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IGCC Technology Overview&

Genoa Site FeasibilitySeptember 3, 2008

Response to March 29, 2008, Vernon Electric Cooperative Resolution

In response to the resolution passed at the VEC annual meeting, which states the following: Dairyland Power Cooperative should convert the Genoa pulverized coal plant to Integrated Gasification Combined Cycle (IGCC) technology in order to meet EPA emission standards.

EXECUTIVE SUMMARYDairyland has conducted a detailed and careful evaluation of gasification technology and the concept of repoweringourGenoa#3Station(G-3)withtheadditionofthistechnology.Followingthisevaluation,we have determined it is not technically nor logistically feasible to use this technology at the Genoa Site.Evenifitwerepossibletoimplement,theeconomicimpactandhighlevelofuncertaintyregardingthis new technology would put all Vernon Electric Cooperative ratepayers and those of other member cooperatives in the Dairyland system at risk.

There are six major issues which prevent Dairyland from converting the G-3 plant to a gasification facility:

1) Reliability–ThefewexistingcommercialapplicationsofgasificationorIGCCtechnologyhaveproved to be extremely unreliable. While several utilities have proposed IGCC projects, almost all have been put on hold or rejected by state public service commissions because of the lack of proven reliability and high cost.

2) SpaceLimitations–Thereisnotasufficientareaforlaydownandconstructionofaprojectofthismagnitude and not enough land to accommodate such a facility, which would include gasifiers, supportsystems,watertreatment,fuelhandling,andauxiliaries,ontheGenoaSite.

3) BoilerandTurbineDesign–Theexistingboilerwouldnotbeamenabletoconversiontosyntheticgas and would have to be completely replaced. The existing boiler is also not compatible with IGCCtechnologywhichwoulduseaHeatRecoverySteamGenerator(HRSG).WedonotbelieveanHRSGcouldbedesignedtomatchthesupercriticalpressure,temperature,anddual-reheat design of the existing turbine, necessitating its replacement as well.

4) ReplacementPowerCosts–Whiletheexistingboilerwasrazedandnewequipmentwaserected,which would likely take several years, the Dairyland system would be in need of replacement electricity. This very significant capacity and energy purchase would have to be made in a very volatile market with extraordinarily unacceptable pricing risks.

5) Economic–ThecurrentG-3planthasanestimatedreplacementvaluetodayofover$1billion.We estimate the cost of demolishing G-3 and replacing it with new gasification or IGCC equipmenttobemorethan$1.5billion.SinceG-3has20ormoreyearsofremainingusefullife,this significant expenditure is not justified, especially since no additional energy nor air quality benefits would be gained after all of that expense.

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6) Permitting–Ourexperienceisthatpermitsforsuchamajorprojectwouldbedifficulttoobtain,if even possible. Particularly given the risky nature of IGCC technology, it could literally take years to receive the necessary permits for construction.

In addition to these six primary issues, there are myriad additional items which could be problematic. We have elaborated on some of these issues throughout the remainder of this document.

Dairyland takes seriously our responsibility to evaluate all alternatives before launching a major project such as the environmental upgrades to the G-3 plant. The production of electricity is an incredibly complex business. In this document, we will expand on the points made above.

This is fairly technical information; however, we understand the sincere desire by members to have us explore this option. Therefore, we will thoroughly explain in this document our rationale for why we have determined IGCC is not the right answer at Genoa, as we work to improve the environment and meet state and federal air pollution regulations.

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BACKGROUND & TECHNOLOGY OVERVIEW

G-3 BACKGROUNDGenoa#3Station(G-3)wascompletedin1969atacostof$56million.G-3wasnamedsimplybecause it was the third generating facility to be built in Genoa, Wis. This single-unit coal-fired facility has a generating capacity of about 375 megawatts (MW) or 375,000 kilowatts of electricity. On average, each MW of electrical production can power nearly 650 homes. G-3 produces over 2 billion kilowatt-hours (kWh) of electric energy each year.

G-3 is extremely efficient, due mainly to a unique double reheat of the steam and supercritical steam pressures. The term “supercritical” is used for power plants with high operating pressures above where normal boiling occurs at a given temperature. For water at 1000 deg F, the supercritical point occurs at pressures in excess of 3,200 psi (pounds per square inch).

Supercriticalunitscanachievethermalefficiencyofmorethan45%,comparedwithatypicalsubcriticalplant’s30-38%.SupercriticalpowergenerationunitslikeG-3’sfeature“once-through”boilersdesignedtooperatewithpressuresfrom3,500to4,000psi,versus1,800to2,500psiforconventionalboilers.Higherfiring temperatures and pressures translate into better efficiency, defined as more electricity generated perBTUofcoalconsumed.Thisisimportanttopowerproducersandconsumers,astheseincreasedefficiencies translate into reduced fuel costs and fewer emissions for every kilowatt-hour generated.

In essence, the boiler is used to convert the chemical energy in the coal to heat energy. The heat from the burning fuel causes water in the boiler to change into steam. The steam, which now contains heat energy, is sent to turbines, where it causes the turbine blades to rotate, transforming much of its energy into a mechanical form. In the case of G-3, this steam is sent back to the boiler for reheating twice prior to use in additional turbines. A shaft connects the turbines to a generator through couplings. As the turbine blades rotate, they cause the generator shaft to rotate. The generator converts the rotating mechanical energy into electrical energy.

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IGCC TECHNOLOGY OVERVIEWIt is important to understand both the basics of IGCC technology and concepts as well as those of G-3 beforeaninformeddecisionabouttheuseofthistechnologyattheGenoaSitecanbemade.

IGCC is a type of power plant that generates synthetic gas (syngas) from coal and then burns that syngas to power a gas turbine (similar to a jet engine). The heat from the gas turbine exhaust then generates steamtorunasteamturbine.Noneofthebasictechnologies–coalgasification,gasturbinesandsteamturbines–arenew.Itistheintegration of these into electric power plants that is new, and presents engineering challenges. A typical schematic is provided.

IGCC technology basically consists of four processes: gasification, gas cleanup, gas turbine combined cycle operationsandcryogenicairseparation.Thefourprocessesmustbeintegratedtooptimizetheplant.

The first process is gasification. A feedstock (fuel, such as coal) can be gasified in several ways. The most commontechniquepartiallyoxidizesthefeedstockwithpureoxygeninsideareactor.Thecarbonandhydrogen from the feedstock are converted into a mixture composed primarily of hydrogen and carbon monoxide.Thismixtureiscommonlycalledsyngas.Syngashasaheatingvalueof125to350BTU/scf,which is three to eight times lower than that of natural gas.

The syngas from the reactor must be cleaned before it can be used as a gas turbine fuel. The cleanup process typically involves removing sulfur compounds, ammonia, metals, alkalytes, ash and particulates to meet the gas turbine’s fuel gas specifications. To make IGCC more economically attractive, marketableproductssuchasmethanol,ammonia,fertilizersandotherchemicalscanbeproducedfromthe compounds removed from the syngas. This process often further reduces the hydrogen content and therefore the heating value of the syngas. These processes need to be further evaluated based on market conditions and the cost for each specific process.

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A gas turbine combined cycle is characteristic of a power producing engine or plant that employs more than one thermodynamic cycle.Sinceheatenginesareonlyabletouseaportionoftheenergytheirfuelproduces(usuallylessthan50%),theremainingheatfromcombustionisgenerallywasted.Combiningtwoormore“cycles” results in improved overall efficiency. In a combined cycle gas turbine plant, a gas turbine generator produceselectricityandthewasteheatisusedtomakesteaminaheatrecoverysteamgenerator(HRSG)togenerate additional electricity via a steam turbine. This enhances the efficiency of electricity generation.

A cryogenic air separation unit is required to provide pure oxygen to the gasification reactor, often using or being supplemented with post-compression air bleed from the gas turbine. This is a fairly complex process in itself.

There are many variations in the air separation cycles which are used to make industrial gas products. Design variations arise from differences in user requirements. Process cycles are somewhat different depending upon how many products are desired (either nitrogen or oxygen, both oxygen and nitrogen, or nitrogen, oxygen and argon); required product purities; gaseous product delivery pressures; and whether one or more products will need to be produced and stored in liquid form.

All cryogenic air separations consist of a similar series of steps;• Filtering,compressingandcoolingair• Removingwatervaporandcarbondioxide• Cryogeniccooling(~-300deg.F)andcolumndistillation

Variationsincryogenicairseparationreflectthedesiredproductmix(ormixes)andthepriorities/evaluationcriteriaoftheuser.Somedesignsminimizecapitalcost,someminimizeenergyusage,somemaximizeproductrecovery,andsomeallowgreateroperatingflexibility.

ThetwoexistingIGCCfacilitiesintheU.S.areinthe250MWnetrangeandemployGEframe7FAgasturbinesratedatapproximately192MWandHRSG/steamturbinecombinationsinthe125MWvicinity.As much as 65 MW of the electricity generated by these plants is used to power auxiliaries.

Advantages of Integrated Gasification Combined Cycle (IGCC)

IGCC is an advanced technology that represents the cleanest of currently available coal technologies. Advantages of IGCC over current conventional coal-based power generation systems include:

• Higherefficienciesandloweremissions-Improvementsinefficiencydramaticallyreduceemissionsfromcoalcombustion.Increasingefficiencyfrom35to40%,forexample,reducescarbondioxideemissionsbyover10%.Withefficienciescurrentlyapproaching50%,IGCCpower plants use less coal.

• Higheroutput-Usingsyngasinagasturbineincreasesitsoutput,especiallywhennitrogenfroman oxygen blown unit is fed to the turbine. Thus a turbine rated at 170 MW, when fired on natural gas, can yield 190 MW or more on syngas. Furthermore, output is less dependent on ambient temperature than is the case with natural gas.

• Productflexibility-includingcarboncaptureandhydrogenproduction-Thegasificationprocessin IGCC enables the production of not only electricity, but a range of chemicals, by-products for industrial use, and transport fuels.

• Carbondioxidecanbecapturedfromthecoalsyngas(carbonmonoxideandhydrogen)throughawater/gasshiftprocess-TheCO2canbecapturedinaconcentratedstream,makingiteasierto convert into other products, or to sequester (for example, store underground). An added advantage in this process is that there are low additional costs for carbon capture, particularly if the plant is oxygen driven.

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• Inadditiontoelectricitygeneration,hydrogenproducedfromtheprocesscanpotentiallybeusedas a transport fuel, in fuel cells.

Barriers to Implementing IGCC at GenoaWhile it is clear that IGCC technology needs to be evaluated as a potential resource in the future, as any utility looks at adding new generators on the system; Dairyland finds the following issues to be significant barriers when looking at it for renovating our existing G-3 plant.

ISSUE 1 – IGCC RELIABILITYIGCC technology is still in its infancy with only limited commercial applications in existence. These initial operations have proven to be extremely unreliable in comparison to existing coal technologies. While several utilities have proposed IGCC projects, several state public service commissions have rejected them because of the high cost and the lack of proven reliability.

The following chart depicts availability percentages for various existing gasification type projects.

These availability percentages are much lower than what we would expect out of coal-fired generators. Many experts hope that the next generation of IGCC will have availability which is more in line with current industry expectations; but the current state of the technology has not demonstrated that level of availability. Current and near-term IGCC plants must be viewed as technically feasible, but not delivering the cost or the performance to be economically attractive.

ASeptember2004studycommissionedbythe DOE found that, despite a long history of gasification, only two gasified coal plants whose primary output is for electrical generation have been built in this country.

A number of studies have looked at “market barriers” to widespread IGCC implementation. IGCC “uncertainties” include lack of standard plant design, performance guarantees and high capital costs. These uncertainties call into question whether the technology is commercially viable today. IGCC veteran StephenD.JenkinstestifiedinJanuary2007thatIGCCtechnologywillnotbereadyforsixtoeightyears, has limited performance and emissions guarantees, and that commercial-scale carbon dioxide capture and storage has not been demonstrated.

ThetwocurrentlyoperatingIGCCplantsintheU.S.arethePolkplantinTampa,Florida,andWabashRiverinIndiana.Althoughmanypetroleumandchemicalplantsemploygasification,thePolkandWabashRiverplantsaretheonlyutilityscalefacilitiestousecoaltogenerateelectricalpowerwithcombined cycle turbines.

The “FutureGen” project, a 275 MW “clean coal” IGCC demonstration program of the DOE, was four yearsintoitsplanningandscheduledtobeconstructedinIllinoiswhenitwasrecently(January2008)cancelledbytheDOEbecausethebudgetestimateclimbedto$1.8billionfrom$1.0billionandofficialsfeared it would increase further.

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ISSUE 2 – SPACE LIMITATIONSThe lack of space for the extensive chemical plant required by IGCC, and the need for a wastewater treatment plant, are the main barriers to even considering this technology at Genoa.

There is inadequate area for lay down of materials and construction for a project of this magnitude and not enough land to accommodate the completed facility (including gasifiers, support systems, water treatment,fuelhandlingandauxiliaries)ontheGenoaSite.

ThesizeofexistingIGCCfacilitiesisestimatedtobeapproximately100acresormore.Thesizeofourentire property at Genoa is 80 acres. Without even considering scale up issues to match Genoa’s current output, it is doubtful that the Genoa site could support a project like this. The geographic constraints of Highway35,therailroadtracksandtheMississippiRiverlimittheamountoflandavailable,alongwithexisting plant facilities that could not be eliminated.

In addition to land issues for the proposed IGCC facility, there are legitimate concerns about construction laydown and fabrication areas that are required above and beyond the footprint of the facility. It is believed that much of this construction land would need to be found off-site of the existing facility, adding to construction cost, complexity, traffic and safety concerns.

ISSUE 3 – G-3 BOILER AND TURBINE DESIGNThe existing G-3 boiler would not be amenable to conversion to the burning of synthetic gas and would have to be completely replaced. The boiler is also not compatible with IGCC technology which would useaHeatRecoverySteamGenerator(HRSG).ItisdoubtfulthatwecoulderectaHRSGboilertomatch the supercritical pressure, temperature, and dual-reheat design of the existing turbine, necessitating replacement of the turbine as well.

Inaddition,theexistingsteamturbineisfartoolarge(~375MW)touseinacombinedcycleapplication,renderingituselessatanIGCCplant.TypicalIGCCapplicationshavesteamturbine/generatorsetsratedat approximately 125 MW.

Therefore, the boiler and turbine at G-3 would need to be replaced in a IGCC retrofit. These issues of incompatibleboilerandturbinedesignwouldforcetheexistingbuildingtoberazedandnewfacilitieslikely put in their place. This would add to initial demolition costs and would impose extraordinary replacement power costs on the cooperative for the extended period that the facilities were unavailable.

ISSUE 4 – REPLACEMENT POWER COSTSItwouldtakeseveralyearstorazetheexistingboileranderectnewequipment.Duringthattime,theDairyland system would need to buy replacement electricity to serve our cooperative members needs. With growing energy needs in the region, it would likely be virtually impossible to secure long-term replacement power for a large facility such as G-3 without simply relying on the energy market. This significant capacity and energy purchase would have to be made in a very volatile market with huge upward price risks.

RecentaveragemarketpricingsuggeststhattheenergywhiletheG-3facilityisnotoperatingwouldbeapproximately$87millionmoreexpensivethanifG-3wereoperating.Theuseofaveragepricingdoesnot account for the risk inherent in the wildly volatile marketplace of today.

In addition to the need to replace energy during demolition and construction of the new facility, power generatingcapacitywouldneedtobepurchasedtocoverthesizelimitationsofthefacility.CurrentlyIGCC technology has capacities in the range of 250 MW. This 125 MW shortfall needs to be replaced yearly.Usingthesamemarketassumptions,theyearlycosttocoverthecapacityshortfallwouldbeapproximately$11million.

These are all costs that would need to be absorbed by Dairyland’s membership that would not be required without the IGCC plant.

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ISSUE 5 – ECONOMIC CONSIDERATIONSThecurrentG-3planthasareplacementvaluetodayofwellover$1billion.WeestimatethecostofremovingthefacilityandreplacingitwithnewequipmentforanIGCCretrofittobemorethan$1.5billion.SinceG-3has20ormoreyearsofremainingusefullifethiskindofsignificantexpenditureisnotjustified, especially since no additional energy would be gained after all of that expense.

Capital Cost vs. EfficiencyIGCC has the potential to use coal in a more efficient process and with lower emissions than conventional coal power plants. The combined cycle portion of the process is attractive from a capital cost perspective compared to a conventional coal plant, but the addition of gasification, coal feeding, gas cooling, gas cleanup, and the oxygen plant result in an overall cost that is higher than a conventional coal plant. Higherefficiencythanaconventionalcoalplantcouldjustifyhighercapitalcosts.However,thecurrentlydemonstratedcapitalcostisabout30%higherandefficiencyisonlyabout5%betterthanaconventionalcoalplant.In2004,IndeckEnergyServicestestifiedbeforetheIllinoisStateEPAthatIGCC’s“capitalcostsare30%higher.”

TheU.S.DepartmentofEnergy(DOE)initiallyestimatedthetotalcapitalcostfortheproposed600MWIGCCMesabaplantinMinnesotaat$800million,butthefinalcostiscurrentlyestimatedat$2.155billionor$3,593perkW, not including carbon capture, transportation or storage. In April 2007, Minnesota’sOfficeofAdministrativeHearings,astateagencychargedwithconductingnon-partialandbalanced reviews of contentious cases, rejected the Mesaba plant, finding:

• NeithertheprojectnortheIGCCtechnologyislikelytobealeast-costresource• Emissionsofnitrogenoxides(NO

x) and mercury are not reduced significantly, and are not lower

thancurrentlyavailablecontroltechnologyforpulverizedcoal• Thereisnoguaranteeofcarbonsequestration• Theplantwouldcost9-11cents/kWh;andcapturingandtransportingthecarbonwouldaddat

least5cents/kWh.

Wisconsin’sPublicServiceCommission(PSC)andDepartmentofNaturalResources(DNR)collaborated in a task force review of IGCC technology in 2006, with a report issued in February 2007.Inthestudy,IGCCwascomparedtoconventionalsupercriticalpulverizedcoal(SCPC)planttechnology. The report was to review the costs, benefits and prospects for future use of IGCC in the state of Wisconsin.

The task force investigation showed that IGCC, before considering the treatment for carbon dioxide, has acostpremiumoverSCPCof$5to$7/MWh(onabout$50energycost)withcostsprimarilydependenton construction, operational reliability and heat rate. Many in the industry believe these premiums could beevenmoresubstantial.Thefinalreportofthetaskforceadditionallyrecognizedthedifficultyinestimating the construction costs, as only two IGCC plants are operating in this country and both were constructedmorethan10yearsago(PolkStationinFloridaandWabashRiverStationinIndiana–bothabout 250 MW).

The Minnesota Department of Commerce estimated carbon dioxide sequestration costs for Mesaba at roughly$1.107billionin2011;andpipelinecostsat$635.4million.Carbondioxidesequestrationandstorage costs are highly uncertain as none of this has been done before on a power plant scale.

ContinuingimprovementsinefficiencyofSCPCplantdesignsisdrawingintoquestionwhetherIGCCwillbeabletoclaimanyadvantagebasedonenvironmentalimpactinthenearfuture–withtheexception of carbon dioxide capture, and it appears now that DOE is suggesting that retrofit CO2 capture onSCPCplantsmaybeverycomparabletoIGCC.

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A review of data from the Department of Energy also indicates that G-3 has the lowest heat rate (best efficiency)ofanyutilityboilerintheStateofWisconsininrecentyears,makingittheleastattractiveoption for repowering to new technology from a state wide perspective.

Carbon Capture and Storage Economic RisksCarboncaptureandstorage(CCS)isanapproachtomitigate global warming by capturing carbon dioxide (CO

2) from large point sources such as fossil fuel power plants and storing it instead of releasing

itintotheatmosphere.StorageoftheCO2 is envisaged either in deep geological formations, in deep

ocean masses, or in the form of mineral carbonates. After capture, the CO2 must be transported to

suitable storage sites. This is done by pipeline, which is generally the cheapest form of transport. The pipeline system that would be required largely doesn’t exist today.

AccordingtotheDOE,IGCCCCSisseenastooriskyforprivateinvestors,andrequiresenormoussubsidies from the federal, state and sometimes local government. Extensive research is required before a commercial-scale IGCC plant could capture, transport and store carbon dioxide.

A February 2006 presentation on IGCC by Xcel Energy stated that the “wild card” in the IGCC cost equation is carbon dioxide capture, but no currently operating plants include carbon dioxide capture. Transport and storage costs must also be included in the total cost of electricity.

It is also worth noting that ongoing research relative to CO2 capture on conventional coal facilities

suggests that the cost differential relative to IGCC facilities may not be as great as earlier estimated.

Stranded Investment in GenoaG-3hasanaccreditedcapacityofabout375MW.Theunitwascommissionedin1969,andsoisabout40years old; we expect its remaining life is on the order of about 20 more years. The installed replacement value,forasimilarfacilitytoday,iswellover$1billion(375MWx$3,000/kW).

ReplacingG-3withanIGCCplantwouldconceivablycostontheorderof$1.5billionbasedonthecancelled ‘FutureGen’ project, plus additional costs for the following:

• Razingexistingfacility• Replacementpowercostsforanextendedperiodduringdemolitionandconstruction• Permitting

Dairyland could not justify such a retrofit to a unit with an expected additional life in the range of 20 years. Even if our Board of Directors wanted to pursue this course of action, we do not believe it would be possible to obtain financing given those circumstances.

ISSUE 6 – PERMITTINGDairyland Power has significant concerns about whether such an IGCC facility could be permitted at all in the current regulatory environment. Our experience is that permits for such a major project would be difficult to obtain. Particularly given the risky nature of IGCC technology, it could take several years to receive the necessary permits for construction.

WEEnergiesrecently(2002)madeapplicationtothePSCforapprovaltobuilda600MWIGCCplantattheirElmRoadfacilitytocomplementtwoplanned600MWsupercriticalpulverizedcoalplants.ThatapplicationwasdeniedbythePSConthegroundsthatthetechnologywasnotsufficientlymatureforcommercial application at this scale and the costs not well-enough known. The decision of the Wisconsin PSCtorejectIGCCisconsistentwithactionsbyregulatingcommissionsinmanyotherstates.

American Electric Power (AEP) announced about two years ago their intent to build five IGCC plants within their service territory. They drastically scaled back that initiative to only two units as they were

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unabletosecureauthorizationforraterecoveryfromregulatorycommissions.OnMarch14,2008,theycancelled those two projects as well.

A special Minnesota law passed in 2003 committed Minneapolis-based Xcel Energytobuy450MWof power from Excelsior Energy’s proposed Mesaba Energy Project. In April 2007, the Minnesota PublicUtilitiesCommission’sAdministrativeLawJudgesrecommendedthattheMesabaplantbedenied a Power Purchase Agreement, as it is not a least-cost resource, nor an “innovative energy project” asdefinedbyMinnesotastatelaw.InAugust,thestatePUCaffirmedthisfinding,arguingthattheIntegrated Gasification Combined Cycle (IGCC) plant is not in the public’s best interest.

ISSUE 7 – MISCELLANEOUS ITEMSIn addition to the six primary issues, the following additional items could be problematic as well.

AIR EMISSIONS CHALLENGESPower plant emissions are higher during start-up procedures than in steady-state operation (some estimatesindicateasmuchas38%higher).Duetotheirinconsistentreliability,gasificationplantsrequireabout60start-up/shut-downeventseveryyear(asopposedtotwoorthreeforpulverizedcoal).Theseadditionalstart-up/shut-downepisodeswouldmakeitdifficulttocomplywithregulationslimitingairemissions. Based on research it is uncertain that IGCC alone could ensure compliance with the Clean Air Act regulations across our system of generators.

POTENTIAL FOR WASTEWATER ISSUESIGCC uses water to clean the syngas and thus creates additional water contamination and treatment issues.TheDOEIGCCpilotprojectinWabashRiver,Indianafoundthatelevatedlevelsofselenium,cyanide and arsenic in the wastewater caused a permit violation, and that selenium and cyanide limits were “routinely exceeded.”

Approaches under consideration to correct the issue include chemical precipitation, bio-remediation, reverse osmosis and evaporation. The additional cost and complexity of these potential solutions must be factored into any planned replication of this coal gasification technology.

CARBON DIOXIDE CAPTURE AND STORAGE TECHNICAL RISKSAs has been discussed previously, there are many economic issues associated with carbon dioxide capture and sequestration. There are many technical issues as well.

Although IGCC is promoted as being capture “ready,” no IGCC plants are actually capturing and storing carbon dioxide in commercial quantities.

A big problem for implementation in Wisconsin is that, once captured, there is no significant known geological reserve which is likely to work for carbon dioxide sequestration. To successfully sequester carbon dioxide captured from Wisconsin generating plants, pipelines will have to be built to suitable locations in other states. The technical, economic and political challenges to geologic sequestration of carbon dioxide are significant, and yet to be resolved.

GASIFICATION ISSUESIGCChasbeendemonstratedintwoU.S.commercial-scalefacilities.Avarietyofcoalshavebeengasified, the resulting gases have been cleaned up to allow use in combustion turbines, and electricity has beengenerated.However,thecapitalcostandperformanceinanumberofareashasnotbeenasattractiveas planned.

The troublesome areas for IGCC have included high-temperature heat recovery and hot gas cleanup. An important part of achieving an attractive heat rate is generation of high pressure and temperature steam from the high-temperature raw gas generated by gasifying coal.

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Thetemperatureoftherawgasisdependentonthegasificationprocessandthecoal.Slagginggasifiers,such as the Texaco process, typically generate gases in the 2500 to 2800oF range. These high-temperature gases containing corrosive compounds, such as hydrogen sulfides, create a very demanding environment for the generation of high pressure and temperature steam. The reliable generation of steam under these conditions has not been demonstrated in a commercial application. Alternatives not recovering the heat in the raw gas, such as direct quenching of the gas, result in lower efficiencies.

It is also attractive from an efficiency perspective to provide clean gas to the combustion turbine at an elevated temperature without cooling and reheating, hence the desire to use hot gas cleanup. Again, this demanding service has not been reliably demonstrated in a commercial application, resulting in less efficient approaches being used for current plants.

COMBUSTION TURBINE ISSUESSyngashasabout25%oftheheatingvalueofnaturalgas–meaningmuchmoremassflowthroughtheturbines is required. The most significant differences in the combined cycle are modifications to the combustionturbinetoallowuseofa250to300Btu/SCFgas.Whiletheseissuescanbeovercome,thereis much less industry experience on these types of machines calling into question their proven reliability.

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CONCLUSIONDairyland conducted a detailed and careful evaluation of gasification technology and the concept of repoweringGenoa#3Station(G-3)withthistechnology.Asaresult,wehavedeterminedthatthisoptionisnottechnicallynorlogisticallyfeasibleattheGenoaSite.Evenifitwerepossibletoimplement,theeconomic impact and high level of uncertainty regarding this new technology would put all Vernon Electric Cooperative ratepayers and the other cooperative members of the Dairyland system at risk. However,theenvironmentalcontrolsDairylandisintheprocessofimplementingatG-3WILLensurewe are improving air quality in our region and will remain in compliance with state and federal emission regulations while continuing to provide reliable and economic power to the region.

Significant References and Additional Reading

1. Integrated Gasification Combined-Cycle Technology: Costs, Benefits, and Prospects for Future Use in Wisconsin; February 2007; A joint study of the Department of Natural Resources and the Public Service Commission of Wisconsin.

2. Tampa Electric Integrated Gasification Combined-Cycle Project Fact Sheets; 2003; Clean Coal Technology Demonstration Program, Advanced Electric Power Generation.

3. Wabash River Coal Gasification Repowering Project Fact Sheets; 2003; Clean Coal Technology Demonstration Program, Advanced Electric Power Generation.

4. Tampa Electric Polk Power Station Integrated Gasification Combined-Cycle Project – Final Technical Report; August 2002; Tampa Electric Company.

5. Wabash River Coal Gasification Repowering Project – Final Technical Report; August 2000; Wabash River Coal Gasification Project Joint Venture.

6. Wabash River Coal Gasification Repowering Project – Project Performance Summary; January 2002; U.S. Department of Energy.

7. Wabash River Coal Gasification Repowering Project: A DOE Assessment; January 2002; U.S. Department of Energy, National Energy Technology Laboratory (NETL).

8. Practical Experience Gained During the First Twenty Years of Operation of the Great Plains Gasification Plant and Implications for Future Projects; April 2006; U.S. Department of Energy, Office of Fossil Energy.

9. Updated Cost and Performance Estimates for Clean Coal Technologies Including CO2 Capture - 2006 (Report 1013355); Technical Update March 2007; Electric Power Research Institute (EPRI).

10. Operating Experience, Risk, and Market Assessment of Clean Coal Technologies – 2007 (Report 1014212; Technical Update December 2007; Electric Power Research Institute (EPRI).

11. An Environmental Assessment of IGCC Power Systems; Presented at Nineteenth Annual Pittsburgh Coal Conference September 23-27, 2002; Jay A. Ratafia-Brown, et al., Science Applications International Corporation and Gary J. Stiegel, U.S. DOE/NETL.

12. FutureGen Fact Sheet; January 2008; U.S. Department of Energy

13. Rising Utility Construction Costs: Sources and Impacts; September 2007; The Brattle Group for The Edison Foundation.