2022 Common Case Study Report (2011 Study Program)

2022 PC1 Common Case

(2022 PC1 Common CaseSeptember 19, 2013)

Introduction

A new 2022 horizon study case has been developed as the starting point for the 10 year studies of the Transmission Expansion Planning Policy Committee’s (TEPPC) 2011 and 2012 Study Programs. This basic case is named the 2022 PC1 Common Case (“Common Case”) and has been used as a starting point to evaluate the implications of options to meet existing and potential future energy polices, including the impact technology changes and external drivers might have on transmission needs and costs in the Western Interconnection.

Key Questions

The 2022 Common Case represents the trajectory of recent Western Interconnection planning information, developments and policies looking out 10 years. Many stakeholders participated in the development of hundreds of assumptions that depict the system changes over the 10-year study horizon. This case serves as a starting point for the other 10-year studies identified in the 2011 and 2012 TEPPC Study Programs. The primary goal in developing the 2022 Common Case was to define an authentic ‘reference point’ for the rest of the studies.

The key questions associated with the case are:

1. How do the implemented assumptions for load, transmission, and generation affect transmission path flows?

2. How does the planned addition of significant amounts of renewable resources impact base-load unit operation and transmission path flows?

3. What was the impact on generation dispatch and transmission of modeling additional commitment of reserves (beyond contingency reserves) to meet operational flexibility requirements in a system with substantial wind/solar penetration?

Study Limitations

The studies were conducted by the WECC staff using PROMOD IV, a Production Cost Model (PCM) that solves the hourly commitment and security constrained dispatch based on various transmission and generation constraints. A more extensive explanation of PCM study limitation is included in the Tools and Models portion of the Plan.

A limited validation of the 2022 Common Case was completed due to several last-minute modeling changes. As a result, the Technical Advisory Subcommittee (TAS) and its workgroups agreed to conduct sensitivity studies to test the effects of bookend gas prices, removal of the flexibility reserves, and price adjustments related to the cycling/ramping of base-load generation.

Although the PROMOD DC line algorithm was improved over the 2009 version PROMOD still appears to slightly favor AC transmission over DC transmission. The impact is difficult to measure, given the complexity of an Interconnection-wide study.

Study Assumptions

A brief summary of the key assumptions is provided here. The detailed input assumptions are listed in the Data and Assumptions portion of the Plan.

Transmission Assumptions

The stakeholder process by which the 2022 transmission network assumptions were developed is described in Appendix {TBD}. In summary, per the TEPPC Planning Protocol, the Subregional Planning Group (SPG) Coordination Group (SCG) is the stakeholder group charged with identifying what transmission is to be assumed built by 2022 for the 2022 Common Case. TEPPC’s philosophy for conducting transmission planning studies has been to include transmission projects in the 2022 Common Case that have a high probability of being in service within the study timeframe. Results from a base case planning study would be unrealistic if they included changes in predicted load and generation, but failed to include high-probability incremental transmission, or if they included transmission that could not pass a high-probability threshold. The SCG created the list of 2022 Common Case Transmission Assumption (CCTA) [footnoteRef:1] projects in order to meet this need. [1: The CCTA is similar to the Foundational Project List developed for the 2020 Reference Case. The name of the list was changed by the SCG to better reflect its purpose.]

The SCG used a multi-step process to select the transmission projects that were included in the 2022 Common Case network topology. The CCTA projects were selected by the SCG using a transparent, repeatable, consistent and documented process. The process relied upon public data and predefined criteria that were used to guide the selection of projects for inclusion in the CCTA. Project information, project development status indicators, selection criteria and any exceptions to the established process have been documented in the CCTA report. The CCTA projects for the 2022 Common Case are shown in Figure 1.

Figure 1: 2022 Common Case Transmission Assumptions

The 2022 Common Case transmission topology for the existing system plus additional lower voltage, local transmission reinforcements were modeled using a Technical Studies Subcommittee (TSS)-approved 2020HS1 power flow case as a model input. If CCTA projects were not already modeled in this power flow case, they were added to the 2022 Common Case transmission topology. If high-voltage regionally significant projects were included in the power flow cases but were not CCTA projects, they were removed from the Common Case topology and not assumed in the studies.

Load Assumptions

The monthly peak demands and energy loads were derived from the Balancing Authority (BA) load forecasts submitted to the Loads and Resources Subcommittee (LRS) in 2011. The 2022 LRS load forecasts were supplemented by Lawrence Berkeley National Laboratory (LBNL) analysis occurring under the auspices of the State and Provincial Steering Committee (SPSC) Demand-side Management Work Group that account for the expected impact of energy efficiency programs, given current policies and utility integrated resource plans. Demand response data, based on the LRS non-firm load forecasts, were also provided. Peak and energy assumptions (and adjustments from the LRS data) are shown in Figure 2.

Actual hourly BA loads from 2005 were also entered into the model and were used together with the monthly peak and energy forecasts to derive the 2022 hourly loads for the study. The coincident WECC peak load for the 2022 Common Case was 173,161 MW and occurred on Thursday, July 21 at 4:00 p.m. Mountain Time.

Figure 2: Common Case Annual Peak and Energy

Generation Assumptions

Several sources were used to define the generation portfolio in the Common Case, including:

· Loads and Resources data submittals

· Utility integrated resource plans (IRPs)

· Utility Resource Planner Surveys

· State renewable portfolio standards (RPS)

· California once-through-cooling (OTC) policy assumptions via stakeholders

It was also assumed that each subregion would, at a minimum, meet the planning reserve margins developed for the 2011 Power Supply Assessment (PSA) prepared by the LRS. The Studies Work Group (SWG) evaluated the initial planning margins in the 2022 Common Case and added generic resources to subregions that were identified as resource deficient given the assumed generation build-outs. The planning reserve margins developed by the LRS for the 2011 PSA assume continuation of traditional minimum planning reserve margins as a function of peak demand (e.g., 15 percent of forecast peak demand). With high concentrations of solar generation, the most significant grid reliability challenge may become the provision of adequate ramping resources during the early evening hours when solar is shutting down and evening loads are increasing. Traditional planning reserve margins are not structured to ensure adequate ramping capacity and may give way to alternative methods for deciding how much, and what type, of installed generation capacity is needed.

A summary of the generation capacity (existing and incremental) by subregion modeled in the 2022 Common Case is provided in Table 1. The incremental capacity is net of retirements, which are listed in Table 2 for units greater than 100 MW.

Table 1 - Existing and Incremental Generation Summary (MW)

Subregion

Status[footnoteRef:2] [2: Incremental units: 1 = under construction; 2 = approved or permitted; 3 = planned but not 1 or 2. The cutoff date for existing units was assumed to be December 31, 2010.]

Hydro+PS[footnoteRef:3] [3: Hydro pumped storage]

Thermal

Renewable

Total

Canada

Existing

16,918

10,196

1,635

28,749

Incr 1+2

0

2,936

4,088

7,024

Incr 3

2,126

3,954

893

6,973

Total

19,044

17,086

6,616

42,746

NWUS

Existing

30,902

12,456

5,158

48,516

Incr 1+2

0

40

4,490

4,530

Incr 3

0

456

3,478

3,934

Total

30,902

12,952

13,126

56,980

Basin

Existing

2,342

11,695

2,488

16,525

Incr 1+2

0

300

492

792

Incr 3

0

0

1,371

1,371

Total

2,342

11,995

4,352

18,688

RMPA

Existing

1,837

12,728

1,336

15,901

Incr 1+2

0

1,240

605

1,845

Incr 3

0

608

2,154

2,762

Total

1,837

14,576

4,095

20,507

AZNMSNV

Existing

2,905

35,880

771

39,557

Incr 1+2

0

1,393

534

1,927

Incr 3

0

87

5,092

5,179

Total

2,905

37,360

6,397

46,662

California

Existing

13,038

36,393

9,513

58,944

Incr 1+2

40

10,228

1,382

11,650

Incr 3

0

1,502

15,769

17,271

Total

13,078

48,123

26,664

87,865

WECC

Existing

67,941

119,348

20,902

208,191

Incr 1+2

40

16,136

11,591

27,768

Incr 3

2,126

6,607

28,756

37,490

Total

70,107

142,091

61,250

273,448

Generation Retirements

A listing of the assumed plant retirements (>100 MW) between 2011 and 2022 is provided in Table 2.

Table 2 - Generation Retirements (>100 MW)

Province/State

Unit Name

Capacity (MW)

Retirement Year

Alberta

Battle River 3,4

296

2013

HR Milner

143

2021

Sundance 3

353

2021

British Columbia

Burrard Thermal 1-6[footnoteRef:4] [4: Burrard Thermal is subject to regulation that will restrict its use to generating under emergency conditions only once certain system reinforcements are completed. The 2022 PC1 Common Case assumes these reinforcements will occur by 2014.]

904

2014

California

Coolwater 1,2

145

2015

Kearny 1-3

136

2013

Mandalay 3

130

2020

Pittsburg 7

682

2017

see OTC list for other OTC related retirements

Colorado

Arapaho 3,4

154

2013

Cherokee 1,2

217

2012

Cherokee 3,4

505

2016

Valmont 5

178

2017

Zuni 1,2

115

2013

Nevada

Fort Churchhill 1,2

234

2021

Reid Gardner 1-3

330

2020

Sunrise 1,2

149

2020

Tracy 1,2

141

2015

New Mexico

Four Corners 1-3

560

2021

Rio Grande 6,7

93

2017

Oregon

Boardman 1

510

2020

Texas (EPE)

Newman 1-3

247

2019

Washington

Centralia 1

728

2020

Fredonia 1,2

208

2019

Fredrickson 1,2

149

2016

Whitehorn 1,2

149

2016

Once-Through-Cooling (OTC) Retirements and Additions

In California, the owners of several plants that use OTC are required to retire or retrofit their plants by 2020.[footnoteRef:5] Plans (as of November 2011) for these retirements and retrofits as collected by TEPPC stakeholder are reflected in Table 3, which also shows the preliminary plans for replacement generation. [5: California’s two nuclear facilities have until 2022 and 2024 to comply with the once-through cooling policy approved by the California State Water Resources Control Board.]

Table 3 - Once-through-cooling Compliance Plan

Resource Name

Type

2009 Capacity

Group[footnoteRef:6] [6: “OTC -“ represents retirements due to OTC implementation. “OTC +” represents generator additions or retrofits intended to replace retired OTC generators.]

LSE[footnoteRef:7] [7: Load serving entity]

Capacity Retired

Capacity Added

Year Added or Retired

Comments

Alamitos 1-6

STM

2,010

OTC -

SCE

2,010

2020

Contra Costa6

STM

337

OTC -

PG&E

337

2014

Replaced by Marsh Landing Project (see below)

Contra Costa 7

STM

337

OTC -

PG&E

337

2014

El Segundo 3

STM

335

OTC -

SCE

335

2013

Replaced by NRG El Segundo Repower Project (see below)

El Segundo 4

STM

335

OTC -

SCE

335

2017

Not part of unit 1-3 repower, may be repowered separately later

El Segundo RP

CC

OTC +

SCE

560

2013

Encina 1-5

STM

945

OTC -

SDGE

945

2017

Encina GT

CT

15

OTC -

SDGE

15

2017

Generic CC (SCE)

CC

OTC +

SCE

1,000

2020

Generic CT (SCE)

CT

OTC +

SCE

1,000

2020

Haynes 5

STM

341

OTC -

LDWP

341

2013

Haynes 6

STM

341

OTC -

LDWP

341

2013

Haynes GT 1-6

CT

OTC +

LDWP

600

2012

Huntington Beach 1

STM

226

OTC -

SCE

226

2020

See addition of Generic CC/CT (SCE) above.

Huntington Beach 2

STM

226

OTC -

SCE

226

2020

Huntington Beach 3

STM

225

OTC -

SCE

225

2013

See Walnut Creek; retired early to transfer air permits to WC.

Huntington Beach 4

STM

227

OTC -

SCE

227

2013

Mandalay 1-2

STM

430

OTC -

SCE

430

2020

See addition of Generic CC/CT (SCE).

Marsh Landing

CC

OTC +

PG&E

719

2014

Replacing Contra Costa 6 & 7

Morro Bay 3

STM

325

OTC -

PG&E

325

2015

Morro Bay 4

STM

325

OTC -

PG&E

325

2015

Moss Landing 1-2

CC

PG&E

2017

considering retrofit of existing units

Moss Landing 6

STM

754

OTC -

PG&E

754

2017

Moss Landing 7

STM

756

OTC -

PG&E

756

2017

Ormond Beach 1-2

STM

1,516

OTC -

SCE

1,516

2020

Pittsburg 5

STM

312

OTC -

PG&E

312

2017

also considering retrofit; assume retirement

Pittsburg 6

STM

317

OTC -

PG&E

312

2017

Redondo Beach 5-8

STM

1,343

OTC -

SCE

1,343

2020

See Generic CC/CT (SCE).

Scattergood 3

STM

445

OTC -

LDWP

445

2016

Scattergood CC

CC

OTC +

LDWP

509

2016

Renewable Generation

It was assumed that all state-enacted Renewable Portfolio Standards (RPS) and targets will be met. Where the LRS data did not identify sufficient incremental renewable resources to meet the RPS requirements, generic renewables were added using input from utility integrated resource plans, resource planners, and the WREZ Peer Analysis Tool.

Ten states in the Western Interconnection have adopted RPS or targets that vary between 4 and 33 percent (interpolated where necessary) for the year 2022. The standards and targets are shown in Table 4, which also shows the states and provinces that have renewable generation, but no formal requirements.

Table 4 - Renewable Standards for 2022

RPS Percentages in 2022 by State/Province

State/Province

IOU

Public

Federal

Cooperative

Other

Alberta

Renewable resources, No requirement

Arizona

12%

12%

12%

British Columbia

Renewable resources, No requirement

California

33%

33%

33%

33%

33%

Colorado

30%

10%

10%

Idaho

Renewable resources, No requirement

Montana

15%

Nevada

23.5%

New Mexico

20%

10%

Texas-EPE

5%

Utah

16%

16%

16%

State

Utilities > 3% state load

Utilities < 3% and > 1.5%

Utilities < 1.5% state load

Oregon

22%

8%

4%

State

Utilities > 25k customers

Utilities < 25k customers

Washington

15%

As mentioned previously, TEPPC assumes that all RPS requirements will be met in 2022. To meet these requirements, a significant amount of incremental renewable resources were added to the 2022 Common Case. Figure 3 shows the incremental renewable build-out for each subregion between 2011 and 2021, inclusive. A summary graph of the overall incremental WECC build-out of renewable resources between 2011 and 2021 is provided in Figure 4. Based on the TEPPC data, this equates to an increase of 148 percent of existing installed renewable capacity.

Figure 3 - Renewable Build-out

Figure 4: Renewable Additions - WECC Overall PC1 Common Case

Figure 5 shows that the vast majority of generation added between 2012 and 2022 is for gas (mainly CTs and CCs), wind and solar resources. Most of the incremental gas resources are located in California and Alberta. It is worth noting that a large number of the gas resources in Alberta were implemented by TEPPC due to insufficient resources within that province. Solar and wind also see strong development with California adding the most incremental renewable resources.

Figure 5: Generation Capacity Additions by State

The annual energy from renewable generation in the 2022 Common Case was 168,988 GWh. Wind generation accounts for roughly 54 percent of this generation. Geothermal makes up 20 percent of the total, and solar 14 percent. The remaining energy is supplied by biomass and small hydro resources. This breakdown is shown in Figure 6. There is also a breakdown by state where we can see that nearly 43 percent of the 2022 Common Case renewable generation comes from California. No other state or province contributed more than 10 percent to the total.

Figure 6: Total Renewable Energy by Type and State/Province

As previously mentioned, TEPPC creates a case that is RPS compliant in terms of annual renewable energy production. As expected, not all states plan to meet their RPS by relying solely on resources within their borders in the 2022 Common Case. However, Figure 7 shows that states plan to procure most of their resources from in-state generation (with the exception of Utah). Overall, 81 percent of the RPS energy in the 2022 Common Case is met via in-state resources. The preference for in-state resources is a key driver of transmission utilization and congestion, or lack thereof.

Figure 7: In- and Out-of-State RPS Compliance

The hourly shapes (8,760 hours per simulated year) for the loads, hydro profiles, wind profiles, and solar profiles are based on 2005 data, with a few exceptions where 2005 data was unavailable.

The out-of-state RPS assumption for California in the 2022 Common Case is lower than was assumed in the 2020 Common Case by nearly 2,000 MW (see Table 5), largely reflecting ongoing contracting trends.

Table 5: California Out-of-state RPS Capacity

Case

AZNMNV

BASIN

CANADA

NWUS

RMPP

TOTAL

2020 PC1

713

261

872

1885

517

4248

2022 PC1

1207

637

448

0

0

2292

Modeling Improvements

It is important to specifically highlight a few key modeling improvements that were incorporated into the 2022 Common Case as compared to previous TEPPC datasets.

Improvement 1 – Modeling of Cogeneration and Combined Heat and Power Units

Cogeneration (CG) and Combined Heat and Power (CHP) units serve a dual purpose of supplying power and steam (or heat) to a host or contractual facility and excess power to the grid. In order to model these types of units correctly, it is necessary to know their operational practices and typical power export to the grid. LBNL contracted Energy and Environmental Economics (E3) to investigate the representation and modeling of existing cogeneration in the TEPPC dataset and to recommend adjustments to CHP modeling in the TEPPC 2022 Common Case. As a result of this effort, many of the CG and CHP plants that had been previously modeled incorrectly are now modeled in the 2022 Common Case to operate in a predefined range that more accurately reflects their dual purpose. In most cases, this increased the modeled annual energy output of the CHP plants. The modeling changes included one or more of the following:

· CHP/CG units that were not previously designated as must-run were changed to must-run, with the exception of certain California CHP plants identified by the California Public Utility Commission (CPUC) as ‘dispatchable’.

· The modeled minimum capacities of CHP/CG units that operate continuously at full output were changed to 99 percent of maximum capacity.

· Plant heat rates were adjusted to a net heat rate based on EIA 906/920 data gathered from 2007-2010.

· The monthly maximum capacity for non-dispatchable California Independent System Operator (CISO) area CG was set equal to the monthly net qualifying capacities (NQC) based on the CPUC 2012 NQC List.

· The heat rates of some CHP/CG units that operate at high-capacity factors, but are subject to displacement by load reductions, hydro generation, and wind generation were reduced to change their positions in the resource dispatch stack.

Improvement 2 – Operational and Cycling Costs of Thermal Generation

A production cost model uses several generator parameters to economically dispatch generation to meet the load. Under a joint contract with NREL, Intertek-APTECH provided costs associated with cycling the most prevalent types of thermal generation. Industry studies have shown a potential increase in the amount of base-load generator cycling in response to changes in generation preferences. The Intertek information was used to update the unit non-fuel startup costs and the Variable Operations and Maintenance (VOM) costs.

Improvement 3 – Flexibility Reserves – Operating Reserve Impacts from Variable Generation

There is an expectation that system operators will balance the variability of wind and solar generation with conventional resources having sufficient operational flexibility. Given the high penetration of variable generation resources planned in the Western Interconnection, the corresponding need to properly account for how overall system operation must accommodate this inherent variability is paramount for TEPPC’s studies. One way to model this in a production cost model is to increase the operating reserve requirement to capture the increased uncertainty during periods with high wind and solar generation. This modeling approach was included in the 2022 Common Case with the help of a tool developed by NREL that calculates the hourly reserve requirement increase given a defined level of wind and solar generation output. NREL and others have named this ‘regulation’ type reserve parameter that accounts for the variability of wind and solar resources as a ‘flexibility reserve’.

The flexibility reserve requirement calculated by NREL was added to the load-based spinning reserve requirement (4 percent[footnoteRef:8] of daily peak load) to develop an hourly composite reserve requirement for each TEPPC subregion, which are shown in Figure 8. Out of the eight subregions in the TEPPC topology, California South (CA_S), California North (CA_N), and AZNMNV were impacted the most by the flexibility reserve adjustment because of their higher wind and solar penetrations. [8: The 4 percent reserves includes three percent for spinning and one percent for contingency for each of the eight regions, which approximates 50 percent of the WECC reserve requirement (after forced outages) – seven percent for thermal and five percent for hydro.]

Figure 8: TEPPC Subregions

The histogram in Figure 9 shows the frequency (hours) for the composite reserve requirement for CA_S. The requirement was generally between 5 and 13 percent, but did get as high as 19 percent for a few hours.

Figure 9 – Operating Reserve Requirement for Southern California

Improvement 4 - Reserve Contribution from Coal-fired Resources

In previous TEPPC datasets, the entire unloaded capability of coal-fired resources was assumed available to meet the operating reserve requirements. Since this may overstate the actual reserve contribution of these resources, a limitation was added in the 2022 Common Case that limits the contribution to the lesser of:

a) 10 percent of the maximum capacity; or

b) The unloaded capacity (maximum capacity minus the current dispatch level).

The 10 percent limitation was derived from the average ramp rates for coal plants during a 10-minute period. For example, a 500-MW plant that is dispatched at 300 MW with a ramp rate of 5 MW per minute could only ramp up 50 MW in 10 minutes, or 25 percent of its unloaded capacity.

Deferred Changes

The 2022 Common Case dataset was locked-down for dataset validation on April 13, 2012 and published for use by stakeholders on May 2, 2012. Any data or modeling changes that were not received or not approved prior to April 13 were not incorporated into the dataset. A few key data “notifications” that were submitted but not incorporated are listed below.

· Loads for Arizona Public Service (APS) – APS sent notification that a revised 10-year load forecast had been developed based on a lower growth rate. Because a load change would require revisions to the renewable resources, flexibility reserves, energy efficiency and demand response at a time when the dataset was already overdue, the load change for APS was not incorporated into the 2022 Common Case.

· Hydro capacity for British Columbia – BC Hydro reported in June 2012 that the hydro capabilities that had previously been submitted for the 2022 Common Case were too high. A new forecast was made available with an overall decrease in hydro energy of 8,566 GWh. Although the revised data were not incorporated, the CISO did conduct a sensitivity study to determine the impact, and those results are attached to this report.

· Flexibility reserves – NREL reported in June 2012 that their tool for calculating flexibility reserves had overstated the reserves required for solar resources. NREL also reported that a new tool was under development, and a beta release of the new tool was provided to WECC in September 2012. Preliminary results verify that the updated tool calculates a flexibility reserve requirement that is slightly lower than what was incorporated into the 2022 Common Case. Given the number of studies in the 2012 Study Program, there was not time to run a sensitivity with the slightly lower flexibility reserves requirement.

· The renewable resource portfolio provided by the California PUC significantly contributes to overall west-wide renewable resources modeled for 2022 . That portfolio represents resource planning assumptions of an early 2011 vintage. Subsequent California RPS planning portfolios in 2012 and 2013, arising from multi-agency and stakeholder process in California, updated planning assumptions. These more recent portfolios reflect ongoing procurement activity, and are more heavily weighted towards in-state solar resources (with less wind and geothermal). This more recent information was not timely for the recent cycles of the multi-layered data intensive TEPPC study process, although certain sensitivity cases run late in the study cycle contain higher levels of California in-state solar generation.

Study Results – Answers to Key Questions

The following study results provide answers to the key questions associated with the 2022 Common Case. Since the questions are interrelated with common topics, the answers are presented by topic. The key questions associated with the case are:

1. How do the modeled assumptions for load, transmission, and generation affect transmission path flows?

2. How does the planned addition of significant amounts of variable resources impact operation of base-load generation and transmission path flows?

How did modeling of additional reserves commitment for flexibility purposes impact generation dispatch and transmission flows (relative to not adding this additional reserves commitment)?

Regional Transfers

In the TEPPC study cases the 39 load bubbles, approximately corresponding to the WECC BAs, are grouped into eight subregions as shown in Figure 10. The load bubbles are grouped for reporting purposes and the subregional groupings are used by PROMOD to perform the initial committment of generation to meet load prior to evaluating opportunities for economic interchange between subregions. Energy transfers between the eight subregions provide insights into how the study case assumptions impact transmission congestion and utilization in the Western Interconnection.

Figure 10 - TEPPC Subregions

Average region-to-region energy transfers observed in the 2022 Common Case are compared against these same energy transfers observed in TEPPC’s 2020 Reference Case in Figure 11. The results reflect the additional hydro generation assumed in British Columbia and the increase in local generation in California (must-run cogeneration, higher efficiency OTC replacements, and more in-state renewable generation) in the 2022 Common Case, and underlie the illustrated decrease in the transfers from the Northwest to northern California (CA_N), but a significant increase in the transfers from northern California to southern California (CA_S).

Figure 11 - Regional Transfers

The generation changes and modeling improvements discussed earlier had some important impacts on the modeling results for CA_N. The more refined modeling of the CHP/CG resources and the incremental renewable generation increased the must-run and must-take generation in northern California. The CA_N load/gen balance (local generation minus local load) for the 2022 Common Case is compared to the 2020 Reference Case in Figure 12, where positive values represent generation exports and negative values represent generation imports, including imports to displace local generation. The annual exports for the 2022 Common Case results surpassed the imports by 1,418 GWh, which indicates a net generation surplus. This represents a swing of 5,039 GWh from the 2020 Reference Case where the net annual balance was -3,621 GWh.

Figure 12 – Northern California (CA_N) Hourly Load/Generation Balance

Path Flow Results and Comparisons

The flows observed on a few key WECC paths[footnoteRef:9] are shown in a duration plot format in which the flows for the 8,760 hours of the year are sorted highest to lowest. This has proven to be an effective way to compare study case path flows with historical flows or with other study case results. The 2022 Common Case flows are compared below with historical flows (where available) and with flows from the 2020 Reference Case from the previous TEPPC study program. Note that some changes from historical should be expected; hence caution is necessary when drawing conclusions from the comparisons. [9: Paths were selected based on their historical significance in TEPPC studies.]

Path 1 – Alberta to British Columbia

Path 1 is used for energy transfers between Alberta and British Columbia. The hydro portfolio for British Columbia in 2022 Common Case produced a surplus of hydro energy that could often be exported to markets in Alberta and the United States. Figure 13 compares the 2022 Common Case results with historical flows and the 2020 Reference Case results.

Figure 13 - Duration plots for Path 1

Path 3 – Northwest to Canada

Path 3 consists of three transmission lines that run between the Northwest (Washington) and British Columbia. Historically, the flows along this path have been predominantly south to north into Canada (see Figure 14) with an opposite flow for only about 20 percent of the year. The 2022 load and generation assumptions have prompted a reversal in this trend, with significant exports from British Columbia to the Northwest U.S. This is at least in part due to the planned addition of 2,000 MW of hydro generation in British Columbia by 2022.

Figure 14 - Path 3 Duration plot

Path 8 – Montana to Northwest

Path 8 links Montana to Idaho/Washington. It was built to deliver the output of the Colstrip power plant to its partial owners in Washington and Oregon, who own 1,343 MW (or 64 percent) of the total 2,094 MW of capacity. As wind farm developers seek to site facilities in wind-rich Montana the utilization of Path 8 is expected to increase and become constrained as is shown for this case in Figure 15.

Figure 15 - Path 8 Duration plots

A 10-day snapshot of the NWMT load/gen balance in 2022 is provided in Figure 16 and shows some dramatic curtailments of coal-fired resources in Montana. The displacements appear to be related to significant changes in export opportunities during several off-peak periods.

Figure 16 - NWMT 10-day Load/Gen Snapshot - 2022 Common Case

Path 26 – Northern to Southern California

Path 26 is essentially the tie or cut-plane between Pacific Gas and Electric (PG&E) in northern California and Southern California Edison (SCE) in southern California. As evident in Figure 17, Path 26 is heavily utilized in the 2022 Common Case. This appears to be a result of a shift of assumptions related to California CHP/CG (discussed earlier) and RPS resources, as shown in the comparison in Table 6. Compared to the 2020 Reference Case, the 2022 Common Case features 3,816 MW more renewable generation in northern California, and 2,892 MW less generation in southern California.

Figure 17 - Path 26 Duration Plot - 2022 Common Case

Table 6: California Renewable Resource Shifts - 2020 PC1 versus 2022 Common Case

Biomass RPS

Geothermal

Small Hydro RPS

Solar PV

Solar CSP

Wind

Total

CA_N

161

477

29

1,776

-

1,373

3,816

CA_S

121

(592)

262

503

(2,995)

(192)

(2,892)

Path 27 – Intermountain DC Line

Path 27 is the DC line between central Utah and southern California. It was built to deliver the output of the Intermountain Generation Station to its California participants. The path had a rating increase in the north to south direction in 2011 from 1,920 MW to 2,400 MW. A nomogram was used in the 2022 Common Case to constrain the path flow to be within 1,000 MW of the combined generation output of Intermountain Generation Station, Milford Wind farm, and Hatch geothermal. The allowed deviation in the nomogram was increased from the 2020 level in anticipation of the impacts of the California greenhouse gas cap and trade system, which would likely lower or eliminate coal imports into the state.

Figure 18 - Path 27 Duration plots

Path 28 – Intermountain to Mona

Path 28 is the path between the Intermountain Generation Station and the transmission backbone system serving the Rocky Mountain Power area of Utah. A portion of the generator output near the Intermountain substation flowed on Path 28 and Path 29.

Figure 19 - Path 28 Duration plots

Path 29 – Intermountain to Gonder

Path 29 connects the Intermountain Power Project with Northern Nevada. This path is often more heavily utilized than historical in the TEPPC studies.

Figure 20 - Path 29 Duration Plot

Path 46 – West of Colorado River

Path 46 is the path that connects Arizona and southern Nevada with southern California, and is commonly called the West of Colorado River (or West of River) path. One of the primary purposes for the path is to enable the delivery of jointly owned and contractual shares of generation in Arizona, Nevada, and New Mexico to California. The plot in Figure 21 shows that the flow on this path for 2022 Common Case is 2,000 to 4,000 MW lower than historical, largely due to the generation changes in California (i.e., CHP/CG and incremental CC). Furthermore, California’s shift to in-state RPS resources reflected in the updated RPS planning portfolios decreased the opportunity for imports via flow on Path 46. The location of resources in California is not much of an issue since there is no hurdle rate between northern and southern California.

Contractual obligations and rights have not been modeled in the TEPPC datasets, partly due to the modeling implications and partly due to the uncertainty regarding continuation of these contracts in the ten year horizon. This hasn’t been as much of an issue in the past, but in the 2022 Common Case excluding contractual obligations may be portraying unrealistically low flows on Path 46.

Figure 21 - Path 46 Duration plots

The results in Figure 22 show the hourly imports into California from Arizona and Nevada. Contractual deliveries of base-load nuclear and coal-fired generation on Path 46 are expected to be over 3,500 MW in 2022. Historically these deliveries and deliveries of economy purchases were consistently above 4,500 MW, with a few exceptions during planned and unplanned outages.

Figure 22 - West of Colorado River Hourly Flow - 2022 Common Case

Path 65 - Pacific DC Intertie (PDCI) and Path 66 - California – Oregon AC Intertie (COI)

Path 65 and Path 66 together connect the Northwest with California and are used to provide California access to the vast hydro generation and developing renewable energy supply in the Northwest. This major corridor is comprised of an AC path (Path 66) that runs from southern Oregon to northern California, and a DC intertie (Path 65) between northern Oregon and southern California. The flows on the combination of the two paths are shown in Figure 23.

Figure 23 - Path 65 plus Path 66 Duration plots

Except for a few hours the 2022 flows are well within the path constraints.

The factors that contributed to the change compared to the 2020 PC1 results were:

· Unit level tuning of the CHP and cogeneration resources.

· Retirements of thermal units, including 4,330 MW of coal-fired capacity.

· Revisions to the renewable generation portfolio.

· Updated implementation of the OTC requirements in California.

· Three percent increase in load requirements.

Path Utilization

A utilization screening is used to capture any highly utilized or potentially congested paths in the TEPPC study cases. The metrics and utilization thresholds used for the 10-year plan utilization screening are provided in Table 7. The utilization metrics provide a measure of how often (i.e. number of hours) the path flows exceed 75, 90 and 99 percent of the path limits, and if flows exceed these limits for a given number of hours a year (percent threshold) the path is flagged as ‘highly utilized’. In hypothetical example 1, the path flow was greater than 75 percent of the path limit for 4,100 hours, greater than 90 percent of the path limit for 2,100 hours, and greater than 99 percent of the path limit for 600 hours. Since the percent threshold was met, and even exceeded, for both the U90 and U99 utilization metrics, the path would be flagged as one of the “most heavily utilized” within the study case.

Table 7 - Path Congestion Criteria

Criteria Description

Flow > 75% of limit

Flow > 90% of limit

Flow > 99% of limit

Utilization Metric

U75

U90

U99

% of path limit

75%

90%

99%

Utilization screening

Percent threshold

50%

20%

5%

Hours (standard 8,760 hour year)

4,380

1752

438

Example 1

Hours > xx%

4,100

2,100

600

Percent of criteria

46.8%

24.0%

6.9%

Passes screening test

No

Yes

Yes

The most heavily utilized paths for the 2022 Common Case are shown in Figure 24. The graph is color coded by utilization metric to show the path flow results and screening thresholds. 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 24 - Most Heavily Utilized Paths - 2022 Common Case

A synopsis by path is provided below for the paths that exceeded the U90 metric for at least 20 percent of the year.

· Path 45 (SDG&E – CFE) is heavily utilized in the 2022 Common Case with a net interchange of 2,145 GWh from the San Diego Gas & Electric (SDG&E) area to Mexico (CFE). This is an average flow of 245 MW/h on the 408-MW path, and is mostly the result of economic transfers due to in-sufficient resources modeled in CFE.

· Path 26 (Northern – Southern California) is also heavily utilized (see Figure 17). The flow seems to be related to economic transfers, meaning that it is more cost effective to dispatch and then transport energy from northern California to southern California, as opposed to dispatching generation near load in southern California. This is likely the indirect result of the California generation and cogen/CHP assumptions discussed earlier.

· Path 8 (Montana – Northwest) has historically been highly utilized as the delivery path for the Colstrip Generation facility. In the 2022 Common Case, 580 MW of incremental wind capacity was sited in Montana, which contributed to the high utilization in the TEPPC studies.

· Path 3 (Northwest – British Columbia) is heavily utilized in the reverse direction (British Columbia to the Northwest) as presented in Figure 14. The high utilization is related to the addition of a large hydro project in British Columbia. Note that Interstate WA-BA, which is listed as a heavily utilized path, is included as a portion of Path 3 and thus is not included in a separate summary.

· Path 29 (Intermountain – Gonder) is often more heavily utilized in the PROMOD results than has been observed historically. This may be related to the least-cost solution arrived at by PROMOD that chose to deliver a portion of the Intermountain Generation Station via the AC system as opposed to all of the IGS generation being dispatched on the IPP DC-line (Path 27). Note that Path 29 is a small path in terms of its capacity and thus does not of great concern in Interconnection-level planning.

· Path 47 (southern New Mexico) is used in actual operations to deliver the entitlement shares of joint plants in Arizona and northern New Mexico to the El Paso area. Although the entitlements are not modeled in the TEPPC studies, a lack of resources near EPE prompts Promod to transfer surplus energy from Arizona and New Mexico to EPE on this path.

·

Generation Results

The generation breakdown used to serve the load in the 2022 Common Case is presented in Figure 25. Note that cogeneration is an aggregation of several generator types, but is shown separately to differentiate these generators from the non-cogeneration units.

Figure 25: 2022 Common Case WECC Annual Energy by Type

The annual generation by renewable resources is 168,988 GWh in the 2022 Common Case and equates to 16.6 percent of the total generation (1,016,213 GWh). This is over 4,000 GWh more renewable generation than what was observed in the 2020 Reference Case (16.7 percent of total Reference Case generation). In the 2022 Common Case an additional 9,769 GWh of available renewable energy was not used due to economics (geothermal and biomass dispatch[footnoteRef:10]) and in some instances transmission constraints. The most impacted areas for less than maximum biomass dispatch were British Columbia, California, Washington, and Oregon. [10: Adjustments to the biomass modeling and dispatch are scheduled for the next planning cycle. Biomass and geothermal are modeled as dispatchable resources while solar, wind, and small hydro are not.]

A summary graphical comparison of the annual generation by type in the 2022 Common Case versus the 2020 Reference case is presented in Figure 26. This shows the effects of the CHP/cogeneration modeling changes and an increase in projected load of 2.9 percent (28,000 GWh) over the two-year-period. It also shows the change in the assumed renewable portfolio with more wind and less solar and geothermal.

Figure 26 - Difference in generation by type - 2022 Common Case vs. 2020 PC1

Table 8 provides a tabular listing of the differences in generation-related results compared to the 2020 SPSC Reference Case. The contributing factors behind the changes were:

· Unit level tuning of the CHP and cogeneration resources.

· Retirements of thermal units, including 4,330 MW of coal-fired capacity.

· Revisions to the renewable generation portfolio.

· Updated implementation of the OTC requirements in California.

· Three percent increase in load requirements.

· Change to 2005 hourly energy shapes in the 2022 Common Case, as opposed to 2006 shapes in the 2020 Reference Case.

Table 8 - Generation Summary comparison - 2020 Reference Case vs. 2022 Common Case

Generation Results (MWh)

Category

2020 PC1 SPSC Ref Case

2022 PC1 Common Case

Difference

Diff %

Conventional Hydro

246,812,313

246,879,484

67,171

0.0%

Pumped Storage

2,616,848

3,095,937

479,089

18.3%

Steam - Coal

287,756,234

267,319,561

(20,436,673)

-7.1%

Steam - Other

3,125,271

2,401,909

(723,362)

-23.1%

Nuclear

76,417,356

74,888,892

(1,528,465)

-2.0%

Combined Cycle

161,069,942

156,645,763

(4,424,179)

-2.8%

Combustion Turbine

12,159,985

5,080,137

(7,079,848)

-58.2%

Cogeneration

26,230,895

86,098,511

59,867,616

228.2%

Internal Combustion

225,484

188,052

(37,431)

-16.6%

Negative Bus Load

4,640,148

4,627,470

(12,678)

-0.3%

Biomass RPS

14,900,622

13,572,744

(1,327,877)

-8.9%

Geothermal

35,741,481

33,454,146

(2,287,334)

-6.4%

Small Hydro RPS

7,755,782

7,150,890

(604,892)

-7.8%

Solar

29,672,103

23,616,314

(6,055,790)

-20.4%

Wind

76,671,934

91,193,635

14,521,702

18.9%

Total

985,796,398

1,016,213,446

30,417,047

3.1%

Renewable Total

164,741,922

168,987,730

4,245,808

2.6%

Renewable Percent

16.7%

16.6%

(0)

-0.5%

Generation Outages

Expected annual rates for both planned maintenance outages and unplanned forced outages are input into the TEPPC dataset for dispatchable generation. Planned or scheduled maintenance outages are first developed by PROMOD and then adjusted by TEPPC to ensure realistic schedules are simulated that avoid significant outages during times of heavy load and to prevent unrealistic simultaneous outages of large plants. Maintenance data was not requested or provided to TEPPC by generator owners due to confidentiality concerns.

Forced outages are determined by a Monte Carlo algorithm in PROMOD and are applied after the planned maintenance. The two types of outages are honored by PROMOD such that a unit maintenance outage rate of 4 percent and forced outage rate of 5 percent result in a total outage rate of 9 percent. There is a potential for the independent processes to create some periods of severe outages.

Figure 27 shows a snapshot of the AZNMNV subregion with modeled forced outages of two Palo Verde units occurring at the same time as one Palo Verde unit is offline for refueling. Fortunately, this occurred during the spring runoff when sufficient energy was available for import.

Figure 27 - AZNMNV Load/Generation Snapshot - 2022 Common Case

Cycling of Base Load Generation

In the 2020 Study Report and 2011 10-Year Regional Transmission Plan there was some discussion of increased cycling[footnoteRef:11] of base-load generation in response to significant non-dispatchable (must-take) and hydro resources within the TEPPC study cases. There was some attempt to address this issue in the 2022 Common Case with the changes to the startup and variable O&M costs provided by Intertek/APTECH. Even with these changes the resource stack in the hourly model must respond to the load requirements in the most economical way, which continued to cause cycling of base-load resources proportionate to the load shapes and energy contributions of resources lower on the stack. . [11: In this report “cycling” refers to both the on/off cycling and the dispatch changes between minimum and maximum generation.]

The increased cycling is evident in Figure 28, which shows significant cycling of base-load generation in the Northwest subregion. In this example the model is backing down the coal-fired and nuclear generation during the off-peak due to the input assumptions that drive the model solution.

Figure 28 - NWUS Load/Gen 10 day snapshot

Similar cycling was observed in other areas such as the AZNMNV subregion, shown in Figure 29. Here the cycling appears to be related to the load patterns in the subregion and the lack of exports to other areas.

Figure 29 - AZNMNV Load/Gen Balance Snapshot

The plots in Figure 30 and Figure 31 further illustrate the frequency of the cycling/ramping in the Northwest.

Figure 30: NWUS Coal Output – 2022 Common Case

Figure 31: NWUS Coal Output - 2022 Common Case (May + June)

Impact of Flexibility Reserves

A sensitivity case was run without the flexibility reserve component of operating reserves. This made the hourly reserve requirement equal to just 4 percent of the daily peak (as calculated for each TEPPC subregion). This sensitivity case was compared to the 2022 Common Case in order to evaluate the impact of the flexibility reserves. The changes in annual generation are presented in Figure 32 and Figure 33, and show a slight increase in the amount of energy from coal-fired resources when the flexibility reserve component is removed. This is an indication that the restriction placed on the contribution of coal-fired generation to the operating reserve has a greater impact on the generation dispatch when the flexibility reserves are in place. There may have been hours that the coal generation had to be backed off to allow CC and CT units to be dispatched to meet the increased reserve requirement.

Figure 32: Difference in generation without flexibility reserves

Figure 33: Generation change by state and type

The impact of the flexibility reserves on the regional energy transfers is shown in Figure 34. Region-to-region transfers did not change substantially from the 2022 Common Case to the no-flexibility reserves sensitivity, which suggests that adding the flexibility reserves assumption to the 2022 Common Case did not impact the utilization of the transmission system. However, as noted previously, the generator dispatch was slightly impacted by the additional reserve requirement.

Figure 34: Comparison of Regional Transfers

Other Observations

1. The additional hydro generation modeled in British Columbia in the 2022 Common Case (versus 2020 Reference Case) created a significant energy surplus that flowed into the northwest in the simulations. At the TEPPC meeting in June 2012 members from BC Hydro reported that there were proposals in British Columbia for a few large industrial loads that could absorb most of the new hydro and renewable resources, but these loads were not reflected in the 2022 Common Case. As the plans for these large industrial plants move forward, their corresponding loads will be reflected in the BC Hydro load forecasts for future TEPPC study cycles.

Study Summary

The 2022 Common Case portrays an expected future with the following highlights.

· Renewable generation accounting for 16.8 percent of total WECC annual generation.

· A shift towards replacing coal-fired generation with gas-fired and renewable generation between 2011 and 2021.

· Coal retirements = 4,300 MW

· Gas additions = 21,700 MW

· Renewable additions = 40,350 MW

· The addition of 2,000 MW of conventional hydro generation in British Columbia.

· A reduction in the net imports into California. This is related to the following modeling changes as compared to the 2020 Reference Case.

· Refinements in modeling of cogeneration and CHP plants resulting in increased generation from these resources.

· Revisions to the renewable generation portfolio, including a net in-state increase of 2000 MW from the in-state/out-of-state assumptions

· Increased efficiency (and dispatch) of generation additions that replaced units retired for OTC.

Based on these assumptions, the 2022 Common Case produced the following major observations:

1. The most significant change in the generation dispatch observed in the 2022 Common Case as compared to the 2020 Reference Case (see Figure 26) was the increase in cogeneration and CHP. The adjustments made to the modeling of CHP and cogeneration units resulted in an additional 56 thermal units being designated as “must-run” compared to the 2020 Reference Case. In addition, the minimum capacities of 104 units in California were increased from 30 – 50 percent up to 99 percent. Because the must-run units are dispatched to at least their minimum generation level, these units are forced to run at a much higher level of output consistent with their actual operation.

2. In the 2022 Common Case net transfers from British Columbia to Alberta appear to be low as compared to historical flows. This may be related to the high hurdle rate ($48/MWh) applied to transfers in that direction of flow, which was carried over from the 2020 study cases, where the hurdle rate served as a modeling patch to limit unrealistic imports of hydro generation into the Alberta energy market.. Another contributing factor could be the heat rate adjustments made to the cogeneration units in Alberta. The Alberta cogeneration heat rates were reduced, thus resulting in a more economic generator that was more likely to be dispatched to fill the energy short fall in Alberta. A chart comparing the 2022 Common Case results to the actual Alberta – British Columbia annual interchange is shown in Figure 35.

Figure 35 - Alberta - British Columbia Interchange

Based on the comparisons, an adjustment to the hurdle rates between Alberta and British Columbia would be an acceptable option to further improve the results.

3. The west to east flow between California and Arizona is unusual as compared to historic flows. The graph in Figure 36 reflects the dispatch decisions made by PROMOD and expands the information presented in Figure 29 regarding generation displacement in the AZNMNV subregion. It is anticipated that current contractual obligations will be honored through 2022 and if these were modeled in the 2022 Common case the results could be different.

Figure 36 - AZNMNV Hourly Balance (positive represents exports)

The product of all of the input assumptions is reflected in the path flow results for the 2022 Common Case. The placement of generic generation projects and the incremental transmission projects have a significant impact on the study results. Importantly, the 2022 Common Case serves as the starting point for the majority of the other ten year study cases in the 2011 and 2012 Study Programs.

Peak and Energy Load Adjustments

LRS Forecast vs. PC1 Common Case

PC1 EnergyAESO APS AVA BCH BPA CFE CHPD DOPD EPE FAR EAST GCPD IID LDWP MAGIC VLY NEVP NWMT PACE_ID PACE_UT PACE_WY PACW PG&E_BAY PG&E_VLY PGN PNM PSC PSE SCE SCL SDGE SMUD SPP SRP TEP TIDC TPWR TREAS VLY WACM WALC WAUW 13034.2579908675694994.8059360730641729.8401826484017571.28995433789996161.17579908675731706.5867579908681463.00228310502314225.433789954337931289.6118721461187354.14383561643865590.92465753424642511.51826484018253665.239726027397620.742009132419533131.92922374429241340.502283105023515.943373344748924418.24788333332891606.63729155251082649.31506849315065710.91324200913287724.93150684931152739.509132420091621205618.99543378995443090.627853881280313479.7260273972621254.62328767123292891.8721461187222065.87899543378991483.44748858447474386.96917808219221858.3789954337901337.78538812785388625.547945205478871314.04109589041083578.1392694063911870.0799086757995297.739726027397296LRS EnergyAESO APS AVA BCH BPA CFE CHPD DOPD EPE FAR EAST GCPD IID LDWP MAGIC VLY NEVP NWMT PACE_ID PACE_UT PACE_WY PACW PG&E_BAY PG&E_VLY PGN PNM PSC PSE SCE SCL SDGE SMUD SPP SRP TEP TIDC TPWR TREAS VLY WACM WALC WAUW 1.2873680079792393E-2115.2292759168103754.8282197577768786.7512128998714694E-35.0611800725164368E-4-7.9685716325457196E-3-3.2710941958953329E-3-1.089714433248902E-441.3211006617436287.15921647581336984.0216315278485126E-416.5557709436984269.48142524614701212.64124008945133746.32937022866735840.324304589397996.778486870139541858.05843020833252421.10945952126144233.573857555650577383.64224591538277545.598010755565561.135597263841646160.06030273437489223.322582227454467.211838256278483952.7621602097624427.283810132170402194.2805933843468269.21273566816488221.964212217287219266.96917808219189146.1720862541022810.9348021903538694.5985391682279453E-426.61946503103628594.957628781393041-5.9669529457551161E-4-1.6909037551045005E-3LRS PeakAESO APS AVA BCH BPA CFE CHPD DOPD EPE FAR EAST GCPD IID LDWP MAGIC VLY NEVP NWMT PACE_ID PACE_UT PACE_WY PACW PG&E_BAY PG&E_VLY PGN PNM PSC PSE SCE SCL SDGE SMUD SPP SRP TEP TIDC TPWR TREAS VLY WACM WALC WAUW 15866.910120.200000000004278411996.210463.13460.9722.3423.62325.3000000000002735.3857.81234.59999999999998344.51400.86843.71894.4871.372089099999588582.60829399999241879.07581899999994315.810200.10299999999213939.4894318.83226.483185429.325626.06200000000519535496.33800000000064443.22210.58118.73392.5695.81039.90000000000012814.94886.90000000000051600.1153PC1 Peak158679787272011996104633461722.29998779296841423.600006103515852244724.70001220703182857.7999877929684112018200138267341833861.70001220703182848718584266894012126422029767954532222311190948174303215875213128673.700012207031821040277747241600153

Energy - aMW Peak - MW

WECC Annual Energy by Type : 2022 PC1 Common Case

Internal Combustion0.0%

Conventional HydroPumped StorageSteam - CoalSteam - OtherNuclearCombined CycleCombustion TurbineCogenerationICNegative Bus LoadBiomass RPSGeothermalSmall Hydro RPSSolarWind246879484.373095936.7800000012267319560.520000012401908.989999999874888891.539999992156645763.170000055080137.470000003586098510.86999999188052.18999999977462747013572744.37999999933454146.3099999957150889.980000000423616313.55000000891193635.400000006

Page 1 of 41

Page 2 of 41

02,0004,0006,0008,00010,00012,00014,00016,0002011202120112021201120212011202120112021201120212011202120112021AlbertaBritish

Columbia

AZ_NM_NVSBASINCalif_NorthCalif_SouthNWUSRMPA

Renewable Buildout (2011 -2021) -2022 Common CaseTotal at year-end

WindSolarSmall Hydro RPSGeothermalBiomass RPSMW

02,0004,0006,0008,00010,00012,00014,00016,00018,00020,000

Biomass RPSGeothermalSmall Hydro

RPS

SolarWind

Megawatts

PC1-CC WECC Additions 2011 -2021

02004006008001000120014001600

Histogram of CA-SOUTH Composite Reserve Requirement -2022 PC1 CC

British ColumbiaBCHNorthwest

AVAGCPDPSEBPANWMTSCLCHPDPACWTPWRDOPDPGNWAUW

Basin

ID –FAR EASTID –MAGIC VLYID –TREAS VLYPACE_ID

PACE_UT

PACE_WYSPP

AZNMSNV

APSSRPEPETEPNEVPWALCPNM

AlbertaAESORMPAPSCWACMCA_South

CFESCEIIDSDGELDWP

CA_North

PG&E_BAYPG&E_VLYSMUDTIDC

8 Pools

39 Areas

(2000)(1000)0 1000 2000 3000 4000 5000 AZNMNV To Ca_SBasin To AZNMNVBasin To Ca_NBasin To Ca_SCa_N To Ca_SCanada To NWUSNWUS To BasinNWUS To Ca_NNWUS To Ca_SRMPA To AZNMNVRMPA To BasinAverage Megawatts

Transfers between Sub-Regions (aMW)

2020 PC12022 PC1

-8000-6000-4000-200002000400060008000

CA_North Hourly Load/Gen Balance

2020 PC12022 PC1

-800-600-400-2000200400600800

Megawatts

P01 Alberta-British Columbia Path Duration Plots

2010PC1_20PC1_22

E->W

05001,0001,5002,0002,5003,0003,5004,000

7/5/20227/6/20227/7/20227/8/20227/9/20227/10/20227/11/20227/12/20227/13/20227/14/2022

NWMT Load/Gen Balance Snapshot -PC1 CC

DSMOtherCombustion Turbine Steam -Other Combined Cycle Biomass RPS Geothermal Solar Steam -Coal Small Hydro RPS Nuclear Hydro+PSWind DemandDump

MW

-1500-1000-5000500100015002000

Megawatts

P28 Intermountain -Mona 345 kV Path Duration Plots

2010PC1_20PC1_22

W->E

-250-200-150-100-50050100150200250

Megawatts

P29 Intermountain-Gonder 230 kV Path Duration Plots

2010PC1_20PC1_22

E->W

0%10%20%30%40%50%60%70%Percent of Hours

Most Heavily Utilized Paths -PC1 Common Case

U75U90U99

(40,000)(20,000)020,00040,00060,00080,000

Conventional HydroPumped StorageSteam - CoalSteam - OtherNuclearCombined CycleCombustion TurbineCogenerationInternal CombustionNegative Bus LoadBiomass RPSGeothermalSmall Hydro RPSSolarWind

GWh

Annual Energy Difference: 2020 PC1 SPSC Ref Case vs. 2022 PC1 Common Case

02,0004,0006,0008,00010,00012,00014,00016,00018,00020,000

3/28/20223/29/20223/30/20223/31/20224/1/20224/2/20224/3/20224/4/20224/5/20224/6/2022

AZNMNV Load/Gen Balance Snapshot -PC1 CC

DSMOtherCombustion Turbine Steam -Other Combined Cycle Biomass RPS Geothermal Small Hydro RPS Hydro+PSSolar Wind Steam -Coal Nuclear DemandDump

MW

05,00010,00015,00020,00025,00030,00035,000

7/5/20227/6/20227/7/20227/8/20227/9/20227/10/20227/11/20227/12/20227/13/20227/14/2022

NWUS Load/Gen Balance Snapshot -PC1 CC

DSMOtherCombustion Turbine Steam -Other Combined Cycle Biomass RPS Geothermal Small Hydro RPS Hydro+PSSolar Wind Steam -Coal Nuclear DemandDump

MW

05,00010,00015,00020,00025,00030,00035,000

7/5/20227/6/20227/7/20227/8/20227/9/20227/10/20227/11/20227/12/20227/13/20227/14/2022

AZNMNV Load/Gen Balance Snapshot -PC1 CC

DSMOtherCombustion Turbine Steam -Other Combined Cycle Biomass RPS Geothermal Small Hydro RPS Hydro+PSSolar Wind Steam -Coal Nuclear DemandDump

MW

050010001500200025003000350011583154726297869431100125714141571172818852042219923562513267028272984314132983455361237693926408342404397455447114868502551825339549656535810596761246281643865956752690970667223738075377694785180088165832284798636

PC1 Coal-fired Gen -NWUS

MW

0500100015002000250030003500

PC1 Coal Fired Gen (May + June) -NWUS

MW

(400)(200)0200400600Conventional HydroPumped StorageSteam - CoalSteam - OtherNuclearCombined CycleCombustion TurbineCogenerationICNegative Bus LoadBiomass RPSGeothermalSmall Hydro RPSSolarWind GWh

Annual Energy Difference: 2022 PC1 Common Case vs. 2022 PC1 NoFlex

-400-300-200-1000100200300

GWh

Annual Energy Difference: 2022 PC1 Common Case vs. 2022 PC1 NoFlex

Hydro+PSSteam - BoilerCombined CycleCombustion TurbineCogenerationRenewableOther

(500)050010001500200025003000

AZNMNV

To Ca_S

Basin To

AZNMNV

Basin To

Ca_N

Basin To

Ca_S

Ca_N To

Ca_S

Canada To

NWUS

NWUS To

Basin

NWUS To

Ca_N

NWUS To

Ca_S

RMPA To

AZNMNV

RMPA To

Basin

Average Megawatts

Transfers between Sub -Regions (aMW)

PC1 CCNoFlexRsv

-500 1,000 1,500 2,000 2,500 3,000 3,500 2006200720082009201020112022 PC1AESO Annual Market StatisticsTEPPC

Comparison of Alberta -B.C. Interchange (GWh)

Imports on B.C. IntertieExports on B.C. IntertieNet Imports from B.C.

-10000.00-8000.00-6000.00-4000.00-2000.000.002000.004000.006000.008000.00

2022 PC1 AZNMNV Hourly Load/Gen Balance