IX. Assignment of Proceeding
Carl Wood and Geoffrey Brown are the Assigned Commissioners and Thomas Pulsifer is the assigned ALJ in this proceeding.
1. D.02-03-055 determined that, as a condition of retaining the DA suspension as effective after September 20, 2001, a surcharge must be imposed on DA customers sufficient to prevent cost shifting to bundled customers as a result of DA migration between July 1 and September 20, 2001.
2. By ALJ ruling dated March 29, 2002, the scope of this proceeding was expanded to consider cost responsibility surcharges for "Departing Load" in order to prevent cost shifting to bundled customers.
3. Pursuant to Rule 51.1, a joint motion was filed for approval of a Settlement Agreement proposing disposition of various contested issues in this proceeding relating to cost responsibility surcharges applicable to Departing Load served by Customer Generation.
4. The Settlement Agreement is offered as an integrated document, and not as a collection of separate agreements on discrete issues. Each party has reserved the right to withdraw support of the Agreement if the Commission makes modifications or makes approval conditional upon modifications.
5. In October 2002, hearings were held on the issues underlying the Settlement Agreement. Parties also filed comments on the Settlement Agreement.
6. The CRS elements that are at issue for Customer Generation include DWR bond charges and ongoing power charges, "tail" CTC charges, and the historic procurement charge for SCE.
7. A number of parties raised concerns that adoption of a CRS on CG departing load will create economic disincentives to develop various forms of alternative generation, as well as be contrary to Legislative and Commission policy.
8. The Legislature has recently enacted numerous statues codifying its policy preferences for customer generation, including AB 29, SB 28X, AB 58, SB 1038, and SB 2228.
9. The Commission (through the utilities) and the CEC, under Legislative direction, offer financial incentives for installation of certain forms of environmentally-preferable customer generation.
10. The provisions of the net metering program embodied in Public Utilities Code Section 2827 prohibiting a requirement for a second meter to measure gross electricity generation make it impossible to apply cost responsibility surcharges to the gross electricity usage of net metered customers. All other tariff components are applicable to the net consumption of such customers, which therefore assure a reasonable contribution to DWR costs.
11. The provisions for ongoing DWR power charges under the Settlement Agreement provides a reasonable recognition of forecasted Customer Generation that was taken into account in determining contractual commitments for the procurement of power by DWR during 2001.
12. The MW caps set forth in the Settlement form a logical basis for determining the exclusion of going-forward DWR costs applicable to Customer Generation.
13. DWR began procuring electricity on behalf of retail end use customers in the service territories of the California utilities: for PG&E and SCE on January 17, 2001, and for SDG&E on February 7, 2001.
14. AB 1X provides for DWR to collect revenues by applying charges to the electricity that it purchased on behalf of retail customers, as a direct obligation of DWR.
15. AB 117 requires that "each retail end-use customer that has purchased power from an electrical corporation on or after February 1, 2001, should bear a fair share of the DWR's electricity purchase costs, as well as electricity purchase contract obligations incurred..." but leaves the determination of "fair share" up to the discretion of this Commission.
16. Any customer generation departing load that departed prior to February 1, 2001 is exempt from any DWR bond charges or ongoing power charges.
17. Providing exceptions to some small and environmentally-preferable customer generation, as defined in this decision, that departed from utility service on or after February 1, 2001 from having to pay DWR bond charges and ongoing power charges is consistent with applicable provisions of AB 117 and AB 1X and the legislative policy directives in recently enacted statutes as specified in this decision.
18. The Commission has discretion to apply differentially a "tail" CTC, covering those cost categories defined in Public Utilities Code Section 367 (a)(1)-(6), consistent with Commission and legislative mandates for customers to bear their share of responsibility for the above-market component of utility purchased power and QF contracts.
19. The Commission has the discretion to apply a Historic Procurement Charge from Customer Generation differentially in the SCE service territory, covering a share of the costs authorized in D.02-07-032, as modified by
D.03-02-035, and calculated as described in the text of this decision.
20. Granting exceptions to certain portions of the CRS for customer generation up to 3000 MW will not result in any cost-shifting among customers, since costs for those MW were not incurred by DWR.
1. The Commission has broad authority under general provisions of Public Utilities Code Section 701 to regulate public utilities and to "do all things...which are necessary and convenient in the exercise of such power and jurisdiction."
2. The Commission has authority under AB 117 and AB 1X to impose CRS on Customer Generation Departing Load to recover DWR-related costs and to determine each customer's fair share of those costs.
3. Pursuant to AB 117, as codified in Public Utilities Code Section 366.2(d), AB 1X and Public Utilities Code Sections 701 and 366(d), as well as the provisions of D.02-02-051, the Commission has legal authority to apply DWR Bond Charges on Departing Load Customer Generation that departed from utility service after DWR began procuring power on behalf of retail utility customers.
4. Under Rule 51.1(e), the Commission must find a settlement, whether contested or uncontested, to be "reasonable in light of the whole record, consistent with the law, and in the public interest" before it may approve a settlement.
5. As prescribed in D.01-12-018, when a contested settlement is presented and where hearings have been held on contested issues, the Commission is free to consider such settlements under Rule 51.1(e) or as joint recommendations that may or may not be supported by record evidence.
6. As discussed in this decision, we reject the Settlement Agreement as inconsistent with Legislative and Commission policy, and contrary to the public interest, primarily due to its treatment of small and environmentally-preferable customer generation departing load.
7. It is reasonable and consistent with Legislative and Commission policy to provide an exception for customer generation under 1 MW in size and eligible for either net metering, CPUC self-generation funding, or CEC financial incentives, from all CRS cost components. It is also reasonable to reevaluate this size cap within three years of the date of this decision, to take into account developments in technology and economies of scale.
8. The CPUC should revisit the eligibility criteria for its self-generation incentive program in our new distributed generation rulemaking, to ensure that our efficiency standards are continuously improved.
9. It is reasonable to permit eligible customer generation under Public Utilities Code Section 353.2 not to pay DWR ongoing power charges, and HPC, up to a MW cap as established in this decision.
10. It is reasonable and consistent with AB 1X and AB 117 to adopt an exception so that all customer generation installed after February 1, 2001, up to a maximum MW cap, are not required to pay DWR ongoing power costs.
11. It is reasonable to set an absolute cap of 3,000 MW for customer generation involving DWR ongoing power charges in order to minimize risk of cost-shifting to bundled customers. It is also reasonable to reevaluate this cap within three years of the date of this decision, or when the amount of installed customer generation reaches 1000 MW, whichever occurs first.
12. It is reasonable to limit the amount of non-renewable customer generation over 1 MW in size to half of the total cap, or 1,500 MW, in order to ensure that renewable generation has an advantage. It is also reasonable to apply this cap three increments: 600 MW by the end of 2004, an additional 500 MW by July 1, 2008, and the final 400 MW thereafter.
13. It is reasonable to provide a set-aside from the caps for UC/CSU as follows: 10 MW before the end of 2004, an additional 80 MW by the end of 2008, and an additional 75 MW thereafter.
14. If a Customer Generation unit serving new or incremental load can pass the physical test adopted in D.98-12-067, showing that the load is being met through a direct transaction does not otherwise require the use of transmission or distribution facilities owned by the utility, that load will not be considered as departing, and will not be obligated to pay a CRS in accordance with Public Utilities Code Section 369.
15. In the passage of AB 2228, the Legislature specifically considered and elected to make an exception for biodigester projects from any net metering or other charges for departing the utility system. Accordingly such biodigester projects are not required to pay CRS.
16. The CEC is the logical entity to determine eligibility for qualifying for the exceptions to paying the CRS as specified in this order, with additional assistance from and information provided by the utilities.
17. It is reasonable to count systems under 1 MW toward the cap on exceptions, but to automatically grant the exceptions authorized in this order.
18. This decision construes, applies, implements, and interprets the provisions of AB 1X (Chapter 4 of the Statutes of 2001-02 First Extraordinary Session). Therefore, Public Utilities Code Section 1731(c) (applications for rehearing are due within 10 days after the date of issuance of the order or decision) and Public Utilities Code Section 1768 (procedures applicable to judicial review) are applicable.
IT IS ORDERED that:
1. This order shall apply to the service territories of Southern California Edison (SCE), Pacific Gas and Electric Company (PG&E), and San Diego Gas & Electric Company (SDG&E).
2. The Settlement Agreement is rejected as inconsistent with Legislative and Commission policy and not in the public interest.
3. A mechanism for the determination of a Cost Responsibility Surcharge (CRS) applicable to Departing Load served by Customer Generation is hereby adopted, as set forth below.
4. Departing load that began to receive service from customer generation on or before February 1, 2001 except during any period and to the extent that the departing load thereafter receives bundled or direct access service, shall be exempt from all DWR bond charges and ongoing power charges.
5. Customer generation, not otherwise included in Ordering Paragraph 4, that commenced commercial operation on or before January 1, 2002, 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, 2003 are not required to pay DWR ongoing power charges.
6. Biogas digester customer generation eligible under AB 2228 are not required to pay any CRS charges.
7. Customer generation departing load that is under 1 MW in size and eligible for net metering pay DWR charges based on their net energy consumption and are not required to pay any of the other CRS components adopted in this decision. Customer generation departing load that is under 1 MW in size and eligible for financial incentives from the CPUC's self-generation program or from the CEC, are not required to pay any CRS, including the DWR bond charge, DWR ongoing power charges, any SCE or potential other utility historic procurement charges (HPC), and the "tail" competition transition charge (CTC).
8. Customer generation departing load that is over 1 MW in size but that otherwise meets all criteria in Public Utilities Code Section 353.2 as "ultra-clean and low-emissions", shall pay the DWR bond charge and tail CTC (if not otherwise excepted by Public Utilities Code Section 372 and/or 374), but are not required to pay DWR ongoing power charges or any HPC, except as provided in Ordering Paragraph 10 below.
9. Customer generation departing load other than that defined in Ordering Paragraphs 4-8 above are not required to pay DWR ongoing power charges, except as provided in Ordering Paragraph 10 below.
10. Exceptions adopted in today's decision as provided in Ordering Paragraphs 8 and 9, shall expire when the cumulative total of customer generation departing load eligible under those Ordering Paragraphs exceeds 3,000 MW, as determined on a first-come, first-served basis by the California Energy Commission. The amount of customer generation exceptions defined in Ordering Paragraph 9 shall be limited to 1,500 MW with no more than 600 MW by the end of 2004, an additional 500 MW by July 1, 2008, and a final 400 MW thereafter.
11. UC/CSU shall be granted a set-aside within the caps discussed in Ordering Paragraph 10 as follows: 10 MW by the end of 2004, an additional 80 MW by the end of 2008, and an additional 75 MW thereafter.
12. The MW caps, as defined in Ordering Paragraph 10, shall be reevaluated by this Commission within three years of the date of this decision, or when the amount of installed customer generation in Ordering Paragraphs 7, 8, and 9 reaches 1000 MW, whichever occurs first. At that time, we will also reevaluate the 1 MW size limit defined in Ordering Paragraph 7, to take into account developments in technology and economies of scale.
13. To the extent that Departing Load customers are responsible for paying a DWR ongoing power charge after reaching the MW cap described in Ordering Paragraph 10, such charge shall be set equal to the corresponding cents per kilowatt-hour (kWh) surcharge component in effect on the date of departure as determined pursuant to the Direct Access (DA) phase of R.02-01-011 and related or successor proceedings.
14. SCE is authorized to recover HPC from departing load not otherwise excepted in this order, and calculated as defined in the text of this order.
15. "Tail" CTC will be defined and calculated consistent with the text of this order. Departing load exempt from CTC pursuant to any statute, including without limitation Public Utilities Code Sections 372 and 374, as the legislation existed as of the adoption of this order, as well as additional exceptions adopted in this order, shall not be required to pay "tail" CTC.
16. The recovery of the CRS element relating to recovery of DWR bond charges shall be implemented once this decision becomes final and unappealable. During the interim, the bond charge component shall be tracked through the subaccount process established in D.02-10-063 and D.02-11-074.
17. PG&E, SCE, and SDG&E, respectively, are hereby directed to file necessary tariff revisions to incorporate and implement the other surcharge elements adopted in this order. The utilities shall make compliance advice letter filings within ten days of the effectiveness of this order, to implement the CRS element, other than bond charges, as adopted in this order. The advice letters shall be effective on filing, subject to post-filing review by the Energy Division.
18. The utilities shall report to the Energy Division and the CEC, on a quarterly basis, the amount of customer generation installed under the provisions of this order.
This order is effective today.
Dated April 3, 2003, at San Francisco, California.
MICHAEL R. PEEVEY
President
GEOFFREY F. BROWN
SUSAN P. KENNEDY
Commissioners
I will file a dissent.
LORETTA M. LYNCH
Commissioner
I will file a dissent.
CARL W. WOOD
Commissioner
