SECTION 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, 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:

(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, 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.

Source Note: The provisions of this §25.263 adopted to be effective December 24, 2001, 26 TexReg 10498; amended to be effective August 7, 2003, 28 TexReg 5993; amended to be effective June 2, 2004, 29 TexReg 5338; amended to be effective July 20, 2006, 31 TexReg 5603