XII. Assignment of Proceeding
Carl W. Wood and Geoffrey F. Brown are the Assigned Commissioners and Thomas Pulsifer is the assigned Administrative Law Judge in this proceeding.
1. D.02-03-055 determined that as a condition of retaining the DA suspension date of September 21, 2001, a surcharge must be imposed on DA customers sufficient to make bundled customers economically indifferent between a DA suspension date of July 1 versus September 21, 2001.
2. By D.02-11-022, an interim DA CRS cap of 2.7 cents/kWh was adopted pending further study and possible revision effective on and after July 1, 2003.
3. A reasonable criterion in setting a cap for purposes of preserving bundled customer indifference with respect to DA load migration is to ensure full payback of the DA CRS undercollection no later than the end of the DWR contract term expected to occur in 2011.
4. To provide a framework for analysis of potential future DA CRS obligations and the resulting effects of alternative caps, Navigant produced a range of 24 separate modeling scenarios, incorporating the "total portfolio indifference" approach.
5. The Navigant scenarios are based upon three sets of resource assumptions, comprising a low, high, and base case in which the sensitivities of the undercollection and payback period are tested with respect to changes in key variables relating to DA load, natural gas prices, new generation, and CTC levels.
6. While certain parties support use of the base case for evaluating DA CRS payback periods, no support was provided to show that the assumptions underlying the base case (other than DA load levels) have a greater overall likelihood of occurrence relative to the low or high case.
7. No party supported the high case as offering more reliable forecast assumptions than either the low or base case.
8. Of the modeling runs produced by Navigant, the scenarios based upon the low case with off-system sales valued at 100% of market-clearing price represent the most likely forecast assumptions relating to future DA CRS requirements for purposes of evaluating cap levels, as represented in Navigant Scenarios 13 through 16.
9. Although Navigant's low case scenarios generally are more reliable than its base case scenarios, the base case assumptions concerning DA load are more defensible than either the high or low base case assumptions for this variable.
10. AREM presented a scenario combining the base case assumption for DA load with the other assumptions underlying the low case, essentially as depicted in Navigant Scenario 14, and computing the effects of this combination of assumptions as "Scenario 25."
11. Based on the AREM Scenario 25 results, payback of the DA CRS undercollection would occur within a five-year period for PG&E, within a four-year period for SCE, and within a two-year period for SDG&E.
12. Although Navigant's initial runs did not identify a single actual 2001-2002 recorded undercollection applicable to DA CRS, it subsequently submitted revised calculations that identified values for the actual undercollection applicable to each utility.
13. The updated data regarding estimated 2001-2002 undercollection values submitted by Navigant provide a reasonable approximation for the limited purposes of analyzing the expected payback of DA CRS undercollections subject to further verification of the actual values.
14. The substitution of the updated data regarding actual 2001-2002 recorded undercollection values submitted by Navigant still provides for expected DA CRS payback periods prior to 2011, reflecting a DA CRS cap of 2.7 cents.
15. Based upon forecast results presented in Scenarios 13 and 14 as further refined by Scenario 25, the goal of realizing full bundled customer payback of the DA CRS undercollection by the end of the DWR contract term in 2011 can be satisfied by maintaining the current 2.7 cents cap for each utility, subject to periodic review and adjustment as necessary.
16. In order to remain indifferent with respect to the DA CRS undercollection, bundled customers must be fairly compensated for the time value of money through an appropriate interest rate.
17. To the extent the utility rate of return includes a component for utility stockholders' equity, its risk-and-return is not a relevant indicator of the risk and return applicable to a debt-related obligation such as the DA CRS undercollection.
18. The fact that a three-month commercial paper rate may compensate a utility for financing certain types of balancing accounts does not necessarily indicate that such a rate is indicative of bundled customers' cost of money associated with financing the DA CRS undercollection.
19. The length of time that balancing account is expected to exist is not the sole determinant of the appropriate interest rate factor to be applied, particularly in the case of the DA CRS where financing is not provided by the utility, but rather by bundled customers, who do not necessarily have the same access to the capital markets.
20. Since the source of financing of the DA CRS undercollection is bundled customers, and not the utility, the relevant interest rate is based upon the risk-adjusted cost of money experienced by the bundled customer rather than financing sources to which a utility may have access.
21. Because the DA CRS undercollection is long term in nature, the most appropriate indicator of the bundled customers `cost of money is a long-term debt instrument rather than short-term forms of debt such as three-month commercial paper or a consumer revolving line of credit.
22. The broadest based measure of long term debt in this record is the long term corporate debt based on Moody's Investors Service Corp., with a 10-year average of 7.6% and 7.1% average for 2002.
23. A reasonable proxy for bundled customers' cost of money for the financing of the DA CRS undercollection is an interest rate based on the long-term corporate debt measure as indicated by the Moody's Investors Service Corp., and reported in the Farm Bureau's testimony.
24. For purposes of applying an interest rate factor to the DA CRS for the 2001-03 period, the average 2002 long-term corporate interest rate factor of 7.1% reported by Moody's Investor Services, Inc. represents the most reasonable proxy in the record.
25. For purposes of assessing the effects of interest in connection with a longer-term forecast of the DA CRS payback period, the 10-year average long-term corporate interest rate factor of 7.6% reported by Moody's Investor Services, Inc. represents the most reasonable proxy in the record.
26. Because business customers typically may deduct interest for income tax purposes, an after-tax interest rate provides an appropriate basis for purposes of accruing interest on their share of the DA CRS undercollection.
27. Because residential customers, typically cannot deduct interest for incremental borrowings, a before-tax interest rate provides an appropriate measure for purposes of accruing interest on their share of the DA CRS undercollection.
28. In D.02-07-032, the Commission found that there should be a cap on the total surcharge levels imposed on DA customers (including the impact of any changes to the PX credits) to avoid making DA uneconomic.
29. The Commission stated its policy in D.02-03-055 that there is value to California in maintaining DA. In D.02-07-032, the Commission found that failure to consider an overall cap would be inconsistent with this policy.
30. A appropriate approach for setting the DA CRS cap for the period subsequent to July 1, 2003 is one that takes into account the dual goals of achieving bundled customer indifference and avoiding making DA uneconomic.
31. Because of the diversity of DA contracts and customers, no single cap will necessarily prevent the return of any DA customers to bundled service, or prevent any DA business failure or relocation outside California.
32. No party justified that any cap lower than 2.7 cents is warranted in order to balance the goals of achieving bundled customer indifference whole avoiding making DA uneconomic.
33. The continuation of DA provides jobs and enhances the tax base in support of the California economy, and promotes the diversity of energy supplies within California.
34. For certain SCE rate schedules, bundled service is expected to be cheaper than DA even at a 2.7 cents cap after the PROACT reductions contemplated in A.03-01-019 are implemented. Any cap increase now will risk further tipping the scales further in favor of leaving DA for bundled service.
35. For certain DA customers, particularly in energy intensive industries, increases in the cap will increase the risk of DA becoming unviable.
36. Given the risk that increases in the cap may create incentives to leave DA for bundled service, relocate out of state, or go bankrupt, and considering that the existing cap provides for payoff by 2011, maintaining the existing caps avoids risking erosion of DA levels while protecting bundled customers.
37. ORA's proposal to allocate between two broad classes, core and noncore, provides a reasonable approach to implement the intent of the Commission expressed in D.02-11-022 concerning the assignment of the undercollection among different categories of bundled customers.
38. Under ORA's proposal, core would include residential and small commercial under 20 kW and noncore would cover customers over 20 kW.
39. ORA proposals for accounting for the DA CRS undercollections provide a reasonable means of assuring that the allocation between core and noncore customers is properly implemented.
40. The default in obligation of DA customers associated with the noncore class properly remains an obligation exclusively to be made up by other customers in the noncore class. The default in obligation of DA customers associated with the core class properly remains an obligation exclusively to be made up by other customers in the core class.
41. Because PG&E's tariffs do not precise correspond the 20 kW criterion proposed under ORA's allocation, it is reasonable for PG&E to modify the allocations as necessary to conform to its own tariff classes even though they may deviate somewhat from the 20 kW level.
42. It is reasonable to include the entire agricultural class and streetlighting class in the core category for purposes of assigning DA CRS undercollections.
43. Periodic reevaluations of the DA CRS cap level will mitigate the risk of future DA CRS forecast error, and assure timely bundled customer payoff of undercollections.
44. Determination of final figures for the 2001-2002 undercollection and 2003 prospective revenue requirement for DA CRS have yet to be implemented in coordination with the DWR proceeding in A.00-11-038 et al.
45. The revised order of collection of DA CRS elements with CTC collected second and DWR power charge collected third will simplify the accounting and administrative process.
46. In keeping with the requirement in D.02-11-022, that SCE to recover the HPC second in order after the DWR Bond Charge, the effect of the change in the sequence of collection adopted in this order means that SCE collects CTC third in order after the DWR bond charge and the HPC.
47. Because the CTC element has not yet been finalized, it is reasonable to time the implementation of the revised order of collection of the DA CRS elements to coincide with the finalization of the CTC element for each utility.
48. Because the DA CRS undercollection for 2001-02 and the prospective 2003 DA CRS revenue requirement have not yet been finalized, a further process is required to coordinate finalization of DA CRS obligations with the redetermination of the 2003 DWR revenue requirement in A.00-11-038 et al.
49. Since the DWR proceeding in A.00-11-038 et al. does not address URG costs, a separate process is needed to examine URG costs and to adopt a CTC component as prescribed under the total portfolio approach prescribed in D.02-11-022.
50. In order to assure proper coordination and timely finalization of the CTC components for the 2001-02 historic period and 2003 prospective period, it is reasonable to address those matters in this docket in coordination with the 2003 DWR revenue requirement redetermination in A.00-11-038 et al.
51. For prospective CTC determinations in 2004 and thereafter, it is reasonable to use the Energy Revenue Resource Account proceeding.
52. In order to assure consistent allocation of each DWR revenue requirements between bundled and DA load and proper interest accruals on the undercollection, it will be necessary to update the prospective DA cost responsibility obligation along with bundled customers' requirement for each new 12-month period as part of each DWR update proceeding.
53. Unless the allocation between bundled and DA load is made based upon consistent assumptions, the requirement for bundled customer indifference will be compromised.
54. Since the DA CRS cap already anticipates that collections will be extended over multiple years, variances in forecast costs over a single year will not necessarily require annual changes in the cap level.
55. To the extent that key resource variables (i.e., gas prices, DA load levels or off-system sales prices) deviate significantly from the forecast assumptions underlying this order, however, it may indicate that a reassessment of the cap is necessary to assure that payback goals are achieved.
56. In the event that key resource variables (i.e., gas prices, DA load levels or off-system sales prices) deviate from the levels assumed in this order by a significant degree at the time of the next annual DWR revenue requirement redetermination, further procedural steps would be warranted to consider the need for a reassessment of the level of the DA CRS cap.
57. For purposes of defining a significant level of variation in the identified key resource variables, it would be reasonable to assume a variation on the order of magnitude between the base case and the low case as defined in this proceeding.
58. Absent a significant variation in key resource variables, as defined above, it is reasonable to limit a reassessment of the cap level to once every two years.
1. This phase of the proceeding is focused on evaluating the DA CRS cap subsequent to July 1, 2003 rather than adopting total DA CRS revenue requirement elements.
2. The determination of the total authorized DA CRS level of the 2003 DWR power charge and 2001-2002 undercollections should be made in parallel with the overall determination of the total DWR revenue requirement in A.00-11-038 et al.
3. The adoption of a total authorized level of the CTC element comprising the DA CRS should not be finalized in this phase of the proceeding because further scrutiny of the utilities' proposed CTC calculations is warranted.
4. The task of finalizing CTC levels for the year 2004 and thereafter should be addressed in the ERRA proceeding for each utility.
5. SDG&E should amend its CTC calculation to be consistent with the total portfolio approach adopted in D.02-11-022, such that below-benchmark resources are included with above-benchmark resources.
6. The purpose of the DWR and CTC calculations presented in this phase of the proceeding is to provide a range of forecasts to evaluate the sensitivity of variances in key resource inputs and cap levels in relation to DA CRS undercollections and resulting payback periods.
7. The Commission should determine the level of DA CRS cap that balances the criteria of preserving bundled customer indifference and maintaining DA viability.
8. The criteria for preserving bundled customer indifference should provide assurance that CRS undercollections resulting from the cap will be repaid in full to bundled customers, with compensatory interest, over a reasonable period of time.
9. A reasonable time period for full repayment of the DA CRS undercollection should not exceed the term of the DWR contracts, due to expire in 2011.
10. The modeling scenarios of forecast DA CRS levels prepared by DWR/Navigant provide an appropriate framework for evaluating the potential cumulative undercollections and time period required to achieve full pay back to bundled customers for each utility.
11. The 2.7 cents/kWh cap level should continue in effect for each utility during the period on and after July 1, 2003 subject to possible revision in the next DA CRS cap review proceeding to the extent necessary to balance the dual goals of preserving bundled customer indifference and preventing economic harm to DA customers.
12. In each periodic DA CRS cap review proceeding, the cap should be subject to adjustment, to the extent necessary to maintain that the goal of full bundled customer payback by the end of the DWR contract term in 2011. The process for periodic review and readjustment of the DA CRS cap for each utility should conform to the requirements of Ordering Paragraphs 19-21 below.
13. In order to preserve bundled customer indifference, an interest rate must be applied to the DA CRS undercollection that reasonably compensates bundled customers for the time value of money.
14. An interest rate corresponding the long-term cost of corporate debt of 7.1% as referenced in the testimony of the Farm Bureau offers a reasonable approximation of bundled customers' cost of money associated with financing the DA CRS undercollection.
15. The proposal of ORA to allocate the DA CRS undercollection based upon a core and noncore segregation of customers should be adopted (subject to modifications specified below) as a pragmatic approach to fairly allocating the undercollection while avoiding excessive increases in charges to any single class of bundled customers.
16. The proposal of ORA should be adopted to establish an accounting mechanism to track the DA CRS undercollections and to assure that the appropriate levels are allocated between the core and noncore customer categories.
17. In order to simplify the administrative and accounting process, PG&E's proposal to revise the order in which the respective DA CRS are deemed collected should be adopted so that CTC is collected second with the DWR power charge collected third.
18. In the case of SCE, the order of collection should be revised to sequence the HPC second and the CTC third.
IT IS ORDERED that:
1. The existing Direct Access (DA) cost responsibility surcharge (CRS) cap of 2.7 cents/kWh applicable to each of the three utilities shall continue to remain in effect for the period beginning on and after July 1, 2003. The 2.7 cents cap shall be subject to possible future adjustment, as deemed necessary to pay off the DA CRS undercollection by 2011, through periodic review as prescribed in Ordering Paragraphs 20 and 21 below.
2. The final recorded confirmation of the DA CRS undercollection for 2001-2002, together with the adoption of the final adopted allocation of 2003 DWR power charges to the DA CRS shall be determined and implemented on a parallel basis in coordination with the implementation of the 2003 DWR revenue requirement redetermination in Application (A.) 00-11-038. The Administrative Law Judges in both this docket and in A.00-11-038 shall coordinate as necessary to ensure the timely implementation of this process in connection with the DWR 2003 revenue requirement redetermination.
3. The proposal of the Office of Ratepayer Advocates (ORA) for allocation of the DA CRS undercollection on a core versus noncore basis is hereby adopted with modifications as noted below.
4. The core/noncore allocation shall incorporate the entirety of the agricultural classes and the streetlighting classes.
5. PG&E shall be permitted to deviate from the 20 kW allocation separation criterion as necessary to conform to its tariff schedule categories, so as not to require splitting customers within a single tariff schedule category.
6. The ORA core/noncore allocation shall be adopted on a provisional basis, subject to subsequent adjustment, as necessary, to conform to any subsequent legislative actions that may require reexamination of the categorization criteria or purposes for which the categories are established.
7. The proposal of ORA for implementation of an accounting mechanism to track the DA CRS undercollection to ensure the appropriate allocation between the core and noncore categories is hereby adopted in accordance with the principles incorporated in Appendix B hereto.
8. The ALJ shall schedule a workshop to address in further detail how to implement the accounting for growth and repayment of the undercollection in accordance with the core and noncore approach adopted in this order.
9. The interest rate on DA CRS undercollections shall be applied based upon the long-term debt rate index derived from Moody's Investment Services Corp., as referenced in the testimony of the California Farm Bureau Federation.
10. For the period 2001-02 and for 2003, the interest rate to be applied to DA CRS undercollections for PG&E and SCE shall be based on a 7.1% interest rate, representing the 2002 average corporate interest rate, as set forth in testimony of the California Farm Bureau.
11. The interest rate on DA CRS shall be applied on an after-tax basis for residential bundled customers and on a before-tax basis for other bundled customers.
12. For applying interest accruals on the DA CRS undercollection applicable to bundled residential customers, the 7.1% interest rate shall be accrued on a before-tax basis. For other bundled customers, the 7.1% interest rate shall be accrued on an after-tax basis, resulting in an after-tax rate of 4.22% (incorporating an after-tax factor of 59.46% based upon utility corporate tax rates as computed by SCE). These interest rates shall remain in effect until the next annual DA cost responsibility redetermination when they shall be subject to updating.
13. The applicable long-term corporate interest rate to be used for 2004 shall be determined based upon updated data on long-term corporate interest rates using similar data sources as were used in this proceeding in connection with setting the DA cost responsibility obligation for 2004.
14. The proposal of Pacific Gas and Electric Company to revise the order of collection of the DA CRS elements is hereby adopted. Accordingly, the CTC element shall be deemed to be collected second in order after the DWR bond charge. The DWR power charge shall be deemed to be collected third in order after the CTC element.
15. Pursuant to the change in the sequence of collection ordered herein, SCE shall collect CTC third in order after the DWR bond charge and the HPC.
16. The change in the order of collection of CTC shall be implemented concurrently with the finalization of the CTC element for each of the utilities for 2001-02 and 2003.
17. The finalization of the CTC element of the DA CRS for the 2001-02 historic period and for 2003 prospectively shall be determined in a separate phase of this proceeding to be coordinated with the finalization of the 2001-02 DA CRS undercollection and prospective DWR power charge, as prescribed in Ordering Paragraph 2 above.
18. The finalization of the CTC element for year 2004 and thereafter shall be addressed in the ERRA proceeding.
19. The DA cost responsibility total obligation shall remain subject to annual redetermination in connection with the ongoing annual cost responsibility obligation annual redetermination of DWR revenue requirements.
20. In each annual update proceeding for DWR and DA CRS revenue requirements, to the extent that specified key variables deviates significantly from the forecast assumptions underlying this order, the assigned ALJ shall take further procedural steps to consider the need for a reassessment of the level of the DA CRS cap. The specified key resource variables are natural gas prices, DA load levels, and off-system sales levels. A significant deviation is defined as a magnitude on the order of the difference between Navigant's low and base case assumptions, as presented in this proceeding.
21. In the event that the designated key resource variables do not deviate by a significant event in the next DWR revenue requirement redetermination, the next reassessment of the DA CRS cap levels shall be scheduled to commence two years from the effective date of this order subject to periodic biannual review thereafter until the DA undercollection is eliminated.
This order is effective today.
Dated July 10, 2003, at San Francisco, California.
MICHAEL R. PEEVEY
President
GEOFFREY F. BROWN
SUSAN P. KENNEDY
Commissioners
I will file a concurrence.
/s/ SUSAN P. KENNEDY
Commissioner
I will file a dissent.
/s/ CARL. W. WOOD
Commissioner
I will file a dissent.
/s/ LORETTA M. LYNCH
Commissioner
APPENDIX B
DIRECT ACCESS COST RESPONSIBILITY SURCHARGE
TRACKING ACCOUNT REQUIREMENTS
Core Subaccount
The purpose of this subaccount is to track the debt owned by core direct access ("DA") customers to bundled core customers. Monthly accounting entries will be made as follows:
1. A debit entry representing the CRS obligation of core direct access ("DA") customers.
2. A credit entry representing the CRS payment by core DA customers.
3. A credit entry representing the CRS make-up payment made by core DA customers when they return to bundled service.
4. A debit entry representing the CRS uncollectable from core DA customers that default.
5. A debit entry representing the interest on the combined balance of lines
1 - 5 calculated using the applicable interest rate.
In months where the combination of lines 1 - 5 for the month produce a debit balance, the generation revenue requirement of core DA customers will be decreased by that amount, and the generation revenue requirement of core bundled customers will be increased by the same amount.
In months where the combination of lines 1 - 5 for the month produce a credit balance, the generation revenue requirement of core DA customers will be increased by that amount, and the generation revenue requirement of core bundled customers will be decreased by the same amount.
When the cumulative balance in this subaccount reaches zero, no further entries will be made.
Non-Core Subaccount
The purpose of this subaccount is to track the debt owed by non-core direct access ("DA") customers to bundled non-core customers. Monthly accounting entries will be made as follows:
1. A debit entry representing the CRS obligation of non-core DA customers.
2. A credit entry representing the CRS payment by non-core DA customers.
3. A credit entry representing the CRS make-up payment made by non-core DA customers when they return to bundled service.
4. A debit entry representing the CRS uncollectable from non-core DA customers that default.
5. A debit entry representing the interest on the combined balance of lines
1 - 5 calculated using an applicable interest rate.
In months where the combination of lines 1 - 5 for the month produce a debit balance, the generation revenue requirement of non-core DA customers will be decreased by that amount, and the generation revenue requirement of non-core bundled customers will be increased by the same amount.
In months where the combination of lines 1 - 5 for the month produce a credit balance, the generation revenue requirement of non-core DA customers will be increased by that amount, and the generation revenue requirement of non-core bundled customers will be decreased by the same amount.
When the cumulative balance in this subaccount reaches zero, no further entries will be made.
(END OF APPENDIX B)
CONCURRING OPINION of Commissioner Susan P. Kennedy:
During the Commission's meeting, I supported the Proposed Decision by ALJ Pulsifer concerning the Direct Access Cost Responsibility Surcharge. My concern is that bundled customers are currently bearing unnecessary costs caused by the Commission's delay in suspending Direct Access in 2001. As I have stated previously, I am committed to ensuring that this cost-shift is remedied as quickly as possible and that bundled customers are repaid in full with interest.
The Proposed Decision estimates that bundled customers will be fully repaid within 2 to 5 years. More specifically, San Diego customers will be repaid within 2 years, Edison customers will be repaid in 4 years and PG&E customers will be repaid in 5 years; this is achieved by what the Proposed Decision finds to be a reasonable set of forecast assumptions. This timeframe is consistent with my position that bundled customers' repayment should not be excessive. The Interim Decision in this proceeding estimated that it might have been 15 years before bundled customers were paid back. This was unacceptable to me.
I believe the Proposed Decision by ALJ Pulsifer accomplishes the goal of bundled customer indifference within a reasonable timeframe, while maintaining the CRS cap at a level that does the least harm to California's economy. In addition, attached to this concurrence is my letter to Senators Debra Bowen and John Burton in response to their June 23, 2003 letter to President Peevey regarding the cap for the Cost Responsibility Surcharge.
PUBLIC UTILITIES COMMISSION
STATE OF CALIFORNIA
505 VAN NESS AVENUE
SAN FRANCISCO, CALIFORNIA 94102
SUSAN P. KENNEDY TEL: (415) 703-3700
COMMISSIONER FAX: (415) 703-3352
July 9, 2003
The Honorable John L. Burton The Honorable Debra Bowen
President pro Tempore of the Senate Chair
State Capitol, Room 205 Energy, Utilities and Communications
Sacramento, CA 95814 Committee
State Capitol, Room 4040
Sacramento, CA 95814
Dear Senators Burton and Bowen:
Thank you for your letter of June 23, 2003 to President Peevey regarding our upcoming decision on the cap for the Cost Responsibility Surcharge (CRS). Please know that I share your concern that bundled customers are currently bearing unnecessary costs caused by the Commission's delay in suspending Direct Access in 2001. As I have stated previously, I am committed to ensuring that this cost-shift is remedied as quickly as possible and that bundled customers are repaid in full with interest.
Initial calculations as to the amount of the undercollection and the length of time it would take to fully recompense bundled customers under an interim cap of 2.7 cents/kWh resulted in a repayment schedule as long as 15 years. I said during my confirmation hearing that I believe this excessive repayment schedule is unacceptable, and I would be willing to increase the cap in order to ensure repayment in a timelier manner.
The Commission's Interim Decision approved on November 7, 2002 ordered workshops to be conducted with Commission staff, DWR and its consultants, and with other interested parties in order to develop a more accurate model to determine the estimated undercollection. As a result of those workshops the updated model reduces the estimated undercollection by a significant amount.
In his Proposed Decision, Judge Pulsifer also proposes to apply an interest rate of 4.52% to non-core customers based on their share of the undercollection.
The combination of a more accurate model to determine the undercollection plus the proposed interest rate results in higher total compensation for bundled ratepayers and a greatly reduced repayment schedule without changing the current cap of 2.7 cents/kWh. In fact, the Proposed Decision estimates that bundled customers will be fully repaid within 2 to 5 years. Using this model, San Diego customers will be repaid within 2 years, Edison customers will be repaid in 4 years and PG&E customers will be repaid in 5 years under a reasonable set of forecast assumptions.
Below is a more detailed explanation of the changes that have occurred since the Interim Decision which provide the basis for the accelerated repayment schedule contained in the Proposed Decision:
_ AB 117 directed that assigned cost responsibility to DA customers that migrated between 2/1/01-7/1/01. The Interim Decision only took into account the volume of DA load that migrated from bundled service between 7/1/01 and the 9/20/01 DA suspension date. By contrast, the currently pending Proposed Decision recognizes the additional contribution provided by DA load between 2/1/01 and 7/1/01. Consequently, by spreading the cost obligation over a greater volume of DA load, the per-kWh DA CRS obligation declines and the projected DA CRS payback period for bundled customers occurs sooner with the same 2.7 cents cap compared with assumptions used in the earlier Interim Decision.
_ Certain DWR modeling changes that provide a more accurate and updated reflection of the price that the Investor Owned Utilities (IOUs) will be able to recoup when selling excess DWR energy into the market. Initially DWR was able to recoup 50 percent of the market price, but now the IOUs, since taking over the DWR contracts, are able to recoup 100 percent of the market price. Other modeling changes include the adoption of Low Case Scenarios rather than Base Case Scenarios because the record in this proceeding indicates that these scenarios are more likely to occur given recent market information. Given these changes, DWR undercollections will decrease, thus shortening the time period for payback.
_ The IOUs provided more accurate figures concerning Utility Retained Generation costs for the years beyond 2002, thus allowing DWR to incorporate these estimates into the total portfolio calculations that determine the bundled customer indifference costs. These more precise numbers had the effect of further lowering the DWR undercollection.
The Proposed Decision also includes provisions to monitor and adjust the cap prospectively to the extent there are variations between forecasts and actual costs. Thus, the Proposed Decision does, in fact, incorporate safeguards to assure that the projected timetable for payback of the DA CRS undercollection will remain on track.
I believe the Proposed Decision by Judge Pulsifer achieves the goal of bundled customer indifference within a reasonable time period, while maintaining the CRS cap at a level that does the least harm to California's economy.
Sincerely,
