2032 scenario 1 study report - wecc€¦ · web viewcompared to the 2032 reference case, scenario 1...

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 1 - Focus on Economic Recovery:

“This represents a world in which an initially slow uptick out of recession is followed by rising economic growth in the Western Interconnection. Happening in concert with a steady pace of incremental, rather than breakthrough, technology improvements in the power sector, this growth supports the emergence of the next generation power system for the region – one which is more efficient, flexible, responsive to customers, and takes full advantage of a spreading smart grid. After a period of international financial instability, the U.S. economy, with more growth, is back on a more solid fiscal foundation with the restructuring of the national debt leading to the implementation of new tax and fiscal policies. The U.S., with its growing population, entrepreneurial culture, and ability to develop advanced technologies, helps to bring the global economy back into balance.

A steadily improving economy drives increasing electricity demands from consumers and expanding businesses and industries – both large and small. In the early years, natural gas meets this demand as increasing supplies keep domestic prices low. As the last decade unfolds however, there is a major shift toward renewables driven by a robust regional electricity market facilitating the integration of renewables, and increasing environmental concerns about land and water use and air quality. Continued concern about climate change leads to efforts to reduce CO2 emissions and culminates in a

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Scenario 1 Focus on Economic Recovery

September 19, 2013

2032 Scenario 1 – “Focus on Economic Growth”

federal energy policy, which includes a national carbon tax. These changes contribute to economic growth as they trigger innovation, revitalize markets and drive new investment.

Even without game-changing breakthroughs, the energy sector is a primary beneficiary of the prowess of the U.S. in both technology development and entrepreneurial vigor and provides a solid basis for overall economic growth for the nation. The WECC region, home to some of the nation’s best educational and financial management institutions, leads the long-term positive evolution of the nation’s economy.”

In summary, Scenario 1 depicts a future “Focused on Economic Recovery” with the following key characteristics:

Wide-spread economic growth in the WECC region with increasing standards of living;

Evolutionary, rather than breakthrough, changes in supply and transmission technology; and

No overriding policy theme, but a focus on growth.

A detailed description of Scenario 1 is available in the Plan. As mentioned, 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 and the four WECC scenarios is presented in Figure 1. Scenario 1 features relatively lower technology innovation but high economic growth. The figure provides an easy way to analyze how the key drivers shape the scenarios. An understanding of the difference between scenarios is useful when comparing scenario study results.

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Figure 1: Scenario Drivers

Key QuestionsScenario 1 hopes to answer some key stakeholder questions, including the following:

What transmission is added by the Long-term Planning Tool (LTPT) in the 2022-2032 timeframe?

What is the generation build-out associated with this transmission? How did study assumptions impact CO2 emissions? How do the aforementioned results compare with the 2032 Reference Case and the

other WECC 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 section, where the LTPT model is explained in detail.

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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 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 assumptions are available in the Tools and Models, Data and Assumptions, and 2032 Reference Case reports.

The following is a description of the assumptions specific to Scenario 1; however, the assumptions described here may be an addition or alternative to those assumptions used in the 2032 Reference Case.

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

Table 1: Scenario 1 Key Metrics

Input Parameter 2032 Reference Case Scenario 1Gas Price (2012$/mmBTU) $6.90 $10.48Cost of Carbon (2012$/metric ton) $37.11 $37.11Peak Demand Compound Annual Growth Rate (CAGR)* 1.25% 1.66%Energy CAGR* 1.54% 1.93%RPS State policy State policy* After all electrification, DSM/DR, and energy efficiency policy adjustments included in the modeling results

Detailed Scenario 1 Metrics in 2032In addition to the key metrics used to describe Scenario 1, there are a number of other input parameters that could change from the 2032 Reference Case to Scenario 1. These inputs and their changes from the 2032 Reference Case (if applicable) are outlined in Table 2.

Table 2: Scenario 1 Input Parameters

Input Parameters Units 2032Reference Value Scenario 1

Fuel & Carbon CostsNatural Gas 2012$/MMBtu $6.90 $10.48Coal 2012$/MMBtu $2.84 $2.84

Carbon 2012$/metric ton

$37.11 $37.11

Capital Cost ReductionsGeothermal % below 2012 0% 0%

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Input Parameters Units 2032Reference Value Scenario 1

cost

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% 0%

Net Energy for LoadBase Energy GWh 1,163,526 1,210,159Policy-Driven Energy Reductions GWh 0 0

Policy-Driven Electrification GWh 0 0

WECC Net Energy GWh 1,163,526 1,210,159Implied Growth Rate, Unadjusted Energy %/yr 1.54% 1.93%

Implied Growth Rate, Adjusted Energy %/yr 1.54% 1.93%

Coincident Peak DemandBase Demand MW 198,715 206,685Policy-Driven Demand Reductions MW -3,780 -3,780

Policy-Driven Electrification MW 0 0

WECC Coincident Peak MW 194,935 202,905

Implied Growth Rate, Unadjusted Load %/yr 1.45% 1.85%

Implied Growth Rate, Adjusted Load %/yr 1.25% 1.66%

Renewable Goals

State RPS % of Load Energy

Current state policies Current state policies

Federal RPS % of Load Energy

none none

In-state RPS Requirement

% of RPS requirement

Current in-state preferences applied to

RPS requirements

Current in-state preferences applied to

RPS requirements

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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 ResultsGeneration results are a key component for Scenario 1 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:

Local policy goals – for most study cases, including the 2032 Reference Case, this is generally distributed generation (DG) set asides specified in state 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.

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 1 assumed a higher energy and peak demand resulting primarily from economic growth that is higher than in the 2032 Reference Case. Because of this assumption, more resources were added in the 2022-2032 timeframe in Scenario 1 than in the 2032 Reference Case. Scenario 1 resulted in the addition of ~75,000 MW of resources from 2022 to 2032, which brings the Interconnection-wide total generation capacity to ~344,000 MW in 2032. The Scenario 1 breakdown of the 2032 total generation capacity by resource type is provided in Figure 2. All resources in the 2022 Common Case were selected and continued to operate in the 2022-2032 timeframe. The existing and incremental generation results in a diverse resource portfolio - wind, water (hydro), and gas resources make up roughly equal parts of 77 percent of the Western Interconnection’s total capacity. Renewable resources represent 36 percent of the Western Interconnection’s resource capacity under this future.

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Figure 2: Scenario 1 2032 Total Generation Capacity

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, new renewable generation at Western Renewable Energy Zone (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 3 shows how the Western Interconnection’s total generation capacity in 2032 breaks down by resource and state. Figure 4 shows the same information geospatially. California remains the largest supplier of electricity in this study with ~80,000 MW of the Western Interconnection’s total capacity. This value is very close to the California capacity in the 2032 Reference Case. After California, a number of states have resource capacities between 20,000-30,000 MW. In the figures, the term “gap” resources refers to local gas resources used to meet load in Alberta.

Figure 5 shows the Interconnection wide net change in resource capacity. There was no displacement of existing 2022 Common Case generation. Of the total Interconnection wide generation capacity, 22 percent consists of new generation additions and 78 percent consists of existing 2022 Common Case generation.

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Figure 3: Scenario 1 2032 Total Generation Capacity (by State)

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Figure 4: Scenario 1 2032 Total Generation Capacity

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Figure 5: Net Change in Resource Capacity (MW)

The previous discussion focused on the total generation capacity of the Western Interconnection in 2032. However, the incremental transmission added from 2022-2032 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.

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From 2022-2032, all existing generation used in 2022 was selected for use in 2032, and about 75,000 MW of generation was added to the Western Interconnection in Scenario 1. These added resources are broken down by resource type in Figure 6. Note that 86 percent of the incremental resources were wind. The rest of the added capacity was made up of a combination of gap, other (combined heat and power), solar, and water (small RPS-eligible hydro) generation. The vast majority of the wind resources were added in four states: Wyoming, New Mexico, Colorado, and Wyoming, as shown in Figure 7. Figure 8 shows the same information geospatially. These states have historically provided some of the best wind resources in the Western Interconnection, so it is not a surprising result that the majority of the added wind is located in this region. No incremental gas resources were selected in the 2022-2032 timeframe.

Figure 6: Scenario 1 2022-2032 Added Generation Capacity

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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.

It is useful to compare the LCOE of resources selected for inclusion in Scenario 1, as shown in Figure 9. The diagram shows the resources added from 2022-2032, 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 at what average cost (in LCOE). Note that the LCOE presented on the chart is a capacity-weighted average LCOE for all resources of the indicated fuel type that were added from 2022-2032 and careful interpretation is required. For example, the ~65 GW of wind installed at a cost of $90/MWh should not suggest that there is 65 GW of wind available at that energy cost. Most of the wind is available at a greater or lower cost than $90/MWh. Only the weighted average cost is presented. This weighted average simplifies the diagram and makes for easy resource comparison.

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

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Since the resource selection was dominated by wind resources, there are few other additions for which costs can be compared. Total LCOE is dependent on the composition of a number of components. A minor change in key assumptions such as resource capital costs, CO2 price, transmission costs, or gas price could swing the Scenario 1 solution in numerous directions, resulting in drastically more or less wind or combined cycle resources being selected by the model.

Scenario 1 used a $10.48/mBTU gas price, as compared to the $6.90/mBTU price in the 2032 Reference Case. This caused gas resources to have a much higher LCOE in Scenario 1 compared to the 2032 Reference Case. This higher LCOE caused the model to add wind almost exclusively, as opposed to high-quality wind and gas added in the 2032 Reference Case. An example of this shift in gas generation, LCOE is shown for a single combined cycle generator in Figure 10. The diagram shows a composite LCOE for a gas generator in Wyoming in the 2032 Reference Case and Scenario 1. In the 2032 Reference Case, this resource was added. In Scenario 1, the higher gas price increased the LCOE for new gas resources from $90/MWh to almost $120/MWh, thus making this generator an un-economic choice as compared to other options, such as wind resources in varying locations throughout the Western Interconnection. Based on this, the resource was not selected by the model in Scenario 1. Although just a single case study for a generator, it shows how the gas price assumption drives the selection of wind (or other resources) over gas resources in Scenario 1.

Figure 10: Gas LCOE Comparison (2012 dollars)

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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 1 study, the system peak reserve was 30,200 MW (15 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.

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 11. 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 Generation 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 1 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. Note that the indicator values are dropping over time not because gas resources are being retired, but rather due to the large amount of renewable resources that are being added to the resource portfolio.

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 11: 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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Figure 12 presents the expansions that were added in all of the system condition transmission expansions. Any project that was added by the transmission model in any one of the four system conditions is shown on the map. There were some expansions that only appeared in only one system conditions, while there were other expansions that were added regardless of the condition analyzed. The majority of the expansion was located in the Eastern and Northwest portions of the Western Interconnection.

Figure 12: Scenario 1 All Expansions for All System Conditions

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These expansions were added by the tool in the 2022-2032 timeframe but they do not represent all high-voltage incremental projects assumed in the tool for the 2012-2032 timeframe since 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 were also “added” in the 2012-2022 timeframe. Thus, the total transmission expansions 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 13.

Figure 13: Scenario 1 All Expansions for All System Conditions and CCTA

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The overall transmission expansion from 2022-2032 is simply the summation of the individual system condition expansions that represent heavy summer, heavy winter, light spring and light fall operating conditions. The LTPT expansion, CCTA, generation dispatch, and load distribution for heavy summer is presented in Figure 14. The major transmission expansions are from the generation surpluses in the eastern and northwest portions of the Western Interconnection to the generation deficit basin and west.

Figure 14: Scenario 1 Heavy Summer LTPT Expansion, CCTA, and Generation and Load

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The Scenario 1 light spring LTPT expansion, CCTA, generation dispatch, and load distribution is shown in Figure 15. Relatively low loads during the light-spring hour, coupled with high renewable generation from the existing and added resources results in expansions from the generation surpluses in the northwest and eastern portions of the Western Interconnection to the generation deficit west and basin. Recall that these are the same regions where the majority of wind was added in the 2022-2032 timeframe. These new resources are located remote from load and there is not sufficient transmission to deliver their large output to distant load centers during this system condition. Because of this, a large amount of expansions were added to relieve the resulting line overloads.

Figure 15: Scenario 1 Light Spring LTPT Expansion, CCTA, and Generation and Load

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The light fall system condition LTPT expansion, CCTA, generation dispatch, and load distribution is shown in Figure 16. In this system condition, loads are relatively low and the renewable dispatch is high. The major expansions are from the generation surpluses in the southeast, northeast and northwest to the west and basin portions of the Western Interconnection which are generation deficient.

Figure 16: Scenario 1 Light Fall LTPT Expansion, CCTA, and Generation and Load

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LTPT expansion, CCTA, generation dispatch, and load distribution for the heavy winter system condition are shown in Figure 17. The major expansions are from the generation surpluses in the east and northwest to the central portions of the Western Interconnection which are generation deficient. A number of expansions were added in both the heavy-winter and heavy-summer expansions.

Figure 17: Scenario 1 Heavy Winter LTPT Expansion, CCTA, and Generation and Load

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Several expansions were added in more than one of the system condition expansions. From a high-level planning perspective, these facilities may represent the most critical expansions since they are needed under a broad array of conditions in this future, which would likely result in a higher asset utilization compared to an expansion which occurred in a single system condition. These “recurrent” expansions are shown in Figure 18 and are expansions that were added in three or four of the four system condition expansions. The expansions in the Eastern portion of the Western Interconnection are most notable as their inclusion as recurrent expansions is driven by the large additions of wind in Wyoming, Colorado and New Mexico.

Figure 18: Recurrent Expansions

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Costs and Carbon EmissionFigure 19 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 1 had a large generation capital cost and transmission investment. The LCOE in Scenario 1 was about $10/MWh higher than in the 2032 Reference Case.

Figure 19: Capital Cost and LCOE Results (2012 dollars)

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The resource portfolio and the assumed dispatch of these resources also results in varying levels of CO2 output, as shown in Figure 20. Scenario 1 has less CO2 output than the 2032 Reference Case. This is due in part to the large amount of incremental wind selected in lieu of incremental gas in Scenario 1 relative to the wind and gas burning resources selected in the 2032 Reference Case. The CO2 output from the 2022 Common Case is provided as a point of comparison. Scenario 1 resulted in a resource portfolio that produced 13 percent less CO2 than the 2022 Common Case.

Figure 20: CO2 Production

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Study SummaryThe following findings summarize the key results from Scenario 1 “Focus on Economic Growth”:

Wind resource additions caused large transmission expansionThe spring and fall system conditions drove a large transmission build out for Scenario 1. These conditions typically have low loads at population centers and heavy output from VG, namely wind in this future. The physical separation of wind resources from load centers and lack of existing transmission between load and low-cost VG resulted in the large transmission expansion observed in Scenario 1.

Wind resources additions were in excess of RPS requirementsScenario 1 added wind generation, almost exclusively, in the 2022-2032 timeframe. These resources were added initially for policy needs, but this requirement was easily met. Wind continued to be the most economic resource in the Western Interconnection for serving load (other than a small amount of hydro). This was partly due to the high gas price assumed in the scenario.

Resource flexibility issues may existThe amount of flexible generation compared to the amount of variable generation in Scenario 1 represents a significant shift from the ratio at which the Western Interconnection is currently operated. This shift highlights the complex operational issues that may be encountered under this type of future.

Levelized cost of energy (LCOE) and capital costs are highScenario 1 has an average LCOE that is 20 percent higher than the 2032 Reference Case. Capital expenditures on transmission and resource investments also exceed the 2032 Reference Case. These cost increases are due to the assumed gas price, and load growth - which required that new resources be added. Notably, this future is one of great economic growth and the resulting high costs could be offset, or justified, by the economic growth experienced in the West.

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