2032 scenario 4 study report · web viewfigure 9 presents the lcoe supply curve for those resources...

IntroductionThis report discusses the modeling results for one of seven study cases included in the 20-year analysis. The results discussed within the report include comparisons to the 2032 Reference Case. The basis for this and all other 20-year studies is the 2032 Reference Case Report. Thus, it is highly recommended that readers begin with the 2032 Reference Case Report as it contains explanations of modeling methodologies, limitations and cross-cutting results, which are pertinent to, but not repeated, within this document.

TEPPC uses a scenario-based approach to manage the uncertainties inherent in long-term transmission planning, where capital investments are large, infrastructure lead times are long, and the industry is at the mercy of future economic conditions that are impossible to predict. A key advantage of creating scenarios to identify strategic choices for transmission expansion planning is that they are “plausible” futures that consider a broad range of drivers. Rather than being strictly hypothetical, they describe a set of economic, social, technological and societal circumstances that could reasonably come to pass. Although it is not possible to predict the future, scenario development allows planners to identify strategic choices that planners, developers, regulators and advocates may reasonably need to make in the future.

The following briefly describes Scenario 4 Focus on Long-Term Societal Costs:

“Despite uneven economic growth across the western Unites States and Canada, this world experiences a fundamental shift in the usage and generation of electricity. Economic growth is slowed by constraints on government spending and persistent problems in the capital markets. Sufficient government support for developing new energy technologies encourages further private investment that lead to significant breakthroughs. Technological advances in areas indirectly related to electric energy, such as information and communications, material science and robotics nevertheless feed change in the power industry. The new technology picks up momentum because of innovative features and lower costs, which drive growing rates of adoption. Energy efficiency as well as demand-side management help to drive the shifts seen in this world. States and companies in the Western Interconnection play a leading role in this transformation demonstrating the effectiveness of the new applications. Support for this transition also comes from voters consistently expressing values in support of a cleaner and healthier environment.

Consumers are willing to pay for cleaner and more environmentally sustainable products because they see the benefits in improved health and lifestyles, which don’t require exceptionally higher spending as many new technologies are very cost competitive and

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Scenario 4Focus on Long-term Societal Costs

September 19, 2013

2032 Scenario 4 – Focus on Long-term Societal Costs

highly efficient. The lagging effects from the 2008-2009 credit crises and housing bubble, higher and more volatile oil prices, and some poor national policy choices plague the U.S. and the global economy, allowing only short periods of sporadic growth. Despite these economic troubles, the transformation of the U.S. energy industry, through the leadership of western states, becomes a bright spot for the nation over the ensuing two decades.”

In summary, Scenario 4 depicts a future “Focused on Long-term Societal Costs” with the following key characteristics:

Narrow and Slow Economic Growth in the WECC region with Stagnating Standards of Living;

Paradigm-changing technological developments in Electric Supply and Distribution Technology; and

A policy focus on controlling long-term societal costs.

A detailed description of Scenario 4 “Focus on Long-term Societal Costs” is available in the Plan. Two key drivers – technology innovation in electric supply and distribution and economic growth in the WECC region – helped shape and define the four WECC scenarios. The relationship of these drivers to the four WECC scenarios is presented in Figure 1. Scenario 4 features relatively high levels of technology innovation and lower economic growth, as compared to the 2032 Reference Case. This chart provides an easy method to visualize how the key drivers shape the scenarios. An understanding of the high-level conceptual difference between scenarios is useful when comparing scenario study results.

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Figure 1: Scenario Drivers

Key QuestionsScenario 4 hopes to answer some key stakeholder questions, including the following:

What is the generation build-out associated with this transmission? What transmission is added by the Long-term Planning Tool (LTPT) in the 2022-2032

timeframe? How did study assumptions impact CO2 emissions? How do the aforementioned results compare with the 2032 Reference Case and the

other SPSG Scenarios?

Study LimitationsIn the next planning cycle, WECC can build upon its early success with the LTPT and the 20-year 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 AssumptionsAll 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

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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 20-year study. Full 2032 Reference Case assumption are available in the Tools and Models, Data and Assumptions, and 2032 Reference Case reports.

The following is a description of those assumptions specific to Scenario 4, however, that may be in addition to or an alternative of those assumptions used in the 2032 Reference Case.

Key Scenario 4 Metrics in 2032There are five key metrics that can be used to quickly define Scenario 4, relative to the 2032 Reference Case, as shown in Table 1.

Table 1: Scenario 4 Key Metrics

Parameter 2032 Reference Case Scenario 4Gas Price (2012$/mmBTU) $6.90 $5.24Cost of Carbon (2012$/metric ton) $37.11 $75.00Peak Demand Compound Annual Growth Rate (CAGR)*

1.25% 0.18%

Energy CAGR* 1.54% 0.43%RPS State policy +50% from current state policies

except for in-state preferences, 15% minimum Federal RPS otherwise

* After all electrification, DSM/DR and energy efficiency policies policy adjustments included in the modeling results.

Detailed Scenario 4 Metrics in 2032In addition to the key metrics used to describe Scenario 4, there are a number of other input parameters that could change from the 2032 Reference Case to Scenario 4. These metrics and their changes from the Reference Case (if applicable) are outlined in .

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Table 2: Scenario 4 Metrics

Input Parameters Units 2032Reference Value Scenario 4

Fuel and Carbon Costs

Natural Gas 2012$/MMBtu $6.90 $5.24

Coal 2012$/MMBtu $2.84 $2.84

Carbon 2012$/metric ton $37.11 $75.00

Capital Cost Reductions

Geothermal % below 2012 cost 0% 10%

IGCC w/ CCS % below 2012 cost 0% 0%

Solar PV % below 2012 cost 31% 31%

Solar Thermal

% below 2012 cost 25% 25%

Wind % below 2012 cost 8% 12%

Net Energy

Base Energy GWh 1,163,526 1,118,518Policy-Driven Energy Reductions GWh 0 -125,082

Policy-Driven Electrification GWh 0 +50,000

WECC Net Energy GWh 1,163,526 1,043,436Implied Growth Rate, Unadjusted Load %/yr 1.54% 1.14%

Implied Growth Rate, Adjusted Load %/yr 1.54% 0.43%

Coincident Peak Demand

Base Demand MW 198,715 191,023Policy-Driven Demand Reductions MW -3,780 -24,276

Policy-Driven Electrification MW 0 +8,539

WECC Coincident Peak MW 194,935 175,285

Implied Growth Rate, %/yr 1.45% 1.05%

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Input Parameters Units 2032Reference Value Scenario 4

Unadjusted LoadImplied Growth Rate, Adjusted Load %/yr 1.25% 0.18%

Renewable Goals

State RPS % of Load Energy Current state policies Current state policies, increased by 50%

Federal RPS % of Load Energy none 15% minimum RPS for each U.S. state

In-state RPS Requirement

% of RPS requirement

Current in-state preferences applied to RPS requirements

Current in-state preferences applied to current policy RPS requirements; no preference for in-state resources to meet increase in RPS targets

Study Results

The following study results are organized by type. Generation results are presented first followed by the transmission expansion results. As a reminder, 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 ResultsGenerator results are a key component for Scenario 4 as they are tied closely with the transmission expansions. “Additions” in the generation results represent those resources that were added in the 2022-2032 timeframe. “Existing” generation is any generation assumed to be present in the 2022 Common Case.

Generation Selection The LTPT adds enough generation in the model iterations, in the order shown, to meet four basic goals, in the order shown:

Local policy goals – for most study cases, including the 2032 Reference Case, this is generally distributed generation (DG) set asides specified in state renewable portfolio standards (RPS) policies;

Generic policy goals – generally state RPS requirements;

System energy goals – annual energy required by the system. The model will add resources in addition to those already selected for policy goals until this goal is met;

System peak goal – to ensure the system has enough resources to meet the system peak being analyzed.

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The LTPT selects resources for the model based on the levelized cost of energy (LCOE) for each of these goals system wide (i.e., resource deliverability is not considered in resource selections).

Total Capacity and AdditionsCompared to the 2032 Reference Case, Scenario 4 assumed a lower system energy demand and system peak than the 2032 Reference Case, but higher carbon costs. These factors together caused some existing 2022 coal resources to be retired, and thus the model had to make up for this generation. Scenario 4 had a final resource capacity in 2032 of 327,000 MW, as compared to the 325,000 MW in the 2032 Reference Case.

The total resource portfolio of the Scenario 4 future is broken down by resource type in Figure 2. Notably, wind, hydro (water) and gas resources make up nearly equal parts of 87 percent of the Western Interconnection’s total capacity. This future also depicts very few carbon-emitting resources, as only 36 percent of the Western Interconnection’s resources emit CO2. This is driven by the high ($75/mTon) CO2 cost in Scenario 4. A focus on long-term societal costs implies a future with a resource portfolio with few carbon emissions or pollutants. The generation results in Scenario 4 comply with this perception and clean energy is a result of this future. Note that Figure 2 introduces the term “gap resources,” which are gas resources used in Alberta to serve load.

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Figure 2: Scenario 4 Total 2032 Generation Capacity

Scenario 4 has a higher resource capacity than the 2032 Reference Case. Scenario 4 has lower loads, so intuition might suggest that fewer resources would be added by the model. However, Scenario 4’s focus on long-term societal benefits assumes a carbon price that is roughly double that of the 2032 Reference Case. As a result, a large amount of existing 2022 Common Case coal generation was not selected due to the high carbon price despite not having a capital cost (investment) component of LCOE cost.

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Figure 3 shows the Interconnection-wide net change in resource capacity. Approximately 30,100 MW of existing 2022 Common Case generation was displaced by new additions consisting primarily of Gas and Wind generation. Of the total Interconnection wide generation capacity, 15 percent consists of new generation additions and 85 percent consists of existing 2022 Common Case generation.

Figure 3: Net Change in Resource Capacity (MW)

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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 area hubs, new renewable generation in Western Renewable Energy Zone (WREZ) hubs, or incremental distributed generation (DG) at load area 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 state and resource breakdown for the Western Interconnection’s generation capacity (MW) in 2032 under the Scenario 4 future. Figure 5 shows the same information geospatially. California has the largest portion of the Western Interconnection’s resources. Interestingly, gas-fired and wind resources make up a large portion of almost every state’s generating capacity under this future, where societal costs are paramount.

Figure 4: Scenario 4 Total 2032 Generation Capacity (by State)

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Figure 5: Scenario 4 Total 2032 Generation Capacity

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. New generation drives new transmission in the model. As such, there is value in investigating the type and location of incremental resources as it helps to justify and explain the transmission expansions.

Scenario 4 added 88,000 MW of generation in the 2022-2032 timeframe, while the 2032 Reference Case added 57,000 MW. Because of the retirements previously mentioned, Scenario 4 had to add more resources than the 2032 Reference Case, even though their ending total capacities were roughly equivalent. These 2022-2032 resource additions for the Scenario 4 future are broken down by resource type in Figure 6. Eighty percent of the incremental generation was provided by wind generation. Gas was the second most prevalent addition, but only represented 15 percent of the capacity added from 2022 to 2032. The high carbon cost and the relatively low cost of renewables (compared to the 2032 Reference Case) in this future

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caused the majority of the incremental generation to be first wind and second gas resources. In some cases, existing coal was rendered un-economic (and effectively retired) due to the CO2 pricing assumptions. This prompted the model to replace this capacity with lower-cost resources.

The incremental resources added for Scenario 4 are further broken down by state and resource type in Figure 7. Figure 8 shows the same information geospatially. Additional gas resources were distributed throughout the Western Interconnection, while wind resources were added primarily in the east – Montana, Wyoming, Colorado, and New Mexico. Significant wind resources were also added in Arizona, California and Mexico – this is unique to this scenario. This is an explainable result given the LTPT goals of minimizing cost. Gas can typically be built close to load, thus providing an economic resource that requires little transmission expansion. However, the cost of wind is heavily based on the resource’s capacity factor, and thus, the physical location of the resource. The model results suggest that the cost of transmission to deliver these remote wind resources to load can be overcome due to the significant cost advantage provided by the resource’s high capacity factor.

Figure 6: Scenario 4 2022-2032 Added Generation Capacity

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Figure 7: Scenario 4 2022-2032 Added Generation Capacity (by State)

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Figure 8: Scenario 4 2022-2032 Added Generation Capacity

Levelized Cost of EnergyThe 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 Scenario 4 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 Scenario 4 that presents the resources added from 2022 to 2032, ranked and sorted by resource type and average LCOE. This supply-curve 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. Note that the LCOE presented on the chart is a weighted average LCOE and careful interpretation is required. For example, the ~70 GW of wind installed at a cost of $60/MWh should not suggest that there is ~70 GW of wind available at that energy cost in this scenario. Most of the wind is available at a greater or lower cost than $60/MWh. Only the weighted average cost is presented. This weighted average simplifies the diagram and makes for easy resource comparison.

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Figure 9 presents the LCOE supply curve for those resources selected by the model during the 2022-2032 timeframe under the Scenario 4 future. The least expensive resource, on average, 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 was the second most economic resource. There was a substantial addition of wind due to cost improvements and the implementation of a higher CO2 price under this future. There was nearly 15 GW of gas generation selected by the mode. This generation was selected because wind resources began to become relatively expensive as the high capacity resources were used up. Thus, the model selected gas as the next most economic option. The amount of resources added by the model in this scenario was more than the 2032 Reference Case and other WECC scenarios, so note the difference in X-axis scales when comparing diagrams.

Figure 9: 2022-2032 Resource Additions LCOE Supply Curve (2012 dollars)

Resource Adequacy and Operational FlexibilityResource 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 Scenario 4 study, the system peak reserve was 35,300 MW (20 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 Generation 1 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 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.

Scenario 4 has a lower Flexible Resource Indicator than both the 2022 Common Case and the 2032 Reference Case. The indicator decreases from 2012 to the 2022 Common Case, which suggests that states are adding large amounts of renewable resources and fewer gas burning resources to achieve RPS compliance. 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. Under the Scenario 4 future, the 2022-2032 timeframe features the addition of even more renewable resources, very few gas resources, and the displacement of coal resources. This is driven by higher RPS requirements, high carbon costs and decreasing wind capital costs, which result in wind being the most economic resource available to serve RPS needs and load growth in the 2022-2032 timeframe. By adding this wind with fewer gas resources (or any other balancing resources) and displacing coal resources, the Western Interconnection appears to further decrease its flexibility in the 2022-2032 timeframe under the Scenario 4 future.

1 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 ResultsWhen 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 LTPT models, it may be better to aggregate load areas that are in close proximity so that the focus remains on Interconnection-wide planning.

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Expansions that were added in all of the system condition transmission expansions are shown in Figure 11. Expansions that were added by the transmission model in any one of the four system conditions are shown on the map. Some expansions only appeared in one system condition, while there were other expansions that were added in all of the system conditions analyzed. The Scenario 4 overall expansion was extremely large in comparison to the 2032 Reference Case and other WECC scenarios. Scenario 4, which focused on long-term societal costs, had slightly lower load requirements, yet higher RPS requirements, than the 2032 Reference Case. These differences were not the key drivers of the transmission build out. The CO2 cost increase and decrease in wind capital costs resulted in many new wind resources, nearly all of which were located remote from load. These remote resources overloaded many transmission lines prompting the large transmission expansion shown on the map.

Figure 11: All Scenario 4 Expansions

These expansions were added by the tool in the 2022-2032 timeframe but do not represent all high-voltage incremental projects assumed in the tool for the 2012-2032 timeframe. The Common Case Transmission Assumptions (CCTA) included in the 2022 Common Case

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represents the set of high-probability transmission projects that are assumed to be present in the analysis and were also “added” in the 2012-2022 timeframe. Thus, the total transmission additions from 2012 to 2032 would be those added by the LTPT from 2022-2032, 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.

Figure 12: All Scenario 4 Expansions and CCTA

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The heavy summer LTPT expansion, CCTA, generation dispatch, and load distribution for Scenario 4 is shown in Figure 13. The major expansions are from the generation surpluses in the northwest, Montana, and Wyoming to the central portions of the Western Interconnection which are generation deficient. These particular expansions appear to be driven by the location of various segments of the CCTA network, primarily the Gateway and SWIP projects.

Figure 13: Scenario 4 Heavy Summer LTPT Expansion, CCTA, and State Generation and Load

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The light spring condition has low loads and high renewable energy output. The Scenario 4 light spring system condition LTPT expansion, CCTA, generation dispatch, and load distribution for this system condition is shown in Figure 14. In this particular system condition, the Western Interconnection load was so low that a significant amount of balancing resources (gas) were decremented to obtain a load-resource balance, which lead to the small amount of gas generation across the West. Most of the load is being met with renewable generation during this hour. The major expansions are from the generation surpluses in the northwest and east to the central portions of the Western Interconnection which are generation deficient.

Figure 14: Scenario 4 Light Spring LTPT Expansion, CCTA, and State Generation and Load

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The light fall expansion featured condition similar to the light spring case (e.g., high variable generation, low loads), albeit in a different load and resource pattern. The resulting expansion is shown in Figure 15. The expansion is similar to that of the light spring system in that the Western Interconnection load was so low that a significant amount of balancing resources (gas) were decremented to obtain a load-resource balance, which lead to the small amount of gas generation across the West. The major expansions are from the generation surpluses in the northwest and southeast to the central and western portions of the Western Interconnection which are generation deficient.

Figure 15: Scenario 4 Light Fall LTPT Expansion, CCTA, and State Generation and Load

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Figure 16 shows the LTPT expansion, CCTA, generation dispatch, and load distribution for the heavy winter system condition. The major expansions supply the generation deficient basin with the generation surpluses in the rest of the Western Interconnection.

Figure 16: Scenario 4 Heavy Winter LTPT Expansion, CCTA, and State Generation and Load

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Several expansions 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, which would likely result in a higher asset utilization as compared to an expansion which occurred in a single system condition. These “recurrent” expansions are shown in Figure 17, and thus were added in three or four of the four system conditions. The Northwest expansions are due to the modeling nuance previously explained. Therefore, the only recurrent transmission expansions in Scenario 4 were additions in the east and the central regions, which were added to facilitate renewable delivery and to make up for the lack of conventional resource dispatch, respectively.

Figure 17: Recurrent Expansions

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Costs and Carbon EmissionFigure 18 shows the capital cost and the weighted average LCOE for the 2032 Reference Case and each of the four WECC scenarios. Compared to the 2032 Reference Case, Scenario 4 had a high generation capital cost and high transmission investment. The average LCOE in Scenario 4 was about $3/MWh lower than the 2032 Reference Case. This result, high energy and capital cost, are perhaps expected in this Scenario, which focuses on long-term societal costs. Giving more consideration to the environment and society’s long-term benefits may require capital investment, as shown in this case.

Figure 18: Capital Cost and LCOE Results (2012 dollars)

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The resource portfolio and the assumed dispatch of these resources also result in varying levels of CO2 output, as shown in Figure 19. Scenario 4 has much less CO2 output than the 2032 Reference Case – more than a 50 percent reduction. This is largely due to the incremental wind resources and the high carbon price.

Figure 19: CO2 Production

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Study SummaryThe following findings summarize the key results from Scenario 4 “Focus on Long-term Societal Costs”:

Wind resource additions caused large transmission expansionWind resources were the primary resource addition in the Scenario 4 future. This resulted in a large transmission expansion due to the physical separation of wind resources from load centers and lack of existing transmission connecting them.

$75 per metric ton (2012 dollars) carbon price had a large impactThe higher carbon cost assumed in the Scenario 4 future caused some existing (i.e., 2022 Common Case) coal resources to be displaced by resource additions - primarily wind and gas resources. This impacted the transmission expansions in some system conditions as these resources were no longer available for dispatch.

Levelized cost of energy (LCOE) and capital costs are highA future focused on reducing long-term societal costs does reduce CO2 output and provide the Western Interconnection with a “cleaner” resource portfolio than the 2032 Reference Case. However, these reductions are not without cost as the capital cost investment is higher in Scenario 4 than in the 2032 Reference Case. This case also resulted in the lowest average LCOE for the final portfolio of resources. Many existing (i.e. 2022 Common Case) thermal resources were displaced by new resources in this future (due to carbon costs) and the capital costs associated with those displacements was not accounted for in the modeling.

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2032 scenario 4 study report · web viewfigure 9 presents the lcoe supply curve for those resources...

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