Nine northeastern and mid-Atlantic states released an outline in late August of a regional “cap-and-trade” program to reduce carbon dioxide, or CO2, emissions from power plants.
This is the first effort by states to require mandatory CO2 reductions on a regional basis. Massachusetts and New Hampshire have already moved within their own borders to require CO2 reductions at specific coal-fired power plants.
The nine states announced a two-phase program thatwill cap CO2 emissions from power plants starting in 2009 at approximately 150 million tons a year. That is based on an average of the highest three years of emissions reached in the region during the period 2000 to 2004. The first
phase limit is a cap on emissions from 2009 through 2015, and the second phase limit will be 10% less than the limit during the first phase. The second phase limit will be in effect during the period 2015 to 2020. The affected power plants have generating capacities of 25 megawatts or more.
The initiative started with a proposal by New York Governor George Pataki in 2003 to address global warming on a state level since the Bush administration remains opposed to any action at the federal level. The nine states are working to achieve a consensus on the details of the program. It is expected to be memorialized in a memorandum of agreement among the states. The nine states are Connecticut, Delaware, Maine, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island and Vermont. Maryland, Pennsylvania, the District of Columbia, the eastern Canadian provinces and New Brunswick are participating as observers.” Under the plan, states will be allowed to allocate up to 75% of the available CO2 allowances to power plants directly. The signatory states will agree to set aside 20% of the allowances for public benefit purposes, including promotion of renewables and energy efficient projects and efforts to mitigate ratepayer impacts. States will also be required to set aside 5% of the allowances for a regional “strategic carbon fund” that will be used to encourage developers of new projects to achieve supplemental CO2 reductions and to sequester carbon beyond what is required by the cap. States will also have the discretion to create a CO2 allowance set-aside program for new sources.
The program is expected to allow the use of “offset credits” from qualified projects within the nine-state region, including from producing landfill gas, reforestation and certain energy efficiency projects. The nine states may also expand the use of offsets to include European Union greenhouse gas allowances that are traded to comply with the Kyoto protocol requirements, and offsets generated by Kyoto-approved “clean development mechanism” projects
in emerging market countries. The states are expected to place a cap on the number of offset credits that can be used for compliance purposes. One issue that will need to be addressed is how to account for potential emissions “leakage” by utilities agreeing to purchase electricity from generators outside of the nine states. Environmental groups charge that as much as 40% of the expected CO2 reductions might be undermined by “leakage” where utilities look outside the region to buy power. This just shifts CO2 emissions to other states. The nine states have decided to revisit in 2015 whether mitigation measures are needed to address the “leakage” issue.
The CO2 reduction plan is expected to be finalized before the end of this year. A more detailed implementation rule will follow. The nine states are then expected to seek approval of the plan from their legislatures. California, Oregon and Washington are also reportedly considering a similar CO2 cap-and-trade regional program in the Pacific Northwest.
In related news, a federal district court in New York rejected a lawsuit filed by eight states, New York City and several environmental groups against five power companies charging that their power plants emit large quantities of CO2. The defendants in the suit were American Electric Power, Southern Company, the Tennessee Valley Authority, Xcel Energy and Cinergy Corporation. The petitioners claim that the five utilities account for about 650 million tons of CO2 or about 25% of all CO2 emissions from US power plants. The companies own or operate 174 fossil-fuel fired power plants in 20 states.
The case was based on a seldom-used legal theory that CO2 emissions from the plants cause a “public nuisance.” The judge said the case would require the court to rule on a “political question” that is not an appropriate “case or controversy” for the courts but rather should be addressed by Congress. The petitioners are expected to appeal. Canada released proposed “offset system” rules in August as part of its effort to comply with its obligations under the Kyoto protocol to reduce greenhouse gas emissions. The draft rules explain how to create verified offset credits that can be sold to the Canadian Climate Fund or to other companies. Canada agreed in the Kyoto protocol to reduce greenhouse gas emissions by 6%, compared to 1990 emissions, by the period 2008 through 2012. The proposed rules give the following examples of projects that qualify for offset credits: demand-side management programs that reduce energy consumption, reforestation, landfill gas projects, agricultural carbon sequestration and renewable energy projects. The proposed offset credit rules are expected to be finalized by the end of 2005.
Congress is moving, in the wake of hurricanes Katrina and Rita and soaring gasoline prices, to pass legislation that would help expand gasoline refinery capacity in the United States and increase domestic oil and gas output. A bill reported to the full House by the House Energy and Commerce Committee in late September includes several controversial environmental provisions.
It would let state governors ask the US Department of Energy to oversee environmental permitting in their states for construction of new or expanded refineries. DOE would coordinate all permitting for siting, construction, expansion and operation of a refinery under the federal environmental laws, including the Clean Air Act, the Clean Water Act and the Safe Drinking Water Act, regardless of whether permits under these statutes are normally issued by state agencies. The bill also requires President Bush to designate at least three former military bases as locations for new
refineries. The bill would also consolidate permitting for oil pipelines under the Federal Energy Regulatory Commission.
While the main focus of the bill is oil and gas, the measure also would rewrite the rules for when permits are required to make upgrades to existing power plants under “new source review,” or NSR, procedures in the Clean Air Act. Section 106(b) of the bill would clarify that an upgrade is not considered a “modification” to a power plant for air permitting purposes unless it rises to the level of a modification for purposes of the “new source performance standards,” or NSPS, program. This is significant because it is much harder to trigger a “modification” under the NSPS
program. Under the NSPS program, a modification occurs when there is an increase in the hourly emission rate. In the new source review program, a modification is triggered when there is a significant increase in annual emissions at a plant compared to a baseline of the plant’s actual emissions during a consecutive two-year period within the previous five years. For example, modifications to a boiler that restore the unit to its original hourly emission rate would not trigger a modification under the NSPS program, but they would probably trigger a modification under the NSR program.
There is a split in the federal appeals courts on the issue of how significant an upgrade must be to be considered a “modification” under the new source review program. The US appeals court for the 4th circuit held in US v. Duke Energy Corp. in June that “modification” has the same meaning for purposes of both NSR and NSPS permits. However, the US appeals court for the District of Columbia circuit said in New York v. EPA nine days later that the Environmental Protection Agency is free to adopt a stricter view of what is a “modification” for NSR permits.
The House bill also would codify a key portion of a controversial rule the Bush administration proposed in 2003 on the types of “routine maintenance, repair, and replacement” of equipment that can be completed at existing power plants without the need for a NSR permit. The Bush administration has been barred by a US appeals court from implementing its rule until the court rules on the merits. The House bill would write into the law a bright-line test that spares power plant owners from having to get permits to replace equipment where three conditions are met. First, the owner must be replacing an existing component of a unit (for example, a boiler or turbine) with identical components or components that serve the same purpose. Second, the fixed capital cost of the replaced component and any other costs associated with the replacement activity must not exceed 20% of the current replacement value of the unit. Third, the equipment replacement must not alter the basic design of the unit or cause it to exceed any emission limitations.
The House bill would also authorize the US Environmental Protection Agency to extend the headlines for areas that are downwind from “nonattainment areas” to comply with the national ambient air quality standards for ozone. This provision could have the effect of delaying currently required reductions in NOx and VOC emissions in certain downwind nonattainment areas.
The refineries and oil pipeline bill remains controversial. It is expected to pass the House, but the outlook in the Senate is unclear. The best guess, as the NewsWire went to press, is that the controversial environmental provisions will end up being dropped.
Meanwhile, the Environmental Protection Agency is reportedly preparing to embrace the decision in US v. Duke Energy Corp. that “modification” has the same meaning for both NSR and NSPS permits without waiting for legislation from Congress. It would be a reversal of a longstanding EPA policy. If EPA goes forward with a proposed rule, a period for public comment can be expected later this year.
The US Senate failed narrowly in September to overrule the “clean air mercury rule” that the environmental Protection Agency adopted in May 2005. The clean air mercury rule uses a two-phased “cap-and-trade” approach to reduce mercury emissions from existing coal-fired power plants instead of the “command-and-control” regime that would typically have been imposed under section 112 of the Clean Air Act. The vote was 47 to 51. It marked one of the few times that the Congressional Review Act of 1995 procedures were used to try to overturn an EPA rule. That statute lets Congress overturn an agency regulation by a majority vote.
Meanwhile, the clean air mercury rule is being challenged in a federal appeals court in a case brought by 11 states and several environmental groups. They want the government to adopt strict technology-based emission standards for mercury rather than leave power plant owners with the flexibility either to reduce mercury emissions or buy allowances from others who have done so. The petitioners claim that simply ordering reductions would probably lead to as much as a 90% reduction in mercury emissions at most coalfired plants. Under the clean air mercury rule that
the Bush administration issued, the first phase of the mercury reductions commences in 2010 with a 38-ton cap followed by a reduction to a 15-ton cap in the second phase starting in 2018. Approximately 48 tons a year of mercury are emitted by US power plants today.
The appeals court for the District of Columbia circuit declined to “stay” implementation of the clean air mercury rule while it hears the case. In order to grant a stay, the court would have had to conclude that the petitioners are likely to win the case on the merits and there is a likelihood of irreparable harm if the rule is not stayed. Since the first phase of the mercury reductions will not occur until 2010, the petitioners could not show the risk of irreparable harm if the court waits to hear the merits of the lawsuit. A decision on the merits is not expected until late 2006 or early 2007.
In related news, the Environmental Quality Board in Pennsylvania agreed in August to a request by a coalition of environmental and public interest groups to impose mercury emission reduction requirements on coal-fired power plants that go beyond the federal clean air mercury rule. The Board’s action gives the Pennsylvania Department of Environmental Protection the authority to require 39 coal-fired power plants in the state to reduce mercury. The petitioners asked for mandatory reductions of at least 90% or a limit of 3.00 mg/MW-hr. Pennsylvania is expected to adopt a standard by November 2006.
Toxics Release Inventory
The Environmental Protection Agency took steps in September to streamline reporting requirements under the “toxics release inventory program.”The “Emergency Planning and Community Right to Know Act” requires factories to make annual reports on the location and quantities of chemicals stored on-site to state and local agencies in order to help communities better prepare for chemical spills and other emergencies. Reports are filed with EPA each year for nearly 24,000 facilities and 650 chemicals. Most information is submitted on a five-page “Form R.” EPA is proposing to let some companies use a shorter “Form A.”
Under the proposal, Form A could now be used for persistent, bioaccumulative and toxic, or PBT, chemicals, except for dioxin and dioxin compounds, provided the facility manufactures, processes or otherwise uses no more than one million pounds of the chemical, there are no releases of the PBT chemical to the environment, and the plant does not manage more than 500 pounds of waste toxic chemicals at the facility by treatment, energy recovery or recycling. PBT chemicals include mercury, lead and other toxics. Current rules bar companies from using Form A to report PBT chemicals.
EPA also proposes that plants with non-PBT chemicals would be able to use Form A for a toxic chemical if the facility manufactures, processes or otherwise uses no more than one million pounds of a chemical and the facility manages no more than 5,000 pounds of waste toxic chemicals at the plant by treatment, energy recovery, recycling, disposal or other releases to the environment. The current threshold for non-PBT chemicals is a total annual reportable amount of 500 pounds that are treated, recovered, recycled, disposed or released. Comments on use of the new forms are due by December 5, 2005. In a separate but related action, the Environmental
Protection Agency notified Congress in early October that it plans to let power plants and other industrial plants report every other year — rather than annually — under the toxics release inventory program. EPA must wait 12 months after notifying Congress before it can initiate a rulemaking process to change the reporting frequency.
The Environmental Protection Agency explained in September what states must do to reduce fine particulate matter, or PM2.5, to meet the national ambient air quality standard for PM2.5. The PM2.5 standard was imposed in July 1997, and litigation challenging the rule was resolved in 2002. The affected states and the District of Columbia have until April 2008 to submit their plans to the federal government for approval.
Earlier this year, EPA identified 224 counties in 20 states and the District of Columbia that fail to meet the PM2.5, national ambient air quality standard. The nonattainment areas are mainly in the midwest, the mid-Atlantic states, the southeast, and California, with Ohio (31 areas), Georgia (28 areas), Pennsylvania (23 areas) and Indiana (19 areas) having the highest number of PM2.5 nonattainment areas. States must meet the PM2.5 standard by 2010; however, states may request an extension of up to five years for areas where there are more severe PM 2.5 problems and emission control measures are not feasible or available.
Particulates are particles found in air, including dust, dirt, soot, smoke and liquid droplets. The primary sources of fine particulates are motor vehicles, power plants, wood-burning stoves and forest fires. The proposed PM2.5 implementation would authorize states to regulate PM2.5 direct emissions, SO2, NOx, VOCs and ammonia. Fine particulates are believed to pose a health risk, particularly to older individuals and children, because their small size (less than 1/30th the size of an average human hair) lets them lodge deeply in the lungs.
The proposed rule contains some controversial exemptions that may trigger a lawsuit from environmental groups. In particular, the proposed rule would exempt power plants subject to the clean air interstate rule from complying with “reasonably available control technology” standards to reduce fine particulate pollutants. These standards require a minimum required level of emission reductions, but are not as stringent as the technology-based standards imposed on new and modified sources under the new source review program. The proposal would also set the “major source” threshold for new source review at 100 tons a year of PM2.5 for nonattainment areas as compared to the PM10 threshold of 70 tons a year for areas classified as serious PM10 nonattainment areas. The PM10 standard applies to larger “coarse” particulates.
The EPA proposal will be subject to a 60 day public comment period after the proposal is published in the Federal Register.
The PM2.5 implementation rules may require existing power plants and factories to install costly new pollution control equipment or to upgrade existing controls to reduce fine particulate emissions.
Industry groups representing utilities and coal producers are challenging the “clean air visibility rule” in the US court of appeals. The rule requires states to identify older power plants and factories that were built between 1962 and 1977 and have the potential to emit more than 250 tons a year of NOx, SO2, PM2.5 or volatile organic compounds that affect visibility in so-called lass I areas, such as national parks or federal wilderness areas. The rule requires these facilities to install “best available retrofit technology.”The industry groups that are in court argue that the
clean air visibility rule runs afoul of prior court decisions on how states are supposed to identify ho must comply. EPA adopted the rule that is now under challenge in July.
EPA published a final rule in late August exempting Georgia from complying with the “NOx SIP all” rule. The NOx SIP call rule imposes ozone season (May 1 to September 30) NOx emission reduction requirements on sources in 20 states east of the Mississippi River. Georgia was originally required to comply with the NOx SIP call rule starting on May 1, 2007. However, EPA has now concluded that emission sources in Georgia do not significantly affect ozone attainment in downwind states. North Carolina is objecting to the decision to exempt Georgia and is expected to file a lawsuit.
The New Jersey Board of Public Utilities voted to increase the amount of electricity that utilities in the state must supply from “class I” renewable resources, including solar, wind, landfill gas, geothermal, wave and tidal and sustainable biomass, from 4% by 2008 to 20% by 2020. The proposal would require that 2% of the amount come from solar energy.
Finally, the US House of Representatives passed significant revisions to the Endangered Species
Act in September. It authorizes conservation grants and financial awards to private property owners to compensate for the loss of use of their property where the Department of Interior has
concluded that there would be a “taking” of the property under the Endangered Species Act. The measure also establishes new financial incentives for private landowners who agree to enter into voluntary species recovery agreements and species conservation contract agreements to protect or restore habitat for covered species. The Senate has yet to act.