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

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

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 i

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 CO 2 Emissions... 3-11 BLACK & VEATCH / SEPA Table of Contents ii

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-1

IMPACTS KEY OBSERVATIONS Flexible Capacity Needs System Curtailments 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. 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 CO 2 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 CO 2 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 Executive Summary ES-2

AB2514 IMPACT OF HIGH SOLAR AND ENERGY STORAGE LEVELS ON WHOLESALE POWER MARKETS 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 700 MW Transmission Level proposed greenhouse gas (GHG) emissions allowance regulations, makes solar energy a prime resource to 425 MW Distribution Level offset natural gas and coal generation in the Western Electricity Coordinating Council (WECC) 200 MW Customer Sited 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. BLACK & VEATCH / SEPA Introduction 1-1

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 jurisdiction 3 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 subrequirement 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 fastramping 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 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. 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. BLACK & VEATCH / SEPA Introduction 1-2

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 Introduction 1-3

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 Black & Veatch Energy Market Perspective Energy and Environmental Policies World U.S. Black & Veatch Energy Market View World Oil & LNG Prices Commodity Market Models Four cases were developed for the purposes of distinguishing impacts on wholesale electricity prices and system Fuel, Power and Allowances 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 / SEPA Modeling Approach 2-1

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 Base Case Maintain 33% RPS by 2030 in California 1,325 MW energy storage mandate (AB2514) in California Natural Gas Alternative Natural gas generation replaces planned solar resources required for 33% RPS 1,325 MW energy storage mandate (AB2514)in California High Solar Case Increase 50% RPS by 2030 in California 1,325 MW energy storage mandate (AB2514) in California High Storage Case 50% RPS by 2030 10,000 MW energy storage 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. BLACK & VEATCH / SEPA Modeling Approach 2-2

Nameplate MW IMPACT OF HIGH SOLAR AND ENERGY STORAGE LEVELS ON WHOLESALE POWER MARKETS fast-ramping load following service and frequency regulation. The Base Case also includes the 1,325 MW of energy storage mandated in California. 50,000 45,000 40,000 35,000 30,000 25,000 20,000 15,000 10,000 5,000 0 Base Case Natural Gas Alternative High Solar High Storage Energy Storage (MW) Existing Solar New Solar New Combined Cycle New Fast Ramping New Simple Cycles Figure 2-1 Total New Capacity Additions by Case 10 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 (%) ENERGY STORAGE (MW) 2015 EXISTING SOLAR (MW) 11 2030 TOTAL SOLAR (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. BLACK & VEATCH / SEPA Modeling Approach 2-3

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 fastramping 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 hours 13 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/ BLACK & VEATCH / SEPA Modeling Approach 2-4

1 AM 2 AM 3 AM 4 AM 5 AM 6 AM 7 AM 8 AM 9 AM 10 AM 11 AM Noon 1 PM 2 PM 3 PM 4 PM 5 PM 6 PM 7 PM 8 PM 9 PM 10 PM 11 PM 12 PM MW IMPACT OF HIGH SOLAR AND ENERGY STORAGE LEVELS ON WHOLESALE POWER MARKETS 600 500 400 300 200 100 0-100 -200-300 -400-500 -600 Base Case - 33% RPS High Solar - 50% RPS Natural Gas Alternative 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. BLACK & VEATCH / SEPA Modeling Approach 2-5

1 AM 2 AM 3 AM 4 AM 5 AM 6 AM 7 AM 8 AM 9 AM 10 AM 11 AM Noon 1 PM 2 PM 3 PM 4 PM 5 PM 6 PM 7 PM 8 PM 9 PM 10 PM 11 PM 12 PM MW IMPACT OF HIGH SOLAR AND ENERGY STORAGE LEVELS ON WHOLESALE POWER MARKETS 5,000 4,000 3,000 2,000 1,000 0-1,000-2,000-3,000-4,000-5,000 High Storage 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 AM 15, 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. BLACK & VEATCH / SEPA Modeling Approach 2-6

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 (CO 2) 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. BLACK & VEATCH / SEPA Modeling Results 3-1

1 AM 2 AM 3 AM 4 AM 5 AM 6 AM 7 AM 8 AM 9 AM 10 AM 11 AM Noon 1 PM 2 PM 3 PM 4 PM 5 PM 6 PM 7 PM 8 PM 9 PM 10 PM 11 PM 12 PM MW IMPACT OF HIGH SOLAR AND ENERGY STORAGE LEVELS ON WHOLESALE POWER MARKETS 80,000 Average California Load And Renewable Energy 70,000 60,000 50,000 40,000 30,000 20,000 10,000 0 Natural Gas Alternative Base Case - 33% RPS High Solar - 50% RPS Average CA Load Peak CA Load Minimum CA Load 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. BLACK & VEATCH / SEPA Modeling Results 3-2

1 AM 2 AM 3 AM 4 AM 5 AM 6 AM 7 AM 8 AM 9 AM 10 AM 11 AM Noon 1 PM 2 PM 3 PM 4 PM 5 PM 6 PM 7 PM 8 PM 9 PM 10 PM 11 PM 12 PM amw IMPACT OF HIGH SOLAR AND ENERGY STORAGE LEVELS ON WHOLESALE POWER MARKETS 45,000 California Net Load 40,000 35,000 30,000 25,000 20,000 15,000 10,000 5,000 0 High Storage High Solar - 50% RPS Base Case - 33% RPS Natural Gas Alternative 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. BLACK & VEATCH / SEPA Modeling Results 3-3

MW IMPACT OF HIGH SOLAR AND ENERGY STORAGE LEVELS ON WHOLESALE POWER MARKETS 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. 30,000 Average Daily Maximum 3 Hour Ramp (3 PM -6 PM) 25,000 20,000 15,000 10,000 5,000 0 High Storage Base Case - 33% RPS High Solar - 50% RPS Natural Gas Alternative 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 lowercost 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. BLACK & VEATCH / SEPA Modeling Results 3-4

Table 3-1 Summary of Load Weighted Average Prices at SP15 (2014$/MWh) CASE ON-PEAK 17 OFF-PEAK LOAD- WEIGHTED AVERAGE PRICE CHANGE (+/-) RELATIVE TO BASE CASE 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 gigawatthours (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. BLACK & VEATCH / SEPA Modeling Results 3-5

1 AM 2 AM 3 AM 4 AM 5 AM 6 AM 7 AM 8 AM 9 AM 10 AM 11 AM Noon 1 PM 2 PM 3 PM 4 PM 5 PM 6 PM 7 PM 8 PM 9 PM 10 PM 11 PM 12 PM 1 AM 2 AM 3 AM 4 AM 5 AM 6 AM 7 AM 8 AM 9 AM 10 AM 11 AM Noon 1 PM 2 PM 3 PM 4 PM 5 PM 6 PM 7 PM 8 PM 9 PM 10 PM 11 PM 12 PM Average LMP $/MWh IMPACT OF HIGH SOLAR AND ENERGY STORAGE LEVELS ON WHOLESALE POWER MARKETS $80 $70 $60 $50 $40 $30 $20 $10 $0 2030 SP15 Average LMPs High Storage High Solar - 50% RPS Base Case - 33% RPS Natural Gas Alternative 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. $90 $80 $70 $60 $50 $40 $30 $20 $10 $0 August 2030 Average SP15 LMPs High Storage High Solar - 50% RPS Base Case - 33% RPS Natural Gas Alternative Figure 3-5 SP15 Load Weighted Average LMP August 2030 Daily Profile BLACK & VEATCH / SEPA Modeling Results 3-6

1 AM 2 AM 3 AM 4 AM 5 AM 6 AM 7 AM 8 AM 9 AM 10 AM 11 AM Noon 1 PM 2 PM 3 PM 4 PM 5 PM 6 PM 7 PM 8 PM 9 PM 10 PM 11 PM 12 PM IMPACT OF HIGH SOLAR AND ENERGY STORAGE LEVELS ON WHOLESALE POWER MARKETS 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. January 2030 Average SP15 LMPS $80 $70 $60 $50 $40 $30 $20 $10 $0 High Storage High Solar - 50% RPS Base Case - 33% RPS Natural Gas Alternative 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. BLACK & VEATCH / SEPA Modeling Results 3-7

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. BLACK & VEATCH / SEPA Modeling Results 3-8

1 AM 2 AM 3 AM 4 AM 5 AM 6 AM 7 AM 8 AM 9 AM 10 AM 11 AM Noon 1 PM 2 PM 3 PM 4 PM 5 PM 6 PM 7 PM 8 PM 9 PM 10 PM 11 PM 12 PM Number of Curtailment IMPACT OF HIGH SOLAR AND ENERGY STORAGE LEVELS ON WHOLESALE POWER MARKETS 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. 140 120 100 80 60 40 20 0 Potential Curtailment Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec High Solar High Storage 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. 120 Potential SP15 Curtailments by Hour 100 80 60 40 20 0 High Solar High Storage Figure 3-8 Potential Solar Curtailments by Hour BLACK & VEATCH / SEPA Modeling Results 3-9

MW IMPACT OF HIGH SOLAR AND ENERGY STORAGE LEVELS ON WHOLESALE POWER MARKETS 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 lines 19 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. 12,000 10,000 8,000 Path 46 West of River Maximum Import 6,000 4,000 2,000 0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Base Case - 33% RPS High Solar - 50% RPS Path 46 - West of River Figure 3-9 Average Monthly Flow on Path 46 (West of River) BLACK & VEATCH / SEPA Modeling Results 3-10

CO2 Million Metric Tons IMPACT OF HIGH SOLAR AND ENERGY STORAGE LEVELS ON WHOLESALE POWER MARKETS 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 CO 2 emissions by displacing natural gas-fired generation. Figure 3-10 shows the forecast amount of CO 2 emissions in California for each case. 80 70 60 50 40 30 20 10 California CO2 Emissions 0 Natural Gas Alternative Base Case - 33% RPS High Solar - 50% RPS High Storage Figure 3-10 California CO 2 Emissions The benefits of a higher RPS goal in California can be seen in the reduction in the CO 2 emissions across the state. The Base Case, with a 33 Percent RPS standard, reduces CO 2 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 CO 2 emission by approximately 18 percent. BLACK & VEATCH / SEPA Modeling Results 3-11