Environmental Update; California Greenhouse Gas Measures
The Global Warming Solutions Act, signed by California Governor Arnold Schwarzenegger on September 26, will regulate all but de minimis stationary sources of greenhouse gas emissions, but will not reach mobile source emissions.
It requires the California Air Resources Board - called “CARB” - to write regulations that would reduce carbon emissions to 1990 levels by the year 2020. This would amount to a 25% reduction in greenhouse gas emissions. By contrast, the Kyoto protocol that the Bush administration said would impose too great an economic cost on the United States would have committed the US to a 7% reduction in greenhouse gas emissions from 1990 levels by the year 2012.
The new law provides a framework for emissions reductions through a combination of measures: installing maximum technologically-feasible pollution control equipment, greenhouse gas emission caps and possible trading of credits or allowances. Any trading program has been left to CARB to develop and would presumably involve trading along the lines of that currently employed by the European Union. Credits or allowances authorizing the holder to emit a certain quantity of CO2 or its equivalent would be available for purchase in the market. The idea is to allow companies the option of continuing to emit CO2, but to cover the emissions by purchasing credits from other companies that have freed up credits for sale by reducing their emissions.
Opponents of the California legislation argue that the new law will impose a severe cost on the state’s economy with limited environmental benefit in the absence of a broader national strategy. Although California is a large state, it may not have a large enough economic base upon which an efficient trading program could be developed. Even the European Union trading scheme has encountered significant difficulties in properly allocating emissions credits, despite its large scale, and there have been large swings in credit prices.
The outline of the California program should take shape fairly soon. There is a mind-numbing series of deadlines. CARB has until June 30, 2007 to publish a list of early action greenhouse gas emission reduction measures that can be implemented prior to January 1, 2012. The agency then has until January 1, 2010 to adopt regulations implementing this list of early action greenhouse gas emission reduction measures. Regulations for greenhouse gas reduction methods must also be enforceable by January 1, 2010.
CARB is supposed to announce by January 1, 2008 what the statewide greenhouse gas emissions level was in 1990 and to set a statewide cap on greenhouse gas emissions beginning in 2012 for significant sources that will have to start ratcheting down their emissions to meet the 2020 goal. By January 1, 2009, CARB must approve a scoping plan that achieves the maximum technologically-feasible and cost-effective reductions in greenhouse gas emissions from sources or categories of sources by 2020.
By January 1, 2011, CARB must adopt greenhouse gas emission limits and emission reduction measures to achieve the maximum technologically-feasible and cost-effective reductions in statewide greenhouse gas emissions to become operative January 1, 2012. California’s governor retains the power to adjust deadlines under certain circumstances, including the threat of significant economic harm.
Governor Schwarzenegger is looking for ways to address concerns about California’s capacity to establish an efficient greenhouse gas trading system by connecting the new state program with other large existing programs, including trading programs in the northeastern US and the European Union. On October 17, he signed an executive order directing CARB to explore ways for California to join both a “regional greenhouse gas initiative” - called RGGI - in New England and the EU trading scheme.
RGGI is a regional initiative to reduce greenhouse gas emissions. It was initially among seven states, but has now expanded to eight. The original seven were Connecticut, Delaware, Maine, New Hampshire, New Jersey, New York and Vermont. Maryland will join by June 2007. Under RGGI, states will use a regional cap-and-trade system to limit CO2 emissions. Each ton of CO2 emissions will be worth one tradable allowance. Unlike the new law in California, which regulates greenhouse gases from a wide variety of stationary sources, RGGI is limited to emissions from power plants.
Coordinating the two programs will be challenging, although there should be time to work out the details. The deadline for states to implement RGGI is 2009 while California has set a deadline for itself of 2011.
One nagging problem facing RGGI remains “leakage.” Leakage occurs if emissions increase in neighboring states as reductions in RGGI states push the power industry to generate electricity elsewhere for export into the RGGI region.
California addressed the issue in its new legislation. The state is imposing new standards on contracts that California utilities sign to buy electricity from independent generators or to invest in power projects. The utilities will not be able to enter into any new long-term financial commitments unless any baseload generator complies with a greenhouse gas emission performance standard. A “long-term financial commitment” is “either a new ownership investment in baseload generation or a new or renewed contract with a term of five or more years, which includes procurement of baseload generation.” In turn, “baseload generation” means “electricity generation from a power plant that is designed and intended to provide electricity at an annualized capacity factor of at least 60 percent.”
It remains to be seen whether anyone will try to challenge the new California actions on grounds that they violate the US constitution. The commerce and supremacy clauses limit the ability of states to take actions that impede interstate commerce. In the past, courts have restricted state and local environmental programs that attempted to protect out-of-state sources from exploiting the economic disadvantages caused by heightened environmental requirements. Examples of state programs that were found to impede interstate commerce include efforts to require businesses to use local landfills rather than ship waste out of state.
Renewable Fuel Standards
The US Environmental Protection Agency proposed rules in late September for implementing a new federal renewable fuels program. The rules set standards for the average percentage of renewable fuel content in new motor vehicle fuels to be produced during 2007. When final, the rules would replace an interim program that was established by the Energy Policy Act of 2005.
The draft rules only apply to the 48 contiguous US states, although Hawaii and Alaska may opt into the program. EPA is required by law to increase the overall volume of renewable fuels produced each year from four billion gallons in 2006 to 7.5 billion gallons in 2012. To reach these goals, a standard will be published each November 30 for the following year showing the amount of renewable fuel that each obligated party must use as a percentage of gasoline sold. Because full rulemaking could not be completed for 2006, a default standard of 2.78% applies in 2006. This default standard will be treated as a collective obligation that applies to the pool of all gasoline sold to
consumers. There are no provisions for credit generation or trading for the 2006 year. Also, because EPA will not be able to finalize the new rules by November 30 this year, it has chosen a fairly unaggressive standard of 3.71% for calendar year 2007.
Parties potentially subject to the new standard — called “obligated parties” — include refiners, importers and blenders (other than oxygenate blenders), but exclude small refineries and small refiners. To determine his or her individual obligation, an obligated party multiplies the percentage standard for the year by his or her annual gasoline production volume. This result is the volume of renewable fuel that must be blended into gasoline sold for use in the United States, with credit for certain renewable fuels that are not blended into gasoline. Renewable fuels include cellulosic ethanol and waste-derived ethanol. Renewable fuels also include biodiesel and motor vehicle fuels that are produced from biomass. Motor vehicle fuels using a feedstock of natural gas are included if the natural gas came from a biogas source such as a landfill, sewage waste treatment plant, feedlot, or source of decaying organic matter.
It does not matter whether the renewable fuel is blended with gasoline or used neat as ethanol, methanol and natural gas. However, fuels must be designated for use in a motor vehicle, including off-road vehicles, to count against the new standard. Fuels that are designated for any other use, such as fuel oil for boilers and heaters, will not qualify.
Compliance will be tracked with renewable identification numbers called “RINs.” EPA is proposing to assign every gallon of renewable fuel produced or imported into the United States a RIN, or a block of RINs in the case of a batch of fuel. As renewable fuel travels though a distribution system, the RIN rides along on product transfer documents. The RIN can be separated from the renewable fuel when an obligated party purchases the renewable fuel or the fuel is blended into a vehicle fuel. At this point, the RIN could be used for compliance, banked or traded. Different fuels would have different values based upon their equivalence values. Equivalence values are based on the energy content of the fuel compared to ethanol. For example, corn-based ethanol would have an equivalence value 1.0, while cellulosic ethanol would have a value of 2.5.
Because EPA recognizes that biofuel production can contribute to pollution if appropriate practices are not followed, EPA is also considering voluntary labeling in an effort to minimize the potential environmental effects of relying more on renewable fuels. One suggested option is to attach a designation to the RIN. For example, fuel producers using best practices would have the option of adding a “G” (for green) to the RIN indicating that the fuel is environmentally friendly.
Under the proposed rules, RINs would be valid up to 12 months after they are generated. If a fuel producer has collected fewer RINs in a year than he needs to comply, then the deficit could be made up the next year. However a cap is proposed so that no more than 20% of the current year obligation may be satisfied using RINs from the previous year. Deficit carryovers would not be allowed two years in succession. Under the proposed rule, at most, deficits could occur every other year.
Comments on the proposed rules must be received by November 12.
Environmental groups have had mixed results in their efforts to use Clean Air Act permit requirements to force power companies to use integrated-gasification combined- cycle technology for new coal-fired power plants. IGCC is a process where coal is turned into gas before the gas is combusted to produce electricity.
Led by the Sierra Club, the groups have been trying to force states and the Environmental Protection Agency to require developers of coal-fired power plants applying for air permits to show they considered the use of IGCC as an alternative to traditional emissions control systems. The Clean Air Act requires that major new sources of air pollution employ the best available control technology - called “BACT” - for controlling emissions. Last year, EPA said in a letter that developers of new coal-fired power plants do not have to consider IGCC as a form of BACT. Environmental groups sued EPA in federal court, arguing that this was essentially a new regulation illegally promulgated in the form of a letter.
On October 12, the parties filed a preliminary settlement with the US appeals court in the District of Columbia. Under the settlement terms, which will be held open for public comment, the agency letter is not considered a “final agency action” and “creates no rights, duties, obligations, nor any other legally binding effects on EPA, the states, tribes, any other regulated entity or any person.” While this settlement, if approved, disposes of the current litigation, US states now can no longer rely on the letter to dispose of IGCC issues. States must now decide whether to encourage the use of IGCC in their permitting processes.
Environmental groups have had less success in their efforts to challenge individual air permits for not applying IGCC. In August, the EPA environmental appeals board ruled in favor of a permit approving a new 1,500-mw coal-fired power plant in Illinois and a similar ruling was rendered earlier this year in a state administrative appeal of a Kentucky air permit. Although coal gasification was mentioned in another state-level decision in August ruling against a Texas air permit, the Texas administrative law judge appeared primarily concerned with the ability of the 1,500-mw coal plant to comply with the limits specified in its application.
In its ruling regarding the Illinois plant, the appeals board concluded that emissions of NOx and SO2 from IGCC are equivalent to emissions in other modern coal-burning plants, but IGCC is much more costly. The Clean Air Act requires that cost be considered as a factor in BACT determinations.
Separately, an important technical change took effect to the Superfund liability defense for “innocent purchasers” of what turn out to be contaminated properties. Superfund exempts bona fide purchasers from liability for cleaning up a site that was already polluted when it was purchased. To establish the requisite level of “innocence” for such a defense, a person must perform an investigation that qualifies as an appropriate inquiry under EPA regulations. That means researching the past and current uses of the property. Until November 1, the EPA had relied upon a six-year old standard developed by the independent standards organization called ASTM. An appropriate inquiry meant doing what is required by ASTM standard E 1527-00. Now EPA has adopted the newer ASTM standard E 1527-05 in place of its older version.
ASTM E 1527-05 is a more demanding standard. Purchasers will have to gather more information in the future. For example, interviews with neighboring or nearby property owners of abandoned properties are now mandatory parts of the phase I site assessment process.
The new standards will also have an immediate effect on private sector transactions. ASTM 1527-05 is now being adopted for phase I site assessments that are a staple of financing and M&A transactions. For pending transactions, older site assessments complying with the former standard may have to be re-performed or expanded to include the newly-required information.
Finally, the International Finance Corporation issued seven new environmental, health and safety guidelines for public comment in early November. These guidelines are important not only because the IFC uses them in its lending decisions, but also because they are widely employed by other lenders and investors across the globe. The new guidelines address environmental design and performance standards for seven industry sectors, including airports, gas distribution systems, railways, ports, harbors and terminals. The new guidelines were posted by the IFC on November 6 and will be available for comment until January 15, 2007. They are the third installment of 62 new IFC environmental guidelines. Twenty five have already been published. Prior guidelines included rules for wind energy and geothermal power projects. The widely-used thermal power guidelines have not yet been published formally. In addition to the industry sector guidelines, the IFC has also published a general environmental, health and safety guideline that remains open for public comment until December 15.
— contributed by Andrew Giaccia and Sue Cowell, in Washington