EFFICIENCY OF SOLAR NET METERING & RELATED POLICIES IN THE UNITED STATES

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1 EFFICIENCY OF SOLAR NET METERING & RELATED POLICIES IN THE UNITED STATES James Heidell 1, PA Consulting, , Overview In the United States, the number of behind the utility meter customer-owned photovoltaic systems has grown substantially. Data compiled as of 2013 indicates that a cumulative total of over 6 GW of residential and commercial net metering installations at over 500,000 sites in the United States. While these installations are a small percentage of U.S. installed generation capacity, non-utility distributed installations increased by approximately 50% in 2013 with potential for significantly more growth. The increase in installations has been enabled by federal and state tax policies, utility rebates, net metering policies, and dramatic declines in installed system cost. Depending on one s perspective, this rapid growth can be viewed as both a success for U.S. renewable energy policy and PV technology, or as a threat to the utility business model spurned by inefficient policies. Accordingly, the associated tax policies, utility incentives, and net metering rules have become the subject of increasing controversy. The renewable energy policy debate has numerous dimensions, including the associated benefits attributed to job creation, regional economic development, energy security, and the environmental benefits from emission reductions associated with utilizing non-carbon-based fuels. In particular, the net energy metering (NEM) policy debate centers on economic efficiency and customer equity arguments. This paper explores the efficiency of NEM policy by conducting an economic analysis of residential net metering in four states that account for approximately 70% of the distributed installed solar net metering capacity and have the largest installed base amongst the states: California, Arizona, New Jersey, and Colorado. Economic efficiency in this paper is measured with tests that have been robustly applied to energy efficiency utility programs in the United States. The analysis incorporates consideration of the long term avoided costs, including electric generation, transmission, and distribution. Estimates of environmental benefits associated with avoided CO 2 emissions, variable cost of production as well as potential associated reliability costs are based upon third party models, analysis conducted by PA Consulting, and market data. Our analysis confirms the cost effectiveness from the participant s perspective. This is not surprising given the rapid growth in installations in the states examined. The cost effectiveness for residences is driven by significant tax credits and rate design coupled with the net metering policy. From a societal perspective it is not as clear that the residential PV systems are as cost effective based upon consideration of net benefits. However, the calculation of societal net benefits is subject to significant controversy with regards to perspectives on the value of avoided carbon emissions and broader national and regional economic impacts. This paper commences with an overview of the issue followed by a review of the economic efficiency tests applied. A summary of the net metering rules, and the key utility and tax incentives for the four states analyzed is also provided. The key data assumptions and sources consulted are summarized. Multiple scenarios related to costs and benefits are evaluated since there is both considerable uncertainty and disagreement regarding the estimate of long-run avoided costs. Finally, the results of the analysis and associated conclusions are presented. 1 The author wishes to thank Matt Mooren, David Cherney, and Gabe Segal of PA Consulting for their review of the paper and assistance with providing supporting data

2 Net Metering Policies Net metering policies for retail customers are implemented on a state-by-state basis. At this point net metering policies exist in 43 states. These policies typically have two major components: interconnection standards and associated tariff terms and conditions. Standardized interconnection requirements for systems below a threshold capacity are typically established at the utility level to decrease transaction costs while maintaining safety. In most states the customer takes service under their otherwise applicable rate schedule but for net metering. While net metering typically involves separate meters for the on-site production and for utility purchases, the policies effectively only charge customers for electricity used in excess of production. Net metering tariffs allow for netting solar generation in excess of the customer s load against periods where the customer s load exceeds the solar generation. This netting is typically accumulated over a one year period with associated policies for the rate at which customers are paid for any generation in excess of total load on an annual basis. A number of policy tools are utilized in the U.S. to subsidize and promote the penetration of distributed renewable resources (primarily solar photovoltaic systems). These policies include a 30% federal tax credit associated with the initial system cost, state income tax credits, sales tax exclusions, property tax exclusions, utility payments for the associated renewable energy credits, and utility bill reductions through net metering. In addition, some states further promote small PV systems through mandates for minimum levels of distributed generation as part of their renewable portfolio standards. Advocates for net metering frequently point to the cost savings associated with offsetting conventional generation costs along with transmission and distribution cost savings. Advocates also point to additional benefits including: Reducing system peak loads and deferring infrastructure additions, Reducing the intensity of CO 2 emissions in the electric power generation sector, Promoting an emerging technology and driving down the costs of the technology through economies of scale, Job creation and economic development, and Reliability and security benefits associated with a distributed power supply. However, there is considerable controversy surrounding the benefits of NEM. Detractors of policy often argue that the credits provided to customers exceed the benefits of the energy produced and that the policy unfairly shifts costs to non net metering customers. While most state net metering policies are less than a decade old, a number of utilities are trying to change net metering policies as the penetration of distributed PV increases. Two modifications frequently discussed are the replacement of net metering with credits for the value of the distributed generation produced and implementation of a monthly charge per kw of solar capacity to pay for the fixed costs of the transmission and distribution system that NEM customers rely upon. Utilities in the three of the four states reviewed have recently conducted efforts to impose a fee on net metering. A summary of net metering in these states and recent policy debates are shown in Table 1. The remainder of this paper examines the costs and benefits of net metering with emphasis on the longrun avoided cost savings associated with residential customer-owned PV systems. 2

3 Table 1: Net Metering Summary for Study States Policy / State CA AZ CO NJ Max Participants / No aggregate No aggregate Percent of Load capacity limit capacity limit Charge for Net Metering Cap removed but customers under 5% participation limit are grandfathered for 20 years under existing policy Rejected in 2012 as conflicting with state law disallowing additional charges. A law in 2013 allows for utilities to reexamine net metering the sooner of reaching state caps or 2017 $0.70 / kw-month for installations after 2013 Xcel program for additional charge under Review No current limit but regulator can limit participation to 2.5% of peak load No charge. The state recently accelerated the requirement for distributed generation to prop up the solar REC market Set Aside 2.05% in 2014 increasing to 4.1% from solar by 2028 Evaluating the Economic Efficiency of Net Metering This paper uses four approaches to evaluate the economics of NEM. These different approaches have historically been used to evaluate utility sponsored energy efficiency programs. The four methods of evaluation are: The societal view, referred to as the Total Resource Cost (TRC) test, The utility s view, referred to as the Utility Cost Test (UCT), The ratepayer s view, referred to as the Rate Impact Measure (RIM), and The participant s view, referred to as the Participant Cost Test (PCT). The TRC text measures whether the value of the resources saved by the policy exceeds the costs to achieve the savings. The benefits are the value of the resources saved (measured by their avoided cost) while the costs include those borne by the utility, the participants, third parties, and by non-participants. The UCT assesses whether the policy will reduce the utility s cost to serve relative to what would otherwise occur. The benefits of the program are the costs the policy causes to be avoided, namely the avoided energy, capacity, emissions, and transmission and distribution (T&D) costs that result because of the actions arising from the policy. The costs of the policy include the cost the utility incurs as a result of the policy, including incentives paid to participants, the costs of administering the program, integrating the energy injected into the system, metering and interconnecting the systems (if paid for by the utility), etc. 2 The RIM test measures the impact of the policy on the utility expenditures of non-participants. The RIM uses the same measure of benefits as the UCT. For the costs, it uses the UCT measure of costs but adds the revenue lost from the policy. 2 There are other potential benefits of distributed generation that may, or may not, be explicitly (or implicitly) valued in the Utility Cost Test. These include the effects of the renewable penetration on risk (fuel prices, capital costs, or interest rates) or on reliability. 3

4 The PCT test looks at the costs and savings to the participants. Finally, we note that the components of these tests can also be used to separately identify the value of distributed generation service. A summary identifying which costs are included in each test is provided in Table 2. The sum of the benefits and the costs included in each test are used to calculate a benefit / cost ratio. Benefit cost ratios for each state and each of the four tests are reported later in this paper. The components of avoided costs are detailed in the next section. Table 2: Components of the Economic Tests TRC RIM UCT PCT Component Benefit Cost Benefit Cost Benefit Cost Benefit Cost System Cost X X Income Taxes X Program Costs X X X Avoided Costs X X X Avoided Bills X X REC Revenues X A number of advocates of net metering have recently argued to go beyond the tests that have been historically used in utility regulatory proceedings to include a range of wider benefits including job creation, economic development, and energy security. It should be noted that the substitution of a generation source not only creates economic activity for the new source, but also reduces economic activity associated with the substituted generation. The analysis is also complicated if the measurement is based upon incremental benefits, but for a policy, versus absolute benefits. These considerations are beyond the scope of this paper. In addition, the scope of externalities that should be incorporated in the social test is frequently debated. Addressing the debate about externalities is beyond the scope of this paper. However, the analysis presented includes a scenario that incorporates the social cost of CO 2. Components of the Avoided Cost Analysis The four economic tests summarized above typically incorporate calculation of the long-run avoided components summarized in Table 3. The costs in Table 3 are included in the analysis presented in this paper. Additional components that are sometimes included are shown in Table 4. The costs in Table 4 are not incorporated in the analysis presented in this paper. 4

5 Table 3: Utility Avoided Costs Components Calculated Avoided Component Energy costs Generation capacity Transmission capacity Distribution capacity Avoided CO 2 Renewable energy credits Generation integration. Comment / Issues Long run avoided electricity costs including an adjustments for line losses Based upon selection of the combustion turbine as the proxy capacity unit and an adjustment for the reliability and coincidence of distributed solar. The coincidence factor can vary with level of solar penetration. Includes an adjustment for losses. Note, selection of the proxy unit and the capacity benefit attributed to PV are typically controversial items. Numerous methodologies are used in this calculation including the value of deferring capacity additions or examining historical expenditures. This approach used in this analysis depended on what the referenced utility used. Calculation includes line losses. Separating reliability from capacity improvements is often controversial. Numerous methodologies are used in this calculation including the value of deferring capacity additions or examining historical expenditures. This approach used in this analysis depended on what the referenced utility used. Significant controversy over how to measure this, or whether distributed solar may create additional costs. Calculation includes line losses savings. Analysis uses forecasts of market prices where there are current or anticipated market-based CO 2 costs. A separate scenario considers social costs of CO 2. The use of a market or social cost is a controversial issue. Analysis incorporates the value of RECs transferred to the utility or reduced REC requirements from lower retail loads. Controversy over whether this constitutes double counting since the value is often incorporated into utility incentives Costs associated with serving intermittent load (ancillary services & ramping). There is considerable disagreement over the calculation of these costs and how they are likely to change at different penetration levels of intermittent resources. Table 4: Avoided Costs Components Sometimes Used Avoided Component Fuel hedging Environmental externalities Non-utility social benefits Grid security Comment / Issues Attribution of value to decreased reliance on natural gas, a fuel that has significant price volatility Externalities beyond CO 2. Typical other air pollutants include NOx, SOx, and particulates. Items such as job creation and state economic development Benefits of a distributed power source. Table 4 is not intended to be exhaustive but collectively Tables 3 and 4 highlight the principle components of avoided costs. The tables also highlight the issue that there is not only significant controversy regarding what components to measure, but also on how to measure a particular component. Any analysis of net metering benefits inevitably reflects some biases regarding what constitutes an avoided cost that should be measured and how to measure the those costs. In the review of literature associated with net metering analysis there are significant differences in how the utilities and other parties evaluate avoided costs. This paper attempts to apply a consistent methodology across the four states of interest so at least the relative cost effectiveness of the net metering policy can be considered. Study Methodology & Data Sources A variety of data sources were used to develop the avoided cost estimates for this study. These data sources include: Studies conducted by utilities and solar energy advocates in the states of interest, PA Consulting forecasts of: marginal energy costs, marginal capacity costs, CO 2, prices, and REC prices, 5

6 PV system costs and estimates of hourly production data from the System Advisor Model developed by the U.S. National Renewable Energy Laboratory, and Various databases and models developed by and reported by the U.S. Department of Energy s Energy Information Administration. A review of recent studies highlight that depending on the entity sponsoring the study, there are typically large differences in assumptions regarding the social value, environmental value, and economic development value of PV energy. As a result, different studies of the same program often have radically different conclusions regarding the cost effectiveness of net metering. A model was developed to evaluate the net metering programs in the four states using the previously described economic tests. A representative utility was used for each state in the model for assumptions regarding customer electricity rates and loads and for transmission and distribution avoided costs. The model uses a single natural gas price forecast for Henry Hub across the four states with state-specific adjustments for hub basis and transportation from the hub. The model incorporates two scenarios for carbon. The low scenario reflects either a forecast of carbon costs under the current regulatory regimes that are in place for New Jersey and California, or utility forecasts for Colorado and Arizona where there are currently no state carbon regulations. A high scenario uses the social cost of carbon as published by the U.S. Government in May 2013 under Executive Order The model relies on the estimates of marginal distribution and transmission costs proposed in the referenced studies. Since one of the focuses of the paper is the economic impacts of high penetration of distributed renewables, the selection of avoided T&D costs and coincidence factors is biased towards estimates related to high penetration. Economic Analysis of four Utility / State Net Metering Programs A more detailed discussion of the assumptions used in the economic analysis of the four state net metering programs is provided in this section. A summary of the analysis for each state is also provided with a discussion of the collective results provided in the next section. Colorado The net metering analysis model inputs were derived from multiple sources including: an analysis prepared by Public Service Company of Colorado (PSCo), a critique of the PSCo study prepared by Crossborder Energy, and PA forecasts and analysis of multiple data sources. Key analytic assumptions follow. Use of the combustion turbine cost as the proxy for generation capacity, Development of the associated generation capacity credit using PSCo s solar capacity credit assumption, Avoided energy costs are estimated using PA s forecast of the market heat rate and natural gas costs, Two CO 2 cases are analyzed: PSCO s CO 2 cost and the social cost of carbon, Ten years of REC purchases by the utility at the current rate, Transmission limited benefits associated with deferral of capacity improvements, and Distribution limited benefits are anticipated at high penetration and potentially an increase in losses 3 Note this forecast is not without controversy. However, it was selected as a study that is intended to be exclusive of a wide range of externalities. 6

7 Three cases were developed for sensitivity analysis. The key differences between the cases are shown in Table 5. The twenty year levelized benefits are shown in Figure 1, tabular results provided in the appendix, and the results of the economic tests are shown in Table 6. (The definitions of what are costs and what are benefits in each test are provided in Table 2.) The second scenario highlights the substantial increase in benefits associated with shifting from a market cost of carbon to a social cost of carbon. The third case highlights the policy mandates for renewable energy create value and the consequences of meeting mandates and removing the demand for incremental renewable energy credits. Table 5: Colorado Scenarios Data Assumption Case 1 / Scenario 1 Case 2 / Scenario 2 Case 3 / Scenario 3 CO 2 Utility case Social cost of CO 2 Utility case REC payment Current policy Current policy No payment High penetration impacts Reduced T&D benefits + intermittency costs Figure 1: Colorado Residential PV Benefits Table 6: Results of Colorado Economic Tests B/C Ratio Test Scenario 1 Scenario 2 Scenario 3 UCT RIM TRC PCT

8 New Jersey This analysis has some unique differences to the three other regions analyzed since New Jersey has enacted retail choice and the regulated electric utilities have divested their rate-based generation. While the regulated utility serves as a provider of last resort, the utility s marginal energy cost is equal to the expenses recovered in rates for providing electricity. A second difference is that the state developed a program where the utilities, in general, did not offer rebates or directly purchase the customers RECs. Qualified systems are granted SRECs through the state s Clean Energy Program. SRECs are awarded based upon metered production for the first 15 years of production. Customers can retain SRECs and sell them in the market but the more common approach is to transfer to title to the installer (or system owners in the case of leased systems) in exchange for a reduction in the system purchase cost. SRECs are currently priced well above the required level of payment required over a fifteen year period to make the system economical to the owner. The SREC market is generally liquid for about a three year period. In the net metering model the price of SRECs was reduced after year three to a levelized cost necessary for the a system installed in year four to have a NPV of zero at the home owner s discount rate. The net metering analysis model inputs were derived from a study prepared by the Mid Atlantic Solar Energy Industries Association & Pennsylvania Solar Energy Industries Association as well as PA analysis and assembled data. Key analytic assumptions include the following. A PA forecast of avoided long run capacity cost based upon the PJM Reliability Pricing Model (RPM) construct, A PA wholesale electric energy price forecast for eastern PJM, Two CO 2 cases are analyzed: A PA forecast of CO 2 costs under the current Regional Greenhouse Gas Initiative (RGGI) and the social cost of carbon, Fifteen years of REC sales; three years at the current market price and the remaining years at a price necessary to support new residential installations, and Transmission & distribution based upon assumptions regarding the value of deferred investments. Three cases were developed for sensitivity analysis. The key differences between the cases are shown in Table 7. The twenty year levelized benefits are shown in Figure 2, tabular results shown in the appendix, and the results of the economic tests are shown in Table 8. Note that the current prices for solar RECs are a large driver of the value for Scenario 4. These prices are created by short term shortages in PV as a result of a carve-out for solar as part of the state s RPS standard. As the market responds to the shortage of solar generation the price of the RECs decline. That state has already responded to the price decline once by increasing demand through accelerating the compliance schedule for the solar carve-out an mandates for set-asides. Scenarios 5 and 6 illustrate the drop in benefits in incremental residential PV once the carve-out mandates are met. The impact of switching from the benefits based upon the social cost of carbon to benefits based upon the market cost of carbon is highlighted in the sixth scenario versus the fifth scenario. Table 7: New Jersey Scenarios Data Assumption Case 1 / Scenario 4 Case 2 / Scenario 5 Case 3 / Scenario 6 CO 2 RGGI case Social cost of CO 2 RGGI case REC payment Current policy No payment No payment High penetration impacts Reduced T&D benefits + intermittency costs 8

9 Figure 2: New Jersey Residential PV Benefits Table 8: Results of New Jersey Economic Tests B/C Ratio Test Scenario 4 Scenario 5 Scenario 6 UCT RIM TRC PCT Arizona The Arizona analysis has one scenario with no assumed incentives since Arizona Public Service Company s funding for incentives was depleted in September The utility is awaiting Arizona Corporation Commission decision regarding renewed funding of incentives. Consequentially, there is also a scenario assuming the recent historical incentives. The net metering analysis model inputs were derived from studies prepared by SAIC for Arizona Public Service (APS) and a study prepared by Cross Border Energy as well as PA analysis and assembled data. Key analytic assumptions include the following. Use of the combustion turbine cost as the proxy for generation capacity, Development of the associated generation capacity credit using APS s solar capacity credit assumption, Marginal production costs are estimated using PA s forecast of market heat rate and natural gas costs, 9

10 Two CO 2 cases are analyzed: Assuming the California CO 2 forecast starting in 2021 (used by APS) and the social cost of carbon, Currently APS is not paying incentives since the utility has exhausted the dedicated funding. The second scenario assumes incentive funding is renewed at the previous level, Transmission & distribution based upon the fore-mentioned reports, and Inclusion of a state income tax incentive in addition to the federal incentive. Three cases were developed for sensitivity analysis. The key differences between the cases are shown in Table 9. The twenty year levelized benefits are shown in Figure 3, tabular results are shown in the appendix, and the results of the economic tests are shown in Table 10. APS currently does not offer incentives for customer owned PV systems. However, Scenarios 7 and 8 assume that the regulator directs the utility to allocate new funding to restore the prior incentives. The current policy of no incentives is reflected in Scenario 9. The most significant driver of the change in benefits between Scenarios 8 and 9 is that Scenario 9 excludes the estimate of the social cost of carbon and instead assumes a policy enacted in Table 9: Arizona Scenarios Data Assumption Case 1 / Scenario 7 Case 2 / Scenario 8 Case 3 / Scenario 9 CO 2 Utility case Social cost of CO 2 Utility case REC payment Prior policy Prior policy No payment High penetration impacts intermittency costs Reduced T&D benefits + intermittency costs Figure 3: Arizona Residential PV Benefits 10

11 Table 10: Results of Arizona Economic Tests B/C Ratio Test Scenario 7 Scenario 8 Scenario 9 UCT RIM TRC PCT California The California analysis is based upon the Pacific Gas and Electric Company (PG&E) service territory and assumes the current time-of-use rate schedules that incorporate significant inclining block prices in the higher residential energy blocks. However under A.B. 327, passed in 2013, there are likely to be rate structure and net metering changes in the future. The analysis also assumes the current NEM rate structure and does not take into account that the California investor owned utilities are authorized to submit revised NEM tariffs for new net metering customers after the earlier of reaching the 5% of peak load level from net metering or July 1, The analysis also does not assume that there are any more residential solar PV billing credits as the utility has meet its targets and therefore no longer offers an incentive. The net metering analysis model inputs were derived from studies prepared by the California Public Utilities Commission; a study prepared by Cross Border Energy as well as PA analysis and assembled data. Key analytic assumptions include the following. Use of the combustion turbine cost as the proxy for generation capacity, Development of the associated generation capacity credit using the E3 solar capacity credit assumption, Marginal production costs are estimated using PA s forecast of market heat rate and natural gas costs, Two CO 2 cases are analyzed: assuming the California CO 2 forecast starting in 2021 (used by APS) and the social cost of carbon, The residential customer owns the RECS so in one case we assume that the customer receives a credit, probably through the installer, equal to the value of the RECs to the utility. The second scenario assumes that the RECs do not have value, and Transmission & distribution based upon the fore-mentioned reports. Three cases were developed for sensitivity analysis. The key differences between the cases are shown in Table 11. The twenty year levelized benefits are shown in Figure 4, tabular results are provided in the appendix, and the results of the economic cost benefit tests are shown in Table 12. Table 11: California Scenarios Data Assumption Case 1 / Scenario 10 Case 2 / Scenario 11 Case 3 / Scenario 12 CO 2 Utility case Social cost of CO 2 Utility case REC payment Utility Value Utility Value No payment High penetration impacts intermittency costs Reduced T&D benefits + intermittency costs 11

12 Levelized $/MWh Figure 4: California Residential PV Benefits Scenario 10 Scenario 11 Scenario 12 Marginal Energy Marginal Capacity Marginal T&D RECs CO2 Table 12: Results of California Economic Tests B/C Ratio Test Scenario 10 Scenario 11 Scenario 12 UCT RIM TRC PCT Results The economic benefits of net metering vary significantly based upon the test applied, the state / utility analyzed, and the assumptions regarding long run avoided costs. A summary of the range in levelized benefits is shown in Figure 5. Significant drivers of the analysis include the electric rates avoided by the customer with net metering, assumptions regarding long-run avoided utility costs, and the value of the reductions in CO2 emissions. Avoided utility costs varied significantly across the scenarios. A key issue is the assumptions used regarding how higher penetration of customer-owned distributed generation impacts: the electric distribution system, changes the utility s load shape, and the cost of the utility to maintain a stable grid with growing amounts of intermittent generation. Our analysis does not take into account any significant shift of load that could cause a shift in the utility peak. 12

13 Figure 5: Summary of Benefits A summary of the results of the cost benefit tests is provided in Figure 6. This summary is based upon averaging the results across the three scenarios for each cost benefit test and state analyzed. A discussion of the results and implications of each test follows. Participants Cost Test Figure 6: Summary of Cost Benefit Tests State PCT UCT RIM TRC Colorado New Jersey Arizona California In most of the states and scenarios the PCT was slightly less, or greater than one despite the phase out of utility production and installation cost incentives. This suggests that distributed residential PV in the states examined is near the point of grid parity with the current combination of tax policy, market value of RECs, rate design, and financing options. Presumably, wide scale penetration will not occur without the systems yielding positive net benefits to the customer. In other words, when the PV systems have exceeded the rate parity threshold penetration may dramatically increase. This analysis used a conservative twenty year system life. Additional utility support, beyond net metering, for PV in the residential sector does not appear to be necessary assuming further anticipated PV system cost reductions and the continuation of tax incentives. The 30% investment tax credit to offset federal income taxes is a significant factor in the economics of PV. This tax credit is scheduled to expire at the end of 2016 and in the near term system cost reductions will not be sufficient to offset the loss of the tax credit. Therefore, the rate of growth in residential systems in the four states examined is anticipated to fall off after However, this is a high level conclusion that depends on a number of parameters and the analysis is utility market specific. The history has been that the state and utility policies have responded to changes in the economics of PV in order to meet goals and / or regulations regarding the contribution of distributed generation. Utility Cost Test Results In all the scenarios the UCT is positive. This result is not surprising in that the test evaluates the ratio of the marginal cost savings to the net metering program costs. Program costs are relatively low for New Jersey, Arizona, and California since the analysis is based on current policies where there are no customer payments from the utility. This test does not consider the change in revenue requirement and rates necessary for the utility to have an opportunity to earn its allowed rate of return even with lost net 13

14 metering load. Given the ideal of perfect regulation, that the revenue requirement is adjusted to maintain the target revenue requirement, net metering does not harm the utility based upon the UCT. However, the test does not take into account the impact on overall rates, impacts on non-participants, and that utilities can be financially harmed absent mechanisms to recover the lost margin. Ratepayer Impact Measure In all of the scenarios the RIM test has a ratio less than one. The implication is that non-participants will have to pay more since the sum of the revenue losses and program costs exceed both the short run and long run avoided cost savings. The level of residential rate increases necessary for the utility to maintain its target revenue requirements were calculated at different penetrations. The rate impact test coupled with assertions that solar PV is typically installed by higher income customers frequently leads to the argument that NEM is not an equitable policy. Analyses that the NEM customers are not paying their fair share of the costs is typically one of the arguments put forth to support proposed NEM policy changes. The calculations of the RIM test were used to develop a high-level estimate of the rate increases necessary to recover lost utility margin based upon different levels of distributed PV penetration. The analysis contains two simplifying assumptions: The level of costs and benefits associated with each system does not change with higher penetration, and The lost margin is recovered solely within the residential rate class. The results of the analysis are shown in Table 13. The 15% residential penetration level is considered reasonable in a number of the studies reviewed. The increases at the 15% level shown for California are likely to be less since the investor owned utilities are in the process of doing some rate redesign that will reverse the recent trend of excluding the lower residential energy blocks from rate increases. Table 13: Levels of Residential Rate Increases Residential 2.5% 5% 10% 15% Penetration Colorado 1.0% 2.1% 4.3% 6.7% New Jersey 2.2% 4.4% 9.0% 14.9% Arizona 1.1% 2.2% 4.7% 7.4% California 3.1% 5.6% 11.9% 18.9% Total Resource Cost Test The total resource cost test results are less than one across all of our scenarios. It should be noted that with the exception, of the scenarios of incorporating the social cost of carbon, externalities are not priced into the models. In addition, as previously noted the analysis does not consider the macro economic benefits of net metering versus other energy policies. Incorporation of externalities can increase the value of the TRC test significantly. Finally, it is readily noted that others have ascribed greater values to the marginal T&D and other savings and consequentially have achieved values greater than one for the TRC test. Given the direction of these tests, it raises the question of whether the most efficient policies are in place to support resource acquisition in general, as well as to achieve renewable energy generation goals. 14

15 Conclusions Net energy metering and associated tax incentive policies have been instrumental in driving the growth of PV systems installed on the customer side of the meter. However, the current implementation may not be an economically efficient and sustainable long-term utility policy as the penetration of installations increases. Issues with the policy in conjunction with higher penetration include: creating non-economic price signals for customer to bypass utility generation and cost shifting that leads to distorted price signals for non-participants. Uneconomic bypass can lead to higher societal costs and potential cross subsidies that may be contrary to other economic / social policies being pursued by the regulator. The instances where the programs fail the economic tests suggests that alternative polices should be considered in order to improve the allocation of resources. 15

16 References AEO2014 Early Release Overview, Report Number DOE/EIA-0383ER (2014) Electric Power Sales, Revenue, and Energy Efficiency Form EIA-861, U.S. Energy Information Administration, U.S. Solar Market Insight Report the 2013 Year-in-Review, GTM Research & SEIA, California Standard Practice Manual Economic Analysis of Demand-Side Programs and Projects, October The Value of Distributed Solar Electric Generation to New Jersey and Pennsylvania, Clean Power Research, November Evaluating the Benefits and Costs of Net Metering in California, R Beach & Patrick McGuire, Crossborder Energy, January The Benefits and Costs of Solar Distributed Generation for Arizona Public Service, Crossborder Energy, May Updated Solar PV Value Report, SAIC, May Benefits and Costs of Solar Distributed Generation for the Public Service Company of Colorado. A Critiques of PSCO s Distributed Solar Generation Study, Crossborder Energy Thomas Beach & Patrick McGuire, December 2, Costs and Benefits of Distributed Solar Generation on the Public Service Company of Colorado System, Study Report in Response to Colorado Public Utilities Commission Decision No. C , Xcel Energy Services, Inc., May Evaluating the Benefits and Costs of Net Metering in California, Beach & McGuire, Crossborder Energy, January In the Matter of Establishing a Distributed Solar Value Methodology under Minn. Stat. 216B.164, subd. 10 and (f), Staff Briefing Papers, Minnesota Public Utilities Commission, March 12, Comments Value of Solar Methodology Docket No. E999/M-14-65, Xcel Energy, February 13, The Value of Distributed Solar Electric Generation to New Jersey and Pennsylvania, Clean Power Research, Perez, Norris & Hoff, November California Net Metering Ratepayer Impacts Evaluation, California Public Utilities Commission Energy Division, October Technical Support Document: - Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis - Under Executive Order 12866, Interagency Working Group on Social Cost of Carbon, United States Government, May 2013 System Advisor Model, Version , National Renewable Energy Laboratory. 16

17 Appendix I. Results of the Cost / Benefit Analysis Table 14: Colorado 20 Year Levelized Costs & Benefits ($/MWH) Benefits Costs Category Scenario 1 Scenario 2 Scenario 3 Scenario 1 Scenario 2 Scenario 3 Marginal Energy Marginal Capacity Marginal RNS Marginal T&D RECs CO Integration Costs Program Costs Solar Billing Credits Table 15: New Jersey 20 Year Levelized Costs & Benefits ($/MWH) Benefits Costs Category Scenario 4 Scenario 5 Scenario 6 Scenario 4 Scenario 5 Scenario 6 Marginal Energy Marginal Capacity Marginal RNS Marginal T&D RECs CO Integration Costs Program Costs Solar Billing Credits Table 16: Arizona 20 Year Levelized Costs & Benefits ($/MWH) Benefits Costs Category Scenario 7 Scenario 8 Scenario 9 Scenario 7 Scenario 8 Scenario 9 Marginal Energy Marginal Capacity Marginal RNS Marginal T&D RECs CO Integration Costs Program Costs Solar Billing Credits

18 Table 17: California 20 Year Levelized Costs & Benefits ($/MWH) Benefits Category Scenario 10 Scenario 11 Scenario 12 Scenario 10 Scenario 11 Scenario 12 Marginal Energy Marginal Capacity Marginal T&D RECs CO Costs Integration Costs Program Costs