PART IV – EPA’s Proposed 111(d) Rule: Some Insights & Open Legal Questions

The fourth and final post in a series offering some initial insights and observations, and posing several open legal questions related to EPA’s proposed 111(d) rule.

ElectricalgridThis is the fourth and final post in a series offering some initial insights and observations, and posing several open legal questions related to EPA’s proposed 111(d) rule (See Parts I, II, & III.)

Over the course of this series, I welcome our knowledgeable and insightful LegalPlanet audience to join the dialogue in the comments. What strikes you about the proposed rule? What legal questions puzzle you? What are your thoughts on the below issues?

My first post made some big-picture observations about EPA’s proposed 111(d) rule, my second post dug into EPA’s determination of the best system of emission reduction (BSER) and calculation of state goals, and my third post discussed the rule’s implications for existing and new greenhouse gas cap-and-trade programs.  In this fourth and final post, I discuss next steps and a variety of odds and ends.

This document is a proposal. Those familiar with administrative law know well that a proposed rulemaking is just an early step in the regulatory process; but this important nuance has been missing from many media accounts and bears repeating. In its proposed CO2 rulemaking, EPA set forth a variety of regulatory alternatives and options for comment. Once the proposed rule is published in the Federal Register, interested members of the public have 120 days to comment on the proposal.  EPA also will hold hearings around the country on:  July 29 (Atlanta, GA & Denver, CO), July 31 (Pittsburgh, PA), and July 28 (Washington, D.C.).

Ultimately, the final rule could look very different from this proposal—even in terms of the state-specific CO2 reduction goals. Indeed, if prior greenhouse gas rules are any indication (see, e.g., the NSPS rulemaking process), EPA will receive an extraordinarily large volume of comments, and the agency may materially alter the content of the rule in the course of responding to comments and preparing the final rulemaking. This proposal, in particular, seeks comments on many open questions and alternative proposals. The contours of the rule and the legal interpretations underpinning the rule remain unsettled. Furthermore, section 111(d) refers to such documents as a “guideline” for state regulation. Which leads me to the following question . . . .

Is it legally significant that the proposed rule is a guidelineIn contrast to Clean Air Act section 111(b), which directs EPA to regulate new sources, section 111(d) makes clear that EPA does not have authority to regulate existing sources directly. Instead, EPA must issue guidelines to guide state regulation of existing sources and EPA approval of state plans. Emission guidelines can perhaps best be thought of as a recommended federal baseline, or a set of criteria for state plan approval. States have great flexibility to design regulatory programs in §111(d) state plans (see, e.g., my discussion of 40 C.F.R.§ 60.24(f) in Post II). In practice, however, states have, in many instances, adopted the federal guideline as the state emission standard. Overall, there is limited precedent for emission guidelines because there are so few designated pollutants. Does the fact that EPA has authority to issue only emission guidelines have implications for future legal challenges to the proposed rule? How vulnerable is EPA to challenges from states with state plans that do not meet EPA’s stated approval criteria?  Is it significant that judicial review of state plans would occur outside of the D.C. Circuit? 

EPA invokes Chevron authority to deal with 1990 Clean Air Act Amendments drafting errors. In a previous post, Kate Konschnik excellently analyzed the apparent “drafting errors” that occurred during incorporation of the 1990 Clean Air Act Amendments. Kate argued that EPA should receive Chevron deference for its reasonable interpretation of its authority to regulate existing greenhouse gas sources in spite of the drafting errors. EPA agrees, and sets forth the agency’s legal arguments and invocation of Chevron in the proposed rule (see pp. 125-26). This issue likely will be the subject of future litigation.

EPA plans to engage in an interagency effort to develop new guidance for renewable energy and end-use energy efficiency measures. EPA declares in the proposal that the agency intends to develop, in concert with other federal agencies, new guidance specific to the evaluation, monitoring, and verification of renewable energy and demand-side energy efficiency (RE/EE) programs for the purposes of section 111(d) state plans (p. 427). This new guidance will help states calculate the emission reductions associated with measures such as appliance standards and building codes that are not typically subject to regulatory verification and monitoring (p. 491). The new guidance could help encourage states and localities to adopt such measures.  Thinking about building codes in particular raises an interesting question—How will/should/could states and localities interact in §111(d) compliance, and in what context?

Timelines.  EPA has proposed that any “measures taken by a state or its sources after the date of this proposal, or programs already in place, and which result in CO2 emission reductions at affected EGUs during the 2020-2030 period, would apply toward achievement of the state’s CO2 goal” (p. 333; see also pp. 115, 476). As an alternative, EPA proposes to “recognize emission reductions that existing state requirements, programs and measures achieved starting from a specified date prior to the initial plan performance period, as well as emission reductions achieved during a plan performance period. The specified date could be, for example: the date of promulgation of the emission guidelines; the date of proposal of the emission guidelines; the end date of the base period for the EPA’s BSER-based goals analysis (e.g., the beginning of 2013 for blocks 1-3 and the beginning of 2017 for block 4, end-use energy efficiency); the end of 2005; or another date” (p. 478). When should EPA begin counting emission reductions? What is the significance of the different potential start dates?

Additionally, EPA has requested comment on whether the agency should develop state-specific emission performance goals that extend beyond 2030 (p. 422). Should EPA develop goals that extend beyond 2030? What would be the relative advantages and disadvantages of (or legal challenges inherent in) requiring states to meet longer-term goals?

Electricity imports and multistate issues. The interstate nature of the U.S. electricity system inherently conflicts with §111(d)’s federalist structure. If a state that imports electricity, like California, were to adopt new end-use energy efficiency policies, the associated emission reductions might occur at EGUs located in other states, like Utah. EPA reports that its state goal calculation formula includes an adjustment to account for this effect, and further declares that, “[g]iven the extremely low cost of CO2 emission reductions achievable through demand-side energy efficiency programs, implementation of such programs is likely to reduce CO2 emissions at reasonable cost even for a state whose own affected EGUs achieve only part of the CO2 emission reduction benefit . . . .” (p. 233). For more significant interstate effects, EPA notes that “adjustments may be appropriate in some circumstances” (p. 343, n.253).

Any adjustments of this nature raise the possibility of double-counting.  There may be interstate conflicts over credit for emission reductions. EPA seeks comment on how, if at all, it may be able to allow states to take credit for out-of-state emission reductions resulting from energy efficiency programs while avoiding double-counting (p. 495). For renewable energy measures, EPA proposes that “a state could take into account all of the CO2 emission reductions from renewable energy measures implemented by the state, whether they occur in the state or in other states,” following the RPS model (p. 495). More broadly, “EPA solicits comment on whether an emission reduction becomes duplicative (and therefore cannot be used for demonstrating performance in a plan) if it is used as part of another state’s demonstration of emission performance under its CAA section 111(d) plan” (p. 448).

This all amounts to rather complicated calculations. A more elegant solution might be to follow California’s model and require each state to take responsibility for the emissions associated with its electricity imports. Could EPA defensibly adopt a rule that holds states accountable for the emissions associated with electricity imports?  How should EPA manage the potential problem of double-counting? Should EPA develop an interstate crediting system? 

There is much more to say about EPA’s proposed rule than I have mentioned in this series of four posts.  Stay tuned as LegalPlanet continues to follow the development of the rule, its implications, and any future litigation.

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Reader Comments

4 Replies to “PART IV – EPA’s Proposed 111(d) Rule: Some Insights & Open Legal Questions”

  1. I am glad that you raised the potential for “double counting” of reductions is more states adopt the California (CA) GHG accounting convention. But I think the CA procedure is even more controversial than you suggest.

    California includes other-state GHGs arising from the production of electricity that is sold into California in the California GHG baseline. Under this accounting method, when the state cuts of imported power, a GHG reduction is credited to CA, no the state in which the physical GHG reduction will occur–that is, if any does occur. The California regulation obliges all suppliers of electricity to the state to acquire and retire CA GHG quota (CCAs). Then the California regulator freely allocated quota to CA electricity distributors, in excess of the quota purchase obligations of their suppliers, through 2020. Finally, the regulator ruled that CA distributors could make CA quota available to in-state generators in their supply chain, but not to suppliers of imported power.

    The combination of the incorporation of imported power GHGs in the state’s baseline, along with the effective (though indirect) access to free quota for in-state generators, makes for a significant state barrier to trade in electricity. The CA rule does not assign comparable net GHG liabilities to generation sources with identical GHG profiles.

    My question: doesn’t the CA rule already breach federal laws protecting interstate commerce? (This is not a loaded question. I am very interested in your responses.)

    1. Thanks for your comment, Alyden. LegalPlanet has previously discussed the relationship between the dormant commerce clause and California’s cap-and-trade rules for imported electricity. See, e.g., Ann Carlson’s post from 2012:, and Rick Frank’s 2010 post: See also LegalPlanet’s discussion of the dormant commerce clause and California’s low carbon fuel standard here:

  2. Megan,

    Doesn’t the proposed rule have the effect of being more than a mere guideline in practice (at least in regards to the amount of emissions reductions required for each state) since 111(d)(2) gives EPA’s Administrator the power to prescribe a plan for the state in cases where the state plans are not satisfactory (in this case not achieving the 111(a)(1) “standard of performance” determined by the BSER)?


    1. Thank you for your comment, D. I tend to agree with your interpretation of the role of EPA’s emission guideline document. I think opposing states and industry parties will argue differently, however, in the context of challenging the final rule and any state plan disapprovals.

      See, for example, the section 111(d) analysis Hunton & Williams prepared last year for the Utility Air Regulatory Group ( On p. 8, the authors present evidence to suggest that emission guidelines were never meant to serve as legally enforceable emission standards. The analysis then goes on to highlight 40 CFR s. 60.24, which discusses instances in which state plans can diverge from the federal emission guideline. The Hunton & Williams analysis continually emphasizes that “EPA has no direct authority to impose . . . standards of performance on existing EGUs” and “EPA’s authority to influence the formulation of such standards [in state plans] is circumscribed” (p. 13).

      Hunton & Williams prepared its analysis prior to the release of the proposed rule, but the analysis offers a peek at some of the arguments that potential opponents are considering including in challenges to EPA’s authority. If I were an attorney for an opponent, I would latch onto the federalist “guideline” structure of 111(d) and the flexibility in EPA’s regulations to argue for maximum state plan flexibility and to contest that the proposed state goals are binding. As an attorney for EPA, I would expand upon the arguments that the agency previewed in the proposed rule preamble to support its position that “the state-specific goals will be binding emission guidelines” (see, e.g., pp. 357-63). As you mention, that EPA has authority to prescribe a plan for a state that fails to submit a satisfactory plan supports EPA’s position.

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About Megan

As the Emmett/Frankel Fellow at UCLA School of Law from 2012 to 2016, Megan Herzog taught and researched environmental law and policy issues for the Emmett Institute on C…

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About Megan

As the Emmett/Frankel Fellow at UCLA School of Law from 2012 to 2016, Megan Herzog taught and researched environmental law and policy issues for the Emmett Institute on C…

READ more