Low Carbon Grid Study: Comparison of 2030 Fixed Costs of Renewables, Efficiency, and Integration with Production Cost Savings

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1 Low Carbon Grid Study: Comparison of 2030 Fixed Costs of Renewables, Efficiency, and Integration with Production Cost Savings Prepared by JBS Energy, Inc. 311 D Street West Sacramento California, USA William B. Marcus Principal Economist 1

2 Table of Contents Introduction... 3 Analysis of Renewable Fixed Costs Versus Production Cost Savings... 7 A. Introduction...7 B. Capital and O&M Cost Analysis C. Nominal Fixed Charge Rate D. Income Tax Analysis E. Property Tax and Insurance Rate II. Economic Scenarios III. Analysis of Production Costs A. Gas Prices B. Carbon Prices IV. Sensitivity of Production Cost Results to Gas and Carbon Prices A. Production Cost Sensitivity Analysis B. Conventional Flexibility vs. Enhanced Flexibility Cases Dispatch Restrictions and Storage V. Comparison of Capital Costs and Production Cost Savings A. Economic/Interest Rate Scenarios B. Combination of Technology and Economics C. Sensitivity to Gas and Carbon Prices D. Comparison to Expected 2030 Utility Revenue Requirements VI. Appendix A A. Cost Assumptions for New Resources Adjustments to capital costs B. I-b. Program costs Energy efficiency Capacity Payments C. References VII. Appendix B VIII. APPENDIX C IX. APPENDIX D

3 Introduction This work was conducted for the Low Carbon Grid Study, a project to study the California electric grid in 2030 with deep reductions in carbon emissions using existing technology. Project sponsors and all documentation including work papers and public sources of data used for the study can be found at This paper is one of four documents that make up Phase II of that study. 1 It calculates the mostly fixed cost of investments required to achieve at least 50% reduction in carbon emissions in 2030 from 2012 and compares this cost to the mostly variable cost savings that result from adding enough zero carbon, zero variable cost energy to the system to achieve those carbon targets. 2 This comparison is not strictly speaking a rate impact analysis since no attempt is made to calculate distribution effects between and among California utilities, producers and consumers, or ratepayer classes. Nor is it a utility revenue requirement analysis since some of the costs and benefits do not necessarily appear as a cost to load serving entities and capital costs are levelized. However, for context, in this report, the net cost differential between various scenarios is often expressed as a percentage of estimated state wide utility revenue requirements in When making these future cost comparisons, it is important to not only convey a range of results across a plausible range of input variables, but also to recognize that even in the Base Case, the electric grid in 2030 will evolve over the next fifteen years with or without a major new policy decision to heavily invest in new zero carbon resources to achieve the carbon reduction targets. Specifically, achievement of the current renewable 1 The NREL report Low Carbon Grid Study: Analysis of 50% Emission Reduction in California, The GE Report Low Carbon Grid Study: Discussion of Dynamic Performance Limitations in WECC, Nicholas Miller, GE Energy Consulting, April 29, 2015 and, Low Carbon Grid Study: Energy Efficiency Savings and Cost Assumptions, Tierra Resource Consultants LLC, August can all be found at lowcarbongrid2030.org/materials/ under Phase II Results. 2 Variable costs of biomass and geothermal are included in the production costs. The reported savings are net of the additional variable costs of these resources. 3

4 target of 33% by 2020 and other existing policy will provide enough incentive to provide a more flexible grid that will more easily accommodate variable renewable resources such as wind and solar than the grid that exists today. This evolution must be explicitly recognized across all future scenarios in order to isolate the impact of the policy decision to dramatically increase the use of renewable resources, otherwise, the imputed cost savings will be double counted. The principal relevant common themes across all scenarios are as follows: - Default assumptions for WECC wide loads and resources and transmission topology in 2030 are taken from the TEPPC 2024/2034 Common Case. 3 Thus, e.g., all existing WECC renewable portfolio mandates are assumed met in all cases. - Current law that prohibits long-term investment in coal resources meant to serve California load is fully implemented. In conjunction with strengthening of existing criteria pollutant regulations, low gas prices, and simple age, roughly one-third of the existing WECC coal fleet is retired by 2030 as represented in the TEPPC Common Case. Thus carbon emissions will fall across WECC even in the absence of new CA or Federal policy. - Current law that phases out the use of once through ocean cooling (OTC) causes the retirement/repowering of all old gas fired coastal steam plants before Thus, in all cases, the California gas fleet is 2030 is much more flexible and efficient than today. - Current trends to improve the efficiency of real time trading across WECC continue in all cases. Thus all scenarios include an efficient WECC wide dayahead bilateral spot market based on existing trading hubs and a real time Energy Imbalance Market ( EIM ) that expands on the existing CAISO/PAC 3 WECC TEPPC Common Case datasets can be found at 4

5 market that began operations in 2015 to significantly improve unit commitment and dispatch decisions across the region. - Distribution upgrade costs/benefits to accommodate a dramatic increase in distribute generation (mostly rooftop PV) were assumed to be equal in all cases. Market penetration of these resources is independent of a policy to increase bulk utility scale renewables. Summary The principal finding of this work is that, while carbon emissions from electricity production to serve CA load will trend down without any new State policy, the net cost of achieving at least a 50% reduction in carbon emissions from California s electric grid (from 95 MMTCO2e in 2012 to less than 47.5 MMTCO2e in 2030) is 0.75% of the estimated utility revenue requirement in 2030 in the Target Case. 4 the cost analysis of a broad range of natural gas prices, carbon prices, macroeconomic variables and renewable capital costs show a net cost range from -3% to about +4% of utility revenue requirements in 2030 to achieve the 50% carbon reduction target, and the cost of these reductions as expressed as cap and trade allowance prices is roughly $30/ton. These results assume that significant policy driven initiatives to improve energy efficiency in existing buildings and electrification of the transportation sector are successfully implemented in concert with the investment in new renewable resources. While these other policy initiatives are not analyzed in this study, their impact on electric load and load shape is included in this analysis. In addition, the study found that the following significantly impacts cost effectiveness of achieving the carbon target: 4 Using mid-case assumptions for input assumptions for technology costs, interest rates, gas costs, and carbon costs in

6 - Procuring a diverse mix of best fit zero carbon renewable resources across technologies and geographic locations rather than a simple least first cost procurement strategy. - Recognizing that new renewable resources need to be configured to supply Essential Reliability Services ( ERS, aka, ancillary services) and that grid operating practices need to evolve to rely on this capability. - Recognizing that non-iou hydro resources in both the State and Federal water supply systems need to be better integrated into the ESR supply for the state. - Understanding that details on how out of state renewable resources are imported and when they are exported during times of surplus energy within California are important. The consequences of the current interpretation of the RPS Portfolio Content Rules need to be carefully considered. Finally, the study found that long duration (4-6 hr) bulk storage and new forms of Demand Response can cost-effectively supply additional flexibility to the system as variable renewable resource contribution to electric supply increases. However, at current and projected prices for storage and considering round trip efficiency losses, bulk storage is the marginal resource addition and, as such, is clearly more expensive than the other mitigation measures listed above. The less diverse the renewable resource additions and the less successful the three initiatives listed above that make up the enhanced flexibility package are executed, the higher the system cost and the more bulk storage will be found to be cost effective. 6

7 Analysis of Renewable Fixed Costs Versus Production Cost Savings A. Introduction In order to review the economics of the analysis of 50% carbon reduction by 2030, it is necessary to compare the capital and fixed O&M costs of new renewable projects (and supporting projects such as storage and transmission), with the savings in production costs from operating the existing system and any reductions in capital costs from the existing system due to the addition of increasing renewables. 5 The table below shows the specific resource additions relative to the base case in the Target Case and High Solar Case, as identified for the project. The target case shifts some solar resources in the Base Case from fixed orientation to tracking, yielding negative numbers. The amount of resource adequacy capacity provided by the Target and High Solar cases varies immaterially (by 3 MW or less than 0.1%). 5 The only capital cost reduction observed on the existing system from was removal of a 600 MW combined cycle unit. The existing system has a significant amount of excess capacity, even without new renewables. 7

8 Table 1: Technology Portfolios Analyzed Target Case Capacity (MW) High Solar Case Capacity (MW) Technology Non-Tracking PV PV CA -2,586 1,200 PV AZ PV NV PV UT Tracking PV PV CA 3,202 6,273 PV AZ PV NV Solar Thermal Base Solar Thermal CA ST AZ ST NV ST Generic Wind Base Wind CA 4,536 3,759 Wind NV Wind NM 1,687 - Wind WY 2,676 2,676 Biomass Biogas - Landfill Geothermal Flash CA 1, Geothermal Flash NV Geothermal Binary CA Geothermal Binary NV CAES (POU) Pumped Storage Combined Cycle Energy Efficiency $/first year kwh GWh TOTAL BEFORE RA CREDIT Resource Adequacy Credit 4263 MW 4263 This comparison was made in 2014 dollars, so that we did not need to forecast inflation (with the exception of a limited interaction between inflation and the cost of debt, equity, and income taxes associated with equity). 8

9 To make this kind of comparison, it is first necessary to determine the capital cost and fixed operating and maintenance (fixed O&M or FO&M) cost of various resources. The bulk of these cost estimates start with E3 s March 2014 Capital Cost Review of Power Generation Technologies: Recommendations for WECC s 10- and 20-Years Studies (E3, 2014), which provides a comprehensive overview of data from various sources for the 2013 vintage installed cost of generation technologies in WECC at the time of publication. However, for solar in particular, where costs have been declining dramatically, and also for other resources (such as bulk storage), other data sources were used to provide a range of potential costs. The source of data for capital and FO&M costs for low, medium, and high technological cost cases is presented in Appendix A. In a number of cases, the high case identified in written documentation was higher than that used in Appendix A; the rationale was that if certain projects cost as much as these high case figures, they would not actually be built, but other projects with different technologies would be constructed instead. The capital costs were then annualized (i.e., spread over the life of the projects 20 years for solar, wind and biomass based on maximum power purchase agreement lengths, 30 years for geothermal, 30 years for utility-owned combined cycle and compressed air storage projects, and 40 years for pumped storage and transmission projects. Fixed O&M was added. These costs of new power projects were compared to the production cost savings from adding these very low variable cost resources. These costs are comprised largely of fuel use in California ( all gas), along with variable O&M expenses, costs of powerplant startups (partly fixed and partly fuel), avoided imports into California, value of exports from California, and carbon costs associated with the fuel and imports. Imports were valued at the short run marginal price at the CA receiving node while exports were valued at the short run marginal cost of the importing balancing authority. While there are a variety of cases based on differences in capital costs and fuel costs, that difference in total costs between the Baseline case (before renewable additions) and the Target case (after renewable additions and storage and transmission to support them) was $232 million. In the base case, there were $5,083 million of capital costs and $4,8 9

10 million of savings in production costs. This amount is about 0.75% of the 2030 revenue requirement estimate by the California Public Utilities Commission of $30.6 billion dollars 6. In essence, given the time frame and the uncertainties in costs, the cost stream of new capital and fixed costs of renewables and supporting investments and the avoided production costs of the existing system were very similar. In addition, any small excess of costs hedges against rising carbon costs and rising gas costs since the cost savings are largely variable, while the renewable investment costs are fixed. This hedge effect is important since natural gas prices have been extremely volatile throughout history. The renewable efforts in 2030 also provide a stepping stone toward even further increases in renewables and efficiency as decarbonization of both the electric sector and replacement of carbon in other sectors such as transportation proceed approaching B. Capital and O&M Cost Analysis The analysis of capital projects starts with high, medium, and low scenarios of capital costs for each technology. High, medium, and low scenarios were used for operation and maintenance costs for photovoltaics, where cost estimators saw the potential for a significant range, but not for other technologies, where a single value was used. Capital and O&M costs were analyzed in 2014 dollars. In our analysis, the annualized capital cost of a resource was calculated as follows: Annualized capital cost = (Capital Cost of Resource) X [(Nominal Fixed Charge Rate) + (Property Tax and Insurance Percentage)] + (Fixed O&M Cost) These capital and O&M costs were multiplied by the number of megawatts of each technology. Different methods were used to analyze transmission lines (where total dollars of transmission investment were multiplied by a nominal fixed charge rate that includes O&M), and for energy efficiency, where costs are expensed and not capitalized. EE costs 6 RPS Calculator v6.1 but expressed in 2014 dollars 10

11 were based on the total amount of public dollars spent to acquire the savings in the twelve-year time frame divided by the 12-year expected life of EE measures. Details on how acquisition costs of energy efficiency were calculated can be found in a paper sponsored by the Energy Efficiency Industries Council for this study 7 and are shown in Appendix A. C. Nominal Fixed Charge Rate The method used to annualize the cost of the portfolio of options is a nominal fixed charge rate. A nominal fixed charge rate is the amount of money that will recover the capital-related costs (excluding O&M but including income taxes, property taxes and insurance) associated with a given capital investment in equal numbers of nominal dollars every year It is also called a levelized fixed charge rate. The nominal fixed charge rate depends on the percentage of equity and debt, the cost of equity and debt, tax rates, tax benefits available to the project owner, and property tax and insurance rates. Other methods can be used for economic analysis. These include a real economic carrying charge rate (which recovers the project s costs in an equal number of real dollars every year but escalates with inflation), which is often used for project evaluation, as well as calculation of marginal or avoided costs. It also measures the value of deferring the project a year at a time. The utility revenue requirement, which is downward sloping (higher payments up-front), reflects how rates are actually set. In this case the nominal fixed charge rate was used specifically to evaluate ratepayer impacts of portfolio options. There are several reasons. First, it is representative of how many renewable projects are financed by third-party developers. In recent years, they have tended to contract for projects in flat nominal dollars. 7 Guidance on interpreting the forecast and production cost model for energy efficiency by Tierra Consultants can be found on lowcarbongrid2030.org/materials/ under Phase II Results. 11

12 Second, a real economic carrying charge rate, while reflective of economic analysis, does not reflect what customers will actually be paying, but reshapes it so that payments are higher in the future and lower up front. While reflective of economic analysis when deciding to build a project or defer it for one or more years, it is essentially not a financeable contract on which projects can be built. The third method (utility revenue requirement) was not used because it is sensitive to specific assumptions as to when a project is placed in service and is also a snapshot of a single given year, rather than reflecting the present value of the project over its life. Finally, certain consumer costs/benefits that do not flow through utility rates such as rebates from the Greenhouse Gas Reduction Fund (cap and trade revenues) are not considered, while non-utility public costs such as potential Property Assessed Clean Energy (PACE) financing 8 subsidies for energy efficiency are included. D. Income Tax Analysis We used a federal tax rate of 35% and a state tax rate equal to that in the specific states where projects might be built (ranging from zero in Nevada to 8.84% in California). We depreciated each type of renewable project according to its schedule, and included all investment and production tax credits currently applicable after We assumed that any existing tax credits with a legislated expiration date would not be extended. E. Property Tax and Insurance Rate Because these figures are relatively small, we did not use a state-by-state analysis of property taxes and insurance. We used 1.2% nominal levelized in most cases. This is approximately equivalent to a property tax rate of 1% declining with depreciation of property and an insurance rate of 0.4% escalating with inflation. The insurance rate is effectively a mid-case variable, between utility costs (0.1 to 0.25%) and potentially higher costs for other private sector parties (estimated by the CEC at 0.6%, although without 8 A mechanism to finance purchase of efficiency measures and payback with a lien on property tax rolls. 12

13 any supporting documentation or evidence). A lower rate was used in California for solar (0.75%) because a property tax exemption exists through 2025 and some projects will be built before then. Utility projects (combined cycle, pumped storage, etc.) had property taxes and insurance included in fixed capital-related costs automatically, so an adder was not required for them. II. Economic Scenarios While all projects and all natural gas costs are analyzed in 2014 dollars, inflation, the real rate of risk-free long-term interest, and risk premiums for various levels of debt and equity affect the levelized nominal cost of capital applied to utility and renewable investments. The effect of inflation is solely through income taxes on equity investments. The other parameters have direct effects. Three economic scenarios were run. They were built up starting with inflation, adding real risk-free interest rates (long-term inflation adjusted government bonds), and adding risk premiums for utility bonds and equity and for the weighted average cost of capital (WACC) for equity investors in independent power projects (the preponderance of new renewables). The low scenario starts implicitly with lower economic growth. It is accompanied by lower inflation, lower long-term risk-free real interest rates, and lower risk premiums. The high scenario, conversely has higher inflation, higher long-term risk-free real interest rates, and higher risk premiums. The three scenarios are outlined below. 13

14 Low Mid High Inflation 1.50% 2.00% 2.75% Long-Term TIPS* 1.50% 2.00% 2.25% Long-Term Treasury 3.02% 4.04% 5.06% Utility Bond 4.02% 5.04% 6.56% Utility Equity 10% 10.60% 11.50% Independent Power WACC 6.50% 7.25% 8.25% Gas Price Mid-low Mid Mid-high *TIPS= Treasury Inflation Protected Security The Treasury inflation protected security rate (real rate of interest) was based in the low case on the average rate from The high case was the average rate in the high economic growth period of The mid case was intermediate. III. Analysis of Production Costs A. Gas Prices We used a base price for natural gas in 2030, of $6.96 per MMBtu ($/MMbtu). This is consistent with the CPUC Renewable Portfolio Standard (RPS) Calculator modeling assumptions of the price in 2013 dollars of $6.86 per MMBtu burner tip in California escalated to 2014 dollars. Under RPS Calculator modeling assumptions, this figure includes the Henry Hub price plus a base differential of $0.28 per MMBtu, plus local transportation of $0.37 per MMBtu plus average local taxes. The associated Henry Hub price was about $6.23 per MMBTu (2014 dollars). We run a low case and a high case of gas prices at 15% below and 15% above the Henry Hub prices to reflect potential differences in various factors including oil prices, resource availability, and economic conditions. These yield California burner tip prices of $6.01 to $7.90 (2014 dollars). 14

15 There is little question that spot natural gas prices have historically demonstrated much higher volatility than +/- 15%. Henry Hub prices in the past seven and a half years (half of the elapsed time until 2030) have ranged from below $2.50 to over $ However, this analysis seeks a mean gas price, because neither very high nor very low prices have persisted for long periods of time. Moreover, utilities hedge the bulk of the natural gas acquired (whether used in their own plants or contracted for through tolling arrangements with independently owned generators) with hedges of one or more years in duration to reduce volatility. The elasticity of the cost comparisons vs. gas price are discussed in more detail below. Mid-low and mid-high cases are used with a 5% differential from the base case in the economic scenarios. The low economic scenario (with lower interest rate and lower risk premiums) is consistent with lower economic growth and the high interest rate and higher risk scenario is consistent with higher growth. EIA estimated approximately a 5% differential in gas prices between its base case and both of its low and high economic growth cases in its 2015 Annual Energy Outlook. 9 These differentials occurred because gas demand was less in the low growth case, so fewer high cost supplies were needed. Gas demand was higher in the high growth case inducing greater high cost supplies. The gas price scenarios are given below. Low Mid-Low Mid Mid-High High Henry Hub $ 5.30 $ 5.92 $ 6.23 $ 6.54 $ 7.16 basis local transport local tax 1.14% 1.14% 1.14% 1.14% 1.14% burner tip $ 6.01 $ 6.64 $ 6.96 $ 7.27 $ 7.90 We also run a scenario starting with the base gas price but with a 3% lower gas price in the target case than in the base case (about $6.75/MMBtu) to reflect that lower demand for gas (caused by greater renewable production here and possibly elsewhere) is associated with lower gas prices. This case is illustrative of the elasticity of gas prices 9 EIA Annual Energy Outlook 2015 can be found at 15

16 with respect to a change in demand that has been observed in EIA s work and a number of other studies. (See Appendix D) We modeled gas prices by simply scaling the costs from the production cost modeling directly related to natural gas (California gas costs) by the burner tip price. We made adjustments to the cost of California imports (20% fixed off-peak and 80% sensitive to gas price), and to start-up and shut-down costs of powerplants (50% fixed, as per combined cycle service agreements adding costs for starts, and 50% fuel-related). For conservatism, we did not change the cost of the relatively small amount of California exports, although gas prices might change them also. With these assumptions, overall, it appears that a 15% change in Henry Hub gas prices (13.5% change in gas prices delivered to California) causes a 9-10% change in the net benefits upward and 11-12% downward in the target case. Thus, at this level of sensitivity, the upward elasticity of benefits to gas price is 0.6 to 0.7, while the downward elasticity is 0.7 to 0.8. Given the minimal fossil imports and the tendency of coal prices to be correlated with gas prices, these elasticities will hold over a broader range of gas prices than +/- 15%, though low prices, particularly with high carbon prices, can reduce coal dispatch. The sensitivity to 3% lower gas prices in the target case relative to the base case showed about a 4% increase in production cost savings from the target case relative to the base case due to the lower gas price in the target case. This is approximately equal to using the mid-high case for both base and target. B. Carbon Prices The base case carbon price is $32.44/ton in 2014 dollars. This is estimated conservatively based on the California Energy Commission s low case scenario projected to In other words, it is less than the price expected in the CEC s base case. This price is bracketed by a low case of $17.84 CEC carbon price forecast low case, frozen at 2020 real levels and a high case of $51.48, which is the CEC s 2013 high case frozen in real terms in 2024 and projected to

17 We use proportional adjustments to the carbon price as well as the gas price because it will generally not affect dispatch. There is one exception. Of the nine combinations of low, mid, and high carbon and low, mid, and high gas, one case, the low-gas, high carbon sensitivity was deliberately designed to dispatch considerably more coal at the margin than any of the other eight cases. Therefore that case was separately run through the production cost model and was not treated proportionately in this analysis. This change in dispatch overwhelmingly occurs outside of California and has little impact on either CA production costs or carbon emissions because of the minimal fossil imports of any kind in all of the cases. However, WECC wide carbon emissions are significantly impacted. IV. Sensitivity of Production Cost Results to Gas and Carbon Prices A. Production Cost Sensitivity Analysis Production Cost Results are given below for the five gas price scenarios. Results are also compared (base case only) between the same conventional flexibility ( CF ) scenarios 10 and for the cases where high carbon and low gas prices were used to flip out of state marginal dispatch from gas to coal. The conventional flexibility scenarios are similar to the base case except that, a.) the ability of non combustion resources to supply Essential Reliability Services is limited to today s levels even though the physical ability to supply ESR and thus reduce gas consumption is significantly higher, b.) they do not have storage resources added (so their capital costs are also lower and Resource Adequacy ( RA ) capacity supplied by storage is also not included), c.) they also contain local generation requirements that result in natural gas plants being constrained on in light load hours causing higher curtailments of renewable energy, and d.) minimum amounts of out of state contracted renewable power must actually be imported into California in every hour even when energy is surplus in CA but not in the rest of WECC. Details of 10 Also referred to in several charts as Business as Usual or BAU scenarios. 17

18 how these assumptions were modeled can be found in the NREL report on the production cost modeling. Model runs also show the impacts of relaxing these dispatch constraints in the Base Case, of adding back these dispatch constraints in the target case, of a high solar case (which we also analyze in the capital cost section) where the investment portfolio is much less diverse, and, finally, a case with higher renewable penetration in other western states which limits export potential from CA. Low and high hydro cases were run, but those cases cannot be compared between the base case and the target case because hydro availability is a natural process, not a policy decision. All of these cases were analyzed under 6 gas price scenarios. Table 2: Differences between Base Case and Other Scenarios at Varying Gas Prices Baseline to Target Base Low Mid-Low Mid-High High Gas price and demand case * same scenario Base case gas price $ 6.96 $ 6.01 $ 6.64 $ 7.27 $ 7.90 $6.75 target Baseline Baseline BAU $ (66) $ (57) $ (63) $ (69) $ (75) Baseline High West Penetration $ 235 $ 204 $ 225 $ 246 $ 267 Baseline Low Gas / High CO2 $ 411 Baseline High West Penetration, Low Gas / High CO2 $ 454 Target $ 4,847 $ 4,331 $ 4,668 $ 5,015 $ 5,357 $5,019 $ 4,847 Target BAU $ 4,304 $ 3,853 $ 4,147 $ 4,451 $ 4,751 $4,490 $ 4,370 Target High West Penetration $ 4,962 $ 4,426 $ 4,776 $ 5,137 $ 5,492 $5,130 $ 4,726 Target BAU High West Penetration $ 4,467 $ 3,992 $ 4,302 $ 4,622 $ 4,937 $4,648 $ 4,533 Target BAU with locked DA import schedules $ 4,201 $ 3,767 $ 4,050 $ 4,343 $ 4,631 $4,391 $ 4,267 Target BAU with no 70% Import Requirement $ 4,807 $ 4,368 $ 4,655 $ 4,951 $ 5,242 $4,996 $ 4,873 Target BAU with no 25% local generation requirement $ 4,710 $ 4,202 $ 4,533 $ 4,875 $ 5,212 $4,884 $ 4,776 Target BAU with additional Storage / DR $ 4,977 $ 4,459 $ 4,797 $ 5,147 $ 5,490 $5,149 $ 5,043 Target High Solar BAU $ 4,071 $ 3,666 $ 3,931 $ 4,203 $ 4,471 $4,268 $ 4,137 Target High Solar $ 4,635 $ 4,176 $ 4,476 $ 4,785 $ 5,089 $4,820 $ 4,635 Target with 70% OOS RE Import Requirement $ 4,711 $ 4,197 $ 4,532 $ 4,879 $ 5,219 $4,884 $ 4,711 Target with 25% local generation requirement $ 4,682 $ 4,231 $ 4,525 $ 4,829 $ 5,129 $4,869 $ 4,682 Target with low gas / high CO2 $ 5,099 $ 4,688 Target High West with low gas / high CO2 $ 5,275 $ 4,821 Target with high hydro $ 5,024 $ 4,485 $ 4,837 $ 5,200 $ 5,557 $5,191 Target with low hydro $ 3,890 $ 3,481 $ 3,748 $ 4,024 $ 4,295 $4,086 Target BAU with high hydro $ 4,475 $ 4,009 $ 4,313 $ 4,627 $ 4,936 $4,658 Target BAU with low hydro $ 3,454 $ 3,097 $ 3,330 $ 3,570 $ 3,806 $3,661 * 6.96 base case,3% less ($6.75) target case The high solar case has lower production cost savings than the base case. This result may arise from the specific resources that were backed out to make room for the additional photovoltaic power, but it does raise questions regarding the value of PV power, particularly without the addition of new storage resources and with less dispatch flexibility in the conventional flexibility case. 18

19 An analysis of sensitivity to carbon costs was also conducted. Holding gas prices constant at base case levels, and moving to low carbon prices (the carbon price is 46% lower) the production cost savings were about 6-7% lower. In the high case, carbon prices rise by 58%, but production cost savings rise by 6-8%. Table 3: Differences between Base Case and Other Scenarios at Varying Gas and Carbon Prices base gas base carbon base gas low carbon base gas high carbon high gas low carbon high gas high carbon low gas low carbon low gas high carbon difference low gas high carbon Baseline Baseline BAU $ (66) $ (49) $ (88) $ (59) $ (97) $ (40) Baseline High West Penetration $ 235 $ 106 $ 404 $ 138 $ 435 $ 75 Baseline Low Gas / High CO2 $ 411 Baseline High West Penetration, Low Gas / High CO2 $ 454 Target $ 4,847 $ 4,528 $ 5,263 $ 5,038 $ 5,773 $ 4,012 Target BAU $ 4,304 $ 4,056 $ 4,628 $ 4,502 $ 5,075 $ 3,604 Target High West Penetration $ 4,962 $ 4,559 $ 5,487 $ 5,090 $ 6,017 $ 4,023 Target BAU High West Penetration $ 4,467 $ 4,158 $ 4,870 $ 4,628 $ 5,340 $ 3,683 Target BAU with locked DA import schedules $ 4,201 $ 3,993 $ 4,473 $ 4,422 $ 4,903 $ 3,558 Target BAU with no 70% Import Requirement $ 4,807 $ 4,570 $ 5,117 $ 5,005 $ 5,551 $ 4,131 Target BAU with no 25% local generation requirement $ 4,710 $ 4,400 $ 5,114 $ 4,902 $ 5,617 $ 3,892 Target BAU with additional Storage / DR $ 4,977 $ 4,695 $ 5,346 $ 5,208 $ 5,858 $ 4,177 Target High Solar BAU $ 4,071 $ 3,834 $ 4,380 $ 4,235 $ 4,780 $ 3,430 Target High Solar $ 4,635 $ 4,328 $ 5,036 $ 4,782 $ 5,490 $ 3,869 Target with 70% OOS RE Import Requirement $ 4,711 $ 4,396 $ 5,121 $ 4,904 $ 5,630 $ 3,882 Target with 25% local generation requirement $ 4,682 $ 4,436 $ 5,003 $ 4,882 $ 5,450 $ 3,985 Target with low gas / high CO2 $ 5,099 $ 4,688 Target High West with low gas / high CO2 $ 5,275 $ 4,821 Target with high hydro $ 5,024 $ 4,667 $ 5,490 $ 5,200 $ 6,023 $ 4,128 Target with low hydro $ 3,890 $ 3,661 $ 4,189 $ 4,066 $ 4,594 $ 3,252 Target BAU with high hydro $ 4,475 $ 4,203 $ 4,829 $ 4,665 $ 5,290 $ 3,737 Target BAU with low hydro $ 3,454 $ 3,282 $ 3,678 $ 3,635 $ 4,030 $ 2,926 B. Conventional Flexibility vs. Enhanced Flexibility Cases Dispatch Restrictions and Storage The conventional flexibility cases exclude new storage beyond the current CPUC mandate. However, they also place restrictions on dispatch. Therefore, the cases must be analyzed carefully. The difference between the target and target conventional flexibility case is $543 million of production cost savings, while storage costs add $390 million in fixed costs for a net cost decrease of $153 million between target and conventional flexibility. A similar difference ($177 million) is found between target and conventional flexibility in the high solar case. However, higher value cases can be found if dispatch assumptions can be selectively relaxed in the conventional case. A case relaxing either the 25% local generation constraint or the 70% deliverability of actual imports is cheaper than the target case with 19

20 storage. Conventional dispatch plus storage is also cheaper than the target case with storage, because the storage essentially cancels out the conventional dispatch options. The table below shows all of the results for the mid-case (mid-fuel, mid-carbon, and as they affect storage costs, mid-tech and mid-economic). Table 4: Production Costs vs. Storage Costs, Mid Case Production Cost Savings Relative to Baseline Storage Costs Storage RA Value Net Savings Baseline Baseline conventional flexibility (CF) ($66) Target $4,847 ($390) $121 $4,578 Target CF $4,304 $4,304 Target CF no 70% import $4,807 $4,807 Target CF no 25% local $4,710 $4,710 Target CF storage $4,977 ($390) $121 $4,708 Target with 70% import $4,711 ($390) $121 $4,442 Target with 25% local $4,682 ($390) $121 $4,413 Target High Solar $4,635 ($390) $121 $4,366 Target CF High Solar $4,071 $4,071 We also ran the high carbon case. It is apparent that the uneconomic dispatch options in the high carbon case are more costly, but the conventional flexibility case relaxing either the 25% local generation constraint or the 70% deliverability of actual imports is still cheaper than the target case with storage. 20

21 Table 5: Production Costs vs. Storage Costs, High Carbon Case Production Cost Savings Relative to Baseline Storage Costs Storage RA Value Net Savings Baseline Baseline conventional flexibility (CF) ($88) Target $5,263 ($390) $121 $4,994 Target CF $4,628 $4,628 Target CF no 70% import $5,117 $5,117 Target CF no 25% local $5,114 $5,114 Target CF storage $5,346 ($390) $121 $5,077 Target with 70% import $5,121 ($390) $121 $4,852 Target with 25% local $5,003 ($390) $121 $4,734 Target High Solar $5,036 ($390) $121 $4,767 Target CF High Solar $4,380 $4,380 The choice to build new storage beyond the current CPUC mandated level plus the storage that accompanies the new CSP facilities is thus a close case at the 2030 level of renewable penetration in this study. If dispatch assumptions cannot be relaxed, additional storage is clearly cost-effective to mitigate them. However, if dispatch assumptions can be relaxed in whole or in part, a no-storage option may offer greater net benefits than an option with storage. Stated another way, if we create a supply curve of mitigation options for overgeneration/curtailment, relaxing the dispatch assumptions are lower cost and additional storage is on the margin at this level of renewable penetration. Increasing the percentage of solar PV in the renewable portfolio pushes the mitigation options further out on the supply curve making storage more cost effective but does not change the basic conclusion. While it may be more cost-effective to spend no money on storage and simply change the rules, this does not mean that storage should not be added for other reasons, such as, developing experience and staging the overall portfolio toward increasing levels of 21

22 renewables in the 20 years following the end of this study period. In addition, bulk storage, especially pumped storage that consists of large synchronous machines provides a full range of ESR benefits including capacity value, voltage support, primary frequency response and transient stability. In any event, the storage that is included is presumed to provide RA capacity. V. Comparison of Capital Costs and Production Cost Savings Capital costs and production costs were compared to determine the costs and/or benefits of the 2030 strategy under various assumptions of economics, technology costs, and fuel and carbon prices. A. Economic/Interest Rate Scenarios The table below compares capital costs and production cost savings for the three different economic cases. The table includes the mid-low and mid-high gas prices in the low and high economic scenarios as discussed above. The mid-gas price is used in the mid economic scenario. The mid-carbon scenario is used here also. Table 6: Comparison of Capital Costs and Production Cost Savings, Economic Scenarios Target case assumptions produce net costs of $135-$232 million in the low and mid economics case, but in the high economics case with higher interest rates, the net costs rise to $523 million. The high solar case has worse economics at the mid technology case than the target case. Mid Technology Low Economics Mid Economics High Economics Capital cost base case $ 4,802 $ 5,078 $ 5,538 Target Production Savings $ 4,668 $ 4,847 $ 5,015 $ 135 $ 232 $ 523 Capital cost high solar $ 5,089 $ 5,383 $ 5,873 High Solar Production Savings $ 4,476 $ 4,635 $ 4,785 $ 613 $ 748 $ 1,088 22

23 Sensitivity to Technology Costs The technology cost cases have a greater impact on the difference between production costs and production cost savings than the assumptions regarding interest rates and economics. The mid gas prices were used in the technology scenarios, which are based on mid-range economic conditions. A fourth case was also prepared, with low photovoltaic prices and mid prices for other technologies. It had a greater effect on the high solar case. Table 7: Comparison of Capital Costs and Production Cost Savings, Technology Cost Scenarios Mid Economics Low Technology Mid Technology High Technology Low Solar, Mid Other Capital cost base case $ 4,495 $ 5,078 $ 5,738 $ 5,033 Target Production Savings $ 4,847 $ 4,847 $ 4,847 $ 4,847 Difference $ (352) $ 232 $ 891 $ 186 Capital cost high solar $ 4,310 $ 5,383 $ 6,144 $ 4,598 High Solar Production Savings $ 4,635 $ 4,635 $ 4,635 $ 4,635 Difference $ (326) $ 748 $ 1,509 $ (38) With lower technology costs the 50% renewable case is cheaper (capital costs less than production cost savings), but the high technology cost case generates almost $900 million of annual costs. B. Combination of Technology and Economics While we do not think the results are likely to end up at these extremes, we show here the low and high ranges where technology and economics converge. These cases bookend the analysis with relatively low probabilities at each end of the probability distribution. The gas price forecasts for the specific economic forecasts were used. A combination of high interest rates and high technology costs increases costs for the renewable future by more than a combination of low interest rates and low technology costs decrease it. 23

24 Table 8: Comparison of Capital Costs and Production Cost Savings, Interest Rate and Technology Cost Bookends Lowest to Highest Low Economics Mid Economics High Economics Low Technology Mid Technology High Technology Capital cost base case $ 4,261 $ 5,078 $ 6,275 Target Production Savings $ 4,668 $ 4,847 $ 5,015 $ (407) $ 232 $ 1,260 Capital cost high solar $ 4,084 $ 5,383 $ 6,716 High Solar Production Savings $ 4,476 $ 4,635 $ 4,785 $ (391) $ 748 $ 1,931 C. Sensitivity to Gas and Carbon Prices We analyzed sensitivities to the mid technology case together with varying gas and carbon prices, as well as the interaction of carbon prices and technology costs. As expected, production cost savings increased as gas and carbon prices increased, yielding lower net costs and net benefits in some cases. Two tables are given below. 24

25 Table 9: Sensitivity of Results to Gas and Carbon Prices (Mid Technology, Mid Economic Cases) Low Gas Low Gas Low Gas Mid Gas Mid Gas Mid Gas High Gas High Gas High Gas Low Carbon Mid Carbon High Carbon Low Carbon Mid Carbon High Carbon Low Carbon Mid Carbon High Carbon Capital cost target case $ 5,078 $ 5,078 $ 5,078 $ 5,078 $ 5,078 $ 5,078 $ 5,078 $ 5,078 $ 5,078 Target Production Savings $ 4,012 $ 4,331 $ 4,688 $ 4,528 $ 4,847 $ 5,263 $ 5,038 $ 5,357 $ 5,773 Net cost (benefit) $ 1,066 $ 747 $ 391 $ 551 $ 232 $ (184) $ 40 $ (279) $ (695) Capital cost high solar $ 5,383 $ 5,383 $ 5,383 $ 5,383 $ 5,383 $ 5,383 $ 5,383 $ 5,383 High Solar Production Savings $ 3,869 $ 4,176 N/A $ 4,328 $ 4,635 $ 5,036 $ 4,782 $ 5,089 $ 5,490 Net cost (benefit) $ 1,515 $ 1,207 $ 1,056 $ 748 $ 348 $ 601 $ 294 $ (107) N/A - case not run in production cost model; low gas and high carbon changes dispatch, so proportional extrapolation will not produce the result. Table 10: Sensitivity of Results to Technology and Carbon Prices (Mid Gas Price, Mid Economic Case) Low Tech Low Tech Low Tech Mid Tech Mid Tech Mid Tech High Tech High Tech High Tech Low Carbon Mid Carbon High Carbon Low Carbon Mid Carbon High Carbon Low Carbon Mid Carbon High Carbon Capital Cost target case $ 4,495 $ 4,495 $ 4,495 $ 5,078 $ 5,078 $ 5,078 $ 5,738 $ 5,738 $ 5,738 Target Production Savings $ 4,528 $ 4,847 $ 5,263 $ 4,528 $ 4,847 $ 5,263 $ 4,528 $ 4,847 $ 5,263 Net cost (benefit) $ (33) $ (352) $ (768) $ 551 $ 232 $ (184) $ 1,210 $ 891 $ 475 Capital cost high solar $ 4,310 $ 4,310 $ 4,310 $ 5,383 $ 5,383 $ 5,383 $ 6,144 $ 6,144 $ 6,144 High Solar Production Savings $ 4,328 $ 4,635 $ 5,036 $ 4,328 $ 4,635 $ 5,036 $ 4,328 $ 4,635 $ 5,036 Net cost (benefit) $ (18) $ (326) $ (726) $ 1,056 $ 748 $ 348 $ 1,816 $ 1,509 $ 1,108 25

26 D. Comparison to Expected 2030 Utility Revenue Requirements Our target case analysis shows a cost increase of $232 million (2014 dollars) in 2030 in the base case. While the cost increases will be different (and even become benefits) with different levels of gas and carbon prices and different economic and technological conditions, it is important to compare this result to the revenue requirement of the California IOUs in 2030, which the CPUC estimates to be $42.2 billion ($30.8 billion in 2014 dollars with 2% inflation from ). 11 Thus, the base case value of the change in costs is about a 0.75% increase in costs in Any of the figures in this analysis may be compared to that $30.8 billion figure to provide a general magnitude of the impact on utility ratepayers. Moreover, the CPUC revenue requirement estimate may be conservative in estimating rates for functions other than the generation and RPS resources that it was designed to analyze. Distribution revenue requirements rise at 2% inflation plus load growth, which may not take into account significant future system replacement needs or even the rate of labor and health care inflation experienced by the utilities, which has been greater than general inflation in recent decades. The E-3 model used by the CPUC also appears to assume that Diablo Canyon s license will be extended and that its costs will rise only at inflation until Therefore the $30.8 billion figure may be low, and the $232 million may be even a smaller fraction of future rates. E. Results Summary To assist understanding of the range of results, the following two figures show most of these results graphically. Figure 1 shows the range of results as a percentage of the estimated 2030 revenue requirements for the Mid-economic scenario for the three ranges 11 CPUC RPS Calculator Version 6.1 downloaded from 26

27 of renewable capital costs. The error bars for each case span the range of natural gas and carbon costs. The second set of dots in the mid-technology scenario shows the low cost solar, mid everything else sensitivity. Figure 1 Figure 2 shows the range of results for the range of macro-economic variables in the mid-technology case with the range of gas and carbon prices represented by error bars 27

28 Figure 2 28

29 VI. Appendix A A. Cost Assumptions for New Resources Capital cost assumptions for the technologies in the LCGS portfolios were developed based on E3 s March 2014 Capital Cost Review of Power Generation Technologies: Recommendations for WECC s 10- and 20-Years Studies (E3, 2014), which provides a comprehensive overview of data from various sources for the 2013 vintage installed cost of generation technologies in WECC at the time of publication. In some cases, E3 s data did not fit the needs of the LCGS and data from external sources was used to develop LCGS low, mid, and high assumptions. For example, E3 s geothermal cost data was not sufficiently technology-specific because it did not differentiate between binary and flash geothermal technologies. In other cases, such as solar PV, wind, and pumped hydro storage, installed costs have declined since the publication of E3 s report. In those cases, data from market reports that were published after the release of E3 s report was incorporated into the LCGS assumptions. Figure 1: Legend for installed cost comparison charts. E3 data Updated market report or other High Mid LCGS capital cost Low In the following sections are plots that compare the LCGS assumptions (low, mid, and high) for 2013 vintage installed costs with the underlying data compiled by E3 and any supplemental data that was used. A key for these plots is provided in Figure 1. For quick reference, all of the LCGS installed cost assumptions for 2013 vintage installations can be found in Table 11. Table 11: Installed costs for 2013 vintage technologies in the LCGS in 2014 dollars. Low Mid High Generation Capital cost ($/kw) FO&M cost ($/kw-yr) Biogas - landfill gas $1,647 $2,779 $3,003 $100 Biogas (other) $4,721 $5,600 $6,256 $120 Biomass $3,974 $4,465 $5,773 $120 CSP-TES (solar thermal) $6,525 $6,869 $7,600 $60 Geothermal - binary $2,496 $3,571 $5,279 $120 29

30 Geothermal - flash $4,016 $5,417 $6,819 $120 Wind $1,657 $1,912 $2,100 $30 Fixed PV* $2,460 $2,460 $2,860 $23 Tracking PV* $2,750 $2,750 $3,380 $23 Bulk storage - PHS $1,725 $1,898 $2,156 $16.60 Bulk storage - CAES $1,600 $1,500 $1,400 $16.60 Combined cycle $1,084 $1,238 $1,300 $9.30 Transmission** Capital cost (million $) WY wind - Delta, UT $1,906 $2,118 $2,542 NM wind - Four Corners $238 $264 $317 SWIP $480 $533.8 $641 *Solar PV is assumed to have an inverter loading ratio of 1.3 dc/ac. Solar PV mid and low cases are differentiated by their assumed cost declines (see Solar PV section below). **Transmission FO&M is included in the fixed charge rate. 1. Adjustments to capital costs To be useful, the assumptions in Table 11 need to be adjusted to reflect their installation year and location. E3 s paper provides both regional multipliers, which reflect difference in materials, equipment, and labor costs by state, as well as learning rates, which reflect anticipated cost declines for emerging technologies (wind, solar PV, solar CSP). E3 s data can be found in Table 12 and Table 13. The only adjustments that were made to E3 s data were in the solar PV learning rates. Details of that adjustment are in the Solar PV section, below. Table 12: Assumptions for regional multipliers, adapted from Table 35 in E3's report. Technology AZ CA NV NM UT WY Biogas Biomass Geothermal Hydro PS

31 Solar PV Solar (thermal) CSP Wind Fixed O&M Table 13: Assumptions for learning-by-doing cost declines for emerging technologies, based on Tables 39 and 40 in E3's report. Adjustments to solar PV data have been made to reflect updated market information. Technology Wind 100% 98.2% 94.9% 92.7% 91.1% Solar (thermal) CSP 100% 96.4% 83.2% 78.5% 73.8% Solar PV - fixed tilt (mid) 100% 84.5% 78.9% 73.5% 69.3% Solar PV - fixed tilt (low) 100% 70.5% 50.5% 46.4% 42.6% Solar PV - single-axis tracking (mid) 100% 84.8% 78.8% 73.5% 69.6% Solar PV - single-axis tracking (low) 100% 77.2% 55.8% 51.3% 47.2% 31