|(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
(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
(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):
(D) transmission and distribution utility metering
(E) transmission and distribution utility billing system
(F) additional retail billing services;
(G) transmission and distribution utility customer
(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
(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
(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
(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