1-1 By: Sibley, et al. S.B. No. 7
1-2 (In the Senate - Filed January 20, 1999; January 26, 1999,
1-3 read first time and referred to Special Committee on Electric
1-4 Utility Restructuring; March 11, 1999, reported adversely, with
1-5 favorable Committee Substitute by the following vote: Yeas 7, Nays
1-6 0; March 11, 1999, sent to printer.)
1-7 COMMITTEE SUBSTITUTE FOR S.B. No. 7 By: Cain
1-8 A BILL TO BE ENTITLED
1-9 AN ACT
1-10 relating to electric utility restructuring and to the powers and
1-11 duties of the Public Utility Commission of Texas; providing civil
1-12 and administrative penalties; making an appropriation.
1-13 BE IT ENACTED BY THE LEGISLATURE OF THE STATE OF TEXAS:
1-14 SECTION 1. Section 11.003, Utilities Code, is amended to
1-15 read as follows:
1-16 Sec. 11.003. DEFINITIONS. In this title:
1-17 (1) "Affected person" means:
1-18 (A) a public utility or electric cooperative
1-19 affected by an action of a regulatory authority;
1-20 (B) a person whose utility service or rates are
1-21 affected by a proceeding before a regulatory authority; or
1-22 (C) a person who:
1-23 (i) is a competitor of a public utility
1-24 with respect to a service performed by the utility; or
1-25 (ii) wants to enter into competition with
1-26 a public utility.
1-27 (2) "Affiliate" means:
1-28 (A) a person who directly or indirectly owns or
1-29 holds at least five percent of the voting securities of a public
1-31 (B) a person in a chain of successive ownership
1-32 of at least five percent of the voting securities of a public
1-34 (C) a corporation that has at least five percent
1-35 of its voting securities owned or controlled, directly or
1-36 indirectly, by a public utility;
1-37 (D) a corporation that has at least five percent
1-38 of its voting securities owned or controlled, directly or
1-39 indirectly, by:
1-40 (i) a person who directly or indirectly
1-41 owns or controls at least five percent of the voting securities of
1-42 a public utility; or
1-43 (ii) a person in a chain of successive
1-44 ownership of at least five percent of the voting securities of a
1-45 public utility;
1-46 (E) a person who is an officer or director of a
1-47 public utility or of a corporation in a chain of successive
1-48 ownership of at least five percent of the voting securities of a
1-49 public utility; or
1-50 (F) a person determined to be an affiliate under
1-51 Section 11.006.
1-52 (3) "Allocation" means the division among
1-53 municipalities or among municipalities and unincorporated areas of
1-54 the plant, revenues, expenses, taxes, and reserves of a utility
1-55 used to provide public utility service in a municipality or for a
1-56 municipality and unincorporated areas.
1-57 (4) "Commission" means the Public Utility Commission
1-58 of Texas.
1-59 (5) "Commissioner" means a member of the Public
1-60 Utility Commission of Texas.
1-61 (6) "Cooperative corporation" means:
1-62 (A) an electric cooperative [
1-63 organized under Chapter 161 or a predecessor statute to Chapter 161
1-64 and operating under that chapter]; or
2-1 (B) a telephone cooperative corporation
2-2 organized under Chapter 162 or a predecessor statute to Chapter 162
2-3 and operating under that chapter.
2-4 (7) "Corporation" means a domestic or foreign
2-5 corporation, joint-stock company, or association, and each lessee,
2-6 assignee, trustee, receiver, or other successor in interest of the
2-7 corporation, company, or association, that has any of the powers or
2-8 privileges of a corporation not possessed by an individual or
2-9 partnership. The term does not include a municipal corporation or
2-10 electric cooperative, except as expressly provided by this title.
2-11 (8) "Counsellor" means the public utility counsel.
2-12 (9) "Electric cooperative" means:
2-13 (A) a corporation organized under Chapter 161 or
2-14 a predecessor statute to Chapter 161 and operating under that
2-16 (B) a corporation organized as an electric
2-17 cooperative in a state other than Texas that has obtained a
2-18 certificate of authority to conduct affairs in the State of Texas;
2-20 (C) a successor to an electric cooperative
2-21 created in accordance with a conversion plan approved by a vote of
2-22 the members of the electric cooperative before June 1, 1999.
2-23 (10) "Facilities" means all of the plant and equipment
2-24 of a public utility, and includes the tangible and intangible
2-25 property, without limitation, owned, operated, leased, licensed,
2-26 used, controlled, or supplied for, by, or in connection with the
2-27 business of the public utility.
2-28 (11) [ (10)] "Municipally owned utility" means a
2-29 utility owned, operated, and controlled by a municipality or by a
2-30 nonprofit corporation the directors of which are appointed by one
2-31 or more municipalities.
2-32 (12) [ (11)] "Office" means the Office of Public
2-33 Utility Counsel.
2-34 (13) [ (12)] "Order" means all or a part of a final
2-35 disposition by a regulatory authority in a matter other than
2-36 rulemaking, without regard to whether the disposition is
2-37 affirmative or negative or injunctive or declaratory. The term
2-39 (A) the issuance of a certificate of convenience
2-40 and necessity; and
2-41 (B) the setting of a rate.
2-42 (14) [ (13)] "Person" includes an individual, a
2-43 partnership of two or more persons having a joint or common
2-44 interest, a mutual or cooperative association, and a corporation,
2-45 but does not include an electric cooperative.
2-46 (15) [ (14)] "Proceeding" means a hearing,
2-47 investigation, inquiry, or other procedure for finding facts or
2-48 making a decision under this title. The term includes a denial of
2-49 relief or dismissal of a complaint.
2-50 (16) [ (15)] "Rate" includes:
2-51 (A) any compensation, tariff, charge, fare,
2-52 toll, rental, or classification that is directly or indirectly
2-53 demanded, observed, charged, or collected by a public utility for a
2-54 service, product, or commodity described in the definition of
2-55 utility in Section 31.002 or 51.002; and
2-56 (B) a rule, practice, or contract affecting the
2-57 compensation, tariff, charge, fare, toll, rental, or
2-59 (17) [ (16)] "Ratemaking proceeding" means[ :]
2-60 [ (A)] a proceeding in which a rate is changed[ ;
2-62 [ (B) a proceeding initiated under Chapter 34].
2-63 (18) [ (17)] "Regulatory authority" means either the
2-64 commission or the governing body of a municipality, in accordance
2-65 with the context.
2-66 (19) [ (18)] "Service" has its broadest and most
2-67 inclusive meaning. The term includes any act performed, anything
2-68 supplied, and any facilities used or supplied by a public utility
2-69 in the performance of the utility's duties under this title to its
3-1 patrons, employees, other public utilities, an electric
3-2 cooperative, and the public. The term also includes the
3-3 interchange of facilities between two or more public utilities.
3-4 The term does not include the printing, distribution, or sale of
3-5 advertising in a telephone directory.
3-6 (20) [ (19)] "Test year" means the most recent 12
3-7 months, beginning on the first day of a calendar or fiscal year
3-8 quarter, for which operating data for a public utility are
3-10 (21) [ (20)] "Trade association" means a nonprofit,
3-11 cooperative, and voluntarily joined association of business or
3-12 professional persons who are employed by public utilities or
3-13 utility competitors to assist the public utility industry, a
3-14 utility competitor, or the industry's or competitor's employees in
3-15 dealing with mutual business or professional problems and in
3-16 promoting their common interest.
3-17 SECTION 2. Section 12.005, Utilities Code, is amended to
3-18 read as follows:
3-19 Sec. 12.005. APPLICATION OF SUNSET ACT. The Public Utility
3-20 Commission of Texas is subject to Chapter 325, Government Code
3-21 (Texas Sunset Act). Unless continued in existence as provided by
3-22 that chapter, the commission is abolished and this title expires
3-23 September 1, 2005 [ 2001].
3-24 SECTION 3. Section 12.101, Utilities Code, is amended to
3-25 read as follows:
3-26 Sec. 12.101. COMMISSION EMPLOYEES. The commission shall
3-28 (1) an executive director; and
3-29 (2) [ a general counsel; and]
3-30 [ (3)] officers and other employees the commission
3-31 considers necessary to administer this title.
3-32 SECTION 4. Sections 12.151 and 12.152, Utilities Code, are
3-33 amended to read as follows:
3-34 Sec. 12.151. REGISTERED LOBBYIST. A person required to
3-35 register as a lobbyist under Chapter 305, Government Code, because
3-36 of the person's activities for compensation on behalf of a
3-37 profession related to the operation of the commission may not serve
3-38 as a commissioner [ or act as general counsel to the commission].
3-39 Sec. 12.152. Conflict of Interest. (a) A person is not
3-40 eligible for appointment as a commissioner [ or for employment as
3-41 the general counsel] or executive director of the commission if:
3-42 (1) the person serves on the board of directors of a
3-43 company that supplies fuel, utility-related services, or
3-44 utility-related products to regulated or unregulated electric or
3-45 telecommunications utilities; or
3-46 (2) the person or the person's spouse:
3-47 (A) is employed by or participates in the
3-48 management of a business entity or other organization that is
3-49 regulated by or receives funds from the commission;
3-50 (B) directly or indirectly owns or controls more
3-51 than a 10 percent interest or a pecuniary interest with a value
3-52 exceeding $10,000 in:
3-53 (i) a business entity or other
3-54 organization that is regulated by or receives funds from the
3-55 commission; or
3-56 (ii) a utility competitor, utility
3-57 supplier, or other entity affected by a commission decision in a
3-58 manner other than by the setting of rates for that class of
3-60 (C) uses or receives a substantial amount of
3-61 tangible goods, services, or funds from the commission, other than
3-62 compensation or reimbursement authorized by law for commission
3-63 membership, attendance, or expenses; or
3-64 (D) notwithstanding Paragraph (B), has an
3-65 interest in a mutual fund or retirement fund in which more than 10
3-66 percent of the fund's holdings at the time of appointment is in a
3-67 single utility, utility competitor, or utility supplier in this
3-68 state and the person does not disclose this information to the
3-69 governor, senate, commission, or other entity, as appropriate.
4-1 (b) A person otherwise ineligible because of Subsection
4-2 (a)(2)(B) may be appointed to the commission and serve as a
4-3 commissioner or may be employed as [ the general counsel or]
4-4 executive director if the person:
4-5 (1) notifies the attorney general and commission that
4-6 the person is ineligible because of Subsection (a)(2)(B); and
4-7 (2) divests the person or the person's spouse of the
4-8 ownership or control:
4-9 (A) before beginning service or employment; or
4-10 (B) if the person is already serving or
4-11 employed, within a reasonable time.
4-12 SECTION 5. Section 13.002, Utilities Code, is amended to
4-13 read as follows:
4-14 Sec. 13.002. APPLICATION OF SUNSET ACT. The Office of
4-15 Public Utility Counsel is subject to Chapter 325, Government Code
4-16 (Texas Sunset Act). Unless continued in existence as provided by
4-17 that chapter, the office is abolished and this chapter expires
4-18 September 1, 2005 [ 2001].
4-19 SECTION 6. Subsection (d), Section 14.101, Utilities Code,
4-20 is amended to read as follows:
4-21 (d) This section does not apply to:
4-22 (1) the purchase of a unit of property for
4-23 replacement; [ or]
4-24 (2) an addition to the facilities of a public utility
4-25 by construction; or
4-26 (3) transactions that facilitate unbundling, asset
4-27 valuation, minimization of ownership or control of generation
4-28 assets, or other purposes consistent with Chapter 39.
4-29 SECTION 7. Subsections (a) and (b), Section 16.001,
4-30 Utilities Code, are amended to read as follows:
4-31 (a) To defray the expenses incurred in the administration of
4-32 this title, an assessment is imposed on each public utility, retail
4-33 electric provider, and electric cooperative within the jurisdiction
4-34 of the commission that serves the ultimate consumer, including each
4-35 interexchange telecommunications carrier.
4-36 (b) An assessment under this section is equal to one-sixth
4-37 of one percent of the public utility's, retail electric provider's,
4-38 or electric cooperative's gross receipts from rates charged to the
4-39 ultimate consumer in this state.
4-40 SECTION 8. Section 31.002, Utilities Code, is amended to
4-41 read as follows:
4-42 Sec. 31.002. DEFINITIONS. In this subtitle:
4-43 (1) "Affiliated power generation company" means a
4-44 power generation company that is affiliated with or the successor
4-45 in interest of an electric utility certificated to serve an area.
4-46 (2) "Affiliated retail electric provider" means a
4-47 retail electric provider that is affiliated with or the successor
4-48 in interest of an electric utility certificated to serve an area.
4-49 (3) "Aggregation" includes the following:
4-50 (A) the purchase of electricity from a retail
4-51 electric provider by an electricity customer for its own use in
4-52 multiple locations; or
4-53 (B) the purchase of electricity by an
4-54 electricity customer as part of a voluntary association of
4-55 electricity customers.
4-56 (4) "Customer choice" means the freedom of a retail
4-57 customer to purchase electric services, either individually or
4-58 through voluntary aggregation with other retail customers, from the
4-59 provider or providers of the customer's choice and to choose among
4-60 various fuel types, energy efficiency programs, and renewable power
4-62 (5) "Electric Reliability Council of Texas" or "ERCOT"
4-63 means the area in Texas served by electric utilities, municipally
4-64 owned utilities, and electric cooperatives that is not
4-65 synchronously interconnected with electric utilities outside the
4-67 (6) "Electric utility" means a person or river
4-68 authority that owns or operates for compensation in this state
4-69 equipment or facilities to produce, generate, transmit, distribute,
5-1 sell, or furnish electricity in this state. The term includes a
5-2 lessee, trustee, or receiver of an electric utility and a
5-3 recreational vehicle park owner who does not comply with Subchapter
5-4 C, Chapter 184, with regard to the metered sale of electricity at
5-5 the recreational vehicle park. The term does not include:
5-6 (A) a municipal corporation;
5-7 (B) a qualifying facility;
5-8 (C) a power generation company;
5-9 (D) an exempt wholesale generator;
5-10 (E) [ (D)] a power marketer;
5-11 (F) [ (E)] a corporation described by Section
5-12 32.053 to the extent the corporation sells electricity exclusively
5-13 at wholesale and not to the ultimate consumer; or
5-14 (G) an electric cooperative;
5-15 (H) a retail electric provider;
5-16 (I) this state or an agency of this state; or
5-17 (J) [ (F)] a person not otherwise an electric
5-18 utility who:
5-19 (i) furnishes an electric service or
5-20 commodity only to itself, its employees, or its tenants as an
5-21 incident of employment or tenancy, if that service or commodity is
5-22 not resold to or used by others;
5-23 (ii) owns or operates in this state
5-24 equipment or facilities to produce, generate, transmit, distribute,
5-25 sell, or furnish electric energy to an electric utility, if the
5-26 equipment or facilities are used primarily to produce and generate
5-27 electric energy for consumption by that person; or
5-28 (iii) owns or operates in this state a
5-29 recreational vehicle park that provides metered electric service in
5-30 accordance with Subchapter C, Chapter 184.
5-31 (7) [ (2)] "Exempt wholesale generator" means a person
5-32 who is engaged directly or indirectly through one or more
5-33 affiliates exclusively in the business of owning or operating all
5-34 or part of a facility for generating electric energy and selling
5-35 electric energy at wholesale and who:
5-36 (A) does not own a facility for the transmission
5-37 of electricity, other than an essential interconnecting
5-38 transmission facility necessary to effect a sale of electric energy
5-39 at wholesale; and
5-40 (B) has:
5-41 (i) applied to the Federal Energy
5-42 Regulatory Commission for a determination under 15 U.S.C. Section
5-43 79z-5a; or
5-44 (ii) registered as an exempt wholesale
5-45 generator as required by Section 35.032.
5-46 (8) "Freeze period" means the period beginning on
5-47 January 1, 1999, and ending on December 31, 2001.
5-48 (9) "Independent system operator" means an entity
5-49 supervising the collective transmission facilities of a power
5-50 region that is charged with nondiscriminatory coordination of
5-51 market transactions, systemwide transmission planning, and network
5-53 (10) "Power generation company" means a person who:
5-54 (A) generates electricity that is intended to be
5-55 sold at wholesale;
5-56 (B) does not own a transmission or distribution
5-57 facility in this state other than an essential interconnecting
5-58 facility, a facility not dedicated to public use, or a facility
5-59 otherwise excluded from the definition of "electric utility" under
5-60 Subdivision (6); and
5-61 (C) does not have a certificated service area,
5-62 although its affiliated electric utility or transmission and
5-63 distribution utility may have a certificated service area.
5-64 (11) [ (3)] "Power marketer" means a person who:
5-65 (A) becomes an owner of electric energy in this
5-66 state for the purpose of selling the electric energy at wholesale;
5-67 (B) does not own generation, transmission, or
5-68 distribution facilities in this state;
5-69 (C) does not have a certificated service area;
6-2 (D) has:
6-3 (i) been granted authority by the Federal
6-4 Energy Regulatory Commission to sell electric energy at
6-5 market-based rates; or
6-6 (ii) registered as a power marketer under
6-7 Section 35.032.
6-8 (12) "Power region" means a contiguous geographical
6-9 area which is a distinct region of the North American Electric
6-10 Reliability Council.
6-11 (13) [ (4)] "Qualifying cogenerator" and "qualifying
6-12 small power producer" have the meanings assigned those terms by 16
6-13 U.S.C. Sections 796(18)(C) and 796(17)(D). A qualifying
6-14 cogenerator that provides electricity to the purchaser of the
6-15 cogenerator's thermal output is not for that reason considered to
6-16 be a retail electric provider or a power generation company.
6-17 (14) [ (5)] "Qualifying facility" means a qualifying
6-18 cogenerator or qualifying small power producer.
6-19 (15) [ (6)] "Rate" includes a compensation, tariff,
6-20 charge, fare, toll, rental, or classification that is directly or
6-21 indirectly demanded, observed, charged, or collected by an electric
6-22 utility for a service, product, or commodity described in the
6-23 definition of electric utility in this section and a rule,
6-24 practice, or contract affecting the compensation, tariff, charge,
6-25 fare, toll, rental, or classification that must be approved by a
6-26 regulatory authority.
6-27 (16) "Retail customer" means the separately metered
6-28 end-use customer who purchases and ultimately consumes electricity.
6-29 (17) "Retail electric provider" means a person that
6-30 sells electric energy to retail customers in this state. A retail
6-31 electric provider may not own, operate, or control generation
6-33 (18) "Separately metered" means metered by an
6-34 individual meter that is used to measure electric energy
6-35 consumption by a retail customer and for which the customer is
6-36 directly billed by a utility or retail electric provider.
6-37 (19) "Transmission and distribution utility" means a
6-38 person or river authority that owns or operates for compensation in
6-39 this state equipment or facilities to transmit or distribute
6-40 electricity, except for facilities necessary to interconnect a
6-41 generation facility with the transmission or distribution network,
6-42 a facility not dedicated to public use, or a facility otherwise
6-43 excluded from the definition of "electric utility" under
6-44 Subdivision (6), in a qualifying power region certified pursuant to
6-45 Section 39.152 but does not include a municipally owned utility or
6-46 an electric cooperative.
6-47 (20) [ (7)] "Transmission service" includes
6-48 construction or enlargement of facilities, transmission over
6-49 distribution facilities, control area services, scheduling
6-50 resources, regulation services, reactive power support, voltage
6-51 control, provision of operating reserves, and any other associated
6-52 electrical service the commission determines appropriate.
6-53 SECTION 9. Subchapter A, Chapter 32, Utilities Code, is
6-54 amended by adding Section 32.0015 to read as follows:
6-55 Sec. 32.0015. REGULATION OF SUCCESSOR ELECTRIC UTILITY OR
6-56 ELECTRIC COOPERATIVE. If an electric utility purchases, acquires,
6-57 merges, or consolidates with or acquires 50 percent or more of the
6-58 stock of an electric utility or electric cooperative, the
6-59 commission shall regulate the successor electric utility or
6-60 electric cooperative in the same manner that the commission would
6-61 regulate the entity that was subject to the stricter regulation
6-62 before the purchase, acquisition, merger, or consolidation.
6-63 SECTION 10. Sections 32.051 and 32.052, Utilities Code, are
6-64 amended to read as follows:
6-65 Sec. 32.051. Exemption of River Authority From Wholesale
6-66 Rate Regulation. Notwithstanding any other provision of this
6-67 title, the commission may not directly or indirectly regulate
6-68 revenue requirements, rates, fuel costs, fuel charges, or fuel
6-69 acquisitions that are related to the generation and sale of
7-1 electricity at wholesale, and not to ultimate consumers, by a river
7-2 authority operating a steam generating plant on or before
7-3 January 1, 1999.
7-4 Sec. 32.052. Ability of Certain River Authorities to
7-5 Construct Improvements. A river authority operating a steam
7-6 generating plant on or before January 1, 1999, may acquire,
7-7 finance, construct, rebuild, repower, and use new or existing power
7-8 plants, equipment, transmission lines, or other assets to sell
7-9 electricity exclusively at wholesale to:
7-10 (1) a purchaser in San Saba, Llano, Burnet, Travis,
7-11 Bastrop, Blanco, Colorado, or Fayette County; or
7-12 (2) a purchaser in an area served by the river
7-13 authority on January 1, 1975.
7-14 SECTION 11. Section 32.053, Utilities Code, is amended by
7-15 amending Subsections (b) and (f) and adding Subsections (g) and (h)
7-16 to read as follows:
7-17 (b) Notwithstanding a river authority's enabling legislation
7-18 or Chapter 245, Acts of the 67th Legislature, Regular Session, 1981
7-19 (Article 717p, Vernon's Texas Civil Statutes), a corporation may:
7-20 (1) acquire, finance, construct, rebuild, repower,
7-21 operate, or sell a facility directly related to the generation of
7-22 electricity; [ and]
7-23 (2) sell, at wholesale only, the output of the
7-24 facility to a purchaser, other than an ultimate consumer, at any
7-25 location in this state; and
7-26 (3) purchase and sell electricity, at wholesale only,
7-27 to a purchaser, other than an ultimate consumer, at any location in
7-28 this state.
7-29 (f) The proceeds from the sale of bonds or other obligations
7-30 the interest on which is exempt from taxation and that are issued
7-31 by a corporation or river authority subject to this section, other
7-32 than a bond or obligation available to an investor-owned utility or
7-33 exempt wholesale generator, may not be used by the corporation[ ,
7-34 and may not have been used,] to finance the construction or
7-35 acquisition of or the rebuilding or repowering of a facility for
7-36 the generation of electricity by the corporation.
7-37 (g) Notwithstanding any other law, the board of directors of
7-38 a river authority may sell, lease, loan, or otherwise transfer
7-39 some, all, or substantially all of the electric generation property
7-40 of the river authority to a nonprofit corporation authorized under
7-41 this section or Chapter 245, Acts of the 67th Legislature, Regular
7-42 Session, 1981 (Article 717p, Vernon's Texas Civil Statutes). The
7-43 property transfer shall be made pursuant to terms and conditions
7-44 approved by the board of directors of the river authority.
7-45 (h) Subsections (a)-(f) do not apply to a corporation
7-46 created pursuant to Chapter 245, Acts of the 67th Legislature,
7-47 Regular Session, 1981 (Article 717p, Vernon's Texas Civil
7-48 Statutes), to serve an area described in Section 32.052.
7-49 SECTION 12. Section 35.001, Utilities Code, is amended to
7-50 read as follows:
7-51 Sec. 35.001. Definition. In this subchapter, "electric
7-52 utility" includes a municipally owned utility and an electric
7-54 SECTION 13. Section 35.004, Utilities Code, is amended to
7-55 read as follows:
7-56 Sec. 35.004. PROVISION OF TRANSMISSION SERVICE. (a) An
7-57 electric utility or transmission and distribution utility that owns
7-58 or operates transmission facilities shall provide wholesale
7-59 transmission service at rates and terms, including terms of access,
7-60 that are comparable to the rates and terms of the utility's own use
7-61 of its system.
7-62 (b) The commission shall ensure that an electric utility or
7-63 transmission and distribution utility provides nondiscriminatory
7-64 access to wholesale transmission service for qualifying facilities,
7-65 exempt wholesale generators, power marketers, power generation
7-66 companies, retail electric providers, and other electric utilities
7-67 or transmission and distribution utilities.
7-68 (c) When an electric utility, electric cooperative, or
7-69 transmission and distribution utility provides wholesale
8-1 transmission service within ERCOT at the request of a third party,
8-2 the commission shall ensure that the utility recovers the utility's
8-3 reasonable costs in providing wholesale transmission services
8-4 necessary for the transaction from the entity for which the
8-5 transmission is provided so that the utility's other customers do
8-6 not bear the costs of the service.
8-7 (d) The commission shall price wholesale transmission
8-8 services within ERCOT based on the postage stamp method of pricing
8-9 under which a transmission-owning utility's rate is based on the
8-10 ERCOT utilities' combined annual costs of transmission divided by
8-11 the total demand placed on the combined transmission systems of all
8-12 such transmission-owning utilities within a power region. An
8-13 electric utility subject to the freeze period imposed by Section
8-14 39.052 may treat transmission costs in excess of transmission
8-15 revenues during the freeze period as an expense for purposes of
8-16 determining annual costs in the annual report filed pursuant to
8-17 Section 39.257. Notwithstanding Section 36.201, the commission may
8-18 approve rates that may be periodically adjusted to ensure timely
8-19 recovery of transmission investment.
8-20 (e) The commission shall ensure that ancillary services
8-21 necessary to facilitate the transmission of electric energy are
8-22 available at reasonable prices with terms and conditions that are
8-23 not unreasonably preferential, prejudicial, discriminatory,
8-24 predatory, or anticompetitive. In this subsection, "ancillary
8-25 services" means services necessary to facilitate the transmission
8-26 of electric energy including load following, standby power, backup
8-27 power, reactive power, and such other services as the commission
8-28 may determine by rule.
8-29 SECTION 14. Subsection (b), Section 35.005, Utilities Code,
8-30 is amended to read as follows:
8-31 (b) The commission may require transmission service at
8-32 wholesale, including the construction or enlargement of a
8-33 facility[ , in a proceeding not related to approval of an integrated
8-34 resource plan].
8-35 SECTION 15. Section 35.033, Utilities Code, is amended to
8-36 read as follows:
8-37 Sec. 35.033. Affiliate Wholesale Provider. An affiliate of
8-38 an electric utility may be an exempt wholesale generator or power
8-39 marketer and may sell electric energy to its affiliated electric
8-40 utility in accordance with [ Chapter 34 and other] laws governing
8-41 wholesale sales of electric energy.
8-42 SECTION 16. Section 35.034, Utilities Code, is amended by
8-43 adding Subsection (c) to read as follows:
8-44 (c) For purposes of this section, "electric utility" does
8-45 not include a river authority.
8-46 SECTION 17. Section 35.035, Utilities Code, is amended by
8-47 adding Subsection (d) to read as follows:
8-48 (d) For purposes of this section, "electric utility" does
8-49 not include a river authority.
8-50 SECTION 18. Chapter 35, Utilities Code, is amended by adding
8-51 Subchapter D to read as follows:
8-52 SUBCHAPTER D. STATE AUTHORITY TO SELL OR CONVEY POWER
8-53 Sec. 35.101. DEFINITIONS. In this subchapter:
8-54 (1) "Commissioner" means the Commissioner of the
8-55 General Land Office.
8-56 (2) "Public retail customer" means a retail customer
8-57 that is an agency of this state, an institution of higher
8-58 education, a public school district, or a political subdivision of
8-59 this state.
8-60 Sec. 35.102. STATE AUTHORITY TO SELL OR CONVEY POWER. The
8-61 commissioner, acting on behalf of the state, may sell or otherwise
8-62 convey power directly to a public retail customer regardless of
8-63 whether the public retail customer is also classified as a
8-64 wholesale customer under other provisions of this title.
8-65 Sec. 35.103. ACCESS TO TRANSMISSION AND DISTRIBUTION
8-66 SYSTEMS; RATES. (a) The state is entitled to have access to all
8-67 transmission and distribution systems of all electric utilities,
8-68 transmission and distribution utilities, municipally owned
8-69 utilities, and electric cooperatives that serve public retail
9-2 (b) An entity described by Subsection (a) shall provide any
9-3 utility service, including transmission, distribution, and other
9-4 services, to the state at the lowest applicable rate charged for
9-5 similar service to other customers.
9-6 Sec. 35.104. LIMIT IN CERTAIN AREAS. In a certificated
9-7 service area in which customer choice has not been introduced, the
9-8 state may not engage in retail transactions that exceed 2.5 percent
9-9 of a retail electric utility's total retail load.
9-10 Sec. 35.105. COSTS OF SERVING STATE AGENCY. An electric
9-11 utility, a municipally owned utility, or an electric cooperative
9-12 may not recover from a residential customer or from any other
9-13 customer class the assigned and allocated costs of serving a state
9-14 agency, institution of higher education, public school district, or
9-15 political subdivision of this state.
9-16 Sec. 35.106. WHOLESALE CUSTOMERS. This subchapter does not
9-17 prevent the commissioner, acting on behalf of this state, from
9-18 registering as a power marketer.
9-19 SECTION 19. Section 36.008, Utilities Code, is amended to
9-20 read as follows:
9-21 Sec. 36.008. STATE TRANSMISSION SYSTEM. In establishing
9-22 rates for an electric utility [ not required to file an integrated
9-23 resource plan], the commission may review the state's transmission
9-24 system and make recommendations to the utility on the need to build
9-25 new power lines, upgrade power lines, and make other necessary
9-26 improvements and additions.
9-27 SECTION 20. Section 36.052, Utilities Code, is amended to
9-28 read as follows:
9-29 Sec. 36.052. ESTABLISHING REASONABLE RETURN. In
9-30 establishing a reasonable return on invested capital, the
9-31 regulatory authority shall consider applicable factors, including:
9-32 (1) [ the efforts of the electric utility to comply
9-33 with its most recently approved integrated resource plan;]
9-34 [ (2)] the efforts and achievements of the utility in
9-35 conserving resources;
9-36 (2) [ (3)] the quality of the utility's services;
9-37 (3) [ (4)] the efficiency of the utility's operations;
9-39 (4) [ (5)] the quality of the utility's management.
9-40 SECTION 21. Subsection (d), Section 36.058, Utilities Code,
9-41 is amended to read as follows:
9-42 (d) In making a finding regarding an affiliate transaction,
9-43 [ including an affiliate transaction subject to Chapter 34,] the
9-44 regulatory authority shall:
9-45 (1) determine the extent to which the conditions and
9-46 circumstances of that transaction are reasonably comparable
9-47 relative to quantity, terms, date of contract, and place of
9-48 delivery; and
9-49 (2) allow for appropriate differences based on that
9-51 SECTION 22. Section 36.201, Utilities Code, is amended to
9-52 read as follows:
9-53 Sec. 36.201. AUTOMATIC ADJUSTMENT FOR CHANGES IN COSTS.
9-54 Except as permitted by [ Chapter 34 or] Section 36.204, the
9-55 commission may not establish a rate or tariff that authorizes an
9-56 electric utility to automatically adjust and pass through to the
9-57 utility's customers a change in the utility's fuel or other costs.
9-58 SECTION 23. Section 36.204, Utilities Code, is amended to
9-59 read as follows:
9-60 Sec. 36.204. COST RECOVERY AND INCENTIVES. In establishing
9-61 rates for an electric utility [ not required to file an integrated
9-62 resource plan], the commission may:
9-63 (1) allow timely recovery of the reasonable costs of
9-64 conservation, load management, and purchased power, notwithstanding
9-65 Section 36.201; and
9-66 (2) authorize additional incentives for conservation,
9-67 load management, purchased power, and renewable resources.
9-68 SECTION 24. Section 36.207, Utilities Code, is amended to
9-69 read as follows:
10-1 Sec. 36.207. USE OF MARK-UPS. Any mark-ups approved under
10-2 [ Chapter 34 or] Section 36.206 are an exceptional form of rate
10-3 relief that the electric utility may recover from ratepayers only
10-4 on a finding by the commission that the relief is necessary to
10-5 maintain the utility's financial integrity.
10-6 SECTION 25. Section 37.001, Utilities Code, is amended to
10-7 read as follows:
10-8 Sec. 37.001. DEFINITIONS. In this chapter:
10-9 (1) "Certificate" means a certificate of convenience
10-10 and necessity.
10-11 (2) "Electric utility" includes an electric
10-13 (3) "Retail electric utility" means a person,
10-14 political subdivision, or agency that operates, maintains, or
10-15 controls in this state a facility to provide retail electric
10-16 utility service. The term does not include a corporation described
10-17 by Section 32.053 to the extent that the corporation sells
10-18 electricity exclusively at wholesale and not to the ultimate
10-19 consumer. A qualifying cogenerator that sells electric energy at
10-20 retail to the sole purchaser of the cogenerator's thermal output
10-21 under Sections 35.061 and 36.007 is not for that reason considered
10-22 to be a retail electric utility.
10-23 SECTION 26. Section 37.051, Utilities Code, is amended by
10-24 adding Subsection (c) to read as follows:
10-25 (c) Notwithstanding any other provision of this chapter,
10-26 including Subsection (a), an electric cooperative is not required
10-27 to obtain a certificate of public convenience and necessity for the
10-28 construction, installation, operation, or extension of any
10-29 generating facilities or necessary interconnection facilities.
10-30 SECTION 27. Subchapter B, Chapter 37, Utilities Code, is
10-31 amended by adding Sections 37.060 and 37.061 to read as follows:
10-32 Sec. 37.060. DIVISION OF MULTIPLY CERTIFICATED SERVICE
10-33 AREAS. (a) This subsection and Subsections (b)-(g) shall apply
10-34 only to areas in which each retail electric utility that is
10-35 authorized to provide retail electric utility service to the area
10-36 is providing customer choice. For purposes of this subsection, an
10-37 electric cooperative or a municipally owned electric utility shall
10-38 be deemed to be providing customer choice if it has approved a
10-39 resolution adopting customer choice that is effective upon
10-40 certification of the applicable power region pursuant to Section
10-41 39.152 or effective within 24 months after the date of the
10-42 resolution adopting customer choice. All other retail electric
10-43 utilities shall be deemed to be providing customer choice if
10-44 customer choice will be allowed for customers of the retail
10-45 electric utility upon certification of the applicable power region
10-46 pursuant to Section 39.152. In areas in which each certificated
10-47 retail electric utility is providing customer choice, the
10-48 commission, if requested by a retail electric utility, shall
10-49 examine all areas within the service area of the retail electric
10-50 utility making the request that are also certificated to one or
10-51 more other retail electric utilities and, after notice and hearing,
10-52 shall amend the retail electric utilities' certificates so that
10-53 only one retail electric utility is certificated to provide
10-54 distribution services in any such area. Only retail electric
10-55 utilities certificated to serve an area on June 1, 1999, may
10-56 continue to serve the area or portion of the area under an amended
10-57 certificate issued pursuant to this subsection.
10-58 (b) This section shall not apply in any area in which a
10-59 municipally owned utility is certificated to provide retail
10-60 electric utility service if the municipally owned utility serving
10-61 the area files with the commission by February 1, 2000, a request
10-62 that areas within the certificated service area of the municipally
10-63 owned utility remain as presently certificated.
10-64 (c) The commission shall enter its order dividing multiply
10-65 certificated areas within one year of the date a request is
10-67 (d) In amending certificates under this section, the
10-68 commission shall take into consideration the factors set out in
10-69 Section 37.056.
11-1 (e) Notwithstanding Section 37.059, the commission shall
11-2 revoke certificates to the extent necessary to achieve the division
11-3 of retail electric service areas as provided by this section.
11-4 (f) Unless otherwise agreed by the affected retail electric
11-5 utilities, each retail electric utility shall be allowed to
11-6 continue to provide service to the location of
11-7 electricity-consuming facilities it is serving on the date an
11-8 application for division of the affected multiply certificated
11-9 service areas is filed. No customer located within the affected
11-10 multiply certificated service areas shall be permitted to switch
11-11 from one retail electric utility to another while an application
11-12 for division of the affected multiply certificated service areas is
11-14 (g) If on June 1, 1999, retail service is being provided in
11-15 an area by another retail electric utility with the written consent
11-16 of the retail electric utility certificated to serve the area, such
11-17 consent shall be filed with the commission. Upon notification of
11-18 such consent and a request by an affected retail electric utility
11-19 to amend the relevant certificates, the commission may grant an
11-20 exception or amend a retail electric utility's certificate.
11-21 (h) The commission shall not grant an additional retail
11-22 electric utility certificate to serve an area if the effect of the
11-23 grant would cause the area to be multiply certificated unless the
11-24 commission finds that the certificate holders are not providing
11-25 service to any part of the area for which a certificate is sought
11-26 and are not capable of providing adequate service to the area in
11-27 accordance with applicable standards. However, neither this
11-28 subsection nor the deadline of June 1, 1999, provided by Subsection
11-29 (a) shall apply to any application for multiple certification filed
11-30 with the commission on or before February 1, 1999, and such
11-31 applications may be processed in accordance with applicable law in
11-32 effect on the date the application was filed. Applications for
11-33 multiple certification filed with the commission on or before
11-34 February 1, 1999, may not be amended to expand the area for which a
11-35 certificate is sought except for contiguous areas within
11-36 municipalities that provide consent, as required by Section
11-37 37.053(b), no later than June 1, 1999.
11-38 (i) Notwithstanding Subsection (h), the commission may
11-39 singly certificate the service territory of a municipally owned
11-40 utility provided that:
11-41 (1) the application is limited to single certification
11-42 of the area within the municipality's boundaries as of June 1,
11-44 (2) the commission preserves the right of an electric
11-45 utility or an electric cooperative to serve its existing customers;
11-47 (3) the municipality is a member city of a municipal
11-48 power agency as that term is used in Section 40.059.
11-49 Sec. 37.061. EXISTING SERVICE AREA AGREEMENTS.
11-50 (a) Notwithstanding any other provision of this title, the
11-51 commission shall allow a municipally owned utility to amend the
11-52 service area boundaries of its certificate if:
11-53 (1) the municipally owned utility was the holder of a
11-54 certificate as of January 1, 1999;
11-55 (2) the municipally owned utility has an agreement
11-56 existing prior to January 1, 1999, with a public utility serving
11-57 the area that the public utility will not contest an application to
11-58 amend the certificate to add municipal territory; and
11-59 (3) the area for which a certificate is requested is
11-60 not certificated to a retail electric utility that is not a party
11-61 to the agreement and that has not consented in writing to
11-62 certification of the area to the municipality.
11-63 (b) The commission may not amend the certificate of the
11-64 public utility serving the affected area based upon the granting of
11-65 a certificate to the municipally owned utility.
11-66 SECTION 28. Subsection (a), Section 37.101, Utilities Code,
11-67 is amended to read as follows:
11-68 (a) If an area is or will be included within a municipality
11-69 as the result of annexation, incorporation, or another reason, each
12-1 electric utility and each electric cooperative that holds or is
12-2 entitled to hold a certificate under this title to provide service
12-3 or operate a facility in the area before the inclusion has the
12-4 right to continue to provide the service or operate the facility
12-5 and extend service within the utility's certificated area in the
12-6 annexed or incorporated area under the rights granted by the
12-7 certificate and this title.
12-8 SECTION 29. Section 38.001, Utilities Code, is amended to
12-9 read as follows:
12-10 Sec. 38.001. GENERAL STANDARD. An electric utility and an
12-11 electric cooperative shall furnish service, instrumentalities, and
12-12 facilities that are safe, adequate, efficient, and reasonable.
12-13 SECTION 30. Section 38.004, Utilities Code, is amended to
12-14 read as follows:
12-15 Sec. 38.004. MINIMUM CLEARANCE STANDARD. Notwithstanding
12-16 any other law, a transmission or distribution line owned by an
12-17 electric utility or an electric cooperative must be constructed,
12-18 operated, and maintained, as to clearances, in the manner described
12-19 by the National Electrical Safety Code Standard ANSI (c)(2), as
12-20 adopted by the American National Safety Institute and in effect at
12-21 the time of construction.
12-22 SECTION 31. Subchapter A, Chapter 38, Utilities Code, is
12-23 amended by adding Section 38.005 to read as follows:
12-24 Sec. 38.005. ELECTRIC SERVICE RELIABILITY MEASURES.
12-25 (a) The commission shall implement service quality and reliability
12-26 standards relating to the delivery of electricity to retail
12-27 customers by electric utilities and transmission and distribution
12-28 utilities. The commission by rule shall develop reliability
12-29 standards including but not limited to the following:
12-30 (1) the system-average interruption frequency index;
12-31 (2) the system-average interruption duration index;
12-32 (3) achievement of average response time for customer
12-33 service requests or inquiries; or
12-34 (4) other standards that the commission finds
12-35 reasonable and appropriate.
12-36 (b) The standards implemented under Subsection (a) shall
12-37 require each electric utility and transmission and distribution
12-38 utility subject to this section to maintain adequately trained and
12-39 experienced personnel throughout the utility's service area so that
12-40 the utility is able to fully and adequately comply with the
12-41 appropriate service quality and reliability standards.
12-42 (c) The standards shall ensure that electric utilities do
12-43 not neglect any geographic area, including rural areas, communities
12-44 of less than 1,000 persons, and low-income areas, with regard to
12-45 system reliability.
12-46 (d) The commission may require each electric utility and
12-47 transmission and distribution utility to supply data to assist the
12-48 commission in developing the reliability standards.
12-49 (e) Each electric utility, transmission and distribution
12-50 utility, and generation provider shall be obligated to comply with
12-51 any operational criteria duly established by the independent
12-52 organization as defined by Section 39.151 or adopted by the
12-54 SECTION 32. Section 38.071, Utilities Code, is amended to
12-55 read as follows:
12-56 Sec. 38.071. Improvements in Service; Interconnecting
12-57 Service. The commission, after notice and hearing, may:
12-58 (1) order an electric utility to provide specified
12-59 improvements in its service in a specified area if:
12-60 (A) service in the area is inadequate or
12-61 substantially inferior to service in a comparable area; and
12-62 (B) requiring the company to provide the
12-63 improved service is reasonable; or
12-64 (2) order two or more electric utilities or electric
12-65 cooperatives to establish specified facilities for interconnecting
12-67 SECTION 33. Subtitle B, Title 2, Utilities Code, is amended
12-68 by adding Chapters 39, 40, and 41 to read as follows:
13-1 CHAPTER 39. RESTRUCTURING OF ELECTRIC UTILITY INDUSTRY
13-2 SUBCHAPTER A. GENERAL PROVISIONS
13-3 Sec. 39.001. LEGISLATIVE POLICY AND PURPOSE. (a) This
13-4 chapter is enacted to protect the public interest during the
13-5 transition to and in the establishment of a fully competitive
13-6 electric power industry.
13-7 (b) The legislature finds that it is in the public interest
13-9 (1) implement on January 1, 2002, a competitive retail
13-10 electric market that allows each retail customer to choose the
13-11 customer's provider of electricity and that encourages full and
13-12 fair competition among all providers of electricity;
13-13 (2) allow utilities with uneconomic generation-related
13-14 assets and purchased power contracts to recover the reasonable
13-15 excess costs over market of such assets and purchased power
13-16 contracts; and
13-17 (3) educate utility customers about anticipated
13-18 changes in the provision of retail electric service to ensure that
13-19 the benefits of the competitive market reach all customers.
13-20 Sec. 39.002. APPLICABILITY. This chapter, other than
13-21 Sections 39.155, 39.157(e), 39.203, 39.603, and 39.604, does not
13-22 apply to a municipally owned utility or an electric cooperative.
13-23 Sections 39.157(e), 39.203, and 39.604, however, apply only to a
13-24 municipally owned utility or an electric cooperative that is
13-25 offering customer choice. If there is a conflict between the
13-26 specific provisions of this chapter and any other provisions of
13-27 this title, except for Chapters 40 and 41, the provisions of this
13-28 chapter control.
13-29 Sec. 39.003. OPERATIONS IN MULTIPLE POWER REGIONS. In this
13-30 chapter, a retail electric utility whose certificated service area
13-31 includes areas that are located in a qualifying power region and
13-32 areas that are located in a power region that is not a qualifying
13-33 power region shall be considered a retail electric utility in a
13-34 qualifying power region for that part of its certificated service
13-35 area that is located in a qualifying power region and shall be
13-36 considered a retail electric utility not in a qualifying power
13-37 region for that part of its certificated service area that is
13-38 located in a power region that is not a qualifying power region.
13-39 SUBCHAPTER B. TRANSITION TO COMPETITIVE RETAIL
13-40 ELECTRIC MARKET
13-41 Sec. 39.051. UNBUNDLING. (a) On or before September 1,
13-42 2000, each electric utility shall unbundle its costs and rates into
13-43 generation, transmission, distribution, and retail energy services
13-44 and a system benefit fund charge and expected competition
13-45 transition charge.
13-46 (b) Not later than January 1, 2002, each electric utility
13-47 shall separate its business activities from one another into the
13-48 following units:
13-49 (1) a power generation company;
13-50 (2) a retail electric provider; and
13-51 (3) a transmission and distribution utility.
13-52 (c) An electric utility may accomplish the separation
13-53 required by Subsection (b) either through the creation of separate
13-54 nonaffiliated companies or separate affiliated companies owned by a
13-55 common holding company or through the sale of assets to a third
13-57 (d) Each electric utility shall unbundle under this section
13-58 in a manner that provides for a separation of personnel,
13-59 information flow, functions, and operations.
13-60 (e) Each electric utility shall file with the commission a
13-61 plan to implement this section by January 1, 2000.
13-62 (f) Within 120 days of the date the plan required under
13-63 Subsection (e) is filed with the commission, the commission shall
13-64 adopt the utility's plan for business separation required by
13-65 Subsection (b), adopt the plan with changes, or reject the plan and
13-66 require the utility to file a new plan.
13-67 (g) If the commission determines that a power region will
13-68 not qualify for customer choice under Section 39.152 by January 1,
13-69 2002, it may adjust the filing and implementation dates in this
14-1 section for utilities in that region.
14-2 (h) Transactions by electric utilities involving sales,
14-3 transfers, or other disposition of assets to accomplish the
14-4 purposes of this section shall not be subject to Section 14.101,
14-5 35.034, or 35.035.
14-6 Sec. 39.052. FREEZE ON EXISTING RETAIL BASE RATE TARIFFS.
14-7 (a) Until January 1, 2002, an electric utility shall provide
14-8 retail electric service within its certificated service area in
14-9 accordance with the electric utility's retail base rate tariffs in
14-10 effect on September 1, 1999, including its purchased power cost
14-11 recovery factor.
14-12 (b) During the freeze period an electric utility may not
14-13 increase its retail base rates above the rates provided by this
14-14 section except for losses caused by force majeure as provided by
14-15 Section 39.055.
14-16 (c) Notwithstanding any other provision of this title,
14-17 during the freeze period the regulatory authority may not reduce
14-18 the retail base rates of an electric utility, except as may be
14-19 ordered as stipulated to by an electric utility in a proceeding
14-20 that was pending before the commission on January 1, 1999.
14-21 (d) During the freeze period the retail base rates, overall
14-22 revenues, return on invested capital, and net income of an electric
14-23 utility are not subject to complaint, hearing, or determination as
14-24 to reasonableness.
14-25 (e) An electric utility that has a rate proceeding pending
14-26 before the commission as of January 2, 1999, shall provide service
14-27 in accordance with the tariffs approved in that proceeding from the
14-28 date of approval until the end of the freeze period.
14-29 (f) Nothing in this section affects the authority of the
14-30 commission to fulfill its obligations under Section 39.262.
14-31 (g) Nothing in this section shall deny a utility its right
14-32 to have the commission conduct proceedings and issue a final order
14-33 pertaining to any matter that may be remanded to the commission by
14-34 a court having jurisdiction, except that the final order may not
14-35 affect the rates charged to customers during the freeze period but
14-36 shall be taken into account during the utility's true-up proceeding
14-37 under Section 39.262.
14-38 (h) Nothing in this title shall be construed to prevent an
14-39 electric utility or a transmission and distribution utility from
14-40 filing, and the commission from approving, a change in wholesale
14-41 transmission service rates during the freeze period.
14-42 Sec. 39.053. COST RECOVERY ADJUSTMENTS. This subchapter
14-43 does not limit or alter the ability of an electric utility during
14-44 the freeze period to revise its fuel factor or to reconcile fuel
14-45 expenses and to either refund fuel overcollections or surcharge
14-46 fuel undercollections to customers, as authorized by its tariffs
14-47 and Sections 36.203 and 36.205.
14-48 Sec. 39.054. RETAIL ELECTRIC SERVICE DURING THE FREEZE
14-49 PERIOD. (a) An electric utility shall provide retail electric
14-50 service during the freeze period in accordance with any contract
14-51 terms applicable to a particular retail customer approved by the
14-52 regulatory authority and in effect on December 31, 1998.
14-53 (b) Nothing in Sections 39.052(c) and (d) shall be construed
14-54 to restrict any customer's right to complain during the freeze
14-55 period to the regulatory authority regarding the quality of retail
14-56 electric service provided by the electric utility or the
14-57 applicability of an electric utility's particular tariff to the
14-59 (c) Nothing in this title shall be construed to restrict an
14-60 electric utility, voluntarily and at its sole discretion, from
14-61 offering new services or new tariff options to its customers during
14-62 the freeze period.
14-63 (d) Any offering of new services or tariff options under
14-64 this section shall be equal to or greater than an electric
14-65 utility's long-run marginal cost and not be unreasonably
14-66 preferential, prejudicial, discriminatory, predatory, or
14-68 (e) Revenue from any new offering under this section shall
14-69 be accounted for in a manner consistent with Section 36.007.
15-1 Sec. 39.055. FORCE MAJEURE. (a) An electric utility may
15-2 recover losses resulting from force majeure through an increase in
15-3 its retail base rates during the freeze period.
15-4 (b) Notwithstanding Subchapter C, Chapter 36, the regulatory
15-5 authority, after a hearing to determine the electric utility's
15-6 losses from force majeure, shall permit the utility to fully
15-7 collect any approved force majeure increase through an appropriate
15-8 customer surcharge mechanism.
15-9 (c) For purposes of this section, "force majeure" means a
15-10 major event or combination of major events, including new or
15-11 expanded state or federal statutory or regulatory requirements;
15-12 hurricanes, tornadoes, ice storms, or other natural disasters; or
15-13 acts of war, terrorism, or civil disturbance, beyond the control of
15-14 an electric utility that the regulatory authority finds increases
15-15 the utility's total reasonable and necessary nonfuel costs or
15-16 decreases the utility's total nonfuel revenues related to the
15-17 generation and delivery of electricity by more than 10 percent for
15-18 any calendar year during the freeze period. The term does not
15-19 include any changes in general economic conditions such as
15-20 inflation, interest rates, or other factors of general application.
15-21 SUBCHAPTER C. RETAIL COMPETITION
15-22 Sec. 39.101. CUSTOMER SAFEGUARDS. (a) Before retail
15-23 competition begins on January 1, 2002, the commission shall ensure
15-24 that retail customer protections are established that entitle a
15-26 (1) to safe, reliable, and reasonably priced
15-27 electricity, including protection against service disconnections in
15-28 extreme weather or in cases of medical emergency or nonpayment for
15-29 unrelated services;
15-30 (2) to privacy of customer consumption and credit
15-32 (3) to bills presented in a clear format and in
15-33 language readily understandable by customers;
15-34 (4) to the option to have all electric services on a
15-35 single bill, except in those instances where multiple bills are
15-36 allowed under Chapters 40 and 41;
15-37 (5) to protection from discrimination on the basis of
15-38 race, color, sex, nationality, religion, or marital status;
15-39 (6) to accuracy of metering and billing;
15-40 (7) to information in English and Spanish and any
15-41 other language as necessary concerning rates, key terms and
15-42 conditions, and the environmental impact of certain production
15-44 (8) to information in English and Spanish and any
15-45 other language as necessary concerning low-income assistance
15-46 programs and deferred payment plans; and
15-47 (9) to other information or protections necessary to
15-48 ensure high-quality service to customers.
15-49 (b) A customer is entitled:
15-50 (1) to be informed about rights and opportunities in
15-51 the transition to a competitive electric industry;
15-52 (2) to choose the customer's retail electric provider
15-53 consistent with this chapter, to have that choice honored, and to
15-54 assume that the customer's chosen provider will not be changed
15-55 without the customer's informed consent;
15-56 (3) to have access to providers of energy efficiency
15-57 services and to providers of energy generated by renewable energy
15-59 (4) to be served by a provider of last resort that
15-60 offers a commission-approved standard service package;
15-61 (5) to receive sufficient information to make an
15-62 informed choice of service provider;
15-63 (6) to be protected from unfair, misleading, or
15-64 deceptive practices, including protection from being billed for
15-65 services that were not authorized or provided; and
15-66 (7) to have an impartial and prompt resolution of
15-67 disputes with its chosen retail electric provider and transmission
15-68 and distribution utility.
15-69 (c) The commission has the authority to adopt and enforce
16-1 such rules as may be necessary or appropriate to carry out
16-2 Subsections (a) and (b), including but not limited to rules for
16-3 minimum service standards for a retail electric provider relating
16-4 to customer deposits and the extension of credit, switching fees,
16-5 levelized billing programs, termination of service, and quality of
16-6 service. The commission has jurisdiction over all providers of
16-7 electric service in enforcing Subsections (a) and (b) and may
16-8 assess civil and administrative penalties under Section 15.023 and
16-9 seek civil penalties under Section 15.028.
16-10 (d) On or before December 31, 2001, the commission shall
16-11 modify its current rules regarding customer protections to ensure
16-12 that at least the same level of customer protection against
16-13 potential abuses and the same quality of service that exists on
16-14 December 31, 1999, is maintained in a restructured electric
16-16 Sec. 39.102. RETAIL CUSTOMER CHOICE. (a) Each retail
16-17 customer in the state, except retail customers in power regions
16-18 that are not certified as qualifying for competition by the
16-19 commission and retail customers of electric cooperatives and
16-20 municipally owned utilities that have not opted for customer
16-21 choice, shall have customer choice on and after January 1, 2002.
16-22 (b) The affiliated retail electric provider of the electric
16-23 utility serving a retail customer on December 31, 2001, may
16-24 continue to serve that customer until the customer chooses service
16-25 from a different retail electric provider, an electric cooperative
16-26 offering customer choice, or a municipally owned utility offering
16-27 customer choice.
16-28 (c) An electric utility that has in effect a systemwide
16-29 freeze for residential and commercial customers extending beyond
16-30 December 31, 2001, that has been found by a regulatory authority to
16-31 be in the public interest shall not be subject to this chapter. At
16-32 the expiration of the utility's freeze period, the utility shall be
16-33 subject to the provisions of this chapter and shall, at that time,
16-34 have no claim for stranded cost recovery.
16-35 Sec. 39.103. COMMISSION AUTHORITY TO DELAY COMPETITION AND
16-36 SET NEW RATES. If the commission determines under Section 39.104
16-37 that a power region is unable to offer fair competition and
16-38 reliable service to all retail customer classes on January 1, 2002,
16-39 or that the power region fails to meet the requirements of Section
16-40 39.152, the commission shall delay customer choice for the power
16-41 region and may on or after January 1, 2002, establish new rates for
16-42 all electric utilities in the power region as provided by Chapter
16-44 Sec. 39.104. CUSTOMER CHOICE PILOT PROJECTS. (a) Customer
16-45 choice pilot projects may be used to allow the commission to
16-46 evaluate the ability of each power region and electric utility to
16-47 implement customer choice.
16-48 (b) The commission shall require each electric utility
16-49 operating in ERCOT to offer customer choice in its service area
16-50 amounting to five percent of the utility's combined load of all
16-51 customer classes beginning on June 1, 2001.
16-52 (c) The commission may require an electric utility operating
16-53 outside of ERCOT to offer customer choice in its service area
16-54 amounting to five percent of the utility's combined load of all
16-55 customer classes beginning on June 1, 2001.
16-56 (d) The load designated for customer choice under this
16-57 section shall be distributed among all customer classes of a
16-58 utility consistent with the purpose of this section and subject to
16-59 commission approval.
16-60 (e) Customers participating in a pilot project under this
16-61 section may buy electric energy from any retail electric provider
16-62 certified by the commission under Section 39.352, including an
16-63 affiliated retail electric provider; provided, however, that a
16-64 retail electric provider may not participate in a pilot project in
16-65 the certificated service area served by the electric utility with
16-66 which it is affiliated.
16-67 (f) Each utility operating a pilot project under this
16-68 section shall charge residential and small commercial customers in
16-69 accordance with Section 39.052.
17-1 (g) The commission may prescribe reporting requirements it
17-2 considers necessary to evaluate a pilot project consistent with the
17-3 purpose of this section.
17-4 (h) Customers having customer choice under this section
17-5 shall be billed as provided by Section 39.107.
17-6 (i) The commission may prescribe terms and conditions it
17-7 considers necessary to prohibit anticompetitive practices and to
17-8 encourage customer choice offered under this section.
17-9 (j) Notwithstanding any other provision of this title, a
17-10 retail electric provider participating in a pilot project under
17-11 this section is not an electric utility or a retail electric
17-13 Sec. 39.105. LIMITATION ON SALE OF ELECTRICITY. (a) After
17-14 January 1, 2002, in areas in which customer choice has been
17-15 introduced, a transmission and distribution utility may not sell
17-16 electricity or otherwise participate in the market for electricity
17-17 except for the purpose of buying electricity to serve its own
17-19 (b) A person or retail electric utility may not provide,
17-20 furnish, or make available electric service at retail within the
17-21 certificated service area of an electric cooperative that has not
17-22 adopted customer choice or a municipally owned utility that has not
17-23 adopted customer choice. However, this subsection shall not
17-24 prohibit the provision of electric service in multiply certificated
17-25 service areas to customers of any other retail electric utility.
17-26 Sec. 39.106. PROVIDER OF LAST RESORT. (a) The commission
17-27 shall designate retail electric providers in areas of the state in
17-28 which customer choice is in effect to serve as providers of last
17-30 (b) A provider of last resort shall offer a standard retail
17-31 service package for each class of customers designated by the
17-32 commission at a fixed, nondiscountable rate approved by the
17-34 (c) A provider of last resort shall provide the standard
17-35 retail service package to any requesting customer in the territory
17-36 for which it is the provider of last resort.
17-37 (d) For all areas of the state for which the commission has
17-38 determined that customer choice is to be introduced on January 1,
17-39 2002, the commission shall designate the provider or providers of
17-40 last resort no later than June 1, 2001. For areas of the state for
17-41 which customer choice is not to be introduced on January 1, 2002,
17-42 except as provided in Sections 40.053(c) and 41.053(c), the
17-43 commission shall designate the provider or providers of last resort
17-44 at the earliest feasible date after determining that conditions for
17-45 permitting customer choice in that area have been met but no later
17-46 than 180 days before customer choice is to begin.
17-47 (e) The commission shall determine the procedures and
17-48 criteria, which may include the solicitation of bids, for
17-49 designating a provider or providers of last resort. The commission
17-50 may redesignate the provider of last resort according to a schedule
17-51 it considers appropriate.
17-52 (f) In the event that no retail electric provider applies to
17-53 be the provider of last resort for a given area of the state on
17-54 reasonable terms and conditions, the commission may require a
17-55 retail electric provider to become the provider of last resort as a
17-56 condition of receiving or maintaining a certificate pursuant to
17-57 Section 39.352.
17-58 (g) In the event that a retail electric provider fails to
17-59 serve any or all of its customers, the provider of last resort
17-60 shall offer each such customer the standard retail service package
17-61 for that customer class with no interruption of service to any
17-63 Sec. 39.107. METERING AND BILLING SERVICES. (a) On
17-64 introduction of customer choice in a service area, metering
17-65 services for the area shall continue to be provided by the
17-66 transmission and distribution utility affiliate of the electric
17-67 utility that was serving the area prior to the introduction of
17-68 customer choice. Metering services shall be provided on a
17-69 competitive basis beginning:
18-1 (1) January 1, 2004, in areas in which customer choice
18-2 is introduced January 1, 2002; and
18-3 (2) in areas in which customer choice begins at a
18-4 later date, two years after the date that customer choice is
18-5 introduced in the area.
18-6 (b) On introduction of customer choice in a service area,
18-7 tenants of leased or rented property that is separately metered
18-8 shall have the right to choose a retail electric provider, and the
18-9 owner of the property must grant reasonable and nondiscriminatory
18-10 access to transmission and distribution utilities or retail
18-11 electric providers for metering purposes.
18-12 (c) Beginning on the date of introduction of customer choice
18-13 in a service area, a transmission and distribution utility shall
18-14 bill a customer's retail electric provider for nonbypassable
18-15 delivery charges as determined pursuant to Section 39.201. The
18-16 retail electric provider must pay these charges.
18-17 (d) A transmission and distribution utility may bill retail
18-18 customers at the request of a retail electric provider. A
18-19 transmission and distribution utility that provides billing service
18-20 at the request of an affiliated retail electric provider shall
18-21 offer billing service on comparable terms and conditions to any
18-22 other requesting retail electric provider of a customer served by
18-23 the transmission and distribution utility.
18-24 (e) Beginning on the date of introduction of customer choice
18-25 in a service area, any charges for metering and billing services
18-26 shall comply with rules adopted by the commission relating to
18-27 nondiscriminatory rates of service.
18-28 Sec. 39.108. CONTRACTUAL OBLIGATIONS. This chapter shall
18-30 (1) interfere with or abrogate the rights or
18-31 obligations of any party, including a retail or wholesale customer,
18-32 to a contract with an investor-owned electric utility, river
18-33 authority, municipally owned utility, or electric cooperative;
18-34 (2) interfere with or abrogate the rights or
18-35 obligations of a party under a contract or agreement concerning
18-36 certificated utility service areas; or
18-37 (3) result in a change in wholesale power costs to
18-38 wholesale customers in Texas purchasing electricity under wholesale
18-39 power contracts the pricing provisions of which are based on
18-40 formulary rates, fuel adjustments, or average system costs.
18-41 SUBCHAPTER D. MARKET STRUCTURE
18-42 Sec. 39.151. ESSENTIAL ORGANIZATIONS. (a) Before obtaining
18-43 commission certification as a qualifying power region, a power
18-44 region must establish one or more independent organizations to
18-45 perform the following functions:
18-46 (1) ensure access to the transmission and distribution
18-47 systems for all buyers and sellers of electricity on
18-48 nondiscriminatory terms;
18-49 (2) ensure the reliability and adequacy of the
18-50 regional electrical network;
18-51 (3) ensure that information relating to a customer's
18-52 choice of retail electric provider is conveyed in a timely manner
18-53 to the persons who need such information; and
18-54 (4) ensure that electricity production and delivery
18-55 are accurately accounted for among the generators and wholesale
18-56 buyers and sellers in the region.
18-57 (b) "Independent organization" means an independent system
18-58 operator or other person that is sufficiently independent of any
18-59 producer or seller of electricity that its decisions will not be
18-60 unduly influenced by any producer or seller. An entity will be
18-61 deemed to be independent if it is governed by a board that has
18-62 three representatives from each segment of the electric market,
18-63 with the consumer segment being represented by one residential
18-64 customer, one commercial customer, and one industrial retail
18-66 (c) The commission shall certify an independent organization
18-67 or organizations to perform the functions set out in this section.
18-68 (d) An independent organization certified by the commission
18-69 for a power region shall establish and enforce procedures,
19-1 consistent with this title and the commission's rules, relating to
19-2 the reliability of the regional electrical network and accounting
19-3 for the production and delivery of electricity among generators and
19-4 all other market participants. The procedures shall be subject to
19-5 commission oversight and review.
19-6 (e) The commission may authorize an independent organization
19-7 that is certified under this section to charge a reasonable and
19-8 competitively neutral rate to wholesale buyers and sellers to cover
19-9 the independent organization's costs.
19-10 (f) In implementing this section, the commission may
19-11 cooperate with the utility regulatory commission of another state
19-12 or the federal government and may hold a joint hearing or make a
19-13 joint investigation with that commission.
19-14 (g) If it amends its governance rules to allow
19-15 representation reflecting the makeup of the retail market on its
19-16 governing board in accordance with Subsection (b), the existing
19-17 independent system operator in ERCOT will meet the criteria
19-18 provided by Subsection (a) with respect to ensuring access to the
19-19 transmission systems for all buyers and sellers of electricity in
19-20 the ERCOT region and ensuring the reliability of the regional
19-21 electrical network. The ERCOT independent system operator may meet
19-22 the criteria relating to the other functions of an independent
19-23 organization provided by Subsection (a) by adopting procedures and
19-24 acquiring resources needed to carry out those functions.
19-25 (h) The commission may delegate authority to the existing
19-26 independent system operator in ERCOT to enforce operating standards
19-27 within the ERCOT regional electrical network and to establish and
19-28 oversee transaction settlement procedures. The commission may
19-29 establish the terms and conditions for the ERCOT independent system
19-30 operator's authority to oversee utility dispatch functions after
19-31 the introduction of customer choice.
19-32 (i) A retail electric provider, municipally owned utility,
19-33 electric cooperative, power marketer, transmission and distribution
19-34 utility, or power generation company shall observe all scheduling,
19-35 operating, and settlement policies, rules, guidelines, and
19-36 procedures established by the independent system operator in ERCOT.
19-37 Failure to comply with this subsection may result in the
19-38 revocation, suspension, or amendment of a certificate as provided
19-39 by Section 39.356 or in the imposition of an administrative penalty
19-40 as provided by Section 39.357.
19-41 (j) To the extent the commission has authority over an
19-42 independent organization outside of ERCOT, the commission may
19-43 delegate authority to the independent organization consistent with
19-44 Subsection (h).
19-45 (k) No operational criteria, protocols, or other requirement
19-46 established by an independent organization, including the ERCOT
19-47 independent system operator, may adversely affect or impede any
19-48 manufacturing or other internal process operation associated with
19-49 an industrial generation facility, except to the minimum extent
19-50 necessary to assure reliability of the transmission network.
19-51 Sec. 39.152. QUALIFYING POWER REGIONS. (a) The commission
19-52 shall certify a power region as qualifying for customer choice if:
19-53 (1) a sufficient number of interconnected utilities in
19-54 the power region fall under the operational control of an
19-55 independent organization as described by Section 39.151;
19-56 (2) the power region has a generally applicable tariff
19-57 that guarantees open and nondiscriminatory access for all users to
19-58 transmission and distribution facilities in the power region as
19-59 provided by Section 39.203; and
19-60 (3) no person owns and controls more than 20 percent
19-61 of the installed generation capacity located in or capable of
19-62 delivering electricity to a power region.
19-63 (b) In determining whether a power region not entirely
19-64 within the state meets the requirements of this section, the
19-65 commission shall consider the extent to which the available
19-66 transmission facilities limit the delivery of electricity from
19-67 generators located outside the state to areas of the power region
19-68 within the state.
19-69 Sec. 39.153. CAPACITY AUCTION. (a) Each electric utility
20-1 subject to this section shall sell at auction, at least 60 days
20-2 before the date set for customer choice to begin in the power
20-3 region in which the electric utility serves, entitlements to at
20-4 least 15 percent of the electric utility's installed generation
20-5 capacity. For the purposes of this section, the term "electric
20-6 utility" includes any affiliated power generation company that is
20-7 unbundled from the electric utility in accordance with Section
20-8 39.051, but does not include any entity owning less than 400
20-9 megawatts of installed generation capacity.
20-10 (b) The obligation to auction the entitlements shall
20-11 continue until the earlier of 60 months after the date customer
20-12 choice is introduced in the power region or the date the commission
20-13 determines that 40 percent or more of the electric power consumed
20-14 by residential and small commercial customers within the affiliated
20-15 transmission and distribution utility's certificated service area
20-16 before the onset of customer choice is provided by nonaffiliated
20-17 retail electric providers.
20-18 (c) An affiliate of the electric utility selling
20-19 entitlements in the auction required by this section shall not be
20-20 allowed to purchase entitlements from the affiliated electric
20-21 utility at the auction. Entitlements may only be purchased by
20-22 entities lawfully able to sell electricity in Texas.
20-23 (d) An electric utility may choose to auction additional
20-24 entitlements beyond those required by Subsection (a) or continue to
20-25 auction entitlements after the period required by Subsection (b) in
20-26 order to comply with Section 39.154.
20-27 (e) The commission shall adopt rules by December 31, 2000,
20-28 that define the scope of the capacity entitlements to be auctioned.
20-29 Entitlements may be auctioned in blocks of less than 15 percent.
20-30 The rules shall state the minimum amount of capacity that can be
20-31 sold at auction as an entitlement. At a minimum, the rules shall
20-32 provide that the entitlements:
20-33 (1) may be sold and purchased in periods of no less
20-34 than one month nor more than four years;
20-35 (2) may be resold to any lawful purchaser, except for
20-36 a retail electric provider affiliated with the electric utility
20-37 that originally auctioned the entitlement;
20-38 (3) include no possessory interest in the unit from
20-39 which the power is produced;
20-40 (4) include no obligations of a possessory owner of an
20-41 interest in the unit from which the power is produced; and
20-42 (5) give the purchaser the right to designate the
20-43 dispatch of the entitlement, subject to planned outages, outages
20-44 beyond the control of the utility operating the unit, and other
20-45 considerations subject to the oversight of the applicable
20-46 independent organization.
20-47 (f) The commission shall adopt rules by December 31, 2000,
20-48 that prescribe the procedure for the auction of the entitlements.
20-49 Such rules shall include:
20-50 (1) a process for conducting the auction or auctions,
20-51 including who shall conduct it, how often it shall be conducted,
20-52 and how winning bidders shall be determined;
20-53 (2) a process for the electric utility to designate
20-54 which generation units or combination of units are offered for
20-56 (3) a provision for the utility to establish an
20-57 opening bid price based upon the electric utility's expected cost,
20-58 with the commission prescribing the means for determining the
20-59 opening bid price, which shall not include return on equity; and
20-60 (4) a provision that allows a bidder to specify the
20-61 magnitude and term of the entitlement, subject to the conditions
20-62 established in Subsection (e).
20-63 (g) In adopting the process under Subsection (f)(2), the
20-64 commission shall consider the furtherance of the development of the
20-65 competitive market, the cost of transmission, physical constraints
20-66 of the transmission system, the proximity of the generation to
20-67 load, economic efficiency, and such other factors as the commission
20-68 finds relevant. The process may provide for commission approval of
20-69 the designation prior to auction. The commission may consult with
21-1 the applicable independent organization to develop the process.
21-2 Sec. 39.154. LIMITATION OF OWNERSHIP OF INSTALLED CAPACITY.
21-3 (a) Beginning on the date of introduction of customer choice, no
21-4 power generation company may own and control more than 20 percent
21-5 of the installed generation capacity located in, or capable of
21-6 delivering electricity to, a qualifying power region, which
21-7 capacity is available for sale to others.
21-8 (b) In a power region not entirely within the state, the
21-9 commission may waive or modify the requirement in Subsection (a)
21-10 upon a finding of good cause.
21-11 (c) In determining the percentage shares of installed
21-12 generation capacity under this section, the commission shall
21-13 combine capacity owned and controlled by a power generation company
21-14 and any entity that is affiliated with that power generation
21-15 company within the power region, reduced by the installed
21-16 generation capacity of those facilities that are made subject to
21-17 capacity entitlements auctions under Sections 39.153(a) and (d).
21-18 Sec. 39.155. COMMISSION ASSESSMENT OF MARKET POWER.
21-19 (a) Each person, municipally owned utility, electric cooperative,
21-20 and river authority that owns generation facilities and offers
21-21 electricity for sale in this state shall report to the commission
21-22 its installed generation capacity, the total amount of capacity
21-23 available for sale to others, the total amount of capacity under
21-24 contract to others, the total amount of capacity dedicated to its
21-25 own use, its annual wholesale power sales in the state, its annual
21-26 retail power sales in the state, and any other information
21-27 necessary for the commission to assess market power or the
21-28 development of a competitive retail market in the state. The
21-29 commission shall by rule prescribe the nature and detail of such
21-30 reporting requirements and shall administer those reporting
21-31 requirements in a manner that ensures the confidentiality of
21-32 competitively sensitive information.
21-33 (b) The ERCOT independent system operator shall submit an
21-34 annual report to the commission identifying existing and potential
21-35 transmission and distribution constraints and system needs within
21-36 ERCOT, alternatives for meeting system needs, and recommendations
21-37 for meeting system needs. The first report shall be submitted on
21-38 or before October 1, 1999. Subsequent reports shall be submitted
21-39 by January 15 of each year or as determined necessary by the
21-41 (c) Before the date of introduction of customer choice in a
21-42 power region other than ERCOT, each electric utility owning
21-43 transmission and distribution facilities in that region shall
21-44 submit an annual report to the commission identifying existing and
21-45 potential transmission and distribution constraints and system
21-46 needs in the power region, alternatives for meeting system needs,
21-47 and recommendations for meeting system needs as directed by the
21-49 (d) After the introduction of customer choice in a
21-50 qualifying power region, the reports required by Subsections (b)
21-51 and (c) shall be submitted by the independent organization or
21-52 organizations having authority over the power region or discrete
21-53 areas thereof.
21-54 Sec. 39.156. MARKET POWER MITIGATION PLAN. (a) In this
21-55 section, "market power mitigation plan" or "plan" means a written
21-56 proposal by an electric utility or a power generation company for
21-57 reducing its ownership and control of installed generation capacity
21-58 as required by Section 39.154.
21-59 (b) An electric utility or power generation company owning
21-60 and controlling more than 20 percent of the generation capacity
21-61 located in, or capable of delivering electricity to, a power region
21-62 shall file a market power mitigation plan with the commission no
21-63 later than December 31, 2000.
21-64 (c) The plan may provide for:
21-65 (1) the sale or exchange of generation assets to or
21-66 with an unaffiliated person;
21-67 (2) the auctioning of generation capacity entitlements
21-68 subject to commission approval under Section 39.153; or
21-69 (3) any reasonable method of mitigation.
22-1 (d) For the purposes of this section, generation capacity
22-2 shall be net of the generation capacity subject to an auction under
22-3 Section 39.153.
22-4 (e) The plan shall be in a form prescribed by the commission
22-5 and shall provide information the commission finds reasonably
22-6 necessary to evaluate the plan.
22-7 (f) The commission shall approve, modify, or reject a plan
22-8 within 180 days after the date of a filing under Subsection (b).
22-9 The commission shall not modify a plan to require divestiture by
22-10 the electric utility or the power generation company.
22-11 (g) In reaching its determination under Subsection (f), the
22-12 commission shall consider:
22-13 (1) the degree to which the electric utility's or
22-14 power generation company's stranded costs, if any, are minimized;
22-15 (2) whether on disposition of the generation assets
22-16 the reasonable value is likely to be received;
22-17 (3) the effect of the plan on the electric utility's
22-18 or power generation company's federal income taxes;
22-19 (4) the effect of the plan on current and potential
22-20 competitors in the generation market; and
22-21 (5) whether the plan is consistent with the public
22-23 (h) An electric utility or power generation company with an
22-24 approved mitigation plan may request to amend or repeal its plan.
22-25 Upon a showing of good cause, the commission shall modify or repeal
22-26 an electric utility's or power generation company's mitigation
22-28 (i) If an electric utility's or a power generation company's
22-29 market power mitigation plan is not approved before January 1 of
22-30 the year it is to take effect, the commission may order the
22-31 electric utility or power generation company to auction generation
22-32 capacity entitlements according to Section 39.153, subject to
22-33 commission approval, of any capacity exceeding the maximum
22-34 allowable capacity prescribed by Section 39.154 until such time a
22-35 mitigation plan is approved.
22-36 (j) An auction under Subsection (i) shall be held no later
22-37 than 60 days after the order is entered.
22-38 Sec. 39.157. COMMISSION AUTHORITY TO ADDRESS MARKET POWER.
22-39 (a) The commission shall monitor market power associated with the
22-40 generation, transmission, distribution, and sale of electricity in
22-41 this state. On a finding, after notice and opportunity for
22-42 hearing, that market power abuses are occurring, the commission
22-43 shall require reasonable mitigation of the market power by ordering
22-44 the construction of additional transmission or distribution
22-45 facilities, by requiring a reduction of generation capacity through
22-46 the auction of generation capacity entitlements, by instituting
22-47 price cap regulation, by setting appropriate restrictions on sales
22-48 of electricity, by establishing limitations on the use of
22-49 generation, transmission, or distribution facilities, or by any
22-50 other reasonable remedy.
22-51 (b) Beginning on the date of introduction of customer
22-52 choice, no person that owns generation facilities may own
22-53 transmission or distribution facilities in this state except for
22-54 those facilities necessary to interconnect a generation facility
22-55 with the transmission or distribution network, a facility not
22-56 dedicated to public use, or a facility otherwise excluded from the
22-57 definition of electric utility under Section 31.002(6). However,
22-58 nothing in this chapter shall prohibit a power generation company
22-59 affiliated with a transmission and distribution utility from owning
22-60 generation facilities.
22-61 (c) The commission shall monitor market shares of installed
22-62 capacity to ensure that the limitations in Section 39.154 are not
22-63 exceeded. If the commission finds, after notice and opportunity
22-64 for hearing, that a person has violated a limitation in Section
22-65 39.154, the commission shall order the person to file, within 60
22-66 days of the date of the order, a market power mitigation plan
22-67 consistent with the requirements in Section 39.156.
22-68 (d) In order to avoid potential market power abuses and
22-69 cross-subsidizations between regulated and unregulated activities,
23-1 the commission shall adopt rules to govern transactions or
23-2 activities between a transmission and distribution utility and its
23-4 (e) The commission shall by rule establish a code of conduct
23-5 that must be observed by all market participants and their
23-6 affiliates to protect against anticompetitive practices.
23-7 (f) To avoid anticompetitive activity in the sale of
23-8 electric generation, the commission shall establish predatory
23-9 pricing safeguards not later than September 1, 2000.
23-10 (g) Beginning on the date of introduction of customer
23-11 choice, and following review of the annual report submitted to it
23-12 under Sections 39.155(b) and (c), the commission shall determine
23-13 whether specific transmission or distribution constraints or
23-14 bottlenecks within this state give rise to market power in specific
23-15 geographic markets in the state. The commission, on a finding that
23-16 specific transmission or distribution constraints or bottlenecks
23-17 within this state give rise to market power, may order reasonable
23-18 mitigation of that potential market power by ordering, pursuant to
23-19 Section 39.203(e), one or more electric utilities or transmission
23-20 and distribution utilities to construct additional transmission or
23-21 distribution capacity, or both, subject to the certification
23-22 provisions of this title.
23-23 Sec. 39.158. MERGERS AND CONSOLIDATIONS. (a) An owner of
23-24 electric generation facilities that offers electricity for sale in
23-25 the state and proposes to merge, consolidate, or otherwise become
23-26 affiliated with another owner of electric generation facilities
23-27 that offers electricity for sale in this state shall obtain the
23-28 approval of the commission prior to closing. Such approval shall
23-29 be requested at least 120 days prior to the proposed closing. The
23-30 commission shall approve the transaction unless the commission
23-31 finds that the transaction results in a violation of Section
23-32 39.154. If the commission finds that the transaction as proposed
23-33 would violate Section 39.154, the commission may condition approval
23-34 of the transaction on adoption of reasonable modifications to the
23-35 transaction as prescribed by the commission to mitigate potential
23-36 market power abuses.
23-37 (b) Nothing in this chapter shall be construed to confer
23-38 immunity from state or federal antitrust laws. This chapter is
23-39 intended to complement other state and federal antitrust
23-40 provisions. Therefore, antitrust remedies may also be sought in
23-41 state or federal court to remedy anticompetitive activities.
23-42 (c) This section shall not be deemed to authorize commission
23-43 review or approval of transactions entered into between or among
23-44 municipally owned utilities, river authorities, special districts
23-45 created by law, or other political subdivisions, whether or not
23-46 such transactions may be characterized as mergers, consolidations,
23-47 or other affiliations, when the transaction is authorized or
23-48 structured pursuant to state law.
23-49 SUBCHAPTER E. PRICE REGULATION AFTER COMPETITION
23-50 Sec. 39.201. COST OF SERVICE TARIFFS AND CHARGES. (a) Each
23-51 electric utility shall, on or before April 1, 2000, file proposed
23-52 tariffs for its proposed transmission and distribution utility.
23-53 (b) The filing under this section shall include supporting
23-54 cost data for determination of nonbypassable delivery charges,
23-55 which shall be the sum of:
23-56 (1) transmission and distribution utility charges by
23-57 customer class based on a forecasted 2002 test year;
23-58 (2) a system benefit fund charge; and
23-59 (3) an expected competition transition charge, if any.
23-60 (c) Each electric utility shall also identify the unbundled
23-61 generation and retail energy service costs by customer class.
23-62 (d) On or before October 1, 2000, and in accordance with a
23-63 schedule and procedures it establishes, the commission shall hold a
23-64 hearing and approve or modify and make effective as of January 1,
23-65 2002, the transmission and distribution utility's proposed tariffs
23-66 for transmission and distribution services, the system benefit fund
23-67 charge, and the expected competition transition charge, if any.
23-68 (e) The system benefit fund charge shall be that established
23-69 by the commission pursuant to Section 39.603.
24-1 (f) The expected competition transition charge shall be that
24-2 as determined under Subsections (g) and (h) and as implemented
24-3 under Subsections (i)-(l).
24-4 (g) The expected competition transition charge approved by
24-5 the commission shall be calculated from the amount of stranded
24-6 costs as defined in Subchapter F which are reasonably projected to
24-7 exist on the last day of the freeze period modified to reflect any
24-8 adjustments determined appropriate by the commission pursuant to
24-9 Section 39.261(c).
24-10 (h) The electric utility shall use the ECOM administrative
24-11 model referenced in Section 39.262(h) to determine estimated
24-12 stranded costs. The model must include updated company-specific
24-13 inputs and updated natural gas price forecasts as determined by the
24-15 (i) An electric utility may:
24-16 (1) at any time after the start of the freeze period,
24-17 securitize 100 percent of its regulatory assets as defined by
24-18 Section 39.251(6) and up to 75 percent of its remaining estimated
24-19 stranded costs as defined by this section and recover such charges
24-20 through a qualified intangible charge, pursuant to a qualified rate
24-21 order issued by the commission under Section 39.303;
24-22 (2) implement, under bond, a nonbypassable charge of
24-23 up to 100 percent of its estimated stranded costs; or
24-24 (3) use a combination of the two methods under
24-25 Subdivisions (1) and (2).
24-26 (j) Any competition transition charge shall be allocated
24-27 among retail customer classes based on the relevant customer class
24-28 characteristics as of May 1, 1999, in accordance with the
24-29 methodology used to allocate the costs of the underlying assets in
24-30 the electric utility's most recent commission order addressing rate
24-31 design, unless the utility has agreed to an alternative allocation
24-32 of stranded costs in a settlement agreed to as part of a transition
24-33 plan approved by the commission on or after January 1, 1998, in
24-34 which case the alternative allocation shall apply.
24-35 (k) In determining the length of time over which costs under
24-36 Subsection (h) may be recovered, the commission shall consider:
24-37 (1) the electric utility's rates as of the end of the
24-38 freeze period;
24-39 (2) the sum of the transmission, distribution, and
24-40 system benefit fund charges;
24-41 (3) the proportion of estimated stranded costs to the
24-42 invested capital of the electric utility; and
24-43 (4) any other factor consistent with the public
24-44 interest as expressed in this chapter.
24-45 (l) Two years after customer choice is introduced in the
24-46 electric utility's power region, the stranded cost estimate under
24-47 this section shall be reviewed and, if necessary, adjusted to
24-48 reflect a final, actual valuation in the true-up proceeding under
24-49 Section 39.262. If, based on that proceeding, the competition
24-50 transition charge is not sufficient, the commission may extend the
24-51 collection period for the charge or, if necessary, increase the
24-52 charge. Alternatively, if it is found in the true-up proceeding
24-53 that the competition transition charge is larger than is needed to
24-54 recover any remaining stranded costs, the commission may:
24-55 (1) reduce the competition transition charge, to the
24-56 extent it has not been securitized;
24-57 (2) reverse, in whole or in part, the depreciation
24-58 expense which has been redirected pursuant to Section 39.256;
24-59 (3) reduce the transmission and distribution utility's
24-60 rates; or
24-61 (4) implement a combination of the elements in
24-62 Subdivisions (1)-(3).
24-63 (m) If the commission determines that a power region will
24-64 not qualify for customer choice under Section 39.152 by January 1,
24-65 2002, it may adjust the filing and implementation dates in this
24-66 section for utilities in that region.
24-67 Sec. 39.202. PRICE TO BEAT. (a) On and after January 1,
24-68 2002, in areas in which customer choice has been introduced, an
24-69 affiliated retail electric provider shall charge residential and
25-1 small commercial customers of its affiliated transmission and
25-2 distribution utility rates which, on a bundled basis, are five
25-3 percent less than the affiliated electric utility's corresponding
25-4 average residential and small commercial rates, on a bundled basis,
25-5 that were in effect on January 1, 1999, adjusted to reflect the
25-6 fuel factor determined as provided by Subsection (b) and adjusted
25-7 for any base rate reduction as stipulated to by an electric utility
25-8 in a proceeding that was pending before the commission on
25-9 January 1, 1999. These rates on a bundled basis shall be known as
25-10 the "price to beat" for residential and small commercial customers.
25-11 (b) For an area where customer choice is to be introduced on
25-12 January 1, 2002, the commission shall determine the fuel factor for
25-13 each electric utility in the area as of December 31, 2001. For an
25-14 area where customer choice is to be introduced subsequent to
25-15 January 1, 2002, the commission shall determine the fuel factor for
25-16 each electric utility in the area on the day prior to the day
25-17 customer choice is introduced.
25-18 (c) Subsequent to the introduction of customer choice, each
25-19 affiliated power generation company shall file a final fuel
25-20 reconciliation for the period ending the day prior to the day
25-21 customer choice is introduced. The final fuel balance from that
25-22 reconciliation shall be included in the true-up proceeding pursuant
25-23 to Section 39.262.
25-24 (d) An affiliated retail electric provider shall make public
25-25 its price to beat in a manner that provides adequate disclosure as
25-26 determined by the commission.
25-27 (e) The affiliated retail electric provider may not charge
25-28 rates that are different from the price to beat until the earlier
25-29 of 60 months after the date customer choice is introduced in the
25-30 power region or the date the commission determines that 40 percent
25-31 or more of the electric power consumed by residential and small
25-32 commercial customers within the affiliated transmission and
25-33 distribution utility's certificated service area before the onset
25-34 of customer choice is provided by nonaffiliated retail electric
25-36 (f) The commission shall establish procedures and reporting
25-37 requirements as necessary to monitor residential and small
25-38 commercial consumption in the transmission and distribution
25-39 utility's certificated service area for the purpose of determining
25-40 the duration of the continuation of the price to beat.
25-41 (g) The commission shall notify an affiliated retail
25-42 electric provider at such time as the commission determines that
25-43 the price to beat no longer applies to the retail electric
25-45 (h) Following the true-up proceedings conducted pursuant to
25-46 Section 39.262, the commission may adjust the price to beat
25-47 consistent with the results of that proceeding.
25-48 (i) An affiliated retail electric provider may request that
25-49 the commission adjust the fuel factor established under Subsection
25-50 (b) up to twice a year if the affiliated retail electric provider
25-51 demonstrates that the existing fuel factor does not adequately
25-52 reflect significant changes in the market price of natural gas and
25-53 purchased energy used to serve retail customers.
25-54 (j) In this section, "small commercial customer" means a
25-55 commercial customer having a peak demand of 1,000 kilowatts or
25-57 (k) Upon finding that a retail electric provider will be
25-58 unable to maintain its financial integrity if it complies with
25-59 Subsection (a), the commission shall set the retail electric
25-60 provider's price to beat at the minimum level that will allow the
25-61 retail electric provider to maintain its financial integrity.
25-62 However, in no event shall the price to beat exceed the level of
25-63 rates, on a bundled basis, charged by the affiliated electric
25-64 utility on September 1, 1999, adjusted for fuel as provided in
25-65 Subsection (b).
25-66 Sec. 39.203. TRANSMISSION AND DISTRIBUTION SERVICE.
25-67 (a) All transmission and distribution utilities shall provide
25-68 transmission service at wholesale under Subchapter A, Chapter 35.
25-69 In addition, on and after January 1, 2002, a transmission and
26-1 distribution utility shall provide transmission or distribution
26-2 service, or both, at retail to an electric utility, a retail
26-3 electric provider, a municipally owned utility, an electric
26-4 cooperative, or an end-use customer at rates, terms of access, and
26-5 conditions that are comparable to those that apply to the
26-6 transmission and distribution utility and its affiliates. A
26-7 municipally owned utility offering customer choice or an electric
26-8 cooperative offering customer choice shall likewise provide
26-9 transmission or distribution service, or both, at retail to all
26-10 such entities pursuant to the commission's rules applicable to
26-11 terms and conditions of access and at rates adopted in accordance
26-12 with Sections 40.055(a)(1) and 41.055(1), respectively.
26-13 (b) When necessary to serve a wholesale customer an electric
26-14 utility, an electric cooperative that has not opted for customer
26-15 choice, or a municipally owned utility that has not opted for
26-16 customer choice shall provide wholesale transmission service at
26-17 distribution voltage.
26-18 (c) On or before January 1, 2002, the commission shall
26-19 establish for all retail electric utilities offering customer
26-20 choice reasonable and comparable terms and conditions, pursuant to
26-21 Section 39.201, that comply with Subsection (a) for open access on
26-22 distribution facilities and shall establish, for all retail
26-23 electric utilities offering customer choice other than municipally
26-24 owned utilities and electric cooperatives, reasonable and
26-25 comparable rates for open access on distribution facilities.
26-26 (d) The terms of access, conditions, and rates established
26-27 under Subsection (c) shall be comparable to the terms of access,
26-28 conditions, and rates that the electric utility applies to itself
26-29 or its affiliates. The rules shall also provide that all ancillary
26-30 services provided by the utility to itself or its affiliates are
26-31 also available to third parties on request on a nondiscriminatory
26-33 (e) The commission may require an electric utility or a
26-34 transmission and distribution utility to construct or enlarge
26-35 facilities to ensure safe and reliable service for the state's
26-36 electric markets. In any proceeding brought pursuant to Chapter
26-37 37, an electric utility or transmission and distribution utility
26-38 ordered to construct or enlarge facilities pursuant to this
26-39 subchapter need not prove that the construction ordered is
26-40 necessary for the service, accommodation, convenience, or safety of
26-41 the public and need not address the factors listed in Section
26-42 37.056(c)(1)-(3) and (4)(E).
26-43 (f) The commission's rules must be consistent with the
26-44 standards of this title and may not be contrary to an applicable
26-45 decision, rule, or policy statement of a federal regulatory agency
26-46 having jurisdiction.
26-47 (g) Each qualifying power region shall have generally
26-48 applicable tariffs approved by the commission or a federal
26-49 regulatory agency having jurisdiction that guarantees open and
26-50 nondiscriminatory access as required by Section 39.152. This
26-51 subsection shall not be deemed to vest in the commission power to
26-52 set or approve distribution access rates of a municipally owned
26-53 utility or an electric cooperative that has adopted customer
26-55 Sec. 39.204. TARIFFS FOR OPEN ACCESS. Each transmission and
26-56 distribution utility shall file a tariff implementing the open
26-57 access rules with the commission or the federal regulatory
26-58 authority having jurisdiction over the transmission and
26-59 distribution service of the utility not later than the 90th day
26-60 before the date customer choice is offered by that utility.
26-61 Sec. 39.205. REGULATION OF COSTS FOLLOWING THE FREEZE
26-62 PERIOD. At the conclusion of the freeze period, any remaining
26-63 costs associated with nuclear decommissioning obligations continue
26-64 to be subject to cost of service rate regulation and shall be
26-65 included as a nonbypassable charge to retail customers.
26-66 SUBCHAPTER F. RECOVERY OF STRANDED COSTS
26-67 Sec. 39.251. DEFINITIONS. In this subchapter:
26-68 (1) "Above market purchased power costs" means
26-69 wholesale demand and energy costs that a utility is obligated to
27-1 pay under an existing purchased power contract to the extent the
27-2 costs are greater than the purchased power market value.
27-3 (2) "Existing purchased power contract" means a
27-4 purchased power contract in effect on January 1, 1999, including
27-5 any amendments and revisions to such contracts resulting from
27-6 litigation initiated prior to January 1, 1999.
27-7 (3) "Generation assets" means all assets associated
27-8 with the production of electricity, including generation plants,
27-9 electrical interconnections of the generation plant to the
27-10 transmission system, fuel contracts, fuel transportation contracts,
27-11 water contracts, lands, surface or subsurface water rights,
27-12 emissions-related allowances, gas pipeline interconnections, and
27-13 generation-related regulatory assets.
27-14 (4) "Market value" means, for nonnuclear assets and
27-15 certain nuclear assets, the value the assets would have if bought
27-16 and sold in a bona fide third-party transaction or transactions on
27-17 the open market under Section 39.262(g) or, for certain nuclear
27-18 assets, as described by Section 39.262(h), the value determined
27-19 under the method provided by that subsection.
27-20 (5) "Purchased power market value" means the value of
27-21 demand and energy bought and sold in a bona fide third-party
27-22 transaction or transactions on the open market and determined by
27-23 using the weighted average costs of the highest three offers from
27-24 the market for purchase of the demand and energy available under
27-25 the existing purchased power contracts.
27-26 (6) "Regulatory assets" means costs that have been
27-27 deferred for future recovery as a result of an order by a
27-28 regulatory authority as of September 1, 1999, offset by the
27-29 applicable portion of investment tax credits permitted under the
27-30 Internal Revenue Code of 1986, including:
27-31 (A) unrecovered deferred income taxes recorded
27-32 under Statement of Financial Accounting Standards No. 109
27-33 ("Accounting for Income Taxes");
27-34 (B) plant accounting deferrals, including mirror
27-35 construction work in progress; and
27-36 (C) costs associated with reacquisition of
27-37 securities, canceled plants, litigation and settlement costs, and
27-38 voluntary retirement and severance programs.
27-39 (7) "Retail stranded costs" means that part of net
27-40 stranded cost associated with the provision of retail service.
27-41 (8) "Stranded cost" means the positive excess of the
27-42 net book value of generation assets over the market value of the
27-43 assets, taking into account all of the electric utility's
27-44 generation assets, and any above market purchased power costs.
27-45 Sec. 39.252. RIGHT TO RECOVER STRANDED COSTS. (a) An
27-46 electric utility is allowed to recover all of its net, verifiable,
27-47 nonmitigable stranded costs incurred in purchasing power and
27-48 providing electric generation service.
27-49 (b) Recovery of retail stranded costs by an electric utility
27-50 shall be from all existing or future retail customers, including
27-51 the facilities, premises, and loads of such retail customers,
27-52 within the utility's geographical certificated service area as it
27-53 existed on May 1, 1999.
27-54 (c) In multiply certificated areas, a retail customer may
27-55 not avoid stranded cost recovery charges by switching to another
27-56 electric utility, electric cooperative, or municipally owned
27-57 utility after May 1, 1999. A customer in a multiply certificated
27-58 service area that requested to switch providers on or before May 1,
27-59 1999, or was not taking service from an electric utility on May 1,
27-60 1999, and does not do so after that date is not responsible for
27-61 paying retail stranded costs of that utility.
27-62 Sec. 39.253. ALLOCATION OF STRANDED COSTS. Retail stranded
27-63 costs shall be allocated among retail customer classes, based on
27-64 the relevant customer class characteristics as of May 1, 1999, in
27-65 accordance with the methodology used to allocate the costs of the
27-66 underlying assets in the electric utility's most recent commission
27-67 order addressing rate design, unless the utility has agreed to an
27-68 alternative allocation of stranded costs in a settlement agreed to
27-69 as part of a transition plan approved by the commission on or after
28-1 January 1, 1998, in which case the alternative allocation shall
28-3 Sec. 39.254. USE OF REVENUES FOR UTILITIES WITH STRANDED
28-4 COSTS. This subchapter provides a number of tools to an electric
28-5 utility to mitigate stranded costs. Each electric utility that was
28-6 reported by the commission to have positive "excess costs over
28-7 market" (ECOM), denoted as the "base case" for the amount of
28-8 stranded costs before full retail competition in 2001 with respect
28-9 to its Texas jurisdiction, in the April 1998 Report to the Texas
28-10 Senate Interim Committee on Electric Utility Restructuring entitled
28-11 "Potentially Strandable Investment (ECOM) Report: 1998 Update,"
28-12 must use these tools to reduce the net book value of, otherwise
28-13 referred to as "accelerate" the cost recovery of, its stranded
28-14 costs each year. Any positive difference under the report required
28-15 by Section 39.257(b) shall be applied to the net book value of
28-16 generation assets.
28-17 Sec. 39.255. USE OF REVENUES FOR UTILITIES WITH NO STRANDED
28-18 COSTS. (a) An electric utility that does not have stranded costs
28-19 described by Section 39.254 shall be permitted to use any positive
28-20 difference under the report required by Section 39.257(b) on
28-21 capital expenditures to improve or expand transmission or
28-22 distribution facilities, or on capital expenditures to improve air
28-23 quality, as approved by the commission. Any such capital
28-24 expenditures shall be made in the calendar year immediately
28-25 following the year for which the report required by Section 39.257
28-26 is calculated. Such capital expenditures shall be reflected in any
28-27 future proceeding under this chapter to set transmission or
28-28 distribution rates as a reduction to the utility's transmission and
28-29 distribution invested capital, as approved by the commission.
28-30 (b) To the extent that positive differences under the report
28-31 required by Section 39.257(b) are not used for such capital
28-32 expenditures, such amounts shall be flowed back to the electric
28-33 utility's Texas jurisdictional customers through the power cost
28-34 recovery factor.
28-35 (c) This section applies only to the use of positive
28-36 differences under the report required by Section 39.257(b) for each
28-37 year during the freeze period.
28-38 Sec. 39.256. OPTION TO REDIRECT DEPRECIATION. (a) During
28-39 the freeze period, an electric utility described in Section 39.254
28-40 may redirect all or a part of the depreciation expense relating to
28-41 transmission and distribution assets to its net generation plant
28-43 (b) The electric utility shall report a decision under
28-44 Subsection (a) to the commission and any other applicable
28-45 regulatory authority.
28-46 (c) Any adjustments made to the book value of transmission
28-47 and distribution assets or the creation of any related regulatory
28-48 assets resulting from the redirection under this section shall be
28-49 accepted and applied by the commission for establishing net
28-50 invested capital and transmission and distribution rates for retail
28-51 customers in all future proceedings.
28-52 (d) Notwithstanding the provisions of Subsection (c), the
28-53 design of post-freeze-period retail rates may not:
28-54 (1) shift the allocation of responsibility for
28-55 stranded costs;
28-56 (2) include the adjusted costs in wholesale
28-57 transmission and distribution rates; or
28-58 (3) apply the adjustments for the purpose of
28-59 establishing net invested capital and transmission and distribution
28-60 rates for wholesale customers.
28-61 Sec. 39.257. ANNUAL REPORT. (a) Beginning with the 1999
28-62 calendar year, each electric utility shall file a report with the
28-63 commission no later than 90 days after the end of each year during
28-64 the freeze period under a schedule and a format determined by the
28-66 (b) The report shall identify any positive difference
28-67 between annual revenues, reduced by the amount of annual revenues
28-68 under Sections 36.203 and 36.205 and the revenues received under
28-69 the interutility billing process as adopted by the commission to
29-1 implement Sections 35.004, 35.006, and 35.007, and annual costs.
29-2 Sec. 39.258. ANNUAL REPORT: DETERMINATION OF ANNUAL COSTS.
29-3 For the purposes of determining the annual costs in each annual
29-4 report, the following amounts shall be used:
29-5 (1) the Texas jurisdictional operation and maintenance
29-6 expense reflected in each utility's 1996 Federal Energy Regulatory
29-7 Commission Form 1, plus factoring expenses not included in
29-8 operation and maintenance, adjusted for:
29-9 (A) costs under Sections 36.062, 36.203, and
29-10 36.205, and not indexed for inflation or load growth; and
29-11 (B) any difference between the annual revenues
29-12 and the expenses recorded under the interutility billing process
29-13 adopted by the commission to implement Sections 35.004, 35.006, and
29-15 (2) the amount of nuclear decommissioning expense
29-16 approved in the electric utility's last rate proceeding before the
29-17 commission, as may be required to be adjusted to comply with
29-18 applicable federal regulatory requirements;
29-19 (3) the depreciation rates approved in the electric
29-20 utility's last rate proceeding before the commission;
29-21 (4) the amortization expense approved in the electric
29-22 utility's last rate proceeding before the commission, except that
29-23 if the items are fully amortized during the freeze period, the
29-24 expense shall be adjusted accordingly;
29-25 (5) taxes and fees, including municipal franchise fees
29-26 to the extent not included in Subdivision (1), other than federal
29-27 income taxes, and assessments incurred that year;
29-28 (6) federal income tax expense, computed according to
29-29 the stand-alone methodology and using the actual capital structure
29-30 and actual cost of debt as of December 31 of the report year;
29-31 (7) return on invested capital, computed by
29-32 multiplying invested capital as of December 31 of the report year,
29-33 determined as provided by Section 39.259, by the cost of capital
29-34 approved in the electric utility's most recent rate proceeding
29-35 before the commission in which the cost of capital was specifically
29-36 adopted, or, in the case of a range, the midpoint of the range, if
29-37 the final rate order for the proceeding was issued on or after
29-38 January 1, 1992. If such an order does not exist, a cost of
29-39 capital of 9.6 percent shall be used; and
29-40 (8) the amount resulting from any operation and
29-41 maintenance expense savings tracker from a merger of two utilities
29-42 and contained in a settlement agreement approved by the commission
29-43 prior to January 1, 1999.
29-44 Sec. 39.259. ANNUAL REPORT: DETERMINATION OF INVESTED
29-45 CAPITAL. (a) For the purposes of determining invested capital in
29-46 each annual report, the net plant in service, regulatory assets,
29-47 and deferred federal income taxes shall be updated each year, and
29-48 generation-related invested capital shall be reduced by the amount
29-49 of securitization under Section 39.201(i) and 39.262(c) to the
29-50 extent otherwise included in invested capital.
29-51 (b) Capital additions to a plant in an amount less than
29-52 1-1/2 percent of the electric utility's net plant in service on
29-53 December 31, 1998, less plant items previously excluded by the
29-54 commission, for each of the years 1999 through 2001 are presumed
29-56 (c) All other items in invested capital shall be as approved
29-57 in the electric utility's last rate proceeding before the
29-59 Sec. 39.260. USE OF GENERALLY ACCEPTED ACCOUNTING
29-60 PRINCIPLES. (a) The definition and identification of invested
29-61 capital and other terms used in this subchapter that affect the net
29-62 book value of generation assets and the treatment of transactions
29-63 performed under Section 35.035 and other transactions authorized by
29-64 this title or approved by the regulatory authority that affect the
29-65 net book value of generation assets during the freeze period shall
29-66 be treated in accordance with generally accepted accounting
29-67 principles as modified by regulatory accounting rules generally
29-68 applicable to utilities.
29-69 (b) The principles and criteria described by Subsection (a),
30-1 including the criteria for applicability of Statement of Financial
30-2 Accounting Standards No. 71 ("Accounting for the Effects of Certain
30-3 Types of Regulation"), shall be applied for purposes of this
30-4 subchapter as they existed on January 1, 1999.
30-5 Sec. 39.261. REVIEW OF ANNUAL REPORT. (a) The annual
30-6 report filed under this subchapter is a public document and shall
30-7 be reviewed by the staff of the commission and the office of public
30-8 utility counsel. Both staffs may review work papers and supporting
30-9 documents and engage in discussions with the utility about the data
30-10 underlying the reports.
30-11 (b) The staff of the commission and the office of public
30-12 utility counsel shall communicate in writing to an electric utility
30-13 not later than the 180th day after the date the report is filed if
30-14 they have any disagreements with the data or computations.
30-15 (c) The commission shall finalize and resolve any
30-16 disagreements related to the annual report as follows:
30-17 (1) for each calendar year, the commission shall
30-18 finalize the annual report prior to establishing the competition
30-19 transition charge pursuant to Section 39.201; and
30-20 (2) for each calendar year, the commission shall
30-21 finalize the annual report and reflect the result as part of the
30-22 true-up proceeding pursuant to Section 39.262.
30-23 Sec. 39.262. TRUE-UP PROCEEDING. (a) An electric utility,
30-24 together with its affiliated retail electric provider and its
30-25 affiliated transmission and distribution utility, may not be
30-26 permitted to overrecover stranded costs through the procedures
30-27 established by this section or through the application of the
30-28 measures provided by the other sections of this subchapter.
30-29 (b) After the freeze period, an electric utility located in
30-30 a power region not subject to competition pursuant to Section
30-31 39.152 shall continue to file annual reports pursuant to Sections
30-32 39.257, 39.258, and 39.259 as if the freeze period remained in
30-33 effect, until such time as the power region qualifies for
30-34 competition under Section 39.152. In addition, the commission
30-35 staff and the office of public utility counsel shall continue to
30-36 review the annual reports as provided by Section 39.261.
30-37 (c) After January 1, 2004, or after two years following the
30-38 beginning of competition in a power region, whichever is later, at
30-39 a schedule and under procedures to be determined by the commission,
30-40 each transmission and distribution utility, its affiliated retail
30-41 electric provider, and its affiliated power generation company
30-42 shall jointly file to finalize stranded costs pursuant to
30-43 Subsections (g) and (h) and reconcile those costs with the
30-44 estimated stranded costs used to develop the competition transition
30-45 charge in the proceeding held under Section 39.201. Any resulting
30-46 difference shall be applied to the nonbypassable delivery rates of
30-47 the transmission and distribution utility, except that at the
30-48 utility's option, any or all of the remaining stranded costs may be
30-49 securitized pursuant to Subchapter G.
30-50 (d) The affiliated power generation company shall reconcile,
30-51 and either credit or bill to the transmission and distribution
30-52 utility, the net sum of:
30-53 (1) the former electric utility's final fuel balance
30-54 determined pursuant to Section 39.202(c); and
30-55 (2) any difference between the price of power obtained
30-56 through the capacity auctions under Sections 39.153 and 39.156 and
30-57 the power cost projections which were employed for the same time
30-58 period in the ECOM model to estimate stranded costs in the
30-59 proceeding under Section 39.201.
30-60 (e) To the extent that the price to beat exceeded the market
30-61 price of electricity, the affiliated retail electric provider shall
30-62 reconcile and credit to the affiliated transmission and
30-63 distribution utility any positive difference between the price to
30-64 beat established under Section 39.202, reduced by the nonbypassable
30-65 delivery charge established under Section 39.201, and the
30-66 prevailing market price of electricity during the same time period;
30-67 provided, however, that no such reconciliation shall be required
30-68 under this subsection of any affiliated retail electric provider
30-69 that satisfies the requirements of Section 39.202(e) prior to the
31-1 expiration of two years from the introduction of customer choice in
31-2 the applicable power region. In no event shall the amount credited
31-3 exceed 50 percent of the net income reported by the affiliated
31-4 retail electric provider in its annual report to the Securities and
31-5 Exchange Commission on Form 10-K.
31-6 (f) Based on the credits or bills received from its
31-7 affiliates pursuant to Subsections (d) and (e), the transmission
31-8 and distribution utility shall make necessary adjustments to the
31-9 nonbypassable delivery rates it charges to retail electric
31-10 providers. If the commission determines that the nonbypassable
31-11 delivery rates are not sufficient, the commission may extend the
31-12 original collection period for the charge or, if necessary,
31-13 increase the charge. Alternatively, if the commission determines
31-14 that the nonbypassable delivery rates are larger than are needed to
31-15 recover the transmission and distribution utility's costs, the
31-16 commission shall correspondingly reduce:
31-17 (1) the competition transition charge, to the extent
31-18 it has not been securitized;
31-19 (2) the depreciation expense which has been redirected
31-20 pursuant to Section 39.256;
31-21 (3) the transmission and distribution utility's rates;
31-23 (4) a combination of the elements in Subdivisions
31-25 (g) For the purpose of finalizing the stranded cost estimate
31-26 used to establish the competition transition charge under Section
31-27 39.201, and, except as provided in Subsection (h), the affiliated
31-28 power generation company shall quantify its stranded costs using
31-29 one or more of the following methods:
31-30 (1) Sale of Assets. If, at any time after December
31-31 31, 1999, an electric utility or its affiliated power generation
31-32 company has sold some or all of its generation assets, which sale
31-33 shall include all generating assets associated with each generating
31-34 plant that is sold, in a bona fide third-party transaction under a
31-35 competitive offering, the total net value realized from the sale
31-36 establishes the market value of the generation assets sold. If not
31-37 all assets are sold, the market value of the remaining generation
31-38 assets shall be established by one or more of the other methods in
31-39 this section.
31-40 (2) Stock Valuation Method. If, at any time after
31-41 December 31, 1999, an electric utility or its affiliated power
31-42 generation company has transferred some or all of its generation
31-43 assets, including, at the election of the electric utility or power
31-44 generation company, any fuel and fuel transportation contracts
31-45 related to those assets, to one or more separate affiliated or
31-46 nonaffiliated corporations, not less than 51 percent of the common
31-47 stock of each corporation is spun off and sold to public investors
31-48 through a national stock exchange, and the common stock has been
31-49 traded for not less than one year, the resulting average daily
31-50 closing price of the common stock over 30 consecutive trading days
31-51 chosen by the commission out of the last 120 consecutive trading
31-52 days before the filing required under Subsection (c) establishes
31-53 the market value of the common stock equity in each transferee
31-54 corporation. The book value of each transferee corporation's debt
31-55 and preferred stock securities shall be added to the market value
31-56 of its assets. The market value of each transferee corporation's
31-57 assets shall be reduced by the corresponding net book value of the
31-58 assets acquired by each transferee corporation from any entity
31-59 other than the affiliated electric utility or power generation
31-60 company. The resulting market value of the assets establishes the
31-61 market value of the generation assets transferred by the electric
31-62 utility or power generation company to each separate corporation.
31-63 If not all assets are disposed of in this manner, the market value
31-64 of the remaining assets shall be established by one or more of the
31-65 other methods in this section.
31-66 (3) Partial Stock Valuation Method. If, at any time
31-67 after December 31, 1999, an electric utility or its affiliated
31-68 power generation company has transferred some or all of its
31-69 generation assets, including, at the election of the electric
32-1 utility or power generation company, any fuel and fuel
32-2 transportation contracts related to those assets, to one or more
32-3 separate affiliated or nonaffiliated corporations, at least 19
32-4 percent, but less than 51 percent, of the common stock of each
32-5 corporation is spun off and sold to public investors through a
32-6 national stock exchange, and the common stock has been traded for
32-7 not less than one year, the resulting average daily closing price
32-8 of the common stock over 30 consecutive trading days chosen by the
32-9 commission out of the last 120 consecutive trading days before the
32-10 filing required under Subsection (c) shall be presumed to establish
32-11 the market value of the common stock equity in each transferee
32-12 corporation. The commission may accept the market valuation to
32-13 conclusively establish the value of the common stock equity in each
32-14 transferee corporation or convene a valuation panel of three
32-15 independent financial experts to determine whether the percentage
32-16 of common stock sold is fairly representative of the total common
32-17 stock equity or whether a control premium exists for the retained
32-18 interest. The valuation panel must consist of financial experts,
32-19 chosen from proposals submitted in response to commission requests,
32-20 from the top 10 nationally recognized investment banks with
32-21 demonstrated experience in the United States electric industry as
32-22 indicated by the dollar amount of public offerings of long-term
32-23 debt and equity of United States investor-owned electric companies
32-24 over the immediately preceding three years as ranked by the
32-25 publications "Securities Data" or "Institutional Investor." If the
32-26 panel determines that a control premium exists for the retained
32-27 interest, the panel shall determine the amount of the control
32-28 premium, and the commission shall adopt the determination but may
32-29 not increase the market value by a control premium greater than 10
32-30 percent. The costs and expenses of the panel, as approved by the
32-31 commission, shall be paid by each transferee corporation. The
32-32 determination of the commission based on the finding of the panel
32-33 conclusively establishes the value of the common stock of each
32-34 transferee corporation. The book value of each transferee
32-35 corporation's debt and preferred stock securities shall be added to
32-36 the market value of its assets. The market value of each
32-37 transferee corporation's assets shall be reduced by the
32-38 corresponding net book value of the assets acquired by each
32-39 transferee corporation from any entity other than the affiliated
32-40 electric utility or power generation company. The resulting market
32-41 value of the assets establishes the market value of the generation
32-42 assets transferred by the electric utility or power generation
32-43 company to each separate corporation.
32-44 (h) Unless an electric utility or its affiliated power
32-45 generation company combines all of its generation assets into one
32-46 or more transferee corporations as described in Subsections (g)(2)
32-47 and (3), the electric utility shall quantify its stranded costs for
32-48 nuclear assets using the ECOM method. The ECOM method is the
32-49 estimation model prepared for and described by the commission's
32-50 April 1998 Report to the Texas Senate Interim Committee on Electric
32-51 Restructuring entitled "Potentially Strandable Investment (ECOM)
32-52 Report: 1998 Update." The methodology used in the model must be
32-53 the same as that used in the 1998 report to determine the "base
32-54 case." At the time of the proceeding under this section, the ECOM
32-55 model shall be rerun using updated company-specific inputs required
32-56 by the model, updating the market price of electricity, and using
32-57 updated natural gas price forecasts and the capacity cost based on
32-58 the long-run marginal cost of the most economic new generation
32-59 technology then available. Natural gas price projections used in
32-60 the model must be based on the most credible publicly available
32-61 market-based data. The commission by rule shall establish, before
32-62 June 1, 2000, the precise methodology to be used by the commission
32-63 in updating natural gas forecasts.
32-64 (i) The commission shall conduct the hearing in this case as
32-65 a contested case.
32-66 (j) The commission shall issue a final order not later than
32-67 the 150th day after the date of the filing under this section by
32-68 the transmission and distribution utility, its affiliated retail
32-69 electric provider, and its affiliated power generation company, and
33-1 the resulting order shall be subject to judicial review under
33-2 Chapter 2001, Government Code.
33-3 (k) Notwithstanding Section 39.252, to the extent that a
33-4 customer's actual load has been lawfully served by a fully
33-5 operational qualifying facility before September 1, 2001, or by an
33-6 on-site power production facility with a rated capacity of 10
33-7 megawatts or less, any charge for recovery of stranded costs under
33-8 this section or Subchapter G assessed on that customer after the
33-9 facility becomes fully operational shall be included only in those
33-10 tariffs or charges associated with the services actually provided
33-11 by the transmission and distribution utility, if any, to the
33-12 customer after the facility became fully operational and may not
33-13 include any costs associated with the service provided to the
33-14 customer by the electric utility or its affiliated transmission and
33-15 distribution utility under their tariffs before the operation of
33-16 that qualifying facility. To qualify under this subsection, a
33-17 qualifying facility must have made substantially complete filings
33-18 on or before December 31, 1999, for all necessary site-specific
33-19 environmental permits under the rules of the Texas Natural Resource
33-20 Conservation Commission in effect at the time of filing.
33-21 Sec. 39.263. STRANDED COST RECOVERY OF ENVIRONMENTAL CLEANUP
33-22 COSTS. (a) Subject to the provisions of Subsection (c), capital
33-23 costs incurred by an electric utility to improve air quality prior
33-24 to January 1, 2002, are eligible for inclusion as net invested
33-25 capital under Section 39.259, notwithstanding the limitations
33-26 imposed under Sections 39.259(b) and (c).
33-27 (b) Subject to the provisions of Subsection (c), capital
33-28 costs incurred by an electric utility to improve air quality
33-29 subsequent to January 1, 2002, and prior to May 1, 2003, are
33-30 eligible for inclusion in the determination of invested capital in
33-31 the true-up proceeding under Section 39.262.
33-32 (c) Costs incurred under Subsections (a) and (b) shall be
33-33 included as invested capital and considered in an electric
33-34 utility's stranded cost determination only to the extent that:
33-35 (1) the cost is applied to offset or reduce the
33-36 emission of airborne contaminants from an electric generating
33-37 facility, where:
33-38 (A) the reduction or offset is determined by the
33-39 Texas Natural Resource Conservation Commission to be an essential
33-40 component in achieving compliance with a national ambient air
33-41 quality standard; or
33-42 (B) the reduction or offset is necessary in
33-43 order for an unpermitted electric generating facility to obtain a
33-45 (2) the retrofit decision is determined to be the most
33-46 cost-effective after consideration of alternative measures,
33-47 including the retirement of the generating facility;
33-48 (3) the amount and location of resulting emission
33-49 reductions is consistent with the air quality goals and policies of
33-50 the Texas Natural Resource Conservation Commission; and
33-51 (4) resulting emission reduction credits are conveyed
33-52 to the state for inclusion in the state implementation plan.
33-53 (d) If the retirement of a generating facility is the most
33-54 cost-effective alternative, the net book value, including
33-55 retirement costs and offsetting salvage value, of the affected
33-56 facility shall be included in the electric utility's stranded cost
33-57 determination if the electric utility complies with Subsection
33-58 (c)(4), notwithstanding the provisions of Section 39.259(c).
33-59 (e) Not later than November 15, 2000, the commission and the
33-60 Texas Natural Resource Conservation Commission shall submit a joint
33-61 report to the governor, the lieutenant governor, the speaker of the
33-62 house of representatives, and the electric utility restructuring
33-63 legislative oversight committee as created in Section 39.607. The
33-64 report shall include:
33-65 (1) an update on the scope of and the actual and
33-66 estimated capital costs authorized by this section;
33-67 (2) the feasibility of an emission reduction credit
33-68 and trading program and the implementation of emission performance
33-69 standards for fossil fuel generation facilities;
34-1 (3) the feasibility of allowing the Texas Natural
34-2 Resource Conservation Commission to sell or auction the emission
34-3 reduction credits conveyed to the state under Subsection (c)(4) in
34-4 order to encourage the investment of new and efficient generation
34-5 technology in Texas, and the impact of using the proceeds to
34-6 encourage renewable technology development in Texas; and
34-7 (4) the feasibility of implementing additional
34-8 programs that would encourage the reduction of emissions from
34-9 electric generating facilities in a way that is competitively
34-11 Sec. 39.264. RIGHTS NOT AFFECTED. This chapter is not
34-12 intended to alter any rights of utilities to recover stranded costs
34-13 from wholesale customers.
34-14 SUBCHAPTER G. SECURITIZATION
34-15 Sec. 39.301. PURPOSE. The purpose of this subchapter is to
34-16 enable utilities to use securitization financing to recover
34-17 stranded costs, because this type of debt will lower the carrying
34-18 costs of the assets relative to the costs that would be incurred
34-19 using conventional utility financing methods.
34-20 Sec. 39.302. DEFINITIONS. In this subchapter:
34-21 (1) "Assignee" means any individual, corporation, or
34-22 other legally recognized entity to which an interest in transition
34-23 property is transferred, other than as security, including any
34-24 assignee of such party.
34-25 (2) "Financing order" means an order of the commission
34-26 adopted pursuant to Section 39.252 or 39.262 approving the issuance
34-27 of transition bonds and the creation of transition charges for the
34-28 recovery of qualified costs.
34-29 (3) "Financing party" means a holder of transition
34-30 bonds, including trustees, collateral agents, and other persons
34-31 acting for the benefit of such holder.
34-32 (4) "Qualified costs" means 100 percent of an electric
34-33 utility's regulatory assets and 75 percent of its remaining
34-34 recoverable costs determined by the commission pursuant to Section
34-35 39.252 and any remaining stranded costs determined pursuant to
34-36 Section 39.262 together with the costs of issuing, supporting, and
34-37 servicing transition bonds and any costs of retiring and refunding
34-38 the electric utility's existing debt and equity securities in
34-39 connection with the issuance of transition bonds. The term
34-40 includes the costs to the commission of acquiring professional
34-41 services for the purpose of evaluating proposed transactions
34-42 pursuant to Section 39.201 and this subchapter.
34-43 (5) "Transition bonds" means bonds, debentures, notes,
34-44 certificates of participation or of beneficial interest, or other
34-45 evidences of indebtedness or ownership that are issued by an
34-46 electric utility, its successors, or an assignee under a financing
34-47 order, that have a term no longer than 15 years, and that are
34-48 secured by or payable from transition property. If certificates of
34-49 participation, beneficial interest, or ownership are issued,
34-50 references in this subchapter to principal, interest, or premium
34-51 shall refer to comparable amounts under those certificates.
34-52 (6) "Transition charges" means nonbypassable amounts
34-53 to be charged for the use or availability of electric services,
34-54 approved by the commission pursuant to a financing order to recover
34-55 qualified costs, which shall be collected by an electric utility,
34-56 its successors, an assignee, or other collection agents as provided
34-57 for in the financing order.
34-58 (7) "Transition property" means the property described
34-59 in Section 39.304.
34-60 Sec. 39.303. FINANCING ORDERS; TERMS. (a) The commission
34-61 shall adopt a financing order, on application of a utility to
34-62 recover the utility's eligible stranded costs under Section 39.252
34-63 or 39.262, upon making a finding that the total amount of revenues
34-64 to be collected pursuant to the financing order is less than the
34-65 revenue requirement that would be recovered over the remaining life
34-66 of the stranded costs using conventional financing methods.
34-67 (b) The financing order shall detail the amount of stranded
34-68 costs to be recovered and the period over which the nonbypassable
34-69 transition charges shall be recovered, which period shall not
35-1 exceed 15 years.
35-2 (c) Transition charges shall be collected and allocated
35-3 among customers in the same manner as transition charges pursuant
35-4 to Section 39.201.
35-5 (d) A financing order shall become effective in accordance
35-6 with its terms, and the financing order, together with the
35-7 transition charges authorized in the order, shall thereafter be
35-8 irrevocable and not subject to reduction, impairment, or adjustment
35-9 by further action of the commission, except as permitted by Section
35-11 (e) The commission shall issue a financing order pursuant to
35-12 Subsections (a) and (g) no later than 90 days after the utility
35-13 files its request for the financing order.
35-14 (f) A financing order shall not be subject to rehearing by
35-15 the commission. A financing order may be reviewed by appeal only
35-16 to a Travis County district court by a party to the proceeding
35-17 filed within 15 days after the financing order is signed by the
35-18 commission. The judgment of the district court may be reviewed
35-19 only by direct appeal to the Supreme Court of Texas filed within 15
35-20 days after entry of judgment. All appeals shall be heard and
35-21 determined by the district court and the Supreme Court of Texas as
35-22 expeditiously as possible with lawful precedence over other
35-23 matters. Review on appeal shall be based solely on the record
35-24 before the commission and briefs to the court and shall be limited
35-25 to whether the financing order conforms to the constitution and
35-26 laws of this state and the United States and is within the
35-27 authority of the commission pursuant to this chapter.
35-28 (g) At the request of an electric utility, the commission
35-29 may adopt a financing order providing for retiring and refunding
35-30 transition bonds upon making a finding that the future transition
35-31 charges required to service the new transition bonds, including
35-32 transaction costs, will be less than the future transition charges
35-33 required to service the transition bonds being refunded. Upon the
35-34 retirement of the refunded transition bonds, the commission shall
35-35 adjust the related transition charges accordingly.
35-36 Sec. 39.304. PROPERTY RIGHTS. (a) The rights and interests
35-37 of an electric utility or successor under a financing order,
35-38 including the right to impose, collect, and receive transition
35-39 charges authorized in the order, shall be only contract rights
35-40 until they are first transferred to an assignee or pledged in
35-41 connection with the issuance of transition bonds, at which time
35-42 they will become "transition property."
35-43 (b) Transition property shall constitute a present property
35-44 right for purposes of contracts concerning the sale or pledge of
35-45 property, even though the imposition and collection of transition
35-46 charges depends on further acts of the utility or others which have
35-47 not yet occurred; the financing order shall remain in effect and
35-48 the property shall continue to exist for the same period as the
35-49 pledge of the state described in Section 39.310.
35-50 (c) All revenues and collections resulting from transition
35-51 charges shall constitute proceeds only of the transition property
35-52 arising from the financing order.
35-53 Sec. 39.305. NO SETOFF. The interest of an assignee or
35-54 pledgee in transition property and in the revenues and collections
35-55 arising from that property shall not be subject to setoff,
35-56 counterclaim, surcharge, or defense by the electric utility or any
35-57 other person or in connection with the bankruptcy of the electric
35-58 utility or any other entity. A financing order shall remain in
35-59 effect and unabated notwithstanding the bankruptcy of the electric
35-60 utility, its successors, or assignees.
35-61 Sec. 39.306. NO BYPASS. A financing order shall include
35-62 terms ensuring that the imposition and collection of transition
35-63 charges authorized in the order shall be nonbypassable.
35-64 Sec. 39.307. TRUE-UP. A financing order shall include a
35-65 mechanism requiring that transition charges be reviewed and
35-66 adjusted at least annually, within 45 days of the anniversary date
35-67 of the issuance of the transition bonds, to correct any
35-68 overcollections or undercollections of the preceding 12 months and
35-69 to ensure the expected recovery of amounts sufficient to timely
36-1 provide all payments of debt service and other required amounts and
36-2 charges in connection with the transition bonds.
36-3 Sec. 39.308. TRUE SALE. An agreement by an electric utility
36-4 or assignee to transfer transition property that expressly states
36-5 that the transfer is a sale or other absolute transfer signifies
36-6 that the transaction is a true sale and is not a secured
36-7 transaction and that title, legal and equitable, has passed to the
36-8 entity to which the transition property is transferred. This true
36-9 sale shall apply regardless of whether the purchaser has any
36-10 recourse against the seller, or any other term of the parties'
36-11 agreement, including the seller's retention of an equity interest
36-12 in the transition property, the fact that the electric utility acts
36-13 as the collector of transition charges relating to the transition
36-14 property, or the treatment of the transfer as a financing for tax,
36-15 financial reporting, or other purposes.
36-16 Sec. 39.309. SECURITY INTERESTS; ASSIGNMENT; COMMINGLING;
36-17 DEFAULT. (a) Transition property shall not constitute an account
36-18 or general intangible under Section 9.106, Business & Commerce
36-19 Code. The creation, granting, perfection, and enforcement of liens
36-20 and security interests in transition property are governed by this
36-21 section and not by the Business & Commerce Code.
36-22 (b) A valid and enforceable lien and security interest in
36-23 transition property shall be created only by a financing order and
36-24 the execution and delivery of a security agreement with a financing
36-25 party in connection with the issuance of transition bonds. The
36-26 lien and security interest shall attach automatically from the time
36-27 that value is received for the bonds and, upon perfection through
36-28 the filing of notice with the secretary of state in accordance with
36-29 the rules prescribed under Subsection (d), shall be a continuously
36-30 perfected lien and security interest in the transition property and
36-31 all proceeds thereof, whether accrued or not, shall have priority
36-32 in the order of filing and take precedence over any subsequent
36-33 judicial or other lien creditor. If notice is filed within 10 days
36-34 after value is received for the transition bonds, the security
36-35 interest shall be perfected retroactive to the date value was
36-36 received; otherwise, the security interest shall be perfected as of
36-37 the date of filing.
36-38 (c) Transfer of an interest in transition property to an
36-39 assignee shall be perfected against all third parties, including
36-40 subsequent judicial or other lien creditors, when the financing
36-41 order becomes effective, transfer documents have been delivered to
36-42 the assignee, and a notice of that transfer has been filed in
36-43 accordance with the rules prescribed under Subsection (d);
36-44 provided, however, that if notice of the transfer has not been
36-45 filed in accordance with this subsection within 10 days after the
36-46 delivery of transfer documentation, the transfer of the interest
36-47 shall not be perfected against third parties until the notice is
36-49 (d) The secretary of state shall implement this section by
36-50 establishing and maintaining a separate system of records for the
36-51 filing of notices under this section and prescribing the rules for
36-52 such filings based on Chapter 9, Business & Commerce Code, adapted
36-53 to the provisions of this subchapter and using the terms defined in
36-54 this subchapter.
36-55 (e) The priority of a lien and security interest perfected
36-56 under this section will not be impaired by any later modification
36-57 of the financing order under Section 39.307 or by the commingling
36-58 of funds arising from financing charges with other funds, and any
36-59 other security interest that may apply to those funds shall be
36-60 terminated when they are transferred to a segregated account for
36-61 the assignee or a financing party. If transition property has been
36-62 transferred to an assignee, any proceeds of that property shall be
36-63 held in trust for the assignee.
36-64 (f) If a default or termination occurs under the transition
36-65 bonds, the financing parties or their representatives may foreclose
36-66 on or otherwise enforce their lien and security interest in any
36-67 transition property as if they were secured parties under Chapter
36-68 9, Business & Commerce Code, and the commission may order that
36-69 amounts arising from financing charges be transferred to a separate
37-1 account for the financing parties' benefit, to which their lien and
37-2 security interest shall apply. On application by or on behalf of
37-3 the financing parties, a district court of Travis County shall
37-4 order the sequestration and payment to them of revenues arising
37-5 from the financing charges.
37-6 Sec. 39.310. PLEDGE OF STATE. Transition bonds are not a
37-7 debt or obligation of the state and are not a charge upon its full
37-8 faith and credit or taxing power. The state pledges, however, for
37-9 the benefit and protection of financing parties and the electric
37-10 utility, that it will not take or permit any action that would
37-11 impair the value of transition property, or, except as permitted by
37-12 Section 39.307, reduce, alter, or impair the financing charges to
37-13 be imposed, collected, and remitted to financing parties, until the
37-14 principal, interest and premium, and any other charges incurred and
37-15 contracts to be performed in connection with the related transition
37-16 bonds have been paid and performed in full. Any party issuing
37-17 transition bonds is authorized to include this pledge in any
37-18 documentation relating to such bonds.
37-19 Sec. 39.311. TAX EXEMPTION. Transactions involving the
37-20 transfer and ownership of transition property and the receipt of
37-21 financing charges shall be exempt from state and local income,
37-22 sales, franchise, gross receipts, and other taxes or similar
37-24 Sec. 39.312. NO PUBLIC UTILITY. No assignee or financing
37-25 party shall be considered to be a public utility or person
37-26 providing electric service solely by virtue of the transactions
37-27 described in this subchapter.
37-28 Sec. 39.313. SEVERABILITY. Effective upon the date the
37-29 first utility transition bonds are issued under this subchapter, if
37-30 any provision in this title or portion thereof is held to be
37-31 invalid or is invalidated, superseded, replaced, repealed, or
37-32 expires for any reason, such occurrence shall not affect the
37-33 validity or continuation of this subchapter, Section 39.201,
37-34 39.251, 39.252, or 39.262, or any part thereof, or any other
37-35 provision of this title that is relevant to the issuance,
37-36 administration, payment, retirement, or refunding of transition
37-37 bonds or to any actions of the electric utility, its successors, an
37-38 assignee, a collection agent, or a financing party related thereto,
37-39 which shall remain in full force and effect.
37-40 SUBCHAPTER H. CERTIFICATION AND REGISTRATION; PENALTIES
37-41 Sec. 39.351. REGISTRATION OF POWER GENERATION COMPANIES.
37-42 (a) A person may not generate electricity unless the person is
37-43 registered with the commission as a power generation company in
37-44 accordance with this section. A person may register as a power
37-45 generation company by filing the following information with the
37-47 (1) a description of the location of any facility used
37-48 to generate electricity;
37-49 (2) a description of the type of services provided;
37-50 (3) a copy of any information filed with the Federal
37-51 Energy Regulatory Commission in connection with registration with
37-52 that commission; and
37-53 (4) any other information required by commission rule,
37-54 provided that in requiring such information the commission shall
37-55 protect the competitive process in a manner that ensures the
37-56 confidentiality of competitively sensitive information.
37-57 (b) A power generation company shall comply with the
37-58 reliability standards adopted by an independent organization
37-59 certified by the commission to ensure the reliability of the
37-60 regional electrical network for a power region in which the power
37-61 generation company is generating or selling electricity.
37-62 (c) A power generation company may register anytime after
37-63 September 1, 2000.
37-64 Sec. 39.352. CERTIFICATION OF RETAIL ELECTRIC PROVIDERS.
37-65 (a) In areas where customer choice has been introduced, no person,
37-66 including an affiliate of an electric utility, may provide retail
37-67 electric service in this state unless the person is certified by
37-68 the commission as a retail electric provider, in accordance with
37-69 this section.
38-1 (b) The commission shall issue a certificate to provide
38-2 retail electric service to a person applying for certification who
38-4 (1) the financial and technical resources to provide
38-5 continuous and reliable electric service to customers in the area
38-6 for which the certification is sought;
38-7 (2) the managerial and technical ability to supply
38-8 electricity at retail in accordance with customer contracts;
38-9 (3) the resources needed to meet the customer
38-10 protection requirements of this title; and
38-11 (4) ownership or lease of an office located within
38-12 this state for the purpose of providing customer service, accepting
38-13 service of process, and making available in that office books and
38-14 records sufficient to establish the retail electric provider's
38-15 compliance with the requirements of this subchapter.
38-16 (c) A person applying for certification under this section
38-17 shall comply with all applicable customer protection provisions,
38-18 disclosure requirements, and marketing guidelines established by
38-19 the commission and by this title.
38-20 (d) In determining whether the requirements in Subsections
38-21 (b) and (c) have been met, the commission shall consider the nature
38-22 of the retail transactions and the types of customers served.
38-23 (e) A retail electric provider may apply for certification
38-24 anytime after September 1, 2000.
38-25 (f) The commission shall use any information required in
38-26 this section in a manner that ensures the confidentiality of
38-27 competitively sensitive information.
38-28 Sec. 39.353. REGISTRATION OF AGGREGATORS. (a) A person may
38-29 not provide aggregation services in the state unless the person is
38-30 registered with the commission as an aggregator.
38-31 (b) In this subchapter, "aggregator" means a person joining
38-32 two or more customers, other than municipalities, into a single
38-33 purchasing unit to negotiate the purchase of electricity from
38-34 retail electric providers. Aggregators may not sell or take title
38-35 to electricity. Retail electric providers are not aggregators.
38-36 (c) A person registering under this section shall comply
38-37 with all customer protection provisions, all disclosure
38-38 requirements, and all marketing guidelines established by the
38-39 commission and by this title.
38-40 (d) The commission may establish terms and conditions it
38-41 determines necessary to regulate the reliability and integrity of
38-42 aggregators in the state.
38-43 (e) An aggregator may register anytime after September 1,
38-45 Sec. 39.354. REGISTRATION OF MUNICIPAL AGGREGATORS. (a) A
38-46 municipal aggregator may not provide aggregation services in the
38-47 state unless the municipal aggregator registers with the
38-49 (b) In this section, "municipal aggregator" means a person
38-50 authorized by two or more municipal governing bodies to join the
38-51 bodies into a single purchasing unit to negotiate the purchase of
38-52 electricity from retail electric providers.
38-53 (c) A municipal aggregator may register anytime after
38-54 September 1, 2000.
38-55 Sec. 39.355. REGISTRATION OF POWER MARKETERS. A person may
38-56 not sell electric energy at wholesale as a power marketer unless
38-57 the person registers with the commission.
38-58 Sec. 39.356. REVOCATION OF CERTIFICATION. (a) The
38-59 commission may after notice and opportunity for hearing suspend,
38-60 revoke, or amend a retail electric provider's certificate for
38-61 significant violations of this title or the rules adopted pursuant
38-62 to this title or of any reliability standard adopted by an
38-63 independent organization certified by the commission to ensure the
38-64 reliability of a power region's electrical network, including the
38-65 failure to observe any scheduling, operating, or settlement
38-66 protocols established by the independent organization. The
38-67 commission may also suspend or revoke a retail electric provider's
38-68 certificate if the provider no longer has the financial or
38-69 technical capability to provide continuous and reliable electric
39-2 (b) The commission may suspend or revoke a power generation
39-3 company's registration for significant violations of this title or
39-4 the rules adopted pursuant to this title or of the reliability
39-5 standards adopted by an independent organization certified by the
39-6 commission to ensure the reliability of a power region's electrical
39-7 network, including the failure to observe any scheduling,
39-8 operating, or settlement protocols established by the independent
39-10 (c) The commission may suspend or revoke an aggregator's
39-11 registration for significant violations of this title or of the
39-12 rules adopted pursuant to this title.
39-13 Sec. 39.357. ADMINISTRATIVE PENALTY. In addition to the
39-14 suspension, revocation, or amendment of a certification, the
39-15 commission may impose an administrative penalty, as provided by
39-16 Section 15.023, for violations described by Section 39.356.
39-17 SUBCHAPTER I. MISCELLANEOUS PROVISIONS
39-18 Sec. 39.601. SCHOOL FUNDING LOSS MECHANISM. (a) Not later
39-19 than March 1 each year, the comptroller shall certify to the Texas
39-20 Education Agency any property wealth reductions, determined by
39-21 taking the difference between current year and prior year appraisal
39-22 values attributable to electric utility restructuring.
39-23 (b) The Texas Education Agency shall determine the reduction
39-24 of the amount of property taxes recaptured by the state from school
39-25 districts subject to wealth equalization under Chapter 41,
39-26 Education Code, as a result of the property wealth reductions
39-27 certified under Subsection (a) and shall notify the commission of
39-28 the amount necessary to compensate the state for the reduction.
39-29 (c) The Texas Education Agency shall determine the amount
39-30 necessary to compensate school districts for lost revenue resulting
39-31 from the property wealth reductions under Subsection (a) and shall
39-32 notify the commission of this amount. The amounts necessary to
39-33 compensate districts shall be the sum of:
39-34 (1) decreases in the level of funding to which a
39-35 school district is entitled under Chapters 42 and 46, Education
39-36 Code, that are directly attributable to the decline in property
39-37 values caused by utility restructuring; and
39-38 (2) losses of property tax collections incurred by
39-39 school districts that are directly attributable to property value
39-40 declines caused by utility restructuring and that are not accounted
39-41 for under Subdivision (1), including amounts which a school
39-42 district would be entitled to retain under Chapter 41, Education
39-44 (d) The amounts determined by the comptroller and the Texas
39-45 Education Agency under this section, for the purposes of this
39-46 section, are final and may not be appealed.
39-47 (e) Not later than May 1 of each year, the commission shall
39-48 transfer from the system benefit fund to the foundation school fund
39-49 the amounts determined by the Texas Education Agency under
39-50 Subsections (b) and (c). Amounts transferred from the system
39-51 benefit fund pursuant to this section are appropriated for the
39-52 support of the foundation school program and are available, in
39-53 addition to any amounts allocated by the General Appropriations
39-54 Act, to finance actions under Section 41.002(b) or 42.252(e),
39-55 Education Code.
39-56 (f) The Texas Education Agency shall, upon the transfer of
39-57 funds from the system benefit fund to the foundation school fund,
39-58 compensate school districts for losses incurred under Subsection
39-60 (g) The commissioner of education and the comptroller may
39-61 adopt rules necessary to implement this section.
39-62 (h) This section is effective through the 2006-2007 school
39-63 year. This section expires August 31, 2007.
39-64 Sec. 39.602. CUSTOMER EDUCATION. (a) On or before January
39-65 1, 2001, the commission shall develop and implement an educational
39-66 program to inform customers, including low-income and
39-67 non-English-speaking customers, about changes in the provision of
39-68 electric service resulting from the opening of the retail electric
39-69 market and the customer choice pilot program under this chapter.
40-1 The educational program shall be neutral and nonpromotional and
40-2 shall provide customers with the information necessary to make
40-3 informed decisions relating to the source and type of electric
40-4 service available for purchase and other information the commission
40-5 considers necessary. In planning and implementing this program,
40-6 the commission shall consult with the office, with the Texas
40-7 Department of Housing and Community Affairs, and with customers of
40-8 and providers of retail electric service. The commission may enter
40-9 contracts for professional services to carry out the customer
40-10 education program.
40-11 (b) The commission shall report on the status of the
40-12 educational program, developed and implemented as provided by
40-13 Subsection (a), to the electric utility restructuring legislative
40-14 oversight committee on or before December 1, 2001.
40-15 (c) After the opening of the retail electric market, the
40-16 commission shall conduct ongoing customer education designed to
40-17 help customers make informed choices of electric services and
40-18 retail electric providers. As part of ongoing education, the
40-19 commission may provide customers information concerning specific
40-20 retail electric providers, including instances of complaints
40-21 against them and records relating to quality of customer service.
40-22 Sec. 39.603. SYSTEM BENEFIT FUND. (a) The commission shall
40-23 establish the system benefit fund.
40-24 (b) The system benefit fund is financed by a nonbypassable
40-25 charge set by the commission in an amount not to exceed 50 cents
40-26 per MWh.
40-27 (c) The system benefit fund shall provide funding for:
40-28 (1) customer education programs;
40-29 (2) programs to assist low-income electric customers;
40-30 (3) the school funding loss mechanism provided by
40-31 Section 39.601; and
40-32 (4) administrative costs incurred by the commission in
40-33 implementing this chapter and Chapters 40 and 41.
40-34 (d) For the purposes of this section, a "low-income electric
40-35 customer" is an electric customer who is a qualifying low-income
40-36 consumer as defined by the commission.
40-37 Sec. 39.604. GOAL FOR RENEWABLE CAPACITY. (a) It is the
40-38 intent of the legislature that by January 1, 2007, renewable energy
40-39 technologies shall constitute not less than five percent of the
40-40 installed electric generation capacity that is physically located
40-41 in the state and available to sell power at wholesale or retail.
40-42 (b) The introduction of competition and retail customer
40-43 choice is expected to create opportunities that will stimulate the
40-44 economic development of renewable energy technologies in the state
40-45 to a level that achieves the goal of Subsection (a) through
40-46 reliance on market forces alone.
40-47 (c) Beginning on January 1, 2004, each retail electric
40-48 provider, municipally owned utility, and electric cooperative
40-49 operating in the state shall include a minimum of one percent of
40-50 capacity from renewable energy technologies in its supply
40-52 (d) The commission shall establish a renewable energy
40-53 credits trading program. Any retail electric provider, municipally
40-54 owned utility, or electric cooperative that does not satisfy the
40-55 requirement of Subsection (c) shall purchase sufficient renewable
40-56 energy credits to satisfy the requirement by holding renewable
40-57 energy credits in lieu of capacity from renewable energy
40-59 (e) In this section, "renewable energy technology" means any
40-60 technology that exclusively relies on an energy source that is
40-61 naturally regenerated over a short time and derived directly from
40-62 the sun, indirectly from the sun, or from other natural movements
40-63 and mechanisms of the environment. A renewable energy technology
40-64 does not rely on energy resources derived from fossil fuels, waste
40-65 products from fossil fuels, or waste products from inorganic
40-67 Sec. 39.605. GOAL FOR ENERGY EFFICIENCY. It is the intent
40-68 of the legislature that:
40-69 (1) regulated utilities shall administer customer
41-1 information and energy savings incentive programs;
41-2 (2) all customers, in all customer classes, shall have
41-3 a choice of and access to energy efficiency alternatives and other
41-4 choices that allow each customer to reduce energy consumption and
41-5 reduce energy costs;
41-6 (3) utilities may offer loans at below-market interest
41-7 rates for energy efficiency investments, other energy efficiency
41-8 market transformation programs which result in below-market cost to
41-9 the customer, and grants and other special programs to address the
41-10 needs of small businesses, tenants, low-income consumers, and other
41-11 customer groups not served by market-based incentive programs; and
41-12 (4) regulated utilities shall acquire, through
41-13 market-based standard offer programs or targeted market
41-14 transformation programs, additional energy efficiency equivalent to
41-15 at least 25 percent of each year's annual growth in demand.
41-16 Sec. 39.606. DISPLACED WORKERS. In order to mitigate
41-17 potential negative impacts on utility personnel directly affected
41-18 by electric industry restructuring, the commission may allow the
41-19 recovery of reasonable employee related transition costs.
41-20 Sec. 39.607. LEGISLATIVE OVERSIGHT COMMITTEE. (a) In this
41-21 section, "committee" means the electric utility restructuring
41-22 legislative oversight committee.
41-23 (b) The committee is composed of six members as follows:
41-24 (1) the chair of the Senate Committee on Economic
41-25 Development, who shall serve as the chair of the committee;
41-26 (2) the chair of the House Committee on State Affairs,
41-27 who shall serve as the vice chair of the committee;
41-28 (3) two members of the senate appointed by the
41-29 lieutenant governor; and
41-30 (4) two members of the house of representatives
41-31 appointed by the speaker of the house of representatives.
41-32 (c) An appointed member of the committee serves at the
41-33 pleasure of the appointing official.
41-34 (d) The committee is subject to Chapter 325, Government Code
41-35 (Texas Sunset Act). Unless continued in existence as provided by
41-36 that chapter, the committee is abolished September 1, 2005.
41-37 (e) The committee shall:
41-38 (1) meet at least annually with the commission;
41-39 (2) receive information about rules relating to
41-40 electric utility restructuring proposed or adopted by the
41-42 (3) review recommendations for legislation proposed by
41-43 the commission; and
41-44 (4) monitor the effectiveness of electric utility
41-45 restructuring, including the fairness of rates, the reliability of
41-46 service, and the effect of stranded costs and market power on
41-48 (f) The committee may request reports and other information
41-49 from the commission as necessary to carry out this section.
41-50 (g) Not later than November 15 of each even-numbered year,
41-51 the committee shall report to the governor, lieutenant governor,
41-52 and speaker of the house of representatives on the committee's
41-53 activities under Subsection (e). The report shall include:
41-54 (1) an analysis of any problems caused by electric
41-55 utility restructuring; and
41-56 (2) recommendations of any legislative action
41-57 necessary to address such problems and to further retail
41-58 competition within the electric power industry.
41-59 Sec. 39.608. EFFECT OF SUNSET PROVISION. (a) If the
41-60 commission is abolished and the other provisions of this title
41-61 expire as provided by Chapter 325, Government Code (Texas Sunset
41-62 Act), this subchapter, including the provisions of this title
41-63 referred to in this subchapter, continues in full force and effect
41-64 and does not expire.
41-65 (b) The authorities, duties, and functions of the commission
41-66 under this chapter shall be performed and carried out by a
41-67 successor agency to be designated by the legislature before
41-68 abolishment of the commission or, if the legislature does not
41-69 designate the successor, by the secretary of state.
42-1 CHAPTER 40. COMPETITION FOR MUNICIPALLY OWNED UTILITIES
42-2 AND RIVER AUTHORITIES
42-3 SUBCHAPTER A. GENERAL PROVISIONS
42-4 Sec. 40.001. APPLICABLE LAW. (a) Notwithstanding any other
42-5 provision of law, this chapter governs the transition to and the
42-6 establishment of a fully competitive electric power industry for
42-7 municipally owned utilities. This chapter controls over any other
42-8 provision of this title, except Sections 39.155, 39.157(e), 39.203,
42-9 39.603, and 39.604.
42-10 (b) Except as specifically provided in this subsection, the
42-11 provisions of Chapter 39 shall not apply to a river authority
42-12 operating a steam generating plant on or before January 1, 1999, or
42-13 a corporation authorized by Chapter 245, Acts of the 67th
42-14 Legislature, Regular Session, 1981 (Article 717p, Vernon's Texas
42-15 Civil Statutes), or Section 32.053. A river authority operating a
42-16 steam generating plant on or before January 1, 1999, shall be
42-17 subject to Sections 39.051(a)-(c), 39.108, 39.155, 39.157(e), and
42-19 (c) For purposes of Section 39.051, hydroelectric assets
42-20 shall not be deemed to be generating assets, and the transfer of
42-21 generating assets to a corporation authorized by Chapter 245, Acts
42-22 of the 67th Legislature, Regular Session, 1981 (Article 717p,
42-23 Vernon's Texas Civil Statutes), shall satisfy the requirements of
42-24 Section 39.051.
42-25 (d) Accommodation shall be made in the code of conduct
42-26 established under Section 39.157(e) for the provisions of Chapter
42-27 245, Acts of the 67th Legislature, Regular Session, 1981 (Article
42-28 717p, Vernon's Texas Civil Statutes), and the commission shall not
42-29 prohibit a river authority and any related corporation from sharing
42-30 officers, directors, employees, equipment, and facilities or from
42-31 providing goods or services to each other at cost without the need
42-32 for a competitive bid.
42-33 Sec. 40.002. DEFINITION. For purposes of this chapter,
42-34 "body vested with the power to manage and operate a municipally
42-35 owned utility" shall mean a body created in accordance with Article
42-36 1115 or 1115a, Revised Statutes, or by municipal charter.
42-37 Sec. 40.003. SECURITIZATION. (a) Municipally owned
42-38 utilities and river authorities may adopt and use securitization
42-39 provisions having the effect of the provisions set out in
42-40 Subchapter G, Chapter 39, to recover through rates stranded costs,
42-41 at a recovery level deemed appropriate by the municipally owned
42-42 utility or river authority up to 100 percent, under rules and
42-43 procedures that shall be established:
42-44 (1) in the case of a municipally owned utility, by the
42-45 municipal governing body or a body vested with the power to manage
42-46 and operate the municipally owned utility, including procedures
42-47 providing for rate orders of such body having the effect of
42-48 qualified rate orders, providing for a separate nonbypassable
42-49 charge to be collected from all retail electric customers of the
42-50 municipally owned utility to fund the recovery of the stranded
42-51 investment and all reasonable related expenses, and providing for
42-52 the issuance of bonds necessary to recover the amount deemed
42-53 appropriate by the municipally owned utility through a securitized
42-54 financing transaction; and
42-55 (2) in the case of a river authority, by the
42-57 (b) The rules and procedures for securitization established
42-58 by the commission under Subsection (a)(2) shall include procedures
42-59 for the recovery of stranded costs pursuant to the terms of a rate
42-60 order adopted by the governing body of the river authority, which
42-61 rate order shall have the effect of a qualified rate order.
42-62 (c) The rules and procedures for securitization established
42-63 by the commission under Subsection (a)(2) shall include rules and
42-64 procedures for the issuance of bonds issued in a securitized
42-65 financing transaction. The issuance of any bonds issued in a
42-66 securitized financing transaction by a river authority is hereby
42-67 expressly authorized and shall be governed by the laws governing
42-68 the issuance of bonds or other obligations by the river authority.
42-69 Findings made by the governing body of a river authority in a
43-1 qualified rate order issued pursuant to the rules and procedures
43-2 described in this subsection shall be conclusive, and any
43-3 nonbypassable charge incorporated in such rate order to recover the
43-4 principal, interest, and all reasonable expenses associated with
43-5 any securitized financing transaction shall constitute property
43-6 rights, as described in Subchapter G, Chapter 39, and otherwise
43-7 conform in all material respects to the nonbypassable charges set
43-8 forth in Subchapter G, Chapter 39.
43-9 (d) The rules and procedures established under this section
43-10 shall be consistent with other law applicable to municipally owned
43-11 utilities and river authorities and with the terms of any
43-12 resolutions, orders, charter provisions, or ordinances authorizing
43-13 outstanding bonds or other indebtedness of the municipalities or
43-14 river authorities.
43-15 Sec. 40.004. JURISDICTION OF THE COMMISSION. Except as
43-16 specifically otherwise provided in this chapter, the commission has
43-17 jurisdiction over municipally owned utilities only for the
43-18 following purposes:
43-19 (1) to regulate wholesale transmission rates and
43-20 service, including terms of access, to the extent provided by
43-21 Subchapter A, Chapter 35;
43-22 (2) to regulate certification of retail service areas
43-23 to the extent provided by Chapter 37;
43-24 (3) to regulate rates on appeal pursuant to
43-25 Subchapters D and E, Chapter 33, subject to the provisions of
43-26 Section 40.051(c);
43-27 (4) to establish a code of conduct as provided by
43-28 Section 39.157(e) applicable to anticompetitive activities and to
43-29 affiliate activities limited to structurally unbundled affiliates
43-30 of municipally owned utilities, subject to Section 40.054;
43-31 (5) to establish terms and conditions for open access
43-32 to transmission and distribution facilities for municipally owned
43-33 utilities providing customer choice, as provided by Section 39.203;
43-34 (6) to require collection of the nonbypassable charge
43-35 established under Section 39.603(b) and to administer the renewable
43-36 energy credits program under Section 39.604(d); and
43-37 (7) to require reports of municipally owned utility
43-38 operations only to the extent necessary to:
43-39 (A) enable the commission to determine the
43-40 aggregate load and energy requirements of the state and the
43-41 resources available to serve that load; or
43-42 (B) enable the commission to determine
43-43 information relating to market power as provided by Section 39.155.
43-44 SUBCHAPTER B. MUNICIPALLY OWNED UTILITY CHOICE
43-45 Sec. 40.051. GOVERNING BODY DECISION. (a) The municipal
43-46 governing body or a body vested with the power to manage and
43-47 operate a municipally owned utility has the discretion to decide
43-48 when or if the municipally owned utility will provide customer
43-50 (b) Municipally owned utilities may choose to participate in
43-51 customer choice at any time on or after January 1, 2002, by
43-52 adoption of an appropriate resolution of the municipal governing
43-53 body or a body vested with power to manage and operate the
43-54 municipally owned utility. The decision to participate in customer
43-55 choice by the adoption of a resolution is irrevocable.
43-56 (c) After a decision to offer customer choice has been made,
43-57 Subchapters D and E, Chapter 33, do not apply to any action taken
43-58 under this chapter.
43-59 Sec. 40.052. UTILITY NOT OFFERING CUSTOMER CHOICE. (a) A
43-60 municipally owned utility that has not chosen to participate in
43-61 customer choice may not offer electric energy at unregulated prices
43-62 directly to retail customers outside its certificated retail
43-63 service area.
43-64 (b) A municipally owned utility under Subsection (a) retains
43-65 the right to offer and provide a full range of customer service and
43-66 pricing programs to the customers within its certificated area and
43-67 to purchase and sell electric energy at wholesale without
43-68 geographic restriction.
43-69 Sec. 40.053. RETAIL CUSTOMER'S RIGHT OF CHOICE. (a) If a
44-1 municipally owned utility chooses to participate in customer
44-2 choice, after that choice all retail customers served by the
44-3 municipally owned utility within the certificated retail service
44-4 area of the municipally owned utility shall have the right of
44-5 customer choice consistent with the provisions of this chapter, and
44-6 the municipally owned utility shall provide open access for retail
44-8 (b) Notwithstanding Section 39.107, the metering function
44-9 shall not be deemed a competitive service for customers of the
44-10 municipally owned utility within such service area and may, at the
44-11 option of the municipally owned utility, continue to be offered by
44-12 the municipally owned utility as sole provider.
44-13 (c) Upon its initiation of customer choice, a municipally
44-14 owned utility shall designate itself or another entity as the
44-15 provider of last resort for customers within the municipally owned
44-16 utility's certificated service area as that area existed on the
44-17 date of the utility's initiation of customer choice. The
44-18 municipally owned utility shall fulfill the role of default
44-19 provider of last resort in the event no other entity is available
44-20 to act in that capacity.
44-21 (d) If a customer is unable to obtain service from a retail
44-22 electric provider, upon request by the customer, the provider of
44-23 last resort shall offer the customer the standard retail service
44-24 package for the appropriate customer class, with no interruption of
44-25 service, at a fixed, nondiscountable rate that is at least
44-26 sufficient to cover the reasonable costs of providing such service,
44-27 as approved by the governing body of the municipally owned utility
44-28 which has the authority to set rates.
44-29 (e) The governing body of a municipally owned utility may
44-30 establish the procedures and criteria for designating the provider
44-31 of last resort and may redesignate the provider of last resort
44-32 according to a schedule it considers appropriate.
44-33 Sec. 40.054. SERVICE OUTSIDE AREA. (a) A municipally owned
44-34 utility participating in customer choice shall have the right to
44-35 offer electric energy and related services at unregulated prices
44-36 directly to retail customers within qualifying power regions
44-37 without regard to geographic location.
44-38 (b) In providing service under Subsection (a) to retail
44-39 customers outside its certificated retail service area as that area
44-40 exists on the date of adoption of customer choice, a municipally
44-41 owned utility is subject to the commission's rules establishing a
44-42 code of conduct regulating anticompetitive practices.
44-43 (c) For municipally owned utilities participating in
44-44 customer choice, the commission shall have jurisdiction to
44-45 establish terms and conditions, but not rates, for access by other
44-46 retail electric providers to the municipally owned utility's
44-47 distribution facilities.
44-48 (d) Accommodation shall be made in the commission's terms
44-49 and conditions for access and in the code of conduct for specific
44-50 legal requirements imposed by state or federal law applicable to
44-51 municipally owned utilities.
44-52 (e) The commission does not have jurisdiction to require
44-53 unbundling of services or functions of, or to regulate the recovery
44-54 of stranded investment of, a municipally owned utility or, except
44-55 as provided by this section, jurisdiction with respect to the
44-56 rates, terms, and conditions of service for retail customers of a
44-57 municipally owned utility within the utility's certificated service
44-59 (f) A municipally owned utility shall maintain separate
44-60 books and records of its operations from those of the operations of
44-61 any affiliate.
44-62 Sec. 40.055. JURISDICTION OF MUNICIPAL GOVERNING BODY.
44-63 (a) The municipal governing body or a body vested with the power
44-64 to manage and operate a municipally owned utility has exclusive
44-65 jurisdiction to:
44-66 (1) set all terms of access, conditions, and rates
44-67 applicable to services provided by the municipally owned utility,
44-68 subject to Sections 40.054 and 40.056, including nondiscriminatory
44-69 and comparable terms of access, conditions, and rates for
45-1 distribution but excluding wholesale transmission rates, terms of
45-2 access, and conditions for wholesale transmission service set by
45-3 the commission under this subtitle, provided that the rates for
45-4 distribution access established by the municipal governing body
45-5 shall be comparable to the distribution access rates that apply to
45-6 the municipally owned utility and the municipally owned utility's
45-8 (2) determine whether to unbundle any energy-related
45-9 activities and, if the municipally owned utility chooses to
45-10 unbundle, whether to do so structurally or functionally;
45-11 (3) reasonably determine the amount of the municipally
45-12 owned utility's stranded investment;
45-13 (4) establish nondiscriminatory transition charges
45-14 reasonably designed to recover the stranded investment over an
45-15 appropriate period of time, provided that recovery of retail
45-16 stranded costs shall be from all existing or future retail
45-17 customers, including the facilities, premises, and loads of such
45-18 retail customers, within the utility's geographical certificated
45-19 service area as it existed on May 1, 1999;
45-20 (5) determine the extent to which the municipally
45-21 owned utility will provide various customer services at the
45-22 distribution level, including other services that the municipally
45-23 owned utility is legally authorized to provide, or will accept the
45-24 services from other providers;
45-25 (6) manage and operate the municipality's electric
45-26 utility systems, including exercise of control over resource
45-27 acquisition and any related expansion programs;
45-28 (7) establish and enforce service quality and
45-29 reliability standards and consumer safeguards designed to protect
45-30 retail electric customers, including safeguards that will
45-31 accomplish the objectives of Sections 39.101(a) and (b), consistent
45-32 with the provisions of this chapter;
45-33 (8) determine whether a base rate reduction is
45-34 appropriate for the municipally owned utility;
45-35 (9) determine any other utility matters that the
45-36 municipal governing body or body vested with power to manage and
45-37 operate the municipally owned utility believes should be included;
45-39 (10) make any other decisions affecting the
45-40 municipally owned utility's participation in customer choice that
45-41 are not inconsistent with the provisions of this chapter.
45-42 (b) In multiply certificated areas, a retail customer,
45-43 including a retail customer of an electric cooperative or a
45-44 municipally owned utility, may not avoid stranded cost recovery
45-45 charges by switching to another electric utility, electric
45-46 cooperative, or municipally owned utility.
45-47 Sec. 40.056. ANTICOMPETITIVE ACTIONS. (a) If, upon
45-48 complaint by a retail electric provider, the commission finds that
45-49 a municipal rule, action, or order relating to customer choice is
45-50 anticompetitive or does not provide other retail electric providers
45-51 with nondiscriminatory terms and conditions of access to
45-52 distribution facilities or customers within the municipally owned
45-53 utility's certificated retail service area that are comparable to
45-54 the municipally owned utility's and its affiliates' terms and
45-55 conditions of access to distribution facilities or customers, the
45-56 commission shall notify the municipally owned utility.
45-57 (b) The municipally owned utility shall have three months to
45-58 cure the anticompetitive or noncompliant behavior described in
45-59 Subsection (a), following opportunity for hearing on the complaint.
45-60 If the rule, action, or order is not fully remedied within that
45-61 time, the commission may prohibit the municipally owned utility or
45-62 affiliate from providing retail service outside its certificated
45-63 retail service area until the rule, action, or order is remedied.
45-64 Sec. 40.057. BILLING. (a) A municipally owned utility that
45-65 opts for customer choice may continue to bill directly electric
45-66 customers located in its certificated retail service area, as that
45-67 area exists on the date of adoption of customer choice, for all
45-68 transmission and distribution services. The municipally owned
45-69 utility may also bill directly for generation services and customer
46-1 services provided by the municipally owned utility to those
46-3 (b) A municipally owned utility that opts for customer
46-4 choice shall not adopt anticompetitive billing practices that would
46-5 discourage customers in its service area from choosing a retail
46-6 electric provider.
46-7 (c) A customer that is being provided wires service by a
46-8 municipally owned utility at distribution or transmission voltage
46-9 and that is served by a retail electric provider for retail service
46-10 has the option of being billed directly by each service provider or
46-11 to receive a single bill for distribution, transmission, and
46-12 generation services from the municipally owned utility.
46-13 Sec. 40.058. TARIFFS FOR OPEN ACCESS. A municipally owned
46-14 utility that owns or operates transmission and distribution
46-15 facilities shall file with the commission tariffs implementing the
46-16 open access rules established by the commission under Section
46-17 39.203 and shall file with the commission the rates for open access
46-18 on distribution facilities as set by the municipal regulatory
46-19 authority, before the 90th day preceding the date the utility
46-20 offers customer choice. The commission has no authority to
46-21 determine the rates for distribution access service for a
46-22 municipally owned utility.
46-23 Sec. 40.059. MUNICIPAL POWER AGENCY; RECOVERY OF STRANDED
46-24 COSTS. (a) In this section, "member city" means a municipality
46-25 that participated in the creation of a municipal power agency
46-26 formed pursuant to Chapter 163 by the adoption of a concurrent
46-27 resolution by the municipality on or before August 1, 1975.
46-28 (b) After a member city adopts a resolution choosing to
46-29 participate in customer choice under Section 40.051(b), a member
46-30 city may include stranded costs described in Subsection (c) in its
46-31 distribution costs and may recover such costs through a
46-32 nonbypassable charge. The nonbypassable charge shall be as
46-33 determined by the member city's governing body and may be spread
46-34 over 16 years.
46-35 (c) The stranded costs that may be recovered under this
46-36 section are those costs that were determined by the commission and
46-37 set forth in the commission's April 1998 Report to the Texas Senate
46-38 Interim Committee on Electric Utility Restructuring entitled
46-39 "Potentially Strandable Investment (ECOM) Report: 1998 Update" and
46-40 specifically set forth in the report at Appendix A (ECOM Estimates
46-41 Including the Effects of Transition Plans) under the commission
46-42 base case benchmark base market price for the year 2002.
46-43 (d) The stranded cost amounts described in this section
46-44 shall not be included in the generation costs used in setting rates
46-45 by the member city's governing body.
46-46 (e) The provisions of this section are cumulative of all
46-47 other provisions of this chapter, and nothing in this section shall
46-48 be construed to limit or restrict the application of any provision
46-49 of this chapter to the member cities.
46-50 (f) The municipal power agency shall extinguish the agency's
46-51 indebtedness by sale of the electric facility to one or more
46-52 purchasers, by way of a sale through the issuance of taxable or
46-53 tax-exempt debt to the member cities, or by any other method. The
46-54 agency shall set as an objective the extinguishment of the agency's
46-55 debt by September 1, 2000. In the event this objective is not met,
46-56 the agency shall provide detailed reasons to the electric utility
46-57 restructuring legislative oversight committee by November 1, 2000,
46-58 why the agency was not able to meet this objective.
46-59 Sec. 40.060. NO POWER TO AMEND CERTIFICATES. Nothing in
46-60 this chapter empowers a municipal governing body or a body vested
46-61 with the power to manage and operate a municipally owned utility to
46-62 issue, amend, or rescind a certificate of public convenience and
46-63 necessity granted by the commission. This subsection does not
46-64 affect the ability of a municipal governing body or a body vested
46-65 with the power to manage and operate the municipally owned utility
46-66 to pass a resolution under Section 40.051(b).
46-67 SUBCHAPTER C. RIGHTS NOT AFFECTED
46-68 Sec. 40.101. INTERFERENCE WITH CONTRACT. (a) This subtitle
46-69 shall not interfere with or abrogate the rights or obligations of
47-1 parties, including a retail or wholesale customer, to a contract
47-2 with a municipally owned utility or river authority.
47-3 (b) This subtitle shall not interfere with or abrogate the
47-4 rights or obligations of a party under a contract or agreement
47-5 concerning certificated utility service areas.
47-6 Sec. 40.102. ACCESS TO WHOLESALE MARKET. Nothing in this
47-7 subtitle shall limit the access of municipally owned utilities to
47-8 the wholesale electric market.
47-9 Sec. 40.103. PROTECTION OF BONDHOLDERS. Nothing in this
47-10 subtitle or any rule adopted under this subtitle shall impair
47-11 contracts, covenants, or obligations between this state, river
47-12 authorities, municipalities, and the bondholders of revenue bonds
47-13 issued by the river authorities or municipalities.
47-14 Sec. 40.104. TAX-EXEMPT STATUS. Nothing in this subtitle
47-15 may impair the tax-exempt status of municipalities, electric
47-16 cooperatives, or river authorities, nor shall anything in this
47-17 subtitle compel any municipality, electric cooperative, or river
47-18 authority to use its facilities in a manner which violates any
47-19 contractual provisions, bond covenants, or other restrictions
47-20 applicable to facilities financed by tax-exempt debt.
47-21 Notwithstanding any other provision of law, the decision to
47-22 participate in customer choice by the adoption of a resolution in
47-23 accordance with Section 40.051(b) is irrevocable.
47-24 CHAPTER 41. ELECTRIC COOPERATIVES AND COMPETITION
47-25 SUBCHAPTER A. GENERAL PROVISIONS
47-26 Sec. 41.001. APPLICABLE LAW. Notwithstanding any other
47-27 provision of law, except Sections 39.155, 39.157(e), 39.203,
47-28 39.603, and 39.604, this chapter governs the transition to and the
47-29 establishment of a fully competitive electric power industry for
47-30 electric cooperatives. Regarding the regulation of electric
47-31 cooperatives, this chapter shall control over any other provision
47-32 of this title, except for sections in which the term "electric
47-33 cooperative" is specifically used.
47-34 Sec. 41.002. DEFINITIONS. In this chapter:
47-35 (1) "Board of directors" means the board of directors
47-36 of an electric cooperative as described in Section 161.071.
47-37 (2) "Rate" includes any compensation, tariff, charge,
47-38 fare, toll, rental, or classification that is directly or
47-39 indirectly demanded, observed, charged, or collected by an electric
47-40 cooperative for any service, product, or commodity and any rule,
47-41 practice, or contract affecting the compensation, tariff, charge,
47-42 fare, toll, rental, or classification.
47-43 (3) "Stranded investment" means:
47-44 (A) the excess, if any, of the net book value of
47-45 generation assets over the market value of the generation assets;
47-47 (B) any above market purchased power costs.
47-48 Sec. 41.003. SECURITIZATION. (a) Electric cooperatives may
47-49 adopt and use securitization provisions having the effect of the
47-50 provisions set out in Subchapter G, Chapter 39, to recover through
47-51 rates stranded costs at a recovery level deemed appropriate by the
47-52 board of directors up to 100 percent, under rules and procedures
47-53 that shall be established by the commission.
47-54 (b) The rules and procedures for securitization established
47-55 under Subsection (a) shall include rules and procedures for the
47-56 recovery of stranded costs pursuant to the terms of a rate order
47-57 adopted by the board of directors of the electric cooperative,
47-58 which rate order shall have the effect of a financing order.
47-59 (c) The rules and procedures established by the commission
47-60 under Subsection (b) shall include rules and procedures for the
47-61 issuance of transition bonds issued in a securitized financing
47-62 transaction. The issuance of any transition bonds issued in a
47-63 securitized financing transaction by an electric cooperative is
47-64 expressly authorized and shall be governed by the laws governing
47-65 the issuance of bonds or other obligations by the electric
47-66 cooperative. Findings made by the board of directors of an
47-67 electric cooperative in a rate order issued under the rules and
47-68 procedures described by this subsection shall be conclusive, and
47-69 any transition charges incorporated in such rate order to recover
48-1 the principal, interest, and all reasonable expenses associated
48-2 with any securitized financing transaction shall constitute
48-3 property rights, as described in Subchapter G, Chapter 39, and
48-4 shall otherwise conform in all material respects to the transition
48-5 charges set forth in Subchapter G, Chapter 39.
48-6 Sec. 41.004. JURISDICTION OF THE COMMISSION. Except as
48-7 specifically provided otherwise in this chapter, the commission has
48-8 jurisdiction over electric cooperatives only as follows:
48-9 (1) to regulate wholesale transmission rates and
48-10 service including terms of access, to the extent provided in
48-11 Subchapter A, Chapter 35;
48-12 (2) to regulate certification of retail service areas
48-13 to the extent provided in Chapter 37;
48-14 (3) to establish a code of conduct as provided in
48-15 Section 39.157(e) subject to Section 41.054;
48-16 (4) to establish terms and conditions, but not rates,
48-17 for open access to distribution facilities for electric
48-18 cooperatives providing customer choice, as provided in Section
48-19 39.203; and
48-20 (5) to require reports of electric cooperative
48-21 operations only to the extent necessary to:
48-22 (A) ensure the public safety;
48-23 (B) enable the commission to satisfy its
48-24 responsibilities relating to electric cooperatives under this
48-26 (C) enable the commission to determine the
48-27 aggregate electric load and energy requirements in the state and
48-28 the resources available to serve that load; or
48-29 (D) enable the commission to determine
48-30 information relating to market power as provided in Section 39.155.
48-31 Sec. 41.005. LIMITATION ON MUNICIPAL AUTHORITY.
48-32 Notwithstanding any other provision of this title, a municipality
48-33 may not directly or indirectly regulate the rates, operations, and
48-34 services of an electric cooperative. This section shall not
48-35 prohibit a municipality from making a lawful charge for the use of
48-36 public rights-of-way within the municipality as provided by Section
48-37 182.025, Tax Code.
48-38 SUBCHAPTER B. ELECTRIC COOPERATIVE UTILITY CHOICE
48-39 Sec. 41.051. BOARD DECISION. (a) The board of directors
48-40 has the discretion to decide when or if the electric cooperative
48-41 will provide customer choice.
48-42 (b) Electric cooperatives that choose to participate in
48-43 customer choice may do so at any time on or after January 1, 2002,
48-44 by adoption of an appropriate resolution of the board of directors.
48-45 The decision to participate in customer choice by the adoption of
48-46 such a resolution may be revoked only if no customer has opted for
48-47 choice within four years of the resolution's adoption. An electric
48-48 cooperative may initiate a customer choice pilot project at any
48-50 Sec. 41.052. ELECTRIC COOPERATIVES NOT OFFERING CUSTOMER
48-51 CHOICE. (a) An electric cooperative that chooses not to
48-52 participate in customer choice may not offer electric energy at
48-53 unregulated prices directly to retail customers outside its
48-54 certificated retail service area.
48-55 (b) An electric cooperative under Subsection (a) retains the
48-56 right to offer and provide a full range of customer service and
48-57 pricing programs to the customers within its certificated retail
48-58 service area and to purchase and sell electric energy at wholesale
48-59 without geographic restriction.
48-60 (c) A generation and transmission electric cooperative may
48-61 offer electric energy at unregulated prices directly to retail
48-62 customers outside of its parent electric cooperatives' certificated
48-63 service areas only if a majority of the parent electric
48-64 cooperatives of the generation and transmission electric
48-65 cooperative have chosen to offer customer choice.
48-66 (d) A subsidiary of an electric cooperative may not provide
48-67 electric energy at unregulated prices outside of its parent
48-68 electric cooperative's certificated retail service area unless the
48-69 electric cooperative offers customer choice inside its certificated
49-1 retail service area.
49-2 Sec. 41.053. RETAIL CUSTOMER RIGHT OF CHOICE. (a) If an
49-3 electric cooperative chooses to participate in customer choice,
49-4 after that choice, all retail customers within the certificated
49-5 service area of the electric cooperative shall have the right of
49-6 customer choice, and the electric cooperative shall provide
49-7 nondiscriminatory open access for retail service.
49-8 (b) Notwithstanding Section 39.107, the metering function
49-9 shall not be deemed a competitive service for customers of the
49-10 electric cooperative within such service area and may, at the
49-11 option of the electric cooperative, continue to be offered by the
49-12 electric cooperative as sole provider.
49-13 (c) Upon its initiation of customer choice, an electric
49-14 cooperative shall designate itself or another entity as the
49-15 provider of last resort for retail customers within the electric
49-16 cooperative's certificated service area and shall fulfill the role
49-17 of default provider of last resort in the event no other entity is
49-18 available to act in that capacity.
49-19 (d) If a retail electric provider fails to serve a customer
49-20 described in Subsection (c), upon request by the customer, the
49-21 provider of last resort shall offer the customer the standard
49-22 retail service package for the appropriate customer class, with no
49-23 interruption of service, at a fixed, nondiscountable rate that is
49-24 at least sufficient to cover the reasonable costs of providing such
49-25 service, as approved by the board of directors.
49-26 (e) The board of directors may establish the procedures and
49-27 criteria for designating the provider of last resort and may
49-28 redesignate the provider of last resort according to a schedule it
49-29 considers appropriate.
49-30 Sec. 41.054. SERVICE OUTSIDE CERTIFICATED AREA. (a) An
49-31 electric cooperative participating in customer choice shall have
49-32 the right to offer electric energy and related services at
49-33 unregulated prices directly to retail customers within qualifying
49-34 power regions without regard to geographic location.
49-35 (b) In providing service under Subsection (a) to retail
49-36 customers outside its certificated service area as that area exists
49-37 on the date of adoption of customer choice, an electric cooperative
49-38 becomes subject to commission jurisdiction as to the commission's
49-39 rules establishing a code of conduct regulating anticompetitive
49-40 practices under Section 39.157(e), except to the extent such rules
49-41 conflict with this chapter.
49-42 (c) For electric cooperatives participating in customer
49-43 choice, the commission shall have jurisdiction to establish terms
49-44 and conditions, but not rates, for access by other electric
49-45 providers to the electric cooperative's distribution facilities.
49-46 (d) Notwithstanding Subsections (b) and (c), the commission
49-47 shall make accommodation in the code of conduct for specific legal
49-48 requirements imposed by state or federal law applicable to electric
49-49 cooperatives. The commission shall accommodate the organizational
49-50 structures of electric cooperatives and shall not prohibit an
49-51 electric cooperative and any related entity from sharing officers,
49-52 directors, or employees.
49-53 (e) The commission does not have jurisdiction to require the
49-54 unbundling of services or functions of, or to regulate the recovery
49-55 of stranded investment of, an electric cooperative or, except as
49-56 provided by this section, jurisdiction with respect to the rates,
49-57 terms, and conditions of service for retail customers of an
49-58 electric cooperative within the electric cooperative's certificated
49-59 service area.
49-60 (f) An electric cooperative shall maintain separate books
49-61 and records of its operations and the operations of any subsidiary
49-62 and shall ensure that the rates charged for provision of electric
49-63 service do not include any costs of its subsidiary or any other
49-64 costs not related to the provision of electric service.
49-65 Sec. 41.055. JURISDICTION OF BOARD OF DIRECTORS. A board of
49-66 directors has exclusive jurisdiction to:
49-67 (1) set all terms of access, conditions, and rates
49-68 applicable to services provided by the electric cooperative, except
49-69 as provided by Sections 41.054 and 41.056, including
50-1 nondiscriminatory and comparable terms of access, conditions, and
50-2 rates for distribution but excluding wholesale transmission rates,
50-3 terms of access, and conditions for wholesale transmission service
50-4 set by the commission under Subchapter A, Chapter 35, provided that
50-5 the rates for distribution established by the electric cooperative
50-6 shall be comparable to the distribution rates that apply to the
50-7 electric cooperative and its subsidiaries;
50-8 (2) determine whether to unbundle any energy-related
50-9 activities, and if the board of directors chooses to unbundle,
50-10 whether to do so structurally or functionally;
50-11 (3) reasonably determine the amount of the electric
50-12 cooperative's stranded investment;
50-13 (4) establish nondiscriminatory transition charges
50-14 reasonably designed to recover the stranded investment over an
50-15 appropriate period of time;
50-16 (5) determine the extent to which the electric
50-17 cooperative will provide various customer services, including
50-18 nonelectric services, or accept the services from other providers;
50-19 (6) manage and operate the electric cooperative's
50-20 utility systems, including exercise of control over resource
50-21 acquisition and any related expansion programs;
50-22 (7) establish and enforce service quality standards,
50-23 reliability standards, and consumer safeguards designed to protect
50-24 retail electric customers;
50-25 (8) determine whether a base rate reduction is
50-26 appropriate for the electric cooperative;
50-27 (9) determine any other utility matters that the board
50-28 of directors believes should be included;
50-29 (10) sell electric energy and capacity at wholesale,
50-30 regardless of whether the electric cooperative participates in
50-31 customer choice; and
50-32 (11) make any other decisions affecting the electric
50-33 cooperative's method of conducting business that are not
50-34 inconsistent with the provisions of this chapter.
50-35 Sec. 41.056. ANTICOMPETITIVE ACTIONS. (a) If, after notice
50-36 and hearing, the commission finds that an electric cooperative
50-37 providing customer choice has engaged in anticompetitive behavior
50-38 by not providing other retail electric providers with
50-39 nondiscriminatory terms and conditions of access to distribution
50-40 facilities or customers within the electric cooperative's
50-41 certificated service area that are comparable to the electric
50-42 cooperative's and its subsidiaries' terms and conditions of access
50-43 to distribution facilities or customers, the commission shall
50-44 notify the electric cooperative.
50-45 (b) The electric cooperative shall have three months to cure
50-46 the anticompetitive or noncompliant behavior described in
50-47 Subsection (a). If the behavior is not fully remedied within that
50-48 time, the commission may prohibit the electric cooperative or its
50-49 subsidiary from providing retail service outside its certificated
50-50 retail service area until the behavior is remedied.
50-51 Sec. 41.057. BILLING. (a) An electric cooperative that
50-52 opts for customer choice may continue to bill directly electric
50-53 customers located in its certificated service area for all
50-54 transmission and distribution services. The electric cooperative
50-55 may also bill directly for generation and customer services
50-56 provided by the electric cooperative or its subsidiaries to those
50-58 (b) A customer served by an electric cooperative for
50-59 transmission and distribution services and by a retail electric
50-60 provider for retail service has the option of being billed directly
50-61 by each service provider or receiving a single bill for
50-62 distribution, transmission, and generation services from the
50-63 electric cooperative.
50-64 Sec. 41.058. TARIFFS FOR OPEN ACCESS. An electric
50-65 cooperative that owns or operates transmission and distribution
50-66 facilities shall file tariffs implementing the open access rules
50-67 established by the commission under Section 39.203 with the
50-68 appropriate regulatory authorities having jurisdiction over the
50-69 transmission and distribution service of the electric cooperative
51-1 before the 90th day preceding the date the electric cooperative
51-2 offers customer choice.
51-3 Sec. 41.059. NO POWER TO AMEND CERTIFICATES. Nothing in
51-4 this chapter empowers a board of directors to issue, amend, or
51-5 rescind a certificate of public convenience and necessity granted
51-6 by the commission.
51-7 Sec. 41.060. CUSTOMER SERVICE INFORMATION. (a) The
51-8 commission shall keep information submitted by customers and retail
51-9 electric providers pertaining to the provision of electric service
51-10 by electric cooperatives.
51-11 (b) The commission shall notify the appropriate electric
51-12 cooperative of information submitted by a customer or retail
51-13 electric provider, and the electric cooperative shall respond to
51-14 the customer or retail electric provider. The electric cooperative
51-15 shall notify the commission of its response.
51-16 (c) The commission shall prepare a report for the Sunset
51-17 Advisory Commission that includes information submitted and
51-18 responses by electric cooperatives pursuant to the Sunset Advisory
51-19 Commission's schedule for reviewing the commission.
51-20 Sec. 41.061. RETAIL RATE CHANGES BY ELECTRIC COOPERATIVES.
51-21 (a) This section shall apply to retail rates of an electric
51-22 cooperative that has not adopted customer choice and to the retail
51-23 delivery rates of an electric cooperative that has adopted customer
51-24 choice. This section shall not apply to rates for:
51-25 (1) sales of electric energy by an electric
51-26 cooperative that has adopted customer choice; or
51-27 (2) wholesale sales of electric energy.
51-28 (b) An electric cooperative may change its rates by:
51-29 (1) adopting a resolution approving the proposed
51-31 (2) mailing notice of the proposed change to each
51-32 affected customer whose rate would be increased by the proposed
51-33 change at least 30 days before implementation of the proposed
51-34 change, which notice may be included in a monthly billing; and
51-35 (3) holding a meeting to discuss the proposed rate
51-36 changes with affected customers, if any change is expected to
51-37 increase total system annual revenues by more than $100,000 or one
51-38 percent, whichever is greater.
51-39 (c) An electric cooperative may implement the proposed rates
51-40 upon completion of the requirements under Subsection (b), and such
51-41 rates shall remain in effect until changed by the electric
51-42 cooperative as provided by this section or, for rates other than
51-43 retail delivery rates, until this section is no longer applicable
51-44 because the electric cooperative adopts customer choice.
51-45 (d) The electric cooperative may reconsider a rate change at
51-46 any time and adjust the rate by board resolution without additional
51-47 notice or meeting of customers if the rate as adjusted is within
51-48 the general scope of the notice previously provided to affected
51-49 customers or is expected to decrease the revenues of the electric
51-51 (e) Retail rates set by an electric cooperative that has not
51-52 adopted customer choice and retail delivery rates set by an
51-53 electric cooperative that has adopted customer choice shall be just
51-54 and reasonable, not unreasonably preferential, prejudicial, or
51-55 discriminatory; provided, however, that an electric cooperative may
51-56 charge market-based rates to customers who have energy supply
51-58 (f) A customer of the electric cooperative who is adversely
51-59 affected by a resolution of the electric cooperative setting rates
51-60 is entitled to judicial review. A person initiates judicial review
51-61 by filing a petition in the district court of Travis County not
51-62 later than the 60th day after the date the resolution is
51-64 (g) The resolution of the electric cooperative setting
51-65 rates, as it may have been amended as described in Subsection (d),
51-66 shall be presumed valid, and the burden of showing that the
51-67 resolution is invalid rests upon the persons challenging the
51-68 resolution. A court reviewing a rate change by an electric
51-69 cooperative may consider any relevant factor that may be considered
52-1 by a court in reviewing a decision of the commission including the
52-2 cost of providing service.
52-3 (h) If the court finds that the electric cooperative's
52-4 resolution setting rates violates the standards contained in
52-5 Subsection (e), the court shall enter an order:
52-6 (1) stating the specific basis for its determination
52-7 that the rates set in the electric cooperative's resolution violate
52-8 Subsection (e); and
52-9 (2) directing the electric cooperative to:
52-10 (A) set, within 60 days, revised retail rates
52-11 that do not violate the standards of Subsection (e); and
52-12 (B) refund or credit against future bills, at
52-13 the electric cooperative's option, revenues collected under the
52-14 rate found to violate the standards of Subsection (e) that exceed
52-15 the revenues that would have been collected under the revised
52-16 rates. The refund or credit shall be made over a period of not
52-17 more than 12 months, as determined by the electric cooperative.
52-18 (i) No remedy other than or additional to a remedy under
52-19 Subsection (h) may be ordered by the court. The court may not set
52-20 revised rates either for the period the challenged resolution was
52-21 in effect or prospectively.
52-22 (j) Except as provided by this section, and Subchapter A,
52-23 Chapter 35, with regard to wholesale transmission rates, the rates
52-24 of an electric cooperative are not subject to review.
52-25 Sec. 41.062. ALLOCATION OF STRANDED INVESTMENT. Any
52-26 competition transition charge shall be allocated among retail
52-27 customer classes based on the relevant customer class
52-28 characteristics as of the end of the electric cooperative's most
52-29 recent fiscal year prior to implementation of customer choice, in
52-30 accordance with the methodology used to allocate the costs of the
52-31 underlying assets or expenses in the electric cooperative's most
52-32 recent cost of service study certified by a professional engineer
52-33 or certified public accountant or approved by the commission. In
52-34 multiply certificated areas, a retail customer may not avoid
52-35 stranded cost recovery charges by switching to another electric
52-36 cooperative, an electric utility, or a municipally owned utility.
52-37 SUBCHAPTER C. RIGHTS NOT AFFECTED
52-38 Sec. 41.101. INTERFERENCE WITH CONTRACT. (a) This subtitle
52-39 shall not interfere with or abrogate the rights or obligations of
52-40 parties, including a retail or wholesale customer, to a contract
52-41 with an electric cooperative or its subsidiary.
52-42 (b) No provision of this subtitle may interfere with or be
52-43 deemed to abrogate the rights or obligations of a party under a
52-44 contract or an agreement concerning certificated service areas.
52-45 Sec. 41.102. ACCESS TO WHOLESALE MARKET. Nothing in this
52-46 subtitle shall limit the access of an electric cooperative or its
52-47 subsidiary, either on its own behalf or on behalf of its customers,
52-48 to the wholesale electric market.
52-49 Sec. 41.103. PROTECTION OF BONDHOLDERS. Nothing in this
52-50 subtitle or any rule adopted under this subtitle shall impair
52-51 contracts, covenants, or obligations between an electric
52-52 cooperative and its lenders and holders of bonds issued on behalf
52-53 of or by the electric cooperative.
52-54 Sec. 41.104. TAX-EXEMPT STATUS. Nothing in this subtitle
52-55 may impair the tax-exempt status of electric cooperatives, nor
52-56 shall anything in this subtitle compel any electric cooperative to
52-57 use its facilities in a manner which violates any contractual
52-58 provisions, bond covenants, or other restrictions applicable to
52-59 facilities financed by tax-exempt or federally insured or
52-60 guaranteed debt.
52-61 SECTION 34. Section 252.022, Local Government Code, is
52-62 amended by adding Subsection (c) to read as follows:
52-63 (c) This chapter does not apply to expenditures by a
52-64 municipally owned electric or gas utility or unbundled divisions of
52-65 a municipally owned electric or gas utility in connection with any
52-66 purchases by the municipally owned utility or divisions of a
52-67 municipally owned utility made in accordance with procurement
52-68 procedures adopted by a resolution of the body vested with
52-69 authority for management and operation of the municipally owned
53-1 utility or its divisions that sets out the public purpose to be
53-2 achieved by such procedures. This subsection shall not be deemed
53-3 to exempt a municipally owned utility from any other applicable
53-4 statute, charter provision, or ordinance.
53-5 SECTION 35. Section 272.001, Local Government Code, is
53-6 amended by adding Subsection (j) to read as follows:
53-7 (j) This section does not apply to sales or exchanges of
53-8 land owned by a municipality operating a municipally owned electric
53-9 or gas utility if the land is held or managed by the municipally
53-10 owned utility, or by a division of the municipally owned electric
53-11 or gas utility that constitutes the unbundled electric or gas
53-12 operations of the utility, provided that the governing body of the
53-13 municipally owned utility shall adopt a resolution stating the
53-14 conditions and circumstances for the sale or exchange and the
53-15 public purpose that will be achieved by the sale or exchange. For
53-16 purposes of this subsection, "municipally owned utility" includes a
53-17 river authority engaged in the generation, transmission, or
53-18 distribution of electric energy to the public, and "unbundled"
53-19 operations are those operations of the utility that have, in the
53-20 discretion of the utility's governing body, been functionally
53-22 SECTION 36. Subsection (c), Section 402.002, Local
53-23 Government Code, is amended to read as follows:
53-24 (c) The municipality may manufacture its own electricity,
53-25 gas, or anything else needed or used by the public. It may
53-26 purchase, and make contracts for the purchase of, gas, electricity,
53-27 oil, or any other commodity or article used by the public and may
53-28 sell it to the public on terms as provided by the municipal
53-29 charter, ordinance, or resolution of the governing body of the
53-30 municipally owned utility.
53-31 SECTION 37. Subchapter D, Chapter 551, Government Code, is
53-32 amended by adding Section 551.086 to read as follows:
53-33 Sec. 551.086. CERTAIN PUBLIC POWER UTILITIES: COMPETITIVE
53-34 MATTERS. (a) Notwithstanding anything in this chapter to the
53-35 contrary, the rules provided by this section apply to competitive
53-36 matters of a public power utility.
53-37 (b) In this section:
53-38 (1) "Public power utility" means an entity providing
53-39 electric or gas utility services that is subject to the provisions
53-40 of this chapter.
53-41 (2) "Public power utility governing body" means the
53-42 board of trustees or other applicable governing body, including a
53-43 city council, of a public power utility.
53-44 (3)(A) "Competitive matter" means a utility-related
53-45 matter that the public power utility governing body in good faith
53-46 determines, by a vote under this section: (i) is related to the
53-47 public power utility's competitive activity, including commercial
53-48 information and (ii) would, if disclosed, give advantage to
53-49 competitors or prospective competitors.
53-50 (B) The following categories of information
53-51 shall not be deemed to be competitive matters:
53-52 (i) information relating to the provision
53-53 of distribution access service, including the terms and conditions
53-54 of such service and the rates charged for the service but not
53-55 including information concerning utility-related services or
53-56 products that are competitive;
53-57 (ii) information relating to the provision
53-58 of transmission service that is required to be filed with the
53-59 Public Utility Commission of Texas, subject to any confidentiality
53-60 provided for under the rules of the commission;
53-61 (iii) information for the distribution
53-62 system pertaining to reliability and continuity of service, to the
53-63 extent not security-sensitive, that relates to emergency
53-64 management, identification of critical loads such as hospitals and
53-65 police, records of interruption, and distribution feeder standards;
53-66 (iv) any substantive rule of general
53-67 applicability regarding service offerings, service regulation,
53-68 customer protections, or customer service adopted by the public
53-69 power utility as authorized by law;
54-1 (v) aggregate information reflecting
54-2 receipts or expenditures of funds of the public power utility, of
54-3 the type that would be included in audited financial statements;
54-4 (vi) information relating to equal
54-5 employment opportunities for minority groups, as filed with local,
54-6 state, or federal agencies;
54-7 (vii) information relating to the public
54-8 power utility's performance in contracting with minority business
54-10 (viii) information relating to nuclear
54-11 decommissioning trust agreements, of the type required to be
54-12 included in audited financial statements;
54-13 (ix) information relating to the amount
54-14 and timing of any transfer to an owning city's general fund;
54-15 (x) information relating to environmental
54-16 compliance as required to be filed with any local, state, or
54-17 national environmental authority, subject to any confidentiality
54-18 provided under the rules of such authorities;
54-19 (xi) names of public officers of the
54-20 public power utility and the voting records of such officers for
54-21 all matters other than those within the scope of a competitive
54-22 resolution provided for by this section;
54-23 (xii) a description of the public power
54-24 utility's central and field organization, including the established
54-25 places at which the public may obtain information, submit
54-26 information and requests, or obtain decisions and the
54-27 identification of employees from whom the public may obtain
54-28 information, submit information or requests, or obtain decisions;
54-30 (xiii) information identifying the general
54-31 course and method by which the public power utility's functions are
54-32 channeled and determined, including the nature and requirements of
54-33 all formal and informal policies and procedures.
54-34 (c) This chapter does not require a public power utility
54-35 governing body to conduct an open meeting to deliberate, vote, or
54-36 take final action on any competitive matter, as that term is
54-37 defined in Subsection (b)(3). Before a public power utility
54-38 governing body may deliberate, vote, or take final action on any
54-39 such competitive matter in a closed meeting, the public power
54-40 utility governing body must first make a good-faith determination,
54-41 by majority vote of its members, that such matter is a competitive
54-42 matter that satisfies the requirements of Subsection (b)(3). The
54-43 vote shall be taken during the closed meeting and be included in
54-44 the certified agenda or tape recording of the closed meeting. If a
54-45 public power utility governing body fails to determine by such vote
54-46 that the matter satisfies the requirements of Subsection (b)(3),
54-47 the public power utility governing body may not deliberate or take
54-48 any further action on the matter in the closed meeting. This
54-49 section does not limit the right of a public power utility
54-50 governing body to hold a closed session pursuant to any other
54-51 exception provided for in this chapter.
54-52 (d) For purposes of Section 551.041, the notice of the
54-53 subject matter of an item that may be considered as a competitive
54-54 matter under this section is required to contain no more than a
54-55 general representation of the subject matter to be considered, such
54-56 that the competitive activity of the public power utility with
54-57 respect to the issue in question is not compromised or disclosed.
54-58 (e) With respect to municipally owned utilities subject to
54-59 this section, this section shall apply whether or not the
54-60 municipally owned utility has adopted customer choice or serves in
54-61 a multiply certificated service area under the Utilities Code.
54-62 (f) Nothing in this section is intended to preclude the
54-63 application of the enforcement and remedies provisions of
54-64 Subchapter G.
54-65 SECTION 38. Subchapter C, Chapter 552, Government Code, is
54-66 amended by adding Section 552.131 to read as follows:
54-67 Sec. 552.131. EXCEPTION: PUBLIC POWER UTILITY COMPETITIVE
54-68 MATTERS. (a) In this section:
54-69 (1) "Public power utility" means an entity providing
55-1 electric or gas utility services that is subject to the provisions
55-2 of this chapter.
55-3 (2) "Public power utility governing body" means the
55-4 board of trustees or other applicable governing body, including a
55-5 city council, of a public power utility.
55-6 (3)(A) "Competitive matter" means a utility-related
55-7 matter which the public power utility governing body in good faith
55-8 determines by a vote under this section: (i) is related to the
55-9 public power utility's competitive activity, including commercial
55-10 information; and (ii) would, if disclosed, give advantage to
55-11 competitors or prospective competitors.
55-12 (B) The following categories of information
55-13 shall not be deemed to be competitive matters:
55-14 (i) information relating to the provision
55-15 of distribution access service, including the terms and conditions
55-16 of such service and the rates charged for the service but not
55-17 including information concerning utility related services or
55-18 products that are competitive;
55-19 (ii) information relating to the provision
55-20 of transmission service that is required to be filed with the
55-21 Public Utility Commission of Texas, subject to any confidentiality
55-22 provided for under the rules of the commission;
55-23 (iii) information for the distribution
55-24 system pertaining to reliability and continuity of service, to the
55-25 extent not security-sensitive, that relates to emergency
55-26 management, identification of critical loads such as hospitals and
55-27 police, records of interruption, and distribution feeder standards;
55-28 (iv) any substantive rule of general
55-29 applicability regarding service offerings, service regulation,
55-30 customer protections, or customer service adopted by the public
55-31 power utility as authorized by law;
55-32 (v) aggregate information reflecting
55-33 receipts or expenditures of funds of the public power utility, of
55-34 the type that would be included in audited financial statements;
55-35 (vi) information relating to equal
55-36 employment opportunities for minority groups, as filed with local,
55-37 state, or federal agencies;
55-38 (vii) information relating to the public
55-39 power utility's performance in contracting with minority business
55-41 (viii) information relating to nuclear
55-42 decommissioning trust agreements, of the type required to be
55-43 included in audited financial statements;
55-44 (ix) information relating to the amount
55-45 and timing of any transfer to an owning city's general fund;
55-46 (x) information relating to environmental
55-47 compliance as required to be filed with any local, state, or
55-48 national environmental authority, subject to any confidentiality
55-49 provided under the rules of such authorities;
55-50 (xi) names of public officers of the
55-51 public power utility and the voting records of such officers for
55-52 all matters other than those within the scope of a competitive
55-53 resolution provided for by this section;
55-54 (xii) a description of the public power
55-55 utility's central and field organization, including the established
55-56 places at which the public may obtain information, submit
55-57 information and requests, or obtain decisions and the
55-58 identification of employees from whom the public may obtain
55-59 information, submit information or requests, or obtain decisions;
55-61 (xiii) information identifying the general
55-62 course and method by which the public power utility's functions are
55-63 channeled and determined, including the nature and requirements of
55-64 all formal and informal policies and procedures.
55-65 (b) Information or records are excepted from the
55-66 requirements of Section 552.021 if the information or records are
55-67 reasonably related to a competitive matter, as defined in this
55-68 section. Such information or records include the text of any
55-69 resolution of the public power utility governing body determining
56-1 which issues, activities, or matters constitute competitive
56-2 matters. Information or records of a municipally owned utility
56-3 that are reasonably related to a competitive matter are not subject
56-4 to disclosure under this chapter, whether or not, under the
56-5 Utilities Code, the municipally owned utility has adopted customer
56-6 choice or serves in a multiply certificated service area. This
56-7 section does not limit the right of a public power utility
56-8 governing body to withhold from disclosure information deemed to be
56-9 within the scope of any other exception provided for in this
56-10 chapter, subject to the provisions of this chapter.
56-11 (c) In connection with any request for an opinion of the
56-12 attorney general under Section 552.301 with respect to information
56-13 alleged to fall under this exception, in rendering a written
56-14 opinion under Section 552.306 the attorney general shall find the
56-15 requested information to be outside the scope of this exception
56-16 only if the attorney general determines, based on the information
56-17 provided in connection with the request: (i) that the public power
56-18 utility governing body has failed to act in good faith in making
56-19 the determination that the issue, matter, or activity in question
56-20 is a competitive matter; or (ii) that the information or records
56-21 sought to be withheld are not reasonably related to a competitive
56-23 SECTION 39. Subsection (d), Section 791.011, Government
56-24 Code, is amended to read as follows:
56-25 (d) An interlocal contract must:
56-26 (1) be authorized by the governing body of each party
56-27 to the contract; however, if a party to the contract is a
56-28 municipally owned electric utility, the governing body may
56-29 establish procedures for entering into interlocal contracts that do
56-30 not exceed $100,000 without requiring the approval of the governing
56-32 (2) state the purpose, terms, rights, and duties of
56-33 the contracting parties; and
56-34 (3) specify that each party paying for the performance
56-35 of governmental functions or services must make those payments from
56-36 current revenues available to the paying party.
56-37 SECTION 40. Subchapter A, Chapter 2256, Government Code, is
56-38 amended by adding Section 2256.0201 to read as follows:
56-39 Sec. 2256.0201. AUTHORIZED INVESTMENTS; MUNICIPAL UTILITY.
56-40 (a) A municipality that owns a municipal electric utility that is
56-41 engaged in the distribution and sale of electric energy or natural
56-42 gas to the public may enter into a hedging contract and related
56-43 security and insurance agreements in relation to fuel oil, natural
56-44 gas, and electric energy to protect against loss due to price
56-45 fluctuations. A hedging transaction must comply with the
56-46 regulations of the Commodity Futures Trading Commission and the
56-47 Securities and Exchange Commission. If there is a conflict between
56-48 the municipal charter of the municipality and this chapter, this
56-49 chapter prevails.
56-50 (b) A payment by a municipally owned electric or gas utility
56-51 under a hedging contract or related agreement in relation to fuel
56-52 supplies or fuel reserves is a fuel expense, and the utility may
56-53 credit any amounts it receives under the contract or agreement
56-54 against fuel expenses.
56-55 (c) The governing body of a municipally owned electric or
56-56 gas utility or the body vested with power to manage and operate the
56-57 municipally owned electric or gas utility may set policy regarding
56-58 hedging transactions.
56-59 (d) In this section, "hedging" means the buying and selling
56-60 of fuel oil, natural gas, and electric energy futures or options or
56-61 similar contracts on those commodity futures as a protection
56-62 against loss due to price fluctuation.
56-63 SECTION 41. Subsections (a), (c), and (d), Section 52.133,
56-64 Natural Resources Code, are amended to read as follows:
56-65 (a) Each oil or gas lease covering land leased by the board,
56-66 by a board for lease [ other than the Board for Lease of University
56-67 Lands], or by the surface owner of land under which the state owns
56-68 the minerals, commonly referred to as Relinquishment Act land,
56-69 which shall be subject to approval by the commissioner before it is
57-1 effective, shall include a provision granting the board authorized
57-2 to lease the land or the owner of the soil of Relinquishment Act
57-3 land and the commissioner authority to take their royalty in kind,
57-4 and the commissioner and the boards for lease may include any other
57-5 reasonable provisions that are not inconsistent with this section.
57-6 (c) The commissioner, the owner of the soil under Subchapter
57-7 F [ of this chapter], or the commissioner[ ,] acting on the behalf of
57-8 and at the direction of an owner of the soil under Subchapter F [ of
57-9 this chapter], the board, or a board for lease, or at the direction
57-10 of the Board for Lease of University Lands, may negotiate and
57-11 execute contracts or any other instruments or agreements necessary
57-12 to dispose of or enhance their portion of the royalty taken in
57-13 kind, including contracts for sale, purchase, transportation, and
57-14 storage and including insurance contracts or other agreements, to
57-15 secure or guarantee payment.
57-16 (d) The commissioner, the owner of the soil under Subchapter
57-17 F, or the commissioner acting on behalf of and at the direction of
57-18 an owner of the soil under Subchapter F, the board, or a board for
57-19 lease, may negotiate and execute contracts or any other instruments
57-20 or agreements necessary to convert that portion of the royalty
57-21 taken in kind into other forms of energy, including electricity.
57-22 [ This section does not apply to or have any effect on the Board for
57-23 Lease of University Lands or any lease executed on university
57-25 SECTION 42. Section 53.026, Natural Resources Code, is
57-26 amended to read as follows:
57-27 Sec. 53.026. In Kind Royalty. (a) The commissioner or the
57-28 commissioner acting on behalf of and at the direction of the board
57-29 or a board for lease may negotiate and execute a contract or any
57-30 other instrument or agreement necessary to dispose of or enhance
57-31 their portion of the royalty taken in kind, including contracts [ a
57-32 contract] for sale, purchase, transportation, or storage.
57-33 (b) The commissioner or the commissioner acting on behalf of
57-34 and at the direction of the board or a board for lease may
57-35 negotiate and execute a contract or any other instrument or
57-36 agreement necessary to convert that portion of the royalty taken in
57-37 kind to other forms of energy, including electricity.
57-38 (c) This section shall not be construed to surrender or in
57-39 any way affect the right of the state under an existing or future
57-40 lease to receive monetary royalty from its lessee.
57-41 SECTION 43. Section 53.077, Natural Resources Code, is
57-42 amended to read as follows:
57-43 Sec. 53.077. In Kind Royalty. (a) The commissioner, each
57-44 owner of the soil under this subchapter, or the commissioner acting
57-45 on the behalf of and at the direction of an owner of the soil under
57-46 this subchapter may negotiate and execute a contract or any other
57-47 instrument or agreement necessary to dispose of or enhance their
57-48 portion of the royalty taken in kind, including a contract for
57-49 sale, transportation, or storage.
57-50 (b) The commissioner, each owner of the soil under this
57-51 subchapter, or the commissioner acting on behalf of and at the
57-52 direction of the owner of the soil under this subchapter may
57-53 negotiate and execute a contract or any other instrument or
57-54 agreement necessary to convert that portion of the royalty taken in
57-55 kind to other forms of energy, including electricity.
57-56 (c) This section shall not be construed to surrender or in
57-57 any way affect the right of the state or the owner of the soil
57-58 under an existing or future lease to receive monetary royalty from
57-59 its lessee.
57-60 SECTION 44. Chapter 245, Acts of the 67th Legislature,
57-61 Regular Session, 1981 (Article 717p, Vernon's Texas Civil
57-62 Statutes), is amended by adding Section 4C to read as follows:
57-63 Sec. 4C. (a) This section applies only to a river authority
57-64 that is engaged in the distribution and sale of electric energy to
57-65 the public.
57-66 (b) Notwithstanding any other law, a river authority may:
57-67 (1) provide transmission services, as defined by the
57-68 Utilities Code or the Public Utility Commission of Texas, on a
57-69 regional basis to any eligible transmission customer at any
58-1 location within or outside the boundaries of the river authority;
58-3 (2) acquire, including by lease-purchase; lease from
58-4 or to any person; finance; construct; rebuild; operate; or sell
58-5 electric transmission facilities at any location within or outside
58-6 the boundaries of the river authority; provided, however, that
58-7 nothing in this section shall:
58-8 (A) allow a river authority to construct
58-9 transmission facilities to an ultimate consumer of electricity to
58-10 enable an ultimate consumer to bypass the transmission or
58-11 distribution facilities of its existing provider; or
58-12 (B) relieve a river authority from an obligation
58-13 to comply with the provisions of the Utilities Code concerning a
58-14 certificate of convenience and necessity for a transmission
58-16 SECTION 45. Sections 1 and 2, Article 1115a, Revised
58-17 Statutes, are amended to read as follows:
58-18 Sec. 1. This article applies only to a home-rule
58-19 municipality that owns an electric utility system, that by
58-20 ordinance or charter elects to have the management and control of
58-21 the system governed by a board of trustees [ this article], and
58-23 (1) has outstanding obligations payable in whole or
58-24 part [ solely] from and secured by a lien on and pledge of net
58-25 revenues of the system; or
58-26 (2) issues obligations that are payable in whole or
58-27 part [ solely] from and secured by a lien on and pledge of the net
58-28 revenues of the system and that are approved by the attorney
58-30 Sec. 2. A municipality by ordinance may transfer management
58-31 and control of the electric utility system to a [ five-member] board
58-32 of trustees appointed by the municipality's governing body. The
58-33 municipality by ordinance shall determine [ set] the qualifications
58-34 for appointment to the board and the number of members. The
58-35 municipality may by ordinance vest the power to establish rates and
58-36 related terms and conditions for its municipally owned electric
58-37 utility in the board of trustees appointed under this section,
58-38 notwithstanding any charter provision to the contrary.
58-39 SECTION 46. Subsection (a), Section 151.0101, Tax Code, is
58-40 amended to read as follows:
58-41 (a) "Taxable services" means:
58-42 (1) amusement services;
58-43 (2) cable television services;
58-44 (3) personal services;
58-45 (4) motor vehicle parking and storage services;
58-46 (5) the repair, remodeling, maintenance, and
58-47 restoration of tangible personal property, except:
58-48 (A) aircraft;
58-49 (B) a ship, boat, or other vessel, other than:
58-50 (i) a taxable boat or motor as defined by
58-51 Section 160.001;
58-52 (ii) a sports fishing boat; or
58-53 (iii) any other vessel used for pleasure;
58-54 (C) the repair, maintenance, and restoration of
58-55 a motor vehicle; and
58-56 (D) the repair, maintenance, creation, and
58-57 restoration of a computer program, including its development and
58-58 modification, not sold by the person performing the repair,
58-59 maintenance, creation, or restoration service;
58-60 (6) telecommunications services;
58-61 (7) credit reporting services;
58-62 (8) debt collection services;
58-63 (9) insurance services;
58-64 (10) information services;
58-65 (11) real property services;
58-66 (12) data processing services;
58-67 (13) real property repair and remodeling;
58-68 (14) security services; [ and]
58-69 (15) telephone answering services; and
59-1 (16) a sale by a transmission and distribution
59-2 utility, as defined in Section 31.002, Utilities Code, of
59-3 transmission or delivery of service directly to an electricity
59-4 end-use customer whose consumption of electricity is subject to
59-5 taxation under this chapter.
59-6 SECTION 47. Subdivision (1), Section 182.021, Tax Code, is
59-7 amended to read as follows:
59-8 (1) "Utility company" means a person who owns or
59-9 operates a gas, electric light, electric power, or water works, or
59-10 water and light plant used for local sale or [ and] distribution
59-11 located within an incorporated city or town in this state or who is
59-12 a retail electric provider, as that term is defined in Section
59-13 31.002, Utilities Code, that makes local sales within an
59-14 incorporated city or town in this state. A person who owns an
59-15 electric light or electric power plant used for distribution but
59-16 who does not make retail sales to the ultimate consumer within an
59-17 incorporated city or town in this state is not included in this
59-19 SECTION 48. Subchapter B, Chapter 182, Tax Code, is amended
59-20 by adding Section 182.027 to read as follows:
59-21 Sec. 182.027. NO EXEMPTION. Notwithstanding anything to the
59-22 contrary in Chapter 161, Utilities Code, this subchapter applies to
59-23 a retail electric provider that is an organizational unit of an
59-24 electric cooperative organized under Chapter 161, Utilities Code,
59-25 that is subject to retail competition under Chapter 41, Utilities
59-27 SECTION 49. The following provisions are repealed:
59-28 (1) Section 12.104, Utilities Code;
59-29 (2) Chapter 34, Utilities Code;
59-30 (3) Subchapters F and G, Chapter 36, Utilities Code; and
59-31 (4) Section 37.058, Utilities Code.
59-32 SECTION 50. (a) Nothing in this Act shall restrict or limit
59-33 a municipality's historical right to control and receive reasonable
59-34 compensation for use of public streets, alleys, rights-of-way, or
59-35 other public property to convey or provide electricity.
59-36 (b) Nothing in this Act shall affect a retail electric
59-37 utility's right to provide electric service in accordance with its
59-38 certificate of public convenience and necessity. A certificate of
59-39 convenience and necessity may, however, be revoked or modified as
59-40 provided by Section 37.059, Utilities Code, and Section 37.060,
59-41 Utilities Code, as added by this Act.
59-42 SECTION 51. The Public Utility Commission of Texas shall
59-43 study and make recommendations by December 15, 2000, to the 77th
59-44 Legislature for additional legislation that would move to and
59-45 establish a competitive electric market on January 1, 2002, in
59-46 accordance with the changes in law made by this Act.
59-47 SECTION 52. No later than 180 days after the effective date
59-48 of this Act, the Public Utility Commission of Texas shall establish
59-49 rules and procedures for the securitization of stranded costs for
59-50 river authorities, as provided by Subdivision (2), Subsection (a),
59-51 Section 40.003, Utilities Code, as added by this Act, and for
59-52 electric cooperatives, as provided by Section 41.003, Utilities
59-54 SECTION 53. This Act takes effect September 1, 1999.
59-55 SECTION 54. The importance of this legislation and the
59-56 crowded condition of the calendars in both houses create an
59-57 emergency and an imperative public necessity that the
59-58 constitutional rule requiring bills to be read on three several
59-59 days in each house be suspended, and this rule is hereby suspended.
59-60 * * * * *