Electric Analysis Contents Washington State Depend On PSE For
CHAPTER 5Electric AnalysisContentsMore than a million customers inWashington state depend on PSE for1. Resource Need . 5-1safe, reliable, and affordable electric2. Existing Resources . 5-10services. The IRP analysis described3. Resource Alternatives . 5-22in this chapter enables PSE todevelop valuable foresight about how4. Analytic Methodology . 5-29resource decisions may unfold over5. Results andKey Findings . 5-37the next 20 years in conditions thatdepict a wide range of possiblefutures.1. Resource NeedFor PSE, resource need has three dimensions. The first is physical: Can we providereliable service to our customers at peak demand hours and at all hours? The second iseconomic: Can we meet the needs of customers across all hours cost effectively? Thethird is policy-driven: Are there enough renewable resources in the portfolio to fulfill thestate’s renewable portfolio standard requirements? Each dimension is described below.Physical reliability needPhysical reliability need refers to the resources required to ensure reliable operation ofthe system. This operational requirement has three components: customer demand,planning margins, and operational reserves. The word “load” – as in “PSE must meetload obligations” – specifically refers to the total of generated demand plus planningmargins and operating reserve obligations. The planning margin and reserves must bemaintained in order to minimize interruption of service due to extreme weather or theunlikely event of equipment failure or transmission interruption.5-1
CHAPTER 5 – ELECTRIC ANALYSISPhysical characteristics of the electric grid are very complex, so for planning purposesPSE simplifies physical resource need into a peak hour capacity metric through a loss ofload probability analysis. That is, if PSE has sufficient resources modeled in the IRP tomeet its normal peak hour demand plus a planning margin and the operating reservesrequired to dispatch those resources, the company will be able to maintain an adequatelevel of reliability across all hours. We can simplify physical resource need in this waybecause PSE is much less hydro-dependent than other utilities in the region, andbecause resources in the IRP are assumed to be available year-round. If we were morehydro-dependent, issues like the sustained peaking capability of hydro and annualenergy constraints could be important; likewise, if seasonal resources or contracts werecontemplated, supplemental capacity metrics may be appropriate to ensure adequatereliability in all seasons.Figure 5-1 shows physical reliability need for the three demand scenarios modeled in thisIRP. The components of this “peak need” are described more fully following the chart.Figure 5-1Electric Peak Need (Physical Reliability Need)Comparison of projected peak hour need with existing resources10,0009,0008,0007,000671 MW3,151 MWMW6,0002,238 MW5,0004,0003,0002,0001,0000ColstripNatural GasContractsHydroWindAvailable Mid-C TransmissionAdditional Mid-C Transmission Available w/ RenewalsDec Peak Load PM Op ReservesHigh Peak Load PM Op ReservesLow Peak Load PM Op Reserves5-24,948 MW
CHAPTER 5 – ELECTRICAL ANALYSISCustomer demandPSE uses national, regional, and local economic and population data to develop a range1of demand forecasts for the 20-year IRP planning horizon. These forecasts areincorporated into the scenarios modeled in the electric analysis. (See Chapter 4 forsummary descriptions, and Appendix H for a detailed discussion of the methodologiesand inputs used to develop the forecasts.)PSE is a winter-peaking utility, meaning that we experience the highest end-use demandfor electricity when the weather is coldest, so projecting peak energy demand begins witha forecast of how much power will be used at a temperature of 23 degrees Fahrenheit atSeaTac (a normal winter peak for PSE, see Appendix H, Demand Forecasts). We alsoexperience sustained strong demand during the summer air-conditioning season,although these highs do not reach winter peaks.Planning marginPSE incorporates a planning margin in its description of resource need in order toachieve a 5 percent loss of load probability (LOLP). The 5 percent LOLP is an industrystandard resource adequacy metric used to evaluate the ability of a utility to serve its load,2and one that is used by the Pacific Northwest Resource Adequacy Forum. The processhas two steps. First, we perform an analysis on the likelihood that load will exceedresources on an hourly basis over the course of a full year with focus on the winter periodsince PSE has a winter peaking load. Included are uncertainties around temperatureimpacts on loads and conservation savings, hydro conditions, wind, and forced outagerates (both their likelihood and duration). This analysis allows us to identify the amount ofresources needed to achieve a 5 percent LOLP in the winter period. In step two, the 5percent LOLP is translated into the planning margin for the winter period. (For thecalculations used to determine the planning margin, see the discussion of PSE’s Loss ofLoad Probability Model in Appendix K, Electric Analysis.) Figure 5-2 shows the updatedtargets for winter period planning margins that are estimated to result in an adequatelevel of reliability. Given that PSE has a winter peaking load, any capacity brought in tomeet the planning margin in the winter is also available to meet capacity in other seasons.1The demand forecasts developed for the IRP are a snapshot in time, since the full IRP analysistakes more than a year to complete and this input is required at the outset. Forecasts are updatedcontinually during the business year, which is why those used in acquisitions planning or ratecases may differ from the IRP.2See -3
CHAPTER 5 – ELECTRIC ANALYSISFigure 5-2(2013 IRP Winter Period Planning Margin)Planning Margins Net of Operating Reserves @ 5% RP2013-Winter Season13.5%14.0%16.0%In addition to the planning margin, the LOLP model also allows PSE to calculate theincremental capacity equivalent (ICE) of different types of new resources. Theincremental capacity equivalent is defined as the change in capacity of a generic naturalgas peaking plant that results from adding a new type of resource with any given energyproduction characteristics to the system while keeping the LOLP target constant at 5percent. The new resource could be wind, battery, coal plant, or even a power purchaseagreement (PPA). This allows us to assign the capacity contribution of certain projectsrelative to a gas peaker, and it is especially useful for variable energy resources such aswind. Fixed PPAs have an ICE of more than 100 percent, since they are available allhours without the forced outage rate peakers must account for. (For a more detailedexplanation of ICE, see Appendix K, Electric Analysis.) Figure 5-3 below shows theestimated incremental capacity equivalent of certain projects.3Although a generic wind project could be located in many parts of the Northwest, asoutheast Washington wind location was chosen as the generic wind for this IRP. Goodhistorical wind data exists for the area, PSE already owns development rights at theLower Snake River site, and transmission to the grid already exists in this location.Comparison of improvements in the incremental capacity equivalents for other wind sitesmust account for the incremental transmission costs required to connect the site to theregional grid.3PSE examined the incremental capacity equivalent of a central Washington wind project in the2011 IRP.5-4
CHAPTER 5 – ELECTRICAL ANALYSISFigure 5-3ICE ComparisonsIncremental Capacity Equivalent @5% LOLPWinterResource Type2018-2019** Natural Gas Peaker100%1) Existing Wind (Cumulative 822MW)10%2) New Wind (SE Washington 100MW)4%3) Battery (100MW, 400 MWhs Energy, Charge/Discharge Time 4Hrs)57%4) Colstrip (All Units 657MW4)90%5) Fixed PPA (200MW, 8760Hours)106%Operating reservesNorth American Electric Reliability Council (NERC) standards require that utilitiesmaintain a “reserve” in excess of end-use demand as a contingency in order to ensurecontinuous, reliable operation of the regional electric grid. PSE’s operating agreementswith the Northwest Power Pool, therefore, require the company to maintain two kinds ofoperating reserves: contingency reserves and balancing reserves.Contingency reserves. Contingency reserves are intended to bolster shortterm reliability in the event of forced outages. Under the Northwest Power Pool’scontingency reserve sharing agreement, generators must reserve an additional 5 percentof hydro or wind resources and 7 percent of thermal resources, when such units aredispatched to meet firm sales obligations. This capacity must be available within 10minutes, and 50 percent of it must be spinning. For example, if a 100 MW thermalgenerator is dispatched to meet firm sales, the utility must have an additional 7 MW ofresources available to meet the contingency reserve sharing obligation. Each member ofthe power pool maintains such reserves. If any member’s generator experiences a forcedoutage, the contingency reserve sharing agreement is activated. Reserves from othermembers come online to make up for the lost generation. This is a very short-termarrangement. Contingency reserve sharing covers such forced outages for up to onehour. After that, the utility must balance its load (firm sales plus operating reserves) byeither purchasing resources on the market or, if necessary, shedding load.4Colstrip capacity of 657 MW reflects the 677 MW of Net Maximum Capacity described in theExisting Resources section below, minus transmission line losses on BPA’s transmission system.5-5
CHAPTER 5 – ELECTRIC ANALYSISThe Federal Energy Regulatory Commission (FERC) is likely to approve a new ruling thatwill affect the amount of reserves we carry. Instead of 5 percent of hydro and wind and 7percent of thermal, Bal-002-WECC-1 would require us to carry 3 percent of generatingresources (hydro, wind and thermal) and 3 percent of load. Primarily, this affects dailyoperations in hours when we are relying more on market power purchases than PSEowned generation. The rule will increase peak hour capacity need in 2014 byapproximately 35 MW. NERC approved the standard on Nov 7, 2012; next, NERC will filefor final approval from FERC.5Balancing reserves. Utilities must also have sufficient reserves available tomaintain system reliability within the operating hour; this includes frequency support,managing load and variable resource forecast error, and actual load and generationdeviations. Balancing reserves do not provide the same kind of short-term, forced-outagereliability benefit as contingency reserves, which are triggered only when certain criteriaare met; balancing reserves must be able to ramp up and down as loads and resourcesfluctuate instantaneously each hour. For a more detailed explanation, see Appendix G,Operational Flexibility.For PSE, the amount of balancing reserves is 123 MW. This amount is based on a 95percent confidence interval, or the amount of reserves that would capture 95 percent ofthe within-hour load and resource deviations. This confidence interval is derived fromhistorical data during the months of December and January, coinciding with the periodused for PSE’s winter-peak planning. 123 MW reflects an increase from the 35 MW usedin prior IRPs, which was also termed ”regulating reserves.” This was the amounthistorically needed for PSE to meet its Control Performance Standard 2, a NERCreliability metric that measures a utility’s Area Control Error every 10 minutes. While thisamount is adequate for balancing the system over 10 minute periods, it is inadequate forbalancing the system over the entire operating hour. For more information, see AppendixG, Operational Flexibility.5For more information,go to 3/default.aspx.5-6
CHAPTER 5 – ELECTRICAL ANALYSISEnergy needMeeting customers’ “energy need” is more of a financial concept that involves minimizingcost rather than a physical planning constraint for PSE. Portfolios are required to coverthe amount of energy needed to meet physical loads, but our models also examine howto do this most economically. We do not have to constrain (or force) the model todispatch resources that are not economical; if it is cheaper to buy power than dispatch agenerator, PSE will choose to buy. Similarly, if a zero (or negative) marginal costresource like wind is available, PSE will displace higher-cost market purchases and usethe wind to meet the “energy need.” Figure 5-4, below, illustrates the company’s energyposition into the future, based on the energy load forecasts and economic dispatched ofthe Base Scenario presented in Chapter 4, Key Assumptions.Figure 5-4Annual Energy Position for 2013 IRP Base Scenario450040003500aMW300025001030 aMW689 aMW753 aMW1785 aMW20001500100050002014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033ColstripContractsWind2013 IRP Demand Forecast less 2013 Base IRPDSR5-7Natural Gas - Economic DispatchHydro2013 IRP Demand Forecast
CHAPTER 5 – ELECTRIC ANALYSISRenewable resourcesWashington state’s renewable portfolio standard (RPS) requires PSE to meet specificpercentages of our load with renewable resources or renewable energy credits (RECs)by specific dates. The main provisions of the statute (RCW 19.285) are summarizedbelow.For all practical purposes, wind remains themain resource available to fulfill RPSrequirements for PSE. Existing hydroelectricWashingt on St at eRPS T arge t sresources may not be counted towards RPSgoals except under certain circumstances for3% of supply-side resources by 2012new run of river and efficiency upgrades, and9% of supply-side resources by 2016other renewable technologies are not yet15% of supply-side resources by 2020capable of producing power on a largeenough scale to make substantialcontributions to meeting the targets.Renewable resources influence supply-side resourcedecisions.Adding wind to the portfolio increases the need for stand-by back-up generation that canbe turned on and off or adjusted up or down quickly. The amount of electricity supplied tothe system by wind drops off when the wind stops, but customer need does not. As theamount of wind in the portfolio increases, so does the need for reliable back-upgeneration. Appendix G, Operational Flexibility, discusses PSE wind integrationchallenges in more detail.Demand-side achievements affect renewable amounts.Washington’s renewable portfolio standard calculates the required amount of renewableresources as a percentage of kWh sales; therefore, if the kWh decreases, so does theamount of renewables we need to plan for. Achieving demand-side resources (DSR) hasprecisely this effect: DSR decreases sales volumes, and therefore the amount ofrenewables needed.5-8
CHAPTER 5 – ELECTRICAL ANALYSISREC banking provisionWashington’s renewable portfolio standard allows for REC banking. Unused RECs canbe banked forward one year or can be borrowed from one year in the future. In this IRP,PSE assumes that the company would employ a REC banking strategy that would pushthe need for additional RECs further into the future.Figure 5-5 illustrates the need for renewable energy after accounting for REC bankingand the savings from demand-side resources that were found cost effective for the 2013IRP.Figure 5-5RPS Need Based on Achievement of All Cost-effective DSR5,0004,500Minimum amounts of produced and banked RECsHydroRECNeed:2013 IRP Base Demand less Base DSRREC Need: 2013 IRP Base Demand Forecast4,0003,5001626RECs '0003,0006942,5002,0001,5001,0005002012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 20335-9
CHAPTER 5 – ELECTRIC ANALYSIS2. Existing ResourcesResources are divided into two categories, depending on where they originate. Supplyside resources generally originate on the company side of the meter, while demand-sideresources (DSR) generally originate on the customer side of the meter.With supply-side resources, power is generated by means of water, natural gas, coal,wind, etc., and then transmitted (or “supplied”) to customers.Demand-side resources include energy efficiency measures, demand-response, andother techniques that reduce the amount of power customers need (or “demand”) in orderto operate their homes and businesses.Existing supply-side resourcesTo build the portfolios for the IRP analysis, we begin with a snapshot of PSE’s existingresources. The map and tables that follow summarize PSE’s existing resources and theirexpiration dates as of March 2013. The location of PSE’s existing supply-side generationresources is pictured in Figure 5-6.5 - 10
CHAPTER 5 – ELECTRICAL ANALYSISFigure 5-6Location of Supply-side ResourcesPSE’s supply-side resources are diversified geographically and by fuel type. Most of the company’sgas-fueled resources are in western Washington. The major hydroelectric contracted resources arein central Washington, outside PSE’s service area. Wind facilities are located in central andeastern Washington. Coal-fired generation is located in eastern Montana.Resource capacity note. The following tables represent the capacity value ofresources in terms of Net Maximum Capacity in megawatts. The Net Maximum Capacityis different than the winter peak capacity used for the IRP peak capacity need. This isconsistent with the descriptions contained in the company’s10K (which is filed with theU.S. Securities and Exchange Commission) and FERC Form 1. Net Maximum Capacityis the capacity a unit can sustain over a specified period of time – in this case 60 minutes– when not restricted by ambient conditions or deratings, less the losses associated withauxiliary loads.5 - 11
CHAPTER 5 – ELECTRIC ANALYSISYou may notice that PSE sometimes references different capacity values in differentpublications for the same plant. This is because plant output can vary for many reasons,among them ambient temperature, fuel supply, whether a natural gas plant is using ductfiring, whether a combined-cycle facility is delivering steam to a steam host, outages,upgrades and expansions, just to name a few. When talking about the relative size ofresources, it is often necessary to select a single reference point based on a consistentset of assumptions. Depending on the nature and timing of the discussion, theseassumptions – and thus the capacity – may vary.Hydroelectric resourcesFigure 5-7Hydroelectric ResourcesPSESHARE %NET MAXIMUMCAPACITY (MW)1CONTRACTEXPIRATION s Co. PUDChelan Co. PUDChelan Co. PUDGrant Co. PUDGrant Co. 9965PLANTOWNERUpper Baker RiverLower Baker RiverSnoqualmie FallsElectronTotal PSE-OwnedWellsRocky ReachRock Island I & IIWanapumPriest RapidsMid-Columbia TotalTotal Hydro3/31/1810/31/3110/31/3104/04/5204/04/52NOTES1 Net maximum capacity reflects PSE's share only.2 Snoqualmie Falls is running at partial capacity while powerhouse 1 is offline for redevelopment. The plant is expected tobe fully operational and provide a net maximum capacity of approximately 54 MW upon completion of powerhouse 1, whichexpected in the second quarter of 2013.3 As of December 31, 2012, Electron project output is limited to approximately 7 MW due to the condition of the flume thatconveys water to the plant. This limitation is expected into 2013.4 Based on Grant Co. PUD current load forecast for 2012; our share will be reduced to this level in 2013.5 Individual resource and Mid-Columbia totals are rounded to the nearest megawatt.5 - 12
CHAPTER 5 – ELECTRICAL ANALYSISCoal, natural gas, and wind resourcesFigure 5-8Coal, Combined-cycle Combustion Turbines, Simple-cycle Combustion Turbines, andWind ResourcesColstrip 1 & 2PSEOWNERSHIP50%NET MAXIMUMCAPACITY (MW)1307Colstrip 3 & 425%370POWER TYPEUNITSCoalCoalTotal 5%136CCCTFredericksonCCCTGoldendale100%278CCCTMint Farm100%297CCCTSumas100%127Total CCCT1,256SCCTFredonia 1 & 2100%207SCCTFredonia 3 & 4100%107SCCTWhitehorn 2 & 3100%149SCCTFrederickson 1 & 2100%149Total SCCT612WindHopkins Ridge100%157WindLower Snake River, Phase 1100%343WindWild Horse100%273Total Wind773NOTES1 Net maximum capacity reflects PSE's share only.2 Frederickson 1 CCCT unit is co-owned with Atlantic Power Corporation - USA.5 - 13
CHAPTER 5 – ELECTRIC ANALYSISLong-term contractsLong-term contracts consist of agreements with independent producers and other utilitiesto supply electricity to PSE. Fuel sources include hydro, gas, waste products, and systemdeliveries without a designated supply resource. These contracts are summarized below.Short-term contracts negotiated by PSE’s energy trading group are not included in thislisting.Figure 5-9Long-term Contracts for Electric Power MW)1BPA- WNP-3 ngoing8BPA Baker ReplacementHydro9/5/20297ThermalOngoing300Canadian EAHydro09/15/2024- 40.5Barclays BankSystem02/28/201575Transition Coal12/31/20251802Klamath TollNatural Gas2/29/2016100Klondike IIIWind11/31/202650Twin FallsHydro-QF3/8/202520Koma KulshanHydro-QF3/31/203710.9Weeks FallsHydro-QF12/31/20224.6Hutchison CreekHydro-QF9/30/20161.0Cascade Clean Energy- SygitowiczHydro-QF2/21/2014 1Biogas12/11/2013 1Farm Power LyndenSchedule 91 - Biogas12/31/2019 1Farm Power RexvilleSchedule 91 - Biogas12/31/2019 1Rainier BiogasSchedule 91 – Biogas12/31/20201.0Vanderhaak DairySchedule 91 – Biogas12/31/2019 1Van DykSchedule 91 – Biogas12/31/2020 1Bio EnergySchedule 91 - Biogas12/31/20214.88Edaleen DairySchedule 91 – Biogas12/31/2021 1Bio fuels, WASchedule 91 – Biogas12/31/20214.5PG&E Seasonal Exchange-PSECentralia Transition CoalQualco Dairy5 - 14
CHAPTER 5 – ELECTRICAL ookumchuckSchedule 91 – Hydro12/31/20201Smith CreekSchedule 91 – Hydro12/31/2020 1Black CreekSchedule 91 – Hydro3/24/20214.2Nooksack HydroSchedule 91 – Hydro12/31/20213.5Island SolarSchedule 91 – Solar12/31/2021 1Finn Hill Solar (Lake Wash SD)Schedule 91 – Solar12/31/2021 1Knudson WindSchedule 91 – Wind12/31/2019 13 Bar-G WindSchedule 91 – Wind12/31/20191.395Swauk WindSchedule 91 – Wind12/31/20214.25NAMETotal828Notes1 Capacity reflects PSE share only.2 The capacity of the TransAlta Centralia PPA is designed to ramp up over time to help meet PSE's resource needs.According to the contract, PSE will receive 180 MW from 12/1/2014 to 11/30/2015, 280 MW from 12/1/2015 to 11/30/2016,380 MW from 12/1/2016 to 12/31/2024, and 300 MW from 1/1/2025 to 12/31/2025.Existing transmission resourcesTransmission capacity to the Mid-Columbia (Mid-C) market hub gives PSE access to themost liquid principal market hub in the Northwest and one of the major trading hubs in theWECC. It is the central market for northwest hydroelectric generation. As shown earlier inFigure 5-1, Mid-C transmission access to market is a significant portion of PSE’s peaksupply portfolio. The majority of this transmission is contracted from BPA on a long-termbasis. PSE owns 450 MW of capacity to Mid-C. PSE’s transmission contracts with BPAand owned capacity are shown in Figure 5-10 below.5 - 15
CHAPTER 5 – ELECTRIC ANALYSISFigure 5-10Transmission Resources as of 12/31/12NAMEBPA Mid-C TransmissionMidwayMidwayMidwayMidwayRock IslandRocky ReachRocky ReachRocky ReachRocky ReachRocky ReachRocky ReachRocky ReachRocky tageVantageWellsNWE Purchase IR ConversionSpokane Municipal WasteTotal BPA Mid-C TransmissionPSE Owned Mid-C TransmissionMcKenzie to BeverlyRocky Reach to White RiverTotal PSE Mid-C 0Total Mid-C Transmission2488Notes:1.The capacity of this contract decreases from 235 to 209 MW upon expiration of the existing contract as of 12/1/2014.5 - 16
CHAPTER 5 – ELECTRICAL ANALYSISAs shown, PSE has 2,038 MW of BPA transmission capacity and owns 450 MW ofcapacity for a total of 2,488 MW. The capacities and contract periods for the various BPAcontracts are also shown in Figure 5-11.PSE’s Mid-C peak transmission capacities are included in Figure 5-1, Electric Peak Need.The specific allocation of that capacity as of December 2014 is listed in Figure 5-11.Figure 5-11PSE Mid-C Transmission Capacity as of December 2014Total Mid-C Transmission2462Allocated to Long-term Resources & Contracts(844)Available for hedging and short-term market purchases1618As of December 2014, PSE will have 2,462 MW of Mid-C transmission. A portion of thecapacity, 844 MW, is allocated to long-term contracts and existing resources such asPSE’s portion of the Mid-C hydro projects. This leaves 1,618 MW of capacity available forshort-term market purchases.Existing demand-side resourcesWhile DSR includes demand-response, fuel conversion, distributed generation,distribution efficiency, and generation efficiency, energy efficiency measures are by farthe most substantial contributor to meeting resource need. During the 2010-2011 tariffperiod, the 72.7 aMW contributed by these programs amounted to enough energy topower approximately 55,000 homes. Since 1978, annual first-year savings (as reported atthe customer meter) have increased more than 300 percent, from 9 aMW in 1978 to 39.1aMW in 2011. The cumulative investment and savings from 1978 through 2011 are over 800 million and 490 aMW respectively. Figure 5-12 shows the cumulative savings from1978 through 2011. This represents more than the annual output from PSE’s share ofColstrip 1 & 2, and is equivalent to the electricity used by about 372,000 homes for a year.As with supply-side resources, PSE evaluates energy efficiency programs for costeffectiveness and suitability within a lowest reasonable cost strategy.5 - 17
CHAPTER 5 – ELECTRIC ANALYSISFigure 5-12Cumulative Electric Energy Savings from DSR, 1978 to 2011600500Note: Annual savings added in anygiven year are only counted overthe average life of those 9201020110Our energy efficiency programs serve all types of customers – residential, low-income,commercial, and industrial. Energy savings targets and the programs to achieve thosetargets are established every two years. The 2010-2011 biennial program periodconcluded at the end of 2011; current programs operate January 1, 2012 throughDecember 31, 2013. The majority of electric energy efficiency programs are funded usingelectric “rider” funds collected from all customers.6For the 2012-2013 period, a two-year target of approximately 76 aMW in energy savingswas adopted. This goal was based on extensive analysis of savings potentials anddeveloped in collaboration with key external stakeholders represented by theConservation Resource Advisory Group (CRAG) and Integrated Resource Plan AdvisoryGroup (IRPAG).6See Electric Rate Schedule 120 for more information.5 - 18
CHAPTER 5 – ELECTRICAL ANALYSISCurrent electric energy efficiency programsThe two largest programs offered by PSE to customers are the Commercial andIndustrial Retrofit Program and the residential Energy Efficient Lighting Programs.The Commercial and Industrial Retrofit Program offers expert assistance and grants tohelp existing commercial and industrial customers use electricity and natural gas moreefficiently via cost-effective and energy efficient equipment, designs, and operations. Thisprogram gave out grants totaling more than 13.6 million to over 830 business customersin 2012 to achieve a savings of over 70,000 MWh.The Energy Efficient Lighting Programs offer instant rebates for residential customersand builders who purchase Energy Star fixtures and compact fluorescent light bulbs. Thisprogram provided incentives totaling more than 6 million, which resulted in theinstallation of over 3.5 million CFL lamps and fixtures in 2011 to achieve savings of over86,000 MWh.Figure 5-13Annual Energy Efficiency Program Summary, 2010-2013(Dollars in millions, except MWh)ProgramElectricProgram CostsMegawattHour Savings’10-’112010 - udget% ctualvs.‘12-13% Total 153 16792.0% 92 19348%636,000622,000102%339,500666,00051%Figure 5-13 shows program performance compared to two-year budget and savingsgoals for the biennial 2010-2011 electric energy efficiency programs, and records 2012progress against 2012-2013 budget and savings goals.During 2010-2011, electric energy efficiency programs saved a total of 77 aMW ofelectricity at a cost of 153 million. The company surpassed two-year savings goals whileoperating at a cost that was under budget. In 2012, these programs saved 39 aMW ofelectricity at a cost of 92 million. The average cost for acquiring energy efficiency in2010-2011 was approximately 240 per MWh, compared to a budgeted cost ofapproximately 290 per MWh in the 2012-2013 program cycle.5 - 19
CHAPTER 5 – ELECTRIC ANALYSISDistribution efficiencyThis energy efficiency measure consists of conservation voltage reduction (CVR)accompanied by load
Washington state depend on PSE for safe, reliable, and affordable electric services. The IRP analysis described in this chapter enables PSE to develop valuable foresight about how resource decisions may unfold over the next 20 years in conditions that
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USC at Ohio State LAST WEEK’S RESULTS Boise State 19, Oregon 8 LSU at Washington Stanford 39, Washington State 13 Arizona 19, Central Michigan 6 Arizona State 50, Idaho State 3 California 52, Maryland 13 Oregon State 34, Portland State 7 UCLA 33, San Diego State 14 USC 56, San Jose State 3 WASHINGTON vs. IdAHO
