(a) An electric utility, together with its affiliated retail electric provider and its affiliated transmission and distribution utility, may not be permitted to overrecover stranded costs through the procedures established by this section or through the application of the measures provided by the other sections of this chapter.
(b) After the freeze period, an electric utility located in a power region that is not certified under § 39.152 shall continue to file annual reports under Sections 39.257, 39.258, and 39.259 as if the freeze period remained in effect, until the time the power region qualifies as certified under § 39.152. In addition, the commission staff and the office shall continue to review the annual reports as provided by § 39.261.

(c) After January 10, 2004, at a schedule and under procedures to be determined by the commission, each transmission and distribution utility, its affiliated retail electric provider, and its affiliated power generation company shall jointly file to finalize stranded costs under Subsections (h) and (i) and reconcile those costs with the estimated stranded costs used to develop the competition transition charge in the proceeding held under § 39.201. Any resulting difference shall be applied to the nonbypassable delivery rates of the transmission and distribution utility, except that at the utility’s option, any or all of the amounts recovered under this section may be securitized under Subchapter G.
(d) The affiliated power generation company shall reconcile, and either credit or bill to the transmission and distribution utility, the net sum of:
(1) the former electric utility’s final fuel balance determined under § 39.202(c); and
(2) any difference between the price of power obtained through the capacity auctions under Sections 39.153 and 39.156 and the power cost projections that were employed for the same time period in the ECOM model to estimate stranded costs in the proceeding under § 39.201.
(e) To the extent that the price to beat exceeded the market price of electricity, the affiliated retail electric provider shall reconcile and credit to the affiliated transmission and distribution utility any positive difference between the price to beat established under § 39.202, reduced by the nonbypassable delivery charge established under § 39.201, and the prevailing market price of electricity during the same time period. A reconciliation for the applicable customer class is not required under this subsection for an affiliated retail electric provider that satisfies the requirements of § 39.202(e)(1) or (2) before the expiration of two years from the introduction of customer choice. If a reconciliation is required, in no event shall the amount credited exceed an amount equal to the number of residential or small commercial customers served by the affiliated transmission and distribution utility that are buying electricity from the affiliated retail electric provider at the price to beat on the second anniversary of the beginning of competition, minus the number of new customers obtained outside the service area, multiplied by $150.
(f) To the extent that any amount of regulatory assets included in a transition charge or competition transition charge 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 whether such amounts were appropriately calculated and constituted reasonable and necessary costs pursuant to Subchapter B, Chapter 36. If the commission finds that the amount of regulatory assets specified in § 39.302(5) is subject to modification, a credit or other rate adjustment shall be made to the transmission and distribution utility’s nonbypassable delivery rates; provided, however, that no adjustment may be made to a transition charge established under Subchapter G.
(g) Based on the credits or bills received from its affiliates under Subsections (d), (e), and (f), the transmission and distribution utility shall make necessary adjustments to the nonbypassable delivery rates it charges to retail electric providers. If the commission determines that the nonbypassable delivery rates are not sufficient, the commission may extend the original collection period for the charge or, if necessary, increase the charge. Alternatively, if the commission determines that the nonbypassable delivery rates are larger than are needed to recover the transmission and distribution utility’s costs, the commission shall correspondingly reduce:
(1) the competition transition charge, to the extent it has not been securitized;
(2) the depreciation expense that has been redirected under § 39.256;
(3) the transmission and distribution utility’s rates; or
(4) a combination of the elements in Subdivisions (1)-(3).
(h) Except as provided in Subsection (i), for the purpose of finalizing the stranded cost estimate used to establish the competition transition charge under § 39.201, the affiliated power generation company shall quantify its stranded costs using one or more of the following methods:
(1) Sale of Assets. If, at any time after December 31, 1999, an electric utility or its affiliated power generation company has sold some or all of its generation assets, which sale shall include all generating assets associated with each generating plant that is sold, in a bona fide third-party transaction under a competitive offering, the total net value realized from the sale establishes the market value of the generation assets sold. If not all assets are sold, the market value of the remaining generation assets shall be established by one or more of the other methods in this section.
(2) Stock Valuation Method. If, at any time after December 31, 1999, an electric utility or its affiliated power generation company has transferred some or all of its generation assets, including, at the election of the electric utility or power generation company, any fuel and fuel transportation contracts related to those assets, to one or more separate affiliated or nonaffiliated corporations, not less than 51 percent 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 required under Subsection (c) establishes the market value of the common stock equity in each transferee corporation. The book value of each transferee corporation’s debt and preferred stock securities shall be added to the market value of its assets. The market value of each transferee corporation’s assets shall be reduced by the corresponding net book value of the assets acquired by each transferee corporation from any entity other than the affiliated electric utility or power generation company. The resulting market value of the assets establishes the market value of the generation assets transferred by the electric utility or power generation company to each separate corporation. If not all assets are disposed of in this manner, the market value of the remaining assets shall be established by one or more of the other methods in this section.
(3) Partial Stock Valuation Method. If, at any time after December 31, 1999, an electric utility or its affiliated power generation company has transferred some or all of its generation assets, including, at the election of the electric utility or power generation company, any fuel and fuel transportation contracts related to those assets, to one or more separate affiliated or nonaffiliated corporations, at least 19 percent, but less than 51 percent, 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 required under Subsection (c) shall be presumed to establish the market value of the common stock equity in each transferee corporation. 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 percentage of common stock sold is fairly representative of the total common stock equity or whether a control premium exists for the retained interest. The valuation panel must consist of financial experts, chosen from proposals submitted in response to commission requests, from the top 10 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 publications “Securities Data” or “Institutional Investor.” 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 increase the market value by a control premium greater than 10 percent. The costs and expenses of the panel, as approved by the commission, shall be paid by each transferee corporation. The determination of the commission based on the finding of the panel conclusively establishes the value of the common stock of each transferee corporation. The book value of each transferee corporation’s debt and preferred stock securities shall be added to the market value of its assets. The market value of each transferee corporation’s assets shall be reduced by the corresponding net book value of the assets acquired by each transferee corporation from any entity other than the affiliated electric utility or power generation company. The resulting market value of the assets establishes the market value of the generation assets transferred by the electric utility or power generation company to each separate corporation.
(4) Exchange of Assets. If, at any time after December 31, 1999, an electric utility or its affiliated power generation company has transferred 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 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. 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 subdivision. 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 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.
(i) Unless an electric utility or its affiliated power generation company combines all of its remaining generation assets into one or more transferee corporations as described in Subsections (h)(2) and (3), the electric utility shall quantify its stranded costs for nuclear assets using the ECOM method. 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.” At the time of the proceeding under this section, the ECOM model shall be rerun 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. Natural gas price projections used in the model must be market-based natural gas forward prices, where available. 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. Capital additions shall be benchmarked using the limitation in § 39.259(b).
(j) The commission shall issue a final order not later than the 150th day after the date of the filing under this section by the transmission and distribution utility, its affiliated retail electric provider, and its affiliated power generation company, and the resulting order shall be subject to judicial review under Chapter 2001, Government Code.
(k) Notwithstanding § 39.252, to the extent that a customer’s actual load has been lawfully served by a fully operational qualifying facility before September 1, 2001, or by an on-site power production facility with a rated capacity of 10 megawatts or less, any charge for recovery of stranded costs under this section or Subchapter G assessed on that customer after the facility becomes fully operational shall be included only in those tariffs or charges associated with the services actually provided by the transmission and distribution utility, if any, to the customer after the facility became fully operational and may not include any costs associated with the service provided to the customer by the electric utility or its affiliated transmission and distribution utility under their tariffs before the operation of that qualifying facility. To qualify under this subsection, a qualifying facility must have made substantially complete filings on or before December 31, 1999, for all necessary site-specific environmental permits under the rules of the Texas Natural Resource Conservation Commission in effect at the time of filing.
(l) To protect retail customers in this state, and ensure the appropriateness of the nonbypassable rates of electric utilities and transmission and distribution utilities, notwithstanding any other provision of this title, an electric utility or transmission and distribution utility must report to and obtain approval of the commission before closing any transaction in which:
(1) the electric utility or transmission and distribution utility will be merged or consolidated with another electric utility or transmission and distribution utility;
(2) at least 50 percent of the stock of the electric utility or transmission and distribution utility will be transferred or sold; or
(3) a controlling interest or operational control of the electric utility or transmission and distribution utility will be transferred.
(m) The commission shall approve a transaction under Subsection (l) if the commission finds that the transaction is in the public interest. In making its determination, the commission shall consider whether the transaction will adversely affect the reliability of service, availability of service, or cost of service of the electric utility or transmission and distribution utility. The commission shall make the determination concerning a transaction under this subsection not later than the 180th day after the date the commission receives the relevant report. The commission may extend the deadline provided by this subsection for not more than 60 days if the commission determines the extension is needed to evaluate additional information, to consider actions taken by other jurisdictions concerning the transaction, to provide for administrative efficiency, or for other good cause. If the commission has not made a determination before the expiration of the deadline provided by or extended under this subsection, the transaction is considered approved.
(n) Subsections (l) and (m) do not apply to a transaction described by Subsection (l) for which a definitive agreement was executed before April 1, 2007, if an electric utility or transmission and distribution utility or a person seeking to acquire or merge with an electric utility or transmission and distribution utility made a filing for review of the transaction under § 14.101 before May 1, 2007, and the resulting proceeding was not withdrawn.
(o) If an electric utility or transmission and distribution utility or a person seeking to acquire or merge with an electric utility or transmission and distribution utility files with the commission a stipulation, representation, or commitment in advance of or as part of a filing under Subsection (l) or under § 14.101, the commission may enforce the stipulation, representation, or commitment to the extent that the stipulation, representation, or commitment is consistent with the standards provided by this section and § 14.101. The commission may reasonably interpret and enforce conditions adopted under this section.