SUPPLEMENTARY INFORMATION:

I. General Information

A. Overview

In 2009, the EPA issued a finding that greenhouse gas (GHG) air pollution may reasonably be anticipated to endanger Americans' public health and welfare, now and in the future, by contributing to climate change. In the notice of proposed rulemaking that was published on April 13, 2012 (April 2012 document), the EPA proposed to limit ( printed page 1353) GHG emissions from new fossil fuel-fired power plants through standards for CO₂ emissions.^[1] These power plants are the largest stationary sources of U.S. GHG emissions.

The April 2012 document proposed federal standards of performance for new fossil fuel-fired power plants that the EPA concluded could be met with existing technology. Specifically, the EPA proposed a single electricity-output-based emission standard of 1,000 pounds of CO₂ per megawatt-hour of gross electrical output (1,000 lb CO₂ /MWh) for all new affected fossil fuel-fired power plants. This standard was based on the demonstrated performance of recently constructed, modern natural gas combined cycle (NGCC) units, which the EPA concluded were in wide use throughout the country and were likely to be the predominant fossil fuel-fired technology for new generation in the future. Indeed, modeling conducted in support of that proposal predicted no new coal-fired EGUs would be constructed at least until after 2020. However, the EPA recognized that a very small number of new fossil fuel-fired utility boilers and IGCC units may be built, and if so, they could meet the proposed standard through the use of available carbon capture and storage (CCS) technology. To assist such sources in complying with the standard, the EPA proposed an alternative 30-year averaging option that would be available only for affected coal- and petroleum coke-fired sources complying with the standard through the use of CCS.

In addition, the EPA identified as “transitional” sources certain coal-fired power plants that had received approval of their PSD preconstruction permits as of the date of the April 2012 proposal (or that had approved PSD permits that expired and were in the process of being extended, if they were participating in a Department of Energy CCS funding program), and that commenced construction within one year of the date of the April proposal. For those sources, the EPA did not propose a standard of performance.

The EPA also stated that it was not proposing standards of performance for simple cycle combustion turbines or for non-continental sources (i.e., those in Hawaii or the U.S. territories).

In a separate notice of proposed rulemaking published in today's Federal Register , the EPA has made several key changes to its original proposal. First, instead of proposing a single limit covering all affected fossil fuel-fired EGUs, the EPA is proposing three different limits: (1) A limit of 1,000 lb CO₂ /MWh for large natural gas-fired stationary combustion turbines, (2) a limit of 1,100 lb CO₂ /MWh for small natural gas-fired stationary combustion turbines, and (3) a limit of 1,100 lb CO₂ /MWh for fossil fuel-fired utility boilers and IGCC units. Second, instead of proposing an alternative 30-year averaging compliance option for new solid fuel-fired EGUs, the EPA is proposing an alternative 7-year (84-operating month) averaging option and is soliciting comment on a limit of 1,000 to 1,050 lb CO₂ /MWh. Third, the EPA is no longer excluding all previously identified transitional sources (but is considering a subcategory for one to three coal-fired projects that are still currently under development). Fourth, instead of proposing to exempt simple cycle combustion turbines, the EPA is proposing to exempt units that sell to the grid a relatively small portion of their potential electric output. These exempt units generate less than one-third of their potential electric output over a three year rolling averaging period.

B. Why is the EPA withdrawing the proposed rule?

In response to the proposed rule, the EPA received over 2.5 million public comments on all aspects of its proposal. Many commenters were supportive of the Agency's proposed actions, other commenters opposed the proposed actions, and many commenters provided new information and/or recommended significant changes in the EPA's proposed requirements. In addition, the EPA has obtained and analyzed new information that significantly alters its views on important assumptions and which counsel for major changes in some of the requirements proposed in the April 2012 document.

We fully describe the actions we are proposing to take in response to the comments received and the results of our analyses of new information in a notice of proposed rulemaking published elsewhere in today's Federal Register . The following is a description of the principal reasons why those changes warrant rescission of the April 2012 document and issuance of a new proposal.

1. Changes in Proposed Applicability Requirements

Changes to the proposed rule's applicability will impact which sources are potentially covered. By changing the proposed rule's applicability, projects based on NGCC technology that are intended to, and that do, generate less than one-third of their potential electric output on a three year rolling average, which would have been covered by the original proposal, are not covered by today's proposal. Such projects could be beneficial because they are likely to be more efficient and lower emitting and could potentially cost less than natural gas-fired simple cycle combustion turbines in some instances. If we did not withdraw the original proposal, developers might not consider this technology because they may perceive a greater risk that we would finalize the applicability requirements of the original proposal. This could have the unintended effect of potentially stifling development of NGCC technology that can be used to meet peak energy demand.

2. Changes With Respect to Proposed Standards

The Agency is also proposing significant substantive changes from the original proposal in today's new proposal with respect to the standards themselves.

a. Projected New Coal-Fired Electrical Generating Capacity

In the April 2012 proposal, although the EPA acknowledged the possibility of a very small amount of construction of new coal-fired generating capacity, the EPA relied primarily on several modeling analyses, including analyses using the EPA's Integrated Planning Model (IPM), which projected that there would be no construction of new coal-fired generation through the year 2030 without CCS even assuming the potential for higher future electric demand or with higher future natural gas prices. Comments received, along with new information, have brought more clearly into focus the possibility that, in fact, there could well be limited new coal-fired generating capacity being constructed within the planning timeframe covered by the proposed rule. This new capacity could be in response to the need for companies to establish or maintain fuel diversity in their generation portfolios or the ability of some companies to combine coal-fired generation of electricity with the profitable sale of by-products from gasification or combustion of coal. As a result, even though our baseline analysis does not project any new coal that would not meet the originally proposed standard, the EPA believes it is appropriate to develop separate standards for coal-fired capacity, which, as it turns out, differ from those for new natural gas-fired EGUs. ( printed page 1354)

b. Best System of Emission Reduction for Coal-Fired EGUs

The April 2012 proposal set a single standard of performance for all affected fossil fuel-fired EGUs, regardless of generation technology or fuel, based on our proposed findings that the best system of emission reduction adequately demonstrated (BSER) for fossil fuel-fired units is natural gas combined cycle technology. Thus, in the April 2012 proposal, we did not propose a separate BSER for coal- and other solid fossil fuel-fired EGUs, although we identified carbon capture and storage (or sequestration) (CCS) technology as a compliance alternative for those EGUs and we proposed a 30-year averaging compliance option for those EGUs that implemented CCS.

We received significant public comments on this approach. Our evaluation of those comments has led us to modify significantly our conclusions regarding the BSER and the resulting emission limitations for fossil fuel-fired sources, and we no longer consider it appropriate to propose a single standard for all such units.

Instead, we are proposing separate emission standards based on separate BSER determinations for (i) fossil fuel-fired utility boilers and IGCC units and (ii) natural gas-fired stationary combustion turbines. For fossil fuel-fired utility boilers and IGCC units, we are proposing partial-capture CCS as the BSER. Additionally, we now believe that a shorter compliance averaging option than the 30-year scheme proposed in the April 2012 notice may be more appropriate.

These changes are significant. Moreover, they affect at least one unit in advanced stages of project development. As a result, the EPA believes it is important to withdraw the original document, in part to make it clear to the developer of this project—and any other projects in development—that their new source performance standards will be based on a BSER determination that is more closely aligned with technology appropriate to those projects.

c. Emission Standards for Natural-Gas Fired Stationary Combustion Units

As noted, in the new action, the EPA is proposing separate emission standards for fossil fuel-fired utility boilers and IGCC units and for natural gas-fired stationary combustion turbines. In the new proposal, the EPA also is proposing separate emission standards for smaller natural gas-fired stationary combustion turbines and for larger natural gas-fired stationary combustion turbines. This differentiation may be significant to projects under development.

d. Treatment of Transitional Sources

We received numerous comments objecting to our proposed treatment of transitional sources. In light of many of those comments and additional information we have obtained, we have reassessed this issue and are revisiting our proposed treatment of these types of units.

e. Title V Permit Fees

When EPA finalizes CO₂ emission requirements for new fossil fuel-fired EGUs, GHGs will, for the first time, fall within the definition of “regulated air pollutant” in parts 70 and 71, which implement the title V permitting program. This would trigger requirements related to the calculation of permit fees under federal and state title V operating permit programs. The April 2012 proposal did not address title V fee issues related to GHG emissions, but we recognize that it is important to do so. The reproposal addresses title V fees for GHG emissions and includes several options for calculating the reasonable costs associated with GHG permitting.

II. Impacts of This withdrawal

The April 2012 document provided estimated air and energy impacts, as well as projected compliance costs, economic and employment impacts, and benefits associated with the proposed rule. This action withdraws the April 2012 proposal, and thus any projected impacts associated with it are being replaced with the results of a new assessment accompanying the notice of proposed rulemaking published elsewhere in today's Federal Register .

III. Statutory Authority

Pursuant to CAA section 307(d)(1)(V), the Administrator is determining that this action is subject to the provisions of CAA section 307(d). The statutory authority for this action is provided by sections 111, 301 and 307(d) of the CAA as amended (42 U.S.C. 7411, 7601 and 7607(d)).