The SPM lists each of the cost-benefit tests described above and specifies which costs and benefits are included in the calculation for each test.
Some costs and benefits may be captured in an avoided cost designed for general application. For example, avoided costs capture the value of reduced natural gas usage. The inclusion of additional costs and benefits-or adders-in the calculation would reflect those impacts of a DG facility that are better (in the case of benefits) or worse (in the case of costs) than central station facilities or which are not captured by the avoided cost calculation at all.
Most parties agree with the basic list of costs and benefits identified by the Commission and reflected in the Itron Framework. However, the parties did not agree on specific values proposed for use in the SPM tests. We now turn to a detailed discussion of the disputed areas.
5.1. Utility and Program Administrator Costs
The utilities and the Itron Framework include in their cost-benefit tests the costs incurred by the utilities or program administrators for managing DG programs.13 No party opposed inclusion of these costs in the RIM, TRC, and Societal tests and we include them in the models we adopt today. CCDC, however, believes PG&E's interconnection costs are overstated and asks the Commission to inquire as to why those costs exceed the charges to DG customers.
The administrative costs that should be included in the SPM tests should be current actual program administrative costs, including any interconnection costs, as reported by the SGIP and CSI program administrators in their quarterly reports to Energy Division. With regard to CCDC's concerns about interconnection costs, one suggestion was to rely on expected CEC research on interconnection costs rather than utility estimates, but that research has not been completed. Therefore, we direct that where actual, project specific data on interconnection is available, it should be used. Where it is not available, we will rely on utility data of actual aggregate or program-wide interconnection costs. We direct the utilities and program administrators to develop data collection capabilities and work with Energy Division to provide the necessary cost information, including interconnection costs, to enable us to apply the SPM tests and cost-benefit methodology as soon as possible. After our first cost-effectiveness review of DG programs is complete and to the extent parties still dispute these utility interconnection costs, the ALJ or assigned Commissioner may solicit further comments, or hold workshops or hearings to resolve such disputes and refine this variable in the future cost-benefit tests accordingly.
5.2. Line Losses
DG facilities reduce utility line losses because the energy resource is at the customer's premises, or is in or near a load center, and therefore does not need to be transported over transmission lines. There is some debate about how to reflect a project's size in the cost-benefit calculation. SDG&E/SCG observes that the cost-benefit calculation could make simplifying assumptions for small projects. For projects more than 100 kW, SDG&E/SCG suggests that engineering studies are required to calculate avoided transmission and distribution (T&D) costs and line losses.
In D.07-09-040,14 the Commission noted that line loss adjustments could be determined in accordance with the methodology adopted in D.01-01-007, and declined to modify the line loss adjustment calculation. (D.07-09-040, at 75.) While we had initially considered using the line loss methodology adopted in D.01-01-007, parties commented in response to the proposed decision that the data required for the methodology adopted in D.01-01-007 is no longer available from the California Independent System Operator (CAISO). Solar Alliance and FuelCell Energy suggest we estimate line losses using the system-wide line loss assumptions in the E3 Avoided Cost Calculator. We agree that this approach is reasonable, and we will adopt that suggestion.
5.3. T&D Investment Deferrals
The Commission has found that DG facilities can reduce the need for new investment in utility T&D facilities. D.03-02-068 adopted several criteria for assessing the extent to which a DG facility might receive payment from a utility to substitute for T&D investments, among them the requirements that the facility be operating in time for the utility to avoid system expansion, that it must be of a size that serves the utility's planning needs, and that it provide a "physical assurance" that the customer will not ever require the utility service that would have otherwise been provided over the deferred investment. (See D.03-02-068, at 18.) Thus, D.03-02-068 adopted criteria for contracts between DG owners and utilities for T&D investment deferrals, which are site-specific. The decision does not discuss recognition of T&D deferral benefits for DG projects collectively.
CCDC and ASPv believe cost-benefit models should identify T&D investment deferrals as among the benefits of DG, notwithstanding the specific characteristics of an individual facility. CCDC makes a distinction between DG that is incorporated into a utility's resource plan and affords the utility distribution system benefits (i.e., "grid-side DG") and DG that is analogous to energy efficiency and is not included in a utility's resource plan (i.e., "customer-side DG").15 CCDC states that there is no basis for applying the strict physical assurance requirements adopted in D.03-02-068 to customer-side DG, and requests that a more flexible approach be adopted for this proceeding. CCDC argues that the Commission should rely on the diversity of DG projects rather than physical assurance in evaluating customer-side DG avoided costs because these customer-side DG projects, when viewed collectively, are likely to have very strong reliability benefits as shown for DG cogeneration projects, and the probability of simultaneous forced outages is very low. ASPv proposes to measure the physical assurance of DG projects at the program or portfolio level, which would recognize the combined value of the state's DG facilities. ASPv believes that even a single DG facility provides value to the system in terms of avoided T&D usage, although it does not estimate that value. CAC/EPUC asks the Commission to assure that large cogeneration plants receive recognition for transmission and distribution investment deferrals.
SDG&E/SCG, PG&E, and SCE argue that the inclusion of this benefit is contrary to the Commission's existing policy and that the DG parties have not justified the automatic inclusion of T&D deferrals in cost-benefit calculations for every DG installation. PG&E concedes that such a benefit might at some point be included in cost-benefit methodologies when there is sufficient DG in its territory that system planners can rely on their availability.
SDG&E/SCG believes the Commission should continue to recognize the prospect for DG projects to respond to load growth, recommending that projects be evaluated in the context of the distribution planning process established pursuant to Section 353.5.
The policy we adopted in D.03-02-068 relates to utility control over planning and operations of its T&D system. In that decision, we found that a utility could contract with a DG owner for a deferral of utility T&D investments only in specific circumstances where a DG facility meets our "physical assurance" criteria, that is, it can demonstrate its location, capacity and operational characteristics justify a utility investment deferral. The policy context in D.03-02-068 is payment to specific DG facilities for investment deferrals. In this decision, we turn to the separate and distinct issue of estimating the collective T&D investment deferral benefits of DG in an effort to analyze the net costs and benefits of our DG programs.
We find no compelling reason to change our existing policy regarding contracts for T&D deferrals, as adopted in D.03-02-068, that are relied on for utility resource planning. We intend to measure the benefits of any contracts for T&D deferrals by applying the existing criteria to specific projects, as set forth in D.03-02-068. We concur with SDG&E that this is a matter for consideration on a plant-specific basis and consistent with each utility's distribution planning process and D.03-02-068.
That being said, we can still include in our DG cost-benefit methodology an estimation of collective DG T&D investment deferrals, including DG facilities that do not meet the physical assurance criteria. It would be unnecessarily restrictive to apply the physical assurance criteria from D.03-02-068 since many smaller DG projects are not required to meet these criteria to interconnect. We agree with CCDC and ASPv that a more flexible approach is needed for cost-benefit evaluation purposes to measure the collective benefit of DG facilities. It is possible to consider the diversity of installations and the collective benefit to the T&D system of high DG penetration levels in certain geographic areas. Therefore, we find it reasonable to attempt to measure a T&D deferral benefit based on DG penetration, location, and diversity levels.
Itron's SGIP Year 6 Impact Report uses this approach and demonstrates that a collective measurement of T&D deferrals is feasible when specific characteristics of each DG technology are taken into account.16 As predicted, there is not a significant value until the DG resource is on-line and properly located. Still, the value should not arbitrarily be set to zero when it can be measured. Thus, we direct that the Itron methodology, which uses the E3 calculator as set forth in the SGIP Year 6 Impact Report, be used to estimate T&D deferrals, if any, for either grid-side or customer-side DG installations, without regard to whether the DG facilities are included in a utility's resource plan. Again, we reiterate that use of this Itron methodology to estimate T&D investment deferrals does not in any way modify the specific physical assurance or other requirements in D.03-02-068 for contracts between DG facilities and utilities for distribution capacity deferrals. In addition, this estimation of collective T&D benefits is not intended to prejudge any other Commission proceedings regarding prices for wholesale DG.
5.4. Electricity Market Price Impacts
Some parties propose that the cost-benefit calculation recognize lower electricity market prices that might occur as a result of a DG project's operation. This effect is also referred to as "price elasticity of demand." The Itron Framework includes a price elasticity adder in its Societal and RIM tests, in accordance with the E3 avoided cost methodology.
SCE, SDG&E/SCG, and PG&E oppose including a variable for market price impacts in the equation. SCE contends that DG can reduce market prices in the near term if penetration of DG is not anticipated by the wholesale electricity market and oversupply results. However, SCE further contends that if the Commission's resource adequacy requirements assure the proper investment in new resources, DG simply offsets new construction and there should be no lasting effect on market prices. (SCE Comments, 2/25/09, at 8.) The Solar Alliance observes that the E3 methodology included a price elasticity adder in the years when new supply-side resources were assumed to not be needed. At this time, since the California utilities are actively adding resources according to their adopted long-term procurement plans, the Solar Alliance agrees there is no need for a price elasticity adjustment in the RIM and Societal Tests. (Solar Alliance Comments, 3/9/09, at 15.) We find these arguments persuasive, namely, that if DG resources are planned, we should not assume their addition will impact market prices. Therefore, we will not include a price elasticity adder in the RIM, TRC or Societal Tests.
5.5. Reliability Impacts
The Itron Framework includes a reliability adder from the E3 avoided cost methodology. Some parties agree that the cost-benefit calculation should include increased system reliability as a benefit. Conceptually at least, DG may improve system reliability under certain circumstances, for example, by providing a dispersed and versatile source of power supply. On the other hand, those reliability benefits could be offset by the unpredictability of a DG customer's need for power from the utility's system or an operator's decision to shut down the generator when market prices are low.
SDG&E/SCG states that enhanced systemwide reliability is unlikely but concedes that DG has the potential of reducing reliability costs for a utility where DG reduces peak load in constrained areas. It believes these benefits will be nearly zero by 2010, however, when new generation is expected to come on-line. SDG&E/SCG also states that DG does not have the control capabilities to provide ancillary services and should therefore be treated as load reduction for purposes of ancillary services and VAR support, as Itron proposes. SDG&E/SCG proposes the Commission use the values presented in the E3 report and adopted in D.05-04-024.
PG&E believes the avoided cost calculation reflects a DG facility's value as a generation resource generally, although it does not assign more or less reliability to the DG facility than a central station facility. In comments on the proposed decision, PG&E asserts that the E3 reliability adder is "overly optimistic" and suggests further study is necessary before it is used. (PG&E Comments, 7/9/09 at 9.)
CCDC concurs that quantifying the value of DG to the transmission system will not be possible immediately and proposes the utilities be ordered to conduct a transmission system simulation to determine those potential benefits. The utilities oppose such an effort as time consuming and expensive, and believe this type of task is part of the CAISO's transmission system planning process. CCDC also recommends that the Commission adopt E3's estimate for transmission reliability improvements by DG during peak hours.
The extent to which DG projects can improve reliability is unclear. Nevertheless, we believe that, on balance, DG facilities may relieve the strain on some critical elements of the utility system, as SDG&E/SCG observes. The Itron Framework proposes using the same E3 reliability adder which values reliability benefits from demand reductions and is currently used for evaluation of energy efficiency programs. Use of the existing E3 reliability adder assumes reductions in demand caused by DG have at least roughly the same reliability impacts as changes in demand caused by energy efficiency or any other source of fluctuation. We will include the reliability adder in the E3 avoided cost methodology we use in our SPM tests, as suggested in the Itron Framework, at least for now.
At the same time, it is worth noting that in the Commission's Resource Adequacy rulemaking (R.08-01-025), the Commission adopted a new methodology for analyzing the peak load contributions of utility-scale renewable generation from intermittent resources, such as wind and solar power plants.17 The outcome of this new methodology in the Resource Adequacy context could impact our findings here on how to incorporate reliability assumptions for intermittent DG resources into our cost-benefit analysis. We will direct our Energy Division to further study whether the outcome of that proceeding affects our decision here to use the E3 reliability adder. After such further study, Energy Division should report to the ALJ and assigned Commissioner whether modifications to this decision are necessary, and the ALJ and assigned Commissioner will determine if further Commission action is needed.
DG facilities may also improve the reliability of the DG customer because of its value as back-up power or voltage support. We do not have estimates of the value of a DG facility to the customer who owns it. To the extent the utility or the project developer has developed an estimate for each project and this information is readily available, it may be reported by program administrators as additional useful information, but we will not incorporate this information into the cost-benefit tests at this time.
5.6. Employment and Tax Revenue Effects
DG proponents propose the Commission include increased employment and tax revenue as among the benefits of DG. The utilities argue, however, that we have no evidence from our current record in this proceeding to suggest that DG installations would create more jobs than those displaced as a result of the reduced demand for central station generation facilities. At this time, therefore, we cannot quantify a variable for increased employment or tax revenue for inclusion in our cost-benefit models.
Nevertheless, we see value in working towards quantifying an employment and tax revenue effect from our DG programs. We recognize that DG projects, particularly solar installations through our CSI program, have created jobs in California for the past several years. On the other hand, we lack any quantification of how this job creation compares to potential reductions in jobs at the utilities to build central station generation or other facilities. As part of our program evaluation plan for CSI, we intend to examine employment effects of our CSI program. At the same time, we will require the contractor performing the DG cost-benefit analysis to suggest a methodology for quantifying the employment and tax revenue effects of our DG programs so that parties can comment on this area further. Once the contractor has suggested a methodology, the ALJ can solicit comments or hold a workshop on this topic to consider whether to include these effects in future cost-benefit analyses. This quantification of employment or tax effects should not be included in the SPM tests until further Commission proceedings are held on this topic.
5.7. Market Transformation Effects
Some DG Proponents propose the Commission treat DG development as a "market transformation" program and that the cost-benefit calculations include market transformation effects as a benefit. Market transformation in this context refers to development of a self-sustaining market for DG whereby customers have a wealth of potential suppliers of DG and can make independent and free-ranging choices about DG installation. We would also expect a transformed market to need minimal or no public subsidies in order to remain competitive and support multiple providers and options for consumers. PV Now explains that the models presented in this proceeding are narrowly defined to promote immediate resource acquisition and do not take into account the more important long-term objectives of assuring that photovoltaic technologies, in particular, are sustainable in competitive markets without subsidies. CalSEIA, the City of San Diego and ASPv offer similar comments.
SCE and SDG&E/SCG object to recognizing market transformation objectives in cost-benefit models, claiming that attempts to measure the market transformation effects of DG would be expensive and unjustified. They also believe the SGIP program has been developed as a resource acquisition program rather than one that is intended to have long-term market impacts. We disagree.
This Commission has stated its strong support for solar photovoltaic generation and other DG technologies as part of a larger effort to promote the development of a diverse and environmentally sound energy production system. For example, in D.06-01-024, where the Commission established the CSI program, the Commission explicitly acknowledged that solar technologies may not be cost-effective yet, but determined that an incentive program was justified as a means of market transformation. In D.06-01-024, the Commission stated:
Our decision today is informed by our view that a common sense program of monetary incentives, combined with technical assistance, could promote less expensive and more efficient technologies. We also approach our task here with the understanding that solar technologies may not be as cost-effective as other clean alternatives, in particular energy efficiency efforts and certain other renewable distributed generation technologies. However, a solar incentive program will aid California's transition to an affordable clean energy portfolio. We are convinced that a cost-effective and sustainable solar market is unlikely to develop without a commitment for market support that is both long-term and finite. For that reason, we state our intent to monitor the progress in the market place, and to modify the program on the basis of ongoing evaluation. (D.06-01-024, at 4-5.)
Similarly, Senate Bill (SB) 1, the legislation codifying the CSI program, acknowledges the resource acquisition goal for CSI, but further declares that it is the goal of the state "to establish a self-sufficient solar industry in which solar energy systems are a viable mainstream option for both homes and businesses in 10 years."18 It appears both the Commission and the Legislature view the CSI as a market transformation program, at least in part. Therefore, we find that market transformation benefits are legitimately included in a cost-benefit evaluation of DG programs.
Moreover, the Commission has expressed support for DG in the Energy Action Plan, requiring DG to be deployed ahead of other energy production technologies. The SGIP program is explicitly designed to promote DG development, as are several tariff exemptions or discounts for DG operators and customers.
There is no question that the Commission has take action directly supporting the development of a viable market for DG projects, especially those using renewable resource technologies, as alternatives to energy facilities employing fossil fuels, coal and nuclear resources. Notwithstanding the short-term goals of the SGIP and CSI programs, we believe the programs will and should influence the types of energy technologies deployed in California and the structure of the state's energy production and delivery system.
The value of "market transformation" is neither specified nor quantified in the early record of this proceeding. Subsequently, Itron produced a report in February 2007 entitled "Solar PV Costs and Incentive Factors" (Solar Cost Report)19 that examines the key relationships between solar PV performance, cost, and incentive levels. The report includes an assessment of the impact of incentive levels on program results based on different funding scenarios. Itron's Solar Cost Report finds that these forecast scenarios illustrate the impacts of performance and cost factors on program goals and incentive design. (Exhibit 39 at 2-2.) In addition, E3 provided to Energy Division a discussion draft in May 2007 entitled "SGIP Market Transformation Effects Evaluation Methodology." This E3 draft suggests a method for forecasting the future cost-effectiveness of SGIP and then evaluating the attribution of cost reductions to SGIP (i.e., the "market transformation" effect of the program) through a learning curve analysis, expert interviews, and literature review.
The Itron Solar Cost Report and the E3 draft indicate to us that there are reasonable methods to estimate the market transformation effects of our DG programs. Now that we have several years of SGIP data, and after CSI has been operational for a few years, it may be possible to use either the Itron scenario approach or the E3 method to perform qualitative assessments of the market transformation effects of our programs. Therefore, we direct Energy Division to ensure the consultant who performs the cost-benefit analyses of our DG programs uses either of these methods, or a reasonable substitute, to analyze and estimate the market transformation effects of CSI and SGIP. The consultant should first perform the SPM tests without any market transformation analysis, and then conduct a second set of the SPM tests that incorporates a market transformation component. The purpose of the market transformation assessment is to demonstrate if or when the incentive program for a DG technology is cost effective and the market significantly transformed, or when the program is expected to be cost-effective, under the different SPM tests given a variety of scenarios. We expect the overall cost-benefit analysis to include an assessment of the progress towards the goal of market transformation, and an analysis of how the cost-effectiveness test results might be expected to change as the markets for various DG technologies evolve.
We acknowledge that any market transformation analysis will involve scenario analysis and a host of assumptions. Among other things, these assumptions will likely include varying levels of future total installation costs for DG. Parties will undoubtedly want an opportunity to examine and critique the analysis. Therefore, we anticipate that after a consultant performs a market transformation analysis as part of the cost-effectiveness review of our DG programs, the ALJ or assigned Commissioner may choose to hold workshops, hearings, or solicit comments to consider refinements to the market transformation analysis.
5.8. Reduced T&D and Commodity Revenues
The Itron Framework includes measurement of decreased T&D revenues and foregone commodity revenues from reduced sales of electricity or natural gas. PG&E and SCE contend that when a customer installs DG, there is a resulting loss of T&D and commodity revenues by the utility and this "lost revenue" is borne by other customers through the process of revenue allocation and rate design. PG&E believes these reduced revenues should be included in the Participant Test (as a benefit) and RIM Test (as a cost to ratepayers), but not the TRC or Societal Test.
CAC/EPUC objects to including purported "lost" revenues as a cost, believing that lower revenues are offset by lower costs. CAC/EPUC also believes the Commission should follow the Federal Energy Regulatory Commission (FERC) precedent and assume that such lost revenues are normal business risk. PG&E responds that T&D costs are generally fixed and ratepayers remit T&D revenues on a volumetric basis. In addition, the RIM test does not measure losses to the utility but to ratepayers. Even if T&D costs fell, ratepayers would not receive the benefits of lower costs between general rate cases.
The Solar Alliance and IREC claim the RIM test should not include reduced commodity revenue because the utilities should have followed Commission directives and included DG in their long term procurement planning.
Under existing ratemaking, the Commission authorizes a distribution and non-fuel generation revenue requirement for each utility, and then sets rates based on a forecast of sales. If sales are lower than the forecast, the difference is tracked and the utility's ratepayers must ultimately make up any reduced revenues to allow recovery of the authorized distribution and non-fuel generation revenue requirement. Transmission rates are regulated by FERC, and if a utility's sales differ from forecast, it will see reduced transmission revenues and most likely seek rate adjustments in its next transmission rate case at FERC. Accordingly, this is not a case where utility "business risk" is an issue. The risk is ultimately borne by the ratepayer. As customers install DG and no longer pay these charges, non-participating ratepayers may ultimately see higher charges. Therefore, in order to ensure an accurate assessment of how DG facilities affect ratepayers, we agree that reduced transmission, distribution and non-fuel generation revenues should be included as a cost in the RIM test, and as a benefit in the Participant Test. The benefit included in the Participant Test is measured as the exemption from standby charges, which is discussed further in Section 5.12 below. The estimates for these costs to ratepayers would be based on actual utility rates and the DG output from facilities installed under our incentive programs, as derived from utility rate tariffs and DG production data.
In addition to distribution and non-fuel generation charges, the utilities recover their actual purchased power and fuel related generation costs (also called procurement or commodity costs). Solar Alliance and IREC raise a valid point that utility procurement costs already factor in a DG load forecast. As a utility's sales drop, the utility presumably buys or generates less power or gas and incurs lower costs. In other words, the commodity revenue a utility "loses" would simply have paid the fuel or purchased power cost the utility did not have to buy or generate. There is no need to include reduced commodity revenue as a cost if the cost is avoided. Moreover, if a utility buys less power or fuel for a smaller customer base, it is not a given that the remaining customers will pay a higher cost. It would be speculative to assume that reduced commodity revenues translate into a cost for non-participating customers.
5.9. DG Project Costs
All parties agree that the costs of installing and maintaining DG units should be included in the Participant Test and the Societal Test. We agree that this is appropriate.
CalSEIA proposed to measure DG project costs using estimates of future costs at lower levels than that presented in existing databases. SDG&E/SCG believes the Commission should use data collected from the SGIP and the CEC's Emerging Renewables Program (ERP). SDG&E/SCG observes that this data are derived from actual facilities' costs.
We have no basis upon which to forecast future technology costs and we are not convinced that future costs provide an appropriate proxy for current project costs. We intend to use actual data to measure the costs of DG projects. As costs fall, they will be reflected in the databases. The SGIP and CSI programs both have project tracking databases that reflect project costs and this actual program data should be used. The CEC retains some data tracking such costs associated with solar photovoltaic projects, which could be used as well. Otherwise, estimates available through manufacturers for specific technologies should be included in the analysis.
5.10. Environmental Values-CO2, NOx, and PM 10 Emissions
The Itron Framework describes how DG, in displacing conventional central station generation, may have environmental impacts. To the extent these environmental impacts are not internalized by the marketplace, the Itron Framework suggests a method for placing a value on these impacts and including them in the Societal Test. The method suggested in the Itron Framework relies on the E3 environmental adder, derived from the E3 avoided cost calculator. The Itron Framework notes this has been a fairly standard practice in California when assessing energy efficiency options.
The utilities generally support the use of the E3 calculator for generation and fuel to recognize air quality improvements from DG.20 The E3 data incorporates reductions in carbon dioxide (CO2), nitrogen oxides (NOx) and particulate matter 10 (PM 10) emissions.
CCDC would modify the E3 environmental adder by reflecting the actual mix of existing and expected power plants and their operating characteristics rather than using futures prices to estimate electricity market prices. The CCDC estimate would affect emission costs for CO2, NOx and PM 10. CCDC states that the dirtiest power plants are those most likely to be used during peak periods, and these marginal units should be included in the model, at least for the early years of a DG project. CCDC recognizes that emission avoided costs should be tailored by DG technology, time period, and facility location. CCDC also believes the E3 Report's use of the New York Mercantile Exchange (NYMEX) futures prices does not accurately reflect California conditions and an environmental adder would improve the price estimate in that regard.
We will not adopt CCDC's proposed modification to the E3 environmental adder at this time. As we have previously noted, D.06-06-063 updated natural gas and generation costs for the E3 calculator and its environmental adder. These updated avoided costs and environmental adder are used when evaluating energy efficiency programs, and we conclude that we should apply the same method when evaluating DG in order to compare resource options with a consistent set of avoided costs. As environmental values used for cost-effectiveness evaluations of energy efficiency programs are updated, the same updates should be applied here.
PG&E believes that DG facilities may increase CO2 emissions relative to central station plants because modern plants burn fuel at a much higher heat rate. It therefore proposes that this impact be included as a net cost of DG facilities.
We wish to capture all benefits attributable to DG facilities and, in particular, to recognize those that improve environmental quality. In addition, we note that the method proposed in the Itron Framework includes modification of the E3 environmental adder for individual technologies to reflect the net CO2 impacts of DG. We find this approach addresses PG&E's concern that we capture the net cost of DG facilities.
We herein adopt the Itron Framework's method for valuing environmental benefits along with the updated avoided costs from D.06-06-063, which incorporate environmental values for CO2, NOx, and PM 10, for use in the TRC, Societal, PA Cost, and RIM tests. Again, as these environmental values are updated by the Commission for use in energy efficiency evaluations, the same values should be applied in DG cost-effectiveness tests.21
5.11. Combined Heat and Power Applications
CCDC proposes that the E3 avoided cost estimate for fuel and generation be modified to recognize that cogeneration uses a single fuel to produce electricity and production heat. SDG&E/SCG agrees that this benefit would always accrue to the DG customer and may represent a societal benefit if the efficiency of the DG facility is higher than a central station plant. SDG&E suggests these benefits would be plant-specific and believes the Itron Framework appropriately accounts for them.
We agree that the Participant, TRC, and Societal Tests should include a value that recognizes more efficient use of cogeneration facilities, where appropriate. We will direct that these tests include an estimate of the related plant-specific characteristics. This approach was described in Appendix A3 of the Itron SGIP Evaluation Report (dated September 2005) and in the SGIP Year 5 and Year 6 Impact Reports (dated March and August 2007, respectively).
5.12. Standby Charges
The Itron Framework includes the loss of revenues from exemptions from standby charges as among the costs that should be included in the RIM Test. SDG&E/SCG concurs with this methodology and suggests estimating this cost using data it has collected as part of the SGIP program.
SCE believes that if the revenue shortfall from standby charges is not offset by total DG benefits, Section 353.9 requires that the shortfall be recovered from members of the DG class only.
We agree that this standby charge exemption should be included as a cost in the RIM Test, because it represents a revenue loss, and also as a benefit in the Participant Test. Estimates would be derived using the utilities' rate tables and according to the DG facilities' production. We also agree in principle with SCE's observation that any revenue shortfall requires recovery according to the terms set forth in Section 353.9. This latter issue involves revenue allocation, which is outside the scope of this proceeding. We therefore defer this matter to proceedings that allocate revenues among rates and customer classes. For SCE and PG&E, this would be in their respective general rate cases. For SDG&E, this could be in its general rate case or "rate design window" application.
In comments on the proposed decision, IREC raises the concern that including standby charge exemptions as a cost in the RIM and PA Cost Tests could result in double counting of lost T&D revenues. (IREC Comments, 7/9/09 at 3.) PG&E acknowledged this concern in earlier comments. (PG&E Comments, 3/9/09 at 9.) We recognize the complexity of electricity ratemaking and the difficulty, at times, in deciphering actual standby costs. Despite this complexity, we agree with IREC that it is important to not double count costs. To the extent standby charge exemptions are already included as lost revenues, as discussed in Section 5.8 earlier in this decision, they should not be counted twice.
Similarly, Solar Alliance comments that including standby charge exemptions as a cost is inconsistent with current studies of the diversity benefits of standby customers. (Solar Alliance, 7/9/09, p. 7.) We disagree with this comment, because the cost-benefit methodology we adopt in this decision already incorporates benefits of the diversity of DG facilities through efforts to quantify T&D deferral benefits and reliability benefits of DG.
5.13. Electric and Natural Gas Avoided Costs
The parties generally agree that DG facilities allow the utilities to avoid commodity and capacity costs for electricity and natural gas. SDG&E/SCG proposes that we adopt the E3 values adopted in D.05-04-024. SCE and PG&E would apply those values until the Commission has modified them for DG in a later phase of that proceeding. In D.06-06-063, the Commission refined the interim avoided costs adopted in D.05-04-024.
As stated in Section 3.2, we herein adopt the E3 avoided cost methodology for electric and natural gas avoided costs, as adopted in D.05-04-024 and updated in D.06-06-063, and with the inputs currently applied to energy efficiency evaluation. These avoided costs should be used in the DG cost-benefit analysis as set forth in Attachment A of this decision.22
5.14. Net Metering
Certain renewable DG projects qualify for "net metering," which permits a DG operator to receive bill credits for electricity delivered to the utility. Under net metering, a DG customer will receive bill credits when the DG system is producing more electricity than the customer needs. These bill credits may be applied against charges incurred by a DG customer for electricity consumed at other times. For solar DG less than 1 MW and wind DG less than 50 kW, the amount of the net metering bill credit is equal to the fully bundled retail rate of electricity that the customer would otherwise pay.23 The fully bundled net metering credit includes a generation component as well as a T&D component. The fully bundled net metering credit amounts to a payment-in-kind that can be substantially in excess of the avoided cost the utility would otherwise pay to procure electricity and that a DG facility would otherwise receive for selling wholesale power to the utility. Moreover, DG customers who qualify for net metering credits still use the T&D system to export energy to the grid.
Because bill credits under net metering are a subsidy from ratepayers to DG facilities, SDG&E/SCG proposes to include them as a cost in the RIM Test.
We agree with SDG&E/SCG that bill credits under net metering are an incentive designed to promote DG development, and we agree that energy exported to the grid by DG facilities in excess of their annual load is a benefit of net metering. Because we are able to measure both bill credits under net metering and energy exports, we intend to include both the costs and benefits of net metering in the appropriate tests. Net metering bill credits are a cost in the PA Cost, and RIM Tests. They are a benefit for the Participant Test. By the same token, energy exports are a benefit for the PA Cost, and RIM Tests. However, the benefit of energy exports should already be included in the tests when DG production is calculated and energy purchases are avoided based on that calculation. To the extent the tests already calculate avoided costs based on estimated DG production, we should not include a separate variable for energy exports or we would count the benefit twice. Finally, NEM costs and benefits represent transfers in both the TRC and Societal Tests, and are therefore omitted from these tests.
5.15. Exemptions from the Cost Responsibility Surcharge
The Cost Responsibility Surcharge (CRS) permits the collection of power purchase liabilities incurred by the Department of Water Resources (DWR) during the state's energy crisis, which are generally more expensive than market prices. DG projects under 1 megawatt (MW) and the first MW of clean DG units that do not exceed 5 MW are exempt from the CRS. (See D.07-05-006.)
The utilities argue that the RIM Test should reflect the loss of CRS revenues when a DG facility goes on-line, as the Itron Framework recommends.
CAC/EPUC believes the RIM Test should not include reduced CRS revenues because DWR did not purchase power for DG customers and small DG customers are exempt from CRS charges. CCDC makes similar comments.
CAC/EPUC is correct. Lost revenues associated with exemptions from CRS should not be accounted for in the RIM Test. In developing its strategy for purchasing power during California's energy crisis, DWR believed that it could rely on a forecasted amount of DG power to meet the state's energy demand and purchased power supplies accordingly. For that reason, we found in D.03-04-030 that certain DG facilities should be exempt from the CRS. D.03-04-030 found that DWR excluded 3,000 MW of power for DG from its forecast, and therefore the exemption is not a cost shift. For this reason, we conclude that lost CRS revenues should not be considered a cost in the RIM Test.
5.16. SGIP and CSI Incentives
Currently, both the CEC and this Commission sponsor incentive programs for renewable DG projects through SGIP and the CSI. Once we establish that DG facilities should be analyzed using the cost-benefit tests described in this decision, there is no controversy about whether and how to recognize these incentives in the models. As the utilities suggest, these incentive payments are appropriately considered a cost in the TRC, Societal, RIM, and PA Cost Tests and as a benefit in the Participant, TRC, and Societal Tests. The incentive amounts are available through the program rules and databases and are readily applied according to facility characteristics and performance.
5.17. Tax Incentives
Both the state and federal governments provide tax incentives for certain types of DG projects. No party opposes recognizing these subsidies in the models. They should be included as benefits in the Participant Test.
For both the TRC and the Societal Test, federal tax incentives should be included if we define the relevant "society" as California and the benefit of these incentives flows into California from federal taxpayers. State tax incentives would not be included because they are merely transfers within California.24
Tax incentives should be estimated using Internal Revenue Service regulations and State Franchise Tax Board rules, or the information provided by DG vendors.
13 The CSI and SGIP programs are administered by the utilities in the PG&E and SCE territories and by the CCSE in the SDG&E territory.
14 D.07-09-040, Opinion on Future Policy and Pricing for Qualifying Facilities, September 20, 2007, R.04-04-003/R.04-04-025.
15 CCDC Opening Brief, 6/27/05, at 16.
16 See Section 5.3 "Transmission and Distribution Impacts," SGIP Year 6 Impact Report, Itron, August 30, 2007. The Itron methodology uses the E3 calculator and compares DG facility hourly generation profiles against hourly distribution line loadings. For each technology, a reliability curve is developed based on the measured data to produce a probability of achieving a given amount of load reduction.
17 See D.09-06-028, Section 4.10, in R.08-01-025.
18 See Section 4 of SB 1 (Ch 132, Stats of 2006), which adds Section 25780(a) to the Public Resources Code.
19 "CPUC SGIP: Solar PVCosts and Incentive Factors," Itron Inc., February 2007 (Exhibit 39).
20 PG&E initially argued in its 2005 testimony and briefs that no value should be given to DG environmental effects if they are not regulated or their mitigation mandated. PG&E states in its July 2009 comments on the proposed decision that it has dropped this position and it now agrees that environmental values used in other Commission avoided cost proceedings should also apply to DG, both as potential costs and benefits.
21 We note that the California Air Resources Board, in its Climate Change Scoping Plan adopted December 11, 2008, has stated its intention to implement a cap and trade program beginning in 2012 to limit total GHG emissions from covered sectors consistent with Assembly Bill 32, the California Global Warming Solutions Act of 2006. Under this framework, emission allowances would be issued such that the sum of total emissions would not exceed the level of the cap. Because the deployment of renewable DG will not change the number of allowances in circulation once the cap goes into effect in 2012, these facilities may not result in emission reductions below the level of the cap. While the deployment of clean DG will reduce the carbon liability of the electricity sector, thereby reducing the number of allowances the electricity sector needs to purchase to cover its carbon liability, these allowances would presumably be procured by other entities such that total emissions under the cap remain unchanged. As such, while from the perspective of the electricity sector, the costs of these emission permits will be avoided, from a societal view, there may be no reduction in GHG emissions or their costs. To the extent the Itron framework ascribes a specific value to the societal benefit of avoided GHG emissions from DG, the methodology may require adjustments to account for the implications of a cap and trade system on the ability of DG deployment to change total emissions. We do not take steps to amend the methodology and address this issue at this time, but we reserve the right to evaluate whether further adjustments to environmental impact values are necessary to account for the implementation of a cap and trade program.
22 We note that the E3 calculator may not fully reflect the value that customer-side DG, or other demand side resources, provide in terms of reduced renewable energy obligations. By reducing a utility's retail sales, which serve as the basis for determining a utility's renewable procurement needs, these customer-side resources lower the amount of renewable energy that needs to be procured, all else equal. To the extent that renewable resources are more expensive than conventional resources, we believe there may be some value that DG and other demand side resources provide that is not being fully quantified. While we do not address this issue specifically here, Energy Division will work with E3 to ensure that in the future this value is fully and appropriately incorporated into the E3 calculator.
23 For larger wind DG (greater than 50 kW, but less than 1 MW), biogas DG less than 1 MW and fuel cell DG less than 1 MW, the amount of the net metering bill credit is equal to the generation component of the rate only.
24 If the TRC or Societal Test were performed with the relevant society defined as one utility's service area as opposed to statewide, then state tax incentives could be treated as a benefit. At this time, we choose to run the TRC and Societal Tests based on a statewide definition of society in order to evaluate our DG programs on a statewide basis.