Part 2. PUBLIC UTILITY COMMISSION OF TEXAS

Chapter 25. SUBSTANTIVE RULES APPLICABLE TO ELECTRIC SERVICE PROVIDERS

Subchapter J. COSTS, RATES AND TARIFFS

2. RECOVERY OF STRANDED COSTS

16 TAC §25.263

The Public Utility Commission of Texas (commission) adopts an amendment to §25.263, relating to True-up Proceeding, with changes to the proposed text as published in the April 4, 2003 Texas Register (28 TexReg 2848). The amendment to §25.263 implements the provisions of Public Utility Regulatory Act (PURA) §39.262, which sets forth the requirements for the final true-up of stranded costs. The amendment modifies subsection (d)(1) to establish the true-up filing schedule required by PURA §39.262(c). This amendment is adopted under Project Number 27401.

The commission received written comments and reply comments on the proposed amendment from AEP Texas North Company and AEP Texas Central Company (collectively, the AEP Companies); Centerpoint Energy Houston Electric, LLC and Texas Genco, LP (collectively, Centerpoint); Office of Public Utility Counsel (OPC); Texas Industrial Energy Consumers (TIEC); and TXU SESCO Energy Services Company (TXU SESCO). Additionally, Reliant Resources, Inc. (Reliant) filed initial comments only, while the City of Houston filed reply comments only.

Summary of parties' original comments

TXU SESCO comments

TXU SESCO commented that the only aspect of the true-up proceeding to which it is subject is the retail clawback provision of PURA §39.262(e). However, TXU SESCO pointed out that the first requirement of §39.262(e)--that the price to beat exceeds the market price of electricity--is not likely to be met in its service area. TXU SESCO therefore stated its belief that no retail clawback will be required in its service territory. TXU SESCO indicated that it plans to make a filing with the commission after January 10, 2004 to demonstrate that its price to beat did not exceed the market price of electricity. Because such a filing would not constitute a full-fledged true-up filing in the manner envisioned by the commission's true-up rule, TXU SESCO does not believe that it is necessary to include it in the schedule for true-up filings.

The "retail clawback" provision contained in PURA §39.262(e) requires that, to the extent that the price to beat exceeds the market price of electricity, the affiliated retail electric provider shall credit such differences to the affiliated transmission and distribution utility. Even if TXU SESCO does not believe that its price to beat exceeds the market price in its service territory, the actual determination of this fact will be made by the independent third party described in §25.263(c)(2). Therefore, the commission concludes that it is appropriate to include TXU SESCO in the true-up filing schedule for the limited purpose of fulfilling the provisions of PURA §39.262(e), and establishes January 12, 2004 as TXU SESCO's filing date.

AEP comments

The AEP Companies supported the schedule contained in the proposed rule. The AEP Companies acknowledged that the true-up proceeding for AEP Texas North Company (and Mutual Energy WTU LP) should have as its sole issues the "retail clawback" calculation required by PURA §39.262(e) and the final fuel reconciliation. Because of the comparatively limited scope of the true-up proceeding for these companies, it will likely be less complex than the other cases.

With regard to AEP Texas Central, the AEP Companies commented that the proposed date of September 3, 2004 appears to be reasonable, based on current facts. AEP Texas Central has indicated its intent to sell its generation assets and expects the sale process to be effectively complete by September 2004.

The AEP Companies also expressed support for including in the rule a good-cause provision allowing a company to request an alternative true-up filing date if circumstances so warrant.

The commission generally concurs with the AEP Companies' comments and retains the originally proposed filing date for AEP Texas North Company. For AEP Texas Central Company, in recognition of the indefinite nature of the timing aspect of the sale-of-assets market-valuation method, the commission slightly alters the wording of the rule language to provide enhanced flexibility for the filing date. Specifically, the amendment changes the scheduling language for AEP Texas Central Company to "the later of September 3, 2004, or 60 days following completion of the sale of its generation assets." This slight modification to the language better accommodates the timing uncertainties related to when the sale of AEP Texas Central Company's generation assets will be completed.

The good-cause exception supported by the AEP Companies was included in the proposed rule, and the commission retains this provision on adoption.

Reliant comments

Reliant supported the proposed schedule. Reliant stated that the proposed filing date for Centerpoint is consistent with the time period that will be used for valuing Reliant's option to purchase all the shares of Texas Genco common stock owned by Centerpoint. Reliant did not offer specific comments on the filing schedules of other companies' true-up proceedings other than to agree that the proposed spacing of the filings would allow the commission the opportunity to effectively manage its resources when processing the filings.

Centerpoint comments

Centerpoint provided multiple reasons why it supports the proposed schedule that places it at the beginning of the filing sequence. The major reasons cited by Centerpoint include: 1) a January 12, 2004 filing date is necessary to effectuate Centerpoint's business separation plan as approved by the commission; 2) it has long been expected that Centerpoint would make its true-up filing on January 12, 2004, and there is no reason why Centerpoint should not be allowed to file on that date; 3) the commission has recently taken action in Centerpoint's final fuel reconciliation case anticipating a January 12, 2004 true-up filing by Centerpoint; and 4) requiring Centerpoint to file for its true-up proceeding after January 12, 2004 would be extremely costly to Centerpoint.

Centerpoint stated that, with regard to the first reason above, its business separation plan envisioned that stranded costs will be quantified using the partial stock valuation method allowed under PURA §39.262(h)(3), and that a key element of that plan is that Reliant Resources has an option, which can be exercised between January 10 and 24, 2004, to purchase the remaining stock of Texas Genco held by Centerpoint Energy. The option price is to be calculated in accordance with the partial stock valuation method prescribed in PURA §39.262(h)(3), including the control premium, if any. Centerpoint commented that the option held by Reliant Resources was an integral part of the business separation plan and that the plan met the requirements of PURA §39.051, which mandated the separation of integrated electric utilities into distinct business units. Centerpoint further commented that the above-described elements of the business separation plan were designed to coordinate the sales price of Texas Genco with the market value used in the stranded-cost true-up. This coordination is appropriate because it allows Centerpoint Energy to recover the book value of the former utility's generating assets--no more and no less. If Centerpoint is not permitted to file for the true-up of stranded costs by mid-January 2004, the market value determined under PURA §39.262(h)(3) could be different from the value used to price the option, and Centerpoint would recover more or less than the book value of the generating assets. Centerpoint stated in its comments that this potential deviation in values would expose it to risks and uncertainty that the approved business separation plan was carefully crafted to avoid.

With regard to the second reason cited by Centerpoint--that it has long been expected that Centerpoint would make its true-up filing on January 12, 2004, and there is no reason why Centerpoint should not be allowed to file on that date--Centerpoint commented that its need to file at the earliest possible date was apparent when Reliant Energy, Incorporated filed its Second Amended Business Separation Plan in August 2000. Centerpoint also pointed out that it specifically asked for a January 12, 2004 filing date in its comments filed July 16, 2001 in the true-up rulemaking proceeding. Given these facts, Centerpoint stated that it has been widely expected for almost two years that it would be allowed to file its case on January 12, 2004, and that assigning Centerpoint to a later date would now be perceived, particularly by the financial markets, as adverse to both Centerpoint Energy, Inc. and Texas Genco, LP. Centerpoint additionally stated that any suggestion that delaying its filing might increase the value of Texas Genco, LP would be pure speculation, and that it is not feasible to "time the market." Centerpoint also commented that there is no reason to delay its filing to allow the market to "mature," as the Legislature determined that scheduling the true-up proceedings two years after the opening of retail choice gave the market sufficient time to mature for purposes of assessing the market value of generating assets. Finally, Centerpoint argued that there is no practical reason why it should not be allowed to make its true-up filing on January 12, 2004, because it wants to file on that date. Even if other companies also desire an early filing date, that is still no reason to change Centerpoint's proposed filing date. Centerpoint stated that the true-up filings are important to all companies and, if necessary, the commission should be willing to accept multiple filings on the same date and process them accordingly.

To support its third reason--that the commission has recently taken action in Centerpoint's final fuel reconciliation case that anticipates a January 12, 2004 true-up filing--Centerpoint stated that all elements necessary for its true-up filing will be in place by January 12, 2004. Accordingly, there is no reason why Centerpoint should not be allowed to file on that date.

Finally, with regard to its fourth reason--that requiring Centerpoint to file for its true-up proceeding after January 12, 2004 would be extremely costly to the company--Centerpoint stated that, because carrying costs on true-up balances do not begin to accrue until the date of the commission's final order, it would cost Centerpoint approximately $35 - $45 million (based on current estimates of Centerpoint's stranded costs) in pre-tax earnings for every month it does not have a final order.

OPC comments

The central focus of OPC's initial comments was that Centerpoint's true-up filing should be delayed until later in 2004. OPC stated that allowing Centerpoint to file its true-up case first in the filing sequence will likely increase stranded costs because Reliant's option to purchase 81% of Texas Genco stock creates uncertainty for the 19% of traded stock used for the stranded-cost determination. OPC commented that the existence of the option has major consequences for the long-term prospects of Texas Genco because it will determine whether Texas Genco is associated with an affiliated retail electric provider and will also have implications for Texas Genco's future dividend policy. If the option is not exercised, it is possible that Texas Genco will be spun off into a separate independent entity or sold to another corporation. OPC pointed out that uncertainty about the long-term future of the enterprise translates into risk and thus exerts downward pressure on the stock price. However, OPC argued, the uncertainty regarding the option and any distorting effects on Texas Genco's stock price resulting therefrom could be eliminated if the stock price used for valuation of Texas Genco's assets reflects a period after the option has expired. OPC therefore argues that the commission should set a filing date for Centerpoint that is 30 to 60 days after the expiration of Reliant's option to purchase the shares of Texas Genco held by Centerpoint.

OPC also commented that, despite the fact that Centerpoint will likely be the most litigated of all the true-up filing and will therefore require the greatest amount of resources, those required resources will be the same regardless of the timing of Centerpoint's filing. Additionally, OPC noted that the existence of Reliant's option may raise significant issues as to whether stranded costs were adequately mitigated by Centerpoint. OPC stated that if a schedule is adopted that allows stock trading for the post-option period, it is possible that a contentious issue could be obviated or reduced, thus requiring less litigation time.

OPC additionally provided an alternative to Centerpoint filing first by suggesting that Texas-New Mexico Power Company (TNMP) be moved to the first position. OPC noted that TNMP has already sold its assets and, given the apparent lesser amount of stranded costs, its proceeding could perhaps be resolved more quickly than the other cases.

TIEC comments

Like OPC's comments, TIEC's comments were principally directed to the issue of Centerpoint's filing date. TIEC argued that, for a number of reasons (discussed below), Centerpoint should file its true-up case no earlier than May 28, 2004. With regard to the proposed filing schedule in general, TIEC essentially argued that the filing dates of Centerpoint and WTU should be switched--that is, WTU would file on January 12, 2004, and Centerpoint would file on May 28, 2004.

The first reason TIEC provided for its recommended schedule is that the Centerpoint filing will be extremely complicated and that consideration of the issues in the WTU and TNMP cases will benefit the consideration of the Centerpoint case. TIEC suggested that lessons learned in the administration of the earlier cases may enhance settlement possibilities.

The second reason TIEC provided is that the South Texas Project (STP) Unit 1 is currently out of service, and the market valuation of Texas Genco will be negatively impacted because of concerns about the plant's status. TIEC commented that if the coolant leak issue is not fully and favorably resolved prior to Centerpoint's filing, issues regarding the prudence of STP's operation and maintenance could become a part of the true-up case. Additionally, TIEC commented that the circumstances surrounding the leak problem have the potential to depress the stock price of Texas Genco, so it is appropriate to delay Centerpoint's true-up filing to increase the likelihood that STP Unit 1 will be returned to full service by the time of the filing and any negative impact on the stock price will have been reduced or eliminated.

The third reason cited by TIEC for moving Centerpoint's filing to a later date is that the capital markets for energy-related stocks are currently depressed relative to historical levels. A delay of Centerpoint's filing for several more months would allow the markets more time to return to more rational and historically normal levels, thus minimizing stranded costs. TIEC also pointed out that valuing assets during a time of historically low stock prices may raise a question regarding the commercial reasonableness of the valuation method, and TIEC provided recent examples of how some energy companies that have attempted to sell assets and/or stock in the current market have decided to withdraw their proposal once they determined that the current market is not attractive. TIEC commented that its recommendation that the commission allow more time for capital markets to improve is not a simple attempt to time the market, but rather, it is a request to follow the commercially reasonable practice of maximizing asset value by postponing a valuation until the markets have returned to more historically reasonable levels.

The fourth reason cited by TIEC for moving Centerpoint's filing to a later date is that Reliant's option to purchase Centerpoint's shares of Texas Genco has never been approved by the commission, and this creates uncertainty and likely increases stranded costs. TIEC commented that although the commission approved Reliant Energy, Incorporated's business separation plan, it never approved the stock option (emphasis in TIEC's comments). TIEC further stated that the commission found that approving the business separation plan does not preclude a review of whether Reliant Energy, Incorporated pursued commercially reasonable means to reduce stranded costs, raising the implication that the granting of the option may not have been commercially reasonable. Similar to OPC's comments, TIEC stated that the option creates uncertainty, and this uncertainty has a negative impact on the value of Texas Genco's stock because of stockholder concern that Texas Genco will be majority owned by Reliant, whose liquidity problems are common knowledge. Because of the option, TIEC argues that the current market value of Texas Genco stock is not based on its stand-alone value, but rather is heavily tied to the value of Reliant's stock.

The fifth reason provided by TIEC to delay Centerpoint's filing date is that such a delay will not create uncertainty regarding the full recovery of stranded costs. TIEC stated that stranded costs are not known and measurable until a filing is made under substantive rule §25.263. This rule--and the statute--provides that the market value of the common stock will be determined based on a 30-day period chosen by the commission out of the last 120 consecutive trading days before the filing. TIEC argues that it is irrelevant that Centerpoint granted Reliant an option the value of which is based on the 30-day average stock price out of the last 120 consecutive trading days prior to January 9, 2004. TIEC reiterated its comment that the commission never explicitly approved the option, and the fact that the valuation derived from the option may be different from the valuation conducted pursuant to PURA §39.262(h)(3) is a risk that Centerpoint alone has chosen to bear. Ratepayers should not have to bear this risk.

Summary of parties' reply comments

OPC replies

OPC replied to Centerpoint's comments regarding the use of Reliant's option as part of Centerpoint's approved business separation plan by stating that if Centerpoint files its true-up case prior to the conclusion of the option exercise period (January 10 - January 24, 2004), this will increase uncertainty surrounding the 19% of traded stock used for valuation purposes. OPC further replied that a more accurate valuation of Texas Genco's assets may be possible if the stock prices include the period after the option period has expired, thus reducing the possibility that uncertainty regarding the option has distorted the stock price.

Regarding Centerpoint's comments that "it has long been expected that Centerpoint would make its filing on January 12, 2004," OPC replied that such an expectation is based upon false assumptions, and that Centerpoint alone expected to file on that date. With respect to Centerpoint's comments that the commission recently moved the date of the interim hearing for Centerpoint's final fuel reconciliation to allow sufficient time to conclude that proceeding before January 12, 2004, OPC replied that moving up that hearing simply means that Centerpoint's final fuel reconciliation will be completed prior to the filing of the true-up case, regardless of when in 2004 such filing occurs.

The final point in OPC's replies was that it is incorrect for Centerpoint to claim that moving its filing date beyond January 12, 2004 would be extremely costly to Centerpoint. OPC stated that the Austin Court of Appeals recently affirmed that part of the true-up rule which states that true-up balances do not begin to accrue interest until the date of the commission's final order in the true-up case. OPC stated that because Centerpoint does not legally have any carrying costs until the date on which the commission decides that it has stranded costs, Centerpoint is precluded from arguing that delaying its true-up filing will increase its carrying costs.

TIEC replies

TIEC replied to Centerpoint's comments by stating that while PURA §39.051(b) mandated the separation of integrated electric utilities into three separate units, it did not mandate that one of the separated businesses provide an option to purchase the stock of one of the other businesses. Therefore, TIEC asserted, the option is irrelevant to both the approved business separation plan and the filing date of Centerpoint's true-up proceeding. TIEC further replied that, based upon the commission's statements in its final order for Reliant's business separation plan, Reliant had satisfied the statutory standards for business separation regardless of the presence of the stock option. Furthermore, TIEC stated that it is indisputable that the commission never approved the stock option.

TIEC also reiterated its comments that the presence of the stock option creates a cloud on the Texas Genco stock price that could result in higher levels of stranded costs. TIEC strongly expressed its belief that the truest market valuation of Texas Genco will occur only if the stock option lapses. TIEC stated that, through the use of the stock option, Centerpoint is attempting to create a new stranded cost valuation method not contemplated in PURA. TIEC argued that, given that Centerpoint has chosen the partial stock valuation method to determine the value of its generation assets, any payments that Centerpoint receives from an affiliate pursuant to a stock option are irrelevant to the stranded cost equation. Moreover, because the stock option had not yet been reduced to writing at the time the commission approved the final business separation plan, there has been very little, if any, regulatory review of the option. Therefore, TIEC argued, it is inappropriate to order that Centerpoint file its stranded cost true-up case in January so as to give effect to an option that has never been approved by the commission.

TIEC also replied that concern by Centerpoint about differences in timing between the true-up filing date and the option exercise could be resolved by an agreement between Centerpoint and Reliant to amend the option to provide for a different strike date. TIEC averred that Centerpoint granted Reliant the option at its own risk, and ratepayers should not be asked to bear the risk of a business decision between affiliated companies. Accordingly, TIEC argued, the stock option has no bearing on the timing of Centerpoint's true-up filing.

TIEC also stated in its replies that if the option lapses, regulatory complexity will be reduced. TIEC stated that, in the true-up case, the commission has full authority to determine whether the granting of the option was commercially reasonable and a normal business practice. TIEC stated that if Centerpoint's schedule is moved to May, as TIEC suggested, there is a greater chance that the stock option will not be exercised, and factual and legal arguments regarding the meanings of "commercially reasonable" and "normal business practices" as they apply to the stock option will not need to be a part of Centerpoint's case.

Regarding Centerpoint's comments that "it has long been expected" that Centerpoint would make its true-up filing on January 12, 2004, TIEC replied that TIEC has not expected such an outcome, nor apparently has OPC or the City of Houston. TIEC pointed out that, notwithstanding representations by Centerpoint, Reliant, and Texas Genco, there has never been certainty that Centerpoint's true-up filing would occur on January 12, 2004. TIEC further replied that the blame for any adverse impact--such as a negative perception by the financial markets--that would result from the commission setting a later filing date for Centerpoint would fall entirely on Centerpoint for making overly optimistic statements. Accordingly, the potential reaction of Wall Street, which does not consider the public interest, should not dictate to the commission when it should determine the market value of Texas Genco stock.

City of Houston replies

City of Houston filed reply comments only, and basically supported the comments filed by TIEC and OPC. City of Houston stated that Centerpoint's true-up proceeding will likely be the most complicated and contentious true-up case at least partially because the stock valuation method will be used as the basis for quantifying stranded costs. City of Houston added that the complexity of Centerpoint's case will be increased because several issues--involving hundreds of millions of dollars--relating to its final fuel reconciliation have been postponed for consideration until the true-up proceeding. City of Houston argued that, because TNMP's case is expected to involve a considerably lesser amount of stranded costs, it is more reasonable to schedule TNMP first in the filing sequence. Additionally, because of the expected less complex nature of TNMP's proceeding, any issues arising in that case that may be common in all true-up proceedings could be afforded more attention.

City of Houston stated that the more important reason to delay Centerpoint's filing is because of increased risk associated with uncertainty regarding whether Reliant will exercise the option to purchase Centerpoint's shares of Texas Genco. Like OPC and TIEC, City of Houston argued that delaying the filing date for Centerpoint until later in 2004 would allow additional trading days after the option is exercised or not exercised, and would allow additional time for the financial markets to return to more rational and historically normal levels. City of Houston also argued that delaying the filing date for Centerpoint would allow more time for the resolution of issues related to the service concerns of STP Unit 1. For the foregoing reasons, City of Houston recommended that the commission schedule TNMP's true-up proceeding first, followed by Centerpoint later in 2004.

AEP replies

The AEP Companies replied to TIEC's and OPC's comments by stating that while the AEP Companies have no position on the matter of moving the Centerpoint filing date, the commission should reject TIEC's effort to argue substantive issues regarding the scope of the true-up cases in this procedural rulemaking. The AEP Companies stated that TIEC's arguments are premature and unnecessary at this stage. Furthermore, the AEP Companies argued, TIEC's comments contain a critical legal error. To the extent that TIEC seeks to have the commission question the market valuation that results from one of the valuation methods provided for in PURA §39.262(h) or (i), it is seeking to indirectly do what PURA §39.252(d) says the commission cannot do directly--substitute its judgment for a market valuation of generation assets. The AEP Companies also replied to TIEC's comments regarding the shifting of AEP Texas North Company to January 2004 by reiterating their support for the filing schedule as originally proposed, but acknowledging that AEP Texas North could be ready for filing at the earlier date if the commission finds that to be in the public interest.

Centerpoint replies

Centerpoint replied to TIEC's and OPC's comments by stating two basic points: 1) no utility, affiliated power generation company, affiliated retail electric provider, combination of those entities, municipal regulator, or nonaffiliated retail electric provider objected to the proposed schedule, and 2) only TIEC and OPC argued for a change in the schedule, and the basis for their arguments is the unsupported speculation that a delay in Centerpoint's filing might result in higher prices for the shares of Texas Genco.

Centerpoint replied that the bottom line is that TIEC and OPC seek a three- to five-month delay in Centerpoint's filing in an ill-advised effort to "time" the market, and that the benefits claimed by TIEC and OPC are entirely speculative because the Texas Genco stock price is as likely to fall as it is to rise during that time. However, Centerpoint argues, its economic damage is not speculative--the delay sought by TIEC and OPC will cost Centerpoint from $100 million to $200 million in lost carrying costs.

Centerpoint stated that TIEC and OPC have not presented any reason that justifies changing the proposed date for Centerpoint's filing in the true-up schedule, and the commission should not set dates based on speculation as to what might occur in markets affected by a variety of factors, including long term excess generating capacity, specific generating plant operations, fuel prices, and interest rates. Though most of these factors can and probably will change over time, what will not change in the near future is the factor that may have the largest impact on the value of generating assets in ERCOT--the fact that ERCOT will have generating capacity in excess of 15% until at least 2007. Any delay of a few months will not change the impact this excess capacity has on the value of Texas Genco stock.

Centerpoint included in its replies the argument that, in adopting a rule, a governmental agency must apply sound reasoning, and explain how and why it reached the conclusions it did. That is, the agency must summarize the evidence it considered, state a justification for its decision based on the evidence before it, and demonstrate that its justification is reasoned. The agency's explanation of the facts and policy concerns it relied upon when it adopted the rule must demonstrate that the agency considered all the factors relevant to the objective of the agency's delegated rulemaking authority and that it engaged in reasoned decision-making. Centerpoint argued that, in short, the commission cannot delay Centerpoint's filing based on TIEC's and OPC's speculation that delay might result in lowering stranded costs without hard evidence that such delay is more likely to lower than to increase costs and that the benefits of delay will outweigh the harm to Centerpoint the delay will cause.

Centerpoint further argued in its replies that no one can predict whether delaying Centerpoint's filing will reduce stranded costs; it is equally likely that delay will increase stranded costs. Centerpoint stated that what TIEC is actually seeking is to have the commission speculate on stock prices while imposing on Centerpoint additional carrying costs of $35 - $40 million per month for at least four and a half months. This speculation could result in stranded costs being higher or lower and is as likely to harm customers as it is to help them.

Centerpoint pointed out in its replies that when the Legislature passed the Texas Electric Choice Act (Senate Bill 7, Act of May 21, 1999, 76th Leg., R.S., ch. 405, 1999 Tex. Gen. Laws 2543) in 1999, it was determined that there would be a two-year period after the opening of retail choice before proceedings were conducted by the commission to calculate and true-up stranded costs. This established a neutral "test period" for determining the value of generation because no one could accurately project in 1999 what the generation market in ERCOT would be by January, 2004. Centerpoint argued that when the Legislature gave the commission the authority to set the schedule for the true-up filings, it intended to give the commission the ability to manage its resources, not to have the commission manipulate the legislatively determined test period or try to "time" the stock market.

In response to TIEC's comments that recent attempts to sell generating assets were unsuccessful, Centerpoint replied that TIEC ignores the fact that a number of sales and stock issuances (the data for which Centerpoint provided) of generating assets have occurred in recent months. In response to TIEC's argument that its recommendation for delay is "not a simple attempt to time the market," but rather a "request to follow the commercially reasonable practice of maximizing asset value," Centerpoint replied that a delay for the purpose of "maximizing asset value" is precisely an "attempt to time the market," but that TIEC ignores the illogic of its own statement.

Centerpoint also replied to TIEC's statement that "the capital markets for energy-related stocks are currently depressed relative to historical levels." Centerpoint stated that TIEC never specifies the "historical levels" and does not explain how or when the markets will return to those levels. Centerpoint adds that the more important question, however, is the very real question of whether it is logical to expect that investors' long term perceptions of the ERCOT market for generation, which is expected to have a surplus of capacity for at least four years , will materially change during a delay of four and a half months (emphasis in Centerpoint's reply comments). Centerpoint argued that it is purely speculative to say that the market for Texas Genco stock will change dramatically in that short of a time period, and the commission should not engage in such speculation.

In response to OPC's comments, Centerpoint replied that there is no evidence that the Texas Genco option decreases market value or that a more accurate value for Texas Genco's generating assets will be achieved by delaying Centerpoint's true-up filing. Centerpoint disagreed with the thrust of OPC's comments that the option held by Reliant to purchase the shares of Texas Genco held by Centerpoint creates uncertainty and thereby creates risks and exerts downward pressure on the shares of Texas Genco. Centerpoint stated that TIEC raises the same contention but goes a step further by asserting that the stock price of Texas Genco is artificially low because of the capital markets' negative perception of Reliant. Centerpoint replied that OPC's and TIEC's arguments, distilled to their essence, are simply that a control premium exists that should be applied to the Texas Genco stock because there is the possibility that Reliant could own the majority of Texas Genco stock rather than Centerpoint Energy, Incorporated or another party. Centerpoint stated that is an issue for the true-up proceeding and will be decided by the commission after a determination by a panel of experts in accordance with the specific procedures in PURA §39.262(h)(3). Accordingly, Centerpoint believes that none of OPC's or TIEC's contentions provide a basis for delaying Centerpoint's filing beyond January 12, 2004.

Regarding Reliant's option, Centerpoint replied that TIEC mischaracterizes the commission's actions regarding the option. Centerpoint stated that the commission approved Reliant's option when it approved Reliant Energy, Incorporated's business separation plan, and pointed out that Finding of Fact No. 52 in that Order on Rehearing stated:

"The commission finds that Reliant's proposed separation meets the requirements of PURA §39.051 whether the stock option is exercised or allowed to lapse. Consequently, there is no need for the commission to approve the stock option as a separate matter . The proposed stock option is an integral part of the Second Amended Plan , which the commission finds in this Order meets the separation requirement in PURA §39.051 (emphasis in Centerpoint's replies)."

Centerpoint further argued that, contrary to TIEC's assertion, the commission's Order on Rehearing does not imply that the granting of the option may have been commercially unreasonable. Centerpoint stated that in the Open Meeting in which the commission approved the business separation plan, Chairman Pat Wood stated that "on its own, the buy-back--or the stock purchase option does not trigger any higher burdens on the Company to rebut than any other normal business practice issue," and Commissioner Walsh stated, "I think we're saying the option is okay. We're not going to second guess that." Centerpoint argued that second-guessing the Reliant option is exactly what OPC and TIEC want the commission to do when they argue for delaying Centerpoint's filing date for its true-up proceeding.

Centerpoint also argued in its replies that OPC's and TIEC's arguments claim that the value of the Texas Genco stock will increase after the conclusion of the option period, but neither OPC nor TIEC offers any support for that claim. Centerpoint stated that TIEC attempts to tie the value of Texas Genco stock to Reliant stock and casts aspersions on the value of Reliant stock in order to conclude that "because of Reliant's financial problems, the presence of the stock option has a negative effect on the current price of Texas Genco." Centerpoint states that while it disagrees with TIEC's view of Reliant and the effect of the option on the value of Texas Genco stock, ultimately TIEC is defeated by its own argument. Centerpoint argues that if the Reliant option reduces Texas Genco's stock price, as TIEC claims, the stock will decline even more when Reliant exercises its option and makes Reliant ownership of the majority of the stock a reality, rather than just a possibility. Consequently, Centerpoint argues, if TIEC really believed its own contentions, TIEC would argue against any delay in Centerpoint's true-up filing.

Centerpoint stated in its replies that Reliant is the logical strategic buyer for Texas Genco because Reliant serves a significant load in the Houston area and therefore needs a significant amount of power in the geographical region where most of Texas Genco's generation is located. Thus, there is no reason to believe that the existence of the Reliant option exerts downward pressure on the stock of Texas Genco. Centerpoint points out that those utilities that did not separate into two separate holding companies as Centerpoint and Reliant have done have the same situation that the option was designed to achieve--an alignment of generating assets with the loads that the assets were traditionally used to serve. Therefore, there is no basis for assuming that the option creates any less value for Texas Genco's generating assets than if the assets were placed in Reliant to begin with. In short, Centerpoint argues, the existence of the Texas Genco option provides no basis for delaying Centerpoint's filing. Centerpoint again pointed out that, as discussed in the preamble and in Centerpoint's initial comments on the proposed rule, with regard to stranded costs, allowing Centerpoint to file its true-up case on January 12, 2004 will allow it to recover the book value--no more, no less--of the former utility's generating assets.

In response to TIEC's comments, Centerpoint stated that consideration of the WTU and TNMP cases before Centerpoint's will not benefit the consideration of Centerpoint's filing nor facilitate settlement. Centerpoint expressed its belief that these proceedings will be fact-specific cases involving different utilities that have chosen different valuation methodologies, and it is unlikely that decisions on the issues in the WTU and TNMP cases will be of any benefit in the consideration of Centerpoint's filing. Centerpoint believes that, in fact, it is more probable that the opposite of what TIEC suggests is true: processing a larger, more complicated case first could facilitate expedient consideration of the cases with fewer issues. Centerpoint also replied to TIEC's argument that for "settlement to be a viable possibility, key precedential issues need to be resolved." Centerpoint replied that TIEC never explains what are the "key precedential issues" applicable to Centerpoint that can be resolved in the WTU and TNMP cases. Centerpoint also argued that TIEC's statement that "parties must have time to process the complicated filings and to run and rerun revenue studies and rates" is shorthand for TIEC's saying that it will not even be in a position to consider a settlement until Centerpoint makes its filing, regardless of when Centerpoint makes the filing. Centerpoint therefore argued that taking TIEC's statements at face value, the chances of settlement are not affected by allowing Centerpoint to file its case on January 12, 2004.

With regard to TIEC's comments that the current outage of STP Unit 1 has the potential to depress the price of Texas Genco common stock, Centerpoint replied by first pointing out that STP Unit 1 represents less than 3.0% of Texas Genco's generating capacity. Centerpoint also argued that a number of factors go into the pricing of Texas Genco stock and that TIEC's arguments unrealistically assume that investors in generating assets will focus only on short-term operational issues at one generating unit. Centerpoint argued that there is no reason to believe that investor perceptions of the risks associated with Texas Genco's ownership interest in STP will be higher or lower if Centerpoint's filing is delayed. Centerpoint reiterated its argument that TIEC has provided no evidence that factors affecting STP Unit 1 will cause the market price of Texas Genco's stock during any 30 consecutive trading days in the 120 trading days before May 28, 2004 (TIEC's suggested date for Centerpoint's filing) to be better than the 30 consecutive trading days chosen by the commission from the 120 trading days before January 12, 2004.

Commission response

Most of the parties' comments and replies in this rulemaking proceeding focused on the issue of Centerpoint's filing date. The filing schedule has specific valuation implications for Centerpoint, because Centerpoint's stranded costs will be determined primarily on the basis of the prices at which Texas Genco stock trades during the 120 trading days prior to filing. With regard to the majority of arguments that were offered by TIEC, OPC, and the City of Houston that Centerpoint's filing should be delayed, the commission is not persuaded that such arguments are well-founded. While the possibility exists that the amount of stranded costs could be reduced if the schedule were altered on the basis of these arguments, it is also possible that stranded costs could be increased. To a large degree, therefore, many of the arguments for delaying Centerpoint's filing are speculative in nature. For example, TIEC, OPC, and the City of Houston all argued that delaying Centerpoint's filing date would allow for a longer period of time to pass during which the stock of Texas Genco could be expected to become more favorably valued. A delay in the scheduling of Centerpoint's filing for the purpose of waiting for a more favorable stock value is ultimately the common denominator of the arguments relating to both the suggestion that stock valuation levels should be allowed an opportunity to return to "historically normal" levels and the impact of the leak at STP Unit 1. In response to these points, the commission agrees with Centerpoint that the essence of such arguments is an attempt to "time the market," with the ultimate outcome of such attempts being inherently unpredictable. As Centerpoint argued, delaying the filing is as likely to result in lower stock prices that would be used in valuing Centerpoint's generation assets as higher stock prices. Consequently, the commission refrains from relying upon such arguments as justification for changing the proposed true-up filing schedule.

Other arguments offered by TIEC, OPC, and the City of Houston relate to learning-curve advantages that might be achieved by processing TNMP's case first and the facilitation of a settlement that could possibly be realized by delaying the filing of Centerpoint's case. The commission, however, agrees with Centerpoint that few critical issues, if any, will be common between the TNMP and Centerpoint cases primarily because the two companies will be relying upon different market-valuation methodologies. TNMP has sold its generating assets and will therefore be relying upon the sale-of-assets method for the determination of stranded costs, while Centerpoint will be using the partial stock valuation method. Moreover, the TNMP case will not include the issues of the capacity auction true-up and the control-premium determination. Consequently, there are not likely to be any meaningful efficiencies gained on these major, potentially controversial issues simply by having TNMP file first. Similarly, the commission agrees with Centerpoint's comment that any settlement in its case is unlikely to happen until after Centerpoint makes its filing, regardless of when that filing occurs.

The foregoing notwithstanding, the commission finds that, based on the extensive initial and reply comments with regard to the existence of Reliant's option to purchase the 81% of Texas Genco stock held by Centerpoint, sufficiently credible arguments have been put forth to justify a change in the order in which the companies will make their true-up filings. Specifically, the principal rationale underlying the commission's decision to alter the filing schedule relates to the uncertainty created by the existence of the Reliant option and the impact of this uncertainty on the price of Texas Genco stock. The commission believes that the existence of an unexercised option results in a stock price on the true-up filing date that is a less accurate proxy for the value of Texas Genco's assets than if the option had expired or had been exercised sufficiently in advance of the filing date. The commission concludes, however, that the magnitude and direction of the effects of this uncertainty cannot be determined in advance. Reasonable arguments can be made about whether the effect of the option on the price of Texas Genco Stock is large or small and even whether it is positive or negative--that is, it is conceivable that the option has a propping-up effect on the stock price of Texas Genco, a depressing effect, or little meaningful effect at all. Presumably, investors in Texas Genco assign some value to the quality of management and financial condition of the company that owns 81% of its stock, and presumably they are aware that Reliant has an option to acquire that 81%. In assessing the value of the stock, they can be assumed to have factored in some measure of likelihood that Reliant will acquire 81% of the Texas Genco stock, but they cannot be certain that the option will be exercised. Inevitably, there is a degree of uncertainty about who will be the majority owner of Texas Genco, who will manage it, the effectiveness with which it will be managed, and the financial condition of the majority owner. Thus, the removal of some of this uncertainty by the expiration or exercise of the option may result in a change in the value of the stock.

Therefore, in view of the uncertain impact of the Reliant option, the commission concludes that it is prudent to schedule the timing of Centerpoint's true-up filing on a date that enables the 120-day trading period used in the partial stock valuation methodology to encompass time periods both before and after the exercise date of the option. Accordingly, the commission is adopting true-up filing dates for TNMP and Centerpoint that are the reverse of the dates that were originally proposed for these companies. The true-up filing date for TNMP is scheduled to be not earlier than January 12, 2004 and not later than ten days thereafter, and the filing date for Centerpoint is scheduled to be not earlier than March 31, 2004 and not later than ten days thereafter. Because the Reliant option exercise period is January 10 - 24, 2004, scheduling Centerpoint's filing approximately two and one-half months thereafter, namely, on March 31, 2004, allows the 120-day valuation period that will be used in the true-up proceeding to span the time period before and after the exercise period of the option. Thus, if the existence of the option does in fact have an impact (in whichever direction) on the price of Texas Genco stock, the commission will have the discretion of using whichever time period provides the higher valuation for purposes of determining stranded costs, so as to minimize the costs to electric customers.

With regard to Centerpoint's claims that the commission's order in Docket Number 21956, Application of Reliant Energy, Inc. for Approval of Business Separation Plan effectively approves the option, the commission concludes that the order acknowledges the option as part of Centerpoint/Reliant's Second Amended Business Plan, but does not say anything about giving specific consideration to the option at the time of true-up, and certainly nothing about the option influencing the scheduling of the true-up filings. While the finding of fact that Centerpoint relied upon in its reply comments addresses the option from the perspective of the approval of an unbundling plan, it does not address the option from the perspective of valuing stranded costs. In fact, the commission did not "approve" the stock-purchase option as an independent transaction in the business separation plan proceeding. When taken as a whole, the business separation plan order makes it clear that the commission only evaluated the stock option as it related to the business separation findings, and decided that the business separation was adequate. The business separation plan order further finds that approval of the separation plan does not preclude a reasonableness review of certain business practices in the 2004 true-up proceeding. This is highlighted by the fact that the stock purchase option was not yet finalized and reduced to writing at the time of the business separation plan order. Accordingly, the commission finds that the statements in the Docket Number 21956 order regarding the option are not directly relevant to this rulemaking and that the establishment of the true-up filing schedule is not controlled by any findings in the final order in that proceeding.

With regard to Centerpoint's argument that any delay in its filing will be extremely costly to the company, this issue is tied to Centerpoint's claim that they have counted on the January filing date for some time. Regardless of Centerpoint's expectations, the statute clearly says the true-up proceedings will be filed on a schedule established by the commission. The commission has never promised or guaranteed Centerpoint that it can file in January. Centerpoint has requested that date, but for reasons explained in this preamble, the commission has now chosen a different date. Centerpoint has presented no evidence that the stock purchase option agreement was conditioned either upon any regulatory condition to exercise or any conditions precedent based on the actions of, or approval by, this commission, particularly with respect to the filing date for the true-up proceeding. Additionally, given the timing of the execution of the stock purchase option agreement, Centerpoint could not have relied upon the commission's schedule as contained in the published version of this rule, which set the Centerpoint true-up filing date in January 2004, as this rule was published more than two years after the option was executed. Nor does the commission find any commitment in the business separation plan order to schedule Centerpoint's true-up proceeding in January 2004. The regulatory risk Centerpoint faces regarding the scheduling of its true-up filing is present for any company whose filing is later in the sequence. If the legislature had intended for companies to be compensated for this regulatory lag, it could have explicitly done so, but it did not.

Moreover, PURA §39.262(c) grants the commission broad authority to set a schedule for the true-up proceedings. The fact that the commission is charged with preparing a schedule clearly indicates that the legislature intended that different companies subject to true-up proceedings would make their filings at different times during 2004. Centerpoint's argument that its true-up should be filed in January because scheduling it later in the year will allegedly result in the imposition of carrying costs runs counter to the principles of setting a schedule. If, in fact, incurring carrying costs is a sufficient reason to schedule Centerpoint's true-up case no later than January, then the logical extension of that argument would be that any company scheduled after January might incur these costs and therefore they should likewise be scheduled in January--thus eliminating the need for any schedule.

The commission also notes that Centerpoint and Reliant in February 2003 agreed to an amendment to the option that provides an extension of time--up to 45 business days--in which Reliant can rescind its exercise of the option if it is unable by that date to secure financing for its purchase of the Texas Genco shares on terms reasonably acceptable to Reliant, despite the exercise by Reliant of commercially reasonable efforts to obtain such financing. Setting Centerpoint's true-up filing date on March 31, 2004 allows the 45-day period to pass, and eliminates or at least reduces any uncertainty related to a possible rescission by Reliant that may be reflected in Texas Genco's stock price.

Finally, with regard to the scheduling, the commission notes that TNMP is the first company to have completed the sale and apparent market valuation of its generation assets. TNMP has thus for some time been prepared for and ready to file its true-up application. Moreover, the true-up proceeding for TNMP can be reasonably expected to be less controversial than later filings by Centerpoint and AEP Texas Central Company because the amount of TNMP's apparent stranded costs is considerably smaller and because, as previously noted, the particulars of TNMP's case do not include other potentially controversial true-up issues such as the capacity auction true-up and the control-premium issue. As a result, the resolution of the TNMP true-up case is likely to be more readily and expeditiously achieved than Centerpoint's case, thus freeing up additional staff resources if needed for the more complex Centerpoint case.

This amendment is adopted under the Public Utility Regulatory Act, Texas Utilities Code Annotated §14.002 (Vernon 1998, Supplement 2003) (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 §39.262, which requires the commission to conduct a true-up proceeding for each investor-owned electric utility on a schedule and under procedures to be determined by the commission.

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, 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 according to the following schedule.

(A) Texas-New Mexico Power Company and First Choice Power, Inc.--not earlier than January 12, 2004, and not later than ten days thereafter;

(B) TXU SESCO Energy Services Company--not earlier than January 12, 2004, and not later than ten days thereafter;

(C) Centerpoint Energy Houston, LLC, Reliant Energy Retail Service, LLC, and Texas Genco, LP--not earlier than March 31, 2004, and not later than ten days thereafter;

(D) AEP Texas North Company and Mutual Energy WTU, LP--not earlier than May 28, 2004, and not later than ten days thereafter;

(E) AEP Texas Central Company and Mutual Energy CPL, LP--the later of September 3, 2004, or 60 days following completion of the sale of its generation assets.

(F) Notwithstanding the schedule in subparagraphs (A) - (E) of this paragraph, the commission may allow a company, upon a showing of good cause, to file its true-up application on a different date.

(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) 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 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. 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)."

Figure: 16 TAC §25.263(l)(1) (No change.)

(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. 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) 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 on 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.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on July 18, 2003.

TRD-200304355

Rhonda G. Dempsey

Rules Coordinator

Public Utility Commission of Texas

Effective date: August 7, 2003

Proposal publication date: April 4, 2003

For further information, please call: (512) 936-7308

16 TAC §§25.487 - 25.490

The Public Utility Commission of Texas (commission) adopts new §25.487, relating to Obligations Related to Move-In Transactions; §25.488, relating to Procedures for a Premise with No Service Agreement; §25.489, relating to Treatment of Premises with No Retail Electric Provider of Record; and §25.490, relating to Moratorium on Disconnection on Move-Out, with changes to the proposed text as published in the March 21, 2003 Texas Register (28 TexReg 2441). The commission withdraws §25.486, relating to Establishment of Service for Customers Disconnected for Non-Payment, as proposed in the March 21, 2003 Texas Register (28 TexReg 2441). Project Number 27084 has been assigned to this proceeding.

The transition from a regulated utility system to a competition-based system of utility regulation has generated a number of unanticipated problems that have required the commission, market participants, and customers to implement temporary solutions until more permanent solutions are developed. One area that has generated problems involves the switching of customers from one service provider to another. Under traditional service changes, a customer usually disconnects from one provider before obtaining service from the new provider. Because the service change could result in the customer being without essential electric service if there was a delay in the new connection, the commission, with the agreement of market participants, instituted a process which included a moratorium on disconnections during the service change. Although this process prevented unnecessary service outages, it led to confusion for both customers and service providers. The primary goal of these rules is to standardize the move-in and move-out processes, which will reduce the number of customers without a retail electric provider (REP) of record, reduce the amount of unaccounted-for-energy (UFE) and implement performance standards to lift the moratorium on disconnections when a customer moves out of a premise. These rules will reduce costs to market participants, reduce confusion for customers, and provide certainty in the competitive retail electric market in Texas. These rules will further the legislative policy and purpose of protecting the public interest during the transition to, and in the establishment of, a fully competitive electric power industry.

Comments were received on April 21, 2003 and reply comments were received on April 30, 2003. No request for a public hearing was made within 30 days of publication; therefore no hearing was held.

The commission received written comments on the proposed rule and registration form from Reliant Resources, Inc. (RRI), Alliance for Retail Markets (ARM), AEP Texas Central Company and AEP Texas North Company (AEP Companies), CenterPoint Energy Houston Electric, LLC (CenterPoint), Office of the Public Utility Counsel (OPUC), Electric Reliability Council of Texas (ERCOT), TXU Energy Retail and Oncor Electric Delivery Company (TXU/Oncor), and Nueces Electric Cooperative (Nueces).

In addition to the proposed new sections, the commission requested comments on the following questions:

1. Should the rule allow transmission and distribution utilities (TDUs) to bill retail customers, for past transmission and distribution charges, who have been receiving electricity but have not been billed because there is no REP of record associated with the premise?

AEP Companies, CenterPoint, Nueces, and RRI suggested that it was appropriate to permit the TDU to bill a customer directly for past transmission and distribution charges in those instances in which the customer actually lived in the premise and received the service, but did not pay because there was no REP of record associated with the premise. RRI did not oppose allowing a TDU to bill end-use customers for wires charges as proposed in §25.489(g), as long as the TDU is able to justify the charges with verifiable data and the REP is not required to pass along any such charges to its customers through its own billing systems. RRI acknowledged that the Texas market structure in general does not contemplate the TDU having a traditional utility billing relationship with end-use customers, but pointed out that current market experiences suggest that this remedy is necessary to minimize financial damage experienced by TDUs and REPs as a result of customers not paying for service they receive. CenterPoint added that financial harm is imposed on TDUs if recovery is not permitted, noting that the disconnection moratorium for move-outs causes the company to lose at least $165,000 per month. CenterPoint explained that a TDU's rates were based upon the legitimate expenses incurred to provide electric service and at the time these rates were set, the commission did not contemplate the moratorium. In addition, CenterPoint argued that failure to bill a customer for energy used provides an incentive for a customer to not establish service with a REP when power is already provided.

AEP Companies emphasized that the current TDU tariff already allows the collection of delivery charges from a customer for periods when the customer has no REP of record. Under the Initiation of Delivery Service section (Section 5.3.1.1, Initiation of Delivery System Service Where Construction Services are Not Required) of the TDU's Tariff for Retail Delivery Service, a retail customer is responsible for selecting a REP and selection of a REP is a precondition to receipt of delivery service. Thus, according to AEP Companies, a retail customer who is using power without a REP of record is using the TDU's delivery system without authorization. Furthermore, AEP Companies referred to language in Section 5.4.7, Unauthorized Use of Delivery System, which provides that a person using the delivery system without authorization may be required to pay all charges, including the delivery charges associated with the estimated amount of electricity delivered without TDU authorization. AEP Companies emphasized that this section does not require that the customer use the TDU's system with any intent to defraud. Thus, AEP Companies asserted that the customer should be charged for the use of the delivery system, so long as the TDU can reasonably support its claim that a particular customer occupied the premises during the period in which the consumption occurred and can show that it reasonably estimated the consumption for that period.

OPUC argued that retail customers should not be billed if the termination request was not made by the previous REP or electric utility, when appropriate, or if a termination request was not processed. If, however, there is no indication that a termination was or should have been made, OPUC would not oppose backbilling the retail customer.

ARM and TXU/Oncor opposed allowing a TDU to bill retail customers who have no REP of record because it is inconsistent with the market structure, would cause significant customer confusion, and would negatively affect customer education concerning the competitive market. ARM stated that this practice would put REPs in an awkward position of running interference between the TDU and the customer. In addition, ARM argued that allowing TDUs to directly bill customers would likely prove to be a disservice to many innocent customers, noting that the TDU will not likely know who to bill or whether the current occupant of the premise was the occupant during the period when service was received without a REP of record. TXU/Oncor pointed out that after unbundling, Oncor no longer has a mechanism to bill such charges to end-use customers, and, even if it were possible, in the majority of cases it would not be cost- effective to devote the resources required to investigate and prove that a particular customer was actually the responsible party for prior usage at a premise with no REP of record. TXU/Oncor noted that the processes in proposed §25.489 and §25.490 will largely remedy the problem of customers with no REP or record and, therefore, recommended deletion of proposed §25.489(g). TXU/Oncor asserted that the benefits of allowing TDUs to recover these costs do not outweigh the significant customer confusion and practical challenges and expenses that would be caused by such a rule. At a minimum, TXU/Oncor proposed that the commission make any backbilling permissive instead of mandatory.

In reply, AEP Companies noted that, contrary to TXU/Oncor's situation, it has not found the costs associated with backbilling to be prohibitively high and should not be barred from backbilling because of mere speculation regarding these costs. AEP Companies also noted that ARM's comments are unwarranted because it is reasonable to expect that the TDU's bill would contain TDU contact information for customers.

The commission agrees with ARM and TXU/Oncor that a TDU should not be allowed to bill end-use retail customers for wires charges solely for the reason that there was no REP of record. The competitive retail market structure in Texas is unique in that customers no longer have a direct relationship with the TDU. REPs are responsible for billing and customer service in the new market structure, not the TDU. Allowing TDUs to bill end use customers directly would cause customer confusion because customers would receive a bill from a company that is not their chosen electric provider and which is a company that the customer could never choose as their electric provider. In addition, the commission does not agree that providing TDU contact information on bills for wires charges is sufficient to resolve the customer confusion issue. TDU call centers and customer service groups are not likely to be sufficiently staffed and trained to communicate with customers about TDU bills because these functions largely moved to the affiliated REP when the integrated utility unbundled.

While the commission agrees with AEP that a moratorium on disconnecting service when a customer moves out was not contemplated when TDU rates were approved, the financial impact of the moratorium has been felt by REPs as well, because the cost of unaccounted-for-energy at such premises is charged to all REPs in the market. Allowing the TDU to directly bill for wires charges only injects customer confusion that is likely to harm REPs, while not allowing those REPs to recover their losses.

A TDU may bill an end-use customer only in conformance with its approved tariff. The standard Tariff for Retail Delivery Service referenced in substantive rule §25.214(d) (relating to Terms and Conditions of Retail Delivery Service Provided by Investor Owned Transmission and Distribution Utilities) requires the TDU to bill the retail customer's REP except in certain specific instances listed in Section 5.8.2 of the tariff. Section 5.8.2 does not authorize the TDU to directly bill the retail customer when the customer has no REP of record. A separate provision of the tariff, Section 5.4.7, Unauthorized Use of Delivery System, allows the TDU to bill a person found to be using the TDU's system without authorization. The commission finds that Section 5.4.7 is intended to primarily address situations involving meter tampering or bypass, or other instances in which the customer, or its agent, has engaged in fraud or misrepresentation in order to avoid payment for services. These were expected to be the only situations in which a customer would not have a REP of record. Language in this section of the tariff relating to "replacement or repair" of damaged meters and costs relating to "installment of protective facilities or of relocation" of the meter to prevent future unauthorized use are consistent with this intent. The tariff does provide that unauthorized use could occur by "other means," but that language should be interpreted in a manner consistent with the other provisions of Section 5.4.7, which imply an improper act by the customer before the use is deemed to be "unauthorized." The circumstance where a large number of customers have no REP of record is largely a result of the moratorium on disconnection on move-out, and was not contemplated when the market rules and tariffs were developed.

The commission acknowledges that it is possible , given the moratorium on disconnects on move-out, a customer could take advantage of the moratorium by: (1) knowingly request a move-out from their REP, with no intention of actually vacating the premise because they became aware that the premise would not actually be disconnected; or (2) move into a vacated premise where the power was still energized and intentionally not choose a REP because they are aware that they will not be billed by a REP). These circumstances could be construed as unauthorized use.

However, it is also certainly the case that a customer could have no REP of record in circumstances where the customer was not attempting to obtain service by improper means: (1) a customer's REP inadvertently requests a move-out for a premise; (2) a customer's enrollment or move-in request is not completed properly, due to a failure somewhere in the transaction pipeline; (3) a customer believes that he is enrolled with a REP and has in fact been receiving estimated bills from a REP, but the TDU does not show a REP of record in its system; or (4) a customer moves into a premise and enrolls with a REP, but a prior tenant did not.

In any of these cases, and potentially others, a current customer might receive a bill for prior months' wires charges after the customer either made extensive attempts at enrolling with or believed he or she was enrolled with a REP and thus had a good faith belief that their usage was authorized. Additionally, some customers may have been receiving and paying bills from a REP during the period of time for which the TDU would back-bill them. Lastly, the customer may not have been physically in the premise for the period in which the charges are being assessed.

The determination of whether or not a particular customer's use is considered an "unauthorized use" under the tariff should be made on a case-by-case basis. However, the comments indicate that there is confusion concerning whether the lack of a REP of record for a particular account should be considered an "unauthorized use" under the tariff. In order to clarify the confusion concerning the TDU's ability to directly bill an end-user customer, the commission is amending the rule to specify that direct billing is only authorized in those instances specified in the TDU's tariff that conforms to the commission's standard Tariff for Retail Delivery Service. Additionally, the commission is amending the rule to reflect that the lack of a REP of record, standing alone, does not constitute an "unauthorized use" under the tariff.

Finally, the commission agrees with TXU/Oncor that the processes in proposed §25.489 and §25.490 will largely remedy the problem of customers with no REP of record, on a prospective basis. New §25.490 permits the moratorium on disconnections on move-outs to be lifted if a TDU meets the performance standards established with respect to timely initiation and reconnection of service for customers. If a TDU meets standards of new §25.490, then it may begin disconnecting service to premises on a move-out requests, thus reducing the incidence of service locations without a REP of Record. Also, new §25.489 provides a process by which a TDU will be able to expeditiously remedy a circumstance where a service location does not have a REP of record by disconnecting service after providing proper notice. As such, no premise should be without a REP of record for a sustained period of time.

For these reasons, the commission amends §25.489(g) to clarify when a TDU may bill customers directly for wires charges and to clarify that the mere lack of a REP of record for a premise does not constitute unauthorized use under the tariff.

2. If backbilling for past TDU charges is appropriate, should the TDU be required to pass the charges through the customer's REP, or should the TDU be permitted to bill the customer directly?

CenterPoint recommended that the TDU pass the backbilling charges to the customer's REP because it follows the market design established by the Public Utility Regulatory Act (PURA) (i.e., that only REPs render bills directly to the customer). In support of its position, CenterPoint referred to PURA §39.107, which provides that a TDU must bill a REP for non-bypassable delivery charges and that a TDU can only provide billing agent services to a customer on behalf of a REP. Moreover, CenterPoint pointed out that it does not have the system capability to directly bill an end-use customer due to the re-design of its billing systems to prepare for the retail market. ARM strongly opposed CenterPoint's recommendation, noting that it was wholly inappropriate to put the REP in the position of collecting charges incurred by a customer when the customer had no relationship with the REP.

AEP Companies, RRI, and Nueces recommended that the TDU bill the customer directly for all justifiable charges that were incurred while the customer was without a REP of record. After a customer selects a REP, RRI suggested that the selected REP bill the customer only for charges that were incurred while the new REP was the REP of record and that the TDU submit a bill to the customer within 35 days after the date the customer is switched to the new REP. RRI strongly opposed CenterPoint's recommendation to pass the charges through to the customer's REP, noting that it would lead to more confusion than if the TDU billed the customer directly. RRI noted that if a customer with no REP of record begins service with a new REP, and that REP issues the customer a bill for changes incurred prior to the period the customer/REP relationship was established, the customer is likely to question the legitimacy of those charges. According to RRI, this practice would likely lead to increased complaints, as well as a negative perception of competition in general. Nueces added that the TDU would be in a better position to address the questions and disputes that would arise.

AEP Companies indicated that when no REP is identified for the customer for the period in question, the customer's new REP cannot bill the customer for service used by that customer for that prior period. Therefore, according to AEP Companies, the only way the TDU can bill for delivery service is to directly bill the customer. AEP Companies noted, however, that it would be appropriate for the TDU to bill the REP in instances in which the customer had a REP but that fact was previously unknown to the TDU.

However, ARM and TXU/Oncor argued that the TDU should not be allowed to bill customers directly for past wires charges or to pass these charges to the customer's REP to bill the customer and serve as the collection agent for the TDU. They noted that direct billing by TDUs would cause customer confusion and that passing charges through to the REP would impair the customer's relationship with the REP and would financially obligate the REP for wires charges during a time period when the REP had no relationship with the customer. According to ARM, the customer is arguably not obligated to its current REP for such charges and the risk of those unpaid charges should not be inappropriately shifted from the TDU to the REP. Nonetheless, if the commission determines that a customer should be billed for wires charges incurred when a customer did not have a REP, ARM suggested that the only reasonable mechanism would be for the TDU to bill the customer directly.

After reviewing the initial comments, RRI indicated that it would support a decision to prohibit backbilling by the TDUs in this situation.

The commission agrees with ARM and TXU/Oncor that TDUs should not be allowed to bill customers directly for past wires charges except as authorized by their tariffs. The commission also agrees that the TDU should not pass these charges to the customer's REP to bill the customer and require the REP to serve as the collection agent for the TDU. The commission agrees that direct billing by TDUs would cause customer confusion and that passing charges through to the REP would impair the customer's relationship with the customer and would financially obligate the REP for charges incurred by the TDU during a time period when the REP had no relationship with the customer. The commission, as indicated above, amends §25.489(g) to prohibit a TDU from billing customers directly for wires charges except in accordance with its commission-approved tariff.

3. Should the rule limit the TDU's backbilling to six months?

RRI suggested that any rule addressing backbilling of TDUs be consistent with rules pertaining to REPs and should apply prospectively.

OPUC asserted that a TDU's backbilling should be limited to six months, consistent with the reasons behind §25.28 of this title (relating to Bill Payment and Adjustment) and §25.480(e) of this title (relating to Bill Payment and Adjustments). Nueces agreed and noted that the customer should not be required to pay the accumulated charges for the past period all at once.

ARM indicated that in situations in which a customer actually had a REP yet did not receive a bill from that REP (e.g., if ERCOT's database failed to identify the REP of record), the REP should be able to bill for all charges incurred by the customer while served by the REP, including the TDU's wires charges. Moreover, ARM suggested that a REP be allowed to backbill the customer for charges over six months if both the REP and the TDU can produce records to justify such charges as being the responsibility of the current customer at that premise. ARM pointed out that the Texas Civil Practice and Remedies Code §16.004(3) limits the collection of a debt to four years and that ARM was unable to identify any authority that would allow the commission to shorten this for the provision of electricity.

Further, AEP Companies argued that a six-month limitation on TDU backbilling in proposed §25.489(g) is contrary to Civil Practice and Remedies Code §16.070, which prohibits a contract or agreement from providing a limitation period shorter than two years. AEP Companies also emphasized that any removal of the statutory limitations with regard to overbilling is inconsistent with case law that holds that agreements in advance to waive indefinitely the statute of limitations is contrary to public policy. In addition, AEP Companies argued that a state agency has no authority to adopt a rule that is inconsistent with state law, citing Railroad Commission of Texas v. Arco Oil and Gas Co. , 876 S.W.2d 473, 481 (Tex. App-Austin 1994, writ denied) and Gerst v. Oak Cliff Savings and Loan Association , 432 S.W.2d 702, 706 (Tex.-1968). Further, AEP Companies contended that the commission has neither an express nor implied grant of authority to alter the limitation periods. According to AEP Companies, if the commission has authority to address limitations by virtue of its authority over billing, the commission can harmonize such authority with existing law by setting a limit on backbilling that does not conflict with the Texas Civil Practices and Remedies Code §16.070 (i.e., set the limit for longer than two years). Even if the rule limiting backbilling were found to be lawful, AEP Companies indicated that there are strong policy reasons for not applying the rule when the failure to bill earlier was due to circumstances beyond the TDU's control.

ARM generally agreed with AEP Companies, but emphasized that the commission should recognize that tension might exist if a REP can be backbilled for more than six months yet be unable to collect these charges from its customers, either because a customer cannot be found or because seeking recovery would irreparably harm the customer-REP relationship. Even if market participants may legally be entitled to backbill more than six months, ARM indicated that it does not seem realistic that market participants would now attempt to bill for charges that have heretofore been recognized as uncollectible. ARM also proposed requiring TDUs to bill charges within three billing cycles and requiring REPs to bill charges within six billing cycles from the cycle in which the charges were incurred. According to ARM, the TDU's obligation to submit usage information in a timely manner should be embodied in the TDU's tariff.

CenterPoint stated that there should be no limitation on a TDU's backbilling in this situation, noting that neither PURA nor the commission's substantive rules limit a TDU's recovery of its delivery service charges that have never been billed.

OPUC disagreed with commenters who argued that backbilling for a TDU should be allowed for a period of four years, consistent with the Civil Practices and Remedies Code. OPUC noted that the commission already established a backbilling limit for REPs and the presumed justification is equally applicable to a TDU.

As discussed in the responses to Preamble Question Number 1, the commission has amended §25.489(g) to only permit a TDU to directly bill retail customers as permitted by its tariff and clarifies that "unauthorized use" of the delivery system is not established merely by the fact that there is no REP of record. The commission also notes that Section 5.4.7 of the Tariff for Retail Delivery Service governs the ability of a TDU to directly bill customers for unauthorized use. Therefore, the commission does not find a need to address that issue further here. The commission agrees that in situations in which a customer actually had a REP yet did not receive a bill from that REP, the REP should be able to bill for all charges incurred by the customer while served by the REP, including the TDU's wires charges, in accordance with §25.480, relating to Bill Payment and Adjustments. As part of Project Number 27084, the commission is currently reviewing §25.480 and will address ARM's suggestions to extend backbilling by a REP beyond six months during that phase of the project schedule. Accordingly, the commission has amended the proposed rule to remove any reference to backbilling limits.

4. What recourse, if any, should the TDU have if the customer with no REP of record does not pay the TDU for backbilled wires charges?

AEP and Nueces recommended allowing the TDU to disconnect service to a customer with no REP of record who does not pay for backbilled wires charges. AEP pointed out that the TDU tariff (Sections 5.4.7 and 5.3.7.2) authorizes the TDU to suspend or disconnect service to the customer for unauthorized use of service and to refuse to reconnect service until delivery charges are paid. Moreover, AEP suggested that Section 5.3.7.2 of the tariff allows a TDU to suspend service to a retail customer for failure to comply with the terms of an agreement with the TDU (e.g., for construction- related service), and Section 5.8.2 permits the TDU to directly bill the retail customer for those services. Further, AEP argued that no justification exists to treat customers differently for failing to pay for services depending on whether the services are provided by the REP and the TDU or services provided solely by the TDU.

ARM argued that in the event TDUs are allowed to directly bill customers with no REP of record, a TDU should not be allowed to disconnect a customer for non-payment of wires charges. ARM noted that neither the market nor market rules support giving any entity other than the affiliated REP or provider of last resort the right to disconnect a customer for non-payment. In addition, ARM contended that the consequences to the REP and the customer confusion associated with allowing a TDU to disconnect in these circumstances outweigh the potential benefits to TDUs. RRI and ARM suggested that the TDU seek restitution for unpaid debt in accordance with applicable law, such as through third-party collection agents.

CenterPoint indicated that PURA establishes that the TDU must bill the REP and, therefore, the REP would be the appropriate entity to render a bill to the customer. According to CenterPoint, the recourse for the TDU is set forth in the TDU tariff.

The commission agrees with AEP that the TDU tariff (Sections 5.4.7 and 5.3.7.2) authorizes the TDU to suspend or disconnect service to the customer for unauthorized use of service and to refuse to reconnect service until delivery charges are paid. However, as explained in response to Preamble Question Number 1, the commission finds that the TDU tariff regarding unauthorized use of a delivery system was never intended to apply to customers solely for the reason that there is not a REP of record.

As already explained above, the commission finds that §25.489(g) should be amended to prohibit TDUs from directly billing the end-use customer except as authorized by their commission-approved tariffs and to clarify that a customer's usage is not considered unauthorized use merely because there was no REP of record. Under the current market rules, only the affiliated REP or provider of last resort has the right to disconnect a customer for non-payment.

§25.486. Establishment of Service for Customers Disconnected for Non- Payment.

ARM, RRI, TXU/Oncor, and CenterPoint all commented that §25.486 should not be adopted as proposed because it would create an incentive for customers to avoid paying their bill by providing an expedited switch for customers who have been or are about to be disconnected for non-payment. Also, RRI, TXU/Oncor, and CenterPoint all cited various technical and market design concerns regarding the use of a move-in transaction for customers who have been or are about to be disconnected.

ARM argued against the adoption of proposed §25.486, arguing that that the policies reflected in the proposed rule are not in the public interest. ARM offered that the current market structure does not balance the rights and responsibilities of customers served by competitive providers, resulting in higher levels of bad debt expense for competitive providers in the deregulated market than in the regulated market. ARM stated that the rights and responsibilities of customers and REPs are not balanced, because the only consequence for a customer who seeks to avoid paying a bill is being transferred to the affiliated REP. ARM argued that §25.486 further weakens the balance of rights and responsibilities between customers and REPs, because the rule creates a special process that increases incentives for a non-paying customer to switch REPs, rather than pay the current REP what is owed. ARM argued that the commission should not reward customers who fail to meet their obligations to their provider with a benefit not available to others in the market. To do so makes it even more difficult for REPs to manage their credit risk, which threatens the viability of competition for all customers, especially residential customers. Therefore, ARM urged the commission to withdraw §25.486.

RRI stated that proposed §25.486 would create a perverse incentive for customers to avoid paying the REP of record by switching to a different REP. Additionally, RRI offered that the rule is not workable in practice. The rule requires the REP to ascertain whether the customer is being disconnected for nonpayment. RRI argued that such a question is invasive to customers who are setting up service in the normal course of business and unlikely to elicit an honest response from customers who are setting up service in an attempt to avoid paying their current REP. Thus, the REP will not be able to determine reliably when §25.486 applies. RRI offered that even if a REP could determine when §25.486 is applicable, the REP has no practical way of determining if the out-of-cycle switch can be completed prior to the actual disconnect, as required by subsection (c)(2).

Rather than requesting that the commission withdraw the rule, RRI requested that the rule be re-focused. RRI offered that the rule should be used to specify when a REP should use a move-in transaction, as opposed to a switch request. RRI recommended that a REP use a switch transaction if the customer who requests service (1) is not a current customer of the REP; (2) does not indicate that he or she is moving into a premise or establishing service at a vacant premise; and (3) indicates that the premise for which service is being requested has power. Conversely, a move-in transaction should be used if the customer indicates (1) he or she is moving into the premise; (2) he or she is establishing service at a premise that has been vacant; or (3) the premise to be served is without power. RRI stated that under these guidelines, the REP does not have to ask every customer whether there is a pending disconnection. Rather, if a customer with a pending disconnection requests service, then the REP should initiate a switch and explain to the customer that a switch can take up to 45 days or more to become effective. At this point, the customer can ascertain that the pending disconnection may occur before the switch is complete, and the customer can then determine whether to proceed with the switch or contact the current REP regarding payment. If the customer proceeds with the switch and is disconnected prior to completion of the switch, then the new REP can cancel the pending switch and issue a move-in transaction.

CenterPoint also argued against adoption of §25.486, because the proposed rule is a significant departure from the customer protections established for this market. CenterPoint also stated that the rule conflicts with the application of approved tariffs, and presents conflicts with existing market systems and designs, which CenterPoint will not be able to overcome. CenterPoint requested the commission withdraw consideration of §25.486 because the retail market currently has well-established procedures for reconnection of a customer's service when the customer has been disconnected for nonpayment. Under the current market design, a customer that has been disconnected for nonpayment can reconnect service by either paying the bill or switching to another REP and requesting an out-of-cycle switch. CenterPoint argued that this market design should be strengthened, rather than changed, because the proposed changes bypass market protections that have been built into the current market. A switch transaction allows time for a customer to receive notice of the pending switch and either accept the switch or contact ERCOT to cancel the switch. In contrast, a move-in transaction does not allow for customer notification to prevent slamming, and move-in transactions are forwarded directly to the TDU's by ERCOT. Thus, using a move-in transaction allows a customer who has been disconnected for nonpayment to circumvent the market design, which sets an unhealthy precedent for sustaining sound competition in the retail market. CenterPoint suggested that rather than adopt the proposed new §25.486, the commission should clearly state that a move-in transaction should not be used if the only change is to the REP of record.

TXU/Oncor also argued against the adoption of §25.486, because the rule would serve as a roadmap for non-paying customers on how to switch REPs and avoid paying their bill or getting disconnected. TXU/Oncor stated that, currently, there is an incentive for customers to pay their bills, which would be destroyed by adoption of §25.486. Presently, if a customer is served by the affiliated REP or provider of last resort (POLR), then the customer is at risk for disconnection for non-payment. If a customer fails to pay the bill and switches to a new REP, then under the current rules, that switch could take several days to process. Thus, customers who do not pay are at risk of being disconnected, even if they switch REPs. Under the new rules, however, the consequences of failing to pay one's bill are mitigated, because customers who fail to pay and switch REPs are afforded an expedited switch process.

In its comments, ERCOT noted that because the rule deviates from the standard use of a move-in transaction, the commission should clarify that this is the only situation in which a move-in would be used for an existing customer.

In reply comments, CenterPoint stated that it strongly agreed with the comments of ARM and TXU/Oncor in that the commission should withdraw §25.486, as opposed to re-focusing the rule, as suggested by RRI. CenterPoint stated that the rule unfairly offers an expedited switch for non-paying customers that is not available to customers in good standing. CenterPoint also reiterated its position that the proposed rule constitutes a redesign of the market, circumvents commission-approved customer protections, and conflicts with existing system and processes used in the market with the application of approved tariffs.

In reply comments, RRI concurred with ARM and TXU/Oncor that the rule, as currently written, would have an adverse impact on the market. RRI stated that creating an avenue in the rules for customers to avoid payment and disconnection is likely to interfere with a REP's means of holding customers accountable for services rendered. In contrast to ARM and TXU/Oncor, RRI urged that the commission re-focus the rule to delineate the appropriate uses of move-in transactions and switch requests. Additionally, RRI stated that re-focusing the rule would comport with CenterPoint's suggestion that the commission strengthen the existing market design.

In reply comments, TXU/Oncor concurred with ARM, RRI, and CenterPoint in that this rule would enable customers to switch from REP to REP leaving bad debt in their wake. Additionally, TXU/Oncor strongly recommended that the commission withdraw proposed §25.486.

In reply comments, OPUC disagreed with the comments of ARM, RRI, CenterPoint, and TXU/Oncor. OPUC argued that the REPs already have procedures for requiring a customer to establish satisfactory credit; thus, the rule provides no inherent incentive for customers to avoid paying their bills. OPUC noted that it is the REP's obligation to establish a customer's credit standing and use the credit information and the deposit procedures as specified in the substantive rules to mitigate financial losses. OPUC also stated that it cannot be assumed that a customer who is disconnected for non-payment has been accurately and fairly billed by the customer's REP. Billing errors have been common under competition; thus, it is feasible that a disconnection notice could be issued simply because the REP and customer fail to reach an agreement regarding charges.

The commission agrees with RRI, TXU/Oncor, and CenterPoint that there are various technical and market design concerns regarding the use of a move-in transaction for customers who have been or are about to be disconnected. In addition, the commission agrees with RRI that REPs should not be required to ascertain whether an applicant is being disconnected for nonpayment by another REP.

For these reasons, the commission declines to adopt §25.486 at this time. The commission will consider whether §25.483, relating to Disconnection of Service, should be amended to address these issues. In addition, ERCOT's Retail Market Subcommittee is addressing this issue and evaluating whether additional protocols or transactions should be adopted for a REP to reconnect a customer who has been disconnected by another REP. The commission suggests that RRI's comments regarding specifying when a move-in transaction is appropriate and when a switch transaction is appropriate be addressed in the taskforce.

Proposed new §25.486 was not intended to provide an incentive or means for customers to avoid paying their electric bill. The commission believes that a customer has an obligation to pay for the service provided by the chosen REP. Commission rules already address a REP's remedies for a non-paying customer (§25.482, relating to Termination of Contract, and §25.483, Disconnection of Service).

However, the commission notes that PURA §39.001 provides that a customer has the right to choose their REP, and does not place prohibitions on a customer doing so even if they are disconnected by their current REP for non-payment.

The commission disagrees with ARM that the proposed rule weakens a customer's incentive to pay an electric bill to a competitive REP beyond those incentives that currently exist in the marketplace today. The structure of the market whereby the affiliated REP and the POLR have the right to disconnect for non-payment and all other REPs may terminate service and drop non-paying customers to either the Affiliate REP or POLR, as appropriate, is not at issue in this proposed rule, and was fully addressed by the commission in Project Number 25360, Rulemaking Proceeding to Amend Requirements for Provider of Last Resort Service.

Although the commission is withdrawing proposed new §25.486 at this time, the commission finds that it is important that how a customer who has been disconnected for non-payment should be switched when that customer exercises the right to choose a different REP should be addressed. The commission agrees that such a process should not provide special benefits to allow non-paying customers to switch providers that are not available to other customers. All customers may currently request an out-of-cycle switch and pay the TDU charge for the special meter read. The commission believes that there should be a standard transaction so that a REP can switch a customer and energize service to that customer if they have been disconnected by another REP.

Various parties had other comments concerning §25.486 that were consistent with the comments summarized above or suggested modifications to improve it. As is noted above, the commission concludes that this section should not be adopted, and the issues raised by the parties should be addressed in conjunction with the possible amendment of §25.483 or in ERCOT working groups.

§25.487. Obligations Related to Move-in Transactions.

In its comments, OPUC was very supportive of the "safety net" process, as defined in the proposed rule, because it ensures that move-in customers receive electric service in a timely manner.

Nueces pointed out that this section applies to all retail electric providers (REPs) and municipally-owned utilities and electric cooperatives registered with ERCOT as competitive retailers (CRs). Cooperatives and municipal utilities are not REPs in that they do not register with the commission; however, they are registered with ERCOT as competitive retailers. Therefore, for the purpose of clarification, Nueces proposed that §25.487 and §25.488 be modified to indicate that these provisions are applicable to CRs as well as REPs.

The commission disagrees that it is necessary to clarify that these provisions are applicable to all competitive retailers. In §25.471(d)(12), a municipally owned utility or electric cooperative is only considered a REP where it sells retail electric power and energy outside its certified service territory. Therefore the concern raised by Nueces is already addressed by the existing rules. Modifying these provisions to account for both competitive retailers and REPs is superfluous and likely to cause confusion.

Initial comments by ARM, TXU/Oncor, CenterPoint and reply comments by AEP Companies strongly opposed memorializing the safety-net workaround and recommended that §25.487 be withdrawn. These parties generally agreed that the focus should be on improving transaction performance in the market to eliminate the need for the workaround entirely. TXU/Oncor mentioned that through §25.88, relating to Retail Market Performance Measure Reporting, the commission has the authority to subject market participants to performance improvement plans and potential enforcement procedures for failing to process move-in transactions within the timeframes required by the ERCOT protocols and TDU tariffs. Through the enforcement of these performance measures, the need for the workaround should significantly decrease.

ARM suggested that the commission either withdraw the rule and impose a three month timeline for phasing out the safety-net process or revise the rule to provide for a sunset of the rule three months after it is adopted, with a three month timeline for phasing out the process imposed through the rule. RRI recommended that the commission adopt March 1, 2004, as a sunset provision for reviewing the effectiveness of the safety-net process. RRI argued that a sunset provision is necessary to ensure that market participants do not inappropriately rely on the safety-net process as a permanent solution. RRI proposed a new subsection to establish the recommended sunset provision. ARM suggested that if a sunset date is incorporated into the rule, then that date should be much earlier than March 1, 2004. In its reply comments, the AEP Companies also agreed with RRI's position that a sunset provision to review the effectiveness of the safety-net process is worthy of consideration. In reply comments, TXU/Oncor agreed with CenterPoint that the commission should leave the safety-net process as a workaround, so that the process can easily expire when it is no longer needed. However, if the commission adopts the proposed rule memorializing the workaround, TXU/Oncor recommended that the commission revise the proposed rule to include the sunset provision proposed by RRI. TXU/Oncor offered that RRI's proposal offers the most practical and flexible method for phasing out the safety-net process.

The commission agrees that a sunset date for reviewing the effectiveness of the safety-net process is appropriate and adopts RRI's proposal in new subsection (e).

In its comments, CenterPoint stated that codification of the safety net process could potentially deprive market participants of the flexibility needed to ensure that the process will support the market's needs for the future. CenterPoint suggested that the commission allow ERCOT's Retail Market Subcommittee (RMS) and Protocol Revision Subcommittee (PRS) to address the technical interplay surrounding the implementation of this workaround. In reply comments, CenterPoint stated that although a secondary or back-up safety-net procedure might always be necessary to ensure the timely initiation of service for retail customers, the safety-net process should not be the primary or predominant method for service initiation, and REPs should be encouraged to follow up with appropriate transactions in a timely manner. In reply comments, the AEP Companies reasserted their stance that if this rule is adopted, the safety-net process should only be used for legitimate purposes and not to by-pass standard rules and processes.

The commission agrees that the ultimate goal is to improve the market's transaction performance and eliminate the need for frequent use of the safety net workaround. The commission agrees with CenterPoint's reply comments that the safety-net process should not be the primary or predominant method for service initiation, and that REPs should be encouraged to follow up with the appropriate transactions in a timely manner. This is the express purpose of this proposed rule - to require that when a safety-net move-in is used, a REP must then follow it up by submitting an electronic move-in transaction. The commission concludes that incorporating this idea in the rule is appropriate in the current state of market development, and that the sunset provision provides an orderly way of removing the requirement when the workaround is no longer needed. Therefore, the commission declines to accept commenters' suggestions to not adopt this rule.

The AEP Companies suggested that the commission add language to clarify that the move-in date on the safety-net spreadsheet and the EDI transactions should match. Under the safety-net process, EDI transactions are matched to the items on the safety-net spreadsheet. The proposed rule suggests that the TDU use the date on the safety-net spreadsheet as the date when wires charges and fees may begin to accumulate for billing by the TDU. However, as the AEP Companies noted, there is no provision in the rule to address the possibility that no EDI transaction has been delivered to the TDU. Therefore, the ERCOT daily extract will be utilized to timely identify potential conditions in which the records of market participants are not consistent. AEP concluded that it should be incumbent on the REPs to monitor the daily extract and quickly identify any REP of record on the safety-net spreadsheet that is at variance with the REP identified on the ERCOT extract.

The commission agrees that matching the date on the safety net spreadsheet to the date in the EDI transaction is absolutely essential to the success of this workaround and adds clarifying language to the rule. The commission has amended subsection (d)(1) to clarify that the effective date on the safety-net move-in request will also be the effective date for the move-in when the applicable move-in electronic transactions are processed.

§25.487(b), Definition

TXU/Oncor, RRI, ARM, and CenterPoint all suggested amending §25.487(b), as well as subsection (d)(1), to make the safety-net process applicable regardless of whether the move-in transaction requires the installation of a new meter. TXU/Oncor argued that there is no clear reason to distinguish between a move-in where a meter is already installed versus one where a meter is being installed for the first time. Therefore, the safety net should apply to new meter installations, as long as the TDU has completed construction of the necessary distribution infrastructure to establish electric service at a premise. TXU/Oncor, as well as CenterPoint, pointed out that the safety-net process must be available for new premises. In addition, builders and developers may be inconvenienced or financially harmed by not receiving timely installations.

The commission agrees that §25.487(b) should be amended to clarify that the safety-net process is applicable regardless of whether or not there is a meter at the premise at the time the request is made.

TXU/Oncor suggested that subsection (b), which defines the safety-net process as pertaining to certain "residences," should be amended such that the rule applies to all "premises." According to TXU/Oncor, the safety-net process is successfully being used to expedite move-ins to not only residential premises but also commercial and industrial premises.

The commission agrees that §25.487(b) should be amended to clarify that the safety-net process is applicable to all premise types.

Finally, the AEP Companies suggested expanding and clarifying the definition of the term "safety-net process" in proposed §25.487(b). The AEP Companies pointed out that the language should clarify that the safety-net process should be used for legitimate purposes and not to by-pass standard rules and processes.

The commission agrees with AEP and makes the suggested change.

§25.487(c), Standard move-in request

RRI argued that proposed new §25.487(c), as currently written, implies that a REP should submit a move-in transaction any time service is established. RRI suggested that this was not intended because there are times when a switch is the more appropriate transaction. Therefore, RRI provided language to eliminate a possible interpretation that a move-in is the proper transaction for all service initiations.

The commission agrees that RRI's proposed language serves to clarify the rule's intent and has made the clarifying amendment.

§25.487(d), Safety-net move-in request

According to RRI, if a REP does not receive confirmation that the TDU has received the appropriate move-in transaction, it does not necessarily mean that a REP should submit a move-in through the safety-net process. Although the REP may not receive confirmation of the move-in, it is possible that the REP may receive a valid move-in rejection, in which case the safety-net process should not be initiated.

The commission agrees that RRI's modifications to the proposed rule serve to clarify that if the REP receives a valid move-in rejection, such as a "not-first-in" rejection, then the REP should not submit the safety-net transaction.

In addition, RRI argued against establishing a definitive two-day timeline for the REP to submit the move-in request when using the safety-net process. Each TDU in this market is unique in its operational capabilities related to workarounds, and therefore, some TDUs may not need or want two days advance notice from the REP. Since this process is intended to be a workaround, TDUs should be allowed the necessary flexibility to establish effective timelines. CenterPoint expressed concerns about disrupting behind- the-scenes interaction between market participants and evolving processes with the overlay of static rules. However, CenterPoint suggested that if the proposed rule is adopted, the safety-net list should be sent to the TDU by the morning of the business day before the customer's requested move-in date. Receipt of the list by that time would provide the parties a reasonable opportunity to execute customer orders on the date requested without potentially over-riding electronic requests being sent through ERCOT.

The commission finds that it is important to implement a uniform practice in the market regarding when a safety-net move in request should be sent. The commission agrees with CenterPoint that requiring that the safety-net request be sent two days ahead might conflict with electronic requests being sent through ERCOT. Therefore, the commission concludes that the deadline for REPs to send the safety-net request should be closer to the effective date of the move-in. The commission has amended this section to require REPs to send the safety-net move-in by noon on the business day prior to the customer's requested move-in date. The rule is intended to provide minimum standards for this process. If a TDU is able to accommodate last minute requests by a REP, the rule does not prohibit the TDU from providing this level of service, as long as the REP and the TDU agree.

TXU/Oncor, RRI, CenterPoint, and ARM all suggested eliminating the requirement that the safety-net process only be used for premises at which a meter is already installed.

The commission agrees that this requirement should be deleted for the reasons indicated in comments on subsection (b) and has amended this subsection accordingly.

RRI commented that it supports requiring the TDUs to use the safety-net move-in date as the effective date for the initial meter read that denotes a change in REP ownership due to the move-in. RRI added that the TDU should not, however, issue any subsequent transactions associated with that move-in, such as an initial meter read, periodic consumption file, or wires invoice, until the REP submits the electronic transaction for that move-in. To do otherwise would cause a mismatch of ESI ID ownership between the TDU and ERCOT systems, resulting in manual error processing. The TDUs' withholding of the initial meter read, periodic consumption file, and wires invoices until an electronic move-in transaction is processed also provides an incentive to the REP to promptly submit the electronic move-in transaction, so that the REP can bill the customer with an actual meter read. ARM suggested that RRI's proposed changes to subsections (d)(2) and (d)(3), as proposed, should be modified simply to require that the REP submit the electronic move-in transaction in a timely manner. In addition, ARM advocated penalties for any other market participant that fails to take the steps necessary to complete a valid move-in submitted by a REP in a timely manner. ARM agreed with CenterPoint and TXU/Oncor that the REP's right to serve a customer should be established upon the execution or effective date of a move-in, not the date the move-in request is submitted. TXU/Oncor recommended that subsection (d)(2), as proposed, be amended to provide: "the REP establishes its right to serve the customer from the date the TDU executes the move-in by connecting service to the premise" and that such date also be the effective date for all wires charges and fees associated with that ESI ID. CenterPoint pointed out that the Texas Standard Electronic Transaction (SET) 867_04 Initial Meter Read Notification is recognized as establishing the REP's initial service date and the date from which the TDU's wires charges and fees will accrue. Without some amendment, the proposed rule would introduce unnecessary and burdensome complexity into both the wholesale and retail markets, possibly requiring modifications to existing systems and transactions, with no benefit to the customer.

The commission agrees with ARM, CenterPoint, and TXU/Oncor that the REP's right to serve a customer should be established upon the execution or effective date of a move- in, not the date the move-in request is submitted. The commission believes that this decision helps the market to remain consistent with established business processes and avoid potential out-of-synch conditions. The commission also concurs with RRI that the TDU should not issue any subsequent transactions associated with the move-in, except in response to an electronic transaction submitted by the REP.

RRI argued that the TDU should be entitled to late fees for delinquent payments of wires charges in the event that the REP is unable to complete the processing of an electronic move-in transaction prior to the date that the initial wires invoice would otherwise have been due if associated with an electronic move-in transaction. TXU/Oncor agreed with RRI regarding providing an incentive for REPs to promptly submit electronic move-in transactions after submitting a safety-net move in. TXU/Oncor stated that RRI's recommended revisions to proposed §25.487(d)(1) and (2) would address stacking service and synchronization issues associated with transactions related to move-ins. According to TXU/Oncor, RRI's recommended revisions make sense because of the progress that has been made in processing market transactions and the planned implementation of further enhancements.

The commission declines to amend the rule to incorporate a specific requirement that a REP must pay a late fee to the TDU in the event the REP is unable to complete the processing of an electronic move-in transaction prior to the date that the initial wires invoice would otherwise have been due if associated with an electronic move-in transaction. The TDU standard Tariff for Retail Delivery Service already allows the TDU to assess late fees in general when a REP does not timely pay for wires charges billed by the TDU. The requirements for late fees are within the scope of the generic tariff and not this rule.

TXU/Oncor suggested language to highlight that TDUs, REP's, and ERCOT may have responsibilities with regard to the transfer of information and transactions needed to finalize a move-in.

The commission agrees that all market participants have a responsibility to ensure the successful processing of move-ins and has amended the rule accordingly.

CenterPoint agreed that the REP should follow up all safety-net requests with a move-in transaction to ERCOT and that the appropriate response and notice transactions should be sent to the new REP and previous REP as soon as practical. CenterPoint indicated that most safety-net requests are the result of "not first in" move-in transaction rejections from ERCOT. As such, the most efficient way to accomplish the notice to the previous REP is for ERCOT to modify their system not to reject the move-in transaction for "not first in," thereby allowing the notice to be issued to the previous REP. These market design changes are currently being addressed by retail market participants. In the interim, requiring TDUs and ERCOT to provide the notice manually would only add another layer of administrative burden to an already manual process with no significant value added. Also, CenterPoint stated that it has found that when the TDU notifies a previous REP for a premise, the TDU is often caught in the middle of a contractual dispute between the previous REP and the customer.

The commission adds language to clarify that the "appropriate notice … sent to any prior REP of record in the TDU's or ERCOT's system" in the rule merely refers to the 814_06 transaction that is sent by ERCOT to the CR who is "losing" the customer.

AEP Companies proposed adding the following provision to proposed subsection (d)(3): "within ten business days, an EDI Transaction should be submitted by the gaining CR, and the TDU should retain the right to bill wire charges to the REP that submits a safety-net spreadsheet even when an EDI transaction is not received."

The commission agrees that a specific timeframe for follow-up by the REP is necessary, but believes that ten days is too long. The commission amends the rule to require the REP to submit the EDI transaction on or before the fifth business day after the move-in was submitted through the safety net process.

§25.488. Termination of Service to a Premise with No Contract (now Procedures for a Premise with no Service Agreement).

Nueces commented that in each subsection that refers to a REP or a non-affiliated REP the words "or a CR" should follow the word REP but that these words would not be added in those instances where the reference is to an affiliate REP.

As noted in response to similar comments on §25.487, a municipally owned utility or an electric cooperative is only considered a REP where it sells retail electric power and energy outside its certified service territory. Therefore the concern raised by Nueces is already addressed by the existing rules. Modifying these provisions to account for both competitive retailers and REPs is superfluous and likely to cause confusion.

ARM stated that subsection (b) presumes that ERCOT will notify a REP that it is serving a premise for which the REP has no service agreement. ARM does not believe this to be true but stated that the REP will likely learn that it does not have a relationship with a premise, because either mail relating to the premise is returned or because someone calls the REP to complain that they are being billed for service at a premise for which they are not responsible. ARM also stated that they are concerned that the language in the rule regarding the REP's receipt of "notice from ERCOT that it is responsible for providing service…" misstates the REP's obligation. ARM stated that the REP is not responsible for serving a premise for which it does not have a service agreement and that this rule should not presume that such a responsibility exists. ARM suggested this provision be revised to apply when a REP "learns or has reason to believe" that it is providing service at a premise for which it does not have a service agreement.

The commission agrees with ARM that the REP will likely learn that it does not have a relationship with a premise by means other than a notification from ERCOT. The proposed language already presumes this and does not require that a REP receive such notification before proceeding under the options provided for in subsections (b)(1) and (2).

ARM and RRI argued that the rule should be revised to require that the REP utilize the move-out process in situations where the name of the customer is not known.

ARM expressed concern about the requirement that the process for transferring a customer to the affiliate REP for non-payment be used for a situation where the customer does not have a contract with the REP. ARM stated that Texas SET 1.5 will require a customer's name to be provided when the customer is transferred to the affiliate REP and argued that under the circumstances contemplated in this section, the only transaction that will support these circumstances is the move-out. ARM stated that including the identity of the former customer at that premise could impair the credit of an innocent customer.

ARM also commented that it is unclear why the REP should be put at financial risk for the additional usage of the customer pending completion of a transfer of the customer to the affiliated REP. ARM stated that the process is necessarily more time-consuming than a move-out and that under current commission rules, if the REP does not have a relationship with the person occupying the premise, it cannot bill that customer for services provided. ARM commented that the REP is put in a situation where it is obligated to serve a customer for a period of time when the customer has no parallel obligation to the REP. ARM stated that the commission should allow the REP to bill the person occupying the premise for all services rendered by the REP.

RRI stated that, as the rule is drafted, the affiliated REP or POLR will be unreasonably required to provide service to a customer that has not selected a REP. RRI stated that circumstances addressed by the rule occur because of the moratorium on de- energizing a residential service premise and an existing customer leaving a premise without requesting a move out. RRI stated that, under the proposed rule, the affiliated REP and POLR are tasked with providing service in circumstances where the occupant has not requested service and the occupant has provided no contact information for the purposes of establishing a customer/ REP relationship. RRI recommended that when a REP finds that the customer at the premise it is serving does not have a contract with the REP and the REP is not able to establish service with the customer, then a non-affiliated REP should be permitted to process a move-out and the affiliated REP should be permitted to process a disconnect. RRI suggested that if the customer does not initiate service with the REP of record within ten calendar days from the date the move-out or disconnection notice was issued, then the move-out or disconnection transaction should be processed and the customer should also be permitted to choose another REP for service. RRI suggested that the transaction for choosing another REP should be a switch or a move-in transaction. RRI stated that under its proposal the customer would be made responsible for selecting a REP to establish service, and the affiliated REP and POLR would not be tasked to provide service to the customer. RRI stated that before retail choice, if an existing customer moved out and the new customer did not request service, the premise would be de-energized because either a move-out would have been initiated or the service would be disconnected as the utility would not receive payment for service rendered. RRI stated that the new rule should be consistent with these practices.

In reply comments, TXU/Oncor questioned whether this proposal would benefit the process, because as long as the moratorium on disconnecting a premise on a move-out is in effect, the electric service will remain on. In addition, TXU/Oncor argued, RRI's recommendation to wait ten days to process the move-out would allow electric service charges to continue to be incurred during that time period by a REP with whom the customer has no relationship and would create another manual process. TXU/Oncor suggested that this section be amended so that current occupants of a premise with no contract with the REP of record and customers whose contract has expired are transferred to the POLR instead of to the affiliated REP.

The commission declines to amend this section to allow REPs to submit a move-out for a current occupant who is not the customer with whom the REP of record has a contract. Under the rule, if the current occupant of a residential or small commercial premise is receiving service, but the REP providing the service does not have a contract with the current occupant, then the REP may transfer that account to the affiliated REP (and an affiliated REP may disconnect). This is consistent with the structure set up for non-paying customers. Sending a current occupant of a premise with no contract with the REP providing service to the POLR instead of the affiliated REP puts the current occupant in a less favorable situation than a non-paying customer, even though it may have been the previous occupant that failed to notify the REP of record to request a move-out. If the current occupant is not paying the REP's bills that are addressed to the previous customer, then the account should be transferred to the affiliated REP, consistent with the rules for non-paying customers.

The commission finds that allowing competitive REPs to issue a move-out would result in that premise becoming an account with no REP of record resulting in additional unaccounted-for-energy, which all REPs must pay. In accordance with new §25.489, the TDU would then issue a disconnect notice to that customer. Allowing REPs to issue a move-out in these situations would essentially give competitive REPs the right to disconnect, which is inconsistent with the rules established in §25.43, relating to the Provider of Last Resort, §25.482, relating to Termination of a Contract, and §25.483, relating to Disconnection of Service.

The commission disagrees with TXU that customers whose service agreement has expired should be transferred to the POLR because §25.43(n)(2) limits such a transfer to large non-residential customers only. Because §25.43 already addresses these customers, the commission finds that it is not appropriate to include customers with an expired contract under the provisions of §25.488(b). This subsection has been amended accordingly. The commission may address the issue of treatment of customers upon contract expiration when reviewing existing customer protection rules.

As previously stated in the commission's response to comments on proposed new §25.486(d), the commission agrees that a REP should be allowed to submit a move-out after a specified period of time after a customer has been disconnected for non-payment. The commission will address this issue at a later date in its review of §25.483, relating to Disconnection of Service (Project Number 27084).

TXU/Oncor recommended that subsection (b) be revised to provide clarification as to whom certain actions are to be addressed. TXU/Oncor stated that subsection (b) refers in several instances to a "customer" when the person is actually not a "customer" of any REP. TXU/Oncor recommended that "customer" be changed to "current occupant" in several appropriate circumstances.

The commission agrees and makes TXU/Oncor's suggested clarifying changes.

TXU/Oncor also suggested that the execution date of a termination or disconnection be changed from "ten business days" to "ten days" to be consistent with §25.482(h)(3) and §25.483(l)(3) and suggested that termination and disconnection be optional instead of mandatory so that the proposed rule is consistent with §25.482(b) and §25.483(c).

In reply comments, ARM agreed with TXU/Oncor that subsection (b) should be revised such that the execution date of a termination or disconnection notice is ten days rather than ten business days.

The commission agrees that the notice provisions in this rule should be consistent with those in §25.482 and §25.483, which require ten days notice, not ten business days notice. The commission is currently reviewing §25.482 and §25.483 and will consider at that time whether all notices for termination or disconnection of service should provide ten calendar days or ten business days notice. If necessary, the commission will make changes to the notice provision in this rule at that time. Accordingly, this section has been amended to require "ten days notice."

TXU/Oncor also suggested using the word "agreement" instead of contract because residential and small commercial occupants do not a have a "contract" with their affiliated REP for service.

The commission agrees that using the term "contract" is not the most appropriate term for the reasons cited by TXU/Oncor. The commission amends this section to replace the word "contract" with "service agreement" to clarify.

RRI stated that a new subsection (e) should be added that would ensure that the affiliated REP would reconnect service if the customer takes action after the disconnect to establish service. In reply comments, ARM objected to RRI's proposed new subsection (e) that provides only the affiliated REP the ability to reestablish service with a customer. ARM stated that a customer should have the ability to designate any REP as its provider and have its service reestablished. ARM suggested that the commission not adopt new subsection (e).

The commission declines to add a new subsection (e) as suggested by RRI. The current occupant does not have a service agreement with the affiliated REP in this situation. If the affiliated REP chooses to issue a disconnection notice, as provided for in subsection (b)(2), and disconnects the account, the current occupant may then choose any REP, including the affiliated REP. The gaining REP must then enroll the customer, with proper authorization and verification, in accordance with §25.474. If RRI's suggestion were adopted, then the current occupant could be reconnected with the affiliated REP and there would be no record of that customer's authorization to enroll with the affiliated REP.

ERCOT suggested several clarifying changes such as using the term "electric service" instead of "service" and using "notice of termination" instead of "notice." ERCOT also suggested substituting "ERCOT protocols" for "independent organization" and suggested the deletion of the requirement that the affiliated REP submit a switch request within three business days after receiving the transfer request, in order for it to be effective on the next meter read. ERCOT suggested instead that subsection (c) state: "The non- affiliated REP shall submit the appropriate electronic drop to affiliated REP request to be effective on the next meter read date." It also suggested that the word "premise" be used instead of "location" in subsection (e), pertaining to large non-residential customers.

In response to ERCOT's comments, the commission amends this subsection to clarify that a REP should submit a termination notice or disconnection notice, as appropriate.

The commission does not agree that the rule should refer to "ERCOT protocols," rather than "independent organization." The commission has designated ERCOT to be the independent organization required by PURA §39.151, therefore the appropriate term to include in the rule is "independent organization," which would include any entity that should be designated as such by the commission.

The commission also does not agree with the proposed language for timing of a switch submittal. The existing language is intended to present REPs with a deadline for submitting the switch and the proposed language would not include that deadline.

The commission does agree that "premise" be substituted for "location" and has made the appropriate changes.

§25.489. Treatment of Premises with No Retail Electric Provider of Record.

OPUC, ARM, AEP, RRI, and TXU/Oncor generally supported this section because, they said, it sets out a standardized process for addressing situations where there is no REP of record. TXU/Oncor, CenterPoint, and RRI each cited the moratorium on move- out disconnections as a primary cause for accounts with no REP of record.

These parties generally agreed that once the disconnection moratorium is lifted, there will be only a small number of occurrences in which a customer is receiving service with no REP of record. In its reply comments, ARM noted that elimination of the disconnect moratorium should reduce the number of no REP of record accounts, but was not convinced that the problem will simply disappear once the disconnect moratorium is lifted. In addition, under the proposed rules, the conditions warranting lifting the moratorium will be solely a function of TDU performance. ARM believes that a process to deal with no REP of record accounts should be put in place in the event that a TDU fails to meet the conditions precedent to lifting the moratorium.

OPUC was particularly supportive of the door hanger process for premises with no REP of record because, they argued, it is a reasonable method to notify electric customers of their responsibilities to select a REP, and the door hanger itself provides the necessary information for customers to comply with the electric service rules. RRI supported the commission's decision to conduct a workshop regarding proposed new §25.489 so that parties may address specific concerns and outline a plan of action to make the rule amenable to all parties involved.

CenterPoint did not support the adoption of this section of the proposed rules. CenterPoint asserted that the new procedures would supplant the process that staff and the market informally adopted in April 2002, with no clear benefit to the end-use customer. CenterPoint argued that once the disconnection moratorium is lifted, the few "no REP of record" accounts that remain could be transferred to a REP using the procedures currently in effect within the market. CenterPoint asserted that the TDUs do not currently have approved tariffs to offset the costs associated with compliance with the proposed rule. In addition, according to CenterPoint, the query for pending transactions in the TDU's and ERCOT's systems, which typically takes five or six hours for the Company's system to perform, must be performed three separate times during the proposed process: once prior to the circulation of the No REP of Record List to the retailers, again after the three-day response period for the REP has expired, and immediately prior to the issuance of the notice of disconnection, and a third time once the ten-day notice period has expired and the disconnection of service has been scheduled. Finally, CenterPoint argued that it no longer has the mass billing system necessary to create either bills or door hangers. In its reply comments, CenterPoint reasserted its position that it does not support the adoption of this section of the proposed rules and urged the commission to withdraw the proposed rule and to move forward with lifting the moratorium.

In its reply comments ARM stated that a process to deal with "no REP of record" accounts should be put in place in the event that a TDU fails to meet the conditions precedent to lifting the moratorium. ARM disagreed with CenterPoint that a process for scrubbing customer lists to identify "no REP of record" accounts is not needed and supported the approach to managing these accounts discussed at the April 24, 2003 workshop.

The commission finds that the proposed rule, requiring a TDU to identify accounts with no REP of record, and then provide notice of disconnection unless the customer selects a REP, is the best way to deal with such accounts. The commission agrees that the problem of these "orphan accounts" is largely due to the moratorium on disconnecting a premise when a move-out is requested. The current, unofficial procedure whereby the TDU simply assigns orphan accounts to the affiliated REP has many problems. First, competitive REPs are never notified of any orphan accounts and are not given the opportunity to claim any accounts that may be theirs. As a result, it is possible that a competitive REP's customers are given to the affiliated REP simply because a move-in transaction was lost in system. In addition, this procedure puts a burden on affiliated REPs who are responsible for wires charges beginning on the day the TDU assigns the orphan account to the affiliated REP. The affiliated REP must then send a notice to the premise, without a customer name, and may only disconnect service to the premise ten days after notice is sent out. This burdens the affiliated REP with approximately two weeks worth of energy costs and wires charges for which they cannot submit a bill to the customer.

With the adoption of §25.490, the commission anticipates that each of the TDUs will meet the required performance standards to end the moratorium on disconnections on a move out, significantly reducing the number of orphan accounts. However, the commission agrees with ARM that ending the moratorium will not eliminate all orphan accounts. For this reason, TDUs should have a standard practice for handling such accounts. Therefore, the commission declines to adopt the changes suggested by CenterPoint and retains the requirement that the TDU compile a list of orphan accounts, scrub that list with ERCOT and all REPs, and provide the occupant of the premise with a disconnection notice.

§25.489(b), Definition

ARM recommends that the definition of the term "no REP of record" be clarified as follows: "For this section, the term "no REP of record" means a premise that is receiving electricity equal to or greater than 150 kWh in a single meter reading cycle, but for which no REP is designated as serving the premise in the TDU's system."

The commission agrees and makes the clarifying change.

§25.489(c), Obligation of TDUs to identify premises with no REP of record

TXU/Oncor supported the process outlined in subsection (c), because it will significantly decrease the amount of energy consumed at premises that are not the subject of an agreement with a REP for the provision of electric service.

ARM suggested that subsection (c) should be modified to better define the specific steps to be undertaken by REPs and TDUs with respect to development and refinement of the list. ARM pointed out that while the rule specifies that the TDU shall compile the list monthly, it does not specify how frequently that list will be provided to REPs, nor does it address the need for REPs to receive these lists on staggered dates throughout the month to avoid being inundated with lists from multiple TDUs all at one time. ARM believes that the details concerning development and processing of this list could be readily developed using the more detailed ESI-ID reconciliation process currently being implemented by the AEP wires company as a template.

The commission agrees with ARM and makes amendments to subsections (c) and (d) to clarify that TDU's shall send the list to REPs on a monthly basis. The commission understands ARM's concerns about REPs being inundated with "No REP of Record" Lists. The commission will work with REPs and TDUs following the adoption of this rule regarding a monthly schedule for the TDUs to send the list to REPs. Because the lists will be shorter each month due to the process adopted in new §25.489 and §25.490, the commission finds that staggered lists may eventually become unnecessary.

AEP proposed that in subsection (c)(1), the text "on a monthly basis" be deleted because the frequency of the preparation of the No REP of Record List should be at the discretion of the TDU. ARM argued that it is important for the market that the No REP of Record List be maintained on an ongoing basis and there should be minimum timeframes imposed on the TDUs for repetition of the scrubbing process.

TXU/Oncor disagreed with AEP on this issue and recommended that the lists be provided on a weekly basis in order to allow them to be routinely created, reviewed, and maintained (rather than requiring a "fire drill" once a month to produce and review the lists), and to expedite the disconnection of those residences, thus cutting the losses that are being incurred as a result of serving them. ARM supported TXU/Oncor's proposal and specifically requested that a standardized format for the list be required of all TDUs for a weekly list. If non-standard formats are used, the burden of scrubbing up to five lists on a weekly basis would be too difficult for individual REPs to manage.

The commission disagrees with AEP that the frequency of the No REP of Record List should be at the discretion of the TDUs. The market needs standardization and the commission seeks to establish minimum timeframes for creating the list. However, the commission declines to design a standard format in which the list should be sent to REPs.

The commission disagrees with TXU/Oncor's proposal to require TDUs to prepare a No REP of Record List each week. The commission understands that this process may be resource intensive initially, mostly due to the moratorium on disconnection. Requiring TDUs to create this list every week, instead of every month, would only worsen the impact on TDUs. Further, Oncor, CenterPoint, and TNMP indicated in the workshop, held on April 24, 2003, that creating the list will be a manual process. For this reason, the commission finds that it is appropriate to retain the current language that requires TDUs to prepare the list on a monthly basis.

CenterPoint proposed that the 150 kWh presumed vacancy threshold should not be a ceiling. For premises above the stated threshold, CenterPoint argued that TDUs should be allowed to make a business decision as to whether it is economical to initiate the proposed process on an account-by-account basis. The unaccounted-for-energy and unbilled delivery service charges provide the TDUs with sufficient incentive to reduce losses associated with these premises.

The commission disagrees with CenterPoint and declines to revise this section to allow a TDU to not comply with the notification process for premises with usage over 150 kWh. To do so would only increase unaccounted-for-energy and circumvent the intent of the rule. TDUs would have the discretion of lowering the 150 kWh threshold, as that would further reduce the number of accounts with no REP of record and reduce unaccounted-for-energy.

§25.489(d), Submission of No REP of Record Lists to REPs.

TXU/Oncor argued that it would be more appropriate to provide REPs with a full business week (five business days) to "scrub" the lists to verify if they have a contractual relationship concerning any of the ESI IDs included on the lists. Furthermore, because the TDUs' obligation to issue disconnection notices to premises on the list is triggered by the expiration of a REP's time period to scrub the list and a TDU will not necessarily know when a REP "receives" the list from the TDU, TXU/Oncor recommended that the five-day time period begin when the TDU sends the list, rather than when the REP receives it.

The commission agrees with TXU/Oncor's suggestions and makes the changes accordingly.

RRI recommended deletion of the proposed language in §25.489(d) related to door hangers because it is repetitive of §25.489(f).

The commission agrees and makes the suggested change. Proposed subsection (f) already specifies that the accounts on the final list shall receive the disconnect notification.

Proposed §25.489(e), Prohibition on use of No REP of Record List

TXU/Oncor recommended deletion of subsection (e), which prohibits the use of the No REP of Record List as a marketing tool, because the persons on that list are exactly the persons that need to be provided with the information necessary to enable them to choose a REP. Moreover, they argued, other customer protection rules related to marketing (e.g., §25.474) should sufficiently protect these persons from improper marketing.

ARM and RRI both supported revising this section to allow for a minimum "dead period" of three days in which no REP will market to customers on the list. This period should provide a REP who determines that it has an existing relationship with a customer on the list to contact the customer and inform the customer of the steps that will be taken to establish official service to the premise. After the expiration of the "dead period," all REPs should be free to market to customers on the list. TXU/Oncor did not support the three-day delay period concerning use of the No REP of Record List as a marketing tool, because it is impractical and would not accomplish the stated goal. TXU/Oncor stated that unless the No REP of Record List was re-published by a TDU without the inclusion of customers that have been claimed by a REP (which would necessitate identification by the REP of the customers and communication of that information to the TDU), then the list after three days is no different than it was on the day it was published. Therefore, they argued, the three-day dead period would not benefit the process, yet it would add another regulatory restriction that would have to be observed by REPs and potentially monitored by the commission.

OPUC disagreed with ARM and RRI and stated that REPs should not use the TDUs "No REP of Record List" as a marketing tool, even after a three day period has elapsed.

The commission agrees that there is a benefit to allowing REPs to market to occupants of a premise listed on the No REP of Record List. However, the commission agrees that implementing a three-day delay period before REPs are allowed to market would not benefit the process. The purpose of this rule is to facilitate selection of a REP and establishing an account by a current occupant who is receiving electric service, but has no REP of record. Allowing REPs to use the list of occupants to extend offers for service is consistent with this goal. The commission notes, however, that any REP that claims a premise in accordance with subsection (d) and any REP that enrolls an orphan account shall comply with all authorization and verification requirements under §25.474 of this title (relating to Selection or Change of Retail Electric Provider). The commission deletes subsection (e), and amends subsection (d) to include the language regarding a REP's responsibility to comply with §25.474.

Proposed §25.489(f), Customer notification

RRI supported the provision to require that the door hanger be provided in standardized bilingual format.

CenterPoint, TXU/Oncor, and AEP recommended that the proposed notification method be expanded to allow TDUs the option of either providing notice through a written mailing or a door hanger. Because a door hanger methodology likely would be much more costly than a mailing methodology, without providing significant additional benefits (if any), these commenters argued that the door hanger method of providing notification would be extremely resource intensive.

The commission agrees with commenters that it is reasonable to allow TDUs the flexibility to either mail the notice or to provide it as a door hanger. However the commission is concerned that notices mailed to an address may be returned to sender. To reduce this possibility, the commission finds that it is appropriate to require that TDUs sending a disconnect notice by mail in this situation should address the notice to "current occupant." TDUs that choose to send notice by mail should provide an advance copy of the notice to commission staff.

Proposed §25.489(g), Wires charges billed to customer with no REP of record

The AEP Companies proposed that in proposed subsection (g), the term regarding the billing of wires charges "from the date of the last move-out transaction that completed the transaction lifecycle, or for the previous six months, whichever is less," should be eliminated. AEP stated its position on the six months issue in response to Preamble Question Number 3.

As discussed in response to comments to Preamble Question Number 3, the commission has amended this subsection to prohibit TDU's from backbilling an occupant at a premise with no REP of record for wires charges.

Proposed §25.489(h), Door hanger format (now Format of notice)

ARM suggested that the TDU should provide the ESI ID for the premise with no REP of record on the door hanger in an effort to facilitate the enrollment process when a customer contacts a REP. The addition of the ESI ID on the door hanger will be particularly helpful in cases where a customer's premise has multiple ESI IDs.

The commission agrees that including the ESI ID on the door hanger or mailed notice would facilitate the customer's enrollment with a REP. The commission amends this subsection accordingly.

ARM also pointed out that there will actually be two door hangers - one for residential customers and one for commercial customers. ARM recommended that subsection (h)(2) be revised to indicate that the door hanger for commercial customers will include a "comprehensive list of REPs serving commercial customers in the TDU's territory...."

CenterPoint and TXU/Oncor disagreed with ARM on this point, and recommend that the rule not require that the notices list all of the REPs serving customers in the TDU's service area because that list is subject to change frequently and therefore could cause significant waste of printed material. Rather, both CenterPoint and TXU/Oncor suggested including the commission's customer service hotline phone number and the commission's website address that lists all certified REPs so that customers can access the most up-to-date information concerning potential REPs.

The commission finds that it is important that the notice provided to an occupant at a premise with no REP of record is informative and facilitates that customer's enrollment with a REP. Including a list of REPs from which that customer may choose is the most important information on the notice. However, the commission amends this subsection to clarify that the list of REPs is provided in the notice, but delete that the list must be "listed below." In addition, the commission agrees that this section should be amended to recognize that a separate notice will be needed for commercial premises and makes the clarifying changes accordingly.

CenterPoint proposed that language be added to the notice to reflect that disconnection will occur no earlier than "ten calendar days" after the date the notice is issued. In the instance of notification by mail, three days should be added to the stated minimum "ten calendar day" notice period.

As already discussed in the commission's response to comments on §25.488, the commission is currently reviewing §25.482 and §25.483 and will consider at that time whether all notices for termination or disconnection of service should provide ten calendar days or ten business days notice. If necessary, the commission will make changes to the notice provision in this rule at that time. Accordingly, this section has been amended to require "ten days notice."

Proposed §25.489(i), REP obligation to submit move-in transaction

As discussed in conjunction with proposed §25.486, ARM argued that the three- day rescission period must be eliminated for all move-in transactions in order to ensure that the REP will be able to bill for services rendered. This is particularly true if the commission mandates that a move-in transaction be used.

The commission agrees that a REP should not be obligated to provide the three day rescission period when submitting a move-in transaction. However, the commission finds that it is unnecessary to amend this subsection, because it is more appropriate to amend §25.474(h), relating to a customer's right of cancellation. As part of Project Number 27084, the commission is currently reviewing that rule and will propose amendments later this year.

TXU/Oncor recommended that proposed §25.489 be amended to add a subsection that addresses instances where customers are disconnected due to an error in the "no REP of record" process. Regardless of whether the error is due to an action of the REP, the TDU, ERCOT, or the customer, there should be an expedited process to reconnect such customers. TXU/Oncor provided language for a new subsection (i) that would require TDUs to have such a process, and allows the TDUs to charge appropriate fees to REPs for such expedited requests unless the TDU is at fault in causing the disconnection. In response to TXU/Oncor's suggestion concerning expedited reconnections for customers disconnected in error, CenterPoint noted that the TDUs should only provide expedited reconnection service as set forth in each TDU's commission-approved tariff.

The commission strongly encourages TDUs and REPs to work together to ensure that customers are not erroneously disconnected and if that should happen, the customer should be reconnected on an expedited basis. Accordingly, the commission has included TXU/Oncor's suggestion in the rule (as a new subsection (j)), but clarified that the reconnection should be done in accordance with commission rules in addition to the TDU tariff.

Proposed §25.489(j), Disconnection of premise with no REP of record

CenterPoint suggested that the rule language be changed to reflect that upon expiration of the "ten calendar day" notice period, the TDUs should be permitted to complete the disconnections according to existing crew and resource availabilities and schedules.

The commission declines to make this change in this rule. As part of Project Number 27084, the commission is currently reviewing the disconnection rule and will propose amendments later this year.

§25.490. Moratorium on Disconnection on Move-Out.

RRI strongly supported proposed §25.490, indicating that the rule would significantly reduce the number of premises with no REP of record. CenterPoint argued, however, that there is no reason to preserve the disconnection moratorium because the market has gained experience and made significant improvements in handling move-in transactions and there is a safety net process to ensure the successful initiation of service. CenterPoint also noted that the commission already has the tools to monitor and ensure timely processing of move-in transactions through the performance measures adopted in Project Number 24462, PUC Proceeding to Establish Performance Measures Relating to the Competitive Retail Electric Market . Further, CenterPoint emphasized that the moratorium is the primary driver of the "orphaned" account issues and cost-recovery concerns discussed in response to the preamble questions. According to CenterPoint, the moratorium creates more problems than it solves and no longer serves a useful purpose.

ARM agreed with CenterPoint that steps to lift the disconnection moratorium should be taken as expeditiously as possible because the moratorium has caused problems in the market. However, ARM argued that the proposed rule is warranted and supported the notion that TDUs should have to meet a specific performance level in order to lift the moratorium.

The commission disagrees with CenterPoint that the moratorium should be eliminated at this time. While the commission recognizes that the moratorium has caused problems, it is necessary and essential for customers to keep the moratorium in place until the market can maintain satisfactory performance in processing move-in transactions and reconnections. The rule provides an appropriate goal for TDUs to lift the moratorium by achieving and maintaining the performance standards related to these transactions.

§25.490(a), Applicability

TXU/Oncor recommended modifying subsection (a) to clarify that the rule applies only to residential premises because the move-out disconnection moratorium applies only to residential customers.

The commission agrees with TXU/Oncor and clarifies the rule accordingly.

§25.490(c), Filing requirement (now Reporting requirement)

CenterPoint recommended removing from the success rate move-in requests involving atypical situations, including: (1) connections that are attempted but "unexecutable" because of a fence, dangerous animal, etc.; (2) instances when a permit is required before a connection can be performed; and (3) connections that require construction of distribution infrastructure other than a meter (e.g., poles and wires) to establish service. If the rule is adopted, CenterPoint proposed excluding similar situations, as well as situations in which a meter must be installed or the move-in request is dated for a date in the past.

The commission finds that by amending subsection (c) to measure a TDU's success rate from the "scheduled date" instead of the "requested date," CenterPoint's suggestion to take out special circumstances is unnecessary. A REP may submit a request for a move- in for a specific date; however, the TDU may then reject that request date for any of the reasons cited by CenterPoint. The final scheduled date would already take into account special circumstances such as required construction, a necessary permit, a needed meter, or restricted access. The commission does agree with CenterPoint that removing back- dated move-ins from the reporting requirement is appropriate and makes the corresponding change to the rule.

RRI and TXU/Oncor suggested requiring each TDU to report on its current success rate for achieving the 95% benchmark within 15 days, instead of ten days, following the end of the month covered by the report. TXU/Oncor noted that this time was needed to acquire and process all of the information required by the proposed rules. CenterPoint suggested that TDUs submit the monthly report no later than the last day of the month following the reporting month.

The commission agrees with RRI and TXU/Oncor that it is reasonable for TDUs to submit the monthly reports 15 days following the last day of the reporting month, instead of ten days as proposed. The commission disagrees with CenterPoint that the deadline should be extended to the last day of the month following the reporting month. It has not been demonstrated that this additional time is necessary and it may delay resolution of issues that could be identified through the tracking and reporting process.

AEP Companies proposed removing the phrase "on or before" the requested date in subsection (c), noting that the concern for public safety and liability for connecting customers prior to the move-in date makes this wording inappropriate. RRI proposed adding language in subsections (c) and (d) that specifies that the measurements be based on adherence to ERCOT protocols.

The commission agrees with AEP that the phrase "on or before" is problematic. It is noted that if a REP submits a safety-net move in request, new §25.487 requires the REP to then submit an electronic move-in request. That electronic request would have a backdated scheduled date and would not be included in the TDU reports. The commission disagrees with RRI's proposal to rely on adherence to ERCOT protocols, because the protocols do not provide timelines for completion of move-ins or reconnections. The commission amends this subsection to require the TDU to measure the success of reconnections and move-ins from the scheduled date of the move-in or reconnection.

§25.490(d), Relaxation of moratorium on disconnection

TXU/Oncor agreed that the moratorium should be lifted if the move-in processes are working on a timely basis, but recommended lifting the moratorium no earlier than October 1, 2003. According to TXU/Oncor, this would permit systems to progress and the market to mature through an additional summer period, so that the move-out disconnections will begin when the weather is milder and the active summer moving period has ended. RRI disagreed with TXU/Oncor's proposal, noting that TDUs should be encouraged to reach the 95% standard for processing move-ins as soon as possible so that the moratorium and its related problems can be eliminated.

The commission disagrees with TXU/Oncor that the moratorium should be mandatory until October 1, 2003. While the commission appreciates TXU/Oncor's concern about possible problems with the high-volume of move-in transactions occurring during the summer months, the commission believes that a TDU should be permitted (and encouraged) to discontinue the moratorium at the earliest possible date that it can demonstrate and maintain satisfactory performance in processing these transactions. If a TDU subsequently falls below the standards set forth in the rule, the rule would require that it re-instate the moratorium. The commission believes that this approach will eliminate at the earliest possible date the problems associated with the moratorium that RRI, CenterPoint, and other market participants have identified.

ARM generally supported proposed §25.490, but recommended modifying the TDU's reporting requirements to include monthly reporting of both standard and safety- net move-in requests, and all service reconnection orders by the requested date.

The commission declines to make this change. As noted above, if a REP submits a safety-net move in request, new §25.487 requires the REP to then submit an electronic move-in request. That electronic request would have a backdated scheduled date and would not be included in the TDU reports.

While TXU/Oncor supported lifting the moratorium based on a TDU's success rate of processing move-in requests, the company questioned conditioning the end of the moratorium on the success rate of reconnections. TXU/Oncor pointed out that TDUs are not currently required to track reconnection success rates and, in fact, there is no common transaction used to initiate reconnections that would allow such tracking to occur. Moreover, TXU/Oncor stated that the term "reconnection" is ambiguous and could refer to all reconnections, including those executed for a move-in request, service issues, etc. In addition, AEP Companies argued that combining service connection and reconnection for non-payment under the rule is inappropriate because these transactions are completely different processes. AEP Companies pointed out that reconnection after disconnection for non-payment has no influence on the disconnection after a move-out. TXU/Oncor agreed with AEP Companies and emphasized that reconnections related to issues other than move-out disconnections should not be a criteria for lifting the moratorium.

The commission disagrees with AEP Companies and TXU/Oncor that TDUs should not be required to report their performance with regard to reconnection requests. The commission is currently reviewing §25.483, relating to Disconnection of Service, to require specific timelines for reconnection of service when a customer has been disconnected for nonpayment. The commission finds that it is important to measure the success rate of a TDU in energizing a premise on time. It is equally important to measure whether a TDU is meeting requests to reconnect service as it is to measure the success in initially connecting service.

AEP indicated that the measurement in subsection (d) for relaxing the disconnection moratorium is based on the date the customer requests commencement of service and can create the illusion that the TDU is not conforming to the rules. AEP Companies explained that a customer may request a same-day or next-day service connection in a situation in which construction, permits, etc. are required to complete the move-in, making the customer's request impossible to meet. Moreover, AEP Companies noted that Section 15.1.4.1 (Request to Begin Electric Service) of the ERCOT Protocols states that same-day move-ins will be supported by ERCOT if received by 9:00 a.m., and forwarded to the TDU within six hours of receipt by ERCOT. Same-day move-ins received after 9:00 a.m. will be processed the next business day. In addition, AEP Companies suggested that any backdated move-in request must be excluded from the performance measurements. AEP proposed modifying subsection (d) to measure move-in requests for reconnection on the requested date, and if the date of service is at least two days after the TDU receives ERCOT's order. For a period that is less than this time allotment, AEP Companies suggested that the TDU be considered in compliance when the order is completed by the close of the next business day after the TDU receives the order. TXU/Oncor proposed measuring the success rate according to the date the TDU schedules execution of a move-in request, not the move-in date requested by the REP.

For the same reasons stated above, the commission amends this section so that the TDU success rate is measured based on meeting the scheduled date of reconnections and move-ins, instead of the requested date.

TXU/Oncor recommended adding a new subsection (f) that requires a TDU to send notices to REPs in its service areas prior to changing the status of executing disconnections upon the receipt of a move-out request.

The commission agrees that the notice proposed by TXU/Oncor would be useful for REPs and would not be a significant burden on TDUs. Therefore, the commission amends the rule by adding new subsection (f) to that effect.

ARM suggested adding a new subsection to the rule to address the permanent lifting of the moratorium when the TDU has demonstrated a 95% success rate for 12 consecutive months. CenterPoint replied that the 12-month time frame suggested by ARM is unnecessarily costly and excessive, because there is already a safety-net measure to support the overarching goal of customers receiving timely provision of service. CenterPoint supported the three-month provision for demonstrating successful performance.

OPUC objected to the proposal in the rule to relax the disconnection moratorium on move-outs. OPUC suggested that the rule require the TDU to show on a continuing basis that 95% of move-in requests have been processed on the requested date. Specifically, OPUC recommended that the rule require TDUs that have met the 95% success rate for 12 consecutive months, to keep continuous records past the initial 12-month period, and to report to the commission and OPUC upon request.

The commission agrees with OPUC that TDU's should be required to meet the performance standards in the rule on an ongoing basis. The commission finds that requiring TDUs to file monthly performance reports with the commission for 12 months is an appropriate length of time. In addition, the commission finds that OPUC's recommendation that TDUs provide a report to the commission only upon request after the initial 12 months is beneficial to the market, but fair to TDUs because the monthly reporting requirement would still expire after 12 months.

The commission does not agree that the rule should require TDUs to file the reports with OPUC upon request. OPUC may access these reports in the same manner as all other reports filed with the commission. If the commission requests that a TDU file a report after the 12-month reporting period has expired, OPUC may obtain a copy at that time as well.

These new sections are adopted under the Public Utility Regulatory Act, Texas Utilities Code Annotated §14.002 (Vernon 1998, Supplement 2003) (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 PURA §39.101, which grants the commission authority to establish various, specific protections for retail customers; PURA §39.102, which provides for retail customer choice; and PURA chapter 17, subchapters A, C and D, which deal, respectively, with general provisions relating to customer protection policy, the retail customer's right to choice, and protection of the retail customer against unauthorized charges.

Cross Reference to Statutes: PURA §§14.002, 39.101, 39.102, and PURA chapter 17, subchapters A, C, and D.

§25.487.Obligations Related to Move-In Transactions.

(a) Applicability. This section applies to all retail electric providers (REPs).

(b) Definition. For this section, the term "safety-net process" means a process developed and implemented by the market participants in the Texas retail electric market in 2002 to ensure that a customer who moves into a premise receives electric service in a timely manner. The safety-net process should be used for legitimate purposes and not to bypass standard rules and processes.

(c) Standard move-in request. A REP shall submit a move-in transaction to the registration agent electronically, in accordance with applicable protocols and guidelines of the independent organization to establish service for a new customer.

(d) Safety-net move-in request. In the event a REP does not receive a confirmation that the transmission and distribution utility (TDU) has received the appropriate move- in request transaction from the Electric Reliability Council of Texas (ERCOT), and does not receive a valid move-in rejection, the REP shall submit the move-in request using the safety-net process by noon on the business day prior to the customer's move-in date.

(1) In submitting a move-in request using the safety-net process, the REP establishes its right to serve the customer at the premise identified by the electric service identifier (ESI ID) from the date the TDU executes the move-in by connecting service to the premise. The date the TDU executes the move-in by connecting service to the premise is the effective date for all wires charges and fees associated with that ESI ID. This date will also be the effective date for the move-in when the applicable move-in electronic transactions are processed. The TDU may bill monthly wires charges and fees to the REP commencing with the effective date, but may not issue wires charges and fees or consumption records until the REP submits the electronic transaction.

(2) The REP shall ensure that the standard electronic move-in transaction is submitted to ERCOT in accordance with applicable protocols on or before the fifth business day after submitting the move-in through the safety net process, even if the physical move-in has already taken place as a result of being submitted through the safety net process. The REP, ERCOT, and the TDU shall work to ensure that the appropriate premise information and enrollment response transaction is sent to and received by the new REP and that the appropriate drop (due to switch request) transaction is sent to the losing REP of record as shown in ERCOT's systems.

(e) Sunset provision for review of safety-net process. By March 1, 2004, the commission shall, after input provided by market participants, review the safety- net process and determine whether it should be continued.

§25.488.Procedures for a Premise with No Service Agreement.

(a) Applicability. This section applies to all retail electric providers (REPs).

(b) Service to premise with no service agreement. If a REP finds that a current occupant at a premise for which the provider is shown as the REP of record in the ERCOT or TDU system is not the customer with whom the REP currently has a service agreement for retail electric service:

(1) the REP may establish service with the occupant. The REP shall obtain verification of the occupant's authorization to establish service with the REP consistent with the requirements of §25.474 of this title (relating to Selection or Change of Retail Electric Provider); or

(2) the non-affiliated REP may issue a termination notice and the affiliated REP may issue a disconnection notice to the current occupant. The notice shall contain the following:

(A) The date the termination (or disconnection) will occur, provided that the date shall not be sooner than ten days from the date the notice is issued;

(B) For notices issued by a non-affiliated REP to a residential or small non-residential customer, as those terms are defined in §25.43 of this title (relating to Provider of Last Resort (POLR)), that the customer's service shall be transferred to the affiliated REP if the customer does not respond within ten days after issuance of the notice;

(C) For notices issued by the affiliated REP to residential and small non- residential customers, as those terms are defined in §25.43 of this title, that the customer's service shall be disconnected if the customer does not respond within ten days after the issuance of the notice;

(D) For notices issued to large non-residential customers, as that term is defined in §25.43 of this title, that the customer's service shall be transferred to the provider of last resort if the customer does not respond within ten days after the issuance of the notice;

(E) What actions the customer must take if that customer believes the notice is in error or desires to establish service with the REP; and

(F) A statement that informs the customer of the right to obtain service from another licensed REP and that information about other REPs can be obtained from the commission.

(c) Termination of service to residential and small non-residential customer by non- affiliated REPs. If a non-affiliated REP terminates service to an occupant in accordance with this section, the REP shall transfer that occupant to the affiliated REP using the procedures established by the independent organization in order to effectuate the termination of contract provision in §25.482(b) of this title (relating to Termination of Contract).

(d) Disconnection of residential and small non-residential customer by affiliated REP. If an affiliated REP disconnects service with the occupant, it shall comply with the requirements of §25.483 of this title (relating to Disconnection of Service).

(e) Termination of service to a large non-residential customer. If a REP terminates electric service to a large non-residential occupant in accordance with this section, the REP shall transfer that occupant to the provider of last resort.

(f) Prohibition on using move-out transactions. A REP may not submit a move-out transaction, as defined by ERCOT protocols, to effectuate the transfers under this section.

§25.489.Treatment of Premises with No Retail Electric Provider of Record.

(a) Applicability. This section applies to all transmission and distribution utilities (TDUs) and retail electric providers (REPs) in areas open to retail customer choice.

(b) Definition. For this section, the term "no REP of record" means a premise that is receiving electricity equal to or greater than 150 kilowatt-hours (kWh) in a single meter reading cycle, but for which no REP is designated as serving the premise in the TDU's system.

(c) Obligation of TDUs to identify premises with no REP of record. Each TDU shall implement the following procedures to identify those premises that have no REP of record:

(1) Each TDU shall prepare a No REP of Record List on a monthly basis, identifying all premises with consumption equal to or greater than 150 kilowatt hours (kWh) in a single meter reading cycle, but no REP of record in the TDU's Customer Information System;

(2) Each TDU shall delete a premise from the list if there is evidence of erroneous meter reads for the premise;

(3) Each TDU shall cross reference the list with ERCOT's pending orders to identify any move-in transactions that indicate that a REP is initiating service at a premise on the list and remove such premises from the list;

(4) Each TDU shall review safety-net move-in requests to initiate service and remove such premises from the list; and

(5) Each TDU shall review its internal systems for pending transactions and any correspondence from REPs claiming that a premise should be assigned to the REP. Any corresponding matches of premises shall be removed from the list.

(d) Submission of No REP of Record List to REPs.

(1) Each TDU shall send the No REP of Record List to all REPs offering service in its service area each month;

(2) Within five business days after the TDU sends the list, a REP shall inform the TDU in writing if it has a contract with a customer for a location on the list. The TDU shall delete all claimed premises from the list.

(3) Nothing in this section is meant to absolve a REP of its responsibilities under §25.474 of this title (relating to Selection or Change of Retail Electric Provider).

(e) Customer notification. TDUs shall provide notice to all remaining premises in a standardized bilingual (English and Spanish) format consistent with subsection (g) of this section. TDUs may either provide notice by placing door hangers at each premise or by mailing notice to each premise.

(f) Wires charges billed to customer with no REP of record. A premise with no REP of record shall not constitute unauthorized use of service under the TDU's tariff for retail delivery service approved pursuant to §25.214 of this title (relating to Terms and Conditions of Retail Delivery Service Provided by Investor Owned Transmission and Distribution Utilities).

(g) Format of notice. The notice provided by the TDU to a customer on the final list of accounts with no REP of record shall have the identifying code #999 printed in bold letters to enable the REPs to identify customers contacting them as premises on the No REP of Record List and shall comply with the content requirements of this subsection.

(1) The notice shall include the following information and be formatted as follows:

Figure: 16 TAC §25.489(g)(1) (.pdf format)

(2) A comprehensive list of REPs serving residential customers in the TDU's territory, including each REP's toll-free number and website address (if available), shall be listed on the notice provided to residential premises. A comprehensive list of REPs serving commercial customers in the TDU's territory, including each company's toll-free number and website address (if available), shall be listed on the notice provided to commercial premises.

(h) REP obligation to submit move-in transaction. A REP that enrolls a premise in response to the TDU notice shall submit a move-in transaction, not a switch transaction, to the registration agent in accordance with the requirements of §25.487 of this title (relating to Obligations Related to Move-In Transactions).

(i) Disconnection of premise with no REP of record. Each TDU may disconnect a premise with no REP of record no earlier than ten days after the customer receives the TDU's notification required by this section. Prior to disconnecting the service for a premise with no REP of record, each TDU shall repeat the procedures listed in subsection (c) of this section (other than issuing notice) to prevent the disconnection of a customer who has initiated service with a REP. A TDU shall not disconnect any premise that has been claimed by a REP in accordance with this section.

(j) Expedited reconnection of premise. If a TDU disconnects a premise in error, the TDU shall reconnect a premise on an expedited basis in accordance with its tariff and commission rules, whichever process is shorter.

§25.490.Moratorium on Disconnection on Move-Out.

(a) Applicability. This section applies to all transmission and distribution utilities (TDUs) with respect to residential customers.

(b) Moratorium on disconnection on move-out. A TDU shall not disconnect a residential premise after receiving a move-out transaction unless the requirements of subsection (d) of this section have been met.

(c) Reporting requirement.

(1) A TDU shall report monthly to the commission its success rate in processing standard electronic move-in requests for residential customers. The success rate shall be measured based on whether the meter read and energizing of the premise is accomplished on the scheduled date. The report shall omit backdated move-in requests.

(2) A TDU shall also report to the commission its success rate in processing requests for reconnection of electric service. The success rate shall be measured based on whether the re-energizing of the premise is accomplished on the scheduled date.

(3) The reports shall be filed with the commission on or before the 15th day of the month following the last day of the reporting month.

(d) Relaxation of moratorium on disconnection. Upon approval from commission staff, a TDU may disconnect residential premises after receiving a move-out transaction, as defined in the ERCOT protocols. To achieve approval, the TDU must demonstrate through reports filed in accordance with subsection (c) of this section that it has for three consecutive months or more processed 95% or greater of all move-ins and requests for reconnection of electric service no later than the scheduled date. If a TDU's success rate falls below 95% for two consecutive months or below 90% in any one month, the TDU shall immediately notify commission staff in writing, and commission approval shall be automatically revoked.

(e) Elimination of reporting requirement. Once a TDU demonstrates a 95% success rate in completing reconnections and move-ins on the scheduled date for 12 consecutive months, it shall no longer be required to submit monthly reports, as required by subsection (c) of this section. However, upon request by the commission, a TDU shall file a report on its current success rate.

(f) Notice of moratorium status. The TDU shall notify each REP in its service territory each time it changes its status, pursuant to subsection (d) of this section, concerning the moratorium on move-out disconnections. The TDU shall not disconnect any residential premise prior to completion of this notice.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on July 15, 2003.

TRD-200304273

Rhonda G. Dempsey

Rules Coordinator

Public Utility Commission of Texas

Effective date: August 4, 2003

Proposal publication date: March 21, 2003

For further information, please call: (512) 936-7223