76R16147 E
By Sibley, et al. S.B. No. 7
Substitute the following for S.B. No. 7:
By Wolens C.S.S.B. No. 7
A BILL TO BE ENTITLED
1-1 AN ACT
1-2 relating to electric utility restructuring and to the powers and
1-3 duties of the Public Utility Commission of Texas, Office of Public
1-4 Utility Counsel, and Texas Natural Resource Conservation
1-5 Commission; providing penalties.
1-6 BE IT ENACTED BY THE LEGISLATURE OF THE STATE OF TEXAS:
1-7 SECTION 1. Section 11.003, Utilities Code, is amended to
1-8 read as follows:
1-9 Sec. 11.003. DEFINITIONS. In this title:
1-10 (1) "Affected person" means:
1-11 (A) a public utility or electric cooperative
1-12 affected by an action of a regulatory authority;
1-13 (B) a person whose utility service or rates are
1-14 affected by a proceeding before a regulatory authority; or
1-15 (C) a person who:
1-16 (i) is a competitor of a public utility
1-17 with respect to a service performed by the utility; or
1-18 (ii) wants to enter into competition with
1-19 a public utility.
1-20 (2) "Affiliate" means:
1-21 (A) a person who directly or indirectly owns or
1-22 holds at least five percent of the voting securities of a public
1-23 utility;
2-1 (B) a person in a chain of successive ownership
2-2 of at least five percent of the voting securities of a public
2-3 utility;
2-4 (C) a corporation that has at least five percent
2-5 of its voting securities owned or controlled, directly or
2-6 indirectly, by a public utility;
2-7 (D) a corporation that has at least five percent
2-8 of its voting securities owned or controlled, directly or
2-9 indirectly, by:
2-10 (i) a person who directly or indirectly
2-11 owns or controls at least five percent of the voting securities of
2-12 a public utility; or
2-13 (ii) a person in a chain of successive
2-14 ownership of at least five percent of the voting securities of a
2-15 public utility;
2-16 (E) a person who is an officer or director of a
2-17 public utility or of a corporation in a chain of successive
2-18 ownership of at least five percent of the voting securities of a
2-19 public utility; or
2-20 (F) a person determined to be an affiliate under
2-21 Section 11.006.
2-22 (3) "Allocation" means the division among
2-23 municipalities or among municipalities and unincorporated areas of
2-24 the plant, revenues, expenses, taxes, and reserves of a utility
2-25 used to provide public utility service in a municipality or for a
2-26 municipality and unincorporated areas.
2-27 (4) "Commission" means the Public Utility Commission
3-1 of Texas.
3-2 (5) "Commissioner" means a member of the Public
3-3 Utility Commission of Texas.
3-4 (6) "Cooperative corporation" means:
3-5 (A) an electric cooperative [corporation
3-6 organized under Chapter 161 or a predecessor statute to Chapter 161
3-7 and operating under that chapter]; or
3-8 (B) a telephone cooperative corporation
3-9 organized under Chapter 162 or a predecessor statute to Chapter 162
3-10 and operating under that chapter.
3-11 (7) "Corporation" means a domestic or foreign
3-12 corporation, joint-stock company, or association, and each lessee,
3-13 assignee, trustee, receiver, or other successor in interest of the
3-14 corporation, company, or association, that has any of the powers or
3-15 privileges of a corporation not possessed by an individual or
3-16 partnership. The term does not include a municipal corporation or
3-17 electric cooperative, except as expressly provided by this title.
3-18 (8) "Counsellor" means the public utility counsel.
3-19 (9) "Electric cooperative" means:
3-20 (A) a corporation organized under Chapter 161 or
3-21 a predecessor statute to Chapter 161 and operating under that
3-22 chapter;
3-23 (B) a corporation organized as an electric
3-24 cooperative in a state other than Texas that has obtained a
3-25 certificate of authority to conduct affairs in the State of Texas;
3-26 or
3-27 (C) a successor to an electric cooperative
4-1 created before June 1, 1999, in accordance with a conversion plan
4-2 approved by a vote of the members of the electric cooperative,
4-3 regardless of whether the successor later purchases, acquires,
4-4 merges with, or consolidates with other electric cooperatives.
4-5 (10) "Facilities" means all of the plant and equipment
4-6 of a public utility, and includes the tangible and intangible
4-7 property, without limitation, owned, operated, leased, licensed,
4-8 used, controlled, or supplied for, by, or in connection with the
4-9 business of the public utility.
4-10 (11) [(10)] "Municipally owned utility" means a
4-11 utility owned, operated, and controlled by a municipality or by a
4-12 nonprofit corporation the directors of which are appointed by one
4-13 or more municipalities.
4-14 (12) [(11)] "Office" means the Office of Public
4-15 Utility Counsel.
4-16 (13) [(12)] "Order" means all or a part of a final
4-17 disposition by a regulatory authority in a matter other than
4-18 rulemaking, without regard to whether the disposition is
4-19 affirmative or negative or injunctive or declaratory. The term
4-20 includes:
4-21 (A) the issuance of a certificate of convenience
4-22 and necessity; and
4-23 (B) the setting of a rate.
4-24 (14) [(13)] "Person" includes an individual, a
4-25 partnership of two or more persons having a joint or common
4-26 interest, a mutual or cooperative association, and a corporation,
4-27 but does not include an electric cooperative.
5-1 (15) [(14)] "Proceeding" means a hearing,
5-2 investigation, inquiry, or other procedure for finding facts or
5-3 making a decision under this title. The term includes a denial of
5-4 relief or dismissal of a complaint.
5-5 (16) [(15)] "Rate" includes:
5-6 (A) any compensation, tariff, charge, fare,
5-7 toll, rental, or classification that is directly or indirectly
5-8 demanded, observed, charged, or collected by a public utility for a
5-9 service, product, or commodity described in the definition of
5-10 utility in Section 31.002 or 51.002; and
5-11 (B) a rule, practice, or contract affecting the
5-12 compensation, tariff, charge, fare, toll, rental, or
5-13 classification.
5-14 (17) [(16)] "Ratemaking proceeding" means[:]
5-15 [(A)] a proceeding in which a rate is changed[;
5-16 and]
5-17 [(B) a proceeding initiated under Chapter 34].
5-18 (18) [(17)] "Regulatory authority" means either the
5-19 commission or the governing body of a municipality, in accordance
5-20 with the context.
5-21 (19) [(18)] "Service" has its broadest and most
5-22 inclusive meaning. The term includes any act performed, anything
5-23 supplied, and any facilities used or supplied by a public utility
5-24 in the performance of the utility's duties under this title to its
5-25 patrons, employees, other public utilities, an electric
5-26 cooperative, and the public. The term also includes the
5-27 interchange of facilities between two or more public utilities.
6-1 The term does not include the printing, distribution, or sale of
6-2 advertising in a telephone directory.
6-3 (20) [(19)] "Test year" means the most recent 12
6-4 months, beginning on the first day of a calendar or fiscal year
6-5 quarter, for which operating data for a public utility are
6-6 available.
6-7 (21) [(20)] "Trade association" means a nonprofit,
6-8 cooperative, and voluntarily joined association of business or
6-9 professional persons who are employed by public utilities or
6-10 utility competitors to assist the public utility industry, a
6-11 utility competitor, or the industry's or competitor's employees in
6-12 dealing with mutual business or professional problems and in
6-13 promoting their common interest.
6-14 SECTION 2. Section 12.005, Utilities Code, is amended to
6-15 read as follows:
6-16 Sec. 12.005. APPLICATION OF SUNSET ACT. The Public Utility
6-17 Commission of Texas is subject to Chapter 325, Government Code
6-18 (Texas Sunset Act). Unless continued in existence as provided by
6-19 that chapter or by Chapter 39, the commission is abolished and this
6-20 title expires September 1, 2005 [2001].
6-21 SECTION 3. Section 12.101, Utilities Code, is amended to
6-22 read as follows:
6-23 Sec. 12.101. COMMISSION EMPLOYEES. The commission shall
6-24 employ:
6-25 (1) an executive director; and
6-26 (2) [a general counsel; and]
6-27 [(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
7-27 supplier, or other entity affected by a commission decision in a
8-1 manner other than by the setting of rates for that class of
8-2 customer;
8-3 (C) uses or receives a substantial amount of
8-4 tangible goods, services, or funds from the commission, other than
8-5 compensation or reimbursement authorized by law for commission
8-6 membership, attendance, or expenses; or
8-7 (D) notwithstanding Paragraph (B), has an
8-8 interest in a mutual fund or retirement fund in which more than 10
8-9 percent of the fund's holdings at the time of appointment is in a
8-10 single utility, utility competitor, or utility supplier in this
8-11 state and the person does not disclose this information to the
8-12 governor, senate, commission, or other entity, as appropriate.
8-13 (b) A person otherwise ineligible because of Subsection
8-14 (a)(2)(B) may be appointed to the commission and serve as a
8-15 commissioner or may be employed as [the general counsel or]
8-16 executive director if the person:
8-17 (1) notifies the attorney general and commission that
8-18 the person is ineligible because of Subsection (a)(2)(B); and
8-19 (2) divests the person or the person's spouse of the
8-20 ownership or control:
8-21 (A) before beginning service or employment; or
8-22 (B) if the person is already serving or
8-23 employed, within a reasonable time.
8-24 SECTION 5. Section 13.002, Utilities Code, is amended to
8-25 read as follows:
8-26 Sec. 13.002. APPLICATION OF SUNSET ACT. The Office of
8-27 Public Utility Counsel is subject to Chapter 325, Government Code
9-1 (Texas Sunset Act). Unless continued in existence as provided by
9-2 that chapter, the office is abolished and this chapter expires
9-3 September 1, 2005 [2001].
9-4 SECTION 6. Subsection (a), Section 13.003, Utilities Code,
9-5 is amended to read as follows:
9-6 (a) The office:
9-7 (1) shall assess the effect of utility rate changes
9-8 and other regulatory actions on residential consumers in this
9-9 state;
9-10 (2) shall advocate in the office's own name a position
9-11 determined by the counsellor to be most advantageous to a
9-12 substantial number of residential consumers;
9-13 (3) may appear or intervene, as a party or otherwise,
9-14 as a matter of right on behalf of:
9-15 (A) residential consumers, as a class, in any
9-16 proceeding before the commission, including an alternative dispute
9-17 resolution proceeding; and
9-18 (B) small commercial consumers, as a class, in
9-19 any proceeding in which the counsellor determines that small
9-20 commercial consumers are in need of representation, including an
9-21 alternative dispute resolution proceeding;
9-22 (4) may initiate or intervene as a matter of right or
9-23 otherwise appear in a judicial proceeding:
9-24 (A) that involves an action taken by an
9-25 administrative agency in a proceeding, including an alternative
9-26 dispute resolution proceeding, in which the counsellor is
9-27 authorized to appear; or
10-1 (B) in which the counsellor determines that
10-2 residential electricity consumers or small commercial electricity
10-3 consumers are in need of representation;
10-4 (5) is entitled to the same access as a party, other
10-5 than commission staff, to records gathered by the commission under
10-6 Section 14.204;
10-7 (6) is entitled to discovery of any nonprivileged
10-8 matter that is relevant to the subject matter of a proceeding or
10-9 petition before the commission;
10-10 (7) may represent an individual residential or small
10-11 commercial consumer with respect to the consumer's disputed
10-12 complaint concerning utility services that is unresolved before the
10-13 commission; and
10-14 (8) may recommend legislation to the legislature that
10-15 the office determines would positively affect the interests of
10-16 residential and small commercial consumers.
10-17 SECTION 7. Section 13.024, Utilities Code, is amended to
10-18 read as follows:
10-19 Sec. 13.024. Prohibited Acts. (a) The counsellor may not[:]
10-20 [(1)] have a direct or indirect interest in a utility
10-21 company regulated under this title[; or]
10-22 [(2) provide legal services directly or indirectly to
10-23 or be employed in any capacity by a utility company regulated under
10-24 this title], its parent, or its subsidiary companies, corporations,
10-25 or cooperatives or a utility competitor, utility supplier, or other
10-26 entity affected in a manner other than by the setting of rates for
10-27 that class of customer.
11-1 (b) The prohibition under Subsection (a) applies during the
11-2 period of the counsellor's service [and until the second
11-3 anniversary of the date the counsellor ceases to serve as
11-4 counsellor.]
11-5 [(c) This section does not prohibit a person from otherwise
11-6 engaging in the private practice of law after the person ceases to
11-7 serve as counsellor].
11-8 SECTION 8. Section 13.043, Utilities Code, is amended to
11-9 read as follows:
11-10 Sec. 13.043. PROHIBITION ON EMPLOYMENT OR REPRESENTATION.
11-11 (a) A former counsel may not make any communication to or
11-12 appearance before the commission or an officer or employee of the
11-13 commission before the second anniversary of the date the person
11-14 ceases to serve as counsel if the communication or appearance is
11-15 made:
11-16 (1) on behalf of another person in connection with any
11-17 matter on which the person seeks official action; or
11-18 (2) with the intent to influence a commission decision
11-19 or action.
11-20 (b) A former counsel may not represent any person or receive
11-21 compensation for services rendered on behalf of any person
11-22 regarding a matter before the commission before the second
11-23 anniversary of the date the person ceases to serve as counsel.
11-24 (c) A person commits an offense if the person violates this
11-25 section. An offense under this subsection is a Class A
11-26 misdemeanor.
11-27 (d) An [The counsellor or an] employee of the office may
12-1 not:
12-2 (1) be employed by a public utility that was in the
12-3 scope of the [counsellor's or] employee's official responsibility
12-4 while the [counsellor or] employee was associated with the office;
12-5 or
12-6 (2) represent a person before the commission or a
12-7 court in a matter:
12-8 (A) in which the [counsellor or] employee was
12-9 personally involved while associated with the office; or
12-10 (B) that was within the [counsellor's or]
12-11 employee's official responsibility while the [counsellor or]
12-12 employee was associated with the office.
12-13 (e) [(b)] The prohibition of Subsection (d)(1) [(a)(1)]
12-14 applies until the[:]
12-15 [(1) second anniversary of the date the counsellor
12-16 ceases to serve as a counsellor; and]
12-17 [(2)] first anniversary of the date the employee's
12-18 employment with the office ceases.
12-19 (f) [(c)] The prohibition of Subsection (d)(2) [(a)(2)]
12-20 applies while an [a counsellor or] employee of the office is
12-21 associated with the office and at any time after.
12-22 (g) For purposes of this section, "person" includes an
12-23 electric cooperative.
12-24 SECTION 9. Subsection (d), Section 14.101, Utilities Code,
12-25 is amended to read as follows:
12-26 (d) This section does not apply to:
12-27 (1) the purchase of a unit of property for
13-1 replacement; [or]
13-2 (2) an addition to the facilities of a public utility
13-3 by construction; or
13-4 (3) transactions that facilitate unbundling, asset
13-5 valuation, minimization of ownership or control of generation
13-6 assets, or other purposes consistent with Chapter 39.
13-7 SECTION 10. Subsections (a) and (b), Section 16.001,
13-8 Utilities Code, are amended to read as follows:
13-9 (a) To defray the expenses incurred in the administration of
13-10 this title, an assessment is imposed on each public utility, retail
13-11 electric provider, and electric cooperative within the jurisdiction
13-12 of the commission that serves the ultimate consumer, including each
13-13 interexchange telecommunications carrier.
13-14 (b) An assessment under this section is equal to one-sixth
13-15 of one percent of the public utility's, retail electric provider's,
13-16 or electric cooperative's gross receipts from rates charged to the
13-17 ultimate consumer in this state.
13-18 SECTION 11. Section 31.002, Utilities Code, is amended to
13-19 read as follows:
13-20 Sec. 31.002. DEFINITIONS. In this subtitle:
13-21 (1) "Affiliated power generation company" means a
13-22 power generation company that is affiliated with or the successor
13-23 in interest of an electric utility certificated to serve an area.
13-24 (2) "Affiliated retail electric provider" means a
13-25 retail electric provider that is affiliated with or the successor
13-26 in interest of an electric utility certificated to serve an area.
13-27 (3) "Aggregation" includes the following:
14-1 (A) the purchase of electricity from a retail
14-2 electric provider, a municipally owned utility, or an electric
14-3 cooperative by an electricity customer for its own use in multiple
14-4 locations; or
14-5 (B) the purchase of electricity by an
14-6 electricity customer as part of a voluntary association of
14-7 electricity customers.
14-8 (4) "Customer choice" means the freedom of a retail
14-9 customer to purchase electric services, either individually or
14-10 through voluntary aggregation with other retail customers, from the
14-11 provider or providers of the customer's choice and to choose among
14-12 various fuel types, energy efficiency programs, and renewable power
14-13 suppliers.
14-14 (5) "Electric Reliability Council of Texas" or "ERCOT"
14-15 means the area in Texas served by electric utilities, municipally
14-16 owned utilities, and electric cooperatives that is not
14-17 synchronously interconnected with electric utilities outside the
14-18 state.
14-19 (6) "Electric utility" means a person or river
14-20 authority that owns or operates for compensation in this state
14-21 equipment or facilities to produce, generate, transmit, distribute,
14-22 sell, or furnish electricity in this state. The term includes a
14-23 lessee, trustee, or receiver of an electric utility and a
14-24 recreational vehicle park owner who does not comply with Subchapter
14-25 C, Chapter 184, with regard to the metered sale of electricity at
14-26 the recreational vehicle park. The term does not include:
14-27 (A) a municipal corporation;
15-1 (B) a qualifying facility;
15-2 (C) a power generation company;
15-3 (D) an exempt wholesale generator;
15-4 (E) [(D)] a power marketer;
15-5 (F) [(E)] a corporation described by Section
15-6 32.053 to the extent the corporation sells electricity exclusively
15-7 at wholesale and not to the ultimate consumer;
15-8 (G) an electric cooperative;
15-9 (H) a retail electric provider;
15-10 (I) this state or an agency of this state; or
15-11 (J) [(F)] a person not otherwise an electric
15-12 utility who:
15-13 (i) furnishes an electric service or
15-14 commodity only to itself, its employees, or its tenants as an
15-15 incident of employment or tenancy, if that service or commodity is
15-16 not resold to or used by others;
15-17 (ii) owns or operates in this state
15-18 equipment or facilities to produce, generate, transmit, distribute,
15-19 sell, or furnish electric energy to an electric utility, if the
15-20 equipment or facilities are used primarily to produce and generate
15-21 electric energy for consumption by that person; or
15-22 (iii) owns or operates in this state a
15-23 recreational vehicle park that provides metered electric service in
15-24 accordance with Subchapter C, Chapter 184.
15-25 (7) [(2)] "Exempt wholesale generator" means a person
15-26 who is engaged directly or indirectly through one or more
15-27 affiliates exclusively in the business of owning or operating all
16-1 or part of a facility for generating electric energy and selling
16-2 electric energy at wholesale and who:
16-3 (A) does not own a facility for the transmission
16-4 of electricity, other than an essential interconnecting
16-5 transmission facility necessary to effect a sale of electric energy
16-6 at wholesale; and
16-7 (B) has:
16-8 (i) applied to the Federal Energy
16-9 Regulatory Commission for a determination under 15 U.S.C. Section
16-10 79z-5a; or
16-11 (ii) registered as an exempt wholesale
16-12 generator as required by Section 35.032.
16-13 (8) "Freeze period" means the period beginning on
16-14 January 1, 1999, and ending on December 31, 2001.
16-15 (9) "Independent system operator" means an entity
16-16 supervising the collective transmission facilities of a power
16-17 region that is charged with nondiscriminatory coordination of
16-18 market transactions, systemwide transmission planning, and network
16-19 reliability.
16-20 (10) "Power generation company" means a person that:
16-21 (A) generates electricity that is intended to be
16-22 sold at wholesale;
16-23 (B) does not own a transmission or distribution
16-24 facility in this state other than an essential interconnecting
16-25 facility, a facility not dedicated to public use, or a facility
16-26 otherwise excluded from the definition of "electric utility" under
16-27 this section; and
17-1 (C) does not have a certificated service area,
17-2 although its affiliated electric utility or transmission and
17-3 distribution utility may have a certificated service area.
17-4 (11) [(3)] "Power marketer" means a person who:
17-5 (A) becomes an owner of electric energy in this
17-6 state for the purpose of selling the electric energy at wholesale;
17-7 (B) does not own generation, transmission, or
17-8 distribution facilities in this state;
17-9 (C) does not have a certificated service area;
17-10 and
17-11 (D) has:
17-12 (i) been granted authority by the Federal
17-13 Energy Regulatory Commission to sell electric energy at
17-14 market-based rates; or
17-15 (ii) registered as a power marketer under
17-16 Section 35.032.
17-17 (12) "Power region" means a contiguous geographical
17-18 area which is a distinct region of the North American Electric
17-19 Reliability Council.
17-20 (13) [(4)] "Qualifying cogenerator" and "qualifying
17-21 small power producer" have the meanings assigned those terms by 16
17-22 U.S.C. Sections 796(18)(C) and 796(17)(D). A qualifying
17-23 cogenerator that provides electricity to the purchaser of the
17-24 cogenerator's thermal output is not for that reason considered to
17-25 be a retail electric provider or a power generation company.
17-26 (14) [(5)] "Qualifying facility" means a qualifying
17-27 cogenerator or qualifying small power producer.
18-1 (15) [(6)] "Rate" includes a compensation, tariff,
18-2 charge, fare, toll, rental, or classification that is directly or
18-3 indirectly demanded, observed, charged, or collected by an electric
18-4 utility for a service, product, or commodity described in the
18-5 definition of electric utility in this section and a rule,
18-6 practice, or contract affecting the compensation, tariff, charge,
18-7 fare, toll, rental, or classification that must be approved by a
18-8 regulatory authority.
18-9 (16) "Retail customer" means the separately metered
18-10 end-use customer who purchases and ultimately consumes electricity.
18-11 (17) "Retail electric provider" means a person that
18-12 sells electric energy to retail customers in this state. A retail
18-13 electric provider may not own or operate generation assets.
18-14 (18) "Separately metered" means metered by an
18-15 individual meter that is used to measure electric energy
18-16 consumption by a retail customer and for which the customer is
18-17 directly billed by a utility, retail electric provider, electric
18-18 cooperative, or municipally owned utility.
18-19 (19) "Transmission and distribution utility" means a
18-20 person or river authority that owns or operates for compensation in
18-21 this state equipment or facilities to transmit or distribute
18-22 electricity, except for facilities necessary to interconnect a
18-23 generation facility with the transmission or distribution network,
18-24 a facility not dedicated to public use, or a facility otherwise
18-25 excluded from the definition of "electric utility" under this
18-26 section, in a qualifying power region certified under Section
18-27 39.152, but does not include a municipally owned utility or an
19-1 electric cooperative.
19-2 (20) [(7)] "Transmission service" includes
19-3 construction or enlargement of facilities, transmission over
19-4 distribution facilities, control area services, scheduling
19-5 resources, regulation services, reactive power support, voltage
19-6 control, provision of operating reserves, and any other associated
19-7 electrical service the commission determines appropriate, except
19-8 that, on and after the implementation of customer choice, control
19-9 area services, scheduling resources, regulation services, provision
19-10 of operating reserves, and reactive power, voltage control, and
19-11 other services provided by generation resources are not
19-12 "transmission service."[.]
19-13 SECTION 12. Subchapter A, Chapter 32, Utilities Code, is
19-14 amended by adding Section 32.0015 to read as follows:
19-15 Sec. 32.0015. REGULATION OF SUCCESSOR ELECTRIC UTILITY OR
19-16 ELECTRIC COOPERATIVE. If an electric utility purchases, acquires,
19-17 merges, or consolidates with or acquires 50 percent or more of the
19-18 stock of an electric utility or electric cooperative, the
19-19 commission shall regulate the successor electric utility or
19-20 electric cooperative in the same manner that the commission would
19-21 regulate the entity that was subject to the stricter regulation
19-22 before the purchase, acquisition, merger, or consolidation.
19-23 SECTION 13. Sections 32.051 and 32.052, Utilities Code, are
19-24 amended to read as follows:
19-25 Sec. 32.051. Exemption of River Authority From Wholesale
19-26 Rate Regulation. Notwithstanding any other provision of this
19-27 title, the commission may not directly or indirectly regulate
20-1 revenue requirements, rates, fuel costs, fuel charges, or fuel
20-2 acquisitions that are related to the generation and sale of
20-3 electricity at wholesale, and not to ultimate consumers, by a river
20-4 authority operating a steam generating plant on or before
20-5 January 1, 1999.
20-6 Sec. 32.052. Ability of Certain River Authorities to
20-7 Construct Improvements. A river authority operating a steam
20-8 generating plant on or before January 1, 1999, may acquire,
20-9 finance, construct, rebuild, repower, and use new or existing power
20-10 plants, equipment, transmission lines, or other assets to sell
20-11 electricity exclusively at wholesale to:
20-12 (1) a purchaser in San Saba, Llano, Burnet, Travis,
20-13 Bastrop, Blanco, Colorado, or Fayette County; or
20-14 (2) a purchaser in an area served by the river
20-15 authority on January 1, 1975.
20-16 SECTION 14. Section 32.053, Utilities Code, is amended by
20-17 amending Subsections (b) and (f) and adding Subsections (g) and (h)
20-18 to read as follows:
20-19 (b) Notwithstanding a river authority's enabling legislation
20-20 or Chapter 245, Acts of the 67th Legislature, Regular Session, 1981
20-21 (Article 717p, Vernon's Texas Civil Statutes), a corporation may:
20-22 (1) acquire, finance, construct, rebuild, repower,
20-23 operate, or sell a facility directly related to the generation of
20-24 electricity; [and]
20-25 (2) sell, at wholesale only, the output of the
20-26 facility to a purchaser, other than an ultimate consumer, at any
20-27 location in this state; and
21-1 (3) purchase and sell electricity, at wholesale only,
21-2 to a purchaser, other than an ultimate consumer, at any location in
21-3 this state.
21-4 (f) The proceeds from the sale of bonds or other obligations
21-5 the interest on which is exempt from taxation and that are issued
21-6 by a corporation or river authority subject to this section, other
21-7 than a bond or obligation available to an investor-owned utility or
21-8 exempt wholesale generator, may not be used by the corporation[,
21-9 and may not have been used,] to finance the construction or
21-10 acquisition of or the rebuilding or repowering of a facility for
21-11 the generation of electricity by the corporation.
21-12 (g) Notwithstanding any other law, the board of directors of
21-13 a river authority may sell, lease, loan, or otherwise transfer
21-14 some, all, or substantially all of the electric generation property
21-15 of the river authority to a nonprofit corporation authorized under
21-16 this section or Chapter 245, Acts of the 67th Legislature, Regular
21-17 Session, 1981 (Article 717p, Vernon's Texas Civil Statutes). The
21-18 property transfer shall be made under terms and conditions approved
21-19 by the board of directors of the river authority.
21-20 (h) Subsections (a)-(f) do not apply to a corporation
21-21 created under Chapter 245, Acts of the 67th Legislature, Regular
21-22 Session, 1981 (Article 717p, Vernon's Texas Civil Statutes), to
21-23 serve an area described in Section 32.052.
21-24 SECTION 15. Subchapter A, Chapter 33, Utilities Code, is
21-25 amended by adding Section 33.008 to read as follows:
21-26 Sec. 33.008. FRANCHISE CHARGES. (a) Following the end of
21-27 the freeze period for a municipality that has been served by an
22-1 electric utility, and following the date a municipally owned
22-2 utility or an electric cooperative has implemented customer choice
22-3 for a municipality that has been served by that municipally owned
22-4 utility or electric cooperative, a municipality may impose on an
22-5 electric utility, transmission and distribution utility,
22-6 municipally owned utility, or electric cooperative, as appropriate,
22-7 that provides distribution service within the municipality a
22-8 reasonable charge as specified in Subsection (b) for the use of a
22-9 municipal street, alley, or public way to deliver electricity to a
22-10 retail customer. A municipality may not impose a charge on:
22-11 (1) an electric utility, or transmission and
22-12 distribution utility, municipally owned utility, or electric
22-13 cooperative for electric service provided outside the municipality;
22-14 (2) a qualifying facility;
22-15 (3) an exempt wholesale generator;
22-16 (4) a power marketer;
22-17 (5) a retail electric provider;
22-18 (6) a power generation company;
22-19 (7) a person that generates electricity on and after
22-20 January 1, 2002; or
22-21 (8) an aggregator, as that term is defined by Section
22-22 39.353.
22-23 (b) If a municipality collected a charge or fee for a
22-24 franchise to use a municipal street, alley, or public way from an
22-25 electric utility, a municipally owned utility, or an electric
22-26 cooperative before the end of the freeze period, the municipality,
22-27 after the end of the freeze period or after implementation of
23-1 customer choice by the municipally owned utility or electric
23-2 cooperative, as appropriate, is entitled to collect from each
23-3 electric utility, transmission and distribution utility,
23-4 municipally owned utility, or electric cooperative that uses the
23-5 municipality's streets, alleys, or public ways to provide
23-6 distribution service a charge based on each kilowatt hour of
23-7 electricity delivered by the utility to each retail customer whose
23-8 consuming facility's point of delivery is located within the
23-9 municipality's boundaries. The charge imposed shall be equal to
23-10 the total electric franchise fee revenue due the municipality from
23-11 electric utilities, municipally owned utilities, or electric
23-12 cooperatives, as appropriate, for calendar year 1998 divided by the
23-13 total kilowatt hours delivered during 1998 by the applicable
23-14 electric utility, municipally owned utility, or electric
23-15 cooperative to retail customers whose consuming facilities' points
23-16 of delivery were located within the municipality's boundaries. The
23-17 compensation a municipality may collect from each electric utility,
23-18 transmission and distribution utility, municipally owned utility,
23-19 or electric cooperative providing distribution service shall be
23-20 equal to the charge per kilowatt-hour determined for 1998
23-21 multiplied times the number of kilowatt-hours delivered within the
23-22 municipality's boundaries.
23-23 (c) The municipal franchise charges authorized by this
23-24 section shall be considered a reasonable and necessary operating
23-25 expense of each electric utility, transmission and distribution
23-26 utility, municipally owned utility, or electric cooperative that is
23-27 subject to a charge under this section. The charge shall be
24-1 included in the nonbypassable delivery charges that a customer's
24-2 retail electric provider must pay under Section 39.107 to the
24-3 utility serving the customer.
24-4 (d) The municipal franchise charges authorized by this
24-5 section are in lieu of any franchise charges or fees payable under
24-6 a franchise agreement in effect before the expiration of the freeze
24-7 period or, as appropriate, before the implementation of customer
24-8 choice by a municipally owned utility or electric cooperative.
24-9 Except as otherwise provided by this section, this section does not
24-10 affect a provision of a franchise agreement in effect before the
24-11 end of the freeze period or, as appropriate, before the
24-12 implementation of customer choice by a municipally owned utility or
24-13 electric cooperative.
24-14 (e) A municipality may conduct an audit or other inquiry or
24-15 may pursue any cause of action in relation to an electric
24-16 utility's, transmission and distribution utility's, municipally
24-17 owned utility's, or electric cooperative's payment of charges
24-18 authorized by this section only if such audit, inquiry, or pursuit
24-19 of a cause of action concerns a payment made less than two years
24-20 before commencement of such audit, inquiry, or pursuit of a cause
24-21 of action, provided, however, that this subsection does not apply
24-22 to an audit, inquiry, or cause of action commenced before September
24-23 1, 1999. An electric utility, transmission and distribution
24-24 utility, municipally owned utility, or electric cooperative shall,
24-25 on request of the municipality in connection with a municipal
24-26 audit, identify the service provider and the type of service
24-27 delivered for any service in addition to electricity delivered
25-1 directly to retail customers through the utility's
25-2 electricity-conducting facilities that are located in the
25-3 municipality's streets, alleys, or public ways and for which the
25-4 utility receives compensation.
25-5 (f) Notwithstanding any other provision of this section, on
25-6 the expiration of a franchise agreement existing on September 1,
25-7 1999, an electric utility, transmission and distribution utility,
25-8 municipally owned utility, or electric cooperative and a
25-9 municipality may mutually agree to a different level of
25-10 compensation or to a different method for determining the amount
25-11 the municipality may charge for the use of a municipal street,
25-12 alley, or public way in connection with the delivery of electricity
25-13 at retail within the municipality.
25-14 (g) After the end of the freeze period or after
25-15 implementation of customer choice by the municipally owned utility
25-16 or electric cooperative, as appropriate, a newly incorporated
25-17 municipality or a municipality that has not previously collected
25-18 compensation for the delivery of electricity at retail within the
25-19 municipality may adopt and collect compensation based on the same
25-20 rate per kilowatt hour that is collected by any other municipality
25-21 in the same county that is served by the same electric utility,
25-22 transmission and distribution utility, municipally owned utility,
25-23 or electric cooperative.
25-24 (h) In this section, "distribution service" means the
25-25 delivery of electricity to all retail customers.
25-26 SECTION 16. Section 35.001, Utilities Code, is amended to
25-27 read as follows:
26-1 Sec. 35.001. Definition. In this subchapter, "electric
26-2 utility" includes a municipally owned utility and an electric
26-3 cooperative.
26-4 SECTION 17. Section 35.004, Utilities Code, is amended to
26-5 read as follows:
26-6 Sec. 35.004. PROVISION OF TRANSMISSION SERVICE. (a) An
26-7 electric utility or transmission and distribution utility that owns
26-8 or operates transmission facilities shall provide wholesale
26-9 transmission service at rates and terms, including terms of access,
26-10 that are comparable to the rates and terms of the utility's own use
26-11 of its system.
26-12 (b) The commission shall ensure that an electric utility or
26-13 transmission and distribution utility provides nondiscriminatory
26-14 access to wholesale transmission service for qualifying facilities,
26-15 exempt wholesale generators, power marketers, power generation
26-16 companies, retail electric providers, and other electric utilities
26-17 or transmission and distribution utilities.
26-18 (c) When an electric utility, electric cooperative, or
26-19 transmission and distribution utility provides wholesale
26-20 transmission service within ERCOT at the request of a third party,
26-21 the commission shall ensure that the utility recovers the utility's
26-22 reasonable costs in providing wholesale transmission services
26-23 necessary for the transaction from the entity for which the
26-24 transmission is provided so that the utility's other customers do
26-25 not bear the costs of the service.
26-26 (d) The commission shall price wholesale transmission
26-27 services within ERCOT based on the postage stamp method of pricing
27-1 under which a transmission-owning utility's rate is based on the
27-2 ERCOT utilities' combined annual costs of transmission divided by
27-3 the total demand placed on the combined transmission systems of all
27-4 such transmission-owning utilities within a power region. An
27-5 electric utility subject to the freeze period imposed by Section
27-6 39.052 may treat transmission costs in excess of transmission
27-7 revenues during the freeze period as an expense for purposes of
27-8 determining annual costs in the annual report filed under Section
27-9 39.257. Notwithstanding Section 36.201, the commission may approve
27-10 wholesale rates that may be periodically adjusted to ensure timely
27-11 recovery of transmission investment.
27-12 (e) The commission shall ensure that ancillary services
27-13 necessary to facilitate the transmission of electric energy are
27-14 available at reasonable prices with terms and conditions that are
27-15 not unreasonably preferential, prejudicial, discriminatory,
27-16 predatory, or anticompetitive. In this subsection, "ancillary
27-17 services" means services necessary to facilitate the transmission
27-18 of electric energy including load following, standby power, backup
27-19 power, reactive power, and any other services as the commission may
27-20 determine by rule. On the introduction of customer choice in the
27-21 ERCOT power region, acquisition of generation-related ancillary
27-22 services on a nondiscriminatory basis by the independent
27-23 organization in ERCOT on behalf of entities selling electricity at
27-24 retail shall be deemed to meet the requirements of this subsection.
27-25 SECTION 18. Subsection (b), Section 35.005, Utilities Code,
27-26 is amended to read as follows:
27-27 (b) The commission may require transmission service at
28-1 wholesale, including the construction or enlargement of a
28-2 facility[, in a proceeding not related to approval of an integrated
28-3 resource plan].
28-4 SECTION 19. Section 35.033, Utilities Code, is amended to
28-5 read as follows:
28-6 Sec. 35.033. Affiliate Wholesale Provider. An affiliate of
28-7 an electric utility may be an exempt wholesale generator or power
28-8 marketer and may sell electric energy to its affiliated electric
28-9 utility in accordance with [Chapter 34 and other] laws governing
28-10 wholesale sales of electric energy.
28-11 SECTION 20. Section 35.034, Utilities Code, is amended by
28-12 adding Subsection (c) to read as follows:
28-13 (c) For purposes of this section, "electric utility" does
28-14 not include a river authority.
28-15 SECTION 21. Section 35.035, Utilities Code, is amended by
28-16 adding Subsection (d) to read as follows:
28-17 (d) For purposes of this section, "electric utility" does
28-18 not include a river authority.
28-19 SECTION 22. Subchapter C, Chapter 35, Utilities Code, is
28-20 amended by adding Section 35.067 to read as follows:
28-21 Sec. 35.067. APPLICATION FOR RECERTIFICATION. (a) An
28-22 electric cooperative or a qualifying facility may submit to the
28-23 commission for recertification an agreement previously certified
28-24 under Section 35.062 or a predecessor statute if the agreement:
28-25 (1) permits recertification; or
28-26 (2) the qualifying facility agrees to submission.
28-27 (b) The commission may deny recertification if the
29-1 commission determines that a material condition or fact on which
29-2 the commission based the original certification, including the
29-3 facility's status as a qualifying facility under 16 U.S.C. 796(18)
29-4 or as determined by the Federal Energy Regulatory Commission, has
29-5 changed or is no longer true.
29-6 SECTION 23. Chapter 35, Utilities Code, is amended by adding
29-7 Subchapter D to read as follows:
29-8 SUBCHAPTER D. STATE AUTHORITY TO SELL OR CONVEY POWER
29-9 Sec. 35.101. DEFINITIONS. In this subchapter:
29-10 (1) "Commissioner" means the commissioner of the
29-11 General Land Office.
29-12 (2) "Public retail customer" means a retail customer
29-13 that is an agency of this state, an institution of higher
29-14 education, a public school district, or a political subdivision of
29-15 this state.
29-16 Sec. 35.102. STATE AUTHORITY TO SELL OR CONVEY POWER. The
29-17 commissioner, acting on behalf of the state, may sell or otherwise
29-18 convey power directly to a public retail customer regardless of
29-19 whether the public retail customer is also classified as a
29-20 wholesale customer under other provisions of this title.
29-21 Sec. 35.103. ACCESS TO TRANSMISSION AND DISTRIBUTION
29-22 SYSTEMS; RATES. (a) Except as provided in Section 35.104, the
29-23 state is entitled to have access to all transmission and
29-24 distribution systems of all electric utilities, transmission and
29-25 distribution utilities, municipally owned utilities, and electric
29-26 cooperatives that serve public retail customers.
29-27 (b) An entity described by Subsection (a) shall provide any
30-1 utility service, including transmission, distribution, and other
30-2 services, which must include any applicable stranded costs or
30-3 system benefit fees, to the state at the lowest applicable rate
30-4 charged for similar service to other customers.
30-5 Sec. 35.104. LIMIT IN CERTAIN AREAS. Sections 35.102 and
30-6 35.103 do not apply to the rates, retail service area, facilities,
30-7 or public retail customers of a municipally owned electric utility
30-8 that has not adopted customer choice or an electric cooperative
30-9 that has not adopted customer choice. In a certificated service
30-10 area of an electric utility in which customer choice has not been
30-11 introduced, the state may not engage in retail transactions that
30-12 exceed 2.5 percent of a retail electric utility's total retail
30-13 load.
30-14 Sec. 35.105. WHOLESALE CUSTOMERS. This subchapter does not
30-15 prevent the commissioner, acting on behalf of this state, from
30-16 registering as a power marketer.
30-17 SECTION 24. Section 36.008, Utilities Code, is amended to
30-18 read as follows:
30-19 Sec. 36.008. STATE TRANSMISSION SYSTEM. In establishing
30-20 rates for an electric utility [not required to file an integrated
30-21 resource plan], the commission may review the state's transmission
30-22 system and make recommendations to the utility on the need to build
30-23 new power lines, upgrade power lines, and make other necessary
30-24 improvements and additions.
30-25 SECTION 25. Section 36.052, Utilities Code, is amended to
30-26 read as follows:
30-27 Sec. 36.052. ESTABLISHING REASONABLE RETURN. In
31-1 establishing a reasonable return on invested capital, the
31-2 regulatory authority shall consider applicable factors, including:
31-3 (1) [the efforts of the electric utility to comply
31-4 with its most recently approved integrated resource plan;]
31-5 [(2)] the efforts and achievements of the utility in
31-6 conserving resources;
31-7 (2) [(3)] the quality of the utility's services;
31-8 (3) [(4)] the efficiency of the utility's operations;
31-9 and
31-10 (4) [(5)] the quality of the utility's management.
31-11 SECTION 26. Subsection (d), Section 36.058, Utilities Code,
31-12 is amended to read as follows:
31-13 (d) In making a finding regarding an affiliate transaction,
31-14 [including an affiliate transaction subject to Chapter 34,] the
31-15 regulatory authority shall:
31-16 (1) determine the extent to which the conditions and
31-17 circumstances of that transaction are reasonably comparable
31-18 relative to quantity, terms, date of contract, and place of
31-19 delivery; and
31-20 (2) allow for appropriate differences based on that
31-21 determination.
31-22 SECTION 27. Section 36.201, Utilities Code, is amended to
31-23 read as follows:
31-24 Sec. 36.201. AUTOMATIC ADJUSTMENT FOR CHANGES IN COSTS.
31-25 Except as permitted by [Chapter 34 or] Section 36.204, the
31-26 commission may not establish a rate or tariff that authorizes an
31-27 electric utility to automatically adjust and pass through to the
32-1 utility's customers a change in the utility's fuel or other costs.
32-2 SECTION 28. Section 36.204, Utilities Code, is amended to
32-3 read as follows:
32-4 Sec. 36.204. COST RECOVERY AND INCENTIVES. In establishing
32-5 rates for an electric utility [not required to file an integrated
32-6 resource plan], the commission may:
32-7 (1) allow timely recovery of the reasonable costs of
32-8 conservation, load management, and purchased power, notwithstanding
32-9 Section 36.201; and
32-10 (2) authorize additional incentives for conservation,
32-11 load management, purchased power, and renewable resources.
32-12 SECTION 29. Section 36.207, Utilities Code, is amended to
32-13 read as follows:
32-14 Sec. 36.207. USE OF MARK-UPS. Any mark-ups approved under
32-15 [Chapter 34 or] Section 36.206 are an exceptional form of rate
32-16 relief that the electric utility may recover from ratepayers only
32-17 on a finding by the commission that the relief is necessary to
32-18 maintain the utility's financial integrity.
32-19 SECTION 30. Section 37.001, Utilities Code, is amended to
32-20 read as follows:
32-21 Sec. 37.001. DEFINITIONS. In this chapter:
32-22 (1) "Certificate" means a certificate of convenience
32-23 and necessity.
32-24 (2) "Electric utility" includes an electric
32-25 cooperative.
32-26 (3) "Retail electric utility" means a person,
32-27 political subdivision, electric cooperative, or agency that
33-1 operates, maintains, or controls in this state a facility to
33-2 provide retail electric utility service. The term does not include
33-3 a corporation described by Section 32.053 to the extent that the
33-4 corporation sells electricity exclusively at wholesale and not to
33-5 the ultimate consumer. A qualifying cogenerator that sells
33-6 electric energy at retail to the sole purchaser of the
33-7 cogenerator's thermal output under Sections 35.061 and 36.007 is
33-8 not for that reason considered to be a retail electric utility.
33-9 The owner or operator of a qualifying cogeneration facility who was
33-10 issued the necessary environmental permits from the Texas Natural
33-11 Resource Conservation Commission after January 1, 1998, and who
33-12 commenced construction of such qualifying facility before July 1,
33-13 1998, may provide electricity to the purchasers of the thermal
33-14 output of that qualifying facility and shall not for that reason be
33-15 considered an electric utility or a retail electric utility,
33-16 provided that the purchasers of the thermal output are owners of
33-17 manufacturing or process operation facilities that are located on a
33-18 site entirely owned before September 1987 by one owner who retained
33-19 ownership after September 1987 of some portion of the facilities
33-20 and that those facilities now share some integrated operations,
33-21 such as the provision of services and raw materials.
33-22 SECTION 31. Section 37.051, Utilities Code, is amended by
33-23 adding Subsection (c) to read as follows:
33-24 (c) Notwithstanding any other provision of this chapter,
33-25 including Subsection (a), an electric cooperative is not required
33-26 to obtain a certificate of public convenience and necessity for the
33-27 construction, installation, operation, or extension of any
34-1 generating facilities or necessary interconnection facilities.
34-2 SECTION 32. Section 37.054(b), Utilities Code, is amended to
34-3 read as follows:
34-4 (b) A person or electric cooperative interested in the
34-5 application may intervene at the hearing.
34-6 SECTION 33. Subchapter B, Chapter 37, Utilities Code, is
34-7 amended by adding Sections 37.060 and 37.061 to read as follows:
34-8 Sec. 37.060. DIVISION OF MULTIPLY CERTIFICATED SERVICE
34-9 AREAS. (a) This subsection and Subsections (b)-(g) apply only to
34-10 areas in which each retail electric utility that is authorized to
34-11 provide retail electric utility service to the area is providing
34-12 customer choice. For purposes of this subsection, an electric
34-13 cooperative or a municipally owned electric utility shall be deemed
34-14 to be providing customer choice if it has approved a resolution
34-15 adopting customer choice that is effective on January 1, 2002, or
34-16 effective within 24 months after the date of the resolution
34-17 adopting customer choice. All other retail electric utilities
34-18 shall be deemed to be providing customer choice if customer choice
34-19 will be allowed for customers of the retail electric utility on
34-20 January 1, 2002. In areas in which each certificated retail
34-21 electric utility is providing customer choice, the commission, if
34-22 requested by a retail electric utility, shall examine all areas
34-23 within the service area of the retail electric utility making the
34-24 request that are also certificated to one or more other retail
34-25 electric utilities and, after notice and hearing, shall amend the
34-26 retail electric utilities' certificates so that only one retail
34-27 electric utility is certificated to provide distribution services
35-1 in any such area. Only retail electric utilities certificated to
35-2 serve an area on June 1, 1999, may continue to serve the area or
35-3 portion of the area under an amended certificate issued under this
35-4 subsection.
35-5 (b) This section does not apply in any area in which a
35-6 municipally owned utility is certificated to provide retail
35-7 electric utility service if the municipally owned utility serving
35-8 the area files with the commission by February 1, 2000, a request
35-9 that areas within the certificated service area of the municipally
35-10 owned utility remain as presently certificated.
35-11 (c) The commission shall enter its order dividing multiply
35-12 certificated areas within one year of the date a request is
35-13 received.
35-14 (d) In amending certificates under this section, the
35-15 commission shall take into consideration the factors prescribed by
35-16 Section 37.056.
35-17 (e) Notwithstanding Section 37.059, the commission shall
35-18 revoke certificates to the extent necessary to achieve the division
35-19 of retail electric service areas as provided by this section.
35-20 (f) Unless otherwise agreed by the affected retail electric
35-21 utilities, each retail electric utility shall be allowed to
35-22 continue to provide service to the location of
35-23 electricity-consuming facilities it is serving on the date an
35-24 application for division of the affected multiply certificated
35-25 service areas is filed. No customer located within the affected
35-26 multiply certificated service areas shall be permitted to switch
35-27 from one retail electric utility to another while an application
36-1 for division of the affected multiply certificated service areas is
36-2 pending.
36-3 (g) If on June 1, 1999, retail service is being provided in
36-4 an area by another retail electric utility with the written consent
36-5 of the retail electric utility certificated to serve the area, that
36-6 consent shall be filed with the commission. On notification of
36-7 that consent and a request by an affected retail electric utility
36-8 to amend the relevant certificates, the commission may grant an
36-9 exception or amend a retail electric utility's certificate. This
36-10 provision shall not be construed to limit the commission's
36-11 authority to grant exceptions or to amend a retail electric
36-12 utility's certificate, upon request and notification, for areas to
36-13 which retail service is being provided pursuant to written consent
36-14 granted after June 1, 1999.
36-15 (h) The commission may not grant an additional retail
36-16 electric utility certificate to serve an area if the effect of the
36-17 grant would cause the area to be multiply certificated unless the
36-18 commission finds that the certificate holders are not providing
36-19 service to any part of the area for which a certificate is sought
36-20 and are not capable of providing adequate service to the area in
36-21 accordance with applicable standards. However, neither this
36-22 subsection nor the deadline of June 1, 1999, provided by Subsection
36-23 (a) shall apply to any application for multiple certification filed
36-24 with the commission on or before February 1, 1999, and those
36-25 applications may be processed in accordance with applicable law in
36-26 effect on the date the application was filed. Applications for
36-27 multiple certification filed with the commission on or before
37-1 February 1, 1999, may not be amended to expand the area for which a
37-2 certificate is sought except for contiguous areas within
37-3 municipalities that provide consent, as required by Section
37-4 37.053(b), not later than June 1, 1999.
37-5 (i) Notwithstanding any other provision of this section, if
37-6 requested by a municipally owned utility, the commission shall
37-7 examine all areas within the municipally owned utility's service
37-8 area that are also certificated to one or more other retail
37-9 electric utilities and, after notice and hearing, may amend the
37-10 retail electric utilities' certificates so that only one retail
37-11 electric utility is certificated to provide distribution services
37-12 in the area, provided that:
37-13 (1) the application is filed with the commission
37-14 within 12 months of the effective date of this provision and is
37-15 limited to single certification of the area within the
37-16 municipality's boundaries as of February 1, 1999;
37-17 (2) the commission preserves the right of an electric
37-18 utility or an electric cooperative to serve its existing customers,
37-19 including any property owned or leased by any customer; and
37-20 (3) the municipality is a member city of a municipal
37-21 power agency, as that term is used in Section 40.059.
37-22 Sec. 37.061. EXISTING SERVICE AREA AGREEMENTS.
37-23 (a) Notwithstanding any other provision of this title, the
37-24 commission shall allow a municipally owned utility to amend the
37-25 service area boundaries of its certificate if:
37-26 (1) the municipally owned utility was the holder of a
37-27 certificate as of January 1, 1999;
38-1 (2) the municipally owned utility has an agreement
38-2 existing before January 1, 1999, with a public utility serving the
38-3 area that the public utility will not contest an application to
38-4 amend the certificate to add municipal territory; and
38-5 (3) the area for which a certificate is requested is
38-6 not certificated to a retail electric utility that is not a party
38-7 to the agreement and that has not consented in writing to
38-8 certification of the area to the municipality.
38-9 (b) The commission may not amend the certificate of the
38-10 public utility serving the affected area based on the granting of a
38-11 certificate to the municipally owned utility.
38-12 SECTION 34. Subsection (a), Section 37.101, Utilities Code,
38-13 is amended to read as follows:
38-14 (a) If an area is or will be included within a municipality
38-15 as the result of annexation, incorporation, or another reason, each
38-16 electric utility and each electric cooperative that holds or is
38-17 entitled to hold a certificate under this title to provide service
38-18 or operate a facility in the area before the inclusion has the
38-19 right to continue to provide the service or operate the facility
38-20 and extend service within the utility's or cooperative's
38-21 certificated area in the annexed or incorporated area under the
38-22 rights granted by the certificate and this title.
38-23 SECTION 35. Section 38.001, Utilities Code, is amended to
38-24 read as follows:
38-25 Sec. 38.001. GENERAL STANDARD. An electric utility and an
38-26 electric cooperative shall furnish service, instrumentalities, and
38-27 facilities that are safe, adequate, efficient, and reasonable.
39-1 SECTION 36. Section 38.004, Utilities Code, is amended to
39-2 read as follows:
39-3 Sec. 38.004. MINIMUM CLEARANCE STANDARD. Notwithstanding
39-4 any other law, a transmission or distribution line owned by an
39-5 electric utility or an electric cooperative must be constructed,
39-6 operated, and maintained, as to clearances, in the manner described
39-7 by the National Electrical Safety Code Standard ANSI (c)(2), as
39-8 adopted by the American National Safety Institute and in effect at
39-9 the time of construction.
39-10 SECTION 37. Subchapter A, Chapter 38, Utilities Code, is
39-11 amended by adding Section 38.005 to read as follows:
39-12 Sec. 38.005. ELECTRIC SERVICE RELIABILITY MEASURES.
39-13 (a) The commission shall implement service quality and reliability
39-14 standards relating to the delivery of electricity to retail
39-15 customers by electric utilities and transmission and distribution
39-16 utilities. The commission by rule shall develop reliability
39-17 standards, including:
39-18 (1) the system-average interruption frequency index
39-19 (SAIFI);
39-20 (2) the system-average interruption duration index
39-21 (SAIDI);
39-22 (3) achievement of average response time for customer
39-23 service requests or inquiries; or
39-24 (4) other standards that the commission finds
39-25 reasonable and appropriate.
39-26 (b) The commission shall take appropriate enforcement action
39-27 under this section, including but not limited to action against a
40-1 utility if any feeder with 10 or more customers appears on the
40-2 utility's list of worst 10 percent performing feeders for any two
40-3 consecutive years or has had a SAIDI or SAIFI average that is more
40-4 than 300 percent greater than the system average of all feeders
40-5 during any two-year period, beginning in the year 2000.
40-6 (c) The standards implemented under Subsection (a) shall
40-7 require each electric utility and transmission and distribution
40-8 utility subject to this section to maintain adequately trained and
40-9 experienced personnel throughout the utility's service area so that
40-10 the utility is able to fully and adequately comply with the
40-11 appropriate service quality and reliability standards.
40-12 (d) The standards shall ensure that electric utilities do
40-13 not neglect any local neighborhood or geographic area, including
40-14 rural areas, communities of less than 1,000 persons, and low-income
40-15 areas, with regard to system reliability.
40-16 (e) The commission may require each electric utility and
40-17 transmission and distribution utility to supply data to assist the
40-18 commission in developing the reliability standards.
40-19 (f) Each electric utility, transmission and distribution
40-20 utility, electric cooperative, municipally owned utility, and
40-21 generation provider shall be obligated to comply with any
40-22 operational criteria duly established by the independent
40-23 organization as defined by Section 39.151 or adopted by the
40-24 commission.
40-25 SECTION 38. Section 38.022, Utilities Code, is amended to
40-26 read as follows:
40-27 Sec. 38.022. DISCRIMINATION AND RESTRICTION ON COMPETITION.
41-1 An electric utility may not:
41-2 (1) discriminate against a person or electric
41-3 cooperative who sells or leases equipment or performs services in
41-4 competition with the electric utility; or
41-5 (2) engage in a practice that tends to restrict or
41-6 impair that competition.
41-7 SECTION 39. Section 38.071, Utilities Code, is amended to
41-8 read as follows:
41-9 Sec. 38.071. Improvements in Service; Interconnecting
41-10 Service. The commission, after notice and hearing, may:
41-11 (1) order an electric utility to provide specified
41-12 improvements in its service in a specified area if:
41-13 (A) service in the area is inadequate or
41-14 substantially inferior to service in a comparable area; and
41-15 (B) requiring the company to provide the
41-16 improved service is reasonable; or
41-17 (2) order two or more electric utilities or electric
41-18 cooperatives to establish specified facilities for interconnecting
41-19 service.
41-20 SECTION 40. Subtitle B, Title 2, Utilities Code, is amended
41-21 by adding Chapters 39, 40, and 41 to read as follows:
41-22 CHAPTER 39. RESTRUCTURING OF ELECTRIC UTILITY INDUSTRY
41-23 SUBCHAPTER A. GENERAL PROVISIONS
41-24 Sec. 39.001. LEGISLATIVE POLICY AND PURPOSE. (a) The
41-25 legislature finds that the production and sale of electricity is
41-26 not a monopoly warranting regulation of rates, operations, and
41-27 services and that the public interest in competitive electric
42-1 markets requires that, except for transmission and distribution
42-2 services and for the recovery of stranded costs, electric services
42-3 and their prices should be determined by customer choices and the
42-4 normal forces of competition. As a result, this chapter is enacted
42-5 to protect the public interest during the transition to and in the
42-6 establishment of a fully competitive electric power industry.
42-7 (b) The legislature finds that it is in the public interest
42-8 to:
42-9 (1) implement on January 1, 2002, a competitive retail
42-10 electric market that allows each retail customer to choose the
42-11 customer's provider of electricity and that encourages full and
42-12 fair competition among all providers of electricity;
42-13 (2) allow utilities with uneconomic generation-related
42-14 assets and purchased power contracts to recover the reasonable
42-15 excess costs over market of those assets and purchased power
42-16 contracts;
42-17 (3) educate utility customers about anticipated
42-18 changes in the provision of retail electric service to ensure that
42-19 the benefits of the competitive market reach all customers; and
42-20 (4) protect the competitive process in a manner that
42-21 ensures the confidentiality of competitively sensitive information
42-22 during the transition to a competitive market and after the
42-23 commencement of customer choice.
42-24 (c) Regulatory authorities, excluding the governing body of
42-25 a municipally owned electric utility that has not opted for
42-26 customer choice or the body vested with power to manage and operate
42-27 a municipally owned electric utility that has not opted for
43-1 customer choice, may not make rules or issue orders regulating
43-2 competitive electric services, prices, or competitors or
43-3 restricting or conditioning competition except as authorized in
43-4 this title and may not discriminate against any participant or type
43-5 of participant during the transition to a competitive market and in
43-6 the competitive market.
43-7 (d) Regulatory authorities, excluding the governing body of
43-8 a municipally owned electric utility that has not opted for
43-9 customer choice or the body vested with power to manage and operate
43-10 a municipally owned electric utility that has not opted for
43-11 customer choice, shall authorize or order competitive rather than
43-12 regulatory methods to achieve the goals of this chapter to the
43-13 greatest extent feasible and shall adopt rules and issue orders
43-14 that are both practical and limited so as to impose the least
43-15 impact on competition.
43-16 (e) Judicial review of competition rules adopted by the
43-17 commission shall be conducted under Chapter 2001, Government Code,
43-18 except as otherwise provided by this chapter. Judicial review of
43-19 the validity of competition rules shall be commenced in the Court
43-20 of Appeals for the Third Court of Appeals District and shall be
43-21 limited to the commission's rulemaking record. The rulemaking
43-22 record consists of:
43-23 (1) the notice of the proposed rule;
43-24 (2) the comments of all interested persons;
43-25 (3) all studies, reports, memoranda, or other
43-26 materials on which the commission relied in adopting the rule; and
43-27 (4) the order adopting the rule.
44-1 (f) A person who challenges the validity of a competition
44-2 rule must file a notice of appeal with the court of appeals and
44-3 serve the notice on the commission not later than the 15th day
44-4 after the date on which the rule as adopted is published in the
44-5 Texas Register. The notice of appeal shall designate the person
44-6 challenging the rule as the appellant and the commission as the
44-7 appellee. The commission shall prepare the rulemaking record and
44-8 file it with the court of appeals not later than the 30th day after
44-9 the date the notice of appeal is served on the commission. The
44-10 court of appeals shall hear and determine each appeal as
44-11 expeditiously as possible with lawful precedence over other
44-12 matters. The appellant, and any person who is permitted by the
44-13 court to intervene in support of the appellant's claims, shall file
44-14 and serve briefs not later than the 30th day after the date the
44-15 commission files the rulemaking record. The commission, and any
44-16 person who is permitted by the court to intervene in support of the
44-17 rule, shall file and serve briefs not later than the 60th day after
44-18 the date the appellant files the appellant's brief. The court of
44-19 appeals may, on its own motion or on motion of any person for good
44-20 cause, modify the filing deadlines prescribed by this subsection.
44-21 The court of appeals shall render judgment affirming the rule or
44-22 reversing and, if appropriate on reversal, remanding the rule to
44-23 the commission for further proceedings, consistent with the court's
44-24 opinion and judgment. The Texas Rules of Appellate Procedure apply
44-25 to an appeal brought under this section to the extent not
44-26 inconsistent with this section.
44-27 Sec. 39.002. APPLICABILITY. This chapter, other than
45-1 Sections 39.155, 39.157(e), 39.203, 39.903, and 39.904, does not
45-2 apply to a municipally owned utility or an electric cooperative.
45-3 Sections 39.157(e), 39.203, and 39.904, however, apply only to a
45-4 municipally owned utility or an electric cooperative that is
45-5 offering customer choice. If there is a conflict between the
45-6 specific provisions of this chapter and any other provisions of
45-7 this title, except for Chapters 40 and 41, the provisions of this
45-8 chapter control.
45-9 Sec. 39.003. CONTESTED CASES. Unless specifically provided
45-10 otherwise, each commission proceeding under this chapter, other
45-11 than a rulemaking proceeding, report, notification, or
45-12 registration, shall be conducted as a contested case and the burden
45-13 of proof is on the incumbent electric utility.
45-14 (Sections 39.004-39.050 reserved for expansion
45-15 SUBCHAPTER B. TRANSITION TO COMPETITIVE RETAIL
45-16 ELECTRIC MARKET
45-17 Sec. 39.051. UNBUNDLING. (a) On or before September 1,
45-18 2000, each electric utility shall separate from its regulated
45-19 utility activities its customer energy services business activities
45-20 that are otherwise also already widely available in the competitive
45-21 market.
45-22 (b) Not later than January 1, 2002, each electric utility
45-23 shall separate its business activities from one another into the
45-24 following units:
45-25 (1) a power generation company;
45-26 (2) a retail electric provider; and
45-27 (3) a transmission and distribution utility.
46-1 (c) An electric utility may accomplish the separation
46-2 required by Subsection (b) either through the creation of separate
46-3 nonaffiliated companies or separate affiliated companies owned by a
46-4 common holding company or through the sale of assets to a third
46-5 party. An electric utility may create separate transmission and
46-6 distribution utilities.
46-7 (d) Each electric utility shall unbundle under this section
46-8 in a manner that provides for a separation of personnel,
46-9 information flow, functions, and operations, consistent with
46-10 Section 39.157(d).
46-11 (e) Each electric utility shall file with the commission a
46-12 plan to implement this section by January 10, 2000.
46-13 (f) The commission shall adopt the utility's plan for
46-14 business separation required by Subsection (b), adopt the plan with
46-15 changes, or reject the plan and require the utility to file a new
46-16 plan.
46-17 (g) Transactions by electric utilities involving sales,
46-18 transfers, or other disposition of assets to accomplish the
46-19 purposes of this section are not subject to Section 14.101, 35.034,
46-20 or 35.035.
46-21 Sec. 39.052. FREEZE ON EXISTING RETAIL BASE RATE TARIFFS.
46-22 (a) Until January 1, 2002, an electric utility shall provide
46-23 retail electric service within its certificated service area in
46-24 accordance with the electric utility's retail base rate tariffs in
46-25 effect on September 1, 1999, including its purchased power cost
46-26 recovery factor.
46-27 (b) During the freeze period, an electric utility may not
47-1 increase its retail base rates above the rates provided by this
47-2 section except for losses caused by force majeure as provided by
47-3 Section 39.055.
47-4 (c) Notwithstanding any other provision of this title,
47-5 during the freeze period the regulatory authority may not reduce
47-6 the retail base rates of an electric utility, except as may be
47-7 ordered as stipulated to by an electric utility in a proceeding for
47-8 which a final order had not been issued by January 1, 1999.
47-9 (d) During the freeze period, the retail base rates, overall
47-10 revenues, return on invested capital, and net income of an electric
47-11 utility are not subject to complaint, hearing, or determination as
47-12 to reasonableness.
47-13 (e) An electric utility that has a rate proceeding pending
47-14 before the commission as of January 2, 1999, shall provide service
47-15 in accordance with the tariffs approved in that proceeding from the
47-16 date of approval until the end of the freeze period.
47-17 (f) Nothing in this section affects the authority of the
47-18 commission to fulfill its obligations under Section 39.262.
47-19 (g) Nothing in this section shall deny a utility its right
47-20 to have the commission conduct proceedings and issue a final order
47-21 pertaining to any matter that may be remanded to the commission by
47-22 a court having jurisdiction, except that the final order may not
47-23 affect the rates charged to customers during the freeze period but
47-24 shall be taken into account during the utility's true-up proceeding
47-25 under Section 39.262.
47-26 (h) Nothing in this title shall be construed to prevent an
47-27 electric utility or a transmission and distribution utility from
48-1 filing, and the commission from approving, a change in wholesale
48-2 transmission service rates during the freeze period.
48-3 Sec. 39.053. COST RECOVERY ADJUSTMENTS. This subchapter
48-4 does not limit or alter the ability of an electric utility during
48-5 the freeze period to revise its fuel factor or to reconcile fuel
48-6 expenses and to either refund fuel overcollections or surcharge
48-7 fuel undercollections to customers, as authorized by its tariffs
48-8 and Sections 36.203 and 36.205.
48-9 Sec. 39.054. RETAIL ELECTRIC SERVICE DURING FREEZE PERIOD.
48-10 (a) An electric utility shall provide retail electric service
48-11 during the freeze period in accordance with any contract terms
48-12 applicable to a particular retail customer approved by the
48-13 regulatory authority and in effect on December 31, 1998.
48-14 (b) Nothing in Sections 39.052(c) and (d) shall be construed
48-15 to restrict any customer's right to complain during the freeze
48-16 period to the regulatory authority regarding the quality of retail
48-17 electric service provided by the electric utility or the
48-18 applicability of an electric utility's particular tariff to the
48-19 customer.
48-20 (c) Nothing in this title shall be construed to restrict an
48-21 electric utility, voluntarily and at its sole discretion, from
48-22 offering new services or new tariff options to its customers during
48-23 the freeze period, consistent with Section 39.051(a).
48-24 (d) Any offering of new services or tariff options under
48-25 this section shall be equal to or greater than an electric
48-26 utility's long-run marginal cost and may not be unreasonably
48-27 preferential, prejudicial, discriminatory, predatory, or
49-1 anticompetitive.
49-2 (e) Revenue from any new offering under this section shall
49-3 be accounted for in a manner consistent with Section 36.007.
49-4 Sec. 39.055. FORCE MAJEURE. (a) An electric utility may
49-5 recover losses resulting from force majeure through an increase in
49-6 its retail base rates during the freeze period.
49-7 (b) Notwithstanding Subchapter C, Chapter 36, the regulatory
49-8 authority, after a hearing to determine the electric utility's
49-9 losses from force majeure, shall permit the utility to fully
49-10 collect any approved force majeure increase through an appropriate
49-11 customer surcharge mechanism.
49-12 (c) For purposes of this section, "force majeure" means a
49-13 major event or combination of major events, including new or
49-14 expanded state or federal statutory or regulatory requirements;
49-15 hurricanes, tornadoes, ice storms, or other natural disasters; or
49-16 acts of war, terrorism, or civil disturbance, beyond the control of
49-17 an electric utility that the regulatory authority finds increases
49-18 the utility's total reasonable and necessary nonfuel costs or
49-19 decreases the utility's total nonfuel revenues related to the
49-20 generation and delivery of electricity by more than 10 percent for
49-21 any calendar year during the freeze period. The term does not
49-22 include any changes in general economic conditions such as
49-23 inflation, interest rates, or other factors of general application.
49-24 (Sections 39.056-39.100 reserved for expansion
49-25 SUBCHAPTER C. RETAIL COMPETITION
49-26 Sec. 39.101. CUSTOMER SAFEGUARDS. (a) Before customer
49-27 choice begins on January 1, 2002, the commission shall ensure that
50-1 retail customer protections are established that entitle a
50-2 customer:
50-3 (1) to safe, reliable, and reasonably priced
50-4 electricity, including protection against service disconnections in
50-5 extreme weather or in cases of medical emergency or nonpayment for
50-6 unrelated services;
50-7 (2) to privacy of customer consumption and credit
50-8 information;
50-9 (3) to bills presented in a clear format and in
50-10 language readily understandable by customers;
50-11 (4) to the option to have all electric services on a
50-12 single bill, except in those instances where multiple bills are
50-13 allowed under Chapters 40 and 41;
50-14 (5) to protection from discrimination on the basis of
50-15 race, color, sex, nationality, religion, or marital status;
50-16 (6) to accuracy of metering and billing;
50-17 (7) to information in English and Spanish and any
50-18 other language as necessary concerning rates, key terms and
50-19 conditions, in a standard format that will permit comparisons
50-20 between price and service offerings, and the environmental impact
50-21 of certain production facilities;
50-22 (8) to information in English and Spanish and any
50-23 other language as necessary concerning low-income assistance
50-24 programs and deferred payment plans; and
50-25 (9) to other information or protections necessary to
50-26 ensure high-quality service to customers.
50-27 (b) A customer is entitled:
51-1 (1) to be informed about rights and opportunities in
51-2 the transition to a competitive electric industry;
51-3 (2) to choose the customer's retail electric provider
51-4 consistent with this chapter, to have that choice honored, and to
51-5 assume that the customer's chosen provider will not be changed
51-6 without the customer's informed consent;
51-7 (3) to have access to providers of energy efficiency
51-8 services, to on-site distributed generation, and to providers of
51-9 energy generated by renewable energy resources;
51-10 (4) to be served by a provider of last resort that
51-11 offers a commission-approved standard service package;
51-12 (5) to receive sufficient information to make an
51-13 informed choice of service provider;
51-14 (6) to be protected from unfair, misleading, or
51-15 deceptive practices, including protection from being billed for
51-16 services that were not authorized or provided; and
51-17 (7) to have an impartial and prompt resolution of
51-18 disputes with its chosen retail electric provider and transmission
51-19 and distribution utility.
51-20 (c) A retail electric provider, power generation company,
51-21 aggregator, or other entity that provides retail electric service
51-22 may not refuse to provide retail electric or electric generation
51-23 service or otherwise discriminate in the provision of electric
51-24 service to any customer because of race, creed, color, national
51-25 origin, ancestry, sex, marital status, lawful source of income,
51-26 disability, or familial status. A retail electric provider, power
51-27 generation company, aggregator, or other entity that provides
52-1 retail electric service may not refuse to provide retail electric
52-2 or electric generation service to a customer because the customer
52-3 is located in an economically distressed geographic area or
52-4 qualifies for low-income affordability or energy efficiency
52-5 services. The commission shall require a provider to comply with
52-6 this subsection as a condition of certification or registration.
52-7 (d) A retail electric provider, power generation company,
52-8 aggregator, or other entity that provides retail electric service
52-9 shall submit reports to the commission and the office annually and
52-10 on request relating to the person's compliance with this section.
52-11 The commission by rule shall specify the form in which a report
52-12 must be submitted. A report must include:
52-13 (1) information regarding the extent of the person's
52-14 coverage;
52-15 (2) information regarding the service provided,
52-16 compiled by zip code and census tract; and
52-17 (3) any other information the commission or the office
52-18 considers relevant to determine compliance.
52-19 (e) The commission has the authority to adopt and enforce
52-20 such rules as may be necessary or appropriate to carry out
52-21 Subsections (a)-(d), including rules for minimum service standards
52-22 for a retail electric provider relating to customer deposits and
52-23 the extension of credit, switching fees, levelized billing
52-24 programs, interconnection and use of on-site generation,
52-25 termination of service, and quality of service. The commission has
52-26 jurisdiction over all providers of electric service in enforcing
52-27 Subsections (a)-(d) and may assess civil and administrative
53-1 penalties under Section 15.023 and seek civil penalties under
53-2 Section 15.028.
53-3 (f) On or before June 30, 2001, the commission shall modify
53-4 its current rules regarding customer protections to ensure that at
53-5 least the same level of customer protection against potential
53-6 abuses and the same quality of service that exists on December 31,
53-7 1999, is maintained in a restructured electric industry.
53-8 (g) Compliance with Subsections (a)-(e) of this section by a
53-9 provider of electric service which is a municipally owned utility
53-10 shall be administered solely by the governing body of the
53-11 municipally owned utility, which shall adopt, implement, and
53-12 enforce, as to the municipally owned utility, rules having the
53-13 effect of accomplishing the objectives of Subsections (a)-(e).
53-14 Reports containing the information required by Subsection (d) shall
53-15 be filed by the municipally owned utility with the governing body.
53-16 Sec. 39.102. RETAIL CUSTOMER CHOICE. (a) Each retail
53-17 customer in this state, except retail customers of electric
53-18 cooperatives and municipally owned utilities that have not opted
53-19 for customer choice, shall have customer choice on and after
53-20 January 1, 2002.
53-21 (b) The affiliated retail electric provider of the electric
53-22 utility serving a retail customer on December 31, 2001, may
53-23 continue to serve that customer until the customer chooses service
53-24 from a different retail electric provider, an electric cooperative
53-25 offering customer choice, or a municipally owned utility offering
53-26 customer choice.
53-27 (c) An electric utility that has in effect a systemwide
54-1 freeze for residential and commercial customers in effect September
54-2 1, 1997, extending beyond December 31, 2001, that has been found by
54-3 a regulatory authority to be in the public interest is not subject
54-4 to this chapter. At the expiration of the utility's freeze period,
54-5 the utility shall be subject to this chapter and, at that time, has
54-6 no claim for stranded cost recovery.
54-7 Sec. 39.1025. LIMITATIONS ON TELEPHONE SOLICITATION. (a) A
54-8 person may not make or cause to be made a telephone solicitation to
54-9 an electricity customer who has given notice to the commission of
54-10 the customer's objection to receiving telephone solicitations
54-11 relating to the customer's choice of retail electric providers.
54-12 (b) The commission shall establish and provide for the
54-13 operation of a database to compile a list of customers who object
54-14 to receiving telephone solicitations. The commission may operate
54-15 the database or contract with another entity to operate the
54-16 database.
54-17 (c) A customer shall pay a fee of not more than $5 for
54-18 inclusion in the database. The commission shall prescribe the
54-19 amount of the fee.
54-20 Sec. 39.103. COMMISSION AUTHORITY TO DELAY COMPETITION AND
54-21 SET NEW RATES. If the commission determines under Section 39.104
54-22 that a power region is unable to offer fair competition and
54-23 reliable service to all retail customer classes on January 1, 2002,
54-24 the commission shall delay customer choice for the power region and
54-25 may on or after January 1, 2002, establish new rates for all
54-26 electric utilities in the power region as provided by Chapter 36.
54-27 Sec. 39.104. CUSTOMER CHOICE PILOT PROJECTS. (a) Customer
55-1 choice pilot projects may be used to allow the commission to
55-2 evaluate the ability of each power region and electric utility to
55-3 implement customer choice. However, in a multiply certificated
55-4 area, an electric utility may not include customers that were
55-5 served by an electric cooperative or a municipally owned utility on
55-6 May 1, 1999.
55-7 (b) The commission shall require each electric utility to
55-8 offer customer choice in its service area within this state
55-9 amounting to five percent of the utility's combined load of all
55-10 customer classes within this state beginning on June 1, 2001.
55-11 (c) The load designated for customer choice under this
55-12 section shall be distributed among all customer classes of a
55-13 utility consistent with the purpose of this section and subject to
55-14 commission approval.
55-15 (d) Customers participating in a pilot project under this
55-16 section may buy electric energy from any retail electric provider
55-17 certified by the commission under Section 39.352, including an
55-18 affiliated retail electric provider; provided, however, that a
55-19 retail electric provider may not participate in a pilot project in
55-20 the certificated service area served by the electric utility with
55-21 which it is affiliated.
55-22 (e) Each utility operating a pilot project under this
55-23 section shall charge residential and small commercial customers in
55-24 accordance with Section 39.052.
55-25 (f) The commission may prescribe reporting requirements it
55-26 considers necessary to evaluate a pilot project consistent with the
55-27 purpose of this section.
56-1 (g) Customers having customer choice under this section
56-2 shall be billed as provided by Section 39.107.
56-3 (h) The commission may prescribe terms and conditions it
56-4 considers necessary to prohibit anticompetitive practices and to
56-5 encourage customer choice offered under this section.
56-6 (i) Notwithstanding any other provision of this title, a
56-7 retail electric provider participating in a pilot project under
56-8 this section is not an electric utility or a retail electric
56-9 utility.
56-10 (j) Twenty percent of the load designated for customer
56-11 choice under this section shall be initially set aside for
56-12 aggregated loads.
56-13 Sec. 39.105. LIMITATION ON SALE OF ELECTRICITY. (a) After
56-14 January 1, 2002, a transmission and distribution utility may not
56-15 sell electricity or otherwise participate in the market for
56-16 electricity except for the purpose of buying electricity to serve
56-17 its own needs.
56-18 (b) A person or retail electric utility may not provide,
56-19 furnish, or make available electric service at retail within the
56-20 certificated service area of an electric cooperative that has not
56-21 adopted customer choice or a municipally owned utility that has not
56-22 adopted customer choice. However, this subsection does not
56-23 prohibit the provision of electric service in multiply certificated
56-24 service areas to customers of any other retail electric utility.
56-25 Sec. 39.106. PROVIDER OF LAST RESORT. (a) The commission
56-26 shall designate retail electric providers in areas of the state in
56-27 which customer choice is in effect to serve as providers of last
57-1 resort.
57-2 (b) A provider of last resort shall offer a standard retail
57-3 service package for each class of customers designated by the
57-4 commission at a fixed, nondiscountable rate approved by the
57-5 commission.
57-6 (c) A provider of last resort shall provide the standard
57-7 retail service package to any requesting customer in the territory
57-8 for which it is the provider of last resort.
57-9 (d) The commission shall designate the provider or providers
57-10 of last resort not later than June 1, 2001.
57-11 (e) The commission shall determine the procedures and
57-12 criteria, which may include the solicitation of bids, for
57-13 designating a provider or providers of last resort. The commission
57-14 may redesignate the provider of last resort according to a schedule
57-15 it considers appropriate.
57-16 (f) In the event that no retail electric provider applies to
57-17 be the provider of last resort for a given area of the state on
57-18 reasonable terms and conditions, the commission may require a
57-19 retail electric provider to become the provider of last resort as a
57-20 condition of receiving or maintaining a certificate under Section
57-21 39.352.
57-22 (g) In the event that a retail electric provider fails to
57-23 serve any or all of its customers, the provider of last resort
57-24 shall offer that customer the standard retail service package for
57-25 that customer class with no interruption of service to any
57-26 customer.
57-27 Sec. 39.107. METERING AND BILLING SERVICES. (a) On
58-1 introduction of customer choice in a service area, metering
58-2 services for the area shall continue to be provided by the
58-3 transmission and distribution utility affiliate of the electric
58-4 utility that was serving the area before the introduction of
58-5 customer choice. Metering services provided to commercial and
58-6 industrial customers shall be provided on a competitive basis
58-7 beginning on January 1, 2004.
58-8 (b) Metering and billing services provided to residential
58-9 customers shall continue to be provided by the transmission and
58-10 distribution utility affiliate of the electric utility that was
58-11 serving the area before the introduction of customer choice until
58-12 the later of September 1, 2005, or the date on which at least 40
58-13 percent of those residential customers are taking service from
58-14 unaffiliated retail electric providers. Metering and billing
58-15 services provided to residential customers shall be governed by the
58-16 customer safeguards adopted by the commission under Section 39.101.
58-17 (c) Beginning on the date of introduction of customer choice
58-18 in a service area, tenants of leased or rented property that is
58-19 separately metered shall have the right to choose a retail electric
58-20 provider, an electric cooperative offering customer choice, or a
58-21 municipally owned utility offering customer choice, and the owner
58-22 of the property must grant reasonable and nondiscriminatory access
58-23 to transmission and distribution utilities, retail electric
58-24 providers, electric cooperatives, and municipally owned utilities
58-25 for metering purposes.
58-26 (d) Beginning on the date of introduction of customer choice
58-27 in a service area, a transmission and distribution utility, or an
59-1 electric cooperative or municipally owned utility providing the
59-2 customer's energy requirements shall bill a customer's retail
59-3 electric provider for nonbypassable delivery charges as determined
59-4 under Section 39.201. The retail electric provider or the electric
59-5 cooperative or municipally owned utility, as appropriate, must pay
59-6 these charges.
59-7 (e) A transmission and distribution utility may bill retail
59-8 customers at the request of a retail electric provider or, if an
59-9 electric cooperative or municipally owned utility is providing the
59-10 customer's energy requirements, at the request of the electric
59-11 cooperative or municipally owned utility. A transmission and
59-12 distribution utility that provides billing service on such request
59-13 shall offer billing service on comparable terms and conditions to
59-14 those of any such requesting retail electric provider or, as
59-15 applicable, the electric cooperative or municipally owned utility
59-16 providing energy requirements to a customer served by the
59-17 transmission and distribution utility.
59-18 (f) Beginning on the date of introduction of customer choice
59-19 in a service area, any charges for metering and billing services
59-20 shall comply with rules adopted by the commission relating to
59-21 nondiscriminatory rates of service.
59-22 (g) Metered electric service sold to residential customers
59-23 on a prepaid basis may not be sold at a price that is higher than
59-24 the price charged by the provider of last resort.
59-25 Sec. 39.108. CONTRACTUAL OBLIGATIONS. This chapter may not:
59-26 (1) interfere with or abrogate the rights or
59-27 obligations of any party, including a retail or wholesale customer,
60-1 to a contract with an investor-owned electric utility, river
60-2 authority, municipally owned utility, or electric cooperative;
60-3 (2) interfere with or abrogate the rights or
60-4 obligations of a party under a contract or agreement concerning
60-5 certificated utility service areas; or
60-6 (3) result in a change in wholesale power costs to
60-7 wholesale customers in Texas purchasing electricity under wholesale
60-8 power contracts the pricing provisions of which are based on
60-9 formulary rates, fuel adjustments, or average system costs.
60-10 Sec. 39.109. NEW OWNER OR SUCCESSOR. (a) To ensure the
60-11 continued safe and reliable operation of electric generating
60-12 facilities, the commission shall require a generating facility that
60-13 is transferred to a new owner or successor in interest between June
60-14 1, 1999, and January 1, 2002, to continue to be operated and
60-15 maintained by the same operating personnel for not less than two
60-16 years, except that the personnel may be dismissed for cause.
60-17 (b) This section shall apply only if the facility is
60-18 actually operated during the two-year period after the sale.
60-19 (c) This section shall not require that the purchaser cause
60-20 the facility to be operated in whole or in part, nor shall it
60-21 preclude a temporary closure of the facility during the two-year
60-22 period.
60-23 (d) This section shall not create any obligation extending
60-24 after the two-year period following the sale.
60-25 (Sections 39.110-39.150 reserved for expansion
60-26 SUBCHAPTER D. MARKET STRUCTURE
60-27 Sec. 39.151. ESSENTIAL ORGANIZATIONS. (a) A power region
61-1 must establish one or more independent organizations to perform the
61-2 following functions:
61-3 (1) ensure access to the transmission and distribution
61-4 systems for all buyers and sellers of electricity on
61-5 nondiscriminatory terms;
61-6 (2) ensure the reliability and adequacy of the
61-7 regional electrical network;
61-8 (3) ensure that information relating to a customer's
61-9 choice of retail electric provider is conveyed in a timely manner
61-10 to the persons who need that information; and
61-11 (4) ensure that electricity production and delivery
61-12 are accurately accounted for among the generators and wholesale
61-13 buyers and sellers in the region.
61-14 (b) "Independent organization" means an independent system
61-15 operator or other person that is sufficiently independent of any
61-16 producer or seller of electricity that its decisions will not be
61-17 unduly influenced by any producer or seller. An entity will be
61-18 deemed to be independent if it is governed by a board that has
61-19 three representatives from each segment of the electric market,
61-20 with the consumer segment being represented by one residential
61-21 customer, one commercial customer, and one industrial retail
61-22 customer.
61-23 (c) The commission shall certify an independent organization
61-24 or organizations to perform the functions prescribed by this
61-25 section.
61-26 (d) An independent organization certified by the commission
61-27 for a power region shall establish and enforce procedures,
62-1 consistent with this title and the commission's rules, relating to
62-2 the reliability of the regional electrical network and accounting
62-3 for the production and delivery of electricity among generators and
62-4 all other market participants. The procedures shall be subject to
62-5 commission oversight and review.
62-6 (e) The commission may authorize an independent organization
62-7 that is certified under this section to charge a reasonable and
62-8 competitively neutral rate to wholesale buyers and sellers to cover
62-9 the independent organization's costs.
62-10 (f) In implementing this section, the commission may
62-11 cooperate with the utility regulatory commission of another state
62-12 or the federal government and may hold a joint hearing or make a
62-13 joint investigation with that commission.
62-14 (g) If it amends its governance rules to provide that its
62-15 governing body is composed as prescribed by this subsection, the
62-16 existing independent system operator in ERCOT will meet the
62-17 criteria provided by Subsection (a) with respect to ensuring access
62-18 to the transmission systems for all buyers and sellers of
62-19 electricity in the ERCOT region and ensuring the reliability of the
62-20 regional electrical network. To comply with this subsection, the
62-21 governing body must be composed of:
62-22 (1) the chairman of the commission as an ex officio
62-23 nonvoting member;
62-24 (2) the counsellor as an ex officio voting member;
62-25 (3) the director of the independent system operator as
62-26 an ex officio voting member;
62-27 (4) four representatives of the power generation
63-1 sector as voting members;
63-2 (5) four representatives of the transmission and
63-3 distribution sector as voting members;
63-4 (6) four representatives of the power sales sector as
63-5 voting members; and
63-6 (7) the following people as voting members, appointed
63-7 by the commission:
63-8 (A) one representative of residential customers;
63-9 (B) one representative of commercial customers;
63-10 and
63-11 (C) one representative of industrial customers.
63-12 The four representatives specified in each of Subdivisions (4),
63-13 (5), and (6) shall be selected in a manner that ensures equitable
63-14 representation for the various sectors of industry participants.
63-15 (h) The ERCOT independent system operator may meet the
63-16 criteria relating to the other functions of an independent
63-17 organization provided by Subsection (a) by adopting procedures and
63-18 acquiring resources needed to carry out those functions.
63-19 (i) The commission may delegate authority to the existing
63-20 independent system operator in ERCOT to enforce operating standards
63-21 within the ERCOT regional electrical network and to establish and
63-22 oversee transaction settlement procedures. The commission may
63-23 establish the terms and conditions for the ERCOT independent system
63-24 operator's authority to oversee utility dispatch functions after
63-25 the introduction of customer choice.
63-26 (j) A retail electric provider, municipally owned utility,
63-27 electric cooperative, power marketer, transmission and distribution
64-1 utility, or power generation company shall observe all scheduling,
64-2 operating, planning, reliability, and settlement policies, rules,
64-3 guidelines, and procedures established by the independent system
64-4 operator in ERCOT. Failure to comply with this subsection may
64-5 result in the revocation, suspension, or amendment of a certificate
64-6 as provided by Section 39.356 or in the imposition of an
64-7 administrative penalty as provided by Section 39.357.
64-8 (k) To the extent the commission has authority over an
64-9 independent organization outside of ERCOT, the commission may
64-10 delegate authority to the independent organization consistent with
64-11 Subsection (i).
64-12 (l) No operational criteria, protocols, or other requirement
64-13 established by an independent organization, including the ERCOT
64-14 independent system operator, may adversely affect or impede any
64-15 manufacturing or other internal process operation associated with
64-16 an industrial generation facility, except to the minimum extent
64-17 necessary to assure reliability of the transmission network.
64-18 (m) A power region outside of ERCOT shall be deemed to have
64-19 met the requirement to establish an independent organization to
64-20 perform the transmission functions specified in Subsection (a) if
64-21 the Federal Energy Regulatory Commission has approved a regional
64-22 transmission organization for the region and found that the
64-23 regional transmission organization meets the requirements of
64-24 Subsection (a).
64-25 Sec. 39.152. QUALIFYING POWER REGIONS. (a) The commission
64-26 shall certify a power region if:
64-27 (1) a sufficient number of interconnected utilities in
65-1 the power region fall under the operational control of an
65-2 independent organization as described by Section 39.151;
65-3 (2) the power region has a generally applicable tariff
65-4 that guarantees open and nondiscriminatory access for all users to
65-5 transmission and distribution facilities in the power region as
65-6 provided by Section 39.203; and
65-7 (3) no person owns and controls more than 20 percent
65-8 of the installed generation capacity located in or capable of
65-9 delivering electricity to a power region, as determined according
65-10 to Section 39.154.
65-11 (b) In determining whether a power region not entirely
65-12 within the state meets the requirements of this section, the
65-13 commission shall consider the extent to which the available
65-14 transmission facilities limit the delivery of electricity from
65-15 generators located outside the state to areas of the power region
65-16 within the state.
65-17 (c) For a power region outside of ERCOT, the requirements of
65-18 Subsection (a)(2) shall be deemed to have been met if power
65-19 aggregating to approximately 50,000 megawatts can be delivered to
65-20 the portion of the power region that is in this state through the
65-21 payment of not more than one transmission tariff.
65-22 (d) For a power region outside of ERCOT, a power generation
65-23 company that is affiliated with an electric utility may elect to
65-24 demonstrate that it meets the requirements of Subsection (a)(3) by
65-25 showing that it does not own and control more than 20 percent of
65-26 the installed capacity in a geographic market that includes the
65-27 power region, using the guidelines, standards, and methods adopted
66-1 by the Federal Energy Regulatory Commission.
66-2 (e) In a power region outside of ERCOT, if customer choice
66-3 is introduced before the requirements of Subsection (a) are met,
66-4 an affiliated retail electric provider may not compete for retail
66-5 customers in any area of the power region that is within this state
66-6 and outside of the affiliated transmission and distribution
66-7 utility's certificated service area unless the affiliated power
66-8 generation company makes a commitment to maintain and does maintain
66-9 rates that are based on cost of service for any electric
66-10 cooperative or municipal utility that was a wholesale customer on
66-11 January 1, 1999, and was purchasing power at rates that were based
66-12 on cost of service. This subsection requires a power generation
66-13 company to sell power at rates that are based on cost of service,
66-14 notwithstanding the expiration of a contract for that service,
66-15 until the requirements of Subsection (a) are met.
66-16 (f) If the commission determines that the available
66-17 transmission facilities limit the delivery of electricity from
66-18 generators located outside this state to areas of the power region
66-19 within this state and that the requirements of Subsection (a) have
66-20 not been met for that region, any utility-affiliated power
66-21 generation company in the power region shall maintain adequate
66-22 supply and facilities to provide electric service to persons who
66-23 were or would have been retail customers of the affiliated retail
66-24 electric provider on December 31, 2001. The obligation provided by
66-25 this subsection remains in effect until the commission determines
66-26 that the available transmission facilities do not limit the
66-27 delivery of electricity from generators located outside this state
67-1 to the power region or that the requirements of Subsection (a) have
67-2 been met for the region.
67-3 Sec. 39.153. CAPACITY AUCTION. (a) Each electric utility
67-4 subject to this section shall sell at auction, at least 60 days
67-5 before the date set for customer choice to begin, entitlements to
67-6 at least 15 percent of the electric utility's Texas jurisdictional
67-7 installed generation capacity. For the purposes of this section,
67-8 the term "electric utility" includes any affiliated power
67-9 generation company that is unbundled from the electric utility in
67-10 accordance with Section 39.051, but does not include any entity
67-11 owning less than 400 megawatts of installed generation capacity.
67-12 (b) The obligation to auction the entitlements shall
67-13 continue until the earlier of 60 months after the date customer
67-14 choice is introduced or the date the commission determines that 40
67-15 percent or more of the electric power consumed by residential and
67-16 small commercial customers within the affiliated transmission and
67-17 distribution utility's certificated service area before the onset
67-18 of customer choice is provided by nonaffiliated retail electric
67-19 providers.
67-20 (c) An affiliate of the electric utility selling
67-21 entitlements in the auction required by this section may not
67-22 purchase entitlements from the affiliated electric utility at the
67-23 auction. Entitlements may only be purchased by entities lawfully
67-24 able to sell electricity in Texas.
67-25 (d) An electric utility may choose to auction additional
67-26 entitlements beyond those required by Subsection (a) or continue to
67-27 auction entitlements after the period required by Subsection (b) in
68-1 order to comply with Section 39.154.
68-2 (e) The commission shall adopt rules by December 31, 2000,
68-3 that define the scope of the capacity entitlements to be auctioned.
68-4 Entitlements may be auctioned in blocks of less than 15 percent.
68-5 The rules shall state the minimum amount of capacity that can be
68-6 sold at auction as an entitlement. At a minimum, the rules shall
68-7 provide that the entitlements:
68-8 (1) may be sold and purchased in periods of not less
68-9 than one month nor more than four years;
68-10 (2) may be resold to any lawful purchaser, except for
68-11 a retail electric provider affiliated with the electric utility
68-12 that originally auctioned the entitlement;
68-13 (3) include no possessory interest in the unit from
68-14 which the power is produced;
68-15 (4) include no obligations of a possessory owner of an
68-16 interest in the unit from which the power is produced; and
68-17 (5) give the purchaser the right to designate the
68-18 dispatch of the entitlement, subject to planned outages, outages
68-19 beyond the control of the utility operating the unit, and other
68-20 considerations subject to the oversight of the applicable
68-21 independent organization.
68-22 (f) The commission shall adopt rules by December 31, 2000,
68-23 that prescribe the procedure for the auction of the entitlements.
68-24 The rules shall include:
68-25 (1) a process for conducting the auction or auctions,
68-26 including who shall conduct it, how often it shall be conducted,
68-27 and how winning bidders shall be determined;
69-1 (2) a process for the electric utility to designate
69-2 which generation units or combination of units are offered for
69-3 auction;
69-4 (3) a provision for the utility to establish an
69-5 opening bid price based on the electric utility's expected cost,
69-6 with the commission prescribing the means for determining the
69-7 opening bid price, which may not include return on equity; and
69-8 (4) a provision that allows a bidder to specify the
69-9 magnitude and term of the entitlement, subject to the conditions
69-10 established in Subsection (e).
69-11 (g) In adopting the process under Subsection (f)(2), the
69-12 commission shall consider the furtherance of the development of the
69-13 competitive market, the cost of transmission, physical constraints
69-14 of the transmission system, the proximity of the generation to
69-15 load, economic efficiency, and any other factors the commission
69-16 finds relevant. The process may provide for commission approval of
69-17 the designation before auction. The commission may consult with
69-18 the applicable independent organization to develop the process.
69-19 Sec. 39.154. LIMITATION OF OWNERSHIP OF INSTALLED CAPACITY.
69-20 (a) Beginning on the date of introduction of customer choice, a
69-21 power generation company may not own and control more than 20
69-22 percent of the installed generation capacity located in, or capable
69-23 of delivering electricity to, a power region.
69-24 (b) In a power region not entirely within the state, the
69-25 commission may waive or modify the requirement in Subsection (a) on
69-26 a finding of good cause.
69-27 (c) In determining the percentage shares of installed
70-1 generation capacity under this section, the commission shall
70-2 combine capacity owned and controlled by a power generation company
70-3 and any entity that is affiliated with that power generation
70-4 company within the power region, reduced by the installed
70-5 generation capacity of those facilities that are made subject to
70-6 capacity auctions under Sections 39.153(a) and (d).
70-7 (d) In this chapter, "installed generation capacity" means
70-8 all potentially marketable electric generation capacity, including
70-9 the capacity of:
70-10 (1) generating facilities that are connected with a
70-11 transmission or distribution system;
70-12 (2) generating facilities used to generate electricity
70-13 for consumption by the person owning or controlling the facility;
70-14 and
70-15 (3) generating facilities that will be connected with
70-16 a transmission or distribution system and operating within 12
70-17 months.
70-18 (e) In determining the percentage shares of installed
70-19 generation capacity owned and controlled by a power generation
70-20 company under this section and Section 39.156, the commission
70-21 shall, for purposes of calculating the numerator, reduce the
70-22 installed generation capacity owned and controlled by that power
70-23 generation company by the installed generation capacity of any
70-24 "grandfathered facility" within an ozone nonattainment area as of
70-25 September 1, 1999, for which that power generation company has
70-26 commenced complying or made a binding commitment to comply with
70-27 Section 39.264.
71-1 Sec. 39.155. COMMISSION ASSESSMENT OF MARKET POWER. (a)
71-2 Each person, municipally owned utility, electric cooperative, and
71-3 river authority that owns generation facilities and offers
71-4 electricity for sale in this state shall report to the commission
71-5 its installed generation capacity, the total amount of capacity
71-6 available for sale to others, the total amount of capacity under
71-7 contract to others, the total amount of capacity dedicated to its
71-8 own use, its annual wholesale power sales in the state, its annual
71-9 retail power sales in the state, and any other information
71-10 necessary for the commission to assess market power or the
71-11 development of a competitive retail market in the state. The
71-12 commission shall by rule prescribe the nature and detail of the
71-13 reporting requirements and shall administer those reporting
71-14 requirements in a manner that ensures the confidentiality of
71-15 competitively sensitive information.
71-16 (b) The ERCOT independent system operator shall submit an
71-17 annual report to the commission identifying existing and potential
71-18 transmission and distribution constraints and system needs within
71-19 ERCOT, alternatives for meeting system needs, and recommendations
71-20 for meeting system needs. The first report shall be submitted on
71-21 or before October 1, 1999. Subsequent reports shall be submitted
71-22 by January 15 of each year or as determined necessary by the
71-23 commission.
71-24 (c) Before the date of introduction of customer choice in a
71-25 power region other than ERCOT, each electric utility owning
71-26 transmission and distribution facilities in that region shall
71-27 submit an annual report to the commission identifying existing and
72-1 potential transmission and distribution constraints and system
72-2 needs in the power region, alternatives for meeting system needs,
72-3 and recommendations for meeting system needs as directed by the
72-4 commission.
72-5 (d) In a qualifying power region, the reports required by
72-6 Subsections (b) and (c) shall be submitted by the independent
72-7 organization or organizations having authority over the power
72-8 region or discrete areas thereof.
72-9 Sec. 39.156. MARKET POWER MITIGATION PLAN. (a) In this
72-10 section, "market power mitigation plan" or "plan" means a written
72-11 proposal by an electric utility or a power generation company for
72-12 reducing its ownership and control of installed generation capacity
72-13 as required by Section 39.154.
72-14 (b) An electric utility or power generation company owning
72-15 and controlling more than 20 percent of the generation capacity
72-16 located in, or capable of delivering electricity to, a power region
72-17 shall file a market power mitigation plan with the commission not
72-18 later than December 1, 2000.
72-19 (c) The plan may provide for:
72-20 (1) the sale of generation assets to a nonaffiliated
72-21 person;
72-22 (2) the exchange of generation assets with a
72-23 nonaffiliated person located in a different power region;
72-24 (3) the auctioning of generation capacity entitlements
72-25 as part of a capacity auction required by Section 39.153;
72-26 (4) the sale of the right to capacity to a
72-27 nonaffiliated person for at least four years; or
73-1 (5) any reasonable method of mitigation.
73-2 (d) For the purposes of this section, generation capacity
73-3 shall be net of the generation capacity subject to an auction under
73-4 Section 39.153.
73-5 (e) The plan shall be in a form prescribed by the commission
73-6 and shall provide information the commission finds reasonably
73-7 necessary to evaluate the plan.
73-8 (f) The commission shall approve, modify, or reject a plan
73-9 within 180 days after the date of a filing under Subsection (b).
73-10 The commission may not modify a plan to require divestiture by the
73-11 electric utility or the power generation company.
73-12 (g) In reaching its determination under Subsection (f), the
73-13 commission shall consider:
73-14 (1) the degree to which the electric utility's or
73-15 power generation company's stranded costs, if any, are minimized;
73-16 (2) whether on disposition of the generation assets
73-17 the reasonable value is likely to be received;
73-18 (3) the effect of the plan on the electric utility's
73-19 or power generation company's federal income taxes;
73-20 (4) the effect of the plan on current and potential
73-21 competitors in the generation market; and
73-22 (5) whether the plan is consistent with the public
73-23 interest.
73-24 (h) An electric utility or power generation company with an
73-25 approved mitigation plan may request to amend or repeal its plan.
73-26 On a showing of good cause, the commission shall modify or repeal
73-27 an electric utility's or power generation company's mitigation
74-1 plan.
74-2 (i) If an electric utility's or a power generation company's
74-3 market power mitigation plan is not approved before January 1 of
74-4 the year it is to take effect, the commission may order the
74-5 electric utility or power generation company to auction generation
74-6 capacity entitlements according to Section 39.153, subject to
74-7 commission approval, of any capacity exceeding the maximum
74-8 allowable capacity prescribed by Section 39.154 until the time a
74-9 mitigation plan is approved.
74-10 (j) An auction under Subsection (i) shall be held not later
74-11 than 60 days after the date the order is entered.
74-12 Sec. 39.157. COMMISSION AUTHORITY TO ADDRESS MARKET POWER.
74-13 (a) The commission shall monitor market power associated with the
74-14 generation, transmission, distribution, and sale of electricity in
74-15 this state. On a finding that market power abuses or other
74-16 violations of this section are occurring, the commission shall
74-17 require reasonable mitigation of the market power by ordering the
74-18 construction of additional transmission or distribution facilities,
74-19 by seeking an injunction or civil penalties as necessary to
74-20 eliminate or to remedy the market power abuse or violation as
74-21 authorized by Chapter 15, by imposing an administrative penalty as
74-22 authorized by Chapter 15, or by suspending, revoking, or amending a
74-23 certificate or registration as authorized by Section 39.356.
74-24 Section 15.024(c) does not apply to an administrative penalty
74-25 imposed under this section. For purposes of this subchapter,
74-26 market power abuses are practices by persons possessing market
74-27 power that are unreasonably discriminatory or tend to unreasonably
75-1 restrict, impair, or reduce the level of competition, including
75-2 practices that tie unregulated products or services to regulated
75-3 products or services or unreasonably discriminate in the provision
75-4 of regulated services. For purposes of this section, "market power
75-5 abuses" include predatory pricing, withholding of production,
75-6 precluding entry, and collusion. A violation of the code of
75-7 conduct provided by Subsection (d) that materially impairs the
75-8 ability of a person to compete in a competitive market shall be
75-9 deemed to be an abuse of market power. The possession of a high
75-10 market share in a market open to competition may not, of itself, be
75-11 deemed to be an abuse of market power; however, this sentence shall
75-12 not affect the application of state and federal antitrust laws.
75-13 (b) Beginning on the date of introduction of customer
75-14 choice, a person that owns generation facilities may not own
75-15 transmission or distribution facilities in this state except for
75-16 those facilities necessary to interconnect a generation facility
75-17 with the transmission or distribution network, a facility not
75-18 dedicated to public use, or a facility otherwise excluded from the
75-19 definition of "electric utility" under Section 31.002. However,
75-20 nothing in this chapter shall prohibit a power generation company
75-21 affiliated with a transmission and distribution utility from owning
75-22 generation facilities.
75-23 (c) The commission shall monitor market shares of installed
75-24 capacity to ensure that the limitations in Section 39.154 are not
75-25 exceeded. If the commission finds that a person has violated a
75-26 limitation in Section 39.154, the commission shall order the person
75-27 to file, within 60 days of the date of the order, a market power
76-1 mitigation plan consistent with the requirements in Section 39.156.
76-2 (d) Not later than January 10, 2000, the commission shall
76-3 adopt rules and enforcement procedures to govern transactions or
76-4 activities between a transmission and distribution utility and its
76-5 competitive affiliates to avoid potential market power abuses and
76-6 cross-subsidizations between regulated and competitive activities
76-7 both during the transition to and after the introduction of
76-8 competition. Nothing in this subsection is intended to affect or
76-9 modify the obligations or duties relating to any rules or standards
76-10 of conduct that may apply to a utility or the utility's affiliates
76-11 under orders or regulations of the Federal Energy Regulatory
76-12 Commission or the Securities and Exchange Commission. A utility
76-13 that is subject to statutes or regulations in other states that
76-14 conflict with a provision of this section may petition the
76-15 commission for a waiver of the conflicting provision on a showing
76-16 of good cause. The rules adopted under this section shall ensure
76-17 that:
76-18 (1) a utility makes any products and services, other
76-19 than corporate support services, that it provides to a competitive
76-20 affiliate available, contemporaneously and in the same manner, to
76-21 the competitive affiliate's competitors and applies its tariffs,
76-22 prices, terms, conditions, and discounts for those products and
76-23 services in the same manner to all similarly situated entities;
76-24 (2) a utility does not:
76-25 (A) give a competitive affiliate or a
76-26 competitive affiliate's customers any preferential advantage,
76-27 access, or treatment regarding services other than corporate
77-1 support services; or
77-2 (B) act in a manner that is discriminatory or
77-3 anticompetitive with respect to a nonaffiliated competitor of a
77-4 competitive affiliate;
77-5 (3) a utility providing electric transmission or
77-6 distribution services:
77-7 (A) provides those services on nondiscriminatory
77-8 terms and conditions;
77-9 (B) does not establish as a condition for the
77-10 provision of those services the purchase of other goods or services
77-11 from the utility or the competitive affiliate; and
77-12 (C) does not provide competitive affiliates
77-13 preferential access to the utility's transmission and distribution
77-14 systems or to information about those systems;
77-15 (4) a utility does not release any proprietary
77-16 customer information to a competitive affiliate or any other
77-17 entity, other than an independent organization as defined by
77-18 Section 39.151 or a provider of corporate support services for the
77-19 purposes of providing the services, without obtaining prior
77-20 verifiable authorization, as determined from the commission, from
77-21 the customer;
77-22 (5) a utility does not:
77-23 (A) communicate with a current or potential
77-24 customer about products or services offered by a competitive
77-25 affiliate in a manner that favors a competitive affiliate; or
77-26 (B) allow a competitive affiliate, before
77-27 September 1, 2005, to use the utility's corporate name, trademark,
78-1 brand, or logo unless the competitive affiliate includes on
78-2 employee business cards and in its advertisements of specific
78-3 services to existing or potential residential or small commercial
78-4 customers locating within the utility's certificated service area a
78-5 disclaimer that states, "(Name of competitive affiliate) is not the
78-6 same company as (name of utility) and is not regulated by the
78-7 Public Utility Commission of Texas, and you do not have to buy
78-8 (name of competitive affiliate)'s products to continue to receive
78-9 quality regulated services from (name of utility).";
78-10 (6) a utility does not conduct joint advertising or
78-11 promotional activities with a competitive affiliate in a manner
78-12 that favors the competitive affiliate;
78-13 (7) a utility is a separate, independent entity from
78-14 any competitive affiliates and, except as provided by Subdivisions
78-15 (8) and (9), does not share employees, facilities, information, or
78-16 other resources, other than permissible corporate support services,
78-17 with those competitive affiliates unless the utility can prove to
78-18 the commission that the sharing will not compromise the public
78-19 interest;
78-20 (8) a utility's office space is physically separated
78-21 from the office space of the utility's competitive affiliates by
78-22 being located in separate buildings or, if within the same
78-23 building, by a method such as having the offices on separate floors
78-24 or with separate access, unless otherwise approved by the
78-25 commission;
78-26 (9) a utility and a competitive affiliate:
78-27 (A) may, to the extent the utility implements
79-1 adequate safeguards precluding employees of a competitive affiliate
79-2 from gaining access to information in a manner inconsistent with
79-3 Subsection (g) or (i), share common officers and directors,
79-4 property, equipment, offices to the extent consistent with
79-5 Subdivision (8), credit, investment, or financing arrangements to
79-6 the extent consistent with Subdivision (17), computer systems,
79-7 information systems, and corporate support services; and
79-8 (B) are not required to enter into prior written
79-9 contracts or competitive solicitations for non-tariffed
79-10 transactions between the utility and the competitive affiliate,
79-11 except that the commission by rule may require the utility and the
79-12 competitive affiliate to enter into prior written contracts or
79-13 competitive solicitations for certain classes of transactions,
79-14 other than corporate support services, that have a per unit value
79-15 of more than $75,000 or that total more than $1 million;
79-16 (10) a utility does not temporarily assign, for less
79-17 than one year, employees engaged in transmission or distribution
79-18 system operations to a competitive affiliate unless the employee
79-19 does not have knowledge of information that is intended to be
79-20 protected under this section;
79-21 (11) a utility does not subsidize the business
79-22 activities of an affiliate with revenues from a regulated service;
79-23 (12) a utility and its affiliates fully allocate costs
79-24 for any shared services, corporate support services, and other
79-25 items described by Subdivisions (8) and (9);
79-26 (13) a utility and its affiliates keep separate books
79-27 of accounts and records and the commission may review records
80-1 relating to a transaction between a utility and an affiliate;
80-2 (14) assets transferred or services provided between a
80-3 utility and an affiliate, other than transfers that facilitate
80-4 unbundling under Section 39.051 or asset valuation under Section
80-5 39.262, are priced at a level that is fair and reasonable to the
80-6 customers of the utility and reflects the market value of the
80-7 assets or services or the utility's fully allocated cost to provide
80-8 those assets or services;
80-9 (15) regulated services that a utility provides on a
80-10 routine or recurring basis are included in a tariff that is subject
80-11 to commission approval;
80-12 (16) each transaction between a utility and a
80-13 competitive affiliate is conducted at arm's length; and
80-14 (17) a utility does not allow an affiliate to obtain
80-15 credit under an arrangement that would include a specific pledge of
80-16 assets in the rate base of the utility or a pledge of cash
80-17 reasonably necessary for utility operations.
80-18 (e) The commission shall by rule establish a code of conduct
80-19 that must be observed by electric cooperatives and municipally
80-20 owned utilities and their affiliates to protect against
80-21 anticompetitive practices. The rules adopted by the commission
80-22 under this subsection shall be consistent with Chapters 40 and 41
80-23 and may not be more restrictive than the rules adopted under
80-24 Subsection (d).
80-25 (f) Following review of the annual report submitted to it
80-26 under Sections 39.155(b) and (c), the commission shall determine
80-27 whether specific transmission or distribution constraints or
81-1 bottlenecks within this state give rise to market power in specific
81-2 geographic markets in the state. The commission, on a finding that
81-3 specific transmission or distribution constraints or bottlenecks
81-4 within this state give rise to market power, may order reasonable
81-5 mitigation of that potential market power by ordering, under
81-6 Section 39.203(e), one or more electric utilities or transmission
81-7 and distribution utilities to construct additional transmission or
81-8 distribution capacity, or both, subject to the certification
81-9 provisions of this title.
81-10 (g) The sharing of corporate support services in accordance
81-11 with this section may not allow or provide a means for the transfer
81-12 of confidential information from a utility to an affiliate, create
81-13 the opportunity for preferential treatment or an unfair competitive
81-14 advantage, lead to customer confusion, or create significant
81-15 opportunities for cross-subsidization of affiliates.
81-16 (h) A utility or competitive affiliate may not circumvent
81-17 the provisions or the intent of the provisions of Subsection (d) by
81-18 using any utility affiliate to provide information, services, or
81-19 subsidies between the utility and a competitive affiliate.
81-20 (i) In this section:
81-21 (1) "Competitive affiliate" means an affiliate of a
81-22 utility that provides services or sells products in a competitive
81-23 energy-related market in this state, including telecommunications
81-24 services, to the extent those services are energy related.
81-25 (2) "Corporate support services" means services shared
81-26 by a utility, its parent holding company, or a separate affiliate
81-27 created to perform corporate support services, with its affiliates
82-1 of joint corporate oversight, governance, support systems, and
82-2 personnel. Examples of services that may be shared, to the extent
82-3 the services comply with the requirements prescribed by Subsections
82-4 (d) and (g), include human resources, procurement, information
82-5 technology, regulatory services, administrative services, real
82-6 estate services, legal services, accounting, environmental
82-7 services, research and development, internal audit, community
82-8 relations, corporate communications, financial services, financial
82-9 planning and management support, corporate services, corporate
82-10 secretary, lobbying, and corporate planning. Examples of services
82-11 that may not be shared include engineering, purchasing of electric
82-12 transmission, transmission and distribution system operations, and
82-13 marketing.
82-14 Sec. 39.158. MERGERS AND CONSOLIDATIONS. (a) An owner of
82-15 electric generation facilities that offers electricity for sale in
82-16 the state and proposes to merge, consolidate, or otherwise become
82-17 affiliated with another owner of electric generation facilities
82-18 that offers electricity for sale in this state shall obtain the
82-19 approval of the commission before closing if the electricity
82-20 offered for sale in the power region by the merged, consolidated,
82-21 or affiliated entity will exceed one percent of the total
82-22 electricity for sale in the power region. The approval shall be
82-23 requested at least 120 days before the date of the proposed
82-24 closing. The commission shall approve the transaction unless the
82-25 commission finds that the transaction results in a violation of
82-26 Section 39.154. If the commission finds that the transaction as
82-27 proposed would violate Section 39.154, the commission may condition
83-1 approval of the transaction on adoption of reasonable modifications
83-2 to the transaction as prescribed by the commission to mitigate
83-3 potential market power abuses.
83-4 (b) Nothing in this chapter shall be construed to confer
83-5 immunity from state or federal antitrust laws. This chapter is
83-6 intended to complement other state and federal antitrust
83-7 provisions. Therefore, antitrust remedies may also be sought in
83-8 state or federal court to remedy anticompetitive activities.
83-9 (c) This section may not be deemed to authorize commission
83-10 review or approval of transactions entered into between or among
83-11 municipally owned utilities, river authorities, special districts
83-12 created by law, or other political subdivisions, whether or not
83-13 those transactions may be characterized as mergers, consolidations,
83-14 or other affiliations, when the transaction is authorized or
83-15 structured under state law.
83-16 (Sections 39.159-39.200 reserved for expansion
83-17 SUBCHAPTER E. PRICE REGULATION AFTER COMPETITION
83-18 Sec. 39.201. COST OF SERVICE TARIFFS AND CHARGES. (a) Each
83-19 electric utility shall, on or before April 1, 2000, file proposed
83-20 tariffs for its proposed transmission and distribution utility.
83-21 (b) The filing under this section shall include supporting
83-22 cost data for determination of nonbypassable delivery charges,
83-23 which shall be the sum of:
83-24 (1) transmission and distribution utility charges by
83-25 customer class based on a forecasted 2002 test year;
83-26 (2) a system benefit fund fee; and
83-27 (3) an expected competition transition charge, if any.
84-1 (c) Each electric utility shall also identify the unbundled
84-2 generation and retail energy service costs by customer class.
84-3 (d) In accordance with a schedule and procedures it
84-4 establishes, the commission shall hold a hearing and approve or
84-5 modify and make effective as of January 1, 2002, the transmission
84-6 and distribution utility's proposed tariffs for transmission and
84-7 distribution services, the system benefit fund fee, and the
84-8 expected competition transition charge as determined under
84-9 Subsections (g) and (h) and as implemented under Subsections
84-10 (i)-(l), if any.
84-11 (e) The system benefit fund fee shall be that established by
84-12 the commission under Section 39.903.
84-13 (f) The expected competition transition charge shall be that
84-14 as determined under Subsections (g) and (h) and as implemented
84-15 under Subsections (i)-(l).
84-16 (g) The expected competition transition charge approved by
84-17 the commission shall be calculated from the amount of stranded
84-18 costs as defined in Subchapter F that are reasonably projected to
84-19 exist on the last day of the freeze period modified to reflect any
84-20 adjustments determined appropriate by the commission under Section
84-21 39.261(c).
84-22 (h) The electric utility shall use the ECOM administrative
84-23 model referenced in Section 39.262 to determine estimated stranded
84-24 costs. The model must include updated company-specific inputs.
84-25 Natural gas prices used in the model must be market-based natural
84-26 gas forward prices, where available. Growth rates in generating
84-27 plant operations and maintenance costs and allocated administrative
85-1 and general costs shall be benchmarked by comparing those costs to
85-2 the best available information on cost trends for comparable
85-3 generating plants. Capital additions shall be benchmarked using
85-4 the limitation in Section 39.259(b).
85-5 (i) An electric utility may:
85-6 (1) at any time after the start of the freeze period,
85-7 securitize 100 percent of its regulatory assets as defined by
85-8 Section 39.302 and up to 75 percent of its estimated stranded costs
85-9 as defined by this section and recover those charges through a
85-10 transition charge, in accordance with a financing order issued by
85-11 the commission under Section 39.303;
85-12 (2) implement, under bond, a nonbypassable charge of
85-13 up to 100 percent of its estimated stranded costs; or
85-14 (3) use a combination of the two methods under
85-15 Subdivisions (1) and (2).
85-16 (j) Any competition transition charge shall be allocated
85-17 among retail customer classes based on the relevant customer class
85-18 characteristics as of May 1, 1999, adjusted for normal weather
85-19 conditions, in accordance with the methodology used to allocate the
85-20 costs of the underlying assets in the electric utility's most
85-21 recent commission order addressing rate design, unless the utility
85-22 has agreed to an alternative allocation of stranded costs in a
85-23 settlement agreed to as part of a transition plan approved by the
85-24 commission on or after January 1, 1998, in which case the
85-25 alternative allocation shall apply.
85-26 (k) In determining the length of time over which stranded
85-27 costs under Subsection (h) may be recovered, the commission shall
86-1 consider:
86-2 (1) the electric utility's rates as of the end of the
86-3 freeze period;
86-4 (2) the sum of the transmission and distribution
86-5 charges and the system benefit fund fees;
86-6 (3) the proportion of estimated stranded costs to the
86-7 invested capital of the electric utility; and
86-8 (4) any other factor consistent with the public
86-9 interest as expressed in this chapter.
86-10 (l) Two years after customer choice is introduced, the
86-11 stranded cost estimate under this section shall be reviewed and, if
86-12 necessary, adjusted to reflect a final, actual valuation in the
86-13 true-up proceeding under Section 39.262. If, based on that
86-14 proceeding, the competition transition charge is not sufficient,
86-15 the commission may extend the collection period for the charge or,
86-16 if necessary, increase the charge. Alternatively, if it is found
86-17 in the true-up proceeding that the competition transition charge is
86-18 larger than is needed to recover any remaining stranded costs, the
86-19 commission may:
86-20 (1) reduce the competition transition charge, to the
86-21 extent it has not been securitized;
86-22 (2) reverse, in whole or in part, the depreciation
86-23 expense that has been redirected under Section 39.256;
86-24 (3) reduce the transmission and distribution utility's
86-25 rates; or
86-26 (4) implement a combination of the elements in
86-27 Subdivisions (1)-(3).
87-1 Sec. 39.202. PRICE TO BEAT. (a) From January 1, 2002,
87-2 until January 1, 2007, an affiliated retail electric provider shall
87-3 make available to residential and small commercial customers of its
87-4 affiliated transmission and distribution utility rates that, on a
87-5 bundled basis, are six percent less than the affiliated electric
87-6 utility's corresponding average residential and small commercial
87-7 rates, on a bundled basis, that were in effect on January 1, 1999,
87-8 adjusted to reflect the fuel factor determined as provided by
87-9 Subsection (b) and adjusted for any base rate reduction as
87-10 stipulated to by an electric utility in a proceeding for which a
87-11 final order had not been issued by January 1, 1999. These rates on
87-12 a bundled basis shall be known as the "price to beat" for
87-13 residential and small commercial customers, except that the "price
87-14 to beat" for a utility is the rate in effect as a result of a
87-15 settlement approved by the commission after January 1, 1999, if the
87-16 commission determines that base rates for that utility have been
87-17 reduced by more than 12 percent as a result of a final order issued
87-18 by the commission after October 1, 1998.
87-19 (b) The commission shall determine the fuel factor for each
87-20 electric utility as of December 31, 2001.
87-21 (c) After the date of customer choice, each affiliated power
87-22 generation company shall file a final fuel reconciliation for the
87-23 period ending the day before the date customer choice is
87-24 introduced. The final fuel balance from that reconciliation shall
87-25 be included in the true-up proceeding under Section 39.262.
87-26 (d) An affiliated retail electric provider shall make public
87-27 its price to beat in a manner that provides adequate disclosure as
88-1 determined by the commission.
88-2 (e) The affiliated retail electric provider may not charge
88-3 rates for residential or small commercial customers that are
88-4 different from the price to beat until the earlier of 36 months
88-5 after the date customer choice is introduced or:
88-6 (1) for service to residential customers, the date the
88-7 commission determines that 40 percent or more of the electric power
88-8 consumed by residential customers within the affiliated
88-9 transmission and distribution utility's certificated service area
88-10 before the onset of customer choice is committed to be served by
88-11 nonaffiliated retail electric providers; or
88-12 (2) for service to small commercial customers, the
88-13 date the commission determines that 40 percent or more of the
88-14 electric power consumed by small commercial customers within the
88-15 affiliated transmission and distribution utility's certificated
88-16 service area before the onset of customer choice is committed to be
88-17 served by nonaffiliated retail electric providers.
88-18 (f) Notwithstanding Subsection (e), the affiliated retail
88-19 electric provider may charge rates that are different from the
88-20 price to beat for service to aggregated loads of nonresidential
88-21 customers having an aggregated peak demand greater than 1,000
88-22 kilowatts, provided that all affected customers are:
88-23 (1) commonly owned; or
88-24 (2) franchisees of the same franchisor.
88-25 (g) The affiliated retail electric provider may not
88-26 encourage or provide an incentive to a customer to switch to a
88-27 nonaffiliated retail electric provider, promote any nonaffiliated
89-1 retail electric provider, or exchange customers with any
89-2 nonaffiliated retail electric provider to comply with the
89-3 requirements of Subsection (e)(1) or (2).
89-4 (h) The following standards shall be used for measuring
89-5 electric power consumption during the period before the onset of
89-6 customer choice:
89-7 (1) the consumption of residential and small
89-8 commercial customers with an annual peak demand less than or equal
89-9 to 20 kilowatts shall be based on the average annual consumption of
89-10 those respective groups during the year 2000;
89-11 (2) consumption for all small commercial customers
89-12 with an annual peak demand larger than 20 kilowatts shall be based
89-13 on each customer's usage during the year 2000; and
89-14 (3) for purposes of determining whether an affiliated
89-15 retail electric provider has met the requirements of Subsection
89-16 (e)(2), the aggregated loads of nonresidential customers having a
89-17 peak demand greater than 1,000 kilowatts that are served by the
89-18 affiliated retail electric provider at a rate different from the
89-19 price to beat under Subsection (f) shall be deducted from the
89-20 electric power consumption of small commercial customers during the
89-21 period before the onset of customer choice.
89-22 (i) For purposes of Subsection (h)(2), if less than 12
89-23 months of consumption history exists for any such customer, the
89-24 usage history shall be supplemented with the prior history of that
89-25 customer's location. For service to a new location, the annual
89-26 consumption shall be determined as the transmission and
89-27 distribution utility's estimate of the maximum annual kilowatt
90-1 demand used in sizing the electric service to that customer
90-2 multiplied by 8,760 hours, and that product multiplied by the
90-3 average annual customer load factor for small commercial customers
90-4 with loads greater than 20 kilowatts for the year 2000.
90-5 (j) On determining that its affiliated retail electric
90-6 provider has met the requirements of Subsection (e)(1) or (2), an
90-7 electric utility or a transmission and distribution utility shall
90-8 make a filing with the commission attesting to the fact that those
90-9 requirements have been met and that the restrictions of Subsection
90-10 (e)(1) or (2) and the true-up in Section 39.262(e) are no longer
90-11 applicable. The commission shall adopt appropriate procedures to
90-12 enable it to accept or reject the filing within 30 days.
90-13 (k) Following the true-up proceedings conducted under
90-14 Section 39.262, the commission may adjust the price to beat.
90-15 (l) An affiliated retail electric provider may request that
90-16 the commission adjust the fuel factor established under Subsection
90-17 (b) not more than twice a year if the affiliated retail electric
90-18 provider demonstrates that the existing fuel factor does not
90-19 adequately reflect significant changes in the market price of
90-20 natural gas and purchased energy used to serve retail customers.
90-21 (m) In a power region outside of ERCOT, if customer choice
90-22 is introduced before the requirements of Section 39.152(a) are met,
90-23 an affiliated retail electric provider shall charge rates to
90-24 customers other than residential and small commercial customers
90-25 that are no higher than the rates that, on a bundled basis, were in
90-26 effect on January 1, 1999, adjusted to reflect the fuel factor as
90-27 provided by Subsection (b) and adjusted for any base rate reduction
91-1 as stipulated to by an electric utility in a proceeding for which a
91-2 final order had not been issued by January 1, 1999.
91-3 (n) Notwithstanding Subsection (a), in a power region
91-4 outside of ERCOT, if customer choice is introduced before the
91-5 requirements of Section 39.152(a) are met, an affiliated retail
91-6 electric provider shall continue to offer the price to beat to
91-7 residential and small commercial customers, unless the price is
91-8 changed by the commission in accordance with this chapter, until
91-9 the later of 60 months after the date customer choice is introduced
91-10 or the requirements of Section 39.152(a) are met.
91-11 (o) In this section, "small commercial customer" means a
91-12 commercial customer having a peak demand of 1,000 kilowatts or
91-13 less.
91-14 (p) On finding that a retail electric provider will be
91-15 unable to maintain its financial integrity if it complies with
91-16 Subsection (a), the commission shall set the retail electric
91-17 provider's price to beat at the minimum level that will allow the
91-18 retail electric provider to maintain its financial integrity.
91-19 However, in no event shall the price to beat exceed the level of
91-20 rates, on a bundled basis, charged by the affiliated electric
91-21 utility on September 1, 1999, adjusted for fuel as provided by
91-22 Subsection (b).
91-23 Sec. 39.203. TRANSMISSION AND DISTRIBUTION SERVICE. (a)
91-24 All transmission and distribution utilities shall provide
91-25 transmission service at wholesale under Subchapter A, Chapter 35.
91-26 In addition, on and after January 1, 2002, a transmission and
91-27 distribution utility shall provide transmission or distribution
92-1 service, or both, at retail to an electric utility, a retail
92-2 electric provider, a municipally owned utility, an electric
92-3 cooperative, or an end-use customer at rates, terms of access, and
92-4 conditions that are comparable to those that apply to the
92-5 transmission and distribution utility and its affiliates. A
92-6 municipally owned utility offering customer choice or an electric
92-7 cooperative offering customer choice shall likewise provide
92-8 transmission or distribution service, or both, at retail to all
92-9 such entities in accordance with the commission's rules applicable
92-10 to terms and conditions of access and at rates adopted in
92-11 accordance with Sections 40.055(a)(1) and 41.055(1), respectively.
92-12 (b) When necessary to serve a wholesale customer an electric
92-13 utility, an electric cooperative that has not opted for customer
92-14 choice, or a municipally owned utility that has not opted for
92-15 customer choice shall provide wholesale transmission service at
92-16 distribution voltage. A customer of a municipally owned utility
92-17 that has not opted for customer choice or of an electric
92-18 cooperative that has not opted for customer choice may not claim
92-19 the status of a wholesale customer or be designated as a wholesale
92-20 customer if the customer is being or has been served under a retail
92-21 rate schedule of the municipally owned utility or electric
92-22 cooperative.
92-23 (c) On or before January 1, 2002, the commission shall
92-24 establish for all retail electric utilities offering customer
92-25 choice reasonable and comparable terms and conditions, in
92-26 accordance with Section 39.201, that comply with Subsection (a) for
92-27 open access on distribution facilities and shall establish, for all
93-1 retail electric utilities offering customer choice other than
93-2 municipally owned utilities and electric cooperatives, reasonable
93-3 and comparable rates for open access on distribution facilities.
93-4 (d) The terms of access, conditions, and rates established
93-5 under Subsection (c) shall be comparable to the terms of access,
93-6 conditions, and rates that the electric utility applies to itself
93-7 or its affiliates. The rules shall also provide that all ancillary
93-8 services provided by the utility to itself or its affiliates are
93-9 also available to third parties on request on a nondiscriminatory
93-10 basis.
93-11 (e) The commission may require an electric utility or a
93-12 transmission and distribution utility to construct or enlarge
93-13 facilities to ensure safe and reliable service for the state's
93-14 electric markets. In any proceeding brought under Chapter 37, an
93-15 electric utility or transmission and distribution utility ordered
93-16 to construct or enlarge facilities under this subchapter need not
93-17 prove that the construction ordered is necessary for the service,
93-18 accommodation, convenience, or safety of the public and need not
93-19 address the factors listed in Sections 37.056(c)(1)-(3) and (4)(E).
93-20 (f) The commission's rules must be consistent with the
93-21 standards of this title and may not be contrary to an applicable
93-22 decision, rule, or policy statement of a federal regulatory agency
93-23 having jurisdiction.
93-24 (g) Each power region shall have generally applicable
93-25 tariffs approved by the commission or a federal regulatory agency
93-26 having jurisdiction that guarantees open and nondiscriminatory
93-27 access as required by Section 39.152. This subsection may not be
94-1 deemed to vest in the commission power to set or approve
94-2 distribution access rates of a municipally owned utility or an
94-3 electric cooperative that has adopted customer choice.
94-4 Sec. 39.204. TARIFFS FOR OPEN ACCESS. Each transmission and
94-5 distribution utility shall file a tariff implementing the open
94-6 access rules with the commission or the federal regulatory
94-7 authority having jurisdiction over the transmission and
94-8 distribution service of the utility not later than the 90th day
94-9 before the date customer choice is offered by that utility.
94-10 Sec. 39.205. REGULATION OF COSTS FOLLOWING FREEZE PERIOD.
94-11 At the conclusion of the freeze period, any remaining costs
94-12 associated with nuclear decommissioning obligations continue to be
94-13 subject to cost of service rate regulation and shall be included as
94-14 a nonbypassable charge to retail customers.
94-15 (Sections 39.206-39.250 reserved for expansion
94-16 SUBCHAPTER F. RECOVERY OF STRANDED COSTS
94-17 THROUGH COMPETITION TRANSITION CHARGE
94-18 Sec. 39.251. DEFINITIONS. In this subchapter:
94-19 (1) "Above market purchased power costs" means
94-20 wholesale demand and energy costs that a utility is obligated to
94-21 pay under an existing purchased power contract to the extent the
94-22 costs are greater than the purchased power market value.
94-23 (2) "Existing purchased power contract" means a
94-24 purchased power contract in effect on January 1, 1999, including
94-25 any amendments and revisions to that contract resulting from
94-26 litigation initiated before January 1, 1999.
94-27 (3) "Generation assets" means all assets associated
95-1 with the production of electricity, including generation plants,
95-2 electrical interconnections of the generation plant to the
95-3 transmission system, fuel contracts, fuel transportation contracts,
95-4 water contracts, lands, surface or subsurface water rights,
95-5 emissions-related allowances, and gas pipeline interconnections.
95-6 (4) "Market value" means, for nonnuclear assets and
95-7 certain nuclear assets, the value the assets would have if bought
95-8 and sold in a bona fide third-party transaction or transactions on
95-9 the open market under Section 39.262(h) or, for certain nuclear
95-10 assets, as described by Section 39.262(i), the value determined
95-11 under the method provided by that subsection.
95-12 (5) "Purchased power market value" means the value of
95-13 demand and energy bought and sold in a bona fide third-party
95-14 transaction or transactions on the open market and determined by
95-15 using the weighted average costs of the highest three offers from
95-16 the market for purchase of the demand and energy available under
95-17 the existing purchased power contracts.
95-18 (6) "Retail stranded costs" means that part of net
95-19 stranded cost associated with the provision of retail service.
95-20 (7) "Stranded cost" means the positive excess of the
95-21 net book value of generation assets over the market value of the
95-22 assets, taking into account all of the electric utility's
95-23 generation assets, any above market purchased power costs, and any
95-24 deferred debit related to a utility's discontinuance of the
95-25 application of Statement of Financial Accounting Standards No. 71
95-26 ("Accounting for the Effects of Certain Types of Regulation") for
95-27 generation-related assets if required by the provisions of this
96-1 chapter. For purposes of Section 39.262, book value shall be
96-2 established as of December 31, 2001, or the date a market value is
96-3 established through a market valuation method under Section
96-4 39.262(h), whichever is earlier, and shall include stranded costs
96-5 incurred under Section 39.263.
96-6 Sec. 39.252. RIGHT TO RECOVER STRANDED COSTS. (a) An
96-7 electric utility is allowed to recover all of its net, verifiable,
96-8 nonmitigable stranded costs incurred in purchasing power and
96-9 providing electric generation service.
96-10 (b) Recovery of retail stranded costs by an electric utility
96-11 shall be from all existing or future retail customers, including
96-12 the facilities, premises, and loads of those retail customers,
96-13 within the utility's geographical certificated service area as it
96-14 existed on May 1, 1999.
96-15 (c) In multiply certificated areas, a retail customer may
96-16 not avoid stranded cost recovery charges by switching to another
96-17 electric utility, electric cooperative, or municipally owned
96-18 utility after May 1, 1999. A customer in a multiply certificated
96-19 service area that requested to switch providers on or before May 1,
96-20 1999, or was not taking service from an electric utility on May 1,
96-21 1999, and does not do so after that date is not responsible for
96-22 paying retail stranded costs of that utility.
96-23 (d) An electric utility shall pursue commercially reasonable
96-24 means to reduce its potential stranded costs, including good faith
96-25 attempts to renegotiate above-cost fuel and purchased power
96-26 contracts or the exercise of normal business practices to protect
96-27 the value of its assets. The commission shall consider the
97-1 utility's efforts under this subsection when determining the amount
97-2 of the utility's stranded costs, provided, however, that nothing in
97-3 this section authorizes the commission to substitute its judgment
97-4 for a market valuation of generation assets determined under
97-5 Sections 39.262(h) and (i).
97-6 Sec. 39.253. ALLOCATION OF STRANDED COSTS. (a) In
97-7 allocating retail stranded costs among retail customer classes, the
97-8 commission shall determine a cost allocation methodology that
97-9 incorporates the following factors:
97-10 (1) the type of generation plant for which the
97-11 stranded costs exist;
97-12 (2) the load that the plant serves; and
97-13 (3) the average demand of each customer class
97-14 throughout the year for the output of the plant.
97-15 (b) Retail stranded costs not directly related to a
97-16 generation plant shall be allocated to retail customer classes
97-17 based on the kilowatt hour usage of each class.
97-18 (c) Except as provided by Section 39.262(k), no customer or
97-19 customer class may avoid the obligation to pay the amount of
97-20 stranded costs allocated to that customer or class.
97-21 Sec. 39.254. USE OF REVENUES FOR UTILITIES WITH STRANDED
97-22 COSTS. This subchapter provides a number of tools to an electric
97-23 utility to mitigate stranded costs. Each electric utility that was
97-24 reported by the commission to have positive "excess costs over
97-25 market" (ECOM), denoted as the "base case" for the amount of
97-26 stranded costs before full retail competition in 2001 with respect
97-27 to its Texas jurisdiction, in the April 1998 Report to the Texas
98-1 Senate Interim Committee on Electric Utility Restructuring entitled
98-2 "Potentially Strandable Investment (ECOM) Report: 1998 Update,"
98-3 must use these tools to reduce the net book value of, otherwise
98-4 referred to as "accelerate" the cost recovery of, its stranded
98-5 costs each year. Any positive difference under the report required
98-6 by Section 39.257(b) shall be applied to the net book value of
98-7 generation assets.
98-8 Sec. 39.255. USE OF REVENUES FOR UTILITIES WITH NO STRANDED
98-9 COSTS. (a) An electric utility that does not have stranded costs
98-10 described by Section 39.254 shall be permitted to use any positive
98-11 difference under the report required by Section 39.257(b) on
98-12 capital expenditures to improve or expand transmission or
98-13 distribution facilities, or on capital expenditures to improve air
98-14 quality, as approved by the commission. Any such capital
98-15 expenditures shall be made in the calendar year immediately
98-16 following the year for which the report required by Section 39.257
98-17 is calculated. The capital expenditures shall be reflected in any
98-18 future proceeding under this chapter to set transmission or
98-19 distribution rates as a reduction to the utility's transmission and
98-20 distribution invested capital, as approved by the commission.
98-21 (b) To the extent that positive differences under the report
98-22 required by Section 39.257(b) are not used for capital
98-23 expenditures, the amounts shall be flowed back to the electric
98-24 utility's Texas jurisdictional customers through the power cost
98-25 recovery factor.
98-26 (c) This section applies only to the use of positive
98-27 differences under the report required by Section 39.257(b) for each
99-1 year during the freeze period.
99-2 Sec. 39.256. OPTION TO REDIRECT DEPRECIATION. (a) For the
99-3 calendar years of 1998, 1999, 2000, and 2001, an electric utility
99-4 described by Section 39.254 may redirect all or a part of the
99-5 depreciation expense relating to transmission and distribution
99-6 assets to its net generation plant assets.
99-7 (b) The electric utility shall report a decision under
99-8 Subsection (a) to the commission and any other applicable
99-9 regulatory authority.
99-10 (c) Any adjustments made to the book value of transmission
99-11 and distribution assets or the creation of any related regulatory
99-12 assets resulting from the redirection under this section shall be
99-13 accepted and applied by the commission for establishing net
99-14 invested capital and transmission and distribution rates for retail
99-15 customers in all future proceedings.
99-16 (d) Notwithstanding Subsection (c), the design of
99-17 post-freeze-period retail rates may not:
99-18 (1) shift the allocation of responsibility for
99-19 stranded costs;
99-20 (2) include the adjusted costs in wholesale
99-21 transmission and distribution rates; or
99-22 (3) apply the adjustments for the purpose of
99-23 establishing net invested capital and transmission and distribution
99-24 rates for wholesale customers.
99-25 Sec. 39.257. ANNUAL REPORT. (a) Beginning with the 1999
99-26 calendar year, each electric utility shall file a report with the
99-27 commission not later than 90 days after the end of each year during
100-1 the freeze period under a schedule and a format determined by the
100-2 commission.
100-3 (b) The report shall identify any positive difference
100-4 between annual revenues, reduced by the amount of annual revenues
100-5 under Sections 36.203 and 36.205, the revenues received under the
100-6 interutility billing process as adopted by the commission to
100-7 implement Sections 35.004, 35.006, and 35.007, revenues associated
100-8 with transition charges as defined by Section 39.302, and annual
100-9 costs.
100-10 Sec. 39.258. ANNUAL REPORT: DETERMINATION OF ANNUAL COSTS.
100-11 For the purposes of determining the annual costs in each annual
100-12 report, the following amounts shall be used:
100-13 (1) the lesser of:
100-14 (A) the utility's Texas jurisdictional operation
100-15 and maintenance expense reflected in each utility's Federal Energy
100-16 Regulatory Commission Form 1 of the report year, plus factoring
100-17 expenses not included in operation and maintenance, adjusted for:
100-18 (i) costs under Sections 36.062, 36.203,
100-19 and 36.205; and
100-20 (ii) revenues recorded under the
100-21 interutility billing process adopted by the commission to implement
100-22 Sections 35.004, 35.006, and 35.007; or
100-23 (B) the Texas jurisdictional operation and
100-24 maintenance expense reflected in each utility's 1996 Federal Energy
100-25 Regulatory Commission Form 1, plus factoring expenses not included
100-26 in operation and maintenance, adjusted for:
100-27 (i) costs under Sections 36.062, 36.203,
101-1 and 36.205, and not indexed for inflation;
101-2 (ii) any difference between the annual
101-3 revenues and the expenses recorded under the interutility billing
101-4 process adopted by the commission to implement Sections 35.004,
101-5 35.006, and 35.007; and
101-6 (iii) the annual percentage change in the
101-7 average number of utility customers;
101-8 (2) the amount of nuclear decommissioning expense
101-9 approved in the electric utility's last rate proceeding before the
101-10 commission, as may be required to be adjusted to comply with
101-11 applicable federal regulatory requirements;
101-12 (3) the depreciation rates approved in the electric
101-13 utility's last rate proceeding before the commission;
101-14 (4) the amortization expense approved in the electric
101-15 utility's last rate proceeding before the commission or in any
101-16 other proceeding in which deferred costs and the amortization of
101-17 those costs are established, except that if the items are fully
101-18 amortized during the freeze period, the expense shall be adjusted
101-19 accordingly;
101-20 (5) taxes and fees, including municipal franchise fees
101-21 to the extent not included in Subdivision (1), other than federal
101-22 income taxes, and assessments incurred that year;
101-23 (6) federal income tax expense, computed according to
101-24 the stand-alone methodology and using the actual capital structure
101-25 and actual cost of debt as of December 31 of the report year;
101-26 (7) return on invested capital, computed by
101-27 multiplying invested capital as of December 31 of the report year,
102-1 determined as provided by Section 39.259, by the cost of capital
102-2 approved in the electric utility's most recent rate proceeding
102-3 before the commission in which the cost of capital was specifically
102-4 adopted, or, in the case of a range, the midpoint of the range, if
102-5 the final rate order for the proceeding was issued on or after
102-6 January 1, 1992, or if such an order does not exist, a cost of
102-7 capital of 9.6 percent shall be used; and
102-8 (8) the amount resulting from any operation and
102-9 maintenance expense savings tracker from a merger of two utilities
102-10 and contained in a settlement agreement approved by the commission
102-11 before January 1, 1999.
102-12 Sec. 39.259. ANNUAL REPORT: DETERMINATION OF INVESTED
102-13 CAPITAL. (a) For the purposes of determining invested capital in
102-14 each annual report, the net plant in service, regulatory assets,
102-15 and deferred federal income taxes shall be updated each year, and
102-16 generation-related invested capital shall be reduced by the amount
102-17 of securitization under Sections 39.201(i) and 39.262(c) to the
102-18 extent otherwise included in invested capital.
102-19 (b) Capital additions to a plant in an amount less than
102-20 1-1/2 percent of the electric utility's net plant in service on
102-21 December 31, 1998, less plant items previously excluded by the
102-22 commission, for each of the years 1999 through 2001 are presumed
102-23 prudent.
102-24 (c) All other items in invested capital shall be as approved
102-25 in the electric utility's last rate proceeding before the
102-26 commission.
102-27 Sec. 39.260. USE OF GENERALLY ACCEPTED ACCOUNTING
103-1 PRINCIPLES. (a) The definition and identification of invested
103-2 capital and other terms used in this subchapter and Subchapter G
103-3 that affect the net book value of generation assets and the
103-4 treatment of transactions performed under Section 35.035 and other
103-5 transactions authorized by this title or approved by the regulatory
103-6 authority that affect the net book value of generation assets
103-7 during the freeze period shall be treated in accordance with
103-8 generally accepted accounting principles as modified by regulatory
103-9 accounting rules generally applicable to utilities.
103-10 (b) The principles and criteria described by Subsection (a),
103-11 including the criteria for applicability of Statement of Financial
103-12 Accounting Standards No. 71 ("Accounting for the Effects of Certain
103-13 Types of Regulation"), shall be applied for purposes of this
103-14 subchapter as they existed on January 1, 1999.
103-15 Sec. 39.261. REVIEW OF ANNUAL REPORT. (a) The annual
103-16 report filed under this subchapter is a public document and shall
103-17 be reviewed by the staff of the commission and the office. Both
103-18 staffs may review work papers and supporting documents and engage
103-19 in discussions with the utility about the data underlying the
103-20 reports.
103-21 (b) The staff of the commission and the office shall
103-22 communicate in writing to an electric utility not later than the
103-23 180th day after the date the report is filed if they have any
103-24 disagreements with the data or computations.
103-25 (c) The commission shall finalize and resolve any
103-26 disagreements related to the annual report, consistent with the
103-27 requirements of Section 39.258, as follows:
104-1 (1) for each calendar year, the commission shall
104-2 finalize the annual report before establishing the competition
104-3 transition charge under Section 39.201; and
104-4 (2) for each calendar year, the commission shall
104-5 finalize the annual report and reflect the result as part of the
104-6 true-up proceeding under Section 39.262.
104-7 Sec. 39.262. TRUE-UP PROCEEDING. (a) An electric utility,
104-8 together with its affiliated retail electric provider and its
104-9 affiliated transmission and distribution utility, may not be
104-10 permitted to overrecover stranded costs through the procedures
104-11 established by this section or through the application of the
104-12 measures provided by the other sections of this chapter.
104-13 (b) After the freeze period, an electric utility located in
104-14 a power region that is not certified under Section 39.152 shall
104-15 continue to file annual reports under Sections 39.257, 39.258, and
104-16 39.259 as if the freeze period remained in effect, until the time
104-17 the power region qualifies as certified under Section 39.152. In
104-18 addition, the commission staff and the office shall continue to
104-19 review the annual reports as provided by Section 39.261.
104-20 (c) After January 10, 2004, at a schedule and under
104-21 procedures to be determined by the commission, each transmission
104-22 and distribution utility, its affiliated retail electric provider,
104-23 and its affiliated power generation company shall jointly file to
104-24 finalize stranded costs under Subsections (h) and (i) and reconcile
104-25 those costs with the estimated stranded costs used to develop the
104-26 competition transition charge in the proceeding held under Section
104-27 39.201. Any resulting difference shall be applied to the
105-1 nonbypassable delivery rates of the transmission and distribution
105-2 utility, except that at the utility's option, any or all of the
105-3 remaining stranded costs may be securitized under Subchapter G.
105-4 (d) The affiliated power generation company shall reconcile,
105-5 and either credit or bill to the transmission and distribution
105-6 utility, the net sum of:
105-7 (1) the former electric utility's final fuel balance
105-8 determined under Section 39.202(c); and
105-9 (2) any difference between the price of power obtained
105-10 through the capacity auctions under Sections 39.153 and 39.156 and
105-11 the power cost projections that were employed for the same time
105-12 period in the ECOM model to estimate stranded costs in the
105-13 proceeding under Section 39.201.
105-14 (e) To the extent that the price to beat exceeded the market
105-15 price of electricity, the affiliated retail electric provider shall
105-16 reconcile and credit to the affiliated transmission and
105-17 distribution utility any positive difference between the price to
105-18 beat established under Section 39.202, reduced by the nonbypassable
105-19 delivery charge established under Section 39.201, and the
105-20 prevailing market price of electricity during the same time period.
105-21 A reconciliation for the applicable customer class is not required
105-22 under this subsection for an affiliated retail electric provider
105-23 that satisfies the requirements of Section 39.202(e)(1) or (2)
105-24 before the expiration of two years from the introduction of
105-25 customer choice. If a reconciliation is required, in no event
105-26 shall the amount credited exceed an amount equal to the number of
105-27 residential or small commercial customers served by the affiliated
106-1 transmission and distribution utility that are buying electricity
106-2 from the affiliated retail electric provider at the price to beat
106-3 on the second anniversary of the beginning of competition, minus
106-4 the number of new customers obtained outside the service area,
106-5 multiplied by $150.
106-6 (f) To the extent that any amount of regulatory assets
106-7 included in a securitization charge or competitive transition
106-8 charge exceeds the amount of regulatory assets approved in a rate
106-9 order which became effective on or before September 1, 1999, the
106-10 commission shall conduct a review during the true-up proceeding to
106-11 determine whether such amounts were appropriately calculated and
106-12 constituted reasonable and necessary costs pursuant to Subchapter
106-13 B, Chapter 36. If the commission finds that the amount of
106-14 regulatory assets specified in Section 39.302(5) is subject to
106-15 modification, a credit or other rate adjustment shall be made to
106-16 the transmission and distribution utility's non-bypassable delivery
106-17 rates; provided, however, that no adjustment may be made to a
106-18 transition charge established under Subchapter G.
106-19 (g) Based on the credits or bills received from its
106-20 affiliates under Subsections (d), (e), and (f), the transmission
106-21 and distribution utility shall make necessary adjustments to the
106-22 nonbypassable delivery rates it charges to retail electric
106-23 providers. If the commission determines that the nonbypassable
106-24 delivery rates are not sufficient, the commission may extend the
106-25 original collection period for the charge or, if necessary,
106-26 increase the charge. Alternatively, if the commission determines
106-27 that the nonbypassable delivery rates are larger than are needed to
107-1 recover the transmission and distribution utility's costs, the
107-2 commission shall correspondingly reduce:
107-3 (1) the competition transition charge, to the extent
107-4 it has not been securitized;
107-5 (2) the depreciation expense that has been redirected
107-6 under Section 39.256;
107-7 (3) the transmission and distribution utility's rates;
107-8 or
107-9 (4) a combination of the elements in Subdivisions
107-10 (1)-(3).
107-11 (h) Except as provided in Subsection (i), for the purpose of
107-12 finalizing the stranded cost estimate used to establish the
107-13 competition transition charge under Section 39.201, the affiliated
107-14 power generation company shall quantify its stranded costs using
107-15 one or more of the following methods:
107-16 (1) Sale of Assets. If, at any time after December
107-17 31, 1999, an electric utility or its affiliated power generation
107-18 company has sold some or all of its generation assets, which sale
107-19 shall include all generating assets associated with each generating
107-20 plant that is sold, in a bona fide third-party transaction under a
107-21 competitive offering, the total net value realized from the sale
107-22 establishes the market value of the generation assets sold. If not
107-23 all assets are sold, the market value of the remaining generation
107-24 assets shall be established by one or more of the other methods in
107-25 this section.
107-26 (2) Stock Valuation Method. If, at any time after
107-27 December 31, 1999, an electric utility or its affiliated power
108-1 generation company has transferred some or all of its generation
108-2 assets, including, at the election of the electric utility or power
108-3 generation company, any fuel and fuel transportation contracts
108-4 related to those assets, to one or more separate affiliated or
108-5 nonaffiliated corporations, not less than 51 percent of the common
108-6 stock of each corporation is spun off and sold to public investors
108-7 through a national stock exchange, and the common stock has been
108-8 traded for not less than one year, the resulting average daily
108-9 closing price of the common stock over 30 consecutive trading days
108-10 chosen by the commission out of the last 120 consecutive trading
108-11 days before the filing required under Subsection (c) establishes
108-12 the market value of the common stock equity in each transferee
108-13 corporation. The book value of each transferee corporation's debt
108-14 and preferred stock securities shall be added to the market value
108-15 of its assets. The market value of each transferee corporation's
108-16 assets shall be reduced by the corresponding net book value of the
108-17 assets acquired by each transferee corporation from any entity
108-18 other than the affiliated electric utility or power generation
108-19 company. The resulting market value of the assets establishes the
108-20 market value of the generation assets transferred by the electric
108-21 utility or power generation company to each separate corporation.
108-22 If not all assets are disposed of in this manner, the market value
108-23 of the remaining assets shall be established by one or more of the
108-24 other methods in this section.
108-25 (3) Partial Stock Valuation Method. If, at any time
108-26 after December 31, 1999, an electric utility or its affiliated
108-27 power generation company has transferred some or all of its
109-1 generation assets, including, at the election of the electric
109-2 utility or power generation company, any fuel and fuel
109-3 transportation contracts related to those assets, to one or more
109-4 separate affiliated or nonaffiliated corporations, at least 19
109-5 percent, but less than 51 percent, of the common stock of each
109-6 corporation is spun off and sold to public investors through a
109-7 national stock exchange, and the common stock has been traded for
109-8 not less than one year, the resulting average daily closing price
109-9 of the common stock over 30 consecutive trading days chosen by the
109-10 commission out of the last 120 consecutive trading days before the
109-11 filing required under Subsection (c) shall be presumed to establish
109-12 the market value of the common stock equity in each transferee
109-13 corporation. The commission may accept the market valuation to
109-14 conclusively establish the value of the common stock equity in each
109-15 transferee corporation or convene a valuation panel of three
109-16 independent financial experts to determine whether the percentage
109-17 of common stock sold is fairly representative of the total common
109-18 stock equity or whether a control premium exists for the retained
109-19 interest. The valuation panel must consist of financial experts,
109-20 chosen from proposals submitted in response to commission requests,
109-21 from the top 10 nationally recognized investment banks with
109-22 demonstrated experience in the United States electric industry as
109-23 indicated by the dollar amount of public offerings of long-term
109-24 debt and equity of United States investor-owned electric companies
109-25 over the immediately preceding three years as ranked by the
109-26 publications "Securities Data" or "Institutional Investor." If the
109-27 panel determines that a control premium exists for the retained
110-1 interest, the panel shall determine the amount of the control
110-2 premium, and the commission shall adopt the determination but may
110-3 not increase the market value by a control premium greater than 10
110-4 percent. The costs and expenses of the panel, as approved by the
110-5 commission, shall be paid by each transferee corporation. The
110-6 determination of the commission based on the finding of the panel
110-7 conclusively establishes the value of the common stock of each
110-8 transferee corporation. The book value of each transferee
110-9 corporation's debt and preferred stock securities shall be added to
110-10 the market value of its assets. The market value of each
110-11 transferee corporation's assets shall be reduced by the
110-12 corresponding net book value of the assets acquired by each
110-13 transferee corporation from any entity other than the affiliated
110-14 electric utility or power generation company. The resulting market
110-15 value of the assets establishes the market value of the generation
110-16 assets transferred by the electric utility or power generation
110-17 company to each separate corporation.
110-18 (4) Exchange of Assets. If, at any time after
110-19 December 31, 1999, an electric utility or its affiliated power
110-20 generation company has transferred some or all of its generation
110-21 assets, including any fuel and fuel transportation contracts
110-22 related to those assets, in a bona fide third-party exchange
110-23 transaction, the stranded costs related to the transferred assets
110-24 shall be the difference between the book value and the market value
110-25 of the transferred assets at the time of the exchange, taking into
110-26 account any other consideration received or given. The market
110-27 value of the transferred assets may be determined through an
111-1 appraisal by a nationally recognized independent appraisal firm, if
111-2 the market value is subject to a market valuation by means of an
111-3 offer of sale in accordance with this subdivision. To obtain a
111-4 market valuation by means of an offer of sale, the owner of the
111-5 asset shall offer it for sale to other parties under procedures
111-6 that provide broad public notice of the offer and a reasonable
111-7 opportunity for other parties to bid on the asset. The owner of
111-8 the asset may establish a reserve price for any offer based on the
111-9 sum of the appraised value of the asset and the tax impact of
111-10 selling the asset, as determined by the commission.
111-11 (i) Unless an electric utility or its affiliated power
111-12 generation company combines all of its remaining generation assets
111-13 into one or more transferee corporations as described in
111-14 Subsections (g)(2) and (3), the electric utility shall quantify its
111-15 stranded costs for nuclear assets using the ECOM method. The ECOM
111-16 method is the estimation model prepared for and described by the
111-17 commission's April 1998 Report to the Texas Senate Interim
111-18 Committee on Electric Restructuring entitled "Potentially
111-19 Strandable Investment (ECOM) Report: 1998 Update." The
111-20 methodology used in the model must be the same as that used in the
111-21 1998 report to determine the "base case." At the time of the
111-22 proceeding under this section, the ECOM model shall be rerun using
111-23 updated company-specific inputs required by the model, updating the
111-24 market price of electricity, and using updated natural gas price
111-25 forecasts and the capacity cost based on the long-run marginal cost
111-26 of the most economic new generation technology then available.
111-27 Natural gas price projections used in the model must be
112-1 market-based natural gas forward prices, where available. Growth
112-2 rates in generating plant operations and maintenance costs and
112-3 allocated administrative and general costs shall be benchmarked by
112-4 comparing those costs to the best available information on cost
112-5 trends for comparable generating plants. Capital additions shall
112-6 be benchmarked using the limitation in Section 39.259(b).
112-7 (j) The commission shall issue a final order not later than
112-8 the 150th day after the date of the filing under this section by
112-9 the transmission and distribution utility, its affiliated retail
112-10 electric provider, and its affiliated power generation company, and
112-11 the resulting order shall be subject to judicial review under
112-12 Chapter 2001, Government Code.
112-13 (k) Notwithstanding Section 39.252, to the extent that a
112-14 customer's actual load has been lawfully served by a fully
112-15 operational qualifying facility before September 1, 2001, or by an
112-16 on-site power production facility with a rated capacity of 10
112-17 megawatts or less, any charge for recovery of stranded costs under
112-18 this section or Subchapter G assessed on that customer after the
112-19 facility becomes fully operational shall be included only in those
112-20 tariffs or charges associated with the services actually provided
112-21 by the transmission and distribution utility, if any, to the
112-22 customer after the facility became fully operational and may not
112-23 include any costs associated with the service provided to the
112-24 customer by the electric utility or its affiliated transmission and
112-25 distribution utility under their tariffs before the operation of
112-26 that qualifying facility. To qualify under this subsection, a
112-27 qualifying facility must have made substantially complete filings
113-1 on or before December 31, 1999, for all necessary site-specific
113-2 environmental permits under the rules of the Texas Natural Resource
113-3 Conservation Commission in effect at the time of filing.
113-4 Sec. 39.263. STRANDED COST RECOVERY OF ENVIRONMENTAL CLEANUP
113-5 COSTS. (a) Subject to Subsection (c), capital costs incurred by
113-6 an electric utility to improve air quality before January 1, 2002,
113-7 are eligible for inclusion as net invested capital under Section
113-8 39.259, notwithstanding the limitations imposed under Sections
113-9 39.259(b) and (c).
113-10 (b) Subject to Subsection (c), capital costs incurred by an
113-11 electric utility or an affiliated power generation company to
113-12 improve air quality after January 1, 2002, and before May 1, 2003,
113-13 are eligible for inclusion in the determination of invested capital
113-14 in the true-up proceeding under Section 39.262.
113-15 (c) Reasonable costs incurred under Subsections (a) and (b)
113-16 shall be included as invested capital and considered in an electric
113-17 utility's stranded cost determination only to the extent that:
113-18 (1) the cost is applied to offset or reduce the
113-19 emission of airborne contaminants from an electric generating
113-20 facility, where:
113-21 (A) the reduction or offset is determined by the
113-22 Texas Natural Resource Conservation Commission to be an essential
113-23 component in achieving compliance with a national ambient air
113-24 quality standard; or
113-25 (B) the reduction or offset is necessary in
113-26 order for an unpermitted electric generating facility to obtain a
113-27 permit in the manner provided by Section 39.264;
114-1 (2) the retrofit decision is determined to be the most
114-2 cost-effective after consideration of alternative measures,
114-3 including the retirement of the generating facility; and
114-4 (3) the amount and location of resulting emission
114-5 reductions is consistent with the air quality goals and policies of
114-6 the Texas Natural Resource Conservation Commission.
114-7 (d) If the retirement of a generating facility is the most
114-8 cost-effective alternative, taking into account the cost of
114-9 replacement generating capacity, the net book value, including
114-10 retirement costs and offsetting salvage value, of the affected
114-11 facility shall be included in the electric utility's stranded cost
114-12 determination, notwithstanding Section 39.259(c).
114-13 Sec. 39.264. EMISSIONS REDUCTIONS OF "GRANDFATHERED
114-14 FACILITIES." (a) In this section:
114-15 (1) "Conservation commission" means the Texas Natural
114-16 Resource Conservation Commission.
114-17 (2) "Electric generating facility" means a facility
114-18 that generates electric energy for compensation and is owned or
114-19 operated by a person in this state, including a municipal
114-20 corporation, electric cooperative, or river authority.
114-21 (b) This section applies only to an electric generating
114-22 facility existing on January 1, 1999, that is not subject to the
114-23 requirement to obtain a permit under Section 382.0518(g), Health
114-24 and Safety Code.
114-25 (c) It is the intent of the legislature that, for the
114-26 12-month period beginning on May 1, 2003, and for each 12-month
114-27 period after the end of that period, total annual emissions of
115-1 nitrogen oxides from facilities subject to this section may not
115-2 exceed levels equal to 50 percent of the total emissions of that
115-3 pollutant during 1997, as reported to the conservation commission,
115-4 and total annual emissions of sulphur dioxides from coal-fired
115-5 facilities subject to this section may not exceed levels equal to
115-6 75 percent of the total emissions of that pollutant during 1997, as
115-7 reported to the conservation commission. The limitations
115-8 prescribed by this subsection may be met through an emissions
115-9 allocation and allowance transfer system described by this section.
115-10 (d) A municipal corporation, electric cooperative, or river
115-11 authority may exclude any electric generating facilities of 25
115-12 megawatts or less from the requirements prescribed by this section.
115-13 Not later than January 1, 2000, a municipal corporation, electric
115-14 cooperative, or river authority must inform the conservation
115-15 commission of its intent to exclude those facilities.
115-16 (e) The owner or operator of an electric generating facility
115-17 shall apply to the conservation commission for a permit for the
115-18 emission of air contaminants on or before September 1, 2000. A
115-19 permit issued by the conservation commission under this section
115-20 shall require the facility to achieve emissions reductions or
115-21 trading emissions allowances as provided by this section. If the
115-22 facility uses coal as a fuel, the permit must also be conditioned
115-23 on the facility's emissions meeting opacity limitations provided by
115-24 conservation commission rules. Notwithstanding Section
115-25 382.0518(g), Health and Safety Code, a facility that does not
115-26 obtain a permit as required by this subsection may not operate
115-27 after May 1, 2003, unless the conservation commission finds good
116-1 cause for an extension.
116-2 (f) The conservation commission shall develop rules for the
116-3 permitting of electric generating facilities. The rules adopted
116-4 under this subsection shall provide, by region, for the allocation
116-5 of emissions allowances of sulphur dioxides and nitrogen oxides
116-6 among electric generating facilities and for facilities to trade
116-7 emissions allowances for those contaminants.
116-8 (g) The conservation commission by rule shall establish an
116-9 East Texas Region, a West Texas Region, and an El Paso Region for
116-10 allocation of air contaminants under the permitting program under
116-11 Subsection (f). The East Texas Region must contain all counties
116-12 traversed by or east of Interstate Highway 35 or Interstate Highway
116-13 37, including Bosque, Coryell, Hood, Parker, Somervell, and Wise
116-14 counties. The West Texas Region includes all of the state not
116-15 contained in the East Texas Region or the El Paso Region. The El
116-16 Paso Region includes El Paso County.
116-17 (h) Not later than January 1, 2000, the conservation
116-18 commission shall allocate to each electric generating facility in
116-19 each region a number of annual emissions allowances, with each
116-20 allowance equal to one ton of sulphur dioxides or of nitrogen
116-21 oxides emitted in a year, that permit emissions of the contaminants
116-22 from the facility in that year. The conservation commission must
116-23 allocate to each facility a number of emissions allowances equal to
116-24 an emissions rate measured in pounds per million British thermal
116-25 units divided by 2,000 and multiplied by the facility's total heat
116-26 input in terms of million British thermal units during 1997. For
116-27 the East Texas Region, the emissions rate shall be 0.14 pounds per
117-1 million British thermal units for nitrogen oxides and 1.38 pounds
117-2 per million British thermal units for sulphur dioxides. For the
117-3 West Texas and El Paso regions, the emissions rate shall be 0.195
117-4 pounds per million British thermal units for nitrogen oxides.
117-5 Allowances for sulphur dioxides may only be allocated among
117-6 coal-fired facilities.
117-7 (i) A person, municipal corporation, electric cooperative,
117-8 or river authority that owns and operates an electric generating
117-9 facility not covered by this section may elect to designate that
117-10 facility to become subject to the requirements of this section and
117-11 to receive emissions allowances for the purpose of complying with
117-12 the emissions limitations prescribed by Subsection (c). The
117-13 conservation commission shall adopt rules governing this election
117-14 that:
117-15 (1) require an owner or operator of an electric
117-16 generation facility to designate to the conservation commission in
117-17 its permit application under Subsection (e) any facilities that
117-18 will become subject to this section;
117-19 (2) require the conservation commission,
117-20 notwithstanding the allocation mechanism provided by Subsection
117-21 (h), to allocate additional allowances to facilities governed by
117-22 this subsection in an amount equal to each facility's actual
117-23 emissions in tons in 1997;
117-24 (3) provide that any unit designated under this
117-25 subsection may not transfer or bank allowances conserved as a
117-26 result of reduced utilization or shutdown, except that the
117-27 allowances may be transferred or carried forward for use in
118-1 subsequent years to the extent that the reduced utilization or
118-2 shutdown results from the replacement of thermal energy from the
118-3 unit designated under this subsection with thermal energy generated
118-4 by any other unit; and
118-5 (4) provide that emissions reductions from electing
118-6 facilities designated in this subsection may only be used to
118-7 satisfy the emissions reductions for grandfathered facilities
118-8 defined in Subsection (c) to the extent that reductions used to
118-9 satisfy the limitations in Subsection (c) are beyond the
118-10 requirements of any other state or federal standard, or both.
118-11 (j) The conservation commission by rule shall permit a
118-12 facility to trade emissions allocations with other electric
118-13 generating facilities only in the same region.
118-14 (k) The conservation commission by rule shall provide
118-15 methods for the conservation commission to determine whether a
118-16 facility complies with the permit issued under this section. The
118-17 rules must provide for:
118-18 (1) monitoring and reporting actual emissions of
118-19 sulphur dioxides and nitrogen oxides from each facility;
118-20 (2) provisions for saving unused allowances for use in
118-21 later years; and
118-22 (3) a system for tracking traded allowances.
118-23 (l) A facility may not trade an unused allowance for a
118-24 contaminant for use as a credit for another contaminant.
118-25 (m) A person possessing market power shall not withhold
118-26 emissions allowances from the market in a manner that is
118-27 unreasonably discriminatory or tends to unreasonably restrict,
119-1 impair, or reduce the level of competition.
119-2 (n) The conservation commission shall penalize a facility
119-3 that emits an air contaminant that exceeds the facility's
119-4 allowances for that contaminant by:
119-5 (1) enforcing an administrative penalty, in an amount
119-6 determined by conservation commission rules, for each ton of air
119-7 contaminant emissions by which the facility exceeds its allocated
119-8 emissions allowances; and
119-9 (2) reducing the facility's emissions allowances for
119-10 the next year by an amount of emissions equal to the excessive
119-11 emissions in the year the facility emitted the excessive air
119-12 contaminants.
119-13 (o) The conservation commission may penalize a facility that
119-14 emits an air contaminant that exceeds the facility's allowances
119-15 for that contaminant by:
119-16 (1) ordering the facility to cease operations; or
119-17 (2) taking other enforcement action provided by
119-18 conservation commission rules.
119-19 (p) The conservation commission by rule shall provide for a
119-20 facility in the El Paso Region to meet emissions allowances by
119-21 using credits from emissions reductions achieved in Ciudad Juarez,
119-22 United Mexican States.
119-23 (q) If the conservation commission or the United States
119-24 Environmental Protection Agency determines that reductions in
119-25 nitrogen oxides emissions in the El Paso Region otherwise required
119-26 by this section would result in increased ambient ozone levels in
119-27 El Paso County, facilities in the El Paso Region are exempt from
120-1 the nitrogen oxides reduction requirements.
120-2 (r) An applicant for a permit under Subsection (e) shall
120-3 publish notice of intent to obtain the permit in accordance with
120-4 Section 382.056, Health and Safety Code. The conservation
120-5 commission shall provide an opportunity for a public hearing and
120-6 the submission of public comment and send notice of a decision on
120-7 an application for a permit under Subsection (e) in the same manner
120-8 as provided by Sections 382.0561 and 382.0562, Health and Safety
120-9 Code. The conservation commission shall review and renew a permit
120-10 issued under this section in accordance with Section 382.055,
120-11 Health and Safety Code.
120-12 (s) This section does not limit the authority of the
120-13 conservation commission to require further reductions of nitrogen
120-14 oxides, sulphur dioxides, or any other pollutant from generating
120-15 facilities subject to this section or Section 39.263.
120-16 Sec. 39.265. RIGHTS NOT AFFECTED. This chapter is not
120-17 intended to alter any rights of utilities to recover stranded costs
120-18 from wholesale customers.
120-19 (Sections 39.266-39.300 reserved for expansion
120-20 SUBCHAPTER G. SECURITIZATION
120-21 Sec. 39.301. PURPOSE. The purpose of this subchapter is to
120-22 enable utilities to use securitization financing to recover
120-23 regulatory assets and stranded costs, because this type of debt
120-24 will lower the carrying costs of the assets relative to the costs
120-25 that would be incurred using conventional utility financing
120-26 methods. The savings associated with securitization shall work to
120-27 the benefit of ratepayers. The amount securitized may not exceed
121-1 the present value of the revenue requirement over the life of the
121-2 proposed transition bond associated with the regulatory assets or
121-3 stranded costs sought to be securitized. The present value
121-4 calculation shall use a discount rate equal to the proposed
121-5 interest rate on the transition bonds.
121-6 Sec. 39.302. DEFINITIONS. In this subchapter:
121-7 (1) "Assignee" means any individual, corporation, or
121-8 other legally recognized entity to which an interest in transition
121-9 property is transferred, other than as security, including any
121-10 assignee of that party.
121-11 (2) "Financing order" means an order of the commission
121-12 adopted under Section 39.201 or 39.262 approving the issuance of
121-13 transition bonds and the creation of transition charges for the
121-14 recovery of qualified costs.
121-15 (3) "Financing party" means a holder of transition
121-16 bonds, including trustees, collateral agents, and other persons
121-17 acting for the benefit of the holder.
121-18 (4) "Qualified costs" means 100 percent of an electric
121-19 utility's regulatory assets and 75 percent of its recoverable costs
121-20 determined by the commission under Section 39.201 and any remaining
121-21 stranded costs determined under Section 39.262 together with the
121-22 costs of issuing, supporting, and servicing transition bonds and
121-23 any costs of retiring and refunding the electric utility's existing
121-24 debt and equity securities in connection with the issuance of
121-25 transition bonds. The term includes the costs to the commission of
121-26 acquiring professional services for the purpose of evaluating
121-27 proposed transactions under Section 39.201 and this subchapter.
122-1 (5) "Regulatory assets" means the generation-related
122-2 portion of the Texas jurisdictional portion of the amount reported
122-3 by the electric utility in its 1998 annual report on Securities and
122-4 Exchange Commission Form 10-K as regulatory assets and liabilities,
122-5 offset by the applicable portion of generation-related investment
122-6 tax credits permitted under the Internal Revenue Code of 1986.
122-7 (6) "Transition bonds" means bonds, debentures, notes,
122-8 certificates of participation or of beneficial interest, or other
122-9 evidences of indebtedness or ownership that are issued by an
122-10 electric utility, its successors, or an assignee under a financing
122-11 order, that have a term not longer than 15 years, and that are
122-12 secured by or payable from transition property. If certificates of
122-13 participation, beneficial interest, or ownership are issued,
122-14 references in this subchapter to principal, interest, or premium
122-15 shall refer to comparable amounts under those certificates.
122-16 (7) "Transition charges" means nonbypassable amounts
122-17 to be charged for the use or availability of electric services,
122-18 approved by the commission under a financing order to recover
122-19 qualified costs, that shall be collected by an electric utility,
122-20 its successors, an assignee, or other collection agents as provided
122-21 for in the financing order.
122-22 (8) "Transition property" means the property described
122-23 in Section 39.304.
122-24 Sec. 39.303. FINANCING ORDERS; TERMS. (a) The commission
122-25 shall adopt a financing order, on application of a utility to
122-26 recover the utility's regulatory assets and eligible stranded costs
122-27 under Section 39.201 or 39.262, on making a finding that the total
123-1 amount of revenues to be collected under the financing order is
123-2 less than the revenue requirement that would be recovered over the
123-3 remaining life of the stranded costs using conventional financing
123-4 methods and that the financing order is consistent with the
123-5 standards in Section 39.301.
123-6 (b) The financing order shall detail the amount of
123-7 regulatory assets and stranded costs to be recovered and the period
123-8 over which the nonbypassable transition charges shall be recovered,
123-9 which period may not exceed 15 years.
123-10 (c) Transition charges shall be collected and allocated
123-11 among customers in the same manner as competition transition
123-12 charges under Section 39.201.
123-13 (d) A financing order shall become effective in accordance
123-14 with its terms, and the financing order, together with the
123-15 transition charges authorized in the order, shall thereafter be
123-16 irrevocable and not subject to reduction, impairment, or adjustment
123-17 by further action of the commission, except as permitted by Section
123-18 39.307.
123-19 (e) The commission shall issue a financing order under
123-20 Subsections (a) and (g) not later than 90 days after the utility
123-21 files its request for the financing order.
123-22 (f) A financing order is not subject to rehearing by the
123-23 commission. A financing order may be reviewed by appeal only to a
123-24 Travis County district court by a party to the proceeding filed
123-25 within 15 days after the financing order is signed by the
123-26 commission. The judgment of the district court may be reviewed
123-27 only by direct appeal to the Supreme Court of Texas filed within 15
124-1 days after entry of judgment. All appeals shall be heard and
124-2 determined by the district court and the Supreme Court of Texas as
124-3 expeditiously as possible with lawful precedence over other
124-4 matters. Review on appeal shall be based solely on the record
124-5 before the commission and briefs to the court and shall be limited
124-6 to whether the financing order conforms to the constitution and
124-7 laws of this state and the United States and is within the
124-8 authority of the commission under this chapter.
124-9 (g) At the request of an electric utility, the commission
124-10 may adopt a financing order providing for retiring and refunding
124-11 transition bonds on making a finding that the future transition
124-12 charges required to service the new transition bonds, including
124-13 transaction costs, will be less than the future transition charges
124-14 required to service the transition bonds being refunded. On the
124-15 retirement of the refunded transition bonds, the commission shall
124-16 adjust the related transition charges accordingly.
124-17 Sec. 39.304. PROPERTY RIGHTS. (a) The rights and interests
124-18 of an electric utility or successor under a financing order,
124-19 including the right to impose, collect, and receive transition
124-20 charges authorized in the order, shall be only contract rights
124-21 until they are first transferred to an assignee or pledged in
124-22 connection with the issuance of transition bonds, at which time
124-23 they will become "transition property."
124-24 (b) Transition property shall constitute a present property
124-25 right for purposes of contracts concerning the sale or pledge of
124-26 property, even though the imposition and collection of transition
124-27 charges depends on further acts of the utility or others that have
125-1 not yet occurred. The financing order shall remain in effect and
125-2 the property shall continue to exist for the same period as the
125-3 pledge of the state described in Section 39.310.
125-4 (c) All revenues and collections resulting from transition
125-5 charges shall constitute proceeds only of the transition property
125-6 arising from the financing order.
125-7 Sec. 39.305. NO SETOFF. The interest of an assignee or
125-8 pledgee in transition property and in the revenues and collections
125-9 arising from that property are not subject to setoff, counterclaim,
125-10 surcharge, or defense by the electric utility or any other person
125-11 or in connection with the bankruptcy of the electric utility or any
125-12 other entity. A financing order shall remain in effect and
125-13 unabated notwithstanding the bankruptcy of the electric utility,
125-14 its successors, or assignees.
125-15 Sec. 39.306. NO BYPASS. A financing order shall include
125-16 terms ensuring that the imposition and collection of transition
125-17 charges authorized in the order shall be nonbypassable.
125-18 Sec. 39.307. TRUE-UP. A financing order shall include a
125-19 mechanism requiring that transition charges be reviewed and
125-20 adjusted at least annually, within 45 days of the anniversary date
125-21 of the issuance of the transition bonds, to correct any
125-22 overcollections or undercollections of the preceding 12 months and
125-23 to ensure the expected recovery of amounts sufficient to timely
125-24 provide all payments of debt service and other required amounts and
125-25 charges in connection with the transition bonds.
125-26 Sec. 39.308. TRUE SALE. An agreement by an electric utility
125-27 or assignee to transfer transition property that expressly states
126-1 that the transfer is a sale or other absolute transfer signifies
126-2 that the transaction is a true sale and is not a secured
126-3 transaction and that title, legal and equitable, has passed to the
126-4 entity to which the transition property is transferred. This true
126-5 sale shall apply regardless of whether the purchaser has any
126-6 recourse against the seller, or any other term of the parties'
126-7 agreement, including the seller's retention of an equity interest
126-8 in the transition property, the fact that the electric utility acts
126-9 as the collector of transition charges relating to the transition
126-10 property, or the treatment of the transfer as a financing for tax,
126-11 financial reporting, or other purposes.
126-12 Sec. 39.309. SECURITY INTERESTS; ASSIGNMENT; COMMINGLING;
126-13 DEFAULT. (a) Transition property does not constitute an account
126-14 or general intangible under Section 9.106, Business & Commerce
126-15 Code. The creation, granting, perfection, and enforcement of liens
126-16 and security interests in transition property are governed by this
126-17 section and not by the Business & Commerce Code.
126-18 (b) A valid and enforceable lien and security interest in
126-19 transition property may be created only by a financing order and
126-20 the execution and delivery of a security agreement with a financing
126-21 party in connection with the issuance of transition bonds. The
126-22 lien and security interest shall attach automatically from the time
126-23 that value is received for the bonds and, on perfection through the
126-24 filing of notice with the secretary of state in accordance with the
126-25 rules prescribed under Subsection (d), shall be a continuously
126-26 perfected lien and security interest in the transition property and
126-27 all proceeds of the property, whether accrued or not, shall have
127-1 priority in the order of filing and take precedence over any
127-2 subsequent judicial or other lien creditor. If notice is filed
127-3 within 10 days after value is received for the transition bonds,
127-4 the security interest shall be perfected retroactive to the date
127-5 value was received, otherwise, the security interest shall be
127-6 perfected as of the date of filing.
127-7 (c) Transfer of an interest in transition property to an
127-8 assignee shall be perfected against all third parties, including
127-9 subsequent judicial or other lien creditors, when the financing
127-10 order becomes effective, transfer documents have been delivered to
127-11 the assignee, and a notice of that transfer has been filed in
127-12 accordance with the rules prescribed under Subsection (d),
127-13 provided, however, that if notice of the transfer has not been
127-14 filed in accordance with this subsection within 10 days after the
127-15 delivery of transfer documentation, the transfer of the interest is
127-16 not perfected against third parties until the notice is filed.
127-17 (d) The secretary of state shall implement this section by
127-18 establishing and maintaining a separate system of records for the
127-19 filing of notices under this section and prescribing the rules for
127-20 those filings based on Chapter 9, Business & Commerce Code, adapted
127-21 to this subchapter and using the terms defined in this subchapter.
127-22 (e) The priority of a lien and security interest perfected
127-23 under this section is not impaired by any later modification of the
127-24 financing order under Section 39.307 or by the commingling of funds
127-25 arising from transition charges with other funds, and any other
127-26 security interest that may apply to those funds shall be terminated
127-27 when they are transferred to a segregated account for the assignee
128-1 or a financing party. If transition property has been transferred
128-2 to an assignee, any proceeds of that property shall be held in
128-3 trust for the assignee.
128-4 (f) If a default or termination occurs under the transition
128-5 bonds, the financing parties or their representatives may foreclose
128-6 on or otherwise enforce their lien and security interest in any
128-7 transition property as if they were secured parties under Chapter
128-8 9, Business & Commerce Code, and the commission may order that
128-9 amounts arising from transition charges be transferred to a
128-10 separate account for the financing parties' benefit, to which their
128-11 lien and security interest shall apply. On application by or on
128-12 behalf of the financing parties, a district court of Travis County
128-13 shall order the sequestration and payment to them of revenues
128-14 arising from the transition charges.
128-15 Sec. 39.310. PLEDGE OF STATE. Transition bonds are not a
128-16 debt or obligation of the state and are not a charge on its full
128-17 faith and credit or taxing power. The state pledges, however, for
128-18 the benefit and protection of financing parties and the electric
128-19 utility, that it will not take or permit any action that would
128-20 impair the value of transition property, or, except as permitted by
128-21 Section 39.307, reduce, alter, or impair the transition charges to
128-22 be imposed, collected, and remitted to financing parties, until the
128-23 principal, interest and premium, and any other charges incurred and
128-24 contracts to be performed in connection with the related transition
128-25 bonds have been paid and performed in full. Any party issuing
128-26 transition bonds is authorized to include this pledge in any
128-27 documentation relating to those bonds.
129-1 Sec. 39.311. TAX EXEMPTION. Transactions involving the
129-2 transfer and ownership of transition property and the receipt of
129-3 transition charges are exempt from state and local income, sales,
129-4 franchise, gross receipts, and other taxes or similar charges.
129-5 Sec. 39.312. NOT PUBLIC UTILITY. An assignee or financing
129-6 party may not be considered to be a public utility or person
129-7 providing electric service solely by virtue of the transactions
129-8 described in this subchapter.
129-9 Sec. 39.313. SEVERABILITY. Effective on the date the first
129-10 utility transition bonds are issued under this subchapter, if any
129-11 provision in this title or portion of this title is held to be
129-12 invalid or is invalidated, superseded, replaced, repealed, or
129-13 expires for any reason, that occurrence does not affect the
129-14 validity or continuation of this subchapter, Section 39.201,
129-15 39.251, 39.252, or 39.262, or any part of those provisions, or any
129-16 other provision of this title that is relevant to the issuance,
129-17 administration, payment, retirement, or refunding of transition
129-18 bonds or to any actions of the electric utility, its successors, an
129-19 assignee, a collection agent, or a financing party, which shall
129-20 remain in full force and effect.
129-21 (Sections 39.314-39.350 reserved for expansion
129-22 SUBCHAPTER H. CERTIFICATION AND REGISTRATION; PENALTIES
129-23 Sec. 39.351. REGISTRATION OF POWER GENERATION COMPANIES.
129-24 (a) A person may not generate electricity unless the person is
129-25 registered with the commission as a power generation company in
129-26 accordance with this section. A person may register as a power
129-27 generation company by filing the following information with the
130-1 commission:
130-2 (1) a description of the location of any facility used
130-3 to generate electricity;
130-4 (2) a description of the type of services provided;
130-5 (3) a copy of any information filed with the Federal
130-6 Energy Regulatory Commission in connection with registration with
130-7 that commission; and
130-8 (4) any other information required by commission rule,
130-9 provided that in requiring that information the commission shall
130-10 protect the competitive process in a manner that ensures the
130-11 confidentiality of competitively sensitive information.
130-12 (b) A power generation company shall comply with the
130-13 reliability standards adopted by an independent organization
130-14 certified by the commission to ensure the reliability of the
130-15 regional electrical network for a power region in which the power
130-16 generation company is generating or selling electricity.
130-17 (c) A power generation company may register any time after
130-18 September 1, 2000.
130-19 Sec. 39.352. CERTIFICATION OF RETAIL ELECTRIC PROVIDERS.
130-20 (a) After the date of customer choice, a person, including an
130-21 affiliate of an electric utility, may not provide retail electric
130-22 service in this state unless the person is certified by the
130-23 commission as a retail electric provider, in accordance with this
130-24 section.
130-25 (b) The commission shall issue a certificate to provide
130-26 retail electric service to a person applying for certification who
130-27 demonstrates:
131-1 (1) the financial and technical resources to provide
131-2 continuous and reliable electric service to customers in the area
131-3 for which the certification is sought;
131-4 (2) the managerial and technical ability to supply
131-5 electricity at retail in accordance with customer contracts;
131-6 (3) the resources needed to meet the customer
131-7 protection requirements of this title; and
131-8 (4) ownership or lease of an office located within
131-9 this state for the purpose of providing customer service, accepting
131-10 service of process, and making available in that office books and
131-11 records sufficient to establish the retail electric provider's
131-12 compliance with the requirements of this subchapter.
131-13 (c) A person applying for certification under this section
131-14 shall comply with all applicable customer protection provisions,
131-15 disclosure requirements, and marketing guidelines established by
131-16 the commission and by this title.
131-17 (d) Notwithstanding Subsections (b)(1)-(3), if a retail
131-18 electric provider files with the commission a signed, notarized
131-19 affidavit from each retail customer with which it has contracted to
131-20 provide one megawatt or more of capacity stating that the customer
131-21 is satisfied that the retail electric provider meets the standards
131-22 prescribed by Subsections (b)(1)-(3) and Subsection (c), the retail
131-23 electric provider shall be certified for purposes of serving those
131-24 customers only, so long as it demonstrates that it meets the
131-25 requirements of Subsection (b)(4).
131-26 (e) A retail electric provider may apply for certification
131-27 any time after September 1, 2000.
132-1 (f) The commission shall use any information required in
132-2 this section in a manner that ensures the confidentiality of
132-3 competitively sensitive information.
132-4 (g) If a retail electric provider serves an aggregate load
132-5 in excess of 300 megawatts within this state, not less than five
132-6 percent of the load in megawatt hours must consist of residential
132-7 customers. This requirement applies to an affiliated retail
132-8 electric provider only with respect to load served outside of the
132-9 electric utility's service area, and, in relation to that load, the
132-10 affiliated retail electric provider shall meet the requirements of
132-11 this subsection by serving residential customers outside of the
132-12 electric utility's service area. For the purpose of this
132-13 subsection, the load served by retail electric providers that are
132-14 under common ownership shall be combined. A retail electric
132-15 provider may meet the requirements of this subsection by
132-16 demonstrating on an annual basis that it serves residential load
132-17 amounting to five percent of its total load, by demonstrating that
132-18 another retail electric provider serves sufficient qualifying
132-19 residential load on its behalf, or by paying an amount into the
132-20 system benefit fund equal to $1 multiplied by a number equal to the
132-21 difference between the number of megawatt hours it sold to
132-22 residential customers and the number of megawatt hours it was
132-23 required to sell to such customers, or in the case of an affiliated
132-24 retail electric provider, $1 multiplied by a number equal to the
132-25 difference between the number of megawatt hours sold to residential
132-26 customers outside of the electric utility's service area and the
132-27 number of megawatt hours it was required to sell to such customers
133-1 outside of the electric utility's service area. Qualifying
133-2 residential load may not include customers served by an affiliated
133-3 retail electric provider in its own service area. Each retail
133-4 electric provider shall file reports with the commission that are
133-5 necessary to implement this subsection. This subsection applies
133-6 for 36 months after retail competition begins. The commission
133-7 shall adopt rules to implement this subsection.
133-8 Sec. 39.353. REGISTRATION OF AGGREGATORS. (a) A person may
133-9 not provide aggregation services in the state unless the person is
133-10 registered with the commission as an aggregator.
133-11 (b) In this subchapter, "aggregator" means a person joining
133-12 two or more customers, other than municipalities and political
133-13 subdivision corporations, into a single purchasing unit to
133-14 negotiate the purchase of electricity from retail electric
133-15 providers. Aggregators may not sell or take title to electricity.
133-16 Retail electric providers are not aggregators.
133-17 (c) A person registering under this section shall comply
133-18 with all customer protection provisions, all disclosure
133-19 requirements, and all marketing guidelines established by the
133-20 commission and by this title.
133-21 (d) The commission shall establish terms and conditions it
133-22 determines necessary to regulate the reliability and integrity of
133-23 aggregators in the state by June 1, 2000.
133-24 (e) An aggregator may register any time after September 1,
133-25 2000.
133-26 (f) The commission shall have up to 60 days to process
133-27 applications for registration filed by aggregators.
134-1 (g) Registration is not required of a customer that is
134-2 aggregating loads from its own location or facilities.
134-3 Sec. 39.354. REGISTRATION OF MUNICIPAL AGGREGATORS. (a) A
134-4 municipal aggregator may not provide aggregation services in the
134-5 state unless the municipal aggregator registers with the
134-6 commission.
134-7 (b) In this section, "municipal aggregator" means a person
134-8 authorized by two or more municipal governing bodies to join the
134-9 bodies into a single purchasing unit to negotiate the purchase of
134-10 electricity from retail electric providers.
134-11 (c) A municipal aggregator may register any time after
134-12 September 1, 2000.
134-13 Sec. 39.3545. REGISTRATION OF POLITICAL SUBDIVISION
134-14 AGGREGATORS. (a) A political subdivision aggregator may not
134-15 provide aggregation services in the state unless the political
134-16 subdivision aggregator registers with the commission.
134-17 (b) In this section, "political subdivision aggregator"
134-18 means a person or political subdivision corporation authorized by
134-19 two or more political subdivision governing bodies to join the
134-20 bodies into a single purchasing unit or multiple purchasing units
134-21 to negotiate the purchase of electricity from retail electric
134-22 providers for the facilities of the aggregated political
134-23 subdivisions.
134-24 (c) A political subdivision aggregator may register any time
134-25 after September 1, 2000.
134-26 Sec. 39.355. REGISTRATION OF POWER MARKETERS. A person may
134-27 not sell electric energy at wholesale as a power marketer unless
135-1 the person registers with the commission.
135-2 Sec. 39.356. REVOCATION OF CERTIFICATION. (a) The
135-3 commission may suspend, revoke, or amend a retail electric
135-4 provider's certificate for significant violations of this title or
135-5 the rules adopted under this title or of any reliability standard
135-6 adopted by an independent organization certified by the commission
135-7 to ensure the reliability of a power region's electrical network,
135-8 including the failure to observe any scheduling, operating,
135-9 planning, reliability, or settlement protocols established by the
135-10 independent organization. The commission may also suspend or
135-11 revoke a retail electric provider's certificate if the provider no
135-12 longer has the financial or technical capability to provide
135-13 continuous and reliable electric service.
135-14 (b) The commission may suspend or revoke a power generation
135-15 company's registration for significant violations of this title or
135-16 the rules adopted under this title or of the reliability standards
135-17 adopted by an independent organization certified by the commission
135-18 to ensure the reliability of a power region's electrical network,
135-19 including the failure to observe any scheduling, operating,
135-20 planning, reliability, or settlement protocols established by the
135-21 independent organization.
135-22 (c) The commission may suspend or revoke an aggregator's
135-23 registration for significant violations of this title or of the
135-24 rules adopted under this title.
135-25 Sec. 39.357. ADMINISTRATIVE PENALTY. In addition to the
135-26 suspension, revocation, or amendment of a certification, the
135-27 commission may impose an administrative penalty, as provided by
136-1 Section 15.023, for violations described by Section 39.356.
136-2 Sec. 39.358. LOCAL REGISTRATION OF RETAIL ELECTRIC PROVIDER.
136-3 (a) A municipality may require a retail electric provider to
136-4 register with the municipality as a condition of serving residents
136-5 of the municipality. The municipality may assess a reasonable
136-6 administrative fee for this purpose.
136-7 (b) The municipality may suspend or revoke a retail electric
136-8 provider's registration and operation in that municipality for
136-9 significant violations of this chapter or the rules adopted under
136-10 this chapter.
136-11 (Sections 39.359-39.400 reserved for expansion
136-12 SUBCHAPTER I. PROVISIONS FOR CERTAIN NON-ERCOT UTILITIES
136-13 Sec. 39.401. APPLICABILITY. This subchapter shall apply to
136-14 investor-owned electric utilities operating solely outside of ERCOT
136-15 having fewer than six synchronous interconnections with voltage
136-16 levels above 69 kilovolts systemwide on the effective date of this
136-17 subchapter. This subchapter recognizes that circumstances exist
136-18 that require that areas served by such utilities be treated as
136-19 competitive development areas in which full retail customer choice
136-20 may develop on a more structured schedule than is anticipated for
136-21 the rest of the state. If there are any conflicts between this
136-22 subchapter and any other provisions of this chapter, the provisions
136-23 of this subchapter shall control, but shall not be deemed to limit
136-24 or in any way restrict any provision of this title that governs
136-25 customer protection or quality or reliability of service.
136-26 Sec. 39.402. TRANSITION TO COMPETITION PLAN. All electric
136-27 utilities subject to this subchapter shall file a transition to
137-1 competition plan with the commission not later than December 1,
137-2 2000. This transition to competition plan shall identify how
137-3 utilities subject to this subchapter shall achieve full customer
137-4 choice, including specific alternatives for constructing additional
137-5 transmission facilities, auctioning rights to generation capacity,
137-6 divesting generation capacity, or any other measure necessary for
137-7 the electric utility to meet the requirements of Section 39.152(a)
137-8 and that is consistent with the public interest. The commission
137-9 shall approve, modify, or reject a plan within 180 days after the
137-10 date of a filing under this section. The transition to competition
137-11 plan may be updated or amended as circumstances change, subject to
137-12 commission approval.
137-13 Sec. 39.403. UNBUNDLING. Electric utilities subject to this
137-14 subchapter shall unbundle as required by Section 39.051.
137-15 Sec. 39.404. RATE FREEZE. Electric utilities subject to
137-16 this subchapter shall freeze their rates until January 1, 2002, as
137-17 required by Section 39.052. The price to beat established pursuant
137-18 to Section 39.406 shall become effective January 1, 2002. For
137-19 customer classes other than residential and small commercial
137-20 customers, an electric utility subject to this subchapter may not
137-21 charge rates that are higher than the rates that, on a bundled
137-22 basis, were in effect January 1, 1999, until the region qualifies
137-23 for competition or until rates are reset pursuant to Section
137-24 39.405(c).
137-25 Sec. 39.405. PILOT PROJECT. (a) Electric utilities subject
137-26 to this subchapter shall undertake a pilot project as set forth in
137-27 Section 39.104. As part of approving an electric utility's
138-1 transition to competition plan pursuant to Section 39.402, the
138-2 commission shall extend the duration of the pilot project beyond
138-3 January 1, 2002, and expand the percentage of participation in the
138-4 pilot project beyond the five percent level prescribed by Section
138-5 39.104 based on the market conditions in the region and consistent
138-6 with the level of competition that the region can support. The
138-7 commission shall review the pilot project as circumstances change
138-8 and may adjust the percentage level of participation consistent
138-9 with this subsection.
138-10 (b) An electric utility subject to this subchapter shall
138-11 design any customer choice pilot project it undertakes pursuant to
138-12 Section 39.104 in such a manner that there is a proportional
138-13 participation between customers receiving service from the utility
138-14 located in a service area that is certificated solely to the
138-15 utility and those customers of the utility that are located in a
138-16 multiply certificated area. The utility shall file reports
138-17 pursuant to this section with the commission to permit it to
138-18 monitor whether proportional participation is achieved. Nothing in
138-19 this section requires a utility to design a pilot project to serve
138-20 in multiply certificated areas.
138-21 (c) If any electric utility subject to this subchapter fails
138-22 to meet the requirements of Section 39.152(a), a proceeding under
138-23 Section 36.102 or 36.151 may be filed after January 1, 2006, to set
138-24 its rates effective one year after the date of the filing.
138-25 Sec. 39.406. PRICE TO BEAT. Electric utilities subject to
138-26 this subchapter shall include within their transition to
138-27 competition plans pursuant to Section 39.402 a provision to
139-1 establish the price to beat under Section 39.202. The commission
139-2 may reduce rates by six percent consistent with Section 39.202(a)
139-3 unless it determines that a lesser reduction is necessary and
139-4 consistent with the capital requirements needed to develop the
139-5 infrastructure necessary to facilitate competition among electric
139-6 generators.
139-7 Sec. 39.407. RELEVANT MARKET AND RELATED MATTERS. (a) The
139-8 commission shall certify that the requirements of Section
139-9 39.152(a)(3) are met for electric utilities subject to this
139-10 subchapter, only upon a finding that the total capacity owned and
139-11 controlled by each such electric utility and its affiliates does
139-12 not exceed 20 percent of the total installed generation capacity
139-13 within the constrained geographic region served by each such
139-14 electric utility plus the total available transmission capacity
139-15 capable of delivering firm power and energy to that constrained
139-16 geographic region.
139-17 (b) In the area of a power region served by an electric
139-18 utility subject to this subchapter, if customer choice is
139-19 introduced before the requirements of Section 39.152(a) are met, an
139-20 affiliated retail electric provider of an electric utility subject
139-21 to this subchapter may not compete for retail customers in any area
139-22 of the power region that is within this state and outside of the
139-23 affiliated transmission and distribution utility's certificated
139-24 service area unless the affiliated power generation company makes a
139-25 commitment to maintain and does maintain rates that are based on
139-26 cost of service for any electric cooperative or municipal utility
139-27 that was a wholesale customer on January 1, 1999, and was
140-1 purchasing power at rates that were based on cost of service. This
140-2 subsection requires a power generation company to sell power at
140-3 rates that are based on cost of service, notwithstanding the
140-4 expiration of a contract for that service, until the requirements
140-5 of Section 39.152(a) are met.
140-6 (c) If the requirements of Section 39.152(a) have not been
140-7 met for an electric utility subject to this subchapter, then any
140-8 power generation company in the power region affiliated with an
140-9 electric utility subject to this subchapter shall maintain adequate
140-10 supply and facilities to provide electric service to persons who
140-11 were or would have been retail customers of the affiliated retail
140-12 electric provider on December 31, 2001. The obligation provided by
140-13 this subsection remains in effect until the commission determines
140-14 that the requirements of Section 39.152(a) have been met for the
140-15 region.
140-16 Sec. 39.408. USE OF REVENUES FOR UTILITIES WITH NO STRANDED
140-17 COSTS. In addition to the permitted uses for any positive
140-18 difference under the report required by Section 39.257(b) set forth
140-19 in Section 39.255, during the freeze period ending December 31,
140-20 2001, electric utilities subject to this subchapter may request,
140-21 subject to approval by the commission, to use such positive
140-22 differences to accelerate the amortization of their regulatory
140-23 assets.
140-24 (Sections 39.409-39.900 reserved for expansion
140-25 SUBCHAPTER Z. MISCELLANEOUS PROVISIONS
140-26 Sec. 39.901. SCHOOL FUNDING LOSS MECHANISM. (a) Not later
140-27 than March 1 each year, the comptroller shall certify to the Texas
141-1 Education Agency any property wealth reductions, determined by
141-2 taking the difference between current year and prior year appraisal
141-3 values attributable to electric utility restructuring.
141-4 (b) The Texas Education Agency shall determine the reduction
141-5 of the amount of property taxes recaptured by the state from school
141-6 districts subject to wealth equalization under Chapter 41,
141-7 Education Code, as a result of the property wealth reductions
141-8 certified under Subsection (a) and shall notify the commission of
141-9 the amount necessary to compensate the state for the reduction.
141-10 (c) The Texas Education Agency shall determine the amount
141-11 necessary to compensate school districts for lost revenue resulting
141-12 from the property wealth reductions under Subsection (a) and shall
141-13 notify the commission of this amount. The amounts necessary to
141-14 compensate districts shall be the sum of:
141-15 (1) decreases in the level of funding to which a
141-16 school district is entitled under Chapters 42 and 46, Education
141-17 Code, that are directly attributable to the decline in property
141-18 values caused by utility restructuring; and
141-19 (2) losses of property tax collections incurred by
141-20 school districts that are directly attributable to property value
141-21 declines caused by utility restructuring and that are not accounted
141-22 for under Subdivision (1), including amounts that a school district
141-23 would be entitled to retain under Chapter 41, Education Code.
141-24 (d) The amounts determined by the comptroller and the Texas
141-25 Education Agency under this section, for the purposes of this
141-26 section, are final and may not be appealed.
141-27 (e) Not later than May 1 of each year, the commission shall
142-1 transfer from the system benefit fund to the foundation school fund
142-2 the amounts determined by the Texas Education Agency under
142-3 Subsections (b) and (c). If in any year the system benefit fund is
142-4 insufficient to make the transfer designated by the Texas Education
142-5 Agency, the shortfall shall be included in the projected revenue
142-6 requirement for the system benefit fund the next time the
142-7 commission sets the fee under Section 39.903, and the shortfall
142-8 amount shall be transferred to the Foundation School Program the
142-9 following year. Amounts transferred from the system benefit fund
142-10 under this section may be appropriated only for the support of the
142-11 Foundation School Program and are available, in addition to any
142-12 amounts allocated by the General Appropriations Act, to finance
142-13 actions under Section 41.002(b) or 42.252(e), Education Code.
142-14 (f) The Texas Education Agency shall, on the transfer of
142-15 funds from the system benefit fund to the foundation school fund,
142-16 compensate school districts for losses incurred under Subsection
142-17 (c).
142-18 (g) The commissioner of education and the comptroller shall
142-19 adopt rules necessary to implement this section, including rules
142-20 providing for public input.
142-21 (h) This section is effective through the 2006-2007 school
142-22 year. This section expires August 31, 2007.
142-23 Sec. 39.902. CUSTOMER EDUCATION. (a) On or before January
142-24 1, 2001, the commission shall develop and implement an educational
142-25 program to inform customers, including low-income and
142-26 non-English-speaking customers, about changes in the provision of
142-27 electric service resulting from the opening of the retail electric
143-1 market and the customer choice pilot program under this chapter.
143-2 The educational program shall be neutral and nonpromotional and
143-3 shall provide customers with the information necessary to make
143-4 informed decisions relating to the source and type of electric
143-5 service available for purchase and other information the commission
143-6 considers necessary. The educational program may not be targeted
143-7 to areas served by municipally owned utilities or electric
143-8 cooperatives that have not adopted customer choice. In planning
143-9 and implementing this program, the commission shall consult with
143-10 the office, with the Texas Department of Housing and Community
143-11 Affairs, and with customers of and providers of retail electric
143-12 service. The commission may enter into contracts for professional
143-13 services to carry out the customer education program.
143-14 (b) The commission shall report on the status of the
143-15 educational program, developed and implemented as provided by
143-16 Subsection (a), to the electric utility restructuring legislative
143-17 oversight committee on or before December 1, 2001.
143-18 (c) After the opening of the retail electric market, the
143-19 commission shall conduct ongoing customer education designed to
143-20 help customers make informed choices of electric services and
143-21 retail electric providers. As part of ongoing education, the
143-22 commission may provide customers information concerning specific
143-23 retail electric providers, including instances of complaints
143-24 against them and records relating to quality of customer service.
143-25 Sec. 39.903. SYSTEM BENEFIT FUND. (a) The commission shall
143-26 establish the system benefit fund.
143-27 (b) The system benefit fund is financed by a nonbypassable
144-1 fee set by the commission in an amount not to exceed 50 cents per
144-2 megawatt hour, provided that, in any year, the sum of the revenue
144-3 collected through the nonbypassable fee and any retained surplus in
144-4 the system benefit fund may not exceed 125 percent of the projected
144-5 revenue requirements for the fund.
144-6 (c) The nonbypassable fee may not be imposed on the retail
144-7 electric customers of a municipally owned utility or electric
144-8 cooperative before the sixth month preceding the date on which the
144-9 utility or cooperative implements customer choice. On request by a
144-10 municipally owned utility or electric cooperative, the commission
144-11 shall reduce the nonbypassable fee imposed on retail electric
144-12 customers served by the municipally owned utility or electric
144-13 cooperative by an amount equal to the amount provided by the
144-14 municipally owned utility or electric cooperative or its ratepayers
144-15 for local low-income programs and local programs that educate
144-16 customers about the retail electric market in a neutral and
144-17 nonpromotional manner.
144-18 (d) Not later than March 1 of each year, the commission
144-19 shall review and approve system benefit fund accounts, projected
144-20 revenue requirements, and proposed nonbypassable fees.
144-21 (e) The system benefit fund shall provide funding solely for
144-22 the following regulatory purposes:
144-23 (1) customer education programs;
144-24 (2) programs to assist low-income electric customers
144-25 provided by Subsections (f)-(k); and
144-26 (3) the school funding loss mechanism provided by
144-27 Section 39.901.
145-1 (f) Notwithstanding Section 39.106(b), the commission shall
145-2 adopt rules regarding programs to assist low-income electric
145-3 customers. The programs may not be targeted to areas served by
145-4 municipally owned utilities or electric cooperatives that have not
145-5 adopted customer choice. The programs shall include:
145-6 (1) reduced electric rates as provided by Subsections
145-7 (g)-(k); and
145-8 (2) targeted energy efficiency programs to be
145-9 administered by the Texas Department of Housing and Community
145-10 Affairs in coordination with existing weatherization programs.
145-11 (g) Until January 1, 2002, an electric utility may not
145-12 reduce, in any manner, programs already offered to assist
145-13 low-income electric customers.
145-14 (h) Following the introduction of customer choice, the
145-15 commission shall adopt rules to determine a reduced rate to be
145-16 discounted off the standard retail service package as approved by
145-17 the commission under Section 39.106, or the price to beat
145-18 established by Section 39.202, whichever is lower.
145-19 (i) The commission may provide for a reduced rate:
145-20 (1) during periods when severe weather occurs or is
145-21 likely to occur; or
145-22 (2) for customers living in all-electric dwelling
145-23 units or who depend on electrically operated medical equipment.
145-24 (j) A retail electric provider not subject to the price to
145-25 beat shall be reimbursed for the difference between the reduced
145-26 rate and the rate established under Section 39.106. A retail
145-27 electric provider who is subject to the price to beat shall be
146-1 reimbursed for the difference between the reduced rate and the
146-2 price to beat.
146-3 (k) A retail electric provider is prohibited from charging
146-4 the customer a fee for participation in the reduced rate program.
146-5 (l) For the purposes of this section, a "low-income electric
146-6 customer" is an electric customer who is a qualifying low-income
146-7 consumer as defined by the commission.
146-8 Sec. 39.904. GOAL FOR RENEWABLE ENERGY. (a) It is the
146-9 intent of the legislature that by January 1, 2009, an additional
146-10 2,000 megawatts of generating capacity from renewable technologies
146-11 will have been installed in this state. The cumulative installed
146-12 renewable capacity in this state shall total 1,280 megawatts by
146-13 January 1, 2003, 1,730 megawatts by January 1, 2005, 2,280
146-14 megawatts by January 1, 2007, and 2,880 megawatts by January 1,
146-15 2009.
146-16 (b) The commission shall establish a renewable energy
146-17 credits trading program. Any retail electric provider, municipally
146-18 owned utility, or electric cooperative that does not satisfy the
146-19 requirements of Subsection (a) by directly owning or purchasing
146-20 capacity using renewable energy technologies shall purchase
146-21 sufficient renewable energy credits to satisfy the requirements by
146-22 holding renewable energy credits in lieu of capacity from renewable
146-23 energy technologies.
146-24 (c) Not later than January 1, 2000, the commission shall
146-25 adopt rules necessary to administer and enforce this section. At a
146-26 minimum, the rules shall:
146-27 (1) establish the minimum annual renewable energy
147-1 requirement for each retail electric provider, municipally owned
147-2 utility, and electric cooperative operating in this state in a
147-3 manner reasonably calculated by the commission to produce, on a
147-4 statewide basis, compliance with the requirement prescribed by
147-5 Subsection (a); and
147-6 (2) specify reasonable performance standards that all
147-7 renewable capacity additions must meet to count against the
147-8 requirement prescribed by Subsection (a) and that:
147-9 (A) are designed and operated so as to maximize
147-10 the energy output from the capacity additions in accordance with
147-11 then-current industry standards; and
147-12 (B) encourage the development, construction, and
147-13 operation of new renewable energy projects at those sites in this
147-14 state that have the greatest economic potential for capture and
147-15 development of this state's environmentally beneficial renewable
147-16 resources.
147-17 (d) In this section, "renewable energy technology" means any
147-18 technology that exclusively relies on an energy source that is
147-19 naturally regenerated over a short time and derived directly from
147-20 the sun, indirectly from the sun, or from moving water or other
147-21 natural movements and mechanisms of the environment. Renewable
147-22 energy technologies include those that rely on energy derived
147-23 directly from the sun, on wind, geothermal, hydroelectric, wave, or
147-24 tidal energy, or on biomass or biomass-based waste products,
147-25 including landfill gas. A renewable energy technology does not
147-26 rely on energy resources derived from fossil fuels, waste products
147-27 from fossil fuels, or waste products from inorganic sources.
148-1 (e) A municipally owned utility operating a gas distribution
148-2 system may credit toward satisfaction of the requirements of this
148-3 section any production or acquisition of landfill gas supplied to
148-4 the gas distribution system, based on conversion to kilowatt hours
148-5 of the thermal energy content in British thermal units of the
148-6 renewable source and using for the conversion factor the annual
148-7 heat rate of the most efficient gas-fired unit of the combined
148-8 utility's electric system as measured in British thermal units per
148-9 kilowatt hour and using the British thermal unit measurement based
148-10 on the higher heating value measurement.
148-11 Sec. 39.9044. GOAL FOR NATURAL GAS. (a) It is the intent
148-12 of the legislature that 50 percent of the megawatts of generating
148-13 capacity installed in this state after January 1, 2000, use natural
148-14 gas. To the extent permitted by law, the commission shall establish
148-15 a program to encourage utilities to comply with this section by
148-16 using natural gas produced in this state as the preferential fuel.
148-17 This section does not apply to generating capacity for renewable
148-18 technologies.
148-19 (b) The commission shall establish a natural gas energy
148-20 credits trading program. Any power generation company, municipally
148-21 owned utility, or electric cooperative that does not satisfy the
148-22 requirements of Subsection (a) by directly owning or purchasing
148-23 capacity using natural gas technologies shall purchase sufficient
148-24 natural gas energy credits to satisfy the requirements by holding
148-25 natural gas energy credits in lieu of capacity from natural gas
148-26 energy technologies.
148-27 (c) Not later than January 1, 2000, the commission shall
149-1 adopt rules necessary to administer and enforce this section and to
149-2 perform any necessary studies in cooperation with the Railroad
149-3 Commission of Texas. At a minimum, the rules shall:
149-4 (1) establish the minimum annual natural gas
149-5 generation requirement for each power generation company,
149-6 municipally owned utility, and electric cooperative operating in
149-7 this state in a manner reasonably calculated by the commission to
149-8 produce, on a statewide basis, compliance with the requirement
149-9 prescribed by Subsection (a); and
149-10 (2) specify reasonable performance standards that all
149-11 natural gas capacity additions must meet to count against the
149-12 requirement prescribed by Subsection (a) and that:
149-13 (A) are designed and operated so as to maximize
149-14 the energy output from the capacity additions in accordance with
149-15 then-current industry standards and best industry standards; and
149-16 (B) encourage the development, construction, and
149-17 operation of new natural gas energy projects at those sites in this
149-18 state that have the greatest economic potential for capture and
149-19 development of this state's environmentally beneficial natural gas
149-20 resources.
149-21 (d) The commission, with the assistance of the Railroad
149-22 Commission of Texas, shall adopt rules allowing and encouraging
149-23 retail electric providers and municipally owned utilities and
149-24 electric cooperatives that have adopted customer choice to market
149-25 electricity generated using natural gas produced in this state as
149-26 environmentally beneficial. The rules shall allow a provider,
149-27 municipally owned utility, or cooperative to:
150-1 (1) emphasize that natural gas produced in this state
150-2 is the cleanest-burning fossil fuel; and
150-3 (2) label the electricity generated using natural gas
150-4 produced in this state as "green" electricity.
150-5 (e) In this section, "natural gas technology" means any
150-6 technology that exclusively relies on natural gas as a primary fuel
150-7 source.
150-8 Sec. 39.9048. NATURAL GAS FUEL. It is the intent of the
150-9 legislature that:
150-10 (1) the cost of generating electricity remain as low
150-11 as possible;
150-12 (2) the state establish and publicize a program to
150-13 keep the costs of fuel, such as natural gas, used for generating
150-14 electricity low; and
150-15 (3) as part of the program relating to natural gas
150-16 established under Subdivision (1), the commission work with the
150-17 comptroller in implementing, administering, and publicizing the tax
150-18 refunds and credits provided by Sections 191.0825 and 201.059, Tax
150-19 Code.
150-20 Sec. 39.905. GOAL FOR ENERGY EFFICIENCY. (a) It is the
150-21 intent of the legislature that:
150-22 (1) electric utilities administer customer information
150-23 and energy savings incentive programs in a market-neutral,
150-24 nondiscriminatory manner, but not offer underlying competitive
150-25 services;
150-26 (2) all customers, in all customer classes, have a
150-27 choice of and access to energy efficiency alternatives and other
151-1 choices from the market that allows each customer to reduce energy
151-2 consumption and reduce energy costs;
151-3 (3) electric utilities be allowed to offer loans at
151-4 below-market interest rates for energy efficiency investments,
151-5 other energy efficiency market transformation programs that result
151-6 in below-market cost to the customer, and grants and other special
151-7 programs to address the needs of small businesses, tenants,
151-8 low-income consumers, and other customer groups not served by
151-9 market-based incentive programs; and
151-10 (4) electric utilities acquire, through market-based
151-11 standard offer programs or limited targeted market transformation
151-12 programs, additional cost-effective energy efficiency equivalent to
151-13 at least 25 percent of each year's annual growth in demand.
151-14 (b) The commission shall provide oversight and adopt rules,
151-15 procedures, and penalties, as necessary, to ensure that the intent
151-16 of this section is achieved.
151-17 Sec. 39.906. DISPLACED WORKERS. In order to mitigate
151-18 potential negative impacts on utility personnel directly affected
151-19 by electric industry restructuring, the commission shall allow the
151-20 recovery of reasonable employee related transition costs incurred
151-21 and projected for severance, retraining, early retirement,
151-22 outplacement, and related expenses for the employees.
151-23 Sec. 39.907. LEGISLATIVE OVERSIGHT COMMITTEE. (a) In this
151-24 section, "committee" means the electric utility restructuring
151-25 legislative oversight committee.
151-26 (b) The committee is composed of six members as follows:
151-27 (1) the chair of the Senate Committee on Economic
152-1 Development and the chair of the House Committee on State Affairs,
152-2 who shall serve as joint chairs of the committee;
152-3 (2) two members of the senate appointed by the
152-4 lieutenant governor; and
152-5 (3) two members of the house of representatives
152-6 appointed by the speaker of the house of representatives.
152-7 (c) An appointed member of the committee serves at the
152-8 pleasure of the appointing official.
152-9 (d) The committee is subject to Chapter 325, Government Code
152-10 (Texas Sunset Act). Unless continued in existence as provided by
152-11 that chapter, the committee is abolished September 1, 2005.
152-12 (e) The committee shall:
152-13 (1) meet at least annually with the commission;
152-14 (2) receive information about rules relating to
152-15 electric utility restructuring proposed by the commission and may
152-16 submit comments to the commission on those proposed rules;
152-17 (3) review recommendations for legislation proposed by
152-18 the commission; and
152-19 (4) monitor the effectiveness of electric utility
152-20 restructuring, including the fairness of rates, the reliability of
152-21 service, and the effect of stranded costs, market power, and
152-22 regulation on the normal forces of competition.
152-23 (f) The committee may request reports and other information
152-24 from the commission as necessary to carry out this section.
152-25 (g) Not later than November 15 of each even-numbered year,
152-26 the committee shall report to the governor, lieutenant governor,
152-27 and speaker of the house of representatives on the committee's
153-1 activities under Subsection (e). The report shall include:
153-2 (1) an analysis of any problems caused by electric
153-3 utility restructuring; and
153-4 (2) recommendations of any legislative action
153-5 necessary to address those problems and to further retail
153-6 competition within the electric power industry.
153-7 Sec. 39.908. EFFECT OF SUNSET PROVISION. (a) If the
153-8 commission is abolished and the other provisions of this title
153-9 expire as provided by Chapter 325, Government Code (Texas Sunset
153-10 Act), this subchapter, including the provisions of this title
153-11 referred to in this subchapter, continues in full force and effect
153-12 and does not expire.
153-13 (b) The authorities, duties, and functions of the commission
153-14 under this chapter shall be performed and carried out by a
153-15 successor agency to be designated by the legislature before
153-16 abolishment of the commission or, if the legislature does not
153-17 designate the successor, by the secretary of state.
153-18 CHAPTER 40. COMPETITION FOR MUNICIPALLY OWNED UTILITIES
153-19 AND RIVER AUTHORITIES
153-20 SUBCHAPTER A. GENERAL PROVISIONS
153-21 Sec. 40.001. APPLICABLE LAW. (a) Notwithstanding any other
153-22 provision of law, except Sections 39.155, 39.157(e), 39.203,
153-23 39.903, and 39.904, this chapter governs the transition to and the
153-24 establishment of a fully competitive electric power industry for
153-25 municipally owned utilities. With respect to the regulation of
153-26 municipally owned utilities, this chapter controls over any other
153-27 provision of this title, except for sections in which the term
154-1 "municipally owned utility" is specifically used.
154-2 (b) Except as specifically provided in this subsection,
154-3 Chapter 39 does not apply to a river authority operating a steam
154-4 generating plant on or before January 1, 1999, or a corporation
154-5 authorized by Chapter 245, Acts of the 67th Legislature, Regular
154-6 Session, 1981 (Article 717p, Vernon's Texas Civil Statutes), or
154-7 Section 32.053. A river authority operating a steam generating
154-8 plant on or before January 1, 1999, is subject to Sections
154-9 39.051(a)-(c), 39.108, 39.155, 39.157(e), and 39.203.
154-10 (c) For purposes of Section 39.051, hydroelectric assets may
154-11 not be deemed to be generating assets, and the transfer of
154-12 generating assets to a corporation authorized by Chapter 245, Acts
154-13 of the 67th Legislature, Regular Session, 1981 (Article 717p,
154-14 Vernon's Texas Civil Statutes), satisfies the requirements of
154-15 Section 39.051.
154-16 (d) Accommodation shall be made in the code of conduct
154-17 established under Section 39.157(e) for the provisions of Chapter
154-18 245, Acts of the 67th Legislature, Regular Session, 1981 (Article
154-19 717p, Vernon's Texas Civil Statutes), and the commission may not
154-20 prohibit a river authority and any related corporation from sharing
154-21 officers, directors, employees, equipment, and facilities or from
154-22 providing goods or services to each other at cost without the need
154-23 for a competitive bid.
154-24 Sec. 40.002. DEFINITION. For purposes of this chapter,
154-25 "body vested with the power to manage and operate a municipally
154-26 owned utility" shall mean a body created in accordance with Article
154-27 1115 or 1115a, Revised Statutes, or by municipal charter.
155-1 Sec. 40.003. SECURITIZATION. (a) Municipally owned
155-2 utilities and river authorities may adopt and use securitization
155-3 provisions having the effect of the provisions provided by
155-4 Subchapter G, Chapter 39, to recover through appropriate charges
155-5 their stranded costs, at a recovery level deemed appropriate by the
155-6 municipally owned utility or river authority up to 100 percent,
155-7 under rules and procedures that shall be established:
155-8 (1) in the case of a municipally owned utility, by the
155-9 municipal governing body or a body vested with the power to manage
155-10 and operate the municipally owned utility, including procedures
155-11 providing for rate orders of the governing body having the effect
155-12 of financing orders, providing for a separate nonbypassable charge
155-13 approved by the governing body, in the nature of a transition
155-14 charge, to be collected from all retail electric customers of the
155-15 municipally owned utility, identified as of a date determined by
155-16 the governing body, to fund the recovery of the stranded costs of
155-17 the municipally owned utility and of all reasonable related
155-18 expenses, as determined by the governing body, and providing for
155-19 the issuance of bonds, having a term and other characteristics as
155-20 determined by the governing body, as necessary to recover the
155-21 amount deemed appropriate by the governing body through
155-22 securitization financing; and
155-23 (2) in the case of a river authority, by the
155-24 commission.
155-25 (b) In order to implement securitization financing under the
155-26 rules and procedures established by and for a municipally owned
155-27 utility under Subsection (a)(1), municipalities are expressly
156-1 authorized and empowered to issue bonds, notes, or other
156-2 obligations, including refunding bonds, payable from and secured by
156-3 a lien on and pledge of the revenues collected under an order of
156-4 the governing body of the municipality, and the bonds shall be
156-5 issued, without an election or any requirement of giving notice of
156-6 intent to issue the bonds, by ordinance adopted by the governing
156-7 body of the municipality, in the form and manner and sold on a
156-8 negotiated basis or on receipt of bids and on the terms and
156-9 conditions as shall be determined by the governing body of the
156-10 municipality.
156-11 (c) Bonds issued under the authority conferred by
156-12 Subsections (a)(1) and (2) and Subsection (b) may be issued in the
156-13 form and manner, with or without credit enhancement or liquidity
156-14 enhancement and using the procedures as provided in the Bond
156-15 Procedures Act of 1981 (Article 717k-6, Vernon's Texas Civil
156-16 Statutes) or other laws applicable to the issuance of bonds,
156-17 including Chapter 656, Acts of the 68th Legislature, Regular
156-18 Session, 1983 (Article 717q, Vernon's Texas Civil Statutes),
156-19 Chapter 503, Acts of the 54th Legislature, Regular Session, 1955
156-20 (Article 717k, Vernon's Texas Civil Statutes), and Chapter 642,
156-21 Acts of the 65th Legislature, Regular Session, 1977 (Article
156-22 1118n-12, Vernon's Texas Civil Statutes) as if those laws were
156-23 fully restated in this section and made a part of this section for
156-24 all purposes, and a municipality or river authority shall have the
156-25 right and authority to use those other laws, notwithstanding any
156-26 applicable restrictions contained in those laws, to the extent
156-27 convenient or necessary to carry out any power or authority,
157-1 express or implied, granted under this section, in the issuance of
157-2 bonds by a municipality or river authority in connection with
157-3 securitization financing. This section is wholly sufficient
157-4 authority for the issuance of bonds, notes, or other obligations,
157-5 including refunding bonds, and the performance of the other
157-6 authorized acts and procedures, without reference to any other laws
157-7 or any restrictions or limitations contained in those laws. To the
157-8 extent of any conflict or inconsistency between the provisions of
157-9 this authorization and any provisions of any other law or home-rule
157-10 charter, the authorization and power to issue bonds conferred on
157-11 municipalities or river authorities under this section shall
157-12 prevail and control.
157-13 (d) The rules and procedures for securitization established
157-14 by the commission under Subsection (a)(2) shall include procedures
157-15 for the recovery of qualified costs under the terms of a financing
157-16 order adopted by the governing body of the river authority.
157-17 (e) The rules and procedures for securitization established
157-18 by the commission under Subsection (a)(2) shall include rules and
157-19 procedures for the issuance of transition bonds. Findings made by
157-20 the governing body of a river authority in a financing order issued
157-21 under the rules and procedures described in this subsection shall
157-22 be conclusive, and any nonbypassable transition charge incorporated
157-23 in the rate order to recover the principal, interest, and all
157-24 reasonable expenses associated with any transition bonds shall
157-25 constitute property rights, as described in Subchapter G, Chapter
157-26 39, and otherwise conform in all material respects to the
157-27 nonbypassable transition charges provided by Subchapter G, Chapter
158-1 39.
158-2 (f) The rules and procedures established under this section
158-3 shall be consistent with other law applicable to municipally owned
158-4 utilities and river authorities and with the terms of any
158-5 resolutions, orders, charter provisions, or ordinances authorizing
158-6 outstanding bonds or other indebtedness of the municipalities or
158-7 river authorities.
158-8 Sec. 40.004. JURISDICTION OF COMMISSION. Except as
158-9 specifically otherwise provided in this chapter, the commission has
158-10 jurisdiction over municipally owned utilities only for the
158-11 following purposes:
158-12 (1) to regulate wholesale transmission rates and
158-13 service, including terms of access, to the extent provided by
158-14 Subchapter A, Chapter 35;
158-15 (2) to regulate certification of retail service areas
158-16 to the extent provided by Chapter 37;
158-17 (3) to regulate rates on appeal under Subchapters D
158-18 and E, Chapter 33, subject to Section 40.051(c);
158-19 (4) to establish a code of conduct as provided by
158-20 Section 39.157(e) applicable to anticompetitive activities and to
158-21 affiliate activities limited to structurally unbundled affiliates
158-22 of municipally owned utilities, subject to Section 40.054;
158-23 (5) to establish terms and conditions for open access
158-24 to transmission and distribution facilities for municipally owned
158-25 utilities providing customer choice, as provided by Section 39.203;
158-26 (6) to require collection of the nonbypassable fee
158-27 established under Section 39.903(b) and to administer the renewable
159-1 energy credits program under Section 39.904(b); and
159-2 (7) to require reports of municipally owned utility
159-3 operations only to the extent necessary to:
159-4 (A) enable the commission to determine the
159-5 aggregate load and energy requirements of the state and the
159-6 resources available to serve that load; or
159-7 (B) enable the commission to determine
159-8 information relating to market power as provided by Section 39.155.
159-9 (Sections 40.005-40.050 reserved for expansion
159-10 SUBCHAPTER B. MUNICIPALLY OWNED UTILITY CHOICE
159-11 Sec. 40.051. GOVERNING BODY DECISION. (a) The municipal
159-12 governing body or a body vested with the power to manage and
159-13 operate a municipally owned utility has the discretion to decide
159-14 when or if the municipally owned utility will provide customer
159-15 choice.
159-16 (b) Municipally owned utilities may choose to participate in
159-17 customer choice at any time on or after January 1, 2002, by
159-18 adoption of an appropriate resolution of the municipal governing
159-19 body or a body vested with power to manage and operate the
159-20 municipally owned utility. The decision to participate in customer
159-21 choice by the adoption of a resolution is irrevocable.
159-22 (c) After a decision to offer customer choice has been made,
159-23 Subchapters D and E, Chapter 33, do not apply to any action taken
159-24 under this chapter.
159-25 Sec. 40.052. UTILITY NOT OFFERING CUSTOMER CHOICE. (a) A
159-26 municipally owned utility that has not chosen to participate in
159-27 customer choice may not offer electric energy at unregulated prices
160-1 directly to retail customers outside its certificated retail
160-2 service area.
160-3 (b) A municipally owned utility under Subsection (a) retains
160-4 the right to offer and provide a full range of customer service and
160-5 pricing programs to the customers within its certificated area and
160-6 to purchase and sell electric energy at wholesale without
160-7 geographic restriction.
160-8 Sec. 40.053. RETAIL CUSTOMER'S RIGHT OF CHOICE. (a) If a
160-9 municipally owned utility chooses to participate in customer
160-10 choice, after that choice all retail customers served by the
160-11 municipally owned utility within the certificated retail service
160-12 area of the municipally owned utility shall have the right of
160-13 customer choice consistent with the provisions of this chapter, and
160-14 the municipally owned utility shall provide open access for retail
160-15 service.
160-16 (b) Notwithstanding Section 39.107, the metering function
160-17 may not be deemed a competitive service for customers of the
160-18 municipally owned utility within that service area and may, at the
160-19 option of the municipally owned utility, continue to be offered by
160-20 the municipally owned utility as sole provider.
160-21 (c) On its initiation of customer choice, a municipally
160-22 owned utility shall designate itself or another entity as the
160-23 provider of last resort for customers within the municipally owned
160-24 utility's certificated service area as that area existed on the
160-25 date of the utility's initiation of customer choice. The
160-26 municipally owned utility shall fulfill the role of default
160-27 provider of last resort in the event no other entity is available
161-1 to act in that capacity.
161-2 (d) If a customer is unable to obtain service from a retail
161-3 electric provider, on request by the customer, the provider of last
161-4 resort shall offer the customer the standard retail service package
161-5 for the appropriate customer class, with no interruption of
161-6 service, at a fixed, nondiscountable rate that is at least
161-7 sufficient to cover the reasonable costs of providing that service,
161-8 as approved by the governing body of the municipally owned utility
161-9 that has the authority to set rates.
161-10 (e) The governing body of a municipally owned utility may
161-11 establish the procedures and criteria for designating the provider
161-12 of last resort and may redesignate the provider of last resort
161-13 according to a schedule it considers appropriate.
161-14 Sec. 40.054. SERVICE OUTSIDE AREA. (a) A municipally owned
161-15 utility participating in customer choice shall have the right to
161-16 offer electric energy and related services at unregulated prices
161-17 directly to retail customers who have customer choice without
161-18 regard to geographic location.
161-19 (b) In providing service under Subsection (a) to retail
161-20 customers outside its certificated retail service area as that area
161-21 exists on the date of adoption of customer choice, a municipally
161-22 owned utility is subject to the commission's rules establishing a
161-23 code of conduct regulating anticompetitive practices.
161-24 (c) For municipally owned utilities participating in
161-25 customer choice, the commission shall have jurisdiction to
161-26 establish terms and conditions, but not rates, for access by other
161-27 retail electric providers to the municipally owned utility's
162-1 distribution facilities.
162-2 (d) Accommodation shall be made in the commission's terms
162-3 and conditions for access and in the code of conduct for specific
162-4 legal requirements imposed by state or federal law applicable to
162-5 municipally owned utilities.
162-6 (e) The commission does not have jurisdiction to require
162-7 unbundling of services or functions of, or to regulate the recovery
162-8 of stranded investment of, a municipally owned utility or, except
162-9 as provided by this section, jurisdiction with respect to the
162-10 rates, terms, and conditions of service for retail customers of a
162-11 municipally owned utility within the utility's certificated service
162-12 area.
162-13 (f) A municipally owned utility shall maintain separate
162-14 books and records of its operations from those of the operations of
162-15 any affiliate.
162-16 Sec. 40.055. JURISDICTION OF MUNICIPAL GOVERNING BODY. (a)
162-17 The municipal governing body or a body vested with the power to
162-18 manage and operate a municipally owned utility has exclusive
162-19 jurisdiction to:
162-20 (1) set all terms of access, conditions, and rates
162-21 applicable to services provided by the municipally owned utility,
162-22 subject to Sections 40.054 and 40.056, including nondiscriminatory
162-23 and comparable rates for distribution but excluding wholesale
162-24 transmission rates, terms of access, and conditions for wholesale
162-25 transmission service set by the commission under this subtitle,
162-26 provided that the rates for distribution access established by the
162-27 municipal governing body shall be comparable to the distribution
163-1 access rates that apply to the municipally owned utility and the
163-2 municipally owned utility's affiliates;
163-3 (2) determine whether to unbundle any energy-related
163-4 activities and, if the municipally owned utility chooses to
163-5 unbundle, whether to do so structurally or functionally;
163-6 (3) reasonably determine the amount of the municipally
163-7 owned utility's stranded investment;
163-8 (4) establish nondiscriminatory transition charges
163-9 reasonably designed to recover the stranded investment over an
163-10 appropriate period of time, provided that recovery of retail
163-11 stranded costs shall be from all existing or future retail
163-12 customers, including the facilities, premises, and loads of those
163-13 retail customers, within the utility's geographical certificated
163-14 service area as it existed on May 1, 1999;
163-15 (5) determine the extent to which the municipally
163-16 owned utility will provide various customer services at the
163-17 distribution level, including other services that the municipally
163-18 owned utility is legally authorized to provide, or will accept the
163-19 services from other providers;
163-20 (6) manage and operate the municipality's electric
163-21 utility systems, including exercise of control over resource
163-22 acquisition and any related expansion programs;
163-23 (7) establish and enforce service quality and
163-24 reliability standards and consumer safeguards designed to protect
163-25 retail electric customers, including safeguards that will
163-26 accomplish the objectives of Sections 39.101(a) and (b), consistent
163-27 with this chapter;
164-1 (8) determine whether a base rate reduction is
164-2 appropriate for the municipally owned utility;
164-3 (9) determine any other utility matters that the
164-4 municipal governing body or body vested with power to manage and
164-5 operate the municipally owned utility believes should be included;
164-6 and
164-7 (10) make any other decisions affecting the
164-8 municipally owned utility's participation in customer choice that
164-9 are not inconsistent with this chapter.
164-10 (b) In multiply certificated areas, a retail customer,
164-11 including a retail customer of an electric cooperative or a
164-12 municipally owned utility, may not avoid stranded cost recovery
164-13 charges by switching to another electric utility, electric
164-14 cooperative, or municipally owned utility.
164-15 Sec. 40.056. ANTICOMPETITIVE ACTIONS. (a) If, on complaint
164-16 by a retail electric provider, the commission finds that a
164-17 municipal rule, action, or order relating to customer choice is
164-18 anticompetitive or does not provide other retail electric providers
164-19 with nondiscriminatory terms and conditions of access to
164-20 distribution facilities or customers within the municipally owned
164-21 utility's certificated retail service area that are comparable to
164-22 the municipally owned utility's and its affiliates' terms and
164-23 conditions of access to distribution facilities or customers, the
164-24 commission shall notify the municipally owned utility.
164-25 (b) The municipally owned utility shall have three months to
164-26 cure the anticompetitive or noncompliant behavior described in
164-27 Subsection (a), following opportunity for hearing on the complaint.
165-1 If the rule, action, or order is not fully remedied within that
165-2 time, the commission may prohibit the municipally owned utility or
165-3 affiliate from providing retail service outside its certificated
165-4 retail service area until the rule, action, or order is remedied.
165-5 Sec. 40.057. BILLING. (a) A municipally owned utility that
165-6 opts for customer choice may continue to bill directly electric
165-7 customers located in its certificated retail service area, as that
165-8 area exists on the date of adoption of customer choice, for all
165-9 transmission and distribution services. The municipally owned
165-10 utility may also bill directly for generation services and customer
165-11 services provided by the municipally owned utility to those
165-12 customers.
165-13 (b) A municipally owned utility that opts for customer
165-14 choice may not adopt anticompetitive billing practices that would
165-15 discourage customers in its service area from choosing a retail
165-16 electric provider.
165-17 (c) A customer that is being provided wires service by a
165-18 municipally owned utility at distribution or transmission voltage
165-19 and that is served by a retail electric provider for retail service
165-20 has the option of being billed directly by each service provider or
165-21 to receive a single bill for distribution, transmission, and
165-22 generation services from the municipally owned utility.
165-23 Sec. 40.058. TARIFFS FOR OPEN ACCESS. A municipally owned
165-24 utility that owns or operates transmission and distribution
165-25 facilities shall file with the commission tariffs implementing the
165-26 open access rules established by the commission under Section
165-27 39.203 and shall file with the commission the rates for open access
166-1 on distribution facilities as set by the municipal regulatory
166-2 authority, before the 90th day preceding the date the utility
166-3 offers customer choice. The commission does not have authority to
166-4 determine the rates for distribution access service for a
166-5 municipally owned utility.
166-6 Sec. 40.059. MUNICIPAL POWER AGENCY; RECOVERY OF STRANDED
166-7 COSTS. (a) In this section, "member city" means a municipality
166-8 that participated in the creation of a municipal power agency
166-9 formed under Chapter 163 by the adoption of a concurrent resolution
166-10 by the municipality on or before August 1, 1975.
166-11 (b) After a member city adopts a resolution choosing to
166-12 participate in customer choice under Section 40.051(b), a member
166-13 city may include stranded costs described in Subsection (c) in its
166-14 distribution costs and may recover those costs through a
166-15 nonbypassable charge. The nonbypassable charge shall be as
166-16 determined by the member city's governing body and may be spread
166-17 over 16 years.
166-18 (c) The stranded costs that may be recovered under this
166-19 section are those costs that were determined by the commission and
166-20 stated in the commission's April 1998 Report to the Texas Senate
166-21 Interim Committee on Electric Utility Restructuring entitled
166-22 "Potentially Strandable Investment (ECOM) Report: 1998 Update" and
166-23 specifically stated in the report at Appendix A (ECOM Estimates
166-24 Including the Effects of Transition Plans) under the commission
166-25 base case benchmark base market price for the year 2002.
166-26 (d) The stranded cost amounts described in this section may
166-27 not be included in the generation costs used in setting rates by
167-1 the member city's governing body.
167-2 (e) The provisions of this section are cumulative of all
167-3 other provisions of this chapter, and nothing in this section shall
167-4 be construed to limit or restrict the application of any provision
167-5 of this chapter to the member cities.
167-6 (f) The municipal power agency shall extinguish the agency's
167-7 indebtedness by sale of the electric facility to one or more
167-8 purchasers, by way of a sale through the issuance of taxable or
167-9 tax-exempt debt to the member cities, or by any other method. The
167-10 agency shall set as an objective the extinguishment of the agency's
167-11 debt by September 1, 2000. In the event this objective is not met,
167-12 the agency shall provide detailed reasons to the electric utility
167-13 restructuring legislative oversight committee by November 1, 2000,
167-14 why the agency was not able to meet this objective.
167-15 (g) The municipal power agency or its successor in interest
167-16 may, at its option, use the rate of return method for calculating
167-17 its transmission cost of service. If the rate of return method is
167-18 used, the return component for the transmission cost of service
167-19 revenue requirement shall be sufficient to meet the transmission
167-20 function's pro rata share of levelized debt service and debt
167-21 service coverage ratio (1.50) and other annual debt obligations,
167-22 provided, however, that the total levelized debt service may not
167-23 exceed the total debt service under the current payment schedule.
167-24 Any additional revenue generated by the methodology described in
167-25 this subsection shall be applied to reduce the agency's outstanding
167-26 indebtedness.
167-27 Sec. 40.060. NO POWER TO AMEND CERTIFICATES. Nothing in
168-1 this chapter empowers a municipal governing body or a body vested
168-2 with the power to manage and operate a municipally owned utility to
168-3 issue, amend, or rescind a certificate of public convenience and
168-4 necessity granted by the commission. This subsection does not
168-5 affect the ability of a municipal governing body or a body vested
168-6 with the power to manage and operate the municipally owned utility
168-7 to pass a resolution under Section 40.051(b).
168-8 Sec. 40.061. UNAUTHORIZED RETAIL ACCESS TO DISTRIBUTION
168-9 FACILITIES. A municipally owned utility that has not adopted
168-10 customer choice may not be required to provide access over its
168-11 facilities for service to its retail customer in its certificated
168-12 service area.
168-13 (Sections 40.062-40.100 reserved for expansion
168-14 SUBCHAPTER C. RIGHTS NOT AFFECTED
168-15 Sec. 40.101. INTERFERENCE WITH CONTRACT. (a) This subtitle
168-16 may not interfere with or abrogate the rights or obligations of
168-17 parties, including a retail or wholesale customer, to a contract
168-18 with a municipally owned utility or river authority.
168-19 (b) This subtitle may not interfere with or abrogate the
168-20 rights or obligations of a party under a contract or agreement
168-21 concerning certificated utility service areas.
168-22 Sec. 40.102. ACCESS TO WHOLESALE MARKET. Nothing in this
168-23 subtitle shall limit the access of municipally owned utilities to
168-24 the wholesale electric market.
168-25 Sec. 40.103. PROTECTION OF BONDHOLDERS. Nothing in this
168-26 subtitle or any rule adopted under this subtitle shall impair
168-27 contracts, covenants, or obligations between this state, river
169-1 authorities, municipalities, and the bondholders of revenue bonds
169-2 issued by the river authorities or municipalities.
169-3 Sec. 40.104. TAX-EXEMPT STATUS. Nothing in this subtitle
169-4 may impair the tax-exempt status of municipalities, electric
169-5 cooperatives, or river authorities, nor shall anything in this
169-6 subtitle compel any municipality, electric cooperative, or river
169-7 authority to use its facilities in a manner that violates any
169-8 contractual provisions, bond covenants, or other restrictions
169-9 applicable to facilities financed by tax-exempt debt.
169-10 Notwithstanding any other provision of law, the decision to
169-11 participate in customer choice by the adoption of a resolution in
169-12 accordance with Section 40.051(b) is irrevocable.
169-13 CHAPTER 41. ELECTRIC COOPERATIVES AND COMPETITION
169-14 SUBCHAPTER A. GENERAL PROVISIONS
169-15 Sec. 41.001. APPLICABLE LAW. Notwithstanding any other
169-16 provision of law, except Sections 39.155, 39.157(e), 39.203,
169-17 39.903, and 39.904, this chapter governs the transition to and the
169-18 establishment of a fully competitive electric power industry for
169-19 electric cooperatives. Regarding the regulation of electric
169-20 cooperatives, this chapter shall control over any other provision
169-21 of this title, except for sections in which the term "electric
169-22 cooperative" is specifically used.
169-23 Sec. 41.002. DEFINITIONS. In this chapter:
169-24 (1) "Board of directors" means the board of directors
169-25 of an electric cooperative as described in Section 161.071.
169-26 (2) "Rate" includes any compensation, tariff, charge,
169-27 fare, toll, rental, or classification that is directly or
170-1 indirectly demanded, observed, charged, or collected by an electric
170-2 cooperative for any service, product, or commodity and any rule,
170-3 practice, or contract affecting the compensation, tariff, charge,
170-4 fare, toll, rental, or classification.
170-5 (3) "Stranded investment" means:
170-6 (A) the excess, if any, of the net book value of
170-7 generation assets over the market value of the generation assets;
170-8 and
170-9 (B) any above market purchased power costs.
170-10 Sec. 41.003. SECURITIZATION. (a) Electric cooperatives may
170-11 adopt and use securitization provisions having the effect of the
170-12 provisions provided by Subchapter G, Chapter 39, to recover through
170-13 rates stranded costs at a recovery level deemed appropriate by the
170-14 board of directors up to 100 percent, under rules and procedures
170-15 that shall be established by the commission.
170-16 (b) The rules and procedures for securitization established
170-17 under Subsection (a) shall include rules and procedures for the
170-18 recovery of stranded costs under the terms of a rate order adopted
170-19 by the board of directors of the electric cooperative, which rate
170-20 order shall have the effect of a financing order.
170-21 (c) The rules and procedures established by the commission
170-22 under Subsection (b) shall include rules and procedures for the
170-23 issuance of transition bonds issued in a securitized financing
170-24 transaction. The issuance of any transition bonds issued in a
170-25 securitized financing transaction by an electric cooperative is
170-26 expressly authorized and shall be governed by the laws governing
170-27 the issuance of bonds or other obligations by the electric
171-1 cooperative. Findings made by the board of directors of an
171-2 electric cooperative in a rate order issued under the rules and
171-3 procedures described by this subsection shall be conclusive, and
171-4 any transition charges incorporated in the rate order to recover
171-5 the principal, interest, and all reasonable expenses associated
171-6 with any securitized financing transaction shall constitute
171-7 property rights, as described in Subchapter G, Chapter 39, and
171-8 shall otherwise conform in all material respects to the transition
171-9 charges provided by Subchapter G, Chapter 39.
171-10 Sec. 41.004. JURISDICTION OF COMMISSION. Except as
171-11 specifically provided otherwise in this chapter, the commission has
171-12 jurisdiction over electric cooperatives only as follows:
171-13 (1) to regulate wholesale transmission rates and
171-14 service including terms of access, to the extent provided in
171-15 Subchapter A, Chapter 35;
171-16 (2) to regulate certification to the extent provided
171-17 in Chapter 37;
171-18 (3) to establish a code of conduct as provided in
171-19 Section 39.157(e) subject to Section 41.054;
171-20 (4) to establish terms and conditions, but not rates,
171-21 for open access to distribution facilities for electric
171-22 cooperatives providing customer choice, as provided in Section
171-23 39.203; and
171-24 (5) to require reports of electric cooperative
171-25 operations only to the extent necessary to:
171-26 (A) ensure the public safety;
171-27 (B) enable the commission to satisfy its
172-1 responsibilities relating to electric cooperatives under this
172-2 chapter;
172-3 (C) enable the commission to determine the
172-4 aggregate electric load and energy requirements in the state and
172-5 the resources available to serve that load; or
172-6 (D) enable the commission to determine
172-7 information relating to market power as provided in Section 39.155.
172-8 Sec. 41.005. LIMITATION ON MUNICIPAL AUTHORITY.
172-9 Notwithstanding any other provision of this title, a municipality
172-10 may not directly or indirectly regulate the rates, operations, and
172-11 services of an electric cooperative, except, with respect to
172-12 operations, to the extent necessary to protect the public health,
172-13 safety, or welfare. This section does not prohibit a municipality
172-14 from making a lawful charge for the use of public rights-of-way
172-15 within the municipality as provided by Section 182.025, Tax Code,
172-16 and Section 33.008. An electric cooperative shall be an electric
172-17 utility for purposes of Section 182.025, Tax Code, and Section
172-18 33.008.
172-19 (Sections 41.006-41.050 reserved for expansion
172-20 SUBCHAPTER B. ELECTRIC COOPERATIVE UTILITY CHOICE
172-21 Sec. 41.051. BOARD DECISION. (a) The board of directors
172-22 has the discretion to decide when or if the electric cooperative
172-23 will provide customer choice.
172-24 (b) Electric cooperatives that choose to participate in
172-25 customer choice may do so at any time on or after January 1, 2002,
172-26 by adoption of an appropriate resolution of the board of directors.
172-27 The decision to participate in customer choice by the adoption of a
173-1 resolution may be revoked only if no customer has opted for choice
173-2 within four years of the resolution's adoption. An electric
173-3 cooperative may initiate a customer choice pilot project at any
173-4 time.
173-5 Sec. 41.052. ELECTRIC COOPERATIVES NOT OFFERING CUSTOMER
173-6 CHOICE. (a) An electric cooperative that chooses not to
173-7 participate in customer choice may not offer electric energy at
173-8 unregulated prices directly to retail customers outside its
173-9 certificated retail service area.
173-10 (b) An electric cooperative under Subsection (a) retains the
173-11 right to offer and provide a full range of customer service and
173-12 pricing programs to the customers within its certificated retail
173-13 service area and to purchase and sell electric energy at wholesale
173-14 without geographic restriction.
173-15 (c) A generation and transmission electric cooperative may
173-16 offer electric energy at unregulated prices directly to retail
173-17 customers outside of its parent electric cooperatives' certificated
173-18 service areas only if a majority of the parent electric
173-19 cooperatives of the generation and transmission electric
173-20 cooperative have chosen to offer customer choice.
173-21 (d) A subsidiary of an electric cooperative may not provide
173-22 electric energy at unregulated prices outside of its parent
173-23 electric cooperative's certificated retail service area unless the
173-24 electric cooperative offers customer choice inside its certificated
173-25 retail service area.
173-26 Sec. 41.053. RETAIL CUSTOMER RIGHT OF CHOICE. (a) If an
173-27 electric cooperative chooses to participate in customer choice,
174-1 after that choice, all retail customers within the certificated
174-2 service area of the electric cooperative shall have the right of
174-3 customer choice, and the electric cooperative shall provide
174-4 nondiscriminatory open access for retail service.
174-5 (b) Notwithstanding Section 39.107, the metering function
174-6 may not be deemed a competitive service for customers of the
174-7 electric cooperative within that service area and may, at the
174-8 option of the electric cooperative, continue to be offered by the
174-9 electric cooperative as sole provider.
174-10 (c) On its initiation of customer choice, an electric
174-11 cooperative shall designate itself or another entity as the
174-12 provider of last resort for retail customers within the electric
174-13 cooperative's certificated service area and shall fulfill the role
174-14 of default provider of last resort in the event no other entity is
174-15 available to act in that capacity.
174-16 (d) If a retail electric provider fails to serve a customer
174-17 described in Subsection (c), on request by the customer, the
174-18 provider of last resort shall offer the customer the standard
174-19 retail service package for the appropriate customer class, with no
174-20 interruption of service, at a fixed, nondiscountable rate that is
174-21 at least sufficient to cover the reasonable costs of providing that
174-22 service, as approved by the board of directors.
174-23 (e) The board of directors may establish the procedures and
174-24 criteria for designating the provider of last resort and may
174-25 redesignate the provider of last resort according to a schedule it
174-26 considers appropriate.
174-27 Sec. 41.054. SERVICE OUTSIDE CERTIFICATED AREA. (a)
175-1 Notwithstanding any provisions of Chapter 161:
175-2 (1) an electric cooperative participating in customer
175-3 choice shall have the right to offer electric energy and related
175-4 services at unregulated prices directly to retail customers who
175-5 have customer choice without regard to geographic location; and
175-6 (2) any person, without restriction, except as may be
175-7 provided in the electric cooperative's articles of incorporation
175-8 and bylaws, may be a member of an electric cooperative.
175-9 (b) In providing service under Subsection (a) to retail
175-10 customers outside its certificated service area as that area exists
175-11 on the date of adoption of customer choice, an electric cooperative
175-12 becomes subject to commission jurisdiction as to the commission's
175-13 rules establishing a code of conduct regulating anticompetitive
175-14 practices under Section 39.157(e), except to the extent those rules
175-15 conflict with this chapter.
175-16 (c) For electric cooperatives participating in customer
175-17 choice, the commission shall have jurisdiction to establish terms
175-18 and conditions, but not rates, for access by other electric
175-19 providers to the electric cooperative's distribution facilities.
175-20 (d) Notwithstanding Subsections (b) and (c), the commission
175-21 shall make accommodation in the code of conduct for specific legal
175-22 requirements imposed by state or federal law applicable to electric
175-23 cooperatives. The commission shall accommodate the organizational
175-24 structures of electric cooperatives and may not prohibit an
175-25 electric cooperative and any related entity from sharing officers,
175-26 directors, or employees.
175-27 (e) The commission does not have jurisdiction to require the
176-1 unbundling of services or functions of, or to regulate the recovery
176-2 of stranded investment of, an electric cooperative or, except as
176-3 provided by this section, jurisdiction with respect to the rates,
176-4 terms, and conditions of service for retail customers of an
176-5 electric cooperative within the electric cooperative's certificated
176-6 service area.
176-7 (f) An electric cooperative shall maintain separate books
176-8 and records of its operations and the operations of any subsidiary
176-9 and shall ensure that the rates charged for provision of electric
176-10 service do not include any costs of its subsidiary or any other
176-11 costs not related to the provision of electric service.
176-12 Sec. 41.055. JURISDICTION OF BOARD OF DIRECTORS. A board of
176-13 directors has exclusive jurisdiction to:
176-14 (1) set all terms of access, conditions, and rates
176-15 applicable to services provided by the electric cooperative, except
176-16 as provided by Sections 41.054 and 41.056, including
176-17 nondiscriminatory and comparable rates for distribution but
176-18 excluding wholesale transmission rates, terms of access, and
176-19 conditions for wholesale transmission service set by the commission
176-20 under Subchapter A, Chapter 35, provided that the rates for
176-21 distribution established by the electric cooperative shall be
176-22 comparable to the distribution rates that apply to the electric
176-23 cooperative and its subsidiaries;
176-24 (2) determine whether to unbundle any energy-related
176-25 activities and, if the board of directors chooses to unbundle,
176-26 whether to do so structurally or functionally;
176-27 (3) reasonably determine the amount of the electric
177-1 cooperative's stranded investment;
177-2 (4) establish nondiscriminatory transition charges
177-3 reasonably designed to recover the stranded investment over an
177-4 appropriate period of time;
177-5 (5) determine the extent to which the electric
177-6 cooperative will provide various customer services, including
177-7 nonelectric services, or accept the services from other providers;
177-8 (6) manage and operate the electric cooperative's
177-9 utility systems, including exercise of control over resource
177-10 acquisition and any related expansion programs;
177-11 (7) establish and enforce service quality standards,
177-12 reliability standards, and consumer safeguards designed to protect
177-13 retail electric customers;
177-14 (8) determine whether a base rate reduction is
177-15 appropriate for the electric cooperative;
177-16 (9) determine any other utility matters that the board
177-17 of directors believes should be included;
177-18 (10) sell electric energy and capacity at wholesale,
177-19 regardless of whether the electric cooperative participates in
177-20 customer choice; and
177-21 (11) make any other decisions affecting the electric
177-22 cooperative's method of conducting business that are not
177-23 inconsistent with the provisions of this chapter.
177-24 Sec. 41.056. ANTICOMPETITIVE ACTIONS. (a) If, after notice
177-25 and hearing, the commission finds that an electric cooperative
177-26 providing customer choice has engaged in anticompetitive behavior
177-27 by not providing other retail electric providers with
178-1 nondiscriminatory terms and conditions of access to distribution
178-2 facilities or customers within the electric cooperative's
178-3 certificated service area that are comparable to the electric
178-4 cooperative's and its subsidiaries' terms and conditions of access
178-5 to distribution facilities or customers, the commission shall
178-6 notify the electric cooperative.
178-7 (b) The electric cooperative shall have three months to cure
178-8 the anticompetitive or noncompliant behavior described in
178-9 Subsection (a). If the behavior is not fully remedied within that
178-10 time, the commission may prohibit the electric cooperative or its
178-11 subsidiary from providing retail service outside its certificated
178-12 retail service area until the behavior is remedied.
178-13 Sec. 41.057. BILLING. (a) An electric cooperative that
178-14 opts for customer choice may continue to bill directly electric
178-15 customers located in its certificated service area for all
178-16 transmission and distribution services. The electric cooperative
178-17 may also bill directly for generation and customer services
178-18 provided by the electric cooperative or its subsidiaries to those
178-19 customers.
178-20 (b) A customer served by an electric cooperative for
178-21 transmission and distribution services and by a retail electric
178-22 provider for retail service has the option of being billed directly
178-23 by each service provider or receiving a single bill for
178-24 distribution, transmission, and generation services from the
178-25 electric cooperative.
178-26 Sec. 41.058. TARIFFS FOR OPEN ACCESS. An electric
178-27 cooperative that owns or operates transmission and distribution
179-1 facilities shall file tariffs implementing the open access rules
179-2 established by the commission under Section 39.203 with the
179-3 appropriate regulatory authorities having jurisdiction over the
179-4 transmission and distribution service of the electric cooperative
179-5 before the 90th day preceding the date the electric cooperative
179-6 offers customer choice.
179-7 Sec. 41.059. NO POWER TO AMEND CERTIFICATES. Nothing in
179-8 this chapter empowers a board of directors to issue, amend, or
179-9 rescind a certificate of public convenience and necessity granted
179-10 by the commission.
179-11 Sec. 41.060. CUSTOMER SERVICE INFORMATION. (a) The
179-12 commission shall keep information submitted by customers and retail
179-13 electric providers pertaining to the provision of electric service
179-14 by electric cooperatives.
179-15 (b) The commission shall notify the appropriate electric
179-16 cooperative of information submitted by a customer or retail
179-17 electric provider, and the electric cooperative shall respond to
179-18 the customer or retail electric provider. The electric cooperative
179-19 shall notify the commission of its response.
179-20 (c) The commission shall prepare a report for the Sunset
179-21 Advisory Commission that includes information submitted and
179-22 responses by electric cooperatives in accordance with the Sunset
179-23 Advisory Commission's schedule for reviewing the commission.
179-24 Sec. 41.061. RETAIL RATE CHANGES BY ELECTRIC COOPERATIVES.
179-25 (a) This section shall apply to retail rates of an electric
179-26 cooperative that has not adopted customer choice and to the retail
179-27 delivery rates of an electric cooperative that has adopted customer
180-1 choice. This section may not apply to rates for:
180-2 (1) sales of electric energy by an electric
180-3 cooperative that has adopted customer choice; or
180-4 (2) wholesale sales of electric energy.
180-5 (b) An electric cooperative may change its rates by:
180-6 (1) adopting a resolution approving the proposed
180-7 change;
180-8 (2) mailing notice of the proposed change to each
180-9 affected customer whose rate would be increased by the proposed
180-10 change at least 30 days before implementation of the proposed
180-11 change, which notice may be included in a monthly billing; and
180-12 (3) holding a meeting to discuss the proposed rate
180-13 changes with affected customers, if any change is expected to
180-14 increase total system annual revenues by more than $100,000 or one
180-15 percent, whichever is greater.
180-16 (c) An electric cooperative may implement the proposed rates
180-17 on completion of the requirements under Subsection (b), and those
180-18 rates shall remain in effect until changed by the electric
180-19 cooperative as provided by this section or, for rates other than
180-20 retail delivery rates, until this section is no longer applicable
180-21 because the electric cooperative adopts customer choice.
180-22 (d) The electric cooperative may reconsider a rate change at
180-23 any time and adjust the rate by board resolution without additional
180-24 notice or meeting of customers if the rate as adjusted is not
180-25 expected to increase the revenues from a customer class. However,
180-26 if notice is given to a customer class that would receive an
180-27 increase as a result of the adjustment, then the rates for the
181-1 customer class may be increased without additional meeting of the
181-2 customers. A customer may petition to appeal within the time
181-3 provided in Subsection (f).
181-4 (e) Retail rates set by an electric cooperative that has not
181-5 adopted customer choice and retail delivery rates set by an
181-6 electric cooperative that has adopted customer choice shall be just
181-7 and reasonable, not unreasonably preferential, prejudicial, or
181-8 discriminatory; provided, however, if the customer agrees, an
181-9 electric cooperative may charge a market-based rate to customers
181-10 who have energy supply options if rates are not increased for other
181-11 customers as a result.
181-12 (f) A customer of the electric cooperative who is adversely
181-13 affected by a rate setting resolution of the electric cooperative
181-14 is entitled to judicial review. A person initiates judicial review
181-15 by filing a petition in the district court of Travis County not
181-16 later than the 90th day after the resolution is implemented.
181-17 (g) The resolution of the electric cooperative setting
181-18 rates, as it may have been amended as described in Subsection (d),
181-19 shall be presumed valid, and the burden of showing that the
181-20 resolution is invalid rests on the persons challenging the
181-21 resolution. A court reviewing a change of a rate or rates by an
181-22 electric cooperative may consider any relevant factor including the
181-23 cost of providing service.
181-24 (h) If the court finds that the electric cooperative's
181-25 resolution setting rates violates the standards contained in
181-26 Subsection (e), or that the electric cooperative's rate violates
181-27 Subsection (e) the court shall enter an order:
182-1 (1) stating the specific basis for its determination
182-2 that the rates set in the electric cooperative's resolution violate
182-3 Subsection (e); and
182-4 (2) directing the electric cooperative to:
182-5 (A) set, within 60 days, revised retail rates
182-6 that do not violate the standards of Subsection (e); and
182-7 (B) refund or credit against future bills, at
182-8 the electric cooperative's option, revenues collected under the
182-9 rate found to violate the standards of Subsection (e) that exceed
182-10 the revenues that would have been collected under the revised
182-11 rates. The refund or credit shall be made over a period of not
182-12 more than 12 months, as determined by the court.
182-13 (i) The court may not enter an order delaying or prohibiting
182-14 implementation of a rate change or set revised rates either for the
182-15 period the challenged resolution was in effect or prospectively.
182-16 (j) A person having obtained an order of the court requiring
182-17 an electric cooperative to set revised retail rates pursuant to
182-18 Subsection (h)(2)(A) may, once the order is no longer subject to
182-19 appeal, initiate an original proceeding in the district court of
182-20 Travis County either to:
182-21 (1) seek enforcement of the court's order by writ of
182-22 mandamus if the electric cooperative has failed to adopt a
182-23 resolution approving revised rates within the time prescribed; or
182-24 (2) seek judicial review of the electric cooperative's
182-25 most current resolution setting rates as provided in this section,
182-26 if the electric cooperative has set revised rates pursuant to the
182-27 order of the court within the time prescribed. In the event of
183-1 such enforcement proceeding or judicial review the court may, in
183-2 addition to the other remedies provided for in this section, award
183-3 reasonable costs, including reasonable attorney's fees, to the
183-4 party prevailing on the case as a whole. Additionally, if the
183-5 court finds that either party has acted in bad faith solely for the
183-6 purpose of perpetuating the rate dispute between the parties, the
183-7 court may impose sanctions on the offending party in accordance
183-8 with the provisions of Subsections (b), (c), and (e), Section
183-9 10.004, Civil Practice and Remedies Code.
183-10 (k) An electric cooperative that has not adopted customer
183-11 choice and that has not changed each of its nonresidential rates
183-12 since January 1, 1999, shall, on or before May 1, 2002, adopt a
183-13 resolution setting rates. The resolution shall be subject to
183-14 judicial review as provided in this section whether or not any rate
183-15 is changed. In the event the electric cooperative fails to adopt a
183-16 resolution setting rates pursuant to this subsection, a customer
183-17 may petition for judicial review of the electric cooperative's
183-18 rates. A person initiates judicial review by filing a petition in
183-19 the district court of Travis County not later than November 1,
183-20 2002.
183-21 Sec. 41.062. ALLOCATION OF STRANDED INVESTMENT. Any
183-22 competition transition charge shall be allocated among retail
183-23 customer classes based on the relevant customer class
183-24 characteristics as of the end of the electric cooperative's most
183-25 recent fiscal year before implementation of customer choice, in
183-26 accordance with the methodology used to allocate the costs of the
183-27 underlying assets or expenses in the electric cooperative's most
184-1 recent cost of service study certified by a professional engineer
184-2 or certified public accountant or approved by the commission. In
184-3 multiply certificated areas, a retail customer may not avoid
184-4 stranded cost recovery charges by switching to another electric
184-5 cooperative, an electric utility, or a municipally owned utility.
184-6 Sec. 41.063. RETAIL RATES OF SUCCESSOR ELECTRIC UTILITY TO
184-7 ELECTRIC COOPERATIVE. (a) For purposes of this section, an
184-8 electric cooperative as described by Section 11.003(9)(C) is a
184-9 "successor cooperative" and the rates of a successor cooperative
184-10 are subject to this section. Effective January 1, 2000, a customer
184-11 of a successor cooperative who has reason to believe the customer
184-12 is being charged a rate in violation of Subsection (b) is entitled
184-13 to judicial review by filing a petition in a district court of
184-14 Travis County. The customer has the burden of proving the rate
184-15 violates Subsection (b).
184-16 (b) Retail rates of a successor cooperative shall be just
184-17 and reasonable and not unreasonably preferential, prejudicial, or
184-18 discriminatory. However, a successor cooperative may charge a
184-19 lower, market-based rate to customers who have energy supply
184-20 options, and in that event the standards that would otherwise
184-21 govern the rates charged to other customers are modified only to
184-22 the minimum extent necessary to enable those customers having
184-23 energy supply options to receive lower, market-based rates.
184-24 (c) A court reviewing a rate by a successor cooperative may
184-25 consider any relevant factor that may be considered by a court in
184-26 reviewing a decision of the commission, including the cost of
184-27 providing service.
185-1 (d) If the court finds that the successor cooperative's rate
185-2 violates the standards contained in Subsection (b), the court shall
185-3 enter an order:
185-4 (1) stating the specific basis for its determination
185-5 that the rate violates Subsection (b); and
185-6 (2) directing the successor cooperative to:
185-7 (A) set, within 60 days, a revised retail rate
185-8 that does not violate the standards of Subsection (b); and
185-9 (B) refund or credit against future bills, at
185-10 the successor cooperative's option, revenues collected under the
185-11 rate found to violate the standards of Subsection (b) that exceed
185-12 the revenues that would have been collected under the revised
185-13 rates.
185-14 (e) The refund or credit shall be made over a period of not
185-15 more than 12 months, as determined by the electric cooperative. If
185-16 the court has ordered relief under Subsection (d), and after 60
185-17 days the court finds that the successor cooperative's resolution
185-18 setting rates still violates the standards contained in Subsection
185-19 (b), the court shall enter an order imposing any sanction
185-20 authorized by Section 10.004(c), Civil Practice and Remedies Code.
185-21 (f) No remedy other than or additional to a remedy under
185-22 Subsections (d) and (e) may be ordered by the court. The court may
185-23 not set revised rates either for the period the challenged
185-24 resolution was in effect or prospectively.
185-25 Sec. 41.064. UNAUTHORIZED RETAIL ACCESS TO DISTRIBUTION
185-26 FACILITIES. An electric cooperative that has not adopted customer
185-27 choice may not be required to provide access over its facilities
186-1 for service to its retail customers in its certificated service
186-2 area.
186-3 (Sections 41.065-41.100 reserved for expansion
186-4 SUBCHAPTER C. RIGHTS NOT AFFECTED
186-5 Sec. 41.101. INTERFERENCE WITH CONTRACT. (a) This subtitle
186-6 may not interfere with or abrogate the rights or obligations of
186-7 parties, including a retail or wholesale customer, to a contract
186-8 with an electric cooperative or its subsidiary.
186-9 (b) No provision of this subtitle may interfere with or be
186-10 deemed to abrogate the rights or obligations of a party under a
186-11 contract or an agreement concerning certificated service areas.
186-12 Sec. 41.102. ACCESS TO WHOLESALE MARKET. Nothing in this
186-13 subtitle shall limit the access of an electric cooperative or its
186-14 subsidiary, either on its own behalf or on behalf of its customers,
186-15 to the wholesale electric market.
186-16 Sec. 41.103. PROTECTION OF BONDHOLDERS. Nothing in this
186-17 subtitle or any rule adopted under this subtitle shall impair
186-18 contracts, covenants, or obligations between an electric
186-19 cooperative and its lenders and holders of bonds issued on behalf
186-20 of or by the electric cooperative.
186-21 Sec. 41.104. TAX-EXEMPT STATUS. Nothing in this subtitle
186-22 may impair the tax-exempt status of electric cooperatives, nor
186-23 shall anything in this subtitle compel any electric cooperative to
186-24 use its facilities in a manner that violates any contractual
186-25 provisions, bond covenants, or other restrictions applicable to
186-26 facilities financed by tax-exempt or federally insured or
186-27 guaranteed debt.
187-1 SECTION 41. Section 252.022, Local Government Code, is
187-2 amended by amending Subsection (a) and by adding Subsection (c) to
187-3 read as follows:
187-4 (a) This chapter does not apply to an expenditure for:
187-5 (1) a procurement made because of a public calamity
187-6 that requires the immediate appropriation of money to relieve the
187-7 necessity of the municipality's residents or to preserve the
187-8 property of the municipality;
187-9 (2) a procurement necessary to preserve or protect the
187-10 public health or safety of the municipality's residents;
187-11 (3) a procurement necessary because of unforeseen
187-12 damage to public machinery, equipment, or other property;
187-13 (4) a procurement for personal, professional, or
187-14 planning services;
187-15 (5) a procurement for work that is performed and paid
187-16 for by the day as the work progresses;
187-17 (6) a purchase of land or a right-of-way;
187-18 (7) a procurement of items that are available from
187-19 only one source, including:
187-20 (A) items that are available from only one
187-21 source because of patents, copyrights, secret processes, or natural
187-22 monopolies;
187-23 (B) films, manuscripts, or books;
187-24 (C) [electricity,] gas, water, and other utility
187-25 services;
187-26 (D) captive replacement parts or components for
187-27 equipment;
188-1 (E) books, papers, and other library materials
188-2 for a public library that are available only from the persons
188-3 holding exclusive distribution rights to the materials; and
188-4 (F) management services provided by a nonprofit
188-5 organization to a municipal museum, park, zoo, or other facility to
188-6 which the organization has provided significant financial or other
188-7 benefits;
188-8 (8) a purchase of rare books, papers, and other
188-9 library materials for a public library;
188-10 (9) paving drainage, street widening, and other public
188-11 improvements, or related matters, if at least one-third of the cost
188-12 is to be paid by or through special assessments levied on property
188-13 that will benefit from the improvements;
188-14 (10) a public improvement project, already in
188-15 progress, authorized by the voters of the municipality, for which
188-16 there is a deficiency of funds for completing the project in
188-17 accordance with the plans and purposes authorized by the voters;
188-18 (11) a payment under a contract by which a developer
188-19 participates in the construction of a public improvement as
188-20 provided by Subchapter C, Chapter 212;
188-21 (12) personal property sold:
188-22 (A) at an auction by a state licensed
188-23 auctioneer;
188-24 (B) at a going out of business sale held in
188-25 compliance with Subchapter F, Chapter 17, Business & Commerce Code;
188-26 (C) by a political subdivision of this state, a
188-27 state agency of this state, or an entity of the federal government;
189-1 or
189-2 (D) under an interlocal contract for cooperative
189-3 purchasing administered by a regional planning commission
189-4 established under Chapter 391;
189-5 (13) services performed by blind or severely disabled
189-6 persons; [or]
189-7 (14) goods purchased by a municipality for subsequent
189-8 retail sale by the municipality; or
189-9 (15) electricity.
189-10 (c) This chapter does not apply to expenditures by a
189-11 municipally owned electric or gas utility or unbundled divisions of
189-12 a municipally owned electric or gas utility in connection with any
189-13 purchases by the municipally owned utility or divisions of a
189-14 municipally owned utility made in accordance with procurement
189-15 procedures adopted by a resolution of the body vested with
189-16 authority for management and operation of the municipally owned
189-17 utility or its divisions that sets out the public purpose to be
189-18 achieved by those procedures. This subsection may not be deemed to
189-19 exempt a municipally owned utility from any other applicable
189-20 statute, charter provision, or ordinance.
189-21 SECTION 42. Subtitle C, Title 9, Local Government Code, is
189-22 amended by adding Chapter 303 to read as follows:
189-23 CHAPTER 303. ENERGY AGGREGATION MEASURES FOR LOCAL GOVERNMENTS
189-24 Sec. 303.001. AGGREGATION BY POLITICAL SUBDIVISIONS. (a)
189-25 In this chapter, "political subdivision" means a county,
189-26 municipality, hospital district, or any other political
189-27 subdivision.
190-1 (b) A political subdivision may join with another political
190-2 subdivision or subdivisions to form a political subdivision
190-3 corporation or corporations to act as an agent to negotiate the
190-4 purchase of electricity, or to likewise aid or act on behalf of the
190-5 political subdivisions for which the corporation is created, with
190-6 respect to their own electricity use for their respective public
190-7 facilities.
190-8 (c) The articles of incorporation and the bylaws of a
190-9 political subdivision corporation must be approved by ordinance,
190-10 resolution, or order adopted by the governing body of each
190-11 political subdivision for which the corporation is created.
190-12 (d) A political subdivision corporation may negotiate on
190-13 behalf of its incorporating political subdivisions for the purchase
190-14 of electricity, make contracts for the purchase of electricity,
190-15 purchase electricity, and take any other action necessary to
190-16 purchase electricity for use in the public facilities of the
190-17 political subdivision or subdivisions represented by the political
190-18 subdivision corporation. In this subsection, "electricity" means
190-19 electric energy, capacity, energy services, ancillary services, or
190-20 other electric services for retail or wholesale consumption by the
190-21 political subdivisions.
190-22 (e) A political subdivision corporation may recover the
190-23 expenses of the political subdivision corporation through the
190-24 assessment of dues to the incorporating political subdivisions or
190-25 through an aggregation fee charged per kilowatt hour, or a
190-26 combination of both.
190-27 (f) A political subdivision corporation may appear on behalf
191-1 of its incorporating political subdivisions before the Public
191-2 Utility Commission of Texas, the Railroad Commission of Texas, the
191-3 Texas Natural Resource Conservation Commission, any other
191-4 governmental agency or regulatory authority, the Texas Legislature,
191-5 and the courts.
191-6 (g) A political subdivision corporation has the powers of a
191-7 corporation created and incorporated pursuant to the provisions of
191-8 the Texas Non-Profit Corporation Act (Article 1396-1.01 et seq.,
191-9 Vernon's Texas Civil Statutes) and such other powers as specified
191-10 in Section 39.3545, Utilities Code.
191-11 (h) The provisions of the Texas Non-Profit Corporation Act
191-12 (Article 1396-1.01 et seq., Vernon's Texas Civil Statutes) relating
191-13 to powers, standards of conduct, and interests in contracts apply
191-14 to the directors and officers of a political subdivision
191-15 corporation.
191-16 (i) A member of the board of directors of a political
191-17 subdivision corporation:
191-18 (1) is not a public official by virtue of that
191-19 position; and
191-20 (2) unless otherwise ineligible, may be elected to
191-21 serve as an official of a political subdivision or be employed by a
191-22 political subdivision.
191-23 Sec. 303.002. AGGREGATION BY POLITICAL SUBDIVISION FOR
191-24 CITIZENS. (a) A political subdivision aggregator may negotiate
191-25 for the purchase of electricity and energy services on behalf of
191-26 the citizens of the political subdivision. The citizens must
191-27 affirmatively request to be included in the aggregation services by
192-1 the political subdivision aggregator.
192-2 (b) A political subdivision may contract with a third party
192-3 or another aggregator to administer the aggregation of electricity
192-4 and energy services purchased under Subsection (a).
192-5 (c) The political subdivision aggregator may use any mailing
192-6 from the subdivision to invite participation by its citizens.
192-7 SECTION 43. Section 272.001, Local Government Code, is
192-8 amended by adding Subsection (j) to read as follows:
192-9 (j) This section does not apply to sales or exchanges of
192-10 land owned by a municipality operating a municipally owned electric
192-11 or gas utility if the land is held or managed by the municipally
192-12 owned utility, or by a division of the municipally owned electric
192-13 or gas utility that constitutes the unbundled electric or gas
192-14 operations of the utility, provided that the governing body of the
192-15 municipally owned utility shall adopt a resolution stating the
192-16 conditions and circumstances for the sale or exchange and the
192-17 public purpose that will be achieved by the sale or exchange. For
192-18 purposes of this subsection, "municipally owned utility" includes a
192-19 river authority engaged in the generation, transmission, or
192-20 distribution of electric energy to the public, and "unbundled"
192-21 operations are those operations of the utility that have, in the
192-22 discretion of the utility's governing body, been functionally
192-23 separated.
192-24 SECTION 44. Subsection (c), Section 402.002, Local
192-25 Government Code, is amended to read as follows:
192-26 (c) The municipality may manufacture its own electricity,
192-27 gas, or anything else needed or used by the public. It may
193-1 purchase, and make contracts for the purchase of, gas, electricity,
193-2 oil, or any other commodity or article used by the public and may
193-3 sell it to the public on terms as provided by the municipal
193-4 charter, ordinance, or resolution of the governing body of the
193-5 municipally owned utility.
193-6 SECTION 45. Subchapter D, Chapter 551, Government Code, is
193-7 amended by adding Section 551.086 to read as follows:
193-8 Sec. 551.086. CERTAIN PUBLIC POWER UTILITIES: COMPETITIVE
193-9 MATTERS. (a) Notwithstanding anything in this chapter to the
193-10 contrary, the rules provided by this section apply to competitive
193-11 matters of a public power utility.
193-12 (b) In this section:
193-13 (1) "Public power utility" means an entity providing
193-14 electric or gas utility services that is subject to the provisions
193-15 of this chapter.
193-16 (2) "Public power utility governing body" means the
193-17 board of trustees or other applicable governing body, including a
193-18 city council, of a public power utility.
193-19 (3) "Competitive matter" means a utility-related
193-20 matter that the public power utility governing body in good faith
193-21 determines by a vote under this section is related to the public
193-22 power utility's competitive activity, including commercial
193-23 information, and would, if disclosed, give advantage to competitors
193-24 or prospective competitors, but may not be deemed to include the
193-25 following categories of information:
193-26 (A) information relating to the provision of
193-27 distribution access service, including the terms and conditions of
194-1 the service and the rates charged for the service but not including
194-2 information concerning utility-related services or products that
194-3 are competitive;
194-4 (B) information relating to the provision of
194-5 transmission service that is required to be filed with the Public
194-6 Utility Commission of Texas, subject to any confidentiality
194-7 provided for under the rules of the commission;
194-8 (C) information for the distribution system
194-9 pertaining to reliability and continuity of service, to the extent
194-10 not security-sensitive, that relates to emergency management,
194-11 identification of critical loads such as hospitals and police,
194-12 records of interruption, and distribution feeder standards;
194-13 (D) any substantive rule of general
194-14 applicability regarding service offerings, service regulation,
194-15 customer protections, or customer service adopted by the public
194-16 power utility as authorized by law;
194-17 (E) aggregate information reflecting receipts or
194-18 expenditures of funds of the public power utility, of the type that
194-19 would be included in audited financial statements;
194-20 (F) information relating to equal employment
194-21 opportunities for minority groups, as filed with local, state, or
194-22 federal agencies;
194-23 (G) information relating to the public power
194-24 utility's performance in contracting with minority business
194-25 entities;
194-26 (H) information relating to nuclear
194-27 decommissioning trust agreements, of the type required to be
195-1 included in audited financial statements;
195-2 (I) information relating to the amount and
195-3 timing of any transfer to an owning city's general fund;
195-4 (J) information relating to environmental
195-5 compliance as required to be filed with any local, state, or
195-6 national environmental authority, subject to any confidentiality
195-7 provided under the rules of those authorities;
195-8 (K) names of public officers of the public power
195-9 utility and the voting records of those officers for all matters
195-10 other than those within the scope of a competitive resolution
195-11 provided for by this section;
195-12 (L) a description of the public power utility's
195-13 central and field organization, including the established places at
195-14 which the public may obtain information, submit information and
195-15 requests, or obtain decisions and the identification of employees
195-16 from whom the public may obtain information, submit information or
195-17 requests, or obtain decisions; or
195-18 (M) information identifying the general course
195-19 and method by which the public power utility's functions are
195-20 channeled and determined, including the nature and requirements of
195-21 all formal and informal policies and procedures.
195-22 (c) This chapter does not require a public power utility
195-23 governing body to conduct an open meeting to deliberate, vote, or
195-24 take final action on any competitive matter, as that term is
195-25 defined in Subsection (b)(3). Before a public power utility
195-26 governing body may deliberate, vote, or take final action on any
195-27 competitive matter in a closed meeting, the public power utility
196-1 governing body must first make a good faith determination, by
196-2 majority vote of its members, that the matter is a competitive
196-3 matter that satisfies the requirements of Subsection (b)(3). The
196-4 vote shall be taken during the closed meeting and be included in
196-5 the certified agenda or tape recording of the closed meeting. If a
196-6 public power utility governing body fails to determine by that vote
196-7 that the matter satisfies the requirements of Subsection (b)(3),
196-8 the public power utility governing body may not deliberate or take
196-9 any further action on the matter in the closed meeting. This
196-10 section does not limit the right of a public power utility
196-11 governing body to hold a closed session under any other exception
196-12 provided for in this chapter.
196-13 (d) For purposes of Section 551.041, the notice of the
196-14 subject matter of an item that may be considered as a competitive
196-15 matter under this section is required to contain no more than a
196-16 general representation of the subject matter to be considered, such
196-17 that the competitive activity of the public power utility with
196-18 respect to the issue in question is not compromised or disclosed.
196-19 (e) With respect to municipally owned utilities subject to
196-20 this section, this section shall apply whether or not the
196-21 municipally owned utility has adopted customer choice or serves in
196-22 a multiply certificated service area under the Utilities Code.
196-23 (f) Nothing in this section is intended to preclude the
196-24 application of the enforcement and remedies provisions of
196-25 Subchapter G.
196-26 SECTION 46. Subchapter C, Chapter 552, Government Code, is
196-27 amended by adding Section 552.131 to read as follows:
197-1 Sec. 552.131. EXCEPTION: PUBLIC POWER UTILITY COMPETITIVE
197-2 MATTERS. (a) In this section:
197-3 (1) "Public power utility" means an entity providing
197-4 electric or gas utility services that is subject to the provisions
197-5 of this chapter.
197-6 (2) "Public power utility governing body" means the
197-7 board of trustees or other applicable governing body, including a
197-8 city council, of a public power utility.
197-9 (3) "Competitive matter" means a utility-related
197-10 matter that the public power utility governing body in good faith
197-11 determines by a vote under this section is related to the public
197-12 power utility's competitive activity, including commercial
197-13 information, and would, if disclosed, give advantage to competitors
197-14 or prospective competitors, but may not be deemed to include the
197-15 following categories of information:
197-16 (A) information relating to the provision of
197-17 distribution access service, including the terms and conditions of
197-18 the service and the rates charged for the service but not including
197-19 information concerning utility-related services or products that
197-20 are competitive;
197-21 (B) information relating to the provision of
197-22 transmission service that is required to be filed with the Public
197-23 Utility Commission of Texas, subject to any confidentiality
197-24 provided for under the rules of the commission;
197-25 (C) information for the distribution system
197-26 pertaining to reliability and continuity of service, to the extent
197-27 not security-sensitive, that relates to emergency management,
198-1 identification of critical loads such as hospitals and police,
198-2 records of interruption, and distribution feeder standards;
198-3 (D) any substantive rule of general
198-4 applicability regarding service offerings, service regulation,
198-5 customer protections, or customer service adopted by the public
198-6 power utility as authorized by law;
198-7 (E) aggregate information reflecting receipts or
198-8 expenditures of funds of the public power utility, of the type that
198-9 would be included in audited financial statements;
198-10 (F) information relating to equal employment
198-11 opportunities for minority groups, as filed with local, state, or
198-12 federal agencies;
198-13 (G) information relating to the public power
198-14 utility's performance in contracting with minority business
198-15 entities;
198-16 (H) information relating to nuclear
198-17 decommissioning trust agreements, of the type required to be
198-18 included in audited financial statements;
198-19 (I) information relating to the amount and
198-20 timing of any transfer to an owning city's general fund;
198-21 (J) information relating to environmental
198-22 compliance as required to be filed with any local, state, or
198-23 national environmental authority, subject to any confidentiality
198-24 provided under the rules of those authorities;
198-25 (K) names of public officers of the public power
198-26 utility and the voting records of those officers for all matters
198-27 other than those within the scope of a competitive resolution
199-1 provided for by this section;
199-2 (L) a description of the public power utility's
199-3 central and field organization, including the established places at
199-4 which the public may obtain information, submit information and
199-5 requests, or obtain decisions and the identification of employees
199-6 from whom the public may obtain information, submit information or
199-7 requests, or obtain decisions; or
199-8 (M) information identifying the general course
199-9 and method by which the public power utility's functions are
199-10 channeled and determined, including the nature and requirements of
199-11 all formal and informal policies and procedures.
199-12 (b) Information or records are excepted from the
199-13 requirements of Section 552.021 if the information or records are
199-14 reasonably related to a competitive matter, as defined in this
199-15 section. Excepted information or records include the text of any
199-16 resolution of the public power utility governing body determining
199-17 which issues, activities, or matters constitute competitive
199-18 matters. Information or records of a municipally owned utility
199-19 that are reasonably related to a competitive matter are not subject
199-20 to disclosure under this chapter, whether or not, under the
199-21 Utilities Code, the municipally owned utility has adopted customer
199-22 choice or serves in a multiply certificated service area. This
199-23 section does not limit the right of a public power utility
199-24 governing body to withhold from disclosure information deemed to be
199-25 within the scope of any other exception provided for in this
199-26 chapter, subject to the provisions of this chapter.
199-27 (c) In connection with any request for an opinion of the
200-1 attorney general under Section 552.301 with respect to information
200-2 alleged to fall under this exception, in rendering a written
200-3 opinion under Section 552.306 the attorney general shall find the
200-4 requested information to be outside the scope of this exception
200-5 only if the attorney general determines, based on the information
200-6 provided in connection with the request:
200-7 (1) that the public power utility governing body has
200-8 failed to act in good faith in making the determination that the
200-9 issue, matter, or activity in question is a competitive matter; or
200-10 (2) that the information or records sought to be
200-11 withheld are not reasonably related to a competitive matter.
200-12 SECTION 47. Subsection (d), Section 791.011, Government
200-13 Code, is amended to read as follows:
200-14 (d) An interlocal contract must:
200-15 (1) be authorized by the governing body of each party
200-16 to the contract unless a party to the contract is a municipally
200-17 owned electric utility, in which event the governing body may
200-18 establish procedures for entering into interlocal contracts that do
200-19 not exceed $100,000 without requiring the approval of the governing
200-20 body;
200-21 (2) state the purpose, terms, rights, and duties of
200-22 the contracting parties; and
200-23 (3) specify that each party paying for the performance
200-24 of governmental functions or services must make those payments from
200-25 current revenues available to the paying party.
200-26 SECTION 48. Subchapter A, Chapter 2256, Government Code, is
200-27 amended by adding Section 2256.0201 to read as follows:
201-1 Sec. 2256.0201. AUTHORIZED INVESTMENTS; MUNICIPAL UTILITY.
201-2 (a) A municipality that owns a municipal electric utility that is
201-3 engaged in the distribution and sale of electric energy or natural
201-4 gas to the public may enter into a hedging contract and related
201-5 security and insurance agreements in relation to fuel oil, natural
201-6 gas, and electric energy to protect against loss due to price
201-7 fluctuations. A hedging transaction must comply with the
201-8 regulations of the Commodity Futures Trading Commission and the
201-9 Securities and Exchange Commission. If there is a conflict between
201-10 the municipal charter of the municipality and this chapter, this
201-11 chapter prevails.
201-12 (b) A payment by a municipally owned electric or gas utility
201-13 under a hedging contract or related agreement in relation to fuel
201-14 supplies or fuel reserves is a fuel expense, and the utility may
201-15 credit any amounts it receives under the contract or agreement
201-16 against fuel expenses.
201-17 (c) The governing body of a municipally owned electric or
201-18 gas utility or the body vested with power to manage and operate the
201-19 municipally owned electric or gas utility may set policy regarding
201-20 hedging transactions.
201-21 (d) In this section, "hedging" means the buying and selling
201-22 of fuel oil, natural gas, and electric energy futures or options or
201-23 similar contracts on those commodity futures as a protection
201-24 against loss due to price fluctuation.
201-25 SECTION 49. Subsections (a), (c), and (d), Section 52.133,
201-26 Natural Resources Code, are amended to read as follows:
201-27 (a) Each oil or gas lease covering land leased by the board,
202-1 by a board for lease [other than the Board for Lease of University
202-2 Lands], or by the surface owner of land under which the state owns
202-3 the minerals, commonly referred to as Relinquishment Act land,
202-4 which shall be subject to approval by the commissioner before it is
202-5 effective, shall include a provision granting the board authorized
202-6 to lease the land or the owner of the soil of Relinquishment Act
202-7 land and the commissioner authority to take their royalty in kind,
202-8 and the commissioner and the boards for lease may include any other
202-9 reasonable provisions that are not inconsistent with this section.
202-10 (c) The commissioner, the owner of the soil under Subchapter
202-11 F [of this chapter], or the commissioner[,] acting on the behalf of
202-12 and at the direction of an owner of the soil under Subchapter F [of
202-13 this chapter], the board, or a board for lease, or at the direction
202-14 of the Board for Lease of University Lands, may negotiate and
202-15 execute contracts or any other instruments or agreements necessary
202-16 to dispose of or enhance their portion of the royalty taken in
202-17 kind, including contracts for sale, purchase, transportation, and
202-18 storage and including insurance contracts or other agreements, to
202-19 secure or guarantee payment.
202-20 (d) The commissioner, the owner of the soil under Subchapter
202-21 F, or the commissioner acting on behalf of and at the direction of
202-22 an owner of the soil under Subchapter F, the board, or a board for
202-23 lease, may negotiate and execute contracts or any other instruments
202-24 or agreements necessary to convert that portion of the royalty
202-25 taken in kind into other forms of energy, including electricity.
202-26 [This section does not apply to or have any effect on the Board for
202-27 Lease of University Lands or any lease executed on university
203-1 land.]
203-2 SECTION 50. Section 53.026, Natural Resources Code, is
203-3 amended to read as follows:
203-4 Sec. 53.026. In Kind Royalty. (a) The commissioner or the
203-5 commissioner acting on behalf of and at the direction of the board
203-6 or a board for lease may negotiate and execute a contract or any
203-7 other instrument or agreement necessary to dispose of or enhance
203-8 their portion of the royalty taken in kind, including contracts [a
203-9 contract] for sale, purchase, transportation, or storage.
203-10 (b) The commissioner or the commissioner acting on behalf of
203-11 and at the direction of the board or a board for lease may
203-12 negotiate and execute a contract or any other instrument or
203-13 agreement necessary to convert that portion of the royalty taken in
203-14 kind to other forms of energy, including electricity.
203-15 (c) This section shall not be construed to surrender or in
203-16 any way affect the right of the state under an existing or future
203-17 lease to receive monetary royalty from its lessee.
203-18 SECTION 51. Section 53.077, Natural Resources Code, is
203-19 amended to read as follows:
203-20 Sec. 53.077. In Kind Royalty. (a) The commissioner, each
203-21 owner of the soil under this subchapter, or the commissioner acting
203-22 on the behalf of and at the direction of an owner of the soil under
203-23 this subchapter may negotiate and execute a contract or any other
203-24 instrument or agreement necessary to dispose of or enhance their
203-25 portion of the royalty taken in kind, including a contract for
203-26 sale, transportation, or storage.
203-27 (b) The commissioner, each owner of the soil under this
204-1 subchapter, or the commissioner acting on behalf of and at the
204-2 direction of the owner of the soil under this subchapter may
204-3 negotiate and execute a contract or any other instrument or
204-4 agreement necessary to convert that portion of the royalty taken in
204-5 kind to other forms of energy, including electricity.
204-6 (c) This section shall not be construed to surrender or in
204-7 any way affect the right of the state or the owner of the soil
204-8 under an existing or future lease to receive monetary royalty from
204-9 its lessee.
204-10 SECTION 52. Chapter 245, Acts of the 67th Legislature,
204-11 Regular Session, 1981 (Article 717p, Vernon's Texas Civil
204-12 Statutes), is amended by adding Section 4C to read as follows:
204-13 Sec. 4C. (a) This section applies only to a river authority
204-14 that is engaged in the distribution and sale of electric energy to
204-15 the public.
204-16 (b) Notwithstanding any other law, a river authority may:
204-17 (1) provide transmission services, as defined by the
204-18 Utilities Code or the Public Utility Commission of Texas, on a
204-19 regional basis to any eligible transmission customer at any
204-20 location within or outside the boundaries of the river authority;
204-21 and
204-22 (2) acquire, including by lease-purchase, lease from
204-23 or to any person, finance, construct, rebuild, operate, or sell
204-24 electric transmission facilities at any location within or outside
204-25 the boundaries of the river authority; provided, however, that
204-26 nothing in this section shall:
204-27 (A) allow a river authority to construct
205-1 transmission facilities to an ultimate consumer of electricity to
205-2 enable an ultimate consumer to bypass the transmission or
205-3 distribution facilities of its existing provider; or
205-4 (B) relieve a river authority from an obligation
205-5 to comply with the provisions of the Utilities Code concerning a
205-6 certificate of convenience and necessity for a transmission
205-7 facility.
205-8 SECTION 53. Sections 1 and 2, Article 1115a, Revised
205-9 Statutes, are amended to read as follows:
205-10 Sec. 1. This article applies only to a home-rule
205-11 municipality that owns an electric utility system, that by
205-12 ordinance or charter elects to have the management and control of
205-13 the system governed by a board of trustees [this article], and
205-14 that:
205-15 (1) has outstanding obligations payable in whole or
205-16 part [solely] from and secured by a lien on and pledge of net
205-17 revenues of the system; or
205-18 (2) issues obligations that are payable in whole or
205-19 part [solely] from and secured by a lien on and pledge of the net
205-20 revenues of the system and that are approved by the attorney
205-21 general.
205-22 Sec. 2. A municipality by ordinance may transfer management
205-23 and control of the electric utility system to a [five-member] board
205-24 of trustees appointed by the municipality's governing body. The
205-25 municipality by ordinance shall determine [set] the qualifications
205-26 for appointment to the board and the number of members. The
205-27 municipality may by ordinance vest the power to establish rates and
206-1 related terms and conditions for its municipally owned electric
206-2 utility in the board of trustees appointed under this section.
206-3 SECTION 54. Subsection (a), Section 151.0101, Tax Code, is
206-4 amended to read as follows:
206-5 (a) "Taxable services" means:
206-6 (1) amusement services;
206-7 (2) cable television services;
206-8 (3) personal services;
206-9 (4) motor vehicle parking and storage services;
206-10 (5) the repair, remodeling, maintenance, and
206-11 restoration of tangible personal property, except:
206-12 (A) aircraft;
206-13 (B) a ship, boat, or other vessel, other than:
206-14 (i) a taxable boat or motor as defined by
206-15 Section 160.001;
206-16 (ii) a sports fishing boat; or
206-17 (iii) any other vessel used for pleasure;
206-18 (C) the repair, maintenance, and restoration of
206-19 a motor vehicle; and
206-20 (D) the repair, maintenance, creation, and
206-21 restoration of a computer program, including its development and
206-22 modification, not sold by the person performing the repair,
206-23 maintenance, creation, or restoration service;
206-24 (6) telecommunications services;
206-25 (7) credit reporting services;
206-26 (8) debt collection services;
206-27 (9) insurance services;
207-1 (10) information services;
207-2 (11) real property services;
207-3 (12) data processing services;
207-4 (13) real property repair and remodeling;
207-5 (14) security services; [and]
207-6 (15) telephone answering services; and
207-7 (16) a sale by a transmission and distribution
207-8 utility, as defined in Section 31.002, Utilities Code, of
207-9 transmission or delivery of service directly to an electricity
207-10 end-use customer whose consumption of electricity is subject to
207-11 taxation under this chapter.
207-12 SECTION 55. Subdivision (1), Section 182.021, Tax Code, is
207-13 amended to read as follows:
207-14 (1) "Utility company" means a person:
207-15 (A) who owns or operates a gas[, electric light,
207-16 electric power,] or water works, or water [and light] plant used
207-17 for local sale and distribution located within an incorporated city
207-18 or town in this state; or
207-19 (B) who owns or operates an electric light or
207-20 electric power works, or light plant used for local sale and
207-21 distribution located within an incorporated city or town in this
207-22 state, or who is a retail electric provider, as that term is
207-23 defined in Section 31.002, Utilities Code, that makes local sales
207-24 within an incorporated city or town in this state; provided,
207-25 however, that a person who owns an electric light or electric power
207-26 or gas plant used for distribution but who does not make retail
207-27 sales to the ultimate consumer within an incorporated city or town
208-1 in this state is not included in this definition.
208-2 SECTION 56. Effective January 1, 2002, Section 182.025, Tax
208-3 Code, is amended to read as follows:
208-4 Sec. 182.025. CHARGES BY A CITY. (a) An incorporated city
208-5 or town may make a reasonable lawful charge for the use of a city
208-6 street, alley, or public way by a public utility in the course of
208-7 its business.
208-8 (b) The total charges, however designated or measured, may
208-9 not exceed two percent of the gross receipts of the public utility
208-10 for the sale of gas[, electric energy,] or water within the city.
208-11 (c) The total charges, however designated or measured,
208-12 relating to distribution service of an electric utility or
208-13 transmission and distribution utility within the city may not
208-14 exceed the amount or amounts prescribed by Section 33.008,
208-15 Utilities Code. The charges paid by an electric utility or
208-16 transmission and distribution utility under this subsection may be
208-17 only for distribution service.
208-18 (d) If a public utility taxed under this subchapter pays a
208-19 special tax, rental, contribution, or charge under a contract or
208-20 franchise executed before May 1, 1941, the city shall credit the
208-21 payment against the amount owed by the public utility on any charge
208-22 allowable under Subsection (a) of this section.
208-23 (e) In this section:
208-24 (1) "Distribution service" has the meaning assigned by
208-25 Section 33.008, Utilities Code.
208-26 (2) "Electric utility" has the meaning assigned by
208-27 Section 31.002, Utilities Code.
209-1 (3) "Public utility" means:
209-2 (A) a person who owns or operates a gas or water
209-3 works or water plant used for local sale and distribution located
209-4 within an incorporated city or town in this state; or
209-5 (B) an electric utility or transmission and
209-6 distribution utility providing distribution service within an
209-7 incorporated city or town in this state.
209-8 (4) "Transmission and distribution utility" has the
209-9 meaning assigned by Section 31.002, Utilities Code.
209-10 SECTION 57. Subchapter B, Chapter 182, Tax Code, is amended
209-11 by adding Section 182.027 to read as follows:
209-12 Sec. 182.027. NO EXEMPTION. Notwithstanding anything to the
209-13 contrary in Chapter 161, Utilities Code, this subchapter applies to
209-14 a retail electric provider as defined in Section 31.002(17),
209-15 Utilities Code, that is owned, operated, or controlled by an
209-16 electric cooperative.
209-17 SECTION 58. Subchapter E, Chapter 191, Tax Code, is amended
209-18 by adding Section 191.0825 to read as follows:
209-19 Sec. 191.0825. REFUND OR CREDIT. (a) A person subject to
209-20 the tax imposed by this subchapter is entitled to a refund of the
209-21 tax imposed by this subchapter if:
209-22 (1) the person performs taxable services on a gas well
209-23 that was drilled after January 1, 2000; and
209-24 (2) the well produced gas that was primarily used as a
209-25 fuel to generate electricity.
209-26 (b) The comptroller may provide for a person subject to the
209-27 tax imposed by this subchapter to claim a credit against the tax
210-1 imposed by this subchapter instead of claiming a refund.
210-2 SECTION 59. Subchapter B, Chapter 201, Tax Code, is amended
210-3 by adding Section 201.059, Tax Code, to read as follows:
210-4 Sec. 201.059. REFUND OR CREDIT OF TAX. (a) Natural gas
210-5 produced from a gas well drilled after January 1, 2000, is exempt
210-6 from the taxes imposed by this chapter if the gas produced from the
210-7 well is primarily used as a fuel to generate electricity.
210-8 (b) The tax must be paid when due at the rate provided by
210-9 Section 201.052 for all gas exempt under this section. The person
210-10 responsible for paying the tax may apply to the comptroller for a
210-11 refund of the gas that is eligible for the tax exemption and is
210-12 entitled to receive a refund.
210-13 (c) The comptroller may provide for a person responsible for
210-14 paying the tax imposed by this chapter to claim a credit against
210-15 the taxes imposed by this chapter instead of claiming a refund.
210-16 SECTION 60. The Texas Public Finance Authority Act (Article
210-17 601d, Vernon's Texas Civil Statutes) is amended by adding Section
210-18 9E to read as follows:
210-19 Sec. 9E. FINANCING OF STRANDED COSTS. (a) The authority
210-20 shall, either directly or by means of a trust or trusts established
210-21 by it, have the power to issue bonds, notes, certificates of
210-22 participation, or other obligations or evidences of indebtedness
210-23 ("indebtedness") for the purpose of financing stranded costs of a
210-24 municipal power agency created by concurrent resolution by its
210-25 member cities on or before August 1, 1975, pursuant to Chapter 163,
210-26 Utilities Code, or a predecessor statute to that chapter. The
210-27 stranded costs of the municipal power agency are set forth as
211-1 allocated to the member cities in the "Potentially Strandable
211-2 Investment (ECOM) Report: 1998 Update" issued by the Public
211-3 Utility Commission of Texas.
211-4 (b) At the request of any member city of a municipal power
211-5 agency, which shall include a statement of the payment terms for
211-6 recovering stranded costs, the authority shall issue indebtedness
211-7 in the amount of the requesting member city's stranded costs, plus
211-8 the costs described in Subdivision (1) along with issuance costs
211-9 and shall make a grant of the proceeds of such indebtedness to the
211-10 municipal power agency, subject to conditions that:
211-11 (1) the municipal power agency shall use such grant to
211-12 reduce the outstanding principal of the agency's debts allocable to
211-13 stranded costs of the requesting member city for federal income tax
211-14 purposes, whether by redemption, defeasance, or tender offer,
211-15 together with any interest expenses, call premium, tender premium,
211-16 or administrative expenses associated with such principal payment;
211-17 and
211-18 (2) the municipal power agency shall reduce the amount
211-19 payable by the requesting member city under its power sales
211-20 contract with the agency to reflect the reduced debt service on the
211-21 agency's debt as a result of the foregoing payments.
211-22 (c) Indebtedness issued by the authority pursuant to this
211-23 section shall be secured by nonbypassable charges imposed by the
211-24 authority upon retail customers receiving transmission and
211-25 distribution services provided by the requesting member city, which
211-26 shall be consistent with the stranded cost recovery terms set forth
211-27 in the requesting member city's application unless otherwise
212-1 approved by the requesting member city. Indebtedness issued by the
212-2 authority pursuant to this section shall not be the debt of the
212-3 State of Texas, the municipal power agency, or any member of the
212-4 municipal power agency.
212-5 (d) The Public Utility Commission of Texas shall provide
212-6 such assistance to the authority as is necessary to ensure the
212-7 collection and enforcement of the nonbypassable charges, whether
212-8 directly or by using the assistance and powers of the requesting
212-9 member city.
212-10 (e) The authority and the Public Utility Commission of Texas
212-11 are granted all such powers necessary to effectuate the foregoing
212-12 duties and responsibilities. This section shall be interpreted
212-13 broadly in a manner consistent with the most cost-effective
212-14 financing of stranded costs. To the extent possible, the
212-15 indebtedness issued by the authority shall be structured so that
212-16 the interest thereon is excluded from gross income for federal
212-17 income tax purposes. In all events, the interest thereon shall not
212-18 be subject to tax or included as part of the measurement of tax by
212-19 the state or any of its political subdivisions.
212-20 SECTION 61. Section 11(a), Texas Public Finance Authority
212-21 Act (Article 601d, Vernon's Texas Civil Statutes), is amended to
212-22 read as follows:
212-23 (a) The board's authority under this Act is limited to the
212-24 financing of the acquisition or construction of a building, [or]
212-25 the purchase or lease of equipment, or the financing of stranded
212-26 costs of a municipal power agency. That authority does not affect
212-27 the authority of the commission or any other state agency.
213-1 SECTION 62. The following provisions are repealed:
213-2 (1) Section 12.104, Utilities Code;
213-3 (2) Chapter 34, Utilities Code;
213-4 (3) Subchapters F and G, Chapter 36, Utilities Code;
213-5 and
213-6 (4) Section 37.058, Utilities Code.
213-7 SECTION 63. (a) Nothing in this Act shall restrict or limit
213-8 a municipality's historical right to control and receive reasonable
213-9 compensation for use of public streets, alleys, rights-of-way, or
213-10 other public property to convey or provide electricity.
213-11 (b) Nothing in this Act shall affect a retail electric
213-12 utility's right to provide electric service in accordance with its
213-13 certificate of public convenience and necessity. A certificate of
213-14 convenience and necessity may, however, be revoked or modified as
213-15 provided by Section 37.059, Utilities Code, and Section 37.060,
213-16 Utilities Code, as added by this Act.
213-17 SECTION 64. Notwithstanding any other provision of this Act,
213-18 any person or entity that provides electric service to the
213-19 institution of higher education on December 31, 2001, shall
213-20 continue to offer electric service to an institution of higher
213-21 education until September 1, 2007, at a total rate that is no
213-22 higher than the rate paid by the institution on December 31, 2001.
213-23 The rate paid by an institution of higher education on December 31,
213-24 2001, shall be based on the rates provided for or described in
213-25 Section 36.351, Utilities Code. As used in this section, "person
213-26 or entity" includes, but is not limited to, an electric utility,
213-27 retail electric provider, municipal corporation, cooperative
214-1 corporation, or river authority.
214-2 SECTION 65. The Public Utility Commission of Texas shall
214-3 study and make recommendations by December 15, 2000, to the
214-4 legislature for additional legislation that would move to and
214-5 establish a competitive electric market in accordance with the
214-6 changes in law made by this Act.
214-7 SECTION 66. Not later than the 180th day after the effective
214-8 date of this Act, the Public Utility Commission of Texas shall
214-9 establish rules and procedures for the securitization of stranded
214-10 costs for river authorities, as provided by Subdivision (2),
214-11 Subsection (a), Section 40.003, Utilities Code, as added by this
214-12 Act, and for electric cooperatives, as provided by Section 41.003,
214-13 Utilities Code.
214-14 SECTION 67. This Act takes effect September 1, 1999.
214-15 SECTION 68. The importance of this legislation and the
214-16 crowded condition of the calendars in both houses create an
214-17 emergency and an imperative public necessity that the
214-18 constitutional rule requiring bills to be read on three several
214-19 days in each house be suspended, and this rule is hereby suspended.