My name is Bill Tyndall. Since August 1998, I have been Vice President of Environmental Services for Cinergy Corporation, an electric utility company based in Cincinnati, Ohio that provides power to 1.4 million electricity customers and 470,000 gas customers in Ohio, Indiana and Kentucky. Prior to joining Cinergy, I served Representative John Dingell and other Committee Democrats as minority counsel to the House Commerce Committee and advised them on air quality issues. Still earlier, I was a senior policy advisor in EPA's Office of Air and Radiation. Still prior to that, I served in EPA's Office of General Counsel, where I worked on new source review and other stationary source issues under the Clean Air Act.
Thus, I am speaking to you today as someone who has spent nearly ten years addressing air policy issues from a variety of perspectives. I am also speaking to you on behalf of the Edison Electric Institute, an association that represents investor-owned electric utilities such as Cinergy. I will be addressing what I see as the successes and the problems of the Clean Air Act as amended by Congress in 1990.
The Clean Air Act has proved effective at reducing air pollution in this country. Since the Act was adopted in 1970, emissions of the "criteria" air pollutants – sulfur oxides such as sulfur dioxide (SO2), particulate matter, ozone, carbon monoxide, nitrogen dioxide and lead – and their precursors (such as nitrogen oxides (NOx)) have fallen dramatically. While emissions of these pollutants from all industrial sectors have decreased, I will focus on those from power plants, a source category that is the focus of a large number of control programs under the Act. Consistent with the overall trend in emission reductions, emissions from power plants have fallen significantly since the Clean Air Act was adopted, and continue to decline as a result of the Title IV program for electric utilities adopted in 1990.
According to the Environmental Protection Agency, utility emissions of NOx, which had been 6.7 million tons in 1990, declined to about 6.2 million tons by the year 1997. By 2000, EPA projects that power plant NOx emissions will have declined by 2.1 million tons annually.
Between 1970 and 1997, SO2 emissions resulting from fuel combustion by electric utilities declined by over 4 million tons a year (from a peak in 1980 of 17.5 million tons to 13.1 million tons in 1997). Once the second phase of the Title IV program is fully implemented, we project further significant declines in SO2 emissions, to less than 10 million tons annually.
Electric utility particulate matter emissions have also declined substantially -- by almost an order of magnitude (from 1.8 million tons in 1970 to 0.3 million tons in 1997).3 Virtually all coal-fired boilers in this country are now equipped with advanced particulate controls, including electrostatic precipitators (ESPs) and baghouses.
These emission reductions are even more remarkable when one considers that they have occurred during a period of substantial economic growth. This economic growth triggered concomitant growth in electricity production and use. For example, between 1970 and 1996, electric utilities experienced a greater than 120% growth in sales, from 1392 billion kilowatt-hours to 3084 billion kilowatt-hours. Nevertheless, the utility industry implemented control programs that substantially reduced emissions from all of their facilities -- both new and existing.
But reducing emissions has not come cheaply. Information provided to the government by electric utilities on FERC Form No. 1 indicates that utilities and, as a result, their customers spent over $32 billion for air pollution control facilities between 1976 and 1996. Additional billions of dollars are being spent as the industry implements the second phase of the Title IV program. Utilities also bear the substantial, additional costs of operating and maintaining these pollution control facilities.
As even EPA recognizes, the costs associated with Clean Air Act compliance have increased over time. EPA estimates that annual costs to electric utilities for Clean Air Act compliance, which were $1.5 billion in 1985, had risen to $1.9 billion by 1990. The 1990 Clean Air Act Amendments increased these costs substantially. The SO2 emission reduction program in Title IV alone has been estimated to increase the cost to electric utilities by up to $2.1 billion annually once it is fully implemented. There is every reason to believe that utility costs will continue to increase. Cinergy alone faces capital costs of up to $700 million for control of NOx emissions.
While I am on the subject of costs, let me point to one program that has helped to keep these costs – although high – lower than they would otherwise have been. I am referring, of course, to the market-based approach to reducing SO2 emissions that is found in Title IV of the Act. Title IV has been a great success, with 100 percent compliance and substantial cost savings due to the flexibility of the program. Given the experience with Clean Air Act Title IV, I urge Congress to consider market-based approaches, as opposed to the traditional command-and-control approach to environmental regulation, whenever it considers reform or refinement of Clean Air Act emission reduction programs.
However, to call the Title IV SO2 trading program a panacea is not correct either. Its success cannot be extrapolated to trading of NOx under EPA's SIP call, for example. Most of the SO2 trading cost savings have come about as a consequence of lower prices of western low-sulfur coal and its transportation. A similar low-cost fuels fix is not available for NOx. In addition, the SO2 program, unlike EPA's NOx SIP call, was designed in such a way as to maximize opportunities for trading. The SO2 program was phased in over ten years, while the NOx SIP call controls are due in less than four years. Furthermore, the SO2 program required only a 50 percent reduction while the NOx SIP call requires an 85 percent reduction, which virtually mandates one type of emission control technology across most of the affected facilities. To maximize opportunities for NOx trading, the system should be modified to alleviate these problems.
While the Clean Air Act has been successful in terms of producing improved air quality, I would now like to focus on some aspects of the Act that, in my opinion, have made producing that improvement more burdensome and costly than necessary. In this regard, the Act features many programs that are directed towards the same pollutants from the same sources. This can result in increased administrative burdens to States and the regulated community, reduced compliance flexibility, greater difficulty in responding to changing market forces, and less cost-effective control requirements.
Let me illustrate my concern by referring to the many programs that are currently aimed at controlling NOx emissions from power plants. The statutory bases for controlling NOx emissions include the National Ambient Air Quality Standards (NAAQS) for ozone (of which NOx is a precursor) (CAA § 109), programs required to provide for the "attainment and maintenance" of the NAAQS (CAA §§ 110, 172, & 181-185), the Title IV existing source NOx reduction program (CAA § 407), the new source performance standard ("NSPS") program for NOx emissions from new sources (CAA §§ 111), the visibility improvement program (CAA §§ 169A & 169B), the new source review ("NSR") program (CAA §§ 165, 172 & 173), and a number of other programs.
For example, the Clean Air Act requires areas that do not attain the ozone NAAQS to implement "reasonably available control technology" for NOx emissions from major sources such as power plants (CAA § 172(c)(1)), and to have an overall plan for making reasonable, further reductions in NOx emissions in order to attain and maintain the standard (CAA § 110(a)(2)). The 1990 Clean Air Act Amendments added a number of specific NOx emission control requirements for power plants located in ozone nonattainment areas (CAA § 182).
In addition, new power plants are required to meet new source performance standards, and can be built only after being subjected to either "prevention of significant deterioration" (in attainment areas) (CAA § 165) or nonattainment review (in nonattainment areas) (CAA § 173). The same requirements apply to existing plants that are "modified" to create new capacity to emit air pollution beyond their original capacity. Title IV of the 1990 CAAA requires revision of the new source performance standards for NOx applicable to power plants (CAA § 407(c)).
Sections 169A and 169B of the Act require States to develop programs, pursuant to regulatory guidance issued by EPA, to address visibility concerns in the national parks. EPA just issued regulations in July of this year providing criteria for these state programs. These programs could address, among other things, NOx emissions from power plants.
The 1990 Amendments added an important new program addressing NOx emissions from existing power plants -- the Title IV program. These new provisions impose NOx emission limits on existing power plants covered by the Title IV acid rain provisions (CAA § 407(b)). These limits have been imposed in two phases, the second of which must be implemented by the year 2000.
EPA's implementation of these numerous, overlapping requirements that address NOx emissions from new and existing power plants has added to the complexity and cost of industry compliance efforts. For example, in 1997, EPA used the NAAQS provisions of the Act to promulgate a new ambient standard for ozone that was more stringent than the existing standard -- the standard that serves as the basis for the specific NOx control programs Congress wrote into Subpart 2 of Title I of the Act in 1990. EPA has indicated that the new ozone NAAQS would be implemented largely through NOx controls. But while Congress specified a detailed program for reducing ozone levels in Subpart 2 of the Act --a program that addresses NOx as well as VOC ("volatile organic compound") emissions -- the Agency indicated that it would not rely on that program when implementing the new NAAQS. The United States Court of Appeals for the District of Columbia Circuit understood the problems these inconsistencies posed and held that any new standard could not be implemented other than through the Congressional ozone reduction program.
At the same time that EPA has revised the ozone NAAQS, EPA has sought to use its Clean Air Act authority to review the adequacy of state implementation plans to develop a program for further NOx reductions for power plants in 22 States throughout the Eastern United States. This program is referred to as EPA's NOx SIP call rule. In many cases, the power plants affected by these NOx reduction requirements are far removed from the ozone nonattainment areas.
NOx reduction requirements could also be imposed on specific power plants in response to petitions filed by Northeastern States under § 126 of the Act. EPA has issued a rule which includes findings that would result in the automatic grant of these § 126 petitions, thereby triggering a 3-year compliance schedule, if states do not respond to EPA's NOx SIP call rule by November of this year. EPA has, however, temporarily stayed this rule while it undertakes additional rulemaking to "de-link" the § 126 rule from the SIP call rule, thereby abandoning the Agency's earlier conclusion that the § 126 program should proceed only after states had an opportunity to consider additional control programs pursuant to the SIP call rule
The utility industry is therefore confronted with numerous programs that address the same pollutant. Each program has potentially different implementation schedules. Each program raises different questions for a company's compliance planning. As you can imagine, this mix of programs and implementation schedules makes compliance planning exceedingly difficult and compliance itself unnecessarily expensive.
One key problem is that the differing programs may demand different technologies. A utility that invested in low NOx burners to meet its Title IV NOx requirements, for example, may also have to add Selective Catalytic Reduction (SCR) or Selective Non-catalytic Reduction ("SNCR"), or even switch to an alternative fuel such as natural gas, depending upon the schedule for and stringency of future requirements. The choice of technology is influenced not only by the stringency of and schedule for future requirements, but also by the nature of the implementation scheme. For example, will trading or banking of NOx emission credits be allowed, and under what conditions? These changing and uncertain requirements are both frustrating and costly for regulated industry and States.
Furthermore, because one program is not allowed to work before another is implemented, it is unclear that all of these overlapping programs are necessary from an environmental standpoint. For example, the detailed Congressional ozone control program contained in Subpart 2 of Title I reduced the number of ozone nonattainment areas by 62% (from 100 to 38) between 1991 and 1998.1 But EPA did not permit that program to come to fruition before adopting a new ozone NAAQS that would be implemented through a different program – under Subpart 1 instead of Subpart 2 of the Act. It is questionable that adoption of this new program will speed or enhance public health protection, but it certainly complicates planning for sources possibly subject to two NAAQS implementation programs.
Furthermore, while the previous discussion has addressed those portions of the Clean Air Act that concern power plant NOx emissions, the Clean Air Act contains numerous other programs addressing electric utilities that a company must consider in formulating its overall compliance strategy. I am providing with this testimony a chart that illustrates the myriad of new requirements that electric utilities face under the Clean Air Act regarding their emissions of SO2 and NOx over the next decade. These include monitoring, reporting and control requirements for sulfur dioxide (SO2) emissions; additional SO2 emission reduction requirements under a possible short-term SO2 ambient standard and a revised PM2.5 standard; possible SO2 and NOx limitations as part of regional haze programs; and revised new source review requirements. Other regulatory programs that electric utilities may face include possible regulation of mercury emissions and possible future regulatory requirements targeting CO2 emissions.
A company must also consider the possibility that legislation to restructure the electric utility industry could include new air quality programs. Because the system of air quality regulation is already so complex and burdened by a large number of programs addressing both new and existing power plants, I simply urge that restructuring legislation is not the place for more air quality legislation.
In sum, a company must evaluate its compliance plans in light of all of these programs -- a daunting task given the continued regulatory uncertainty regarding many of them. The result could be commitments to expensive control technologies today for certain substances, which would be rendered useless during the next decade if new regulatory requirements dictate another compliance strategy, such as a switch to natural gas.
Finally, all of these difficulties are compounded by EPA's changing interpretations of key provisions of the Clean Air Act. For example, all of the regulatory programs discussed previously are being developed or implemented at the same time that EPA has proposed to change the Clean Air Act rule defining when an existing source is "modified" to such an extent that it must meet new source requirements, including NSPS and preconstruction permitting requirements under the PSD and nonattainment programs.
The Clean Air Act modification rule is perhaps the most complex and least understood of the Clean Air Act programs. EPA and the States have issued volumes of dense and sometimes conflicting guidance regarding the program. Indeed, EPA has recognized the confusing, cumbersome and byzantine nature of the NSR modification rules and is working with various stakeholders including industry and States to develop an appropriate fix.
This effort to develop a fix to the modification rule on which all can agree is critical, because EPA's recent efforts to reform this program have created tremendous confusion about the nature of repairs and activities that can be allowed at existing plants. Let me explain. Historically, EPA has stated Congress "did not intend to make every activity at a source subject to new source requirements," and that the Clean Air Act modification rule "in no way intends to discourage physical or operational changes that increase efficiency or reliability or lower operating costs, or improve other operational characteristics of the unit." By contrast, EPA explained in its July 1998 proposed revisions to the modification rule that the proposed rule changes would target activities undertaken "to increase reliability, lower operating costs, or improve operational characteristics of the unit," even if doing so would not result in any increase in the unit's emission rate.
This proposed change in the modification rule would strike at the heart of efforts to maintain the competitiveness of American industry in an international marketplace. For the utility industry, the proposed new approach to the modification rule would hinder the industry's efforts to optimize the reliability, efficiency and safety of its generating units at a time of declining electricity reserve margins. By discouraging such efficiency gains it is contrary to the Administration's goals of reducing greenhouse gases. Before proceeding with this rulemaking, therefore, it is critical that EPA take time to pursue the discussions with States, industry, and other stakeholders and that EPA take their concerns into account. EPA must adopt a modification rule that is clear and understandable, and that avoids unnecessary administrative and regulatory costs.
The electric utility industry recognizes that it has a responsibility to produce and supply the power this nation needs in an environmentally-responsible manner. Its voluntary establishment and participation in the Climate Challenge program in partnership with the Department of Energy is evidence of its commitment to meeting that responsibility. This program will lead to 170 million tons of greenhouse gas reductions in the year 2000.
There are a variety of ways to achieve emissions reduction goals for this industry, while continuing to ensure a reliable and affordable delivery of electricity. EEI is working to develop new innovative approaches to dealing with these challenges. While I cannot speak for the entire industry, Cinergy strongly believes that Congress needs to replace the myriad of emission control programs aimed at utilities with a comprehensive approach that establishes a single set of reasonable reduction requirements with adequate lead times and market-based implementation mechanisms. This can be done in a manner that is consistent with the air quality and public health goals established in the Clean Air Act and that is more efficient, economic and provides more regulatory certainty than the existing piecemeal, uncoordinated approach that I have described today. And, along with such innovative solutions, we also need a significant increase in public/private partnerships for research and development to identify the next generation of technology alternatives, and create incentives that will move us to even cleaner forms of electric generation in the future. But this will put this issue squarely before this Committee since it cannot be done without Congressional action.
With fair and clear environmental goals, appropriate time frames, and flexible implementation, utilities can best determine a future course for their companies, be it pollution control installation or fuel switching or a combination that will give us the environmental solution we are striving to attain.