IMPACT OF HIGH SOLAR AND ENERGY STORAGE LEVELS ON WHOLESALE POWER … · 2016. 4. 26. · IMPACT OF HIGH SOLAR AND ENERGY STORAGE LEVELS ON WHOLESALE POWER MARKETS BLACK & VEATCH

IMPACT OF HIGH SOLAR AND ENERGY STORAGE LEVELS ON WHOLESALE POWER MARKETS

BENSON JOE – BLACK & VEATCH

MON HONG – BLACK & VEATCH

JOHN STERLING – SOLAR ELECTRIC POWER ASSOCIATION

1 JUNE 2015

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BLACK & VEATCH / SEPA | Table of Contents i

Table of Contents

Executive Summary .............................................................................................................................................. 1

1.0 Introduction .......................................................................................................................................... 1-1

2.0 Modeling Approach ............................................................................................................................ 2-1

2.1 Cases Studied ......................................................................................................................................... 2-2

2.2 Energy Storage Modeling .................................................................................................................. 2-4

3.0 Modeling Results ................................................................................................................................. 3-1

3.1 Net Load Impacts ................................................................................................................................. 3-1

3.2 Energy Mix .............................................................................................................................................. 3-7

3.3 Curtailments ........................................................................................................................................... 3-8

3.4 Imports/Exports ................................................................................................................................ 3-10

3.5 CO2 Emissions ..................................................................................................................................... 3-11

4.0 Conclusions............................................................................................................................................ 4-1

5.0 Next Steps ............................................................................................................................................... 5-1

5.1 Additional Areas for Research and Focus .................................................................................. 5-1

Appendix A. Black & Veatch Energy Market Perspective ................................................................ 5-3


BLACK & VEATCH / SEPA | Table of Contents ii

LIST OF TABLES Table 1-1 Flexible Resource Adequacy Categories ..................................................................................... 1-2

Table 2-1 Production Cost Model Case Descriptions ................................................................................. 2-2

Table 2-2 Capacity Expansion Plan by Case .................................................................................................. 2-3

Table 3-1 Summary of Load Weighted Average Prices at SP15 (2014$/MWh) ............................. 3-5

Table 3-2 Generation by Fuel Type ................................................................................................................... 3-8

LIST OF FIGURES Figure 1-1 CAISO Forecast of Total System Flexible Capacity Requirements ................................... 1-3

Figure 2-1 Total New Capacity Additions by Case ........................................................................................ 2-3

Figure 2-2 Modeled SCE Average Energy Storage Profile ......................................................................... 2-5

Figure 2-3 Modeled SCE Average Energy Storage Profile High Storage .............................................. 2-6

Figure 3-1 2030 Average California Load and Renewable Energy ........................................................ 3-2

Figure 3-2 2030 California Annual Average Net Load ................................................................................ 3-3

Figure 3-3 Average Daily Flexible Ramping Capacity Requirements ................................................... 3-4

Figure 3-4 SP15 Load Weighted Average LMP – 2030 Annual Daily Profile ..................................... 3-6

Figure 3-5 SP15 Load Weighted Average LMP – August 2030 Daily Profile ..................................... 3-6

Figure 3-6 SP15 Load Weighted Average LMP – January 2030 Daily Profile .................................... 3-7

Figure 3-7 Potential Solar Curtailments by Month....................................................................................... 3-9

Figure 3-8 Potential Solar Curtailments by Hour.......................................................................................... 3-9

Figure 3-9 Average Monthly Flow on Path 46 (West of River) ............................................................. 3-10

Figure 3-10 California CO2 Emissions ................................................................................................................. 3-11


BLACK & VEATCH / SEPA | Executive Summary ES-1

Executive Summary The State of California has long been a leader in advancing clean technology through energy policies that promote the adoption of renewable energy and, more recently, energy storage. In addition to significant wind and geothermal resources developed in the state, SEPA data show that California utilities installed over 3,000 MW of solar in 2014 alone and have installed over 8,600 MW of solar total, more than the rest of the states combined. This focus on solar energy development has been driven primarily by direction from the State legislature in the form of a 33% by 2020 Renewable Energy Standard. Recently, the legislature has added a storage mandate through AB2514, which requires a cumulative 1,325 MW of investment by California’s investor owned utilities (IOUs) by 2020. While these targets for renewables and storage are already quite robust, as the state’s utilities have demonstrated the ability to reach these goals, policymakers have begun discussing even more aggressive mandates both for renewables generation and for storage.

Together, Black & Veatch and the Solar Electric Power Association (SEPA) have partnered to study what these policies will likely mean to the physical makeup of the conventional resource mix, how market pricing will likely be affected, and consequently where the industry should look for future deep-dive studies. Developing a strong understanding of the hour-to-hour interplay among the mix of all of the resources in California requires a set of use cases for comparison purposes. The following use cases were identified to both provide guidance on how current and potential policies may impact the market:

Base Case, which assumes the continued trajectory of a 33 percent renewable portfolio standard (RPS) and utility storage mandate of 1,325 megawatts (MW) of energy storage.

Natural Gas Alternative, which assumes no additional investment in renewables from today, with natural gas capacity additions meeting future load growth; i.e. a proxy case for a non-RPS generation portfolio.

High Solar Case, which aligns with Governor Brown’s desire to increase the California RPS to 50 percent by 2030, using primarily solar generation to go from 33 percent to 50 percent RPS.

High Solar + Storage Case, which takes the 50 percent RPS requirement and 10,000 MW of energy storage (8,700 MW incremental).

The project team modeled these cases using Black & Veatch’s PROMOD-based production cost forecasting model and proprietary battery storage model to understand the impacts of solar and storage investments, specifically on southern California (SP15) in the year 2030.

IMPACTS KEY OBSERVATIONS

Market Pricing The cases with increased renewable energy show clear reductions in both weighted-average locational marginal pricing (LMPs) as well as in the on-peak to off-peak spread compared to the Natural Gas Alternative.

The Base Case load-weighted market price was $1/MWh cheaper than the Natural Gas Alternative, with the High Solar Case and High Storage Case $5.28/MWh and $3.61/MWh less expensive, respectively, compared to the Natural Gas Alternative Case.


BLACK & VEATCH / SEPA | Executive Summary ES-2

IMPACTS KEY OBSERVATIONS

Flexible Capacity Needs

Pursuing additional renewable resources will require the addition of flexible capacity to manage afternoon ramping requirements, with approximately 12,000 MW of new flexible capacity required in the High Solar Case compared to the Base Case.

If California did not pursue additional renewable resources, it is likely no new flexible capacity would be required.

Most new flexible capacity would be a combination of natural gas combined cycles and traditional simple cycle gas turbines, though

Significant levels of energy storage can effectively replace the need for quick start capacity as the flexible resource addition.

Energy storage, when dispatched based purely on energy price arbitrage, significantly reduces the maximum 3 hour ramping requirement in the California Independent System Operator (CAISO) and leads to a flatter overall system load shape.

System Curtailments

No curtailments were forecast under the Base Case; however, the high Solar 50 Percent RPS Case did show solar curtailments, particularly in winter and shoulder months.

High levels of energy storage significantly reduced solar curtailments, from nearly 500 curtailment events in the High Solar Case to under 100 in the High Storage Case.

CO2 Emissions The Base Case, with a 33% RPS standard, reduces CO2 emissions by 14% compared to the Natural Gas Alternative Case, clearly showing the environmental value of the current portfolio

Moving towards a 50% RPS standard can reduce CO2 emissions by an incremental 18% over the Base Case.

It is clear that increased solar and other renewable energy on the California grid will have significant benefits in terms of reducing wholesale market clearing prices, reducing imports and reducing power sector carbon emissions. While the increase in solar will require more fast ramping capacity and create more curtailments, energy storage can readily address both issues.. This study lays the foundation for more detailed analyses of a wider range of scenarios, which can be used to understand the interplay between new transmission capacity, alternative storage dispatch algorithms, the role of expanded balancing areas and an energy imbalance market (EIM,) the dynamics of additional wind capacity additions, and the effect of solar energy and energy storage on sub-hourly dispatch, as well as for a variety of commodity price and energy demand assumptions. This further work can then be used to help guide future resource planning, business strategy, and policy discussions and decisions as stakeholders seek to understand how best to meet California’s energy policy goals.


BLACK & VEATCH / SEPA | Introduction 1-1

AB

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700 MW Transmission Level

425 MW Distribution Level

200 MW Customer Sited

1.0 Introduction In his inaugural speech opening his fourth term as the Governor of California, Jerry Brown laid out an aggressive plan to raise the Renewable Portfolio Standard (RPS) target to 50 percent by 2030. California utilities are already well on their way to reach their legally mandated goal of procuring 33 percent of their electricity from renewable sources by 2020. Leading the way to the 33 percent RPS target is the solar power industry, which has seen a dramatic decline in the price of solar generation. With many existing signed solar power purchase agreements (PPAs) already in place, the California electricity grid is certain to see more solar energy being integrated into the system as more commercial solar projects start to come on line over the next several years.

As California moves closer to achieving its 33 percent RPS target, with the potential for a further increase to 50 percent by 2030, the high solar and renewable energy penetration is anticipated to help reduce the marginal cost of energy for California as well as help California achieve its carbon targets.

However, the California Independent System Operator (CAISO), the transmission organization responsible for maintaining grid reliability for most of California, is concerned about the future impact to the system.1 In recent years, the CAISO has sounded the alarm on the impending “duck curve”.2 As more solar is added to the system, the CAISO will experience very low net loads during the day followed by a fast increase in net load during the late afternoon when generation from solar is ramping down, which coincides with energy demand ramping up. The duck curve creates legitimate concerns that there will not be enough flexible capacity on the system to handle the huge ramping (i.e., load following) requirement that occurs daily as well as the potential for overproduction during low load periods. This overproduction could require significant curtailment of generation, and potentially in lower grid stability and reliability.

To help address the issues associated with high renewable energy penetration, AB2514, passed in October 2013, instructs California’s IOUs Pacific Gas & Electric (PG&E), Southern California Edison (SCE), and San Diego Gas & Electric (SDG&E) to expand their electricity storage capacity and procure 1,325 MW of electric and thermal storage by 2020, segmented by connection level.

The continuing price decline in solar panels, combined with expected higher prices for natural gas and proposed greenhouse gas (GHG) emissions allowance regulations, makes solar energy a prime resource to offset natural gas and coal generation in the Western Electricity Coordinating Council (WECC) Interconnection. As policymakers debate the merits of increasing the RPS in California to 50 percent by 2030, one of the many uncertainties that the energy industry needs to understand is what solar and increased energy storage will do to wholesale electricity prices. To help address this important question, Black & Veatch and SEPA have teamed together to examine the impact solar and energy storage have on wholesale electricity prices in the CAISO market.

The results of this study are particularly important because of the increasing role that solar is playing in the energy mix. Solar energy is the fastest growing resource in the nation, with 5,300

1 Not all utilities in California are members of CAISO. CAISO is a balancing authority and is responsible for

overseeing the operations of the transmission system and ensuring fair and open access transmission. 2 Shown in Figure 3-2.



MW being added in 2014. California is by far the Nation’s leading state when it comes to solar energy. SEPA data show that California utilities installed over 3,000 MW in 2014 alone and have installed over 8,600 MW total, more than the rest of the States combined. In 2015 the CAISO is expected to have around 10,000 MW of solar on the system during the summer.

The California Public Utilities Commission (CPUC) Resource Adequacy (RA) program was implemented in the early 2000s as a direct response to address system reliability concerns brought about by the California energy crisis. The CPUC RA program requires utilities that are under the jurisdiction3 of the CPUC to procure enough firm capacity to meet a 15 to 18 percent reserve margin. However, the CPUC’s RA program did not originally take into consideration operating limitations of specific technologies.

Recent enhancements to the RA program created a sub-requirement focused on flexible capacity requirements based on operational limitations. In anticipation of more solar resources being added to the grid, enhanced resource adequacy requirements starting in 2015 will include a flexible capacity requirement to help integrate solar into the CAISO grid. Load serving entities (LSE) regulated by the CPUC will be required to procure flexible capacity in the future to address the fast-ramping capacity requirements voiced by the CAISO. The CAISO has spent a lot of time and effort studying the pending flexible ramping requirements. The Flexible Resource Adequacy Capacity (FRAC) requirement being implemented is intended to procure and incentivize the right type of resources onto the CAISO grid.

Table 1-1 lists the flexible capacity categories.

Table 1-1 Flexible Resource Adequacy Categories

Source: CAISO

Category 1 resources are the most flexible and have the fewest amounts of operational constraints. Category 1 resources essentially allow the CAISO to meet the morning and afternoon ramps on the

3 The three largest IOUs in California; Pacific Gas & Electric, Southern California Edison, and San Diego Gas &

Electric are under CPUC jurisdiction.

Category 1 (Base Flexibility):

•Meet minimum start requirements of either two starts per day or can ramp to cover the morning and late afternoon ramp.

Category 2 (Peak Flexibility):

•Resources must have flexible capacity that can be available to the CAISO market through economic bids submitted daily for at least 5 hours per day.

Category 3 (Super Peak Flexibility):

•Resources must have a minimum of 3 hours of run time per dispatch and availability for at least 5 flexibility-based dispatches per month.



system throughout the entire year and comprise the largest portion of flexible capacity needed. Category 2 resources such as traditional simple cycles generally have run hour limits and/or limitations on the number of starts but can still provide some flexible capacity. Categories 3 resources are the most restrictive and can be used to meet only 5 percent of the total CAISO FRAC requirement. Under the FRAC program, Category 1 resources can be used in place of Category 2 and 3 resources.

Figure 1-1 is a forecast of ramping requirements by resource category type on the CAISO system for 2015. Higher energy demand in the summer months reduces the ramping requirement on the system because higher energy demand can accommodate higher solar generation levels.

Source: CAISO

Figure 1-1 CAISO Forecast of Total System Flexible Capacity Requirements

As more solar generation is added to the system, and in light of higher RPS targets under discussion in California, several questions arise. For example, will California face the same depressed prices seen in Texas and Germany or the levels of curtailments that occurred with wind generation in Texas several years ago? And given the concerns of the CAISO related to the duck curve, how should long-term planners in California be viewing resource needs and what would a move to a 50 percent RPS future entail? The CPUC is currently working on updating an RPS calculator that evaluates all renewables resources across the West, including required transmission, to help determine renewable resource portfolios that could be used to get California utilities to a potential 50 percent RPS by 2030.

In light of these future developments, this white paper seeks to advance the discussion of the impact of high solar photovoltaic (PV) penetration on the California system and the potential role of energy storage from an economic (spot market pricing) perspective. In addition, this study will review the level and type of generation needed to maintain resource adequacy targets under a variety of scenarios, and will also look at how a high penetration of energy storage impacts those requirements.


BLACK & VEATCH / SEPA | Modeling Approach 2-1

2.0 Modeling Approach To understand the impact of high solar penetration and the potential role of energy storage, the study team leveraged Black & Veatch’s production cost modeling capabilities using Black & Veatch’s semiannual Energy Market Perspective (EMP), which is a 25 year outlook of energy, fuel, and emissions markets across the United States.4 Additionally, given the limited capabilities of traditional production cost models to accurately model battery energy storage systems (BESS), the study team relied on an additional modeling tool, the GNU Linear Programming Kit (GLPK), to capture the dispatch signals for the BESS in the cases.5

Four cases were developed for the purposes of distinguishing impacts on wholesale electricity prices and system operations. In order to facilitate a concise analysis the study team focused on a snapshot of a single year in the future (2030). Furthermore, for the purposes of illustrating the impact of solar and battery storage, the results presented herein only reflect the market pricing area of South of Path 15 (SP15) in the CAISO balancing area. Although only the SP15 market prices are shown in this study, the entire Western Electricity Coordinating Council (WECC) and CAISO footprint was also simulated in the study.

To maintain consistency among the four cases and to isolate the impact of solar only on wholesale electricity prices, the natural gas and GHG emissions allowance prices were held constant across all cases.6 All prices reported in the study are in 2014$ unless specified otherwise. In addition, another key underlying assumption held constant was the build-out of the transmission system across all the cases. The addition of any transmission inside or outside the CAISO transmission system would cause electricity prices to propagate to neighboring systems and balancing authorities. Maintaining the same transmission system under all cases allowed the study to isolate the impact of solar only on wholesale electricity prices.7

In addition, this study does not take into account the dynamic relationship between electricity prices and energy demand, such as change in electric vehicle demand. Long-term consumer demand patterns may change in response to market pricing signals created by high solar penetration levels.

4 The EMP utilizes PROMOD, an hourly production cost model, to produce a 25 year hourly electricity price forecast

for key market areas. 5 Further descriptions of these tools can be found at Appendix X.

6 The average annual prices modeled for natural gas at SoCal Citygate was $5.12/mmBtu (one million British

thermal units), and the GHG emissions allowance forecast was assumed to be $18/ton (2014 dollars). 7 Black & Veatch did not perform any dynamic feedback loop to recalculate natural gas or emissions allowances

prices to reflect changes in natural gas fuel consumption or total emissions. In the case of a 50% RPS, it is likely that additional in-state or out-of-state transmission will be needed.

Black & Veatch Energy Market Perspective

Energy andEnvironmental Policies

World Oil &LNG Prices

Black & VeatchEnergy Market View

World U.S.

Commodity Market Models

Fuel, Power and Allowances



2.1 CASES STUDIED The cases in this study were constructed to examine discrete impacts of changes to wholesale electricity prices resulting from solar and energy storage additions and do not necessarily reflect actual scenarios of the future. The Black & Veatch and SEPA team acknowledges that the renewable portfolios under each of these cases do not necessarily align with portfolios developed under the CPUC RPS Calculator efforts.8 This simplified approach, however, does provide insights into how the market may function under a solar-heavy future and how flexible capacity needs change across each case.

Table 2-1 shows the production model cases that were studied. Renewable and thermal expansion plans corresponding to each case were adjusted to produce a reasonable approximation of how the system might look.9

Table 2-1 Production Cost Model Case Descriptions

The study team started with the Base Case, which had already been developed for the EMP. This mix of renewable energy and conventional generation projects is consistent with Black & Veatch’s 2014 EMP and assumes that California continues to maintain a 33 percent RPS beyond 2020 as load grows.

As shown on Figure 2-1 below, nearly 19,000 MW of solar are included in the Base Case, with about 6,000 MW consisting of distributed generation (DG) solar resources in California. To meet future load growth, replace retiring once-through-cooling (OTC) steam turbines, and integrate renewable resources, Black & Veatch forecast that approximately 11,000 MW of new natural gas fired capacity would be required by 2030. Of the 11,000 MW of new natural gas capacity, Black & Veatch estimates that almost half would need to be flexible, fast-ramping capacity capable of providing

8 The CPUC is currently working on updating the RPS Calculator for the entire WECC to determine possible

renewable resources including transmission cost that could allow California to achieve the 50% RPS goal by 2030. 9 This study did not look at the total portfolio costs, including generation and transmission capital costs, across

each case vs. renewable energy costs. A more comprehensive study would need to be performed to determine which case in Table 2-1 produced the lowest total cost to the State.

•Maintain 33% RPS by 2030 in California •1,325 MW energy storage mandate (AB2514) in California

Base Case

•Natural gas generation replaces planned solar resources required for 33% RPS

•1,325 MW energy storage mandate (AB2514)in California Natural Gas Alternative

•Increase 50% RPS by 2030 in California •1,325 MW energy storage mandate (AB2514) in California

High Solar Case

•50% RPS by 2030 •10,000 MW energy storage

High Storage Case



fast-ramping load following service and frequency regulation. The Base Case also includes the 1,325 MW of energy storage mandated in California.

Figure 2-1 Total New Capacity Additions by Case10

Table 2-2 lists the expansion plan for each of the cases constructed for this study. The expansion plan for all of California was adjusted to reflect the resource requirements needed to integrate different renewable penetration levels

Table 2-2 Capacity Expansion Plan by Case

CASE

2030 RENEWABLE PORTFOLIO STANDARD

(%)

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(MW)

2015 EXISTING

SOLAR (MW)11

2030 TOTALSOLAR (MW)12

NEW COMBINED

CYCLE (MW)

NEW FAST RAMPING

(MW)

NEW SIMPLE CYCLES (MW)

Base Case 33% 1,325 10,000 19,000 3,250 5,400 2,200

Natural Gas Alternative 24% 1,325 10,000 10,000 10,000 0 5,000

High Solar 50% 1,325 10,000 30,000 0 9,000 2,200

High Storage 50% 10,000 10,000 30,000 0 0 2,200

10

New wind projects are also included in the EMP but are not shown in graph. Energy storage was modeled as BESS with 4 hours of energy capacity and 87 percent round-trip efficiency (RTF). 11

Includes approximately both utility scale and distributed solar 12

Includes 6,000 MW of distributed solar.

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To understand the relative impact of the 33 percent RPS on the spot market in general, the study team developed a Natural Gas Alternative Case where no new incremental renewables beyond the existing projects today are built. This case assumes that all new capacity additions to meet load growth and retirements consist of natural gas plants. This results in approximately 15,000 MW of combined cycle gas turbine (CCGT) and simple cycle plants without any new fast-ramping capacity needed.

Next, facing the potential of increased RPS requirements to 50 percent by 2030, the study team also tested a High Solar Case where almost all additional renewable energy needs (beyond the 33 percent Base Case) were met with solar. This effectively doubled the new solar installations modeled to 30,000 MW. As a result of the additional solar in the 50 percent RPS case, the expansion plan was adjusted to add 9,000 MW of more fast-ramping capacity to compensate.

To see whether energy storage can be an alternative to conventional fast-ramping capacity, the energy storage in the system was increased to 10,000 MW, effectively replacing all of the fast-ramping conventional capacity in the 50 percent RPS case and any new combined cycle plants. This fourth case is called the High Storage Case.

The cases with more solar have more capacity added than the cases with less solar because of the capacity contribution of solar. The capacity contribution of solar in this study was assumed to be 50 percent of the nameplate capacity. This study did not address the effective load carrying capability (ELCC) of solar at higher solar penetration levels. This area will require further analysis.

2.2 ENERGY STORAGE MODELING While there are many types of energy storage technologies available in the marketplace today, the energy storage technology modeled in this study is a battery energy storage system (BESS) with 4 hour storage and 87% roundtrip cycle efficiency. The BESS takes about 4.6 hours13 to charge for zero to full power to account for losses. This study optimized the deployment of BESS assuming optimization around wholesale hourly energy prices as represented by the SP15 wholesale market. The study team recognizes that optimization of BESS or other types of energy storage technologies for other purposes such as ancillary services, capacity, and transmission and distribution capital expenditures is also possible. GLPK was used to optimize the dispatch of BESS based upon SP15 hourly wholesale prices for the year 2030 from each of the cases modeled. GLPK is intended for solving large-scale linear programming (LP), mixed integer programming (MIP), and other related problems.14 GLPK includes the program Glpsol, a stand-alone LP/MIP solver. Using Glpsol, the BESS is dispatched so that the revenue generated by BESS is maximized in the hourly SP15 wholesale market. The model assumed perfect foresight on the hourly price forecast for each day, charging BESS when energy prices are low and discharging when energy prices are high.

The resulting average energy storage charging and discharging profile is shown on Figure 2-2 for the cases that include the base level of energy storage.

13

Depending on the BESS technology and configuration the time to charge can be vary accordingly. 14

http://www.gnu.org/software/glpk/



Figure 2-2 Modeled SCE Average Energy Storage Profile

The Natural Gas Alternative, the Base Case, and the High Solar Case all assume 1,325 MW of energy storage in California. Figure 2-2 shows just SCE’s projected share of the energy storage mandate, which is 580 MW in all cases except in the High Storage Case (Figure 2-3), which assumes that SCE would have 4,500 MW on its system. Looking at the average BESS charge/discharge profile, there is clear evidence that a higher solar penetration level can cause significant changes in wholesale electricity market prices. In the Natural Gas Alternative Case, the BESS dispatch on the SCE system charges up when prices are lowest during the early morning hours and then dispatches to maximize energy revenue during the late evening when wholesale prices are highest. As California moves toward the 33 percent RPS target in 2030, there is a shift in the BESS profile, which indicates that BESS is charging during the middle of the day corresponding to when solar is generating. The High Solar Case shows almost a complete shift to charging up the BESS to coincide with the generating profile of solar compared to the Natural Gas Alternative Case, which show BESS charging up only during the early morning hours.

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Figure 2-3 Modeled SCE Average Energy Storage Profile High Storage

Figure 2-3 above highlights the complementary nature of energy storage with solar by minimizing the electric price dampening effect that solar has on the wholesale market at high penetration levels. The charging of the BESS corresponds to when solar is operating, suggesting that higher levels of energy storage could possibly negate some of the undesirable impacts of the high solar penetration levels on the wholesale market. Under high solar penetration levels energy storage may be able to offset the wholesale market price impact of excess solar and use the solar to charge up BESS for use during the early evening ramping of the net load. Solar output usually begins around 8 AM15, which is a signal for energy storage to start charging up to coinciding with the solar generation profile.

15

The timing of solar generation ramping up and down for the daily will vary by time during the year.

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BLACK & VEATCH / SEPA | Modeling Results 3-1

3.0 Modeling Results The cases constructed in this study were created to examine the impact of resource decisions on the

wholesale electricity market. The results from the four cases are discussed herein with respect to

the following six key impacts:

1. Net load

2. Locational marginal pricing (LMP)16

3. Energy mix

4. Curtailments

5. Carbon dioxide (CO2) emissions

6. California imports/exports

3.1 NET LOAD IMPACTS While solar output coincides with many on-peak hours, solar peak output does not necessarily coincide with the overall system load peak. This hourly gap between the solar peak versus the load peak is the main driver of the of the “duck curve”.

Figure 3-1 presents the 2030 average, max, and minimum load shape in California, contrasted to the average renewable energy profile of the cases studied. The graph illustrates the reality that peak solar output in California is not perfectly aligned with the peaking of the system load. Notice that the average renewable energy for a typical day is greater than the minimum load and only around 10,000 MW less than the average load in California. When energy demand in California is high during the summer months, high levels of solar do not appear to be a problem; however, when energy demand is lower, excess solar on the system is expected to displace natural gas generation on the margin and cause wholesale market prices to go lower.

16

On-peak is defined as the hour ending at 7 a.m. to the hour ending at 10 p.m. Monday to Saturday in the WECC. All other hours are considered to be off-peak including all of Sunday.



Figure 3-1 2030 Average California Load and Renewable Energy

Figure 3-2 below shows the net load of the system after all the renewable energy generation has been subtracted off the total load. The net load is the portion of the load to which the thermal units will need to dispatch. High solar penetration levels clearly results in a more problematic duck curve for the CAISO to address.

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Natural Gas Alternative Base Case - 33% RPS High Solar - 50% RPS

Average CA Load Peak CA Load Minimum CA Load



Figure 3-2 2030 California Annual Average Net Load

Similar to the findings by the CAISO, the addition of large amounts of solar generating resources is anticipated to cause a greater need for flexible capacity resources to match the “neck of the duck,” which is the primary ramp in the net load from hours 3 to 6 p.m. The “belly of the duck” is noticeable during the day in the Base Case and gets larger in the High Solar Case. The addition of 10,000 MW of energy storage in the High Storage Case shrinks the belly of the duck, while significantly reducing the net load in the peak hours.

In this study, the energy storage technology was dispatched to maximize energy value by optimizing the charge/discharge profile based only on energy price arbitrage in the wholesale electricity market. There may be alternatives to maximize the capacity value of energy storage by attempting to use energy storage in a manner to minimize flexible ramping requirements to the CAISO system. Energy storage could also be deployed to flatten out the slope of the daily ramp, thereby allowing slower reacting resources to help meet CAISO load ramping and load following requirements. These additional benefits were not modeled in this study.

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Figure 3-3 shows the calculated amount of flexible capacity that would be needed on the CAISO system for each case for an average day. The average flexible ramping capacity required in the High Solar Case is approximately 12,000 MW greater than in the Base Case. It should be noted that there is approximately 15,000 MW of additional solar added in the High Solar Case compared to the Base Case.

Figure 3-3 Average Daily Flexible Ramping Capacity Requirements

Ramping requirements are minimal in the Natural Gas Alternative, but become significant as more solar is added to the system. The High Storage Case shows a reduction of 9,000 MW of flexible as a direct result of the 10,000 MW of energy storage added to the system.

The results of this study suggest that the addition of solar energy reduces overall wholesale electricity prices by displacing more expensive resources in the supply stack and allowing lower-cost resources to set the electricity price margin in the CAISO market.

Figure 3-1 below shows the impact that high penetration levels of solar and energy storage have on wholesale market prices. In the Natural Gas Alternative Case, the load-weighted average wholesale electricity market price is roughly 2 percent higher than in the Base Case, as more expensive natural gas resources, which were otherwise displaced in some hours in the Base Case, set the market clearing price more often. This is most clearly shown by the higher on-peak price in the Natural Gas Alternative Case relative to the Base Case.

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Table 3-1 Summary of Load Weighted Average Prices at SP15 (2014$/MWh)

CASE ON-PEAK17 OFF-PEAK

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Base Case $53.18 $45.76 $50.00

Natural Gas Alternative $54.86 $45.85 $51.00 2%

High Solar $47.02 $43.98 $45.72 -9%

High Storage $48.94 $45.33 $47.39 -5%

Increasing solar generation in the High Solar Case causes a significant reduction in average LMP of 9 percent. California’s 2030 annual energy demand is forecasted to be about 326,000 gigawatt-hours (GWh).

In addition to reducing overall wholesale market prices, solar also has a significant impact on the pricing differential between the on-peak and off-peak hours by decreasing the spread, as a result of displacing natural gas resources that would normally be operating during the on-peak hours. As more solar is added to the CAISO market, on-peak prices are lowered because of natural gas displacement. The effect of adding more solar to the system is a narrowing of the price differential between on-peak and off-peak hours. In the High Solar Case, the time-of-day (TOD) price differential is only $3.04/MWh, which is the lowest among all the cases. The highest TOD price differential can be found in the Natural Gas Alternative Case, which supports the theory that solar reduces TOD price differentials. Adding more solar generation appears to narrow electricity price spreads on a time-of-day basis because solar will cause on-peak prices to go lower while not having much impact on off-peak prices. In addition, while natural gas price volatility was not studied as part of this analysis, it can be surmised that the additional solar energy would greatly reduce LMP price volatility compared to the Natural Gas Alternative Case.

If additional energy storage is implemented, as in the High Storage Case, the overall system average LMP increases. The impact of energy storage can be seen by comparing the High Solar 50 Percent RPS Case with the High Energy Storage Case. The TOD price differential increases with 10,000 MW of energy storage added to the CAISO system under the 50 percent RPS scenario in 2030. This is consistent with the charging and discharging profile of BESS. In the High Solar and High Storage Cases, energy storage takes advantage of lower prices attributed to excess solar energy and charges up 4 hours’ worth of storage when solar is generating, then dispatches from 6 to 9 p.m. in the evening when wholesale electricity prices are the highest and solar is ramping down. Figure 3-4 shows the average daily LMP profile at the SP15 pricing hub for all of 2030.

17

On-Peak is defined as the hour ending at 7 a.m. to the hour ending at 10 p.m. Monday to Saturday in the WECC. All other hours are considered to be off-peak including all of Sunday.



Figure 3-4 SP15 Load Weighted Average LMP – 2030 Annual Daily Profile

While solar generation does have a dampening effect on LMP in general, the impact of solar is not as dramatic in the summer months, as shown on Figure 3-5. Higher energy demand in the summer months helps accommodate higher solar output.

Figure 3-5 SP15 Load Weighted Average LMP – August 2030 Daily Profile

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The impact of solar on LMP is more pronounced when a winter month such as January is examined. January energy demands are much lower than those in August. While solar output is less in the winter months compared to the summer months, the output of solar in the High Solar 50 Percent RPS Case clearly creates a situation in which the California energy demands during the middle of the day do not match well with high solar output. The benefits of energy storage at high solar penetration levels are best illustrated on Figure 3-6. By creating additional demand on the system by charging up when solar is operating, energy storage is able absorb some of the excess solar which uplifts LMPs by $15-25/MWh when solar is operating.

Figure 3-6 SP15 Load Weighted Average LMP – January 2030 Daily Profile

The reduction in wholesale electricity prices caused by solar is interesting in that it can be viewed in two contradictory lights. The first is that lower electricity prices will benefit customers. An alternative view is that lower electricity prices will hurt solar energy producers, which may not allow solar projects to be justified economically. Balancing these positions requires a more detailed review of the all-in cost of each portfolio, where capital expenditures are included, multiple sensitivities on key variables analyzed, and a variety of benefit/cost tests employed to understand how all players are impacted.

3.2 ENERGY MIX The level of solar penetration on the system plays a large role in determining the optimal capacity expansion plan for the system. More solar on the system reduces the need for baseload combined cycle and simple cycle gas turbine capacity. Solar always plays a large role in altering the energy mix in California by affecting the supply curve and merit order dispatch. Solar and wind are considered to be zero energy cost resources and are offered into the CAISO market at zero price or even negative price to fully realize the benefit of any production tax credits (PTCs). Such bidding behavior allows solar resources to be dispatched ahead of most conventional thermal resources.

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The primary impact of increasing solar generation in the resource mix is the reduction in the use of natural gas. Table 3-2 shows the forecasted generation mix in 2030 by fuel source.

Table 3-2 Generation by Fuel Type

CALIFORNIA PERCENT GENERATION BY CASE

NATURAL GAS ALTERNATIVE BASE CASE

HIGH SOLAR

HIGH STORAGE

Baseload Renewable 9% 9% 8% 8%

Coal 4% 4% 3% 3%

Energy Storage 0% 0% 1% 5%

Hydro 11% 11% 11% 11%

Natural Gas 49% 40% 31% 29%

Nuclear 9% 9% 9% 9%

Solar 3% 14% 28% 27%

Wind 7% 7% 9% 9%

Imports/(Exports) 8% 7% (-2%) 0%

Generation from natural gas decreased from 40 percent of the energy mix in the Base Case to 31 percent of the energy mix in the High Solar Case, while the solar generation correspondingly increases from 14 percent to 28 percent, respectively. The results from this study show that solar will displace natural gas generation and will also alter the flow of power coming into and out of California. As more in-state solar resources are added to the grid, the amount of California imports is expected to decrease as a result.

3.3 CURTAILMENTS This study assumed that the existing high-voltage transmission system for each of the cases would not be altered except to allow for solar at the low-voltage and distribution level to serve load. During hours when there is excess solar on the system, wholesale electricity prices are expected to trend toward zero. For purposes of this study, potential curtailments are counted when wholesale electricity prices go below $10/MWh, because low or negative pricing is a clear market price signal that there is excess generation on the system. Under these system conditions, excess renewable energy could potentially be curtailed due to system over-generation conditions.

In the Base Case and the Natural Gas Alternative Case, there were no hours in which curtailment of renewable energy was forecast under normal weather and hydro conditions in the SP15 zone.18 The result of the High Solar Case shows that the potential risk of curtailment caused by excess generation from solar occurs in the winter and shoulder months of the year. The risk of solar curtailment is minimal during the summer months because of higher loads during the summer.

18

In drought conditions, such as are being experienced currently in California, it is anticipated that curtailment events would be reduced due to the lack of hydro production. Conversely, high hydro years could see curtailments increase significantly.



The extent that energy storage can mitigate curtailments may be tied to the assumption of the 4 hour storage technology modeled. More energy storage may be able to manage curtailments further. Figure 3-7 shows the possible solar curtailments on a monthly basis. The likelihood of solar curtailments appears to be the greatest during the winter and shoulder months.

Figure 3-7 Potential Solar Curtailments by Month

Importantly, the addition of energy storage helps to minimize the hours of curtailments substantially, though there are still some hours of curtailments in the winter months. Figure 3-8 below shows the hours when solar is curtailed in the High Solar Case and the High Storage Case.

Figure 3-8 Potential Solar Curtailments by Hour

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The addition of 30,000 MW of solar resources in 2030 in the High Solar Case could cause curtailments on the CAISO system; however, that assumes that no new transmission upgrades or new interstate transmission lines are built. Historically, California has been a net importer of power; in most years California imports about 25 percent of its power from out of state. Pending retirements of coal plants outside of California will reduce the percentage of imported energy in the future. As coal plants retire across the West, the transmission lines19 connecting neighboring states to California will begin to free up as California LSEs start to rely more on in-state sited natural gas and renewable generation instead of out-of-state coal generation.

3.4 IMPORTS/EXPORTS A possible alternative to solar curtailments is for California to export solar generation to neighboring states. Path 46, also called West of Colorado River, Arizona-California West-of-the-River Path (WOR), is a set of many high-voltage alternating-current transmission lines that are located in southern California and Nevada and extend up to the Colorado River. Path 46 is an important transmission interface in the western transmission system because it allows lower cost power from out-of-state to be imported to meet the electricity demands of Southern California‘s massive population centers. The retirement of coal plants in the Desert Southwest combined with increasing solar resources in California may lower the reliance of California on imported power.

In addition to the impact on wholesale electricity prices, this study briefly examined changes in power flows in and out of the CAISO. Studying the possible changes in the power flow on Path 46 provides an indication that the introduction of high levels of solar located inside California will reduce California’s reliance on imported power and possibly free up transmission in and out of California. Figure 3-9 shows the average hourly loading on the Path 46 West of River interface from the Base Case 33 Percent RPS and the High Solar 50 Percent RPS cases.

Figure 3-9 Average Monthly Flow on Path 46 (West of River)

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The results of this study indicate that higher levels of in-state solar resources could reduce the need for California to import power to meet energy demands. If California has access to high quality low cost solar resources does it make sense for resource planners across the state to look to develop more solar to meet internal demand and for export into neighboring states? Hypothetically, transmission lines used to import mostly non-renewable power may be used to export solar generated power. Other states may look to develop additional renewable resources to sell into the California wholesale power market if California does go to a 50 Percent RPS.

3.5 CO2 EMISSIONS Higher solar penetration level will bring with it the environmental benefits of lower CO2 emissions by displacing natural gas-fired generation. Figure 3-10 shows the forecast amount of CO2 emissions in California for each case.

Figure 3-10 California CO2 Emissions

The benefits of a higher RPS goal in California can be seen in the reduction in the CO2 emissions across the state. The Base Case, with a 33 Percent RPS standard, reduces CO2 emissions by 14 percent compared to the Natural Gas Alternative Case, clearly showing the environmental value of the current portfolio. Going from a 33 Percent RPS to a 50 Percent RPS may result in an additional reduction of CO2 emission by approximately 18 percent.

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BLACK & VEATCH / SEPA | Conclusions 4-1

4.0 Conclusions This study provided key insights into how the CAISO marketplace may function in 2030. Some of the assumptions used in this analysis were formulated to stimulate further discussion and promote research of the impact of high solar and energy storage on the wholesale power markets. From the work performed, Black & Veatch and SEPA have identified the following observations for broad consideration:

Market Pricing

● Solar energy provides price mitigation compared to a natural gas alternative. Both the weighted-average LMP in 2030 and the spread between on-peak and off-peak pricing were lower in the Base Case compared to the Natural Gas Alternative Case, and the High Solar Case showed even more dramatic price reductions.

● The introduction of high levels of BESS dampened the wholesale electricity price reduction somewhat, but that may have been a result of the analysis’ dispatch decisions for BESS. Alternative dispatch approaches and energy storage technologies may lead to different wholesale market pricing impacts.

Flexible Capacity Needs

● High penetrations of solar generation will require the addition of flexible capacity, likely in the form of quick start fast ramping gas turbines or energy storage with minimal operating limitations.

● Significant levels of BESS may be able to obviate the need for any new quick start capacity even in the High Solar Case. In addition, BESS, when dispatched strictly for price arbitrage, significantly reduces the 3 hour ramping requirement that otherwise exists from high levels of solar energy. Pairing these resources together can lead to a flatter overall load shape for the CAISO.

System Curtailments

● Black & Veatch does not forecast any possible solar curtailments in the Base Case under normal system operating conditions, which were assumed to occur when market prices dipped below $10/MWh under normal weather and system operating conditions.

● Under the High Solar Case, where almost all incremental renewable energy is met with solar generation resources, there were non-trivial levels of solar curtailments. This was particularly prevalent in winter and shoulder months.

● Adding in higher levels of BESS in the High Storage Case successfully mitigated a majority of the curtailments that were experienced in the High Solar Case.


BLACK & VEATCH / SEPA | Next Steps 5-1

5.0 Next Steps

5.1 ADDITIONAL AREAS FOR RESEARCH AND FOCUS While this report certainly touches on a host of key issues surrounding the future of the CAISO system, additional considerations and detailed studies should be pursued. Initial ideas from the Black & Veatch and SEPA team include the following:

Change in Demand Usage Patterns—Additional analyses may want to incorporate potential changes in future usage patterns in response to changes in prices. This study does not take into account the dynamic relationship between electricity prices and energy demand. Long-term consumer demand patterns may change in response to electric pricing signals resulting from high solar penetration levels. Instead of heavy energy usage during the early morning hours, consumers may choose to increase energy usage to correspond to when solar is generating. This study assumed a static energy demand profile, which further highlighted the potential impact of high solar and energy storage amounts on the system.

Distributed Generation—This study assumed that the majority of incremental solar was added in the form of utility scale solar, rather than distributed solar. The system would look significantly different with more distributed solar, considered to be behind the meter compared to utility scale solar that is integrated at the higher voltage transmission level.

Sub-Hourly Modeling—Currently, production cost models such as PROMOD, which Black & Veatch leveraged in this report, dispatch resources against load on an hourly basis. Historically, this approach has worked very well; however, with the increase in intermittent resources such as wind and solar, where weather-related events can cause minute-to-minute fluctuations in production, this hourly view may not provide the level of granularity needed for integrated resource planning. The impact of 30,000 MW of solar generation on system frequency, system stability, and voltage support would require an extensive study to understand fully.

Forecast Accuracy—This study assumed perfect forecast accuracy, both for solar production and battery charge and discharge cycles against LMPs. The ability to perfectly optimize the value of BESS is not likely to occur under real world market conditions. In addition, key input variables such as natural gas prices and emissions prices were held constant across all cases. In the future, a detailed look at the impacts of forecasting error and system benefits of better renewable energy forecasting should be explored.

Declining Solar Value—Preliminary studies have provided an initial indication that the value of solar energy and capacity declines at higher solar penetration levels. As this study also suggested, high levels of solar energy will eventually cause a decline in the energy value as represented by the LMP. A more comprehensive solar ELCC study being performed by E3 Consulting20 will help to determine the capacity credit of solar for long-term resource planning purposes.

Energy Imbalance Markets—CAISO and some surrounding systems are beginning to

coordinate activities in the new EIM. This holds the promise of leveraged shared resources

across multiple geographic regions to better manage system imbalance and, which may lead

to cost reductions for all participants. The results of this study, particularly related to

20

https://ethree.com/public_projects/recap.php



curtailments and battery dispatch, may look significantly different were the EIM modeled as

being deployed across the WECC or with more Transmission Owners (TO) participating.

Alternative Energy Storage Technology Options—As mentioned previously, this report leveraged one specific dispatch strategy for BESS that sought to maximize price arbitrage. BESS is an extremely flexible resource that has multiple potential applications. For example, the value of BESS may be different if it is dispatched for load following or fast ramping capacity to meet afternoon ramping requirements. Other energy storage technologies exist that may be optimized to provide other system benefits.

Clean Power Plan—The Environmental Protection Agency’s (EPA’s) pending carbon regulations are still under review and development. As that rule becomes finalized and states and regions identify compliance plans, a study could be performed looking at the ability to leverage California-based solar energy for neighboring states’ compliance.

Renewable Portfolio Economics—This study assumed that additional solar was developed in California to meet a higher RPS goal in the state. Resource planners across the state are starting to look at developing renewables above and beyond the current 33% RPS target based upon economics and environmental stewardship, rather than just RPS purposes. This study did not calculate the total cost of all resource added in each case to determine which case provide the lowest cost power to the consumer or the most societal benefits.

Holistic Application of DERs - Increasingly, the electric industry is incorporating a wide variety of distributed energy resources at the edge of the grid. Rooftop and small scale solar PV, demand response, electric vehicles, customer-sited storage, and other future applications are all impacting the way customers both use and interact with energy. While today many of these applications are reviewed either as a net load impact (increased consumption from electric vehicles) or as stand-alone resources for consideration (demand response), the ways these technologies are adopted and the variety of possibilities for their inter-connectivity with the utility has never been considered in an integrated resource planning framework. A future study could focus on maximizing the deployment and dispatch of all forms of DERs and analyzing how that holistic approach behind the meter impacts economic dispatch and, ultimately, wholesale markets and long-term resource decisions.



Appendix A. Black & Veatch Energy Market Perspective

The Black & Veatch EMP has been designed to respond to the needs of a wide range of energy

industry participants: investors, developers, lenders, utilities and energy users. The energy industry

has been in a nearly continuous state of rapid evolution for several decades. Dating back to the first

OPEC oil embargo in 1973, consumers, investors and governments have all struggled with making

energy decisions in a world of uncertainty. Central to their decision process, all stakeholders need

an objective view of the energy markets—an understanding of how the future may unfold, given

the lessons of the past and current trends in economics, technology, markets and government

regulation. By providing a careful consideration of the multiplicity of factors impacting today’s

energy markets, the Black & Veatch EMP uses an integrated, iterative analytical process to develop

a comprehensive view of the energy industry and how it can evolve in light of multiple dynamic

factors, providing a sound framework for decision making.

The vision of the EMP is to provide a world-class energy market benchmark which can be used by

our clients across a wide range of applications. It is prepared every six months to provide Black &

Veatch clients with a contemporary and insightful assessment of the current state of North

American energy markets, and long-term base case view of how those markets may function.

Critical elements of the EMP include:

A thoughtful, transparent and internally consistent approach to analyses of the energy markets

and the government policies that influence them.

Incorporation of Black & Veatch’s engineering and technical expertise across all key

assumptions.

A view of the markets for generation fuel sources.

A view of the electric power markets.

The EMP is designed to capture both the broad policy level assumptions and detailed structural

market representations to arrive at a consistent market view. From a “top down” perspective, Black

& Veatch assesses the current state of energy and environmental policies at both a US and global

level to determine their impact on North American energy markets and prices. Black & Veatch also

analyzes likely future conditions in world oil and liquefied natural gas (LNG) markets, as these

markets are becoming increasingly linked to U.S. market conditions.

Concurrently, Black & Veatch addresses North American commodity markets with a very detailed

“bottom up” approach, using sophisticated structural market models to simulate market participant

behavior in terms of rent extraction and new resource development, utilizing model inputs as

diverse as power plant capital costs, environmental and regulatory policy, fuel basin exploration

and development costs, and projected gas pipeline expansions. The figure below shows the EMP

regional coverage for the different regions in the U.S.



EMP Regional Coverage

Source: Black & Veatch 2015 EMP Outlook

The EMP can be used to forecast likely asset operations and market revenues — which can drive

transactional due diligence, asset portfolio optimization, environmental compliance, risk management

and the analysis of business expansion and exit strategies.

The EMP is underlain by a series of fundamental structural energy market models. Black & Veatch

utilizes its Integrated Market Model (IMM) as a basis for the current industry structure as well as a

starting point for long-term analysis. In order to arrive at this market view, Black & Veatch draws

on a number of commercial data sources and supplements them with its own view on a number of

key market drivers, for example, power plant capital costs, environmental and regulatory policy,

natural gas finding and development costs, and gas pipeline expansions. Black & Veatch uses this

data in a series of vendor-supplied and internally-developed energy market models to arrive at its

proprietary market perspective.



From the EMP process, Black & Veatch has developed independent forecasts of every North

American wholesale electricity market. This zonal analysis of the regional markets incorporates the

results of Black & Veatch’s assessment of market-based capacity additions and retirements, the

impact of potential greenhouse gas legislation, and the inter-zonal transmission transfer

capabilities implicit in the existing transmission system and the new transmission facilities needed

to facilitate renewables development.

Black & Veatch’s Integrated Market Modeling Process

Source: Black & Veatch 2015 EMP Outlook

Black & Veatch’s market perspective considers the resource adequacy value of capacity in each

market with a “Net Cost of New Entry” process, and to the extent that forecasted energy prices are

insufficient to induce reliable levels of generation, Black & Veatch calculates the equivalent of a

capacity price forecast that “fills the gap” between energy market net operating revenues and new

entrant revenue requirements. This approach is structurally consistent with the administrative

capacity markets in ISO-NE, NYISO and PJM, and is reasonable to use as an indication of value in

other markets where there are no administrative capacity markets.

Documents

IMPACT OF HIGH SOLAR AND ENERGY STORAGE LEVELS ON WHOLESALE POWER … · 2016. 4. 26. · IMPACT OF HIGH SOLAR AND ENERGY STORAGE LEVELS ON WHOLESALE POWER MARKETS BLACK & VEATCH