2032 scenario 3 study report · web viewfigure 9 shows a supply curve for scenario 3 that presents...

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 3 – Focus on Short-term Consumer Costs:

“This is a world in which the failure to regulate the financial sector coupled with inadequate policy choices exacerbate the detrimental impacts of the 2008-2009 trifecta of a credit crisis, the burst of the housing bubble, and massive government deficits. Economic growth in the United States, including the Western Interconnection, is restrained for two decades. Similar to the long-term doldrums that hit the Japanese economy starting in the 1990s, a large overhang of debt constrains both lending in the broader economy and government investment initiatives to spur growth. Increases in taxes, failure to invest in the future, and worsening wealth disparities also play a role in slowing growth. Societal values are shaken by a loss of confidence in financial institutions and in the regulation of these institutions. Even as values like the protection of natural resources remain, they are balanced against economic costs in times when scarcity is felt in society.

States hit particularly hard by the housing crisis in the Western Interconnection are very slow to recover as they dig out of years of real estate overcapacity. Unemployment remains above historic levels, keeping consumer spending on a slow-growth trajectory. Within the electricity sector, the slower economic growth discourages power companies in all sectors from taking large risks and causes most companies to be cautious when

of 26

Scenario 3Focus on Short-term Consumer Costs

September 19, 2013

2032 Scenario 3 – Focus on Short-term Consumer Costs

investing in and implementing new technologies and continues delays in transmission investment.

Those technologies that are low risk, proven and assured of cost recovery proceed at a steady pace. Low natural gas prices encourage the continued use of traditional power generation technologies in concert with improving renewable technologies that meet portfolio standards required by legislators and regulators. Expansion of transmission systems occurs mostly within states as states focus on self-sufficiency and minimal voluntary power exchanges occur to meet system reliability.”

In summary, Scenario 3 depicts a future “Focused on Short-term Consumer Costs” with the following key characteristics:

Slow and narrow economic growth/stagnating standards of living];

Evolutionary technology development that follows current patterns; and

A policy theme of slow growth that leads to tough choices and focuses on keeping rates low.

A thorough description of Scenario 3 “Focus on Short-term Consumer Costs” 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 3 features relatively lower levels of technology innovation and lower economic growth as compared to the 2032 Reference Case. This chart 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.

of 26


Figure 1: Scenario Drivers

Key QuestionsScenario 3 hopes to answer some key stakeholder questions, including the following:

What is the generation build-out associated with this scenario? What transmission is added by the LTPT in the 2022-2032 timeframe? How did study assumptions impact CO2 emissions? How do the aforementioned results compare with the 2032 Reference Case and the

other SPSG Scenarios?

Study LimitationsIn the next planning cycle, WECC can build upon its early success with the LTPT and the 20-year study methodology by making improvements to the model to enhance the tool’s ability to address stakeholder study requests. A number of limitations and areas for enhancement have been identified and are described in the 2032 Reference Case report. A more extensive list of model limitations is provided in the Tools and Models report, where the LTPT model is explained in detail.

of 26


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 assumption 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 3, however, the assumptions described here may be an addition or alternative to those assumptions used in the Reference Case.

Key Scenario 3 Metrics in 2032There are six key metrics that can be used to quickly define Scenario 3, relative to the 2032 Reference Case, as shown in Table 1.

Table 1: Scenario 3 Key Metrics

Parameter 2032 Reference

CaseScenario 3

Gas Price (2012$/mmBTU) $6.90 $6.90

Cost of Carbon (2012$/metric ton) $37.11 $0.00

Peak Demand Compound Annual Growth Rate (CAGR)* 1.25% 0.85%

Energy CAGR* 1.54% 1.14%

RPS State policy -50% from state policy levels

Technology Capital Costs Reference Case values

Smaller reductions in solar and wind capital costs than in the 2032 Reference Case

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

Detailed Scenario 3 Metrics in 2032In addition to the key metrics used to describe Scenario 3, there are a number of other input parameters that could change from the 2032 Reference Case to Scenario 3. These metrics and their changes from the 2032 Reference Case (if applicable) are outlined in .

of 26


Table 2: Scenario 3 Metrics

Input Parameters Units 2032Reference Value Scenario 3

Fuel & Carbon CostsNatural Gas 2012$/MMBtu $6.90 $6.90Coal 2012$/MMBtu $2.84 $2.84Carbon 2012$/metric ton $37.11 $0.00Capital Cost Reductions

Geothermal % below 2012 cost 0% 0%

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

Solar PV % below 2012 cost 31% 15%

Solar Thermal % below 2012 cost 25% 12%

Wind % below 2012 cost 8% 0%

Net Energy for LoadBase Energy GWh 1,163,526 1,118,518Policy-Driven Energy Reductions GWh 0 0

Policy-Driven Electrification GWh 0 0WECC Net Energy GWh 1,163,526 1,118,518Implied Growth Rate, Unadjusted Load %/yr 1.54% 1.14%

Implied Growth Rate, Adjusted Load %/yr 1.54% 1.14%

Coincident Peak DemandBase Demand MW 198,715 191,023Policy-Driven Demand Reductions MW -3,780 -3,780

Policy-Driven Electrification MW 0 0WECC Coincident Peak MW 194,935 187,243Implied Growth Rate, Unadjusted Load %/yr 1.45% 1.05%

Implied Growth Rate, Adjusted Load %/yr 1.25% 0.85%

Renewable Goals

State RPS % of Load Energy Current state policies Current state policies,

reduced by 50%

Federal RPS % of Load Energy none none

In-state RPS Requirement % of RPS requirement

Current in-state preferences applied to RPS

Current in-state preferences applied to RPS

of 26


Input Parameters Units 2032Reference Value Scenario 3

requirements requirements

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, in the order shown:

Local policy goals – for most study cases, including the 2032 Reference Case, this is generally distributed generation (DG) set asides specified in state 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 AdditionsDue to stagnating levels of economic growth, Scenario 3 assumed a lower energy and system peak than the 2032 Reference Case, thus fewer resources were added by the model in Scenario 3. The final resource capacity of Scenario 3 in 2032 was 314,000 MW. This value is less than the 2032 Reference Case capacity, which was 325,000 MW. As mentioned, this lower capacity was driven by the lower loads and the fact that high capacity factor resources, mainly gas, were added in the 2022-2032 timeframe. Based on this, fewer resources were needed to meet loads. Furthermore, the low loads and decreased renewable portfolio standards (RPS)

of 26


requirements reduced the amount of renewable resources that were required by the model. In addition, some biofuel capacity was “retired,” or not selected by the model in Scenario 3 due to its being non-economical.

The total resource capacity of Scenario 3 in 2032, broken down by resource type, is provided in Figure 2. Gas-burning resources represent 42 percent of the Western Interconnection’s capacity. Wind is the most predominant renewable resource and makes up 13 percent of the capacity. This large preference for conventional resources is driven by the study assumptions, particularly the lack of a carbon cost and only marginal decreases from present day renewable energy costs. No 2022 Common Case generators were retired in this scenario. Note that Figure 2 introduces the term “gap resources,” which are gas resources used in Alberta to serve load.

Figure 2: Scenario 3 Total 2032 Generation Capacity

of 26


Figure 3 shows the Interconnection wide net change in resource capacity. Approximately 3,000 MW of existing 2022 Common Case generation was displaced by new additions of Solar and Wind generation. Of the total Interconnection wide generation capacity, 15 percent consists of new generation additions and 85 percent consists of existing 2022 Common Case generation.

Figure 3: Net Change in Resource Capacity (MW)

of 26


The LTPT had many options when selecting resources to meet policy, energy and capacity goals. These options were spread across many states in the form of gas generation at key gas hubs and load area hubs, new renewable generation in Western Renewable Energy Zone (WREZ) hubs, or incremental distributed generation (DG) at load area hubs. This diversity allowed the model to pick the most economic resources while considering the cost of transmission in that decision. Figure 4 shows the state and resource breakdown for the Western Interconnection’s total capacity (MW) in 2032 under the Scenario 3 future. Figure 5 shows the same information geospatially. California has the largest portion of the Western Interconnection’s resources. Interestingly, gas-fired resources make up a large portion of almost every state’s generating capacity under this low-cost, consumer-focused future.

Figure 4: Scenario 3 Total 2032 Generation Capacity (by State)

of 26


Figure 5: Scenario 3 Total 2032 Generation Capacity

The previous discussion focused on the total generation capacity of the Western Interconnection in 2032. However, the incremental transmission added from 2022 to 2032 is driven by the generation additions during that same time period. New generation drives new transmission in the model. As such, there is value in investigating the type and location of incremental resources as it helps to justify and explain the transmission expansions.

Scenario 3 added only 48,000 MW of generation in the 2022-2032 timeframe, while the 2032 Reference Case added 57,000 MW. These additions for the Scenario 3 future are broken down by resource type in Figure 6. Notice that 83 percent of the incremental generation was from gas-burning resources. Wind was the second most prevalent addition, but only represented 10 percent of the capacity added from 2022 to 2032. The lack of a carbon cost and the relatively high cost of renewables (compared to the 2032 Reference Case) in this future caused the majority of the incremental generation to be gas resources.

of 26


The incremental resources added for Scenario 3 are further broken down by state and resource type in Figure 7. Figure 8 shows the same information geospatially. Additional gas resources were distributed fairly evenly Interconnection-wide. This is an explainable result given the LTPT goals of minimizing cost. Gas can typically be built close to load, thus providing an economic resource that requires little transmission expansion. Almost all of the wind resources added in Scenario 3 were added in Wyoming.

Figure 6: Scenario 3 Added Generation Capacity

of 26


Figure 7: Scenario 3 Added Generation Capacity (by State)

of 26


Figure 8: Scenario 3 Added Generation Capacity

Levelized Cost of EnergyThe LTPT selects resources based on the LCOE. The use of LCOE in the LTPT is described in more detail in the 2032 Reference Case report. Comparing the levelized cost of resources added during the 2022-2032 timeframe in Scenario 3 allows for the identification of the most economic resources, as well as information about how resource costs compare on average. Figure 9 shows a supply curve for Scenario 3 that presents the resources added from 2022 to 2032, ranked and sorted by resource type and average LCOE. This supply-curve format allows the user to see how much capacity (MW) of a resource was selected, and at what average cost (LCOE) is representative of these resources. Note that the LCOE presented on the chart is a weighted average and careful interpretation is required. For example, the ~4 GW of wind installed at a cost of $70/MWh should not suggest that there is ~4 GW of wind available at that energy cost in this scenario. Most of the wind is available at a greater or lower cost than

of 26


$70/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

Figure 9 helps to show variances between the amount and average price of selected resources. The least expensive resource, on average, was small hydro RPS units that essentially represent hydro upgrade projects that can be developed for a very low capital cost and are economic to operate. However, there are few of these resources available. Wind was the second most economic resource. However, there are only a small amount of potential wind resources with capacity factors that allow the resource to compete (economically) with gas under this no-carbon cost and high wind cost future. The model selected nearly 40 GW of gas generation because of this LCOE differential. Compared to gas, only high capacity factor wind resources were economic in this future. Lastly, the small scale of the X-axis in Figure 9 is important. The total amount of resources added by the model in this scenario was much less than the 2032 Reference Case and other WECC scenarios.

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 3 study, the system peak reserve was 60,900 MW (33 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.

of 26


Comparing levels of flexibility from study case results with levels from a system known to be reliable (i.e., today’s grid) enables the identification of potential future operational challenges and areas for additional evaluation. To make this comparison, TEPPC developed the Flexible Resource Indicator, the calculation for which is shown below. A detailed description of the Flexible Resource Indicator and its use in the 20-year analysis can be found in the 2032 Reference Case report.

Flexible Resource Indicator = Flexible Generation 1 Capacity Variable Generation Capacity

The indicator is provided as an aggregated Interconnection-wide value. For example, a Flexible Resource Indicator equal to 5 means that Interconnection-wide there is 5 MW of flexible generation for every 1 MW of VG.

The Flexible Resource Indicator values are presented in Figure 10. The calculation was performed for 2012 and 2022 using the 2022 Common Case data to provide context. The information shows that in the 2022 Common Case there are approximately 2 MW of Flexible Generatoin 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 present on the system in 2012.

Scenario 3 has a higher 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. However, due to the assumptions in the Scenario 3 future, the second 10-year timeframe (2022-2032) features the addition of mostly gas resources. This is driven by lower RPS requirements and no carbon costs, which result in gas being the most economic resource available to serve most of the additional load. By adding more gas and fewer renewables, the Western Interconnection increases its resource flexibility in the 2022-2032 timeframe under this future.

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

of 26


Figure 10: Flexible Resource Indicator

The complementary nature of wind and solar is not considered in the Flexible Resource Indicator. The indicator is designed to point out operational complexities that may arise with large penetrations of VG. The indicator is also useful in identifying futures that look similar to the grid today, or those futures that may look and operate substantially differently. A more detailed and thorough analysis is required to evaluate the plausibility of operating these types of high-VG systems. The indicator’s value is by no means conclusive or prohibitive of these futures.

Transmission ResultsWhen reviewing the transmission results, recall that these are modeling results based on the input parameters. The results can inform choices about transmission expansion, but many factors contribute to ultimate decisions about building or not building any specific transmission expansion. As mentioned previously, all of the transmission results are AC expansions. The LTPT has the capability to evaluate and choose DC expansions; however, these were not fully explored due to time restrictions.

The LTPT consistently showed expansions near the California Bay Area and between the Washington load areas. These are due to the high concentration and close proximity of load areas in these portions of the Western Interconnection. The focus of the LTPT studies is on transmission connections between load areas in the Western Interconnection, thus assumptions were made about transmission reinforcements within TEPPC load areas and between close proximity load areas - refer to the Tools and Models report for more detail on the LTPT modeling and limitations. The flows between load areas can depend on the reinforcement internal to load areas, especially when load areas are in close proximity and they are all reinforced internally. Such is the case with the California Bay Area and between the Washington load areas. These portions of the Western Interconnection are very sensitive to transmission and generation dispatch changes, whether they are regional or internal to load areas. In future LTPT models, it may be better to aggregate load areas that are in close proximity so that the focus remains on Interconnection-wide planning.

of 26


Expansions that were added in all of the system condition transmission expansions are shown in Figure 11. Expansions that were added by the transmission model in any one of the four system conditions are shown on the map. Some expansions only appeared in one system condition, while there were other expansions added in all of the conditions analyzed. The Scenario 3 overall expansion was very small in comparison to the 2032 Reference Case and the other WECC scenarios. Scenario 3, which focused on short-term consumer costs, had relatively small resource requirements due to the lower loads and a decrease in RPS requirements (50 percent less than current state requirements). Based on this, the model added only 47 GW of generation, mostly gas burning resources close to load centers. With few incremental remote resources there were fewer line overloads, and consequently a small transmission expansion in this future.

Figure 11: Scenario 3 All Expansions

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. The Common Case Transmission Assumptions (CCTA) included in the 2022

of 26


Common Case represent the set of high-probability transmission projects assumed in the analysis were also “added” in the 2012-2022 timeframe. Thus, the total transmission additions between 2012 and 2032 would be those added by the LTPT from 2022-2032, as well as the set of CCTA projects that were included in the model. A map of both sets of these projects is shown in Figure 12.

Figure 12: Scenario 3 All Expansions and CCTA

of 26


The overall expansion from 2022 to 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 the heavy summer condition is presented in Figure 13. There were very few expansions in this system condition, which is expected since the majority of the resource additions were gas and were closer to load than the added renewables. The major expansions are from the generation surpluses in the east to the central and western portions of the Western Interconnection which are generation deficient.

Figure 13: Scenario 3 Heavy Summer LTPT Expansion, CCTA, and State Generation and Load

of 26


The light spring LTPT expansion, CCTA, generation dispatch, and load distribution is shown in Figure 14. Again, there were very few expansions in this system condition. As with the heavy summer system condition, the major expansions are from the generation surpluses in the east to the central and western portions of the Western Interconnection which are generation deficient.

Figure 14: Scenario 3 Light Spring LTPT Expansion, CCTA, and State Generation and Load

of 26


The light fall LTPT expansion, CCTA, generation dispatch, and load distribution for Scenario 3 is shown in Figure 15. The major expansions are from the generation surpluses in Wyoming to Colorado and Utah which are generation deficient. Recall that the only incremental remote resource added in this scenario was a ~4,000 MW of wind added in Wyoming. The rest of the incremental generation was gas resources. In this particular system condition, the Western Interconnection load was so low that a significant amount of balancing resources (gas) were decremented to obtain a load-resource balance, which lead to Colorado’s and Utah’s generation deficiency.

Figure 15: Scenario 3 Light Fall LTPT Expansion, CCTA, and State Generation and Load

of 26


Figure 16 shows the Scenario 3 heavy winter system condition LTPT expansion, CCTA, generation dispatch, and load distribution. Recall that the only incremental remote resource added in this scenario was a ~4,000 MW of wind added in Wyoming. The rest of the incremental generation were gas resources and were located close to load – thus reducing the need for large scale transmission. The major expansions are from the generation surpluses in the south and east to the central portions of the Western Interconnection which are generation deficient.

Figure 16: Scenario 3 Heavy Winter LTPT Expansion, CCTA, and State Generation and Load

of 26


There were several expansions that were added in more than one of the system condition expansions. From the high level planning perspective, these expansions may represent the most critical additions since they are needed under a broad array of conditions in this future, which would likely result in a higher asset utilization as compared to an expansion which occurred in a single system condition. These “recurrent” expansions are shown in Figure 17 and were added in three or four of the four system condition expansions. The Northwest expansions were due to the modeling nuance previously explained. Therefore, the only true recurrent transmission expansions in Scenario 3 were added in the Wyoming area to facilitate exporting coal, gas, and wind generation.

Figure 17: Recurrent Expansions

of 26


Costs and Carbon EmissionFigure 18 shows the capital cost and the weighted average LCOE for the 2032 Reference Case and each of the four SPSG scenarios. Compared to the 2032 Reference Case, Scenario 3 had a low generation capital cost and low transmission investment. The average LCOE in Scenario 3 was about $2/MWh lower than in the 2032 Reference Case. This result of low energy and capital costs are consistent with Scenario 3’s theme – focus on consumer costs.

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

of 26


The resource portfolio and the assumed dispatch of these resources also result in varying levels of CO2 output, as shown in Figure 19. Scenario 3 has more CO2 output than the 2032 Reference Case. This is largely due to the incremental gas resources and the lack of new renewable resources. This result was expected as Scenario 3 depicts a future with no CO2 cost while the 2032 Reference Case had a $37/mTon cost for CO2. Without the carbon cost, CO2 output increased in Scenario 3 as compared to the 2032 Reference Case. However, it is interesting to note that despite the lack of a CO2 costs, emissions did not significantly increase from the level observed in the 2022 Common Case.

Figure 19: CO2 Production

of 26


Study SummaryThe following findings summarize the key results from Scenario 3 “Focus on Short-Term Consumer Costs”:

Small transmission expansionWith local gas resources being the primary resource addition, Scenario 3 resulted in a small transmission expansion. With the exception of wind resources with high capacity factor values added in Wyoming, there were few remote renewables added, and thus, a small transmission expansion.

Gas is preferred over coal, even without carbon costScenario 3 assumed a $0.00 per metric ton carbon cost. Despite the lack of carbon costs, gas was the most economic conventional resource for most of the incremental resource need, rather than coal.

Levelized cost of energy (LCOE) and capital costs are lowConsistent with the future described in Scenario 3, results suggest that a future focused on short-term consumer costs facilitates low energy costs and low capital cost expenditures on transmission and generation, provided that natural gas costs remain low.

of 26

2032 scenario 3 study report · web viewfigure 9 shows a supply curve for scenario 3 that presents...

Documents