XII. Comments on the Alternate Decision
The Alternate Decision of Commissioner Wood was mailed to parties on February 7, 2002. Comments on this alternate decision were received on February 14, and have been incorporated herein, as appropriate.
1. AB1X, among other things, authorized DWR to purchase power on behalf of retail customers in the service territories of PG&E, SCE, and SDG&E.
2. AB1X authorized DWR to determine its revenue requirement sufficient to recover its procurement-related costs, and required the Commission to implement the cost recovery of DWR's revenue requirement.
3. Timely implementation of DWR's revenue requirement cost recovery is necessary to support the sale of bonds as prescribed under California Water Code Section 80130.
4. Up until the present time, DWR has been relying on General Fund appropriations, a $4.3 billion interim loan, and interim customer remittances as its funding sources pending implementation of this decision, and the sale of bonds, currently expected to occur in the second quarter of 2002.
5. In order to stay within the requirements of the Interim Loan DWR must determine its revenue requirement on the assumption that bonds are not issued, and to continue with this assumption until bonds actually are issued.
6. Notwithstanding the requirements of the Interim Loan, DWR has indicated that it expects bonds to be sold at the end of the second quarter of 2002.
7. DWR's revenue requirement represents the amounts to be collected from customers in the service territories of the three major electric utilities covering the 2001-2002 time period, after deducting the proceeds from interim loans.
8. DWR submitted an initial estimated revenue requirement on May 2, 2001, covering the 18 months from January 2001 to May 31, 2002.
9. DWR provided the Commission with an updated revenue requirement on July 23, 2001, covering 24 months ending December 2002, and provided further updates on August 7, October 19, and November 5, 2001.
10. Parties of record were provided notice and an opportunity to review DWR's revenue requirement submittals, to participate in technical workshops, and to file comments in response to DWR's submittals.
11. Parties expressed disagreement with various assumptions underlying DWR's revenue requirement, and contested DWR's representation that DWR's costs are "just and reasonable."
12. Based in part on parties comments, DWR sent a letter on February 21, 2002 concluding that adjustments could be made to its November 21, 2001 revenue requirement of up to $958 million.
13. DWR presents its revenue requirement on an aggregate basis for all three utilities, but defers to the Commission to determine and apply an allocation rationale for assigning the revenue requirement among customers in each service territory
14. In D.01-03-082, the Commission granted a surcharge increase of three-cents per kWh to be collected by SCE and PG&E, prescribing that a portion of that surcharge would be allocated to DWR upon receipt, analysis, and comment on DWR's revenue requirement.
15. In D.01-05-060, the Commission established an initial generation rate component of 6.5 cents/kWh for SDG&E.
16. In D.01-09-059, the Commission provided an interim rate increase to SDG&E to provide for remittance to DWR at 9.02 cents/kWh.
17. DWR forecasts a total revenue requirement, with allowable adjustments, to be collected of $9.045 billion, as set forth in Appendix A of this decision, covering the period January 17, 2001 through December 31, 2002.
18. DWR states that it has determined that its revenue requirement is just and reasonable based upon several factors including its competitive solicitation of bids, cost-based recovery, and the true-up provisions of forecast variances that will take place in future adjustments.
19. DWR's revenue requirement includes $5.284 billion in long-term power costs and $9.534 billion for short term purchases procured on behalf of customers in the service territories of the three major electric utilities.
20. DWR's revenue requirement includes $1.102 billion for ancillary service costs incurred by DWR on behalf of customers in the service territories of the three major electric utilities.
21. Pursuant to a FERC Order issued on November 7, 2001, the ISO sent $956 million in invoices to DWR for transactions with third party power suppliers for the period January 17 through July 31, 2001, on behalf of the noncreditworthy entities, PG&E and SCE.
22. The sales that DWR has presented in its revenue requirement model for purposes of computing charges for remittance purposes do not include sales to direct access customers.
23. It is reasonable to implement DWR cost recovery in the form of a discrete amount per kWh sold by DWR to facilitate segregation of DWR funds from those of the utility.
24. DWR's revenue requirement does not include a provision to account for franchise fees associated with power that it sells to utility customers.
25. Unresolved questions remain concerning the rights of municipalities to receive franchise fees on DWR power sales, and the respective obligations of DWR or investor-owned utilities to collect and remit franchise fees on DWR power sales.
26. DWR's revenue requirement is comprised of cost categories as authorized for recovery from utility ratepayers under AB1X, including the costs of long term and short term power contracts, ancillary services, administrative overhead, demand-side management, uncollectibles, and an allowance for leads or lags in cash receipts and disbursements.
27. DWR's revenue requirement is based on forecasts of various costs that may prove to be incorrect over time.
28. The allocation of DWR's revenue requirement as adopted in the ordering paragraphs below results in a revenue responsibility (in dollars and percentages) for PG&E's service territory in the amount of $ 4,507,238,000 (49.8%); for SCE's service territory of $3,553,841,000 (39.3%); and for SDG&E's service territory of $984,383,000 (10.9%).
29. The allocation of DWR's revenue requirement as adopted in the ordering paragraphs below results in a uniform cents per kWh charge applicable to billed revenues for PG&E's service territory in the amount of 9.295; for SCE's service territory in the amount of 9.744; and for SDG&E's service territory in the amount of 7.285.
30. The Commission has traditionally recognized the general principle that utility revenues should be allocated among customer classes on the basis of cost causality.
31. Allocation of the DWR revenue requirement is a novel application of the Commission's cost-based ratemaking since it involves allocation across different utility service territories, as opposed to the traditional practice of allocation among customer classes within a single utility service territory.
32. SCE's proposed mix of pro rata allocation of long-term procurement costs on a statewide basis along with utility-specific allocations of short-term costs is not inconsistent with cost-based ratemaking principles to the extent that no other objective measure exists to differentiate cost incurrence.
33. The allocation of revenue requirements based upon cost of service provides for an equitable and economically efficient matching of cost responsibility with service rendered.
34. The allocation approach proposed by SDG&E seeks to apply a cost-based approach by relating the costs of specific supply sources with specific utility service territories in geographical proximity.
35. The SDG&E allocation segregate energy sources solely on a geographic basis, with sources transmitted over facilities (a) north of Path 15 being allocated to PG&E customers, and (b) south of Path 15 being allocated to SCE and SDG&E customers.
36. SDG&E's allocation approach separately allocates both long term and short term energy purchases on a geographically differentiated basis.
37. SCE's allocation approach allocates only short term energy purchases on a regionally differentiated basis, but treats long term purchases as a homogeneous cost to be allocated on a pro rata statewide basis in relation to the net short position of each utility.
38. DWR's contracts have served to stabilize the power market, to the benefit of all California ratepayers.
39. Most of the DWR's costs and cash reserves related to its power purchase program are not specific to any single utility.
40. DWR generation is not necessarily dedicated to any particular off system sales customers, and disproportionate assignment of DWR revenues of a geographical basis would be arbitrary.
41. SCE provides an objective criterion to justify applying different allocation approaches between long term fixed price contracts and supply sources of 90 days or less.
42. DWR did not procure separate portfolios of supplies for each of the three utility service territories such that specific supply sources could be exclusively identified with service to any one particular utility service territory.
43. DWR's stated procurement policy was to use power purchased under many contracts to meet the net short position in more than one utility service territory, directly or though swaps, exchanges, or otherwise.
44. The allocation of DWR costs on the basis of geographical differentiation between NP15 and SP 15 presumes a cause-and-effect relationship between the location where energy supplies were procured and the specific utility service territory in which the associated electricity was consumed.
45. For certain power supplies procured north of Path 15, DWR incurred usage charges relating to transmitting power from north to south over Path 15 during periods of expected congestion, a situation that has been referred to as a "transmission constraint."
46. Congestion-related usage charges could be imposed simply on the expectation that Path 15 congestion would occur in the day-ahead power market even when there turned out to be no actual transmission congestion in real time.
47. The congestion-related charges incurred by DWR for power transmitted over Path 15 were an artifact of a statewide dysfunctional power market. The charges subsided after FERC adopted measures to help minimize or eliminate market flaws in the California electric power market.
48. The causes of price differentials between NP 15 and SP 15 were not necessarily related exclusively to congestion, but to some extent were a function of other factors such as when the related contract was signed.
49. The timing of when particular contracts were signed was not linked to specific utility service territories. Instead, DWR was trying to find power wherever it was available, particularly during the early months of 2001, to address the statewide power crisis.
50. Use of hourly data for allocation purposes has theoretical appeal as a means to promote linkage between DWR costs and revenues, but unanswered questions concerning the availability, complexity, and litigiousness associated with such data make it inadvisable to adopt such a requirement at this time.
51. Pursuant to Executive Orders issued by the Governor, DWR has been given responsibility and has been authorized to implement the 20/20 Rebate Program.
52. DWR agrees to track its net short energy purchases and ancillary service purchases to compare against the projected accruals of the revenue requirement and will update projections on a monthly basis.
53. DWR's monthly monitoring will be used to determine if there should be any adjustment, up or down, in the revenue requirement and the associated recovery of that revenue requirement from the customers of the respective utility service territories.
54. Although the end user's retail rates will not fluctuate to reflect monthly differences in DWR sales, the rate per kWh that is included in the bill for the power that the utility itself provides through URG sources (i.e., the "effective utility rate") will vary from month to month.
55. With fixed overall retail tariffed rates and a fixed per kWh charge payable to DWR, there is, in effect, an amount that the utility is entitled to receive for its own account for the kWh that it supplies to its retail customers, referred to as the "imputed utility rate."
56. It will not be necessary for each utility to maintain a separate balancing account to track its respective share of under or overcollections in DWR's actual costs since DWR will independently perform this function.
57. Even though DWR will account for its own under and overcollections, each utility will still need to keep track of the actual portion of total monthly sales revenue billed to customers attributable to DWR-supplied power in order to determine the residual portion of billed retail revenues available to recover URG-related costs.
58. As discussed in the Draft Decision on the URG revenue requirement, a "Revenue Shortfall Balancing Account" (RSBA) established by each utility would provide for tracking of billed URG-related revenues against authorized URG revenue requirements.
59. In order to credit the proper amount of URG billed revenue to the RSBA, it will be necessary for the utility to track actual DWR billed revenue and subtract it from the balance to be credited to the RSBA.
60. Although the end user's retail rates will not fluctuate to reflect monthly differences in DWR sales, the rate per kWh that is included in the bill for the power that the utility itself provides through URG sources (i.e., the "effective utility rate") will vary from month to month.
61. With fixed overall retail tariffed rates and a fixed per-kWh charge payable to DWR, there is, in effect, an amount that the utility is entitled to receive for its own account for the kWh that it supplies to its retail customers, referred to as the "imputed utility rate."
62. Truing-up the utility RSBA at a later date will ensure that the utility bills, and its customers pay (over time), the imputed rate for utility-supplied power.
63. The applicable kWh sales for computing prospective remittances under the DWR charges established in this order cover the period from March 1, 2002 through December 31, 2002.
64. It will be necessary for each utility to remit to DWR payments in separate installments for DWR energy delivered to customers prior to March 1, 2002, to the extent that prior interim remittances to DWR were less than the amounts indicated for those prior periods under the allocation of DWR's $9.045 billion revenue requirement as adopted herein.
65. The servicing agreements that have been approved for each of the utilities includes provisions prescribing the billing, collection, and related services to be performed by each utility relating to AB1X-authorized power purchases by DWR.
66. Although D.01-09-015 allows PG&E to seek Bankruptcy Court approval of its servicing agreement, the Bankruptcy Court has not yet approved PG&E's servicing agreement.
67. Even though the Bankruptcy Court has not approved PG&E's servicing agreement, the relevant language in PG&E's servicing agreement pertaining specifically to the billing, collection, and remittance of funds to DWR can still be independently extracted and incorporated for use in this order.
68. The FERC has recently confirmed that DWR, as the creditworthy party, is responsible for Imbalance Energy charges for PG&E.
1. Because this decision construes, applies, implements, and interprets the provisions of AB 1X (Chapter 4 of the Statutes of 2001-02 First Extraordinary Session), Section 1731(c) (applications for rehearing are due within 10 days after the date of issuance of the order or decision) and Section 1768 (procedures applicable to judicial review) are applicable.
2. Under the provisions of Water Code Section 80110, it is within the authority of the DWR to conduct and determine any just and reasonable review of its revenue requirement pursuant to Public Utilities Code Section 451. Accordingly, this Commission makes no independent conclusions concerning whether the DWR revenue requirement implemented in this order is just and reasonable.
3. DWR is legally entitled to payment for its revenue requirement associated with power it purchases and sells to retail end-use customers pursuant to Division 27 of the California Water Code.
4. Pursuant to the mandates of AB1X, a revenue requirement for DWR should be implemented in accordance with the provisions of this order.
5. Based on the amounts that DWR has submitted pursuant to its authority under Water Code Section 80110, the total revenue requirement to be implemented totals $9.045 billion for the service areas of the three major California utilities, covering the period January 2001 through December 2002.
6. DWR should be entitled to recover revenues in an amount equal to the number of kWh sold by DWR and billed to customers in the service territories of PG&E, SCE, and SDG&E, respectively, multiplied by the relevant charges as set forth in the Ordering Paragraph (O.P.) 3 below.
7. Based upon the estimates of URG revenue requirements that have been submitted as testimony in that phase, there is a range of potential outcomes could be decided by the Commission that could result in either a shortfall or surplus of revenues for each of the utilities.
8. The effect of this order on the need for retail rate increases for the utilities cannot be determined until after the URG phase of this docket is completed.
9. The effect of this order on the need for interim retail rate increases for SDG&E is subject to consideration in a separate docket (A.00-10-045 et al.).
10. It is reasonable to adopt a SCE's approach to allocate DWR's costs.
11. The adoption of SCE's proposed allocation of DWR revenue requirement represents a reasonable application of a cost-based revenue allocation of the DWR revenue requirement and related DWR charges to be applied among the service areas of the three utilities.
12. The goal of our cost allocation is that electricity customers in each utility's service territory pay for the cost of providing DWR service in that territory.
13. A process should be established whereby the actual costs incurred in each service territory will be compared with the costs that were previously projected in order to set future DWR charges.
14. DWR's periodic adjustment to its revenue requirement should reflect the variances between actual and forecasted costs, and take into account actual and projected fund balances.
15. DWR should promptly provide an adjustment to its revenue requirement as soon as bonds are issued, reflecting the removal of the interim loan costs that will not be incurred as a result.
16. Upon removal of the interim loan costs from the revenue requirement by DWR, if these sums are not needed to pay interest on the long term bonds or to reimburse the General Fund, the Commission would expect to be able to implement a prompt adjustment to the DWR remittance charges payable by the utilities for the balance of 2002.
17. An interim arrangement calling for utilities to remit franchise fees on DWR power sales should be adopted to provide for municipalities to continue to receive such fees pending further determination of a proper disposition of this issue.
18. This decision does not reach the issue of whether franchise fees are owed on revenues associated with DWR sale of power, but rather orders the utilities to maintain the status quo until this issue is resolved.
19. The utilities should be authorized to establish and maintain memorandum accounts to ensure that the utilities are made whole for any franchise fee payments made on behalf of DWR that are not already included in retail rates.
20. In this decision, we do not endorse the DWR uncollectibles factor of 0.0033.
21. Whatever assumptions DWR makes concerning uncollectibles in its revenue requirements determination, we do not intend for the utilities to retain uncollectible allowances in excess of the amounts that have been adopted for utility ratemaking purposes.
22. The record should be further developed concerning the rights and obligations of municipalities, DWR, and the utilities with respect to the collection and remittance of franchise fees associated with DWR power sales. The ALJ should issue a procedural ruling to solicit further comments for this purpose.
23. The servicing agreements approved for SDG&E and SCE should be applied in prescribing the manner of billing, collection, and remittance to be followed by each of those respective utilities with respect to DWR charges implemented in this order.
24. While the servicing agreement for PG&E has not been approved by the Bankruptcy Court, the pertinent language from its servicing agreement as identified in the ALJ ruling dated December 6, 2001, forms a reasonable basis for prescribing the manner of billing, collection, and remittance to be followed by PG&E with respect to DWR charges implemented in this order.
25. In the interests of facilitating PG&E's process of seeking Bankruptcy Court approval of the servicing agreement, it is reasonable to forbear at this time from implementing the provisions of PG&E's servicing agreement relating to remittance methodology.
26. Commission forbearance does not constitute any admission or judgment concerning the Commission's lack of jurisdiction to implement whatever remittance measures may be called for in the interests of complying with applicable statutory mandates relating to the DWR revenue requirement.
27. Although the DWR charges implemented in this order include a provision for imbalance energy, the Commission makes no prejudgment nor endorsement concerning the ultimate responsibility for payment of imbalance energy or other related costs that are the subject of negotiations between DWR and the utilities.
28. PG&E should also be remitting revenues to DWR for Imbalance Energy in that DWR is responsible for such charges according to the order of the FERC.
29. The impacts of Direct Access customers' responsibility for a share of the DWR revenue requirement allocation has not been reflected in the amounts presented in this order, but the assessment of those potential impacts should be considered in this docket on a timely basis in coordination with A.98-07-003.
30. In order to facilitate independent charges that will be segregated and remitted directly to DWR, a separate per kWh charge should be used in computing the revenue to be forwarded to DWR by each utility on a monthly basis.
31. To ensure that the utility recovers neither more nor less than it would otherwise recover under its imputed utility rate, the utilities should each be authorized to establish interest-bearing balancing account, to the extent one is not already authorized, as a provision of their filed tariffs.
32. The DWR remittance charges implemented in this order do not require any of the utilities to advance their own equity funds.
33. Even to the extent that the funds remitted to DWR by the utility may temporarily exceed the provision covering DWR sales collected through current retail rates, the excess amount remitted to DWR does not constitute an advance of utility investors' funds since such funds are provided by ratepayers.
34. To the extent that the remittance of DWR payments leaves a deficit remaining for coverage of URG-related costs, the utility will be made whole through the balancing account established for that purpose.
35. The utilities continue to have the obligation to serve pursuant to Public Utilities Code Section 451 and Water Code Section 80002.
IT IS ORDERED that:
1. The revenue requirement of the California Department of Water (DWR) in the amount of $9,045,462,000 (as set forth in Appendix A) is hereby implemented as provided in the following ordering paragraphs, covering the period January 17, 2001 through December 31, 2002.
2. The total DWR revenue requirement is hereby allocated among the customers in the service territories of three major utilities as follows: for the service territory of Pacific Gas and Electric Company (PG&E) in the amount of $4,507,238,000; for the service territory of Southern California Edison Company (SCE) in the amount of $3,553,841,000; and the remaining allocation to the service territory of San Diego Gas and Electric Company (SDG&E) in the amount of $984,383,000.
3. PG&E, SCE, and SDG&E are directed to begin disbursement of proceeds to DWR, as required by their respective servicing agreements or commission order, using the respective charges in cents per kWh of 9.295 for PG&E, 9.744 for SCE and 7.285 for SDG&E. These charges shall apply to each DWR-supplied kWh included on bills rendered on or after March 15, 2002.
4. The cents per kWh charges referenced in Ordering Paragraph 3 above shall remain in effect for each utility through December 31, 2002 (unless DWR indicates an earlier adjustment is needed), and shall provide recovery of the DWR revenue requirement applicable through that period. Updated DWR charges shall be scheduled to take effect for customers in each of the utilities' service territories beginning on January 1, 2003, covering the DWR revenue requirement for the forecast period from January 1, 2003 through December 31, 2003.
5. To the extent it has not already done so, each utility shall remit an additional payment to DWR representing amounts owing for DWR power delivered to that utility's customers and billed prior to March 15, 2002. The payment shall be based on the difference between the applicable interim charges that have already been remitted to DWR and the amounts that are due based on the DWR revenue requirement allocated in this order to each utility through March 15, 2002. The utilities shall remit the payment to DWR, amortized in equal monthly installments over a six-month period. All other sums to be forwarded to DWR pursuant to Ordering Paragraph 3 shall be sent at the time specified in the servicing agreement (for SDG&E and SCE) with which the Commission has ordered the utilities to comply.
6. In the case of PG&E, because its servicing agreement has not been approved by the Bankruptcy Court, PG&E shall be permitted to continue using its current procedures to remit payments to DWR.
7. Each of the utilities shall be required to remit the total amount of DWR energy, including scheduled and real-time imbalance energy, delivered to customers, to the extent reflected in the revenue requirement implemented herein, both for past deliveries and on a prospective basis.
8. In implementing DWR charges covering imbalance energy or any other related ISO payments subject to ongoing negotiations between DWR and the parties, the Commission makes no prejudgment and reaches no final disposition concerning the ultimate responsibility for the reimbursement of costs that are the subject of these ongoing negotiations.
9. Each of the three utilities shall establish an interest-bearing Revenue Shortfall Balancing Account (or shall use a previously authorized balancing account, if applicable) to segregate DWR-related billed revenues from URG-related billed revenues. The balancing account shall be credited with URG revenues and shall exclude DWR-related kWh sales.
10. The share of under- or overcollection in DWR costs shall be chargeable to customers in each utility service territory based upon the actual percentage allocation of net short, adjusted for other items as specified in this order, multiplied by the total actual under- or overcollection of DWR revenue requirement.
11. The under or overcollection in DWR revenue requirement shall be determined as the difference between (a) the total DWR revenues billed, collected, and remitted to DWR and (b) the share of actual DWR costs allocated to the utility. The DWR revenue allocations implemented in this order shall be trued-up, pursuant to a subsequent Commission order, no later than during the next update proceeding for DWR.
12. The schedule for the next update of DWR revenue requirement shall be set to begin June 1, 2002, with DWR charges to be revised effective January 1, 2003. The Commission or the ALJ shall issue further orders or rulings establishing any necessary provisions as to the manner and process for the DWR revenue requirement update proceeding.
13. The assigned ALJ shall issue a procedural ruling calling for further briefing and comments regarding pertinent legal issues as to the rights and obligations of municipalities, utilities and their customers, and DWR with respect to the billing, collection, and remittance of franchise fees associated with DWR electric power sales.
14. The ALJ shall issue any further rulings as necessary to expedite consideration of issues relating to Direct Access Customers' cost responsibility for DWR revenue requirements, including any associated adjustments to the adopted DWR allocation percentages as may be relevant to recognize Direct Access impacts.
This order is effective today.
Dated February 21, 2002, at San Francisco, California.
LORETTA M. LYNCH
President
CARL W. WOOD
GEOFFREY F. BROWN
Commissioners
I dissent.
/s/ RICHARD A. BILAS
Commissioner
I will file a dissent.
/s/ HENRY M. DUQUE
Commissioner
Appendix A | ||||||||||||||||||
Table 1 | ||||||||||||||||||
DWR Revenue Requirement | ||||||||||||||||||
For the Period January 17, 2001 through December 31, 2002 | ||||||||||||||||||
($000s) | ||||||||||||||||||
Quarter |
Retail Sales (GWhs) |
A&G |
Other |
DSM |
Contract Power |
Residual Net Short |
Ancillary Services |
Total Commitments |
(Lag) Lead Accrual to Cash |
Total Operating Expenditures |
Financing Cost |
Total Expenditures |
Revenue Lead (Lag) |
Spot Sales Revenue |
Estimated Quarterly Fund Balance |
Total DWR Revenues Needed |
Net Borrowed Proceeds |
Customer Revenue Requirement |
A |
B |
C |
D |
E |
F |
G (Sum of A thru F) |
H |
I (= G + H) |
J |
K (= I + J) |
L |
M |
N |
O (=K - L -M + N) |
P |
Q (=O - P) | ||
Q1, 2001 |
12,360 |
7,848 |
- |
- |
- |
3,581,465 |
367,847 |
3,957,160 |
(1,619,382) |
2,337,778 |
(0) |
2,337,778 |
(544,097) |
- |
293,176 |
3,175,051 |
2,400,000 |
775,051 |
Q2, 2001 |
19,620 |
10,162 |
- |
482 |
627,601 |
3,884,229 |
419,215 |
4,941,690 |
6,302 |
4,947,991 |
(0) |
4,947,991 |
(1,030,866) |
- |
4,239,624 |
9,925,305 |
7,908,729 |
2,016,576 |
Q3, 2001 |
16,054 |
11,346 |
3,734 |
226,446 |
888,404 |
1,135,727 |
57,667 |
2,323,324 |
(55,479) |
2,267,845 |
(10,481) |
2,257,364 |
(329,133) |
- |
3,182,822 |
1,529,696 |
(116,300) |
1,645,996 |
Q4, 2001 |
10,365 |
8,998 |
4,008 |
61,968 |
670,470 |
248,590 |
43,889 |
1,037,923 |
447,469 |
1,485,392 |
- |
1,485,392 |
420,407 |
20,884 |
2,963,069 |
824,348 |
- |
824,348 |
Q1, 2002 |
9,313 |
15,104 |
3,667 |
- |
652,644 |
169,756 |
51,551 |
892,722 |
1,234,971 |
2,127,693 |
(47,143) |
2,080,550 |
879,565 |
24,819 |
2,499,879 |
712,975 |
- |
712,975 |
Q2, 2002 |
7,957 |
15,104 |
3,211 |
- |
665,651 |
129,830 |
42,678 |
856,474 |
(19,771) |
836,703 |
471,932 |
1,308,635 |
20,355 |
39,279 |
2,128,890 |
878,012 |
- |
878,012 |
Q3, 2002 |
12,312 |
15,104 |
4,895 |
- |
946,735 |
220,184 |
64,080 |
1,250,998 |
(25,251) |
1,225,748 |
392,449 |
1,618,197 |
(257,440) |
45,879 |
1,643,471 |
1,344,339 |
- |
1,344,339 |
Q4, 2002 |
10,812 |
15,104 |
4,249 |
- |
832,758 |
164,417 |
54,752 |
1,071,280 |
20,493 |
1,091,773 |
125,321 |
1,217,095 |
195,076 |
26,043 |
1,495,658 |
848,163 |
- |
848,163 |
Total |
98,793 |
98,771 |
23,764 |
288,896 |
5,284,264 |
9,534,199 |
1,101,678 |
16,331,571 |
(10,648) |
16,320,924 |
932,079 |
17,253,002 |
(646,134) |
156,903 |
19,237,890 |
10,192,429 |
9,045,461 | |
- Notes
1. Total Commitments equals sum of A&G, Other (Uncollectables), DSM, Contract Power, Residual Net Short, and Ancillary Services
2. Total Operating Expenditures equals Total Commitments plus (Lag) Lead Accrual to Cash
3. Total Expenditures equals Total Operating Expenditures plus Financing Cost
4. Total DWR Revenues Needed equals Total Expenditures minus Revenue Lead (Lag), minus Spot Sales Revenue, plus Estimated Quarterly Fund Balance
Customer Revenue Requirement equals Total DWR Revenues Needed minus Net Borrowed Proceeds
Appendix B
Summary of Parties' Comments Regarding the Reasonableness
of DWR's Revenue Requirement
This appendix sets forth parties' position regarding various concerns raised in their comments filed on November 13, 2001 regarding their review of the DWR revenue requirement submittal of November 5, 2001. In response to a letter of Commissioner Brown to DWR dated, DWR provided further responses to the concerns raised by parties, as summarized below. These comments are provided for informational purposes, with the understanding that DWR retains responsibility for conducting a "just and reasonable" review of its costs pursuant to Public Utilities Code Section 451.
1. DWR Losses on Surplus Power Sales
DWR's revenue requirements include costs associated with surplus power that is sold off-system. PG&E argues that under Water Code Section 80116, DWR may not charge retail end-use customers for losses incurred on off-system sales of surplus power because retail end-use customers are only liable for the costs of the power actually sold to them.
DWR states that it is impossible to identify which specific purchases by DWR are subsequently sold off system to non utility customers, precluding DWR from quantifying a true "cost" of surplus power. DWR did provide, however, a weighted average monthly summary through September 2001 and quarterly thereafter of cost and volume of long term power, residual net short purchases, and off-system sales.
DWR disagrees with PG&E's characterization of any DWR purchases as being made for any purpose other than for the provision of the utilities net short position. DWR explains that from time to time, it may purchase more energy than is currently required to serve retail customers net short. The excess energy is sold into wholesale markets to provide off system revenues which are used to decrease revenue requirements recovered from retail customers. DWR states that such balancing of needs by periodic off system sales is standard industry practice. Therefore, DWR asserts that it is appropriate to consider all purchased power costs (including losses) incurred in DWR's revenue requirement.
DWR states that sales of surplus power are a byproduct of ongoing adjustments that are inherent in balancing load forecasts which are only estimates of actual load, subject to weather and numerous other uncontrollable factors.
DWR cites Water Code Section 80134(a) which states that DWR's revenue requirements must be sufficient to provide all of DWR's costs "to make payments under any other contracts, agreements, or obligations entered into by it pursuant hereto." DWR states that excluding the cost of power which proves to be surplus from the retail revenue requirement undercuts this statutory directive. Accordingly, DWR asserts that losses on the sale of surplus energy are authorized for recovery by DWR in its revenue requirement.
2. Spot Electricity Prices in Q3-2001
PG&E has noted that DWR's estimate of spot electricity prices for Q-3 in the November 5 Revenue Requirement (Table 6, pg. 16) of $117MWH price is significantly above the FERC-mandated price cap in effect during Q3- 2001. PG&E claims that DWR's Q3-2001 prices are inflated by as much as $700 Million due to this effect.
PG&E asked that DWR explain the re-classification of its short-term contracts (90-days or less) that are now part of the "Residual Net Short," and indicate to what extent these 90-day contracts have caused the residual net short average costs to exceed the FERC price cap during third quarter 2001. PG&E asked that DWR provide detailed workpapers regarding the dates, amounts and costs of such 90-day contracts entered into during the period immediately prior to and during third quarter 2001, especially after adoption of FERC's price mitigation order.
In its December 13 reply, DWR explains that it has not reclassified short term contracts, nor are the 90-day contracts responsible for the residual net short average to rise above the FERC price cap. In its reply, DWR provides a table summarizing the prices and volumes for components of the net short by month during third quarter 2001. DWR explains that actual purchases in each of the spot markets are all below the current FERC non-Stage 1 alert price cap of $101.06/mWh. Yet, in computing its reported third quarter prices, DWR includes the net effects of off-system sales, causing reported unit prices to exceed the FERC price cap in the month of July 2001.
3. Line Losses
PG&E claimed that the 9% assumed by the DWR for PG&E's transmission and distribution losses should be reduced to no more than 6.4%. PG&E assumes a 0.6% reduction of transmission losses due to the fact that the ISO typically requires generators to make up the associated transmission losses. PG&E claims that DWR's revenue requirement constitutes double-charging of PG&E customers by about $390 Million because it includes ISO's Unaccounted-for Energy (UFE) charges for PG&E, but also assumes additional energy is procured by DWR for UFE.
DWR disagrees with PG&E's contention that line losses should be reduced to 6.4% and denies any double counting of UFE charges. DWR states that the fact that the ISO requires generators to make up line losses does not mean that losses do not occur, or that DWR does not incur costs for associated energy to account for those line losses. DWR further states that no explicit UFE charges were considered in the revenue requirement after August 2001. UFE amounts are inherently included as part of the forecast of energy procured by DWR.
4. Direct Access Estimates for PG&E
In its October 26 comments to DWR, PG&E provided updated estimates for the fourth quarter of 2001 for direct access, although DWR has not incorporated PG&E's update in its latest revenue requirement. However, PG&E now believes that the actual direct access amount for the fourth quarter of 2001 and for all of 2002 will be even higher than previously forecasted.
DWR states that it cannot confirm with reasonable certainty PG&E's estimates of direct access. Because of the multiple uncertainties surrounding the future of direct access, DWR does not believe it is appropriate at this time to alter its estimates of direct access based on more recent estimates. DWR states that it will consider expected changes to California's retail electricity markets when developing its next determination of revenue requirements.
5. WAPA Loads
PG&E claims that DWR's estimate of Western Area Power Administration (WAPA) loads of 5,429 GWh is too high. PG&E provided DWR an estimate of 5,026 GWh for 2001 and 3,837 GWh for 2002 for WAPA loads in its October 26 comments, corresponding to a reduction in DWR's revenue requirement for PG&E by about $90 Million.
DWR states that it will continue to review PG&E's updated WAPA load estimates and incorporate any changes in DWR's true up process relating to updating its future determinations of revenue requirement.
6. Treatment of Wholesale Contracts
SCE questions whether DWR has been consistent in its treatment of SCE's wholesale contract obligations, in particular, SCE's exchange contracts, or whether these contracts were considered in estimating SCE's net short position.
DWR asserts that it has been consistent in its treatment of wholesale obligations and exchanges between the three utilities. DWR explains that many of the utility-to-municipal exchanges are included within the PROSYM simulations. While other exchanges are not explicitly modeled within PROSYM, they are included in DWR's true up to actual costs.
7. Short-Term Load Resource Balance
On page A-20 of its revenue requirement submittal, DWR notes that it is limiting imports into California to generation owned by the utilities as part of their retained generation, out-of-state generation owned by municipal utilities, or existing bilateral contracts with out-of-state suppliers. PG&E has claimed that this understates the amount of power that could be imported into California.
DWR responds that PG&E misinterprets the explanatory notes to Table III-1 in the November 5 Determination. DWR is not limiting its power procurement only to new, in-state generation without consideration of imports. Table III-1 is indicative of resources firmly committed to consumers in California at the summer peak hour over DWR's revenue requirement period. DWR states that other, non-firm, out-of-state resources expected to be available have been incorporated into its estimates of power to meet net short requirements.
8. DWR Reserve Requirements
DWR revenue requirements include cash to fund reserve requirements. According to DWR, the cash reserves are needed for debt service reserves and for handling future cost and revenue volatility under different "stress scenarios" involving variations in natural gas and spot market prices, and forced outages at generating plants.
Aglet observes that DWR's reserve requirements are large compared to normal utility working cash requirements, and argues that the Commission should not require utility customers to fund any DWR cash reserve requirements. Aglet claims there are better ways to protect DWR from cash flow volatility. Aglet argues that for large firms, and by extension for DWR, the preferred response to operating volatility is the use of credit facilities-not cash reserves. Creditworthy utilities respond to cost volatility by relying on lines of credit, commercial paper and other short-term borrowing and lending. Aglet believes the Commission and DWR should cooperatively seek a "line of credit" or equivalent financial backup from the State.
If the Commission insists that customers put up the requested cash reserves, then Aglet argues that customers should be credited with interest accruals on the full amount of the DWR's cash reserve, consistent with rate base reductions ordered for utilities with contributions in aid of construction. Aglet asks the Commission to encourage DWR to return unneeded reserves to customers promptly after the State issues its bonds and in any other circumstance where DWR recognizes that its cash flows will become less volatile.
(END OF APPENDIX B)
Appendix C
Natural Gas Pricing Assumptions
Natural gas prices are an input in DWR's estimated power prices in meeting utility customers' net short requirements. DWR provides a detailed discussion of its assumptions underlying natural gas prices in Appendix VI of its November 5th submittal. Estimated prices have been developed using a proprietary forecasting model developed by Navigant.
The Appendix C Table below shows the cost of natural gas assumed in the development of both contract power costs as well as the cost of residual net short power resources for the DWR revenue requirement. Fuel transportation charges are estimated in DWR's generation dispatch model based upon regional location of generating sources. During the summer of 2001, minor volumes of gas were procured for part of 2001 and the first quarter of 2002 for some of those contracts under which DWR has rights to purchase or supply fuel to a generator. Those costs are included in DWR's contract energy costs. All fuel costs included in the contracts and the spot market purchases are assumed to be equal to the average spot market price of natural gas.
TABLE GAS PRICE ASSUMPTIONS ($/MMBTU IN 2001 DOLLARS) | |||
SoCal Border |
Malin |
PG&E City Gate | |
Q3 2001 |
3.72 |
3.59 |
3.87 |
Q4 2001 |
3.54 |
3.01 |
3.49 |
Q12002 |
3.55 |
3.02 |
3.51 |
Q2 2002 |
3.52 |
2.99 |
3.47 |
Q3 2002 |
3.36 |
2.86 |
3.33 |
Q4 2002 |
I 3.78 |
I 3.22 |
I 3.72 |
(END OF APPENDIX C)
************ APPEARANCES ************ |
James Weil |
Barbara R. Barkovich |
Jennifer Tachera |
Jennifer Chamberlin |
Patrick Mcguire |
Norman J. Furuta |
Andrew B. Brown |
Brian Cragg |
Morten Henrik Greidung |
Daniel L. Rial |
John W. Leslie |
Jeffrey H. Goldfien |
Sara Steck Myers |
William H. Edwards |
Lon W. House |
Dana S. Appling |
Justin D. Bradley |
Itzel Iberrio |
Jerry Bloom |
Robert Pernell |
Robert Miyashiro |
Julie Halligan |
Donald J. Lafrenz |
Steve Roscow |
Rosalina White |
Frank Annunziato |
Stephen Layman |
Karen Cann |
Joseph M. Paul |
James Meyn |
Joelle Ogg |
Thomas S. Hixson |
Kris Cheh |
Bruce Bowen |
Ron Helgens |
Michael Bazeley |
Frank J. Cooley |
Patricia Vanmidde |
(END OF APPENDIX D)
A.00-11-038
D.02-02-052
Commissioner Henry M. Duque dissenting:
I cannot support the majority decision. The assumptions underlying the majority decision are not supported by the record. It applies differing allocation assumptions depending on whether the power is from short term contracts or fixed price contracts. For fixed price contracts, the majority decision agrees that there is no sound basis to disaggregate contract costs depending on whether the power was procured from a contract North of Path 15 or South of Path 15. For such contracts, it agrees that such contracts were entered into to serve the joint needs of all customers statewide.
The majority decision then makes a contrary assumption for contracts that cover a term of 90 days or less, assuming such contract costs can be disaggregated on a North or South of Path 15 basis. However, there is nothing in the record to support the assumption that DWR's purchasing strategy or dispatch criteria were different depending upon whether the originating source of the power was from a contract greater than or less than 90 days.
As the record makes clear, most of the short term contracts were signed during the spring of 2001 to supply power during key summer periods. Since delivery under the vast majority of long term contracts could not begin until after the summer of 2001, DWR had to rely on the short term contracts to bridge the gap of the intervening period. During the spring of 2001, DWR was "scrambling" to find power sources wherever it could to avoid power shortages or blackouts. Thus, to the extent there is any cost causation related to short term contracts versus long term contracts, the causative factor is time-related, not geographically related. Short term contracts were entered into because they could be executed more quickly than long term contracts, not because the power was destined to a particular utility's service territory to the exclusion of others. There is no more basis for allocating short term contracts on a zonal basis any more than long term contracts (which the majority decision concedes is not proper).
The criticism of the rationale underlying the ALJ's proposed decision, moreover, is misplaced. The majority decision claims that the allocation approach in the ALJ's decision is wrong because "transmission constraints make it impractical to provide all of a utility's load with generation from outside the utility's service territory." Yet, under the ALJ's allocation method, PG&E would still receive about 2/3 of its power from URG located entirely within NP 15 and would be allocated about 48% if DWR's NP 15 purchases. Together, these NP 15 resources actually account for the majority of PG&E's total requirements. Therefore, the majority decision relies on an incorrect premise in claiming that "all of a utility's load" is assumed to be supplied by another delivery zone under the ALJ's allocation approach.
For these reasons, I must dissent.
/s/ HENRY M. DUQUE
Henry M. Duque
Commissioner
San Francisco, California
February 21, 2002
