Responding to Limits on Greenhouse Gas Emissions: Three Questions for Companies in the Electric Power Sector

If your company generates, transmits or sells electricity, you are thinking about climate change regulation. Coming GHG emissions restrictions – whether imposed by regulation or legislation – will profoundly affect fossil generation. The rising renewables sector must continue to press its climate-related advantages to remain competitive – and overcome the infrastructure problems that have been exacerbated by increasing the renewable share of total generation. Nuclear power may seize the opportunity to shake off thirty years of stagnation. Meanwhile, the nation’s demand for energy is projected only to increase,[1] and the task of meeting that demand – producing the energy, moving it across the country, and marketing it to consumers – must continue while responding to the rising tide of climate-related regulation.

To address these issues, this article poses three questions meant to highlight what is certain – and what is not – about the impact of climate-related regulation on the energy industry. Perhaps counterintuitively, the first question involves the consequences of inaction.

1. What If Federal Climate Legislation Doesn’t Pass?

The House has passed Waxman-Markey (a.k.a. the American Clean Energy and Security Act, ACES, or H.R. 2454), and the Senate is now considering Kerry-Lieberman (a.k.a the American Power Act). See Senate Climate Bill Introduced Amid Considerable Fanfare, and an Uncertain Future, Marten Law News (May 14, 2010). But whether a comprehensive greenhouse gas regulatory regime will ever become law remains an open question. Industry must plan for the possibility that it will not. That possibility promises a continuation of incremental change at the federal level, further proliferation of state level standards, and continued uncertainty as pro-legislation interests press for change.

a. Incremental Federal Change

Since Massachusetts v. EPA, the writing has been on the wall. EPA is now poised to bring GHGs under the regulatory umbrella of the Clean Air Act. See EPA Proposes Regulating Stationary Source Greenhouse Gas Emissions Under Federal Clean Air Act, Marten Law News (Oct. 7, 2009); EPA Issues Final Rule Regulating Greenhouse Gases From New and Modified Sources, Marten Law News (May 14, 2010).

While EPA’s actions have been challenged in the courts and in Congress, as currently on the books EPA’s rules will introduce GHG emissions control requirements beginning in January 2011. The most significant change will be the imposition of Best Available Control Technology (BACT) on all new and significantly modified stationary sources emitting over 75,000 tons per year CO2e.[2] In the first half of 2011, this will be required only for those projects that would, today, have to obtain a construction permit under the Clean Air Act’s Prevention of Significant Deterioration (“PSD”) program because of non-GHG emissions. Beginning in July 2011, the requirement will extend to facilities solely on the basis of the GHG emissions (i.e., even if they would not have required a PSD permit under today’s regime) but with the CO2e threshold raised to 100,000 tons per year. [3] For the electric power sector, this second phase is not likely to be relevant, except perhaps for some landfill gas-powered projects, since any large fossil fuel-based project is likely to trigger PSD due to its emissions of other regulated pollutants. EPA has indicated that it may expand the net further after 2016, by lowering the annual CO2e tonnage threshold.

Given the time required to obtain a PSD permit, any significant generation project that starts permitting now is likely to be covered by the first phase of GHG permittings, which starts January 2, 2011. The energy-related facilities captured under these requirements will come as no surprise: fossil fuel-burning generation resources. A utility-scale natural gas plant would likely be covered, as CO2 emissions will easily exceed 75,000 tons a year. New coal generation in particular has faced coordinated opposition on climate change grounds, and while EPA's action will not end those challenges, it may alter the points of contention. While EPA has now decided whether new or existing plants must limit GHGs, attention must now shift to the question of how.[4].

There will be significant argument over what BACT means for CO2. Today, there simply is no standard. While technologies exist to capture other emissions, no similar method for carbon has been demonstrated on a commercial scale. Given that BACT requires consideration of the technologic and economic feasibility of any control, arguments will arise over whether (or when) such new technologies must be employed. EPA has recognized that carbon capture and storage, for example, is not yet BACT.[5] Environmental groups have also called for consideration of “fuel switching” – considering whether the best way to reduce emissions is to burn, e.g., natural gas instead of coal. Concerns that EPA will change its longstanding position that fuel switching need not be considered in BACT analysis were heightened by the agency’s recent decision on a Title V review petition for the proposed Cash Creek Integrated Gasification Combined Cycle plant.[6] That plant was designed to burn natural gas initially for six months, then switch to syngas produced from the coal gasifiers. EPA sent the permit back to the state agency for an explanation of why the plant could not simply burn natural gas permanently, rather than switch to syngas. The potential extension of this decision to other projects is in doubt, however, due to the unusual configuration of that project. Finally, given the current difficulties in supply-side control, CO2 BACT may focus on demand-side initiatives such as energy efficiency. EPA has indicated that improved efficiency reduces power consumption and therefore associated GHGs; the agency has promised to issue guidance on the role of energy efficiency in BACT analysis before the end of the year.[7]

b. Proliferating State Standards

While imposition of PSD requirements may create incentives against constructing new or modifying existing high-GHG energy resources, another trend will continue to create incentives for low-GHG power sources: renewable portfolio standards (“RPS”). Currently, 32 states and the District of Columbia[8] have adopted some form of renewable or alternative energy standard. California, for example, currently requires that 20 percent of all energy come from renewable resources, increasing to 33 percent by 2020;[9] New York has set a goal of 30 percent by 2015.[10] Lacking a national RPS, these standards will continue to evolve on a state-by-state basis, subject to the vicissitudes of state-level politics, but also responding to state-level priorities of, for example, the types of facilities that will be counted toward the standard or receive added incentives through credit multipliers.

Similarly, regional emissions control regimes will continue to move forward. The Northeast’s Regional Greenhouse Gas Initiative (RGGI) – covering only electricity generation – has already begun auctioning credits. The Western Climate Initiative (WCI) and Midwestern Regional Greenhouse Gas Reduction Accord (Midwestern Accord) – both broader initiatives than RGGI that will include energy and other sectors, and over much larger regions – are still in development. Although each of these initiatives has faced pressure since its enactment (exacerbated by the recession) these programs were enacted specifically because of state-level dissatisfaction with federal progress on climate issues. Congress’s failure to enact climate legislation this year will likely give proponents of these programs added incentive – and political support – to redouble their efforts.

c. Continued Uncertainty

If the last decade is any guide,[11] even if federal climate legislation does not become law, there is always likely to be something on the table for discussion. The possibility of federal action will cast its shadow over all other climate-related regulatory activity until supporters of a bill either stop trying (not likely) or gain the political support necessary to see a bill through Congress. This continuing drumbeat, whether loud or soft, leads to the logical next question.

2. What If Federal Climate Legislation Does Pass?

Whatever the political prospects may be today, the electric power sector must also plan for the possibility of federal climate change legislation. The details of the bills currently under consideration are widely reported, and are not repeated here. However, a few points are worth mentioning. First, the electric power sector will be among the first industries to face regulation under all of the currently pending climate bill proposals. Waxman-Markey, Kerry-Boxer and now Kerry-Lieberman all capture electric industry emissions in the first proposed compliance year (2012 or 2013). All of today’s proposals have mechanisms for reducing the price impact to consumers of electric power that would otherwise ensue, and the dividing up of these allowances will be an important part of any eventual political compromise that brings a bill across the finish line.

Less appreciated is to what extent a climate change bill will pre-empt existing initiatives. This could include any or all of the programs discussed above. Regarding EPA’s regulation of new and existing sources under the Clean Air Act, both Waxman-Markey and Kerry-Lieberman would pre-empt these programs by removing GHG emissions as triggers for PSD and Title V permitting.

Regarding renewable portfolio standards, Waxman-Markey would impose a national standard that would require every utility in the nation to procure 20 percent of their energy from renewable sources by 2020. The Senate bill currently does not include a nationwide RPS, but the bill’s Section 1601 calls for one. The Senate Energy Committee has reported out a bill, S.1462, that would establish a federal RPS comparable to the Waxman-Markey proposal, and all or portions of that bill may be combined with Kerry-Lieberman before it reaches the Senate floor. If a final bill has a national RPS, the bill will also need to address whether states with more restrictive standards may keep them in place, and to what extent renewable energy credits earned toward state programs (including associated multipliers) will count toward the federal program.

Finally, federal legislation may – or may not – pre-empt RGGI, WCI and the Midwestern Accord. Waxman-Markey drew criticism from some state officials for its provision prohibiting states from enforcing GHG emissions restrictions between 2012 and 2017. See Congress to Consider Preemption of Regional Climate Pacts, Marten Law News (April 19, 2010). Nonetheless, the Senate bill would preempt state programs entirely.

Federal legislation, no matter what its final form, is a future concern. Unless and until it becomes a reality, GHG sources in the electric power sector face the CAA permitting and state-driven requirements discussed above in response to the first question posed by this article. They also face a series of GHG-related requirements that will remain in place regardless of whether or not federal climate change legislation is enacted. That leads to a final question.

3. What Existing GHG Requirements Would Be Unaffected by Federal Legislation?

a. Compliance with the New GHG Monitoring and Reporting Requirements

EPA’s regulations governing GHG reporting and monitoring are already in effect. See EPA Issues Mandatory Greenhouse Gas Reporting Rule, Marten Law News (Sept. 23, 2009). These rules will apply to every fossil-burning generating facility in the country producing over 25,000 tons CO2e per year. As of Q2 2010, these facilities are expected to have installed necessary monitoring equipment and to have prepared monitoring plans, and must be ready to submit monitoring reports to EPA in March 2011.

Facilities already regulated by EPA’s Acid Rain Program[12] – virtually all U.S. fossil-burning facilities capable of producing 25+ MW – have tracked their CO2 emissions for fifteen years.[13] Compliance with the new rules will mean adapting to new recordkeeping and reporting requirements,[14] but EPA has allowed these facilities to follow the pre-existing monitoring protocols using pre-existing monitoring equipment (extrapolating other necessary data according to established formulas).[15]

Many fossil facilities, however, have nameplate capacities below 25 MW but will exceed the 25,000-ton CO2e threshold this year.[16] Compliance will be more difficult for these facilities, which now must quickly adopt new and potentially onerous monitoring technology and reporting protocols.[17]

Generation is not the only electricity-related segment to face new reporting requirements. In recently published rule proposals, EPA presented its plan to require reporting for the use, manufacture and refurbishing of electric transmission and distribution equipment utilizing sulfur hexafluoride (SF6) and perfluorocarbons (PFCs) (e.g., gas-insulated substations and lines, transformers, switchgear, etc.). See EPA Releases Additional Proposed Greenhouse Gas Emissions Reporting Rules for Three Industry Sectors, Marten Law News (Apr. 19, 2010).[18] So-called “upstream” fuel suppliers are also subject to their own reporting requirements, based on quantities of fuel sold.

b. Climate Risk Disclosure

Publicly traded companies in the electric power sector with high GHG emissions are impacted by climate risk disclosure. The SEC recently issued an interpretive guidance explaining the climate-related risk disclosures expected of publicly traded companies. See SEC Issues Interpretive Guidance on Climate Change Disclosure Requirements for Public Companies; Marten Law News (Feb. 3, 2010). The SEC expects companies to disclose the potential direct impacts on the companies’ businesses posed by pending climate-related legislation, regulation or an international accord; as well as any potential indirect consequences (e.g., on product or service demand) of such developments, and forecast any direct consequences to their business of the actual, physical impacts of climate change.

One area of potential development for companies with generation assets is the requirement to disclose risks associated with the physical impacts of climate change and costs of adaptation. Disclosures might touch on increasing weather variability as applied to renewable energy resources; rising air temperature and increasing water scarcity as applied to generation efficiencies and cooling needs at fossil and nuclear facilities; or agricultural trends for biomass resources.[19]

Many publicly held electric services companies already included some disclosure of climate change risks in their filings prior to the SEC’s guidance, and all should be keeping a close eye on new developments as companies begin to file 10-Ks prepared after the guidance was issued. So far, many companies’ climate-related disclosures in 10-Ks have not changed drastically from last year’s.[20] However, several notable exceptions have been filed by energy sector companies[21] and the area is rapidly developing.[22]

c. Environmental Review

Any energy infrastructure that requires a federal approval – e.g., a wetlands fill permit, federal rights-of-way, endangered species consultation, and certain air and water permits – is subject to environmental review under the National Environmental Policy Act (NEPA). After much controversy over how NEPA would treat climate change and GHGs, the Council on Environmental Quality recently released guidance on the subject. See CEQ Marks 40th Anniversary of NEPA With New Guidance on Greenhouse Gas Impacts, Mitigation and Categorical Exclusions, Marten Law News (Feb. 22, 2010).[23] Environmental review documents for projects with “meaningful” emissions – possibly in excess of 25,000 tons per year CO2e – must include a climate change analysis, although CEQ offered very little meaningful guidance on what, exactly, that analysis requires or what level of emissions are “significant,” triggering the need for an Environmental Impact Statement.

The new standards leave enough unanswered questions that any facility emitting GHGs could, as has been the case for some time, face NEPA challenges. It should be noted that this is not necessarily limited to generating resources. A power line may require a federal approval to cross federal land, opening the door to environmental review of the project’s impacts, which – it has been argued – include climate change if the transmission serves fossil resources.

Conclusion

Meeting the country’s steadily rising demand for electricity is a monumental task. The electric power industry has been and will continue to be equal to that task, in compliance with environmental regulations. The unique challenges posed by climate change have lead to new regulatory requirements and a rethinking of old ones, and much change is yet to come. When it does, the electric power sector will be ready.

For more information on climate-related regulation of the electric power sector, please contact Adam Orford or any member of Marten Law’s Climate Change or Energy practice groups.