II. Issues Relating to DA CRS Obligations
A. DA CRS Undercollection Balances as of
December 31, 2005
Parties reached a consensus on the level of DA CRS undercollection balances as of December 31, 2005, even though they disagreed as to the appropriate underlying market benchmark methodology to calculate the CRS undercollections. Under the CRS "indifference" methodology, a market benchmark is used to calculate the hypothetical cost of power that the IOU would have incurred if DA load had continued to take bundled service (i.e., a "DA-in" modeling scenario). The incremental costs attributable to changes in DA load forms the basis to derive bundled customer "indifference."
Parties recognize that it would be difficult and time-consuming to litigate different hypothetical market benchmark approaches. Protracted litigation would increase business uncertainty and delay finalizing CRS obligations. Accordingly, while disagreeing on the underlying methodology, the parties reached a compromise agreement on end-of-year 2005 CRS undercollection balances for PG&E and SCE. Parties agree that the end-of-year 2005 CRS undercollection balance for SDG&E is zero.
Parties reached a compromise to agree on a DA CRS undercollection for PG&E of $30 million as of December 31, 2005, and also reached consensus that PG&E's undercollection is $30 million for DWR bond charge recovery, applicable to DA customers as of the end of 2005. The benchmark prices thus agreed to for PG&E are $51.6/Megawatt-hour (MWh) in 2003, $55.7/MWh for 2004 and $65/MWh for 2005. Parties also reached a compromise to agree on a DA CRS undercollection balance of $522 million for SCE as of year-end 2005. Parties also agreed to an undercollection of $55 million for the DWR bond charge applicable to SCE. The parties also reached consensus on the annual benchmark power price that would have been incurred by SCE to serve DA load for 2003-2005 of $51/MWh, $53/MWh and $64/MWh respectively.9
Parties' calculations of PG&E's end-of-year 2005 CRS balance range from a $140 million overcollection (based on the Market Price Referent (MPR) model)10 to a $156 million undercollection (based on the model currently in effect, utilizing spot purchase and sales prices). The parties likewise calculated a range of DA CRS undercollection levels for SCE as of year-end 2005, from $357 million to $552 million. The $357 million figure, offered by CMTA, CLECA, and AReM was based on a benchmark utilizing the MPR model with provision for "negative" indifference. The $552 million undercollection balance was based on the currently used benchmark based on spot purchase and sales prices.11
PG&E and SCE proposed benchmarks that would place the year-end 2005 undercollection balances within this range. Parties disagreed as to the capacity costs that would have been incurred on a "DA-in" basis for those historic periods. Each utility acknowledged, however, that some capacity-related cost above the cost of spot purchases and sales should be reflected in the benchmark.
Parties' consensus as to year-end 2005 DA CRS balances are within the middle range of values calculated by DA customer parties versus TURN and ORA, and are within the range calculated by PG&E and SCE. We approve the consensus reached on these undercollection figures. Thus, we adopt as a reasonable figure for the PG&E end of year 2005 DA CRS undercollection balance, of $30 million plus the DWR Bond Charge balance of $30 million. We also adopt, as a reasonable outcome, the consensus end-of-year 2005 DA CRS undercollection for SCE of $522 million, and the DWR Bond Charge undercollection of $55 million, to be recovered from DA customers. We conclude that the compromise reached by parties reasonably balances the differing interests involved.
B. Prospective DA CRS Market Benchmark
Methodology Revisions
Parties representing DA customers assert that the current CRS market benchmark, which is based solely on spot market purchases and sales of surplus power, is unduly cumbersome, administratively difficult and slow to provide predictions of the indifference charge. DA parties express concern that under the current methodology, the DWR power charge component of the DA CRS cannot be determined in a timely manner, in part because of the need for true up after the fact. Parties are left without information concerning the level of CRS applicable to their current consumption. The current method also relies on utility power purchase and sales data which the utilities view as confidential and proprietary. Thus, relevant data are not made available to many of the parties that are responsible for paying CRS. The DA Parties propose that the current methodology be revised so that customers can know their CRS liability on a current basis.
Participants in the Working Group discussed alternative methodologies, and to what degree any changes in methodology should be made prospectively. The Working Group reached agreement on a benchmark based on published futures prices to replace the weighted average spot purchase and sales benchmark used in previous CRS model runs. The Working Group recommends that the benchmark be revised annually based on an average of one-year strip power futures quotes for "North Path" (NP) 15 and "South Path" (SP) 15 for each calendar year as published in the Megawatt Daily periodical.12
Parties propose that for purposes of determining the indifference charge for 2006, the average of cost quotes for one-year strips of power be taken during the period November 15 through December 15.13
Parties also agree that a Resource Adequacy / Generation Capacity ("RA/capacity") cost adder should be incorporated for each IOU,14 based on the annual capital costs for a combustion turbine generator. The Parties negotiated RA/Capacity adders in developing the agreed-upon 2005 year-end undercollection balances.
Parties also negotiated RA/Capacity adder values for 2006, since there is no RA/Capacity market available at the present time to provide transparent values.15 For years after 2006, parties propose that the cost quotes for one-year strips be gathered for the period October 1 through October 31 of the preceding year to facilitate timely filings by the utilities. The power costs would be differentiated as between NP 15 and SP 15, and applied to each IOU. These benchmarks are to be grossed up for line losses.
The resulting 2006 market benchmarks developed by the Working Group for the DA non-exempt customers' CRS obligations are $90.12/MWh ($95.52 at the meter) for PG&E and $95.17/MWh ($100.22 at the meter) for SCE. These benchmarks represent the 30-day average, over the period from November 15, 2005 to December 15, 2005, of 12 month forward prices for 2006 at NP 15 and SP15, respectively.
Parties agreed to apply this market benchmark methodology for prospective CRS calculations beginning in 2006 for PG&E and SCE, but differed with respect to application of the revised methodology to prior periods. TURN and ORA, in particular, opposed applying the revised benchmark methodology to past periods. With regard to SDG&E, parties agreed that since its undercollection balance was paid off in 2005, there is no need for further discussion of methodological changes for the 2003-2005 period applicable to SDG&E.
We conclude that the proposed revision in the benchmark methodology to utilize futures-based prices offers advantages over the existing process. The existing benchmark may also understate relevant costs under a variety of market conditions, whereas the revised benchmark more accurately incorporates firm power costs and capacity charges. The need for a RA/capacity value was acknowledged in the Commission's white paper on RA/capacity markets ("California Public Utilities Commission Capacity/Resource Adequacy Markets White Paper," issued August 25, 2005). Such an adder also recognizes the cost of complying with resource adequacy requirements.
The revised benchmark offers the following advantages:
· Reflects procurement practices. A futures-based benchmark reflects current resource adequacy requirements better than model-derived market prices, after-the-fact spot prices, or administrative values from other proceedings. Resource adequacy requirements dictate that the IOUs have 90% of their power forward-contracted or self-supplied a year in advance and rely on spot power for no more than 5% of their resources. The futures market provides publicly available estimates of the price the IOU would have to pay to serve DA/DL customers.
· Minimizes the need for after-the-fact true-ups. The forecasted value of utility and DWR resources will be measured against the benchmark, whether separately or combined. Any difference between these forecasts and actual costs will be accommodated via balancing accounts in the ERRA or DWR Revenue Requirement proceedings, and will not require separate true-up. The benchmark itself can be set at the beginning of the year and not be subject to change. If drastic conditions occur that would prompt significant changes to the CRS market price benchmark, such a modification could be requested.
· Provides Transparency. Published futures prices provide transparency. All interested parties will be able to verify the benchmark value, avoiding the problems otherwise faced by parties who have been precluded from reviewing confidential utility data where the benchmark is based on utility activity in power markets.
· Promotes Simplicity. Using published forward prices, with minor adjustments, is simple, easily verifiable, and avoids using complex models or calculations that are not transparent to establish a market price benchmark.
Based on these considerations, we find the proposed revised benchmark methodology reasonable and hereby adopt it.16
We adopt the Working Group proposal to incorporate the revised benchmark methodology, as discussed above, in the CRS calculation of bundled customer indifference prospectively, beginning with calendar year 2006. Each utility's total power portfolio costs (in cents/kilowatt-hour (kWh)) including both utility retained generation (URG) power and their allocated DWR power costs will be compared to a market price benchmark comprised of the cost of a one-year strip of power plus a RA/capacity adder, as described above.
The DA CRS obligations for 2006 shall incorporate a share of the 2006 DWR revenue requirement adopted in D.05-12-010. The 2006 revenue requirement for "old world" resources is the amount adopted in the utilities' 2006 ERRA proceedings and/or in the most recent base revenue requirement proceeding.17 The sales forecast used to determine the direct access non-exempt customers' share of these costs will be the sales forecast presented in the utilities' 2006 ERRA proceedings, as modified in the 2006 Annual Electric True-Up (AET), for PG&E. The AET is an advice letter process in which PG&E consolidates revenue requirements authorized on January 1 of the following year (see Resolutions E-3906, E-3956 addressing the rate changes effective January 1, 2005, and 2006, respectively). Thus, we clarify that the only modifications to the ERRA sales forecast that PG&E may make in its AET advice letter must have been previously authorized by a Commission order. If the 2006 DWR revenue requirement or utilities' 2006 ERRA/Ongoing CTC revenue requirement is modified, then the calculations described above shall be likewise modified to reflect such changes.
For 2006, we adopt parties' consensus for a RA/capacity cost adder of $8/MWh for SCE and $4/MWh for PG&E, which will be added to the average strip price.
The utilities shall file an advice letter prior to the end of each year or update testimony in their ERRA proceedings to reflect such indifference charge in the CRS adopted for the subsequent year. It is difficult now to predict appropriate levels for the cost of RA/capacity for future years.
The Working Group agrees to reconvene in August 2006 to discuss RA/Capacity adders to be proposed for 2007 and beyond based on publicly reported transactions in a California RA/capacity market or other suitable public index once available. The issue of a suitable adder to reflect RA/capacity value will be revisited for 2007 and beyond as warranted by progress in developing transparent and publicly reported values for RA/capacity. We adopt this proposal and authorize the Energy Division to coordinate and arrange, as necessary, for the Working Group to reconvene within 30 days of this order to address RA/capacity adders, as noted.
C. Use of Uniform Benchmark
for Ongoing CTC and DWR Components
The Parties agree that the Commission should apply a consistent benchmark among each of the IOUs in the treatment of both the ongoing CTC and DWR power charge components. The Parties agreed on a modified methodology to calculate ongoing CTC and DWR Power Charge components of the DA CRS after 2005 with specific market benchmark figures used for DA CRS calculations.
Pursuant to D.03-07-030, the ongoing CTC component of the CRS is determined in the IOUs' annual ERRA proceedings. Ongoing CTC consists of "old world" URG resources as specified in Pub. Util. Code § 367(a)(1) - (6) in calculating above-market costs. 18 Parties have referred to this as the "statutory approach" for calculating ongoing CTC.19
DA load that is not required to pay a DWR power charge is responsible for paying ongoing CTC.20 For DA load responsible for paying a DWR power charge, however, ongoing CTC is blended with the combined effects of DWR and URG sources of power. Regardless of the blended indifference charge amount, the ongoing CTC component is the same as for DA load not responsible for paying the DWR power charge. However, if the ongoing CTC component is higher, the DWR power charge will be lower by an offsetting amount, and vice versa. In D.02-11-022, this was referred to as the "total portfolio method" for calculating the CRS indifference component.
The benchmark used in the calculation of ongoing CTC has been based on the levelized cost of a combined cycle turbine. By contrast, the benchmark for calculating the CRS indifference charge has been the IOU's weighted average price of spot purchases and surplus sales. Under the total portfolio method as adopted in D.02-11-022, the CRS incorporates "above-market" URG costs in excess of a designated market benchmark. Both DWR and URG sources of power are recognized in computing DA cost responsibility for a power charge. The DWR power charge component of the DA CRS is the residual between the indifference charge and the ongoing CTC component.21
Working Group members agree that the market price benchmark should be applied consistently across all relevant CRS components (i.e., both for ongoing CTC and DWR power charges). SDG&E, however, is concerned with additional cost shifting to bundled customers should the market price benchmark be used to determine the ongoing CTC in SDG&E's 2006 ERRA filing. SDG&E thus recommends that the market price benchmark be applied to the DA CRS calculation for 2006, but not to SDG&E's ongoing CTC calculation in its 2006 ERRA filing. PG&E's 2006 ongoing CTC has already been set in the 2006 ERRA filing and is not intended to be modified.
We shall adopt the approach, as proposed above by the Working Group, for calculating ongoing CTC, applying a uniform methodology for all components of the CRS. For 2006, the ongoing CTC calculation shall employ the benchmark based upon the MPR model set forth in SDG&E's and PG&E's 2006 ERRA filings. The ongoing CTC is based on forecast costs, providing for accruals of under- or over-collections in utility ERRA accounts attributable to the cost of resources reflected in the ongoing CTC calculations as well as other costs of "old world URG" at the end of each year.22 Under or overcollections are reflected in the calculation of the DWR Power Charge and ongoing CTC components of the DA CRS in the following year. The DWR revenue requirement allocations to the IOUs already includes the true-ups from prior years, so no explicit adjustment is necessary. The modified approach will be simpler, more transparent, less cumbersome, and will use the same benchmark to calculate ongoing CTC.
D. Treatment of "Negative"
Indifference Charges
Another issue with respect to ongoing CTC involves the question of how to treat "negative" indifference charges, and the extent to which any such "negative" charge should be offset against positive undercollections to reduce overall charges. A negative indifference charge can result where the ongoing CTC amount is larger than the total indifference charge, in order that overall indifference is maintained.
The parties agree that the ongoing CTC adopted in PG&E's ERRA proceeding should be used in conjunction with the indifference calculation. The DWR power charge component of DA CRS will thus be the residual of the Indifference Charge less the ongoing CTC. In PG&E's service territory, the DA non-exempt customers' share of the indifference amount is their proportion of the above market component of the sum of (1) PG&E's 2006 DWR Power Charge revenue requirement plus (2) PG&E's old world generation.
The ongoing CTC will be used in the indifference charge calculation for SCE in the same manner as for PG&E, with the following exception: In the event the benchmark in a given year exceeds the level of SCE's total portfolio power cost for that year, and to the extent there remains a DA CRS undercollection balance, the negative indifference charge shall be reflected in calculating the accruals to the undercollection balance for such year. Because non-exempt DA customers in SCE service territory are subject to a much larger CRS undercollection than DA customers in the other territories, the parties agree that any negative indifference charge that may occur for SCE should offset any existing DA CRS undercollection.
We conclude that parties' proposed treatment of negative indifference charges is reasonable and hereby adopt it. Once the existing CRS undercollection is eliminated, the indifference charge for non-exempt DA customers shall not be permitted to decrease below zero, and no negative balance should be carried forward. In no event shall such a negative indifference charge result in any net payment to customers who have left utility service. However, any accumulated negative indifference amount shall continue to be tracked and applied to any future positive indifference amounts that may accrue in later years of the applicability of the DA CRS. This approach is consistent with D.05-12-045, which permits a negative ongoing CTC to offset a subsequent positive ongoing CTC.
SCE shall track accruals to the CRS undercollection balance and file an advice letter in anticipation of such balance reaching zero to reduce the CRS to the level dictated by the remaining individual CRS elements. Given the parties agreement on the end of year 2005 undercollection balance, with the balance reaching zero by June 2006, PG&E will not be required to track the undercollection balance thereafter.
E. Billing Adjustments Between Core
and Noncore Bundled Customers
Another issue to be resolved involves the proper billing adjustments to "core" (i.e., small bundled customers) versus "noncore" (i.e., large industrial bundled customers) attributable to their past respective contributions toward CRS obligations. Since implementation of the PG&E bankruptcy settlement rates in March 2004, noncore bundled customers have contributed excess revenues to fund the CRS undercollection "loan" estimated in the amount of $325 million. The $325 million excess payments benefited core bundled customers through lower power charges.
Effective January 1, 2006, with the implementation of the Phase 2 bundled rates in PG&E's 2003 GRC, the CRS undercollection "loan" element previously reflected in bundled customer rates was removed.
Effective with its anticipated July 1, 2006 advice letter filing, however, PG&E agrees to adjust bundled customer power charges to reflect the overpayment by noncore bundled customers in the amount of $325 million. This overpayment amount will be recovered from core bundled service customers and credited against the rates of noncore bundled customers over a 30-month period ending December 31, 2008. The equivalent annual increase to core bundled customers will be $130 million with a corresponding annual decrease to noncore bundled customers.
We find the proposed approach reasonable as a means of compensating noncore bundled customers for their excess contributions, and hereby adopt it. On July 1, 2006, January 1, 2007 and January 1, 2008, the applicable adjustment shall be allocated among customer groups on an equal cents per kWh basis, by increasing or decreasing energy related generation surcharge components by an equal amount per kWh. In the residential class, consistent with current practice, the increase will be allocated proportionally to the Tier 3, Tier 4, and Tier 5 surcharges such that the revenue allocated to the residential class is fully collected from the residential class. On January 1, 2009, this differential adjustment to core and noncore bundled rates will be discontinued.
SCE's large bundled noncore customers have been paying an increment to fund the CRS undercollection since August/September 2003 per the SCE "settlement" charges (D.03-07-029). SCE estimates that its large bundled customers paid $701 million toward funding the CRS undercollection by end of year 2005. The parties agree that this amount exceeds the high point of the CRS undercollection balance, and that large bundled customers have overpaid by $95 million.
The parties agree that this "loan" increment should be removed from large bundled customer power charges through the filing of an advice letter which reduces large bundled customer power charges. Further, the parties agree that DA undercollection repayment amounts in 2006 and subsequent years should be credited to small and large bundled customers in the same proportion as such loan amounts were paid by small and large bundled customers.
We find the proposal reasonable as a means of compensating noncore SCE bundled customers for their excess contributions. The $95 million that the large bundled customers overpaid to fund the CRS undercollection "loan" relative to the maximum level of the DA CRS undercollection shall be reimbursed by small bundled customers following the date on which the CRS undercollection balance reaches zero, over a reasonable amortization period.
DA customers who received DA service during the period the DA CRS undercollection was incurred and who subsequently return to bundled service are responsible for repayment of a portion of that undercollection. The Undercollection Charge (UC) for these customers will be calculated by subtracting the sum of the DWR bond charge, historic procurement charge (HPC) (while it is in effect), the ongoing CTC and the DWR power charge component of DA CRS when non-zero, and the negative Power Charge Indifference Adjustment (PCIA) charge when the DWR power charge component of the DA CRS is zero, from the DA CRS cap of 2.7¢ per kWh. The UC will be prorated based on the number of months that such customers received DA service while the DA CRS undercollection was being accumulated.
The DA CRS undercollection for SDG&E was paid off during 2005. SDG&E filed Advice Letter 1726-E-A to set the DA CRS power charge component to zero, effective November 15, 2005. Since the historical undercollection was paid off prior to the November 15 date, an overcollection amount exists that SDG&E proposes to credit from bundled to DA Non-Exempt customers through a separate advice letter filing.
We find this approach reasonable and hereby authorize SDG&E to file an advice letter for this purpose as outlined above.
F. Status of the 2.7¢ DA CRS CAP
In D.02-11-022, the Commission capped the CRS billed to DA customers at 2.7¢ per kWh. The total accrued DA cost obligation exceeded the revenues collected under the 2.7¢/kWh, however, resulting initially in a CRS undercollection. Based on forecasts examined in D.03-07-030, we concluded that the 2.7¢ DA CRS would eventually generate sufficient revenues to pay off the undercollections. As a precaution, we directed that the 2.7¢ cap be subject to biannual review and readjusted, if necessary, to assure the DA CRS undercollection would be paid off no later than the expiration of the DWR power contracts (i.e., in 2011-2012).
A June 2, 2005 ALJ ruling, directed the Working Group to perform the necessary calculations to assess whether, or to what extent, the 2.7¢/kWh DA CRS cap should continue or be revised, consistent with the objectives of D.03-07-030. Accordingly, the Working Group updated forecasts of CRS obligations through 2011,23 subject to alternative assumptions. The Working Group analyzed whether the CRS undercollections from DA customers of each utility were forecast to be fully recovered by the time that DWR contracts expire based on assumptions concerning the 2.7¢/kWh CRS.
DWR, through its consultant, Navigant, Inc., prepared two alternative forecasts of CRS obligations through 2011. The first forecast (in Table 2A of the Report) applies the currently used benchmark and modeling approach. This benchmark is equal to the weighted average purchase and sale of short term power by each utility in a given year and limits the DWR power charge component of the CRS to a non-negative number. The second forecast (in Tables 2B and 2C of the Report) applies the revised benchmark proposed for the period 2006-11, and does not limit the DWR Power Charge component of the CRS to a non-negative number during that period.
DWR's consultant calculated the expected date that the paydown of the DA CRS undercollection is completed for each of the three IOUs. The paydown occurs by the time the DWR contracts expire using either the currently adopted methodology or the parties' proposed methodology. Appendix Table 2A and Table 2C of the Working Group Report summarize the upper and lower estimates for the year that paydown of the CRS undercollection is completed based on data inputs and provided in Appendix C thereof. A comparison of these estimates under both the current and proposed CRS methodology is presented below:
DA CRS UNDERCOLLECTION ESTIMATED PAYDOWN PERIODS
Utility |
Current Methodology * |
Recommended Methodology** |
Year Paydown Completed |
Year Paydown Completed | |
PG&E |
2008 |
2006 |
SCE |
2011 |
2008 |
SDG&E |
2005 |
2005 |
*Assumes Currently Adopted (Navigant) Methodology based on spot (i.e. less than 90 days) prices and sales as Market Price Benchmark.
** Assumes Parties' Recommended Methodology based on use of one-year strips plus a RA/capacity value to set Market Price Benchmark.
Source: Navigant January 24, 2006 model results provided to CRS Working Group.
Based on these calculations, the parties agree that the DA CRS cap should remain at the current 2.7¢/kWh until the undercollection reaches zero for each IOU. Since the CRS undercollection for PG&E is expected to reach zero as of June 30, 2006, parties propose that the 2.7¢ cap be eliminated from the CRS calculation for PG&E after July 1, 2006. For SCE, DA CRS billings are expected to begin drawing down the undercollection in 2006, accelerating in late 2006 with the phase out of the HPC. At expected accrual and collection rates, SCE's combined undercollection balance of $577 million is expected to reach zero before the end of 2008.
We find parties' proposals concerning the phase out of the 2.7¢/kWh CRS cap to be reasonable, particularly since the CRS undercollections are expected to be paid off sooner than previously anticipated in D.03-07-030. We agree that the DA CRS cap of 2.7¢/kWh should remain in effect for SCE until the undercollection reaches zero, which is expected to occur in 2008. For PG&E, we approve parties' recommendation that the 2.7¢/kWh CRS cap be removed as of June 30, 2006.
The SDG&E undercollection of DA CRS obligations was fully paid off in 2005. SDG&E filed Advice Letter 1726-E, and Advice Letter 1726-E-A (replacing Advice Letter 1726-E in its entirety) proposing to suspend the DWR power charge component of the CRS as of November 15, 2005 to avoid large overcollections on an ongoing basis. The Energy Division has approved this advice letter, so that DWR will not receive any power charge revenues from DA customers in the SDG&E territory in 2006. SDG&E may file to reinstate the charge in the future, if necessary, depending on the effects of the adopted methodology and benchmark on future DA CRS charges. SDG&E shall file an advice letter, if necessary, to credit from bundled to DA Non-Exempt customers the overcollection amount resulting from the time lag of when the historical undercollection was paid off in 2005 and when the charge was set to zero on November 15, 2005.
G. Institution of the Power Charge
Indifference Adjustment
Parties propose effective July 1, 2006, to replace the DWR power charge component of the DA CRS, as currently identified on customers' bills, with a PCIA, as defined below. Parties propose that the CRS components be thereafter calculated on a bottoms-up basis rather than on the residual basis established in D.02-11-022. The DWR bond charge, the Energy Cost Recovery Amount (ECRA) rate, and the ongoing CTC will not change on July 1, 2006, nor will the basis for calculating the Franchise Fee Surcharge currently paid by DA customers.
The PCIA is intended to preserve the indifference concept adopted in D.02-11-022 for DA customers who pay the DWR power charge component of CRS. To accomplish this intent, the cost responsibility for ongoing CTC and the PCIA charge for DA customers who pay the DWR power charge would equal their responsibility under the indifference rate concept, plus recovery of franchise fees associated with the DWR revenues collected from direct access customers for the DWR bond charge and the DWR power charge.
We conclude that the proposal to institute the PCIA, as described below, is reasonable, and hereby adopt it. The following provisions shall apply to the PCIA:
· The revenue requirement for the PCIA charge is the difference, positive or negative, between direct access non-exempt customers' share of the indifference amount and their share of the ongoing CTC revenue requirement, plus the franchise fees associated with the revenues collected from direct access customers for the DWR bond and power charges.
· The revenues collected from direct access non-exempt customers under the PCIA charge and the ongoing CTC, combined, are equal to these customers' share of the indifference amount, plus the franchise fees associated with the DWR revenues collected.
· The direct access non-exempt customers' responsibility for franchise fees associated with DWR revenues will be determined based on an estimate of DWR bond charge and power charge revenues paid by these customers, multiplied by the adopted franchise fee factor. No provision for franchise fees associated with DWR revenues will be assessed on direct access customers who pay the DWR bond charge, but not the DWR power charge.
· If direct access non-exempt customers' share of the indifference amount exceeds these customers' share of the ongoing CTC revenue requirement, then the difference is these customers' DWR power charge obligation. If the PCIA charge is positive, it has the effect of decreasing bundled customers' DWR remittance rate, and, for PG&E only, of decreasing bundled customers' Power Charge Collection Balancing Account rate.
· If direct access non-exempt customers' share of the indifference amount is less than their share of the ongoing CTC revenue requirement, then these customers' DWR power charge obligation is zero. If the PCIA charge is negative, it has the effect of increasing bundled customers' ERRA costs (for PG&E) or URG rates (for SCE). The PCIA charge (including franchise fees associated with DWR revenues collected) will be set in proportion to the ongoing CTC.
The sum of the PCIA component and the ongoing CTC component equal the CRS indifference charge, calculated using the same market benchmark as used for ongoing CTC. SDG&E's ongoing CTC calculation in its 2006 ERRA filing shall not be subject to the market benchmark from the DA CRS Working Group.
Based on parties' benchmark calculations, the average resulting PCIA charge for 2006 for PG&E is negative 0.306 cents per kWh and for SCE is negative 1.805¢ per kWh.24 We adopt these figures for 2006 as being reasonable.
H. Process for Future Updates
of CRS Components
Under current procedure, the DWR power charge component of CRS obligations is determined in this proceeding (R.02-01-011) while overall DWR revenue requirements and allocations are determined in a separate proceeding (currently in A.00-11-038 et. al.). By August of each year (or more frequently, if necessary), DWR generally notifies the Commission of its revenue requirement for the upcoming year. The Commission generally issues a proposed decision by November of the same year, which includes an inter-utility allocation of DWR costs and true-up of DWR costs for the year prior. For instance, in August 2006 DWR will notify the Commission of its 2007 revenue requirement and provide data for the Commission to calculate any inter-utility true-up for 2005.
Parties propose that for future determinations of the DA/DL CRS, each IOU file an advice letter at the end of each year or file an update to its ERRA to establish the indifference charge for the subsequent year, as well as the PCIA and ongoing CTC components of the DA CRS. This filing would be based on information contained in the DWR Revenue Requirement proceeding (presently A.00-11-038 et al.) and the utilities' ERRA proceedings, and subject to the data requirements in Section IV of the Report.25
We find this procedural approach reasonable and hereby adopt it. Thus, with the adoption of these procedures for determination of CRS requirements in the ERRA proceeding, there is no need to keep this proceeding open for subsequent determinations of CRS for DA or DL customers. With disposition of remaining issues concerning MDL CRS methodologies as discussed further below, we shall close R.02-01-011.
9 The parties agreed that these benchmark prices are for the sole purpose of setting the year-end 2005 DA CRS undercollection and are not to be used as precedent in any other Commission proceeding.
10 The MPR model was developed and reviewed in the Renewable Portfolio Standard proceeding (Rulemaking (R.) 04-04-026) and adopted in D.04-06-15 and
Resolution E-3942. The MPR model was used in the calculation of the CTC benchmark in PG&E's 2006 Energy Resource Recovery Account (ERRA) proceeding. (Application (A.) 05-06-007, D.05-12-045.)
11 The Tables in Appendix 2A and 2B of this order show the undercollection results for PG&E and SCE based on different benchmark methodologies.
12 A second alternative approach to deriving the benchmark was discussed based on one-year forward prices for natural gas at Henry Hub, converted to electricity prices using the methodology for calculating the MPR. The benchmarks estimated in this fashion were $55.5/MWh in 2003, $60/MWh for 2004 and $66.4/MWh for 2005.
13 The power costs reflect a 6 X 16 product, and the price will be multiplied by a factor of 0.87 to convert the power cost to a 7 X 24 product price.
14 SDG&E prefers a gas futures-based benchmark and has not yet determined whether it will agree to a power futures-based benchmark.
15 RA/capacity adders for 2006 were negotiated as part of on-going workshop report discussions. Proposals have ranged from approximately $1.20/MWh-$9.60/MWh. The lower value of this range is based on PG&E's proposal to use the going-forward fixed cost needed to maintain a specific 300 MW steam unit on the PG&E system net of the energy benefit received from this unit. The higher value is based on CLECA, CMTA, and AReM's proposal to use the annual carrying cost of a combustion turbine.
16 A detailed description of the adopted benchmark methodology is set forth in Appendix 1 of this order.
17 SCE agreed to file an advice letter to update the DA CRS calculation following the issuance of a final general rate case (GRC) Phase 1 decision if that decision results in a change in the generation revenue requirement of more than 2% from that reflected in the current calculation. A similar 2% update rule shall apply to future changes in the IOUs' generation base revenue requirements.
18 "Old World" URG refers to contracts and generation resources acquired prior to January 1, 2003. "New World" URG, by contrast, refers to contracts and generation resources acquired by the IOUs since January 1, 2003, when they resumed responsibilities, previously held by DWR, for power procurement.
19 Prior to their 2006 ERRA/ongoing CTC proceedings, both PG&E and SCE had incorporated the CRS indifference calculation for URG adopted in D.02-11-022 in their annual ongoing CTC revenue requirement. Under this approach (referred to by parties as a "total portfolio" approach), all "old world" IOU resources were included in the above market cost calculation, not just the ongoing CTC costs covered under
§ 367(a)(1) - (6). The Commission approved the inclusion of the CRS indifference charge in PG&E and SCE's 2004 and 2005 ongoing CTC revenue requirement. However, in response to allegations by parties that the Commission had adopted two "methodologies" for calculating ongoing CTC, the Commission ordered that only ongoing CTC be included in future IOU ERRA/ongoing CTC revenue requirement applications. (See e.g., D.05-12-045 and D.06-01-035.) Thus, to eliminate any future misunderstanding, we note that "statutory CTC" is the same as "ongoing CTC" and does not represent one of several ways to calculate ongoing CTC.
20 In D.02-11-022, that portion of DA load that had been continuously on DA status prior to February 1, 2001 was not required to pay a DWR Power Charge.
21 See computational example in Appendix 1A, as prepared by DL parties. No other Working Group participants have disputed its accuracy.
22 If the decision in an IOU's GRC or similar base revenue requirement proceeding changes that utility's generation revenue requirement by more than 2% in mid-year, the utility shall file an advice letter to update the DA CRS to reflect that change in generation base revenue requirement. This adjustment is necessary because generation base revenue requirements are not trued up to actual costs in the same manner as ERRA and DWR costs.
23 D.03-07-030, Finding of Fact #3, stated, "a reasonable criterion 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." Although the last DWR contract does not actually expire until 2015, the vast majority of contracts expire by 2011.
24 This negative 1.805 cents figure is subject to adjustment should the Commission adopt the ALJ's recommendation with respect to treatment of administrative costs in Edison's 2006 GRC.
25 These data requirements are adopted as set forth in Appendix 2 of this order.
