8. Assignment of Proceeding
President Michael R. Peevey is the assigned Commissioner and Dorothy Duda is the assigned Administrative Law Judge (ALJ) in this portion of the proceeding.26
1. The Commission has an avoided cost methodology, the E3 Calculator, adopted in D.05-04-024 and modified by D.06-06-063, that it can apply to DG cost-benefit models.
2. The RIM test measures the relative costs and benefits of DG projects or programs on utility rates.
3. The RIM Test is not required for evaluation of the cost-effectiveness of energy efficiency programs.
4. The TRC and Societal Tests each provide a unique perspective to measure the impacts of DG facilities on the state's economy generally and compare DG facilities to other energy resource options.
5. The TRC Test is used by the Commission to evaluate the cost-effectiveness of energy efficiency programs.
6. The Participant Test measures the economic viability of a DG facility to the developer or customer installing the facility and can assist the Commission in determining the level of incentive needed to promote the investment.
7. The PA Cost Test measures the net costs incurred by the PA for DG programs and may be used to evaluate program budgets and expenditures.
8. The Standard Practice Manual methodology was developed to measure resource costs and benefits for many types of resources, including energy efficiency, demand response, and distributed generation.
9. The SPM has been used in the past primarily to evaluate energy efficiency programs.
10. The cost-benefit specifications presented in the Itron Framework were developed specifically to analyze DG facilities.
11. Utility and program administrator costs are reported by SGIP and CSI program administrators in their quarterly reports to Energy Division.
12. In D.01-01-007, the Commission adopted a method to estimate line losses, and affirmed that method in D.07-09-040, but the data needed to support that methodology is no longer available.
13. In D.03-02-068, the Commission adopted "physical assurance" criteria relating to payments to a DG facility might receive if it contracts with a utility for T&D investment deferrals.
14. The E3 reliability adder assumes reductions in demand caused by DG have roughly the same reliability impacts as changes in demand caused by energy efficiency.
15. DG facilities may improve reliability of power supplies to DG customers.
16. The record of this proceeding provides no evidence whether DG facilities increase or decrease the level of employment relative to employment at utility central station generation facilities, but the Commission can conduct further inquiry on these effects and add a variable to the methodology at a later date.
17. The Commission's policy to promote DG as a vital energy resource in the state is consistent with the idea of "market transformation," which assumes the assimilation of DG technologies as an integral part of the state's energy resources. In this proceeding, the Commission has no estimates of the market transformation effects of DG programs, but there are reasonable methods available to perform qualitative assessment of these effects.
18. Including reduced transmission, distribution and non-fuel generation revenues in the RIM Test would estimate the losses to ratepayers when DG customers reduce or eliminate these charges.
19. SGIP and CSI databases provide actual program data to reflect the costs of installing, maintaining and operating DG projects.
20. The E3 environmental adder and avoided costs from D.06-06-063 are used when evaluating energy efficiency programs.
21. Cogeneration plants use a single fuel to produce electricity and production heat, which may be more efficient from an engineering standpoint than electricity production at a central station plant.
22. Exemptions to DG facilities for standby charges are a revenue loss to utility ratepayers, and a benefit to DG program participants.
23. The Commission adopted avoided costs estimated by E3 for electricity and natural gas in D.05-04-024, updated them in D.06-06-063, and specified further input adjustments to this methodology for use in evaluating energy efficiency programs.
24. Bill credits under net metering are an incentive designed to promote DG development.
25. Exemptions from CRS liabilities for DG facilities do not result in a loss of revenues because DWR did not purchase power for DG customers.
26. SGIP and CSI incentive payments represent a cost to utility ratepayers and a benefit to DG customers.
27. Tax incentives represent a benefit to DG customers.
28. The Participant, PA Cost, TRC, and Societal Tests can collectively provide a tool to assist the Commission in the ongoing evaluation of DG programs.
1. The Commission should immediately implement DG cost-benefit tests using the avoided cost methodology adopted in D.05-04-024, as modified by D.06-06-063, and with any input adjustments currently directed by the Commission to be used in evaluating energy efficiency programs.
2. The contractor performing the cost-benefit analysis should document and justify any modifications to the avoided costs to adapt them to DG facilities.
3. The Commission should not require the use of the RIM Test to evaluate DG programs because it is not relied on to evaluate energy efficiency programs.
4. The Commission should require the use of both the TRC Test and the Societal Test to measure the impacts of DG programs on the state's economy generally and to compare DG programs to other energy resource options.
5. The Commission should require the use of the Participant Test to help identify "free riders," that is, those DG projects that would be profitable for DG customers absent all or some portion of existing incentives.
6. The Commission should require the use of the PA Cost test to evaluate the net costs of DG program budgets and expenditures.
7. The SPM cost-benefit tests described in this order should be adopted with the specifications, data and variables set forth herein and as summarized in Attachment A.
8. Current program administrative and interconnection costs as reported by the SGIP and CSI program administrators in their quarterly reports to Energy Division should be used in the SPM Tests as set forth in Attachment A. If project-specific data on interconnection costs is not available, actual aggregate or progam-wide data can be used.
9. Values for line loss reductions should be included in the TRC, Societal and RIM Tests and should be estimated using the system-wide line loss assumptions in the E3 Calculator.
10. In estimating the collective impact of DG facilities on T&D avoided costs, the Commission should not change the requirement for "physical assurance" adopted in D.03-02-068 for a DG facility that receives payments from a utility for T&D investment deferrals.
11. It is reasonable to estimate the collective T&D deferral benefit of both grid-side and customer-side DG facilities based on DG penetration levels, without applying the restrictive physical assurance requirement, but using a methodology equivalent or analogous to the method employed by Itron in its SGIP Year 6 Impact Report.
12. The price elasticity adder presented in the Itron Framework should not be used in the RIM, TRC, or the Societal Tests because if DG resources are planned, we should not assume their addition will impact market prices.
13. The Commission should require the use of the E3 reliability adder in the avoided costs adopted in D.05-04-024, and updated in D.06-06-063 for system reliability impacts in the RIM, TRC, and Societal tests.
14. Energy Division should study whether the new methodology adopted in D.09-06-028 to assess peak load contributions of intermittent resources in the Resource Adequacy rulemaking affects the use of the E3 Reliability Adder in the DG cost-benefit tests.
15. If a DG customer or developer has an estimate of the reliability benefits of DG projects to DG customers, this information may be reported by program administrators, but should not be used in the cost-benefit tests.
16. Until further review by the Commission, cost-benefit models should not assume that DG projects improve employment or tax revenues in California.
17. Energy Division should ensure the entity performing the cost-benefit analyses performs a qualitative assessment of the market transformation effects of DG programs, based on the Itron or E3 method, or other reasonable substitute.
18. The consultant should first perform the SPM tests without any market transformation analysis, and then conduct a second set of the tests that incorporates a market transformation component, which includes an assessment of progress toward the goal of market transformation and how cost-benefit test results might change as DG technologies evolve.
19. Reduced transmission, distribution and non-fuel generation revenues should be included in RIM Tests based on estimates derived from utility rate tariffs and DG production data.
20. Current and most recent data from SGIP and CSI databases about the costs of installing, maintaining, and operating DG projects should be included in the TRC, Societal, and Participant Tests.
21. The Commission should apply the same method used for valuing environmental impacts of energy efficiency when valuing environmental impacts of DG in order to compare resource options with consistent avoided costs.
22. The Commission should use the method described in the Itron Framework, along with the most current avoided costs inputs used to evaluate energy efficiency, to value environmental impacts of DG.
23. The valuation of environmental impacts may require adjustments at a future date to account for the effects of a cap and trade regime to reduce GHG emissions.
24. The Participant, TRC and the Societal Tests for a DG cogeneration plant should estimate the plant's efficiency relative to central station facilities.
25. Exemptions from standby charges should be reflected as a cost in the RIM Test and a benefit in the Participant Test.
26. The costs and benefits of net metering should be included in the SPM cost-benefit tests.
27. Reduced CRS revenues should not be included as a cost in the RIM Test.
28. SGIP and CSI incentive payments should be included as a cost in the TRC, Societal, RIM, and PA Cost Tests, and as a benefit in the Participant, TRC, and Societal Tests.
29. Tax incentives should be included as a benefit in the Participant Test.
30. Federal tax incentives should be included as a benefit in the TRC and Societal Tests, and state tax incentives should be considered a transfer payment in both tests.
31. Attachment A, which summarizes costs and benefits and input variables for each of the adopted cost-benefit tests, should be adopted to guide cost-benefit calculations for DG facilities, subject to modification as the Commission determines.
32. The Energy Division should oversee the cost-benefit analysis work to ensure the consultant performing the cost-benefit analyses applies the cost-benefit models adopted in this decision and the most recent data available.
33. If data to perform the cost-benefit tests is not readily available or it is cost prohibitive to obtain it, Energy Division may direct the consultant performing the work to use alternative data sources, with accompanying justification.
34. The Commission should review the results of the cost-benefit tests adopted in this order as a tool to assist in DG program evaluation.
35. Once the cost-benefit analysis is completed, the ALJ shall allow parties to comment on the completed analysis and, in consultation with the Assigned Commissioner, consider hearings or workshops on further modifications and refinements to the analysis as deemed necessary.
IT IS ORDERED that:
1. The Commission's distributed generation programs, which are supported by incentives and rate exemptions funded by jurisdictional utility ratepayers, shall be analyzed using the three cost-benefit tests described in this decision, namely, the Participant Test, the Total Resource Cost Test (including its variant, the Societal Test), and the Program Administrator Cost Test, and the tests shall be run with the input variables and data sources set forth in Attachment A.
2. Beginning on the effective date of this order, the Commission's Energy Division shall ensure the cost-benefit models set forth in Ordering Paragraph 1 and Attachment A are applied to distributed generation programs. If data to perform the tests as set forth in Attachment A is not readily available, or if it is cost-prohibitive to obtain it, Energy Division may use its discretion to direct the entity performing the analysis work to use alternative data sources, as long as any deviations are communicated and justified in the resulting study.
3. Within 30 days of this order, Energy Division shall initiate cost-effectiveness studies as described in the California Solar Initiative Program Evaluation Plan using the cost-benefit methodology adopted in Ordering Paragraph 1.
4. Within six months of this order, Energy Division shall ensure the Self-Generation Incentive Program program administrators have begun efforts to hire independent contractors to perform a cost-benefit analysis of the Self-Generation Incentive Program for all prior program years using the methodology adopted in Ordering Paragraph 1.
5. Pacific Gas and Electric Company, San Diego Gas & Electric Company, Southern California Edison Company, Southern California Gas Company, and the California Center for Sustainable Energy shall develop data collection capabilities and work with the Commission's Energy Division to obtain, facilitate the obtainment of, or provide the program data, distributed generation participant data or any other relevant information specified in Attachment A in order to apply the cost-benefit models adopted in this order.
6. The Energy Division should report to the Administrative Law Judge and assigned Commissioner whether modifications are necessary to the reliability assumptions for intermittent distributed generation resources used in the adopted cost-benefit tests.
7. Following completion of the cost-effectiveness analysis, the assigned Commissioner or Administrative Law Judge shall allow comments on the completed analysis, and may hold workshops or hearings as deemed necessary to consider refinements and modifications to the variables or data sources used in this cost-benefit methodology.
8. Rulemaking 08-03-008 remains open.
This order is effective today.
Dated August 20, 2009, at San Francisco, California.
MICHAEL R. PEEVEY
President
DIAN M. GRUENEICH
JOHN A. BOHN
RACHELLE B. CHONG
TIMOTHY ALAN SIMON
Commissioners
ATTACHMENT B
STATUTORY DEFINITIONS OF DISTRIBUTED ENERGY RESOURCES
AND SOLAR ENERGY SYSTEM
Public Utilities Code Section 379.6
(a) (1) The commission, in consultation with the State Energy Resources Conservation and Development Commission, shall administer, until January 1, 2012, the self-generation incentive program for distributed generation resources originally established pursuant to Chapter 329 of the Statutes of 2000.
(2) Except as provided in paragraph (3), the extension of the program pursuant to Chapter 894 of the Statutes of 2003, as amended by Chapter 675 of the Statutes of 2004 and Chapter 22 of the Statutes of 2005, shall apply to all eligible technologies, as determined by the commission, until January 1, 2008.
(3) The commission shall administer solar technologies separately, after January 1, 2007, pursuant to the California Solar Initiative adopted by the commission in Decision 06-01-024.
(b) Commencing January 1, 2008, until January 1, 2012, eligibility for the program pursuant to paragraphs (1) and (2) of subdivision (a) shall be limited to fuel cells and wind distributed generation technologies that meet or exceed the emissions standards required under the distributed generation certification program requirements of Article 3 (commencing with Section 94200) of Subchapter 8 of Chapter 1 of Division 3 of Title 17 of the California Code of Regulations.
(c) Eligibility for the self-generation incentive program's level 3 incentive category shall be subject to the following conditions: (1) Commencing January 1, 2007, all combustion-operated distributed generation projects using fossil fuel shall meet an oxides of nitrogen (NO x) emissions rate standard of 0.07 pounds per megawatthour and a minimum efficiency of 60 percent. A minimum efficiency of 60 percent shall be measured as useful energy output divided by fuel input. The efficiency determination shall be based on
100 percent load.
(2) Combined heat and power units that meet the 60-percent efficiency standard may take a credit to meet the applicable NOx emissions standard of 0.07 pounds per megawatthour. Credit shall be at the rate of one megawatthour for each 3.4 million British thermal units (Btus) of heat recovered.
(3) Notwithstanding paragraph (1), a project that does not meet the applicable NOx emissions standard is eligible if it meets both of the following requirements:
(A) The project operates solely on waste gas. The commission shall require a customer that applies for an incentive pursuant to this paragraph to provide an affidavit or other form of proof, that specifies that the project shall be operated solely on waste gas. Incentives awarded pursuant to this paragraph shall be subject to refund and shall be refunded by the recipient to the extent the project does not operate on waste gas. As used in this paragraph, "waste gas" means natural gas that is generated as a byproduct of petroleum production operations and is not eligible for delivery to the utility pipeline system.
(B) The air quality management district or air pollution control district, in issuing a permit to operate the project, determines that operation of the project will produce an onsite net air emissions benefit, compared to permitted onsite emissions if the project does not operate. The commission shall require the customer to secure the permit prior to receiving incentives.
(d) In determining the eligibility for the self-generation incentive program, minimum system efficiency shall be determined either by calculating electrical and process heat efficiency as set forth in Section 218.5, or by calculating overall electrical efficiency.
(e) In administering the self-generation incentive program, the commission may adjust the amount of rebates, include other ultraclean and low-emission distributed generation technologies, as defined in Section 353.2, and evaluate other public policy interests, including, but not limited to, ratepayers, and energy efficiency and environmental interests.
(f) On or before November 1, 2008, the State Energy Resources Conservation and Development Commission, in consultation with the commission and the State Air Resources Board, shall evaluate the costs and benefits, including air pollution, efficiency, and transmission and distribution system improvements, of providing ratepayer subsidies for renewable and fossil fuel "ultraclean and low-emission distributed generation," as defined in Section 353.2, as part of the integrated energy policy report adopted pursuant to Chapter 4 (commencing with Section 25300) of Division 15 of the Public Resources Code. The State Energy Resources Conservation and Development Commission shall include recommendations for changes in the eligibility of technologies and fuels under the program, and whether the level of subsidy should be adjusted, after considering its conclusions on costs and benefits pursuant to this subdivision.
(g) (1) In administering the self-generation incentive program, the commission shall provide an additional incentive of 20 percent from existing program funds for the installation of eligible distributed generation resources from a California supplier.
(2) "California supplier" as used in this subdivision means any sole proprietorship, partnership, joint venture, corporation, or other business entity that manufactures eligible distributed generation resources in California and that meets either of the following criteria:
(A) The owners or policymaking officers are domiciled in California and the permanent principal office, or place of business from which the supplier's trade is directed or managed, is located in California.
(B) A business or corporation, including those owned by, or under common control of, a corporation, that meets all of the following criteria continuously during the five years prior to providing eligible distributed generation resources to a self-generation incentive program recipient:
(i) Owns and operates a manufacturing facility located in California that builds or manufactures eligible distributed generation resources.
(ii) Is licensed by the state to conduct business within the
state.
(iii) Employs California residents for work within the state.
(3) For purposes of qualifying as a California supplier, a distribution or sales management office or facility does not qualify as a manufacturing facility.
Public Utilities Code Section 2852 (a)(3)
"Solar energy system" means a solar energy device that has the primary purpose of providing for the collection and distribution of solar energy for the generation of electricity, that produces at least one kilowatt, and produces not more than five megawatts, alternating current rated peak electricity, and that meets or exceeds the eligibility criteria established by the commission or the State Energy Resources Conservation and Development Commission.
(END OF ATTACHMENT B)
26 The issues in this decision were initially heard by ALJ Kim Malcolm as part of R.04-03-017. That rulemaking was closed in March 2006, and the record supporting this order was transferred to R.06-03-004 and then to R.08-03-008 under ALJ Duda.
