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Summary of Observations—2016–2017 Study Program
System Adequacy Planning (SAP) DepartmentOctober 12, 2018
155 North 400 West, Suite 200
Salt Lake City, Utah 84103-1114
2018 SAP Summary Report 1
Table of Contents
1. Introduction.......................................................................................................... 3
2. Context................................................................................................................. 4
2.1 2016—The Current World...........................................................................................................4
2.1.1. 2016 Loads...........................................................................................................................4
2.1.2 2016 SOTI Generation..........................................................................................................5
2.1.3 2016 Transmission...............................................................................................................5
2.2. 2026—The 10-Year Planning Horizon.........................................................................................6
2.2.1. 2026 Loads...........................................................................................................................6
2.2.2. 2026 Generation..................................................................................................................6
2.2.3. 2026 Transmission...............................................................................................................8
2.3. 2034—Plausible Futures............................................................................................................. 9
3. Year 10 Production Cost Model Studies...............................................................11
3.1 Year 10 PCM Study Cases..........................................................................................................11
3.2 Modeling Approach...................................................................................................................13
3.2.1 Load Topology....................................................................................................................14
3.2.2 Transmission Topology......................................................................................................15
3.2.3 Generation Resources........................................................................................................15
3.2.4 Other Assumptions............................................................................................................16
3.3 2026 Common Case.................................................................................................................. 17
3.3.1 Resource Mix..................................................................................................................... 18
3.3.2 Transmission Utilization.....................................................................................................18
3.4 Year 10 Summary Observations................................................................................................20
4. Year 20 Capital Expansion (CapEx) Model Studies................................................20
4.1 Year 20 Capital Expansion Studies.............................................................................................21
4.1.1 Modeling Approach........................................................................................................... 22
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4.2 2034 Reference Case.................................................................................................................25
4.2.2 CO2 Emissions.....................................................................................................................27
4.2.3 Water Consumption...........................................................................................................28
4.2.4 Levelized Cost of Energy....................................................................................................29
4.2.5 Resource Cost Observations..............................................................................................34
4.2.6 Transmission Utilization and Expansion Needs..................................................................35
4.3 Other Year 20 Study Cases........................................................................................................36
4.4 Year 20 Study Case Summary Observations..............................................................................43
5. NERC Long-Term Reliability Assessment..............................................................44
5.1 LTRA Results (2017)...................................................................................................................45
6. Overall Reliability Assessment Observations........................................................46
6.1 Potential Reliability Risks.......................................................................................................... 47
7. Recommendations for Future Reliability Assessments.........................................47
Appendix A: Glossary of Terms...................................................................................48
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1. Introduction
The Western Electricity Coordinating Council (WECC) promotes Bulk Electric System (BES) reliability in the Western Interconnection. WECC is the Regional Entity responsible for compliance monitoring and enforcement. In addition, WECC provides an environment for the development of Reliability Standards and the coordination of the operating and planning activities of its members, as set forth in the WECC Bylaws.
WECC is geographically the largest and most diverse of the eight Regional Entities with delegated authority from the North American Electric Reliability Corporation (NERC) and Federal Energy Regulatory Commission (FERC). WECC serves the Western Interconnection which extends from Canada to Mexico and includes the provinces of Alberta and British Columbia, the northern portion of Baja California, Mexico, and all or portions of the 14 Western states between.
Figure 1: NERC Interconnections
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WECC's System Adequacy Planning (SAP) department looks for potential reliability risks to the BES caused by changes in load, resource, and transmission topology in the next 10 to 20 years. The department develops an annual study program to answer reliability-related questions and to show opportunities for reliability improvement. The SAP department gives unbiased study program results to stakeholders and the public so that stakeholders can create region-specific solutions to the challenges facing the Western Interconnection.
2. Context
2016 is the base or reference year for the SAP’s 2016–2017 study program. Starting from the load, resource, and transmission topology conditions of 2016, the SAP department develops a two-year study program to better understand potential reliability risks in the 10- to 20-year planning horizon. The department applied various modeling tools and methods to evaluate changes to forecast loads, expected resources, and the transmission system; and to show the extent to which those changes might affect the reliability of the Western Interconnection.
2.1 2016—The Current World
Each year, WECC prepares the “State of the Interconnection” (SOTI) report to give a high-level look at the Western Interconnection. Among other information, the report includes data on loads, resources, and transmission. The following load, resource, and transmission information was taken from the 2017 State of the Interconnection report.
2.1.1. 2016 Loads
Table 1: 2016 Loads
2016 Load Summary
Peak Demand: 157,000 MW
Total Energy: 879,000 GWh
Over the last several years, annual energy consumption has changed in response to various factors which are driving demand, including fluctuations in weather patterns and economic conditions. For example, installed capacity of rooftop solar in the Western Interconnection increased by 85 percent during 2014 and 2015 and, as of December 2015, was 4,679 MW of installed capacity. Rooftop solar decreases the effective load by reducing consumption when the rooftop solar panels are producing electricity. Rooftop solar production creates operational challenges because it is “behind-the-meter”; it cannot be measured or dispatched by system operators, but its variability must be balanced by other resources.
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2.1.2 2016 SOTI Generation
Table 2: 2016 Generation Summary
2016 Generation Summary
Nameplate Capacity: 267,073 MW
Net Generation
Fossil Fuels: 401,850 GWh 55%
Hydro: 173,192 GWh 24%
Renewables: 93,211 GWh 13%
Nuclear: 60,911 GWh 8%
The resource mix of the Western Interconnection is undergoing significant change. Environmental regulations and an aging fleet contribute to changes in coal capacity. Renewable portfolio standards (RPS) help drive development of wind and solar resources. Increased reliance on natural gas is changing how the gas and electric systems are operated.
Changes to the resource portfolio are altering the operational characteristics of the Interconnection. They lead to several challenges, including ensuring the resource portfolio gives enough voltage, frequency support, and ramping capability to balance generation and load. Without these essential reliability services (ERS), the grid cannot be run reliably.
As variable generation is added to the system, more ERS are needed. Sufficient resources with the flexibility to respond to sudden changes in generation and demand strengthen the grid. These services are needed both Interconnection-wide and locally.
2.1.3 2016 Transmission
Table 3: 2017 Transmission Summary
2017 Transmission Summary
Transmission Miles: 136,000
WECC Paths: 66
The Western Interconnection is characterized by long transmission lines connecting remote generation to load centers. Around 121,200 circuit-miles of transmission lines cross the Western Interconnection.
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2.2. 2026—The 10-Year Planning Horizon
The SAP department develops a database and associated assessment model to measure potential reliability risks 10 years in the future from the base year. Although it is not possible to exactly predict conditions 10 years in the future, this database—which shows the most likely combination of loads, resources, and transmission topology in 2026—is referred to as the 2026 Common Case. This database is a reference point for the BES in 2026. It is built from information provided by WECC’s stakeholders and is vetted through WECC’s stakeholder process. While the 2026 Common Case may not exactly match the conditions of the BES, the case still serves as the reference for planning studies. Individual components are described below. Further, reliability assessments based on this case are referred to as “Year 10” cases, as they examine a single year, 10 years in the future.
2.2.1. 2026 Loads
The annual energy consumed is expected to increase by 9.6 percent from 2015 to 2026 (compound annual increase of 0.8 percent), and the summer peak demand is expected to increase by 9.1 percent during that same period (compound annual increase of 0.8 percent).
Figure 2: Load Growth 2016 to 2026
800,000
820,000
840,000
860,000
880,000
900,000
920,000
940,000
960,000
980,000
1,000,000
1,020,000
150,000
152,000
154,000
156,000
158,000
160,000
162,000
164,000
166,000
168,000
170,000
172,000
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
Annu
al E
nerg
y (G
Wh)
Peak
Dem
and
(MW
)
Load Growth Forecast
Peak Demand (MW) Annual Energy (GWh)
2.2.2. 2026 Generation
The generation inputs for the 2026 Common Case show existing resources plus planned resource changes between 2015 and 2026. The total net capacity changes for each resource type are shown in Figure 3: Key Resource Net Capacity Change (MW) between 1/1/2016 and 12/31/2026, with a net capacity change of 12,706 MW (excluding the load modifiers). These changes are based on the
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Common Case input assumptions and may be different from the SOTI assumptions reported elsewhere in this report.
Coal retirements are based on data submissions and media announcements from the generator owners and Balancing Authorities (BA). Most of the Steam-Other retirements are associated with compliance agreements for the California Once-Through-Cooling (OTC) requirements.
The largest increase in the 2026 resource mix is in 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) generation. The additions for metered solar and wind are also significant and will be discussed in more detail later in this report.
Figure 3: Key Resource Net Capacity Change (MW) between 1/1/2016 and 12/31/2026
Conventional Hydro
Energy Storage
Steam - Coal
Steam - Other
Nuclear
Combined Cycle
Combustion Turbine
IC
Other
Biomass RPS
Geothermal
Small Hydro RPS
Solar
Wind
DG/DR/EE - Incremental
(15,000) (10,000) (5,000) 0 5,000 10,000 15,000 20,000 25,000
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Figure 4: Net Generation Capacity in 2026
Conventional Hydro23.4%
Energy Storage0.3%
Steam - Coal18.5%
Steam - Other0.2%
Nuclear3.9%
Combined Cycle27.8% Combustion Turbine
4.2%IC0.1%
DG/DR/EE - Incre-mental
3.0%Biomass RPS
2.2%
Geothermal3.1%
Small Hydro RPS0.3%Solar
3.7%
Wind9.2%
Generation Breakdown By Category - 2026 Common Case v2.0
2.2.3. 2026 Transmission
The WECC Transmission Project Information Portal (PIP) has publicly available project information for 98 transmission projects under development in the Western Interconnection. The Regional Planning Coordination Group (RPCG), a stakeholder group consisting of Western Planning Region (WPR) representatives, provides a list of "regionally significant” projects, known as the Common Case Transmission Assumptions (CCTA) that are expected to be in service 10 years after the reference year. The RPCG planned these projects using a transparent, consistent, and well-documented process that is open to all WECC stakeholders. The full CCTA report is posted here.
Projects included in the CCTA—and in the transmission topology used in the 2026 Common Case—are shown in Figure 5: Transmission Projects Added 2016-2026.
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Figure 5: Transmission Projects Added 2016-2026
2.3. 2034—Plausible Futures
As noted above, Year 10 reliability assessments examine the most likely set of loads, resources, and transmission topology 10 years in the future from the base or reference year. If such assessments find reliability risks that can be mitigated by transmission infrastructure enhancements, it is necessary to consider such enhancements promptly, since their design, authorization, and construction could take more than 10 years to complete. It is also necessary to consider potential reliability risks beyond 10 years in to the future.
WECC has a scenario development process for showing plausible futures 20 years from the reference year. This process identifies a focus question about reliability risks and drivers that will influence future conditions, then defines a few of plausible futures to help plan strategies to handle those risks. For the first scenarios, the focus question was, “How will demand for electric power services in the Western Interconnection change in the future (10–20 years), and how will electric power supply services (and related transmission networks) change to meet that demand?”
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In 2010-2012, WECC and its stakeholders defined four plausible futures, shown in the following matrix:
Figure 6: WECC Scenario Matrix
Scenario 1 is a future that includes high and widespread economic growth, but only evolutionary technological development. There is no overriding policy theme and the focus is on growth.
Scenario 2 includes high and widespread economic growth, and breakthrough and paradigm-changing technological developments. The policy theme is on reducing greenhouse gas emissions and on developing new technology.
Scenario 3 includes low and localized economic growth, combined with evolutionary technological development. Slow growth would be expected to lead to tough policy choices and keeping consumers’ rates low.
Scenario 4 is a future with low and localized economic growth, but with breakthrough and paradigm-changing technological developments. Policies would be expected to focus on capturing high return/low risk investments in clean energy technologies.
In 2015, WECC and its stakeholders defined a fifth scenario, the “Energy-Water-Climate Change Scenario” that considers the interaction of energy, water, and climate change and how that interaction may influence reliability.
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The original WECC Scenario Report and the Energy-Water-Climate Change Scenario are posted on the WECC website.
3. Year 10 Production Cost Model Studies
WECC’s reliability assessments in the Year 10 planning horizon use a Production Cost Model (PCM) to show resource dispatch needed to meet load for each of the 8,760 hours in the test year, in this instance, 2026 in the case of the Common Case used for this report. The transmission topology is limited to the current transmission system (i.e., transmission lines and substations) plus new transmission infrastructure that is expected to be completed within the planning horizon. Facilities determined to be “likely to be completed” are those included in the transmission plans developed by Regional Planning Groups (RPG) to fulfill their FERC Order 1000 obligations and in transmission plans developed by International Planning Regions (IPR).
3.1 Year 10 PCM Study Cases
In 2016, WECC and its stakeholders developed a study program that included the 2026 Common Case, and other study cases, to explore sensitivities around the Common Case; for example, high and low load levels, as well as other study cases that could impact reliability. In 2017, WECC augmented the Year 10 study cases included in its 2016 study program based on collaboration with stakeholders.
Year 10 PCM study cases included in the 2016–2017 study program include:
Sensitivity cases that examine the effects of increases and decreases in specific drivers, such as loads, hydro availability, natural gas prices, and CO2 prices;
Resource cases that examine specific changes to the resource mix in the Western Interconnection, such as increases to solar and wind energy penetration;
Transmission expansion cases that examine potential enhancements to inter-regional transmission capacity; and
Special interest cases that examine unique approaches, such as probabilistic assessment and addition of energy storage.
The following table shows the specific study cases in the 2016–2017 study program. Each study includes links to the scoping document and final report for each case. This report will not repeat specific findings of each study case. Rather, the following section shows overall observations spanning several study cases.
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Table 4: 2016–2017 Year 10 Study Cases
Study Case ID Description Final Report
2026 PC01 2026 Common Case—Version 1.7 Final Report
2026 PC01 Changes from Version 1.7 to (final) Version 2.0 Final Report
2026 PC02 Sensitivity Case—Increased Load Final Report
2026 PC03 Sensitivity Case—Decreased Load Final Report
2026 PC04 Sensitivity Case—Increased Hydro Final Report
2026 PC05 Sensitivity Case—Decreased Hydro Final Report
2026 PC06 Sensitivity Case—Increased Natural Gas Price Final Report
2026 PC07 Sensitivity Case—Decreased Natural Gas Price Final Report
2026 PC08 Sensitivity Case—Increased CO2 Price Final Report
2026 PC09 Sensitivity Case—Decreased CO2 Price Final Report
2026 PC11 High Coal Retirement / Low CO2 Future Final Report
2026 PC12 High Renewables / Low CO2 Final Report
2026 PC13 High Energy Efficiency (EE) Based on California Legislation
Final Report
2026 PC14 Probabilistic Study of High Renewables Final Report
2026 PC15 High Distributed Energy Resource (DER) Future Final Report
2026 PC16 Impacts of High Pumped Storage with High Renewables
Final Report
2026 PC17 Evaluation of Compressed Air Energy Storage (CAES) with High Renewables
Final Report
2026 PC18 Evaluation of Double CAES Capacity Relative to PC17 Final Report
2026 PC19 High Battery Electric Storage with High Renewables Final Report
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Study Case ID Description Final Report
2026 PC20 High Energy Storage that Integrates CAES and Battery Storage
Final Report
2026 PC21 High Additions of Wind Energy in New Mexico and Wyoming
Final Report
2026 PC22 High Increases of Renewable Energy in Southern California and the Southwest Region
Final Report
2026 PC23 Increased Renewable Energy in Northern California and the Northwest Region and High Hydro Availability
Final Report
2026 PC24 Decommissioning of Eldorado-Moenkopi 500-kV Transmission Line
Final Report
2017 PC02 High Wind Energy Portfolio in Wyoming, Montana, and New Mexico
Final Report
2017 PC03 High Solar Energy Portfolio Final Report
2017 EC01 High Wind Energy Portfolio with Enhanced East-to-West Inter-Regional Transmission Capacity
Final Report
2017 EC02 High Wind Energy Portfolio with Enhanced Northeast-to-Southwest and Central Inter-Regional Transmission Capacity
Final Report
2017 EC03 High Solar Energy Portfolio with Enhanced Transmission Backbone
Final Report
2017 EC04 Investigation of Potential Prices for Curtailing Renewable Resources
Final Report
3.2 Modeling Approach
Detailed input assumptions for the Year 10 assessments are given in a separate document of release notes. 1 A few of the assumptions are listed below to give a basis for the assessment results.
1 2026 Common Case & Release Notes
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3.2.1 Load Topology
Each of the WECC BAs provides a 10-year forecast of their monthly peak and energy loads each year. A few of the BAs provide a more detailed breakdown to support the Transmission Expansion Planning Policy Committee (TEPPC) load topology as shown in Figure 7: Common Case Load Topology. The forecasts submitted in March 2015 were used for the 2026 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: Common Case Load Topology
The primary factors driving the reduction in the overall energy load of the 2026 Common Case are compared to the 2024 Common Case in the following table.
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Table 5: Common Case Load Adjustments
Factors for load reduction (2024 → 2026) Load Change (MWh)Decreases in load forecasts, especially in California and Alberta
-27,061,139
Increase in Distributed Generation, Demand Response, and Energy Efficiency
-12,522,889
Reduced exports to MRO and SPP in the Eastern Interconnection
-5,364,720
Reduced energy storage load (charging, compressing, pumping)
-3,432,610
One less day as 2024 was a leap year -2,750,585
Total: -51131943
3.2.2 Transmission Topology
The transmission network used in the 2026 Common Case was derived from the TSS 2025-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 were listed previously in Figure 5: Transmission Projects Added 2016-2026. Note that three out of the 16 projects are under construction.
Other study-specific transmission projects were added or removed as requested in the studies outlined in the 2016 Study Program.
3.2.3 Generation Resources
There have been several changes to the generation assumptions since the 2024 Common Case was developed in 2014. A few examples are highlighted below.
Decision by the Pacific Gas and Electric Company (PG&E) to retire the Diablo Canyon nuclear power plant in 2025.
Revised retirement plans for coal-fired generation that removed over 2,700 MW of additional coal-fired capacity.
Revised OTC compliance schedule and replacement plan for California.
Renewable generation made compliant with state RPS requirements as a function of the new annual energy loads for 2026.
Addition of gap generation to meet peak demand and planning reserves.
The changes in generation capacity by state/province and category are provided in Figure 8: 2026 Common Case Resource Additions by State/Province. The load modifiers are excluded from the graph.
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Figure 8: 2026 Common Case Resource Additions by State/Province
(20,000)
(15,000)
(10,000)
(5,000)
0
5,000
10,000
15,000
20,000
AZ CA CO ID MT NM NV OR UT WA WY NE SD TX AB BC MX
Generation Additions (MW) from 2015 - 2026
Wind
Solar
Small Hydro RPS
Geothermal
Biomass RPS
IC
Combustion Turbine
Combined Cycle
Nuclear
Steam - Other
Steam - Coal
Energy Storage
Conventional Hydro
3.2.4 Other Assumptions
The majority of the data inputs for the 2026 Common Case are based on information provided by BAs and Planning Authorities in WECC. However, there are some issues that require additional assumptions to model a 10-year horizon case. Some of these assumptions are listed below. A complete list of the assumptions can be found in the 2026 Common Case Release Notes.
State RPS assumptions: Western Interconnection utilities intend to comply with the RPSs for the loads in the state(s) that they serve. RPSs are usually set as a percentage of retail sales. For example, a BA with annual retail sales of 100,000 MWh, in a state with an RPS of 25 percent, would be expected to serve 25,000 MWh with renewable generation. Per the agreed-upon process, if the qualifying renewable generation in a state is deficient, additional resources are selected from the generation in the next class(es) of generation (see Table 6: Resource Construction Classifications).
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BA Reserve Requirements: The utilities 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 multilateral power contractual arrangements: Although many of the contractual arrangements between Generator Owners (GO) and Load-Serving Entities (LSE) are modeled in the 2026 Common Case, a significant portion is not modeled.
Operating conditions: Several operating constraints that restrict certain aspects of the transmission system are reflected in the modeling.
Table 6: Resource Construction Classifications
Class Definition Description
1 Existing Resources that currently exist.
2 Under Construction Resources that are under construction
3 Approved and/or Financed
Resources that are not yet under construction, but for which construction is approved and/or financed.
4 Conceptual Resources that are neither approved nor financed, but could be developed within the time frame specifed by the RPS
3.3 2026 Common Case
In 2016, WECC developed a study program that included study cases analyzed with a PCM. Study cases for the Year 10 time horizon evaluate the effects that existing and future energy policies and external drivers, such as technology changes, may have on transmission needs and costs in the Western Interconnection. All Year 10 studies use the 2026 Common Case as a starting point. The 2026 Common Case is based on stakeholder-provided assumptions about loads, generation, and transmission.
WECC’s Year 10 study program seeks to answer two primary questions. Given the expected loads, resources, and transmission topology 10 years in the future from the reference year:
1. What would be the expected resource mix? and
2. Which paths might experience high use?
The following are summaries of results that address those questions.
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3.3.1 Resource Mix
The load, resource, and transmission topology inputs for versions 1.7 and 2.0 of the 2026 Common Case produced the following resource mix:
Figure 9: 2026 Common Case Resource Mix
Conventional HydroEnergy Storage
Steam - CoalSteam - Other
NuclearCombined Cycle
Combustion TurbineIC
OtherDG/DR/EE - Incremental
Biomass RPSGeothermal
Small Hydro RPSSolarWind
0 50,000,000 100,000,000 150,000,000 200,000,000 250,000,000 300,000,000
Annual Generation by Category (GWh)2026 WECC v2.0
The portion of the 2026 resource mix due to renewable resources (20.2 percent) reflects the growing penetration of wind and solar resources in the generation profile of the Western Interconnection.
3.3.2 Transmission Utilization
WECC and its stakeholders have developed the following metrics for describing transmission use, based on the rated capacities of transmission Paths:
U75: The percentage of hours during the year when, based on the PCM results, flows exceed 75 percent of the path’s ratings;
U90: The percentage of hours when flows exceed 90 percent of the path’s ratings; and
U95: The percentage of hours when flows exceed 95 percent of the path’s ratings.
A path is named as “heavily utilized” if the metrics exceed the following limits:
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Table 7: Transmission Utilization Metrics
Utilization MetricThreshold for
“Highly Utilized”
U75 50%
U90 20%
U99 5%
The most-used paths for the 2026 Common Case are shown in Figure 10: 2026 Common Case Most Highly Utilized Paths. The graph is color-coded to show the path flow results and screening thresholds, and sorted according to the U90 metric. A leading minus sign in the path name means that the predominant path flow is opposite to that of the “from-to” path-naming convention. High use on the paths is shown by the U99 metric, since this means that a path is operating at its rated limit.
Figure 10: 2026 Common Case Most Highly Utilized Paths
0%
10%
20%
30%
40%
50%
60%
Most Highly Utilized Paths - 26PC1_V2_0 2027 Common Case V2.0
U75 U90 U99
Perc
ent o
f Hou
rs
Based on the results of the 2026 Common Case, none of the WECC paths meet the criteria for “highly utilized.” This may be due to:
Retirements of remote generation;
Emphasis on renewable generation, often local; or
• Carbon prices that reduce the economics of off-peak coal generation.
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3.4 Year 10 Summary Observations
Observations specific to each of the study cases are included in the final report for each study. WECC staff observed the following in the 2016–2017 study program:
1. Across all study cases, based on modeling results, transmission in the Bulk Power System (BPS) appears to be adequate, as none of the Year 10 study cases showed unserved load. Note that the model manages the “duck curve” in California by using imports to supplement the morning and evening ramps.
2. In high renewable cases, there was a clear response by gas-fired units to changes in renewable generation: As renewable generation decreased, gas-fired resources generated more to compensate.
3. There was no consistency in the effect of renewable generation changes on transmission flows. While flows near large renewable resource facilities responded to local generation changes, there were no consistent links between Interconnection-wide transmission flows and changes to renewable resource portfolios.
4. Carbon prices are the main driver for high-carbon resources such as coal not being selected by the PCM for dispatch. The resources selected by the model to replace the carbon resources had a significant effect on the transmission flows.
5. Storage cases showed that pumped hydro storage could ease fluctuations in renewable resource generation; notably wind generation. However, there were no significant effects on transmission flows resulting from the storage-wind linkage.
6. Increasing pumped storage above the levels defined in the study cases does not appear to have a proportional benefit to using renewable resources. This may be due to a limitation in modeling pumped hydro storage.
7. Coal-fired generation tends to increase the use of long-haul transmission corridors more than gas-fired generation, as most gas-fired units serve load pockets near them without a need for long-distance transmission.
4. Year 20 Capital Expansion (CapEx) Model Studies
In 2016, like the Year 10 study cases, WECC developed a study program that included long-term study cases analyzed with a Capital Expansion (CapEx) model. The tool used in these studies, known as the Long-Term Planning Tool (LTPT) was developed over the past several years, starting with two products produced by separate vendors, and redesigned extensively by WECC and its consultants. The Year 20 studies are designed to find potential reliability risks and transmission expansion needs, which may lead to investment decisions needed to assure reliability in the long-term. WECC uses these studies as
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a screening tool to inform decision makers of energy futures that may occur and the accompanying risks that may call for further study.
Like the Year 10 studies, the Year 20 studies began with a common starting data set and model known as the 2034 Reference Case. The 2034 Reference Case is built by extending the assumptions used in the Year 10 case 10 more years. These assumptions, as well as metrics used to model additional Year 20 cases, are vetted extensively through collaboration with WECC’s stakeholders. Due to the uncertainties that come with looking 20 years into the future, WECC does not consider the 2034 Reference Case the “most likely” future. However, it serves as a reference point for other Year 20 study cases.
Note that the reference year for the Year 20 study cases is 2014 (leading to the “2034 Reference Case”) rather than 2016. This is because the Year 20 study program was originally developed in 2014, but could not be completed due to ongoing modifications to the LTPT. WECC and its stakeholders decided that continuing to use 2034 as the study year would give enough information on potential long-term reliability risks without changing the base year to 2016.
4.1 Year 20 Capital Expansion Studies
Year 20 CapEx study cases included in the 2016–2017 study program include:
The 2034 Reference Case; Study cases that model three of the original four WECC scenarios2; The Energy-Water-Climate Change Scenario; and Two special cases.
Table 8: Year 20 Study Cases Included the 2016–2017 Study Program lists the specific study cases included in the 2016–2017 study program. Each study includes links to the scoping document and final report for each study case. This report will not repeat specific findings of each study case. Rather, the following sections show overall observations spanning multiple study cases.
Table 8: Year 20 Study Cases Included the 2016–2017 Study Program
Case ID Case Summary Comments
2034 PC01 2034 Reference Case. Built on assumptions in 2026 Common Case.
2034 PC 1 Assessment of SPSG Scenario 2 – Aggressive policies to decrease GHG and promote technological innovation.
Study case based on the 2034 Reference Case.
2 Scenario 2 was not modeled because discussions with stakeholders led to the conclusion that the scenario was almost identical to conditions in 2016.
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Case ID Case Summary Comments
2034 PC 2 Assessment of SPSG Scenario 3 – Slow growth with focus on consumer costs.
Study case based on the 2034 Reference Case.
2034 PC 3 SPSG Scenario 4 – Slow growth with focus on low-hanging fruit clean energy investments.
Study case based on the 2034 Reference Case.
2034 PC 4 20 Year High DG case. Study case based on the 2034 Reference Case.
2034 PC 5 20 Year study of coal retirements or low-CO2 pathway including increased electrification of energy use.
Study case based on the 2034 Reference Case.
2034 PC 6 Energy-Water-Climate Change (EWCC) scenario intended to examine possible adverse impacts to the environment, in addition to increased average global temperature, that may occur because of global changes, and to assess impacts on the electrical reliability of the Western Interconnection.
Study case based on the 2034 Reference Case.
4.1.1 Modeling Approach
The Year 20 modeling approach is quite different from the Year 10 modeling approach described in other WECC documents. The following sections describe how loads, resources, and transmission are modeled in the Year 20 assessments, as well as how levelized cost of energy (LCOE) is used in modeling.
4.1.1.1 Load
Forecasted loads for the Year 20 Reference Case (Y20-RC) are derived from the Year 10 Common Case (Y10-CC) loads, keeping the same load assumptions and compound annual growth rates (CAGR) as that of the Y10-CC. Figure 7 shows the process upon which the Y10-CC loads are forecasted.
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Figure 11: Year 10 Load Forecast Model
Y20-RC loads are derived for each load area defined within the Y10-CC, further parsed by state boundaries, and are composed of both annual load energy and load demand by seasonal heavy- and light-load levels.
4.1.1.2 Resource Optimization
Year 20 study cases model renewable resources using resource optimization goals composed of annual energy goals and season capacity goals based on state, provincial, and other regulatory requirements. The goal of resource optimization is to arrive at a resource portfolio that is economical and satisfies all applicable goals. The cost minimization goal is based on levelized cost of energy (LCOE) described in Section 4.1.1.4. Resource optimization goals include:
State RPS, Annual load energy requirements, Must-run resources, Flexibility requirements, Reliability requirements, Reserve requirements, Effective load-carrying capabilities, and Seasonal load level demand requirements.
Once the tool produces an initial resource portfolio, it sends a simplified commitment of that portfolio for each seasonal load level as an input to a security-constrained transmission optimization function. Any cost associated with transmission optimization is assigned back to the generation optimization as a
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component cost of LCOE and the optimization process is repeated until convergence to a co-optimized solution in which both resource and transmission optimization goals are satisfied.
4.1.1.3 Transmission Optimization
The transmission optimization method begins with a geospatial optimization of transmission corridors to minimize environmental impact and to derive transmission corridor candidates for consideration. The tool uses WECC’s environmental data set (see Environmental and Cultural Considerations on WECC’s web page) to determine and minimize environmental impacts. Transmission candidates are composed of configurations ranging from 230 kV single-circuit lines at a capacity of 400 MW to 500 kV double-circuit lines at a capacity of 3,000 MW and 500 kV DC lines also at a capacity of 3,000 MW. The security-constrained part of the transmission optimization focuses on WECC paths. The transfer capability of each interface is enforced as a security constraint. In addition, transmission corridor candidates and related costs are associated with each interface. A security constrained optimization is then performed for each load level and generation portfolio to co-optimize generation dispatch with transmission. If there are remaining violations, the need for transmission expansion is determined and the associated costs are assigned to those generation buses contributing to the need.
4.1.1.4 Levelized Cost of Energy
LCOE is a measure of the overall cost of different generating technologies considering all costs incurred in generating power. Key inputs to calculating LCOE include:
Capital costs; Fuel costs; Fixed and variable operations and maintenance (O&M) costs; Financing costs; An assumed energy production rate for each plant type; and
Transmission expansion costs.
LCOE is the per-megawatt-hour cost of building and operating a generating plant over an assumed financial life and energy production rate.
The LCOE formulation used in the LTSP is that of the NREL Simple Levelized Cost of Energy (LCOE).
Please note that LCOE is calculated for both retained Y10-CC resources and new resource additions. Y10-CC retained resources are assumed to have a zero-investment cost component of LCOE (capital costs are assumed to be sunk), while new Y20-RC additions have a non-zero capital cost component. As such, retained Y10-CC resources of the same technology type have lower LCOEs than those of new additions. Because of this, the LCOE of the overall system portfolio may vary significantly depending on the mix of retained resources to added resources.
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4.2 2034 Reference Case
The 2034 Reference Case is the reference point for Year 20 study cases included in WECC’s 2016–2017 Study Program. It uses 2014 as its reference year because it was started in 2014 and, through the review process, WECC and its stakeholders determined that its results would be sufficiently instructive with 2034 as the long-term case, rather than revising assumptions to create a 2036 case. Load and resource assumptions in the 2026 Common Case were extended by eight years to arrive at the 2034 Reference Case.
4.2.1 Resource Portfolio Mix
Total system energy production for the portfolio mix in the Y20-RC (retained Y10-CC and new resource additions) is shown in Figure 12: Total System 2034 Energy Production. In this mix, wind makes up the largest part of the portfolio; gas resources make up only 13 percent. This is a significant shift from today’s portfolio mix. Gas-fired resources (made up entirely of retained Y10-CC resources) are 13 percent of the portfolio mix. The retained Y10-CC gas resources were dispatched to meet capacity and reliability requirements.
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Figure 12: Total System 2034 Energy Production3
The total system 2034 capacity (retained Y10-CC and new resource additions) is shown in Figure 13: Total System 2034 Capacity. In the 2034 Reference Case, wind generation has surpassed gas generation (44 percent versus 21 percent) as the largest source of generating capacity. Distributed Energy Resources (DER) also represent a significant portion of the generation mix (14 percent). The nameplate capacity of the portfolio is 332 GW, while the maximum system seasonal demand is 154 GW, due to the use of many resources, primarily to support reliability. The weighted average effective load carrying capability (ELCC)4 factor of the portfolio is 47 percent, which translates to an ELCC of 156 GW, as compared to the maximum system seasonal demand of 154 GW (with the 2 GW excess attributed to additional flexible generation requirement goals).
3 In this and following presentations of resource energy production in Year 20 studies, small hydro is approximately 1 percent of the total energy production reported for hydro resources.4 ELCC is defined as the amount of incremental load that a resource, such as wind, can reliably serve, while also considering the probability of generation shortfalls and forced outages as factors of unserved load.
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Figure 13: Total System 2034 Capacity
4.2.2 CO2 Emissions
The Y20-RC case shows a reduction in CO2 emissions of over 90 percent, compared to the Y10-CC case as shown in Figure 14: 2026 and 2034 CO2 Production. This is due to several factors, including:
A $58/ton CO2 cost for those resources that produce CO2 emissions, leading to those resources not being selected in the dispatch; and
Significant reductions in investment costs of renewable resources with technology advances and economies of scale in 2034, which displace CO2-emitting resources.
With a CO2 cost of $58/ton, neither coal nor gas resources were selected by the model based on energy production only. Coal-fired resources are completely displaced in the Y20-RC case, and gas resources from the Y10-CC case were dispatched only to the extent that they were needed to satisfy capacity and reliability requirements. No new coal or gas resources were added in the Y20-RC case. This reduction in CO2 emissions was seen across all 2034 studies.
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Figure 14: 2026 and 2034 CO2 Production
4.2.3 Water Consumption
The Y20-RC case shows a 70-percent reduction in water consumption from the Y10-CC case, as shown in Figure 15: 2026 and 2034 Water Consumption. This is due to several factors, including:
A $58/ton CO2 cost for those resources that produce CO2 emissions which also consume water for wet cooling; and
Significant reductions in investment costs of renewable resources with technology advances and economies of scale, which displace water-consuming resources.
As noted above, no new coal or gas resources were added in the Y20-RC case. These displaced resources consume water for wet cooling. Reduction in water consumption was saw across all 2034 legacy studies.
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Figure 15: 2026 and 2034 Water Consumption
4.2.4 Levelized Cost of Energy
The 2034 Reference Case compares resources using LCOE, an amortization of the overall cost of generating technologies over their economic lives. The LCOE considers all costs—capital, operations, and maintenance—incurred in generating power. In the 2034 case, the average LCOE for all resources was $42.00/MWh. The total system (new additions and retained Y10-CC resources), weighted LCOE by generation type and vintage, is shown in Figure 16: System Total Weighted LCOE by Resource Type and 17. LCOE cost components are weighted average costs and include:
Capital – Capital investment cost (assumed to be zero for Y10-CC resources);
FOM – Fixed operating and maintenance cost;
VOM – Variable operating and maintenance cost;
Fuel – Fuel cost;
CO2 – CO2 emission cost;
ITC – Investment tax credit;
PTC – Production tax credit;
PTI – Property tax and insurance cost; and
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Grid – Grid cost (i.e., transmission path cost).
Net LCOE costs are the net system and vintage weighted average LCOE costs for:
CC-Net – Net weighted average cost of retained Y10-CC resources;
New-Net – Net weighted average cost of newly added resources; and
System-Avg – Net weighted average cost of combined retained Y10-CC and newly added resources.
Figure 16: System Total Weighted LCOE by Resource Type
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Figure 17: System Total Weighted LCOE by Resource Type (cont.)
Note the following observations of the resources’ LCOE:
Y10-CC resources have a $0 capital cost component of LCOE (assumed to be a sunk cost);
A larger mix of retained Y10-CC renewable resources, which have a $0 capital cost component of LCOE, relative to new candidate resource additions (including a positive capital cost component) disproportionately reduces the system LCOE to $42/MWh.
The LCOE of retained gas-fired resources is higher than the system average LCOE. Y10-CC gas fired resources are dispatched only to the extent that they are needed to meet capacity and reliability requirements. The gas-fired resources dispatched were primarily combined-cycle. No new gas fired resources were added.
The LCOE of new generating resource candidates are presented in Figure 19: LCOE of New Resource Candidate Types (cont.).
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Figure 18: LCOE of New Resource Candidate Types
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Figure 19: LCOE of New Resource Candidate Types (cont.)
Please note in Figure 18: LCOE of New Resource Candidate Types and Figure 19: LCOE of New ResourceCandidate Types (cont.):
The LCOE of new candidate resources are above the given portfolio weighted average LCOE of $42/MWh.
The LCOE spread between wind and solar is highly sensitive to underlying LCOE components—especially Investment Tax Credits (ITC) and Production Tax Credits (PTC)—and to assumptions of annual capacity factors for locational production potential.
The LCOE of battery storage 20 years into the future is highly dependent on capital cost reductions and life cycle improvements.
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4.2.5 Resource Cost Observations
WECC staff saw the following in resource costs:
The weighted average LCOE of the Y20-RC case is $42/MWh where the generating resource portfolio is composed of both retained Y10-CC resources (no capital cost component) and new candidate resource additions (including a capital cost component) weighted by annual energy production potential.
All retained coal-fired resources are displaced due to the $58/ton CO2 emission cost.
The LCOE of retained gas-fired resources is significantly more than the system average LCOE. Y10-CC gas-fired resources are used only when they are needed to meet reliability requirements. The dispatched gas-fired resources were mostly combined cycle. No new gas-fired resources were added.
Including gas resources in all 2034 legacy studies was necessary for reliability, rather than for energy production.
Distributed resources (DR) were added to meet RPS requirements.
Wind and solar resources were added to meet RPS requirements, wind being the most competitive. The price spread between wind and solar is highly sensitive to underlying LCOE components—especially ITCs and PTCs—and to assumptions of locational production potential measured by annual capacity factors.
Battery storage resources were distributed to meet reliability requirements. Note that the LCOE of battery storage is less than the retained gas-fired resources. The LCOE of added battery storage is based on a 20-year economic life, which is dependent on technology advances in battery storage. Today, the economic life of battery storage is about five to 10 years, depending on use. The LCOE of battery storage 20 years into the future is highly dependent on improvements in life cycle.
New additions of Biomass, Coal, Gas, Geothermal, Hydro, Nuclear, Other, RPS – Other, and Storage – Water were not economic from either an energy or reliability standpoint and, therefore, not used.
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4.2.6 Transmission Utilization and Expansion Needs
Figure 13 shows the transmission use and expansion needs suggested in the Y20-RC. Transmission expansions to boost the export capability from New Mexico would accommodate large amounts of wind resource in New Mexico to the Y20-RC portfolio. Note that states and provinces with surplus generation are shown in blue; red shows a generation deficit. Table 9: 2034 Reference Case Path Parameters details the transmission flows.
Figure 20: 2034 Reference Case Transmission Flows
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Table 9: 2034 Reference Case Path Parameters
Path Limit (MW) Flow (MW) % of LimitCANO-CASO 3,675 1,982 54%DSW-Basin 1,300 803 62%DSW-RMPA 964 1,514 157%NM-AZ 2,400 5,701 238%PCNW-CASO 2,600 2,347 90%UT-LADWP 1,920 1,903 99%WY-CO 1,400 1,475 105%
4.3 Other Year 20 Study Cases
In addition to the 2034 Reference Case, WECC used the LTPT to analyze six more study cases; four based on the future scenarios described previously, and two others:
Table 10: Year 20 Study Cases
Study Case ID Description
2034 PC01 Scenario 2, “Focus on Clean Energy,” which includes high and widespread economic growth combined with paradigm-changing technological breakthroughs
2034 PC02 Scenario 3, “Focus on Consumer Costs,” which includes low economic growth confined to limited areas combined with evolutionary technological growth confined to current patterns
2034 PC03 Scenario 4, “Focus on Long-Term Societal Costs,” which includes low economic growth confined to limited areas combined with paradigm-changing technological breakthroughs
2034 PC04 High-Distributed Energy
2034 PC05 Low CO2 Production
2034 PC06 Energy-Water-Climate Change Scenario
Details of the six study cases are included in the 2034 Legacy Studies Report, to be posted soon on the WECC website. Results of these study cases are summarized in
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Table 11: Study Case Changes Relative to 2034 Reference Case.
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Table 11: Study Case Changes Relative to 2034 Reference Case5
Observation Scenario 2
(PC 1)
Scenario 3
(PC 2)
Scenario 4
(PC 3)
High DG
(PC 4)
Low CO2
(PC 5)
EWCC
(PC 6)
Equally Plausible
Comment
Total Renewable Resource Allocation
Solar PV Allocation
Distributed Resource Allocation
Wind Allocation
Gas Resource Allocation
Battery Storage Allocation
Retained Y10-CC Resource Allocation
New Candidate Resource
5 – study case value is higher than the 2034 RC value, – value is lower than the 2034 RC value, – value is about the same as the 2034 RC.
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Observation Scenario 2
(PC 1)
Scenario 3
(PC 2)
Scenario 4
(PC 3)
High DG
(PC 4)
Low CO2
(PC 5)
EWCC
(PC 6)
Equally Plausible
Comment
Allocation
Excess Energy Production Potential
ELCC/Capacity Factor Ratio
A decrease in ELCC relative to Capacity Factor means that more resources will need to be allocated to the portfolio for reliability.
Total Renewable Resource Weighted LCOE
LCOE increases when component costs increase and/or allocations increase, allocating more expensive resources from the supply curves (usually resource additions having non-zero capital
Solar Weighted LCOE
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Observation Scenario 2
(PC 1)
Scenario 3
(PC 2)
Scenario 4
(PC 3)
High DG
(PC 4)
Low CO2
(PC 5)
EWCC
(PC 6)
Equally Plausible
Comment
cost);
LCOE decreases when component costs decrease and/or allocations decrease, allocating less expensive resources from the supply curves (usually retained Y10-CC resources not having zero capital cost).
Gas Weighted LCOE
Combined Portfolio Weighted LCOE
Transmission Utilization Stress
Western Interconnection as a whole.
DSW South-to-North Flows
Exclusive of California Path 26 Flows
California Path 26 North-to-South Flows
Exclusive of DSW Transmission South-to-North Flows
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Observation Scenario 2
(PC 1)
Scenario 3
(PC 2)
Scenario 4
(PC 3)
High DG
(PC 4)
Low CO2
(PC 5)
EWCC
(PC 6)
Equally Plausible
Comment
California Path 26 South-to-North Flows
Exclusive of DSW Transmission South-to-North Flows
COI North-to-South Flows
COI South-to-North Flows
Wyoming North-to-South Flows
Wyoming South-to-North Flows
BC-to-AB (West-to-East)
BC-to-PCNW (North-to-South)
PCNW-to- BC (South-to-North)
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4.4 Year 20 Study Case Summary Observations
Looking across all the Year 20 study cases, WECC staff saw the following:
Although gas-fired resources may not be economically competitive for producing energy; they are needed for reliability.
Increased CO2 constraints, beyond the Reference Case $58/ton CO2 emission cost, result in little change to the overall portfolio mix—other than a slight change in the location of resources for capacity and reliability requirements.
An increase in energy production “potential” does not necessarily mean an increase in actual energy production, since more resources in the overall portfolio may be needed to satisfy season load demands relative to the ELCC of the resources.
The overall system-weighted LCOE is about $42/MWh across all Y20 studies, regardless of the changes in resource portfolio mixes.
Since modeling results show that combined-cycle generators would not be economically competitive for energy production in 2034, new combustion turbines (CT) would be a better alternative gas-fired resource for reliability because their investment cost is less.
Transmission use and expansion needs are relatively constant across all studies.
The Intermountain Power Plant location in Utah shows potential as an interconnection point for transmission expansion that may be needed to transfer renewable energy from the eastern part of the Interconnection to the load centers farther west. This site becomes especially desirable considering the displacement of coal resources and the existence of the Intermountain DC line, which primarily feeds load centers in Southern California.
Wind is the least-cost new generation resource, especially in New Mexico, with an LCOE about half that of solar PV.
Solar generation becomes more economical as load increases and where public policy favors solar.
Significant concentrations of new intermittent resource additions without geographic diversity, for example large wind resource additions in New Mexico, could produce a reliability risk due to the potential for losing a significant amount of capacity if local weather conditions change.
The increase in renewable resources in the system requires a larger generation portfolio capacity to support increased resource variability, as more capacity would be needed for reserve and flexibility energy requirements, compared to serving the load with gas-fired resources.
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A CO2 cost of $58.00/ton in 2034 is a primary driver for:
o Displacing all coal present in 2026;
o Retaining gas resources to meet reliability needs;
o Decreasing water consumption and CO2 production by over 50 percent relative to 2026; and
o Changing transmission flows because of resource displacements and additions.
Energy and capacity goals produce different resource requirements.
o Resources selected in the 2026 Common Case can satisfy most low load growth Year 20 energy goals.
o More resources (10–40 percent of the capacity needed to meet energy needs) are needed for capacity and seasonal variations in moderate to higher load growth scenarios.
The 2034 transmission grid appears to be robust enough to handle new generation portfolio mixes.
The only transmission paths that consistently showed a need for transmission expansion were export paths out of New Mexico to accommodate new wind resources added to the future resource portfolio. The model selected more New Mexico wind resources than in other states due to favorable wind profiles in New Mexico.
Most of the gas resources from the Y10-CC were displaced across all study cases. Those gas resources that were kept were needed to meet reliability goals. Although Y10-CC gas resources may not be economical for providing energy, they will likely be needed for reliability assurance.
While not economical for supporting energy production alone, new battery storage resources may have reliability value.
Year 20 cases that include low economic growth need lower capacity additions to meet seasonal requirements.
5. NERC Long-Term Reliability Assessment
Each year, NERC directs the creation of a Long-Term Reliability Assessment (LTRA) by each region in North America. The LTRA is developed by NERC under the Energy Policy Act of 2005 (Title 18, § 39.111 of the Code of Federal Regulations). It also fulfils the Electric Reliability Organization’s (ERO) Rules of Procedure, which instructs NERC to conduct periodic assessments of the North American BPS.
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The LTRA is based on data and narrative information collected by NERC from the eight Regional Entities to independently gauge the long-term reliability of the North American BPS, while showing trends, emerging issues, and potential risks during the 10-year assessment period.
5.1 LTRA Results (2017)
The 2017 LTRA included the following highlights for WECC:
Load-Serving Entities (LSE) in the Western Interconnection are forecasted to add over 9,000 MW of solar nameplate capacity, and over 5,000 MW of wind nameplate capacity, during the assessment period. In addition, over 12,500 MW (nameplate) of rooftop solar is forecasted to be installed over the next decade.
WECC is funded a study of the interdependence of the natural gas and electric systems and its effect on reliability. This study was completed in June 2018.
The Los Angeles Basin in southern California continues to be an area of short-term concern due to the reduced availability of the Aliso Canyon natural gas storage facility. WECC has studied, and continues to study, the affect this reduced availability has on reliability.
Three 55-MW, oil-fired units in CAISO (WECC-CAMX assessment area) will be needed through 2018 to ensure reliability. CAISO’s board of governors extended a “reliability must-run” (RMR) contract in September 2017 for the three units, located near Oakland, CA.
The LTRA showed the following issues related to reliability:
Planning Reserve Margins: WECC’s Reference Margin Level, a “building block” approach, is based on contingency reserves, regulating reserves, forced outages, and a high-temperature adder. No WECC subregion drops below the Reference Margin Level during the assessment period (2017-2027).
Demand: The CA/MX subregion has forecasted very little peak demand growth over the next 10 years (0.27 percent) due to the projected increases in rooftop solar installations. Other WECC subregions show growth rates between 0.62 percent and 1.88 percent, consistent with recent demand forecasts.
Demand-Side Management (DSM): Entities within WECC are forecasting little increase in controllable demand response. The California ISO’s demand response initiative programs are being developed with a goal to avoid adverse long-term reliability impacts. Energy efficiency and conservation are viewed as a permanent reduction in demand and are shown as reductions in the load growth forecasts.
Distributed Energy Resources (DER): It is estimated that there was about 5,500 MW of rooftop solar installed throughout the Western Interconnection by the end of 2016. That number is
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forecasted to increase to over 10,000 MW by the end of 2022 and over 17,000 MW by the end of 2027. The CAISO, which has experienced significant challenges in ramping resources to meet demand changes from rooftop solar installations, expects to have nearly 13,000 MW of rooftop solar installed in its footprint by the end of 2027.
Generation: WECC is not a planning entity and does not approve or reject planned retirements. However, WECC does incorporate announced and planned retirements when creating datasets for planning models. Retirement of generation resources is not now a major concern, as ample generation exists in the Western Interconnection. However, that condition could change over the assessment period. WECC monitors generation retirements and studies the potential effects on Interconnection-wide reliability associated with announced, planned, and actual retirements. The large geographic footprint of the Western Interconnection helps mitigate generation retirements, as seasonal transfers—from winter peaking regions to summer peaking regions and vice versa—are very common in the Western Interconnection.
The full LTRA report for 2017 is posted here.
6. Overall Reliability Assessment Observations
The System Adequacy Department’s reliability assessments in 2016 and 2017 were based on data from a variety of sources and on models that simulate results 10 or 20 years into the future. WECC saw the following across multiple, individual study cases based on modeling results:
1. Overall, the transmission infrastructure expected to be in place in 2034 appears sufficient to serve expected load with the available resources. Analysis of specific operational challenges posed by the changing resource mix is beyond the scope of this report.
2. Carbon prices, and their effects on the economics of fossil fuel use, will be a major factor in the resource mix in the Western Interconnection. Although costs for CO2 emissions apply only in limited areas of the Western Interconnection, it is likely that costs for carbon emissions will become more commonplace. WECC and its stakeholders must be aware of potential reliability impacts from changes in the resource mix.
3. Future needs for transmission infrastructure are location-specific. Changes to the BPS because of changes to the distribution-level system (driven primarily by the expansion of distributed energy resources) need to be evaluated.
4. The increase in renewable resources require a larger generation portfolio to account for increased variability, as more capacity is needed for reserve and flexibility requirements.
5. Gas-fired resources look less economical for supplying energy needs alone in the 20-year planning horizon, but are probably needed for reliability.
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6.1 Potential Reliability Risks
Reliability risks that WECC and its stakeholders have suggested for further study include:
Inverter-based resources and the best ways to model them;
The changing resource mix, especially the increase in Distributed Energy Resources (DER);
Changing market structure and Reliability Coordinator function;
Evolving roles of the organizations involved with planning parts of the BPS;
Large-scale electrification; for example, high penetration of electric vehicles;
Increasing use of energy storage;
Expansive geography and remoteness of assets—nuances in managing physical and cyber security issues; and
Major disruptions on the BPS that test its resilience; for example, weather-related events and natural disasters.
7. Recommendations for Future Reliability Assessments
In addition to future opportunities found in the 2016–2017 Study Program, three initiatives will significantly affect WECC’s reliability assessments in 2018 and 2019:
1. WECC has begun a process to define near-term priorities. Starting with a Reliability Workshop on March 21, 2018, and continuing with a Board of Directors workshop on April 30, 2018, WECC and its stakeholders are working to prioritize potential reliability risks for further study. The Board approved 2019-2021 Near-Term Priorities at its June 20, 2018, meeting.
2. WECC’s Reliability Assessment Committee’s (RAC) Scenario Development Subcommittee (SDS) is creating new future scenarios (plausible futures) for the Interconnection. The scenarios consider the most significant policies, economic and technological factors, and other drivers that could affect the reliability of the BPS. When completed—likely in the Third Quarter, 2018—WECC plans to work with stakeholders to model each scenario as a long-term study case.
3. The RAC’s Studies Subcommittee is developing an integrated study program for 2018-2019. This program will prioritize the reliability assessments to be completed through the RAC and its subcommittees and work groups over the next 12–18 months, to give insight into potential reliability risks and mitigations.
WECC will be working with its stakeholders in the coming weeks to develop a study program that evaluates the highest—priority potential reliability risks in the 10- and 20-year planning horizons.
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Appendix A: Glossary of Terms
Acronym Term Definition
BA Balancing Authority The responsible entity that prepares near-term resource requirements, maintains load-interchange-generation balance within a Balancing Authority Area, and supports Interconnection frequency in real time.
BAA Balancing Authority Area The collection of generation, transmission, and loads within the metered boundaries of the Balancing Authority. The Balancing Authority maintains load-resource balance within this area.
BPM Base Planning Margin Also known as “Building Block Margin,” BPM is a method for determining a planning reserve margin by considering contingency reserves, regulating reserves, forced outages, and temperature adders.
BES Bulk Electric System The electrical generation resources, transmission lines, interconnections with neighboring systems, and associated equipment operated at 100 kV or higher.
BLM United States Bureau of Land Management
An organization within the United States Department of the Interior charged with sustaining the health, diversity, and productivity of the United States’ public lands.
CA/MX California/Mexico An entity that includes parts of California and Mexico and which shares contingency reserves to maximize generator dispatch efficiency.
CCTA Common Case Transmission Assumptions
The list of transmission expansion projects in progress that are determined by the RPCG as highly likely to be complete by December 2024.
DG Distributed Generation Energy that is generated at or near the point of
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Acronym Term Definition
consumption.
Dump Energy Energy in a production cost model analysis that is selected in the economic dispatch to be delivered to load but cannot actually be delivered due to modeling constraints.
ELCC Effective Load Carrying Capability
The amount of incremental load that a resource, such as wind, can dependably and reliably serve, while considering the probability of generation shortfalls and forced outages as factors of unserved load.
Energy Storage Any technology that can store energy for use later, including batteries, flywheels, compressed air, thermal technologies, and pumped hydro power.
Gap Resources Unspecified resources added to defined resources in a production cost model case to balance resources, energy, demand, and planning reserves.
LCOE Levelized Cost of Energy The per-kilowatt hour cost (in real dollars) of building and operating a power plant over an assumed financial life and duty cycle.
LTPT Long-Term Planning Tool The capital expansion model used by WECC to complete 20-year planning studies.
LMP Locational Marginal Price In a nodal pricing system, the cost of dispatching the next increment of supply to meet the next increment of load.
LOLP Loss-of-Load Probability The odds that the responsible Load-Serving Entity is unable to serve some or all of its customers’ loads; for example, when multiple generation failures result in insufficient reserves.
NERC National Electric Reliability Corporation
A non-profit international regulatory authority whose mission is to assure the reliability of the Bulk Power System in North America by
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Acronym Term Definition
developing and enforcing reliability standards; annually assessing seasonal and long term ‐reliability; monitoring the Bulk Power System through system awareness; and educating, training, and certifying industry personnel.
NXT Network Expansion Tool A part of the Long-Term Planning Tool that focuses on transmission optimization.
NWPP Northwest Power Pool A non-profit organization composed of major generating utilities serving the Northwestern U.S., British Columbia, and Alberta that seeks to achieve benefits from coordinated operations.
PA Planning Authority The responsible entity that coordinates and integrates transmission facilities and service plans, resource plans, and protection systems.
PCC Planning Coordination Committee
A WECC standing committee that evaluates potential future generation and load balance (two years or greater timeframe) and adequacy of the physical infrastructure of the interconnected Bulk Electric System.
PSA Power Supply Assessment An evaluation of generation resource reserve margins for the WECC summer and winter peak hours.
PCM Production Cost Model A model used by WECC to complete studies in the 10-year planning horizon in which resources are dispatched according to their levelized cost to meet load in each of the 8,760 hours of the planning year.
RE Regional Entity An organization to which the North American Reliability Corporation (NERC) has delegated responsibility for developing and enforcing Reliability Standards within specified boundaries.
RAWG Reliability Assessment Work Group
A WECC work group that defines facility outage data reporting requirements and makes recommendations on reliability performance-
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Acronym Term Definition
level adjustments. The group also monitors the status and analysis of resource adequacy in the Western Interconnection.
Reliability Standard A requirement approved by the United States Federal Energy Regulatory Commission under Section 215 of the Federal Power Act, or approved or recognized by an applicable governmental authority in other jurisdictions, to support reliable operation of the Bulk Power System.
RPCG Regional Planning Coordination Group
An organization consisting of representatives from each of the Regional Planning Groups in the Western Interconnection.
RPG Regional Planning Group Entities within the Western Interconnection that have been organized under FERC Order 1000 or under TEPPC’s charter to address common issues within a particular portion of the Western Interconnection and have a close relationship with smaller load serving entities such as municipal utilities and rural electric cooperatives.
RMRG Rocky Mountain Reserve Sharing Group
A NERC-registered entity that includes parts of Colorado, Nebraska, South Dakota, New Mexico, and Wyoming and that shares contingency reserves to maximize generator dispatch efficiency.
Solar PV Solar Photovoltaic Generation sources that convert sunlight into electricity using photovoltaic technology.
SAP System Adequacy Planning The WECC department responsible for various planning-related databases, 10-year and 20-year analyses, probabilistic assessments, and NERC-related reliability assessments.
SCDT Study Case Development Tool A part of the Long-Term Planning Tool that focuses on generation optimization.
SPSG Scenario Planning Steering A stakeholder group responsible for developing
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Acronym Term Definition
Group future scenarios for the Western Interconnection.
SRSG Southwest Reserve Sharing Group
A NERC-registered entity that includes parts of Arizona, California, New Mexico, and Texas, which shares contingency reserves to maximize generator dispatch efficiency.
SWG Studies Work Group A work group under the Technical Advisory Subcommittee that develops a proposal for TEPPC’s annual study program and establishes the resource portfolio and transmission network assumptions used in each of the study cases.
TAS Technical Advisory Subcommittee
A subcommittee under TEPPC that collects and distributes data for both historic and forward-looking congestion studies and advises TEPPC on technical matters.
TSS Technical Studies Subcommittee
A WECC subcommittee that performs studies, keeps data files, evaluates proposed system additions or alterations, prepares reports and recommendations, and performs such other duties as directed by the Planning Coordination Committee.
TEPPC Transmission Expansion Planning Policy Committee
A committee to oversee and maintain public databases for transmission planning; develop, implement, and coordinate planning processes and policies; conduct transmission planning studies; and prepare Interconnection-wide transmission plans.
WI Western Interconnection The A wide area synchronous alternating current power grid that extends from Canada to Mexico and includes the provinces of Alberta and British Columbia, the northern portion of Baja California, Mexico, and all or portions of the 14 Western states between.
WPR Western Planning Region One of four geographic regions within the Western Interconnection that has compliance
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Acronym Term Definition
obligations under FERC Order 1000.
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