2017 Pacific Northwest Power Supply Adequacy Assessment ...



2017 Pacific Northwest Power Supply Adequacy Assessment and State of the System ReportDRAFT – Version 44205501-5186151/3/20132017 Pacific Northwest Power Supply Adequacy Assessment andState of the System ReportContents TOC \o "1-3" \h \z \u Executive Summary PAGEREF _Toc344962954 \h 3Summary PAGEREF _Toc344962955 \h 4Pacific NW Resource Adequacy Standard PAGEREF _Toc344962956 \h 8Previous Assessments PAGEREF _Toc344962957 \h 92017 Resource Adequacy Assessment PAGEREF _Toc344962958 \h 9Other Adequacy Metrics PAGEREF _Toc344962959 \h 12Dealing with Uncertainties PAGEREF _Toc344962960 \h 12Reliance on Market Supply PAGEREF _Toc344962961 \h 14Generating Resources Dispatch PAGEREF _Toc344962962 \h 16Curtailment Statistics PAGEREF _Toc344962963 \h 19Appendix A – Assumptions PAGEREF _Toc344962964 \h 29Appendix B – 2017 Resources and Loads PAGEREF _Toc344962965 \h 32Appendix C – Assuring Adequacy for a Resource Plan PAGEREF _Toc344962966 \h 46Executive SummaryIn 2010, as a part of its Sixth Power Plan, the Northwest Power and Conservation Council reported that the region’s power supply was on the cusp of becoming inadequate by 2015. Based on an assessment prepared by the Resource Adequacy Forum, the plan noted that relying only on existing resources and targeted energy efficiency savings would result in a 5 percent likelihood of a shortfall, which is right at the limit the Council adopted in 2008. This result is consistent with the plan’s finding that energy efficiency could meet most but not all forecasted load growth.In this updated assessment, the forum concludes that the likelihood of a shortfall in 2017 has increased to 6.6 percent. This means that the region will have to acquire additional resources in order to maintain an adequate power supply, a finding that supports acquisition actions currently being taken by regional utilities.Between 2015 and 2017, regional electricity demands, net of planned energy efficiency savings, are expected to grow by about 300 average megawatts. Since the last assessment, 114 megawatts of new thermal capacity, about 1,200 megawatts of new wind capacity and about 250 megawatts of small hydro and hydro upgrades have been added to the analysis. Also, a Northwest utility has contracted to purchase 380 megawatts of capacity from an independent power producer, which shifts this in-region generation from the market supply to firm resource status. Meanwhile, availability of the winter California market is assumed to decrease from 3,200 to 1,700 megawatts, mainly due to the retirement of coastal water-cooled thermal power plants.The majority of potential future problems are short-term capacity shortfalls. The most critical months are January and February and, to a lesser extent, August. This is a different result from the 2015 assessment, which indicated that August was the most critical month. The major reason for this shift is the use of an updated streamflow record, which contains 10 more years of historical flows, new irrigation withdrawal amounts and various updates to reservoir operations both in the U.S. and Canada. The net result yields a higher average streamflow in August, thus improving summer adequacy. The forum analyzed two different approaches to lowering the likelihood of a shortfall in 2017 back down to the 5 percent limit. Results show that adding 350 megawatts of additional dispatchable generation capacity or lowering the 2017 annual load by 300 average megawatts would bring the likelihood of a shortfall back down to the 5 percent limit. Demand response may also be a viable option but was not analyzed. It should be noted that this assessment is not a substitute for a comprehensive resource acquisition plan. The optimal amount and mix of new resources needed to provide an adequate, efficient, economic and reliable regional power system is determined by the Council’s power plan. This assessment also does not fully reflect constraints and needs of individual utilities within the region. Thus, these results should be viewed as a conservatively lower bound on regional needs for new resource capacity. SummaryThe Resource Adequacy Standard and What it Means In 2008, the Northwest Power and Conservation Council adopted a regional power supply adequacy standard to “provide an early warning should resource development fail to keep pace with demand growth.” The standard, developed by the Northwest Resource Adequacy Forum, deems the power supply to be inadequate should the likelihood of curtailment five years in the future be higher than 5 percent. The forum uses probabilistic analysis to assess that likelihood, most often referred to as the loss of load probability.The assessment only counts existing resources and those expected to be operational. It also includes targeted energy efficiency savings from the Council’s Sixth Power Plan. When the likelihood of curtailment exceeds the 5 percent limit, a separate analysis is made to quantify the minimum amount of new generation capacity or load reduction needed to bring the loss of load probability back down to 5 percent. 2017 Resource Adequacy AssessmentThe last official adequacy assessment was adopted as part of the Sixth power plan. That assessment indicated the region’s power supply for 2015 was on the cusp of becoming inadequate -- the implied loss of load probability was 5 percent. Between 2015 and 2017, the region’s electricity loads, net of planned energy efficiency savings, are expected to grow by about 300 average megawatts or about a 0.7 percent annual rate. Since the last assessment, 114 megawatts of new thermal capacity and about 1,200 megawatts of new wind capacity have been added along with about 250 megawatts of small hydro and hydro upgrades. The recent acquisition of 380 megawatts of a regional independent power resource has been included and the in-region market supply has correspondingly decreased. California is expected to retire a substantial amount of its coastal water-cooled thermal power plants. It is also uncertain whether two units at the San Onofre Nuclear Generating Station will be operational in 2017. As a result, the forum reduced its assumption for the availability of California winter on-peak market supply from 3,200 to 1,700 megawatts. Taking all of these changes into account, the expected loss of load probability for the 2017 power supply is 6.6 percent, indicating an inadequate supply if no additional resources are acquired. Types of potential problems the region could face range from energy shortfalls that could last for several days to peak curtailments that last several hours. Results show that the majority of simulated shortfalls are four hours or less in duration and over 40 percent are two hours or less. To minimize cost and risk, new resource additions should be tailored to specifically address the expected types of shortfalls, that is, peak-hour shortages. This suggests that capacity resources such as simple-cycle combustion turbines or demand response programs or winter-peaking energy efficiency measures should be considered. It should be noted again, however, that the scope of this assessment is only to provide a gauge of the relative adequacy of the power supply. The determination of the quantity and mix of new resource capacity needed make the power supply adequate is left to more comprehensive integrated resource planning processes. With that being said, the forum analyzed two different approaches to lowering the likelihood of a shortfall in 2017 back down to the 5 percent limit. First it examined how much additional dispatchable generating capacity would be needed to reduce the likelihood to 5 percent and secondly, it examined how much of an annual load reduction would accomplish the same objective. The results show that adding 350 megawatts of new dispatchable generation capacity would lower the 6.6 percent likelihood down to 5 percent. The same level of adequacy can be achieved by lowering the 2017 annual load by 300 average megawatts. Demand response is another alternative but the forum did not examine how much would be needed. The findings for 2017 are consistent with assessments made by regional utilities indicating a need for new resources. It is also consistent with the plan, which concluded that energy efficiency alone will not be sufficient to offset all future load growth. In aggregate, utility planned resources far exceed the 350 megawatt gap. In the analysis for 2017, the most critical months are January and February and, to a lesser extent, August. This is a different result from the last official assessment, which indicated that August was the most critical month. The major reason for this shift is the use of an updated streamflow record. The new record contains;80 years of historical streamflow data (the old record had 70 years)New irrigation withdrawal amountsMore current Canadian system operation (both for treaty and non-treaty storage)Updated operating requirements at Grand CouleeMore accurate representation of the operation of Snake River Basin damsOther miscellaneous adjustments at various hydroelectric projects These changes, in aggregate, result in an overall shift in streamflows across the months of the year. In particular, the average August streamflow is expected to increase by about 10,000 cubic feet per second, which translates into about 650 megawatts of additional power for the regional system. Dependence on the MarketThe methodology used to assess the adequacy of the Northwest power supply assumes a certain amount of reliance on market power supplies, both from within the region and from California. A significant part of the Northwest market is made up of independent power producer resources. The full capability of these resources, about 3,450 megawatts, is assumed to be available for Northwest use during winter months. However, during summer months, due to competition with California utilities, the Northwest market availability for Northwest use is limited to 1,000 megawatts. The California market is broken into on-peak and off-peak availabilities. The off-peak availability is assumed to be 3,000 megawatts year round. Energy from the off-peak market is purchased during light-load hours prior to periods of potential shortfalls and is often referred to as a purchase-ahead resource. The on-peak availability is assumed to be 1,700 megawatts during winter and not available at all during summer. Northwest utilities routinely rely on market resources to maintain an adequate power supply. The amount of market resources used depends on a number of conditions, with the biggest factors being stream flow levels, outages of utility-owned resources, and temperature-driven load variations. For 2017, assuming only existing resources and targeted energy efficiency, the analysis shows the region would purchase an average of 1,170 megawatt-months of market supplied energy in December representing about 18 percent of the total available energy (6,450 megawatts-months). In August the region is would purchase an average of 400 megawatt-months of market supplied energy or approximately 10 percent of the total available energy (4,000 megawatts-months). However, averages can be misleading and a more important statistic is how much market supplied energy is needed during extreme events when the regional load-resource balance tightens. Ten percent of the time, market purchases would exceed 2,200 megawatt-months in December (34 percent of the total) and 820 megawatt-months in August (21 percent of the total). The full amount of market supplied energy would be needed in less than 1 percent of all hours. UncertaintiesThe forum’s analytical tools account for uncertainties in stream flows, wind generation, temperature-driven demand variations, and generating resource availability. However, there are additional uncertainties that are not explicitly modeled. Two of the more significant uncertainties are economic load growth and the availability of the California energy market. The expected 6.6 percent loss of load probability assumes the Council’s medium load forecast and 1,700 megawatts of expected California on-peak winter market supply. To investigate the potential impacts of different combinations of economic load growth and California market availability, scenario analyses were performed. In the worst case, with high load growth and no California market, the loss of load probability would be 16.8 percent. The good news is that this scenario is very unlikely. In the best case, with low load growth and 3,200 megawatts of California market, the loss of load probability drops to 2.8 percent, well within the Council’s limit. While the current assessment provides the best estimate for the probability of a power supply shortage, the loss of load probability could be larger or smaller depending on load and market conditions in 2017. And, because the uncertainty surrounding these particular variables is not well defined, it is difficult to develop a range of likely loss of load probability values. What is clear is that there is a relatively high chance that the region will need some level of new resource development by 2017 in order to maintain an adequate supply. Future AssessmentsThe Resource Adequacy Forum will continue to annually assess the adequacy of the power supply. However, this task is becoming more difficult because the power supply has become more complex in recent years. The increase in variable generation resources, combined with changing patterns for electricity demand, is forcing utility planners and operators to more carefully assess what resources are needed in reserve to ensure that demand can be met minute to minute. The current adequacy assessment incorporates a certain amount of minute-to-minute reserves, but it is not certain that they will be sufficient. Regional planners are evaluating various methods to quantify and plan for these flexibility needs. Another emerging concern is the lack of access for some utilities to market supplies due to insufficient transmission or other factors. For the current adequacy assessment, the Northwest region is split into two subsections and only the major East-West transmission lines are modeled. Similarly, only the major Canadian-US and Northwest-Southwest interties are modeled. It may be necessary to divide the Northwest region into more subsections to better address the effects of transmission congestion on power supply adequacy. Resource adequacy continues to be a concern in the Northwest. The forum’s results are consistent with regional utility integrated resource planning, which supports the need for additional capacity. The Council and forum will continue to improve methods used to assess the power supply adequacy. Pacific NW Resource Adequacy StandardIn December of 2011, the Northwest Power and Conservation Council adopted an adequacy standard for the regional power supply. The standard, recommended by the Resource Adequacy Forum, provides an early warning should resource development and efficiency savings fail to keep pace with demand growth. Power supply adequacy is assessed by using a probabilistic analysis to compute the likelihood of a supply shortfall five years into the future. The analysis is based on a chronological hourly simulation of the region’s power supply over many different future combinations of stream flows, temperatures, wind generation and forced generator outages. Only existing generating resources and those that are expected to be operational five years out are counted along with targeted energy efficiency savings. The simulation also assumes a conservative amount of market resource availability, both within and outside of the region. The power supply is deemed to be inadequate if the likelihood of a shortfall (referred to as the loss of load probability or LOLP) is greater than 5 percent. In such cases, the Forum also estimates how much new dispatchable resource generating capacity is required to bring the system’s LOLP back down to 5 percent. This standard, however, is not intended to provide a resource planning target because it assesses only one of the Council’s criteria for developing a power plan. The Council must develop a plan that provides an adequate, efficient, economic and reliable power supply. There is no guarantee that a power supply that satisfies the adequacy standard will also be the most economical or efficient. Thus, the adequacy standard should be thought of as simply an early warning to test for sufficient resource development. Use of Standby ResourcesStandby resources are demand-side actions and small generating machines that are not explicitly modeled in the adequacy analysis. They are mainly composed of demand response measures, load curtailment agreements and small thermal resources. Demand response measures, are expected to be used every year to help lower demand during peak hours of the day. These resources only have a capacity component and are not intended to provide extended energy relief. To the extent that these measures have been implemented, their contribution is already reflected in the Council’s load forecast. New demand response measures that have no operating history and are therefore not accounted for in the load forecast are classified as part of the set of standby resources. Load curtailment actions and small generating resources that are contractually available to utilities help reduce peak hour load and may also provide some energy assistance. However, they are not intended to be used often. The energy and capacity capabilities of these non-modeled resources are aggregated along with the demand response measures mentioned above to define the total capability of standby resources. A post-processing algorithm uses these capabilities to adjust the simulated curtailment record and calculate the final LOLP. Currently, the aggregate energy capability of standby resources, as we have defined them, is 83,000 megawatt-hours. The peaking capability of these resources varies by season, with a 660 megawatt capacity in winter and a 720 megawatt capacity in summer. Previous AssessmentsThe history of adequacy measures for the Pacific Northwest power supply dates back more than half a century. Although probabilistic methods to assess adequacy had been around for awhile, limited computer capability made it nearly impossible to use them. Thus, since about the turn of the century, deterministic measures were used. These measures simply counted up available resources and compared their aggregate energy availability to the forecasted energy load. The criterion for an adequate supply was (implied) that energy availability had to be greater than the expected annual energy demand. Because of the predominance of hydro power in the Northwest, the region was fuel short (energy) and machine rich (capacity) so the criterion focused only on energy. The annual energy and load assessments were published in the PNUCC Northwest Regional Forecast and in the BPA White Book. There were some key assumptions in that calculation that should be emphasized. The first is that the Northwest was assumed to be an island and thus, no out-of-region market supplies were counted. And, at the time, no in-region market resources existed. The second is that critical hydro generation was used to assess the hydroelectric system’s energy availability. Critical hydro generation is the amount of energy produced when the region’s lowest historical streamflows are combined with reservoir storage operations to shape hydro generation to monthly loads. This sequence of low water conditions is referred to as the “critical period.” Critical hydro generation was intended to represent the amount of “firm” or “guaranteed” hydro generation. Critical period streamflows were used to assess the amount of firm hydro generation because of limited reservoir storage in the Northwest, where the total useable storage is only about 15 percent of the average annual runoff volume of water. If reservoir storage were greater, say at least equal to the average runoff volume, then “average” hydro conditions could be used to assess firm hydro generation. But even early on it was generally accepted that the planning standard (energy availability must equal average load) was too conservative because Southwest market supplies are generally available during the Northwest’s peak winter season and the likelihood of a critical period repeat is very low (perhaps 1 or 2 percent). Building new resources to this strict standard would likely lead to a high cost power supply with thermal resources often being displaced by cheaper hydro generation. In order to reduce resource additions and keep costs down, an agreement was made between utilities and aluminum companies that made part of the aluminum load nonfirm in return for a cheaper rate. This effectively increased the amount of firm hydro generation. However, since then much of the aluminum load has gone away. Nonetheless, even without the aluminum industry’s nonfirm contracts, planners understand that building to meet a slight “firm” deficit (as defined above) is actually more cost effective than planning to meet a balanced system. The problem is that no one really knew at that time how much of a deficit to plan to, in other words, where to draw the line to differentiate between an adequate power supply from an inadequate one. This was exacerbated in 1998 when the anticipated balance for the following year was nearing a 4,000 average megawatt deficit. The BPA administrator appealed to the Council to develop a more precise measure of adequacy. This invigorated discussions of probabilistic measures and lead the Council to develop the GENESYS model, which has the capability of assessing the likelihood of potential future shortfalls. The first assessment, made for 2003, yielded a 24 percent loss of load probability -- much higher than the anticipated maximum of 5 percent. Then the 2001 energy crisis hit with a non-functioning California market and the second driest conditions on record. Table 1- Adequacy MilestonesYearMilestone1998Large load/resource balance deficit concern1999Ad-hoc committee recommends using LOLP, GENESYS created2000First assessment yields 24 percent LOLP -- much higher than 5 percent standard2001West Coast energy crisis2005Resource Adequacy Forum created2007Unofficial assessment for 2013 indicates an adequate supply2008Council adopts first adequacy standard, translates LOLP to deterministic measures2009-10Adequacy methodology is peer reviewed2010Council’s 6th plan implies a 5 percent LOLP for 20152011Council revises its adequacy standard, uses only LOLP2012Assessment for 2017 shows an inadequate supply with LOLP at 6.6 percentTable 1 illustrates the evolving nature of the effort to better quantify power supply adequacy. Over the seven years since the Adequacy Forum was established, the methodology and associated assumptions have changes significantly, making it difficult to compare annual assessments. And, while this evolution is likely to continue, the Forum now believes that the current standard and assumptions will be fairly stable. This year’s assessment for the 2017 operating year is the first assessment with the revised standard and assumptions from 2011. The Forum hopes that this year’s assessment along with future assessments will create a history of adequacy evaluations that can be used to record trends over time. 2017 Resource Adequacy Assessment In spite of the changing nature of adequacy assessments over this past decade, we can infer from studies done for the 2015 operating year that the power supply was estimated to be on the cusp of inadequacy. That assessment, reported in the Council’s 6th Power Plan, indicated that the summer sustained peak reserve margin was right at the limit set by the first standard adopted by the Council in 2008. That analysis implies that the LOLP for 2015 would have been right at 5 percent, which is the current standard’s threshold. Between 2015 and 2017, the region’s electricity loads, net of planned energy efficiency savings, are expected to grow by about 300 average megawatts or about a 0.7 percent annual rate. Since the last assessment, 114 megawatts of new thermal capacity and about 1,200 megawatts of new wind capacity have been added along with about 250 megawatts of small hydro and hydro upgrades. The recent acquisition of 380 megawatts of a regional independent power resource has been included and the in-region market supply has correspondingly decreased. California is expected to retire a substantial amount of its coastal water-cooled thermal power plants. It is also uncertain whether two units at the San Onofre Nuclear Generating Station will be operational in 2017. As a result, the forum reduced its assumption for the availability of California winter on-peak market supply from 3,200 to 1,700 megawatts. Taking all of these changes into account, the expected loss of load probability for the 2017 power supply is 6.6 percent, indicating an inadequate supply if no additional resources are acquired. Types of potential problems the region could face range from energy shortfalls that could last for several days to peak curtailments that last several hours. Results show that the majority of simulated shortfalls are four hours or less in duration and over 40 percent are two hours or less. The 6.6% LOLP value indicates that the power supply is inadequate, in other words, the likelihood of a serious shortfall is greater than the region’s tolerance for such events. This value is driven by single hour shortfalls in August. Assessing the LOLP based solely on energy results in a value of 1.4 percent. Figures 1 and 2 show the curtailment probability curves for total annual energy and single hour shortfalls. Figure 1 - Annual Curtailment Energy Probability CurveFigure 2 - Max Peak Curtailment Probability CurveFigure 3 - Monthly LOLPFigure 4 - Effect of New Hydro Record on Monthly LOLPOther Adequacy MetricsTable 2 - Adequacy Metric DefinitionsMetric DescriptionLOLP Loss of load probability = number of games with a problem divided by the total number of games (in percent)USRP Use of standby resource probability = Number of games that dispatch standby resources at least once divided by total games (in percent)CVaR (energy) Conditional value at risk, energy = average annual curtailment for 5% worst games (in megawatt-hours)CVaR (peak) Conditional value at risk, peak = average single-hour curtailment for worst 5% of games (in megawatts)EUE Expected unserved energy = total curtailment divided by the total number of games (in megawatt-hours)LOLH Loss of load hours = total number of hours of curtailment divided by total number of games (in hours)PGCPercent of games with curtailment = Use of Standby Resources (in percent)Table 3 - Adequacy Measures for 2017Adequacy MetricsMetricValueUnitsLOLP6.6PercentUse SR9.7PercentCVaR (energy) 99000MW-hoursCVaR (peak)4000MW EUE5000MW-hoursLOLH2.7Hours/year% Games w/Curt9.7PercentDealing with UncertaintiesFigure 5 - Load and SW Market Impacts to LOLPFigure 6 - Load and SW Market Uncertainty LOLP MapFigure 7 - Illustrative Example of LOLP Likelihood based on Load & Market UncertaintyReliance on Market SupplyThe current adequacy methodology assumes that all reasonably available resources will be dispatched to avoid shortfalls. In this sense, the analysis represents the likelihood that demand will be served, cost notwithstanding. It is not intended to be a resource needs assessment, when costs and other factors are considered. But for this analysis, non-firm resources are included. These resources include regional Independent Power Producer (IPP) generation, out-of-region markets (primarily from the Southwest) and the use of borrowed hydro, which is energy derived by using water below the drafting rights elevation. The general dispatch order for these resources is to first buy from IPPs, secondly to buy from out-of-region markets and lastly to use borrowed hydro energy. When borrowed hydro is used, it is replaced as quickly as possible, even if it means buying from out-of-region markets at a later time. Figure 3 below illustrates the expected likelihood of use for each of these three types of non-firm resources by month. It should be noted that the SW market on-peak purchases are limited to the winter months only. Also modeled, but still under debate, is the availability of light load hour purchases made in advance of potential peak hour problems. This purchase-ahead resource is limited to 1,000 megawatts in any light load hour and is called upon only when borrowed hydro is expected to be used during the next peak demand period. Figure 4 shows the average contribution from each resource by month. However, average values are not always very informative. Thus, Figures 5-8 provide the dispatch probability curves for these 4 non-firm resources. Figure 8 - Monthly Energy Market Purchase ProbabilityFigure 9 - Hourly Market Purchase Probability (All Hours) Figure 10 - Hourly Market Purchase Probability by MonthGenerating Resources DispatchTable 4 - Average Resource Dispatch by MonthOCTNOVDECJANFEBMARAPRMAYJUNJULAUGSEPAnnNuclear97310151022102410261027102400102310251024849Coal39983834376733263150284514494479312329372842172835Gas296415711589167414901062535401634921185525341436Wind1044107810611130115713691629155314801363121810361260Market66611941168120010287101932184147402550614Figure 11 - Wind Generation Probability by MonthFigure 12 - Gas-Fired Generation Dispatch Probability by MonthFigure 13 - Coal-Fired Generation Dispatch Probability by MonthFigure 14 - Nuclear Generation Dispatch Probability by MonthCurtailment Statistics Sometimes, simply looking at simulation results can provide insight into the behavior of the power system. Table 5 below summarizes a few statistics for the curtailment events reported in our analysis. It should be noted that this particular study was only run with 210 simulations and thus the statistics for curtailment events (as well as the adequacy measures) will have a larger error range. Besides looking at curtailment statistics, it may also be of great use to examine what conditions existed during the time of each shortfall. Thus, a record of all curtailment events along with the values for the four random variables used in the analysis will be provided in a separate spreadsheet (available on the Forum’s website). The four random variables displayed in the spreadsheet are;Water supply, as a percentage of monthly runoff volumeTemperature, as a percentage of that day’s historical temperature rangeWind generation, based on historical wind capacity factors from BPA’s wind fleetForced outage conditionsSome attempts have been made to correlate shortfall events with the occurrence of certain temperatures, water conditions, wind generation patterns and forced outages, but unfortunately without much success. This is an area of study that should be explored further. Table 5 – Curtailment StatisticsStatisticValueUnitsExp Events/year0.21?EventsAvg Event Duration13HoursAvg Event Magnitude24,361MW-hrsAvg Event Peak1,764MW Exp Curt Hrs/year2.7?HoursLOLP6.6%Figure 15 - Curtailment Event Duration ProbabilityFigure 16 - Curtailment Magnitude ProbabilityFigure 17 - Curtailment Magnitude Probability for Events Less than 4 HoursFigure 18 - Curtailment Event Magnitude vs. DurationTable 6 - Sample Curtailment Event RecordEventGameMonthDURMAGPeakHydro %Temp %Wind %FO %12Feb1254254398701622Feb21304652398701633Jan242221628843723443Jan74145122540137325353Jan395564937073765263Jan22285171637731173Jan2245015273830483Jan14034033832498Jan10273694637148517109Feb17697690471712119Feb3221813170482910129Feb215047890491110139Feb758741192059251416Jan6538955100921516Jan2314430955803371647Jan21188113549438151749Aug17463659923940151877Sep235118195714151980Oct155462216212080Jan26894552589342183Feb408566244434721422100Feb111111146430423100Feb22464147046431424100Feb23251202246434825100Feb273543946691826109Jan13535283116627129Jan2139410149664228129Jun53616102111731529144Aug7782125365161230146Feb140405763231146Feb288282157622332153Jun49764520342833154Jan4789309422262522434160Oct1280418564644152935163Feb273655445381536163Feb2214166241245351537163Feb2237516254648838163Feb33831200046411039163Aug62299468133921140163Aug124781574135331441164Jan1163464736087106515442164Jan20290323135107559443164Jan22331142710820244164Feb1258258115922EventGameMonthDURMAGPeakHydro %Temp %Wind %FO %45169Jan264478244680661346169Jan23456172806716247177Jan2424942289630628948177Jan7123297475003061281149177Feb72248783675032613450220Nov1702702459121051220Jan1300300118651052220Jan219171086118631053233Feb2443325108701054235Dec14848199214755252Oct122348245332912356252Oct17373332912257253Jan43239733021458253Jan3330517483324159253Jan2206912873370160254Feb5486704419247573361254Feb22251112647736262256Jan216611270563201163279Sep71837276621502264289Dec1253253112861165289Dec2201310061128331266300Feb11333133315763467300Feb442482355157620468300Feb27212752502157210269300Feb222541644157212170300Feb21900150415721171313Dec41787443842148781172313Dec296565514854873313Dec270361014900574313Dec23770203814900375313Dec21584132814820376313Dec138477249014820977313Dec160160114631978314Feb21587930730379323Jan5511744650003647480330Aug1320329226216981331Feb5412578754176573382333Jan31073533336737883353Dec649827763784353Dec22613277630785380Sep7224742643401986385Jan6825405187551554610Table 7 - Sample Energy Curtailment Distribution by MonthGameOctNovDecJanFebMarAprMayJunJulAugSepAnn Total1104810483336263336263824726247261625714257141710510557620962097344444482166491664910040844084129172117211431295129514632232215472415724151591666116661160415041501633873871643919375494397432169241795241795173952095201761192111921177164589317574482163233428142812341193119325379399479684194254932099320928929529530047986479863144647464731610127101273232142202142203311613121613123333693693852547092547093935081508139584184140816235631958616748210941314514541718242818242845148954895465225029225029484295395952954904851017101749426312263125011012010120GameOctNovDecJanFebMarAprMayJunJulAugSepAnn Total52951675167539488754887554548613486135543652365255558395839562171748244300416049564656296562957126697266975775695696028528526201037103762450266502666254086408663411571157639115599115599644217217648918259182570193484934847151737717377716302432302432729849108491078060342603427852700542700547933811313564799932537579511091109797746474648021486851486858161876818218950817835128351285221466214668574744748702891528915875622512241184668839157915788983838914504508937437743790533663366929293002930094615108151089471636916369Table 8 - Sample Peak Hour Curtailment Distribution by MonthGameOctNovDecJanFebMarAprMayJunJulAugSepMax1579579370537053840934093163505350517105105577737737332832882276327631001593159312999999914354754714632232215443554355159637637160170017001633873871646362207863621695417541717390390317620872087177584885428542233420420234185185253351133435112544382438228929529530028152815314124212423162861286132355275527331535753573331061063858956895639334923492395417417408507282362982364131451454176522652245131931946566976697484506295506248575175149425302530GameOctNovDecJanFebMarAprMayJunJulAugSepMax50170470452988088053936573657545464246425543353355551026102656254915793579356432083208571270227025771181186025055056201037103762444294429625121812186342022026394862486264421721764851185118701586258627151292129271677277727729616161617804528452878555875587793150877435277743795929279775675680257535753816277461277481736323632852340034008572372378702857285787513819431381883409440948898383891888889317111711905666666929304430449462213221394721792179Appendix A – Assumptions2017 Pacific Northwest Resource Adequacy AssessmentStudy ParametersMain ParametersOperating Year:October 2016 through September 2017Simulation Mode:Each hour of the yearRandom Variable SettingsNumber of games:6,160Water year selection:Sequential (because Canadian operation is fixed)Water years selected:80 years, 1929 through 2008Temperature year selection:RandomTemperature years selected:77 years, 1929 through 2005 (to match wind year data)Wind year selection:Lockstep with temperatureWind years selected:77-year temperature correlated synthetic set Stochastic forced outage:YesMarket and Wind AssumptionsNameplate wind capacity:4,579 MWNW Market winter:Full IPP = 3,451 MWNW Market summer:1,000 MWSW Market on-peak winter:1,700 MWSW Market off-peak winter:3,000 MW (purchase ahead)SW Market on-peak summer:0 MWSW Market off-peak summer:3,000 MW (purchase ahead)Maximum import limit:3,200 MWResource AssumptionsColumbia Generating Station:On maintenance May and JuneHydro INC/DEC requirements:900/1,100 MW (4K wind Peak vs. Energy file)Thermal seasonal capacity:Off (not sufficient data)Thermal ramp rates:Not yet implementedCoal day-must-run:On (if coal dispatched, must run at least one day)Forced outages:Stochastic for each plant (if on FOR, plant is out)Maintenance:Each plant derated for aggregate thermal maintenance rate (Same method and data used in AURORAxmp)Borrowed Hydro:1,000 MW-months maximum(Hydro energy below drafting-rights elevation)Operating reserves thermal:7 percentOperating reserves hydro:5 percentLoad AssumptionsHourly loads:Council’s Short-Term Model (econometric)77 load years based on temps from 1929-2005Conservation:6th Power Plan target level, included in the hourly loadsPumping loads:Included in the hourly loadsTransmission losses:Included in the hourly loadsStandby Resource AssumptionsAppendix B – 2017 Resources and LoadsTable 9 - Northwest Resources including NW Market Resources NameTypeNWFORIPP1910 Meyers FallsHyd00Alden Bailey (Wauna Peaking/Loki)GT110.051Amalgamated Sugar (TASCO) (Nampa) 1 - 3Coal00.07Amalgamated Sugar (TASCO) (Twin Falls) 1-3Coal00.07Amy RanchHyd10Barber DamHyd30Basin Creek 1 - 9IC170.047Beaver 1 - 7CCCT5090.059Beaver 8GT200.051Bennett MountainGT1800.051Bettencourt B6 Dairy (Cargill)IC20.047Bettencourt Dry Creek Biofactory (Cargill)IC20.047Big Hanaford CC 1A-1ECCCT00.059248Big Sheep CreekHyd20Big Sky West Dairy DigesterIC10.047Biomass One 1 & 2STCG250.07Birch CreekHyd10Black CreekHyd40Black Eagle 1 - 3Hyd00Blind CanyonHyd00BoardmanCoal4350.067Boise 1 & 2 (Medford)Biomass ST90.07Boulder Park 1-6IC250.047Boundary GTIC10.047Box CanyonHyd00Box Canyon 1 & 2Hyd30Briggs CreekHyd10Broadwater Toston DamHyd10Bull Run No. 1 (Portland Hydro)Hyd180Bull Run No. 2 (Portland Hydro)Hyd00BypassHyd40Cedar Draw Creek (Crystal Springs)Hyd10Central Oregon SiphonHyd00Centralia 1IPPCoal00.067290Centralia 1PSECoal3800.067?Centralia 2Coal00.067670Chehalis Generating FacilityCCCT5140.059Chester DiversionHyd30City of Albany (Vine Street WTP)Hyd10Clearwater Hatchery (Dworshak)Hyd30NameTypeNWFORIPPClearwater Paper 1 - 4STCG750.07Cochrane 1 & 2Hyd00Coffin Butte 1 - 5IC60.047Cogen II (D.R. Johnson) 1 & 2STCG80.07Colstrip 1Coal1540.067Colstrip 2Coal1540.067Colstrip 3Coal5180.067Colstrip 4Coal6810.067Columbia Blvd Wastewater Treatment PlantIC20.047Columbia Generating StationNuclear11300.0885Columbia Ridge LandfillIC120.047Colville Indian Power & Veneer 1 & 2STCG10.07COPCO 1 (1 & 2)Hyd240COPCO 2 (1 & 2)Hyd320Corrette (J.E. Corette)Coal00.067Covanta MarionMSW130.07Cowiche Hydroelectric ProjectHyd00Coyote Springs 1CCCT2590.059Coyote Springs 2CCCT3010.059Crystal MountainIC30.047Danskin (Evander Andrews) CT1GT1830.051Danskin (Evander Andrews) CT2 (ex. Danskin 1)GT470.051Danskin (Evander Andrews) CT3 (ex. Danskin 2)GT470.051Deep CreekHyd00DeRuyter DairyIC10.047Dietrich DropHyd20Don Plant (Simplot Pocatello)STCG80.07Double A DairyIC10.047Douglas County Forest ProductsSTCG30.07Dry CreekHyd00Dry Creek LandfillIC20.047Elk Creek (El Dorado Hydro Elk Creek)Hyd00Eltopia Branch Canal 4.6Hyd00Encogen 1-4CCCT1790.059Evergreen Forest Products (Tamarack)STCG40.07Fall Creek 1 - 3Hyd20Falls RiverHyd40Falls CreekHyd10Farm Power LyndenIC10.047Farm Power RexvilleIC10.047Farmers Irr. Dist. No. 2 (Copper Dam)Hyd50Farmers Irr. Dist. No. 3 (Peters Drive)Hyd00FaulknerHyd00Finley Buttes Regional LandfillIC30.047Flathead County LandfillIC20.047NameTypeNWFORIPPFordHyd00FortixIC10.047Frederickson 1GT800.051Frederickson 2GT800.051Frederickson Power 1CCCT2800.059Fredonia 1GT1110.051Fredonia 2GT1110.051Fredonia 3GTAero590.051Fredonia 4GTAero590.051Freres Lumber (Evergreen Andrews Power Complex)STCG100.07GalesvilleHyd00Geo-Bon No. 2Hyd00Georgia-Pacific (Camas)STCG520.07Georgia-Pacific (Wauna)STCG320.07Glenns Ferry CogenerationCCCT100.059Goldendale CC 1A & 1BCCCT2890.059Grant Village 1 & 2IC10.047Grays Harbor Energy Facility (Satsop)CCCT00.059650Ground Water Pumping StationHyd50H.W. Hill (Roosevelt Biogas) 1 - 5IC110.047Hampton LumberSTCG40.07Hardin Generating StationCoal00.067109Hauser 1 - 6Hyd00Hazelton AHyd30Hazelton BHyd30Hermiston Generating Project CC 1A & 1BCCCT2360.059Hermiston Generating Project CC 2A & 2BCCCT2360.059Hermiston Power ProjectCCCT00.059630Hidden HollowHyd30Holter 1 - 4Hyd00Horseshoe Bend HydroelectricHyd40Ingram Warm Springs Ranch AHyd00Ingram Warm Springs Ranch BHyd00International Paper (Springfield) 4STCG220.07Iron GateHyd180Jim Bridger 1Coal5300.067Jim Bridger 2Coal5300.067Jim Bridger 3Coal5300.067Jim Bridger 4Coal5300.067Jim Ford Creek 1-3 (Ford Hydro LP)Hyd10John Day Creek (Cereghino)Hyd00Juniper RidgeHyd30Kasel-WitherspoonHyd00Kettle Falls Generating StationBiomass ST470.07Kettle Falls GTGT110.051NameTypeNWFORIPPKlamath Cogeneration ProjectCCCT00.059484Klamath Generation Peakers 1 & 2GTAero00.05150Klamath Generation Peakers 3 & 4GTAero00.05150Koma KulshanHyd120Koyle Ranch 1-3Hyd00LacombHyd00LakeIC00.047Lake OswegoHyd10Lancaster (Rathdrum Generating Station)CCCT2790.059Langley GulchCCCT3000.059Lateral No. 10Hyd10Lilliwaup Falls 1 - 7Hyd00Little Mac (Cedar Draw)Hyd20Little Wood ReservoirHyd00Little Wood River RanchHyd00LM Angus RanchHyd00Low Line Canal Drop (South Forks Hydro)Hyd50Low Line MidwayHyd10Lower Low Line (aka Low Line Rapids)Hyd20LQ-LS DrainsHyd20Lucky Peak 1 - 3Hyd00MacClarenIC10.047Madison 1 - 4Hyd00Magic DamHyd00Main Canal HeadworksHyd00March Point 1 - 4CCCT1450.059Marion InvestmentHyd00Marsh ValleyHyd00Metro West Point Treatment Plant 1 - 3IC50.047Meyers FallsHyd10Middle Fork Irrigation District 1Hyd30Middle Fork Irrigation District 2Hyd00Middle Fork Irrigation District 3Hyd00Mile 28 (1 & 2)Hyd10Mill Creek (Cove) 1 & 2Hyd00Mill Creek/Dave Gates Generating StationIC470.047Mink CreekHyd00Mint FarmCCCT3010.059Mirror Lake (Hutchinson Creek)Hyd10Mitchell ButteHyd00Montana One (Colstrip Energy)Coal50.067Mora Canal DropHyd20Morony 1 & 2Hyd00Morrow PowerGTAero00.05125Mystic 1 & 2Hyd00NameTypeNWFORIPPN-32 (Northside Canal)Hyd00Nichols GapHyd00North Fork Sprague RiverHyd00North Valmy 1Coal1270.067North Valmy 2Coal1340.067Northeast 1GTAero330.051Northeast 2GTAero330.051Old Faithful 1 & 2IC10.047Olympic View 1 & 2IC60.047Opal SpringsHyd30Orchard Avenue 1 & 2Hyd00Owyhee DamHyd00Owyhee Tunnel No. 1Hyd30Pasco (Franklin/Grays) GT 1GT110.051Pasco (Franklin/Grays) GT 2GT110.051Pasco (Franklin/Grays) GT 3GT110.051Pasco (Franklin/Grays) GT 4GT110.051Plummer Forest ProductsSTCG60.07Port Westward CC 1A & 1BCCCT4230.059Portland General Electric Distributed PVPV110Portneuf RiverHyd00Potholes East Canal 66.0Hyd10Potholes East Canal HeadworksHyd00Prather CreekHyd00QualcoIC00.047Quincy ChuteHyd00Raft River IGeothermal130.021Rainbow 1 - 8Hyd00Rathdrum (Boekel Rd) 1GT880.051Rathdrum (Boekel Rd) 2GT880.051River Road Generating PlantCCCT2350.059Riverbend LandfillIC50.047Rock Creek #1Hyd10Rock Creek #2Hyd10Rocky BrookHyd20Ross CreekHyd00Rough & Ready LumberSTCG10.07Rupert CogenerationCCCT80.059Russell D. SmithHyd00Ryan 1 - 6Hyd00SahkoHyd10Salmon 1IC30.047Salmon 2IC30.047Savage Rapids DiversionHyd10SchaffnerHyd00NameTypeNWFORIPPShasta RiverHyd00Short Mountain 1 - 4IC30.047Shoshone/Shoshone IIHyd00Simpson Tacoma Kraft CogenerationSTCG00.07SkookumchuckHyd10Slate CreekHyd40South Dry CreekHyd00SPI AberdeenSTCG50.07SPI BurlingtonSTCG30.07Spokane Waste-to-Energy (Wheelabrator)MSW150.07St. AnthonyHyd10Stahlbush Island FarmsIC20.047Sumas Cogeneration StationCCCT1340.059Summer Falls 1 & 2Hyd00Tenaska Washington Partners Cogeneration StationCCCT00.059245Tiber-MontanaHyd00Tieton DamHyd00Tuttle Ranch (Ravenscroft)Hyd10Twin Falls (TFHA)Hyd200Twin ReservoirsHyd20U.S. Bankcorp IC1 - IC4IC60.047U.S. Navy (Puget Sound Naval Shipyard)IC120.047U.S. Navy (Submarine Base Bangor) 1IC80.047U.S. Navy (Submarine Base Bangor) 2IC100.047UpriverHyd160Wapato Drop 2 (#1)Hyd30Wapato Drop 3 (#1 - 2)Hyd20Warm Springs Forest Products 1 - 3STCG00.07Weeks FallsHyd50Whitehorn Generating Station 2GT800.051Whitehorn Generating Station 3GT800.051Wild Horse SolarPV00Wilson LakeHyd00Woods Creek 1 & 2Hyd10WSU Grimes Way Central Steam PlantIC30.047Yellowstone Energy (BGI)STCG70.07Youngs CreekHyd70Total?127653451New since 2015Biotech/Life Sciences Building Generator 836IC10.047Black Cap Solar ProjectPV20Burton CreekHyd00Esquatzel PowerHyd10Fargo DropHyd10NameTypeNWFORIPPFighting Creek LandfillIC30.047H.W. Hill (Roosevelt Biogas) ExpansionIC260.047Highwood Generating Station IGTAero130.051McKenzieHyd00PonderosaHyd10Puyallup Energy Recovery Company (PERC) 1 - 3 (South Hill)IC20.047Seneca Saw MillSTCG190.07Misc Hyd Resource Lump *Hyd290Misc Thr Resource Lump *STCG150Total New?114Total All?12879Table 10 - Wind Serving NW LoadsSource NameCapOwnerNW MWBennett Creek21Big Horn I199MSR0Big Horn II50MSR0Big Top (Echo Wind Farm)1.65Biglow Canyon I125.4PGE125.4Biglow Canyon II149.5PGE149.5Biglow Canyon III174.8PGE174.8Burley Butte19.5IDA19.5Butter Creek (Echo Wind Farm)4.95PAC4.95Camp Reed22.5IDA22.5Cassia10.5IDA10.5Cassia Gulch18.9IDA18.9Coastal Energy6Grays Harbor6Combine Hills I41PAC41Combine Hills II63Clark63Condon49.8BPA49.8Elkhorn Valley100IDA100Fairfield WindFoote Creek I41.4BPA, PAC, EWEB41.4Foote Creek II1.8BPA1.8Foote Creek IV16.8BPA16.8Fossil Gulch10.5IDA10.5Four Corners (Echo Wind Farm)10PAC10Four Mile Canyon (Echo Wind Farm)10PAC10Glacier Wind Energy I106.5N W E106.5Glacier Wind Energy II103.5N W E103.5Golden Valley12IDA12Goodnoe Hills94PAC94Gordon ButteGoshen North (Goshen II)124.5SCE0Harvest Wind98.9WA Publics98.9Hay Canyon100.8Snohomish100.8Hopkins Ridge156.6PSE156.6Horse Butte57.6UAMP0Horseshoe Bend Wind Park10IDA9Hot Springs21IDA9Judith Gap135N W E135Juniper Canyon I151.2IPP151.2Kittitas Valley Wind100.8IPP100.8Klondike I24BPA24Klondike II75PGE75Klondike III223.6BPA, EWEB, PSE125Klondike IIIA76.5PG&E0Leaning Juniper I100.5PAC100.5Source NameCapOwnerNW MWLeaning Juniper IIa90.3IPP90.3Leaning Juniper IIb111IPP111Linden Ranch50SCPPA0Lower Snake River Phase I343PSE343Marengo I140.4PAC140.4Marengo II70.2PAC70.2Milner Dam19.5IDA19.5Musselshell Wind IMusselshell Wind IINine Canyon95.9WA Publics95.9Oregon Trail (Echo Wind Farm)9.9PAC9.9Oregon Trail (Idaho Wind)13.5IDA13.5Pacific Canyon (Echo Wind Farm)8.25PAC8.25Palouse Wind104.4Avista104.4PaTu9PGE9Payne's Ferry21IDA21Pebble Springs99LADWP0Pilgrim Stage Station10.5IDA10.5Rattlesnake Road (aka Arlington Wind Power Project)102.9PG&E0Rock River I50Rocky Mnt0Rockland79.2IDA79.2Salmon Falls21IDA21Sand Ranch (Echo Wind Farm)9.9PAC9.9Sawtooth Winds22.4IDA22.4Shepherds Flat North (North Hurlburt)265SCE0Spion Kop40N W E40Star Point98.7Modesto0Stateline300BPA NW Utilities300Thousand Springs12IDA12Three-mile Canyon9.9PAC9.9Tuana Gulch10.5IDA10.5Tuana Springs (Cassia Gulch Expansion)16.8IDA16.8Tuolumne (Windy Point; Windy Point/Windy Flats I)136.6Turlock0Two Dot Projects3.22N W E3.22Two Dot Projects IIVansycle Wind Energy Center I25PGE25Vansycle Wind Energy Center II98.9IPP98.9Vantage Wind Project90PG&E0Wagon Trail (Echo Wind Farm)3.3PAC3.3Ward Butte (Echo Wind Farm)6.6PAC6.6Wheat Field96.6Snohomish96.6White Creek204.7WA Publics204.7Wild Horse I & II272.6PSE272.6Willow Creek72LADWP0Windy Flats (Windy Point/Windy Flats IIA)262.2SCPPA0Source NameCapOwnerNW MWWKNWolverine Creek64.5Rocky Mnt0Yahoo Creek21IDA21Total??4579Table 11 - Average Monthly Load by Temperature YearOctNovDecJanFebMarAprMayJunJulAugSep1929239002807231869320632856827253260802400324587278722576423340193024412290772914035041338122656126829236292513826184262242343519312414328110311873936928638279132473923440243032640326389234421932240243212234092293962850127237254402327824156265682643723874193324494267023755632917333722826925552233502547625643258312381419342403728378293823237935040276662541723808247102646526192232211935235732677329421285782735426336244322326524799262012566723721193627951294083102640000286352783526482235712542527649251522359119372404229259314423081233959289912709123077250792660125928233961938235772735329869394053104226692252812311625444267542538023517193923818293423129030536289382803324786238652524827160249582360519402503526783296762897232167288562562223340253962760126273232041941242402920332369302882771026381252432316125301267342632323598194224045288143071732478277542668624479233442470028059263762353319432498827680309773700129639277132448723846259692655925923236411944250772669430682398542912628806250332347825418264672590423495194523171276883140131027285172902725014235502547127198252052419119462424328575326072998328270281922585523165249862678525707234441947254402882531422306202812627256252402308824798271452568323415194823492283962964733812284122783825469231092419226944256292332019492469427684333823052629257280692551424152260802581425723234691950249252665232834384303216227128243392377724053264862753723909195124513273792949940522401172845225441243702581226388262292378419522533028013316823410331541305032481723571258062659725893235611953240003140330114379312997628430252382371924064264982675123232195424136265872913929109283602846525957239282423226800251952382819552498329165317753542028624289702544923837246402598625797230761956252073397332371309712999630723259482393924678263192543324320195725198288163508534316345092937925769234942514727587254352345319582392028374292273728531491276232529723230249072558524777238101959236382916729490293832791728414253772313625704276752625724013196024054305323127040056290242822525041240892499627387260242344019612399127894309623443230765311832499023476250422719927021232531962250202879433762328382744628017257712397224904274562691423310196323823287683029435306315512935424659236762511426875255502380519642451728226313753988929820271142517423962247192581426362239401965244002846634378295772952828325255052443724320264802533723154OctNovDecJanFebMarAprMayJunJulAugSep1966233682730931755304992895727864257152408725309272072743823121196723946270853023630992285602858725075232492499526050263052401519682410127497329832970928461278362528523678252082644226472240071969241392713737241315412773326827258822355424940270192694923906197024291292332984435725298182778224988241172445126076253512361719712540230664312873245527597279592561023651253792686325596229431972259702695731774337933078330688258882341524979275202713523249197325459272433658734786326972808025783234152526826134274392342519742434327725290623550927985273482571023402256592692226061242021975239342773230664384162823829272255212363825442265952693523617197624609320603117733517299482744827177238402431527163254872378919772379229041301883062829668297262546223175256482643725560234311978242063127530995342242781828042250202364824872260592691923459197925061296433811132152277972743425243237512553126958272202311019802422029138301563567833414276502524923308251462756625920236361981243792739132762335263018127468257952332724300265392583923662198223572282003060628874299262673626052236682501526972273032395219832427429375317003506730611268362633123716251922644926153235321984238482815935956302742793926039260052377424806258532626123147198526471277023675532686280352637425324237872515426756262932330619862484035810331583295032022280332549523639247262716325283232701987236122817830227296082957326508256862351625634260232674123865198823655283393245932264279602655525358238722642726406268172420619892440427815310983328930768269862587324391250072741525930236191990245112744230769312743671831291254912320424623264462602623295199124074272533946029572320682710624655231032558427190264392396019922578228644301223349426767275872559323816245052618826510240441993235212897733145295632778925714255332341226027274632625423275199423828324613094334297304992827925324233172466224963268042365919952401829475327832914730934273862497623333249042762826550235341996251742617132249309093209627573249642330626046274832606223633199724761291383098235236339892719625053239402453627461257782333919982436726751306123138529502279012629223667243402638526547235291999244622712638364342132763827729249292332125327281392663224098200024074269943020630408287612786426708241122450526789261842344920012425529080322182998627980274282491523382258072624226680233522002241512755030251312202989827585260402387924937262912636623511200326027273603072430289284713005624646236582541627137254082356220042570530542302922856728545272132616423490261142739326333242672005246132886229213396822830026619242672310925494277742645323606Average244582859331838331432994927929254542359625078267732615123589Table 12 - Maximum Hour Load by Temperature YearOctNovDecJanFebMarAprMayJunJulAugSep19292003122065250762494923697215842056219775206192163220931196991930199072276423828267792581521965209421987520604213012118819771193120280225562495328697231022179119873198942051621336213031982119322002223067251582395223386218692017319754205442156321080197981933200562165226114252632439422088202481980120846209922099319765193419926220542351724778252282215820487200352064921307211221968119351990021412240972344722660209681954319768206792129421160198011936204562309624570250592333622682206911988520587212612086419889193719920228152415824066261892256220090197662084621425212101967219381972421679240312904524251216872060019781206712144120788198691939199192272124276244982358822150201251992920811217102073919853194019989218442352423860243942223420410197972048921421212681971019411979022891241602432123039213752006419766209012146821165198641942200102186424055242972284721138199021983620566218262102519637194320045224172410826348238442221120136199422045121540212471977819442008522080246732658723464225952003819968204792127520862198301945196612229125043248132364122502203901983920559213652088019849194620014222312476424148233172239220768197502050621498210711973519472046222760242142449923401220842040319759204612137120990197461948199432238524047258442308121634200821970120510213502074419687194920182226672564824505237122255620653199932076920938206401978019502038221402247352879724742220672011219760205052115020999198311951201552230723519295132451722678207582000020631212712110919856195220301224272552525299238522329420140198192075221439209021979119531976823177242652619123992226812028519888203762134321061197211954199432167623956233282357922305207381987720238211712093519878195520215215102453225398234802283020781197932034420902205031970919562012823201249442504224438235112120719960205262078420843198411957203712279624789247412547922838202471987420411215132084619748195820165224922384627421241772221220290197472058521056206961985619591990422496237332392922402222582044719750208712189521487197921960200712278524576248912383222176202891997020643215922076419682196120007222522489625947237572248820430199042063721889207371970719622028722952249212405422896220102067219951209772170921640197121963199692194023931257662364422643201651996420701211922074419761196419935220602470426769224682212720607199272056620971210791992419651998522875249712457423895224952076220020204272112120692196281966197232158724770246542346922088203511999320572216092116919633196720130220022382324528234112215420231197382057021132210901983219681996021964246812389323229225742088519879208572165821818199241969200692197925244247902244621477207301985120674216452081819773197020157221042411726897239472199420397197862076421244209231978619712033322088247932475122664220412094819862208402153021135195741972204552218325062248172351522831204941976020383215142163019684OctNovDecJanFebMarAprMayJunJulAugSep197320249219192515025674238722173020912198132061921461213761974719741999822485238012540623169220562040519786206852153920846198151975200092210124177261932339522066203691991720929212462100519885197620205225062434525224242652266921082199132045421693206891981119772002021966245332440323819229152057019731205352135220745197561978200122266024615257352278122214199481989920894212092154519745197920034232832610524264229822141420405198922078121434210051963919801993122817240162689824002214792039419824207362165221070198351981200902211324177262672338822277200471975720409213012065919718198220138217732436923752233502155520503199602042721042215021986519832008222848247972526523830221852085519910209302104721084197961984199892181926139236842269621371203671994220541209632127919693198520539223422602124415232352154420649199752050221344211761974619862020425029265432598124678226302028819889206692197520855195961987198702222224798239602354021280205842001620897207602155119757198819862218002516024916229362154919990196812092121102210361985819891978522179246822519623278220292023819893207062139421034198351990200972196624590247062560422480199001974920771212652083819774199120136219332654624038241602170119931198502071521704213121989819922029222157241852514822415223602051519875203882150521301198181993198862241025414239622251921036200131973521062214572130719654199419887233952458026066242252181720359197892054220454209261982219952009723028245442361824124215242004519725206662180221290197901996201852148624475238132286221783203331983920706214832071219897199720306225512482324960239872198320212199702054521703211161968519982013021656246682464923622221242056919763205362125921458198301999200842173825282243882302921819203581975120607219502141319982200020021215212410224136234522221620654200882055221394211961978020011999323220249342471323325221881999119866207832136721135196832002201922178624517245382411922057206691987720577212142125719805200320232219772425324499236252284220446200092079721620209721978320041978622877242242355923502217692044619968208772197321404198532005199782217924119254772330721334198141971820926219262149519729Average200662232924637251332365322104203901985820644213932107119776Appendix C – Assuring Adequacy for a Resource PlanThe Resource Adequacy Forum has developed a method to assess the adequacy of the Northwest’s power supply. More specifically, it has defined a probabilistic measure to gauge whether Northwest’s resources will sufficiently satisfy the region’s needs. It focuses only on the adequacy of electricity supply and does not take transmission outages into account (it does capture variation in transmission capacity for the east-to-west regional interties). The Northwest Resource Adequacy Standard uses the probabilistic measure defined by the Forum to assess whether existing resources will be sufficient through the next five year period. That assessment only takes into account existing resources and new resources that are expected to be completed and operational during that time period. If the power supply is deemed to be inadequate (e.g. LOLP greater than five percent), then specific actions are initiated. Those actions include reporting the known problem, validating load and resource data and identifying potential solutions. The process described above is intended to be an early warning for the region that indicates when resource development does not sufficiently keep up with demand. Although similar, the assessment of a resource strategy differs in significant ways. First, a resource strategy spans a much longer time period, namely 20 years for the Council’s power plan. Second, a strategy implies that resource development will be dynamic, in other words, it does not identify specific resources and specific build dates. Rather, the strategy identifies a supply of cost-effective resources that can be acquired as future conditions warrant. One can extract a single resource plan out of a particular resource strategy and then assess the adequacy of that single plan but that is not the same as assessing the adequacy of the strategy itself. The adequacy measure, as adopted by the Council, assesses the sufficiency of a specific set of resources combined with a specific forecasted demand by simulating the operation of those resources over many different futures. In those futures, water conditions, temperatures (which affect load), wind generation and thermal resource availability can vary. Based on those random variables only, a loss of load probability is calculated and compared to the five percent maximum allowed under the standard. The five percent LOLP threshold can be translated into deterministic metrics, which are more easily used for assessing adequacy or for incorporation into resource planning models. For example, a power system will provide an adequate supply of energy for the region when the average generation of existing resources plus about 1,500 average megawatts of market supply equals the average annual load. Similarly, the system will provide an adequate supply of peaking capability when the surplus sustained-peak generating capability is 23 percent in winter and 24 percent in summer. In each of these cases, the resulting LOLP will be five percent. These calibrated deterministic metric thresholds are easily incorporated into the Council’s Resource Portfolio Model (RPM). That model simulates a wider variety of future conditions with many more future unknowns than the Genesys model, which is used to assess LOLP. The RPM acquires resources based on economic considerations but if those resources do not measure up to the deterministic adequacy metric threshold, the model will add resources until that condition is satisfied. In this way, the Council can be sure that each resource plan examined under any particular resource strategy will be adequate, at least for energy supply.The problem is that currently, the only adequacy metric incorporated into the RPM is the energy measure. It may be possible (but unlikely) that some resource plans generated by the RPM may not meet the peaking adequacy thresholds. Given that the region is transitioning from a winter energy-limited system into a summer capacity-limited system, this omission from the RPM needs to be addressed. Perhaps future versions of the model can also include measures to test the peaking adequacy of various resource plans.However, the question at hand is how to assess the adequacy of a resource strategy developed by the RPM. One suggestion is to assess the adequacy of each resource plan (types of resources and build dates) for all 750 simulated futures for each strategy, using the deterministic adequacy metrics. This is time consuming but very doable. However, it is not clear what an acceptable result would be. Do all 750 plans need to be adequate or would it be acceptable if only 95 percent of them were adequate? Another option would be to assess the adequacy of the “average” build-out schedule of the strategy. If this average scenario is adequate does that imply that the strategy is adequate? The problem is that the RPM simulates future conditions with many more random variables than does Genesys. The most important variable, from an adequacy point of view, is probably long-term load uncertainty. This is not the uncertainty in demand caused by variation in temperature but rather the potentially much larger change in demand due to economic or other factors. A result of this is that the RPM will simulate situations when the region will under or overbuild, much like it has in real life over the past 50 years. There really is no way to avoid such conditions because we cannot accurately forecast all future conditions, especially demand. We could have the RPM calculate a loss of load probability for its all of its plans in each strategy but that calculation could be misleading. Although labeled LOLP, the RPM version provides a vastly different measure of the power supply than does the Genesys LOLP because the random variables are different. At this time it is unknown what a reasonable RPM LOLP value would be or whether it would ever be meaningful, since the RPM is not an hourly simulation model and thus can only approximate peaking operations. So what do we do? The first thing to remember is that the real scope of this power plan has a five year time period. We will revisit these questions five years from now. So, potential inadequacies in the later years of the study horizon may be interesting but are unlikely to change the five-year action plan. Thus, if we are to assess the adequacy of all (or some) of the resource build-outs from an RPM strategy, we should only focus on the first five years. It seems to me that most of those plans should pass the Genesys adequacy test (at least the deterministic ones). If a significant number of those plans fail the test, we should ask ourselves why that is and perhaps change our five-year action plan to address the problem. However, this does not appear to be the case for the draft power plan. There is the additional issue of whether the adequacy of all RPM strategies should be assessed. Some of those strategies are based on assumptions that have little or no likelihood of being realized. In those cases, it makes no sense to spend the time calculating adequacy, especially because they do not drive the action items in the plan. Thus the current recommendation is to simply use some form of deterministic adequacy metric inside of the RPM to dynamically test for adequacy during the analysis. It is not recommended that we take any of the “build-out” cases out of the RPM and assess the LOLP specifically. ________________________________________q:\jf\2017 adequacy\sos\2017 sos report draft 4.docx ................
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