2015 Integrated Transmission and Reliability Assessment-Final€¦ · Web view09/03/2016 · The Western Interconnection has a diverse residential, commercial, industrial and agricultural

Integrated Transmission and Resource Assessment

Summary of 2015 Planning Analyses

System Adequacy Planning DepartmentMarch 9, 2016

155 North 400 West, Suite 200

Salt Lake City, Utah 84103-1114

2015 Integrated Transmission and Resource Assessment 1

Table of Contents

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

2. Context................................................................................................................. 2

2.1 2014—The Current World...........................................................................................................2

2.1.1. 2014 Loads...........................................................................................................................2

2.1.2. 2014 Generation..................................................................................................................3

2.1.3. 2014 Transmission...............................................................................................................3

2.2. 2024—The Expected Future........................................................................................................4

2.2.1. 2024 Loads...........................................................................................................................4

2.2.2. 2024 Generation..................................................................................................................4

2.2.3. 2024 Transmission...............................................................................................................6

2.3. 2034—Plausible Futures............................................................................................................. 7

3. Analyses................................................................................................................ 9

3.1 10-Year Production Cost Model (PCM) Studies...........................................................................9

3.1.1 Stress Conditions............................................................................................................... 10

3.1.2 Bookends........................................................................................................................... 11

3.1.3 Policy-Driven Changes........................................................................................................12

3.1.4 Specific Study Cases...........................................................................................................12

3.1.5 Summary Observations......................................................................................................21

3.2 20-Year Capital Expansion Studies............................................................................................22

3.2.1 Model Enhancements........................................................................................................22

3.2.2 20-Year Study Cases...........................................................................................................23

3.3 Cost Analyses............................................................................................................................ 23

3.4 Regional Analyses......................................................................................................................24

3.5 Base Case request of WECC...................................................................................................... 25

3.5 Probabilistic Assessments.........................................................................................................25

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


4. Reliability Issues..................................................................................................27

4.1 Western Interconnection Flexibility Assessment......................................................................27

4.1.1 Study Implications..............................................................................................................28

4.2 Energy-Water-Climate Change Nexus.......................................................................................31

4.3 Clean Power Plan...................................................................................................................... 33

4.3.1 Regional Engagement........................................................................................................33

4.3.2 Internal Efforts...................................................................................................................34

4.4 Planning for Uncertainty...........................................................................................................34

4.4.1 Background........................................................................................................................34

4.4.2 Study Focus........................................................................................................................35

4.4.3 Methodology..................................................................................................................... 35

4.4.4 Scenarios and Deterministic vs. Probabilistic Approach to Modeling................................37

4.4.5 Results and Recommendations..........................................................................................39

4.4.6 Implications for WECC’s Planning Activities.......................................................................40

4.5 Planning Tool Alignment...........................................................................................................40

4.6 NERC/WECC Reliability Assessments.........................................................................................41

4.6.1 Assessment Caveats...........................................................................................................50

5. Recommendations...............................................................................................51

5.1 Priorities for Infrastructure.......................................................................................................51

5.2 Priorities for Policy....................................................................................................................52

6. Conclusion...........................................................................................................53

Appendix A: Glossary of Terms...................................................................................54

Appendix B: Analytical Reports Completed in 2015....................................................59



1. Introduction

WECC’s footprint is the Western Interconnection, which includes all or part of 14 Western states, two Canadian provinces and a portion of Baja California in Mexico (see below). Within that area, WECC is the entity responsible for assuring reliability and offers a unique Interconnection-wide perspective on issues that could affect the reliability of the Bulk Electric System. WECC has identified several strategic objectives, many of which directly impact transmission and resource planning including:

• Working with the Region’s leaders to provide unbiased information to inform their decisions regarding critical electric reliability issues facing the Western Interconnection;

• Working in partnership with WECC’s stakeholders to help them plan, develop and operate the Bulk Electric System in accordance with industry-accepted reliability standards;

• Building a shared understanding of key reliability challenges that will drive WECC’s programs;

• Supporting the Region’s long-term reliability planning needs; and

• Effectively integrating stakeholder expertise and ensuring transparency of WECC’s work.



Figure 1: NERC Interconnections

WECC’s System Adequacy Planning (SAP) Department and the Transmission Expansion Planning Policy Committee (TEPPC) developed an analytical program for 2014-2015 designed to identify potential risks to reliability as well as opportunities for reliability improvement. These risks and opportunities could result from changes in loads, resources and transmission topology in the next 10-20 years, as well as to understand the impacts of evolving public policies affecting the Bulk Electric System (BES) in the Western Interconnection. WECC’s analytical program is designed to answer reliability-related questions WECC has identified as well as to provide unbiased information to inform stakeholders about potential solutions to the many challenges facing the Western Interconnection.

An important change within WECC during 2015 was its decision to reorganize its Reliability Planning and Performance Analysis (RAPA) function. One part of this reorganization was to combine the Transmission Expansion Planning and Resource Adequacy Departments into a single department known as System Adequacy Planning. As a result, the SAP department now includes additional functions not included in the former Transmission Expansion Planning Department, an enhancement reflected in the additional content included in this report.



This report presents a summary of analyses completed during 2014 and 2015. It does not repeat or duplicate analytical reports published or discussed previously. Rather, it describes their context and identifies overarching themes and recommendations based on multiple study results. This report also includes sections addressing reliability analyses completed consistent with NERC’s requirements, and probabilistic analyses--two functions added to the combined SAP Department. Individual study reports and supporting documents referred to in this summary report are listed in Appendix B of the report with hyperlinks that will lead the reader to a specific report.

2. Context

By definition, planning looks into the future and compares a possible future state with the present state. WECC’s SAP Department focuses on three primary planning horizons: 1-10 years (for resource adequacy), 10 years and 20 years into the future. The reference year for studies described in this report is 2014.

In looking to the future, the key question WECC’s planning studies seeks to answer is “how might the grid in the Western Interconnection need to change in the next 10-20 years to reliably and economically meet expected load with available and planned resources?” The answer to this question depends largely on understanding for each planning horizon what loads are expected to be, what resources are expected to be available to meet load, and what the transmission topology will be as well as expected regulatory mandates.

2.1 2014—The Current World

Each year, WECC prepares the “State of the Interconnection” report to provide a high-level look at the general state of the Western Interconnection. Among other information, the report includes information on loads, resources and transmission in the Western Interconnection as of its publication date. The following Load, Resource and Transmission information was taken from the 2014 State of the Interconnection report.

2.1.1. 2014 Loads

2014 Load Summary

Summer Peak Demand: 147,500 MW

2013-2014 Winter Peak Demand 133,400 MW

Total Energy: 888,200 GWh

The Western Interconnection has a diverse residential, commercial, industrial and agricultural load composition. From 2010 to 2014, annual energy consumption across the Interconnection increased an



average of 0.98 percent (8,400 GWh) each year, while seasonal peak demand has decreased 0.04 percent (100 MW) in the summer and increased 2.33 percent (3,000 MW) in the winter each year. Large daily peak variations may occur during the shoulder periods of the year (October–November and April–May) when entities tend to schedule maintenance. The potential for large load increases should be factored into maintenance scheduling decisions. While the summer peak has remained essentially flat, the winter coincident peak has increased in each of the last four years. This could be due in part to increasing behind-the-meter generation, such as distributed solar photovoltaic generation, that tends to reduce the summer peak more than the winter peak.

2.1.2. 2014 Generation

2014 Generation Summary

Nameplate Capacity: 284,300 MW

Net Generation

Fossil Fuels: 450,600 GWh

Hydro: 216,600 GWh

Wind and Solar: 63,600 GWh

The Western Interconnection is comprised of a divergent mix of generation resources varying by geographic area.

• The largest category of generation added in 2014 was the installation of more than 3,400 MW of new utility-scale solar generation.

• Approximately 30 percent of installed wind capacity and 80 percent of installed solar capacity in the United States is located in the Western Interconnection.

• The base-load nature of coal and nuclear fueled generation resources tends to keep the output from these resources relatively steady throughout the day and throughout the year. However, generation from natural gas and hydro units can vary widely during the day to respond to changes in consumer demand and output from variable generation resources, with the relative proportion of these two resources varying by hydro conditions. In good hydro years when more hydro resources are available, they will be used in higher proportion to gas due to their lower cost, while gas will be used in higher proportion when less hydro is available.



2.1.3. 2014 Transmission

2014 Transmission Summary

Transmission Miles (2012): 127,700

WECC Paths: 67

The Western Interconnection is characterized by long transmission lines connecting remote generation to load centers. Over 127,700 circuit miles of transmission lines cross the Western Interconnection. The majority of major WECC paths are regularly operated under 75 percent of their rating.

2.2. 2024—The 10-Year Planning Horizon

The 2024 TEPPC Common Case is a data set based on a collection of assumptions that are designed to serve as a reference point for the WECC Bulk Electric System in 2024. It is built from information provided by WECC’s stakeholders and is vetted thoroughly through WECC’s stakeholder process. While WECC does not predict that loads, resources and transmission topology will exactly match the 2024 Common Case, it serves as the reference for planning. Individual components are described below.

2.2.1. 2024 Loads

Based on the Balancing Authority (BA) load forecasts provided to WECC’s Reliability Assessment Work Group (RAWG), the peak demand in 2024 is estimated to be 27,669 MW higher than the 2014 actual peak demand (compound annual growth rate of 1.7%) and total energy is estimated to be 143,054 GWh higher than in 2014 (compound annual growth rate of 1.5%). Figure 2: Load Growth 2014 to 2024 below shows the trend from the actual peak demand in 2014 to the forecast peak demand in 2024.



Figure 2: Load Growth 2014 to 2024

147,500

175,169

888,200

1,031,254

800,000

850,000

900,000

950,000

1,000,000

1,050,000

130,000

135,000

140,000

145,000

150,000

155,000

160,000

165,000

170,000

175,000

180,000

Peak Demand (MW) Annual Energy (GWh)

Trend ------------------>>

2.2.2. 2024 Generation

The generation inputs for the 2024 Common Case reflect existing resources plus expected resource additions for combined cycle, combustion turbine, and renewable generation between 2014 and 2024. Assumptions for resource additions were based on project status (e.g., under construction, pre-construction regulatory review and future-planned) as well as on collaboration with stakeholders. Conversely, plans to retire (or convert the fuel) for several coal-fired and oil-gas steam generators are also represented. The total net capacity1 changes for the referenced resource types are shown in Figure 2, with a net capacity change of 17,893 MW (excluding the Distributed Generation/Demand Response/Energy Efficiency (DG/DR/EE) that was modeled as modifications to load in the Common Case). The decrease in Steam-Other reflects the mandatory retirements of Once-Through-Cooling units along the coast of California. Figure 3: Key Resource Net Capacity Change (MW) between 1/1/2014 and1/1/2024 shows total net generation capacity in 2024.

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



Figure 3: Key Resource Net Capacity Change (MW) between 1/1/2014 and 1/1/2024

-15,000 -10,000 -5,000 0 5,000 10,000 15,000

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



Figure 4: Net Generation Capacity in 2024

Conventional Hydro23.7%

Energy Storage2.2%

Steam - Coal11.3%

Steam - Other1.1%

Nuclear2.6%

Combined Cycle22.7%

Combustion Turbine12.3%

IC0.4%

Other0.5% DG/DR/EE -

Incremental4.6%

Biomass RPS1.0% Geothermal

1.4%Small Hydro RPS

0.4%

Solar5.5%

Wind10.3%

Net Generation Capacity - 2024 (MW)

2.2.3. 2024 Transmission

Expected transmission in 2024 is the summation of transmission in the current grid plus new transmission expected to be added through 2024. The transmission network was derived from the Technical Studies Subcommittee (TSS) 2023-HS1 Heavy Summer Power Flow Base Case and updated as described in the 2024 Common Case release notes (included as part of the 2024 Common Case package).

While many potential transmission projects are underway, WECC has adopted the Common Case Transmission Assumptions (CCTA) as the proposed transmission additions that are likely to be complete in 2024. This list of transmission additions is developed and approved by the Regional Planning Coordination Group (RPCG). The 2024 Common Case Transmission Assumptions (CCTA) report is posted on the WECC web site. The future projects that were either retained from the Base Case or added per stakeholder review are shown below in Figure 5: 2024 Common Case Transmission Projects. Note that 12 out of the 22 projects are either complete or under construction.


https://www.wecc.org/_layouts/15/WopiFrame.aspx?sourcedoc=/Reliability/RPCG_2024CCTA_Report.pdf&action=default&DefaultItemOpen=1

https://www.wecc.org/Reliability/2024-Common-Case.zip


Figure 5: 2024 Common Case Transmission Projects

2.3. 2034—Plausible Futures

During the 2010-2012 planning cycle, WECC expanded its planning activities by exploring a 20-year planning horizon. While there is significant uncertainty in a planning horizon as long as 20 years, analyses in this time frame identify strategic choices that planners should consider during that period. It is not possible to “predict” the state of the Western Interconnection 20 years in the future. However, by describing futures that are plausible, planners can identify strategic choices that will impact the infrastructure needed to reliably serve expected load with available resources.

The 2024 Common Case describes a planning point of comparison 10 years from the reference year. Due to the significant uncertainties associated with looking another 10 years into the future (20 years from the reference year), WECC is developing a “Reference Case” to provide the context for studies in the 20-year planning horizon. The 2034 Reference Case extends the assumptions used in the 2024 Common Case an additional 10 years to create a reference point for studies completed in the 20-year



planning horizon. Results of study cases completed in the 20-year planning horizon would then be compared to the 2034 Reference Case2.

WECC has adopted a “scenario planning” approach to provide a broad context for planning in the 20-year horizon and to identify plausible futures for the Western Interconnection. From 2010 through 2012, the Scenario Planning Steering Group (SPSG) identified four plausible futures shown below in Figure 5: WECC Scenario Matrix. The matrix is defined by two primary drivers: economic growth in the Western Interconnection and technological innovation in electric supply.

Figure 6: WECC Scenario Matrix

Scenario 1 is a future that includes high and widespread economic growth, but only evolutionary technological development. There is no overriding policy theme, and the focus is on growth.

Scenario 2 is a future that includes high and widespread economic growth, and breakthrough and paradigm-changing technological developments. The policy theme is on reducing greenhouse gas emissions and on developing new technologies.

Scenario 3 is a future that includes relatively low and localized economic growth combined with evolutionary technological development. Slow growth would be expected to lead to tough policy choices and keeping consumers’ rates low.

2 WECC plans to complete the 2034 Reference Case early in 2016.



Scenario 4 is a future with relatively low and localized economic growth, but with breakthrough and paradigm-changing technological developments. Policies would be expected to focus on capturing “low-hanging fruit” investments in clean energy technologies.

The complete WECC Scenario Report is posted on the WECC web site.

From 2013 through 2015, the SPSG expanded WECC’s future scenarios with the addition of a fifth scenario focusing on the nexus between energy, water and climate change. That scenario formed a foundation for exploring potential reliability risks that could result from an average global temperature increase of 3oF. by 2035. This initiative is described in greater detail in Section 4 of this report and the complete report of the Energy-Water-Climate Change Scenario is posted on the WECC web site.

3. Analyses

3.1 10-Year Production Cost Model (PCM) Studies

The 10-year studies that were run during the study program and 2015 work plan were intended to provide insights from stress conditions, “bookends” to the range of potential study cases, and policy-driven changes. The completed studies are listed below in Table 1.

Table 1:2015 WECC 10-Year Study Cases3

Case ID DescriptionPC01 2024 Common CasePC02 High Load; loads increased by 10%PC03 Low Load; loads decreased by 10%PC04 High HydroPC05 Low HydroPC06 High NG pricePC07 Low NG pricePC10 Variable carbon pricePC17 Wind UncertaintyPC18 High Distributed PV – California onlyPC19 High Distributed Photovoltaic (PV) – West-widePC20 Coal RetirementPC22 High RenewablePC26 Replace Intermountain coal with CC, Wind, and/or Compressed Air StoragePC30 BLM Resource additions

3 Links to each of these study cases are included in Appendix B.


https://www.wecc.org/Reliability/WECC-Energy-Water-Climate-Change-Scenario-Final.pdf

https://www.wecc.org/Reliability/WECC_Scenarios.docx


In addition, some of these study cases included “expansion cases” that explored the impacts of adding various transmission expansion projects to the study case. The results from the studies were analyzed to find the impacts to transmission utilization, generation dispatch, variable production cost, and CO2 emissions.

Many evaluations of transmission utilization involve the term “congestion.” This term can present challenges to understanding study results, since some transmission lines are designed to operate during a high portion of the year with flows approaching their rated capacities, a condition some stakeholders might refer to as congested. Technically congestion occurs when the electrical system reaches a binding limit – for example, the thermal rating of a transmission facility or path – such that system operators must take actions to ensure that the limit is not exceeded. These actions often involve changing the dispatch pattern of generation away from the pattern that the entities controlling generation would otherwise have preferred. Usually re-dispatching generation increases costs as the output of relatively efficient generators is decreased and the output of relatively less efficient generators increased.

From a modeling perspective it is difficult to capture the myriad of factors that can result in a congestion event, for example, unexpected outages of multiple transmission elements, unplanned facility derates, unusual weather patterns which can change electrical loads and resource output in unanticipated ways. As a consequence, in addition to the standard measures of congestion – such as differences in Locational Marginal Prices (LMPs), congestion rents, and the number of hours per year that a constraint is binding in the model, WECC has chosen to report the metric “heavily utilized paths.” A path is designated as “heavily utilized” if it meets one or more of the following conditions:

• Flows on the path are at or above 75% of the path rating for 50% or more of the hours in the study year (“U75 > 50%); or

• Flows on the path are at or above 90% of the path rating for 20% or more of the hours in the study year (“U90 > 20%); or

• Flows on the path are at or above 99% of the path rating for 5% or more of the hours in the study year (“U99 > 5%).

3.1.1 Stress Conditions

Some of the studies completed in 2015 simulated particularly stressful conditions. These studies included large increases in power flows and the potential for unserved load. The “high stress” cases in the 2015 study program included PC2 (high loads), PC5 (reduced hydroelectric generation), and PC20 (large amounts of retired coal-fired generation). A few of the key results are compared to the common case in Table 2.



Table 2: Key Results from Selected Study Cases

ResultPC1 –

Common CasePC2 – High

LoadPC5 – Low

HydroPC20 – Coal Retirement

PC22 – High Renewables

Unserved Load (GWh) 0 60 0 0 0

Annual Generation (GWh) 1,050,342 1,153,055 1,030,860 1,047,365 1,051,062

Annual Renewable generation (GWh) 168,293 166,760 167,353 224,970 293,432

Dump Energy (GWh)4 358 552 375 1,481 32,297

Var. Production Cost (M$) 22,843 27,026 25,354 22,200 18,771

CO2 Amount (MMetrTn) 363 420 394 277 294

The impact to transmission utilization is shown in Table 3.

Table 3: Metrics for Highly Utilized Paths5

Number of Hours At or Exceeding Metrics

Path and Metrics6

PC1 – Common

Case PC2 – High LoadPC5 – Low


PC22—High Renewables

P01 Alberta-British Columbia 75%(E-to-W) 90%

99%

6622

6

1183773564

1064670502

368184102

1072684480

P18 Montana-Idaho 75%

(E-to-W) 90%99%

527231131

456171

74

1937323

563206

89

1778794424

P26 Northern-Southern CA 75%

(N-to-S) 90%99%

854353195

1707742457

306114

58

923332177

1744842501

P31 TOT 2A 75%(N-to-S) 90%

99%

1100

261513

511

712296155

1320838583

P45 SDG&E-CFE 75% 321 297 258 707 1780

4 Energy in a Production Cost Model analysis that is selected in the economic dispatch to be delivered to load but cannot actually be delivered due to modeling constraints.

5 In some cases, lines may be designed to have flows at a high percentage of rated capacity.6 Utilization metrics are met if the utilization criteria are met while operating the path in either direction. Note that many

paths have different ratings for operations in different directions.



Number of Hours At or Exceeding Metrics

Path and Metrics

PC1 – Common

Case PC2 – High LoadPC5 – Low


PC22—High Renewables

(N-to-S) 90%99%

204144

185134

12184

477381

15061349

P48 Northern NM 75%(NW-to-SE) 90%

99%

1246164

7

1985357

24

94771

1

18440

23720

0P52 Silver Pk-Control

75%(W-to-E) 90%

99%

29841948

0

41262828

0

41212764

0

30102038

029322055

0P60 Inyo-Control 75%

(E-to-W) 90%99%

610340192725

60033754

40

678947983342

335921811624

32481501

803P83 Montana Alberta

Tie 75%(N-to-S) 90%

99%

1058361156

368125311945

739277142

1794934572

424532852722

3.1.2 Bookends

Several bookend cases were run to test the impact of extreme values for some of the study cases’ more significant input variables. These cases represented extreme high and low values that might be expected for loads, hydro generation availability, gas prices and carbon prices, factors that have a significant effect on study results.

Many of the impacts are predictable with the expected impacts shown in Table 4.

Table 4: Expected Impacts of Bookend Cases

Case

Expected Impacts relative to Common Case

Heaviest Path

Utilization

Total Variable

Production Cost

CO2

EmissionsDump

Energy7

Proportion of

RenewableEnergy

PC2 Low Loads

PC3 High Loads

PC4 High Hydro Unknown Unknown

7 Energy in a Production Cost Model analysis that is selected in the economic dispatch to be delivered to load but cannot actually be delivered due to modeling constraints.



Case

Expected Impacts relative to Common Case

Heaviest Path

Utilization

Total Variable

Production Cost

CO2

EmissionsDump Energy

Proportion of

RenewableEnergy

PC5 Low Hydro Unknown

PC6 High NG price Unknown

PC7 Low NG price Unknown

PC 10 High CO2 $ Unknown

PC 11 Low CO2 $ Unknown Unknown

3.1.3 Policy-Driven Changes

Study cases that explored policy-driven changes in the 2015 TEPPC Study Program included studies that examined various carbon prices, various levels of distributed solar PV, coal retirements, high renewable penetrations, and studies requested by the U.S. Bureau of Land Management (BLM). All except the carbon price studies involve adding additional renewable generation. In the coal retirement study, renewable generation replaces the retired coal-fired units.

3.1.4 Specific Study Cases

The following study cases are selected from the complete list of cases completed during 2015 to illustrate some of the more significant study results.

3.1.4.1 PC10 – Carbon Price

PC10 examined the impacts of implementing various carbon prices. The carbon prices drive the model to displace coal-fired generation with gas-fired generation due to the lower CO2 intensity of natural gas. Since California already has a carbon tax (AB32), this tax was modeled in the common case and a non-California carbon tax was added in the increments listed in Table 5.



Table 5: Application of Carbon Price in 10-Year Study Cases

CaseCarbon Tax ($/metric ton)

DescriptionWECC (non-California)

California

PC1 0.00 27.51 Common case with AB32 in CaliforniaPC10-15 15.00 27.51 Assume that California would not lower their taxPC10-27 27.51 27.51 Apply AB32 tax WECC-widePC10-40 40.00 40.00 WECC-wide $40 taxPC10-50 50.00 50.00 WECC-wide $50 taxPC10-60 60.00 60.00 WECC-wide $60 tax

The generation impacts from the carbon taxes are presented in Figure 7.. The progressive shift from coal-fired to gas-fired generation reflects the increasing cost of CO2 emissions.

Figure 7: Generation Impacts of Carbon Prices

A simple average of capacity factors for the two fuels also shows the effect of the increasing carbon taxes.



Figure 8: Capacity Factor Impacts of Carbon Prices

In PC10, generation shifted from coal-fired to gas-fired throughout the Western Interconnection due to the difference in carbon intensity between the two fuels. As coal becomes less economic, it is displaced by other generation in economic order, which in some cases reduces the transmission flows on certain paths. One result of this was that imports into California decreased proportionately with the increasing carbon prices, thus reducing north-to-south flows on Paths 65 and 66.

3.1.4.2 PC19 – Distributed PV

PC19 included a significant increase of distributed resources. Approximately 22,648 MW (47,487,402 MWh) of generation was distributed throughout the Western Interconnection. These resources were modeled as small scale solar PV or “rooftop solar” for individual retail customers. Dump energy in PC19 occurred primarily in Southern California. A thorough investigation into the direct causes of this noted increase was not performed due to time limitations. However, from preliminary testing, it appears that local minimum generation nomograms, as well as branch and path rating limits were the primary associated modeling constraints. In future studies, if this dump energy reoccurs, the next investigative measure would be to tune the hourly renewable resources as “must run” units, whether by disallowing “spillage” or by setting their monthly redispatch price to -100 $/MWh. An increase in path utilization in Southern California and through the northeast Western Interconnect was also observed in this study.

Changes to the generation dispatch are shown in Figure 9.



Figure 9: Changes to Generation Dispatch - PC19

Conventional HydroEnergy Storage

Steam - CoalSteam - Other

NuclearCombined Cycle

Combustion TurbineIC

OtherDG/DR/EE - Incremental

Biomass RPSGeothermal

Small Hydro RPSSolarWind

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

Annual Generation by Category (MWh)2024 PC19 High DG WECC 2024 PC1 v1.5

3.1.4.3 PC21 – Coal Retirement

One of the studies completed in 2015, PC21, considered several additional coal unit retirements beyond those already modeled in the 2024 Common Case. The retired coal units were replaced by renewable generation and gas-fired units, resulting in a 54% reduction in coal-produced Mwh. The goal was to achieve a CO2 reduction that matches the climate model trajectory of reducing carbon emissions to 80 percent below 2005 levels by 2050. Stakeholders requesting the study case selected the specific coal generating units to be retired in the case (the retirements were not related to any utility’s specific Integrated Resource Plan).

Note that this study case differs from WECC’s analysis of reliability impacts related to implementing the Clean Power Plan (CPP). In 2014, WECC published a preliminary technical report on potential impact of CPP implementation. WECC continued to follow developments related to the CPP during 2015 and worked with the Western Interconnection Regional Advisory Body (WIRAB) to validate its analytical capabilities. Section 4.3 of this report discusses these activities in greater detail.

The changes to the generation dispatch resulting from PC21 are shown in Figure 10.


https://www.wecc.org/Reliability/140912_EPA-111(d)_PhaseI_Tech-Final.pdf


Figure 10: Generation Changes in PC21 Relative to 2024 Common Case

The CO2 emissions reduction is presented in Figure 11: CO2 Emission Reductions in PC21 Relative to 2024 Common Case, where the intersection of the blue line and the 2024 vertical line represents the goal (248 million metric tons), and the red and green markers show the emissions from the PC1 common case and the PC21 coal retirement case.



Figure 11: CO2 Emission Reductions in PC21 Relative to 2024 Common Case

0

50

100

150

200

250

300

350

400

2005

2007

2009

2011

2013

2015

2017

2019

2021

2023

2025

2027

2029

2031

2033

2035

2037

2039

2041

2043

2045

2047

2049

Western Interconnection CO2(million metric tons)

GoalPC01PC21PC21 277

Goal 248Short 29

3.1.4.4 PC22 – High Renewable

PC22 investigated the system changes that might necessary to accommodate significantly higher levels of renewable resource penetration across the Western Interconnection (WI), focusing on penetration levels of about 50 percent. The study focused on five regions within the U.S. portion of the WI, since these regions tend to have similar weather and load patterns across the region; limited internal transmission constraints; some degree of existing regional coordination; and limited reliance on other regions.


248 MMT

277 MMT


Figure 12: Regions Used for PC21

NORTHWEST

BASIN ROCKY MOUNTAIN

CALIFORNIA

DESERT SOUTHWEST

CANADA

Changes to generation dispatch in PC22 are shown in Figure 13: Generation Dispatch Changes in PC22 Relative to 2024 Common Case.



Figure 13: Generation Dispatch Changes in PC22 Relative to 2024 Common Case

The extent of renewable resources added in PC22 caused significant impacts on path flows throughout the Western Interconnection. Ten paths were highly utilized in this study, as shown below in Figure 14:Highly Utilized Paths in PC22.



Figure 14: Highly Utilized Paths in PC22

3.1.4.5 PC30 – BLM Renewable Additions

As a compliment to a prior 2022 CC BLM study, refined assumptions were developed with the Bureau of Land Management to include “High Priority Renewable Energy” resources. These resources are broadly defined as solar generating facilities that have a high probability of being developed in the near term. As a starting point, the National Renewable Energy Laboratory (NREL) compiled locations and capacities with greatest real-world potential for renewable development. This resulted in the addition of nine solar generators to the 2024 Common Case to become PC30. These generators were distributed across southern California and Nevada, at approximately 2800 MW (6,570,172 MWh) of potential generation. There were no significant adverse effects noted due to the increased resource additions and there was an apparent increase in transmission utilization.

Changes to the generation dispatch are shown in Figure 15.



Figure 15: Changes to Generation Dispatch for PC30

Conventional HydroEnergy Storage

Steam - CoalSteam - Other

NuclearCombined Cycle

Combustion TurbineIC

OtherDG/DR/EE - Incremental

Biomass RPSGeothermal

Small Hydro RPSSolarWind

0

50,000,000

100,000,000

150,000,000

200,000,000

250,000,000

300,000,000

Annual Generation by Category (MWh)2024 PC30 BLM Study 2024 PC1 v1.5

3.1.5 Summary Observations

In looking across the results of all 10-year study cases completed in 2015, WECC notes the following observations.

1. Despite analyses of many different combinations of loads, resources and transmission expansion, there were no studies that resulted in unserved load. While encouraging, this result cannot be interpreted as conclusive evidence that none of the study cases would present reliability risks. One consideration is the likelihood that in the future there will be significantly larger amounts of intermittent resources on the grid, resulting in many possible grid conditions that could present reliability risks beyond the scope of production cost modeling. For example, rapidly changing weather patterns coupled with unexpected load changes could pose operating challenges that deterministic modeling, by itself, cannot replicate.

2. Path flows in the Western Interconnection were affected in different ways by each of the study cases with highly-utilized paths changing from case-to-case. While various paths were heavily utilized in one or more study cases, it is likely that BAs would be able to maintain reliable operations without exceeding path ratings in all of the study cases examined in 2015.



3. Study cases that involved large additions of renewable energy often included significant amounts of dump energy (energy that could not be used to serve load due to various constraints). As a result, based on current modeling, simply increasing renewable generation injected into the grid may not increase renewable energy available to the grid Mwh-for-Mwh. WECC’s modeling as of 2015 did not reflect the flexible capabilities of resources, markets or operations that may exist on the system in 2024, thus leaving existing sources of system flexibility under-utilized or un-utilized. This finding indicates the need to improve WECC’s modeling of the system and for balancing area operators to continue to improve their capabilities to recognize latent and emerging flexibility options.

4. When load is increased across the Western Interconnection, the incremental load is served by the lowest-cost available resource. If zero-energy-cost resources such as solar or wind are available, they will be dispatched to meet incremental load. If these resources are unavailable, the model will move up the supply curve and select the next-lowest-cost resource, often coal or natural gas. The economic preference for coal and gas resources to meet incremental load would be expected to lessen as the capital costs of other resources decrease.

5. The price assumed for carbon makes a significant impact on resource selection due to its impact on resources’ Levelize2.d Cost of Energy (LCOE)8. Policies that implement increased carbon prices could have significant impacts on the resource mix in the Western Interconnection.

6. Agreeing on coal resources to retire in the coal retirement study case required extensive discussions with stakeholders. And, the CO2 reduction produced by the study case fell short of the target for the interim goal identified in the EPA’s Clean Power Plan. Considering the challenges in reaching agreement among stakeholders to identify coal-fired units to retire for this study case, i2.0t may be challenging to identify sufficient coal-fired units to retire if states pursue coal retirements as a primary way to comply with the Clean Power Plan.

3.2 20-Year Capital Expansion Studies

The starting point for 20-year capital expansion studies is the 2034 Reference Case, which is based on the 2024 Common Case. Parameters used in the 2034 Reference Case are based on values developed for the Common Case and assumptions used for the Common Case are extended an additional 10 years. In most cases, data sources for the Common Case and the Reference Case are the same, one exception being that loads used in the Reference Case were developed using the Forecast Manager System (FMS), while load in the Common Case were based on load forecasts submitted by Balancing Areas.

8 LCOE is the per-kilowatt hour cost (in real dollars) of building and operating a power plant over an assumed financial life and duty cycle.



3.2.1 Model Enhancements

During 2015, WECC continued enhancements to the Long-Term Planning Tool (LTPT), the model used to complete capital expansion studies in the 20-year planning horizon. Enhancements in progress during 2015 include:

Creating a Transmission Corridor Library to correlate corridors with transmission technology types and study cases;

Quantifying data driven goals and constraints to provide modeling flexibility and extensibility. Goals provide information such as amounts of flexible generation and reliability generation. Modeling constraints include information such as water availability constraints, carbon emission constraints, and fuel constraints;

Co-optimizing generation and transmission expansion into a single solution across multiple load duration blocks. The co-optimization addresses probable load duration blocks for heavy and light loads across the four seasonal periods, a loss-of-load severity measure and cost minimization;

Creating an optimization hierarchy to guide generator re-dispatch. This hierarchy allow grouping of re-dispatchable units into priority tiers; and

Creating a network reduction model to reduce the number of busses from about 20,000 throughout the Western Interconnection to less than 200 while still maintaining the critical functionality of the model. This reduction greatly reduces the runtime of the LTPT from days to hours, thus improving the efficiency of completing 20-year studies.

While WECC was able to make significant progress in developing these enhancements, they were not all complete as of December, 2015. As a result, WECC was not able to complete the 2034 Reference Case or complete capital expansion study cases based on the Reference Case. Pending study cases include the scenario-based study cases and the high coal retirement case.

3.2.2 20-Year Study Cases

The 2015 TEPPC Study Program included seven 20-year study cases: one for each of the original four WECC Scenarios, and one each for the Energy-Water Climate Change Scenario, the Coal Retirement Study Case and the High Renewables Study Case. Because the 2034 Reference Case was not completed in 2015, the 20-year cases based on the 2034 Reference Case also were not completed in 2015. WECC will consider these study cases in developing the 2016 TEPPC Study Program.

3.3 Cost Analyses

The role of generation and transmission capital costs is quite different in the capital expansion model (LTPT) than in the Production Cost Model. The starting point generation portfolio and transmission topology are determined exogenously for use in the LTPT.



WECC staff, with assistance from stakeholders, develops assumptions for a 10-Year Common Case, as well as a number of change cases that alter some of these assumptions. In this context, the inclusion of resource capital costs in WECC’s 10-Year studies allows for a more complete quantification of the relative costs of each change case relative to the Common Case or other Base Case used for reference. By accounting for the differences in fixed and variable costs between the cases, a complete picture of each change case can be drawn.

The role of capital costs in the 20-year studies (using the LTPT) is quite different. In this process, the Study Case Development Tool (SCDT) and the Network Expansion Tool (NXT)—together, the Long-Term Planning Tool (LTPT)—optimize the electric sector’s expansion subject to a large number of constraints to minimize the cost of delivered energy in 2034. Costs are a key input to the tool. Combined fixed and variable costs (more specifically levelized costs) are the objective function for determining potential generation and transmission additions that will minimize levelized costs.

The transmission capital cost estimates calculated for the 2024 transmission expansion projects were also drawn from WECC’s capital cost tool, and are estimates based on line mileage by jurisdiction for a range of voltage options. Cost estimates include rights-of-way, transmission towers and conductors and line termination facilities within existing substations or new substations where applicable. The annual levelized fixed cost calculation emulates the revenue requirement calculations used in utility rate cases (e.g., recognizing investment, O&M expense, depreciation, cost of capital, capital structure) and assumes a 40-year amortization (i.e., cost recovery) period.

The capital cost tool provides an estimate for substation and termination costs which can be used directly to calculate the total annualized transmission cost estimate. TEPPC uses the results from these tools to develop recommendations and observations for decision makers.

3.4 Regional Analyses

In response to the FERC order 1000 planning requirements, the four Regional Planning Groups (RPGs) have initiated independent regional planning processes and are also attempting to implement an “Inter-Regional Coordination” process as part of their planning efforts. Key discussion issues in 2015 across the inter-regional coordination included:

• Aligning criteria for selecting proposed inter-regional transmission projects forcost-allocation of selected projects

• Data-sharing protocols between project developers and planning entities

• Coordination on public policy considerations across Regional Planning Groups

• Identifying data needs and relevant information from WECC’s Base Case and Common Case processes


http://www.ferc.gov/industries/electric/indus-act/trans-plan.asp


The Regional Planning Groups in each of the four 2015 TEPPC meetings have in different ways confirmed the need and relevance of using WECC’s data sets (Base Case and Common Case data sets).

3.5 Base Case request submitted to WECC

On January 30, 2015, four planning Regions (Northern Tier Transmission Group, ColumbiaGrid, the California ISO and WestConnect) collectively submitted a request to WECC asking that it include a ten-year, light load case in WECC’s 2015 Annual Study Program. The Planning Coordination Committee (PCC) and Transmission Expansion Planning Policy Committee (TEPPC) supported the request using the TEPPC “placeholder” slot in WECC’s Study Program. WestConnect agreed to take the lead on providing the case description to WECC. The Base Case request reflects light spring loading conditions and wind generation resources operating at 30% of nameplate ratings. WECC is currently in the process of completing this request. The Base Case requested by the four planning regions is also intended to represent renewable resource requirements based on currently-enacted public policy requirements, such as renewable portfolio standards. The requested Base Case will also be used in regional analyses in the next regional planning cycle set to commence in 2016, and assist the Regional Planning Groups in evaluating future high renewable penetration scenarios.

3.5 Probabilistic Assessments

Probabilistic studies are ways of looking at multiple future scenarios to determine the range of possibilities that may occur due to variances from the expected scenario. These variances include, but are not limited to, events such as unplanned outages among all different types of generating resources and transmission lines, changes in technology, weather, or even forecast uncertainty, and the correlation amongst variables when one variable changes. This approach differs from the standard deterministic approach that tends to produce one scenario as a base, derived by user defined assumptions, that is then compared to another deterministic scenario when studying the impact of changing one variable. The probabilistic approach can use the variation around loads and resources to create multiple study cases to be analyzed with the deterministic (production cost) model.. This approach may provide a more comprehensive understanding of sensitivities around one or more variables.

To consider a probabilistic planning focus, a two-step phased approach is needed:

Phase 1 – Develop the distributions or “ranges” for the load forecast of each area as well as for the generation capability of each resource within the Western Interconnection.

Phase 2 – Apply the distributions to all planning forecasts used within WECC’s analytical models.

In 2015, WECC completed phase 1 by developing the probability distributions for each hour for loads and resources in the Western Interconnection (WI) based on historical data. While it is unlikely that



loads and resources will actually vary according to these distributions, they are now ready for phase 2 of the analysis which is expected to occur in 2016. This work is expected to improve the analytical work being conducted across many organizations at WECC. Applying these distributions to the base forecasts will allow for a more comprehensive look at what the impacts may be across an entire range of possibilities when an impact study is conducted. Instead of being limited to reporting the impact of a study case based on a single base forecast, WECC will be able to report impacts across a range of base forecasts that will encompass almost 100% of future possibilities.

At the conclusion of phase 1, WECC had sufficient information to perform loss-of-load probability (LOLP) studies which are also based on a probabilistic approach. Consistent with how WECC models loads and resources, the monthly peak and energy data provided by each of the WI BAs were turned into an hourly forecast. . The load distributions were compared to the resource distributions in each area to determine the LOLP if each BA was islanded from the rest of the interconnection for each hour of the 2016 forecast. This analysis determined a bookend and highlighted the extreme LOLP with no benefit from import capabilities.

Next, WECC determined the level at which each area’s Planning Reserve Margin would cross an LOLP of a 1-in-10-year level of LOLP. This allows WECC to study areas with higher reserve margins needed to maintain this threshold as vulnerability areas. The higher margins are due to more volatility with either the resources or the load which may vary across regions as well as time of the year and even day. Figure 16 below shows an example of the output from the probabilistic study for one of the Balancing Authorities in the Western Interconnection. The results analyze the loss of load probability associated with different levels of planning reserve margins for each quarter of the study year.

Figure 16: LOLP as a Function of Reserve Margin

This study will be conducted each year as new data is acquired to maintain an understanding of where the reliability challenges may be in the WI when it comes to resource adequacy. A report is currently being written to highlight the findings of this study.



4. Reliability Issues

4.1 Western Interconnection Flexibility Assessment

Given a landscape of increasing renewable policy targets and declining renewable costs in the Western Interconnection, interest in renewable generation and understanding its impacts on system operations has surged in recent years. Regulators, utilities, and policymakers have begun to confront the question of how much “flexibility” is needed to operate a system with high penetrations of renewable generation. Increasing amounts of intermittent resources introduce significant new challenges for power system operators.

WECC, in its role as the Regional Entity responsible for reliability in the Western Interconnection, is interested in understanding the long-term adequacy of the interconnected western grid to meet the operational challenges posed by renewable resources such as wind and solar generation across a range of plausible levels of penetration. WECC stakeholders have expressed a similar interest through study requests examining high renewable futures that implicate operational and flexibility concerns. The Western Interstate Energy Board (WIEB) is interested in understanding these issues in order to inform policymakers about the implications of potential future policies targeting higher renewable penetrations.

With this motivation, WECC and WIEB collaborated to jointly sponsor the WECC Flexibility Assessment. The sponsors engaged Energy + Environmental Economics (E3) to complete the analytical work for the study and present its results to WECC, WIEB and their stakeholders. The sponsors established three goals for this effort:

1. Assess the ability of the fleet of resources in the Western Interconnection to accommodate high renewable penetrations while maintaining reliable operations. Higher penetrations of renewable generation will test the flexibility of the electric systems of the West by requiring individual power plants to operate in fundamentally new ways and changing the dynamics of wholesale power markets. This study aimed to identify the major changes in operational patterns that may occur at such high penetrations and to measure the magnitude and frequency of possible challenges that may result.

2. Investigate potential enabling strategies to facilitate renewable integration that consider both institutional and physical constraints on the Western system. Existing literature has identified a wide range of possible strategies that may facilitate the integration of high penetrations of renewables into the Western Interconnection. These strategies comprise both institutional changes—increased use of curtailment as an operational strategy and greater regional coordination in planning and operations—as well as physical changes—such as new investments in flexible generating resources and the development of novel demand-side


https://www.wecc.org/Reliability/WECC_Flexibility_Assessment_Report_2016-01-11.pdf


programs. This study examines how such strategies can solve the challenge to future increases in the penetration of renewable generation.

3. Provide lessons for future study of system flexibility. Future studies could consider the relative importance of various operational and mitigation approaches. The study of flexibility and its need at high renewable penetrations is an evolving field. This effort is designed with an explicit goal of providing useful information to modelers and technical analysts to improve analytical capabilities for further investigation.

E3’s analysis explored these issues by examining two study cases in detail: the 2024 Common Case and a “High Renewables Case” (PC22).

4.1.1 Study Implications

The technical findings and conclusions reached through this study have a number of implications that are relevant for regulators and policymakers seeking to enable higher penetrations of renewable generation on the system and to address the associated challenges.

1. Operating an electric system reliably at high renewable penetrations is technically feasible. In both the Common Case and the High Renewables Case, the flexibility assessment demonstrates that each region’s electric system is capable of serving loads across a diverse range of system conditions. Further, no “need” for additional flexible capacity beyond existing and planned resources is identified in either case.

2. While both the Common Case and the High Renewables Case demonstrate adequate flexibility to meet loads across all conditions, a significant challenge distinguishes the high penetration scenarios examined: the frequent curtailment of renewable resources. At relatively low penetrations, renewable generation can be integrated into the system with limited need to curtail; however, once a region’s penetration surpasses a certain threshold, curtailment begins to appear in simulations. Renewable curtailment serves as an indicator that a system is unable to absorb all the available renewable generation and is characteristic of all of the High Renewables scenarios investigated: Figure 17: Renewable Curtailment Frequency in High Renewable Case summarizes the range of curtailment frequency across all of these scenarios.



Figure 17: Renewable Curtailment Frequency in High Renewable Case

3. Ensuring that the proper signals exist to enable routine economic curtailment is a fundamental necessity for achieving high penetrations. Renewable curtailment serves as the relief valve that allows the system to operate reliably in spite of the increased demand for flexibility that renewable generation imposes on the system. Ensuring that curtailment is available and can be used efficiently in day-to-day operations requires a number of steps:

a. Market structures and scheduling processes must be organized to allow renewable participation in short-term markets. Within organized deregulated markets, this means ensuring that utilities can submit bids into the market on behalf of renewable generators that reflect the opportunity cost of curtailing these resources as well as ensuring that renewable plants are not excessively penalized for deviations from their schedules due to forecast errors. In environments in which vertically integrated utilities or another type of scheduling coordinator is responsible for determining system dispatch, the operator must begin to consider the role of renewable curtailment in scheduling and dispatch decisions for both renewable and conventional resources.

b. Contracts between utilities and renewable facilities must be structured to allow for economic curtailment. Historically, many power purchase agreements have been set up to pay renewables for the generation that they produce and have included provisions limiting curtailment under the premise that limiting risk and ensuring an adequate revenue stream to the project are necessary to secure reasonable financing; “Compensated curtailment,” under which developers are paid a Power Purchase Agreement (PPA) price both for generation that is delivered to the system as well for estimated generation that is curtailed, would be one means of achieving this goal.



However, the tradeoff between reduced renewable financing costs and the costs consumers incur to pay for energy that is not produced, must be assessed.

c. Operators must fully understand the conditions and circumstances under which renewable curtailment is necessary. In some instances—namely, in oversupply conditions—the need to curtail is relatively intuitive; however, in other instances, the important role of curtailment may not be so obvious. For example, an operator faced with a choice between keeping a specific coal unit on-line and curtailing renewables or decommitting that coal unit to allow additional renewable generation should make that decision with knowledge of the confidence in the net load forecast as well as an understanding of the consequences of possible forecast errors. Similarly, an operator anticipating a large upward net load ramp may decide to curtail renewable generation prospectively to spread the ramp across a longer duration if the ramp rates of conventional dispatchable units are limited. Additional work is necessary to identify such operating practices and conditions in which renewable curtailment may be necessary outside of oversupply conditions to ensure reliable service.

While renewable curtailment is identified as the predominant challenge in operations at high renewable penetrations, its magnitude can be mitigated through efficient coordination of operations throughout the Western Interconnection. Today’s balkanized operations may act as an institutional barrier to efficient renewable integration. By allowing full utilization of the natural diversity of loads and resources throughout the Western Interconnection, regional coordination offers low-hanging fruit to mitigate integration challenges. A number of studies have identified the significant operational benefits that can be achieved through Balancing Authority consolidation, a conclusion that is supported by the reduction in renewable curtailment at high penetrations identified in this study.

In addition to pursuing institutional solutions to renewable integration, entities within the Western Interconnection should create an organized decision-making framework through which appropriate procurement and investment decisions may be made. Routine economic curtailment implies a wholesale market in which the cost of energy is zero or negative throughout significant portions of the year—in many regions, a radical change from historical patterns in which the avoided cost of thermal generation has established the short-term value of energy. It also underscores the need for the establishment of an economic framework through which investments in new flexible resources or demand-side programs can be evaluated and ultimately justified. This idea is illustrated in Figure 18: Costs of Renewable Curtailment, which shows a conceptual tradeoff between the costs of renewable curtailment with the costs of measures undertaken to avoid it. Renewable curtailment, as a default solution to renewable integration challenges, serves as an “avoided cost” of flexibility.



Figure 18: Costs of Renewable Curtailment

Renewable curtailment imposes a cost upon ratepayers, reflected in this study by the idea of the “replacement cost,” and, to the extent it can be reduced through investments in flexibility, its avoidance provides benefits to ratepayers. At the same time, designing and investing in an electric system that is capable of delivering all renewable generation to loads at high penetrations is, itself, cost-prohibitive. Between these two extremes is a point at which the costs of some new investments or programs that provide flexibility may be justified by the curtailment they avoid, but the cost of further investments would exceed the benefits.

While not performed in the context of this study, this type of economic evaluation of flexibility solutions to support renewables integration will depend on rigorous modeling of system operations combined with accurate representation of the costs and non-operational benefits of various solutions. This study provides both an example of the type of analytical exercise that could be performed to quantify the operational benefits of flexibility solutions as well as a survey of the analytical considerations and tradeoffs that must be made in undertaking such an exercise. The specific types of investments to enable renewable integration that are found necessary will vary from one jurisdiction to the next, but the overarching framework through which those necessary investments are identified may be consistent.

4.2 Energy-Water-Climate Change Nexus

In June, 2014 WECC introduced its new Integrated Reliability Assurance Model, which outlines the process through which WECC will identify, analyze, and address the top reliability challenges facing the Western Interconnection. One of the identified challenges is the impacts of climate changes. Climates are constantly changing at both the global and more granular levels. Two key questions for WECC to consider are:



1. In addition to increased average global temperature, what changes to the environment, might occur as a result of global climate changes?

2. Would these climate changes impact the electrical reliability of the Western Interconnection?

Changes to climactic conditions have the potential to cause electric system impacts in the Western Interconnection in a number of ways, specifically, with higher temperatures, drought and extreme weather. If not mitigated through normal and potential event-focused planning and operating practices, these system impacts could pose significant risks to the reliability of the electric grid in the Western Interconnection. WECC has a keen interest in identifying and addressing reliability risks that could arise in the 20-year planning horizon. While implementing mitigation measures is beyond the scope of WECC’s responsibilities, the results of this scenario planning effort could lead to possible mitigation measures to be explored further by other organizations.

The Scenario Planning Steering Group (SPSG), under the guidance of its consultant, the Quantum Planning Group, lead an initiative in 2014 and 2015 to describe a plausible future in 2034 in which climate changes are characterized by a 3°F average global temperature rise (relative to the average value for 1960 to 1979). This included exploring the nexus between electricity and water. While electric and water utility services are different, they are related in that electric service providers use, transform and consume significant amounts of water and water service providers use significant amounts of electricity. The complete report on this scenario planning effort is posted on the WECC web site.

The second step in this process was to identify potential impacts to the electric system from the changing climate. During 2015, WECC engaged Energy + Environmental Economics (E3) to analyze in greater detail potential impacts of climate changes on the transmission system in the Western Interconnection. A preliminary report on the study is posted on the WECC web site.

While additional work is needed to fully address potential reliability risks related to changes to the climate, scenario planning work during 2015 identified several categories of risk that could be explored further:

Identifying climate change-related electric system impacts that could evolve into reliability risks;

Prioritizing potential reliability risks;

Preemptively and selectively hardening transmission and generation assets;

Improving the effectiveness and efficiency of responses to system impact events;

Increasing collaboration between electric and water utility managers; and


https://www.wecc.org/Administrative/06%20-%20Potential%20Climate%20Change%20Impacts-Kahrl.pdf



Improving overall coordination between electric industry representatives; water system managers; federal, state and local governments; tribes and First Nations; and non-governmental organizations.

Future steps in this analysis include:

1. Exploring the interactive impacts of the nexus between energy and water by defining one or more study cases for analysis (2016);

2. Identifying potential risks to the reliability of the Bulk Electric System in the Western Interconnection as a result of changes to the climate (2016-17); and

3. Suggesting possible mitigation measures that could be considered to address identified reliability risks (2016-17).

4.3 Clean Power Plan

The EPA’s Clean Power Plan has the potential to dramatically reshape the Bulk Electric System’s (BES) resource mix over the next 15 years and raises a significant number of potential reliability concerns for the Western Interconnection. Implementation options included in the CPP could well lead to more renewable generation, more gas and less coal generation and a significant change to the way power flows across the Western Interconnection. This may create new vulnerabilities for the Interconnection in terms of challenges to the adequacy of resources and transmission and the reliable functioning of the high-voltage grid.

A preliminary study completed by WECC in 2014 determined that in general, compliance with the “Proposed” CPP rules was within reach if states explore inter-state strategies for greenhouse gas reductions. However, based on the final CPP rule, further reliability assessments would be needed to assess any potential increases or decreases to reliability risks for the Interconnection, e.g., potential challenges to the adequacy of resources and transmission and the reliable functioning of the high-voltage grid.

The West is reliant on a coordinated Bulk Electric System as energy flows across state borders on transmission lines that span hundreds of miles. Since WECC does not operate, site, or own generation or transmission infrastructure, it has no direct economic interest in how states comply with the EPA’s proposed Clean Power Plan. However, WECC expects to have an ongoing role in assisting planning regions and states, as the implementation plans that states will develop to comply with the proposed Clean Power Plan will drive BES changes that must be assessed to assure continued reliable operation of the Western Interconnection.

4.3.1 Regional Engagement

Subsequent to the EPA publishing the final CPP rule in August 2015, WECC initiated efforts to discuss how it can assist the Western stakeholder community in helping assess the reliability considerations of


http://www.epa.gov/cleanpowerplan


the resultant implementation plans. In addition to submitting formal comments to the EPA in November 2014, WECC has communicated its analytical activities by participating in several meetings during 2015, including:

• FERC technical forums at its Western Regional Technical Conference in March 2015;

• Summer meetings of the National Association of Regulatory Utility Commissioners (NARUC) and the Environmental Committee for NARUC; and

• Western Interstate Regional Advisory Board’s (WIRAB) annual fall meeting.

Finally, WECC hosted four distinguished panelists—Joe Goffman (EPA), Travis Kavulla (NARUC/Montana PSC), Bill Ritter, Jr. (Center for the New Energy Economy), and John Savage (WIRAB/Oregon PUC)—at the December meeting of WECC’s Board of Directors to discuss their views on how WECC can be instrumental in assuring reliability throughout the Western Interconnection as it is transformed by states’ implementation of CPP plans. Each of the panelists expressed interest in seeing WECC play some role in a Western Interconnection-wide assessment of reliability issues around the Clean Power Plan.

4.3.2 Internal Efforts

WECC is currently evaluating existing skillsets and in-house tools, and has formed a cross-functional team to look at how various dimensions of reliability (resource and system adequacy, system stability and gas-electric interface) may be impacted by CPP implementation. The cross functional team is comprised of members from WECC’s Reliability Planning, Performance Analysis, System Adequacy and Operational Planning departments.

During the summer of 2015, WECC also participated with WIEB to validate WECC’s capabilities to assess the reliability challenges of implementing the CPP through a “mock assessment” of future aggregated compliance plans. While this analysis of CPP implementation was only for internal assessment of tools and data needs, WECC remains committed to continually tracking any and all federal and state efforts to comply with the CPP and related reliability considerations.

4.4 Planning for Uncertainty

4.4.1 Background

The WECC 2013 Transmission Plan (Plan) recommended that WECC Staff evaluate the role of uncertainty in future transmission planning studies. The Plan recommended that WECC:

Include uncertainty in planning studies, especially beyond 2020;

Assess operational and infrastructure investment approaches to providing operational flexibility;

Further quantify and bound long-run uncertainties; and


https://www.wecc.org/_layouts/15/WopiFrame.aspx?sourcedoc=/Reliability/131009-2013Plan-ThePlan-Final-v6.pdf&action=default&DefaultItemOpen=1

https://www.wecc.org/Reliability/141125_EPAComments_WECC.pdf


Acknowledge uncertainty around construction of transmission projects assumed to be completed in the 10-year planning horizon.

In response to these recommendations, WECC partnered with the U.S. Department of Energy’s (USDOE) Lawrence Berkley National Laboratory (LBNL) to jointly seek USDOE American Recovery Reinvestment Act (ARRA) funds in 2013 to assess the implications of including uncertainty in transmission planning. WECC and LBNL partnered with Johns Hopkins University (JHU) and a Technical Advisory Committee (comprised of TEPPC members) to successfully complete an innovative study that tested the inclusion of uncertainty variables in a deterministic and stochastic setting. The following sub-sections summarize the focus, methodology, approach and results.

4.4.2 Study Focus

The John Hopkins University (JHU)-based team quantified the benefit of including uncertainty in the form of multiple scenarios over a multi-decadal time horizon, while explicitly representing the information available at different decision points. The study recognized two investment decision stages:

1. “Here and now” (first stage decisions that are made without knowing which of the scenarios will turn out to be the case); and

2. “Wait-and-see” (later investments that are made after the scenario is known, enabling the planner to adapt the system to the realized conditions).

In the modeling framework, these corresponded to the year 10 and year 20 phases of the WECC Transmission Expansion Planning Policy Committee (TEPPC) planning process. This two-stage decision framework (called “stochastic programming” or “mathematical programming with recourse”) is widely used in engineering and business and applications including generation investment planning and academic research involving power network planning. The two-stage stochastic programming model for transmission planning was called JHSMINE (Johns Hopkins Stochastic Multistage Integrated Network Expansion). Compared to stochastic approaches that have been proposed previously, the modeling was conducted under more realistic conditions with the collaboration of planners and analysts from WECC, using data bases of generation, loads, and networks from the 2013 TEPPC plan.

The key focuses of this study were:

• How would transmission planning recommendations differ between the stochastic and deterministic models? and

• What economic benefits can be obtained by following the stochastic recommendations?

4.4.3 Methodology

The methodology used a co-optimization model that included commitments to investment – transmission and generation – with the first set of investments in 2014 (first stage, with an in-service



date of 2024) and 2024 (second stage, in service in 2034). Figure 19: Co-Optimization of Transmission and Generation Investments reflects the logic for a transmission planner anticipating how the location and types of generation investment respond to network availability. Decisions about system operations (generation dispatch and line flows) are made in 2024 (first stage) and 2034 (second stage), with the second stage operating decisions continuing for additional decades after 2034. The CCTA lines (year 10 lines that the 2013 WECC Plan recommends) were assumed to be built in every solution; the model also recommended additional year 10 lines that appear to be economically attractive by 2024.

Figure 19: Co-Optimization of Transmission and Generation Investments

To implement this decision tree of two-state transmission-generation-optimization sequence, the following key assumptions were used so as to reflect an economic equilibrium:

• Short-run generation markets were cleared by competitive generation companies that optimize their generation schedules against locational marginal prices (LMPs), and there are no barriers to trade among regions aside from physical transmission capacity.

Long-run generation investment decisions were made by maximizing the probability-weighted present worth of short-run gross margins (based on LMPs) minus investment costs.

The transmission operator and owner invest in grid-expansion to maximize the probability-weighted net social welfare (sum of surpluses in the market) and in the short-run operates the



grid to maximize the value to the market provided by transmission (equivalent to maximizing transmission surplus, with price taking assumptions for LMPs).

• All generators are price-takers, and all market parties are risk neutral; all have the same interest rate (5%/year real), and have the same expectations concerning the probability distributions of long-run scenarios and short-run load, wind, and solar conditions.

The study incorporated the basic JHSMINE model structure with two versions of the model: a 21-zone and 300-bus versions of the WECC system that were compared in order to assess the computational effort required for more detailed models and the effects of assuming a more disaggregated network upon the results. The 21-zone model assumed a “pipes-and-bubbles” load flow, as does one version of the 300-bus model. In addition, the study applied a 300-bus model that enforces Kirchhoff’s current and voltage laws, thus representing the physics of power flow more accurately. The result is that power flows over all parallel paths between sources and sinks, and congestion is generally greater than in the “pipes-and-bubbles” formulation, which only enforces Kirchhoff’s current law. In all models, transmission capacity limits were enforced in alignment with official WECC paths between the regions of the model.

4.4.4 Scenarios and Deterministic vs. Probabilistic Approach to Modeling

With the collaboration of a project technical advisory committee consisting of WECC stakeholders, 20 scenarios were considered in the stochastic planning model. These were derived by various combinations of uncertain variables that were identified by the stakeholders as potentially important uncertainties in the 2020’s and 2030’s. Table 6: 90% Confidence Values of 2024 Scenario Variables shows the assumed values of the variables in 2024.

The study quantified the economic value of identifying near-term transmission investments by stochastic planning by comparing the cost performance of the first stage (year 10) investments derived with versions of JHSMINE that consider 1, 5 or 20 scenarios (Figure 20: Consideration of 1, 5 or 20 Scenarios), as follows:

• “Deterministic Planning” (20 plans examined) • “Deterministic Heuristics” (3 approaches) • “Stochastic (5)” (1 approach)

• “Stochastic (20)” (1 approach)

These plans were then compared for their expected performance. This is done by inserting the values of the first stage (year 10) decisions that represent values of the transmission investments installed by 2024 into the 20 scenario stochastic model. All other variables (including the 2024 and 2034 generation investments, and the 2034 transmission investments) are allowed to take on their optimal values. This means that, first, generators invest anticipating the “actual” distribution of 20 scenarios,



and second, the transmission owner makes optimal decisions in the 2nd stage when it knows what scenario is realized.

The economic benefit of using stochastic programming to make near-term transmission investments was then obtained by comparing the present worth of expected costs of (a) the naïve solution in which the 20-scenario stochastic program is solved while imposing the first stage transmission decisions from one of the sub-optimal models (Deterministic, Heuristic, or Stochastic(5)) with (b) the expected costs of the unconstrained 20 scenario model, which can be no worse than the value in (a). This difference was called the “value of the stochastic solution” in stochastic programming, or also called the “cost of ignoring uncertainty.”

By comparing the values of (a) for different solutions, the accuracy of heuristic strategies were compared. Furthermore, a comparison of Stochastic (5) solution performance with the other solutions was undertaken to determine if a model that includes multiple scenarios, but only a small subset of them, does almost as well as the fully optimal Stochastic (20) solution. The results validated this. Twenty scenarios based on various combinations of the variables are considered in the analyses. Table 6 depicts the variables used to define the scenarios.

Table 6: 90% Confidence Values of 2024 Scenario Variables

Variables Low Value High Value

Capital Cost

Onshore Wind ($/kW) 1,569 2,065

Offshore Wind ($/kW) 4,369 6,106

Geothermal ($/kW) 5,015 6,490

Solar PV—Residential Rooftop ($/kW) 2,855 5,209

Solar PV—Commercial Rooftop ($/kW) 2,320 4,233

Solar PV—Fixed Tilt, 1-20 MW ($/kW) 2,048 3,736

Solar Thermal, No Storage ($/kW) 3,560 4,519

Solar Thermal, 6-hour Storage ($/kW) 5,178 6,572

Integrated Gasification Combined Cycle (IGCC) with Carbon Capture and Sequestration (CCS) ($/kW)

7,600 10,000

Fuel & Carbon Prices

Natural Gas ($/MMBtu) 3.86 14.50

Carbon ($/Ton) 25.9 87.5



Variables Low Value High Value

Coal ($/MMBtu) 2.24 3.50

Net Energy for Load

DG Capacity as % of Peak Demand (%) 3.2 20.0

DR Capacity as % of Peak Demand (%) 2.2 10.0

Storage Capacity as % of Peak Demand (%)

3.9 10.7

Total WECC Load Growth (%/year) 1.0 1.9

Energy Reductions (%/year) 0.3 4.0

Electrification (%/year) 0.3 1.8

Figure 20: Consideration of 1, 5 or 20 Scenarios



4.4.5 Results and Recommendations

Using the stochastic planning models for the 21-zone or 300-bus models of the WECC system under multiple scenarios was computationally practicable. Considering more than one scenario simultaneously in a planning model resulted in distinctly different plans than when evaluating multiple scenarios separately. The reduction in probability-weighted cost that would result from implementing the stochastic model’s recommendations was on the same order of magnitude as the size of the first stage (year 10) investment. JHU research team recommended that WECC consider implementation of a stochastic model as part of its next planning cycle in order to build confidence that near term (year 10) transmission reinforcements will reflect uncertainty effectively.

Adaptability and robustness is best assessed with a model that recognizes that some line additions will be more effective in poising the system to accommodate future changes in fuel costs, loads, technologies and policies. Such a model must consider multiple possible futures at once and how a system can adapt to them over multiple decades. Finally, because the generation siting responds to transmission availability, a co-optimization formulation is ideal to use as a methodology so as to capture savings in generation capital costs as well as expenses due to transmission additions.

4.4.6 Implications for WECC’s Planning Activities

Based on the results of the JHU study, WECC should consider augmenting its future planning activities in the following ways:

Identify ways in which future WECC studies consider stochastic scenarios to be used in developing transmission assumptions that reflect risk and uncertainty conditions.

Test a WECC study case using the 10-year production cost model under differing assumptions - stochastic framework and currently used deterministic platform – to see if there is a significant difference in how security constrained dispatch of resources and transmission investments take place.

Explore ways for the CCTA 2028 process to include a probabilistic planning framework to better reflect uncertainty in transmission planning.

4.5 Planning Tool Alignment

One of the challenges WECC and its stakeholders have faced in analyzing planning issues is inconsistencies between data used in planning models. In a perfect world, data used as inputs to planning models and produced as outputs from planning models would be interchangeable, regardless of the model being used. In practice, this is not the case. As an example, resource data used in a Base Case to produce a power flow cannot be used in a production cost model without modifications and adjustments. Likewise, outputs from a production cost model cannot be used as inputs to a power flow model without significant modifications.



In 2015, WECC began the “Round Trip Process” to reduce these data inconsistencies and facilitate easier data interchange between planning models. The first deliverable, the ability to extract one or more hours of output from WECC’s production cost model and use the data with minimal modifications to run a power flow analysis—is targeted for completion in the First Quarter of 2016. Future enhancements of this capability would continue through 2016. The ultimate goal of a single planning model data base that is usable by any planning model will require longer to complete, but is a priority for WECC.

4.6 NERC/WECC Reliability Assessments

WECC is one of the eight North American Reliability Corporation (NERC) Regional Entities that provide reliability assessment information to NERC for inclusion in its summer and winter seasonal assess-ments, and its annual Long-Term Reliability Assessments (10-year).9 These assessments focus on re-source adequacy and are introduced to this report as a component of WECC’s Integrated Transmission and Resource Assessment. In addition to the NERC assessments, WECC prepares annual Power Supply Assessments (PSA) that are associated with, but independent from and more detailed than, the NERC Long-Term Reliability Assessments.10 The WECC and NERC assessments are based on the concept of comparing expected reserve margins against base planning margins (BPMs), which provides a simple yes/no resource adequacy result. If the expected margins exceed the base planning margins, resources are deemed to be adequate. WECC’s most recent PSA document indicates an expectation of resource adequacy throughout the 2016-2025 timeframe.11

The load and resource data used in the assessments are provided by the 38 balancing authorities within the Western Interconnection. The Balancing Authority data are aggregated into 19 load and generation zones to reflect inter-area transfer limitations. The data for these 19 zones are further ag-gregated into four subregions—the Northwest Power Pool (NWPP); the Rocky Mountain Reserve Group (RMRG); the Southwest Reserve Sharing Group (SRSG); and California/Mexico (CA/MX)—to re-flect seasonal load patterns and resource type differences, and to maintain load forecast data confi-dentiality.

9 NERC Reliability Assessments10 WECC Reliability Assessments11 The reader should note caveats presented at the end of this section of the report.


https://www.wecc.org/ReliabilityAssessment/Pages/Default.aspx

http://www.nerc.com/pa/RAPA/ra/Pages/default.aspx


Figure 21: Western Interconnection Balancing Authorities



Figure 22: Western Interconnection Subregions

Table 7: Resource Class Descriptions

Resource Class Description

Existing Generation Generation that is available (in-service) as of December 31, 2014

New Generation Generation that will be added in the future

Class 1 Generation additions/retirements that were reported to be under active construction as of the reporting date of December 31, 2014 and are projected to be in-service/retired prior to January 2020. Class 1 also includes facilities or units that have a firm retirement date within the assessment period12 as a result of regulatory requirements or corporate decisions.

Class 2 Generation additions/retirements that were reported to have:

received regulatory approval or are to undergo regulatory review;

a signed interconnection agreement; or

an expected on-line/retirement date prior to January 2022.

This class includes resources that were expected to be in-service as early as Class 1 resources, but did not meet the test of being under construction; or

12 The assessment period is from 2016 through 2025 for summer and from 2016/17 through 2025/26 for winter.



Resource Class Description

have an estimated retirement date within the assessment period.

Class 3 Generation additions/retirements that were reported and met the North American Electric Reliability Corporation (NERC) criteria for Tier 213 but do not qualify as WECC Class 1 or 2 resources.

Class 4 Generation additions/retirements that were reported and met the NERC criteria for Tier 3.14

The following graphics and tables present the peak-season margin information for each of the four as-sessment subregions. Explanations regarding the graphic/table abbreviations, etc., are presented fol-lowing the margin tabulations.

Figure 23: NWPP Case 1 through 4 Winter Results

2016 2017 2018 2019 2020 2021 2022 2023 2024 20250.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

35.0%

NWPP: Case 1 through 4 - Winter Results

Existing and Class 1Existing and Class 1 through 2Existing and Class 1 through 3Existing and Class 1 through 4BBM - Winter 16.1%

13 Definition included in the NERC Long-Term Reliability Assessment (LTRA): http://www.nerc.com/pa/RAPA/ra/Pages/default.aspx.14 Ibidem.


http://www.nerc.com/pa/RAPA/ra/Pages/default.aspx


Figure 24: RMRG Case 1 through 4 Summer Results

2016 2017 2018 2019 2020 2021 2022 2023 2024 20250.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

35.0%

40.0%

RMRG: Case 1 through 4 - Summer Results

Existing and Class 1Existing and Class 1 through 2Existing and Class 1 through 3Existing and Class 1 through 4BBM - Summer 13.9%

Figure 25: SRSG Case 1 through 4 Summer Results

2016 2017 2018 2019 2020 2021 2022 2023 2024 20250.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

35.0%

SRSG: Case 1 through 4 - Summer Results




Figure 26: CA/MX Case 1 through 4 Summer Results

2016 2017 2018 2019 2020 2021 2022 2023 2024 20250.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

35.0%

40.0%

CA/MX: Case 1 through 4 - Summer Results




Table 8: NWPP Case 1 Existing/Class 1 Resources Winter Results

2016 2017 2018 2019 2020 2021 2022 2023 2024 2025Net Internal Demand 71,145 72,526 73,668 74,851 75,588 76,401 77,294 77,985 78,703 79,402Anticipated Internal Capacity 92,108 91,870 90,675 91,162 91,838 88,929 89.788 90,560 91,416 92,211

Wind Expected On-Peak MW 3,464 3,501 3,501 3,501 3,501 3,501 3,501 3,501 3,501 3,501Percentage of Wind Capacity 28.5% 28.5% 28.5% 28.5% 28.5% 28.5% 28.5% 28.5% 28.5% 28.5%Solar Expected On-Peak MW 0 0 0 0 0 0 0 0 0 0Percentage of Solar Capacity 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%Hydro Expected On-Peak MW 34,360 34,380 34,392 34,404 34,404 34,404 34,404 34,404 34,404 34,404Percentage of Hydro Capacity 63.9% 63.9% 63.9% 63.9% 63.9% 63.9% 63.9% 63.9% 63.9% 63.9%

Imports 1,501 1,501 1,501 1,501 1,501 1,501 2,151 2,951 2,851 5,176Exports 0 0 0 0 0 0 0 0 0 0Anticipated Resource Reserve Margin MW 9,508 7,677 5,147 4,260 4,081 228 50 20 42 25Anticipated Resource Reserve Margin % 29.5% 26.7% 23.1% 21.8% 21.5% 16.4% 16.2% 16.1% 16.2% 16.1%

Table 9: RMRG: Case 1 – Existing/Class 1 Resources Summer Results

2016 2017 2018 2019 2020 2021 2022 2023 2024 2025Net Internal Demand 12,055 12,171 12,417 12,667 12,830 13,129 13,414 13,736 13,932 14,194Anticipated Internal Capacity 15,211 15,634 15,685 15,253 15,647 15,557 15,490 15,648 15,886 16,185

Wind Expected On-Peak MW 775 775 775 775 775 775 775 775 775 775Percentage of Wind Capacity 29.7% 29.7% 29.7% 29.7% 29.7% 29.7% 29.7% 29.7% 29.7% 29.7%Solar Expected On-Peak MW 52 52 52 52 52 52 52 52 52 52Percentage of Solar Capacity 42.8% 42.8% 42.8% 42.8% 42.8% 42.8% 42.8% 42.8% 42.8% 42.8%Hydro Expected On-Peak MW 1,303 1,303 1,303 1,303 1,303 1,303 1,303 1,303 1,303 1,303Percentage of Hydro Capacity 40.8% 40.8% 40.8% 40.8% 40.8% 40.8% 40.8% 40.8% 40.8% 40.8%

Imports 0 0 0 0 0 0 0 150 550 775Exports 575 575 575 575 575 575 575 575 575 575Anticipated Resource Reserve Margin MW 1,480 1,771 1,542 825 1,033 603 211 3 17 18



2016 2017 2018 2019 2020 2021 2022 2023 2024 2025Anticipated Resource Reserve Margin % 26.2% 28.5% 26.3% 20.4% 22.0% 18.5% 15.5% 13.9% 14.0% 14.0%

Table 10: SRSG: Case 1 – Existing/Class 1 Resources Summer Results


Wind Expected On-Peak MW 164 164 164 164 164 164 163 163 163 163Percentage of Wind Capacity 19.6% 19.6% 19.6% 19.6% 19.6% 19.6% 19.6% 19.6% 19.6% 19.6%Solar Expected On-Peak MW 382 382 382 382 382 382 382 382 382 382Percentage of Solar Capacity 35.9% 35.9% 35.9% 35.9% 35.9% 35.9% 35.9% 35.9% 35.9% 35.9%Hydro Expected On-Peak MW 733 733 733 733 733 733 733 733 733 733Percentage of Hydro Capacity 25.7% 25.7% 25.7% 25.7% 25.7% 25.7% 25.7% 25.7% 25.7% 25.7%

Imports 379 379 379 379 529 1,104 1,554 2,504 3,604 4,004Exports 3,601 3,601 3,601 3,601 3,601 3,601 3,601 3,601 3,601 3,601Anticipated Resource Reserve Margin MW 1,655 1,383 1,149 513 83 86 82 169 206 219Anticipated Resource Reserve Margin % 23.2% 22.0% 20.9% 18.2% 16.4% 16.4% 16.4% 16.7% 16.9% 16.9%

Table 11: CA/MX: Case 1 – Existing/Class 1 Resources Summer Results


Wind Expected On-Peak MW 3,553 3,553 3,553 3,725 3,725 3,725 3,725 3,725 3,725 3,725Percentage of Wind Capacity 36.1% 36.1% 36.1% 36.1% 36.1% 36.1% 36.1% 36.1% 36.1% 36.1%Solar Expected On-Peak MW 2,577 2,915 3,323 3,779 3,779 3,779 3,779 3,779 3,779 3,779Percentage of Solar Capacity 36.4% 36.4% 36.4% 36.4% 36.4% 36.4% 36.4% 36.4% 36.4% 36.4%Hydro Expected On-Peak MW 3,590 3,593 3,593 3,593 3,801 3,801 3,801 3,801 3,801 3,801Percentage of Hydro Capacity 31.2% 31.2% 31.2% 31.2% 31.5% 31.5% 31.5% 31.5% 31.5% 31.5%

Imports 2,746 2,746 2,746 2,746 2,746 2,746 2,746 2,746 2,746 2,746Exports 450 450 450 450 600 1,175 1,625 2,575 3,675 4,075



2016 2017 2018 2019 2020 2021 2022 2023 2024 2025Anticipated Resource Reserve Margin MW 3,707 5,754 6,229 7,137 6,434 5,567 4,509 3,371 2,647 1,839Anticipated Resource Reserve Margin % 22.0% 25.9% 26.7% 28.4% 27.0% 25.3% 23.3% 21.2% 19.9% 18.4%



4.6.1 Assessment Caveats

Among the important caveats that should be considered when reviewing these results are:

1. The analysis is based on Loads and Resources (LAR) data submitted in March 2015. The demand forecasts and reported resources for each BA were “locked” as of May 2015. New generation projects announced after the data were “locked” are not included in the resource totals.

2. WECC does not speculate which units may retire due to environmental requirements or financial considerations. Therefore, only generating units that were reported with a planned retirement date are incorporated in these studies.

3. Results of this assessment may differ from the results of similar assessments performed by other parties.

4. Case results are specific to the assumptions used for these studies. The use of different assumptions will produce different results.

5. Transmission constraints apply only between zones. All generation within a zone is deemed deliverable within the zone.

6. GridView is a production cost dispatch model. The model transfers energy in accordance with the distribution of loads and the relative variable operating costs of every resource on the grid, observing applicable constraints . Simultaneous flows, loop flows, and other transfer restrictions are approximated by the restricted transfer limits that were used in the studies, but the model is not a power flow model.

7. The GridView model allows WECC staff to capture the Western Interconnection coincidental peak demand. The model uses static hourly demand curves for each BA within WECC. These curves were created by averaging five years of actual hourly demand for each BA. GridView uses an algorithm with the amounts of monthly peak and energy supplied by each BA to modify these curves for each year of the study period. The algorithm “fixes” the monthly peak at the amount supplied by the BA and adjusts the curves up or down to match the demand under the curve to the annual energy reported. This process “flattens” the annual demand curve if the energy load growth rate exceeds the peak demand growth rate. The process also “peaks” the annual curve if the energy load growth rate is less than the peak demand growth rate.

8. For hydro plants in the Northwest and California, the model employs an algorithm that shapes the available hydro energy based on the shape of the area’s energy load. This means there can be hydro capacity that is unavailable because it is constrained by the available energy in the hydro system.



5. Recommendations

In 2013, WECC published the 2013 WECC Interconnection-wide Transmission Plan. That report included several recommendations based on analytic work completed from 2011 through 2013. Many of those recommendations are still valid and are reflected in the following sections. In some cases, WECC has expanded on previous recommendations or added new ones based on work completed during 2014 and 2015.

5.1 Priorities for Infrastructure

1. Uncertainties in Planning

When considering the likely future 10 years from now or a plausible future 20 years from now, there are significant uncertainties in loads, resources and transmission topology. Some factors could have significant impacts on loads, resources and transmission, notably natural gas prices, prices or penalties imposed on CO2 emissions and technology costs. Future planning studies should continue considering ranges of these factors as well as other variables that would be expected to affect the reliability of the Western Interconnection.

2. Expected Future Grid

The expected future grid, based on existing transmission plus the Common Case Transmission Assumptions, appears to be adequate for the Western Interconnection to meet its load requirements over the 10-year study period as examined by the 2024 Common Case study program. Assuming all CCTA elements are built, the analyses completed by WECC during 2015 do not indicate a need for additional transmission capacity beyond projects included in the CCTA.

3. Need for Greater Collaboration and Improved Base Case Review

As WECC and its stakeholders broaden their analyses to include a variety of planning tools (power flow, production cost dispatch, capital expansion), it will be increasingly important to coordinate requests for Base Cases and other planning studies. Many tools are available to analyze “reliability” in the Western Interconnection; WECC and stakeholders can maximize the efficiency of their analyses by coordinating study requests and identifying key questions and themes that will provide insight into potential reliability risks. This will also require greater coordination among the committees and subcommittees that support WECC’s planning activities. Reviews of WECC Committees’ scopes and structures that will be conducted during 2016 as a result of WECC’s Section 4.9 review should provide insight and guidance for improving coordination among committees and stakeholders.

4. Continue Investigation of Variable Resource Integration

The Flexibility study was envisioned not only as a means to characterize flexibility challenges for the Western fleet under high renewable resource penetration, but to identify best practices for these types


https://www.wecc.org/Reliability/WECC_Flexibility_Assessment_Report_2016-01-11.pdf

https://www.wecc.org/SystemAdequacyPlanning/Pages/Reliability-Analysis-and-Reporting.aspx


of analyses as well as areas where additional efforts might be usefully focused. Continued refinement of modeling techniques and constructs explored in the study will serve to highlight renewable integration tradeoffs.

5. Continue to Assess Operational Flexibility Needs

The Flexibility Study described above provided much-needed insight into options for operating the grid reliably in an environment that includes high penetration of intermittent renewable resources. But, more work is needed. Future assessments should expand this analysis by considering less conventional sources of flexibility such as market and operational reforms, demand-side measures and all forms of storage.

6. Investigate Flexibility Reserve Requirements

A key area for additional work in assessing flexibility needs is the need to identify whether a minimum level of inertia is necessary to ensure grid reliability, and if so, what the most economic sources of such inertia may be. Additionally, the changing mix of synchronous (e.g., gas-fired generators) and non-synchronous generation (e.g., wind and solar resources) could call into question the ability to provide adequate voltage control, under both steady state and contingency conditions. In addition, the role of battery storage and smart inverter technology could be assessed.

In the 2015 TEPPC studies a minimum generation constraint was applied to certain areas within the state of California, the San Diego area, the Los Angeles basin and the LADWP system.. This assumption is not intended to suggest that such constraints might not exist on other systems, but is merely a reflection of a lack of available information on their operating constraints, particularly as low net load conditions exert pressure on dispatchable fleets to reduce output as low as possible. Further work to identify and characterize such constraints will help to provide an enhanced view of potential integration challenges outside of California.

7. Continue to Evaluate Potential Risks Related to the Gas-Electric Interface

Recent progress has been made in evaluating the gas-electric interface and the risk to reliability it may pose for the Western Interconnection. Many of these studies have created the framework for additional analysis that is needed in 2016 and beyond to quantify the risks and vulnerabilities faced by the Bulk Power System regarding this issue.

8. Continue to Evaluate the Impacts of California’s 50% RPS

California has passed legislation enacting a 50% Renewable Portfolio Standard (RPS) by 2030. This presents a need to update data used in TEPPC’s planning models and data bases, and to continue evaluating how this level of renewable resource penetration—most of which will be intermittent resources—may affect reliability in the Western Interconnection.



5.2 Priorities for Policy

Policy development nationally and within the Western Interconnection is dynamic and could potentially have significant impacts on reliability. Key policy areas that WECC should consider in developing a study program for 2016 could include:

1. Clean Power Plan-related resource mix changes.

States’ plans to comply with the Clean Power Plan will likely change the resource mix in the Western Interconnection. WECC plans to evaluate the reliability implications of states’ aggregate CPP implementation plans, once they are known. Meanwhile, other studies related to potential resource changes could help to identify associated reliability and economic issues.

2. Effects of Distributed Energy Resource (DER) technologies and policies.

With costs of DER technologies continuing to fall, it is likely that deployment will continue to increase in the coming years. Potential impacts on the BES include voltage stability, frequency stability and an increased need for operational flexibility. It will be critical to monitor closely developments in DER-related policies to assess their potential reliability impacts.

3. Transmission utilization effects of issues such as California’s SB 350 legislation15, increased electric vehicle adoption, the EPA’s Clean Power Plan and related regional responses.

4. Coal fleet flexibility potential and retirements (re-dispatch limitations).

Both economic considerations and policy issues such as the Clean Power Plan are likely to have significant impact on the coal resource fleet in the Western Interconnection. Potential coal resource retirements and re-dispatch plans will continue to be a priority policy issue.

5. System flexibility to accommodate higher levels of Variable Energy Resources (VERs).

As intermittent resources such as solar and wind achieve increasing penetration levels, WECC, RPGs and BAAs within WECC’s footprint will need to consider operational and economic options for meeting daily operational needs.

6. Impacts on the Bulk Electric System due to the expansion of the Energy-Imbalance Market in the Western Interconnection.

PacifiCorp’s decision to join the California Independent System Operator (CAISO) Energy Imbalance Market (EIM)16 in November 2014 significantly expanded the reach of a fluid market for meeting the changing imbalance energy needs within the Western Interconnection. Nevada Power and

15 California’s SB350 would require that the amount of electricity generated and sold to retail customers per year from eligible renewable energy resources be increased to 50% by December 31, 2030. The bill would make other revisions to the Renewable Portfolio Standard Program and to certain other requirements on public utilities and publicly owned electric utilities.16 The Energy Imbalance Market (EIM) operated by the California Independent System Operator (CAISO) allows the CAISO to economically dispatch resources to balance energy needs.



Puget Sound Energy joined the EIM in October, 2015 and several other entities have announced plans to consider joining the EIM. WECC will need to monitor closely the expansion of the EIM in the Western Interconnection to fully understand potential associated reliability impacts. It will also need to consider the appropriate analytical tools that could be used to provide insight into potential reliability impacts of EIM expansion in the Western Interconnection.

7. The interaction between transmission and distribution planning.

Technology changes, such as the development of advanced inverters, power electronics and storage could reduce the need for the bulk power system to provide load following and other reserves and reliability services, and focus more on response and resilience to contingencies.

8. The extent and pace of technology innovation.

New technologies for electricity generation, transmission and control may not replace existing technologies, but could lead to significant changes in system planning and operations. It will be important to understand policies at all levels as drivers of these changes.

6. Conclusion

WECC’s internal staff and external stakeholders, working together during 2015, have been able to accomplish a great deal in the past year amid many significant transitions. As WECC’s staff and stakeholders continue to collaborate in 2016 to identify priority study themes and issues, they will be able to further expand their understanding of how the many technological developments, policy issues and economic drivers could affect the reliability of the Western Interconnection.



Appendix A: Glossary of Terms

Acronym Term Definition

BA Balancing Authority The responsible entity that prepares near-term resource requirements, maintains load-interchange-generation balance within a Balancing Authority Area, and supports Interconnection frequency in real time.

BAA Balancing Authority Area The collection of generation, transmission, and loads within the metered boundaries of the Balancing Authority. The Balancing Authority maintains load-resource balance within this area.

BPM Base Planning Margin Also known as “Building Block Margin,” BPM is a methodology for determining a planning reserve margin by considering Contingency Reserves, Regulating Reserves, Forced Outages and Temperature Adders.

BES Bulk Electric System The electrical generation resources, transmission lines, interconnections with neighboring systems, and associated equipment, generally operated at voltages of 100 kV or higher.

BLM United States Bureau of Land Management

An organization within the United States Department of the Interior that is charged with sustaining the health, diversity, and productivity of America’s public lands.

CA/MX California/Mexico An entity that includes parts of CA and Mexico and that shares contingency reserves to maximize generator dispatch efficiency.

CCTA Common Case Transmission Assumptions

The list of transmission expansion projects currently in progress that are determined by the RPCG to be highly likely to be complete by December 2024.

DG Distributed Generation Energy that is generated at or near the point of




consumption.

Dump Energy Energy in a Production Cost Model analysis that is selected in the economic dispatch to be delivered to load but cannot actually be delivered due to modeling constraints.

Energy Storage Any technology that can store energy for use later, including batteries, flywheels, compressed air, thermal technologies and pumped hydro power.

LCOE Levelized Cost of Energy The per-kilowatt hour cost (in real dollars) of building and operating a power plant over an assumed financial life and duty cycle.

LTPT Long-Term Planning Tool The capital expansion model used by WECC to complete 20-year planning studies.

LMP Locational Marginal Price In a nodal pricing system, the LMP is the cost for dispatching the next increment of supply to meet the next increment of load.

LOLP Loss of Load Probability The probability that the responsible load-serving entity may be unable to serve some or all of its customers’ loads, for example, due to multiple generation failures that result in insufficient reserves.

NERC National Electric Reliability Corporation

A not-for-profit international regulatory authority whose mission is to assure the reliability of the Bulk Power System in North America by developing and enforcing reliability standards; annually assessing seasonal and long term ‐reliability; monitoring the Bulk Power System through system awareness; and educating, training, and certifying industry personnel.

NXT Network Expansion Tool A portion of the Long-Term Planning Tool that focuses on transmission optimization.




NWPP Northwest Power Pool A non-profit organization comprised of major generating utilities serving the Northwestern U.S., British Columbia and Alberta that seeks to achieve benefits from coordinated operations.

PCC Planning Coordination Committee

A WECC Standing Committee that evaluates potential future generation and load balance (two years or greater timeframe) and adequacy of the physical infrastructure of the interconnected Bulk Electric System.

PSA Power Supply Assessment An evaluation of generation resource reserve margins for the WECC summer and winter peak hours.

PCM Production Cost Model A model used by WECC to complete studies in the 10-year planning horizon in which resources are dispatched according to their levelized cost to meet load in each of the 8,760 hours of the planning year.

RAWG Reliability Assessment Work Group

A WECC work group that defines facility outage data reporting requirements and makes recommendations on reliability performance level adjustments. The group also monitors the status and analysis of resource adequacy in the Western Interconnection.

RPCG Regional Planning Coordination Group

An organization consisting of representatives of each of the Regional Planning Groups in the Western Interconnection.

RPG Regional Planning Group Entities within the Western Interconnection that have been organized under FERC Order 1000 or under TEPPC’s Charter to address common issues within a particular portion of the Western Interconnection and have a close relationship with smaller load serving entities such as municipal utilities and rural electric cooperatives.




RMRG Rocky Mountain Reserve Sharing Group

A NERC-registered entity that includes parts of CO, NE, SD and WY and that shares contingency reserves to maximize generator dispatch efficiency.

Solar PV Solar Photovoltaic Generation sources based on converting sunlight directly into electricity using photovoltaic technology.

SAP System Adequacy Planning The WECC department responsible for various planning-related data bases, 10-year and 20-year analyses, probabilistic assessments and NERC-related reliability assessments.

SCDT Study Case Development Tool A portion of the Long-Term Planning Tool that focuses on generation optimization.

SPSG Scenario Planning Steering Group

A stakeholder group responsible for, among other things, developing future scenarios for the Western Interconnection.

SRSG Southwest Reserve Sharing Group

A NERC-registered entity that includes parts of AZ, CA, NM and TX and that shares contingency reserves to maximize generator dispatch efficiency.

SWG Studies Work Group A work group under TAS that develops a proposal for TEPPC’s annual study program and establishes the resource portfolio and transmission network assumptions used in each of the study cases.

TAS Technical Advisory Subcommittee

A subcommittee under TEPPC that collects and disseminates data for both historic and forward-looking congestion studies and advises TEPPC on technical matters.

TSS Technical Studies Subcommittee A WECC subcommittee that performs studies, maintains data files, evaluates proposed system additions or alterations, prepares reports and recommendations, and performs such other dutiess as directed by the Planning Coordination




Committee.

TEPPC Transmission Expansion Planning Policy Committee

A Committee created by the WECC Board of Directors to oversee and maintain public databases for transmission planning; develop, implement, and coordinate planning processes and policy; conduct transmission planning studies; and prepare Interconnection-wide transmission plans.

WI Western Interconnection The largest and most diverse of the eight Regional Entities with delegated authority from the North American Electric Reliability Corporation (NERC) and Federal Energy Regulatory Commission (FERC). The WECC Region extends from Canada to Mexico and includes the provinces of Alberta and British Columbia, the northern portion of Baja California, Mexico, and all or portions of the 14 Western states between.



Appendix B: Analytical Reports Completed in 2015

I. Data Bases and Tools

A. 2024 Common Case

B. 2014 Generation Capital Cost Calculator

C. 2014 Transmission Cost Calculator

II. 10-Year (Production Cost) Study Cases

A. PC01: 2024 Common Case

B. PC02: High Load; loads increased by 10%

C. PC03: Low Load; loads decreased by 10%

D. PC04: High Hydro

E. PC05: Low Hydro

F. PC06: High NG price

G. PC07: Low NG price

H. PC10: Variable carbon price

I. PC17: Wind Uncertainty

J. PC18: High Distributed PV – California only

K. PC19: High Distributed PV – West-wide

L. PC21: Coal Retirement

M. PC22: High Renewable

N. PC26: Replace Intermountain coal with CC, Wind, and/or Compressed Air Storage

O. PC30: BLM Resource additions

III. Issue-Based Analyses

A. Energy-Water-Climate Change Scenario

B. Flexibility Study

C. Planning For Uncertainty


https://www.wecc.org/Administrative/Planning-for-Uncertainty-%20JHU-Project-2015-05-04.pdf

https://www.wecc.org/_layouts/15/WopiFrame.aspx?sourcedoc=/Administrative/Flexibility%20Study%20-%20E3.pdf&action=default&DefaultItemOpen=1


https://www.wecc.org/Administrative/151026_PC30_BLM_Study.pptx

https://www.wecc.org/Administrative/160208_PC26_Study_Results_IPP-Swap.pptx

https://www.wecc.org/Administrative/151026_PC22_High_RPS.pptx

https://www.wecc.org/Reliability/150429_PC21_StudyReport_Coal_Retirement.pptx

https://www.wecc.org/Administrative/150423_PC19_High_DG-WECC.pptx

https://www.wecc.org/Administrative/150423_PC18_High_DG-CA.pptx

https://www.wecc.org/Administrative/150416_Study_Results_Wind_Forecasting_Error.pptx

https://www.wecc.org/Administrative/SP1314_PC10_Study_Results_Carbon_Price-2014.pptx

https://www.wecc.org/Administrative/SP1314_PC0607_NG_Price-2014.pptx

https://www.wecc.org/Administrative/SP1314_PC0607_NG_Price-2014.pptx

https://www.wecc.org/Administrative/150624_PC05_LowHydro.pptx

https://www.wecc.org/Administrative/150624_PC04_HighHydro.pptx

https://www.wecc.org/Administrative/150416_Study_Results_Decreased_Load.pptx

https://www.wecc.org/Administrative/150416_Study_Results_Increased_Load.pptx

https://www.wecc.org/Reliability/151002_2024%20CCV1.5_StudyReport_draft.docx

https://www.wecc.org/Reliability/2014_TEPPC_TransCapCostCalculator.xlsx

https://www.wecc.org/Reliability/2014_TEPPC_GenCapCostCalculator.xlsm

https://www.wecc.org/Reliability/2024-Common-Case.zip

Documents

2015 Integrated Transmission and Reliability Assessment-Final€¦ · Web view09/03/2016 · The Western Interconnection has a diverse residential, commercial, industrial and agricultural