The thermometer is rising as coal-fired plants cope with the uncertainties of mercury regulation. Here’s a diagnosis and a suggested cure.
By Kenneth Reich, WolfBlock
In light of the new United States Environmental Protection Agency’s (EPA) mercury emissions rule and the advent of even more stringent state rules, planning for new coal-fired power plants or existing plant expansions has become more complex and uncertain. This article discusses the new playing field created by mercury regulation and provides some suggestions for coping with the uncertainty.
The EPA issued its final Clean Air Mercury Rule (CAMR) on March 15, 2005 (70 Fed. Reg. 28606 – May 18, 2005). CAMR creates a cap-and-trade program in which nationwide mercury emissions are capped at 38 tons per year (tpy) by 2010 and must be reduced to 15 tpy by 2018. The EPA believes that significant mercury emissions reductions will be achieved as a co-benefit of air pollution controls designed for SO2 and NOX that must be installed to comply with EPA’s Clean Air Interstate Rule (CAIR). CAMR establishes a mercury emissions cap for each state based on the total heat input of each state’s existing power plants, adjusted to reflect the rank of coal combusted by each plant.
Coal-fired facilities must demonstrate compliance with the emissions standard by holding one allowance for each ounce of mercury emitted in any given year and by monitoring mercury emissions with continuous emission monitoring systems (CEMS) by January 1, 2009, with some flexibility to use other monitoring methods. CAMR also sets a new source performance standard for new plants, defined as plants on which construction, modification or reconstruction began after January 30, 2004.
CAMR, along with a companion rule, was challenged by numerous states, environmental groups and others in the D.C. Circuit Court of Appeals. The companion rule (Power Plant Exemption Rule), issued March 15, 2005, held it was not appropriate or necessary to regulate hazardous air emissions from coal-fired or oil-fired electric utility steam generating units (70 Fed. Reg. 15994 – March 29, 2005). This rule freed coal-fired plants from Maximum Available Control Technology (MACT) requirements for hazardous air pollutants, including mercury, and opened the door for CAMR.
The EPA responded to the challenges by convening reconsideration proceedings on specific issues in CAMR and the Power Plant Exemption Rule. The EPA concluded those reconsideration proceedings in May 2006 and decided not to make any major changes to the two rules. In light of EPA’s reconsideration, the judicial proceedings have started up again, but it is unlikely that those challenges will be resolved before another year, if not longer.
States Are Taking Charge
As a result of widespread dissatisfaction among state agencies and environmentalists with CAMR, the action has shifted to the states. CAMR imposes a November 2006 deadline on states for the submission of a final state rule that meets CAMR mercury reduction goals, so the states are actively promulgating mercury emission rules to meet this deadline. The general trend is for state rules to be more stringent than CAMR. In November 2005, the State and Territorial Air Pollution Program Administrators and Association of Local Air Pollution Control Officers (STAPPA/ALAPCO) promulgated its own more stringent model mercury rule, which would reduce mercury emissions from power plants by 90 to 95 percent by 2012.
Many states are also considering, or have already passed, rules more stringent than CAMR, requiring up to 90 percent mercury capture by coal-fired power plants in a shorter timeframe than CAMR allows. Many of these same states are also considering a ban on interstate trading of federal mercury allowances, which is at the heart of CAMR. At the time of this writing (August 2006), Connecticut, Maryland, Massachusetts, Minnesota, New Hampshire, New Jersey and Wisconsin had mercury rules in place that were more stringent than CAMR (although Wisconsin was modifying its rule to meet the requirements of CAMR). Numerous other states have proposed rules or legislation that adopt or are more stringent than CAMR. Table 1 provides a summary of state mercury rules as of August 2006.
Several states had mercury emission reduction laws or rules in place before CAMR was promulgated. These laws or regulations therefore do not discuss or allow the trading of mercury allowances. In 2003, Connecticut became the first state to require mercury emissions reductions from power plants by a certain date. Connecticut requires coal-fired power plants to either achieve an emissions standard of 0.6 pounds per trillion Btu (tBtu) or a 90 percent efficiency rate in technology installed to control mercury emissions. The limits go into effect after July 1, 2008. The law does give the state and industry some flexibility; if a plant installs and maintains the best available control technology and still fails to meet the new emissions rate, the state must provide an alternative increased emissions rate. However, after July 1, 2012, the state must review the mercury emission limits applicable to all sources in the state and may impose more stringent limits on the sources.
In 2004, three states adopted mercury rules. Massachusetts adopted a mercury emissions rule that reduces emissions in two phases. In the first phase, power plants must capture 85 percent of the mercury emissions, or emit no more than 0.0075 pounds per net gigawatt-hour (GWh) of electricity produced, by January 1, 2008. In the second phase, plants must capture 95 percent, or emit no more than 0.0025 pounds per net GWh produced, by October 1, 2012. New Jersey requires coal-fired power plants to reduce mercury emissions by 90 percent by the end of 2007. However, the plants can extend the compliance date to 2012 if they also make certain reductions in emissions of sulfur dioxide, nitrogen oxides and particulates. Wisconsin requires coal-fired power plants to reduce mercury emissions by 40 percent in 2010 and 75 percent by 2015, and sets a goal of 80 percent reduction by 2018.
Maryland, Minnesota and New Hampshire passed mercury emission laws after CAMR was promulgated that are more stringent than CAMR. These states require an 80 to 90 percent reduction of mercury emissions and do not allow any trading of mercury allowances. However, at least Minnesota and New Hampshire provide utilities with some flexibility or incentives. Minnesota allows plants to file for time extensions to comply, if needed, and New Hampshire provides economic incentives for earlier installation and greater emission reductions. Virginia also adopted legislation that regulates generators whose combined mercury emissions from all units in Virginia exceeded 200 pounds in 1999. These units are prohibited from purchasing allowances to meet emissions limits, but may bank or sell excess allowances. The largest generator (over 900 pounds of mercury emissions in 1999) must meet the Phase 2 CAMR emission limits by 2015, three years earlier than required by CAMR.
Other states are considering similar laws or rules.
For example, in Montana, the Board of Environmental Review is considering a mercury emissions rule for coal-fired power plants that would set a limit for new and existing plants equal to about 90 percent or more reduction beginning January 1, 2010, with flexibility to obtain an alternative emission limit which would expire in 2015 unless extended through 2018. Facilities that emit below their allocation would be able to sell the excess allowances and facilities with an alternative emissions limit could buy credits up to that limit as necessary. Unlike CAMR, the proposed Montana rule treats new sources and existing sources equitably and allocates a proportionate amount of mercury allowances to new sources.
The rule developed by the Pennsylvania Department of Environmental Protection (PA DEP) through a multi-stakeholder process proposes to achieve at least 90 percent mercury reduction by 2015, requires all facilities to meet a mercury cap and prohibits intrastate and interstate mercury emissions trading. In April 2006, the Pennsylvania legislature proposed bipartisan bills in both the Senate and House that would prohibit the proposed DEP rule and adopt CAMR, including an interstate mercury allowance trading scheme. As of August 2006, the DEP rule was moving through formal notice and comment, the Senate had passed a bill that would block the DEP rule and adopt CAMR and the House had failed to vote on the bill before recessing for the summer, creating even more uncertainty in Pennsylvania.
Faced with the uncertainties of the challenges to CAMR, the increasing number of state rules and the impending 2008 presidential elections, developers of coal-fired power plants – regardless of whether they are expansions or new projects – must consider a number of issues.
Mercury is the toxin du jour among environmental organizations. In addition, public health groups, women’s health groups, hunting and angling organizations are supporting mercury emission rules that are more stringent than CAMR. Any proposal to build a coal-fired power plant will likely draw fierce opposition from local and national environmental organizations. This concern will lead to pressure on state regulators to impose stringent mercury emission limits, or in some cases, to ban construction. For example, on April 7, 2006, then Idaho governor, Dirk Kempthorne, signed into law House Bill 791, which establishes a two-year moratorium on the issuance of permits, licenses and variances for the construction of coal-fired power plants in Idaho, unless the plants are owned or constructed by a public utility, cooperative or municipality. This legislation was drafted partially in response to a proposed 600 MW coal-fired power plant that was to be built in Jerome County by Sempra Energy. As a result of HB 791, Sempra cancelled plans to build the plant. The potential effects of the public response to coal-fired power plants and potential mercury emissions should not be ignored.
CAMR proposes that states adopt an optional interstate trading system for mercury allowances. The interstate trading program may mitigate the mercury reduction requirements imposed by both CAMR and by the states by allowing sources to trade for extra allowances if control options are not feasible. However, numerous states, such as Montana and Pennsylvania, are proposing to either restrict or ban interstate trading of allowances.
Developers of coal-fired power plants should look at the potential advantages of capitalizing on the co-benefits of pollution control equipment designed for SO2 and NOx, such as selected catalytic reduction and improved bag houses. These types of pollution control equipment have been shown to remove mercury in some cases, and the EPA and some states (for example, Pennsylvania) believe that sources can meet the mercury emission standards without taking any more action than is necessary to meet the federal air quality standards of CAIR for SO2 and NOX. However, each individual source needs to determine for itself if those controls alone will allow it to achieve the degree of reductions that are being considered at the state level.
The price of oil and natural gas is high and it is not expected to get lower in the near future. Developers of coal-fired plants should examine the trends in the price of energy when deciding whether it is cost-effective to proceed with coal, even accounting for the cost of mercury control.
Project developers must consider types of coal supplies. For example, typical western sub-bituminous coal generally contains less mercury than typical bituminous coal from eastern states. However, eastern bituminous coal generally contains a higher level of chlorine, which enhances the removal efficiency of mercury control technology.
Project developers should also examine who will pay for the cost of mercury controls. Can the costs be passed on to customers? Mercury control is a very hot market area. In response to demand, cheaper and better mercury control technologies are likely to be developed in response to EPA and state efforts to reduce mercury emissions.
Here are some suggestions for the developers of expanded or new coal-fired power plants.
Consider alternatives to plant expansion, including demand-side management measures and use of renewable sources of energy (particularly wind). Most states now require a certain percentage of a power utility’s portfolio to be from renewable sources. Many funding options are also available for renewable sources through state and federal grant, loan or tax credit programs. For example, the Energy Policy Act of 2005 (Public Law 109-58) expanded the tax credit program for wind power development.
Consider new capacity options including renewables. However, remember that baseload requires a constant, dependable source. Renewable energy sources like wind are not considered a reliable source of baseload power in most areas of the country because the wind blows intermittently. Compare the cost of natural gas plants, including relatively efficient, but more expensive and currently less reliable, integrated gasification combined cycle (IGCC) technology, to the cost of coal-fired plants, adding in the extra costs of a coal-fired plant such as mercury and particulate controls.
Nuclear energy is another possible alternative that is becoming more attractive to utilities because nuclear plants do not emit any mercury, SO2, NOX or carbon dioxide (CO2), the latter of which may be regulated sooner rather than later. However, the potential environmental benefits from operating a nuclear plant need to be balanced with high capital costs, complex and uncertain permitting procedures and concerns about radioactive waste disposal and reactor safety and security.
If you select a new technology, make sure it can be financed. Commercial lenders are presently reluctant to finance IGCC facilities because of uncertainties about reliability.
Also, consider the potential greenhouse gas emissions from a coal-fired plant and the prospect of future regulation in the form of CO2 emission controls or a carbon tax. Some states have already begun to impose such regulations. Seven northeastern states (with several more potentially joining) have formed the Regional Greenhouse Gas Initiative (RGGI) to regulate CO2 in participating states. The RGGI calls for a cap on regional CO2 emissions set at approximately 1990 emission levels from 2009 through 2014 and a further reduction by 10 percent by 2018. Companies must reduce emissions below their individual caps or purchase allowances through a cap-and-trade program. In addition, California recently entered into an agreement with the United Kingdom to share information regarding the reduction of carbon dioxide emissions.
Finally, be sure to factor in the cost of the litigation and negative publicity that will likely follow any proposal to build a new coal-fired plant.
If you decide to build a new coal plant, speak with boilermakers and mercury control vendors to see what guarantees they are willing to provide on mercury control before talking with the regulators about permit limits for mercury emissions. Remember that you must meet your permit limits regardless of what guarantees the vendor agrees to, or you will face enforcement.
The accuracy and reliability of mercury CEMS for different flue gas conditions and day-to-day field use is not clearly established at this time. Talk with mercury control vendors and independent electric power research groups to determine which monitoring method allowed by CAMR (or by another state rule) will work best for the specific plant you are proposing to build and the flue gas conditions that are predicted to be present at the plant.
Actively participate in the state discussions on the implementation of the state mercury rule and the allocation of the EPA’s state mercury budget allotments. CAMR provides a budget of mercury allowances to each state but leaves the decision solely to the state to determine how to distribute mercury allowances to new or modified sources and whether to allow trading of allowances. A state could make it prohibitively expensive for new coal-fired sources by not reserving allowances for new sources and simultaneously banning interstate (and intrastate) trading.
Be proactive with potential plant opponents, and be open and transparent about your planned project. As a best-case scenario, you may be able to work out certain issues with the opposition, avoiding litigation. As a worst-case scenario, you will learn what issues your opponents are most concerned with and can try to address their concerns and objections through planning and design.
Given the uncertainties with the state of mercury emission regulations at both the federal and state levels, there is no easy diagnosis for dealing with the mercury issue. Both proposed and existing sources will be affected by the new regulations. By getting involved in the rulemaking process, carefully weighing alternative fuel sources and control technologies and dealing openly and transparently with coal-fired plant opponents from the start, you can help minimize your risk in this sea of uncertainty.
Author: Kenneth Reich is a Boston-based partner in the law firm of WolfBlock and practices in the area of environmental and energy law and litigation. He represents a client who is currently developing a coal-fired plant. He acknowledges the valuable assistance of Phillip R. Bower, an associate of the firm, in preparing this article.