By: Sibley, et al. S.B. No. 7
A BILL TO BE ENTITLED
1-1 relating to electric utility restructuring and to the powers and
1-2 duties of the Public Utility Commission of Texas; providing civil
1-3 and administrative penalties; making an appropriation.
1-4 BE IT ENACTED BY THE LEGISLATURE OF THE STATE OF TEXAS:
1-5 SECTION 1. Section 11.003, Utilities Code, is amended to
1-6 read as follows:
1-7 Sec. 11.003. DEFINITIONS. In this title:
1-8 (1) "Affected person" means:
1-9 (A) a public utility or electric cooperative
1-10 affected by an action of a regulatory authority;
1-11 (B) a person whose utility service or rates are
1-12 affected by a proceeding before a regulatory authority; or
1-13 (C) a person who:
1-14 (i) is a competitor of a public utility
1-15 with respect to a service performed by the utility; or
1-16 (ii) wants to enter into competition with
1-17 a public utility.
1-18 (2) "Affiliate" means:
1-19 (A) a person who directly or indirectly owns or
1-20 holds at least five percent of the voting securities of a public
1-22 (B) a person in a chain of successive ownership
1-23 of at least five percent of the voting securities of a public
2-1 (C) a corporation that has at least five percent
2-2 of its voting securities owned or controlled, directly or
2-3 indirectly, by a public utility;
2-4 (D) a corporation that has at least five percent
2-5 of its voting securities owned or controlled, directly or
2-6 indirectly, by:
2-7 (i) a person who directly or indirectly
2-8 owns or controls at least five percent of the voting securities of
2-9 a public utility; or
2-10 (ii) a person in a chain of successive
2-11 ownership of at least five percent of the voting securities of a
2-12 public utility;
2-13 (E) a person who is an officer or director of a
2-14 public utility or of a corporation in a chain of successive
2-15 ownership of at least five percent of the voting securities of a
2-16 public utility; or
2-17 (F) a person determined to be an affiliate under
2-18 Section 11.006.
2-19 (3) "Allocation" means the division among
2-20 municipalities or among municipalities and unincorporated areas of
2-21 the plant, revenues, expenses, taxes, and reserves of a utility
2-22 used to provide public utility service in a municipality or for a
2-23 municipality and unincorporated areas.
2-24 (4) "Commission" means the Public Utility Commission
2-25 of Texas.
2-26 (5) "Commissioner" means a member of the Public
3-1 Utility Commission of Texas.
3-2 (6) "Cooperative corporation" means:
3-3 (A) an electric cooperative [
3-4 organized under Chapter 161 or a predecessor statute to Chapter 161
3-5 and operating under that chapter]; or
3-6 (B) a telephone cooperative corporation
3-7 organized under Chapter 162 or a predecessor statute to Chapter 162
3-8 and operating under that chapter.
3-9 (7) "Corporation" means a domestic or foreign
3-10 corporation, joint-stock company, or association, and each lessee,
3-11 assignee, trustee, receiver, or other successor in interest of the
3-12 corporation, company, or association, that has any of the powers or
3-13 privileges of a corporation not possessed by an individual or
3-14 partnership. The term does not include a municipal corporation or
3-15 electric cooperative, except as expressly provided by this title.
3-16 (8) "Counsellor" means the public utility counsel.
3-17 (9) "Electric cooperative" means:
3-18 (A) a corporation organized under Chapter 161 or
3-19 a predecessor statute to Chapter 161 and operating under that
3-21 (B) a corporation organized as an electric
3-22 cooperative in a state other than Texas that has obtained a
3-23 certificate of authority to conduct affairs in the State of Texas;
3-25 (C) a successor to an electric cooperative
3-26 created in accordance with a conversion plan approved by a vote of
4-1 the members of the electric cooperative before June 1, 1999.
4-2 (10) "Facilities" means all of the plant and equipment
4-3 of a public utility, and includes the tangible and intangible
4-4 property, without limitation, owned, operated, leased, licensed,
4-5 used, controlled, or supplied for, by, or in connection with the
4-6 business of the public utility.
4-7 (11) [ (10)] "Municipally owned utility" means a
4-8 utility owned, operated, and controlled by a municipality or by a
4-9 nonprofit corporation the directors of which are appointed by one
4-10 or more municipalities.
4-11 (12) [ (11)] "Office" means the Office of Public
4-12 Utility Counsel.
4-13 (13) [ (12)] "Order" means all or a part of a final
4-14 disposition by a regulatory authority in a matter other than
4-15 rulemaking, without regard to whether the disposition is
4-16 affirmative or negative or injunctive or declaratory. The term
4-18 (A) the issuance of a certificate of convenience
4-19 and necessity; and
4-20 (B) the setting of a rate.
4-21 (14) [ (13)] "Person" includes an individual, a
4-22 partnership of two or more persons having a joint or common
4-23 interest, a mutual or cooperative association, and a corporation,
4-24 but does not include an electric cooperative.
4-25 (15) [ (14)] "Proceeding" means a hearing,
4-26 investigation, inquiry, or other procedure for finding facts or
5-1 making a decision under this title. The term includes a denial of
5-2 relief or dismissal of a complaint.
5-3 (16) [ (15)] "Rate" includes:
5-4 (A) any compensation, tariff, charge, fare,
5-5 toll, rental, or classification that is directly or indirectly
5-6 demanded, observed, charged, or collected by a public utility for a
5-7 service, product, or commodity described in the definition of
5-8 utility in Section 31.002 or 51.002; and
5-9 (B) a rule, practice, or contract affecting the
5-10 compensation, tariff, charge, fare, toll, rental, or
5-12 (17) [ (16)] "Ratemaking proceeding" means[ :]
5-13 [ (A)] a proceeding in which a rate is changed[ ;
5-15 [ (B) a proceeding initiated under Chapter 34].
5-16 (18) [ (17)] "Regulatory authority" means either the
5-17 commission or the governing body of a municipality, in accordance
5-18 with the context.
5-19 (19) [ (18)] "Service" has its broadest and most
5-20 inclusive meaning. The term includes any act performed, anything
5-21 supplied, and any facilities used or supplied by a public utility
5-22 in the performance of the utility's duties under this title to its
5-23 patrons, employees, other public utilities, an electric
5-24 cooperative, and the public. The term also includes the
5-25 interchange of facilities between two or more public utilities.
5-26 The term does not include the printing, distribution, or sale of
6-1 advertising in a telephone directory.
6-2 (20) [ (19)] "Test year" means the most recent 12
6-3 months, beginning on the first day of a calendar or fiscal year
6-4 quarter, for which operating data for a public utility are
6-6 (21) [ (20)] "Trade association" means a nonprofit,
6-7 cooperative, and voluntarily joined association of business or
6-8 professional persons who are employed by public utilities or
6-9 utility competitors to assist the public utility industry, a
6-10 utility competitor, or the industry's or competitor's employees in
6-11 dealing with mutual business or professional problems and in
6-12 promoting their common interest.
6-13 SECTION 2. Section 12.005, Utilities Code, is amended to
6-14 read as follows:
6-15 Sec. 12.005. APPLICATION OF SUNSET ACT. The Public Utility
6-16 Commission of Texas is subject to Chapter 325, Government Code
6-17 (Texas Sunset Act). Unless continued in existence as provided by
6-18 that chapter or by Chapter 39, the commission is abolished and this
6-19 title expires September 1, 2005 [ 2001].
6-20 SECTION 3. Section 12.101, Utilities Code, is amended to
6-21 read as follows:
6-22 Sec. 12.101. COMMISSION EMPLOYEES. The commission shall
6-24 (1) an executive director; and
6-25 (2) [ a general counsel; and]
6-26 [ (3)] officers and other employees the commission
7-1 considers necessary to administer this title.
7-2 SECTION 4. Sections 12.151 and 12.152, Utilities Code, are
7-3 amended to read as follows:
7-4 Sec. 12.151. REGISTERED LOBBYIST. A person required to
7-5 register as a lobbyist under Chapter 305, Government Code, because
7-6 of the person's activities for compensation on behalf of a
7-7 profession related to the operation of the commission may not serve
7-8 as a commissioner [ or act as general counsel to the commission].
7-9 Sec. 12.152. Conflict of Interest. (a) A person is not
7-10 eligible for appointment as a commissioner [ or for employment as
7-11 the general counsel] or executive director of the commission if:
7-12 (1) the person serves on the board of directors of a
7-13 company that supplies fuel, utility-related services, or
7-14 utility-related products to regulated or unregulated electric or
7-15 telecommunications utilities; or
7-16 (2) the person or the person's spouse:
7-17 (A) is employed by or participates in the
7-18 management of a business entity or other organization that is
7-19 regulated by or receives funds from the commission;
7-20 (B) directly or indirectly owns or controls more
7-21 than a 10 percent interest or a pecuniary interest with a value
7-22 exceeding $10,000 in:
7-23 (i) a business entity or other
7-24 organization that is regulated by or receives funds from the
7-25 commission; or
7-26 (ii) a utility competitor, utility
8-1 supplier, or other entity affected by a commission decision in a
8-2 manner other than by the setting of rates for that class of
8-4 (C) uses or receives a substantial amount of
8-5 tangible goods, services, or funds from the commission, other than
8-6 compensation or reimbursement authorized by law for commission
8-7 membership, attendance, or expenses; or
8-8 (D) notwithstanding Paragraph (B), has an
8-9 interest in a mutual fund or retirement fund in which more than 10
8-10 percent of the fund's holdings at the time of appointment is in a
8-11 single utility, utility competitor, or utility supplier in this
8-12 state and the person does not disclose this information to the
8-13 governor, senate, commission, or other entity, as appropriate.
8-14 (b) A person otherwise ineligible because of Subsection
8-15 (a)(2)(B) may be appointed to the commission and serve as a
8-16 commissioner or may be employed as [ the general counsel or]
8-17 executive director if the person:
8-18 (1) notifies the attorney general and commission that
8-19 the person is ineligible because of Subsection (a)(2)(B); and
8-20 (2) divests the person or the person's spouse of the
8-21 ownership or control:
8-22 (A) before beginning service or employment; or
8-23 (B) if the person is already serving or
8-24 employed, within a reasonable time.
8-25 SECTION 5. Section 13.002, Utilities Code, is amended to
8-26 read as follows:
9-1 Sec. 13.002. APPLICATION OF SUNSET ACT. The Office of
9-2 Public Utility Counsel is subject to Chapter 325, Government Code
9-3 (Texas Sunset Act). Unless continued in existence as provided by
9-4 that chapter, the office is abolished and this chapter expires
9-5 September 1, 2005 [ 2001].
9-6 SECTION 6. Section 13.024, Utilities Code, is amended to
9-7 read as follows:
9-8 Sec. 13.024. Prohibited Acts. (a) The counsellor may not[ :]
9-9 [ (1)] have a direct or indirect interest in a utility
9-10 company regulated under this title[ ; or]
9-11 [ (2) provide legal services directly or indirectly to
9-12 or be employed in any capacity by a utility company regulated under
9-13 this title], its parent, or its subsidiary companies, corporations,
9-14 or cooperatives or a utility competitor, utility supplier, or other
9-15 entity affected in a manner other than by the setting of rates for
9-16 that class of customer.
9-17 (b) The prohibition under Subsection (a) applies during the
9-18 period of the counsellor's service [ and until the second
9-19 anniversary of the date the counsellor ceases to serve as
9-21 [ (c) This section does not prohibit a person from otherwise
9-22 engaging in the private practice of law after the person ceases to
9-23 serve as counsellor].
9-24 SECTION 7. Section 13.043, Utilities Code, is amended to
9-25 read as follows:
9-26 Sec. 13.043. PROHIBITION ON EMPLOYMENT OR REPRESENTATION.
10-1 (a) A former counsel may not make any communication to or
10-2 appearance before the commission or an officer or employee of the
10-3 commission before the second anniversary of the date the person
10-4 ceases to serve as counsel if the communication or appearance is
10-6 (1) on behalf of another person in connection with any
10-7 matter on which the person seeks official action; or
10-8 (2) with the intent to influence a commission decision
10-9 or action.
10-10 (b) A former counsel may not represent any person or receive
10-11 compensation for services rendered on behalf of any person
10-12 regarding a matter before the commission before the second
10-13 anniversary of the date the person ceases to serve as counsel.
10-14 (c) A person commits an offense if the person violates this
10-15 section. An offense under this subsection is a Class A
10-17 (d) An [ The counsellor or an] employee of the office may
10-19 (1) be employed by a public utility that was in the
10-20 scope of the [ counsellor's or] employee's official responsibility
10-21 while the [ counsellor or] employee was associated with the office;
10-23 (2) represent a person before the commission or a
10-24 court in a matter:
10-25 (A) in which the [ counsellor or] employee was
10-26 personally involved while associated with the office; or
11-1 (B) that was within the [ counsellor's or]
11-2 employee's official responsibility while the [ counsellor or]
11-3 employee was associated with the office.
11-4 (e) [ (b)] The prohibition of Subsection (d)(1) [ (a)(1)]
11-5 applies until the[ :]
11-6 [ (1) second anniversary of the date the counsellor
11-7 ceases to serve as a counsellor; and]
11-8 [ (2)] first anniversary of the date the employee's
11-9 employment with the office ceases.
11-10 (f) [ (c)] The prohibition of Subsection (d)(2) [ (a)(2)]
11-11 applies while an [ a counsellor or] employee of the office is
11-12 associated with the office and at any time after.
11-13 SECTION 8. Subsection (d), Section 14.101, Utilities Code,
11-14 is amended to read as follows:
11-15 (d) This section does not apply to:
11-16 (1) the purchase of a unit of property for
11-17 replacement; [ or]
11-18 (2) an addition to the facilities of a public utility
11-19 by construction; or
11-20 (3) transactions that facilitate unbundling, asset
11-21 valuation, minimization of ownership or control of generation
11-22 assets, or other purposes consistent with Chapter 39.
11-23 SECTION 9. Subsections (a) and (b), Section 16.001,
11-24 Utilities Code, are amended to read as follows:
11-25 (a) To defray the expenses incurred in the administration of
11-26 this title, an assessment is imposed on each public utility, retail
12-1 electric provider, and electric cooperative within the jurisdiction
12-2 of the commission that serves the ultimate consumer, including each
12-3 interexchange telecommunications carrier.
12-4 (b) An assessment under this section is equal to one-sixth
12-5 of one percent of the public utility's, retail electric provider's,
12-6 or electric cooperative's gross receipts from rates charged to the
12-7 ultimate consumer in this state.
12-8 SECTION 10. Section 31.002, Utilities Code, is amended to
12-9 read as follows:
12-10 Sec. 31.002. DEFINITIONS. In this subtitle:
12-11 (1) "Affiliated power generation company" means a
12-12 power generation company that is affiliated with or the successor
12-13 in interest of an electric utility certificated to serve an area.
12-14 (2) "Affiliated retail electric provider" means a
12-15 retail electric provider that is affiliated with or the successor
12-16 in interest of an electric utility certificated to serve an area.
12-17 (3) "Aggregation" includes the following:
12-18 (A) the purchase of electricity from a retail
12-19 electric provider by an electricity customer for its own use in
12-20 multiple locations; or
12-21 (B) the purchase of electricity by an
12-22 electricity customer as part of a voluntary association of
12-23 electricity customers.
12-24 (4) "Customer choice" means the freedom of a retail
12-25 customer to purchase electric services, either individually or
12-26 through voluntary aggregation with other retail customers, from the
13-1 provider or providers of the customer's choice and to choose among
13-2 various fuel types, energy efficiency programs, and renewable power
13-4 (5) "Electric Reliability Council of Texas" or "ERCOT"
13-5 means the area in Texas served by electric utilities, municipally
13-6 owned utilities, and electric cooperatives that is not
13-7 synchronously interconnected with electric utilities outside the
13-9 (6) "Electric utility" means a person or river
13-10 authority that owns or operates for compensation in this state
13-11 equipment or facilities to produce, generate, transmit, distribute,
13-12 sell, or furnish electricity in this state. The term includes a
13-13 lessee, trustee, or receiver of an electric utility and a
13-14 recreational vehicle park owner who does not comply with Subchapter
13-15 C, Chapter 184, with regard to the metered sale of electricity at
13-16 the recreational vehicle park. The term does not include:
13-17 (A) a municipal corporation;
13-18 (B) a qualifying facility;
13-19 (C) a power generation company;
13-20 (D) an exempt wholesale generator;
13-21 (E) [ (D)] a power marketer;
13-22 (F) [ (E)] a corporation described by Section
13-23 32.053 to the extent the corporation sells electricity exclusively
13-24 at wholesale and not to the ultimate consumer; or
13-25 (G) an electric cooperative;
13-26 (H) a retail electric provider;
14-1 (I) this state or an agency of this state; or
14-2 (J) [ (F)] a person not otherwise an electric
14-3 utility who:
14-4 (i) furnishes an electric service or
14-5 commodity only to itself, its employees, or its tenants as an
14-6 incident of employment or tenancy, if that service or commodity is
14-7 not resold to or used by others;
14-8 (ii) owns or operates in this state
14-9 equipment or facilities to produce, generate, transmit, distribute,
14-10 sell, or furnish electric energy to an electric utility, if the
14-11 equipment or facilities are used primarily to produce and generate
14-12 electric energy for consumption by that person; or
14-13 (iii) owns or operates in this state a
14-14 recreational vehicle park that provides metered electric service in
14-15 accordance with Subchapter C, Chapter 184.
14-16 (7) [ (2)] "Exempt wholesale generator" means a person
14-17 who is engaged directly or indirectly through one or more
14-18 affiliates exclusively in the business of owning or operating all
14-19 or part of a facility for generating electric energy and selling
14-20 electric energy at wholesale and who:
14-21 (A) does not own a facility for the transmission
14-22 of electricity, other than an essential interconnecting
14-23 transmission facility necessary to effect a sale of electric energy
14-24 at wholesale; and
14-25 (B) has:
14-26 (i) applied to the Federal Energy
15-1 Regulatory Commission for a determination under 15 U.S.C. Section
15-2 79z-5a; or
15-3 (ii) registered as an exempt wholesale
15-4 generator as required by Section 35.032.
15-5 (8) "Freeze period" means the period beginning on
15-6 January 1, 1999, and ending on December 31, 2001.
15-7 (9) "Independent system operator" means an entity
15-8 supervising the collective transmission facilities of a power
15-9 region that is charged with nondiscriminatory coordination of
15-10 market transactions, systemwide transmission planning, and network
15-12 (10) "Power generation company" means a person who:
15-13 (A) generates electricity that is intended to be
15-14 sold at wholesale;
15-15 (B) does not own a transmission or distribution
15-16 facility in this state other than an essential interconnecting
15-17 facility, a facility not dedicated to public use, or a facility
15-18 otherwise excluded from the definition of "electric utility" under
15-19 Subdivision (6); and
15-20 (C) does not have a certificated service area,
15-21 although its affiliated electric utility or transmission and
15-22 distribution utility may have a certificated service area.
15-23 (11) [ (3)] "Power marketer" means a person who:
15-24 (A) becomes an owner of electric energy in this
15-25 state for the purpose of selling the electric energy at wholesale;
15-26 (B) does not own generation, transmission, or
16-1 distribution facilities in this state;
16-2 (C) does not have a certificated service area;
16-4 (D) has:
16-5 (i) been granted authority by the Federal
16-6 Energy Regulatory Commission to sell electric energy at
16-7 market-based rates; or
16-8 (ii) registered as a power marketer under
16-9 Section 35.032.
16-10 (12) "Power region" means a contiguous geographical
16-11 area which is a distinct region of the North American Electric
16-12 Reliability Council.
16-13 (13) [ (4)] "Qualifying cogenerator" and "qualifying
16-14 small power producer" have the meanings assigned those terms by 16
16-15 U.S.C. Sections 796(18)(C) and 796(17)(D). A qualifying
16-16 cogenerator that provides electricity to the purchaser of the
16-17 cogenerator's thermal output is not for that reason considered to
16-18 be a retail electric provider or a power generation company.
16-19 (14) [ (5)] "Qualifying facility" means a qualifying
16-20 cogenerator or qualifying small power producer.
16-21 (15) [ (6)] "Rate" includes a compensation, tariff,
16-22 charge, fare, toll, rental, or classification that is directly or
16-23 indirectly demanded, observed, charged, or collected by an electric
16-24 utility for a service, product, or commodity described in the
16-25 definition of electric utility in this section and a rule,
16-26 practice, or contract affecting the compensation, tariff, charge,
17-1 fare, toll, rental, or classification that must be approved by a
17-2 regulatory authority.
17-3 (16) "Retail customer" means the separately metered
17-4 end-use customer who purchases and ultimately consumes electricity.
17-5 (17) "Retail electric provider" means a person that
17-6 sells electric energy to retail customers in this state. A retail
17-7 electric provider may not own or operate generation assets.
17-8 (18) "Separately metered" means metered by an
17-9 individual meter that is used to measure electric energy
17-10 consumption by a retail customer and for which the customer is
17-11 directly billed by a utility or retail electric provider.
17-12 (19) "Transmission and distribution utility" means a
17-13 person or river authority that owns or operates for compensation in
17-14 this state equipment or facilities to transmit or distribute
17-15 electricity, except for facilities necessary to interconnect a
17-16 generation facility with the transmission or distribution network,
17-17 a facility not dedicated to public use, or a facility otherwise
17-18 excluded from the definition of "electric utility" under
17-19 Subdivision (6), in a qualifying power region certified pursuant to
17-20 Section 39.152 but does not include a municipally owned utility or
17-21 an electric cooperative.
17-22 (20) [ (7)] "Transmission service" includes
17-23 construction or enlargement of facilities, transmission over
17-24 distribution facilities, control area services, scheduling
17-25 resources, regulation services, reactive power support, voltage
17-26 control, provision of operating reserves, and any other associated
18-1 electrical service the commission determines appropriate.
18-2 SECTION 11. Subchapter A, Chapter 32, Utilities Code, is
18-3 amended by adding Section 32.0015 to read as follows:
18-4 Sec. 32.0015. REGULATION OF SUCCESSOR ELECTRIC UTILITY OR
18-5 ELECTRIC COOPERATIVE. If an electric utility purchases, acquires,
18-6 merges, or consolidates with or acquires 50 percent or more of the
18-7 stock of an electric utility or electric cooperative, the
18-8 commission shall regulate the successor electric utility or
18-9 electric cooperative in the same manner that the commission would
18-10 regulate the entity that was subject to the stricter regulation
18-11 before the purchase, acquisition, merger, or consolidation.
18-12 SECTION 12. Sections 32.051 and 32.052, Utilities Code, are
18-13 amended to read as follows:
18-14 Sec. 32.051. Exemption of River Authority From Wholesale
18-15 Rate Regulation. Notwithstanding any other provision of this
18-16 title, the commission may not directly or indirectly regulate
18-17 revenue requirements, rates, fuel costs, fuel charges, or fuel
18-18 acquisitions that are related to the generation and sale of
18-19 electricity at wholesale, and not to ultimate consumers, by a river
18-20 authority operating a steam generating plant on or before
18-21 January 1, 1999.
18-22 Sec. 32.052. Ability of Certain River Authorities to
18-23 Construct Improvements. A river authority operating a steam
18-24 generating plant on or before January 1, 1999, may acquire,
18-25 finance, construct, rebuild, repower, and use new or existing power
18-26 plants, equipment, transmission lines, or other assets to sell
19-1 electricity exclusively at wholesale to:
19-2 (1) a purchaser in San Saba, Llano, Burnet, Travis,
19-3 Bastrop, Blanco, Colorado, or Fayette County; or
19-4 (2) a purchaser in an area served by the river
19-5 authority on January 1, 1975.
19-6 SECTION 13. Section 32.053, Utilities Code, is amended by
19-7 amending Subsections (b) and (f) and adding Subsections (g) and (h)
19-8 to read as follows:
19-9 (b) Notwithstanding a river authority's enabling legislation
19-10 or Chapter 245, Acts of the 67th Legislature, Regular Session, 1981
19-11 (Article 717p, Vernon's Texas Civil Statutes), a corporation may:
19-12 (1) acquire, finance, construct, rebuild, repower,
19-13 operate, or sell a facility directly related to the generation of
19-14 electricity; [ and]
19-15 (2) sell, at wholesale only, the output of the
19-16 facility to a purchaser, other than an ultimate consumer, at any
19-17 location in this state; and
19-18 (3) purchase and sell electricity, at wholesale only,
19-19 to a purchaser, other than an ultimate consumer, at any location in
19-20 this state.
19-21 (f) The proceeds from the sale of bonds or other obligations
19-22 the interest on which is exempt from taxation and that are issued
19-23 by a corporation or river authority subject to this section, other
19-24 than a bond or obligation available to an investor-owned utility or
19-25 exempt wholesale generator, may not be used by the corporation[ ,
19-26 and may not have been used,] to finance the construction or
20-1 acquisition of or the rebuilding or repowering of a facility for
20-2 the generation of electricity by the corporation.
20-3 (g) Notwithstanding any other law, the board of directors of
20-4 a river authority may sell, lease, loan, or otherwise transfer
20-5 some, all, or substantially all of the electric generation property
20-6 of the river authority to a nonprofit corporation authorized under
20-7 this section or Chapter 245, Acts of the 67th Legislature, Regular
20-8 Session, 1981 (Article 717p, Vernon's Texas Civil Statutes). The
20-9 property transfer shall be made pursuant to terms and conditions
20-10 approved by the board of directors of the river authority.
20-11 (h) Subsections (a)-(f) do not apply to a corporation
20-12 created pursuant to Chapter 245, Acts of the 67th Legislature,
20-13 Regular Session, 1981 (Article 717p, Vernon's Texas Civil
20-14 Statutes), to serve an area described in Section 32.052.
20-15 SECTION 14. Section 35.001, Utilities Code, is amended to
20-16 read as follows:
20-17 Sec. 35.001. Definition. In this subchapter, "electric
20-18 utility" includes a municipally owned utility and an electric
20-20 SECTION 15. Section 35.004, Utilities Code, is amended to
20-21 read as follows:
20-22 Sec. 35.004. PROVISION OF TRANSMISSION SERVICE. (a) An
20-23 electric utility or transmission and distribution utility that owns
20-24 or operates transmission facilities shall provide wholesale
20-25 transmission service at rates and terms, including terms of access,
20-26 that are comparable to the rates and terms of the utility's own use
21-1 of its system.
21-2 (b) The commission shall ensure that an electric utility or
21-3 transmission and distribution utility provides nondiscriminatory
21-4 access to wholesale transmission service for qualifying facilities,
21-5 exempt wholesale generators, power marketers, power generation
21-6 companies, retail electric providers, and other electric utilities
21-7 or transmission and distribution utilities.
21-8 (c) When an electric utility, electric cooperative, or
21-9 transmission and distribution utility provides wholesale
21-10 transmission service within ERCOT at the request of a third party,
21-11 the commission shall ensure that the utility recovers the utility's
21-12 reasonable costs in providing wholesale transmission services
21-13 necessary for the transaction from the entity for which the
21-14 transmission is provided so that the utility's other customers do
21-15 not bear the costs of the service.
21-16 (d) The commission shall price wholesale transmission
21-17 services within ERCOT based on the postage stamp method of pricing
21-18 under which a transmission-owning utility's rate is based on the
21-19 ERCOT utilities' combined annual costs of transmission divided by
21-20 the total demand placed on the combined transmission systems of all
21-21 such transmission-owning utilities within a power region. An
21-22 electric utility subject to the freeze period imposed by Section
21-23 39.052 may treat transmission costs in excess of transmission
21-24 revenues during the freeze period as an expense for purposes of
21-25 determining annual costs in the annual report filed pursuant to
21-26 Section 39.257. Notwithstanding Section 36.201, the commission may
22-1 approve rates that may be periodically adjusted to ensure timely
22-2 recovery of transmission investment.
22-3 (e) The commission shall ensure that ancillary services
22-4 necessary to facilitate the transmission of electric energy are
22-5 available at reasonable prices with terms and conditions that are
22-6 not unreasonably preferential, prejudicial, discriminatory,
22-7 predatory, or anticompetitive. In this subsection, "ancillary
22-8 services" means services necessary to facilitate the transmission
22-9 of electric energy including load following, standby power, backup
22-10 power, reactive power, and such other services as the commission
22-11 may determine by rule.
22-12 SECTION 16. Subsection (b), Section 35.005, Utilities Code,
22-13 is amended to read as follows:
22-14 (b) The commission may require transmission service at
22-15 wholesale, including the construction or enlargement of a
22-16 facility[ , in a proceeding not related to approval of an integrated
22-17 resource plan].
22-18 SECTION 17. Section 35.033, Utilities Code, is amended to
22-19 read as follows:
22-20 Sec. 35.033. Affiliate Wholesale Provider. An affiliate of
22-21 an electric utility may be an exempt wholesale generator or power
22-22 marketer and may sell electric energy to its affiliated electric
22-23 utility in accordance with [ Chapter 34 and other] laws governing
22-24 wholesale sales of electric energy.
22-25 SECTION 18. Section 35.034, Utilities Code, is amended by
22-26 adding Subsection (c) to read as follows:
23-1 (c) For purposes of this section, "electric utility" does
23-2 not include a river authority.
23-3 SECTION 19. Section 35.035, Utilities Code, is amended by
23-4 adding Subsection (d) to read as follows:
23-5 (d) For purposes of this section, "electric utility" does
23-6 not include a river authority.
23-7 SECTION 20. Chapter 35, Utilities Code, is amended by adding
23-8 Subchapter D to read as follows:
23-9 SUBCHAPTER D. STATE AUTHORITY TO SELL OR CONVEY POWER
23-10 Sec. 35.101. DEFINITIONS. In this subchapter:
23-11 (1) "Commissioner" means the Commissioner of the
23-12 General Land Office.
23-13 (2) "Public retail customer" means a retail customer
23-14 that is an agency of this state, an institution of higher
23-15 education, a public school district, or a political subdivision of
23-16 this state.
23-17 Sec. 35.102. STATE AUTHORITY TO SELL OR CONVEY POWER. The
23-18 commissioner, acting on behalf of the state, may sell or otherwise
23-19 convey power directly to a public retail customer regardless of
23-20 whether the public retail customer is also classified as a
23-21 wholesale customer under other provisions of this title.
23-22 Sec. 35.103. ACCESS TO TRANSMISSION AND DISTRIBUTION
23-23 SYSTEMS; RATES. (a) Except as provided in Section 35.104, the
23-24 state is entitled to have access to all transmission and
23-25 distribution systems of all electric utilities, transmission and
23-26 distribution utilities, municipally owned utilities, and electric
24-1 cooperatives that serve public retail customers.
24-2 (b) An entity described by Subsection (a) shall provide any
24-3 utility service, including transmission, distribution, and other
24-4 services, to the state at the lowest applicable rate charged for
24-5 similar service to other customers.
24-6 Sec. 35.104. LIMIT IN CERTAIN AREAS. Sections 35.102,
24-7 35.103, and 35.105 shall not apply to the rates, retail service
24-8 area, facilities, or public retail customers of a municipally owned
24-9 electric utility that has not adopted customer choice or an
24-10 electric cooperative that has not adopted customer choice. In a
24-11 certificated service area of an electric utility in which customer
24-12 choice has not been introduced, the state may not engage in retail
24-13 transactions that exceed 2.5 percent of a retail electric utility's
24-14 total retail load.
24-15 Sec. 35.105. COSTS OF SERVING STATE AGENCY. An electric
24-16 utility may not recover from a residential customer or from any
24-17 other customer class the assigned and allocated costs of serving a
24-18 state agency, institution of higher education, public school
24-19 district, or political subdivision of this state. The rates of a
24-20 municipally owned utility or an electric cooperative shall be set
24-21 in accordance with the provisions of Chapters 40 and 41,
24-23 Sec. 35.106. WHOLESALE CUSTOMERS. This subchapter does not
24-24 prevent the commissioner, acting on behalf of this state, from
24-25 registering as a power marketer.
24-26 SECTION 21. Section 36.008, Utilities Code, is amended to
25-1 read as follows:
25-2 Sec. 36.008. STATE TRANSMISSION SYSTEM. In establishing
25-3 rates for an electric utility [ not required to file an integrated
25-4 resource plan], the commission may review the state's transmission
25-5 system and make recommendations to the utility on the need to build
25-6 new power lines, upgrade power lines, and make other necessary
25-7 improvements and additions.
25-8 SECTION 22. Section 36.052, Utilities Code, is amended to
25-9 read as follows:
25-10 Sec. 36.052. ESTABLISHING REASONABLE RETURN. In
25-11 establishing a reasonable return on invested capital, the
25-12 regulatory authority shall consider applicable factors, including:
25-13 (1) [ the efforts of the electric utility to comply
25-14 with its most recently approved integrated resource plan;]
25-15 [ (2)] the efforts and achievements of the utility in
25-16 conserving resources;
25-17 (2) [ (3)] the quality of the utility's services;
25-18 (3) [ (4)] the efficiency of the utility's operations;
25-20 (4) [ (5)] the quality of the utility's management.
25-21 SECTION 23. Subsection (d), Section 36.058, Utilities Code,
25-22 is amended to read as follows:
25-23 (d) In making a finding regarding an affiliate transaction,
25-24 [ including an affiliate transaction subject to Chapter 34,] the
25-25 regulatory authority shall:
25-26 (1) determine the extent to which the conditions and
26-1 circumstances of that transaction are reasonably comparable
26-2 relative to quantity, terms, date of contract, and place of
26-3 delivery; and
26-4 (2) allow for appropriate differences based on that
26-6 SECTION 24. Section 36.201, Utilities Code, is amended to
26-7 read as follows:
26-8 Sec. 36.201. AUTOMATIC ADJUSTMENT FOR CHANGES IN COSTS.
26-9 Except as permitted by [ Chapter 34 or] Section 36.204, the
26-10 commission may not establish a rate or tariff that authorizes an
26-11 electric utility to automatically adjust and pass through to the
26-12 utility's customers a change in the utility's fuel or other costs.
26-13 SECTION 25. Section 36.204, Utilities Code, is amended to
26-14 read as follows:
26-15 Sec. 36.204. COST RECOVERY AND INCENTIVES. In establishing
26-16 rates for an electric utility [ not required to file an integrated
26-17 resource plan], the commission may:
26-18 (1) allow timely recovery of the reasonable costs of
26-19 conservation, load management, and purchased power, notwithstanding
26-20 Section 36.201; and
26-21 (2) authorize additional incentives for conservation,
26-22 load management, purchased power, and renewable resources.
26-23 SECTION 26. Section 36.207, Utilities Code, is amended to
26-24 read as follows:
26-25 Sec. 36.207. USE OF MARK-UPS. Any mark-ups approved under
26-26 [ Chapter 34 or] Section 36.206 are an exceptional form of rate
27-1 relief that the electric utility may recover from ratepayers only
27-2 on a finding by the commission that the relief is necessary to
27-3 maintain the utility's financial integrity.
27-4 SECTION 27. Section 37.001, Utilities Code, is amended to
27-5 read as follows:
27-6 Sec. 37.001. DEFINITIONS. In this chapter:
27-7 (1) "Certificate" means a certificate of convenience
27-8 and necessity.
27-9 (2) "Electric utility" includes an electric
27-11 (3) "Retail electric utility" means a person,
27-12 political subdivision, or agency that operates, maintains, or
27-13 controls in this state a facility to provide retail electric
27-14 utility service. The term does not include a corporation described
27-15 by Section 32.053 to the extent that the corporation sells
27-16 electricity exclusively at wholesale and not to the ultimate
27-17 consumer. A qualifying cogenerator that sells electric energy at
27-18 retail to the sole purchaser of the cogenerator's thermal output
27-19 under Sections 35.061 and 36.007 is not for that reason considered
27-20 to be a retail electric utility.
27-21 SECTION 28. Section 37.051, Utilities Code, is amended by
27-22 adding Subsection (c) to read as follows:
27-23 (c) Notwithstanding any other provision of this chapter,
27-24 including Subsection (a), an electric cooperative is not required
27-25 to obtain a certificate of public convenience and necessity for the
27-26 construction, installation, operation, or extension of any
28-1 generating facilities or necessary interconnection facilities.
28-2 SECTION 29. Subchapter B, Chapter 37, Utilities Code, is
28-3 amended by adding Sections 37.060 and 37.061 to read as follows:
28-4 Sec. 37.060. DIVISION OF MULTIPLY CERTIFICATED SERVICE
28-5 AREAS. (a) This subsection and Subsections (b)-(g) shall apply
28-6 only to areas in which each retail electric utility that is
28-7 authorized to provide retail electric utility service to the area
28-8 is providing customer choice. For purposes of this subsection, an
28-9 electric cooperative or a municipally owned electric utility shall
28-10 be deemed to be providing customer choice if it has approved a
28-11 resolution adopting customer choice that is effective upon
28-12 certification of the applicable power region pursuant to Section
28-13 39.152 or effective within 24 months after the date of the
28-14 resolution adopting customer choice. All other retail electric
28-15 utilities shall be deemed to be providing customer choice if
28-16 customer choice will be allowed for customers of the retail
28-17 electric utility upon certification of the applicable power region
28-18 pursuant to Section 39.152. In areas in which each certificated
28-19 retail electric utility is providing customer choice, the
28-20 commission, if requested by a retail electric utility, shall
28-21 examine all areas within the service area of the retail electric
28-22 utility making the request that are also certificated to one or
28-23 more other retail electric utilities and, after notice and hearing,
28-24 shall amend the retail electric utilities' certificates so that
28-25 only one retail electric utility is certificated to provide
28-26 distribution services in any such area. Only retail electric
29-1 utilities certificated to serve an area on June 1, 1999, may
29-2 continue to serve the area or portion of the area under an amended
29-3 certificate issued pursuant to this subsection.
29-4 (b) This section shall not apply in any area in which a
29-5 municipally owned utility is certificated to provide retail
29-6 electric utility service if the municipally owned utility serving
29-7 the area files with the commission by February 1, 2000, a request
29-8 that areas within the certificated service area of the municipally
29-9 owned utility remain as presently certificated.
29-10 (c) The commission shall enter its order dividing multiply
29-11 certificated areas within one year of the date a request is
29-13 (d) In amending certificates under this section, the
29-14 commission shall take into consideration the factors set out in
29-15 Section 37.056.
29-16 (e) Notwithstanding Section 37.059, the commission shall
29-17 revoke certificates to the extent necessary to achieve the division
29-18 of retail electric service areas as provided by this section.
29-19 (f) Unless otherwise agreed by the affected retail electric
29-20 utilities, each retail electric utility shall be allowed to
29-21 continue to provide service to the location of
29-22 electricity-consuming facilities it is serving on the date an
29-23 application for division of the affected multiply certificated
29-24 service areas is filed. No customer located within the affected
29-25 multiply certificated service areas shall be permitted to switch
29-26 from one retail electric utility to another while an application
30-1 for division of the affected multiply certificated service areas is
30-3 (g) If on June 1, 1999, retail service is being provided in
30-4 an area by another retail electric utility with the written consent
30-5 of the retail electric utility certificated to serve the area, such
30-6 consent shall be filed with the commission. Upon notification of
30-7 such consent and a request by an affected retail electric utility
30-8 to amend the relevant certificates, the commission may grant an
30-9 exception or amend a retail electric utility's certificate.
30-10 (h) The commission shall not grant an additional retail
30-11 electric utility certificate to serve an area if the effect of the
30-12 grant would cause the area to be multiply certificated unless the
30-13 commission finds that the certificate holders are not providing
30-14 service to any part of the area for which a certificate is sought
30-15 and are not capable of providing adequate service to the area in
30-16 accordance with applicable standards. However, neither this
30-17 subsection nor the deadline of June 1, 1999, provided by Subsection
30-18 (a) shall apply to any application for multiple certification filed
30-19 with the commission on or before February 1, 1999, and such
30-20 applications may be processed in accordance with applicable law in
30-21 effect on the date the application was filed. Applications for
30-22 multiple certification filed with the commission on or before
30-23 February 1, 1999, may not be amended to expand the area for which a
30-24 certificate is sought except for contiguous areas within
30-25 municipalities that provide consent, as required by Section
30-26 37.053(b), no later than June 1, 1999.
31-1 (i) Notwithstanding any other provision of this section, if
31-2 requested by a municipally owned utility, the commission shall
31-3 examine all areas within the municipally owned utility's service
31-4 area that are also certificated to one or more other retail
31-5 electric utilities and, after notice and hearing, may amend the
31-6 retail electric utilities' certificates so that only one retail
31-7 electric utility is certificated to provide distribution services
31-8 in the area, provided that:
31-9 (1) the application is filed with the commission
31-10 within 12 months of the effective date of this provision and is
31-11 limited to single certification of the area within the
31-12 municipality's boundaries as of February 1, 1999;
31-13 (2) the commission preserves the right of an electric
31-14 utility or an electric cooperative to serve its existing customers,
31-15 including any property owned or leased by any customer; and
31-16 (3) the municipality is a member city of a municipal
31-17 power agency as that term is used in Section 40.059.
31-18 Sec. 37.061. EXISTING SERVICE AREA AGREEMENTS.
31-19 (a) Notwithstanding any other provision of this title, the
31-20 commission shall allow a municipally owned utility to amend the
31-21 service area boundaries of its certificate if:
31-22 (1) the municipally owned utility was the holder of a
31-23 certificate as of January 1, 1999;
31-24 (2) the municipally owned utility has an agreement
31-25 existing prior to January 1, 1999, with a public utility serving
31-26 the area that the public utility will not contest an application to
32-1 amend the certificate to add municipal territory; and
32-2 (3) the area for which a certificate is requested is
32-3 not certificated to a retail electric utility that is not a party
32-4 to the agreement and that has not consented in writing to
32-5 certification of the area to the municipality.
32-6 (b) The commission may not amend the certificate of the
32-7 public utility serving the affected area based upon the granting of
32-8 a certificate to the municipally owned utility.
32-9 SECTION 30. Subsection (a), Section 37.101, Utilities Code,
32-10 is amended to read as follows:
32-11 (a) If an area is or will be included within a municipality
32-12 as the result of annexation, incorporation, or another reason, each
32-13 electric utility and each electric cooperative that holds or is
32-14 entitled to hold a certificate under this title to provide service
32-15 or operate a facility in the area before the inclusion has the
32-16 right to continue to provide the service or operate the facility
32-17 and extend service within the utility's certificated area in the
32-18 annexed or incorporated area under the rights granted by the
32-19 certificate and this title.
32-20 SECTION 31. Section 38.001, Utilities Code, is amended to
32-21 read as follows:
32-22 Sec. 38.001. GENERAL STANDARD. An electric utility and an
32-23 electric cooperative shall furnish service, instrumentalities, and
32-24 facilities that are safe, adequate, efficient, and reasonable.
32-25 SECTION 32. Section 38.004, Utilities Code, is amended to
32-26 read as follows:
33-1 Sec. 38.004. MINIMUM CLEARANCE STANDARD. Notwithstanding
33-2 any other law, a transmission or distribution line owned by an
33-3 electric utility or an electric cooperative must be constructed,
33-4 operated, and maintained, as to clearances, in the manner described
33-5 by the National Electrical Safety Code Standard ANSI (c)(2), as
33-6 adopted by the American National Safety Institute and in effect at
33-7 the time of construction.
33-8 SECTION 33. Subchapter A, Chapter 38, Utilities Code, is
33-9 amended by adding Section 38.005 to read as follows:
33-10 Sec. 38.005. ELECTRIC SERVICE RELIABILITY MEASURES.
33-11 (a) The commission shall implement service quality and reliability
33-12 standards relating to the delivery of electricity to retail
33-13 customers by electric utilities and transmission and distribution
33-14 utilities. The commission by rule shall develop reliability
33-15 standards including but not limited to the following:
33-16 (1) the system-average interruption frequency index;
33-17 (2) the system-average interruption duration index;
33-18 (3) achievement of average response time for customer
33-19 service requests or inquiries; or
33-20 (4) other standards that the commission finds
33-21 reasonable and appropriate.
33-22 (b) The standards implemented under Subsection (a) shall
33-23 require each electric utility and transmission and distribution
33-24 utility subject to this section to maintain adequately trained and
33-25 experienced personnel throughout the utility's service area so that
33-26 the utility is able to fully and adequately comply with the
34-1 appropriate service quality and reliability standards.
34-2 (c) The standards shall ensure that electric utilities do
34-3 not neglect any local neighborhood or geographic area, including
34-4 rural areas, communities of less than 1,000 persons, and low-income
34-5 areas, with regard to system reliability.
34-6 (d) The commission may require each electric utility and
34-7 transmission and distribution utility to supply data to assist the
34-8 commission in developing the reliability standards.
34-9 (e) Each electric utility, transmission and distribution
34-10 utility, and generation provider shall be obligated to comply with
34-11 any operational criteria duly established by the independent
34-12 organization as defined by Section 39.151 or adopted by the
34-14 SECTION 34. Section 38.071, Utilities Code, is amended to
34-15 read as follows:
34-16 Sec. 38.071. Improvements in Service; Interconnecting
34-17 Service. The commission, after notice and hearing, may:
34-18 (1) order an electric utility to provide specified
34-19 improvements in its service in a specified area if:
34-20 (A) service in the area is inadequate or
34-21 substantially inferior to service in a comparable area; and
34-22 (B) requiring the company to provide the
34-23 improved service is reasonable; or
34-24 (2) order two or more electric utilities or electric
34-25 cooperatives to establish specified facilities for interconnecting
35-1 SECTION 35. Subtitle B, Title 2, Utilities Code, is amended
35-2 by adding Chapters 39, 40, and 41 to read as follows:
35-3 CHAPTER 39. RESTRUCTURING OF ELECTRIC UTILITY INDUSTRY
35-4 SUBCHAPTER A. GENERAL PROVISIONS
35-5 Sec. 39.001. LEGISLATIVE POLICY AND PURPOSE. (a) The
35-6 legislature finds that the production and sale of electricity is
35-7 not by definition or necessity a monopoly warranting regulation of
35-8 rates, operations, and services and that the public interest in
35-9 competitive electric markets requires that, except for transmission
35-10 and distribution services and for the recovery of stranded costs,
35-11 electric services and their prices should be determined by customer
35-12 choices and the normal forces of competition. As a result, this
35-13 chapter is enacted to protect the public interest during the
35-14 transition to and in the establishment of a fully competitive
35-15 electric power industry.
35-16 (b) The legislature finds that it is in the public interest
35-18 (1) implement on January 1, 2002, a competitive retail
35-19 electric market that allows each retail customer to choose the
35-20 customer's provider of electricity and that encourages full and
35-21 fair competition among all providers of electricity;
35-22 (2) allow utilities with uneconomic generation-related
35-23 assets and purchased power contracts to recover the reasonable
35-24 excess costs over market of such assets and purchased power
35-26 (3) educate utility customers about anticipated
36-1 changes in the provision of retail electric service to ensure that
36-2 the benefits of the competitive market reach all customers; and
36-3 (4) protect the competitive process in a manner that
36-4 ensures the confidentiality of competitively sensitive information
36-5 during the transition to a competitive market and after the
36-6 commencement of customer choice.
36-7 (c) Regulatory authorities shall not make rules or issue
36-8 orders regulating competitive electric services, prices, or
36-9 competitors or restricting or conditioning competition except as
36-10 authorized in this title and shall not discriminate against any
36-11 participant or type of participant during the transition to a
36-12 competitive market and in the competitive market.
36-13 Sec. 39.002. APPLICABILITY. This chapter, other than
36-14 Sections 39.155, 39.157(e), 39.203, 39.603, and 39.604, does not
36-15 apply to a municipally owned utility or an electric cooperative.
36-16 Sections 39.157(e), 39.203, and 39.604, however, apply only to a
36-17 municipally owned utility or an electric cooperative that is
36-18 offering customer choice. If there is a conflict between the
36-19 specific provisions of this chapter and any other provisions of
36-20 this title, except for Chapters 40 and 41, the provisions of this
36-21 chapter control.
36-22 Sec. 39.003. OPERATIONS IN MULTIPLE POWER REGIONS. In this
36-23 chapter, a retail electric utility whose certificated service area
36-24 includes areas that are located in a qualifying power region and
36-25 areas that are located in a power region that is not a qualifying
36-26 power region shall be considered a retail electric utility in a
37-1 qualifying power region for that part of its certificated service
37-2 area that is located in a qualifying power region and shall be
37-3 considered a retail electric utility not in a qualifying power
37-4 region for that part of its certificated service area that is
37-5 located in a power region that is not a qualifying power region.
37-6 SUBCHAPTER B. TRANSITION TO COMPETITIVE RETAIL
37-7 ELECTRIC MARKET
37-8 Sec. 39.051. UNBUNDLING. (a) On or before September 1,
37-9 2000, each electric utility shall unbundle its costs and rates into
37-10 generation, transmission, distribution, and retail energy services
37-11 and a system benefit fund charge and expected competition
37-12 transition charge.
37-13 (b) Not later than January 1, 2002, each electric utility
37-14 shall separate its business activities from one another into the
37-15 following units:
37-16 (1) a power generation company;
37-17 (2) a retail electric provider; and
37-18 (3) a transmission and distribution utility.
37-19 (c) An electric utility may accomplish the separation
37-20 required by Subsection (b) either through the creation of separate
37-21 nonaffiliated companies or separate affiliated companies owned by a
37-22 common holding company or through the sale of assets to a third
37-24 (d) Each electric utility shall unbundle under this section
37-25 in a manner that provides for a separation of personnel,
37-26 information flow, functions, and operations.
38-1 (e) Each electric utility shall file with the commission a
38-2 plan to implement this section by January 1, 2000.
38-3 (f) Within 120 days of the date the plan required under
38-4 Subsection (e) is filed with the commission, the commission shall
38-5 adopt the utility's plan for business separation required by
38-6 Subsection (b), adopt the plan with changes, or reject the plan and
38-7 require the utility to file a new plan.
38-8 (g) If the commission determines that a power region will
38-9 not qualify for customer choice under Section 39.152 by January 1,
38-10 2002, it may adjust the filing and implementation dates in this
38-11 section for utilities in that region.
38-12 (h) Transactions by electric utilities involving sales,
38-13 transfers, or other disposition of assets to accomplish the
38-14 purposes of this section shall not be subject to Section 14.101,
38-15 35.034, or 35.035.
38-16 Sec. 39.052. FREEZE ON EXISTING RETAIL BASE RATE TARIFFS.
38-17 (a) Until January 1, 2002, an electric utility shall provide
38-18 retail electric service within its certificated service area in
38-19 accordance with the electric utility's retail base rate tariffs in
38-20 effect on September 1, 1999, including its purchased power cost
38-21 recovery factor.
38-22 (b) During the freeze period an electric utility may not
38-23 increase its retail base rates above the rates provided by this
38-24 section except for losses caused by force majeure as provided by
38-25 Section 39.055.
38-26 (c) Notwithstanding any other provision of this title,
39-1 during the freeze period the regulatory authority may not reduce
39-2 the retail base rates of an electric utility, except as may be
39-3 ordered as stipulated to by an electric utility in a proceeding for
39-4 which a final order had not been issued by January 1, 1999.
39-5 (d) During the freeze period the retail base rates, overall
39-6 revenues, return on invested capital, and net income of an electric
39-7 utility are not subject to complaint, hearing, or determination as
39-8 to reasonableness.
39-9 (e) An electric utility that has a rate proceeding pending
39-10 before the commission as of January 2, 1999, shall provide service
39-11 in accordance with the tariffs approved in that proceeding from the
39-12 date of approval until the end of the freeze period.
39-13 (f) Nothing in this section affects the authority of the
39-14 commission to fulfill its obligations under Section 39.262.
39-15 (g) Nothing in this section shall deny a utility its right
39-16 to have the commission conduct proceedings and issue a final order
39-17 pertaining to any matter that may be remanded to the commission by
39-18 a court having jurisdiction, except that the final order may not
39-19 affect the rates charged to customers during the freeze period but
39-20 shall be taken into account during the utility's true-up proceeding
39-21 under Section 39.262.
39-22 (h) Nothing in this title shall be construed to prevent an
39-23 electric utility or a transmission and distribution utility from
39-24 filing, and the commission from approving, a change in wholesale
39-25 transmission service rates during the freeze period.
39-26 Sec. 39.053. COST RECOVERY ADJUSTMENTS. This subchapter
40-1 does not limit or alter the ability of an electric utility during
40-2 the freeze period to revise its fuel factor or to reconcile fuel
40-3 expenses and to either refund fuel overcollections or surcharge
40-4 fuel undercollections to customers, as authorized by its tariffs
40-5 and Sections 36.203 and 36.205.
40-6 Sec. 39.054. RETAIL ELECTRIC SERVICE DURING THE FREEZE
40-7 PERIOD. (a) An electric utility shall provide retail electric
40-8 service during the freeze period in accordance with any contract
40-9 terms applicable to a particular retail customer approved by the
40-10 regulatory authority and in effect on December 31, 1998.
40-11 (b) Nothing in Sections 39.052(c) and (d) shall be construed
40-12 to restrict any customer's right to complain during the freeze
40-13 period to the regulatory authority regarding the quality of retail
40-14 electric service provided by the electric utility or the
40-15 applicability of an electric utility's particular tariff to the
40-17 (c) Nothing in this title shall be construed to restrict an
40-18 electric utility, voluntarily and at its sole discretion, from
40-19 offering new services or new tariff options to its customers during
40-20 the freeze period.
40-21 (d) Any offering of new services or tariff options under
40-22 this section shall be equal to or greater than an electric
40-23 utility's long-run marginal cost and not be unreasonably
40-24 preferential, prejudicial, discriminatory, predatory, or
40-26 (e) Revenue from any new offering under this section shall
41-1 be accounted for in a manner consistent with Section 36.007.
41-2 Sec. 39.055. FORCE MAJEURE. (a) An electric utility may
41-3 recover losses resulting from force majeure through an increase in
41-4 its retail base rates during the freeze period.
41-5 (b) Notwithstanding Subchapter C, Chapter 36, the regulatory
41-6 authority, after a hearing to determine the electric utility's
41-7 losses from force majeure, shall permit the utility to fully
41-8 collect any approved force majeure increase through an appropriate
41-9 customer surcharge mechanism.
41-10 (c) For purposes of this section, "force majeure" means a
41-11 major event or combination of major events, including new or
41-12 expanded state or federal statutory or regulatory requirements;
41-13 hurricanes, tornadoes, ice storms, or other natural disasters; or
41-14 acts of war, terrorism, or civil disturbance, beyond the control of
41-15 an electric utility that the regulatory authority finds increases
41-16 the utility's total reasonable and necessary nonfuel costs or
41-17 decreases the utility's total nonfuel revenues related to the
41-18 generation and delivery of electricity by more than 10 percent for
41-19 any calendar year during the freeze period. The term does not
41-20 include any changes in general economic conditions such as
41-21 inflation, interest rates, or other factors of general application.
41-22 SUBCHAPTER C. RETAIL COMPETITION
41-23 Sec. 39.101. CUSTOMER SAFEGUARDS. (a) Before retail
41-24 competition begins on January 1, 2002, the commission shall ensure
41-25 that retail customer protections are established that entitle a
42-1 (1) to safe, reliable, and reasonably priced
42-2 electricity, including protection against service disconnections in
42-3 extreme weather or in cases of medical emergency or nonpayment for
42-4 unrelated services;
42-5 (2) to privacy of customer consumption and credit
42-7 (3) to bills presented in a clear format and in
42-8 language readily understandable by customers;
42-9 (4) to the option to have all electric services on a
42-10 single bill, except in those instances where multiple bills are
42-11 allowed under Chapters 40 and 41;
42-12 (5) to protection from discrimination on the basis of
42-13 race, color, sex, nationality, religion, or marital status;
42-14 (6) to accuracy of metering and billing;
42-15 (7) to information in English and Spanish and any
42-16 other language as necessary concerning rates, key terms and
42-17 conditions, and the environmental impact of certain production
42-19 (8) to information in English and Spanish and any
42-20 other language as necessary concerning low-income assistance
42-21 programs and deferred payment plans; and
42-22 (9) to other information or protections necessary to
42-23 ensure high-quality service to customers.
42-24 (b) A customer is entitled:
42-25 (1) to be informed about rights and opportunities in
42-26 the transition to a competitive electric industry;
43-1 (2) to choose the customer's retail electric provider
43-2 consistent with this chapter, to have that choice honored, and to
43-3 assume that the customer's chosen provider will not be changed
43-4 without the customer's informed consent;
43-5 (3) to have access to providers of energy efficiency
43-6 services and to providers of energy generated by renewable energy
43-8 (4) to be served by a provider of last resort that
43-9 offers a commission-approved standard service package;
43-10 (5) to receive sufficient information to make an
43-11 informed choice of service provider;
43-12 (6) to be protected from unfair, misleading, or
43-13 deceptive practices, including protection from being billed for
43-14 services that were not authorized or provided; and
43-15 (7) to have an impartial and prompt resolution of
43-16 disputes with its chosen retail electric provider and transmission
43-17 and distribution utility.
43-18 (c) A retail electric provider, power generation company,
43-19 aggregator, or other entity that provides retail electric service
43-20 may not refuse to provide retail electric or electric generation
43-21 service or otherwise discriminate in the provision of electric
43-22 service to any customer because of race, creed, color, national
43-23 origin, ancestry, sex, marital status, lawful source of income,
43-24 disability, or familial status. A retail electric provider, power
43-25 generation company, aggregator, or other entity that provides
43-26 retail electric service may not refuse to provide retail electric
44-1 or electric generation service to a customer because the customer
44-2 is located in an economically distressed geographic area or
44-3 qualifies for low-income affordability or energy efficiency
44-4 services. The commission shall require a provider to comply with
44-5 this subsection as a condition of certification or registration.
44-6 (d) A retail electric provider, power generation company,
44-7 aggregator, or other entity that provides retail electric service
44-8 shall submit reports to the commission and the office annually and
44-9 on request relating to the person's compliance with this section.
44-10 The commission by rule shall specify the form in which a report
44-11 must be submitted. A report must include:
44-12 (1) information regarding the extent of the person's
44-14 (2) information regarding the service provided,
44-15 compiled by zip code and census tract; and
44-16 (3) any other information the commission or the office
44-17 considers relevant to determine compliance.
44-18 (e) The commission has the authority to adopt and enforce
44-19 such rules as may be necessary or appropriate to carry out
44-20 Subsections (a)-(d), including but not limited to rules for minimum
44-21 service standards for a retail electric provider relating to
44-22 customer deposits and the extension of credit, switching fees,
44-23 levelized billing programs, termination of service, and quality of
44-24 service. The commission has jurisdiction over all providers of
44-25 electric service in enforcing Subsections (a)-(d) and may assess
44-26 civil and administrative penalties under Section 15.023 and seek
45-1 civil penalties under Section 15.028.
45-2 (f) On or before December 31, 2001, the commission shall
45-3 modify its current rules regarding customer protections to ensure
45-4 that at least the same level of customer protection against
45-5 potential abuses and the same quality of service that exists on
45-6 December 31, 1999, is maintained in a restructured electric
45-8 Sec. 39.102. RETAIL CUSTOMER CHOICE. (a) Each retail
45-9 customer in the state, except retail customers in power regions
45-10 that are not certified as qualifying for competition by the
45-11 commission and retail customers of electric cooperatives and
45-12 municipally owned utilities that have not opted for customer
45-13 choice, shall have customer choice on and after January 1, 2002.
45-14 (b) The affiliated retail electric provider of the electric
45-15 utility serving a retail customer on December 31, 2001, may
45-16 continue to serve that customer until the customer chooses service
45-17 from a different retail electric provider, an electric cooperative
45-18 offering customer choice, or a municipally owned utility offering
45-19 customer choice.
45-20 (c) An electric utility that has in effect a systemwide
45-21 freeze for residential and commercial customers extending beyond
45-22 December 31, 2001, that has been found by a regulatory authority to
45-23 be in the public interest shall not be subject to this chapter. At
45-24 the expiration of the utility's freeze period, the utility shall be
45-25 subject to the provisions of this chapter and shall, at that time,
45-26 have no claim for stranded cost recovery.
46-1 Sec. 39.103. COMMISSION AUTHORITY TO DELAY COMPETITION AND
46-2 SET NEW RATES. If the commission determines under Section 39.104
46-3 that a power region is unable to offer fair competition and
46-4 reliable service to all retail customer classes on January 1, 2002,
46-5 or that the power region fails to meet the requirements of Section
46-6 39.152, the commission shall delay customer choice for the power
46-7 region and may on or after January 1, 2002, establish new rates for
46-8 all electric utilities in the power region as provided by Chapter
46-10 Sec. 39.104. CUSTOMER CHOICE PILOT PROJECTS. (a) Customer
46-11 choice pilot projects may be used to allow the commission to
46-12 evaluate the ability of each power region and electric utility to
46-13 implement customer choice.
46-14 (b) The commission shall require each electric utility
46-15 operating in ERCOT to offer customer choice in its service area
46-16 amounting to five percent of the utility's combined load of all
46-17 customer classes beginning on June 1, 2001.
46-18 (c) The commission may require an electric utility operating
46-19 outside of ERCOT to offer customer choice in its service area
46-20 within the state amounting to five percent of the utility's
46-21 combined load within the state of all customer classes beginning on
46-22 June 1, 2001.
46-23 (d) The load designated for customer choice under this
46-24 section shall be distributed among all customer classes of a
46-25 utility consistent with the purpose of this section and subject to
46-26 commission approval.
47-1 (e) Customers participating in a pilot project under this
47-2 section may buy electric energy from any retail electric provider
47-3 certified by the commission under Section 39.352, including an
47-4 affiliated retail electric provider; provided, however, that a
47-5 retail electric provider may not participate in a pilot project in
47-6 the certificated service area served by the electric utility with
47-7 which it is affiliated.
47-8 (f) Each utility operating a pilot project under this
47-9 section shall charge residential and small commercial customers in
47-10 accordance with Section 39.052.
47-11 (g) The commission may prescribe reporting requirements it
47-12 considers necessary to evaluate a pilot project consistent with the
47-13 purpose of this section.
47-14 (h) Customers having customer choice under this section
47-15 shall be billed as provided by Section 39.107.
47-16 (i) The commission may prescribe terms and conditions it
47-17 considers necessary to prohibit anticompetitive practices and to
47-18 encourage customer choice offered under this section.
47-19 (j) Notwithstanding any other provision of this title, a
47-20 retail electric provider participating in a pilot project under
47-21 this section is not an electric utility or a retail electric
47-23 Sec. 39.105. LIMITATION ON SALE OF ELECTRICITY. (a) After
47-24 January 1, 2002, in areas in which customer choice has been
47-25 introduced, a transmission and distribution utility may not sell
47-26 electricity or otherwise participate in the market for electricity
48-1 except for the purpose of buying electricity to serve its own
48-3 (b) A person or retail electric utility may not provide,
48-4 furnish, or make available electric service at retail within the
48-5 certificated service area of an electric cooperative that has not
48-6 adopted customer choice or a municipally owned utility that has not
48-7 adopted customer choice. However, this subsection shall not
48-8 prohibit the provision of electric service in multiply certificated
48-9 service areas to customers of any other retail electric utility.
48-10 Sec. 39.106. PROVIDER OF LAST RESORT. (a) The commission
48-11 shall designate retail electric providers in areas of the state in
48-12 which customer choice is in effect to serve as providers of last
48-14 (b) A provider of last resort shall offer a standard retail
48-15 service package for each class of customers designated by the
48-16 commission at a fixed, nondiscountable rate approved by the
48-18 (c) A provider of last resort shall provide the standard
48-19 retail service package to any requesting customer in the territory
48-20 for which it is the provider of last resort.
48-21 (d) For all areas of the state for which the commission has
48-22 determined that customer choice is to be introduced on January 1,
48-23 2002, the commission shall designate the provider or providers of
48-24 last resort no later than June 1, 2001. For areas of the state for
48-25 which customer choice is not to be introduced on January 1, 2002,
48-26 except as provided in Sections 40.053(c) and 41.053(c), the
49-1 commission shall designate the provider or providers of last resort
49-2 at the earliest feasible date after determining that conditions for
49-3 permitting customer choice in that area have been met but no later
49-4 than 180 days before customer choice is to begin.
49-5 (e) The commission shall determine the procedures and
49-6 criteria, which may include the solicitation of bids, for
49-7 designating a provider or providers of last resort. The commission
49-8 may redesignate the provider of last resort according to a schedule
49-9 it considers appropriate.
49-10 (f) In the event that no retail electric provider applies to
49-11 be the provider of last resort for a given area of the state on
49-12 reasonable terms and conditions, the commission may require a
49-13 retail electric provider to become the provider of last resort as a
49-14 condition of receiving or maintaining a certificate pursuant to
49-15 Section 39.352.
49-16 (g) In the event that a retail electric provider fails to
49-17 serve any or all of its customers, the provider of last resort
49-18 shall offer each such customer the standard retail service package
49-19 for that customer class with no interruption of service to any
49-21 Sec. 39.107. METERING AND BILLING SERVICES. (a) On
49-22 introduction of customer choice in a service area, metering
49-23 services for the area shall continue to be provided by the
49-24 transmission and distribution utility affiliate of the electric
49-25 utility that was serving the area prior to the introduction of
49-26 customer choice. Metering services shall be provided on a
50-1 competitive basis beginning:
50-2 (1) January 1, 2004, in areas in which customer choice
50-3 is introduced January 1, 2002; and
50-4 (2) in areas in which customer choice begins at a
50-5 later date, two years after the date that customer choice is
50-6 introduced in the area.
50-7 (b) On introduction of customer choice in a service area,
50-8 tenants of leased or rented property that is separately metered
50-9 shall have the right to choose a retail electric provider, and the
50-10 owner of the property must grant reasonable and nondiscriminatory
50-11 access to transmission and distribution utilities or retail
50-12 electric providers for metering purposes.
50-13 (c) Beginning on the date of introduction of customer choice
50-14 in a service area, a transmission and distribution utility shall
50-15 bill a customer's retail electric provider for nonbypassable
50-16 delivery charges as determined pursuant to Section 39.201. The
50-17 retail electric provider must pay these charges.
50-18 (d) A transmission and distribution utility may bill retail
50-19 customers at the request of a retail electric provider. A
50-20 transmission and distribution utility that provides billing service
50-21 at the request of an affiliated retail electric provider shall
50-22 offer billing service on comparable terms and conditions to any
50-23 other requesting retail electric provider of a customer served by
50-24 the transmission and distribution utility.
50-25 (e) Beginning on the date of introduction of customer choice
50-26 in a service area, any charges for metering and billing services
51-1 shall comply with rules adopted by the commission relating to
51-2 nondiscriminatory rates of service.
51-3 Sec. 39.108. CONTRACTUAL OBLIGATIONS. This chapter shall
51-5 (1) interfere with or abrogate the rights or
51-6 obligations of any party, including a retail or wholesale customer,
51-7 to a contract with an investor-owned electric utility, river
51-8 authority, municipally owned utility, or electric cooperative;
51-9 (2) interfere with or abrogate the rights or
51-10 obligations of a party under a contract or agreement concerning
51-11 certificated utility service areas; or
51-12 (3) result in a change in wholesale power costs to
51-13 wholesale customers in Texas purchasing electricity under wholesale
51-14 power contracts the pricing provisions of which are based on
51-15 formulary rates, fuel adjustments, or average system costs.
51-16 SUBCHAPTER D. MARKET STRUCTURE
51-17 Sec. 39.151. ESSENTIAL ORGANIZATIONS. (a) Before obtaining
51-18 commission certification as a qualifying power region, a power
51-19 region must establish one or more independent organizations to
51-20 perform the following functions:
51-21 (1) ensure access to the transmission and distribution
51-22 systems for all buyers and sellers of electricity on
51-23 nondiscriminatory terms;
51-24 (2) ensure the reliability and adequacy of the
51-25 regional electrical network;
51-26 (3) ensure that information relating to a customer's
52-1 choice of retail electric provider is conveyed in a timely manner
52-2 to the persons who need such information; and
52-3 (4) ensure that electricity production and delivery
52-4 are accurately accounted for among the generators and wholesale
52-5 buyers and sellers in the region.
52-6 (b) "Independent organization" means an independent system
52-7 operator or other person that is sufficiently independent of any
52-8 producer or seller of electricity that its decisions will not be
52-9 unduly influenced by any producer or seller. An entity will be
52-10 deemed to be independent if it is governed by a board that has
52-11 three representatives from each segment of the electric market,
52-12 with the consumer segment being represented by one residential
52-13 customer, one commercial customer, and one industrial retail
52-15 (c) The commission shall certify an independent organization
52-16 or organizations to perform the functions set out in this section.
52-17 (d) An independent organization certified by the commission
52-18 for a power region shall establish and enforce procedures,
52-19 consistent with this title and the commission's rules, relating to
52-20 the reliability of the regional electrical network and accounting
52-21 for the production and delivery of electricity among generators and
52-22 all other market participants. The procedures shall be subject to
52-23 commission oversight and review.
52-24 (e) The commission may authorize an independent organization
52-25 that is certified under this section to charge a reasonable and
52-26 competitively neutral rate to wholesale buyers and sellers to cover
53-1 the independent organization's costs.
53-2 (f) In implementing this section, the commission may
53-3 cooperate with the utility regulatory commission of another state
53-4 or the federal government and may hold a joint hearing or make a
53-5 joint investigation with that commission.
53-6 (g) If it amends its governance rules to allow
53-7 representation reflecting the makeup of the retail market on its
53-8 governing board in accordance with Subsection (b), the existing
53-9 independent system operator in ERCOT will meet the criteria
53-10 provided by Subsection (a) with respect to ensuring access to the
53-11 transmission systems for all buyers and sellers of electricity in
53-12 the ERCOT region and ensuring the reliability of the regional
53-13 electrical network. The ERCOT independent system operator may meet
53-14 the criteria relating to the other functions of an independent
53-15 organization provided by Subsection (a) by adopting procedures and
53-16 acquiring resources needed to carry out those functions.
53-17 (h) The commission may delegate authority to the existing
53-18 independent system operator in ERCOT to enforce operating standards
53-19 within the ERCOT regional electrical network and to establish and
53-20 oversee transaction settlement procedures. The commission may
53-21 establish the terms and conditions for the ERCOT independent system
53-22 operator's authority to oversee utility dispatch functions after
53-23 the introduction of customer choice.
53-24 (i) A retail electric provider, municipally owned utility,
53-25 electric cooperative, power marketer, transmission and distribution
53-26 utility, or power generation company shall observe all scheduling,
54-1 operating, and settlement policies, rules, guidelines, and
54-2 procedures established by the independent system operator in ERCOT.
54-3 Failure to comply with this subsection may result in the
54-4 revocation, suspension, or amendment of a certificate as provided
54-5 by Section 39.356 or in the imposition of an administrative penalty
54-6 as provided by Section 39.357.
54-7 (j) To the extent the commission has authority over an
54-8 independent organization outside of ERCOT, the commission may
54-9 delegate authority to the independent organization consistent with
54-10 Subsection (h).
54-11 (k) No operational criteria, protocols, or other requirement
54-12 established by an independent organization, including the ERCOT
54-13 independent system operator, may adversely affect or impede any
54-14 manufacturing or other internal process operation associated with
54-15 an industrial generation facility, except to the minimum extent
54-16 necessary to assure reliability of the transmission network.
54-17 Sec. 39.152. QUALIFYING POWER REGIONS. (a) The commission
54-18 shall certify a power region as qualifying for customer choice if:
54-19 (1) a sufficient number of interconnected utilities in
54-20 the power region fall under the operational control of an
54-21 independent organization as described by Section 39.151;
54-22 (2) the power region has a generally applicable tariff
54-23 that guarantees open and nondiscriminatory access for all users to
54-24 transmission and distribution facilities in the power region as
54-25 provided by Section 39.203; and
54-26 (3) no person owns and controls more than 20 percent
55-1 of the installed generation capacity located in or capable of
55-2 delivering electricity to a power region, as determined according
55-3 to Section 39.154, when customer choice is introduced.
55-4 (b) In determining whether a power region not entirely
55-5 within the state meets the requirements of this section, the
55-6 commission shall consider the extent to which the available
55-7 transmission facilities limit the delivery of electricity from
55-8 generators located outside the state to areas of the power region
55-9 within the state.
55-10 Sec. 39.153. CAPACITY AUCTION. (a) Each electric utility
55-11 subject to this section shall sell at auction, at least 60 days
55-12 before the date set for customer choice to begin in the power
55-13 region in which the electric utility serves, entitlements to at
55-14 least 15 percent of the electric utility's installed generation
55-15 capacity. For the purposes of this section, the term "electric
55-16 utility" includes any affiliated power generation company that is
55-17 unbundled from the electric utility in accordance with Section
55-18 39.051, but does not include any entity owning less than 400
55-19 megawatts of installed generation capacity.
55-20 (b) The obligation to auction the entitlements shall
55-21 continue until the earlier of 60 months after the date customer
55-22 choice is introduced in the power region or the date the commission
55-23 determines that 40 percent or more of the electric power consumed
55-24 by residential and small commercial customers within the affiliated
55-25 transmission and distribution utility's certificated service area
55-26 before the onset of customer choice is provided by nonaffiliated
56-1 retail electric providers.
56-2 (c) An affiliate of the electric utility selling
56-3 entitlements in the auction required by this section shall not be
56-4 allowed to purchase entitlements from the affiliated electric
56-5 utility at the auction. Entitlements may only be purchased by
56-6 entities lawfully able to sell electricity in Texas.
56-7 (d) An electric utility may choose to auction additional
56-8 entitlements beyond those required by Subsection (a) or continue to
56-9 auction entitlements after the period required by Subsection (b) in
56-10 order to comply with Section 39.154.
56-11 (e) The commission shall adopt rules by December 31, 2000,
56-12 that define the scope of the capacity entitlements to be auctioned.
56-13 Entitlements may be auctioned in blocks of less than 15 percent.
56-14 The rules shall state the minimum amount of capacity that can be
56-15 sold at auction as an entitlement. At a minimum, the rules shall
56-16 provide that the entitlements:
56-17 (1) may be sold and purchased in periods of no less
56-18 than one month nor more than four years;
56-19 (2) may be resold to any lawful purchaser, except for
56-20 a retail electric provider affiliated with the electric utility
56-21 that originally auctioned the entitlement;
56-22 (3) include no possessory interest in the unit from
56-23 which the power is produced;
56-24 (4) include no obligations of a possessory owner of an
56-25 interest in the unit from which the power is produced; and
56-26 (5) give the purchaser the right to designate the
57-1 dispatch of the entitlement, subject to planned outages, outages
57-2 beyond the control of the utility operating the unit, and other
57-3 considerations subject to the oversight of the applicable
57-4 independent organization.
57-5 (f) The commission shall adopt rules by December 31, 2000,
57-6 that prescribe the procedure for the auction of the entitlements.
57-7 Such rules shall include:
57-8 (1) a process for conducting the auction or auctions,
57-9 including who shall conduct it, how often it shall be conducted,
57-10 and how winning bidders shall be determined;
57-11 (2) a process for the electric utility to designate
57-12 which generation units or combination of units are offered for
57-14 (3) a provision for the utility to establish an
57-15 opening bid price based upon the electric utility's expected cost,
57-16 with the commission prescribing the means for determining the
57-17 opening bid price, which shall not include return on equity; and
57-18 (4) a provision that allows a bidder to specify the
57-19 magnitude and term of the entitlement, subject to the conditions
57-20 established in Subsection (e).
57-21 (g) In adopting the process under Subsection (f)(2), the
57-22 commission shall consider the furtherance of the development of the
57-23 competitive market, the cost of transmission, physical constraints
57-24 of the transmission system, the proximity of the generation to
57-25 load, economic efficiency, and such other factors as the commission
57-26 finds relevant. The process may provide for commission approval of
58-1 the designation prior to auction. The commission may consult with
58-2 the applicable independent organization to develop the process.
58-3 Sec. 39.154. LIMITATION OF OWNERSHIP OF INSTALLED CAPACITY.
58-4 (a) Beginning on the date of introduction of customer choice, no
58-5 power generation company may own and control more than 20 percent
58-6 of the installed generation capacity located in, or capable of
58-7 delivering electricity to, a qualifying power region.
58-8 (b) In a power region not entirely within the state, the
58-9 commission may waive or modify the requirement in Subsection (a)
58-10 upon a finding of good cause.
58-11 (c) In determining the percentage shares of installed
58-12 generation capacity under this section, the commission shall
58-13 combine capacity owned and controlled by a power generation company
58-14 and any entity that is affiliated with that power generation
58-15 company within the power region, reduced by the installed
58-16 generation capacity of those facilities that are made subject to
58-17 capacity entitlements auctions under Sections 39.153(a) and (d).
58-18 (d) In this chapter, "installed generation capacity" means
58-19 all potentially marketable electric generation capacity, including
58-20 the capacity of:
58-21 (1) generating facilities that are connected with a
58-22 transmission or distribution system;
58-23 (2) generating facilities used to generate electricity
58-24 for consumption by the person owning or controlling the facility;
58-26 (3) generating facilities for which the Texas Natural
59-1 Resource Conservation Commission has issued a permit authorizing
59-2 the initiation of construction and which are anticipated to be in
59-3 operation within two years.
59-4 Sec. 39.155. COMMISSION ASSESSMENT OF MARKET POWER.
59-5 (a) Each person, municipally owned utility, electric cooperative,
59-6 and river authority that owns generation facilities and offers
59-7 electricity for sale in this state shall report to the commission
59-8 its installed generation capacity, the total amount of capacity
59-9 available for sale to others, the total amount of capacity under
59-10 contract to others, the total amount of capacity dedicated to its
59-11 own use, its annual wholesale power sales in the state, its annual
59-12 retail power sales in the state, and any other information
59-13 necessary for the commission to assess market power or the
59-14 development of a competitive retail market in the state. The
59-15 commission shall by rule prescribe the nature and detail of such
59-16 reporting requirements and shall administer those reporting
59-17 requirements in a manner that ensures the confidentiality of
59-18 competitively sensitive information.
59-19 (b) The ERCOT independent system operator shall submit an
59-20 annual report to the commission identifying existing and potential
59-21 transmission and distribution constraints and system needs within
59-22 ERCOT, alternatives for meeting system needs, and recommendations
59-23 for meeting system needs. The first report shall be submitted on
59-24 or before October 1, 1999. Subsequent reports shall be submitted
59-25 by January 15 of each year or as determined necessary by the
60-1 (c) Before the date of introduction of customer choice in a
60-2 power region other than ERCOT, each electric utility owning
60-3 transmission and distribution facilities in that region shall
60-4 submit an annual report to the commission identifying existing and
60-5 potential transmission and distribution constraints and system
60-6 needs in the power region, alternatives for meeting system needs,
60-7 and recommendations for meeting system needs as directed by the
60-9 (d) After the introduction of customer choice in a
60-10 qualifying power region, the reports required by Subsections (b)
60-11 and (c) shall be submitted by the independent organization or
60-12 organizations having authority over the power region or discrete
60-13 areas thereof.
60-14 Sec. 39.156. MARKET POWER MITIGATION PLAN. (a) In this
60-15 section, "market power mitigation plan" or "plan" means a written
60-16 proposal by an electric utility or a power generation company for
60-17 reducing its ownership and control of installed generation capacity
60-18 as required by Section 39.154.
60-19 (b) An electric utility or power generation company owning
60-20 and controlling more than 20 percent of the generation capacity
60-21 located in, or capable of delivering electricity to, a power region
60-22 shall file a market power mitigation plan with the commission no
60-23 later than December 31, 2000.
60-24 (c) The plan may provide for:
60-25 (1) the sale or exchange of generation assets to or
60-26 with an unaffiliated person;
61-1 (2) the auctioning of generation capacity entitlements
61-2 subject to commission approval under Section 39.153; or
61-3 (3) any reasonable method of mitigation.
61-4 (d) For the purposes of this section, generation capacity
61-5 shall be net of the generation capacity subject to an auction under
61-6 Section 39.153.
61-7 (e) The plan shall be in a form prescribed by the commission
61-8 and shall provide information the commission finds reasonably
61-9 necessary to evaluate the plan.
61-10 (f) The commission shall approve, modify, or reject a plan
61-11 within 180 days after the date of a filing under Subsection (b).
61-12 The commission shall not modify a plan to require divestiture by
61-13 the electric utility or the power generation company.
61-14 (g) In reaching its determination under Subsection (f), the
61-15 commission shall consider:
61-16 (1) the degree to which the electric utility's or
61-17 power generation company's stranded costs, if any, are minimized;
61-18 (2) whether on disposition of the generation assets
61-19 the reasonable value is likely to be received;
61-20 (3) the effect of the plan on the electric utility's
61-21 or power generation company's federal income taxes;
61-22 (4) the effect of the plan on current and potential
61-23 competitors in the generation market; and
61-24 (5) whether the plan is consistent with the public
61-26 (h) An electric utility or power generation company with an
62-1 approved mitigation plan may request to amend or repeal its plan.
62-2 Upon a showing of good cause, the commission shall modify or repeal
62-3 an electric utility's or power generation company's mitigation
62-5 (i) If an electric utility's or a power generation company's
62-6 market power mitigation plan is not approved before January 1 of
62-7 the year it is to take effect, the commission may order the
62-8 electric utility or power generation company to auction generation
62-9 capacity entitlements according to Section 39.153, subject to
62-10 commission approval, of any capacity exceeding the maximum
62-11 allowable capacity prescribed by Section 39.154 until such time a
62-12 mitigation plan is approved.
62-13 (j) An auction under Subsection (i) shall be held no later
62-14 than 60 days after the order is entered.
62-15 Sec. 39.157. COMMISSION AUTHORITY TO ADDRESS MARKET POWER.
62-16 (a) The commission shall monitor market power associated with the
62-17 generation, transmission, distribution, and sale of electricity in
62-18 this state. On a finding, after notice and opportunity for
62-19 hearing, that market power abuses are occurring, the commission
62-20 shall require reasonable mitigation of the market power by ordering
62-21 the construction of additional transmission or distribution
62-22 facilities, by requiring a reduction of generation capacity through
62-23 the auction of generation capacity entitlements, by instituting
62-24 price cap regulation, by setting appropriate restrictions on sales
62-25 of electricity, by establishing limitations on the use of
62-26 generation, transmission, or distribution facilities, or by any
63-1 other reasonable remedy.
63-2 (b) Beginning on the date of introduction of customer
63-3 choice, no person that owns generation facilities may own
63-4 transmission or distribution facilities in this state except for
63-5 those facilities necessary to interconnect a generation facility
63-6 with the transmission or distribution network, a facility not
63-7 dedicated to public use, or a facility otherwise excluded from the
63-8 definition of electric utility under Section 31.002(6). However,
63-9 nothing in this chapter shall prohibit a power generation company
63-10 affiliated with a transmission and distribution utility from owning
63-11 generation facilities.
63-12 (c) The commission shall monitor market shares of installed
63-13 capacity to ensure that the limitations in Section 39.154 are not
63-14 exceeded. If the commission finds, after notice and opportunity
63-15 for hearing, that a person has violated a limitation in Section
63-16 39.154, the commission shall order the person to file, within 60
63-17 days of the date of the order, a market power mitigation plan
63-18 consistent with the requirements in Section 39.156.
63-19 (d) In order to avoid potential market power abuses and
63-20 cross-subsidizations between regulated and unregulated activities,
63-21 the commission shall adopt rules to govern transactions or
63-22 activities between a transmission and distribution utility and its
63-24 (e) The commission shall by rule establish a code of conduct
63-25 that must be observed by all market participants and their
63-26 affiliates to protect against anticompetitive practices.
64-1 (f) The commission may impose administrative penalties or
64-2 take another action under Subchapter B, Chapter 15, on a finding,
64-3 after notice and opportunity for hearing, that a power generation
64-4 company has engaged in predatory pricing. In determining whether a
64-5 power generation company has engaged in predatory pricing, the
64-6 commission shall apply the elements for a finding of predatory
64-7 pricing under Sections 15.05(a) and (b), Business & Commerce Code,
64-8 as applied by the courts of this state.
64-9 (g) Beginning on the date of introduction of customer
64-10 choice, and following review of the annual report submitted to it
64-11 under Sections 39.155(b) and (c), the commission shall determine
64-12 whether specific transmission or distribution constraints or
64-13 bottlenecks within this state give rise to market power in specific
64-14 geographic markets in the state. The commission, on a finding that
64-15 specific transmission or distribution constraints or bottlenecks
64-16 within this state give rise to market power, may order reasonable
64-17 mitigation of that potential market power by ordering, pursuant to
64-18 Section 39.203(e), one or more electric utilities or transmission
64-19 and distribution utilities to construct additional transmission or
64-20 distribution capacity, or both, subject to the certification
64-21 provisions of this title.
64-22 Sec. 39.158. MERGERS AND CONSOLIDATIONS. (a) An owner of
64-23 electric generation facilities that offers electricity for sale in
64-24 the state and proposes to merge, consolidate, or otherwise become
64-25 affiliated with another owner of electric generation facilities
64-26 that offers electricity for sale in this state shall obtain the
65-1 approval of the commission prior to closing. Such approval shall
65-2 be requested at least 120 days prior to the proposed closing. The
65-3 commission shall approve the transaction unless the commission
65-4 finds that the transaction results in a violation of Section
65-5 39.154. If the commission finds that the transaction as proposed
65-6 would violate Section 39.154, the commission may condition approval
65-7 of the transaction on adoption of reasonable modifications to the
65-8 transaction as prescribed by the commission to mitigate potential
65-9 market power abuses.
65-10 (b) Nothing in this chapter shall be construed to confer
65-11 immunity from state or federal antitrust laws. This chapter is
65-12 intended to complement other state and federal antitrust
65-13 provisions. Therefore, antitrust remedies may also be sought in
65-14 state or federal court to remedy anticompetitive activities.
65-15 (c) This section shall not be deemed to authorize commission
65-16 review or approval of transactions entered into between or among
65-17 municipally owned utilities, river authorities, special districts
65-18 created by law, or other political subdivisions, whether or not
65-19 such transactions may be characterized as mergers, consolidations,
65-20 or other affiliations, when the transaction is authorized or
65-21 structured pursuant to state law.
65-22 SUBCHAPTER E. PRICE REGULATION AFTER COMPETITION
65-23 Sec. 39.201. COST OF SERVICE TARIFFS AND CHARGES. (a) Each
65-24 electric utility shall, on or before April 1, 2000, file proposed
65-25 tariffs for its proposed transmission and distribution utility.
65-26 (b) The filing under this section shall include supporting
66-1 cost data for determination of nonbypassable delivery charges,
66-2 which shall be the sum of:
66-3 (1) transmission and distribution utility charges by
66-4 customer class based on a forecasted 2002 test year;
66-5 (2) a system benefit fund charge; and
66-6 (3) an expected competition transition charge, if any.
66-7 (c) Each electric utility shall also identify the unbundled
66-8 generation and retail energy service costs by customer class.
66-9 (d) On or before October 1, 2000, and in accordance with a
66-10 schedule and procedures it establishes, the commission shall hold a
66-11 hearing and approve or modify and make effective as of January 1,
66-12 2002, the transmission and distribution utility's proposed tariffs
66-13 for transmission and distribution services, the system benefit fund
66-14 charge, and the expected competition transition charge, if any.
66-15 (e) The system benefit fund charge shall be that established
66-16 by the commission pursuant to Section 39.603.
66-17 (f) The expected competition transition charge shall be that
66-18 as determined under Subsections (g) and (h) and as implemented
66-19 under Subsections (i)-(l).
66-20 (g) The expected competition transition charge approved by
66-21 the commission shall be calculated from the amount of stranded
66-22 costs as defined in Subchapter F which are reasonably projected to
66-23 exist on the last day of the freeze period modified to reflect any
66-24 adjustments determined appropriate by the commission pursuant to
66-25 Section 39.261(c).
66-26 (h) The electric utility shall use the ECOM administrative
67-1 model referenced in Section 39.262(h) to determine estimated
67-2 stranded costs. The model must include updated company-specific
67-3 inputs and updated natural gas price forecasts as determined by the
67-5 (i) An electric utility may:
67-6 (1) at any time after the start of the freeze period,
67-7 securitize 100 percent of its regulatory assets as defined by
67-8 Section 39.251(6) and up to 75 percent of its remaining estimated
67-9 stranded costs as defined by this section and recover such charges
67-10 through a transition charge, pursuant to a financing order issued
67-11 by the commission under Section 39.303;
67-12 (2) implement, under bond, a nonbypassable charge of
67-13 up to 100 percent of its estimated stranded costs; or
67-14 (3) use a combination of the two methods under
67-15 Subdivisions (1) and (2).
67-16 (j) Any competition transition charge shall be allocated
67-17 among retail customer classes based on the relevant customer class
67-18 characteristics as of May 1, 1999, in accordance with the
67-19 methodology used to allocate the costs of the underlying assets in
67-20 the electric utility's most recent commission order addressing rate
67-21 design, unless the utility has agreed to an alternative allocation
67-22 of stranded costs in a settlement agreed to as part of a transition
67-23 plan approved by the commission on or after January 1, 1998, in
67-24 which case the alternative allocation shall apply.
67-25 (k) In determining the length of time over which costs under
67-26 Subsection (h) may be recovered, the commission shall consider:
68-1 (1) the electric utility's rates as of the end of the
68-2 freeze period;
68-3 (2) the sum of the transmission, distribution, and
68-4 system benefit fund charges;
68-5 (3) the proportion of estimated stranded costs to the
68-6 invested capital of the electric utility; and
68-7 (4) any other factor consistent with the public
68-8 interest as expressed in this chapter.
68-9 (l) Two years after customer choice is introduced in the
68-10 electric utility's power region, the stranded cost estimate under
68-11 this section shall be reviewed and, if necessary, adjusted to
68-12 reflect a final, actual valuation in the true-up proceeding under
68-13 Section 39.262. If, based on that proceeding, the competition
68-14 transition charge is not sufficient, the commission may extend the
68-15 collection period for the charge or, if necessary, increase the
68-16 charge. Alternatively, if it is found in the true-up proceeding
68-17 that the competition transition charge is larger than is needed to
68-18 recover any remaining stranded costs, the commission may:
68-19 (1) reduce the competition transition charge, to the
68-20 extent it has not been securitized;
68-21 (2) reverse, in whole or in part, the depreciation
68-22 expense which has been redirected pursuant to Section 39.256;
68-23 (3) reduce the transmission and distribution utility's
68-24 rates; or
68-25 (4) implement a combination of the elements in
68-26 Subdivisions (1)-(3).
69-1 (m) If the commission determines that a power region will
69-2 not qualify for customer choice under Section 39.152 by January 1,
69-3 2002, it may adjust the filing and implementation dates in this
69-4 section for utilities in that region.
69-5 Sec. 39.202. PRICE TO BEAT. (a) On and after January 1,
69-6 2002, in areas in which customer choice has been introduced, an
69-7 affiliated retail electric provider shall charge residential and
69-8 small commercial customers of its affiliated transmission and
69-9 distribution utility rates which, on a bundled basis, are five
69-10 percent less than the affiliated electric utility's corresponding
69-11 average residential and small commercial rates, on a bundled basis,
69-12 that were in effect on January 1, 1999, adjusted to reflect the
69-13 fuel factor determined as provided by Subsection (b) and adjusted
69-14 for any base rate reduction as stipulated to by an electric utility
69-15 in a proceeding for which a final order had not been issued by
69-16 January 1, 1999. These rates on a bundled basis shall be known as
69-17 the "price to beat" for residential and small commercial customers.
69-18 (b) For an area where customer choice is to be introduced on
69-19 January 1, 2002, the commission shall determine the fuel factor for
69-20 each electric utility in the area as of December 31, 2001. For an
69-21 area where customer choice is to be introduced subsequent to
69-22 January 1, 2002, the commission shall determine the fuel factor for
69-23 each electric utility in the area on the day prior to the day
69-24 customer choice is introduced.
69-25 (c) Subsequent to the introduction of customer choice, each
69-26 affiliated power generation company shall file a final fuel
70-1 reconciliation for the period ending the day prior to the day
70-2 customer choice is introduced. The final fuel balance from that
70-3 reconciliation shall be included in the true-up proceeding pursuant
70-4 to Section 39.262.
70-5 (d) An affiliated retail electric provider shall make public
70-6 its price to beat in a manner that provides adequate disclosure as
70-7 determined by the commission.
70-8 (e) The affiliated retail electric provider may not charge
70-9 rates that are different from the price to beat until the earlier
70-10 of 60 months after the date customer choice is introduced in the
70-11 power region or the date the commission determines that 40 percent
70-12 or more of the electric power consumed by residential and small
70-13 commercial customers within the affiliated transmission and
70-14 distribution utility's certificated service area before the onset
70-15 of customer choice is committed to be served by nonaffiliated
70-16 retail electric providers.
70-17 (f) The following standards shall be used for measuring
70-18 electric power consumption during the period prior to the onset of
70-19 customer choice:
70-20 (1) the consumption of residential and small
70-21 commercial customers with an annual peak demand less than or equal
70-22 to 20 kilowatts shall be based on the average annual consumption of
70-23 those respective groups during the year 2000; and
70-24 (2) consumption for all small commercial customers
70-25 with an annual peak demand larger than 20 kilowatts shall be based
70-26 on each customer's usage during the year 2000. If less than 12
71-1 months of consumption history exists for any such customer, the
71-2 usage history shall be supplemented with the prior history of that
71-3 customer's location. For service to a new location, the annual
71-4 consumption shall be determined as the transmission and
71-5 distribution utility's estimate of the maximum annual kilowatt
71-6 demand used in sizing the electric service to that customer
71-7 multiplied by 8,760 hours, and that product multiplied by the
71-8 average annual customer load factor for small commercial customers
71-9 with loads greater than 20 kilowatts for the year 2000.
71-10 (g) Upon determining that its affiliated retail electric
71-11 provider has met the requirements of Subsection (e), an electric
71-12 utility or a transmission and distribution utility shall make a
71-13 filing with the commission attesting to the fact that those
71-14 requirements have been met and that the restrictions of this
71-15 section are no longer applicable. The commission shall accept or
71-16 reject such filing within 30 days.
71-17 (h) Following the true-up proceedings conducted pursuant to
71-18 Section 39.262, the commission may adjust the price to beat
71-19 consistent with the results of that proceeding.
71-20 (i) An affiliated retail electric provider may request that
71-21 the commission adjust the fuel factor established under Subsection
71-22 (b) up to twice a year if the affiliated retail electric provider
71-23 demonstrates that the existing fuel factor does not adequately
71-24 reflect significant changes in the market price of natural gas and
71-25 purchased energy used to serve retail customers.
71-26 (j) In this section, "small commercial customer" means a
72-1 commercial customer having a peak demand of 1,000 kilowatts or
72-3 (k) Upon finding that a retail electric provider will be
72-4 unable to maintain its financial integrity if it complies with
72-5 Subsection (a), the commission shall set the retail electric
72-6 provider's price to beat at the minimum level that will allow the
72-7 retail electric provider to maintain its financial integrity.
72-8 However, in no event shall the price to beat exceed the level of
72-9 rates, on a bundled basis, charged by the affiliated electric
72-10 utility on September 1, 1999, adjusted for fuel as provided in
72-11 Subsection (b).
72-12 Sec. 39.203. TRANSMISSION AND DISTRIBUTION SERVICE.
72-13 (a) All transmission and distribution utilities shall provide
72-14 transmission service at wholesale under Subchapter A, Chapter 35.
72-15 In addition, on and after January 1, 2002, a transmission and
72-16 distribution utility shall provide transmission or distribution
72-17 service, or both, at retail to an electric utility, a retail
72-18 electric provider, a municipally owned utility, an electric
72-19 cooperative, or an end-use customer at rates, terms of access, and
72-20 conditions that are comparable to those that apply to the
72-21 transmission and distribution utility and its affiliates. A
72-22 municipally owned utility offering customer choice or an electric
72-23 cooperative offering customer choice shall likewise provide
72-24 transmission or distribution service, or both, at retail to all
72-25 such entities pursuant to the commission's rules applicable to
72-26 terms and conditions of access and at rates adopted in accordance
73-1 with Sections 40.055(a)(1) and 41.055(1), respectively.
73-2 (b) When necessary to serve a wholesale customer an electric
73-3 utility, an electric cooperative that has not opted for customer
73-4 choice, or a municipally owned utility that has not opted for
73-5 customer choice shall provide wholesale transmission service at
73-6 distribution voltage.
73-7 (c) On or before January 1, 2002, the commission shall
73-8 establish for all retail electric utilities offering customer
73-9 choice reasonable and comparable terms and conditions, pursuant to
73-10 Section 39.201, that comply with Subsection (a) for open access on
73-11 distribution facilities and shall establish, for all retail
73-12 electric utilities offering customer choice other than municipally
73-13 owned utilities and electric cooperatives, reasonable and
73-14 comparable rates for open access on distribution facilities.
73-15 (d) The terms of access, conditions, and rates established
73-16 under Subsection (c) shall be comparable to the terms of access,
73-17 conditions, and rates that the electric utility applies to itself
73-18 or its affiliates. The rules shall also provide that all ancillary
73-19 services provided by the utility to itself or its affiliates are
73-20 also available to third parties on request on a nondiscriminatory
73-22 (e) The commission may require an electric utility or a
73-23 transmission and distribution utility to construct or enlarge
73-24 facilities to ensure safe and reliable service for the state's
73-25 electric markets. In any proceeding brought pursuant to Chapter
73-26 37, an electric utility or transmission and distribution utility
74-1 ordered to construct or enlarge facilities pursuant to this
74-2 subchapter need not prove that the construction ordered is
74-3 necessary for the service, accommodation, convenience, or safety of
74-4 the public and need not address the factors listed in Section
74-5 37.056(c)(1)-(3) and (4)(E).
74-6 (f) The commission's rules must be consistent with the
74-7 standards of this title and may not be contrary to an applicable
74-8 decision, rule, or policy statement of a federal regulatory agency
74-9 having jurisdiction.
74-10 (g) Each qualifying power region shall have generally
74-11 applicable tariffs approved by the commission or a federal
74-12 regulatory agency having jurisdiction that guarantees open and
74-13 nondiscriminatory access as required by Section 39.152. This
74-14 subsection shall not be deemed to vest in the commission power to
74-15 set or approve distribution access rates of a municipally owned
74-16 utility or an electric cooperative that has adopted customer
74-18 Sec. 39.204. TARIFFS FOR OPEN ACCESS. Each transmission and
74-19 distribution utility shall file a tariff implementing the open
74-20 access rules with the commission or the federal regulatory
74-21 authority having jurisdiction over the transmission and
74-22 distribution service of the utility not later than the 90th day
74-23 before the date customer choice is offered by that utility.
74-24 Sec. 39.205. REGULATION OF COSTS FOLLOWING THE FREEZE
74-25 PERIOD. At the conclusion of the freeze period, any remaining
74-26 costs associated with nuclear decommissioning obligations continue
75-1 to be subject to cost of service rate regulation and shall be
75-2 included as a nonbypassable charge to retail customers.
75-3 SUBCHAPTER F. RECOVERY OF STRANDED COSTS
75-4 Sec. 39.251. DEFINITIONS. In this subchapter:
75-5 (1) "Above market purchased power costs" means
75-6 wholesale demand and energy costs that a utility is obligated to
75-7 pay under an existing purchased power contract to the extent the
75-8 costs are greater than the purchased power market value.
75-9 (2) "Existing purchased power contract" means a
75-10 purchased power contract in effect on January 1, 1999, including
75-11 any amendments and revisions to such contracts resulting from
75-12 litigation initiated prior to January 1, 1999.
75-13 (3) "Generation assets" means all assets associated
75-14 with the production of electricity, including generation plants,
75-15 electrical interconnections of the generation plant to the
75-16 transmission system, fuel contracts, fuel transportation contracts,
75-17 water contracts, lands, surface or subsurface water rights,
75-18 emissions-related allowances, gas pipeline interconnections, and
75-19 generation-related regulatory assets.
75-20 (4) "Market value" means, for nonnuclear assets and
75-21 certain nuclear assets, the value the assets would have if bought
75-22 and sold in a bona fide third-party transaction or transactions on
75-23 the open market under Section 39.262(g) or, for certain nuclear
75-24 assets, as described by Section 39.262(h), the value determined
75-25 under the method provided by that subsection.
75-26 (5) "Purchased power market value" means the value of
76-1 demand and energy bought and sold in a bona fide third-party
76-2 transaction or transactions on the open market and determined by
76-3 using the weighted average costs of the highest three offers from
76-4 the market for purchase of the demand and energy available under
76-5 the existing purchased power contracts.
76-6 (6) "Regulatory assets" means costs that have been
76-7 deferred for future recovery as a result of an order by a
76-8 regulatory authority as of September 1, 1999, offset by the
76-9 applicable portion of investment tax credits permitted under the
76-10 Internal Revenue Code of 1986, including:
76-11 (A) unrecovered deferred income taxes recorded
76-12 under Statement of Financial Accounting Standards No. 109
76-13 ("Accounting for Income Taxes");
76-14 (B) plant accounting deferrals, including mirror
76-15 construction work in progress; and
76-16 (C) costs associated with reacquisition of
76-17 securities, canceled plants, litigation and settlement costs, and
76-18 voluntary retirement and severance programs.
76-19 (7) "Retail stranded costs" means that part of net
76-20 stranded cost associated with the provision of retail service.
76-21 (8) "Stranded cost" means the positive excess of the
76-22 net book value of generation assets over the market value of the
76-23 assets, taking into account all of the electric utility's
76-24 generation assets, and any above market purchased power costs.
76-25 Sec. 39.252. RIGHT TO RECOVER STRANDED COSTS. (a) An
76-26 electric utility is allowed to recover all of its net, verifiable,
77-1 nonmitigable stranded costs incurred in purchasing power and
77-2 providing electric generation service.
77-3 (b) Recovery of retail stranded costs by an electric utility
77-4 shall be from all existing or future retail customers, including
77-5 the facilities, premises, and loads of such retail customers,
77-6 within the utility's geographical certificated service area as it
77-7 existed on May 1, 1999.
77-8 (c) In multiply certificated areas, a retail customer may
77-9 not avoid stranded cost recovery charges by switching to another
77-10 electric utility, electric cooperative, or municipally owned
77-11 utility after May 1, 1999. A customer in a multiply certificated
77-12 service area that requested to switch providers on or before May 1,
77-13 1999, or was not taking service from an electric utility on May 1,
77-14 1999, and does not do so after that date is not responsible for
77-15 paying retail stranded costs of that utility.
77-16 Sec. 39.253. ALLOCATION OF STRANDED COSTS. Retail stranded
77-17 costs shall be allocated among retail customer classes, based on
77-18 the relevant customer class characteristics as of May 1, 1999, in
77-19 accordance with the methodology used to allocate the costs of the
77-20 underlying assets in the electric utility's most recent commission
77-21 order addressing rate design, unless the utility has agreed to an
77-22 alternative allocation of stranded costs in a settlement agreed to
77-23 as part of a transition plan approved by the commission on or after
77-24 January 1, 1998, in which case the alternative allocation shall
77-26 Sec. 39.254. USE OF REVENUES FOR UTILITIES WITH STRANDED
78-1 COSTS. This subchapter provides a number of tools to an electric
78-2 utility to mitigate stranded costs. Each electric utility that was
78-3 reported by the commission to have positive "excess costs over
78-4 market" (ECOM), denoted as the "base case" for the amount of
78-5 stranded costs before full retail competition in 2001 with respect
78-6 to its Texas jurisdiction, in the April 1998 Report to the Texas
78-7 Senate Interim Committee on Electric Utility Restructuring entitled
78-8 "Potentially Strandable Investment (ECOM) Report: 1998 Update,"
78-9 must use these tools to reduce the net book value of, otherwise
78-10 referred to as "accelerate" the cost recovery of, its stranded
78-11 costs each year. Any positive difference under the report required
78-12 by Section 39.257(b) shall be applied to the net book value of
78-13 generation assets.
78-14 Sec. 39.255. USE OF REVENUES FOR UTILITIES WITH NO STRANDED
78-15 COSTS. (a) An electric utility that does not have stranded costs
78-16 described by Section 39.254 shall be permitted to use any positive
78-17 difference under the report required by Section 39.257(b) on
78-18 capital expenditures to improve or expand transmission or
78-19 distribution facilities, or on capital expenditures to improve air
78-20 quality, as approved by the commission. Any such capital
78-21 expenditures shall be made in the calendar year immediately
78-22 following the year for which the report required by Section 39.257
78-23 is calculated. Such capital expenditures shall be reflected in any
78-24 future proceeding under this chapter to set transmission or
78-25 distribution rates as a reduction to the utility's transmission and
78-26 distribution invested capital, as approved by the commission.
79-1 (b) To the extent that positive differences under the report
79-2 required by Section 39.257(b) are not used for such capital
79-3 expenditures, such amounts shall be flowed back to the electric
79-4 utility's Texas jurisdictional customers through the power cost
79-5 recovery factor.
79-6 (c) This section applies only to the use of positive
79-7 differences under the report required by Section 39.257(b) for each
79-8 year during the freeze period.
79-9 Sec. 39.256. OPTION TO REDIRECT DEPRECIATION. (a) During
79-10 the freeze period, an electric utility described in Section 39.254
79-11 may redirect all or a part of the depreciation expense relating to
79-12 transmission and distribution assets to its net generation plant
79-14 (b) The electric utility shall report a decision under
79-15 Subsection (a) to the commission and any other applicable
79-16 regulatory authority.
79-17 (c) Any adjustments made to the book value of transmission
79-18 and distribution assets or the creation of any related regulatory
79-19 assets resulting from the redirection under this section shall be
79-20 accepted and applied by the commission for establishing net
79-21 invested capital and transmission and distribution rates for retail
79-22 customers in all future proceedings.
79-23 (d) Notwithstanding the provisions of Subsection (c), the
79-24 design of post-freeze-period retail rates may not:
79-25 (1) shift the allocation of responsibility for
79-26 stranded costs;
80-1 (2) include the adjusted costs in wholesale
80-2 transmission and distribution rates; or
80-3 (3) apply the adjustments for the purpose of
80-4 establishing net invested capital and transmission and distribution
80-5 rates for wholesale customers.
80-6 Sec. 39.257. ANNUAL REPORT. (a) Beginning with the 1999
80-7 calendar year, each electric utility shall file a report with the
80-8 commission no later than 90 days after the end of each year during
80-9 the freeze period under a schedule and a format determined by the
80-11 (b) The report shall identify any positive difference
80-12 between annual revenues, reduced by the amount of annual revenues
80-13 under Sections 36.203 and 36.205, the revenues received under the
80-14 interutility billing process as adopted by the commission to
80-15 implement Sections 35.004, 35.006, and 35.007, revenues associated
80-16 with transition charges as defined by Section 39.302, and annual
80-18 Sec. 39.258. ANNUAL REPORT: DETERMINATION OF ANNUAL COSTS.
80-19 For the purposes of determining the annual costs in each annual
80-20 report, the following amounts shall be used:
80-21 (1) the Texas jurisdictional operation and maintenance
80-22 expense reflected in each utility's 1996 Federal Energy Regulatory
80-23 Commission Form 1, plus factoring expenses not included in
80-24 operation and maintenance, adjusted for:
80-25 (A) costs under Sections 36.062, 36.203, and
80-26 36.205, and not indexed for inflation or load growth; and
81-1 (B) any difference between the annual revenues
81-2 and the expenses recorded under the interutility billing process
81-3 adopted by the commission to implement Sections 35.004, 35.006, and
81-5 (2) the amount of nuclear decommissioning expense
81-6 approved in the electric utility's last rate proceeding before the
81-7 commission, as may be required to be adjusted to comply with
81-8 applicable federal regulatory requirements;
81-9 (3) the depreciation rates approved in the electric
81-10 utility's last rate proceeding before the commission;
81-11 (4) the amortization expense approved in the electric
81-12 utility's last rate proceeding before the commission, except that
81-13 if the items are fully amortized during the freeze period, the
81-14 expense shall be adjusted accordingly;
81-15 (5) taxes and fees, including municipal franchise fees
81-16 to the extent not included in Subdivision (1), other than federal
81-17 income taxes, and assessments incurred that year;
81-18 (6) federal income tax expense, computed according to
81-19 the stand-alone methodology and using the actual capital structure
81-20 and actual cost of debt as of December 31 of the report year;
81-21 (7) return on invested capital, computed by
81-22 multiplying invested capital as of December 31 of the report year,
81-23 determined as provided by Section 39.259, by the cost of capital
81-24 approved in the electric utility's most recent rate proceeding
81-25 before the commission in which the cost of capital was specifically
81-26 adopted, or, in the case of a range, the midpoint of the range, if
82-1 the final rate order for the proceeding was issued on or after
82-2 January 1, 1992. If such an order does not exist, a cost of
82-3 capital of 9.6 percent shall be used; and
82-4 (8) the amount resulting from any operation and
82-5 maintenance expense savings tracker from a merger of two utilities
82-6 and contained in a settlement agreement approved by the commission
82-7 prior to January 1, 1999.
82-8 Sec. 39.259. ANNUAL REPORT: DETERMINATION OF INVESTED
82-9 CAPITAL. (a) For the purposes of determining invested capital in
82-10 each annual report, the net plant in service, regulatory assets,
82-11 and deferred federal income taxes shall be updated each year, and
82-12 generation-related invested capital shall be reduced by the amount
82-13 of securitization under Section 39.201(i) and 39.262(c) to the
82-14 extent otherwise included in invested capital.
82-15 (b) Capital additions to a plant in an amount less than
82-16 1-1/2 percent of the electric utility's net plant in service on
82-17 December 31, 1998, less plant items previously excluded by the
82-18 commission, for each of the years 1999 through 2001 are presumed
82-20 (c) All other items in invested capital shall be as approved
82-21 in the electric utility's last rate proceeding before the
82-23 Sec. 39.260. USE OF GENERALLY ACCEPTED ACCOUNTING
82-24 PRINCIPLES. (a) The definition and identification of invested
82-25 capital and other terms used in this subchapter that affect the net
82-26 book value of generation assets and the treatment of transactions
83-1 performed under Section 35.035 and other transactions authorized by
83-2 this title or approved by the regulatory authority that affect the
83-3 net book value of generation assets during the freeze period shall
83-4 be treated in accordance with generally accepted accounting
83-5 principles as modified by regulatory accounting rules generally
83-6 applicable to utilities.
83-7 (b) The principles and criteria described by Subsection (a),
83-8 including the criteria for applicability of Statement of Financial
83-9 Accounting Standards No. 71 ("Accounting for the Effects of Certain
83-10 Types of Regulation"), shall be applied for purposes of this
83-11 subchapter as they existed on January 1, 1999.
83-12 Sec. 39.261. REVIEW OF ANNUAL REPORT. (a) The annual
83-13 report filed under this subchapter is a public document and shall
83-14 be reviewed by the staff of the commission and the office of public
83-15 utility counsel. Both staffs may review work papers and supporting
83-16 documents and engage in discussions with the utility about the data
83-17 underlying the reports.
83-18 (b) The staff of the commission and the office of public
83-19 utility counsel shall communicate in writing to an electric utility
83-20 not later than the 180th day after the date the report is filed if
83-21 they have any disagreements with the data or computations.
83-22 (c) The commission shall finalize and resolve any
83-23 disagreements related to the annual report as follows:
83-24 (1) for each calendar year, the commission shall
83-25 finalize the annual report prior to establishing the competition
83-26 transition charge pursuant to Section 39.201; and
84-1 (2) for each calendar year, the commission shall
84-2 finalize the annual report and reflect the result as part of the
84-3 true-up proceeding pursuant to Section 39.262.
84-4 Sec. 39.262. TRUE-UP PROCEEDING. (a) An electric utility,
84-5 together with its affiliated retail electric provider and its
84-6 affiliated transmission and distribution utility, may not be
84-7 permitted to overrecover stranded costs through the procedures
84-8 established by this section or through the application of the
84-9 measures provided by the other sections of this chapter.
84-10 (b) After the freeze period, an electric utility located in
84-11 a power region not subject to competition pursuant to Section
84-12 39.152 shall continue to file annual reports pursuant to Sections
84-13 39.257, 39.258, and 39.259 as if the freeze period remained in
84-14 effect, until such time as the power region qualifies for
84-15 competition under Section 39.152. In addition, the commission
84-16 staff and the office of public utility counsel shall continue to
84-17 review the annual reports as provided by Section 39.261.
84-18 (c) After January 1, 2004, or after two years following the
84-19 beginning of competition in a power region, whichever is later, at
84-20 a schedule and under procedures to be determined by the commission,
84-21 each transmission and distribution utility, its affiliated retail
84-22 electric provider, and its affiliated power generation company
84-23 shall jointly file to finalize stranded costs pursuant to
84-24 Subsections (g) and (h) and reconcile those costs with the
84-25 estimated stranded costs used to develop the competition transition
84-26 charge in the proceeding held under Section 39.201. Any resulting
85-1 difference shall be applied to the nonbypassable delivery rates of
85-2 the transmission and distribution utility, except that at the
85-3 utility's option, any or all of the remaining stranded costs may be
85-4 securitized pursuant to Subchapter G.
85-5 (d) The affiliated power generation company shall reconcile,
85-6 and either credit or bill to the transmission and distribution
85-7 utility, the net sum of:
85-8 (1) the former electric utility's final fuel balance
85-9 determined pursuant to Section 39.202(c); and
85-10 (2) any difference between the price of power obtained
85-11 through the capacity auctions under Sections 39.153 and 39.156 and
85-12 the power cost projections which were employed for the same time
85-13 period in the ECOM model to estimate stranded costs in the
85-14 proceeding under Section 39.201.
85-15 (e) To the extent that the price to beat exceeded the market
85-16 price of electricity, the affiliated retail electric provider shall
85-17 reconcile and credit to the affiliated transmission and
85-18 distribution utility any positive difference between the price to
85-19 beat established under Section 39.202, reduced by the nonbypassable
85-20 delivery charge established under Section 39.201, and the
85-21 prevailing market price of electricity during the same time period;
85-22 provided, however, that no such reconciliation shall be required
85-23 under this subsection of any affiliated retail electric provider
85-24 that satisfies the requirements of Section 39.202(e) prior to the
85-25 expiration of two years from the introduction of customer choice in
85-26 the applicable power region. In no event shall the amount credited
86-1 exceed 50 percent of the net income reported by the affiliated
86-2 retail electric provider in its annual report to the Securities and
86-3 Exchange Commission on Form 10-K.
86-4 (f) Based on the credits or bills received from its
86-5 affiliates pursuant to Subsections (d) and (e), the transmission
86-6 and distribution utility shall make necessary adjustments to the
86-7 nonbypassable delivery rates it charges to retail electric
86-8 providers. If the commission determines that the nonbypassable
86-9 delivery rates are not sufficient, the commission may extend the
86-10 original collection period for the charge or, if necessary,
86-11 increase the charge. Alternatively, if the commission determines
86-12 that the nonbypassable delivery rates are larger than are needed to
86-13 recover the transmission and distribution utility's costs, the
86-14 commission shall correspondingly reduce:
86-15 (1) the competition transition charge, to the extent
86-16 it has not been securitized;
86-17 (2) the depreciation expense which has been redirected
86-18 pursuant to Section 39.256;
86-19 (3) the transmission and distribution utility's rates;
86-21 (4) a combination of the elements in Subdivisions
86-23 (g) For the purpose of finalizing the stranded cost estimate
86-24 used to establish the competition transition charge under Section
86-25 39.201, and, except as provided in Subsection (h), the affiliated
86-26 power generation company shall quantify its stranded costs using
87-1 one or more of the following methods:
87-2 (1) Sale of Assets. If, at any time after December
87-3 31, 1999, an electric utility or its affiliated power generation
87-4 company has sold some or all of its generation assets, which sale
87-5 shall include all generating assets associated with each generating
87-6 plant that is sold, in a bona fide third-party transaction under a
87-7 competitive offering, the total net value realized from the sale
87-8 establishes the market value of the generation assets sold. If not
87-9 all assets are sold, the market value of the remaining generation
87-10 assets shall be established by one or more of the other methods in
87-11 this section.
87-12 (2) Stock Valuation Method. If, at any time after
87-13 December 31, 1999, an electric utility or its affiliated power
87-14 generation company has transferred some or all of its generation
87-15 assets, including, at the election of the electric utility or power
87-16 generation company, any fuel and fuel transportation contracts
87-17 related to those assets, to one or more separate affiliated or
87-18 nonaffiliated corporations, not less than 51 percent of the common
87-19 stock of each corporation is spun off and sold to public investors
87-20 through a national stock exchange, and the common stock has been
87-21 traded for not less than one year, the resulting average daily
87-22 closing price of the common stock over 30 consecutive trading days
87-23 chosen by the commission out of the last 120 consecutive trading
87-24 days before the filing required under Subsection (c) establishes
87-25 the market value of the common stock equity in each transferee
87-26 corporation. The book value of each transferee corporation's debt
88-1 and preferred stock securities shall be added to the market value
88-2 of its assets. The market value of each transferee corporation's
88-3 assets shall be reduced by the corresponding net book value of the
88-4 assets acquired by each transferee corporation from any entity
88-5 other than the affiliated electric utility or power generation
88-6 company. The resulting market value of the assets establishes the
88-7 market value of the generation assets transferred by the electric
88-8 utility or power generation company to each separate corporation.
88-9 If not all assets are disposed of in this manner, the market value
88-10 of the remaining assets shall be established by one or more of the
88-11 other methods in this section.
88-12 (3) Partial Stock Valuation Method. If, at any time
88-13 after December 31, 1999, an electric utility or its affiliated
88-14 power generation company has transferred some or all of its
88-15 generation assets, including, at the election of the electric
88-16 utility or power generation company, any fuel and fuel
88-17 transportation contracts related to those assets, to one or more
88-18 separate affiliated or nonaffiliated corporations, at least 19
88-19 percent, but less than 51 percent, of the common stock of each
88-20 corporation is spun off and sold to public investors through a
88-21 national stock exchange, and the common stock has been traded for
88-22 not less than one year, the resulting average daily closing price
88-23 of the common stock over 30 consecutive trading days chosen by the
88-24 commission out of the last 120 consecutive trading days before the
88-25 filing required under Subsection (c) shall be presumed to establish
88-26 the market value of the common stock equity in each transferee
89-1 corporation. The commission may accept the market valuation to
89-2 conclusively establish the value of the common stock equity in each
89-3 transferee corporation or convene a valuation panel of three
89-4 independent financial experts to determine whether the percentage
89-5 of common stock sold is fairly representative of the total common
89-6 stock equity or whether a control premium exists for the retained
89-7 interest. The valuation panel must consist of financial experts,
89-8 chosen from proposals submitted in response to commission requests,
89-9 from the top 10 nationally recognized investment banks with
89-10 demonstrated experience in the United States electric industry as
89-11 indicated by the dollar amount of public offerings of long-term
89-12 debt and equity of United States investor-owned electric companies
89-13 over the immediately preceding three years as ranked by the
89-14 publications "Securities Data" or "Institutional Investor." If the
89-15 panel determines that a control premium exists for the retained
89-16 interest, the panel shall determine the amount of the control
89-17 premium, and the commission shall adopt the determination but may
89-18 not increase the market value by a control premium greater than 10
89-19 percent. The costs and expenses of the panel, as approved by the
89-20 commission, shall be paid by each transferee corporation. The
89-21 determination of the commission based on the finding of the panel
89-22 conclusively establishes the value of the common stock of each
89-23 transferee corporation. The book value of each transferee
89-24 corporation's debt and preferred stock securities shall be added to
89-25 the market value of its assets. The market value of each
89-26 transferee corporation's assets shall be reduced by the
90-1 corresponding net book value of the assets acquired by each
90-2 transferee corporation from any entity other than the affiliated
90-3 electric utility or power generation company. The resulting market
90-4 value of the assets establishes the market value of the generation
90-5 assets transferred by the electric utility or power generation
90-6 company to each separate corporation.
90-7 (h) Unless an electric utility or its affiliated power
90-8 generation company combines all of its generation assets into one
90-9 or more transferee corporations as described in Subsections (g)(2)
90-10 and (3), the electric utility shall quantify its stranded costs for
90-11 nuclear assets using the ECOM method. The ECOM method is the
90-12 estimation model prepared for and described by the commission's
90-13 April 1998 Report to the Texas Senate Interim Committee on Electric
90-14 Restructuring entitled "Potentially Strandable Investment (ECOM)
90-15 Report: 1998 Update." The methodology used in the model must be
90-16 the same as that used in the 1998 report to determine the "base
90-17 case." At the time of the proceeding under this section, the ECOM
90-18 model shall be rerun using updated company-specific inputs required
90-19 by the model, updating the market price of electricity, and using
90-20 updated natural gas price forecasts and the capacity cost based on
90-21 the long-run marginal cost of the most economic new generation
90-22 technology then available. Natural gas price projections used in
90-23 the model must be based on the most credible publicly available
90-24 market-based data. The commission by rule shall establish, before
90-25 June 1, 2000, the precise methodology to be used by the commission
90-26 in updating natural gas forecasts.
91-1 (i) The commission shall conduct the hearing in this case as
91-2 a contested case.
91-3 (j) The commission shall issue a final order not later than
91-4 the 150th day after the date of the filing under this section by
91-5 the transmission and distribution utility, its affiliated retail
91-6 electric provider, and its affiliated power generation company, and
91-7 the resulting order shall be subject to judicial review under
91-8 Chapter 2001, Government Code.
91-9 (k) Notwithstanding Section 39.252, to the extent that a
91-10 customer's actual load has been lawfully served by a fully
91-11 operational qualifying facility before September 1, 2001, or by an
91-12 on-site power production facility with a rated capacity of 10
91-13 megawatts or less, any charge for recovery of stranded costs under
91-14 this section or Subchapter G assessed on that customer after the
91-15 facility becomes fully operational shall be included only in those
91-16 tariffs or charges associated with the services actually provided
91-17 by the transmission and distribution utility, if any, to the
91-18 customer after the facility became fully operational and may not
91-19 include any costs associated with the service provided to the
91-20 customer by the electric utility or its affiliated transmission and
91-21 distribution utility under their tariffs before the operation of
91-22 that qualifying facility. To qualify under this subsection, a
91-23 qualifying facility must have made substantially complete filings
91-24 on or before December 31, 1999, for all necessary site-specific
91-25 environmental permits under the rules of the Texas Natural Resource
91-26 Conservation Commission in effect at the time of filing.
92-1 Sec. 39.263. STRANDED COST RECOVERY OF ENVIRONMENTAL CLEANUP
92-2 COSTS. (a) Subject to the provisions of Subsection (c), capital
92-3 costs incurred by an electric utility to improve air quality prior
92-4 to January 1, 2002, are eligible for inclusion as net invested
92-5 capital under Section 39.259, notwithstanding the limitations
92-6 imposed under Sections 39.259(b) and (c).
92-7 (b) Subject to the provisions of Subsection (c), capital
92-8 costs incurred by an electric utility to improve air quality
92-9 subsequent to January 1, 2002, and prior to May 1, 2003, are
92-10 eligible for inclusion in the determination of invested capital in
92-11 the true-up proceeding under Section 39.262.
92-12 (c) Costs incurred under Subsections (a) and (b) shall be
92-13 included as invested capital and considered in an electric
92-14 utility's stranded cost determination only to the extent that:
92-15 (1) the cost is applied to offset or reduce the
92-16 emission of airborne contaminants from an electric generating
92-17 facility, where:
92-18 (A) the reduction or offset is determined by the
92-19 Texas Natural Resource Conservation Commission to be an essential
92-20 component in achieving compliance with a national ambient air
92-21 quality standard; or
92-22 (B) the reduction or offset is necessary in
92-23 order for an unpermitted electric generating facility to obtain a
92-25 (2) the retrofit decision is determined to be the most
92-26 cost-effective after consideration of alternative measures,
93-1 including the retirement of the generating facility;
93-2 (3) the amount and location of resulting emission
93-3 reductions is consistent with the air quality goals and policies of
93-4 the Texas Natural Resource Conservation Commission; and
93-5 (4) resulting emission reduction credits are conveyed
93-6 to the state for inclusion in the state implementation plan.
93-7 (d) If the retirement of a generating facility is the most
93-8 cost-effective alternative, the net book value, including
93-9 retirement costs and offsetting salvage value, of the affected
93-10 facility shall be included in the electric utility's stranded cost
93-11 determination if the electric utility complies with Subsection
93-12 (c)(4), notwithstanding the provisions of Section 39.259(c).
93-13 (e) Not later than November 15, 2000, the commission and the
93-14 Texas Natural Resource Conservation Commission shall submit a joint
93-15 report to the governor, the lieutenant governor, the speaker of the
93-16 house of representatives, and the electric utility restructuring
93-17 legislative oversight committee as created in Section 39.607. The
93-18 report shall include:
93-19 (1) an update on the scope of and the actual and
93-20 estimated capital costs authorized by this section;
93-21 (2) the feasibility of an emission reduction credit
93-22 and trading program and the implementation of emission performance
93-23 standards for fossil fuel generation facilities;
93-24 (3) the feasibility of allowing the Texas Natural
93-25 Resource Conservation Commission to sell or auction the emission
93-26 reduction credits conveyed to the state under Subsection (c)(4) in
94-1 order to encourage the investment of new and efficient generation
94-2 technology in Texas, and the impact of using the proceeds to
94-3 encourage renewable technology development in Texas; and
94-4 (4) the feasibility of implementing additional
94-5 programs that would encourage the reduction of emissions from
94-6 electric generating facilities in a way that is competitively
94-8 Sec. 39.264. RIGHTS NOT AFFECTED. This chapter is not
94-9 intended to alter any rights of utilities to recover stranded costs
94-10 from wholesale customers.
94-11 SUBCHAPTER G. SECURITIZATION
94-12 Sec. 39.301. PURPOSE. The purpose of this subchapter is to
94-13 enable utilities to use securitization financing to recover
94-14 stranded costs, because this type of debt will lower the carrying
94-15 costs of the assets relative to the costs that would be incurred
94-16 using conventional utility financing methods. The savings
94-17 associated with securitization shall work to the benefit of
94-18 ratepayers. The amount securitized may not exceed the present
94-19 value of the revenue requirement over the life of the proposed
94-20 transition bond associated with the regulatory assets or stranded
94-21 costs sought to be securitized. The present value calculation
94-22 shall use a discount rate equal to the proposed interest rate on
94-23 the transition bonds.
94-24 Sec. 39.302. DEFINITIONS. In this subchapter:
94-25 (1) "Assignee" means any individual, corporation, or
94-26 other legally recognized entity to which an interest in transition
95-1 property is transferred, other than as security, including any
95-2 assignee of such party.
95-3 (2) "Financing order" means an order of the commission
95-4 adopted pursuant to Section 39.201 or 39.262 approving the issuance
95-5 of transition bonds and the creation of transition charges for the
95-6 recovery of qualified costs.
95-7 (3) "Financing party" means a holder of transition
95-8 bonds, including trustees, collateral agents, and other persons
95-9 acting for the benefit of such holder.
95-10 (4) "Qualified costs" means 100 percent of an electric
95-11 utility's regulatory assets and 75 percent of its remaining
95-12 recoverable costs determined by the commission pursuant to Section
95-13 39.201 and any remaining stranded costs determined pursuant to
95-14 Section 39.262 together with the costs of issuing, supporting, and
95-15 servicing transition bonds and any costs of retiring and refunding
95-16 the electric utility's existing debt and equity securities in
95-17 connection with the issuance of transition bonds. The term
95-18 includes the costs to the commission of acquiring professional
95-19 services for the purpose of evaluating proposed transactions
95-20 pursuant to Section 39.201 and this subchapter.
95-21 (5) "Transition bonds" means bonds, debentures, notes,
95-22 certificates of participation or of beneficial interest, or other
95-23 evidences of indebtedness or ownership that are issued by an
95-24 electric utility, its successors, or an assignee under a financing
95-25 order, that have a term no longer than 15 years, and that are
95-26 secured by or payable from transition property. If certificates of
96-1 participation, beneficial interest, or ownership are issued,
96-2 references in this subchapter to principal, interest, or premium
96-3 shall refer to comparable amounts under those certificates.
96-4 (6) "Transition charges" means nonbypassable amounts
96-5 to be charged for the use or availability of electric services,
96-6 approved by the commission pursuant to a financing order to recover
96-7 qualified costs, which shall be collected by an electric utility,
96-8 its successors, an assignee, or other collection agents as provided
96-9 for in the financing order.
96-10 (7) "Transition property" means the property described
96-11 in Section 39.304.
96-12 Sec. 39.303. FINANCING ORDERS; TERMS. (a) The commission
96-13 shall adopt a financing order, on application of a utility to
96-14 recover the utility's eligible stranded costs under Section 39.201
96-15 or 39.262, upon making a finding that the total amount of revenues
96-16 to be collected pursuant to the financing order is less than the
96-17 revenue requirement that would be recovered over the remaining life
96-18 of the stranded costs using conventional financing methods.
96-19 (b) The financing order shall detail the amount of stranded
96-20 costs to be recovered and the period over which the nonbypassable
96-21 transition charges shall be recovered, which period shall not
96-22 exceed 15 years.
96-23 (c) Transition charges shall be collected and allocated
96-24 among customers in the same manner as competition transition
96-25 charges pursuant to Section 39.201.
96-26 (d) A financing order shall become effective in accordance
97-1 with its terms, and the financing order, together with the
97-2 transition charges authorized in the order, shall thereafter be
97-3 irrevocable and not subject to reduction, impairment, or adjustment
97-4 by further action of the commission, except as permitted by Section
97-6 (e) The commission shall issue a financing order pursuant to
97-7 Subsections (a) and (g) no later than 90 days after the utility
97-8 files its request for the financing order.
97-9 (f) A financing order shall not be subject to rehearing by
97-10 the commission. A financing order may be reviewed by appeal only
97-11 to a Travis County district court by a party to the proceeding
97-12 filed within 15 days after the financing order is signed by the
97-13 commission. The judgment of the district court may be reviewed
97-14 only by direct appeal to the Supreme Court of Texas filed within 15
97-15 days after entry of judgment. All appeals shall be heard and
97-16 determined by the district court and the Supreme Court of Texas as
97-17 expeditiously as possible with lawful precedence over other
97-18 matters. Review on appeal shall be based solely on the record
97-19 before the commission and briefs to the court and shall be limited
97-20 to whether the financing order conforms to the constitution and
97-21 laws of this state and the United States and is within the
97-22 authority of the commission pursuant to this chapter.
97-23 (g) At the request of an electric utility, the commission
97-24 may adopt a financing order providing for retiring and refunding
97-25 transition bonds upon making a finding that the future transition
97-26 charges required to service the new transition bonds, including
98-1 transaction costs, will be less than the future transition charges
98-2 required to service the transition bonds being refunded. Upon the
98-3 retirement of the refunded transition bonds, the commission shall
98-4 adjust the related transition charges accordingly.
98-5 Sec. 39.304. PROPERTY RIGHTS. (a) The rights and interests
98-6 of an electric utility or successor under a financing order,
98-7 including the right to impose, collect, and receive transition
98-8 charges authorized in the order, shall be only contract rights
98-9 until they are first transferred to an assignee or pledged in
98-10 connection with the issuance of transition bonds, at which time
98-11 they will become "transition property."
98-12 (b) Transition property shall constitute a present property
98-13 right for purposes of contracts concerning the sale or pledge of
98-14 property, even though the imposition and collection of transition
98-15 charges depends on further acts of the utility or others which have
98-16 not yet occurred; the financing order shall remain in effect and
98-17 the property shall continue to exist for the same period as the
98-18 pledge of the state described in Section 39.310.
98-19 (c) All revenues and collections resulting from transition
98-20 charges shall constitute proceeds only of the transition property
98-21 arising from the financing order.
98-22 Sec. 39.305. NO SETOFF. The interest of an assignee or
98-23 pledgee in transition property and in the revenues and collections
98-24 arising from that property shall not be subject to setoff,
98-25 counterclaim, surcharge, or defense by the electric utility or any
98-26 other person or in connection with the bankruptcy of the electric
99-1 utility or any other entity. A financing order shall remain in
99-2 effect and unabated notwithstanding the bankruptcy of the electric
99-3 utility, its successors, or assignees.
99-4 Sec. 39.306. NO BYPASS. A financing order shall include
99-5 terms ensuring that the imposition and collection of transition
99-6 charges authorized in the order shall be nonbypassable.
99-7 Sec. 39.307. TRUE-UP. A financing order shall include a
99-8 mechanism requiring that transition charges be reviewed and
99-9 adjusted at least annually, within 45 days of the anniversary date
99-10 of the issuance of the transition bonds, to correct any
99-11 overcollections or undercollections of the preceding 12 months and
99-12 to ensure the expected recovery of amounts sufficient to timely
99-13 provide all payments of debt service and other required amounts and
99-14 charges in connection with the transition bonds.
99-15 Sec. 39.308. TRUE SALE. An agreement by an electric utility
99-16 or assignee to transfer transition property that expressly states
99-17 that the transfer is a sale or other absolute transfer signifies
99-18 that the transaction is a true sale and is not a secured
99-19 transaction and that title, legal and equitable, has passed to the
99-20 entity to which the transition property is transferred. This true
99-21 sale shall apply regardless of whether the purchaser has any
99-22 recourse against the seller, or any other term of the parties'
99-23 agreement, including the seller's retention of an equity interest
99-24 in the transition property, the fact that the electric utility acts
99-25 as the collector of transition charges relating to the transition
99-26 property, or the treatment of the transfer as a financing for tax,
100-1 financial reporting, or other purposes.
100-2 Sec. 39.309. SECURITY INTERESTS; ASSIGNMENT; COMMINGLING;
100-3 DEFAULT. (a) Transition property shall not constitute an account
100-4 or general intangible under Section 9.106, Business & Commerce
100-5 Code. The creation, granting, perfection, and enforcement of liens
100-6 and security interests in transition property are governed by this
100-7 section and not by the Business & Commerce Code.
100-8 (b) A valid and enforceable lien and security interest in
100-9 transition property shall be created only by a financing order and
100-10 the execution and delivery of a security agreement with a financing
100-11 party in connection with the issuance of transition bonds. The
100-12 lien and security interest shall attach automatically from the time
100-13 that value is received for the bonds and, upon perfection through
100-14 the filing of notice with the secretary of state in accordance with
100-15 the rules prescribed under Subsection (d), shall be a continuously
100-16 perfected lien and security interest in the transition property and
100-17 all proceeds thereof, whether accrued or not, shall have priority
100-18 in the order of filing and take precedence over any subsequent
100-19 judicial or other lien creditor. If notice is filed within 10 days
100-20 after value is received for the transition bonds, the security
100-21 interest shall be perfected retroactive to the date value was
100-22 received; otherwise, the security interest shall be perfected as of
100-23 the date of filing.
100-24 (c) Transfer of an interest in transition property to an
100-25 assignee shall be perfected against all third parties, including
100-26 subsequent judicial or other lien creditors, when the financing
101-1 order becomes effective, transfer documents have been delivered to
101-2 the assignee, and a notice of that transfer has been filed in
101-3 accordance with the rules prescribed under Subsection (d);
101-4 provided, however, that if notice of the transfer has not been
101-5 filed in accordance with this subsection within 10 days after the
101-6 delivery of transfer documentation, the transfer of the interest
101-7 shall not be perfected against third parties until the notice is
101-9 (d) The secretary of state shall implement this section by
101-10 establishing and maintaining a separate system of records for the
101-11 filing of notices under this section and prescribing the rules for
101-12 such filings based on Chapter 9, Business & Commerce Code, adapted
101-13 to the provisions of this subchapter and using the terms defined in
101-14 this subchapter.
101-15 (e) The priority of a lien and security interest perfected
101-16 under this section will not be impaired by any later modification
101-17 of the financing order under Section 39.307 or by the commingling
101-18 of funds arising from transition charges with other funds, and any
101-19 other security interest that may apply to those funds shall be
101-20 terminated when they are transferred to a segregated account for
101-21 the assignee or a financing party. If transition property has been
101-22 transferred to an assignee, any proceeds of that property shall be
101-23 held in trust for the assignee.
101-24 (f) If a default or termination occurs under the transition
101-25 bonds, the financing parties or their representatives may foreclose
101-26 on or otherwise enforce their lien and security interest in any
102-1 transition property as if they were secured parties under Chapter
102-2 9, Business & Commerce Code, and the commission may order that
102-3 amounts arising from transition charges be transferred to a
102-4 separate account for the financing parties' benefit, to which their
102-5 lien and security interest shall apply. On application by or on
102-6 behalf of the financing parties, a district court of Travis County
102-7 shall order the sequestration and payment to them of revenues
102-8 arising from the transition charges.
102-9 Sec. 39.310. PLEDGE OF STATE. Transition bonds are not a
102-10 debt or obligation of the state and are not a charge upon its full
102-11 faith and credit or taxing power. The state pledges, however, for
102-12 the benefit and protection of financing parties and the electric
102-13 utility, that it will not take or permit any action that would
102-14 impair the value of transition property, or, except as permitted by
102-15 Section 39.307, reduce, alter, or impair the transition charges to
102-16 be imposed, collected, and remitted to financing parties, until the
102-17 principal, interest and premium, and any other charges incurred and
102-18 contracts to be performed in connection with the related transition
102-19 bonds have been paid and performed in full. Any party issuing
102-20 transition bonds is authorized to include this pledge in any
102-21 documentation relating to such bonds.
102-22 Sec. 39.311. TAX EXEMPTION. Transactions involving the
102-23 transfer and ownership of transition property and the receipt of
102-24 transition charges shall be exempt from state and local income,
102-25 sales, franchise, gross receipts, and other taxes or similar
103-1 Sec. 39.312. NO PUBLIC UTILITY. No assignee or financing
103-2 party shall be considered to be a public utility or person
103-3 providing electric service solely by virtue of the transactions
103-4 described in this subchapter.
103-5 Sec. 39.313. SEVERABILITY. Effective upon the date the
103-6 first utility transition bonds are issued under this subchapter, if
103-7 any provision in this title or portion thereof is held to be
103-8 invalid or is invalidated, superseded, replaced, repealed, or
103-9 expires for any reason, such occurrence shall not affect the
103-10 validity or continuation of this subchapter, Section 39.201,
103-11 39.251, 39.252, or 39.262, or any part thereof, or any other
103-12 provision of this title that is relevant to the issuance,
103-13 administration, payment, retirement, or refunding of transition
103-14 bonds or to any actions of the electric utility, its successors, an
103-15 assignee, a collection agent, or a financing party related thereto,
103-16 which shall remain in full force and effect.
103-17 SUBCHAPTER H. CERTIFICATION AND REGISTRATION; PENALTIES
103-18 Sec. 39.351. REGISTRATION OF POWER GENERATION COMPANIES.
103-19 (a) A person may not generate electricity unless the person is
103-20 registered with the commission as a power generation company in
103-21 accordance with this section. A person may register as a power
103-22 generation company by filing the following information with the
103-24 (1) a description of the location of any facility used
103-25 to generate electricity;
103-26 (2) a description of the type of services provided;
104-1 (3) a copy of any information filed with the Federal
104-2 Energy Regulatory Commission in connection with registration with
104-3 that commission; and
104-4 (4) any other information required by commission rule,
104-5 provided that in requiring such information the commission shall
104-6 protect the competitive process in a manner that ensures the
104-7 confidentiality of competitively sensitive information.
104-8 (b) A power generation company shall comply with the
104-9 reliability standards adopted by an independent organization
104-10 certified by the commission to ensure the reliability of the
104-11 regional electrical network for a power region in which the power
104-12 generation company is generating or selling electricity.
104-13 (c) A power generation company may register anytime after
104-14 September 1, 2000.
104-15 Sec. 39.352. CERTIFICATION OF RETAIL ELECTRIC PROVIDERS.
104-16 (a) In areas where customer choice has been introduced, no person,
104-17 including an affiliate of an electric utility, may provide retail
104-18 electric service in this state unless the person is certified by
104-19 the commission as a retail electric provider, in accordance with
104-20 this section.
104-21 (b) The commission shall issue a certificate to provide
104-22 retail electric service to a person applying for certification who
104-24 (1) the financial and technical resources to provide
104-25 continuous and reliable electric service to customers in the area
104-26 for which the certification is sought;
105-1 (2) the managerial and technical ability to supply
105-2 electricity at retail in accordance with customer contracts;
105-3 (3) the resources needed to meet the customer
105-4 protection requirements of this title; and
105-5 (4) ownership or lease of an office located within
105-6 this state for the purpose of providing customer service, accepting
105-7 service of process, and making available in that office books and
105-8 records sufficient to establish the retail electric provider's
105-9 compliance with the requirements of this subchapter.
105-10 (c) A person applying for certification under this section
105-11 shall comply with all applicable customer protection provisions,
105-12 disclosure requirements, and marketing guidelines established by
105-13 the commission and by this title.
105-14 (d) Notwithstanding Subsections (b)(1)-(3), if a retail
105-15 electric provider files with the commission a signed, notarized
105-16 affidavit from each retail customer with which it has contracted to
105-17 provide one megawatt or more of capacity stating that the customer
105-18 is satisfied that the retail electric provider meets the standards
105-19 set forth in Subsections (b)(1)-(3) and Subsection (c), the retail
105-20 electric provider shall be certified for purposes of serving those
105-21 customers only, so long as it demonstrates that it meets the
105-22 requirements of Subsection (b)(4).
105-23 (e) A retail electric provider may apply for certification
105-24 anytime after September 1, 2000.
105-25 (f) The commission shall use any information required in
105-26 this section in a manner that ensures the confidentiality of
106-1 competitively sensitive information.
106-2 Sec. 39.353. REGISTRATION OF AGGREGATORS. (a) A person may
106-3 not provide aggregation services in the state unless the person is
106-4 registered with the commission as an aggregator.
106-5 (b) In this subchapter, "aggregator" means a person joining
106-6 two or more customers, other than municipalities, into a single
106-7 purchasing unit to negotiate the purchase of electricity from
106-8 retail electric providers. Aggregators may not sell or take title
106-9 to electricity. Retail electric providers are not aggregators.
106-10 (c) A person registering under this section shall comply
106-11 with all customer protection provisions, all disclosure
106-12 requirements, and all marketing guidelines established by the
106-13 commission and by this title.
106-14 (d) The commission shall establish terms and conditions it
106-15 determines necessary to regulate the reliability and integrity of
106-16 aggregators in the state by June 1, 2000.
106-17 (e) An aggregator may register anytime after September 1,
106-19 (f) The commission shall have up to 60 days to process
106-20 applications for registration filed by aggregators.
106-21 (g) Registration is not required of a customer that is
106-22 aggregating loads from its own location or facilities.
106-23 Sec. 39.354. REGISTRATION OF MUNICIPAL AGGREGATORS. (a) A
106-24 municipal aggregator may not provide aggregation services in the
106-25 state unless the municipal aggregator registers with the
107-1 (b) In this section, "municipal aggregator" means a person
107-2 authorized by two or more municipal governing bodies to join the
107-3 bodies into a single purchasing unit to negotiate the purchase of
107-4 electricity from retail electric providers.
107-5 (c) A municipal aggregator may register anytime after
107-6 September 1, 2000.
107-7 Sec. 39.355. REGISTRATION OF POWER MARKETERS. A person may
107-8 not sell electric energy at wholesale as a power marketer unless
107-9 the person registers with the commission.
107-10 Sec. 39.356. REVOCATION OF CERTIFICATION. (a) The
107-11 commission may after notice and opportunity for hearing suspend,
107-12 revoke, or amend a retail electric provider's certificate for
107-13 significant violations of this title or the rules adopted pursuant
107-14 to this title or of any reliability standard adopted by an
107-15 independent organization certified by the commission to ensure the
107-16 reliability of a power region's electrical network, including the
107-17 failure to observe any scheduling, operating, or settlement
107-18 protocols established by the independent organization. The
107-19 commission may also suspend or revoke a retail electric provider's
107-20 certificate if the provider no longer has the financial or
107-21 technical capability to provide continuous and reliable electric
107-23 (b) The commission may suspend or revoke a power generation
107-24 company's registration for significant violations of this title or
107-25 the rules adopted pursuant to this title or of the reliability
107-26 standards adopted by an independent organization certified by the
108-1 commission to ensure the reliability of a power region's electrical
108-2 network, including the failure to observe any scheduling,
108-3 operating, or settlement protocols established by the independent
108-5 (c) The commission may suspend or revoke an aggregator's
108-6 registration for significant violations of this title or of the
108-7 rules adopted pursuant to this title.
108-8 Sec. 39.357. ADMINISTRATIVE PENALTY. In addition to the
108-9 suspension, revocation, or amendment of a certification, the
108-10 commission may impose an administrative penalty, as provided by
108-11 Section 15.023, for violations described by Section 39.356.
108-12 SUBCHAPTER I. MISCELLANEOUS PROVISIONS
108-13 Sec. 39.601. SCHOOL FUNDING LOSS MECHANISM. (a) Not later
108-14 than March 1 each year, the comptroller shall certify to the Texas
108-15 Education Agency any property wealth reductions, determined by
108-16 taking the difference between current year and prior year appraisal
108-17 values attributable to electric utility restructuring.
108-18 (b) The Texas Education Agency shall determine the reduction
108-19 of the amount of property taxes recaptured by the state from school
108-20 districts subject to wealth equalization under Chapter 41,
108-21 Education Code, as a result of the property wealth reductions
108-22 certified under Subsection (a) and shall notify the commission of
108-23 the amount necessary to compensate the state for the reduction.
108-24 (c) The Texas Education Agency shall determine the amount
108-25 necessary to compensate school districts for lost revenue resulting
108-26 from the property wealth reductions under Subsection (a) and shall
109-1 notify the commission of this amount. The amounts necessary to
109-2 compensate districts shall be the sum of:
109-3 (1) decreases in the level of funding to which a
109-4 school district is entitled under Chapters 42 and 46, Education
109-5 Code, that are directly attributable to the decline in property
109-6 values caused by utility restructuring; and
109-7 (2) losses of property tax collections incurred by
109-8 school districts that are directly attributable to property value
109-9 declines caused by utility restructuring and that are not accounted
109-10 for under Subdivision (1), including amounts which a school
109-11 district would be entitled to retain under Chapter 41, Education
109-13 (d) The amounts determined by the comptroller and the Texas
109-14 Education Agency under this section, for the purposes of this
109-15 section, are final and may not be appealed.
109-16 (e) Not later than May 1 of each year, the commission shall
109-17 transfer from the system benefit fund to the foundation school fund
109-18 the amounts determined by the Texas Education Agency under
109-19 Subsections (b) and (c). Amounts transferred from the system
109-20 benefit fund pursuant to this section are appropriated for the
109-21 support of the foundation school program and are available, in
109-22 addition to any amounts allocated by the General Appropriations
109-23 Act, to finance actions under Section 41.002(b) or 42.252(e),
109-24 Education Code.
109-25 (f) The Texas Education Agency shall, upon the transfer of
109-26 funds from the system benefit fund to the foundation school fund,
110-1 compensate school districts for losses incurred under Subsection
110-3 (g) The commissioner of education and the comptroller may
110-4 adopt rules necessary to implement this section.
110-5 (h) This section is effective through the 2006-2007 school
110-6 year. This section expires August 31, 2007.
110-7 Sec. 39.602. CUSTOMER EDUCATION. (a) On or before January
110-8 1, 2001, the commission shall develop and implement an educational
110-9 program to inform customers, including low-income and
110-10 non-English-speaking customers, about changes in the provision of
110-11 electric service resulting from the opening of the retail electric
110-12 market and the customer choice pilot program under this chapter.
110-13 The educational program shall be neutral and nonpromotional and
110-14 shall provide customers with the information necessary to make
110-15 informed decisions relating to the source and type of electric
110-16 service available for purchase and other information the commission
110-17 considers necessary. In planning and implementing this program,
110-18 the commission shall consult with the office, with the Texas
110-19 Department of Housing and Community Affairs, and with customers of
110-20 and providers of retail electric service. The commission may enter
110-21 contracts for professional services to carry out the customer
110-22 education program.
110-23 (b) The commission shall report on the status of the
110-24 educational program, developed and implemented as provided by
110-25 Subsection (a), to the electric utility restructuring legislative
110-26 oversight committee on or before December 1, 2001.
111-1 (c) After the opening of the retail electric market, the
111-2 commission shall conduct ongoing customer education designed to
111-3 help customers make informed choices of electric services and
111-4 retail electric providers. As part of ongoing education, the
111-5 commission may provide customers information concerning specific
111-6 retail electric providers, including instances of complaints
111-7 against them and records relating to quality of customer service.
111-8 Sec. 39.603. SYSTEM BENEFIT FUND. (a) The commission shall
111-9 establish the system benefit fund.
111-10 (b) The system benefit fund is financed by a nonbypassable
111-11 charge set by the commission in an amount not to exceed 50 cents
111-12 per MWh.
111-13 (c) The system benefit fund shall provide funding for:
111-14 (1) customer education programs;
111-15 (2) programs to assist low-income electric customers
111-16 provided by Subsections (d)-(i);
111-17 (3) the school funding loss mechanism provided by
111-18 Section 39.601; and
111-19 (4) administrative costs incurred by the commission in
111-20 implementing this chapter and Chapters 40 and 41.
111-21 (d) Notwithstanding Section 39.106(b), the commission shall
111-22 adopt rules regarding programs to assist low-income electric
111-23 customers. Such programs shall include:
111-24 (1) reduced electric rates as provided by Subsections
111-25 (e)-(i); and
111-26 (2) targeted energy efficiency programs to be
112-1 administered by the Texas Department of Housing and Community
112-2 Affairs in coordination with existing weatherization programs.
112-3 (e) Until January 1, 2002, or such time as customer choice
112-4 is in effect, an electric utility may not reduce, in any manner,
112-5 programs already offered to assist low-income electric customers.
112-6 (f) Following the introduction of customer choice, the
112-7 commission shall adopt rules to determine a reduced rate to be
112-8 discounted off the standard retail service package as approved by
112-9 the commission pursuant to Section 39.106, or the "price to beat"
112-10 established by Section 39.202, whichever is lower.
112-11 (g) The commission may provide for a reduced rate:
112-12 (1) during periods when severe weather occurs or is
112-13 likely to occur; or
112-14 (2) for customers living in all-electric dwelling
112-15 units or who depend on electrically operated medical equipment.
112-16 (h) A retail electric provider not subject to the "price to
112-17 beat" shall be reimbursed for the difference between the reduced
112-18 rate and the rate established pursuant to Section 39.106. A retail
112-19 electric provider who is subject to the "price to beat" shall be
112-20 reimbursed for the difference between the reduced rate and the
112-21 "price to beat."
112-22 (i) A retail electric provider is prohibited from charging
112-23 the customer a fee for participation in the reduced rate program.
112-24 (j) For the purposes of this section, a "low-income electric
112-25 customer" is an electric customer who is a qualifying low-income
112-26 consumer as defined by the commission.
113-1 Sec. 39.604. GOAL FOR RENEWABLE ENERGY. (a) Each retail
113-2 electric provider, municipally owned utility, and electric
113-3 cooperative operating in the state shall obtain a minimum of 1.65
113-4 percent of its annual capacity requirements from renewable energy
113-5 technologies by January 1, 2003, 2.15 percent of its annual
113-6 capacity requirements from renewable energy technologies by January
113-7 1, 2005, 2.75 percent of its annual capacity requirements from
113-8 renewable energy technologies by January 1, 2007, and 3 percent of
113-9 its annual capacity requirements from renewable energy technologies
113-10 by January 1, 2009.
113-11 (b) The commission shall establish a renewable energy
113-12 credits trading program. Any retail electric provider, municipally
113-13 owned utility, or electric cooperative that does not satisfy the
113-14 requirements of Subsection (a) shall purchase sufficient renewable
113-15 energy credits to satisfy the requirements by holding renewable
113-16 energy credits in lieu of capacity from renewable energy
113-18 (c) In this section, "renewable energy technology" means any
113-19 technology that exclusively relies on an energy source that is
113-20 naturally regenerated over a short time and derived directly from
113-21 the sun, indirectly from the sun, or from moving water or other
113-22 natural movements and mechanisms of the environment. Renewable
113-23 energy technologies include, but are not restricted to, those that
113-24 rely on energy derived directly from the sun; on wind, geothermal,
113-25 hydroelectric, wave, or tidal energy; or on biomass or
113-26 biomass-based waste products. A renewable energy technology does
114-1 not rely on energy resources derived from fossil fuels, waste
114-2 products from fossil fuels, or waste products from inorganic
114-4 Sec. 39.605. GOAL FOR ENERGY EFFICIENCY. It is the intent
114-5 of the legislature that:
114-6 (1) regulated utilities shall administer customer
114-7 information and energy savings incentive programs;
114-8 (2) all customers, in all customer classes, shall have
114-9 a choice of and access to energy efficiency alternatives and other
114-10 choices that allow each customer to reduce energy consumption and
114-11 reduce energy costs;
114-12 (3) utilities may offer loans at below-market interest
114-13 rates for energy efficiency investments, other energy efficiency
114-14 market transformation programs which result in below-market cost to
114-15 the customer, and grants and other special programs to address the
114-16 needs of small businesses, tenants, low-income consumers, and other
114-17 customer groups not served by market-based incentive programs; and
114-18 (4) regulated utilities shall acquire, through
114-19 market-based standard offer programs or targeted market
114-20 transformation programs, additional energy efficiency equivalent to
114-21 at least 25 percent of each year's annual growth in demand.
114-22 Sec. 39.606. DISPLACED WORKERS. In order to mitigate
114-23 potential negative impacts on utility personnel directly affected
114-24 by electric industry restructuring, the commission may allow the
114-25 recovery of reasonable employee related transition costs.
114-26 Sec. 39.607. LEGISLATIVE OVERSIGHT COMMITTEE. (a) In this
115-1 section, "committee" means the electric utility restructuring
115-2 legislative oversight committee.
115-3 (b) The committee is composed of six members as follows:
115-4 (1) the chair of the Senate Committee on Economic
115-5 Development, who shall serve as the chair of the committee;
115-6 (2) the chair of the House Committee on State Affairs,
115-7 who shall serve as the vice chair of the committee;
115-8 (3) two members of the senate appointed by the
115-9 lieutenant governor; and
115-10 (4) two members of the house of representatives
115-11 appointed by the speaker of the house of representatives.
115-12 (c) An appointed member of the committee serves at the
115-13 pleasure of the appointing official.
115-14 (d) The committee is subject to Chapter 325, Government Code
115-15 (Texas Sunset Act). Unless continued in existence as provided by
115-16 that chapter, the committee is abolished September 1, 2005.
115-17 (e) The committee shall:
115-18 (1) meet at least annually with the commission;
115-19 (2) receive information about rules relating to
115-20 electric utility restructuring proposed by the commission and may
115-21 submit comments to the commission on such proposed rules;
115-22 (3) review recommendations for legislation proposed by
115-23 the commission; and
115-24 (4) monitor the effectiveness of electric utility
115-25 restructuring, including the fairness of rates, the reliability of
115-26 service, and the effect of stranded costs, market power, and
116-1 regulation on the normal forces of competition.
116-2 (f) The committee may request reports and other information
116-3 from the commission as necessary to carry out this section.
116-4 (g) Not later than November 15 of each even-numbered year,
116-5 the committee shall report to the governor, lieutenant governor,
116-6 and speaker of the house of representatives on the committee's
116-7 activities under Subsection (e). The report shall include:
116-8 (1) an analysis of any problems caused by electric
116-9 utility restructuring; and
116-10 (2) recommendations of any legislative action
116-11 necessary to address such problems and to further retail
116-12 competition within the electric power industry.
116-13 Sec. 39.608. EFFECT OF SUNSET PROVISION. (a) If the
116-14 commission is abolished and the other provisions of this title
116-15 expire as provided by Chapter 325, Government Code (Texas Sunset
116-16 Act), this subchapter, including the provisions of this title
116-17 referred to in this subchapter, continues in full force and effect
116-18 and does not expire.
116-19 (b) The authorities, duties, and functions of the commission
116-20 under this chapter shall be performed and carried out by a
116-21 successor agency to be designated by the legislature before
116-22 abolishment of the commission or, if the legislature does not
116-23 designate the successor, by the secretary of state.
117-1 CHAPTER 40. COMPETITION FOR MUNICIPALLY OWNED UTILITIES
117-2 AND RIVER AUTHORITIES
117-3 SUBCHAPTER A. GENERAL PROVISIONS
117-4 Sec. 40.001. APPLICABLE LAW. (a) Notwithstanding any other
117-5 provision of law, this chapter governs the transition to and the
117-6 establishment of a fully competitive electric power industry for
117-7 municipally owned utilities. This chapter controls over any other
117-8 provision of this title, except Sections 39.155, 39.157(e), 39.203,
117-9 39.603, and 39.604.
117-10 (b) Except as specifically provided in this subsection, the
117-11 provisions of Chapter 39 shall not apply to a river authority
117-12 operating a steam generating plant on or before January 1, 1999, or
117-13 a corporation authorized by Chapter 245, Acts of the 67th
117-14 Legislature, Regular Session, 1981 (Article 717p, Vernon's Texas
117-15 Civil Statutes), or Section 32.053. A river authority operating a
117-16 steam generating plant on or before January 1, 1999, shall be
117-17 subject to Sections 39.051(a)-(c), 39.108, 39.155, 39.157(e), and
117-19 (c) For purposes of Section 39.051, hydroelectric assets
117-20 shall not be deemed to be generating assets, and the transfer of
117-21 generating assets to a corporation authorized by Chapter 245, Acts
117-22 of the 67th Legislature, Regular Session, 1981 (Article 717p,
117-23 Vernon's Texas Civil Statutes), shall satisfy the requirements of
117-24 Section 39.051.
117-25 (d) Accommodation shall be made in the code of conduct
117-26 established under Section 39.157(e) for the provisions of Chapter
118-1 245, Acts of the 67th Legislature, Regular Session, 1981 (Article
118-2 717p, Vernon's Texas Civil Statutes), and the commission shall not
118-3 prohibit a river authority and any related corporation from sharing
118-4 officers, directors, employees, equipment, and facilities or from
118-5 providing goods or services to each other at cost without the need
118-6 for a competitive bid.
118-7 Sec. 40.002. DEFINITION. For purposes of this chapter,
118-8 "body vested with the power to manage and operate a municipally
118-9 owned utility" shall mean a body created in accordance with Article
118-10 1115 or 1115a, Revised Statutes, or by municipal charter.
118-11 Sec. 40.003. SECURITIZATION. (a) Municipally owned
118-12 utilities and river authorities may adopt and use securitization
118-13 provisions having the effect of the provisions set out in
118-14 Subchapter G, Chapter 39, to recover through appropriate charges
118-15 their stranded costs, at a recovery level deemed appropriate by the
118-16 municipally owned utility or river authority up to 100 percent,
118-17 under rules and procedures that shall be established:
118-18 (1) in the case of a municipally owned utility, by the
118-19 municipal governing body or a body vested with the power to manage
118-20 and operate the municipally owned utility, including procedures
118-21 providing for rate orders of such governing body having the effect
118-22 of financing orders, providing for a separate nonbypassable charge
118-23 approved by the governing body, in the nature of a transition
118-24 charge, to be collected from all retail electric customers of the
118-25 municipally owned utility, identified as of a date determined by
118-26 the governing body, to fund the recovery of the stranded costs of
119-1 the municipally owned utility and of all reasonable related
119-2 expenses, as determined by the governing body, and providing for
119-3 the issuance of bonds, having a term and other characteristics as
119-4 determined by the governing body, as necessary to recover the
119-5 amount deemed appropriate by the governing body through
119-6 securitization financing; and
119-7 (2) in the case of a river authority, by the
119-9 (b) In order to implement securitization financing pursuant
119-10 to the rules and procedures established by and for a municipally
119-11 owned utility under Subsection (a)(1), municipalities are expressly
119-12 authorized and empowered to issue bonds, notes, or other
119-13 obligations, including refunding bonds, payable from and secured by
119-14 a lien on and pledge of the revenues collected under an order of
119-15 the governing body of the municipality, and the bonds shall be
119-16 issued, without an election or any requirement of giving notice of
119-17 intent to issue the bonds, by ordinance adopted by the governing
119-18 body of the municipality, in such form and manner and sold on a
119-19 negotiated basis or upon receipt of bids and on such terms and
119-20 conditions as shall be determined by the governing body of the
119-22 (c) Bonds issued pursuant to authority conferred under
119-23 Subsections (a)(1) and (2) and Subsection (b) may be issued in such
119-24 form and manner, with or without credit enhancement or liquidity
119-25 enhancement and using such procedures as provided in the Bond
119-26 Procedures Act of 1981 (Article 717k-6, Vernon's Texas Civil
120-1 Statutes) or other laws applicable to the issuance of bonds,
120-2 including Chapter 656, Acts of the 68th Legislature, Regular
120-3 Session, 1983 (Article 717q, Vernon's Texas Civil Statutes),
120-4 Chapter 503, Acts of the 54th Legislature, Regular Session, 1955
120-5 (Article 717k, Vernon's Texas Civil Statutes), and Chapter 642,
120-6 Acts of the 65th Legislature, Regular Session, 1977 (Article
120-7 1118n-12, Vernon's Texas Civil Statutes) as if such laws were fully
120-8 restated herein and made a part hereof for all purposes, and a
120-9 municipality or river authority shall have the right and authority
120-10 to use such other laws, notwithstanding any applicable restrictions
120-11 contained therein, to the extent convenient or necessary to carry
120-12 out any power or authority, express or implied, granted under this
120-13 section, in the issuance of bonds by a municipality or river
120-14 authority in connection with securitization financing; provided,
120-15 however, that the provisions herein contained shall be wholly
120-16 sufficient authority for the issuance of bonds, notes, or other
120-17 obligations, including refunding bonds, and the performance of the
120-18 other acts and procedures herein authorized, without reference to
120-19 any other laws or any restrictions or limitations contained
120-20 therein; and to the extent of any conflict or inconsistency between
120-21 the provisions of this authorization and any provisions of any
120-22 other law or home-rule charter, the authorization and power to
120-23 issue bonds conferred on municipalities or river authorities under
120-24 this section shall prevail and control.
120-25 (d) The rules and procedures for securitization established
120-26 by the commission under Subsection (a)(2) shall include procedures
121-1 for the recovery of qualified costs pursuant to the terms of a
121-2 financing order adopted by the governing body of the river
121-4 (e) The rules and procedures for securitization established
121-5 by the commission under Subsection (a)(2) shall include rules and
121-6 procedures for the issuance of transition bonds. Findings made by
121-7 the governing body of a river authority in a financing order issued
121-8 pursuant to the rules and procedures described in this subsection
121-9 shall be conclusive, and any nonbypassable transition charge
121-10 incorporated in the rate order to recover the principal, interest,
121-11 and all reasonable expenses associated with any transition bonds
121-12 shall constitute property rights, as described in Subchapter G,
121-13 Chapter 39, and otherwise conform in all material respects to the
121-14 nonbypassable transition charges set forth in Subchapter G, Chapter
121-16 (f) The rules and procedures established under this section
121-17 shall be consistent with other law applicable to municipally owned
121-18 utilities and river authorities and with the terms of any
121-19 resolutions, orders, charter provisions, or ordinances authorizing
121-20 outstanding bonds or other indebtedness of the municipalities or
121-21 river authorities.
121-22 Sec. 40.004. JURISDICTION OF THE COMMISSION. Except as
121-23 specifically otherwise provided in this chapter, the commission has
121-24 jurisdiction over municipally owned utilities only for the
121-25 following purposes:
121-26 (1) to regulate wholesale transmission rates and
122-1 service, including terms of access, to the extent provided by
122-2 Subchapter A, Chapter 35;
122-3 (2) to regulate certification of retail service areas
122-4 to the extent provided by Chapter 37;
122-5 (3) to regulate rates on appeal pursuant to
122-6 Subchapters D and E, Chapter 33, subject to the provisions of
122-7 Section 40.051(c);
122-8 (4) to establish a code of conduct as provided by
122-9 Section 39.157(e) applicable to anticompetitive activities and to
122-10 affiliate activities limited to structurally unbundled affiliates
122-11 of municipally owned utilities, subject to Section 40.054;
122-12 (5) to establish terms and conditions for open access
122-13 to transmission and distribution facilities for municipally owned
122-14 utilities providing customer choice, as provided by Section 39.203;
122-15 (6) to require collection of the nonbypassable charge
122-16 established under Section 39.603(b) and to administer the renewable
122-17 energy credits program under Section 39.604(d); and
122-18 (7) to require reports of municipally owned utility
122-19 operations only to the extent necessary to:
122-20 (A) enable the commission to determine the
122-21 aggregate load and energy requirements of the state and the
122-22 resources available to serve that load; or
122-23 (B) enable the commission to determine
122-24 information relating to market power as provided by Section 39.155.
122-25 SUBCHAPTER B. MUNICIPALLY OWNED UTILITY CHOICE
122-26 Sec. 40.051. GOVERNING BODY DECISION. (a) The municipal
123-1 governing body or a body vested with the power to manage and
123-2 operate a municipally owned utility has the discretion to decide
123-3 when or if the municipally owned utility will provide customer
123-5 (b) Municipally owned utilities may choose to participate in
123-6 customer choice at any time on or after January 1, 2002, by
123-7 adoption of an appropriate resolution of the municipal governing
123-8 body or a body vested with power to manage and operate the
123-9 municipally owned utility. The decision to participate in customer
123-10 choice by the adoption of a resolution is irrevocable.
123-11 (c) After a decision to offer customer choice has been made,
123-12 Subchapters D and E, Chapter 33, do not apply to any action taken
123-13 under this chapter.
123-14 Sec. 40.052. UTILITY NOT OFFERING CUSTOMER CHOICE. (a) A
123-15 municipally owned utility that has not chosen to participate in
123-16 customer choice may not offer electric energy at unregulated prices
123-17 directly to retail customers outside its certificated retail
123-18 service area.
123-19 (b) A municipally owned utility under Subsection (a) retains
123-20 the right to offer and provide a full range of customer service and
123-21 pricing programs to the customers within its certificated area and
123-22 to purchase and sell electric energy at wholesale without
123-23 geographic restriction.
123-24 Sec. 40.053. RETAIL CUSTOMER'S RIGHT OF CHOICE. (a) If a
123-25 municipally owned utility chooses to participate in customer
123-26 choice, after that choice all retail customers served by the
124-1 municipally owned utility within the certificated retail service
124-2 area of the municipally owned utility shall have the right of
124-3 customer choice consistent with the provisions of this chapter, and
124-4 the municipally owned utility shall provide open access for retail
124-6 (b) Notwithstanding Section 39.107, the metering function
124-7 shall not be deemed a competitive service for customers of the
124-8 municipally owned utility within such service area and may, at the
124-9 option of the municipally owned utility, continue to be offered by
124-10 the municipally owned utility as sole provider.
124-11 (c) Upon its initiation of customer choice, a municipally
124-12 owned utility shall designate itself or another entity as the
124-13 provider of last resort for customers within the municipally owned
124-14 utility's certificated service area as that area existed on the
124-15 date of the utility's initiation of customer choice. The
124-16 municipally owned utility shall fulfill the role of default
124-17 provider of last resort in the event no other entity is available
124-18 to act in that capacity.
124-19 (d) If a customer is unable to obtain service from a retail
124-20 electric provider, upon request by the customer, the provider of
124-21 last resort shall offer the customer the standard retail service
124-22 package for the appropriate customer class, with no interruption of
124-23 service, at a fixed, nondiscountable rate that is at least
124-24 sufficient to cover the reasonable costs of providing such service,
124-25 as approved by the governing body of the municipally owned utility
124-26 which has the authority to set rates.
125-1 (e) The governing body of a municipally owned utility may
125-2 establish the procedures and criteria for designating the provider
125-3 of last resort and may redesignate the provider of last resort
125-4 according to a schedule it considers appropriate.
125-5 Sec. 40.054. SERVICE OUTSIDE AREA. (a) A municipally owned
125-6 utility participating in customer choice shall have the right to
125-7 offer electric energy and related services at unregulated prices
125-8 directly to retail customers within qualifying power regions
125-9 without regard to geographic location.
125-10 (b) In providing service under Subsection (a) to retail
125-11 customers outside its certificated retail service area as that area
125-12 exists on the date of adoption of customer choice, a municipally
125-13 owned utility is subject to the commission's rules establishing a
125-14 code of conduct regulating anticompetitive practices.
125-15 (c) For municipally owned utilities participating in
125-16 customer choice, the commission shall have jurisdiction to
125-17 establish terms and conditions, but not rates, for access by other
125-18 retail electric providers to the municipally owned utility's
125-19 distribution facilities.
125-20 (d) Accommodation shall be made in the commission's terms
125-21 and conditions for access and in the code of conduct for specific
125-22 legal requirements imposed by state or federal law applicable to
125-23 municipally owned utilities.
125-24 (e) The commission does not have jurisdiction to require
125-25 unbundling of services or functions of, or to regulate the recovery
125-26 of stranded investment of, a municipally owned utility or, except
126-1 as provided by this section, jurisdiction with respect to the
126-2 rates, terms, and conditions of service for retail customers of a
126-3 municipally owned utility within the utility's certificated service
126-5 (f) A municipally owned utility shall maintain separate
126-6 books and records of its operations from those of the operations of
126-7 any affiliate.
126-8 Sec. 40.055. JURISDICTION OF MUNICIPAL GOVERNING BODY.
126-9 (a) The municipal governing body or a body vested with the power
126-10 to manage and operate a municipally owned utility has exclusive
126-11 jurisdiction to:
126-12 (1) set all terms of access, conditions, and rates
126-13 applicable to services provided by the municipally owned utility,
126-14 subject to Sections 40.054 and 40.056, including nondiscriminatory
126-15 and comparable terms of access, conditions, and rates for
126-16 distribution but excluding wholesale transmission rates, terms of
126-17 access, and conditions for wholesale transmission service set by
126-18 the commission under this subtitle, provided that the rates for
126-19 distribution access established by the municipal governing body
126-20 shall be comparable to the distribution access rates that apply to
126-21 the municipally owned utility and the municipally owned utility's
126-23 (2) determine whether to unbundle any energy-related
126-24 activities and, if the municipally owned utility chooses to
126-25 unbundle, whether to do so structurally or functionally;
126-26 (3) reasonably determine the amount of the municipally
127-1 owned utility's stranded investment;
127-2 (4) establish nondiscriminatory transition charges
127-3 reasonably designed to recover the stranded investment over an
127-4 appropriate period of time, provided that recovery of retail
127-5 stranded costs shall be from all existing or future retail
127-6 customers, including the facilities, premises, and loads of such
127-7 retail customers, within the utility's geographical certificated
127-8 service area as it existed on May 1, 1999;
127-9 (5) determine the extent to which the municipally
127-10 owned utility will provide various customer services at the
127-11 distribution level, including other services that the municipally
127-12 owned utility is legally authorized to provide, or will accept the
127-13 services from other providers;
127-14 (6) manage and operate the municipality's electric
127-15 utility systems, including exercise of control over resource
127-16 acquisition and any related expansion programs;
127-17 (7) establish and enforce service quality and
127-18 reliability standards and consumer safeguards designed to protect
127-19 retail electric customers, including safeguards that will
127-20 accomplish the objectives of Sections 39.101(a) and (b), consistent
127-21 with the provisions of this chapter;
127-22 (8) determine whether a base rate reduction is
127-23 appropriate for the municipally owned utility;
127-24 (9) determine any other utility matters that the
127-25 municipal governing body or body vested with power to manage and
127-26 operate the municipally owned utility believes should be included;
128-2 (10) make any other decisions affecting the
128-3 municipally owned utility's participation in customer choice that
128-4 are not inconsistent with the provisions of this chapter.
128-5 (b) In multiply certificated areas, a retail customer,
128-6 including a retail customer of an electric cooperative or a
128-7 municipally owned utility, may not avoid stranded cost recovery
128-8 charges by switching to another electric utility, electric
128-9 cooperative, or municipally owned utility.
128-10 Sec. 40.056. ANTICOMPETITIVE ACTIONS. (a) If, upon
128-11 complaint by a retail electric provider, the commission finds that
128-12 a municipal rule, action, or order relating to customer choice is
128-13 anticompetitive or does not provide other retail electric providers
128-14 with nondiscriminatory terms and conditions of access to
128-15 distribution facilities or customers within the municipally owned
128-16 utility's certificated retail service area that are comparable to
128-17 the municipally owned utility's and its affiliates' terms and
128-18 conditions of access to distribution facilities or customers, the
128-19 commission shall notify the municipally owned utility.
128-20 (b) The municipally owned utility shall have three months to
128-21 cure the anticompetitive or noncompliant behavior described in
128-22 Subsection (a), following opportunity for hearing on the complaint.
128-23 If the rule, action, or order is not fully remedied within that
128-24 time, the commission may prohibit the municipally owned utility or
128-25 affiliate from providing retail service outside its certificated
128-26 retail service area until the rule, action, or order is remedied.
129-1 Sec. 40.057. BILLING. (a) A municipally owned utility that
129-2 opts for customer choice may continue to bill directly electric
129-3 customers located in its certificated retail service area, as that
129-4 area exists on the date of adoption of customer choice, for all
129-5 transmission and distribution services. The municipally owned
129-6 utility may also bill directly for generation services and customer
129-7 services provided by the municipally owned utility to those
129-9 (b) A municipally owned utility that opts for customer
129-10 choice shall not adopt anticompetitive billing practices that would
129-11 discourage customers in its service area from choosing a retail
129-12 electric provider.
129-13 (c) A customer that is being provided wires service by a
129-14 municipally owned utility at distribution or transmission voltage
129-15 and that is served by a retail electric provider for retail service
129-16 has the option of being billed directly by each service provider or
129-17 to receive a single bill for distribution, transmission, and
129-18 generation services from the municipally owned utility.
129-19 Sec. 40.058. TARIFFS FOR OPEN ACCESS. A municipally owned
129-20 utility that owns or operates transmission and distribution
129-21 facilities shall file with the commission tariffs implementing the
129-22 open access rules established by the commission under Section
129-23 39.203 and shall file with the commission the rates for open access
129-24 on distribution facilities as set by the municipal regulatory
129-25 authority, before the 90th day preceding the date the utility
129-26 offers customer choice. The commission has no authority to
130-1 determine the rates for distribution access service for a
130-2 municipally owned utility.
130-3 Sec. 40.059. MUNICIPAL POWER AGENCY; RECOVERY OF STRANDED
130-4 COSTS. (a) In this section, "member city" means a municipality
130-5 that participated in the creation of a municipal power agency
130-6 formed pursuant to Chapter 163 by the adoption of a concurrent
130-7 resolution by the municipality on or before August 1, 1975.
130-8 (b) After a member city adopts a resolution choosing to
130-9 participate in customer choice under Section 40.051(b), a member
130-10 city may include stranded costs described in Subsection (c) in its
130-11 distribution costs and may recover such costs through a
130-12 nonbypassable charge. The nonbypassable charge shall be as
130-13 determined by the member city's governing body and may be spread
130-14 over 16 years.
130-15 (c) The stranded costs that may be recovered under this
130-16 section are those costs that were determined by the commission and
130-17 set forth in the commission's April 1998 Report to the Texas Senate
130-18 Interim Committee on Electric Utility Restructuring entitled
130-19 "Potentially Strandable Investment (ECOM) Report: 1998 Update" and
130-20 specifically set forth in the report at Appendix A (ECOM Estimates
130-21 Including the Effects of Transition Plans) under the commission
130-22 base case benchmark base market price for the year 2002.
130-23 (d) The stranded cost amounts described in this section
130-24 shall not be included in the generation costs used in setting rates
130-25 by the member city's governing body.
130-26 (e) The provisions of this section are cumulative of all
131-1 other provisions of this chapter, and nothing in this section shall
131-2 be construed to limit or restrict the application of any provision
131-3 of this chapter to the member cities.
131-4 (f) The municipal power agency shall extinguish the agency's
131-5 indebtedness by sale of the electric facility to one or more
131-6 purchasers, by way of a sale through the issuance of taxable or
131-7 tax-exempt debt to the member cities, or by any other method. The
131-8 agency shall set as an objective the extinguishment of the agency's
131-9 debt by September 1, 2000. In the event this objective is not met,
131-10 the agency shall provide detailed reasons to the electric utility
131-11 restructuring legislative oversight committee by November 1, 2000,
131-12 why the agency was not able to meet this objective.
131-13 (g) The municipal power agency or its successor in interest
131-14 may, at its option, use the rate of return method for calculating
131-15 its transmission cost of service. If the rate of return method is
131-16 used, the return component for the transmission cost of service
131-17 revenue requirement shall be sufficient to meet the transmission
131-18 function's pro rata share of levelized debt service and debt
131-19 service coverage ratio (1.50) and other annual debt obligations;
131-20 provided, however, that the total levelized debt service may not
131-21 exceed the total debt service under the current payment schedule.
131-22 Any additional revenue generated by the methodology described in
131-23 this subsection shall be applied to reduce the agency's outstanding
131-25 Sec. 40.060. NO POWER TO AMEND CERTIFICATES. Nothing in
131-26 this chapter empowers a municipal governing body or a body vested
132-1 with the power to manage and operate a municipally owned utility to
132-2 issue, amend, or rescind a certificate of public convenience and
132-3 necessity granted by the commission. This subsection does not
132-4 affect the ability of a municipal governing body or a body vested
132-5 with the power to manage and operate the municipally owned utility
132-6 to pass a resolution under Section 40.051(b).
132-7 SUBCHAPTER C. RIGHTS NOT AFFECTED
132-8 Sec. 40.101. INTERFERENCE WITH CONTRACT. (a) This subtitle
132-9 shall not interfere with or abrogate the rights or obligations of
132-10 parties, including a retail or wholesale customer, to a contract
132-11 with a municipally owned utility or river authority.
132-12 (b) This subtitle shall not interfere with or abrogate the
132-13 rights or obligations of a party under a contract or agreement
132-14 concerning certificated utility service areas.
132-15 Sec. 40.102. ACCESS TO WHOLESALE MARKET. Nothing in this
132-16 subtitle shall limit the access of municipally owned utilities to
132-17 the wholesale electric market.
132-18 Sec. 40.103. PROTECTION OF BONDHOLDERS. Nothing in this
132-19 subtitle or any rule adopted under this subtitle shall impair
132-20 contracts, covenants, or obligations between this state, river
132-21 authorities, municipalities, and the bondholders of revenue bonds
132-22 issued by the river authorities or municipalities.
132-23 Sec. 40.104. TAX-EXEMPT STATUS. Nothing in this subtitle
132-24 may impair the tax-exempt status of municipalities, electric
132-25 cooperatives, or river authorities, nor shall anything in this
132-26 subtitle compel any municipality, electric cooperative, or river
133-1 authority to use its facilities in a manner which violates any
133-2 contractual provisions, bond covenants, or other restrictions
133-3 applicable to facilities financed by tax-exempt debt.
133-4 Notwithstanding any other provision of law, the decision to
133-5 participate in customer choice by the adoption of a resolution in
133-6 accordance with Section 40.051(b) is irrevocable.
133-7 CHAPTER 41. ELECTRIC COOPERATIVES AND COMPETITION
133-8 SUBCHAPTER A. GENERAL PROVISIONS
133-9 Sec. 41.001. APPLICABLE LAW. Notwithstanding any other
133-10 provision of law, except Sections 39.155, 39.157(e), 39.203,
133-11 39.603, and 39.604, this chapter governs the transition to and the
133-12 establishment of a fully competitive electric power industry for
133-13 electric cooperatives. Regarding the regulation of electric
133-14 cooperatives, this chapter shall control over any other provision
133-15 of this title, except for sections in which the term "electric
133-16 cooperative" is specifically used.
133-17 Sec. 41.002. DEFINITIONS. In this chapter:
133-18 (1) "Board of directors" means the board of directors
133-19 of an electric cooperative as described in Section 161.071.
133-20 (2) "Rate" includes any compensation, tariff, charge,
133-21 fare, toll, rental, or classification that is directly or
133-22 indirectly demanded, observed, charged, or collected by an electric
133-23 cooperative for any service, product, or commodity and any rule,
133-24 practice, or contract affecting the compensation, tariff, charge,
133-25 fare, toll, rental, or classification.
133-26 (3) "Stranded investment" means:
134-1 (A) the excess, if any, of the net book value of
134-2 generation assets over the market value of the generation assets;
134-4 (B) any above market purchased power costs.
134-5 Sec. 41.003. SECURITIZATION. (a) Electric cooperatives may
134-6 adopt and use securitization provisions having the effect of the
134-7 provisions set out in Subchapter G, Chapter 39, to recover through
134-8 rates stranded costs at a recovery level deemed appropriate by the
134-9 board of directors up to 100 percent, under rules and procedures
134-10 that shall be established by the commission.
134-11 (b) The rules and procedures for securitization established
134-12 under Subsection (a) shall include rules and procedures for the
134-13 recovery of stranded costs pursuant to the terms of a rate order
134-14 adopted by the board of directors of the electric cooperative,
134-15 which rate order shall have the effect of a financing order.
134-16 (c) The rules and procedures established by the commission
134-17 under Subsection (b) shall include rules and procedures for the
134-18 issuance of transition bonds issued in a securitized financing
134-19 transaction. The issuance of any transition bonds issued in a
134-20 securitized financing transaction by an electric cooperative is
134-21 expressly authorized and shall be governed by the laws governing
134-22 the issuance of bonds or other obligations by the electric
134-23 cooperative. Findings made by the board of directors of an
134-24 electric cooperative in a rate order issued under the rules and
134-25 procedures described by this subsection shall be conclusive, and
134-26 any transition charges incorporated in such rate order to recover
135-1 the principal, interest, and all reasonable expenses associated
135-2 with any securitized financing transaction shall constitute
135-3 property rights, as described in Subchapter G, Chapter 39, and
135-4 shall otherwise conform in all material respects to the transition
135-5 charges set forth in Subchapter G, Chapter 39.
135-6 Sec. 41.004. JURISDICTION OF THE COMMISSION. Except as
135-7 specifically provided otherwise in this chapter, the commission has
135-8 jurisdiction over electric cooperatives only as follows:
135-9 (1) to regulate wholesale transmission rates and
135-10 service including terms of access, to the extent provided in
135-11 Subchapter A, Chapter 35;
135-12 (2) to regulate certification of retail service areas
135-13 to the extent provided in Chapter 37;
135-14 (3) to establish a code of conduct as provided in
135-15 Section 39.157(e) subject to Section 41.054;
135-16 (4) to establish terms and conditions, but not rates,
135-17 for open access to distribution facilities for electric
135-18 cooperatives providing customer choice, as provided in Section
135-19 39.203; and
135-20 (5) to require reports of electric cooperative
135-21 operations only to the extent necessary to:
135-22 (A) ensure the public safety;
135-23 (B) enable the commission to satisfy its
135-24 responsibilities relating to electric cooperatives under this
135-26 (C) enable the commission to determine the
136-1 aggregate electric load and energy requirements in the state and
136-2 the resources available to serve that load; or
136-3 (D) enable the commission to determine
136-4 information relating to market power as provided in Section 39.155.
136-5 Sec. 41.005. LIMITATION ON MUNICIPAL AUTHORITY.
136-6 Notwithstanding any other provision of this title, a municipality
136-7 may not directly or indirectly regulate the rates, operations, and
136-8 services of an electric cooperative. This section shall not
136-9 prohibit a municipality from making a lawful charge for the use of
136-10 public rights-of-way within the municipality as provided by Section
136-11 182.025, Tax Code.
136-12 SUBCHAPTER B. ELECTRIC COOPERATIVE UTILITY CHOICE
136-13 Sec. 41.051. BOARD DECISION. (a) The board of directors
136-14 has the discretion to decide when or if the electric cooperative
136-15 will provide customer choice.
136-16 (b) Electric cooperatives that choose to participate in
136-17 customer choice may do so at any time on or after January 1, 2002,
136-18 by adoption of an appropriate resolution of the board of directors.
136-19 The decision to participate in customer choice by the adoption of
136-20 such a resolution may be revoked only if no customer has opted for
136-21 choice within four years of the resolution's adoption. An electric
136-22 cooperative may initiate a customer choice pilot project at any
136-24 Sec. 41.052. ELECTRIC COOPERATIVES NOT OFFERING CUSTOMER
136-25 CHOICE. (a) An electric cooperative that chooses not to
136-26 participate in customer choice may not offer electric energy at
137-1 unregulated prices directly to retail customers outside its
137-2 certificated retail service area.
137-3 (b) An electric cooperative under Subsection (a) retains the
137-4 right to offer and provide a full range of customer service and
137-5 pricing programs to the customers within its certificated retail
137-6 service area and to purchase and sell electric energy at wholesale
137-7 without geographic restriction.
137-8 (c) A generation and transmission electric cooperative may
137-9 offer electric energy at unregulated prices directly to retail
137-10 customers outside of its parent electric cooperatives' certificated
137-11 service areas only if a majority of the parent electric
137-12 cooperatives of the generation and transmission electric
137-13 cooperative have chosen to offer customer choice.
137-14 (d) A subsidiary of an electric cooperative may not provide
137-15 electric energy at unregulated prices outside of its parent
137-16 electric cooperative's certificated retail service area unless the
137-17 electric cooperative offers customer choice inside its certificated
137-18 retail service area.
137-19 Sec. 41.053. RETAIL CUSTOMER RIGHT OF CHOICE. (a) If an
137-20 electric cooperative chooses to participate in customer choice,
137-21 after that choice, all retail customers within the certificated
137-22 service area of the electric cooperative shall have the right of
137-23 customer choice, and the electric cooperative shall provide
137-24 nondiscriminatory open access for retail service.
137-25 (b) Notwithstanding Section 39.107, the metering function
137-26 shall not be deemed a competitive service for customers of the
138-1 electric cooperative within such service area and may, at the
138-2 option of the electric cooperative, continue to be offered by the
138-3 electric cooperative as sole provider.
138-4 (c) Upon its initiation of customer choice, an electric
138-5 cooperative shall designate itself or another entity as the
138-6 provider of last resort for retail customers within the electric
138-7 cooperative's certificated service area and shall fulfill the role
138-8 of default provider of last resort in the event no other entity is
138-9 available to act in that capacity.
138-10 (d) If a retail electric provider fails to serve a customer
138-11 described in Subsection (c), upon request by the customer, the
138-12 provider of last resort shall offer the customer the standard
138-13 retail service package for the appropriate customer class, with no
138-14 interruption of service, at a fixed, nondiscountable rate that is
138-15 at least sufficient to cover the reasonable costs of providing such
138-16 service, as approved by the board of directors.
138-17 (e) The board of directors may establish the procedures and
138-18 criteria for designating the provider of last resort and may
138-19 redesignate the provider of last resort according to a schedule it
138-20 considers appropriate.
138-21 Sec. 41.054. SERVICE OUTSIDE CERTIFICATED AREA. (a) An
138-22 electric cooperative participating in customer choice shall have
138-23 the right to offer electric energy and related services at
138-24 unregulated prices directly to retail customers within qualifying
138-25 power regions without regard to geographic location.
138-26 (b) In providing service under Subsection (a) to retail
139-1 customers outside its certificated service area as that area exists
139-2 on the date of adoption of customer choice, an electric cooperative
139-3 becomes subject to commission jurisdiction as to the commission's
139-4 rules establishing a code of conduct regulating anticompetitive
139-5 practices under Section 39.157(e), except to the extent such rules
139-6 conflict with this chapter.
139-7 (c) For electric cooperatives participating in customer
139-8 choice, the commission shall have jurisdiction to establish terms
139-9 and conditions, but not rates, for access by other electric
139-10 providers to the electric cooperative's distribution facilities.
139-11 (d) Notwithstanding Subsections (b) and (c), the commission
139-12 shall make accommodation in the code of conduct for specific legal
139-13 requirements imposed by state or federal law applicable to electric
139-14 cooperatives. The commission shall accommodate the organizational
139-15 structures of electric cooperatives and shall not prohibit an
139-16 electric cooperative and any related entity from sharing officers,
139-17 directors, or employees.
139-18 (e) The commission does not have jurisdiction to require the
139-19 unbundling of services or functions of, or to regulate the recovery
139-20 of stranded investment of, an electric cooperative or, except as
139-21 provided by this section, jurisdiction with respect to the rates,
139-22 terms, and conditions of service for retail customers of an
139-23 electric cooperative within the electric cooperative's certificated
139-24 service area.
139-25 (f) An electric cooperative shall maintain separate books
139-26 and records of its operations and the operations of any subsidiary
140-1 and shall ensure that the rates charged for provision of electric
140-2 service do not include any costs of its subsidiary or any other
140-3 costs not related to the provision of electric service.
140-4 Sec. 41.055. JURISDICTION OF BOARD OF DIRECTORS. A board of
140-5 directors has exclusive jurisdiction to:
140-6 (1) set all terms of access, conditions, and rates
140-7 applicable to services provided by the electric cooperative, except
140-8 as provided by Sections 41.054 and 41.056, including
140-9 nondiscriminatory and comparable terms of access, conditions, and
140-10 rates for distribution but excluding wholesale transmission rates,
140-11 terms of access, and conditions for wholesale transmission service
140-12 set by the commission under Subchapter A, Chapter 35, provided that
140-13 the rates for distribution established by the electric cooperative
140-14 shall be comparable to the distribution rates that apply to the
140-15 electric cooperative and its subsidiaries;
140-16 (2) determine whether to unbundle any energy-related
140-17 activities, and if the board of directors chooses to unbundle,
140-18 whether to do so structurally or functionally;
140-19 (3) reasonably determine the amount of the electric
140-20 cooperative's stranded investment;
140-21 (4) establish nondiscriminatory transition charges
140-22 reasonably designed to recover the stranded investment over an
140-23 appropriate period of time;
140-24 (5) determine the extent to which the electric
140-25 cooperative will provide various customer services, including
140-26 nonelectric services, or accept the services from other providers;
141-1 (6) manage and operate the electric cooperative's
141-2 utility systems, including exercise of control over resource
141-3 acquisition and any related expansion programs;
141-4 (7) establish and enforce service quality standards,
141-5 reliability standards, and consumer safeguards designed to protect
141-6 retail electric customers;
141-7 (8) determine whether a base rate reduction is
141-8 appropriate for the electric cooperative;
141-9 (9) determine any other utility matters that the board
141-10 of directors believes should be included;
141-11 (10) sell electric energy and capacity at wholesale,
141-12 regardless of whether the electric cooperative participates in
141-13 customer choice; and
141-14 (11) make any other decisions affecting the electric
141-15 cooperative's method of conducting business that are not
141-16 inconsistent with the provisions of this chapter.
141-17 Sec. 41.056. ANTICOMPETITIVE ACTIONS. (a) If, after notice
141-18 and hearing, the commission finds that an electric cooperative
141-19 providing customer choice has engaged in anticompetitive behavior
141-20 by not providing other retail electric providers with
141-21 nondiscriminatory terms and conditions of access to distribution
141-22 facilities or customers within the electric cooperative's
141-23 certificated service area that are comparable to the electric
141-24 cooperative's and its subsidiaries' terms and conditions of access
141-25 to distribution facilities or customers, the commission shall
141-26 notify the electric cooperative.
142-1 (b) The electric cooperative shall have three months to cure
142-2 the anticompetitive or noncompliant behavior described in
142-3 Subsection (a). If the behavior is not fully remedied within that
142-4 time, the commission may prohibit the electric cooperative or its
142-5 subsidiary from providing retail service outside its certificated
142-6 retail service area until the behavior is remedied.
142-7 Sec. 41.057. BILLING. (a) An electric cooperative that
142-8 opts for customer choice may continue to bill directly electric
142-9 customers located in its certificated service area for all
142-10 transmission and distribution services. The electric cooperative
142-11 may also bill directly for generation and customer services
142-12 provided by the electric cooperative or its subsidiaries to those
142-14 (b) A customer served by an electric cooperative for
142-15 transmission and distribution services and by a retail electric
142-16 provider for retail service has the option of being billed directly
142-17 by each service provider or receiving a single bill for
142-18 distribution, transmission, and generation services from the
142-19 electric cooperative.
142-20 Sec. 41.058. TARIFFS FOR OPEN ACCESS. An electric
142-21 cooperative that owns or operates transmission and distribution
142-22 facilities shall file tariffs implementing the open access rules
142-23 established by the commission under Section 39.203 with the
142-24 appropriate regulatory authorities having jurisdiction over the
142-25 transmission and distribution service of the electric cooperative
142-26 before the 90th day preceding the date the electric cooperative
143-1 offers customer choice.
143-2 Sec. 41.059. NO POWER TO AMEND CERTIFICATES. Nothing in
143-3 this chapter empowers a board of directors to issue, amend, or
143-4 rescind a certificate of public convenience and necessity granted
143-5 by the commission.
143-6 Sec. 41.060. CUSTOMER SERVICE INFORMATION. (a) The
143-7 commission shall keep information submitted by customers and retail
143-8 electric providers pertaining to the provision of electric service
143-9 by electric cooperatives.
143-10 (b) The commission shall notify the appropriate electric
143-11 cooperative of information submitted by a customer or retail
143-12 electric provider, and the electric cooperative shall respond to
143-13 the customer or retail electric provider. The electric cooperative
143-14 shall notify the commission of its response.
143-15 (c) The commission shall prepare a report for the Sunset
143-16 Advisory Commission that includes information submitted and
143-17 responses by electric cooperatives pursuant to the Sunset Advisory
143-18 Commission's schedule for reviewing the commission.
143-19 Sec. 41.061. RETAIL RATE CHANGES BY ELECTRIC COOPERATIVES.
143-20 (a) This section shall apply to retail rates of an electric
143-21 cooperative that has not adopted customer choice and to the retail
143-22 delivery rates of an electric cooperative that has adopted customer
143-23 choice. This section shall not apply to rates for:
143-24 (1) sales of electric energy by an electric
143-25 cooperative that has adopted customer choice; or
143-26 (2) wholesale sales of electric energy.
144-1 (b) An electric cooperative may change its rates by:
144-2 (1) adopting a resolution approving the proposed
144-4 (2) mailing notice of the proposed change to each
144-5 affected customer whose rate would be increased by the proposed
144-6 change at least 30 days before implementation of the proposed
144-7 change, which notice may be included in a monthly billing; and
144-8 (3) holding a meeting to discuss the proposed rate
144-9 changes with affected customers, if any change is expected to
144-10 increase total system annual revenues by more than $100,000 or one
144-11 percent, whichever is greater.
144-12 (c) An electric cooperative may implement the proposed rates
144-13 upon completion of the requirements under Subsection (b), and such
144-14 rates shall remain in effect until changed by the electric
144-15 cooperative as provided by this section or, for rates other than
144-16 retail delivery rates, until this section is no longer applicable
144-17 because the electric cooperative adopts customer choice.
144-18 (d) The electric cooperative may reconsider a rate change at
144-19 any time and adjust the rate by board resolution without additional
144-20 notice or meeting of customers if the rate as adjusted is within
144-21 the general scope of the notice previously provided to affected
144-22 customers or is expected to decrease the revenues of the electric
144-24 (e) Retail rates set by an electric cooperative that has not
144-25 adopted customer choice and retail delivery rates set by an
144-26 electric cooperative that has adopted customer choice shall be just
145-1 and reasonable, not unreasonably preferential, prejudicial, or
145-2 discriminatory; provided, however, that an electric cooperative may
145-3 charge market-based rates to customers who have energy supply
145-5 (f) A customer of the electric cooperative who is adversely
145-6 affected by a resolution of the electric cooperative setting rates
145-7 is entitled to judicial review. A person initiates judicial review
145-8 by filing a petition in the district court of Travis County not
145-9 later than the 60th day after the date the resolution is
145-11 (g) The resolution of the electric cooperative setting
145-12 rates, as it may have been amended as described in Subsection (d),
145-13 shall be presumed valid, and the burden of showing that the
145-14 resolution is invalid rests upon the persons challenging the
145-15 resolution. A court reviewing a rate change by an electric
145-16 cooperative may consider any relevant factor that may be considered
145-17 by a court in reviewing a decision of the commission including the
145-18 cost of providing service.
145-19 (h) If the court finds that the electric cooperative's
145-20 resolution setting rates violates the standards contained in
145-21 Subsection (e), the court shall enter an order:
145-22 (1) stating the specific basis for its determination
145-23 that the rates set in the electric cooperative's resolution violate
145-24 Subsection (e); and
145-25 (2) directing the electric cooperative to:
145-26 (A) set, within 60 days, revised retail rates
146-1 that do not violate the standards of Subsection (e); and
146-2 (B) refund or credit against future bills, at
146-3 the electric cooperative's option, revenues collected under the
146-4 rate found to violate the standards of Subsection (e) that exceed
146-5 the revenues that would have been collected under the revised
146-6 rates. The refund or credit shall be made over a period of not
146-7 more than 12 months, as determined by the electric cooperative.
146-8 (i) No remedy other than or additional to a remedy under
146-9 Subsection (h) may be ordered by the court. The court may not set
146-10 revised rates either for the period the challenged resolution was
146-11 in effect or prospectively.
146-12 (j) Except as provided by this section, and Subchapter A,
146-13 Chapter 35, with regard to wholesale transmission rates, the rates
146-14 of an electric cooperative are not subject to review.
146-15 Sec. 41.062. ALLOCATION OF STRANDED INVESTMENT. Any
146-16 competition transition charge shall be allocated among retail
146-17 customer classes based on the relevant customer class
146-18 characteristics as of the end of the electric cooperative's most
146-19 recent fiscal year prior to implementation of customer choice, in
146-20 accordance with the methodology used to allocate the costs of the
146-21 underlying assets or expenses in the electric cooperative's most
146-22 recent cost of service study certified by a professional engineer
146-23 or certified public accountant or approved by the commission. In
146-24 multiply certificated areas, a retail customer may not avoid
146-25 stranded cost recovery charges by switching to another electric
146-26 cooperative, an electric utility, or a municipally owned utility.
147-1 SUBCHAPTER C. RIGHTS NOT AFFECTED
147-2 Sec. 41.101. INTERFERENCE WITH CONTRACT. (a) This subtitle
147-3 shall not interfere with or abrogate the rights or obligations of
147-4 parties, including a retail or wholesale customer, to a contract
147-5 with an electric cooperative or its subsidiary.
147-6 (b) No provision of this subtitle may interfere with or be
147-7 deemed to abrogate the rights or obligations of a party under a
147-8 contract or an agreement concerning certificated service areas.
147-9 Sec. 41.102. ACCESS TO WHOLESALE MARKET. Nothing in this
147-10 subtitle shall limit the access of an electric cooperative or its
147-11 subsidiary, either on its own behalf or on behalf of its customers,
147-12 to the wholesale electric market.
147-13 Sec. 41.103. PROTECTION OF BONDHOLDERS. Nothing in this
147-14 subtitle or any rule adopted under this subtitle shall impair
147-15 contracts, covenants, or obligations between an electric
147-16 cooperative and its lenders and holders of bonds issued on behalf
147-17 of or by the electric cooperative.
147-18 Sec. 41.104. TAX-EXEMPT STATUS. Nothing in this subtitle
147-19 may impair the tax-exempt status of electric cooperatives, nor
147-20 shall anything in this subtitle compel any electric cooperative to
147-21 use its facilities in a manner which violates any contractual
147-22 provisions, bond covenants, or other restrictions applicable to
147-23 facilities financed by tax-exempt or federally insured or
147-24 guaranteed debt.
147-25 SECTION 36. Section 252.022, Local Government Code, is
147-26 amended by adding Subsection (c) to read as follows:
148-1 (c) This chapter does not apply to expenditures by a
148-2 municipally owned electric or gas utility or unbundled divisions of
148-3 a municipally owned electric or gas utility in connection with any
148-4 purchases by the municipally owned utility or divisions of a
148-5 municipally owned utility made in accordance with procurement
148-6 procedures adopted by a resolution of the body vested with
148-7 authority for management and operation of the municipally owned
148-8 utility or its divisions that sets out the public purpose to be
148-9 achieved by such procedures. This subsection shall not be deemed
148-10 to exempt a municipally owned utility from any other applicable
148-11 statute, charter provision, or ordinance.
148-12 SECTION 37. Section 272.001, Local Government Code, is
148-13 amended by adding Subsection (j) to read as follows:
148-14 (j) This section does not apply to sales or exchanges of
148-15 land owned by a municipality operating a municipally owned electric
148-16 or gas utility if the land is held or managed by the municipally
148-17 owned utility, or by a division of the municipally owned electric
148-18 or gas utility that constitutes the unbundled electric or gas
148-19 operations of the utility, provided that the governing body of the
148-20 municipally owned utility shall adopt a resolution stating the
148-21 conditions and circumstances for the sale or exchange and the
148-22 public purpose that will be achieved by the sale or exchange. For
148-23 purposes of this subsection, "municipally owned utility" includes a
148-24 river authority engaged in the generation, transmission, or
148-25 distribution of electric energy to the public, and "unbundled"
148-26 operations are those operations of the utility that have, in the
149-1 discretion of the utility's governing body, been functionally
149-3 SECTION 38. Subsection (c), Section 402.002, Local
149-4 Government Code, is amended to read as follows:
149-5 (c) The municipality may manufacture its own electricity,
149-6 gas, or anything else needed or used by the public. It may
149-7 purchase, and make contracts for the purchase of, gas, electricity,
149-8 oil, or any other commodity or article used by the public and may
149-9 sell it to the public on terms as provided by the municipal
149-10 charter, ordinance, or resolution of the governing body of the
149-11 municipally owned utility.
149-12 SECTION 39. Subchapter D, Chapter 551, Government Code, is
149-13 amended by adding Section 551.086 to read as follows:
149-14 Sec. 551.086. CERTAIN PUBLIC POWER UTILITIES: COMPETITIVE
149-15 MATTERS. (a) Notwithstanding anything in this chapter to the
149-16 contrary, the rules provided by this section apply to competitive
149-17 matters of a public power utility.
149-18 (b) In this section:
149-19 (1) "Public power utility" means an entity providing
149-20 electric or gas utility services that is subject to the provisions
149-21 of this chapter.
149-22 (2) "Public power utility governing body" means the
149-23 board of trustees or other applicable governing body, including a
149-24 city council, of a public power utility.
149-25 (3)(A) "Competitive matter" means a utility-related
149-26 matter that the public power utility governing body in good faith
150-1 determines, by a vote under this section: (i) is related to the
150-2 public power utility's competitive activity, including commercial
150-3 information and (ii) would, if disclosed, give advantage to
150-4 competitors or prospective competitors.
150-5 (B) The following categories of information
150-6 shall not be deemed to be competitive matters:
150-7 (i) information relating to the provision
150-8 of distribution access service, including the terms and conditions
150-9 of such service and the rates charged for the service but not
150-10 including information concerning utility-related services or
150-11 products that are competitive;
150-12 (ii) information relating to the provision
150-13 of transmission service that is required to be filed with the
150-14 Public Utility Commission of Texas, subject to any confidentiality
150-15 provided for under the rules of the commission;
150-16 (iii) information for the distribution
150-17 system pertaining to reliability and continuity of service, to the
150-18 extent not security-sensitive, that relates to emergency
150-19 management, identification of critical loads such as hospitals and
150-20 police, records of interruption, and distribution feeder standards;
150-21 (iv) any substantive rule of general
150-22 applicability regarding service offerings, service regulation,
150-23 customer protections, or customer service adopted by the public
150-24 power utility as authorized by law;
150-25 (v) aggregate information reflecting
150-26 receipts or expenditures of funds of the public power utility, of
151-1 the type that would be included in audited financial statements;
151-2 (vi) information relating to equal
151-3 employment opportunities for minority groups, as filed with local,
151-4 state, or federal agencies;
151-5 (vii) information relating to the public
151-6 power utility's performance in contracting with minority business
151-8 (viii) information relating to nuclear
151-9 decommissioning trust agreements, of the type required to be
151-10 included in audited financial statements;
151-11 (ix) information relating to the amount
151-12 and timing of any transfer to an owning city's general fund;
151-13 (x) information relating to environmental
151-14 compliance as required to be filed with any local, state, or
151-15 national environmental authority, subject to any confidentiality
151-16 provided under the rules of such authorities;
151-17 (xi) names of public officers of the
151-18 public power utility and the voting records of such officers for
151-19 all matters other than those within the scope of a competitive
151-20 resolution provided for by this section;
151-21 (xii) a description of the public power
151-22 utility's central and field organization, including the established
151-23 places at which the public may obtain information, submit
151-24 information and requests, or obtain decisions and the
151-25 identification of employees from whom the public may obtain
151-26 information, submit information or requests, or obtain decisions;
152-2 (xiii) information identifying the general
152-3 course and method by which the public power utility's functions are
152-4 channeled and determined, including the nature and requirements of
152-5 all formal and informal policies and procedures.
152-6 (c) This chapter does not require a public power utility
152-7 governing body to conduct an open meeting to deliberate, vote, or
152-8 take final action on any competitive matter, as that term is
152-9 defined in Subsection (b)(3). Before a public power utility
152-10 governing body may deliberate, vote, or take final action on any
152-11 such competitive matter in a closed meeting, the public power
152-12 utility governing body must first make a good-faith determination,
152-13 by majority vote of its members, that such matter is a competitive
152-14 matter that satisfies the requirements of Subsection (b)(3). The
152-15 vote shall be taken during the closed meeting and be included in
152-16 the certified agenda or tape recording of the closed meeting. If a
152-17 public power utility governing body fails to determine by such vote
152-18 that the matter satisfies the requirements of Subsection (b)(3),
152-19 the public power utility governing body may not deliberate or take
152-20 any further action on the matter in the closed meeting. This
152-21 section does not limit the right of a public power utility
152-22 governing body to hold a closed session pursuant to any other
152-23 exception provided for in this chapter.
152-24 (d) For purposes of Section 551.041, the notice of the
152-25 subject matter of an item that may be considered as a competitive
152-26 matter under this section is required to contain no more than a
153-1 general representation of the subject matter to be considered, such
153-2 that the competitive activity of the public power utility with
153-3 respect to the issue in question is not compromised or disclosed.
153-4 (e) With respect to municipally owned utilities subject to
153-5 this section, this section shall apply whether or not the
153-6 municipally owned utility has adopted customer choice or serves in
153-7 a multiply certificated service area under the Utilities Code.
153-8 (f) Nothing in this section is intended to preclude the
153-9 application of the enforcement and remedies provisions of
153-10 Subchapter G.
153-11 SECTION 40. Subchapter C, Chapter 552, Government Code, is
153-12 amended by adding Section 552.131 to read as follows:
153-13 Sec. 552.131. EXCEPTION: PUBLIC POWER UTILITY COMPETITIVE
153-14 MATTERS. (a) In this section:
153-15 (1) "Public power utility" means an entity providing
153-16 electric or gas utility services that is subject to the provisions
153-17 of this chapter.
153-18 (2) "Public power utility governing body" means the
153-19 board of trustees or other applicable governing body, including a
153-20 city council, of a public power utility.
153-21 (3)(A) "Competitive matter" means a utility-related
153-22 matter which the public power utility governing body in good faith
153-23 determines by a vote under this section: (i) is related to the
153-24 public power utility's competitive activity, including commercial
153-25 information; and (ii) would, if disclosed, give advantage to
153-26 competitors or prospective competitors.
154-1 (B) The following categories of information
154-2 shall not be deemed to be competitive matters:
154-3 (i) information relating to the provision
154-4 of distribution access service, including the terms and conditions
154-5 of such service and the rates charged for the service but not
154-6 including information concerning utility related services or
154-7 products that are competitive;
154-8 (ii) information relating to the provision
154-9 of transmission service that is required to be filed with the
154-10 Public Utility Commission of Texas, subject to any confidentiality
154-11 provided for under the rules of the commission;
154-12 (iii) information for the distribution
154-13 system pertaining to reliability and continuity of service, to the
154-14 extent not security-sensitive, that relates to emergency
154-15 management, identification of critical loads such as hospitals and
154-16 police, records of interruption, and distribution feeder standards;
154-17 (iv) any substantive rule of general
154-18 applicability regarding service offerings, service regulation,
154-19 customer protections, or customer service adopted by the public
154-20 power utility as authorized by law;
154-21 (v) aggregate information reflecting
154-22 receipts or expenditures of funds of the public power utility, of
154-23 the type that would be included in audited financial statements;
154-24 (vi) information relating to equal
154-25 employment opportunities for minority groups, as filed with local,
154-26 state, or federal agencies;
155-1 (vii) information relating to the public
155-2 power utility's performance in contracting with minority business
155-4 (viii) information relating to nuclear
155-5 decommissioning trust agreements, of the type required to be
155-6 included in audited financial statements;
155-7 (ix) information relating to the amount
155-8 and timing of any transfer to an owning city's general fund;
155-9 (x) information relating to environmental
155-10 compliance as required to be filed with any local, state, or
155-11 national environmental authority, subject to any confidentiality
155-12 provided under the rules of such authorities;
155-13 (xi) names of public officers of the
155-14 public power utility and the voting records of such officers for
155-15 all matters other than those within the scope of a competitive
155-16 resolution provided for by this section;
155-17 (xii) a description of the public power
155-18 utility's central and field organization, including the established
155-19 places at which the public may obtain information, submit
155-20 information and requests, or obtain decisions and the
155-21 identification of employees from whom the public may obtain
155-22 information, submit information or requests, or obtain decisions;
155-24 (xiii) information identifying the general
155-25 course and method by which the public power utility's functions are
155-26 channeled and determined, including the nature and requirements of
156-1 all formal and informal policies and procedures.
156-2 (b) Information or records are excepted from the
156-3 requirements of Section 552.021 if the information or records are
156-4 reasonably related to a competitive matter, as defined in this
156-5 section. Such information or records include the text of any
156-6 resolution of the public power utility governing body determining
156-7 which issues, activities, or matters constitute competitive
156-8 matters. Information or records of a municipally owned utility
156-9 that are reasonably related to a competitive matter are not subject
156-10 to disclosure under this chapter, whether or not, under the
156-11 Utilities Code, the municipally owned utility has adopted customer
156-12 choice or serves in a multiply certificated service area. This
156-13 section does not limit the right of a public power utility
156-14 governing body to withhold from disclosure information deemed to be
156-15 within the scope of any other exception provided for in this
156-16 chapter, subject to the provisions of this chapter.
156-17 (c) In connection with any request for an opinion of the
156-18 attorney general under Section 552.301 with respect to information
156-19 alleged to fall under this exception, in rendering a written
156-20 opinion under Section 552.306 the attorney general shall find the
156-21 requested information to be outside the scope of this exception
156-22 only if the attorney general determines, based on the information
156-23 provided in connection with the request: (i) that the public power
156-24 utility governing body has failed to act in good faith in making
156-25 the determination that the issue, matter, or activity in question
156-26 is a competitive matter; or (ii) that the information or records
157-1 sought to be withheld are not reasonably related to a competitive
157-3 SECTION 41. Subsection (d), Section 791.011, Government
157-4 Code, is amended to read as follows:
157-5 (d) An interlocal contract must:
157-6 (1) be authorized by the governing body of each party
157-7 to the contract; however, if a party to the contract is a
157-8 municipally owned electric utility, the governing body may
157-9 establish procedures for entering into interlocal contracts that do
157-10 not exceed $100,000 without requiring the approval of the governing
157-12 (2) state the purpose, terms, rights, and duties of
157-13 the contracting parties; and
157-14 (3) specify that each party paying for the performance
157-15 of governmental functions or services must make those payments from
157-16 current revenues available to the paying party.
157-17 SECTION 42. Subchapter A, Chapter 2256, Government Code, is
157-18 amended by adding Section 2256.0201 to read as follows:
157-19 Sec. 2256.0201. AUTHORIZED INVESTMENTS; MUNICIPAL UTILITY.
157-20 (a) A municipality that owns a municipal electric utility that is
157-21 engaged in the distribution and sale of electric energy or natural
157-22 gas to the public may enter into a hedging contract and related
157-23 security and insurance agreements in relation to fuel oil, natural
157-24 gas, and electric energy to protect against loss due to price
157-25 fluctuations. A hedging transaction must comply with the
157-26 regulations of the Commodity Futures Trading Commission and the
158-1 Securities and Exchange Commission. If there is a conflict between
158-2 the municipal charter of the municipality and this chapter, this
158-3 chapter prevails.
158-4 (b) A payment by a municipally owned electric or gas utility
158-5 under a hedging contract or related agreement in relation to fuel
158-6 supplies or fuel reserves is a fuel expense, and the utility may
158-7 credit any amounts it receives under the contract or agreement
158-8 against fuel expenses.
158-9 (c) The governing body of a municipally owned electric or
158-10 gas utility or the body vested with power to manage and operate the
158-11 municipally owned electric or gas utility may set policy regarding
158-12 hedging transactions.
158-13 (d) In this section, "hedging" means the buying and selling
158-14 of fuel oil, natural gas, and electric energy futures or options or
158-15 similar contracts on those commodity futures as a protection
158-16 against loss due to price fluctuation.
158-17 SECTION 43. Subsections (a), (c), and (d), Section 52.133,
158-18 Natural Resources Code, are amended to read as follows:
158-19 (a) Each oil or gas lease covering land leased by the board,
158-20 by a board for lease [ other than the Board for Lease of University
158-21 Lands], or by the surface owner of land under which the state owns
158-22 the minerals, commonly referred to as Relinquishment Act land,
158-23 which shall be subject to approval by the commissioner before it is
158-24 effective, shall include a provision granting the board authorized
158-25 to lease the land or the owner of the soil of Relinquishment Act
158-26 land and the commissioner authority to take their royalty in kind,
159-1 and the commissioner and the boards for lease may include any other
159-2 reasonable provisions that are not inconsistent with this section.
159-3 (c) The commissioner, the owner of the soil under Subchapter
159-4 F [ of this chapter], or the commissioner[ ,] acting on the behalf of
159-5 and at the direction of an owner of the soil under Subchapter F [ of
159-6 this chapter], the board, or a board for lease, or at the direction
159-7 of the Board for Lease of University Lands, may negotiate and
159-8 execute contracts or any other instruments or agreements necessary
159-9 to dispose of or enhance their portion of the royalty taken in
159-10 kind, including contracts for sale, purchase, transportation, and
159-11 storage and including insurance contracts or other agreements, to
159-12 secure or guarantee payment.
159-13 (d) The commissioner, the owner of the soil under Subchapter
159-14 F, or the commissioner acting on behalf of and at the direction of
159-15 an owner of the soil under Subchapter F, the board, or a board for
159-16 lease, may negotiate and execute contracts or any other instruments
159-17 or agreements necessary to convert that portion of the royalty
159-18 taken in kind into other forms of energy, including electricity.
159-19 [ This section does not apply to or have any effect on the Board for
159-20 Lease of University Lands or any lease executed on university
159-22 SECTION 44. Section 53.026, Natural Resources Code, is
159-23 amended to read as follows:
159-24 Sec. 53.026. In Kind Royalty. (a) The commissioner or the
159-25 commissioner acting on behalf of and at the direction of the board
159-26 or a board for lease may negotiate and execute a contract or any
160-1 other instrument or agreement necessary to dispose of or enhance
160-2 their portion of the royalty taken in kind, including contracts [ a
160-3 contract] for sale, purchase, transportation, or storage.
160-4 (b) The commissioner or the commissioner acting on behalf of
160-5 and at the direction of the board or a board for lease may
160-6 negotiate and execute a contract or any other instrument or
160-7 agreement necessary to convert that portion of the royalty taken in
160-8 kind to other forms of energy, including electricity.
160-9 (c) This section shall not be construed to surrender or in
160-10 any way affect the right of the state under an existing or future
160-11 lease to receive monetary royalty from its lessee.
160-12 SECTION 45. Section 53.077, Natural Resources Code, is
160-13 amended to read as follows:
160-14 Sec. 53.077. In Kind Royalty. (a) The commissioner, each
160-15 owner of the soil under this subchapter, or the commissioner acting
160-16 on the behalf of and at the direction of an owner of the soil under
160-17 this subchapter may negotiate and execute a contract or any other
160-18 instrument or agreement necessary to dispose of or enhance their
160-19 portion of the royalty taken in kind, including a contract for
160-20 sale, transportation, or storage.
160-21 (b) The commissioner, each owner of the soil under this
160-22 subchapter, or the commissioner acting on behalf of and at the
160-23 direction of the owner of the soil under this subchapter may
160-24 negotiate and execute a contract or any other instrument or
160-25 agreement necessary to convert that portion of the royalty taken in
160-26 kind to other forms of energy, including electricity.
161-1 (c) This section shall not be construed to surrender or in
161-2 any way affect the right of the state or the owner of the soil
161-3 under an existing or future lease to receive monetary royalty from
161-4 its lessee.
161-5 SECTION 46. Chapter 245, Acts of the 67th Legislature,
161-6 Regular Session, 1981 (Article 717p, Vernon's Texas Civil
161-7 Statutes), is amended by adding Section 4C to read as follows:
161-8 Sec. 4C. (a) This section applies only to a river authority
161-9 that is engaged in the distribution and sale of electric energy to
161-10 the public.
161-11 (b) Notwithstanding any other law, a river authority may:
161-12 (1) provide transmission services, as defined by the
161-13 Utilities Code or the Public Utility Commission of Texas, on a
161-14 regional basis to any eligible transmission customer at any
161-15 location within or outside the boundaries of the river authority;
161-17 (2) acquire, including by lease-purchase; lease from
161-18 or to any person; finance; construct; rebuild; operate; or sell
161-19 electric transmission facilities at any location within or outside
161-20 the boundaries of the river authority; provided, however, that
161-21 nothing in this section shall:
161-22 (A) allow a river authority to construct
161-23 transmission facilities to an ultimate consumer of electricity to
161-24 enable an ultimate consumer to bypass the transmission or
161-25 distribution facilities of its existing provider; or
161-26 (B) relieve a river authority from an obligation
162-1 to comply with the provisions of the Utilities Code concerning a
162-2 certificate of convenience and necessity for a transmission
162-4 SECTION 47. Sections 1 and 2, Article 1115a, Revised
162-5 Statutes, are amended to read as follows:
162-6 Sec. 1. This article applies only to a home-rule
162-7 municipality that owns an electric utility system, that by
162-8 ordinance or charter elects to have the management and control of
162-9 the system governed by a board of trustees [ this article], and
162-11 (1) has outstanding obligations payable in whole or
162-12 part [ solely] from and secured by a lien on and pledge of net
162-13 revenues of the system; or
162-14 (2) issues obligations that are payable in whole or
162-15 part [ solely] from and secured by a lien on and pledge of the net
162-16 revenues of the system and that are approved by the attorney
162-18 Sec. 2. A municipality by ordinance may transfer management
162-19 and control of the electric utility system to a [ five-member] board
162-20 of trustees appointed by the municipality's governing body. The
162-21 municipality by ordinance shall determine [ set] the qualifications
162-22 for appointment to the board and the number of members. The
162-23 municipality may by ordinance vest the power to establish rates and
162-24 related terms and conditions for its municipally owned electric
162-25 utility in the board of trustees appointed under this section,
162-26 notwithstanding any charter provision to the contrary.
163-1 SECTION 48. Subsection (a), Section 151.0101, Tax Code, is
163-2 amended to read as follows:
163-3 (a) "Taxable services" means:
163-4 (1) amusement services;
163-5 (2) cable television services;
163-6 (3) personal services;
163-7 (4) motor vehicle parking and storage services;
163-8 (5) the repair, remodeling, maintenance, and
163-9 restoration of tangible personal property, except:
163-10 (A) aircraft;
163-11 (B) a ship, boat, or other vessel, other than:
163-12 (i) a taxable boat or motor as defined by
163-13 Section 160.001;
163-14 (ii) a sports fishing boat; or
163-15 (iii) any other vessel used for pleasure;
163-16 (C) the repair, maintenance, and restoration of
163-17 a motor vehicle; and
163-18 (D) the repair, maintenance, creation, and
163-19 restoration of a computer program, including its development and
163-20 modification, not sold by the person performing the repair,
163-21 maintenance, creation, or restoration service;
163-22 (6) telecommunications services;
163-23 (7) credit reporting services;
163-24 (8) debt collection services;
163-25 (9) insurance services;
163-26 (10) information services;
164-1 (11) real property services;
164-2 (12) data processing services;
164-3 (13) real property repair and remodeling;
164-4 (14) security services; [ and]
164-5 (15) telephone answering services; and
164-6 (16) a sale by a transmission and distribution
164-7 utility, as defined in Section 31.002, Utilities Code, of
164-8 transmission or delivery of service directly to an electricity
164-9 end-use customer whose consumption of electricity is subject to
164-10 taxation under this chapter.
164-11 SECTION 49. Subdivision (1), Section 182.021, Tax Code, is
164-12 amended to read as follows:
164-13 (1) "Utility company" means a person:
164-14 (A) who owns or operates a gas[ , electric light,
164-15 electric power,] or water works, or water [ and light] plant used
164-16 for local sale and distribution located within an incorporated city
164-17 or town in this state; or
164-18 (B) who owns or operates an electric light or
164-19 electric power works, or light plant used for local sale and
164-20 distribution located within an incorporated city or town in this
164-21 state, or who is a retail electric provider, as that term is
164-22 defined in Section 31.002, Utilities Code, that makes local sales
164-23 within an incorporated city or town in this state; provided,
164-24 however, that a person who owns an electric light or electric power
164-25 or gas plant used for distribution but who does not make retail
164-26 sales to the ultimate consumer within an incorporated city or town
165-1 in this state is not included in this definition.
165-2 SECTION 50. Subchapter B, Chapter 182, Tax Code, is amended
165-3 by adding Section 182.027 to read as follows:
165-4 Sec. 182.027. NO EXEMPTION. Notwithstanding anything to the
165-5 contrary in Chapter 161, Utilities Code, this subchapter applies to
165-6 a retail electric provider that is an organizational unit of an
165-7 electric cooperative organized under Chapter 161, Utilities Code,
165-8 that is subject to retail competition under Chapter 41, Utilities
165-10 SECTION 51. The following provisions are repealed:
165-11 (1) Section 12.104, Utilities Code;
165-12 (2) Chapter 34, Utilities Code;
165-13 (3) Subchapters F and G, Chapter 36, Utilities Code; and
165-14 (4) Section 37.058, Utilities Code.
165-15 SECTION 52. (a) Nothing in this Act shall restrict or limit
165-16 a municipality's historical right to control and receive reasonable
165-17 compensation for use of public streets, alleys, rights-of-way, or
165-18 other public property to convey or provide electricity.
165-19 (b) Nothing in this Act shall affect a retail electric
165-20 utility's right to provide electric service in accordance with its
165-21 certificate of public convenience and necessity. A certificate of
165-22 convenience and necessity may, however, be revoked or modified as
165-23 provided by Section 37.059, Utilities Code, and Section 37.060,
165-24 Utilities Code, as added by this Act.
165-25 SECTION 53. The Public Utility Commission of Texas shall
165-26 study and make recommendations by December 15, 2000, to the 77th
166-1 Legislature for additional legislation that would move to and
166-2 establish a competitive electric market on January 1, 2002, in
166-3 accordance with the changes in law made by this Act.
166-4 SECTION 54. No later than 180 days after the effective date
166-5 of this Act, the Public Utility Commission of Texas shall establish
166-6 rules and procedures for the securitization of stranded costs for
166-7 river authorities, as provided by Subdivision (2), Subsection (a),
166-8 Section 40.003, Utilities Code, as added by this Act, and for
166-9 electric cooperatives, as provided by Section 41.003, Utilities
166-11 SECTION 55. This Act takes effect September 1, 1999.
166-12 SECTION 56. The importance of this legislation and the
166-13 crowded condition of the calendars in both houses create an
166-14 emergency and an imperative public necessity that the
166-15 constitutional rule requiring bills to be read on three several
166-16 days in each house be suspended, and this rule is hereby suspended.