VIII. Comments on Proposed Decision
The proposed decision was issued for comment on _____________, 2005, in accordance with Pub. Util. Code § 311(d) and Rule 77.1 of the Rules of Practice and Procedure. Comments were filed on ___________.
1. The State Legislature effectively directed the Commission to develop a cost-benefit methodology by enacting Section 353.9, effective May 2001, which requires the Commission to create a "firewall" that protects each group of customer classes from subsidies to DG projects in other customer classes.
2. The Commission has available data and avoided cost estimates to apply to cost-benefit models immediately and during the period before more refined avoided costs are adopted for DG facilities in R.04-04-025.
3. Using the non-participant test to measure the impacts of DG subsidies on utility rates will help the Commission in compliance with Section 353.9 and fulfill its more general obligation to protect ratepayers from unreasonable rates.
4. The societal test would measure the impacts of DG facilities on the state's economy generally and establish the extent to which DG facilities are worthwhile resource additions compared to other energy resource options.
5. The participant test would help identify "free riders," that is, those DG projects that would be profitable for DG customers absent all or some portion of existing subsidies or other incentives.
6. 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.
7. The SPM has been used in the past primarily to evaluate energy efficiency programs.
8. The cost-benefit specifications presented in the Itron report were developed specifically to analyze DG facilities.
9. DG facilities and energy efficiency programs and projects are dissimilar in some significant ways.
10. The utilities presented estimates of most administrative costs that reasonably reflect actual costs. The CEC is estimating utility interconnection costs using current and historical data.
11. D.05-04-024 adopted avoided costs for reductions in line losses that are readily applicable to small DG projects. Reductions in line losses attributable to projects greater than 100 kW may be estimated with engineering studies.
12. The requirement that a project demonstrate "physical assurance," a concept adopted in D.03-02-068, assures the DG project is a reliable resource for utility planning purposes by assessing the DG project's location, capacity, and operational characteristics.
13. DG projects may reduce market prices by reducing customer demand for resources in the state's energy markets. This reduction in demand is not offset by an additional supply because that supply is not offered in the relevant markets. If it were, the impact would be to put downward pressure on prices.
14. The E3 avoided costs for system reliability impacts of energy efficiency programs and projects is readily applicable to DG projects for use in the non-participant and societal tests until and unless the Commission adopts more specific avoided costs for DG facilities.
15. DG facilities may improve reliability of power supplies to DG customers.
16. DG facilities may increase or decrease the level of employment relative to employment at central station plants.
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. The Commission has no estimates of the value of market transformation in this proceeding.
18. Including reduced T&D revenues in the non-participant test would estimate the losses to ratepayers for financial support of the T&D system.
19. Current and most recent data about the costs of installing, maintaining and operating DG projects would promote a more realistic evaluation of a project's net value than estimates of future costs.
20. Including only those environmental benefits that are attributable to regulatory or other legal requirements would permit the exclusion of tangible and valuable environmental benefits of DG projects.
21. CCDC's proposal to modify the E3 avoided cost estimate for electricity and natural gas by reflecting the air pollutants from the actual mix of power plants, including those that are operated on the margin, would improve the accuracy of those avoided costs where air quality benefits are concerned.
22. 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.
23. Exemptions to DG facilities for standby charges represent a subsidy from ratepayers to DG customers.
24. The Commission adopted avoided costs estimated by E3 for electricity and natural gas in D.05-04-024 that may be applied to DG cost-benefit tests until and unless the Commission adopts specific values for DG facilities.
25. The cost of estimating the cost of net metering would itself not be cost-effective.
26. Exemptions for DGs from CRS liabilities do not result in a loss of revenues because DWR did not purchase power for DG customers.
27. SGIP subsidies represent a cost to utility ratepayers and a benefit to DG customers.
28. Tax incentives represent a benefit to DG customers.
29. SCE, SDG&E/SCG, and PG&E have stated in this proceeding that they normally have more requests for SGIP funding than their respective SGIP budgets could support. The cost-benefit models adopted today could help the utilities determine which projects on their waiting lists should receive priority for SGIP funds.
30. Proposed DG projects that would be cost-effective to the DG customer without ratepayer subsidies do not require ratepayer subsidies to motivate project construction and operation.
31. The Commission should immediately implement cost-benefit tests using available data and avoided costs estimates before more refined avoided costs are adopted for DG facilities in R.04-04-025.
32. The Commission should require the use of the non-participant test to measure the impacts of DG subsidies on utility rates to assure compliance with Section 353.9 and fulfill its more general obligation to protect ratepayers from unreasonable rates.
33. The Commission should require the use of the societal test to measure the impacts of DG facilities on the state's economy generally and establish the extent to which DG facilities are worthwhile resource additions compared to other energy resource options.
34. 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 subsidies or other incentives.
35. The cost-benefit models referred to as the participant test, the non-participant test and the societal test should be adopted with the specifications, data and variables set forth herein and as summarized in Attachment A.
36. The utilities' estimates of most administrative costs should be used in societal and non-participant cost-benefit models except that the CEC's estimates of utility interconnection costs should be used.
37. The avoided costs adopted in D.05-04-024 for reductions in line losses should be applied to small DG projects. Reductions in line losses attributable to projects greater than 100 kW should be estimated with engineering studies. Values for line loss reductions should be included in societal tests and non-participant tests.
38. In estimating the 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.
39. The impact of DG projects on market prices presented in the Itron report should be used in the non-participant test and the societal test.
40. The Commission should require the use of the E3 avoided costs for system reliability impacts in the non-participant and societal tests until and unless the Commission adopts more specific avoided costs for DG facilities.
41. The Commission should direct the parties to estimate the reliability benefits of DG projects to DG customers and to include those estimates in the participant test.
42. Cost-benefit models should not assume that DG projects improve employment in California.
43. The parties should estimate the value of market transformation effects in R.04-04-025 for inclusion of that variable in the societal test.
44. Reduced T&D revenues should be included in non-participant tests.
45. Current and most recent data about the costs of installing, maintaining, and operating DG projects should be included in the societal test and the participant test.
46. The Commission should require the inclusion in cost-benefit models of all known environmental benefits of DG projects, whether or not they are attributable to regulatory or other legal requirements.
47. The participant test and the societal test for a DG cogeneration plant should estimate the plant's efficiency relative to central station facilities.
48. Exemptions from standby charges should be reflected as a cost in the non-participant test.
49. The avoided costs estimated by E3 for electricity and natural gas and adopted in D.05-04-024 should be applied to DG cost-benefit tests until and unless the Commission adopts specific and more permanent values for DG facilities.
50. Non-participant tests should not include as a cost the reduced revenues attributable to net metering.
51. Reduced CRS revenues should not be included as a cost in the non-participant test.
52. SGIP subsidies should be included in the non-participant test.
53. Tax incentives should be included as a benefit in the participant test.
54. Attachment A, which summarizes costs and benefits for each of the three adopted cost-benefit models, should be adopted to guide cost-benefit calculations for DG facilities, subject to modification in R.04-04-025 and as the Commission determines.
55. The Commission should direct SDG&E/SCG, SCE, and PG&E to apply the cost-benefit models we adopt herein to establish which proposed DG facilities on their waiting lists should receive scarce SGIP funding.
56. Attachment A should be included as part of the program guidelines for SGIP and should be immediately implemented to guide the selection of DG facilities that qualify for SGIP funding.
57. The Commission should develop the record in this proceeding to determine exactly how to use the adopted cost-benefit models in DG programs.
58. The utilities should be ordered to withhold funding for proposed DG projects that are determined to be cost-effective for the DG customer using the participant test adopted herein.
59. SCE, PG&E, and SDG&E/SCG should be ordered to reassess the state's SGIP program using the models, specifications, variables and data adopted herein. The utilities should file the results of the analysis in this proceeding within 45 days.
IT IS ORDERED that:
60. The cost-benefit models and model specifications described in Attachment A and discussed herein are adopted for the purpose of assessing distributed generation (DG) facilities in California that qualify for subsidies, incentives, and rate exemptions supported by jurisdictional utility ratepayers.
61. Beginning on the effective date of this order, Pacific Gas and Electric Company (PG&E), Southern California Edison Company (SCE), San Diego Gas & Electric Company/Southern California Gas Company (SDG&E/SCG) shall use the models and specifications summarized in Attachment A to determine which projects qualify for Self-Generation Incentive Program (SGIP) funding. Those projects on the waiting lists that are the most cost-effective investments for ratepayers and society should receive first priority for SGIP funding. Projects that do not require funding in order to be cost-effective for DG customers whose projects are analyzed using the participant test adopted herein shall not receive SGIP funding.
62. PG&E, SCE, and SDG&E/SCG shall collaboratively reassess the state's SGIP program using the models, specifications, and data adopted herein and summarized in Attachment A. The utilities shall file the results of the analysis in this proceeding within 45 days of the effective date of this order.
63. In order to effectuate the Legislature's intent as set forth in Public Utilities Code Section 353.9, this order is effective today.
Dated , at San Francisco, California.
