9. 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.
1. No motion for evidentiary hearing was filed.
2. MRTU uses LMP price signals to reflect supply and demand in multiple locations.
3. MRTU significantly changes the way generation resources are scheduled, dispatched and potentially located, and it is reasonable for IOU contracts to reflect the MRTU's economic approach to resource allocation.
4. The economic curtailment proposal in the pro forma contracts of PG&E and SCE (as modified) are financeable, share congestion cost risk between stakeholders, provide economic information to parties, and are negotiable.
5. Making specific congestion cost information (to the extent used in LCBF evaluations) available to bidders promotes transparency in the LCBF methodology.
6. PG&E's economic curtailment proposal effectively results in the potential for economic curtailments in excess of five percent.
7. Energy-only interconnections may increase congestion cost risk.
8. Congestion cost concerns are addressed by economic curtailment contract terms and disclosure of LCBF treatment of congestion cost (including price data if specific data is used), and need not also be addressed by eliminating an interconnection option currently allowed by the CAISO.
9. We have previously rejected proposals for non-zero integration cost adders, and no new information or argument presented here justifies a change.
10. The stay of D.10-03-021 has been lifted, and the Commission now permits the use of TRECs for RPS compliance.
11. There was robust response from resources located in the Imperial Valley to the 2009 RPS solicitation.
12. IOU proposals regarding CAISO's SCP reasonably allocate not just benefits but also burdens; and reasonably allocate potential penalties to the seller, who is best positioned to mitigate those penalties.
13. Evidence presented here does not demonstrate that the Commission process for fast-track review of short term contracts does not work, cannot work, or cannot be reasonably modified, if necessary.
14. IOU-proposed pilot programs for short-term contract preapprovals lack reasonable limits and specificity on price and cost.
15. IOU Plans continue to be complex documents (including many attachments, different model contracts and multiple related forms), but the goals of increased simplicity, transparency, efficiency and competition can be advanced by the three IOUs continuing to make incremental improvements in standardization and uniformity of Plan form and format.
16. Several events have occurred that have not been adequately or fully reflected in draft Plans.
17. IOU Plans (including protocols, pro forma contracts and other attachments) are the vehicle for each IOU in one complete, comprehensive and up-to-date document to explain to all stakeholders how the IOU plans to achieve state-mandated RPS targets and goals, including but not limited to an assessment of supply and demand, use of flexible compliance, and a bid solicitation.
18. MJUs must now file, in years in which an IRP is not filed, a comprehensive IRP Supplement at the same time as IOUs file their Plans, but this creates a logistical challenge for MJUs and is less efficient than setting a fixed filing date.
19. SCE's proposal to amend its 2011 Plan to include a new shortlisting requirement is made late in this proceeding, and SCE fails to convincingly show that the PVC and LCBF tools result in shortlisting projects that would be rejected under its new requirement.
20. IOUs propose several changes in contract terms including, but not limited to, SCE's proposed changes to credit and collateral provisions, SCE's new shortlisting requirement, and SDG&E's proposed changes to TOD factors.
21. The PVC is a standardized comparison tool for project screening, and is one factor in the evaluation of projects, but is not determinative of the exact merit of a particular project or contract.
22. PacifiCorp's Supplement does not clearly show if prior RFPs have produced sufficient response for PacifiCorp to meet California RPS targets or if further action is needed and, if so, how much and when.
23. The RPS Program involves implementing statutes requiring that electrical corporations take reasonable actions to reach and maintain a very large quantity of renewable resources, with Commission implementation and administration often involving many complicated and significant technical details while balancing complimentary and competing interests of a wide range of stakeholders.
1. With some exceptions, electric utilities are required to prepare a renewable energy procurement plan, and the Commission is required to review and accept, modify, or reject each plan.
2. Electric utilities should continue to have reasonable flexibility in the way each satisfies RPS program requirements, subject to Commission guidance, limited specific requirements, and certain specific dates (where applicable) for the 2011 solicitation.
3. Conditional approval of each 2011 draft Plan (including Protocol, RFO, RFP, model contracts, other forms), and each Supplement to the IRP, does not constitute endorsement or adoption of each element of each Plan or Supplement; rather, each utility remains responsible for overall program success, subject to rules for flexible compliance and tests of reasonableness (e.g., how each entity administers the program, including the extent to which each entity takes Commission guidance; demonstrates creativity and vigor in program execution; and successfully reaches program targets, goals and requirements).
4. The proposed 2011 RPS Procurement Plans of PG&E, SCE, and SDG&E should each be conditionally accepted, subject to the guidance, necessary modifications, changes and clarifications stated in this order, including, but not necessarily limited to, each item summarized in Appendix A; and the Supplements to IRPs of PacifiCorp and Sierra (now CalPeco) should each be accepted subject to the guidance stated in this order including, but not limited to, the relevant items summarized in Appendix A.
5. PG&E, SCE, and SDG&E should each, within 14 days of the date this order is mailed, file a Final 2011 Plan with the Commission's Docket Office, serve it on the service list, and also file a copy with the Energy Division Director. Unless suspended by the Executive Director or Energy Division Director within 21 days of the date this order is mailed, each utility should use its Final 2011 Plan for its 2011 RPS solicitation.
6. Parties to executed contracts should use the dispute resolution provisions in existing contracts to address differences regarding economic curtailment, and the Commission should not disturb the negotiation process for contracts now being negotiated.
7. IOUs should be held accountable for contract failure due to unreasonable contract administration of economic curtailment terms.
8. Each IOU should include buyer-directed economic curtailment terms in its Final 2011 Plan.
9. SCE should incorporate assessment of congestion costs in its 2011 LCBF evaluations; both SDG&E and PG&E should continue to assess congestion costs in their 2011 LCBF evaluations (as they now do or commit to doing); all three IOUs should modify their LCBF descriptions to include economic curtailment and congestion cost information, as necessary; all three IOUs should release congestion cost information to bidders (to the extent specific data is used in LCBF evaluations) in order to promote transparency of the LCBF methodology; and all three IOUs should modify their LCBF descriptions, as necessary, to make treatment of RA, and use of RA adders, clear.
10. IOU Final 2011 Plans should not include non-zero integration cost adders, but IOUs should be allowed to file an advice letter to amend Final 2011 Plans if such adders are developed in R.10-05-006.
11. Final 2011 Plans filed pursuant to this order by an IOU (and Amended Supplements, if any, filed by an MJU) should include planned use of TRECs in a manner consistent with that authorized by the Commission.
12. No remedial measures should be adopted within RPS Plans regarding the Sunrise project and Imperial Valley resources but specific monitoring of Imperial Valley proposals and projects should continue; and IOUs should be encouraged to do outreach and take all reasonable action to secure optimal resource development, including possible special Imperial Valley bidder's conferences.
13. IOUs' proposals regarding treatment of benefits and burdens of CAISO's SCP should be accepted.
14. IOUs' proposals for pilot programs regarding preapproval of short-term contracts should be rejected.
15. IOUs should not wait until formal commencement of the development of the next Plan but should begin now to meet and coordinate to make incremental improvements toward adopting a common, uniform and streamlined form and format among the IOUs, including the overall summary document and multiple attachments (e.g., Protocol, RFP, RFO, model contracts, multiple related forms).
16. Final 2011 Plans filed pursuant to this order should amend draft Plans to include recent events not fully reflected in draft Plans to the extent they are intended to be used by IOUs to meet Program targets and goals (e.g., RAM, solar PV programs, small power production reflected in the adopted QF Settlement Agreement, RPS utility-owned generation).
17. MJUs should file a comprehensive IRP Supplement on July 15 of each year in which an IRP is not filed.
18. NDAs and confidentiality provisions should be modified to permit bidders/sellers to disclose information on the bidding and PPA negotiating process to the Commission, Commission staff, PRG and IE; but neither the Commission nor Commission staff should become involved in the negotiations, or the taking of sides in the bargaining, between buyer and bidder/seller.
19. Changes in the PVC should be made by Energy Division staff with stakeholder participation.
20. SCE's proposal to amend its 2011 Plan to include a new shortlisting requirement should be rejected.
21. IOUs' proposed changes (e.g., contract terms, SCE credit and collateral provisions, SDG&E TOD factors), unless specifically rejected herein, should be accepted to the extent described in this order consistent with the IOU ultimately being responsible for its portion of RPS Program success.
22. PacifiCorp should make clear in its next IRP or Supplement how it intends to achieve 20% by 2010.
23. Sierra's Supplement should be accepted, subject to Sierra (now CalPeco) being responsible for meeting California RPS Program targets and goals.
24. The 2011 RPS solicitation schedule in Appendix B should be adopted.
25. The same approach for Commission review and acceptance, rejection or modification of the 2012 RPS Procurement Plans should be used as employed for prior Plans, with the assigned Commissioner setting the specific schedule and addressing TRCRs.
26. The Executive Director should hire and manage one or more consultants to provide technical support and assist staff with certain tasks, with cost recovery on a proportional basis from the three largest IOUs, as provided herein.
27. SCE, PG&E, and SDG&E should each be authorized to record RPS technical contractor costs in their RPSCMAs; the costs should be recorded when paid; the costs should be subject to a limit on the total prorated amount to the three IOUs of $600,000 annually for up to four years; unspent funds in one year should be eligible to be carried forward to the next year (including years beyond year four), but the total expenditure should not exceed $2.4 million.
28. Evidentiary hearings are not necessary for the issues raised in this decision.
29. This proceeding should remain open.
30. This order should be effective today so that the 2011 RPS solicitation may proceed without delay.
IT IS ORDERED that:
1. Each utility-proposed renewable energy procurement plan, as part of the California Renewables Portfolio Standard Program, is conditionally accepted for the next Renewables Portfolio Standard Program solicitation. Each Plan includes, but is not limited to, Protocols, Request for Proposals, Request for Offers, model contracts and/or Power Purchase Agreements. The Plans are in the following documents:
a. The Pacific Gas and Electric Company "2010 Renewable Energy Procurement Plan (Draft Version)" filed December 18, 2009 (as updated on February 17, 2010, and amended on April 9 and June 6, 2010).
b. The Southern California Edison Company "2010 RPS Procurement Plan" filed December 18, 2009 (as amended on April 9 and June 12, 2010).
c. The San Diego Gas & Electric Company "2010 Draft Renewable Procurement Plan" filed December 18, 2009 (as updated on February 17, 2010 and amended on April 9, 2010).
2. Each document referenced above is adopted on the condition that:
a. Within 14 days of the date this order is mailed, Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company shall each file and serve a Final 2011 Renewables Portfolio Standard Procurement Plan that is consistent with all the orders in this decision, plus all guidance in this decision with which the utility agrees, and simultaneously file a copy with the Director of the Energy Division. The orders and guidance are summarized in, but not limited to, Appendix A.
b. Unless suspended by the Executive Director or Energy Division Director within 21 days of the date this order is mailed, each utility shall use its Final 2011 Renewables Portfolio Standard Procurement Plan for its 2011 solicitation.
3. The 2011 Renewables Portfolio Standard procurement schedule shall be as stated in Appendix B. The schedule may be modified by the Executive Director or Energy Division Director as reasonable and necessary for efficient administration of this solicitation. Parties may seek schedule modification by letter to the Executive Director (pursuant to Rule 16.6 of the Commission's Rules of Practice and Procedure).
4. The PacifiCorp "Additional Supplement to its 2008 Integrated Resource Plan (2010 Supplement)" filed December 18, 2009, and the Sierra Pacific Power Company (now California Pacific Electric Company, LLC) "Renewables Portfolio Standard 2010 Supplemental Filing" filed December 18, 2009, are each accepted. In its next Plan, PacifiCorp shall improve its explanation of how it will achieve California Renewables Portfolio Standard Program targets.
5. Consistent with all prior and current Commission orders and directions, each utility ultimately remains responsible for reasonable Renewables Portfolio Standard Program outcomes, within application of flexible compliance criteria. The Commission shall later review the results of renewable resource solicitations submitted for Commission approval, and accept or reject proposed contracts based on consistency with each approved Renewables Portfolio Standard Procurement Plan. The Commission shall also judge contract results, program results, and non-compliance pleadings by (but not limited to) considering the degree to which each utility implements Commission orders; reasonably elects to take or reject the guidance provided herein; reasonably demonstrates creativity, innovation and vigor in program execution; reaches program targets, goals, and requirements; and shows it took all reasonable actions to achieve compliance, including but not limited to the factors identified in this and prior orders.
6. The assigned Commissioner or Administrative Law Judge in this, or a successor, proceeding shall set a schedule for the filing and service of proposed Renewables Portfolio Standard Procurement Plans for the 2012 solicitation, as necessary. The assigned Commissioner or Administrative Law Judge shall set a schedule for matters related to Transmission Ranking Cost Reports to be used in the ranking of bids in a Renewables Portfolio Standard solicitation. The assigned Commissioner shall assess the adequacy of each Transmission Ranking Cost Report based on filed comments and reply comments, and shall determine whether each Transmission Ranking Cost Report shall be accepted, modified, or other steps taken before a Transmission Ranking Cost Report is used in ranking bids in a Renewables Portfolio Standard solicitation.
7. PacifiCorp and California Pacific Electric Company, LLC shall file by July 15, in years in which an Integrated Resource Plan is not filed, a Comprehensive Renewables Portfolio Standard Supplement to the Integrated Resource Plan.
8. The Executive Director may hire and manage one or more contractors to perform tasks described in this order for the purpose of advancing Renewables Portfolio Standard Program goals. Such costs, if any, shall not exceed a total annual amount of $600,000 for up to four years (with a cumulative total not to exceed $2.4 million). The costs shall be reimbursed by Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company on a proportional basis in relationship to retail sales reported each year in the March 1 Renewables Portfolio Standard compliance report (or other first report each year as directed by the Executive Director). Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company are authorized to record payments for these Renewables Portfolio Standard technical contractor costs into their Renewables Portfolio Standard Costs Memorandum Accounts. These costs shall be recorded when paid. Unspent funds in one year may be carried over and spent in a subsequent year, including years beyond year four, but the total shall not exceed $2.4 million.
9. Rulemaking 08-08-009 remains open.
This order is effective today.
Dated April 14, 2011, at San Francisco, California
MICHAEL R. PEEVEY
President
TIMOTHY ALAN SIMON
MICHEL PETER FLORIO
CATHERINE J.K. SANDOVAL
MARK FERRON
Commissioners
I reserve the right to file a concurrence.
/s/ TIMOTHY ALAN SIMON
Commissioner
APPENDIX A
SUMMARY OF KEY ITEMS
The attached decision reviews and conditionally accepts the 2011 RPS Procurement Plans of PG&E, SCE, and SDG&E. It reviews the Supplement to the IRP of CalPeco (formerly Sierra) and PacifiCorp. The orders and guidance, while not limited to those stated in this abstract, are summarized below in the same sequence addressed in the attached decision.
1. Buyer-Directed Economic Curtailment:
a. Pre-2011 Contracts: Decline to interpret terms in executed contracts; disputes of terms in executed contracts should be addressed via dispute resolution procedures within the contract; negotiations may occur on this and other modifiable terms in contracts not yet executed; an IOU is responsible for reasonable contract administration, including interpretation of terms in executed contracts and prior pro forma contracts.
b. 2011 Contracts: Require each IOU to include provisions in its Final 2011 Plan (including pro forma contract) for buyer-directed economic curtailment; require SCE to include congestion cost assessment in 2011 LCBF evaluations; affirm the continued assessment by SDG&E and PG&E of congestion costs in their LCBF evaluations; require each IOU to modify its LCBF description, as necessary, to explain use of economic curtailment and congestion costs; release specific congestion cost data (to the extent used in LCBF evaluations) to bidders as part of making its LCBF methodology transparent.
c. Full Deliverability: Decline to require that projects use the fully deliverable interconnection option. Require each IOU to modify its LCBF description, as necessary, to make its treatment of resource adequacy, and use of resource adequacy adders, clear as part of making its LCBF methodology transparent.
2. Integration Cost Adders: Decline to adopt non-zero integration cost adders; require each IOU to exclude language that would incorporate use of non-zero integration cost adders; permit each IOU to file an advice letter to amend its Final 2011 Plan if an adder is developed in R.10-05-006.
3. Tradable Renewable Energy Credits: Final 2011 Plans should include an IOU's intended use of TRECs; an MJU should file an Amended Supplement if its planned TREC use is changed as a result of the Commission's recent order.
4. Sunrise/Imperial Valley Issues: Decline to order any remedial measures, but continue monitoring of Imperial Valley proposals and projects; encourage each IOU to do appropriate outreach, including possible special Imperial Valley bidder's conferences.
5. CAISO Standard Capacity Product: Adopt IOU proposals to allocate both benefits and risks of CAISO SCP.
6. Pilot Program for Preapproval of Short-Term Contracts: Decline to adopt IOU proposals for preapproval of short-term contracts; encourage IOUs to be creative and vigorous in their use of Commission-authorized fast-track approval process; encourage IOUs to continue to consider and propose refinements to fast-track approval process based on experience with that process and the market.
7. Plan Organization and Standardization: Encourage IOUs to coordinate and develop a uniform, streamlined Plan among IOUs; encourage IOUs to increase Plan standardization in form and format, including solicitation protocols and pro forma contracts, to the fullest extent possible beginning immediately, with one proposed standardized contract among the IOUs for Commission preapproval (with negotiation between parties of that standardized contract before execution always permitted, to the extent necessary).
8. Other Updates: Each Final 2011 Plan should be a complete, comprehensive, up-to-date plan of all procurement tools an IOU intends to use to reach RPS targets and goals, including procurement via the Renewable Auction Mechanism, solar photovoltaic programs, qualifying facilities, utility-owned RPS generation, and any others to be used by an IOU.
9. Date for MJU Supplemental Filing: Set July 15 as the date by which MJUs must file comprehensive supplements in years when an Integrated Resource Plan is not filed.
10. Nondisclosure Agreements: Non-disclosure agreements and confidentiality provisions must be modified to permit disclosure by bidders/sellers of the bidding and negotiating process to the Commission, Commission staff, PRG, and IE. The disclosures must focus on process and not individual bids. The Commission and Commission staff will not be drawn into negotiations or the taking of sides in the bargaining between buyer and bidder/seller.
11. PG&E: Accept changes proposed by PG&E subject to PG&E being held responsible for reaching program targets and goals.
12. SCE:
a. Modifications to Project Viability Calculator: Decline to authorize changes proposed by SCE; PVC is a uniform, standardized tool developed by Energy Division staff used for project assessment and comparisons, but IOUs may work with Energy Division staff to initiate a stakeholder process if modifications are sought.
b. Credit and Collateral Provisions: Accept changes proposed by SCE subject to SCE being held responsible for reaching program targets and goals.
c. Shortlisting Requirement: Decline to authorize new shortlisting requirement proposed by SCE.
d. Other: Accept other changes proposed by SCE subject to SCE being held responsible for reaching program targets and goals.
13. SDG&E:
a. TOD Factors: Accept proposed changes to TOD factors based on all-in (capacity plus energy) factors.
b. Other: Accept other changes proposed by SDG&E subject to SDG&E being held responsible for reaching program targets and goals.
14. PacifiCorp: Additional Supplement is accepted, subject to PacifiCorp being held responsible for reaching program targets and goals; direct PacifiCorp to do a better job in its next showing of explaining how it will achieve California RPS targets.
15. CalPeco: Accept IRP Supplement subject to CalPeco being held responsible for reaching program targets and goals.
16. Schedule:
a. 2011: Schedule in Appendix B is adopted.
b. 2012: The assigned Commissioner or Administrative Law Judge will set the specific schedule; the assigned Commissioner shall rule on the proposed Transmission Ranking Cost Reports; parties should continue to consider and, where feasible, propose alternatives that accomplish RPS Program objectives while mitigating some of the burden placed on all stakeholders from an annual solicitation; encourage IOUs to propose Plans that may either be adopted for more than one year, or more than one year with only minor updates; encourage IOUs to propose something other than an annual solicitation cycle and, in particular, consider approaches that would permit frequent, if not continuous, RPS solicitations.
17. Additional Resources: The Executive Director may hire and manage one or more consultants to accomplish RPS Program goals at a cost not to exceed $600,000 per year for no more than four years, with the costs reimbursed by PG&E, SCE, and SDG&E; unspent funds may be carried forward and spent in a subsequent year (including years beyond year four), but the total expenditure may not exceed $2.4 million.
(END OF APPENDIX A)
APPENDIX B
ADOPTED SCHEDULE FOR 2011 SOLICITATION
LINE NO. |
ITEM |
NO. OF DAYS (cumulative) |
1 |
Mailing of Commission decision conditionally approving 2011 RPS Plans |
0 |
2 |
IOUs file amended RPS Plans |
14 |
3 |
IOUs issue RFOs (unless amended Plans are suspended by Energy Division Director by Day 21) |
21 (a) |
4 |
IOUs notify Commission that bidding is closed |
81 |
5 |
Date IOUs notify bidders of shortlist; no exclusivity agreements may be required before this date |
123 |
6 |
IOUs submit shortlists to Commission and PRG |
133 |
7 |
IOUs file by Tier 2 advice letter (a) Evaluation Criteria and Selection Process Report and (b) Independent Evaluator's Preliminary Report |
163 |
8 |
IOUs submit ALs with PPAs for Commission consideration (as necessary for earmarking) |
282 |
Note: The Energy Division Director may change these dates. Party requests for changes must be directed to the Executive Director (Rule 16.6).
(a) An IOU may adjust this date to a day after day 21, as necessary, without Commission approval.
(END OF APPENDIX B)
APPENDIX C
LINKS TO DRAFT 2011 PROCUREMENT PLANS
AND SUPPLEMENTS TO INTEGRATED RESOURCE PLANS
FOR RENEWABLES PORTFOLIO STANDARD PROGRAM
1. Pacific Gas and Electric Company
http://docs.cpuc.ca.gov/EFILE/MISC/119090.htm
2. Southern California Edison Company
http://docs.cpuc.ca.gov/EFILE/MOTION/120022.htm
3. San Diego Gas & Electric Company
http://docs.cpuc.ca.gov/EFILE/REPORT/116582.htm
4. PacifiCorp
http://docs.cpuc.ca.gov/EFILE/MISC/111935.htm
5. California Pacific Electric Company, LLC
(formerly Sierra Pacific Power Company)
(END OF APPENDIX C)
APPENDIX D
SUMMARY OF CHANGES PROPOSED BY IOUS IN 2011 PLANS
The three large IOUs propose several changes for their pro forma contracts. The major changes identified by the IOUs are summarized here.
PACIFIC GAS AND ELECTRIC COMPANY
As described by PG&E, changes include but are not limited to:
· delay in online date;
· guaranteed energy production;
· commercially reasonable efforts to maintain eligible renewable resource status;
· updated insurance provisions;
· clearer delineation of buyer and seller responsibilities for CAISO Eligible Intermittent Resource Program (EIRP) costs; and
· modifiable standard terms and conditions.
PG&E also proposes several other changes. These include:
· require sellers located outside the CAISO balancing area to provide more detail about how they plan to deliver energy to the CAISO grid;
· require sellers to identify if the project is located in a renewable energy zone associated with the Regional Transmission Planning Initiatives (RETI), Western Renewable Energy Zone (WREZ) or other comprehensive and official resource study effort;
· limit number of project offers PG&E will accept from each seller to no more than 5 projects (or more than 5 projects if the aggregate total is less than 200 MW);
· extension of time for sellers to post offer deposits, with a modified definition of Letter of Credit;
· requirement that bidders submit a detailed term sheet with the initial offer that identifies key commercial terms and conditions with PPA modifications sought by bidder (eliminating the requirement that bidders submit a marked-up form PPA with the initial offer);
· remove the requirement that PPA purchase options be at a fixed price only at years 5 and 10 but may be at fair market value at dates proposed in the offer;
· limit joint development and ownership proposals to those located within California using commercially proven technologies; and
· require more complete information with joint development and ownership proposals.
SOUTHERN CALIFORNIA EDISON COMPANY
As described by SCE, changes include but are not limited to:
· Non-disclosure Agreement (NDA) Procedure: SCE will now require sellers to agree to a "short-term NDA" (which generally covers matters up to the date of the shortlist, with those items then held confidential for 5 years), rather than negotiate an NDA before the bids are evaluated;
· Deletion of Alternate Wind Performance Standard: SCE will present and explain the alternate wind performance standard during negotiations rather than post the alternate on SCE's website and in solicitation materials (since SCE has found most sellers do not use the alternate);
· Procurement Protocol: added seller's breach of exclusivity agreement as a condition for forfeiture of a short list deposit; requires proposals with terms longer than 20 years to also include a 20 year term (to assist in proposal comparison); states preference for facilities whose first point of interconnection within Western Electricity Coordinating Council (WECC) is with a California balancing authority (while still open to considering proposals from out-of-state facilities);
· Form of Seller's Proposal: requires bidders to submit proposals electronically in an e-binder rather than printed copies; requires greater bid specificity of delivery point, detail for transmitting energy to delivery point, and explanation of whether delivery costs are in energy price; requires disclosure of possible equipment availability constraints;
· Seller's Acknowledgements: clarification of language that seller will obtain approvals of PPA with SCE at the conclusion of negotiations (not by the time bidder first submits proposal); modified language to require seller to negotiate with SCE in good faith (rather than be bound by a redlined proposed PPA; the redlined PPA has been replaced with a required outline of contract terms and conditions setting forth key changes seller seeks in PPA); elimination of requirement that seller submit CEC audits regarding ERR status (audits are addressed in the PPA);
· Seller's Proposal Template and Calculator: integrated revenue calculator into Seller's Proposal Template and Calculator; require each proposal to provide contract prices based on curtailment caps;67 required some additional information and eliminated other information no longer needed;
· PPA: require sellers to invoice SCE monthly to receive payment; narrowed the circumstances under which a "compliance expenditure cap" applies (e.g., dollar limit on seller's costs to maintain certain characteristics due to a change in law); changes the Energy Replacement Damage Amount penalty calculation from being based on "market" prices (dominated by conventional generation resources) to "green market" prices (i.e., price for renewable generation resources); added language to specify proper allocation of roles and responsibilities of SCE (as scheduling coordinator for purposes of North American Electric Reliability Corporation (NERC) compliance) and seller (as the generator operator); revised language so SCE may terminate the PPA and retain development deposit under any one of six circumstances (to eliminate a termination right disfavored by lenders while ensuring the SCE can terminate projects unlikely to be built); requiring seller to specifically state before contract execution whether seller will seek an investment tax credit, production tax credit, or no tax credit; divided into two sections the right of either party to terminate when seller fails to obtain permits (to better allow individually-tailored time periods); allocation of Standard Capacity Product incentive payments and charges defined in CAISO tariff;68 modified energy payment calculation formula relative to delivery losses to mirror current CAISO MRTU market; modified wind and solar performance requirements; modified indemnification obligations to more clearly reflect different duties, responsibilities and risks of SCE and sellers; removed requirement that seller provide its financial information for purposes of consolidating seller's financial information into SCE's financial statements (given June 2009 changes by Financial Accounting Standards Board (SFAS 167 Amendments to FASB Interpretation No. 46(R)) regarding conditions associated with consolidation); modified data collection regarding seller's estimate of lost output and SCE right to verify data.
SAN DIEGO GAS & ELECTRIC COMPANY
As described by SDG&E, changes include but are not limited to:
· LCBF Ranking Price: Adjusted to use above market funds (AMF) Calculator (which values a bid's cost relative to MPR and takes into consideration applicable delivery profiles and TOU factors); not use TOD Adder (since AMF Calculator includes adjustments for TOD factors), RA Adder (since proposed TOD factors include some capacity valuation), Duration Equalizer Adder (since experience shows no material impact on outcomes);
· LCBF Very Short Term Offers: Will use price reasonableness benchmark methodology for very short-term RPS (to conform with D.09-06-050);
· Pricing Forms: Revised to capture bidders' suggestions, automate certain inputs, reduce bidder errors (making bid forms simpler and more user-friendly);
· RFO: Continue utility-owned generation consideration, but not in RFO seeking bids (to fulfill code of conduct obligations in D.07-12-052);
· RFO: Increase minimum project size for projects in SDG&E's area from 1.5 MW to 3.0 MW if SB 32 implemented (allowing FIT to accommodate smaller projects); and
· Proforma PPA: Make selected terms defined terms and correct grammar errors (for consistency).
(END OF APPENDIX D)
Concurrence of Commissioner Timothy Alan Simon
Decision Conditionally Accepting 2011 Renewables Portfolio Standard Procurement Plans and Integrated Resource Plan Supplements
Introduction
This Decision69 makes a number of important improvements and updates to our renewable procurement planning requirements for Investor-Owned Utilities and Multi-Jurisdictional Utilities, and thus marks another step forward in California's Renewable Portfolio Standard (RPS) programs. In particular, I am pleased that we are incorporating a greater level of specificity and utility control in the provisions of economic curtailment and related modifications to pro-forma contract terms.70 Another essential element of this Decision is the required use of integration cost adders associated with ancillary services to ensure greater reliability in lieu of increased variability in generation and/or load.71 However, in concurrence with this Decision, on a forward looking basis I want to ensure that the California Public Utilities Commission (CPUC) incorporates additional economic considerations in our RPS procurement planning process and "Least Cost Best Fit" contract evaluations.
Evaluating the Impacts of Renewable Targets on the California Economy
In the signing ceremony of SB2x72 Governor Edmund Brown, Jr. reiterated that 33 percent is the floor and not the ceiling of renewable procurement, and accordingly envisions 40 percent as an achievable RPS goal.73 I support this ambitious long-term objective, but we must remain vigilant that we balance our environmental goals with a healthy economy. This mandate will require a more selective process by the CPUC in examining the quality and cost-effectiveness of individual contracts that we approve. This is imperative to meet the energy needs of California's commercial and industrial customers, which could see substantial increases in electricity bills if we fail to foster adequate competition in our renewable portfolio. I have concerns that increased electricity costs and limited Direct Access could result in job losses, even as clean technology development in California is premised in part on the hope of increased economic activity. Accordingly, a heightened focus on energy efficiency and demand response technologies is critical to California achieving a balance between greenhouse gas emissions reductions and competitive advantage in attracting and retaining business opportunities. To this end, I remain concerned that our rapid pursuit of renewable generation is overly incremental and ad hoc in deployment.
Tracking the True Cost of Renewable Generation
To achieve a cost effective and balanced energy mix we must evaluate the full fuel cycle costs of renewable generation when weighing incremental procurement choices. As we examine firming and shaping needs for renewable generation, we cannot ignore the magnitude of shale gas discoveries across the U.S. and the positive impact this can have on the full fuel cycle cost of clean energy alternatives. For instance, when combined with other domestic shale gas supplies, the Utica74 and Marcellus shale plays could offer up to 200 years of natural gas supply. Shale exploration is not without controversy, as the hydraulic tracking debate continues. With effective environmental management of exploration, vast gas supplies may give a low cost energy advantage to competing states. Additionally, as we explore and advance energy storage options,75 it is clear that a comprehensive policy on fuel options is critical.
New Targets, New Technological and Economic Considerations
Our new legislative mandates76 require increasingly complex analyses of alternative supply- and demand-side energy resources in our long-term procurement planning processes. While I am very supportive of our continued RPS development, I challenge this Commission and staff to expand our understanding of the comprehensive costs of California's clean tech pursuits. In doing so, I believe we will establish the discipline necessary to carefully weigh all procurement options by considering some of the practical results and consequences of our decisions on the welfare of all customer classes. Accordingly, I concur with this Decision, and look forward to monitoring our progress as renewable procurement evolves and presents challenges in our broad long-term procurement planning process.
Dated April 19, 2011, at San Francisco, California.
/s/ TIMOTHY ALAN SIMON | ||
Timothy Alan Simon Commissioner |
67 As each IOU must do relative to all decisions in this order, we specifically point out that SCE must modify this portion of the Seller's Proposal Template and Calculator to align with our decisions on economic curtailment elsewhere in this order.
68 As each IOU must do relative to all decisions in this order, we specifically point out that SCE must modify this portion of the Seller's Proposal Template and Calculator to align with our decisions on SCP incentive payments elsewhere in this order.
69 Decision Conditionally Accepting 2011 Renewables Portfolio Standard Procurement Plans and Integrated Resource Plan Supplements (D.11-04-030), April 14, 2011.
70 Id. At 12-13.
71 Id. at 22.
72 Senate Bill 2x (Simitian, D-Palo Alto), signed into law on April 12, 2011, raises California's Renewable Portfolio Standard target to 33%.
73 See http://www.latimes.com/news/local/la-me-renewable-energy-20110413,0,3118203.story for details about Governor Brown's speech at the signing ceremony in Milpitas, California on April 12, 2011.
74 See discussion of Utica and other shale formations at http://oilshalegas.com/uticashale.html.
75 Order Instituting Rulemaking Pursuant to Assembly Bill 2514 to Consider the Adoption of Procurement Targets for Viable and Cost-Effective Energy Storage Systems (R.10-12-007) issued December 21, 2010.
76 SB2x requires that we reach 20% renewables by the end of 2013, 25% renewables by the end of 2016, and 33% by the end of 2020.
