In this edition of Dentons' Climate Change Newsletter, we start with the United States Supreme Court's most recent review of Environmental Protection Agency (EPA) regulations, the so-called "tailoring rule," a story that broke just as this newsletter was being finalized. We turn then to events happening around the world, including the announcement of a long-awaited and extremely comprehensive proposed regulation.

Please do not hesitate to contact any member of Dentons' Climate Change Newsletter team. We welcome your questions, feedback and comments.

Topics

• US Supreme Court largely upholds EPA's regulation of GHGs from major new and modified sources
• EPA envisions a clean power future with its existing power plant proposal
• ACORE statement on CPP
• China’s reply?
• Trading among states allowed as a tool for CPP
• Global prices on carbon allowances
• Recent and proposed regulatory changes in the Canadian GHG emissions landscape
• Meanwhile in Europe - a status report
• South African government considers carbon offset scheme as part of carbon tax

US Supreme Court largely upholds EPA's regulation of GHGs from major new and modified sources

by James Rubin

On June 23, 2014, the Supreme Court issued a split decision in Utility Air Regulatory Group v. EPA, striking down part of an EPA rule requiring pre-construction permits for large sources of greenhouse gas (GHGs) emissions, while upholding EPA's authority to require inclusion of GHGs in pre-construction permits mandated for other pollutants. Specifically, the Court held that the Clean Air Act neither compelled nor required EPA to apply GHG regulations to stationary sources once it set GHG limits for cars and trucks. In so doing, the Court invalidated the "Tailoring Rule," whereby EPA rewrote statutory emissions thresholds to allow it to operate a pre-construction permit process for large sources of GHG emissions. At the same time, the Court concluded that EPA had the discretion to require sources to apply the "Best Available Control Technology" to GHG emissions when securing pre-construction permits based on emissions of conventional pollutants (so called "anyway" sources).

The mixed decision underscores the Court's view that EPA has authority to regulate GHG emissions under the Clean Air Act (CAA), including under other provisions, but that the scope of those regulations must be appropriate to the purpose and context of the specific provisions. Moreover, the Court strongly warns EPA that it should not establish broad-ranging programs to address climate change without clear congressional direction. Hence, the ruling does not directly impact EPA's recent proposals for GHG performance standards from new and existing power plants, but it certainly suggests that the Court may more strictly scrutinize such EPA actions purporting to impact the power sector at large and reduce energy demand.

For a more detailed analysis of the ruling, please see our recent client alert, "US Supreme Court ruling on EPA greenhouse gas regulations: So who really won?"

EPA envisions a clean power future with its existing power plant proposal

by James Rubin

On June 2, 2014, the EPA released its Clean Power Program (CPP), the cornerstone of the Obama administration's Climate Change Action Plan to regulate greenhouse gas emissions. The CPP establishes requirements for states to issue "standards of performance" for emissions of carbon dioxide (CO2) from existing fossil fuel electrical generating units (EGUs) under the Clean Air Act (CAA) section 111(d). But the broad name EPA has given to its proposal—Clean Power Program—more accurately reflects the sweeping nature and scope of its efforts to help propel the US power sector forward onto a cleaner, less carbon-intensive path.

The Clean Power Program follows EPA's proposed New Source Performance Standards for new EGUs under CAA section 111(b) (new unit rule), published in February 2014. But where the new unit rule was clearly intended to drive new plant construction toward coal-fired power with carbon capture and sequestration and natural gas combined cycle generation, the Clean Power Program seeks to promote a wide array of low- or zero-carbon options, including further natural gas dispatch, renewable energy, nuclear energy, energy efficiency and demand-side management, and to ensure that these elements are integrated into long-term planning and investment. EPA's broad reach creates legal vulnerabilities for the proposal, but it also creates opportunities for states and for electricity generators to make greater investments in a clean energy future.

The CPP's goal is to secure 30 percent CO2 reductions from fossil fuel-fired generation by 2030 based on a 2005 baseline. To get there, EPA sets carbon intensity rate goals for each state, expressed as the average rate of emissions per net megawatt hour (MWh) of electricity across all power plants in that state. EPA develops these goals by taking each state's 2012 power plant emission levels and calculating a reduction target based on the application of four "building blocks" identified, in the aggregate, as the "Best System of Emission Reductions." These are: 1) heat rate improvements for individual coal-fired units; 2) increased dispatch of natural gas to displace oil and coal generation; 3) increased renewable energy and changes in nuclear capacity; and 4) increasing demand-side energy efficiency programs.

EPA provides states with significant flexibility in developing plans to meet these goals, which are in reality hard caps. State plans must ensure that these goals are met, beginning in 2020 and throughout the decade, achieving an average interim goal from 2020–2029 and a final goal by 2030 and thereafter. States can apply emission limits directly to affected EGUs, use any of the building blocks in a "portfolio approach," or use any other measure as long as they are enforceable and help meet interim and final targets. States can also create regional programs and submit regional plans. States can even convert their rate-based targets to mass-based targets (tons of CO2 emitted) since that may better enable them to participate in regional trading programs.

States must submit plans within one year of the finalization of the rule, which EPA intends to complete in June 2015. This means states must file plans by June 2016. However, they may seek an additional year or, if they create regional plans, two extra years. States must apply for an exemption and still make interim filings in June 2016. Once a plan is submitted, EPA has a year to review, and once approved, state requirements become federally enforceable.

The proposal was published in the Federal Register on June 18, 2014, initiating a 120-day comment period. EPA will also hold four public hearings in several states and in Washington, DC, over the summer. EPA plans to finalize the rule by June 2015; after that, it will surely be challenged in court. EPA also plans to issue a final new unit rule before or concurrently with the Clean Power Program, as well as a companion rule setting standards for modified and reconstructed EGUs.

If the Clean Power Program is finalized largely as proposed, it could create major opportunities for clean energy providers and investment in clean energy. This could include spurring further dispatch and construction of new natural gas generation capacity, further development of renewable power, and perhaps a rescue of "at risk" nuclear plants. It would also provide opportunities for utilities and other entities to enhance energy efficiency measures and take a wide range of actions to reduce energy demand well beyond EGUs or the power sector. At the same time, it is likely to lead to additional retirements of coal plants, already buffeted by sustained low gas prices and EPA's air toxics rule.

The proposal will—and already has—generated legal and political opposition. Members of Congress immediately attacked the proposal as too costly. Opponents of the regulation are likely to challenge the program in court based, in part, on its very breadth, arguing that section 111(d) in no way authorizes EPA to implement such sweeping regulation of the power sector.

Whether and how the Clean Power Program might eventually impact the power sector may ultimately depend as much on the District of Columbia Circuit Court as it does on who is in the White House after 2016.

ACORE statement on CPP

The American Council on Renewable Energy (ACORE) announced its support for CPP the day it was announced.

ACORE board member and Dentons principal Sydney McNiff Johnson commented as a business leader within the industry and suggested that this development is overdue. "The fact is, many companies are already pricing carbon into their business models for the future. EPA can capitalize on this private-sector development by encouraging carbon markets and opening the door to clean energy build-out."

China’s reply?

by Matt Adams

Just hours after the EPA proposed new limits on GHG emissions from America's existing fossil fuel electric generating units, China announced its own ambitious plans to limit GHGs. Or did it?

On June 3, He Jiankun, vice chairman of China's National Expert Committee on Climate Change, was quoted in several news outlets as announcing that the Chinese government will impose an absolute cap on GHG emissions beginning in 2016. But subsequent statements have characterized the Chinese GHG cap as a proposal, rather than a final policy or requirement. For now, the only certain thing is the absence of certainty.

If China ultimately enacts a firm cap on GHG emissions, it could significantly change the dynamics at upcoming United Nations climate change negotiations in Lima (December 2014) and Paris (December 2015). In the past, the United States has been reluctant to pursue an international agreement on GHGs until developing nations move to limit their own emissions. A meaningful cap on China's GHG emissions would help break that logjam.

Limits on China's GHG emissions could also change the dynamics of the United States' domestic debate over EPA's proposed limits on existing fossil fuel electric generating units. Opponents of EPA's proposal are concerned that it will undermine American economic performance and provide unfair advantages to international competitors. Limits on Chinese GHG emissions would offset those concerns and help make the EPA proposal more politically palatable.

Trading among states allowed as a tool for CPP

by Jeffrey Fort

A key element of the Clean PowerProgram proposal announced by EPA is its encouragement of states to develop and use trading programs as a method of reaching each state’s performance goal. Having set a goal for each state to meet, and outlined its four “building blocks” to meet those goals, EPA also made clear it would be receptive to multistate programs to allow for the trading of allowances.

Of course, the use of environmental commodities is well known under the Clean Air Act and in state implementation plans (SIPs). The utility sector is familiar with this tool which has also been used for reducing nitrogen oxide (NOx) and sulfur oxide (SOx) emissions from Electric Generating Units (EGUs). Like the allotments under Title IV of the 1990 Clean Air Act Amendments (the “acid rain” program) these environmental commodities delivered emission reductions at a lower cost than a facility-by-facility, command and control approach. Indeed, EPA's use of a performance standard for each state to meet appears intended to address the requirement that SIPs be measured on a state-by-state basis. The state-by-state performance standards proposed by EPA do not reflect a uniform reduction of carbon dioxide emissions from the EGU sector and appear to recognize the existing fuels and technologies which different states have available.

The reader will recall that there are presently two state-based systems using tradable carbon allowances, one a multistate program for nine northeastern states, the Regional Greenhouse Gas Initiative (RGGI), and the other an economy-wide carbon trading program in California. The states of Washington and Oregon (and other western states) were involved in forming the Western Climate Initiative and are considering a new agreement with California for trading of GHG allotments. The RGGI market is certainly a potential option for states to join. Recall that the Midwest Governors Association also had considered launching a platform for interstate trading when it appeared likely that Congress might pass national legislation, in part in order to have a role in a federal system. Now, the issue may be much simpler: how to meet the regulatory expectations of EPA at the lowest cost.

The recognition of increased renewable power as one of the building blocks may affect another potential tradable commodity: the Renewable Energy Credit (REC). Twenty-nine states and the District of Columbia have renewable portfolio standards (RPS). Under those standards, these RECs are, for the most part, tradable among regulated utilities to meet the state-specific RPS. But they are not the same as a carbon credit, and the two commodities have operated in separate trading programs. While EPA did not equate existing RPS with measures to meet the CPP proposed regulation, there may come a convergence of RECs into a CPP carbon trading scheme with new renewable generating units.

The use of tradable credits, tied into a state-based strategy, is not a unique development. Environmental trading programs have been in use for more than 20 years and are not uncommon, particularly for utilities in the Midwest and the eastern United States for other pollutants from coal-combustion in EGUs: NOx and SOx. A difference in this proposal is that EPA has set state-by-state goals based on the “best system of emission reduction” which are available to a state instead of on a regional atmospheric model. This may give states a wide range of alternatives, including trading programs, to meet those goals. Moreover, the use of state implementation programs involve more familiar stakeholders and economic considerations than is the case with the usual federal, technology-specific, standards. Once again, the use of interstate trading programs seems intended to provide a method of controlling costs for the electric sector.

Global prices on carbon allowances

by Susan Wood

There is much conversation about the "price of carbon." We thought it useful to list the varied prices that exist in the many markets around the world.

Environmental commodities (emission credits, carbon credits and renewable energy credits) are some of the most esoteric commodities traded on markets. Price discovery and liquidity is a luxury often not afforded to these markets, so pricing, buying and selling these commodities can often be difficult and confusing. It is for this reason that clients occasionally ask Dentons to provide pricing evaluations of these markets. Most recently, the implementation of the California and the China carbon markets has increased the interest in prices for environmental commodities across the board. The following is a snapshot of some key indexes currently trading in the markets.

Recent and proposed regulatory changes in the Canadian GHG emissions landscape

by John Goetz

Just days after the EPA announced its Clean Power Plan to reduce emissions from the power sector by 30 percent, the government of Canada announced a proposed Air Pollutants Regulation aimed at significantly lowering smog levels and improving air quality by reducing nitrogen oxide (NOx), sulfur dioxide (SO2), volatile organic compounds, ammonia and particulate matter emissions. The government of Canada estimates that these regulations will reduce GHG emissions (NOx) by 3.4 million metric tons between 2013 and 2035. The first phase of the regulations will cover industrial boilers and heaters, stationary engines such as those used for gas compression and the cement manufacturing sector. Like its US counterpart, Environment Canada is pointing to health benefits to be achieved through these regulations and projecting net health benefits totaling C$9 billion between 2013 and 2035. Canada introduced regulations in 2012 to reduce emissions from coal-fired generation plants by setting a new performance standard for generation plants and plants that had reached the end of their useful life, fixed at 420 metric tons of carbon dioxide per gigawatt hour (CO2/GWh). This effectively requires plants at the end of their lives to install carbon capture and sequestration (CCS) mechanisms or cease operations. This year, the province of Ontario became the first jurisdiction in North America to eliminate coal as a source of electricity. In 2003, coal produced 25 percent of Ontario’s electricity. It now uses a mix of nuclear, hydro, renewable and cleaner burning natural gas and biofuels.

Changes are occurring in the GHG emissions regulatory landscape in Canada, principally in Alberta and Quebec. Alberta’s GHG Emissions Regulation is due to expire on September 1 of this year and is expected to either be renewed in an amended form prior to that date or extended on a temporary basis until a new leader/premier is selected by the governing Progressive Conservative party. The province was considering increasing both its emission reduction targets and its carbon price by implementing a “double-double” plan that involved doubling the price of its government issued compliance credits from C$15 to C$30 per metric ton and doubling the emission intensity reduction requirement from 12 percent to 24 percent. These combined changes would have doubled the volume of annual reductions required from approximately nine million to 18 million metric tons and quadrupled the annual compliance costs for regulated emitters from approximately C$135 million to C$540 million. However, Alberta Energy Minister Robin Campbell was quoted in mid-June as saying that the province is not looking to increase its emissions reduction targets. It is not clear at this time whether or not the province will increase its price per metric ton, but it is beginning to seem less and less likely that the province will be making significant changes. Minister Campbell also indicated that the province hoped to have its new GHG emissions program released in October, which indicates that a temporary extension to the existing regulation is likely.

Emitters have spent more than C$800 million on emission offsets, performance credits and allowances since the regulation was introduced in 2007, but Alberta does not appear to be on track to meet its 2020 target of 15 percent below 2005 intensity levels or its 2050 target of 200 million metric tons (50 percent below projected business as usual or 14 percent less than 2005 levels). Due to its reliance on coal-fired generation and the growth of its oil sands sector, Alberta’s GHG emissions are projected to nearly double by 2050 unless effective emission reductions are achieved.

Approximately 70 percent of the planned reductions are projected to come through CCS projects, but only two such projects are proceeding at this time, with estimated combined sequestration capacity of approximately two million metric tons of CO2 annually (1.5 percent of the 2050 CCS target). With a few exceptions, CCS is not proving to be economically viable using currently available technologies due to the high cost of capturing CO2 from power plants and the low price of carbon. As of 2012, Alberta has achieved about one-third of its annual emission reduction target for 2020.

The lack of meaningful progress on emission reductions has environmental critics around the globe pointing fingers at Alberta’s growing emissions and calling for a shutdown of oil sands production. According to Environment Canada, Alberta’s annual GHG emissions increased by approximately seven percent between 2005 and 2011 and are projected to increase by about 21 percent between 2005 and 2020, largely due to increasing population, increasing economic activity and a near tripling in oil sands production. These projections are based on existing government programs and technologies, which could change in the coming years and have a material impact on emissions. It will be interesting to see what changes Alberta makes in its revised emissions regulation.

Elsewhere in Canada, the province of Quebec completed its third GHG allowances auction on May 27, marking the first auction in which all available 2014 vintage allowances were sold. Previous auctions in December 2013 and March 2014 sold 34 percent and 98.6 percent of available 2014 allowances, respectively. The allowances continued to sell at the floor price of C$11.39 per unit; 85 percent of the 1,527,000 available 2017 vintage units were also sold at the floor price. California and Quebec announced that they will be holding their first joint auction in November and conducting a practice joint auction in August.

Meanwhile in Europe - a status report

by Adam Brown

In the EU, the environmental regulation of the operation of fossil fuel-fired generating plants is dominated by two EU directives. The EU Emissions Trading Scheme (EU ETS, established by Directive 2003/87/EC) is designed to reduce the EU's overall emissions of greenhouse gases through an EU-wide cap-and-trade system. The Industrial Emissions Directive (IED, Directive 2010/75EU) is primarily focused on other pollutants—notably, in the case of power plants, sulfur dioxide (SO2), nitrogen oxides (NOx) and dust.

Although IED permits are in principle intended to regulate all significant pollutant streams from industrial installations, national authorities are generally not meant to (and do not) use them to control GHG emissions. Yet, paradoxically, it is the IED (with its precursors, the Large Combustion Plant Directive, or LCPD, and the Integrated Pollution Permitting and Control Directive, or IPPCD), rather than the EU ETS, which arguably has so far done most to reduce the carbon intensity of the EU generating sector by driving coal, oil and older gas plants out of business.

Under the EU ETS, operators of installations which emit GHGs must report and surrender allowances in respect of their GHG emissions (in metric tons of carbon dioxide equivalent) each year. In Phase 3 of the scheme, which began on January 1, 2013, operators in the power sector no longer receive a free allocation of allowances and must purchase them through auctions or on the EU emissions trading market. Yet while this has meant that operators of large combustion plants are now subject to significant compliance costs, the fact remains that the carbon price created by the EU ETS has much of the time been far below the level required to drive decarbonization (for much of 2013 it was about £5). This has led the UK government, for example, to try to reinforce the weak price signal generated by the EU ETS with a direct levy on carbon-intensive generators known as the Carbon Price Floor—although it has recently reduced future increases in the levy to avoid placing too great a burden on energy intensive industries. The government has also introduced legislation—partly inspired by Californian precedents—that prevents the construction of new coal-fired power stations with a capacity of more than 50 MW unless they are fitted with carbon capture and storage.

In contrast to the quasi-market approach of the EU ETS, the IED, like the LCPD and IPPCD before it, requires Member States to control SO2, NOx and dust emissions by setting emissions performance limits for individual plant (existing and new) that reflect what are acknowledged as the "best available techniques" for limiting such emissions, with the directive itself setting upper limits on what the permits can allow. Broadly speaking, new plants are set somewhat stricter limits and have to comply from an earlier date, while existing plants are also given opportunities to move into compliance over a period of a few years, to run for only 1,500 hours each year or to close after running for no more than 17,500 hours before the end of 2023. The LCPD effectively forced all UK coal-fired power stations to invest in SO2 abatement technology or close. The IED aims to curb NOx emissions significantly. Taken together, they may close up to 20 percent of the UK's grid-connected generating capacity. Brownouts and blackouts are a real prospect for the first time in many years.

From an environmental point of view, the LCPD and IED are designed to control pollutants that damage human health and give rise to phenomena such as eutrophication and acid rain, rather than global warming, but because the same plants produce the highest concentrations of both GHGs and SO2/NOx, LCPD has had a substantial decarbonizing effect. But whether IED will have as much of an impact as the LCPD and IPPCD have had when it affects existing plants after January 1, 2016, is not yet clear. This is partly because concerns about the adequacy of generation capacity is leading EU Member State governments, which are also concerned about the need to balance intermittent renewable generation, to develop "capacity markets" as a way of subsidizing readily dispatchable fossil fuel-fired plants. But the bigger incentives to upgrade old coal plants to meet IED NOx standards come from outside the EU. The US shale revolution and the high price of gas in the EU have potentially made it worthwhile to upgrade old coal plants, meaning that—notwithstanding the EU ETS and even national measures like the Carbon Price Floor—the EU's old coal plants will continue to provide baseload generation for some time to come.

South African government considers carbon offset scheme as part of carbon tax

by Helen Bowdren

The South African National Treasury has published proposals for a carbon offset scheme. The scheme aims to increase investments in projects that will reduce GHG emissions. It will also enable businesses to reduce their liability to carbon tax, which is due to be introduced in 2016.

Carbon offsets are a form of trade. Buying an offset helps to fund projects that reduce GHG emissions. The government hopes that the scheme will drive investment in GHG-mitigation projects that reduce emissions at a lower cost than the carbon tax, and that it will fund projects to generate considerable sustainable development benefits in South Africa.

Projects that could generate carbon offsets include:

• Solar and wind energy projects
• Transportation projects (for example rapid rail or bus links)
• Solar water heating
• Sequestration of carbon through land-based projects (for example, reforestation)

The projects are subject to strict eligibility criteria. Only credits from South Africa-based projects will be eligible, and any projects registered or implemented prior to the introduction of the carbon tax regime will have to fulfill specified conditions to be accepted to the scheme.

The paper proposes to accept offsets from four established offset standards, all of which are already in use in South Africa:

• Clean Development Mechanism (CDM)
• Verified Carbon Standard
• Gold Standard
• Climate, Community and Biodiversity Standard

There are currently 111 registered carbon offset projects in South Africa, developed either under the CDM or one of the other standards above.

The proposals also suggest that carbon offsets can be used to reduce carbon-tax liability, by increasing the basic tax-free threshold from 60 percent to up to 90 percent. The use of carbon offsets to reduce carbon-tax liability reflects current global trends, where a number of countries have employed such measures.

The Carbon Offsets Paper is available for download from the website of the South African National Treasury.