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
2024 PC1 Common Case
ii
Overview
This document is for technical review purposes only. It has not been endorsed or approved by the
WECC Board of Directors, the Transmission Expansion Planning Policy Committee (TEPPC), the TEPPC
Scenario Planning Steering Group (SPSG), or WECC Management.
The current results are from the PC1 version 1.5 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.1
1
2024 Common Case & Release Notes.
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Table of Contents
Introduction...................................................................................................................................... 1
Abstract of Case ................................................................................................................................ 2
Key Inputs and Results from TEPCC 2024 Common Case Version 1.5 ................................................... 2
Load ..................................................................................................................................................... 3
Generation .......................................................................................................................................... 4
CO2 Emissions...................................................................................................................................... 7
Transmission congestion..................................................................................................................... 7
Additional Discussion of Input Assumptions and Study Results .......................................................... 9
Study Limitations .................................................................................................................................... 9
Dataset Updates...................................................................................................................................... 9
Summary Inputs and Assumptions ....................................................................................................... 10
Load Topology ................................................................................................................................... 10
Transmission Network ...................................................................................................................... 11
Generation Resources....................................................................................................................... 12
Load Modifiers .................................................................................................................................. 15
Overriding Assumptions.................................................................................................................... 16
Key Data and Modeling Improvements ............................................................................................ 17
Future Data Improvements............................................................................................................... 18
Additional Study Results ....................................................................................................................... 18
Generation by State/Province .......................................................................................................... 18
Peak Hour Breakdown ...................................................................................................................... 20
Generator Operational Statistics ...................................................................................................... 21
Transmission Path Flows ................................................................................................................... 23
Conclusions and Observations ......................................................................................................... 28
Appendix A ..................................................................................................................................... 31
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Introduction
The 2024 Common Case is a production cost model (PCM) dataset that serves as the “expected future”
10-year 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.
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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
Generation Capacity (MW)
Annual Generation (GWh)
Peak Demand (MW)
Key Results
Transmission Congestion (%U90)3
Hydro
Thermal
Renewable
Other
<Total>
Hydro
Thermal
Renewable
Other
<Total>
Summer
Winter
Unserved Load (MWh)
Var. Production Cost (M$)
CO2 Emissions (MMetTons)
Dump2 Generation (MWh)
Path 3
Path 26
Path 46
Path 65
Path 66
2013
66,117
141,030
31,524
1,385
240,056
n/a
155,000
128,000
n/a
Confidential
2024
66,790
134,601
52,592
20,672
274,655
238,956
618,219
168,293
24,874
1,050,342
175,169
0
22,843
363
357,799
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.
2
Dump energy is generation that would have been dispatched if not for a constraint such as a transmission limit.
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.
3
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Load
The components of the projected WECC peak demand and energy load4 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.
Table 2: Load Forecast Components
Load Components
Native Load
Pumping Load
Energy Storage Pumping
Exports
DG/DR/EE Incremental
Total
2024 Forecast and Load modifiers
Summer Peak
Winter Peak
Annual Energy
(MW)
(MW)
(GWh)
176,914
1,029,552
1,038
11,132
0
3,122
510
5,365
-3,293
-17,917
175,169
1,031,254
Figure 1: Load Growth
Peak Demand (MW)
Annual Energy (GWh)
1,031,254 1,050,000
180,000
175,000
175,169 1,000,000
170,000
165,000
950,000
160,000
155,000 888,235
900,000
150,000
145,000
150,894
850,000
140,000
135,000
800,000
Trend ------------------>>
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.
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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 capacity5 changes for the referenced resource types are shown in
Figure 2, with a net capacity change of 23,928 MW (excluding the load modifiers).
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
Conventional Hydro
Energy Storage
Steam - Coal
Steam - Other
Nuclear
Combined Cycle
Combustion Turbine
IC
Other
DG/DR/EE - Incremental
Biomass RPS
Geothermal
Small Hydro RPS
Solar
Wind
-20,000
5
-15,000
-10,000
-5,000
0
5,000
10,000
15,000
The reported capacities represent the highest “available to the grid” capacities over the study year.
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The 2024 Common Case was run through a production cost model6 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.
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.7
The effect of the retirement of the San Onofre nuclear plant in southern California is also
evident with a reduction in nuclear energy.
6
For the current cycle WECC used ABB GridView for the PCM studies.
Coal generation displacement was primarily due to implementation of the California Global Warming Solutions Act (AB32)
and increased penetrations of renewable resources.
7
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6
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)
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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 congestion8
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:




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8
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 path’s 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.
Congestion refers to a condition where the flow may have been higher if not for a defined limit.
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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:
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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.
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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 generator’s output can become undeliverable and create
dump energy.9 There are a few instances where this has occurred in the common case, and these
may be addressed in a future release.
Load Shapes: The hourly load shapes for each load area are based on the actual hourly loads from
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.

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
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.
9
Dump energy is generation that would have been dispatched if not for a constraint such as a transmission limit.
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Summary Inputs and Assumptions
The detailed input assumptions are provided in a one-hundred page document of release notes.10 A
few of the assumptions are listed in relevant sections below to provide a basis for the enclosed results.
Load Topology
Each of the WECC Balancing Authorities (BA) provides a ten-year forecast of their monthly peak and
energy loads each year. A few of the BAs provide a more granular breakdown to support the TEPPC
load topology as shown in Figure 6. The forecasts that were submitted in March 2013 were used for
the 2024 Common Case.
Figure 6: TEPPC Load Area Topology
10
Link to release notes: 2024 Common Case & Release Notes.
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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.
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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.
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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
Arapahoe 3,4
Battle River 3
Ben French 1
Boardman
Carbon 1,2
Centralia 1
Cherokee 3 [CTG]*
Cherokee 4
Cholla 2
Four Corners 1-3
HR Milner
JE Corette
Lamar 4,6
Naughton 3 [CTG]*
Navajo (1 unit of 3)
Neil Simpson 1
Osage 1-3
Reid Gardner 1-3
Reid Gardner 4
RioBravo Jasmin
San Juan 2,3
Sundance 1,2
Valmont 5
Valmy 1
WN Clark 1,2
Total
State/Province
Colorado
Alberta
S. Dakota
Oregon
Utah
Washington
Colorado
Colorado
Arizona
Arizona
Alberta
Montana
Colorado
Wyoming
Arizona
Wyoming
Wyoming
Nevada
Nevada
California
New Mexico
Alberta
Colorado
Nevada
Colorado
Retired Capacity (MW)
2022
2024
153
153
148
148
0
25
610
610
0
172
688
688
0
0
352
352
0
262
560
560
144
144
0
153
0
38
0
0
0
750
0
18
0
30
330
330
0
257
35
35
0
839
0
576
184
184
0
254
0
40
3,204
6,618
*Converting to gas, Cherokee 3 (152 MW), Naughton 3 (330 MW), Other (70 MW)
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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
Generation Additions (MW) from 2013 - 2024
30,000
25,000
20,000
Wind
Solar
15,000
Small Hydro RPS
Geothermal
10,000
Biomass RPS
IC
5,000
Combustion Turbine
Combined Cycle
0
Nuclear
Steam - Other
(5,000)
Steam - Coal
Energy Storage
(10,000)
Conventional Hydro
(15,000)
(20,000)
AZ
CA
CO
ID
MT NM NV OR UT WA WY NE
SD
TX
AB
BC MX
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.
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Figure 9: Cumulative Resource Capacity Assumptions
Cumulative Capacity (MW) by Category - 2024 Common Case
70,000
60,000
Conventional Hydro
Energy Storage
Steam - Coal
50,000
Steam - Other
Nuclear
40,000
Combined Cycle
Combustion Turbine
IC
30,000
Other
DG/DR/EE - Incremental
20,000
Biomass RPS
Geothermal
Small Hydro RPS
10,000
Solar
Wind
0
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.
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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.
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Table 4: Load Modifiers Modeled as Generators (GWh)
AZ
Distributed
Generation
2,784
Demand
Response
0.456
Energy
Efficiency
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
13,336
6.49
4,574
State
Total
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)11 of generation.

BA Reserve Requirements: The BAs intend to meet their projected loads and reserve requirements.
Resources are selected from the class portfolios in order of class, until the RPS requirement is met
and the load and reserve are met.
11
The established classes are: existing, under-construction, approved and/or financed, and future conceptual.
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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.


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
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 charges12 (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.
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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 25percent-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 contractually13 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.
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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.
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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.
Generation at Peak Hour
Other
0.4%
Wind
1.1%
Biomass RPS
1.3%
Steam - Other
0.8%
Combined Cycle
29.7%
Steam - Coal
16.9%
Combustion
Turbine
13.3%
Solar
4.2%
A ten-day snapshot of the hourly
Small Hydro RPS
generation by category that
0.4%
Nuclear
includes the peak hour is presented
4.1%
Geothermal
in Figure 12. For WECC overall, the
2.1%
primary resource types that follow
the load are hydro, combined cycle, combustion turbine, and solar.14
DG/DR/EE
1.9%
Hydro+ES
23.7%
Figure 12: Ten-day Snapshot of Hourly Generation - WECC
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.
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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
Number of Units with Range of Starts
350
Number of Units
300
250
Conventional Hydro
200
Steam - Coal
150
Steam - Other
100
Combined Cycle
Combustion Turbine
50
IC
0
Biomass RPS
Number of Starts
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 PumpStorage, 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.
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Figure 14: Capacity Factors by Category
Number of Units with Range of Capacity Factors
600
Number of Units
500
Conventional Hydro
400
Steam - Coal
300
Steam - Other
200
Combined Cycle
100
Combustion Turbine
IC
0
Biomass RPS
Capacity Factor
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.
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Figure 15: Results compared to EIA 2012 actual
Difference Run vs EIA by Type and State (GWh)
Hourly Resource
Hydro
Pumped Storage
Thermal
Total
20,000
Positive = Run was higher than EIA
15,000
10,000
5,000
0
-5,000
-10,000
-15,000
-20,000
AZ
CA
CO
ID
MT
NE
NM
NV
OR
SD
TX
UT
WA
WY
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.
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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.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.
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.
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.
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Figure 17: Impact of AB32 Tiered rates on Paths 65 & 66
AB32 Tier 1
COI plus PDCI
6000
5000
4000
3000
2000
1000
0
-1000
-2000
1
148
295
442
589
736
883
1030
1177
1324
1471
1618
1765
1912
2059
2206
2353
2500
2647
2794
2941
3088
3235
3382
3529
3676
3823
3970
4117
4264
4411
4558
4705
4852
4999
5146
5293
5440
5587
5734
5881
6028
6175
6322
6469
6616
6763
6910
7057
7204
7351
7498
7645
7792
7939
8086
8233
8380
8527
8674
-3000
Figure 18: Area Load-weighted LMP
PG&E
LDWP
BPA
70
60
50
40
30
20
10
1
145
289
433
577
721
865
1009
1153
1297
1441
1585
1729
1873
2017
2161
2305
2449
2593
2737
2881
3025
3169
3313
3457
3601
3745
3889
4033
4177
4321
4465
4609
4753
4897
5041
5185
5329
5473
5617
5761
5905
6049
6193
6337
6481
6625
6769
6913
7057
7201
7345
7489
7633
7777
7921
8065
8209
8353
8497
8641
0
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.
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Figure 19: Path 3
P03 Northwest-British Columbia Path Duration Plots
4000
3000
Megawatts
2000
1000
0
-1000
-2000
-3000
-4000
Net 4827
-2545
2010
2012
-16811
2022PC1_CC
-4134
2024_PC1_1_5
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
P26 Northern-Southern California Path Duration Plots
5000
4000
3000
Megawatts
2000
1000
0
-1000
-2000
-3000
Net 5752
-4000
2010
7348
2012
23680
2022PC1_CC
11725
2024_PC1_1_5
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.
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Figure 21: Path 27
P27 Intermountain Power Project DC Line Path Duration Plots
3000
2500
2000
Megawatts
1500
1000
500
0
-500
-1000
-1500
Net 12471
-2000
2010
11076
2012
10758
2022PC1_CC
8287
2024_PC1_1_5
The energy deliveries on path 46 were lower than historical, likely impacted by the renewable buildout in California as well as the effects of AB32.
Figure 22: Path 46
P46 West of Colorado River (WOR) Path Duration Plots
15000
10000
Megawatts
5000
0
-5000
-10000
Net 44091
-15000
2010
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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 states16 show a
significant shortfall in meeting the EPA CO2 emission goal17 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 uncertain18 retirement plans
for a few coal plants.
Figure 23: CO2 results and targets
US WEST CO2 Target (Million LBS)
750,000
700,000
650,000
600,000
550,000
500,000
450,000
400,000
EPA Goal

Actual
2024 PC1 v1.5
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.
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.
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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
Calif Interchange Balance (gen - load) - 2024 PC1 15-04-09 (MW)
5000
Average is -6596 MW
3000
1000
-1000
-3000
-5000
-7000
-9000
-11000
-13000
-15000

W
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:
o Sufficient generation and imports are required for each subregion to meet the sum of its
peak load and planning reserve requirement.
o 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).
o 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
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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
Biomass
Coal
Combined Cycle
Combustion Turbine
Geothermal
Hydro – Conv.
Hydro – Small

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Capacity Range
(%)
65 – 100
100
95 – 100
95 – 100
70 – 100
70 – 95
35
Generation Type
Nuclear
Other Steam
Pumped Storage
Solar CSP0
Solar CSP6
Solar PV
Wind
Capacity Range
(%)
100
100
100
72 – 95
95 – 100
60
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.
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Appendix A
Additional Tables and Charts
Table 6: Cumulative Capacities (MW) by Type and Year
Conventional
Hydro
Energy Storage
Pre2010
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
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
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
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
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
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
Nuclear
Combined
Cycle
Combustion
Turbine
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
DG/DR/EE Incremental
Biomass RPS
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
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
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
Small Hydro
RPS
Solar
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
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
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
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
Wind
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Net Generation Capacity - 2024 (MW)
Combustion Turbine
12.3%
Combined Cycle
22.7%
IC
0.4%
Other
0.5% DG/DR/EE Incremental
4.6%
Biomass RPS
1.0% Geothermal
1.4%
Nuclear
2.6%
Small Hydro RPS
0.4%
Steam - Other
1.1%
Solar
5.5%
Steam - Coal
11.3%
Wind
10.3%
Energy Storage
2.2%
Conventional Hydro
23.7%
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