Environmental Law ReSource : Environmental Lawyer & Attorney : Reed Smith Law Firm : Climate Change, Sustainability

1. Offshore Wind Power Generation (Robert Vilter, New York)

The Obama Administration is pursuing the development of 10 gigawatts of offshore wind-generating capacity by 2020, and 54 gigawatts by 2030. This would produce enough energy to power 2.8 million and 15.2 million homes, respectively. However, because of complicated and overlapping federal and state regulations, it takes anywhere from seven to 10 years to receive approvals and to fully permit an offshore wind project – more than double the amount of time it takes to permit an offshore oil or natural gas platform. The U.S. Department of the Interior has announced a “Smart from the Start” wind energy initiative to facilitate siting, leasing and construction of new projects in an effort to shorten this time line. Keep in mind that offshore wind farms, such as Cape Wind, also face local hurdles to development, oftentimes in the form of opposition by well-funded citizen groups.

2. Renewable Energy Incentive Programs (Arnold Grant, Chicago)

The cash grant program enacted under Section 1603 of American Recovery and Reinvestment Act in order to help renewable energy developers has expired except for projects that (i) began construction before January 1, 2012, and (ii) are placed in service before a specified date. The date varies depending on the type of project. The major remaining federal tax benefits are the energy tax credit under IRC Section 48, the production tax credit under IRC Section 45, and accelerated tax depreciation under IRC Section 168. Various structures are available to help renewable energy developers monetize these incentives.

3. Hydraulic Fracturing Regulation (Larry Demase, Pittsburgh)

Hydraulic fracturing or “fracking” is a practice of stimulating and maximizing production of natural gas in shale formations that has been in use in the United States for more than 50 years, but which has recently gained public attention. It involves pumping, under high pressure, a mixture of very large quantities of water and very small quantities of chemicals and proppants to create fissures in the shale and to hold fissures open so that gas will flow in greater quantities to the well bore. The controversy over its use concerns the amount of water being withdrawn from ground and surface resources, alleged contamination of drinking water from the fracking fluid and the disposal and treatment of waste water. In 2011 the U.S. Environmental Protection Agency (EPA) announced it will study the impacts of hydraulic fracturing on drinking water resources. The results of EPA’s study are intended to provide decision makers with some answers to fundamental questions about the effect of fracking on drinking water. The results will also no doubt be the impetus for regulatory and policy changes that could have a significant impact on the shale gas industry. A panel of experts will analyze the effect of fracking using reported cases of alleged groundwater contamination, laboratory studies, toxicological assessments of chemicals used in hydraulic fracturing, their degradation and/or reaction products, and naturally occurring substances that may be released or mobilized as a result of fracking.

There will be two reports resulting from EPA’s study with the first to be completed in 2012. An additional report based on long term study projects is to be issued in 2014. In the meantime, look for states to address these issues in various ways.

4. Aggregation (Larry Demase, Pittsburgh)

As we’ve discussed in previous posts, aggregation is the process of determining whether emissions from multiple operations should be aggregated into a single source for air permitting purposes. A significant issue related to oil and gas operations is whether emissions from individual operations, such as wells, processing plants and compressor stations, should be combined so that they become major sources for permitting purposes, subject to Title V requirements and New Source Review.

In 2011, a number of public interest groups challenged air permits issued by the Pennsylvania Department of Environmental Protection (DEP) on the grounds that DEP should have included multiple sources of emissions in those permits so that they would be considered “major” permits. The Clean Air Council, Group Against Smog and Pollution, and Citizens for Pennsylvania’s Future have asserted before the Pennsylvania Environmental Hearing Board and the United States District Court for the Middle District of Pennsylvania, that DEP failed to properly apply the three-part test for deciding whether sources should be “aggregated” together for permitting purposes. One case asserts that the permittee should be penalized for failing to submit an “aggregated” permit application. Decisions in these cases could result in precedents that will impact development of the shale gas industry in Pennsylvania.

Initial decisions in all three cases are expected in 2012, but final results could be extended if the losing parties seek appeals.

5. Greenhouse Gas Litigation (Jennifer Smokelin, Pittsburgh)

Regarding greenhouse gas (GHG) litigation, there are two main areas to watch in 2012: (i) the United States Supreme Court (and the Ninth Circuit) in the aftermath of American Electric Power v. Connecticut (AEP), and (ii) four consolidated cases in the D.C. Circuit challenging the endangerment finding slated for argument at the end of February.

Before the Supreme Court ruled in Massachusetts v. EPA, certain states sued the nation’s five largest coal-fired electric power corporations in the Southern District of New York under federal and state common law, charging AEP and other defendants with contributing to the public nuisance of global warming and seeking an injunction to cap and reduce their carbon dioxide emissions. The AEP Court voted unanimously that federal common law had been “displaced” by the Clean Air Act (and the Obama Administration’s efforts to regulate emissions), and thus states cannot use federal common law to restrict greenhouse gas emissions. The AEP ruling leaves open the question of (i) whether states can sue under state law, and (ii) whether climate change victims can seek damages through the courts. The issues are likely to be litigated in 2012 in a case, Kivalina v. Exxon Mobil.

Following the decision in Massachusetts v. EPA, but before AEP was decided in the U.S. Supreme Court: (i) EPA published two endangerment findings under the Clean Air Act, triggering a mandatory duty for EPA to adopt regulations to control emissions from power plants, industries, motor vehicles, and other sources; (ii) EPA issued tailpipe emission standards for new cars and trucks under the Clean Air Act; and (iii) EPA issued Best Available Control Technology (BACT) guidance for new sources and New Source Performance Standards (NSPS) for existing sources of GHG emissions under the Clean Air Act. Four cases are consolidated in the D.C. Circuit that challenge EPA’s Endangerment Findings. The cases are Coalition for Responsible Regulation Inc., et al. v. EPA, case numbers 09-1322, 10-1092 and 10-1073; and American Chemistry Council v. EPA, case number 10-1167, in the U.S. Court of Appeals for the District of Columbia Circuit. Argument will take place February 28 and 29, 2012. This is a very complex series of cases that will affect not only utilities but many other industries as well, since the fundamental underpinning to all GHG regulation under the Clean Air Act is essentially up for review.

6. California’s Cap-and-Trade Program (Todd Maiden, San Francisco)

In October 2011, the California Air Resources Board approved final regulations implementing a “cap-and-trade” program under the state’s climate law (more commonly referred to by its legislative bill number, “AB 32”). These regulations became effective January 1, 2012, and many consider California a possible test case for similar programs in other parts of the country. Regulated entities under the first phase of this program include utilities and large industrial facilities (i.e., emitters of greater than 25,000 metric tons of CO2 equivalent per year). The regulations trigger two 2012 auctions for buying and selling rights to emit, and requires entities to comply with a series of progressively stringent emission caps beginning January 2013.

7. California's Green Chemistry Initiative (Todd Maiden, San Francisco)

In October 2011, California’s Department of Toxic Substances Control (DTSC ) released revised “informal” draft regulations of its Green Chemistry initiative titled the “Safer Consumer Products Regulation.” DTSC’s new informal draft makes substantial changes, specifically in the areas of timeframes, the prioritization of chemicals and products, alternative assessment compliance, and exemptions. The informal draft also significantly broadens the chemicals that will initially be regulated to include an estimated 3,000 Chemicals of Concern without limits on which product categories may initially be considered. These draft regulations are highly controversial, yet DTSC is projecting that it will likely finalize these regulations – or something close to them – in spring 2012.

In a related development, California’s Office of Environmental Health Hazard Assessment recently finalized separate regulations that regulate the hazard traits in chemicals of concern. While finalized, these regulations remain controversial within the regulated community, and we anticipate administrative or litigation challenges to these regulations as well.

8. New Mercury Standards for Coal and Oil-Burning Power Plants (Douglas Everette, Washington, D.C.)

The final version of EPA's Mercury and Air Toxics Standards, or MATS rule, was signed December 21, 2011. For the first time in history, power plants will have to reduce all of their air toxic emissions, not just mercury, arsenic and lead – but a wide range of toxic chemicals. For coal-fired generators, the MATS rule sets emissions limits for mercury, particulate matter (a surrogate for toxic metals), and hydrogen chloride (a surrogate for acid gases). For oil-fired units, limits are set for particulate matter, hydrogen chloride and hydrogen fluoride. Also revised are new source performance standards for power plants to address emissions of particulate matter, sulfur dioxide and nitrogen oxides. According to EPA, approximately 1,400 existing coal and oil-fired units are affected. Existing sources are required to comply within three years of the effective date of the MATS rule, with case-by-case extensions up to five years beyond the effective date for documented electric reliability issues. These extensions are not offered to new or reconstructed sources. Vigorous debate centers on the practical implementation of the MATS rule deadlines and whether the electric grid will have enough capacity to avoid outages stemming from coal power plant retirements.

9. Fallout from Burlington Northern and Santa Fe Railway Co. v. U.S. (Robert Frank, Philadelphia)

In Burlington Northern and Santa Fe Railway Co. v. United States (BNSF), 556 U.S. 599 (2009), the U.S Supreme Court decided two key issues for parties facing Superfund liability: the standard for establishing “arranger” liability and the standard for establishing divisibility of liability. Since then, more than 100 courts have cited the decision. On arranger liability, including two at the federal appellate level, the cases illustrate that courts are following the Supreme Court’s directive to conduct a fact-intensive inquiry into a defendant’s purported “intent” to dispose of a hazardous substance. It’s fair to say that courts have been more reluctant to establish liability under an arranger theory than in the era preceding BNSF and look for that trend to continue in 2012.

For example, last year, the Ninth Circuit issued its first “arranger” liability decision under CERCLA since being reversed by the Supreme Court in the 2009 Burlington Northern decision.

In Team Enterprises, LLC v. Western Investment Real Estate Trust, 647 F.3d 901 (9th Cir. 2011), plaintiff argued that the requisite "intent to dispose" element necessary to trigger CERCLA arranger liability could be inferred from the fact that the dry cleaning machine was designed in a way that made disposal inevitable. Plaintiff also argued that the fact that the manufacturer exercised control over the disposal process provided a sufficient basis to infer the requisite intent necessary to trigger CERCLA arranger liability. The Ninth Circuit held that a manufacturer of equipment used to recycle wastewater from dry cleaning machines, as a matter of law, had neither the intent nor the control necessary to be held liable as an arranger. The court held that, to sustain an arranger claim against a “company selling a product that uses and/or generates a hazardous substance as part of its operation,” the plaintiff must prove “that the company entered into the relevant transaction with the specific purpose of disposing of a hazardous substance.” The holding underscores the high bar plaintiffs must meet in order to establish CERCLA arranger liability following the BNSF decision.

Regarding divisibility, there have been fewer cases applying the Supreme Court’s divisibility holding in BNSF. Generally, the courts looking at whether a “reasonable basis” for apportionment exists have reviewed the evidence that defendants have submitted to determine whether they have met their burden of proof. These cases have been very fact-intensive and, so far, it is difficult to identify a trend.

10. Final Rules for Conflict Minerals (David Wagner, Pittsburgh)

Section 1502 of the Dodd-Frank Act requires the Securities and Exchange Commission (SEC) to issue disclosure and reporting regulations regarding manufacturers’ use of conflict minerals from the Democratic Republic of Congo (DRC) and adjoining countries. The SEC was required to issue its conflicts minerals rules last year but missed the deadline. Look for the final rules – and plenty of implementation concerns – sometime in 2012. The legislation for conflict minerals is part of a broader multilateral effort to require manufacturers and other users of certain minerals to closely track and publicly disclose where their raw materials originate. It is designed to suppress end-use demand for minerals produced in certain high-risk areas where minerals operations and revenues have been linked to violent and repressive rebel groups.

The law focuses on forcing supply chain transparency for users of certain minerals (which are used primarily in electronic components, engine components, aerospace equipment, jewelry and other industries). It does not directly impose restrictions on mining or metals companies, or create any sort of embargo on the DRC.

1.         The Start of USEPA’s “Tailoring” Rule

Despite a lot of buzz, proposed bills and speculation, the U.S. Congress failed to comprehensively address GHG emissions last year. In filling the void, USEPA has taken several steps to regulate GHGs, including promulgation of the Tailoring Rule, the first rule under the stationary source provisions of the Clean Air Act controlling GHG emissions. It applies only to new and modified sources; certain larger GHG emission sources will be subject to permitting requirements for planned construction projects under the Tailoring Rule starting January 2, 2011. For further details on this and related issues, please contact Larry Demase, Lou Naugle, Todd Maiden, Harley Trice or Jennifer Smokelin.

2.         The Application of USEPA’s BACT Guidance for GHGs

USEPA recently released a key piece of the GHG permitting puzzle, a guidance entitled “PSD and Title V Permitting Guidance for Greenhouse Gases.” With the January 2011 implementation of the Tailoring Rule requiring large industrial sources to obtain permits for GHG emissions, this guidance aims to assist permitting authorities in enacting GHG permitting programs. In particular, the 97-page document addresses Prevention of Significant Deterioration (PSD) applicability to GHG and BACT (Best Available Control Technology), and other PSD requirements. The guidance also discusses Title V applicability requirements and GHGs, as well as permitting requirements for Title V permits with regard to GHGs. We’ve analyzed these BACT issues on our blog and discussed them in our quarterly climate change teleseminars. For further details on this and related issues, contact Larry Demase, Jennifer Smokelin or David Wagner.

3.         With the Defeat of AB 23 in California, the State Continues to Pursue Cap and Trade

Proposition 23 would have suspended California's Global Warming Solutions Act of 2006, also known as AB 32. AB 32 is one of the most aggressive and forward-thinking environmental laws in the United States, and sets targets to reduce greenhouse gas emissions to 1990 levels by 2020 and obtain 33 percent of the state’s power from renewable sources by 2020. California's voters’ rejection of a ballot measure to effectively suspend the implementation of AB 32 means California remains on track to issue aggressive cap and trade regulation of GHGs come 2012. For further details on this and related issues, contact Todd Maiden, John Lynn Smith, or Eric McLaughlin.

4.         SEC’s Corporate Disclosure Requirement Regarding Climate Change

Early last year, the Securities and Exchange Commission voted to adopt interpretive guidance addressing public company disclosure standards in connection with climate change. While this interpretive guidance is not intended to impose new standards, it continues to serve as an important reminder for public companies, potentially as part of their disclosure controls and procedures, to assess whether climate change may have a material impact upon their business and financial condition. For further details on this and related issues, contact Lou Naugle or Jennifer Smokelin.

5.         Following COP Failures in 2009 and 2010, Will 2011 Reverse the Trend?

This United Nations-sponsored conference of the parties (“COP”) in Copenhagen at the end of 2009 (also know as COP 15, as the 15th conference of parties under the UNFCCC) was thought to be the vehicle for a treaty on the reduction of GHG gases, but produced almost no significant results. Further, last month’s COP 16 did not seem to make any significant progress on major issues, but it did serve to affirm the UN as the venue for international climate action. With several UN climate meetings in 2011, including COP 17, we’ll again look for significant international agreement on climate issues in 2011. For further details on this and related issues, contact Larry Demase, Jennifer Smokelin or David Wagner.

6.         Increasing Interest in Regulations Related to Carbon Capture and Storage

Although carbon dioxide (CO2) is a valuable and marketable commodity, there are several barriers to the near-term deployment of commercial-scale carbon capture and storage (CCS) projects in the United States. They include cost and the related lack of economic drivers, regulatory uncertainty, and an inadequate legal framework for CCS. There is, however, a growing federal interest in CCS, and Jennifer Smokelin recently discussed a few examples of this interest, including USEPA’s BACT guidance and a GHG reporting rule. In particular, a USEPA rule requires permit holders to create a CO2 monitoring, reporting and verification plan, and to report the amount of CO2 sequestered using a mass balance approach under the Clean Air Act. Regulated entities must collect data in 2011 and begin submitting reports to USEPA by March 31, 2012. Also, in 2011, look for more CCS activity on the state level, including recommendations in support of a comprehensive legal/regulatory framework for permitting proposed CCS projects in California. Internationally, we expect the International Energy Agency to work with countries to implement its CCS Model Regulatory Framework. To learn more about CCS issues, please contact Jennifer Smokelin or David Wagner.

7.         Mandatory GHG Emission Monitoring and Reporting Requirements

GHG reporting requirements from certain sources that emit 25,000 metric tons or more of GHGs per year are due March 31, 2011. Douglas Everette addressed issues and problems to consider regarding GHG emissions monitoring and reporting in Reed Smith's 4th Quarter Climate Change Report. In addition to this rule and the GHG reporting requirements related to carbon capture and sequestration (discussed above), USEPA finalized a rule that requires the annual reporting of GHG emissions from qualifying facilities in the upstream oil and natural gas sector, including onshore production. USEPA is operating on an expedited timetable, requiring applicable industries under these rules to begin collecting data January 1, 2011, and begin submitting the first round of reports to USEPA by March 31, 2012. For more information on the rules, please go to Jennifer Smokelin’s post or send her an email.

8.         Single Stationary Source Determinations for Oil and Gas Operations

Here’s an air issue of particular relevance to Marcellus Shale well sites: whether and to what extent air emissions from the exploration, extraction and production activities related to well sites should be aggregated. The aggregation of gas (and oil) activities by regulatory bodies will influence whether they must obtain a minor source permit or a major source permit for purposes of Title V permitting, new source review and prevention of significant deterioration. With respect to Marcellus Shale, the pollutant-emitting activities include individual compressor stations, such as internal combustion engines, boilers, and emergency generators, and multiple compressor stations connected by pipelines. In 2011, aggregation will be an issue related to USEPA’s upcoming air quality standards for ozone and fine particulate matter (PM 2.5), technical guidance developed on the state level (including by Pennsylvania’s Department of Environmental Protection), and the scope of the federal requirement to report GHG emissions for “all petroleum and natural gas equipment … located in a single hydrocarbon basin.” To discuss these issues, please contact Lou Naugle, Larry Demase, Jennifer Smokelin or David Wagner. 

9.         For the First Time, USEPA Will Issue GHG Emission Standards

Under a recent settlement filed in federal appeals court, USEPA will propose GHG emissions standards for power plants by July 2011 and for refineries by December 2011. The standards, known as New Source Performance Standards, would set the level of GHG emissions new facilities may emit and also address emissions from existing facilities. For more information, contact Larry Demase, Lou Naugle or Jennifer Smokelin, or visit Larry’s blog post on this development.

10.       With the Approval of the Cape Wind Renewable Energy Project in Nantucket Sound, Other Approvals Are Expected in Late 2011

In early 2010, the federal government approved the Cape Wind energy project in Nantucket Sound, a $1 billion wind farm in the U.S. Outer Continental Shelf. According to the government, the Cape Wind project will generate enough power to meet 75 percent of the electricity demand for Cape Cod, Martha's Vineyard and Nantucket Island combined, and, as compared with conventional power plants, will cut carbon dioxide emissions by 700,000 tons each year. Building on the Cape Wind lease, the U.S. Department of the Interior announced in November that it would work quickly to identify priority areas and expedite leases for offshore wind projects in the Atlantic Ocean. The first leases are expected to be offered in Maryland, Delaware, New Jersey, Virginia, Rhode Island and Massachusetts waters by the end of 2011, to be followed shortly thereafter by New York, Maine, North Carolina, South Carolina and Georgia. For questions related to this issue, including applications for offshore transmission lines, please contact Larry Demase or David Wagner.

11.       The Clean Development Mechanism and the Uncertainty in the Carbon Markets Created by HFCs

The United Nations’ Clean Development Mechanisn (CDM) allows industrialized countries to invest in emission reductions wherever it is cheapest globally, and certified emission reductions (CERs) are a type of carbon credit issued by the CDM Executive Board for emission reductions achieved by CDM projects.  In late November, the CDM Executive Board decided to revise the rules governing hydrofluorocarbon-23 (HFC-23) destruction on the basis that carbon credits related to HFC-23 are creating windfall profits and threatening the integrity of the carbon market.  The CDM Executive Board’s decision came just days after a European Commission proposal to ban the use of HFC-23 in the EU Emissions Trading Scheme as of January 2013. The Commission explained that “the acceptance of credits from industrial-gas projects has been controversial for some time. Certain gases [such as HFC-23] have a very high global-warming potential, and abatement is very cheap. This can create huge financial rewards for project developers.” A majority of CERs issued to date have come from HFC-23 projects, mostly in China and India, and these two countries, especially China, are not happy. As Larry Demase anticipated in Reed Smith's 3rd Quarter Climate Change Report, this issue is creating significant uncertainty and it could have a destabilizing effect on the CER market. To learn more, please contact Larry Demase or Jennifer Smokelin.

Future of the Kyoto Protocol

As background, the Kyoto Protocol is the binding international agreement regarding greenhouse gas emissions and is the framework for international reduction of such emissions. The protocol was signed at COP 3 with the signatures of (now) 121 countries. The agreement sets binding greenhouse gas emissions targets for 37 industrialized countries including the European Union in a first phase from 2008-2012. Because it is legally binding it has been instrumental in framing countries’ legal response to climate change – like the EU ETS, Europe’s cap and trade system. But what happens after 2012?

At COP 16, there was clearly a divide between rich and poor countries over the future of the Kyoto protocol after 2012. Maintaining Kyoto is crucial to the future of the Clean Development Mechanism and the offset market, such as LULUCF and REDD+. The Kyoto Protocol is the connecting tissue on all the international GHG framework issues –if it falls (like a house of cards) so do the rest.

From the get-go of COP16 it was clear there was disagreement with regard to the future of the Kyoto Protocol. The crisis over Kyoto erupted at the start of the talks when Japan said it was not prepared to sign on to a second phase of the agreement without commitments on reducing emissions from emerging economies such as India and China because without these other economies, the Kyoto Protocol only committed 30% of the world’s GHG emission to any sort of emission reduction. By the end of COP16, Japan softened its position but Russia and Canada became even more forceful about scrapping Kyoto – meaning that if all three backed out, only 18% of global carbon emissions would be covered by the second phase of the Kyoto Protocol. 18% is not enough to do any sort of good from a climate standpoint.

Midway through the second week, EU and a group of small island Pacific states jointly proposed a new international treaty at the talks to commit developing and developed countries to reducing their climate emissions. The move outraged many developing countries, including China, Brazil and India, who fear that rich countries will use the proposal to lay the foundations to ditch the Kyoto protocol and replace it with a much weaker alternative

In the end the continued resistance by some countries to the Kyoto Protocol was a stumbling block for any meaningful and comprehensive reduction agreements. Still, negotiators finally found a compromise in the Cancun Agreements and, late into the night, delegates cheered speeches from governments that been demanding during negotiations – as, one by one, they endorsed the final draft. However, not much concrete was actually agreed to. The Cancun Agreements state that countries will “aim to complete” work about extending the Kyoto Protocol “as early as possible and in time to ensure that there is no gap between the first and second commitment periods.” Developed nations will consider extending the Kyoto Protocol, but only as part of a wider agreement that commits all countries to making emissions cuts. The text refers to findings by the UN panel of climate scientists that greenhouse gas emissions by developed nations would have to fall by between 25 and 40 percent below 1990 levels by 2020 to avoid the worst damage

Green Climate Fund

The debate over the future of the Kyoto agreement was not the only potential breaking point in the talks. The US climate envoy, Todd Stern, was accused of blocking a deal on the Green Climate Fund by insisting the details be fully worked out at Cancún – instead of deferred to the next set of climate negotiations. If you recall, the Copenhagen Accord (negotiated at COP 15) created the Green Climate Fund, where developed nations promised new funds "approaching $30 billion for 2010-2012" to help developing countries. In the longer term, "developed countries commit to a goal of mobilizing jointly $100 billion a year by 2020." However, the Copenhagen Accord was never formally adopted by the UNFCCC congress and the Copenhagen Accord avoided the crucial point of how to fund this Green Climate Fund, particularly the long-term $100 billion. Of the agreed $30 billion that was pledged since Copenhagen, only $8 billion has actually been committed to international climate change programs and only $4 billion has actually been received. Going into COP 16, a recent report from the high-level Advisory Group on Climate Change Finance convened by UN Secretary General Ban Ki-Moon found that while it will be challenging, the developed countries can meet their pledges.

The Cancun Agreements formally set up a financial structure or “Green Climate Fund” that provides funding and technology to less developed nations to stave off the threats posed by climate change. The Fund will manage the annual $100 billion pledged by developing countries at the Copenhagen COP, money that is to be handed out beginning in 2020.

In the Cancun Agreements, the structure of the fund is set out in detail, including governance, voting and accountability. The board will have 15 members from developed and 25 from developing countries. The World Bank is appointed to serve as Trustee for the first 3 years.

Going in to COP16, negotiators recognized the big problem in designing the Fund was giving its operational control to a body with significant financial proficiency, and identifying a financial caretaker for the fund that has the institutional capability to handle billions of dollars. The Cancun Agreements resolved the financial caretaker issue (World Bank), but didn’t advance significantly on the first part of the problem

CCS

Discussions on whether CO2 capture and storage (CCS) can be included under the Kyoto Protocol’s Clean Development Mechanism (CDM) have been underway since COP-10 in 2005. At each COP, a decision is often discussed and yet ultimately postponed, with Parties’ positions on support or opposition seeming immobile. At COP-16, on December 4th, the Subsidiary Body for Scientific and Technical Advice (SBSTA) proposed a draft decision that, while recognizing that there are issues with CCS and CDM, provided a new context that both respects the issues and establishes a process for resolving them. In contrast, previous decisions on this issue have simply listed concerns, framing the decision in a “yes” or “no” framework.

In the end, the COP parties adopted as one of the Cancun Agreements a decision that carbon dioxide capture and storage in geological formations is eligible as project activities under the clean development mechanism, provided that the issues identified at COP 15 (in decision 2/CMP.5, paragraph 29, to be exact) are resolved and the next SBSTA “elaborate modalities and procedures for the inclusion of carbon dioxide capture and storage in geological formations as project activities under the clean development mechanism, with a view to recommending a decision to the Conference of the Parties serving as the meeting of the Parties to the Kyoto Protocol at its seventh session (that is, COP 17)” Thus there is now a path towards getting CCS included under CDM.

REDD+

REDD+ (“reducing emissions from deforestation and (forest) degradation”) essentially supports developing countries financially and technically, to either prevent deforestation or regenerate forests through afforestation. The resulting carbon sequestration is aimed to reduce overall emissions, while the move itself will enable sustainable forestry and halt degradation. The negotiating language covering REDD+ was the most settled coming into Cancun.

The final language is a careful compromise among the parties. The negotiation points in COP 16 were limited to a few obstacles, specifically related to financing (see above) and whether REDD+ can be counted in countries'" Nationally Appropriate Mitigation Actions". The Cancun Agreements build an international system to reduce deforestation, another important step in officially adopting proposals from the Copenhagen Accord. For much of the developed world, REDD is being viewed as a mechanism to reduce global GHG emissions. At present, developed nations are facing severe economic and political roadblocks to implementing concrete emissions reduction targets through domestic legislation – they can use REDD credits instead to meet reduction targets. However, funding REDD remain unclear, particularly in the long term. As of now, REDD would be financed in an adhoc approach through seed funds set up by developed nations and through private sector voluntary carbon markets. When negotiators meet next year in South Africa they will need to add more substance to these efforts.

In sum, in Cancun 193 nations attempted to hammer out their differences and finalized the Cancun Agreements that alone will not solve global warming. The Cancun agreements did formalize many of the proposals of the Copenhagen Accord and establish a temperature target for climate change mitigation, an agreement on reducing emissions from deforestation and forest degradation (REDD), and the architecture for a climate green fund that apply to all parties and not just developed countries. Look for clarification on all these issues at the next COP. Most agree that REDD will rapidly move forward over the next few years with encouragement from developed nations (for the cheap offsets) and developing countries (for the preservation of forests and offset profit) that view REDD as a faster vehicle to control deforestation and GHGs, as well as a source of economic incentives to tackle clear cutting and forest fires.
 

California’s Global Warming Solutions Act of 2006, also known as AB 32, mandates that California reduce GHG emissions to 1990 levels by 2020. In December 2008, CARB issued a Scoping Plan that outlines California’s strategies for meeting this mandate. Establishing a California cap-and-trade program is a prominent component of the Scoping Plan. Cap-and-trade refers to a system in which production of pollutants is capped, producers receive allowances that give them the right to pollute up to specified amounts, and a market is created for trading allowances among producers. For more background on AB 32, the Scoping Plan, and cap-and-trade programs, please review our earlier postings.

California’s cap-and-trade program will include a stringent declining emissions cap, meaning the amount of emissions allowed will be reduced for each subsequent compliance period. The proposed regulations outline three three-year compliance periods (2012 to 2014, 2015 to 2017, and 2018 and 2020). But CARB is considering shortening the compliance period to one year. 

Sectors subject to the cap-and-trade program include large stationary sources of GHG emissions, electricity deliverers, and fuel deliverers that emit at or above a 25,000 metric ton of carbon dioxide equivalent (MTCO₂e) threshold. In the Scoping Plan, CARB outlined a staggered approach for phasing regulated sectors into the program. Under the staggered approach, certain sectors would be covered by the program starting in the first compliance period (e.g. 2012 to 2014) with additional sectors becoming covered in subsequent periods. The proposed regulations retain the staggered approach, with 600 of California’s largest GHG-emitting stationary sources subject to the program starting January 1, 2012. But CARB has indicated that it is considering abandoning this approach and making all regulated sectors subject to the program starting January 1, 2012.

Once covered by the cap-and-trade program, an entity will hold emission allowances that it can (1) surrender to cover its emissions, (2) bank for future use, (3) trade to another entity, or (4) retire. The preliminary draft outlines the process for each of the options. But the biggest issue left open is how emission allowances will be allocated in the first instance. Options include free allocation, auction, or a mix of the two. CARB has formed a 17-member Economic and Allocation Advisory Committee (EAAC) to advise CARB on allocation and implementation issues. EAAC is expected to issue a report regarding allocation strategies in January 2010 and the recommendations in this report will be addressed in the revised draft regulations to be issued in Spring 2010.

Additional issues addressed by the preliminary draft include offsets and linkage to other trading programs. Offsets are tradable credits that represent GHG emission reductions in areas or sectors outside the scope of the cap-and-trade program. The preliminary draft proposes that covered entities be allowed to use offsets to cover up to four percent of their emissions. Thus, instead of surrendering emission credits to cover those emissions, the entity would use offsets. Emission reductions achieved by offsets must be real, permanent, verifiable, enforceable, and quantifiable. Further, the reduction must be additional to what is required by law or regulation or would otherwise have occurred.

The preliminary draft also outlines how California’s program could be linked with regional or national cap-and-trade programs. Outside of California and the Northeast, however, little is happening with regards to cap-and-trade programs. National cap-and-trade regulations are currently stalled in Congress. Thus, rather than linkage, the issue is really one of preemption. There is concern that a later-enacted national program could conflict with California’s program or that express preemption of California’s program could hamper California’s ability to meet its AB 32 mandate. Aside from a standard severability provision, preemption is not discussed in the preliminary draft but it will remain an issue in the national debate.

The full text of the preliminary draft regulations can be found here. For additional information, including specific applicability questions, please contact the Reed Smith lawyer with whom you regularly work.

The EPA estimates that the new program will apply to approximately 10,000 facilities and cover approximately 85% of all GHG emissions in the United States. Similar to the California mandatory GHG reporting program, which began earlier this year, applicability is determined by source category and/or emissions levels. In general, suppliers of fossil fuels and industrial greenhouse gases, manufacturers of vehicles and engines, and facilities that emit 25,000 metric tons or more per year of GHG emissions are required to submit annual reports to the EPA under the rule. Key source categories excluded from the rule’s scope include electronics manufacturing, food processing, industrial landfills, coal suppliers, and wastewater treatment facilities. The EPA estimates that most small businesses will be excluded as well because their emissions will fall below the 25,000 metric ton threshold. How to report is obviously a big concern and the EPA has developed a general “Applicability Tool” to help emitters evaluate whether they are subject to the rule’s reporting requirements. An earlier posting on our blog also provided advice to facilities on how to establish that they do not have to report. That information can be found here.

In general, reporting is done on a facility level, even where there are multiple sources at one facility. Facility is broadly defined to include any plant, building, structure, source, or stationary equipment that is located on contiguous or adjacent property and under common control. The key exception to the facility-wide reporting requirement is that certain suppliers of fossil fuels as well as vehicle and engine manufacturers will report at the corporate level.

Specific gases to be reported include carbon dioxide (CO₂), methane (CH₄), nitrous oxide (N₂O), hydrofluorocarbons (HFC), perfluorocarbons (PFC), sulfur hexafluoride (SF₆), and other fluorinated gases including nitrogen trifluoride (NF₃) and hydrofluorinated ethers (HFE). The final rule sets forth specific methodologies for calculating emissions of these gases. The methodologies must be used, with only one exception. The EPA will allow the use of “best available data” for reporting between January and March 2010. Facilities can request an extension of the exception past March 2010 but the EPA has expressed that no extensions beyond December 2010 will be granted.

Unlike the California program, the final rule does not mandate third-party verification of the reported data. In California, third-party verification is required beginning in 2010. Under the nationwide program, however, reporters can self-certify their data, which will then be verified by the EPA.

EPA estimates that, for the first year of reporting, the annualized costs of reporting for the private sector will be approximately $115 million and that, for subsequent years, those costs will be reduced to $72 million.

The EPA is currently providing information about the new rule. For additional information, including specific applicability and reporting questions, please contact the Reed Smith lawyer with whom you regularly work.

Large Sources: EPA is proposing mandatory reporting for facilities that emit 25,000 mtCO2e or more annually. For reference sake, 25,000 mtCO2e is equivalent to emissions from annual energy use of about 2,200 homes. It is also equivalent to just more than 58,000 barrels of oil consumed or 131 railcars' worth of coal.

In addition, for some 19 source categories created by the proposed rule, all of the facilities with that particular source category within their boundaries would be subject to the reporting requirements. These source categories include large manufacturing operations such as petroleum refineries and cement production. 

If your facility is not in one of these 19 source categories, you need to report only if you emit 25,000 mtCO2e or more annually.

Small Sources: EPA is clear that very small sources – households, certain commercial buildings, and individual vehicle owners – will not need to report. The average annual household emissions in the United States are about 11.3 mtCO2e, well below the threshold for reporting. Also, if your facility simply has "stationary fuel combustion units" (boilers, combustion turbines, engines, incinerators, and process heaters) and no other emission sources within their boundary—say, commercial office space—you do not need to report if the aggregate maximum rated heat input capacity of the stationary fuel combustion units summed is less than 30 mmBtu/hr. If a building does have an aggregate maximum rated heat input capacity equal to or greater than 30 mmBtu/hr, then that facility may need to do further calculations to determine if it meets the threshold for reporting. However, EPA is seeking further comment on this strategy in the proposal.

Mid-Size Sources: What about mid-size manufacturing facilities—will they have to report? The short answer is that some mid-size facilities will have to report, and others will not.

How do you determine whether your mid-size facility will have to report? Under the proposed regulations, there is an affirmative obligation on the owner or operator of a facility to review the "appropriate records" to determine whether the threshold has been exceeded. The question, of course, is whether your facility has these "appropriate records" for review, or whether such records will need to be generated in the first reporting year.

Annual Emissions Estimates: In general terms, to determine the applicability of the thresholds, a facility will have to estimate the annual emissions of CO2, CH4, N2O, and fluorinated GHG (as defined in §98.6) in metric tons from stationary fuel combustion units, miscellaneous uses of carbonate, and any applicable source category listed in the Proposed GHG Regulations. (See Proposed GHG Regulation, §98.2(b))

A facility would then sum the GHG emissions totals from each of these three subcategories and determine if its facility-wide emissions are under 25,000 mtCO2e.1

Exemptions from Emission Reports: The Proposed GHG Rule expressly states that the owners and operators of a facility that does not meet the 25,000 mtCO2e threshold are not required to submit an emission report for the facility. However, such owners and operators must reevaluate the applicability of reporting (which reevaluation must include the revising of any relevant emissions calculations or other calculations) whenever there is any change to the facility or supplier that could cause the facility or supplier to meet the applicability requirements of reporting. Such changes include, but are not limited to, process modifications, increases in operating hours, increases in production, changes in fuel or raw material use, addition of equipment, and facility expansion.

Penalties: Are there penalties for those who fail to estimate and collect the data needed to decide whether or not to report? The Proposed GHG Rule states:

Any violation of the requirements of this part shall be a violation of the Clean Air Act. A violation includes, but is not limited to, failure to report GHG emissions, failure to collect data needed to calculate GHG emissions, failure to continuously monitor and test as required, failure to retain records needed to verify the amount of GHG emission, and failure to calculate GHG emissions following the methodologies specified in this part. Each day of a violation constitutes a separate violation.

(emphasis added) Thus, there are potentially serious consequences for failing to collect appropriate data and properly calculate GHG emissions to determine whether reporting requirements apply to your facility. The proposed regulations are silent with regard to record-retention requirements for non-reporting facilities; however, particularly if the facility falls just slightly short of a threshold, a prudent owner or operator of the facility should follow the recordkeeping provision for reporting entities – in case the facility's responsibility to report is called into question.

GHG Reporting ("Once in, always in"): Also note that EPA is adopting a "once in, always in" approach to GHG reporting: Once a facility is subject to the reporting requirements, the owners and operators of the facility must continue for each year thereafter to comply with all requirements of this part, including the requirement to submit GHG emission reports, even if the facility does not meet the applicability threshold for reporting in a future year. (See Proposed GHG Regulation, §98.2(g))

A final point bears mentioning that the threshold requirements for reporting under this Proposed GHG Rule have a strong likelihood of being repeated as the thresholds for permitting under the federal cap and trade system when it is eventually enacted. Therefore, determinations of applicability with regard to threshold reporting under the Proposed GHG Rule may have implications with regard to whether your facility is a "covered source" for purposes of the expected federal cap and trade system.

For all the reason stated above, mid-sized manufacturing facilities that are close to the reporting thresholds would be well served to carefully analyze and sufficiently document their determination with regard to "near misses" of the threshold, and discuss such determination with counsel. In fact, even though third-party verification of calculations and emissions—or even opinions from legal counsel—are not required under the Proposed GHG Rule, they should be considered by certain mid-sized facilities.

If you would like to comment on the provisions of the Proposed GHG Rule, set forth above or otherwise, please contact Jennifer Smokelin, Larry Demase, Todd Maiden, Lou Naugle, or the Reed Smith attorney with whom you usually work. Comment period will be open for 60 days after publication of the proposed rule in the Federal Register, which has not occurred yet.

Footnote 1: Suppliers of industrial GHGs have to report if they are supplying product that is equivalent to 25,000 mtCO2e or more when released.  Thus, if you are a mid-sized supplier of industrial GHGs, you would need to follow the regulations and keep records and perform calculations to determine if you are supplying product that is equivalent to 25,000 mtCO2e or more when released.

Currently, the electricity sector accounts for 25 percent of California's GHG emissions. The CARB's Climate Change Draft Scoping Plan expects that the electricity industry will contribute at least 40 percent of the total GHG reductions from direct mandatory approaches and measures. With the addition of a potential cap-and-trade program, the electricity sector may be called upon to reduce its emissions even more. The Proposed Final Opinion describes specific mechanisms for requiring the electricity industry to meet the goals set out in the draft Scoping Plan. To achieve these ambitious cuts in GHG emissions, the Proposed Final Opinion offers recommendations and options in energy efficiency and renewable resources and combined heat and power ("CHP"), and describes a complementary cap-and-trade program. In more detail, the Proposed Final Opinion:

• Reaffirms the commitment to pursue all of the state's cost-effective energy efficiency options and urges the expansion of renewable energy to 33 percent of energy usage for all retail providers.
• Considers electric sector costs and rate impacts of reaching the 2020 GHG levels through more energy efficiency, greater use of renewable energy, and increased CHP, and concludes that the impacts will vary depending on service territory and on the design of the ultimate program developed by the CARB. (Staff and consultants of the Commissions developed a variety of illustrative scenarios that indicate that, unrelated to AB 32 compliance, utility rates are likely to rise above the rate of inflation because of increased capital and operating costs and load growth. Under some scenarios related to AB 32 policies, however, utility costs may be reduced compared with business as usual, after accounting for the adoption of significant energy efficiency measures by consumers.
• Recognizes the value of higher energy efficiency provided by CHP projects, and recommends that for larger installations (over the size-threshold adopted by CARB), the GHG emissions for electricity consumed onsite and/or delivered to the grid be included in the cap-and-trade program, and receive allowance allocations comparable to other electricity providers and consumers.
• Identifies auctioning as the preferred method to distribute emission allowances. Starting in 2012, 80 percent of the emission permits or allowances would be distributed for free to electricity deliverers and 20 percent would be auctioned, with 100 percent auctioned by 2016.
• Recommends that free allowances be allocated to deliverers based on energy output and electricity fuel source. (Allowances would be granted to the electricity retail providers on behalf of their customers, with the allowances offered for sale in an independent, centralized auction. These allowance allocations will change over time based on historical portfolio emissions to a sales basis by 2020, to allow transition time for retail providers with emission intensive portfolios.)
• Proposes that auction revenues be used for AB 32-related purposes, and all revenues auctioned by the retail providers be used to support investments in renewables, efficiency, new energy technology, infrastructure, and customer bill relief.
• Urges, in considering market structure, that the key market design feature is maintaining environmental integrity. (Market structure should encourage open and transparent allowance trading with many participants, unlimited banking of allowances and offsets, and offsets that must meet AB 32 requirements to be real and permanent. Offsets should not be limited geographically. If a multi-sector regional cap-and-trade is developed, a three-year compliance period should be established to allow time to implement emission reduction measures and to account for hydrologic conditions that can significantly impact the electricity sector.)

The development of this Proposed Final Opinion has been an open public process beginning with a joint Commission symposium in April 2007 that addressed GHG emissions and various types of possible cap-and-trade markets. A number of workshops have helped craft the recommendations. The Proposed Final Opinion on Greenhouse Strategies, A Summary of the Proposed Opinion, and Frequently Asked Questions are available from the Energy Commission, and are also available from the California Public Utilities Commission.