DISCUSSION

Energy Division evaluates SMUD's annexation proposal utilizing modified CPUC criteria.

In Resolution E-3472, the CPUC used three criteria for evaluating the Government Code Section 56131 provision of whether the district's proposed service would "substantially impair the ability of the public utility to provide adequate service at reasonable rates within the reminder of the service area of the public utility." The criteria were used to assess whether there are any costs to PG&E's remaining ratepayers from customer bypass of transition costs and/or from the installation of duplicative infrastructure causing idle facilities, and if so whether such costs would have a significant rate impact. It would be reasonable to apply these criteria to the SMUD proposed annexation. However, these criteria should be expanded as discussed in more detail below in order to identify and properly evaluate all quantifiable costs associated with the proposed service that would be shifted to remaining PG&E customers. In doing this, the CPUC should also determine whether there are any positive quantifiable benefits which would offset any of these costs.

Unless specifically exempted by the CPUC, customers in the proposed annexation territory will not be able to bypass payment of applicable transition costs.

For purposes of evaluating SMUD's annexation proposal, transition costs include all components currently included in the Cost Responsibility Surcharge (CRS)³. In a series of decisions issued over the last two years⁴, the CPUC has ruled on the obligations of Municipal Departing Load (MDL) customers to pay the following components of the CRS: the DWR bond charge (DWRBC), the DWR power charge (DWRPC), the ongoing competition transition charge (CTC), and the energy cost recovery amount (ECRA) charge.⁵

PG&E and SMUD agree that the net result of the aforementioned CPUC decisions is that transferred and new MDL sales in the annexation area would continue to be responsible for payment of the DWRBC and the ongoing CTC. However, a portion of the transferred load MDL sales, and all new MDL (subject to a specified cap) would be exempt from the DWRPC per D.04-11-014 and D.04-12-059. Moreover, Public Utilities Code Section 848.1(c) and D. 05-08-035 require that all new MDL sales that are eligible for the DWR exemption also receive an exemption from the ECRA charge.

As a result of the annexation, PG&E's remaining customers will assume costs resulting from the DWRPC and ECRA payment exceptions previously adopted by the CPUC for MDL customers in the annexed area.

Although PG&E and SMUD agree that some annexed customers may be exempt from the DWRPC and the ECRA charge, they disagree as to whether PG&E's remaining customers would have to cover any costs associated with the exemptions. PG&E estimates a total cost impact of $74 million (over a 20-year period), or approximately $7.3 million per year on an annualized basis, in lost revenues resulting from the DWRPC and ECRA charge exemptions that would have to be covered by remaining PG&E customers⁶. SMUD argues that the CPUC determined that since DWR did not incur costs to serve the exempted load, the exemptions will not result in any costs to PG&E's remaining ratepayers.

Transition costs, by way of the CRS components, are to be recovered from all PG&E bundled service customers and all non-exempt direct access customers, customer generation departing load customers and MDL customers. The overall cost obligation is a fixed amount. To the extent annexed load is excepted from any of this cost obligation, that portion they would have otherwise paid now must be assumed by PG&E's remaining ratepayers and other non-exempt direct access and departing load customers.

SMUD's proposed new integration facilities may duplicate but do not idle existing PG&E facilities.

SMUD proposes construction of an 18-mile transmission line and a new substation to integrate the annexed electric system into the SMUD grid. PG&E asserts that these new integration facilities duplicate PG&E infrastructure that adequately serves load in the area.

SMUD responds that the proposed new facilities are not duplicative of PG&E facilities. Instead, they are supplemental facilities required to remedy long-standing reliability and load-serving issues. SMUD alleges that PG&E has failed to maintain adequate transmission capacity in the area and that a number of upgrades and modifications would be necessary in the area even in the absence of SMUD's annexation proposal. SMUD supports its allegations with references to consultant studies and historical reliability data

PG&E alleges that there are no deficiencies in the area. It asserts that the consultant analysis SMUD relied upon was flawed, and that SMUD's arguments ignore the fact that relevant reinforcement projects will be completed and/or substantially in progress prior to SMUD's proposed acquisition date. PG&E maintains that the new facilities SMUD proposes will serve no purpose other than to integrate the system with SMUD's, and are therefore duplicate facilities.

With such a discrepancy of factual information, it is indeed debatable whether or not SMUD's proposed integration facilities would result in the installation of duplicative infrastructure. Nonetheless, our main concern regarding duplicative facilities is whether PG&E facilities would become idle as a result requiring PG&E customers to cover the costs of the idled facilities. There is the potential that SMUD's new integration facilities may be duplicative of PG&E's existing facilities assuming that PG&E information is correct. However, PG&E does not claim that any of its facilities would become idled or stranded as a result of SMUD's proposal to build these new facilities. Accordingly, no costs would be shifted to PG&E's remaining ratepayers as result of their construction.

Other aspects of SMUD's annexation proposal result in the stranding of PG&E facilities.

Although we conclude that SMUD's proposed new integration facilities, in and by themselves, do not idle PG&E's existing facilities, a few of PG&E's assets will be stranded as a result of SMUD's proposed acquisition and severance plans. With this in mind, we believe our second criterion perhaps narrowly spoke only to idle facilities/cost impacts resulting from duplicative infrastructure, and instead should more broadly assess whether any aspects of the proposal would result in idle facilities and whether remaining PG&E customers would be required to cover the costs of those idled/stranded facilities.

SMUD has identified approximately 10.7 miles of existing PG&E transmission line⁷ and two line taps that will be "stranded" by its acquisition and severance proposals. SMUD states that it will provide compensation to PG&E for these few facilities. In addition to these stranded assets, PG&E states portions of its Rio Oso-West Sacramento and Brighton-West Sacramento transmission lines will be stranded resulting in a $21 million (Net PresentValue) cost to remaining ratepayers or approximately $2.1 million per year on an annualized basis. SMUD responds that these additional PG&E facilities will be not be stranded and PG&E customers will not suffer a loss because SMUD proposes to pay compensation for the "acquired" portions of these transmission lines, and allows the "remaining" portions to be reconfigured for PG&E's use.

To the extent SMUD compensates PG&E for "acquired" and "stranded" facilities in accordance with a court or CPUC/FERC asset valuation decision, no cost impacts associated with those facilities will be shifted to PG&E's remaining ratepayers.

In Resolution E-3472, regarding duplicative facilities, we stated that if a district were to purchase or lease existing infrastructure from PG&E, then the costs associated with those facilities would not be shifted to remaining PG&E customers. SMUD plans to condemn PG&E property and pay PG&E compensation for "acquired" and "stranded" facilities through negotiated agreement, or if that does not succeed, through eminent domain. This is akin to a purchase arrangement, irrespective of whether the arrangement is effected by a condemnation judgment or by mutual agreement. Assuming the price paid fully compensates PG&E for the facilities, then no costs will be shifted to remaining ratepayers, and thus ratepayers are indifferent.

PG&E argues that the amount proposed by SMUD grossly understates the actual value⁸ and has grave concerns that in an eminent domain proceeding, the court may not require SMUD to fully compensate PG&E causing its remaining ratepayers to bear the shortfall. SMUD, on the other hand, states that if an eminent domain action is necessary, the compensation determined by a final, non-appealable judgment will constitute full compensation, and therefore, there will be no shortfall to be borne by PG&E's remaining ratepayers.

We agree with SMUD. Under eminent domain laws, the court will assess evidence regarding the valuation of utility assets and the amount of compensation owed in order to fully compensate PG&E for those assets. This is a matter best left to the Court.⁹

If SMUD does not file an eminent domain action but rather PG&E and SMUD reach agreement on the terms of the transfer of facilities, including the sale price, PG&E would be required to seek CPUC approval of the proposed transaction pursuant to Public Utilities Code § 851 for any distribution assets and Federal Energy Regulatory Commission (FERC) approval for any transmission assets. It is through this process, that asset valuation methodologies will be debated and the reasonableness of the provisions of the proposed asset sale/transfer agreement will be decided. The CPUC and/or FERC approved sale price amount will constitute reasonable compensation.

If"remaining" transmission lines resulting from SMUD's acquisition and severance plans become idle because they cannot be reconfigured for PG&E's use as SMUD proposes, PG&E's remaining customers must cover the costs of the idled facilities.

SMUD argues that given reliability concerns in the area, PG&E would need to upgrade, modify or construct new facilities in the annexation area in order to continue reliable service. Instead, SMUD states the "remaining" portions of the Rio Oso-West Sacramento and Brighton-West Sacramento transmission lines can be reconfigured to serve PG&E's remaining load more reliably without additional infrastructure upgrades.

PG&E responds that SMUD's proposed reconfiguration is of no use to PG&E. PG&E alleges that Brighton substation, which would be the only substation connected to SMUD's proposed reconfigured line, is already connected to the bulk transmission system via two 230 kV lines from Rio Oso and Bellota. PG&E asserts that these lines have more than adequate capacity for the 35 MW load served via the Grand Island substation, which would be the only load directly served from Brighton. In the unlikely event of an outage of both 230 kV lines, PG&E states that Grand Island has the option of being served from the south via two 115 kV lines that are normally operated open. Thus, it concludes that there is no need for a 115 kV line connecting Rio Oso and Brighton and as a result the "remaining" portions resulting from SMUD's proposed acquisition and severance plans will be stranded.

We are faced with disparate assertions from PG&E and SMUD that need further detailed technical analysis beyond that allowed through this Resolution process to verify the accuracy of their claims. Given the disparity of the facts, we must take a conservative approach and assume that there is the possibility that the reconfiguration will not work and will result in additional stranded facilities. Accordingly, utilizing PG&E's estimate, approximately $2.1 million per year may be shifted to PG&E's remaining customers.

Other quantifiable costs and benefits associated with the annexation proposal should be considered in the rate impact analysis.

In addition to the cost impacts to remaining customers from any transition cost exemptions and/or idled facilities, the Energy Division requested PG&E to identify any other costs associated with the proposed annexation. In response, PG&E states that its remaining customers would be adversely affected by lost transmission and distribution (T&D) revenues¹⁰, lost lease agreement revenues, and additional costs to reinforce various high voltage assets to wheel power to SMUD. While SMUD believes it is neither appropriate nor necessary to expand the criteria used by the CPUC in Resolution E-3472, SMUD responds to each of PG&E's cost/revenue loss claims and includes estimated benefits of the annexation. We believe it is appropriate to consider the quantifiable costs and benefits of the proposed annexation proposal as identified by PG&E and SMUD.

PG&E asserts that its remaining customers must pay more to cover the lost T&D revenues that otherwise PG&E would have collected from the customers in the area. PG&E agrees it would avoid some T&D-related costs should the annexation occur; however, it estimates that the lost revenue will exceed the avoided costs. Furthermore, PG&E admits lost revenues would partly be offset by the compensation ultimately provided by SMUD for the T&D assets, up to their book value, since this value would be removed from PG&E's rate base. PG&E's calculations result in Contribution to Margin (CTM) losses¹¹ of $439 million (Net Present Value), or approximately $43.4 million per year on an annualized basis.

SMUD believes PG&E's loss estimates are inflated. In its own "worst case" analysis, SMUD believes the maximum potential loss would be approximately $17 million annually. SMUD asserts this impact will be entirely offset by six to nine months of load growth on PG&E's system. Ignoring this assertion, SMUD maintains that the "worst case" impact can be reduced by approximately $12.7 million per year if you factor in the benefit that additional low cost hydroelectric and nuclear generation will be available for reallocation to PG&E's remaining customers as a result of the annexation.

In addition to CTM losses, PG&E states that the proposed annexation will also result in a reduction of revenues that PG&E receives for leasing space on its transmission facilities. This includes various types of telecommunications and fiber assets owned by others, for which PG&E receives a revenue contribution that is shared with its ratepayers. PG&E has not yet quantified these impacts. In response, SMUD states that it plans to compensate PG&E for the value of such leases and thus its acquisition of these assets will not impact PG&E's remaining ratepayers.

PG&E estimates that it will also incur costs necessary to reinforce various high voltage (230 KV and 500 KV) transmission assets that it owns that are used, in part, to wheel power to SMUD. It claims if the Yolo load plus the UC Davis load is added to the SMUD area, the power to serve this load will flow over a different path than is presently the case. PG&E believes that as a result, facilities south of Rio Oso Substation would be come overloaded and need to be upgraded. PG&E currently estimates the costs to upgrade these facilities at roughly $20 million (Net Present Value), or approximately $2 million per year on an annualized basis¹². SMUD disagrees that PG&E would be required to reinforce and expand the capacity of its current transmission interconnections with SMUD because load flow studies confirm that SMUD has sufficient load serving capability in place to serve the annexed load.

Even a conservative estimate of all costs due to bypass of transition costs, idle facilities, and other lost revenues results in a de minimis overall rate impact to PG&E's remaining ratepayers.

As discussed above, there is a wide variance between PG&E and SMUD estimates of lost revenues, additional costs and benefits. PG&E estimates a total annualized cost of $54.8 million ($7.3 million for transition cost exceptions plus $2.1 million for stranded facilities plus $43.4 million for CTM losses plus $2 million for high voltage transmission upgrade costs) which would translate into a 0.091 cents per kilowatt-hour (kWh) rate impact. SMUD calculates a much lower figure of $4.3 million ($17 million for CTM losses less $12.7 million for low cost power benefits) which would translate into a rate impact of 0.005 cents per kWh.

Due to the significant difference in estimates and our inability to validate these disputed issues of fact within the timeframe allowed, we believe it is appropriate to be conservative and use PG&E's estimate. We note that PG&E's current system average rate is 12.77 cents per kWh for bundled service customers¹³. Using PG&E's calculations, this current system average rate would increase by less than a tenth of a cent. PG&E asserts that although the amount of this rate impact on individual customers may be small, the cost shift substantially affects the reasonableness of the resulting rates. We conclude that a potential rate impact of this magnitude would not substantially impair PG&E's ability to provide adequate service at reasonable rates within the remainder of its service territory.

Furthermore, we agree with SMUD that it is appropriate to net out any quantifiable annexation benefits, which has the effect of significantly reducing PG&E's rate impact figure.

Broader energy policy issues raised by PG&E are beyond the scope of CPUC's required statutory reporting requirements but could be considered in a separate CPUC proceeding.

In addition to the quantifiable cost/benefit related issues discussed above, PG&E also raised some energy policy issues that it believes will place additional burdens upon its remaining ratepayers. In particular, PG&E believes that SMUD's annexation proposal 1) fosters continued "balkanization" of the CAISO grid, 2) removes load from CPUC oversight thereby eliminating requirements for adherence to CPUC and State Energy Action Plan policies, and 3) takes away AB 1X rate increase protections.

Although SMUD responded to each issue raised by PG&E, it believes none of these matters are relevant to the CPUC's inquiry under Government Code Section 56131. We are concerned about the risks posed by fragmentation of the CAISO grid on the reliability of the Western Interconnection¹⁴, and acknowledge the importance of AB 1X rate protections and adherence to the State's Energy Action Plan policies. Nevertheless, these issues are not within the scope of our review of SMUD's proposal under Government Code Section 56131. The consideration of broader policy issues could be the subject of a CPUC issued Order Instituting Rulemaking (OIR) to comprehensively address issues associated with the formation of or expansion of public power within a public utility's service territory. Accordingly, we do not expand the scope of our review to consider them in this Resolution.

Cumulative impacts of additional annexation proposals are outside the scope of the CPUC's statutory reporting requirements but could be considered in a separate CPUC proceeding.

In Resolution E-3876 dated August 19, 2004, the CPUC found that an individual annexation proposal did not have a significant impact on the regulated utility's ability to serve its remaining customers but that the cumulative impact of additional such proposals in the future may pose a substantial impairment to the utility's ability to provide adequate service at reasonable rates. The Energy Division requested PG&E to address cumulative impact issues. In response, PG&E summarized other potential annexation proposals in the near future and estimated that an additional $175.9 million per year would be shifted to PG&E's remaining ratepayers should they occur.

SMUD argues that consideration of the cumulative impacts of additional proposals is outside the scope of the review authorized in Government Code Section 56131. That statute speaks only to the particular proposal under review and says nothing about potential service by another publicly owned utility, whether existing at the time of the service proposal under review or potentially arising in the future. In Resolution E-3876, we expressly agreed that "[t]he statute requires us to report to the LAFCo on the potential impacts only of the particular proposed municipal service" but expressed concern regarding cumulative impact of additional proposals. We agree with SMUD that it would not be appropriate, in the context of our report under Government Code Section 56131, to analyze cumulative impacts of additional proposals. This type of analysis could be the subject of a CPUC issued OIR to comprehensively address energy policy issues associated with the formation of or expansion of public power within a public utility's service territory.

³ Transition costs do not include the Nuclear Decommissioning Charge (NDC), the Fixed Transition Amount (FTA), or the Public Purpose Program (PPP) charge.

⁴ See Decision (D.) 03-07-028, D.03-08-076, D.04-11-014, D.04-12-059, D.05-07-038, and D.05-08-035.

⁵ The DWRBC covers the costs associated with the bonds DWR issued in 2002 to recover the costs it incurred to procure power during the energy crisis. The DWRPC covers the above-market costs associated with the contracts entered into by DWR. The on-going CTC covers the above-market portion of the contracts that PG&E executed with qualifying facilities, as authorized via Assembly Bill 1890. The ECRA charge, sometimes referred to as the Energy Recovery Bond charge or the Dedicated Rate Component, collects the costs associated with the energy recovery bonds issued to finance PG&E's bankruptcy-related costs

⁶ PG&E states there is a possibility that SMUD may argue for a CTC "stand-alone" exemption per Public Utilities Code Section 369 in the future which it believes would shift additional costs to PG&E's remaining ratepayers, if granted. SMUD does not believe its customers in Yolo County would qualify for the CTC "stand-alone" exemption per Public Utilities Code Section 369 on any broad scale.

⁷ This is comprised of an 8.16 mile portion of the Woodland-Rio Oso #1 and a 2.5 mile portion of the Brighton-Davis line.

⁸ SMUD believes compensation for the facilities should be based on what PG&E actually paid for the facilities using the Original Cost Less Depreciation (OCLD) valuation methodology. PG&E believes it is entitled to current fair market value for its facilities using the Replacement Cost New Less Depreciation (RCNLD) methodology.

⁹ Under Public Utilities Code § 1401 et seq., SMUD has the option to seek this Commission's determination of the just compensation to be paid for any PG&E assets that it seeks to acquire in connection with its annexation proposal. If, after their initial negotiations, PG&E and SMUD cannot reach agreement on the terms of the transfer of the facilities necessary to effectuate the proposed annexation, we would encourage SMUD to utilize the auspices of this Commission under that law in order to resolve this disagreement. However, resort to this Commission's procedures under Public Utilities Code § 1401 et seq is not mandatory, and SMUD always retains the option of initiating an eminent domain proceeding in the courts if it and PG&E are unable to negotiate an agreed-on set of terms for the transfer of facilities.

¹⁰ This includes revenues from T&D rate components as well as revenues from some non-bypassable charges.

¹¹ PG&E calculates the loss of CTM as the difference between the lost revenues and the sum of avoided costs and book value.

¹² PG&E notes this is a preliminary estimate because more analysis is needed for more precision and to determine the extent to which these investments might be required absent SMUD's annexation.

¹³ PG&E Advice Letter 2706-E filed on September 1, 2005.

¹⁴ Detailed concerns were articulated to Spencer Abraham (then Secretary of the U.S. Department of Energy) on July 29, 2004 in a letter from CPUC President Peevey.