On April 13, 2012, the U.S. Environmental Protection Agency (“EPA”) published its first-ever carbon dioxide emission standards for new fossil fuel-fired power plants (“Draft Rule”). The Draft Rule essentially requires all new fossil fuel-fired power plants to meet the carbon dioxide (“CO2″) emissions profile of a combined cycle natural gas plant. While most new natural gas plants will not be required to include any new technologies, no new coal plants can be constructed without carbon capture and sequestration (“CCS”) capabilities. Litigation is expected over the Draft Rule due to the novel nature of the Draft Rule in regulating CO2 and EPA’s departure in several instances in the Draft Rule from its usual method of setting new source performance standards (“NSPS”) on a source category by source category basis.
The Draft Rule applies only to new fossil fuel-fired power plants, but we note that the Draft Rule will trigger a requirement under the Clean Air Act for the EPA (in coordination with the states) to address CO2 emissions from existing sources. With approximately 600 existing coal plants in the U.S., this future action to regulate CO2 emissions from existing sources is arguably more significant than the Draft Rule itself.
Below we provide highlights of the Draft Rule. For a more in-depth analysis of the Draft Rule and its implications for your business, please contact Richard Saines, Marisa Martin or Daniel De Deo. Full contact details provided in the left-hand column.
The Draft Rule is the result of litigation that commenced in 2008 between the EPA and several environmental groups, states and the City of New York. The plaintiffs in that litigation challenged a 2006 EPA rule setting NSPS for electricity generating units (“EGUs”) that did not address greenhouse gases (“GHGs”). To resolve the litigation, the EPA and plaintiffs entered into a settlement agreement in December 2010 that required the EPA to take certain actions relating to NSPS for electricity generating units. The EPA agreed to issue a proposed rule under Section 111(b) of the Clean Air Act that includes performance standards for GHGs for new and modified electricity generating units. The EPA also agreed to issue a proposed rule under Section 111(d) of the Clean Air Act setting emission guidelines for GHGs from existing electricity generating units. After nearly a year of delay, the EPA issued the Draft Rule in order to comply with the first requirement in the settlement.
CO2 Emissions Standard & Covered Electricity Generating Units
The Draft Rule establishes a NSPS equal to a single output-based CO2 emission limit of 1,000 lb CO2/MWh (“CO2 Standard”) that is applicable to new electricity generating units (referred to as “Covered EGUs”, defined below). The CO2 Standard is equivalent to the CO2 emissions from a natural gas combined cycle power plant. The EPA determined that the CO2 Standard constituted the “best system of emission reduction” (“BSER”) which has been “adequately demonstrated”, which is the definition of “standard of performance” under Section 111(a) of the Clean Air Act.
Notably, the EPA proposes a new TTTT category of “new sources” subject to the CO2 Standard (deemed “Covered EGUs”) that includes both coal and natural gas power plants in one category. Generally, the EPA sets a NSPS based on the type of technology used and does not combine sources into one category with one NSPS. The new TTTT category combines boilers and integrated gasification combined cycle (“IGCC”) units (currently included in the Da category) and combined cycle units that generate electricity for sale and that meet certain size criteria (currently included in the KKKK category). The Draft Rule defines a “Covered EGU” as “any fossil fuel-fired combustion unit that supplies more than one-third of its potential annual electric output and more than 25 MW net-electrical output (MWe) to any utility power distribution system for sale” with some exceptions. Based on this definition, Covered EGUs include electric utility steam generating units (“boilers”); stationary combined cycle combustion turbines and their associated heat recovery steam generator (“HRSG”) and duct burners; and IGCC units, including their combustion turbines and associated HRSGs. Covered EGUs do not include stationary simple cycle combustion turbines (e.g., peakers) or EGUs located in non-continental areas. Also, solid waste incineration units subject to emission requirements under Section 129 of the Clean Air Act are not subject to the Draft Rule.
New coal-fired EGUs would need to capture approximately 50% of the CO2 at the exhaust stream at startup to meet the CO2 Standard. Alternatively, the EPA is proposing a 30-year averaging compliance option that would be available for coal- and pet coke-fired Covered EGUs that did not install carbon capture technology at startup. Under this option, coal- and pet coke-fired Covered EGUs, with EPA’s approval, could comply with a less stringent CO2 annual limit for the first ten years of operation and a more stringent CO2 limit for the last twenty years such that on a 30-year basis, the facility would meet the CO2 Standard. The initial ten-year limit would be 1,800 lb CO2/MWh, which is the best demonstrated performance of a coal-fired facility without CCS. The CO2 limit for the following twenty years would be 600 lb CO2/MWh and beyond the 30th year, the source would be required to meet the CO2 Standard (i.e., 1,000 lb CO2/MWh).
- Trading of Emission Credits to Meet the CO2 Standard
After the federal cap-and-trade program proposal failed on the national level in 2010, there has been speculation whether the EPA could allow for the trading of emission credits under the existing Clean Air Act. Some commentators interpreted the NSPS provisions in Section 111 of the Clean Air Act to allow EPA to authorize the trading of emission credits to meet a NSPS for greenhouse gases. This is based on the language of Section 111 as well as the fact that the EPA has explicitly determined that a cap-and-trade program constituted BSER for other non-greenhouse gas pollutants (e.g., mercury). Without significant discussion, the Draft Rule states that no averaging or emissions trading among Covered EGUs would be allowed for the CO2 Standard and that each Covered EGU would be required to meet the CO2 Standard. As discussed below, whether trading may be authorized for regulating CO2 from existing power plants (either directly or through state equivalency determinations) remains an open question.
Sources Excluded from the Draft Rule
- Modified Sources & Reconstructed Sources
Covered EGUs undergoing modifications that increase CO2 emissions and reconstructed sources are not required to meet the CO2 Standard under the Draft Rule. The EPA notes that it had insufficient information to develop a proposal for reconstructed sources or sources that undergo “modifications” that would normally trigger NSPS and subject the source to the CO2 Standard. The EPA states that most modifications that would increase the maximum achievable hourly rate of CO2 emissions would likely be related to the installation of pollution control equipment, which is an action specifically exempted from the definition of modification. Sources undergoing modifications or reconstructed sources would be subject to any future CO2 standards that are issued for existing sources (see further discussion below).
Notably, the EPA creates a new category of power plants – deemed “transitional sources” – in the Draft Rule. A transitional source is defined as a power plant that has received approval for its Prevention of Significant Deterioration (“PSD”) construction permit by April 13, 2012 (i.e., the date of Federal Register publication of the Draft Rule) and has commenced construction by April 13, 2013. The EPA justifies its exclusion of transitional sources from the Draft Rule based on gaps in information regarding the extent such sources have sunk costs and material commitments such that the CO2 Standard would not be considered BSER.
Approximately 15 power plants are expected to be considered transitional sources and thus not subject to the Draft Rule. The Draft Rule specifically notes that although transitional sources are exempted from the CO2 Standard, they would be subject to the requirements the EPA will promulgate for existing sources under Section 111(d) of the Clean Air Act, which is discussed in more detail below. In addition, a transitional source’s PSD permit may also contain CO2 limits.
Application of CO2 Standard to Existing Sources
The EPA projects in the Draft Rule that most new power plants in the U.S. will be natural gas-fired and thus not required to install any add-on technology to comply with the Draft Rule. Any new coal plant built in the U.S. will be required to install CCS in order to comply with Draft Rule but new coal plants that are not considered “transitional sources” (and exempted from the Draft Rule) are expected to be few, according to the EPA. Because there are hundreds of coal fired-power plants already constructed and operating without CCS, a significant issue will be the extent to which the Draft Rule will affect existing power plant sources.
- Emission Guidelines for Existing Sources
The EPA emphasizes that the Draft Rule, promulgated pursuant to Section 111(b) of the Clean Air Act, does not affect existing power plant sources. While technically accurate, Section 111(d) of the Clean Air Act requires the EPA, after promulgating NSPS under Section 111(b) for pollutants like CO2 that are not regulated under the National Ambient Air Quality Standards (“NAAQS”) or as a hazardous air pollutant, to issue standards of performance for “existing sources”. Specifically, Section 111(d) states that the EPA “shall prescribe regulations which establish a procedure under which each State shall submit . . . a plan which establishes standards of performance for any existing source for any air pollutant . . . to which a standard of performance under this section would apply if such existing source were a new source.” Because the EPA set NSPS for CO2 for new sources in the Draft Rule, it is obligated under Section 111(d) to set performance standards for CO2 from existing sources.
Under Section 111(d), the EPA issues regulations known as “emission guidelines” that establish binding requirements that the states must address in the development of their state plans. For the CO2 Standard, existing sources would include transitional sources as defined by the Draft Rule, modified sources, reconstructed sources and any other sources that are not new sources. Because many pollutants are regulated under the NAAQS or are hazardous air pollutants, there is little precedent for EPA’s actions under Section 111(d). When it has acted, the EPA has generally issued a model rule that can then be adopted by the states. For instance, for mercury emissions the EPA determined that a national cap-and-trade program was BSER for existing sources and issued a model rule establishing the program for adoption by the States.
States must adopt the emission guidelines for existing sources through a state rulemaking action with EPA review and comment similar to the State Implementation Plan (“SIP”) process. The states and EPA may set less stringent standards or longer compliance schedules for existing sources considering cost of control; useful life of the facilities; location or process design at a particular facility; physical impossibility of installing necessary control equipment; or other factors making such variances appropriate. If the state fails to submit a satisfactory plan, the EPA has the authority under Section 111(d)(2) to prescribe a plan and to enforce the provisions of such plan.
If the EPA fails to address CO2 emissions from existing sources as required by Section 111(d), it could face additional litigation under the Clean Air Act as well as an enforcement action in connection with the 2010 settlement agreement, which required the EPA to issue emission guidelines for existing fossil fuel-fired sources.
- Equivalent State Programs
Due to the absence of comprehensive climate change policy on the federal level, many states have already implemented programs aimed at controlling greenhouse gas emissions from power plants (e.g., Renewable Portfolio Standards (“RPS”), cap-and-trade programs, state-based CO2 emission limits for power plants). Several states and policymakers have indicated such programs should be considered equivalent to any emission guidelines for existing sources issued by the EPA. For example, the State of California has stated that its greenhouse gas cap-and-trade program that covers power plants should be considered for the purposes of applying the CO2 Standard under the Draft Rule to existing sources. Other commentators have noted that state RPS programs could be similarly treated. Due to the lack of precedent in the area, whether state-based greenhouse gas trading programs (or other state rules that control CO2 emissions) will be considered equivalent to the Draft Rule remains an open question. The EPA could issue a model rule setting forth the necessary requirements of any state program seeking equivalency or could work individually with states to approve programs that it deems would result in equivalent emission reductions.
The EPA is requesting public comment on the Draft Rule, and all comments must be received on or before June 25, 2012. The EPA will hold two public hearings on the Draft Rule on May 24, 2012 in Chicago and Washington, D.C. While the Draft Rule may be changed during the comment period, any power plant constructed after April 13, 2012 is required to meet the CO2 Standard, so it is essentially in force at this time. Regarding the timing of the EPA’s emission guidelines for existing sources, any regulation of CO2 from existing sources will be controversial. It is widely expected that the EPA will not issue a rulemaking for existing sources in advance of the presidential elections in November 2012.