Client Alert

Recent Developments in the Regional Greenhouse Gas Initiative

The ultimate design of and state-based implementation of the RGGI bears a close watch by industries and individuals outside of the Northeast.

Regions, states, municipalities and major corporations across the United States have begun to take action with regard to climate change. At present, more than half of the states have climate action plans, and 22 have specific renewable power targets for their utilities. The mayors of more than 200 cities have signed the United States Mayors Climate Protection Agreement, pledging, among other things, to reduce greenhouse gas emissions in their cities to 1990 levels by 2012. Such a bottom-up effort has not been seen since the 1960s and 1970s, when dual efforts to regulate air and water quality on the part of states and industries led to the development of the federal Clean Water and Clean Air Acts.

A coalition of Northeastern and Mid-Atlantic states has been at the forefront of these efforts, working to implement the first mandatory greenhouse gas emission reduction program in the United States with the March 23, 2006 issuance of a draft model rule for the region. Each participating state is committed to implementing the final model rule through state law by December 31, 2008. The Regional Greenhouse Gas Initiative (RGGI) imposes a regional cap on emissions from the electric generating sector, from which each state will receive an emissions budget to allocate to individual sources. These individual sources can then trade emission credits or allowances across the region.

RGGI includes plans for geographic, source and emissions expansion and is widely considered to be the most likely precursor to any federal program to reduce greenhouse gas emissions. As the extensive comments received on the draft model rule indicate, attention across the United States is focused on RGGI, particularly its structure for the allocation of emissions, restrictions on offsets and problems with leakage, expected impacts on ratepayers, the relative competitiveness of various industries and the RGGI program's overall ability to reduce greenhouse gas emissions.

RGGI's Current Status and Anticipated Timeline

Both significant progress and set-backs have occurred over the past year. On December 20, 2005, the seven RGGI participating states – Connecticut, Delaware, Maine, New Hampshire, New Jersey, New York and Vermont – signed a Memorandum of Understanding (MOU) on the major themes of the RGGI. At the same time, Massachusetts and Rhode Island, two original participants, withdrew from RGGI, citing concerns that it did not sufficiently protect businesses and consumers from increased energy costs that might result from the emissions caps. In April, however, Maryland committed to join RGGI. This is a substantial development, as Maryland's energy sector relies heavily on coal (unlike other RGGI states that rely on natural gas and nuclear energy), and its carbon dioxide emissions exceed those of Massachusetts and Rhode Island combined.

Each RGGI state must now pass independent legislation or promulgate rulemakings for the model rule to take effect. Vermont became the first state to do so with legislation enacted on May 3, 2006. It is anticipated that the final model rule will be issued on July 6, 2006, and New York and New Jersey plan to commence with rulemakings immediately thereafter. New York hopes to finalize its rule in the first quarter of 2007. New Hampshire requires legislative approval prior to rulemaking, and Maine is expected to pursue legislative action as well; thus, implementation may take longer in those states.

Two issues key to RGGI's success and national expansion will be further evaluated over the next few months. A Leakage Working Group has been established to evaluate the impact of electricity imports from outside the region on RGGI, and to identify options for how to address leakage and its potential impacts. Its final report is due in July 2007. Additionally, a stakeholder discussion on the role of auctions in emissions allocations is scheduled for July 20, 2006 in New York City.

The Draft Model Rule: Key Provisions and Comments

Extensive and disparate comments were received from regulated and non-impacted industries, environmental, and ratepayer groups on key provisions of the draft model rule. Commentors focused on: certain source exemptions, allowance distribution, restrictions on offsets and problems with leakage. Notably, a consistent thread among the comments – that individual state programs be as similar as possible to reduce uncertainty – runs counter to the key RGGI principle of flexible, individual state-based implementation. These and other key provisions of the rule, as discussed below, are likely to remain contentious as the model rule is finalized and the RGGI states craft their individual rulemakings and legislation.

The Regional Cap Will Contract Over Time

From 2009 to 2014, emissions of carbon dioxide from the power sector in the RGGI participating states will be capped at close to current levels – approximately 121 million tons annually. The RGGI states will then begin reducing CO2 emissions incrementally over a four-year period, by 2.5 percent per state, to achieve an overall CO2 emissions reduction of 10 percent below the initial cap by the end of 2018.

RGGI Exemptions Raise Concerns

Initially, only fossil fuel-fired units serving an electric generator with a nameplate capacity of 25 megawatts and greater, which burn more than 50 percent fossil fuel, are subject to regulation under RGGI. Smaller units and units that burn bio-mass for more than 50 percent of their total fuel are expressly exempt, and the draft model rule includes an optional "Behind the Meter" exemption that gives each state the discretion to exempt from regulation units that produce power for industries but supply less than 10 percent of their electrical output to the grid. Additionally, generators can take early action and receive credit for emissions reductions occurring as early as December 20, 2005.

These exemptions and early action credits (EACs) have been criticized by environmental groups for their inflationary pressure on the cap. The emissions from exempt units were calculated in each state-based cap; therefore, unless the caps are reduced, the pool of allowances available to other sources will increase, and the environmental benefit of the cap will be reduced. Similarly, the draft model rule does not specify whether the cap for the initial compliance period will be reduced to account for allowances met by a source through EACs.

Industry stakeholders have noted that the draft model rule does not accurately explain how new sources of emissions will be regulated. These groups have argued that new sources should initially be exempt from RGGI requirements, rather than forced to purchase allocations prior to beginning operations, to promote a level playing field with existing sources. Conversely, environmental groups argue that any exemptions for new sources must be met by reductions in the cap, to ensure that there is an overall reduction in greenhouse gas emissions.

Allowances Distribution Has Cost, Competitiveness and Leakage Implications

Each state will issue one allowance for each ton of CO2 emissions allowed by its cap. Each regulated entity must have enough allowances to cover its CO2 emissions, either by reducing emissions, purchasing allowances or achieving reductions outside the electricity sector through offset projects. If a source has failed to cover its emissions at the end of a compliance period, the regulatory agency can deduct up to three times the deficit from the source's future allocations, as well as apply state-specific penalties.

Sources report their emissions annually but must only true-up, or cover their emissions with allowances, every three years. Each state must determine how its emissions allowances will be distributed no later than January 1, 2009 for the years 2009, 2010, 2011 and 2012 – and they must true-up for the first compliance period by March 1, 2012 (CO2 allowances must be submitted by the March 1 following the relevant three year control period). By January 1 of each year succeeding 2009, allowances will be allocated for the year beginning three years later.

Each participating state will determine how to allocate allowances. Although the draft model rule requires each state to allocate a minimum of 25 percent of its emissions allowances to "consumer benefit or strategic energy purposes," the state has discretion in how to do so. Similarly, the remaining 75 percent of the allowances can be allocated by participating states as they see fit, including: giving away the allowances to affected generators (or even non-generators), auctioning them in an open emissions market to the highest bidders, or reallocating allowances regularly based on capacity factors, heat input rates and fuel type.

How emission credits will initially be allocated, and how the consumer strategic energy allocation will be structured, can have a major economic impact. Hence, it is the subject of significant debate between the electric industry, consumer and environmental advocates. Industry favors an allocation of allowances to generators, whereas the others prefer an auction or sale.

Environmental and consumer groups claim that generators will merely include the cost (or market value) of allowances in their offering price to the wholesale electricity market, regardless of how they obtain allowances, providing them with a windfall and raising the cost of electricity to consumers. However, it is not obvious which allocation method will result in the lowest cost to consumers of electricity. Generators have operating limitations in wholesale day-ahead and real-time electricity markets, such as minimum generation levels, minimum run times, minimum down times and requirements to use a minimum amount of fuel oil for reliability reasons. Some generators will be able to pass directly the cost of implementation on to ratepayers and will do so, while others are locked into long-term contracts and will have to absorb the cost of purchasing allowances on the open market, setting up offset projects, or installing pollution control devices.

Vermont has encouraged other states to follow its model, which puts a non-political body, the Public Service Commission, in charge of managing the CO2 allocation budget to maximize revenue by banking or selling credits, and requires that 100 percent of the proceeds go to benefit ratepayers. New York has indicated a similar commitment to auction its allowances and use the revenue for consumer benefit programs, including investments in renewable energy.

The revenue from an auction or sale of allowances arguably could be used to support energy efficiency, renewable energy, innovative clean-energy technologies or consumer rate rebates. However, allocating allowances through an auction approach poses different, but significant risks to electricity prices – and to generators, who simply must ensure that they are able to purchase sufficient allowances to permit their plants to operate. A single auction, for instance, creates an incentive for bilateral deals in the electricity marketplace. A series of auctions may create a more stable market, but it is still likely some facilities will not be able to bear and/or recoup additional costs and perhaps have to shut-down. High auction prices may result in higher customer costs than if allowances were allocated for free.

Another option is for states to allocate allowances to load-serving entities, rather than generators, and restrict the ability of such utilities to purchase power from outside the RGGI participating states. Such a move may help to combat leakage, which is the shifting of power from unregulated coal-based emission sources from non-RGGI states in to the region. However, the implications of such a move on energy prices and system reliability are not well understood. Additionally, any attempt to restrict the "carbon content" of electricity imports risks running afoul of the commerce clause and could be vulnerable to legal challenge.

Concerns about "leakage" have plagued the RGGI process. RGGI state utilities may face increased competition if their costs rise and their customers can purchase cheaper energy from states which are not part of RGGI. Importation of power from unregulated sources has the potential to counterbalance some or all of the in-region emission reductions, as well as to increase the economic impact of the RGGI program on RGGI state sources. Although the MOU establishes a commitment to monitor leakage, how it will be done is an open question.

Offset Provisions Have Proven Contentious

The absence of readily available CO2 control technologies means that RGGI regulated entities must switch fuels, buy allowances on the market, or invest in projects to "offset" or generate allowance credits for compliance. The structure of the offset provisions thus impacts allowance pricing, trading and the overall cost of the RGGI. If the offset provisions are overly complex or restrictive, as numerous industry, environmental and consumer advocates alike noted is the case under the draft model rule, higher allowance and energy prices may result, and it will be more difficult for generators to expand to meet a growth in power demand.

The draft model rule allows sources to use "offset allowances" to meet up to 3.3 percent of their overall emissions. Offsets occurring in RGGI participating states generate one allowance for every ton of emission reduction, and offsets occurring elsewhere in North America count on a one-for-two basis (which makes them half the value of offsets within RGGI's participating states). This limitation, which is estimated to cover approximately half of the projected average emissions reduction obligations of each source, means that a significant portion of emissions reductions must still occur at the regulated entity.

If the RGGI allowance price exceeds certain price triggers or thresholds, the use of offsets will be expanded. For instance, if the RGGI allowance price equals or exceeds $7.00/ton for 12 months, then up to 5 percent of a source's emissions can be covered with offsets, and offset projects located throughout North America will be credited on a one-for-one basis.

If the average allowance price exceeds $10.00/ton on a 12-month rolling average basis, then the RGGI compliance period can be extended by a year at a time, for a maximum three-year extension. If allowance prices are still above the $10 trigger price after two years of extension, regulated sources will be able to cover up to 20 percent of their reported emissions with offsets in the fourth, fifth and sixth years of the extended compliance period. They will also be able to use independently certified offsets from international trading programs to cover their emissions during years four through six of the extended compliance period.

The draft model rule places other limitations on the use of offsets. At present, there are only six categories of projects eligible for RGGI offset credits, although many have recommended expanding this list:

To qualify as an offset, the emissions reductions must be additional to and not otherwise occur from regulatory compliance obligations or economic incentives. Projects that would be developed in the absence of RGGI, such as those subsidized through system benefit charges or renewable portfolio standards (RPS), are therefore not eligible for both offset credits and the additional subsidy. Project sponsors must "pick a market" or incentive program, such as the RGGI carbon market or the RPS market, and cannot secure financing through both. The rationale is straightforward: the market outcomes are expected to accrue even in the absence of RGGI, and such programs have already been included in many states' climate and energy policy planning. However, projects which have co-funding can be better investments, and multiple revenue streams may be necessary for some projects to be financially viable.

These limitations on the use of offsets under the RGGI substantially complicate the contractual issues, financial and regulatory risks associated with developing offset projects. The regulatory additionality provisions, for instance, prevent allowances for pre-approved offset projects from being used after a change in law, regulation or order. This complicates the financing options for project sponsors who have to factor into their investment decision a risk analysis of whether they can rely on revenue streams beyond the initial certification period.

Unlike the Kyoto Protocol, which requires each project to be evaluated on a case-by-case basis, the RGGI draft model rule establishes specific and verifiable objective standards for each category of offset. To qualify as an offset, individual projects must meet these standards, which include: establishment of emission baselines, measurement of emission reductions, quantification, certification, and procedures for monitoring and verification of offset allowances. The geographic restrictions on receipt of credit for offset projects were developed, in part, because of the difficulty in verifying that these standards are being followed outside the RGGI participating states.

The RGGI offset provisions have received extensive criticism for serving no environmental purpose, creating uncertainty, quelling investment and creating barriers to emissions trading (by limiting the supply of projects and the geographic locations in which they can be developed). Since the RGGI addresses the global problem of climate change, many suggest that there is no environmental basis for geographic, categorical or other restrictions on use of offsets, as long as reliable monitoring and verification protocols are in place.

Conclusion: It is Too Soon to Gauge the Costs and Benefits of the RGGI

If the United States pursues a national climate policy, the RGGI states will be ahead of the curve in the implementation of emission reduction strategies. RGGI presents new opportunities for the development and improvement of renewable technologies, nuclear energy and carbon control devices and will likely stimulate new energy efficiency investments in the region.

However, until the final model rule is issued and the individual state-based implementation plans promulgated, it is difficult to predict the ultimate costs and benefits of the RGGI. Although the economic impact modeling done by the RGGI staff indicates that it is likely to have a negligible impact on the growth of the regional economy and small impacts at the household level and on retail electricity prices, it is not certain that this analysis is correct. The direct impact of the RGGI will be felt across a range of industries, and the magnitude of the impact cannot be determined at this time. Sources of emissions will face different costs of compliance depending on their age, type, efficiency and fuel source. Some plants may have to shut down because investment in emission reduction is not viable or financially attractive.

The project development and finance impact of the RGGI depends on a number of factors, including the price of allowances and offsets. According to some estimates, the RGGI emissions cap will likely result in limited demand for allowances and prices in the RGGI market are estimated to be less than $1/ton. If this is the case, the transaction costs involved in developing new offsets may make them uneconomical for compliance with RGGI. However if prices of allowances are high enough relative to the cost of development, and clear eligibility criteria have been established for approval of offset projects, opportunities should exist to use project finance structures to finance offset projects. Approved offset projects could potentially generate long-term and predictable revenue streams, making them cost-effective and profitable.

Regional, national and international attention is highly focused on climate change. According to a recent poll published in Time Magazine, 85 percent of Americans say global warming is probably happening, and an even larger percentage (88 percent) think it threatens future generations. The ultimate design of and state-based implementation of the RGGI bears a close watch by industries and individuals outside of the Northeast.

If you have any questions about this Client Alert, please contact  Kellie N. Ortega in our New Jersey office, Claudia M. O'Brien in our Washington, D.C. office or any of the following attorneys.

Brussels Andreas Weitbrecht +32-2-788-6000 Chicago Cary R. Perlman (312) 876-7700 Frankfurt Hans-Jürgen Lütt +49-69-6062-6000 Hamburg Jörg P. Soehring +49-40-41 40 30 Hong Kong Joseph A. Bevash +852-2522-7886 London Andrew C. Moyle +44-20-7710-1000 Los Angeles Gene A. Lucero Robert A. Wyman, Jr. (213) 485-1234

Milan David Miles +39 02-3046-2000 Moscow Anya Goldin +7-501-785-1234 Munich Jörg Kirchner +49 89 20 80 3 8000 New Jersey David J. McLean Kellie N. Ortega (973) 639-1234 New York David S. Langer (212) 906-1200 Northern Virginia Eric L. Bernthal (703) 456-1000 Orange County Michael J. Carroll (714) 540-1235 Paris Olivier Delattre +33-1-4062-2000

San Diego Joel H. Mack (619) 236-1234 San Francisco Karl S. Lytz (415) 391-0600 Shanghai Rowland Cheng +8621 6101-6000 Silicon Valley Ora T. Fisher (650) 328-4600 Singapore Mark A. Nelson +65-6536-1161 Tokyo Bernard E. Nelson +81-3-6212-7800 Washington, D.C. David J. Hayes Claudia M. O'Brien (202) 637-2200

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