PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA
I.D. # 11526
ENERGY DIVISION RESOLUTION E-4494
September 13, 2012
RESOLUTION
Resolution E-4494. Pacific Gas & Electric Company requests approval of a replacement power purchase agreement with O.L.S. Energy-Agnews, Inc.
PROPOSED OUTCOME: This Resolution approves without modification the Replacement PPA between Pacific Gas and Electric and OL.S. Energy-Agnews, which converts the CHP facility to a dispatchable Utility Prescheduled Facility under the QF/CHP Settlement.
ESTIMATED COST: The costs associated with the Replacement PPA are expected to provide ratepayer benefits in comparison to the terms of the Existing PPA. These benefits result from reduced firm capacity payments and reduced operational costs associated with the conversion of Agnews to a Utility Prescheduled Facility.
By Advice Letter 4010-E filed on March 9, 2012 which was supplemented by Advice Letter 4010-E-A filed on April 24, 2012.
__________________________________________________________
SUMMARY
Pacific Gas and Electric Company's ("PG&E's") Replacement Power Purchase Agreement ("Replacement PPA") to the existing Interim Standard Offer 4 ("ISO4" or "Existing") PPA with O.L.S. Energy-Agnews ("Agnews" or "Seller") complies with the requirements of a bilaterally negotiated PPA for conversion to a Utility Prescheduled Facility ("UPF") under the QF/CHP Settlement ("Settlement") and is approved without modification.
On March 9, 2011, PG&E filed Advice Letter ("AL") 4010-E requesting Commission approval of a new PPA with Agnews for the remainder of the contract term, approximately eight years. Agnews is a 36.1 MW nameplate capacity natural gas topping cycle combined heat and power facility located in San Jose. The facility operates up to a maximum contract capacity of 28 MW under an existing ISO4 PPA. The ISO4 PPA was executed April 16, 1985, and was amended in 1989, 2001, and 2006. The existing ISO4 PPA expires on
April 18, 2021.
Under the Existing PPA, PG&E does not have scheduling rights and, pursuant to the Public Utilities Regulatory Policies Act of 1978 ("PURPA"), PG&E is obligated to purchase the electricity generated notwithstanding the need for the energy or its cost-effectiveness. PG&E pays Agnews for electricity deliveries at the variable short run avoided cost1 ("SRACVAR") and firm capacity payments for its first 24 MW and fixed as-available capacity for any additional capacity the facility provides. By converting the facility into a UPF, the Replacement PPA eliminates the must-take requirement and provides PG&E the right to schedule the facility when needed.
Agnews is contractually obligated until 2020 to provide electricity and steam to the Developmental Center, a hospital and medical facility, operated by the State of California. The Developmental Center provided a load and steam host for the CHP. As the State phased out the use of the Developmental Center between
2004 and 2009, PG&E identified that the discontinuation of the thermal host provided an opportunity to replace the ISO4 PPA with a new Replacement PPA that would provide substantial customer benefits.
PG&E has determined that since 2007, the operating efficiency of the facility has and will continue to comply with the PURPA regulations defined in 18 C.F.R. §292.205 for the remainder of the existing contract. As such, PG&E negotiated with Seller to determine a Replacement PPA for the facility that removes the must-take obligation. Upon Commission approval and satisfaction of precedent conditions, the Replacement PPA becomes effective until expiration on
April 18, 2021.
Granting PG&E the right to schedule the facility as needed and when cost-effective allows for both enhanced operational flexibility and improved integration with the California Independent System Operator's ("CAISO") scheduling protocols. Decreasing the capacity factor from in excess of 60% to significantly lower than 50% provides substantial greenhouse gas ("GHG") emissions reductions. Additionally, customers benefit from lowered firm capacity payments and continued Resource Adequacy benefits. In comparison to the total value of the ISO4 PPA, the execution of the new Replacement PPA provides a net savings benefit to ratepayers.
A summary of the Replacement PPA and an analysis of benefits are included within the Confidential Appendix A of this Resolution.
BACKGROUND
On December 16, 2010, the Commission adopted the Qualifying Facilities and Combined Heat and Power (QF/CHP) Program Settlement with the issuance of Decision (D.)10-12-035. The Settlement resolves a number of longstanding issues regarding the contractual obligations and procurement options for facilities operating under legacy and new QF contracts.
The QF/CHP Settlement establishes Megawatt ("MW") procurement targets and greenhouse gas ("GHG") emissions reduction targets the investor-owned utilities are required to meet by entering into contracts with eligible CHP facilities, as defined in the Settlement. Pursuant to the Decision, the IOUs must procure a minimum of 3,000 MW of CHP and reduce 4.8 MMT of GHG emissions consistent with the California Air Resources Board ("CARB") Scoping Plan.
Among other things, D.10-12-035 updates methodologies and formulas for Short Run Avoided Cost ("SRAC") energy price for QFs to be used in standard offer contracts for QFs under 20 megawatts ("MW"), Transition PPAs, amendments to existing QF PPAs, and Optional As-Available PPAs. The SRAC methodology under the QF/CHP settlement includes:
(1) By January 1, 2015, transitioning SRAC pricing from a formula that is based in part on administratively-determined heat rates to a formula that solely uses market heat rates;
(2) Investor-owned utility ("IOU")-specific time-of-use ("TOU") factors to be applied to energy prices to encourage energy deliveries during the times when the energy is most needed by customers;
(3) A locational adjustment based on California Independent System Operator ("CAISO") nodal prices; and,
(4) Pricing options based on whether a cap-and-trade program or other form of greenhouse gas ("GHG") regulation is developed in California or nationally.
In addition, the Commission defined several procurement options for the IOUs within the Settlement. One of these contracting options allows the IOUs to change the operations of an existing CHP to convert to a dispatchable generation facility, known as a "Utility Prescheduled Facility."2 This conversion can provide significant operational flexibility to facilitate the integration of intermittent renewable resources and provides a means to enable a CHP resource to continue operating when a thermal host no longer exists. The Commission has already approved a UPF conversion for a CHP where its thermal host has discontinued operations.3
NOTICE
Notice of AL 4010-E was made by publication in the Commission's Daily Calendar. Pacific Gas & Electric states that a copy of the Advice Letter was mailed and distributed in accordance with Section 3.14 of General Order 96-B.
PROTESTS
Advice Letter 4010-E was protested.
Advice Letter 4010-E was timely protested by Marin Energy Authority (MEA) and Alliance for Retail Energy Markets (AREM) on March 29, 2012. PG&E responded to the protest of MEA on April 5, 2012. PG&E filed Supplement
AL 4010-E-A in response on April 24, 2012. The protest period was not closed. The Supplement Advice Letter 4010-E-A ("Supplement") received two protests on May 14, 2012. The first protest was raised jointly by MEA, AREM, the Direct Access Consumer Coalition (DACC), and the Energy Users Forum (EUF) ("Joint Protestors"). The second protest was received from Californians for Renewable Energy (CARE). PG&E filed a reply to the protests to the Supplement on
May 21, 2012.
MEA and AREM assert that AL 4010-E does not appropriately allocate costs.
In the March 29, 2012 protest, MEA and AREM asserted that "the Advice Letter does not allocate costs and RA benefits as required by D.10-12-035."4 This protest refers to PG&E's second request that the Commission "Authorize Recovery of the costs associated with the Replacement PPA, through PG&E's ERRA and recovery of stranded costs consistent with D.08-09-012." The protest argues that this method of cost recovery is inconsistent with D.10-12-035 which prescribed that the utilities procure CHP resources on behalf of the Electricity Service Providers ("ESPs") and Community Choice Aggregators ("CCAs") and allocate the resource adequacy ("RA") benefits and net capacity costs ("NCC") per Section 13.1.2.2 of the CHP Program Settlement Agreement Term Sheet ("Term Sheet").5
In its response, PG&E acknowledged this error and revised its requests within the Supplement to conform to the cost recovery requirements of the Settlement.
MEA and AREM assert that AL 4010-E does not appropriately allocate GHG emissions reductions.
Second, MEA and AREM asserted that "the Advice Letter intends to allocate GHG reductions to PG&E's emissions reductions targets, notwithstanding the proportionate ESP and CCA emissions reductions targets."6 This protest refers to PG&E's third request that the Commission "Determine that any GHG reductions associated with the Replacement PPA count toward PG&E's GHG Emissions Reduction Target included in the CHP Settlement." MEA and AREM appear to be concerned that if GHG reductions from the Replacement PPA would "count toward PG&E's" reduction target then resulting emissions would not count toward the ESP and CCA allocation of the CARB CHP GHG Recommended Reduction Measure ("RRM") as prescribed in Section 6.3.2 of the Term Sheet.
In its response, PG&E recognized this concern. In the Supplement PG&E edited the language of the Advice Letter to reflect that GHG reductions from the Replacement PPA would count toward "the GHG Emissions Reduction Targets included in the Settlement."
Joint Protesters assert that the Supplement AL 4010-E-A does not appropriately allocate RA benefits.
On May 14, 2012, Joint Protestors filed a protest to the Supplement 4010-E-A asserting that it "Does not allocate RA benefits as required by D.10-12-035."7
Joint Protesters assert that the Supplement AL 4010-E-A does not appropriately allocate GHG benefits.
Second, Joint Protestors protested that the Supplement "Does not clearly allocate the GHG benefits associated with the facility."8 The protestors requested more specific language to clarify that GHG reductions associated with the Replacement PPA shall count toward the reduction target "for PG&E and ESPs and CCAs within PG&E's service territory."
CARE asserts that the QF/CHP Settlement fails to comply with Federal Law.
On May 14, 2012, CARE protested that the QF/CHP Settlement "fails to comply with federal law." CARE references a FERC order and a Federal District Court judge's order.9
DISCUSSION
On March 9, 2012 PG&E filed Advice Letter ("AL") 4010-E which requests Commission approval of a power purchase agreement with O.L.S. Energy-Agnews, Inc. that will replace an existing Qualifying Facility ("QF") contract. The existing QF contract for energy and capacity deliveries from the Agnews facility, a 28 MW topping cycle natural gas-fired cogeneration facility in San Jose, California, was executed April 16, 1986 and will expire in April 2021.
Specifically, PG&E requests that the Commission:
1. Approve the Replacement PPA without modification as just and reasonable;
2. Authorize recovery of the costs associated with the Replacement PPA through the cost recovery mechanisms set forth in D.10-12-035 (as modified by D.11-07-010), Section 13.1.2.2 of the QF/CHP Settlement Term Sheet, and PG&E's Advice Letter 3922-E.10
3. Determine that any GHG reductions associated with the Replacement PPA count toward the GHG Emissions Reduction Targets included in the QF/CHP Settlement; and11
4. Find that because the expected annualized plant capacity factor of the Facility under the Replacement PPA is below 60 percent, the Replacement PPA is not a covered procurement subject to the EPS adopted in
D.07-01-039.
Energy Division evaluated the Proposed PPA based on the following criteria:
· Consistency with D.10-12-035 which approved the QF/CHP Program Settlement including:
o Consistency with bilateral negotiations
o Consistency with MW accounting
o Consistency with GHG accounting
o Consistency with cost recovery requirements
· Cost reasonableness
· Project viability
· Consistency with the Emissions Performance Standard
· Consistency with D.02-08-071, which requires Procurement Review Group (PRG) participation
In considering these factors, Energy Division also considers the analysis and recommendations of an Independent Evaluator, if available.12 In this case, neither PG&E nor Seller elected to engage with an Independent Evaluator.
Consistency with D.10-12-035 which approved the QF/CHP Program Settlement including:
Consistency with bilateral negotiations
On December 16, 2010, the Commission adopted the QF/CHP Program Settlement with the issuance of D.10-12-035. The Settlement resolves a number of longstanding issues regarding the contractual obligations and procurement options for facilities operating under legacy and new QF contracts. Among other things, it establishes methodologies and formulas for calculating SRAC to be used in new QF standard offer contracts. Furthermore, the Settlement allows for bilaterally negotiated contracts with QFs to determine alternative energy and capacity payments mutually agreeable by relevant parties and subject to CPUC approval. Finally, the Settlement establishes a MW and GHG target for the IOUs. The IOUs must procure 3,000 MW of CHP and 4.8 MMT of greenhouse gas reduction emission reductions in proportion to the load of the IOU and non-IOU Load Serving Entities. The QF/CHP Settlement became effective on
November 23, 2011.
Per Section 4.3 of the Term Sheet, bilaterally negotiated and executed Utility Prescheduled Facility PPAs are included among the procurement options in the CHP Program. Pricing, terms, and conditions will be determined according to the executed and approved PPA.
Per Section 4.8.1.1, a CHP facility must meet the PURPA efficiency requirements13 as of September 20, 2007 to obtain a PPA to convert to a Utility Prescheduled Facility. Agnews has met the PURPA efficiency requirements as shown in Confidential Appendix A.
Pursuant to the QF/CHP Settlement, PG&E is permitted to enter a bilaterally-negotiated Utility Prescheduled Facility power purchase agreement ("Replacement PPA") with O.L.S. Energy-Agnews ("Seller") because the Agnews facility meets the efficiency requirements under the Public Utility Regulatory Policies Act of 1978 ("PURPA").
CARE's protest that the Settlement "does not comply" with federal law and therefore bars the Commission from approving contracts pursuant to the Settlement must be dismissed. CPUC rules related to Supplements to Advice Letters require that "[a]ny new protest shall be limited to the substance of the Supplement or additional information."14 The Supplement was limited to revisions to PG&E's requests related to the allocation of costs and GHG benefits. CARE's protest exceeds the scope of the Supplement as required by Rule 7.5.1. The Commission has ordered that the Settlement is effective November 23, 2011 and is permitted to act on this Advice Letter.
CARE's protest is dismissed upon the grounds that it exceeds the scope of the Supplement, as required by Rule 7.5.1.
Consistency with MW accounting
Per Term Sheet Section 4.8.1.2, new PPAs that change generating facilities' operations into Utility Prescheduled Facilities, that are not Legacy PPA Amendments, count towards the MW Targets if the existing QF PPA expires before the end of the Transition Period, July 1, 2015. OLS-Energy Agnews' Interim Standard Offer 4 (ISO4) PPA terminates after the end of the transition period on April 18, 2021. Therefore it does not count toward PG&E's MW Target. This is appropriately reflected in the Advice Letter as supplemented.
Pursuant to the QF/CHP Settlement, Seller's contract capacity under the Replacement PPA does not count toward PG&E's MW procurement target because Seller's existing QF ISO4 PPA expires after the end of the Transition Period.
Consistency with Greenhouse Gas accounting
Per Term Sheet Section 7.3.1.3, a CHP Facility Change in Operations or Conversion to a Utility Prescheduled Facility counts as a GHG credit for the IOUs' GHG Emissions Reduction Targets. Measurement is based on the baseline year emissions (the average of the previous two years of operational data) minus the projected PPA emissions and emissions associated with replacing 100% of the decreased electric generation at a time differentiated heat rate.
For example, the GHG credit is calculated by first subtracting the expected emissions from operations in the Replacement PPA from the baseline emissions in the ISO4 PPA. The GHG credit deducts from this difference the emissions resulting from "replacement" electric generation. Replacement (or "backfill") electricity accounts for the market electricity required to compensate for the decreased operations from the conversion to a UPF.
The Replacement PPA provides PG&E rights as the Scheduling Coordinator for the Agnews facility. PG&E anticipates that generating operations will be significantly reduced compared to the existing power purchase agreement. The capacity factor is expected to decrease from above 60% under current operations to significantly less than 50%. This change in the facility's operating schedule reduces its greenhouse gas emissions proportionately. The resulting emissions reductions can be accounted as a credit of 14,635 metric tonnes (MT) toward the GHG Emissions Reductions Targets of the Settlement as prescribed in Section 7.3.1.3. This is appropriately reflected in the Advice Letter as supplemented.
Additional information about the GHG emissions accounting is included in Confidential Appendix A.
The facility's operations under the Replacement PPA as a Utility Prescheduled Facility will be significantly reduced compared to the prior two years of operations, yielding 14,635 MT of greenhouse gas emissions reductions under the accounting methodologies pursuant the Settlement that will be credited toward the QF/CHP Settlement greenhouse gas ("GHG") Emissions Reduction Target.
Consistency with cost recovery requirements
In D.10-12-035, Ordering Paragraph 5, the Commission ordered the IOUs to purchase CHP resources on behalf of the Electricity Service Providers and Community Choice Aggregators and to allocate the Resource Adequacy benefits and Net Capacity Costs associated with this procurement to the ESPs and CCAs as described in Section 13.1.2.2 of the Term Sheet.
PG&E revised its Advice Letter in Supplement AL 4010-E-A and requests that the Commission "Authorize the recovery of costs associated with the Replacement PPA as set forth in D.10-12-035 (as modified by D.11-07-010), Section 13.1.2.2 of the QF/CHP Settlement Term Sheet, and PG&E AL-3922-E."
Ordering Paragraph 5 of D.10-12-035 orders the three large electric IOUs to recover the net capacity costs from CHP Program contracts on a non-bypassable basis from all bundled service, DA and CCA, and Departing Load Customers (DLC), except for CHP DLC. With this authorization, the Settlement supersedes to the extent necessary D.06-07-029 and D.08-09-012, which, established and modified the Cost Allocation Mechanism, respectively. Section 13.1.2.2 requires that the IOU recover CHP contract costs, net of the value of energy and ancillary services provided to the IOU. Non-IOU LSEs receive RA credits in proportion to the allocation of the net capacity costs that they pay.
On November 23, 2011 the Commission approved AL-3922-E, which authorized PG&E to establish the New System Generation Balancing Account to recover the net capacity costs of CHP contracts as it was directed by D.10-12-035. AL-3922-E determines the net capacity costs as the result of a debit and credit, where:15
· Debit: NCC recovery-eligible capacity and energy costs for QF/CHP Program contracts.
· Credit: NCC recovery-eligible energy revenues, the product of energy assumed to be dispatched under the Energy Auction PPA and the CAISO hourly day-ahead nodal price for the PPA's injection point.
Joint Protestors claim that the methodology outlined in the revisions to Advice Letter 4010-E-A, and as Energy Division describes above, do not properly allocate 1) RA benefits and 2) GHG benefits.
First, regarding the allocation of RA benefits, Energy Division accepts the protest that the RA benefits are included within the substance of the Supplement. The method of allocating RA credits is affected by the method of allocating net capacity costs per Term Sheet 13.1.2.2. Energy Division acknowledges this protest but denies the protestors' request to alter the language of the Advice Letter. PG&E's revised request that the Commission authorize recovery of costs associated with the Replacement PPA through the mechanisms set forth in
D.10-12-035 (as modified by D.11-07-010), Section 13.1.2.2, and AL 3922-E adequately determines the means by which RA credits will be allocated.
Section 13.1.2.2 clearly states:
In exchange for paying a share of the net costs of the CHP Program, the LSEs serving DA and CCA customers will receive a pro-rata share of the RA credits procured via the CHP Program.
ESP and CCA customers will be allocated RA credits commensurate to the proportion of the net capacity costs that they pay as required by the terms of Section 13.1.2.2. As a result, there is no need to change the language of the request in the Supplement.
Resource adequacy ("RA") credits are to be allocated according to the share of the net capacity costs paid by load-serving entities ("LSEs") serving direct access ("DA") and community choice aggregation ("CCA") customers as prescribed in Section 13.1.2.2 of the Term Sheet.
Second, regarding the allocation of GHG benefits, Energy Division denies the proposed revision seeking more specific language concerning the emissions reduction targets. The requested revision is unnecessary because D.10-12-035 Ordering Paragraph 5 determined that the IOUs will procure CHP resources to meet both the IOUs and ESP/CCAs' GHG Emissions Reduction Targets as described in Section 6.3 of the Term Sheet. The non-IOU LSEs serving DA and CCA customers are not responsible for purchasing CHP resources, and are therefore not required to procure their respective shares of the CARB GHG RRM. Section 6.3.2 clearly states:
As set forth further in Section 13.1.2, the IOUs will obtain CHP [on behalf of DA and CCA customers]16 and each non-IOU LSE will be allocated cost responsibility for GHG reductions attributable to CHP based on its proportion of statewide retail sales.
ESP and CCA customers will be allocated cost responsibility for GHG reductions for CHP resources purchased by the IOUs on their behalf, but there will be no allocation of "GHG benefits." Section 6.3.2 determines that the IOUs are exclusively responsible for acquiring the CHP resources necessary to meet the combined Emissions Reduction Target ("ERT") of the IOUs and non-IOU LSEs (currently defined as CARB's RRM in Section 6.2.2.3). Furthermore, the IOUs will remain obligated to procure CHP to meet the ERT (or MW Target) until the end of the Second Program Period.17 Restated, there is no need to specifically allocate GHG benefits from each CHP contract to each LSE because the IOUs have sole liability to meet the GHG goal. As stated above, RA credits -allocated in proportion to the net capacity costs paid by an LSE for the CHP Program- are the only benefits allocated during the recovery of CHP contract costs. As a result, Energy Division denies the Joint Protestors' proposed revisions to PG&E's
AL 4010-E-A.
RA credits are allocated in proportion to net capacity costs per Section 13.1.2.2 of the Term Sheet. It is not necessary to allocate GHG benefits because the IOUs have sole responsibility for the Emissions Reduction Target per Section 6.3.2 of the Term Sheet.
Since the bilaterally negotiated UPF Replacement PPA for the Agnews facility is an eligible procurement option pursuant to the Settlement, PG&E shall allocate and recover costs of the contract that are eligible for net capacity cost recovery as was authorized in Section 13.1.2.2 and in AL-3922-E.
PG&E's request to recover costs in accordance with Section 13.1.2.2 of the Term Sheet and AL-3922-E is consistent with the directives of the QF/CHP Settlement.
Cost reasonableness
Agnews' new Utility Prescheduled Facility Replacement PPA provides benefits over the ISO4 PPA. As the Scheduling Coordinator of the facility, PG&E will be able to manage its operations and will receive day-ahead information on the availability of the Facility. Seller is required to notify PG&E of available capacity, comply with forced outage and other reporting obligations, and comply with CAISO tariff and interconnection provisions it otherwise would not be required to under the Existing PPA. Agnews must comply with more stringent summer and non-summer month availability requirements and in the event of non-compliance will receive discounted payments. Agnews' conversion to a utility dispatchable generator will allow PG&E to ensure the economic delivery of electricity to the CAISO markets.
The Replacement PPA stipulates that Agnews forgo the existing PURPA "must-take" requirement. Under the Replacement PPA, Agnews will receive monthly payments from PG&E based on firm capacity, fixed and variable operations and maintenance, and other payments based on the fulfillment of certain precedent conditions. The Replacement PPA also stipulates that Seller will guarantee a range of heat rates within which the facility will operate, subject to changes based on a projection of efficiency degradation and planned maintenance activities.
PG&E will receive exclusive right to the Resource Adequacy credits from the facility's 28 MW contract capacity. This right to RA credits is, as noted in the previous section, subject to allocation to the non-IOU LSEs in proportion to the LSEs' contribution to the net capacity cost of the contract as required by Section 13.1.2.2 of the Term Sheet. PG&E is responsible for Seller's greenhouse gas costs incurred under the AB 32 cap and trade program, which are based on the actual performance of the facility.
Ratepayers benefit from the negotiation of this Replacement PPA directly as a result of the decreased price for firm capacity payment to Seller that would otherwise have continued for the remainder of the contract. In addition, the elimination of the PURPA requirement to purchase Seller's electricity at SRACVAR provides PG&E the ability to determine Agnews' operations when necessary and economic for their portfolio. Whereas previously PG&E was obliged to pay for energy even when the cost, set at SRACVAR, exceeded the benefit, in terms of the market price of energy, under the Replacement PPA the facility will only run when it is economic to do so. In total, the Replacement PPA results in a net decrease in payments to Seller compared to the continuation of the ISO4 for the remainder of the contract.
Additional information on the contract cost is provided in Confidential Appendix A.
The terms of the Replacement PPA for conversion to a Utility Prescheduled Facility, including lower firm capacity payments and significantly decreased operations, overall provide net benefits to ratepayers in comparison to the existing Interim Standard Offer 4 PPA.
Project Viability
Agnews is an existing qualifying facility and has operated since 1990. As an existing QF, the project faces minimal project development risk. The conversion to a UPF is effective the first of the month following the Commission's approval of the Replacement PPA and other precedent conditions, after which PG&E will receive the right to schedule the operations of Agnews.
Agnews is an existing CHP facility and therefore is a viable project.
Consistency with the Emissions Performance Standard
California Public Utilities Code Sections 8340 and 8341 require that the Commission consider emissions costs associated with new long-term (five years or greater) power contracts procured on behalf of California ratepayers.
D.07-01-039 adopted an interim Emissions Performance Standard ("EPS") that establishes an emission rate for obligated facilities to levels no greater than the greenhouse gas emissions of a combined-cycle gas turbine power plant.
Pursuant to Sections 4.10.4.1 of the CHP Program Settlement Term Sheet, PPAs greater than five years that are submitted to the CPUC in a Tier 2 or Tier 3 advice letter must be compliant with the EPS.
The EPS applies to all energy contracts that are at least five years in duration for baseload generation, which is defined as a power plant that is designed and intended to provide electricity at an annualized plant capacity factor greater than 60 percent.
Under the Replacement PPA, the Agnews facility is converting to a UPF until April 2021. The terms of the UPF Replacement PPA enable PG&E to limit the facility's electricity deliveries as a schedulable resource. Because PG&E estimates that the operational schedule will limit the annualized plant capacity factor to significantly less than 60 percent, the EPS does not apply.
The Replacement PPA is not subject to the EPS under D.07-01-039 as the Facility will be operating with an annualized plant capacity factor of less than 60 percent.
Consistent with D.02-08-071, PG&E's Procurement Review Group ("PRG") was notified of the Replacement PPA.
PG&E's PRG consists of representatives from: the Division of Ratepayer Advocates (DRA), The Utility Reform Network (TURN), California Department of Water Resources (CDWR), Coalition of California Utility Employees (CUE), PG&E's Independent Evaluators, and the Commission's Energy and Legal Divisions.
Negotiations on the Replacement PPA between Seller and PG&E began in May 2011 and were completed in June 2011. PG&E provided a description of the Replacement PPA to its PRG on July 12, 2011.
PG&E has complied with the Commission's rules for involving the PRG.
COMMENTS
Public Utilities Code section 311(g)(1) provides that this resolution must be served on all parties and subject to at least 30 days public review and comment prior to a vote of the Commission. Section 311(g)(2) provides that this 30-day period may be reduced or waived upon the stipulation of all parties in the proceeding.
The 30-day comment period for the draft of this resolution was neither waived or reduced. Accordingly, this draft resolution was mailed to parties for comments, and will be placed on the Commission's agenda no earlier than 30 days from today.
FINDINGS AND CONCLUSIONS
1. Pursuant to the QF/CHP Settlement, PG&E is permitted to enter a bilaterally-negotiated Utility Prescheduled Facility power purchase agreement ("Replacement PPA") with O.L.S. Energy-Agnews ("Seller") because the Agnews facility meets the efficiency requirements under the Public Utility Regulatory Policies Act of 1978 ("PURPA").
2. Pursuant to the QF/CHP Settlement, Seller's contract capacity under the Replacement PPA does not count toward PG&E's MW procurement target because Seller's existing QF ISO4 PPA expires after the end of the Transition Period.
3. The facility's operations under the Replacement PPA as a Utility Prescheduled Facility will be significantly reduced compared to the prior two years of operations, yielding 14,635 MT of greenhouse gas emissions reductions under the accounting methodologies pursuant the Settlement that will be credited toward the QF/CHP Settlement greenhouse gas ("GHG") Emissions Reduction Target.
4. Resource adequacy ("RA") credits are to be allocated according to the share of the net capacity costs paid by load-serving entities ("LSEs") serving direct access ("DA") and community choice aggregation ("CCA") customers as prescribed in Section 13.1.2.2 of the QF/CHP Settlement Term Sheet.
5. RA credits are allocated in proportion to net capacity costs per Section 13.1.2.2 of the Term Sheet. It is not necessary to allocate GHG benefits because the IOUs have sole responsibility for the Emissions Reduction Target per Section 6.3.2 of the Term Sheet.
6. PG&E's request to recover costs in accordance with Section 13.1.2.2 of the Term Sheet and AL-3922-E is consistent with the directives of the QF/CHP Settlement.
7. The terms of the Replacement PPA for conversion to a Utility Prescheduled Facility, including lower firm capacity payments and significantly decreased operations, overall provide net benefits to ratepayers in comparison to the existing Interim Standard Offer 4 PPA.
8. Agnews is an existing CHP facility and therefore is a viable project.
9. The Replacement PPA is not subject to the EPS under D.07-01-039 as the Facility will be operating with an annualized plant capacity factor of less than 60 percent.
10. PG&E has complied with the Commission's rules for involving the PRG.
THEREFORE IT IS ORDERED THAT:
1. The request of the Pacific Gas & Electric Company in Advice Letter AL 4010-E for the Commission to approve without modification the Replacement Power Purchase Agreement ("Replacement PPA") with O.L.S. Energy-Agnews as just and reasonable is approved.
2. PG&E is authorized to recover the costs associated with the Replacement PPA through the cost recovery mechanisms set forth in D.10-12-035 (as modified by D.11-07-010), Section 13.1.2.2 of the QF/CHP Settlement Term Sheet, and PG&E's Advice Letter 3922-E.
3. All greenhouse gas ("GHG") reductions associated with the Replacement PPA count towards the GHG Emissions Reduction target included in the QF/CHP Settlement.
4. Because the expected annualized plant capacity factor of the Facility under the Replacement PPA is below 60%, the Commission finds that the facility is not subject to the GHG Emissions Performance Standard adopted in
D.07-01-039.
This Resolution is effective today.
I certify that the foregoing resolution was duly introduced, passed and adopted at a conference of the Public Utilities Commission of the State of California held on September 13, 2012; the following Commissioners voting favorably thereon:
_______________
Paul Clanon
Executive Director
Confidential Appendix A
Summary and Analysis of Agnews
Replacement Power Purchase Agreement
[REDACTED]
STATE OF CALIFORNIA Edmund G. Brown Jr., Governor
PUBLIC UTILITIES COMMISSION
505 VAN NESS AVENUE
SAN FRANCISCO, CA 94102-3298
August 10, 2012 I.D. #11526 Draft Resolution E-4494 September 13, 2012 Commission Meeting
TO: PARTIES TO DRAFT RESOLUTION E-4494
Enclosed is Draft Resolution E-4494 of the Energy Division addressing Pacific Gas & Electric Company's advice letter (AL) 4010-E as supplemented by AL 4010-E-A. It will be on the agenda at the next Commission meeting that is at least 30 days from the date of this letter, which is expected to be September 13, 2012. The Commission may then vote on this Draft Resolution or it may postpone a vote until later.
When the Commission votes on a Draft Resolution, it may adopt all or part of it as written, amend, modify or set it aside and prepare a different Resolution. Only when the Commission acts does the Resolution become binding on the parties.
Parties may submit comments on the Draft Resolution no later than 20 days of this draft, Thursday, August 30, 2012.
An original and two copies of the comments, with a certificate of service, should be submitted to:
ED Tariff Unit
Energy Division
California Public Utilities Commission
505 Van Ness Avenue
San Francisco, CA 94102
A copy of the comments should be submitted to:
Noel Crisostomo
Energy Division
Andy Schwartz
Energy Division
Those submitting comments must serve a copy of their comments on 1) the entire service list attached to the Draft Resolution, 2) all Commissioners, and 3) the Director of the Energy Division, the Chief Administrative Law Judge and the General Counsel, on the same date that the comments are submitted to the Energy Division.
Comments may be submitted electronically.
Comments shall be limited to five pages in length plus a subject index listing the recommended changes to the Draft Resolution and an appendix setting forth the proposed findings and ordering paragraphs.
Comments shall focus on factual, legal or technical errors in the proposed Draft Resolution. Comments that merely reargue positions taken in the advice letter or protests will be accorded no weight and are not to be submitted.
/s/ Andy Schwartz
Andy Schwartz
Project and Program Supervisor
Energy Division
Enclosure:
Certificate of Service
cc: Brian Cherry, PG&E
Joseph Abhulimen, DRA/CPUC
Elizabeth Rasmussen, MEA/AREM/DACC/EUF
Jordis Weaver, MEA/AREM/DACC/EUF
Sarah Gardner, MEA/AREM
Dan Douglass, MEA/AREM
Michael Boyd, CARE
CERTIFICATE OF SERVICE
I certify that I have by mail this day served a true copy of Draft Resolution
E-4494 on all parties in these filings or their attorneys as shown on the attached list.
Dated August 10, 2012 at San Francisco, California.
/s/ _Julia Tom___________
Julia Tom
NOTICE
Parties should notify the Energy Division, Public Utilities
Commission, 505 Van Ness Avenue, Room 4002
San Francisco, CA 94102, of any change of address to
insure that they continue to receive documents. You
must indicate the Resolution number on the service list
on which your name appears.
1 PG&E's Historical variable SRAC prices are listed at http://www.pge.com/includes/docs/word_xls/b2b/qualifyingfacilities/prices/Historical%20Variable%20Energy.xls
2 D.10-12-035 at 45-46.
3 In D.11-06-029, the Commission approved a contract amendment for PG&E's Greenleaf 1 facility and found that the amendment provided better operational benefits than could have been achieved under the existing ISO4 contract.
4 Protest of Marin Energy Authority and Alliance for Retail Energy Markets to PG&E Advice Letter 4010-E, March 29, 2012. Page 1.
5 D.10-12-035. Ordering Paragraph 5.
6 Protest of Marin Energy Authority and Alliance for Retail Energy Markets to PG&E Advice Letter 4010-E, March 29, 2012. Page 2.
7 Protest of Marin Energy Authority, Alliance for Retail Energy Markets, Direct Access Customer Coalition, and the Energy Users Forum to PG&E Advice Letter 4010-E-A.
May 14, 2012. Page 1.
8 Ibid. Page 2.
9 Protest of Californians for Renewable Energy to PG&E Advice Letter 4010-E-A. May 14, 2012. Page 1.
10 PG&E Advice Letter 4010-E-A. Page 3.
11 Ibid.
12 Per Term Sheet 4.1.2: Use of an IE shall be required for any negotiations between an IOU and its affiliate and may be used, at the election of either the buyer or the Seller, in other negotiations.
13 18 C.F.R. §292.205 requires an Operating Standard of ≥ 5% and an Efficiency Standard of
≥ 45% for topping cycle CHP facilities.
14 CPUC General Order 96-B, Rule 7.5.1. Supplements.
15 PG&E Advice Letter 3922-E http://www.pge.com/nots/rates/tariffs/tm2/pdf/ELEC_3922-E.pdf
16 Per Term Sheet Section 13.1.2.2
17 Per Term Sheet 16.3.1, the obligation to meet CARB's MW or GHG Target is subject to change in a CPUC LTPP or other pertinent proceeding.
