V. Other Issues

A. Applicability of Surcharges to New Customer Load

1. Position of Parties

Parties disagree on the applicability of the CRS to "new load." The Municipal Parties argue that neither DWR and CTC cost responsibility surcharges should be applicable to new municipal customer load. CMUA defines "new load" as follows:

"Load associated with a newly constructed facility that has never been interconnected with the electric system of an investor-owned utility but instead interconnects with the electric system of a publicly owned utility, notwithstanding the fact that the load happens to be located in a geographic area that previously was part of an investor-owned utility's service area but has subsequently become served by a publicly owned utility"

The Municipal parties interpret AB 1890, and specifically Section 369, which provides for recovery of CTCs from "all existing and future consumers," as exempting new load from CTC responsibility as well as DWR cost responsibility.⁶⁸ CMUA acknowledges that Section 369 applies to former customers of the investor-owned utilities that are subsequently served by publicly owned utilities, but denies that it applies to New Municipal Customer Load

As a basis for excluding "new municipal load, CMUA cites Section 369 which states:

The commission shall establish an effective mechanism that ensures recovery of transition costs referred to in Sections 367, 368, 375, and 376, and subject to the conditions in Sections 371 to 374, inclusive, from all existing and future consumers in the service territory in which the utility provided electricity services as of December 20, 1995; provided, that the costs shall not be recoverable for new customer load or incremental load of an existing customer where the load is being met through a direct transaction and the transaction does not otherwise require the use of transmission or distribution facilities owned by the utility. However, the obligation to pay the competition transition charges cannot be avoided by the formation of a local publicly owned electrical corporation on or after December 20, 1995, or by annexation of any portion of an electrical corporation's service area by an existing local publicly owned electric utility. (Emphasis added.)

The IOUs view the Section 369 phrase "future consumers in the service territory in which the utility provided electricity services as of December 20, 1995" as expressing Legislative intent to make CTC applicable to New Municipal Customer Load.⁶⁹ CMUA argues, however, that this was never discussed as part of the development of AB 1890.

CMUA argues that if the Section 369 phrase "future consumers in the [investor-owned utility's] service territory..." was intended to include new municipal load, there would be no need for the succeeding sentence that reads "[h]owever, the obligation to pay the competition transition charges cannot be avoided by the formation of a local publicly owned electrical corporation on or after December 20, 1995, or by annexation of any portion of an electrical corporation's service area by an existing local publicly owned electric utility."

CMUA argues that this sentence, which specifically and expressly applies Section 369 to customers of municipal utilities would be superfluous if the phrase "future consumers in the [investor-owned utility's] service territory..." was intended to include new municipal load. CMUA thus argues that the specific phase is controlling over the general phrase"⁷⁰

CMUA also argues that the Preferred Policy Decision⁷¹ and subsequent Commission decisions show that neither the Legislature nor the Commission intended or contemplated that CTC would apply to New Municipal Customer Load.

CMUA claims that that it was the retail customers (i.e., "consumers") of the investor-owned utilities who were on notice of and ought to have expected to bear responsibility for the competition transition charge in the Preferred Policy Decision. The Commission stated therein:

"[W]e will institute a nonbypassable charge, called the competition transition charge (CTC), for all customers who are retail customers on or after [December 20, 1995], whether they continue to take bundled service from their current utility or pursue other options."⁷²

"[W]e also will require utilities to modify the Preliminary Statement of their tariffs to provide all current and new customers with notice of our intent to authorize collection of retail transition costs."⁷³

CMUA thus argues that a service relationship with a "regulated electric utility" is required in order for the Commission to intervene and impose a charge. CMUA contends that New Municipal Customer Load, by definition, does not include a service relationship as a "retail end-use customer that has purchased power from an electrical corporation." CMUA also argues that any imposed charge should fall on customers in rough proportion to the benefits the customers "have received" from the investor-owned utility's system.

D.96-11-041 again reiterated that a service relationship with a regulated electric utility is a prerequisite to the imposition of the CTC, stating:

"[Section] 369 requires the Commission to develop a mechanism that collects transition costs `from all existing and future consumers,' indicating a Legislative intent that new customers' load would also be subject to the CTC unless they qualified for an exemption."⁷⁴

In discussing the treatment of new load, the Commission again stated the requirement that there be a service relationship with an IOU. A new customer was described as one who moved into PG&E's service territory and took service from PG&E.⁷⁵

In D.97-06-060, as part of its discussion on jurisdictional concerns associated with a FERC-jurisdictional tariff, the Commission reiterated that service under a CPUC-jurisdictional tariff is essential for the implementation of CTC. The Commission stated that a customer would be subject to the competition transition charge "who was [taking] PG&E service subject to CPUC jurisdiction...and then displaced that PG&E service..."⁷⁶

Merced also argues that while Section 369 allows the utilities to collect CTCs from future IOU customers, it does not authorize the IOUs to collect CTCs from future customers that do not take service from IOUs, such as new irrigation district customers. Merced argues that, consistent with this interpretation, the IOUs have not collected CTCs over the years from new publicly-owned utility load,⁷⁷ and that the Commission is not bound to apply Section 369 in the DWR cost context.

Merced argues that new publicly-owned utility customer load that has never taken service from and investor-owned utility and that need not take transmission or distribution service from an investor-owned utility after it locates in the publicly-owned utility service area should not be subject to the DWR Bond Charge or Power Charge.

Merced further proposes that a customer departing investor-owned utility service and entering a brand new site in a publicly-owned utility's service area -- which has never previously received electric service from the investor-owned utility -- not be subject to the DWR Bond Charge or Power Charge. In this scenario, Merced claims, imposing a surcharge on such a customer would mean, in most cases, double cost recovery for the load at the site where the customer departed. The new customer moving into the old site will contribute toward the recovery of DWR past and future costs through bundled rates, and the departing customer will contribute toward recovery of those same costs through the DWR Bond Charge and Power Charge.⁷⁸

The IOUs and ORA propose including "new load" in assessing DWR charges. PG&E disputes Municipal Parties' interpretation of Section 369 as limiting Commission authority to impose responsibility for costs other than CTC on municipal departing load generally (and new load specifically). PG&E argues that no evidence suggests that the Legislature intended to repeal the Commission's general ratemaking authority and responsibilities under Sections 451, 453, 701, and 728 when it enacted Section 369, or that the various statutory sections cannot be reconciled with one another.

PG&E contends that the language of Section 369 and the IOUs' tariffs permit the IOUs to charge CTCs to new load. Moreover, while unique factual circumstances made it impractical to implement CTC collection from new load, PG&E argues, such implementation issues did not constitute a waiver of the IOUs' authority to collect CTCs or other nonbypassable charges approved by the Commission from new load.

PG&E disputes CMUA's argument that the Legislature's use of the words "existing and future consumers" in Section 369 should be interpreted to preclude recovery of CTCs from new load.⁷⁹ PG&E argues that exemption of new load from DWR's costs would create a perverse incentive for publicly owned utilities to entice developers and new businesses locating within the IOUs' service areas but within the publicly owned utility's reach to take service from the publicly owned utility simply to avoid DWR's costs.⁸⁰ Meanwhile, similarly situated new load in PG&E's, SCE's, or SDG&E's service territory taking service from the IOU would pay DWR's costs as part of its bundled service rate.

PG&E claims that load served by a municipality " located in a geographic area that previously was part of an investor-owned utility's service area" ⁸¹ does not properly constitute "new load" contrary to CMUA's characterizations. PG&E claims that in many cases, a publicly owned utility may serve new load in an area where the IOU still retains its obligation to serve. In addition, even where a city annexes territory in an IOU's service area, the IOU retains its county franchise rights and its obligation to serve.⁸² An electric consumer that locates in such an area but takes electric service from the publicly owned utility would constitute "new load," consistent with PG&E's Preliminary Statement BB.6 (Ex. 106).

PG&E disputes CMUA's claim, however, that the Legislature, in AB 117, intended by inference to exempt new load from cost responsibility. While the first sentence of Section 366.2(d)(1) is silent regarding new load, the second sentence of that section contains a broader statement of legislative intent that is not limited to retail end use customers that purchased power on or after February 1, 2001. Specifically, Section 366.2(d)(1)'s second sentence provides: "It is further the intent of the Legislature to prevent any shifting of recoverable costs between customers." PG&E argues that this broad legislative goal of avoiding cost shifting supports assessing these charges against new load since costs not recovered from new load would necessarily be borne by the IOUs' other customers.

2. Discussion

For the assessment of CRS, we adopt the IOUs' definition which includes new load that locates within the IOU service territory but purchases or consumes power supplied and delivered by a new or expanding municipal utility. The adopted definition of MDL does not include current or future load served by a publicly owned utility that is within the publicly owned utility's exclusive service territory.

In accordance with Section 369, "new load" for purposes of CRS recovery excludes load being met through a direct transaction that does not otherwise require the use of transmission and distribution facilities owned by the IOU. Section 369, however, does not exempt new municipal load where the municipal agency serves such load through interconnection with and use of the IOU's transmission system.

We shall also include "new load" added subsequent to February 1, 2001 within the scope of customers subject to the CRS. The dispute over the treatment of "new load" in the context of municipal customers raises issues different from those facing us in the DA phase of this proceeding. Since the right to acquire DA was suspended effective September 20, 2001, there was no issue regarding CRS treatment of new DA customers after September 20, 2001. By contrast, there is no suspension in effect with respect to customers' rights to migrate to a municipality or irrigation district. Thus, the question arises as to the applicability of CRS to new customers migrating into municipalities or irrigation districts in previously undeveloped service areas.

When DWR entered into long term contracts to meet the net short requirements of both current and future increases in load within the defined IOU service territories as they existed on February 1, 2001. The fact that a municipality may subsequently municipalize or annex a portion of the IOU's service territory and install new facilities to serve customers moving into that annexed area does not eliminate the cost responsibility associated with that new load. Even though the installed municipal facilities are new and the geographic area was not previously populated with customers, if the development is within the geographic bounds of IOU service territory as it existed on February 1, 2001, then it is part of the region assumed to be served by IOUs in DWR's forecasts.⁸³

Moreover, CMUA's proposal to exclude "new load" from CRS provides for no identification of customers that have never been served by an IOU versus existing customers merely migrating from an IOU. Exemption of "new load" as proposed could enable departing IOU customers to escape cost responsibility merely by relocating into a newly annexed municipal territory. Because such departing customers would have borne responsibility for DWR charges as IOU bundled customers, they should not be permitted to escape that responsibility merely by relocating to a newly annexed area whose electric load is served by a municipality.

In the same manner, new bundled customer load will bear responsibility for paying DWR bond and power charges even if specific customers were not individually taking bundled service from the IOU during 2001. The fact that DWR undertook procurement obligations to serve future load growth within the IOU service territories as of February 1, 2001 creates a link between DWR costs and new load whether it is served by the IOU or the municipality. Our mandate to avoid cost shifting warrants adoption of cost responsibility for new load within each IOU service territory as it existed on February 1, 2001.

We are not persuaded by CMUA's arguments citing Section 369. CMUA's interpretation of Section 369 defies the plain meaning of the statute.⁸⁴ While the Legislature could have used the simple word "customer" in Section 369, it instead used the phrase "all existing and future consumers in the service territory in which the utility provided electricity services as of December 20, 1995." (Emphasis added.) The broad scope of the words "all existing and future consumers of electricity" in a geographic area simply refers to one who consumes electricity.

We conclude that Section 369 imposes CTC responsibility on "existing and future consumers" of electricity in the IOUs' service territories as they existed as of December 20, 1995. We reject CMUA's interpretation that Section 369 only applies to customers taking service from an IOU. CMUA's interpretation of Section 369 would render meaningless the exception for a transaction that does not otherwise require the use of the transmission or distribution facilities of the utility. If the first portion of the statute only applies to a customer of the utility, then the exception would never apply because by definition a utility customer uses the utility's transmission or distribution facilities.⁸⁵

CMUA cites the Section 369 provision stating that "the obligation to pay the competition transition charges cannot be avoided" by creating a new publicly owned utility or by annexation of the IOUs' service territory. The first part of Section 369 imposes CTC responsibility broadly on all "consumers" of electricity; and the second part specifically provides that such consumers cannot avoid their CTC responsibility through municipalization or annexation efforts, that is, through a partial change of the IOU's service territory.

As PG&E points out, because Section 369 contains "belt-and-suspenders" language to ensure that no consumer of electricity within the IOUs' service territories as of December 21, 1995, escapes responsibility, there is no basis to conclude that new load could avoid its responsibility for payment of CTCs. This language does not constitute "proof" that the Legislature exempted new load from CTC responsibility.

CMUA also argues that AB 117 excludes New Municipal Customer Load from cost responsibility, limiting its applicability to " each retail end-use customer that has purchased power from an electrical corporation on or after February 1, 2001" § 366(d)(1), emphasis added) CMUA omits additional language in AB 117, however, stating that it is the intent of the Legislature "to prevent any shifting of recoverable costs between customers." As stated in AB 117, these costs at issue are not just the purchase costs incurred in 2001, but the "purchase contract obligations incurred." These obligations related to multi-year contracts for supplies serving load growth beyond February 1, 2001 within the IOU service territories over a period of years. The DWR forecasts of load growth necessarily contemplated new load in the IOU service territories that would need to be served.⁸⁶ Even though individual customers moving into a previously undeveloped region of service territory may not have personally taken DWR power deliveries, the fact remains that DWR contracted for power supplies to serve load growth in the entire IOU service territory as it existed on February 1, 2001. Thus, there is a cause-and-effect relationship between DWR contracting and load growth subsequent to February 1, 2001. Load growth can occur not only through higher demand in pre-existing developed regions, but also through customer migration into previously undeveloped regions of the IOU service territory. Even though a municipality annexes a previously undeveloped region of the IOU service territory and installs its own facilities to serve municipal customers, the pre-existing cost responsibility obligation applicable to the IOU service territory does not terminate merely because ownership of the territory has changed hands. If a new IOU bundled customer moves into a portion of the IOU service territory that is developed after February 1, 2001, that customer still is obligated to pay DWR bond and power charges on the same basis as other bundled customers. Likewise, corresponding cost responsibility treatment should apply to customers moving into previously undeveloped IOU service territory even though that territory happens to be acquired by a municipality after February 1, 2001. As noted previously, no explicit reduction was incorporated into the forecasts to represent that portion of new load in the IOU service territory that would be subsequently acquired by a municipality. Absent a sharing of cost responsibility by new municipal customer load for the DWR costs, the DWR contract cost obligations would be shifted to existing bundled customers, which is in conflict with stated legislative intent in AB 117.

B. Effect of Surcharges on Economic Viability of Municipal Service

1. Parties' Positions

Parties dispute the economic implications and incentives that would be created as a result of imposing CRS on MDL. Merced argues that adding DWR surcharges on top of existing utility protections will unnecessarily increase irrigation districts' cost burden and make the provision of service by irrigation districts uneconomic.⁸⁷

SCE responds that the IOUs' customers, just as those of Irrigation Districts, must pay the costs the CRS is designed to recover. The increased cost burdens that municipal customers must bear do not make their service any more uneconomic than the IOUs' service. SCE also argues that failure to impose cost responsibility on municipals will create a perverse incentive for new municipalization, and lead to an exodus of customers from the IOUs to the municipals. SCE witness Payne testified that representatives of potential municipal utilities have told him "specifically, that if it turned out that these charges did apply, they would ...as [SCE] to take the distribution back."⁸⁸ SCE witness Payne states that he has seen a number of different studies regarding the feasibility of municipalization.⁸⁹ Payne testified that at one point during the energy crisis, around 50 of the 180 cities in SCE's service territory were studying some form of municipalization.⁹⁰

Merced claims that the only "evidence" presented regarding the potential for exodus was broad-based speculation and a footnote reference to a consultant's report prepared for East Bay Municipal Utility District.⁹¹ Merced argues that not only is this "evidence" vague, it also focuses on publicly-owned utilities generally and does not address specifically irrigation districts. As a result, Merced argues, this "evidence" does not overcome relevant irrigation district precedent, or focused evidence regarding the market share of irrigation districts. Merced rebuts the utilities' concern that any conclusion that departing load CRS do not apply to irrigation district departing load will create a mass departure from utility service.

CMUA likewise argues that municipal annexations provide a "commonsense response" to urban and suburban development, and occur for a variety of public interest reasons other than the price of electric power. Annexations provide an opportunity to centralize and maximize the utilization of various municipal services, and are usually considered in response to the request of developers who desire to obtain all of the same services that other residents and businesses receive, including police and fire protection and water and sewage service. Additionally, where a municipality operates a publicly owned utility, CMUA argues, it is only logical that this service be requested as well.

CMUA maintains that up until recently, the transfer of utility facilities in connection with annexations was a common, uneventful occurrence. CMUA argues that the economic impact associated with cost responsibility surcharges, however, has caused certain cities have been forced to delay annexation activity until matters relating to cost responsibility surcharges become more certain.

2. Discussion

We are not persuaded by the anecdotal evidence presented by the parties concerning the potential economic impacts of a CRS on municipal utilities and irrigation districts. The dispute between municipal parties and IOUs on this issue is at least to some degree an argument over whether the glass is half empty or half full. IOUs argue that the incentive to municipalize may turn on whether or not a CRS is imposed on MDL customers. While CMUA responds that municipalizations happen for a variety of other reasons other than the level of electricity prices, CMUA also claims that the potential for electricity surcharges for DWR costs are already delaying or discouraging plans for new municipalizations. Thus, while each side argues for an opposite result, both sides appear to agree that a CRS is of potentially significant economic consequence in the decision of whether to municipalize or whether an existing IOU customer may migrate to municipal electric service.

We find no basis to exempt MDL customers merely because the CRS may serve to some extent as a disincentive toward municipalization. Our mandate to prevent cost shifting requires that MDL customers bear their fair share of CRS costs. As discussed below, we reserve judgment on whether or to what extent a cap should be imposed on the MDL CRS as a possible remedy to address any undesirable disincentives toward municipalization. On the other hand, the absence of a CRS on MDL could potentially promote unintended incentives to municipalize merely to escape DWR charges, with the potential for cost shifting between customers. We believe the potential for such a result is of serious concern, given CMUA's admission about municipalization plans being impacted by this proceeding. Therefore a CRS is an appropriate tool to guard against unintended incentives to avoid cost responsibility.

C. Quantifying MDL CRS and Implementing Billing and Collection

1. Parties' Positions

PG&E and SCE generally concur that the Commission should adopt and apply to MDL customers the same CRS methodology as was established for DA customers in D.02-11-022, except that municipal the MDL CRS not be capped.⁹² SCE states that the effect that MDL will have on its system is largely the same as the effect that of post-July 1, 2001 DA load.⁹³ The IOUs propose that the Commission should convene workshops to implement the process for billing and collecting the MDL CRS.⁹⁴

Municipal parties argue that the IOUs have not provided any record support demonstrating the level of costs that were incurred on behalf of departing load.⁹⁵ Corona also argues that the IOUs have not provided any detail concerning the mechanism by which the CRS would be collected from municipal utility customers.⁹⁶

SCE responds that just because parties representing municipal interests did not participate extensively in the DA CRS phase of the proceeding, DWR and the IOUs did in fact provide such evidence in the prior phase to this proceeding regarding the CRS adopted for DA customers.⁹⁷ SCE argues, therefore, that merely because municipal parties have not provided evidence on the actual level of the CRS, does not mean that there is no record support for the level of MDL CRS.

The IOUs acknowledge that the manner in which the MDL CRS will be billed and collected is yet to be devised, but argue that does not mean that the Commission should delay a decision now establishing that MDL responsibility for the costs that have been incurred on their behalf. SCE notes that the same statement was true when the Legislature adopted Section 369, which unambiguously gives utilities the right to collect CTC from MDL.

SCE believes that a process for collecting the CRS can be developed after a decision is issued in this phase of the proceeding, and that delaying resolution of the threshold question of responsibility actually makes determination of the cost recovery mechanism more difficult. PG&E likewise agrees that the fact that the IOUs have not yet put forth detailed implementation proposals to charge or collect CRS from MDL does not mean that MDL should be relieved of their responsibility to pay such fees.

SCE proposes that workshops be convened to initiate a further process to develop and implement measures providing for the identification, billing, and collection of CRS from MDL customers. The issues proposed by SCE for the workshop include:

- whether the CRS would be paid by (a) MDL customers served in the areas that were formally IOU service territory, (b) municipal utility acquiring those customers, or (c) wholesale distribution charges in the MDL's Wholesale Distribution Access Tariff (WDAT) service.

- Whether the CRS should be assessed in one lump sum or installments

- Means of estimating and incorporating anticipated load growth

2. Discussion

We conclude that the DA CRS costing approach adopted in D.02-11-022 provides an appropriate framework for applying a DWR ongoing power charge to MDL customers. We agree with SCE's observation that the departure of a customer has similar cost-shifting effects whether the customer migrates to DA or to a municipal utility. In D.02-11-022, we directed that workshops be convened to quantify the actual DA CRS taking into account the 2003 DWR revenue requirements based on the DA-in/out methodology adopted therein. There is no necessity to undertake an independent DWR costing analysis for MDL customers other than to identify the applicable magnitude of MDL to apply as an input into the modeling process. Therefore we shall direct that the methodological approach for determining DWR cost responsibility adopted for DA customers in D.02-11-022 be applied to encompass MDL.

In D.02-11-022, we determined the starting point of September 21, 2001 for purposes of tracking DA cost responsibility for ongoing DWR power charges (in contrast to Bond Charges). Because DA customers had not previously paid for any share of DWR power charges, we directed that a charge be assessed on DA customers for the above-market portion of ongoing DWR power costs incurred on or after September 21, 2001, to be tracked through a deferred account established by each IOU. We also approved a process for the modeling of DA cost responsibility for 2003 DWR costs based on an updated modeling run to be performed by Navigant, Inc. In similar fashion, we shall direct that the CRS implementation process for DA costs be extended to assign the applicable share of cost responsibility to MDL customers. The implementation will entail identifying the kWh volumes of MDL to be incorporated into the CRS modeling, and also to compute the CRS costs to be assigned to MDL customers for the period between September 21, 2001 and the first billing date of CRS to MDL customers.

We order a separate phase of this proceeding to address necessary implementation measures to enable the MDL CRS billing and collection to take effect. These implementation measures include the process for incorporating the applicable kWh load volumes into the modeling of CRS, and for enabling the IOUs to account for, bill, and collect the requisite charges from MDL customers. In particular, unresolved questions remain concerning the role of the municipal utility or irrigation district in facilitating and cooperating with the IOUs to enable the billing and collection process to be implemented. The ALJ is directed to issue a procedural ruling initiating further actions required to integrate MDL into the DA CRS modeling process and to implement the accounting, billing and collection of MDL CRS, as adopted in this order.

The IOUs oppose any cap on the CRS level paid by MDL customers, such as the 2.7 cents/kWh cap applied to DA load. SCE argues that municipal load provides no benefit to bundled service customers, and therefore, bundled customers should not be required to finance any cap in order to promote municipal load. Corona disagrees, claiming that municipal load offers a competitive incentive for the IOUs to offer lower prices and better service to bundled customers.

Merced argues that adding CRS on top of existing customer charges will increase irrigation districts' cost burden and render the provision of service uneconomic.⁹⁸ Merced argues that such additional cost burden will impair districts' ability to exercise their statutory authority to supply electric power services. PG&E's witness acknowledged that if the charges that irrigation district customers pay are "too high," the irrigation district may lose customers.⁹⁹

The record is insufficient at this point to make any final determination as to whether the MDL CRS should be capped, and if so, whether that cap should equal the DA CRS cap or some other level. Further evidence is needed concerning the actual level of MDL CRS and the potential economic implications for municipal utilities. The currently adopted DA CRS cap of 2.7 cents/kWh is also in the process of being reevaluated and is subject to revision following proceedings and Commission order due by July 1, 2003. The record being developed in that phase may have potential relevance in evaluating the nature and extent of any MDL cap that may be considered.

Capping of CRS obligations causes bundled customers to fund resulting CRS undercollections which must ultimately be reimbursed with interest. The need for and nature of any cap for MDL (as well as DA) customers must be weighed carefully in recognition of our obligation to achieve bundled customer indifference and to avoid cost shifting. Thus, we defer consideration of the imposition of any MDL caps pending our further developments regarding DA CRS caps and the quantification of the total MDL CRS obligation. We shall provide for appropriate opportunity to be heard on the issue of a MDL cap before finalizing the implementation of any CRS to be billed to MDL customers.