ML100840642

Feasibly Study for Conversion of Prairie Island to Natural Gas Fired Generation. Submitted with Comments on Draft Generic Environmental Impact Statement for Prairie Island Nuclear Generating Plant, Units 1 and 2, Supplement 39 to NUREG- 143

ML100840642
Person / Time
Site:	Prairie Island
Issue date:	11/20/2002
From:	Utility Engineering Corp
To:	Office of Nuclear Reactor Regulation
References
NUREG-1437
Download: ML100840642 (61)

Text

IC7---77777 Feasibility Std, for Conversion of Prairie Island to Natural Gas Fired Generation

'UTILITY ENGINEERING November 20, 2002 I

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BEFORE THE MINNESOTA PUBLIC UTILITIES COMMISSION Gregory Scott Chair Edward A. Garvey Commissioner Marshall Johnson Commissioner I LeRoy Koppendrayer Commissioner Phyllis A. Reha Commissioner

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In the Matter of a Petition of Northern States ISSUE DATE: February 13, 2002 Power Company dba Xcel Energy for Review of the Prairie Island Contingent Request for Proposals DOCKET NO. E-002/M-0I-1480 In the Matter of Northern States Power DOCKET NO. E-002/RP-00-787 Company's Application for Approval of its 2000-2014 Resource Plan ORDER DIRECTING ANALYSIS OF NATURAL GAS CONVERSION OF PRAIRIE ISLAND UNIT I AND REQUIRING CONSULTATION PROCEDURAL HISTORY On August 29, 2001, the Commission issued its ORDER APPROVING XCEL ENERGY'S 2000-2014 RESOURCE PLAN, AS MODIFIED in this matter. In its Order, the Commission accepted an agreement proposed by several parties, including Xcel, under Xcel would provide a kiatus report on the issue of the fairness of its. bidding process to renewable resource generation by July 15 and propose a Request for Proposals (RFP) to the Commission by September 30. In Order Paragraph 9, the Commission directed Xcel to abide by its agreement to propose an RFP by September 30, 2001.

On September 28, 2001, Xcel submitted a letter to the Commission. In its letter, Xcel stated that it would submit an RFP for the Prairie Island contingency bid for regulatory review on October 1 but requested an additional 30 days to submit its all-source bidding RFP.

On October 1, 2001, Xcel filed an RFP for the Prairie Island contingency bid and filed a 2001 All-Source RFP on November 8, 2001.' This Order focuses on the Prairie Island contingency bid RFP filed October 1, 2001.

Issues raised by the Minnesota Department of Commerce (the Department) regarding Xcel's failure to file its All-Source bid by October 1, 2002 and failure to make a timely request for permission to file it at a later date were addressed in a previous Order in this matter: ORDER DENYING REQUEST FOR ORDER TO SHOW CAUSE AND REQUIRING REPORT, INFORMATION, AND CONSULTATION, Docket No. E-002/M-00-622 (February 11, 2002).

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During the 30-day review and comment period for the Prairie Island contingency bid RFP,2 no party filed objections to the RFP or requested an investigation. The Department and the Company identified modifications to the RFP, however, and Xcel filed a finalized RFP on November 8, 2001.

On December 3, 2001, Xcel conducted the pre-bid conference at its offices in Minneapolis.

On January 4, 2002, the Izaak Walton League of America (IWLA), Citizens United for Renewable Energy (C.U.R.E.), and Minnesotans for an Energy Efficient Economy (ME3) filed a letter noting that the Company's RFP does not mention the option of converting Unit 1 of the Prairie Island facility to natural gas. These parties requested that the Commission order the Company to notify potential bidders of its desire to consider bids for natural gas conversion of Unit 1 in this RFP.

The Commission met to consider this matter on January 31, 2002.

FINDINGS AND CONCLUSIONS Two unfortunate things have occurred. First, in its Prairie Island contingency bid RFP (invitation to submit bid to replace the energy currently provided by its Prairie Island nuclear plant), Xcel did not explicitly open the door to proposals to convert Unit 1 into a gas-fueled generator. The possibility of gas conversion is a logical option for consideration. Second, no party objected to this omission and the bid process has moved ahead.

At this point, the Commission will not interrupt the bid process or require the Company to notify potential bidders of its desire to consider bids for natural gas conversion of Unit 1, as requested by IWLA, C.U.R.E., and ME3. At this stage of the process, this would pose an unwarranted risk of sending an unsettling signal to the potential bidders.

In order to have adequate information in the record to thoroughly examine the options, however, the Commission will secure a detailed analysis of converting Prairie Island Unit 1 to natural gas-2 Step 2 of Xcel's Commission-approved bid process is as follows: NSP will file a proposed Request for Proposals (RFP) with the Commission and serve it on the Parties.

Absent a request for investigation by any party, NSP may issue the request for proposals (RFP) to potential bidders 30 days after the filing without Commission approval. See In the Matter of the Petition of Northern States Power Company for Review of its 1999 All Source Bid Request Proposals, E-002/M-99-888, ORDER GRANTING INTERVENTION (September 29, 2000), pages 1-2 and ORDER REJECTING REQUESTS FOR FURTHER INVESTIGATION, APPROVING FINAL BID SELECTIONS, AND OPENING DOCKET REGARDING EXTERNALITY VALUES .(February 7, 2001), pages 1-2.

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filed generation. Having a reasonable estimate of the costs and benefits of conversion will allow the Commission to compare them with the costs and benefits of bids received through the contingent bid 'process.

Two practical questions arise:

1) who should perform the conversion analysis/report: the Company or an independent entity retained by the Company and

2) when should the report be submitted to the Commission: at the time Xcel files its short list of bidders, about July, 1, 2002, or when it files its next resource plan, December 1, 2002?

On the timing question, the Commission's concern is not to receive the conversion information so late in the bid process that conversion would be precluded as practical matter. All parties assure the Commission, however, that submission on the later date would not preclude the conversion option. Since a later submission date may yield a more thorough analysis, the Commission will designate the later date, December 1, 2002.

As to who should perform the analysis, the Commission's initial inclination for an independent evaluator was based in its concern that the integrity of an analysis conducted by Xcel would certainly be subject to question. IWLA, C.U.R.E., and ME3, however, expressed their confidence in or acceptance of the Company doing the study, noting that the study will have to stand on its own merits in any event and that any independent evaluator would be selected by the Company and would need to rely substantially on the Company's information in making its analysis, diminishing the value to be gained from requiring an independent contractor.

Finally, IWLA, C.U.R.E., and ME3 requested and the Company agreed that the parties should meet to discuss scoping issues, i.e. what the conversion analysis/report should contain. The three parties stated, for example, that the generation costs should be segregated from the plant decommissioning costs. The Commission agrees that this kind of discussion is a good idea and will so order. The parties may find it beneficial to include the Department in these discussions.

ORDER

1. Xcel shall perform and submit a detailed analysis (report) of converting Prairie Island Unit I to natural gas-fired generation.

2. The Company shall meet with the parties (IWLA, C.U.R.E., and ME3) to discuss the scope of its conversion analysis (report).

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3. The Company shall file its report (conversion analysis) by December 1, 2002, the date set for filing its next resource plan,

4. This Order shall become effective immediately.

BY ER OF THE C MMISSION Burl W. Haar Executive Secretary (S E A L)

This document can be made available in alternative formats (i.e., large print or audio tape) by calling (651) 297-4596 (voice), (651) 297-1200 (TTY), or 1-800-627-3529 (TTY relay service).

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THE IzAAK WALTON.

Dr. Burl Haar Executive Secretary Minnesota Public Utilities Commission . .

350 Metro Square Building .. -

1217' Place East St. Paul., MN 55101-2147..

Re:. Northern States Power Company 2001 Prairie Island Contingency Request for Supply. Proposals for Contingencies in 2007 and 2008 Docket,#: E-002/RP-00-787

Dear Dr. Haar:

You may recall the discussion of contingency bids. for replacement. power for Prairie Island at the final hearing on Xcel Energy's (Xcel or Company) .2000-2014 .Integrated Resource Plan. During this discussion, in conjunction with Xcel's proposal to replace the steam generator in Unit lin 2004, Chair Scott raised the6question of including a bid for c.onversion of Unit 1 to natural gas as part "of the bidding process.. The. question was addressed to Mr. Alders who replied that Xcel could not bid on its 'own plant, -so an independent bid would have to be submitted. He indicated that a transferof assets would have to take place .if the bid were pursued. Howerver, he did not indicate any major problem with. the option at the bidding level. We note that gas .conversion of Unit 1 was not mentioned in the Company's recently released 2001 Prairie Island Contingency Request For Proposals. We wish to bring the timeliness of exploring this option to your attention for the following two reasons:

I). Unit 1 will fall below acceptable capacity, according to Xcel, in the 2004 to replace the steam generator at that time.

timeframe. The have Several parties concerns isabout the timeliness of such an investment, raised proposal Company's due to lack of resolution of waste storage and other factors. The Commission.

chose not to approve steam generator replacement in the 2000-2014 IRP.

2) Conversion of Unit 1 could. impact the costs and risks of decommissioning in 2007, precluding appropriate resolution of waste storage issues.

The Company has acknowledged that the location of the Prairie Island plant is important electrically to Xcel's system. In statements made to CURE by Goodhue County officials, the Company has been clear with the County that the plant- is too valuable to close and that Xcel would likely convert the plant to. another fuel source'rather than close it NATIONAL OFFICE ThE WJ I1.W MIDWEST OFFICE 707 Conservation Lane 1.; 1619 Dayton Avenue, Suite 202 Gaithersburg, Mar'land 20878-2983 St. Paul, Minnesota 55104-6206 Phone: (301) 548-0150 Phone: (651) 649-1446 Fax: (301) 543-0146 Fax: (651) 649-1494 E-mail: generai@iwla.org fMS E;3 E-mail: midwestoffice@iwla.org www.iwla.org .

Printed on Process Chlorine Free Paper

CURE submitted an information request to Xcel during the IRP process regarding this conversion plan, and asked also for a list of nuclear facilities that have been converted to natural' gas. Xcel's response to this information request was delayed until the day after final comments were due, several months later. CURE submitted the conversion section of the Appel report to the Electric Energy Task Force (@1997) in lieu of having information from Xcel. This section by Ron Sundberg, a local engineer specializing in conversion technologies, confirmed that it is-technically possible to convert the 500 MW Unit 1 to a double turbine steam generator powered by natural gas, and gain efficiency and output to make up most of the 1000 MW's of both units. In addition, the conversion could feasibly utilize, in part, the existing equipment and might include a district heating benefit to local communities.

The Prairie Island Indian Community and Department both raised concerns about moving forward with steam generator replacement for Unit 1 in 2004. We further note that investigation of any alternative configuration of generation at that site would help the Company and the Commission to evaluate options for the future. For these reason we recommend that the Company be required to notify potential bidders of its desire to consider bids for natural gas conversion of Unit 1 in the instant RFP.

Respectufullyy Wil Grant Kristin Eide-Tollefson Michael Noble Ditctor C.U.R.E. Executive Director Izaak Walton League of America Minnesotans for an Midwest Office Energy Efficient Economy

-- Non Public Document - Contains Trade Secret (or Privilejed) Data Public Document - Trade Secret Data Has Been Excised

[ Public Document Northern States Power Company Docket No. E002/RP-00-787 Response To Communities United for Resp. Energy Information Request"No. 7 Date Received: November 15, 2000 Question:

In 1994 there was mention, by NSP, during the legislative session that a conversion plan for Prairie Island existed. No documentation was produced. NSP has told city/county officials in Red Wind/Goodhue County at several junctures over the last 8 years that Prairie Island was too valuable to close and that they would convert rather than close the facility should':the necessity arise. CURE has indicated its interest in conversion technologies in several venues over the last 5 years. We are particularly interested in responses to the following questions:

1) Please identify (not produce) a) The conversion plan which would have been the referent in the 1994 session;_

b) Any requirements for contingency conversion plans for Prairie Island from any permitting or funding agent.

2) Please provide copy of the conversion section of the Appel report to the Electric Eni-gy Task Force and identify additional research or application in addition to the information.

provided in that report known to NSP on the conversion potential of nuclear plants.

3) Please provide a list of nuclear plants that have been converted to other forms of generation for the following categories:

a) Plants converted which were never operational (as nuclear plants);

b) Plants converted which were partially operational; c) Plants converted which had been fully operational.

4) Please explain what conversion NSP may have been referring to in its discussion with Red Wing / Goodhue Co. (testimony provided upon request).

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Response

1) '1,have not been successful in finding any conversion plan that might have been referred to in 1994. NSP did prepare a technology screening study in 1996 that was shared with the Legislative Electric Energy Task Force consultants. The screening study was a high level examination of technology approaches that might be used to repowering the Prairie Island site using natural gas. The results of the study are fairly summarized in the Appel report (Study B, Section 18) We are aware of no requirements for contingency conversion plans for Prairie Island from any permitting or funding agent.

2) Section B8 of the Appel report is enclosed.

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3) a) We are aware of two plants that fall in this category, Zimmer in Ohioj Midland in Michigan.

b) None to our knowledge.

c) Pathfinder(South Dakota-oil); Elk River(Minnesota-coal); Fort St Vrain (Colorado-natural gas combined cycle) Zion (Illinois, transmission support via electric motor drives for the existing generators)

4) We do not know what was being referred to in Red Wing and Goodhue County. If the exchange you are referring to occurred after the 1996 screening work and Appel Report, that work may have been the study work being referred to.

Response By: James Alders

Title:

Manager Regulatory Adm Department: Regulatory Services Telephone: 612 330 6732 Date: March 8, 2001 2

B8 CONVERSION OF NUCLEAR AND COAL PLANTS TO LESS ENVIRONMENTALLY DAMAGING, ENERGY SOURCES Is itfeasible to convert existing nuclearpower and coal-firedelectricgeneratingplants to utilization of energy sources that resultin significantly less environmental damage; if so, what are the short-term and longt.erm costs and benefits of doing so; how do shorteror longertime periodsfor conversion affect the cost/benefit analysis?

Summary Existing coal-fired or nuclear electric generating plants can be adapted to use less environmentally damaging energy sources. Common approaches include replacing the fossil or.nuclear: fueled steam source with a natural gas fired steam generator, or using the waste heat from a gas turbine generator to generate steam that can be used to power the existing turbine generator. Typically, an attempt is made to use the steam turbine/generator and as much of the existing plant as practical.

In some cases it is practical to convert existing coal-fired, generating plants to burn biomass. Some of the benefits of biomass fuel can be gained by cofihing or blending another fuel with the coal. In some situations, it is practical to produ&a-a gaseous fuel that can be burned in an existing boiler, from biomass by using a thermal gasification process.

Biomass fuels are often not competitive 'with fossil fuels in traditional generation plants. When biomass fuel is derived from either wasteior a byproduct there is concern about long-term fuel supply and price instability. Several technologies have been developed that would provide a dependable and consistent source of fuel and thus, over the long term, reduce the cost of electricity produced from biomass fuels. NSP is-presently considering proposals from developers of biomass technologies for electric generation, including Whole Tree Energyrm and gasification combined cycle (see Section BI).

A preliminary design for repowering a coal-fired unit at TVA's Watts Bar plant with the Whole Tree EnergyTM technology was conduci6d in 1992. The estimated capital cost for repowering one 68

CURE- Communities United for Responsible Energy P.O. Box 130 Frontenac, MN 55026 Utility Information Request Date of Request: 11/13/00 No. 7 Due: 11/23 Requested from: Jim Alders

Subject:

Conversion of nuclear facilities In 1994 there was mention, by NSP, during the legislative, session that a conversion plan for Prairie Island existed. No documentation was produced. NSP has told city/county officials in Red Wing!

Goodhue County at several junctures over the last 8 years that Prairie Island was too valuable to close and that they would convert rather than close the facililty should the necessity arise. CURE has indicated its interest in conversion technologies in several venues over the last 5 years. We are particularly interested in responses to the following questions:

1) Please identify (not,produce):

a) The conversion plan which would have been the referent in the 1994 session; b) Any requirements for contingency conversion plans for Prairie Island from any permitting or funding agent.

2) Please provide copy of the conversion section.of the Appel report to the Electric Energy Task Force and identify additional research or application in addition to the information provided in .that report known to NSM on: the conversion potential of nuclearplants.

3) Please provide a list of nuclear plants that have been converted to other forms of generation for the following catagories:,

-1)-Plants converted.whichwere never operational (as nuclear plants);

2) Plants converted which were partially operational; beer fullk operational.

3) Plants converted. which .:had':

4) Please ex'plain whhatconversion NSP may have .been referring to in its discussion with Red Wing /Goodhue Co. (testimo*ny provided upon request).

Conversion of Nuclear and Coal Plants to Less Environmentally Damaging Energy Sources 60 MW unit was $410/kW in 1991 dollars, or about $475/kW in 1996 dollars. The estimated cost of electricity from the repowered plant was about 3.5c/kWh in 1996 dollars.

Repowering The tenn "repowering" is usually used to describe the conversion of an existing plant to a new

.energy source. Technical approaches that could be used to repower electric generating plants in Minnesota are presented in this section. Capital cost estimates and the cost of electricity from the repowered plant are also discussed. It must be emphasized that any costs presented can be used only as a guide. Reliable cost information can obtained only from plant-specific analysis and preliminary design.

Repowering With Natural Gas In the simplest:situation, a coal-fired boiler can be adapted to burn natural gas. The modification would involve securing a source of natural gas, and installing gas burners within the existing coal-fired boiler. In many cases, it ma.ybe necessary to site a new natural gas pipeline specifically for the repowered plant. While this conversion is relatively simple, it is likely that the plant would be derated (perhaps by as muchkas 10%) ince the boiler heat exchanger would not have been designed for the bp ning characteristicsý.ofnaturalgas. Thefuel and ash handling operations in the plant would,be simplified,.but the plant would-now be operating on a more expensive fueL since the costf natualgasgonaBtu basis, canbee~xpected to be 2 to 2.5 times the cost of coal.

In the case of a nuclear plant, the nuclear reactor system could be replaced by new natural gas-fired steam generation equipment.

Natural gas haswide availability, but this must be evaluated in terms of the plant location. It will generally be delivered by pipeline. However, the pipeline must be evaluated in terms of its ability to meet the -needs of the repowered plant in addition to those of the: current consumers. This may require consideration of a new pipeline dedicated to the repowering.

Combustion Turbine Combined Cycles The efficiency of generating electricity can be improved considerably by including a gas-fired combustion.turbine in an existing plant cycle. The combustion turbine is one of the more flexible components in a generation system. When the combustion turbine is integrated with another generation: systerd such as a steam turbine, it is referred to as a combined cycle. In this case, waste heat from the combustion turbine is used to drive a steam turbine generator and thus increase the 69

Conversion of Nuclear and Coal Plants to Less Eaviroumentally Damaging Energy Somures efficiency of the overall system. The overall efficiency of combined cycle plants is now approaching 60% - almost twice the efficiency of a coal- or biomass-fired plant.

The combustion turbine is very similar to an aircraft jet engine"with the addition of a power turbine with a shaft to power an electric generator. Many of the combustion turbines used in industry today are jet engine designs that have been adapted for ladid-bi power generation.

The thermal efficiency of a gas turbine engine is no greaterhan the'efficiency of a coal-fired steam cycle power plant. However, almost all of the energy that is fiot converted into shaft power is rejected as heat in the turbine's exhaust gases. The exhaVtrgl irbm the turbine is relatively clean, high in oxygen and at a temperature of around 1,000T. The heat in the combustion turbine exhaust can be recovered to produce steam by using a heat recovery steam generator (HRSG). In a combined cycle, the steam from the HRSG is used to power a steam turbine generator.

Additional natural gas can be burned in the turbine exhaust to provide higher temperature and pressure conditions for the steam turbine. This is ternied Supl'nna f;iring".

When an existing plant is repowered: using the combined cycle, the steam from the HRSG is used to drive the existing steam turbine. Since this approach*iiaksi of heat that might otherwise be wasted, fththermal efcec is higher :than for astand.,rd, steam cycle plant. The electric genetating capacity of the repowered plant willbe greaterIthbn theoriginal plant when. the gas turbine generator is included. An important consideration in this repowering scheme is matching the design steam conditions of the existing turbine.

The capital cost of a combined cycle generating plant is on*.e oidi'r of $600/kW of installed generating capacity. If significant portions of an existingel~nt 6&&_ utilized in a repowering this cost can be significantly reduced. The cost of electricity produced from a combined cycle plant depends on the cost of natural gas that has been allocated to theýp1it A Minnesota combined cycle plant could produce electricity in the 3/kWh range.

Biomass and Biomass Cofiring In some cases it is practical to convert existing coal-fired generadag plants to bum biomass. Some of the benefits of biomass fuel can be gained by cofiring or blending another fuel with the coal. In some situations, it is practical to produce a gaseous fuel that can-be burned in.an existing boiler, from biomass by using a thermal gasification process.

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Conversion of Nuclear and Coal Plants to Less Environmentally Damaging Encrgy Sourmcs Characteristics of Biomass Fuel Fuel derived from biomass is a potentially renewable resource with fewer environmental impacts than fossil fuels. Biomass contains negligible amounts of sulfur and nitrogen and hence will not contribute significantly to acid rain. Burning biomass fuels produced in a renewable closed-loop cycle can be considered to have no net carbon emissions.

The ash that results from burning biomass such as wood is much easier to dispose of than the ash from coal. The alkaline character of the ash makes it attractive as a soil conditioner and it can often be beneficially spread on crop land.

Electricity produced from biomass is often more expensive than that produced from conventional fuels. Typically, biomass and waste fuels contain less energy per unit mass and: have higher transportation costs than conventional fuels. The chemical, and physical properties of many biomass fuels also reduce combustion efficiency compared to coal or natural gas. Without processing, the properties of 'biomass fuel are not as uniform as those of other commercial fuels.

Using Biomass Fuel.. Directly.

Older plants. that have stoker-fed boilers can often burn wood chips or other processed biomass fuel without.extensive modification. However, this is at the expense of a significant derating of the power plant capacity. The derating results from the lower heating value and high-moisture content of the biomass and might be as much as 301%. Older, smaller coal-fnied plants are the best candidates for repowering with biomass. NSP and Minnesota Power have successfully repowered several such plants with biomass and waste fuels. The capacity of these plants is typically less than 50 MW and the fuel needs match the biomass/waste fuel resource available. If the plant is near the end of its useful life a relatively small additional investment will provide new capacity.

The repowering of an older coal-fired plant is complicated by Federal Clean Air Act (CAA) emission regulations. Because most of the coal-fired boilers in Minnesota were commissioned before the CAA, they are not required to meet the more stringent Federal New Source Performance Standards or the requirements of the Federal New Source Review and are subject only to the state requirements. If the plant is modified to burn another fuel such as biomass, the emission control equipment must be upgraded to meet the federal requirements. Generally, if an older plant is modified to burn biomass, it must meet all of the federal standards, as well as the New Source Review. There are, however some exceptions, including modifying a plant to burn certain waste fuels such as refuse derived fuel (RDF).

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Conversion of Nuclear and Coal Plants to Less Environmentally Damaging Energy Sources 'D Cofiring Often it is practical to blend a biornass fuel with coal in an existing utility boiler. ThIis' tied cofn-ing, and the biomass blended might represent around 5% to 15% of the hearing va;iWue b "the fuel Cofiring is a well-established technology, and electric utilities and industry hav*, d:t, coal-firad boilers to cofire biomass or waste fuels such as wood wastes, tire-derived.ft- (M'PF) and refuse-derived fuel (RDF). Minnesota Pollution Control Regulations allow the c6 -fEas much as 30% by weight of municipal solid waste or refuse-derived fuel. Also, there ke-iidait restrictions on cofiring with biomass such as wood, as long as significant plant modif&Nr1*t+/-e not required.

Cofiring can provide the following advantages:

" A reduction in S.O. and NO. emissions relative to 100% coal firing, , ,.* .

• A lower,incremental capital cost and a higherefficiency compared to a new 11 ý I -

biomass boiler. Also, the variability in fuel composition is less of a problem.. tne im biomnass or waste, fuel is only a fraction of the fuel fired.

" Waste fuels are often less expensive than coal.

• Mixing biomass ash with coal ash provides a more environmentally acceptabI~h*YIE"o Possible disadvantages of cofiring relate to derating of the boiler due to the higher m;A1ure",ntent and reduced heating value of the fuel stream.

Gasification Gasification can be used to produce a gaseous fuel from peat,.coal, wood or other: fio* .cThis ( ""

gaseous.fuel can be burned directly in an appropriate furna, or after processing hee"-

gas can be used to power a combustion turbine or reciprocating engine. Thus, gasiffitgof feedstock is a means of utilizing existing boiler equipment or using biomass to powerWLiise or reciprocating engine. The capital cost of the gasification equipment is a significant* *.t cost of repowering a coal fired plant.

The product of biomass gasification is often referred to as low Btu to medium Btu gasŽ 4t ftmally has a heating value on the order of 100-500 Btu/cubic foot or 10% to 50% of the heig*jvaIbf "

natural gas. Tars/oils and corrosive constituents are also released as part of the gasificon3r- ':.

process. These may be removed by cooling, filtering and otherwise processing the gasp- TI cleaning of the biomass gas reduces the overall efficiency of the process. Often, the moit -

economic approach is to burn the gas directly (dirty) in an appropriate furnace. a. T .*

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Cooversion of Nuclear and Coal Plants to Less Environmentally Damaging Energy Sources Repowering With Biomass Crops Biomass fuels are often not competitive with fossil fuels in traditional generation plants. When biomass fuel is derived from either waste or a byproduct there is concern about long-term fuel supply and price instability. Several technologies have been developed that would provide a

'dependable and consistent source of fuel and thus, over the long tern, reduce the cost of electricity produced from biomass fuels. NSP is presently considering proposals from developers of biomass technologies for electric generation, including Whole Tree EnergyTM and gasification combined cycle (see Section BI).

A preliminary design for repowering a coal-fired unit at TVA's Watts Bar generating plant with the Whole Tree EnergyTM technology was conductedin 1992. This plant consists of four 60 MW coal-fired generating units. All four units started operating in 1945 and the plant last produced-electrical power in 1982. The preliminary design indicated that the plant could be repowered using the WTE technology for a cost of $4l0IkW in 1991 dollars, or about $475 in 1996 dollars, and that the resulting cost of 'electricity from the plant would be around 3.5e/kWh in 1996 dollars.

Another concept that could be usedpto repower an existingplant utilizesa portion of an agricultural crop. In this case alfalfa:is harvested and the stems are used as a fuel after the high nitrogen leaves are converted into a meal product Thus, therelaxe two income streams from the crop.

The portion of the crop used for fuel is converted to a low-Btu gas fuel by a gasification process.

The low-Bra gas is cleaned of impurities so that it can be used as fuel for a gas combustion turbine.

Heat is recovered from the combustion turbine exhaust to make steam for a condensing steam turbine generator.

The cost of a complete 75 MW electric generation facility, including the gas turbine and steam turbine, was estimated at $1643/kW in 1994 dollars. The projected cost of electricity would be 5.2e/kWh in 1994 dollars. This would be $1743/kW and 5.5 ¢/kW in 1996 dollars.

This concept could be used to repower an existing coal-fired plant. The cost would be reduced if the steam turbine generator and plant infrastructue could be used in the repowered plant In the most limited situation, a new fuel processing and electric generation system could be sited at the existing facility. If practical, the repowering system would be designed so that the steam from the HRSG would power the turbine generator from the existing plant. The plant size most suited to this approach would likely have an original capacity of 50 to 75 MW. A 75 MW repowered facilir 73

I I Conversion of Nuclear and Coal Plants to Less Envirounentally Damaging Energy Sources would likely use a 30 MW steam turbine from the existing plant, however, if the original plant size were near that of the repowered plant, it may require less overall modification. An estimate of the cost of repowering a coal fired plant with this concept was made by adjusting the cost estimate for a new plant for the equipment and infrastuctu*re that might be reused from an existing plant It is estimated that the cost of repowering would be around $1,200/kW in 1996 dollars for a 75 MW generating plant. It is likely that the cost of electricity produced would be somewhat less than in the case an entirely new plant Repowering a Nuclear Plant With Natural Gas A nuclear power plant uses a nuclear reactor as a heat source to produce steam that is expanded through a turbine to drive an electric generator. Repowering typically could involve replacing the reactor with a fossil fuel-fired heat source to produce the steam. This steam source could be a conventional fossil-fueled boiler or the heat recovery steam generator on a gas turbine exhaust (combined cycle).

The decision to decommission an operating nuclear plant is very complex and -is discussed separately at the end of this section. An important consideration is the best economic utilization of the plant assets. The lowest cost of electricity would likely result from operating the plant until shutdown is indicated by relicensing or technical requirements. There are other issues that may be importantto a cetificate of need or siting for a repowered plant In the case of the Ft. St- Vrain nuclear station in Colorado, the Public Utilities Commission considered the safety of a natural gas fired plant located at a nuclear spent fuel storage site. The conclusion was that the facility was safe and should be permitted; however, this is an example of the issues that could be considered.

Repowering Schemes A wide range of schemes have been proposed for repowering nuclear power plants. The options range from reusing none of the existing equipment and just using the site and plant infiasmtre as a location for new genron, to including the steam turbine and electric generator in the repowering. The objective in repowering a plant is to use as much of the existing plant as practicaL The amount of existing equipment that can be used in the repowering depends on the technology used in the nuclear plant, as well as the amount of electrical generating capacity that is desired from the repowered facility. The two nuclear plants in Minnesota use different technologies and would thus require very different schemes for repowering.

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Conversion of Nuclear and Coal Plants to Less Environmentally Damaging Energy Sources The Prairie Island reactor is a pressurized water reactor. This technology features a heat exchanger between the reactor and the steam turbine. As a result, the existing steam turbine does not become contaminated from exposure to radioactive material. The Monticello reactor, by contrast, is termed a boiling water reactor. In this case the water heated by the reactor also passes through the turbine as steam, and the turbine does become contaminated. Thus, if the Prairie Island plant were to be repowered,**ntrbine and generator could be included in the operation of new facility. The turbine at the Monticello plant would be contaminated and could not be included.

The existing steam turbine and generator is a valuable asset and would be used if it fits the repowering scheme. The first consideration:is to match the steam conditions of the new steam source to the design inlet conditions of the existing turbine.

Schemes that Might be Used at Prairie Island In the simplest approach, a natural gas-fired steam generator would be designed to produce steam at the required pressure and temperature for the existing turbine. This approach, however, would not provide the most efficient or lowest cost of electric production. Steamnturbines for nuclear plants such as Prairie Island are designed to receive steam at near saturation conditions rather than the higher temperaturie and pressure's-uperheated steam conditions thattarel standard for amodem:

fossil power plant-The approach that would'be likely to produce the lowest cost of-electricity is to use the existing turbine as part of a combustion turbine combined cycle. In:this case the existing turbinewould receive steam from heat that is recovered from the-exhaustof a combustion trbine that also drives an electric generator. This would provide considerably better economics; however, it would also substantially increase the plant electrical capacity.

If the objective of the repowering design is to minimize the production cost of electricity and use as much of the existing turbine equipment as possible, the uldmate capacity of the plant would be as much as 2 to 4 times that of its current output At this capacity, there would be questions of adequate supply of natural gas. There would also be additional generating capacity that may not be needed.

Another approach would be to convert only one of the units at Prairie Island, thus matching the output of the repowered plant to near that of the present plant. In either case, the cost of electricity produced would be greater because of the additional capital investment, and higher fuel cost.

75

Conversion of Nuclear and Coal Plants to Less Environmentally Damaging Energy Sources Schemes that Might. be Used at Monticello The existing turbine in the. Monticello plant would not likely be used in a repowering scheme since it would be contaminated from expostue to.steam produced in the nuclear reactor. The most likely approach tolrepowering would be a new generating plant based either on a combined cycle gas turbine or a new biomass-fueled facility at the present plant location.

Examples of Refueled or Repowered Plants The cost of refueling or repowering a plant is specific to the plant and the design. Examples of plants that have been refueled or repowered are presented in, this section.

Cofiring with Biomass Cofiring is an established technology. There are several very good examples of coal-fired plants that have been modified to allow cofiring with alternative fuels.

EPRIJanalyzed the cofiringof a.200 MW plant with coal and wood- [EPRI 1993] In this case, the plant was.,adapted tobumnapproximately 15% wood waste (measured by heat ontent). The capital cost wasest teddat-$204 ;W in 1991. dollars, or $236/kW in 1996 dollars. It was concluded from the analysis that the breakeven cost for wood, iLe., the cost for the wood fuel where the plant could produce electricity at the same cost as with 100% coal was -$24.22/tor. Thus, the utility would need to receive or be paid $24.22 for each ton of wood burned. This would only be feasible if the.wood: were, a-waste product andi.the cost of alternative disposal such as in a land fill was greater thani$24.22/toa. Thisis generally not the case. Waste wood is typically sold to power plants for $10-20/dry tonplus mansport costs.

The French Island plant is an older 30 MW coal-fired plant located just outside of La Crosse, Wisconsin. In the early 1980s NSP replaced one of the original boilers with a bubbling fluidized bed combustion uit sothat the plant could burnwaste wood. In 1985, NSP in cooperation with La Crosse County developed a joint project to process municipal solid waste into refuse-derived fuel (RDF) to be burned in the modified plant At this time, the other boiler unit was modified so that it could burn RDF. In 1990, the plant burned 68% wood and 32% RDF.

The Red Wing and Wilmarth plants are older NSP coal-fired plants with original capacities of approximately 25 MW. The facilities are located in Red Wing and Mankato, MN. In the early 1980s the plants were adapted to bum RDF from the Metro region processed at the Ramsey/Washington County waste processing facility.

76

Conversion of Nuclear and Coal Plants to Less Environmentally Damaging Energy Sources The Hibbard Plant is an older plant in Duluth owned by Minnesota Power. Units 3 and 4 have not produced electricity since the early 1980s. When the Lake Superior Paper Industries mill on nearby property was constructed, Units 3 and 4 boilers were refurbished and converted to burn a coal gas, wood mix to supply process steam to the paper mill The retrofitted boilers were equipped with electrostatic precipitators for particulate control and were designed to meet applicable New Source Performance Standards for S02, NOx, CO'parziculate and opacity. In additional to the process steam needs of the paper mill, the boilers have the capacity to produce enough steam to generate approximately 30 MW of electricity.

Examples of Combined Cycle Repowering We are not aware of any plants in Minnesota that have been repowered utilizing the combined cycle. In 1990, Minnesota Power hired the consulting firm of Sargent & Lundy to assess the cost and feasibility of repowering the Syl Laskin plant. A large natural gas pipeline traverses MP's service area passing close to the Laskin plant. The pipeline can; be fed-from both Canadian and domestic ýsources of natural gas. The prlimioary design included the reuse of the existing steam turbine/generator set as well as. muchIof the existing fifrastructure. The plant capacity would increase-from about 50MW to 250:M,. ýMPconcludedthat the plant could be repowered for a relatively low. capital cost assu"in

• gpant would otherwise be retired.

In another recent example outside Minnesota, Virginia Power replaced two of its older coal-f'red units with a combined cycle plant at its Chesterfield Station. The original plant had a capacity of 70 MW. The two combined cycle units supply almost 400 MW of capacity, and although they were designed as "intermediate duty units, they have performed well enough that Virginia Power has been using them. as baseload units. The capital cost of the combined cycle conversion was

$600/kW. The costd-natural gas committed to the plant is $2.50/million Btu. This provides a variable cost of electricity of 2O/kWh (cost of capital not included).

Examples of Re.powered Nuclear Plants There are very few examples of nuclearpower plants that have been repowerd, and only one or two that have actuallyrun as a nuclear plant before they were decommissioned and repowered.

This includes plants such as the Midland plant in Michigan that was converted to a natural gas-fired cogeneration plant a'-it was being constructed. None of the repowering examples apply particularly well to either the Prairie Island or the Monticello plants.

77

Conversion of Nuclear and Coal Plants to Less Environmentally Damaging Energy Sources The most recent example of a repowered nuclear power plant is the Ft. St. Vrain Station owned by the Public Service Company of Colorado. This plant was designed as a 330 MW nuclear generating station. The reactor type is different firom either of the two reactors in Minnesota; it is a high temperature gas-cooled reactor. This is significant in that the steam turbine operates at higher steam inlet conditions and thus this design is somewhat more favorable for.some of the natural gas repowering approaches.

The decision to end nuclear operation was made in 1989. The plant was decommissioned and defueled at a cost of $315 million. The Ft. St. Vrain combined cycle repowering scheme utilizes two natural gas-fired combustion turbines and two heat recovery steam generators. The output of the repowered plant will total 471 MW. The total cost of the repowering has been capped at $200 million in 1993 dollars. This equates to about $508/kW of capacity in 1996 dollars. This does not include capital costs of adding natural gas pipeline transmission.

The Future for Nuclear, Power Plants The popular view .of nuclear plants is that they are too expensive, particularly in relation to today's wholesale market price. .This view, however, may,well be incomplete, because:

L....Today's market price is notlikly to::bethe steady-state price in the. future. Rather than 1.5-2.,5/kWh, a morera.istic 3.5-4,5¢/kWh is.probably a better forecast.

2. Many nuclear pladt's a peie o*y ausef pital recovery obligations; their operating cost proffles are in many cases quite cheap (on the order of 1-2c/kWh).

In the fu= some nuclear: plants will become valuable assets,: not only to their owne (because of their cash flow potential), but also to society at large (because excess electric generating capacity will shrink, and they will be able to operate and deliver the product cheaply). Today, the need to recover past investments - in many cases an order of magnitude greater than originally anticipated

- is what pushes nuclear costs so high for many plants. This need constitutes a big.part of today's stranded asset debate in California and other states.

In the short term (3-5 years), recovery of past investment may well remain an.acute problem for many owners, but 10 years. in the future much of the sunk investment will have been recovered or written off. If the. market price of power begins to inch back up, some nuclear assets could turn into "cash cows". The biggest uncertainty apart from market prices is the ability of nuclear plant owners to control future investment needs and costs of decommissioning and waste disposal.

There has been for some years an idea, among some nuclear plant own'ers, to extend the operating licenses of their plants beyond the original 40 years to 60 years. They have been exploring with 78

Conversion of Nuclear and Coal Plants to Less Environmentally Damaging Energy Sources the Nuclear Regulatory Commission (NRC) approaches to accomplishing this. The life extension process among nuclear owners has not yet gathered momentum, despite the potential cash flow opportunities, in part because of the threat of additional investment needs. As a prelude to a life extension application, a nuclear owner will likely need to do a thorough condition assessment, and in many cases the owner may be fearful of what will be found.

In Conclusion The future for nuclear power assets is problematicat best. The non-economic problems of nuclear technology are real, and quite difficult. Such issues. asthe appropriate level of safety, enforcement, and permanent waste disposal are still without.answers, and are so fundamental that they may yet override the economics of nuclear power regardless of how electricity markets change in the future.

However, it is critical to keep several possibilities in mind:

Excess electric capacity is probably not permanent. As it shrinks over time, market prices will probably tend to rise.

• Nuclear assets can be operated relatively cheaply. Once initial investments are paid off or written.,off, nuclear coststo.deliver electricity: .may drop signifiCantly.

The keys to nuclear cost control in-.the.,future ar1e ) the need for ongoing investment, and 2)'

the need to budget fully for the ultimate costs of decommissioning and long-term waste storage..ý Ifcontrol is not possible,. ow ners may decide that walking away early is preferable to walking away later.:

79

REFERENCES Colorado Public Utilities Commission (Contact Morey Wolfson). 1996. "Ft. St. Vrain Nuclear Defueling, Decommissioning, and Repowering Information".

Edison Electric Institute (EEl). 1993. "Statistical Yearbook of the Electric Utility Industry, 1992".

EEI, Washington DC, 1993.

Electric Power Research Institute (EPRI). 1995. "Biomass Energy: Cost of Crops and Power".

Prepared by George A. Wiltsee Jr. and Evan E. Hughes. EPRI TR-102107-VoL 2, Final Report, October 1995.

Electric Power Research Institute (EPRI). 1993. "Strategic Analysis of Biomass and Waste Fuels for Electric Power Generation". Prepared by Appel Consultants, Inc. EPRITR-102773, Final Report, December 1993.

Electric Power Research Institute (EPRI). 1992. "Waste-to-Energy Screening Guide". EPRI TR-100670. Electric Power Research Institute,.Palo AtO, CA, August 1992.

Energy I4formaton Adninistratimn(EI1A). 19."eea Energy Subsidies: Direct and Indirect Interventions in Energy Markets". Service Report SRIEMEU/92-02, November 1992.

Energy Performance Systems, Inc. 1992. "Final Report, Watts Bar Conversion to Whole Tree Energy"'. Tennessee Valley Authority, Southeastern Regional Biomass Energy Program, 1992.

Farhar, Barbara C. 1993. 'Trends in Public Perceptions and Preferences on Energy and.

Environmental Policy". National Renewable Energy Laboratory, Golden, CO, 1993.

Jenkins, Alec F., and Hugh E. Reilly. 1996. "'axBarriers to Four Renewable Electric Generation Technologies". 1996 ASME/JSME/SES International Solar Energy Conference.

Johansson, Thomas B., Henry Kelly, Amulya K.N. Reddy, and Robert H. Williams. 1993.

"Renewable Fuels and Electricity for a Growing World Economy- Definipg and Achieving the Potential". In Jbhansson et. al. (Eds), Renewable Energy: Sources for Fuels and Electric.ty.

Island Press, 1993.

Koplow, Douglas N. 1993. "Federal Energy Subsidies: Energy, Environmental, and Fiscal Impacts". The Alliance to Save Energy Report, Washington DC, 1993.

Levitt, Theodore. 1980. "Market Success through Differentiation - of Anything". Harard Bsinessevie, January 1980.

McCormick, Robert. 1996. "Customer Choice, Consumer Value: An Analysis of Retail Competition in the American Electric Industry". Citizens for a Sound Economy, 1996. As reported in Electric Utility Week, June 3, 1996, pp. 11-12.

80

Rde'eioes Minnesota- 1996. "Findings of Fact, Conclusions, Recommendation and Memorandum". State of Minnesota Office of Administrative Hearings, Pursuant to Laws of Minnesota 1993, Chapter 356, Section 3. March 1996.

Minnesota Power Company. 1994. 'lAskin Units 1 & 2 and Boswell Units 1& 2 Gas Combined Cycle Repower". Minnesota Power 1994 Resource Plan, Page 76.

Naural Resources Defense Council (NRDC). 1996. Presentation by Kari Smith to a solar energy conference in Palm Springs on March 15, 1996. As repdrted by IRP Report, McGraw-Hill Inc.,

April 1996.

Navarro, Peter. 1996. "Electric Utilities: The Argument for Radical Deregulation". Harvd Business Review, January-February 1996, pp. 112-125.

Patti, F.J. 1996. '1fechnical Considerations in Repowering a Nuclear Plant for Fossil Fueled Operation". Brookhaven National Lab, Upton, NY. (1996), 6p, DOE Contract AC0276CH00016.

Power Engineering. 1996. "Coal Units Convert to Gas-fired Combined Cycle". May 1996, Volume 100, No. 5, Page 50.

Public Service Company of Colorado. 1996. "Annual Status Report, 1996, Fort St- Vrain Repowering Project". March 31, 1996.

Public Utilities Commission of Colorado. 1994. Select pages from the PUC's Decision allowing PSCo to repower FL St. Vrain, adopted June 28, 1994.

Union of Concerned Scientists (UCS). 1993. "Powering the Midwest: Renewable Energy for the Economy and the Environment". 1993.

Vansant, C., and Michael Hilts. 1993. "WTE in North America: Managing 110,000 TPD".

Solid Waste & Power, May/June 1993.

Yanney, Fred G. 1996. "Comments of the California Municipal Utilities Association Regarding Joint Applications Filed with the Federal Energy Regulatory Commission". Before the Public Utilities Commission of the State of California, P,94-04-031, 1.94-04-032, May 28, 1996.

Yergin, Daniel 1991. The Prize: The _Epic Quest for Oil. Money & Power, Touchstone, Simon

& Schuster, New York 1991.

81

6L)Ut 4t.

Appendix B Feasibility Study for Conversion of Prairie Island to Natural Gas Fired Generation

I 1.~.

J Feasibility Study for Conversion of Prairie Island to I Natural Gas Fired Generation

]

I I.

AUTILITY wENGINEERING November 20, 2002

Table of Contents Abstract 3 Analysis Approach and Key Assumptions 5 Simple Cycle Capacity Replacement 6 Combined Cycle Capacity Replacement 7 Repowering 9 Natural Gas Requirements 13 Water and Cooling Requirements 15 Transmission Issues 15 Nuclear Regulatory Issues 16 Environmental Considerations 18 Continuity of Site Capacity 18 Schedule 21 Operations and Maintenance (O&M) Costs 21 Appendix 22 Schedule Simple Cycle Cost and Emission Data Combined Cycle Cost and Emission Data Repower Cost and Emission Data 2

1 IAbstract JThis report documents a general feasibility study that examines the conversion of the Prairie Island site from nuclear to natural gas generation. A number of plausible alternatives were investigated. These alternatives involve the replacement orrepowering of nuclear capacity with natural gas combustion turbine platforms.

Although all of the scenarios involve some use of existing plant and equipment, the repowering option uses the most existing plant and equipment and in particular employs the existing steam turbine generators. The generation alternatives investigated include simple cycle capacity replacement, combined cycle capacity replacement, and combined cycle repowering. These alternatives are detailed below.

1. Replace the nuclear capacity with gas turbine generators running in simple cycle mode

2. Replace the nuclear capacity with two standard natural gas combined cycle plants

3. Repower one nuclear unit with steam from a combined cycle plant and retire the other nuclear unit

4. Repower both nuclear units with steam from two separate combined cycle plants Budgetary capital and Operation and Maintenance (O&M) cost estimates for each generation scenario are provided. The study provides brief discussions of significant I technical and licensing issues that introduce project risk and influence feasibility. The study also includes discussions of key advantages and disadvantages of the various generation alternatives. For each alternative, a complementary real-life example is I presented to show a known commercial implementation of a similar project Supporting data is provided in the appendices.

For reasons identified herein, the combined cycle replacement option (2) and the repower one nuclear unit option (3) provide the most effective alternatives to replace the Prairie Island generating capacity. Accordingly, more detailed information regarding the implementation, construction, and scheduling of these particular alternatives is provided.

Option (4) is not a practical engineering solution and is not treated in detail beyond the necessary discussion of the constraints that restrict feasibility. Althoughlthe simple cycle option (I) is not nearly as favorable a replacement for the Prairie Island capacity as options (2) and (3), plant cost and other relevant data for simple cycle are provided at certain points for comparison purposes.

j I

I

• 3 1

Table 1 below, Summary of Prairie Island Natural Gas Generation Alternatives, shows the salient results of this analysis.

Table 1 Summary of Prairie Island Natural Gas Generation Alternatives Net Plant Unit Net Heat Rate at Total Capital. Normalized Generation Alternative Output (MW) ISO Conditions Requirement Capital Cost (1BTU/kwh LHV) ($1000) ($/kw)

1) Simple Cycle Replacement of Both 999 10539 571,645 572 Nuclear Units

2) Combined Cycle Replacement of Both 1036 6366 643,812 597 Nuclear Units

3) Repower One Nuclear 943 6815 Unit (4xl) 510,921" 542*

• Duct Burners Included 1063* 7298*

4) Repower Both 1886 6815 NA NA Nuclear Units,(4xl) ....

5) Present Plant - 1070 10470 Nuclear Units (9783. design). .

4

Analysis Approach and Key Assumptions The feasibility study employed EPRI's State of the Art Power Plant (SOAPP) CT workstation to develop the plant financial models. For the repowering case, the GE Gate Cycle workstation was used to determine a plant heat balance and a viable conceptual design. The following list shows significant assumptions and inputs used in the analysis.

. Plant heat rate results are given at the performance point using natural gas as the primary fuel-

• Natural gas supply costs, project development and management costs, and other soft costs such as interest during construction that add to capital cost are included in addition to process capital costs. U J-"

• Environmental externalities have not been quantified or monetized.

• The results are presented in 2002 dollars.

• Existing equipment not used in the scenarios was assumed to be abandoned-in-place, decommissioning costs were assumed to be unaffected, and demolition costs are excluded.

• Offsite transmission costs such as-those that may be needed to preserve system stability are not included. These costs may have a material effect, and should be investigated further if a more detailed study is contemplated. A brief discussion of transmission issues. is included herein.

• Because this study concerns general feasibility, the plant configurations have not been economically optimized. The costs presented herein reflect approximate costs associated with reasonable and viable plant designs.

0 The physical characteristics of the site are deemed.adequate for the scenarios.

Additional site restrictions such as underground obstacles, barriers to construction, or contaminated soils are not contemplated.

• Environmental costs to support BACT controls for NOx are included.

M repowering analysis is limited to replacing the reactor steam with that from a The natural gas CT/HRSG combination. Other forms of repowering such as coal boiler or gasification are not considered herein.

Existing plant equipment reused in the natural gas generation scenarios is assumed to be in good working order.

5

Simple Cycle Capacity Replacement Scenario The simple cycle capacity replacement scenario involves installation of twelve combustion gas turbines at the PI site operating in simple cycle mode to replace the nuclear capacity.

Description A simple cycle plant consists of a combustion gas turbine operating in open cycle mode.

A simple cycle plant is run intermittently and is principally used for peak shaving. The plant heat rates are less efficient than combined cycle plants, but the plant response time to serve load is faster. Typical startup times are on the order of 20 minutes. Because of their higher heat rates and associated higher variable operating costs, these plants are higher up:in the dispatch order and; would not be expected to operate more than 15% of the time. A total of 12 units are assumed, with each 6-unit:block producing approximately 500 MW. Turbine inlet air fogging was assumed as, a performance enhancement. A General Electric 7EA combustion gas turbine with Dry Low Nitrogen (DLN) combustors was chosen as the base unit for this study. The 7EA machine is a typical base unitfor large peaking plants. Great River Energy has a six unit peaking plant*(Lakefield iunction) in Trimont, MN, which is basedlon the 7EA platform. The 7EA is also the platform used-at Duke's Vermillion Plantihi Lincoln County, NC. At 1200 MW, this.16-unit plant is the largest peaking plant in the United States.

MajorRetainedEquipment and Facilities For this scenario, the following existing equipment was assumed to be available and incorporated into the cost model: Switchyard and Administration Buildings.

Key Advantages The large turbine order (12 units) may allow for some savings on price. Turbine availability concerns have been obviated by recent plant cancellations and reducedorder flow to suppliers.

• A simple cycle is an uncomplicated and modular design with the fastest construction schedule, which allows for quick asset mobilization.

P Can beinstalled with relatively little disruption to the operation of nuclear units Key Disadvantages The simple cycle peaking capacity does not replace the baseload capacity lost with the nuclear unit shutdown. The ability to control system voltage and frequency within the transmission system may be adversely affected. This may degrade transmission system reliability. See Transmission Issues section below.

6

Combined Cycle Capacity Replacement Scenario The combined cycle capacity replacement scenario involves the installation of two standard 2x1 natural gas combined cycle plants, each with new steam turbine generators, to replace the nuclear capacity at Prairie Island.

IDescription A typical combined cycle plant consists of a combustion gas turbine (CTG), matched with an unfired Heat Recovery Steam Generator (HRSG), providing steam to a steam turbine generator (STG). For this analysis, the industry standard 2x 1 plant configuration was.assumed. That is, two CTGs,seach with a matched HRSG, providing steam to a single steam turbine generator was assumed for the base plant. In a combined cycle plant, the gas turbine.generators contribute approximately two-thirds of the total plant power. A typical.output for this configuration is 500 MW per plant. In order to fully replace the PI generation capacity and utilize the existing transmission capacity, two standard-plants are needed.

I Combined.cycle plants are highly efficient-unitsi that are suitable for base load and mid-range dispatch. Net thermal ..efficiencies .for these plants are on the order of 53% LHV.

e plant is assumed to operate.in baseload. mode, although: it is well suited for cycling, duty of approximately 16 hour1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />sa day. Combined cycle plants are usually shutdown

! duringunprofitable.

kunits weekends and evenings when the spark spread for non-peak power makes these The gas turbine platform for this analysis is the. Seimens -Westinghouse 501 FD. For these analyses, the gas turbines .are assumed to be equipped with Dry Low NOx (DLN) combustors, and each HRSG has an integral Selective Catalytic Reduction (SCR) unit to reduce stack gas NOx emissions.

The Sacramento Municipal Utility District (SMUD) is currently engaged in the desiga and licensing of a natural gas combined cycle plant at the decommissioned, Rancho Seco I nuclear power plant facility. This project is known as the Cosunmes Power Plant Project

- CPP. According to their: submittals to the California Energy Commission (Docket 01-

]project.

AFC-19), a total of 1000MW of combined cycle replacement power isplanned for this The proposed plant uses the existing switchyard and some other facilities. The plants are scheduled for construction in two phases consisting of 500 MW each. The first phase is scheduled for commercial operation in 2005 and the second phase, if completed, is scheduled for 2008.

J Florida Power and Light (FPL) is currently engaged in the early stages of the siting process for a stand alone combined cycle 550 MW plant to be located adjacent to Exelon V Nuclear's Limerick Generating Station. This project is an.example of constructing a

natural gas plant at an operating nuclear generation site. Although limited public information has been provided, it appers that there ar-e no plans to shutdown the nuclear units as part of this project or to share any significant equipment. As of June 2002, the NRC was preparing to review the impacts on nuclear operations with input from Exelon, which is a requirement of the Limerick operating license. The siting process has, however, been halted: as the township's decision to allow the plant construction has recently beenwovertumed. The following is an excerpt of an article that appeared in the October 3, 2002 edition ofthe Philadelphia Inqurer.

A three-judge panel in Montgomery County Court on Tuesday overturned an unpopular decision by township officials to allow the plant to be built in the Linfield section. The movement against the gas-powered plant, which opponents argued did not belongin a light-industrial zone, also helped topple the political careers of four township supervisors who backed it. The $300 million plant was slated to be running

-at a site near Peco's nuclear power plant by next summer. It would have employed 20 to 25 full-time workers and contributed about $3 million a year to the tax rolls of Limerick Township, Montgomery County, and the Spring-Ford Area School District,

?PLEnergy and its local subsidiary, Limerick Partners L.L.C., could not be'reached for comment. They have 30 days to appeal-the decision to Commonwealth Court.

Major RetainedEquipment and Facilities For this scenario, the following existing equipment was assumed to be available and incorporated into the, costmodel: Water Treatment System, Switchyard, Circulating Water System, Cooling Tower, Ad stration Buildings.

Key Advantages

" High hermalplant efficiencies

" Relatively shortstarting times for a baseload unit

• Excellent part-load operating performance and flexible duty cycle SStandardized design and construction

• Modular design and construction reduces AFUDC

• Fewer design compromises needed to match new equipment with older existing equipment

• Gas.utbines can be installed in Simple cycle mode prior to full.combined cycle mode to reduce the impact of the lost capacity .

Key Disadvantages

• Higher initial capital costs 8

i Renowering Discussion

] The attractiveness of repowering is usually due to savings from the use of existing equipment permits and public acceptance of the existing site as a generating facility.

Repowering projects avoid the cost and uncertainty of siting a new facility while the plant heat rate is typically improved over the existingunit and the capacity of the existing plant increases. In the case of replacing existing fossil-fueled boilers, repowering also can significantly reduce plant emissions. Most repowering projects in the United States have involved replacing a fossil-fueled heat source.

The performance improvements coupled with the reduction in emissions make repowering an efficient choice where capacity additions are needed. A typical increase in I Cinvolves r,.,powered 2out (MW) is triple the originalplantoutut. The concept o0repowering replacing the original steam generation source with more efficient equipment thatis thermally matched to the existing steam turbine generator. A repowering option retains as,much auxiliary equipmentzas possible. Repowering is designed to improve the oveiall:thermal,.efficiepcy of the plant while keeping site development costs low and 1 -

while keeping capital costs low by using existing equipment. Because nuclear fuel costs are much lower than fossil fuels improving the plant heat rate is less of an economic incentive for repowering at Prairie Island.

Because ofthe optimization engineered into. the greenfield .combined cycle design equipped with integral steam turbine generators, a repowered plant will not be as ernnally efficient as anew combined cycle plant. In order for a repowering project to be an efficient use of capital compared to a greenfield generation alternative, the equipment cost savings derived from repowering needto exceed the inherent,efficiency advantages of the greenfield alternative for a given amount of deployable MW to the grid. That is, the efficiency difference should not be so great as to result in a material shifting of the dispatch order of the repowered plant over a greenfield alternative. In deregulated markets, an investnent in repowering option is not typically warranted if the end result is to simply displace an existing unit in the dispatch order.

Repowering of steam power plants with gas turbine generators and HRSGs is being accomplished in various applications. Colorado Public Servicerepowered the existing steam turbines at the previously decommissioned Fort St. Vrain nuclear-facility in 1999.

This plant was originally rated at 330 MW and has been repowered to approximately 720

]MW with the installation of three GE 7FA gas turbines and three HRSGs. While there is considerable experience with repowering to replace fossil fueled boilers with gas turbine exhaust (dating to approximately 1960), there have been no nuclear repowering projects other than Fort St. Vrain in the United States.

Florida Power & Light (FP&L) is repowering the 540 MW oil-fired Fort Myers plant j with combined cycle technology to ultimately increase plant capacity to approximately 1440 MW. This project provides an example of repowering a steam turbine generator j .9

that is very similar in capacity to the existing Prairie Island steam turbines. Thermal efficiency is expected to increase from approximately 39.6% to 53.7% LHV at ISO load conditions. Six GE Frame 7FA combustion gas turbines and six Foster Wheeler HRSGs with triple pressure and reheat are being installed to replace the oil-fired boiler. The six gas turbines were initially installed in a simple cycle configuration and provided an additional 912 MW from the Fort Myers site. Full combined cycle repowered operation is scheduled for fall of 2002. The cost of this single-unit repowering project was approximately $450 to 500 million.

Scenarios The PI repowering scenarios involve installation of combustion turbine generators running in combined cycle using the existing steam turbine generators. The design parameters for the existing steam turbine generators were used in the model. Two scenarios were examined: 1) repower a single unit and, 2) repower both units.

Description The GE Frame 7FA unit with Dry Low Nitrogen (DLN) combustors was used as the base CTG in the simulation because it provides sufficiently high gas exhaust temperature for the reheat cycle. The efficiency and output of a steam turbine is a function of the gas turbine exhaust temperature. The 7FA is the most widely used unit in modem combined cycle applications. It has an extensive operating history and proven reliability. Siemens-Westinghouse has installed a G class machine with slightly higher efficiencies at a few locations, but these machines do not yethave a detailed history of reliability.

,,~. . ....

According to the heat balance model, six gas turbines are needed to efficiently repower an existing steam turbine at Prairie Island. The performance of one repowered plant in a 6xl configuration is estimated as follows.

Net Plant Output -1418.2 MW Net Plant Heat Rate - 6599 Btu/kWh LHV Repowered.ST Generator Output- 446.6 MWW (of 535 MW available)

To efficiently operate the existing STGs, six CTGs are needed to replace,the steam flow formerly provided by the nuclear reactor. Repowering one nuclear STG results with a more efficient 6x1 configuration results in a site output of approximately 1412 MW, which is approximately 352 MW above current output. Kepowering tbott plants in a 6xl configuration would result in a site output of 2836 MW, which is I VU MW above current output. Since these results exceed equipment limits, the 6xI configuration was not further analyzed. See Transmission Issues section below.

Four CTGs in a 4x1 configuration were used so that current site capacity w.matched 1, andut-put was within known switchyard equipment and transmission limi..

Repbe-ring a single nuclear STG with a 4xl configuration would result in a site output of 943 MW and 1060 MW with a duct burner performance enhancemeat. Since a duct

burner equipped configuration matches the current nuclear output well, it was used in as the base repowering scenario. Repowering both plants in a 4xI configuration results in a site output of 1886 MW, which, is 826 MW above current outut and above known equipment and t ssion ýA 4xl configuration also allows for future conversion to a 6xl coiguratlon with an increase from 943 MWto 1412MW if dictated by system load. .

EngineeringIssues and the Heat BalanceModel A heat recovery steam generator is most efficient when steam is generated at multiple pressure levels. This contradicts the conventional boiler method of using steam turbine extractions to heat the feedwater. Instead, steam is introducedinto thesteam turbine at different points, with the .steam turbine designed to handle the additional flow at lower pressures. Given the above, the use of the existing feedwater heaters at Prairie Island would rob the HRSGs ofheat absorption capability, so the feedwater heaters have been removed from the conceptual design. Since the PI turbines were designed to operate in a saturated steam nuclear cycle, the blades have moisture separation features. The ability to drain the separated moisture has been retained in the model, assuming that the extraction points would.be converted into level controlled drip legs of sufficient size to handle.,the drain capacity.

Whena conventional plant steam turbine is repowered with combined cycle steam, the turb*ne is typicýaly.*restrcs_ toa maximum amount of exhaust flow. The result of the LowJ *pr)ssure (Lstea flow limitation is that the bowl pressure after the throttling valves drops to telpoint that,continuinglto use-the steam chest costs performance. Most combined cycle steam turbines are designed without a control stageand operate with valves wide,open to-accommodaterapid: fluctuations in heat iniut to the HRSG, due to a number ofvariables,÷affecting the gas turbinedperformance. Load is controlled by changing the load point of the gas turbines. In order to allow the HRSGs to dampen thermal changes, the control

Table 2 Configuration Efficiencies of a Single Repowered Unit Configuration Net Plant Net Plant Heat Rate STG Output (MW)

Output (MW) (BTU/kwh,LIV) (535 MW avail.)

2xl 450 6939 127 4xl 943 6815 280 4x1withduct burners 1060 7310 401 6xl 1418 6599 447 MajorRetained Equipment andFacilities For the PI repower scenario, the following existing equipment and facilities were assumed- to be available and incorporated into the cost model: STG, Condenser and Condensate System, Water Treatment System, Switchyard, Circulating Water System, Cooling Tower, Turbine Building, Administration Buildings.

Key Advantages Lower initial capital costs. The repowering option uses the most existing plant equipment. The repower option saves the process cost of a new STG, which according to the manufActurer is approximately $35M FOB per STG at Prairie Island. With engineering and other costs, approximately $100M in capital cost savings could be realized over a combined cycle plant.

o Replacesbaseload duty cycle ofexisting plant o A repowered plant provides relativelyefficient power if the conceptual design heat rate can be achieved. Note, however, that the existing steam turbine generators will: not be optimized within a repowered steam cycle.

• If'justifiable, an option exists to increase current site capacity by adding additional gas turbine generators from 4xI to 6x1 or repowering the other plant.

• Gas turbines can be installed in simple cycle mode prior to full combined cycle mode to provide excess power or reduce the impact of the lost capacity.

Key Disadvantages

• Non-standardized design introduces uncertainties and longer installation cycles.

These risks will be monetized by higher engineering fees, higher project contingency costs, and higher financing costs. For example, the Mystic project in Massachusetts, which is a first of a kind design in that it is the largest combined cycle plant in the US, is behind schedule and as of July 1, 2002, is experiencing hundreds of millions of dollars in cost overruns.

o Large natural gas capacity requirements and modifications.

• The attendant poorer reliability of older existing equipment retained in a repowered plant will likely result in higher maintenance costs over new equipment.

12

The most optimal 6x1 repower configuration is not practical as it results in a plant output that will require switchyard modifications, cooling tower upgrades, and (fOA may require significant transmission system upgrades.

• Repowering in a phased construction approach to maintain continuity of site power output introduces significant regulatory uncertainty and risk if one nuclear unit is maintained operational. See Nuclear Issues section below.

I* The repowered plant's duty cycle is not as flexible as that for a combined cycle unit.

Natural Gas Requirements Discussion Each scenario relies. on a combustion turbine for power conversion. Consequently, the project must have access to a reliable high-pressure supply of natural gas. The combined cycle CTs will require, significant volumes of gas provided on a 24-hour firn basis that will require capacity additions for the natural. gas, supplier. This involves a firm design load of approximately 200,000 mcflday of natural gas for the combined cycle and single repower alternatives depending on the configuration and dispatch characteristics.

The simple cycle., plants,were. assumed to.require gas on a 5x 16 summer operation protocol. Although gas pressures within interstate gas transmission lines are typically maiied abov 1 psig,epressure levels maintained within the LDC's system are subially lower.,(<100 psig), and are insufficient for proper: operation of a large CT.

Gas pr w a distribution system is typically:increased. by adding compressor facilities, by enlarging or paralleling with existing high-pressure mains, and by constructing new sipply main. This results in significant additions to. capital costs. For e purposes of:this:tdy, it was assumed that natural.gas would be, available at the site at sufficient pressur to e fte e need for an onsite gas compressor.

In addition to equipment costs, the large gas loads associated with CT operation will require the supplier or a third party to actively manage the gas supply to maintain capacity and system integrity, which will tend to increase the plant O&M costs.

The two potential natural gas suppliers for the Red Wing Station are Viking Gas I Transmission Company (Viking), an Xcel subsidiary, and Northern Natural Gas Company (Northern), formerly an Enron subsidiary now owned by Dynegy. On August 191, Dynegy sold the Northern pipeline to MidAmerican Energy Holdings.

Viking In order to supply gas to the PI site, Viking will need to install.a.47-mile lateral line and a metering station. In addition, the mainline will have to be expanded to accommodate the high gas throughputs of the various plants. The capacity of the existing mainline is insufficient to. supply the large gas load and this requires significant infrastructure modifications to increase system capacity. The mainline cost shown below is the up front 13

capital required to expand Viking's mainline to move the additional volumes from Emerson to the proposed lateral. Table 3 below shows a summary of Viking gas costs to 3 support the various scenarios.

Table 3 Viking Gas Capital Costs (000s)

Plant Configuration Lateral Metering Compression Total Station and Mainline Improvements Two Simple Cycle $29,870 $430 $262,000 $292,300 Replacement Units Two Combined $25,620 $275 $176,000 $201,895 Cycle Replacement Units One Repowered $29,870 $350 $220,000 .$250,220 Unit (6x1)

Two Repowered $29,870 $480 $289,225 $31'9,575 Units Northern NaturalGas.

The Northern Natural Gas (NNG) system is physically closer to the PI site than the Viking system. The length of the lateral would be approximately 28 miles and would originate. from the NNG Farmington compressor site. TheNNG system is not as capacity constrained as the Viking pipeline and requires less mainline modifications to accommodate theproposed PI load. Table 4 below shows the Northern Natural Gas costs to. support the various scenarios. Given the clear-cost advantages, it was assumed that NNG would act as the project gas supplier.

Table 4 Northern Natural Gas Capital Costs (O00s)

Plant Configuration Lateral Metering Compression Total Station and Mainline Improvements Two Simple Cycle $28,000 $600 NA $28,600 Units (interruptible)

Two Simple Cycle $28,000 $600 $4100 $32,700 Units Two Combined $22,700 $600 $4100 $27,400 Cycle Units ... _,,

One Repowered Unit $28,000 $600 $4100 $32,700 Two Repowered $34,600 $800 $5500 $40,900 Units 14

Water and Cooling Reouirements The Prairie Island Circulating Water System is appropriated 615 million gal/day of surface (river) water by DNR permit #69-072. The well water permits for PI allow consumption of approximately 470 gpm, This allotment is well in excess of the makeup

.andcooling water requiremenq of an of the above scenarios. A typical combined cycle plant uses on the or o 3 to jmillion g A simple cycle plant cant amounts of makeup water. The maximum consumption would be approximately 750 gpm (per 6 unit block) if the gas turbines were operated on fuel oil. This consumption rate is well within the existing water permit With onsite storage tanks, the simple cycle plants could feasibly-operate within the capacity provided by the well water only. If only natural gas is used fuel, only insignificant amounts of water would be required a ater or steaminjeeton Uor'INOx conatroL would notý be.eceE§W~.

The existing circulating water system and associated cooling towers can be used as heat1 sinks for the proposed alternatives. Cooling towers are not required for the simple cycle plants.

! Transmission Issues The MW.outputs of the power block-configurations usedý in this study were chosen to match and fully utilize.thef existing transmission capability of the ;site. Ifthe new generating equipment-supplies power minexcess of the capability and ratings of the existing switchyard and :transmission system, such.as in the-6x1 repower case, switchyard and,transmission modificationsmwill be'needed. For the simple and combined cycle cases and the 4x1 single repower case, the output of the new units is within the existing switchyard ratings, and no significant switchyard modifications were assumed.

C.,alternative An interconnection study is necessary to determine the transmission system impact of thei generation. As part of the siting process, all new generation facilities are analyzed to determine the impact on the reliability of the: associated electrical transmission study. These studies include analyses of fault duty, stability, and system voltage support. Usually fault duty studies are undertaken first. If these results are favorable, additional studies are conducted. An interconnection study must be requested through the Midwest ISO or developed by a third party. Generally ISO stuidies are undertaken when a certain project is likely to be developed, and the generation is likely to eventually become part of the system model. An ISO study cost is approximately

$40,000, depending on complexity. Since this feasibility study is preliminary and somewhat prospective in nature, interconnection studies were not performed.

NSP has examined thermal limitations for substation capacity increases for the 2001 All-Source Request for Supply Proposals. This indicative finding showed that approximately 800 MW could be added on the 345 KV bus at Prairie Island without exceeding loadings 15

on transmission elements. Given this finding, all cases except the double repower case would not require mitigation for thispanticular-t~e ofarn mtercor cton s WEy.*

/ery mportant to-note, however, that the Prairie Island output is presently constrafined by*

/aflowgate ont

• Island-Byron interfacsuch that no increases in capacity above th*peent capacity could be undertaken without system modificatio~ns. /

Given these constraints and the increase in capacity above existing, the 6xl repower configuration will require transmission and switchyard modifications and the double repower case will likely require transmission and switchyard modifications and additional modifications to demonstrate fault duty compliance. A full interconnection study is necessary to further evaluate feasibility and to determine more detailed cost estimates.

Nuclear Regulatory Issues Natural Gas and:SpentFuel Interaction There are two natural gas powered generation projects at former nuclear plant sites in the United States. These projects provide some insight into natural gas generation projects at Prairie Island. A:repowering.project at Fort St. Vrain (FSV) is complete and operational.

A capacity replacement project at Rancho Seco is in the siting phase. Both of these projects involved previously decommissioned reactors with. spent nuclear fuel completely transferred -to:an.Independent Spent Fuel Storage Installation (ISFSi)_ to nstrtcion of the naturaL gas firediuits. The repoweingoptions at Praiielsland Qwould involve evaluagtigthedimpact of large quantities of natural gas on site with spent nuclear fuel still located in the-reactor or spent fuel storage pool.

Each of these projects was requireddto examine nuclear impacts to the spent fuel stored in the ISFSI. The NRC regards nuclear impacts as minimal as long as the new plant is l greater than one half mile from the nuclear fuel and the new plant has been sufficiently Lisolated and secured from the existing nuclear plant. Gas and oil installations within 2 of an ISFSI require specific evaluations of the possible impacts to the nuclear fuel" Ml'prior NRC approval. This.spatial isolation is a reuirement of the ISFSI license at FSV. SMUD controls a large plat of land at the Rancho Seco site, and they were able to use the existing switchyard while locating the plant sufficiently far from the nuclear unit and the ISFSI. The ýSMUD project does not involve gas or oil impacts within /2 mile of the fuel. As of August 23, 2002, all of the Rancho Seco fuel was transferred to dry storage.

The ISFSI at FSV is located 1_400 ft away from the nearest gas line. The NRC determined that this arrangement was satisfactory from a safety standpoint (FSV safety evaluation). This required examinations of the effects of postulated natural gas accidents.

At FSV, the effects eofa service line rupture, a main supply line rupture and a turbine building detonation were reviewed and found not to impact the safety function of the ISFSL 16

t I

....!J

-from

......:;.A [Given thea above, to locate natural,itgas would be plant power in theand nuclear gas infrastructure safety and supporting at least economic interests a PIhalf ofone mile project the fuel, whether the fuel is located in the spent fuel pool, the reactor, or the ISFSI.

J

[By examhining the PI site layout, this appears at least geographically possible for the

',Simple and combined cycle capacity replacement scenarios by locating these plants at the far northern boundary of the site. (Other analysis such as soil mechanics would have to Ibe accomplished.) A gas line that is within 1/2 mile of an ISFI or a spent fuel pool does not, of itself, disqualify a project, but such a location will entail detailed failure mode and effects analyses for nuclear safety concerns.

The PI repower scenario that contemplates continued operation of one of the nuclear units during construction-of a repowered unit entails significant regulatory uncertainty because of the safety ramifications of a failure mode and effects analyses. *epowern cannot be accomplished outside of the standard V mile interface area establishe7y the NRC. The pressure drop between the HRSG superheater discharge and the existing.

steam turbine nozzle, which is a strong function of the length of the steam pipe run, should be minimized for plant efficiency.

I There is no precedent that contemplates construction of a repowered plant that uses one of the two existing STGs at an operating nuclear power plant in the United States. High volume natural gas .facilities introduce explosion hazards and safety concerns to.an I operating nuclear-plant that would:be hard to justify on a:basis that repowering may have economic advantages over alternative generation. For instance, natural gas from a pipe failure could enter a structure through ventilation systems and be igted and affect operators and nuclear safety equipment. Explosions have occur'ed at natural gas fired, power plants. In 1999, a natural gas explosion destroyed a boiler at a KCPL coal plant.

An explosion and large fire occurred at Sithe's South Boston 700 MW natural gas power plant on October 1, 2002.

I NuclearSafety and ProjectReviews It is estimated that from the time of a decision to pursue th oýower.ihat it would take approximately tWO yerto,completeithemnuclear reulatory IW) revieV u s. This two years includes 6 months for the licensee to prepare the required safety analyses for submittal, an estimated 6 months for review by the Nuclear Regulatory I Commission and 1year for public hearings should they be requested.

As part of the siting process, a repowering project would be subject to an analysis of feasible generation alternativei, which is required as part of the state's review to determine a given projectr7senvironmental impact. This would involve a review of the comparative merits of other reasonable alternatives to the repowering project that could satisfy the project objectives but may avoid or lessen the effects of the project. A competent reviewer would certainly need to examine the relative risks of repowering due to the proximity of nuclear fuel over other plausible alternatives such as siting replacement generation elsewhere. Because of the nuclear safety impacts, a favorable ruling for the repowering alternative, especially on a site with an operating nuclear plant, 17

over other generation alternatives may be difficult to obtain regardless of an NRC approval. For these and other reasons, a repowering project would likely be the subject of legal challenges from interveners. There are no industry precedents for siting a natural gas power plant on a nuclear site where the reactor has not been decommissioned. The ability to successfully license a repowered plant at Prairie Island cannot be predicted with any certainty. These feasibility risks should be well understood prior to undertaking a repowering project.

Environmental Considerations For the purposes of this study, it was assumed that Best Available Control Technology (BACT) environmental controls are installed consistent with recent MPCA requirements for similar plants in attainment areas. For the combined cycle and repowering cases, it was assumed that dry low NOx combustion turbines and SCRs were installed.

The specific environmental impacts of routing the gas line or constructing and operating the plant have not been identified. The cost of the environmental surveys and consulting work has been included in the model. Environmental externalities were not monetized for this analysis. There are no cost provisions for environmental mitigation measures,

~such as purchasing. wetlands for the purpose of set asides for compensatory habitat.

,(These issues wouldbe addressed in a more detailed study.

Continuity of Site Capacity TransitionTime The scenarios addressed herein postulate a simultaneous shutdown of both nuclear units in the last.quarter of.2006 followed by operation of thereplacement or'repowered units on or about January2007. Current planning indicates a shutdown of Unit One-in mid 2006 and Unit Two in late 2006 if additional spent fuel casks are not installed. For simplification purposes, the analysis assumes a simultaneous shutdown of both nuclear units such that the commercial operation of the gas-fired units is assumed to pproximately oincide with the nuclear shutdown.

These eases, however, are somewhat hypothetical with regard to complete continuity of site power in that the integration and operation ofthe ýgas-fired units for continuous service would involve some modification and preparation of equipment formerly used by the nuclear unit(s) presumed to shutdown. Depending on regulatory requirements, the final routing of the gas pipeline onto the site may be scheduled subsequent to the nuclear plant shutdown. First fire of associated plant equipment would occur after the gas line had been installed. In addition, system and integrated plant testing would also need to be accomplished. For the purposes of this report this time will be referred to as the transition time. Transition time should be scheduled to occur when the impact to the grid is minimized much leapranned outage is scheduled. In general, the transition time would be a function of how much equipment is retained from the existing plant to the new plant. Detailed planning and staging equipment can minimize transition time. There 18

1 are, however, practical liisto optimizing thsprocess because of the number of plant systems that need to be tested and certified for insurance, warranties, contractual requirements and other purposes.

Because of the uniqueness. of this project, there are no direct examples available of transition time for a project of this type, but a reasonable estimate can be made from jsimilar projects. A repower of a similar steam turbine at a fossil fueled plant (Ft. Myers) is expected to have a transition time of approximately 6 months. According to the EPRI model used for this study, the full testing phase of a typical combined cycle plant without nuclear complications is on the order of 7 months. Recent combined cycle projects have executed the testing phase in 4 to 6 months. Some have taken much longer. Given this information and allowing for nuclear-related contingencies, a reasonable estimate for months for a repower of one.unit- This estimate assumes that the NRC does not require I' any other additional testing or special requirements for nuclear safety purposes. If this occurs, which is not unlikely, the transition time will be extended, perhaps significantly.

i Siting, Design, and ConstructionTimes Because of Odsign standardization, combined cycle plants% are being designed and C

constructed well within 3 years of a notice.to proceed. Some combined cycle projects have been completed in 24 months or less. Simple cycle plants are less complex and can be completed in less time than combined cycle plants. The PI site has inherent advantages such as existing administrative buildings and other infrastructure that would I contribute to a reduction in the construction time. The supporting off site natural gas, infrastructure can be designed and constructed in 2 years and can be done in parallel with the,power block, design and. onstuction. Allowing six months for up front siting work, no deays in regulatory ,app*rvals, ýanddreasonable transition times,(as defined ,above), the IDombined!ycler and single unitrepowýr generation alternatives could feasibly be).

I kcompleted by late 2006if a decision.is made by the second quarter 2003.

The timing of regulatory approvals for the repower cases, however, is subject to potentially lengthy delays due to, siting issues and licensing uncertainty. A replacement simple or combined cycle plant that cannot be located outside of 1/2/mile from the area would alsobe subject to more detailed nuclear safety requirements and more uncertain I regulatory approval times. See Nuclear-Regulatory Issuesabove.

PhasedConstructionto Support an Extended Service Life ofNuclear Unit 2 I The phased approach would involve a replacement of the retired capacity associated with the shutdown.of one-nuclear unit followed later by a replacement, of the retired capacity associated with the-shutdown of the second nuclear unit when the spent fuel pool is full.

At the end of Phase 1, a gas-fired unit and a nuclear unit areproviding power. At the end of Phase 2, two matching gas-fired units are providing power, and the nuclear.units are I retired. For the PI site this would involve an earlier shutdown ofUnit One in fall of 2004 without initiation of its.last fuel cycle in order to extend the service life of the Unit Two 19

by approximately 18 months to mid 2008 (depending on the fuel burnup rate). This is not considered feasible or desirable for reasons discussed below.

It is not realistic to assume that a combined cycle or repowered plant can be fully completed by the fall of 2004. A simple cycle plant or the simple cycle portion of a combined cycle plant could possibly be completed if theproject is authorized and notice to proceeds for various contracts are issued by early 2003 and no delays in siting, design, procurement, and construction, including natural gas infirastructure, are experienced. The combined cycle portion could be finished by early 2006. Given the unique nature of this project where the~siting and construction necessarily involves a first-of-a-kind review of the impacts to an operating nuclear power plant (Unit Two), a streamlined fast track process with no delays is considered extremely unlikely.

A phased aproach will cost more (estimate 30%-5.0%) because: 1) the Engineer Procure and Construct (EPC) contractor wil require contingencies and incentives to complete, the complex project on an abbreviated schedule, and 2) resources are mobilized at two different times-as the second natural gas generation unit is completed-years later from the first plant. This approach, does provide some flexibility in that-it -setsup an option to cancel construction of the second unit if system load decreases or if other substitute generation capacity is added. If a phased construction approach for repowering were undertaken, the combustion turbines could be installed in increments, however the work available fromthe turbine would not be as efficiently utilized until all six CTs were installed. As discussed above, at interim gas turbine ,configurations,the net plant output will decrease and.the plant heat ratewill degrade somewhat atconfigurations less than a 6x1 (2xl, 4x1). This approach would also cost morethan an uninterrupted, project.;

Another consideration is that the cost to maintain a nuclear plant shutdown without a

• '-"ossession only license (which can be obtained from the NRC post decommissioning) can easily be as much or more as that needed to maintain it operating. Because of relatively inexpensive fuel costs, the variable operating costs at nuclear units are much less than those of a fossil unit. Because of higher labor, shutdown maintenance, and insurance costs, the fixed costs for a shutdown nuclear unit are significant. Finally, the economies of scalthat are realized with both units operating would be lost Stand Alone Construction In order to minimize impacts to the existing nuclear plant, the simple and combined cycle plants could be designed and built without the use of any existing site power equipment.

Administrative buildings and non-safety related infrastructure could still be used. This would add approximately $20 million of equipment costs to the simple cycle plant and

$50 million to the combined cycle plants. Of course this is not an option for the repowering alternatives. One potential feasibility risk element with this approach is that it would involve changes to the surface water appropriation and the existing circulating water system. These changes engender a much more expensive and less streamlined approach to the siting process due to the necessity to obtain changes in the plant water permits.

20

I 1.

In addition, once stand-alone construction is contemplated, a competent generation 9*planner would compare the costs of stand alone construction at PI with a greenfield generation project at carefully chosen offsite location. It is altogether likely that the greenfield site offsite would pose significantly less risk and also be price competitive with a stand alone project at PL Schedule A representative Level 1 schedule has been provided in the appendix that shows an estimate of the power plant development and construction cycle to satisfy a 2007 startup.

It was assumed the gas pipeline projects could be completed in parallel with the design and construct power plant tasks without affecting the critical path elements. According to Northern Natural Gas, a general time estimate for the design and FERC filing requirements for a project of this scope is one year. An in-service construction timeframe estimate for aproject of this scopewould also be approximately one year. There likely would be.some overlap in these time.horizons: such that a reasonable project timeline

! estimate to-complete-the. gas pipeline project would be 1.75 years.

Operations and Maintenance :(O&M) Costs I The fixed and variable O&Mcosts for each practical scenario is given in Table 5, Altemativest Operations and.Maintenance Costs below.: Gas costs, which are highly volatile, were.notincludedin the O&M estimates. The fixed O&M costs- do-not include any future capitalupgrades. ,The variable costs: assume I 0% capacity factor for simple cycle and a 92% capacity factor for combined cycle and repower. These costs also do not include any costs: to operate, maintain, demolish, or provide security for any of the PI nuclear facilities.

IAlternatives Operations Table 5 and Maintenance Costs Alternative Fixed O&M Non-gas Variable O&M (S/kw-yr) ($IMWh)

Simple Cycle Capacity Replacement 2.37 2.67*

I Combined Cycle Capacity

,,Rep ae~ent 3.23 l'.79**

Repower One Unit with DuctBurners 3.15 1.68**

• 10% capacity factor

• • 92% capacity factor _

I 21

Appendix 22

I I Schedule Combined Cycle or Repower Plant Schedule Planned Planned Planned Start End Duration (Days)

Design, Procurement and Delivery 1/1/2004 9/1/2006 974 Engineering 1/1/2004 3/112006 790 Permitting 1/1/2004 6/11/2005 517 Procurement, Fabrication and Delivery 4/1/2004 9/1/2006 883 Construction 4/15/2005 11/11/2006 565 j Mobilization and Site Preparation Underground Piping, Elec and Misc Facilities 4/15/2005 6/15/2005 611/2005 3/15/2006 47 273 Field Erected Tanks 10/1/2005 2/1/2006 123 I Substructure Work Superstructure Work 5/15/2005 1/1/2006 10/15/2005 6/1/2006 153 151 HRSGs and Aux Installation 6/15/2005 8/11/2006 412 I Combustion Turbine Installation Steam Turbine Installation*

1111/2005 1/1/2006 9/1/2006 611/2006 304 151 Balance Of Plant (BOP) Equip installation 12/15/2005 10115/2006 304 I BOP Electrical Sys Installation BOP Control and Instrumentation Installation 12/15/2005 1/1/2006 10/15/2006 11/1/2006 304 304 Final Site and Finish Architectural Work 8/1/2006 11/11/2006 92 I Testing Plant Startup 411/2006 4/1/2006 1/1/2007 12(1(2006 275 244 Combustion Turbine Startup 5/1/2006 10/1/2006 153 I HRSG Startup Steam Turbine Startup 5/15/2006 4/15/2006 11/1/2006 12/1/2006 170 230 Plant Performance Testing 12/1/2006 1/1/2007 31 Commercial Operating Date 1/1/2007 1/1/2007

• Steam turbine integration for repower case I

I I

I I

23

Cost and Emission Data SIMPLE CYCLE SIMPLE CYCLE COSTS TOTAL PROCESS CAPITAL - 364,105,984 General Facilities 14,564,240 Engineering and Home Office Fees 25,487,420 Project Contingency 36,410;600 Process Contingency 0 TOTAL PLANT COST 440,568,256 AFUDC or IDC See Capital Outlay Table TOTAL PLANT INVESTMENT 440,568,256 Prepaid Royalties 0 Preproduction Costs 18,875,486 Inventory Capital 2,202,841 Initial Cost - Catalyst and Chemicals 0 Land 0 Capital Cost Adders 32,700,000 TOTAL CAPITAL REQUIREMENT 494,346,592 TOTAL CAPITAL REQUIREMENT (Currency/net kW) 494.8 0 + M and Fuel Costs (in Base Year (2002) Currency)

Fixed O + M Direct Operating Labor 406,140

- Number of Operating Staff 5 Direct Maintenance Labor 519,770

- Number of Maintenance Staff 9 Annual Services, Materials, & Purchased Power

- AnnualIO&M Services & Materials 552,259

- Non-operating Purchased Power 397,264 Indirect Labor Costs

- Benefits 273,404

- Home Office Costs 216,486 TOTAL FIXED O+M 2,365,325 24

SIMPLE CYCLE COSTS (Continued)

~Variable O+M Scheduled Maintenance Parts & Materials

- CT Inspection/Overhaul 1,998,717

- HRSG Inspection/Refurbish 0

- ST Inspection/Overhaul 0

- BOP Refurbish 20,876 Scheduled Maintenance Labor

- CT Inspection/Overhaul 139,910

- HRSG Inspection/Refurbish 0 ST Inspection/Overhaul 0

- BOP Refurbish 32,861 Unscheduled Maintenance Allowance 109,618 Catalyst Replacement

- SCR Catalyst Materials & Labor 0

- CO Catalyst Materials & Labor 0 Other Consumables

- Raw water 11,830

- Circulating water 0

-NH3 0

- H2SO4 12,979

- NaOH 15,673

- Misc 15,968:

Disposal Charges

- Spent:SCR catalyst 0

-Spent CO catalyst 0

- Other disposal 75 Byproduct Credit 0 Total Variable O+M 2,358,510 Total Variable O+M (Currency/MWh) 2.67 Total Fixed and Variable O+M 4,723,835 Fuel Cost Fuel Cost 31-,934,028 Fuel Cost (Currency/MWh) 36.17 25

SIMPLE CYCLE CAPITAL OUTLAY Category Total 1 2 3 Calendar Year (Jan 1 - Dec 31) 2004 2005 2006 Total Plant Cost In Base Year (2002) Currency 440,568,256 9,862,531 162,282,496 268,423,232 Amount of Escalation 32,458,140 398,446 9,932,987 22,126,706 Escalated Total Plant Cost 473,026,432 10,260,977 172,215,488 290,549,952 Other Outlays(*) 23,042,888 0 0 23,042,888 Gross Outlay 496,069,312 10,260,977 172,215,488 313,592,832 Investment Tax Credits 0 0 0 0 Other Income Tax Offsets 0 0 0 0 Net Total Capital Requirement Net Cash Outlay 496,069,312 10,260,977 172,215,488 313,592,832 AFUDC - Equity(**) 26,179,826 AFUDC - Interest 16,696,738 Total (Excluding capital cost adders) 538,945,856 Gross Depreciable investment 510,357,920 Non-Depreciable Net Plant Outlay(**) 2,408,152 Equity AFUDC 26,179,826 Total Non-Depreciable Investment 28,587,978 Capital Cost Adders 32,700,000 Total Capital Requirement 571,645,888 Less Investment Tax Credit 0 Net Total Capital Requirement 571,645,888

(*) Consists Of Land 0 Preproduction Costs 20,634,736 Prepaid Royalties 0 Inventory Cap + Init Cat/Chem 2,408,152 Total 23,042,888

(*) Consists of.

Preferred Stock AFUDC 0 Common Equity AFUDC 26,179,826 Total 26,179,826 (t) Consists of Land 0 Inventory Cap + Init Cat/Chem 2,408,152 Total 2,408,152

.26

SIMPLE CYCLE EMISSIONS Variable Value Units PLANT DESIGN BASIS Ambient Air Temperature 59 F Site Elevation Above MSL 695 ft Cycle Type Simple Cycle Number of Combustion Turbines Operating 12 CT Primary Fuel Type Natural Gas CT NOx Control Type - Primary Fuel Dry Low NOx Combustors Inlet Air Cooling Fogging CT Air Precooler Discharge Temperature 52 F AIR EMISSIONS - COMBUSTION TURBINES Firing Primary Fuel C02 Mass Flow Per CT Stack 113,904.96 lb/h CO"Mass Flow Per CT Stack 53.27 lb/h NOx (As N02) Mass Flow Per CT Stack 31.51 lb/h S02 Mass Flow Per CT Stack 0 lb/h CO Concentration 25 ppmvd @ 15% 02 NOx Concentration 9 ppmvd @ 15% 02 S02 Concentration 0 ppmvd@ 15% 02, Volumetric Flow Rate Per CT Stack 1,483,875 ft3/min-act C02 Mass Flow Total Plant 1,366,859.50 Ib/h CO Mass Flow Total Plant 639.24 lb/h NOx (As N02) Mass Flow Total Plant 378.07 lb/h S02 Mass Flow Total Plant 0 lb/h LIQUID DISCHARGES Total Waste Water Discharge Peak Flow 962 gpm Total Waste Water Discharge Average Flow 29 gpm

.27

COMBINED CYCLE COMBINED CYCLE COSTS TOTAL PROCESS CAPITAL 452,102,016 General Facilities 13,563,060 Engineeing and Home Office Fees 31,647,140 Project Contingency 45,210,200 Process Contingency 0 TOTAL PLANT COST 542,522,368 AFUDC or IDC See Capital Outlay Table TOTAL PLANT INVESTMENT 542,522,368 TOTAL PLANT'INVESTMENT ($/kW) 515.02 Prepaid Royalties 0 Preproduction Costs 17,795,884 Inventory Capital 2,712,611 Land 0 Capital Cost Adders 27,400,000 TOTAL CAPITAL REQUIREMENT 590,430,848 0 + M and Fuel Costs (in Base Year (2002) $)

Fixed 0 + M Direct Operating Labor 1,069,159

- Number of Operating Staff 17 Direct Maintenance Labor 901,818

- Number of Maintenance Staff 15 Annual Services, Materials, & Purchased Power

- Annual O&M Services & Materials 348,525

- Non-operating Purchased Power 115,347 Indirect Labor Costs

- Benefits 616,896

- Home Office Costs 294,421 TOTAL FIXED O+M 3,346,168 28

I -, *COMBINED CYCLE COSTS (continued)

Variable O+M Scheduled Maintenance Parts & Materials

- CT Inspection/Overhaul 9,312,600

- HRSG Inspection/Refurbish 592,303

- ST Inspection/Overhaul 744,000

-BOP. Refurbish 506,000 Scheduled: Maintenance Labor

- CT Inspection/Overhaul 651,882

- HRSG Inspection/Refurbish 177,691

- ST Inspection/Overhaul 111,000

- BOP Refurbish 85,199 Unscheduled Maintenance Allowance 582,049 Catalyst Replacement

- SCR Catalyst Materials & Labor 177,024 CO Catalyst Materials & Labor 1 0 Other Consumables

-.Raw water 1,831,258

- Circulating water 0

- NH3 50,773

- H2SO4 39,568

- NaOH. 47,780

- Misc 44,655 Disposal Charges,

- Spent SCR catalyst .11,064

- Spent CO catalyst 0

- Other disposal 3,875 Byproduct Credit 0 Total Non Gas Variable O+M 14,962,721 Total Non Gas Variable O+M ($/MWh) 92% CF 1.83 Total Fixed and Variable O+M 18,308,889 I

I I

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29 I

COMBINED CYCLE CAPITAL OUTLAY Category Total 1 2 3 Calendar Year (Jan 1 - Dec 31) 2004 2005 2006 Total Plant Cost In Base Year (2002) Currency 516,219,648 21,360,704 57,966,872 436,892,064 Amount of Escalation 40,424,964 862,972 3,548,036 36,013,956 Escalated Total Plant Cost 556,644,608 22,223,676 61,514,908 472,906,016 Other Outlays(*) 21,705,646 0 0 21,705,646 Gross Outlay 578,350,208 22,223,676 61,514,908-494,611,648 Investment Tax Credits 0 0 0 0 Other Income Tax Offsets 0 0 0 0 Net Total Capital Requirement Net Cash Outlay 578,350,208 22,223,676 61,514,908 494,611,648 AFUDC - Equity(") 23,202,630 AFUDC - Interest 14,858,861 Total (Excluding capital cost adders) 616,411,712 Gross Depreciable Investment 590,387,456 Non-Depreciable Net Plant Outlay( m ) 2,821,663 Equity AFUDC . 23,202,630 Total Non-Depreciable Investment 26,024,294 Capital;CostAdders 27,400,000 Total, Capital-Requirement 643,811,776 Less Investment Tax Credit 0 Net Total Capital Requirement 643,811,776

(*)Consists Of Land 0 Preproduction Costs 18,883,982 Prepaid Royalties 0 Inventory Cap + Init Cat/Chem 2,821,663 Total 21,705,646

(*) Consists of Preferred Stock AFUDC 0 Common Equity AFUDC 23,202,630 Total 23,202,630

(*) Consists of:

Land 0 Inventory Cap + Init Cat/Chem 2,821,663 Total 2,821,663 30

COMBINED CYCLE EMISSIONS Variable Value Units PLANT DESIGN BASIS Ambient Air Temperature 59 F Site Elevation Above MSL 695 ft Cycle Type Combined Cycle Cogeneration Number of Combustion Turbines Operating 4 CT'Primary Fuel Type Natural Gas CT NOx Control Type - Primary Fuel Dry Low NOx Combustors CT Air Precooler Discharge Temperature 59 F Cooling System Type Wet Mech Draft Cooling Twr SCR Configuration Anhydrous Ammonia Injection NOx Conversion Efficiency (%), Primary Fuel 45 AIR EMISSIONS - HRSG's Firing Primary Fuel CO2 Mass Flow Per HRSG Stack 213,608.19 lb/h CO Mass Flow Per HRSG Stack 40.42 lb/h NOx (As N02) Mass Flow Per HRSG Stack 33.2 lb/h NH3 Mass Flow Per HRSG Stack 12.27 lb/h S02 Mass Flow Per HRSG Stack 0 lb/h CO Concentration 10 ppmvd@. 15% 02 NOx Concentration 5 ppmvd @ 15% 02 NH3 Concentration 5 ppmvd@ 15% 02 S02 Concentration 0 ppmvd @ 15%.02 Volumetric Flow Rate Per HRSG Stack 1,045,319 ft3/min-act C02 Mass Flow Total Plant 854,432.75 lb/h CO Mass Flow Total Plant 161.68 lb/h NOx (As NO2) Mass Flow Total Plant 132.81 lb/h NH3 Mass Flow Total Plant 49.08 lb/h S02 Mass Flow Total Plant 0 lb/h LIQUID DISCHARGES Raw Cycle Water Make-up Peak Flow 147 gpm Raw Cycle Water Make-up Average Flow 98 gpm Cooling Tower Make-up Peak Flow 7,319 gpm Cooling Tower Make-up Average Flow 4,879 gpm Cooling Tower Blowdown Peak Flow 1,403 gpm Cooling Tower Blowdown Average Flow 936 gpm Total Waste Water Discharge Peak Flow 18,747 gpm Total Waste Water Discharge Average Flow 1,036 gpm SOLID WASTES SCR Catalyst Material Vanadium Pentoxide/Zeolite SCR Catalyst Volume 922 ft3 SCR Catalyst Replacement Frequency 5 to 10 years J 31

REPOWER REPOWER ONE UNIT 4X1 Costs TOTAL PROCESS CAPITAL 342,284,992 General Facilities 10,268,550 Engineering and Home Office Fees 23,959,950 Project Contingency 34,228;500 Process Contingency 0 TOTAL PLANT COST 410,742,016 AFUDC or IDC See Capital Outlay Table TOTAL PLANT INVESTMENT 410,742,016 TOTAL PLANT INVESTMENT ($/kW) 386 Prepaid Royalties 0 Preproduction Costs 15,530,286 Inventory Capital .2,053,709 Initial Cost - Catalyst and Chemicals 0 Land 0 Capital Cost Adders 37,400,000 TOTAL CAPITAL REQUIREMENT 465,725,984 0 + M and Fuel Costs (in Base Year (2002) $)

Fixed O + M Direct Operating Labor 1,069,159

- Number of Operating Staff 17 Direct Maintenance Labor 901,818

- Number of Maintenance Staff 15 Annual Services, Materials, & Purchased Power

- Annual O&M Services & Materials 374,337

- Non-operating Purchased Power .120,404 Indirect Labor Costs

- Benefits 616,896

- Home Office Costs 294,421 TOTAL FIXED O+M 32

I 1

REPOWER ONE UNIT Costs (Continued)

] "Variable O+M Scheduled Maintenance Parts & Materials

- CT Inspection/Overhaul 8,863,800

- HRSG lnspection/Refurbish 582,614

- ST Inspection/Overhaul 744,000

- BOP Refurbish 500,000 Scheduled Maintenance Labor

- CT Inspection/Overhaul 620,466

- HRSG Inspection/Refurbish 174,784

- ST Inspection/Overhaul 111000

- BOP Refurbish 85,199 Unscheduled Maintenance Allowance 529,098 Catalyst Replacement

- SCR Catalyst Materials & Labor 172,608

- CO Catalyst Materials & Labor 0.

I Other Consumables

- Rawwater 1,843,527

- Circulating water 0

- NH3 46,357

- H2SO4 39,547

- NaOH.. 47,755 I - M1sc 44,781 Disposal :Charges

- Spent SCR catalyst 10,788

- Spent CO catalyst 0

- Other disposal 3,698 Byproduct Credit 0 Total Non Gas Variable O+M 14,420,022 Total Non Gas Variable O+M ($/MWh) 1.68 Total Fixed and Variable O+M 14,420,022 I

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]

REPOWER ONE UNIT Capital Outlay Category Total 1 2 3 Calendar Year (Jan 1 - Dec 31) 2004 2005 2006 Total Plant Cost In Base Year (2002) Currency 394,110,016 16,382,303 53,702,056 324,025,664 Amount of Escalation 30,658,974 661,845 3,286,995 26,710,134 Escalated Total Plant Cost 424,769,024 17,044,148 56,989,052 350,735,808 Other Outlays(*) 18,576,800 0 0 18,576,800 Gross Outlay 443,345,792 17,044,148 56,989,052 369,312,608 Investment Tax Credits 0 0 0 0 Other Income Tax Offsets .0 0 0 0 Net Total Capital Requirement Net Cash Outlay 443,345,792 17,044,148 56,989,052 369,312,608 AFUDC - Equity(**) .18,400,370 AFUDC - Interest 11,775,106 Total (Excluding .capital cost adders) 473,521,280 Gross Depreciable Investment 452,966,720 Non-Depreciable Net Plant Outlay(***) 2,154,211 Equity AFUDC 18,400,370 Total.Non-Depreciable Investment 20,554,580 Capital: Cost Adders 37,400,000 Total Capital Requirement 510,921,312 Less: Investment Tax Credit 0

.Net Total.Capital Requirement 510,921,312

(*)Consists,Of Land 0 Preproduction Costs 16,422,588 Prepaid Royalties 0 Inventory Cap + Init Cat/Chem 2,154,211 Total 18,576,800

(*) Consists of:

Preferred Stock AFUDC 0 Common Equity AFUDC 18,400,370 Total 18,400,370

(***) Consists of.

Land 0 Inventory Cap + Init Cat/Chem 2,154,211 Total 2,154,211 34

• 1 REPOWER ONE UNIT 4X1 Emissions Variable Value Units PLANT DESIGN BASIS Ambient Air Temperature 59 F Site Elevation Above MSL 695 ft Cycle Type Combined Cycle Cogeneration Number of Combustion Turbines Operating 4 CT Primary Fuel Type Natural Gas CT NOx Control Type - Primary Fuel Dry Low NOx Combustors CT Air Precooler Discharge Temperature 59 F Cooling System Type Wet Mech Draft Cooling Twr SCR Configuration Anhydrous Ammonia Injection NOx Conversion Efficiency (%). Primary Fuel 51 I Include Duct Burners Duct Burner Use Yes Full-Time I DB Primary Fuel Type Natural Gas AIR EMISSIONS - HRSG's Firing Primary Fuel C02 Mass Flow Per HRSG Stack 225,714.88 lb/h CO Mass Row Per HRSG Stack 57.35 lb/h NOx (As N02) Mass Flow Per HRSG Stack 34,77 lb/h NH3 Mass Flow Per HRSG Stack 12.85 lb/h S02 Mass Flow Per HRSG Stack 0 lb/h CO Concentration 14 ppmvd @ 15% 02 NOx Concentration 5 ppmvd @ 15% 02 NH3 Concentration 5 ppmvd @ 15% 02 S02 Concentration 0 ppmvd @ 15% 02 Volumetric Flow Rate Per HRSG Stack 979,280 ft3/min-act C02 Mass Flow Total Plant 902,859.50 lb/h CO Mass Flow Total Plant 229 lb/h NOx (As N02) Mass Flow Total Plant 139.07 lb/h NH3 Mass Flow Total Plant 51.4 lb/h 0

S02 Mass Flow Total Plant lb/h LIQUID DISCHARGES Raw Cycle Water Make-up Peak Flow 179 gpm Raw Cycle Water Make-up Average Flow 119 gpm Cooling Tower Make-up Peak Flow 8,681 gpm Cooling Tower Make-up Average Flow 5,787 gpm I Cooling Tower Blowdown Peak Flow Cooling Tower Blowdown Average Flow Total Waste Water Discharge Peak Flow 1,664 1,110 21,951 gpm gpm gpm I Total Waste Water Discharge Average Flow 1,231 gpm I 35

REPOWER ONE UNIT 4X1 Emissions (Cont.)

SOLID WASTES SCR Catalyst Material Vanadium Pentoxide/Zeolite SCR Catalyst Volume 1,039 ft3 SCR Catalyst Replacement Frequency 37,386 years 36