1. The June 27, 2011 ALJ Ruling, our RAM Program, and the October 13, 2011 Renewable FiT Staff Proposal contain the following five policy guidelines relevant to today's decision:
i. Establish a feed-in tariff price based on quantifiable ratepayer avoided costs that will stimulate market demand;
ii. Contain costs and ensure maximum value to the ratepayer and the utility;
iii. Ensure administrative ease and lower transaction costs for the buyer, seller, and regulator;
iv. Use existing transmission and distribution infrastructure efficiently; and
v. Establish project viability criteria to increase probability of successful projects within the program.
2. The MPR price may be too high or too low for different FiT product types, such as baseload, peaking as-available and non-peaking as-available.
3. The MPR is a price based on a natural gas-fired electric plant, and not a renewable generator. The MPR reflects the costs of a different energy market, fossil fuels.
4. The renewable market has evolved since the Commission first established the MPR in 2003 at the beginning of the RPS Program.
5. The renewable market is sufficiently robust to serve as the point of reference for establishing the market price for small renewable projects rather than the very different market represented by the MPR, which reflects the costs of a combined-cycle natural-gas power plant.
6. The methodologies presented to determine certain adders, such as those based on technology specific generation, are largely based on general avoided societal costs, and not ratepayer costs.
7. It is not easy to quantify the general societal benefits that support specific types of renewable technologies consistent with the provisions of state law and federal law.
8. Net surplus generation is provided without a power purchase agreement on an intermittent, unpredictable, and as-available basis over a 12-month period. In addition, the Commission found that the only generation the utility avoids when a net-energy metered customer provides surplus generation is reduced electricity procurement from the short-term wholesale market.
9. This decision adopts a pricing methodology that relies upon the November 2011 renewable market power pricing information from the RAM adopted in D.10-12-048 and takes components from a number of different pricing proposals presented by parties, including IREC, SunEdison, Silverado Power, Vote Solar Initiative, and SCE and by Staff. The pricing methodology also relies upon a two-month price adjustment mechanism to increase or decrease the FiT price for a particular product type based on market conditions.
10. A separate price for each of the three product types (baseload, peaking as-available, and non-peaking as-available) better captures the value provided by the different technology types.
11. Baseload projects provide firm energy deliveries (e.g., bioenergy and geothermal); peaking projects provide non-firm energy deliveries during peak hours (e.g., solar); and non-peaking as-available projects provide non-firm energy deliveries during non-peak hours (e.g., wind and hydro).
12. There is not enough market information for the three product types to enable us to adopt a unique starting price for each product type.
13. Adjusting the starting price by time-of-delivery factors based on the generator's actual energy delivery profile captures the value of each generator to the utility.
14. Based on the results from the November 2011 RAM auction, we anticipate that the starting price for each separate product type will be $89.23/MWh (pre-time-of-delivery adjustment).
15. The Re-MAT price should only increase or decrease if there is sufficient market interest in a product type, which may be determined by how many projects execute contracts at a particular Re-MAT price.
16. Ratepayer exposure to excessive cost due to market manipulation or malfunction is possible.
17. Temporarily suspending the program based on evidence of market manipulation or malfunction will guard against ratepayer exposure to excessive costs.
18. Allocating a utility's total capacity share to the three product types over a limited time period will serve to stimulate the market for small renewable distributed generation by providing an adequate supply of available capacity to each product type.
19. The total process for a deliverability study, which can take two years, may require costly upgrades to the transmission system in order to make the generator fully deliverable. The CAISO is currently conducting a stakeholder process to evaluate alternative paths to deliverability for distributed generation.
20. To ensure ratepayer indifference under § 399.20(d)(3), a market-based approach to pricing is in the best interest of California electricity customers.
21. Section 399.20(f) restricts the Commission from creating program requirements that interfere with the first-come-first-served requirement as it applies to the program as a whole but also permits consideration of a limited type of pricing elements.
22. In the absence of any specific legislative directive, a Commission requirement that pricing be distinguished based on a technology-specific basis would interfere with the application of the statutory provisions requiring first-come-first-served, ratepayer indifference, and cost containment.
23. The statute allows for first-come-first-served on a product specific basis as it specifically directs the Commission to consider the value of different electricity products including baseload, peaking, and as-available electricity in § 399.20(d).
24. This decision implements the statutory amendments by increasing the maximum size of the eligible facility to 3 MW.
25. Additional measures must be implemented to prevent daisy-chaining, i.e., when a project appears to be part of a larger overall installation by the same company or consortium in the same general location, as daisy-chaining is a means to evade the size restrictions.
26. Unless today's decision modifies the RAM Program, the RAM Program and the FiT Program will overlap for projects 3 MW and under and the potential for gaming of the price of the two programs for projects of 3 MW and under will exist.
27. A means to ensure that only viable projects participate in the FiT Program is required.
28. Increasing the viability of contracts executed pursuant to the FiT Program will allow for more efficient management of the limited program capacity and benefit the market by reducing speculative contracts.
29. Supporting viable projects supports the fifth policy guideline adopted by this decision to increase the probability of successful projects by establishing project viability criteria.
30. The plain language of the statute provides the Commission with authority to modify the program as applied to small electrical corporations in a manner that includes fully removing these utilities from the program. The costs of administering this program for the smaller utilities outweighs any potential benefit from their contribution of approximately 3 MW to the overall program.
31. The plain language of the statute establishes a total cap of 750 MW for the entire § 399.20 Program.
32. Consistency and administrative simplicity will be furthered by retaining the existing allocation methodology for 750 MW, updated in certain respects, adopted by the Commission in D.07-07-027.
33. No statutory provision requires us to consider a set aside, and a set aside program for a particular technology is inconsistent with the requirement that the program be made available on a first-come-first-served basis.
34. PG&E, SCE, and SDG&E maintain two tariff schedules under § 399.20 which are similar in many respects. In the interest of administrative efficiency, no justification exits to retain two separate schedules should no longer be retained.
35. The plain language of § 399.20 establishes that the FiT Program is not limited to retail customers of the electrical corporation but, instead, available to those that are owners or operators of the electric generation facility.
36. The plain language of the statute does not prohibit the sale of excess generation.
37. While the plain language of the statute does not provide definitive direction on the question of reporting frequency, annual reporting, rather than a longer time interval is appropriate because of the importance of proper maintenance of the electric system.
38. Adopting reporting requirements similar to those already included in existing programs, such as the RAM Program implemented by D.10-12-048 and various advice letters, including PG&E's Advice Letter 3809-E, provides efficiencies and transparency. While the statutory language does not require this level of information, it does not prohibit the Commission from requiring such disclosure and is justified by our goal of increased transparency.
39. Administrative ease and reducing transaction costs are achieved by adopting clear policies around when an electric corporation may deny a tariff request; it is also reasonable to place a certain amount of discretion in the utility to carrying out subsection (n), especially since the denials are subject to a statutorily required appeal process before the Commission.
40. Neither the statutory language itself nor secondary sources further clarify denial of requests under § 399.20(n).
41. The statutory language set forth in § 399.20(l) and the interest of promoting stability of this program suggest that the termination provisions be interpreted narrowly.
42. Expedited interconnection is critical to the success of the § 399.20 FiT Program and is required by statute.
43. SB 32 added subsection (k) to § 399.20 to require owners of eligible generation facilities to refund any incentives received from the CSI or the SGIP before participating in the FiT Program.
44. The Joint Parties filed a motion on December 19, 2011 requesting further consideration of an administratively determined, avoided cost based pricing mechanism and noted their concern that this proceeding had given the Renewable FiT Staff Proposal greater consideration or more evidentiary weight than other pricing proposals because the Staff's Proposal was presented in an ALJ's ruling dated October 13, 2011 and, in addition, discussed at a Staff Workshop on September 26, 2011.
45. The issues framed by Solutions for Utilities' petition for modification have been addressed in different aspects of this proceeding or will be addressed either in this proceeding or in the separate, ongoing Commission rulemaking on Rule 21 interconnection matters, R.11-09-011.
46. The issues framed by Sustainable Conservation's petition for modification are addressed in today's decision or will be addressed in the separate, ongoing rulemaking before the Commission, R.11-09-011.