and in so doing offset the emissions from plants. 

Perhaps another utility wanted to retain its ability to operate an otherwise relatively inefficient 

power plant in order to manage an overall resource adequacy issue. This utility could propose 

a limit on the operating permit of that power plant, in order to maintain it on the system for 

reliability reasons during seasonal peak energy demand, while also committing to lower output 

at that plant. 

To allow different sets of actions for different utilities that reflected each one’s particular 

circumstances, the state could structure its SIP to give each utility the ability to manage the 

cumulative emissions associated with its fleet’s power generation over a multi-year time period 

in order to satisfy economic and reliability requirements efficiently while also complying with 

the necessary GHG emission reductions. 

Example 2: Trading Among Power Plants Owned by Multiple Owners Within a Single State. 

In this example, another state 

with a similar industry 

structure (no RTO, power 

plants owned by multiple 

companies) decides that it will 

propose a SIP that would 

permit intra-state trading 

among all of the power plants 

subject to Section 111(d) plants 

within the state. The state 

could use the EPA’s state-wide 

target CO2/MWh rate(s) for that 

state, and allow owners of 

plants with emissions higher than that rate to trade with plants lower than that rate. The state 

could either use the tradable-rate-based model or a mass-based approach, with a ceiling on total 

emissions during a time period and with tradable allowances that companies were either given 

for free or allowed to purchase through an auction.

Different states in this situation might approach this allowance allocation differently. One 

might chose to give away for free the allowed statewide average target emissions rate (e.g., 

CO2/MWh). The plants with higher-than-average emissions would purchase enough CO2

credits to accomplish the target blended rate. The generator with lower-than-average emissions 
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could sell off the difference between its actual rate and the target rate allocated to it, without 

taking any further action. Another generator with economically attractive opportunities to 

make improvements and/or add low-carbon resources to bring its own fleet average even 

further below the statewide target would have even more CO2 credits to sell. 

By contrast, another state could decide to allocate higher-than-average emissions credits to one 

owner of Section 111(d) units with relatively high emissions, and a different allocation rate to 

another owner, reflecting equity, stranded costs, electricity price impacts and reliability 

considerations across the different service territories. Another state might decide that each 

owner of a Section 111(d) generating unit would need to buy all of its needed CO2 credits 

(rather than receiving even the average initial allocation for free), and then use the proceeds 

from the sale of those CO2 credits to offset consumers’ price impacts or to fund energy efficiency 

program to reduce the overall MWh requirements, achieve CO2 emissions reductions as a result. 

Additionally, the state could choose whether to allocate the target CO2/MWh rate to only 

Section 111(d) generating units, to all fossil units, or to all generating sources (including ones 

with zero carbon electricity production). The former would tend to lead to trading among fossil 

units only, and the state could accompany this model with other SIP elements (e.g., increased 

RPS requirements; new nuclear unit upgrade; a new TES or CES) to increase and/or maintain 

zero-carbon electricity as a displacement of MWh produced at fossil units. The latter would 

tend to rely on an economically efficient mechanism for lowering CO2/MWh through creating 

value for zero-carbon energy options and retaining capacity for reliability and diversity 

purposes.

A company could manage its own in-state fleet by using its preferred combination of inside-thefence options, redispatch of its own power plants, procurement of zero-carbon MWh, and 

purchases/sales of tradable CO2 credits with other power plant owners in the state. The 

tradable credit or tradable allowance would end up having a price reflecting economic 

investments in CO2 reductions across the state’s set of power plants. 

Such approaches could accommodate many different operational/reliability issues 

economically. The utility with potential stranded investment in MATs compliance, for example, 

could purchase output (and credits) from another power plant owner’s lower-emitting but 

otherwise underutilized generator. The power plant owner that faces a curtailment of natural 

gas supply during a winter shortage condition could run a unit with higher emissions at that 

time and offset that unit’s CO2 rate with purchases of a tradable credit from another power 

plant with lower-than-average emissions. Again, the main point is that states could formulate 
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their SIPs to allow each power plant owner to manage the cumulative emissions associated with 

its fleet’s power generation over a multi-year time period so that the average CO2/MWh target 

is met, along with all operating and resource-adequacy requirements necessary for system 

reliability.

Example 3a: Trading Among Power Plants in Multiple States That are Owned by a Common 

Holding Company. In this example, electric generating units located in two states are owned 

by a common parent 

company (Holding 

Company D, in the figure) 

that operates all of its 

power plants as a single 

integrated system for 

resource adequacy, 

operational security and 

economic purposes. From 

the point of view of system 

operations, Holding 

Company D dispatches 

plants in both states 

according to security-constrained economic dispatch principles, and shares the economic value 

of that common system with customers in both states. In this example, there are also other 

utility companies and IPPs (Companies A, B, C, and D) that own power plants in the relevant 

state. 

Let’s assume that each state has been given a different GHG emissions’ rate target in EPA’s 

guidance. Each state decides to include in its SIP a mechanism that allows for trading within 

company-owned fleets or across companies within a state (as in Examples 1 and 2). But for the 

holding company, the two states decide that they would like to retain the efficiencies associated 

with that company’s multi-state dispatch. So the two states enter into a formal agreement to 

allow for interstate trading specifically for Holdco D located in both states, thus enabling it to 

continue to operate its fleet on a single system basis. (The two states may or may not allow 

Holdco D to trade with Companies A, B, C, and E.) To the extent that such multi-state dispatch 

of Holdco’s plants means that State X’s CO2/MWh average rate that is higher over the relevant 

time period than it otherwise would be under single state operation, then the states’ agreements
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would need to establish a mechanism for tracking and offsetting such emissions through deeper 

reductions in State Y.

This example suggests a way for states to collaborate voluntarily in the design of their SIPs, to 

tailor elements to fit the structure of their electric industry and to honor long-standing economic 

and reliability relationships among various utilities and other industry institutions.

Example 3b: Trading Among Power Plants Owned by Multi-State Holding Companies and 

With the States Having Different Appetites for Other In-State Trading. This example is a 

slight variation on the same theme as Example 3A. Here, the three states still get different 

CO2/MWh targets from the 

EPA, in light of the 

different conditions in 

those states. The three 

states sharing the holding 

company agree formally to 

allow that company’s 

subsidiary companies in 

the three states to 

participate in a common 

interstate CO2 credittrading program. In 

exchange for allowing that 

flexibility, the states agree 

to require the holding 

company to achieve more GHG emissions reductions in its fleet than it would otherwise absorb 

if each state gave the holding company each state’s statewide average CO2/ MWh target. For 

power plants owned by entities unaffiliated with the holding company, one of those states 

allows other trading within the states, but the others do not. 

The three-state agreement is included in each of the three states’ SIPs, and it details the 

mechanism through which the states will credit/offset/true-up emissions located in one state 

against the other states’ compliance requirements. The three states could establish a multi-state 

cap over that holding company’s generating resources. The holding company has the ability to 

meet its target through a combination of dispatching its power plants, incremental purchase of 
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power generated at low-carbon resources, energy efficiency, demand response or other actions 

to reduce CO2/MWh across the three states. The other company in State Y has the same ability 

to use its fleet to achieve a blended average emissions rate that complies with EPA guidance for 

the state. 

Again this example suggests tailored strategies to reflect economic, reliability and other 

conditions unique to a set of states. 

Example 4: No Interstate Trading Except for Emissions Associated with a Multi-State Energy 

Imbalance Market. In this example, the electric companies in a number of states operate as 

vertically integrated stand-alone utilities, owning generating assets and serving load in a single 

state. Some of them (e.g., 

Company A in State X) also 

own power plants (or contracts 

for power) in another state (e.g., 

in State Z) for producing part of 

the supply for retail customers 

in the home state (State X). 

These various approaches have 

traditionally provided resource 

adequacy. Each company is 

interconnected to other utilities 

in the region through 

transmission lines, and each 

company plans for and schedules the dispatch of its own power plants to meet its customers’ 

requirements (load) with operational reliability. Specifically, each company is the grid operator 

(balancing authority) in its electric system. Because anticipated demand varies in real time from 

actual demand, the interconnected utilities have entered into an “energy imbalance market” to 

allow power companies to voluntarily make their generating assets available to the entire 

region to allow for efficient dispatch of generating units across multiple systems to make sure 

that the systems have supply and demand in balance at all times. 

The states in this interconnected region enter into an agreement to allow for the CO2 emissions 

associated with such energy imbalances (which are important for both reliable and efficient 
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power supply) to be accommodated within each affected states’ SIPs and to credit/offset 

emissions changes in one state that result from such an interstate energy imbalance market. 

Example 5: Multistate RTO. Example 5 depicts a multi-state area, where all of the power 

plants located in the three states participate in a single RTO. The RTO is responsible for 

centralized securityconstrained economic 

dispatch of all power plants 

in the states. The three states 

seek to retain the economic 

and reliability benefits of 

this multi-state RTO, 

recognizing that CO2/MWh 

in one state may be affected 

by the dispatch protocols of 

the RTO that affect all power 

plants in the region. 

Each of the states includes in 

its SIP a formal agreement to 

allow trading across the units in the RTO footprint. The states could work with the RTO to 

establish the mechanism(s) through which the RTO would introduce CO2 prices and/or other 

constraints into the dispatch (e.g., through a shadow price116 or through actual tradable credits).

In addition to providing this interstate trading arrangement as part of their SIPs, affected states 

could also include in their SIPs various other policies – energy efficiency, clean energy 

standards, more aggressive RPS, contracts with zero-carbon electricity supplies, integrated 

resource planning with a shadow price on carbon, and so forth – that affect the CO2 emitted 

from the fossil plants in the RTO. Together, these approaches respect the regional operational 

reliability practices, market-based dispatch approaches, and state-specific policy preferences 

and resource-adequacy approaches.

 116 As an example, stakeholders in MISO are exploring the implications of a CO2 design that would use a limit on total 

emissions in the RTO footprint, along with a shadow price to use in security-constrained economic dispatch. Judy

Chang, Jurgen Weiss, Yingxia Yang, Jon Brekke, and Will Kaul, “A Market-based Regional Approach to Implementing EPA’s GHG 

Emissions Regulation,” Brattle Group and Great River Energy, January 2014. Also, MISO, “Refresh of MTEP-10 Carbon Analysis,” 

presentation to PAC Meeting February 19, 2014. 
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Example 6: States with Multiple Multi-State RTOs: This example is similar to the prior one, 

except that one of the 

states in this region has

Section 111(d) power 

plants located in two 

different RTOs, each 

covering a portion of 

the state. In this 

example, to the extent 

that each state seeks to 

allow its power plants 

to trade within the RTO 

market, each state 

would enter into an 

agreement to participate in a common trading program, potentially administered by each RTO. 

The state with electric utilities situated in two RTOs could determine the target CO2/MWh that

Section 111(d) units in each part of the state would need to achieve through the inter-state 

trading program administered by each RTO.

Example 7: States with Multiple Multi-State RTOs and a Multi-State CO2 Trading Programs. 

A final example involves a multi-state region with multiple RTOs and with a multi-state GHG 

trading program whose boundaries are not coincident with the boundaries of the RTO. The 

GHG trading program is 

a mass-based model, 

using a cap-and-trade 

system with CO2

allowances purchased by 

all fossil generating units 

(including EGUs and 

NGCCs). (An example of 

such an approach is the 

RGGI program in the 

Northeast.) In this

model, the states have 
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included in their SIPs their agreements with the other states that participate in the multi-state 

GHG program. State SIPs would delineate the manner in which the Section 111(d) units within 

their borders may trade emission allowances (or reductions or averaging) within the program, 

but not with other units in the portions of the RTO (e.g., RTO 1) where the program is not in 

effect. Reliability practices, like security-constrained dispatch or capacity markets for resource 

adequacy, would integrate smoothly with the multi-state nature of the RTO and GHG emissionreduction program.

Outside-the-Fence Models Approaches: Collateral policies

In the examples above, each state may also choose to include in its SIP other elements that 

contribute to the state’s compliance strategy for reliably reducing GHG emissions at existing 

EGUs and NGCCs. The state would need to demonstrate and quantify the effect of such other 

SIP elements on emissions from Section 111(d) units, with a monitoring and verification 

protocol with back-up actions in the event that such other SIP elements do not bring forth their 

anticipated emissions reduction outcomes. For example:

 A state wanting to encourage the eventual shutdown of a particular utility-owned 

generating unit (e.g., a coal plant with high emissions CO2 per MWh) learns from the grid 

operator that the plant is needed for reliability issues pending completion of transmission 

upgrades (or the completion of a new power plant then under construction). The utility 

does not want to retire the plant when those other facilities are complete, because the plant 

would have stranded costs. To encourage the timely retirement of the high-emitting coal 

plant, the state could include in its SIP a plan to allocate to the utility owner a quantity of 

CO2/MWh credits for some number of years beyond the unit’s actual retirement, as long as 

the unit were to retire by a date certain. This could allow that unit’s owner offset its 

stranded costs by selling those emissions to others after the unit retirement occurs. 

 One state wanting to gain access to underutilized NGCC capacity in a neighboring state 

through cost-effective transmission upgrades might enter into an interstate agreement to 

allocate additional credits to the neighboring state upon completion of the line. The state 

might propose to shut down a particular Section 111(d) unit upon the completion of the

transmission-system upgrade, and free up those credits to cover the emissions in the 

neighboring state that will go up once the line is energized and the NGCC capacity factors 

increase.
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 A state seeking to avoid the premature retirement of a financially challenged but wellperforming existing nuclear unit(s) might propose a SIP element to create financial 

incentives for the unit to remain in operation through its full operating license period. For 

example, a state already participating in a multi-state RTO and multi-state GHG program 

might additionally introduce a clean energy (applicable to LSEs) or a tradable emission 

standard (applicable to all generating units located physically within the state). Through 

the CES or the TES, the nuclear unit could generate MWh without emitting any CO2, sell 

those zero-carbon MWh credits to other generators in the state, capture enough monetary 

value for its supply of zero-carbon MWh to remain in service, and in so doing, help the 

entire system retain greater fuel diversity and reliability while also cost-effectively reducing 

system-wide CO2/MWh. 

These examples are suggestive of the types of elements that a state may include in its SIP to 

address local industry conditions, reliability considerations, system diversity, and economic 

impacts of Section 111(d) compliance. As many states have already begun to do, they can start 

their SIP planning processes with the expectation that they will be able to tailor their plan to suit 

their own preferences and policy objectives. This flexibility is inherent within Section 111(d), 

and affords a strong basis for allowing the states to comply with the CAA’s requirements 

without jeopardizing electric system reliability. 

Conclusions

The bottom line: as long as states and the industry start their planning process soon, there is no 

reasonable basis for anticipating that EPA’s guidance, the states’ SIPs and the electric industry’s 

compliance with them will create reliability problems for the power system. 

The nature of Section 111(d) affords the states with many options for compliance, both in terms 

of plan elements and timing. States will have significant flexibility in developing their GHG 

reduction plans, and EPA will allow them to craft their plans in ways that accommodate 

reliability considerations. This flexibility is a hallmark of the Section 111(d) regulatory 

framework, and this ‘cooperative federalism’ framework distinguishes it from some of the other 

recent air regulations that allow for a more narrow range of compliance strategies (e.g., MATS 

regulations affecting existing coal-fired power plants). 

Moreover, the conditions in the industry are such that compliance paths may be facilitated by 

low natural gas prices, significant existing under-utilized NGCC capacity, relatively slow 
Electric System Reliability and GHG Emission Reductions Under CAA Section 111(d) – May 2014

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growth in demand for electricity, increased supply expected from low-carbon renewable 

energy, and retirements of many of the older and least efficient coal-fired power plants before 

the implementation dates anticipated for Section 111(d).

To a significant degree, if a state has concerns about the reliability implications of compliance 

with EPA’s action to regulate GHG emission from existing fossil power plants, that state has a 

range of actions it can take today to address and mitigate these concerns. The states need not 

wait for EPA to propose and finalize its guidance before asking parties to propose plan 

elements; many states have already begun such discussions and planning. States can request 

transmission plans from their utilities and grid operators that examine the implications of 

particular plan elements on generation dispatch, emissions outlooks, and reliability issues. 

They can examine conditions that could cause output at Section 111(d) units to increase and to 

put pressure on meeting GHG emissions targets, and explore potential actions to mitigate those 

risks. State can step up actions to address reliability concerns now, rather than 18 months from 

now when the EPA finalizes its guidance. 

The states are in the driver seat in navigating compliance paths under Section 111(d) that assure 

reliable electricity supply as well as cost-effective GHG emissions reductions from existing 

power plants. 
Electric System Reliability and GHG Emission Reductions Under CAA Section 111(d) – May 2014

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APPENDIX 1: 

The Clean Air Act Section 111 – Excerpts 

Section 111(a) 

(a) Definitions. For purposes of this section: 

(1) The term “standard of performance” means a standard for emissions of air pollutants which 

reflects the degree of emission limitation achievable through the application of the best system of 

emission reduction which (taking into account the cost of achieving such reduction and any nonair 

quality health and environmental impact and energy requirements) the Administrator determines 

has been adequately demonstrated.

(2) The term “new source” means any stationary source, the construction or modification of which is 

commenced after the publication of regulations (or, if earlier, proposed regulations) prescribing a 

standard of performance under this section which will be applicable to such source.

(3) The term “stationary source” means any building, structure, facility, or installation which emits or 

may emit any air pollutant. Nothing in subchapter II of this chapter relating to nonroad engines shall 

be construed to apply to stationary internal combustion engines. 

(4) The term “modification” means any physical change in, or change in the method of operation of, a 

stationary source which increases the amount of any air pollutant emitted by such source or which 

results in the emission of any air pollutant not previously emitted.

(5) The term “owner or operator” means any person who owns, leases, operates, controls, or 

supervises a stationary source.

(6) The term “existing source” means any stationary source other than a new source......

Section 111(d) Standards of performance for existing sources; remaining useful life of source

(1) The Administrator shall prescribe regulations which shall establish a procedure similar to that 

provided by section 110 under which each State shall submit to the Administrator a plan which (A) 

establishes standards of performance for any existing source for any air pollutant (i) for which air 

quality criteria have not been issued or which is not included on a list published under section 108(a) 

or 112(b)(1)(A) but (ii) to which a standard of performance under this section would apply if such 

existing source were a new source, and (B) provides for the implementation and enforcement of such 

standards of performance. Regulations of the Administrator under this paragraph shall permit the 

State in applying a standard of performance to any particular source under a plan submitted under 

this paragraph to take into consideration, among other factors, the remaining useful life of the 

existing source to which such standard applies.

(2) The Administrator shall have the same authority—

(A) to prescribe a plan for a State in cases where the State fails to submit a satisfactory plan as he 

would have under section 110(c) in the case of failure to submit an implementation plan, and 

(B) to enforce the provisions of such plan in cases where the State fails to enforce them as he would 

have under sections 113 and 114 with respect to an implementation plan. In promulgating a standard 

of performance under a plan prescribed under this paragraph, the Administrator shall take into 

consideration, among other factors, remaining useful lives of the sources in the category of sources to 

which such standard applies.
Electric System Reliability and GHG Emission Reductions Under CAA Section 111(d) – May 2014

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APPENDIX 2 –

Generating Capacity Subject to 111(d) by State as of the beginning of 2013 (Page 1)

State 

MW 

Capacity

Number of 

Units

Capacity 

Factor 

(2012)

MW 

Capacity

Number of 

Units

Capacity 

Factor 

(2012)

MW 

Capacity

Number of 

Units

Capacity 

Factor 

(2012)

MW 

Capacity

Number of 

Units

Capacity 

Factor 

(2012)

MW 

Capacity

Number of 

Units

Capacity 

Factor 

(2012)

ALABAMA 10,790 35 49% 453 15 49% 64 9 77% 6,255 42 63% 0 0 0%

ALASKA 118 16 67% - - 0% - - 0% 279 4 70% 47 1 77%

ARIZONA 6,230 18 75% - - 0% 974 9 7% 6,452 43 32% 0 0 0%

ARKANSAS 5,144 7 63% 300 11 71% 1,203 8 8% 3,060 23 38% 0 0 0%

CALIFORNIA 250 8 61% - - 0% 12,848 48 8% 12,830 129 51% 0 0 0%

COLORADO 5,377 26 73% - - 0% 120 4 1% 1,663 28 39% 0 0 0%

CONNECTICUT 388 1 3% 1,861 7 2% 44 5 23% 2,303 15 23% 0 0 0%

DELAWARE 430 3 31% - - 0% 846 6 15% 756 6 53% 0 0 0%

FLORIDA 10,493 29 49% 5,499 23 17% 1,038 14 22% 16,785 104 60% 0 0 0%

GEORGIA 12,583 43 38% 655 20 52% 129 2 9% 4,877 26 55% 0 0 0%

HAWAII 180 1 95% 1,119 21 46% - - 0% - - 0% 375 12 55%

IDAHA 17 6 61% 74 4 65% - - 0% 374 4 39% 0 0 0%

ILLINOIS 15,943 71 56% - - 0% 40 7 3% 2,005 14 33% 0 0 0%

INDIANA 18,283 78 58% 158 4 0% - - 0% 1,549 12 64% 0 0 0%

IOWA 6,784 49 60% - - 0% 65 2 14% 813 7 12% 0 0 0%

KANSAS 5,096 14 63% - - 0% 1,714 29 11% - - 0% 0 0 0%

KENTUCKY 15,329 54 63% - - 0% - - 0% - - 0% 0 0 0%

LOUISIANA 4,430 14 64% 266 7 62% 8,049 64 22% 5,916 41 54% 0 0 0%

MAINE - - 0% 1,222 19 20% 93 2 65% 880 5 33% 0 0 0%

MARYLAND 4,771 16 40% 1,730 4 18% 321 8 6% 157 2 31% 0 0 0%

MASSACHUSETTS 1,439 8 18% 2,138 6 1% 645 16 6% 4,315 26 34% 282 4 4%

MICHIGAN 11,778 83 53% 51 2 86% 2,182 9 4% 3,378 33 45% 0 0 0%

MINNESOTA 4,755 41 55% 15 1 50% 174 17 18% 1,502 11 29% 0 0 0%

MISSISSIPPI 2,566 7 33% 235 8 59% 2,773 23 20% 4,685 29 49% 0 0 0%

MISSOURI 12,435 51 67% - - 0% 116 6 1% 1,425 11 19% 0 0 0%

MONTANA 1,763 8 62% - - 0% - - 0% 41 1 0% 0 0 0%

NEBRASKA 4,160 20 69% - - 0% 268 9 2% 296 5 11% 0 0 0%

NEVADA 1,303 7 36% - - 0% 470 5 7% 3,377 34 54% 0 0 0%

NEW HAMPSHIRE 554 4 26% 407 4 2% - - 0% 882 4 57% 0 0 0%

NEW JERSEY 2,001 7 15% 163 3 2% 629 8 3% 4,132 42 49% 0 0 0%

NEW MEXICO 3,430 7 72% - - 0% 779 11 32% 925 8 48% 0 0 0%

NEW YORK 1,736 15 25% 2,795 9 10% 6,927 22 17% 6,425 63 49% 0 0 0%

NORTH CAROLINA 11,084 34 50% 163 7 66% - - 0% 2,809 21 46% 0 0 0%

NORTH DAKOTA 4,153 14 78% - - 0% - - 0% - - 0% 0 0 0%

OHIO 19,394 84 49% 45 3 82% 35 2 1% 2,292 20 67% 0 0 0%

OKLAHOMA 5,323 15 63% 58 1 85% 5,085 32 19% 4,394 31 49% 0 0 0%

OREGON 585 1 52% 59 2 41% 32 2 26% 2,100 18 44% 0 0 0%

PENNSYLVANIA 14,901 59 58% 842 5 7% 1,635 4 11% 5,614 42 64% 0 0 0%

RHODE ISLAND - - 0% 4 2 19% 9 4 22% 1,293 11 47% 0 0 0%

SOUTH CAROLINA 6,082 22 50% 244 7 44% 107 3 47% 1,682 10 48% 0 0 0%

SOUTH DAKOTA 475 1 68% - - 0% - - 0% 170 1 1% 0 0 0%

TENNESSEE 7,734 49 52% 186 6 46% - - 0% 960 5 48% 0 0 0%

TEXAS 21,335 40 69% 161 6 77% 18,553 88 13% 27,324 207 50% 0 0 0%

UTAH 4,887 15 72% - - 0% 240 4 6% 713 5 55% 0 0 0%

VERMONT - - 0% 2 3 26% - - 0% - - 0% 0 0 0%

VIRGINIA 5,890 41 26% 1,899 14 11% 334 4 7% 2,779 20 78% 0 0 0%

WASHINGTON 1,340 2 32% 150 9 55% 5 1 15% 2,225 21 23% 0 0 0%

WEST VIRGINIA 14,378 33 56% - - 0% - - 0% - - 0% 0 0 0%

WISCONSIN 8,618 58 44% 135 8 55% 7 1 16% 1,724 12 44% 0 0 0%

WYOMING 6,431 24 77% 0 1 51% 3 3 65% - - 0% 0 0 0%

50 STATES 292,375 1,204 22,636 227 68,489 482 148,160 1,154 705 17

source: SNL Financial

Steam Turbine - Coal Steam Turbine - Oil Steam Turbine - Natural Gas Combined Cycle - Natural Gas Combined Cycle - Oil
Electric System Reliability and GHG Emission Reductions Under CAA Section 111(d) – May 2014

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APPENDIX 2 –

Generating Capacity Subject to 111(d) by State as of the beginning of 2013 (Page 2)

State MW Capacity

Number of 

Units

MW 

Capacity

Number of 

Units

Capacity 

Factor 

(2012)

MW 

Capacity

Number of 

Units

Capacity 

Factor 

(2012)

MW 

Capacity

Number of 

Units

MW 

Capacity

Number of 

Units

ALABAMA 17,562 101 5,135 5 91% 0 1 0% 10,361 175 33,058 282

ALASKA 444 21 - - 0% 33 25 7% 1,766 473 2,243 519

ARIZONA 13,656 70 3,937 3 93% 829 65 16% 9,634 133 28,056 271

ARKANSAS 9,707 49 1,865 2 95% - - 0% 4,300 112 15,872 163

CALIFORNIA 25,929 185 2,240 2 90% 6,202 498 19% 33,424 1,431 67,795 2,116

COLORADO 7,161 58 - - 0% 2,411 61 29% 5,685 228 15,256 347

CONNECTICUT 4,596 28 2,117 2 92% 1 6 0% 2,687 144 9,401 180

DELAWARE 2,032 15 - - 0% 15 4 20% 1,001 31 3,048 50

FLORIDA 33,815 170 3,140 4 65% 74 11 16% 23,441 401 60,470 586

GEORGIA 18,244 91 4,061 4 95% 3 3 5% 17,498 350 39,806 448

HAWAII 1,674 34 - - 0% 185 27 20% 813 110 2,672 171

IDAHA 465 14 - - 0% 973 32 22% 3,725 203 5,162 249

ILLINOIS 17,988 92 11,673 11 94% 3,579 36 25% 14,462 577 47,703 716

INDIANA 19,991 94 - - 0% 1,543 15 24% 6,300 217 27,834 326

IOWA 7,663 58 622 1 80% 5,050 77 32% 3,134 499 16,469 635

KANSAS 6,810 43 1,205 1 78% 2,516 19 22% 3,504 403 14,034 466

KENTUCKY 15,329 54 - - 0% - - 0% 6,768 111 22,098 165

LOUISIANA 18,660 126 2,157 2 83% - - 0% 5,551 134 26,368 262

MAINE 2,195 26 - - 0% 411 10 23% 2,057 292 4,663 328

MARYLAND 6,979 30 1,734 2 89% 148 14 26% 3,819 156 12,680 202

MASSACHUSETTS 8,820 60 685 1 98% 93 32 11% 5,171 231 14,769 324

MICHIGAN 17,389 127 4,131 4 77% 820 16 15% 9,412 644 31,753 791

MINNESOTA 6,445 70 1,697 3 80% 2,867 145 30% 5,333 433 16,342 651

MISSISSIPPI 10,260 67 1,265 1 66% - - 0% 4,532 71 16,056 139

MISSOURI 13,977 68 1,240 1 99% 459 6 31% 7,185 377 22,860 452

MONTANA 1,803 9 - - 0% 638 10 26% 3,150 95 5,591 114

NEBRASKA 4,725 34 1,271 2 52% 415 11 34% 2,032 253 8,443 300

NEVADA 5,150 46 - - 0% 411 18 12% 5,486 135 11,046 199

NEW HAMPSHIRE 1,843 12 1,247 1 75% 171 3 14% 1,311 142 4,571 158

NEW JERSEY 6,924 60 4,273 4 88% 285 128 11% 8,889 233 20,371 425

NEW MEXICO 5,134 26 - - 0% 921 34 31% 1,833 67 7,887 127

NEW YORK 17,883 109 5,286 6 88% 1,598 27 20% 15,171 843 39,937 985

NORTH CAROLINA 14,056 62 5,206 5 86% 153 64 8% 11,321 344 30,736 475

NORTH DAKOTA 4,153 14 - - 0% 1,805 28 34% 626 40 6,585 82

OHIO 21,765 109 2,176 2 90% 484 13 24% 9,588 332 34,012 456

OKLAHOMA 14,860 79 - - 0% 2,973 27 31% 5,494 129 23,326 235

OREGON 2,776 23 - - 0% 3,154 60 22% 8,144 256 14,074 339

PENNSYLVANIA 22,992 110 9,896 9 87% 1,377 43 18% 9,967 375 44,232 537

RHODE ISLAND 1,306 17 - - 0% 2 1 0% 712 35 2,019 53

SOUTH CAROLINA 8,115 42 6,659 7 88% 0 1 0% 9,158 254 23,931 304

SOUTH DAKOTA 645 2 - - 0% 767 11 42% 2,825 75 4,237 88

TENNESSEE 8,879 60 3,512 3 82% 44 5 12% 8,077 190 20,512 258

TEXAS 67,373 341 5,020 4 87% 11,700 116 31% 22,492 504 106,585 965

UTAH 5,840 24 - - 0% 19 1 24% 1,550 143 7,408 168

VERMONT 2 3 628 1 91% 133 11 9% 545 139 1,308 154

VIRGINIA 10,902 79 3,637 4 90% - - 0% 11,750 626 26,288 709

WASHINGTON 3,719 33 1,158 1 92% 2,802 24 27% 24,743 379 32,422 437

WEST VIRGINIA 14,378 33 - - 0% 583 6 25% 1,542 50 16,503 89

WISCONSIN 10,485 79 1,209 2 92% 614 12 28% 6,252 534 18,559 627

WYOMING 6,434 28 - - 0% 1,383 30 35% 586 58 8,404 116

50 STATES 532,364 3,084 94,944 95 60,642 1,786 354,445 13,992 1,042,395 18,957

source: SNL Financial

All Section 111(d) Units Nuclear Wind and Solar Other Total Grid-Connected 
Electric System Reliability and GHG Emission Reductions Under CAA Section 111(d) – May 2014

Analysis Group, Inc. Page | 71

APPENDIX 3 –

MAP of NERC REGIONS AND SUBREGIONS