alerts & publications

Environmental Protection Agency Proposes Greenhouse Gas Emissions Reductions

On June 2, 2014, the U.S. Environmental Protection Agency (“EPA”) proposed greenhouse gas (“GHG”) emissions reduction regulations that will require a 30% reduction of GHG emissions over 2005 levels by 2030 for existing fossil fuel-fired electric generating units (“EGUs”) (the “Clean Power Plan”). Publication in the Federal Register of the Clean Power Plan (which has not yet occurred) will start a 120-day public comment period. In addition, EPA will hold four public hearings on the Clean Power Plan during the week of July 28, 2014 in Atlanta, GA, Denver, CO, Pittsburgh, PA, and Washington, DC.

Background

Following suits filed in 2006 by a consortium of twelve states seeking to compel action by EPA on GHG emissions, the Supreme Court in U.S. v. Massachusetts, 549 U.S. 497 (2007), found that EPA was empowered to regulated GHG emissions from mobile and stationary sources under the federal Clean Air Act. In 2009, President Obama pledged to reduce GHG emissions by 17% over 2005 levels by 2020 and by 83% by 2050 as part of a United Nations convention that has also elicited non-binding commitments from other countries which have not entered into the Kyoto accord, including China. In May 2014, the Administration issued its “All-of -the above” Energy Strategy which provides for regulation of mobile GHG sources, power industry sources and other industrial sources in sequence to achieve GHG reduction and energy independence goals. Also last month, the Supreme Court in EPA v. EME Homer City Generation, L.P., 572 U.S. __ (2014), issued a further opinion that supported EPA’s regulatory authority under the Clean Air Act while at the same time noting that the Act requires deference to the States on implementation of new regulations under State Implementation Plans (“SIPs”).

Proposed Rule

EPA’s Clean Power Plan includes state-specific goals, expressed as average emission rates, for carbon dioxide (“CO2”) emissions from the power sector, as well as guidelines for states to follow in developing plans to achieve those goals. These are not requirements on specific EGUs, instead each state must meet the goal by lowering overall “carbon intensity” of its power sector. Under the Clean Power Plan, EPA anticipates that, by 2030, CO2 emissions from the power sector will be reduced approximately 26-30% from 2005 CO2 emission levels, but that coal and natural gas will remain the two leading sources of electricity generation, each providing more than 30% of projected generation.

EPA expects to finalize the Clean Power Plan by June 1, 2015 and to require initial state SIP amendment submissions by June 30, 2016, with extensions of up to two years available for the submission of final plans in some instances. EPA proposes to approve or deny each state plan within 12 months after submittal. In addition, no less than every two years, beginning January 1, 2022, each state would be required to compare the emissions performance achieved by affected EGUs with the emissions performance projected in the state plan, and report the results to EPA.

The Clean Power Plan regulations are predicated on Section 111(d) of the Clean Air Act, 42 U.S.C. Section 7411(d), which allows EPA to require States to submit SIP amendments that adopt standards of performance for stationary sources as to air pollutants for which air quality criteria have not been issued. Under Section 111(d) , state SIP amendments must establish standards of performance that reflect the degree of emissions limitation achievable through the application of the “best system of emission reduction… adequately demonstrated” (“BSER”) taking into account the cost of achieving such reduction and any non-air quality health and environmental impacts and energy requirements. EPA based its BSER determination for EGU CO2 emissions on a range of emission reduction measures that fall into four main categories, or “building blocks:” (i) reducing emission rates at affected EGUs, including by improving combustion efficiency (heat rate), switching from coal to natural gas, and applying pollution controls such as carbon capture and storage (“CCS”), (ii) increasing dispatch of lower-emitting EGUs, such as natural gas-fired combined cycle units, (iii) increasing dispatch of low and zero-emitting energy sources, such as nuclear, wind, solar and geothermal, and (iv) reducing overall demand for electricity. Notably, EPA rejected stand-alone retrofit CCS as BSER.

EPA has proposed state-specific, adjusted output-weighted-average CO2 emissions rates for affected EGUs, based on the amount of emissions (on a net generation basis) that can be reduced at existing fossil fuel-fired EGUs through application of BSER, including consideration of each state’s fuel mix, electricity market and other state-specific factors. A state can adopt the rate-based goal or an equivalent mass-based goal, and may achieve the emissions reductions through any combination of EPA’s building blocks and any other measures, such as market-based trading programs. In addition, states may participate in multi-state programs, such as the existing Regional Greenhouse Gas Initiative (“RGGI”) CO2 cap and trade program.

State plans must include emission limits for affected EGUs which, for coal-fired facilities, are expected to be in the range of 1100 pounds of carbon dioxide per megawatt-hour (rate-based systems). However, states can adopt a portfolio approach that includes enforceable CO2 emission limits for EGUs as well as other enforceable measures, such as renewable energy and demand-side energy efficiency measures, that avoid EGU CO2 emission limits (mass-based systems). States also may permit use of “cap and trade” credits such as those available from the RGGI consortium of northeast states, which holds auctions on a quarterly basis (the next auction will occur on June 4, 2014). States adopting such a portfolio approach and choosing to achieve rate-based (rather than mass-based) goals would be able to make adjustments to the emissions rates of affected EGUs to account for measures that reduce state-wide CO2 emissions but do not affect emissions rates from affected EGUs, such as demand reduction or dispatch of low or zero-emission sources.

If a state fails to submit a complete plan by the deadline or the plan is not approvable, it is likely that EPA would develop, implement, and enforce a Federal Implementation Plan (“FIP”) to meet the emission reductions, and could take enforcement actions pursuant to Sections 113(a) – (h) of the Clean Air Act. In EPA v. EME Homer City Generation, L.P., the Supreme Court upheld EPA’s authority to implement a FIP for states that failed to create acceptable SIPs under the Cross-State Air Pollution Rule. EPA is also requesting comments on the consequences that should apply to an approved state plan that fails to achieve the interim or final goal, including comments regarding whether EPA should promulgate a mechanism under Section 111(d) similar to the SIP mechanism in section 110, where the EPA would require the state to cure the deficiency with a new plan within a specified period of time, after which the EPA would have the authority to promulgate a FIP.

Significant Open Issues

The Clean Power Plan is expected to face stiff opposition from states with the primarily impacted coal-fired facilities, including West Virginia, Ohio, and Indiana, where most of the nation’s 600 coal-fired power plants reside. Industry groups and a consortia of Attorneys General have indicated that a court challenge will likely focus on the scope of EPA’s authority under Section 111(d) of the Clean Air Act, a largely untested area of law. However, even if enforceable, significant issues and uncertainty, including the following, remain outstanding.

• What criteria will the EPA apply to approve SIPs utilizing mass-based limits? This is a crucial issue, because, under a rate-based system, total CO2 emissions within a State can increase with increases in the number or extent of generation facilities. It appears that in order to implement a mass-based limit, such as a cap and trade system, states will be required to predict future electricity demand and corresponding generation in order to set the applicable emission limits in tons of CO2.
• How will changes in demand as a result of population shifts and economic factors from the 2005 baseline through 2030 and subsequent years be addressed? In the past twenty-six years states such as Arizona have experienced large increases in population, with resulting increases in energy demand, while during the 2008 recession energy consumption declined steeply in many locales. Over the next twenty-six years, as demand shifts due to various circumstances in certain states, how will these changes be factored into state emission limits?
• How will increases in non-traditional forms of low and zero-emission generation, such as residential distributed solar generation, be addressed? Will states receive full credit in their emission rates for the electricity generated from these sources, or will generation of this type be treated as demand reduction measures, and if so, how will they be reflected in state emission-rates?
• What enforcement mechanism will be implemented in the event that states opt to utilize a portfolio approach, placing federally enforceable legal responsibilities on a variety of non-EGU entities to offset emissions through use of renewable energy, nuclear power, and demand-side energy efficiency?
• How will EPA administer enforcement mechanisms for non-compliance? As indicated above, EPA has requested comments as to whether it should promulgate a mechanism similar to the SIP mechanism in section 110, providing for the possibility that EPA would eventually have the authority to promulgate a FIP under the Clean Power Plan. EPA has also requested comments on how consequences for non-compliance should vary depending on reasons for deficiency in performance, including triggering of corrective measures or plan revisions.

This memorandum is a summary for general information and discussion only and may be considered an advertisement for certain purposes. It is not a full analysis of the matters presented, may not be relied upon as legal advice, and does not purport to represent the views of our clients or the Firm. Eric Rothenberg, an O'Melveny partner licensed to practice law in Missouri and New York, Kelly McTigue, an O'Melveny partner licensed to practice law in California, Danielle Gray, an O'Melveny partner licensed to practice law in New York, John Renneisen, an O'Melveny counsel licensed to practice law in the District of Columbia, and Jesse Glickstein, an O'Melveny associate licensed to practice law in New Jersey and New York, contributed to the content of this newsletter. The views expressed in this newsletter are the views of the authors except as otherwise noted.

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