Part 2.
PUBLIC UTILITY COMMISSION OF TEXAS
Chapter 25.
SUBSTANTIVE RULES APPLICABLE TO ELECTRIC SERVICE PROVIDERS
Subchapter E. CERTIFICATION, LICENSING AND REGISTRATION
16 TAC §25.101
The Public Utility Commission of Texas (commission) proposes
an amendment to §25.101 relating to Certification Criteria. The proposed
amendment will revise §25.101(c) by establishing criteria for the commission
to consider in its evaluation of applications for approval of electric transmission
lines. The proposed amendment will also remove references to Chapter 23, §25.173,
and will make other non-substantive changes. Project Number 24101 has been
assigned to this proceeding.
Mel Eckhoff, Engineering Specialist, Electric Division, has determined
that for each year of the first five-year period the proposed section is in
effect there will be no fiscal implications for state or local government
as a result of enforcing or administering the section.
Mr. Eckhoff has also determined that for each year of the first five years
the proposed section is in effect the public benefit anticipated is that the
impact on directly affected landowners will be minimized as a result of enforcing
the section. There will be no effect on small businesses or micro-businesses
as a result of enforcing this section. There is no anticipated economic cost
to persons who are required to comply with the section as proposed.
Mr. Eckhoff has also determined that for each year of the first five years
the proposed section is in effect there should be no effect on a local economy,
and therefore no local employment impact statement is required under Administrative
Procedure Act 2001.022.
The commission staff will conduct a public hearing on this rulemaking under
Government Code §2001.029 at the commission's offices, located in the
William B. Travis Building, 1701 North Congress Avenue, Austin, Texas 78701,
on Tuesday, August 7, 2001 at 10:00 a.m. in the Commissioners' Hearing Room
on the seventh floor.
Comments on the proposed amendment (16 copies) may be submitted to the
Filing Clerk, Public Utility Commission of Texas, 1701 North Congress Avenue,
P.O. Box 13326, Austin, Texas 78711-3326, within 30 days after publication.
Reply comments may be submitted within 45 days after publication. The commission
invites specific comments regarding the costs associated with, and benefits
that will be gained by, implementation of the proposed section. The commission
will consider the costs and benefits in deciding whether to adopt the section.
All comments should refer to Project Number 24101.
Specifically, the commission requests comments on the question:
Should the commission prioritize the standards
set out in §25.101(c)(6)(D)?
This amendment is proposed under the Public Utility Regulatory
Act, Texas Utilities Code Annotated §14.002 (Vernon 1998, Supplement
2001) (PURA), which provides the Public Utility Commission of Texas with the
authority to make and enforce rules reasonably required in the exercise of
its powers and jurisdiction, §37.051 that requires an electric utility
to obtain certification for electric facilities, and §37.056, which governs
the issuance of certificates of convenience and necessity for electric facilities.
Cross Reference to Statutes: PURA §14.002, and, PURA Chapter 37, Subchapter
B.
§25.101.Certification Criteria.
(a) - (b)
(No change.)
(c)
Certificates of convenience and necessity for new service
areas and facilities. Except for certificates granted under subsection (b)
of this section, the commission may grant an application and issue a certificate
only if it finds that the certificate is necessary for the service, accommodation,
convenience, or safety of the public. For transmission line certificate applications
the commission shall give great weight to the recommendation of the Electric
Reliability Council of Texas (ERCOT) Independent System Operator (ISO) in
determining the need for a proposed transmission line. [
(1) - (4)
(No change.)
(5)
Expedited Approval:
(A)
Uncontested applications: Except for an application for
a new transmission line, an application for a certificate under
paragraph
(1) of this
subsection [
(i)
(No change.)
(ii)
the
commission staff
[
(B)
(No change.)
(C)
Uncontested transmission lines: An application for a certificate
for a transmission line shall be approved administratively within 80 days
from the date of filing a complete application if:
(i) - (ii)
(No change.)
(iii)
the
commission
[
(D)
(No change.)
(6)
Standards of construction. In determining standard practice,
the commission will be guided by the provision of the American National Standards
Institute, Incorporated, the National Electric Safety Code, and such other
codes and standards that are generally accepted by the industry, except as
modified by this commission or by municipal regulations within their jurisdiction.
Each electric utility shall construct, install, operate, and maintain its
plant, structures, equipment, and lines in accordance with these standards,
and in such manner to best accommodate the public, and to prevent interference
with service furnished by other public utilities insofar as practical.
(A) - (C)
(No change.)
(D)
A new transmission line shall meet the
criteria in the Public Utility Regulatory Act (PURA) §37.056 and shall
be routed to the extent practical to moderate the impact on directly affected
landowners unless grid reliability and security dictate otherwise. The following
factors shall be considered in assessing the impact on directly affected landowners:
(i)
whether the preferred and alternate routes utilize existing
compatible rights-of-way, including the use of vacant positions on existing
multiple-circuit transmission lines;
(ii)
whether the preferred and alternate routes parallel existing
compatible rights-of-way; and
(iii)
whether the preferred and alternate routes parallel property
lines.
(d) - (f)
(No change.)
[(g)
To the extent that any portion of Chapter
23 of this title may be inconsistent with this section, this section controls.]
This agency hereby certifies that the proposal has been reviewed
by legal counsel and found to be within the agency's legal authority to adopt.
Filed with the Office of
the Secretary of State, on June 1, 2001.
TRD-200103061
Rhonda Dempsey
Rules Coordinator
Public Utility Commission of Texas
Earliest possible date of adoption: July 15, 2001
For further information, please call: (512) 936-7308
2.
RECOVERY OF STRANDED COSTS
16 TAC §25.263
The Public Utility Commission of Texas (commission) proposes
new §25.263 relating to True-Up Proceeding required pursuant to the Public
Utility Regulatory Act (PURA) §39.262. The proposed new rule establishes
the process for quantifying and reconciling stranded costs, the differences
in the price of power obtained through the capacity auctions and the power
costs used in the excess cost over market (ECOM) model, the results of the
annual reports, the level of excess revenues for customers who continue to
pay the price to beat, the reasonable regulatory assets not previously approved
in a rate order that are being recovered through competition transition charges
or transition charges, and the final fuel balances. Project Number 23571 has
been assigned to this proceeding.
When commenting on specific subsections of the proposed rule, parties are
encouraged to describe "best practice" examples of regulatory policies, and
their rationale, that have been proposed or implemented successfully in other
states already undergoing electric industry restructuring, if the parties
believe that Texas would benefit from application of the same policies. The
commission is only interested in receiving "leading edge" examples that are
specifically related and directly applicable to the Texas statute, rather
than broad citations to other state restructuring efforts.
In addition to comments on the proposed rule, the commission requests that
parties specifically address the following issues:
1. The true-up adjustment required by PURA §39.262(d)(2) is determined
in the proposed rule by calculating the effect on ECOM of using capacity auction
prices, actual fuel costs, and actual sales as certain inputs to the ECOM
model. Are there any substantive differences between using this method versus
a method in which the adjustment is simply the difference between the price
of power obtained through the capacity auctions and the corresponding power
cost projections used in the ECOM model in the PURA §39.201 proceeding?
If so, should an alternative method for calculating the adjustment required
by PURA §39.262(d)(2) be incorporated into the final rule?
2. Should the final rule incorporate criteria for determining whether a
utility has used good- faith attempts to renegotiate above-cost fuel and purchased
power costs as required by PURA §39.252(d)? If so, what should those
criteria be?
3. The definitions of market price used in subsection (j) of the proposed
rule use the same mix of power products (i.e., based on a three-year full
requirements request for proposal and 12 months of capacity auction products)
developed in the price to beat rule (Substantive Rule §25.41) to permit
adjustments to the price to beat. Is this the appropriate method to determine
the "prevailing market price" or is another method more appropriate? If this
method is appropriate, should the prices used be forward looking or should
they be historical prices?
Figures 1 and 2, based on positive and negative true-up balances, respectively,
provide various scenarios illustrating the treatment of the true-up balance
pursuant to the rule.
Figure 1: 16 TAC Chapter 25 - preamble
Figure 2: 16 TAC Chapter 25 - preamble
Darryl Tietjen, Director of Financial Analysis, Financial Review Division,
has determined that for each year of the first five-year period the proposed
section is in effect there will be no fiscal implications for state or local
government as a result of enforcing or administering the section.
Mr. Tietjen has also determined that for each year of the first five years
the proposed section is in effect the public benefit anticipated as a result
of enforcing the section will be a final reconciliation of amounts due the
unbundled successors-in-interest of deregulated electric utilities. There
will be no effects on small businesses or micro-businesses as a result of
enforcing this section. There will be economic costs to persons who are required
to comply with the section as proposed associated with preparing and processing
their true-up applications and defending their applications at hearing, if
necessary. There may also be additional economic costs to such persons if
they are required to return funds to electric customers as a result of the
true-up proceeding.
Mr. Tietjen has also determined that for each year of the first five years
the proposed section is in effect there should be no effect on a local economy,
and therefore no local employment impact statement is required under Administrative
Procedure Act §2001.022.
The commission staff will conduct a public hearing on this rulemaking under
Government Code §2001.029 at the commission's offices, located in the
William B. Travis Building, 1701 North Congress Avenue, Austin, Texas 78701,
on Wednesday, July 25, 2001, at 9:00 a.m. in the Commissioners' Hearing Room
on the 7th floor.
Comments on the proposed new rule (16 copies) may be submitted to the Filing
Clerk, Public Utility Commission of Texas, 1701 North Congress Avenue, P.O.
Box 13326, Austin, Texas 78711-3326, within 30 days after publication. Reply
comments may be submitted within 45 days after publication. The commission
invites specific comments regarding the costs associated with, and benefits
that will be gained by, implementation of the proposed section. The commission
will consider the costs and benefits in deciding whether to adopt the section.
All comments should refer to Project Number 23571.
This new rule is proposed under the Public Utility Regulatory
Act, Texas Utilities Code Annotated §14.002 (Vernon 1998, Supplement
2001) (PURA), which provides the Public Utility Commission with the authority
to make and enforce rules reasonably required in the exercise of its powers
and jurisdiction; and specifically, PURA §39.252 which addresses a utility's
right to recover stranded costs and PURA §39.262 which requires the commission
to conduct a true-up proceeding for each investor-owned electric utility after
the introduction of customer choice and which prohibits overrecovery of stranded
costs.
Cross Reference to Statutes: Public Utility Regulatory Act §§14.002,
39.252 and 39.262.
§25.263.True-up Proceeding.
(a)
Purpose.
(1)
The purpose of the true-up proceeding is to quantify and
reconcile the amount of stranded costs, the differences in the price of power
obtained through the capacity auctions and the power costs used in the excess
costs over market (ECOM) model, the results of the annual reports, the level
of excess revenues from customers who continue to pay the price to beat, the
reasonable regulatory assets not previously approved in a rate order that
are being recovered through competition transition charges (CTCs) or transition
charges (TCs), and the final fuel balances.
(2)
An electric utility, together with its affiliated retail
electric provider (AREP), its affiliated power generation company (APGC),
and its affiliated transmission and distribution utility, shall not be permitted
to overrecover stranded costs through the application of the measures provided
in the Public Utility Regulatory Act (PURA), Chapter 39, or under the procedures
established in PURA §39.262 and this section.
(b)
Application. This section applies to all investor-owned
transmission and distribution utilities established pursuant to PURA §39.051,
their affiliated power generation companies, and their affiliated retail electric
providers.
(c)
Definitions. The following words and terms, when used in
this section, shall have the following meanings unless the context indicates
otherwise:
(1)
Capacity auction total price of power ($/MWh)--The total
(fuel plus non-fuel) capacity auction revenues divided by the total capacity
auction energy delivered for a specified time period.
(2)
Mitigation--The total excess earnings and redirected depreciation
applied to generation assets pursuant to PURA §39.254 and §39.256
or a commission order.
(3)
Net mitigation--Any mitigation that has not been reversed
or refunded as of the date of the final order in the true-up proceeding.
(4)
Net value realized--All compensation paid by a buyer for
generating assets, including the buyer's assumption of debt, less any costs
of sale such as legal fees, broker fees, and other reasonable transaction
costs.
(5)
Projected stranded costs--The value produced by the ECOM
model and approved by the commission in the proceeding conducted pursuant
to PURA §39.201.
(6)
Regulatory assets--The generation-related portion of the
Texas jurisdictional portion of the amount reported by the electric utility
in its 1998 annual report on Securities and Exchange Commission Form 10-K
as regulatory assets and liabilities, offset by the applicable portion of
generation-related investment tax credits permitted under the Internal Revenue
Code of 1986.
(7)
Residential market price of electricity--The simple average
of the results of a three-year request for proposal for full-requirements
service for 10% of residential price to beat load and the most recent aggregated
12-month forward capacity auction prices, utilizing the appropriate mix of
capacity auction products needed to serve residential customers.
(8)
Residential net price to beat--The average residential
price to beat rate (expressed in cents per kilowatt-hour) in effect on January
1, 2004, less the average non- bypassable charges (expressed in cents per
kilowatt-hour) applicable to residential customers.
(9)
Small commercial market price of electricity--The simple
average of the results of a three-year request for proposal for full-requirements
services for 10% of small commercial price to beat load and the most recent
aggregated 12-month forward capacity auction prices, utilizing the appropriate
mix of capacity auction products needed to serve small commercial customers.
(10)
Small commercial net price to beat--The average small
commercial price to beat rate (expressed in cents per kilowatt-hour) in effect
on January 1, 2004, less the average non-bypassable charges (expressed in
cents per kilowatt-hour) applicable to small commercial customers.
(11)
Transferee corporation--A separate affiliated or non-affiliated
company to whom an electric utility or its APGC transfers generation assets.
(12)
Transmission and distribution utility (TDU)--A transmission
and distribution utility that, pursuant to PURA §39.051, is the successor
in interest of an electric utility certificated to serve an area.
(13)
Transmission and distribution utility region (TDU region)--The
affiliated transmission and distribution utility's service territory.
(d)
Obligation to file a true-up proceeding.
(1)
Each TDU, its APGC, and its AREP shall jointly file after
January 12, 2004, on a schedule to be determined by the commission, a true-up
application pursuant to subsection (e) of this section.
(2)
Each TDU that is a successor in interest of any utility
that was reported by the commission to have positive ECOM, denoted as the
"base case" for the amount of stranded costs before full retail competition
in 2002 with respect to its Texas jurisdiction in the April 1998 Report to
the Texas Senate Interim Committee on Electric Utility Restructuring entitled
"Potentially Strandable Investment (ECOM) Report: 1998 Update," and such TDU's
APGC and AREP, shall file the true-up application as required by subsections
(f) - (k) of this section.
(3)
All TDUs not described in paragraph (2) of this subsection,
their APGCs, and their AREPs shall file the applications required by subsections
(h) and (j) of this section.
(e)
True-up filing procedures.
(1)
Each TDU, APGC and AREP shall file all testimony and schedules
on which they intend to rely in accordance with the true-up filing package
prescribed by the commission.
(A)
Within 20 calendar days of the filing of a true-up application,
commission staff or any intervenor may file a motion stating that the filing
is materially deficient. Any such motion shall include a detailed explanation
of the claimed material deficiencies.
(B)
If the presiding officer determines that an application
is materially deficient, the TDU, APGC, and AREP shall correct the deficiencies
within 30 calendar days. The deadline for final commission order shall be
extended day for day from the date of initial filing until the corrections
are filed with the commission.
(2)
At least 180 days prior to the filing of the first true-up
application scheduled by the commission, a utility's APGC shall file a notification
of intent with the commission if it intends to utilize PURA §39.262(i)
to determine the amount of its stranded costs for nuclear assets.
(3)
The commission may initiate a generic proceeding to determine
true-up issues that are common to multiple TDUs, APGCs and AREPs. This proceeding
may include updates to the ECOM model required by subsection (f)(2)(B) of
this section, in the event a notification of intent is filed pursuant to paragraph
(2) of this subsection. The commission may order further updates to any order
approved in a generic proceeding pursuant to this section for any utility
whose customers are not offered competition on January 1, 2002.
(4)
As part of the true-up proceeding, the commission shall
make a determination with respect to whether the TDU, the APGC, and the AREP
have complied with PURA §39.252(d). If the commission finds that the
TDU, the APGC, or the AREP have failed, individually or in combination, to
fully comply with their obligations under PURA §39.252(d), the commission
may reduce the net book value of the APGC's generation assets or take other
measures it deems appropriate in the true- up proceeding filed under this
section.
(5)
The State Office of Administrative Hearings shall employ
expedited procedures during discovery in the true-up proceedings.
(6)
The commission shall issue the final order for each proceeding
filed under this section not later than the 150th day after the filing of
a complete, non-deficient application. Notwithstanding the foregoing, however,
the 150-day deadline may be extended by the commission for good cause.
(f)
Quantification of market value of generation assets.
(1)
Market value of generation assets shall be quantified using
one or more of the following methods:
(A)
Sale of assets method. If an electric utility or its APGC
sells some or all of its generation assets after December 31, 1999, in a bona
fide third-party transaction under a competitive offering, the total net value
realized from the sale shall establish the market value of the generation
assets sold. The utility shall provide to the commission, at least 120 days
prior to the transfer, a detailed explanation of the transaction and a complete
description of all assets to be sold, including any ancillary items related
to the assets.
(B)
Stock valuation method. The following method of market
valuation without using a control premium may be used to value generation
assets.
(i)
If, at any time after December 31, 1999, an electric utility
or its APGC has transferred some or all of its generation assets, including,
at the election of the electric utility or the APGC, any fuel and fuel transportation
contracts related to those assets, to one or more separate affiliated or nonaffiliated
corporations, not less than 51% of the common stock of each corporation is
spun off and sold to public investors through a national stock exchange, and
the common stock has been traded for not less than one year, the resulting
average daily closing price of the common stock over 30 consecutive trading
days chosen by the commission out of the last 120 consecutive trading days
before the true-up filing required by this section establishes the market
value of the common stock equity in each transferee corporation.
(ii)
The average book value of each transferee corporation's
debt and preferred stock securities during the 30-day period chosen by the
commission to determine the market value of common stock shall be added to
the market value of its stock.
(iii)
The market value of each transferee corporation's assets
that is determined as the sum of clauses (i) and (ii) of this subparagraph
shall be reduced by the corresponding net book value of the assets acquired
by the transferee corporation from any entity other than the affiliated electric
utility or power generation company.
(iv)
The market value of the assets determined from the procedures
required by clauses (i), (ii), and (iii) of this subparagraph establishes
the market value of the generation assets transferred by the electric utility
or power generation company to each separate corporation.
(C)
Partial stock valuation method. The following method of
market valuation using a control premium may be used to value generation assets.
(i)
If, at any time after December 31, 1999, an electric utility
or its APGC has transferred some or all of its generation assets, including,
at the election of the electric utility or the APGC, any fuel and fuel transportation
contracts related to those assets, to one or more separate affiliated or nonaffiliated
corporations, at least 19%, but less than 51%, of the common stock of each
corporation is spun off and sold to public investors through a national stock
exchange, and the common stock has been traded for not less than one year,
the resulting average daily closing price of the common stock over 30 consecutive
trading days chosen by the commission out of the last 120 consecutive trading
days before the filing establishes the market value of the common stock equity
in each transferee corporation.
(ii)
The commission may accept the market valuation to conclusively
establish the value of the common stock equity in each transferee corporation
or convene a valuation panel of three independent financial experts to determine
whether the per-share value of the common stock sold is fairly representative
of the per-share value of the total common stock equity or whether a control
premium exists for the retained interest.
(iii)
Should the commission elect to convene a valuation panel,
the panel must consist of financial experts chosen from proposals submitted
in response to commission requests from the top ten nationally recognized
investment banks with demonstrated experience in the United States electric
industry, as indicated by the dollar amount of public offerings of long-term
debt and equity of United States investor-owned electric companies over the
immediately preceding three years as ranked by the publication "Securities
Data" or "Institutional Investor."
(iv)
None of the financial experts chosen for the panel shall
have participated, or be employed by an investment house or brokerage house
which has participated, in the business separation, securitization, or other
activities related to the implementation of PURA Chapter 39 on behalf of the
utility for which the market valuation is being determined.
(v)
If the panel determines that a control premium exists for
the retained interest, the panel shall determine the amount of the control
premium, and the commission shall adopt the determination, but may not use
the control premium to increase the market value of the assets by more than
10%.
(vi)
The costs and expenses of the panel, as approved by the
commission, shall be paid by each transferee corporation.
(vii)
The determination of the commission, based on the finding
of the panel and other admitted evidence, conclusively establishes the value
of the common stock of each transferee corporation.
(viii)
The average book value of each transferee corporation's
debt and preferred stock securities during the 30-day period chosen by the
commission to determine the market value of common stock shall be added to
the market value of its stock.
(ix)
The market value of each transferee corporation's assets
shall be reduced by the corresponding net book value of the assets acquired
by the transferee corporation from any entity other than the electric utility
or its APGC.
(x)
The market value of the assets resulting from the procedures
required by clauses (i) - (ix) of this subparagraph establishes the market
value of the generation assets transferred by the electric utility or APGC
to each transferee corporation.
(D)
Exchange of assets method. If, at any time after December
31, 1999, an electric utility or its APGC transfers some or all of its generation
assets, including any fuel and fuel transportation contracts related to those
assets, in a bona fide third-party exchange transaction, the stranded costs
related to the transferred assets shall be the difference between the net
book value and the market value of the transferred assets at the time of the
exchange, taking into account any other consideration received or given.
(i)
The market value of the transferred assets may be determined
through an appraisal by a nationally recognized independent appraisal firm,
if the market value is subject to a market valuation by means of an offer
of sale in accordance with this subparagraph.
(ii)
To obtain a market valuation by means of an offer of sale,
the owner of the asset shall offer it for sale to other parties under procedures
that provide broad public notice of the offer and a reasonable opportunity
for other parties to bid on the asset.
(iii)
The owner of the asset may establish a reserve price
for any offer based on the sum of the appraised value of the asset and the
tax impact of selling the asset, as determined by the commission.
(iv)
The utility shall provide to the commission, at least
120 days prior to the transfer, a detailed explanation of the transaction
and a complete description of all assets to be exchanged, including any ancillary
items related to the assets.
(2)
ECOM Method. Unless an electric utility or its APGC combines
all its remaining generation assets into one or more transferee corporations
pursuant to paragraph (1)(B) or (C) of this subsection, the electric utility
shall quantify its stranded costs for nuclear assets using the ECOM method.
(A)
The ECOM method is the estimation model prepared for and
described by the commission's April 1998 Report to the Texas Senate Interim
Committee on Electric Restructuring entitled "Potentially Strandable Investment--
ECOM Report: 1998 Update." The methodology used in the model must be the same
as that used in the 1998 report to determine the "base case."
(B)
As part of the filing specified in subsection (d) of this
section, the electric utility shall rerun the ECOM model using updated company
specific inputs required by the model, updating the market price of electricity,
and using updated natural gas price forecasts and the capacity cost based
on the long- run marginal cost of the most economic new generation technology
then available, as approved by the commission pursuant to subsection (e)(3)
of this section. Natural gas price projections used in the model shall be
forward prices of Houston Ship Channel natural gas.
(C)
Growth rates in generating plant operations and maintenance
costs and allocated administrative and general costs shall be benchmarked
by comparing those costs to the best available information on cost trends
for comparable generating plants.
(D)
Capital additions shall be benchmarked using the 1.5% limitation
set forth in PURA §39.259(b).
(g)
Quantification of net book value of generation assets.
(1)
For purposes of this section, the net book value of generation
assets shall be established as of December 31, 2001, or the date a market
value is established through a market valuation method under subsection (f)
of this section, whichever is earlier.
(2)
Net book value of generation assets consists of:
(A)
The generation-related electric plant in service, less
accumulated depreciation, plus generation-related asset additions as allowed
in the ECOM model filed pursuant to the unbundled cost of service (UCOS) rate
filing package, reduced by:
(i)
net mitigation;
(ii)
the net book value of nuclear generation assets if quantification
of ECOM related to those nuclear generation assets is determined pursuant
to PURA §39.262(i); and
(iii)
any generation-related invested capital recoverable through
a CTC, exclusive of related carrying costs, projected to be collected through
the date of the final order in the true-up proceeding.
(B)
Above-market purchased power costs arising from contracts
in effect before January 1, 1999.
(i)
The purchased power market value of the demand and energy
included in the purchased power contracts shall be determined by using the
weighted average costs of the highest three offers from a bona fide third-party
transaction or transactions on the open market.
(ii)
The bona fide third-party transaction or transactions
on the open market shall be structured so that the above-market purchased
power costs are determined pursuant to subclause (I) or (II) of this clause.
(I)
A transaction may be structured so the electric utility
pays a third party to assume the utility's obligations under the purchased
power contract. The weighted average of the three highest offers received
in the transaction establishes the above-market purchased power costs.
(II)
A transaction may be structured so a third party pays
the utility to take power under the purchased power contract. The difference
between the net present value of obligations under the existing contracts
at the utility's cost of capital and the weighted average of the three highest
offers received in the transaction establishes the above-market purchased
power costs.
(C)
Deferred debits related to a utility's discontinuance of
the application of SFAS No. 71 ("Accounting for the Effects of Certain Types
of Regulation") for generation-related assets if required by PURA Chapter
39.
(D)
Capital costs incurred before May 1, 2003 to improve air
quality to the extent they have been approved by the commission pursuant to §25.261
of this title (relating to Stranded Cost Recovery of Environmental Cleanup
Costs).
(E)
Any adjustments resulting from the commission's review
of the TDU's, APGC's, and AREP's efforts pursuant to subsection (e)(4) of
this section.
(h)
True-up of final fuel balance.
(1)
An APGC shall reconcile the former electric utility's final
fuel balance determined under PURA §39.202(c).
(2)
The final fuel balance shall be reduced by any revenues
collected by the AREP under any commission-approved fuel surcharge, from the
date of introduction of competition to the utility's customers through the
date of the true-up filing under this section.
(3)
If an electric utility or its TDU or APGC is assessed by
another utility in Texas a fuel surcharge after 2001 for underrecoveries occurring
through the end of 2001, the surcharged utility shall add the amount of surcharges
paid after 2001 to its final fuel balance calculated pursuant to this section.
(4)
The final fuel balance shall include carrying costs on
the positive or negative fuel balance equal to the rate approved in §25.236
of this title (related to Recovery of Fuel Costs) until the date of the final
true-up order.
(i)
True-up of capacity auction proceeds.
(1)
For purposes of the true-up required by PURA §39.262(d)(2),
and for final reconciliation of monthly capacity auction true-up adjustment
amounts billed or credited by the APGC as provided for under §25.381(h)(1)
of this title (related to Capacity Auctions), the APGC shall compute the difference
in ECOM resulting from any difference between the capacity auction total price
of power and the power cost projections for the same time period as used in
the determination of ECOM for each utility in the proceeding under PURA §39.201.
(2)
The ECOM.xls model that supports the APGC's commission-approved
ECOM run in the proceeding under PURA §39.201 shall be used to calculate
the capacity auction true-up amount for each year. This will be accomplished
by calculating the revised ECOM amount resulting from substituting the capacity
auction total price of power for the projected ECOM market prices as included
on rows 5, 9, and 13 of the "Prices" worksheet of the ECOM.xls model for 2002
and 2003. The APGC shall also update the fuel expense for 2002 and 2003 based
on the actual fuel costs incurred by the APGC. The APGC shall also update
the sales for 2002 and 2003 based on the actual system-wide megawatt-hours
at the busbar. The difference between this revised ECOM amount and the ECOM
amount approved by the commission in the proceeding under PURA §39.201
will be calculated to produce the change in ECOM resulting from use of the
capacity auction total price of power for that year.
(j)
True-up of price to beat revenues. This subsection specifies
how the forty- percent threshold is calculated and how the price to beat comparison
is made.
(1)
An AREP is not required to perform the reconciliation described
in PURA §39.262(e) for the residential or small commercial customer class
if the commission has determined that the AREP has reached the applicable
40% threshold requirements prior to January 1, 2004, pursuant to filing requirements
listed in §25.41(l) of this title (relating to Price to Beat) applicable
to that class.
(2)
If an AREP has not reached the applicable 40% threshold
requirements prior to January 1, 2004, for either the residential or the small
commercial class, or both, the net price to beat for each such class must
be compared to the market price of electricity for that class in the TDU region
on January 1, 2004 as provided in paragraphs (3) and (4) of this subsection.
(3)
If the 40% consumption threshold has not been reached for
the residential class, the utility shall compute the difference between the
residential net price to beat and the residential market price of electricity.
The difference shall be multiplied by the total kilowatt-hours consumed by
residential net price to beat customers of the AREP for the period beginning
January 1, 2002 and ending January 1, 2004.
(4)
If the 40% consumption threshold has not been reached for
the small commercial class, the utility shall compute the difference between
the small commercial net price to beat and the small commercial market price
of electricity. The difference shall be multiplied by the total kilowatt-hours
consumed by small commercial price to beat customers for the period beginning
January 1, 2002 and ending January 1, 2004.
(5)
For each of the residential and small commercial classes,
the AREP shall credit the TDU the lesser of the amounts calculated in subparagraphs
(A) and (B) of this paragraph:
(A)
$150 multiplied by (the difference between the number of
residential or small commercial customers, as applicable, in the TDU Region
taking price to beat service from the AREP on January 1, 2004 and the number
of residential or small commercial customers, as applicable, outside the TDU
region being served by the AREP on January 1, 2004); or
(B)
the total differential between the net price to beat and
the market price of electricity calculated for the applicable class under
paragraph (3) or (4) of this subsection.
(k)
Regulatory assets. To the extent that any amount of regulatory
assets included in a TC or CTC exceeds the amount of regulatory assets approved
in a rate order which became effective on or before September 1, 1999, the
commission shall conduct a review during the true-up proceeding to determine
any such amounts that were not appropriately calculated or that did not constitute
reasonable and necessary costs.
(l)
TDU/APGC True-up balance.
(1)
The formula to establish the true-up balance between the
TDU and APGC is shown in the following table. TDUs described in subsection
(d)(3) of this section and their APGCs shall insert zero for all inputs in
this equation except the input entitled "Final fuel balance calculated pursuant
to subsection (h)."
Figure: 16 TAC §25.263(l)(1)
(2)
For TDUs described in subsection (d)(2) of this section,
the TDU/APGC true-up balance shall be compared to projected stranded costs
as provided in subparagraphs (A) - (C) of this paragraph. For TDUs described
in subsection (d)(3) of this section, the TDU/APGC true-up balance shall be
treated as provided in subparagraph (D) of this paragraph.
(A)
If the TDU/APGC true-up balance is positive, and greater
than projected stranded costs, then the commission shall increase the CTC
(or establish a CTC, if no CTC has previously been approved for the utility),
extend the time for the collection of the CTC, or both, to enable the TDU
to collect the TDU/APGC true-up balance. The utility may seek to securitize
any or all of the amounts determined under this subparagraph under PURA Chapter
39, Subchapter G.
(B)
If the TDU/APGC true-up balance is positive, but less than
projected stranded costs, then the commission shall reduce non-bypassable
delivery rates in the amount of the difference by:
(i)
reducing any CTC established under PURA §39.201;
(ii)
reversing, in whole or in part, the depreciation expense
that has been redirected under PURA §39.256;
(iii)
reducing the TDU's rates; or
(iv)
any combination of clauses (i), (ii), and (iii) of this
subparagraph.
(C)
If the TDU/APGC true-up balance is negative, then
(i)
any CTC established under PURA §39.201 shall be eliminated;
(ii)
net mitigation shall be reversed until exhausted or until
a zero true-up balance is achieved, and the amount of net mitigation reversed
shall be returned to ratepayers by the APGC through an excess mitigation credit;
and
(iii)
if net mitigation is exhausted and some amount of the
negative true- up balance remains, then a negative CTC shall be established
based upon the lesser of the absolute value of the remaining negative true-up
balance or the securitization amount on which any TCs are based.
(D)
If the TDU/APGC true-up balance is positive, then a CTC
shall be imposed to enable the APGC to recover any positive fuel balance.
If the TDU/APGC true-up balance is negative, then a fuel credit shall be implemented
to return the over-recovered fuel balance to ratepayers.
(3)
The TDU shall be allowed to recover, or shall be liable
for, carrying costs on the true- up balance. Carrying costs shall be calculated
using the utility's cost of capital established in the utility's UCOS proceeding,
and shall be calculated for the period of time from the date of the true-up
final order until fully recovered.
(m)
TDU/AREP true-up balance. The TDU shall bill the AREP for,
and the AREP shall remit to the TDU, the amount calculated pursuant to subsection
(j) of this section, plus carrying costs. Carrying costs shall be calculated
using the utility's cost of capital established in the utility's UCOS proceeding,
and shall be calculated for the period of time from the date of the true-up
final order until fully recovered. The commission may reduce the TDU's rates
to reflect the amounts due from the AREP.
(n)
Rate case subsequent to the true-up proceeding.
(1)
The TDU shall file an application to adjust its rates within
60 days following the issuance of a final, appealable order on its true-up
proceeding. In the rate case, the commission shall adjust the TDU's rates
and any CTC approved in the true-up proceeding, and allocate the recovery
responsibility for such rates and any CTC to the TDU's customer classes.
(2)
In the rate case, the commission shall also consider adopting
remittance standards, if necessary, with respect to the credits or bills as
among the TDU, the APGC and the AREP.
This agency hereby certifies that the proposal has been
reviewed by legal counsel and found to be within the agency's legal authority
to adopt.
Filed with the Office of
the Secretary of State, on May 30, 2001.
TRD-200103037
Rhonda Dempsey
Rules Coordinator
Public Utility Commission of Texas
Earliest possible date of adoption: July 15, 2001
For further information, please call: (512) 936-7308
Subchapter M. OPERATOR SERVICES
This subsection
does not apply to a certificate of convenience and necessity for a new generating
plant requested as part of the integrated resource planning process under §25.171
of this title (relating to Certificates of Convenience and Necessity for Generation
Facilities).
]
(c)(1) of this section
] shall be
approved administratively within 80 days from the date of filing a complete
application if:
Office of Regulatory
Affairs Staff
] has determined that the application meets all applicable
statutory criteria and filing requirements, including, but not limited to,
the provision of proper notice of the application.
Office of Regulatory
Affairs
] staff has determined that the application meets all applicable
statutory criteria and filing requirements, including, but not limited to,
the provision of proper notice of the application.
Subchapter J. COSTS, RATES AND TARIFFS
Chapter 26.
SUBSTANTIVE RULES APPLICABLE TO TELECOMMUNICATIONS SERVICE PROVIDERS