15. Assignment of Proceeding

Michael R. Peevey is the assigned Commissioner, and Anne E. Simon and Burton W. Mattson are the assigned ALJs for this proceeding.

Findings of Fact

1. It is feasible and desirable to design a streamlined procurement process for smaller renewable energy projects.

2. Smaller renewable energy projects may be able to be developed more quickly and with greater certainty than larger scale renewable projects given their smaller geographic and environmental footprint, and the ability to interconnect without requiring additional transmission or distribution system upgrades.

3. RAM is a market-based pricing mechanism wherein the price is set by the seller participating in a competitive solicitation, not the Commission.

4. A fundamental assumption underlying the adopted RAM is that competition is, and will remain, vigorous in this market, resulting in just and reasonable rates and optimal resource outcomes.

5. The RPS statute and program is premised upon employing competition to reach optimal outcomes.

6. The time and cost of an administrative process to set a fixed rate for a FIT tariff is not zero, and could be the same as or more than the sum of all RAM bid preparation costs.

7. A RAM-determined contract price provides reasonable price certainty for the purposes of project economic evaluation and subsequent cash-flow for cost recovery.

8. A RAM balances the ability for a small project to secure financing and attain a reasonable price, with the assurance that the ratepayer is not overpaying.

9. The Existing FIT is a must-take obligation on a first-come first-served basis up to a program capacity limit.

10. Because IOUs are given discretion to reject bids that are uncompetitive, the issue of whether RAM is a must-take obligation is moot.

11. SCE has implemented its RSC program, has conducted one solicitation in 2010, and has already executed 21 contracts pursuant to this solicitation.

12. Establishing one primary procurement vehicle for the system-side DG market can enhance competition and put downward pressure on bid prices.

13. A proportional allocation of the 1,000 MW cap to the largest of the four SMJUs would be about 4 MW, and to all four of the SMJUs would be about 6 MW.

14. Relative to a 20 MW per project criterion, allocating 4 MW or less to each of the four SMJUs makes little practical sense while increasing administrative burden.

15. Calculating a revenue requirement cap will require coordination with the CPUC's procurement planning processes.

16. Before a revenue requirement cap is calculated, a total capacity cap of 1,000 MW is a relatively simple approach that is sufficiently large to test the adopted program but sufficiently small to provide protection against adverse outcomes.

17. If an IOU would like to procure beyond its initial allocation of the 1,000 MW cap, it is reasonable for an IOU to request an increase in its implementation advice letter.

18. It is reasonable to authorize the Director of Energy Division to explore methodologies for aligning RAM procurement authority with the Commission's procurement planning process to assess the need for RAM products going forward.

19. It is reasonable for the Director of Energy Division to have the authority to adjust the capacity cap on its own motion or in response to a utility advice letter filing requesting an update to the cap amount.

20. If IOUs hold two RAM auctions per year, it will provide market participants with regular opportunities to participate.

21. Multiple RAM auctions will not be unreasonably burdensome or costly if IOUs design a standard contract and bid protocol that meet the goals of being simple, easy to implement, and streamlined.

22. Project selection limited to the price variable is consistent with the RAM being relatively simple and transparent.

23. Ranking an auction result only by price is reasonable when the auction is targeting products with similar value.

24. Renewable products that are baseload, peaking as-available and non-peaking as-available provide different value to an IOU's electric portfolio.

25. It is reasonable for an IOU to have the discretion to reject bids if they are not cost competitive or if there is evidence of market manipulation.

26. A Tier 2 advice letter gives notice to the Commission and the public regarding a RAM contract without causing implementation delay.

27. Not requiring the seller to be a retail customer, and not requiring the project be located on property owned or under the control of the retail customer, provides a reasonable opportunity to increase the number of potential sellers, the amount of competition, and the amount of renewable generation.

28. Having both the full buy/sell and excess sales options available at the choice of the seller has been, and continues to be workable, with no evidence showing the contrary.

29. The CEC has repeatedly recommended that we study and implement an FIT for projects up to 20 MW, and a project size of 20 MW is used for many program and regulatory purposes.

30. Small RPS projects connecting to utility service territories incur none of the additional costs associated with some other forms of renewable generation.

31. Adopting standard non-negotiable RAM contracts is consistent with the goals of the RAM program, including simplicity and reduced transaction costs.

32. An 18-month limit for a project to begin commercial operation (with one potential six-month extension) reasonably streamlines RAM administration, while accommodating legitimate delays.

33. A development deposit is a form of collateral that helps compensate the IOU and ratepayers for damages from a project that fails to reach commercial operation.

34. A development deposit of $20/kW for projects 5 MW and smaller, and a $60/$90 per kW for intermittent and baseload resources, respectively, for projects greater than 5 MW and up to 20 MW in size is consistent with IOU requirements in other programs for similar resources.

35. A performance deposit is a form of collateral that helps compensate the IOU and ratepayers for damages from project performance failure.

36. A performance deposit is a cost of doing business, and a rational RAM bidder will include this cost with all other project costs in bid development.

37. It is appropriate to require performance consistent with good utility practices, and it is prudent to adopt a minimum performance requirement.

38. The risk and cost to ratepayers of capping damages at 5 cents/kWh compared to the benefit from an increased ability to finance contacts, if any, is unknown, while a minimum penalty of 2 cents/kWh penalizes projects if actual damages are less.

39. A requirement that the IOU be the project's scheduling coordinator (unless this service is specifically declined by the project, or the IOU is unable to perform this service) simplifies RAM administration.

40. A requirement that a project meet certain minimum project viability criteria to submit a bid provides an initial screen of more viable from less viable projects; simplifies bid review and selection; provides an incentive for bidders to submit realistic, competitive bids; complements the provision of limited time to commercial operation; assists with reasonable queue management; and should reduce the number of extension requests.

41. Issues regarding jurisdiction of distribution-level interconnections have been raised in FERC Docket No. ER11-1830-000.

42. Information is vital to an effectively functioning competitive market.

43. Data on the feasibility of interconnection must be sufficiently detailed and current to be useful to potential project developers.

44. Preferred areas are likely to be those near load where the IOU has a reasonable expectation of surplus transmission or distribution capacity.

45. As renewable DG penetrations continue to increase, IOUs should evaluate and benchmark new software tools and analytics to keep pace with the expected increase in interconnection requests for small DG.

46. The Critical Infrastructure Information Act of 2002 has no bearing on the Commission's decision about whether interconnection information should be provided to potential distributed generation developers.

47. It is reasonable to allow ED to revise any aspect of the RAM program through resolutions proposed for Commission approval.

48. IOU reporting on their experience with RAM will allow the Commission, IOUs, and market to evaluate the design of the program and track its progress.

49. IOUs recover RPS program costs from bundled customers, while certain non-bypassable costs are also recovered from customers that depart from the utility bundle after new resources are procured.

Conclusions of Law

1. A streamlined procurement process in the form of RAM should be implemented for smaller system-side renewable energy market.

2. A market-based pricing approach should be adopted for the RAM.

3. RAM avoids or eliminates a jurisdictional conflict with FERC's wholesale rate-setting authority.

4. The limitation imposed by Pub. Util. Code Section 399.15(d) on procurement of renewable energy at prices above the MPR does not apply to RAM.

5. The IOUs should be required to use RAM exclusively for the procurement of system-side renewable projects up to 20 MW in size with the exception of other Commission-approved programs such as the utility solar photovoltaic programs already authorized by the Commission and annual RPS solicitations; IOUs should not use voluntary programs that target the same market segment or bilateral negotiations.

6. IOUs should limit their procurement of system-side renewable DG to the RAM, to annual RPS solicitations, and to Commission-approved utility solar photovoltaic programs.

7. RAM should apply only to the three largest IOUs.

8. SCE should be given the discretion to apply the contract capacity of any of the 21 contracts already executed through its 2010 RSC program to its RAM capacity cap if the contract(s) is approved by the Commission.

9. SCE should be given the discretion to submit additional contracts to the Commission for approval resulting from its 2010 RSC solicitation via a Tier 3 advice letter; however, the capacity associated with these contracts should not reduce SCE's procurement obligations under RAM.

10. The following RAM auction design elements should be adopted: an interim procurement requirement of 1,000 MW, subject to increase in an IOU's implementation advice letter or adjustment in any appropriate proceeding; an initial capacity allocation to the three IOUs using the same proportions as in the Existing FIT program; 25% of the 1,000 MW total allocation offered in each RAM auction; each IOU should hold two RAM auctions per year; project bid selection based only on price with least-cost bids selected first; and IOUs can choose the types of products to solicit, subject to Commission approval; simplified contract approval through Tier 2 for RAM contracts executed up to the capacity cap authorized by the Commission for each IOU.

11. The Director of Energy Division should be authorized to explore methodologies for aligning RAM procurement authority with the Commission's procurement planning process to assess the need for RAM capacity and products in the future.

12. At any time, the Director of Energy Division may issue a resolution, either on its own motion or in response to a utility advice letter filing to update the capacity authorization.

13. An IOU should be authorized to request an increase to its capacity cap to be procured through the RAM if consistent with its portfolio need.

14. Respondents and parties may seek modification by request to the Executive Director pursuant to Rule 16.4 of the Commission's Rules of Practice and Procedure. Any modifications proposed should be based on evidence that the modification is necessary to improve the RAM program.

15. While the inputs and methodology are not in place to adopt a revenue requirement cap at this time, the Director of Energy Division may explore methodologies for aligning RAM procurement authority with the Commission's procurement planning process.

16. If an auction is less than fully subscribed, or if the subscribed capacity drops out of the program, the unsubscribed or dropped capacity should be added to the next available auction.

17. Each of the three largest IOUs should conduct two RAM auctions per year; the three IOUs should hold RAM auctions simultaneously.

18. RAM project selection should be by price with least expensive selected first.

19. Rates for RAM should be all-in energy rates adjusted by time of delivery (TOD) factors.

20. Eliminating negotiation over price, terms, and conditions as part of the RAM reasonably streamlines and simplifies this procurement option.

21. RAM products should be baseload, peaking as-available, and non-peak as-available electricity.

22. An IOU should define the products it would like to procure through RAM based on its portfolio need, and include this request in its implementation advice letter.

23. An IOU should be able to reject bids if it determines that one or more bids are not cost competitive or if there is evidence of market manipulation. If this occurs, the IOU should demonstrate in an advice letter filing to the Commission why bids were rejected before the capacity cap was exhausted.

24. An IOU should file all executed RAM contracts up to the capacity allocation approved by the Commission in response to its implementation advice letter through a Tier 2 advice letter filing.

25. A seller eligible for RAM should not be required to be a retail customer of the IOU, and an eligible project should not be required to be located on property owned or under the control of a retail customer.

26. Projects participating in RAM, either through a full buy/sell or excess sales transaction, should not exceed 20 MW.

27. Sellers selected via RAM should continue to have the choice of full buy/sell or excess sales.

28. Deliveries should be from projects located in one of the IOU's service territories.

29. Eliminating negotiation over price, terms, and conditions as part of the RAM reasonably streamlines and simplifies this procurement option.

30. Each IOU should develop its own standard RAM contract and file it as part of its implementation advice letter filing; to the greatest extent possible, IOUs should work from an existing, simple standard contract that has been vetted through a stakeholder process.

31. RAM projects should be given 18 months from contract execution to begin commercial operation or lose RAM eligibility, subject to one 6-month extension provided the seller can prove a regulatory delay.

32. A RAM development deposit of $20/kW for projects 5 MW and smaller, and a $60/$90 per kW for intermittent and baseload resources, respectively, for projects greater than 5 MW and up to 20 MW in size should be adopted, with this deposit either refundable upon achieving COD or applied to the subsequent performance deposit; it should be due on the date of contract execution in the form of cash or a letter of credit from a reputable U.S. bank; and it should be forfeited if the project fails to come on line within 18 months (or with one six-month extension if granted by the IOU).

33. For projects less than 5 MW, a RAM performance deposit should be adopted equal to the development deposit; for projects 5 MW and larger, a performance deposit should be adopted of 5% of expected total project revenues.

34. RAM product performance should be consistent with good utility (or prudent electrical) practices; damages should be limited to the actual, direct losses (without a maximum or minimum amount); and neither party should be liable for consequential, incidental, punitive, exemplary or indirect damages, lost profits or other business interruption damages regardless of cause.

35. RAM product performance should, in addition, require deliveries of 140% of expected annual net energy production based on two years of rolling production.

36. RAM standard contracts for the three IOUs should define and apply force majeure and events of default provisions.

37. The RAM should require that the IOU be the seller's scheduling coordinator (unless that service is affirmatively declined by the seller, or the IOU is unable to perform the service); and the IOU, as scheduling coordinator, should bear the risk of scheduling deviations if the generator provides the IOU with timely availability information.

38. A bidder should be required to show as part of its bid that the project meets minimum project viability criteria, with failure to meet these criteria justification for an IOU to reject the bid.

39. An IOU should use pre-determined project viability screens to determine which bids are eligible to participate in the auction. These screens include: demonstration of site control upon submitting bid; demonstration of developer experience; deployment of a commercialized technology; and filed interconnection application prior to bid submission.

40. The IOUs should track project milestones and provide this information publicly using a simple format developed in collaboration with Commission staff.

41. If an IOU would like to include other bid evaluation metrics, such as seller concentration, in a RAM auction, it should propose the criteria in its implementation advice letter for Commission review; an IOU's proposal should not conflict with a price-only bid selection methodology.

42. Commission staff will consider and address interconnection issues in the future as appropriate and necessary, including, without limitation, ensuring non-discriminatory interconnection procedures based on developments in or resolution of the relevant FERC proceeding.

43. The IOUs should proactively modify their interconnection protocols for use in RAM where such modifications are reasonable and would enhance the implementation timelines and probability of success of RAM projects. The IOUs should consider adopting or modifying criteria for expedited processing where possible, either at the FERC or at this Commission.

44. IOUs should provide the "available capacity" at the substation and circuit level, updated on a monthly basis, which is defined as the total capacity minus the allocated and queued capacity. The IOUs should provide this information in map format.

45. Each IOU should examine DG interconnection screening tools currently used to screen DG interconnection applications. The IOUs should evaluate how individual project studies could be automated to provide the requested data and a reasonable assessment of a DG project's impact on the distribution system.

46. The IOUs should work with parties and Commission staff through the Renewable Distributed Energy Collaborative (Re-DEC) or other forums in order to improve the data, usefulness of the maps, and to discuss other issues related to the interconnection of distributed resources.

47. RAM should not require an eligible project to be a QF.

48. RECs should be transferred to the IOU for the energy that is purchased by the IOU.

49. Regular reports on the RAM program are also necessary and each IOU should provide an annual report on RAM. The IOUs may combine RAM reports with other reports, such as the annual compliance filings required in the IOU Solar PV Programs.

50. IOUs should work with ED to determine the content of the RAM report before filing. Among other things, the RAM report should address the competitiveness of the auctions; auction timing and design issues; and project milestones and status, including the time and the cost necessary to interconnect and bring projects on-line and any other information reasonably necessary to present a complete report and allow monitoring of important program elements.

51. The IOUs should hold annual program forums to solicit feedback from stakeholders regarding the RAM program design and implementation and potential modifications and refinements thereto.

52. IOUs and ED should make the maximum possible amount of RAM information public to, among other things, gain public acceptance of RAM.

53. RAM program costs should be charged to bundled customers and departing customers in the same manner as now charged.

54. Each IOU should, within 60 days of the date of this order, file a Tier 3 advice letter in compliance with the orders herein.

55. This order should be effective today to permit timely filing of the authorized RAM bid protocols and standard contracts, and timely conduct of the first RAM auction, thereby providing additional tools for IOUs to reach RPS targets and goals, and helping IOUs avoid the potential of penalties for failure to reach required RPS targets.

ORDER

IT IS ORDERED that:

1. Within 60 days of the date this order is mailed, each electrical corporation named herein shall file and serve a Tier 3 advice letter containing a standard contract, bid protocol and any other necessary documents to implement the renewable auction mechanism adopted in this order.

a. The electrical corporations are: Southern California Edison Company, Pacific Gas and Electric Company, and San Diego Gas & Electric Company.

b. The advice letter shall be in compliance with General Order 96-B.

c. The standard contract and bid protocol shall be consistent with the directions stated in this decision, and summarized in Appendix A. These directions include, but are not limited to:

· rate determination is by use of the renewable auction mechanism;

· capacity limit and procurement requirement of at least 1,000 megawatts, allocated to the three electrical corporations;

· no more, and no less, than 25% of the allocation offered in each auction;

· unsubscribed capacity (or subscribed capacity that drops out) is added to the next available auction;

· two auctions per year;

· electricity products eligible for purchase via this procurement protocol are baseload, peaking as-available, and non-peaking as-available;

· selection of winning bids is by price (least expensive selected first);

· bids are not negotiable with respect to bid price, terms or conditions;

· rates are paid on the basis of all-in energy rates by time of delivery;

· contracts executed pursuant to this program to be submitted via Tier 2 advice letter;

· projects 20 megawatts and less may participate;

· standard non-negotiable contract;

· bidders must show in the bid that the project complies with adopted project viability criteria;

· a project must be located in one of the investor-owned utility service territories;

· a seller eligible to subscribe under this procurement program need not be a retail customer of the electrical corporation, and the project need not be located on property owned or under the control of the retail customer;

· and a seller eligible to subscribe under this procurement program need not be a qualifying facility under federal law.

2. The IOUs shall use an Independent Evaluator (IE) consistent with and pursuant to the requirements established in Decision (D.) 07-12-052, as modified by D.08-11-008 to assess the integrity and competitiveness of each RAM auction as well as to assess the appropriateness/reasonableness of the bids selected from those auctions. The IE's report shall be submitted by the respective utility to the Commission along with the Tier 2 advice letter seeking approval of contracts resulting from each RAM auction.

3. Each electrical corporation named herein shall file and serve one Tier 2 advice letter with the Commission including all executed contracts resulting from each auction up to the approved capacity limits. After the effective date of this decision, the electrical corporations may not submit contracts with facilities up to 20 MW in size that are negotiated and executed outside of the Renewable Auction Mechanism program with the exception of contracts executed pursuant to the annual Renewables Portfolio Standard Program, the Commission-approved utility solar photovoltaic programs, and the contracts that Southern California Edison has or will execute pursuant to its 2010 Renewables Standard Contract program, or other Commission-approved programs. The electrical corporations are: Southern California Edison Company, Pacific Gas and Electric Company, and San Diego Gas & Electric Company.

4. Each year, each electrical corporation named herein shall file data, information, and evaluation in a report on relevant aspects of the renewable auction mechanism adopted in this order, and summarized in Appendix A.

a. The electrical corporations are: Southern California Edison Company, Pacific Gas and Electric Company, and San Diego Gas & Electric Company.

b. The reports shall be published on the electrical corporation's website.

c. The electrical corporations shall adopt a uniform form and format in consultation with Energy Division.

d. Each report shall include information to monitor program design and elements. It shall include information, data, and evaluation with respect to: competition, competitiveness, and auction design. The first report shall include information and recommendations on a definition of competition generally, a definition of competition in this market specifically, and measures of competition.

e. As data becomes available, reports shall contain information described in this order including but not limited to: measures of market competition, measures of market power, seller concentration, data on each auction (based on all bidders), data on each auction (based on projects selected), and any other data necessary to present a complete report. At a minimum, we require specific information to be revealed publicly. For all bids received and shortlisted, we require the IOUs to provide the following information: names of participating companies and the number of bids per company; number of bids received and shortlisted; project size, participating technologies, quantitative summary of how many projects passed each project viability screen, and location of bids by county provided in a map format. Finally, the IOUs must release information on the achievement of project development milestones for all executed RAM contracts.

5. The IOUs shall hold a program forum once per year, beginning after the initial RAM auctions are conducted to discuss program design and implementation, and provide opportunities for stakeholder comments. In organizing these forums, the utilities should consult with Energy Division staff and at a minimum notify the service list to this proceeding or subsequent proceedings. The IOUs may use the stakeholder feedback from each forum to develop and submit an advice letter seeking modifications to the RAM program. Similarly, Energy Division may issue a resolution on its own motion to propose program modifications based on information from these program forums or the annual reports developed pursuant to Ordering Paragraph 3 above. The IOUs may combine the RAM program forums with other program forums, such as those required for the IOU Solar PV programs.

This order is effective today.

Dated December 16, 2010, at San Francisco, California.

MICHAEL R. PEEVEY

President

DIAN M. GRUENEICH

JOHN A. BOHN

TIMOTHY ALAN SIMON

NANCY E. RYAN

Commissioners

APPENDIX A

SUMMARY OF ADOPTED PROGRAM

The attached decision establishes a new procurement protocol called the Renewable Auction Mechanism, or RAM. The orders, while not limited to those stated in this abstract, are summarized below. The items are generally summarized in the same sequence discussed in the attached decision.

RENEWABLE AUCTION MECHANISM

1. Price Determination: Renewable Auction Mechanism (RAM)

· Projects submit price bids

· IOUs select projects in order of least-costly first, up to program capacity limit

2. Auction Design:

a. Program Procurement Requirement:

i. 1,000 MW Capacity Limit

ii. Adjustment to the Program Capacity Limit: May occur in any appropriate proceeding or through a Tier 3 advice letter/Resolution, or a Resolution on the Commission's own motion

iii. Capacity Allocation for total RAM program and per auction

iv. Number of Auctions per Year: Two per year, held concurrently by all three IOUs; a project may bid into all three auctions.

v. Amount per auction: 25% of the total program allocation will be offered in the initial auction; unsubscribed capacity, or drop out capacity, is added to the next auction

vi. Procurement Requirement: Each IOU must enter into a standard contract with each winning bidder up to the capacity limits in each solicitation and total program capacity limits. IOUs select on the basis of least costly projects first until the IOU fully subscribes its allocated capacity for that auction. IOUs have the discretion to not enter into contracts if there is evidence of market manipulation or if the bids are not competitive compared to other renewable procurement opportunities. The IOU must submit an advice letter explaining its decision not to enter into contracts.

b. Products and Selection

· Products: Firm, non-firm peaking, and non-firm non-peaking electricity

o IOU shall specify the amount of each product for the initial four auctions in the first advice letter filed pursuant to this order. Utilities are required to solicit and procure capacity up to the capacity limit for each solicitation.

o Project must submit eligibility information (e.g., generation profile, project characteristic information) corresponding to the product bid, as established by the IOU

· Selection: Each product is selected on the basis of price, least expensive first until the capacity limit in each solicitation is reached; IOU may normalize (adjust) bids to place bids on an equivalent basis before making least cost selection using method approved, if any, in the advice letter implementing RAM

· Independent Evaluator: Utilities will employ an Independent Evaluator to assess the competitiveness and integrity of each RAM auction and submit the IE's report with it Tier 2 advice letter requesting approval of contracts resulting from those auctions.

3. Eligibility:

· Location: Combined IOU service territories (e.g. a project bidding into SCE's auction can be located in either PG&E or SDG&E's service territory).

· Retail Customer/Third Party Ownership: Seller need not be a retail customer and the facility need not be located on property owned or under the control of a retail customer

· Utility Applicability: Southern California Edison Company (SCE), Pacific Gas and Electric Company (PG&E), and San Diego Gas & Electric Company (SDG&E)

· Project and Transaction Limit: 20 megawatts (MW)

This is the maximum size for any project signing a full buy/sell or excess sales transaction through the RAM^.140

· Full Buy/Sell or Excess Sales: Seller may elect either full buy/sell or excess sales

· Counting Excess Sales: Capacity associated with the transaction size is applied to the program cap.

4. RAM Standard Contract:

· Contract Language: IOUs can use their individual contracts, but should start with a contract that is simple, streamlined, and has already been vetted by stakeholders through another CPUC program.

· Negotiations: Price, terms, and conditions are not negotiable.

· Contract Terms and Conditions

o Length of Time to COD: Within 18 months of contract execution, with one 6-month extension for regulatory delays.

o Development Deposit: $20/kW for projects 5 MW and smaller, and a $60/$90 per kW for intermittent and baseload resources, respectively, for projects greater than 5 MW and up to 20 MW in size, refundable upon achieving commercial operation or applied to the performance deposit; development deposit is due on the date of contract execution in the form of cash or letter of credit from a reputable U.S. bank; development deposit forfeited if project fails to come on line within 18 months or other 6-month extension granted by IOU.

o Performance Deposit:

_ For projects less than five MW: conversion of development deposit to performance deposit

_ For projects five MW and larger: 5% of expected total project revenues

o Performance Obligation:

_ Performance is required to be consistent with good utility (or prudent electrical) practices; project is obligated to have liability insurance against utility losses; the project is liable for an IOU's direct, actual losses; and project must perform consistent with generation profile or other characteristics for the product, to the extent stated in the Commission-adopted contract

_ Minimum deliveries of 140% of expected annual net energy production based on two years of rolling production

o Damages for Failure to Perform: Damages are limited to actual, direct damages; neither party is liable for consequential, incidental, punitive, exemplary or indirect damages, lost profits or other business interruption damages regardless of cause

o Force Majeure and Events of Default: Each RAM contract shall include a force majeure definition and provision

o Insurance: IOU discretion, submitted in implementation advice letter

o Scheduling Coordinator: Where possible, the contracting IOU shall be the scheduling coordinator for each project using the RAM, and the IOU shall bear the risk of scheduling deviations if the generator provides the IOU with timely information on its availability; the IOU can decline scheduling coordinator responsibilities only upon a written, affirmative request from the seller that the IOU not be the scheduling coordinator, or if unable to perform these duties

5. Project Viability Requirements

Bidder must demonstrate the following items with its bid. An IOU shall reject a bid that fails to demonstrate the following items. Each IOU shall adopt reasonable definitions and lists, related to:

· Site Control: Bidder must show 100% site control through (a) direct ownership, (b) lease or (c) an option to lease or purchase that may be exercised upon award of the RAM contract

· Development Experience: Bidder must show that at least one member of the development team has (a) completed at least one project of similar technology and capacity or (b) begun construction of at least one other similar project

· Commercialized Technology: Bidder must show the project is based on commercialized technology (e.g., is neither experimental, research, demonstration, nor development)

· Interconnection Application: Bidder must show that it has filed its interconnection application

6. Market Elements

a. Preferred Locations: The IOUs must provide the "available capacity" at the substation and circuit level, defined as the total capacity minus the allocated and queued capacity. The IOUs should provide this information in map format. If unable to initially provide this level of detail, each IOU must provide the data at the most detailed level feasible, and work to increase the precision of the information over time. This information is to be available in the advice letter implementing RAM and updated on a monthly basis.

i. Each IOU should examine DG interconnection screening tools currently used to screen DG interconnection applications. The IOUs should evaluate how individual project studies could be automated to provide the requested data and a reasonable assessment of a DG project's impact on the distribution system.

ii. The IOUs should work with parties and Commission staff through the Renewable Distributed Energy Collaborative (Re-DEC) or other forums in order to improve the data, usefulness of the maps, and to discuss other issues related to the interconnection of distributed resources.

b. Project Milestones: Sellers shall submit a project development milestone timeline to the IOU upon RAM contract signing, and quarterly progress reports. The only enforceable milestone is the commercial operation data (COD) (subject to a one 6-month extension for regulatory delays).

c. Relationship to Voluntary and Other Programs: 1,000 MW capacity limit does not include capacity subscribed under the Existing FIT (up to 1.5 MW, subject to expansion to three MW under SB 32). SCE is permitted to draw down its capacity limit with the 21 contracts it selected in November 2010 from the RSC solicitation, if the CPUC approves these contracts

d. FERC Certification: No FERC certification as a QF is required for a project to be eligible for RAM

e. Conveyance of RECs: RECs transferred in relationship to the amount of the purchase (for full buy/sell, the IOU buys the RECs coincident with the entire output; for excess sales, the IOU buys the RECs coincident with the purchased excess energy)

7. Regulation and Commission Oversight

a. Program modifications: The Commission can modify any element of the program at any time through a Commission resolution.

b. Advice Letter Review: All executed RAM contracts from each auction are filed with the Commission in one Tier 2 advice letter.

c. Program Evaluation: RAM to be monitored and evaluated annually, with each IOU filing a report each year. The report shall be filed with ED and posted on the IOU's website. ED shall include RAM program information in the Commission's reports to the legislature on the RPS program.

d. Data:

Each annual report shall include information and evaluation on all relevant items and characteristics including but not limited to:

· Competition and competitiveness

· Auction design

· Time necessary to complete projects

· Auction timing

· Project status

· Anything else determined by ED to be necessary for a complete report

IOUs shall adopt a uniform report template with guidance from Energy Division

The first report shall include each IOU's proposal for a definition of a competitive market, proposed measurements of RPS markets generally, and proposed measurements of this RAM market specifically

As available over time, each report shall include data on:

· Measures of the requirements for a perfectly competitive market

· Measures of market power

· Seller concentration

· Data on each RAM results

· Information on the achievement of project development milestones for all executed RAM contracts

· Any other information necessary to present a complete report

e. Public release of aggregated Data:

i. IOUs and ED shall make the maximum amount of RAM data public, including the following:

· Names of participating companies and number of bids per company

· Number of bids received and shortlisted

· Project size

· Participating technologies

· Quantitative summary of how many projects passed each project viability screen

· Location of bids by county provided in a map format

· Information on the achievement of project development milestones for all executed RAM contracts

f. Cost Recovery: RAM costs may be charged to bundled and departing customers consistent with current practice

8. Implementation Advice Letter: PG&E, SCE, and SDG&E shall file Tier 3 advice letters within 60 days of the date this order. The implementation advice letters shall include:

· Procurement protocols

· RAM standard contract

· Program implementation details

· Timing of RAM auctions

· Specific amounts of capacity and type of resources in each auction over the next two years

· Explanation of any normalization procedures used for bid selection process

· Detailed description of the generation profiles and characteristics that correspond with each product bucket

· Description of how IOU-proposed product eligibility requirements will provide reasonable assurance that a bid for one product will, if selected, deliver energy in a manner that corresponds to the generation profile associated with that

· Identify seller concentration limit, if any

· Provide the preferred locations map and a description of how the maps were computed

· Provide a simple methodology to measure the status of project development milestones

(END OF APPENDIX A)

APPENDIX B

ACRONYMS

ACRONYMS FOR PARTY NAMES

ACRONYM	PARTY NAME
AG	California Attorney General
AreM	Alliance for Retail Energy Markets
Axio	Axio Power, Inc.
CAC	Cogeneration Association of California
CAISO	California Independent System Operator
CALSEIA	California Solar Energy Industries Association
CARE	Californians for Renewable Energy, Inc.
CEERT	Center for Energy Efficiency and Renewable Technologies
CESA	California Energy Storage Alliance
DRA	Division of Ratepayer Advocates
Environmental Council	Community Environmental Council
enXco	enXco, Inc.
EPUC	Energy Producers and Users Coalition
Farm Bureau	California Farm Bureau Federation
FuelCell Energy	FuelCell Energy, Inc.
Fortistar Methane	Fortistar Methane Group
First Solar	First Solar, Inc.
GPI	Green Power Institute
GreenVolts	GreenVolts, Inc.
IEP	Independent Energy Producers Association
LA Community College District	Los Angeles Community College District
PG&E	Pacific Gas and Electric Company
Recurrent	Recurrent Energy, Inc.
Reid	L. Jan Reid
SCE	Southern California Edison Company
SDG&E	San Diego Gas & Electric Company
Sempra Generation	Sempra Generation
Sempra Energy	Sempra Energy Solutions LLC
SFUI	Solutions for Utilities, Inc.
Sierra Pacific	Sierra Pacific Power Company
Sierra Club	Sierra Club
TURN	The Utility Reform Network

OTHER ACRONYMS

ACRONYM	ITEM OR NAME
AB	Assembly Bill
ALJ	Administrative Law Judge
AMF	Above market funds
CAISO	California Independent System Operator
CCA	Community choice aggregator
CEC	California Energy Commission
CHP	Combined Heat and Power
COD	Commercial Operation Date
Commission	California Public Utilities Commission
CSI	California Solar Initiative
D.	Decision
ED	Energy Division
ERAM	Electric Revenue Adjustment Mechanism
ESP	Energy service provider
FERC	Federal Energy Regulatory Commission
FIT	Feed-in Tariff
FPA	Federal Power Act
GHG	Greenhouse gas
GW	Gigawatt
IOU	Investor-owned utility
IPP	Independent power producer
ISO 4	Interim Standard Offer No. 4
kV	Kilovolt
LCBF	Least Cost-Best Fit
LCOE	Levelized cost of electricity
LSE	Load Serving Entity
LTTP	Long term procurement plan
MPR	Market price referent
MW	Megawatt
MWh	Megawatt-hour
PIER	Public Interest Energy Research
PIRP	Participating Intermittent Resource Program
PRG	Procurement Review Group
PURPA	Public Utilities Regulatory Policies Act
PV	Photovoltaic
QF	Qualifying Facility
RAM	Renewable Auction Mechanism
RD&D	Research, demonstration and development
REC	Renewable energy credit
RPS	Renewables Portfolio Standard
RSC	Renewables Standard Contract
SB	Senate Bill
SGIP	Self Generation Incentive Program
SMJU	Small and multi-jurisdictional utilities
SPP	Small power producer
TOU	Time of use
TOD	Time of delivery
UL	Underwriter's Laboratories

(END OF APPENDIX B)

APPENDIX C

DURATION OF PRICES AND TOD PERIODS

The Administrative Law Judge identified five rate design examples, and parties were asked to comment. (Ruling dated August 27, 2009, Appendix B.) We look at one example here. This example reveals tensions between short-term and long-term goals and responsibilities between various stakeholders. We encourage respondents and parties to continue to consider the problems identified by this example, and propose creative solutions.

In particular, respondents and parties were asked to comment on the following pricing example:¹

· A price structure exclusively using energy payments; an initial price of $0.25/kWh paid by TOD factors set in the standard contract; the $0.25/kWh is paid in two parts over the life of the contract;

· The first part is payment of $0.20/kWh over the contract term;

· The second part is payment of $0.05/kWh; the $0.05/kWh is subject to adjustment at years 5, 10 and 15 to reflect the current market (e.g., formula in the contract based on an index to model seller's variable costs); and

· The TOD factors are updated once at year 10 to align with the current TOD profile of the buyer.

SCE identifies a particular problem with this example:²

"This example provides a fixed energy price component similar to the forecast energy price option provided to renewable Qualifying Facilities ("QF") under the Interim Standard Offer No. 4 ("ISO 4") contracts approved by the Commission in the early 1980s. As such, it embodies significant risks of overpayment for ratepayers (and a windfall for project owners) similar to those experienced during the life of the ISO 4 contracts.

The forecast energy payments under the ISO 4 agreement (which could be paid on either a levelized cents/kWh price or an escalating series of prices at the producer's election) was based on a forecast of utility avoided cost of energy that turned out to be much higher than actual market energy prices for most of the term of these contracts (which extended up to 30 years). As a result, ratepayers were saddled with overpayments for energy from these projects for many years. In light of this experience, the Commission should approach fixed payment schemes as proposed in this example with extreme caution.

More specifically, the proposal here to offer a fixed component for 80% of the energy price (i.e., 20 cents/kWh) for the entire 20 year term of the contract imposes the same price risk on ratepayers for an even longer period than the ISO 4 contract did. [Footnote 20.] In addition to the extreme ratepayer risk associated with the fixed prices being above market, in the event that pricing under this example falls below market prices, project owners might be tempted to cease operating under the FIT and seek other opportunities to sell their power. Unless mitigated by appropriate security requirements or contract sanctions, this scenario would force SCE's customers to

bear the risk of having to pay for replacement power from other sources to make up the shortfall left by defaulting FIT producers. SCE strongly recommends against this scenario."

__________

Footnote 20: Under the ISO 4 contract, the project owner was paid for energy under the forecast for a "First Period" that was limited to 10 years for contracts with a term of 20, 25 or 30 years. For contracts with a 5-year term length, the forecast was only available for the first 5 years. After the First Period, energy payments were based on avoided cost.

The risk identified by SCE is present in the current RPS program. For example, prices in the current RPS program typically are fixed for the duration of the contract, which is often 20 years. A 20-year fixed price essentially doubles the 10-year risk exposure experienced for the majority of the price under ISO 4. Further, 100% of the RPS price is fixed for the contract duration, whereas only a portion (about 20%) of the ISO 4 price was fixed for the contract duration, with the remainder (about 80%) fixed for 10 years or less, then subject to "true-up" to the market.

The fixed price risk in either the ISO 4 price or RPS price can result in either a "good" or "bad" outcome. Ratepayers will be apparent "winners," for example, if the prices set by contract for 10 years (ISO 4) or 20 years (RPS Program) turn out to be less than the market prices over the 10 to 20-year duration of the contract.³ As SCE identifies, however, ratepayers will be apparent "losers" if the contract prices set for 10 to 20 years turn out to be more than the market prices over the same period.

In actuality, the comparison of contract price with market price is a comparison of dissimilar products.⁴ Nonetheless, it demonstrates the tension that can arise when a long-term price set by contract differs from the current market price.

A similar tension can arise relative to TOD periods. Current TOD factors place most costs in the summer on-peak period (e.g., SCE's summer on-peak factor is 3.13; PG&E's is 2.20). California has a target of reaching 20% renewables by 2010, and seeks 33% of its generation from RPS resources by 2020. If successful in reaching the 33% goal, but if done with fixed TOD periods in 20 to 25 year contracts, California will achieve 33% of California's resources delivering electricity during a fixed summer on-peak period based on TOD factors in the contract set when the contract was signed. Demand, and the demand profile by TOD, however, may change over 20 to 25 years due to many factors.⁵ While stability and predictability for both buyer and seller are advanced by fixed prices and TOD periods, they can also be undermined by pre-determined, inflexible prices and TOD periods that bear little relationship to changing market conditions.⁶ Changing prices and TOD periods (e.g., which results in RPS electricity being delivered in an on-peak period that is no longer on-peak) may require IOUs or developers to build additional resources to meet the changing economics and demand. Alternatively, IOUs might want or need to modify contracts with RPS resources to better match supply with demand. Contract modifications may be costly. Thus, inflexibility can lead to higher costs.⁷

Parties do not present a solution and we do not craft one here. Nonetheless, we must avoid creating an inflexible system where, if successful in reaching a 20% or 33% RPS resource base, we have fixed the economic prices and signals with contract requirements for RPS projects to sell electricity that is too expensive in the wrong TOD periods. We encourage IOUs and parties to continue to assess these concerns, and present reasonable solutions if and when appropriate, including the use of capacity rates parallel to those used in the annual RPS bid solicitation, or other devices or tools which will reasonably balance these tensions.

(END OF APPENDIX C)

¹³⁹ As described in the text of this decision, SCE's procurement obligation may be reduced by the capacity represented in the 21 contracts it has executed from its 2010 RSC solicitation. Furthermore, SCE may elect to submit additional contracts resulting from its 2010 RSC solicitation via a Tier 3 advice letter, however, these additional contracts and associated capacity will not reduce SCE's procurement obligations under RAM.

¹⁴⁰ If a project elects to pursue excess sales, the total project size, including the capacity associated with the wholesale transaction under RAM as well as the capacity associated with onsite load, is counted as part of the project's capacity for purposes of project eligibility. However, only the capacity associated with the wholesale transaction will count against the capacity limit under RAM.

¹ August 27, 2009 Ruling, Attachment B, Item 12 at page 4 (also identified as Example D).

² SCE Pricing Comments at 18-19.

³ This assumes, as noted by SCE, that security requirements and contract sanctions (e.g., deposits, damages) are sufficient to prevent an owner from ceasing operations and seeking other opportunities to sell its power.

⁴ The price comparison confuses long-run and short-run (e.g., the market-based price for a 20-year contract (long-run) compared to the market-based price for a transaction of less duration (short-run, such as one day, one week, or one month); the comparison generally shows that the market-based long-run contract price is "too high" or "too low" compared to the market-based short-run price). The price comparison also confuses one long-run price with a different long-run price (e.g., market-determined contract price based on supply and demand in year x for a contract of "y" years duration compared to the market-determined contract price based on supply and demand in year x+5 for a contract of "y" years duration).

⁵ If California's investment in the smart grid is successful, for example, California may be able to move the "peaking" part of the summer on-peak load to another period. If plug-in hybrid automobiles become a significant portion of California's vehicle fleet, demand in the off-peak period may grow substantially, perhaps changing the on-peak period, or at least altering TOD allocation factors. If storage technologies are successful, this may further alter demand and supply, thereby changing TOD periods or allocation factors (e.g., if plug-in hybrid automobiles are able to sell electricity back to the gird).

⁶ See, for example, Recurrent Pricing Comments at 15.

⁷ Some ratepayers would like the certainty of a rate fixed for the long term (e.g., 20 years). Similar tensions would occur, however, if the Commission set IOU ratepayer rates for the long-term. IOUs would face the risk of rates not recovering costs, recovering too much cost, or being out-of-alignment with TOD periods. We balance competing interests and adjust ratepayer rates periodically (e.g., via general rate cases every three years, or balancing accounts every year). We do not set ratepayer rates for 20 years, however (even though ratepayers make capital investment decisions for electricity consuming products which have product lives of 20 or more years).