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TITLE 16ECONOMIC REGULATION
PART 2PUBLIC UTILITY COMMISSION OF TEXAS
CHAPTER 25SUBSTANTIVE RULES APPLICABLE TO ELECTRIC SERVICE PROVIDERS
SUBCHAPTER OUNBUNDLING AND MARKET POWER
DIVISION 1UNBUNDLING
RULE §25.344Cost Separation Proceedings

(a) Purpose. The purpose of this section is to establish the procedure by which affected utilities will comply with the Public Utility Regulatory Act (PURA) §39.201.

(b) Application. This section shall apply to all utilities subject to PURA §39.201.

(c) Compliance and timing.

  (1) All electric utilities must file a cost separation case under this section on or before April 1, 2000 according to a unbundled cost of service rate filing package (UCOS-RFP) approved by the commission. Each electric utility shall, in its cost separation filing, file proposed tariffs for its proposed transmission and distribution utility. The filings shall include supporting cost data for the determination of the utility's non-bypassable delivery charges, which shall be the sum of transmission charges, distribution charges, metering system service charges, billing system service charges, customer service system charges (if any), municipal franchise charges, nuclear decommissioning charges (if any), and a competition transition charge (if any).

  (2) Notwithstanding any other provision in this section, an electric utility not subject to this section until the expiration of the exemption set forth in PURA §39.102(c), must file its cost separation case on or before 170 days prior to the expiration of the exemption.

(d) Test year. A historic test year shall be used to determine a forecast test year, defined as follows:

  (1) Historic year--for utilities filing a cost separation case on or before April 1, 2000, the historic year shall be the 12-month period ended September 30, 1999. For a utility filing a cost separation case after April 1, 2000, the historic year shall be a 12-month period deemed reasonable by the commission.

  (2) Forecast year--for utilities filing a cost separation case on or before April 1, 2000, the forecast year shall be the projected 12-month period ended December 31, 2002. For a utility filing a cost separation case after April 1, 2000, the forecast year shall be a 12-month period deemed reasonable by the commission.

(e) Rate of return. Each electric utility shall file a rate of return that is based on its weighted average cost of capital as determined by one of the alternative methods indicated in the Unbundled Cost of Service Rate Filing Package (UCOS-RFP) approved by the commission.

(f) Separation of affiliate costs and functional cost separation.

  (1) Affiliate costs.

    (A) Separation of affiliate costs. The affiliate schedules accompanying the UCOS-RFP shall provide sufficient detail to enable the commission to evaluate the necessity and reasonableness of the affiliate expenses and the "no higher than" cost provisions of PURA §36.058 (relating to Consideration of Payment to Affiliate); §25.272 of this title (relating to Code of Conduct for Electric Utilities and Their Affiliates); and §25.273 of this title (relating to Contracts Between Electric Utilities and Their Affiliates). The schedules shall provide the net total amount of affiliate expense requested for each of the historic and forecast years. This information shall be provided by class of items for all affiliate transactions between the transmission and distribution utility and its affiliates including the affiliated power generation company and the affiliated retail electric provider.

    (B) Affiliated service company. If there is an affiliated service company providing support to the regulated transmission and distribution utility and the other affiliates, then the UCOS-RFP shall include the transactions between the service company, the regulated transmission and distribution utility, the power generation company, the retail electric provider, and all the other affiliates pursuant to PURA §14.154. The UCOS-RFP shall include detailed information on allocation formulas as defined by the reporting schedules.

    (C) Compliance with affiliate rules. The affiliate transactions reported in the UCOS-RFP shall comply with the code of conduct rules as promulgated in §§25.84 of this title (relating to Annual Reporting of Affiliate Transactions for Electric Utilities), 25.272 of this title, and 25.273 of this title.

  (2) Functional cost separation. All electric utilities shall separate their costs into nine categories, relating to the following functions, as defined by §25.341 of this title (relating to Definitions):

    (A) generation;

    (B) transmission;

    (C) distribution;

    (D) transmission and distribution utility metering system services;

    (E) transmission and distribution utility billing system services;

    (F) additional retail billing services;

    (G) transmission and distribution utility customer service;

    (H) competitive energy service; and

    (I) other unregulated services.

  (3) Method of cost separation. Costs shall be assigned to the nine functions using the following three-tier process. No common costs shall be assigned to regulated functions by default. If the utility cannot meet its burden of proof, the costs in question shall be assigned to competitive functions.

    (A) For each Federal Energy Regulatory Commission (FERC) account, costs shall be directly assigned to functions to the extent possible, and all relevant workpapers provided.

    (B) The utility shall provide detailed workpapers documenting the nature of any costs that cannot be directly assigned. For adequately documented costs, the utility may derive an account-specific functionalization factor based on the directly assigned costs or appropriate cost causation principles. The utility must justify the assignment of common costs to regulated functions, and must present evidence to support any such assignment.

    (C) If adequately documented costs remain for which direct assignment or account-specific functionalization cannot be identified, an appropriate functionalization factor as described in the UCOS-RFP may be used. These functionalization factors should only be used as a last resort. If a utility deems a functionalization factor other than the functionalization factor prescribed in the UCOS-RFP to be necessary, the utility shall provide a detailed justification for the chosen functionalization factor.

(g) Jurisdiction and Texas retail class allocation. Allocation of each of the functions comprising the transmission and distribution system services revenue requirement to the existing rate classes shall be based on forecasted 2002 test year load data. Costs related to other functions may be allocated based on a test year ending September 30, 1999.

  (1) Jurisdictional allocation. Functionalized total company costs for the forecast year shall be allocated to the Texas retail jurisdiction. Jurisdictional allocators shall be based on either the methodology approved by the Federal Energy Regulatory Commission (FERC), or the methodology used in the last commission-approved cost of service study.

  (2) Texas retail class allocation. Total Texas retail jurisdiction costs for each of the nine categories shall be allocated among existing rate classes. Consolidation of classes shall be done only during the rate design process.

    (A) Transmission revenue requirement (system services). Electric Reliability Council of Texas (ERCOT) utilities shall allocate the total transmission revenue requirement based on the average of the four coincident peaks for each existing rate class at the time of ERCOT peak, if that data is available. If that data is not available, the utility may use the average of the four coincident peaks for each existing rate class at the time of the transmission and distribution utility's system peak. Non-ERCOT utilities shall allocate transmission revenue requirement based on either the FERC-approved methodology or the methodology approved in the last commission-approved cost of service study.

    (B) Distribution revenue requirement (system services). Costs purely related to demand or customers shall be allocated based on the methodology used in the last cost of service study unless otherwise determined by the commission. Other costs shall be allocated based on allocators analogous to those used during the functionalization process, or appropriate cost-causation principles.

    (C) Generation costs. Total generation costs shall be allocated to the existing rate classes based on the methodology used to allocate generation costs in the last cost of service study.

    (D) Retail electric provider costs. Total costs of services which will be provided by the retail electric provider as approved in the business separation plan shall be allocated among classes based on the allocators used in the last cost of service study.

    (E) Decommissioning costs. Costs associated with nuclear decommissioning obligations shall be allocated based on the methodology used in the last cost of service study unless otherwise approved by the commission. Total costs shall be reported in the unbundled cost of service studies as a separate line item (or subaccount) in each account where such costs occur.

(h) Determination of ERCOT and Non-ERCOT transmission costs.

  (1) ERCOT transmission costs.

    (A) The transmission cost of service for an electric utility in ERCOT shall be as described in §25.192(b) of this title (relating to Transmission Service Rates).

    (B) The UCOS-RFP adopted by the commission for the cost separation filings shall be used by the electric utilities filing under this section.

    (C) Any redirection of transmission depreciation expense to production by an electric utility in ERCOT pursuant to PURA §39.256 should not affect the utility's wholesale transmission cost of service that is used for determining the ERCOT postage stamp rate.

  (2) Non-ERCOT transmission costs. For an electric utility in Texas operating outside ERCOT, the utility's open access transmission tariff approved by FERC will be used to determine the utility's transmission cost and rates in Texas.

(i) Rate design. Utilities shall consolidate existing rate classes into the minimum number of classes needed to recognize differences in usage of the transmission and distribution systems. Class consolidation shall not materially disadvantage any customer class.


Source Note: The provisions of this §25.344 adopted to be effective February 9, 2000, 25 TexReg 720; amended to be effective May 13, 2018, 43 TexReg 3001

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