A step back from the precipice: Implementing CAA performance guidelines for carbon emissions

by Dan Watkiss, McDermott Will & Emery LLP

For the first time in 3 million years, this May the average daily atmospheric concentration of carbon dioxide (CO2) exceeded 400 parts per million. As the nation that historically has contributed most to that concentration of greenhouse gases (GHG), how should the U.S. commemorate this inauspicious milestone?

Because the what-me-worry crowd in Congress will prevent that body from enacting a carbon tax or otherwise capping carbon emissions, the Obama Administration announced June 25th that it would use a Supreme Court ruling and existing Clean Air Act (CAA) powers. Congress delegated to the Environmental Protection Agency (EPA) to ratchet down emissions of carbon pollution from existing, as well as new or modified, fossil-fueled electricity generating units (EUGs). Those EUGs are the source of roughly 40 percent of U.S. GHG emissions. While arguably not as flexible of a tool as a carbon tax, which would have revenue-generating muscle and distributional flexibility, as I described in my Electric Light & Power Jan./Feb. 2013 column, performance standards under Section 111 of the CAA have a proven track record and could be effective in achieving the U.S. Copenhagen Accord commitment to reduce its carbon emissions and preventing uneconomical investments in the nation’s antiquated fleet of coal-fired EUGs.

The presidential memorandum that accompanied the June 25th announcement directs the EPA to issue and implement unprecedented carbon pollution performance guidelines under Section 111(d) for modified, reconstructed and existing EGUs. Those guidelines will be implemented in addition to the best system of emission reduction (BSER) standard–1,000 lbs. of CO2 per MWhr of electricity produced–that EPA proposed a year earlier for new EUGs.

Performance standards for controlling air emissions under Section 111 for identified stationary emission source categories have been part of the CAA toolbox first enacted by Congress and delegated to EPA more than 40 years ago. Performance standards have been imposed under Section 111(b) primarily on new or significantly modified source categories of harmful emissions, but less often and indirectly on existing sources, and never with respect to GHGs. Section 111(d), however, not only authorizes but now requires emission controls on existing sources of GHGs, which the Supreme Court in Massachusetts vs. EPA determined to be a pollutant subject to regulation under the CAA. The EPA subsequently determined to endanger public health and welfare.

Short of a carbon tax, Section 111(d) stands to prove an effective and timely step toward controlling carbon pollution in at least two noteworthy respects. First, Section 111(d) (in contrast with the process for prescribing a BSER for new or modified sources under Section 111(b)) promotes a flexible, state-driven bottom-up process. In it, Congress directed that performance standards implementation for existing sources should follow the state implementation plan (SIP) approach used to enforce compliance with other air quality standards under CAA. In this SIP-like process, a state air quality authority enjoys flexibility in achieving the prescribed EPA performance guideline for a stationary source category such as an EGU. That means that achieving the guideline could take the traditional form of an emission rate per unit of output or heat input or, alternatively, market-based forms like those President Obama validated and endorsed in the presidential memorandum.

In its March 2013 report “Closing the Power Plant Carbon Pollution Loophole,” the Natural Resources Defense Council (NRDC), along with a diverse group of power industry participants and industry consulting powerhouse ICF, modeled the costs and achievable benefits of flexible Section 111(d)-type guidelines for reducing carbon emissions from existing fossil-fuel EGUs. The results generated by ICF’s proprietary integrated planning model showed that implementation of the Section 111(d) approach by 2020 could reduce CO2 emissions from the existing U.S. fossil generating fleet by 26 percent below 2005 levels. This equates to annualized costs of approximately $4 billion in 2020 and benefits ranging from a low of $25 billion up to $60 billion.

The proposed NRDC guidelines are premised on the reality that each state is unique in the degree of its dependence on fossil fuels, particularly coal, for its electricity generation. The guidelines therefore determine for each state a baseline of its coal and natural gas/oil dependence per MWh generated for the most recent period for which data is available (2008 through 2010 in the NRDC model). That baseline progressively ratchets down emissions to a nominal rate of 1,500 lbs/MWh for a state’s coal fleet (down from 2,063 lbs/MWhr) and 1,000 lbs/MWh for its natural gas/oil fleet (down from 1,065 lbs/MWh) by 2020. The latter rate has been adequately demonstrated to be achievable in a natural gas combined-cycle EGU, as EPA’s regulations require. In contrast, the coal rate is likely achievable only through carbon capture and sequestration (CCS) processes, which are not adequately demonstrated largely due to political dithering over FutureGen and similar CCS demonstration projects.

In addition to reducing CO2 emissions 26 percent below 2005 levels in 2020 and 34 percent below 2005 levels in 2025, Section 111(d) virtues of allowing states to average their emission rates across fossil-fuel EGUs and credit emission reductions achieved through displacing fossil-fuels or through demand management also are included in the NRDC proposal. Emission reductions achieved but not needed for compliance in one year could be banked for later use. Compacts of states could also be authorized to combine fleets for compliance purposes because the harm of carbon pollution is globally ambient and not localized in “hot spots.” Importantly, existing programs in which states have taken the lead, such as the Regional Greenhouse Gas Initiative of the Northeast and Mid-Atlantic region or California’s recently implemented cap-and-trade program, would not be pre-empted by and could be rolled into the flexible guidelines of the NRDC proposal.

Section 111(d) guidelines also can be effective during the window of time that the presidential memorandum prescribes EPA to set performance guidelines for existing EGUs. That is because the owners and operators of the nation’s fossil-fuel EGU fleet are confronting decisions not only about how they will meet new carbon emissions’ performance standards, but also other costly investments required under other CAA programs to reduce nitrogen oxide, sulfur dioxide and the hazardous pollutant mercury emissions.

Some commentators have questioned whether implementing all of these emission controls concurrently will trigger a “train wreck.” That view is myopic. Separate or seriatim decisions on whether and how to invest in complying with each Clean Air Act requirement would likely result in pollution control investments that seem economical in isolation, but are otherwise not warranted and likely to become stranded. Many of the fossil-fuel EGUs that will be required to comply with this suite of emission controls pre-date the CAA are antiquated and cannot be operated economically in compliance with the CAA’s mandatory controls. An integrated assessment of all compliance investments required is in order and, in many instances will lead to the reasoned decision that a plant should be retired or repowered with a cleaner fuel source.

Author

Dan Watkiss is a partner in the law firm McDermott Will & Emery LLP and is based in Washington, D.C. He focuses on transactional and regulatory matters in energy and related infrastructure industries. Reach him at dwatkiss@mwe.com.

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