2032 reference case study report · web viewthe 2032 reference case plays an important role in the...

IntroductionThe objective of the 20-year analysis is to draw clear connections between energy policy, technology costs, and environmental drivers on generation and transmission choices. Because of uncertainties inherent in the 20-year planning horizon, TEPPC uses a scenario-based planning approach. Scenario-based planning is an effective way to manage uncertainties and perform 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. Scenario-based analysis offers a tool for describing various plausible futures (scenarios), analyzing and comparing those futures, and drawing valuable insight into how the drivers identified in and among those futures affect transmission expansion and generation build out. The 2032 Reference Case provides the point of reference for this comparison and is TEPPC’s first 20-year planning horizon study case. It was designed for use in WECC’s new LTPT, which optimizes future generation and transmission capital investment decisions given a set of future policy, economic, environmental and other considerations. The LTPT is described in detail in the Tools and Models report.

The 2032 Reference Case represents the load, resource and transmission topology characteristics that would be present in 2032 if the assumptions used to create the 2022 Common Case are carries out to 2032. The 2022 Common Case is a critical starting point for the 2032 Reference Case and 20-year study cases because it anchors the analysis in a discrete set of foundational assumptions. Unlike the 2022 Common Case, which is an “expected future,” the Reference Case does not convey an expectation of how the future will look in 20 years. The Reference Case serves as a point of reference for planners as they navigate the uncertainties in the 20-year planning horizon. Extending the well-vetted and tested 2022 Common Case assumptions to the 2032 Reference Case provided a credible and defendable point of reference.

There are seven future scenarios in the 20-year analysis. In addition to the four comprehensive multi-dimensional alternative future scenarios (provided by the Scenario Planning Steering Group (SPSG)) shown in Figure 1, there are three “single-parameter” sensitivity analyses examining the impacts of changes (from the 2032 Reference Case assumptions) of single factors.

High EE/DR/DG – Scenario evaluating future with higher than expected levels of EE, DR, and DG

Low carbon – Scenario featuring load reductions and CO2 cost that results in large CO2 decrease

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2032 Reference CaseSeptember 19, 2013

2032 Reference Case

Technology breakthrough cases – Scenario featuring breakthroughs in cost of certain renewable energy technologies

In-depth descriptions of each scenario and the associated analysis results are provided in the individual scenario reports.

Figure 1: Four Scenarios Studied in 20-Year Analysis

The results from the 2032 Reference Case, when considered with the results from other 20-year study cases, will identify strategic options that transmission planners, developers, and regulators should consider in the future. This provides a more robust view of opportunities and risks than would be obtained by studying a narrower range of futures. It is important to understand that the purpose of the 2032 Reference Case and future scenario cases is to highlight how the policy choices that create future scenarios drive transmission and generation choices. The 2032 Reference Case and the 20-year study cases do not predict the future, the exact shape and structure of the future electric network, or advocate any policy or transmission decision.

The 2032 Reference Case plays an important role in the evaluations of all 20-year study cases as it serves as the baseline for study input assumption development, as well as the reference point for study output result comparisons. For example, a study case featuring a “high” gas price should have the assumed gas price relatively higher than what was established for the 2032 Reference Case. Likewise, the transmission expansion resulting from the hypothetical high-gas-price study is best understood when compared to the baseline transmission expansion produced by the 2032 Reference Case. Thus, a robust 2032 Reference Case is key in

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developing a useful set of 20-year studies as it provides the basis for developing and structuring all types model inputs, as well as providing the baseline frame-of-reference against which the most important results of other study cases can be identified and assessed.

To meet the needs of the 20-year analysis, WECC developed the Long-Term Planning Tool (LTPT). This complex capital expansion optimization tool is comprised of the Study Case Development Tool (SCDT) and the Network Expansion Tool (NXT) that work together to co-optimize generation and transmission expansions necessary to meet load at least-cost given a set of stakeholder-derived decision factors (e.g., environmental, policy, economic) and reliability-based constraints. The 2032 Reference Case and all other 20-year analyses were run on the LTPT.

Key QuestionsThe 2032 Reference Case aims to answer some key stakeholder questions, including the following:

Based on the input assumptions, what is the resource build-out needed to meet load in the 2032 Reference Case?

Based on the resource build-out, what are the optimized transmission expansions needed in the 2022-2032 timeframe?

What key input assumptions (e.g., gas price, CO2 price) are most important in driving these results?

What are the capital costs, energy costs, and carbon emission implications of the 2032 Reference Case?

How effective is the LTPT modeling approach for illuminating key drivers, linkages and uncertainties?

How do the results of the 2032 Reference Case compare to alternative futures modeled in the other 20-year study cases?

Study LimitationsThe LTPT promises to be a powerful tool in evaluating potential future resource and transmission expansion decisions. In this study cycle, the creation of this “proof-of-concept” tool was a resounding success and a useful addition to the suite of tools currently used in long-term planning. In the next planning cycle, WECC can build upon its early success with the LTPT by making improvements to the model to enhance the tool’s ability to address stakeholder study requests. An extensive list of model limitations is provided in the Tools and Models report, where the LTPT model is explained in detail.

Study AssumptionsSignificant data and assumptions for the 2032 Reference case are broken out by transmission, generation, and load in the section below. More extensive documentation of these assumptions is in the Data and Assumptions report. The 2022 Common Case served as the starting point for the 2032 Reference Case LTPT model runs. Because of this, the 2032 Reference Case shares

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many of the same assumptions as the 2022 Common Case with regard to transmission, generation, load, hub locations (e.g., TEPPC load areas) and pricing.

TransmissionThere are two types of transmission assumptions in the LTPT: existing transmission and transmission expansions. Existing transmission represents the system as of 2022 (i.e., included in the 2022 Common Case). Transmission expansions include characteristics, including capital costs, for a large set of potential new transmission segments that are available for selection in the Network Expansion Tool (NXT) portion of the LTPT’s iterative generation-transmission optimization process.

Existing TransmissionExisting transmission, also known as the 2022 Common Case transmission topology, includes transmission components existing in 2012 plus the Common Case Transmission Assumptions. This topology was assumed as the starting point for the 2032 Reference Case.

When calculating the initial sets of incremental transmission costs, the LTPT assumed “straight-line” routings (i.e., potential transmission is in a straight line between hub A and hub B). Also, in order to model all study cases using the LTPT, the transmission network had to be simplified by aggregating and reducing the number of network components relative to what was modeled in the 10-year horizon studies.

Tie lines between Balancing Authorities (BA) greater than 230 kV are preserved in the model. All other lines were subject to aggregation. Radial lines were also aggregated.

Load and existing generation are represented at 39 TEPPC area hubs.

Buses were reduced from 18,000 to 1,000, and branches from 24,000 to 2,400.

Transmission ExpansionsTransmission expansions for the 2032 Reference Case were selected via the LTPT’s iterative generation-transmission optimization process. Transmission cost assumptions, detailed in the Data and Assumptions report, were used for the incremental transmission optimization between 2022 and 2032. The LTPT model has the option to add any combination of ~1000 candidate transmission expansions made up of 230-kV, 345-kV, and 500-kV single and double circuits (shown in Figure 2). All of the candidate expansions shown are AC options. The LTPT has the capability to evaluate DC expansions; however, there was not enough time to explore and vet all of the modeling assumptions needed for DC candidates, so the study focused on establishing the proof-of-concept with only AC transmission projects. TEPPC will explore and vet the modeling assumptions for DC expansion candidates in the LTPT in future study cycles to explicitly evaluate DC expansions in addition to the AC transmission candidates.

Candidate transmission connects reduced-network 2022 Common Case buses, TEPPC area hubs, Western Renewable Energy Zone (WREZ) hubs, and natural gas market hubs, all aggregated as previously described. Capital costs for candidate transmission expansions were

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characterized via TEPPC’s transmission capital cost tool, which includes transmission line and substation costs. Capital cost factors include the following:1

Equipment (e.g., conductors, towers, substations) Terrain Right of way Allowance of funds used during construction Breakers Transformers Voltage support Reactive components

Figure 2: LTPT Candidate Transmission

GenerationGeneration assumptions also break out into two categories: existing and additional. As with existing transmission, the existing generation comes from the 2022 Common Case. Generation additions represent the options that the model has to choose from when adding resources.

Existing GenerationAll generators included in the 2022 Common Case are also included within the 2032 Reference Case as existing generation with “sunk” investment costs, meaning they have a capital cost of zero. Thus, when the LTPT selects resources to add in the 2032 Reference Case (for load or RPS requirements), existing resources may likely be selected before new resources since

1 For a more detailed list, with descriptions, see the “Data and Assumptions” document.

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existing resources have a zero capital cost component of the overall levelized cost of energy (LCOE).2 Importantly, stakeholder requests to model the retirements of existing resources between 2022 and 2032 in the LTPT were not explicitly made in the TEPPC Study Request Open Seasons3 leading up to the 2013 Plan. Thus these retirements were not modeled. Additionally, there were no assertions made regarding the retirement of units based on the results of the studies using the LTPT.

The LTPT does not determine which units should be retired, but rather, the LTPT may simply not select a particular generator to be included in a generation profile for a given case study due to study case modeling criteria. The benefit of not subjectively modeling generator unit retirements within the context of long-term planning is that generator selection is subject only to the study case criteria assumptions. For example, existing coal generators were not selected for inclusion in the generation profile in some study cases where there were policy criteria of high carbon prices. In this example, we learn how carbon policy may impact the viability of existing resources, which we would otherwise not be able to glean if existing resources were subjectively retired.

The 2022 Common Case generators were aggregated at area load hubs by type and area. The area load hubs served as a proxy for internal TEPPC load areas and interconnected to other load hubs, gas hubs and potential renewable generation sources (at WREZ hubs) through the overall reduced transmission network. Interties between TEPCC load areas were preserved in the reduced network as were 2022 Common Case Transmission Assumptions. Necessary transmission reinforcements within a TEPCC load area were assumed.

Reliability generation is needed to ensure system reliability. Reliability generating units generally include those generating units needed to meet system reliability criteria, serve load in constrained areas, and provide voltage and stability support. Important characteristics of reliability units include dependable availability and the ability to respond quickly (i.e., fast ramping, quick start, short required down time) to disturbances on the electric system. The LTPT models reliability generation using a flexible rule-based approach. Reliability rules can be defined within the LTPT to designate specific generating units for “automatic” selection in an optimized generation profile as reliability units, regardless of cost. The type and quantity of resources designated for reliability is determined exogenously to the LTPT as a modeling proxy. This reliability resource proxy can be defined within the LTPT in any number of ways. How the reliability resource proxy is defined should be vetted through stakeholder review. In the context of the current study program, all 2022 Common Case combustion turbines (CT) are designated as reliability units within the LTPT. CTs are typically the primary resources used to serve the final load block during high load periods and respond when additional generation is needed

2 Levelized cost is the present value of the total cost of building and operating an electric generation plant. The value reflects overnight capital cost, fuel cost, fixed and variable O&M cost, financing costs, and an assumed utilization rate for each plant type. It is commonly used to compare cost of different resource types.

3 TEPPC Study Request Open Seasons are held annually from November through January. Study requests are vetted through the Technical Advisory Subcommittee and TEPPC. Selected studies are then included in the subsequent TEPPC Study Program. The study results then inform the next WECC Interconnection-wide Transmission Plan.

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quickly, which makes them the best choice for the reliability designation. The Common Case CTs are the least expensive CTs because they have no capital costs (i.e., they are assumed to already exist in 2032). Designation of 2022 Common Case CTs as reliability units enables the model to balance the optimized generation with the demand goal without being too costly. Notably, the reliability units are still subject to economic dispatch considerations in the optimization when satisfying the System Peak Demand Goal. In that regard, they are not “must-run” units.

Generation AdditionsThe model selects incremental generation according to each resource’s LCOE. Detailed information on the capital costs used to calculate the LCOE is located in the Data and Assumptions report. A brief list of additional parameters governing the LTPT’s selection of additional generation includes:

The LTPT does not perform an hourly dispatch, so resource capacity factors must be assumed in the model. When the transmission expansion is performed, this generation can be adjusted such that load and generation match. Detailed information on these assumptions is located in the Data and Assumptions report.

Gas price differentials are relative to Henry Hub state-by-state. Each resource’s contribution to peak is the same as in the 2022 Common Case. Incremental renewable generation is located at WREZ Hubs and (for distributed

resources) at load centers.o Data on profiles for capacity factors comes from the National Renewable Energy

Laboratory (NREL), and Energy + Environmental Economics (E3) for some distributed resources.

o On-peak capacity credit for any type of resource is the same as in the 2022 Common Case assumptions.

Incremental gas resources are added at natural gas hubs and/or TEPPC load hubs. Incremental conventional generation expected capacity factors (annual energy) are

provided by the Capital Cost tool.o On-peak capacity is the same as in the 2022 Common Case assumptions.

LoadThe 2022 Common Case loads were assumed as the starting point for the 2032 Reference Case loads. Area level growth rates from 2012 to 2022 were applied to the 2022-2032 timeframe to produce the final 2032 Reference Case loads. The 2022 loads were expanded out to 2032 using the following rates:

West-wide energy compound annual growth rate (CAGR) = 1.54 percent

West-wide peak demand CAGR = 1.41 percent4

BA-level CAGRs are presented in Figure 3. These values include demand response (DR) adjustments to area peak values, which were provided by Lawrence Berkeley National Laboratory, which developed a DR dispatch module that simulated the operation of DR programs and computed the associated reduction in peak demand. That peak-demand reduction was then applied to the load forecast. DR assumptions for the 2032 Reference Case 4 CAGRs specific to each TEPPC load area were used, resulting in the above CAGRs in the Western

Interconnection. These growth rates are before the application of DR assumptions.

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were developed by extrapolating the DR resources from the 2022 Common Case, based on each BA’s peak-load growth. No additional energy efficiency (EE) adjustments were made to the forecast for 2022 to 2032. By extrapolating the 2022 Common Case forecast, the 2032 Reference Case forecast effectively assumed that EE savings would continue to grow at the same rate as in the 2022 Common Case. Specifically, in the 2022 Common Case, EE savings reach about 10 percent of load in 2022. By extrapolating the 2022 Common Case forecasts, the 2032 Reference Case assumes that EE savings will grow further to about 20 percent of load in 2032. The annual energy and peak assumptions are summarized in Figure 4.

Figure 3: WECC Area CAGR 2022-2032

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Figure 4: 2032 Reference Case Loads

HubsThe 2032 Reference Case uses 104 total hubs that serve as potential locations for new generation resources, as shown on the map in Figure 5. These hubs represent existing resources, loads and future generation, as well as transmission expansions between the nodes. They also identify the end points for potential transmission expansions. The types of hubs are:

TEPPC area hubs (39) used for loads and local BA/area resources WREZ hubs (52) that serve as nodes for incremental renewable resources Natural gas market hubs (13) that provide options for expanding gas generation (aside

from adding generation at the TEPPC area hubs)

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Figure 5: LTPT Hubs

Capital and Operating Cost ParametersCapital costs, fuel prices, the CO2 price and tax policies are key assumptions for the 2032 Reference Case.

Henry Hub Gas Price o $6.90 mmBTU (2012 dollars) – EIA Annual Energy Outlook 20121

o Differentials by stateo Gas is assumed 100 percent deliverable in the LTPT studies

Resource Types and Costso Capital Costs – E3 analysis/report and stakeholder reviewo Future types and cost reductions – 2027 Vintage per E3 toolo Simplified LCOE – E3 tool

Transmission Capital Costso TEPPC Transmission Capital Costs based on review by Black and Veatch

CO2 Price: $37.11/mTon (2012 dollars) Tax Policies

o No Production Tax Credit – current production tax credits for biomass, biogas, geothermal, hydro and wind are assumed to expire in 2016

o Solar Investment Tax Credit reduced from current 30 percent to 10 percent

Study ResultsThe following study results are organized by type. Generation results are presented first, followed by the four transmission build outs corresponding to the four different system conditions (high summer, high winter, low spring and low fall), discussed in the transmission

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results. Environmental analysis of the incremental transmission projects is currently in progress and will be added to the report when available.

Generation ResultsGenerator results are a key component for the 2032 Reference Case. “Additions” in the generation results represent those resources that were added in the 2022-2032 timeframe. “Existing” generation is any generation assumed in the 2022 Common Case.

When reviewing these results, recall that the LTPT has the ability to represent transmission investment decisions in the resource selection process by calculating and applying grid costs. This approach allows for transmission needs and costs to influence, and in some cases determine, which resources are selected during the 2022-2032 timeframe.

Generation Selection The LTPT adds enough generation in the optimization (generation and transmission selection) iterations to meet four basic goals:

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

2. Generic-policy goals – generally state RPS requirements.3. 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.4. 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 LCOE for each of these goals system wide (i.e., resource deliverability is not considered in resource selections).

Total Capacity and AdditionsInterconnection-wide installed capacity in 2032, by fuel, is shown in Figure 6. Total generating capacity in the 2032 Reference Case was 326,000 MW. About 35 percent of this capacity was from gas-burning resources, such as combined cycle (CC) and CT generators. Hydroelectric energy was the second most abundant resource, providing 22 percent of the Western Interconnection’s capacity. Wind was by far the most prevalent renewable resource and made up 21 percent of the generating capacity. Solar resources provided 4 percent of the generating capacity.5 Notably, wind generating capacity was in excess of coal, which only provided 11 percent of the Western Interconnection’s capacity. Note that Figure 6 introduces the term “Gap” resources, which represents gas resources used to meet load in Alberta.

Renewable resources in the 2032 Reference Case represented 27 percent of the Western Interconnection’s installed resource capacity. This is driven by state RPS requirements, which forced renewable energy resources to be selected, and also the capital cost assumptions. In several instances renewable resources, as opposed to more conventional gas and coal resources, were the most economic choice to meet the system energy requirement.

5 This value represents solar-fueled resources, including solar PV, solar thermal and solar distributed generation.

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Figure 6: Interconnection-wide Capacity (by Resource)

Figure 7 shows the Interconnection wide net change in resource capacity. There is no displacement of existing 2022 Common Case generation. Of the total Interconnection-wide generation capacity, 18 percent consists of new generation additions and 82 percent consists of existing 2022 Common Case generation.

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Figure 7: 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, renewable generation in WREZ hubs, or DG in load area hubs. This diversity allowed the model to pick the most economic generating resources (while considering the cost of transmission in that decision). The installed capacity of the Western Interconnection in the 2032 Reference Case is further broken down by state and fuel type in Figure 8. Figure 9 provides the same information geospatially. California had about 81,000 MW of the overall resource capacity, while Arizona and Washington each had roughly 34,000 MW of installed capacity.

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Figure 8: 2032 Total Installed Capacity by State and Fuel

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Figure 9: 2032 Total Installed Generation Capacity

The previous discussion focused on the total generation capacity of the Western Interconnection in 2032. However, a large portion of this capacity included the 2022 Common Case generation which had zero capital cost in the LTPT, thereby making it highly economic for selection in the LTPT. Resources added between 2022 and 2032 can be distinguished from the entire population of projected system resources. During this 10-year span, it was necessary to add 57,000 MW of generating capacity to the ~268,700 MW assumed in the 2022 Common Case to meet all modeling goals. This represents a 21 percent increase in capacity. These additions are broken down by resource type in Figure 10. Wind resources were the most frequent addition making up 56 percent of the incremental capacity. Gas made up 35 percent of the incremental capacity, and the remaining additions were split between water (small hydro), solar and gap6 units. Note that fuel types omitted from the chart were not selected by the model in the 2022-2032 timeframe. This means that no incremental coal, nuclear, biomass or geothermal resources were added from 2022 to 2032.

6 In TEPPC studies, Alberta is an area of concern as there are many issues with balancing load and generation. To resolve this, “gap” units were forced into Alberta to equalize the area’s load-gen balance. These units are gas resources and this modeling is consistent with Alberta’s policy to become energy independent.

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Figure 10: 2022-2032 Resource Additions

Figure 11 shows the state and resource breakdown of the 57,000 MW of incremental resources added between 2022 and 2032. Figure 12 provides the same information geospatially. New Mexico received the most additional capacity, with 2,000 MW of new gas generation and over 11,000 MW of additional wind resources, nearly twice as much as any other state. Wyoming added significant resources, mainly gas (~3,300 MW) and wind (~7,100 MW). The only state to see a significant increase in solar installations was Arizona where ~1,300 MW of solar was added.

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Figure 11: 2022-2032 Added Capacity by State and Fuel

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Figure 12: 2022-2032 Added Generation Capacity

Levelized Cost of EnergyTEPPC uses the Levelized Cost of Energy (LCOE) to compare the relative costs of generation options in its analyses. The LTPT selects resources based on the LCOE. Levelized costs represent total cost of building and operating a generating plant over an assumed financial lifetime, converted to annual payments. The LCOE reflects capital cost, capacity factor, contribution to peak, fuel cost, fixed and variable O&M costs, financing costs, and grid cost. It is important to note the inclusion of grid cost in the LCOE. This is a key component of the LTPT as grid costs allow for the consideration of transmission costs in the resource selection decisions made by the model. Two resources of identical characteristics but different locations could have different LCOEs due to variances in grid cost, thus affecting which resource the model selects. An example LCOE breakdown and comparison is shown in Figure 13. This figure is a hypothetical example intended to show how the cost components create the overall LCOE, which may differ from one resource to another.

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Figure 13: Hypothetical LCOE Component Breakdown

It is useful to compare the LCOE of resources selected for inclusion in the 2032 Reference Case shown in Figure 14. The diagram shows 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 the amount of capacity (MW) of a resource was selected, and at what average cost (in LCOE). Note that the LCOE presented on the chart is a weighted average LCOE and careful interpretation is required. For example, the ~30 GW of wind installed at a cost of $80/MWh does not suggest that there is ~30 GW of wind available at that energy cost. Most of the wind is available at a greater or lower cost than $80/MWh, and only the weighted average cost is presented. This weighted average simplifies the diagram and makes for easy resource comparison.

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Hypothetical values for reference only

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Figure 14: 2022-2032 Resource Additions LCOE Supply Curve (2012 dollars)

One noteworthy takeaway from Figure 14 is the diminutive difference in LCOE between the added wind resources and the added combined cycle gas units. They are separated by only ~$10/MWh due to the total LCOE being dependent on the composition of a number of components. A minor change in key assumptions such as resource capital costs, CO2 price, transmission cost, or gas price could “swing” the 2032 Reference Case solution in either direction. This has the potential to result in drastically more or less wind or combined cycle resources being selected by the model. This would have a large impact on the transmission expansion results as wind is typically remote from loads while gas generators can be located near more populous areas.

It is also interesting to observe the rather large discrepancy of the solar weighted average LCOE versus that of wind. The wind average LCOE was roughly $40/MWh less than the LCOE of the selected solar resources. This is likely understating the difference between the “best” of both the wind and solar resources. The $120/MWh LCOE for solar represents a small quantity of the lowest cost resources on the solar supply curve. Alternatively, there was much more wind selected, so the “best” resources on the lowest-cost portion of the wind supply curve were less costly than the $80/MWh average LCOE shown in the diagram.

The difference between wind and solar costs are best shown through a comparison chart, as presented in Figure 15. The chart compares the two most economic wind and solar resource

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options selected by the LTPT in the 2032 Reference Case. The compared resources are of similar size, but vary by technology type and location. As shown, the most economic large-scale solar selected was ~$120/MWh solar PV (tracking) in New Mexico. The 225 MW of wind selected in Wyoming had an overall LCOE of $64/MWh. This nearly two-fold difference in levelized cost is mainly attributable to the capital cost difference between the resources. Based on LCOE ($/MWh), solar is twice as expensive as wind in this example.

Figure 15: LCOE Comparison - Wind vs. Solar (2012 dollars)

Figure 15 also suggests that grid costs reduced the levelized cost of both wind and solar (for those generators in the example). The solar in New Mexico had a near-zero grid cost, while the wind in Wyoming had a grid cost that totaled less than 5 percent of its total LCOE. Grid cost is directly based on the amount and location of additional transmission facilities that were added by the model to connect the resource to the grid. Based on this, more costs would be allocated to generators that required significantly expanded transmission systems to get their generation to load than to the example wind and solar generators. These resources were located such that they did not require extensive transmission expansions because much of the added generation was delivered on existing transmission lines (during the system conditions analyzed).

The absence of coal and nuclear generation from the incremental resource selection is notable. The assumed CO2 price of $37.11/mTon was a key driver of the coal-fired generation not being selected as it caused new coal-fired generation to become uneconomical as a new resource. An example of coal not being a viable option is presented in Figure 16. The LCOE of Wyoming’s most economic resource, or first resource selected (wind), was compared to the LCOE of its last resource selected (combined cycle gas turbine (CCGT)), and the lowest cost options of two resource types that were not selected: traditional coal and integrated gasification combined cycle (IGCC) with carbon capture and sequestration (CCS) coal. As shown, a particular wind

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plant in Wyoming was the most economic option at ~$64/MWh. A CCGT was the least economic option that was still selected, with a LCOE of $93/MWh. All units selected for addition in Wyoming fell within this $70-$93/MWh range. New coal is not a viable option as its LCOE ranged from $121-161/MWh, depending on the technology. CO2 emission costs were a key driver of the high cost of traditional coal resources. If there was no CO2 emission cost, the coal resource in the figure would be closer to $80/MWh – a much more economic option that might have been selected for dispatch. However, given the variability in gas pricing, it is conceivable that ~20 $/MWh of fuel cost could be added to the CCGT resource, thus making coal and gas combined cycle fairly price competitive. Furthermore, a future with no CO2 cost and a high gas price would likely make coal more economic than gas.

Figure 16: LCOE Comparison of Coal (2012 dollars)

Figure 16 also shows an interesting portrayal of the cost of IGCC with CCS. This technology has a lower fuel cost and lower CO2 emission component (due to the CO2 storage) than CC gas. However, it is widely known that this technology is expensive, and this is shown by the capital cost portion of the LCOE, which at $80/MWh alone proves to be more expensive than the all-in LCOE of most wind resources, and comparable to some gas resources.

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Resource Adequacy and Operational FlexibilityResource adequacy and operational flexibility are important elements of reliable grid operation. The LTPT is a capital expansion model and only performs four unique system-wide dispatches under which transmission flows and expansions are evaluated: high summer, high winter, low spring and low fall. In these generation dispatches, generation must be equal to load. All resources, including variable generation (VG), are able to contribute to meeting this load. VG tends to have a low LCOE due to its low operational cost, so the model selects these resources to meet loads in the optimization. However, this VG may or may not be available every hour of the year. 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 Reference Case, the system peak reserve was 45,100 MW (23 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—which is done in this section.

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. Since generation must equal load in all hours, resources are required to “balance” the VG. Even when there is significant geographic diversity—which tends to smooth out overall variability as the diversity increases—in the installed renewable resource portfolio, there would be times when the model would need to dispatch non-renewable resources to meet system load. In many instances, gas-burning and portions of hydro resources are the most economical option to provide this balancing capability. TEPPC created a simple indicator based on how the model accounts for variability to help determine if study results show a potential operational flexibility issue. Other options for providing flexibility are not considered in the indicator, as an analysis of those options is more appropriately left to additional evaluation identified using the indicator. The Flexible Resource Indicator is equal to the Flexible Generation Capacity defined as the amount of gas-fired generation plus 15 percent of the hydro generation, divided by the amount of VG. While very coarse, this indicator provides a general ratio of the amount of flexible generation typically used for balancing VG to the amount of potential variability in the system. The indicator does not take into account balancing resources other than gas-fired and hydro generation or the smoothing effects of geographic diversity on variability; however, it helps identify the TEPPC studies that would benefit from future studies which could include these additional elements.

The Flexible Resource Indicator is defined as:

Flexible Resource Indicator = Flexible Generation 7 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. Importantly, the LTPT and the Long Term Planning process,

7 Flexible Generation Capacity consists of the total gas-fired generation capacity and 15 percent of the total hydro generation capacity.

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itself, are new and will mature over time, as lessons are learned and models and processes are re-examined and refined. No one can predict the future with absolute certainty. One may, however, reduce future uncertainties by creating and refining tools and models in order to better understand the future. Such is the case with the Flexible Resource Indicator.

The Flexible Resource Indicator values are presented in Figure 17. The calculation was performed for 2012 and 2022 using the 2022 Common Case data to provide context for the 2032 Reference Case value.

The indicator shows that the 2022 Common Case “expected future” has approximately 2 MW of gas resources for every 1 MW of VG. This is a large departure from the ~5 MW of gas generation for every 1 MW of VG that was available in 2012. Clearly, in the approaching 10-year timeframe the Western Interconnection is undergoing a paradigm shift in the relative amount of renewable resources and, as a result, how the system is operated.

The 2032 Reference Case has an even lower flexibility indicator than the 2022 Common Case. This suggests that operating the transmission system under this future - with higher levels of VG - will take precision, cooperation, robust transmission and a heavy reliance on existing and potentially new balancing resources. These indicators are dropping over time not because gas resources are being retired, but rather due to the large amount of variable resources that are being added relative to conventional resources.

Figure 17: Flexible Resource Indicator

Over the next 20-years, system flexibility (as measured by the Flexible Resource Indicator) could decrease significantly. This decrease is cause for concern and decision-makers in the Western Interconnection may need to consider additional gas resources, or to the extent those resources are not available or preferred, other flexible generation. Figure 18 shows a range of flexibility options and how they may meet the need for flexibility on the grid. This “all-of-the-

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above” approach in securing appropriate sources for system flexibility could be critical to continued reliable and efficient operation of the Western Interconnection.

Figure 18: Flexibility Options

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 Transmission expansion results are a key outcome from the 2032 Reference Case. Generation selection and transmission build out are inherently tied together in the LTPT modeling approach. This interdependence is intentional as it serves two key objectives of the analysis: to consider the cost of transmission in resource selection, and to make optimal use of transmission corridors within which incremental transmission costs are relatively low. The LTPT works through an iterative process. In the first iteration, the LTPT optimizes the generation by selecting resources based on LCOE. The selected resources are assumed in the next iteration, which

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adds the most cost-effective transmission given the resource assumptions.8 . In the third iteration, the model optimizes the generation, this time with the grid costs included in the LCOE of the new resources. The newly-assigned grid costs increase the LCOE of the resource to which they were assigned, thus potentially changing the resource’s position in the economic dispatch stack. In this manner, the LTPT allows transmission costs to be included in the generation selection phase, and also for the value of selected generators (in terms of reliable on-peak capacity and LCOE) to drive which transmission is selected.

The iterative process is performed on the “heavy summer” system condition in the LTPT. This is the default process in the current modeling methodology—and may present an opportunity for enhancements in the methodology and model in the next study cycle. In order to gain a better understanding of what transmission might be required for conditions other than the heavy summer condition, a generation expansion selection is then tested for transmission use impacts (potential overload) under three additional system conditions: light spring, light fall, and heavy winter. These additional iterations do not feed back into the LTPT optimization, but they can indicate additional transmission requirements for a selected resource mix beyond those transmission requirements calculated under the “heavy summer” condition.

The LTPT consistently showed expansions near the California Bay Area and between the Washington load areas9. 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.

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.

Figure 19 presents the projects selected in all of the transmission expansions. Any project that was added by the Network Expansion Tool (NXT) in any one of the four system conditions is shown on this map. The notable transmission expansions were in the central and eastern portions of the Western Interconnection. These projects were added by the tool in the 2022-

8 A more detailed description of how the LTPT works can be found in the Tools and Models report. 9 In this context, the Washington load areas refer to PSE, BPA, SCL, TPWR, AVA, CHPD, PGN, GCPD,

and DOPD.

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2032 timeframe. However, they do not represent all high-voltage projects assumed in the tool for the final 2032 power flow analysis. This is because the Common Case Transmission Assumptions (CCTA) included in the 2022 Common Case represent the set of high-probability transmission projects assumed in the analysis and “added” in the 2012-2022 timeframe. Thus, the total transmission expansions from 2012 through 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 20.

Figure 19: All Expansions

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Note: Lines represent expansions that resulted from any one of the four system condition transmission expansion runs. Expansions vary in voltage and capacity, although most are either 1500 MW or 3000 MW (500kV single or double circuit).

2032 Reference Case

Figure 20: All Expansions and CCTA

There were 59 LTPT expansions chosen across the four system conditions evaluated. This number takes into account any duplicate expansions that, for instance, were added in multiple system conditions. It also considers the fact that an expansion in one system condition would meet the need for a smaller expansion in another system condition. For example, a 3,000 MW expansion in light fall would fulfill the need for a 1,500 MW expansion in heavy winter. Thus, these duplicate expansions are not counted individually, but rather are one unique expansion (at the higher capacity).

These 59 expansions represent about 124,200 MW of high-voltage transmission capacity added in the 2022-2032 timeframe. Of the 59 expansions, 25 are 3,000 MW 500-kV double-circuit projects. The total cost of the expansions (assuming straight line routing) is $25.72 billion. Assuming an economic life of 40 years, this value annualizes to $3.7 billion per year.

As previously mentioned, each of the four system conditions evaluated in the NXT resulted in a unique transmission expansion. These four expansions are presented in Figure 21. Note that all

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expansions are shown as a single line but many are multiple circuits of varying capacities. The expansions are also summarized in Table 1.

Figure 21: Expansions for Each System Condition

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Table 1: Reference Case Expansions Summary

ExpansionsHeavy Summer Light Spring Light Fall Heavy

WinterCombined10

# Expansion Projects 25 24 37 24 59Capacity Added (MW)

49,900 51,000 71,300 48,400 124,200

2012 Dollar Cost (M$)

$8,043 $9,185 $13,482 $10,513 $25,720

Line Miles 3,153 3,198 4,252 3,378 8,089

A comparison of the transmission expansions, based on the four system conditions, shows the heavy summer expansion had the fewest projects added the least incremental capacity and the lowest transmission cost. This is counterintuitive as one would typically associate the summer peak with being the most stressful condition faced by the transmission system. However, upon further consideration, this result is logical. The generation selection (SCDT) portion of the LTPT incorporates grid cost with information from the heavy summer condition only. It was also discovered that after satisfying the annual energy goals, there was ample generation capacity available to satisfy the system demand goals. The result of this is that the installed generation profile was the same across all conditions, with the exception of certain load demand levels over specific system conditions where the generation dispatch was different. This is an important nuance to consider. The energy goals are satisfied annually because that is how they are defined (e.g., RPS requirements are specified as percentages of annual energy). Economic dispatch must balance MW generation with MW load demand for a given demand hour associated with each condition. The result of this is that the economic dispatch for each condition is performed from the same supply stack of generation, as dictated by the annual energy goal optimization.

Another unexpected result was that the light fall system condition had the most additional projects, greatest additional capacity, and highest cost ($13.5 billion). Traditional deterministic transmission expansion planning has often focused more on the annual peak load period and less on the lighter annual load periods of a year. The result of this is that system transmission reinforcements were often tailored more to meet the needs of the grid during annual peak conditions than that of other load conditions over the course of a year. The advent of unexpected transmission expansion needs appearing in the study results during light fall conditions suggests that a paradigm shift may be needed in the planning focus. Changes in the focus of transmission expansion planning from what were typically perceived as the most critical transmission hours (peak load) to a focus on other load conditions and hours where there may be significant renewables on the system and relatively light load such as that of the light fall system condition may be appropriate. In the light fall system condition case, the transmission expansion is driven by the renewable generation additions and the high contribution of wind resources assumed in creating this condition. (More detailed information on this may be found in

10 Total from four expansions, duplicates removed

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the Tools and Models report.) Alternatively, the light spring condition resulted in the fewest added projects, lowest capacity and lowest cost (excluding the heavy summer condition).

The LTPT transmission results and associated power flow analysis depend on three main factors: load level, generation dispatch, and the existing transmission system (and associated physical properties). The load level varies for each of the system conditions and the starting point transmission system is the same for every expansion. Importantly, the generation selection (installed capacity) is the same for all four tested transmission system conditions, but the dispatch levels vary (e.g., heavy summer vs. light fall). Different loads and different generator dispatches will result in unique line overloads for each of the four system conditions causing different transmission expansions to be selected for each condition. However, there may also be similar overloads in two or more conditions, thus prompting the addition of the same or similar expansions in each system condition.

More can be learned by viewing the transmission expansion results, selected generation results, and load distribution simultaneously.

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Heavy SummerFigure 22 shows the LTPT expansion, CCTA, generation dispatch, and load distribution for the heavy summer system condition. The major transmission expansions deliver generation surpluses in the East and Northwest to the generation deficit California and Basin. The summer dispatch had relatively few renewables on the system Interconnection-wide (California is the exception given the large solar dispatch).

Figure 22: Heavy Summer LTPT Expansions, CCTA, and State Generation Dispatch and Load

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Light SpringFigure 23 shows the LTPT expansion, CCTA, generation dispatch, and load distribution for the light spring system condition, which had a significant renewable dispatch. There were significantly more hydro generation dispatched in the Northwest, which coincides with spring runoff and historically high hydro generation. The light spring condition was a daytime hour with large renewable dispatches, which is evident across the Western Interconnection as there are much more renewable than in the heavy summer system condition. The major transmission expansions were in the south and east portions of the Western Interconnection. The expansions deliver New Mexico’s large surplus of generation to generation deficit Colorado and the Basin states.

Figure 23: Light Spring LTPT Expansions, CCTA, and State Generation and Load

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Light Fall Figure 24 shows the LTPT expansion, CCTA, generation dispatch, and load distribution for the light fall system condition, in which the major of the Western Interconnection appears to be resource deficit. The majority of the expansions in the light fall system condition were added from the Northeast, Southeast, and Mexico to the rest of the Western Interconnection, which was resource deficit. The light fall hour featured a significant penetration of renewable generation despite the light fall hour falling on a nighttime hour. This system condition featured the highest wind dispatch contribution of any of the other system conditions, which more than made up for the absence of solar generation.

Figure 24: Light Fall LTPT Expansions, CCTA, and State Generation and Load

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Heavy WinterFigure 25 shows the LTPT expansion, CCTA, generation dispatch, and load distribution for the heavy winter system condition. The major transmission expansions were from the northeast, south, and northwest to the west and central portions of the Western Interconnection, delivering resource surpluses to areas with resource deficiencies.

Figure 25: Heavy Winter LTPT Expansions, CCTA, and State Generation and Load

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Expansion InterpretationAs with most models, the LTPT results are not intended to be used explicitly and directly, or to be used as an absolute depiction of what would occur under a particular modeled future – judgment and interpretation are essential. This is especially the case when using the LTPT, which provides a wide scope of potential interdependent transmission and resource investments across a range of possible futures at the necessary expense of reduced operational detail. Upon reviewing the overall results and those stemming from the four system conditions, the transmission expansion interpretation is presented in Figure 26. The interpreted expansion is not intended to explain or assess all of the expansion candidates that were selected. Many of the expansions are short and relatively low-capacity circuits that will be handled by local reinforcement or the regional planning efforts. TEPPC is concerned with transmission that has an Interconnection-wide impact and the interpreted expansion was developed with that in mind. There are three basic elements of the overarching interpretation of the 2032 Reference Case resource and transmission selections:

Reinforcements in Northwest and near the California Bay Area: These portions of the Western Interconnection are very sensitive to local and regional transmission changes and require a lower-level study (outside the scope of Interconnection-wide planning) to fully investigate.

Gather renewables: This portion of the interpreted expansion is based on the large number of expansions in the eastern portion of the Western Interconnection that connect WREZ hubs to the high-voltage grid. Connecting WREZ hubs to the key eastern transmission corridors will likely require additional transmission.

Deliver to load: The last portion of the expansion interpretation is tied closely to the “gather renewables” element. The generation in the eastern portion of the Western Interconnection proves to be some of the most cost effective. The “deliver to load” transmission expansion captures the large number of east-to-west expansions that cross-cut the Western Interconnection and deliver wind, solar and even gas generation located in the less densely populated east to the more densely populated west. It is not enough to connect major WREZ hubs (in which generation was selected) to the high-voltage grid, it is also necessary to ensure that there is enough downstream transmission capacity to deliver them to load centers. The exact length and location of these delivery expansions would be highly dependent on associated contracts from shippers and buyers. Thus, the generic lines presented in Figure 26 are intended only to represent the concept of delivering cost-effective eastern generation to loads somewhere in the West.

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Figure 26: 2032 Reference Case Results Interpretation

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Largest and Most Frequent ExpansionsFigure 27 depicts the combined transmission expansions that were the result of multiple system conditions. If an expansion showed up in multiple expansions, it is represented on the map to reflect this by the total number of occurrences in the form of parallel lines. For example, if a 500-kV double-circuit line was added in two of the four system condition expansions (e.g., heavy summer and light fall), then the map will show two parallel lines. (Each system condition-specific transmission selection is represented by only one line, even if that expansion involves a double circuit.)

Figure 27: All Expansions from All Four System Conditions

It is reasonable to conclude that expansions showing up in multiple studies are of greater need, or perhaps more valuable, than an expansion that shows up in only one transmission system condition expansion. The transmission expansions that were added in all four system conditions are presented in Figure 28. Since the system conditions represent a diverse set of grid operational conditions, it would be highly unlikely that four very different system dispatches under four very different system conditions would dispatch generation in a manner that caused the same transmission overload(s). Such is the case in the Reference Case, as the only

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expansions that showed up in all four system conditions are those near the California Bay Area and between the Washington load areas. As previously mentioned, these are indicative of these areas’ sensitivity to generation and transmission expansion rather than notable transmission expansions.

Figure 28: Expansions with Four Occurrences

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Expansions that were present in three system condition transmission expansions are presented in Figure 29. The expansions near the California Bay Area and between the Washington load areas show up again in this illustration due to the expansion sensitivity in these areas. The expansions in the eastern and southern portions of the Western Interconnection are driven by added renewable resources in those areas.

Figure 29: Expansions with Three Occurrences

Costs and Carbon EmissionThe LTPT makes generator selection decisions based on the LCOE of new resources. The capital costs of transmission are also considered when the model tries to provide the least cost transmission expansion. These two pieces of information allow for the relative comparison of LCOE and capital cost for each case. An energy-weighted LCOE for all resources in a study can be compared to that of a different study in order to better understand system operational costs in each future. Alternatively, the capital cost of the transmission and generation investment represents the expenditure that would be required in order to achieve this future. Comparing these two metrics provides a useful insight into the potential costs faced by the Western Interconnection under a variety of futures.

Figure 30 shows the capital cost and the weighted average LCOE for the 2032 Reference Case and each of the four WECC scenarios. The LCOE used for the generation optimization includes a CO2 cost component; however, the LCOE used in Figure 30 is from a “cost to society” perspective and does not include the CO2 cost component. This cost, in reality, would be repaid

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to society in the form of societal benefits or other monetary “payback” investments (e.g., reduced taxes, investments in clean energy, alternative investments).

Figure 30: Capital Cost and LCOE Results (2012 dollars)

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Resource costs, load and CO2 pricing assumptions, along with the necessary transmission build out, drive which resources are selected by the model. These resources have varying costs, as presented in Figure 30. The resource portfolio and the assumed dispatch of these resources also results in varying levels of CO2 output, as shown in Figure 31. 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 31: CO2 Production

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Study SummaryThere are several key takeaways that effectively summarize the 2032 Reference Case findings. Importantly, overcoming the study limitations mentioned previously could substantially change these finding.

Renewable generation was selected based on cost competitiveness State-enacted RPS requirements were modeled in the 2032 Reference Case. However, the amount of required incremental renewable energy generation in the 2022-2032 timeframe is relatively small because most state RPS requirements do not expand beyond 2022. This means that states simply have to add enough renewable generation to keep up with RPS energy at the required fraction of total load. In some states, load growth is low, thus they are required to add very few renewables. However, due to the low cost of some renewable energy in the model, renewable resources (mostly wind) were selected based on economics and not policy requirements. This means that renewables were cost competitive with more conventional generation such as gas CC in the 2022-2032 timeframe.

New coal-fired generation is not economic with a $37.11 per metric ton CO2

priceThe LTPT selects resources to meet energy needs based on LCOE. The model showed great preference for wind and gas to meet the Western Interconnection’s energy needs. Coal generation had an LCOE that made it non-competitive when compared to these other more economic generation. The assumed CO2 price of $37.11 per metric ton was a key driver of the high LCOE for coal.

Solar Penetration is Trending Higher than Envisioned in the 2032 Reference Case (and 2022 Common Case)The latest developments and expectations now indicate that the level of solar penetration should exceed those levels depicted in the 2022 Common Case and the 2032 Reference Case. Whereas the 2032 Reference Case contains about 14 GW of solar generation Interconnection-wide, the most recent planning cases in California alone contain about 11 GW of solar in 2022, most of which is now operating, contracted, or contained within large DG procurement queues in 2013 (including behind-the-meter solar generation would further increase this figure). This growing role for solar reflects the decline of costs and increase in competitive pricing. Updated CPUC staff data on contracting, aggregated to protect confidentiality, indicate a 50 percent reduction in solar PV bid prices between the 2009 and 2012 RPS solicitations. Furthermore, the average solar PV bid price from the 2012 RPS solicitation was approximately 25 percent lower than the average bid price for all other (non-solar PV) technologies combined.

Levelized cost of energy (LCOE) for new gas and wind resources are very close The LCOE of wind and gas resources throughout the Western Interconnection are very close. They are separated by only ~$10/MWh. Key assumptions (e.g., resource capital costs, CO2 price, transmission cost or gas price) could “swing” the 2032 Reference Case solution in either direction, resulting in drastically more or less wind or CC resources being selected by the

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model. This would have a large impact on the transmission expansion results as wind is typically remote from loads while gas resources can be located near more populous areas. However, additional pipeline and infrastructure costs for load-located new gas may tip the balance back to wind. This observation emphasizes the importance of key assumptions in directing resource selection.

Transmission needs are driven primarily by renewable generation additionsThe 2032 Reference Case transmission expansions fall into two high-level categories: 1) renewable collection and 2) renewable energy delivery to load centers. The expansions gather renewable resources in the eastern portion of the Western Interconnection and deliver those resources to loads in the West. Although the 2032 Reference Case also includes significant gas resource additions, these tend to be located near load centers and do not drive significant transmission expansions.

Sufficient dispatchable resources exist to meet peak needs, but system flexibility for balancing variable resources may be a concernBased on results from the 2032 Reference Case, the Western Interconnection would have adequate resources to meet peak demand and annual energy needs without relying on output from VG resources, such as wind and solar. However, this analysis does not guarantee delivery of these resources across all locations and hours. Furthermore, the modeled generator dispatch did not assume such a future, and variable resources were selected for their energy value (and also contributed somewhat to peak needs). However, due to the variability of these resources, there is value in investigating how the Western Interconnection would meet needs without these variable resources. Variable generation penetration in the 2032 Reference Case exceeds that in the 2022 Common Case by a substantial but not great amount, due largely to load growth. Modeling of flexible reserves commitment in the more operationally detailed 10-year studies did not show any flexibility shortfall for the 2022 Common Case. It is thus reasonable that the 2032 Reference Case resource mix could be flexibility-sufficient or close to it, if tested via an appropriately detailed analysis.

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