The Final Clean Power Plan

(Originally published in Issue 2, 2015 American Coal Magazine, pg. 39)

Gifford, Sopkin, Larson - The Final CPP

EPA’s Carbon IRP Process, State Plan Options, and Implications for 2016 State Legislative Sessions

By Raymond L. Gifford, Gregory E. Sopkin and Matthew S. Larson – Wilkinson, Barker, Knauer LLP

The Environmental Protection Agency’s (EPA) renovated the final Clean Power Plan rule in August, sparking discussion of changed Building Blocks, new emission targets, state-based and national cap-and-trade, “just say no,” and lots of number-crunching by environmental and utility attorneys ill-equipped to handle such complicated equations. Deep in the 1,500 pages of the final rule is what the final rule means for state policymakers and legislators in upcoming 2016 sessions. Because even EPA concedes that this state legislation will be necessary to implement the final rule in many instances, the upcoming legislative sessions will be crucial for how the rule gets treated in the states.[1]

 

Background: EPA’s National Carbon Resource Planning

Integrated resource planning is historically done by state utility commissions, which oversee and ultimately approve integrated resource plans (IRPs) submitted by regulated utilities. In wholesale market regions, “planning” is done by the market and demand for electricity in the given region. In many states, the process of resource planning involves months of administrative litigation, including discovery and live hearings, to craft plans suited to the utility in question and with express consideration of costs to customers and system reliability. Environmental regulators, with a few limited exceptions,[2] are not involved in the IRP process in any material way.

Superseding the traditional authority of state utility commissions, EPA candidly engages in a national resource planning process to craft the final rule and determine the “best system of emission reduction,” the operative legal standard under Section 111(d) of the Clean Air Act.[3] At a high-level, EPA conducted an extensive review of the actions of utilities in their specific IRP contexts and used them to formulate a nationwide “Carbon IRP.”  This Carbon IRP gives rise to stringent emission standards for coal-fueled power plants and natural gas combined cycle units under the final rule, and the ultimate result of EPA’s Carbon IRP is a final rule that is far more punitive on coal-centric states than the initially proposed rule. One could write at length on the computation of the emission standards, but a related and less visible consequence of EPA’s approach is what it means as a matter of state law in the near-term.

 

Options: State Plan Permutations

At the risk of oversimplification, state plans are due September 6, 2016 unless a state files an “initial state plan” and a request for a two-year extension to September 6, 2018. The final rule contemplates two types of state plan approaches: (1) an “emissions standard” approach and (2) a “state measures” approach.[4]  The emissions standard approach places all of the compliance requirements directly on affected coal- and gas-fired sources, which are federally enforceable by EPA and through the citizen suit provision of the Clean Air Act. For example, this requires coal-fueled power plants to achieve a rate-based emission rate of 1,305 lbs CO2/MWh.[5] This will be difficult, if not impossible, in many states given the overly-optimistic inputs (specifically with regard to potential renewable energy additions) plugged into the Carbon IRP process. The impracticality of this compliance pathway means one of two things, likely depending upon the political makeup of a given state: (1) states will not submit a state plan; or (2) states will embrace the “state measures” approach.

The “state measures” approach is a variation of the so-called “state commitment approach”[6] referenced approvingly by several states in comments on the proposed rule.  This approach requires the use of the mass-based state goal and “would result in the affected EGUs meeting the statewide mass-based goal by allowing a state to rely upon state-enforceable measures on entities other than affected EGUs, in conjunction with any federally enforceable emission standards the state chooses to impose on affected EGUs.”[7]  Accordingly, states could employ policies and programs (i.e., energy efficiency programs or renewable portfolio standards) without rendering them federally enforceable.

The “state measures” approach is facially attractive to meet the standards developed through the Carbon IRP because it does away with the federal enforcement overlay that concerned many states in comments on the proposed rule. Further, it allows states to structure compliance plans in a way that transitions a portion of the compliance burden away from its baseload generation fleet.  However, there is a catch because “’[s]tate measures’ refer to measures that the state adopts and implements as a matter of state law. Such measures are enforceable only per state law, and are not included in and codified as part of the federally enforceable state plan.”[8]  Accordingly, for a state to rely upon renewable energy adoption or energy efficiency deployment under a “state measures” plan, these would need to be codified and contain a substantive enforcement mechanism. The voluntary standards adopted in many states to incent renewable energy acquisitions or encourage utilities to offer energy efficiency programs are of no value; it is as if these voluntary measures do not exist for purposes of compliance through a “state measures” plan. Instead, states need codified renewable portfolio standards (“RPSs”) or energy efficiency targets to include them in a “state measures” plan. Many RPSs are subject to retail rate impact caps, too, such that if a utility is charging a specific amount of annual sales (1%, 2%, etc.), then the utility is not required to meet the percentage requirements of the RPS.  These off-ramps are well-established consumer protection mechanisms, but also create uncertainty as to whether the full amount of renewable energy will be adopted to achieve the RPS.

A related issue is fragmented jurisdiction over different types of utilities. Environmental regulators have jurisdiction over generation sources such as coal-fueled power plants, but many state utility regulators have limited jurisdiction over municipal utilities and cooperatives. This means that utility regulators do not approve IRPs for municipal utilities and cooperatives, which in turn makes it difficult to sync up all utilities’ emission reduction activities within a single state. The same is true with RPSs and energy efficiency mandates – investor-owned utilities are subject to these requirements but municipal utilities and cooperatives are either exempt or under relaxed standards. Relaxed standards can mean diminished requirements or lack of true enforcement, both of which cause significant issues with regard to a “state measures” approach.

 

Outcomes: Anticipated Issues at State Legislatures in 2016

The final rule is more than a math and a fuel-switching exercise, contrary to many a public affairs campaign and reckless Twitter feed. The Clean Power Plan is coming to a state legislature near you early in 2016 because absent sweeping action by many state legislatures, the “state measures” approach is simply off the table under the existing statutory architecture of many states. Assuming the predicted rush of states (among states that chose to submit a plan) to the “state measures” approach, state legislatures will be called upon to pass significant energy policy legislation during the upcoming session dictating increased renewable adoption, removing retail rate caps in RPSs or implementing enforceable energy efficiency targets to allow states to meet their Carbon IRP goals. There could also be strains of legislation forcing municipal utilities and cooperatives into significantly more extensive regulatory regimes (e.g., IRP processes, RPSs, etc.) States that lack codified and enforceable RPSs or energy efficiency targets and choose to move forward with a “state measures” plan without new state legislation do so at their own peril and subject to risk of litigation or rejection of their state plan by EPA.


Endnotes:

[1] Environmental Protection Agency, 40 CFR Part 60, Docket No. [EPA-HQ-OAR-2013-0602; FRL-XXXX-XX-OAR], Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Generating Units, at 1047 (Aug. 3, 2015) (“Some commenters argued that the 1-year period for initial submittals and, even assuming an extension, the additional 1- to 2-year period for final submittals were unreasonably short, particularly in light of the possibility that some state legislatures might need to act to provide adequate legal authority for these particular plans. We are not finalizing the 1-year extension for single state submittals, and we have addressed concerns about legal authority for the initial submittals by allowing states to identify remaining legislative action in those submittals.”) (hereinafter CPP Final Rule).

[2] See, e.g., Colo. Rev. Stat. § 40-3.2-204(2)(b) (outlining a role for the Colorado Department of Public Health and Environment in reviewing the impacts of a utility’s emission reduction plan under the Clean Air-Clean Jobs Act in Colorado).

[3] CPP Final Rule, at 323 (“A survey of integrated resource plans (IRPs), included in the docket, shows that fossil fuel-fired EGUs are taking actions to reduce emissions of both non-GHG air pollutants and GHGs. Some fossil fuel-fired EGUs are investing in lower- or zero-emitting generation. In fact, our review indicates that the great majority of fossil fuel-fired generators surveyed are including new RE resources in their planning. In addition, some fossil fuel-fired EGUs are using those measures to replace their higher-emitting generation.”)

[4] See, e.g., CPP Final Rule, at 32-33 (“A state will be able to choose to establish emission standards for its affected EGUs sufficient to meet the requisite performance rates or state goal, thus placing all of the requirements directly on its affected EGUs, which we refer to as the ‘emission standards approach.’ Alternatively, a state can adopt a ‘state measures approach,’ which would result in the affected EGUs meeting the statewide mass-based goal by allowing a state to rely upon state-enforceable measures on entities other than affected EGUs, in conjunction with any federally enforceable emission standards the state chooses to impose on affected EGUs.”)

[5] CPP Final Rule, at 231 (“For fossil fuel-fired steam generating units, we are finalizing a performance rate of 1,305 lb CO2/MWh. For stationary combustion turbines, we are finalizing a performance rate of 771 lb CO2/MWh.”)

[6] 79 Fed. Reg. 34,902 (June 18, 2014) (“[U]nder the state commitment approach, the state requirements for entities other than affected EGUs would not be components of the state plan and therefore would not be federally enforceable. Instead, the state plan would include an enforceable commitment by the state itself to implement state-enforceable (but not federally enforceable) measures that would achieve a specified portion of the required emission performance level on behalf of affected EGUs.”)

[7] CPP Final Rule, at 33 (emphasis added).

[8] CPP Final Rule, at 880, n. 782 (emphasis added).

10. December 2015 by Jason Hayes
Categories: CO2, CPP, Energy, Environment, EPA, Policy, USA | Tags: , , , | Comments Off on The Final Clean Power Plan