5. Ratemaking Considerations

A. Allocation of PG&E's Gain on Sale and Lease Revenues Between Shareholders and Ratepayers

PG&E will receive the following revenues from MOD based on the above transactions:

· Revenues from the license/lease of electric distribution facilities to MOD;




· Payment by MOD of half of the costs of removing any stranded facilities upon expiration of the license/lease agreement;




· Revenues from the lease of PG&E's transmission assets, e.g., the wooden poles;




· PG&E's gain on sale resulting from the sale of certain distribution facilities to MOD.

The parties agree that PG&E should allocate revenues from the license and lease of electric distribution assets to MOD to Other Operating Revenue (OOR). We approve this allocation of license/lease revenues.¹⁴

The parties also agree that PG&E should credit MOD's payment of half of the costs of removing any stranded facilities upon the expiration of the license/lease agreement to the depreciation reserve to reduce rate base. We find this ratemaking treatment appropriate because ratepayers paid for those facilities while the facilities were in ratebase.

PG&E proposes to allocate its revenues from the wooden pole lease according to Federal Energy Regulatory Commission (FERC) ratemaking principles, because the poles are transmission assets. ORA contends that since MOD entered into the pole lease in order to place distribution assets on the poles and to accommodate distribution wires purchased from PG&E, the poles should not be treated as transmission assets and the lease revenues should be credited to OOR. In the alternative, ORA argues that even if the pole lease relates to electric transmission property for ratemaking purposes, the Commission should allocate lease revenues according to its own ratemaking principles, rather than FERC's Uniform System of Accounts (USOA), because the USOA is not binding on the Commission.

However, ORA has cited no authority to support its argument that the poles are not transmission assets because MOD is using space on the poles for distribution assets. In contrast, paragraph 14 of the Joint Statement of Stipulated Facts (stipulation) refers to the wooden poles as "transmission assets."¹⁵ Moreover, the Wood Pole Lease Agreement signed by both parties specifically refers to the poles leased to MOD as "transmission poles."¹⁶ The parties have presented no further evidence related to the proper characterization of the poles for ratemaking purposes.

Under these circumstances, we believe that the wooden poles should be treated as transmission assets for ratemaking purposes. Revenues from the lease or sale of transmission assets are generally allocated pursuant to FERC ratemaking principles.¹⁷ PG&E shall therefore allocate revenues obtained from the wooden pole lease according to the applicable FERC requirements.¹⁸

PG&E and ORA agree that PG&E's gain resulting from the sale of distribution facilities to MOD should generally be allocated according to our Redding II decision (Redding II).¹⁹

In Redding II, we held that a utility's gain on the sale of all or part of a distribution system should be allocated to utility shareholders as non-utility income under the following four circumstances, provided that ratepayers did not contribute capital to the distribution system:

· The distribution system is sold to a public entity, such as a municipality or a special utility district;




· The distribution system consists of part or all of the utility's operating system located within a geographically defined area;




· Components of the system are or have been included in the utility's ratebase; and




· The sale of the distribution system is concurrent with the utility's being relieved of its obligation to serve customers in the area served by the distribution system, and the public entity that purchased the distribution system assuming this obligation.

However, Redding II also provides that if a transfer of a utility distribution system will adversely impact the cost or quality of service for remaining utility ratepayers, the gain on sale should be allocated to ratepayers to the extent necessary to mitigate the adverse impacts.

Redding II was later extended to cover streetlight conveyances and other partial liquidations.²⁰

We agree with the parties that Redding II applies to this case, because (a) PG&E is selling certain distribution facilities in the Mountain House Area to a public agency, MOD, (b) PG&E's sale of the distribution facilities is a partial liquidation of PG&E's operating system in the area, (c) these distribution assets have previously been included in PG&E's ratebase, and (d) PG&E's sale of the distribution system to MOD is concurrent with PG&E's relief from its obligation to serve customers in the Mountain House Area pursuant to § 9610. However, the Commission will be initiating a rulemaking to examine issues related to the allocation of a utility's gain on sale in the near future. Although Redding II applies to PG&E's sale of distribution assets to MOD, the Commission wishes to reconsider the appropriate allocation of a utility's gain on sale in this type of transaction in the rulemaking.

ORA also argues that PG&E should allocate part of its gain resulting from the sale of distribution assets to ratepayers, because ratepayers have paid an estimated $46,590 for the revenue requirement for these facilities during the past three years, while PG&E also obtained license revenues from MOD. PG&E argues that removals of property from ratebase cannot occur instantly but must be accomplished through a general rate case. PG&E also contends that allocation of license/lease revenues received from MOD to OOR financially benefits ratepayers, because OOR is credited toward PG&E's overall revenue requirements, which relieves ratepayers of the obligation to pay a corresponding amount for PG&E's operational costs. We believe that consideration of this argument should also occur in the context of the rulemaking, so that we may decide this issue on a broad policy basis.

We therefore defer our decision on these ratemaking issues to the upcoming gain on sale rulemaking.

However, we will address ORA's argument regarding protection of PG&E's remaining ratepayers from a potential default by MOD on its obligation to pay NBCs for departing customers here. ORA claims that if MOD were to default on this obligation, PG&E would place an unfair financial burden on its remaining ratepayers by recovering the lost revenue from them. ORA therefore asks the Commission to require PG&E to place funds from its gain on sale in an amount equal to these NBCs in a holding account, to be utilized if MOD defaults on its obligation to pay these NBCs. ORA also requests that PG&E shareholders be held jointly and severally liable with MOD for the NBCs, as additional security. In the alternative, ORA requests that MOD subject itself to Commission jurisdiction for the purpose of enforcing MOD's contractual obligation to pay NBCs on behalf of these customers.

PG&E and MOD argue that ORA has not presented any evidence that MOD is likely to default on this obligation, and if a default occurs, PG&E may address the issue through binding arbitration. We agree that a default by MOD on its obligations to pay NBCs on behalf of departing customers is unlikely. The parties have stipulated that MOD is a financially solvent irrigation district and has an A plus bond rating from two rating agencies, Standard and Poor's and Fitch.²¹ MOD is an established public entity that owns and operates an electric transmission and distribution service and serves customers in San Joaquin, Stanislaus and Tuolumne Counties.²² ORA has presented no evidence to show that MOD is financially unstable or has defaulted on similar obligations in the past.²³ If MOD were to default, PG&E could pursue the issue through binding arbitration and enter a judgment against MOD in any court having jurisdiction. Further, if MOD had not agreed to pay these NBCs for departing customers, PG&E would have to collect these NBCs directly from departing customers, which would be far more difficult and would involve a greater risk of non-payment. Therefore, we find it unnecessary to order PG&E to place a portion of its gain on sale equal to the amount that MOD has agreed to pay for NBCs otherwise owed by departing customers in a holding account or to require PG&E shareholders to be jointly and severally liable with MOD for these NBCs.²⁴

However, as additional protection for remaining PG&E ratepayers, we direct PG&E to promptly pursue any default by MOD on its obligation to pay NBCs on behalf of departing customers through the dispute resolution process stated in the license/lease.

B. Requirement for Annual "True-Up" of NBCs Owed by MOD

ORA also asks the Commission to require PG&E to submit an annual "true-up" of the NBCs to be paid by MOD, in part because these charges may vary over time. We find ORA's request reasonable. Exhibit A to the stipulation, which explains PG&E's proposed methodology for calculating NBCs for departing Mountain House customers, states that certain NBCs will be fixed on an annual basis and will vary between schedules. Further, Table 1-1 of Exhibit A contains only an illustrative example of calculations of these NBCs, rather than calculations of the actual charges. We therefore order PG&E to file a revised statement of its methodology by advice letter no later than 90 days after the effective date of this decision.²⁵ PG&E shall also submit a statement of the proposed NBCs to be paid by MOD, which shows the specific calculations and methodologies used, by advice letter annually at least 90 days before the date on which MOD's payment of the NBCs is due for approval by the Commission Energy Division.