PRESIDENT AND CHIEF OPERATING OFFICER
DTE ENERGY RESOURCES
ON BEHALF OF
THE EDISON ELECTRIC INSTITUTE
BEFORE THE COMMITTEE ON ENVIRONMENT AND PUBLIC WORKS
UNITED STATES SENATE
NOVEMBER 15, 2001
Good morning Mr. Chairman and distinguished Members of the Senate Environment and Public Works Committee, and thank you for inviting me here today. My name is Gerry Anderson and I am President and Chief Operating Officer of DTE Energy Resources, one of three major business units of DTE Energy Company. I am responsible for the company’s more than 11,000 megawatts of generation and the associated fuel supply organization. I am also responsible for the company’s subsidiaries focused on energy projects and services (DTE Energy Services), energy trading (DTE Energy Trading), non-regulated power generation (DTE Generation), coal marketing and transportation (DTE Coal Services), and biomass energy (DTE biomass Energy).
DTE Energy Company is a Detroit-based, diversified energy company involved in the development and management of energy-related businesses and services nationwide. Its combined electric and natural gas utilities create a premiere regional energy provider.
DTE Energy has regulated and unregulated subsidiaries involved in a wide range of energy-related businesses. The subsidiaries sell electricity, steam, natural gas, landfill methane gas, coal and metallurgical coke, and are involved in the management and development of energy-related businesses and services. In addition, DTE Energy affiliates are developing electric fuel cells for homes and automobiles, and other cutting-edge energy technologies. The company’s growth strategy is focused on continued excellence of its core utility businesses, the development of non-regulated, energy-related ventures and investment in and development of emerging technologies.
I appreciate the opportunity to address the Committee on this important issue on behalf of the Edison Electric Institute (EEI). EEI is the association of U.S. shareholder-owned electric companies, international affiliates and industry associates worldwide.
EEI’s U.S. members serve more than 90 percent of all customers served by the shareholder-owned segment of the industry, generate approximately three-quarters of all of the electricity generated by electric companies in the country, and serve about 70 percent of all ultimate customers in the nation.
Let me state at the outset that EEI supports an integrated, multi-emissions approach that includes reform of the new source review (NSR) program that, if designed properly, can achieve important environmental, energy, and economic goals. Because of multiple, uncoordinated, and overlapping existing and proposed emission control requirements from federal and state, and even neighboring countries (See Appendix A-1), the electric power industry faces enormous uncertainty as it tries to develop appropriate plans to develop new generation capacity, upgrade plants and add pollution controls. In lieu of the current regime, a reasonable, sound, and integrated multi-emissions strategy would streamline the regulatory process, accomplishing meaningful air quality benefits at a much lower cost, while protecting electric reliability. To achieve these results, EEI developed a set of criteria that must underlie a well-designed multi-emissions approach to accomplish important air quality objectives:
With respect to this last point, I want to emphasize that EEI believes fuel diversity – including the use of coal, natural gas, nuclear energy, oil, hydropower and other renewables, to generate electricity – must be maintained as a matter of national energy
policy and national security. See Appendix A-2. A diverse fuel mix protects consumers and electric companies from fuel unavailability, price fluctuations, and changes in regulatory practices. Diverse fuel and technology options contribute to a stable, reliable and affordable energy supply over the long term.
We need a national energy policy that takes advantage of energy resources available within our country. One of the most plentiful energy resources is coal, and more than 90 percent of U.S. coal usage is the generation of electricity. This valuable but underutilized asset can meet the nation’s energy needs for about 250 to 350 years. Nuclear power can also be a plentiful resource with a virtually unlimited supply potential. On the other hand, according to EIA, the known supply of natural gas reserves looks adequate only for 40 years, based on current consumption (and much less given anticipated increased consumption levels). And when one considers the multiple beneficial uses for natural gas, especially for residential heating, it is reasonable to examine its use for central station power generation when electricity from coal is available to do the same work. Coal-based capacity additions, which already look attractive, will look even better as technology drives down their costs.
New technology puts coal-based plants in position to clear today’s environmental hurdles. The lower emissions and higher efficiency of new coal-based plants exceed current environmental requirements for SO2 and NOx. Clean coal technology also addresses greenhouse gases. Because of increased efficiency, new technology coal plants produce significantly less carbon dioxide (CO2) per megawatt hour than old plants.
I also want to return to a point mentioned in the criteria discussed above. The concern is with the new source review program. NSR is one of the most complex programs of the Clean Air Act. NSR presents a significant challenge to the safe, reliable, and affordable operations of the nation’s current fleet of electric generating power plants. The NSR program generally has been successful in assuring that major new emission sources install the best available control technology (BACT). However, EPA’s current reinterpretation of NSR, a departure from how the program had been understood and implemented for decades and contrary to the existing regulations, would prevent power plant operators at existing plants from making necessary improvements and undertaking routine maintenance and repair activities that allow reliable electricity generation, increase plant efficiency, and provide more electricity to meet our nation’s energy demands. For example, due to the need to make safety and reliability maintenance repairs to units at our Monroe Power plant, we have the opportunity to increase the efficiency of those units and produce more electricity with the same fuel input, something good for the environment and our customers’ costs. However, because of the present reinterpretation by EPA of the NSR regulations, as demand for electricity increase, we will have to limit the use of these units to the levels they have been used in the recent past and serve that increased demand with less efficient units. This does not help our customers or the environment. Therefore, while administrative changes are needed to address problems with the NSR program in the short term, a comprehensive multi-emissions legislative package must also include necessary long-term reforms of the NSR program.
II. Specific Comments On S. 556
As I have stated, EEI supports the concept of a well-designed multi-emissions bill provided it satisfies the criteria outlined above. S. 556, however, fails to do so, and thus EEI does not support the legislation. We are not alone in this respect. Other representatives of the electric power industry oppose S. 556. Many other industry sectors have expressed their strong opposition as well. The Bush Administration, in recent testimony before this committee, also has registered its opposition.
The electric utility industry has made remarkable progress in reducing air emissions. While coal use tripled between 1970 and 1999 due to increasing demands for electricity, emissions from electricity generation from coal declined significantly – and will continue to decline – as a result of current emission reduction programs.
Control programs for NOx (in 1996, 2000, and 2004) and SO2 (starting in 1995 and concluding later this decade) will reduce both emissions by about half from their highest levels. Meanwhile, the SO2 emission rate will drop 80 percent, and the NOx emission rate will decline about 70 percent. In other words, only one-fifth as much SO2 and one-third as much NOx will be produced with each kilowatt of electricity. Perhaps more importantly, these programs already cap future power plant emissions. Additionally, existing control technologies at power plants reduce mercury emissions by an average of 40 percent. Since 1974, DTE emissions of SO2 have been reduced by 61 percent, NOx by 41 percent, particulate matter by 89 percent, and mercury by 4 percent. During this same period, DTE’s annual system generation rose 44 percent or more than 15 billion kilowatt hours.
These advancements in the control and minimization of electric power emissions have resulted from significant capital investment in control technologies and a strong record of utility compliance. Over the past 25 years, the electric power industry has invested approximately $40 billion (capital) in technologies to reduce these air emissions. In addition, utilities spend $3 billion to $5 billion annually in operations and maintenance related to environmental performance. As we speak, DTE Energy, similar to many other companies, is spending approximately $630 million on NOx reductions to address ozone transport issues.
According to a recent analysis conducted by the Energy Information Administration (EIA) of the U.S. Department of Energy, coal-based electricity generation is predicted to decline 38-42 percent on a national scale if S. 556 is enacted. In turn, natural gas-based generation is projected to increase 60 percent. The rapid fuel switching – in this case the substitution of natural gas for coal – that would occur as a result of S. 556 could produce short-term power supply interruptions. According to EIA, “[T]he annual increases in production [of natural gas] required between 2005 an 2010 would be near record levels, representing a serious challenge for the industry … it is far from certain that the power sector would be able to move from dependence mostly on coal to dependence on natural gas and renewables in a relatively short time period without encountering supply problems.”
EIA also cautions that stringent emissions reductions like those proposed in S. 556 would require large amounts of pollution control equipment to be installed at power plants around the country over a very short period of time. Consequently, “system reliability could be of particular concern during the period when a large amount of emissions control equipment would have to be added.” In effect, construction, operation, and maintenance of these new control technologies will mean more “down time” for existing power plants, and in some cases multiple power plants in the same region severely impacting the availability, cost, and reliability of electric power. Consumers could face electricity shortages during the lag between the closing of these facilities and the siting and construction of new generation, resulting in increased prices and reduced reliability.
Furthermore, due to regional electric transmission constraints, it will be difficult, and in some areas impossible, to import the electric power necessary to meet demand while coal-based generation is fitted with new emission controls, or replaced with gas-based generation. The strain of re-routing electric power to serve areas impacted by the shutdown, restoration, and maintenance of power plants could further compromise the reliability of the nation’s electric power grid. This is a particular concern in Michigan where due to our peninsula nature there is already limited external transmission access that the state is trying to address.
S. 556 does not allow sufficient time for the major construction activities associated with installing necessary control technologies. The Clean Air Act Amendments of 1990 gave the utility industry 10 years to comply with the acid rain requirements for SO2 and NOx. S. 556 calls for much more stringent reductions for SO2, NOx, and mercury over a much shorter time period. Many of the plants will also be forced to apply the most advanced technologies over this short timeframe, even though many of the technologies are yet unproven and still in the introductory phases of development. As EIA observed, “[T]he evolution of new technologies is unpredictable, and Hg [mercury] emissions control technologies are relatively new and untested on a commercial scale.” Mercury is a particular concern to DTE Energy because we are such a large burner of western low sulfur sub-bituminous coal. Mercury emissions from such coal is lower and in an elemental form which minimizes environmental impact. However, elemental mercury is extremely difficult to remove. With a 90% reduction requirement by 2007, we do not know how we could continue burning this fuel.
In addition, the short timeframes for compliance mandated by S. 556 will drive manpower and material shortages, unnecessarily increasing compliance costs and further impact reliability. In fact it now appears that short timeframes, manpower and material availability, and other factors have greatly increased compliance costs. For example, earlier estimates of $60/kW for SCR capital costs have been overshadowed by publicly announced costs above $100kW. It is notable that these much higher costs are being incurred for various company’s’ first SCR installations, which are being undertaken at facilities where SCR would be most cost-effective. SCR applications in less-optimal circumstances are costing well above $100/kw.
C. S. 556 Will Result In Significant Adverse Economic Impacts To Both Industry and Consumers
While claims have been made that the reductions called for in S. 556 will be cost-effective with available technology, a closer look at the numbers reveals that enormous costs will be imposed on the utility industry and its customers. In its October 2001 report (referenced earlier), EIA estimates that the cumulative costs (2001 through 2020) for S.556 will be $177 billion. EIA estimates that the price of electricity will be 33 percent higher in 2020. EIA also noted that electricity prices could be substantially higher if natural gas prices turn out to be higher.
Because of the integral role that low-cost and reliable energy plays in our economy, and our lives, the influence of S. 556 goes well beyond the utility industry. In the case of S. 556 the combination of increased costs of production and decreased household income will lead to significant impacts on the production of non-energy goods, extending the effects of S. 556 well beyond the electricity sector. Energy-intensive industries will be especially hard hit by the rise in energy costs. A broad cross-section of service industries will absorb a large loss in output, although in percentage terms such industries are less affected than other industries due to their relatively low energy use. In addition, exports of goods will fall as U.S. firms lose competitiveness internationally as a result of higher costs of production.
All regions of the country would bear economic losses if S. 556 becomes law. However, the economic losses are not expected to be distributed evenly across the regions within the U.S. The economic burden of S. 556 will vary across states/regions in the U.S. because the industries most likely to be most affected (coal mining, oil and gas extraction, and the energy intensive industries) are not evenly spread across the country. Thus, those regions where these industries make up a disproportionate share of the economy, relative to the U.S. as a whole, will be likely to incur a disproportionate share of the losses. The impact of S. 556 on energy prices would have important implications for the manufacturing base of the U.S. economy that is unevenly distributed across the nation. Some regions like the East North Central, and individual states within regions (e.g., Michigan), will shoulder a significant portion of the burden on manufacturing firms.
D. S. 556 Mercury Reduction Targets May Be Impossible to Meet
There is no single control technology that can effectively remove all forms of mercury. Mercury control options are highly dependent on the existing power plant’s design and operating characteristics and the fuel used. Potential mercury emission reductions are unique to each unit. The characteristics of the coal-based plant that most greatly affect emissions of mercury and the type of control technology used include: the mercury content and other chemical aspects of the coal, the design of the particulate collection devices, and the design of the flue gas treatment systems. For some plants, mercury emissions reductions from 70 to 90 percent may be impossible to achieve. As indicated earlier, this is a particular concern to DTE Energy because of our large reliance on western low sulfur sub-bituminous coal. The only full-scale demonstration of mercury control on a coal-based utility boiler lasted just seven days and produced sustained mercury reductions of only 80 to 85 percent under well-controlled and supervised conditions. Long-term testing may reveal coal-type and plant operation restrictions with this technology. There exists no proven technology to control mercury emissions from oil-based power plants. Also, since no reliable monitoring technology for mercury has been developed, there is still considerable uncertainty in the measurement of mercury emissions and/or reductions.
Research is ongoing to improve the understanding of mercury combustion chemistry and physics, and to find ways to reduce mercury emissions in the most efficient and cost-effective manner possible. Other technologies (including advanced coal washing, the use of alternative sorbents, systems to recycle activated carbon for reuse, and systems to control NOx, SO2, and mercury emissions together) are in various stages of research and development. In fact, full-scale demonstrations of mercury control technologies at individual power plants are just beginning and will not be completed for 2 to 3 years.
Requiring a 90 percent mercury emissions reduction by 2007, as required by
S. 556, would cause significant fuel switching from coal to natural gas. This is inconsistent with national energy policy objectives because it will limit fuel choices, impede the construction on new power plants, and increase the cost of electricity. The excessive reduction requirements and short timeframe also would lead to the installation of a large amount of mercury retrofit control technologies and other pollution control equipment, the actual mercury emissions reduction potential of which is as yet still unclear.
Notwithstanding the practical problems with S. 556’s requirement of 90 percent mercury reduction from current emissions levels will be very expensive to attain. Economic analysis by EIA and the electric utility industry show that the mercury component of S. 556 would cost more than both the NOx and SO2 components combined. Best current estimates by the Department of Energy are about $5-$8 billion annually, in addition to the cost of other emission controls. Again, these costs are based on emerging control technologies, which are relatively new and untested on a commercial scale.
Compounding these problems is the fact that S. 556 does not allow trading for mercury emissions. Opposition to mercury emissions trading centers on concerns about potential hot spots, where mercury emissions might not be reduced or could even increase as a result of emissions trading However, there are several reasons why this should not be concern:
Rejecting mercury trading simply does not make sense and in fact can result in adverse consequences:
· It eliminates the significant cost savings that would be realized from mercury emissions trading. An analysis conducted for the EEI on behalf of the electric utility industry indicates cost savings from mercury trading of approximately $5 billion through 2020 (comparing the same mercury cap levels, with and without trading).
· It creates a major compliance problem for sources that have already cut mercury emissions through past actions (e.g., fuel use or emissions control equipment). S. 556
· requires every source to reduce mercury by 90 percent from 1999 levels. S. 556 would not allow a source that has already reduced mercury to buy credits to meet the 90 percent target.
· It can erase the benefits of SO2 trading. The unit-by-unit 90 percent mercury reduction requirement outlined in S. 556 can force plants to install a scrubber or
switch to natural gas (in contrast to S. 556 allowing SO2 compliance through both low-sulfur coal and SO2 emission trading).
· It can reduce the incentive for utilities and vendors to innovate. A prohibition on trading will force today's technology to be installed throughout the industry, even though it will be in a rather early state of development as of the S. 556 2007 compliance deadline.
S. 556 takes a step backwards in terms of the need for regulatory flexibility and efficiency in achieving air quality goals. In addition to the stringent emissions caps mandated in the bill, S. 556 also introduces a new concept, “modernization,” which would require every single power plant to install the most stringent controls, while producing little marginal environmental benefit. Many power plants would, in all likelihood, be forced to shut down due to the cost of emission control retrofits, even though those units are critical to a reliable and diverse electric supply. The “modernization” concept is currently not part of the Clean Air Act.
The “modernization” program is a response to claims concerning “grandfathered” power plants, the popular definition of which is older plants that are uncontrolled or exempt from the CAA. However, there are no power plants in the U.S. that are exempt from the CAA. The CAA regulates power plants through state implementation plans (SIPs) to meet national ambient air quality standards (NAAQS). For decades, states have
evaluated what emission reductions are needed to meet the NAAQS and then included these reductions in permits. In addition, the 1990 CAA amendments required all electric plants to address their SO2 and NOx emissions related to acid rain. Further, other new initiatives (NOx SIP call, ozone and fine particle standards, mercury, regional haze) will further reduce the gap between the emissions levels of new and older units. In reality, these programs are dramatically reducing all emissions everywhere. As indicated earlier over the last 26 years DTE Energy has reduced its particulate emissions by approximately 89 percent, SO2 approximately 61 percent, and NOx approximately 41 percent with additional ongoing extensive further reductions. There has been no “grandfathering.”
The “modernization” program would effectively supersede the already stringent S. 556 emission caps for SO2 and NOx because:
· Most existing power plant facilities would be subject to “modernization” early in the program:
q 80 percent of coal-fired units generating capacity will be 30 years old in 2007.
q 92 percent of coal-fired units generating capacity will be 30 years old in 2012.
q EPA’s current interpretation of a modification could bring most units into the program almost immediately.
· The sources to be modernized would be subject to strict new source performance standards (NSPS), best available control technology (BACT), or lowest achievable emission rate (LAER) requirements.
Other problems with the “modernization” provision that I would like to note include:
· “Modernization” is a clear example of reductions for reductions sake, since health and environmental benefits are in no way linked to emission reductions by scientific studies, etc.
· To require “modernization” of many older plants, which have already been retrofitted with expensive emission controls to meet the requirements of programs like Title IV and SIPs but that do not meet the current definition of NSPS, BACT or LAER, would create small emission reductions while being cost prohibitive.
· Many small, older units would be likely to shut down due to the cost of emission control technology retrofits or due to site-specific physical limitations, even though these units are critical to a reliable and diverse U.S. electricity supply.
· The “modernization” program included in S. 556 is a return to an inefficient, costly, command-and-control approach to achieving emissions reductions, will effectively negate the market-based approach that has worked so well under Title IV, and will render moot the trading provisions included in the bill.
F. Legislation Must Not Include Mandatory CO2 Reductions
EEI opposes regulation of carbon dioxide (CO2) and other greenhouse gases as pollutants under the Clean Air Act or other statutes. Because there is currently no cost-effective control technology for greenhouse gas emissions, compliance with stringent, mandatory targets and timetables such as those contained in the Kyoto Protocol would cause massive fuel switching in the electric utility industry from coal to natural gas, which would be very expensive and increase electricity prices. It also would further exacerbate EEI’s concerns, noted above, about fuel diversity.
On March 13, 2001, President Bush wrote to four Senators stating his preference for an appropriate multi-pollutant strategy addressing SO2, NOx and mercury emissions but also stating that the federal government should not “impose on power plants mandatory emission reductions for carbon dioxide, which is not a ‘pollutant’ under the Clean Air Act.” In testimony before this Committee several weeks ago, U.S. EPA Assistant Administrator for Air Jeff Holmstead reiterated the Administration’s strong opposition to including CO2 reductions in any multi-emissions bill. In his testimony Mr. Holmstead stated that greenhouse gas emissions “should be addressed in the context of climate change, which is being undertaken by the President’s Cabinet level working group.” EEI agrees with the President’s CO2 policy and believes it to be sound from policy, legal and scientific perspectives.
Instead of mandatory regulation of CO2, the government should consider working with industry to develop successors to the highly successful, voluntary Climate Challenge
program. The utility Climate Challenge program reduced, avoided or sequestered 124 million metric tons of CO2-equivalent (MMTCO2E) greenhouse gases in 1999, and according to the Department of Energy (DOE), utilities were projected to reduce, avoid or sequester 174 mmtCO2E greenhouse gases in 2000.
A robust, enhanced, national voluntary climate initiative should consist of these major elements:
S. 1294 – sponsored by Senators Murkowski, Craig, Hagel, Domenici, Roberts and Bond, and S. 1008 - sponsored by Senators Byrd and Stevens.
Among the advantages of a national voluntary program are that: 1) it would address all sectors of the economy, not just the electric utility industry (which comprises about 1/3 of U.S. emissions); and 2) it would facilitate trading and offsets projects with other sectors of the economy, such as forestry and farming.
In addition to the federal government incentivizing and facilitating the enhanced voluntary program by initiating new policies and regulations, Congress will likely need to enact legislation establishing:
With regard to timing, as previously noted, long lead times are needed for the electric utility industry to avoid the premature retirement of capital stock. In addition, any national goal or policy objective embodied in legislation should be based on an appropriate baseline, such as the year of enactment of legislation or some future year, not a historical artifact such as 1990.
With regard to technology, climate change is a long-term issue that, as previously noted, will require a transition in the medium to long term for cost-effective climate technology RDD&D to develop. There is no technological “silver bullet” or “magic bullet,” such as a carbon scrubber, for CO2. The Department of Energy and other government agencies, as well as private firms, are currently engaging in RD&D of carbon capture, storage and disposal of CO2 from stacks. We support this R&D effort, but believe that the government should be budgeting as much as $500 million annually for 10 years of R&D and five years of deployment in order to jump start the implementation of cost-effective and feasible technology.
Ultimately it may take a menu of technological options to address greenhouse gases in the long term. The government has supporting and partnership roles to play, but it should not put all of its technological eggs in one basket, regardless of whether the technology is integrated gasification combined cycle (IGCC); carbon capture, storage and disposal; clean coal technologies; etc. In the medium to long term, any number of cost-effective technologies may emerge, including clean coal technologies; IGCC (particularly in the 2012-2018 time frame); renewables; nuclear; forestry and soils offset projects; hydrogen and fuel cells; and technologies that we are not now even aware of. The nation’s energy needs and security are well served by fuel diversity in electric generation supply, and that statement is true in the greenhouse gas context as well as other contexts.
At DTE Energy we strongly support continued research and technology development to facilitate a good long-term policy/program to address the global climate issue. We support EPRI research, we are a member of the PEW Center on Global Climate Change Business Environmental Leadership Council and we recently joined the Chicago Climate Exchange to develop a GHG trading program. We support distributed generation and have made significant investments in fuel cell development through the partnership formation of Plug Power and believe that hydrogen based energy is a likely long term solution. In the short term, we strongly support taking reasonable steps that make sense to address the issue. We support preservation of rainforest in Belize, in conjunction with the Michigan Department of Natural Resources we have planted nearly 20 million trees in Michigan and with the strong operation of our Fermi nuclear plant we avoid further emissions of carbon dioxide. Finally, we have a subsidiary, DTE Biomass, that develops landfill methane gas to energy projects across the country (approximately 35 presently in service and others under development). Methane is approximately 21 times more potent a greenhouse gas than carbon dioxide. All of these voluntary efforts have allowed us to significantly offset our increasing CO2 emissions as a result of increasing electricity demand.
If designed properly, a multi-emissions approach can meet important environmental, energy, and economic goals without threatening electric reliability or driving up electricity prices unreasonably. Such an approach would impose reasonable emissions reduction targets and timetables for SO2, NOx, and mercury, and would allow the industry to continue, on a parallel course, to reduce CO2 emissions voluntarily through flexible, cost-effective, and market-based programs.
A well-designed multi-emissions approach that regulates SO2, NOx, and mercury would:
S. 556 simply cannot deliver these results. A well designed, coordinated, and comprehensive integrated approach to the development and implementation of environmental regulations offers a better way to achieve air quality goals. With adequate time and flexibility, the electric power industry can continue to reduce emissions, provide affordable and reliable electricity, and meet the goals of energy and environmental policy. The electric utility industry and DTE Energy specifically is committed to working with the Committee, and the Administration, to design multi-emissions legislation that fulfills these criteria.
 Energy Information Administration (EIA), Annual Energy Review 1999, T, 11.2, T, 11.3.
 Based only on EPA’s acid rain program and the so-called NOx State Implementation Plan (SIP) Call regulations.
 Measured by the pounds of emissions per thousand kilowatt-hours generated by coal.
 All references to EIA in this section are taken from its October 2001 report, Analysis of Strategies for Reducing Multiple Emissions from Electric Power Plans with Advanced Technology Scenarios.
 Under a Kyoto Protocol-type scenario, coal would decline from 50 percent of electric generation to as low as 13 percent in 2010, while natural gas would rise from 25 percent to 50 percent in the same time frame. Research Data International, Inc., U.S. Gas and Power Supply under the Kyoto Protocol, Vol. I at 1-9 (Sept. 1999).
 A recent EIA report (which actually understates costs because mercury had not yet been analyzed) found that reductions in sulfur dioxide, nitrogen oxides and CO2 consistent with recent legislative proposals would increase electricity prices by 17-33 percent in 2005, and by 30-43 percent in 2010. EIA, Analysis of Strategies for Reducing Multiple Emissions from Power Plants: Sulfur Dioxide, Nitrogen Oxides and Carbon Dioxide xvii, 27 (Dec. 2000). The bulk of the cost increases are due to CO2 restrictions.