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TEPPC Study Report: 2024 PC1 Common Case WECC Staff Draft: August 14, 2015
151002-2024 CCV1.5-StudyReport-draft
TEPPC Study Report: 2024 PC1 Common Case
WECC Staff
Draft: August 14, 2015
155 North 400 West, Suite 200
Salt Lake City, Utah 84103-1114
Document Title2
Western Electricity Coordinating Council
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 1.5 dataset. These results supersede the results reported earlier in a draft report using the v1.3 dataset. The list of changes is available in the release notes.[footnoteRef:1] [1: 2024 Common Case & Release Notes.]
Table of Contents
Introduction1
Abstract of Case2
Key Inputs and Results from TEPCC 2024 Common Case Version 1.52
Load3
Generation4
CO2 Emissions7
Transmission congestion7
Additional Discussion of Input Assumptions and Study Results9
Study Limitations9
Dataset Updates9
Summary Inputs and Assumptions10
Load Topology10
Transmission Network11
Generation Resources12
Load Modifiers15
Overriding Assumptions16
Key Data and Modeling Improvements17
Future Data Improvements18
Additional Study Results18
Generation by State/Province18
Peak Hour Breakdown20
Generator Operational Statistics21
Transmission Path Flows23
Conclusions and Observations28
Appendix A31
2024 PC1 Common Case 31
2024 PC1 Common Case Report12
Western Electricity Coordinating Council
Western Electricity Coordinating Council
Introduction
The 2024 Common Case is a production cost model (PCM) dataset that serves as the expected future 10year study scenario for the Transmission Expansion Planning Policy Committee (TEPPC). The case represents the trajectory of recent Western Interconnection planning information, developments and policies looking out 10 years to the year 2024.
A primary goal in developing a Common Case is to define a reasonable foundation for the other resource mix and transmission planning studies (10-year time frame) that are conducted as part of the 2013 and 2014 TEPPC Study Programs. The case is also used throughout the Western Interconnection for a number of purposes, including: FERC Order 890 and 1000 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 10 years. The development of a WECC-wide production cost dataset would not be possible without the huge contribution of all of the TEPPC stakeholders.
WECC staff wishes to express appreciation to everyone who contributed to this effort.
Abstract of Case
The 2024 TEPPC Common Case is a collection of assumptions that are designed to depict a possible representation of the WECC Bulk Power System in the year 2024. Table 1 provides a high-level summary of a few of the inputs and results including, where available, actual data for 2013 (SOTI) for comparison purposes.
Table 1: Summary Table Comparison
Category
Item
2013
2024
Generation Capacity (MW)
Hydro
Thermal
Renewable
Other
66,117
141,030
31,524
1,385
240,056
66,790
134,601
52,592
20,672
274,655
Annual Generation (GWh)
Hydro
Thermal
Renewable
Other
n/a
238,956
618,219
168,293
24,874
1,050,342
Peak Demand (MW)
Summer
Winter
155,000
128,000
175,169
Key Results
Unserved Load (MWh)
Var. Production Cost (M$)
CO2 Emissions (MMetTons)
Dump[footnoteRef:2] Generation (MWh) [2: Dump energy is generation that would have been dispatched if not for a constraint such as a transmission limit.]
n/a
0
22,843
363
357,799
Transmission Congestion (%U90)[footnoteRef:3] [3: The %U90 congestion metric represents the percent of hours over the year that the path flow was at or above 90 percent of its path rating.]
Path 3
Path 26
Path 46
Path 65
Path 66
Confidential
0.10
4.02
0.00
0.00
0.76
Key Inputs and Results from TEPCC 2024 Common Case Version 1.5
A few key inputs and results of the 2024 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[footnoteRef:4] in the 2024 Common Case are provided in Table 2 and compared to the 2013 actual values in Figure 1. Based on the assumptions, the peak demand in 2024 is estimated to be 24,275 MW higher than the 2013 actual peak demand. [4: 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.]
Table 2: Load Forecast Components
Load Components
2024 Forecast and Load modifiers
Summer Peak
(MW)
Winter Peak
(MW)
Annual Energy
(GWh)
Native Load
176,914
1,029,552
Pumping Load
1,038
11,132
Energy Storage Pumping
0
3,122
Exports
510
5,365
DG/DR/EE Incremental
-3,293
-17,917
Total
175,169
1,031,254
Figure 1: Load Growth
Generation
The generation inputs for the 2024 Common Case reflect existing resources plus planned resource additions for combined cycle, combustion turbine, and renewable generation between 2013 and 2024. Conversely plans to retire (or convert the fuel) for several coal-fired and oil-gas steam generators were also represented. The total net capacity[footnoteRef:5] changes for the referenced resource types are shown in Figure 2, with a net capacity change of 23,928 MW (excluding the load modifiers). [5: The reported capacities represent the highest available to the grid capacities over the study year. ]
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 additions for solar and wind are also significant and will be discussed in more detail later in the report.
Figure 2: Key Resource Net Capacity Change (MW) between 1/1/2013 and 1/1/2024
The 2024 Common Case was run through a production cost model[footnoteRef:6] to obtain a load/resource solution for each hour of 2024. A breakdown of the resulting annual generation by category based on the input and modeling assumptions is shown in Figure 3. The largest shares of production were from combined cycle generation (26.6 percent) and conventional hydro (22.8 percent). The share from renewable generation was 16 percent. [6: For the current cycle WECC used ABB GridView for the PCM studies.]
In spite of over 6600 MW of coal retirements, leaving coal at only 11.3 percent of the installed capacity, coal-fired generation contributed 21.7 percent of the annual generation.
Figure 3: Breakdown of Annual Generation - 2024 Common Case
Since the 2022 dataset was developed in 2011 there have been several changes that impacted the generation mix in the 2024 dataset. A comparison of the annual generation for the two datasets (2022 vs. 2024) is shown in Figure 4. The most notable differences are listed below.
The reduction in coal-fired generation due to unit retirements and displacements.[footnoteRef:7] [7: Coal generation displacement was primarily due to implementation of the California Global Warming Solutions Act (AB32) and increased penetrations of renewable resources.]
The effect of the retirement of the San Onofre nuclear plant in southern California is also evident with a reduction in nuclear energy.
Updated information regarding the compliance plans for Once-Through-Cooling (OTC) in California prompted a decrease in Steam Other output.
A lower hydro energy forecast by BC Hydro led to a decrease in hydro generation.
A significant shift in renewable generation assumptions due to cost reductions in solar power.
There was an increase in total generation of 33,930 GWh (3.34 percent) between the 2022 Common Case and the 2024 Common Case, corresponding to assumed load growth.
All of these changes were balanced by increases in combined cycle, combustion turbine, DG/DR/EE Incremental, and biomass generation.
Figure 4: Annual Generation by Category (2022 vs 2024)
CO2 Emissions
In spite of the significant decrease in coal generation, the CO2 emissions increased (2022 versus 2024) from 359 to 362 million metric tons. This can be attributed to three primary factors, all of which may have required increased generation from the remaining coal fleet and gas-fired resources:
1. The retirement of the San Onofre nuclear power generators
2. The reduction in hydro generation
3. The load growth
Transmission congestion[footnoteRef:8] [8: Congestion refers to a condition where the flow may have been higher if not for a defined limit.]
There was minimal transmission congestion in the 2024 Common Case. The congestion issues in previous datasets were mostly mitigated with the transmission project assumptions in the 2024 Common Case Transmission Assumptions (CCTA) and other non-transmission assumptions. The paths with reduced congestion or interesting flow variations are:
Path 8 Montana-Northwest: A project to upgrade this path was assumed to be completed by 2024, effectively eliminating the congestion seen in previous study programs.
Northwest to California: The flows on paths 65 (PDCI) and 66 (COI) decreased significantly due in part to the implementation of the California Global Warming Solutions Act (AB32) that places a financial penalty on imports of electrical power to California, except for surplus hydro generation from 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 2024 Common Case, the CO2 cost penalties from AB32 have a substantial impact on the dispatch of the IPP units and on the utilization of path 27.
Geothermal near California Nevada Border: Paths 52 and 60 east of Big Pine, California are not congested historically; however, the common case assumptions in the ten year horizon created some minor congestion. Adjustments to the paths phase shifter parameters in the model would likely reduce the congestion.
Path 26 Northern-Southern California: Path 26 is the most congested path in the 2024 Common Case. Figure 5 is a chronological plot of the hourly flow results with potential congestion whenever the flow is at the path ratings. The large swings from hour to hour are a function of the PCM objective to converge to the lowest overall cost each hour. A reverse sort of the hourly values (or duration plot) is also superimposed on the chronological plot.
Figure 5: Path 26 Hourly Flow - 2024 Common Case
In the ten-year horizon for the 2024 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.
Additional Discussion of Input Assumptions and Study Results
A more detailed accounting of the study limitations, input assumptions, and results from the 2024 Common Case is presented in the following sections.
Study Limitations
PCM Solution: The solution from the PCM is often more efficient and optimistic than reality for the WECC-wide studies such as the 2024 Common Case. Although there have been efforts to tune the results to more closely meet expectations, there will continue to be unanticipated results. The case still 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 generators output can become undeliverable and create dump energy.[footnoteRef:9] There are a few instances where this has occurred in the common case, and these may be addressed in a future release. [9: Dump energy is generation that would have been dispatched if not for a constraint such as a transmission limit.]
Load Shapes: The hourly load shapes for each load area are based on the actual hourly loads from 2005. 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
A recommendation to apply regular updates to the 2024 Common Case was approved by TEPPC and the Technical Advisory Subcommittee in early 2014. In the past once an official dataset was released, no changes were made until the next data cycle two years later. The intent of the regular updates is to work with the stakeholders to continually improve the dataset and prevent the data from becoming out-of-date. It will be necessary to reference the version number of the common case in all relevant communications regarding the TEPPC 2024 Common Case.
Summary Inputs and Assumptions
The detailed input assumptions are provided in a one-hundred page document of release notes.[footnoteRef:10] A few of the assumptions are listed in relevant sections below to provide a basis for the enclosed results. [10: Link to release notes: 2024 Common Case & Release Notes.]
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 6. The forecasts that were submitted in March 2013 were used for the 2024 Common Case.
Figure 6: TEPPC Load Area Topology
Transmission Network
The transmission network was derived from the TSS 2023-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 7. Note that 12 out of the 22 projects are either complete or under construction.
Figure 7: 2024 Common Case Transmission Projects
Other study specific transmission projects will be added as requested in the studies outlined in the 2013/2014 Study Program.
Generation Resources
There have been several changes to the generation assumptions since the 2022 case was developed in 2011. A few examples are highlighted below.
Decision by Southern California Edison to retire the San Onofre nuclear power plant in 2013.
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 2024.
Addition of gap generation where needed to meet the expected peak demand and planning reserves.
Revised retirement plans for coal-fired generation that removed over 3400 MW of additional coal-fired capacity (see assumptions in Table 3) for a total of 6,618 MW.
Table 3: Coal Retirement Assumptions - 2024 Case vs. 2022 Case
Coal Generator
State/Province
Retired Capacity (MW)
2022
2024
Arapahoe 3,4
Colorado
153
153
Battle River 3
Alberta
148
148
Ben French 1
S. Dakota
0
25
Boardman
Oregon
610
610
Carbon 1,2
Utah
0
172
Centralia 1
Washington
688
688
Cherokee 3 [CTG]*
Colorado
0
0
Cherokee 4
Colorado
352
352
Cholla 2
Arizona
0
262
Four Corners 1-3
Arizona
560
560
HR Milner
Alberta
144
144
JE Corette
Montana
0
153
Lamar 4,6
Colorado
0
38
Naughton 3 [CTG]*
Wyoming
0
0
Navajo (1 unit of 3)
Arizona
0
750
Neil Simpson 1
Wyoming
0
18
Osage 1-3
Wyoming
0
30
Reid Gardner 1-3
Nevada
330
330
Reid Gardner 4
Nevada
0
257
RioBravo Jasmin
California
35
35
San Juan 2,3
New Mexico
0
839
Sundance 1,2
Alberta
0
576
Valmont 5
Colorado
184
184
Valmy 1
Nevada
0
254
WN Clark 1,2
Colorado
0
40
Total
3,204
6,618
*Converting to gas, Cherokee 3 (152 MW), Naughton 3 (330 MW), Other (70 MW)
The changes in generation capacity by state/province and category are provided in Figure 8. The load modifiers are excluded from the graph.
Figure 8: Change in Generation Capacity
The assumptions for the progression of installed generation capacity in the 2024 Common Case are provided by category in Figure 9 (see Table 6 in Appendix A for a tabular format). The large step changes in 2023 represent the true-ups for RPS and the California Long-term Power Plan.
Figure 9: Cumulative Resource Capacity Assumptions
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 10 represents a combination of existing projects, near-term projects under development, and estimated projects. The large increase in 2023 is primarily related to how the renewable resources from the California interconnection queue are added to the dataset.
Figure 10: Renewable Generation Capacity Projections
Load Modifiers
Several minor adjustments to the forecasted loads are modeled in the 2024 Common Case to represent anticipated distributed generation (DG), energy efficiency (EE), and demand response (DR). Rather than apply these changes to the loads, it makes more sense 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 17,917 GWh, which is broken down in Table 4. 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 4: Load Modifiers Modeled as Generators (GWh)
State
Distributed Generation
Demand Response
Energy Efficiency
AZ
2,784
0.456
0
CA
8,280
3.542
4,574
CO
999
0.640
0
ID
58
0.277
0
MT
42
0
0
NM
261
0.100
0
NV
377
0.227
0
OR
230
0.400
0
UT
145
0.412
0
WA
105
0.440
0
WY
55
0
0
Total
13,336
6.49
4,574
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 WECC staff to make 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 2024 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 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)[footnoteRef:11] of generation. [11: The established classes are: existing, under-construction, approved and/or financed, and future conceptual.]
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 2024 Common Case is provided below. The complete list of improvements with detailed explanations can be found in the release notes.
Generator Bus Mapping: The generating units are not always represented at the same detail in the various sources. The 2024 Common Case has more unit-level detail than in past datasets, which simplifies the exchanges with the power flow data.
Seasonal Bus Distribution: In the PCM the area-level hourly loads must be distributed to buses for the Locational Marginal Price (LMP)-based solution. This is derived from the bus loads in the power flow. Previously a single power flow case was used for the entire year, even though the power flow case targeted a particular season. For the 2024 Common Case, three power flows were used to obtain a seasonal load distribution to buses.
Monitored Lines: The number of monitored lines was increased.
Reserve Topology: The multi-level reserve structure in GridView was used to apply reserve requirements at several levels, including for reserve sharing groups.
Flexibility Reserves: Since the 2022 Common Case was developed, NREL has developed an updated and improved algorithm for flexibility reserves that identifies additional reserve requirements to model the uncertainties associated with variable resources like wind and solar.
California Global Warming Solutions Act (AB32): An implementation methodology provided by the California Independent System Operator (CAISO) was applied in the common case. The goal of the methodology is to financially penalize companies for CO2 emissions for generation that serves load in California.
Remote Generation: Several of the generation sources that are physically located in one BA but contractually serve load in other BAs, are so designated in the common case. This remote generation is flagged to be exempt from wheeling charges[footnoteRef:12] (to all parties) and to be eligible to meet reserves per the owned contractual shares. [12: Payment for the movement of electricity from one system to another over transmission facilities of interconnecting systems. Wheeling service contracts can be established between two or more systems.]
State RPS Compliance: The methodology for meeting the RPS requirements for each state with RPS goals or targets was modified to use unallocated renewable generation and/or renewable energy credits. The distributions followed all state guidelines and rules.
Minimum Local Generation: A recommendation from the CAISO was implemented that sets a 25-percent-minimum local generation threshold for certain load centers in California. Nomograms are used to implement this requirement.
Back-to-Back DC Ties: The expected interchange with the Eastern Interconnection via the DC ties was improved.
Future Data Improvements
Power Flow Export: A goal for the 2013-2014 study cycle was to develop the ability to accurately and easily feed data from the 2024 Common Case into a power flow to study reliability issues. This is commonly called a Round Trip since the network data in the PCM is initially directly imported from a power flow. As of the current version, this capability has not been realized.
Cogeneration: A significant portion of the combined heat and power (CHP) and cogeneration has not been updated to reflect the operating requirements of the coordinated processes. The supporting data and a new methodology will be required to move forward.
Generator Cost Parameters: A project to update the generator cost parameters (i.e., heat rates, start costs, variable O&M) and emission rates was halted when a methodology to use a generic algorithm to calculate the heat rates was rejected by stakeholders. There may be a few problems that will need to be resolved on a case-by-case basis.
Additional Study Results
Other results of interest from the 2024 Common Case study are provided below.
Generation by State/Province
The generation results are reported here by their geographical location. Clearly, the generation from many resources is contractually[footnoteRef:13] owned by LSEs in other states or provinces; however the associated contracts and their details are often not publicly available to provide a complete representation. The annual (geographical) generation by state/province and fuel is provided in Figure 11. [13: Data for known contracts is represented in the dataset and the associated units are exempted from wheeling charges.]
Figure 11: Annual Generation by State and Fuel
Renewable Energy Targets
There are nine states in WECC that have Renewable Portfolio Standards (RPS). The estimated amount of renewable energy that would be required for the RPS states in 2024 is 155,994 GWh. In the 2024 Common Case renewable resources accounted for 159,215 GWh in the RPS states. There are also renewable resources in the non-RPS states, as well as Canada and Mexico, which produced almost 27,000 GWh in the common case.
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. The end result is more renewable energy in WECC than is required for the combined RPS requirements.
Peak Hour Breakdown
Based on the current assumptions for the 2024 Common Case, the coincident peak demand of 175,169 MW occurs on July 24, 2024 at 1700 hours, with generation shares as shown. The contribution from renewable resources is approximately 9.1 percent.
A ten-day snapshot of the hourly generation by category that includes the peak hour is presented in Figure 12. For WECC overall, the primary resource types that follow the load are hydro, combined cycle, combustion turbine, and solar.[footnoteRef:14] [14: 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.]
Figure 12: Ten-day Snapshot of Hourly Generation - WECC
Generator Operational Statistics
There are a few operational statistics that provide insights into how the production cost model system dispatch compares to expected behaviors. For example, base-loaded units such as Steam - Coal are designed to run continuously and would be expected to have a low number of starts (off/on cycles), while Combustion Turbines are designed to run during the high peak hours with a high number of starts. Figure 13 shows the starts results from the 2024 Common Case.
Figure 13: Number of Starts by Category
The majority of the thermal units have planned and forced outages that add a few starts during the year. A few generator types that have definitive operating patterns, such as Nuclear, Solar, and Pump-Storage, or random patterns (i.e., wind) were omitted from the chart to make it more readable.
There are often other restrictions that influence the operation of certain generators, such as cogeneration agreements, preferred resource designations, etc. The majority of the combustion turbine and combined cycle units showing a low number of starts in Figure 13 are cogeneration units.
Base load units would also be expected to have high capacity factors, as confirmed in the capacity factor results provided in Figure 14. One concern here involves the wide-ranging capacity factors for combined cycle units, perhaps due to their varying purposes. There may also be some problems with the modeling of CT and IC units.
Figure 14: Capacity Factors by Category
Study Generation Results versus Actual Historical
Another validation exercise that was recommended by the Modeling Work Group is a comparison of the individual generator outputs to the historical outputs that are reported to the U.S. Energy Information Administration (EIA). There are a few drawbacks to this type of comparison such as:
Generator Owners in Alberta, British Columbia, and Baja-Mexico do not report to the EIA
Not all Generator Owners in the U.S. are required to report to the EIA
It often takes about two years for the reported data to be compiled and made available
There are many factors that influence the actual operation of the generator fleet that may not be modeled in the ten-year horizon production cost case
Partial year issue for units that started commercial operation during the actual year (2012)
The chart in Figure 15 represents a comparison of the generator output from the 2024 Common Case versus the 2012 EIA data, using only the matched units. The graph for California suggests that the 2024 Common Case is assuming more hydro generation than occurred in 2012, and the opposite for Oregon and Washington. In most states the hydro difference is balanced by mostly thermal resources. The Hourly Resources are predominantly wind, solar, and hourly fixed-pump storage.
Figure 15: Results compared to EIA 2012 actual
Another key factor for the increased generation overall (23,398 GWh net) is the higher loads in the 2024 Common Case (1,031,254 GWh) versus the actual loads in 2012 (884,751 GWh). In addition to the increase in generation from facilities that were in-service in 2012, several new generators served the expected load in the common case.
Although only a subset of the generation is represented, the comparison is helpful, especially at the unit level where modeling parameters may need some adjustments.
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. Recently 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 2024 Common Case are shown in Figure 16. The graph is color coded by utilization metric to show the path flow results and screening thresholds.[footnoteRef:15] The utilization metrics are sorted according to the U90 metric. 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. [15: 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 50% of the year; or greater than or equal to 90% for more than 20% of the year; or greater than or equal to 99% for 5% of the year.]
Figure 16: Most Heavily Utilized Paths - 2024 Common Case
Paths 52 and 60 often become congested in TEPPC studies due to the siting of renewable resources near the California Nevada border to the north and east of Big Pine, California that must be delivered on these low voltage lines.
The implementation of the California Global Warming Solutions Act (AB32) appears to have impacted the flows on paths 65 and 66. The modeling methodology involves setting a CO2 emission penalty for in-state resources and an import tax for imports from other states. An agreement between California and BPA to exempt imports of surplus hydro generation from the carbon import tax is roughly modeled using monthly tiered-hurdle-rate adders that are tied to the historic surplus of hydro energy. The tiers and flow results are shown in Figure 17. The tiers represent the megawatt values at which the hurdle rate increases from $0.53/MWh to$11.97/MWh. The second chart (Figure 18) helps to explain the periods where the flow is below the tier 1 amount due to low LMP prices in California.
Figure 17: Impact of AB32 Tiered rates on Paths 65 & 66
Figure 18: Area Load-weighted LMP
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 2010 and 2012, and also to the 2022 Common Case.
The results for path 3 in Figure 19 show a good correlation to historic flows, but perhaps a data problem in the 2022 Common Case.
Figure 19: Path 3
The results for path 26 show an increased flow compared to historical. This could be related to the loss of San Onofre and/or the new hydro generation in British Columbia.
Figure 20: Path 26
The impact of the California Global Warming Solutions Act (AB32) is evident in the path flow results for path 27 in Figure 21. The carbon price adder ($27.51/metric-ton) reduces the economics of the Intermountain coal plant.
Figure 21: Path 27
The energy deliveries on path 46 were lower than historical, likely impacted by the renewable build-out in California as well as the effects of AB32.
Figure 22: Path 46
Conclusions and Observations
The portion of the annual WECC generation by renewable resources in the 2024 Common Case was 17.3 percent, including some incremental distributed solar resources. This represents an increase of 0.6 percent from the 2022 Common Case.
Based on the input and modeling assumptions, the CO2 results for the western states[footnoteRef:16] show a significant shortfall in meeting the EPA CO2 emission goal[footnoteRef:17] for 2024, as depicted in Figure 23. The states with the worst shortfalls are California, Arizona, Wyoming, Colorado, and Utah. Some of the contributing factors are load growth, retirement of San Onofre, and uncertain[footnoteRef:18] retirement plans for a few coal plants. [16: Includes AZ, CA, CO, ID, MT, OR, NV, NM, UT, WA, and WY. States having a majority of their load outside of WECC are excluded.] [17: Assuming a linear reduction from 2005 to 2030.] [18: There have been discussions regarding the potential retirements of Centralia 2, Cholla [1,3,4], Intermountain [1,2], and Valmy 2 in 2025.]
Figure 23: CO2 results and targets
The high capacity factor of San Onofre and other base-load units makes their replacement inconsequential. At 2200 MW capacity and a capacity factor of 90 percent, San Onofre would have provided over 17,300 GWh of energy each year. The chart in Figure 4 provides some indication of what may have replaced San Onofre in the 2024 Common Case. The large increase in gas-fueled generation is likely driving the high CO2 emissions.
The California interchange has been discussed in several forums. A chart of the chronological California interchange in the 2024 Common Case is shown in Figure 24. Remote generation that was assigned to California load areas was backed out for this chart, including Copper Mountain, Desert Star, ESJ, IGS, La Rosita, Milford, Parker1, remote RPS, and TDM. These units use the WECC paths for delivery and would thus be part of the interchange. The message from the stakeholders suggested that the imports into California would be as high as 13,000 MW.
Figure 24: California interchange
The methodology for developing the generation assumptions has become more complex in recent years. In the 2024 Common Case there are approximately 36,000 MW of net generation additions modeled, while the peak load only grew by about 24,000 MW. This is a function of the following resource adequacy assumptions:
Sufficient generation and imports are required for each subregion to meet the sum of its peak load and planning reserve requirement.
The reserve requirement increases proportionally with the load (i.e., a 10 percent reserve for a 1000 MW load is 100 MW, versus 110 MW for an 1100 MW load).
The capacities of certain generator types are reduced in a resource adequacy analysis to reflect their expected availabilities at time of peak load. The assumed summer peak capacity value ranges are provided in Table 5. Note that the reductions for Solar PV and Wind are quite substantial, such that a 1000 MW wind farm may only be counted on for 100 MW at time of peak assuming a 10 percent availability. If the load growth was served by only wind, it would be necessary to add 240,000 MW of wind capacity. By adding a diverse group of combined cycle, combustion turbine, solar, wind, hydro and storage resources, only 36,000 MW of additions and load modifiers were needed.
Table 5: Availability Factor Ranges (at time of peak demand)
Generation Type
Capacity Range (%)
Generation Type
Capacity Range (%)
Biomass
65 100
Nuclear
100
Coal
100
Other Steam
100
Combined Cycle
95 100
Pumped Storage
100
Combustion Turbine
95 100
Solar CSP0
72 95
Geothermal
70 100
Solar CSP6
95 100
Hydro Conv.
70 95
Solar PV
60
Hydro Small
35
Wind
5 16
Overall, the 2024 Common Case is a fairly decent representation of what the Western Interconnection could look like in 2024. Stakeholders are invited to submit any and all recommendations regarding the case to WECC.
Appendix A
Additional Tables and Charts
Table 6: Cumulative Capacities (MW) by Type and Year
Pre-2010
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
Conventional Hydro
62,615
63,527
63,684
63,841
64,216
65,068
65,727
65,983
66,005
65,917
65,917
65,819
65,772
65,772
66,872
66,790
Energy Storage
4,729
4,729
4,749
4,769
4,934
4,934
4,934
6,219
6,219
6,219
6,219
6,219
6,219
6,219
6,219
6,219
Steam - Coal
37,437
38,213
38,855
38,757
37,982
37,634
37,157
36,897
35,265
34,935
33,317
32,019
31,765
31,765
31,765
31,765
Steam - Other
19,820
19,482
19,322
18,850
16,888
15,586
14,277
13,476
10,597
10,584
10,584
4,420
4,307
4,231
3,293
3,088
Nuclear
9,532
9,532
9,532
9,532
7,382
7,382
7,382
7,382
7,382
7,382
7,382
7,382
7,382
7,382
7,382
7,382
Combined Cycle
48,379
49,834
50,636
51,677
53,147
54,567
58,816
59,750
60,724
62,142
62,701
63,985
63,985
63,781
64,286
64,131
Combustion Turbine
19,926
20,514
21,630
22,381
25,174
26,313
27,682
30,240
30,498
31,497
31,768
32,249
32,349
32,450
34,783
34,783
IC
597
760
809
809
809
809
1,028
1,028
1,028
1,028
1,028
1,028
1,028
1,028
1,028
1,028
Other
1,330
1,330
1,330
1,330
1,330
1,330
1,330
1,330
1,330
1,330
1,330
1,330
1,330
1,330
1,330
1,330
DG/DR/EE - Incremental
0
0
0
0
0
0
0
1,013
1,013
1,013
1,013
1,013
1,013
1,013
13,123
13,123
Biomass RPS
2,170
2,281
2,472
2,773
2,896
3,021
3,124
3,120
3,100
3,032
2,920
2,842
2,682
2,621
2,937
2,875
Geothermal
2,755
2,755
2,890
3,047
3,274
3,314
3,349
3,349
3,325
3,306
3,306
3,332
3,332
3,332
3,880
3,880
Small Hydro RPS
1,163
1,163
1,178
1,178
1,178
1,178
1,185
1,185
1,185
1,185
1,185
1,120
1,120
1,120
1,120
1,120
Solar
612
722
1,018
2,302
5,274
6,788
8,483
8,983
9,062
9,471
9,551
9,631
9,659
9,673
15,536
15,551
Wind
10,773
13,045
15,316
20,278
22,188
23,781
25,154
25,499
25,979
27,801
28,101
28,101
28,100
28,100
29,166
29,166
150,894175,169888,2351,031,254800,000850,000900,000950,0001,000,0001,050,000135,000140,000145,000150,000155,000160,000165,000170,000175,000180,000
Peak Demand (MW)Annual Energy (GWh)
Trend ------------------>>
-20,000-15,000-10,000-5,00005,00010,00015,000
Conventional HydroEnergy StorageSteam - CoalSteam - OtherNuclearCombined CycleCombustion TurbineICOtherDG/DR/EE - IncrementalBiomass RPSGeothermalSmall Hydro RPSSolarWind
(20,000)(15,000)(10,000)(5,000)05,00010,00015,00020,00025,00030,000AZCACOIDMTNMNVORUTWAWYNESDTXABBCMX
Generation Additions (MW) from 2013 -2024
WindSolarSmall Hydro RPSGeothermalBiomass RPSICCombustion TurbineCombined CycleNuclearSteam - OtherSteam - CoalEnergy StorageConventional Hydro
010,00020,00030,00040,00050,00060,00070,000
Cumulative Capacity (MW) by Category -2024 Common Case
Conventional HydroEnergy StorageSteam - CoalSteam - OtherNuclearCombined CycleCombustion TurbineICOtherDG/DR/EE - IncrementalBiomass RPSGeothermalSmall Hydro RPSSolarWind
Biomass RPS 1.3%Combined Cycle 29.7%Combustion Turbine
13.3%
DG/DR/EE1.9%Hydro+ES23.7%Geothermal 2.1%Nuclear 4.1%Small Hydro RPS 0.4%Solar 4.2%Steam -Coal 16.9%Steam -Other 0.8%Wind 1.1%Other0.4%
Generation at Peak Hour
050100150200250300350Number of UnitsNumber of Starts
Number of Units with Range of Starts
Conventional HydroSteam - CoalSteam - OtherCombined CycleCombustion TurbineICBiomass RPS
0100200300400500600Number of UnitsCapacity Factor
Number of Units with Range of Capacity Factors
Conventional HydroSteam - CoalSteam - OtherCombined CycleCombustion TurbineICBiomass RPS
-20,000-15,000-10,000-5,00005,00010,00015,00020,000
AZCACOIDMTNENMNVORSDTXUTWAWY
Difference Run vs EIA by Type and State (GWh)
Hourly ResourceHydroPumped StorageThermalTotal
Positive = Run was higher than EIA
-3000-2000-10000100020003000400050006000
114829544258973688310301177132414711618176519122059220623532500264727942941308832353382352936763823397041174264441145584705485249995146529354405587573458816028617563226469661667636910705772047351749876457792793980868233838085278674
AB32 Tier 1COI plus PDCI
010203040506070
1145289433577721865100911531297144115851729187320172161230524492593273728813025316933133457360137453889403341774321446546094753489750415185532954735617576159056049619363376481662567696913705772017345748976337777792180658209835384978641
PG&ELDWPBPA
-4000-3000-2000-100001000200030004000
Megawatts
P03 Northwest-British Columbia Path Duration Plots
201020122022PC1_CC2024_PC1_1_5
Net 4827 -2545 -16811 -4134
-4000-3000-2000-1000010002000300040005000
Megawatts
P26 Northern-Southern California Path Duration Plots
201020122022PC1_CC2024_PC1_1_5
Net 5752 7348 23680 11725
-2000-1500-1000-500050010001500200025003000
Megawatts
P27 Intermountain Power Project DC Line Path Duration Plots
201020122022PC1_CC2024_PC1_1_5
Net 12471 11076 10758 8287
-15000-10000-5000050001000015000
Megawatts
P46 West of Colorado River (WOR) Path Duration Plots
201020122022PC1_CC2024_PC1_1_5
Net 44091 44955 19712 33554
400,000450,000500,000550,000600,000650,000700,000750,000
US WEST CO
2
Target (Million LBS)
EPA GoalActual2024 PC1 v1.5
-15000-13000-11000-9000-7000-5000-3000-1000100030005000
Calif Interchange Balance (gen -load) -2024 PC1 15-04-09 (MW)
Average is -6596 MW
Conventional Hydro23.7%Energy Storage2.2%Steam -Coal11.3%Steam -Other1.1%Nuclear2.6%Combined Cycle22.7%Combustion Turbine12.3%IC0.4%Other0.5%DG/DR/EE -Incremental4.6%Biomass RPS1.0%Geothermal1.4%Small Hydro RPS0.4%Solar5.5%Wind10.3%
Net Generation Capacity -2024 (MW)
