exv99w1
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
|
|
|
| 1 |
|
This overview closely tracks the overview set out in our recent decision
in a related Chapter 39 case, Texas Industrial Energy Consumers v. CenterPoint Energy Houston
Electric, LLC, 324 S.W.3d 95, 97–100 (Tex. 2010). |
| |
| 2 |
|
Act of May 27, 1999, 76th Leg., R.S., ch. 405, 1999 Tex. Gen. Laws
2543–2625; see also City of Corpus Christi v. Pub. Util. Comm’n, 51 S.W.3d 231, 237 (Tex. 2001). |
| |
| 3 |
|
TEX. UTIL. CODE § 39.001(a). See also City of Corpus Christi, 51
S.W.3d at 237. |
| |
| 4 |
|
TEX. UTIL. CODE § 39.051(b). |
| |
| 5 |
|
Id. § 39.102(a). |
| |
| 6 |
|
See id. §§ 39.201–.205; In re TXU Elec. Co, 67 S.W.3d 130, 132
(Tex. 2001) (Phillips, C.J., concurring) (“Because the generating companies and retail electric
providers must use the existing power lines to move electricity from the plant to the retail
customer’s home or business, the transmission and delivery companies will remain regulated
monopolies.”). |
| |
| 7 |
|
CenterPoint Energy, Inc. v. Pub. Util. Comm’n, 143 S.W.3d 81, 82
(Tex. 2004). |
| |
| 8 |
|
City of Corpus Christi, 51 S.W.3d at 237–38; see also TEX. UTIL.
CODE §§ 39.001(b)(2), .251(7), .252(a). |
| |
| 9 |
|
TEX. UTIL. CODE § 39.052. |
| |
| 10 |
|
Id. § 39.201(a), (b). |
| |
| 11 |
|
Id. § 39.201(d). |
|
|
|
| 12 |
|
Id. § 39.201(b), (d), (g). |
| |
| 13 |
|
City of Corpus Christi, 51 S.W.3d at 238 (citing TEX. UTIL. CODE §
39.252). |
| |
| 14 |
|
TEX. UTIL. CODE § 39.201(h). |
| |
| 15 |
|
See id. § 39.262(i). “ECOM” stands for excess costs over market,
see id. § 39.254, and is another term for stranded costs. The PUC began using an ECOM computer
model in 1996. See In re TXU Elec. Co., 67 S.W.3d 130, 160 (Tex. 2001) (Hecht, J., dissenting). The
PUC presented a 1998 ECOM Report to the Legislature. See id.; TEX. UTIL. CODE §§ 39.254, .262(i). |
| |
| 16 |
|
See TEX. UTIL. CODE §§ 39.201(i), .262(c), .301. |
| |
| 17 |
|
Id. § 39.201(i). |
| |
| 18 |
|
CenterPoint Energy, 143 S.W.3d at 91. |
| |
| 19 |
|
TEX. UTIL. CODE § 39.262(c). |
| |
| 20 |
|
Id. § 39.201(l), .262(c). |
| |
| 21 |
|
Id. § 39.201(l). |
| |
| 22 |
|
Id. §§ 39.201(l), .262(c). Alternatively, stranded costs may be
securitized. Id. § 39.262(c). |
| |
| 23 |
|
Id. § 39.262(g). |
| |
| 24 |
|
Id. § 39.202(a). |
| |
| 25 |
|
Id. § 39.202(c). |
| |
| 26 |
|
Id. § 39.153(a). |
| |
| 27 |
|
Id. § 39.153(b). |
| |
| 28 |
|
Id. §§ 39.202(c), .262(d)(1). |
| |
| 29 |
|
Id. § 39.262(d)(2). |
| |
| 30 |
|
Id. § 39.262(e). This credit is subject to a cap. Id. |
| |
| 31 |
|
More specifically, under the business separation plan, Reliant
Energy, Inc. survives as CenterPoint Energy, Inc., a publicly traded holding company. CenterPoint
Energy, Inc. owns CenterPoint Energy Houston Electric, LLC, the transmission and distribution
utility. |
| |
| 32 |
|
More specifically and as discussed below, under the business
separation plan, Reliant Energy, Inc. created Reliant Resources, Inc., a publicly traded company
that became the parent of Reliant Energy Retail Services, LLC, the retail electric provider. |
|
|
|
| 33 |
|
CenterPoint and Genco remain petitioners to this appeal, and for
convenience are sometimes referred to collectively as CenterPoint. |
| |
| 34 |
|
Application of CenterPoint Energy Houston Electric, LLC, Reliant
Energy Retail Servs., LLC, and Tex. Genco, LP to Determine Stranded Costs and Other True-Up
Balances Pursuant to PURA § 39.262, PUC Docket No. 29526 (Dec. 17, 2004) (Order), available at
http://interchange.puc.state.tx.us (item no. 2286). |
| |
| 35 |
|
252 S.W.3d 1. |
| |
| 36 |
|
Issues determined in the Order pertinent to the retail electric
provider, RERS, such as the retail clawback, are not appealed to this Court, and hence that entity
is not a party. |
| |
| 37 |
|
Gulf Coast Coalition of Cities, Houston Council for Health and
Education, City of Houston and Coalition of Cities, and Texas Industrial Energy Consumers. |
| |
| 38 |
|
TEX. UTIL. CODE § 15.001. |
| |
| 39 |
|
Id. § 39.262(j). |
| |
| 40 |
|
TEX. GOV’T CODE § 2001.172. |
| |
| 41 |
|
Mireles v. Tex. Dep’t of Pub. Safety, 9 S.W.3d 128, 131 (Tex.
1999). |
| |
| 42 |
|
Section 2001.174(2) authorizes the court to reverse the agency
decision if it is “in violation of a constitutional or statutory provision,” “in excess of the
agency’s statutory authority,” or “affected by other error of law.” |
| |
| 43 |
|
TEX. GOV’T CODE § 2001.174(2)(F). |
| |
| 44 |
|
First Am. Title Ins. Co. v. Combs, 258 S.W.3d 627, 631 (Tex. 2008). |
| |
| 45 |
|
Id. at 632. |
| |
| 46 |
|
City of Austin v. Sw. Bell Tel. Co., 92 S.W.3d 434, 441 (Tex.
2002). |
| |
| 47 |
|
More precisely, Section 39.251(7) defines stranded costs as
the positive excess of the net book value of generation assets over the market value
of the assets, taking into account all of the electric utility’s generation assets,
any above market purchased power costs, and any deferred debit related to a
utility’s discontinuance of the application of Statement of Financial Accounting
Standards No. 71 (“Accounting for the Effects of Certain Types of Regulation”) for
generation-related assets if required by the provisions of this chapter. For
purposes of Section 39.262, book value shall be established as of December 31, 2001,
or the date a market value is established through a market valuation method under
Section 39.262(h), whichever is earlier, and shall include stranded costs incurred
under Section 39.263. |
| |
| |
|
Section 39.263 pertains to certain environmental cleanup costs. |
| |
| 48 |
|
A fifth method, found in Section 39.262(i), pertains to the
valuation of certain nuclear assets. |
| |
| 49 |
|
TEX. UTIL. CODE § 39.262(h)(3). |
| |
| 50 |
|
Id. |
|
|
|
| 51 |
|
Id. |
| |
| 52 |
|
252 S.W.3d at 17. |
| |
| 53 |
|
See 26 U.S.C. § 1504. According to CenterPoint, one advantage of a
consolidated return is that the parent can offset one subsidiary’s losses against another
subsidiary’s gains. |
| |
| 54 |
|
252 S.W.3d at 16–34. |
| |
| 55 |
|
The SEC explains, “In a ‘spin-off,’ a parent company distributes
shares of a subsidiary to the parent company’s shareholders.” SEC Staff Legal Bulletin No. 4 (Sept.
16, 1997). “[A] spin-off is effected by the parent’s board of directors declaring a dividend of the
subsidiary shares payable to the parent’s stockholders.” Bruce Hawthorn et al., Planning and
Structuring Spin-Offs and Subsidiary Offerings, in CORPORATE LAW AND PRACTICE COURSE HANDBOOK
SERIES 185, 209 (2001). “[I]n its purest form, a spinoff involves the creation of a separate
ownership structure for a business through the distribution of stock of a subsidiary to the
existing stockholders of a parent corporation as a dividend.” Steven Ostner, Spinoffs Discover New
Life: Energized Shareholders Seek Enhanced Value, 210 N.Y. L.J. 11, 11 (1993). “[T]he spin-off
device involves the distribution by a corporation to its shareholders of another corporation’s
securities held by the distributing corporation.” Simon M. Lorne, The Portfolio Spin-Off and
Securities Registration, 52 TEX. L. REV. 918, 919 (1974) (footnote omitted). |
| |
| 56 |
|
The Texas Securities Act, TEX. REV. CIV. STAT. art. 581-4(E),
defines “sale” as follows: |
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.
|
|
|
| 57 |
|
In its entirety Section 39.262(h)(1) states: |
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.
|
|
|
| 58 |
|
According to an SEC filing by CenterPoint, the sale of Genco’s
fossil generation assets was completed on December 15, 2004, two days before the PUC’s Order was
signed, and the sale of Genco’s nuclear assets concluded in April 2005. |
| |
| 59 |
|
16 TEX. ADMIN. CODE § 25.263(e)(6). |
| |
| 60 |
|
The banker testified that the six potential bidders |
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.
|
|
|
| 61 |
|
252 S.W.3d at 26 n.20. |
| |
| 62 |
|
See TEX. UTIL. CODE §§ 39.201(l), .252(d), .262(g). |
| |
| 63 |
|
Id. § 39.252(d). |
| |
| 64 |
|
Id. § 39.262(j). |
|
|
|
| 65 |
|
See id. §§ 39.254, .256, .257. Chapter 39 does not actually use the
term “excess earnings,” but the parties, the PUC, and this Court have used the term as a shorthand
expression for the earnings that are applied to reduce stranded costs under Sections 39.254 and
other provisions. See, e.g., CenterPoint Energy, 143 S.W.3d at 88. According to the PUC’s brief,
the excess earnings concept is tied to the Legislature’s decision to freeze retail rates under
Section 39.052: “Recognizing that a utility might earn more under those frozen rates than if new
rates had been set using more current information,” Section 39.254 “addressed those excess
earnings” by providing that “excess earnings would be credited against stranded costs.” |
| |
| 66 |
|
TEX. UTIL. CODE § 39.262(a). |
| |
| 67 |
|
Id. § 39.252(a). |
| |
| 68 |
|
Courts have noted that a surge in natural gas prices was one reason
projections of stranded costs changed after the 1998 ECOM report. E.g., In re TXU Elec. Co., 67
S.W.3d at 134 (Phillips, C.J., concurring) (“TXU’s investment in the Comanche Peak nuclear plant,
once a liability, had now become profitable because the cost of generating electricity from natural
gas plants exceeded that of generating electricity from nuclear plants.”). |
| |
| 69 |
|
In re TXU Elec. Co., 67 S.W.3d at 131. |
| |
| 70 |
|
Id. at 150 (Hecht, J., dissenting). |
| |
| 71 |
|
City of Corpus Christi v. Pub. Util. Comm’n, 188 S.W.3d 681, 684,
691 (Tex. App.—Austin 2005, pet. denied). |
| |
| 72 |
|
252 S.W.3d at 38. |
| |
| 73 |
|
Id. at 39. |
| |
| 74 |
|
See, e.g., TEX. UTIL. CODE §§ 39.107(e), .203. |
| |
| 75 |
|
In 2002, CenterPoint distributed its remaining ownership in RRI to
CenterPoint’s shareholders. |
| |
| 76 |
|
252 S.W.3d 32–34. |
| |
| 77 |
|
Intervenors repeatedly complain that an NBV adjustment should be
made for the RRI Option under the primary holding as well as the alternative holding. However, they
also argue more generally that this adjustment should be made “regardless of how market value is
determined.” In their brief on the merits and petition for review, they ask that we sum dollar
amounts for the alleged errors of the PUC in failing to use the sale of assets method and to adjust
for the RRI Option, suggesting that these amounts should be stacked if the sale of assets method is
used. |
| |
| 78 |
|
252 S.W.3d at 34. |
| |
| 79 |
|
252 S.W.3d at 62–70. |
| |
| 80 |
|
CenterPoint Energy, 143 S.W.3d at 99 (brackets omitted). |
| |
| 81 |
|
TEX. UTIL. CODE § 39.251(7) (emphasis added). |
| |
| 82 |
|
CenterPoint Energy, 143 S.W.3d at 96. |
| |
| 83 |
|
TEX. UTIL. CODE § 39.262(d)(2). |
|
|
|
| 84 |
|
CenterPoint Energy, 143 S.W.3d at 96. |
| |
| 85 |
|
16 TEX. ADMIN. CODE § 25.263(i). By way of further explanation,
years 2002 and 2003 are used in the capacity true-up calculation because PURA Section 39.262(d)(2)
requires a comparison of a revenue figure based on the capacity auctions and ECOM power cost
projections “for the same time period.” The capacity auctions were required to begin at least 60
days before the date of consumer choice, January 1, 2002. See TEX. UTIL. CODE § 39.153(a). ECOM
power cost projections were run to determine interim tariffs in 2002 and 2003 under Section 39.201.
See id. § 39.201(b)(1),(d), (g), (h), (l). The final true-up filing was initiated and completed in
2004. See id. § 39.262(c), (j). Therefore, the years 2002 and 2003 are the years that data are
compared for purposes of the capacity auction true-up calculation. |
| |
| 86 |
|
See TEX. UTIL. CODE § 36.051 (“In establishing an electric
utility’s rates, the regulatory authority shall establish the utility’s overall revenues at an
amount that will permit the utility a reasonable opportunity to earn a reasonable return on the
utility’s invested capital used and useful in providing service to the public in excess of the
utility’s reasonable and necessary operating expenses.”). |
| |
| 87 |
|
See, e.g., id. § 36.053 (“Electric utility rates shall be based on
the original cost, less depreciation, of property used by and useful to the utility in providing
service.”). |
| |
| 88 |
|
As the PUC noted in its Order, “Stranded-costs recovery is simply a
method to recover the book value of generation assets that would have been recovered through
depreciation and amortization ordinarily over the life of the asset under traditional rate
regulation.” |
| |
| 89 |
|
See CenterPoint Energy, 143 S.W.3d at 102 (Brister, J., dissenting)
(“[W]ith stranded costs, a more apt analogy would be a system in which a jury returns a different
verdict every day for a period of years, each one very different from the verdict the day before,
and each one correct.”). |
| |
| 90 |
|
252 S.W.3d at 45–48. |
| |
| 91 |
|
16 TEX. ADMIN. CODE § 25.263(g)(2)(A). |
| |
| 92 |
|
TEX. UTIL. CODE § 39.153(a). |
| |
| 93 |
|
16 TEX. ADMIN. CODE § 25.381(b). |
| |
| 94 |
|
TEX. UTIL. CODE § 39.201(h). |
| |
| 95 |
|
See id. § 39.262(g). |
| |
| 96 |
|
16 TEX. ADMIN. CODE § 25.263(i). |
| |
| 97 |
|
CenterPoint Energy, 143 S.W.3d at 96. |
| |
| 98 |
|
Id. |
| |
| 99 |
|
16 TEX. ADMIN. CODE § 25.381. |
| |
| 100 |
|
Id. § 25.381(h)(1)(B)(iv). |
| |
| 101 |
|
Id. § 25.381(h)(7)(C). |
|
|
|
| 102 |
|
In addressing the “bias” created by Genco’s inability to auction the required quantity of
product, the PUC stated in its Order that “[t]he absence of capacity products produces a downward
bias in the market price derived from capacity auction sales, thereby overstating the capacity
auction true-up.” However, under the formula described above for calculating the capacity auction
true-up, if Genco had succeeded in selling an additional 21 gas-intermediate entitlements for 1
cent per kilowatt-month, under a proposal approved by the PUC under its safe-harbor rules, the
effect on the capacity auction true-up would have been negligible. |
| |
| 103 |
|
252 S.W.3d at 48–59. |
| |
| 104 |
|
See TEX. GOV’T CODE § 311.021(4) (recognizing that courts, in
construing statutory codes, should presume that “a result feasible of execution is intended”);
Barshop v. Medina Cnty. Underground Water Conservation Dist., 925 S.W.2d 619, 629 (Tex. 1996)
(avoiding construction that would subject parties to an impossible condition). |
| |
| 105 |
|
CenterPoint Energy, 143 S.W.3d at 96. |
| |
| 106 |
|
TEX. UTIL. CODE § 39.262(d)(2) (emphasis added). |
| |
| 107 |
|
See id. § 39.153(d). |
| |
| 108 |
|
See id. § 39.153(c) (“An affiliate of the electric utility selling
entitlements in the auction required by this section may not purchase entitlements from the
affiliated electric utility at the auction.”). |
| |
| 109 |
|
See id. § 39.001(f) (“A person who challenges the validity of a
competition rule must file a notice of appeal with the court of appeals and serve the notice on the
commission not later than the 15th day after the date on which the rule as adopted is published in
the Texas Register.”). |
| |
| 110 |
|
See City of Rockwall v. Hughes, 246 S.W.3d 621, 625 (Tex. 2008)
(“In construing statutes, we ascertain and give effect to the Legislature’s intent as expressed by
the language of the statute.”). |
| |
| 111 |
|
252 S.W.3d at 59–62. |
| |
| 112 |
|
324 S.W.3d 95, 101–05 (Tex. 2010) (hereinafter TIEC). |
| |
| 113 |
|
The current version of the Rule complies with CenterPoint Energy.
16 TEX. ADMIN. CODE § 25.263(l)(3). |
| |
| 114 |
|
Id. at 103–04 (quoting CenterPoint Energy, 143 S.W.3d at 83). |