Section 366.2(d)(1) of AB 117 provides that the costs associated with CCA's procurement of power for local residents and businesses must not require remaining utility customers to assume additional costs, that is, those power procurement costs that would be unavoidable when the utility loses customers to the CCA. In that way, AB 117 anticipates "ratepayer indifference" to the CCA program. No party disputes this principle, although how to calculate and implement the CRS raises some complex and somewhat controversial related issues, discussed below.
The Commission has already adopted such surcharges for other types of customers who stop taking power from the utility, including those who depart from all utility services and generate their own power, direct access customers and departing load customers of municipal utilities that reduce their demand from the utility in favor of other power procurement resources. Where possible, we apply the lessons learned and the policies adopted in those cases to the CRS we adopt for CCAs.
A. The CRS Model
All parties agree that AB 117 requires the CCA CRS to include a variety of costs incurred on behalf of CCA customers prior to their transferring to the CCA. Such costs include (1) costs associated with power contracts and bonds entered into by DWR during the energy crisis; (2) utility power costs, including those of utility retained generation, purchased power and other commitments in approved resource plans; and (3) CTC and historic revenue undercollections and credits applicable to the customer at the time the CCA transferred the customer. No party disputes these cost elements.
The CRS model that was the basis for most discussion was presented by DWR and operated by Navigant Consulting. In general, DWR recommends that the Commission adopt for CCAs its CRS methodology, which is referred to variously as "CCA-in/CCA-out," "total portfolio" model or the "indifference fee" approach. This methodology analyzes the liabilities that would otherwise be assumed by bundled utility ratepayers when the CCA begins serving local customers. Those liabilities would then be incorporated in the CRS so that bundled utility ratepayers are not penalized by the utilities' loss of energy customers. This methodology is the one adopted in D.02-11-022 for direct access customers. It is a forecast of those DWR power costs that are assumed by PG&E, SCE and SDG&E and that are expected to exceed market prices. The CRS will fluctuate according to changes in market prices, that is, as prices goes up, the CRS and related liabilities will fall. Under AB 117, these power cost liabilities must be incorporated in the CRS so that bundled utility ratepayers do not assume liabilities relating to the utilities' loss of energy customers to CCAs. The methodology DWR presented in this proceeding is the one adopted in D.02-11-022 for direct access customers.
In a memorandum to the Commission dated July 9, 2004, DWR presents several recommendations on how to implement the CRS in a way that prevents cost-shifting and promotes administrative simplicity and revenue certainty, where applicable. It did not present a final proposed cost allocation in this proceeding but agrees to work with the Commission and utilities following its resolution of outstanding controversies in how to set the CCA CRS.
The utilities and most parties support DWR's "CCA-in/CCA-out" methodology and truing up the difference between the forecast and actual costs annually. SDG&E recommends removing from DWR's illustrative calculation SDG&E's CTC and bond charge, nonbypassable components applied to the direct access customers that are not relevant to the calculation of a CRS for CCAs. SDG&E also argues against a cap on the CRS, which the Commission applied to direct access customers.
Discussion. No party challenges the utilities' proposal with regard to the types of costs that should be included in the CRS or even the methodology DWR presents. The methodology has been subject to considerable scrutiny in other proceedings and it is reasonable to adopt it here.
The CCA CRS should be calculated separately from the CRS for direct access customers to reflect the utilities' concurrent power purchase liabilities, which may differ from those incurred in previous years. We direct the utilities to impose the CRS on new customers as well as existing customers because both would have been required to assume those liabilities if they had taken service from the utility rather than the CCA. In addition, the CRS should incorporate any refunds to or credits associated with the accounts, bond charges and power purchase contracts that are subject to CRS treatment, which SCE proposes and no party opposes. Consistent with our view that the CRS for each CCA should reflect the costs incurred on behalf of CCA customers, the CRS for each CCA in each period should reflect the cost savings or refunds associated with commitments made on behalf of those CCA customers. The CRS should not include any avoidable costs, such as ISO charges for ancillary services.
B. CRS "Vintaging"
The parties addressed whether and how the CRS should change at regular intervals to reflect changes in utility portfolios that might increase or reduce power purchase liabilities, an exercise the parties refer to as "vintaging." The CCA would then assume liability going forward for only those DWR and utility liabilities that were current at the time the CCA began its operations. The utilities and other parties generally agree that vintaging this portion of the CRS is appropriate to reflect the utilities' prevailing power cost liabilities and to assure CCA customers pay for those resource commitments, and only those commitments, that were incurred on their behalf. PG&E would defer vintaging until there has been more progress in resource planning policies and practices.
We agree with the parties that vintaging the CRS for each generation of CCA would provide equity between CCAs because none would have to assume the stranded power costs incurred on behalf of another. A vintaged CRS may also provide the appropriate forum for updating utility power liabilities that are incurred in the future and would be otherwise unrecoverable if customers are served power by a CCA. On the other hand, we are concerned that vintaging as we understand it may create a complex regulatory process by requiring the Commission and the parties to review potentially many CRS charges, each of which would be updated annually. We do not think any of the parties would endorse such an elaborate regulatory effort if there were options that would obviate the need for it. We also wonder whether the existing proposal would permit dramatic fluctuations in the CRS over time, a type of financial uncertainty that is a significant concern to parties representing CCAs and prospective CCAs. Moreover, we are not certain precisely what "vintaging" would entail on the basis of the existing record and whether in fact the parties agree on what it would entail.
For these reasons, we state a predisposition toward the concept of vintaging but will defer adopting a way of allocating CRS liabilities until after we have explored the matter in more depth in Phase 2. As a preliminary matter, the approach we ultimately adopt for how to develop a CRS for each generation of CCA should, to the extent possible, balance several criteria. It should balance accuracy, equity among different generations of CCAs, administrative simplicity, and certainty for CCAs and the utilities. We also anticipate that each CCA's CRS liability would terminate at some point. We are also interested in an approach that would permit the utilities to develop the forecasts themselves, to the extent possible rather than relying on DWR. One possible model is to adopt a package of liabilities for each generation of CCA that would be fixed (although the dollar liability would vary with changes in market prices) and could therefore be paid off by a forecast date. We also need to consider specifically what liabilities would be included in each generation of CRS and how to incorporate future procurement obligations in any future CRS. We need to consider whether CRS liabilities would be in all cases paid in a charge per kilowatt-hour or whether a CCA could negotiate a quicker pay off CRS liabilities. There may be other options to explore.
We will direct the ALJ to convene workshops and, if necessary, additional hearings on this topic. Because the parties appear to agree on the underlying principles of how to approach this issue, we encourage them to work together to develop a detailed proposal that meets the several criteria we have identified here and which reflects the parties' various and common interests.
C. Utility Resource Planning
The creation of CCAs and transfer of utility customers to them will change the utilities' load and resource plans. The cut-off date for what is included in the CRS for each "vintage" was a matter of considerable concern to all parties. Prospective CCAs want to limit their liability for power commitments made by the utility on behalf of CCA customers. Utilities on the other hand are concerned about system reliability and financial risks to their bundled customers.
SCE proposes that CCA customers be required to pay for all utility procurement incurred up to the date that service is switched from utility service to the CCA. LGCC opposes this, arguing that Section 366.2(f)(2) permits only the recovery of "unavoidable" electricity purchase contract costs that are "attributable to the customer."
PG&E would have the Commission vintage CCA charges only after all long-term procurement matters have been resolved, including those implicated in Phase 2 of this proceeding, and the procurement docket, R.04-04-003. PG&E is especially concerned that issues relating to switching be resolved so that PG&E can plan for procurement contingencies in its role as provider of last resort.
LA/CV and most parties agree that the utility and its bundled customers should assume full responsibility for any future procurement costs and risks assumed after the CCA is established. LGCC would go further by excluding from the CRS costs from any contracts signed after the passage of AB 117.
LA/CV express concern that SDG&E, and potentially other utilities, may fail to consider changes in their resource plans to reflect future changes in load resulting from CCA operations. LA/CV argues that SDG&E has already failed to reflect CCA load in its recently-signed power contracts (approved in D. 04-06-011) even though it was aware that the City of Chula Vista had created a CCA in mid-2001. It argues that SDG&E appears to be racing to sign contracts in a manner that will force CCAs to subsidize such purchasing decisions.
Discussion. The objective of AB 117 in requiring CCAs to pay a CRS is to protect the utilities and their bundled utility customers from paying for the liabilities incurred on behalf of CCA customers. Our complementary objective is to minimize the CRS (and all utility liabilities that are not required) and promote good resource planning by the utilities.
We agree with the parties that the CRS must change to reflect changes in the utilities' resource portfolios. We take PG&E's concerns seriously with regard to the many elements of long-term planning that are implicated by the CCA program. On the other hand, PG&E seems to argue that implementing various rules will make its forecasting job substantially simpler. However, we are not convinced that implementing a switching rule and finalizing a single long-term resource plan will alone substantially reduce forecasting uncertainty. Utility resource plans will need to balance supply security with enough flexibility to accommodate many market contingencies in addition to those associated with the CCA program, as we have recognized. Because it would ideally recognize and anticipate changing markets and supply sources, resource planning will necessarily be an ongoing, interactive exercise.
We do not agree with LGCC that the CRS should exclude any energy commitments entered into following passage of AB 117. As long as the utilities have made reasonable assumptions about future electricity demand, the CRS must include all stranded costs that occur when customers transfer their accounts to the CCA. Although some cities and counties have formed CCAs or expressed an interest in forming CCAs, the utilities have had little basis on which to forecast reductions in load that would occur as a result of AB 117.
On the other hand, SCE's proposal to include in the (vintaged) CRS all contract costs incurred up to the date customers transfer to the CCA is not consistent with the law. There will surely be circumstances where contracting for more energy, assuming all CCA load, would be "avoidable" and where those commitments would not be "attributable to the customer." We share the parties' concerns that the utilities must recognize CCA load in their resource planning and should not sign contracts that might create new liabilities for CCA customers and utility customers where available information suggests the power might not be needed. We understand the utilities face a difficult balancing act by assuring adequate and reliable power supplies in amounts that reflect forecasts that are changing constantly. However, the utilities are accustomed to using available information to forecast customer demand and should incorporate CCA load losses into their planning efforts, just as they would include any other forecast variable related to expected changes in supply or demand.
We will address these matters in more depth in the utilities' resource planning applications and related dockets. With this in mind, we state our commitment to continue to coordinate CCA program elements with our oversight of utility procurement portfolios and resource planning. This should minimize unneeded power purchases by utilities and therefore the CRS.
D. Unbundling of CRS Components
LGCC proposes the CRS be unbundled in order to permit a comparison of each component of the CRS with market benchmarks. LGCC expresses concern that the model currently cannot be understood by any except modelers at DWR and Navigant. Unbundling would make the model components more transparent. LGCC believes unbundling would obviate the need for frequent true-ups and will promote better decision-making by CCAs.
TURN, ORA and SDG&E support some unbundling on customer bills. SDG&E bills for past power purchases with a Competitive Transfer Charge (CTC) that is separately stated on customer bills and therefore need not be included in the CRS. SCE proposes that the Commission confirm that its current CTC would be imposed on CCA customers. PG&E has a "historic utility charge," which should be identified on customer bills the way SDG&E has unbundled its CTC.
Discussion. We understand LGCC's concern that the CRS model is not transparent to most and that identifying cost components individually may provide CCAs and customers with more of the kind of information they need to make good decisions. On the other hand, we cannot tell from the record exactly what LGCC's proposal entails beyond requiring the utilities to break down the CRS components according to the types of costs they incur. LGCC does not make a convincing case that we should abandon DWR's model for forecasting those components.
In order to address some of LGCC's concerns with regard to the components of the CRS relating to utility costs, we direct the utilities to provide to Energy Division staff and any party so requesting that information calculations of each utility cost component, a description of each related assumption, and an explanation of how each component conforms to this decision. The remaining components would relate to DWR costs. The Energy Division will consider requests for a workshop to discuss the information the utilities and DWR provide. To the extent such information is claimed to be confidential, the utilities and DWR may require parties to sign nondisclosure agreements.
We will also direct the utilities to propose a tariffed offering that unbundles CRS elements on CCA customer bills that are not already unbundled or which they do not plan to unbundle.
E. Credits or Liability for "In-Kind" Power
The CRS is intended to collect liabilities associated with power purchase contracts entered into by DWR and the utilities. These liabilities would become "stranded" if utility customers become CCA customers in the absence of the CRS. Because CCAs would be paying for this power, some suggest they should be entitled to take delivery of the power.
Cal-CLERA and King's River propose that the Commission order the utilities to provide energy to the CCAs in proportion to their CRS liability. SDG&E and SCE argue that CCAs are not entitled to these utility assets and that AB 117 does not suggest this is an option. SCE recommends that if the Commission were to require an assignment of power to the CCA that it should require the CCA to take all power assigned to CCA customers rather than only the power that is priced above market. SCE and DWR believe there may be administrative difficulties transferring power liabilities to CCAs. PG&E argues that it cannot assign a power contract or part of it to another entity.
Discussion: Prospective CCAs would like to receive power from specific DWR contracts, which constitutes a physical allocation. The physical allocation of power from the DWR contracts to CCAs, to the extent it is possible or beneficial, may entail some negotiations and the development of service agreements. We assume that financial liability for the DWR contracts should remain with DWR, and do not believe it is possible for DWR to assign its contracts to CCAs. In any event, we should not pass on an opportunity to minimize the state's liability for overpriced and otherwise stranded assets on that basis. We doubt whether the Legislature in its enactment of AB 117 would endorse a circumstance wherein an entity of local government and its citizens are required to pay for energy supplies they do not receive and which could be provided at little or no cost, assuming this is a possible scenario.
We do not understand the utilities' view that a CCA who takes part of a contract obligation should have to assume the entire contract obligation. If that proposal is intended to present a deterrent to or penalty for the economic use of an asset, we would decline to adopt it. PG&E's argument that it cannot assign only a portion of a contract "since scheduling and dispatch rights under a contract generally reside with only a single party" seems to be circular reasoning: it cannot assign rights to a portion of the contract because it has the only rights to the contract. DWR recognizes PG&E's concerns with regard to the administration of allocating contract portions to CCAs but recommends the Commission explore this approach as a way to mitigate stranded costs.
At this point, the record does not allow us to reach any final conclusions about the extent to which CCAs can or should be able to take power from existing contracts. As a general matter, we believe a CCA should have the opportunity to take delivery of any portion of a DWR or utility contract for which it pays through the CRS. On the other hand, we are not sure what this might entail. Accordingly, we will consider this matter further in subsequent workshops or hearings in Phase II of this proceeding.
F. Open Season
SDG&E proposes that the utilities conduct an open season during which a CCA or prospective CCA would be required to commit to a specific load forecast identifying the load expected to be served by the CCA. The open season would be conducted before the utility buys power for that load and according to the utility's resource planning schedule. The objective would be to mitigate the possibility that both the utility and the CCA would be procuring power for the same group of customers. SDG&E proposes that the CCA assume liability for differences between its load forecast and actual demand (and presumably be credited in cases where the difference results in lower costs as well). The proposal presumes that the utility would act as provider-of-last resort in cases where the CCA did not have access to adequate power. If the Commission were to adopt this proposal in concept, SDG&E would provide more details about its operation in Phase 2.
CCSF, ORA, SCE, and TURN support this idea in concept. TURN suggests the utilities be permitted to impose penalties for a CCA's failure to meet its commitments with regard to the timing and demand forecasts of its operations. LA/CV believes an open season would be duplicative of long-term resource planning efforts. It also raises a concern that the CCA's failure to meet its commitments may be due to the failure of the utility to perform services for which the CCA pays.
Discussion. We agree with the parties who advocate in favor of an open season as a way to promote sound resource planning by the utilities and the CCAs, and also facilitate operations. SDG&E's proposal for CCAs to assume the risks associated with forecasting errors is reasonable and similar to the balancing fees we have approved for gas transportation tariffs. Utility tariffs should include fees that bear a reasonable relationship to the costs the utilities will incur as a result of the suspension of the CCA's initial operations or to schedule power on behalf of CCAs. We expect utility tariffs to provide for the forgiveness of such penalties for CCA non-performance if the reason for that non-performance relates to a failure of the utility to meet its commitments to the CCA in any way, for example, with regard to connections, transfer of customer information, mailing of customer notices or any other operational activity.
Although we state our support for an open season here, we agree with the parties who suggest this is a matter that requires further exploration in Phase II of this proceeding. For that reason, we include the matter in Phase II and expect to develop and adopt the details of an open season in a subsequent order. However, we do not intend to delay the initiation of service by CCAs while we are considering this matter. In the interim, the utilities must accommodate CCAs that wish to begin delivering power.
The issue of whether and how the utilities have obligations to CCA customers as "providers of last resort" is a matter we consider in R.04-04-003. We direct the utilities to submit draft tariffs for such services as back-up power and balancing services and will address these matters further in Phase II of this proceeding.
G. Responsibility for CRS Liabilities
LA/CV and CalCLERA raise the issue as to whether the CCA or its customers should be responsible for the CRS. Whether the CCA or its customer receives the bill and pays it, the customer will ultimately assume the cost. The issue is whether the CCA or the utility should determine cost allocation and the arrangements for payment if the CCA assumes liability for the payments. DWR, the utilities and bundled customers would be indifferent on this issue as long as the utility and DWR received the CRS revenues. SCE, however, believes these utility liabilities should be billed directly to customers so the Commission is certain that the way they are allocated is just and reasonable. DWR expresses concern that the assumption of this liability by a CCA may have some implications for its bond and power charge obligations.
Discussion. AB 117 requires the CRS charge to be imposed directly on the customer. Section 366(d)(e) and (f) refer to the obligations of "retail end-use customers" assuming the costs of the components of the CRS in "commission-approved rates." Because of DWR's expressed concern, we adopt the utilities' proposals for billing customers directly for the CRS.
H. Collection of Amounts Relating to CRS Exemption for Baseline Customers
Water Code Section 80110 provides that so long as DWR is recovering its energy procurement costs, the total rate for residential customers with usage below 130% of baseline amounts must remain at the same level as those rates in effect on February 1, 2001. This subsidy is referred to as the "Baseline Exemption." Cost liabilities adopted since that time have been allocated to other customers. The resulting shortfall has been allocated in equal portions to residential, commercial and industrial customers. This subsidy program created by AB1X does not apply to CCAs, although they could voluntarily implement it by structuring their energy cost recovery so that baseline customers do not pay the CRS. Bundled service customers, however, should not have to subsidize residential CCA customers. All parties agree this subsidy should be assumed by the CCA, not bundled customers.
Each utility proposes a different way to implement the subsidy for baseline customers. PG&E is concerned that this subsidy to low-usage customers would promote "cherry picking" of customers by CCAs. To ameliorate this possibility, PG&E would calculate each CCA's CRS liability by estimating the composition of the CCA's customer usage. SCE would allocate the costs of the residential baseline subsidy in a rate component that would apply equally to bundled service customer, direct access customers and CCA customers. SDG&E's proposal is similar to SCE's except that SDG&E would bill CCA customers for the CRS as a nonbypassable surcharge, and unbundle the same amount on its own bundled customer bills in order that no customer may escape liability for related costs.
LGCC and CCSF support SCE's proposal. CCSF and SCE oppose PG&E's proposal to impose the CRS according to the composition of a CCA's customer base. CCSF believes this disparate treatment of CCAs on the basis of customer class characteristics would violate the prohibition on cost-shifting. SCE objects to SDG&E's proposal on the basis that its objective to collect CRS revenues is more readily implemented without the need for another nonbypassable surcharge. SDG&E comments that PG&E's proposal fails to recognize that the AB 1X requirement applies to CCAs as well as utilities and may violate AB1X for that reason.
Discussion. As a preliminary matter, we make no determinations about whether and how a CCA should apply a baseline rate. Because CCAs would be governmental agencies that are accountable to the public, they can be entrusted to design cost allocation according to the needs of their local communities and the types of liabilities they incur with respect to allocating the revenue shortfall. SCE's proposal has the benefit of administrative simplicity and avoids cost-shifting. SDG&E's proposal raises the issue of whether it is wise to add another line item to customer bills, especially for a cost component that is so small and may, as SCE suggests, be reduced further in the future. Although the parties complied with the ALJ's directive to consider the baseline issue, we believe the scope of this proceeding is not broad enough to resolve a rate design issue that goes beyond costs and revenues related to the CCA program. For that reason, we do not resolve the baseline issue here. Instead, we herein direct all three utilities to propose ways to allocate the costs of the subsidy in ratemaking proceedings such as general rate cases, rate design windows or a baseline application.
I. Exclusion for Norton Air Force Base
IVDA seeks an exemption for Norton AFB from the DWR cost component of the CRS in order to promote economic development at the air force base. It justifies its request for an exception on the basis that SCE did not include Norton's load in the demand forecast DWR relied upon when it purchased power that is subject to CRS treatment. IVDA argues its proposal is consistent with the "fair share" principle adopted in orders addressing similar issues for municipal departing load (D.03-07-028) and customer generation departing load (D.03-04-030). IVDA argues that granting an exclusion for Norton AFB is consistent with the prohibition against cost-shifting because DWR did not incur any power costs on behalf of Norton. IVDA believes the prohibition against cost-shifting should be applied consistently to permit a CCA or its customers to receive the benefit of that prohibition as well as assume the liabilities. LGCC supports IVDA's proposal for reasons similar to those put forth by IVDA.
The utilities oppose this exclusion on the basis that it requires other CCA customers or utility customers to make up the difference in contravention of AB 117. PG&E argues the exclusion would be inconsistent with Commission policy on exclusion from DWR bond costs and that DWR forecast no CCA load prior to entering into subject contracts. SCE admonishes IVDA for seeking to capitalize on base closures and argues that IVDA is seeking an exclusion for more acreage than that which comprised Norton AFB.
Discussion. SCE's forecasts to DWR, and upon which DWR relied in signing purchased power contracts, assumed that Norton AFB would close and therefore demand no power during the periods in question. Since that time, IVDA plans to build out at the site.
Because DWR did not purchase any power on behalf of Norton AFB, ratepayers would not be harmed if IVDA is excluded from the DWR component of the CRS. IVDA's interpretation of AB 117 that the prohibition on cost-shifting should work in both directions is reasonable. Although we do not assume the statute requires this reciprocal treatment, we believe we can lawfully permit an exclusion or exception to the CRS requirements on that basis.
The acreage which would apply in this case is not relevant. The exclusion would apply to the load removed from the SCE forecast. For all the forgoing reasons, we direct SCE to exclude IVDA from the DWR component of the CCA CRS for amounts equal to the reduction in demand included in SCE's forecast to DWR. In its brief, SCE states this amount is 523 MWh or 120 kW capacity. IVDA should be permitted to confirm this amount or challenge its accuracy in Phase II of this proceeding.
We clarify here that IVDA's adopted exemption from the CRS applies only in the event IVDA establishes a CCA pursuant to the requirements of AB 117 and proceeds to purchase power for residents and businesses located on the Norton Air Force Base. If IVDA seeks an exemption from the CRS generally, it must seek that exemption in R02-01-011.
J. CRS True-Up
The utilities, DWR, and CCSF propose that the CRS be "trued-up" annually so that undercollections or overcollections are recognized in the subsequent year's CRS. These credits or debits, with interest, would be applied equally to all CRS vintages. PG&E illustrates the risks of forecasting a CRS by observing that DWR estimates for PG&E for 2006 ranged from about $21/MWh to about $51/MWh, depending on market conditions.
CalCLERA and Local Power argue for a forecast CRS for which the utility would be liable. Local Power interprets AB 117 to require the Commission to set a CRS on the basis of a forecast and retain the CRS from year to year. Related to this, several parties proposed a cap on the CRS or a mechanism that would effectively cap the CRS. CCAs and prospective CCAs argue that the cap will provide much-needed certainty. Local Power appears to advocate that the utilities' shareholders should assume the risk associated with a cap. The utilities, ORA and TURN oppose a cap, arguing that a cost cap could cause unlawful cost-shifting or expose shareholders to risks AB 117 does not intend.
Discussion. AB 117 does not refer explicitly to a true-up of the difference between a forecasted CRS amount and actual CRS liabilities, which can only be precisely identified retrospectively. Local Power argues that the statute prohibits a true-up. It refers to Section 366.2(c)(7), which states that "After certification of receipt (from the CCA) of the implementation plan and any additional information requested (of the CCA), the commission shall then provide the community choice aggregator with its findings regarding any cost recovery that must be paid by customers of the community choice aggregator to prevent a shifting of costs..." This language might suggest that the Commission would inform the CCA of a specific total dollar amount for energy contract liabilities.
However, other elements of the statute are clear that utility bundled customers must not have to pay for energy contract liabilities that were incurred on behalf of customers that are ultimately served by the CCA. This is the provision referred to as the "prohibition against cost-shifting." For example, Section 366.2 (c)(5) refers to developing a cost recovery mechanism that would "prevent shifting of costs." Section 366.1(d)(1) states the Legislature's intent "to prevent any shifting of recoverable costs between customers." Section 366.2(f)(2) directs the Commission to set a CRS based on "costs attributable to the customer." Here, the statute states a broad intent to prevent cost-shifting and subsequently refers to that intent clearly and explicitly in sections implementing the cost in question, namely, the CRS. Although the statute never refers to a true-up by any name, it assumes a true-up by implication: because a forecast of the CRS will never exactly match actual costs, setting the CRS according to a forecast that could not be trued-up would permit shifting costs between CCA customers and utility bundled customers. In contrast, the section that might imply a fixed and specific dollar liability is referred to obliquely in a section that describes a transaction between the Commission and the CCA, namely the Commission's duty to "inform" the CCA of its cost liability following review of the CCA's implementation plans and other information. In a case, such as here, where the statute might appear to present a conflict, we must look to the statute as a whole and follow that requirement that is articulated in the statements of Legislative intent and supported by explicit language in subsequent sections of the statute.
We find that AB 117 requires that CCA customers pay the actual rather than forecasted costs that are components of the CRS. We agree with the utilities and consumer groups that the CRS should be trued up annually. An annual true-up is reasonable because it will mitigate the possibility of large swings in CRS levels that more accurately match costs with cost causation than true-ups over longer periods. Similarly, we do not adopt a CRS cap for CCAs. Whether or not the idea is sound from a policy perspective, we believe AB 117 prohibits a rate recovery mechanism that might result in cost-shifting between customers and we would not put the utilities at risk for investments that are stranded for reasons they could not control or foresee.
The utilities should enter CRS costs and revenues into relevant balancing accounts, as they propose, which will be reconciled annually in proceedings addressing the CRS for direct access customers. At this time, the appropriate docket is R.02-01-011.
K. CRS Implementation
Having considered the general methodology and cost allocation treatment for the CRS, we must decide how to implement it. The utilities do not assume the Commission will adopt a number in this phase of the proceeding, preferring to address the issue again and in more detail in subsequent hearings. DWR presented illustrative CRS values but explicitly does not endorse any at this time. DWR offers to work with the utilities to develop final values after the Commission resolves outstanding issues about the CRS methodology and its application. Only one party proposed a specific CRS number for the Commission's consideration. CCSF proposed the Commission adopt a 1.5 cent CRS for a two-year period, which it estimated using DWR's methodology and forecast gas prices. CCSF originally referred to this number as a "cap" but clarifies its view that it should be subject to subsequent modification to reflect market conditions and power commitments, consistent with the utility proposals. CCSF argues that CCAs need some early indication of the level of the CRS for planning purposes.
PG&E argues that CCSF's CRS is substantially below those DWR presented using various market scenarios and was not proposed for SCE or SDG&E. PG&E argues that this phase of the proceeding was not designed to develop an actual number for the CRS.
Discussion. We clarify first that one objective in Phase 1 of this proceeding is to quantify the costs of service and the CCA CRS. This objective should be clear on the basis of the parties' discussion at the prehearing conference with regard to the need to bifurcate the proceeding. Many stated a concern that their litigation of operational issues in this proceeding would be superfluous if the Commission were to set costs at levels that CCAs and prospective CCAs believed were too high to justify developing energy procurement programs. The scoping memo agreed to bifurcate the proceeding on the basis of that discussion. An ALJ ruling dated January 29, 2004 also stated the Commission's intent to develop a CRS in Phase 1.
The utilities' current proposal to delay adoption of a specific CRS amount until after Phase 2 would undermine the Commission's commitment to provide CCAs and prospective CCAs with some early indication of the costs they can expect to incur if they choose to procure energy. Agreeing to wait until after the resolution of Phase 2 issues could delay implementation of the CCA program until mid- or late-2005, almost three years after the enactment of AB 117.
Nor do we agree with the utilities that the record does not provide adequate information to adopt an interim CRS. In fact, we are not sure what the utilities would have the Commission explore in Phase 2 hearings on this issue since the parties agree to the DWR model and its components and this decision resolves related issues.
Adopting an initial CRS amount at this point would require a leap of faith, but one that is reasonable considering the results of the DWR's modeling. DWR presented a sensitivity analysis that included illustrative ranges of CRS amount that vary depending on assumptions about market conditions. DWR explains that components of the CRS related to the DWR bonds and historic utility stranded costs are fairly stable and do not depend much on market conditions. The more variable components of the model are the utility CTC and DWR power charge, which may vary considerably depending on market conditions such as gas prices, load growth, capacity additions, and reserve margins.
Importantly, DWR's analysis shows that the CRS may vary markedly from period to period, and is unlikely to be predictable or stable because of its sensitivity to changing market conditions. This understanding that minor changes in market conditions may have a pronounced effect on the CRS is disappointing from the standpoint of our effort to accommodate the CCA's need for some degree of certainty with regard to their CRS liabilities. On the other hand, it removes one of the arguments for delay, that is, that additional work in this area will provide a more accurate CRS. Additional precision in the modeling may be technically appealing but market conditions that are largely unpredictable and out of our control appear likely to have a more pronounced effect of the level of the CRS level than additional precision in the modeling.
For all the foregoing reasons, we find the record in this proceeding is adequate to adopt an initial CRS using the analysis presented by DWR and CCSF. To avoid further delay, we proceed to fashion an interim CRS that is based on available information and analysis and which may be modified immediately if final CRS calculations are substantially higher or lower than the one we adopt today. This charge, like all CCA CRS amounts, shall be subject to true-up based on actual DWR and utility liabilities.
DWR presented the following range of CRS levels in cents per kilowatt-hour for each of the three electric utilities for 2005 and 2006:
CCSF's estimate of $.015/kWh is on the low end of DWR's range because it applied higher gas prices using more recent market information which reduces CRS liabilities.
While we acknowledge that these estimates are not perfect, they nevertheless permit us to adopt a CRS today that may be trued up later, on the basis of the costing principles we adopt in this order. We will therefore establish a CRS today that may be modified either in 18 months or sooner in the event the utilities' final CRS estimates, using more recent forecasts, are at least 30% higher or lower than the adopted CRS. We set the first CRS at $.020/kWh which lies well within the range of CRS estimates presented by DWR. For SDG&E and SCE, DWR's forecasts for 2006 are considerably lower than those for 2005 and gas prices have fallen substantially since DWR conducted the forecasts presented in this proceeding. For these reasons, we believe $.20 is a reasonable estimate of outstanding liabilities for the next 18 months and may ultimately turn out to be high. Our objective is to avoid a circumstance where a CCA relies on an artificially low CRS only to later have to make up the difference with a substantially higher charge. We balance this objective with our wish to avoid setting the CRS too high and thereby create a barrier to CCA development. We believe $0.020/kWh achieves the appropriate balance. This amount would be in addition to nonbypassable surcharges already on customer bills for bond liabilities or historic utility costs. In subsequent periods, the CRS would differ for each utility because, as DWR explains, utility power liabilities differ.
Consistent with our previously-stated concerns that the CCA program move ahead in spite of slow progress to implement program elements, we direct the utilities to file tariffs within 60 days of the effective date of this order that would set the initial CRS at $.020/kWh, effective January 1, 2005. This amount will be trued-up and recalibrated in 18 months or when the utilities' forecast CRS is more than 30% higher or lower than $.020/kWh. Thereafter, the CRS shall be trued-up every year and possibly vintaged in related DWR revenue requirement proceedings, the details of which will be examined in Phase 2.