- Cowlitz PUD

Capital Costs ...............................................................................................37Fixed O&M Costs.........................................................................................38Variable O&M Costs ....................................................................................39Resource Constraints......................................................................................41Addition Timeline .........................................................................................41Resource Potential ......................................................................................42Existing Resources..........................................................................................43Swift hydro...................................................................................................43Grant hydro..................................................................................................449 Canyon wind .............................................................................................44White Creek wind.........................................................................................44Industrial customers generation...................................................................45Chapter 5: Conservation .....................................................................................46Conservation Resources .................................................................................46Residential Weatherization Plus Program ...................................................47Residential Low Income Weatherization Plus Program ...............................47Residential Energy Matchmaker Program ...................................................47Residential Resource-Efficient Appliance Rebates......................................47Residential Compact Fluorescent Lighting (CFL) Program..........................47Residential Energy Efficient Heat Pump Rebate Program...........................48CEEP Plus Lighting Incentive Offer .............................................................48Commercial Energy Smart Program ............................................................48Industrial/Commercial EnergySPICE Plus Program ....................................49Industrial/Commercial Compressed Air System Efficiency (CASE) Program.....................................................................................................................49Conservation Programs under Development...............................................49Chapter 6: Theories of Model Operation.............................................................51Models Used in the IRP...................................................................................52Aurora XMP .................................................................................................52Crystal Ball...................................................................................................53OptQuest .....................................................................................................53Variability of Hydro Generation........................................................................54Market Heat-Rate ............................................................................................56Natural Gas Price Formation...........................................................................58Power Price Formation....................................................................................58CO2 Legislation...............................................................................................60Resource Adequacy ........................................................................................63Chapter 7: Analysis of Resource Portfolios.........................................................64IRP Approach ..............................................................................................64Chapter 8: Detailed Results ................................................................................72Effect of Legislation .........................................................................................78Chapter 9: Hourly Analysis .................................................................................80Chapter 10: BPA Contracts.................................................................................83Part 1: Overview..............................................................................................83BPA’s “Regional Dialogue” ..........................................................................83Major Components of BPA Proposal ...........................................................833

Part 2: Contract Analysis.................................................................................91“SWOT” analysis..........................................................................................91Chapter 11: Next Steps.......................................................................................92Action Plan – Resource Acquisition.................................................................92Action Plan – IRP Analysis..............................................................................934

Chapter 1: Executive SummaryPublic Utility District No. 1 of Cowlitz County (“Cowlitz” or “the District”) hasdeveloped this Integrated Resource Plan (IRP) in order to develop a long-rangeresource strategy for the period 2008-2027. The District’s IRP defines theDistrict’s need for new resources and investigates different generic resourcetypes with an objective of presenting both quantitative and qualitative analysis ofthe risk and rewards of pursuing different resource technologies to fulfill theDistrict’s future resource requirements.Resource NeedsThe first step in the IRP is establishment of electricity demand for the District’scustomers. Cowlitz constructed an econometric load forecasting model thataggregates forecasts for a variety of customer classes in the District’s serviceterritory. Figure 1 shows the resulting energy net position (i.e. the differencebetween projected annual energy loads and existing generation resources). TheDistrict is projecting adequate existing generation resources to meet its needsthrough most of the study period.Figure 1Net Position Forecast (aMW)2008 2009 2010 2011 2012 2013 2014 2015 2016 201732 32 32 31 30 27 25 22 21 172018 2019 2020 2021 2022 2023 2024 2025 2026 202714 12 10 5 1 (2) (5) (11) (15) (20)Figure 2 shows the current load resource balance projections. Most of theDistrict’s needs will be met from Tier 1 purchases from the Bonneville PowerAdministration (BPA). In addition to BPA contracts, the District will continuereceiving output from the White Creek wind project and the Swift No.2 project onthe Lewis River.Recently the citizens of Washington State passed Initiative 937 (referred toherein as “I-937” or “renewable portfolio standard”) that mandates the addition ofcertain qualifying renewable resources. Figure 3 shows the District’s projectedload resource balance with the addition of these resources5

Figure 2Load Resource Balance700675650625600575aMW550525500475450BPA Tier 1 Swift No.2 Renewable I-937 Additions Load Forecast42540020082009201020112012201320142015201620172018201920202021202220232024202520262027Figure 3Load Resource Balance with I-937 Additions700675650625600575aMW550525500475450BPA Tier 1 Swift No.2 Renewable I-937 Additions Load Forecast425400200820092010201120122013201420152016201720182019202020212022202320242025202620276

Post-2011 BPA PurchaseThe IRP analysis assumes that BPA will continue to make available Slice, Block,and Load Following products to the District at cost-based rates based on thepolicies that BPA adopted in the Regional Dialogue process. All scenariosanalyzed in the IRP assume that the District will purchase all of its entitlement toTier 1 power. The final decision on which product to purchase from BPA is notanswered in this IRP. Instead, this IRP includes an assessment of the positiveand negative attributes of the different products BPA will make available in thepost-2011 period.Modeling and ResultsThe District recognizes that the future is impossible to predict and even the bestforecasts can end up being very different from reality. Therefore, the Districtemployed a stochastic approach to identify the combination of resources bestsuited to meet its needs. Monte Carlo analysis varied underlying fundamentalconditions such as loads, hydro generation, fuel prices, power prices, capitalcosts, CO2 taxation over 100,000 iterations. Oracle Corporation’s OptQuest wasused to identify the combinations of resource additions that provide acceptableoutcomes across a wide array of possible futures. The results from theoptimization establish the efficient frontier of resource sets as shown in Figure 4.Figure 4Cost Risk Efficient Frontier$1,900,000$1,850,000Power Cost 20 Year NPV ($ Thousands)$1,800,000$1,750,000$1,700,000$1,650,000$1,600,000$1,550,000$1,500,000$1,450,000$1,400,000ABCD$55,000 $65,000 $75,000 $85,000 $95,000 $105,000 $115,000STDEV ($ Thousands)Each point on the graph represents a specific set of resource types added on aspecific timeline. The cost risk efficient frontier demonstrates the tradeoffs7

etween an expected low power cost and a measure of variance or risk. Ingeneral the tradeoff is similar to decisions faced by investors. An investor willshoulder additional risk only if he or she is compensated with a higher return.Likewise, if the investor seeks a lower amount of risk the only available choiceswill produce relatively lower returns. The same situation faces the District inchoosing a generation portfolio. The resource combinations that yield the lowestamount of variance have the highest expected power cost. Alternatively, thelowest cost portfolios have the highest amount of variance.The exact tradeoff will differ from utility to utility depending on management’stolerance for risk. Instead of picking a single point from the frontier, the Districtelected to generate a more generalized view of the resource types that workedwell in a certain “neighborhood”. This is illustrated on Figure 4 by the dashedoval line. Four portfolios were picked based on their performance and theirposition on the frontier. These are labeled as portfolios A, B, C and D. Thedetails of each (discussed at length in Chapter 8: Detailed Results) were thenaggregated.Figure 5 highlights the break down of the best performing generatingtechnologies in the first ten and last ten years of the study period. Initially, theresults suggest that the District should concentrate on developing or acquiringrenewable resources such as wind, biomass and landfill gas. Geothermalresources should also be investigated if viable sites are identified in the region.In the latter half of the study period the District will need to reassess the typesand costs of available technologies. During the last half of the period the studyimplies that a significant amount of attention should be given to addition of windresources.8

Figure 5Allocation of Preferred Generating Technologies2018-20277%2008-201727%32%37%53%WindLandFill GasGeothermalCombined CycleBiomass5%13%5%0%21%Action PlanThe District’s IRP defines the District’s need for new resources and investigatesdifferent generic resource types with an objective of presenting both quantitativeand qualitative analysis of the risk and rewards of pursuing different resourcetechnologies to fulfill the District’s resource requirements.The District’s action plan is divided into two sections. The first section describesthe conclusions drawn from this IRP with respect to actions to be taken in regardto electric resource acquisition. The second section describes issues to beinvestigated further for possible inclusion in this IRP or updates to this IRP.Action Plan – Resource Acquisition1. The District does not need additional resources to meet I-937 until 2016and to serve load until 2023, which provides time for the District tothoroughly investigate different resource alternatives before additionalprocurements are made. However, I-937 portfolio standards requireadditional renewable resources starting in 2016.9

2. The District should investigate expansion of the White Creek energyproject.3. Investigate the availability and feasibility for development of landfill gas,biomass and geothermal resources in the Pacific Northwest.4. The District should decline to participate in Energy Northwest’s IGCCproject. The District doesn’t need the resource and the risks of IGCCtechnology are significantly larger than other resource options.5. Implement all cost-effective conservation consistent with the requirementsof, and future amendments to, I-937.6. Continue to support renewal of renewable incentives, such as REPI,Production Tax Credits and CREBs, by Congress.7. Support state legislation that allows publicly owned utilities to fully utilizethe full range of incentives listed above.8. Participate in regional efforts on BPA contracts. Many important issues,including the power purchase arrangements that BPA will offer, theamount and cost of BPA power available to the District remain to beresolved. During 2008, the District will continue working with BPA andother regional parties to develop the new long-term BPA power supplycontracts for cost-based power. In these efforts, the District will promotecreation of products that can best enable the District to meet the needs ofits retail electric customers.Action Plan – IRP Analysis1. Undertake additional analysis of capacity requirements and capacityresources to meet future requirements.2. Monitor development of resource adequacy standards for the PacificNorthwest.3. Develop a better understanding of the Renewable Energy Credit (REC)market.4. Follow trends in the cost of wind projects.a. Wide range in capital costs currently being quoted by regionalutilities.5. BPA in the process of developing a separate rate for integration ofintermittent resources. Continue analysis of the alternative forms of BPApurchase arrangements.10

6. Acquire a better understanding of the proposed mechanism forimplementing the 4% cost cap under I-937. This cost cap may triggerbefore the volumetric requirements of I-937 are met.The District expects to update its IRP on a two-year cycle to ensure the processremains fluid and new issues, analyses, and information are incorporated into theplan on a regular basis.11

Chapter 2: IntroductionCowlitz PUDCowlitz PUD provides electric service to 48,100 residential, commercial,industrial and street lighting customers county wide. Cowlitz also owns the watersystem that serves 3,800 Longview-Kelso area customers in the ColumbiaHeights, Lone Oak, Beacon Hill and Lexington areas. Cowlitz PUD buys themajority of its wholesale power from Bonneville Power Administration. Themajority of the BPA power comes from the Columbia River system hydroelectricprojects. BPA also sells the output of the Columbia Generating System (nuclearplant) near Richland, WA, and makes miscellaneous energy purchases on theopen market, which may include resources other than hydro.Cowlitz PUD owns the 70 megawatt Swift No. 2 Hydroelectric Project located onthe North Fork Lewis River in the southeast corner of Cowlitz County. Swift No. 2provides 10-15% of the PUD’s non-industrial wholesale power needs. Recently,the utility completed development of the White Creek wind project nearGoldendale, WA which is the largest public power initiated wind project in theUnited States. Cowlitz receives 46% of the project output – roughly 94 MW.The remainder of Cowlitz’ power needs are met by purchases made from themid-Columbia hydro projects owned by Grant PUD and wind generation at theNine Canyon project near Kennewick.Overview of IRP processThis integrated resource plan is a detailed analysis that looks at Cowlitz PUD’sprojected resources and load obligations, and attempts to identify the mix ofsupply-side resources and conservation that will best meet its needs. The PUDexamined a wide range of generating technologies as well as a variety ofconservation measures. Going forward, this plan will be updated every twoyears. However, integrated resource planning is a continuous process. The planmust adjust when expectations about demand for energy, legislation andtechnology change.Purpose and use of IRPThe aim of the analysis is to gain insight into the types and optimal times foradditions of generating resources to meet electric loads and legal requirementsfor the next 20 years. To support the decision making process Cowlitz PUDconstructed a decision model that replicates the fundamental drivers of theutility’s power cost function. Advanced simulation and optimization software wasutilized to identify the best combinations of resources.Objectives for the District’s 2008 IRP include:12

Provide information and analysis that assist the District’s Board ofCommissioners to determine a long-term resource portfolio strategy.Develop and implement a comprehensive IRP process at the District,including:o Cross-functional participation by District staff,o Active participation by the Board, ando Opportunities for public involvement.• Develop and implement an integrated portfolio analysis framework that:o Can be used to evaluate a variety of resource strategies,o Identifies key risks and analyzes the potential impacts on resourcestrategies,o Integrates long-term planning for conservation resources withinthe District’s overall electric resource portfolio, ando Considers a range of alternative forms of power purchases undera new long-term contract with the Bonneville Power Administrationo Develops a strategy for meeting legislated mandates, such as arenewable portfolio standard,Legislative requirementsThe Washington State Legislature passed HB 1010 in the 2006 regular session,which is a law that stipulates that all utilities in the state must complete aresource plan by September 1 st , 2008. Utilities with more than 25,000 customersare required to develop a more detailed plan, describing the mix of energy supplyresources. The plans must be submitted to the Washington State Department ofCommunity, Trade and Economic Development (CTED) who will then aggregatethem into a single report for the state legislature. The goal of this law is toencourage the development of “reliable energy resources for affordable andreliable electricity”. The legislature feels that resource planning is an essentialpart of meeting this goal.The legislation defines an IRP as a plan describing the mix of generationresources, and improvements in the efficient generation, transmission,distribution and use of electricity that will meet current and future needs at thelowest reasonable cost to the utility and its ratepayers and that complies with therequirements in the legislation by including, at a minimum:a. A range of forecasts of future customer demand using methods thatexamine the effect of economic forces on the consumption of electricityand that address changes in the number, type, and efficiency of electricalend-uses;13

. An assessment of technically feasible and commercially availableefficiency improvements in the generation, delivery, and use of electricity,including load management and fuel switching, as well as currentlyemployed and new policies and programs needed to obtain the efficiencyimprovements;c. An assessment of technically feasible and commercially available utilityscale generating technologies including but not limited to renewableresources, cogeneration, power purchases, and thermal resources;d. An assessment of transmission system capability and reliability, to theextent such information can be provided consistent with applicable laws;e. An evaluation comparing the cost-effectiveness of generating resourceswith the cost-effectiveness of efficiency improvements in the delivery anduse of electricity;f. The integration of the demand forecasts and resource evaluations into along-range integrated resource plan describing the mix of resources andefficiency measures that will meet current and future needs at the lowestreasonable cost to the utility and ratepayers;g. A short-term plan outlining the specific actions to be taken by the utilityconsistent with the long-range integrated resource plan; andh. For all plans subsequent to the initial integrated resource plan, aprogress report that relates the new plan to the previous plan.Public involvementThe District’s public involvement process in developing this IRP consisted of aninitial meeting with its Board of Commissioners in open session on January 30 th ,2008 and another public hearing on August 12 th 2008 to solicit Board and publiccomment on the draft.TThe District may hold additional meetings as necessary and requested.14

Most of these inputs are straightforward values with defined parameters. Somewere modeled differently due to the uncertainty of the input. For loadrepresentations, stochastic representations were developed. The larger darkblue rectangles represent aggregate factors.The orange diamond represents a “decision” in the process. In this diagram the“Acceptable Plant Types” has this designation. Since only certain plant typeswere viewed as a viable alternative for the District, the field of possiblegeneration resources had been limited by some other work performed before thisanalysis. The model selects the “best” among the limited feasible possibilitiesoutlined later on.The last symbol, the green hexagon, represents the objective in the analysis.For this analysis, the objective is to minimize expected District power cost at anacceptable level of risk.16

Regulatory and Legislative Issues:Environmental regulations heavily affect Cowlitz PUD’s IRP analysis. Followingare brief descriptions of the most significant:Washington I-937I-937 was passed by Washington voters in 2006 and established mandatoryrenewable portfolio standards for the state’s utilities. By 2012, each utility mustmeet 3% of its annual energy load from renewable energy sources. In 2016, thetarget jumps to 9% and then to 15% in 2020. Utilities that fail to comply will befined $50 for every megawatt-hour of shortfall. Cowlitz PUD had already madesignificant progress towards meeting this target through the development of theWhite Creek wind energy project.Figure 7The Amount of Renewable Energy Forecasted to Meet RPS110100908070aMW605040302010-20082009201020112012201320142015201620172018201920202021202220232024202520262027Existing RenewablesI-937 AdditionsFigure 7 above describes the current forecasted requirement for I-937 resources.The White Creek project will satisfy requirements for about seven years. Startingaround 2015 Cowlitz will need to acquire roughly 25 MW of renewable resources.In 2020, the District will need to pick up an additional 40 MW.Initiative 937 Cost Cap DescriptionThe Initiative 937 cost cap is described in Chapter 19.285.050 of the RevisedCode of Washington:Chapter 19.285.050 RCWResource Costs17

(1)(a) A qualifying utility shall be considered in compliance with an annual targetcreated in RCW 19.285.040(2) for a given year if the utility invested four percentof its total annual retail revenue requirement on the incremental costs of eligiblerenewable resources, the cost of renewable energy credits, or a combination ofboth, but a utility may elect to invest more than this amount.(b) The incremental cost of an eligible renewable resource is calculated as thedifference between the levelized delivered cost of the eligible renewableresource, regardless of ownership, compared to the levelized delivered cost of anequivalent amount of reasonably available substitute resources that do notqualify as eligible renewable resources, where the resources being comparedhave the same contract length or facility life.Brief Explanation of the I-937 Cost CapThe cost cap calculation compares the cost of eligible renewable resources orrenewable energy credits (RECs) purchased to meet the renewable standardwith the cost of other new resources. The difference in cost -- the incrementalcost -- between an eligible renewable resource and other available new resourceis the amount used to determine if the cost cap threshold is reached.If this incremental cost exceeds four percent of a utility’s total annual retailrevenue requirement, a utility may acquire fewer eligible renewable resourcesthan would otherwise be required (i.e., less than the targets of 3% of retail loadby 2012, 9% by 2016, and 15% by 2020). The 4% cap does not compound. Autility’s revenue requirement will be calculated each year and may change fromyear to year, and consequently the revenue requirement associated with the fourpercent cap also will change, but expenditures to meet the renewable standardare capped at 4% of the utility’s retail revenue requirement in any given year(note that a utility may elect to spend more than this amount but is not required todo so). The calculation of incremental cost is done at the time the utility acquiresan eligible renewable resource or REC.The cost comparison is meant to be an “apples to apples” comparison. Thismeans that the eligible renewable resource and the alternative resource musthave the same contract length or facility life. The costs of both resources focuson energy delivered to a utility, which includes the cost of transmission andintegration. And the costs are levelized, using present value converted into equalannual payments.A utility’s revenue requirement and expenditures for eligible renewable resourceswill be affected by inflation over time. The effects of inflation (in accordance withthe consumer price index or similar measure) on both the revenue requirementand the incremental cost of the acquired eligible renewable resource should beaccounted for each year in determining whether the cost cap has been reached.Inflation forecasts embedded in levelized costs of resources also should be taken18

into account to prevent bias, such as double counting, in either direction whencalculating inflation adjustments.Note that 19.285.040(2)(d) RCW includes a separate cost cap set at 1% ofannual retail revenue requirements for utilities that meet specific criteria relatedto flat or declining load and new resource contracts.Application to Cowlitz PUDThe total annual retail revenue requirement for Cowlitz in 2007 is estimated to be$193.5 million. This is the amount of electric retail sales revenue for Cowlitz in2007. This amount is likely to be higher in 2012, the first year of reporting forcompliance with I-937. Four percent of $193.5 Million is $7.74 Million. The I-937cost cap rule states that Cowlitz would need to spend at least $7.74 Million peryear on the incremental costs of eligible renewable resources, the cost ofrenewable energy credits, or a combination of both, in order to meet the cost cap.Chapter 194-37 WAC (Washington Administrative Code) provides specific rulesfor implementation of I-937 (Chapter 19.285 RCW) and documentation of theannual revenue requirement and financial cost cap calculations.Federal Emissions LegislationIn response to concerns about the effect of carbon dioxide and other greenhousegasses on global warming, there is wide speculation that the United States willadopt some form of CO2 legislation – either as a tax or a cap-and-trade system.This increases the risk associated with owning heavy CO2 emitting resourcessuch as coal fired plants. A CO2 tax would change the dispatch economics ofemitting resources and likely increase wholesale power pricesCowlitz PUD believes that there is a high likelihood of some form of CO2legislation being passed within the study period. In the IRP base case, CO2legislation is assumed to come into effect in 2018 at a price level consistent withanalysis from the Energy Information Agency and the Northwest Power andConservation Council.Carbon Credit Trading Mechanisms and MarketsBackgroundKyoto Protocol: The Kyoto Protocol is an international agreement that is linkedto the United Nations Framework Convention on Climate Change. The Protocolsets binding targets for 37 developed countries and the European Union (EU) toreduce greenhouse gas emissions (GHG). The Kyoto Protocol was adopted by180 nations in 1997 and entered into force in 2005. The Protocol recognizes thatdeveloped nations are responsible for the majority of GHG emissions in the19

atmosphere; as a result, these nations must take a bigger role in emissionsreductions. The Kyoto Protocol has three market-based mechanisms thatparticipants will use to reach target emissions reductions:1. Emissions Trading2. Clean Development Mechanism (CDM)3. Joint Implementation (JI)While the concept of trading emissions credits is fairly straight forward, CDM andJI are project-based mechanisms that promote the development of projects thatcreate sustainable emissions reductions.U.S. ProgramsAlthough the United States did not ratify the Kyoto Protocol, this does not meanthat carbon emission reduction is being ignored. There are several state andregional initiatives that are being implemented to combat GHG emissions. TheRegional Greenhouse Gas Initiative (RGGI) is a cap and trade program that wasdesigned by 10 Northeastern and Mid-Atlantic states to reduce GHG emissions.In addition to RGGI, several western states developed the Western RegionalClimate Action Initiative (WRCAI) in an effort to reduce greenhouse gasemissions. The first allowance auction for RGGI is set for September 2008 andthe program will be fully implemented by January 2009. While RGGI is anexample of an operational program to reduce GHG emissions, several states arein the various stages of crafting legislation for their own programs.PoliticsAlthough the US does not yet have a uniform national program, several programshave been proposed in Congress, the most recent of which was the Lieberman-Warner bill. While it appears inevitable that the US will eventually create anational GHG emissions program, the uncertainty of what the program will looklike is the key risk for those looking to participate in the US carbon market in thefuture. The main issues that policymakers need to address are:1. Will it be a cap and trade system or a just a carbon tax?2. Will carbon credit allowances be allocated, auctioned or somecombination of both?3. Will the program accept global offsets?With the Lieberman-Warner bill stalling on the Senate floor without a vote in earlyJune 2008, we do not expect any major carbon policy to be passed in theremainder of the year. Although it might be a year or two before a US program isadopted as law, both Presidential candidates, Senator John McCain and Barack20

Obama, support some form of cap and trade system. Assuming the adoption ofa cap and trade carbon-trading program, the key differences will likely come inthe percentage of credits that are given as allowances versus auctioned and alsohow the receipts collected from the auctions will be distributed such as R&D, taxcredits, etc.Even though there remains a large amount of uncertainty regarding the specificsof a national GHG reduction program, one can hope that the eventual system willavoid the European market mistake of awarding too many allowances and adoptthe positive aspects of both European and US state/regional programs. BartChilton, a commissioner with the CFTC, predicts that the US GHG emissionsmarket could become a $2 trillion futures market even when using conservativeassumptions.Useful links:EIA: http://www.eia.doe.gov/fuelrenewable.htmlEnvironmental Markets Association:http://www.environmentalmarkets.org/index.wwRegional Greenhouse Gas Initiative (RGGI): http://www.rggi.orgCantor-Fitzgerald: http://www.cantorco2e.com/Environment/?page=CarbonEvolution Markets: http://www.evomarkets.com/mdata/index.php?mm=idxGreen Power Programs: http://www.eere.energy.gov/greenpower/21

Renewable Energy Credit (REC) MarketsBackgroundRenewable energy is not a new concept or technology; in fact, it has beenaround for centuries. Renewable energy resources such as water (hydro),biomass, wind, and solar are “cleaner” alternatives to fossil fuels and are notexhaustible. The benefits associated with renewable energy are being heavilypromoted as the global warming debate and initiatives such as the KyotoProtocol seek to reduce greenhouse gas emissions. As nations seek alternativeenergy sources to reduce GHG emissions, one can see the growth potential forrenewable energy based in the United States as it currently represents a smallpercentage of United States energy supply.Figure 8Renewable Energy Plays a Role in the Nation’s Energy Supply (2006)REC MarketAs nations, companies, and utilities seek to diversify their energy sources, theREC market will provide a source of “green energy” to meet Renewable PortfolioStandards (RPS). For example, states may have a RPS mandate that utilitieshave 20% of their generation come from renewable energy sources by aparticular year. In this instance, a utility can purchase RECs in a compliancemarket to meet this requirement. Businesses looking to be “green” may alsopurchase RECs in voluntary markets.The Energy Information Administration (EIA) reported in its May 1 st , 2008,renewable energy report that wind-generated and solar electricity posted thehighest growth rates among the renewable-generated sources. Wind energy hadthe highest growth rate during the past several years (45% in 2006 and 21% in22

2007) and solar energy had the second highest growth rate (19% in 2007). Aslegendary oilman T. Boone Pickens, who is currently developing a 4,000 MWwind farm in Texas states, “The United States is the Saudi Arabia of wind power.”A primary obstacle to renewable energy plants is the higher cost associated withbuilding and operating these plants than traditional plants and their often remotelocations, which may require building new transmission lines to deliver the power.For example, Mr. Pickens’ Pampa Wind Project may have an eventual price tagof $8-$10 billion once completed and he may also have to invest another $2billion in transmission lines.Renewable Energy Production Tax CreditUnlike in the carbon markets, renewable energy has been able to grow due tofavorable policies (tax credits and Renewable Portfolio Standards). While theRenewable Energy Production Tax Credit (PTC) for wind and other renewableenergies is set to expire at the end of the 2008, the federal government hasextended the credits with a lapse occurring in only three times since it inceptionin 1992. If Congress is unable to extend the PTC, the rapid growth in renewableprojects could wane during the next few years just as it did following the previouslapses in the legislation as seen in Figure 29 below.Figure 9PoliticsWith petroleum supply/demand concerns and record oil prices grabbing nationalheadlines this year, any energy plan (Senator Obama’s, Senator McCain’s or Mr.Pickens’) will likely seek to continue the recent increase in alternative andrenewable energy sources in an effort to reduce both the United States’dependence on foreign oil and the level of greenhouse gas emissions. The key23

to future growth, however, comes from regulatory stability. Unfortunately, givenCongress’ inability to pass energy legislation to combat current high oil prices, donot expect much progress until after the election. As seen by the estimated costof Mr. Pickens wind project, the investment required by the United States toachieve energy independence will be substantial and this endeavor will remainhighly political.DefinitionsRenewable energy certificates (RECs) also known as Green tags, RenewableEnergy Credits, or Tradable Renewable Certificates (TRCs), are the propertyrights to the environmental benefits from generating electricity from renewableenergy sources. These certificates can be sold and traded and the owner of theREC can legally claim to have purchased renewable energy. While traditionalcarbon emissions trading programs promote low-carbon technologies byincreasing the cost of emitting carbon, RECs incentivize carbon-neutralrenewable energy by providing a subsidy to electricity generated from renewablesources (source EMA).Useful links:EIA: http://www.eia.doe.gov/fuelrenewable.htmlEnvironmental Markets Association:http://www.environmentalmarkets.org/index.wwRegional Greenhouse Gas Initiative (RGGI): http://www.rggi.orgCantor-Fitzgerald: http://www.cantorco2e.com/Energy/?page=RenewEvolution Markets: http://www.evomarkets.com/mdata/index.php?mm=idxGreen Power Programs: http://www.eere.energy.gov/greenpower/T. Boone Pickens Energy Plan: http://www.pickensplan.com/Washington Senate Bill 6001The Washington state governor has initiated a greenhouse gas emissions policythat resulted in legislation, SB 6001, being passed to mitigate the impacts ofclimate change. This legislation establishes greenhouse gas emissions (“GHG”)reduction and clean energy economy goals for Washington State. SB 6001 alsoestablishes a performance standard for all base load electric generation,modeled on California’s Senate Bill 1368. SB 6001 would apply to all generationused to serve load in Washington, whether or not that generation is locatedwithin the state. The statute defines base load generation as generation that is“designed and intended to provide electricity” at an annualized plant capacityfactor of at least 60 percent.Beginning July 1, 2008, electric utilities entering into a “long-term financialcommitment” for base load generation must show that the base load generationcomplies with the GHG emission performance standard. The performance24

standard applies to both investor- and consumer-owned utilities such as theDistrict. “Long-term financial commitment is defined as (i) any new or renewedcontract for base load electric generation with a term of five or more years, (ii) anew ownership interest in base load electric generation, or (iii) the modification ofa base load electric generation facility designed primarily to increase the capacityof the facility. The emissions standard would also apply to any base load electricgeneration that commences operation after June 1, 2008 and is located inWashington, whether or not that generation serves load located within the state.Base load generation facilities must initially comply with an 1,100 pounds of CO2per megawatt-hour GHG limit. This limit is intended to match the average rate ofemissions of a new combined-cycle natural gas-fired combustion turbine. A coalfiredgenerating project (conventional pulverized coal and integrated coalgasification) produces GHG emissions well in excess of the new standard.Without a means of sequestering the carbon emissions, utilities are prohibitedfrom acquiring coal-fired generation.Renewable Energy Production Incentives (REPI)The energy policy act of 2005 reauthorized the renewable energy productionincentive (REPI) through 2026. The program was started in 1992 and facilitatesthe payments from the Department of Energy to consumer-owned andcooperative utilities for energy generated from solar, wind, geothermal, landfillgas,biomass, livestock methane and ocean sources 1 . The program was formedto stimulate the greater renewable energy use by public power and to even theplaying field with investor owned utilities that are eligible for energy tax credits.1 American Public Power Association, February 200625

Load-Resource BalanceFigure 10 below shows the District’s forecasted load-resource balance withexisting resources and contracts. On an energy basis, the utility will havesufficient resources to meet its needs through 2022. However, the District willneed to add more renewable resources to meet the renewable portfolio standard.Figure 10Projected Loads and Resources700650600aMW550500450BPA Tier 1 Swift No.2 Renewable I-937 Additions Unofficial Load Forecast40020082009201020112012201320142015201620172018201920202021202220232024202520262027Regional transmissionNumerous transmission constraints exist in the region. These constraints do notappear explicitly in the decision model. The portfolio model considers loads andresources in aggregate. Actual site selection of plants will require detailedconsideration of transmission.There are several constrained cut-planes in the region across which long-termfirm transmission is unavailable. However, the numbers of hours where actualconstraints occur are small. Relying on hourly non-firm transmission does notappear to pose a significant risk at this time. The economic viability of long-termtransmission for an intermittent resource such as wind is questionable anywaydue to low capacity factor. Regional transmission will need to be monitored onan ongoing basis, especially as new resources are contracted further into thefuture.Cowlitz Load ForecastLoad forecasting is the process of estimating the amount of energy that theDistrict’s customers will use in the future. The load forecast is one of two key26

determinants used to identify the District’s resource need. This section describesthe 20-year load forecast assumptions used in the IRP.20-year Annual Load ForecastCowlitz developed a 20-year forecast of energy sales, customer counts, andpeak demand. This forecast is used for planning long-term resource and deliverysystems. It is also used to make annual forecasts of projected retail revenues. Asummary of the District’s 20-year system load forecast that was used in this IRPis provided on page 29 in Figure 13.The IRP analysis evaluated loads and resources on a monthly heavy load hour(HLH) and light load hour (LLH) basis. Heavy load hours are defined as 6:00 amthrough 10:00 pm Monday through Saturday, excluding certain NERC holidays 2 .Light load hours are defined as all other hours.The annual load forecast shown in Figure 11 was allocated to HLH and LLHperiods each month of the 20-year study period in a two-step process. First, theannual load forecast was allocated to each month of the year. Second, themonthly load forecast was allocated to HLH and LLH periods each month. Theallocation of the annual load forecast to monthly HLH and LLH periods is basedon historical actual average load data for the District.Figure 1120 Year Peak and Energy Forecast1,000900800700600aMW500400300200100-20082009201020112012201320142015201620172018201920202021202220232024202520262027EnergyPeakThree different load scenarios were considered to provide a range of reasonablefuture outcomes and to model the resulting affect on resource strategy. Figure12 shows the low, medium, and high load forecast used in the IRP. Loads are a2 NERC holidays are New Year’s Day, Memorial Day, 4 th of July, Labor Day, Thanksgiving Day, andChristmas.27

stochastic variable in the simulation and these assumptions were used toparameterize annual probability distributions.Figure 12Low, Medium and High Assumptions used in the IRP5,700,0005,600,0005,500,0005,400,000MWh5,300,0005,200,000LowExpectedHigh5,100,0005,000,0004,900,0004,800,0002008200920102011201220132014201520162017201820192020202120222023202420252026202728

Figure 13Expected System Load ForecastCowlitz County Public Utility District No. 1Expected Case Load Forecast - With LossesTotal System Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Year2007 PEAK (MW) 795.04 709.84 644.84 620.20 578.67 602.32 609.20 554.22 544.85 583.91 716.40 730.58 795.04ENERGY (aMW) 621.08 622.56 564.72 569.51 546.80 561.06 560.88 517.70 506.94 513.12 542.13 587.43 6,714ENERGY (MWh) 462,082 418,358 420,150 410,047 406,816 403,960 417,292 385,165 364,996 381,759 390,334 437,045 4,898,0042008 PEAK (MW) 764.27 699.95 670.55 654.28 611.18 594.81 583.81 571.12 560.33 600.06 739.16 755.29 764.27ENERGY (aMW) 607.80 612.38 580.44 588.43 561.34 547.36 530.04 531.25 520.21 525.93 558.87 604.19 6,768ENERGY (MWh) 452,205 426,218 431,844 423,666 417,639 394,103 394,351 395,253 374,549 391,291 402,389 449,521 4,953,0282009 PEAK (MW) 781.08 730.53 677.86 670.15 627.92 614.87 600.49 584.85 572.15 613.68 754.45 772.30 781.08ENERGY (aMW) 619.05 638.18 584.24 598.66 571.17 560.57 543.03 541.14 529.91 535.74 568.86 614.68 6,905ENERGY (MWh) 460,570 428,855 434,675 431,039 424,948 403,608 404,017 402,609 381,537 398,594 409,576 457,319 5,037,3462010 PEAK (MW) 803.86 749.87 703.41 683.97 642.45 623.73 608.62 588.37 575.14 617.44 759.44 778.33 803.86ENERGY (aMW) 633.00 652.29 601.48 609.04 581.15 566.65 548.91 542.88 531.63 537.55 570.98 617.27 6,993ENERGY (MWh) 470,951 438,338 447,499 438,510 432,373 407,990 408,389 403,905 382,774 399,936 411,107 459,247 5,101,0192011 PEAK (MW) 809.98 755.30 708.22 688.45 646.81 627.43 611.84 591.74 578.01 621.09 764.34 784.30 809.98ENERGY (aMW) 635.84 655.29 603.95 611.42 583.16 568.51 550.59 544.47 533.22 539.24 573.01 619.79 7,018ENERGY (MWh) 473,062 440,357 449,338 440,220 433,870 409,329 409,639 405,089 383,915 401,196 412,571 461,123 5,119,7102012 PEAK (MW) 816.03 744.31 713.00 692.89 651.15 631.12 615.08 595.13 580.92 624.79 769.31 790.35 816.03ENERGY (aMW) 638.62 643.30 606.39 613.77 585.16 570.36 552.27 546.07 534.81 540.95 575.08 622.35 7,029ENERGY (MWh) 475,134 447,737 451,153 441,913 435,356 410,661 410,886 406,275 385,064 402,470 414,055 463,027 5,143,7312013 PEAK (MW) 822.16 766.16 717.86 697.42 655.59 634.90 618.42 598.63 583.93 628.60 774.41 796.54 822.16ENERGY (aMW) 641.46 661.28 608.89 616.19 587.22 572.28 554.01 547.73 536.48 542.74 577.22 625.00 7,071ENERGY (MWh) 477,247 444,377 453,013 443,654 436,889 412,043 412,185 407,515 386,268 403,802 415,601 464,998 5,157,5912014 PEAK (MW) 828.40 771.75 722.85 702.05 660.14 638.79 621.87 602.25 587.06 632.54 779.66 802.87 828.40ENERGY (aMW) 644.38 664.39 611.46 618.68 589.35 574.28 555.84 549.48 538.24 544.62 579.46 627.74 7,098ENERGY (MWh) 479,417 446,467 454,930 445,452 438,480 413,481 413,542 408,813 387,531 405,196 417,211 467,039 5,177,5572015 PEAK (MW) 834.80 777.50 727.99 706.84 664.85 642.83 625.47 606.02 590.33 636.62 785.08 809.38 834.80ENERGY (aMW) 647.40 667.61 614.15 621.29 591.60 576.38 557.76 551.33 540.10 546.60 581.81 630.60 7,127ENERGY (MWh) 481,666 448,637 456,926 447,329 440,147 414,997 414,976 410,188 388,871 406,668 418,904 469,166 5,198,4752016 PEAK (MW) 841.37 766.53 733.30 711.78 669.73 647.04 629.22 609.96 593.76 640.87 790.69 816.08 841.37ENERGY (aMW) 650.54 655.75 616.95 624.02 593.95 578.61 559.80 553.29 542.08 548.69 584.29 633.58 7,142ENERGY (MWh) 484,004 456,404 459,010 449,294 441,901 416,598 416,495 411,648 390,297 408,228 420,687 471,387 5,225,9522017 PEAK (MW) 848.14 789.54 738.80 716.90 674.79 651.43 633.14 614.06 597.36 645.29 796.50 822.98 848.14ENERGY (aMW) 653.82 674.48 619.88 626.88 596.43 580.96 561.97 555.38 544.19 550.92 586.90 636.70 7,188ENERGY (MWh) 486,439 453,254 461,189 451,352 443,747 418,290 418,105 413,199 391,815 409,881 422,565 473,707 5,243,5442018 PEAK (MW) 855.11 795.86 744.50 722.20 680.04 656.01 637.24 618.35 601.14 649.90 802.52 830.08 855.11ENERGY (aMW) 657.23 678.14 622.94 629.88 599.05 583.44 564.26 557.59 546.43 553.27 589.64 639.96 7,222ENERGY (MWh) 488,976 455,713 463,469 453,511 445,691 420,080 419,813 414,847 393,429 411,632 424,544 476,134 5,267,8402019 PEAK (MW) 862.36 802.45 750.46 727.75 685.55 660.84 641.57 622.88 605.16 654.75 808.83 837.45 862.36ENERGY (aMW) 660.83 682.02 626.20 633.07 601.85 586.12 566.75 559.99 548.86 555.81 592.59 643.42 7,258ENERGY (MWh) 491,659 458,317 465,892 455,812 447,776 422,009 421,660 416,634 395,183 413,523 426,667 478,708 5,293,8402020 PEAK (MW) 869.88 791.79 756.69 733.56 691.33 665.93 646.16 627.67 609.43 659.86 815.43 845.10 869.88ENERGY (aMW) 664.64 670.54 629.65 636.47 604.85 589.00 569.42 562.59 551.50 558.55 595.75 647.09 7,280ENERGY (MWh) 494,491 466,696 468,463 458,261 450,006 424,083 423,651 418,565 397,080 415,561 428,938 481,434 5,327,2292021 PEAK (MW) 877.68 816.47 763.21 739.63 697.38 671.29 651.00 632.72 613.96 665.23 822.33 853.03 877.68ENERGY (aMW) 668.65 690.45 633.32 640.09 608.05 592.09 572.30 565.38 554.34 561.49 599.12 650.97 7,336ENERGY (MWh) 497,479 463,982 471,188 460,862 452,387 426,306 425,791 420,645 399,127 417,749 431,364 484,319 5,351,1982022 PEAK (MW) 885.79 823.91 770.01 745.97 703.71 676.94 656.11 638.05 618.76 670.88 829.54 861.27 885.79ENERGY (aMW) 672.89 695.02 637.19 643.92 611.46 595.39 575.38 568.39 557.40 564.64 602.71 655.06 7,379ENERGY (MWh) 500,627 467,052 474,071 463,621 454,924 428,684 428,086 422,880 401,328 420,093 433,948 487,367 5,382,6822023 PEAK (MW) 894.20 831.67 777.12 752.59 710.33 682.88 661.49 643.66 623.83 676.81 837.08 869.80 894.20ENERGY (aMW) 677.34 699.83 641.29 647.98 615.08 598.92 578.69 571.61 560.68 568.01 606.52 659.39 7,425ENERGY (MWh) 503,942 470,289 477,118 466,543 457,622 431,223 430,542 425,274 403,690 422,599 436,697 490,585 5,416,1242024 PEAK (MW) 902.93 821.44 784.53 759.51 717.26 689.12 667.16 649.56 629.20 683.03 844.95 878.65 902.93ENERGY (aMW) 682.03 688.85 645.61 652.27 618.93 602.68 582.21 575.05 564.19 571.60 610.58 663.95 7,458ENERGY (MWh) 507,429 479,440 480,336 469,635 460,487 433,928 433,164 427,835 406,217 425,273 439,616 493,977 5,457,3352025 PEAK (MW) 911.99 848.14 792.27 766.73 724.51 695.67 673.13 655.76 634.86 689.56 853.17 887.83 911.99ENERGY (aMW) 686.95 710.24 650.17 656.81 623.02 606.67 585.96 578.72 567.94 575.43 614.88 668.75 7,526ENERGY (MWh) 511,093 477,284 483,729 472,901 463,525 436,805 435,957 430,567 408,916 428,119 442,712 497,551 5,489,1582026 PEAK (MW) 921.38 856.88 800.34 774.26 732.07 702.55 679.40 662.28 640.84 696.40 861.75 897.34 921.38ENERGY (aMW) 692.12 715.86 654.98 661.60 627.34 610.92 589.96 582.63 571.93 579.50 619.43 673.81 7,580ENERGY (MWh) 514,941 481,055 487,304 476,349 466,742 439,860 438,929 433,476 411,793 431,146 445,991 501,312 5,528,89629

Chapter 4: Supply-side resourcesIn recent years the capital costs for construction of new power plants haveincreased markedly. This is due to a number of factors, such as heightenedglobal demand, raw materials, and a weakening U.S. dollar. Demand fromemerging economies such as China and India have put a premium on steel,concrete, copper, and nickel. This has resulted in steep price increases for mosttypes of generating technology. According to Randy Zwirn, president of SiemensPower Generation Group, the cost of building a new coal plant has increased by30% since spring of 2006 3 . Christine Real de Azuza of the American WindEnergy Association stated that the cost of a new wind turbine increased by nearly75% from 2004 to 2006. The uncertainty around capital costs exerts a significantinfluence on the resource selections in this plan.Supply Side Resources Considered in the IRPCowlitz PUD analyzed a broad array of supply-side resource options in the IRP.Each technology has its own unique set of advantages and disadvantages, andtherefore, a unique impact on the District’s bottom line. The resourcesconsidered in the plan are not a complete list of all possible generation types.Rather, the IRP reflects technologies that are deemed to be realistic candidatesby the District’s IRP team.The District gathered resource cost data from a variety of sources. In general,the plan attempts to base its analysis on “regional consensus” data. This wasaccomplished by surveying and averaging the assumptions used by other utilitiesin the region for their IRPs. In circumstances where the District had access tomore specific resource cost data, that information was used instead.3 Wald, Matthew L., “Costs Surge for Building Power Plants”, The New York Times, July 10 th 200730

Thermal ResourcesCombined Cycle Combustion TurbinesCombined Cycle Combustion Turbines (CCCTs) use natural gas as a principlefuel source, although they generally have the capability of switching to fuel oil.CCCTs have two main generating components: the turbine(s) and the heatrecovery steam generator (HRSG). The turbine directly combusts the fuel andspins a generator. The HRSG captures the heat from the turbine and uses it todrive a steam generator. In recent years, CCCTs have been the most popularnew generating technology in the region. According to the Northwest Power andConservation Council, CCCTs make up 64% of the 6480 megawatts constructedin the region since the 1990s. At present, CCCTs constitute about 10% ofregional capacity.CCCTs are popular because of the comparatively low capital costs associatedwith construction. Also, natural gas has a small carbon footprint when comparedto coal. Historically, natural gas was inexpensive. However, recently it hasbecome much more expensive and is considered to be one of the most volatilecommodities in the world. As a result, the financial risks associated withoperating CCCTs have increased, dampening the demand somewhat. Thereference plant is an F-class gas turbine with one steam generator, with similareconomics and dispatch to the Frederickson or Chehalis plants.Simple-Cycle Combustion TurbinesSimple cycle combustion turbines (CTs) are similar to CCCTs, but tend to besmaller and less efficient. On the other hand, they tend to have more flexibledispatch ability. This makes them ideal for meeting peak load, a fact that hasmade them an important part of the national generating fleet. However, in theNorthwest, the ability of hydro generation to meet this need has resulted in amuch smaller build-out of this technology relative to other parts of the country.Coal PlantsCoal fired plants are the cornerstone of the U.S. generating fleet. According tothe Northwest Power and Conservation Council, coal plants make up about 23%of the region’s capacity. Coal is a proven technology, with a track record forgenerating inexpensive base load power. Another benefit is a secure domesticfuel supply. However, coal plants are heavy emitters of carbon dioxide. Thisconstitutes a financial risk if legislation is enacted aimed at forcing utilities tointernalize costs associated with emissions. Washington Senate bill 6001 adds agreat amount of uncertainty as to the viability of new coal resources. Thereference plant is a large pulverized coal generator located near existing coalplants or a coal mine.31

IGCCIntegrated Gasification Combined Cycle plants (IGCCs) are another type of coalburning plant. Unlike pulverized coal plants, IGCCs use chemical processes toconvert coal into gas, which is in turn used to run a combined cycle combustionturbine. IGCCs have an advantage to traditional coal plants in that they havecleaner emissions and are more efficient. Another benefit is the ability of IGCCsto sequester carbon dioxide. However, IGCCs are an emerging technology andlarge scale generation is somewhat unproven at this time – particularly thetechnology associated with carbon sequestration. The reference plant isdesigned to have economics similar to the 400 megawatt IGCC plant proposedby Energy Northwest.NuclearCommercial nuclear generation relies on fission of elements such as uranium tocreate heat, which is in turn used to power steam generators. Nucleargeneration has been controversial because of the threat of environmentaldamage linked to inadvertent release of radioactive materials. This fact,combined with lengthy permitting and high capital costs, have caused utilities tochoose other technologies. However, recent concern about the impact of carbondioxide emissions has renewed interest in nuclear generation.Nuclear power plants typically have high capital costs for building a new plant,but low fuel costs. As a result, the viability of nuclear generators is very sensitiveto assumptions about finance costs and construction timeline. According to ajoint 2005 OECD-NEA study the capital investment makes up about 70% of thecost of electricity generated. At present there is a high amount of uncertaintyregarding the capital costs for plant construction. Some analysts have estimatedcapital costs as low as $2,000 per KW and as high as $6,000 per KW.To encourage the development of nuclear power the department of energylaunched the “Nuclear Power 2010” initiative. Under this program, thegovernment offered to subsidize between a quarter to a half of the cost overrunsrelated with construction delays. In the fall of 2007, NRG announced plans tobuild the first new nuclear power plant in the US since 1978.32

Renewable ResourcesWind GenerationIn recent years, installed wind generation has increased in the WECC Region (anarea extending from Canada to Mexico, including all or a portion of 14 westernUS states). In the Pacific Northwest over 1,700 megawatts have been addedsince 1997. Given state mandated renewable portfolio standards (such as I-937in Washington), the competition and costs for new turbines is expected toincrease.Although the fuel for wind generation is free, wind farms tend have low capacityfactors and highly variable generating profiles. As a result, there is usually anassociated shaping charge that accounts for the expense of keeping somedispatchable resource on standby to react to changes in wind farm output.Figure 14Wind Resource Potential (Source: Renewable Energy Atlas of the West)For the IRP, wind generating operational parameters were designed to mirrorthose of a typical central-station wind plant in central Washington located near anexisting substation and not requiring a large investment in transmission to bringthe energy onto the grid.33

GeothermalThere are three different available geothermal generating technologies: drysteam, flashed steam, and binary cycle. There is a high amount of uncertaintysurrounding the availability of suitable sites. According to the Northwest Powerand Conservation Council, the most likely sites would be located in southeasternOregon and southern Idaho.Figure 15Geothermal Resource Potential (Source: Renewable Energy Atlas of the West)According to the Energy Atlas of the West, the potential for geothermal resourcedevelopment in Washington State is relatively low. The reference plant isassumed to be a 50 megawatt flash steam generator.Landfill GasThis generation type utilizes methane produced by decomposing materials inlandfills. According to the Northwest Power and Conservation Council, mostsites use reciprocating engines but micro turbines are starting to become more34

prominent. The reference plant is assumed to be similar to the Klickitatgeneration project.BiomassThere are several different fuel sources that fall underthe biomass category, suchas animal wastes, pulping chemical recovery, and wood residue.Figure 16Biomass Resource Potential (Source: Renewable Energy Atlas of the West)The IRP focuses on generation from wood residue, such as slash from loggingoperations and mill residues. The reference plant is assumed to receive a creditfor co-generated steam.SolarSolar power is a technology that is developing on two fronts: thermal energyconversion and photovoltaic cells. Solar thermal plants use solar heat to makesteam that then drives a turbine generator. In photovoltaic systems, sunlight falls35

on a semiconductor surface, usually made of silicon, and directly produceselectrical current. The main advantages of solar energy are that it causesminimal adverse environmental impacts on air and water quality and that it is arenewable resource. Environmental drawbacks are the amount of land requiredfor a central station power plant and visual effects.According to the Northwest Power and Conservation Council, the best areas inthe region for development of solar generation are southeastern Oregon andsouthern Idaho. These areas receive about 75% of the solar radiation as leadingsites in the southwestern region of the United States.Recent technological developments have opened the possibility of solar cells thatare more efficient and cheaper to produce. The District will monitor changes intechnology and operating economics. The reference plant is assumed to be aproject near the District’s system.Figure 17Solar Resource Potential (Source: Renewable Energy Atlas of the West)36

Consensus Resource Costs & EconomicsThe District based its resource cost assumptions used in the IRP on a survey ofother recently completed regional IRP’s. Because of the time lag in when someIRP’s were prepared and the general escalation in capital costs over the past fewyears, the IRP team used its judgment in setting the cost assumptions.Capital CostsCapital costs for power plants include the purchase price of land, equipmentneeded to run the plant, and costs associated with constructions such as rawmaterials and construction labor. As discussed earlier, capital costs represent asignificant source of uncertainty for the IRP analysis. As raw material cost hasincreased rapidly, so has the construction costs for plants. The following tableshows capital cost assumptions from selected regional IRPs:Figure 18Survey of Capital CostsIdaho Seattle NWPPC Avista PGE Pacificorp Low Med HighWind $ 1,500 $ 1,500 $ 1,160 $ 1,191 $ 1,739 $ 1,738 $ 1,160 $ 1,471 $ 1,739Geothermal $ 3,184 $ 3,150$ 1,976 $ 4,092 $ 3,346 $ 1,976 $ 3,150 $ 4,092Biomass $ 2,449 $ 2,476$ 2,061 $ 2,388 $ 2,061 $ 2,344 $ 2,476Landfill Gas $ 1,500 $ 1,360 $ 1,468$ 1,360 $ 1,443 $ 1,500Solar $ 4,878$ 7,000 $ 7,558$ 4,878 $ 6,479 $ 7,558Pulverized Coal $ 1,596 $ 1,575 $ 1,434 $ 1,343 $ 1,596 $ 2,103 $ 1,343 $ 1,608 $ 2,103IGCC $ 2,396 $ 1,575 $ 2,079 $ 1,949 $ 2,337 $ 2,480 $ 1,575 $ 2,136 $ 2,480CCCT $ 655 $ 613 $ 586 $ 567 $ 710 $ 770 $ 567 $ 650 $ 770CT $ 435 $ 500 $ 420 $ 405 $ 638 $ 454 $ 405 $ 475 $ 638Nuclear $ 2,137$ 1,450 $ 1,566$ 2,636 $ 1,450 $ 1,947 $ 2,636Figure 19 below graphically summarizes the data fromFigure 18 and shows the average as well as high and low values from thesurvey.Figure 19Rank Ordered Capital Cost Assumptions$8,000$7,000$6,000$/kW$5,000$4,000$3,000HighMedLowPacificorp LowPacificorp High$2,000$1,000$-CTCCCTLandfill GasWindPulverized CoalNuclearIGCCBiomassGeothermalSolar37

Figure 20 shows the final assumptions used in the IRP analysis. Due to theuncertainty surrounding these costs the study treated capital costs as astochastic variable. The data points from Figure 20 were used to parameterizeprobability distributions in the simulation.Figure 20Capital Cost Assumptions Used in StudyLow Med HighWind $ 1,191 $ 1,738 $ 1,919Geothermal $ 1,976 $ 3,346 $ 4,092Biomass $ 2,061 $ 2,388 $ 2,563Landfill Gas $ 1,360 $ 1,443 $ 1,500Solar $ 4,878 $ 6,479 $ 7,558Pulverized Coal $ 1,343 $ 2,103 $ 2,266IGCC $ 1,949 $ 2,480 $ 2,690CCCT $ 567 $ 770 $ 822CT $ 405 $ 684 $ 731Nuclear $ 1,566 $ 2,636 $ 2,889Fixed O&M CostsFixed operation and maintenance costs are costs associated with keeping a plantin an operational state. They are incurred regardless of how much the plantruns. Fixed O&M include taxes, insurance, long-term service agreements, plantstaffing costs, expenses related to equipment upkeep and recovery of capital.The following table shows a survey of plant fixed O&M charges from regionalIRPs.Figure 21Survey of Fixed Operational and Maintenance (O&M) CostsIdaho Seattle NWPPC Avista PGE Pacificorp Low Med HighWind $ 23.19 $ 20.00 $ 23.00 $ 18.90 $ 11.30 $ 29.78 $ 11.30 $ 21.03 $ 29.78Geothermal $ 132.00 $ 171.97$ 103.66 $ - $ 22.60 $ - $ 86.05 $ 171.97Biomass $ 92.74 $ 219.00$ 71.80$ 71.80 $ 127.85 $ 219.00Landfill Gas $ 134.00 $ 125.00 $ 134.97$ 125.00 $ 131.32 $ 134.97Solar $ 54.89$ 250.00 $ 34.55$ 34.55 $ 113.15 $ 250.00Pulverized Coal $ 19.50 $ 28.35 $ 46.00 $ 43.19 $ 17.10$ 17.10 $ 30.83 $ 46.00IGCC $ 22.62 $ 28.35 $ 61.00 $ 48.59 $ 28.90 $ 1.31 $ 1.31 $ 31.80 $ 61.00CCCT $ 10.26 $ 10.00 $ 8.00 $ 8.76 $ 8.90 $ 11.29 $ 8.00 $ 9.54 $ 11.29CT $ 6.96 $ 12.00 $ 8.00 $ 8.64$ 5.25 $ 5.25 $ 8.17 $ 12.00Nuclear $ 65.58$ 40.00 $ 43.19$ 109.72 $ 40.00 $ 64.62 $ 109.72Figure 22 graphically summarizes the data from Figure 21 and shows theaverage as well as high and low values from the survey.38

Figure 22Rank Ordered Fixed O&M Assumptions$300.00$250.00$200.00$/MWh$150.00$100.00HighMedLow$50.00$-CT CCCT Wind PulverizedCoalIGCC Nuclear Geothermal Solar Biomass Landfill GasFigure 23 shows the final assumptions used in the IRP analysis. Due to theuncertainty surrounding these costs the study treated fixed O&M costs as astochastic variable. The data points from Figure 23 were used to parameterizeprobability distributions in the simulation.Figure 23Fixed O&M Assumptions Used in StudyLow Med HighWind $ 11.30 $ 20.79 $ 29.78Geothermal $ 22.60 $ 86.09 $ 132.00Biomass $ 71.80 $ 82.27 $ 92.74Landfill Gas $ 125.00 $ 131.32 $ 134.97Solar $ 34.55 $ 44.72 $ 54.89Pulverized Coal $ 17.10 $ 26.60 $ 43.19IGCC $ 22.62 $ 33.37 $ 48.59CCCT $ 8.76 $ 9.80 $ 11.29CT $ 5.25 $ 6.95 $ 8.64Nuclear $ 43.19 $ 72.83 $ 109.72Variable O&M CostsVariable operations and maintenance costs are incurred when the plant isrunning. The principle component variable O&M for most plants is fuel cost.Variable O&M also includes emissions costs, variable fuel transportationcharges, as well as water or anything else consumed in the generation process. 44 Wood Mackenzie, http://www.woodmacresearch.com/cgi-bin/wmprod/portal/energy/highlights39

Figure 24Survey of Variable Operational and Maintenance (O&M) CostsIdaho Seattle NWPPC Avista PGE Pacificorp Low Med HighWind $ 1.16 $ 1.00 $ 1.15 $ 1.08$ 1.00 $ 1.10 $ 1.16Geothermal $ 1.80 $ 2.90$ 26.70 $ 5.50 $ 1.80 $ 9.23 $ 26.70Biomass $ 10.43$ 6.90 $ 1.91 $ 1.91 $ 6.41 $ 10.43Landfill Gas $ 1.00 $ 1.00 $ 1.08$ 1.00 $ 1.03 $ 1.08Solar $ -$ - $ -$ - $ - $ -Pulverized Coal $ 2.58 $ 3.24 $ 2.00 $ 1.89 $ 2.20$ 1.89 $ 2.38 $ 3.24IGCC $ 2.68 $ 3.24 $ 1.80 $ 1.62 $ 5.20 $ 1.10 $ 1.10 $ 2.61 $ 5.20CCCT $ 3.25 $ 2.85$ 2.30 $ 2.32 $ 2.30 $ 2.68 $ 3.25CT $ 4.64 $ 6.00 $ 8.00 $ 8.64 $ 4.50 $ 9.87 $ 4.50 $ 6.94 $ 9.87Nuclear $ 0.49$ 1.00 $ 1.08$ 0.38 $ 0.38 $ 0.74 $ 1.08Figure 25 below graphically summarizes the data from Figure 24 and shows theaverage as well as high and low values from the survey.Figure 25Rank Ordered Variable O&M Assumptions$30.00$25.00$20.00$/MWh$15.00$10.00HighMedLow$5.00$-Solar Nuclear Landfill Gas Wind PulverizedCoalIGCC CCCT Biomass CT GeothermalFigure 26 shows the final assumptions used in the IRP analysis. Due to theuncertainty surrounding these costs the study treated variable O&M costs as astochastic variable. The data points from Figure 26 were used to parameterizeprobability distributions in the simulation.Figure 26Variable O&M Assumptions Used in StudyLow Med HighWind $ 1.08 $ 1.12 $ 1.16Geothermal $ 1.80 $ 3.65 $ 5.50Biomass $ 6.90 $ 8.67 $ 10.43Landfill Gas $ 1.00 $ 1.03 $ 1.08Solar $ - $ - $ -Pulverized Coal $ 1.89 $ 2.22 $ 2.58IGCC $ 1.62 $ 3.17 $ 5.20CCCT $ 2.30 $ 2.62 $ 3.25CT $ 6.00 $ 8.13 $ 9.87Nuclear $ 0.38 $ 0.65 $ 1.0840

Resource ConstraintsIn addition to consideration of capital costs and operational economics, the IRPdecision model honors a handful of constraints. These constraints are meant toenhance the realism of the simulation.Addition TimelineThe IRP assumes that certain technologies will not be available immediately dueto long project lead times. Once a decision has been made to build a powerplant, there are many permits a developer must obtain to conform to the followingregulations:1. Clean air act2. Clean water act3. Environmental policy act4. Endangered species act5. Safe drinking water act6. State industrial siting actsThe following timeline was established to constrain power plant additions in theIRP’s decision model. Most plants are assumed to be available immediately.The underlying assumption being that Cowlitz could purchase a share of anexisting plant or negotiate a tolling agreement. The model assumes that no newcoal or IGCC can be established in the region prior to 2015. The model will notadd nuclear generators until after 2020. This is meant to reflect the lengthypermitting process as well as a shortage of construction labor due to the longperiod of nuclear plant construction inactivity.Figure 27Resource Addition TimelineThese constraints reflect the opinion of Cowlitz PUD’s executive team androughly conform to assumptions made by other regional utilities.41

Resource PotentialThe IRP decision model assumes that there is a regional limit to the types ofresources that can be developed. For example, there are only a finite amount ofsites that are suitable for development of wind or geothermal projects. Inaddition, landfill gas projects are limited by the number of landfill projects. Thechart below shows regional potential estimates from the Northwest Power andConservation Council as well as the Western Governors association.Figure 28Regional Resource Potential6,0005,0005,0004,000aMW3,0002,0001,0001,7001,200300 200-Wind Biomass Geothermal Landfill GasWestern GovernorsNWPPC 5th PlanThis is a very important element in the resource selection simulation givenWashington’s renewable portfolio standard. To satisfy the requirements of thestandard, there will be a very high level of competition to develop or obtainqualifying resources. It would be unrealistic to assume that Cowlitz would beable to:1. Add more than the regional potential of any given resource.2. Add a disproportionate amount of a given technology.The model assumes that Cowlitz will be limited to its “share” of the regionalpotentials shown above. The following table shows the constraints assumed inthe decision modeling process.Wind 150LandFill Gas 25Geothermal 50Biomass 5042

Thermal based plants such as coal, IGCC, natural gas and nuclear are notconstrained because there is no physical limit to number of projects that could beconstructedExisting ResourcesCowlitz PUD has a significant compliment of non-federal generating resources.This section will highlight the principle components of the utility’s current portfolio.Swift hydroThe Swift No. 2 Hydroelectric Project is a 70 MW capacity plant owned byCowlitz PUD and is operated and maintained by PacifiCorp. The facility wasconstructed by the PUD in the late 1950s. In 2002, the project was severelydamaged when a bank of the canal that transports water from the Lewis Rivercollapsed. The project has since been repaired and now provides an average ofroughly 27 MW of generation to the utility.Due to its location on the West side of the cascades, Swift No. 2 provides theDistrict with a measure of generating “portfolio” diversification. This is becausethe majority of regional hydro is influenced by conditions in the Columbia basin.During certain time periods weather patterns on the Western side of theCascades are different from those on the East side. Also, the Lewis Riverregulation is different from the Columbia. Figure 29 below shows that Swift No. 2is about 78% correlated with FBS generation.Figure 29Swift No.2 vs. the FBS45Swift No. 2 Annual Generation (aMW)403530252015105R 2 = 0.7879-6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000FBS Generation (aMW)The next chart compares Swift No. 2 to the FBS in terms of average generation.As you can see, the chart below shows that Swift No. 2 is slightly more volatilethan the FBS. Swift generates at a higher level relative to the FBS in good wateryears.43

Figure 30Swift No.2 vs. the FBS160%140%Generation % of Average120%100%80%60%FBSSwift 240%192919311933193519371939194119431945194719491951195319551957195919611963196519671969197119731975197719791981198319851987Grant hydroCowlitz has traditionally received about 15 MW of power under contract fromGrant PUD’s Wanapum and Priest Rapids Columbia river hydro projects.However, Cowlitz believes that the amount of energy available under thiscontract will diminish in the future. As a result, these contracts are assumed tobe zero for the IRP study period.9 Canyon windCowlitz receives about 2 MW capacity from Energy Northwest’s Nine Canyonwind project located near Kennewick, Washington.White Creek windCowlitz PUD recently completed construction of the White Creek Wind project ina joint effort with Klickitat PUD, Lakeview Light and Power and Tanner ElectricCooperative. The project is located in close proximity to the Columbia RiverGorge near Goldendale, Washington. The project is comprised of eighty nine 2.3MW Siemens wind turbines, and boasts a capacity of 205 MW. Cowlitz receives46% of White Creek’s output. Assuming a capacity factor of 33%, the District willreceive about 31 MW of energy. Site studies have indicated that another 80 MWof generation is possible if the project is expanded. Given the high demand forrenewable energy sources and development of many of the region’s best wind44

generating sites, the decision to develop White Creek gives Cowlitz a valuableoption for meeting its future legal requirements under Washington’s renewableportfolio standard.Industrial customers generationGiven the high concentration of industrial customers in the District’s service area,there may be potential for development or purchase of I-937 qualifying resourcessuch as plant cogeneration.45

Chapter 5: ConservationConservation ResourcesCowlitz PUD has been actively engaged in energy efficiency and demand-sidemanagement for over 26 years and it plans to continue these efforts. Since1981, PUD programs have cumulatively acquired over 24 aMW of conservationresources. The PUD offers education services, financial incentives, applianceand heat pump rebates, and customized programs to all customer segments.Cowlitz PUD recently signed an agreement with a professional firm to develop aConservation Resource Potential Plan that meets the requirements ofWashington State RCW Chapter 19.285, Energy Independence Act (I-937), andRCW Chapter 19.280, Electric Utility Resource Plans (HB1010). These newlaws require reporting and documenting amounts of conservation and efficiencyresources that utilities plan to achieve. The Energy Independence Act requiresutilities to establish conservation targets beginning in 2010 and then documenthow the targets are achieved. Each biennial target must be achieved to avoid apenalty. In general, the Conservation Resource Potential Plan will provide utilityspecifictargets, quantified conservation projections, costs and benefits.Another change that is occurring impacts Bonneville Power Administration (BPA)customers, like Cowlitz PUD. BPA is changing its rate structure from a meldedrate system to a two-tiered rate schedule. Tier 1 rates will be established basedon the cost of the Federal Base System (FBS), but the energy quantity will belimited to the output capability of the current FBS resources. Tier 2 rates areavailable to utilities with requirements above Tier 1 eligible power, but these ratesare reflective of the open market cost for BPA to acquire new resources to servethe added load. BPA utility customers can choose to pay the higher Tier 2 rates,build their own resources, develop conservation, or purchase on the openmarket. Conservation, when viewed as a resource and compared alongsidetraditional supply-side resources, can be significantly less expensive than marketrates. Increasing the amount of conservation in our service territory will benefitratepayers and mesh well with our portfolio of power resources.Developing an effective energy efficiency strategy is very important under thenew regulatory requirements and provides positive economic benefits. Projectedfuture conservation energy savings (NWPPC targets) were incorporated in theIRP analysis as a load reduction to the District’s load forecast. In future studiesthe District expects to use the results of the Conservation Resource PotentialPlan currently under development.The District’s current conservation programs consist of seven residentialprograms and four programs targeted towards the commercial and industrialsectors. A brief description of the current programs follows:46

Residential Weatherization Plus ProgramThe objective of this program is to reduce the energy consumption of electricallyheatedhomes. The program provides financial incentives for the owners ofsingle-family homes, apartments or duplexes for eligible measures includingceiling, floor and wall insulation. The program first started in the early 1980’s,and the current design began in June 2006. Savings depend on the measuresselected, the size of the home and its initial level of inefficiency. In 2006, theaverage upgrade saved approximately 4,200 kWh annually.Residential Low Income Weatherization Plus ProgramThe objective of this program is to reduce home energy use in the low-incomeresidential sector. The program offers financial incentives for the owners ofsingle-family site built homes, apartments or duplexes who have low-incomequalifying tenants. Qualified low-income tenants (with a household income lessthan 125% of the Federal poverty level guidelines) may receive a higherincentive for each weatherization measure (i.e. attic, floor & wall insulation) andmay qualify for an incentive for replacement windows. Low –income status isdetermined by the Lower Columbia Community Action Council (CAP) andcommunicated to the District upon certification.Residential Energy Matchmaker ProgramThe objective of this program is to assist the local Lower Columbia CommunityAction Council (CAP) with a financial in-kind match provided by the State ofWashington Department of Community, Trade and Economic Development(CTED) Housing Division. Based on the amount of funding the PUD uses forlow-income financial incentives under its Residential Low Income WeatherizationProgram the local CAP receives a match for a portion of that amount from theCTED Housing Division for use in weatherizing electrically heated low incomehomes in Cowlitz County.Residential Resource-Efficient Appliance RebatesThe objective of this program is to encourage residential customers to purchaseresource-efficient appliances (i.e. appliances that save both water and energy).The current program, the EnergySHARE Plus (Energy Saving Home ApplianceRebate Effort) started in June 2006. Participants are offered a $70 rebate forqualifying clothes washers and a $25 rebate for qualifying water heaters,dishwashers or refrigerators.Residential Compact Fluorescent Lighting (CFL) ProgramThe objective of the CFL Program, which has had a number of promotions sinceApril 2005, is to reduce energy consumption related to residential lighting. In theinitial campaign customers received a coupon for $4-off of the regular price of anEnergy STAR certified CFL. Currently, the customer receives the benefit of aregional buy-down/mark-down at the wholesale level, which reduces the cost tothe retailers, allowing them to offer the EnergySTAR bulbs at a reduced price.47

There have been as many as twelve retailers in the county participating in theprogram. Retailer SKU numbers are used to track each bulb purchased underthe program.Residential Energy Efficient Heat Pump Rebate ProgramThe objective of this program is to encourage the installation of high qualityenergy efficient residential heat pumps in site-built homes. The H 2 AdvantagePlus Residential Heat Pump Rebate Program (The “Home Heating” Advantage)offers financial incentives ranging from $450 to $900. Rebate levels aredependent upon the location of the duct system in either a heated or unheatedspace and the efficiency rating of the heat pump unit, regardless of the existingfuel type currently being used to heat a customer’s home.Northwest ENERGY STAR ® HomesThe objective of the ENERGY STAR ® program is to encourage builders of newelectrically heated site-built homes to build homes that are at least 15% moreenergy efficient than residential code requirements in Washington State. Thesehomes must be built in Cowlitz County and are eligible for an incentive of up to$1,300 when installing a heat pump or zoned electric heating system. Homescan be new site-built single family, duplex, townhouse or condominiums.Additional details and instructions can be accessed at:www.northwestenergystar.com.CEEP Plus Lighting Incentive OfferThe objective of the Commercial Energy Efficiency Program (CEEP) PlusLighting Incentive Offer is to provide non-residential customers with incentives toupgrade and retrofit their current lighting system in existing buildings with a moreenergy efficient system. The lighting system load in the affected area must bereduced by at least 30%. New construction and major remodels are not eligibleunder this program but can be addressed under the New Construction Program.Commercial Energy Smart ProgramThe objective of the Energy Smart Program, formerly Energy Smart GrocerProgram, is aimed at assisting supermarkets, independent and cornerneighborhood groceries, specialty shops (ice cream, butchers, etc.), institutionalkitchens (schools, hospitals, factories, assisted living and nursing care facilities,etc.), food marts, convenience stores, florists, buffet and sit-down restaurants inreducing electrical energy use and savings on their energy bills. The ESProgram offers no cost energy audits, technical assistance and financialincentives for installing qualifying energy saving measures. Participation issimple. A Field Energy Analyst provides an energy audit in order to pinpointenergy saving opportunities that can be upgraded. The Field Energy Analystproduces and delivers a customized Energy Savings Report that prioritizes thecustomer’s options. This report details potential energy savings, projected rebate48

amounts, estimated retrofit costs and simple payback. In addition the PUD backsup all recommendations with financial incentives.Industrial/Commercial EnergySPICE Plus ProgramThe objective of the Energy Saving Plan Industrial Conservation Effort(EnergySPICE) Plus Program is to provide financial incentives to largecommercial and industrial manufacturers for the development and installation ofelectrical energy saving measures in their processes. EnergySPICE Plusprovides incentives up to $0.12 per kilowatt-hour of verified annual energysavings or 70% of incremental project costs, whichever is less. Typical energyefficiency measures include lighting and controls, complex HVAC systems,chillers, controls, refrigeration, variable speed drives, motor upgrades, pump/fanefficiency upgrades, compressed air improvements and other measures that maybe customized to a specific process improvement.NEMA Premium Efficiency Motor Rebate ProgramThis program provides financial incentives in the form of rebates, to CowlitzCounty PUD commercial and industrial customers who purchase motors thatmeet or exceed “NEMA Premium Efficiency” standards. Rebates are only for“end users” of motors and are not available to motor vendors for motors that theyre-sell. A “Motor Rebate Application Form” must be completed and signed with acopy of the invoice for each applicable motor. Program forms and additionaldetails can be seen at http://www.cowlitzpud.org/pdf/EnergySPICE_Plus.pdf.Incentives vary based on motor horsepower and can range from $70 to $2,810.Industrial/Commercial Compressed Air System Efficiency (CASE)ProgramThe objective of the Compressed Air System Efficiency (CASE) Program is toprovide opportunities for customers to save energy, lower operating costs andimprove compressed air system reliability. Existing or new compressed airsystems are eligible for specific efficient equipment technology incentives. CASEincorporates three major components that will save money and unscheduleddowntime which include comprehensive training, technical assistance andefficient equipment cash incentives.Conservation Programs under DevelopmentCowlitz PUD is in the process of expanding its conservation portfolio to providefor broader market coverage, improve conservation as a reliable energy resourceand increase its capability for meeting regional energy targets. Specificprograms under development include:• A rebate program for residential refrigerator/freezerdecommissioning and recycling which offers a rebate to dispose ofold refrigerators and freezers.• A residential resource and energy saving showerhead give-awayprogram for electric water heater customers.49

• Residential compact fluorescent lighting give-away or couponprograms.• Premium efficiency water heater rebate program where themanufacturer offers a limited lifetime warranty.• A commercial energy smart design program for commercial newconstruction where energy efficiency measures to be installedexceed building codes, such as, lighting upgrades, chillers, andwindow upgrades. Qualifying buildings would receive a financialincentive for upgrades and could also receive technical assistancein the design process.50

Chapter 6: Theories of Model OperationThe goal of the IRP model is to test potential resources under a wide spectrum ofpossible future conditions. To do this, the model attempts to quantify uncertaintyaround a host of variables that make up the Cowlitz PUD power cost function.Roughly speaking, there are three major sources of uncertainty. They are:1) Fiscal: Examples of fiscal uncertainty that are captured in the modelinclude variability in the cost of capital and IPP financing rates,variability around plant capital costs and uncertainty around inflation.2) Physical: Physical uncertainty is arguably the most relevant to theDistrict. Examples that are modeled include loads, generation, fuelprices, power prices and market heat-rates. Oftentimes historicalrecords can be used to define the statistics around physical variables.3) Policy: Public policy and legislation has a measurable impact on theDistrict. Unlike physical fundamentals (like load or runoff) policy isinherently unpredictable. Given the impact legislation can have on thebottom line it is vital to account for the possibility of certain laws beingpassed. The principle lawmaking uncertainty addressed in the IRPmodel is concerned with possible CO2 emission legislation.This chapter will discuss the tools and methods used to measure the sources ofuncertainty discussed above.51

Models Used in the IRPCowlitz PUD employed a wide array of sophisticated computer software in theprocess of developing the IRP. This section will discuss the applications andbackground of each.Aurora XMPAurora XMP is a production cost model developed by EPIS, Inc of Sandpoint,Idaho. Aurora simulates the supply and demand fundamentals that underlie thepower market. Aurora utilizes a multi-zone, transmission constrained dispatchlogic that results in a WECC-wide representation of prices and heat rates.Figure 31WECC Zone Map from Aurora XMPAurora contains a database of every plant in the WECC and its operational andeconomic parameters. Aurora also contains demand forecasts by zone. Themodel then conducts an economic dispatch of the resources for an entire year onan hourly basis. Hourly output is then aggregated into monthly average peakand off-peak values.Aurora was used to correlate hydro generation to market heat rates. Toaccomplish this, historical hydro generation was modeled and run through a52

epresentation of today’s system. A computational dataset was constructed torecord the resulting on-peak and off-peak heat rates.Crystal BallThe analysis for this IRP was prepared using a decision dialog process.Quantitative analysis was performed by constructing an economic and energymodel using Crystal Ball © which is a product designed to perform risk analysiswhen there are uncertainties involved in the decision making process.Crystal Ball is an analytical software program that brings Monte Carlo simulationto bear on spreadsheet models. A simulation is defined by Oracle as “ananalytical method that is intended to imitate a real-life system”. Monte Carlouses random number generation to determine the effects of uncertainty on aselected metric. It is particularly valuable when mathematical approaches aretoo complex; it can solve very complicated problems by “brute force”. Integratedresource plans by nature involve extreme amounts of uncertainty. Crystal Ballenables Cowlitz to define a range of possible values to uncertain variables (e.g.fuel prices, loads, capital cost, etc). Instead of supplying a single point estimate,the program returns a range of possible outcomes and the likelihood of realizinga particular outcome. The danger of relying on deterministic models is that thereis a chance of understating (or overstating) the risks involved with a decision.OptQuestAnother important tool used in the IRP is Oracle’s OptQuest. OptQuest is aglobal optimization program (as opposed to a linear optimization program suchas MS Excel’s Solver) that works in conjunction with Crystal Ball. OptQuest usessophisticated metaheuristic search methods to identify the best solutions. For amore detailed discussion on the application of global optimization on the IRP,please see: Global Optimization53

Variability of Hydro GenerationThe IRP model relies on the BPA produced “60-Year Study” to determine whattoday’s slice system would be capable of producing under historical hydrologicdata compiled from 1929 to 1988. The Crystal Ball software uses the MonteCarlo method to randomly pick water-years to load into the model. A discreteuniform distribution is used, meaning that the model assumes the likelihood ofevery year within the 60-Year Study to be equal.Figure 32Uniform Distribution Dialogue from Crystal BallFigure 33 below shows the confidence intervals yielded by the simulation:Figure 33Simulated Hydro Generation Percentile ValuesSlice Generation Confidence IntervalsSlice Generation (aMW)16,00014,00012,00010,0008,0006,0004,0002,000-Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec5%10%15%20%25%30%35%40%45%50%55%60%65%70%75%80%85%90%95%54

Each water year drawn from the study impacts the amount of hydro energyavailable on average by month for on-peak and off-peak hours. As mentionedearlier, the model relies on a sixty year sample of hydrologic data to calculate theDistrict’s slice generation. It is worth noting that average generation is notnormally distributed. Figure 34 shows a histogram of annual slice generationvalues (aMW) compiled from the 60 year deck.Figure 34Histogram of Simulation Hydro Generation765Frequency432107,2507,5007,7508,0008,2508,5008,7509,0009,2509,5009,75010,00010,25010,50010,75011,00011,25011,50011,75012,00012,250Slice GenerationThe distribution is slightly skewed towards poor water years. In addition, at thefar left there is a secondary “peak”. This phenomenon underlies the probabilitycalculation and occasionally manifests itself as duel-peak power costdistributions.55

Market Heat-RateIt is common in the WECC to express changes in supply-demand expectations interms of spark-spread or heat rate. 5 The market heat rate is a measure of howefficiently the market converts the energy content of the primary fuel into power.The market heat rate is where demand intersects the supply curve. Due to thevariability of hydro generation in the Pacific Northwest, there is significantuncertainty about the future shape and composition of the “supply stack” ofpower generating resources.Figure 35Volumetric Change and Impact on Heat Rates30RegionalDemand25RegionalSupply Stack,Low HydroMMBtu/MWh201510RegionalSupply Stack,High HydroHydro GenVolatility leads tovolatility inMarginal Resource50100070001300017600200002280026600273002800028900294003000030500MWAssuming all else equal, increasing hydro generation will push the supply curveout, causing market heat rates to fall. Conversely, low hydro generation willcause the supply curve to contract and market heat rates to rise. Uncertaintyabout the market heat rate has profound implications for the formation of prices.Heat rates are correlated with hydro conditions. However, due to the complexityof the underlying physical system they are difficult to calculate through traditionalmeans. Therefore the model uses the Aurora XMP electric market modeldeveloped by EPIS to derive market heat rates based on historical hydroconditions.5 Heat rates are denominated in terms of natural gas. This is because natural gas fired generating resourcesare the marginal technology in the WECC’s supply stack.56

Aurora is a production cost model, which uses an optimization procedure thatminimizes the cost of generating power required to meet demand within theWECC. 6 To accomplish this, Aurora specifies:• The characteristics of all of the generating resources within the WECC.• Load characteristics for the entire WECC.• Transmission system interconnections, capacity and limits.• Emissions limitations.• Operating imperatives, such as hydro resource ramping ability,maximum/minimum generation levels, etc.In essence, Aurora models the fundamental economic drivers of the system andforms a heat rate value based on the results. Because there is always a heatrate value corresponding to a slice generation value, heat rates follow thediscrete uniform distribution used by the hydro generation simulation. Figure 36illustrates the confidence intervals produced by the model for Mid-C/Sumas heatrate:Figure 36Simulated Heat Rate Percentile ValuesHeat Rate ($/MMBtu)12,00010,0008,0006,0004,0002,000-Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec5%10%15%20%25%30%35%40%45%50%55%60%65%70%75%80%85%90%95%CriticalUsing ancillary modeling, Aurora calculates monthly on-peak and off-peak heatrate values that correspond to slice generation values from the 60 year study 7 .6 Eydeland, Alexander and Krzysztof Wolyniec. Energy and Power Risk Management. Hoboken: JohnWiley & Sons, 2003. Page 252.7 The Northwest Power and Conservation Council use Aurora for long-term planning. The District wasable to use code collaboratively developed by EPIS and the NWPCC to model the resulting generation oftoday’s system given historical runoff.57

Natural Gas Price FormationFor the IRP analysis, Cowlitz PUD used the Northwest Power and ConservationCouncil’s recently published long term gas price forecast. Natural gas prices area highly important determinant of Mid-C power prices because combined cyclecombustion turbines are the marginal resources for the region. Figure 37 gives agraphical representation of the council’s forecast.Figure 37NWPCC Natural Gas Price Forecast$10.00$9.00$8.00$7.00$/MMBtu$6.00$5.00$4.00$3.00$2.00$1.00$-2000200120022003200420052006200720082009201020112012201320142015201620172018201920202021202220232024202520262027202820292030Medium Low Med-Low Med-High HighFor purposes of the IRP gas prices are assumed to be uncorrelated with heatrate.In the short term this is usually not true. In the long-term gas prices arelinked to global commodities such as oil and continental fundamentals that reactto forces beyond the Pacific Northwest.Power Price FormationIn the model, power prices are derived according to the following formula:HRP = * G1,000Where P is power price, HR is market heat rate and G is the natural gas price.The Aurora model produces a heat rate value, which is multiplied by a naturalgas price. For example, if gas prices are assumed to be $5.00 per MMBtu andthe market heat rate is assumed to be 9,500 then:58

9,500P = *$5.00 = $47.501,000This formation process is useful because one variable can be modeled based onfundamentals (heat rate) and another cannot (natural gas price).59

CO2 LegislationCO2 legislation is major concern for the utility industry, but the effects on thedaily energy market are an unknown. The first major issue with CO2 legislationis the uncertainty surrounding implementation. It is unknown if the nextadministration will be able to enact such a law. Another unknown is the coststructure for the emission tax. It could be a producer tax (a tax on generators) ora consumer tax (tax on retail electricity customers). Also, it is unknown if the taxwill be fixed or escalating.Figure 38 shows the generator emission assumptions used in the decisionmodel. The worst emitter is pulverized coal generation. IGCC is roughly inbetweenpulverized coal and natural gas powered plants. In light ofWashington’s SB 6001, it is likely that any future IGCC project will have tosequester CO2 emissions. With sequestration IGCC may emit less CO2 than anatural gas project. However- as stated earlier-carbon sequestration is anemerging technology that will likely be expensive and risky to implement.Figure 38CO2 Emission Assumptions250214212200170CO2 lbs/MMBtu150100119117 11911750-- - - -CCCT SCCT Coal IGCC Wind LandfillGas (CL)Biomass(CL)NuclearIRP AssumptionNWPCCThe impact of CO2 legislation is considered in the Cowlitz IRP decision model.The plan assumes that the legislation will be enacted sometime within the studyperiod, and will take the form of an escalating producer tax. Figure 39 relayshow the tax is modeled. In the base case (the red line) there is no CO2 tax until2018 which then escalates at a fixed rate through the end of the study period. Inthe actual simulations CO2 legislation is a stochastic variable. The probability for60

passage of the tax starts out very small in 2011 but increases as timeprogresses. The blue line represents an expected value over the course of thesimulation.Figure 39CO2 Tax Assumptions in Decision Model$50.00$45.00$40.00$35.00$/Ton$30.00$25.00$20.00$15.00$10.00$5.00$-20082009201020112012201320142015201620172018201920202021202220232024202520262027Average Stochastic ValueBase Case ValueIn an effort to quantify the effects of a CO2 tax, some preliminary in-housecalculations using the Aurora XMP model estimate the market effect to be a 10%to 20% increase in Mid-C/Sumas heat rates given a $7 per ton and $15 per tontax. The analysis was run over 70 years of historical hydro conditions.Figure 40CO2 Legislation Impact on Mid-C/Sumas Heat Rates13,00012,00011,00010,0009,000Base$7/Ton$15/Ton8,0007,0006,000Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec61

Figure 41 highlights the results from the study. The blue line represents theaverage of 70 scenarios with no CO2 tax. The pink and orange lines indicatethat heat rates are positively correlated to CO2 taxation in the WECC.Figure 41 demonstrates the impact of CO2 legislation in the IRP decision model.The red line represents the average on-peak heat rate over a ten year periodrandomly selected from the hydro generation history that correspond to the lasthalf of the study period. The blue line is the same ten water years with theaddition of the CO2 taxes from the base case.Figure 41CO2 Legislation Impact on Mid-C/Sumas Heat Rates in IRP Model16,00014,00012,00010,000Btu/kWh8,0006,0004,0002,0000Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov DecNo TaxCO2 TaxCO2 TaxNo TaxObviously CO2 taxes, as they are modeled, have a significant impact on themarket in the latter part of the study period. The impact that this has on theDistrict will vary depending on the resource choices it makes in the future.62

Resource AdequacyBPA customers will be required to provide their load and resource data andresource development plans necessary to track implementation of the voluntaryresource adequacy standards adopted by the Northwest Power andConservation Council.The Northwest Power and Conservation Council adopted an energy resourceadequacy standard for its own planning process and recommended that otherentities in the region incorporate it into their planning efforts. The term “standard”in this context does not mean mandatory compliance nor does it imply anenforcement mechanism. The energy metric is defined to be the annual averageload/resource balance in units of energy (average megawatts), where theload/resource balance is defined as the available average annual energy minusthe average annual firm load. The energy target for the Pacific Northwest iszero, that is, on an annual basis; resources should at least match the expectedannual load. The Districtis District is utilizing this standard in assessing its needfor resources in this IRP.63

Chapter 7: Analysis of Resource PortfoliosIRP ApproachIntegrated resource planning is a process of evaluating resource choices under arange of possible future conditions. The best performing resource sets arepicked and the utility proceeds to acquire or build them. Due to the inherentuncertainty about the future of demand, power prices, fuel prices, legislation andregulation this process is not at all simple. A portfolio that performs well under agiven set of conditions may perform poorly against another set. For example, autility with 100% of its generating fleet comprised of coal plants may perform wellin a future with no CO2 taxation. However, the introduction of such a tax mayseverely cripple the financial performance of that utility.How then does a utility go about choosing the right mix of resources to meetimminent needs given uncertainty about the future? Unfortunately, there is nosilver bullet that guarantees that today’s decision will be the right one twentyyears hence. This is true because it is impossible to predict the future. However,there are methods that allow the utility to make the best decision possible giventhe available information. The goal of the IRP is to identify strategies that provideacceptable outcomes across a wide variety of potential futures. The IRP mustconsider cost and risk - minimizing unacceptable outcomes and maximizingfavorable outcomes 8 . This section explains these key conceptual elements thatare utilized in the resource planning analysis.Monte Carlo SimulationMonte Carlo simulation is a computational technique that is suited to integratedresource planning and other complex problems with a high amount ofuncertainty. In general, the Monte Carlo method solves a problem by directlysimulating the underlying physical processes (e.g. power prices, capital costs,hydro generation, loads, fuel prices, plant capacity factors) and then calculatingthe average results of the process 9 . Monte Carlo relies on random numbergeneration and repeated samplings to derive results. It is a data-intensiveenterprise and requires the use of specialized tools. This analysis used OracleCorporation’s Crystal Ball software as the number generating “engine” underlyingthe decision model.The first step in the process is to construct a decision model that functionsproperly with fixed inputs. However, many variables are difficult (if notimpossible) to forecast. Instead of relying on a point estimate for, say, naturalgas prices in 2009, the Monte Carlo method calls for definition of a range ofpossible outcomes. Each point in the range is assigned a probability of8 Northwest Power and Conservation Council, Washington IRP Workshop Presentation, November 27 th20069 Paul Glasserman (2003). Monte Carlo methods in financial engineering. Springer-Verlag. ISBN 0-387-00451-3.64

occurrence. The result is a probability distribution. Probability distributions arespecified for each uncertain variable in the model. The next step is to define howthe distributions are correlated. This task is often the most complicated. Thecorrelations between some variables are famously difficult to quantify – such asthe relationship between hydro generation and Mid-C power prices.Figure 42Generalized Stochastic ProcessX =Natural Gas Price Heat Rate Power Price=Cumulative Probability100%80%60%40%20%0%Cash FlowCash FlowOnce the distributions and correlations are established, Crystal Ball utilizesrandom number generation to draw values out of the probability distributions.The model output is itself a distribution of a key metric like power cost or grossmargin (power cost is used in this analysis). Instead of a single expected powercost value associated with a resource addition, the end result shows the fullspectrum of outcomes. Finally, the median and standard deviation values arederived from the output distribution. This process is illustrated in Figure 42.Figure 43 provides a graphical illustration of the Monte Carlo process in the IRPmodel. The chart shows 25 randomly generated model iterations. It illustratesthe two types of risks that Cowlitz faces over the next 20 years: uncertainty andvariability. As time moves forward, the uncertainty around power costs increases– that is the distance from the highest possible cost and the lowest possible costwidens. This can be observed as the blue band increasing its width.65

The second risk faced by the District is variability – which is the amount powercosts can change from year to year. This also increases over time. Monte Carlosimulation is important because it does a better job capturing these risks thanrelying on point estimates or scenarios.Figure 43Example Annual Power Cost Profiles ($ Thousands)$300,000,000$250,000,000$200,000,000Power Cost$150,000,000$100,000,000$50,000,000$-2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027Year66

Cost Reduction vs. Risk ReductionThe previous section established a methodology for determining a givenresource set’s expected value (median power cost) and a measure of variance(standard deviation). The model makes an assumption that Cowlitz is riskaverse, meaning that given a choice between two portfolios yielding the sameexpected power cost, the utility would pick the one with a lower standarddeviation.Figure 44Illustration of Risk and RewardHigher Cost,Less RiskFrequencyLower Cost,Higher RiskPower CostCowlitz will take on additional risk only if it is rewarded with a lower expectedpower cost. Alternatively, the utility may choose a higher cost portfolio with alower standard deviation. There is not an ultimate “right” choice of portfolios.Each utility will choose resource sets based on its own unique goals, views andtolerance for risk. Figure 44 illustrates the tradeoff between risk and reward.67

Global OptimizationIn the decision model, there are only a handful of variables that the District hasany control over. They are:1. What type of plant to build2. When to build itThese variables are known as decision variables. The IRP optimizationfocuses on selecting the best possible combinations of resources. How is thebest way to accomplish this? It is not as easy task. One option would be totry to enumerate every possible combination. By employing this strategy,Cowlitz would be highly certain that the final choice is the optimal solution.However, consider that in the model there are twenty years in the studyperiod. In each period (assuming no constraints) the District has the option ofbuilding one of ten possible generation types. That would entail running 20 10(10.2 trillion) simulations. If each simulation was 500 iterations, completeenumeration would require 5.1 quadrillion individual iterations. Obviously, thisapproach would require too much time and resources to be practical.Figure 45Generalized OptQuest Search Procedure68

Another alternative would be to search for optimal values in an “ad hoc” way.For example, Cowlitz could start with an arbitrary combination of resourcesand run a simulation. Next, the selection could be modified and thesimulation rerun. The process could be repeated until a satisfactorycombination of resource is found. The problem with this approach is thatthere is no systematic way of searching the feasibility space. This approachruns the risk of returning a suboptimal result.OptQuest uses a metaheuristic search algorithm. Such models are applied toproblems where there is no satisfactory problem specific algorithm – such ascombinatorial optimizations. The goal of OptQuest as it relates to the IRP isto identify a combination of resources that minimizes an arbitrary function. Inthe case of the IRP, the objective to be minimized is the net present value ofpower costs over a twenty year period. A neural network uses adaptivememory procedure to intelligently search for optimal solutions.Figure 46Cowlitz Specific Optimization ProcessFigure 46 provides a general overview of the IRP optimization process. In thefirst step, combinations of resources are added to the decision model. Stochasticsimulation is conducted – yielding distributions around key assumptions such as69

loads and prices. The result is a portfolio power cost distribution that is uniquelyassociated with that combination of resources. The next step is to measure thepower cost distributions median and standard deviation values. OptQuestremembers these values from the past “best” portfolio and compares them to thecurrent results.Figure 47 is a conceptual illustration of the global optimization process. An IRPis a classic combinatorial optimization problem. If one were to create a threedimensional plot of all possible solutions, it may look something like Figure 47.The surface represents all possible combinations of resource additions. Forpurposes of the IRP, Cowlitz is interested only in the best solutions. OptQuestsearches the feasibility surface for the best combinations of resources within acertain “neighborhood” of possible solutions. Once the program is satisfied it hasfound a local solution, it will jump to another place on the feasibility surface andrepeats the process.Figure 47Global and Local OptimizationGlobal OptimumLocal OptimumOptQuest keeps a record of all of the locally optimal solutions. This dataset canbe used to construct an efficient frontier – which is discussed in the next section.70

Efficient Frontier AnalysisA helpful tool for making resource decisions is calculation of the efficient frontier.When OptQuest looks for locally optimal resource combinations, it also records ameasure of the distributions variance. Once all of the locally optimal solutionsare collected, they are organized in a two-dimensional chart that compares eachportfolio in terms of reward (low power cost) and variance.When looking for the best set of resources, Cowlitz makes the evaluation interms of risk and reward.Figure 48Conceptual Illustration of the Efficient FrontierCowlitz Power CostHigh Cost, Low RiskMed Cost, Med RiskHigh Cost, High RiskLow Cost, High RiskRisk: Cost VariabilityIt is important to note that every portfolio that lies on the efficient frontier yieldsthe best return for a certain level of variance. As a result, there is not one pointon the curve that represents the absolute “right” portfolio. Rather, the bestchoice for a utility is dependant on that utility’s tolerance for risk. It is imperativethat policy makers and stakeholders understand these tradeoffs so that informeddecisions can be made on the preferred strategy.71

Chapter 8: Detailed ResultsThis section will provide detailed results from the IRP modeling and simulation.The goal of the IRP model is to test a variety of resource types and developmentschedules against a wide range of possible fundamental conditions or “futures”.Figure 49 shows the efficient frontier calculation for Cowlitz PUD. The Y-axisshows the twenty year net present value power cost discounted back to presentat the District’s cost of capital. The X-axis shows the variance of the distributionassociated with each point on the graph in terms of standard deviation.Figure 49Cowlitz PUD Efficient Frontier Calculations$1,900,000$1,850,000Power Cost 20 Year NPV ($ Thousands)$1,800,000$1,750,000$1,700,000$1,650,000$1,600,000$1,550,000$1,500,000$1,450,000$1,400,000ABCD$55,000 $65,000 $75,000 $85,000 $95,000 $105,000 $115,000STDEV ($ Thousands)Each point in the efficient frontier represents an explicit schedule of resourceadditions. There is a tendency for portfolios to form clusters at various points onthe curve with gaps in between. This is due to the fact that the model cannot addresources in increments greater than oron less than 25 MW on an annual basis.There are several options for choosing the best portfolio to meet the District’sneeds. One option is to choose a single portfolio from the frontier. By doing so,the DistrictDistrict commits to a specific mix of resources and a specific schedulefor obtaining them. This option is used by a handful of regional utilities.Cowlitz elected to pursue an alternate selection methodology. Instead of pickinga single point, the District chose a “neighborhood” that approximated its tolerancefor risk. In Figure 49, this is represented by the dashed oval. From theneighborhood, several of the best portfolios were chosen because of their72

position on the frontier curve. These portfolios were labeled A, B, C & D and areshown in isolation in Figure 50.The rationale behind this approach is that it gives a more broad-based view as tothe best types of resources. Also, the District is not ready to commit to a specificaddition schedule. Rather, it seeks to identify a general timeline for resourceadditions that would allow a measure of flexibility for strategic considerations.Figure 50Representative Portfolios from FrontierPower Costs 20 Year NPV ($ Thousands)$1,640,000$1,620,000$1,600,000$1,580,000$1,560,000$1,540,000$1,520,000A$65,129 ,$1,627,000B$66,346 ,$1,582,700$69,943 ,$1,532,800$74,276 ,$1,512,100$1,500,000$64,000 $66,000 $68,000 $70,000 $72,000 $74,000 $76,000CDSTEDEV ($ Thousands)The following tables reveal the detail behind the chosen portfolios.Figure 51Addition Schedule for Portfolio AA 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027Wind - - - - - - - 25 25 25 25 25 50 50 75 75 75 100 100 100LandFill Gas - - - - - 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25Geothermal - - - - - - - - 25 25 50 50 50 50 50 50 50 50 50 50Combined Cycle - - - - - - - - - - - - - - - - - - 25 25Biomass - - - 25 25 25 50 50 50 50 50 50 50 50 50 50 50 50 50 50Portfolio A is comprised of 100 MW of wind additions, 25 MW of landfill gas, 50MW of geothermal, 50 MW of biomass and 25 MW of combined cycle generation.The first resource is added in 2011.Figure 52Addition Schedule for Portfolio BB 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027Wind - - - - 25 25 25 50 50 50 50 50 75 75 75 75 75 100 100 100LandFill Gas - - - - - 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25Geothermal - - - - - - - - - - 25 25 25 25 25 25 25 25 25 25Combined Cycle - - - - - - - - - - - - - - - - - - 25 25Biomass - - - 25 25 25 50 50 50 50 50 50 50 50 50 50 50 50 50 5073

Portfolio B is comprised of 100 MW of wind additions, 25 MW of landfill gas, 25MW of geothermal, 50 MW of biomass and 25 MW of combined cycle generation.The first resource is added in 2011.Figure 53Addition Schedule for Portfolio CC 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027Wind 25 25 25 25 50 50 50 50 50 50 50 50 75 75 75 75 75 100 100 100LandFill Gas - - - - - 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25Geothermal - - - - - - - - - - - - - - - - - - - -Combined Cycle - - - - - - - - - - - - - - 25 25 25 25 25 25Biomass - - - - - - 25 25 25 25 50 50 50 50 50 50 50 50 50 50Portfolio C is comprised of 100 MW of wind additions, 25 MW of landfill gas, 50MW of biomass and 25 MW of combined cycle generation. The first resource isadded in 2008.Figure 54Addition Schedule for Portfolio DD 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027Wind 25 25 25 25 25 25 25 25 25 50 50 50 50 50 50 50 50 75 75 75LandFill Gas - - - - - 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25Geothermal - - - - - - - - - - - - - - - - - - - -Combined Cycle - - - - 25 25 25 25 25 25 25 25 25 25 50 50 50 50 50 50Biomass - - - - - - - 25 25 25 25 25 25 25 25 25 25 25 25 25Portfolio D is comprised of 75 MW of wind additions, 25 MW of landfill gas, 50MW of biomass and 50 MW of combined cycle generation. The first resource isadded in 2008.Figure 55Four Portfolio Addition Schedule (Energy)Capcity Factor 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027Wind 33% 4 4 4 4 8 8 8 12 12 14 14 14 21 21 23 23 23 31 31 31LandFill Gas 80% 0 0 0 0 0 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20Geothermal 90% 0 0 0 0 0 0 0 0 6 6 17 17 17 17 17 17 17 17 17 17Combined Cycle 50% 0 0 0 0 3 3 3 3 3 3 3 3 3 3 9 9 9 9 16 16Biomass 80% 0 0 0 10 10 10 25 30 30 30 35 35 35 35 35 35 35 35 35 35Figure 55 shows the average resource addition schedule of all four portfolios interms of energy (assumed capacity factors are shown in the tan-coloredcolumn 10 ). In general each of these portfolios is very similar to one another. Thisis due to the penalties associated with non-compliance with Washington’srenewable portfolio standard. The best portfolios must be dominated byrenewable resources to avoid the penalty.Figure 56 shows the percentages of the resources in the average portfolio. Windgeneration is the largest component accounting for 43% of additions. Biomassgeneration is the next largest component at 21% of the additions. Two otherrenewable types landfill gas and geothermal represent 12% and 9%,10 Capacity factors are for illustrative purposes only. What is shown may not represent the average capacityfactors assumed in the simulation.74

espectively. The final 15% of resource additions is part of a combined cyclecombustion turbine. This answer is based on the low capital cost of a CT. Due tothe market prices being generally cheaper than the variable cost of power from aCT, the plant is installed for capacity to satisfy the resource adequacy constraint,and then the energy is purchased from the market or the CT depending uponwhich is cheaper. Although the CT is not heavily utilized, it caps Cowlitz’s cost ofpowerFigure 56Average Resource TypesBiomass21%Wind43%Combined Cycle15%Geothermal9%LandFill Gas12%Figure 57 shows the mix of new resources in the first ten and the last ten years ofthe study period.Figure 57Resource Additions 2008-17 and 2018-2018-20277%2008-201727%32%37%53%WindLandFill GasGeothermalCombined CycleBiomass5%13%5%0%21%2775

In the first half of the study period the District should concentrate on evaluatingwind resources and biomass resources. Landfill gas should also be developed ifit is available. To a lesser extent, the District should assess geothermal andcombined cycle resources. In the second half of the study period, the majority ofthe Districts attention should be focused on developing or acquiring windresources. In this time period the District should shift more attention todevelopment of geothermal resources. At present there are not many examplesof geothermal technology in the Pacific Northwest although there are severalprojects that are under evaluation. By 2018 more will be known about theviability of this technology. In addition to the renewable resources the Districtmay want to access the availability of combined cycle plants.Figure 58 illustrates a generalized addition timeline. Wind, biomass and landfillgas are the resources that the District likely will evaluate in the near-term. It isimportant to note that landfill gas generation was developed to the maximumextent possible in all four scenarios. This is because it is the lowest costrenewable resource followed by biomass. The District may consider addinglandfill gas at an earlier date if the opportunity should arise.Figure 58Four Portfolio Average Addition Schedule (Energy)12010080aMW604020020082009201020112012201320142015201620172018201920202021202220232024202520262027Wind LandFill Gas Geothermal Combined Cycle BiomassThe next chart (Figure 59) shows the projected loads and resources with the IRPadditions. On an energy basis, Cowlitz will not need new resources until the year2023. Note that the IRP calls for the addition of resources beyond what the utilityneeds to meet the demand of its customers. Cowlitz must add these renewableresources to meet the regulations set out in Washington State’s renewableportfolio standard. Given the uncertainty around the load forecast, the model is76

likely adding in some “insurance” renewable resources to lower the probability ofthe District failing to comply with the law.Figure 59Loads vs. Resources with New Additions800750700650aMW600550500450BPA Tier 1 Swift No.2 White Creek & Nine CanyonWind LandFill Gas GeothermalCombined Cycle Biomass Load Forecast40020082009201020112012201320142015201620172018201920202021202220232024202520262027The renewable portfolio standard plays an important role in the results of the IRP.The model adds qualifying resources to avoid situations where Cowlitz is subjectto the non-compliance penalty. Adding resources that the District does not needto serve system load comes with a price tag attached. The next section willdiscuss analysis aimed at measuring the cost of legislation on the District’spower cost function.77

Effect of LegislationDuring the development of the IRP, discussion arose about the costs associatedwith I-937 and other legislative requirements. To answer this question severalalternate scenario optimizations were run in the IRP model. The results aresummarized in Figure 60. The first scenario assumes that I-937 stays in effectbut no CO2 legislation is passed during the study period. The second scenarioassumes that neither I-937 nor CO2 legislation is enacted. The third scenario isthe model base case and assumes that both laws are in effect during the studyperiod. Finally, the fourth scenario assumes that CO2 legislation is passed but I-937 is rescinded.Figure 60Optimized Least Cost Portfolios under Various Regulatory Scenarios$1,750,000$1,700,000$1,702,100$1,675,700Power Cost 20 Year NPV ($Thousands)$1,650,000$1,600,000$1,550,000$1,500,000$1,450,000$1,563,650$1,497,700$1,400,000$1,350,000WITH I-937, NO CO2LegislationNO I-937, NO CO2LegislationWITH I-937, WITH CO2LegislationNO I-937, WITH CO2LegislationThere are two principle results stemming from this analysis. One is that thereappears to be a negative correlation between CO2 legislation and District powercost. In other words, a CO2 tax actually lowers utility power costs. This is nottotally surprising given the assumptions in the model. Once a CO2 tax isimplemented market heat-rates increase which causes the wholesale price ofpower to increase at Mid-C. Cowlitz’s aggregate portfolio is dominated by hydroresources which are not subject to the tax. Because the District tends to havesurplus hydro generation to sell, the value of the energy resold in the market isworth more. This higher revenue stream offsets a greater amount of the District’spower costs.78

Another finding is that Washington’s renewable portfolio standard increases costto the District. Again, this is not unexpected as the District does not needresources until late in the study period. Due to the heightened demand forrenewable resources (due to similar legislation in other parts of the United Statesand the world) capital costs for resources such as wind generation have beenincreasing at a dizzying pace. Competition for suitable sites to build wind farmswill add support to the price of development. Fortunately, the District’s proactivepolicies have likely mitigated the cost to some degree. The White Creek projectgives the District the option to develop an additional 80MW of generation. If thedecision is made to proceed with the addition it will significantly contributetowards meeting the District’s I-937 obligation at a time when other utilities maybe competing for the remaining projects.79

Chapter 9: Hourly AnalysisThe IRP has optimized resource portfolios in terms of energy up to this point.Capacity is also a key component of resource planning. Capacity is a resource’sability to generate a specific amount when it is called on to do so, even if it is fora short amount of time. For example, a combined cycle plant that is capable ofgenerating 100 MW is assumed to have a capacity of 100 MW. This is becausethe resource is able to provide its full capacity for as long as it is economicallyreasonable to do so. A hydro project capable of generating 100 MW is alsoassumed to have capacity of 100 MW. However, the length of time the resourceis able to sustain its maximum generation will depend on how much water it hasin the reservoir feeding the project. Finally, a wind project capable of generating100 MW is assumed to have a capacity of zero. This is because wind generationis not dispatchable – that is it cannot be counted on to generate even if theDistrict is in dire need. It may generate at that time or it may not.Figure 61Peak Winter Weak Analysis – 2020 Test Year150014001300120011001000900MW800700600500400300200100017131925313743495561677379859197103109115121127133139145151157163HourLandfill-N Biomass-N CT-N Geo-N Swift 2Wind-N White Creek Tier 1 Load80

150014001300120011001000900MW800700600500400300200100017131925313743495561677379859197103109115121127133139145151157163HourLandfill-N Biomass-N CT-N Geo-N Swift 2Wind-N White Creek Tier 1 LoadGiven the District’s obligation to comply with the State’s renewable portfoliostandard, the IRP projects a significant build-out of wind generation. Theaddition of wind into the District’s portfolio complicates the resource decisionprocess in that, as stated earlier, it cannot be counted on when planning forresource adequacy. This is particularly true during high load “events” such asabnormally cold winter weather.Figure 61 illustrates an analysis conducted to access the impact of the IRPrecommended portfolio on the District’s ability to meet load during a winter coldsnap. The analysis looks forward to the year 2020 and assumes that the Districthas added the resources outlined in the previous chapter. The District selectedhistorical data from a week where temperatures were low and loads were high.The historical load profile was adjusted by a multiplier so that the peak load fromthe week is the same as the 2020 peak load forecast from the econometricmodel. Wind generation for the White Creek project is based off of actualoperational history for a week in December of 2007. Tier 1 generation is derivedfrom taking Cowlitz’s share of historical FBS generation for the same period. Themajority of IRP suggested resources are assumed to run at a fixed capacityfactor. The exceptions are wind additions and the combined cycle combustion81

turbine. The former is assumed to generate at the same capacity factor as theWhite Creek project. 11 The CT is assumed to be dispatched at full capacity.Figure 62IRP Portfolio’s Ability to Meet Hourly Needs46%54%AbleUnableIn general, the IRP recommended resources are able to meet the District’s needseven in extreme weather. Figure 62 shows the proportion of hours within theweek that the District’s load was met and when it was not. This is the casebecause I-937 requires the addition of more resources than the District needsduring the majority of the year. The IRP recommends development of renewableresources such as geothermal, landfill gas and biomass that have a higherconfidence of running than wind. Surplus from these resources are available tocover load during cold weather.11 Given this District’s option of expanding White Creek, this is not an unrealistic assumption82

Chapter 10: BPA ContractsOne of the key decisions that Cowlitz PUD will need to make in 2008 is theselection of a BPA contract for the 2012-2028 time period. This sectiondiscusses the key issues and analysis that Cowlitz PUD is using for decisionmaking. Final contract selection will be completed towards the end of 2008.Part 1: OverviewBPA’s “Regional Dialogue”BPA’s “Regional Dialogue” policies advance key national and regional goals,preparing the way for post -2011 BPA power sales contracts. The goal is to havenew 20-year power sales contracts signed by December 2008. According toBPA, “A 20-year contract time span will give the long-term certainty necessary forthe major infrastructure investments the region will need.”Summary of issuesKey issues addressed in BPA’s Regional Dialogue proposal include:• Service to Public Utilities• Slice product• The Public Exchange• Benefits to Residential and Small Farm Consumers of the IOUs• Service to Direct Service Industries• Conservation and Renewables• Transfer Service• Resource Adequacy• Long-term Cost Control• Dispute ResolutionOnly the first two issues, Service to Public Utilities and Slice product, areaddressed in this analysis since they are directly related to the District’sIntegrated Resource Plan.Major Components of BPA ProposalBPA will develop new 20-year power sales contracts, along with a long-termTiered Rates methodology. These contracts will be signed by December 2008,and will go into effect October 2011 and run through September 2028.The BPA policy includes a new, Tiered Rate approach that provides each publicutility customer with a High Water Mark (HWM) which will define its right to buypower at a Tier 1 rate. The Tier 1 rate will be based on the cost of the existingfederal system with very little augmentation. If preference customers choose tobuy more power from BPA beyond their HWM, this power will be sold at a Tier 2rate set to fully recover BPA’s costs of securing additional resources to serve thisload.83

Major components of the Tiered Rate proposal include:• Tiered Rateso Tier 1 limited to existing Federal Base System (FBS) plus up to 300aMW of augmentation (plus any augmentation for newpublics)Augmentation only if needed and not to exceed total FBS of7,400 aMWo Tier 1 priced at cost of existing systemo Tier 2 priced at marginal cost of new BPA purchases and/oracquisitions (i.e., equal to the cost of market or new resource)• Each public gets a 20-year allocation of Tier 1 power equal to its “HighWater Mark” (HWM)o The HWM for each utility would be based on its actual loads in FY2010 and the resource amounts established in its Subscriptioncontracts for FY 2010• BPA and the publics would execute Regional Dialogue contracts in FY2008 with an estimate of the HWM and the approach to true it up to actualFY 2010 loads• Publics can buy from BPA at Tier 2 rates, or acquire their own resources,to serve loads in excess of HWMBPA Product OfferingsBPA will offer the following products in the post-2011 period:• Tier 1 - Load Following (Full/Partial Requirements) –Provides all powerneeded to meet a customer’s actual load minus declared resourceamounts.• Tier 1 - Block – Provides a predefined amount of power inmonthly/seasonal flat blocks to meet a customer’s net requirement load.• Tier 1 - Slice/Block – Provides power based on the actual generationshape of the Federal system.• Tier 2 – Available from BPA under any of the above Tier 1 productsTier 1 rate design is being discussed between BPA and public customers andhas not been finalized. However, it appears that the Tier 1 rate designapplicable to Tier 1 products is moving toward a Slice-like rate design. Asignificant portion of the revenue requirement is recovered through acustomer charge based on each customer’s Tier 1 annual firm energy right,expressed as a percentage, applied to that portion of the revenue84

equirement apportioned to the customer charge. The customer charge willbe recovered on a take-or-pay basis.Product Basics:• Start with shape of the FBS under critical water• Public utility customers Tier 1 service provided from this resource• A customer’s product choice can be viewed as a decision on the additionalservices offered by BPA to shape and convert the FBS into energydeliveries that meet the customer’s net requirementFigure 63Average Shape of the FBSHow Existing FBS Value is preserved in Tier 1Rules for Tier 1 are based on the costs associated with the current FBS plus:• Costs of limited augmentation (300 MW, total FBS not to exceed 7,400MW)• Costs of services necessary to provide load shaping and load varianceHow FBS capacity is preserved• Slice: Value is directly included in the product• Block and Load Following: Value is provided through revenue from themarketing of secondary energy• There is a tradeoff between managing capacity to create value forsecondary marketing, and using capacity to serve load and/or to offerresource support services to serve load• The equity issues associated with this tradeoff will be further discussed inthe contract, products and TRM processes and subsequent rate casesLoad Following Product85

• Currently referred to as Full or Partial Requirements• Provides all power needed to meet a customer’s actual load minusdeclared resource amounts• Rates (PPC proposal)o Customer charge (similar to slice rate)o Demand charge: historical and incrementalo Load shaping charge to convert the firm shape of the FBS into thecustomer’s monthly expected load.o Load variance charge to cover variations from the forecast,expected load to actual load.o Includes credits for the value of secondary energy.• Resource integration – Rules based, currently being defined (may requirecomplex Resource Support Services)• Shaping Critical FBS to Load Following Product:• The Load Following Product includes load variance charges, inaddition to the shaping charges incurred by the block product• BPA is responsible for meeting the customer’s hourly load shapeFigure 64Shaping Critical FBS to Load Following ProductBlock Product• Provides a predefined amount of power to meet a customer’s netrequirement load.• Power is delivered as flat monthly blocks.o BPA currently discussing monthly shapes with customerso BPA currently not providing needed flexibility• Block only not an option due to lack of other variable resources.• Rateso Customer chargeo Load shaping charge for the projected cost to convert the firmshape of the FBS into the predefined block shape.86

o Includes credits for the value of secondary energy.Figure 65Shaping Critical FBS Into a Shaped BlockSlice Product• Provides power based on the actual generation shape of the Federalsystem.• Rates:o Customer charge only.o Receives secondary power directly as a part of the raw output ofthe federal system rather than secondary revenue credits.• Slice amounts would be limited to 25% of the Federal system.• Compared to current product, the new Slice would have modestreductions in operational flexibility, and/or clarification of capacity rightsand flexibility.o Modifications based on BPA RD policyo No ability to self-supply ancillary services• Slice must be paired with a Tier 1 Block product to fill in up to theremainder of what the HWM provides.Slice Allocation Methodology• Slice/Block purchasers will request a Selected Slice Percentage (SSP) notto exceed 60% of their Tier 1 purchase (assuming 40% Block minimum).• If the sum of the SSP’s exceeds 25% of the FBS, BPA will reduce theindividual SSP’s proportionately to achieve the 25% limit.• If the SSP is reduced, the purchaser may increase their Block by anamount less than or equal to the reduction in SSP, expressed in aMW.• Example:Total SSP requests = 30% of FBS (Reduced SSP will be calculated as25/30 of the requested SSP)Customer A’s SSP request = 5%Customer B’s SSP request = 1.5%87

Customer A’s reduced SSP = 5 x (25/30) = 4.1667%Customer B’s reduced SSP = 1.5 x (25/30) = 1.25%Condition Forecast at Start-up in FY 2012Based on currently available information, the following conditions are forecast byBPA at the start-up of new power supply contracts in FY 2012.Figure 66FY 2012 ForecastThe Contract High Water Mark (CHWM)High Water Marks can change due to changes in federal resource capability andchanges in service territory:• Changes in Federal Resource Capabilityo Each rate case BPA will calculate the annual firm capability of theFederal system available for sale at the Tier 1 rate.o Each utility’s HWM will be adjusted up or down in proportion to thechange in FBS capability.o The Tiered Rates Methodology Rate Case conducted during FY07will establish the approach for measuring the size of the FBS.• Changes in Service Territoryo Annexations between public utilities with HWMs would result incorresponding adjustments to their HWMs.88

Cowlitz Specific High Water Mark CalculationFigure 67Cowlitz Preliminary Calculation of Estimated High Water MarkLine Item # Line Item BPA Funding Notes1 Total Retail Load, 2010Commission Approved Forecast582.31Adjusted for I-937 Conservation2 Dedicated Resources 19.50 Swift 23 Net Requirement before conservation 563 1-24 Sum of all utilities Net Requirements 7,300 Latest BPA Projection5 % of Sum of Net Req before conservation 7.71% 3/46 FBS 7,300 200 aMW augmentation7 HWM before Conservation 563 No Force Maj/Weather Norm8 Self Funded Conservation @ 100% 0.00 Current projection9 BPA Funded Conservation @ 75% 2.8010 Total Utility's credited conservation 2.1011 Net Req +Conservation adder 565 7+1112 Total of all Utilities' Conservation adders 120 BPA share of 5th Plan13 All utilities' Net Req. +Conservation adders 7,420 4+1314 % of Sum of Net Req. after conservation 7.61% 12/1415 Contract HWM 555.77 4*1516 Net change from conservation adj. -7.04 3-1689

TimelineFigure 68Rough Timeline for Regional Dialogue Contracts and Rates90

Part 2: Contract AnalysisThe following section will detail analysis created to assist Cowlitz PUDmanagement with the BPA contract decision. At present, Cowlitz PUD isexploring the benefits of all of BPA’s product offerings. A final decision will bemade at the end of 2008.“SWOT” analysisSWOT Analysis is a tool used for strategic planning and is comprised of fourdimensions: Strengths, Weaknesses, Opportunities & Threats. Its purpose is toidentify the key internal and external factors that are important for reaching agiven objective. Below is an application of the SWOT method to Cowlitz’s post2011 BPA contract decision. Either option has associated benefits and problemsthat will need to be carefully considered.Figure 69Cowlitz PUD “S.W.O.T” AnalysisSLICELoad Following1 Lower cost to integrate non-federal resources Simple to administerStrengths & Opportunites234District able to customize risk management strategies to managevolume and price uncertainty associated with FCRPSDistrict has immediate knowledge of how FCRPS generation andmarket prices will affect retail ratesDistrict better positioned to respond to changing industry andmarketplace. District better positioned to procure viable Tier 2replacements5 District better positioned to procure new resources6 BPA rates simpler and cost basedWholesale power costs aligned with peersBPA manages risk of secondary energyBPA manages scheduling, trading and settlement systems7 Represents physical allocation8 Better able to customize energy related services to customers1 Complex to administer and manage No diversity from BPAWeaknesses & Threats23Power supply costs may become disconnected from peers in shorttermDistrict must be prepared to manage financial volatility associatedwith SliceDistrict not well positioned to respond to changing industry / marketplaceDistrict does not have direct knowledge of FCRPS generation andmarket prices may affect retail rates4 BPA serves a "pool" rather than individual utilities5 More costly to integrate non-Federal resources; limited options6May restrict non-federal resource development (original purpose ofallocation)7 BPA rates more complex, market based891

Chapter 11: Next StepsThe District’s IRP defines the District’s need for new resources and investigatesdifferent generic resource types with an objective of presenting both quantitativeand qualitative analysis of the risk and rewards of pursuing different resourcetechnologies to fulfill the District’s resource requirements.The District’s action plan is divided into two sections. The first section describesthe conclusions drawn from this IRP with respect to actions to be taken in regardto electric resource acquisition. The second section describes issues to beinvestigated further for possible inclusion in this IRP or updates to this IRP.Action Plan – Resource Acquisition1. The District does not need additional resources to serve load until 2023,which provides time for the District to thoroughly investigate differentresource alternatives before additional procurements are made. However,I-937 portfolio standards require additional renewable resources starting in2016.2. The District should investigate expansion of the White Creek energyproject.3. Investigate the availability and feasibility for development of landfill gas,biomass and geothermal resources in the Pacific Northwest.4. The District should decline to participate in Energy Northwest’s IGCCproject. The District doesn’t need the resource and the risks of IGCCtechnology are significantly larger than other resource options.5. Implement all cost-effective conservation consistent with the requirementsof, and future amendments to, I-937.6. Continue to support renewal of renewable incentives, such as REPI,Production Tax Credits and CREBs, by Congress.7. Support state legislation that allows publicly owned utilities to fully utilizethe full range of incentives listed above.8. Participate in regional efforts on BPA contracts. Many important issues,including the power purchase arrangements that BPA will offer, theamount and cost of BPA power available to the District remain to beresolved. During 2008, the District will continue working with BPA andother regional parties to develop the new long-term BPA power supplycontracts for cost-based power. In these efforts, the District will promote92

creation of products that can best enable the District to meet the needs ofits retail electric customers.9. Determine if the District will seek legislative amendments to I-937standards to modify the requirement to develop renewable resources inexcess of the utility’s load obligations.Action Plan – IRP Analysis1. Undertake additional analysis of capacity requirements and capacityresources to meet future requirements.2. Monitor development of resource adequacy standards for the PacificNorthwest.3. Develop a better understanding of the Renewable Energy Credit (REC)market.4. Undertake further investigation of trends in the cost of wind projects.b. Wide range in capital costs currently being quoted by regionalutilities.c. BPA in the process of developing a separate rate for integration ofintermittent resources.5. Analyze alternative forms of BPA purchase arrangements.6. Acquire a better understanding of the proposed mechanism forimplementing the 4% cost cap under I-937. This cost cap may triggerbefore the volumetric requirements of I-937 are met.The District expects to update its IRP on a two-year cycle to ensure the processremains fluid and new issues, analyses, and information are incorporated into theplan on a regular basis.93