Discussion draft – do not cite or distribute

A Plan for Regulating Power Sector GHGs 

Under CAA Section 111(d): 

Developing and Implementing a

Balanced, Effective, and Efficient Approach

NRG Energy

8/29/13
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Executive Summary

Reactions to the President’s plan for reducing greenhouse gas (GHG) emissions from existing power 

plants through EPA regulation range from full-throated opposition to optimistic but unrealistic 

proposals. The key to achieving the President’s goals is developing and implementing a truly 

workable middle ground approach before 2016. Such an approach should advance not only the GHG 

reduction goals outlined by the President, but also drive increased deployment of clean energy 

resources, and mitigate the risk of derailment due to full blown legal and political opposition. 

Clean Air Act Section 111(d) offers a narrow path for EPA and the states to achieve real GHG 

reductions while simultaneously accelerating the deployment of clean energy and enhanced energy 

efficiency. NRG supports a two-part plan to realize these objectives. First, EPA’s guidelines should 

lay out a package of the core elements of a suitable compliance program. These core elements 

comprise readily achievable performance standards for fuel-based sub-categories of sources; robust 

trading of emission reduction credits -- intrastate and interstate -- across facilities and companies; 

and an alternative compliance payment or “safety valve” to prevent excessively high compliance 

costs and to help fund state clean energy and efficiency initiatives. 

In addition to this core compliance package, EPA should provide states a menu of voluntary clean 

energy initiatives that will provide additional GHG reductions, while simultaneously advancing other 

important goals, by providing additional clean energy incentives for energy efficiency; renewable 

energy deployment; and repowering or retirement of less efficient coal fired power plants. Together, 

the core compliance package and the voluntary clean energy initiatives will:

• Lay out the most pragmatic, achievable and efficient path for state plans to achieve critical 

emission reduction goals, consistent with energy reliability;

• Increase investment in plant efficiency and cleaner fuels for underperforming units;

• Focus incentives on operating efficient plants more and inefficient plants of each fuel type 

less, reducing emissions at the lowest cost;

• Encourage investment in new renewable energy, and advanced energy efficiency; and

• Facilitate the voluntary retirement and repowering of high emission generation with cleaner, 

profitable replacement generation. 

This balanced approach can achieve substantial emission reductions at a low cost to the overall 

economy and, importantly, to the regulated entities in the power sector itself. Low costs to the 

economy and to power companies are essential for political acceptability, stakeholder engagement 

and support, legal stability and enduring emission reductions. Above all, long-term emission 

reductions depend on a regulatory approach that combines strong incentives for reducing emissions 

with the enhancement of energy companies’ ability to invest the hundreds of billions of dollars 

needed to create a clean energy economy. 
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1. Introduction

Clean Air Act section 111(d) requires EPA to issue performance standards for existing sources of

otherwise unregulated dangerous pollutants, but offers only limited guidance for the contents of such 

standards. The key statutory requirements are that:

a. The performance standards must be based on “the best system of emission reduction” that the 

EPA administrator, taking cost into account, determines has been adequately demonstrated; 

b. The rule must consist of a procedure, comparable to that used for State Implementation Plans 

(SIPs) under section 110, whereby each state develops and submits to the Administrator a plan 

that implements performance standards for affected existing sources; and

c. The Administrator has authority to prescribe or enforce plans in the event a State fails to do so.

It appears that EPA will likely base a Section 111(d) rule for existing power plants on several 

performance standards for CO2 emission rates per megawatt-hour. At the same time, given the 

flexibility required to successfully implement such a standard across existing sources, EPA almost 

certainly will have to look beyond a pure numeric standard and employ additional tools and measures 

for such a program to be implemented successfully and at a reasonable cost.

Fortunately, beyond a specific numeric limit that would be enforced uniformly in each state, Section 

111(d) precludes few options while leaving open the door to a wide range of flexible tools EPA can use 

to enhance the success of the regulations. At the outset, we recommend EPA establish a basic package 

of core compliance elements to:

• Establish nation-wide performance standards for GHG emissions by fuel-type subcategory;

• Promote averaging, banking and trading of allowances across facilities and companies;

• Encourage and provide the mechanism for a robust interstate trading system; and

• Cap the price of compliance instruments at reasonable levels.

This core compliance package would allow state plans to achieve a necessary regulatory compliance 

program for existing facilities. EPA should, however, go further and also lay out guidelines for clean 

energy initiatives that states could include voluntarily in their plans to realize additional cost-effective 

opportunities to achieve or exceed the emission reductions required by EPA’s guidance. Such clean 

energy initiatives should include alternative means of compliance based on the deployment of end-use 

energy efficiency and renewable energy, as well as through targeted market-based incentives for the 

retirement and replacement of poor-performing coal plants. 

This combination of a core compliance package and voluntary clean energy initiatives will allow states to 

readily and effectively achieve the goals of GHG reductions from existing facilities, at a low cost to 

regulated entities and their customers, while accelerating the deployment of clean energy. Power 

plants with emissions intensity greater than the relevant performance standard would have an incentive

to make commercially available and feasible improvements in fuel efficiency to meet the standard. 
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Plants for which such investments are excessively costly or infeasible would, in turn, be able to comply 

by purchasing emission reduction credits from plants that whose emission rates are below the standard. 

This additional increase in the marginal cost of operation for the plants with the highest emission rates

would lead to them running less, and their energy output being replaced by plants with lower emission 

rates. This short-run dispatch impact would directly reduce carbon emissions.

Meanwhile, plants that run and earn less are less profitable to maintain, and hence are more likely to 

retire or repower to a more efficient, lower carbon technology. These long run incentives to retire, 

repower or replace less efficient plants, will lead to further emission reductions from existing plants. 

Under our proposal, emission reductions will be further augmented by state plans that voluntarily 

include the clean energy initiatives suggested in the guidance. The net result will be even more emission 

reductions, at a lower cost and with greater potential public support than other more drastic 

approaches EPA may consider.

2. Our Key Design Element Recommendations 1

In our view, an effective 111(d) regulatory approach will have two basic components. The first is a set of 

core elements that would inform all state plans, and the second is a set of additional voluntary 

compliance pathways that states could include in their plans voluntarily. 

A. Four core elements of EPA’s guidance

1. Empirically-supported performance standards.

While market-based mechanisms provide for greater efficiency, the underlying performance standard 

levels will ultimately determine the cost of the program for regulated entities, their customers, and coalintensive regions of the country. To hedge against costly price volatility and high compliance costs that 

will undermine political and legal stability of the program, EPA should base the performance standard 

on a realistic, empirical assessment of the emission reductions that can be achieved through the best 

emission reduction option that is commercially available, considering cost, and that is actually under the 

control of the covered emitters. Because existing plants have engineering, operating and cost 

characteristics distinct from those of state-of-the-art new technologies, the standards for existing plants 

must be distinct from those for new plants.

Key to the success of such standards will be to develop the strongest and soundest empirical basis for 

their deployment at a reasonable cost and in realistic quantities by covered entities. In contrast, basing 

the standards on anecdotal or theoretical potential emission reductions would likely to lead to 

compliance costs far above those anticipated. For example, statistical estimates of historical heat rate 

improvements at coal plants may over-estimate the availability of heat rate improvements and underestimate their costs by assuming that past improvements can be repeated again at the same plants, or 

 1 Most of these features are consistent with the overall recommendations of the National Climate Coalition (NCC) 

for how EPA could regulate GHGs from existing power plants. NRG is a founding member of the NCC.
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that improvements that work for a subset of plants will work at all plants. If fewer emission 

improvements are available, and if they cost more than EPA assumes in setting the standard, the actual 

cost of meeting the standard will be higher – and, in a market based system, potentially much higher –

than EPA anticipates. Excessive compliance costs would be devastating to a number of US power 

companies, and companies facing such uncertain and unhedgeable risks will naturally be strongly 

opposed to any policy that could create such risks. For this reason, the standards should be achievable 

at modest cost under today’s existing technologies, and should also be accompanied with the 

alternative compliance payment discussed below.

Further, performance standards should be subcategorized, at a minimum, by fuel types (coal, gas, oil) to 

ensure that no one fuel type is given standards that it cannot achieve using commercially available, costeffective technologies, and to avoid massive transfers of wealth between different power companies 

and regions of the country. In particular, windfalls for natural gas fired fleets will do little to deploy 

advanced technologies but could lead to a rapid and unbridled switch to gas power plants, locking in 

another generation’s worth of fossil fuel dependency in the power sector.

Sub-categorization is important, not just to avoid this result, but also because a single standard based on 

the average of different fuel types’ emission rates would impose unacceptably costly compliance 

obligations on facilities and companies with more coal-fired assets while transferring large amounts of 

their cash flow to gas-fired power companies. Such a cash outflow from coal-intensive fleets would 

limit the ability of coal-intensive companies to invest in the cleaner technologies they need to deploy to 

survive and succeed in a low carbon future. Further, such an approach would increase the risks of such 

a rule being overturned by the courts, both because of the additional appeals it will induce and because 

of its deviation from the clear statutory requirement to base the standard on the best system of

emission reductions.2

2. Tradeable credits and allowances

A tradable, emission rate-based performance standard would require plants whose emission rates 

exceed the standard to reduce their emission rate to the standard (e.g., through heat rate 

improvements or co-firing with a less carbon intensive fuel) or to buy emission-rate reduction credits 

(ERCs) equal to the difference between the standard and their own emission rate, times their megawatthours of electricity production. Plants with emission rates below the performance standard could sell 

ERCs, based on the difference between the standard and their own emission rate, times the number of 

megawatt-hours of production. 

3. An inter-state trading system

 2 We think it unlikely that Congress meant for the “best system of emission reduction” to include a regulatory 

regime under which Emitter A loses all their profits and renders their assets uneconomic by being required to send 

vast amounts of money to Emitter B or Service Provider C. A trading system should be used to minimize the cost of 

using the best system of emission reductions, not to define it. 
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Material emission reductions at moderate costs are the key to realizing true political and legal stability 

for the existing source rule. Lowest cost emission reductions are virtually certain to be achievable only 

through a broad market-based system and therefore EPA explicitly should encourage SIPs that support 

efficient interstate trading of compliance instruments. This is particularly important for the many 

covered entities with facilities in multiple states, especially those states with competitive wholesale

power markets that have been designed in response to federal government initiatives and 

requirements. The ability to trade and to average emissions and compliance across large, inter-state 

fleets will reduce each company’s cost of compliance while also facilitating more emission reductions, at 

a lower overall cost, than would be available under intra-state trading alone. And a uniform regulatory 

system with interstate trading at least congruent with the federally regulated wholesale power markets 

will help avoid economically perverse results that could result under a plethora of different state 

mechanisms.3

 

4. An appropriate cap for the cost of compliance

To further make the proposed rule more broadly acceptable and to avoid punitive and unintended 

results, such as limiting the ability of coal-based companies to invest in clean energy alternatives, EPA 

should also require SIPs to limit the risk of unacceptably high ERC prices and compliance costs by 

including an Alternative Compliance Payment (ACP), similar to that used in most state renewable energy 

portfolio standards. If ERC prices reach the ACP level, entities could comply by paying the ACP instead 

of buying additional ERCs. The ACP level should be tied specifically to an appropriate cost threshold.4

 

EPA should also assure states that any funds collected through a state’s ACP will be available to that 

state for purposes it deems appropriate for further reducing GHG intensity, such as further deploying 

clean energy and energy efficiency technologies within the state. This will provide additional emission 

reductions, economic benefits, and accelerated maturation and cost reductions of clean energy and 

efficient end-use technologies.

B. A roadmap for voluntary compliance tools to realize additional GHG reductions 

Reducing the emission intensity of existing power plants is an important step in reducing overall GHG 

emissions. But significant emission reductions will require a major increase in renewable energy 

production, end-use energy efficiency, and in the retirement and replacement of the least efficient coal 

plants with far cleaner resources. For this reason, NRG recommends that EPA promote incremental 

 3 For example, proposals that would have different standards for each state, based on each states average of gas 

and coal plant emissions, would allow an inefficient, high emission coal plant in a coal-rich state to have lower 

compliance costs than a much more efficient, much lower emitting coal plant in a gas-rich state. This would give 

the dirtier coal plant a competitive advantage in both power and capital markets. We encourage EPA to avoid such 

results. 

4 For example, if EPA’s empirical study shows that an average 10% emission rate reduction is available across the 

US coal power plant fleet for a maximum cost of $15 per ton of reduced CO2 emissions, the ACP would be set at or 

near $15 per ton. This will assure a strong market incentive for making the kind of heat rate improvements 

identified in the empirical study, while protecting against the crippling high prices that could result if emission rate 

reductions cost significantly more than the study predicted.
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renewable energy, end-use energy efficiency, carbon capture and sequestration and repowering of 

operating coal plants through a roadmap or guidelines for states that wish to voluntarily include such 

initiatives in their 111(d) plans. State clean energy initiatives that comply with these guidelines might 

serve as either an alternative to the core compliance package, or as complementary compliance 

mechanisms in it. We recommend the following key provisions in this 

1. Promoting Energy Efficiency and Clean Energy

Allowing adequate alternative compliance options can increase incentives for deploying clean energy

and efficient end-use technologies, help avoid politically and economically excessive compliance cost 

impacts on both covered entities and customers, and result in additional emission reductions overall. 

EPA, for example, could allow voluntary state programs to generate additional ERCs that could be sold 

into the compliance market. These might include qualified indirect emission reductions in 

implementation options, including incremental renewable energy production, limited repowering of 

coal plants with low emitting natural gas and renewables, CCS, or additional improvements (beyond 

business-as-usual and existing utility programs) in end-use energy efficiency. 

EPA should ensure that such voluntary additional compliance measures meet strict causation, 

attribution, measurement and verification and trading requirements, by providing guidelines SIPs must 

meet in order to be approved. These guidelines should include provisions for any ERCs generated by the 

voluntary compliance options to be traded on an interstate basis. This approach offers the potential for 

EPA and the states to develop appropriate ways to measure and certify indirect emission reductions, 

while encouraging additional market-based development of such resources. If these initiatives can be 

successfully demonstrated as satisfactory for compliance purposes, as well as commercially available 

and reasonable in cost, EPA may be better able to fold such indirect measures into any future updates of 

the performance standards themselves, as may be warranted, e.g., whenever the 111(b) rule for new 

power plants is itself updated. 

2. Fostering an investment pathway for moving capital from coal to cleaner 

alternatives

Any plan the EPA is likely to consider will have the effect of shifting some short-run generation output

from higher emitting to lower emitting resources. However, the political, economic and environmental 

optimum will best be achieved if the plan also includes ways to shift long run capital investment to 

actually replace existing high emitting sources with lower or zero emitting new resources. NRG 

proposes that the EPA use the 111(d) process to encourage states to include in their plans provisions

that will reduce the uncertainty about cost recovery for the voluntary replacement of operating coal 

plants with efficient gas technologies (and other forms of cleaner generation). This would induce more 

owners of marginal coal plants to retire and replace them with efficient gas or renewables voluntarily,

without distorting the balance of supply and demand in competitive wholesale power markets; and 

without undermining grid reliability.

Under such an approach, the EPA would encourage states to consider and, as appropriate, implement 

programs with the following key features:
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• Power companies that, prior to 2020, retire operating coal plants5 and replace them with the 

least cost natural gas plant or other alternatives with comparable or better performance and 

emission characteristics, will be provided a fast-track to cost recovery (for repowering of 

regulated coal plants) or the price certainty needed for project financing (for repowering of 

competitive coal plants).

• For regulated repowering projects that meet the above eligibility criteria, the fast-track would 

be created by each state, in a manner consistent with the state’s integrated resource planning 

or a similar regulatory process.

• For competitive repowering projects, cost recovery would be facilitated by state programs that 

require a suitable counterparty to enter into an agreement with the project, such as a ten year 

contract-for-differences, which would provide it with sufficient price certainty to support project 

finance. The counterparty could be a utility, a consortium of utilities, a power agency or other 

entity able to enter into such an agreement and to flow the cost and benefits of those purchases 

to customers through a broad based “wires charge” or other competitively neutral mechanism.

This approach will help the power sector make wise investment choices in critically needed resources 

during a time of uncertainty and change, without mandates or federal expenditures. Several additional 

features would help assure the efficiency and effectiveness of the program:

o To ensure that this approach does not procure excess or unneeded generating capacity, 

only operating power plants, which would produce substantial amounts of energy at 

projected gas prices, should be eligible, and their replacement cannot exceed the 

capacity, on a MW for MW basis, of the coal facility it replaces.

o Cost discipline could be enhanced by competitive procurement (for regulated utility 

repowering projects) and competitive market benchmarks (for competitive repowering 

projects).

Such a program should have extremely low incremental costs, in that it would lead to the replacement 

of marginally economical or uneconomical coal plants with the most cost-effective generation 

technology and fossil fuel available today. 

4. Conclusion

The key suite of features recommended in this two-part plan would create an effective, low cost, simple 

and relatively uniform market based system for reducing the GHG intensity of the US power sector. It 

would focus the strongest incentive to reduce emissions on the least efficient power plants in both the 

coal and the gas fleets, which are precisely the units with the least economic value and the greatest 

emissions per unit of energy production. It would have a neutral to positive economic impact on more 

efficient and economically important power plants, assuring a moderate overall cost impact for coalintensive companies and regions of the country. This approach should also produce material reductions 

in GHG emissions. It would make the least efficient coal plants less economic relative to efficient gas 

 5

 An appropriate definition of operation status will be necessary, e.g., plants that are in operation today and will produce substantial amounts 

of energy at forward market prices for power and natural gas, or that are deemed needed for reliability.
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plants, and also incent incremental investment in cleaner technologies. In the short run, this would 

decrease the dispatch of inefficient coal plants relative to more efficient gas plants, and in the long run it 

would encourage their replacement by lower or zero carbon alternatives. 

These pragmatic and effective steps to reduce GHGs from existing plants, while also nurturing additional 

energy efficiency and renewable energy deployment and the replacement of inefficient coal plants with 

lower emitting and flexible gas plants is also, in our view, legally permissible under Section 111(d), 

should be attractive to and easy for states to implement, and can be implemented in ways that have a 

very modest impact on the cost and operating requirements of most power sector entities that would 

be regulated under it, including coal-intensive companies and regions of the country. In light of the 

President’s and EPA’s intention to consult intensively with power companies during the development of 

the 111(d) rule, such a framework may help form a broader consensus around appropriate approaches 

to regulating GHGs under the Clean Air Act.