Loads and Resources Methods and Assumptions

Loads and Resources Methods and Assumptions WECC Staff September 2014 155 North 400 West, Suite 200 Salt Lake City, Utah 84103-1114

Loads and Resources Methods and Assumptions ii Contents Purpose... 1 Assessment Process... 1 Subregion and Balancing Authority Maps... 2 Planning Reserve Margins... 3 Demand... 6 Demand-Side Management... 6 Generation... 7 On-Peak Capacity Transactions... 9 Transmission... 9 Transfer Limits... 11 Transmission Planning Considerations... 14 Transmission Expansion Planning... 14

Loads and Resources Methods and Assumptions 1 Purpose The Loads and Resources (LAR) Methods and Assumptions document describes the basic methods and assumptions used by WECC staff when developing the North America Electric Reliability Corporation (NERC) Long-Term Reliability Assessment, the NERC summer and winter assessments, and the WECC Power Supply Assessment. Assessment Process WECC uses a production cost model (PCM) to calculate a supply/demand balance and the associated power transfers among 19 zones. The zones are configured around demand centers and transmission hubs. The subregions (an aggregation of zones) with associated zones and Balancing Authorities (BA) are identified in Table 1. Table 1 - WECC Subregion, Zones, and Balancing Authorities Subregion Zones in Subregion Balancing Authorities in Subregion Northwest Power Pool (NWPP) Rocky Mountain Reserve Group (RMRG) Southwest Reserve Sharing Group (SRSG) Alberta, Balancing Authority of Northern California, British Columbia, Idaho, Montana, Northern Nevada, Pacific Northwest, Southern Nevada, Utah, Western Wyoming Colorado, Eastern Wyoming Arizona, Imperial Irrigation District, New Mexico Alberta Electric System Operator, Avista Corporation, Balancing Authority of Northern California, Bonneville Power Administration - Transmission, British Columbia Hydro and Power Authority, Constellation Energy Control and Dispatch, Idaho Power Company, NaturEner Glacier Wind Energy, NaturEner West Wind, Nevada Power Company, Northwestern Energy, PacifiCorp - East, PacifiCorp - West, Portland General Electric Company, PUD No. 1 of Chelan County, PUD No. 2 of Grant County, PUD No. 1 of Douglas County, Puget Sound Energy, Seattle Department of Lighting, Tacoma Power, Turlock Irrigation District, Western Area Power Administration - Upper Great Plains West Public Service Company of Colorado, Western Area Power Administration- Colorado-Missouri Region Arizona Public Service Company, Arlington Valley, El Paso Electric Company, Gila River Maricopa Arizona, Griffith Energy, Harquahala Generating Maricopa Arizona, Imperial Irrigation District, Public Service Company of New Mexico, Salt River Project, Tucson Electric Power Company, Western Area Power Administration - Lower Colorado Region

Loads and Resources Methods and Assumptions 2 Subregion Zones in Subregion Balancing Authorities in Subregion California/ Mexico (CA/MX) Comisión Federal de Electricidad, Los Angeles Department of Water and Power, Northern CA, San Diego, Southern CA California Independent System Operator, Comisión Federal de Electricidad, Los Angeles Department of Water and Power The resource allocation seeks the lowest overall cost, while maintaining resource adequacy within the subregions. Data elements, as collected from the 38 BAs in the Western Interconnection, needed for the PCM to calculate the WECC-wide, and subregional reserve margins include: monthly and annual peak demand and energy forecasts; expected generation availability; annual energy for energy limited resources; coincident hourly shaping data for loads and energy-limited resources; and simplified transmission interconnection that reflects nominal power transfer capability limits. Subregion and Balancing Authority Maps Western Interconnection Subregions (4)

Loads and Resources Methods and Assumptions 3 Planning Reserve Margins The seasonal reserve margin calculations in this assessment reflect seasonal ratings for Existing- Certain, Future-Planned, and Conceptual resources. WECC s assessment modeling process does not make a distinction between Energy-Only resources and any other resource. Capabilities for Transmission-Limited resources would be reduced to reflect the transmission limitation but presently WECC does not report any such resources. Demand-Side Management is treated as a reduction to Total Internal Demand. Behind-the-meter generation is excluded from the PCM, as is any associated load. The PCM assumes that there are no transactions with entities external to the Western Interconnection. Demands are modeled as BA-level hourly load shapes that are scaled to reflect the BA-level monthly peak demand and energy load forecasts. Subregion demands reported in this assessment reflect sums of the internal BA demands coincident to the subregion-wide coincident peak demand. Region and subregion Target Reserve Margins are calculated using a building block methodology created by WECC s Loads and Resources Subcommittee. 1 As such, they do not reflect a criteria-based margin-determination process and do not reflect any BA or Load-Serving Entity (LSE) level requirements that may have been established through other processes (e.g., state regulatory authorities). Moreover, they are not intended to supplant any of those requirements. The building block methodology is comprised of four elements: 1. Contingency Reserves An amount of operating reserve sufficient to reduce Area Control Error to zero in 10 minutes following loss of generating capacity, which would result from the most severe single contingency. The BA-level Contingency Reserve is equal to the percent required in BAL-002-WECC-1 2, or approximately 6 percent of Total Internal Demand for all BAs. Contingency Reserves are required to be carried by BAs (individually or through reserve sharing pools) by NERC and WECC Standards. 2. Regulating Reserves The amount of spinning reserves responsive to automatic generation control that is sufficient to provide normal regulating margin. The regulating component of the guideline was calculated using data provided in WECC s annual loads and resources data request responses. The BAs are asked how much regulating reserve they expect to carry during the current year, as either a megawatt value or as a percentage of load. Megawatt responses are converted to a percentage of load by dividing the megawatt value provided by the forecasted peak demand. A "sanity" check is done for all responses and those that 1 The Loads and Resources Subcommittee was consolidated with the Reliability Performance Evaluation Work Group into the Reliability Assessment Work Group in March 2014. 2 WECC Standard BAL-002-WECC-1 - Contingency Reserves: http://www.nerc.com/_layouts/printstandard.aspx?standardnumber=bal-002-wecc-1&title=contingency Reserve (WECC)&jurisdiction=United States

Loads and Resources Methods and Assumptions 4 seemed unreasonably low or high are replaced with the subregional weighted average of reported regulating reserves. This component also includes reserves to balance variations in output from variable resources (such as wind) and may be significant for some BAs. The BAs are required to carry Regulating Reserves by NERC and WECC Standards. 3. Forced Outages Reserves for forced outages, beyond what might be covered by operating reserves in order to cover second contingencies, are calculated using the forced outage data supplied to WECC through the loads and resources (LAR) data request responses. Ten years of data are averaged to calculate both a summer (July) and winter (December) forced outage rate. (The actual calculation is total forced outages divided by total resources reported in the loads and resourced data request responses.) The same forced outage rate is used for all BAs in WECC when calculating the building block margin. Neither NERC nor WECC standards require these reserves. 4. Temperature Adders Using historic temperature data for more than 20 years, the annual maximum and minimum temperature for each BA s area is identified. The data are used to calculate the average maximum (summer) and minimum (winter) temperature and the associated standard deviation. An example of the calculation is provided in Table 2.

Loads and Resources Methods and Assumptions 5 Year Table 2 - Temperature Adder Calculation Example Summer Temp Calculation 1992 98.76 AVG 97.04 1993 96.67 STD 2.81 1994 99.03 1995 95.82 z = x x s 1996 96.99 x = x + z(s) 1997 95.77 1998 98.06 z= 1.282 1999 93.04 Temp = 100.6 2000 96.69 Pr()= 0.9 2001 96.18 Temp Increase 3.6 2002 98.13 MW/Degree 60 2003 97.73 MW Increase 216.503 2004 99.79 MW Load 7943 2005 92.09 % Increase 2.7% 2006 99.96 2007 97.89 2008 99.89 2009 104.26 2010 93.30 2011 92.98 2012 94.90 2013 96.90 The standard deviation was multiplied by a 90 percent probability factor, and added to the average historic temperature to convert from a 1-in-2 temperature (50 percent exceedance) condition to a 1-in- 10 (10 percent exceedance) condition. The 1-in-2 temperature was subtracted from the 1-in-10 temperature to calculate the temperature change associated with the 1-in-10 outlook. The temperature change was then multiplied by the megawatt per degree change supplied by the individual BAs to arrive at a megawatt increase associated with converting from a 1-in-2 temperaturerelated forecast to a 1-in-10 forecast. This megawatt change was divided by the forecast peak demand to create a percentage change to be applied to future demand forecasts to convert from a 1-in-2 forecast to a 1-in-10 forecast. Neither NERC nor WECC standards require these reserves. Table 3 relates the building block elements in a hypothetical total forecasted demand example.

Loads and Resources Methods and Assumptions 6 5,600 Table 3 Hypothetical Total Forecast Demand 5,400 1-in-10 Temp Adder 5,200 Contingency Reserve 5,000 Regulating Reserve 4,800 Forced Outage 4,600 4,400 MW 1-in-2 Temp Demand Forecast Demand Total Internal Demands represent BA historical hourly load shapes that have been averaged and scaled by BA-level peak demand and energy load forecasts (1-in-2). The BA-level load shapes are aggregated to create Region and subregion load projections. The Total Internal Demands (firm and non-firm) presented in this assessment reflect extractions of the monthly demands coincident with the WECC Region monthly maximum Total Internal Demands. WECC asks its BAs to submit forecasts with a 50 percent probability of occurrence (1-in-2). The BA-level peak demand and energy load forecasts are based on expected population growth, normalized weather and expected economic conditions. It should be noted that the BA-level forecast submittals to WECC are generally based on the most recently approved forecast and, as such, may reflect a significant time lapse between expected conditions at the time the forecast preparation was initiated and the expected conditions as of the publication of this assessment. This time lag may result in apparent over-forecasts during declining economic conditions and under-forecasts during periods of rapid economic expansion. Demand-Side Management State and other regulatory drivers have led to increases in Demand-Side Management (DSM), energy efficiency, and conservation programs penetration within the WECC subregions. Within some established market structures, DSM has been established as an ancillary service. LSEs within the Region have implemented Demand Response programs and intend to activate the programs when warranted by operating conditions. The programs are generally geared toward

Loads and Resources Methods and Assumptions 7 activation on either short notice or, in many cases, no notice and are often a final step before interruption of firm service to customers. It is important to the LSEs and the BAs that the programs perform as expected. LSEs routinely test their programs and program activation processes and procedures to ensure that expected program responses will occur as and when needed. WECC neither tracks nor assesses energy efficiency and conservation programs. WECC does collect monthly dispatchable and controllable demand response (CDR) information for inclusion in assessments but notes that the activation of the CDR is generally at the discretion of the LSE. CDR programs in WECC often have limitations such as having a limited number of times they can be called on and some can only be activated during a declared local emergency. Consequently, an individual LSE may not activate its CDR in response to a request for assistance from an LSE in a different part of the Interconnection and CDR should not be considered as widely sharable. Thus, total Region and even subregion margins may be overstated by an undetermined amount. Generation Resources represented in the WECC assessment model are limited to generation that is available, or is expected to be available, to serve the forecasted load. Any load that is not to be metered by a BA s energy management system is excluded, as is the generation that is serving that load. Hence, distributed generation, such as residential rooftop solar facilities and behind-the-meter generation, is netted against load and not included in this assessment. The expected output to the grid of existing generation is reported for assessments as Existing-Certain capacity and the derated portion of variable resources as calculated by WECC staff is reported as Existing-Other. All future resources are reported as WECC Class Codes 1 through 5 and aligned with the NERC Class Codes of Tier 1 through 3. The correlation of WECC Class Code to NERC Class Code is listed in Table 4. Definition for each class and tier can be found in the most recent LAR Data Collection Manual. 3 Table 4 - Correlation of WECC Class Code to NERC Class Code NERC Class Code Existing- Certain Existing-Other 4 WECC Class Code 0 3 2014 LAR Data Collection Manual: https://www.wecc.biz/reliability/2014_lar_datamanual.pdf 4 WECC staff does not believe that the Existing-Other class code applies to resources in the Western Interconnection and Existing-Inoperable resources are excluded from the reporting.

Loads and Resources Methods and Assumptions 8 NERC Class Code WECC Class Code 1 T1 2 3 T2 2 3 T3 4 Existing-Inoperable 4-5 Hydro generation in the PCM is constrained by annual energy limits that are based on actual energy production from 2003 for Northwest Hydro generation and from 2002 for California Hydro generation. These two years were selected by WECC s Transmission Expansion Planning Policy Committee (TEPPC) Data Work Group as low water years that would best reflect adverse hydro conditions. Biomass generation is treated as other thermal resource, and is dispatched in merit order. However, the fuel price is set lower than natural gas and should be dispatched before other thermal resources. Variable generation modeling of wind resources is based on curves created using at least five years of actual hourly wind generation data. The data is averaged into six four-hour blocks for each week of the year. Solar resource energy curves were created using up to five years of actual hourly solar generation data. The data is averaged into three-block curves for each week of the year. The variable generation shapes are applied throughout the 10-year study period. This treatment, along with the use of average generation, removes the hourly peaks and valleys in wind and solar generation while maintaining a reasonable representation of variable energy output. Inoperable generation and scheduled maintenance are treated as a reduction in available capacity. Inoperable generation is reported in the LAR data request, and the PCM calculates scheduled maintenance considering seasonal demand peaks to maximize capacity available during the individual subregional peaks, not for the entire Western Interconnection. The majority of the summer outages are scheduled for generation in the winter-peaking Canada and Northwest subregions. Other areas try to have all their units available for the summer peak. The generation owners in the summer-peaking zones usually schedule their maintenance in the fall or spring.

Loads and Resources Methods and Assumptions 9 On-Peak Capacity Transactions WECC s assessment process is based on system-wide modeling that aggregates BA-based load and resource forecasts by geographic subregions with conservatively assumed power transfer capability limits between the zones. The PCM calculates transfers between the zones based on assumed dispatch criteria. This modeling approach excludes a representation of contractual commitments by individual entities and assures that capacity margins reflect potential forecast conditions that are independent of variable contractual transfer assumptions. Resources that are physically located in one BA area but are owned by an entity or entities located in another BA s geographic footprint, are modeled as remote resources. These resources are modeled with transmission links between the resource zone and the owner s zone that are limited to the owner s share of the resource. This treatment allows the owner of the resource, and only the owner, to count the resource for margin calculations. Transfers with other regional councils, such as the Midwest Reliability Organization and the Southwest Power Pool, are not included in this assessment as this would require an assumption regarding the amount of surplus or deficit generation in those councils. Transmission For modeling purposes, the Western Interconnection is separated into 19 load area zones. These zones are used in a simplified transmission model to calculate potential transfers between zones. The simplified model reflects transfer capabilities between the 19 zones used in the studies, wheeling costs, and loss factors. The wheeling costs for each path are used to calculate the transfer costs for any imports into a zone. The wheeling costs range from $0.00 to $6.48 per megawatt-hour. Since the LAR data request specifies that line losses be included in all demand forecasts, a loss factor of zero (0) percent is used in the model. Note that neither the wheeling cost nor the loss factor impedes the model from importing surplus resources to meet load. There are nine regional transmission planning groups that cover the Canadian and U.S. portions of the Western Interconnection. One of the responsibilities of the WECC Regional Planning Coordination Group (RPCG) is to assist in coordinating the regional transmission plans. Information on the RPCG and the regional planning groups can be found on the WECC website. 5 It should be noted that generally the transmission planning groups themselves do not have a responsibility regarding implementation of transmission plans in their respective areas. That responsibility is left to the individual planning group member and its appropriate oversight entity (e.g., state utility commission). State/provincial oversight activities vary widely within the West. In conjunction with commission oversight activities, individual entities may prepare long-term transmission plans on a regular basis. For example, the Arizona 5 RPCG webpage: https://www.wecc.biz/teppc/pages/rpcg.aspx

Loads and Resources Methods and Assumptions 10 Corporation Commission collects entity-level biennial transmission plans and published a biennial transmission assessment report. WECC s TPL-001-WECC-CRT-2.1 System Performance Regional Criteria, requirement WR 3.2 addresses reactive power and voltage stability margins. It specifies that voltage stability is required for an area modeled at a minimum of 105 percent of the reference load level for system normal conditions and for single contingencies. For multiple contingencies, post-transient voltage stability is required with the area modeled at a minimum of 102.5 percent of the reference load level. For this criterion, the reference load level is the maximum established planned load limit for the area under study. Summary guidelines as to how the analysis should be conducted are presented in a Summary of WSCC Voltage Stability Assessment Methodology document. The Western Interconnection is a large and geographically diverse area with significant distances between several generation areas and load areas. The transmission interconnections between these geographically dispersed areas are generally voltage stability-limited, not thermally limited. The System Performance Criterion cited above also addresses transmission system operating limit determination for these interconnections. Many load centers in the West are largely served from remote generation resources through voltage stability-limited transmission interconnections. Consequently, most load within the Interconnection may be considered to be reactive power-limited. LSEs typically address reactive power issues through the installation of local controllable compensation, strengthening interconnections with high-voltage transmission system, and maintaining local must-run generation to provide local voltage support. WECC does not perform studies to identify reactive power-limited areas in the Bulk-Power System. However, Transmission Planners and Planning Coordinators within the Western Interconnection have an obligation under WECC-TPL Regional Criteria to identify dynamic and static reactive power-limited areas. WECC s voltage stability-margin process is centered on meeting certain voltage dip criteria based on certain equipment outage and peak demand assumptions. Consequently, the process indirectly establishes voltage stability margins that Transmission Planners and LSEs are expected to apply when planning transmission and distribution facility additions. Section II of the California Independent System Operator s annual transmission plan provides excellent examples of the application of the WECC Regional Business Practice and associated NERC Reliability Standards in the transmission planning arena. In response to the September 8, 2011 Southwest outage, WECC has created the September 8, 2011 Southwest Response page 6 on its website. The High Level Summary of September 8, 2011 Pacific Outage Survey Results is available on this site. The survey is a white paper that summarizes the current planning and operating practices of entities within the Western Interconnection, identified planning 6 September 8, 2011 Outage Event Response webpage: https://www.wecc.biz/september-8-2011/pages/default.aspx

Loads and Resources Methods and Assumptions 11 gaps, and proposed best practices to address these issues. Many of the short-term issues concerning reliable transmission operations are addressed here. In addition, updates on WECC/NERC/FERC recommended process improvements are posted along with summaries of activities that individual WECC entities are implementing in response to these recommendations. Transfer Limits These diagrams represent the seasonal capacity limits between zones. The colors of the zones in the diagrams also identify the aggregated subregions.

Loads and Resources Methods and Assumptions 12 Table 5 - Summer Transfer Limits British Columbia 800 0 Alberta 2000 0 2000 250 MRO Pacific Northwest 2000 400 500 Montana 200 600 325 1800 200 4200 300 350 Idaho 0 Wyoming 1400 3675 300 185 2200 1400 Northern 100 680 300 2600 California 100 775 100 2858 Northern Nevada 2750 360 235 2750 650 Utah 1920 650 800 1400 3675 800 140 3000 250 Southern California 2300 Southern LADWP Nevada 3883 4727 3750 692 4785 3750 468 1700 250 2814 250 692 600 468 1273 600 2440 San Diego BANC IID Arizona 150 255 150 163 1655 2400 1168 2400 Colorado 350 614 300 664 New Mex ico SPP 408 0 Mex ico Legend For each pair of numbers, the top or left number is the transfer capability (MW) in the direction of the arrow. The bottom or right number is the transfer capability in the opposite direction of the arrow.

Loads and Resources Methods and Assumptions 13 Table 6 - Winter Transfer Limits British Columbia 800 0 Alberta 500 0 2000 250 MRO Pacific Northwest 2000 400 500 Montana 400 600 250 2100 250 4800 300 350 Idaho 0 Wyoming 1400 3675 300 185 2200 1450 Northern 100 680 400 2900 California 100 785 100 2858 Northern Nevada 2750 360 235 2750 650 Utah 1920 650 800 1400 3675 800 260 3000 265 Southern California LADWP 3823 Southern 3883 Nevada 4634 4000 922 4785 3750 468 2814 250 2814 225 922 600 468 1273 600 2440 San Diego BANC IID Arizona 150 321 150 163 1910 2400 1168 2400 Colorado 350 614 300 664 New Mex ico SPP 800 408 Mex ico Legend For each pair of numbers, the top or left number is the transfer capability (MW) in the direction of the arrow. The bottom or right number is the transfer capability in the opposite direction of the arrow.

Loads and Resources Methods and Assumptions 14 Transmission Planning Considerations WECC is not a Transmission Planner (TP) or Transmission Operator (TOP) and does not perform seasonal planning studies. However, TPs and TOPs throughout the region perform studies that analyze the effect on their systems from element outages in their footprints and neighboring areas. These studies are performed for various seasons (summer, winter, spring, and fall), under various load levels (shoulder peak, light and heavy load, etc.), and incorporate all transmission elements that have been deemed to impact the Bulk-Power System, regardless of voltage size. Peak Reliability, the Reliability Coordinator (RC) for the Western Interconnection (excluding Alberta) has developed a Seasonal System Operating Limit (SOL) Coordination Process that provides TOPs, subregional study groups, and the RC processes to follow when coordinating and implementing seasonal operating studies and establishing seasonal SOLs. Details of this process are outlined in the Peak Reliability document: Peak RC Seasonal SOL Coordination Process. 7 Peak Reliability, has developed the Coordinated Outage System (COS) tool and made it available for entities to distribute planned resource outage information. This tool is used to coordinate maintenance-related transmission outages throughout the Western Interconnection to minimize impacts to reliable operation of the Western grid. Transmission Expansion Planning WECC entities, recognizing the need for a regional approach to transmission expansion planning, organized TEPPC to provide transmission expansion planning coordination and leadership across the Western Interconnection. TEPPC works in close coordination with subregional planning groups, transmission operators, and others to facilitate regional economic transmission expansion planning. The functions performed by TEPPC complement, but do not replace the responsibilities of WECC members and stakeholders regarding the planning and development of specific projects. Each year TEPPC develops a study program that details the transmission system expansion studies it will perform. The program is based on study requests received during TEPPC s open season request window (November 1 st January 31 st ). Any interested party can submit a study request to TEPPC for consideration. Analysis and studies performed by TEPPC focus on plans with Interconnection-wide implications and include a high-level assessment of transmission congestion and operational impacts. Results from TEPPC s studies provide useful insight into transmission expansion needs within the Western Interconnection. TEPPC s Biennial Report, and other documents produced by TEPPC are located on the TEP webpage. 8 7 Peak Reliability Library: https://www.peakrc.com/pages/library.aspx 8 TEP website: https://www.wecc.biz/transmissionexpansionplanning/pages/default.aspx