U.S. Environmental Protection Agency Proposes Regulations to Limit Carbon Dioxide Emissions from Existing Electric Utility Generating Units

June 4, 2014

On June 2, 2014, the United States Environmental Protection Agency (“EPA”) issued its long-awaited proposed rule to limit carbon dioxide emissions from existing electric utility generating units (“EGU”).  The proposed rule constitutes the EPA’s latest step in implementing the Obama Administration’s June 2013 Climate Action Plan,[1] and follows the proposed rules affecting newly constructed EGUs that were published by the EPA on January 8, 2014.[2]  Under the EPA’s current proposal, nationwide emissions of carbon dioxide from the power sector would be cut by up to 30% from the 2005 baseline by the year 2030.  The required emission reductions would vary state-by-state, and the proposed rule provides each State flexibility in determining how the emission reductions would be achieved.[3]

A.   The EPA Established CO2 Emission “Goals” for Each State Based on the “Best System of Emission Reduction” Under Section 111 of The Clean Air Act.

The EPA’s performance standards for existing EGUs have been proposed under Section 111(d) of the Clean Air Act, which requires the Agency to develop a procedure for States to establish “standards of performance” for affected sources.[4]  Those standards must reflect the degree of emission limitation achievable through the application of the “best system of emission reduction” (“BSER”) that, taking into account the cost of achieving such reduction and any non-air quality health and environmental impacts and energy requirements, the EPA determines has been adequately demonstrated.[5]  In rulemaking under Section 111(d), the EPA will typically determine the BSER for a source or category of sources and calculate the amount of emission reduction achievable through applying the BSER.  Each State will then promulgate standards of performance that reflect that amount of emission reduction, and incorporate those standards into a compliance plan that is submitted to the EPA for approval.

In this proposed rule, the EPA undertook a seven-step process in order to determine interim and final goals for each State’s emissions of CO2 from affected EGUs.[6]  First, the EPA obtained State-by-State data concerning total annual quantities of CO2 emissions, net electricity generation measured in megawatt-hours, and total electric generating capacity in megawatts based on 2012 data for all affected EGUs.  In Steps 2 through 5, the EPA applied various “building blocks” of emission reductions to the sources within each State.  These “building blocks” formed the core of the EPA’s determination of the BSER, and consisted of the following elements:

  • Building Block 1:  Reducing the carbon intensity of electricity generation at individual affected EGUs through heat rate improvements.  These measures entail improving the efficiency with which EGUs convert fuel heat input to electricity output, such as through upgrades to boilers, steam turbines, and control systems.[7]  In contrast to the EPA’s proposed rule for new EGUs, however, the Agency did not include carbon capture and storage in its determination of the BSER given the substantial costs of integrating a retrofit system into an existing facility.[8]  The EPA likewise did not include fuel switching at individual units (e.g., from coal to natural gas) as part of its BSER assessment on account of the capital and operating costs.[9]
  • Building Block 2:  Reducing emissions from the most carbon-intensive affected EGUs by shifting generation to less carbon-intensive affected EGUs.  Here, the EPA assumed an increased utilization of units with lower CO2 emissions (e.g., natural gas combined cycle units) and a corresponding reduction in the utilization of units with higher CO2 emissions (e.g., coal-fired units).[10]
  • Building Block 3: Reducing emissions from all affected EGUs by shifting generation to low- or zero-carbon emitting units (e.g., those using solar, wind, hydro, geothermal, landfill gas, and biomass).  In this step, the EPA estimated the total quantities of electricity generation from renewable sources and from under-construction or preserved nuclear capacity (operated at a utilization rate of 90 percent) for each State, and applied a corresponding reduction in the amount of CO2 emissions from fossil-fired units.[11]  In this building block, the EPA highlights nuclear power (among other things) as a viable and economic means to provide “carbon-free generation” to reduce CO2 emissions from fossil fuel-fired generating facilities.  The EPA identifies both (i) completing all nuclear units currently under construction (including Plant Vogtle in Georgia and V.C. Summer in South Carolina) and (ii) avoiding further retirement of existing nuclear capacity, as means to replace fossil fuel-fired generation.  In particular, the EPA states that preserving “at-risk” nuclear capacity (i.e., at-risk of retirement for economic reasons) should be a “reasonable cost” means of achieving CO2 reductions.[12]
  • Building Block 4:  Reducing emissions from affected EGUs in the amount that results from the use of demand-side energy efficiency that reduces the amount of generation required.  At this step, the EPA estimated the amount by which the utilization of each State’s affected EGUs would be reduced on account of the implementation in that State of demand-side energy efficiency programs.[13]

After the application of these building blocks in Steps 2 through 5, the EPA next computed an adjusted average annual CO2 emission rate for each State using a formula designed to express numerically the level of CO2 reductions that the EPA expects will be achieved through the application of the building blocks in each year.  Finally, in Step 7 the EPA computed, for each State, goals for the adjusted, output-weighted-average pounds of CO2 per net megawatt-hour from all affected fossil fuel-fired EGUs within the State.  The EPA proposed both an interim goal for the State to meet beginning in 2020 and a final goal for the State to meet by 2030.  The final goals range from a low of 215 pounds of CO2 per megawatt-hour for Washington State to a high of 1,783 in North Dakota.[14]  According to the EPA, “[t]he state-specific CO2 goals derived from application of the methodology vary because, in setting the goals for a state, the EPA used data specific to each state’s EGUs and certain other attributes of its electricity system (e.g., current mix of generation resources).”[15]

B.   The Proposed Rule Highlights Regional and Multi-State Implementation Issues.

The EPA’s proposed rule recognizes that existing institutions such as regional transmission organizations (“RTOs”), which administer multi-State electricity markets that enable utilities across the RTO footprint to procure electricity using the lowest cost mix of generation (or “economic dispatch”), have also integrated environmental costs (e.g., emissions allowances, operating limits) and demand-side measures into their multi-State economic dispatch models.  The EPA therefore  concludes that the measures in Building Blocks 2, 3, and 4 “can be accommodated through the existing regional components of the regional transmission system,” i.e., RTOs.[16]  The proposed rule further acknowledges that existing RTOs (and their single-state counterpart, independent system operators (“ISOs”)) can “provide a structure for achieving efficiencies by coordinating the state plan approach applied throughout a grid region” and in “implementing multi-State plans,” for example, “by jointly demonstrat[ing] CO2 emission performance by affected EGUs across the entire ISO/RTO footprint,”[17] and permitting the distribution of emissions reductions between and among the States in the RTO footprint (e.g., through interstate trading of renewable energy credits).[18]

C.   The Proposed Rule Would Provide States Flexibility in Meeting the Emission Goals.

Although the EPA’s proposed rule and the preamble set forth state-specific CO2 emission goals and the methodology by which the Agency established those goals, the rule would not mandate how a State must meet its goals.  Rather, the rule would “allow[] states to pursue policies to reduce carbon pollution that: 1) continue to rely on a diverse set of energy resources, 2) ensure electric system reliability, 3) provide affordable electricity, 4) recognize investments that states and power companies are already making, and 5) can be tailored to meet the specific energy, environmental and economic needs and goals of each state.”[19]  The State plans would have the following aspects and flexibilities:

  • Each State would be required to determine the CO2 emission performance levels for its affected EGUs that are equivalent to the State-specific CO2 goal in the emission guidelines, as well as the measures needed to achieve those levels and the overall goal.
  • A State would have flexibility concerning the form of the CO2 emissions goals that must be met within the State.  It could adopt the rate-based form of the goal established by the EPA (e.g., a standard expressed as pounds of CO2 per kilowatt-hour) or it may adopt an equivalent mass-based form of the goal.[20]
  • A State would not be required to use each and every one of the measures that the EPA determines constitute the BSER, or to apply any one of those measures to the same extent that the EPA determined is achievable.  Rather, each State could establish its plan around any combination of measures it prefers in order to achieve its CO2 emission reduction goal.
  • The rule would also allow a State to submit its own compliance plan or to collaborate with other States on multi-State plans.[21]
  • A State may take a “portfolio approach,” whereby it would impose CO2 emission limits applicable to affected EGUs and also enact enforceable renewable energy and energy efficiency measures on non-EGU entities.[22]
  • Although the rule would not require the implementation of intra-State or multi-State cap-and-trade programs, the EPA recognizes that States would “have the option of structuring programs (e.g., allowance-trading programs) under which full responsibility [for achieving the required CO2 emissions reductions] rests on the affected EGUs.”[23]

Under the proposed rule, the EPA would evaluate and approve State plans based on four general criteria: (1) enforceable measures that reduce CO2 emissions from affected EGUs; (2) the projected achievement of emission reductions equivalent to the goals established by the EPA and on a timeline equivalent to that in the emission guidelines; (3) quantifiable and verifiable emission reductions; and (4) a process for biennial reporting on plan implementation, progress toward achieving CO2 goals, and implementation of corrective actions, if necessary.

D.   The EPA Expects to Finalize the Rule by June 1, 2015.

After publishing the proposed rule in the Federal Register, the EPA will provide a 120-day period for public comments.  The EPA will also convene four public hearings.  Two will be held on July 29, 2014—one in Atlanta, Georgia and one in Denver, Colorado.  Another hearing will be held on July 31, 2014, in Pittsburgh, Pennsylvania, and a separate hearing will take place the week of July 28, 2014, in Washington, D.C.

In accordance with the Presidential Memorandum on Power Sector Carbon Pollution Standards,[24] the EPA expects to finalize the rulemaking by June 1, 2015.  The EPA is proposing a deadline of June 30, 2016 for States to submit their compliance plans to the EPA.  However, the Agency is also proposing an optional extended two-phased submittal process in the event that a State needs more than one year to complete all of the actions required for its final state plan.[25]  Nevertheless, all States would be required to begin meeting their CO2 emission goals by 2020.  If a State fails to submit a compliance plan, or if the EPA does not approve a State’s plan, then the EPA would be required to establish a plan for that State under Section 111(d)(2)(A) of the Clean Air Act.[26]

   [2]   Standards of Performance for Greenhouse Gas Emissions From New Stationary Sources: Electric Utility Generating Units, 79 Fed. Reg. 1430 (Jan. 8, 2014).

   [3]   To review the proposed rule, EPA’s Press Release and Fact Sheets, please see http://www2.epa.gov/carbon-pollution-standards/clean-power-plan-proposed-rule.

   [4]   42 U.S.C. § 7411(d).

   [5]   Id. § 7411(a)(1).

   [6]   See Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units (prepublication draft) at 350-355.

   [7]   Id. at 142-143, 158-59, 351-52.

   [8]   Id. at 244 (“the EPA does not propose to find that CCS [carbon capture and storage] is a component of the best system of emission reduction for CO2 emissions from existing fossil fuel-fired EGUs.”)

   [9]   Id. at 240 (“The EPA’s economic analysis suggests that there are more cost effective opportunities for coal-fired utility boilers to reduce their CO2 emissions than through natural gas conversion or co-firing. As a result, the EPA has not proposed at this time to include this option in the BSER and has not incorporated implementation of the option into the proposed state goals.”)

  [10]   Id. at 146-149, 352-53.

  [11]   Id. at 151-52, 353.

  [12]   Id. at 214-15

  [13]   Id. at 152, 353-54.

  [14]   Id. at 346-348, Table 8.

  [15]   Id. at 38.

[16]   Id. at 310-311.

[17]   Id. at 430-431

[18]   Id. at 494-495

  [19]   Id. at 15.

  [20]   Id. at 41.

  [21]   Id. at 17.

  [22]   Id. at 44.

  [23]   Id. at 18.

  [25]   Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units (prepublication draft) at 115.

  [26]   42 U.S.C. § 7411(d)(2)(A).

Gibson, Dunn & Crutcher lawyers are available to assist in addressing any questions you may have about these developments.  To learn more about the firm’s Environmental Litigation and Mass Tort Group, Energy and Infrastructure Group or Energy, Regulation and Litigation Group, please contact the Gibson Dunn attorney with whom you usually work or the authors in the firm’s Washington, D.C. office:   

Raymond B. Ludwiszewski (202-955-8665, [email protected])
William S. Scherman (202-887-3510, [email protected])
William R. Hollaway Ph.D. (202-955-8592, [email protected])
Charles H. Haake (202-887-3581, [email protected])
Brandon Johnson (202-955-8587, [email protected])

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