Current through Reg. 50, No. 13; March 28, 2025
(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, net of nonbypassable delivery charges,
from customers who continue to pay the price to beat (PTB); 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. The purpose of the true-up proceeding is
also to provide for the recovery of regulatory assets not already approved for
securitization that were to be considered in future proceedings pursuant to a
commission financing order in a securitization case.
(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 (TDU),
shall not be permitted to over-recover 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 APGCs,
and their AREPs. In addition, the reporting requirements of subsection (j)(6)
of this section apply to all retail electric providers (REPs) serving
residential and small commercial customers.
(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 for entitlements to capacity for the years 2002 and 2003
divided by the total capacity auction energy (expressed in MWh) scheduled to be
delivered for those entitlements over the same time period.
(2) Independent third party--The party
designated by the commission to perform the duties described in subsection (j)
of this section.
(3)
Mitigation--The total excess earnings and redirected depreciation applied to
generation assets pursuant to PURA §39.254 and §39.256 or a
commission order issued after 1996 that approved a utility's transition
case.
(4) Net mitigation--Any
mitigation that has not been reversed or refunded as of the date of the final
order in the true-up proceeding.
(5) Net value realized--All compensation paid
by a buyer for generation assets, including the buyer's assumption of debt,
less any costs of sale such as legal fees, broker fees, and other reasonable
transaction costs.
(6) Projected
stranded costs--The value produced by the ECOM model and approved by the
commission in the proceeding conducted pursuant to PURA §39.201.
(7) 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.
(8) Residential market price of
electricity--The volume-weighted average price, less average nonbypassable
charges (each expressed in cents per kilowatt-hour (kWh)), calculated by the
independent third party for residential electric service provided by
non-affiliated retail electric providers and non-provider of last resort (POLR)
service providers competing in the TDU region. The price determined by the
independent third party shall be based upon pricing disclosures pursuant to
§
25.475(e) of
this title (relating to Information Disclosures to Residential and Small
Commercial Customers) and other information provided to the independent third
party.
(9) Residential net price to
beat--The average residential PTB rate (expressed in cents per kWh) less the
average nonbypassable charges (expressed in cents per kWh) applicable to
residential customers.
(10) Small
commercial market price of electricity--The volume-weighted average price, less
average nonbypassable charges (each expressed in cents per kWh), calculated by
the independent third party for small commercial electric service provided by
non-AREPs and non-POLR service providers competing in the TDU region. The price
determined by the independent third party shall be based upon pricing
disclosures pursuant to §
25.475(e) of
this title and other information provided to the independent third
party.
(11) Small commercial net
price to beat--The average small commercial PTB rate (expressed in cents per
kWh) less the average nonbypassable charges (expressed in cents per kWh)
applicable to small commercial customers.
(12) Transferee corporation--A separate
affiliated or non-affiliated company to whom an electric utility or its APGC
transfers generation assets.
(13)
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.
(14) 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 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's, and AREP's, 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 for their direct case 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 90 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. In making a determination as to compliance with PURA
§39.252(d), the commission shall not substitute its judgment for a market
valuation of generation assets determined under PURA §39.262(h) or
(i).
(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. Within 30 days of closing, the utility or
its APGC shall provide to the commission a detailed explanation, which may be
filed confidentially, of the transaction and a description of the generating
unit, property boundaries, fuel and parts, emission allowances, and other
general categories of items associated with the sale, 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 APGC.
(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 affiliated electric utility or APGC 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) 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
value of the assets by more than 10%.
(v) The costs and expenses of the panel, as
approved by the commission, shall be paid by each transferee
corporation.
(vi) 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.
(vii) 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.
(viii) 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.
(ix) The market value of the assets resulting
from the procedures required by clauses (i) - (viii) 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. The owner of the asset shall provide to the commission copies of all
documentation explaining and attesting to the utility's sale
proposal.
(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)
Within 30 days of closing, the utility or its APGC shall provide to the
commission a detailed explanation, which may be filed confidentially, of the
transaction and a description of the generating unit, property boundaries, fuel
and parts, emission allowances, and other general categories of items
associated with the transfer, 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
(exclusive of depreciation related to mitigation), plus generation-related
construction work in progress, plant held for future use, and nuclear, coal,
and lignite fuel inventories, reduced by:
(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, including any amendments and revisions to such contracts
resulting from litigation initiated 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, to the extent they have
not been securitized, 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, so long as the fuel surcharge is associated with fuel costs
incurred during the time period covered by the final reconcilable fuel
balance.
(3) If an electric utility
or its TDU or APGC is assessed by another utility in Texas a fuel surcharge
after 2001 for under-recoveries occurring through the end of 2001, the
surcharged utility shall add the amount of surcharges and any associated
carrying costs paid after 2001 to its final fuel balance.
(4) The final fuel balance, as adjusted by
paragraphs (2) and (3) of this subsection, shall include carrying costs on the
positive or negative fuel balance equal to:
(A) the weighted-average cost of capital
approved in the company's unbundled cost of service (UCOS) proceeding, if the
period until the date of the final true-up order is greater than one year;
or
(B) the rate approved in §
25.236 of this title (relating to
Recovery of Fuel Costs) if the period until the date of the final true-up order
is one year or less.
(i) True-up of capacity auction proceeds.
(1) For purposes of the true-up required by
PURA §39.262(d)(2), and as provided for under §
25.381(h)(1) of
this title (relating to Capacity Auctions), the APGC shall compute the
difference between the price of power obtained through the capacity auctions
conducted for the years 2002 and 2003 and the power cost projections for the
same time period as used in the determination of ECOM for that utility in the
proceeding under PURA §39.201. The difference shall be calculated
according to the following formula: (ECOM market revenues - ECOM fuel costs) -
((capacity auction price x total 2002 and 2003 busbar sales) - actual 2002 and
2003 fuel costs). For purposes of this paragraph:
(A) "ECOM market revenues" shall be the sum
of rows 12 through 14 for the years 2002 and 2003 in the "Plant Economics"
worksheet of the ECOM model underlying the commission-approved ECOM estimate in
the company's UCOS proceeding;
(B)
"ECOM fuel costs" shall be the sum of rows 33 through 35 for the years 2002 and
2003 in the "Cost Partition" worksheet of the ECOM model underlying the
commission-approved ECOM estimate in the company's UCOS proceeding;
(C) The "capacity auction price" shall be the
APGC's total capacity auction revenues derived from the capacity auctions
conducted for the years 2002 and 2003 divided by that APGC's total MWh sales of
capacity auction products for the years 2002 and 2003.
(2) If, as a result of not having
participated in capacity auctions pursuant to §
25.381(h)(1) of
this title, an APGC is unable to determine a company-specific capacity auction
price, the APGC may request in its true-up application a method using
prevailing capacity auction prices from other APGCs for the calculation in
paragraph (1) of this subsection.
(j) True-up of PTB revenues. This subsection
specifies how the PTB will be compared to prevailing market prices pursuant to
PURA §39.262(e). For purposes of this subsection, the term "small
commercial customer" does not include unmetered lighting accounts unless such
an account has historically been treated as a separate customer for billing
purposes.
(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 PTB for each such class must be
compared to the market price of electricity for that class in the TDU region
for the period January 1, 2002 through January 1, 2004 as provided in
paragraphs (3) and (4) of this subsection.
(3) The independent third party shall compute
the difference between the residential net PTB and the residential market price
of electricity on the last day of each calendar-year quarter for the years 2002
and 2003. The price differential for each quarter shall be multiplied by the
total kWh consumed by residential PTB customers of the AREP for that quarter.
The results shall be summed over the eight quarters within the period from
January 1, 2002 through January 1, 2004.
(4) The independent third party shall compute
the difference between the small commercial net PTB and the small commercial
market price of electricity on the last day of each calendar-year quarter for
the years 2002 and 2003. The price differential for each quarter shall be
multiplied by the total kWh consumed by small commercial PTB customers of the
AREP for that quarter. The results shall be summed over the eight quarters
within the period from January 1, 2002 through 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 PTB 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, provided that such
customers are not receiving POLR service from the AREP); or
(B) the total differential between the net
PTB and the market price of electricity calculated for the applicable class
under paragraph (3) or (4) of this subsection.
(6) All REPs shall provide information to the
independent third party as needed for the performance of calculations set forth
in paragraphs (3) and (4) of this subsection. All data used in the calculations
performed by the independent third party will remain confidential but shall be
subject to audit by the commission.
(7) The functions of the independent third
party shall be funded by the AREPs through one or more assessments made by the
commission.
(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. In addition, to the extent that any amount of regulatory
assets approved for securitization in a commission financing order was not
subsequently included in an issuance of transition bonds, that amount of
regulatory assets shall be included in the TDU/APGC true-up balance under
subsection (l) of this section.
(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)."
Attached
Graphic
(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 nonbypassable 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 for companies that have securitized regulatory assets, 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. If the company has been issued a financing order by the
commission authorizing the securitization of regulatory assets but
securitization has not yet occurred, then the negative CTC will be implemented
at the time the securitization bonds are issued. If the company has not
received a financing order from the commission authorizing securitization of
regulatory assets, then no negative CTC shall be established for purposes of
this subsection.
(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. This provision
shall apply to all amounts the commission has authorized to be collected under
this section that have not been securitized. Carrying costs on the unrecovered
true-up balance shall be calculated from January 1, 2002, until the true-up
balance is fully recovered. Based on the filing described below that is made
within 30 days of the effective date of this rule, carrying costs shall be
calculated using an interest rate determined as follows.
(A) The TDU shall file an application to
adjust the carrying costs and amend its CTC tariff on a prospective basis in
conformance with this paragraph within 30 days of the effective date of an
amendment to this paragraph. The establishment of the interest rate used to
calculate carrying charges shall be based upon the following:
(i) The weighted average of the TDU's
unadjusted historical cost of debt (HC) and an adjusted form of the TDU's
marginal cost of debt (MC), with the weightings based on the utility's most
recently authorized capital structure. The HC component shall be the cost of
debt as determined in a final commission order, provided that the order was
entered within three years of the effective date of this rule, for a rate
proceeding in which the TDU's cost of debt was explicitly addressed or can be
determined based upon the order's authorized weighted-average cost of capital
(overall rate of return on invested capital), proportions of debt and equity,
and allowed return on equity. The MC component shall be based upon the average
yield for long-term bonds of public utilities with the TDU's current credit
rating during the three-month period preceding the filing, as published in
Moody's Credit Perspectives (or a similar publication if
Moody's Credit Perspectives is not available). Additionally,
the MC component shall be adjusted--
i.e., grossed-up--for the
effects of federal income taxes. The following formula shall be used to
determine the weighted-average carrying cost described above: CTC Carrying
Charge Rate = MC * Equity Proportion of Most Recently Authorized Capital
Structure * 1/(1-Tax Rate) + HC * Debt Proportion of Most Recently Authorized
Capital Structure.
(ii) If the
commission, within three years prior to the effective date of this rule, did
not enter a final order in a rate proceeding that addresses the TDU's cost of
debt, the HC component used in the interest rate determination described in the
preceding clause shall be based upon the cost of debt reported in the utility's
most recent Earnings Monitoring Report filed pursuant to §
25.73 of this title (relating to
Financial and Operating Reports), adjusted for known and measurable
changes.
(B) In each
rate case for the TDU, the calculation of carrying costs on the TDU's
unsecuritized true-up balance shall be reviewed and adjusted to reflect
authorized changes in the TDU's capital structure and cost of debt. Further, to
reflect the effect of the CTC carrying charge rate across the entirety of the
TDU's recoverable regulated assets, a composite rate of return incorporating
the CTC carrying charge rate may be applied to both the unsecuritized true-up
balance and the TDU rate base. The composite rate of return shall be calculated
as follows: Composite Pre-Tax Rate of Return = CTC Carrying Charge Rate *
Unsecuritized True-up Balance / (Unsecuritized True-up Balance + TDU Rate Base)
+ TDU Authorized Pre-Tax Weighted-Average Cost of Capital * TDU Rate Base /
(Unsecuritized True-up Balance + TDU Rate Base).
(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 in accordance with subsection (l) of this
section 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) Proceeding subsequent to the true-up.
(1) The TDU shall file an application to
adjust its rates within 60 days following the issuance of a final, appealable
order in its true-up proceeding. In the proceeding, the commission may adjust
the TDU's rates and any CTC, in accordance with PURA §39.262(g), and any
excess mitigation credit. The commission may also allocate the recovery
responsibility for such rates and any CTC to the TDU's customer
classes.
(2) In the proceeding, 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.