TEPPC Study Report: 2026 PC1 Common Case CCV1.7-StudyReport...resource mix and transmission planning...

TEPPC Study Report: 2026 PC1 Common Case

WECC Staff

Draft: January 13, 2017

155 North 400 West, Suite 200

Salt Lake City, Utah 84103‐1114

2026 PC1 Common Case ii

W E S T E R N E L E C T R I C I T Y C O O R D I N A T I N G C O U N C I L

Overview

This document is for technical review purposes only. It has not been endorsed or approved by the

WECC Board of Directors, the Transmission Expansion Planning Policy Committee (TEPPC), the TEPPC

Scenario Planning Steering Group (SPSG), or WECC Management.

The current results are from the PC1 version 1.7 dataset. The detailed input assumptions are available

in the release notes.1

1 2026 Common Case & Release Notes v1.5

2026 PC1 Common Case Report ‐ DRAFT iii


Table of Contents

Introduction ........................................................................................................................................ 1

Abstract of Case .................................................................................................................................. 2

Key Inputs and Results from TEPCC 2026 Common Case Version 1.7 ................................................... 5

Load ..................................................................................................................................................... 5

Generation .......................................................................................................................................... 6

CO2 Emissions ...................................................................................................................................... 9

Transmission congestion .................................................................................................................... 9

Additional Discussion of Input Assumptions and Study Results ......................................................... 11

Study Limitations .................................................................................................................................. 11

Dataset Updates ................................................................................................................................... 11

Summary Inputs and Assumptions ....................................................................................................... 12

Load Topology ................................................................................................................................... 12

Changes in Load ................................................................................................................................ 13

Transmission Network ...................................................................................................................... 13

Generation Resources ....................................................................................................................... 14

Load Modifiers .................................................................................................................................. 17

Overriding Assumptions .................................................................................................................... 17

Key Data and Modeling Improvements ............................................................................................ 18

Additional Study Results ....................................................................................................................... 18

Generation by State/Province .......................................................................................................... 19

Peak Hour Breakdown ...................................................................................................................... 20

Transmission Path Flows ................................................................................................................... 21

Conclusions and Observations ........................................................................................................... 28

Appendix A ....................................................................................................................................... 31

2026 PC1 Common Case 1


Introduction

The 2026 Common Case is a production cost model (PCM) dataset that serves as an “expected future”

of loads, resources and transmission topology in 2026 for the Transmission Expansion Planning Policy

Committee (TEPPC). The case represents the compilation of recent Western Interconnection planning

information, developments and policies looking out 10 years to the year 2026.

A primary goal in developing a Common Case is to define a reasonable foundation for the other

resource mix and transmission planning studies (year‐10 time frame) that are conducted as part of the

2016 TEPPC Study Program. 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. The TEPPC and WECC staff wishes to express

appreciation to everyone who contributed to this effort.

PCM Simulation Parameters

The version and simulation parameters are provided in Table 1.

Table 1: Simulation Parameters

Description Parameter

GridView Version 9.5.14 [2016‐11‐10] 64bit

Generator Reserve Distribution Yes

Generator Exempt Yes

Ramp Rate Enforced Yes – In Unit Commitment

Quick Start Commitment Yes

Look Ahead Logic No

Use Loss Model Yes

Recalculate Loss Matrix Yes

Remove Losses in Loads Yes

Hydro Thermal Coordination Yes

2026 PC1 Common Case Report ‐ DRAFT 2


Abstract of Case

The 2026 TEPPC Common Case is a collection of assumptions that are designed to depict the most

likely representation of the WECC Bulk Power System for the year 2026. Table 2 provides a high‐level

summary for comparison purposes of a few of the inputs and results including, where available, actual

data for 2015 from the WECC 2016 State of the Interconnection (SOTI) report.

Table 2: Summary Table Comparison

Category Item 2015 2026 Change

Peak Demand (MW) Summer Winter

150,700126,200

164,354 148,473

9.1% 17.6%

Generation Capacity (MW)

Hydro + Energy Storage Thermal – Coal Thermal – Gas Thermal – Nuclear Thermal ‐ Other Renewable DG/DR/EE Incremental <Total>

71,30038,700106,000

7,7001,700

39,6000

265,000

68,004 28,028 97,991 5,082 1,053

53,419 21,286 274,863

‐4.6% ‐27.6% ‐7.6% ‐34.0% ‐38.1% 34.9% NA 3.7%

Annual Generation (GWh)

Hydro + Energy Storage Thermal – Coal Thermal – Gas Thermal – Nuclear Thermal ‐ Other Renewable DG/DR/EE Incremental <Total>

196,600216,900266,30060,20017,10083,400

0840,500

243,822 185,693 326,281 39,192 1,989

171,794 30,439 999,210

24.0% ‐14.4% 22.5% ‐34.9% ‐88.4% 105.4% NA

18.8%

A few key observations are:

The increased energy from hydro and energy storage implies an assumption of higher hydro

flows and increased energy storage opportunities.

The reduction in coal is due to several coal‐fired generator retirements and the impact of

carbon price regulations in Alberta, British Columbia, and California.

The reduction in nuclear is due to the announced retirement of the Diablo Canyon Nuclear

Power Station in northern California.

The chart in Figure 1 compares the annual generation by category from the 2026 common case to the

two previous common cases for 2022 and 2024. This clearly shows the progression of retirement plans

for coal and nuclear generation.



Figure 1: Comparison of Annual Generation

Figure 2: Comparison of Total Generation

It is not clear from Figure 1 that the amount of

load to be served fluctuates between common

cases, as apparent in Figure 2. A few of the

factors driving the fluctuations are load forecast

variances, energy storage impacts, and varying

flows between BA’s.

Coal Retirement Assumptions

The retirement of coal‐fired generation has been a key focus area during the last few years. In the 2026

dataset, WECC has reflected the actual retirements and the announced future retirements as plans are

finalized. These assumptions are provided in Table 3.

0 50,000 100,000 150,000 200,000 250,000 300,000 350,000

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

Annual Generation (GWh) by Category

2022 PC1 Final 2024 PC1 v1.5 2026 WECC v1.7

960,000

980,000

1,000,000

1,020,000

1,040,000

1,060,000

2022 PC1 Final 2024 PC1 v1.5 2026 WECC v1.7

Total Generation (GWh)



Table 3: Coal Retirement Assumptions ‐ 2026 Case vs. 2024 Case

Coal Generator State/Province Retirement

Year Retired Capacity (MW)

2024 2026 ACE Cogen California 2014 103 103

Arapahoe 3,4 Colorado 2013 153 153

Battle River 3 Alberta 2019 148 148

Battle River 4 Alberta 2025 0 148

Ben French 1 S. Dakota 2013 25 25

Boardman Oregon 2020 610 610

Carbon 1,2 Utah 2015 172 172

Centralia 1 Washington 2020 688 688

Centralia 2 Washington 2024 0 670

Cherokee 3 Colorado 2015 152 152

Cherokee 4 [CTG]* Colorado 2017 0 0

Cholla 2 Arizona 2016 262 262

Cholla 4 Arizona 2024 0 380

Colstrip 1,2 Montana 2022 0 614

Craig 1 Colorado 2025 0 428

Four Corners 1‐3 Arizona 2014 560 560

HR Milner Alberta 2019 144 144

JE Corette Montana 2015 153 153

Kennecott 1‐3 Utah 2016 0 100

Lamar 4,6 Colorado 2012 38 38

Martin Drake 5 Colorado 2017 0 50

Naughton 3 [CTG]* Wyoming 2018 0 0

Navajo (1 unit of 3) Arizona 2019 750 750

Neil Simpson 1 Wyoming 2014 18 18

Nucla 1‐4 Colorado 2022 0 100

Osage 1‐3 Wyoming 2010 30 30

Reid Gardner 1‐3 Nevada 2014 300 300

Reid Gardner 4 Nevada 2017 287 287

RioBravo Jasmin California 2012 35 35

San Juan 2,3 New Mexico 2017 839 839

Sundance 1,2 Alberta 2019 576 576

Valmont 5 Colorado 2017 184 184

Valmy 1 Nevada 2021 254 254

Valmy 2 Nevada 2025 0 268

WN Clark 1,2 Colorado 2013 40 40

Total 6,521 9,279 *Converting to gas, Cherokee 4 (352 MW), Naughton 3 (330 MW)



Key Inputs and Results from TEPCC 2026 Common Case Version 1.7

A few key inputs and results of the 2026 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 load2 in the 2026 Common Case are

provided in Table 4 and compared to the 2015 actual values in Figure 3. The summer and winter peak

values represent the common case inputs and results during the hour in which the summer and winter

peaks occurred, namely, July 27 at 4:00 pm, and December 8 at 7:00 pm.

Table 4: Load Forecast Components

Load Components 2026 Forecast and Load modifiers3

Summer Peak (MW)

Winter Peak (MW)

Annual Energy (GWh)

Native Load4 Base 170,020 148,871 991,732

Native Load Pumping 537 504 7,511

Energy Storage Pumping 2 17 4,482

Exports 0 0 0

Losses Netted from Load ‐779 ‐768 ‐4,515

Served Load Subtotal 169,780 148,624 999,210

(DG/DR/EE Incremental) ‐5,426 ‐151 ‐30,439

Total Net Energy Load 164,354 148,473 968,771

The peak demand in the 2026 common case is estimated to be 13,654 MW higher than the 2015 actual

peak demand.

2 For modeling purposes the incremental distributed generation (DG), demand response (DR), and energy efficiency (EE) are represented as generators. In reality these components would decrease the load by the amounts in Table 4. 3 Load Modifiers refer to DG, DR, and EE, which can be modeled as a direct load reduction or as generators. 4 Native Load is the collection of end‐use customers that the Load‐Serving Entity is obligated to serve.



Figure 3: Load Growth

Generation

The generation inputs for the 2026 Common Case reflect existing resources plus planned resource

changes between 2015 and 2026. The total net capacity5 changes for the referenced resource types are

shown in Figure 4, with a net capacity change of 12,706 MW (excluding the load modifiers). Note that

these changes are based on the common case input assumptions and may be different than the SOTI

assumptions used in Table 2.

The coal retirements are based on data submittals and media announcements from the Generator

Owners and Balancing Authorities. The majority of the “Steam‐Other” retirements are associated with

the compliance agreements for the California Once‐Through‐Cooling (OTC) requirements.

The largest increase is in the Distributed Generation/Demand Response/Energy Efficiency (DG/DR/EE)

– Incremental category, and reflects the modeling of existing and future Behind‐the‐Meter

Photovoltaic (BTM‐PV). The additions for solar and wind are also significant and will be discussed in

more detail later in the report.

5 The reported capacities represent the highest “available to the grid” capacities over the study year.

150,700

164,354

883,600

968,771

870,000

884,000

898,000

912,000

926,000

940,000

954,000

968,000

982,000

150,000

155,000

160,000

165,000

170,000

GWh

MW

Peak Demand (MW) Annual Energy (GWh)

Trend ‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐>>



Figure 4: Key Resource Net Capacity Change (MW) between 1/1/2015 and 1/1/2026

The 2026 Common Case was modeled using a production cost model6 to obtain a load/resource

solution for each hour of 2026. A breakdown of the resulting annual generation by category based on

the input and modeling assumptions is shown in Figure 5. The largest shares of production were from

combined cycle generation (28.6 percent) and conventional hydro (24.1 percent). The share from

renewable generation (including incremental DG) was 17.0 percent.

6 WECC uses ABB GridView for their PCM studies.

‐15,000 ‐10,000 ‐5,000 0 5,000 10,000 15,000 20,000 25,000

Conventional Hydro

Energy Storage

Steam ‐ Coal

Steam ‐ Other

Nuclear

Combined Cycle

Combustion Turbine

IC

Other


Biomass RPS

Geothermal

Small Hydro RPS

Solar

Wind



Figure 5: Breakdown of Annual Generation ‐ 2026 Common Case

There have been several changes that impacted the generation mix in the 2026 dataset versus the

2024 common case dataset. A comparison of the annual generation for the two datasets (2024 vs.

2026) is shown in Figure 6. The most notable differences are listed below.

The reduction in coal‐fired generation due to unit retirements and displacements.7

The effect of the retirement of the Diablo Canyon nuclear plant in northern California is also

evident with a reduction in nuclear energy.

A continued shift in renewable generation assumptions due to cost reductions in solar power.

There was a 4.9 percent decrease in total generation between the 2024 Common Case and the

2026 Common Case, largely due to revised load growth assumptions in a few areas.

7 Coal generation displacement was primarily due to implementation of carbon taxes in Alberta, British Columbia, and California, and increased penetrations of renewable resources.

Conventional Hydro24.1%

Energy Storage0.3%

Steam ‐ Coal18.6%

Steam ‐Other0.2%

Nuclear3.9%

Combined Cycle28.6%

Combustion Turbine4.0%

IC0.1%

Other0.0%

DG/DR/EE ‐ Incremental3.0%

Biomass RPS2.1%

Geothermal3.1%

Small Hydro RPS0.4%

Solar4.2%

Wind7.2%

Annual Generation Breakdown By Category ‐ 2026 WECC v1.7



Figure 6: Annual Generation by Category (2024 vs 2026)

CO2 Emissions

The annual CO2 emissions in the 2026 common case were 12 percent (44 million metric tons) lower

than in the 2024 common case. Some of the obvious drivers are listed below:

1. The retirement of additional coal‐fired generation

2. Carbon prices added for Alberta and British Columbia, and increased in California.

3. The reduced overall energy load.

4. The increased amount of renewable generation.

Transmission congestion8

There was minimal transmission congestion in the 2026 Common Case. The paths with reduced

congestion relative to historical or interesting flow variations are:

Northwest to California: The flows on paths 65 (PDCI) and 66 (COI) decreased due in part to the

implementation of the California Global Warming Solutions Act (AB32) that places a financial

8 Congestion refers to a condition where the flow may have been higher if not for a defined limit.

0 50,000 100,000 150,000 200,000 250,000 300,000 350,000

Conventional Hydro

Energy Storage

Steam ‐ Coal

Steam ‐ Other

Nuclear

Combined Cycle

Combustion Turbine

IC

Other


Biomass RPS

Geothermal

Small Hydro RPS

Solar

Wind

Annual Generation by Category (GWh)

2024 PC1 v1.5 2026 WECC v1.7



penalty on imports of electrical power to California, except for surplus hydro generation from

Bonneville Power Authority (BPA).

Utah to California: The primary delivery path between Utah and California is the path 27 HVDC

line. This was originally built to deliver the output from the Intermountain Power Project (IPP)

to the California participants. In the 2026 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.

In the ten‐year horizon for the 2026 Common Case, the changes in load and generation were not

expected to create congestion on the major WECC paths due to:

The inclination for developers to build gas‐fired generation near the load centers, and renewable

resources in‐state with access to local transmission.

The projected transmission build‐out in the CCTA (see Figure 8).



Additional Discussion of Input Assumptions and Study Results

A more detailed accounting of the study limitations, input assumptions, and results from the 2026

Common Case is presented in the following sections.

Study Limitations

PCM Solution: The solution from the PCM is subject to the input assumptions and overriding least‐

cost objective. The case provides a high‐level view of generation dispatch and transmission

utilization that can be compared to other study cases and sensitivity cases to formulate hypotheses

and conclusions.

Local Dispatch: The TEPPC study work is designed to investigate transmission utilization across the

entire Western Interconnection, with a focus on interregional transmission. A production cost

simulation that converges to a least‐cost WECC‐wide solution within the constraints and

assumptions may not produce the expected results for an individual area or region.

Local Congestion: There is a potential to create local congestion on area branches when adding

generation to an area. A portion of the generator’s output can become undeliverable and create

dump energy.9 There are a few instances where this has occurred in the common case, and these

may be addressed in a future release.

Load Shapes: The hourly load shapes for each load area are based on the actual hourly loads from

2009. This may overlook the more recent impacts from demand response, energy efficiency,

electric vehicle charging and behind‐the‐meter (BTM) generation such as rooftop solar.

Dataset Updates

The TEPPC PCM datasets are used by several stakeholders for conducting their own studies. There was

agreement during the initial stages of the 2026 common case development for the dataset to be

released at different phases of development. Each subsequent release included improvements and

changes that were identified by the various stakeholder groups. This process may continue such that it

will be necessary to reference the version number of the common case in all relevant communications

regarding the TEPPC 2026 Common Case.

9 Dump energy is generation that would have been dispatched if not for a constraint such as a transmission limit.



Summary Inputs and Assumptions

The detailed input assumptions are provided in a separate 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 7. The forecasts that were 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: TEPPC Load Area Topology

10 2026 Common Case & Release Notes



Changes in Load

The primary factors driving the reduction in the overall energy load of the 2026 common case

compared to the 2024 common case are:

Factors for load reduction (2024 → 2026) Amount (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 forecasts of 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 ‐51,131,943

Transmission Network

The transmission network 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 are listed in Figure 8. Note that 3 out of the 16 projects are

under construction.



Figure 8: 2026 Common Case Transmission Projects

Other study specific transmission projects will be added or removed as requested in the studies

outlined in the 2016 Study Program.

Generation Resources

There have been several changes to the generation assumptions since the 2024 case was developed in 2014. A few examples are highlighted below.

Decision by Pacific Gas & Electric to retire the Diablo Canyon nuclear power plant in 2025.

Revised retirement plans for coal‐fired generation that removed over 2700 MW of additional coal‐fired capacity.

Revised OTC compliance schedule and replacement plan for California.

True‐up of the renewable generation to ensure compliance with state Renewable Portfolio Standards (RPS) requirements as a function of the new annual energy loads for 2026.



Addition of gap generation where needed to meet the expected peak demand and planning reserves.

The changes in generation capacity by state/province and category are provided in Figure 9. The load

modifiers are excluded from the graph.

Figure 9: Change in Generation Capacity

Intermountain Generating Station

The participants in the Intermountain Generating Station (IGS) are currently negotiating an agreement

that would retire both coal‐fired units in 2025 or 2026. The agreement also includes replacement

generation consisting of two 600 MW combined cycle units that would be completed prior to the

shutdown of IGS.

(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



In the 2026 Common Case the IGS coal‐fired generation is not retired, and assumed to be available for

commitment and dispatch. Provided that the required State Implementation Plan (SIP) agreements are

in place, the IGS plans will be incorporated into the common case used for the 2017 TEPPC study

program.

Renewable Generation

The development of renewable resources in the Western Interconnection is moving forward at an

accelerated pace. However, the information about future projects is generally not announced until a

few years prior to commercial operation. It is often necessary to estimate the amount and location of

projects that will be required to meet the state RPS targets. The chart in Figure 10 represents a

combination of existing projects, near‐term projects under development, and estimated projects.

Figure 10: Renewable Generation Capacity Projections

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

Cumulative Net Capacity by Year (MW)

Wind

Solar

Small Hydro RPS

Geothermal

Biomass RPS



Load Modifiers

Several adjustments to the forecasted loads are modeled in the 2026 Common Case to represent

anticipated distributed generation (DG), energy efficiency (EE), and demand response (DR). Rather

than apply these changes to the loads, it is more convenient from an accounting perspective to model

them as generators. Under this methodology they reduce the amount of load that must be served by

other resources. The total energy from the load modifiers is 30,440 GWh, which is broken down in

Table 5. The distributed generation is entirely represented as behind‐the‐meter rooftop solar

photovoltaic (PV). More information regarding these load modifiers can be found in the release notes.

Table 5: Load Modifiers Modeled as Generators (GWh)

State Distributed Generation

Demand Response

Energy Efficiency

AZ 4,235 0.456 0

CA 22,213 3.542 887

CO 1,458 0.640 0

ID 159 0.277 0

MT 45 0 0

NM 580 0.001 0

NV 290 0.227 0

OR 104 0.005 0

UT 288 0.412 0

WA 157 0.044 0

WY 17 0 0

Total 29,546 5.60 887

Overriding Assumptions

The majority of the data inputs are based on information provided by the Balancing Authorities and

Planning Authorities in WECC; however, there are some issues that require the application of

additional assumptions to model a ten‐year horizon case. Some of these key assumptions are listed

below and a complete list of the assumptions can be found in the 2026 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.

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 2026 Common Case is provided below.

The complete list of improvements with detailed explanations can be found in the release notes.

Reserve Topology: The FERC 789 rules for reserve requirements were incorporated into the 2026

common case.

Minimum Local Generation: A recommendation from the CAISO was implemented that models a

requirement that certain combined cycle units be committed to provide frequency response for the

CAISO footprint. Nomograms are used to implement this requirement.

Back‐to‐Back DC Ties: The expected interchange with the Eastern Interconnection via the DC ties

was assumed to be zero at all locations.

Generator Cost Parameters: Volunteers from the California Energy Commission and ColumbiaGrid

used publicly available data to develop new heat rate curves for many of the key thermal

generators in WECC.

Additional Study Results

Other results of interest from the 2026 Common Case study are provided below, including generation

results by state/province for the whole year and for the peak hour, transmission path utilization, and

an analysis of California imports.

11 The established classes are: existing, under‐construction, approved and/or financed, and future conceptual.



Generation by State/Province

The generation results are reported here by their geographical location. The annual (geographical)

generation by state/province and fuel is provided in Figure 11.

Figure 11: Annual Generation by State and Fuel

Clearly, the generation from many resources is contractually12 committed to LSEs in other states or

provinces; however, the associated contracts and their details are often not publicly available to

provide a complete representation.

Renewable Energy Targets

There are ten states/provinces in WECC that have Renewable Portfolio Standards (RPS), namely,

Alberta, Arizona, California, Colorado, Montana, New Mexico, Oregon, Utah, and Washington. The

estimated amount of renewable energy that would be required for the RPS requirements in 2026 is

roughly 200,000 GWh.

As explained in the release notes, several of the RPS states have set limits on how much of the RPS

energy must be produced locally, versus how much can be imported in the form of energy delivered or

Renewable Energy Credits (REC). Two primary goals behind the limits are to protect in‐state

employment and generate tax revenue.

12 Data for known contracts is represented in the dataset and the associated units are exempted from wheeling charges.

0

50,000

100,000

150,000

200,000

250,000

300,000

AB AZ BC CA CO ID MT MX NE NM NV OR SD TX UT WA WY

Annual Generation (GWh) by State and Fuel ‐ 2026 WECC v1.7

Other Thermal

Energy Storage

Other Renewable

Wind

Solar

Nuclear

Hydro

Gas

Coal



Peak Hour Breakdown

Based on the current assumptions for the 2026 Common Case, the coincident peak demand occurs on

July 27, 2026 at 4:00 pm, with generation shares as shown in Figure 12. The contribution from

renewable resources is approximately 12.0 percent.

Figure 12: Peak Hour Generation

A ten‐day snapshot of the hourly generation by category that includes the peak hour is presented in

Figure 13. For WECC overall, the primary resource types that follow the load are hydro, combined

cycle, combustion turbine, and solar.13

13 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.

Biomass RPS 1.8%

Combined Cycle 32.0%

Combustion Turbine 8.6%

DG/DR/EE3.2%

Hydro+ES25.1%

Geothermal 2.1%

Nuclear 3.0%

Small Hydro RPS 0.3%

Solar 5.6%

Steam ‐ Coal 15.1%

Steam ‐ Other 0.5%

Wind 2.2%

Other0.5%

Generation at Peak Hour



Figure 13: Ten‐day Snapshot of Hourly Generation ‐ WECC

Transmission Path Flows

The bulk‐transmission system in the Western Interconnection has evolved over time, but still serves

the purpose of delivering generation to load. The major generation and major load centers are easy to

find on a transmission map as they are connected by major transmission lines. The generation has

historically been sited near the major fuel sources; water, coal, oil, or geothermal. Gas generators have

been sited near the gas pipelines, wind generators near the windy locations, and solar generation near

the Sunbelt. This trend is expected to continue even as the generation mix transforms to meet state

and federal regulations.

The most heavily utilized paths for the 2026 Common Case are shown in Figure 14. The graph is color

coded by utilization metric to show the path flow results and screening thresholds.14 The utilization

metrics are sorted according to the U90 metric15. A leading minus sign in the path name indicates that

the predominant path flow is in the reverse direction. Congestion on the paths is mostly indicated by

the U99 metric since this means that a path is operating at its rated limit.

14 TEPPC has set screening thresholds for the utilization metrics such that a path is considered “heavily utilized” and possibly congested if the flow is greater than or equal to 75% of its limit for more than 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. 15 The U75, U90, and U99 metrics have reference to the path flow thresholds (i.e. 75% of the path limit, etc.)

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

7/20/2026 7/21/2026 7/22/2026 7/23/2026 7/24/2026 7/25/2026 7/26/2026 7/27/2026 7/28/2026 7/29/2026

WECC Load/Gen Balance Snapshot ‐ 2026 PC1 v1.7 16‐12‐07DG/DR/EE

Other

Combustion Turbine

Steam ‐ Other

Combined Cycle

Small Hydro RPS

Biomass RPS

Hydro+ES

Solar

Wind

Geothermal

Steam ‐ Coal

Nuclear

Demand

Dump

MW



Figure 14: Most Heavily Utilized Paths ‐ 2024 Common Case

By the TEPPC definitions, there are no heavily utilized paths in the 2026 common case. Some possible

reasons for this are:

Retirements of remote generation

Emphasis on renewable generation, often local as conditions warrant.

Carbon prices that change the economics of off‐peak coal generation.

Other Paths

One of the validation steps for the PCM datasets is a comparison of the path flow results to the actual

path flows from historical years. The following examples employ a duration plot summary

methodology to compare the study results to historical years 2010 and 2012, and also to the 2024

Common Case. Note that validation against historical years may not be relevant where significant

changes associated with policy decisions impact the simulation results.

A few path duration plots are presented next, along with a short leading statement.

0%

10%

20%

30%

40%

50%

60%

Percent of Hours

Most Heavily Utilized Paths ‐ 26PC1_1_7 2026 Common Case v1.7

U75 U90 U99



The results for path 3 in Figure 15 show a good correlation to historic flows.

Figure 15: Path 3

The results for path 26 show a good match to historical.

Figure 16: Path 26

The impact of the California Global Warming Solutions Act (AB32) is evident in the path flow results for

path 27 in Figure 17. The carbon price adder reduces the economics of the Intermountain coal plant.

‐4000

‐3000

‐2000

‐1000

0

1000

2000

3000

4000

Meg

awat

ts

P03 Northwest‐British Columbia Path Duration Plots

2010 2012 2024_PC1_1_5 2026_PC1_1_7

Net GWh: 4827 ‐2545 ‐4134 ‐3392

‐4000

‐3000

‐2000

‐1000

0

1000

2000

3000

4000

5000

Meg

awat

ts

P26 Northern‐Southern California Path Duration Plots

2010 2012 2024_PC1_1_5 2026_PC1_1_7

Net GWh: 5752 7348 11725 3530



Figure 17: 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 18: Path 46

The results for the combination of Path 65 (PDCI) and Path 66 (COI) in Figure 19 have raised some

concerns because the flows are lower than historical and also flow south to north for 10 percent of the

year.

‐2000

‐1500

‐1000

‐500

0

500

1000

1500

2000

2500

3000

Meg

awat

ts

P27 Intermountain Power Project DC Line Path Duration Plots

2010 2012 2024_PC1_1_5 2026_PC1_1_7

Net GWh: 12471 11076 8287 6604

‐15000

‐10000

‐5000

0

5000

10000

15000

Meg

awat

ts

P46 West of Colorado River (WOR) Path Duration Plots

2010 2012 2024_PC1_1_5 2026_PC1_1_7

Net GWh: 44091 44955 33554 30172



Figure 19: Path 65+66

Each of the results for paths 27, 46, 65 and 66 show various amounts of reverse flow. This is interesting

because these paths all tie into California, which has been a net importer for many years. The average

annual hourly flow for path 66 depicted in Figure 20 suggests that California is finally exporting its

sunshine in the form of solar photovoltaic energy.

Figure 20: Path 66 Hourly Average

The average hourly flow on path 66 for each month is provided in Figure 21. Note that on average the

generation surplus occurs in March, April, May, September, October, November, and December.

‐6000

‐4000

‐2000

0

2000

4000

6000

8000

Meg

awat

ts

xy COI plus PDCI Path Duration Plots

2010 2012 2024_PC1_1_5 2026_PC1_1_7

Net GWh: 23104 37455 16510 13265

‐1,000

‐500

0

500

1,000

1,500

2,000

2,500

3,000

3,500

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Average Flow by Hour (MW) ‐P66 COI ‐Annual

2012 2026_PC1_1_7



Figure 21: Path 66 Hourly Average by Month

0

500

1,000

1,500

2,000

2,500

3,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Average Flow by Hour (MW) ‐P66 COI ‐ January

2012 2026_PC1_1_7

0

500

1,000

1,500

2,000

2,500

3,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Average Flow by Hour (MW) ‐P66 COI ‐ February

2012 2026_PC1_1_7

‐1,500

‐1,000

‐500

0

500

1,000

1,500

2,000

2,500

3,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Average Flow by Hour (MW) ‐P66 COI ‐March

2012 2026_PC1_1_7

‐3,000

‐2,000

‐1,000

0

1,000

2,000

3,000

4,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Average Flow by Hour (MW) ‐P66 COI ‐April

2012 2026_PC1_1_7

‐1,000

‐500

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Average Flow by Hour (MW) ‐P66 COI ‐May

2012 2026_PC1_1_7

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Average Flow by Hour (MW) ‐P66 COI ‐ June

2012 2026_PC1_1_7

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Average Flow by Hour (MW) ‐P66 COI ‐ July

2012 2026_PC1_1_7

‐500

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Average Flow by Hour (MW) ‐P66 COI ‐August

2012 2026_PC1_1_7

‐1,000

‐500

0

500

1,000

1,500

2,000

2,500

3,000

3,500

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Average Flow by Hour (MW) ‐P66 COI ‐ September

2012 2026_PC1_1_7

‐1,000

‐500

0

500

1,000

1,500

2,000

2,500

3,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Average Flow by Hour (MW) ‐P66 COI ‐October

2012 2026_PC1_1_7



If we just look at California’s load/gen balance, the hourly difference represents the hourly interchange

as shown in Figure 22. The pattern generally matches what we observed on the COI flows, and a ten‐

day snapshot in April (Figure 23) provides more details behind the generation surplus. Although

California is importing an average of nearly 6200 MW, the high solar output creates an interesting

reversal pattern for several days of the year.

Figure 22: Hourly California Net Interchange

‐1,000

‐500

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Average Flow by Hour (MW) ‐P66 COI ‐November

2012 2026_PC1_1_7

‐500

0

500

1,000

1,500

2,000

2,500

3,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Average Flow by Hour (MW) ‐P66 COI ‐December

2012 2026_PC1_1_7

‐20000

‐15000

‐10000

‐5000

0

5000

10000

15000

Calif Interchange Balance (gen ‐ load) ‐ 2026 PC1 v1.7 16‐12‐07 (MW)

Average is ‐6156 MW



Figure 23: April Snapshot for California

The California imports include output from several jointly‐owned projects and large‐scale purchases,

including shares of Agua Caliente, Apex, Arlington Valley, Arlington Wind, Big Horn, Copper Mountain

Solar, Desert Star, Dixie Valley, Don A. Campbell Geothermal, ESJ Wind, Glacier Wind, Hoover,

Horseshoe Bend, Hurlburt Wind, Intermountain Generating Station, Klondike Wind, La Rosita, Leaning

Juniper Wind, Linden Wind, Mesquite Solar, Milford Wind, Palo Verde, Parker Dam, Pebble Springs

Wind, Simpson Tacoma, Star Point Wind, Termo Mexicali, Tuolumne Wind, Vantage Wind, Willow

Creek Wind, and Windy Flats.

The delivery of a few of these projects is encouraged in the PCM by exempting them from wheeling

charges and assigning the participants in the reserve distribution table. However, the commitment and

dispatch in California does require sufficient local resources to provide frequency response, inertia, and

voltage support.

Conclusions and Observations

The portion of the annual WECC generation by renewable resources in the 2026 Common Case was

19.9 percent, including the incremental distributed solar resources. This represents an increase of

2.6 percent from the 2024 Common Case.

The model seems to manage the “duck curve” in California quite easily, perhaps by using imports to

supplement the morning and evening ramps. Operational challenges are making it difficult for

some owners of large combined cycle facilities to remain profitable, and more power market

related issues like Sutter and La Paloma could be coming.

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

4/6/2026 4/7/2026 4/8/2026 4/9/2026 4/10/2026 4/11/2026 4/12/2026 4/13/2026 4/14/2026 4/15/2026

Calif Load/Gen Balance Snapshot ‐ 2026 PC1 v1.7 16‐12‐07DG/DR/EE

Other

Combustion Turbine

Steam ‐ Other

Combined Cycle

Small Hydro RPS

Biomass RPS

Hydro+ES

Solar

Wind

Geothermal

Steam ‐ Coal

Nuclear

Demand

Dump

MW



Currently the development of hourly load forecasts for each load area involves the application of

historical hourly shapes from a single year to the firm16 monthly peak and energy forecasts. The

process introduces some errors due to changes in long‐term trends (2009 vs. 2026) and actual year

anomalies, although the tool has different options that can correct some of the errors. The failure

of the process often leads to “clipping” of the peaks or valleys, shifts up or down, abnormal load

factors, and/or large daily swings (see Figure 25 for an example). In the future, stakeholders may

want to consider other methodologies for adding hourly shapes to the monthly peak and energy

forecasts. Perhaps something that is more in line with how load forecasts are actually developed by

the BA’s and LSE’s, where multiple years of data are used and random anomalies are filtered out.

As mentioned at the beginning of the report, the GridView Look‐ahead logic was not turned on for

this case. While there are advantages to using this capability, the calculations are impacted by the

generator cost parameters that have not been reviewed since 2012. One of the expected

improvements of using the look ahead logic is better utilization of the energy storage resources. In

the example in Figure 24, the energy storage appears to be supporting the afternoon ramps as the

solar output falls. Perhaps the look ahead would increase the storage, and provide for additional

displacement of combustion turbine units.

Figure 24: Energy Storage ‐ Peak Week

The concerns about the south to north flows on path 66 are hopefully alleviated by some of the

analysis presented above. The periods of surplus generation in California are associated with the

daily ramp‐up of solar generation, and a region with very few solar resources such as the northwest

is a good market for any surplus.

16 The forecasts include firm and non‐firm components of demand and energy. By only using the firm component WECC is assuming that the non‐firm customers will not be served.

‐3,000

‐2,000

‐1,000

0

1,000

2,000

3,000

4,000

7/20/2026 7/21/2026 7/22/2026 7/23/2026 7/24/2026 7/25/2026 7/26/2026 7/27/2026 7/28/2026 7/29/2026

Energy Storage (MW) ‐WECC

2026 PC1 Common Case 31


Appendix A

Additional Tables and Charts

Table 6: Cumulative Capacities (MW) by Type and Year

Pre‐2011

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026

Conventional Hydro

64,031 64,188 64,346 64,720 65,585 66,807 67,134 67,168 67,080 67,017 66,919 66,901 66,901 68,015 68,005 68,005 68,005

Energy Storage 4,738 4,758 4,778 4,943 4,943 4,943 6,228 6,228 6,228 6,228 6,228 6,228 6,228 6,228 6,228 5,864 5,864

Steam ‐ Coal 37,927 38,569 38,505 37,730 37,312 36,858 36,498 34,822 34,492 32,874 31,619 31,365 30,651 30,651 29,601 28,757 27,989

Steam ‐ Other 19,020 18,860 18,389 16,853 15,792 14,463 14,392 10,730 10,947 10,947 4,826 4,713 4,639 3,479 3,269 2,939 2,939

Nuclear 9,632 9,632 9,632 7,482 7,482 7,482 7,482 7,482 7,482 7,482 7,482 7,482 7,482 7,482 7,482 5,082 5,082

Combined Cycle

50,475 51,277 52,331 53,725 55,270 58,666 59,600 60,623 62,151 62,710 63,994 64,504 64,798 65,075 64,955 64,955 64,955

Combustion Turbine

20,526 21,643 22,393 25,186 26,172 27,610 30,167 30,934 31,933 32,002 32,032 32,132 32,132 34,336 34,336 34,198 33,958

IC 760 809 809 809 828 1,048 1,048 1,048 1,048 1,048 1,048 1,048 1,048 1,048 1,048 1,048 1,048

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 0 0


0 0 0 0 0 0 294 294 294 294 294 294 294 21,286 21,286 21,286 21,286

Biomass RPS 2,643 2,847 3,150 3,291 3,490 3,602 3,637 3,637 3,637 3,637 3,613 3,513 3,513 3,834 3,834 3,794 3,794

Geothermal 2,908 3,043 3,181 3,408 3,448 3,483 3,518 3,494 3,475 3,475 3,501 3,501 3,501 4,050 4,050 4,085 4,085

Small Hydro RPS

1,159 1,174 1,174 1,174 1,174 1,181 1,181 1,181 1,181 1,181 1,116 1,116 1,116 1,116 1,116 1,116 1,116

Solar 741 1,036 2,335 5,569 7,280 9,282 10,949 11,028 11,437 11,517 11,597 11,625 11,639 17,758 17,773 17,765 17,745

Wind 13,227 15,498 20,555 22,462 24,522 25,934 27,019 27,499 29,321 29,521 29,521 29,520 29,520 30,587 30,587 29,725 29,725



Figure 25: Failure of Load Shaping

1500

2000

2500

3000

3500

4000

4500

5000

5500

1

141

281

421

561

701

841

981

1121

1261

1401

1541

1681

1821

1961

2101

2241

2381

2521

2661

2801

2941

3081

3221

3361

3501

3641

3781

3921

4061

4201

4341

4481

4621

4761

4901

5041

5181

5321

5461

5601

5741

5881

6021

6161

6301

6441

6581

6721

6861

7001

7141

7281

7421

7561

7701

7841

7981

8121

8261

8401

8541

8681

PSEI ‐ 2009 actual PSEI ‐ 2026 v1.5

TEPPC Study Report: 2026 PC1 Common Case CCV1.7-StudyReport...resource mix and transmission planning...

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