ATTACHMENT A:
SETTLEMENT AGREEMENT
137768
BEFORE THE PUBLIC UTILITIES COMMISSION
OF THE
STATE OF CALIFORNIA
|
Order Instituting Rulemaking Regarding the Implementation of the Suspension of Direct Access Pursuant to Assembly Bill 1X and Decision 01-09-060. |
Rulemaking 02-01-011 (Filed January 9, 2002) |
SETTLEMENT AGREEMENT
This Settlement Agreement is entered into by and among Arden Realty, Inc., Building Owners and Managers Association of California, California Energy Commission, California Independent Petroleum Association, Clarus Energy Corporation, Cummins West, Inc., Energy Producers and Users Coalition,1 Goodrich Aerostructures Group, Hawthorne Power Systems, Hess Microgen, International Power Technology, Kern Oil and Refining Company, Kimberly Clark Corporation, next>edge, Inc., Nextek Power Systems, Inc., Pacific Gas and Electric Company, Onsite Energy Corporation, Paramount Petroleum Corporation, RealEnergy, Inc., Southern California Edison Company, The Utility Reform Network, University of California/California State University and USS-POSCO Industries this 15th day of October, 2002, and any other parties as join at a later date in this Settlement Agreement.
1. Background
In the summer of 2000, wholesale spot prices for electricity began to escalate to levels unanticipated by the State, the Utilities and Utility customers. The rising prices translated into dramatically increased power purchase costs and revenue undercollections for the Utilities. On January 17, 2001, the State, through the CDWR, assumed the responsibility for power procurement to meet the Utilities' net-short electricity requirements. The State further assisted by providing financing to bridge the gap between the power costs incurred by the CDWR, and the revenues received from the Utilities ratepayers. The CDWR during that time engaged in a long-term power procurement strategy, executing numerous short- and long-term contracts with suppliers for future electricity deliveries to the Utility customers.
The costs of the power purchased during the crisis, along with the costs of forward purchase obligations incurred by CDWR, must now be recovered. On March 29, 2002, the Administrative Law Judge issued a ruling in this proceeding, providing that R.02-01-011 would be the forum in which to assess whether and how CDWR costs or Utility past undercollections may be recovered from Departing Load customers. This Settlement Agreement represents an effort by the Parties to resolve these issues in a manner that fairly balances the legal and policy positions presented by the Parties to date in legal briefing and testimony.
2. Summary of Agreement
Departing Load served by Customer Generation shall pay a share of past and future costs incurred by the CDWR and the Utilities. A summary of operative terms of the Settlement Agreement is as follows:
2.1. Departing Load shall pay a charge for CDWR Historical Costs equal to 72 percent of the CDWR Bond Charge imposed on bundled customers in any year but shall not share with bundled customers in the disposition of certain reserve and deposit accounts funded through the CDWR Bond Charge. Operative provisions are found in Sections 5 and 10 of this Settlement Agreement.
2.2. Departing Load shall pay a charge for CDWR Forward Costs equal to the component of cost responsibility surcharges adopted for direct access customers in this proceeding to recover the cost of CDWR purchases on or after January 1, 2003, provided that the charge would not be applied to:
2.2.1. Existing Load Served by Customer Generation: Departing Load that departed Utility service on or before January 17, 2001;
2.2.2. "Grandfathered" Departing Load: Departing Load served by Customer Generation that becomes operational on or before January 1, 2003 or that submitted its CEQA lead-agency application on or before August 29, 2001 and becomes operational on or before January 1, 2004;
2.2.3. "Qualifying" New Departing Load: Departing Load that is not "existing" or "grandfathered" Departing Load but falls within an annual, utility-specific megawatt cap. The megawatt cap reflects the amount of reduction for Customer Generation in the forecast relied upon by the CDWR in negotiating forward purchase obligations. Operative provisions are found in Sections 6 and 10 of this Settlement.
2.3. Departing Load on the SCE system receiving bundled service prior to departure shall pay a Historical Procurement Charge based on a customer-specific analysis of the customer's contribution to the Utility shortfall and its repayment of the shortfall amount. Departing Load on the SCE system receiving direct access service prior to departure shall pay its Historical Procurement Charge obligation as adopted in Decision No. 02-07-032 or subsequent decisions. Operative provisions are found in ¶7.1 of this Settlement Agreement.
2.4. Resolution of the question of whether and the extent to which Departing Load should pay a Historical Undercollection Charge on the PG&E system is deferred to a later proceeding, as detailed in ¶7.2 of this Settlement Agreement.
2.5. Departing Load not exempt pursuant to any statute, including without limitation Public Utilities Code §§372 and 374, as the statute existed on the execution date of this Settlement Agreement shall pay a "tail" Competition Transition Charge. Operative provisions are found in ¶8.3 of this Settlement Agreement.
2.6. The applicability and determination of existing Departing Load charges, including Public Purpose Program charges, Nuclear Decommissioning charges and Fixed Transition Cost Amounts, are unchanged and remain consistent with existing statutes.
3. Definitions
For purposes of this Settlement Agreement only, the following terms shall be defined as follows:
3.1. "CDWR" means the California Department of Water Resources.
3.2. "CDWR Bond Charge" means the charge implemented by the Commission to recover from Utility bundled ratepayers Bond-Related Costs as that term is defined in Decision 02-02-051.
3.3. "CDWR Bond Issue" means the issuance by CDWR of approximately $11.9 billion pursuant to Assembly Bill 1 (First Extraordinary Session) (the "Act") for the purposes of (1) paying for the cost of electric power procured by CDWR pursuant to the Act and the Governor's Emergency Proclamation dated January 17, 2001; (2) reimbursing the General Fund for advances; and (3) establishing and maintaining reserves in connection with the bonds.
3.4. "CDWR Forward Costs" include the sum of (1) CDWR's procurement costs between September 21, 2001 and December 31, 2002, and (2) CDWR's post-January 1, 2003 procurement costs incurred by the CDWR.
3.5. "CDWR Historical Shortfall" means the approximately $7.6 billion by which the costs of power purchased for and delivered to Utility customers from January 17, 2001 through September 30, 2001 exceeded the revenues remitted by the Utilities on behalf of ratepayers to CDWR for these purchases.
3.6. "CDWR Historical Costs" mean the costs associated with CDWR's revenue requirement developed to recover the principal, financing and other costs associated with the CDWR Bond Issue.
3.7. "CDWR Power Charge" means the charge implemented by the Commission to recover from Utility bundled ratepayers CDWR's then-current costs of power purchased by CDWR and delivered to Utility customers pursuant to Decision 02-02-051.
3.8. "CDWR Shortfall Charge" means a charge implemented to recover the costs of the CDWR Historical Shortfall consistent with §5 of this Agreement.
3.9. "CEQA" means the California Environmental Quality Act (Division 13 (commencing with Section 21000) of the Public Resources Code).
3.10. "Commission" means the California Public Utilities Commission or its successor agency.
3.11. "Customer Generation" means cogeneration, renewable technologies or any other type of generation that (a) is dedicated wholly or in part to serve a specific customer's load; and (b) relies on non-Utility or dedicated Utility distribution wires rather than the Utility grid, to serve the customer, the customer's affiliates and/or tenants, and/or not more than two other persons or corporations, provided that those two persons or corporations are located on site or adjacent to the real property on which the generator is located.
3.12. "Departing Load" means that portion of the Utility customer's electric load2 for which the customer: (a) discontinues or reduces its purchase of bundled or direct access service from the Utility; (b) purchases or consumes electricity supplied and delivered by Customer Generation to replace the Utility or direct access purchases; and (c) remains physically located at the same location or elsewhere within the Utility's service territory as of the date on which a Commission decision adopting this Settlement Agreement becomes effective.3 New customer load not meeting the definition in ¶3.12.2 shall be deemed Departing Load under this definition. Reduction in load qualifies as Departing Load only to the extent that such load is subsequently served with electricity from a source other than the Utility. For purposes of this Settlement Agreement, Departing Load shall not include, and the Departing Load charges described in this Settlement Agreement shall not apply to:
3.12.1. Changes in usage occurring in the normal course of business resulting from changes in business cycles, termination of operations, departure from the utility service territory, weather, reduced production, modifications to production equipment or operations, changes in production or manufacturing processes, fuel switching, enhancement or increased efficiency of equipment or performance of existing Customer Generation equipment, replacement of existing Customer Generation equipment with new power generation equipment of similar size, installation of demand-side management equipment or facilities, energy conservation efforts, or other similar factors.
3.12.2. New customer load or incremental load of an existing customer where the load is being met through a direct transaction with Customer Generation and the transaction does not otherwise require the use of transmission or distribution facilities owned by the Utility.
3.12.3. Load temporarily taking service from a back-up generation unit during emergency conditions called by the Utility, the California Independent System Operator or any successor system operator.
.
3.13. "Energy Commission" means the California Energy Resources Conservation and Development Commission.
3.14. "Historical Procurement Charge" means the charge implemented to recover SCE's past procurement cost undercollections from 2000-01 pursuant to the settlement agreement entered into by SCE and the Commission in Federal District Court Case No. 00-12056-RSWL or any other charge or charges implemented to recover the costs identified for recovery in that settlement.
3.15. "Historical Undercollection Charge" means any charge implemented to recover PG&E's shortfall in recovery of generation-related or commodity-related costs incurred from May 2000 to May 2001.
3.16. "PG&E" means Pacific Gas and Electric Company.
3.17. "Party" means an individual signatory to this Settlement Agreement, and "Parties" mean all signatories to this Settlement Agreement.
3.18. "SCE" means Southern California Edison Company.
3.19. "SDG&E" means San Diego Gas & Electric Company.
3.20. "UC/CSU" means the University of California and the California State University.
3.21. "Utility" means any one of the investor-owned utilities including Southern California Edison Company, Pacific Gas and Electric Company or San Diego Gas & Electric Company, as the case may require. "Utilities" mean all three investor-owned utilities.
4. Scope of Settlement Agreement
4.1. This Settlement Agreement resolves all issues among the Parties presented in this Phase of R.02-01-011 related to Departing Load served by Customer Generation unless otherwise expressly reserved herein. This Settlement Agreement does not address or seek to resolve issues in this Phase of R.02-01-011 related to any other type of departing load.
4.2. Nothing in this Settlement Agreement shall be deemed to constitute an admission or an acceptance by any Party of any fact, principle, or position contained herein, except to the extent that Parties, by signing this Settlement Agreement, acknowledge that they pledge support for Commission approval and subsequent implementation of all the provisions of the Settlement Agreement.
4.3. Nothing in this Settlement Agreement is intended to modify the existing rights or obligations of any Party to support or oppose any proposal for an exemption from CDWR Historical Costs, CDWR Forward Costs or Historical Procurement Charge for "eligible customer-generators", as defined in Public Utilities Code §2827(b)(2), or "eligible biogas digester customer-generator" as defined in Public Utilities Code §2827.9.
4.4. Nothing in this Settlement Agreement is intended to provide for or prohibit the disposition to Departing Load customers of any refunds obtained by the Utility or the State resulting directly or indirectly from San Diego Gas & Electric v. All Sellers et. al., FERC Docket No. EL00-95-045 and related subdockets.
5. Recovery of CDWR Historical Costs
5.1. Departing Load shall pay its share of CDWR Historical Costs as provided in this Section.
5.2. Applicability of Charges
5.2.1. Utility may not recover any portion of CDWR Historical Costs from Departing Load that began to receive service from Customer Generation on or before January 17, 2001 except to the extent such Departing Load thereafter receives bundled or direct access service.
5.2.2. Utility shall recover a share of CDWR Historical Costs from Departing Load that began to receive service from Customer Generation after January 17, 2001 in an amount equal to the CDWR Shortfall Charge in ¶5.3.
5.3. Calculation of CDWR Shortfall Charge
5.3.1. The CDWR Shortfall Charge shall equal a customer's share of $8,636,689,405, which represents the CDWR Historical Shortfall plus a proportionate share of related carrying costs, bond-related reserve accounts, and credit enhancement and issuance costs as calculated by CDWR in A.00-11-038 et al.
5.3.2. The CDWR Shortfall Charge shall be applicable to Departing Load in lieu of the CDWR Bond Charge and shall equal 72 percent of the CDWR Bond Charge imposed in any year on the Utilities' bundled service customers.
5.3.2.1. It is expected that the CDWR Bond Issue may result in bundled service customers being subject to a lesser CDWR Bond Charge in the last few years before the bonds are matured due to the use of the reserves not reflected in the $8,636,689,405 value described in ¶5.3.1 to retire the bonds. In that case, Departing Load shall continue to pay a CDWR Shortfall Charge equal to 72 percent of the CDWR Bond Charge that would have been imposed on bundled service customers if such reserves had not been used to retire the bonds.
5.3.2.2. Departing Load that later returns to bundled Utility service shall thereafter pay the CDWR Bond Charge and shall not receive any reduction in the CDWR Bond Charge resulting from the disposition of any reserve or deposit accounts not included in the calculation of the CDWR Shortfall Charge.
5.3.3. At the election of a Departing Load customer, a Departing Load customer may prepay its total CDWR Shortfall Charge in one lump sum. The prepaid amount shall be based upon the total calculated CDWR Shortfall Charge attributable to the customer, discounted for net present value.
6. Recovery of CDWR Forward Costs
6.1. Departing Load shall pay its share of CDWR Forward Costs as provided in this Section.
6.2. Applicability of Charge
6.2.1. Utility may not recover CDWR Forward Costs through any charge from Departing Load that began to receive service from Customer Generation on or before January 17, 2001 except during any period and to the extent that the Departing Load thereafter receives bundled or direct access service.
6.2.2. Except as provided in ¶6.3, Utility may not recover CDWR Forward Costs through a CDWR Power Charge or any other charge from Departing Load served by:
6.2.2.1. Customer Generation, not otherwise included in ¶6.2.1, that commenced commercial operation on or before January 1, 2003, or for which (a) an application for authority to construct was submitted to the lead agency under CEQA, not later than August 29, 2001 and (b) commercial operation commences not later than January 1, 2004; or
6.2.2.2. Customer Generation commencing operation on or after January 1, 2003, provided that the Departing Load falls within the cap for the calendar year in which the load departs, as specified below in Appendix A to this Settlement Agreement.
6.2.3. By the earlier of December 31, 2007, or upon reaching 90% of any Utility-specific annual cumulative cap referenced in ¶6.2.2.2 and specified in Appendix A to this Settlement Agreement or reaching 75% (2219) of the total cumulative 2,958 megawatt cap, the Commission shall seek information from interested parties, in conjunction with the Energy Commission, through a public process to timely determine whether changes in market conditions, the CDWR purchase portfolio or other conditions warrant an increase in or elimination of either or both the annual cumulative cap referenced in ¶6.2.2.2 and the total cumulative 2,958 megawatt cap.
6.2.4. The charges for a customer currently being served under a Self-Generation Deferral Agreement executed on or before July 1, 1994 shall be in accordance with the provisions of the Self-Generation Deferral Agreement and are not changed by this Settlement Agreement. Those charges shall remain in place for the duration of the Self-Generation Deferral Agreement. This provision does not determine how the revenues received under the Self-Generation Deferral Agreement will be accounted for by the Utility.
6.3. Determination of Charges
6.3.1. Utility shall recover from Departing Load that commences receiving service from Customer Generation after January 17, 2001, that does not qualify for exemption under ¶6.2, a CDWR Power Charge equal to the component of the cost recovery surcharge for recovery of ongoing CDWR costs in effect on the date of departure as determined in the direct access Phase of R. 02-01-011 and related or successor proceedings.
6.3.2. To the extent that the Commission determines that (a) any Commission-imposed direct access surcharge cap has resulted in an undercollection by the Utility of any applicable direct access nonbypassable charges, and (b) individual direct access customers shall remain responsible for a portion of the undercollection if they return to bundled utility service, then these direct access customers shall remain responsible for the same portion of the undercollection when they become Departing Load. At the discretion of the departing direct access customer, the undercollected amount shall be collected through either a lump sum or through monthly billings by the Utility with the total amount of each monthly charge for both direct access undercollections and any applicable Departing Load surcharges subject to the direct access surcharge cap.
7. Recovery of Utility Past Costs
7.1. SCE Historical Procurement Charge
7.1.1. Any recovery by SCE of past procurement cost undercollections from 2000-2001 through a Historical Procurement Charge is predicated on SCE's legal authority to recover such undercollections.
7.1.2. The Historical Procurement Charge responsibility for Departing Load that was receiving bundled service at the time of the departure shall be computed on a customer-specific basis using the methodology specified in Appendix B to this Settlement Agreement.
7.1.3. Departing Load that took direct access service at the time of the departure will continue to pay the Historical Procurement Charge amounts authorized in Decision No. 02-07-032, or successor decisions. Any direct access customer that had load departing after March 29, 2002 but prior to the implementation of this Settlement Agreement will be back-billed to July 27, 2002 at the 2.7¢/kWh rate and will be responsible for the charges adopted in Decision No. 02-07-032, or successor decisions, on a prospective basis.
7.2. PG&E Historical Undercollection Charge
7.2.1. Nothing in this Settlement Agreement shall limit or otherwise affect PG&E's or any other Party's right to propose a methodology for recovery of a Historical Undercollection Charge in any subsequent proceeding.
7.2.2. Nothing in this Settlement Agreement shall limit or otherwise affect the right of any other Party to oppose or support any proposal for recovery of a Historical Undercollection Charge in any subsequent proceeding.
7.2.3. The Parties acknowledge that the question of whether the Historical Undercollection Charge should be imposed on Departing Load has been raised and deferred in this proceeding.
8. "Tail" Competition Transition Charge
8.1. Departing Load exempt from competition transition charges pursuant to any statute, including without limitation Public Utilities Code §§372 and 374, as the statute existed on the execution date of this Settlement Agreement shall be exempt from the charge described in ¶8.3.
8.2. Departing Load not exempt as provided in ¶8.1 shall pay a "tail" Competition Transition Charge (CTC) charge calculated as specified in ¶8.3. If Departing Load commences payment of the charge specified in this ¶8.3 and thereafter qualifies for a statutory exemption under Public Utilities Code §372 as that statute existed on the execution date of this Settlement Agreement, the charge under ¶8.3 shall be discontinued effective on the date of qualification.
8.3. Utility costs eligible for consideration as ongoing or "tail" CTC are transition costs and will be limited to the category of costs as defined in Public Utilities Code §367(a), which are recoverable from all customers beyond December 31, 2001. The eligible cost categories are defined in §367(a)(1)-(6). The specific eligible cost categories covered by this Settlement Agreement are: (1) employee-related transition costs through December 31, 2006; (2) power purchase contract obligations for qualifying facilities and purchase power agreements signed before December 20, 1995; (3) nuclear incremental cost incentive plan for the San Onofre Nuclear Generating Station, provided that the recovery shall not extend beyond December 31, 2003.
8.3.1. The above-market portion or uneconomic portion of these contract costs will be calculated by comparing the weighted average cost of the qualifying facility and power purchase agreement portfolio, in $/MWh, against the benchmark adopted in the direct access phase of R. 02-01-011.
8.3.2. A revenue requirement will be derived for the qualifying facility and power purchase agreement portfolio by multiplying the uneconomic portion ($/MWh) times the forecast of MWh in the portfolio. A total "tail" CTC revenue requirement will be derived by adding the uneconomic portion of the qualifying facility and power purchase agreement revenue requirement to the employee-related transition costs and, in the case of SCE, any costs associated with the nuclear incremental cost incentive plan. The total "tail" CTC revenue requirement will be divided by the total applicable load to derive the CTC rate applicable to Departing Load. The total applicable load includes bundled, direct access, and Departing Load customers not otherwise exempted from ongoing CTC pursuant to statute.
8.3.3. Any other charge established in the direct access phase of R.02-01-011 to recover the cost of above-market utility retained generation assets or power purchase obligations shall not be applied to Departing Load.
9. Other Existing Nonbypassable Charges
9.1. Public Purpose Programs
9.1.1. Nothing in this Settlement Agreement shall modify the existing right of a Utility to recover from Departing Load a charge for public purpose program costs, provided that the charge is approved by the Commission.
9.1.2. Nothing in this Settlement Agreement shall preclude or restrict any Party from opposing the inclusion of any cost or category of costs in a nonbypassable public purpose program charge.
9.2. Nuclear Decommissioning
9.2.1. Nothing in this Settlement Agreement shall modify the existing right of a Utility to recover from Departing Load a charge to fund nuclear decommissioning, provided that the charge is approved by the Commission.
9.2.2. Nothing in this Settlement Agreement shall preclude or restrict any Party from opposing the inclusion of any cost or category of costs in a nonbypassable nuclear decommissioning charge.
9.3. Fixed Transition Cost Amount
9.3.1. Nothing in this Settlement Agreement shall modify the existing right of a Utility to recover from Departing Load a charge to the Fixed Transition Cost Amount as that term is defined in D.97-09-056 as of the date of this Settlement Agreement and provided that the charge is approved by the Commission.
9.3.2. Nothing in this Settlement Agreement shall preclude or restrict any Party from opposing any effort to increase the value, modify the terms of applicability or otherwise alter the application of the Fixed Transition Cost Amount.
10. Direct Access Load
10.1. If direct access customers or any particular category of direct access customer load (including any individual direct access customer or customers) is granted a partial or total exemption in the direct access phase of R.02-01-011 and related or successor proceedings from any charge addressed by this Settlement Agreement, and the exempted direct access load subsequently becomes Departing Load, the exemption shall continue to apply to the customer as Departing Load.
11. Support and Advocacy of Settlement Agreement
11.1. The Parties recognize that is it critical to the public interest and to the development of the State's electric generation market to resolve the issues presented in this Phase of R.02-01-011. The Parties thus jointly and individually agree to advocate in good faith and support the Commission's adoption of this Settlement Agreement without modification.
11.2. This Settlement Agreement is to be treated as a complete package and not as a collection of separate agreements on discrete issues. To accommodate the interests of different parties on diverse issues, the Parties acknowledge that changes, concessions, or compromises by a Party or Parties in one section of this Settlement Agreement resulted in changes, concessions, or compromises by other Parties in other sections. Consequently, the Parties Agree to oppose any modification of the Settlement Agreement not agreed to by all Parties.
11.3. Each Party reserves the right to withdraw its support of the Settlement Agreement if:
11.3.1. the Commission modifies the Settlement Agreement or makes its approval conditional on modifications; or
11.3.2. the Settlement Agreement is not adopted by the Commission within six (6) months after its submission.
APPENDIX A
CDWR Forward Costs
This Appendix establishes the procedure under which Departing Load will qualify for an exemption from CDWR Forward Costs pursuant to ¶6.2.2.2 of the Settlement Agreement.
1. Departing Load Cap
a. The statewide cap specified in ¶6.2.2.2 for new and additional Departing Load shall be allocated among the Utilities and made available for Customer Generation developed in their respective service territories. In addition, a specific allocation within the statewide MW cap shall be provided to UC/CSU. The statewide MW cap shall be allocated by first assigning the direct allocation to UC/CSU and then allocating the remaining MW cap among Utility service territories based on the Utility's proportionate share of load on the date of execution of this Settlement Agreement. The allocations among Utilities shall be as follows: SCE 44%; PG&E 44%; and SDG&E 12%.
b. If for any reason UC/CSU elects not to maintain its allocation separate from the remainder of the statewide cap, the UC/CSU allocation shall be allocated among the Utilities in the proportion specified in ¶1.a. of this Appendix.
2. Carryover of Unused Cap Amounts
a. If, on a utility-specific basis, actual Departing Load is less than the annual MW cap specified in ¶1 of this Appendix in any year, the difference between the annual MW cap specified in ¶1 and the actual Departing Load shall be carried forward and added to the MW cap for the following year or years.
b. If actual Departing Load for UC/CSU falls below the directly allocated cap in any year, the difference between the MW cap specified in ¶1 of this Appendix and the actual Departing Load for UC/CSU may be carried forward and added to the UC/CSU MW cap for the following year or years, provided that such carryover shall not exceed four (4) years. Any amount unused after the four-year carryover shall be returned to the statewide cap and allocated among the Utilities as specified in ¶1 and shall thereafter be available to all other Departing Load and, if unused in any particular year by other Departing Load, to UC/CSU under otherwise applicable provisions of this Settlement Agreement.
3. Departing Load commencing service from Customer Generation in a particular year that does not fall within the specified cap for that year shall be deemed the first Departing Load in the subsequent year to qualify for the exemption provided under ¶6.2.2.2. Departing Load that qualifies in a year for a partial exemption shall be granted a partial exemption in that year with the remainder of its load deemed the first Departing Load in the subsequent year to qualify for exemption.
4. The determination of whether a Departing Load falls within the annual cap shall be made on a first-come, first-served basis determined by the date of departure. The Energy Commission, as a Party to this Settlement Agreement, agrees to make this determination and shall:
a. Maintain for informational purposes a list of projects that intend to seek an exemption pursuant to ¶6.2.2.2, mandating that any project requesting eligibility be required:
i. to provide, upon submission of an application to the Energy Commission or other lead agency, the nameplate rating of the planned Customer Generation facility, the location of the facility, the technology type, the operating mode, the anticipated Departing Load level and the date on which the Departing Load plans to leave Utility service; and
ii. to update the information specified in ¶4.a.i of this Appendix as the project develops.
b. Identify, in coordination with the Utilities, the date on which any Departing Load listed pursuant to ¶4.a. of this Appendix departs Utility service. For purposes of this Section, the date of departure shall be the date on which the Departing Load first begins to receive deliveries of energy from Customer Generation, excluding receipt of deliveries during the testing process.
c. Provide an opportunity for public comment on the manner in which it will gather information, procedures for providing ongoing public notice of Customer Generation projects under development and procedures for granting exempt status prior to the implementation of its responsibilities under this Section, provided that the Energy Commission may after informal meetings with stakeholders commence a determination of eligibility for 2003 subject to modification upon completion of its public process.
d. At the proposal of a majority of stakeholders in the public process developed pursuant to ¶4.c. of this Appendix, modify the requirement herein that grants an exemption based on the date of departure to provide customers greater certainty in the development process regarding the right to claim an exemption. The Energy Commission's right to modify this process shall be limited to modifications concerning the timing of qualification for the exemption under ¶6.2.2 and shall not include any modification relating to other potential criteria for qualification.
APPENDIX B
SCE Historical Procurement Charge
1. The Historical Procurement Charge (HPC) responsibility for Departing Load receiving bundled service at the time of the departure shall be computed on a customer-specific basis as provided in this Appendix B.
2. The generation revenues received from the customer since May 2000 shall be compared with the procurement costs incurred to serve the customer's recorded kWh usage. The procurement costs prior to January 17, 2001 shall be based on the Schedule PX prices. The procurement costs from January 17, 2001 though August 31, 2001 shall be based on the amounts in SCE's Energy Cost Accounting system as reflected in Schedule PE. The procurement costs for September 2001 forward shall be equal to the generation-related recoverable costs incurred on behalf of bundled service customers and reflected in SCE's Settlement Rate Balancing Account on a cents per kilowatt-hour basis.
3. A customer-specific HPC cost responsibility will be determined by multiplying the customer's cumulative undercollection on August 31, 2002, by the ratio of the starting Procurement Related Obligations Account (PROACT) balance to the cumulative SCE procurement-related liabilities identified in the Settlement Agreement and verified by the Commission's Energy Division.
4. The customer's monthly contributions to the PROACT will be calculated by subtracting the customer's monthly generation-related costs from the customer's monthly generation-related revenues.
5. The customer's HPC obligation at the time of departure will be the difference between the customer-specific HPC cost responsibility at the beginning of the recovery period designated in the settlement agreement entered into by SCE and the Commission in Federal District Court Case No. 00-12056-RSWL, and the cumulative contributions to Surplus reflected in the PROACT, but never less than zero.
6. The customer's HPC obligation will be adjusted by the estimated proportion of energy to be served by Customer Generation to the amount of energy used prior to departure.
7. The customer's HPC obligation, at the customer's election, may be amortized and paid over a two-year period or in a single lump sum.
APPENDIX C
CDWR Historical Shortfall Determination,
August 6, 2002 Response to Data Request in A.00-11-038
Request No. 3
Please provide the fund levels to reflect a hypothetical bond issuance as of September 20. 2001 to recover the Department's undercollections from January 17, 2001 up to an including September 20, 2001.
Response No. 3
Based on the bond structure and interest rate assumptions used in the Department's June 14th Proposed Determination of Revenue Requirements, we have completed an analysis of a hypothetical $8,570,670/000 bond issue that would generate sufficient bond proceeds to:
· Finance the Department's undercollections through September 20, 2001;
· Finance the carrying costs of the undercollections from the date of cost incurrence through a hypothetical bond closing date of October 10, 2002
· Fund bond-related accounts at levels required to comply with the Bond Indenture
· Fund credit enhancement and issuance costs associated with the bonds
The sizing of the bond issue does not reflect the financing of any of the Departments power purchasing program reserves, the funding of which will be a condition of the rating agencies in order to secure the Department's desired level of investment grade ratings on the bonds.
The hypothetical sources and uses of the bond proceeds would be as follows:
SOURCES
Par Amount of Bonds $8,570,670,000
Bond Premium 66,019,405
Total Sources $8,636,689,405
USES
DWR Net Operating Loss Through 9-20-01 $7,053,208,281
General Fund Loan Interest to 10-10-02 523,766,709
Pro Rata Share of Interim Loan Interest 65,976,447
Debt Service Reserve Account 710,771,068
Bond Charge Collection Account 36,886,698
Bond Charge Payment Account 110,660,093
Cost of Issuance and Insurance 135,420,109
Total Uses $8,636,689,405
1 EPUC is an ad hoc group representing the electric end use and customer generation interests of the following companies: Aera Energy LLC, BP America Inc. (including Atlantic Richfield Company), Chevron U.S.A. Inc., Texaco Exploration and Production Inc., Equilon Enterprises LLC dba Shell Oil Products US, ExxonMobil Power and Gas Services Inc., on behalf of Exxon Mobil Corporation, THUMS Long Beach Company, Occidental Elk Hills, Inc., Tosco Corporation a Subsidiary of Phillips Petroleum Company, and Valero Refining Company - California. 2 Nothing in this Settlement Agreement shall affect the right of any Party to challenge the applicability of the definition of Departing Load to changes in the distribution of load among accounts at a customer site with multiple accounts load resulting from the reconfiguration of distribution facilities on the customer site, provided that the changes do not result in a discontinuance or reduction of service from the Utility at that location as defined in ¶3.12. 3 Nothing in this Settlement Agreement shall affect the right of any Party to make a proposal regarding or contest the applicability of any Departing Load charge to load that physically disconnects from the Utility grid.
