Minnesota Pollution Control Agency

Xcel Energy Metropolitan Reduction Project

Minnesota Pollution Control Agency Supplemental Comments at the

October 2, 2003 Informational Meeting

Filed: October 23, 2003

Table of Contents

Page

Introduction 1 Emissions 2

- Coarse/Fine Particles 2 - Air Quality Trends/Alerts 2 - Coal Creek Station, ND 3 - Plant Utilization Assumptions 5 - Carbon Dioxide Calculations 5 - Mercury 6

= Mercury Control Technology 6 = Mid American Energy Permit 7 = Enviro scrub 8 = Mercury in Rainfall 9 = Mercury Reductions in MN 9

Costs 10

- High Bridge Primary 10

Benefits 10

- Discount Rate 10 - Cost/Benefit Analysis 11 - Carl Nelson Study 12 - U.S. Office of Management and Budget 13

Regulatory Issues 14

- New Source Review 14 - Clean Air Act Issues 14

Conclusion 15

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MPCA SUPPLEMENTAL COMMENTS OCTOBER 2, 2003

MPCA INFORMATIONAL HEARING

INTRODUCTION This filing supplements three previous filings made by the Minnesota Pollution Control Agency (MPCA) in this matter. The MPCA filed its study of the primary Metropolitan Emission Reduction Proposal (MERP) on December 30, 2002. On April 28, 2003, at the request of the Public Utilities Commission (PUC), the MPCA filed its study of the alternative MERP proposal. On May 28, 2003, the MPCA filed reply comments that included material completing its study of the alternative proposal, making corrections to prior calculations, and responding to the comments of other parties. The content of these filings was brought before the PUC in an informational meeting held on October 2, 2003. At that meeting, a number of additional issues were raised, and requests for clarification were made. MPCA presenters responded to those questions. At several points, the MPCA provided new information that was not contained in its previous filings, and also provided clarifications of its previous studies. In this supplemental filing, the MPCA records these answers and information, so they are easily accessible in the record to the PUC and the parties to this proceeding. The filing contains information on several individual points raised during the hearing, and does not attempt to summarize MPCA’s previous filings. This filing does attach, however, copies of the presentation slides presented to the PUC at the October 2 hearing, as well as the closing comments made by the MPCA at the hearing. Note: There are a couple of concepts that have been the subject of some misunderstanding in interpreting the MPCA filings and the MPCA’s spoken presentations on October 2. Throughout its filings, the MPCA refers to the primary MERP as the “proposal,” that is, the preferred proposal brought forward by Xcel Energy. In its filings, the MPCA refers to the alternative MERP as the “alternative.” At times in its written and spoken words, MPCA will use the term “proposal,” referring to the primary MERP proposal, but it will not always be correctly interpreted by those listening to the MPCA. This should be kept in mind in reviewing MPCA filings and presentations to date on this docket. As a second note, although the MPCA has tried to clarify this in its filings and presentations, the typical method of analysis of the cost and benefits of environmental regulations by EPA and MPCA is stated in terms of annual costs and benefits. In PUC dockets, however, there are attempts to calculate the overall costs and benefits of projects over their expected life span. When thinking about numbers presented by MPCA that are annual benefits calculations, it must be remembered that those benefits will continue to accrue each year for as long as the plants are operated.

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EMISSIONS

COARSE/FINE PARTICLES

The MPCA would like to make a clarification to Figure Three on page 27 of its December 2002 filing. At the October 2, 2003 hearing, there was confusion about what kinds of emissions Figure Three was depicting in the state. Figure Three presents coarse particulate emissions, commonly called “PM10,” in the state of Minnesota. Figure Three does not depict fine particulate (PM2.5) emissions of the power plants. The MPCA apologizes for the confusion caused by its failure to identify which type of particulate emissions was included in Figure Three. Figure One and Figure Two on page 26 of the filing depict the amounts of overall state wide emissions contributed by the power plants to sulfur dioxide and nitrogen oxide, which are a major constituent of PM2.5 formation. The MPCA provided specific information on the contribution of power plants to the formation of PM2.5 on page 31 of the December 2002 filing. Figure Six on that page shows that air monitors located in the Minneapolis/St. Paul area confirm that a major portion of PM2.5 are sulfates and nitrates. Although they have similar names, PM10 and PM2.5 are the subject of separate national ambient air quality standards.

AIR QUALITY TRENDS/ALERTS

The MPCA has been monitoring ambient air quality since 1968. Currently, the MPCA operates 58 monitoring sites statewide, including 34 in the Twin Cities Metro area. At the October 2 meeting, the MPCA explained that while Minnesota is in attainment for all national ambient air quality standards, the MPCA has had air quality alerts with increasing frequency in recent years. For example, in 2003, the MPCA has had four air quality alert days for ozone and ten for fine particles. The MPCA reported that while ambient concentrations of most air pollutants for which there is a national ambient air quality standard have been in decline, ozone levels have been trending toward an increase in recent years. A recent study commissioned by the MPCA determined that ozone levels are rising. In addition, the ambient air quality standard for fine particles (PM 2.5) has only been in existence since 1997. In addition to being the subject of litigation that went to the United States Supreme Court before the standard was upheld in 2002, states have completed only a few years of ambient air quality monitoring on fine particles, which is not a sufficient time period to establish a trend. Total emissions of the precursors to ozone and fine particulates (nitrogen oxides, sulfur dioxide and volatile organic compounds), however, have been increasing in Minnesota in recent years. As the MPCA also described in its December 2002 filing on page 30, when EPA adopted the new national air quality standard for fine particles, EPA noted that its research

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indicated that its adverse health effects are triggered even when the air is cleaner than the standard requires. As a result, EPA requires states to issue health alerts when fine particles reach levels much lower than the ambient air quality standards. This allows citizens to take the suggested actions to reduce their chance of triggering a respiratory event due to the quality of the air on alert days. As a final note, EPA is required to review its air standards every five years, and is currently reviewing the level of the fine particle standard. These reviews are very formal, conducted with a complete review of all peer reviewed scientific research that has been assembled on the effects of the air pollutant. The evaluation is made through a multi-step process that includes review by the EPA Clean Air Science Advisory Board. Based on the latest research, EPA staff has recommended making the current standards more stringent to better reduce the health effects from this pollutant. It is too early to know how EPA will act on this recommendation as it moves through the formal process. At the October 2 hearing, there was a concern expressed about whether the cause of air pollution alerts that had been experienced in the Metropolitan Area result from local emissions or from emissions from other parts of the country. After each air pollution alert episode, the MPCA works with a contractor to evaluate whether the air alert was triggered by transported pollution from other areas, local pollution, or a combination of local and transported pollution. In a combination event, background levels of transported pollution combine with the increased pollution present in the Metropolitan Area to create levels above air alert thresholds. Thus far, the MPCA analysis of air pollution alert events has found that 50% of the events are combination events, 25% are driven predominately by local emissions, and 25% of them are caused by transported air pollution.

COAL CREEK STATION, ND

At the October 2 hearing, there was discussion of how emissions from the Coal Creek Station compare to the MERP proposals. The MPCA has investigated this issue and below compares the emissions from Xcel to the Great River Energy (GRE) Coal Creek Station near Bismarck, North Dakota. Coal Creek has two generating stations, each about 550 MW, burning North Dakota lignite coal. The units were commissioned in 1979 and 1981. Because Coal Creek was built after the Clean Air Act was passed, it was not grandfathered, and its emission limits were set through a BACT analysis. Each unit controls direct particulate matter emissions (PM10) with an electrostatic precipitator, has low-NOx burners with overfire air controls in the boiler to control NOx emissions, and has wet magnesium-enhanced lime flue gas desulfurization (FGD) to control SO2 emissions. The FGD uses a water spray with the magnesium and lime in it to achieve SO2 removal from flue gases sent across the FGD unit of about 94%. Because each unit bypasses roughly 30% of its flue gas around the FGD unit to be mixed again later to reheat the flue gases in the stack, however, total control of SO2 is lower, for a total removal of about 70%1. 1 Personal communication, Mark Strohfus, Great River Energy, October 15 and 16, 2003.

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The graphs below compare Coal Creek’s emissions performance against standards and Xcel’s MERP proposals. The comparison is made looking at the emission rate: the amount of pollutant released for each million Btu of coal burned. Comparing emission rates is standard practice in air pollution control, because it allows one to know how well a control technology performs in relation to other technologies. Comparing total emissions to the air or removal efficiencies can be misleading, because these measures require understanding the size and processes of a facility or the characteristics of fuel—the original amount of sulfur in the coal, for example, which can be highly variable. The graph below compares Coal Creek’s current SO2 emissions rate with the new source performance standard (NSPS), current best available control technology (BACT) limits, Xcel MERP plants’ current emissions, and Xcel MERP plants’ performance under the primary and alternative projects. Coal Creek performs better than required by NSPS, but emissions rates are much higher than what would be required by current BACT (2001).

SO2 Emissions

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Note: Primary MERP SO2 emissions are zero for Riverside and High Bridge units.

The graph below is the same comparison for NOx. Coal Creek’s NOx emission rates are lower than that required by NSPS, but higher than what would be required by current BACT. Emission rates of NOx from Riverside and High Bridge under the alternative plan would be higher than the emission rates for NOx from Coal Creek.

NOx Emissions

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GRE’s Coal Creek station was considered to be a well-controlled plant when its emissions limits were determined through its BACT analysis conducted in the 1970’s. Continued developments in air pollution control, as illustrated by recent BACT analyses, show that coal-fired boilers can be far better-controlled today. What is interesting to note is that the Alternative MERP project would result in NOx emission rates higher at Riverside and High Bridge than current rates from a coal-fired utility built over 20 years ago.

PLANT UTILIZATION ASSUMPTIONS

Xcel’s response to the MPCA’s information request 1 contains the plant utilization rate before and after implementation of the proposal. The emission reductions shown on page 9 of the May 2003 filing reflect both the changes in emission rates due to the use of different fuels and/or air pollution control, as well as change in the number of hours the plants are expected to be operated in the future. The MPCA has not further revised these figures, for the reasons discussed on pages 11 and 12 of this filing.

CARBON DIOXIDE CALCULATIONS

At the October 2, 2003 hearing, a question was raised about an MPCA statement on page 4 of its May 2003 filing, regarding carbon dioxide emission reductions projected in the MERP proposals. That statement was part of the summary of the MPCA report, and the attempt to describe the issue briefly raised confusion about what the MPCA was saying. The MPCA apologizes for this and offers the following explanation. The statement is explained in more detail on pages 11 and 12 of the May 2003 filing. The basic point that the MPCA was making was that Xcel projected a reduction in CO2 emissions from the alternative plan in its July 2002 filing. The MPCA, however, calculated an increase in CO2 emissions, because the alternative proposal would create 60 new MW of capacity at the King Plant, combined with an increase in projected utilization rate at the King Plant from 70% to 82%. This would increase overall emissions of CO2. What the MPCA was pointing out is that if one calculated the environmental benefits of the primary proposal and the alternative, accounting for the fact that the primary proposal would decrease CO2 emissions by 9%, while the alternative proposal would increase CO2 emissions by 7%, the primary proposal produces greater benefits than were calculated by Xcel Energy in its July 2002 filing.

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MERCURY

The issues related to mercury control discussed on October 2 are new to the record. Mercury Control Technology The Clean Air Act amendments of 1990 required EPA to conduct an analysis of power plant emissions to determine whether their hazardous air pollutants (HAPs) needed to be regulated. EPA completed the study in December 2000, announcing that of utilities’ HAP emissions, mercury was the pollutant that needed to be regulated. EPA announced that it would propose a utility mercury control standard by December 2003 and promulgate a final standard by December 2004. Utilities would need to be in compliance with the standard by December 2007. Because the database available to EPA in December 2000 to further investigate technical controls was of questionable quality, after the rulemaking announcement, EPA ordered an Information Collection Request (ICR). The ICR required many coal-fired facilities to conduct coal analyses for mercury, and some utilities to measure mercury emissions from boiler stacks. From the ICR, EPA determined that power plants are the single largest anthropogenic release of mercury to the atmosphere in the United States. The industry emits 96,000 pounds of mercury (48 tons) each year. Department of Energy (DOE), EPA, the Electric Power Research Institute (EPRI) and utilities individually have committed significant research money to controlling mercury. During public hearings, many statements were made that there is technology available today to achieve 90% removal of mercury from the flue gas at coal-fired boilers. This level of mercury removal is possible when the right kind of coal chemistry, boiler configuration and air pollution controls are in place. Unfortunately in Minnesota, the power industry faces particular challenges in achieving this removal efficiency. Mercury from coal combustion is present in three species: as a particulate, as elemental mercury, and as ionic mercury. Ionic mercury is soluble, so is more easily captured in existing control technologies. It is also the form that is easily removed by ACI. The chemical composition of coal will most likely dictate what form of mercury is released from the boiler. Powder River Basin (PRB) subbituminous coal, the coal predominately burned in Minnesota, has lower amounts of chlorine, mercury and sulfur, and higher amounts of sodium and calcium than eastern bituminous coals. These differences in the coal’s chemistry mean that flue gases have very low amounts of ionic mercury, resulting in very low mercury removal rates. DOE and EPRI research shows that this removal efficiency can be improved somewhat by injecting activated carbon, but even that, at best, has been demonstrated to remove about 70 percent of the mercury released from a boiler’s stack. In cyclone boilers burning subbituminous coal, such as the King Plant and Riverside Unit 8, removal is only 30%.

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Research continues to improve this removal efficiency, looking primarily at methods for converting elemental mercury into ionic mercury so that it can be more easily captured by ACI or control equipment already in place for other pollutants. ACI can be made to work with more exotic, and more expensive, types of activated carbon (carbon impregnated with iodine, for instance), but then presents a much higher long-term operating cost rather than an initial capital investment. Common activated carbon could also be made to work by injecting certain chemicals into the boiler, which is a more likely technology than novel carbons in the short term, and continues to be studied. Additionally, DOE and the industry are looking into other technologies, as well as developing sorbents besides carbon. DOE just this summer announced its funding of a series of mercury control projects, to test at full-scale promising technologies, as well as continue fundamental research into mercury control. When the MPCA was evaluating Xcel’s proposals in late 2002, it was difficult to characterize the likely long-term performance of any technology, and so chose not to address it beyond confirming Xcel’s estimate of mercury reductions. Today there is more information to better state what is likely to be achieved. Even though the MPCA is unable to estimate the cost of mercury control, nor an appropriate emissions limit, the MPCA made sure that Xcel included physical space in their refurbishment project that will allow for easily including activated carbon injection or other novel control schemes at the King plant in the future. See Presentation Slide 43. MidAmerican Energy Permit During the public hearings, mention was made of the air emissions permit issued to MidAmerican Energy for a new coal-fired generating unit. The Iowa Department of Natural Resources issued a permit in June 2003 to MidAmerican Energy to construct a new coal-fired 790 MW generating unit burning Powder River Basin coal in Council Bluffs, Iowa. MidAmerican Energy plans to complete construction by 2007, meaning that full operation of the unit will likely occur in 2008. Because the December 2000 announcement by EPA that mercury emissions from utilities will be regulated under the Clean Air Act, state permitting authorities are required to conduct a case-by-case analysis to determine the maximally achievable control technology for mercury releases from new coal-fired power plants (called a “112(g) determination” because the method for this determination is contained in section 112(g) of the CAA). Once EPA adopts such a standard, this case-by-case analysis requirement disappears. Iowa DNR developed the mercury emissions limits based on the results of trials of activated carbon injection at Wisconsin Energy’s Pleasant Prairie generating station and the trials of iodine-impregnated carbon at Great River Energy’s Stanton Station. The

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construction permit contains an emissions limit for mercury from the facility that requires a mercury removal efficiency of about 82 to 85%, assuming the use of activated carbon injection. The permit contains provisions to allow testing of the new steam boiler unit to optimize performance of any mercury control technology, essentially delaying the compliance deadline of the mercury emissions limit by one year. If a mercury emissions limit was made to apply today to an operating Powder River Basin coal-fired unit, the limit would have to be written to take into account the type of boiler, the coal being burned, the existing air pollution control equipment, and the current level of understanding of mercury control. For a pulverized coal unit like the Council Bluffs unit, the standard would likely require about 70% removal for this type of boiler burning this type of coal, because it is what current data suggests is technically achievable at the type of boiler burning PRB. The removal efficiency would likely be lower for cyclone boilers like the boiler at AS King. Information provided by EPA shows that air pollution controls on cyclone boilers may be expected to remove only about 30% of mercury in the flue gases2. As pointed out earlier, significant national effort in research continues on mercury removal, as well as major federal action to set standards that all utilities must comply with by 2007. These two activities will force improvements in mercury control over time, meaning that until 2008 when MidAmerican must determine effectiveness and optimization of its mercury controls, MidAmerican will be able to incorporate much of this development into its plant to meet the standard. Enviro Scrub At the October 2, hearing, there was discussion of other mercury control technologies that might potentially develop for power plants. One of those technologies is put forward by Enviro Scrub. At the hearing, the MPCA noted that Enviro Scrub appears to be an interesting development for controlling power plant emissions, interesting enough that power producers and researchers are willing to invest in further research. But, it’s current application, performance, cost and other important variables related to air pollution control and impacts on plant operations are unknown, and are not likely to be known for several years at best. Also at the hearing, the MPCA explained that the extremely high removal rates for mercury claimed by Enviro Scrub at the public hearings need further investigation. In particular, the MPCA was concerned that the high removal percentages may relate only to a portion of the mercury that leaves the stack. 2 http://cta.policy.net/epamercury.pdf

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Mercury in Rainfall

The National Wildlife Federation (NWF) released a report in early September of their findings from analyzing rainwater in Minnesota. NWF again demonstrated that mercury found in Minnesota’s lakes and streams is deposited from the air by rainfall. NWF pointed out that, in general, mercury concentrations in rain exceed state and federal standards for mercury in surface water. Since 1995, the MPCA has participated in a national program to measure mercury in rain and snow. The MPCA has found that mercury concentrations in precipitation are extremely variable at a given monitoring site, and it takes literally years of data to obtain a useful average value. For example, the volume-weighted average at a monitoring site at Camp Ripley varied over the years 1999-2001 from 17.0 in 1999, to 11.8 in 2000, to 13.6 in 2001. There is a great deal of variability depending on how much it rains, how much dust is in the air, and where air masses happen to be transported from. NWF measured mercury in rain for only a few weeks at a few sites. It appears that the NWF data are compatible with the longer-term data collected by the MPCA. Mercury Reductions in MN

The MPCA described the efforts of the voluntary mercury reduction initiative in the State of Minnesota, noting that mercury has been successfully reduced in products over the last ten years. This has been mainly a result of product bans, such as a ban on including mercury in paint and a ban on the use of mercury thermometers. Having already implemented these steps to reduce mercury emissions in the state, coal and taconite plant emissions represent an increasingly large percentage of the total remaining mercury emissions in state. Emissions of mercury from power plants increased slightly between 1990 and 2000, due to increased utilization of coal-fired power plants. In 2000, 1554 pounds of mercury were emitted from Minnesota’s energy facilities. The primary MERP proposal represents the next available big step in reducing mercury emissions in the state. By reducing mercury emissions 191 pounds, the primary MERP proposal would, by itself, reduce total mercury emissions in the state from power production by 12%. The alternative proposal would reduce mercury emissions by 14 pounds, or 1%.

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COSTS

HIGH BRIDGE PRIMARY

Since filing its analyses of the Primary and Alternative project costs, the MPCA has continued to track power plant construction activity. During our presentation on October 2, 2003, two projects were mentioned when discussing the reasonableness of the proposed cost of the High Bridge combined cycle turbine (CCT). Faribault Energy was issued its Certificate of Need by the PUC on August 13, 2003. (Docket No. IP-6202/CN-02-2006). This project is a 250 MW natural gas CCT with fuel oil backup. It is an intermediate load plant, designed to operate when the Minnesota Municipal Power Agency needs electricity during medium to high load periods. The PUC order mentions that the plant’s estimated construction cost is $150 million. This results in a generating capacity capital cost of $600/kW, consistent with national estimates of greenfield CCTs, and EIA’s estimate of new CCT construction. Of more relevance is the expected cost for construction at an existing power plant site. The question is whether the High Bridge plant construction, a brownfield project estimated at about $700/kW, is a reasonable capital cost. The MPCA monitors trade journals, as they often report costs when completed projects are announced. In the September 2003 volume of Power, it was reported that Dominion Energy commissioned a 550 MW gas-fired combined cycle plant at its Possum Point Power station near Washington D.C. The project involved shutting down two old oil-fired units (143 MW) and converting two coal-fired units to burn gas, then constructing the 550 MW CCT plant, at a capital cost of $400 million. This brownfield development results in a generating capacity capital cost of $727/kW, which compares favorably to Xcel’s estimate for constructing High Bridge under the Primary Proposal.

BENEFITS

DISCOUNT RATE

At the October 2, 2003, hearing, there were questions about the basis of the MPCA’s proposed use of a lower discount rate to account for the public benefits of emission reductions, in contrast to using a private rate of return that applies to financial investment decisions that might be made by shareholders. The MPCA explained the appropriateness of its discount rate on pages 39 to 40 of the December 2002 filing and on pages 13 to 14 of its May 2003 filing. In addition to the material provided in its prior filings, the MPCA notes that the discount rate of 3% is pervasively used by the EPA in developing regulatory requirements and strategies under the Clean Air Act. The 3% public benefits discount rate was approved for use by the federal Office of Management and Budget in analyzing the benefits of EPA’s recently proposed rule for emissions reductions from nonroad diesel engines,

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which is directed at reducing emissions of fine particles, nitrogen oxides and hydrocarbons (all precursors to formation of ozone and fine particles). Additionally, 3% has been the discount rate chosen by EPA to evaluate the benefits of power plant sulfur dioxide, nitrogen oxides and mercury emission reductions in bills currently pending before the Congress. After presenting the reasons for use of a public benefits discount rate to help quantify the public benefits that would accrue to the community from emission reductions as a result of either of the MERP projects, the MPCA did compare, by way of a sensitivity analysis, that use of this lower discount rate nearly doubles the estimated value of the quantifiable portions of the environmental benefits of the project. MPCA December 2002 Filing, at 40. In clarifying this point, the MPCA notes that few of the substantial environmental benefits of the proposal are actually captured or quantified by use of externality values and the discount rates applied to those values.

COST/BENEFIT ANALYSIS

At the October 2 hearing, the MPCA noted that its cost benefit analysis of the environmental benefits of the proposal that could be directly quantified could be changed based on subsequent corrections to the record in two ways. First, as a result of new cost data provided by Xcel energy in its September 10 filing, the primary MERP proposal is expected to cost less than was originally projected. As a result, the cost bar in slide 37 of the MPCA’s October 2 presentation would decrease. At the same time, the MPCA study in December 2002 did not reflect the fact that the primary MERP proposal would eliminate emissions from High Bridge units 3 and 4, thus increasing the quantifiable benefits calculation of the MERP primary proposal, the second bar shown on presentation slide 37. As the MPCA explained at the hearing, the MPCA did not adjust its study presentation to account for these later-discovered factors, because the revised cost figures provided by Xcel Energy treat a range of various 20 year forecasts of the price of natural gas, including a forecast intentionally biased toward a potential high end range that is not in the currently predicted reasonable forecast range for the future price of natural gas. In addition to there not being a way to accurately predict what scenario will come to fruition, the MPCA similarly noted that it is not possible to articulate what type of power might be generated in the event a high natural gas price scenario lowers the capacity factor utilization of the gas plants for an unknown period of time. The MPCA notes recent legislative initiatives that will boost the production of wind power in the state and require more renewable energy production, as well as provide incentives to develop an integrated coal gasification power plant in the state. In addition, dispatch order and economic dispatch are decisions made instantaneously based on the operating conditions of the entire system, as well as the availability of purchased power on the grid that would be impossible to accurately predict.

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The emissions reduction rider statute specifically directs that the proposed projects are to be evaluated on a “stand-alone basis.” In addition, the MPCA notes that changing or trying to adjust cost benefit analysis to try to factor in unknown future developments in the type of power that will be available in Xcel Energy’s system and on the grid would be too hypothetical. Thus, although some more recently collected data could indicate that the primary proposal had even less cost than it had when originally evaluated by the MPCA, and while MPCA itself has discovered additional significant emission benefits from the primary proposal due to the elimination of High Bridge units 3 and 4, which would remain uncontrolled under the alternative proposal, the MPCA believes that the conservative approach is to continue to utilize the quantitative cost benefit analysis done in the December 2002 filing. In addition, the MPCA further notes that the MPCA does not believe that the current quantification of environmental benefits characterizes even the majority of the expected benefits of the primary MERP proposal.

CARL NELSON STUDY

At the first public hearing held in Northeast Minneapolis on September 3, 2003, Carl Nelson introduced into the record a study he prepared for the city of Minneapolis on the health benefits of converting the Riverside plant from coal to natural gas. The MPCA reported on a similar study by Mr. Nelson on page 45 of its December 2002 filing. The MPCA has reviewed the work of Mr. Nelson. His studies were conducted using similar methods as the other health benefit studies reported by the MPCA in its December 30, 2002 filing, including a study conducted by the U.S. Environmental Protection Agency as an analysis of the benefits of the Bush Administration’s power plant emission reduction legislation – Clear Skies. These studies use an air dispersion model to calculate a reduction in ambient air concentrations of fine particles and then apply health impact data derived from national epidemiological studies. The Carl Nelson Study found a total annual benefit from the fuel switch at Riverside to be $57.4 million. He further found that 70 percent of the benefits occur in Minnesota and one-third occurs in Hennepin County. The MPCA believes that the Carl Nelson Study has value and informs this proceeding on the potential magnitude of the benefits associated with converting the Riverside plant to natural gas.

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U.S. OFFICE OF MANAGEMENT AND BUDGET

On September 22, 2003, the Office of Management and Budget (OMB) in the Executive Office of the President issued a study on the costs and benefits of federal regulations.3 The OMB is charged with reviewing the cost benefit analysis prepared by federal agencies before rules are approved by the White House for proposal. The findings of this report confirm the findings of the fine particle cost/benefits studies discussed by the MPCA on pages 43-46 of the December 2002 filing. The OMB’s finding was not just that Clean Air Act rules limiting particulate matter, SO2 and NOX are extremely cost effective. The report actually credited the Clean Air Act rules with providing most of the benefits experienced across the federal government in its rule makings over the last ten years:

It is important to note that of the 107 rules received by OMB over the last ten years, four EPA rules-two rules limiting particulate matter and NOX emissions from heavy duty highway engines, the tier 2 rule limiting emissions from light duty vehicles, and the Acid Rain rule cited above [limiting sulfur dioxide emissions] – account for a substantial fraction of the aggregate benefits reported in Table 2. The four EPA rules have estimated benefits of $101 to $119 billion per year and costs of $8 to $8.8 billion per year. The aggregate benefits and cost for the other 103 rules are $41 to $107 billion and $29 to $34 billion, respectively. OMB Study at 8.

As the MPCA noted in its discussion of trying to quantify the benefits of fine particle reduction, the OMB also noted that it is difficult to translate scientific evidence into precise benefit estimates. The OMB study also recites the cost benefit analysis for reducing particulate matter and nitrogen oxides from non road diesel engines that was proposed earlier this year. That cost benefit analysis documented that at a cost of $192 million per year, the nation would achieve $410 million per year in reduced engine operation costs, as well as $900 million to $7.8 billion in air quality benefits. The OMB study also references that EPA listed a variety of other benefit categories that it was not able to quantify. OMB Study at 13. This study, which shows the large benefit of rules designed to reduce particulates, sulfur dioxide and nitrogen oxides, supports the conclusions reached by the MPCA in its evaluation of the significance of the benefits that could be realized by the reduction in emissions of the precursors of fine particulate formation by the MERP primary proposal. In the MPCA’s December 2002 filing, the MPCA restricted its analysis to similar cost/benefit studies that have taken place with regard to power plant emissions in particular, while the OMB study includes emission control rules for both power plants and vehicles.

REGULATORY ISSUES

3 This study is available at www.whitehouse.gov/omb/inforeg/regpol-reports

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NEW SOURCE REVIEW

There was a question raised about the impact of recent changes to EPA’s federal New Source Review program on the MPCA’s evaluation of the primary and alternative MERP proposals. At the hearing, the MPCA stated that those recent changes do not impact its study of the MERP. The only concept brought into the Minnesota emission reduction rider statue from the federal New Source Review program is that a project qualifies under the statue if it applies “best available control technology” (BACT). BACT is a term of art under the federal New Source Review program. The way that BACT analysis is applied to evaluate proposed controls at a facility is fully explained on pages 7 -8 on the December 2002 filing and pages 6-7 of the May 2003 filing. The important concept is that the Minnesota emission reduction rider statute uses the established concept of BACT as a level of control technology that will qualify a project that is proposed under the statute. The statute does not import for consideration any other aspect of federal New Source Review. The changes to federal New Source Review did not alter the definition of what is “best available control technology” under the New Source Review program. For this reason, the MPCA’s analysis is not affected by recent changes to that federal rule.

CLEAN AIR ACT ISSUES The federal Clean Air Act is a complex regulatory act that has been put together in repeated enactments of Congress over the last thirty years. As a result, the Clean Air Act is a collection of different programs, often formed from different policy approaches that can affect emissions of industries in different ways. It is thus an estimate at best to try to predict what each of the individual programs in their current state or their future evolution will ultimately require of power plant emission reductions. For example, because they constitute established and understood standards for levels of pollution control technology, the Minnesota Legislature borrowed the concepts of best available control technology under the New Source Review Program, and New Source Performance Standards control technology-based limitations from a different program, to fashion the qualification standards for projects under the state emission reduction rider statute. At the same time, there are programs under the Clean Air Act to: 1) address acid rain that are specifically directed at power plant emissions, 2) address regional haze, that are going to be directed at power plant emissions and other sources of emissions, and 3) implement the new national ambient air quality standards for ozone and fine particles, which will seek reductions from power plants, motor vehicles and other industries to reach attainment of the standards. There are also provisions of the Clean Air Act that govern the interstate transport of air pollution that allow states that receive air pollution from

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other states to petition for required reductions in the upwind states in order to secure the air quality of the downwind states. In addition, because all of these programs affect emissions from power plants, there are several proposals pending before the Congress that seek to limit overall levels of emissions from the power sector in lieu of the existing, somewhat independent programs. The Minnesota emission reduction rider statute uses established terms of art to reflect control technology levels as a threshold under the statue. After that, the statue directs that the MPCA evaluate the environmental benefits of any proposal that is brought forward under the statute and report on the expected benefits to be achieved by the emission reductions. In its report, therefore, the MPCA focused on the pollutants that would be reduced by the primary and alternative MERP proposals, and their environmental and human health impact. These pollutants are: sulfur dioxide, nitrogen oxides, course particulate matter (PM 10), fine particulate matter (PM 2.5), mercury and carbon dioxide. The MPCA stands ready to assist parties to understand the regulatory framework of the Clean Air Act and Minnesota state air pollution control law that the MPCA is charged with implementing. In addition to potential developments that affect power plants, the EPA and the MPCA are engaged in a multitude of different pollution control initiatives that affect vehicles and that affect levels of pollution in other industrial sectors. Reducing the large emissions from grandfathered power plants is absolutely key to the MPCA’s overall reduction strategy.

CONCLUSION

The MPCA prepared this supplemental filing in order to properly record additional information and explanation that it presented at the October 2 informational meeting. The MPCA hopes that this additional information is helpful to the PUC and to other parties in understanding the basis for and import of the MPCA’s study of the environmental benefits of the Xcel primary MERP and alternative MERP proposals and the MPCA’s recommendation that the primary MERP proposal be approved.

Review of Xcel�s Metropolitan Emission Reduction Proposal

and AlternativeOctober 2, 2003

2

Engineering review of MERP

! Process for reviewing technical aspects of MERP

! Results of assessment of air pollution control devices

! Results of capital costs review

3

Qualifying projects must…

! Have “best available control technology” (BACT)

! Have controls substantially better than New Source Performance Standards (NSPS)

! Lowest cost-effective level if not cost-effective to meet BACT or NSPS

4

Selective catalytic reduction for NOx

5

Spray dryer/fabric filter

www.niro.com.au/prod-spray-dryer-absorb.htm

6

Fuel choices and pollution control devices

CoalSD/FF

GasSCR

Riverside

CoalSD/FF

GasSCR

High Bridge

CoalSCR/SD/FF

CoalSCR/SD/FF

AS King

AlternativePrimary

7

AS King emission rates

00.20.40.60.8

11.21.41.6

NOx SO2 PM10

Pollutant

lb/m

mbt

u

Current Emissions NSPSMedian of BACT King Emissions, MERP

8

High Bridge emission rates

00.10.20.30.40.50.60.7

NOx SO2 PM10

lb/m

mbt

u

Current Emissions, HB 5 Current Emissions, HB 6NSPS Median of BACT HB, CCT

9

Riverside emission rates

00.20.40.60.8

11.21.4

NOx SO2 PM10

lb/m

mbt

u

Current Emissions, Riv 6/7 Current Emissions, Riv 8NSPS Median of BACT Riv, CCT

10

Primary project qualifies

! Conclude that for each plant, proposal meets BACT

! Because BACT proposed, no further analysis needed

11

High Bridge alternative emission rates

00.20.40.60.8

11.21.4

NOx SO2 PM10

lb/m

mbt

u

Current Emissions, HB 5 Current Emissions, HB 6NSPS Median of BACT HB 5, 6 Alt

12

Riverside alternative emission rates

00.20.40.60.8

11.21.4

NOx SO2 PM10

lb/m

mbt

u

Current Emissions, Riv 6/7 Current Emissions, Riv 8NSPS Median of BACT Unit 6/7Riverside 6/7 Alt Median of BACT Unit 8Riverside 8 Alt

13

NOx NSPS

0123456

NOx

lb/M

wh

NSPS

HB 5,6 alt

Riv Unit 6/7 alt

Riv Unit 8 alt

14

Alternative project qualifies

! High Bridge does not meet BACT —not NSPS, but is cost-effective

! Riverside alternative does not meet BACT, NSPS

! Adding SCR to Unit 8 would be cost-effective under NSR

15

Capital cost review

! Budgetary estimate (+/- 30% of final project cost)

! Compare to real projects — Minnesota projects if possible

! Use EPA cost-estimate tools or national databases

! Engineering judgment! Xcel proposes cost review of actual costs

in PUC rate rider oversight proceedings

16

AS King capital cost estimates — $/kW

0

200

400

Xcel EIA/EPA CUECost

Source of Estimate

Cos

t per

kW

for

Con

trol

SD/FF

FF

SD

NOx

17

High Bridge site plan

18

High Bridge capital cost estimates — $/kW

200

700

Xcel EIA--Outlook 2002 Faribault Energy

19

Riverside capital cost estimates — $/kW

200

300

400

500

600

Xcel Riverside Xcel Black Dog

20

Capital cost conclusions

! Xcel-estimated capital cost of King, Riverside are within reasonable range, both on a national- and statewide-scale

! High Bridge construction cost is higher than national average for greenfieldsites, but acceptable for brownfieldsites

21

High Bridge alternative capital cost — $/kW

050

100150200250300350

Xcel EIA/EPA CUECost

$/kW

NOx/SD/FF

FF

SD

NOx

22

Riverside alternative capital cost — two projects

! Unit 6/7▌ Rehab existing air

pollution control devices, low NOxburners

▌ Total capital cost: $26 million

▌ Reasonable based on engineering judgment

! Unit 8

0

100

200

300

400

500

600

Xcel Unit8

EIA/EPA CUECost

$/kW

NOX/SD/FFFFSDNOx

23

Capital cost conclusions

! Project estimates are reasonable

24

Health and environmental problems with power plants

! Fine particulate matter (PM2.5) (SO2, NOx)! Coarse particles (PM10) ! Ozone (O3) (NOx VOC)! Mercury (Hg)! Regional haze (SO2, NOx)! Lead (Pb)! Greenhouse gases (CO2)! Acid Rain (SO2, NOx)! Localized impacts

25

Statewide sulfur dioxide emissions

26

Statewide nitrogen oxide emissions

27

Statewide mercury emissions

77%

Other point sources77%

Area and mobilesources

16%

Riverside3%

A.S. King2% Highbridge

2%

28

Effect of grandfathering on emission rates

29

Top SO2 sources in Minnesota

SO2 emissions (in tons per year, 2001)

SHERCO

Clay B

oswell

Riversi

de

High B

ridge

Black D

og

Flint H

ills

Hoot L

ake

Silver

Lake

0

5,000

10,000

15,000

20,000

25,000

A.S. King

EVTAC

30

Top NOx sources in Minnesota

NOx emissions (in tons per year, 2001)

SHERCO

A.S. K

ing

MinnTac

Riversi

de

Clay B

oswell

Black D

og

HibbTac

High B

ridge

Flint H

ills0

5,000

10,000

15,000

20,000

25,000

Keewati

n

31

Top mercury sources in Minnesota

Mercury emissions (in pounds per year, 2000)

32

Comparison of emission reductions

tons

per

yea

r

! SO2 and NOx emission reductions

33

Comparison of emissions reductions

0

50

100

150

200

250

Mercury emissions

Current Primary MERP MERP Alternative

! Mercury emission reductions

34

Comparison of emissions reductions

! PM10 emission reductions

35

Comparison of emission reductions

! CO2 emission reductions

0

1,000,000

2,000,000

3,000,000

4,000,000

5,000,000

6,000,000

7,000,000

Current Primary MERP MERP Alternative

CO2 emissions

36

Cost and benefit calculations! Used Xcel’s cost numbers (extended to

2034)! Used Xcel’s benefit estimate with PUC

externality values (NOx, CO, PM10, CO2, Pb)! Extended time period for estimating costs

and benefits from 2020 to 2040! Applied EPA’s Science Advisory Board

recommended 3% discount rate to the environmental/health benefits

! Included Xcel’s estimates of avoided costs for new generation and refurbishing plants

37

Comparison of costs and quantified benefits

38

Cost comparison

! Costs minus avoided costs

39

Unquantified benefits! Fine particles! Sulfur dioxide! Reduced emissions of:

▌ mercury and other bioaccumulative metals▌ pollutants contributing to acid rain, ground-level

ozone and regional haze

! Fewer local impacts from truck/rail traffic and ash disposal

! Reduced need to develop new energy generation sites and transmission lines

40

Other benefit studies

! Clear Skies Initiative (U.S. EPA)

▌ Nearly $18 benefit for every dollar spent to reduce power plant emissions

! Riverside Plant (Nelson)

▌ $57 million in benefits per year

▌ 70% in Minnesota

▌ One-third in Hennepin County

41

Cost – benefit conclusions

! Quantified benefits of the project are equal to and likely exceed the project cost

! Benefit calculations significantly underestimate the health benefits –primarily of PM2.5

! Primary proposal is more cost-effective than alternative

42

43

ESP/baghouseScrubber

CoalCleaningFuel Switchingfuel additives

BoilerCoal

Sorbent/ChemicalInjection

Fixed, fluid beds, plates, honeycombs

Stack

Mercury Control OptionsFilter/Polisher

Catalyst, fixed/fluid beds, corona discharge

Attachment 2

1

CLOSING COMMENTS FROM

OCTOBER 2, 2003 MPCA INFORMATIONAL HEARING

ASSISTANT COMMISSIONER ANN SEHA

Thank you for being so attentive as we presented our study and for your questions that helped us explain our study even better. As you have seen, MPCA’s study was very detailed and very comprehensive. MPCA’s study reflects the latest developments in the science of health and environmental pollution impacts and in the engineering of control equipment technologies. To conclude the presentation of the MPCA study, I will spend a few minutes on our recommendation to you on the appropriateness of the project, which was a required element for MPCA to report on under the emissions reduction rider law. To start, I’ll circle back to the statute. The Legislature established the emissions reduction rider statute to incent voluntary proposals by utilities at the locations of existing grandfathered power plants. The Legislature wanted these projects to yield excellent reductions so it set high standards for projects to qualify, and asked the MPCA to study and verify the qualification of any projects that might be proposed under the statute. Second, the Legislature wanted to know the benefits of any proposed project, and so asked the MPCA to study the benefits of the projects and report its findings to the Public Utilities Commission. Third, the statute was meant to encourage reductions beyond requirements. That is why the statute focused on the grandfathered power plant sites, and disqualified projects from the rider if they were required by new standards or corrective action. It is important to note that the primary proposal is Xcel Energy’s preferred approach under the statute. The MPCA study of the primary proposal confirmed that the pollution control proposed on all three plants utilized the best available control technology for each pollutant. The MPCA study also found that the primary proposal has quantifiable benefits that equal or exceed the cost of the project, plus numerous unquantified benefits. This is particularly true with regard to fine particles (PM2.5). Studies conducted nationally on control of pollutants that contribute to fine particles repeatedly show large benefit from implementation of the reductions in relation to their cost. Therefore, the MPCA has found that the primary proposal fully meets the statutory test under the emission reduction rider statute and should be approved. The MPCA has also done work to compare the primary and alternative proposals, and I now want to move into presenting MPCA’s conclusions based on MPCA’s study of both. I will not repeat the details that Ms. Jackson and Mr. Thornton have given you, but I will offer conclusions from their data.

2

Emissions comparison. As Mr. Thornton’s slides depicted, the primary proposal provides greater reductions of pollution across the board than the alternative proposal. The primary proposal provides significantly more reduction in key pollutants that contribute to fine particle formation, particularly nitrogen oxides (NOX). The primary proposal provides significantly greater reductions in coarse particulate (PM10). Finally, the primary proposal provides significantly more reductions of mercury. Technology comparison. The MPCA’s study found that all controls proposed in the primary MERP proposal meet requirements for best available control technology. The alternative proposal, however, does not meet best available control technology requirements for NOX, nor does it meet the less stringent new source performance standards for NOX. The MPCA examined whether the NOX controls at the High Bridge and Riverside plants meet the catch all, least stringent, cost-effectiveness “due to the age or condition of the generating unit” standard under the emission reduction rider statute. The MPCA concluded that the projects met this standard but did find that the NOX pollution control equipment proposed for Riverside unit 8 was close to not qualifying. It is not surprising to find less capable control technologies in retrofit projects. In general, reconstruction projects, or construction of new units, as is proposed in the primary proposal, allow a company the ability to design a project to reach best available control technology at less cost than when retrofitting an existing unit. Finally, the alternative proposal proposes no control technology at all on High Bridge units 3 and 4, while those units are eliminated in their entirety in the primary proposal. These units emit a large amount of coarse particulate (PM10). Benefits comparison. The calculations of benefits that were displayed by Mr. Thornton reflect directly the emissions differences between the primary and alternative proposals. The primary proposal has much greater emission reductions, both because its reconstructions allow the cost-effective installation of better pollution control technology and because of differences in the chemical composition of the proposed fuels. The primary proposal has quantifiable benefits equal to or greater than its cost, while the alternative proposal has quantifiable benefits that do not reach its cost levels. The MPCA notes that both proposals have large unquantified benefits, as explained by Mr. Thornton, especially regarding PM2.5. The MPCA notes, however, that the primary proposal would have greater benefits regarding PM2.5 due to its much larger reduction of NOX emissions. In addition, the primary proposal eliminates fugitive dust from coal handling at two population centers, while the alternative does not.

3

When quantified in national studies, the cost effectiveness of large reductions in fine particle precursor pollutants has been demonstrated repeatedly. A recent study by the Office of Management and Budget (OMB) summarized the results of several significant Clean Air Act rule makings directed at reducing sulfur dioxide, nitrogen oxides and particulate matter nation wide, finding that the Clean Air Act rules were far and away the most cost effective rules of those studied by the OMB. OMB’s study included rule making across many federal agencies, not just the Environmental Protection Agency. The OMB study found that recent rules reducing particulate matter and nitrogen oxides from heavy diesel engines, reducing emissions from passenger vehicles, and reducing sulfur dioxide emissions a decade ago under the acid rain provisions of the Clean Air Act cost between $8 and $9 billion a year while achieving benefits of $101 to $119 billion a year. These findings on previous rule makings were reaffirmed this year with the OMB’s approval of the cost/benefits study for the proposed rule regulating emissions from non road diesel engines. Under that rule, the EPA calculated a cost of $192 million a year nation wide, achieving a benefit of between $900 million and $8 billion a year. Cost per ton of pollutant removed. The MPCA also made calculations to try to estimate the cost per ton of pollutant removed by the primary and alternative proposals. The MPCA calculates the cost per ton of pollutant removed to allow comparison among different industrial sectors, including the power production sector, of different control strategies. In addition, the MPCA, under EPA rules, uses the cost per ton of pollutant removed to decide whether controls can be cost effectively employed in a new facility that is trying to obtain a permit. Generally, pollution controls are found to be cost-effective unless their cost exceeds $6,000-$10,000 per ton of pollutant removed, depending on the pollutant being evaluated. The MPCA found a low cost of pollution control for the primary MERP proposal. The midpoint of the range of cost per ton of pollutant removed from the primary MERP proposal is $688 per ton, while the mid range of cost per ton of pollutant removed for the alternative project is $830 per ton. This is another measure of the relative cost effectiveness of the primary proposal over the alternative, due to the larger reductions achieved by the primary proposal. The MPCA also notes that the low cost of pollution reductions from these plants per ton of pollutant removed relative to other industrial sectors, reflects the fact that this industry has been grandfathered and has not yet had to put in these kinds of controls, leaving huge reductions available and making the reductions less costly to achieve.

4

Conclusion. In sum, the MPCA studies found that the primary MERP proposal, in comparison to the alternative, will achieve significantly lower levels of harmful emissions, even as it adds 383 MW of new capacity to Xcel’s system and fully refurbishes to new quality 1100 MW of capacity. The alternative proposal, on the other hand, has significantly higher emissions of key pollutants than the primary proposal, only adds 60 MW of capacity to the system and only refurbishes 500 MW of capacity. As Mr. Thornton showed, if you factor out the avoided cost of new capacity and refurbishments, the cost differences between the two proposals shrink substantially. As a result, while the cost of the alternative proposal is less than that of the primary proposal, the primary proposal has substantially greater benefits. In a comparison, the primary MERP proposal is more cost effective for the rate payer. Finally, I want to offer information on how the proposals compare in relation to current air quality standards, and rules required over the next ten years under the existing Clean Air Act and expected new laws. Due to the health impacts that have been demonstrated, the efforts to reduce power plant emissions all recognize the need for very large reductions of multiple pollutants emitted by the nation’s old grandfathered power plants. These efforts will be made either piece-meal, through multiple regulations required by the Clean Air Act, or comprehensively, in multi-pollutant legislation that reduces power plant emissions across the board. Whatever path is chosen, all expected trends point to very large NOX reductions and very large mercury reductions. The MPCA evaluated the primary MERP proposal with expected developments in mind, and found that all three plants should meet the expected standards that will be developed over the next 1 or 2 decades, except that mercury controls are expected to be needed at the King Plant. The alternative proposal has the same issue regarding the King Plant on mercury, because the proposals are identical in this respect, but mercury control could also be an issue with the Riverside and High Bridge plants under the alternative proposal. It is very likely that selective catalytic reduction will ultimately be required on Riverside Unit 8 to control NOX, even though that control technology is not part of the alternative proposal. The MPCA therefore concluded that the alternative project does pose a higher risk of more future costs to comply with future standards than does the primary proposal. This forward-looking aspect of the primary proposal gives it a significant advantage over the alternative proposal. I thank you for all of your attention to this matter, and appreciate your invitation to present our study to you today. The MPCA would be happy to provide further explanation of the study as needed to help the Public Utilities Commission evaluate this matter. Thank You.