Utility customers depend on and expect reliable, affordable electricity for virtually every aspect of their lives. At the same time, electricity producers in the United States are faced with finding cost-effective methods to meet ever-increasing demand and more stringent environmental regulations.
Though it’s not a new trend, the frequency with which new regulatory air quality initiatives are being based on the cumulative environmental impact of many sources from a broad geographic area is increasing. The market-based mechanisms of the Clean Air Act’s Title IV Acid Rain requirements have been successful. As a result, today’s regulatory programs are relying on nondescript emission reduction goals in the form of emissions trading programs to meet quickly changing environmental requirements.
Emissions trading programs designed to accomplish specific environmental goals have several advantages. In theory, an emissions trading program provides for the least-cost solution to a very complex problem. Facilities are not mandated to meet specific emissions reduction goals or emissions standards on a source-by-source basis. Instead, businesses are expected to collectively meet a groupwide emissions milestone.
The theory is simple: Install emission controls on the units that will yield the lowest dollars per ton emission reductions and then share those costs across an emissions trading program. However, electric utilities are faced with the complexity of identifying the best business model for implementing emission reductions in a competitive environment.
In the absence of site-specific regulatory requirements, electric utilities are forced to explain why capital-intensive emission control projects are prudent to internal management, shareholders, rate regulating agencies and public constituencies. The recent Clean Air Interstate and Clean Air Mercury Rules (CAIR and CAMR) bring many of these factors together and require a balancing act from the coal-fired utility sector.
Clean Air Interstate Rule
On May 12, 2005, the U.S. Environmental Protection Agency (EPA) published the final Rule to Reduce Interstate Transport of Fine Particulate Matter and Ozone (Clean Air Interstate Rule); Revisions to Acid Rain Program; Revisions to the NOx SIP Call (FR Vol. 70, No. 91, pp. 25162 – 25405). Known as CAIR, this action requires significant reductions of air emissions in the eastern half of the United States:
Approximately 5.4 million tons of sulfur dioxide (SO2) annually.
Approximately 2 million tons of nitrogen oxides (NOx) annually.
These emission reduction requirements are designed to remedy the affected states’ "failure" to address the significant contribution of pollutant emissions transported from one state to another.
Promulgation of CAIR not only provides a market-trading mechanism through which states could remedy this "failure" but also started the Federal Implementation Plan or "FIP" clock. It thus established a deadline for states to either implement the federal CAIR or have it implemented for them by the EPA.
This was followed by promulgation of the federal implementation plan on April 28, 2006, which became effective June 27, 2006. The primary purpose of issuing the federal implementation plan was to ensure that the CAIR regulations and associated emissions reductions occur within the specified time frame and are not delayed during state rule-making processes.
The regulatory basis of CAIR is section 110(a)(2)(D) of the Clean Air Act, which requires that states develop Clean Air Act implementation plans which:
Contain adequate provisions
Prohibiting, consistent with the provisions of this title, any source or other type of emissions activity within the State from emitting any air pollutant in amounts which will
Contribute significantly to non-attainment in, or interfere with maintenance by, any other State with respect to any such national primary or secondary ambient air quality standard…
Because "contribute significantly" is not defined in the statute, the EPA conducted photochemical transport modeling and developed thresholds of statewide culpability. The aim is to determine which states contribute significantly to downwind nonattainment areas for the eight-hour ozone and fine particulate matter (PM2.5) National Ambient Air Quality Standards.
As a result, the EPA has determined that emissions from 25 states and the District of Columbia contribute significantly to areas of fine particulate matter nonattainment. Additionally, 25 states plus the District of Columbia contribute significantly to areas of ozone nonattainment. The states included in CAIR are in the eastern half of the United States (see map).
Regions of the U.S. covered by the Clean Air Interstate Rule. Source: U.S. Environmental Protection Agency
Although the CAIR rules provide states with flexibility in determining which industry sector, or sectors, will be required to implement emissions controls, the rules are targeted at forcing emissions reductions from the electric utility sector.
The CAIR rules establish applicability at the unit or boiler level for those serving a generator with a nameplate capacity of more than 25 MWe producing electricity for sale. Subject units are stationary, fossil fuel – fired boilers or stationary, fossil fuel – fired combustion turbines serving at any time since the latter of November 15, 1990, or start-up of the unit’s combustion chamber.
"Fossil fuel – fired" is defined as firing any amount of fossil fuel at any time. However, an exemption for solid waste incinerators firing more than 80% non-fossil fuels is provided in the CAIR rules. Co-generation units selling more than one-third of their potential electric output capacity and more than 219,000 MWh annually for sale on any utility power distribution system are also subject to the CAIR requirements.
As noted, the applicability is based on the servicing of a turbine with a nameplate capacity of more than 25 MWe, not heat input or MW equivalent of a particular unit. Smaller boilers using a common steam header to serve a 25-MWe turbine are subject to and included in the CAIR program.
Cair Emission Trading Programs
The CAIR rules establish three independent emissions trading programs. Two of these programs, annual SO2 and annual NOx, are designed to reduce the annual concentration of fine particulate matter in the eastern United States. A third program, for ozone season NOx, is designed to reduce summertime emissions of NOx to reduce ozone concentrations.
The CAIR SO2 emissions trading program uses the existing Title IV Acid Rain market and allowance allocation system. Under this system SO2 allowances will continue to be distributed at the rate and levels contained in the federal Acid Rain provisions. CAIR SO 2 emission reductions are achieved through the implementation of increased allowance retirement ratios based on the vintage year of the SO2 allowances to be retired.
Because emissions allowances are allocated for future years to facilitate emissions trading, each allowance is assigned a vintage. The vintage of an emissions allowance refers to the first year in which that allowance can be used for compliance purposes. For units required to comply with the CAIR SO2 program, the vintage of an SO2 allowance establishes the fraction of a ton of SO 2 emissions an allowance covers for compliance purposes:
Pre-2010 vintage allowances (1:1 retirement ratio): 1 ton of SO2 emissions.
2010 – 2014 vintage allowances (2:1 retirement ratio): 0.5 tons of SO2 emissions.
2015+ vintage allowances (2.86:1 retirement ratio): 0.35 tons of SO2 emissions.
For a unit that emits 1,000 tons of SO2 in 2016, compliance with the CAIR SO2 requirement can be achieved by retiring either 1,000 pre-2010 vintage allowances, 2,000 2010 – 2014 vintage allowances, 2,860 2015 and later vintage allowances, or any combination thereof that equals 1,000 tons of SO2 emissions.
As the retirement ratios indicate, the CAIR SO 2 rules implement a 50% reduction in emissions of SO2 during Phase 1 and a 65% reduction in Phase 2. The use of banked SO2 allowances resulting from the overcontrol of SO2 emissions for compliance with the Acid Rain program may provide temporary relief in terms of the time available to install additional SO2 emission controls.
Similarly, the CAIR ozone season NOx trading program builds on (or, better stated, replaces) the established NOx SIP call program that was developed as part of the one-hour ozone attainment planning in the eastern United States. The ozone season is defined as the five-month period from May 1 through September 30. As a result, the amount of NOx emitted specifically during the ozone season must be tracked and ozone season allowances retired as necessary for compliance.
The CAIR rule also establishes an emissions trading program for the total annual emissions of NOx from affected facilities. Total NOx emissions, including those that occur during the ozone season, are included in the CAIR annual NOx program.
Unlike the CAIR SO2 program, states have extensive discretion regarding how allowances for both the ozone season and annual NOx programs are distributed within their jurisdiction. States may distribute some or all of their allowance allocations and even redirect allowances to other programs such as energy efficiency or renewable energy programs.
Allowance allocations in one state may be based on historic heat input, whereas another state may use an output-based methodology. States can opt to allocate allowances permanently or update allowance allocations with some frequency. As a result, utility companies will face differing NOx emission allocation methodologies from state to state.
Successful market-based emissions trading systems require monitoring of pollutant emissions to obtain accurate inventories of pollutant emissions. Ensuring that emissions are determined in a consistent manner from facility to facility is critical from fairness and market confidence perspectives. Additionally, the monitoring provides regulators and the general public with information on the environmental accomplishments of the program.
CAIR-affected units must monitor emissions in accordance with 40 CFR Part 75. In general, continuous emission monitors provide the most accurate estimate of pollutant emissions. Additional methods for estimating emissions, such as low mass emitter estimation methodologies, are provided for in 40 CFR Part 75.
Facilities that are considering the use of low mass emitter methods should carefully evaluate whether or not these conservative emission estimation methods result in a substantial overestimate of emissions. This information can be used to balance the cost of continuous emission monitoring systems with the potential for emissions overreporting that may result.
Facilities subject to the CAIR requirements are required to begin emission monitoring one year prior to the start date of the trading program. Consequently, facilities that have not been required to monitor emissions to the standards established in 40 CFR Part 75 must commence monitoring of NOx in 2008 and SO 2 in 2009.
Clean Air Mercury Rule
On May 18, 2005, the EPA published the final Standards of Performance for New and Existing Stationary Sources: Electric Utility Steam Generating Units (FR Vol. 70, No. 95, pp 28606 – 28700). Known as CAMR, this action establishes a nationwide cap on emissions of mercury from coal-fired electric generating units.
The mercury emissions cap is implemented in two phases, with the first becoming effective in 2010 and the second in 2018. Current mercury emissions from electric generating units are estimated by the EPA at approximately 48 tons per year nationwide. In the first phase, CAMR caps mercury emissions at 38 tons annually, a 20% reduction that must be met by 2010. Similarly, the second phase further reduces mercury emissions to a national cap of 15 tons annually, or a 70% reduction in mercury from the baseline emission estimates.
In addition to the market-based emissions trading program for mercury, CAMR establishes mercury emission performance standards by coal rank such as bituminous, subbituminous, and lignite.
Unlike the CAIR rules, CAMR does not provide states with flexibility in determining which industry sector or sectors will be required to implement emission controls. Requirements are specific to coal-fired utility units as defined in the federal rule.
CAMR, like CAIR, establishes applicability at the unit or boiler level for those serving a generator with a nameplate capacity of more than 25 MWe producing electricity for sale. Subject units are stationary, coal-fired boilers or stationary, coal-fired combustion turbines serving at any time since the latter of November 15, 1990, or start-up of the unit’s combustion chamber.
"Coal-fired" is defined as combusting any amount of coal or coal-derived fuel, alone or in combination with any other fuel, during any year. Co-generation coal-fired units with a nameplate capacity of more than 25 MWe that supply for sale in any calendar year more than one-third of the unit’s potential electric output capacity or 219,000 MWh (whichever is greater) to any utility power distribution system are also subject to the requirements.
As with CAIR, CAMR applicability is based on the servicing of a turbine with a nameplate capacity of more than 25 MWe. However, there is an area of uncertainty due to conflicting definitions between the CAMR and Boiler MACT rules. Smaller boilers using a common steam header to serve a 25-MWe turbine are subject to and included in the CAMR program requirements.
States have extensive discretion regarding how allowances for CAMR mercury emissions trading program are distributed within their jurisdiction. This flexibility, combined with considerable and ongoing opposition from many environmental groups and some regulatory agencies, will result in utility companies facing a greater variety of mercury allocation methodologies, emission caps, and performance standards from state to state.
Unlike monitoring for SO2 or NOx, the state of the science of continuous emission monitors for mercury is relatively new. CAMR allows for traditional flue gas sampling methods, common to continuous emission monitoring for NOx and SO2. This is in addition to the use of sorbent traps that collect mercury from the flue gas stream over a period of time.
Low mass emitter methodologies are also allowed but are designed to estimate maximum mercury emissions. However, these methodologies have the potential to overestimate actual mercury emissions.
Measurement of mercury emissions at facilities subject to the CAMR regulations presents new challenges for the electric utility sector. Difficulties associated with the installation, operation, and certification of new technologies continue to be worked through by the industry.
As with the CAIR programs, monitoring at CAMR-affected facilities must begin one year prior to Phase 1. All facilities must start mercury emissions monitoring at the beginning of 2009.
Together, the CAIR and CAMR regulatory programs establish a total of four new emissions reduction requirements and associated emissions trading programs for the electric utility sector. The reductions in air emissions that will result from implementation of these rules are substantial. The CAIR NO x cap that begins in 2009 requires that emission rates of NOx from all affected electric generating units in the eastern half of the United States must average approximately 0.15 lb/mmBtu.
Though these emissions reduction requirements can be met on sectorwide basis, uncertainties remain as to exactly how, or with how much room to spare, the emissions targets will be met. There is also the question of what the market price of any surplus emissions allowances generated from the overcontrol at some plants will be, particularly in the first few years of the program.
In what amounts to a high-stakes game of musical chairs, electric utilities are working to identify the best combination of emission controls, operating scenarios, and market dynamics that will ensure cost-effective compliance with the emission reduction requirements of the CAIR and CAMR regulations.