







IN THE SUPREME COURT OF TEXAS








IN THE SUPREME COURT OF
TEXAS
 
════════════
No. 03-0396
════════════
 
CenterPoint
Energy, Inc. f/k/a Reliant Energy, Incorporated
and
American Electric Power Company, Inc., Petitioners
 
v.
 
Public
Utility Commission of Texas, Respondent
 
════════════════════════════════════════════════════
On Petition for
Review from the
Court of Appeals
for the Third District of Texas
════════════════════════════════════════════════════
 
Argued February 18, 2004
 
            Justice
Owen delivered the opinion of the Court, in which Justice Hecht, Justice O=Neill, Justice
Jefferson and Justice Wainwright joined.
 
Justice
Brister filed a dissenting
opinion, in which Chief Justice Phillips,
Justice Schneider and Justice Smith joined.
 
 
In a
regulated environment, electric utility companies made very large expenditures
to build generation plants, some of which were nuclear power plants.  Under regulation, those utilities and their
shareholders were entitled to, and had, a reasonable opportunity to recover
through rates not only their reasonable and prudent investments of capital in
those plants, but also a reasonable, regulated return on those investments.[1]  In 1999, the Texas Legislature decided that
it was in the public interest to partially deregulate the electric power
industry.[2]  The Legislature recognized that in
fundamentally changing the industry, it was altering the assumptions that had
led utilities to invest large sums in power generation assets.  The Legislature understood that the cost of
these assets likely would be recovered in a regulated environment, but might
well become uneconomic and thus unrecoverable in a competitive, deregulated
electric power market.  The Legislature
called such uneconomic assets stranded costs.[3]  The term Astranded
costs@ has a specific definition in the Public
Utility Regulatory Act (APURA@ or Athe Act@),[4]
but generally speaking, it is the extent to which the book value of
generation-related assets and purchased power contracts exceeds their market
value.[5]
The
Legislature concluded that if generating plants became uneconomic as a result
of legislatively mandated deregulation, it was in the public interest for
utilities to be made whole by recovering their full investment in those
generation plants, although the utilities would no longer receive a return on
those investments.[6]  The Legislature determined that utilities
should not be required to forfeit their investments in generating plants with
the advent of deregulation.  The
Legislature thus said in the PURA that if there are stranded costs, an electric
utility Ais allowed to recover all of its net, verifiable,
nonmitigable stranded costs incurred in purchasing
power and providing electric generation service.@[7]  The
Legislature set forth a comprehensive scheme for estimating, finalizing, and
recovering those costs.[8]  Stranded cost recovery, if any, will occur
over a period of years rather than in a lump sum.[9]  No one disputes that the Legislature intended
electric utilities to recover carrying costs on stranded costs to compensate
for the financing costs incurred during the stranded cost recovery period.  Nor does anyone dispute that prior to
deregulation, carrying costs on investments in generation plants were included
in rates.  The only issue before us is
the date from which carrying costs may be recovered once deregulation
commenced:  January 1, 2002, which was
the first day of deregulation, or two or more years later, at the end of final
true-up proceedings.
In a
rulemaking proceeding, the Texas Public Utility Commission determined that
carrying costs on a true-up balance must be calculated from the later date, the
date of a true-up final order (sometime after January 10, 2004).[10]  CenterPoint Energy,
Inc. (formerly known as Reliant Energy, Inc.) and American Electric Power
Company, Inc. (AAEP,@ a public utility holding company whose
Texas operating company was formerly known as Central Power and Light Company)
contend that this rule is invalid, arguing that carrying costs should be
recovered from the date that regulated rates ended and competition commenced,
which was January 1, 2002.  The court of
appeals rejected the generation companies= arguments and upheld Rule 25.263(l)(3).[11]
The
court of appeals also rejected a related challenge to Rule 25.263(l)(3).  In separate proceedings not before us, the
Commission directed CenterPoint and AEP to reverse
early efforts to mitigate potential stranded costs.[12]  If it is ultimately determined in an appeal
from those proceedings that the generation companies have stranded costs and
the Commission erred by reversing early mitigation efforts, the generation
companies argue that Rule 25.263(l)(3) does not permit them to recover interest
for the period of time that amounts associated with early mitigation efforts
were incorrectly refunded to customers.[13]  The court of appeals in this case held that Aa utility=s
right to fully recover its stranded costs does not encompass a right to early
mitigation.@[14]  The
generation companies take issue with this determination, but advise us that the
matter would be moot if this Court concludes that they are entitled to carrying
costs on stranded costs from January 1, 2002.
We hold
that Rule 25.263(l)(3) is inconsistent with the Legislature=s intent, expressed in Chapter 39 of the
PURA, that utilities fully recover their Anet, verifiable, nonmitigable
stranded costs incurred in purchasing power and providing electric generation
service,@[15] that Aexist on the last day of the freeze period
[December 31, 2001].@[16]  A
two- or three-year gap in recovery of carrying costs would not permit
generation companies full recovery of their stranded costs as the Legislature
envisioned.  However, the capacity
auction true-up procedure set forth in the Act[17]
may include a component for return of or on stranded costs in 2002 and 2003, a
determination that cannot be made from the record in this rulemaking
proceeding.  The amount of stranded cost
recovery, if any, through capacity auction true-ups will have to be considered
in determining the amount of carrying costs on stranded costs from January 1,
2002 to ensure that there is no overrecovery of
stranded costs.[18]  We accordingly remand this issue to the
Commission for further consideration of whether to address carrying costs in a
rule or in contested case hearings applicable to each electric utility and its
affiliates.
Because
Rule 25.263(l)(3) is invalid and we are remanding this matter to the
Commission, we do not address whether or under what circumstances generation
companies might be entitled to interest on refunds of early mitigation credits
if those refunds were to be reversed.
I
We first consider the standard of review.  The Commission=s
order adopting Rule 25.263[19]
reflects that the rule was promulgated under section 14.002 of the Act, which
provides:  AThe
Commission shall adopt and enforce rules reasonably required in the exercise of
its powers and jurisdiction.@[20]  The
order also cites sections 39.252 and 39.262 of the PURA, which the Commission
said Aaddress[] a utility=s right to recover stranded costs@ and Arequire the commission to conduct a true-up
proceeding for each . . . utility after the introduction of customer
choice.@[21]
Section
39.001 of the PURA has separate provisions governing review of the validity of
a competition rule.  Section 39.001
provides that A[j]udicial review
of competition rules adopted by the commission shall be conducted under Chapter
2001, Government Code, except as otherwise provided by this chapter [39].@[22] 
Section 39.001 provides for a direct appeal to the Third Court of
Appeals for A[j]udicial review
of the validity of competition rules,@[23] and for expedited procedures in such an
appeal.[24]  The Commission=s
order does not contain a reference to section 39.001.
CenterPoint and
AEP nevertheless filed a direct appeal in the Third Court of Appeals, and the
court of appeals= opinion recites that the court had before
it a direct appeal under subsections 39.001(e) and (f) of the Act.[25]  No one has taken issue with the
characterization of Rule 25.263 as a Acompetition rule@ or the applicability of subsections
39.001(e) and (f).  Regardless of whether
those subsections apply, the validity of Rule 25.263(l)(3) is at issue, and
under the Administrative Procedure Act[26]
and our case law,[27]
the rule is invalid if, among other things, it is in violation of a statutory
provision, in excess of the agency=s statutory authority, or arbitrary,
capricious, or characterized by abuse of discretion or clearly unwarranted
exercise of discretion.  We turn to an
analysis of Rule 25.263(l)(3) with these considerations in mind.
II
This is
the fourth case in which we have addressed issues arising out of the partial
deregulation of the electric power industry, including issues concerning
stranded costs.[28]  Stranded costs include regulatory assets,[29]
which are essentially bookkeeping entries that reflect a charge that was to be
included in a utility=s future rates in a regulated environment.[30]  Stranded costs also include the reasonable
excess cost above the market value of assets such as generating plants,
including nuclear power plants.[31]  As we have previously explained, under the
regulatory scheme that existed before 1999, an electric utility had an
opportunity to recover prudent capital investments in generation assets and a
reasonable return on those investments through rates.[32]  The Act recognizes that, generally, there are
financing or carrying costs associated with generation assets and that these
carrying costs were historically recovered in rates.[33]  Accordingly, under traditional rate
regulation, ratepayers would pay carrying costs as a utility recovered its
investment in generation assets over the useful life of those assets.
The
Commission recognizes that if costs are stranded in a deregulated environment,
a generation company is entitled to recover carrying costs on those stranded
costs, which are recovered over time either through a competition transition
charge or securitization.  The dissent
does not dispute that the Act implicitly, if not explicitly, assumes that there
will be carrying costs on stranded costs. 
The only issue is whether the Act contemplates roughly a two-year gap in
recovery of carrying costs between the date regulation ceased (January 1, 2002)
and the date of a final true-up order (2004 or perhaps beyond).
The
Commission says such a gap is permissible. 
The Commission determined in Rule 25.263(l)(3) that carrying costs
on stranded costs should be recovered by electric utilities only from the date
of the final true-up order.[34]  Carrying costs are to be calculated based on
each utility=s individual cost of capital established in
that utility=s unbundled cost of service (UCOS)
proceeding.[35]  Final true-up orders will be entered sometime
after January 10, 2004, which is specified in section 39.262 as the date after
which each transmission and distribution utility, its affiliated retail
electric provider, and its affiliated power generation company must jointly
file to finalize stranded costs.[36]  We must decide whether the Commission=s failure to permit the recovery of
carrying costs for approximately a two-year period after regulated rates ended
and customer choice began violates the Act, is in excess of the Commission=s statutory authority, or is arbitrary,
capricious, or a clearly unwarranted exercise of discretion.
In its
order adopting Rule 25.263(l)(3), the Commission explained why it chose the
date of a final true-up order as the date from which carrying costs should
accrue by saying Aa utility=s
true-up balance becomes due upon the issuance of a final order in that utility=s true-up proceeding.@[37]  In
its briefing on appeal, the Commission elaborated, contending that stranded
costs did not come into existence on the first day of customer choice, but
instead will come into existence only after a true‑up proceeding is
concluded.  The court of appeals agreed
with this rationale.[38]  In post-submission briefing in this Court,
the Commission contends that in addition to this logic, disallowing carrying
costs from the date customer choice commenced (January 1, 2002) until the date
of a final order sometime in 2004 or later is justified because otherwise
generation companies may receive a double recovery.  The Commission contends that the capacity
auction true-ups that will be conducted under section 39.262(d) of the PURA[39]
include a component that will allow generation companies to recover debt
service on their book generation assets in addition to operating costs.  Texas Industrial Energy Consumers (TIEC), an intervenor in the court of appeals and in this Court,
likewise contends that because of the capacity auction true-up, generation
companies would receive a double recovery if they are permitted to receive
carrying costs from the date customer choice began.
The
generation companies counter that the date as of which stranded costs are to be
determined is December 31, 2001, as reflected throughout chapter 39.  The generation companies also contend that
under section 39.262(d), they are entitled to recover the amount the capacity
auction true-up yields, without regard to whether they have stranded
costs.  Capacity auction true-up proceeds
and stranded cost recovery are entirely separate, the generation companies
contend, and there would be no double recovery if carrying costs on stranded
costs are permitted from January 1, 2002.
Because
of the complexity of the issues, we think it helpful to outline our conclusions
before examining the Act in greater detail. 
We conclude that the Commission=s construction of chapter 39 was incorrect
regarding the date as of which stranded costs are to be determined.  Chapter 39 reflects that the amount of
stranded costs, if any, is to be determined as of the day before competition
beganCDecember 31, 2001Cor earlier in some cases.[40]  However, the Act recognizes that a
determination of whether there were stranded assets as of December 31, 2001,
and a meaningful valuation of those assets as of that date, could not be made
until a deregulated market had a period of time to develop and then to
stabilize.  Because the Commission=s rule is based on an incorrect
construction of the Act in this regard, it is infirm.
That
does not mean that generation companies are entitled to carrying costs on the
entire positive balance of stranded costs, if any, from January 1, 2002.  Based on the record before us, it appears
that the design of the capacity auction true-up may have permitted generation
companies to recover during 2002 and 2003 at least a portion of their fixed
costs, including stranded costs, if any. 
That determination cannot be made from this record.  Preventing an overrecovery
of stranded costs requires a determination, on a company-by-company basis, of
whether proceeds from a capacity auction true-up had a component for return on
or of stranded costs and of the quantity of any such return.  We accordingly remand this proceeding to the
Commission for further consideration.
The
dissent asserts that our holding Apotentially@
entitles utilities to Abillions of dollars in interest.@[41]  As
the dissent concedes, however, it is unknown at this point whether there will
be any stranded costs at all and thus any carrying costs.  If it is determined that stranded costs did
exist on December 31, 2001, the amount of any such costs is likewise unknown,
as is the extent to which stranded cost recovery has or will occur through a
capacity auction true-up.  This Court
must give effect to legislative intent as expressed in the PURA.  We must ensure that the Commission implements
the statutory scheme set forth in Chapter 39 of the PURA without regard to
speculation about how deregulation may or may not affect market values of
generation assets and thus may or may not affect rates.
The
pertinent sections of Chapter 39 and the record in this case are considered
more thoroughly below.
III
The deregulation process has many components, some of which can be
briefly summarized for purposes of this appeal. 
The Legislature determined that the production and sale of electricity
should no longer be regulated in Texas, except for transmission and distribution
services and the recovery of stranded costs.[42]  The Legislature chose January 1, 2002 as the
date on which customer choice would begin, with a few exceptions not relevant
to the issues in this case.[43]  Correspondingly, December 31, 2001 was the
date traditional regulation of wholesale rates would end.[44]  The Legislature recognized that deregulation
could not be accomplished overnight. 
Accordingly, beginning September 1, 1999, and continuing until January
1, 2002, the Legislature froze retail electric rates.[45]  The Legislature also directed that by January
1, 2002, each electric utility must separate its business activities into a
power generation company, a retail electric provider, and a transmission and
distribution utility.[46]  For a five-year period after the beginning of
customer choice, from January 1, 2002 until January 1, 2007, retail electric
providers are required to offer residential and small commercial customers
rates that are six percent less than those in effect on January 1, 1999, with
certain adjustments.[47]  This is the Aprice
to beat@ in the retail market.[48]
Resolution
of the issues raised by Rule 25.263 requires a more detailed focus, however, on
provisions of chapter 39 that govern generation companies and stranded costs.
A
In
enacting deregulation legislation, the Legislature had before it a 1998 report
prepared by the Public Utility Commission that analyzed potential stranded
costs.[49]  The term AECOM@ was used in that report, meaning excess
costs over market.  That report
identified a number of generation companies that, in a deregulated market, were
projected to have unrecoverable or Astranded@
costs, principally nuclear power plant investments.  The Legislature required electric utilities
identified in this 1998 report as having projected stranded costs to use Aa number of tools . . . to
mitigate stranded costs@ by Areduc[ing] the net
book value of, otherwise referred to as >accelerat[ing]= the cost of recovery of, its stranded
costs@ before customer choice began on January 1,
2002.[50]  For each of the three years preceding
customer choice (1999, 2000, and 2001), electric utilities were required to
file annual reports showing whether they had excess earnings from charging
frozen rates,[51]
and if so, to apply those excess earnings to reduce the book value of
potentially stranded investments.[52]  During the period leading up to customer
choice, before utilities were unbundled, utilities also had the option of
redirecting depreciation expense relating to transmission and distribution
assets to generation assets as another tool for reducing the book value of
potentially stranded assets.[53]
The
Legislature recognized that these early mitigation efforts might not be
sufficient to eliminate stranded costs. 
In the period leading up to customer choice on January 1, 2002, the
Legislature gave electric utilities another option.  At any time after September 1, 1999 (the
start of the retail rate-freeze period), a utility was permitted to securitize
100 percent of its regulatory assets[54]
and up to 75 percent of its other estimated stranded costs.[55]  This meant that a generation company could
begin to recover stranded costs even before January 1, 2002, and before the
final dollar amount of those stranded costs, if any, could be quantified.
The only
explicit reference to carrying costs on stranded costs appears in a section of
the Act regarding securitization.[56]  The securitization provisions reflect that
the Legislature implicitly, if not explicitly, assumed that carrying costs on
stranded costs are to be borne by ratepayers over the entire life of the
generating assets under either conventional financing methods or
securitization.[57]  Section 39.301 sets forth the purposes of
allowing securitization.  Securitization
is intended to Alower the carrying costs of the assets
relative to the costs that would be incurred using conventional utility
financing methods.@[58]  The
Acosts that would be incurred using
conventional utility financing methods@ are the carrying costs on generation
assets that customers would otherwise pay to the generation company.  The Legislature commanded the Commission to Aensure that securitization provides
tangible and quantifiable benefits to ratepayers, greater than would have been
achieved absent the issuance of transition bonds.@[59]  In
this same vein, the Legislature said that the Commission could permit
securitization only if it found Athat the total amount of revenues to be
collected under the financing order is less than the revenue requirement that
would be recovered over the remaining life of the stranded costs using
conventional financing methods.@[60] 
Securitization could occur under the statute, and did occur (at least
for regulatory assets),[61]
prior to January 1, 2002.[62]  When securitization is used, carrying costs
on stranded costs are recovered from the date of securitization forward.[63]  There is no two-year gap in payment of
carrying costs for 2002 and 2003.
In
making the determination of whether securitization benefitted
ratepayers, the Legislature directed the Commission to look at the entire
remaining life of stranded costs, beginning as early as September 2, 1999.[64]  There is no suggestion that in making that
calculation, the Commission could drop out the carrying costs for the two-year
period between the onset of customer choice (January 1, 2002), and the
date a final true-up order could be entered (2004 or beyond).  If stranded costs never come into existence
until 2004, as the Commission argues, then the Legislature=s securitization scheme compared apples to
oranges and allowed securitization to proceed using a much less stringent test
from the ratepayers= perspective.  That is not a reasonable construction of the
Act.
B
For estimated stranded costs that had not been mitigated or had not
been or could not be securitized, the Legislature provided that those costs
should be recovered through competition transition charges starting on the
first day of competition, January 1, 2002. 
The Legislature directed in section 39.201 that between April 1, 2000
and January 1, 2002 the Commission was to determine any expected competition
transition charge and make it effective on January 1, 2002.[65]  The actual dollar amount of stranded costs
could not be known at the time those charges were to be determined, so in
section 39.201, the Legislature directed the Commission to calculate
competition transition charges using the ECOM administrative model in the
Commission=s 1998 Report, but using updated,
company-specific inputs and market-based natural gas forward prices, in
addition to other specified updates.[66]
It is
highly significant to the question before us today that the Legislature said in
section 39.201 that the pertinent date for quantifying stranded costs was
December 31, 2001, Athe last day of the freeze period@ and the last day before customer choice
began on January 1, 2002.[67]  In implementing competition transition
charges, the Commission was directed to calculate Athe amount of stranded costs as defined in
Subchapter F that are reasonably predicted to exist on the last day of the
freeze period [December 31, 2001].@ 
Accordingly, the Commission was told that sometime between April 1, 2000
and January 1, 2002, it was to estimate Athe amount of stranded costs as defined in
Subchapter F that are reasonably projected to exist on the last day of the
freeze period [December 31, 2001]@ and to put nonbypassable
rates in effect on January 1, 2002 to begin recovery of these amounts.[68]  The Legislature did not tell the
Commission to estimate the amount of stranded costs that were projected to
exist as of a date in 2004, or at the end of a true-up proceeding, which would
have been appropriate dates if the Commission=s
interpretation of the Act were correct. 
Instead, the Legislature directed the Commission to permit generation
companies to begin recovery of stranded costs on January 1, 2002, through
competition transition charges, if they were projected to have stranded costs
as of December 31, 2001.      
C
The Legislature=s use of the words Aremaining stranded costs@ in section 39.201(l) is also
significant.[69]  That section provides that, A[t]wo years after
customer choice is introduced [meaning two years after January 1, 2002],@ the Commission is to determine in final
true-up proceedings whether there are any Aremaining stranded costs.@[70] 
This indicates that the Legislature thought that stranded costs would
have been in existence before the final true-up and only remaining
stranded costs would be recovered going forward.  If, as the Commission contends, stranded
costs could not come into existence until after the true-up proceedings were
concluded, then the Legislature would not have referred to Aremaining stranded costs@ that are to be quantified during the final
true-up.  The Commission=s position is contrary to the Legislature=s directive that the 2001 Astranded cost estimate@ must Abe reviewed and, if necessary, adjusted to
reflect a final, actual valuation in the true-up proceeding.@  The
2001 projection of what stranded costs would exist as of December 31, 2001 was
to be reviewed and adjusted.
D
As it turned out, the calculations made by the Commission in 2001 using
the ECOM model showed that no generation company was projected to have stranded
costs as of December 31, 2001. 
Accordingly, no competition transition charges were implemented for any
generation company.  That fact seems to
have obscured the Commission=s view of the date as of which section
39.201 says stranded costs are to be measured. 
Rule 25.263(l)(3) is contrary to what the Legislature contemplated could
happen under section 39.201.  If stranded
costs had been projected in 2001 to exist on December 31, 2001 for a generation
company, then that company was entitled to begin collecting stranded costs.[71]  Of course, the stranded costs would not have
been collected in a lump sum.  The
Legislature gave the Commission factors to consider in deciding Athe length of time over which stranded costs@ may be recovered through competition
transition charges.[72]  No one, including the dissent, disputes that
there would have been a component for recovering carrying costs in competition
transition charges.
If
company A had been projected in 2001 to have $5,000,000 in stranded costs, A
would have begun recovering $5,000,000 plus carrying costs through a competition
transition charge from January 1, 2002 over a number of years.[73]  If the 2004 true-up confirmed that the 2001
projection was an accurate predictor of the amount of stranded costs, A would
continue to receive the competition transition charge.  The net result would be that A recovers
carrying costs on stranded costs from January 1, 2002.
But, as
has happened, assume that A was projected in 2001 to have no stranded costs and
therefore did not receive a competition transition charge in 2002 and
2003.  Further assume that in a 2004
true-up proceeding, it is determined that A has stranded costs of $5,000,000.  The Commission says that A could begin
recovering $5,000,000 plus carrying costs from 2004 over a period of
years.  The net result would be that A
recovered carrying costs only from 2004.
We must
ask, why would the Legislature, planning in 1999 for various contingencies,
have intended for company A to recover two years of carrying costs if the 2001
projection turned out to be an accurate predictor of actual stranded costs, but
not if the 2001 projection was not an accurate predictor of actual stranded
costs?  It is extremely unlikely this was
the Legislature=s intent, particularly when it is
undisputed that if the 2001 projection overestimated rather than
underestimated stranded costs, overrecovery dating
back to January 1, 2002 would be reversed.[74]  It seems more likely that the Legislature
intended for its scheme to be symmetricalCrequiring adjustments for both overrecovery and underrecovery if
the 2001 projection was not an accurate predictorCrather
than arbitraryCallowing adjustments only for overrecovery.  The
Act unquestionably provides that if the 2001 projection proved to have
overestimated stranded costs when the true-up was conducted in 2004, then that overrecovery would be rectified through 1) a reduction
in the competition transition charge, to the extent it had not been
securitized, 2) a reversal, in whole or in part, of depreciation expense
redirected under section 39.256, 3) a reduction in the transmission and
distribution utility=s rates, or 4) a combination of these
measures.[75]
If the
Commission and TIEC were correct that no stranded costs could come into
existence until the end of a true-up proceeding, which would be sometime in
2004 or perhaps beyond, then a generation company that collected competition
transition charges under section 39.201 would be required under the rationale
of Rule 25.263(l) to refund all carrying costs collected as part of those
charges between January 1, 2002 and a final true-up order.  Nothing in chapter 39 suggests such a
result.  For example, suppose that the
2001 ECOM model calculations made pursuant to section 39.201 had projected that
a generation company=s stranded costs as of December 31, 2001
were $5,000,000, and that company began collecting competition transition
charges over a fifteen-year period to recover that amount.  Additionally assume that in 2004, the final
true-up showed that the company=s stranded costs were $5,000,000, and that
$1,000,000 of those costs had been recovered through competition transition
charges.  Applying the Commission=s reasoning, the generation company would
have to refund the carrying cost component in the transition charges collected
from 2002 until 2004.  Indeed, applying
the Commission=s reasoning, the company would have to
refund interest on the carrying costs to make up for the time value of the
carrying costs that the company collected before 2004.
The
Commission=s contentions in this appeal regarding
carrying costs are inconsistent with its own rule.  Rule 25.263(g)(2)(A) recognizes that under
the example in the paragraph above, a company that began collecting carrying
costs in 2002 as part of a competition transition charge would keep those
carrying costs if, in a 2004 true-up proceeding, it is found to have stranded
costs.  Rule 25.263(g)(2)(A) provides
that in a final true-up, any generation-related invested capital recoverable
through a competition transition charge, exclusive of carrying costs,
projected to be collected through the date of the final order in the true-up
proceeding, is to be deducted from the December 31, 2001 book value of
generating assets.[76]
The
Commission=s rule creates an anomaly.  Whether carrying charges can be collected
from January 1, 2002 depends entirely on whether the 2001 ECOM model projected
stranded costs.  If the model did, then
unquestionably, section 39.201 required the Commission to put into effect
competition transition charges through which generation companies would begin
recovering stranded costs and carrying costs on those stranded costs.[77]  If the ECOM model projected no stranded
costs, but in 2004, market valuations reveal that the 2001 ECOM projection was
not a good predictor of actual stranded costs, then the Commission=s rule does not permit carrying costs.  Carrying cost recovery under the Commission=s rule can turn entirely on the accuracy of
the 2001 ECOM projections.  This is not a
reasonable construction of sections 39.201 and 39.262.
E
Other
parts of section 39.201 indicate that the Legislature considered December 31,
2001 to be the date as of which stranded costs would finally be calculated in a
true-up proceeding.  Subsection 39.201(l)
says:  ATwo
years after customer choice is introduced [which would be 2004], the stranded
cost estimate under this section shall be reviewed and, if necessary, adjusted
to reflect a final, actual valuation in the true-up proceeding under Section
39.262.@[78]  A[T]he stranded cost estimate@ in subsection (l) refers back to
the estimate performed under subsection (h) that was to apply the ECOM model
with updated inputs in order to calculate Athe amount of stranded costs as defined in
Subchapter F that are reasonably projected to exist on the last day of the
freeze period@ as required by subsection (g).[79]  If stranded costs did not and could not exist
as of December 31, 2001, as the Commission and TIEC contend, then why did the
Legislature direct that the estimate of stranded costs as of December
31, 2001 be adjusted?  If the
Legislature had meant to substitute a calculation of stranded costs as of a
date in 2004, it would have said so.  It
did not.  Even for final true-up
purposes, section 39.201 refers back to stranded costs projected to exist as
of December 31, 2001.[80]
Section
39.262 sets forth in greater detail how the final true-up proceedings are to be
conducted in 2004.  Section 39.262(c)
refers to Afinaliz[ing]@ Athe estimated stranded costs used to
develop the competition transition charge in the proceeding held under Section
39.201.@[81] 
Here again, the Legislature is directing that the 2001 estimates used to
calculate stranded costs Aprojected to exist on the last day of the
freeze period [December 31, 2001]@ be finalized.[82]  The Legislature is directing that a final
determination be made of the stranded costs that existed on the last day of
the freeze period.  It did not direct
the Commission to determine stranded costs that exist Aon the first day a final true-up order is
issued.@
F
The reference in section 39.201(g) to the
definition of stranded costs in Subchapter F leads to another reference to the
December 31, 2001 date.  Stranded costs
are defined in Subchapter F as follows:
 
AStranded cost@
means 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 (AAccounting 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 [regarding true-up proceedings], 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.[83]
 
The Legislature defined
stranded costs by using December 31, 2001, the day before customer choice was
to begin, as the benchmark for book value, or an earlier date if assets were
sold or exchanged.[84]
The
Commission and TIEC point out that the definition of stranded costs in section
39.251(7) has two components, book value as of December 31, 2001, and market
value, which may not be determined for some companies until 2004 or
beyond.  This, they say, is justification
for concluding that stranded costs do not come into existence, and therefore
the company has no right to carrying costs, until the date of a final order in
a true-up proceeding.  This reasoning has
several flaws.  The first is the wording
of the Act itself.
Section
39.251(7) recognizes that stranded costs may be finally determined even before
January 1, 2002, the date that competition began, and certainly before 2004.[85]  The definition of stranded costs provides
that if, under section 39.262(h), a company sells or exchanges assets to
establish market value before December 31, 2001, then for purposes of a true-up
proceeding (section 39.262), book value shall be established on that earlier
date of sale or exchange.[86]  Accordingly, any Apositive excess of the net book value of
generation assets over the market value of the assets@[87] could be known even before January 1,
2002.  How can it be said that such
stranded costs did not come into existence until 2004 or beyond?
Similarly,
a company may have been projected to have no stranded costs when the Commission
performed the ECOM model calculation in 2001 required by section 39.201.  That company may sell or exchange assets
sometime in 2002 or 2003.  Stranded costs
can be finally quantified once that sale or exchange occurs.  Yet the Commission says that these stranded
costs could not come into existence until 2004 and that the generation company
is not entitled to accrue any carrying charges on these stranded costs until
the date the Commission issues a final order in a true-up proceeding.  Here again, the statutory language does not
support such a result.
G
TIEC and, to some extent, the Commission argue that because of
fluctuations in market prices from December 31, 2001 until the date of final
orders in true-up proceedings in 2004, stranded costs could come in and out of
existence.  Therefore, they say, it is
reasonable to choose a date in 2004 rather than December 31, 2001.  This contention ignores the fact that no gain
could be realized from upswings in the market value of generation assets unless
those assets were sold or exchanged. 
Interim market swings therefore have nothing to do with the stranded
cost equation (net book value of generation assets over the market value of the
assets)[88]
unless generation assets are sold or exchanged. 
If they are sold or exchanged, then, as discussed above, the amount of
stranded costs is determinable on the date of sale or exchange, and there is no
justification for deferring the accrual of stranded costs until sometime in
2004 or beyond, at the end of a true-up proceeding.
There is
no cause for concern that rises in gas prices during the interim between
January 1, 2002 and December 31, 2003 would translate into excess profits for
power companies, even if their nuclear power plants operated profitably.  As will be discussed in more detail in
section IV below, the return that a power company could earn during 2002 and
2003 was predetermined in 2001.  If that
predetermined margin is exceeded, then the excess will be refunded by the power
company pursuant to the capacity auction true-up under section 39.262(d)(2).[89]
H
This Court did not resolve the issue now
before us in In re TXU.[90]  That case concerned the Commission=s reversal of early mitigation
efforts.  A majority of the Court held
that mandamus relief was unavailable and did not reach the merits of the
controversy.  The dissent in that case
would have reached the merits of whether the Commission had the statutory
authority to reverse early mitigation efforts before a final true-up.  At one juncture, the dissent said, A[t]he Legislature has required early
mitigation of stranded costs not because those costs actually exist now but
because it has been estimated that they will exist after the 2004 true-up and
waiting until then to begin recovery threatens competition.@[91] 
Read in context, the dissent was explaining that Athe unquestioned fact is that stranded
costs cannot be determined with any accuracy until one knows what the retail
price of electricity is in a competitive market, and no such market exists.@[92] 
Neither the Court nor the dissent purported to decide whether the
Commission could require a two or more year gap in recovery of carrying costs
on stranded costs.
I
Importantly, neither the Commission nor TIEC has offered any rationale
to explain why the Legislature chose to use the book value of generation assets
on December 31, 2001 (or even earlier) in calculating stranded costs if it
intended for stranded costs to come into existence only after a final true-up
proceeding in 2004 or beyond.  But
conversely, there is a compelling reason to determine the amount of stranded
costs that existed as of December 31, 2001 and yet use the market value in
2002, 2003, or 2004 of the stranded assets. 
That compelling reason is that the Legislature knew with certainty that
there would be no valid market indicators on December 31, 2001, the day before
customer choice began, or for up to two years thereafter.
The fact
that the Legislature permits the actual market value of assets in 2002, 2003,
or 2004,[93]
or 2004 projections of the value of nuclear assets,[94]
to be used to calculate the value of stranded costs that existed as of December
31, 2001 is entirely consistent with the rationale underlying the capacity
auction true-up proceeding,[95]
to which we now turn.
IV
It is no coincidence that the capacity auction true-up proceeding[96]
covers roughly the same period of time between the start of customer choice,
January 1, 2002, and the date on which generation companies could first file to
finalize stranded costs in a true-up proceeding, which was January 11, 2004.[97]  By definition, stranded costs include
generation assets= excess book value over market.[98]  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.
There
are two objectives accomplished by the capacity auction true-up proceeding that
are pertinent to this appeal.  The first
is that a generation company is limited to a set margin that it will receive
for sales of power, no matter how high or how low gas prices and fuel costs
might be during 2002 and 2003.  The
second is that a generation company is permitted to earn a return on its
generation assets during this period. 
What cannot be determined from this record is how much of that return is
a return of or on stranded costs.
Section
39.153 requires a generation company to auction entitlements to at least 15
percent of its total power generation capacity, commencing at least 60 days
before the beginning of customer choice.[99]  This auction obligation continues until the
earlier of 60 months (five years) after the beginning of customer choice or the
date the Commission determines that 40 percent or more of the electric power
consumed by residential and small commercial customers within the affiliated
transmission and distribution company=s service area before the onset of customer
choice is provided by nonaffiliated retail electric providers.[100]
At the
end of the first two years that this auction obligation is in effect
(essentially 2002 and 2003), as part of the true-up proceeding in section
39.262,[101]
a determination will be made 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 to estimate
stranded costs under section 39.201 (which determined whether there would be
competition transition charges).[102]  This essentially 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.  The
former electric utility=s fuel balance determined under section
39.202(c) (which is not at issue in this appeal) is netted with this margin.[103]  If the sum of these two items shows that the
power company has overrecovered, the transmission and
distribution utility is credited.[104]  If it shows the power company has underrecovered, the transmission and distribution utility
is billed.[105]
The
court of appeals held that the Commission erred by requiring in Rule 25.263
that any amount owed to the power company resulting from the calculation under
subsection 39.262(d) be netted against any Anegative@ stranded cost calculation.[106]  No one has appealed that ruling.  The generation companies contend, however,
that the court of appeals= holding forecloses any comparison of the
capacity auction true-up to the stranded cost calculation.  The Commission and TIEC counter that the
margin guaranteed by the capacity auction true-up was intended by the Legislature
to be the only means of recovering any part of stranded costs between January
1, 2002 and the date of a final order in a true-up proceeding.  The correct construction of the Act lies
between these two polar positions.
In the
rulemaking proceeding that led to the adoption of Rule 25.263, the power
companies, TIEC, and others disputed how the capacity auction true-up
determination should be made.  The same
order that decided that carrying costs on stranded costs should be recoverable
only from the date of a final true-up order also decided how the capacity
auction true-up would be calculated.[107]  The Commission essentially accepted the power
companies= position regarding the calculation of the
capacity auction true-up.[108]  The Commission determined that actually
re-running the ECOM model was not required by section 39.262(d) of the PURA,
but instead, that it was appropriate to use Aaggregated
capacity auction revenues, actual fuel costs, and sales amounts [which] are
compared to data from the ECOM model.@[109]
It is
not clear from the Commission=s order in this rulemaking proceeding precisely
what is calculated by the capacity auction true-up, but filings by the power
companies as part of the process do shed some light on the matter.  Reliant Energy, Inc., now known as CenterPoint, said in written public comments (part of the
record in this case) that the capacity auction true-up calculation resulted in
a Amargin predicted to be available to
contribute to fixed costs and therefore to reduce stranded costs.@  Reliant
explained in greater detail:
 
For
purposes of the true-up, the ECOM model has two main components: the price of
power and the price of fuel.  The
difference between those components is the margin predicted to be available to
contribute to fixed costs and therefore to reduce stranded costs.  Assume, for example, that the ECOM price of
power is $43/mwh, and the ECOM price of gas is $33/mwh.  The margin that is available to reduce
stranded costs in this example is $10/mwh.
The
capacity auction will also yield a price of power and a price of fuel.  The purpose of the PURA ' 39.262(d)(2) true-up is to ensure
that the [power generation company] ultimately receives the same margin from
the capacity auction process as the ECOM model predicted.  The [power generation company] may recover
part of, all of, or more than that ECOM margin through the bid premiums.  In addition, the [power generation company]
will experience some gain or loss on fuel when the capacity auction strike
prices are compared to the [power generation company=s] actual costs.  The remainder (or overcollection)
of the margin should be recovered from (or paid back to) ratepayers in the
true-up proceeding.  Thus, at the time of
the true-up, the [power generation company] can be made whole by the following
formula:
 
(ECOM market revenues - ECOM fuel costs) -
((capacity auction price x total busbar sales) -
actual fuel costs)
 
Maintaining
the assumption that the margin between the ECOM price of power and the ECOM
price of gas is $10/mwh, the [power generation company] should retain that
margin in the capacity auction true-up, assuming sales remain the same.  For example, suppose the capacity auction
price is composed of a $2/mwh bid premium and a $33/mwh fuel cost, for a total
capacity auction price of $35/mwh. 
Assuming that the actual fuel cost is $33/mwh, the [power generation
company] would recover from the entitlement holder all of its fuel costs and
$2/mwh to apply against stranded costs. 
But to retain the net margin of $10/mwh in the ECOM model, the [power
generation company] should be allowed to recover $8/mwh from ratepayers.
This
method could work to the benefit of ratepayers as well.  For example, assume that the capacity auction
price was $42/mwh and the price of gas was $30/mwh.  In that instance, the [power generation
company] would overrecover its expected margin by
$2/mwh and would owe that amount to ratepayers.         
 
The
Commission adopted a formula for calculating the capacity auction true-up
amount that is substantially the same as that proposed by Reliant, except that
the Commission limited the true-up to the years 2002 and 2003, omitting any
calculation for the months in 2004 before a final true-up order is issued for
each power company.  No one challenges
Rule 25.263 with regard to the capacity auction true-up calculation.
The
capacity auction true-up calculation will be company-specific, based on a
margin developed in each company=s unbundled cost of service (UCOS)
proceeding.[110]  This information appears to be confidential
because of competition concerns.  It is
not part of our record and is not available on the Commission=s website.
What can
be gleaned from the record in this proceeding is that some portion of the
margin that results from the capacity auction true-up may contain a component
that allows a return of or on stranded costs. 
The court of appeals held that if a power company is entitled to bill
the transmission and distribution utility for the amount that netting the final
fuel balance and capacity auction true-up yields, then that amount cannot be
netted against a stranded cost calculation that results in a negative number.[111]  The court of appeals= determination has not been challenged in
this Court and is final.  However, that
determination does not foreclose the Commission from taking into account any
return of or on stranded costs that the margin from the capacity auction
true-up contains in determining the appropriate carrying costs on stranded
costs.  Section 39.262, which addresses
true-up proceedings, provides at the outset that A[a]n
electric utility . . . may not be permitted to overrecover
stranded costs through the procedures established by this section or through
the application of the measures provided by the other sections of this chapter.@[112]  In
setting a competition transition charge or allowing securitization of stranded
costs at the conclusion of a final true-up proceeding, the Commission can
ensure that there is no overrecovery of stranded
costs or carrying costs on stranded costs if the capacity auction true-up
margin has already provided a return of or on part of those stranded costs.[113]
TIEC is
incorrect when it contends that the margin yielded in the ECOM model worksheets
for each company with regard to the capacity auction true-up was intended by the
Legislature to be the only means of recovering carrying costs on stranded costs
until 2004.  Sections 39.201 and
39.262(d) contemplate that a company may recover both competition transition
charges from January 1, 2002, as well as the margin contemplated in the
capacity auction true-up.[114]  As recognized by the court of appeals, Athe [L]egislature
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.@[115]  But
there may be some overlap of recovery of carrying costs on stranded costs under
these sections.  The extent to which
carrying costs on stranded costs have been recovered in the margin provided by
the capacity auction true-up for 2002 and 2003 remains to be determined.
* * * * *
For the reasons considered above, we hold that Rule 25.263(l)(3) is
invalid, and we remand this proceeding to the Commission for further
consideration.
 
_____________________________________
Priscilla R. Owen
Justice
 
 
OPINION DELIVERED: June 18, 2004




[1] See generally City of Corpus
Christi v. Pub. Util. Comm=n, 51 S.W.3d 231, 238 (Tex. 2001).


[2] See generally Chapter 39 of
the Texas Public Utility Regulatory Act, Tex.
Util. Code '' 39.001-.910.


[3] Id. ' 39.001(b).


[4] Id. ' 39.251(7).


[5] Id. ' 39.001(b)(2); see also City of
Corpus Christi, 51 S.W.3d at 237-38.


[6] Tex.
Util. Code ' 39.001(b)(2); see also City of
Corpus Christi, 51 S.W.3d at 238.


[7] Tex.
Util. Code ' 39.252(a).


[8] Id. '' 39.201, .251-.254, .256-.265,
.301-.313.


[9] Id. '' 39.201(k), .262(c).


[10] 16 Tex.
Admin. Code ' 25.263(l)(3).


[11] 101 S.W.3d 129, 146-47.


[12] See Tex. Pub. Util. Comm=n, Application of Reliant Energy
for Approval of Unbundled Cost of Service Rate Pursuant to PURA ' 39.201 and Public Utility Commission
Substantive Rule ' 25.344, Docket No. 22355 (Oct. 4, 2001)
(order), available at http://interchange.puc.state.tx.us
(accessed June 17, 2004); Tex. Pub. Util. Comm=n, Application of Central Power
& Light Company for Approval of Unbundled Cost of Service Rate Pursuant to
PURA ' 39.201 and Public Utility Commission
Substantive Rule ' 25.344, Docket No. 22352 (Oct. 5, 2001)
(order), available at http://interchange.puc.state.tx.us
(accessed June 17, 2004).


[13] 101 S.W.3d at 147.


[14] Id.


[15] Tex.
Util. Code ' 39.252(a).


[16] Id. ' 39.201(g); see also id. '' 39.251(7), .201(l).


[17] Id. ' 39.262(d).


[18] Id. ' 39.262(a) (utilities may not be
permitted to overrecover stranded costs).


[19] 26 Tex. Reg. 10498, 10520 (2001) (citing Tex. Util. Code ' 14.002); see also 26 Tex. Reg. 4359, 4360 (2001) (proposed June
15, 2001) (stating in the Notice of Proposed Rulemaking that Rule 25.263 was
proposed under Tex. Util. Code '' 14.002, 39.252, and 39.262).


[20] Tex.
Util. Code ' 14.002.


[21] 26 Tex. Reg. 10498, 10520 (2001) (citing Tex. Util. Code '' 39.252, .262).


[22] Tex.
Util. Code ' 39.001(e).


[23] Id.


[24] Id. ' 39.001(f).


[25] 101 S.W.3d at 132.


[26] Tex.
Gov=t Code ' 2001.174(2).


[27] See Pub. Util. Comm=n v. City Pub. Serv.
Bd. of San Antonio, 53
S.W.3d 310, 315-16 (Tex. 2001); see also Office of Pub. Util. Counsel v.
Pub. Util. Comm=n, 104 S.W.3d 225, 232 (Tex. App.BAustin 2003, no pet.).


[28] The prior decisions are City of
Corpus Christi v. Public Utility Commission, 51 S.W.3d 231 (Tex. 2001), TXU
Electric Co. v. Public Utility Commission, 51 S.W.3d 275 (Tex. 2001), and In
re TXU Electric Co., 67 S.W.3d 130 (Tex. 2001).


[29] Tex.
Util. Code ' 39.302(5).


[30] City of Corpus Christi, 51
S.W.3d at 238.


[31] Tex.
Util. Code ' 39.001(b)(2).


[32] City of Corpus Christi, 51
S.W.3d at 238.


[33] Tex.
Util. Code ' 39.301.


[34] The rule says:
 
The TDU [transmission and distribution
utility] shall be allowed to recover, or shall be liable for, carrying costs on
the true-up balance.  Carrying costs
shall be calculated using the utility=s cost of capital established in the
utility=s UCOS [unbundled cost of service]
proceeding, and shall be calculated for the period of time from the date of the
true-up final order until fully recovered.
 
16 Tex.
Admin. Code ' 25.263(l)(3).


[35] Id.


[36] Tex.
Util. Code ' 39.262(c).


[37] 26 Tex. Reg. 10498,
10519 (2001).


[38] 101 S.W.3d at 146-47.


[39] Tex.
Util. Code ' 39.262(d).


[40] Id. '' 39.201, .251(7), .262(c), .262(h).


[41] ___ S.W.3d at ___ (Brister, J.,
dissenting).


[42] Tex.
Util. Code ' 39.001(a).


[43] Id. '' 39.101(a), .102.


[44] Id. ' 39.001(b).


[45] Id. ' 39.052.


[46] Id. ' 39.051(b).


[47] Id. ' 39.202.


[48] Id. ' 39.202(a).


[49] See, e.g., id. '' 39.254, .262(i)
(referring to the Report to the Texas
Senate Interim Committee on Electric Utility Restructuring, Potentially
Strandable Investment (ECOM) Report: 1998 Update (Apr. 1998)).


[50] Id. ' 39.254.


[51] Id. ' 39.257.


[52] Id. ' 39.254.


[53] Id. ' 39.256.


[54] ARegulatory assets@ are defined in section 39.302(5) of
the Utilities Code.  See generally
City of Corpus Christi v. Pub. Util. Comm=n, 51 S.W.3d 231 (Tex. 2001); TXU Elec. Co. v. Pub. Util. Comm=n, 51 S.W.3d 275 (Tex. 2001).


[55] Tex.
Util. Code '' 39.201(i),
.301-.303.


[56] Id. ' 39.301.


[57] Id. '' 39.301, .303(a).


[58] Id. ' 39.301.


[59] Id.


[60] Id. ' 39.303(a).


[61] See generally TXU Elec. Co. v.
Pub. Util. Comm=n, 51 S.W.3d 275, 277 (Tex. 2001); City of Corpus Christi
v. Pub. Util. Comm=n, 51 S.W.3d 231, 235-36 (Tex. 2001). 


[62] Tex.
Util. Code ' 39.201(i)(1).


[63] Id. '' 39.301, .302(4), .302(7), .303.


[64] Id. '' 39.201(i),
.301; see also generally TXU Elec. Co., 51 S.W.3d at 281-84.


[65] Tex.
Util. Code ' 39.201(a), (c), (d).


[66] Id. ' 39.201(h) (referring to Utility Code
section 39.262(i)).


[67] Id. ' 39.201(g).  The freeze period is defined in Tex. Util. Code ' 39.052(a) as September 1, 1999 until
January 1, 2002.


[68] Id. ' 39.201(d), (g).


[69] Id. ' 39.201(l).


[70] Id.


[71] Id. ' 39.201(d).


[72] Id. ' 39.201(k).


[73] Id. ' 39.201(a)-(k).


[74] Id. ' 39.201(l).


[75] Id. '' 39.201(l), .262(g).


[76] 16 Tex.
Admin. Code ' 25.263(g)(2)(A).


[77] Tex.
Util. Code ' 39.201(a), (b), (d), (f), (g), (h),
(k).


[78] Id. ' 39.201(l).


[79] Id. ' 39.201(g), (h), (l) (emphasis
added).


[80] Id.


[81] Id. ' 39.262(c); see also id. ' 39.262(h) (describing the methods of
quantifying stranded costs Afor the purpose of finalizing the
stranded cost estimate used to establish the competition transition charge
under Section 39.201@).


[82] Id. ' 39.201(g).


[83] Id. ' 39.251(7).


[84] Id.; see also id. ' 39.262(h) (outlining the methods for
quantifying stranded costs to finalize the stranded cost estimate used to
establish the competition transition charge).


[85] Id. ' 39.251(7).


[86] Id. '' 39.251(7), .262(h).


[87] Id. ' 39.251(7).


[88] Id.


[89] Id. ' 39.262(d)(2).


[90] 67 S.W.3d 130 (Tex. 2001).


[91] Id. at 166 (Hecht, J.,
dissenting).


[92] Id. at 165-66 (Hecht, J.,
dissenting).


[93] See Tex. Util. Code ' 39.262(h).


[94] See id. ' 39.262(i).


[95] Id. '' 39.153, .262(d).


[96] Id.


[97] Id. ' 39.262(c).


[98] Id. ' 39.251(7).


[99] Id. ' 39.153(a).


[100] Id. ' 39.153(b).


[101] Id. ' 39.262(d).


[102] 16 Tex.
Admin. Code ' 25.263; see also 26 Tex. Reg. 10498, 10498-501, 10524 (2001).


[103] Tex.
Util. Code ' 39.262(d).


[104] Id.


[105] Id.


[106] 101 S.W.2d at 138-41.


[107] 26 Tex. Reg. 10498 (2001).


[108] Id. at 10501.


[109] Id.


[110] 16 Tex.
Admin. Code ' 25.263(i)(1).


[111] 101 S.W.3d at 138-41.


[112] Tex.
Util. Code ' 39.262(a).


[113] Id. '' 39.201(l), .252, .262(c).


[114] Id. '' 39.201, .262(a), (d).


[115] 101 S.W.3d at 140.


