TITLE 16.ECONOMIC REGULATION

Part 2. PUBLIC UTILITY COMMISSION OF TEXAS

Chapter 25. SUBSTANTIVE RULES APPLICABLE TO ELECTRIC SERVICE PROVIDERS

The Public Utility Commission of Texas (commission) adopts an amendment to §25.263, relating to True-Up Proceeding, with changes to the text as published in the January 27, 2006 Texas Register (31 TexReg 453). The adopted amendment establishes a new method for calculating carrying costs (interest) on true-up balances that a transmission and distribution utility is permitted to recover through rates but has not securitized. The adopted amendment results in a lower interest rate for unsecuritized true-up balances. This adopted rule is a competition rule subject to judicial review as specified in PURA §39.001(e). Project Number 32008 is assigned to this proceeding.

The commission received written comments and/or reply comments on the proposed new section from American Electric Power Company (AEP); CenterPoint Energy Houston Electric, LLC (CNP); Office of Public Utility Counsel (OPC); Texas Industrial Energy Consumers (TIEC); Texas-New Mexico Power Company (TNMP); and Texas Coalition of Cities for Utility Issues and Cities Served by Texas-New Mexico Power Company (collectively "Cities").

A public hearing on this rule was held at the commission's offices on March 1, 2006.

Comments and Reply Comments

Appropriate Interest Rate

AEP, CNP, and TNMP all commented that the utility's debt rate is inappropriate for carrying costs on unsecuritized true-up balances because it does not reflect how utilities finance their assets. AEP opined that a cost-of-debt rate is inappropriate because long-term assets are not financed on an asset-by-asset basis and thus the risk measure of any given long-term asset cannot be isolated. AEP further argued that applying the cost of debt to true-up balances would distort the return measure for other long-term assets. TNMP noted that ratepayers would be paying interest to the utilities on money owed to the utilities at a lower rate than the rate at which the utilities would have financed the money and that transmission and distribution utilities (TDUs) have to finance unsecuritized balances occurring as a result of retail electric provider (REP) defaults with debt and equity. CNP commented that the amendment makes no provision for the equity component of the utilities' capital structures.

TIEC asserted in its comments that the cost of debt more accurately reflects the risk borne by the utility associated with the recovery of the unsecuritized true-up balance. It added that REP risk is irrelevant because ratepayers pay for REP defaults.

AEP replied that the competition transition charge (CTC) amounts are subject to the risks inherent in the utility enterprise and that it would be difficult to assign higher-cost financing to the assets whose greater risk offsets lower-risk assets. CNP replied to TIEC that assessing the risk of collecting the unsecuritized balance is not the correct analysis for determining carrying costs; rather, the proper question is what costs the utility will incur while waiting for collection of the unsecuritized balance. CNP argued that until the company receives the funds from ratepayers, it will have to go to the debt and equity markets to raise capital. Additionally, CNP asserted, there is material cash-flow uncertainty associated with CTC payments because such payments are tied to billing determinants, and lower energy consumption or REP defaults could lead to collections shortfalls for the TDU. CNP further contended that, to the extend such shortfalls exist and are not addressed until the CTC true-up mechanism is activated, the TDU would have to obtain capital in the meantime at the cost of its weighted-average cost of capital (WACC). TNMP replied to TIEC that the realities of utility financing clearly demonstrate that limiting the CTC carrying charge to only the cost of debt fails to accommodate the fact that utilities must raise capital from both debt and equity.

OPC replied to the companies' positions by noting that if the commission so desired, every utility asset could be isolated and a specific risk level and return could be assigned to each asset. The application of an overall weighted cost of capital to a utility's rate base does not imply that each utility asset is of equal risk. More important, there is good justification for assigning a separate risk measure to the CTC true-up balances. OPC noted that, by statute, the CTC is nonbypassable for all classes of ratepayers and the risk of non-recovery is therefore minimal, and there is no other utility cost-of-service item that has been specifically identified as nonbypassable in PURA. Additionally, commission precedent in Docket No. 30706 (CNP's CTC case) provides additional assurances that every penny of the CTC will be recovered from ratepayers through operation of the true-up mechanisms in the CTC tariffs. OPC further maintained in its reply comments that investor return requirements are determined by the risk level associated with the asset to be financed, and that, in OPC's assessment, CTC assets are fundamentally no riskier than the securitized assets.

Cities stated in reply comments that the utilities fail to acknowledge the fact that the method specified under the Public Utility Regulatory Act (PURA) and commission rules for recovery of final true-up balances is far different from the normal process for recovery of investments under traditional ratemaking. Under the latter, significant regulatory lag exists between the time that investments are made and the time that recovery of and on those investments occurs through base rates. Moreover, recovery of investments through base rates is not guaranteed. While utilities are provided the opportunity to earn a reasonable return on their investments under the traditional regulatory process, there is no true-up mechanism or other guarantee of recovery such as that which applies to the recovery of true-up balances. Additionally, the final true-up balances are recovered over a much shorter period ( e.g. , 14 years) than investments under the traditional base ratemaking process (up to 40 years). Cities further opined that the recovery of true-up balances is much more similar to the recovery process for reconcilable fuel than to the ratemaking process for base rates that has applied under traditional regulation, and Cities noted that the commission has historically applied a short-term interest rate that typically has been lower than the utility cost of debt for calculating interest on fuel balances. Cities further averred that no evidence exists to support the claim by utilities that REP insolvency warrants a higher rate of return for the CTC balance, and that CTC charges to date have represented a relatively small percentage of nonbypassable charges. Cities pointed out that such charges are simply included in the cost of retail energy billed by the REP and collected from end-use customers. Cities also stated that the use of a debt-based rate simply reflects the diminished risk of recovery of true-up costs when compared to traditional regulated investments, which do not enjoy the guaranteed recovery or true-up provisions that are applied to the true-up balances.

TIEC stated in its replies that the true-up assets are unique and need not be supported with a traditional capital structure, and that the high degree of certainty associated with the collection of these assets clearly indicates that they should be financed with debt. TIEC pointed out that the revenues to amortize the unsecuritized true-up assets will be: (1) tracked separately from other revenues; (2) subject to increase or decrease if actual collections fall outside of a 15% band in any given year; and (3) subject to a final-year true-up to ensure no under-collection during the amortization period. Moreover, TIEC pointed out, the CTC charges are nonbypassable. TIEC argued that each of these characteristics is designed to eliminate risk, making the unsecuritized true-up amounts a highly unique asset that need not be treated like the typical utility asset. Because of these unique characteristics of the true-up assets, TIEC opined that the utilities' claim that it is inequitable to lower the carrying cost to a cost of debt is unsound. It must therefore be recognized, TIEC averred, that the commission's careful attention to developing a rate design in order to reduce risk must have some effect (TIEC's emphasis). Yet, TIEC observed, the utilities would ignore all of that and pretend that these assets must be financed in a traditional manner. TIEC also noted that the utilities' arguments that regulatory risk such as the disallowance of requested stranded-cost amounts justifies a high interest rate are far-fetched, because if this type of regulatory risk necessitates a high interest rate, then utilities could simply manufacture such regulatory risk by requesting amounts far in excess of anything that is reasonable. For example, if the commission were to reduce the amount of an award to a just and reasonable level, the utility could claim this treatment as an example of regulatory risk, when in fact the commission was simply applying its discretion to establish just and reasonable rates.

Risk of Collection

TNMP and CNP commented that a TDU must serve all certified REPs under the standard tariff, and that there is no assurance of collection, and TDUs have limited ability to manage their risks of non-collection. TNMP further stated that the end-use consumer's obligation to pay the nonbypassable CTC amount to a REP provides no guarantee that TNMP will recover its charges. TNMP cited recent financial difficulties facing various REPs and argued that the failure of these entities points to an increase in the risks associated with recovering unsecuritized balances. AEP similarly opined that REPs today may be less creditworthy than they were at the various times the commission decided in the past to use the unbundled cost of service (UCOS) WACC for unsecuritized balances, and observed that in the last year alone, at least six REPs in the CNP service area have exited the retail market or are in the process of leaving the market because of financial troubles. CNP expressed its belief that it has more risk in recovering the CTC balance than ratepayers have in recovering the accumulated deferred income taxes (ADFIT) benefit.

TIEC argued that utilities have negligible collection risk associated with recovering the CTC balance because ratepayers will always be available to pay the amounts the utility is owed and, accordingly, there is no material cash-flow uncertainty associated with CTC payments that ratepayers make to the utility. TIEC reiterated that the commission has taken additional steps in its final order addressing CTC design in the one contested case (the CenterPoint case) that it has considered thus far--that is, CenterPoint's CTC final order provides that, in the event of over- or under-recovery equal to or greater than 15%, CenterPoint or the commission staff may initiate a proceeding to adjust the CTC rate to reduce or eliminate the over- or under-recovery; further, the commission authorized a true-up in the final year of the CTC collection to ensure that the utility collects the full amount that the commission has approved. TIEC noted that although collection risk has been virtually eliminated through these commission-approved mechanisms, a carrying cost based on the cost of debt nevertheless reflects whatever small risk may still attach to CTC recovery from ratepayers.

CNP stated in its replies that TIEC's belief that the WACC constitutes an unreasonable burden on ratepayers rings hollow because TIEC has argued in the past that the commission could not allow securitization of non-stranded-cost true-up balances, meaning that such amount had to be recovered in a CTC. CNP suggested that if TIEC truly believed that paying the WACC was an unreasonable burden, it and other intervenors would have agreed to securitize the entire true-up balance, regardless of their views on whether the commission had the power to impose securitization on them.

AEP reiterated in its replies its position that realization of the CTC amounts is subject to the risks inherent in the utility enterprise, and that the long-term cost of capital for those risks is the utility's weighted-average cost of capital. AEP expressed its belief that if the risks for some assets were lower than those of the enterprise in general, assigning lower-cost financing to those assets would require assigning high-cost financing to others if the overall cost of capital is to be properly reflected. AEP asserted that this would be a difficult and complicated way to set rates.

TIEC restated in its replies the point that true-up rates are nonbypassable, and that even if a REP goes bankrupt, ratepayers are the ones who are still on the hook. TIEC held that ratepayers are always there to pay the bill, even in the event of a REP default on nonbypassable payment, and so the utility will still collect its money from ratepayers. TIEC noted that CNP's Tariff for Delivery Service acknowledges this fact and expressly notes that there may be periodic adjustments to the CTC. TIEC rejected CNP's claim that TDUs have no assurance of collecting CTCs, because they are guaranteed--by virtue of a final year true-up--to collect every dollar they are awarded.

CNP and TNMP commented generally that the rule change is unnecessary because the commission has already decided the issue, and further pointed out that on at least six prior occasions, the commission decided to use the utility's WACC from the UCOS case. CNP argued that the risk of recovering the unsecuritized balances is no different today that it was for the six times the commission decided that the UCOS WACC was a fair rate of return. CNP also opined that utility investors rely on the commission to foster a fair and consistent regulatory policy, and that the commission has done so to date with regard to the rate for true-up balances. Cities replied to CNP's comments by noting that investor reports have opined that the greatest financial risk faced by CNP is the pending rate investigation, and Cities further noted that the impact of the true-up interest rule change would be approximately 5 cents per share. Cities additionally pointed out that CNP has already been allowed to recover more than $257 million in interest on true-up balances through August 2004. TIEC replied to CNP that the Wall Street community expects the commission to act rationally and reasonably, and that there is no expectation that an unjustified rate would continue in perpetuity. TIEC stated that it is unlikely that the decremental revenue associated with a reduction to the interest rate applicable to unsecuritized balances would be material to large companies, and TIEC further noted that the daily closing prices of CNP and AEP reveal that their stock prices have suffered no harm as a result of this rulemaking. TIEC pointed out that, in fact, in the days following the commission's entry of a final order reducing AEP Central's total true-up request by almost a billion dollars, AEP's stock price actually increased, and it is therefore unrealistic to assume that any amendment to the carrying cost on the unsecuritized balances would have a material impact on these utilities' stock prices.

Intention of Original Rule

TIEC commented, and OPC agreed, that the drafters of the original rule did not contemplate that the rate that was prescribed therein would be used for an extended period of time. AEP commented that there is no harm in the rate being used for an extended period of time because the original rate is based on sound financial theory.

CNP replied to TIEC and OPC that the commission has previously rejected the contention that the UCOS rate was intended to apply for only a short period of time, and that the commission stated in its order in Docket No. 30706 that no conclusion could be drawn that the interest rate stated in the rule was linked to a form and timing of recovery that was not required by the rule and that was within the utility's discretion to choose. CNP additionally responded that because the commission has found that the time period and the rate are unrelated, the staff testimony cited by TIEC cannot support an amendment of the rule.

While AEP commented that the rule is the product of a reasoned, deliberative process to which affected parties had input, TIEC replied that such claims are disingenuous because the existing rule resulted from a contemplated circumstance--a single overall true-up balance that would be securitized--that has now changed.

Taxes

OPC recommended that the rule have a provision for the rate to include the effect of income taxes. CNP noted that the proposed rule does not have an adjustment to gross-up any portion of the rate assumed to be related to equity, and that as a result, the current proposal is even more punitive to utilities than anything the staff and intervenors have offered in earlier proceedings.

Commission response

The commission agrees with the ratepayer groups--TIEC, OPC, and Cities--that the risk of not recovering the CTC is less than the average risk of all the utility's cash flows. This lower risk is primarily the result of the statutorily approved true-up process and the resulting ratepayer responsibility for the entirety of the CTC payment. The commission also agrees with the utilities--AEP, CNP, and TNMP--that a utility's assets are financed with a combination of debt and equity, the costs of which reflect the risk of the utility's entire enterprise, including assets with various risk levels, the risk associated with the collection of payments from REPs of varying financial condition, and the uncertainty about the future strength of the economy of the TDU's service area. Such factors reflect the combined risk of the enterprise and the fact that all of a utility's cash flows are dedicated to fulfilling all its financial obligations. These two basic positions advocated by the ratepayer groups and the companies are compatible and must both be addressed in answering the question of what interest rate is appropriate for the carrying cost of a utility's unsecuritized true-up balance.

With respect to the lower recovery risk of true-up balances, the commission has previously recognized this aspect of the collection of stranded costs in Docket No. 22344, Generic Issues Associated with Applications for Approval of Unbundled Cost of Service Rate Pursuant to PURA Section 39.201 and Public Utility Commission Subst. R. 25.344 . In that docket, which was conducted in conjunction with the UCOS cases, the commission stated in its Order No. 14 that:

The Commission also concludes that it is appropriate to recognize the reduction in risk resulting from both the guarantee of stranded cost recovery by the Legislature and the shortened recovery term compared with traditional regulation. The Commission has previously recognized that there are reductions in risk due to shortened recovery periods that should be reflected in a lowered rate of return for the utility.

The commission reached the same conclusion on page 18 of its order in Docket No. 22352, Application of Central Power and Light Company for Approval of Unbundled Cost of Service Rate Pursuant to PURA §39.201 and Public Utility Commission Substantive Rule §25.344.

Consistent with these concepts, the commission concludes that a three-step process is appropriate for the determination of the cost of capital of a utility with an unsecuritized true-up balance. All three steps require weighting: two on the basis of different types of capital in the capital structure, and the third on the basis of different types of a utility's recoverable assets.

The first step is to estimate the utility's cost of capital as if it did not have an unsecuritized true-up balance (this assumption is reasonable because a utility's authorized return on equity is typically based in large measure on an analysis of comparable companies that do not have CTC balances). This step requires that the different types of financial instruments in the utility's capital structure be appropriately weighted to calculate the rate of return. This step is typically and best accomplished as part of a rate case, although using the utility's currently allowed rate of return is acceptable.

The second step is to use the same formulaic approach described above for the first step to determine the cost of capital for the unsecuritized true-up balance. This second step applies a rate of return that is partly an actual debt rate and partly a marginal debt rate that is grossed up to reflect the impact of federal income taxes on the recovery of unsecuritized true-up amounts. Application of this approach in this instance recognizes that the risk of recovery of the unsecuritized true-up balance is less than the risk of recovery of the utility's transmission and distribution assets. It further recognizes that all the utility's assets, including the true-up balances, are financed with both debt and equity (albeit a lower-cost equity for the true-up balances). Finally, it recognizes that all of the utility's capital structure supports all the utility's assets and reflects the risks of not recovering sufficient revenue to cover the utility's costs. The weighting in this step is applied to the utility's marginal cost of debt (MC) and the historical cost of debt (HC), and it is to be done according to the formula set forth in greater detail below.

The third step is the final weighting. In this last step, the two costs of capital derived in the first two steps are blended. Each receives a weighting equal to its proportion of the utility's recoverable asset base. This step is the same approach that the commission employed in PUC Docket No. 14965, in which the cost of capital of Central Power and Light (CPL)--the predecessor of AEP Texas Central--was weighted to reflect two different assets with different risks. (See PUC Docket No. 14965, Second Order on Rehearing, Finding of Fact 113A.) One portion of CPL's recoverable asset amount--ECOM, the Excess Cost over Market value of CPL's generation assets--was determined to be less risky than the remaining non-ECOM portion of the utility's asset base. The commission found that both parts of CPL's rate base--the ECOM portion of approximately $800 million and the non-ECOM portion of approximately $2.1 billion--were financed with the same capital structure and the same debt, but the commission concluded that the equity costs of the two parts were different. In that docket, the commission assigned the less risky ECOM portion a cost of equity equal to the utility's historical cost of debt. Additionally, to reflect the equity portion and the associated tax expense of the capital structure associated with the ECOM rate base, the commission grossed-up that portion of the debt rate assumed to be equity.

The resulting cost of capital for CPL's ECOM balance, when blended on a weighted-average basis with the traditional WACC rate for the non-ECOM rate base, represented a composite risk assessment of the entirety of the utility's recoverable assets, and this composite rate was then applied to not only the lower-risk ECOM asset, but to the utility's non-ECOM rate base as well. In this way, the different risks associated with the ECOM assets and the non-ECOM assets were both reflected in the composite rate of return on a proportionate basis, and thus in the commission's determination of CPL's total revenue requirement.

In this rulemaking, the commission adopts the same conceptual approach and has amended the rule to provide for the application of the overall composite rate to both the CTC assets and the T&D assets. As previously noted, this approach takes into account the ratepayer groups' basic position that recovery of the CTC asset entails reduced risk as well as the utility companies' basic position that assets are financed with a combination of debt and equity, the blended costs of which reflect the risk of the utility's entire enterprise.

The commission therefore concludes that the correct rate at which a utility should accrue carrying costs on a stand-alone CTC or unsecuritized true-up balance is the weighted average of an adjusted form of its marginal cost of debt and its unadjusted historical cost of debt, with the weighting based on the utility's most recently authorized capital structure. The MC component is adjusted because it is used as a proxy for the cost of equity and must therefore be grossed-up to account for the effects of federal income taxes. MC will be based upon the average yield for long-term public utility bonds of the utility's credit rating published in Moody's Credit Perspectives or a similar publication during the most recent three months prior to the filing of the utility's application to update its carrying-charge rate. These calculations are summarized in the following formula:

CTC Carrying Charge Rate = MC * Equity Proportion of Most Recently Authorized Capital Structure * 1/(1-Tax Rate) + HC * Debt Proportion of Most Recently Authorized Capital Structure

The CTC Carrying Charge Rate as determined above will then be blended with the utility's authorized TDU WACC to develop a composite rate of return that shall be applied to the entirety of the utility's recoverable regulated assets. The composite rate shall be determined as follows:

Composite Pre-Tax Rate of Return = CTC Carrying Charge Rate * Unsecuritized True-up Balance / (Unsecuritized True-up Balance + TDU Rate Base) + TDU Authorized Pre-Tax WACC * TDU Rate Base / (Unsecuritized True-up Balance + TDU Rate Base)

This approach achieves a reasonable result because it: (1) uses data that are readily ascertainable; (2) reflects all the actual carrying costs that can be calculated or estimated with reasonable certainty; and (3) accommodates the conceptual arguments of both the ratepayer groups in part and the utilities in part. It is also consistent with commission precedent, paralleling the commission's decisions in Docket No. 14965. The rule as adopted incorporates this methodology to allow the commission to take into account in a utility's rate case the effects of the corresponding adjustment to the company's authorized rate of return that is applied to its TDU rate base.

Further, to account for situations in which a utility does not have a pending or near-future rate case in which the rule and the resulting composite rate can be applied to the entirety of the utility's recoverable assets (both the unsecuritized true-up balances as well as the TDU rate base), the commission provides for the CTC Carrying Charge Rate described above to be applied to a company's CTC balance on a stand-alone basis until its next rate proceeding. That is, until a utility has a rate proceeding in which the rate-of-return adjustments described above can be applied to all of the utility's assets that have been authorized for recovery, the rule specifies that the utility's unsecuritized true-up or CTC balance will earn interest at the lower CTC Carrying Charge Rate and the utility's T&D rate base will earn a return at the authorized cost of capital unadjusted for the lower-risk CTC balance. This approach is appropriate because the amount of revenues produced will be the same regardless of whether: (1) the composite rate of return, which is based on a weighted average of the CTC carrying charge rate and the unadjusted traditional WACC, is applied to the entirety of the utility's assets including both the unsecuritized true-up balance and the TDU rate base; or (2) the CTC Carrying Charge Rate is applied to the unsecuritized true-up balance separately while the TDU rate base earns a return based on the unadjusted traditional WACC. Paragraph (l) of the adopted rule sets forth these provisions.

The commission notes that, in a situation in which a utility has a negative CTC balance, the use of the composite blending approach results in the utility's composite rate of return being higher than the unadjusted T&D rate of return. This seemingly counterintuitive result is simply a mathematical consequence of the negative nature of the CTC balance and does not change the fact that, as previously described, the amount of revenues produced is the same under either of the two methods.

Legality of Changing the Interest Rate

TNMP argued that the proposed amendment violates Texas Law by altering the interest rate for recovery of unsecuritized balances previously approved by the commission. TNMP stated that revising the rate to be applied to its true-up balance would reopen the issues settled in the commission's final order in its true-up Docket No. 29206, and that while the commission is not prevented from amending its rules, such amendments can only apply to future orders. TNMP further asserted that the carrying charge rate permitted by the current version of Subst. R. §25.263(l)(3) is no different from the interest rate imposed on unpaid judgment balances. TNMP reiterated in its replies that in Docket No. 29206, the commission calculated the rate to be applied to the unsecuritized amounts to be recovered by TNMP, and that upon appeal to the district court, the commission lost jurisdiction to alter or reconsider the issues determined in that docket.

CNP contended that changing the rate would nullify the commission's rate decision on CenterPoint's competition transition charge proceeding, which is final and on appeal; CNP further asserted that well-settled Texas law prohibits an agency from reconsidering a final order. CNP argued that when a one-time order (such as in its CTC case) has been issued allowing recovery of a specific amount at a specific rate, that order cannot be superseded or nullified by a subsequent rulemaking. CNP opined that a CTC order is distinguishable from a typical utility rate order, which can be superseded at any time by a new rate order. CNP likened the CTC order to a final judgment in a civil case in which a static amount is recovered based upon events that happened solely in the past. CNP also argued that the proposed rule would reduce the rate on unsecuritized balances to nearly the rate paid on securitized amounts, thus effectively allowing ratepayers the benefits of securitization but denying the utilities of its corresponding benefits. CNP averred that such results would be contrary to legislative intent underlying the securitization statutes. CNP went on to state that the commission has said that a utility, not the commission or ratepayers, has the right to choose whether to securitize, but the amended rule would effectively force utilities to accept a securitized rate at a time of the commission's choosing, and that while the such true-up items as the capacity auction cannot be securitized, the amended rule would assign what is essentially a securitization rate to the utilities' capacity auction true-up balances.

TIEC commented that the rule does not violate prohibitions against retroactive laws because those prohibitions only apply if a vested right is impaired. TIEC opined that the commission's previous determinations of the interest rate on true-up balances was based on the rule that it is now considering changing and that the commission has authority to change its own rules. TIEC further stated that an entity that has obtained a prior final order based on a prior rule is expected to comply with the new rule if the commission changes the prior rule; the entity is not given a lifetime exclusion from the application of a new rule simply because it had a final order that referenced, or was guided by, a prior rule.

OPC stated in its replies that the unsecuritized true-up balances are now considered to be regulatory assets, and that the returns thereon are subject to change, either in rate cases or through other proceedings. OPC further replied that the true-up orders for CNP, TNMP, and AEP do not state that the unsecuritized carrying charges cannot be changed on a prospective basis in a future proceeding. OPC argued that the utilities' comparison of the CTC interest rate with the interest rate specified in a court judgment is false. Unlike the jurisdiction of a court in regard to a money judgment and interest thereon, the commission has continuing regulatory jurisdiction over the utility's collection of the CTC after the commission issues its order in a CTC case. OPC expressed its belief that the commission's application of Subst. R. §25.263(l)(3) does not preclude the commission from amending the rule for application on a prospective basis in view of current circumstances. To argue otherwise, OPC contended, would be to say that the commission has no regulatory authority over collection of the CTC once the commission issues its final order in a CTC case.

TIEC reiterated in its replies that utilities do not have a vested right in WACC-based carrying costs because the CTC rate is based on the commission's rule, which is itself within the discretion of the commission to revise. TIEC stated that although the utilities have a vested right to interest on stranded costs, they do not have a vested right in the specific method of determining the rate described in the original version of Subst. R. 25.263(l)(3). The utilities' right to interest is separate and apart from the actual interest rate.

Commission response

The commission concludes that it has authority to change the interest rate on the CTC balance. In reference to their final true-up and CTC orders, several utility commenters argued that the commission cannot amend or reconsider an order that is final. This proceeding, however, is a rulemaking and does not constitute a reconsideration or amendment of any prior contested case orders of the commission. Moreover, the CTC is a "rate," as that term is used in PURA. PURA authorizes the commission to change rates on a prospective basis.

Utility commenters argued that they have a vested property interest in the continuation of the use of the UCOS WACC. The commission disagrees that the rule creates a vested property interest. Under Texas law, a right cannot be considered a vested property right unless it is something more than a mere expectation based upon an anticipated continuance of present laws. PURA provides specifically for making changes to the CTC. Therefore, no person may have a reasonable expectation in the continuance of any specific CTC amount. Moreover, PURA specifically provides that transition charges, in contrast to CTCs, do become vested property rights in the hands of the utility's assignees. If the legislature had intended to create property interests in CTCs, it would have done so.

Retroactive Ratemaking

AEP argued that it is improper to retroactively change the carrying cost for certain unsecuritized amounts back to January 1, 2002, and that while the commission has the authority, under appropriate circumstances, to make a prospective change to the carrying cost rate in the rule, it may not make such a change effective retroactively. Consequently, AEP opined, any change in the carrying cost rate may only be effective prospectively from the date the rule amendment is effective. TNMP commented that any changes to the rule should expressly provide that the new interest rate does not apply to interested accrued between January 1, 2002, and the effective date of the new amendment.

Cities responded that there are no commission final orders that establish the interest rate on the unsecuritized portion of the final true-up balances for those utilities beyond the final order dates in their respective true-up proceeding. Cities also maintained that there would be no retroactive ratemaking concerns because the commission has recognized that true-up adjustments may be necessary to ensure no over- or under-recovery of the CTCs, and that because the proposed rule reflects a change in the period over which the interest rate on the unsecuritized true-up balance would apply, the rule is no more of an improper retroactive adjustment than is the utilities' proposal to allow ongoing future adjustment to their proposed WACC-based carrying charge rates.

AEP stated in its replies that subsection (l)(3)(B) of the proposed rule, which modifies the carrying cost rate used to accrue interest since January 1, 2002, applies to TDUs for which the commission has not entered a true-up proceeding final order. AEP stated that all utilities now have a true-up final order and therefore subsection (l)(3)(B) no longer applies to anyone and should be removed. AEP further contended that even if some parties were to interpret the phrase "true-up proceeding final order" to mean a final and appealable order under the Administrative Procedures Act, that status has now been reached for all companies, including AEP Texas Central in Docket No. 31056. Cities expressed in reply comments the position that for utilities that have final and appealable true-up case orders as of the effective date of this rule, the appropriate effective date of carrying charge rates should be from the date covered by the commission's final order, not from 30 days after the effective date of the rule.

Commission response

Subsection (l)(3)(B) of the proposed rule was intended to address situations in which a utility did not yet have a commission final order. The final orders for all the true-up cases for utilities that have introduced customer choice in their service area are now final and appealable; hence, subsection (l)(3)(b) is no longer applicable to the TDUs that were created from the reorganization of these utilities. Consequently, the commission has deleted proposed subsection (l)(3)(b) from the final rule. Subsequent to the effective date of the rule, changes to the interest rates on utilities' unsecuritized balances will be applied on a prospective basis.

Consistency

AEP stated that using the cost of debt for unsecuritized true-up balances is inconsistent with pertinent statutory provisions, judicial decisions, and commission determinations in every true-up case. AEP also argued--and reiterated in its reply comments--that any rule change should treat similarly situated utilities consistently, and that the WACC rate should apply to the balance of securitizable stranded costs and regulatory assets until such balances are securitized, even if a change is made to the unsecuritizable true-up balances. AEP expressed its belief--and CNP concurred--that the provisions of PURA, which state that the purpose of securitization is to "lower the carrying costs of the assets relative to the costs that would be incurred using conventional financing methods " (AEP's emphasis), confirms the Legislature's understanding that the concept of conventional utility financing means that, absent securitization, utilities would finance their assets through a balanced capital structure consisting of debt and equity.

TIEC asserted that AEP should not be allowed to accrue interest on unsecuritized balances at its WACC rate because it could have filed its true up case earlier as did the other utilities. TIEC stated that Texas ratepayers suffered great harm because of AEP's delay in filing AEP Central's true-up proceeding while accruing interest on the true-up balance at the WACC rate.

TIEC also replied that there should be no connection between what is an appropriate interest rate and the determination of whether securitization makes sense. TIEC argued that the appropriate interest rate should be determined based on the characteristics of the asset to be financed, and that the utilities can point to no legislative history indicating that the legislature intended for assets to be carried at an artificially high interest rate in order to justify securitization.

Commission response

The commission concludes that a significant statutory element of the transition to competition was the opportunity for stranded-cost securitization, which allows for the use of advantageous financing terms in the recovery of stranded-cost balances. The statute's reference to "conventional financing methods" suggests that a conventional rate is appropriate as the benchmark comparison to securitization financing methods. As the commission has noted above, however, a utility's composite financing cost is based on the entirety of its recoverable assets and the relative risks of those assets, including the financing costs of assets having lower risk as well as those having higher risk. This is true even if a utility does not have a lower-risk CTC asset.

The commission's earlier determination of the composite cost of capital for the entirety of a CTC balance and TDU rate base is an application of the same financial concept. It is a reflection of the fundamental financial principle that when the composition of a company's asset base changes, the overall risk borne by investors of recovering all their investments in all the utility's assets correspondingly changes. Accordingly, even if a portion of a utility's asset base--such as the unsecuritized true-up balance--accrues interest at a lower rate, when the securitization rate is compared to the overall composite cost of all financing, as described above in the discussion concerning the blended costs of lower- and higher-risk assets, the assumed financing advantages of securitization as contemplated by the statute remain clearly evident.

Additionally, it is not a reasonable outcome of PURA that significant amounts of true-up balances earn a traditional pre-tax WACC return for up to 15 years (or perhaps even longer), as would be true if a utility chose to not securitize its stranded costs under the rule prior to this amendment. The amounts under consideration are substantial: even if all eligible stranded costs are securitized, other unsecuritizable true-up balances in excess of $1 billion have been authorized by the commission. Given that PURA expressly provides for nonbypassable recovery of these amounts, for interest to accrue on nonbypassable balances of such magnitude at the traditional pre-tax WACC rate for up to 15 years or more is unreasonable. The commission therefore retains in the rule the application of the modified interest rate to all unsecuritized true-up balances.

Effect of Interest Rate Change on ADFIT Benefit

CNP contended that the calculation of the ADFIT benefits at its UCOS WACC rate of 11.075% indicates that the unsecuritized true-up balances should not be carried at the cost of debt. CNP argued that it would be arbitrary and capricious to recalculate carrying charges on a utility's CTC balance without also recalculating the utility ADFIT benefit using the same rate. In any case, CNP argued, there is zero cash-flow uncertainty associated with the ADFIT payments owed by CNP to ratepayer because ratepayers' CTC obligations were greater than CNP's ADFIT obligation, and therefore ratepayers could offset any ADFIT payment deficit against their own obligations to CNP. CNP added that the rule would benefit ratepayers by using a rate that is close to what they would enjoy with securitization, but the utility doesn't get the benefit of up-front bond proceeds.

Cities responded that the present value of the ADFIT benefit was determined based on the facts that existed in specific cases, and that based on those facts, final stranded cost claims were calculated. The proposed rule simply takes these final stranded-cost amounts and addresses the issue of the appropriate carrying charge to apply thereto, and it is not necessary or appropriate to again review the amount of the final approved true-up balances. Cities averred that the utilities' proposal to do just that by adjusting the approved ADFIT benefit is improper and should not be allowed unless the commission is willing to review and adjust the recoverable true-up balances for other changed circumstances impacting the magnitude of the true-up balances and their ultimate recovery. OPC similarly stated that the proposed rule amendment has no effect on the ADFIT benefit calculation.

TIEC responded that there is no connection at all between the interest rate on unsecuritized balances and ADFIT, and that the utilities enjoyed hundreds of millions of dollars of non-cash earnings stemming from applying an interest rate based on the weighted average cost of capital retroactively to January 1, 2002. TIEC replied that CNP's arguments concerning the ADFIT benefit are unpersuasive for three reasons: First, they are separate calculations--the calculation of the ADFIT benefit recognizes that the ADFIT balance is available to the utilities to be used for corporate purposes, thus displacing the need for the utility to raise capital in the capital markets at the WACC rate; recovery of the unsecuritized true-up assets, on the other hand, results in a stream of revenue that, because of sufficient certainty, can be financed solely with corporate debt. Second, the ADFIT benefit was calculated using an interest rate taken at a moment in time, and it would be inappropriate to revisit that calculation without revisiting the carrying costs of every other asset approved for recovery in the true-up proceedings, including the interest rate on stranded costs going back to January 1, 2002. Third, the carrying cost applicable to the true-up balances is governed by a commission rule that is subject to change in the future, whereas the ADFIT benefit calculation is not the subject of a rule, but rather is the subject of an order that has now become final. TIEC and Cities stated in their replies that the utilities have earned WACC interest on stranded costs of literally hundreds of millions of dollars for over four years, and by contrast, using a WACC discount rate to calculate the ADFIT benefit results in an incremental ADFIT benefit that is paltry in comparison to the benefits enjoyed by the utilities by virtue of the application of the WACC interest rate from a date of January 1, 2002.

Commission response

The commission agrees with the ratepayer groups' position that no change should be made to the present-value amount of the ADFIT benefit. Like the quantification of the market value of the generation assets to which the ADFIT balances are related, the present-value quantification of the ADFIT benefits was based upon variables and assumptions that existed at a specific point in time. The market values of the generation assets were based upon expectations regarding a variety of factors including commodity prices, economic conditions, and--like the present-value quantification of the ADFIT benefits--future interest rates. Although all these factors are subject to constant change, the commission authorized a recoverable amount of stranded costs--as well as the related offsetting present-value amount of the ADFIT benefit--based on the particular conditions that existed at the time of market valuation. Once these amounts--both the stranded-cost balance for a utility and the related present-value ADFIT benefit--were determined, they become part of the commission's final order and are now no longer subject to re-quantification.

Moreover, unlike unsecuritized true-up balances, an ADFIT benefit is not part of the asset base in which investors invest. This is affirmed by the fact that, in a traditional rate proceeding, the ADFIT benefit is the result of the utility using the ADFIT balance, which is temporary cost-free capital provided by the government, to reduce the utility's return-earning rate base, and the company's use of the ADFIT balance in this manner neither detracts from nor adds to the rate of return achieved by traditional investors. Rather, in a traditional rate case, the purpose of reducing the return-earning rate base by the ADFIT balance is simply to flow through to customers the benefits of the cost-free capital--and this was exactly the same objective achieved in the true-up cases, with the valuation of the benefits consistent with the terms and timing existing at the point of stranded-cost determination. Accordingly, the commission makes no changes to the rule to re-quantify the amount of ADFIT benefits.

Updating the Rule

AEP, CNP, and TNMP commented that, if the rule is going to be amended at all, the commission should only change the rule so that it authorizes recovery of the unsecuritized true-up balance using a utility's most recent pre-tax WACC as authorized in a rate case. AEP acknowledged that a company's WACC can change over time (as evidenced by the change from the 11.795% WACC rate authorized in its UCOS case to the 9.56% rate in its last rate proceeding, Docket No. 28840), but AEP further stated that if the commissioners believe a current rate should be used, the amended rule should allow for subsequent updates as capital costs change in the future. TIEC agreed, stating that the proposed rule should provide a flexible interest rate that is designed to reflect currently existing market conditions.

AEP reiterated in its reply comments that it does not oppose a flexible rate that can reflect more current market conditions through adjusting the pre-tax weighed average cost of capital to that approved in a base-rate proceeding. CNP noted in its reply comments that it is not necessary to adopt a debt rate to achieve flexibility, and that TIEC implicitly acknowledged this fact in CNP's CTC docket when TIEC recommended that the rate for calculating carrying charges on the CTC balance should be changed whenever TDU rates change.

TIEC observed that although each of the utilities claims that the true-up rule cannot be changed without impermissibly modifying a commission final order, they nevertheless propose an alternative recommendation to use an updated weighted average cost of capital. TIEC contended that the utilities have therefore implicitly acknowledged the propriety of this rulemaking and the unreasonableness of their claims that the commission is somehow prohibited form changing the carrying cost.

Commission response

The commission agrees that updating a utility's CTC interest rate in the utility's future rate cases is appropriate. Such a provision was included in the proposed rule and is retained in the adopted rule.

Changes to rate on retail clawback and fuel balance

AEP and TNMP advised that the commission should adjust the carrying charges on the retail clawback amounts if it changes the carrying cost for the unsecuritized balances. Cities agreed in its replies. OPC replied that changing the interest rate on the CTC balance to more accurately reflect the risk associated with collecting the CTC does not have any impact upon the calculation of interest on the unpaid balance of the retail clawback or a fuel expense over-recovery. OPC opined that the availability to the utility of the funds related to the retail clawback and fuel over-recovery provide the utility with a cost-free source of capital until the balances are paid to ratepayers, and that the benefit to the utility of the use of such funds should not be confused with the risk of collecting the nonbypassable CTC from ratepayers.

AEP pointed out in its reply comments that retaining the use of the pre-tax weighted-average cost of capital could also provide, in some cases, a benefit to ratepayers. This would result from a situation--such as that of AEP Texas Central--in which the CTC consisted of a negative balance to be credited to ratepayers. If the pre-tax WACC were applied to the negative balance instead of a debt-based rate, ratepayers would receive greater benefits.

Commission response

The commission agrees with AEP, TNMP, and Cities that a utility's retail clawback balance and final fuel balance should be subject to the same interest rate adjustment as the rest of the CTC balance. Upon the issuance of a utility's true-up final order, all these true-up items become part of a regulatory asset or regulatory liability and should be accorded the same treatment. The rule has been modified accordingly.

Verifying the Calculation

OPC suggested that the rule should provide for supporting workpapers and a possible review of the debt calculation. CNP replied that it is unnecessary and inappropriate for the cost of debt calculation to be reviewed because it is straightforward and because commission Staff has the resources to confirm that it is done correctly. CNP further replied that if staff needs clarification from the utility on a calculation, it will presumably request whatever information it needs, and that the time and effort spent by staff in refereeing discovery disputes would likely far outweigh any incremental benefits that might accrue as a result of the discovery that OPC seeks.

Commission response

The commission agrees with CNP that it is not necessary for the rule to specifically provide for the inclusion of supporting workpapers and a possible review of the interest-rate calculation. To the extent that commission staff or other parties need additional data, they can request such information. Accordingly, no change to the rule has been made.

All comments, including any not specifically referenced herein, were fully considered by the commission. In adopting this section, the commission makes other minor modifications for the purpose of clarifying its intent.

This amendment is adopted under the Public Utility Regulatory Act, Texas Utilities Code Annotated §14.002 (Vernon 1998 & Supplement 2005) (PURA), which provides the Public Utility Commission with the authority to make and enforce rules reasonably required in the exercise of its powers and jurisdiction; and specifically, PURA §39.252, which addresses a utility's right to recover stranded costs, and PURA §39.262, which requires the commission to conduct a true-up proceeding for each investor-owned electric utility after the introduction of customer choice and which prohibits over-recovery of stranded costs.

Cross Reference to Statutes: Public Utility Regulatory Act §§14.002, 39.252 and 39.262.

§25.263.True-up Proceeding.

(a) Purpose.

(1) The purpose of the true-up proceeding is to quantify and reconcile the amount of stranded costs, the differences in the price of power obtained through the capacity auctions and the power costs used in the excess costs over market (ECOM) model; the results of the annual reports; the level of excess revenues, net of nonbypassable delivery charges, from customers who continue to pay the price to beat (PTB); the reasonable regulatory assets not previously approved in a rate order that are being recovered through competition transition charges (CTCs) or transition charges (TCs); and the final fuel balances. The purpose of the true-up proceeding is also to provide for the recovery of regulatory assets not already approved for securitization that were to be considered in future proceedings pursuant to a commission financing order in a securitization case.

(2) An electric utility, together with its affiliated retail electric provider (AREP), its affiliated power generation company (APGC), and its affiliated transmission and distribution utility (TDU), shall not be permitted to over-recover stranded costs through the application of the measures provided in the Public Utility Regulatory Act (PURA), Chapter 39, or under the procedures established in PURA §39.262 and this section.

(b) Application. This section applies to all investor-owned transmission and distribution utilities established pursuant to PURA §39.051, their APGCs, and their AREPs. In addition, the reporting requirements of subsection (j)(6) of this section apply to all retail electric providers (REPs) serving residential and small commercial customers.

(c) Definitions. The following words and terms, when used in this section, shall have the following meanings unless the context indicates otherwise:

(1) Capacity auction total price of power ($/MWh)--The total (fuel plus non-fuel) capacity auction revenues for entitlements to capacity for the years 2002 and 2003 divided by the total capacity auction energy (expressed in MWh) scheduled to be delivered for those entitlements over the same time period.

(2) Independent third party--The party designated by the commission to perform the duties described in subsection (j) of this section.

(3) Mitigation--The total excess earnings and redirected depreciation applied to generation assets pursuant to PURA §39.254 and §39.256 or a commission order issued after 1996 that approved a utility's transition case.

(4) Net mitigation--Any mitigation that has not been reversed or refunded as of the date of the final order in the true-up proceeding.

(5) Net value realized--All compensation paid by a buyer for generation assets, including the buyer's assumption of debt, less any costs of sale such as legal fees, broker fees, and other reasonable transaction costs.

(6) Projected stranded costs--The value produced by the ECOM model and approved by the commission in the proceeding conducted pursuant to PURA §39.201.

(7) Regulatory assets--The generation-related portion of the Texas jurisdictional portion of the amount reported by the electric utility in its 1998 annual report on Securities and Exchange Commission Form 10-K as regulatory assets and liabilities, offset by the applicable portion of generation-related investment tax credits permitted under the Internal Revenue Code of 1986.

(8) Residential market price of electricity--The volume-weighted average price, less average nonbypassable charges (each expressed in cents per kilowatt-hour (kWh)), calculated by the independent third party for residential electric service provided by non-affiliated retail electric providers and non-provider of last resort (POLR) service providers competing in the TDU region. The price determined by the independent third party shall be based upon pricing disclosures pursuant to §25.475(e) of this title (relating to Information Disclosures to Residential and Small Commercial Customers) and other information provided to the independent third party.

(9) Residential net price to beat--The average residential PTB rate (expressed in cents per kWh) less the average nonbypassable charges (expressed in cents per kWh) applicable to residential customers.

(10) Small commercial market price of electricity--The volume-weighted average price, less average nonbypassable charges (each expressed in cents per kWh), calculated by the independent third party for small commercial electric service provided by non-AREPs and non-POLR service providers competing in the TDU region. The price determined by the independent third party shall be based upon pricing disclosures pursuant to §25.475(e) of this title and other information provided to the independent third party.

(11) Small commercial net price to beat--The average small commercial PTB rate (expressed in cents per kWh) less the average nonbypassable charges (expressed in cents per kWh) applicable to small commercial customers.

(12) Transferee corporation--A separate affiliated or non-affiliated company to whom an electric utility or its APGC transfers generation assets.

(13) Transmission and distribution utility (TDU)--A transmission and distribution utility that, pursuant to PURA §39.051, is the successor in interest of an electric utility certificated to serve an area.

(14) Transmission and distribution utility region (TDU region)--The affiliated transmission and distribution utility's service territory.

(d) Obligation to file a true-up proceeding.

(1) Each TDU, its APGC, and its AREP shall jointly file a true-up application pursuant to subsection (e) of this section.

(2) Each TDU that is a successor in interest of any utility that was reported by the commission to have positive ECOM, denoted as the "base case" for the amount of stranded costs before full retail competition in 2002 with respect to its Texas jurisdiction in the April 1998 Report to the Texas Senate Interim Committee on Electric Utility Restructuring entitled "Potentially Strandable Investment (ECOM) Report: 1998 Update," and such TDU's, APGC's, and AREP's, shall file the true-up application as required by subsections (f) - (k) of this section.

(3) All TDUs not described in paragraph (2) of this subsection, their APGCs, and their AREPs shall file the applications required by subsections (h) and (j) of this section.

(e) True-up filing procedures.

(1) Each TDU, APGC, and AREP shall file all testimony and schedules on which they intend to rely for their direct case in accordance with the true-up filing package prescribed by the commission.

(A) Within 20 calendar days of the filing of a true-up application, commission staff or any intervenor may file a motion stating that the filing is materially deficient. Any such motion shall include a detailed explanation of the claimed material deficiencies.

(B) If the presiding officer determines that an application is materially deficient, the TDU, APGC, and AREP shall correct the deficiencies within 30 calendar days. The deadline for final commission order shall be extended day for day from the date of initial filing until the corrections are filed with the commission.

(2) At least 90 days prior to the filing of the first true-up application scheduled by the commission, a utility's APGC shall file a notification of intent with the commission if it intends to utilize PURA §39.262(i) to determine the amount of its stranded costs for nuclear assets.

(3) The commission may initiate a generic proceeding to determine true-up issues that are common to multiple TDUs, APGCs, and AREPs. This proceeding may include updates to the ECOM model required by subsection (f)(2)(B) of this section, in the event a notification of intent is filed pursuant to paragraph (2) of this subsection. The commission may order further updates to any order approved in a generic proceeding pursuant to this section for any utility whose customers are not offered competition on January 1, 2002.

(4) As part of the true-up proceeding, the commission shall make a determination with respect to whether the TDU, the APGC, and the AREP have complied with PURA §39.252(d). If the commission finds that the TDU, the APGC, or the AREP have failed, individually or in combination, to fully comply with their obligations under PURA §39.252(d), the commission may reduce the net book value of the APGC's generation assets or take other measures it deems appropriate in the true-up proceeding filed under this section. In making a determination as to compliance with PURA §39.252(d), the commission shall not substitute its judgment for a market valuation of generation assets determined under PURA §39.262(h) or (i).

(5) The State Office of Administrative Hearings shall employ expedited procedures during discovery in the true-up proceedings.

(6) The commission shall issue the final order for each proceeding filed under this section not later than the 150th day after the filing of a complete, non-deficient application. Notwithstanding the foregoing, however, the 150-day deadline may be extended by the commission for good cause.

(f) Quantification of market value of generation assets.

(1) Market value of generation assets shall be quantified using one or more of the following methods:

(A) Sale of assets method. If an electric utility or its APGC sells some or all of its generation assets after December 31, 1999, in a bona fide third-party transaction under a competitive offering, the total net value realized from the sale shall establish the market value of the generation assets sold. Within 30 days of closing, the utility or its APGC shall provide to the commission a detailed explanation, which may be filed confidentially, of the transaction and a description of the generating unit, property boundaries, fuel and parts, emission allowances, and other general categories of items associated with the sale, including any ancillary items related to the assets.

(B) Stock valuation method. The following method of market valuation without using a control premium may be used to value generation assets.

(i) If, at any time after December 31, 1999, an electric utility or its APGC has transferred some or all of its generation assets, including, at the election of the electric utility or the APGC, any fuel and fuel transportation contracts related to those assets, to one or more separate affiliated or nonaffiliated corporations, not less than 51% of the common stock of each corporation is spun off and sold to public investors through a national stock exchange, and the common stock has been traded for not less than one year, the resulting average daily closing price of the common stock over 30 consecutive trading days chosen by the commission out of the last 120 consecutive trading days before the true-up filing required by this section establishes the market value of the common stock equity in each transferee corporation.

(ii) The average book value of each transferee corporation's debt and preferred stock securities during the 30-day period chosen by the commission to determine the market value of common stock shall be added to the market value of its stock.

(iii) The market value of each transferee corporation's assets that is determined as the sum of clauses (i) and (ii) of this subparagraph shall be reduced by the corresponding net book value of the assets acquired by the transferee corporation from any entity other than the affiliated electric utility or APGC.

(iv) The market value of the assets determined from the procedures required by clauses (i), (ii), and (iii) of this subparagraph establishes the market value of the generation assets transferred by the affiliated electric utility or APGC to each separate corporation.

(C) Partial stock valuation method. The following method of market valuation using a control premium may be used to value generation assets.

(i) If, at any time after December 31, 1999, an electric utility or its APGC has transferred some or all of its generation assets, including, at the election of the electric utility or the APGC, any fuel and fuel transportation contracts related to those assets, to one or more separate affiliated or nonaffiliated corporations, at least 19%, but less than 51%, of the common stock of each corporation is spun off and sold to public investors through a national stock exchange, and the common stock has been traded for not less than one year, the resulting average daily closing price of the common stock over 30 consecutive trading days chosen by the commission out of the last 120 consecutive trading days before the filing establishes the market value of the common stock equity in each transferee corporation.

(ii) The commission may accept the market valuation to conclusively establish the value of the common stock equity in each transferee corporation or convene a valuation panel of three independent financial experts to determine whether the per-share value of the common stock sold is fairly representative of the per-share value of the total common stock equity or whether a control premium exists for the retained interest.

(iii) Should the commission elect to convene a valuation panel, the panel must consist of financial experts chosen from proposals submitted in response to commission requests from the top ten nationally recognized investment banks with demonstrated experience in the United States electric industry, as indicated by the dollar amount of public offerings of long-term debt and equity of United States investor-owned electric companies over the immediately preceding three years as ranked by the publication "Securities Data" or "Institutional Investor."

(iv) If the panel determines that a control premium exists for the retained interest, the panel shall determine the amount of the control premium, and the commission shall adopt the determination, but may not use the control premium to increase the value of the assets by more than 10%.

(v) The costs and expenses of the panel, as approved by the commission, shall be paid by each transferee corporation.

(vi) The determination of the commission, based on the finding of the panel and other admitted evidence, conclusively establishes the value of the common stock of each transferee corporation.

(vii) The average book value of each transferee corporation's debt and preferred stock securities during the 30-day period chosen by the commission to determine the market value of common stock shall be added to the market value of its stock.

(viii) The market value of each transferee corporation's assets shall be reduced by the corresponding net book value of the assets acquired by the transferee corporation from any entity other than the electric utility or its APGC.

(ix) The market value of the assets resulting from the procedures required by clauses (i) - (viii) of this subparagraph establishes the market value of the generation assets transferred by the electric utility or APGC to each transferee corporation.

(D) Exchange of assets method. If, at any time after December 31, 1999, an electric utility or its APGC transfers some or all of its generation assets, including any fuel and fuel transportation contracts related to those assets, in a bona fide third-party exchange transaction, the stranded costs related to the transferred assets shall be the difference between the net book value and the market value of the transferred assets at the time of the exchange, taking into account any other consideration received or given.

(i) The market value of the transferred assets may be determined through an appraisal by a nationally recognized independent appraisal firm, if the market value is subject to a market valuation by means of an offer of sale in accordance with this subparagraph.

(ii) To obtain a market valuation by means of an offer of sale, the owner of the asset shall offer it for sale to other parties under procedures that provide broad public notice of the offer and a reasonable opportunity for other parties to bid on the asset. The owner of the asset shall provide to the commission copies of all documentation explaining and attesting to the utility's sale proposal.

(iii) The owner of the asset may establish a reserve price for any offer based on the sum of the appraised value of the asset and the tax impact of selling the asset, as determined by the commission.

(iv) Within 30 days of closing, the utility or its APGC shall provide to the commission a detailed explanation, which may be filed confidentially, of the transaction and a description of the generating unit, property boundaries, fuel and parts, emission allowances, and other general categories of items associated with the transfer, including any ancillary items related to the assets.

(2) ECOM Method. Unless an electric utility or its APGC combines all its remaining generation assets into one or more transferee corporations pursuant to paragraph (1)(B) or (C) of this subsection, the electric utility shall quantify its stranded costs for nuclear assets using the ECOM method.

(A) The ECOM method is the estimation model prepared for and described by the commission's April 1998 Report to the Texas Senate Interim Committee on Electric Restructuring entitled "Potentially Strandable Investment (ECOM) Report: 1998 Update." The methodology used in the model must be the same as that used in the 1998 report to determine the "base case."

(B) As part of the filing specified in subsection (d) of this section, the electric utility shall rerun the ECOM model using updated company specific inputs required by the model, updating the market price of electricity, and using updated natural gas price forecasts and the capacity cost based on the long-run marginal cost of the most economic new generation technology then available, as approved by the commission pursuant to subsection (e)(3) of this section. Natural gas price projections used in the model shall be forward prices of Houston Ship Channel natural gas.

(C) Growth rates in generating plant operations and maintenance costs and allocated administrative and general costs shall be benchmarked by comparing those costs to the best available information on cost trends for comparable generating plants.

(D) Capital additions shall be benchmarked using the 1.5% limitation set forth in PURA §39.259(b).

(g) Quantification of net book value of generation assets.

(1) For purposes of this section, the net book value of generation assets shall be established as of December 31, 2001, or the date a market value is established through a market valuation method under subsection (f) of this section, whichever is earlier.

(2) Net book value of generation assets consists of:

(A) The generation-related electric plant in service, less accumulated depreciation (exclusive of depreciation related to mitigation), plus generation-related construction work in progress, plant held for future use, and nuclear, coal, and lignite fuel inventories, reduced by:

(i) net mitigation;

(ii) the net book value of nuclear generation assets if quantification of ECOM related to those nuclear generation assets is determined pursuant to PURA §39.262(i); and

(iii) any generation-related invested capital recoverable through a CTC, exclusive of related carrying costs, projected to be collected through the date of the final order in the true-up proceeding.

(B) Above-market purchased power costs arising from contracts in effect before January 1, 1999, including any amendments and revisions to such contracts resulting from litigation initiated before January 1, 1999.

(i) The purchased power market value of the demand and energy included in the purchased power contracts shall be determined by using the weighted average costs of the highest three offers from a bona fide third-party transaction or transactions on the open market.

(ii) The bona fide third-party transaction or transactions on the open market shall be structured so that the above-market purchased power costs are determined pursuant to subclause (I) or (II) of this clause.

(I) A transaction may be structured so the electric utility pays a third party to assume the utility's obligations under the purchased power contract. The weighted average of the three highest offers received in the transaction establishes the above-market purchased power costs.

(II) A transaction may be structured so a third party pays the utility to take power under the purchased power contract. The difference between the net present value of obligations under the existing contracts at the utility's cost of capital and the weighted average of the three highest offers received in the transaction establishes the above-market purchased power costs.

(C) Deferred debits, to the extent they have not been securitized, related to a utility's discontinuance of the application of SFAS No. 71 ("Accounting for the Effects of Certain Types of Regulation") for generation-related assets if required by PURA Chapter 39.

(D) Capital costs incurred before May 1, 2003 to improve air quality to the extent they have been approved by the commission pursuant to §25.261 of this title (relating to Stranded Cost Recovery of Environmental Cleanup Costs).

(E) Any adjustments resulting from the commission's review of the TDU's, APGC's, and AREP's efforts pursuant to subsection (e)(4) of this section.

(h) True-up of final fuel balance.

(1) An APGC shall reconcile the former electric utility's final fuel balance determined under PURA §39.202(c).

(2) The final fuel balance shall be reduced by any revenues collected by the AREP under any commission-approved fuel surcharge, from the date of introduction of competition to the utility's customers through the date of the true-up filing under this section, so long as the fuel surcharge is associated with fuel costs incurred during the time period covered by the final reconcilable fuel balance.

(3) If an electric utility or its TDU or APGC is assessed by another utility in Texas a fuel surcharge after 2001 for under-recoveries occurring through the end of 2001, the surcharged utility shall add the amount of surcharges and any associated carrying costs paid after 2001 to its final fuel balance.

(4) The final fuel balance, as adjusted by paragraphs (2) and (3) of this subsection, shall include carrying costs on the positive or negative fuel balance equal to:

(A) the weighted-average cost of capital approved in the company's unbundled cost of service (UCOS) proceeding, if the period until the date of the final true-up order is greater than one year; or

(B) the rate approved in §25.236 of this title (relating to Recovery of Fuel Costs) if the period until the date of the final true-up order is one year or less.

(i) True-up of capacity auction proceeds.

(1) For purposes of the true-up required by PURA §39.262(d)(2), and as provided for under §25.381(h)(1) of this title (relating to Capacity Auctions), the APGC shall compute the difference between the price of power obtained through the capacity auctions conducted for the years 2002 and 2003 and the power cost projections for the same time period as used in the determination of ECOM for that utility in the proceeding under PURA §39.201. The difference shall be calculated according to the following formula: (ECOM market revenues - ECOM fuel costs) - ((capacity auction price x total 2002 and 2003 busbar sales) - actual 2002 and 2003 fuel costs). For purposes of this paragraph:

(A) "ECOM market revenues" shall be the sum of rows 12 through 14 for the years 2002 and 2003 in the "Plant Economics" worksheet of the ECOM model underlying the commission-approved ECOM estimate in the company's UCOS proceeding;

(B) "ECOM fuel costs" shall be the sum of rows 33 through 35 for the years 2002 and 2003 in the "Cost Partition" worksheet of the ECOM model underlying the commission-approved ECOM estimate in the company's UCOS proceeding;

(C) The "capacity auction price" shall be the APGC's total capacity auction revenues derived from the capacity auctions conducted for the years 2002 and 2003 divided by that APGC's total MWh sales of capacity auction products for the years 2002 and 2003.

(2) If, as a result of not having participated in capacity auctions pursuant to §25.381(h)(1) of this title, an APGC is unable to determine a company-specific capacity auction price, the APGC may request in its true-up application a method using prevailing capacity auction prices from other APGCs for the calculation in paragraph (1) of this subsection.

(j) True-up of PTB revenues. This subsection specifies how the PTB will be compared to prevailing market prices pursuant to PURA §39.262(e). For purposes of this subsection, the term "small commercial customer" does not include unmetered lighting accounts unless such an account has historically been treated as a separate customer for billing purposes.

(1) An AREP is not required to perform the reconciliation described in PURA §39.262(e) for the residential or small commercial customer class if the commission has determined that the AREP has reached the applicable 40% threshold requirements prior to January 1, 2004, pursuant to filing requirements listed in §25.41(l) of this title (relating to Price to Beat) applicable to that class.

(2) If an AREP has not reached the applicable 40% threshold requirements prior to January 1, 2004, for either the residential or the small commercial class, or both, the net PTB for each such class must be compared to the market price of electricity for that class in the TDU region for the period January 1, 2002 through January 1, 2004 as provided in paragraphs (3) and (4) of this subsection.

(3) The independent third party shall compute the difference between the residential net PTB and the residential market price of electricity on the last day of each calendar-year quarter for the years 2002 and 2003. The price differential for each quarter shall be multiplied by the total kWh consumed by residential PTB customers of the AREP for that quarter. The results shall be summed over the eight quarters within the period from January 1, 2002 through January 1, 2004.

(4) The independent third party shall compute the difference between the small commercial net PTB and the small commercial market price of electricity on the last day of each calendar-year quarter for the years 2002 and 2003. The price differential for each quarter shall be multiplied by the total kWh consumed by small commercial PTB customers of the AREP for that quarter. The results shall be summed over the eight quarters within the period from January 1, 2002 through January 1, 2004.

(5) For each of the residential and small commercial classes, the AREP shall credit the TDU the lesser of the amounts calculated in subparagraphs (A) and (B) of this paragraph:

(A) $150 multiplied by (the difference between the number of residential or small commercial customers, as applicable, in the TDU Region taking PTB service from the AREP on January 1, 2004 and the number of residential or small commercial customers, as applicable, outside the TDU region being served by the AREP on January 1, 2004, provided that such customers are not receiving POLR service from the AREP); or

(B) the total differential between the net PTB and the market price of electricity calculated for the applicable class under paragraph (3) or (4) of this subsection.

(6) All REPs shall provide information to the independent third party as needed for the performance of calculations set forth in paragraphs (3) and (4) of this subsection. All data used in the calculations performed by the independent third party will remain confidential but shall be subject to audit by the commission.

(7) The functions of the independent third party shall be funded by the AREPs through one or more assessments made by the commission.

(k) Regulatory assets. To the extent that any amount of regulatory assets included in a TC or CTC exceeds the amount of regulatory assets approved in a rate order which became effective on or before September 1, 1999, the commission shall conduct a review during the true-up proceeding to determine any such amounts that were not appropriately calculated or that did not constitute reasonable and necessary costs. In addition, to the extent that any amount of regulatory assets approved for securitization in a commission financing order was not subsequently included in an issuance of transition bonds, that amount of regulatory assets shall be included in the TDU/APGC true-up balance under subsection (l) of this section.

(l) TDU/APGC True-up balance.

(1) The formula to establish the true-up balance between the TDU and APGC is shown in the following table. TDUs described in subsection (d)(3) of this section and their APGCs shall insert zero for all inputs in this equation except the input entitled "Final fuel balance calculated pursuant to subsection (h)."

Figure: 16 TAC §26.263(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.

(i) any CTC established under PURA §39.201 shall be eliminated;

(ii) net mitigation shall be reversed until exhausted or until a zero true-up balance is achieved, and the amount of net mitigation reversed shall be returned to ratepayers by the APGC through an excess mitigation credit; and

(iii) if net mitigation is exhausted and some amount of the negative true-up balance remains, then for companies that have securitized regulatory assets, a negative CTC shall be established based upon the lesser of the absolute value of the remaining negative true-up balance or the securitization amount on which any TCs are based. If the company has been issued a financing order by the commission authorizing the securitization of regulatory assets but securitization has not yet occurred, then the negative CTC will be implemented at the time the securitization bonds are issued. If the company has not received a financing order from the commission authorizing securitization of regulatory assets, then no negative CTC shall be established for purposes of this subsection.

(D) If the TDU/APGC true-up balance is positive, then a CTC shall be imposed to enable the APGC to recover any positive fuel balance. If the TDU/APGC true-up balance is negative, then a fuel credit shall be implemented to return the over-recovered fuel balance to ratepayers.

(3) The TDU shall be allowed to recover, or shall be liable for, carrying costs on the true-up balance. This provision shall apply to all amounts the commission has authorized to be collected under this section that have not been securitized. Carrying costs on the unrecovered true-up balance shall be calculated from January 1, 2002, until the true-up balance is fully recovered. Based on the filing described below that is made within 30 days of the effective date of this rule, carrying costs shall be calculated using an interest rate determined as follows.

(A) The TDU shall file an application to adjust the carrying costs and amend its CTC tariff on a prospective basis in conformance with this paragraph within 30 days of the effective date of an amendment to this paragraph. The establishment of the interest rate used to calculate carrying charges shall be based upon the following:

(i) The weighted average of the TDU's unadjusted historical cost of debt (HC) and an adjusted form of the TDU's marginal cost of debt (MC), with the weightings based on the utility's most recently authorized capital structure. The HC component shall be the cost of debt as determined in a final commission order, provided that the order was entered within three years of the effective date of this rule, for a rate proceeding in which the TDU's cost of debt was explicitly addressed or can be determined based upon the order's authorized weighted-average cost of capital (overall rate of return on invested capital), proportions of debt and equity, and allowed return on equity. The MC component shall be based upon the average yield for long-term bonds of public utilities with the TDU's current credit rating during the three-month period preceding the filing, as published in Moody's Credit Perspectives (or a similar publication if Moody's Credit Perspectives is not available). Additionally, the MC component shall be adjusted-- i.e. , grossed-up--for the effects of federal income taxes. The following formula shall be used to determine the weighted-average carrying cost described above: CTC Carrying Charge Rate = MC * Equity Proportion of Most Recently Authorized Capital Structure * 1/(1-Tax Rate) + HC * Debt Proportion of Most Recently Authorized Capital Structure.

(ii) If the commission, within three years prior to the effective date of this rule, did not enter a final order in a rate proceeding that addresses the TDU's cost of debt, the HC component used in the interest rate determination described in the preceding clause shall be based upon the cost of debt reported in the utility's most recent Earnings Monitoring Report filed pursuant to §25.73 of this title (relating to Financial and Operating Reports), adjusted for known and measurable changes.

(B) In each rate case for the TDU, the calculation of carrying costs on the TDU's unsecuritized true-up balance shall be reviewed and adjusted to reflect authorized changes in the TDU's capital structure and cost of debt. Further, to reflect the effect of the CTC carrying charge rate across the entirety of the TDU's recoverable regulated assets, a composite rate of return incorporating the CTC carrying charge rate may be applied to both the unsecuritized true-up balance and the TDU rate base. The composite rate of return shall be calculated as follows: Composite Pre-Tax Rate of Return = CTC Carrying Charge Rate * Unsecuritized True-up Balance / (Unsecuritized True-up Balance + TDU Rate Base) + TDU Authorized Pre-Tax Weighted-Average Cost of Capital * TDU Rate Base / (Unsecuritized True-up Balance + TDU Rate Base).

(m) TDU/AREP true-up balance. The TDU shall bill the AREP for, and the AREP shall remit to the TDU, the amount calculated pursuant to subsection (j) of this section, plus carrying costs. Carrying costs shall be calculated in accordance with subsection (l) of this section and shall be calculated for the period of time from the date of the true-up final order until fully recovered. The commission may reduce the TDU's rates to reflect the amounts due from the AREP.

(n) Proceeding subsequent to the true-up.

(1) The TDU shall file an application to adjust its rates within 60 days following the issuance of a final, appealable order in its true-up proceeding. In the proceeding, the commission may adjust the TDU's rates and any CTC, in accordance with PURA §39.262(g), and any excess mitigation credit. The commission may also allocate the recovery responsibility for such rates and any CTC to the TDU's customer classes.

(2) In the proceeding, the commission shall also consider adopting remittance standards, if necessary, with respect to the credits or bills as among the TDU, the APGC, and the AREP.

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 June 30, 2006

TRD-200603561

Adriana A. Gonzales

Rules Coordinator

Public Utility Commission of Texas

Effective date: July 20, 2006

Proposal publication date: January 27, 2006

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

Chapter 26. SUBSTANTIVE RULES APPLICABLE TO TELECOMMUNICATIONS SERVICE PROVIDERS

Subchapter P. TEXAS UNIVERSAL SERVICE FUND

16 TAC §26.420

The Public Utility Commission of Texas (commission) adopts an amendment to §26.420, relating to Administration of the Texas Universal Service Fund (TUSF), with no changes to the proposed text as published in the April 14, 2006, issue of the Texas Register (31 TexReg 3142). This adopted amendment revises the existing rule to reflect the current assessment methodology adopted by the commission in Docket No. 21208 (see Docket No. 21208, Order Regarding TUSF Assessment of Intrastate Telecommunications Services Receipts, July 29, 2004). The Order in Docket No. 21208 was adopted in response to the decision of the United States Court of Appeals for the Fifth Circuit in AT&T Corp. v. Public Utility Commission of Texas , 373 F. 3d 641 (5th Cir. 2004) (AT&T Decision). This amendment is adopted under Project Number 28708.

§26.420(f)(2)(E) and §26.420(f)(6)

The commission received comments on the proposed amendment from the Office of the Attorney General of the State of Texas (State). The State supported the proposed amendments, and in particular §26.420(f)(2)(E) and §26.420(f)(6), as they retain the State's current exempt status by basing the assessment on taxable receipts. The State asserted that the continuation of the current policy of exempting state agencies from a TUSF surcharge is ultimately protective of consumer and taxpayer interests. The State proposed no changes to the amendment.

This amendment is adopted under the Public Utility Regulatory Act, Texas Utilities Code Annotated §14.002 (Vernon 1998, Supplement 2005) (PURA), which provides the commission with the authority to make and enforce rules reasonably required in the exercise of its powers and jurisdiction; and specifically, PURA §56.023, which requires the commission to adopt procedures to fund the TUSF.

Cross Reference to Statutes: Public Utility Regulatory Act §14.002 and §56.023.

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 June 30, 2006.

TRD-200603568

Adriana A. Gonzales

Rules Coordinator

Public Utility Commission of Texas

Effective date: July 20, 2006

Proposal publication date: April 14, 2006

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