UTILITIES CODE
CHAPTER 39. RESTRUCTURING OF ELECTRIC UTILITY INDUSTRY
SUBCHAPTER A. GENERAL PROVISIONS
§ 39.001. LEGISLATIVE POLICY AND PURPOSE. (a) The
legislature finds that the production and sale of electricity is
not a monopoly warranting regulation of rates, operations, and
services and that the public interest in competitive electric
markets requires that, except for transmission and distribution
services and for the recovery of stranded costs, electric services
and their prices should be determined by customer choices and the
normal forces of competition. As a result, this chapter is enacted
to protect the public interest during the transition to and in the
establishment of a fully competitive electric power industry.
(b) The legislature finds that it is in the public interest
to:
(1) implement on January 1, 2002, a competitive retail
electric market that allows each retail customer to choose the
customer's provider of electricity and that encourages full and
fair competition among all providers of electricity;
(2) allow utilities with uneconomic
generation-related assets and purchased power contracts to recover
the reasonable excess costs over market of those assets and
purchased power contracts;
(3) educate utility customers about anticipated
changes in the provision of retail electric service to ensure that
the benefits of the competitive market reach all customers; and
(4) protect the competitive process in a manner that
ensures the confidentiality of competitively sensitive information
during the transition to a competitive market and after the
commencement of customer choice.
(c) Regulatory authorities, excluding the governing body of
a municipally owned electric utility that has not opted for
customer choice or the body vested with power to manage and operate
a municipally owned electric utility that has not opted for
customer choice, may not make rules or issue orders regulating
competitive electric services, prices, or competitors or
restricting or conditioning competition except as authorized in
this title and may not discriminate against any participant or type
of participant during the transition to a competitive market and in
the competitive market.
(d) Regulatory authorities, excluding the governing body of
a municipally owned electric utility that has not opted for
customer choice or the body vested with power to manage and operate
a municipally owned electric utility that has not opted for
customer choice, shall authorize or order competitive rather than
regulatory methods to achieve the goals of this chapter to the
greatest extent feasible and shall adopt rules and issue orders
that are both practical and limited so as to impose the least impact
on competition.
(e) Judicial review of competition rules adopted by the
commission shall be conducted under Chapter 2001, Government Code,
except as otherwise provided by this chapter. Judicial review of
the validity of competition rules shall be commenced in the Court of
Appeals for the Third Court of Appeals District and shall be limited
to the commission's rulemaking record. The rulemaking record
consists of:
(1) the notice of the proposed rule;
(2) the comments of all interested persons;
(3) all studies, reports, memoranda, or other
materials on which the commission relied in adopting the rule; and
(4) the order adopting the rule.
(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. The notice of appeal shall designate the person
challenging the rule as the appellant and the commission as the
appellee. The commission shall prepare the rulemaking record and
file it with the court of appeals not later than the 30th day after
the date the notice of appeal is served on the commission. The
court of appeals shall hear and determine each appeal as
expeditiously as possible with lawful precedence over other
matters. The appellant, and any person who is permitted by the
court to intervene in support of the appellant's claims, shall file
and serve briefs not later than the 30th day after the date the
commission files the rulemaking record. The commission, and any
person who is permitted by the court to intervene in support of the
rule, shall file and serve briefs not later than the 60th day after
the date the appellant files the appellant's brief. The court of
appeals may, on its own motion or on motion of any person for good
cause, modify the filing deadlines prescribed by this subsection.
The court of appeals shall render judgment affirming the rule or
reversing and, if appropriate on reversal, remanding the rule to
the commission for further proceedings, consistent with the court's
opinion and judgment. The Texas Rules of Appellate Procedure apply
to an appeal brought under this section to the extent not
inconsistent with this section.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.002. APPLICABILITY. This chapter, other than
Sections 39.155, 39.157(e), 39.203, 39.903, and 39.904, does not
apply to a municipally owned utility or an electric cooperative.
Sections 39.157(e), 39.203, and 39.904, however, apply only to a
municipally owned utility or an electric cooperative that is
offering customer choice. If there is a conflict between the
specific provisions of this chapter and any other provisions of
this title, except for Chapters 40 and 41, the provisions of this
chapter control.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.003. CONTESTED CASES. Unless specifically
provided otherwise, each commission proceeding under this chapter,
other than a rulemaking proceeding, report, notification, or
registration, shall be conducted as a contested case and the burden
of proof is on the incumbent electric utility.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
SUBCHAPTER B. TRANSITION TO COMPETITIVE RETAIL ELECTRIC MARKET
§ 39.051. UNBUNDLING. (a) On or before September 1,
2000, each electric utility shall separate from its regulated
utility activities its customer energy services business
activities that are otherwise also already widely available in the
competitive market.
(b) Not later than January 1, 2002, each electric utility
shall separate its business activities from one another into the
following units:
(1) a power generation company;
(2) a retail electric provider; and
(3) a transmission and distribution utility.
(c) An electric utility may accomplish the separation
required by Subsection (b) either through the creation of separate
nonaffiliated companies or separate affiliated companies owned by a
common holding company or through the sale of assets to a third
party. An electric utility may create separate transmission and
distribution utilities.
(d) Each electric utility shall unbundle under this section
in a manner that provides for a separation of personnel,
information flow, functions, and operations, consistent with
Section 39.157(d).
(e) Each electric utility shall file with the commission a
plan to implement this section by January 10, 2000.
(f) The commission shall adopt the utility's plan for
business separation required by Subsection (b), adopt the plan with
changes, or reject the plan and require the utility to file a new
plan.
(g) Transactions by electric utilities involving sales,
transfers, or other disposition of assets to accomplish the
purposes of this section are not subject to Section 14.101, 35.034,
or 35.035.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.052. FREEZE ON EXISTING RETAIL BASE RATE
TARIFFS. (a) Until January 1, 2002, an electric utility shall
provide retail electric service within its certificated service
area in accordance with the electric utility's retail base rate
tariffs in effect on September 1, 1999, including its purchased
power cost recovery factor.
(b) During the freeze period, an electric utility may not
increase its retail base rates above the rates provided by this
section except for losses caused by force majeure as provided by
Section 39.055.
(c) Notwithstanding any other provision of this title,
during the freeze period the regulatory authority may not reduce
the retail base rates of an electric utility, except as may be
ordered as stipulated to by an electric utility in a proceeding for
which a final order had not been issued by January 1, 1999.
(d) During the freeze period, the retail base rates, overall
revenues, return on invested capital, and net income of an electric
utility are not subject to complaint, hearing, or determination as
to reasonableness.
(e) An electric utility that has a rate proceeding pending
before the commission as of January 2, 1999, shall provide service
in accordance with the tariffs approved in that proceeding from the
date of approval until the end of the freeze period.
(f) Nothing in this section affects the authority of the
commission to fulfill its obligations under Section 39.262.
(g) Nothing in this section shall deny a utility its right
to have the commission conduct proceedings and issue a final order
pertaining to any matter that may be remanded to the commission by a
court having jurisdiction, except that the final order may not
affect the rates charged to customers during the freeze period but
shall be taken into account during the utility's true-up proceeding
under Section 39.262.
(h) Nothing in this title shall be construed to prevent an
electric utility or a transmission and distribution utility from
filing, and the commission from approving, a change in wholesale
transmission service rates during the freeze period.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.053. COST RECOVERY ADJUSTMENTS. This subchapter
does not limit or alter the ability of an electric utility during
the freeze period to revise its fuel factor or to reconcile fuel
expenses and to either refund fuel overcollections or surcharge
fuel undercollections to customers, as authorized by its tariffs
and Sections 36.203 and 36.205.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.054. RETAIL ELECTRIC SERVICE DURING FREEZE
PERIOD. (a) An electric utility shall provide retail electric
service during the freeze period in accordance with any contract
terms applicable to a particular retail customer approved by the
regulatory authority and in effect on December 31, 1998.
(b) Nothing in Sections 39.052(c) and (d) shall be construed
to restrict any customer's right to complain during the freeze
period to the regulatory authority regarding the quality of retail
electric service provided by the electric utility or the
applicability of an electric utility's particular tariff to the
customer.
(c) Nothing in this title shall be construed to restrict an
electric utility, voluntarily and at its sole discretion, from
offering new services or new tariff options to its customers during
the freeze period, consistent with Section 39.051(a).
(d) Any offering of new services or tariff options under
this section shall be equal to or greater than an electric utility's
long-run marginal cost and may not be unreasonably preferential,
prejudicial, discriminatory, predatory, or anticompetitive.
(e) Revenue from any new offering under this section shall
be accounted for in a manner consistent with Section 36.007.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.055. FORCE MAJEURE. (a) An electric utility may
recover losses resulting from force majeure through an increase in
its retail base rates during the freeze period.
(b) Notwithstanding Subchapter C, Chapter 36, the
regulatory authority, after a hearing to determine the electric
utility's losses from force majeure, shall permit the utility to
fully collect any approved force majeure increase through an
appropriate customer surcharge mechanism.
(c) For purposes of this section, "force majeure" means a
major event or combination of major events, including new or
expanded state or federal statutory or regulatory requirements;
hurricanes, tornadoes, ice storms, or other natural disasters; or
acts of war, terrorism, or civil disturbance, beyond the control of
an electric utility that the regulatory authority finds increases
the utility's total reasonable and necessary nonfuel costs or
decreases the utility's total nonfuel revenues related to the
generation and delivery of electricity by more than 10 percent for
any calendar year during the freeze period. The term does not
include any changes in general economic conditions such as
inflation, interest rates, or other factors of general application.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
SUBCHAPTER C. RETAIL COMPETITION
§ 39.101. CUSTOMER SAFEGUARDS. (a) Before customer
choice begins on January 1, 2002, the commission shall ensure that
retail customer protections are established that entitle a
customer:
(1) to safe, reliable, and reasonably priced
electricity, including protection against service disconnections
in an extreme weather emergency as provided by Subsection (h) or in
cases of medical emergency or nonpayment for unrelated services;
(2) to privacy of customer consumption and credit
information;
(3) to bills presented in a clear format and in
language readily understandable by customers;
(4) to the option to have all electric services on a
single bill, except in those instances where multiple bills are
allowed under Chapters 40 and 41;
(5) to protection from discrimination on the basis of
race, color, sex, nationality, religion, or marital status;
(6) to accuracy of metering and billing;
(7) to information in English and Spanish and any
other language as necessary concerning rates, key terms and
conditions, in a standard format that will permit comparisons
between price and service offerings, and the environmental impact
of certain production facilities;
(8) to information in English and Spanish and any
other language as necessary concerning low-income assistance
programs and deferred payment plans; and
(9) to other information or protections necessary to
ensure high-quality service to customers.
(b) A customer is entitled:
(1) to be informed about rights and opportunities in
the transition to a competitive electric industry;
(2) to choose the customer's retail electric provider
consistent with this chapter, to have that choice honored, and to
assume that the customer's chosen provider will not be changed
without the customer's informed consent;
(3) to have access to providers of energy efficiency
services, to on-site distributed generation, and to providers of
energy generated by renewable energy resources;
(4) to be served by a provider of last resort that
offers a commission-approved standard service package;
(5) to receive sufficient information to make an
informed choice of service provider;
(6) to be protected from unfair, misleading, or
deceptive practices, including protection from being billed for
services that were not authorized or provided; and
(7) to have an impartial and prompt resolution of
disputes with its chosen retail electric provider and transmission
and distribution utility.
(c) A retail electric provider, power generation company,
aggregator, or other entity that provides retail electric service
may not refuse to provide retail electric or electric generation
service or otherwise discriminate in the provision of electric
service to any customer because of race, creed, color, national
origin, ancestry, sex, marital status, lawful source of income,
disability, or familial status. A retail electric provider, power
generation company, aggregator, or other entity that provides
retail electric service may not refuse to provide retail electric
or electric generation service to a customer because the customer
is located in an economically distressed geographic area or
qualifies for low-income affordability or energy efficiency
services. The commission shall require a provider to comply with
this subsection as a condition of certification or registration.
(d) A retail electric provider, power generation company,
aggregator, or other entity that provides retail electric service
shall submit reports to the commission and the office annually and
on request relating to the person's compliance with this section.
The commission by rule shall specify the form in which a report must
be submitted. A report must include:
(1) information regarding the extent of the person's
coverage;
(2) information regarding the service provided,
compiled by zip code and census tract; and
(3) any other information the commission or the office
considers relevant to determine compliance.
(e) The commission has the authority to adopt and enforce
such rules as may be necessary or appropriate to carry out
Subsections (a)-(d), including rules for minimum service standards
for a retail electric provider relating to customer deposits and
the extension of credit, switching fees, levelized billing
programs, interconnection and use of on-site generation,
termination of service, and quality of service. The commission has
jurisdiction over all providers of electric service in enforcing
Subsections (a)-(d) and may assess civil and administrative
penalties under Section 15.023 and seek civil penalties under
Section 15.028.
(f) On or before June 30, 2001, the commission shall modify
its current rules regarding customer protections to ensure that at
least the same level of customer protection against potential
abuses and the same quality of service that exists on December 31,
1999, is maintained in a restructured electric industry.
(g) Compliance with Subsections (a)-(e) by a provider of
electric service which is a municipally owned utility shall be
administered solely by the governing body of the municipally owned
utility, which shall adopt, implement, and enforce, as to the
municipally owned utility, rules having the effect of accomplishing
the objectives of Subsections (a)-(e). Reports containing the
information required by Subsection (d) shall be filed by the
municipally owned utility with the governing body.
(h) A retail electric provider, power generation company,
aggregator, or other entity that provides retail electric service
may not disconnect service to a residential customer during an
extreme weather emergency or on a weekend day. The entity providing
service shall defer collection of the full payment of bills that are
due during an extreme weather emergency until after the emergency
is over and shall work with customers to establish a pay schedule
for deferred bills. For purposes of this subsection, "extreme
weather emergency" means a period when:
(1) the previous day's highest temperature did not
exceed 32 degrees Fahrenheit and the temperature is predicted to
remain at or below that level for the next 24 hours according to the
nearest National Weather Service reports; or
(2) the National Weather Service issues a heat
advisory for any county in the relevant service territory, or when
such an advisory has been issued on any one of the previous two
calendar days.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.102. RETAIL CUSTOMER CHOICE. (a) Each retail
customer in this state, except retail customers of electric
cooperatives and municipally owned utilities that have not opted
for customer choice, shall have customer choice on and after
January 1, 2002.
(b) The affiliated retail electric provider of the electric
utility serving a retail customer on December 31, 2001, may
continue to serve that customer until the customer chooses service
from a different retail electric provider, an electric cooperative
offering customer choice, or a municipally owned utility offering
customer choice.
(c) An electric utility that has in effect a systemwide
freeze for residential and commercial customers in effect September
1, 1997, extending beyond December 31, 2001, that has been found by
a regulatory authority to be in the public interest is not subject
to this chapter. At the expiration of the utility's freeze period,
the utility shall be subject to this chapter and, at that time, has
no claim for stranded cost recovery.
(d) The commission shall oversee the compliance with this
chapter by electric utilities that were not subject to this chapter
before September 1, 2003, and in so doing shall establish schedules
and procedures and require commission approvals as it deems
necessary to achieve the objectives of this chapter. This
subsection does not apply to an electric utility to which
Subsection (c) applies.
(e) In establishing a schedule under Subsection (d), the
commission shall consider:
(1) the effect of customer choice on the reliability
of service provided by the electric utility;
(2) whether the electric utility's service area is
located in more than one power region;
(3) whether any applicable power region has been
certified as a qualifying power region under Section 39.152(a);
(4) whether other electric utilities in the power
region offer retail customer choice; and
(5) any other relevant factor.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
Amended by Acts 2003, 78th Leg., ch. 1327, § 2, eff. Sept. 1,
2003.
§ 39.1025. LIMITATIONS ON TELEPHONE
SOLICITATION. (a) A person may not make or cause to be made a
telephone solicitation to an electricity customer who has given
notice to the commission of the customer's objection to receiving
telephone solicitations relating to the customer's choice of retail
electric providers.
(b) The commission shall establish and provide for the
operation of a database to compile a list of customers who object to
receiving telephone solicitations. The commission may operate the
database or contract with another entity to operate the database.
(c) A customer shall pay a fee of not more than $5 for
inclusion in the database. The commission shall prescribe the
amount of the fee.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.103. COMMISSION AUTHORITY TO DELAY COMPETITION AND
SET NEW RATES. If the commission determines under Section 39.104
that a power region is unable to offer fair competition and reliable
service to all retail customer classes on January 1, 2002, the
commission shall delay customer choice for the power region and may
on or after January 1, 2002, establish new rates for all electric
utilities in the power region as provided by Chapter 36.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.104. CUSTOMER CHOICE PILOT
PROJECTS. (a) Customer choice pilot projects may be used to allow
the commission to evaluate the ability of each power region and
electric utility to implement customer choice. However, in a
multiply certificated area, an electric utility may not include
customers that were served by an electric cooperative or a
municipally owned utility on May 1, 1999.
(b) The commission shall require each electric utility to
offer customer choice in its service area within this state
amounting to five percent of the utility's combined load of all
customer classes within this state beginning on June 1, 2001.
(c) The load designated for customer choice under this
section shall be distributed among all customer classes of a
utility consistent with the purpose of this section and subject to
commission approval.
(d) Customers participating in a pilot project under this
section may buy electric energy from any retail electric provider
certified by the commission under Section 39.352, including an
affiliated retail electric provider; provided, however, that a
retail electric provider may not participate in a pilot project in
the certificated service area served by the electric utility with
which it is affiliated.
(e) Each utility operating a pilot project under this
section shall charge residential and small commercial customers in
accordance with Section 39.052.
(f) The commission may prescribe reporting requirements it
considers necessary to evaluate a pilot project consistent with the
purpose of this section.
(g) Customers having customer choice under this section
shall be billed as provided by Section 39.107.
(h) The commission may prescribe terms and conditions it
considers necessary to prohibit anticompetitive practices and to
encourage customer choice offered under this section.
(i) Notwithstanding any other provision of this title, a
retail electric provider participating in a pilot project under
this section is not an electric utility or a retail electric
utility.
(j) Twenty percent of the load designated for customer
choice under this section shall be initially set aside for
aggregated loads.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.105. LIMITATION ON SALE OF
ELECTRICITY. (a) After January 1, 2002, a transmission and
distribution utility may not sell electricity or otherwise
participate in the market for electricity except for the purpose of
buying electricity to serve its own needs.
(b) A person or retail electric utility may not provide,
furnish, or make available electric service at retail within the
certificated service area of an electric cooperative that has not
adopted customer choice or a municipally owned utility that has not
adopted customer choice. However, this subsection does not
prohibit the provision of electric service in multiply certificated
service areas to customers of any other retail electric utility.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.106. PROVIDER OF LAST RESORT. (a) The commission
shall designate retail electric providers in areas of the state in
which customer choice is in effect to serve as providers of last
resort.
(b) A provider of last resort shall offer a standard retail
service package for each class of customers designated by the
commission at a fixed, nondiscountable rate approved by the
commission.
(c) A provider of last resort shall provide the standard
retail service package to any requesting customer in the territory
for which it is the provider of last resort.
(d) The commission shall designate the provider or
providers of last resort not later than June 1, 2001.
(e) The commission shall determine the procedures and
criteria, which may include the solicitation of bids, for
designating a provider or providers of last resort. The commission
may redesignate the provider of last resort according to a schedule
it considers appropriate.
(f) In the event that no retail electric provider applies to
be the provider of last resort for a given area of the state on
reasonable terms and conditions, the commission may require a
retail electric provider to become the provider of last resort as a
condition of receiving or maintaining a certificate under Section
39.352.
(g) In the event that a retail electric provider fails to
serve any or all of its customers, the provider of last resort shall
offer that customer the standard retail service package for that
customer class with no interruption of service to any customer.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.107. METERING AND BILLING SERVICES. (a) On
introduction of customer choice in a service area, metering
services for the area shall continue to be provided by the
transmission and distribution utility affiliate of the electric
utility that was serving the area before the introduction of
customer choice. Metering services provided to commercial and
industrial customers shall be provided on a competitive basis
beginning on January 1, 2004.
(b) Metering services provided to residential customers
shall continue to be provided by the transmission and distribution
utility affiliate of the electric utility that was serving the area
before the introduction of customer choice until the later of
September 1, 2005, or the date on which at least 40 percent of those
residential customers are taking service from unaffiliated retail
electric providers. Metering and billing services provided to
residential customers shall be governed by the customer safeguards
adopted by the commission under Section 39.101.
(c) Beginning on the date of introduction of customer choice
in a service area, tenants of leased or rented property that is
separately metered shall have the right to choose a retail electric
provider, an electric cooperative offering customer choice, or a
municipally owned utility offering customer choice, and the owner
of the property must grant reasonable and nondiscriminatory access
to transmission and distribution utilities, retail electric
providers, electric cooperatives, and municipally owned utilities
for metering purposes.
(d) Beginning on the date of introduction of customer choice
in a service area, a transmission and distribution utility, or an
electric cooperative or municipally owned utility providing the
customer's energy requirements shall bill a customer's retail
electric provider for nonbypassable delivery charges as determined
under Section 39.201. The retail electric provider or the electric
cooperative or municipally owned utility, as appropriate, must pay
these charges.
(e) A transmission and distribution utility may bill retail
customers at the request of a retail electric provider or, if an
electric cooperative or municipally owned utility is providing the
customer's energy requirements, at the request of the electric
cooperative or municipally owned utility. A transmission and
distribution utility that provides billing service on such request
shall offer billing service on comparable terms and conditions to
those of any such requesting retail electric provider or, as
applicable, the electric cooperative or municipally owned utility
providing energy requirements to a customer served by the
transmission and distribution utility.
(f) Beginning on the date of introduction of customer choice
in a service area, any charges for metering and billing services
shall comply with rules adopted by the commission relating to
nondiscriminatory rates of service.
(g) Metered electric service sold to residential customers
on a prepaid basis may not be sold at a price that is higher than the
price charged by the provider of last resort.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.108. CONTRACTUAL OBLIGATIONS. This chapter may
not:
(1) interfere with or abrogate the rights or
obligations of any party, including a retail or wholesale customer,
to a contract with an investor-owned electric utility, river
authority, municipally owned utility, or electric cooperative;
(2) interfere with or abrogate the rights or
obligations of a party under a contract or agreement concerning
certificated utility service areas; or
(3) result in a change in wholesale power costs to
wholesale customers in Texas purchasing electricity under
wholesale power contracts the pricing provisions of which are based
on formulary rates, fuel adjustments, or average system costs.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.109. NEW OWNER OR SUCCESSOR. (a) To ensure the
continued safe and reliable operation of electric generating
facilities, the commission shall require a generating facility that
is transferred to a new owner or successor in interest between June
1, 1999, and January 1, 2002, to continue to be operated and
maintained by the same operating personnel for not less than two
years, except that the personnel may be dismissed for cause.
(b) This section shall apply only if the facility is
actually operated during the two-year period after the sale.
(c) This section shall not require that the purchaser cause
the facility to be operated in whole or in part, nor shall it
preclude a temporary closure of the facility during the two-year
period.
(d) This section shall not create any obligation extending
after the two-year period following the sale.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
SUBCHAPTER D. MARKET STRUCTURE
§ 39.151. ESSENTIAL ORGANIZATIONS. (a) A power region
must establish one or more independent organizations to perform the
following functions:
(1) ensure access to the transmission and distribution
systems for all buyers and sellers of electricity on
nondiscriminatory terms;
(2) ensure the reliability and adequacy of the
regional electrical network;
(3) ensure that information relating to a customer's
choice of retail electric provider is conveyed in a timely manner to
the persons who need that information; and
(4) ensure that electricity production and delivery
are accurately accounted for among the generators and wholesale
buyers and sellers in the region.
(b) "Independent organization" means an independent system
operator or other person that is sufficiently independent of any
producer or seller of electricity that its decisions will not be
unduly influenced by any producer or seller. An entity will be
deemed to be independent if it is governed by a board that has three
representatives from each segment of the electric market, with the
consumer segment being represented by one residential customer, one
commercial customer, and one industrial retail customer.
(c) The commission shall certify an independent
organization or organizations to perform the functions prescribed
by this section.
(d) An independent organization certified by the commission
for a power region shall establish and enforce procedures,
consistent with this title and the commission's rules, relating to
the reliability of the regional electrical network and accounting
for the production and delivery of electricity among generators and
all other market participants. The procedures shall be subject to
commission oversight and review.
(e) The commission may authorize an independent
organization that is certified under this section to charge a
reasonable and competitively neutral rate to wholesale buyers and
sellers to cover the independent organization's costs.
(f) In implementing this section, the commission may
cooperate with the utility regulatory commission of another state
or the federal government and may hold a joint hearing or make a
joint investigation with that commission.
(g) If it amends its governance rules to provide that its
governing body is composed as prescribed by this subsection, the
existing independent system operator in ERCOT will meet the
criteria provided by Subsection (a) with respect to ensuring access
to the transmission systems for all buyers and sellers of
electricity in the ERCOT region and ensuring the reliability of the
regional electrical network. To comply with this subsection, the
governing body must be composed of:
(1) the chairman of the commission as an ex officio
nonvoting member;
(2) the counsellor as an ex officio voting member;
(3) the director of the independent system operator as
an ex officio voting member;
(4) four representatives of the power generation
sector as voting members;
(5) four representatives of the transmission and
distribution sector as voting members;
(6) four representatives of the power sales sector as
voting members; and
(7) the following people as voting members, appointed
by the commission:
(A) one representative of residential customers;
(B) one representative of commercial customers;
and
(C) one representative of industrial customers.
The four representatives specified in each of Subdivisions
(4), (5), and (6) shall be selected in a manner that ensures
equitable representation for the various sectors of industry
participants.
(h) The ERCOT independent system operator may meet the
criteria relating to the other functions of an independent
organization provided by Subsection (a) by adopting procedures and
acquiring resources needed to carry out those functions.
(i) The commission may delegate authority to the existing
independent system operator in ERCOT to enforce operating standards
within the ERCOT regional electrical network and to establish and
oversee transaction settlement procedures. The commission may
establish the terms and conditions for the ERCOT independent system
operator's authority to oversee utility dispatch functions after
the introduction of customer choice.
(j) A retail electric provider, municipally owned utility,
electric cooperative, power marketer, transmission and
distribution utility, or power generation company shall observe all
scheduling, operating, planning, reliability, and settlement
policies, rules, guidelines, and procedures established by the
independent system operator in ERCOT. Failure to comply with this
subsection may result in the revocation, suspension, or amendment
of a certificate as provided by Section 39.356 or in the imposition
of an administrative penalty as provided by Section 39.357.
(k) To the extent the commission has authority over an
independent organization outside of ERCOT, the commission may
delegate authority to the independent organization consistent with
Subsection (i).
(l) No operational criteria, protocols, or other
requirement established by an independent organization, including
the ERCOT independent system operator, may adversely affect or
impede any manufacturing or other internal process operation
associated with an industrial generation facility, except to the
minimum extent necessary to assure reliability of the transmission
network.
(m) A power region outside of ERCOT shall be deemed to have
met the requirement to establish an independent organization to
perform the transmission functions specified in Subsection (a) if
the Federal Energy Regulatory Commission has approved a regional
transmission organization for the region and found that the
regional transmission organization meets the requirements of
Subsection (a).
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.152. QUALIFYING POWER REGIONS. (a) The
commission shall certify a power region if:
(1) a sufficient number of interconnected utilities in
the power region fall under the operational control of an
independent organization as described by Section 39.151;
(2) the power region has a generally applicable tariff
that guarantees open and nondiscriminatory access for all users to
transmission and distribution facilities in the power region as
provided by Section 39.203; and
(3) no person owns and controls more than 20 percent of
the installed generation capacity located in or capable of
delivering electricity to a power region, as determined according
to Section 39.154.
(b) In determining whether a power region not entirely
within the state meets the requirements of this section, the
commission shall consider the extent to which the available
transmission facilities limit the delivery of electricity from
generators located outside the state to areas of the power region
within the state.
(c) For a power region outside of ERCOT, the requirements of
Subsection (a)(2) shall be deemed to have been met if power
aggregating to approximately 50,000 megawatts can be delivered to
the portion of the power region that is in this state through the
payment of not more than one transmission tariff.
(d) For a power region outside of ERCOT, a power generation
company that is affiliated with an electric utility may elect to
demonstrate that it meets the requirements of Subsection (a)(3) by
showing that it does not own and control more than 20 percent of the
installed capacity in a geographic market that includes the power
region, using the guidelines, standards, and methods adopted by the
Federal Energy Regulatory Commission.
(e) In a power region outside of ERCOT, if customer choice
is introduced before the requirements of Subsection (a) are met, an
affiliated retail electric provider may not compete for retail
customers in any area of the power region that is within this state
and outside of the affiliated transmission and distribution
utility's certificated service area unless the affiliated power
generation company makes a commitment to maintain and does maintain
rates that are based on cost of service for any electric cooperative
or municipally owned utility that was a wholesale customer on
January 1, 1999, and was purchasing power at rates that were based
on cost of service. This subsection requires a power generation
company to sell power at rates that are based on cost of service,
notwithstanding the expiration of a contract for that service,
until the requirements of Subsection (a) are met.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.153. CAPACITY AUCTION. (a) Each electric utility
subject to this section shall sell at auction, at least 60 days
before the date set for customer choice to begin, entitlements to at
least 15 percent of the electric utility's Texas jurisdictional
installed generation capacity. For the purposes of this section,
the term "electric utility" includes any affiliated power
generation company that is unbundled from the electric utility in
accordance with Section 39.051, but does not include any entity
owning less than 400 megawatts of installed generation capacity.
(b) The obligation to auction the entitlements shall
continue until the earlier of 60 months after the date customer
choice is introduced 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 utility's certificated service area before the onset
of customer choice is provided by nonaffiliated retail electric
providers.
(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. Entitlements may only be purchased by entities lawfully
able to sell electricity in Texas.
(d) An electric utility may choose to auction additional
entitlements beyond those required by Subsection (a) or continue to
auction entitlements after the period required by Subsection (b) in
order to comply with Section 39.154.
(e) The commission shall adopt rules by December 31, 2000,
that define the scope of the capacity entitlements to be auctioned.
Entitlements may be auctioned in blocks of less than 15 percent.
The rules shall state the minimum amount of capacity that can be
sold at auction as an entitlement. At a minimum, the rules shall
provide that the entitlements:
(1) may be sold and purchased in periods of not less
than one month nor more than four years;
(2) may be resold to any lawful purchaser, except for a
retail electric provider affiliated with the electric utility that
originally auctioned the entitlement;
(3) include no possessory interest in the unit from
which the power is produced;
(4) include no obligations of a possessory owner of an
interest in the unit from which the power is produced; and
(5) give the purchaser the right to designate the
dispatch of the entitlement, subject to planned outages, outages
beyond the control of the utility operating the unit, and other
considerations subject to the oversight of the applicable
independent organization.
(f) The commission shall adopt rules by December 31, 2000,
that prescribe the procedure for the auction of the entitlements.
The rules shall include:
(1) a process for conducting the auction or auctions,
including who shall conduct it, how often it shall be conducted, and
how winning bidders shall be determined;
(2) a process for the electric utility to designate
which generation units or combination of units are offered for
auction;
(3) a provision for the utility to establish an
opening bid price based on the electric utility's expected cost,
with the commission prescribing the means for determining the
opening bid price, which may not include return on equity; and
(4) a provision that allows a bidder to specify the
magnitude and term of the entitlement, subject to the conditions
established in Subsection (e).
(g) In adopting the process under Subsection (f)(2), the
commission shall consider the furtherance of the development of the
competitive market, the cost of transmission, physical constraints
of the transmission system, the proximity of the generation to
load, economic efficiency, and any other factors the commission
finds relevant. The process may provide for commission approval of
the designation before auction. The commission may consult with
the applicable independent organization to develop the process.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.154. LIMITATION OF OWNERSHIP OF INSTALLED
CAPACITY. (a) Beginning on the date of introduction of customer
choice, a power generation company may not own and control more than
20 percent of the installed generation capacity located in, or
capable of delivering electricity to, a power region.
(b) In a power region not entirely within the state, the
commission may waive or modify the requirement in Subsection (a) on
a finding of good cause.
(c) In determining the percentage shares of installed
generation capacity under this section, the commission shall
combine capacity owned and controlled by a power generation company
and any entity that is affiliated with that power generation
company within the power region, reduced by the installed
generation capacity of those facilities that are made subject to
capacity auctions under Sections 39.153(a) and (d).
(d) In this chapter, "installed generation capacity" means
all potentially marketable electric generation capacity, including
the capacity of:
(1) generating facilities that are connected with a
transmission or distribution system;
(2) generating facilities used to generate
electricity for consumption by the person owning or controlling the
facility; and
(3) generating facilities that will be connected with
a transmission or distribution system and operating within 12
months.
(e) In determining the percentage shares of installed
generation capacity owned and controlled by a power generation
company under this section and Section 39.156, the commission
shall, for purposes of calculating the numerator, reduce the
installed generation capacity owned and controlled by that power
generation company by the installed generation capacity of any
"grandfathered facility" within an ozone nonattainment area as of
September 1, 1999, for which that power generation company has
commenced complying or made a binding commitment to comply with
Section 39.264. This subsection applies only to a power generation
company that is affiliated with an electric utility that owned and
controlled more than 27 percent of the installed generation
capacity in the power region on January 1, 1999.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.155. COMMISSION ASSESSMENT OF MARKET
POWER. (a) Each person, municipally owned utility, electric
cooperative, and river authority that owns generation facilities
and offers electricity for sale in this state shall report to the
commission its installed generation capacity, the total amount of
capacity available for sale to others, the total amount of capacity
under contract to others, the total amount of capacity dedicated to
its own use, its annual wholesale power sales in the state, its
annual retail power sales in the state, and any other information
necessary for the commission to assess market power or the
development of a competitive retail market in the state. The
commission shall by rule prescribe the nature and detail of the
reporting requirements and shall administer those reporting
requirements in a manner that ensures the confidentiality of
competitively sensitive information.
(b) The ERCOT independent system operator shall submit an
annual report to the commission identifying existing and potential
transmission and distribution constraints and system needs within
ERCOT, alternatives for meeting system needs, and recommendations
for meeting system needs. The first report shall be submitted on or
before October 1, 1999. Subsequent reports shall be submitted by
January 15 of each year or as determined necessary by the
commission.
(c) Before the date of introduction of customer choice in a
power region other than ERCOT, each electric utility owning
transmission and distribution facilities in that region shall
submit an annual report to the commission identifying existing and
potential transmission and distribution constraints and system
needs in the power region, alternatives for meeting system needs,
and recommendations for meeting system needs as directed by the
commission.
(d) In a qualifying power region, the reports required by
Subsections (b) and (c) shall be submitted by the independent
organization or organizations having authority over the power
region or discrete areas thereof.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.156. MARKET POWER MITIGATION PLAN. (a) In this
section, "market power mitigation plan" or "plan" means a written
proposal by an electric utility or a power generation company for
reducing its ownership and control of installed generation capacity
as required by Section 39.154.
(b) An electric utility or power generation company owning
and controlling more than 20 percent of the generation capacity
located in, or capable of delivering electricity to, a power region
shall file a market power mitigation plan with the commission not
later than December 1, 2000.
(c) The plan may provide for:
(1) the sale of generation assets to a nonaffiliated
person;
(2) the exchange of generation assets with a
nonaffiliated person located in a different power region;
(3) the auctioning of generation capacity
entitlements as part of a capacity auction required by Section
39.153;
(4) the sale of the right to capacity to a
nonaffiliated person for at least four years; or
(5) any reasonable method of mitigation.
(d) For the purposes of this section, generation capacity
shall be net of the generation capacity subject to an auction under
Section 39.153.
(e) The plan shall be in a form prescribed by the commission
and shall provide information the commission finds reasonably
necessary to evaluate the plan.
(f) The commission shall approve, modify, or reject a plan
within 180 days after the date of a filing under Subsection (b).
The commission may not modify a plan to require divestiture by the
electric utility or the power generation company.
(g) In reaching its determination under Subsection (f), the
commission shall consider:
(1) the degree to which the electric utility's or power
generation company's stranded costs, if any, are minimized;
(2) whether on disposition of the generation assets
the reasonable value is likely to be received;
(3) the effect of the plan on the electric utility's or
power generation company's federal income taxes;
(4) the effect of the plan on current and potential
competitors in the generation market; and
(5) whether the plan is consistent with the public
interest.
(h) An electric utility or power generation company with an
approved mitigation plan may request to amend or repeal its plan.
On a showing of good cause, the commission shall modify or repeal an
electric utility's or power generation company's mitigation plan.
(i) If an electric utility's or a power generation company's
market power mitigation plan is not approved before January 1 of the
year it is to take effect, the commission may order the electric
utility or power generation company to auction generation capacity
entitlements according to Section 39.153, subject to commission
approval, of any capacity exceeding the maximum allowable capacity
prescribed by Section 39.154 until the time a mitigation plan is
approved.
(j) An auction under Subsection (i) shall be held not later
than 60 days after the date the order is entered.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.157. COMMISSION AUTHORITY TO ADDRESS MARKET
POWER. (a) The commission shall monitor market power associated
with the generation, transmission, distribution, and sale of
electricity in this state. On a finding that market power abuses or
other violations of this section are occurring, the commission
shall require reasonable mitigation of the market power by ordering
the construction of additional transmission or distribution
facilities, by seeking an injunction or civil penalties as
necessary to eliminate or to remedy the market power abuse or
violation as authorized by Chapter 15, by imposing an
administrative penalty as authorized by Chapter 15, or by
suspending, revoking, or amending a certificate or registration as
authorized by Section 39.356. Section 15.024(c) does not apply to
an administrative penalty imposed under this section. For purposes
of this subchapter, market power abuses are practices by persons
possessing market power that are unreasonably discriminatory or
tend to unreasonably restrict, impair, or reduce the level of
competition, including practices that tie unregulated products or
services to regulated products or services or unreasonably
discriminate in the provision of regulated services. For purposes
of this section, "market power abuses" include predatory pricing,
withholding of production, precluding entry, and collusion. A
violation of the code of conduct provided by Subsection (d) that
materially impairs the ability of a person to compete in a
competitive market shall be deemed to be an abuse of market power.
The possession of a high market share in a market open to
competition may not, of itself, be deemed to be an abuse of market
power; however, this sentence shall not affect the application of
state and federal antitrust laws.
(b) Beginning on the date of introduction of customer
choice, a person that owns generation facilities may not own
transmission or distribution facilities in this state except for
those facilities necessary to interconnect a generation facility
with the transmission or distribution network, a facility not
dedicated to public use, or a facility otherwise excluded from the
definition of "electric utility" under Section 31.002. However,
nothing in this chapter shall prohibit a power generation company
affiliated with a transmission and distribution utility from owning
generation facilities.
(c) The commission shall monitor market shares of installed
capacity to ensure that the limitations in Section 39.154 are not
exceeded. If the commission finds that a person has violated a
limitation in Section 39.154, the commission shall order the person
to file, within 60 days of the date of the order, a market power
mitigation plan consistent with the requirements in Section 39.156.
(d) Not later than January 10, 2000, the commission shall
adopt rules and enforcement procedures to govern transactions or
activities between a transmission and distribution utility and its
competitive affiliates to avoid potential market power abuses and
cross-subsidizations between regulated and competitive activities
both during the transition to and after the introduction of
competition. Nothing in this subsection is intended to affect or
modify the obligations or duties relating to any rules or standards
of conduct that may apply to a utility or the utility's affiliates
under orders or regulations of the Federal Energy Regulatory
Commission or the Securities and Exchange Commission. A utility
that is subject to statutes or regulations in other states that
conflict with a provision of this section may petition the
commission for a waiver of the conflicting provision on a showing of
good cause. The rules adopted under this section shall ensure that:
(1) a utility makes any products and services, other
than corporate support services, that it provides to a competitive
affiliate available, contemporaneously and in the same manner, to
the competitive affiliate's competitors and applies its tariffs,
prices, terms, conditions, and discounts for those products and
services in the same manner to all similarly situated entities;
(2) a utility does not:
(A) give a competitive affiliate or a competitive
affiliate's customers any preferential advantage, access, or
treatment regarding services other than corporate support
services; or
(B) act in a manner that is discriminatory or
anticompetitive with respect to a nonaffiliated competitor of a
competitive affiliate;
(3) a utility providing electric transmission or
distribution services:
(A) provides those services on nondiscriminatory
terms and conditions;
(B) does not establish as a condition for the
provision of those services the purchase of other goods or services
from the utility or the competitive affiliate; and
(C) does not provide competitive affiliates
preferential access to the utility's transmission and distribution
systems or to information about those systems;
(4) a utility does not release any proprietary
customer information to a competitive affiliate or any other
entity, other than an independent organization as defined by
Section 39.151 or a provider of corporate support services for the
purposes of providing the services, without obtaining prior
verifiable authorization, as determined from the commission, from
the customer;
(5) a utility does not:
(A) communicate with a current or potential
customer about products or services offered by a competitive
affiliate in a manner that favors a competitive affiliate; or
(B) allow a competitive affiliate, before
September 1, 2005, to use the utility's corporate name, trademark,
brand, or logo unless the competitive affiliate includes on
employee business cards and in its advertisements of specific
services to existing or potential residential or small commercial
customers locating within the utility's certificated service area a
disclaimer that states, "(Name of competitive affiliate) is not the
same company as (name of utility) and is not regulated by the Public
Utility Commission of Texas, and you do not have to buy (name of
competitive affiliate)'s products to continue to receive quality
regulated services from (name of utility).";
(6) a utility does not conduct joint advertising or
promotional activities with a competitive affiliate in a manner
that favors the competitive affiliate;
(7) a utility is a separate, independent entity from
any competitive affiliates and, except as provided by Subdivisions
(8) and (9), does not share employees, facilities, information, or
other resources, other than permissible corporate support
services, with those competitive affiliates unless the utility can
prove to the commission that the sharing will not compromise the
public interest;
(8) a utility's office space is physically separated
from the office space of the utility's competitive affiliates by
being located in separate buildings or, if within the same
building, by a method such as having the offices on separate floors
or with separate access, unless otherwise approved by the
commission;
(9) a utility and a competitive affiliate:
(A) may, to the extent the utility implements
adequate safeguards precluding employees of a competitive
affiliate from gaining access to information in a manner
inconsistent with Subsection (g) or (i), share common officers and
directors, property, equipment, offices to the extent consistent
with Subdivision (8), credit, investment, or financing
arrangements to the extent consistent with Subdivision (17),
computer systems, information systems, and corporate support
services; and
(B) are not required to enter into prior written
contracts or competitive solicitations for non-tariffed
transactions between the utility and the competitive affiliate,
except that the commission by rule may require the utility and the
competitive affiliate to enter into prior written contracts or
competitive solicitations for certain classes of transactions,
other than corporate support services, that have a per unit value of
more than $75,000 or that total more than $1 million;
(10) a utility does not temporarily assign, for less
than one year, employees engaged in transmission or distribution
system operations to a competitive affiliate unless the employee
does not have knowledge of information that is intended to be
protected under this section;
(11) a utility does not subsidize the business
activities of an affiliate with revenues from a regulated service;
(12) a utility and its affiliates fully allocate costs
for any shared services, corporate support services, and other
items described by Subdivisions (8) and (9);
(13) a utility and its affiliates keep separate books
of accounts and records and the commission may review records
relating to a transaction between a utility and an affiliate;
(14) assets transferred or services provided between a
utility and an affiliate, other than transfers that facilitate
unbundling under Section 39.051 or asset valuation under Section
39.262, are priced at a level that is fair and reasonable to the
customers of the utility and reflects the market value of the assets
or services or the utility's fully allocated cost to provide those
assets or services;
(15) regulated services that a utility provides on a
routine or recurring basis are included in a tariff that is subject
to commission approval;
(16) each transaction between a utility and a
competitive affiliate is conducted at arm's length; and
(17) a utility does not allow an affiliate to obtain
credit under an arrangement that would include a specific pledge of
assets in the rate base of the utility or a pledge of cash
reasonably necessary for utility operations.
(e) The commission shall by rule establish a code of conduct
that must be observed by electric cooperatives and municipally
owned utilities and their affiliates to protect against
anticompetitive practices. The rules adopted by the commission
under this subsection shall be consistent with Chapters 40 and 41
and may not be more restrictive than the rules adopted under
Subsection (d).
(f) Following review of the annual reports submitted to it
under Sections 39.155(b) and (c), the commission shall determine
whether specific transmission or distribution constraints or
bottlenecks within this state give rise to market power in specific
geographic markets in the state. The commission, on a finding that
specific transmission or distribution constraints or bottlenecks
within this state give rise to market power, may order reasonable
mitigation of that potential market power by ordering, under
Section 39.203(e), one or more electric utilities or transmission
and distribution utilities to construct additional transmission or
distribution capacity, or both, subject to the certification
provisions of this title.
(g) The sharing of corporate support services in accordance
with this section may not allow or provide a means for the transfer
of confidential information from a utility to an affiliate, create
the opportunity for preferential treatment or an unfair competitive
advantage, lead to customer confusion, or create significant
opportunities for cross-subsidization of affiliates.
(h) A utility or competitive affiliate may not circumvent
the provisions or the intent of the provisions of Subsection (d) by
using any utility affiliate to provide information, services, or
subsidies between the utility and a competitive affiliate.
(i) In this section:
(1) "Competitive affiliate" means an affiliate of a
utility that provides services or sells products in a competitive
energy-related market in this state, including telecommunications
services, to the extent those services are energy related.
(2) "Corporate support services" means services
shared by a utility, its parent holding company, or a separate
affiliate created to perform corporate support services, with its
affiliates of joint corporate oversight, governance, support
systems, and personnel. Examples of services that may be shared, to
the extent the services comply with the requirements prescribed by
Subsections (d) and (g), include human resources, procurement,
information technology, regulatory services, administrative
services, real estate services, legal services, accounting,
environmental services, research and development, internal audit,
community relations, corporate communications, financial services,
financial planning and management support, corporate services,
corporate secretary, lobbying, and corporate planning. Examples of
services that may not be shared include engineering, purchasing of
electric transmission, transmission and distribution system
operations, and marketing.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.158. MERGERS AND CONSOLIDATIONS. (a) An owner of
electric generation facilities that offers electricity for sale in
the state and proposes to merge, consolidate, or otherwise become
affiliated with another owner of electric generation facilities
that offers electricity for sale in this state shall obtain the
approval of the commission before closing if the electricity
offered for sale in the power region by the merged, consolidated, or
affiliated entity will exceed one percent of the total electricity
for sale in the power region. The approval shall be requested at
least 120 days before the date of the proposed closing. The
commission shall approve the transaction unless the commission
finds that the transaction results in a violation of Section
39.154. If the commission finds that the transaction as proposed
would violate Section 39.154, the commission may condition approval
of the transaction on adoption of reasonable modifications to the
transaction as prescribed by the commission to mitigate potential
market power abuses.
(b) Nothing in this chapter shall be construed to confer
immunity from state or federal antitrust laws. This chapter is
intended to complement other state and federal antitrust
provisions. Therefore, antitrust remedies may also be sought in
state or federal court to remedy anticompetitive activities.
(c) This section may not be deemed to authorize commission
review or approval of transactions entered into between or among
municipally owned utilities, river authorities, special districts
created by law, or other political subdivisions, whether or not
those transactions may be characterized as mergers,
consolidations, or other affiliations, when the transaction is
authorized or structured under state law.
(d) Notwithstanding any other provision of this title, an
electric utility which, before the effective date of this chapter,
entered into a stipulation or agreement in support of approval of a
merger which was approved by the commission on or after January 1,
1996, requiring the utility to pass through to ratepayers the
savings resulting from the merger of that utility with another
utility shall continue to be bound by the terms of that stipulation
or agreement. The commission shall ensure that the pass-through of
all merger savings required under any such stipulation or agreement
shall be fully implemented during the freeze period and shall be
reflected in setting the price to beat for that utility.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
SUBCHAPTER E. PRICE REGULATION AFTER COMPETITION
§ 39.201. COST OF SERVICE TARIFFS AND
CHARGES. (a) Each electric utility shall, on or before April 1,
2000, file proposed tariffs for its proposed transmission and
distribution utility.
(b) The filing under this section shall include supporting
cost data for determination of nonbypassable delivery charges,
which shall be the sum of:
(1) transmission and distribution utility charges by
customer class based on a forecasted 2002 test year;
(2) a system benefit fund fee; and
(3) an expected competition transition charge, if any.
(c) Each electric utility shall also identify the unbundled
generation and retail energy service costs by customer class.
(d) In accordance with a schedule and procedures it
establishes, the commission shall hold a hearing and approve or
modify and make effective as of January 1, 2002, the transmission
and distribution utility's proposed tariffs for transmission and
distribution services, the system benefit fund fee, and the
expected competition transition charge as determined under
Subsections (g) and (h) and as implemented under Subsections
(i)-(l), if any.
(e) The system benefit fund fee shall be that established by
the commission under Section 39.903.
(f) The expected competition transition charge shall be
that as determined under Subsections (g) and (h) and as implemented
under Subsections (i)-(l).
(g) The expected competition transition charge approved by
the commission shall be calculated from the amount of stranded
costs as defined in Subchapter F that are reasonably projected to
exist on the last day of the freeze period modified to reflect any
adjustments determined appropriate by the commission under Section
39.261(c).
(h) The electric utility shall use the ECOM administrative
model referenced in Section 39.262 to determine estimated stranded
costs. The model must include updated company-specific inputs.
Natural gas prices used in the model must be market-based natural
gas forward prices, where available. Growth rates in generating
plant operations and maintenance costs and allocated
administrative and general costs shall be benchmarked by comparing
those costs to the best available information on cost trends for
comparable generating plants. Capital additions shall be
benchmarked using the limitation in Section 39.259(b).
(i) An electric utility may:
(1) at any time after the start of the freeze period,
securitize 100 percent of its regulatory assets as defined by
Section 39.302 and up to 75 percent of its estimated stranded costs
as defined by this section and recover those charges through a
transition charge, in accordance with a financing order issued by
the commission under Section 39.303;
(2) implement, under bond, a nonbypassable charge of
up to 100 percent of its estimated stranded costs; or
(3) use a combination of the two methods under
Subdivisions (1) and (2).
(j) Any competition transition charge shall be allocated
among retail customer classes according to Section 39.253.
(k) In determining the length of time over which stranded
costs under Subsection (h) may be recovered, the commission shall
consider:
(1) the electric utility's rates as of the end of the
freeze period;
(2) the sum of the transmission and distribution
charges and the system benefit fund fees;
(3) the proportion of estimated stranded costs to the
invested capital of the electric utility; and
(4) any other factor consistent with the public
interest as expressed in this chapter.
(l) Two years after customer choice is introduced, 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. If, based on that
proceeding, the competition transition charge is not sufficient,
the commission may extend the collection period for the charge or,
if necessary, increase the charge. Alternatively, if it is found in
the true-up proceeding that the competition transition charge is
larger than is needed to recover any remaining stranded costs, the
commission may:
(1) reduce the competition transition charge, to the
extent it has not been securitized;
(2) reverse, in whole or in part, the depreciation
expense that has been redirected under Section 39.256;
(3) reduce the transmission and distribution utility's
rates; or
(4) implement a combination of the elements in
Subdivisions (1)-(3).
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.202. PRICE TO BEAT. (a) From January 1, 2002,
until January 1, 2007, an affiliated retail electric provider shall
make available to residential and small commercial customers of its
affiliated transmission and distribution utility rates that, on a
bundled basis, are six percent less than the affiliated electric
utility's corresponding average residential and small commercial
rates, on a bundled basis, that were in effect on January 1, 1999,
adjusted to reflect the fuel factor determined as provided by
Subsection (b) and adjusted for any base rate reduction as
stipulated to by an electric utility in a proceeding for which a
final order had not been issued by January 1, 1999. These rates on a
bundled basis shall be known as the "price to beat" for residential
and small commercial customers, except that the "price to beat" for
a utility is the rate in effect as a result of a settlement approved
by the commission after January 1, 1999, if the commission
determines that base rates for that utility have been reduced by
more than 12 percent as a result of a final order issued by the
commission after October 1, 1998.
(b) The commission shall determine the fuel factor for each
electric utility as of December 31, 2001.
(c) After the date of customer choice, each affiliated power
generation company shall file a final fuel reconciliation for the
period ending the day before the date customer choice is
introduced. The final fuel balance from that reconciliation shall
be included in the true-up proceeding under Section 39.262.
(d) An affiliated retail electric provider shall make
public its price to beat in a manner that provides adequate
disclosure as determined by the commission.
(e) The affiliated retail electric provider may not charge
rates for residential or small commercial customers that are
different from the price to beat until the earlier of 36 months
after the date customer choice is introduced or:
(1) for service to residential customers, the date the
commission determines that 40 percent or more of the electric power
consumed by residential customers within the affiliated
transmission and distribution utility's certificated service area
before the onset of customer choice is committed to be served by
nonaffiliated retail electric providers; or
(2) for service to small commercial customers, the
date the commission determines that 40 percent or more of the
electric power consumed by small commercial customers within the
affiliated transmission and distribution utility's certificated
service area before the onset of customer choice is committed to be
served by nonaffiliated retail electric providers.
(f) Notwithstanding Subsection (e), the affiliated retail
electric provider may charge rates that are different from the
price to beat for service to aggregated loads of nonresidential
customers having an aggregated peak demand greater than 1,000
kilowatts, provided that all affected customers are:
(1) commonly owned; or
(2) franchisees of the same franchisor.
(g) The affiliated retail electric provider may not
encourage or provide an incentive to a customer to switch to a
nonaffiliated retail electric provider, promote any nonaffiliated
retail electric provider, or exchange customers with any
nonaffiliated retail electric provider to comply with the
requirements of Subsection (e)(1) or (2).
(h) The following standards shall be used for measuring
electric power consumption during the period before the onset of
customer choice:
(1) the consumption of residential and small
commercial customers with an annual peak demand less than or equal
to 20 kilowatts shall be based on the average annual consumption of
those respective groups during the year 2000;
(2) consumption for all small commercial customers
with an annual peak demand larger than 20 kilowatts shall be based
on each customer's usage during the year 2000; and
(3) for purposes of determining whether an affiliated
retail electric provider has met the requirements of Subsection
(e)(2), the aggregated loads of nonresidential customers having a
peak demand greater than 1,000 kilowatts that are served by the
affiliated retail electric provider at a rate different from the
price to beat under Subsection (f) shall be deducted from the
electric power consumption of small commercial customers during the
period before the onset of customer choice.
(i) For purposes of Subsection (h)(2), if less than 12
months of consumption history exists for any such customer, the
usage history shall be supplemented with the prior history of that
customer's location. For service to a new location, the annual
consumption shall be determined as the transmission and
distribution utility's estimate of the maximum annual kilowatt
demand used in sizing the electric service to that customer
multiplied by 8,760 hours, and that product multiplied by the
average annual customer load factor for small commercial customers
with loads greater than 20 kilowatts for the year 2000.
(j) On determining that its affiliated retail electric
provider has met the requirements of Subsection (e)(1) or (2), an
electric utility or a transmission and distribution utility shall
make a filing with the commission attesting to the fact that those
requirements have been met and that the restrictions of Subsection
(e)(1) or (2) and the true-up in Section 39.262(e) are no longer
applicable. The commission shall adopt appropriate procedures to
enable it to accept or reject the filing within 30 days.
(k) Following the true-up proceedings conducted under
Section 39.262, the commission may adjust the price to beat.
(l) An affiliated retail electric provider may request that
the commission adjust the fuel factor established under Subsection
(b) not more than twice a year if the affiliated retail electric
provider demonstrates that the existing fuel factor does not
adequately reflect significant changes in the market price of
natural gas and purchased energy used to serve retail customers.
(m) In a power region outside of ERCOT, if customer choice
is introduced before the requirements of Section 39.152(a) are met,
an affiliated retail electric provider shall charge rates to
customers other than residential and small commercial customers
that are no higher than the rates that, on a bundled basis, were in
effect on January 1, 1999, adjusted to reflect the fuel factor as
provided by Subsection (b) and adjusted for any base rate reduction
as stipulated to by an electric utility in a proceeding for which a
final order had not been issued by January 1, 1999.
(n) Notwithstanding Subsection (a), in a power region
outside of ERCOT, if customer choice is introduced before the
requirements of Section 39.152(a) are met, an affiliated retail
electric provider shall continue to offer the price to beat to
residential and small commercial customers, unless the price is
changed by the commission in accordance with this chapter, until
the later of 60 months after the date customer choice is introduced
or the requirements of Section 39.152(a) are met.
(o) In this section, "small commercial customer" means a
commercial customer having a peak demand of 1,000 kilowatts or
less.
(p) On finding that a retail electric provider will be
unable to maintain its financial integrity if it complies with
Subsection (a), the commission shall set the retail electric
provider's price to beat at the minimum level that will allow the
retail electric provider to maintain its financial integrity.
However, in no event shall the price to beat exceed the level of
rates, on a bundled basis, charged by the affiliated electric
utility on September 1, 1999, adjusted for fuel as provided by
Subsection (b).
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.203. TRANSMISSION AND DISTRIBUTION
SERVICE. (a) All transmission and distribution utilities shall
provide transmission service at wholesale under Subchapter A,
Chapter 35. In addition, on and after January 1, 2002, a
transmission and distribution utility shall provide transmission
or distribution service, or both, at retail to an electric utility,
a retail electric provider, a municipally owned utility, an
electric cooperative, or an end-use customer at rates, terms of
access, and conditions that are comparable to those that apply to
the transmission and distribution utility and its affiliates. A
municipally owned utility offering customer choice or an electric
cooperative offering customer choice shall likewise provide
transmission or distribution service, or both, at retail to all
such entities in accordance with the commission's rules applicable
to terms and conditions of access and at rates adopted in accordance
with Sections 40.055(a)(1) and 41.055(1), respectively.
(b) When necessary to serve a wholesale customer an electric
utility, an electric cooperative that has not opted for customer
choice, or a municipally owned utility that has not opted for
customer choice shall provide wholesale transmission service at
distribution voltage. A customer of a municipally owned utility
that has not opted for customer choice or of an electric cooperative
that has not opted for customer choice may not claim the status of a
wholesale customer or be designated as a wholesale customer if the
customer is being or has been served under a retail rate schedule of
the municipally owned utility or electric cooperative.
(c) On or before January 1, 2002, the commission shall
establish for all retail electric utilities offering customer
choice reasonable and comparable terms and conditions, in
accordance with Section 39.201, that comply with Subsection (a) for
open access on distribution facilities and shall establish, for all
retail electric utilities offering customer choice other than
municipally owned utilities and electric cooperatives, reasonable
and comparable rates for open access on distribution facilities.
(d) The terms of access, conditions, and rates established
under Subsection (c) shall be comparable to the terms of access,
conditions, and rates that the electric utility applies to itself
or its affiliates. The rules shall also provide that all ancillary
services provided by the utility to itself or its affiliates are
also available to third parties on request on a nondiscriminatory
basis.
(e) The commission may require an electric utility or a
transmission and distribution utility to construct or enlarge
facilities to ensure safe and reliable service for the state's
electric markets and to reduce transmission constraints within
ERCOT in a cost-effective manner where the constraints are such
that they are not being resolved through Chapter 37 or the ERCOT
transmission planning process. In any proceeding brought under
Chapter 37, an electric utility or transmission and distribution
utility ordered to construct or enlarge facilities under this
subchapter need not prove that the construction ordered is
necessary for the service, accommodation, convenience, or safety of
the public and need not address the factors listed in Sections
37.056(c)(1)-(3) and (4)(E).
(f) The commission's rules must be consistent with the
standards of this title and may not be contrary to an applicable
decision, rule, or policy statement of a federal regulatory agency
having jurisdiction.
(g) Each power region shall have generally applicable
tariffs approved by the commission or a federal regulatory agency
having jurisdiction that guarantees open and nondiscriminatory
access as required by Section 39.152. This subsection may not be
deemed to vest in the commission power to set or approve
distribution access rates of a municipally owned utility or an
electric cooperative that has adopted customer choice.
(h) A customer in a multiply certificated service area may
switch its retail distribution service provider among certificated
retail electric utilities only by disconnecting from the facilities
of one retail electric utility and connecting to the facilities of
another retail electric utility.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
Amended by Acts 2003, 78th Leg., ch. 295, § 3, eff. June 18,
2003.
§ 39.204. TARIFFS FOR OPEN ACCESS. Each transmission
and distribution utility shall file a tariff implementing the open
access rules with the commission or the federal regulatory
authority having jurisdiction over the transmission and
distribution service of the utility not later than the 90th day
before the date customer choice is offered by that utility.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.205. REGULATION OF COSTS FOLLOWING FREEZE
PERIOD. At the conclusion of the freeze period, any remaining
costs associated with nuclear decommissioning obligations continue
to be subject to cost of service rate regulation and shall be
included as a nonbypassable charge to retail customers.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
SUBCHAPTER F. RECOVERY OF STRANDED COSTS THROUGH COMPETITION
TRANSITION CHARGE
§ 39.251. DEFINITIONS. In this subchapter:
(1) "Above market purchased power costs" means
wholesale demand and energy costs that a utility is obligated to pay
under an existing purchased power contract to the extent the costs
are greater than the purchased power market value.
(2) "Existing purchased power contract" means a
purchased power contract in effect on January 1, 1999, including
any amendments and revisions to that contract resulting from
litigation initiated before January 1, 1999.
(3) "Generation assets" means all assets associated
with the production of electricity, including generation plants,
electrical interconnections of the generation plant to the
transmission system, fuel contracts, fuel transportation
contracts, water contracts, lands, surface or subsurface water
rights, emissions-related allowances, and gas pipeline
interconnections.
(4) "Market value" means, for nonnuclear assets and
certain nuclear assets, the value the assets would have if bought
and sold in a bona fide third-party transaction or transactions on
the open market under Section 39.262(h) or, for certain nuclear
assets, as described by Section 39.262(i), the value determined
under the method provided by that subsection.
(5) "Purchased power market value" means the value of
demand and energy bought and sold in a bona fide third-party
transaction or transactions on the open market and determined by
using the weighted average costs of the highest three offers from
the market for purchase of the demand and energy available under the
existing purchased power contracts.
(6) "Retail stranded costs" means that part of net
stranded cost associated with the provision of retail service.
(7) "Stranded 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
("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.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.252. RIGHT TO RECOVER STRANDED COSTS. (a) An
electric utility is allowed to recover all of its net, verifiable,
nonmitigable stranded costs incurred in purchasing power and
providing electric generation service.
(b)(1) Recovery of retail stranded costs by an electric
utility shall be from all existing or future retail customers,
including the facilities, premises, and loads of those retail
customers, within the utility's geographical certificated service
area as it existed on May 1, 1999. A retail customer may not avoid
stranded cost recovery charges by switching to new on-site
generation except as provided by Section 39.262(k). For purposes
of this subchapter, "new on-site generation" means electric
generation capacity greater than 10 megawatts capable of being
lawfully delivered to the site without use of utility distribution
or transmission facilities and which was not, on or before December
31, 1999, either:
(A) a fully operational facility; or
(B) a project supported by substantially
complete filings for all necessary site-specific environmental
permits under the rules of the Texas Natural Resource Conservation
Commission in effect at the time of filing.
(2) If a customer commences taking energy from new
on-site generation which materially reduces the customer's use of
energy delivered through the utility's facilities, the customer
shall pay an amount each month computed by multiplying the output of
the on-site generation by the new sum of competition transition
charges under Section 39.201 and transition charges under
Subchapter G which are in effect during that month. Payment shall
be made to the utility, its successors, an assignee, or other
collection agent responsible for collecting the competition
transition charges and transition charges and shall be collected in
addition to the competition transition charges and transition
charges applicable to energy actually delivered to the customer
through the utility's facilities.
(c) In multiply certificated areas, a retail customer may
not avoid stranded cost recovery charges by switching to another
electric utility, electric cooperative, or municipally owned
utility after May 1, 1999. A customer in a multiply certificated
service area that requested to switch providers on or before May 1,
1999, or was not taking service from an electric utility on May 1,
1999, and does not do so after that date is not responsible for
paying retail stranded costs of that utility.
(d) 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).
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.253. ALLOCATION OF STRANDED COSTS. (a) Any
capital costs incurred by an electric utility to improve air
quality under Section 39.263 or 39.264 that are included in a
utility's invested capital in accordance with those sections shall
be allocated among customer classes as follows:
(1) 50 percent of those costs shall be allocated in
accordance with the methodology used to allocate the costs of the
underlying assets in the electric utility's most recent commission
order addressing rate design; and
(2) the remainder shall be allocated on the basis of
the energy consumption of the customer classes.
(b) All other retail stranded costs shall be allocated among
retail customer classes in accordance with Subsections (c)-(i).
(c) The allocation to the residential class shall be
determined by allocating to all customer classes 50 percent of the
stranded costs in accordance with the methodology used to allocate
the costs of the underlying assets in the electric utility's most
recent commission order addressing rate design and allocating the
remainder of the stranded costs on the basis of the energy
consumption of the classes.
(d) After the allocation to the residential class required
by Subsection (c) has been calculated, the remaining stranded costs
shall be allocated to the remaining customer classes in accordance
with the methodology used to allocate the costs of the underlying
assets in the electric utility's most recent commission order
addressing rate design. Non-firm industrial customers shall be
allocated stranded costs equal to 150 percent of the amount
allocated to that class.
(e) After the allocation to the residential class required
by Subsection (c) and the allocation to the nonfirm industrial
class required by Subsection (d) have been calculated, the
remaining stranded costs shall be allocated to the remaining
customer classes in accordance with the methodology used to
allocate the costs of the underlying assets in the electric
utility's most recent commission order addressing rate design.
(f) Notwithstanding any other provision of this section, to
the extent that the total retail stranded costs, including
regulatory assets, of investor-owned utilities exceed $5 billion on
a statewide basis, any stranded costs in excess of $5 billion shall
be allocated among retail customer classes in accordance with the
methodology used to allocate the costs of the underlying assets in
the electric utility's most recent commission order addressing rate
design.
(g) The energy consumption of the customer classes used in
Subsections (a)(2) and (c) shall be based on the relevant class
characteristics as of May 1, 1999, adjusted for normal weather
conditions.
(h) For purposes of this section, "stranded costs" includes
regulatory assets.
(i) Except as provided by Section 39.262(k), no customer or
customer class may avoid the obligation to pay the amount of
stranded costs allocated to that customer class.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.254. USE OF REVENUES FOR UTILITIES WITH STRANDED
COSTS. This subchapter provides a number of tools to an electric
utility to mitigate stranded costs. Each electric utility that was
reported by the commission to have positive "excess costs over
market" (ECOM), denoted as the "base case" for the amount of
stranded costs before full retail competition in 2002 with respect
to its Texas jurisdiction, in the April 1998 Report to the Texas
Senate Interim Committee on Electric Utility Restructuring
entitled "Potentially Strandable Investment (ECOM) Report: 1998
Update," must use these tools to reduce the net book value of,
otherwise referred to as "accelerate" the cost recovery of, its
stranded costs each year. Any positive difference under the report
required by Section 39.257(b) shall be applied to the net book value
of generation assets.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.255. USE OF REVENUES FOR UTILITIES WITH NO STRANDED
COSTS. (a) An electric utility that does not have stranded costs
described by Section 39.254 shall be permitted to use any positive
difference under the report required by Section 39.257(b) on
capital expenditures to improve or expand transmission or
distribution facilities, or on capital expenditures to improve air
quality, as approved by the commission. Any such capital
expenditures shall be made in the calendar year immediately
following the year for which the report required by Section 39.257
is calculated. The capital expenditures shall be reflected in any
future proceeding under this chapter to set transmission or
distribution rates as a reduction to the utility's transmission and
distribution invested capital, as approved by the commission.
(b) To the extent that positive differences under the report
required by Section 39.257(b) are not used for capital
expenditures, the amounts shall be flowed back to the electric
utility's Texas jurisdictional customers through the power cost
recovery factor.
(c) This section applies only to the use of positive
differences under the report required by Section 39.257(b) for each
year during the freeze period.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.256. OPTION TO REDIRECT DEPRECIATION. (a) For
the calendar years of 1998, 1999, 2000, and 2001, an electric
utility described by Section 39.254 may redirect all or a part of
the depreciation expense relating to transmission and distribution
assets to its net generation plant assets.
(b) The electric utility shall report a decision under
Subsection (a) to the commission and any other applicable
regulatory authority.
(c) Any adjustments made to the book value of transmission
and distribution assets or the creation of any related regulatory
assets resulting from the redirection under this section shall be
accepted and applied by the commission for establishing net
invested capital and transmission and distribution rates for retail
customers in all future proceedings.
(d) Notwithstanding Subsection (c), the design of
post-freeze-period retail rates may not:
(1) shift the allocation of responsibility for
stranded costs;
(2) include the adjusted costs in wholesale
transmission and distribution rates; or
(3) apply the adjustments for the purpose of
establishing net invested capital and transmission and
distribution rates for wholesale customers.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.257. ANNUAL REPORT. (a) Beginning with the 1999
calendar year, each electric utility shall file a report with the
commission not later than 90 days after the end of each year during
the freeze period under a schedule and a format determined by the
commission.
(b) The report shall identify any positive difference
between annual revenues, reduced by the amount of annual revenues
under Sections 36.203 and 36.205, the revenues received under the
interutility billing process as adopted by the commission to
implement Sections 35.004, 35.006, and 35.007, revenues associated
with transition charges as defined by Section 39.302, and annual
costs.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.258. ANNUAL REPORT: DETERMINATION OF ANNUAL
COSTS. For the purposes of determining the annual costs in each
annual report, the following amounts shall be used:
(1) the lesser of:
(A) the utility's Texas jurisdictional operation
and maintenance expense reflected in each utility's Federal Energy
Regulatory Commission Form 1 of the report year, plus factoring
expenses not included in operation and maintenance, adjusted for:
(i) costs under Sections 36.062, 36.203,
and 36.205; and
(ii) revenues recorded under the
interutility billing process adopted by the commission to implement
Sections 35.004, 35.006, and 35.007; or
(B) the Texas jurisdictional operation and
maintenance expense reflected in each utility's 1996 Federal Energy
Regulatory Commission Form 1, plus factoring expenses not included
in operation and maintenance, adjusted for:
(i) costs under Sections 36.062, 36.203,
and 36.205, and not indexed for inflation;
(ii) any difference between the annual
revenues and the expenses recorded under the interutility billing
process adopted by the commission to implement Sections 35.004,
35.006, and 35.007; and
(iii) the annual percentage change in the
average number of utility customers;
(2) the amount of nuclear decommissioning expense
approved in the electric utility's last rate proceeding before the
commission, as may be required to be adjusted to comply with
applicable federal regulatory requirements;
(3) the depreciation rates approved in the electric
utility's last rate proceeding before the commission;
(4) the amortization expense approved in the electric
utility's last rate proceeding before the commission or in any
other proceeding in which deferred costs and the amortization of
those costs are established, except that if the items are fully
amortized during the freeze period, the expense shall be adjusted
accordingly;
(5) taxes and fees, including municipal franchise fees
to the extent not included in Subdivision (1), other than federal
income taxes, and assessments incurred that year;
(6) federal income tax expense, computed according to
the stand-alone methodology and using the actual capital structure
and actual cost of debt as of December 31 of the report year;
(7) return on invested capital, computed by
multiplying invested capital as of December 31 of the report year,
determined as provided by Section 39.259, by the cost of capital
approved in the electric utility's most recent rate proceeding
before the commission in which the cost of capital was specifically
adopted, or, in the case of a range, the midpoint of the range, if
the final rate order for the proceeding was issued on or after
January 1, 1992, or if such an order does not exist, a cost of
capital of 9.6 percent shall be used; and
(8) the amount resulting from any operation and
maintenance expense savings tracker from a merger of two utilities
and contained in a settlement agreement approved by the commission
before January 1, 1999.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.259. ANNUAL REPORT: DETERMINATION OF INVESTED
CAPITAL. (a) For the purposes of determining invested capital in
each annual report, the net plant in service, regulatory assets,
and deferred federal income taxes shall be updated each year, and
generation-related invested capital shall be reduced by the amount
of securitization under Sections 39.201(i) and 39.262(c) to the
extent otherwise included in invested capital.
(b) Capital additions to a plant in an amount less than
1-1/2 percent of the electric utility's net plant in service on
December 31, 1998, less plant items previously excluded by the
commission, for each of the years 1999 through 2001 are presumed
prudent.
(c) All other items in invested capital shall be as approved
in the electric utility's last rate proceeding before the
commission.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.260. USE OF GENERALLY ACCEPTED ACCOUNTING
PRINCIPLES. (a) The definition and identification of invested
capital and other terms used in this subchapter and Subchapter G
that affect the net book value of generation assets and the
treatment of transactions performed under Section 35.035 and other
transactions authorized by this title or approved by the regulatory
authority that affect the net book value of generation assets
during the freeze period shall be treated in accordance with
generally accepted accounting principles as modified by regulatory
accounting rules generally applicable to utilities.
(b) The principles and criteria described by Subsection
(a), including the criteria for applicability of Statement of
Financial Accounting Standards No. 71 ("Accounting for the Effects
of Certain Types of Regulation"), shall be applied for purposes of
this subchapter as they existed on January 1, 1999.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.261. REVIEW OF ANNUAL REPORT. (a) The annual
report filed under this subchapter is a public document and shall be
reviewed by the staff of the commission and the office. Both staffs
may review work papers and supporting documents and engage in
discussions with the utility about the data underlying the reports.
(b) The staff of the commission and the office shall
communicate in writing to an electric utility not later than the
180th day after the date the report is filed if they have any
disagreements with the data or computations.
(c) The commission shall finalize and resolve any
disagreements related to the annual report, consistent with the
requirements of Section 39.258, as follows:
(1) for each calendar year, the commission shall
finalize the annual report before establishing the competition
transition charge under Section 39.201; and
(2) for each calendar year, the commission shall
finalize the annual report and reflect the result as part of the
true-up proceeding under Section 39.262.
Added by Acts 1999, 76th Leg., ch. 405, § 39, eff. Sept. 1, 1999.
§ 39.262. TRUE-UP PROCEEDING. (a) An electric
utility, together with its affiliated retail electric provider and
its affiliated transmission and distribution 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.
(b) After the freeze period, an electric utility located in
a power reg
