UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT
Pursuant to Section 13 or 15(d) of
the Securities Exchange Act of 1934

CENTERPOINT ENERGY, INC.

(Exact name of registrant as specified in its charter)

Texas (State or other jurisdiction of incorporation)		1-31447 (Commission File Number)		74-0694415 (IRS Employer Identification No.)

1111 Louisiana Houston, Texas (Address of principal executive offices)		77002 (Zip Code)

Registrant’s telephone number, including area code: (713) 207-1111

CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC

(Exact name of registrant as specified in its charter)

Texas (State or other jurisdiction of incorporation)		1-3187 (Commission File Number)		22-3865106 (IRS Employer Identification No.)

1111 Louisiana Houston, Texas (Address of principal executive offices)		77002 (Zip Code)

Registrant’s telephone number, including area code: (713) 207-1111

     Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions ( see General Instruction A.2. below):

o     Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o     Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o     Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o     Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

 

 

Item 8.01 Other Events.

     On March 18, 2011, the Texas Supreme Court issued its ruling on the appeal of the final order (true-up order) issued in 2004 by the Public Utility Commission of Texas (Texas Utility Commission) in connection with CenterPoint Energy Houston Electric, LLC’s (CenterPoint Houston) stranded cost and true-up application (true-up application). CenterPoint Houston is the transmission and distribution subsidiary of CenterPoint Energy, Inc. (collectively with its subsidiaries, CenterPoint Energy). The Supreme Court affirmed in part and reversed in part the decision of the Texas Utility Commission and remanded the matter to the Texas Utility Commission for further proceedings.

     CenterPoint Energy originally filed its true-up application with the Texas Utility Commission requesting recovery of $3.7 billion, excluding interest, as allowed under the Texas Electric Choice Plan. In December 2004, the Texas Utility Commission issued its true-up order allowing CenterPoint Energy to recover a true-up balance of approximately $2.3 billion, which included interest through August 31, 2004, and provided for certain other adjustments. CenterPoint Energy and a number of other parties appealed the Texas Utility Commission’s decision to a district court in Travis County, Texas, the Texas Third Court of Appeals (court of appeals) and, ultimately, to the Texas Supreme Court. A copy of the Texas Supreme Court’s opinion is attached to this report as Exhibit 99.1.

     The impact of the Texas Supreme Court’s decision regarding the matters on appeal with respect to the true-up order is summarized as follows:

	•		The method used by the Texas Utility Commission to calculate the market value of the company’s former generating assets was overturned. In its decision, the Texas Utility Commission had rejected the partial stock valuation method CenterPoint Energy utilized to establish the market value of the generating assets and the Commission had fashioned its own valuation. The Supreme Court ruled that the Commission had no authority to craft an alternative valuation methodology but instead should have valued the generating assets at the value established when CenterPoint Energy later sold its Texas Genco subsidiary. This portion of the decision requires that the valuation question be remanded to the Texas Utility Commission for a determination. By employing the sale of assets methodology, stranded costs are expected to be reduced by approximately $252 million. This portion of the decision is unfavorable to CenterPoint Energy. These sums (plus interest) will be subtracted from the amounts eligible for recovery in the remand proceeding.
	•		The Texas Utility Commission’s order denying recovery of approximately $440 million in capacity auction true-up amounts was reversed. This portion of the decision is favorable to CenterPoint Energy. These sums plus interest are eligible for recovery in the remand proceeding.
	•		The Texas Utility Commission’s refusal to include approximately $378 million related to depreciation in the calculation of stranded costs was reversed. This portion of the decision is favorable to CenterPoint Energy. These sums plus interest are eligible for recovery in the remand proceeding.
	•		The Texas Utility Commission’s order allowing recovery of approximately $358 million in excess mitigation credits (EMCs) that CenterPoint Energy had been erroneously ordered to pay its former affiliate was upheld. This portion of the decision is favorable to CenterPoint Energy. These sums have already been recovered and will not be addressed in the remand proceeding.
	•		The Texas Utility Commission decisions allowing recovery of construction work in progress balances and interest on the capacity auction true-up amounts were upheld. These decisions are favorable to CenterPoint Energy. These sums have already been recovered and will not be addressed in the remand proceeding.

     In its decision, the Texas Supreme Court did not address the treatment of Accumulated Deferred Investment Tax Credits (ADITC) and Excess Deferred Federal Income Taxes (EDFIT) in the true-up order and the related tax normalization issue. In line with the earlier request by the Texas Utility Commission and the decision of the court of appeals, this issue had been remanded to the Texas Utility Commission for further proceedings. The court of appeals decision to remand this issue, which was favorable to CenterPoint Energy in the amount of approximately $146 million, had not been appealed to the Texas Supreme Court. CenterPoint Energy will seek to recover these sums plus interest in the remand proceeding.

     The Texas Supreme court also did not address the court of appeals’ decision allowing CenterPoint Energy to recover approximately $210 million representing the interest component of the EMCs. This decision, which was favorable to CenterPoint Energy, was not appealed to the Texas Supreme Court. These sums plus interest are eligible for recovery in the remand proceeding.

     The decision by the Texas Supreme Court was unanimous, but parties may seek rehearing from the Texas Supreme Court. Once the rehearing process is completed, there is no prescribed timetable for decision by the Texas Utility Commission on the matters remanded to it.

     Based on the Texas Supreme Court’s decision, CenterPoint Energy estimates that, in the remand to the Texas Utility Commission, it will be entitled to seek recovery of approximately $922 million, plus interest.

Cautionary Statement Regarding Forward-Looking Information

     This report includes forward-looking statements. Actual events and results may differ materially from those projected. The statements in this report regarding the anticipated future recovery as a result of the Texas Supreme Court’s decision, the estimated interest on such amounts, the expected timing for, and method of, such recovery, and any other statements that are not historical facts are forward-looking statements. Factors that could affect actual results include the outcome of any requests to the Texas Supreme Court for rehearing, future actions by the Texas Utility Commission in response to the Texas Supreme Court’s ruling and any future appeals thereof, the timing and impact of future

regulatory, legislative, and IRS decisions, financial market conditions, and other factors discussed in CenterPoint Energy, Inc.’s and its subsidiaries’ Form 10-Ks for the fiscal year ended December 31, 2010, and other filings with the Securities and Exchange Commission.

Item 9.01 Financial Statements and Exhibits.

     (d) Exhibits.

99.1

Opinion of the Texas Supreme Court

SIGNATURE

     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

SIGNATURE

     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

EXHIBIT INDEX

EXHIBIT
NUMBER		EXHIBIT DESCRIPTION
99.1		Opinion of the Texas Supreme Court

Exhibit 99.1

IN THE SUPREME COURT OF TEXAS

No. 08-0421

The State of Texas, et al., Petitioners,

v.

Public Utility Commission of Texas, et al., Respondents

 

 

On Petition for Review from the
Court of Appeals for the Third District of Texas

 

 

Argued October 6, 2009

     Justice Willett delivered the opinion of the Court.

     This complex case poses several vexing questions regarding Texas utility-deregulation laws and the Public Utility Commission’s application of those laws. In short, numerous parties — the State of Texas, utility companies, municipal groups, consumer groups, and others — challenge the Commission’s interpretations of various cost-recovery provisions in Chapter 39 of the Utilities Code. As detailed below, we affirm the court of appeals’ judgment in part, reverse it in part, and remand to the PUC for further proceedings consistent with this opinion.

I. Background

A. Overview of Chapter 39¹

     The Legislature in 1999² overhauled the Public Utility Regulatory Act (PURA or Act) to create a “fully competitive electric power industry” in Texas.³ As part of this restructuring, utilities were required, not later than January 1, 2002, to split into three distinct units: (1) a

power-generation company, (2) a retail electric provider, and (3) a transmission and distribution utility.⁴ After that date, retail consumers could choose among competing retail providers.⁵ Rates charged by the transmission and distribution utility continue to be regulated by the Public Utility Commission (PUC or Commission).⁶

     The Legislature recognized that utilities had made investments in power-generation assets that produced a reasonable return under the existing regulated environment “but might well become uneconomic and thus unrecoverable in a competitive, deregulated electric power market.”⁷ The Act thus allows utilities to recover these “stranded costs,” which consist generally of “the portion of the book value of a utility’s generation assets that is projected to be unrecovered through rates that are based on market prices.”⁸

     The Act deregulated the market in phases. Retail rates were frozen from September 1, 1999 until January 1, 2002.⁹

     Section 39.201 directed transmission and distribution utilities to file, on or before April 1, 2000, proposed tariffs that included “nonbypassable delivery charges” to retail electric providers.¹⁰ It also directed the PUC to approve rates as of January 1, 2002.¹¹ The nonbypassable delivery charges included a “competition transition charge” (CTC) based on an estimate of stranded costs projected to exist at the end of the freeze period on December 31, 2001.¹² The CTC is “nonbypassable” in “that with limited exceptions, all retail electric customers in an existing utility’s service area will pay charges to allow that utility to recover stranded costs regardless of whether those customers purchase their electricity from that utility, switch to one of its competitors, or generate their own electricity.”¹³ In estimating stranded costs, utilities were required to use the “ECOM” model,¹⁴ an estimation model earlier used in a 1998 PUC report to the Legislature.¹⁵ Section 39.201(h) required the PUC to rerun the ECOM model using “updated

company-specific updates.” Provision is made in Section 39.201 for a utility to recover estimated stranded costs at any time after the start of the freeze period on September 1, 1999 by issuing bonds and using a “transition charge” (TC) to service the bonds,¹⁶ or by imposing a CTC.¹⁷ However, no such charges were imposed because the Commission concluded after the updated ECOM calculations that no utility would incur stranded costs.¹⁸

     Under Section 39.262, utilities were required, after January 10, 2004, to file with the PUC a reconciliation of stranded costs and the previous estimate of stranded costs that had been used in determining rates under Section 39.201.¹⁹ Section 39.262 further directed the PUC to conduct a “true-up proceeding” and enter a final order adjusting the CTC to reflect the ultimate valuation of stranded costs.²⁰ “If, based on the proceeding, the competition transition charge is not sufficient, the commission may extend the collection period for the charge or, if necessary, increase the charge.”²¹ The adjusted CTC is applied to the nonbypassable delivery rates of the transmission and distribution utility.²²

     In addition to adjustments for stranded costs, the PUC is directed at the true-up proceeding to make other adjustments to the nonbypassable delivery charges of the transmission and distribution utility. The parties refer to these other costs as “non-stranded costs.” These adjustments can result in an increase or decrease in the amount or collection period of the CTC.²³

     From January 1, 2002 until January 1, 2007, affiliated retail electric providers were required to charge rates six percent below average rates that were in effect on January 1, 1999, subject to certain adjustments including a fuel factor.²⁴ This price is known as the “price to beat.” After January 1, 2002, each affiliated power-generation company is required to file a final fuel reconciliation that calculates a final fuel balance as of December 31, 2001.²⁵

     To foster competition, utilities or their unbundled power-generation companies were required, at least 60 days before January 1, 2002, to conduct a “capacity auction” that sold entitlements to at least 15 percent of the utilities’ generation capacity.²⁶ The obligation continued until the earlier of 60 months after the date customer choice was introduced or the date the Commission determined “that 40 percent or more of the electric power consumed by residential and small commercial customers within the affiliated transmission and distribution utility’s certificated service area before the onset of customer choice [was] provided by nonaffiliated retail electric providers.”²⁷

     Under Section 39.262(d), the Act directs the affiliated power-generation company at the true-up proceeding to reconcile and either bill or credit the transmission and distribution utility for the net sum of (1) the former integrated utility’s final fuel balance,²⁸ and (2) a balance parties refer to as the “capacity auction true-up balance” or the “wholesale clawback,” consisting of the difference between the price of power realized at the capacity auctions and the power cost projections used in the ECOM model.²⁹

     Section 39.262(e) directs the affiliated retail electric provider at the true-up proceeding to credit the affiliated transmission and distribution utility for “any positive difference between the price to beat under Section 39.202, reduced by the nonbypassable delivery charge established under 39.201, and the prevailing market price of electricity during the same time period.”³⁰ This credit is sometimes called the “retail clawback.”

B. Proceedings Below

     Pursuant to Chapter 39, Reliant Energy, Inc., an integrated electric utility, separated into three entities:

•		CenterPoint Energy Houston Electric, LLC (CenterPoint) — the transmission and distribution utility,31
•		Reliant Energy Retail Services, LLC (RERS) — the retail electric provider,32 and
•		Texas Genco, LP (Genco or TGN) — the power-generation company.

     These three entities filed an application with the PUC to determine stranded costs and other true-up balances pursuant to Section 39.262.³³ Numerous parties, including the State of Texas, intervened. The intervenors consist of electricity consumers and consumer groups. In this proceeding (the true-up proceeding), the PUC made many factual and legal determinations, some of which are now before us on appeal. The PUC determined that CenterPoint was entitled to recover approximately $2.3 billion in stranded costs and other non-stranded costs. The PUC entered a final order on rehearing (Order) in the true-up proceeding.³⁴ One Commissioner dissented on a single issue, as discussed below.

     CenterPoint and various intervenors appealed the Order to district court. The district court affirmed the Order except as to two issues, one of which, concerning the capacity auction true-up, is discussed below. Both sides appealed to the court of appeals,³⁵ which affirmed the district court on numerous issues, but reversed the district court on a stranded cost issue and a capacity auction issue discussed below. We granted three petitions for review filed by CenterPoint,³⁶ a group of intervenors³⁷ who filed a joint petition, and the State of Texas. The State of Texas and the other petitioner-intervenors (collectively the Intervenors) subsequently filed joint briefing on the merits.

II. Discussion

A. Standards of Review

     Generally, “[a]ny party to a proceeding before the commission is entitled to judicial review under the substantial evidence rule.”³⁸ Chapter 39 also provides that the true-up order is subject to review under Chapter 2001 of the Government Code, the Texas Administrative Procedure Act (APA).³⁹ The APA looks to the scope of review “as provided by the law under which review is sought,”⁴⁰ which in this case is the substantial evidence standard. Under substantial evidence review of fact-based determinations, “[t]he issue for the reviewing court is not whether the agency’s decision was correct, but only whether the record demonstrates some reasonable basis for the agency’s action.”⁴¹

     The APA also provides in Section 2001.174 that, under substantial evidence review, the court may reverse the agency’s order where the agency has made a prejudicial error of law,⁴² or where the order is “arbitrary or capricious or characterized by abuse of discretion or clearly unwarranted exercise of discretion.”⁴³ Questions of statutory construction are questions of law and are reviewed de novo.⁴⁴ We have noted that an agency’s interpretation of the statute it administers is entitled to serious consideration so long as it is reasonable and does not conflict with the statute’s language.⁴⁵ However, “the PUC may not exercise what is effectively a new power” in addition to powers expressly conferred by statute or necessary to accomplish its express duties “on the theory that such a power is expedient for administrative purposes.”⁴⁶

B. Stranded Cost True-Up

1. Market Value

     By statutory definition, stranded costs are based on the difference between the book value of generation assets and the market value of these assets.⁴⁷ Section 39.251(7) provides that for purposes of establishing stranded costs in the true-up proceeding, “market value is established through a market valuation method under Section 39.262(h).”

     Section 39.262(h) provides that the affiliated power-generation company shall establish the market value of its generation assets using one or more of four methods: the sale of assets method, the stock valuation method, the partial stock valuation (PSV) method, and the exchange of assets method.⁴⁸

     CenterPoint complains that the PUC erred in refusing to employ the PSV method. CenterPoint attempted to establish the market value of its generation assets and resulting stranded costs under this method, found in subsection (h)(3). This method may be employed if “at least 19 percent, but less than 51 percent, of the common stock of [Genco] 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.”⁴⁹ If these conditions are met, “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 [stranded cost filing] shall be presumed to establish the market value of the common stock equity in [Genco].”⁵⁰ The PUC may accept this valuation or it may convene “a valuation panel of three independent financial experts to determine whether the percentage of common stock sold is fairly representative of the total common stock equity or whether a control premium exists for the retained interest.”⁵¹ As the court of appeals noted, with a partial stock spinoff, the control retained by the parent company “might increase the value of the stock privately held, rendering the average closing price of the publicly-traded stock an inaccurate measure of the true value of the stock.”⁵²

     CenterPoint contends that the PSV method was appropriately employed because CenterPoint distributed 19.0447 percent of Genco stock to CenterPoint shareholders, and retained ownership of the rest, on January 6, 2003. CenterPoint listed Genco on the New York Stock Exchange, where the stock publicly traded. CenterPoint contends and offered evidence that

it chose a stock dividend to existing shareholders in lieu of an initial public offering (IPO) because market conditions at the time would have made an IPO difficult. It further contends and offered evidence that it sold slightly over 19 percent of the stock because that percentage complied with the statute and also allowed CenterPoint and Genco to benefit from consolidated tax returns. A parent and subsidiary may file consolidated returns if the parent owns at least 80 percent of the stock in the subsidiary.⁵³

     The Commission conceded in its Order that it “may not substitute its judgment for a properly conducted market valuation of generation assets determined under PURA §§ 39.262(h) and (i).” It further recognized that utilities are “required to follow one of the four methods in PURA § 39.262(h) to determine the market value of generation assets for purposes of stranded-cost recovery.” Section 39.252(a) indeed provides that a utility is “allowed to recover all of its net, verifiable, nonmitigable stranded costs,” but Section 39.252(d) makes clear that “nothing in this section authorizes the commission to substitute its judgment for a market valuation of generation assets determined under Sections 39.262(h) and (i).”

     Nevertheless, the PUC concluded that the PSV method could not be employed by CenterPoint. The PUC noted a lack of proof that 19 percent of Genco shares had ever been sold on a national exchange. Focusing on the statutory language that the PSV method relies on a block of stock that “is spun off and sold to public investors through a national stock exchange,” it concluded that while the required amount of stock was “spun off” to public investors, it was not “sold” to public investors. It noted that “CenterPoint did not conduct an initial public offering of [Genco] shares.” It further noted that “[t]here was no public involvement in valuing the distribution of [Genco’s] stock,” and that “a distribution of stock is not a sale of stock.”

     Because the PUC found that the PSV method could not be used and that no other statutorily prescribed method was available, it embarked on an effort to establish market value based on a number of “data points,” including the announced sale of Genco (discussed below), market value estimates chosen by the valuation panel convened under subsection (h)(3), and other information. The valuation reached using this hybrid method resulted in a stranded cost recovery $258 million smaller than the recovery requested by CenterPoint under the PSV method. On this issue, the trial court and the court of appeals⁵⁴ agreed with the PUC.

     CenterPoint, on the other hand, reads the statute to require that (1) 19 percent of Genco’s stock be spun off, and (2) this block trade on a national exchange. It contends that so long as this block is publicly traded, it is being “sold to public investors through a national exchange” under the statute, and the market value of all of Genco’s stock can be determined, subject to a control premium adjustment for the retained interest as provided in the statute.

     The PUC argues that CenterPoint failed to prove that 19 percent of Genco’s common stock sold on a national stock exchange. Assuming that this is a statutory requirement for the partial stock valuation method, it would be satisfied if the spin-off⁵⁵ of Genco’s stock is a “sale” of securities under PURA. However, PURA does not define a “sale” of securities.⁵⁶ There are no Texas cases that decide whether a stock spin-off constitutes a “sale” under Texas securities laws, and while the federal case law seems to suggest a trend, it is far from unanimous on the issue. We need not answer this question because we resolve this valuation issue utilizing the sale of assets method.

     Like CenterPoint, Intervenors contend that the PUC acted outside of its statutory authority in determining fair market value under a method not prescribed in Section 39.262. They contend the PUC should have used the sale of assets method found in Section 39.262(h)(1).

This provision⁵⁷ states that if the utility sells all of its generation assets “in a bona fide third-party transaction under a competitive offering, the total net value realized from the sale establishes the market value of the generation assets sold.”

     During the true-up proceeding, under a signed agreement dated July 21, 2004, CenterPoint agreed to sell Genco, which held all of the joint applicants’ generating assets, to private equity firms. This agreement, styled the “Transaction Agreement,” was made known to the PUC and admitted into the administrative record. The Genco shares held by CenterPoint were sold for $45.25 per share and other shares sold for $47 per share. These prices are higher than the value of $42.425 per share chosen by the PUC under its extra-statutory method of determining fair market value. They are also higher than the price of $36.26 (plus a control premium of up to 10 percent) applicable to the PSV method. Intervenors urged the PUC to reject the use of the PSV method and to either deny any stranded cost recovery or to use the announced sale of Genco under the Transaction Agreement to determine stranded costs. They argue that the Transaction Agreement was a definitive agreement to sell the assets and was made months before the final Order issued on December 17, 2004. They contend that if the Transaction Agreement is used to determine the market value of the generation assets under the sale of assets method, the resultant market value is $253 million higher than the market value determined by the PUC, and the stranded cost recovery should be reduced by this same amount.

     Although acknowledging the existence of the Transaction Agreement, the PUC concluded that “[t]he announced sale of [Genco] does not constitute a sale of assets under PURA § 39.262(h)(1) because the sale is not final and there is not sufficient evidence in the record to establish under the statute that the sale is a bona fide third-party transaction under a competitive offering.”

     We agree with Intervenors and CenterPoint that the PUC should not have used the extra-statutory method it employed in calculating market value. Section 39.262(h) specifies the permitted methods for determining market value. We need not decide if the PSV method could have been used if Genco had not been sold to private investors under the Transaction Agreement. Given that Genco actually did sell under that Agreement, we hold that the PUC should have used the sale of assets method to determine market value. There is no dispute that the Transaction Agreement closed under its terms and Genco was sold to new owners.⁵⁸ Nor is there any dispute that CenterPoint was legally obliged to sell Genco under an agreement signed during the true-up proceeding. A November 9, 2004 CenterPoint press release, filed with the SEC, described the Transaction Agreement as a “definitive agreement.” Nor does the PUC posit any compelling reason it could not have simply delayed issuing the Order if it felt the need for the Transaction Agreement to fully close and fund before it could serve as the basis for calculating market value. Its own rules provide that it can for good cause extend the deadline for issuing the true-up order.⁵⁹

     On remand the Commission should use the sale of assets method to determine market value. For several reasons Chapter 39 compels the use of this method in this case. First, Chapter 39 recognizes and the PUC Order repeatedly acknowledged in both its findings of fact and conclusions of law that “[m]arket value is defined as the value the assets would have if bought and sold in a bona fide third-party transaction on the open market under PURA § 39.262(h).” Section 39.251(4) indeed defines market value using these exact words. While other methods are provided to determine market value indirectly, we think the actual sale of all the generation assets under the Transaction Agreement provides the best measure of market value.

     Second, since CenterPoint succeeded in selling Genco for an amount greater than the value of the company as measured by the PSV method or the extra-statutory method employed by the PUC, CenterPoint achieved a higher market value for the assets by completing the transaction than the market value derived from other methods. This higher market value translates to a lower measure of stranded costs, and is consistent with the utility’s duty under Section 39.252(d) to “pursue commercially reasonable means to reduce its potential stranded costs,” with Section 39.252(a)’s recognition that a utility should recover only “nonmitigable stranded costs,” and with Section 39.262(a)’s requirement that utilities “may not be permitted to overrecover stranded costs through the procedures established by this section.” CenterPoint reduced its stranded costs by executing and fully performing under the Transaction Agreement. The Commission should not ignore that agreement unless it had a sound factual or legal reason to do so, and none appears in this case. CenterPoint’s own chief executive testified that “we’re not trying to recover more money than we have on our books. And if we get it from the sale, as opposed to stranded investment, great. Matter of fact, I think that would help everybody.”

     Third, there is ample evidence in the record that the Transaction Agreement was indeed “a bona fide third-party transaction under a competitive offering” as specified in subsection (h)(1). A CenterPoint investment banker testified that the bidding process for Genco consisted of contacting 107 potential buyers; 90 expressed an interest in receiving a teaser letter; of those 90, confidentiality agreements were negotiated with 38; and 17 expressed an interest in bidding. Ten parties submitted “first round indicative interest proposals”; six of those ten had an opportunity to conduct a full due diligence review of Genco⁶⁰; and three submitted final round bids. Moreover, the fact that the process resulted in a price exceeding the stock price available under the alternative PSV method or the extra-statutory price used by the PUC compels the conclusion

that it was sufficiently “bona fide” and “competitive” to serve the purposes of Chapter 39. The court of appeals recognized that since “[t]he actual market value used by the Commission was lower than the price offered” in the Transaction Agreement, “the apparent purpose of the statute would seem to have been satisfied despite the lack of evidence showing sufficient competitive circumstances.”⁶¹ And the PUC stated in its Order that it considered the Transaction Agreement prices as “data points” in making its hybrid valuation.

     Fourth, as we read Chapter 39, it does not give any preference to the PSV method in this case simply because CenterPoint sought recovery of stranded costs under that method. We disagree with CenterPoint and the PUC to the extent that they argue the utility may choose the valuation method even when the method results in higher stranded costs than another readily available method. In these circumstances, the utility should not be allowed to increase its stranded costs by choosing the market valuation method that results in the smaller measure of market value. While Section 39.262(h) provides that “the affiliated power generation company shall quantify its stranded costs using one or more of the following methods,” other provisions make clear that the PUC ultimately determines stranded costs under Chapter 39 and the rates and charges needed to recoup them.⁶² The true-up procedure set out in Chapter 39 unmistakably assigns the Commission to act as an adjudicative body in “determining the amount of the utility’s stranded costs”⁶³ and issuing a “final order”⁶⁴ in the true-up proceeding, subject to judicial review. The PUC cannot forego use of the sale of assets method if it is otherwise readily available simply because CenterPoint prefers another method that would increase its stranded costs.

2. Net Book Value

a. Excess Mitigation Credits Paid to RERS

     The Act required utilities to undertake certain efforts to mitigate stranded costs in the 1998–2001 time frame. Section 39.254 directed utilities to use these efforts to reduce the book value of generation assets. Because stranded costs represent the difference between book value and market value, a reduction in the book value of generation assets had the effect of reducing stranded costs. The Act directed utilities to redirect depreciation expenses from transmission and distribution assets to generation assets, and to apply certain “excess earnings” to reduce the book value of generation assets.⁶⁵ The required mitigation is consistent with the principles that under Chapter 39 utilities “may not be permitted to overrecover stranded costs”⁶⁶ and are only allowed to recoup their “net, verifiable, nonmitigable stranded costs.”⁶⁷

     Prior to January 1, 2002, CenterPoint engaged in mitigation efforts by redirecting $841 million in depreciation and applying $1.13 billion in excess earnings to reduce the net book value (NBV) of its generation assets.

     Section 39.201(h) required the PUC to make a determination of estimated stranded costs based on the ECOM model using “updated company-specific inputs.” As noted above, Section 39.201 provided for interim rates during the 2002—2003 period, until the calculation of final stranded costs in the Section 39.262 true-up proceeding. The projections indicated that CenterPoint would have no stranded costs.⁶⁸ As a result, the PUC concluded that CenterPoint should cease mitigation efforts and should issue “excess mitigation credits” (EMCs) to all retail electric providers, including its affiliate RERS. The EMCs were deducted from the transmission and distribution charges that retail electric providers paid CenterPoint.

     The EMCs increased the NBV of CenterPoint’s generation assets on a dollar-for-dollar basis. However, the PUC concedes that the ECOM model assumptions underlying the 2001 finding that CenterPoint would have no stranded costs — the finding that the PUC used to justify

the EMCs — proved to be false. At the 2004 true-up proceeding, CenterPoint established that it had substantial stranded costs.

     In a mandamus proceeding, CenterPoint objected to the order requiring EMCs. In that proceeding, the PUC represented to this Court in its briefing and at oral argument that CenterPoint could recoup the EMC payments in the true-up proceeding now under review if CenterPoint was ultimately determined to have stranded costs. This Court denied mandamus relief,⁶⁹ although three justices would have reached the merits and held the EMCs unlawful as unauthorized by Chapter 39.⁷⁰ The PUC terminated EMCs on April 29, 2005. In September 2005, the Third Court of Appeals held that the PUC exceeded its authority in ordering EMCs.⁷¹

     In the true-up proceeding, CenterPoint contended all the EMCs it had already paid retailers could be recovered as stranded costs. CenterPoint argued it should not be penalized for following the PUC’s mistaken decision to order the EMCs. Intervenor City of Houston argued that CenterPoint should not be allowed to recover $385 million in EMCs paid to its retail affiliate, RERS. The PUC rejected this argument, finding “no legal basis for the recommended disallowance” and declining to “penalize CenterPoint for following a Commission order.” One commissioner dissented in part to the true-up Order, solely on this issue. The dissenting commissioner reasoned that the EMC payments to RERS amounted to “wealth transfers between two companies who knew they would be joint applicants in this true-up proceeding.”

     The trial court agreed with the PUC majority on this issue. The court of appeals, however, agreed with the dissenting commissioner and held that CenterPoint could not recoup the EMCs paid to RERS. Although the court of appeals assumed that CenterPoint and RERS are “completely separate entities,”⁷² it reasoned that “joint true-up applicants are prohibited from

overrecovering [stranded costs] as a single unit” by Section 39.262(a), which generally prohibits the overrecovery of stranded costs.⁷³

     We reverse the court of appeals and affirm the PUC on this issue. We need not decide whether the PUC could ever order excess mitigation credits. Even if the PUC theoretically possessed the legal authority to order EMCs, as a factual matter the PUC should not have done so in this case. The credits were ordered only because the ECOM model incorrectly predicted that CenterPoint would have no stranded costs. CenterPoint should recover whatever stranded costs it would have recovered if the EMCs had never been paid. EMCs paid to RERS had the same dollar-for-dollar impact on CenterPoint’s stranded costs as EMCs paid to unaffiliated retailers. Intervenors concede in their brief that as to EMC payments generally, “[f]or every dollar of EMC payments made, CenterPoint wrote up its NBV by one dollar, thus increasing potential stranded costs,” and that as to EMC payments to RERS in particular, “every dollar that CenterPoint paid to [RERS] resulted in CenterPoint writing up NBV by an equal amount.” In either case, the purpose of the EMCs was to increase the NBV of CenterPoint’s generation assets. The PUC did not err, therefore, in declining to adjust stranded costs by disregarding any of the EMCs paid by CenterPoint, and Intervenors fail to demonstrate a sound legal or factual basis for deducting the EMCs that were paid to RERS.

     We cannot agree with the court of appeals that the payment of EMCs to CenterPoint’s affiliate RERS merits special treatment. Chapter 39, in its express measures for recovering stranded costs and preventing the over-recovery of stranded costs, makes no distinction between affiliated and unaffiliated electric retailers that would warrant special treatment of the EMCs paid to RERs. The EMCs were simply an interim and ultimately unwarranted effort to reverse what the PUC perceived to be an over-recovery of stranded costs before the final true-up. There

is no express statutory provision allowing such credits, as the Third Court of Appeals noted in holding that Chapter 39 did not permit them. However, Section 39.201 does provide for the transmission and distribution utility to impose competition transition charges, based on interim estimates of stranded costs. Section 39.107(d) provides that these charges are made to “a customer’s retail electric provider.” These provisions make no exception or distinction for an affiliated retail electric provider. If the interim CTCs result in an over-recovery of stranded costs, Sections 39.201(l) and 39.262(c) provide for the transmission and distribution utility to refund stranded costs by reducing the CTCs or rates charged to retail providers. Again, in providing for these refunds Chapter 39 makes no statutory distinction between affiliated and unaffiliated retailers, and Chapter 39 indeed generally requires that such distinctions not be drawn when billing retail electric providers and their customers.⁷⁴

     Because the EMCs, by design, had the effect of increasing the NBV of generation assets regardless of whether they were directed to an affiliated or unaffiliated retail electric provider, and because such an increase in NBV correspondingly increased the amount of stranded costs under the relevant provisions of Chapter 39, the PUC did not err in refusing to reduce stranded costs by the portion of the EMCs paid to RERS.

b. The RRI Option

     CenterPoint and Intervenors complain that the PUC erred in its treatment of the “RRI Option.” Under the business separation plan, Reliant Energy, Inc. conveyed its generation assets to a subsidiary, Genco. Reliant Energy changed its name to CenterPoint. As discussed above, CenterPoint spun off approximately 19 percent of the shares of Genco to CenterPoint’s shareholders. CenterPoint also spun off a company named Reliant Resources, Inc. (RRI), by selling approximately 20 percent of the shares in RRI in an initial public offering, with

CenterPoint retaining about 80 percent of RRI.⁷⁵ RRI, in turn, owned the affiliated retail electric provider, RERS.

     As part of the business separation plan, which the PUC approved in a separate proceeding, RRI received an option to purchase CenterPoint’s shares in Genco. The Option expired on January 24, 2004. The Option price was set at the price for Genco that was to be determined at the true-up proceeding.

     Under its “primary holding” that rejected the use of the PSV method, the PUC employed an extra-statutory method that considered various “data points” for determining market value, as described above. Under this holding, the PUC concluded that its method of calculating fair market value accounted for the effect of the RRI Option. It therefore held under its primary holding that no adjustment to NBV relating to the RRI Option was necessary. The trial court and the court of appeals⁷⁶ affirmed this decision. Under its “alternative holding,” the PUC calculated true-up amounts assuming that the fair market value was properly calculated under the PSV method. As explained above, we conclude that neither the primary nor the alternative holding can be sustained, because the sale of assets method must be used — and not the extra-statutory method used in the primary holding or the PSV method used in the alternative holding.

     Intervenors complain that if the Court agrees with the primary holding rejecting the use of the PSV method, the PUC nevertheless erred in refusing to make a requested deduction from the NBV calculation to reflect the RRI Option. We need not reach this issue because we reject the primary holding. CenterPoint complains that if as it contends the PSV method must be used, the PUC erred in concluding under its alternative holding that an adjustment should be made to NBV to reflect the RRI option. Again, this issue is moot because we reject the use of the PSV method.

     However, Intervenors argue that “[r]egardless of how market value is determined,” an adjustment to NBV should be made for the RRI Option. Insofar as Intervenors argue an adjustment to NBV should be made for the RRI Option even if we agree with them that the sale of assets method should be used to determine market value,⁷⁷ we reject this argument.

     The PUC reasoned in its alternative holding that if it is required to use the PSV method of calculating market value, an adjustment should be made to NBV to reflect the RRI option. It made the adjustment under PURA Section 39.252(d), which provides:

An electric utility shall pursue commercially reasonable means to reduce its potential stranded costs, including good faith attempts to renegotiate above-cost fuel and purchased power contracts or the exercise of normal business practices to protect the value of its assets. The commission shall consider the utility’s efforts under this subsection when determining the amount of the utility’s stranded costs; provided, however, that nothing in this section authorizes the commission to substitute its judgment for a market valuation of generation assets determined under Sections 39.262(h) and (i).

Applying this provision, the PUC found that CenterPoint had received no compensation for the Option conveyed to RRI and that the Option placed restrictions on the management and operations of Genco that “were not commercially reasonable and did not represent normal business practices.”

     The PUC could consider the commercial reasonableness of the RRI Option in determining NBV. The PUC adjusted NBV in making the stranded cost determination, after finding that the conveyance of the Option was commercially unreasonable and did not represent normal business practices. Section 39.252(d) expressly directs the PUC, when making the stranded cost determination, to consider whether the utility used “commercially reasonable means” and “normal business practices” to reduce stranded costs. Since Section 39.252(d) bars the PUC from adjusting the market value component of stranded costs, it necessarily authorizes an adjustment to NBV, the other principal component of stranded costs.

     CenterPoint points out that in an earlier proceeding approving the business separation plan, the PUC noted that the Option “was an integral part” of the plan and “meets the separation requirements in PURA § 39.051.” Section 39.051, however, is the provision requiring the separation of the utility into three separate entities. The PUC’s conclusion that the business separation plan complied with this provision did not necessarily mean that CenterPoint had taken all reasonable efforts to minimize stranded costs under Section 39.252(d). Indeed, in the earlier proceeding the PUC expressly stated that it was not approving the RRI Option and other agreements that had not yet been finalized, and that its approval of the business separation plan “does not preclude a review in the 2004 true-up proceeding of whether [CenterPoint] pursued reasonable means to reduce its potential stranded costs.”

     The PUC considered evidence that the grant of the RRI option was not a normal business practice and had an adverse effect on the value of the generation assets. One of Genco’s own SEC filings conceded that the Option limited Genco’s ability to (1) merge with another company, (2) sell assets, (3) enter into long-term contracts, (4) engage in other businesses, (5) construct or acquire new plant or capacity, (6) engage in certain hedging activities, (7) encumber assets, (8) issue new securities, (9) pay special dividends, and (10) engage in certain transactions with affiliates. The report states that these restrictions “may adversely affect our ability to compete with companies that are not subject to similar restrictions.” The PUC also considered expert testimony that the Option was very unusual and did not represent normal business practices, gave RRI an incentive to reduce the value of Genco, was viewed negatively in the investment community, and limited Genco’s upside potential. The last point seems obvious, since RRI could derail an outside offer for Genco above the option price by exercising the Option, assuming that RRI had the funds. CenterPoint’s own financial advisor on the spinoff of

Genco acknowledged in a presentation that the “RRI option limits upside potential.” Michael Gorman, a witness for Intervenors, opined that the Option was unreasonable because it “essentially transferred significant control of [Genco] to RRI,” which then had “an incentive to minimize the value of” Genco, an incentive “diametrically opposite of [CenterPoint’s] obligation to protect the value of [Genco] and mitigate stranded costs.” Another witness for Intervenors, William Purcell, testified that the Option “gave RRI in effect the right of first refusal to buy” Genco, which “acted as a deterrent for [Genco or CenterPoint] to receive independent third party purchase bids or indications of interest — and, accordingly, was a drag on [Genco’s] stock price.”

     Gorman calculated the “intrinsic value” of the Option at approximately $330 million. He made further adjustments to this figure that the PUC rejected because they did not reflect the value the Option would have had in an arms-length transaction. The PUC valued the Option at $330,314,000 and determined the NBV should be reduced by this amount, and further grossed up this amount by an additional $177,874,089 to reflect accumulated deferred federal income taxes.

     Summarizing Gorman’s approach (and ignoring that the PUC only agreed with part of his methodology), the Option was priced at the market price to be determined under the PSV method, with an adjustment for a control premium of up to 10 percent to be determined by the PUC, as Section 39.262(h)(3) specifies. Gorman, however, believed that the actual control premium should be 30 percent, based on premiums over market prices paid in corporate acquisitions of similar companies. The difference between the 30 percent market premium and statutory premium was therefore 20 percent. Gorman determined that Genco’s future market value at the Option exercise date would approximately equal its book value of $2.9 billion, took 20 percent of that number ($580 million) to reflect the 20 percent difference in control

premiums, took 81 percent of that figure to reflect CenterPoint’s ownership in Genco ($469.8 million) and then discounted that value back to the date the Option was granted to arrive at $330 million as the Option’s “intrinsic value.”

     We have reviewed the administrative record and conclude that while substantial evidence supports the PUC’s conclusions that the Option was not commercially reasonable and for a time depressed the value of Genco stock, no adjustment should be made to NBV if the sale of assets method is used.

     The PUC apparently believed that the $330 million dollar figure derived from Gorman’s testimony reflected the negative impact of the Option on the market value of Genco. In a subheading on “Market Value,” the PUC found that “the entire [market] valuation process was not commercially reasonable,” and accordingly made an adjustment to NBV as required by Section 39.252(d). Further, the PUC explained that no adjustment to market value under its primary holding was needed because the stock price selected under that method, which included consideration of the market control premium, “takes into consideration the operational constraints placed upon [Genco] by the Option and the control premium.” When it turned to NBV, the PUC made an adjustment for the Option because of its effect on market value, reasoning that “Gorman calculated the amount of the option’s below-market pricing by taking the difference between the 10 percent maximum control premium RRI would have had to pay if it had exercised the option, and an average industry control premium of 30 percent, which RRI would likely have had to pay in a bona fide third-party transaction.” The PUC apparently concluded that the Option depressed the market value of Genco stock by $330 million, since under Gorman’s testimony, as analyzed and accepted in part by the PUC, this amount arguably

reflected the difference between what a third-party bid for the company might have brought and the ceiling on market value imposed by the Option.

     However, this analysis breaks down if the sale of assets method is used, because the actual sale of Genco took place months after the Option expired. The Option expired in January 2004, and the sale of Genco assets occurred in December 2004 and April 2005. There is no evidence that the Option had an impact on the value of the assets sold under the Transaction Agreement. As the PUC notes in its brief to this Court, “The announced future sales price for Genco occurred months after the Option expired. Moreover, the sale itself resolved the uncertainty about the future of the company. Thus, that price was unaffected by the unreasonableness of the expired Option.” The court of appeals similarly noted that the offer to purchase Genco in the Transaction Agreement “came several months after the option expired and after the restrictions placed upon Genco by the option had ended. As a result, any detrimental effect on Genco’s value resulting from the option should have dissipated.”⁷⁸ Further, there is some empirical support for concluding that the sale of Genco long after the Option expired was not affected by the Option, even if the market value of the company had earlier been depressed by it. As CenterPoint notes in a post-submission brief, “The $508 million deduction for the grossed-up Option under the alternate holding using the PSV method would reduce CenterPoint’s stranded-cost recovery by virtually the same amount — $511 million — as the sale-of-assets method Intervenors advocate.”

     Intervenors nevertheless argue that if CenterPoint had sold the Option instead of imprudently giving it away, the sale of that asset could have been used to reduce net book value and thus mitigate stranded costs. But this simply assumes that the Option could have been sold. There was no evidence that RERS or any third party was interested in purchasing the Option, nor

is there any evidence that any party would have actually paid the “intrinsic value” Gorman calculated if the Option had been put up for sale. On the contrary, CenterPoint offered evidence of “extremely difficult market conditions” at the time of the business separation that included the Option, which necessitated the spinoff of Genco to existing CenterPoint shareholders in lieu of an IPO. In their briefing to this Court, Intervenors criticize CenterPoint for its decision to go forward with the business separation at a time when “the wholesale energy markets were in disarray as a result of action undertaken by Enron in California. Nearly all generation company stocks had lost significant value.”

     Accordingly, on remand, the PUC should not make an adjustment to NBV for the RRI Option in conjunction with its use of the sale of assets method to determine market value.

c. Depreciation

     CenterPoint complains that the PUC erred in reducing stranded costs attributable to depreciation on generation assets. The PUC reduced CenterPoint’s stranded costs by reducing the NBV of its generation assets by approximately $378 million, a figure representing depreciation on those assets for years 2002 and 2003. The PUC reasoned that this adjustment was necessary to prevent an excessive recovery of stranded costs. It noted that under Section 39.262(a), a utility “may not be permitted to overrecover stranded costs through the procedures established by this section,” which governs the final stranded cost and capacity auction true-ups.

     Specifically, the PUC found it inappropriate

for the joint applicants to recover the remaining book value of generation assets through stranded-costs recovery while at the same time being guaranteed a level of revenue through the capacity auction that, by design, covers a portion of this same book value. To allow recovery of a portion of the book value through both stranded-costs recovery and the capacity auction true-up is, plain and simple, a double recovery of this portion of book value, and therefore, an overrecovery of stranded costs.

The PUC therefore held that an “adjustment” to NBV must be made in the stranded cost calculation to prevent the perceived “double recovery.” The trial court and the court of appeals⁷⁹ agreed with this result.

     We agree with CenterPoint that the Commission misread the relevant provisions of Chapter 39. As explained above, Chapter 39 requires both a stranded cost true-up and a capacity auction true-up. Nothing in the world of business or accounting requires both true-ups to transition a regulated industry to a more competitive market. But the Legislature provided for both and requires both. As we noted in our earlier CenterPoint decision, “the Legislature chose not to include the capacity auction true-up amount in its definition of stranded costs or to incorporate it into the methods it prescribes for calculating stranded costs.”⁸⁰ The capacity auction true-up amount does not depend on the amount or existence of stranded costs, but on a specific formula set out in Section 39.262(d) and the Commission’s rules thereunder that can result in a positive or negative number. “Stranded costs” is a different matter and a term of art defined by Chapter 39. In this case it essentially consists of the difference between the book value of the generation assets “established as of December 31, 2001” under Section 39.251(7)⁸¹ and the market value of those assets, which are determined under the methods set out in Section 39.262. The PUC conceded in its Order that “stranded-costs recovery requires that book value be determined as of December 31, 2001.”

     On the other hand, as we have previously explained, the capacity auction true-up “guarantees consumers and power companies that the power company will receive no more and no less than a margin predetermined by the PUC in 2001 when the ECOM model was run in compliance with section 39.201.”⁸² This margin is determined by taking the difference between projected power sales and actual power prices “obtained through the capacity auctions.”⁸³

     Critically, the capacity auction true-up amount is determined for the years 2002 and 2003. We have so stated, explaining that this true-up consists of “the difference between the price of power obtained through the capacity auctions and the power cost projections that were employed in the 2001 ECOM model for the years 2002 and 2003.”⁸⁴ The PUC likewise recognized in its Order that the capacity auction true-up “ensures that an affiliated [power-generation company] with significant investment in generation assets will recover the power costs the PUC had projected, in the 2001 ECOM model, would be recovered for the 2002–2003 period.” Its Substantive Rule 25.263(i) also defines precisely the formula for calculating the capacity auction true-up, based on “the difference between the price of power obtained through 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.”⁸⁵

     The PUC apparently reasoned that the capacity auction true-up is based on the ECOM market revenue projections used to set interim rates in the 2001 Section 39.201 proceeding. As discussed further below, we agree with the Order that these revenue projections “assumed the continuation of regulation.” Under traditional rate regulation, rates are set to allow the utility to recover a reasonable return on its capital investments.⁸⁶ Since these capital assets are depreciated over time on the books,⁸⁷ depreciation affects the NBV of the utility. The PUC apparently further reasoned that stranded costs must be based on book value as of the end of 2001, and this value includes generating plant assets that have not yet been depreciated further in years 2002 and 2003. Since the capacity auction true-up is based on revenue projections under rates intended to recoup investments in plants that are further depreciated in 2002 and 2003, the PUC apparently

reasoned that the capacity auction true-up and the stranded costs true-up allowed for a “double recovery” of a portion of book value.

     We think the Commission erred in its analysis. Any utility will eventually retire all of its stranded costs, or any other capital investment or portion thereof, if it survives deregulation and continues to operate at a profit for a sufficient period of time. “Depreciation” is a general term referring to the accounting practice of spreading an asset’s cost over the projected useful life of the asset or some other period.⁸⁸ In this case, however, “stranded costs” is a purely legal term that depends entirely on how it is defined by statute. Under Chapter 39, stranded costs depend on book value as of the end of 2001. We agree with CenterPoint that “[i]t is indisputable that the NBV of generation assets as of December 31, 2001 would not reflect a reduction for depreciation attributable to 2002 and 2003.” An “adjustment” to stranded costs to reflect further depreciation of power plant assets in 2002 and 2003 is not permitted because the PUC is not allowed to alter the statutory definition of stranded costs. The PUC’s view that the adjustment is necessary to prevent a “double recovery” of stranded costs necessarily depends on its conclusion, in direct contravention of the statute, that stranded costs should be redefined to incorporate further depreciation of generation assets in 2002 and 2003, thereby reducing NBV and correspondingly reducing stranded costs. Statutory stranded costs always depend on the distance between two values — NBV and market value — both of which constantly change over time.⁸⁹ The PUC is constrained to determine those values as of the time periods selected by the Legislature.

     Intervenors contend in their brief: “The problem the Commission addressed in the true-up award was that because NBV was frozen as of December 31, 2001, it could not be reduced by the $378 million in depreciation expense that CenterPoint indisputably collected through the capacity auction true-up as a contribution to its fixed costs.” The problem with this analysis is

that, by statutory definition, the NBV component of stranded costs is frozen as of December 31, 2001, and the PUC’s adjustment effectively moved that date in violation of the statute.

d. Construction Work in Progress

     Intervenors argue that the Commission erred in not requiring CenterPoint to meet ratemaking requirements for inclusion of construction work in progress (CWIP) in NBV. The court of appeals⁹⁰ and the district court agreed with the PUC on this issue, as do we.

     Inclusion of CWIP increased stranded costs by about $110 million. The PUC’s Substantive Rule 25.263(g)(2)(A)⁹¹ provides that the NBV of generation assets includes “generation-related construction work in progress.”

     In addressing Intervenors’ arguments, the PUC noted that “[n]o party claimed accounting mistakes or imprudence on any specific project included in CWIP,” and found “there is no evidence of any accounting discrepancies or any failure to follow GAAP in connection with these balances.” It recognized that under PURA § 36.054, applicable to general ratemaking, CWIP can be included in the rate base only if “(1) necessary for the utility’s financial integrity and (2) not inefficiently or imprudently planned or managed.” The PUC, however, declined Intervenors’ request to apply these additional requirements because Chapter 39 is concerned with the unique matter of stranded costs measured by the difference between the NBV of generation assets and market value, while general ratemaking applies ratemaking standards to determine what amounts of book value may be included in the rate base and the appropriate rate of return on that rate base. It also noted that “[o]ne significant difference between a traditional rate case and this proceeding . . . is that whereas under traditional regulation a utility is allowed to file rate cases on a recurring basis into the future, this proceeding is strictly a one-time phenomenon.” In other words, CWIP can be recovered under Section 36.054 in the exceptional case if the

requirements of that provision are met; otherwise, the utility can simply seek recovery for the construction project in a future rate case. There is no analogous recurring procedure for the recovery of stranded costs.

     Intervenors argue that under Section 39.260(a), “[t]he definition and identification of invested capital and other terms . . . that affect the net book value of generation assets . . . shall be treated in accordance with generally accepted accounting principles as modified by regulatory accounting rules generally applicable to utilities.” The PUC did not agree that in the calculation of stranded costs this provision requires the application of Section 36.054’s special rules regarding CWIP. It noted that Section 39.260(a) did not expressly incorporate those particular standards. The PUC further reasoned:

[U]nlike a traditional rate case, there will be no future opportunity for the joint applicants to recover the CWIP costs that are subsequently moved into EPS [electric plant in service]. Second, including CWIP in NBV of generating assets is necessary for an apples-to-apples comparison of book value and market value, because the market value of CWIP is reflected in TGN’s stock price. These additional arguments by CenterPoint further amplify the difference between a traditional rate case and this proceeding. For [these and other reasons], the joint applicants do not need to satisfy rate-case requirements for including CWIP in NBV in this proceeding. Accordingly, the Commission declines to exclude the $109,966,000 for nonenvironmental CWIP from NBV.

We cannot say the Commission’s analysis is legally or factually flawed, and we defer to the Commission on this technical issue.

C. Capacity Auction True-Up

1. Capacity Auction Price

     CenterPoint complains that the court of appeals and the PUC erred in concluding that an adjustment to the capacity auction price should be made in calculating the capacity auction true-up under Section 39.262(d). We agree with CenterPoint.

     Genco became the affiliated power-generation company of CenterPoint in 2001. Section 39.153 required Genco to auction “at least 60 days before [January 1, 2002], entitlements to at least 15 percent of [its] Texas jurisdictional installed generation capacity.”⁹² The capacity auctions thus assured that power was available to new competitors in the deregulated retail electricity market. The PUC recognized in its Substantive Rule 25.381(b) that the purpose of the capacity auctions is to “promote competitiveness in the wholesale market through increased availability of generation and increased liquidity.”⁹³

     Under Section 39.201, the PUC approved rates intended to cover expected stranded costs and other charges. Stranded costs were estimated based on “the ECOM administrative model”⁹⁴ the PUC ran in 2001.

     Section 39.262(d)(2) required a capacity auction true-up at the final true-up proceeding. Section 39.262(d) states:

The affiliated power generation company shall reconcile, and either credit or bill to the transmission and distribution utility, the net sum of:

(1) the former electric utility’s final fuel balance determined under Section 39.202(c); and

(2) any difference between the price of power obtained through the capacity auctions under Sections 39.153 and 39.156 and the power cost projections that were employed for the same time period in the ECOM model to estimate stranded costs in the proceeding under Section 39.201.

The final fuel balance of subpart (1), which is summed with the capacity auction true-up amount, is not at issue in this appeal. Under subpart (2), the power-generation company (Genco) bills the transmission and distribution company (CenterPoint) if revenues as determined by the capacity auction price are less than the revenues predicted by the ECOM model. The amount billed to the transmission and distribution company can then be recovered from consumers through adjustment of the nonbypassable delivery rates.⁹⁵ Under the formula used by the PUC in its Substantive Rule 25.263(i),⁹⁶

(ECOM market revenues — ECOM fuel costs)

less

(market revenues (as determined from capacity auctions) — actual fuel costs)

equals

capacity auction true-up

Under this formula, market revenues “as determined from capacity auctions” is a term of art and is a proxy for actual market revenues of the utility during the relevant period. Under the Rule, market revenues consist of the “capacity auction price x total 2002 and 2003 busbar sales.” “Total busbar sales” refers to the total quantity of power generated for sale by Genco. The formula deems all busbar sales as being made at the average capacity auction price, since Rule 25.263(i)(1)(C) defines the capacity auction price as the affiliated power-generation company’s “total capacity auction revenues derived from the capacity auctions conducted for the years 2002 and 2003 divided by that [company’s] total [megawatt hour] sales of capacity auction products for the years 2002 and 2003.”

     In its Order the PUC stated that “the purpose of the capacity auction true-up is to ensure that utilities receive the margins predicted in the ECOM model which assumed the continuation of regulation.” We agree, having previously noted that the capacity auction true-up “guarantees consumers and power companies that the power company will receive no more and no less than a margin predetermined by the Commission in 2001 when the ECOM model was run in compliance with section 39.201.”⁹⁷ We further explained the underlying rationale for the capacity auction true-up as follows:

The Legislature recognized that on the first day of deregulation, January 1, 2002, there was no way to validly quantify stranded costs, if any, because a market for electricity, both wholesale and retail, would need time to develop, and there would be interim distortions and fluctuations, perhaps severe ones. The

Legislature was also concerned that distortions and fluctuations in the market price of power during the first two years of deregulation could harm consumers and generation companies alike. The Legislature accordingly designed the capacity auction true-up proceeding because of the likelihood that no stable market would exist until up to two years after the first day of deregulation.⁹⁸

     Sections 39.153(e) and (f) required the PUC to adopt rules governing the statutory capacity auctions. The PUC adopted rules governing the auctions in many particulars, covering the time of sale, the type of products sold, and the terms of the sales.⁹⁹ The PUC required Genco to sell entitlements to its generation capacity in four product categories: baseload, gas-intermediate, gas-cyclic, and gas-peaking. Due to variations of market demand, these rules contained a “safe-harbor” provision deeming the 15-percent requirement met if the affiliated power-generation company “offered products in a product category (for example, gas-intermediate) and successfully sold, at least, all of the entitlements offered in one particular month, in that product category.”¹⁰⁰ If demand was insufficient to meet even this provision, the company was to make “a proposal to the commission” to modify the auction process, prices, or products.¹⁰¹

     Genco offered the required 15 percent of its capacity in the four product categories in its statutory capacity auctions and sold all the entitlements for at least one month in 2002 and 2003 for each product category except for gas-intermediate in 2003. Genco made proposals to facilitate the auction for gas-intermediate, two of which were approved by the PUC, that included cut-rate pricing for as little as one cent for kilowatt-month, but Genco was ultimately unsuccessful in meeting the safe-harbor requirement that it sell all entitlements to gas-intermediate for at least one month in 2003.

     The Commission found that Genco had sold only 65 percent of the capacity it was required to sell under the 15 percent requirement of Section 39.153, and less than half the gas-

intermediate capacity required of Commission rules. However, Genco correctly points out that it would have complied with the safe harbor provisions if it had succeeded in selling additional entitlements in one product category for $5,250. Based on this failure, the PUC concluded that Genco had not complied with PURA Section 39.153(a) and therefore its formula under Rule 25.263(i) could not be used. It then proceeded to consider an alternative “proper method” for determining the capacity auction true-up amount, one that in the eyes of the PUC would avoid “the bias created by the failure of [Genco] to auction a full 15 percent of its auction products.”¹⁰²

     The PUC considered various proposals but adopted the approach of an Intervenor witness, Dennis Goins, who proposed “that the capacity auction price used in the formula should be defined as the average price of all capacity products sold in the PUC and private auctions.” Under this formula, the capacity auction true-up amount was reduced by $439,744,218. The district court reversed the PUC on this issue, but the court of appeals agreed with the PUC and reinstated this disallowance.¹⁰³

     We conclude that the court of appeals and the PUC erred in reducing the capacity auction true-up amount as described above. The capacity auction true-up amount should not be reduced by over $400 million because Genco was unable to sell $5000 worth of one subcategory of its generation capacity at auction. While Section 39.153 specifies that the utility sell 15 percent of its generating capacity at auction, the record indicates that Genco made a good faith effort to comply with this statute and was simply unable to sell by auction, at any price, the amount of one product category required by PUC rules. It points out that no utility was able to sell all its gas-intermediate entitlements for even one month in 2003. We avoid statutory constructions that impose an impossible condition.¹⁰⁴

     Further, Section 39.262 does not state that the capacity auction price specified therein should be ignored because of a trivial noncompliance with rules promulgated under Section 39.153. Nothing in Chapter 39 requires such a result. In the portion of the Order discussing the issue, the PUC conceded, “Neither PURA nor the Commission’s rules specify what happens if a company fails to meet the 15 percent sales requirement or the safe-harbor provisions.” The capacity auction true-up in Section 39.262 is not conditioned on compliance with the requirement, under the separate statute governing the capacity auctions themselves, that the utility succeed in auctioning 15 percent of its generating capacity. As discussed above, the two sections address different legislative purposes. The capacity auctions themselves were intended to provide a supply of power to new entrants in the retail electric market, while the capacity auction true-up was intended to assure that the original utilities recovered “a margin predetermined by the Commission in 2001.”¹⁰⁵

     Section 39.262 does, however, expressly require the use of the “price of power obtained through the capacity auctions under Sections 39.153 and 39.156.”¹⁰⁶ Goins conceded that CenterPoint used the statutory price as spelled out in Section 39.262 and Rule 25.263(i) in making its capacity auction true-up request. However, he believed that the statutory formula created a “downward bias” if the auction was unsuccessful in selling a relatively higher-priced product such as gas-intermediate. He therefore proposed following Rule 25.263(i) “with one major modification.” He recommended calculating the capacity auction price based on the average prices of products sold in the PUC capacity auctions as well as prices obtained in so-called “TGN auctions.” The TGN auctions were private auctions that did not have to comply with PUC rules.¹⁰⁷ Notably RERS, Genco’s affiliated retail electric provider and its biggest customer, could participate in these auctions, in direct violation of the letter of Section 39.153¹⁰⁸

and its essential purpose in making capacity available to new competitors. Not surprisingly, the prices obtained in the TGN auctions were sometimes higher than those obtained in the Chapter 39 auctions, since an additional, established competitor was allowed to bid. The chief executive of Genco testified that since RERS “had the majority of the load in the Houston area . . . there was a lot more competition, I believe, in the TGN than there was in the PUC auction.” Goins agreed that the TGN auctions were “somewhat more successful” in selling products because RERS was eligible to participate in those auctions. Goins’s “major modification” was inconsistent with Chapter 39 and the PUC should not have adopted it.

     Section 39.262 unambiguously specifies that the statutory capacity auction price, not some other blended price the PUC finds more appropriate, must be used in calculating the capacity auction true-up amount. The PUC’s Rule 25.263(i), the validity of which is not challenged by any party,¹⁰⁹ provides the correct method for calculating the capacity auction price, and it should have been used. Parties, experts, and the PUC can look to the formula derived from Section 39.262(d)(2) and question why it chooses the capacity auction price instead of some other price in calculating market revenues, why sales in 2002 and 2003 are used instead of sales in some other time period, or indeed why a capacity auction true-up is necessary at all in light of other provisions providing for the recovery of stranded costs. But the statute is clear enough and we apply it as written.¹¹⁰

2. Carrying Costs on Capacity Auction True-Up

     Intervenors complain that the PUC erred in allowing CenterPoint to recover $168 million in interest on the capacity auction true-up award. The trial court and court of appeals¹¹¹ agreed with the PUC on this issue, as do we.

     In Texas Industrial Energy Consumers v. CenterPoint Houston Electric, LLC, we recently held that interest on the capacity auction true-up and other non-stranded costs awarded in a Section 39.262 true-up proceeding was recoverable.¹¹² We upheld the validity of the portion of PUC Rule 25.263(l)(3) providing for “carrying costs on the true-up balance,” even though in CenterPoint Energy we had invalidated another portion of the Rule specifying the date at which interest begins to accrue.¹¹³ We noted that “invalidating the whole rule and barring any recovery of interest whatsoever would contradict our view in CenterPoint Energy ‘that the Legislature intended electric utilities to recover carrying costs on stranded costs to compensate for the financial costs incurred during the stranded cost recovery period,’ consistent with the prior ratemaking principle that ‘carrying costs on investments in generation plants were included in rates.’”¹¹⁴

     While, as discussed above, general ratemaking principles need not always be applied to a Chapter 39 true-up proceeding, we again see no valid reason the PUC cannot provide for interest on true-up balances under Rule 25.263(l)(3), including interest on the capacity auction true-up balance. The parties in TIEC challenged the amount of interest specified under Rule 25.263(l)(3), and did not necessarily question the authority vel non of the PUC to award interest, but in today’s case we see no error in the PUC’s decision to award interest on the capacity auction true-up to reflect the time value of money. Since, as discussed above, this true-up award is designed to assure the recovery of revenues projected in the ECOM model for 2002 and 2003, the PUC reasonably concluded that a full recovery of this amount must include interest to reflect the time value of money. It correctly found in its Order: “Awarding the time value of the capacity auction true-up award puts the joint applicants in the same economic position they would have been in had they received this amount in 2002 and 2003.” Intervenors provide no persuasive reason that

interest on the capacity auction true-up cannot be awarded in this case as in other cases where utilities are allowed to recover costs with interest.

III. Conclusion

     We affirm the court of appeals’ judgment in part and reverse it in part. We remand this case to the Commission for further proceedings consistent with this decision.

OPINION DELIVERED: March 18, 2010

The terms “sale” or “offer for sale” or “sell” shall include every disposition, or attempt to dispose of a security for value. The term “sale” means and includes contracts and agreements whereby securities are sold, traded or exchanged for money, property or other things of value, or any transfer or agreement to transfer, in trust or otherwise.

     As with the federal securities statutes, the Texas definition of “sale” of a security is broad, including “every disposition” and “any transfer or agreement to transfer.” See Tex. Capital Sec., Inc. v. Sandefer, 58 S.W.3d 760, 775 (Tex. App.—Houston [1st Dist.] 2001, pet. denied) (“[The Texas Legislature] broadly defined ‘sale,’ ‘sell,’ and ‘security.’”); 11 WILLIAM V. DORSANEO & PETER WINSHIP, TEXAS LITIGATION GUIDE § 171.03[1][a] (interpreting the statute as including a “for value” requirement). No Texas court has addressed whether a stock distribution though a stock dividend constitutes a “sale,” although a court has said that the exercise of a stock option will constitute a “sale” under the Texas Act. See Key Energy Servs., Inc. v. Eustace, 290 S.W.3d 332, 342–43 (Tex. App.—Eastland 2009, no pet.) (“[T]he grant of an employee stock option on a covered security is a sale of that security.”).

     The Securities Act of 1933 defines “sale” of a security as including “every contract of sale or disposition of a security or interest in a security, for value.” 15 U.S.C § 77b(a)(3). “The term ‘offer to sell’, ‘offer for sale’, or ‘offer’ shall include every attempt or offer to dispose of, or solicitation of an offer to buy, a security or interest in a security, for value.” Id. The Securities Exchange Act of 1934 defines “sale” of a security to include “any contract to sell or otherwise dispose of.” Id. § 78c(a)(14).

     Some federal courts have determined that a spin-off through a stock distribution constitutes a “sale” under both the 1933 Securities Act and the 1934 Securities Exchange Act. Int’l Controls Corp. v. Vesco, 490 F.2d 1334, 1343—44 (2d Cir. 1974) (discussing 1934 Act); S.E.C. v. Datronics Eng’rs, Inc., 490 F.2d 250, 253—54 (4th Cir. 1973) (discussing 1933 Act); S.E.C. v. Harwyn Indus. Corp., 326 F. Supp. 943, 953—54 (S.D.N.Y. 1971) (same); see also S.E.C. v. Sierra Brokerage Servs. Inc., 608 F. Supp. 2d 923, 940—44 (S.D. Ohio 2009) (considering “gifts” of securities to former directors and shareholders as “sales” where defendant schemed to create public companies without registration and then later transfer control for a fee). Other federal circuits have held to the contrary. The Fifth Circuit has held that an asset-for-stock exchange is not a “sale” within the meaning of Section 10(b) of the 1934 Act where the parties are not at arms length. Rathborne v. Rathborne, 683 F.2d 914, 918 (5th Cir. 1982) (“[A] transfer of securities from a wholly controlled subsidiary to its parent or between two corporations wholly controlled by a third does not amount to a statutory purchase or sale.”); see also Blau v. Mission Corp., 212 F.2d 77, 80 (2d Cir. 1954) (determining stock-exchanges between corporations with shared ownership were not “sales” within the meaning of Section 16(b) of the 1934 Act because the transaction was “a mere transfer between corporate pockets”).

Several more recent cases declined to characterize spin-offs as sales, often considering the earlier cases’ reasoning as a means to prevent backdoor IPOs without registration and making information available to the public. See Isquith v. Caremark Int’l, Inc., No. 94 C 5534, 1997 WL 162881, at *6 (N.D. Ill. March 26, 1997) (distinguishing Harwyn and Datronics as SEC enforcement actions, as opposed to shareholder suits), aff’d, 136 F.3d 531 (7th Cir. 1998); In re Union Carbide Corp. Consumer Prods. Bus. Sec. Litig., 676 F. Supp. 458, 475 (S.D.N.Y. 1987) (noting that outside Harwyn and its progeny, “[t]here has been no other case demonstrating acceptance of such a broad view of ‘value’”); Fed. Ins. Co. v. Campbell Soup Co., No. Civ.A. 131-04, 2004 WL 1631405, at *9—13 (N.J. Sup. Ct. Law Div. July 2, 2004) (“Notwithstanding the[] broad statutory definition[], however, courts have still found that spin-offs generally do not constitute a sale of securities. . . . [T]his court finds that in all of the cases cited, the courts which did find a purchase and sale were struggling to do so in order to insure a remedy for a wrong . . . or the mischief of an unsympathetic defendant . . . would not go without a federal remedy.”); see also In re Adelphia Commc’ns Corp. Sec. & Derivatives Litig., 398 F. Supp. 2d 244, 260 (S.D.N.Y. 2005).

     In 1997, the SEC issued a Staff Legal Bulletin No. 4, which attempted to explain the SEC’s view of spin-offs in regards to registration under the 1933 Act. SEC Staff Legal Bulletin No. 4 (Sept. 16, 1997). The Bulletin begins by stating the general requirement that a subsidiary must register if the spin-off is a “sale.” Id. The subsidiary does not have to register, and thus it logically follows no “sale” occurs, if: (1) the parent shareholders do not provide consideration for the spun-off shares; (2) the spin-off is pro-rata to the parent shareholders; (3) the parent provides adequate information about the spin-off and the subsidiary to its shareholders and the trading markets; (4) the parent has a valid business purpose for the spin-off; and (5) if the parent spins off “restricted securities,” it held those securities for at least two years. Id.

Sale of Assets. If, at any time after December 31, 1999, an electric utility or its affiliated power generation company has sold some or all of its generation assets, which sale shall include all generating assets associated with each generating plant that is sold, in a bona fide third-party transaction under a competitive offering, the total net value realized from the sale establishes the market value of the generation assets sold. If not all assets are sold, the market value of the remaining generation assets shall be established by one or more of the other methods in this section.

had the opportunity to meet the management team. They had the opportunity to visit the sites. They had the opportunity to participate and review all the data in the data room. They had the opportunity to ask detailed questions, and they did ask lots of detailed questions. And they basically had the opportunity to do as much due diligence as needed to get to a final round proposal.