Jump to Navigation

Climate Change: EPA Releases Revised Proposed Regulations for Carbon Dioxide Emissions from Power Plants

November 18, 2013

Earlier this fall, EPA released controversial proposed regulations aimed at reducing carbon dioxide (CO2) emissions from newly-constructed coal- and natural gas-fired power plants via the Clean Air Act’s New Source Performance Standards (NSPS) program. EPA’s new draft builds upon a 2012 proposal EPA published, but never finalized, that would have established performance standards for new power plants. Among other things, EPA is proposing an emission performance standard of 1,100 pounds of CO2 per megawatt hour (lbs. CO2/MWh) for new coal-fired power plants – a level that is based on the partial implementation of carbon capture and sequestration (CCS) technology.

While EPA has adopted a suite of Clean Air Act regulations governing greenhouse gas emissions from stationary sources, the agency’s latest proposal is the first set of rules squarely aimed at the power sector. And like EPA’s other greenhouse gas regulations, which are currently before the Supreme Court, EPA’s proposed power plant NSPS will most likely meet strong opposition. See Clean Air Act: U.S. Supreme Court to Tackle GHG Permitting and Cross-State Air Pollution in 2013 Term, Marten Law Environmental News (Oct. 16, 2013). In particular, EPA’s determination that CCS technology has been “adequately demonstrated” will provoke heated debate . The Department of Energy just last year noted that there is “little history of the integration of [CCS] technologies with electric generation in reliable or cost-effective models.” EPA’s conclusion that CCS technology is “adequately demonstrated” technology has prompted protests from utilities and power producers.

EPA is also proposing a separate performance standard for new natural-gas combustion turbines – 1,000 lbs. CO2/MWh for larger units and 1,100 lbs. CO2/MWh for smaller units. Taken together, these two standards ensure that, with limited exceptions, no new coal-fired power plants will be constructed for the foreseeable future. EPA’s new proposal is limited to newly-constructed power plants. But President Obama’s Climate Action Plan instructs EPA to publish draft regulations for modified, reconstructed, and existing power plants by June 1, 2014.

I. Background

A. Statutory Context

The Clean Air Act divides responsibility for air quality between EPA and the states. EPA is responsible for identifying air pollutants and establishing standards for ambient air quality, referred to as National Ambient Air Quality Standards (NAAQS).[1] The states are primarily responsible for implementing and enforcing those standards via State Implementation Plans (SIPs).[2]

The Clean Air Act’s NSPS program (Section 111) requires EPA to designate categories of stationary sources that “cause[, or contribute] significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare.”[3] EPA must develop performance standards for new sources within each category, and those standards must reflect the “best system of emission reduction” (BSER) that “has been adequately demonstrated,” taking into account costs, environmental impact, and energy requirements.[4] EPA may distinguish between classes, types, and sizes within categories of new sources when developing standards.[5] States, in turn, must develop, and submit for EPA approval, a procedure for implementing and enforcing the performance standards for new sources.[6] Like other provisions of the Clean Air Act, “new” sources include both newly constructed sources and sources that have been modified in a manner that increases emissions.[7]

The NSPS program also reaches existing sources. EPA is required to establish procedures under which states submit plans for EPA-approval that establishes performance standards for existing sources for air pollutants (like greenhouse gases) that are neither criteria pollutants (i.e., pollutant that are not subject to NAAQS), nor regulated as hazardous air pollutants.[8] The procedures for developing state-level plans for existing sources must be similar to those procedures used to develop and review SIPs.[9]

B. EPA’s 2012 NSPS Proposal

In 2006, several environmental groups, states, and the city of New York challenged EPA’s 2006 revisions[10] to the NSPS for fossil fuel-fired power plants, alleging that revised regulations should have included standards for CO2 emissions.[11] EPA entered into a settlement in 2010 under which it agreed to issue CO2 NSPS for new and modified power plants, as well as guidelines for existing sources.

EPA published its draft CO2 NSPS for new power plants in April 2012, which established a 1,000 lbs. CO2/MWh performance standard for both coal- and natural gas-fired power plants.[12] That standard reflected the CO2 emissions associated with modern natural gas combined cycle (NGCC) units. EPA proposed an alternate compliance option which would have allowed coal- and pet-coke-fired sources to comply with a less stringent standard (1,800 lbs. CO2/MWh) for the first ten years, and more stringent standard (600 lbs. CO2/MWh) for the remaining 20 years, such that the 30 year average satisfied the 1,000 lbs. CO2/MWh standard. According to EPA, the averaging option would provide operators with greater flexibility in deploying CCS technology.

EPA’s 2012 proposal departed, in many respects, from its historic implementation of the NSPS program. EPA currently regulates coal- and natural gas-fired units as separate NSPS categories (Da and KKKK, respectively). But under its 2012 proposal, those units would have been aggregated into a single new source category (TTTT) solely for purposes of CO2 emissions. Furthermore, the rule would have applied only to new, but not modified, power plants, based on EPA’s determination that it had insufficient information to develop a standard applicable to modified sources.

II. EPA’s September 2013 Revised NSPS Proposal

In light of over 2 million public comments on EPA’s April 2012 proposal, President instructed the agency to issue a revised proposal for newly-constructed power plants. See President Obama’s Climate Action Plan (June 2013). EPA responded with a new proposal on September 20, 2013. Consistent with its historic practices, EPA now proposes to treat fossil-fuel fired and internal gasification combined cycle units (i.e., coal-fired units) and natural gas-fired stationary combustion turbines as separate source categories. EPA will accept written comments on the proposed rules for 60 days after publication in the Federal Register; as of the date of publication of this article, however, the proposed rules had not yet appeared in the Federal Register.

A. Coal-Fired Units – Carbon Capture and Sequestration

The most controversial aspect of EPA’s proposed rule centers on its determination that CCS is an “adequately demonstrated” technology. For new coal-fired units, EPA identified partial implementation of CCS as the best system of emission reduction (BSER) and set a performance standard of 1,100 CO2/MWh. Facilities deploying CCS technology can filter and capture CO2 and other impurities from the emission waste stream. Captured CO2 can be pumped into porous geologic formations like saline formations, or used to extract coal-bed methane or oil in depleted or diminished oil reservoirs (enhanced oil recovery, or EOR).

EPA contends that few, if any, traditional coal-fired units will be built through 2020, and notes that “nearly all of the coal-fired power plants that are currently under development are designed to use some type of CCS.” EPA cites to four projects currently under development that will deploy some type of CCS:

  • Southern Company’s Kemper County Energy Facility – a 582 MW IGCC power plant currently under construction that will sequester 65% of its CO2 emissions;
  • SaskPower’s Boundary Dam CCS Project – a commercial-scale CCS project that will fully integrate a rebuilt 110 MW coal-fired unit with CCS technology to capture 90% of CO2 emissions;
  • Summit Power’s Texas Clean Energy Project (TCEP) – a 400 MW IGCC plant that will sequester approximately 90% of its emissions in support of enhanced oil recovery; and
  • Hydrogen Energy California, LLC – a proposed 300 MW coal and pet-coke plant that will capture CO2 for enhanced oil recovery.

Based on its conclusion that coal-fired power plants without CCS technology will not be built, EPA contends that its new rule will result in negligible CO2 emission changes, energy impacts, quantified benefits, costs, and economic impacts through 2022. EPA further concludes that the rule will not impact the price of electricity, employment or labor markets, or the US economy. The agency goes on to posit that the rule will provide regulatory certainty to the power sector and will support research, development, and investment into CCS technology. Key to EPA’s proposal is its determination that the NSPS provisions are intended to force the development of new technology, and that the agency has the discretion to consider technological innovations when determining BSER.

EPA’s conclusions regarding CCS are not without controversy. Under the Clean Air Act, NSPS must be based on the best system of emission reductions (BSER), taking into account costs, environmental impact, and energy requirements.[13] Commenters have observed that CCS power plants cost upwards of $1 billion – or 75% more than coal-fired units without CCS technology. And EPA noted, in the preamble to its April 2012, proposal, that building generating units with CCS is not “affordable” without receiving major government subsidies.[14] And the coal industry contends that EPA’s proposal will stifle industry efforts to incrementally develop CCS technology.

For comparison, California, Washington, and Oregon have adopted the following emission performance standards similar to those EPA is now proposing:

  • California: Established a 1,100 lbs. CO2/MWh standard for new and existing baseload generation owned by or under long-term contract to publicly owned utilities[15]
  • Washington: Established a 1,100 lbs. CO2/MWh standard for baseload electric generation that began operating after June 1, 2008, and is located in Washington, regardless of whether the facility serves in-state or out-of-state load[16]
  • Oregon: Established a 1,100 lbs. CO2/MWh standard for coal- and natural gas-fired baseload generating units, and prohibited utilities from entering into long-term purchase agreements for baseload electricity with out-of-state facilities that do not meet that standard[17]

B. Natural Gas Combustion Turbine Units

EPA’s proposal would also establish a two-tiered performance standard for combustion turbine units. First, larger units (with a heat input rating greater than 850 MMBtu/hr) would be required to emit less than 1,000 lbs. CO2/MWh, while smaller units (with a heat input rating less than or equal to 850 MMBtu/hr) would be required emit less than 1,100 lbs. CO2/MWh. EPA determined that, unlike coal-fired units, CCS technology was not “adequately demonstrated” for combustion turbine.

C. Modified and Existing Plants

The Plan also instructs EPA to issue draft standards, regulations, and guidelines for modified, reconstructed, and existing power plants by June 1, 2014, and final rules by June 1, 2015. A Presidential Memorandum issued with the Plan states that the draft rules for existing sources should require states to issue implementation plans under Section 111(d) by June 30, 2016.

The Memorandum directs EPA to allow for the use of market-based instruments (e.g., cap-and-trade) and other regulatory flexibilities (e.g., fuel switching, energy efficiency upgrades) when developing its NSPS guidelines for existing sources. The express reference to market-based compliance options may benefit greenhouse gas cap-and-trade programs already underway in California and within northeastern and mid-Atlantic states participating in the Regional Greenhouse Gas Initiative (RGGI).

III. Potential Impact on Gas-Fired Generation

Although much of the discussion about the draft rule has focused on what it would mean for the viability of new coal-fired generating units, the changes between EPA’s 2012 draft rule and the new draft rule may signal that natural gas-fired generating facilities will receive increasing scrutiny as sources of CO2 emissions.

As with the latest proposed rule, EPA’s 2012 proposed rule recognized that NGCC technology represents the “best system of emission reduction” (BSER) for CO2. The 2012 proposed rule included an express exemption for simple cycle turbines.[18] EPA explained that they are designed to provide peaking power:

Because peaking turbines operate less and because it would be much more expensive to lower their emission profile to that of a combined cycle power plant or a coal-fired plant with CCS, the EPA does not believe it is appropriate to include them in this source category.

Although the April 2012 proposed rule included a definition of “simple cycle combustion turbine,”[19] EPA requested comment about whether to include a definition in the final rule, given that the source category included a capacity factor reflecting operation at less than one-third of potential annual output:

The potential electric output requirement in the definition of electric generating unit would already exclude facilities with permit restricting limiting operation to less than 1?3 of their potential electric output, approximately 2,900 hours of full load operation annually. The peaking season is generally considered to be less than 2,500 hours annually, and we are requesting comment on if the capacity factor exemption is sufficient such that specifically exempting simple cycle turbine is unnecessary.[20]

The 2013 proposed rule includes no express exemption for simple cycle turbines. Rather, the proposed rule would require combustion turbine units (defined as including both simple cycle and combined cycle units) with a heat input rating greater than 850 MMBtu/hr to meet an emissions standard for CO2 of 1,000 lbs/MWh, whereas combustion turbine units with a heat input rating at or below that threshold would have to meet an emissions standard of 1,100 lbs. CO2/MWh.

The proposed rule still incorporates a tacit exemption for peaking units, providing that a stationary combustion turbine is not subject to the emissions standard unless it “was constructed for the purpose of supplying, and supplies, one-third or more of its potential electric output and more than 219,000 MWh net-electrical output to a utility distribution system on a 3-year rolling average basis.” That provision, however, does not amount to an exemption for all new simple cycle turbines, particularly given that simple cycle turbines are now finding use not only in meeting peak demand, but also in balancing variable renewable generating resources such as wind. Where simple cycle turbines are used to balance variable generation, the concept of a limited “peaking season” may not be meaningful and the threshold 33 percent capacity factor in EPA’s proposed rule will not be adequate to distinguish baseload generating facilities from simple cycle combustion turbines.

Whether simple cycle turbines can meet a CO2 emissions standard based on the efficiency of combined cycle units bears close examination because s a practical matter, there are only two ways of directly limiting CO2 emissions from combustion turbine units: efficient operation and CCS. Efficient operation remains the only commercially proven approach.

Although CCS has been widely discussed for coal-fir ed generating units, in recent years it has also been examined as a control technology for CO2 emissions from NGCC units. Indeed, Energy Secretary Moniz recently stated that, in order to achieve “really low carbon emissions,” natural gas generation will eventually need to have CCS.[21] However, a basic problem is that the lower concentration of CO2 in the flue gas from a gas-fired unit (as compared to a coal plant) works against the cost-effectiveness of CCS technology when applied to natural gas.

A 2010 study by the National Energy Technology Laboratory[22] examined three approaches to carbon capture: pre-combustion (conversion of carbon in the fuel to CO2, with removal prior to combustion); post-combustion (separating dilute CO2 from flue gas after combustion); and oxy-combustion (using nearly pure oxygen—rather than air—as the oxidant to produce a flue gas consisting mainly of CO2 and water vapor).[23] In addition to the considerable capital costs of the carbon capture approaches,[24] net plant efficiency (measured as higher heating value heat rate) was reduced by over 10 percent in all cases[25] and raw water consumption increased substantially in most cases.[26] Based on comparison to a reference case of NGCC without CCS, the cost of an avoided metric ton of CO2 emissions ranged from a low of $65.32 to a high of $142.27.[27]

CCS for NGCC units, moreover, remains unproven in practice. Indeed, the Obama administration announced in March that President Obama’s FY 2014 budget proposal includes “a new $25 million prize for the first, natural gas combined cycle power plant to integrate carbon capture and storage.”[28]

The “best system of emission reduction” under Section 111(a)(1) must account for “the cost of achieving such emission reduction” and must be “adequately demonstrated.” Considering the likely cost of CO2 emission reductions using CCS on NGCC units, the day when BSER can be based on carbon capture and sequestration may come, but it has not arrived yet.

The biggest uncertainty surrounding EPA’s implementation of the Climate Action Plan, of course, is how the agency—and the states—will address existing sources. EPA rules require the agency to issue guideline documents incorporating information similar to that considered by EPA for new source performance standards under Section 111(a), including an “emission guideline that reflects the application of the best system of emission reduction (considering the cost of such reduction) that has been adequately demonstrated for designated facilities, and the time within which compliance with emission standards of equivalent stringency can be achieved.”[29] States have considerable leeway under Section 111(d); EPA must allow states “in applying a standard of performance to any particular source under a plan submitted under this paragraph to take into consideration, among other factors, the remaining useful life of the existing source to which such standard applies.”[30]

For gas-fired combustion turbine units, the possibilities for “best system of emission reduction” for CO2 emissions from existing units are likely as constrained as for new units: existing units must increase the efficiency of the generating plant to decrease CO2 emissions per megawatt-hour of generation, or capture and sequester CO2. Assuming that EPA will find CCS to be cost prohibitive (or not “adequately demonstrated”) for existing units, the crucial issues will likely be which “existing units” establish the baseline level of CO2 emissions and the manner in which compliance can be demonstrated. A continuum of alternatives will certainly be considered, ranging from requiring unit-by-unit compliance, to allowing facility-wide averaging, to allowing broader trading or offset mechanisms.[31]

Two certainties are that EPA and the states are headed into largely uncharted legal territory under Section 111(d), and that the stakes are high.

IV. Conclusions

EPA’s proposed rules are certain to generate significant controversy and may draw even more than the 2.7 million comments filed on EPA’s 2012 proposed rules. EPA has not yet published the proposed rule in the Federal Register, but once it does so, it will accept public comments for sixty days from the date of publication.

For more information on EPA’s Clean Air Act regulations, please contact Richard Allan or any member of Marten Law’s Air Quality and Climate Change practice groups.

[1] 42 U.S.C. §§ 7408-7409.

[2] Id. at § 7410(a)(1).

[3] Id. at § 7411(b)(1)(A).

[4] Id. at § 7411(a)(1).

[5] Id. at § 7411(b)(2).

[6] Id. at § 7411(c).

[7] Id. at § 7411(b)(1)(B).

[8] Id. at § 7411(d)(1).

[9] Id.

[10] Standards of Performance for Electric Utility Steam Generating Units Industrial-Commercial-Institutional Steam Generating Units, and Small Industrial-Commercial-Institutional Steam Generating Units, 71 Fed. Reg. 9,866 (Feb. 27, 2006).

[11] State of New York v. EPA, No. 06-1322 (D.C. Cir.).

[12] Standards for Performance for Greenhouse Gas Emissions for New Stationary Sources: Electric Utility Generating Units, 77 Fed. Reg. 22,392 (Apr. 13, 2012).

[13] Id. at § 7411(a)(1).

[14] 77 Fed. Reg. at 22,411 and 22,418.

[15] California Senate Bill 1386 (2006).

[16] Washington Substitute Senate Bill 6001 (2007).

[17] Oregon House Bill 3283 (1997).

[18] 77 Fed. Reg. at 22437 (proposed 40 C.F.R. § 60.5520(d)).

[19] Id. at 22440 (proposed 40 C.F.R. § 60.5580).

[20] 77 Fed. Reg. at 22431-32. The April 2012 proposed rule defined the source category, “Electric utility generating unit or EGU” as “any steam electric generating unit or stationary combustion turbine that is constructed for the purpose of supplying more than one-third of its potential electric output capacity and more than 25 MW net-electrical output to any utility power distribution system for sale.” 77 Fed. Reg. 22439 (proposed 40 C.F.R. § 60.5580).

[21] Amy Harder, Moniz: Natural Gas Will Need Carbon-Capture ‘Eventually’ (Aug. 1, 2013).

[22] National Energy Technology Laboratory, Carbon Capture and Sequestration Approaches for Natural Gas Combined Cycle Systems (Dec. 20, 2010).

[23] Id. at 1.

[24] Id. at 8-11.

[25] Id. at 4.

[26] Id. at 6-7.

[27] Id. at 15.

[28] Office of the Press Secretary, White House, President Obama’s Blueprint for a Clean and Secure Energy Future (Mar. 15, 2013).

[29] 40 C.F.R. § 60.22(b)(5).

[30] 42 U.S.C. § 7411(d)(1).

[31] See Jeremy Tarr, et al., Regulating Carbon Dioxide under Section 111(d) of the Clean Air Act: Options, Limits, and Impacts, Nicholas Institute for Environmental Policy Solutions, Duke University (January 2013).

This article is not a substitute for legal advice. Please consult with your legal counsel for specific advice and/or information. Read our complete legal disclaimer.