Integrated Transmission and Resource
Assessment
Summary of 2015 Planning Analyses
System Adequacy Planning Department
January, 2016
155 North 400 West, Suite 200
Salt Lake City, Utah 84103-1114
2015 Integrated Transmission and Resource Assessment
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Table of Contents
1. Introduction .......................................................................................................... 1
2. Context ................................................................................................................. 3
2.1
2014—The Current World ............................................................................................................ 3
2.1.1.
2014 Loads ............................................................................................................................ 3
2.1.2.
2014 Generation ................................................................................................................... 4
2.1.3.
2014 Transmission ................................................................................................................ 4
2.2.
2024—The Expected Future......................................................................................................... 5
2.2.1.
2024 Loads ............................................................................................................................ 5
2.2.2.
2024 Generation ................................................................................................................... 6
2.2.3.
2024 Transmission ................................................................................................................ 8
2.3.
2034—Plausible Futures .............................................................................................................. 9
3. Analyses ...............................................................................................................11
3.1
10-Year Production Cost Model (PCM) Studies ......................................................................... 11
3.1.1
Stress Conditions................................................................................................................. 12
3.1.2
Bookends............................................................................................................................. 13
3.1.3
Policy-Driven Changes......................................................................................................... 14
3.1.4
Specific Study Cases ............................................................................................................ 14
3.1.5
Summary Observations ....................................................................................................... 24
3.2
20-Year Capital Expansion Studies ............................................................................................. 25
3.2.1
Model Enhancements ......................................................................................................... 25
3.2.2
20-Year Study Cases ............................................................................................................ 26
3.3
Cost Analyses.............................................................................................................................. 26
3.4
Regional Analyses ....................................................................................................................... 27
3.5
Base Case request of WECC ....................................................................................................... 27
3.5
Probabilistic Assessments .......................................................................................................... 28
4. Reliability Issues ...................................................................................................29
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Western Interconnection Flexibility Assessment....................................................................... 29
4.1.1
Study Implications............................................................................................................... 31
4.2
Energy-Water-Climate Change Nexus ........................................................................................ 34
4.3
Clean Power Plan........................................................................................................................ 35
4.3.1
Regional Engagement ......................................................................................................... 36
4.3.2
Internal Efforts .................................................................................................................... 36
4.4
Planning for Uncertainty ............................................................................................................ 37
4.4.1
Background ......................................................................................................................... 37
4.4.2
Study Focus ......................................................................................................................... 37
4.4.3
Methodology....................................................................................................................... 38
4.4.4
Scenarios and Deterministic vs. Probabilistic Approach to Modeling ................................ 40
4.4.5
Results and Recommendations .......................................................................................... 42
4.4.6
Implications for WECC’s Planning Activities ....................................................................... 43
4.5
Planning Tool Alignment ............................................................................................................ 43
4.6
NERC/WECC Reliability Assessments ......................................................................................... 44
4.6.1
Assessment Caveats ............................................................................................................ 53
5. Recommendations ...............................................................................................54
5.1
Priorities for Infrastructure ........................................................................................................ 54
5.2
Priorities for Policy ..................................................................................................................... 55
6. Conclusion............................................................................................................56
Appendix A: Glossary of Terms ...................................................................................57
Appendix B: Analytical Reports Completed in 2015 ....................................................62
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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:
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•
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.
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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 that 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 (SAP). 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
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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 into the future
(for resource adequacy), 10 years into the future 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 in order to reliably 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.
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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.
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 diverse 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 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):
WECC Paths:
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127,700
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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 Expected Future
The 2024 TEPPC Common Case is a collection of assumptions that are designed to depict the expected
representation of 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 “expected future” 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.
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Figure 2: Load Growth 2014 to 2024
Peak Demand (MW)
Annual Energy (GWh)
180,000
1,031,254 1,050,000
175,000
175,169
170,000
1,000,000
165,000
160,000
950,000
155,000
150,000
888,200
145,000
147,500
900,000
140,000
850,000
135,000
130,000
800,000
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.
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) load modifiers). 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 and 1/1/2024 shows total net generation
capacity in 2024.
1
The reported capacities represent the highest “available to the grid” capacities over the study year.
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Figure 3: Key Resource Net Capacity Change (MW) between 1/1/2014 and 1/1/2024
Conventional Hydro
Energy Storage
Steam - Coal
Steam - Other
Nuclear
Combined Cycle
Combustion Turbine
IC
Other
DG/DR/EE - Incremental
Biomass RPS
Geothermal
Small Hydro RPS
Solar
Wind
-15,000
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-5,000
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5,000
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10,000
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Figure 4: Net Generation Capacity in 2024
Net Generation Capacity - 2024 (MW)
Combustion Turbine
12.3%
Combined Cycle
22.7%
IC
0.4%
Other
0.5% DG/DR/EE Incremental
4.6%
Biomass RPS
1.0% Geothermal
1.4%
Nuclear
2.6%
Small Hydro RPS
0.4%
Steam - Other
1.1%
Solar
5.5%
Steam - Coal
11.3%
Wind
10.3%
Energy Storage
2.2%
Conventional Hydro
23.7%
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.
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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 must consider during that period. It
would be fruitless 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 the “most likely” future 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 has developed 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
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planning horizon. Results of study cases completed in the 20-year planning horizon would then be
compared to the 2034 Reference Case.
WECC has adopted a “scenario planning” approach to provide a broad context for planning in the 20year 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.
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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 policydriven changes. The completed studies are listed in Error! Reference source not found..
Table 1:2015 WECC 10-Year Study Cases
Case ID
PC01
PC02
PC03
PC04
PC05
PC06
PC07
PC10
PC17
PC18
PC19
PC20
PC22
PC26
PC30
Description
2024 Common Case
High Load; loads increased by 10%
Low Load; loads decreased by 10%
High Hydro
Low Hydro
High NG price
Low NG price
Variable carbon price
Wind Uncertainty
High Distributed PV – California only
High Distributed PV – West-wide
Coal Retirement
High Renewable
Replace Intermountain coal with CC, Wind, and/or Compressed Air Storage
BLM Resource additions
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
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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 is used in many
different ways by different stakeholders and carries with it different meanings. These different
connotations 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. WECC has chosen not to use the term
“congestion” in presenting study case results. Rather, it applies the metric of “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 were particularly stressful to the Interconnection, due to their
large increases in power flows and their potential to create conditions resulting in 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: Key Results from Selected Study Cases
Table 2: Key Results from Selected Study Cases
Result
PC1 –
Common Case
PC2 – High
Load
PC5 – Low
Hydro
PC20 – Coal
Retirement
0
60
0
0
1,050,342
1,153,055
1,030,860
1,047,365
168,293
166,760
167,353
224,970
358
552
375
1,481
22,843
27,026
25,354
22,200
363
420
394
277
Unserved Load (GWh)
Annual Generation (GWh)
Annual Renewable
generation (GWh)
Dump Energy (GWh)
Var. Production Cost (M$)
CO2 Amount (MMetrTn)
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The impact to transmission utilization is shown in Table 3: Metrics for Highly Utilized Paths.
Table 3: Metrics for Highly Utilized Paths
Number of Hours At or Exceeding Metrics
Path and Metrics
PC1 – Common
Case
PC2 – High
Load
PC5 – Low
Hydro
PC20 – Coal
Retirement
66
22
6
527
231
131
854
353
195
11
0
0
321
204
144
1246
164
7
2984
1948
0
6103
4019
2725
1058
361
156
1183
773
564
456
171
74
1707
742
457
26
15
13
297
185
134
1985
357
24
4126
2828
0
6003
3754
40
3681
2531
1945
1064
670
502
193
73
23
306
114
58
5
1
1
258
121
84
947
71
1
4121
2764
0
6789
4798
3342
739
277
142
368
184
102
563
206
89
923
332
177
712
296
155
707
477
381
184
4
0
3010
2038
0
3359
2181
1624
1794
934
572
P01 Alberta-British Columbia 75%
(E-to-W) 90%
99%
P18 Montana-Idaho 75%
(E-to-W) 90%
99%
P26 Northern-Southern CA 75%
(N-to-S) 90%
99%
P31 TOT 2A 75%
(N-to-S) 90%
99%
P45 SDG&E-CFE 75%
(N-to-S) 90%
99%
P48 Northern NM 75%
(NW-to-SE) 90%
99%
P52 Silver Pk-Control 75%
(W-to-E) 90%
99%
P60 Inyo-Control 75%
(E-to-W) 90%
99%
P83 Montana Alberta Tie 75%
(N-to-S) 90%
99%
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: Expected Impacts of Bookend Cases.
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Table 4: Expected Impacts of Bookend Cases
Heaviest
Path
Utilization
Case
Expected Impacts relative to Common Case
Total
Variable
Production
CO2
Dump
Cost
Emissions
Energy2
Proportion
of
Renewable
Energy
PC2 Low Loads
PC3 High Loads
PC4 High Hydro
Unknown
PC5 Low Hydro
Unknown
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.
2
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.
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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 was modeled in the common case and the
non-California carbon tax was added in the increments listed in Table 5: Application of Carbon Price in
10-Year Study Cases.
Table 5: Application of Carbon Price in 10-Year Study Cases
Carbon Tax ($/metric ton)
Description
Case
WECC (nonCalifornia)
California
PC1
0.00
27.51
Common case with AB32 in California
PC10-15
15.00
27.51
Assume that California would not lower their tax
PC10-27
27.51
27.51
Apply AB32 tax WECC-wide
PC10-40
40.00
40.00
WECC-wide $40 tax
PC10-50
50.00
50.00
WECC-wide $50 tax
PC10-60
60.00
60.00
WECC-wide $60 tax
The generation impacts from the carbon taxes are presented in Figure 7: Generation Impacts of Carbon
Prices. The progressive shift from coal-fired to gas-fired generation reflects the increasing cost of CO2
emissions.
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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.
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Figure 8: Capacity Factor Impacts of Carbon Prices
The 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 generators were
modeled as small scale solar PV or “rooftop solar” for individual retail customers. Distributed
Generators (DG) were given a Locational Marginal Price (LMP) of $0.00/MWh, which is essentially seen
as a “free” resource to the model. Because of this, the model will dispatch all available Distributed PV
before dispatching other energy sources. However, the model also recognizes various constraints such
as local minimum generation, branch and path rating limits and others. When the model runs into one
of these constraints and cannot deliver these resources, it selects a less economic resource in its place.
Because of these various constraints, we observe a large increase in dump energy, most notably in
California. When compared to the 2024 Common Case, there is an increase in dump energy of
3,142,084 MWh. In association with modeling constraints and dump energy, increased path utilization
in Southern California and in the northeastern portion of the Western Interconnection is observed.
Further investigation into this significant increase in dump energy is warranted in future studies.
Changes to the generation dispatch are shown in Figure 9: Changes to Generation Dispatch - PC19.
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Figure 9: Changes to Generation Dispatch - PC19
Annual Generation by Category (MWh)
2024 PC1 v1.5
2024 PC19 High DG WECC
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
0
3.1.4.3
50,000
100,000
150,000
200,000
250,000
300,000
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. 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.
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: Generation
Changes in PC21 Relative to 2024 Common Case.
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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.
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Figure 11: CO2 Emission Reductions in PC21 Relative to 2024 Common Case
Western Interconnection CO2
(million metric tons)
400
Goal
350
PC01
300
PC21
Goal
Short
250
PC21
277
248
29
200
150
100
50
2005
2007
2009
2011
2013
2015
2017
2019
2021
2023
2025
2027
2029
2031
2033
2035
2037
2039
2041
2043
2045
2047
2049
0
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%. 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.
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Figure 12: Regions Used for PC21
NORTHWEST
BASIN
ROCKY
MOUNTAIN
CALIFORNIA
DESERT SOUTHWEST
Changes to generation dispatch in PC22 are shown in Figure 13: Generation Dispatch Changes in PC22
Relative to 2024 Common Case.
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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.
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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, 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 improvement in
transmission utilization.
Changes to the generation dispatch are shown in Figure 15: Changes to Generation Dispatch for PC30.
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Figure 15: Changes to Generation Dispatch for PC30
Annual Generation by Category (MWh)
2024 PC1 v1.5
2024 PC30 BLM Study
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
0
50,000
100,000
150,000
200,000
250,000
300,000
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 this observation is not
sufficient to state conclusively that none of the study cases would present reliability risks, it
does provide insight into potential impacts of many of the resource and policy issues currently
under discussion in the Western Interconnection.
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 Balancing Areas (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
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constraints). As a result, simply increasing renewable generation injected into the grid will not
guarantee a higher renewable profile across the Western Interconnection—other
accommodations may be necessary.
4. When load is increased across the Western Interconnection, the incremental load is served
primarily by coal and gas resources. This is a result of WECC’s economic dispatch model—the
least-cost resource is selected to meet load. The economic preference for coal and gas
resources to meet incremental load would be expected to lessen as the costs of other resources
decrease.
5. The price assumed for carbon makes a significant impact on resource selection due to its
impact on resources’ Levelized Cost of Energy (LCOE)3. 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. It 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.
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;
3
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.
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
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 lite
loads across the four seasonal periods, a loss-of-load severity measure and cost minimization;
Creating a hierarchy of optimization generator re-dispatch to 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, such as the scenariobased 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
(Long-Term Planning Tool) than in the Production Cost Model. The generation portfolio and
transmission topology are determined exogenously 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
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. This information complements the changes in
production costs that can be taken direction from PCM result comparisons.
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
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Planning Tool (LTPT)—optimize the electric sector’s expansion subject to a large number of constraints
in order to minimize the cost of delivered energy in 2034. Costs are a key input to the tool as costs
(more specifically levelized costs) is the decision method through which the LTPT makes generation
and transmission choices.
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 and include the cost of both right-of-way and transmission line and substation
construction. 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 originally developed by Black and Veatch 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 planning processes and also an “Inter-Regional Coordination” of their
planning efforts. Key discussion issues in 2015 across the inter-regional coordination included:
•
Aligning criteria for cost-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
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 of 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 tenyear, light load case in the 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 the 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
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completing this request. The base case is also intended to represent renewable resource requirements
based on currently-enacted public policy requirements, such as renewable portfolio standards. The
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 provides a range of base scenarios that can then be
compared to “one-off” deterministic scenarios changing one variable at a time. This approach may
provide a more comprehensive understanding of a variable change impact and how the impact
changes as it is compared to different base cases.
In order 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 of the loads and
resources in the Western Interconnection (WI) based on historical data. These distributions are now
ready to be applied to the future planning efforts through 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. The distributions developed in phase
1 were applied to the Loads and Resource (L&R) forecast as provided by each of the WI Balancing
Authorities (BAs) which is regarded as the WI’s “official” forecast of resources and load forecasts over
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the next 10 years, and is reported to the National Electric Reliability Corporation (NERC). 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 a 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: LOLP as A Function of Reserve Margin 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
In the context of 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 that introduces significant new challenges for power system operators.
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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—new investments in
flexible generating resources and the development of novel demand side 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 on the relative importance of various
considerations in planning exercises. 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 in detail two study cases: the 2024 Common Case and
a “High Renewables Case” (PC22).
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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 that 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 to 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
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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. 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.
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 online 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
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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 an
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.
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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. What changes to the environment, in addition to increased average global temperature, might
occur as a result of global changes?
2. Would these 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 electricity 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.
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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

Improve overall coordination between electric industry representatives; water system
managers; federal, state and local governments; tribes and First Nations; and nongovernmental 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. Suggest 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’s)
resource mix over the next 15 years and raises a significant number of 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 newer vulnerabilities for the
Interconnection in terms of challenges to the adequacy of resources and transmission and the reliable
functioning of the high-voltage grid.
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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, 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
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
comprises 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.
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Planning for Uncertainty
4.4.1 Background
The WECC 2013 Transmission 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

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’s) 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 a very 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
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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 the economic benefits can be of 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.
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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:
W
•
Short-run generation markets were cleared by competitive generation companies who 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 probabilityweighted 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, 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.
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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 which we 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 voltage
law, 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 “pipesand-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 present worth of 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
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(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: 90% Confidence Values
of 2024 Scenario Variables depicts the variables used to define the scenarios that included 2013 WECC
stakeholder-defined scenarios and the Technical Advisory Committee.
Table 6: 90% Confidence Values of 2024 Scenario Variables
Variables
Low Value
High Value
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
Natural Gas ($/MMBtu)
3.86
14.50
Carbon ($/Ton)
25.9
87.5
Coal ($/MMBtu)
2.24
3.50
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
Capital Cost
Fuel & Carbon
Prices
Net Energy for
Load
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Low Value
High Value
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
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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:



4.5
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.
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.
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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
assessments, and its annual Long-Term Reliability Assessments (10-year).4 These assessments focus on
resource 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 (PSAs) that are associated with, but independent from and more detailed
than, the NERC Long-Term Reliability Assessments.5 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.6
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
aggregated 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
reflect seasonal load patterns and resource type differences, and to maintain load forecast data
confidentiality.
4
NERC Reliability Assessments
WECC Reliability Assessments
6
The reader should note caveats presented at the end of this section of the report.
5
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Figure 21: Western Interconnection Balancing Authorities
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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 period7 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
7
The assessment period is from 2016 through 2025 for summer and from 2016/17 through 2025/26 for winter.
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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 28 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 3.9
The following graphics and tables present the peak-season margin information for each of the four
assessment subregions. Explanations regarding the graphic/table abbreviations etc. are presented
following the margin tabulations.
Figure 23: NWPP Case 1 through 4 Winter Results
NWPP: Case 1 through 4 - Winter Results
35.0%
30.0%
25.0%
Existing and Class 1
20.0%
Existing and Class 1 through 2
15.0%
Existing and Class 1 through 3
10.0%
Existing and Class 1 through 4
BBM - Winter 16.1%
5.0%
0.0%
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
8
Definition included in the NERC Long-Term Reliability Assessment (LTRA):
http://www.nerc.com/pa/RAPA/ra/Pages/default.aspx.
9
Ibidem.
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Figure 24: RMRG Case 1 through 4 Summer Results
RMRG: Case 1 through 4 - Summer Results
40.0%
35.0%
30.0%
Existing and Class 1
25.0%
Existing and Class 1 through 2
20.0%
Existing and Class 1 through 3
15.0%
Existing and Class 1 through 4
10.0%
BBM - Summer 13.9%
5.0%
0.0%
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Figure 25: SRSG Case 1 through 4 Summer Results
SRSG: Case 1 through 4 - Summer Results
35.0%
30.0%
25.0%
Existing and Class 1
20.0%
Existing and Class 1 through 2
15.0%
Existing and Class 1 through 3
10.0%
Existing and Class 1 through 4
BBM - Summer 16.1%
5.0%
0.0%
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
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Figure 26: CA/MX Case 1 through 4 Summer Results
CA/MX: Case 1 through 4 - Summer Results
40.0%
35.0%
30.0%
Existing and Class 1
25.0%
Existing and Class 1 through 2
20.0%
Existing and Class 1 through 3
15.0%
Existing and Class 1 through 4
10.0%
BBM - Summer 15.0%
5.0%
0.0%
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
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Table 8: NWPP Case 1 Existing/Class 1 Resources Winter Results
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
Net Internal Demand
71,145
72,526
73,668
74,851
75,588
76,401
77,294
77,985
78,703
79,402
Anticipated 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
3,501
Percentage 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
0
Percentage 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
34,404
Percentage 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
5,176
Exports
0
0
0
0
0
0
0
0
0
0
Anticipated Resource Reserve Margin MW
9,508
7,677
5,147
4,260
4,081
228
50
20
42
25
Anticipated 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
2025
Net Internal Demand
12,055
12,171
12,417
12,667
12,830
13,129
13,414
13,736
13,932
14,194
Anticipated 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
775
Percentage 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
52
Percentage 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
1,303
Percentage 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
775
Exports
575
575
575
575
575
575
575
575
575
575
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2018
2019
2020
2021
2022
2023
2024
2025
Anticipated Resource Reserve Margin MW
1,480
1,771
1,542
825
1,033
603
211
3
17
18
Anticipated 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
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
Net Internal Demand
23,297
23,486
24,047
24,514
25,058
25,516
25,734
26,209
26,763
27,377
Anticipated Internal Capacity
28,703
28,650
29,044
28,974
29,176
29,710
29,959
30,598
31,278
32,004
Wind Expected On-Peak MW
164
164
164
164
164
164
163
163
163
163
Percentage 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
382
Percentage 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
733
Percentage 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
4,004
Exports
3,601
3,601
3,601
3,601
3,601
3,601
3,601
3,601
3,601
3,601
Anticipated Resource Reserve Margin MW
1,655
1,383
1,149
513
83
86
82
169
206
219
Anticipated 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
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
Net Internal Demand
52,669
52,919
53,142
53,373
53,637
53,873
54,109
54,249
54,367
54,412
Anticipated Internal Capacity
64,276
66,611
67,342
68,516
68,117
67,521
66,734
65,758
65,169
64,412
Wind Expected On-Peak MW
3,553
3,553
3,553
3,725
3,725
3,725
3,725
3,725
3,725
3,725
Percentage 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
3,779
Percentage 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
3,801
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2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
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
2,746
Exports
450
450
450
450
600
1,175
1,625
2,575
3,675
4,075
Anticipated Resource Reserve Margin MW
3,707
5,754
6,229
7,137
6,434
5,567
4,509
3,371
2,647
1,839
Anticipated Resource Reserve Margin %
22.0%
25.9%
26.7%
28.4%
27.0%
25.3%
23.3%
21.2%
19.9%
18.4%
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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 resources from areas with
surplus generation to deficit areas, considering transfer path constraints and transmission
losses. 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 a transport model, 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.
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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 is load requirements
over the 10-year study period as examined by the 2024 Common Case study program. 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
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types 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 the level of minimum
thermal generation that is needed to maintain adequate inertia and voltage support. In the TEPPC
studies a minimum generation constraint is applied only to the California fleet. 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 to
evaluate 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:
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6.
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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.
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.
Transmission utilization effects of issues such as California’s SB 350 legislation, increased
electric vehicle adoption, the EPA’s Clean Power Plan and related regional responses.
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.
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.
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 CAISO Energy Imbalance Market
(EIM) in November, 2014 expanded significantly the reach of a fluid market for meeting the
changing imbalance energy needs within the Western Interconnection. Nevada Power and
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.
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.
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Appendix A: Glossary of Terms
Acronym
Term
Definition
BA
Balancing Authority
The responsible entity that prepares near-term
resource requirements, maintains loadinterchange-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
Anentity 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
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Term
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Definition
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
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Definition
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
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Definition
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 NERCrelated 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 forwardlooking 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
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Definition
databases for transmission planning; develop,
implement, and coordinate planning processes
and policy; conduct transmission planning studies;
and prepare Interconnection-wide transmission
plans.
WI
W
Western Interconnection
E S T E R N
E
L E C T R I C I T Y
he 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.
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Appendix B: Analytical Reports Completed in 2015
I.
Data Bases and Tools
II.
III.
10
A.
2024 Common Case
B.
2014 Generation Capital Cost Calculator
C.
2014 Transmission Cost Calculator
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 Storage10
O.
PC30: BLM Resource additions
Issue-Based Analyses
A.
Energy-Water-Climate Change Scenario
B.
Flexibility Study
C.
Planning For Uncertainty
The report on PC26 will be posted to the WECC web site when it is available.
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