TEPPC Study Report: 2026 PC1 Common Case

Transcription

1 TEPPC Study Report: 226 PC1 Common Case WECC Staff Draft: January 13, North 4 West, Suite 2 Salt Lake City, Utah

2 226 PC1 Common Case ii Overview This document is for technical review purposes only. It has not been endorsed or approved by the WECC Board of Directors, the Transmission Expansion Planning Policy Committee (TEPPC), the TEPPC Scenario Planning Steering Group (SPSG), or WECC Management. The current results are from the PC1 version 1.7 dataset. The detailed input assumptions are available in the release notes Common Case & Release Notes v1.5

3 226 PC1 Common Case Report DRAFT iii Table of Contents Introduction... 1 Abstract of Case... 2 Key Inputs and Results from TEPCC 226 Common Case Version Load... 5 Generation... 6 CO 2 Emissions... 9 Transmission congestion... 9 Additional Discussion of Input Assumptions and Study Results Study Limitations Dataset Updates Summary Inputs and Assumptions Load Topology Changes in Load Transmission Network Generation Resources Load Modifiers Overriding Assumptions Key Data and Modeling Improvements Additional Study Results Generation by State/Province Peak Hour Breakdown... 2 Transmission Path Flows Conclusions and Observations Appendix A... 31

4 226 PC1 Common Case 1 Introduction The 226 Common Case is a production cost model (PCM) dataset that serves as an expected future of loads, resources and transmission topology in 226 for the Transmission Expansion Planning Policy Committee (TEPPC). The case represents the compilation of recent Western Interconnection planning information, developments and policies looking out 1 years to the year 226. A primary goal in developing a Common Case is to define a reasonable foundation for the other resource mix and transmission planning studies (year 1 time frame) that are conducted as part of the 216 TEPPC Study Program. The case is also used throughout the Western Interconnection for a number of purposes, including: FERC Order 89 and 1 planning studies by regional planning groups, subregional planning member entities, independent developer studies, market studies (e.g., Energy Imbalance Market) and integration studies, as well as many other uses. Many stakeholder groups provided valuable input and effort in developing the thousands of assumptions that depict the Western Interconnection and how it is expected to change over the next 1 years. The development of a WECC wide production cost dataset would not be possible without the huge contribution of all of the TEPPC stakeholders. The TEPPC and WECC staff wishes to express appreciation to everyone who contributed to this effort. PCM Simulation Parameters The version and simulation parameters are provided in Table 1. Table 1: Simulation Parameters Description GridView Version Generator Reserve Distribution Generator Exempt Ramp Rate Enforced Quick Start Commitment Look Ahead Logic Use Loss Model Recalculate Loss Matrix Remove Losses in Loads Hydro Thermal Coordination Parameter [ ] 64bit Yes Yes Yes In Unit Commitment Yes No Yes Yes Yes Yes

5 226 PC1 Common Case Report DRAFT 2 Abstract of Case The 226 TEPPC Common Case is a collection of assumptions that are designed to depict the most likely representation of the WECC Bulk Power System for the year 226. Table 2 provides a high level summary for comparison purposes of a few of the inputs and results including, where available, actual data for 215 from the WECC 216 State of the Interconnection (SOTI) report. Table 2: Summary Table Comparison Category Item Change Peak Demand (MW) Summer 15,7 164, % Winter 126,2 148, % Hydro + Energy Storage Thermal Coal Thermal Gas 71,3 38,7 16, 68,4 28,28 97, % 27.6% 7.6% Generation Capacity (MW) Thermal Nuclear 7,7 5,82 34.% Thermal Other 1,7 1, % Renewable DG/DR/EE Incremental <Total> 39,6 265, 53,419 21, , % NA 3.7% Annual Generation (GWh) Hydro + Energy Storage Thermal Coal Thermal Gas Thermal Nuclear Thermal Other Renewable DG/DR/EE Incremental <Total> 196,6 216,9 266,3 6,2 17,1 83,4 84,5 243, , ,281 39,192 1, ,794 3, ,21 24.% 14.4% 22.5% 34.9% 88.4% 15.4% NA 18.8% A few key observations are: The increased energy from hydro and energy storage implies an assumption of higher hydro flows and increased energy storage opportunities. The reduction in coal is due to several coal fired generator retirements and the impact of carbon price regulations in Alberta, British Columbia, and California. The reduction in nuclear is due to the announced retirement of the Diablo Canyon Nuclear Power Station in northern California. The chart in Figure 1 compares the annual generation by category from the 226 common case to the two previous common cases for 222 and 224. This clearly shows the progression of retirement plans for coal and nuclear generation.

6 226 PC1 Common Case Report DRAFT 3 Figure 1: Comparison of Annual Generation Annual Generation (GWh) by Category 222 PC1 Final 224 PC1 v WECC v1.7 Conventional Hydro Energy Storage Steam Coal Steam Other Nuclear Combined Cycle Combustion Turbine IC Other DG/DR/EE Incremental Biomass RPS Geothermal Small Hydro RPS Solar Wind 5, 1, 15, 2, 25, 3, 35, It is not clear from Figure 1 that the amount of load to be served fluctuates between common cases, as apparent in Figure 2. A few of the factors driving the fluctuations are load forecast variances, energy storage impacts, and varying flows between BA s. Figure 2: Comparison of Total Generation Total Generation (GWh) 1,6, 1,4, 1,2, 1,, 98, 96, 222 PC1 Final 224 PC1 v WECC v1.7 Coal Retirement Assumptions The retirement of coal fired generation has been a key focus area during the last few years. In the 226 dataset, WECC has reflected the actual retirements and the announced future retirements as plans are finalized. These assumptions are provided in Table 3.

7 226 PC1 Common Case Report DRAFT 4 Table 3: Coal Retirement Assumptions 226 Case vs. 224 Case Coal Generator State/Province Retirement Retired Capacity (MW) Year ACE Cogen California Arapahoe 3,4 Colorado Battle River 3 Alberta Battle River 4 Alberta Ben French 1 S. Dakota Boardman Oregon Carbon 1,2 Utah Centralia 1 Washington Centralia 2 Washington Cherokee 3 Colorado Cherokee 4 [CTG]* Colorado 217 Cholla 2 Arizona Cholla 4 Arizona Colstrip 1,2 Montana Craig 1 Colorado Four Corners 1 3 Arizona HR Milner Alberta JE Corette Montana Kennecott 1 3 Utah Lamar 4,6 Colorado Martin Drake 5 Colorado Naughton 3 [CTG]* Wyoming 218 Navajo (1 unit of 3) Arizona Neil Simpson 1 Wyoming Nucla 1 4 Colorado Osage 1 3 Wyoming Reid Gardner 1 3 Nevada Reid Gardner 4 Nevada RioBravo Jasmin California San Juan 2,3 New Mexico Sundance 1,2 Alberta Valmont 5 Colorado Valmy 1 Nevada Valmy 2 Nevada WN Clark 1,2 Colorado Total 6,521 9,279 *Converting to gas, Cherokee 4 (352 MW), Naughton 3 (33 MW)

8 226 PC1 Common Case Report DRAFT 5 Key Inputs and Results from TEPCC 226 Common Case Version 1.7 A few key inputs and results of the 226 Common Case are provided here. Additional results and a description of the input assumptions are presented in later sections. Load The components of the projected WECC peak demand and energy load 2 in the 226 Common Case are provided in Table 4 and compared to the 215 actual values in Figure 3. The summer and winter peak values represent the common case inputs and results during the hour in which the summer and winter peaks occurred, namely, July 27 at 4: pm, and December 8 at 7: pm. Table 4: Load Forecast Components 226 Forecast and Load modifiers 3 Load Components Summer Peak (MW) Winter Peak (MW) Annual Energy (GWh) Native Load 4 Base 17,2 148, ,732 Native Load Pumping ,511 Energy Storage Pumping ,482 Exports Losses Netted from Load ,515 Served Load Subtotal 169,78 148, ,21 (DG/DR/EE Incremental) 5, ,439 Total Net Energy Load 164, , ,771 The peak demand in the 226 common case is estimated to be 13,654 MW higher than the 215 actual peak demand. 2 For modeling purposes the incremental distributed generation (DG), demand response (DR), and energy efficiency (EE) are represented as generators. In reality these components would decrease the load by the amounts in Table 4. 3 Load Modifiers refer to DG, DR, and EE, which can be modeled as a direct load reduction or as generators. 4 Native Load is the collection of end use customers that the Load Serving Entity is obligated to serve.

9 226 PC1 Common Case Report DRAFT 6 Figure 3: Load Growth Peak Demand (MW) Annual Energy (GWh) 17, 165, 968, , , 968, 954, 94, MW 16, 926, 912, GWh 155, 15, 883,6 15,7 898, 884, 87, Trend >> Generation The generation inputs for the 226 Common Case reflect existing resources plus planned resource changes between 215 and 226. The total net capacity 5 changes for the referenced resource types are shown in Figure 4, with a net capacity change of 12,76 MW (excluding the load modifiers). Note that these changes are based on the common case input assumptions and may be different than the SOTI assumptions used in Table 2. The coal retirements are based on data submittals and media announcements from the Generator Owners and Balancing Authorities. The majority of the Steam Other retirements are associated with the compliance agreements for the California Once Through Cooling (OTC) requirements. The largest increase is in the Distributed Generation/Demand Response/Energy Efficiency (DG/DR/EE) Incremental category, and reflects the modeling of existing and future Behind the Meter Photovoltaic (BTM PV). The additions for solar and wind are also significant and will be discussed in more detail later in the report. 5 The reported capacities represent the highest available to the grid capacities over the study year.

10 226 PC1 Common Case Report DRAFT 7 Figure 4: Key Resource Net Capacity Change (MW) between 1/1/215 and 1/1/226 Conventional Hydro Energy Storage Steam Coal Steam Other Nuclear Combined Cycle Combustion Turbine IC Other DG/DR/EE Incremental Biomass RPS Geothermal Small Hydro RPS Solar Wind 15, 1, 5, 5, 1, 15, 2, 25, The 226 Common Case was modeled using a production cost model 6 to obtain a load/resource solution for each hour of 226. A breakdown of the resulting annual generation by category based on the input and modeling assumptions is shown in Figure 5. The largest shares of production were from combined cycle generation (28.6 percent) and conventional hydro (24.1 percent). The share from renewable generation (including incremental DG) was 17. percent. 6 WECC uses ABB GridView for their PCM studies.

11 226 PC1 Common Case Report DRAFT 8 Figure 5: Breakdown of Annual Generation 226 Common Case Annual Generation Breakdown By Category 226 WECC v1.7 Steam Coal 18.6% Nuclear 3.9% Steam Other.2% Combined Cycle 28.6% Combustion Turbine 4.% IC.1% Other.% DG/DR/EE Incremental 3.% Biomass RPS 2.1% Geothermal 3.1% Solar 4.2% Small Hydro RPS.4% Energy Storage.3% Wind 7.2% Conventional Hydro 24.1% There have been several changes that impacted the generation mix in the 226 dataset versus the 224 common case dataset. A comparison of the annual generation for the two datasets (224 vs. 226) is shown in Figure 6. The most notable differences are listed below. The reduction in coal fired generation due to unit retirements and displacements. 7 The effect of the retirement of the Diablo Canyon nuclear plant in northern California is also evident with a reduction in nuclear energy. A continued shift in renewable generation assumptions due to cost reductions in solar power. There was a 4.9 percent decrease in total generation between the 224 Common Case and the 226 Common Case, largely due to revised load growth assumptions in a few areas. 7 Coal generation displacement was primarily due to implementation of carbon taxes in Alberta, British Columbia, and California, and increased penetrations of renewable resources.

12 226 PC1 Common Case Report DRAFT 9 Figure 6: Annual Generation by Category (224 vs 226) Annual Generation by Category (GWh) 224 PC1 v WECC v1.7 Conventional Hydro Energy Storage Steam Coal Steam Other Nuclear Combined Cycle Combustion Turbine IC Other DG/DR/EE Incremental Biomass RPS Geothermal Small Hydro RPS Solar Wind 5, 1, 15, 2, 25, 3, 35, CO2 Emissions The annual CO 2 emissions in the 226 common case were 12 percent (44 million metric tons) lower than in the 224 common case. Some of the obvious drivers are listed below: 1. The retirement of additional coal fired generation 2. Carbon prices added for Alberta and British Columbia, and increased in California. 3. The reduced overall energy load. 4. The increased amount of renewable generation. Transmission congestion 8 There was minimal transmission congestion in the 226 Common Case. The paths with reduced congestion relative to historical or interesting flow variations are: Northwest to California: The flows on paths 65 (PDCI) and 66 (COI) decreased due in part to the implementation of the California Global Warming Solutions Act (AB32) that places a financial 8 Congestion refers to a condition where the flow may have been higher if not for a defined limit.

13 226 PC1 Common Case Report DRAFT 1 penalty on imports of electrical power to California, except for surplus hydro generation from Bonneville Power Authority (BPA). Utah to California: The primary delivery path between Utah and California is the path 27 HVDC line. This was originally built to deliver the output from the Intermountain Power Project (IPP) to the California participants. In the 226 Common Case, the CO 2 cost penalties from AB32 have a substantial impact on the dispatch of the IPP units and on the utilization of path 27. In the ten year horizon for the 226 Common Case, the changes in load and generation were not expected to create congestion on the major WECC paths due to: The inclination for developers to build gas fired generation near the load centers, and renewable resources in state with access to local transmission. The projected transmission build out in the CCTA (see Figure 8).

14 226 PC1 Common Case Report DRAFT 11 Additional Discussion of Input Assumptions and Study Results A more detailed accounting of the study limitations, input assumptions, and results from the 226 Common Case is presented in the following sections. Study Limitations PCM Solution: The solution from the PCM is subject to the input assumptions and overriding leastcost objective. The case provides a high level view of generation dispatch and transmission utilization that can be compared to other study cases and sensitivity cases to formulate hypotheses and conclusions. Local Dispatch: The TEPPC study work is designed to investigate transmission utilization across the entire Western Interconnection, with a focus on interregional transmission. A production cost simulation that converges to a least cost WECC wide solution within the constraints and assumptions may not produce the expected results for an individual area or region. Local Congestion: There is a potential to create local congestion on area branches when adding generation to an area. A portion of the generator s output can become undeliverable and create dump energy. 9 There are a few instances where this has occurred in the common case, and these may be addressed in a future release. Load Shapes: The hourly load shapes for each load area are based on the actual hourly loads from 29. This may overlook the more recent impacts from demand response, energy efficiency, electric vehicle charging and behind the meter (BTM) generation such as rooftop solar. Dataset Updates The TEPPC PCM datasets are used by several stakeholders for conducting their own studies. There was agreement during the initial stages of the 226 common case development for the dataset to be released at different phases of development. Each subsequent release included improvements and changes that were identified by the various stakeholder groups. This process may continue such that it will be necessary to reference the version number of the common case in all relevant communications regarding the TEPPC 226 Common Case. 9 Dump energy is generation that would have been dispatched if not for a constraint such as a transmission limit.

15 226 PC1 Common Case Report DRAFT 12 Summary Inputs and Assumptions The detailed input assumptions are provided in a separate document of release notes. 1 A few of the assumptions are listed in relevant sections below to provide a basis for the enclosed results. Load Topology Each of the WECC Balancing Authorities (BA) provides a ten year forecast of their monthly peak and energy loads each year. A few of the BAs provide a more granular breakdown to support the TEPPC load topology as shown in Figure 7. The forecasts that were submitted in March 215 were used for the 226 Common Case, except for Alberta Electric System Operator (AESO) and the California Independent System Operator (CAISO) which provided key updates to their forecasts. Figure 7: TEPPC Load Area Topology Common Case & Release Notes

16 226 PC1 Common Case Report DRAFT 13 Changes in Load The primary factors driving the reduction in the overall energy load of the 226 common case compared to the 224 common case are: Factors for load reduction ( ) Amount (MWh) Decreases in load forecasts, especially in California and Alberta 27,61,139 Increase in Distributed Generation, Demand Response, and Energy Efficiency 12,522,889 Reduced forecasts of exports to MRO and SPP in the Eastern Interconnection 5,364,72 Reduced energy storage load (charging, compressing, pumping) 3,432,61 One less day as 224 was a leap year 2,75,585 Total 51,131,943 Transmission Network The transmission network was derived from the TSS 225 HS1 heavy summer power flow base case and updated as described in the release notes. The future projects that were either retained from the base case or added per stakeholder review are listed in Figure 8. Note that 3 out of the 16 projects are under construction.

17 226 PC1 Common Case Report DRAFT 14 Figure 8: 226 Common Case Transmission Projects Other study specific transmission projects will be added or removed as requested in the studies outlined in the 216 Study Program. Generation Resources There have been several changes to the generation assumptions since the 224 case was developed in 214. A few examples are highlighted below. Decision by Pacific Gas & Electric to retire the Diablo Canyon nuclear power plant in 225. Revised retirement plans for coal fired generation that removed over 27 MW of additional coal fired capacity. Revised OTC compliance schedule and replacement plan for California. True up of the renewable generation to ensure compliance with state Renewable Portfolio Standards (RPS) requirements as a function of the new annual energy loads for 226.

18 226 PC1 Common Case Report DRAFT 15 Addition of gap generation where needed to meet the expected peak demand and planning reserves. The changes in generation capacity by state/province and category are provided in Figure 9. The load modifiers are excluded from the graph. Figure 9: Change in Generation Capacity 2, Generation Additions (MW) from , 1, 5, (5,) (1,) (15,) Wind Solar Small Hydro RPS Geothermal Biomass RPS IC Combustion Turbine Combined Cycle Nuclear Steam Other Steam Coal Energy Storage Conventional Hydro (2,) AZ CA CO ID MT NM NV OR UT WA WY NE SD TX AB BC MX Intermountain Generating Station The participants in the Intermountain Generating Station (IGS) are currently negotiating an agreement that would retire both coal fired units in 225 or 226. The agreement also includes replacement generation consisting of two 6 MW combined cycle units that would be completed prior to the shutdown of IGS.

19 226 PC1 Common Case Report DRAFT 16 In the 226 Common Case the IGS coal fired generation is not retired, and assumed to be available for commitment and dispatch. Provided that the required State Implementation Plan (SIP) agreements are in place, the IGS plans will be incorporated into the common case used for the 217 TEPPC study program. Renewable Generation The development of renewable resources in the Western Interconnection is moving forward at an accelerated pace. However, the information about future projects is generally not announced until a few years prior to commercial operation. It is often necessary to estimate the amount and location of projects that will be required to meet the state RPS targets. The chart in Figure 1 represents a combination of existing projects, near term projects under development, and estimated projects. Figure 1: Renewable Generation Capacity Projections 7, Cumulative Net Capacity by Year (MW) 6, 5, 4, 3, 2, Wind Solar Small Hydro RPS Geothermal Biomass RPS 1,

20 226 PC1 Common Case Report DRAFT 17 Load Modifiers Several adjustments to the forecasted loads are modeled in the 226 Common Case to represent anticipated distributed generation (DG), energy efficiency (EE), and demand response (DR). Rather than apply these changes to the loads, it is more convenient from an accounting perspective to model them as generators. Under this methodology they reduce the amount of load that must be served by other resources. The total energy from the load modifiers is 3,44 GWh, which is broken down in Table 5. The distributed generation is entirely represented as behind the meter rooftop solar photovoltaic (PV). More information regarding these load modifiers can be found in the release notes. Table 5: Load Modifiers Modeled as Generators (GWh) State Distributed Generation Demand Response Energy Efficiency AZ 4, CA 22, CO 1, ID MT 45 NM 58.1 NV OR 14.5 UT WA WY 17 Total 29, Overriding Assumptions The majority of the data inputs are based on information provided by the Balancing Authorities and Planning Authorities in WECC; however, there are some issues that require the application of additional assumptions to model a ten year horizon case. Some of these key assumptions are listed below and a complete list of the assumptions can be found in the 226 Common Case Release Notes. State RPS assumptions: The BAs intend to comply with the Renewable Portfolio Standards (RPS) for the loads in the state(s) that they serve. The RPS standards are usually set as a percentage of retail sales. For example, a BA with annual retail sales of 1, MWh in a state with an RPS of 25 percent, would be expected to serve 25, MWh with renewable generation. Per the agreed upon

21 226 PC1 Common Case Report DRAFT 18 process, if the qualifying renewable generation in a state is deficient, additional resources are selected from the generation in the next class(es) 11 of generation. BA Reserve Requirements: The BAs intend to meet their projected loads and reserve requirements. Resources are selected from the class portfolios in order of class, until the RPS requirement is met and the load and reserve are met. Bilateral and Multi lateral power contractual arrangements: Although many of the of the contractual arrangements between Generator Owners and Load Serving Entities (LSE) are modeled, there is a significant portion that are not modeled. Operating conditions: Several operating constraints that restrict certain aspects of the transmission system are modeled using nomograms. Key Data and Modeling Improvements A summary of the key data and modeling improvements for the 226 Common Case is provided below. The complete list of improvements with detailed explanations can be found in the release notes. Reserve Topology: The FERC 789 rules for reserve requirements were incorporated into the 226 common case. Minimum Local Generation: A recommendation from the CAISO was implemented that models a requirement that certain combined cycle units be committed to provide frequency response for the CAISO footprint. Nomograms are used to implement this requirement. Back to Back DC Ties: The expected interchange with the Eastern Interconnection via the DC ties was assumed to be zero at all locations. Generator Cost Parameters: Volunteers from the California Energy Commission and ColumbiaGrid used publicly available data to develop new heat rate curves for many of the key thermal generators in WECC. Additional Study Results Other results of interest from the 226 Common Case study are provided below, including generation results by state/province for the whole year and for the peak hour, transmission path utilization, and an analysis of California imports. 11 The established classes are: existing, under construction, approved and/or financed, and future conceptual.

22 226 PC1 Common Case Report DRAFT 19 Generation by State/Province The generation results are reported here by their geographical location. The annual (geographical) generation by state/province and fuel is provided in Figure 11. Figure 11: Annual Generation by State and Fuel 3, 25, 2, 15, 1, Annual Generation (GWh) by State and Fuel 226 WECC v1.7 Other Thermal Energy Storage Other Renewable Wind Solar Nuclear Hydro Gas Coal 5, AB AZ BC CA CO ID MT MX NE NM NV OR SD TX UT WA WY Clearly, the generation from many resources is contractually 12 committed to LSEs in other states or provinces; however, the associated contracts and their details are often not publicly available to provide a complete representation. Renewable Energy Targets There are ten states/provinces in WECC that have Renewable Portfolio Standards (RPS), namely, Alberta, Arizona, California, Colorado, Montana, New Mexico, Oregon, Utah, and Washington. The estimated amount of renewable energy that would be required for the RPS requirements in 226 is roughly 2, GWh. As explained in the release notes, several of the RPS states have set limits on how much of the RPS energy must be produced locally, versus how much can be imported in the form of energy delivered or Renewable Energy Credits (REC). Two primary goals behind the limits are to protect in state employment and generate tax revenue. 12 Data for known contracts is represented in the dataset and the associated units are exempted from wheeling charges.

23 226 PC1 Common Case Report DRAFT 2 Peak Hour Breakdown Based on the current assumptions for the 226 Common Case, the coincident peak demand occurs on July 27, 226 at 4: pm, with generation shares as shown in Figure 12. The contribution from renewable resources is approximately 12. percent. Figure 12: Peak Hour Generation Generation at Peak Hour Other.5% Wind 2.2% Steam Other.5% Biomass RPS 1.8% Combined Cycle 32.% Steam Coal 15.1% Combustion Turbine 8.6% Small Hydro RPS.3% Solar 5.6% Nuclear 3.% Geothermal 2.1% Hydro+ES 25.1% DG/DR/EE 3.2% A ten day snapshot of the hourly generation by category that includes the peak hour is presented in Figure 13. For WECC overall, the primary resource types that follow the load are hydro, combined cycle, combustion turbine, and solar The majority of the solar generation in the common case is photovoltaic and the electrical output is a function of the solar intensity that may not coincide with the load ramps.

24 226 PC1 Common Case Report DRAFT 21 Figure 13: Ten day Snapshot of Hourly Generation WECC MW 18, 16, 14, 12, 1, 8, 6, 4, 2, WECC Load/Gen Balance Snapshot 226 PC1 v DG/DR/EE Other Combustion Turbine Steam Other Combined Cycle Small Hydro RPS Biomass RPS Hydro+ES Solar Wind Geothermal Steam Coal Nuclear Demand 7/2/226 7/21/226 7/22/226 7/23/226 7/24/226 7/25/226 7/26/226 7/27/226 7/28/226 7/29/226 Dump Transmission Path Flows The bulk transmission system in the Western Interconnection has evolved over time, but still serves the purpose of delivering generation to load. The major generation and major load centers are easy to find on a transmission map as they are connected by major transmission lines. The generation has historically been sited near the major fuel sources; water, coal, oil, or geothermal. Gas generators have been sited near the gas pipelines, wind generators near the windy locations, and solar generation near the Sunbelt. This trend is expected to continue even as the generation mix transforms to meet state and federal regulations. The most heavily utilized paths for the 226 Common Case are shown in Figure 14. The graph is color coded by utilization metric to show the path flow results and screening thresholds. 14 The utilization metrics are sorted according to the U9 metric 15. A leading minus sign in the path name indicates that the predominant path flow is in the reverse direction. Congestion on the paths is mostly indicated by the U99 metric since this means that a path is operating at its rated limit. 14 TEPPC has set screening thresholds for the utilization metrics such that a path is considered heavily utilized and possibly congested if the flow is greater than or equal to 75% of its limit for more than 5% of the year; or greater than or equal to 9% for more than 2% of the year; or greater than or equal to 99% for 5% of the year. 15 The U75, U9, and U99 metrics have reference to the path flow thresholds (i.e. 75% of the path limit, etc.)

25 226 PC1 Common Case Report DRAFT 22 Figure 14: Most Heavily Utilized Paths 224 Common Case Most Heavily Utilized Paths 26PC1_1_7 226 Common Case v1.7 U75 U9 U99 6% 5% Percent of Hours 4% 3% 2% 1% % By the TEPPC definitions, there are no heavily utilized paths in the 226 common case. Some possible reasons for this are: Retirements of remote generation Emphasis on renewable generation, often local as conditions warrant. Carbon prices that change the economics of off peak coal generation. Other Paths One of the validation steps for the PCM datasets is a comparison of the path flow results to the actual path flows from historical years. The following examples employ a duration plot summary methodology to compare the study results to historical years 21 and 212, and also to the 224 Common Case. Note that validation against historical years may not be relevant where significant changes associated with policy decisions impact the simulation results. A few path duration plots are presented next, along with a short leading statement.

26 226 PC1 Common Case Report DRAFT 23 The results for path 3 in Figure 15 show a good correlation to historic flows. Figure 15: Path 3 4 P3 Northwest British Columbia Path Duration Plots 3 2 Megawatts Net GWh: _PC1_1_5 226_PC1_1_7 The results for path 26 show a good match to historical. Figure 16: Path 26 5 P26 Northern Southern California Path Duration Plots Megawatts Net GWh: _PC1_1_5 226_PC1_1_7 The impact of the California Global Warming Solutions Act (AB32) is evident in the path flow results for path 27 in Figure 17. The carbon price adder reduces the economics of the Intermountain coal plant.

27 226 PC1 Common Case Report DRAFT 24 Figure 17: Path 27 3 P27 Intermountain Power Project DC Line Path Duration Plots Megawatts Net GWh: _PC1_1_5 226_PC1_1_7 The energy deliveries on path 46 were lower than historical, likely impacted by the renewable buildout in California as well as the effects of AB32. Figure 18: Path P46 West of Colorado River (WOR) Path Duration Plots 1 5 Megawatts Net GWh: _PC1_1_5 226_PC1_1_7 The results for the combination of Path 65 (PDCI) and Path 66 (COI) in Figure 19 have raised some concerns because the flows are lower than historical and also flow south to north for 1 percent of the year.

28 226 PC1 Common Case Report DRAFT 25 Figure 19: Path xy COI plus PDCI Path Duration Plots 6 4 Megawatts Net GWh: _PC1_1_5 226_PC1_1_7 Each of the results for paths 27, 46, 65 and 66 show various amounts of reverse flow. This is interesting because these paths all tie into California, which has been a net importer for many years. The average annual hourly flow for path 66 depicted in Figure 2 suggests that California is finally exporting its sunshine in the form of solar photovoltaic energy. Figure 2: Path 66 Hourly Average Average Flow by Hour (MW) P66 COI Annual _PC1_1_7 3,5 3, 2,5 2, 1,5 1, 5 5 1, The average hourly flow on path 66 for each month is provided in Figure 21. Note that on average the generation surplus occurs in March, April, May, September, October, November, and December.

29 226 PC1 Common Case Report DRAFT 26 Figure 21: Path 66 Hourly Average by Month Average Flow by Hour (MW) P66 COI January Average Flow by Hour (MW) P66 COI February _PC1_1_ _PC1_1_7 3, 3, 2,5 2,5 2, 2, 1,5 1,5 1, 1, Average Flow by Hour (MW) P66 COI March Average Flow by Hour (MW) P66 COI April _PC1_1_ _PC1_1_7 3, 2,5 2, 1,5 1, 5 5 1, 1, , 3, 2, 1, 1, 2, 3, Average Flow by Hour (MW) P66 COI May Average Flow by Hour (MW) P66 COI June _PC1_1_ _PC1_1_7 4, 3,5 3, 2,5 2, 1,5 1, 5 5 1, ,5 4, 3,5 3, 2,5 2, 1,5 1, Average Flow by Hour (MW) P66 COI July Average Flow by Hour (MW) P66 COI August _PC1_1_ _PC1_1_7 4,5 4, 4, 3,5 3,5 3, 3, 2,5 2,5 2, 2, 1,5 1,5 1, 1, Average Flow by Hour (MW) P66 COI September Average Flow by Hour (MW) P66 COI October _PC1_1_ _PC1_1_7 3,5 3, 2,5 2, 1,5 1, 5 5 1, , 2,5 2, 1,5 1, 5 5 1,

30 226 PC1 Common Case Report DRAFT 27 Average Flow by Hour (MW) P66 COI November Average Flow by Hour (MW) P66 COI December _PC1_1_ _PC1_1_7 4, 3,5 3, 2,5 2, 1,5 1, 5 5 1, , 2,5 2, 1,5 1, If we just look at California s load/gen balance, the hourly difference represents the hourly interchange as shown in Figure 22. The pattern generally matches what we observed on the COI flows, and a tenday snapshot in April (Figure 23) provides more details behind the generation surplus. Although California is importing an average of nearly 62 MW, the high solar output creates an interesting reversal pattern for several days of the year. Figure 22: Hourly California Net Interchange Calif Interchange Balance (gen load) 226 PC1 v (MW) 15 Average is 6156 MW

31 226 PC1 Common Case Report DRAFT 28 Figure 23: April Snapshot for California MW Calif Load/Gen Balance Snapshot 226 PC1 v , 4, 35, 3, 25, 2, 15, 1, 5, 4/6/226 4/7/226 4/8/226 4/9/226 4/1/226 4/11/226 4/12/226 4/13/226 4/14/226 4/15/226 DG/DR/EE Other Combustion Turbine Steam Other Combined Cycle Small Hydro RPS Biomass RPS Hydro+ES Solar Wind Geothermal Steam Coal Nuclear Demand Dump The California imports include output from several jointly owned projects and large scale purchases, including shares of Agua Caliente, Apex, Arlington Valley, Arlington Wind, Big Horn, Copper Mountain Solar, Desert Star, Dixie Valley, Don A. Campbell Geothermal, ESJ Wind, Glacier Wind, Hoover, Horseshoe Bend, Hurlburt Wind, Intermountain Generating Station, Klondike Wind, La Rosita, Leaning Juniper Wind, Linden Wind, Mesquite Solar, Milford Wind, Palo Verde, Parker Dam, Pebble Springs Wind, Simpson Tacoma, Star Point Wind, Termo Mexicali, Tuolumne Wind, Vantage Wind, Willow Creek Wind, and Windy Flats. The delivery of a few of these projects is encouraged in the PCM by exempting them from wheeling charges and assigning the participants in the reserve distribution table. However, the commitment and dispatch in California does require sufficient local resources to provide frequency response, inertia, and voltage support. Conclusions and Observations The portion of the annual WECC generation by renewable resources in the 226 Common Case was 19.9 percent, including the incremental distributed solar resources. This represents an increase of 2.6 percent from the 224 Common Case. The model seems to manage the duck curve in California quite easily, perhaps by using imports to supplement the morning and evening ramps. Operational challenges are making it difficult for some owners of large combined cycle facilities to remain profitable, and more power market related issues like Sutter and La Paloma could be coming.

32 226 PC1 Common Case Report DRAFT 29 Currently the development of hourly load forecasts for each load area involves the application of historical hourly shapes from a single year to the firm 16 monthly peak and energy forecasts. The process introduces some errors due to changes in long term trends (29 vs. 226) and actual year anomalies, although the tool has different options that can correct some of the errors. The failure of the process often leads to clipping of the peaks or valleys, shifts up or down, abnormal load factors, and/or large daily swings (see Figure 25 for an example). In the future, stakeholders may want to consider other methodologies for adding hourly shapes to the monthly peak and energy forecasts. Perhaps something that is more in line with how load forecasts are actually developed by the BA s and LSE s, where multiple years of data are used and random anomalies are filtered out. As mentioned at the beginning of the report, the GridView Look ahead logic was not turned on for this case. While there are advantages to using this capability, the calculations are impacted by the generator cost parameters that have not been reviewed since 212. One of the expected improvements of using the look ahead logic is better utilization of the energy storage resources. In the example in Figure 24, the energy storage appears to be supporting the afternoon ramps as the solar output falls. Perhaps the look ahead would increase the storage, and provide for additional displacement of combustion turbine units. Figure 24: Energy Storage Peak Week Energy Storage (MW) WECC 4, 3, 2, 1, 1, 2, 3, 7/2/226 7/21/226 7/22/226 7/23/226 7/24/226 7/25/226 7/26/226 7/27/226 7/28/226 7/29/226 The concerns about the south to north flows on path 66 are hopefully alleviated by some of the analysis presented above. The periods of surplus generation in California are associated with the daily ramp up of solar generation, and a region with very few solar resources such as the northwest is a good market for any surplus. 16 The forecasts include firm and non firm components of demand and energy. By only using the firm component WECC is assuming that the non firm customers will not be served.

33 226 PC1 Common Case Report DRAFT 3

34 226 PC1 Common Case 31 Appendix A Additional Tables and Charts Table 6: Cumulative Capacities (MW) by Type and Year Pre Conventional Hydro 64,31 64,188 64,346 64,72 65,585 66,87 67,134 67,168 67,8 67,17 66,919 66,91 66,91 68,15 68,5 68,5 68,5 Energy Storage 4,738 4,758 4,778 4,943 4,943 4,943 6,228 6,228 6,228 6,228 6,228 6,228 6,228 6,228 6,228 5,864 5,864 Steam Coal 37,927 38,569 38,55 37,73 37,312 36,858 36,498 34,822 34,492 32,874 31,619 31,365 3,651 3,651 29,61 28,757 27,989 Steam Other 19,2 18,86 18,389 16,853 15,792 14,463 14,392 1,73 1,947 1,947 4,826 4,713 4,639 3,479 3,269 2,939 2,939 Nuclear 9,632 9,632 9,632 7,482 7,482 7,482 7,482 7,482 7,482 7,482 7,482 7,482 7,482 7,482 7,482 5,82 5,82 Combined Cycle 5,475 51,277 52,331 53,725 55,27 58,666 59,6 6,623 62,151 62,71 63,994 64,54 64,798 65,75 64,955 64,955 64,955 Combustion Turbine 2,526 21,643 22,393 25,186 26,172 27,61 3,167 3,934 31,933 32,2 32,32 32,132 32,132 34,336 34,336 34,198 33,958 IC ,48 1,48 1,48 1,48 1,48 1,48 1,48 1,48 1,48 1,48 1,48 1,48 Other 1,33 1,33 1,33 1,33 1,33 1,33 1,33 1,33 1,33 1,33 1,33 1,33 1,33 1,33 1,33 DG/DR/EE Incremental ,286 21,286 21,286 21,286 Biomass RPS 2,643 2,847 3,15 3,291 3,49 3,62 3,637 3,637 3,637 3,637 3,613 3,513 3,513 3,834 3,834 3,794 3,794 Geothermal 2,98 3,43 3,181 3,48 3,448 3,483 3,518 3,494 3,475 3,475 3,51 3,51 3,51 4,5 4,5 4,85 4,85 Small Hydro RPS 1,159 1,174 1,174 1,174 1,174 1,181 1,181 1,181 1,181 1,181 1,116 1,116 1,116 1,116 1,116 1,116 1,116 Solar 741 1,36 2,335 5,569 7,28 9,282 1,949 11,28 11,437 11,517 11,597 11,625 11,639 17,758 17,773 17,765 17,745 Wind 13,227 15,498 2,555 22,462 24,522 25,934 27,19 27,499 29,321 29,521 29,521 29,52 29,52 3,587 3,587 29,725 29,725

35 226 PC1 Common Case Report DRAFT 32 Figure 25: Failure of Load Shaping PSEI 29 actual PSEI 226 v