SPSC Low Carbon Study
September 19, 2013
Introduction
The 20-year SPSC Low Carbon study (“Low Carbon study”) is designed to study a world in
which economy-wide carbon emissions are reduced to 42 percent below 2005 levels by 2032 in
the Western Interconnection on a pathway to deeper carbon reductions of 80 percent below
2005 levels by 2050. Instead of simply applying the economy-wide target to the electric sector,
the SPSC study takes a multi-sector approach to highlight the cross-sectorial nature of the
challenge of decarbonization and the implications of limited opportunities for emissions
reductions outside the electric sector. Because there are few opportunities to reduce carbon
emissions in other sectors, there is broad agreement in studies of long-term carbon reduction
strategies that the electric sector will be responsible for a disproportionately large share of
emissions reductions. Specifically, the electric sector offers three broad opportunities for
substantial reductions:

Aggressive deployment of energy efficiency;

Decarbonization of the electricity supply; and

Electrification of loads traditionally served by fossil fuel combustion (e.g., transportation).
Each of these pathways to deep reduction is considered within the Low Carbon study.
The purpose of the Low Carbon study was to understand achievable potential estimates for
carbon reduction in the Western Interconnection in the 20-year timeframe, and to evaluate the
impact of these estimates on the transmission expansion results from WECC’s Long-term
Planning Tool (LTPT). The study used this ordered approach to achieve these goals:
1) Compile demand inputs due to electrification and energy efficiency (EE); identify
Western Interconnection carbon target (metric tons of CO2); calculate new resource
capital costs; and identify new state renewable portfolio standards (RPS) requirements.
The State-Provincial Steering Committee (SPSC) and Western Interstate Energy Board
(WIEB) led this work, and relied on contractor Energy + Environmental Economics (E3)
for support.
2) Review forecasted low-carbon impacts and assumptions with stakeholders.
3) Input the new loads, resource capital costs and state RPS into the Long-term Planning
Tool (LTPT) model. The LTPT model was then iterated with various carbon costs to
determine the appropriate amount needed to encourage the model to select generation
that complied with the study’s specified carbon target.
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2032 Low Carbon Study
4) Review transmission expansion and generation selection. Compare this result with the
2032 Reference Case, which included expected levels of carbon reduction.
The premise behind the Low Carbon study contrasts well with the Scenario Planning Steering
Group (SPSG) 20-year scenario based studies. The SPSG studies changed numerous
variables – technology costs, load levels, generation tax credits, carbon costs, etc. Alternatively,
the SPSC studies focus on adjusting small sets of variables, in this case electrification loads,
renewable capital costs and carbon costs. While none of these specific futures may come to
pass, it is useful to identify how the transmission expansion changes from the 2032 Reference
Case if only a small set of assumptions are changed. This allows the study to develop
causation, meaning differences in results can be attributed to those few variables that were
changed from the 2032 Reference Case.
Figure 1 shows the flow chart logic of the E3 Low Carbon Tool, which was utilized to create the
Low Carbon study inputs based on:
1. Incremental loads (MW and GWh) due to electrification in 2032;
2. Interconnection-wide electric sector carbon target;
3. Capital cost reductions for wind, solar Photovoltaic (PV) and solar thermal resources
consistent,with assuming a massive increase in global installed capacity; and
4. State RPS policy assumptions.
Figure 1: Flow chart of E3 Low Carbon Tool1
Key Questions
The Low Carbon study hopes to answer two key stakeholder questions:
1
http://www.westgov.org/sptsc/announcements/11-27-12LowCarbonTool.pdf
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2032 Low Carbon Study
1. How will a requirement to reduce Interconnection-wide electric sector emissions to 42
percent below 2005 levels by 2032 affect the expansion of generation and transmission?
2. How will the electric sector serve new and incremental loads associated with the
electrification of end uses traditionally served by fossil fuel combustion while still meeting
the emissions levels described in the previous question?
Study Limitations
In the next planning cycle, WECC can build upon its early success with the LTPT and the 20year study methodology by making improvements to the model to enhance the tool’s ability to
address stakeholder study requests. A number of limitations and areas for enhancement have
been identified and are described in the 2032 Reference Case report. A more extensive list of
model limitations is provided in the Tools and Models report, where the LTPT model is
explained in detail.
Input Assumptions
All 2032 study cases are constructed from the 2032 Reference Case as a starting point. As
such, a number of the assumptions used to construct the 2032 Reference Case are carried
through to each subsequent study. This is especially true with regard to detailed modeling
assumptions – these rarely change from study to study. Generally, only assumptions about load
levels, generator and transmission technology costs, and fuel pricing change for a particular 20year study. However, the Low Carbon study is unique and required an iterative process to
determine the proper CO2 cost as an input assumption.
The following is a description of those assumptions specific to the Low Carbon study; however,
that may be in addition to or an alternative of those assumptions used in the 2032 Reference
Case.
Key Assumptions
Assumptions for the Low Carbon study include EE, demand response (DR), electrification
adjustments, renewable capital cost reductions, revised RPS requirements, and a carbon (CO2
production) target. The Low Carbon study contained the same EE and DR assumptions as the
SPSC 2032 High EE/DR/DG (distributed generation (DG)) study because driving higher
efficiency and more load management programs are greatly tied to driving a low carbon future.
Energy Efficiency (EE) Adjustments
The EE input assumptions were calculated as a percentage of each area’s energy and peak
load that were adjusted downward due to high levels of EE in the 2022-2032 timeframe. It was
assumed that each end-use reaches the most efficient commercially available level today. This
is akin to “technical potential”, but is stated in a less aggressive manner. The EE approach
taken by LBNL does not capture efficiency opportunities associated with new or emerging
technologies, which is conservative. The approach allows these forecasts to serve as a “proxy”
for an estimate of economic potential that accounts for continued EE technology development
over 20 years. EE adjustments to system condition demands and annual energy for the 2032
Low Carbon study are presented in Table 1.
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Table 1: Energy Efficiency Adjustments across the Western Interconnection
Demand (MW)
Reference and Adjustment
2032 Reference Case Demand/Energy
EE Adjustment
(% of 2032 Reference Case)
Heavy
Summer
Light
Spring
Light
Fall
Heavy
Winter
Annual
Energy
(GWh)
198,715
133,969
106,658
170,425
1,163,526
-42,000
(-21.14%)
-28,925
(-21.59%)
-23,225
(-21.78%)
-37,915
(-22.25%)
-250,165
(-21.50%)
Demand Response (DR) Adjustments
The DR potential estimates reflect aggressive, yet plausible, long-run trends in DR program
design, enrollment and participation through 2032. The Lawrence Berkeley National Laboratory
(LBNL) had previously subcontracted with The Brattle Group to update the DR potential
estimates from the Federal Energy Regulatory Commission (FERC) National Assessment of
Demand Response Potential (2009) for the SPSC 10-Year High Demand-side Management
(DSM) Case modeled in WECC’s 2011 study cycle. LBNL and the Brattle Group have since
extended and updated those 10-year DR potential estimates to develop a set of 20-year DR
potential estimates for use in the SPSC’s 20-Year High DSM Case and the Low Carbon study.
Similar to the scenarios employed in the SPSC 10-Year High DSM Case, the DR potential
estimates for the 20-Year High DSM Case are based on two FERC scenarios.
1. Updated version of the FERC 2009 “Achievable Participation Scenario” for California.
2. Updated version of the FERC 2009 “Expanded Business-as-Usual Scenario” for all other
states in the Western Interconnection, where the primary difference between those two
scenarios is a higher participation in dynamic pricing programs assumed under the
Achievable Participation Scenario.
High-level results of the updated DR potential estimates are:
1. The Interconnection-wide DR resource size (as a percent of the Western Interconnection
peak demand) is 9.2 percent in 2022 and 9.7 percent in 2032.
2. The state-by-state DR resource size (as a percent of respective state peak demand) in
2032 varies from 4.1 to 16.2 percent. These state-level differences reflect the economic
attractiveness of DR programs in various states due to different existing generation
mixes and service territory characteristics, such as the different daily and seasonal
variations in demand.
The specific scenario modeled is the “high DR” scenario, which represents aggressive, yet
plausible assumptions about future DR impacts and embeds assumptions about the likely
willingness of utilities and regulators to pursue DR. In the analysis, DR projections are based on
five DR programs: 1-2) pricing with and without enabling technology; 3) automated or direct
control DR; 4) interruptible tariffs; and 5) other DR.
Assumptions related to DR for the Low Carbon study are presented in Table 2. There were no
DR adjustments in the study’s annual energy or lightly loaded system conditions since DR is
utilized to reduce peak demand hours.
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Table 2: Demand Response Adjustments across the Western Interconnection
Demand (MW)
Reference and Adjustment
Heavy
Summer
Light
Spring
Light
Fall
Heavy
Winter
2032 Reference Case Demand/Energy
DR Adjustment
(% of 2032 Reference Case)
198,715
-6,553
(-3.30%)
133,969
106,658
--
--
170,425
-1,581
(-0.93%)
Electrification Adjustments
The Low Carbon study contained electrification load adjustments. Electrification is the rise in
demand and energy due to consumers switching from fossil fuel- to electric-powered devices.
Switching to electric transportation alternatives is one example, but electrification can include
any move to electric alternatives in the residential, commercial or industrial markets.
The SPSC contracted with E3 to develop levels of electrification across the Western
Interconnection that would correlate with a low carbon future. E3 built a multi-sector,
spreadsheet-based accounting tool of all greenhouse gas (GHG) emissions in the WECC
footprint for the SPSC. Included in this tool were various levers to adjust carbon mitigation
strategies to different levels (i.e., electrify X percent of residential natural gas energy use or Y
percent of light duty vehicles). E3 and SPSC set targets for each mitigation strategy (besides
electrification, they also looked at energy efficiency, decarbonization of the electric sector,
biofuels, and fuel switching to natural gas) that provided a pathway to decarbonization that was
balanced between the available strategies.
The electrification adjustments were specified as peak demand and annual energy adjustments
for each area of the Western Interconnection. The area-by-area demand impact of electrification
(as a percent of respective area demand) in 2032 varies from 5 to 28.9 percent. The area-byarea annual energy impact of electrification (as a percent of respective area energy) in 2032
varies from 0.1 to 15.1 percent. These area-level differences reflect the economic attractiveness
of electrification in various service territories.
Assumptions related to electrification for the Low Carbon study are presented in Table 3.
Table 3: Electrification Adjustments across the Western Interconnection
Demand (MW)
Reference and Adjustment
Heavy
Summer
Light
Spring
Light
Fall
Heavy
Winter
Annual
Energy
(GWh)
2032 Reference Case Demand/Energy
198,715
+31,806
(16.01%)
133,969
+22,840
(17.05%)
106,658
+18,144
(17.01%)
170,425
+28,620
(16.79%)
1,163,526
+278,620
(23.95%)
Electrification Adjustment
(% of 2032 Reference Case)
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Renewable Capital Cost Assumptions
The Low Carbon study contained lower costs for renewable resources as they were closely tied
to a low carbon future. Such a future assumes massive increases in global installed capacity of
wind, solar PV and solar thermal over the next 20 years, which accelerates these technologies’
learning curves. Additionally, these increases are modeled as greater capital cost reductions
than those in the 2032 Reference Case.
Assumptions related to capital cost reductions for the Low Carbon study are presented in Table
4. The values for the 2032 Reference Case and WECC Scenario 2 study, a “Focus on Clean
Energy” future, are shown because the SPSC and E3 used these cases as low and high,
respectively, references to determine the Low Carbon study’s reductions.2
Table 4: Capital Cost Reductions by Technology (% reduction relative to 2012)
Resource Technology
Solar PV Solar Thermal Wind
2032 Reference Case
31%
25%
8%
Low Carbon study
43%
35%
9%
WECC Scenario 2 Case
55%
45%
17%
Scenario Case
Renewable Portfolio Standard Assumptions
The Low Carbon study contained high RPS requirements because state RPS policies are
primary drivers for a low carbon future. The RPS targets for the Low Carbon study were
developed assuming each state’s 2020 RPS target increases by 1 percent per year through
2032. SPSC and E3 agreed that increased RPS targets would drive the Western
Interconnection to meet the 2050 CO2 production target previously stated (80 percent below
2005 levels).
Assumptions related to RPS targets for the Low Carbon study are presented in Table 5. These
targets are assumed to apply to 100 percent of retail sales in each state, meaning that they
apply equally to all LSEs.
Table 5: RPS Assumptions
State
AB
AZ
BC
CA
CO
ID
MT
NM
2
Renewable Portfolio Standard
2032 Reference Case Low Carbon study
0%
12%
15%
22%
0%
12%
33%
45%
30%
42%
0%
12%
15%
27%
20%
32%
For more information, see the Scenario 2 Study Report.
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State
NV
OR
UT
WA
WY
Renewable Portfolio Standard
2032 Reference Case Low Carbon study
25%
32%
25%
32%
20%
22%
15%
27%
0%
12%
Western Interconnection Carbon Target Assumptions
The “lowness” of carbon in the Low Carbon study was set by a Western Interconnection Carbon
Target. As stated previously, the LTPT cannot explicitly model a CO2 reduction target. As a
result, the LTPT’s Cost of Carbon parameter – a proxy for policy penalization of carbon
producing resources - was varied until the selected generation produced the desired carbon
production target.
SPSC and E3 determined this target by looking at the necessary economy-wide emissions
reductions that would have to be achieved by 2050 to reduce GHG emissions by 80 percent
relative to 2005 levels and interpolating between the 2050 point and where we are in the
present day, which gave the pathway to long-term decarbonization. The 2032 value on the
interpolated line – 139 million metric tons of CO2 production – was then taken as the 2032
carbon production target for the Low Carbon study. Assumptions related to the Cost of Carbon
for the Low Carbon study are presented in Table 6.
Table 6: Cost of Carbon Assumptions
Input Parameter
Units
2032 Reference Case Low Carbon study
Cost of Carbon 2012$/mTon
$37.11
$81.55
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Study Results
The following study results are organized by type: generation and transmission expansion. The
LTPT considers transmission costs associated with each generation resource; therefore, the
cost of transmission (grid cost) impacts the selection of generation by the model.
Environmental analysis of the incremental transmission is included at the end of the report.
Generation Results
Generation results are a key component of the Low Carbon study. “Additions” in the generation
results represent those resources that were added in the 2022-2032 timeframe. “Existing”
generation is any generation assumed to exist in the 2022 Common Case.
Generation Selection
The LTPT adds enough generation in the model iterations to meet four basic goals:
1. Local policy goals – For most study cases, including the 2032 Reference Case, this is
generally DG specified in state RPS policies.
2. Generic policy goals – These are generally state RPS requirements.
3. System energy goals – These are the annual energy requirements by the system. The
model will add resources to those already selected for policy goals until this goal is met.
4. System peak goal – This is to ensure the system has enough resources to meet the
system peak being analyzed.
The LTPT selects resources for the model based on the Levelized Cost of Energy (LCOE) for
each of these goals on a system-wide basis. Resource deliverability is not considered in
resource selections.
Total Capacity and Additions
EE, DR and electrification adjustments resulted in the Low Carbon study having a lower
demand target but slightly higher energy target than the 2032 Reference Case. Energy is higher
and, thus more resources are needed to meet the system energy requirements. Selecting
additional resources allowed for meeting the lower peak demand requirement. In addition, the
Low Carbon study had higher RPS requirements that encouraged additional renewable
resources. The result in LTPT modeling is that more resources were added in the 2022-2032
timeframe for the Low Carbon study than for the 2032 Reference Case. The total capacity of
resources in 2032 for the Low Carbon study was 398,000 MW. This is more than the total
resource capacity of the 2032 Reference Case and SPSC High EE/DR/DG study that were
325,000 MW and 271,000 MW, respectively. This higher total capacity value is based largely on
the increased electrification assumed for this study case.
The breakdown of the low carbon generation capacity in 2032 is provided in Figure 2. The
percentage mix of total generation capacity in the Low Carbon study included nearly two thirds
of the gas, essentially no coal, 8 percent more wind, and 18 percent more solar than that in the
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2032 Reference Case.3 As the Low Carbon study had a higher selected generation capacity,
these renewable percentage differences downplay the gross amount of renewables selected to
meet this low-carbon future. The total selected wind and solar capacity in the Low Carbon study
(203,200 MW) was more than twice that in the 2032 Reference Case (81,500 MW).
Figure 2: Low Carbon Total 2032 Generation Capacity
3
Approximately 5,400 MW of the existing coal generation was selected, but only because it was located
in Alberta. All of Alberta’s existing generation was forced into the model’s selection due to incomplete
data regarding Alberta’s future resource procurements. It is reasonable to assume that this coal would
not have been selected had Alberta’s coal not been forced into the selection because all the existing
coal in the rest of the Western Interconnection was not selected.
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Figure 3 shows the Interconnection wide net change in resource capacity. Approximately 30,000
MW of existing 2022 Common Case generation was displaced by new additions of Solar and
Wind generation. Of the total Interconnection-wide generation capacity, 40 percent consists of
new generation additions and 60 percent consists of existing 2022 Common Case generation.
Figure 3: Net Change in Resource Capacity (MW)
The LTPT had many options when selecting resources to meet policy, energy and capacity
goals. These options were spread across many states in the form of gas generation at key gas
hubs and load hubs, new renewable generation in Western Renewable Energy Zones (WREZ)
hubs, or incremental DG at load areas hubs. This diversity allowed the model to pick the most
economic resources while considering the cost of transmission in that decision. Figure 4 shows
the resource capacity in 2032 for the Low Carbon study broken down by resource type and
state. Figure 5 shows the same information geospatially. California has the largest resource
capacity at 87,500 MW. Arizona, due to its large amount of new solar resources, provides the
second highest capacity in 2032. As previously mentioned, the Low Carbon study did not
include coal.
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Figure 4: High EE/DR/DG Total 2032 Generation Capacity (by State)
Figure 5: High EE/DR/DG Total 2032 Generation Capacity
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The previous discussion focused on the total generation capacity of the Western
Interconnection in 2032. However, the incremental transmission added from 2022 to 2032 is
driven by the generation additions during that same time period as new generation drives new
transmission in the model. Also, the lack of new transmission is tied to the resource not being
developed. As such, there is value in investigating the type and location of incremental
resources as it helps to justify and explain the transmission expansions, or lack thereof, in the
case of the Low Carbon study.
The Low Carbon study added 160,000 MW of resources in the 2022-2032 timeframe, while the
2032 Reference Case added 57,000 MW. The Low Carbon Study also did not select about
30,000 MW of coal resources that were assumed present in the 2022 Common Case, meaning
that these resources were effectively retired. The net resource addition for the Low Carbon
study was about 129,000 MW. The 2022-2032 resource additions for the Low Carbon future are
broken down by resource type in Figure 6. These additions were split nearly 50/50 between
solar and wind spread across the Western Interconnection. The generation future described in
this chart hints at a future with large transmission expansions as there are large injections of
remote resources.
The incremental resources added for the Low Carbon study are further broken down by state
and resource type in Figure 7. Figure 8 shows the same information geospatially. The major
solar resource injections occurred in Arizona, Mexico, Nevada and New Mexico, whereas wind
resource injections occurred mainly in British Columbia, Colorado, Montana, New Mexico and
Wyoming. The “gap” resources are those added to Alberta to represent Alberta’s commitment to
be self-sufficient. The “water” resources are small (840 MW) amounts of hydro where they were
economically viable in British Columbia and Washington – these were the only added capacity
of any type in Washington. As expected in a low carbon future, there were no gas- or coal-fired
resources added to the Low Carbon study during the 2022-2032 timeframe.
Figure 6: Low Carbon 2022-2032 Added Generation Capacity
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Figure 7: Low Carbon 2022-2032 Added Generation Capacity (by State)
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Figure 8: Low Carbon 2022-2032 Added Generation Capacity (geospatially by state)
Levelized Cost of Energy
The LTPT selects resources based on the LCOE. The use of LCOE in the LTPT is described in
more detail in the 2032 Reference Case report. Comparing the levelized cost of resources
added during the 2022-2032 timeframe in the Low Carbon study allows for the identification of
the most economic resources, as well as information about how resource costs compare on
average. Figure 9 shows a supply curve for the Low Carbon study that presents the resources
added from 2022 to 2032, ranked and sorted by resource type and average LCOE. This supplycurve format allows the user to see how much capacity (MW) of a resource was selected, and
what average cost (LCOE) is representative of these resources. The LCOE presented on the
chart is a weighted average LCOE and careful interpretation is required. For example, the ~80
GW of wind installed at a cost of $92/MWh should not suggest that there is ~10 GW of wind
available at that energy cost in this scenario. Most of the wind is available at a greater or lower
cost than $92/MWh. Only the weighted average cost is presented. This weighted average
simplifies the diagram and makes for easy resource comparison.
Figure 9 presents the LCOE supply curve for those resources selected by the model during the
2022-2032 timeframe under the low carbon future. The least expensive resource, on average,
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was small hydro RPS units that represent hydro upgrade projects that can be developed for a
very low capital cost and are highly economic to operate. However, there are few of these
resources available. Wind and solar were the second and third most economic resources. The
remaining resources were small amounts of DG and the “gap” units inserted into Alberta to
model Alberta’s commitment to self-sufficiency. The LCOE of the added DG resources are quite
high compared to the other additions. Their selection was driven by DG-specific RPS
requirements rather than their LCOE.
Figure 9: LCOE for 2022-2032 Added Generation Capacity (2012 dollars)
Resource Adequacy and Operational Flexibility
Resource adequacy and operational flexibility are important elements of reliable grid operation.
Resource adequacy is not a major concern in the LTPT results because the optimized
generation selection includes designated reliability and balancing units and ensures that the
System Peak Demand Goal is met - for the Low Carbon study, the system peak reserve was
40,500 MW (22 percent of the system peak demand). Operational flexibility considerations, on
the other hand, are not part of the LTPT optimization and need to be evaluated.
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Comparing levels of flexibility from study case results with levels from a system known to be
reliable (i.e., today’s grid) enables the identification of potential future operational challenges
and areas for additional evaluation. To make this comparison, TEPPC developed the Flexible
Resource Indicator, the calculation for which is shown below. A detailed description of the
Flexible Resource Indicator and its use in the 20-year analysis can be found in the 2032
Reference Case report.
Flexible Resource Indicator = Flexible Generation4 Capacity
Variable Generation Capacity
The indicator is provided as an aggregated Interconnection-wide value. For example, a Flexible
Resource Indicator equal to 5 means that Interconnection-wide there is 5 MW of flexible
generation for every 1 MW of variable generation (VG).
The Flexible Resource Indicator values are presented in Figure 10. The calculation was
performed for 2012 and 2022 using the 2022 Common Case data to provide context. The
information shows that in the 2022 Common Case there are approximately 2 MW of flexible
resources for every 1 MW of VG. This is a large departure from the ~5 MW of flexible generation
for every 1 MW of VG present on the system in 2012.
The Low Carbon study has a significantly lower Flexible Resource Indicator than the 2022
Common Case and the 2032 Reference Case (5 and 4 times less, respectively). The
decreasing indicator values suggest that operating the transmission system under these futures
with higher levels of VG will take precision, cooperation, robust transmission and a heavy
reliance on existing and potentially new balancing resources. The Flexible Resource Indicator
value decrease from the 2022 Common Case to the Low Carbon study is caused by the large
additions of renewable resources selected by the LTPT model in the 2022-2032 timeframe due
to RPS requirements beyond those in 2022 and the penalization of carbon producing resources
that are characteristic of a low carbon future. The Low Carbon study also resulted in a Flexible
Resource Indicator value less than that of the 2032 Reference Case. This is because the 2032
Reference Case added both gas and VG during the 2022-2032 timeframe whereas the Low
Carbon study added large quantities of VG and no gas-fired resources.
4
Flexible Generation Capacity consists of the total gas-fired generation capacity and 15 percent of the
total hydro generation capacity.
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Figure 10: Flexible Resource Indicator
The complementary nature of wind and solar is not considered in the Flexible Resource
Indicator. The indicator is designed to point out operational complexities that may arise with
large penetrations of VG. The indicator is also useful in identifying futures that look similar to the
grid today, or those futures that may look and operate substantially differently. A more detailed
and thorough analysis is required to evaluate the plausibility of operating these types of high-VG
systems. The indicator’s value is by no means conclusive or prohibitive of these futures.
Transmission Results
When reviewing the transmission results, recall that these are modeling results based on the
input parameters. The results can inform choices about transmission expansion, but many
factors contribute to ultimate decisions about building or not building any specific transmission
expansion. As mentioned previously, all of the transmission results are AC expansions. The
LTPT has the capability to evaluate and choose DC expansions; however, these were not fully
explored due to time restrictions.
The LTPT consistently showed expansions near the California Bay Area and between the
Washington load areas. These are due to the high concentration and close proximity of load
areas in these portions of the Western Interconnection. The focus of the LTPT studies is on
transmission connections between load areas in the Western Interconnection, thus assumptions
were made about transmission reinforcements within TEPPC load areas and between close
proximity load areas – refer to the Tools and Models report for more detail on the LTPT
modeling and limitations. The flows between load areas can depend on the reinforcement
internal to load areas, especially when load areas are in close proximity and they are all
reinforced internally. Such is the case with the California Bay Area and between the Washington
load areas. These portions of the Western Interconnection are very sensitive to transmission
and generation dispatch changes, whether they are regional or internal to load areas. In future
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LTPT models, it may be better to aggregate load areas that are in close proximity so that the
focus remains on Interconnection-wide planning.
Expansions that were added in all of the system condition transmission expansions are shown
in Figure 11. Some only appeared in one system condition, while others were added in all of the
conditions analyzed.
Figure 11: All Low Carbon Case Expansions
These expansions were added by the tool in the 2022-2032 timeframe, but they do not
represent the constituency of high-voltage incremental projects assumed in the tool for the
2012-2032 timeframe. This is because the Common Case Transmission Assumptions (CCTA)
included in the 2022 Common Case represent the set of high-probability transmission projects
that are assumed in the analysis and also “added” in the 2012-2022 timeframe. Thus, the total
transmission additions would be those added by the LTPT from 2022 to 2032, as well as the set
of CCTA projects that were included in the model. A map of both sets of these projects is shown
in Figure 12. Not including the 2022 CCTA as an assumption in the LTPT would increase the
transmission additions in the 2022-2032 timeframe.
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Figure 12: All Low Carbon Expansions and CCTA
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The heavy summer LTPT expansion, CCTA, generation dispatch, and load distribution for the
Low Carbon study is shown in Figure 13. The major expansions are from the generation
surpluses to the generation deficient - New Mexico to Arizona, Nevada to Utah, Montana to
Idaho, and Northwest to California. The expansions in British Columbia are driven by the large
injection of wind resources at the British Columbia WREZ hubs. In this low carbon future, the
basin portion of the Western Interconnection is in close enough proximity to surrounding
renewable resources to justify displacing the existing, local thermal recourses.
Figure 13: Low Carbon Heavy Summer LTPT Expansions, CCTA, and State Generation Dispatch and Load
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The light spring LTPT expansion, CCTA, generation dispatch and load distribution is shown in
Figure 14. This system condition has light loads and high renewable resource dispatch. Fewer
expansions in British Columbia showed up in this condition than in heavy summer. This
particular condition had such a low load that all gas, coal and the most expensive renewables
were curtailed to balance the generation with the load. British Columbia wind had a relatively
high LCOE as compared to other wind resources and was curtailed more as a result. This
lessened the need for reinforcement in British Columbia for this system condition. The major
expansions are from the generation surpluses to the generation deficient – New Mexico to Utah,
Nevada and Wyoming to Utah, and Northwest to California. There is an expansion between the
Sacramento Municipal Utility District and Sierra Pacific Power load centers to allow for delivery
of solar resources along the west side of Nevada to California load.
Figure 14: Low Carbon Light Spring LTPT Expansions, CCTA, and State Generation Dispatch and Load
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The light fall LTPT expansion, CCTA, generation dispatch, and load distribution is similar to that
of the light spring expansion, as shown in Figure 15. The results are the same as that of the
light spring condition.
Figure 15: Low Carbon Light Fall LTPT Expansions, CCTA, and State Generation Dispatch and Load
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The heavy winter LTPT expansion, CCTA, generation dispatch, and load distribution is shown in
Figure 16. As with the heavy summer condition, the expansions in British Columbia are driven
by the large injection of wind resources at the British Columbia WREZ hubs. The major
expansions are from the wind surpluses in British Columbia and solar surpluses in Nevada and
the south to the rest of the Western Interconnection which is generation deficient.
Figure 16: Low Carbon Heavy Winter LTPT Expansions, CCTA, and State Generation Dispatch and Load
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There were several expansions that were added in more than one of the system condition
expansions. From the high-level planning perspective, these expansions may represent the
most critical additions since they are needed under a broad array of conditions in this future.
This would likely result in higher asset utilization as compared to an expansion which occurred
in a single system condition. These “recurrent” expansions are shown in Figure 17. These are
lines that were added in three or four of the four system condition expansions. The Northwest
and central California expansions are not regionally significant. Therefore, the only recurrent
transmission expansions in the Low Carbon study were additions in the extremely northern
(British Columbia), eastern and southern portions of the Western Interconnection.
Figure 17: Recurrent Expansions
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Costs and Carbon Emission
Figure 18 shows the capital cost and the weighted average LCOE for the 2032 Reference Case,
the Low Carbon study, and the High EE/DR/DG case (for reference only). Compared to the
2032 Reference Case, the Low Carbon study had significantly higher generation capital costs
and transmission investments - results that are intuitive. The Low Carbon study had a higher
energy goal and higher RPS targets than the 2032 Reference Case and renewable resources
generally have low capacity factors. The low capacity factor means that only a small portion of a
renewable resource capacity contributes to the annual energy. As a result, many more
renewable generators had to be selected to meet these larger energy goals.
The average LCOE in the Low Carbon study was nearly $15/MWh higher than the 2032
Reference Case. Capital costs associated with the load reductions due to higher levels of EE
are not accounted for in this analysis.
Figure 18: Capital Cost and LCOE Results
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Figure 19 shows the capital cost and the weighted average LCOE for the WECC Scenarios run
as part of the 2012 TEPPC Study Program. The Low Carbon study has a significantly higher
LCOE than any of the other WECC Scenarios. In addition, the Low Carbon study is one of the
two highest cost cases of the 2012 TEPPC Study Program – it has the highest transmission
capital cost and its generation capital cost ($291.1B) is close to that of the WECC Scenario 2
study ($326.4B) that has the highest overall capital cost.
Figure 19: Capital Cost and LCOE Results of LTPT Scenarios in 2012 Study Program 5
5
The SPSC 2032 Enhanced Geothermal case is not shown as it had the same results as the 2032
Reference Case. A rerun of this scenario was planned to determine the point at which Geothermal
becomes significantly viable; however, those results were not ready for inclusion in this report.
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Resource cost, load and CO2 pricing assumptions, along with the necessary transmission build
out, drive what resources are selected by the model. In addition, the Low Carbon study had a
carbon target (CO2 production target). Figure 20 shows the CO2 production for the Low Carbon
study, the 2032 Reference Case, and (for reference) the 2022 Common Case. The Low Carbon
study nearly met its target of 139 million metric tons of CO2 production, respectively 57 and 61
percent reductions from the 2032 Reference Case and 2022 Common Case. The lower loads,
high carbon cost and increased RPS requirements all made this possible in the Low Carbon
study.
Figure 20: CO2 Production
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Study Summary
The following findings summarize the key results from Low Carbon study.
Renewable additions caused large transmission expansion
The vast majority of resources added in the 2022-2032 timeframe in the Low Carbon study were
remote renewable resources. This drove large transmission expansions across the Western
Interconnection.
Levelized cost of energy (LCOE) and capital costs are high
The carbon reductions driven in the Low Carbon study do not come without a cost. EE is well
known as an extremely cost effective way to reduce load, and thus, CO2 emissions. These
reductions in load were not evaluated from the cost perspective. However, the selected
generation portfolio contained a large amount of remote renewable resources which led to high
generation capital costs and the highest LCOE of any of the WECC scenarios. The Low Carbon
study also had the highest transmission capital cost of any of the WECC scenarios to deliver the
new, remote renewable resources to the load centers.
Resource flexibility issues may exist
The large amount of variable generation added in the 2022-2032 timeframe in the Low Carbon
study would likely make hour-to-hour operation of this future complex and could require high
levels of communication and cooperation.
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