AN ACT
1-1 relating to electric utility restructuring and to the powers and
1-2 duties of the Public Utility Commission of Texas, Office of Public
1-3 Utility Counsel, and Texas Natural Resource Conservation
1-4 Commission; providing penalties.
1-5 BE IT ENACTED BY THE LEGISLATURE OF THE STATE OF TEXAS:
1-6 SECTION 1. Section 11.003, Utilities Code, is amended to
1-7 read as follows:
1-8 Sec. 11.003. DEFINITIONS. In this title:
1-9 (1) "Affected person" means:
1-10 (A) a public utility or electric cooperative
1-11 affected by an action of a regulatory authority;
1-12 (B) a person whose utility service or rates are
1-13 affected by a proceeding before a regulatory authority; or
1-14 (C) a person who:
1-15 (i) is a competitor of a public utility
1-16 with respect to a service performed by the utility; or
1-17 (ii) wants to enter into competition with
1-18 a public utility.
1-19 (2) "Affiliate" means:
1-20 (A) a person who directly or indirectly owns or
1-21 holds at least five percent of the voting securities of a public
1-22 utility;
1-23 (B) a person in a chain of successive ownership
1-24 of at least five percent of the voting securities of a public
2-1 utility;
2-2 (C) a corporation that has at least five percent
2-3 of its voting securities owned or controlled, directly or
2-4 indirectly, by a public utility;
2-5 (D) a corporation that has at least five percent
2-6 of its voting securities owned or controlled, directly or
2-7 indirectly, by:
2-8 (i) a person who directly or indirectly
2-9 owns or controls at least five percent of the voting securities of
2-10 a public utility; or
2-11 (ii) a person in a chain of successive
2-12 ownership of at least five percent of the voting securities of a
2-13 public utility;
2-14 (E) a person who is an officer or director of a
2-15 public utility or of a corporation in a chain of successive
2-16 ownership of at least five percent of the voting securities of a
2-17 public utility; or
2-18 (F) a person determined to be an affiliate under
2-19 Section 11.006.
2-20 (3) "Allocation" means the division among
2-21 municipalities or among municipalities and unincorporated areas of
2-22 the plant, revenues, expenses, taxes, and reserves of a utility
2-23 used to provide public utility service in a municipality or for a
2-24 municipality and unincorporated areas.
2-25 (4) "Commission" means the Public Utility Commission
2-26 of Texas.
3-1 (5) "Commissioner" means a member of the Public
3-2 Utility Commission of Texas.
3-3 (6) "Cooperative corporation" means:
3-4 (A) an electric cooperative [corporation
3-5 organized under Chapter 161 or a predecessor statute to Chapter 161
3-6 and operating under that chapter]; or
3-7 (B) a telephone cooperative corporation
3-8 organized under Chapter 162 or a predecessor statute to Chapter 162
3-9 and operating under that chapter.
3-10 (7) "Corporation" means a domestic or foreign
3-11 corporation, joint-stock company, or association, and each lessee,
3-12 assignee, trustee, receiver, or other successor in interest of the
3-13 corporation, company, or association, that has any of the powers or
3-14 privileges of a corporation not possessed by an individual or
3-15 partnership. The term does not include a municipal corporation or
3-16 electric cooperative, except as expressly provided by this title.
3-17 (8) "Counsellor" means the public utility counsel.
3-18 (9) "Electric cooperative" means:
3-19 (A) a corporation organized under Chapter 161 or
3-20 a predecessor statute to Chapter 161 and operating under that
3-21 chapter;
3-22 (B) a corporation organized as an electric
3-23 cooperative in a state other than Texas that has obtained a
3-24 certificate of authority to conduct affairs in the State of Texas;
3-25 or
3-26 (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,
5-1 but does not include an electric cooperative.
5-2 (15) [(14)] "Proceeding" means a hearing,
5-3 investigation, inquiry, or other procedure for finding facts or
5-4 making a decision under this title. The term includes a denial of
5-5 relief or dismissal of a complaint.
5-6 (16) [(15)] "Rate" includes:
5-7 (A) any compensation, tariff, charge, fare,
5-8 toll, rental, or classification that is directly or indirectly
5-9 demanded, observed, charged, or collected by a public utility for a
5-10 service, product, or commodity described in the definition of
5-11 utility in Section 31.002 or 51.002; and
5-12 (B) a rule, practice, or contract affecting the
5-13 compensation, tariff, charge, fare, toll, rental, or
5-14 classification.
5-15 (17) [(16)] "Ratemaking proceeding" means[:]
5-16 [(A)] a proceeding in which a rate is changed[;
5-17 and]
5-18 [(B) a proceeding initiated under Chapter 34].
5-19 (18) [(17)] "Regulatory authority" means either the
5-20 commission or the governing body of a municipality, in accordance
5-21 with the context.
5-22 (19) [(18)] "Service" has its broadest and most
5-23 inclusive meaning. The term includes any act performed, anything
5-24 supplied, and any facilities used or supplied by a public utility
5-25 in the performance of the utility's duties under this title to its
5-26 patrons, employees, other public utilities, an electric
6-1 cooperative, and the public. The term also includes the
6-2 interchange of facilities between two or more public utilities.
6-3 The term does not include the printing, distribution, or sale of
6-4 advertising in a telephone directory.
6-5 (20) [(19)] "Test year" means the most recent 12
6-6 months, beginning on the first day of a calendar or fiscal year
6-7 quarter, for which operating data for a public utility are
6-8 available.
6-9 (21) [(20)] "Trade association" means a nonprofit,
6-10 cooperative, and voluntarily joined association of business or
6-11 professional persons who are employed by public utilities or
6-12 utility competitors to assist the public utility industry, a
6-13 utility competitor, or the industry's or competitor's employees in
6-14 dealing with mutual business or professional problems and in
6-15 promoting their common interest.
6-16 SECTION 2. Section 12.005, Utilities Code, is amended to
6-17 read as follows:
6-18 Sec. 12.005. APPLICATION OF SUNSET ACT. The Public Utility
6-19 Commission of Texas is subject to Chapter 325, Government Code
6-20 (Texas Sunset Act). Unless continued in existence as provided by
6-21 that chapter or by Chapter 39, the commission is abolished and this
6-22 title expires September 1, 2005 [2001].
6-23 SECTION 3. Section 12.101, Utilities Code, is amended to
6-24 read as follows:
6-25 Sec. 12.101. COMMISSION EMPLOYEES. The commission shall
6-26 employ:
7-1 (1) an executive director; and
7-2 (2) [a general counsel; and]
7-3 [(3)] officers and other employees the commission
7-4 considers necessary to administer this title.
7-5 SECTION 4. Sections 12.151 and 12.152, Utilities Code, are
7-6 amended to read as follows:
7-7 Sec. 12.151. REGISTERED LOBBYIST. A person required to
7-8 register as a lobbyist under Chapter 305, Government Code, because
7-9 of the person's activities for compensation on behalf of a
7-10 profession related to the operation of the commission may not serve
7-11 as a commissioner [or act as general counsel to the commission].
7-12 Sec. 12.152. Conflict of Interest. (a) A person is not
7-13 eligible for appointment as a commissioner [or for employment as
7-14 the general counsel] or executive director of the commission if:
7-15 (1) the person serves on the board of directors of a
7-16 company that supplies fuel, utility-related services, or
7-17 utility-related products to regulated or unregulated electric or
7-18 telecommunications utilities; or
7-19 (2) the person or the person's spouse:
7-20 (A) is employed by or participates in the
7-21 management of a business entity or other organization that is
7-22 regulated by or receives funds from the commission;
7-23 (B) directly or indirectly owns or controls more
7-24 than a 10 percent interest or a pecuniary interest with a value
7-25 exceeding $10,000 in:
7-26 (i) a business entity or other
8-1 organization that is regulated by or receives funds from the
8-2 commission; or
8-3 (ii) a utility competitor, utility
8-4 supplier, or other entity affected by a commission decision in a
8-5 manner other than by the setting of rates for that class of
8-6 customer;
8-7 (C) uses or receives a substantial amount of
8-8 tangible goods, services, or funds from the commission, other than
8-9 compensation or reimbursement authorized by law for commission
8-10 membership, attendance, or expenses; or
8-11 (D) notwithstanding Paragraph (B), has an
8-12 interest in a mutual fund or retirement fund in which more than 10
8-13 percent of the fund's holdings at the time of appointment is in a
8-14 single utility, utility competitor, or utility supplier in this
8-15 state and the person does not disclose this information to the
8-16 governor, senate, commission, or other entity, as appropriate.
8-17 (b) A person otherwise ineligible because of Subsection
8-18 (a)(2)(B) may be appointed to the commission and serve as a
8-19 commissioner or may be employed as [the general counsel or]
8-20 executive director if the person:
8-21 (1) notifies the attorney general and commission that
8-22 the person is ineligible because of Subsection (a)(2)(B); and
8-23 (2) divests the person or the person's spouse of the
8-24 ownership or control:
8-25 (A) before beginning service or employment; or
8-26 (B) if the person is already serving or
9-1 employed, within a reasonable time.
9-2 SECTION 5. Section 13.002, Utilities Code, is amended to
9-3 read as follows:
9-4 Sec. 13.002. APPLICATION OF SUNSET ACT. The Office of
9-5 Public Utility Counsel is subject to Chapter 325, Government Code
9-6 (Texas Sunset Act). Unless continued in existence as provided by
9-7 that chapter, the office is abolished and this chapter expires
9-8 September 1, 2005 [2001].
9-9 SECTION 6. Subsection (a), Section 13.003, Utilities Code,
9-10 is amended to read as follows:
9-11 (a) The office:
9-12 (1) shall assess the effect of utility rate changes
9-13 and other regulatory actions on residential consumers in this
9-14 state;
9-15 (2) shall advocate in the office's own name a position
9-16 determined by the counsellor to be most advantageous to a
9-17 substantial number of residential consumers;
9-18 (3) may appear or intervene, as a party or otherwise,
9-19 as a matter of right on behalf of:
9-20 (A) residential consumers, as a class, in any
9-21 proceeding before the commission, including an alternative dispute
9-22 resolution proceeding; and
9-23 (B) small commercial consumers, as a class, in
9-24 any proceeding in which the counsellor determines that small
9-25 commercial consumers are in need of representation, including an
9-26 alternative dispute resolution proceeding;
10-1 (4) may initiate or intervene as a matter of right or
10-2 otherwise appear in a judicial proceeding:
10-3 (A) that involves an action taken by an
10-4 administrative agency in a proceeding, including an alternative
10-5 dispute resolution proceeding, in which the counsellor is
10-6 authorized to appear; or
10-7 (B) in which the counsellor determines that
10-8 residential electricity consumers or small commercial electricity
10-9 consumers are in need of representation;
10-10 (5) is entitled to the same access as a party, other
10-11 than commission staff, to records gathered by the commission under
10-12 Section 14.204;
10-13 (6) is entitled to discovery of any nonprivileged
10-14 matter that is relevant to the subject matter of a proceeding or
10-15 petition before the commission;
10-16 (7) may represent an individual residential or small
10-17 commercial consumer with respect to the consumer's disputed
10-18 complaint concerning utility services that is unresolved before the
10-19 commission; and
10-20 (8) may recommend legislation to the legislature that
10-21 the office determines would positively affect the interests of
10-22 residential and small commercial consumers.
10-23 SECTION 7. Section 13.024, Utilities Code, is amended to
10-24 read as follows:
10-25 Sec. 13.024. Prohibited Acts. (a) The counsellor may not[:]
10-26 [(1)] have a direct or indirect interest in a utility
11-1 company regulated under this title[; or]
11-2 [(2) provide legal services directly or indirectly to
11-3 or be employed in any capacity by a utility company regulated under
11-4 this title], its parent, or its subsidiary companies, corporations,
11-5 or cooperatives or a utility competitor, utility supplier, or other
11-6 entity affected in a manner other than by the setting of rates for
11-7 that class of customer.
11-8 (b) The prohibition under Subsection (a) applies during the
11-9 period of the counsellor's service [and until the second
11-10 anniversary of the date the counsellor ceases to serve as
11-11 counsellor.]
11-12 [(c) This section does not prohibit a person from otherwise
11-13 engaging in the private practice of law after the person ceases to
11-14 serve as counsellor].
11-15 SECTION 8. Section 13.043, Utilities Code, is amended to
11-16 read as follows:
11-17 Sec. 13.043. PROHIBITION ON EMPLOYMENT OR REPRESENTATION.
11-18 (a) A former counsel may not make any communication to or
11-19 appearance before the commission or an officer or employee of the
11-20 commission before the second anniversary of the date the person
11-21 ceases to serve as counsel if the communication or appearance is
11-22 made:
11-23 (1) on behalf of another person in connection with any
11-24 matter on which the person seeks official action; or
11-25 (2) with the intent to influence a commission decision
11-26 or action, unless acting on his or her own behalf and without
12-1 remuneration.
12-2 (b) A former counsel may not represent any person or receive
12-3 compensation for services rendered on behalf of any person
12-4 regarding a matter before the commission before the second
12-5 anniversary of the date the person ceases to serve as counsel.
12-6 (c) A person commits an offense if the person violates this
12-7 section. An offense under this subsection is a Class A
12-8 misdemeanor.
12-9 (d) An [The counsellor or an] employee of the office may
12-10 not:
12-11 (1) be employed by a public utility that was in the
12-12 scope of the [counsellor's or] employee's official responsibility
12-13 while the [counsellor or] employee was associated with the office;
12-14 or
12-15 (2) represent a person before the commission or a
12-16 court in a matter:
12-17 (A) in which the [counsellor or] employee was
12-18 personally involved while associated with the office; or
12-19 (B) that was within the [counsellor's or]
12-20 employee's official responsibility while the [counsellor or]
12-21 employee was associated with the office.
12-22 (e) [(b)] The prohibition of Subsection (d)(1) [(a)(1)]
12-23 applies until the[:]
12-24 [(1) second anniversary of the date the counsellor
12-25 ceases to serve as a counsellor; and]
12-26 [(2)] first anniversary of the date the employee's
13-1 employment with the office ceases.
13-2 (f) [(c)] The prohibition of Subsection (d)(2) [(a)(2)]
13-3 applies while an [a counsellor or] employee of the office is
13-4 associated with the office and at any time after.
13-5 (g) For purposes of this section, "person" includes an
13-6 electric cooperative.
13-7 SECTION 9. Subsection (d), Section 14.101, Utilities Code,
13-8 is amended to read as follows:
13-9 (d) This section does not apply to:
13-10 (1) the purchase of a unit of property for
13-11 replacement; [or]
13-12 (2) an addition to the facilities of a public utility
13-13 by construction; or
13-14 (3) transactions that facilitate unbundling, asset
13-15 valuation, minimization of ownership or control of generation
13-16 assets, or other purposes consistent with Chapter 39.
13-17 SECTION 10. Subsections (a) and (b), Section 16.001,
13-18 Utilities Code, are amended to read as follows:
13-19 (a) To defray the expenses incurred in the administration of
13-20 this title, an assessment is imposed on each public utility, retail
13-21 electric provider, and electric cooperative within the jurisdiction
13-22 of the commission that serves the ultimate consumer, including each
13-23 interexchange telecommunications carrier.
13-24 (b) An assessment under this section is equal to one-sixth
13-25 of one percent of the public utility's, retail electric provider's,
13-26 or electric cooperative's gross receipts from rates charged to the
14-1 ultimate consumer in this state.
14-2 SECTION 11. Section 31.002, Utilities Code, is amended to
14-3 read as follows:
14-4 Sec. 31.002. DEFINITIONS. In this subtitle:
14-5 (1) "Affiliated power generation company" means a
14-6 power generation company that is affiliated with or the successor
14-7 in interest of an electric utility certificated to serve an area.
14-8 (2) "Affiliated retail electric provider" means a
14-9 retail electric provider that is affiliated with or the successor
14-10 in interest of an electric utility certificated to serve an area.
14-11 (3) "Aggregation" includes the following:
14-12 (A) the purchase of electricity from a retail
14-13 electric provider, a municipally owned utility, or an electric
14-14 cooperative by an electricity customer for its own use in multiple
14-15 locations, provided that an electricity customer may not avoid any
14-16 nonbypassable charges or fees as a result of aggregating its load;
14-17 or
14-18 (B) the purchase of electricity by an
14-19 electricity customer as part of a voluntary association of
14-20 electricity customers, provided that an electricity customer may
14-21 not avoid any nonbypassable charges or fees as a result of
14-22 aggregating its load.
14-23 (4) "Customer choice" means the freedom of a retail
14-24 customer to purchase electric services, either individually or
14-25 through voluntary aggregation with other retail customers, from the
14-26 provider or providers of the customer's choice and to choose among
15-1 various fuel types, energy efficiency programs, and renewable power
15-2 suppliers.
15-3 (5) "Electric Reliability Council of Texas" or "ERCOT"
15-4 means the area in Texas served by electric utilities, municipally
15-5 owned utilities, and electric cooperatives that is not
15-6 synchronously interconnected with electric utilities outside the
15-7 state.
15-8 (6) "Electric utility" means a person or river
15-9 authority that owns or operates for compensation in this state
15-10 equipment or facilities to produce, generate, transmit, distribute,
15-11 sell, or furnish electricity in this state. The term includes a
15-12 lessee, trustee, or receiver of an electric utility and a
15-13 recreational vehicle park owner who does not comply with Subchapter
15-14 C, Chapter 184, with regard to the metered sale of electricity at
15-15 the recreational vehicle park. The term does not include:
15-16 (A) a municipal corporation;
15-17 (B) a qualifying facility;
15-18 (C) a power generation company;
15-19 (D) an exempt wholesale generator;
15-20 (E) [(D)] a power marketer;
15-21 (F) [(E)] a corporation described by Section
15-22 32.053 to the extent the corporation sells electricity exclusively
15-23 at wholesale and not to the ultimate consumer;
15-24 (G) an electric cooperative;
15-25 (H) a retail electric provider;
15-26 (I) this state or an agency of this state; or
16-1 (J) [(F)] a person not otherwise an electric
16-2 utility who:
16-3 (i) furnishes an electric service or
16-4 commodity only to itself, its employees, or its tenants as an
16-5 incident of employment or tenancy, if that service or commodity is
16-6 not resold to or used by others;
16-7 (ii) owns or operates in this state
16-8 equipment or facilities to produce, generate, transmit, distribute,
16-9 sell, or furnish electric energy to an electric utility, if the
16-10 equipment or facilities are used primarily to produce and generate
16-11 electric energy for consumption by that person; or
16-12 (iii) owns or operates in this state a
16-13 recreational vehicle park that provides metered electric service in
16-14 accordance with Subchapter C, Chapter 184.
16-15 (7) [(2)] "Exempt wholesale generator" means a person
16-16 who is engaged directly or indirectly through one or more
16-17 affiliates exclusively in the business of owning or operating all
16-18 or part of a facility for generating electric energy and selling
16-19 electric energy at wholesale and who:
16-20 (A) does not own a facility for the transmission
16-21 of electricity, other than an essential interconnecting
16-22 transmission facility necessary to effect a sale of electric energy
16-23 at wholesale; and
16-24 (B) has:
16-25 (i) applied to the Federal Energy
16-26 Regulatory Commission for a determination under 15 U.S.C. Section
17-1 79z-5a; or
17-2 (ii) registered as an exempt wholesale
17-3 generator as required by Section 35.032.
17-4 (8) "Freeze period" means the period beginning on
17-5 January 1, 1999, and ending on December 31, 2001.
17-6 (9) "Independent system operator" means an entity
17-7 supervising the collective transmission facilities of a power
17-8 region that is charged with nondiscriminatory coordination of
17-9 market transactions, systemwide transmission planning, and network
17-10 reliability.
17-11 (10) "Power generation company" means a person that:
17-12 (A) generates electricity that is intended to be
17-13 sold at wholesale;
17-14 (B) does not own a transmission or distribution
17-15 facility in this state other than an essential interconnecting
17-16 facility, a facility not dedicated to public use, or a facility
17-17 otherwise excluded from the definition of "electric utility" under
17-18 this section; and
17-19 (C) does not have a certificated service area,
17-20 although its affiliated electric utility or transmission and
17-21 distribution utility may have a certificated service area.
17-22 (11) [(3)] "Power marketer" means a person who:
17-23 (A) becomes an owner of electric energy in this
17-24 state for the purpose of selling the electric energy at wholesale;
17-25 (B) does not own generation, transmission, or
17-26 distribution facilities in this state;
18-1 (C) does not have a certificated service area;
18-2 and
18-3 (D) has:
18-4 (i) been granted authority by the Federal
18-5 Energy Regulatory Commission to sell electric energy at
18-6 market-based rates; or
18-7 (ii) registered as a power marketer under
18-8 Section 35.032.
18-9 (12) "Power region" means a contiguous geographical
18-10 area which is a distinct region of the North American Electric
18-11 Reliability Council.
18-12 (13) [(4)] "Qualifying cogenerator" and "qualifying
18-13 small power producer" have the meanings assigned those terms by 16
18-14 U.S.C. Sections 796(18)(C) and 796(17)(D). A qualifying
18-15 cogenerator that provides electricity to the purchaser of the
18-16 cogenerator's thermal output is not for that reason considered to
18-17 be a retail electric provider or a power generation company.
18-18 (14) [(5)] "Qualifying facility" means a qualifying
18-19 cogenerator or qualifying small power producer.
18-20 (15) [(6)] "Rate" includes a compensation, tariff,
18-21 charge, fare, toll, rental, or classification that is directly or
18-22 indirectly demanded, observed, charged, or collected by an electric
18-23 utility for a service, product, or commodity described in the
18-24 definition of electric utility in this section and a rule,
18-25 practice, or contract affecting the compensation, tariff, charge,
18-26 fare, toll, rental, or classification that must be approved by a
19-1 regulatory authority.
19-2 (16) "Retail customer" means the separately metered
19-3 end-use customer who purchases and ultimately consumes electricity.
19-4 (17) "Retail electric provider" means a person that
19-5 sells electric energy to retail customers in this state. A retail
19-6 electric provider may not own or operate generation assets.
19-7 (18) "Separately metered" means metered by an
19-8 individual meter that is used to measure electric energy
19-9 consumption by a retail customer and for which the customer is
19-10 directly billed by a utility, retail electric provider, electric
19-11 cooperative, or municipally owned utility.
19-12 (19) "Transmission and distribution utility" means a
19-13 person or river authority that owns or operates for compensation in
19-14 this state equipment or facilities to transmit or distribute
19-15 electricity, except for facilities necessary to interconnect a
19-16 generation facility with the transmission or distribution network,
19-17 a facility not dedicated to public use, or a facility otherwise
19-18 excluded from the definition of "electric utility" under this
19-19 section, in a qualifying power region certified under Section
19-20 39.152, but does not include a municipally owned utility or an
19-21 electric cooperative.
19-22 (20) [(7)] "Transmission service" includes
19-23 construction or enlargement of facilities, transmission over
19-24 distribution facilities, control area services, scheduling
19-25 resources, regulation services, reactive power support, voltage
19-26 control, provision of operating reserves, and any other associated
20-1 electrical service the commission determines appropriate, except
20-2 that, on and after the implementation of customer choice, control
20-3 area services, scheduling resources, regulation services, provision
20-4 of operating reserves, and reactive power support, voltage control,
20-5 and other services provided by generation resources are not
20-6 "transmission service."[.]
20-7 SECTION 12. Subchapter A, Chapter 32, Utilities Code, is
20-8 amended by adding Section 32.0015 to read as follows:
20-9 Sec. 32.0015. REGULATION OF SUCCESSOR ELECTRIC UTILITY OR
20-10 ELECTRIC COOPERATIVE. If an electric utility purchases, acquires,
20-11 merges, or consolidates with or acquires 50 percent or more of the
20-12 stock of an electric utility or electric cooperative, the
20-13 commission shall regulate the successor electric utility or
20-14 electric cooperative in the same manner that the commission would
20-15 regulate the entity that was subject to the stricter regulation
20-16 before the purchase, acquisition, merger, or consolidation.
20-17 SECTION 13. Sections 32.051 and 32.052, Utilities Code, are
20-18 amended to read as follows:
20-19 Sec. 32.051. Exemption of River Authority From Wholesale
20-20 Rate Regulation. Notwithstanding any other provision of this
20-21 title, the commission may not directly or indirectly regulate
20-22 revenue requirements, rates, fuel costs, fuel charges, or fuel
20-23 acquisitions that are related to the generation and sale of
20-24 electricity at wholesale, and not to ultimate consumers, by a river
20-25 authority operating a steam generating plant on or before
20-26 January 1, 1999.
21-1 Sec. 32.052. Ability of Certain River Authorities to
21-2 Construct Improvements. A river authority operating a steam
21-3 generating plant on or before January 1, 1999, may acquire,
21-4 finance, construct, rebuild, repower, and use new or existing power
21-5 plants, equipment, transmission lines, or other assets to sell
21-6 electricity exclusively at wholesale to:
21-7 (1) a purchaser in San Saba, Llano, Burnet, Travis,
21-8 Bastrop, Blanco, Colorado, or Fayette County; or
21-9 (2) a purchaser in an area served by the river
21-10 authority on January 1, 1975.
21-11 SECTION 14. Section 32.053, Utilities Code, is amended by
21-12 amending Subsections (b) and (f) and adding Subsections (g) and (h)
21-13 to read as follows:
21-14 (b) Notwithstanding a river authority's enabling legislation
21-15 or Chapter 245, Acts of the 67th Legislature, Regular Session, 1981
21-16 (Article 717p, Vernon's Texas Civil Statutes), a corporation may:
21-17 (1) acquire, finance, construct, rebuild, repower,
21-18 operate, or sell a facility directly related to the generation of
21-19 electricity; [and]
21-20 (2) sell, at wholesale only, the output of the
21-21 facility to a purchaser, other than an ultimate consumer, at any
21-22 location in this state; and
21-23 (3) purchase and sell electricity, at wholesale only,
21-24 to a purchaser, other than an ultimate consumer, at any location in
21-25 this state.
21-26 (f) The proceeds from the sale of bonds or other obligations
22-1 the interest on which is exempt from taxation and that are issued
22-2 by a corporation or river authority subject to this section, other
22-3 than a bond or obligation available to an investor-owned utility or
22-4 exempt wholesale generator, may not be used by the corporation[,
22-5 and may not have been used,] to finance the construction or
22-6 acquisition of or the rebuilding or repowering of a facility for
22-7 the generation of electricity by the corporation.
22-8 (g) Notwithstanding any other law, the board of directors of
22-9 a river authority may sell, lease, loan, or otherwise transfer
22-10 some, all, or substantially all of the electric generation property
22-11 of the river authority to a nonprofit corporation authorized under
22-12 this section or Chapter 245, Acts of the 67th Legislature, Regular
22-13 Session, 1981 (Article 717p, Vernon's Texas Civil Statutes). The
22-14 property transfer shall be made under terms and conditions approved
22-15 by the board of directors of the river authority.
22-16 (h) Subsections (a)-(f) do not apply to a corporation
22-17 created under Chapter 245, Acts of the 67th Legislature, Regular
22-18 Session, 1981 (Article 717p, Vernon's Texas Civil Statutes), to
22-19 serve an area described in Section 32.052.
22-20 SECTION 15. Subchapter A, Chapter 33, Utilities Code, is
22-21 amended by adding Section 33.008 to read as follows:
22-22 Sec. 33.008. FRANCHISE CHARGES. (a) Following the end of
22-23 the freeze period for a municipality that has been served by an
22-24 electric utility, and following the date a municipally owned
22-25 utility or an electric cooperative has implemented customer choice
22-26 for a municipality that has been served by that municipally owned
23-1 utility or electric cooperative, a municipality may impose on an
23-2 electric utility, transmission and distribution utility,
23-3 municipally owned utility, or electric cooperative, as appropriate,
23-4 that provides distribution service within the municipality a
23-5 reasonable charge as specified in Subsection (b) for the use of a
23-6 municipal street, alley, or public way to deliver electricity to a
23-7 retail customer. A municipality may not impose a charge on:
23-8 (1) an electric utility, or transmission and
23-9 distribution utility, municipally owned utility, or electric
23-10 cooperative for electric service provided outside the municipality;
23-11 (2) a qualifying facility;
23-12 (3) an exempt wholesale generator;
23-13 (4) a power marketer;
23-14 (5) a retail electric provider;
23-15 (6) a power generation company;
23-16 (7) a person that generates electricity on and after
23-17 January 1, 2002; or
23-18 (8) an aggregator, as that term is defined by Section
23-19 39.353.
23-20 (b) If a municipality collected a charge or fee for a
23-21 franchise to use a municipal street, alley, or public way from an
23-22 electric utility, a municipally owned utility, or an electric
23-23 cooperative before the end of the freeze period, the municipality,
23-24 after the end of the freeze period or after implementation of
23-25 customer choice by the municipally owned utility or electric
23-26 cooperative, as appropriate, is entitled to collect from each
24-1 electric utility, transmission and distribution utility,
24-2 municipally owned utility, or electric cooperative that uses the
24-3 municipality's streets, alleys, or public ways to provide
24-4 distribution service a charge based on each kilowatt hour of
24-5 electricity delivered by the utility to each retail customer whose
24-6 consuming facility's point of delivery is located within the
24-7 municipality's boundaries. The charge imposed shall be equal to
24-8 the total electric franchise fee revenue due the municipality from
24-9 electric utilities, municipally owned utilities, or electric
24-10 cooperatives, as appropriate, for calendar year 1998 divided by the
24-11 total kilowatt hours delivered during 1998 by the applicable
24-12 electric utility, municipally owned utility, or electric
24-13 cooperative to retail customers whose consuming facilities' points
24-14 of delivery were located within the municipality's boundaries. The
24-15 compensation a municipality may collect from each electric utility,
24-16 transmission and distribution utility, municipally owned utility,
24-17 or electric cooperative providing distribution service shall be
24-18 equal to the charge per kilowatt hour determined for 1998
24-19 multiplied times the number of kilowatt hours delivered within the
24-20 municipality's boundaries.
24-21 (c) The municipal franchise charges authorized by this
24-22 section shall be considered a reasonable and necessary operating
24-23 expense of each electric utility, transmission and distribution
24-24 utility, municipally owned utility, or electric cooperative that is
24-25 subject to a charge under this section. The charge shall be
24-26 included in the nonbypassable delivery charges that a customer's
25-1 retail electric provider must pay under Section 39.107 to the
25-2 utility serving the customer.
25-3 (d) The municipal franchise charges authorized by this
25-4 section are in lieu of any franchise charges or fees payable under
25-5 a franchise agreement in effect before the expiration of the freeze
25-6 period or, as appropriate, before the implementation of customer
25-7 choice by a municipally owned utility or electric cooperative.
25-8 Except as otherwise provided by this section, this section does not
25-9 affect a provision of a franchise agreement in effect before the
25-10 end of the freeze period or, as appropriate, before the
25-11 implementation of customer choice by a municipally owned utility or
25-12 electric cooperative.
25-13 (e) A municipality may conduct an audit or other inquiry or
25-14 may pursue any cause of action in relation to an electric
25-15 utility's, transmission and distribution utility's, municipally
25-16 owned utility's, or electric cooperative's payment of charges
25-17 authorized by this section only if such audit, inquiry, or pursuit
25-18 of a cause of action concerns a payment made less than two years
25-19 before commencement of such audit, inquiry, or pursuit of a cause
25-20 of action; provided, however, that this subsection does not apply
25-21 to an audit, inquiry, or cause of action commenced before September
25-22 1, 1999. An electric utility, transmission and distribution
25-23 utility, municipally owned utility, or electric cooperative shall,
25-24 on request of the municipality in connection with a municipal
25-25 audit, identify the service provider and the type of service
25-26 delivered for any service in addition to electricity delivered
26-1 directly to retail customers through the utility's
26-2 electricity-conducting facilities that are located in the
26-3 municipality's streets, alleys, or public ways and for which the
26-4 utility receives compensation.
26-5 (f) Notwithstanding any other provision of this section, on
26-6 the expiration of a franchise agreement existing on September 1,
26-7 1999, an electric utility, transmission and distribution utility,
26-8 municipally owned utility, or electric cooperative and a
26-9 municipality may mutually agree to a different level of
26-10 compensation or to a different method for determining the amount
26-11 the municipality may charge for the use of a municipal street,
26-12 alley, or public way in connection with the delivery of electricity
26-13 at retail within the municipality.
26-14 (g) After the end of the freeze period or after
26-15 implementation of customer choice by the municipally owned utility
26-16 or electric cooperative, as appropriate, a newly incorporated
26-17 municipality or a municipality that has not previously collected
26-18 compensation for the delivery of electricity at retail within the
26-19 municipality may adopt and collect compensation based on the same
26-20 rate per kilowatt hour that is collected by any other municipality
26-21 in the same county that is served by the same electric utility,
26-22 transmission and distribution utility, municipally owned utility,
26-23 or electric cooperative.
26-24 (h) In this section, "distribution service" means the
26-25 delivery of electricity to all retail customers.
26-26 SECTION 16. Section 35.001, Utilities Code, is amended to
27-1 read as follows:
27-2 Sec. 35.001. Definition. In this subchapter, "electric
27-3 utility" includes a municipally owned utility and an electric
27-4 cooperative.
27-5 SECTION 17. Section 35.004, Utilities Code, is amended to
27-6 read as follows:
27-7 Sec. 35.004. PROVISION OF TRANSMISSION SERVICE. (a) An
27-8 electric utility or transmission and distribution utility that owns
27-9 or operates transmission facilities shall provide wholesale
27-10 transmission service at rates and terms, including terms of access,
27-11 that are comparable to the rates and terms of the utility's own use
27-12 of its system.
27-13 (b) The commission shall ensure that an electric utility or
27-14 transmission and distribution utility provides nondiscriminatory
27-15 access to wholesale transmission service for qualifying facilities,
27-16 exempt wholesale generators, power marketers, power generation
27-17 companies, retail electric providers, and other electric utilities
27-18 or transmission and distribution utilities.
27-19 (c) When an electric utility, electric cooperative, or
27-20 transmission and distribution utility provides wholesale
27-21 transmission service within ERCOT at the request of a third party,
27-22 the commission shall ensure that the utility recovers the utility's
27-23 reasonable costs in providing wholesale transmission services
27-24 necessary for the transaction from the entity for which the
27-25 transmission is provided so that the utility's other customers do
27-26 not bear the costs of the service.
28-1 (d) The commission shall price wholesale transmission
28-2 services within ERCOT based on the postage stamp method of pricing
28-3 under which a transmission-owning utility's rate is based on the
28-4 ERCOT utilities' combined annual costs of transmission divided by
28-5 the total demand placed on the combined transmission systems of all
28-6 such transmission-owning utilities within a power region. An
28-7 electric utility subject to the freeze period imposed by Section
28-8 39.052 may treat transmission costs in excess of transmission
28-9 revenues during the freeze period as an expense for purposes of
28-10 determining annual costs in the annual report filed under Section
28-11 39.257. Notwithstanding Section 36.201, the commission may approve
28-12 wholesale rates that may be periodically adjusted to ensure timely
28-13 recovery of transmission investment.
28-14 (e) The commission shall ensure that ancillary services
28-15 necessary to facilitate the transmission of electric energy are
28-16 available at reasonable prices with terms and conditions that are
28-17 not unreasonably preferential, prejudicial, discriminatory,
28-18 predatory, or anticompetitive. In this subsection, "ancillary
28-19 services" means services necessary to facilitate the transmission
28-20 of electric energy including load following, standby power, backup
28-21 power, reactive power, and any other services as the commission may
28-22 determine by rule. On the introduction of customer choice in the
28-23 ERCOT power region, acquisition of generation-related ancillary
28-24 services on a nondiscriminatory basis by the independent
28-25 organization in ERCOT on behalf of entities selling electricity at
28-26 retail shall be deemed to meet the requirements of this subsection.
29-1 SECTION 18. Subsection (b), Section 35.005, Utilities Code,
29-2 is amended to read as follows:
29-3 (b) The commission may require transmission service at
29-4 wholesale, including the construction or enlargement of a
29-5 facility[, in a proceeding not related to approval of an integrated
29-6 resource plan].
29-7 SECTION 19. Section 35.033, Utilities Code, is amended to
29-8 read as follows:
29-9 Sec. 35.033. Affiliate Wholesale Provider. An affiliate of
29-10 an electric utility may be an exempt wholesale generator or power
29-11 marketer and may sell electric energy to its affiliated electric
29-12 utility in accordance with [Chapter 34 and other] laws governing
29-13 wholesale sales of electric energy.
29-14 SECTION 20. Section 35.034, Utilities Code, is amended by
29-15 adding Subsection (c) to read as follows:
29-16 (c) For purposes of this section, "electric utility" does
29-17 not include a river authority.
29-18 SECTION 21. Section 35.035, Utilities Code, is amended by
29-19 adding Subsection (d) to read as follows:
29-20 (d) For purposes of this section, "electric utility" does
29-21 not include a river authority.
29-22 SECTION 22. Chapter 35, Utilities Code, is amended by adding
29-23 Subchapter D to read as follows:
29-24 SUBCHAPTER D. STATE AUTHORITY TO SELL OR CONVEY POWER
29-25 Sec. 35.101. DEFINITIONS. In this subchapter:
29-26 (1) "Commissioner" means the Commissioner of the
30-1 General Land Office.
30-2 (2) "Public retail customer" means a retail customer
30-3 that is an agency of this state, a state institution of higher
30-4 education, a public school district, or a political subdivision of
30-5 this state.
30-6 Sec. 35.102. STATE AUTHORITY TO SELL OR CONVEY POWER. The
30-7 commissioner, acting on behalf of the state, may sell or otherwise
30-8 convey power generated from royalties taken in kind as provided by
30-9 Sections 52.133(f), 53.026, and 53.077, Natural Resources Code,
30-10 directly to a public retail customer regardless of whether the
30-11 public retail customer is also classified as a wholesale customer
30-12 under other provisions of this title. To ensure that the state
30-13 receives the maximum benefit from the sale of power generated from
30-14 royalties taken in kind, the commissioner shall use all feasible
30-15 means to sell that power first to public retail customers that are
30-16 agencies of this state, institutions of higher education, or public
30-17 school districts. The remainder of the power, if any, may be sold
30-18 to public retail customers that are political subdivisions of this
30-19 state.
30-20 Sec. 35.103. ACCESS TO TRANSMISSION AND DISTRIBUTION
30-21 SYSTEMS; RATES. (a) Except as provided in Section 35.104, the
30-22 state is entitled to have access to all transmission and
30-23 distribution systems of all electric utilities, transmission and
30-24 distribution utilities, municipally owned utilities, and electric
30-25 cooperatives that serve public retail customers.
30-26 (b) An entity described by Subsection (a) shall provide any
31-1 utility service, including transmission, distribution, and other
31-2 services, which must include any stranded costs associated with
31-3 providing service, to the state at the lowest applicable rate
31-4 charged for similar service to other customers.
31-5 Sec. 35.104. LIMIT IN CERTAIN AREAS. Sections 35.102 and
31-6 35.103 do not apply to the rates, retail service area, facilities,
31-7 or public retail customers of a municipally owned electric utility
31-8 that has not adopted customer choice or an electric cooperative
31-9 that has not adopted customer choice. In a certificated service
31-10 area of an electric utility in which customer choice has not been
31-11 introduced, the state may not engage in retail transactions that
31-12 exceed 2.5 percent of a retail electric utility's total retail
31-13 load.
31-14 Sec. 35.105. WHOLESALE CUSTOMERS. This subchapter does not
31-15 prevent the commissioner, acting on behalf of this state, from
31-16 registering as a power marketer.
31-17 Sec. 35.106. ACCESS TO POWER GENERATION. If pipeline
31-18 capacity is available on an existing facility of a gas utility or
31-19 municipally owned utility, a gas utility or a municipally owned
31-20 utility may not refuse to provide gas service to an electric
31-21 utility generating facility, if the purpose of the service is to
31-22 generate power for public retail customers by the state or an
31-23 agency of this state.
31-24 SECTION 23. Section 36.008, Utilities Code, is amended to
31-25 read as follows:
31-26 Sec. 36.008. STATE TRANSMISSION SYSTEM. In establishing
32-1 rates for an electric utility [not required to file an integrated
32-2 resource plan], the commission may review the state's transmission
32-3 system and make recommendations to the utility on the need to build
32-4 new power lines, upgrade power lines, and make other necessary
32-5 improvements and additions.
32-6 SECTION 24. Section 36.052, Utilities Code, is amended to
32-7 read as follows:
32-8 Sec. 36.052. ESTABLISHING REASONABLE RETURN. In
32-9 establishing a reasonable return on invested capital, the
32-10 regulatory authority shall consider applicable factors, including:
32-11 (1) [the efforts of the electric utility to comply
32-12 with its most recently approved integrated resource plan;]
32-13 [(2)] the efforts and achievements of the utility in
32-14 conserving resources;
32-15 (2) [(3)] the quality of the utility's services;
32-16 (3) [(4)] the efficiency of the utility's operations;
32-17 and
32-18 (4) [(5)] the quality of the utility's management.
32-19 SECTION 25. Subsection (d), Section 36.058, Utilities Code,
32-20 is amended to read as follows:
32-21 (d) In making a finding regarding an affiliate transaction,
32-22 [including an affiliate transaction subject to Chapter 34,] the
32-23 regulatory authority shall:
32-24 (1) determine the extent to which the conditions and
32-25 circumstances of that transaction are reasonably comparable
32-26 relative to quantity, terms, date of contract, and place of
33-1 delivery; and
33-2 (2) allow for appropriate differences based on that
33-3 determination.
33-4 SECTION 26. Section 36.201, Utilities Code, is amended to
33-5 read as follows:
33-6 Sec. 36.201. AUTOMATIC ADJUSTMENT FOR CHANGES IN COSTS.
33-7 Except as permitted by [Chapter 34 or] Section 36.204, the
33-8 commission may not establish a rate or tariff that authorizes an
33-9 electric utility to automatically adjust and pass through to the
33-10 utility's customers a change in the utility's fuel or other costs.
33-11 SECTION 27. Section 36.204, Utilities Code, is amended to
33-12 read as follows:
33-13 Sec. 36.204. COST RECOVERY AND INCENTIVES. In establishing
33-14 rates for an electric utility [not required to file an integrated
33-15 resource plan], the commission may:
33-16 (1) allow timely recovery of the reasonable costs of
33-17 conservation, load management, and purchased power, notwithstanding
33-18 Section 36.201; and
33-19 (2) authorize additional incentives for conservation,
33-20 load management, purchased power, and renewable resources.
33-21 SECTION 28. Section 36.207, Utilities Code, is amended to
33-22 read as follows:
33-23 Sec. 36.207. USE OF MARK-UPS. Any mark-ups approved under
33-24 [Chapter 34 or] Section 36.206 are an exceptional form of rate
33-25 relief that the electric utility may recover from ratepayers only
33-26 on a finding by the commission that the relief is necessary to
34-1 maintain the utility's financial integrity.
34-2 SECTION 29. Section 37.001, Utilities Code, is amended to
34-3 read as follows:
34-4 Sec. 37.001. DEFINITIONS. In this chapter:
34-5 (1) "Certificate" means a certificate of convenience
34-6 and necessity.
34-7 (2) "Electric utility" includes an electric
34-8 cooperative.
34-9 (3) "Retail electric utility" means a person,
34-10 political subdivision, electric cooperative, or agency that
34-11 operates, maintains, or controls in this state a facility to
34-12 provide retail electric utility service. The term does not include
34-13 a corporation described by Section 32.053 to the extent that the
34-14 corporation sells electricity exclusively at wholesale and not to
34-15 the ultimate consumer. A qualifying cogenerator that sells
34-16 electric energy at retail to the sole purchaser of the
34-17 cogenerator's thermal output under Sections 35.061 and 36.007 is
34-18 not for that reason considered to be a retail electric utility.
34-19 The owner or operator of a qualifying cogeneration facility who was
34-20 issued the necessary environmental permits from the Texas Natural
34-21 Resource Conservation Commission after January 1, 1998, and who
34-22 commenced construction of such qualifying facility before July 1,
34-23 1998, may provide electricity to the purchasers of the thermal
34-24 output of that qualifying facility and shall not for that reason be
34-25 considered an electric utility or a retail electric utility,
34-26 provided that the purchasers of the thermal output are owners of
35-1 manufacturing or process operation facilities that are located on a
35-2 site entirely owned before September, 1987, by one owner who
35-3 retained ownership after September, 1987, of some portion of the
35-4 facilities and that those facilities now share some integrated
35-5 operations, such as the provision of services and raw materials.
35-6 SECTION 30. Section 37.051, Utilities Code, is amended by
35-7 adding Subsection (c) to read as follows:
35-8 (c) Notwithstanding any other provision of this chapter,
35-9 including Subsection (a), an electric cooperative is not required
35-10 to obtain a certificate of public convenience and necessity for the
35-11 construction, installation, operation, or extension of any
35-12 generating facilities or necessary interconnection facilities.
35-13 SECTION 31. Subsection (b), Section 37.054, Utilities Code,
35-14 is amended to read as follows:
35-15 (b) A person or electric cooperative interested in the
35-16 application may intervene at the hearing.
35-17 SECTION 32. Subchapter B, Chapter 37, Utilities Code, is
35-18 amended by adding Sections 37.060 and 37.061 to read as follows:
35-19 Sec. 37.060. DIVISION OF MULTIPLY CERTIFICATED SERVICE
35-20 AREAS. (a) This subsection and Subsections (b)-(g) apply only to
35-21 areas in which each retail electric utility that is authorized to
35-22 provide retail electric utility service to the area is providing
35-23 customer choice. For purposes of this subsection, an electric
35-24 cooperative or a municipally owned electric utility shall be deemed
35-25 to be providing customer choice if it has approved a resolution
35-26 adopting customer choice that is effective on January 1, 2002, or
36-1 effective within 24 months after the date of the resolution
36-2 adopting customer choice. All other retail electric utilities
36-3 shall be deemed to be providing customer choice if customer choice
36-4 will be allowed for customers of the retail electric utility on
36-5 January 1, 2002. In areas in which each certificated retail
36-6 electric utility is providing customer choice, the commission, if
36-7 requested by a retail electric utility, shall examine all areas
36-8 within the service area of the retail electric utility making the
36-9 request that are also certificated to one or more other retail
36-10 electric utilities and, after notice and hearing, shall amend the
36-11 retail electric utilities' certificates so that only one retail
36-12 electric utility is certificated to provide distribution services
36-13 in any such area. Only retail electric utilities certificated to
36-14 serve an area on June 1, 1999, may continue to serve the area or
36-15 portion of the area under an amended certificate issued under this
36-16 subsection.
36-17 (b) This section does not apply in any area in which a
36-18 municipally owned utility is certificated to provide retail
36-19 electric utility service if the municipally owned utility serving
36-20 the area files with the commission by February 1, 2000, a request
36-21 that areas within the certificated service area of the municipally
36-22 owned utility remain as presently certificated.
36-23 (c) The commission shall enter its order dividing multiply
36-24 certificated areas within one year of the date a request is
36-25 received.
36-26 (d) In amending certificates under this section, the
37-1 commission shall take into consideration the factors prescribed by
37-2 Section 37.056.
37-3 (e) Notwithstanding Section 37.059, the commission shall
37-4 revoke certificates to the extent necessary to achieve the division
37-5 of retail electric service areas as provided by this section.
37-6 (f) Unless otherwise agreed by the affected retail electric
37-7 utilities, each retail electric utility shall be allowed to
37-8 continue to provide service to the location of
37-9 electricity-consuming facilities it is serving on the date an
37-10 application for division of the affected multiply certificated
37-11 service areas is filed. No customer located within the affected
37-12 multiply certificated service areas shall be permitted to switch
37-13 from one retail electric utility to another while an application
37-14 for division of the affected multiply certificated service areas is
37-15 pending.
37-16 (g) If on June 1, 1999, retail service is being provided in
37-17 an area by another retail electric utility with the written consent
37-18 of the retail electric utility certificated to serve the area, that
37-19 consent shall be filed with the commission. On notification of
37-20 that consent and a request by an affected retail electric utility
37-21 to amend the relevant certificates, the commission may grant an
37-22 exception or amend a retail electric utility's certificate. This
37-23 provision shall not be construed to limit the commission's
37-24 authority to grant exceptions or to amend a retail electric
37-25 utility's certificate, upon request and notification, for areas to
37-26 which retail service is being provided pursuant to written consent
38-1 granted after June 1, 1999.
38-2 (h) The commission may not grant an additional retail
38-3 electric utility certificate to serve an area if the effect of the
38-4 grant would cause the area to be multiply certificated unless the
38-5 commission finds that the certificate holders are not providing
38-6 service to any part of the area for which a certificate is sought
38-7 and are not capable of providing adequate service to the area in
38-8 accordance with applicable standards. However, neither this
38-9 subsection nor the deadline of June 1, 1999, provided by Subsection
38-10 (a) shall apply to any application for multiple certification filed
38-11 with the commission on or before February 1, 1999, and those
38-12 applications may be processed in accordance with applicable law in
38-13 effect on the date the application was filed. Applications for
38-14 multiple certification filed with the commission on or before
38-15 February 1, 1999, may not be amended to expand the area for which a
38-16 certificate is sought except for contiguous areas within
38-17 municipalities that provide consent, as required by Section
38-18 37.053(b), not later than June 1, 1999.
38-19 (i) Notwithstanding any other provision of this section, if
38-20 requested by a municipally owned utility, the commission shall
38-21 examine all areas within the municipally owned utility's service
38-22 area that are also certificated to one or more other retail
38-23 electric utilities and, after notice and hearing, may amend the
38-24 retail electric utilities' certificates so that only one retail
38-25 electric utility is certificated to provide distribution services
38-26 in the area, provided that:
39-1 (1) the application is filed with the commission
39-2 within 12 months of the effective date of this provision and is
39-3 limited to single certification of the area within the
39-4 municipality's boundaries as of February 1, 1999;
39-5 (2) the commission preserves the right of an electric
39-6 utility or an electric cooperative to serve its existing customers,
39-7 including any property owned or leased by any customer; and
39-8 (3) the municipality is a member city of a municipal
39-9 power agency, as that term is used in Section 40.059.
39-10 Sec. 37.061. EXISTING SERVICE AREA AGREEMENTS.
39-11 (a) Notwithstanding any other provision of this title, the
39-12 commission shall allow a municipally owned utility to amend the
39-13 service area boundaries of its certificate if:
39-14 (1) the municipally owned utility was the holder of a
39-15 certificate as of January 1, 1999;
39-16 (2) the municipally owned utility has an agreement
39-17 existing before January 1, 1999, with a public utility serving the
39-18 area that the public utility will not contest an application to
39-19 amend the certificate to add municipal territory; and
39-20 (3) the area for which a certificate is requested is
39-21 not certificated to a retail electric utility that is not a party
39-22 to the agreement and that has not consented in writing to
39-23 certification of the area to the municipality.
39-24 (b) The commission may not amend the certificate of the
39-25 public utility serving the affected area based on the granting of a
39-26 certificate to the municipally owned utility.
40-1 SECTION 33. Subsection (a), Section 37.101, Utilities Code,
40-2 is amended to read as follows:
40-3 (a) If an area is or will be included within a municipality
40-4 as the result of annexation, incorporation, or another reason, each
40-5 electric utility and each electric cooperative that holds or is
40-6 entitled to hold a certificate under this title to provide service
40-7 or operate a facility in the area before the inclusion has the
40-8 right to continue to provide the service or operate the facility
40-9 and extend service within the utility's or cooperative's
40-10 certificated area in the annexed or incorporated area under the
40-11 rights granted by the certificate and this title.
40-12 SECTION 34. Section 38.001, Utilities Code, is amended to
40-13 read as follows:
40-14 Sec. 38.001. GENERAL STANDARD. An electric utility and an
40-15 electric cooperative shall furnish service, instrumentalities, and
40-16 facilities that are safe, adequate, efficient, and reasonable.
40-17 SECTION 35. Section 38.004, Utilities Code, is amended to
40-18 read as follows:
40-19 Sec. 38.004. MINIMUM CLEARANCE STANDARD. Notwithstanding
40-20 any other law, a transmission or distribution line owned by an
40-21 electric utility or an electric cooperative must be constructed,
40-22 operated, and maintained, as to clearances, in the manner described
40-23 by the National Electrical Safety Code Standard ANSI (c)(2), as
40-24 adopted by the American National Safety Institute and in effect at
40-25 the time of construction.
40-26 SECTION 36. Subchapter A, Chapter 38, Utilities Code, is
41-1 amended by adding Section 38.005 to read as follows:
41-2 Sec. 38.005. ELECTRIC SERVICE RELIABILITY MEASURES.
41-3 (a) The commission shall implement service quality and reliability
41-4 standards relating to the delivery of electricity to retail
41-5 customers by electric utilities and transmission and distribution
41-6 utilities. The commission by rule shall develop reliability
41-7 standards, including:
41-8 (1) the system-average interruption frequency index
41-9 (SAIFI);
41-10 (2) the system-average interruption duration index
41-11 (SAIDI);
41-12 (3) achievement of average response time for customer
41-13 service requests or inquiries; or
41-14 (4) other standards that the commission finds
41-15 reasonable and appropriate.
41-16 (b) The commission shall take appropriate enforcement action
41-17 under this section, including but not limited to action against a
41-18 utility if any feeder with 10 or more customers appears on the
41-19 utility's list of worst 10 percent performing feeders for any two
41-20 consecutive years or has had a SAIDI or SAIFI average that is more
41-21 than 300 percent greater than the system average of all feeders
41-22 during any two-year period, beginning in the year 2000.
41-23 (c) The standards implemented under Subsection (a) shall
41-24 require each electric utility and transmission and distribution
41-25 utility subject to this section to maintain adequately trained and
41-26 experienced personnel throughout the utility's service area so that
42-1 the utility is able to fully and adequately comply with the
42-2 appropriate service quality and reliability standards.
42-3 (d) The standards shall ensure that electric utilities do
42-4 not neglect any local neighborhood or geographic area, including
42-5 rural areas, communities of less than 1,000 persons, and low-income
42-6 areas, with regard to system reliability.
42-7 (e) The commission may require each electric utility and
42-8 transmission and distribution utility to supply data to assist the
42-9 commission in developing the reliability standards.
42-10 (f) Each electric utility, transmission and distribution
42-11 utility, electric cooperative, municipally owned utility, and
42-12 generation provider shall be obligated to comply with any
42-13 operational criteria duly established by the independent
42-14 organization as defined by Section 39.151 or adopted by the
42-15 commission.
42-16 SECTION 37. Section 38.022, Utilities Code, is amended to
42-17 read as follows:
42-18 Sec. 38.022. DISCRIMINATION AND RESTRICTION ON COMPETITION.
42-19 An electric utility may not:
42-20 (1) discriminate against a person or electric
42-21 cooperative who sells or leases equipment or performs services in
42-22 competition with the electric utility; or
42-23 (2) engage in a practice that tends to restrict or
42-24 impair that competition.
42-25 SECTION 38. Section 38.071, Utilities Code, is amended to
42-26 read as follows:
43-1 Sec. 38.071. Improvements in Service; Interconnecting
43-2 Service. The commission, after notice and hearing, may:
43-3 (1) order an electric utility to provide specified
43-4 improvements in its service in a specified area if:
43-5 (A) service in the area is inadequate or
43-6 substantially inferior to service in a comparable area; and
43-7 (B) requiring the company to provide the
43-8 improved service is reasonable; or
43-9 (2) order two or more electric utilities or electric
43-10 cooperatives to establish specified facilities for interconnecting
43-11 service.
43-12 SECTION 39. Subtitle B, Title 2, Utilities Code, is amended
43-13 by adding Chapters 39, 40, and 41 to read as follows:
43-14 CHAPTER 39. RESTRUCTURING OF ELECTRIC UTILITY INDUSTRY
43-15 SUBCHAPTER A. GENERAL PROVISIONS
43-16 Sec. 39.001. LEGISLATIVE POLICY AND PURPOSE. (a) The
43-17 legislature finds that the production and sale of electricity is
43-18 not a monopoly warranting regulation of rates, operations, and
43-19 services and that the public interest in competitive electric
43-20 markets requires that, except for transmission and distribution
43-21 services and for the recovery of stranded costs, electric services
43-22 and their prices should be determined by customer choices and the
43-23 normal forces of competition. As a result, this chapter is enacted
43-24 to protect the public interest during the transition to and in the
43-25 establishment of a fully competitive electric power industry.
43-26 (b) The legislature finds that it is in the public interest
44-1 to:
44-2 (1) implement on January 1, 2002, a competitive retail
44-3 electric market that allows each retail customer to choose the
44-4 customer's provider of electricity and that encourages full and
44-5 fair competition among all providers of electricity;
44-6 (2) allow utilities with uneconomic generation-related
44-7 assets and purchased power contracts to recover the reasonable
44-8 excess costs over market of those assets and purchased power
44-9 contracts;
44-10 (3) educate utility customers about anticipated
44-11 changes in the provision of retail electric service to ensure that
44-12 the benefits of the competitive market reach all customers; and
44-13 (4) protect the competitive process in a manner that
44-14 ensures the confidentiality of competitively sensitive information
44-15 during the transition to a competitive market and after the
44-16 commencement of customer choice.
44-17 (c) Regulatory authorities, excluding the governing body of
44-18 a municipally owned electric utility that has not opted for
44-19 customer choice or the body vested with power to manage and operate
44-20 a municipally owned electric utility that has not opted for
44-21 customer choice, may not make rules or issue orders regulating
44-22 competitive electric services, prices, or competitors or
44-23 restricting or conditioning competition except as authorized in
44-24 this title and may not discriminate against any participant or type
44-25 of participant during the transition to a competitive market and in
44-26 the competitive market.
45-1 (d) Regulatory authorities, excluding the governing body of
45-2 a municipally owned electric utility that has not opted for
45-3 customer choice or the body vested with power to manage and operate
45-4 a municipally owned electric utility that has not opted for
45-5 customer choice, shall authorize or order competitive rather than
45-6 regulatory methods to achieve the goals of this chapter to the
45-7 greatest extent feasible and shall adopt rules and issue orders
45-8 that are both practical and limited so as to impose the least
45-9 impact on competition.
45-10 (e) Judicial review of competition rules adopted by the
45-11 commission shall be conducted under Chapter 2001, Government Code,
45-12 except as otherwise provided by this chapter. Judicial review of
45-13 the validity of competition rules shall be commenced in the Court
45-14 of Appeals for the Third Court of Appeals District and shall be
45-15 limited to the commission's rulemaking record. The rulemaking
45-16 record consists of:
45-17 (1) the notice of the proposed rule;
45-18 (2) the comments of all interested persons;
45-19 (3) all studies, reports, memoranda, or other
45-20 materials on which the commission relied in adopting the rule; and
45-21 (4) the order adopting the rule.
45-22 (f) A person who challenges the validity of a competition
45-23 rule must file a notice of appeal with the court of appeals and
45-24 serve the notice on the commission not later than the 15th day
45-25 after the date on which the rule as adopted is published in the
45-26 Texas Register. The notice of appeal shall designate the person
46-1 challenging the rule as the appellant and the commission as the
46-2 appellee. The commission shall prepare the rulemaking record and
46-3 file it with the court of appeals not later than the 30th day after
46-4 the date the notice of appeal is served on the commission. The
46-5 court of appeals shall hear and determine each appeal as
46-6 expeditiously as possible with lawful precedence over other
46-7 matters. The appellant, and any person who is permitted by the
46-8 court to intervene in support of the appellant's claims, shall file
46-9 and serve briefs not later than the 30th day after the date the
46-10 commission files the rulemaking record. The commission, and any
46-11 person who is permitted by the court to intervene in support of the
46-12 rule, shall file and serve briefs not later than the 60th day after
46-13 the date the appellant files the appellant's brief. The court of
46-14 appeals may, on its own motion or on motion of any person for good
46-15 cause, modify the filing deadlines prescribed by this subsection.
46-16 The court of appeals shall render judgment affirming the rule or
46-17 reversing and, if appropriate on reversal, remanding the rule to
46-18 the commission for further proceedings, consistent with the court's
46-19 opinion and judgment. The Texas Rules of Appellate Procedure apply
46-20 to an appeal brought under this section to the extent not
46-21 inconsistent with this section.
46-22 Sec. 39.002. APPLICABILITY. This chapter, other than
46-23 Sections 39.155, 39.157(e), 39.203, 39.903, and 39.904, does not
46-24 apply to a municipally owned utility or an electric cooperative.
46-25 Sections 39.157(e), 39.203, and 39.904, however, apply only to a
46-26 municipally owned utility or an electric cooperative that is
47-1 offering customer choice. If there is a conflict between the
47-2 specific provisions of this chapter and any other provisions of
47-3 this title, except for Chapters 40 and 41, the provisions of this
47-4 chapter control.
47-5 Sec. 39.003. CONTESTED CASES. Unless specifically provided
47-6 otherwise, each commission proceeding under this chapter, other
47-7 than a rulemaking proceeding, report, notification, or
47-8 registration, shall be conducted as a contested case and the burden
47-9 of proof is on the incumbent electric utility.
47-10 (Sections 39.004-39.050 reserved for expansion
47-11 SUBCHAPTER B. TRANSITION TO COMPETITIVE RETAIL
47-12 ELECTRIC MARKET
47-13 Sec. 39.051. UNBUNDLING. (a) On or before September 1,
47-14 2000, each electric utility shall separate from its regulated
47-15 utility activities its customer energy services business activities
47-16 that are otherwise also already widely available in the competitive
47-17 market.
47-18 (b) Not later than January 1, 2002, each electric utility
47-19 shall separate its business activities from one another into the
47-20 following units:
47-21 (1) a power generation company;
47-22 (2) a retail electric provider; and
47-23 (3) a transmission and distribution utility.
47-24 (c) An electric utility may accomplish the separation
47-25 required by Subsection (b) either through the creation of separate
47-26 nonaffiliated companies or separate affiliated companies owned by a
48-1 common holding company or through the sale of assets to a third
48-2 party. An electric utility may create separate transmission and
48-3 distribution utilities.
48-4 (d) Each electric utility shall unbundle under this section
48-5 in a manner that provides for a separation of personnel,
48-6 information flow, functions, and operations, consistent with
48-7 Section 39.157(d).
48-8 (e) Each electric utility shall file with the commission a
48-9 plan to implement this section by January 10, 2000.
48-10 (f) The commission shall adopt the utility's plan for
48-11 business separation required by Subsection (b), adopt the plan with
48-12 changes, or reject the plan and require the utility to file a new
48-13 plan.
48-14 (g) Transactions by electric utilities involving sales,
48-15 transfers, or other disposition of assets to accomplish the
48-16 purposes of this section are not subject to Section 14.101, 35.034,
48-17 or 35.035.
48-18 Sec. 39.052. FREEZE ON EXISTING RETAIL BASE RATE TARIFFS.
48-19 (a) Until January 1, 2002, an electric utility shall provide
48-20 retail electric service within its certificated service area in
48-21 accordance with the electric utility's retail base rate tariffs in
48-22 effect on September 1, 1999, including its purchased power cost
48-23 recovery factor.
48-24 (b) During the freeze period, an electric utility may not
48-25 increase its retail base rates above the rates provided by this
48-26 section except for losses caused by force majeure as provided by
49-1 Section 39.055.
49-2 (c) Notwithstanding any other provision of this title,
49-3 during the freeze period the regulatory authority may not reduce
49-4 the retail base rates of an electric utility, except as may be
49-5 ordered as stipulated to by an electric utility in a proceeding for
49-6 which a final order had not been issued by January 1, 1999.
49-7 (d) During the freeze period, the retail base rates, overall
49-8 revenues, return on invested capital, and net income of an electric
49-9 utility are not subject to complaint, hearing, or determination as
49-10 to reasonableness.
49-11 (e) An electric utility that has a rate proceeding pending
49-12 before the commission as of January 2, 1999, shall provide service
49-13 in accordance with the tariffs approved in that proceeding from the
49-14 date of approval until the end of the freeze period.
49-15 (f) Nothing in this section affects the authority of the
49-16 commission to fulfill its obligations under Section 39.262.
49-17 (g) Nothing in this section shall deny a utility its right
49-18 to have the commission conduct proceedings and issue a final order
49-19 pertaining to any matter that may be remanded to the commission by
49-20 a court having jurisdiction, except that the final order may not
49-21 affect the rates charged to customers during the freeze period but
49-22 shall be taken into account during the utility's true-up proceeding
49-23 under Section 39.262.
49-24 (h) Nothing in this title shall be construed to prevent an
49-25 electric utility or a transmission and distribution utility from
49-26 filing, and the commission from approving, a change in wholesale
50-1 transmission service rates during the freeze period.
50-2 Sec. 39.053. COST RECOVERY ADJUSTMENTS. This subchapter
50-3 does not limit or alter the ability of an electric utility during
50-4 the freeze period to revise its fuel factor or to reconcile fuel
50-5 expenses and to either refund fuel overcollections or surcharge
50-6 fuel undercollections to customers, as authorized by its tariffs
50-7 and Sections 36.203 and 36.205.
50-8 Sec. 39.054. RETAIL ELECTRIC SERVICE DURING FREEZE PERIOD.
50-9 (a) An electric utility shall provide retail electric service
50-10 during the freeze period in accordance with any contract terms
50-11 applicable to a particular retail customer approved by the
50-12 regulatory authority and in effect on December 31, 1998.
50-13 (b) Nothing in Sections 39.052(c) and (d) shall be construed
50-14 to restrict any customer's right to complain during the freeze
50-15 period to the regulatory authority regarding the quality of retail
50-16 electric service provided by the electric utility or the
50-17 applicability of an electric utility's particular tariff to the
50-18 customer.
50-19 (c) Nothing in this title shall be construed to restrict an
50-20 electric utility, voluntarily and at its sole discretion, from
50-21 offering new services or new tariff options to its customers during
50-22 the freeze period, consistent with Section 39.051(a).
50-23 (d) Any offering of new services or tariff options under
50-24 this section shall be equal to or greater than an electric
50-25 utility's long-run marginal cost and may not be unreasonably
50-26 preferential, prejudicial, discriminatory, predatory, or
51-1 anticompetitive.
51-2 (e) Revenue from any new offering under this section shall
51-3 be accounted for in a manner consistent with Section 36.007.
51-4 Sec. 39.055. FORCE MAJEURE. (a) An electric utility may
51-5 recover losses resulting from force majeure through an increase in
51-6 its retail base rates during the freeze period.
51-7 (b) Notwithstanding Subchapter C, Chapter 36, the regulatory
51-8 authority, after a hearing to determine the electric utility's
51-9 losses from force majeure, shall permit the utility to fully
51-10 collect any approved force majeure increase through an appropriate
51-11 customer surcharge mechanism.
51-12 (c) For purposes of this section, "force majeure" means a
51-13 major event or combination of major events, including new or
51-14 expanded state or federal statutory or regulatory requirements;
51-15 hurricanes, tornadoes, ice storms, or other natural disasters; or
51-16 acts of war, terrorism, or civil disturbance, beyond the control of
51-17 an electric utility that the regulatory authority finds increases
51-18 the utility's total reasonable and necessary nonfuel costs or
51-19 decreases the utility's total nonfuel revenues related to the
51-20 generation and delivery of electricity by more than 10 percent for
51-21 any calendar year during the freeze period. The term does not
51-22 include any changes in general economic conditions such as
51-23 inflation, interest rates, or other factors of general application.
51-24 (Sections 39.056-39.100 reserved for expansion
51-25 SUBCHAPTER C. RETAIL COMPETITION
51-26 Sec. 39.101. CUSTOMER SAFEGUARDS. (a) Before customer
52-1 choice begins on January 1, 2002, the commission shall ensure that
52-2 retail customer protections are established that entitle a
52-3 customer:
52-4 (1) to safe, reliable, and reasonably priced
52-5 electricity, including protection against service disconnections in
52-6 an extreme weather emergency as provided by Subsection (h) or in
52-7 cases of medical emergency or nonpayment for unrelated services;
52-8 (2) to privacy of customer consumption and credit
52-9 information;
52-10 (3) to bills presented in a clear format and in
52-11 language readily understandable by customers;
52-12 (4) to the option to have all electric services on a
52-13 single bill, except in those instances where multiple bills are
52-14 allowed under Chapters 40 and 41;
52-15 (5) to protection from discrimination on the basis of
52-16 race, color, sex, nationality, religion, or marital status;
52-17 (6) to accuracy of metering and billing;
52-18 (7) to information in English and Spanish and any
52-19 other language as necessary concerning rates, key terms and
52-20 conditions, in a standard format that will permit comparisons
52-21 between price and service offerings, and the environmental impact
52-22 of certain production facilities;
52-23 (8) to information in English and Spanish and any
52-24 other language as necessary concerning low-income assistance
52-25 programs and deferred payment plans; and
52-26 (9) to other information or protections necessary to
53-1 ensure high-quality service to customers.
53-2 (b) A customer is entitled:
53-3 (1) to be informed about rights and opportunities in
53-4 the transition to a competitive electric industry;
53-5 (2) to choose the customer's retail electric provider
53-6 consistent with this chapter, to have that choice honored, and to
53-7 assume that the customer's chosen provider will not be changed
53-8 without the customer's informed consent;
53-9 (3) to have access to providers of energy efficiency
53-10 services, to on-site distributed generation, and to providers of
53-11 energy generated by renewable energy resources;
53-12 (4) to be served by a provider of last resort that
53-13 offers a commission-approved standard service package;
53-14 (5) to receive sufficient information to make an
53-15 informed choice of service provider;
53-16 (6) to be protected from unfair, misleading, or
53-17 deceptive practices, including protection from being billed for
53-18 services that were not authorized or provided; and
53-19 (7) to have an impartial and prompt resolution of
53-20 disputes with its chosen retail electric provider and transmission
53-21 and distribution utility.
53-22 (c) A retail electric provider, power generation company,
53-23 aggregator, or other entity that provides retail electric service
53-24 may not refuse to provide retail electric or electric generation
53-25 service or otherwise discriminate in the provision of electric
53-26 service to any customer because of race, creed, color, national
54-1 origin, ancestry, sex, marital status, lawful source of income,
54-2 disability, or familial status. A retail electric provider, power
54-3 generation company, aggregator, or other entity that provides
54-4 retail electric service may not refuse to provide retail electric
54-5 or electric generation service to a customer because the customer
54-6 is located in an economically distressed geographic area or
54-7 qualifies for low-income affordability or energy efficiency
54-8 services. The commission shall require a provider to comply with
54-9 this subsection as a condition of certification or registration.
54-10 (d) A retail electric provider, power generation company,
54-11 aggregator, or other entity that provides retail electric service
54-12 shall submit reports to the commission and the office annually and
54-13 on request relating to the person's compliance with this section.
54-14 The commission by rule shall specify the form in which a report
54-15 must be submitted. A report must include:
54-16 (1) information regarding the extent of the person's
54-17 coverage;
54-18 (2) information regarding the service provided,
54-19 compiled by zip code and census tract; and
54-20 (3) any other information the commission or the office
54-21 considers relevant to determine compliance.
54-22 (e) The commission has the authority to adopt and enforce
54-23 such rules as may be necessary or appropriate to carry out
54-24 Subsections (a)-(d), including rules for minimum service standards
54-25 for a retail electric provider relating to customer deposits and
54-26 the extension of credit, switching fees, levelized billing
55-1 programs, interconnection and use of on-site generation,
55-2 termination of service, and quality of service. The commission has
55-3 jurisdiction over all providers of electric service in enforcing
55-4 Subsections (a)-(d) and may assess civil and administrative
55-5 penalties under Section 15.023 and seek civil penalties under
55-6 Section 15.028.
55-7 (f) On or before June 30, 2001, the commission shall modify
55-8 its current rules regarding customer protections to ensure that at
55-9 least the same level of customer protection against potential
55-10 abuses and the same quality of service that exists on December 31,
55-11 1999, is maintained in a restructured electric industry.
55-12 (g) Compliance with Subsections (a)-(e) by a provider of
55-13 electric service which is a municipally owned utility shall be
55-14 administered solely by the governing body of the municipally owned
55-15 utility, which shall adopt, implement, and enforce, as to the
55-16 municipally owned utility, rules having the effect of accomplishing
55-17 the objectives of Subsections (a)-(e). Reports containing the
55-18 information required by Subsection (d) shall be filed by the
55-19 municipally owned utility with the governing body.
55-20 (h) A retail electric provider, power generation company,
55-21 aggregator, or other entity that provides retail electric service
55-22 may not disconnect service to a residential customer during an
55-23 extreme weather emergency or on a weekend day. The entity
55-24 providing service shall defer collection of the full payment of
55-25 bills that are due during an extreme weather emergency until after
55-26 the emergency is over and shall work with customers to establish a
56-1 pay schedule for deferred bills. For purposes of this subsection,
56-2 "extreme weather emergency" means a period when:
56-3 (1) the previous day's highest temperature did not
56-4 exceed 32 degrees Fahrenheit and the temperature is predicted to
56-5 remain at or below that level for the next 24 hours according to
56-6 the nearest National Weather Service reports; or
56-7 (2) the National Weather Service issues a heat advisory
56-8 for any county in the relevant service territory, or when such an
56-9 advisory has been issued on any one of the previous two calendar
56-10 days.
56-11 Sec. 39.102. RETAIL CUSTOMER CHOICE. (a) Each retail
56-12 customer in this state, except retail customers of electric
56-13 cooperatives and municipally owned utilities that have not opted
56-14 for customer choice, shall have customer choice on and after
56-15 January 1, 2002.
56-16 (b) The affiliated retail electric provider of the electric
56-17 utility serving a retail customer on December 31, 2001, may
56-18 continue to serve that customer until the customer chooses service
56-19 from a different retail electric provider, an electric cooperative
56-20 offering customer choice, or a municipally owned utility offering
56-21 customer choice.
56-22 (c) An electric utility that has in effect a systemwide
56-23 freeze for residential and commercial customers in effect September
56-24 1, 1997, extending beyond December 31, 2001, that has been found by
56-25 a regulatory authority to be in the public interest is not subject
56-26 to this chapter. At the expiration of the utility's freeze period,
57-1 the utility shall be subject to this chapter and, at that time, has
57-2 no claim for stranded cost recovery.
57-3 Sec. 39.1025. LIMITATIONS ON TELEPHONE SOLICITATION. (a) A
57-4 person may not make or cause to be made a telephone solicitation to
57-5 an electricity customer who has given notice to the commission of
57-6 the customer's objection to receiving telephone solicitations
57-7 relating to the customer's choice of retail electric providers.
57-8 (b) The commission shall establish and provide for the
57-9 operation of a database to compile a list of customers who object
57-10 to receiving telephone solicitations. The commission may operate
57-11 the database or contract with another entity to operate the
57-12 database.
57-13 (c) A customer shall pay a fee of not more than $5 for
57-14 inclusion in the database. The commission shall prescribe the
57-15 amount of the fee.
57-16 Sec. 39.103. COMMISSION AUTHORITY TO DELAY COMPETITION AND
57-17 SET NEW RATES. If the commission determines under Section 39.104
57-18 that a power region is unable to offer fair competition and
57-19 reliable service to all retail customer classes on January 1, 2002,
57-20 the commission shall delay customer choice for the power region and
57-21 may on or after January 1, 2002, establish new rates for all
57-22 electric utilities in the power region as provided by Chapter 36.
57-23 Sec. 39.104. CUSTOMER CHOICE PILOT PROJECTS. (a) Customer
57-24 choice pilot projects may be used to allow the commission to
57-25 evaluate the ability of each power region and electric utility to
57-26 implement customer choice. However, in a multiply certificated
58-1 area, an electric utility may not include customers that were
58-2 served by an electric cooperative or a municipally owned utility on
58-3 May 1, 1999.
58-4 (b) The commission shall require each electric utility to
58-5 offer customer choice in its service area within this state
58-6 amounting to five percent of the utility's combined load of all
58-7 customer classes within this state beginning on June 1, 2001.
58-8 (c) The load designated for customer choice under this
58-9 section shall be distributed among all customer classes of a
58-10 utility consistent with the purpose of this section and subject to
58-11 commission approval.
58-12 (d) Customers participating in a pilot project under this
58-13 section may buy electric energy from any retail electric provider
58-14 certified by the commission under Section 39.352, including an
58-15 affiliated retail electric provider; provided, however, that a
58-16 retail electric provider may not participate in a pilot project in
58-17 the certificated service area served by the electric utility with
58-18 which it is affiliated.
58-19 (e) Each utility operating a pilot project under this
58-20 section shall charge residential and small commercial customers in
58-21 accordance with Section 39.052.
58-22 (f) The commission may prescribe reporting requirements it
58-23 considers necessary to evaluate a pilot project consistent with the
58-24 purpose of this section.
58-25 (g) Customers having customer choice under this section
58-26 shall be billed as provided by Section 39.107.
59-1 (h) The commission may prescribe terms and conditions it
59-2 considers necessary to prohibit anticompetitive practices and to
59-3 encourage customer choice offered under this section.
59-4 (i) Notwithstanding any other provision of this title, a
59-5 retail electric provider participating in a pilot project under
59-6 this section is not an electric utility or a retail electric
59-7 utility.
59-8 (j) Twenty percent of the load designated for customer
59-9 choice under this section shall be initially set aside for
59-10 aggregated loads.
59-11 Sec. 39.105. LIMITATION ON SALE OF ELECTRICITY. (a) After
59-12 January 1, 2002, a transmission and distribution utility may not
59-13 sell electricity or otherwise participate in the market for
59-14 electricity except for the purpose of buying electricity to serve
59-15 its own needs.
59-16 (b) A person or retail electric utility may not provide,
59-17 furnish, or make available electric service at retail within the
59-18 certificated service area of an electric cooperative that has not
59-19 adopted customer choice or a municipally owned utility that has not
59-20 adopted customer choice. However, this subsection does not
59-21 prohibit the provision of electric service in multiply certificated
59-22 service areas to customers of any other retail electric utility.
59-23 Sec. 39.106. PROVIDER OF LAST RESORT. (a) The commission
59-24 shall designate retail electric providers in areas of the state in
59-25 which customer choice is in effect to serve as providers of last
59-26 resort.
60-1 (b) A provider of last resort shall offer a standard retail
60-2 service package for each class of customers designated by the
60-3 commission at a fixed, nondiscountable rate approved by the
60-4 commission.
60-5 (c) A provider of last resort shall provide the standard
60-6 retail service package to any requesting customer in the territory
60-7 for which it is the provider of last resort.
60-8 (d) The commission shall designate the provider or providers
60-9 of last resort not later than June 1, 2001.
60-10 (e) The commission shall determine the procedures and
60-11 criteria, which may include the solicitation of bids, for
60-12 designating a provider or providers of last resort. The commission
60-13 may redesignate the provider of last resort according to a schedule
60-14 it considers appropriate.
60-15 (f) In the event that no retail electric provider applies to
60-16 be the provider of last resort for a given area of the state on
60-17 reasonable terms and conditions, the commission may require a
60-18 retail electric provider to become the provider of last resort as a
60-19 condition of receiving or maintaining a certificate under Section
60-20 39.352.
60-21 (g) In the event that a retail electric provider fails to
60-22 serve any or all of its customers, the provider of last resort
60-23 shall offer that customer the standard retail service package for
60-24 that customer class with no interruption of service to any
60-25 customer.
60-26 Sec. 39.107. METERING AND BILLING SERVICES. (a) On
61-1 introduction of customer choice in a service area, metering
61-2 services for the area shall continue to be provided by the
61-3 transmission and distribution utility affiliate of the electric
61-4 utility that was serving the area before the introduction of
61-5 customer choice. Metering services provided to commercial and
61-6 industrial customers shall be provided on a competitive basis
61-7 beginning on January 1, 2004.
61-8 (b) Metering services provided to residential customers
61-9 shall continue to be provided by the transmission and distribution
61-10 utility affiliate of the electric utility that was serving the area
61-11 before the introduction of customer choice until the later of
61-12 September 1, 2005, or the date on which at least 40 percent of
61-13 those residential customers are taking service from unaffiliated
61-14 retail electric providers. Metering and billing services provided
61-15 to residential customers shall be governed by the customer
61-16 safeguards adopted by the commission under Section 39.101.
61-17 (c) Beginning on the date of introduction of customer choice
61-18 in a service area, tenants of leased or rented property that is
61-19 separately metered shall have the right to choose a retail electric
61-20 provider, an electric cooperative offering customer choice, or a
61-21 municipally owned utility offering customer choice, and the owner
61-22 of the property must grant reasonable and nondiscriminatory access
61-23 to transmission and distribution utilities, retail electric
61-24 providers, electric cooperatives, and municipally owned utilities
61-25 for metering purposes.
61-26 (d) Beginning on the date of introduction of customer choice
62-1 in a service area, a transmission and distribution utility, or an
62-2 electric cooperative or municipally owned utility providing the
62-3 customer's energy requirements shall bill a customer's retail
62-4 electric provider for nonbypassable delivery charges as determined
62-5 under Section 39.201. The retail electric provider or the electric
62-6 cooperative or municipally owned utility, as appropriate, must pay
62-7 these charges.
62-8 (e) A transmission and distribution utility may bill retail
62-9 customers at the request of a retail electric provider or, if an
62-10 electric cooperative or municipally owned utility is providing the
62-11 customer's energy requirements, at the request of the electric
62-12 cooperative or municipally owned utility. A transmission and
62-13 distribution utility that provides billing service on such request
62-14 shall offer billing service on comparable terms and conditions to
62-15 those of any such requesting retail electric provider or, as
62-16 applicable, the electric cooperative or municipally owned utility
62-17 providing energy requirements to a customer served by the
62-18 transmission and distribution utility.
62-19 (f) Beginning on the date of introduction of customer choice
62-20 in a service area, any charges for metering and billing services
62-21 shall comply with rules adopted by the commission relating to
62-22 nondiscriminatory rates of service.
62-23 (g) Metered electric service sold to residential customers
62-24 on a prepaid basis may not be sold at a price that is higher than
62-25 the price charged by the provider of last resort.
62-26 Sec. 39.108. CONTRACTUAL OBLIGATIONS. This chapter may not:
63-1 (1) interfere with or abrogate the rights or
63-2 obligations of any party, including a retail or wholesale customer,
63-3 to a contract with an investor-owned electric utility, river
63-4 authority, municipally owned utility, or electric cooperative;
63-5 (2) interfere with or abrogate the rights or
63-6 obligations of a party under a contract or agreement concerning
63-7 certificated utility service areas; or
63-8 (3) result in a change in wholesale power costs to
63-9 wholesale customers in Texas purchasing electricity under wholesale
63-10 power contracts the pricing provisions of which are based on
63-11 formulary rates, fuel adjustments, or average system costs.
63-12 Sec. 39.109. NEW OWNER OR SUCCESSOR. (a) To ensure the
63-13 continued safe and reliable operation of electric generating
63-14 facilities, the commission shall require a generating facility that
63-15 is transferred to a new owner or successor in interest between June
63-16 1, 1999, and January 1, 2002, to continue to be operated and
63-17 maintained by the same operating personnel for not less than two
63-18 years, except that the personnel may be dismissed for cause.
63-19 (b) This section shall apply only if the facility is
63-20 actually operated during the two-year period after the sale.
63-21 (c) This section shall not require that the purchaser cause
63-22 the facility to be operated in whole or in part, nor shall it
63-23 preclude a temporary closure of the facility during the two-year
63-24 period.
63-25 (d) This section shall not create any obligation extending
63-26 after the two-year period following the sale.
64-1 (Sections 39.110-39.150 reserved for expansion
64-2 SUBCHAPTER D. MARKET STRUCTURE
64-3 Sec. 39.151. ESSENTIAL ORGANIZATIONS. (a) A power region
64-4 must establish one or more independent organizations to perform the
64-5 following functions:
64-6 (1) ensure access to the transmission and distribution
64-7 systems for all buyers and sellers of electricity on
64-8 nondiscriminatory terms;
64-9 (2) ensure the reliability and adequacy of the
64-10 regional electrical network;
64-11 (3) ensure that information relating to a customer's
64-12 choice of retail electric provider is conveyed in a timely manner
64-13 to the persons who need that information; and
64-14 (4) ensure that electricity production and delivery
64-15 are accurately accounted for among the generators and wholesale
64-16 buyers and sellers in the region.
64-17 (b) "Independent organization" means an independent system
64-18 operator or other person that is sufficiently independent of any
64-19 producer or seller of electricity that its decisions will not be
64-20 unduly influenced by any producer or seller. An entity will be
64-21 deemed to be independent if it is governed by a board that has
64-22 three representatives from each segment of the electric market,
64-23 with the consumer segment being represented by one residential
64-24 customer, one commercial customer, and one industrial retail
64-25 customer.
64-26 (c) The commission shall certify an independent organization
65-1 or organizations to perform the functions prescribed by this
65-2 section.
65-3 (d) An independent organization certified by the commission
65-4 for a power region shall establish and enforce procedures,
65-5 consistent with this title and the commission's rules, relating to
65-6 the reliability of the regional electrical network and accounting
65-7 for the production and delivery of electricity among generators and
65-8 all other market participants. The procedures shall be subject to
65-9 commission oversight and review.
65-10 (e) The commission may authorize an independent organization
65-11 that is certified under this section to charge a reasonable and
65-12 competitively neutral rate to wholesale buyers and sellers to cover
65-13 the independent organization's costs.
65-14 (f) In implementing this section, the commission may
65-15 cooperate with the utility regulatory commission of another state
65-16 or the federal government and may hold a joint hearing or make a
65-17 joint investigation with that commission.
65-18 (g) If it amends its governance rules to provide that its
65-19 governing body is composed as prescribed by this subsection, the
65-20 existing independent system operator in ERCOT will meet the
65-21 criteria provided by Subsection (a) with respect to ensuring access
65-22 to the transmission systems for all buyers and sellers of
65-23 electricity in the ERCOT region and ensuring the reliability of the
65-24 regional electrical network. To comply with this subsection, the
65-25 governing body must be composed of:
65-26 (1) the chairman of the commission as an ex officio
66-1 nonvoting member;
66-2 (2) the counsellor as an ex officio voting member;
66-3 (3) the director of the independent system operator as
66-4 an ex officio voting member;
66-5 (4) four representatives of the power generation
66-6 sector as voting members;
66-7 (5) four representatives of the transmission and
66-8 distribution sector as voting members;
66-9 (6) four representatives of the power sales sector as
66-10 voting members; and
66-11 (7) the following people as voting members, appointed
66-12 by the commission:
66-13 (A) one representative of residential customers;
66-14 (B) one representative of commercial customers;
66-15 and
66-16 (C) one representative of industrial customers.
66-17 The four representatives specified in each of Subdivisions (4),
66-18 (5), and (6) shall be selected in a manner that ensures equitable
66-19 representation for the various sectors of industry participants.
66-20 (h) The ERCOT independent system operator may meet the
66-21 criteria relating to the other functions of an independent
66-22 organization provided by Subsection (a) by adopting procedures and
66-23 acquiring resources needed to carry out those functions.
66-24 (i) The commission may delegate authority to the existing
66-25 independent system operator in ERCOT to enforce operating standards
66-26 within the ERCOT regional electrical network and to establish and
67-1 oversee transaction settlement procedures. The commission may
67-2 establish the terms and conditions for the ERCOT independent system
67-3 operator's authority to oversee utility dispatch functions after
67-4 the introduction of customer choice.
67-5 (j) A retail electric provider, municipally owned utility,
67-6 electric cooperative, power marketer, transmission and distribution
67-7 utility, or power generation company shall observe all scheduling,
67-8 operating, planning, reliability, and settlement policies, rules,
67-9 guidelines, and procedures established by the independent system
67-10 operator in ERCOT. Failure to comply with this subsection may
67-11 result in the revocation, suspension, or amendment of a certificate
67-12 as provided by Section 39.356 or in the imposition of an
67-13 administrative penalty as provided by Section 39.357.
67-14 (k) To the extent the commission has authority over an
67-15 independent organization outside of ERCOT, the commission may
67-16 delegate authority to the independent organization consistent with
67-17 Subsection (i).
67-18 (l) No operational criteria, protocols, or other requirement
67-19 established by an independent organization, including the ERCOT
67-20 independent system operator, may adversely affect or impede any
67-21 manufacturing or other internal process operation associated with
67-22 an industrial generation facility, except to the minimum extent
67-23 necessary to assure reliability of the transmission network.
67-24 (m) A power region outside of ERCOT shall be deemed to have
67-25 met the requirement to establish an independent organization to
67-26 perform the transmission functions specified in Subsection (a) if
68-1 the Federal Energy Regulatory Commission has approved a regional
68-2 transmission organization for the region and found that the
68-3 regional transmission organization meets the requirements of
68-4 Subsection (a).
68-5 Sec. 39.152. QUALIFYING POWER REGIONS. (a) The commission
68-6 shall certify a power region if:
68-7 (1) a sufficient number of interconnected utilities in
68-8 the power region fall under the operational control of an
68-9 independent organization as described by Section 39.151;
68-10 (2) the power region has a generally applicable tariff
68-11 that guarantees open and nondiscriminatory access for all users to
68-12 transmission and distribution facilities in the power region as
68-13 provided by Section 39.203; and
68-14 (3) no person owns and controls more than 20 percent
68-15 of the installed generation capacity located in or capable of
68-16 delivering electricity to a power region, as determined according
68-17 to Section 39.154.
68-18 (b) In determining whether a power region not entirely
68-19 within the state meets the requirements of this section, the
68-20 commission shall consider the extent to which the available
68-21 transmission facilities limit the delivery of electricity from
68-22 generators located outside the state to areas of the power region
68-23 within the state.
68-24 (c) For a power region outside of ERCOT, the requirements of
68-25 Subsection (a)(2) shall be deemed to have been met if power
68-26 aggregating to approximately 50,000 megawatts can be delivered to
69-1 the portion of the power region that is in this state through the
69-2 payment of not more than one transmission tariff.
69-3 (d) For a power region outside of ERCOT, a power generation
69-4 company that is affiliated with an electric utility may elect to
69-5 demonstrate that it meets the requirements of Subsection (a)(3) by
69-6 showing that it does not own and control more than 20 percent of
69-7 the installed capacity in a geographic market that includes the
69-8 power region, using the guidelines, standards, and methods adopted
69-9 by the Federal Energy Regulatory Commission.
69-10 (e) In a power region outside of ERCOT, if customer choice
69-11 is introduced before the requirements of Subsection (a) are met, an
69-12 affiliated retail electric provider may not compete for retail
69-13 customers in any area of the power region that is within this state
69-14 and outside of the affiliated transmission and distribution
69-15 utility's certificated service area unless the affiliated power
69-16 generation company makes a commitment to maintain and does maintain
69-17 rates that are based on cost of service for any electric
69-18 cooperative or municipally owned utility that was a wholesale
69-19 customer on January 1, 1999, and was purchasing power at rates that
69-20 were based on cost of service. This subsection requires a power
69-21 generation company to sell power at rates that are based on cost of
69-22 service, notwithstanding the expiration of a contract for that
69-23 service, until the requirements of Subsection (a) are met.
69-24 Sec. 39.153. CAPACITY AUCTION. (a) Each electric utility
69-25 subject to this section shall sell at auction, at least 60 days
69-26 before the date set for customer choice to begin, entitlements to
70-1 at least 15 percent of the electric utility's Texas jurisdictional
70-2 installed generation capacity. For the purposes of this section,
70-3 the term "electric utility" includes any affiliated power
70-4 generation company that is unbundled from the electric utility in
70-5 accordance with Section 39.051, but does not include any entity
70-6 owning less than 400 megawatts of installed generation capacity.
70-7 (b) The obligation to auction the entitlements shall
70-8 continue until the earlier of 60 months after the date customer
70-9 choice is introduced or the date the commission determines that 40
70-10 percent or more of the electric power consumed by residential and
70-11 small commercial customers within the affiliated transmission and
70-12 distribution utility's certificated service area before the onset
70-13 of customer choice is provided by nonaffiliated retail electric
70-14 providers.
70-15 (c) An affiliate of the electric utility selling
70-16 entitlements in the auction required by this section may not
70-17 purchase entitlements from the affiliated electric utility at the
70-18 auction. Entitlements may only be purchased by entities lawfully
70-19 able to sell electricity in Texas.
70-20 (d) An electric utility may choose to auction additional
70-21 entitlements beyond those required by Subsection (a) or continue to
70-22 auction entitlements after the period required by Subsection (b) in
70-23 order to comply with Section 39.154.
70-24 (e) The commission shall adopt rules by December 31, 2000,
70-25 that define the scope of the capacity entitlements to be auctioned.
70-26 Entitlements may be auctioned in blocks of less than 15 percent.
71-1 The rules shall state the minimum amount of capacity that can be
71-2 sold at auction as an entitlement. At a minimum, the rules shall
71-3 provide that the entitlements:
71-4 (1) may be sold and purchased in periods of not less
71-5 than one month nor more than four years;
71-6 (2) may be resold to any lawful purchaser, except for
71-7 a retail electric provider affiliated with the electric utility
71-8 that originally auctioned the entitlement;
71-9 (3) include no possessory interest in the unit from
71-10 which the power is produced;
71-11 (4) include no obligations of a possessory owner of an
71-12 interest in the unit from which the power is produced; and
71-13 (5) give the purchaser the right to designate the
71-14 dispatch of the entitlement, subject to planned outages, outages
71-15 beyond the control of the utility operating the unit, and other
71-16 considerations subject to the oversight of the applicable
71-17 independent organization.
71-18 (f) The commission shall adopt rules by December 31, 2000,
71-19 that prescribe the procedure for the auction of the entitlements.
71-20 The rules shall include:
71-21 (1) a process for conducting the auction or auctions,
71-22 including who shall conduct it, how often it shall be conducted,
71-23 and how winning bidders shall be determined;
71-24 (2) a process for the electric utility to designate
71-25 which generation units or combination of units are offered for
71-26 auction;
72-1 (3) a provision for the utility to establish an
72-2 opening bid price based on the electric utility's expected cost,
72-3 with the commission prescribing the means for determining the
72-4 opening bid price, which may not include return on equity; and
72-5 (4) a provision that allows a bidder to specify the
72-6 magnitude and term of the entitlement, subject to the conditions
72-7 established in Subsection (e).
72-8 (g) In adopting the process under Subsection (f)(2), the
72-9 commission shall consider the furtherance of the development of the
72-10 competitive market, the cost of transmission, physical constraints
72-11 of the transmission system, the proximity of the generation to
72-12 load, economic efficiency, and any other factors the commission
72-13 finds relevant. The process may provide for commission approval of
72-14 the designation before auction. The commission may consult with
72-15 the applicable independent organization to develop the process.
72-16 Sec. 39.154. LIMITATION OF OWNERSHIP OF INSTALLED CAPACITY.
72-17 (a) Beginning on the date of introduction of customer choice, a
72-18 power generation company may not own and control more than 20
72-19 percent of the installed generation capacity located in, or capable
72-20 of delivering electricity to, a power region.
72-21 (b) In a power region not entirely within the state, the
72-22 commission may waive or modify the requirement in Subsection (a) on
72-23 a finding of good cause.
72-24 (c) In determining the percentage shares of installed
72-25 generation capacity under this section, the commission shall
72-26 combine capacity owned and controlled by a power generation company
73-1 and any entity that is affiliated with that power generation
73-2 company within the power region, reduced by the installed
73-3 generation capacity of those facilities that are made subject to
73-4 capacity auctions under Sections 39.153(a) and (d).
73-5 (d) In this chapter, "installed generation capacity" means
73-6 all potentially marketable electric generation capacity, including
73-7 the capacity of:
73-8 (1) generating facilities that are connected with a
73-9 transmission or distribution system;
73-10 (2) generating facilities used to generate electricity
73-11 for consumption by the person owning or controlling the facility;
73-12 and
73-13 (3) generating facilities that will be connected with
73-14 a transmission or distribution system and operating within 12
73-15 months.
73-16 (e) In determining the percentage shares of installed
73-17 generation capacity owned and controlled by a power generation
73-18 company under this section and Section 39.156, the commission
73-19 shall, for purposes of calculating the numerator, reduce the
73-20 installed generation capacity owned and controlled by that power
73-21 generation company by the installed generation capacity of any
73-22 "grandfathered facility" within an ozone nonattainment area as of
73-23 September 1, 1999, for which that power generation company has
73-24 commenced complying or made a binding commitment to comply with
73-25 Section 39.264. This subsection applies only to a power generation
73-26 company that is affiliated with an electric utility that owned and
74-1 controlled more than 27 percent of the installed generation
74-2 capacity in the power region on January 1, 1999.
74-3 Sec. 39.155. COMMISSION ASSESSMENT OF MARKET POWER.
74-4 (a) Each person, municipally owned utility, electric cooperative,
74-5 and river authority that owns generation facilities and offers
74-6 electricity for sale in this state shall report to the commission
74-7 its installed generation capacity, the total amount of capacity
74-8 available for sale to others, the total amount of capacity under
74-9 contract to others, the total amount of capacity dedicated to its
74-10 own use, its annual wholesale power sales in the state, its annual
74-11 retail power sales in the state, and any other information
74-12 necessary for the commission to assess market power or the
74-13 development of a competitive retail market in the state. The
74-14 commission shall by rule prescribe the nature and detail of the
74-15 reporting requirements and shall administer those reporting
74-16 requirements in a manner that ensures the confidentiality of
74-17 competitively sensitive information.
74-18 (b) The ERCOT independent system operator shall submit an
74-19 annual report to the commission identifying existing and potential
74-20 transmission and distribution constraints and system needs within
74-21 ERCOT, alternatives for meeting system needs, and recommendations
74-22 for meeting system needs. The first report shall be submitted on
74-23 or before October 1, 1999. Subsequent reports shall be submitted
74-24 by January 15 of each year or as determined necessary by the
74-25 commission.
74-26 (c) Before the date of introduction of customer choice in a
75-1 power region other than ERCOT, each electric utility owning
75-2 transmission and distribution facilities in that region shall
75-3 submit an annual report to the commission identifying existing and
75-4 potential transmission and distribution constraints and system
75-5 needs in the power region, alternatives for meeting system needs,
75-6 and recommendations for meeting system needs as directed by the
75-7 commission.
75-8 (d) In a qualifying power region, the reports required by
75-9 Subsections (b) and (c) shall be submitted by the independent
75-10 organization or organizations having authority over the power
75-11 region or discrete areas thereof.
75-12 Sec. 39.156. MARKET POWER MITIGATION PLAN. (a) In this
75-13 section, "market power mitigation plan" or "plan" means a written
75-14 proposal by an electric utility or a power generation company for
75-15 reducing its ownership and control of installed generation capacity
75-16 as required by Section 39.154.
75-17 (b) An electric utility or power generation company owning
75-18 and controlling more than 20 percent of the generation capacity
75-19 located in, or capable of delivering electricity to, a power region
75-20 shall file a market power mitigation plan with the commission not
75-21 later than December 1, 2000.
75-22 (c) The plan may provide for:
75-23 (1) the sale of generation assets to a nonaffiliated
75-24 person;
75-25 (2) the exchange of generation assets with a
75-26 nonaffiliated person located in a different power region;
76-1 (3) the auctioning of generation capacity entitlements
76-2 as part of a capacity auction required by Section 39.153;
76-3 (4) the sale of the right to capacity to a
76-4 nonaffiliated person for at least four years; or
76-5 (5) any reasonable method of mitigation.
76-6 (d) For the purposes of this section, generation capacity
76-7 shall be net of the generation capacity subject to an auction under
76-8 Section 39.153.
76-9 (e) The plan shall be in a form prescribed by the commission
76-10 and shall provide information the commission finds reasonably
76-11 necessary to evaluate the plan.
76-12 (f) The commission shall approve, modify, or reject a plan
76-13 within 180 days after the date of a filing under Subsection (b).
76-14 The commission may not modify a plan to require divestiture by the
76-15 electric utility or the power generation company.
76-16 (g) In reaching its determination under Subsection (f), the
76-17 commission shall consider:
76-18 (1) the degree to which the electric utility's or
76-19 power generation company's stranded costs, if any, are minimized;
76-20 (2) whether on disposition of the generation assets
76-21 the reasonable value is likely to be received;
76-22 (3) the effect of the plan on the electric utility's
76-23 or power generation company's federal income taxes;
76-24 (4) the effect of the plan on current and potential
76-25 competitors in the generation market; and
76-26 (5) whether the plan is consistent with the public
77-1 interest.
77-2 (h) An electric utility or power generation company with an
77-3 approved mitigation plan may request to amend or repeal its plan.
77-4 On a showing of good cause, the commission shall modify or repeal
77-5 an electric utility's or power generation company's mitigation
77-6 plan.
77-7 (i) If an electric utility's or a power generation company's
77-8 market power mitigation plan is not approved before January 1 of
77-9 the year it is to take effect, the commission may order the
77-10 electric utility or power generation company to auction generation
77-11 capacity entitlements according to Section 39.153, subject to
77-12 commission approval, of any capacity exceeding the maximum
77-13 allowable capacity prescribed by Section 39.154 until the time a
77-14 mitigation plan is approved.
77-15 (j) An auction under Subsection (i) shall be held not later
77-16 than 60 days after the date the order is entered.
77-17 Sec. 39.157. COMMISSION AUTHORITY TO ADDRESS MARKET POWER.
77-18 (a) The commission shall monitor market power associated with the
77-19 generation, transmission, distribution, and sale of electricity in
77-20 this state. On a finding that market power abuses or other
77-21 violations of this section are occurring, the commission shall
77-22 require reasonable mitigation of the market power by ordering the
77-23 construction of additional transmission or distribution facilities,
77-24 by seeking an injunction or civil penalties as necessary to
77-25 eliminate or to remedy the market power abuse or violation as
77-26 authorized by Chapter 15, by imposing an administrative penalty as
78-1 authorized by Chapter 15, or by suspending, revoking, or amending a
78-2 certificate or registration as authorized by Section 39.356.
78-3 Section 15.024(c) does not apply to an administrative penalty
78-4 imposed under this section. For purposes of this subchapter,
78-5 market power abuses are practices by persons possessing market
78-6 power that are unreasonably discriminatory or tend to unreasonably
78-7 restrict, impair, or reduce the level of competition, including
78-8 practices that tie unregulated products or services to regulated
78-9 products or services or unreasonably discriminate in the provision
78-10 of regulated services. For purposes of this section, "market power
78-11 abuses" include predatory pricing, withholding of production,
78-12 precluding entry, and collusion. A violation of the code of
78-13 conduct provided by Subsection (d) that materially impairs the
78-14 ability of a person to compete in a competitive market shall be
78-15 deemed to be an abuse of market power. The possession of a high
78-16 market share in a market open to competition may not, of itself, be
78-17 deemed to be an abuse of market power; however, this sentence shall
78-18 not affect the application of state and federal antitrust laws.
78-19 (b) Beginning on the date of introduction of customer
78-20 choice, a person that owns generation facilities may not own
78-21 transmission or distribution facilities in this state except for
78-22 those facilities necessary to interconnect a generation facility
78-23 with the transmission or distribution network, a facility not
78-24 dedicated to public use, or a facility otherwise excluded from the
78-25 definition of "electric utility" under Section 31.002. However,
78-26 nothing in this chapter shall prohibit a power generation company
79-1 affiliated with a transmission and distribution utility from owning
79-2 generation facilities.
79-3 (c) The commission shall monitor market shares of installed
79-4 capacity to ensure that the limitations in Section 39.154 are not
79-5 exceeded. If the commission finds that a person has violated a
79-6 limitation in Section 39.154, the commission shall order the person
79-7 to file, within 60 days of the date of the order, a market power
79-8 mitigation plan consistent with the requirements in Section 39.156.
79-9 (d) Not later than January 10, 2000, the commission shall
79-10 adopt rules and enforcement procedures to govern transactions or
79-11 activities between a transmission and distribution utility and its
79-12 competitive affiliates to avoid potential market power abuses and
79-13 cross-subsidizations between regulated and competitive activities
79-14 both during the transition to and after the introduction of
79-15 competition. Nothing in this subsection is intended to affect or
79-16 modify the obligations or duties relating to any rules or standards
79-17 of conduct that may apply to a utility or the utility's affiliates
79-18 under orders or regulations of the Federal Energy Regulatory
79-19 Commission or the Securities and Exchange Commission. A utility
79-20 that is subject to statutes or regulations in other states that
79-21 conflict with a provision of this section may petition the
79-22 commission for a waiver of the conflicting provision on a showing
79-23 of good cause. The rules adopted under this section shall ensure
79-24 that:
79-25 (1) a utility makes any products and services, other
79-26 than corporate support services, that it provides to a competitive
80-1 affiliate available, contemporaneously and in the same manner, to
80-2 the competitive affiliate's competitors and applies its tariffs,
80-3 prices, terms, conditions, and discounts for those products and
80-4 services in the same manner to all similarly situated entities;
80-5 (2) a utility does not:
80-6 (A) give a competitive affiliate or a
80-7 competitive affiliate's customers any preferential advantage,
80-8 access, or treatment regarding services other than corporate
80-9 support services; or
80-10 (B) act in a manner that is discriminatory or
80-11 anticompetitive with respect to a nonaffiliated competitor of a
80-12 competitive affiliate;
80-13 (3) a utility providing electric transmission or
80-14 distribution services:
80-15 (A) provides those services on nondiscriminatory
80-16 terms and conditions;
80-17 (B) does not establish as a condition for the
80-18 provision of those services the purchase of other goods or services
80-19 from the utility or the competitive affiliate; and
80-20 (C) does not provide competitive affiliates
80-21 preferential access to the utility's transmission and distribution
80-22 systems or to information about those systems;
80-23 (4) a utility does not release any proprietary
80-24 customer information to a competitive affiliate or any other
80-25 entity, other than an independent organization as defined by
80-26 Section 39.151 or a provider of corporate support services for the
81-1 purposes of providing the services, without obtaining prior
81-2 verifiable authorization, as determined from the commission, from
81-3 the customer;
81-4 (5) a utility does not:
81-5 (A) communicate with a current or potential
81-6 customer about products or services offered by a competitive
81-7 affiliate in a manner that favors a competitive affiliate; or
81-8 (B) allow a competitive affiliate, before
81-9 September 1, 2005, to use the utility's corporate name, trademark,
81-10 brand, or logo unless the competitive affiliate includes on
81-11 employee business cards and in its advertisements of specific
81-12 services to existing or potential residential or small commercial
81-13 customers locating within the utility's certificated service area a
81-14 disclaimer that states, "(Name of competitive affiliate) is not the
81-15 same company as (name of utility) and is not regulated by the
81-16 Public Utility Commission of Texas, and you do not have to buy
81-17 (name of competitive affiliate)'s products to continue to receive
81-18 quality regulated services from (name of utility).";
81-19 (6) a utility does not conduct joint advertising or
81-20 promotional activities with a competitive affiliate in a manner
81-21 that favors the competitive affiliate;
81-22 (7) a utility is a separate, independent entity from
81-23 any competitive affiliates and, except as provided by Subdivisions
81-24 (8) and (9), does not share employees, facilities, information, or
81-25 other resources, other than permissible corporate support services,
81-26 with those competitive affiliates unless the utility can prove to
82-1 the commission that the sharing will not compromise the public
82-2 interest;
82-3 (8) a utility's office space is physically separated
82-4 from the office space of the utility's competitive affiliates by
82-5 being located in separate buildings or, if within the same
82-6 building, by a method such as having the offices on separate floors
82-7 or with separate access, unless otherwise approved by the
82-8 commission;
82-9 (9) a utility and a competitive affiliate:
82-10 (A) may, to the extent the utility implements
82-11 adequate safeguards precluding employees of a competitive affiliate
82-12 from gaining access to information in a manner inconsistent with
82-13 Subsection (g) or (i), share common officers and directors,
82-14 property, equipment, offices to the extent consistent with
82-15 Subdivision (8), credit, investment, or financing arrangements to
82-16 the extent consistent with Subdivision (17), computer systems,
82-17 information systems, and corporate support services; and
82-18 (B) are not required to enter into prior written
82-19 contracts or competitive solicitations for non-tariffed
82-20 transactions between the utility and the competitive affiliate,
82-21 except that the commission by rule may require the utility and the
82-22 competitive affiliate to enter into prior written contracts or
82-23 competitive solicitations for certain classes of transactions,
82-24 other than corporate support services, that have a per unit value
82-25 of more than $75,000 or that total more than $1 million;
82-26 (10) a utility does not temporarily assign, for less
83-1 than one year, employees engaged in transmission or distribution
83-2 system operations to a competitive affiliate unless the employee
83-3 does not have knowledge of information that is intended to be
83-4 protected under this section;
83-5 (11) a utility does not subsidize the business
83-6 activities of an affiliate with revenues from a regulated service;
83-7 (12) a utility and its affiliates fully allocate costs
83-8 for any shared services, corporate support services, and other
83-9 items described by Subdivisions (8) and (9);
83-10 (13) a utility and its affiliates keep separate books
83-11 of accounts and records and the commission may review records
83-12 relating to a transaction between a utility and an affiliate;
83-13 (14) assets transferred or services provided between a
83-14 utility and an affiliate, other than transfers that facilitate
83-15 unbundling under Section 39.051 or asset valuation under Section
83-16 39.262, are priced at a level that is fair and reasonable to the
83-17 customers of the utility and reflects the market value of the
83-18 assets or services or the utility's fully allocated cost to provide
83-19 those assets or services;
83-20 (15) regulated services that a utility provides on a
83-21 routine or recurring basis are included in a tariff that is subject
83-22 to commission approval;
83-23 (16) each transaction between a utility and a
83-24 competitive affiliate is conducted at arm's length; and
83-25 (17) a utility does not allow an affiliate to obtain
83-26 credit under an arrangement that would include a specific pledge of
84-1 assets in the rate base of the utility or a pledge of cash
84-2 reasonably necessary for utility operations.
84-3 (e) The commission shall by rule establish a code of conduct
84-4 that must be observed by electric cooperatives and municipally
84-5 owned utilities and their affiliates to protect against
84-6 anticompetitive practices. The rules adopted by the commission
84-7 under this subsection shall be consistent with Chapters 40 and 41
84-8 and may not be more restrictive than the rules adopted under
84-9 Subsection (d).
84-10 (f) Following review of the annual reports submitted to it
84-11 under Sections 39.155(b) and (c), the commission shall determine
84-12 whether specific transmission or distribution constraints or
84-13 bottlenecks within this state give rise to market power in specific
84-14 geographic markets in the state. The commission, on a finding that
84-15 specific transmission or distribution constraints or bottlenecks
84-16 within this state give rise to market power, may order reasonable
84-17 mitigation of that potential market power by ordering, under
84-18 Section 39.203(e), one or more electric utilities or transmission
84-19 and distribution utilities to construct additional transmission or
84-20 distribution capacity, or both, subject to the certification
84-21 provisions of this title.
84-22 (g) The sharing of corporate support services in accordance
84-23 with this section may not allow or provide a means for the transfer
84-24 of confidential information from a utility to an affiliate, create
84-25 the opportunity for preferential treatment or an unfair competitive
84-26 advantage, lead to customer confusion, or create significant
85-1 opportunities for cross-subsidization of affiliates.
85-2 (h) A utility or competitive affiliate may not circumvent
85-3 the provisions or the intent of the provisions of Subsection (d) by
85-4 using any utility affiliate to provide information, services, or
85-5 subsidies between the utility and a competitive affiliate.
85-6 (i) In this section:
85-7 (1) "Competitive affiliate" means an affiliate of a
85-8 utility that provides services or sells products in a competitive
85-9 energy-related market in this state, including telecommunications
85-10 services, to the extent those services are energy related.
85-11 (2) "Corporate support services" means services shared
85-12 by a utility, its parent holding company, or a separate affiliate
85-13 created to perform corporate support services, with its affiliates
85-14 of joint corporate oversight, governance, support systems, and
85-15 personnel. Examples of services that may be shared, to the extent
85-16 the services comply with the requirements prescribed by Subsections
85-17 (d) and (g), include human resources, procurement, information
85-18 technology, regulatory services, administrative services, real
85-19 estate services, legal services, accounting, environmental
85-20 services, research and development, internal audit, community
85-21 relations, corporate communications, financial services, financial
85-22 planning and management support, corporate services, corporate
85-23 secretary, lobbying, and corporate planning. Examples of services
85-24 that may not be shared include engineering, purchasing of electric
85-25 transmission, transmission and distribution system operations, and
85-26 marketing.
86-1 Sec. 39.158. MERGERS AND CONSOLIDATIONS. (a) An owner of
86-2 electric generation facilities that offers electricity for sale in
86-3 the state and proposes to merge, consolidate, or otherwise become
86-4 affiliated with another owner of electric generation facilities
86-5 that offers electricity for sale in this state shall obtain the
86-6 approval of the commission before closing if the electricity
86-7 offered for sale in the power region by the merged, consolidated,
86-8 or affiliated entity will exceed one percent of the total
86-9 electricity for sale in the power region. The approval shall be
86-10 requested at least 120 days before the date of the proposed
86-11 closing. The commission shall approve the transaction unless the
86-12 commission finds that the transaction results in a violation of
86-13 Section 39.154. If the commission finds that the transaction as
86-14 proposed would violate Section 39.154, the commission may condition
86-15 approval of the transaction on adoption of reasonable modifications
86-16 to the transaction as prescribed by the commission to mitigate
86-17 potential market power abuses.
86-18 (b) Nothing in this chapter shall be construed to confer
86-19 immunity from state or federal antitrust laws. This chapter is
86-20 intended to complement other state and federal antitrust
86-21 provisions. Therefore, antitrust remedies may also be sought in
86-22 state or federal court to remedy anticompetitive activities.
86-23 (c) This section may not be deemed to authorize commission
86-24 review or approval of transactions entered into between or among
86-25 municipally owned utilities, river authorities, special districts
86-26 created by law, or other political subdivisions, whether or not
87-1 those transactions may be characterized as mergers, consolidations,
87-2 or other affiliations, when the transaction is authorized or
87-3 structured under state law.
87-4 (d) Notwithstanding any other provision of this title, an
87-5 electric utility which, before the effective date of this chapter,
87-6 entered into a stipulation or agreement in support of approval of a
87-7 merger which was approved by the commission on or after January 1,
87-8 1996, requiring the utility to pass through to ratepayers the
87-9 savings resulting from the merger of that utility with another
87-10 utility shall continue to be bound by the terms of that stipulation
87-11 or agreement. The commission shall ensure that the pass-through of
87-12 all merger savings required under any such stipulation or agreement
87-13 shall be fully implemented during the freeze period and shall be
87-14 reflected in setting the price to beat for that utility.
87-15 (Sections 39.159-39.200 reserved for expansion
87-16 SUBCHAPTER E. PRICE REGULATION AFTER COMPETITION
87-17 Sec. 39.201. COST OF SERVICE TARIFFS AND CHARGES. (a) Each
87-18 electric utility shall, on or before April 1, 2000, file proposed
87-19 tariffs for its proposed transmission and distribution utility.
87-20 (b) The filing under this section shall include supporting
87-21 cost data for determination of nonbypassable delivery charges,
87-22 which shall be the sum of:
87-23 (1) transmission and distribution utility charges by
87-24 customer class based on a forecasted 2002 test year;
87-25 (2) a system benefit fund fee; and
87-26 (3) an expected competition transition charge, if any.
88-1 (c) Each electric utility shall also identify the unbundled
88-2 generation and retail energy service costs by customer class.
88-3 (d) In accordance with a schedule and procedures it
88-4 establishes, the commission shall hold a hearing and approve or
88-5 modify and make effective as of January 1, 2002, the transmission
88-6 and distribution utility's proposed tariffs for transmission and
88-7 distribution services, the system benefit fund fee, and the
88-8 expected competition transition charge as determined under
88-9 Subsections (g) and (h) and as implemented under Subsections
88-10 (i)-(l), if any.
88-11 (e) The system benefit fund fee shall be that established by
88-12 the commission under Section 39.903.
88-13 (f) The expected competition transition charge shall be that
88-14 as determined under Subsections (g) and (h) and as implemented
88-15 under Subsections (i)-(l).
88-16 (g) The expected competition transition charge approved by
88-17 the commission shall be calculated from the amount of stranded
88-18 costs as defined in Subchapter F that are reasonably projected to
88-19 exist on the last day of the freeze period modified to reflect any
88-20 adjustments determined appropriate by the commission under Section
88-21 39.261(c).
88-22 (h) The electric utility shall use the ECOM administrative
88-23 model referenced in Section 39.262 to determine estimated stranded
88-24 costs. The model must include updated company-specific inputs.
88-25 Natural gas prices used in the model must be market-based natural
88-26 gas forward prices, where available. Growth rates in generating
89-1 plant operations and maintenance costs and allocated administrative
89-2 and general costs shall be benchmarked by comparing those costs to
89-3 the best available information on cost trends for comparable
89-4 generating plants. Capital additions shall be benchmarked using
89-5 the limitation in Section 39.259(b).
89-6 (i) An electric utility may:
89-7 (1) at any time after the start of the freeze period,
89-8 securitize 100 percent of its regulatory assets as defined by
89-9 Section 39.302 and up to 75 percent of its estimated stranded costs
89-10 as defined by this section and recover those charges through a
89-11 transition charge, in accordance with a financing order issued by
89-12 the commission under Section 39.303;
89-13 (2) implement, under bond, a nonbypassable charge of
89-14 up to 100 percent of its estimated stranded costs; or
89-15 (3) use a combination of the two methods under
89-16 Subdivisions (1) and (2).
89-17 (j) Any competition transition charge shall be allocated
89-18 among retail customer classes according to Section 39.253.
89-19 (k) In determining the length of time over which stranded
89-20 costs under Subsection (h) may be recovered, the commission shall
89-21 consider:
89-22 (1) the electric utility's rates as of the end of the
89-23 freeze period;
89-24 (2) the sum of the transmission and distribution
89-25 charges and the system benefit fund fees;
89-26 (3) the proportion of estimated stranded costs to the
90-1 invested capital of the electric utility; and
90-2 (4) any other factor consistent with the public
90-3 interest as expressed in this chapter.
90-4 (l) Two years after customer choice is introduced, the
90-5 stranded cost estimate under this section shall be reviewed and, if
90-6 necessary, adjusted to reflect a final, actual valuation in the
90-7 true-up proceeding under Section 39.262. If, based on that
90-8 proceeding, the competition transition charge is not sufficient,
90-9 the commission may extend the collection period for the charge or,
90-10 if necessary, increase the charge. Alternatively, if it is found
90-11 in the true-up proceeding that the competition transition charge is
90-12 larger than is needed to recover any remaining stranded costs, the
90-13 commission may:
90-14 (1) reduce the competition transition charge, to the
90-15 extent it has not been securitized;
90-16 (2) reverse, in whole or in part, the depreciation
90-17 expense that has been redirected under Section 39.256;
90-18 (3) reduce the transmission and distribution utility's
90-19 rates; or
90-20 (4) implement a combination of the elements in
90-21 Subdivisions (1)-(3).
90-22 Sec. 39.202. PRICE TO BEAT. (a) From January 1, 2002,
90-23 until January 1, 2007, an affiliated retail electric provider shall
90-24 make available to residential and small commercial customers of its
90-25 affiliated transmission and distribution utility rates that, on a
90-26 bundled basis, are six percent less than the affiliated electric
91-1 utility's corresponding average residential and small commercial
91-2 rates, on a bundled basis, that were in effect on January 1, 1999,
91-3 adjusted to reflect the fuel factor determined as provided by
91-4 Subsection (b) and adjusted for any base rate reduction as
91-5 stipulated to by an electric utility in a proceeding for which a
91-6 final order had not been issued by January 1, 1999. These rates on
91-7 a bundled basis shall be known as the "price to beat" for
91-8 residential and small commercial customers, except that the "price
91-9 to beat" for a utility is the rate in effect as a result of a
91-10 settlement approved by the commission after January 1, 1999, if the
91-11 commission determines that base rates for that utility have been
91-12 reduced by more than 12 percent as a result of a final order issued
91-13 by the commission after October 1, 1998.
91-14 (b) The commission shall determine the fuel factor for each
91-15 electric utility as of December 31, 2001.
91-16 (c) After the date of customer choice, each affiliated power
91-17 generation company shall file a final fuel reconciliation for the
91-18 period ending the day before the date customer choice is
91-19 introduced. The final fuel balance from that reconciliation shall
91-20 be included in the true-up proceeding under Section 39.262.
91-21 (d) An affiliated retail electric provider shall make public
91-22 its price to beat in a manner that provides adequate disclosure as
91-23 determined by the commission.
91-24 (e) The affiliated retail electric provider may not charge
91-25 rates for residential or small commercial customers that are
91-26 different from the price to beat until the earlier of 36 months
92-1 after the date customer choice is introduced or:
92-2 (1) for service to residential customers, the date the
92-3 commission determines that 40 percent or more of the electric power
92-4 consumed by residential customers within the affiliated
92-5 transmission and distribution utility's certificated service area
92-6 before the onset of customer choice is committed to be served by
92-7 nonaffiliated retail electric providers; or
92-8 (2) for service to small commercial customers, the
92-9 date the commission determines that 40 percent or more of the
92-10 electric power consumed by small commercial customers within the
92-11 affiliated transmission and distribution utility's certificated
92-12 service area before the onset of customer choice is committed to be
92-13 served by nonaffiliated retail electric providers.
92-14 (f) Notwithstanding Subsection (e), the affiliated retail
92-15 electric provider may charge rates that are different from the
92-16 price to beat for service to aggregated loads of nonresidential
92-17 customers having an aggregated peak demand greater than 1,000
92-18 kilowatts, provided that all affected customers are:
92-19 (1) commonly owned; or
92-20 (2) franchisees of the same franchisor.
92-21 (g) The affiliated retail electric provider may not
92-22 encourage or provide an incentive to a customer to switch to a
92-23 nonaffiliated retail electric provider, promote any nonaffiliated
92-24 retail electric provider, or exchange customers with any
92-25 nonaffiliated retail electric provider to comply with the
92-26 requirements of Subsection (e)(1) or (2).
93-1 (h) The following standards shall be used for measuring
93-2 electric power consumption during the period before the onset of
93-3 customer choice:
93-4 (1) the consumption of residential and small
93-5 commercial customers with an annual peak demand less than or equal
93-6 to 20 kilowatts shall be based on the average annual consumption of
93-7 those respective groups during the year 2000;
93-8 (2) consumption for all small commercial customers
93-9 with an annual peak demand larger than 20 kilowatts shall be based
93-10 on each customer's usage during the year 2000; and
93-11 (3) for purposes of determining whether an affiliated
93-12 retail electric provider has met the requirements of Subsection
93-13 (e)(2), the aggregated loads of nonresidential customers having a
93-14 peak demand greater than 1,000 kilowatts that are served by the
93-15 affiliated retail electric provider at a rate different from the
93-16 price to beat under Subsection (f) shall be deducted from the
93-17 electric power consumption of small commercial customers during the
93-18 period before the onset of customer choice.
93-19 (i) For purposes of Subsection (h)(2), if less than 12
93-20 months of consumption history exists for any such customer, the
93-21 usage history shall be supplemented with the prior history of that
93-22 customer's location. For service to a new location, the annual
93-23 consumption shall be determined as the transmission and
93-24 distribution utility's estimate of the maximum annual kilowatt
93-25 demand used in sizing the electric service to that customer
93-26 multiplied by 8,760 hours, and that product multiplied by the
94-1 average annual customer load factor for small commercial customers
94-2 with loads greater than 20 kilowatts for the year 2000.
94-3 (j) On determining that its affiliated retail electric
94-4 provider has met the requirements of Subsection (e)(1) or (2), an
94-5 electric utility or a transmission and distribution utility shall
94-6 make a filing with the commission attesting to the fact that those
94-7 requirements have been met and that the restrictions of Subsection
94-8 (e)(1) or (2) and the true-up in Section 39.262(e) are no longer
94-9 applicable. The commission shall adopt appropriate procedures to
94-10 enable it to accept or reject the filing within 30 days.
94-11 (k) Following the true-up proceedings conducted under
94-12 Section 39.262, the commission may adjust the price to beat.
94-13 (l) An affiliated retail electric provider may request that
94-14 the commission adjust the fuel factor established under Subsection
94-15 (b) not more than twice a year if the affiliated retail electric
94-16 provider demonstrates that the existing fuel factor does not
94-17 adequately reflect significant changes in the market price of
94-18 natural gas and purchased energy used to serve retail customers.
94-19 (m) In a power region outside of ERCOT, if customer choice
94-20 is introduced before the requirements of Section 39.152(a) are met,
94-21 an affiliated retail electric provider shall charge rates to
94-22 customers other than residential and small commercial customers
94-23 that are no higher than the rates that, on a bundled basis, were in
94-24 effect on January 1, 1999, adjusted to reflect the fuel factor as
94-25 provided by Subsection (b) and adjusted for any base rate reduction
94-26 as stipulated to by an electric utility in a proceeding for which a
95-1 final order had not been issued by January 1, 1999.
95-2 (n) Notwithstanding Subsection (a), in a power region
95-3 outside of ERCOT, if customer choice is introduced before the
95-4 requirements of Section 39.152(a) are met, an affiliated retail
95-5 electric provider shall continue to offer the price to beat to
95-6 residential and small commercial customers, unless the price is
95-7 changed by the commission in accordance with this chapter, until
95-8 the later of 60 months after the date customer choice is introduced
95-9 or the requirements of Section 39.152(a) are met.
95-10 (o) In this section, "small commercial customer" means a
95-11 commercial customer having a peak demand of 1,000 kilowatts or
95-12 less.
95-13 (p) On finding that a retail electric provider will be
95-14 unable to maintain its financial integrity if it complies with
95-15 Subsection (a), the commission shall set the retail electric
95-16 provider's price to beat at the minimum level that will allow the
95-17 retail electric provider to maintain its financial integrity.
95-18 However, in no event shall the price to beat exceed the level of
95-19 rates, on a bundled basis, charged by the affiliated electric
95-20 utility on September 1, 1999, adjusted for fuel as provided by
95-21 Subsection (b).
95-22 Sec. 39.203. TRANSMISSION AND DISTRIBUTION SERVICE.
95-23 (a) All transmission and distribution utilities shall provide
95-24 transmission service at wholesale under Subchapter A, Chapter 35.
95-25 In addition, on and after January 1, 2002, a transmission and
95-26 distribution utility shall provide transmission or distribution
96-1 service, or both, at retail to an electric utility, a retail
96-2 electric provider, a municipally owned utility, an electric
96-3 cooperative, or an end-use customer at rates, terms of access, and
96-4 conditions that are comparable to those that apply to the
96-5 transmission and distribution utility and its affiliates. A
96-6 municipally owned utility offering customer choice or an electric
96-7 cooperative offering customer choice shall likewise provide
96-8 transmission or distribution service, or both, at retail to all
96-9 such entities in accordance with the commission's rules applicable
96-10 to terms and conditions of access and at rates adopted in
96-11 accordance with Sections 40.055(a)(1) and 41.055(1), respectively.
96-12 (b) When necessary to serve a wholesale customer an electric
96-13 utility, an electric cooperative that has not opted for customer
96-14 choice, or a municipally owned utility that has not opted for
96-15 customer choice shall provide wholesale transmission service at
96-16 distribution voltage. A customer of a municipally owned utility
96-17 that has not opted for customer choice or of an electric
96-18 cooperative that has not opted for customer choice may not claim
96-19 the status of a wholesale customer or be designated as a wholesale
96-20 customer if the customer is being or has been served under a retail
96-21 rate schedule of the municipally owned utility or electric
96-22 cooperative.
96-23 (c) On or before January 1, 2002, the commission shall
96-24 establish for all retail electric utilities offering customer
96-25 choice reasonable and comparable terms and conditions, in
96-26 accordance with Section 39.201, that comply with Subsection (a) for
97-1 open access on distribution facilities and shall establish, for all
97-2 retail electric utilities offering customer choice other than
97-3 municipally owned utilities and electric cooperatives, reasonable
97-4 and comparable rates for open access on distribution facilities.
97-5 (d) The terms of access, conditions, and rates established
97-6 under Subsection (c) shall be comparable to the terms of access,
97-7 conditions, and rates that the electric utility applies to itself
97-8 or its affiliates. The rules shall also provide that all ancillary
97-9 services provided by the utility to itself or its affiliates are
97-10 also available to third parties on request on a nondiscriminatory
97-11 basis.
97-12 (e) The commission may require an electric utility or a
97-13 transmission and distribution utility to construct or enlarge
97-14 facilities to ensure safe and reliable service for the state's
97-15 electric markets. In any proceeding brought under Chapter 37, an
97-16 electric utility or transmission and distribution utility ordered
97-17 to construct or enlarge facilities under this subchapter need not
97-18 prove that the construction ordered is necessary for the service,
97-19 accommodation, convenience, or safety of the public and need not
97-20 address the factors listed in Sections 37.056(c)(1)-(3) and (4)(E).
97-21 (f) The commission's rules must be consistent with the
97-22 standards of this title and may not be contrary to an applicable
97-23 decision, rule, or policy statement of a federal regulatory agency
97-24 having jurisdiction.
97-25 (g) Each power region shall have generally applicable
97-26 tariffs approved by the commission or a federal regulatory agency
98-1 having jurisdiction that guarantees open and nondiscriminatory
98-2 access as required by Section 39.152. This subsection may not be
98-3 deemed to vest in the commission power to set or approve
98-4 distribution access rates of a municipally owned utility or an
98-5 electric cooperative that has adopted customer choice.
98-6 (h) A customer in a multiply certificated service area may
98-7 switch its retail distribution service provider among certificated
98-8 retail electric utilities only by disconnecting from the facilities
98-9 of one retail electric utility and connecting to the facilities of
98-10 another retail electric utility.
98-11 Sec. 39.204. TARIFFS FOR OPEN ACCESS. Each transmission and
98-12 distribution utility shall file a tariff implementing the open
98-13 access rules with the commission or the federal regulatory
98-14 authority having jurisdiction over the transmission and
98-15 distribution service of the utility not later than the 90th day
98-16 before the date customer choice is offered by that utility.
98-17 Sec. 39.205. REGULATION OF COSTS FOLLOWING FREEZE PERIOD.
98-18 At the conclusion of the freeze period, any remaining costs
98-19 associated with nuclear decommissioning obligations continue to be
98-20 subject to cost of service rate regulation and shall be included as
98-21 a nonbypassable charge to retail customers.
98-22 (Sections 39.206-39.250 reserved for expansion
98-23 SUBCHAPTER F. RECOVERY OF STRANDED COSTS
98-24 THROUGH COMPETITION TRANSITION CHARGE
98-25 Sec. 39.251. DEFINITIONS. In this subchapter:
98-26 (1) "Above market purchased power costs" means
99-1 wholesale demand and energy costs that a utility is obligated to
99-2 pay under an existing purchased power contract to the extent the
99-3 costs are greater than the purchased power market value.
99-4 (2) "Existing purchased power contract" means a
99-5 purchased power contract in effect on January 1, 1999, including
99-6 any amendments and revisions to that contract resulting from
99-7 litigation initiated before January 1, 1999.
99-8 (3) "Generation assets" means all assets associated
99-9 with the production of electricity, including generation plants,
99-10 electrical interconnections of the generation plant to the
99-11 transmission system, fuel contracts, fuel transportation contracts,
99-12 water contracts, lands, surface or subsurface water rights,
99-13 emissions-related allowances, and gas pipeline interconnections.
99-14 (4) "Market value" means, for nonnuclear assets and
99-15 certain nuclear assets, the value the assets would have if bought
99-16 and sold in a bona fide third-party transaction or transactions on
99-17 the open market under Section 39.262(h) or, for certain nuclear
99-18 assets, as described by Section 39.262(i), the value determined
99-19 under the method provided by that subsection.
99-20 (5) "Purchased power market value" means the value of
99-21 demand and energy bought and sold in a bona fide third-party
99-22 transaction or transactions on the open market and determined by
99-23 using the weighted average costs of the highest three offers from
99-24 the market for purchase of the demand and energy available under
99-25 the existing purchased power contracts.
99-26 (6) "Retail stranded costs" means that part of net
100-1 stranded cost associated with the provision of retail service.
100-2 (7) "Stranded cost" means the positive excess of the
100-3 net book value of generation assets over the market value of the
100-4 assets, taking into account all of the electric utility's
100-5 generation assets, any above market purchased power costs, and any
100-6 deferred debit related to a utility's discontinuance of the
100-7 application of Statement of Financial Accounting Standards No. 71
100-8 ("Accounting for the Effects of Certain Types of Regulation") for
100-9 generation-related assets if required by the provisions of this
100-10 chapter. For purposes of Section 39.262, book value shall be
100-11 established as of December 31, 2001, or the date a market value is
100-12 established through a market valuation method under Section
100-13 39.262(h), whichever is earlier, and shall include stranded costs
100-14 incurred under Section 39.263.
100-15 Sec. 39.252. RIGHT TO RECOVER STRANDED COSTS. (a) An
100-16 electric utility is allowed to recover all of its net, verifiable,
100-17 nonmitigable stranded costs incurred in purchasing power and
100-18 providing electric generation service.
100-19 (b)(1) Recovery of retail stranded costs by an electric
100-20 utility shall be from all existing or future retail customers,
100-21 including the facilities, premises, and loads of those retail
100-22 customers, within the utility's geographical certificated service
100-23 area as it existed on May 1, 1999. A retail customer may not avoid
100-24 stranded cost recovery charges by switching to new on-site
100-25 generation except as provided by Section 39.262(k). For purposes
100-26 of this subchapter, "new on-site generation" means electric
101-1 generation capacity greater than 10 megawatts capable of being
101-2 lawfully delivered to the site without use of utility distribution
101-3 or transmission facilities and which was not, on or before December
101-4 31, 1999, either:
101-5 (A) a fully operational facility; or
101-6 (B) a project supported by substantially
101-7 complete filings for all necessary site-specific environmental
101-8 permits under the rules of the Texas Natural Resource Conservation
101-9 Commission in effect at the time of filing.
101-10 (2) If a customer commences taking energy from new
101-11 on-site generation which materially reduces the customer's use of
101-12 energy delivered through the utility's facilities, the customer
101-13 shall pay an amount each month computed by multiplying the output
101-14 of the on-site generation by the new sum of competition transition
101-15 charges under Section 39.201 and transition charges under
101-16 Subchapter G which are in effect during that month. Payment shall
101-17 be made to the utility, its successors, an assignee, or other
101-18 collection agent responsible for collecting the competition
101-19 transition charges and transition charges and shall be collected in
101-20 addition to the competition transition charges and transition
101-21 charges applicable to energy actually delivered to the customer
101-22 through the utility's facilities.
101-23 (c) In multiply certificated areas, a retail customer may
101-24 not avoid stranded cost recovery charges by switching to another
101-25 electric utility, electric cooperative, or municipally owned
101-26 utility after May 1, 1999. A customer in a multiply certificated
102-1 service area that requested to switch providers on or before May 1,
102-2 1999, or was not taking service from an electric utility on May 1,
102-3 1999, and does not do so after that date is not responsible for
102-4 paying retail stranded costs of that utility.
102-5 (d) An electric utility shall pursue commercially reasonable
102-6 means to reduce its potential stranded costs, including good faith
102-7 attempts to renegotiate above-cost fuel and purchased power
102-8 contracts or the exercise of normal business practices to protect
102-9 the value of its assets. The commission shall consider the
102-10 utility's efforts under this subsection when determining the amount
102-11 of the utility's stranded costs; provided, however, that nothing in
102-12 this section authorizes the commission to substitute its judgment
102-13 for a market valuation of generation assets determined under
102-14 Sections 39.262(h) and (i).
102-15 Sec. 39.253. ALLOCATION OF STRANDED COSTS. (a) Any capital
102-16 costs incurred by an electric utility to improve air quality under
102-17 Section 39.263 or 39.264 that are included in a utility's invested
102-18 capital in accordance with those sections shall be allocated among
102-19 customer classes as follows:
102-20 (1) 50 percent of those costs shall be allocated in
102-21 accordance with the methodology used to allocate the costs of the
102-22 underlying assets in the electric utility's most recent commission
102-23 order addressing rate design; and
102-24 (2) the remainder shall be allocated on the basis of
102-25 the energy consumption of the customer classes.
102-26 (b) All other retail stranded costs shall be allocated among
103-1 retail customer classes in accordance with Subsections (c)-(i).
103-2 (c) The allocation to the residential class shall be
103-3 determined by allocating to all customer classes 50 percent of the
103-4 stranded costs in accordance with the methodology used to allocate
103-5 the costs of the underlying assets in the electric utility's most
103-6 recent commission order addressing rate design and allocating the
103-7 remainder of the stranded costs on the basis of the energy
103-8 consumption of the classes.
103-9 (d) After the allocation to the residential class required
103-10 by Subsection (c) has been calculated, the remaining stranded costs
103-11 shall be allocated to the remaining customer classes in accordance
103-12 with the methodology used to allocate the costs of the underlying
103-13 assets in the electric utility's most recent commission order
103-14 addressing rate design. Non-firm industrial customers shall be
103-15 allocated stranded costs equal to 150 percent of the amount
103-16 allocated to that class.
103-17 (e) After the allocation to the residential class required
103-18 by Subsection (c) and the allocation to the nonfirm industrial
103-19 class required by Subsection (d) have been calculated, the
103-20 remaining stranded costs shall be allocated to the remaining
103-21 customer classes in accordance with the methodology used to
103-22 allocate the costs of the underlying assets in the electric
103-23 utility's most recent commission order addressing rate design.
103-24 (f) Notwithstanding any other provision of this section, to
103-25 the extent that the total retail stranded costs, including
103-26 regulatory assets, of investor-owned utilities exceed $5 billion on
104-1 a statewide basis, any stranded costs in excess of $5 billion shall
104-2 be allocated among retail customer classes in accordance with the
104-3 methodology used to allocate the costs of the underlying assets in
104-4 the electric utility's most recent commission order addressing rate
104-5 design.
104-6 (g) The energy consumption of the customer classes used in
104-7 Subsections (a)(2) and (c) shall be based on the relevant class
104-8 characteristics as of May 1, 1999, adjusted for normal weather
104-9 conditions.
104-10 (h) For purposes of this section, "stranded costs" includes
104-11 regulatory assets.
104-12 (i) Except as provided by Section 39.262(k), no customer or
104-13 customer class may avoid the obligation to pay the amount of
104-14 stranded costs allocated to that customer class.
104-15 Sec. 39.254. USE OF REVENUES FOR UTILITIES WITH STRANDED
104-16 COSTS. This subchapter provides a number of tools to an electric
104-17 utility to mitigate stranded costs. Each electric utility that was
104-18 reported by the commission to have positive "excess costs over
104-19 market" (ECOM), denoted as the "base case" for the amount of
104-20 stranded costs before full retail competition in 2002 with respect
104-21 to its Texas jurisdiction, in the April 1998 Report to the Texas
104-22 Senate Interim Committee on Electric Utility Restructuring entitled
104-23 "Potentially Strandable Investment (ECOM) Report: 1998 Update,"
104-24 must use these tools to reduce the net book value of, otherwise
104-25 referred to as "accelerate" the cost recovery of, its stranded
104-26 costs each year. Any positive difference under the report required
105-1 by Section 39.257(b) shall be applied to the net book value of
105-2 generation assets.
105-3 Sec. 39.255. USE OF REVENUES FOR UTILITIES WITH NO STRANDED
105-4 COSTS. (a) An electric utility that does not have stranded costs
105-5 described by Section 39.254 shall be permitted to use any positive
105-6 difference under the report required by Section 39.257(b) on
105-7 capital expenditures to improve or expand transmission or
105-8 distribution facilities, or on capital expenditures to improve air
105-9 quality, as approved by the commission. Any such capital
105-10 expenditures shall be made in the calendar year immediately
105-11 following the year for which the report required by Section 39.257
105-12 is calculated. The capital expenditures shall be reflected in any
105-13 future proceeding under this chapter to set transmission or
105-14 distribution rates as a reduction to the utility's transmission and
105-15 distribution invested capital, as approved by the commission.
105-16 (b) To the extent that positive differences under the report
105-17 required by Section 39.257(b) are not used for capital
105-18 expenditures, the amounts shall be flowed back to the electric
105-19 utility's Texas jurisdictional customers through the power cost
105-20 recovery factor.
105-21 (c) This section applies only to the use of positive
105-22 differences under the report required by Section 39.257(b) for each
105-23 year during the freeze period.
105-24 Sec. 39.256. OPTION TO REDIRECT DEPRECIATION. (a) For the
105-25 calendar years of 1998, 1999, 2000, and 2001, an electric utility
105-26 described by Section 39.254 may redirect all or a part of the
106-1 depreciation expense relating to transmission and distribution
106-2 assets to its net generation plant assets.
106-3 (b) The electric utility shall report a decision under
106-4 Subsection (a) to the commission and any other applicable
106-5 regulatory authority.
106-6 (c) Any adjustments made to the book value of transmission
106-7 and distribution assets or the creation of any related regulatory
106-8 assets resulting from the redirection under this section shall be
106-9 accepted and applied by the commission for establishing net
106-10 invested capital and transmission and distribution rates for retail
106-11 customers in all future proceedings.
106-12 (d) Notwithstanding Subsection (c), the design of
106-13 post-freeze-period retail rates may not:
106-14 (1) shift the allocation of responsibility for
106-15 stranded costs;
106-16 (2) include the adjusted costs in wholesale
106-17 transmission and distribution rates; or
106-18 (3) apply the adjustments for the purpose of
106-19 establishing net invested capital and transmission and distribution
106-20 rates for wholesale customers.
106-21 Sec. 39.257. ANNUAL REPORT. (a) Beginning with the 1999
106-22 calendar year, each electric utility shall file a report with the
106-23 commission not later than 90 days after the end of each year during
106-24 the freeze period under a schedule and a format determined by the
106-25 commission.
106-26 (b) The report shall identify any positive difference
107-1 between annual revenues, reduced by the amount of annual revenues
107-2 under Sections 36.203 and 36.205, the revenues received under the
107-3 interutility billing process as adopted by the commission to
107-4 implement Sections 35.004, 35.006, and 35.007, revenues associated
107-5 with transition charges as defined by Section 39.302, and annual
107-6 costs.
107-7 Sec. 39.258. ANNUAL REPORT: DETERMINATION OF ANNUAL COSTS.
107-8 For the purposes of determining the annual costs in each annual
107-9 report, the following amounts shall be used:
107-10 (1) the lesser of:
107-11 (A) the utility's Texas jurisdictional operation
107-12 and maintenance expense reflected in each utility's Federal Energy
107-13 Regulatory Commission Form 1 of the report year, plus factoring
107-14 expenses not included in operation and maintenance, adjusted for:
107-15 (i) costs under Sections 36.062, 36.203,
107-16 and 36.205; and
107-17 (ii) revenues recorded under the
107-18 interutility billing process adopted by the commission to implement
107-19 Sections 35.004, 35.006, and 35.007; or
107-20 (B) the Texas jurisdictional operation and
107-21 maintenance expense reflected in each utility's 1996 Federal Energy
107-22 Regulatory Commission Form 1, plus factoring expenses not included
107-23 in operation and maintenance, adjusted for:
107-24 (i) costs under Sections 36.062, 36.203,
107-25 and 36.205, and not indexed for inflation;
107-26 (ii) any difference between the annual
108-1 revenues and the expenses recorded under the interutility billing
108-2 process adopted by the commission to implement Sections 35.004,
108-3 35.006, and 35.007; and
108-4 (iii) the annual percentage change in the
108-5 average number of utility customers;
108-6 (2) the amount of nuclear decommissioning expense
108-7 approved in the electric utility's last rate proceeding before the
108-8 commission, as may be required to be adjusted to comply with
108-9 applicable federal regulatory requirements;
108-10 (3) the depreciation rates approved in the electric
108-11 utility's last rate proceeding before the commission;
108-12 (4) the amortization expense approved in the electric
108-13 utility's last rate proceeding before the commission or in any
108-14 other proceeding in which deferred costs and the amortization of
108-15 those costs are established, except that if the items are fully
108-16 amortized during the freeze period, the expense shall be adjusted
108-17 accordingly;
108-18 (5) taxes and fees, including municipal franchise fees
108-19 to the extent not included in Subdivision (1), other than federal
108-20 income taxes, and assessments incurred that year;
108-21 (6) federal income tax expense, computed according to
108-22 the stand-alone methodology and using the actual capital structure
108-23 and actual cost of debt as of December 31 of the report year;
108-24 (7) return on invested capital, computed by
108-25 multiplying invested capital as of December 31 of the report year,
108-26 determined as provided by Section 39.259, by the cost of capital
109-1 approved in the electric utility's most recent rate proceeding
109-2 before the commission in which the cost of capital was specifically
109-3 adopted, or, in the case of a range, the midpoint of the range, if
109-4 the final rate order for the proceeding was issued on or after
109-5 January 1, 1992, or if such an order does not exist, a cost of
109-6 capital of 9.6 percent shall be used; and
109-7 (8) the amount resulting from any operation and
109-8 maintenance expense savings tracker from a merger of two utilities
109-9 and contained in a settlement agreement approved by the commission
109-10 before January 1, 1999.
109-11 Sec. 39.259. ANNUAL REPORT: DETERMINATION OF INVESTED
109-12 CAPITAL. (a) For the purposes of determining invested capital in
109-13 each annual report, the net plant in service, regulatory assets,
109-14 and deferred federal income taxes shall be updated each year, and
109-15 generation-related invested capital shall be reduced by the amount
109-16 of securitization under Sections 39.201(i) and 39.262(c) to the
109-17 extent otherwise included in invested capital.
109-18 (b) Capital additions to a plant in an amount less than
109-19 1-1/2 percent of the electric utility's net plant in service on
109-20 December 31, 1998, less plant items previously excluded by the
109-21 commission, for each of the years 1999 through 2001 are presumed
109-22 prudent.
109-23 (c) All other items in invested capital shall be as approved
109-24 in the electric utility's last rate proceeding before the
109-25 commission.
109-26 Sec. 39.260. USE OF GENERALLY ACCEPTED ACCOUNTING
110-1 PRINCIPLES. (a) The definition and identification of invested
110-2 capital and other terms used in this subchapter and Subchapter G
110-3 that affect the net book value of generation assets and the
110-4 treatment of transactions performed under Section 35.035 and other
110-5 transactions authorized by this title or approved by the regulatory
110-6 authority that affect the net book value of generation assets
110-7 during the freeze period shall be treated in accordance with
110-8 generally accepted accounting principles as modified by regulatory
110-9 accounting rules generally applicable to utilities.
110-10 (b) The principles and criteria described by Subsection (a),
110-11 including the criteria for applicability of Statement of Financial
110-12 Accounting Standards No. 71 ("Accounting for the Effects of Certain
110-13 Types of Regulation"), shall be applied for purposes of this
110-14 subchapter as they existed on January 1, 1999.
110-15 Sec. 39.261. REVIEW OF ANNUAL REPORT. (a) The annual
110-16 report filed under this subchapter is a public document and shall
110-17 be reviewed by the staff of the commission and the office. Both
110-18 staffs may review work papers and supporting documents and engage
110-19 in discussions with the utility about the data underlying the
110-20 reports.
110-21 (b) The staff of the commission and the office shall
110-22 communicate in writing to an electric utility not later than the
110-23 180th day after the date the report is filed if they have any
110-24 disagreements with the data or computations.
110-25 (c) The commission shall finalize and resolve any
110-26 disagreements related to the annual report, consistent with the
111-1 requirements of Section 39.258, as follows:
111-2 (1) for each calendar year, the commission shall
111-3 finalize the annual report before establishing the competition
111-4 transition charge under Section 39.201; and
111-5 (2) for each calendar year, the commission shall
111-6 finalize the annual report and reflect the result as part of the
111-7 true-up proceeding under Section 39.262.
111-8 Sec. 39.262. TRUE-UP PROCEEDING. (a) An electric utility,
111-9 together with its affiliated retail electric provider and its
111-10 affiliated transmission and distribution utility, may not be
111-11 permitted to overrecover stranded costs through the procedures
111-12 established by this section or through the application of the
111-13 measures provided by the other sections of this chapter.
111-14 (b) After the freeze period, an electric utility located in
111-15 a power region that is not certified under Section 39.152 shall
111-16 continue to file annual reports under Sections 39.257, 39.258, and
111-17 39.259 as if the freeze period remained in effect, until the time
111-18 the power region qualifies as certified under Section 39.152. In
111-19 addition, the commission staff and the office shall continue to
111-20 review the annual reports as provided by Section 39.261.
111-21 (c) After January 10, 2004, at a schedule and under
111-22 procedures to be determined by the commission, each transmission
111-23 and distribution utility, its affiliated retail electric provider,
111-24 and its affiliated power generation company shall jointly file to
111-25 finalize stranded costs under Subsections (h) and (i) and reconcile
111-26 those costs with the estimated stranded costs used to develop the
112-1 competition transition charge in the proceeding held under Section
112-2 39.201. Any resulting difference shall be applied to the
112-3 nonbypassable delivery rates of the transmission and distribution
112-4 utility, except that at the utility's option, any or all of the
112-5 remaining stranded costs may be securitized under Subchapter G.
112-6 (d) The affiliated power generation company shall reconcile,
112-7 and either credit or bill to the transmission and distribution
112-8 utility, the net sum of:
112-9 (1) the former electric utility's final fuel balance
112-10 determined under Section 39.202(c); and
112-11 (2) any difference between the price of power obtained
112-12 through the capacity auctions under Sections 39.153 and 39.156 and
112-13 the power cost projections that were employed for the same time
112-14 period in the ECOM model to estimate stranded costs in the
112-15 proceeding under Section 39.201.
112-16 (e) To the extent that the price to beat exceeded the market
112-17 price of electricity, the affiliated retail electric provider shall
112-18 reconcile and credit to the affiliated transmission and
112-19 distribution utility any positive difference between the price to
112-20 beat established under Section 39.202, reduced by the nonbypassable
112-21 delivery charge established under Section 39.201, and the
112-22 prevailing market price of electricity during the same time period.
112-23 A reconciliation for the applicable customer class is not required
112-24 under this subsection for an affiliated retail electric provider
112-25 that satisfies the requirements of Section 39.202(e)(1) or (2)
112-26 before the expiration of two years from the introduction of
113-1 customer choice. If a reconciliation is required, in no event
113-2 shall the amount credited exceed an amount equal to the number of
113-3 residential or small commercial customers served by the affiliated
113-4 transmission and distribution utility that are buying electricity
113-5 from the affiliated retail electric provider at the price to beat
113-6 on the second anniversary of the beginning of competition, minus
113-7 the number of new customers obtained outside the service area,
113-8 multiplied by $150.
113-9 (f) To the extent that any amount of regulatory assets
113-10 included in a transition charge or competition transition charge
113-11 exceeds the amount of regulatory assets approved in a rate order
113-12 which became effective on or before September 1, 1999, the
113-13 commission shall conduct a review during the true-up proceeding to
113-14 determine whether such amounts were appropriately calculated and
113-15 constituted reasonable and necessary costs pursuant to Subchapter
113-16 B, Chapter 36. If the commission finds that the amount of
113-17 regulatory assets specified in Section 39.302(5) is subject to
113-18 modification, a credit or other rate adjustment shall be made to
113-19 the transmission and distribution utility's nonbypassable delivery
113-20 rates; provided, however, that no adjustment may be made to a
113-21 transition charge established under Subchapter G.
113-22 (g) Based on the credits or bills received from its
113-23 affiliates under Subsections (d), (e), and (f), the transmission
113-24 and distribution utility shall make necessary adjustments to the
113-25 nonbypassable delivery rates it charges to retail electric
113-26 providers. If the commission determines that the nonbypassable
114-1 delivery rates are not sufficient, the commission may extend the
114-2 original collection period for the charge or, if necessary,
114-3 increase the charge. Alternatively, if the commission determines
114-4 that the nonbypassable delivery rates are larger than are needed to
114-5 recover the transmission and distribution utility's costs, the
114-6 commission shall correspondingly reduce:
114-7 (1) the competition transition charge, to the extent
114-8 it has not been securitized;
114-9 (2) the depreciation expense that has been redirected
114-10 under Section 39.256;
114-11 (3) the transmission and distribution utility's rates;
114-12 or
114-13 (4) a combination of the elements in Subdivisions
114-14 (1)-(3).
114-15 (h) Except as provided in Subsection (i), for the purpose of
114-16 finalizing the stranded cost estimate used to establish the
114-17 competition transition charge under Section 39.201, the affiliated
114-18 power generation company shall quantify its stranded costs using
114-19 one or more of the following methods:
114-20 (1) Sale of Assets. If, at any time after December
114-21 31, 1999, an electric utility or its affiliated power generation
114-22 company has sold some or all of its generation assets, which sale
114-23 shall include all generating assets associated with each generating
114-24 plant that is sold, in a bona fide third-party transaction under a
114-25 competitive offering, the total net value realized from the sale
114-26 establishes the market value of the generation assets sold. If not
115-1 all assets are sold, the market value of the remaining generation
115-2 assets shall be established by one or more of the other methods in
115-3 this section.
115-4 (2) Stock Valuation Method. If, at any time after
115-5 December 31, 1999, an electric utility or its affiliated power
115-6 generation company has transferred some or all of its generation
115-7 assets, including, at the election of the electric utility or power
115-8 generation company, any fuel and fuel transportation contracts
115-9 related to those assets, to one or more separate affiliated or
115-10 nonaffiliated corporations, not less than 51 percent of the common
115-11 stock of each corporation is spun off and sold to public investors
115-12 through a national stock exchange, and the common stock has been
115-13 traded for not less than one year, the resulting average daily
115-14 closing price of the common stock over 30 consecutive trading days
115-15 chosen by the commission out of the last 120 consecutive trading
115-16 days before the filing required under Subsection (c) establishes
115-17 the market value of the common stock equity in each transferee
115-18 corporation. The book value of each transferee corporation's debt
115-19 and preferred stock securities shall be added to the market value
115-20 of its assets. The market value of each transferee corporation's
115-21 assets shall be reduced by the corresponding net book value of the
115-22 assets acquired by each transferee corporation from any entity
115-23 other than the affiliated electric utility or power generation
115-24 company. The resulting market value of the assets establishes the
115-25 market value of the generation assets transferred by the electric
115-26 utility or power generation company to each separate corporation.
116-1 If not all assets are disposed of in this manner, the market value
116-2 of the remaining assets shall be established by one or more of the
116-3 other methods in this section.
116-4 (3) Partial Stock Valuation Method. If, at any time
116-5 after December 31, 1999, an electric utility or its affiliated
116-6 power generation company has transferred some or all of its
116-7 generation assets, including, at the election of the electric
116-8 utility or power generation company, any fuel and fuel
116-9 transportation contracts related to those assets, to one or more
116-10 separate affiliated or nonaffiliated corporations, at least 19
116-11 percent, but less than 51 percent, of the common stock of each
116-12 corporation is spun off and sold to public investors through a
116-13 national stock exchange, and the common stock has been traded for
116-14 not less than one year, the resulting average daily closing price
116-15 of the common stock over 30 consecutive trading days chosen by the
116-16 commission out of the last 120 consecutive trading days before the
116-17 filing required under Subsection (c) shall be presumed to establish
116-18 the market value of the common stock equity in each transferee
116-19 corporation. The commission may accept the market valuation to
116-20 conclusively establish the value of the common stock equity in each
116-21 transferee corporation or convene a valuation panel of three
116-22 independent financial experts to determine whether the percentage
116-23 of common stock sold is fairly representative of the total common
116-24 stock equity or whether a control premium exists for the retained
116-25 interest. The valuation panel must consist of financial experts,
116-26 chosen from proposals submitted in response to commission requests,
117-1 from the top 10 nationally recognized investment banks with
117-2 demonstrated experience in the United States electric industry as
117-3 indicated by the dollar amount of public offerings of long-term
117-4 debt and equity of United States investor-owned electric companies
117-5 over the immediately preceding three years as ranked by the
117-6 publications "Securities Data" or "Institutional Investor." If the
117-7 panel determines that a control premium exists for the retained
117-8 interest, the panel shall determine the amount of the control
117-9 premium, and the commission shall adopt the determination but may
117-10 not increase the market value by a control premium greater than 10
117-11 percent. The costs and expenses of the panel, as approved by the
117-12 commission, shall be paid by each transferee corporation. The
117-13 determination of the commission based on the finding of the panel
117-14 conclusively establishes the value of the common stock of each
117-15 transferee corporation. The book value of each transferee
117-16 corporation's debt and preferred stock securities shall be added to
117-17 the market value of its assets. The market value of each
117-18 transferee corporation's assets shall be reduced by the
117-19 corresponding net book value of the assets acquired by each
117-20 transferee corporation from any entity other than the affiliated
117-21 electric utility or power generation company. The resulting market
117-22 value of the assets establishes the market value of the generation
117-23 assets transferred by the electric utility or power generation
117-24 company to each separate corporation.
117-25 (4) Exchange of Assets. If, at any time after
117-26 December 31, 1999, an electric utility or its affiliated power
118-1 generation company has transferred some or all of its generation
118-2 assets, including any fuel and fuel transportation contracts
118-3 related to those assets, in a bona fide third-party exchange
118-4 transaction, the stranded costs related to the transferred assets
118-5 shall be the difference between the book value and the market value
118-6 of the transferred assets at the time of the exchange, taking into
118-7 account any other consideration received or given. The market
118-8 value of the transferred assets may be determined through an
118-9 appraisal by a nationally recognized independent appraisal firm, if
118-10 the market value is subject to a market valuation by means of an
118-11 offer of sale in accordance with this subdivision. To obtain a
118-12 market valuation by means of an offer of sale, the owner of the
118-13 asset shall offer it for sale to other parties under procedures
118-14 that provide broad public notice of the offer and a reasonable
118-15 opportunity for other parties to bid on the asset. The owner of
118-16 the asset may establish a reserve price for any offer based on the
118-17 sum of the appraised value of the asset and the tax impact of
118-18 selling the asset, as determined by the commission.
118-19 (i) Unless an electric utility or its affiliated power
118-20 generation company combines all of its remaining generation assets
118-21 into one or more transferee corporations as described in
118-22 Subsections (h)(2) and (3), the electric utility shall quantify its
118-23 stranded costs for nuclear assets using the ECOM method. The ECOM
118-24 method is the estimation model prepared for and described by the
118-25 commission's April 1998 Report to the Texas Senate Interim
118-26 Committee on Electric Restructuring entitled "Potentially
119-1 Strandable Investment (ECOM) Report: 1998 Update." The
119-2 methodology used in the model must be the same as that used in the
119-3 1998 report to determine the "base case." At the time of the
119-4 proceeding under this section, the ECOM model shall be rerun using
119-5 updated company-specific inputs required by the model, updating the
119-6 market price of electricity, and using updated natural gas price
119-7 forecasts and the capacity cost based on the long-run marginal cost
119-8 of the most economic new generation technology then available.
119-9 Natural gas price projections used in the model must be
119-10 market-based natural gas forward prices, where available. Growth
119-11 rates in generating plant operations and maintenance costs and
119-12 allocated administrative and general costs shall be benchmarked by
119-13 comparing those costs to the best available information on cost
119-14 trends for comparable generating plants. Capital additions shall
119-15 be benchmarked using the limitation in Section 39.259(b).
119-16 (j) The commission shall issue a final order not later than
119-17 the 150th day after the date of the filing under this section by
119-18 the transmission and distribution utility, its affiliated retail
119-19 electric provider, and its affiliated power generation company, and
119-20 the resulting order shall be subject to judicial review under
119-21 Chapter 2001, Government Code.
119-22 (k) Notwithstanding Section 39.252, to the extent that a
119-23 customer's actual load has been lawfully served by a fully
119-24 operational qualifying facility before September 1, 2001, or by an
119-25 on-site power production facility with a rated capacity of 10
119-26 megawatts or less, any charge for recovery of stranded costs under
120-1 this section or Subchapter G assessed on that customer after the
120-2 facility becomes fully operational shall be included only in those
120-3 tariffs or charges associated with the services actually provided
120-4 by the transmission and distribution utility, if any, to the
120-5 customer after the facility became fully operational and may not
120-6 include any costs associated with the service provided to the
120-7 customer by the electric utility or its affiliated transmission and
120-8 distribution utility under their tariffs before the operation of
120-9 that qualifying facility. To qualify under this subsection, a
120-10 qualifying facility must have made substantially complete filings
120-11 on or before December 31, 1999, for all necessary site-specific
120-12 environmental permits under the rules of the Texas Natural Resource
120-13 Conservation Commission in effect at the time of filing.
120-14 Sec. 39.263. STRANDED COST RECOVERY OF ENVIRONMENTAL CLEANUP
120-15 COSTS. (a) Subject to Subsection (c), capital costs incurred by
120-16 an electric utility to improve air quality before January 1, 2002,
120-17 are eligible for inclusion as net invested capital under Section
120-18 39.259, notwithstanding the limitations imposed under Sections
120-19 39.259(b) and (c).
120-20 (b) Subject to Subsection (c), capital costs incurred by an
120-21 electric utility or an affiliated power generation company to
120-22 improve air quality after January 1, 2002, and before May 1, 2003,
120-23 are eligible for inclusion in the determination of invested capital
120-24 in the true-up proceeding under Section 39.262.
120-25 (c) Reasonable costs incurred under Subsections (a) and (b)
120-26 shall be included as invested capital and considered in an electric
121-1 utility's stranded cost determination only to the extent that:
121-2 (1) the cost is applied to offset or reduce the
121-3 emission of airborne contaminants from an electric generating
121-4 facility, where:
121-5 (A) the reduction or offset is determined by the
121-6 Texas Natural Resource Conservation Commission to be an essential
121-7 component in achieving compliance with a national ambient air
121-8 quality standard; or
121-9 (B) the reduction or offset is necessary in
121-10 order for an unpermitted electric generating facility to obtain a
121-11 permit in the manner provided by Section 39.264;
121-12 (2) the retrofit decision is determined to be the most
121-13 cost-effective after consideration of alternative measures,
121-14 including the retirement of the generating facility; and
121-15 (3) the amount and location of resulting emission
121-16 reductions is consistent with the air quality goals and policies of
121-17 the Texas Natural Resource Conservation Commission.
121-18 (d) If the retirement of a generating facility is the most
121-19 cost-effective alternative, taking into account the cost of
121-20 replacement generating capacity, the net book value, including
121-21 retirement costs and offsetting salvage value, of the affected
121-22 facility shall be included in the electric utility's stranded cost
121-23 determination, notwithstanding Section 39.259(c).
121-24 Sec. 39.264. EMISSIONS REDUCTIONS OF "GRANDFATHERED
121-25 FACILITIES." (a) In this section:
121-26 (1) "Conservation commission" means the Texas Natural
122-1 Resource Conservation Commission.
122-2 (2) "Electric generating facility" means a facility
122-3 that generates electric energy for compensation and is owned or
122-4 operated by a person in this state, including a municipal
122-5 corporation, electric cooperative, or river authority.
122-6 (b) This section applies only to an electric generating
122-7 facility existing on January 1, 1999, that is not subject to the
122-8 requirement to obtain a permit under Section 382.0518(g), Health
122-9 and Safety Code.
122-10 (c) It is the intent of the legislature that, for the
122-11 12-month period beginning on May 1, 2003, and for each 12-month
122-12 period after the end of that period, total annual emissions of
122-13 nitrogen oxides from facilities subject to this section may not
122-14 exceed levels equal to 50 percent of the total emissions of that
122-15 pollutant during 1997, as reported to the conservation commission,
122-16 and total annual emissions of sulphur dioxides from coal-fired
122-17 facilities subject to this section may not exceed levels equal to
122-18 75 percent of the total emissions of that pollutant during 1997, as
122-19 reported to the conservation commission. The limitations
122-20 prescribed by this subsection may be met through an emissions
122-21 allocation and allowance transfer system described by this section.
122-22 (d) A municipal corporation, electric cooperative, or river
122-23 authority may exclude any electric generating facilities of 25
122-24 megawatts or less from the requirements prescribed by this section.
122-25 Not later than January 1, 2000, a municipal corporation, electric
122-26 cooperative, or river authority must inform the conservation
123-1 commission of its intent to exclude those facilities.
123-2 (e) The owner or operator of an electric generating facility
123-3 shall apply to the conservation commission for a permit for the
123-4 emission of air contaminants on or before September 1, 2000. A
123-5 permit issued by the conservation commission under this section
123-6 shall require the facility to achieve emissions reductions or
123-7 trading emissions allowances as provided by this section. If the
123-8 facility uses coal as a fuel, the permit must also be conditioned
123-9 on the facility's emissions meeting opacity limitations provided by
123-10 conservation commission rules. Notwithstanding Section
123-11 382.0518(g), Health and Safety Code, a facility that does not
123-12 obtain a permit as required by this subsection may not operate
123-13 after May 1, 2003, unless the conservation commission finds good
123-14 cause for an extension.
123-15 (f) The conservation commission shall develop rules for the
123-16 permitting of electric generating facilities. The rules adopted
123-17 under this subsection shall provide, by region, for the allocation
123-18 of emissions allowances of sulphur dioxides and nitrogen oxides
123-19 among electric generating facilities and for facilities to trade
123-20 emissions allowances for those contaminants.
123-21 (g) The conservation commission by rule shall establish an
123-22 East Texas Region, a West Texas Region, and an El Paso Region for
123-23 allocation of air contaminants under the permitting program under
123-24 Subsection (f). The East Texas Region must contain all counties
123-25 traversed by or east of Interstate Highway 35 or Interstate Highway
123-26 37, including Bosque, Coryell, Hood, Parker, Somervell, and Wise
124-1 counties. The West Texas Region includes all of the state not
124-2 contained in the East Texas Region or the El Paso Region. The El
124-3 Paso Region includes El Paso County.
124-4 (h) Not later than January 1, 2000, the conservation
124-5 commission shall allocate to each electric generating facility in
124-6 each region a number of annual emissions allowances, with each
124-7 allowance equal to one ton of sulphur dioxides or of nitrogen
124-8 oxides emitted in a year, that permit emissions of the contaminants
124-9 from the facility in that year. The conservation commission must
124-10 allocate to each facility a number of emissions allowances equal to
124-11 an emissions rate measured in pounds per million British thermal
124-12 units divided by 2,000 and multiplied by the facility's total heat
124-13 input in terms of million British thermal units during 1997. For
124-14 the East Texas Region, the emissions rate shall be 0.14 pounds per
124-15 million British thermal units for nitrogen oxides and 1.38 pounds
124-16 per million British thermal units for sulphur dioxides. For the
124-17 West Texas and El Paso regions, the emissions rate shall be 0.195
124-18 pounds per million British thermal units for nitrogen oxides.
124-19 Allowances for sulphur dioxides may only be allocated among
124-20 coal-fired facilities.
124-21 (i) A person, municipal corporation, electric cooperative,
124-22 or river authority that owns and operates an electric generating
124-23 facility not covered by this section may elect to designate that
124-24 facility to become subject to the requirements of this section and
124-25 to receive emissions allowances for the purpose of complying with
124-26 the emissions limitations prescribed by Subsection (c). The
125-1 conservation commission shall adopt rules governing this election
125-2 that:
125-3 (1) require an owner or operator of an electric
125-4 generating facility to designate to the conservation commission in
125-5 its permit application under Subsection (e) any facilities that
125-6 will become subject to this section;
125-7 (2) require the conservation commission,
125-8 notwithstanding the allocation mechanism provided by Subsection
125-9 (h), to allocate additional allowances to facilities governed by
125-10 this subsection in an amount equal to each facility's actual
125-11 emissions in tons in 1997;
125-12 (3) provide that any unit designated under this
125-13 subsection may not transfer or bank allowances conserved as a
125-14 result of reduced utilization or shutdown, except that the
125-15 allowances may be transferred or carried forward for use in
125-16 subsequent years to the extent that the reduced utilization or
125-17 shutdown results from the replacement of thermal energy from the
125-18 unit designated under this subsection with thermal energy generated
125-19 by any other unit; and
125-20 (4) provide that emissions reductions from electing
125-21 facilities designated in this subsection may only be used to
125-22 satisfy the emissions reductions for grandfathered facilities
125-23 defined in Subsection (c) to the extent that reductions used to
125-24 satisfy the limitations in Subsection (c) are beyond the
125-25 requirements of any other state or federal standard, or both.
125-26 (j) The conservation commission by rule shall permit a
126-1 facility to trade emissions allocations with other electric
126-2 generating facilities only in the same region.
126-3 (k) The conservation commission by rule shall provide
126-4 methods for the conservation commission to determine whether a
126-5 facility complies with the permit issued under this section. The
126-6 rules must provide for:
126-7 (1) monitoring and reporting actual emissions of
126-8 sulphur dioxides and nitrogen oxides from each facility;
126-9 (2) provisions for saving unused allowances for use in
126-10 later years; and
126-11 (3) a system for tracking traded allowances.
126-12 (l) A facility may not trade an unused allowance for a
126-13 contaminant for use as a credit for another contaminant.
126-14 (m) A person possessing market power shall not withhold
126-15 emissions allowances from the market in a manner that is
126-16 unreasonably discriminatory or tends to unreasonably restrict,
126-17 impair, or reduce the level of competition.
126-18 (n) The conservation commission shall penalize a facility
126-19 that emits an air contaminant that exceeds the facility's
126-20 allowances for that contaminant by:
126-21 (1) enforcing an administrative penalty, in an amount
126-22 determined by conservation commission rules, for each ton of air
126-23 contaminant emissions by which the facility exceeds its allocated
126-24 emissions allowances; and
126-25 (2) reducing the facility's emissions allowances for
126-26 the next year by an amount of emissions equal to the excessive
127-1 emissions in the year the facility emitted the excessive air
127-2 contaminants.
127-3 (o) The conservation commission may penalize a facility that
127-4 emits an air contaminant that exceeds the facility's allowances
127-5 for that contaminant by:
127-6 (1) ordering the facility to cease operations; or
127-7 (2) taking other enforcement action provided by
127-8 conservation commission rules.
127-9 (p) The conservation commission by rule shall provide for a
127-10 facility in the El Paso Region to meet emissions allowances by
127-11 using credits from emissions reductions achieved in Ciudad Juarez,
127-12 United Mexican States.
127-13 (q) If the conservation commission or the United States
127-14 Environmental Protection Agency determines that reductions in
127-15 nitrogen oxides emissions in the El Paso Region otherwise required
127-16 by this section would result in increased ambient ozone levels in
127-17 El Paso County, facilities in the El Paso Region are exempt from
127-18 the nitrogen oxides reduction requirements.
127-19 (r) An applicant for a permit under Subsection (e) shall
127-20 publish notice of intent to obtain the permit in accordance with
127-21 Section 382.056, Health and Safety Code. The conservation
127-22 commission shall provide an opportunity for a public hearing and
127-23 the submission of public comment and send notice of a decision on
127-24 an application for a permit under Subsection (e) in the same manner
127-25 as provided by Sections 382.0561 and 382.0562, Health and Safety
127-26 Code. The conservation commission shall review and renew a permit
128-1 issued under this section in accordance with Section 382.055,
128-2 Health and Safety Code.
128-3 (s) This section does not limit the authority of the
128-4 conservation commission to require further reductions of nitrogen
128-5 oxides, sulphur dioxides, or any other pollutant from generating
128-6 facilities subject to this section or Section 39.263.
128-7 Sec. 39.265. RIGHTS NOT AFFECTED. This chapter is not
128-8 intended to alter any rights of utilities to recover stranded costs
128-9 from wholesale customers.
128-10 (Sections 39.266-39.300 reserved for expansion
128-11 SUBCHAPTER G. SECURITIZATION
128-12 Sec. 39.301. PURPOSE. The purpose of this subchapter is to
128-13 enable utilities to use securitization financing to recover
128-14 regulatory assets and stranded costs, because this type of debt
128-15 will lower the carrying costs of the assets relative to the costs
128-16 that would be incurred using conventional utility financing
128-17 methods. The proceeds of the transition bonds shall be used solely
128-18 for the purposes of reducing the amount of recoverable regulatory
128-19 assets and stranded costs, as determined by the commission in
128-20 accordance with this chapter, through the refinancing or retirement
128-21 of utility debt or equity. The commission shall ensure that
128-22 securitization provides tangible and quantifiable benefits to
128-23 ratepayers, greater than would have been achieved absent the
128-24 issuance of transition bonds. The commission shall ensure that the
128-25 structuring and pricing of the transition bonds result in the
128-26 lowest transition bond charges consistent with market conditions
129-1 and the terms of the financing order. The amount securitized may
129-2 not exceed the present value of the revenue requirement over the
129-3 life of the proposed transition bond associated with the regulatory
129-4 assets or stranded costs sought to be securitized. The present
129-5 value calculation shall use a discount rate equal to the proposed
129-6 interest rate on the transition bonds.
129-7 Sec. 39.302. DEFINITIONS. In this subchapter:
129-8 (1) "Assignee" means any individual, corporation, or
129-9 other legally recognized entity to which an interest in transition
129-10 property is transferred, other than as security, including any
129-11 assignee of that party.
129-12 (2) "Financing order" means an order of the commission
129-13 adopted under Section 39.201 or 39.262 approving the issuance of
129-14 transition bonds and the creation of transition charges for the
129-15 recovery of qualified costs.
129-16 (3) "Financing party" means a holder of transition
129-17 bonds, including trustees, collateral agents, and other persons
129-18 acting for the benefit of the holder.
129-19 (4) "Qualified costs" means 100 percent of an electric
129-20 utility's regulatory assets and 75 percent of its recoverable costs
129-21 determined by the commission under Section 39.201 and any remaining
129-22 stranded costs determined under Section 39.262 together with the
129-23 costs of issuing, supporting, and servicing transition bonds and
129-24 any costs of retiring and refunding the electric utility's existing
129-25 debt and equity securities in connection with the issuance of
129-26 transition bonds. The term includes the costs to the commission of
130-1 acquiring professional services for the purpose of evaluating
130-2 proposed transactions under Section 39.201 and this subchapter.
130-3 (5) "Regulatory assets" means the generation-related
130-4 portion of the Texas jurisdictional portion of the amount reported
130-5 by the electric utility in its 1998 annual report on Securities and
130-6 Exchange Commission Form 10-K as regulatory assets and liabilities,
130-7 offset by the applicable portion of generation-related investment
130-8 tax credits permitted under the Internal Revenue Code of 1986.
130-9 (6) "Transition bonds" means bonds, debentures, notes,
130-10 certificates of participation or of beneficial interest, or other
130-11 evidences of indebtedness or ownership that are issued by an
130-12 electric utility, its successors, or an assignee under a financing
130-13 order, that have a term not longer than 15 years, and that are
130-14 secured by or payable from transition property. If certificates of
130-15 participation, beneficial interest, or ownership are issued,
130-16 references in this subchapter to principal, interest, or premium
130-17 shall refer to comparable amounts under those certificates.
130-18 (7) "Transition charges" means nonbypassable amounts
130-19 to be charged for the use or availability of electric services,
130-20 approved by the commission under a financing order to recover
130-21 qualified costs, that shall be collected by an electric utility,
130-22 its successors, an assignee, or other collection agents as provided
130-23 for in the financing order.
130-24 (8) "Transition property" means the property described
130-25 in Section 39.304.
130-26 Sec. 39.303. FINANCING ORDERS; TERMS. (a) The commission
131-1 shall adopt a financing order, on application of a utility to
131-2 recover the utility's regulatory assets and eligible stranded costs
131-3 under Section 39.201 or 39.262, on making a finding that the total
131-4 amount of revenues to be collected under the financing order is
131-5 less than the revenue requirement that would be recovered over the
131-6 remaining life of the stranded costs using conventional financing
131-7 methods and that the financing order is consistent with the
131-8 standards in Section 39.301.
131-9 (b) The financing order shall detail the amount of
131-10 regulatory assets and stranded costs to be recovered and the period
131-11 over which the nonbypassable transition charges shall be recovered,
131-12 which period may not exceed 15 years.
131-13 (c) Transition charges shall be collected and allocated
131-14 among customers in the same manner as competition transition
131-15 charges under Section 39.201.
131-16 (d) A financing order shall become effective in accordance
131-17 with its terms, and the financing order, together with the
131-18 transition charges authorized in the order, shall thereafter be
131-19 irrevocable and not subject to reduction, impairment, or adjustment
131-20 by further action of the commission, except as permitted by Section
131-21 39.307.
131-22 (e) The commission shall issue a financing order under
131-23 Subsections (a) and (g) not later than 90 days after the utility
131-24 files its request for the financing order.
131-25 (f) A financing order is not subject to rehearing by the
131-26 commission. A financing order may be reviewed by appeal only to a
132-1 Travis County district court by a party to the proceeding filed
132-2 within 15 days after the financing order is signed by the
132-3 commission. The judgment of the district court may be reviewed
132-4 only by direct appeal to the Supreme Court of Texas filed within 15
132-5 days after entry of judgment. All appeals shall be heard and
132-6 determined by the district court and the Supreme Court of Texas as
132-7 expeditiously as possible with lawful precedence over other
132-8 matters. Review on appeal shall be based solely on the record
132-9 before the commission and briefs to the court and shall be limited
132-10 to whether the financing order conforms to the constitution and
132-11 laws of this state and the United States and is within the
132-12 authority of the commission under this chapter.
132-13 (g) At the request of an electric utility, the commission
132-14 may adopt a financing order providing for retiring and refunding
132-15 transition bonds on making a finding that the future transition
132-16 charges required to service the new transition bonds, including
132-17 transaction costs, will be less than the future transition charges
132-18 required to service the transition bonds being refunded. On the
132-19 retirement of the refunded transition bonds, the commission shall
132-20 adjust the related transition charges accordingly.
132-21 Sec. 39.304. PROPERTY RIGHTS. (a) The rights and interests
132-22 of an electric utility or successor under a financing order,
132-23 including the right to impose, collect, and receive transition
132-24 charges authorized in the order, shall be only contract rights
132-25 until they are first transferred to an assignee or pledged in
132-26 connection with the issuance of transition bonds, at which time
133-1 they will become "transition property."
133-2 (b) Transition property shall constitute a present property
133-3 right for purposes of contracts concerning the sale or pledge of
133-4 property, even though the imposition and collection of transition
133-5 charges depends on further acts of the utility or others that have
133-6 not yet occurred. The financing order shall remain in effect and
133-7 the property shall continue to exist for the same period as the
133-8 pledge of the state described in Section 39.310.
133-9 (c) All revenues and collections resulting from transition
133-10 charges shall constitute proceeds only of the transition property
133-11 arising from the financing order.
133-12 Sec. 39.305. NO SETOFF. The interest of an assignee or
133-13 pledgee in transition property and in the revenues and collections
133-14 arising from that property are not subject to setoff, counterclaim,
133-15 surcharge, or defense by the electric utility or any other person
133-16 or in connection with the bankruptcy of the electric utility or any
133-17 other entity. A financing order shall remain in effect and
133-18 unabated notwithstanding the bankruptcy of the electric utility,
133-19 its successors, or assignees.
133-20 Sec. 39.306. NO BYPASS. A financing order shall include
133-21 terms ensuring that the imposition and collection of transition
133-22 charges authorized in the order shall be nonbypassable.
133-23 Sec. 39.307. TRUE-UP. A financing order shall include a
133-24 mechanism requiring that transition charges be reviewed and
133-25 adjusted at least annually, within 45 days of the anniversary date
133-26 of the issuance of the transition bonds, to correct any
134-1 overcollections or undercollections of the preceding 12 months and
134-2 to ensure the expected recovery of amounts sufficient to timely
134-3 provide all payments of debt service and other required amounts and
134-4 charges in connection with the transition bonds.
134-5 Sec. 39.308. TRUE SALE. An agreement by an electric utility
134-6 or assignee to transfer transition property that expressly states
134-7 that the transfer is a sale or other absolute transfer signifies
134-8 that the transaction is a true sale and is not a secured
134-9 transaction and that title, legal and equitable, has passed to the
134-10 entity to which the transition property is transferred. This true
134-11 sale shall apply regardless of whether the purchaser has any
134-12 recourse against the seller, or any other term of the parties'
134-13 agreement, including the seller's retention of an equity interest
134-14 in the transition property, the fact that the electric utility acts
134-15 as the collector of transition charges relating to the transition
134-16 property, or the treatment of the transfer as a financing for tax,
134-17 financial reporting, or other purposes.
134-18 Sec. 39.309. SECURITY INTERESTS; ASSIGNMENT; COMMINGLING;
134-19 DEFAULT. (a) Transition property does not constitute an account
134-20 or general intangible under Section 9.106, Business & Commerce
134-21 Code. The creation, granting, perfection, and enforcement of liens
134-22 and security interests in transition property are governed by this
134-23 section and not by the Business & Commerce Code.
134-24 (b) A valid and enforceable lien and security interest in
134-25 transition property may be created only by a financing order and
134-26 the execution and delivery of a security agreement with a financing
135-1 party in connection with the issuance of transition bonds. The
135-2 lien and security interest shall attach automatically from the time
135-3 that value is received for the bonds and, on perfection through the
135-4 filing of notice with the secretary of state in accordance with the
135-5 rules prescribed under Subsection (d), shall be a continuously
135-6 perfected lien and security interest in the transition property and
135-7 all proceeds of the property, whether accrued or not, shall have
135-8 priority in the order of filing and take precedence over any
135-9 subsequent judicial or other lien creditor. If notice is filed
135-10 within 10 days after value is received for the transition bonds,
135-11 the security interest shall be perfected retroactive to the date
135-12 value was received, otherwise, the security interest shall be
135-13 perfected as of the date of filing.
135-14 (c) Transfer of an interest in transition property to an
135-15 assignee shall be perfected against all third parties, including
135-16 subsequent judicial or other lien creditors, when the financing
135-17 order becomes effective, transfer documents have been delivered to
135-18 the assignee, and a notice of that transfer has been filed in
135-19 accordance with the rules prescribed under Subsection (d);
135-20 provided, however, that if notice of the transfer has not been
135-21 filed in accordance with this subsection within 10 days after the
135-22 delivery of transfer documentation, the transfer of the interest is
135-23 not perfected against third parties until the notice is filed.
135-24 (d) The secretary of state shall implement this section by
135-25 establishing and maintaining a separate system of records for the
135-26 filing of notices under this section and prescribing the rules for
136-1 those filings based on Chapter 9, Business & Commerce Code, adapted
136-2 to this subchapter and using the terms defined in this subchapter.
136-3 (e) The priority of a lien and security interest perfected
136-4 under this section is not impaired by any later modification of the
136-5 financing order under Section 39.307 or by the commingling of funds
136-6 arising from transition charges with other funds, and any other
136-7 security interest that may apply to those funds shall be terminated
136-8 when they are transferred to a segregated account for the assignee
136-9 or a financing party. If transition property has been transferred
136-10 to an assignee, any proceeds of that property shall be held in
136-11 trust for the assignee.
136-12 (f) If a default or termination occurs under the transition
136-13 bonds, the financing parties or their representatives may foreclose
136-14 on or otherwise enforce their lien and security interest in any
136-15 transition property as if they were secured parties under Chapter
136-16 9, Business & Commerce Code, and the commission may order that
136-17 amounts arising from transition charges be transferred to a
136-18 separate account for the financing parties' benefit, to which their
136-19 lien and security interest shall apply. On application by or on
136-20 behalf of the financing parties, a district court of Travis County
136-21 shall order the sequestration and payment to them of revenues
136-22 arising from the transition charges.
136-23 Sec. 39.310. PLEDGE OF STATE. Transition bonds are not a
136-24 debt or obligation of the state and are not a charge on its full
136-25 faith and credit or taxing power. The state pledges, however, for
136-26 the benefit and protection of financing parties and the electric
137-1 utility, that it will not take or permit any action that would
137-2 impair the value of transition property, or, except as permitted by
137-3 Section 39.307, reduce, alter, or impair the transition charges to
137-4 be imposed, collected, and remitted to financing parties, until the
137-5 principal, interest and premium, and any other charges incurred and
137-6 contracts to be performed in connection with the related transition
137-7 bonds have been paid and performed in full. Any party issuing
137-8 transition bonds is authorized to include this pledge in any
137-9 documentation relating to those bonds.
137-10 Sec. 39.311. TAX EXEMPTION. Transactions involving the
137-11 transfer and ownership of transition property and the receipt of
137-12 transition charges are exempt from state and local income, sales,
137-13 franchise, gross receipts, and other taxes or similar charges.
137-14 Sec. 39.312. NOT PUBLIC UTILITY. An assignee or financing
137-15 party may not be considered to be a public utility or person
137-16 providing electric service solely by virtue of the transactions
137-17 described in this subchapter.
137-18 Sec. 39.313. SEVERABILITY. Effective on the date the first
137-19 utility transition bonds are issued under this subchapter, if any
137-20 provision in this title or portion of this title is held to be
137-21 invalid or is invalidated, superseded, replaced, repealed, or
137-22 expires for any reason, that occurrence does not affect the
137-23 validity or continuation of this subchapter, Section 39.201,
137-24 39.251, 39.252, or 39.262, or any part of those provisions, or any
137-25 other provision of this title that is relevant to the issuance,
137-26 administration, payment, retirement, or refunding of transition
138-1 bonds or to any actions of the electric utility, its successors, an
138-2 assignee, a collection agent, or a financing party, which shall
138-3 remain in full force and effect.
138-4 (Sections 39.314-39.350 reserved for expansion
138-5 SUBCHAPTER H. CERTIFICATION AND REGISTRATION; PENALTIES
138-6 Sec. 39.351. REGISTRATION OF POWER GENERATION COMPANIES.
138-7 (a) A person may not generate electricity unless the person is
138-8 registered with the commission as a power generation company in
138-9 accordance with this section. A person may register as a power
138-10 generation company by filing the following information with the
138-11 commission:
138-12 (1) a description of the location of any facility used
138-13 to generate electricity;
138-14 (2) a description of the type of services provided;
138-15 (3) a copy of any information filed with the Federal
138-16 Energy Regulatory Commission in connection with registration with
138-17 that commission; and
138-18 (4) any other information required by commission rule,
138-19 provided that in requiring that information the commission shall
138-20 protect the competitive process in a manner that ensures the
138-21 confidentiality of competitively sensitive information.
138-22 (b) A power generation company shall comply with the
138-23 reliability standards adopted by an independent organization
138-24 certified by the commission to ensure the reliability of the
138-25 regional electrical network for a power region in which the power
138-26 generation company is generating or selling electricity.
139-1 (c) A power generation company may register any time after
139-2 September 1, 2000.
139-3 Sec. 39.352. CERTIFICATION OF RETAIL ELECTRIC PROVIDERS.
139-4 (a) After the date of customer choice, a person, including an
139-5 affiliate of an electric utility, may not provide retail electric
139-6 service in this state unless the person is certified by the
139-7 commission as a retail electric provider, in accordance with this
139-8 section.
139-9 (b) The commission shall issue a certificate to provide
139-10 retail electric service to a person applying for certification who
139-11 demonstrates:
139-12 (1) the financial and technical resources to provide
139-13 continuous and reliable electric service to customers in the area
139-14 for which the certification is sought;
139-15 (2) the managerial and technical ability to supply
139-16 electricity at retail in accordance with customer contracts;
139-17 (3) the resources needed to meet the customer
139-18 protection requirements of this title; and
139-19 (4) ownership or lease of an office located within
139-20 this state for the purpose of providing customer service, accepting
139-21 service of process, and making available in that office books and
139-22 records sufficient to establish the retail electric provider's
139-23 compliance with the requirements of this subchapter.
139-24 (c) A person applying for certification under this section
139-25 shall comply with all applicable customer protection provisions,
139-26 disclosure requirements, and marketing guidelines established by
140-1 the commission and by this title.
140-2 (d) Notwithstanding Subsections (b)(1)-(3), if a retail
140-3 electric provider files with the commission a signed, notarized
140-4 affidavit from each retail customer with which it has contracted to
140-5 provide one megawatt or more of capacity stating that the customer
140-6 is satisfied that the retail electric provider meets the standards
140-7 prescribed by Subsections (b)(1)-(3) and Subsection (c), the retail
140-8 electric provider shall be certified for purposes of serving those
140-9 customers only, so long as it demonstrates that it meets the
140-10 requirements of Subsection (b)(4).
140-11 (e) A retail electric provider may apply for certification
140-12 any time after September 1, 2000.
140-13 (f) The commission shall use any information required in
140-14 this section in a manner that ensures the confidentiality of
140-15 competitively sensitive information.
140-16 (g) If a retail electric provider serves an aggregate load
140-17 in excess of 300 megawatts within this state, not less than five
140-18 percent of the load in megawatt hours must consist of residential
140-19 customers. This requirement applies to an affiliated retail
140-20 electric provider only with respect to load served outside of the
140-21 electric utility's service area, and, in relation to that load, the
140-22 affiliated retail electric provider shall meet the requirements of
140-23 this subsection by serving residential customers outside of the
140-24 electric utility's service area. For the purpose of this
140-25 subsection, the load served by retail electric providers that are
140-26 under common ownership shall be combined. A retail electric
141-1 provider may meet the requirements of this subsection by
141-2 demonstrating on an annual basis that it serves residential load
141-3 amounting to five percent of its total load, by demonstrating that
141-4 another retail electric provider serves sufficient qualifying
141-5 residential load on its behalf, or by paying an amount into the
141-6 system benefit fund equal to $1 multiplied by a number equal to the
141-7 difference between the number of megawatt hours it sold to
141-8 residential customers and the number of megawatt hours it was
141-9 required to sell to such customers, or in the case of an affiliated
141-10 retail electric provider, $1 multiplied by a number equal to the
141-11 difference between the number of megawatt hours sold to residential
141-12 customers outside of the electric utility's service area and the
141-13 number of megawatt hours it was required to sell to such customers
141-14 outside of the electric utility's service area. Qualifying
141-15 residential load may not include customers served by an affiliated
141-16 retail electric provider in its own service area. Each retail
141-17 electric provider shall file reports with the commission that are
141-18 necessary to implement this subsection. This subsection applies
141-19 for 36 months after retail competition begins. The commission
141-20 shall adopt rules to implement this subsection.
141-21 Sec. 39.353. REGISTRATION OF AGGREGATORS. (a) A person may
141-22 not provide aggregation services in the state unless the person is
141-23 registered with the commission as an aggregator.
141-24 (b) In this subchapter, "aggregator" means a person joining
141-25 two or more customers, other than municipalities and political
141-26 subdivision corporations, into a single purchasing unit to
142-1 negotiate the purchase of electricity from retail electric
142-2 providers. Aggregators may not sell or take title to electricity.
142-3 Retail electric providers are not aggregators.
142-4 (c) A person registering under this section shall comply
142-5 with all customer protection provisions, all disclosure
142-6 requirements, and all marketing guidelines established by the
142-7 commission and by this title.
142-8 (d) The commission shall establish terms and conditions it
142-9 determines necessary to regulate the reliability and integrity of
142-10 aggregators in the state by June 1, 2000.
142-11 (e) An aggregator may register any time after September 1,
142-12 2000.
142-13 (f) The commission shall have up to 60 days to process
142-14 applications for registration filed by aggregators.
142-15 (g) Registration is not required of a customer that is
142-16 aggregating loads from its own location or facilities.
142-17 (h) The commission shall work with the Texas Department of
142-18 Economic Development to communicate information about opportunities
142-19 for operation as aggregators to potential new aggregators,
142-20 including small and historically underutilized businesses.
142-21 Sec. 39.354. REGISTRATION OF MUNICIPAL AGGREGATORS. (a) A
142-22 municipal aggregator may not provide aggregation services in the
142-23 state unless the municipal aggregator registers with the
142-24 commission.
142-25 (b) In this section, "municipal aggregator" means a person
142-26 authorized by two or more municipal governing bodies to join the
143-1 bodies into a single purchasing unit to negotiate the purchase of
143-2 electricity from retail electric providers or aggregation by a
143-3 municipality under Chapter 303, Local Government Code.
143-4 (c) A municipal aggregator may register any time after
143-5 September 1, 2000.
143-6 Sec. 39.3545. REGISTRATION OF POLITICAL SUBDIVISION
143-7 AGGREGATORS. (a) A political subdivision aggregator may not
143-8 provide aggregation services in the state unless the political
143-9 subdivision aggregator registers with the commission.
143-10 (b) In this section, "political subdivision aggregator"
143-11 means a person or political subdivision corporation authorized by
143-12 two or more political subdivision governing bodies to join the
143-13 bodies into a single purchasing unit or multiple purchasing units
143-14 to negotiate the purchase of electricity from retail electric
143-15 providers for the facilities of the aggregated political
143-16 subdivisions or aggregation by a person or political subdivision
143-17 under Chapter 303, Local Government Code.
143-18 (c) A political subdivision aggregator may register any time
143-19 after September 1, 2000.
143-20 Sec. 39.355. REGISTRATION OF POWER MARKETERS. A person may
143-21 not sell electric energy at wholesale as a power marketer unless
143-22 the person registers with the commission pursuant to Section
143-23 35.032.
143-24 Sec. 39.356. REVOCATION OF CERTIFICATION. (a) The
143-25 commission may suspend, revoke, or amend a retail electric
143-26 provider's certificate for significant violations of this title or
144-1 the rules adopted under this title or of any reliability standard
144-2 adopted by an independent organization certified by the commission
144-3 to ensure the reliability of a power region's electrical network,
144-4 including the failure to observe any scheduling, operating,
144-5 planning, reliability, or settlement protocols established by the
144-6 independent organization. The commission may also suspend or
144-7 revoke a retail electric provider's certificate if the provider no
144-8 longer has the financial or technical capability to provide
144-9 continuous and reliable electric service.
144-10 (b) The commission may suspend or revoke a power generation
144-11 company's registration for significant violations of this title or
144-12 the rules adopted under this title or of the reliability standards
144-13 adopted by an independent organization certified by the commission
144-14 to ensure the reliability of a power region's electrical network,
144-15 including the failure to observe any scheduling, operating,
144-16 planning, reliability, or settlement protocols established by the
144-17 independent organization.
144-18 (c) The commission may suspend or revoke an aggregator's
144-19 registration for significant violations of this title or of the
144-20 rules adopted under this title.
144-21 Sec. 39.357. ADMINISTRATIVE PENALTY. In addition to the
144-22 suspension, revocation, or amendment of a certification, the
144-23 commission may impose an administrative penalty, as provided by
144-24 Section 15.023, for violations described by Section 39.356.
144-25 Sec. 39.358. LOCAL REGISTRATION OF RETAIL ELECTRIC PROVIDER.
144-26 (a) A municipality may require a retail electric provider to
145-1 register with the municipality as a condition of serving residents
145-2 of the municipality. The municipality may assess a reasonable
145-3 administrative fee for this purpose.
145-4 (b) The municipality may suspend or revoke a retail electric
145-5 provider's registration and operation in that municipality for
145-6 significant violations of this chapter or the rules adopted under
145-7 this chapter.
145-8 (Sections 39.359-39.400 reserved for expansion
145-9 SUBCHAPTER I. PROVISIONS FOR CERTAIN NON-ERCOT UTILITIES
145-10 Sec. 39.401. APPLICABILITY. This subchapter shall apply to
145-11 investor-owned electric utilities operating solely outside of ERCOT
145-12 having fewer than six synchronous interconnections with voltage
145-13 levels above 69 kilovolts systemwide on the effective date of this
145-14 subchapter. This subchapter recognizes that circumstances exist
145-15 that require that areas served by such utilities be treated as
145-16 competitive development areas in which full retail customer choice
145-17 may develop on a more structured schedule than is anticipated for
145-18 the rest of the state. If there are any conflicts between this
145-19 subchapter and any other provisions of this chapter, the provisions
145-20 of this subchapter shall control, but shall not be deemed to limit
145-21 or in any way restrict any provision of this title that governs
145-22 customer protection or quality or reliability of service.
145-23 Sec. 39.402. TRANSITION TO COMPETITION PLAN. All electric
145-24 utilities subject to this subchapter shall file a transition to
145-25 competition plan with the commission not later than December 1,
145-26 2000. This transition to competition plan shall identify how
146-1 utilities subject to this subchapter shall achieve full customer
146-2 choice, including specific alternatives for constructing additional
146-3 transmission facilities, auctioning rights to generation capacity,
146-4 divesting generation capacity, or any other measure necessary for
146-5 the electric utility to meet the requirements of Section 39.152(a)
146-6 and that is consistent with the public interest. The commission
146-7 shall approve, modify, or reject a plan within 180 days after the
146-8 date of a filing under this section. The transition to competition
146-9 plan may be updated or amended as circumstances change, subject to
146-10 commission approval.
146-11 Sec. 39.403. UNBUNDLING. Electric utilities subject to this
146-12 subchapter shall unbundle as required by Section 39.051.
146-13 Sec. 39.404. RATE FREEZE. Electric utilities subject to
146-14 this subchapter shall freeze their rates until January 1, 2002, as
146-15 required by Section 39.052. The price to beat established pursuant
146-16 to Section 39.406 shall become effective January 1, 2002. For
146-17 customer classes other than residential and small commercial
146-18 customers, an electric utility subject to this subchapter may not
146-19 charge rates that are higher than the rates that, on a bundled
146-20 basis, were in effect January 1, 1999, until the region qualifies
146-21 for competition or until rates are reset pursuant to Section
146-22 39.405(c).
146-23 Sec. 39.405. PILOT PROJECT. (a) Electric utilities subject
146-24 to this subchapter shall undertake a pilot project as set forth in
146-25 Section 39.104. As part of approving an electric utility's
146-26 transition to competition plan pursuant to Section 39.402, the
147-1 commission shall extend the duration of the pilot project beyond
147-2 January 1, 2002, and expand the percentage of participation in the
147-3 pilot project beyond the five percent level prescribed by Section
147-4 39.104 based on the market conditions in the region and consistent
147-5 with the level of competition that the region can support. The
147-6 commission shall review the pilot project as circumstances change
147-7 and may adjust the percentage level of participation consistent
147-8 with this subsection.
147-9 (b) An electric utility subject to this subchapter shall
147-10 design any customer choice pilot project it undertakes pursuant to
147-11 Section 39.104 in such a manner that there is a proportional
147-12 participation between customers receiving service from the utility
147-13 located in a service area that is certificated solely to the
147-14 utility and those customers of the utility that are located in a
147-15 multiply certificated area. The utility shall file reports
147-16 pursuant to this section with the commission to permit it to
147-17 monitor whether proportional participation is achieved. Nothing in
147-18 this section requires a utility to design a pilot project to serve
147-19 in multiply certificated areas.
147-20 (c) If any electric utility subject to this subchapter fails
147-21 to meet the requirements of Section 39.152(a), a proceeding under
147-22 Section 36.102 or 36.151 may be filed after January 1, 2006, to set
147-23 its rates effective one year after the date of the filing.
147-24 Sec. 39.406. PRICE TO BEAT. Electric utilities subject to
147-25 this subchapter shall include within their transition to
147-26 competition plans pursuant to Section 39.402 a provision to
148-1 establish the price to beat under Section 39.202. The commission
148-2 may reduce rates by six percent consistent with Section 39.202(a)
148-3 unless it determines that a lesser reduction is necessary and
148-4 consistent with the capital requirements needed to develop the
148-5 infrastructure necessary to facilitate competition among electric
148-6 generators.
148-7 Sec. 39.407. RELEVANT MARKET AND RELATED MATTERS. (a) The
148-8 commission shall certify that the requirements of Section
148-9 39.152(a)(3) are met for electric utilities subject to this
148-10 subchapter only upon a finding that the total capacity owned and
148-11 controlled by each such electric utility and its affiliates does
148-12 not exceed 20 percent of the total installed generation capacity
148-13 within the constrained geographic region served by each such
148-14 electric utility plus the total available transmission capacity
148-15 capable of delivering firm power and energy to that constrained
148-16 geographic region.
148-17 (b) In the area of a power region served by an electric
148-18 utility subject to this subchapter, if customer choice is
148-19 introduced before the requirements of Section 39.152(a) are met, an
148-20 affiliated retail electric provider of an electric utility subject
148-21 to this subchapter may not compete for retail customers in any area
148-22 of the power region that is within this state and outside of the
148-23 affiliated transmission and distribution utility's certificated
148-24 service area unless the affiliated power generation company makes a
148-25 commitment to maintain and does maintain rates that are based on
148-26 cost of service for any electric cooperative or municipally owned
149-1 utility that was a wholesale customer on January 1, 1999, and was
149-2 purchasing power at rates that were based on cost of service. This
149-3 subsection requires a power generation company to sell power at
149-4 rates that are based on cost of service, notwithstanding the
149-5 expiration of a contract for that service, until the requirements
149-6 of Section 39.152(a) are met.
149-7 (c) If the requirements of Section 39.152(a) have not been
149-8 met for an electric utility subject to this subchapter, then any
149-9 power generation company in the power region affiliated with an
149-10 electric utility subject to this subchapter shall maintain adequate
149-11 supply and facilities to provide electric service to persons who
149-12 were or would have been retail customers of the affiliated retail
149-13 electric provider on December 31, 2001. The obligation provided by
149-14 this subsection remains in effect until the commission determines
149-15 that the requirements of Section 39.152(a) have been met for the
149-16 region.
149-17 Sec. 39.408. USE OF REVENUES FOR UTILITIES WITH NO STRANDED
149-18 COSTS. In addition to the permitted uses for any positive
149-19 difference under the report required by Section 39.257(b) set forth
149-20 in Section 39.255, during the freeze period ending December 31,
149-21 2001, electric utilities subject to this subchapter may request,
149-22 subject to approval by the commission, to use such positive
149-23 differences to accelerate the amortization of their regulatory
149-24 assets.
149-25 (Sections 39.409-39.900 reserved for expansion
150-1 SUBCHAPTER Z. MISCELLANEOUS PROVISIONS
150-2 Sec. 39.901. SCHOOL FUNDING LOSS MECHANISM. (a) Not later
150-3 than March 1 each year, the comptroller shall certify to the Texas
150-4 Education Agency any property wealth reductions, determined by
150-5 taking the difference between current year and prior year appraisal
150-6 values attributable to electric utility restructuring.
150-7 (b) The Texas Education Agency shall determine the reduction
150-8 of the amount of property taxes recaptured by the state from school
150-9 districts subject to wealth equalization under Chapter 41,
150-10 Education Code, as a result of the property wealth reductions
150-11 certified under Subsection (a) and shall notify the commission of
150-12 the amount necessary to compensate the state for the reduction.
150-13 (c) The Texas Education Agency shall determine the amount
150-14 necessary to compensate school districts for lost revenue resulting
150-15 from the property wealth reductions under Subsection (a) and shall
150-16 notify the commission of this amount. The amounts necessary to
150-17 compensate districts shall be the sum of:
150-18 (1) decreases in the level of funding to which a
150-19 school district is entitled under Chapters 42 and 46, Education
150-20 Code, that are directly attributable to the decline in property
150-21 values caused by utility restructuring; and
150-22 (2) losses of property tax collections incurred by
150-23 school districts that are directly attributable to property value
150-24 declines caused by utility restructuring and that are not accounted
150-25 for under Subdivision (1), including amounts that a school district
150-26 would be entitled to retain under Chapter 41, Education Code.
151-1 (d) The amounts determined by the comptroller and the Texas
151-2 Education Agency under this section, for the purposes of this
151-3 section, are final and may not be appealed.
151-4 (e) Not later than May 1 of each year, the commission shall
151-5 transfer from the system benefit fund to the foundation school fund
151-6 the amounts determined by the Texas Education Agency under
151-7 Subsections (b) and (c). If in any year the system benefit fund is
151-8 insufficient to make the transfer designated by the Texas Education
151-9 Agency, the shortfall shall be included in the projected revenue
151-10 requirement for the system benefit fund the next time the
151-11 commission sets the fee under Section 39.903, and the shortfall
151-12 amount shall be transferred to the Foundation School Program the
151-13 following year. Amounts transferred from the system benefit fund
151-14 under this section may be appropriated only for the support of the
151-15 Foundation School Program and are available, in addition to any
151-16 amounts allocated by the General Appropriations Act, to finance
151-17 actions under Section 41.002(b) or 42.252(e), Education Code.
151-18 (f) The Texas Education Agency shall, on the transfer of
151-19 funds from the system benefit fund to the foundation school fund,
151-20 compensate school districts for losses incurred under Subsection
151-21 (c).
151-22 (g) The commissioner of education and the comptroller shall
151-23 adopt rules necessary to implement this section, including rules
151-24 providing for public input.
151-25 (h) This section is effective through the 2006-2007 school
151-26 year. This section expires August 31, 2007.
152-1 Sec. 39.9015. INTERIM STUDY ON AFFECTED TAXING UNITS.
152-2 (a) The lieutenant governor and speaker of the house of
152-3 representatives shall appoint an interim committee to conduct an
152-4 interim study and make recommendations regarding the effect of
152-5 electric utility restructuring on the tax revenue of taxing units
152-6 in a county on the coast of the Gulf of Mexico, as defined by
152-7 Section 1.04, Tax Code, other than school districts, that levied an
152-8 ad valorem tax on a nuclear asset of an electric utility on January
152-9 1, 1999.
152-10 (b) Not later than January 1, 2001, the interim committee
152-11 shall file with the lieutenant governor and speaker of the house of
152-12 representatives a report containing an evaluation of:
152-13 (1) the fiscal impact of electric utility
152-14 restructuring on taxing units; and
152-15 (2) recommendations to mitigate any reduction in tax
152-16 revenue to affected taxing units, including allocations from the
152-17 system benefit fund.
152-18 (c) This section expires January 2, 2001.
152-19 Sec. 39.9016. NUCLEAR SAFETY FEE. An electric utility that
152-20 operates a nuclear asset located in a county on the coast of the
152-21 Gulf of Mexico shall pay a nuclear safety fee for the year 2000 and
152-22 the year 2001 to each taxing unit in which the nuclear asset is
152-23 located, other than a school district, in an amount equal to the
152-24 difference between the ad valorem taxes imposed by the taxing unit
152-25 in 1999 and the amount of ad valorem taxes imposed by the unit in
152-26 the year for which the fee is due, except that the amount of the
153-1 fee may not exceed one-half the taxes imposed on the asset by the
153-2 unit in 1999. The nuclear safety fee shall be considered a tax or
153-3 fee under Section 39.258(5).
153-4 Sec. 39.902. CUSTOMER EDUCATION. (a) On or before January
153-5 1, 2001, the commission shall develop and implement an educational
153-6 program to inform customers, including low-income and
153-7 non-English-speaking customers, about changes in the provision of
153-8 electric service resulting from the opening of the retail electric
153-9 market and the customer choice pilot program under this chapter.
153-10 The educational program shall be neutral and nonpromotional and
153-11 shall provide customers with the information necessary to make
153-12 informed decisions relating to the source and type of electric
153-13 service available for purchase and other information the commission
153-14 considers necessary. The educational program shall inform
153-15 customers of their rights and of the protections available through
153-16 the commission and the office. The educational program may not
153-17 duplicate customer information efforts undertaken by retail
153-18 electric providers or other private entities. The educational
153-19 program may not be targeted to areas served by municipally owned
153-20 utilities or electric cooperatives that have not adopted customer
153-21 choice. In planning and implementing this program, the commission
153-22 shall consult with the office, with the Texas Department of Housing
153-23 and Community Affairs, and with customers of and providers of
153-24 retail electric service. The commission may enter into contracts
153-25 for professional services to carry out the customer education
153-26 program.
154-1 (b) The commission shall report on the status of the
154-2 educational program, developed and implemented as provided by
154-3 Subsection (a), to the electric utility restructuring legislative
154-4 oversight committee on or before December 1, 2001.
154-5 (c) After the opening of the retail electric market, the
154-6 commission shall conduct ongoing customer education designed to
154-7 help customers make informed choices of electric services and
154-8 retail electric providers. As part of ongoing education, the
154-9 commission may provide customers information concerning specific
154-10 retail electric providers, including instances of complaints
154-11 against them and records relating to quality of customer service.
154-12 Sec. 39.903. SYSTEM BENEFIT FUND. (a) The system benefit
154-13 fund is created as a trust fund with the comptroller and shall be
154-14 administered by the commission as trustee on behalf of the
154-15 recipients of money from the fund.
154-16 (b) The system benefit fund is financed by a nonbypassable
154-17 fee set by the commission in an amount not to exceed 50 cents per
154-18 megawatt hour, except beginning on January 1, 2002, and ending on
154-19 December 31, 2006, the commission may set the fee in an amount not
154-20 to exceed 65 cents per megawatt hour to the extent necessary to
154-21 collect sufficient revenue to fund the 10 percent reduced rate
154-22 requirements of the program required by Subsection (h). The system
154-23 benefit fund fee is allocated to customers based on the amount of
154-24 kilowatt hours used.
154-25 (c) The nonbypassable fee may not be imposed on the retail
154-26 electric customers of a municipally owned utility or electric
155-1 cooperative before the sixth month preceding the date on which the
155-2 utility or cooperative implements customer choice. Money
155-3 distributed from the system benefit fund to a municipally owned
155-4 utility or an electric cooperative shall be proportional to the
155-5 nonbypassable fee paid by the municipally owned utility or the
155-6 electric cooperative, subject to the reimbursement provided by
155-7 Subsection (i). On request by a municipally owned utility or
155-8 electric cooperative, the commission shall reduce the nonbypassable
155-9 fee imposed on retail electric customers served by the municipally
155-10 owned utility or electric cooperative by an amount equal to the
155-11 amount provided by the municipally owned utility or electric
155-12 cooperative or its ratepayers for local low-income programs and
155-13 local programs that educate customers about the retail electric
155-14 market in a neutral and nonpromotional manner.
155-15 (d) The commission shall annually review and approve system
155-16 benefit fund accounts, projected revenue requirements, and proposed
155-17 nonbypassable fees. The commission shall report to the electric
155-18 utility restructuring legislative oversight committee if the system
155-19 benefit fund fee is insufficient to fund the purposes set forth in
155-20 Subsection (e) to the extent required by this section.
155-21 (e) The system benefit fund shall provide funding solely for
155-22 the following regulatory purposes:
155-23 (1) programs to assist low-income electric customers
155-24 provided by Subsections (f)-(l);
155-25 (2) customer education programs; and
155-26 (3) the school funding loss mechanism provided by
156-1 Section 39.901.
156-2 (f) Notwithstanding Section 39.106(b), the commission shall
156-3 adopt rules regarding programs to assist low-income electric
156-4 customers on the introduction of customer choice. The programs may
156-5 not be targeted to areas served by municipally owned utilities or
156-6 electric cooperatives that have not adopted customer choice. The
156-7 programs shall include:
156-8 (1) reduced electric rates as provided by Subsections
156-9 (h)-(l); and
156-10 (2) targeted energy efficiency programs to be
156-11 administered by the Texas Department of Housing and Community
156-12 Affairs in coordination with existing weatherization programs.
156-13 (g) Until customer choice is introduced in a power region,
156-14 an electric utility may not reduce, in any manner, programs already
156-15 offered to assist low-income electric customers.
156-16 (h) The commission shall adopt rules for a retail electric
156-17 provider to determine a reduced rate for eligible customers to be
156-18 discounted off the standard retail service package as approved by
156-19 the commission under Section 39.106, or the price to beat
156-20 established by Section 39.202, whichever is lower. Municipally
156-21 owned utilities and electric cooperatives shall establish a reduced
156-22 rate for eligible customers to be discounted off the standard
156-23 retail service package established under Section 40.053 or 41.053,
156-24 as appropriate. The reduced rate for a retail electric provider
156-25 shall result in a total charge that is at least 10 percent and, if
156-26 sufficient money in the system benefit fund is available, up to 20
157-1 percent, lower than the amount the customer would otherwise be
157-2 charged. To the extent the system benefit fund is insufficient to
157-3 fund the initial 10 percent rate reduction, the commission may
157-4 increase the fee to an amount not more than 65 cents per megawatt
157-5 hour, as provided by Subsection (b). For a municipally owned
157-6 utility or electric cooperative, the reduced rate shall be equal to
157-7 an amount that can be fully funded by that portion of the
157-8 nonbypassable fee proceeds paid by the municipally owned utility or
157-9 electric cooperative that is allocated to the utility or
157-10 cooperative by the commission under Subsection (e) for programs for
157-11 low-income customers of the utility or cooperative. The reduced
157-12 rate for municipally owned utilities and electric cooperatives
157-13 under this section is in addition to any rate reduction that may
157-14 result from local programs for low-income customers of the
157-15 municipally owned utilities or electric cooperatives.
157-16 (i) A retail electric provider, municipally owned utility,
157-17 or electric cooperative seeking reimbursement from the system
157-18 benefit fund may not charge an eligible low-income customer a rate
157-19 higher than the appropriate rate determined under Subsection (h).
157-20 A retail electric provider not subject to the price to beat, or a
157-21 municipally owned utility or electric cooperative subject to the
157-22 nonbypassable fee under Subsection (c), shall be reimbursed from
157-23 the system benefit fund for the difference between the reduced rate
157-24 and the rate established under Section 39.106 or, as appropriate,
157-25 the rate established under Section 40.053 or 41.053. A retail
157-26 electric provider who is subject to the price to beat shall be
158-1 reimbursed from the system benefit fund for the difference between
158-2 the reduced rate and the price to beat. The commission shall adopt
158-3 rules providing for the reimbursement.
158-4 (j) The commission shall adopt rules providing for methods
158-5 of enrolling customers eligible to receive reduced rates under
158-6 Subsection (h). The rules must provide for automatic enrollment as
158-7 one enrollment option. The Texas Department of Human Services, on
158-8 request of the commission, shall assist in the adoption and
158-9 implementation of these rules. The commission and the Texas
158-10 Department of Human Services shall enter into a memorandum of
158-11 understanding establishing the respective duties of the commission
158-12 and the department in relation to the automatic enrollment.
158-13 (k) A retail electric provider is prohibited from charging
158-14 the customer a fee for participation in the reduced rate program.
158-15 (l) For the purposes of this section, a "low-income electric
158-16 customer" is an electric customer:
158-17 (1) whose household income is not more than 125
158-18 percent of the federal poverty guidelines; or
158-19 (2) who receives food stamps from the Texas Department
158-20 of Human Services or medical assistance from a state agency
158-21 administering a part of the medical assistance program.
158-22 Sec. 39.904. GOAL FOR RENEWABLE ENERGY. (a) It is the
158-23 intent of the legislature that by January 1, 2009, an additional
158-24 2,000 megawatts of generating capacity from renewable energy
158-25 technologies will have been installed in this state. The
158-26 cumulative installed renewable capacity in this state shall total
159-1 1,280 megawatts by January 1, 2003, 1,730 megawatts by January 1,
159-2 2005, 2,280 megawatts by January 1, 2007, and 2,880 megawatts by
159-3 January 1, 2009.
159-4 (b) The commission shall establish a renewable energy
159-5 credits trading program. Any retail electric provider, municipally
159-6 owned utility, or electric cooperative that does not satisfy the
159-7 requirements of Subsection (a) by directly owning or purchasing
159-8 capacity using renewable energy technologies shall purchase
159-9 sufficient renewable energy credits to satisfy the requirements by
159-10 holding renewable energy credits in lieu of capacity from renewable
159-11 energy technologies.
159-12 (c) Not later than January 1, 2000, the commission shall
159-13 adopt rules necessary to administer and enforce this section. At a
159-14 minimum, the rules shall:
159-15 (1) establish the minimum annual renewable energy
159-16 requirement for each retail electric provider, municipally owned
159-17 utility, and electric cooperative operating in this state in a
159-18 manner reasonably calculated by the commission to produce, on a
159-19 statewide basis, compliance with the requirement prescribed by
159-20 Subsection (a); and
159-21 (2) specify reasonable performance standards that all
159-22 renewable capacity additions must meet to count against the
159-23 requirement prescribed by Subsection (a) and that:
159-24 (A) are designed and operated so as to maximize
159-25 the energy output from the capacity additions in accordance with
159-26 then-current industry standards; and
160-1 (B) encourage the development, construction, and
160-2 operation of new renewable energy projects at those sites in this
160-3 state that have the greatest economic potential for capture and
160-4 development of this state's environmentally beneficial renewable
160-5 resources.
160-6 (d) In this section, "renewable energy technology" means any
160-7 technology that exclusively relies on an energy source that is
160-8 naturally regenerated over a short time and derived directly from
160-9 the sun, indirectly from the sun, or from moving water or other
160-10 natural movements and mechanisms of the environment. Renewable
160-11 energy technologies include those that rely on energy derived
160-12 directly from the sun, on wind, geothermal, hydroelectric, wave, or
160-13 tidal energy, or on biomass or biomass-based waste products,
160-14 including landfill gas. A renewable energy technology does not
160-15 rely on energy resources derived from fossil fuels, waste products
160-16 from fossil fuels, or waste products from inorganic sources.
160-17 (e) A municipally owned utility operating a gas distribution
160-18 system may credit toward satisfaction of the requirements of this
160-19 section any production or acquisition of landfill gas supplied to
160-20 the gas distribution system, based on conversion to kilowatt hours
160-21 of the thermal energy content in British thermal units of the
160-22 renewable source and using for the conversion factor the annual
160-23 heat rate of the most efficient gas-fired unit of the combined
160-24 utility's electric system as measured in British thermal units per
160-25 kilowatt hour and using the British thermal unit measurement based
160-26 on the higher heating value measurement.
161-1 (f) A municipally owned utility operating a gas distribution
161-2 system may credit toward satisfaction of the requirements of this
161-3 section any production or acquisition of landfill gas supplied to
161-4 the gas distribution system, based on conversion to kilowatt hours
161-5 of the thermal energy content in British thermal units of the
161-6 renewable source and using for the conversion factor the systemwide
161-7 average heat rate of the gas-fired units of the combined utility's
161-8 electric system as measured in British thermal units per kilowatt
161-9 hour.
161-10 Sec. 39.9044. GOAL FOR NATURAL GAS. (a) It is the intent
161-11 of the legislature that 50 percent of the megawatts of generating
161-12 capacity installed in this state after January 1, 2000, use natural
161-13 gas. To the extent permitted by law, the commission shall
161-14 establish a program to encourage utilities to comply with this
161-15 section by using natural gas produced in this state as the
161-16 preferential fuel. This section does not apply to generating
161-17 capacity for renewable energy technologies.
161-18 (b) The commission shall establish a natural gas energy
161-19 credits trading program. Any power generation company, municipally
161-20 owned utility, or electric cooperative that does not satisfy the
161-21 requirements of Subsection (a) by directly owning or purchasing
161-22 capacity using natural gas technologies shall purchase sufficient
161-23 natural gas energy credits to satisfy the requirements by holding
161-24 natural gas energy credits in lieu of capacity from natural gas
161-25 energy technologies.
161-26 (c) Not later than January 1, 2000, the commission shall
162-1 adopt rules necessary to administer and enforce this section and to
162-2 perform any necessary studies in cooperation with the Railroad
162-3 Commission of Texas. At a minimum, the rules shall:
162-4 (1) establish the minimum annual natural gas
162-5 generation requirement for each power generation company,
162-6 municipally owned utility, and electric cooperative operating in
162-7 this state in a manner reasonably calculated by the commission to
162-8 produce, on a statewide basis, compliance with the requirement
162-9 prescribed by Subsection (a); and
162-10 (2) specify reasonable performance standards that all
162-11 natural gas capacity additions must meet to count against the
162-12 requirement prescribed by Subsection (a) and that:
162-13 (A) are designed and operated so as to maximize
162-14 the energy output from the capacity additions in accordance with
162-15 then-current industry standards and best industry standards; and
162-16 (B) encourage the development, construction, and
162-17 operation of new natural gas energy projects at those sites in this
162-18 state that have the greatest economic potential for capture and
162-19 development of this state's environmentally beneficial natural gas
162-20 resources.
162-21 (d) The commission, with the assistance of the Railroad
162-22 Commission of Texas, shall adopt rules allowing and encouraging
162-23 retail electric providers and municipally owned utilities and
162-24 electric cooperatives that have adopted customer choice to market
162-25 electricity generated using natural gas produced in this state as
162-26 environmentally beneficial. The rules shall allow a provider,
163-1 municipally owned utility, or cooperative to:
163-2 (1) emphasize that natural gas produced in this state
163-3 is the cleanest-burning fossil fuel; and
163-4 (2) label the electricity generated using natural gas
163-5 produced in this state as "green" electricity.
163-6 (e) In this section, "natural gas technology" means any
163-7 technology that exclusively relies on natural gas as a primary fuel
163-8 source.
163-9 Sec. 39.9048. NATURAL GAS FUEL. It is the intent of the
163-10 legislature that:
163-11 (1) the cost of generating electricity remain as low
163-12 as possible; and
163-13 (2) the state establish and publicize a program to
163-14 keep the costs of fuel, such as natural gas, used for generating
163-15 electricity low.
163-16 Sec. 39.905. GOAL FOR ENERGY EFFICIENCY. (a) It is the
163-17 goal of the legislature that:
163-18 (1) electric utilities will administer energy savings
163-19 incentive programs in a market-neutral, nondiscriminatory manner
163-20 but will not offer underlying competitive services;
163-21 (2) all customers, in all customer classes, have a
163-22 choice of and access to energy efficiency alternatives and other
163-23 choices from the market that allow each customer to reduce energy
163-24 consumption and reduce energy costs; and
163-25 (3) each electric utility will provide, through
163-26 market-based standard offer programs or limited, targeted,
164-1 market-transformation programs, incentives sufficient for retail
164-2 electric providers and competitive energy service providers to
164-3 acquire additional cost-effective energy efficiency equivalent to
164-4 at least 10 percent of the electric utility's annual growth in
164-5 demand.
164-6 (b) The commission shall provide oversight and adopt rules
164-7 and procedures, as necessary, to ensure that the goal of this
164-8 section is achieved by January 1, 2004.
164-9 Sec. 39.906. DISPLACED WORKERS. In order to mitigate
164-10 potential negative impacts on utility personnel directly affected
164-11 by electric industry restructuring, the commission shall allow the
164-12 recovery of reasonable employee-related transition costs incurred
164-13 and projected for severance, retraining, early retirement,
164-14 outplacement, and related expenses for the employees.
164-15 Sec. 39.907. LEGISLATIVE OVERSIGHT COMMITTEE. (a) In this
164-16 section, "committee" means the electric utility restructuring
164-17 legislative oversight committee.
164-18 (b) The committee is composed of six members as follows:
164-19 (1) the chair of the Senate Committee on Economic
164-20 Development and the chair of the House Committee on State Affairs,
164-21 who shall serve as joint chairs of the committee;
164-22 (2) two members of the senate appointed by the
164-23 lieutenant governor; and
164-24 (3) two members of the house of representatives
164-25 appointed by the speaker of the house of representatives.
164-26 (c) An appointed member of the committee serves at the
165-1 pleasure of the appointing official. In making appointments to the
165-2 committee, the appointing officials shall attempt to appoint
165-3 persons who represent the gender composition, minority populations,
165-4 and geographic regions of the state.
165-5 (d) The committee is subject to Chapter 325, Government Code
165-6 (Texas Sunset Act). Unless continued in existence as provided by
165-7 that chapter, the committee is abolished September 1, 2005.
165-8 (e) The committee shall:
165-9 (1) meet at least annually with the commission;
165-10 (2) receive information about rules relating to
165-11 electric utility restructuring proposed by the commission and may
165-12 submit comments to the commission on those proposed rules;
165-13 (3) review recommendations for legislation proposed by
165-14 the commission; and
165-15 (4) monitor the effectiveness of electric utility
165-16 restructuring, including the fairness of rates, the reliability of
165-17 service, and the effect of stranded costs, market power, and
165-18 regulation on the normal forces of competition.
165-19 (f) The committee may request reports and other information
165-20 from the commission as necessary to carry out this section.
165-21 (g) Not later than November 15 of each even-numbered year,
165-22 the committee shall report to the governor, lieutenant governor,
165-23 and speaker of the house of representatives on the committee's
165-24 activities under Subsection (e). The report shall include:
165-25 (1) an analysis of any problems caused by electric
165-26 utility restructuring; and
166-1 (2) recommendations of any legislative action
166-2 necessary to address those problems and to further retail
166-3 competition within the electric power industry.
166-4 Sec. 39.908. EFFECT OF SUNSET PROVISION. (a) If the
166-5 commission is abolished and the other provisions of this title
166-6 expire as provided by Chapter 325, Government Code (Texas Sunset
166-7 Act), this subchapter, including the provisions of this title
166-8 referred to in this subchapter, continues in full force and effect
166-9 and does not expire.
166-10 (b) The authorities, duties, and functions of the commission
166-11 under this chapter shall be performed and carried out by a
166-12 successor agency to be designated by the legislature before
166-13 abolishment of the commission or, if the legislature does not
166-14 designate the successor, by the secretary of state.
166-15 Sec. 39.909. PLAN AND REPORT OF WORKFORCE DIVERSITY AND
166-16 OTHER BUSINESS PRACTICES. (a) In this section, "small business"
166-17 and "historically underutilized business" have the meanings
166-18 assigned by Section 481.191, Government Code.
166-19 (b) Before January 1, 2000, each electric utility shall
166-20 develop and submit to the commission a comprehensive five-year plan
166-21 to enhance diversity of its workforce in all occupational
166-22 categories and to increase contracting opportunities for small and
166-23 historically underutilized businesses. The plan must consist of:
166-24 (1) the electric utility's historical and current
166-25 performance with regard to workforce diversity and contracting with
166-26 small and historically underutilized businesses;
167-1 (2) initiatives that the electric utility will pursue
167-2 in these areas over the period of the plan;
167-3 (3) a listing of programs and activities the electric
167-4 utility will undertake to achieve each of those initiatives; and
167-5 (4) a listing of the business partnership initiatives
167-6 the electric utility will undertake to facilitate small and
167-7 historically underutilized business entry into the electric energy
167-8 market as generators and retail energy providers taking into
167-9 account opportunities for contracting and joint ventures.
167-10 (c) Each electric utility shall submit an annual report to
167-11 the commission and the legislature relating to its efforts to
167-12 improve workforce diversity and contracting opportunities for small
167-13 and historically underutilized businesses. The report must be
167-14 submitted on October 1 of each year or may be included as part of
167-15 any other annual report submitted by the electric utility to the
167-16 commission. The report must include:
167-17 (1) the diversity of the electric utility's workforce
167-18 as of the time of the report;
167-19 (2) the electric utility's level of contracting with
167-20 small and historically underutilized businesses;
167-21 (3) the specific progress made under the plan under
167-22 Subsection (b);
167-23 (4) the specific initiatives, programs, and activities
167-24 undertaken under the plan during the preceding year;
167-25 (5) an assessment of the success of each of those
167-26 initiatives, programs, and activities;
168-1 (6) the extent to which the electric utility has
168-2 carried out its initiatives to facilitate opportunities for
168-3 contracts or joint ventures with small and historically
168-4 underutilized businesses; and
168-5 (7) the initiatives, programs, and activities the
168-6 electric utility will pursue during the next year to increase the
168-7 diversity of its workforce and contracting opportunities for small
168-8 and historically underutilized businesses.
168-9 CHAPTER 40. COMPETITION FOR MUNICIPALLY OWNED UTILITIES
168-10 AND RIVER AUTHORITIES
168-11 SUBCHAPTER A. GENERAL PROVISIONS
168-12 Sec. 40.001. APPLICABLE LAW. (a) Notwithstanding any other
168-13 provision of law, except Sections 39.155, 39.157(e), 39.203,
168-14 39.903, and 39.904, this chapter governs the transition to and the
168-15 establishment of a fully competitive electric power industry for
168-16 municipally owned utilities. With respect to the regulation of
168-17 municipally owned utilities, this chapter controls over any other
168-18 provision of this title, except for sections in which the term
168-19 "municipally owned utility" is specifically used.
168-20 (b) Except as specifically provided in this subsection,
168-21 Chapter 39 does not apply to a river authority operating a steam
168-22 generating plant on or before January 1, 1999, or a corporation
168-23 authorized by Chapter 245, Acts of the 67th Legislature, Regular
168-24 Session, 1981 (Article 717p, Vernon's Texas Civil Statutes), or
168-25 Section 32.053. A river authority operating a steam generating
168-26 plant on or before January 1, 1999, is subject to Sections
169-1 39.051(a)-(c), 39.108, 39.155, 39.157(e), and 39.203.
169-2 (c) For purposes of Section 39.051, hydroelectric assets may
169-3 not be deemed to be generating assets, and the transfer of
169-4 generating assets to a corporation authorized by Chapter 245, Acts
169-5 of the 67th Legislature, Regular Session, 1981 (Article 717p,
169-6 Vernon's Texas Civil Statutes), satisfies the requirements of
169-7 Section 39.051.
169-8 (d) Accommodation shall be made in the code of conduct
169-9 established under Section 39.157(e) for the provisions of Chapter
169-10 245, Acts of the 67th Legislature, Regular Session, 1981 (Article
169-11 717p, Vernon's Texas Civil Statutes), and the commission may not
169-12 prohibit a river authority and any related corporation from sharing
169-13 officers, directors, employees, equipment, and facilities or from
169-14 providing goods or services to each other at cost without the need
169-15 for a competitive bid.
169-16 Sec. 40.002. DEFINITION. For purposes of this chapter,
169-17 "body vested with the power to manage and operate a municipally
169-18 owned utility" shall mean a body created in accordance with Article
169-19 1115 or 1115a, Revised Statutes, or by municipal charter.
169-20 Sec. 40.003. SECURITIZATION. (a) Municipally owned
169-21 utilities and river authorities may adopt and use securitization
169-22 provisions having the effect of the provisions provided by
169-23 Subchapter G, Chapter 39, to recover through appropriate charges
169-24 their stranded costs, at a recovery level deemed appropriate by the
169-25 municipally owned utility or river authority up to 100 percent,
169-26 under rules and procedures that shall be established:
170-1 (1) in the case of a municipally owned utility, by the
170-2 municipal governing body or a body vested with the power to manage
170-3 and operate the municipally owned utility, including procedures
170-4 providing for rate orders of the governing body having the effect
170-5 of financing orders, providing for a separate nonbypassable charge
170-6 approved by the governing body, in the nature of a transition
170-7 charge, to be collected from all retail electric customers of the
170-8 municipally owned utility, identified as of a date determined by
170-9 the governing body, to fund the recovery of the stranded costs of
170-10 the municipally owned utility and of all reasonable related
170-11 expenses, as determined by the governing body, and providing for
170-12 the issuance of bonds, having a term and other characteristics as
170-13 determined by the governing body, as necessary to recover the
170-14 amount deemed appropriate by the governing body through
170-15 securitization financing; and
170-16 (2) in the case of a river authority, by the
170-17 commission.
170-18 (b) In order to implement securitization financing under the
170-19 rules and procedures established by and for a municipally owned
170-20 utility under Subsection (a)(1), municipalities are expressly
170-21 authorized and empowered to issue bonds, notes, or other
170-22 obligations, including refunding bonds, payable from and secured by
170-23 a lien on and pledge of the revenues collected under an order of
170-24 the governing body of the municipality, and the bonds shall be
170-25 issued, without an election or any requirement of giving notice of
170-26 intent to issue the bonds, by ordinance adopted by the governing
171-1 body of the municipality, in the form and manner and sold on a
171-2 negotiated basis or on receipt of bids and on the terms and
171-3 conditions as shall be determined by the governing body of the
171-4 municipality.
171-5 (c) Bonds issued under the authority conferred by
171-6 Subsections (a)(1) and (2) and Subsection (b) may be issued in the
171-7 form and manner, with or without credit enhancement or liquidity
171-8 enhancement and using the procedures as provided in the Bond
171-9 Procedures Act of 1981 (Article 717k-6, Vernon's Texas Civil
171-10 Statutes) or other laws applicable to the issuance of bonds,
171-11 including Chapter 656, Acts of the 68th Legislature, Regular
171-12 Session, 1983 (Article 717q, Vernon's Texas Civil Statutes),
171-13 Chapter 503, Acts of the 54th Legislature, Regular Session, 1955
171-14 (Article 717k, Vernon's Texas Civil Statutes), and Chapter 642,
171-15 Acts of the 65th Legislature, Regular Session, 1977 (Article
171-16 1118n-12, Vernon's Texas Civil Statutes), as if those laws were
171-17 fully restated in this section and made a part of this section for
171-18 all purposes, and a municipality or river authority shall have the
171-19 right and authority to use those other laws, notwithstanding any
171-20 applicable restrictions contained in those laws, to the extent
171-21 convenient or necessary to carry out any power or authority,
171-22 express or implied, granted under this section, in the issuance of
171-23 bonds by a municipality or river authority in connection with
171-24 securitization financing. This section is wholly sufficient
171-25 authority for the issuance of bonds, notes, or other obligations,
171-26 including refunding bonds, and the performance of the other
172-1 authorized acts and procedures, without reference to any other laws
172-2 or any restrictions or limitations contained in those laws. To the
172-3 extent of any conflict or inconsistency between the provisions of
172-4 this authorization and any provisions of any other law or home-rule
172-5 charter, the authorization and power to issue bonds conferred on
172-6 municipalities or river authorities under this section shall
172-7 prevail and control.
172-8 (d) The rules and procedures for securitization established
172-9 by the commission under Subsection (a)(2) shall include procedures
172-10 for the recovery of qualified costs under the terms of a financing
172-11 order adopted by the governing body of the river authority.
172-12 (e) The rules and procedures for securitization established
172-13 by the commission under Subsection (a)(2) shall include rules and
172-14 procedures for the issuance of transition bonds. Findings made by
172-15 the governing body of a river authority in a financing order issued
172-16 under the rules and procedures described in this subsection shall
172-17 be conclusive, and any transition charge incorporated in the rate
172-18 order to recover the principal, interest, and all reasonable
172-19 expenses associated with any transition bonds shall constitute
172-20 property rights, as described in Subchapter G, Chapter 39, and
172-21 otherwise conform in all material respects to the transition
172-22 charges provided by Subchapter G, Chapter 39.
172-23 (f) The rules and procedures established under this section
172-24 shall be consistent with other law applicable to municipally owned
172-25 utilities and river authorities and with the terms of any
172-26 resolutions, orders, charter provisions, or ordinances authorizing
173-1 outstanding bonds or other indebtedness of the municipalities or
173-2 river authorities.
173-3 Sec. 40.004. JURISDICTION OF COMMISSION. Except as
173-4 specifically otherwise provided in this chapter, the commission has
173-5 jurisdiction over municipally owned utilities only for the
173-6 following purposes:
173-7 (1) to regulate wholesale transmission rates and
173-8 service, including terms of access, to the extent provided by
173-9 Subchapter A, Chapter 35;
173-10 (2) to regulate certification of retail service areas
173-11 to the extent provided by Chapter 37;
173-12 (3) to regulate rates on appeal under Subchapters D
173-13 and E, Chapter 33, subject to Section 40.051(c);
173-14 (4) to establish a code of conduct as provided by
173-15 Section 39.157(e) applicable to anticompetitive activities and to
173-16 affiliate activities limited to structurally unbundled affiliates
173-17 of municipally owned utilities, subject to Section 40.054;
173-18 (5) to establish terms and conditions for open access
173-19 to transmission and distribution facilities for municipally owned
173-20 utilities providing customer choice, as provided by Section 39.203;
173-21 (6) to require collection of the nonbypassable fee
173-22 established under Section 39.903(b) and to administer the renewable
173-23 energy credits program under Section 39.904(b) and the natural gas
173-24 energy credits program under Section 39.9044(b); and
173-25 (7) to require reports of municipally owned utility
173-26 operations only to the extent necessary to:
174-1 (A) enable the commission to determine the
174-2 aggregate load and energy requirements of the state and the
174-3 resources available to serve that load; or
174-4 (B) enable the commission to determine
174-5 information relating to market power as provided by Section 39.155.
174-6 (Sections 40.005-40.050 reserved for expansion
174-7 SUBCHAPTER B. MUNICIPALLY OWNED UTILITY CHOICE
174-8 Sec. 40.051. GOVERNING BODY DECISION. (a) The municipal
174-9 governing body or a body vested with the power to manage and
174-10 operate a municipally owned utility has the discretion to decide
174-11 when or if the municipally owned utility will provide customer
174-12 choice.
174-13 (b) Municipally owned utilities may choose to participate in
174-14 customer choice at any time on or after January 1, 2002, by
174-15 adoption of an appropriate resolution of the municipal governing
174-16 body or a body vested with power to manage and operate the
174-17 municipally owned utility. The decision to participate in customer
174-18 choice by the adoption of a resolution is irrevocable.
174-19 (c) After a decision to offer customer choice has been made,
174-20 Subchapters D and E, Chapter 33, do not apply to any action taken
174-21 under this chapter.
174-22 Sec. 40.052. UTILITY NOT OFFERING CUSTOMER CHOICE. (a) A
174-23 municipally owned utility that has not chosen to participate in
174-24 customer choice may not offer electric energy at unregulated prices
174-25 directly to retail customers outside its certificated retail
174-26 service area.
175-1 (b) A municipally owned utility under Subsection (a) retains
175-2 the right to offer and provide a full range of customer service and
175-3 pricing programs to the customers within its certificated area and
175-4 to purchase and sell electric energy at wholesale without
175-5 geographic restriction.
175-6 Sec. 40.053. RETAIL CUSTOMER'S RIGHT OF CHOICE. (a) If a
175-7 municipally owned utility chooses to participate in customer
175-8 choice, after that choice all retail customers served by the
175-9 municipally owned utility within the certificated retail service
175-10 area of the municipally owned utility shall have the right of
175-11 customer choice consistent with the provisions of this chapter, and
175-12 the municipally owned utility shall provide open access for retail
175-13 service.
175-14 (b) Notwithstanding Section 39.107, the metering function
175-15 may not be deemed a competitive service for customers of the
175-16 municipally owned utility within that service area and may, at the
175-17 option of the municipally owned utility, continue to be offered by
175-18 the municipally owned utility as sole provider.
175-19 (c) On its initiation of customer choice, a municipally
175-20 owned utility shall designate itself or another entity as the
175-21 provider of last resort for customers within the municipally owned
175-22 utility's certificated service area as that area existed on the
175-23 date of the utility's initiation of customer choice. The
175-24 municipally owned utility shall fulfill the role of default
175-25 provider of last resort in the event no other entity is available
175-26 to act in that capacity.
176-1 (d) If a customer is unable to obtain service from a retail
176-2 electric provider, on request by the customer, the provider of last
176-3 resort shall offer the customer the standard retail service package
176-4 for the appropriate customer class, with no interruption of
176-5 service, at a fixed, nondiscountable rate that is at least
176-6 sufficient to cover the reasonable costs of providing that service,
176-7 as approved by the governing body of the municipally owned utility
176-8 that has the authority to set rates.
176-9 (e) The governing body of a municipally owned utility may
176-10 establish the procedures and criteria for designating the provider
176-11 of last resort and may redesignate the provider of last resort
176-12 according to a schedule it considers appropriate.
176-13 Sec. 40.054. SERVICE OUTSIDE AREA. (a) A municipally owned
176-14 utility participating in customer choice shall have the right to
176-15 offer electric energy and related services at unregulated prices
176-16 directly to retail customers who have customer choice without
176-17 regard to geographic location.
176-18 (b) In providing service under Subsection (a) to retail
176-19 customers outside its certificated retail service area as that area
176-20 exists on the date of adoption of customer choice, a municipally
176-21 owned utility is subject to the commission's rules establishing a
176-22 code of conduct regulating anticompetitive practices.
176-23 (c) For municipally owned utilities participating in
176-24 customer choice, the commission shall have jurisdiction to
176-25 establish terms and conditions, but not rates, for access by other
176-26 retail electric providers to the municipally owned utility's
177-1 distribution facilities.
177-2 (d) Accommodation shall be made in the commission's terms
177-3 and conditions for access and in the code of conduct for specific
177-4 legal requirements imposed by state or federal law applicable to
177-5 municipally owned utilities.
177-6 (e) The commission does not have jurisdiction to require
177-7 unbundling of services or functions of, or to regulate the recovery
177-8 of stranded investment of, a municipally owned utility or, except
177-9 as provided by this section, jurisdiction with respect to the
177-10 rates, terms, and conditions of service for retail customers of a
177-11 municipally owned utility within the utility's certificated service
177-12 area.
177-13 (f) A municipally owned utility shall maintain separate
177-14 books and records of its operations from those of the operations of
177-15 any affiliate.
177-16 Sec. 40.055. JURISDICTION OF MUNICIPAL GOVERNING BODY.
177-17 (a) The municipal governing body or a body vested with the power
177-18 to manage and operate a municipally owned utility has exclusive
177-19 jurisdiction to:
177-20 (1) set all terms of access, conditions, and rates
177-21 applicable to services provided by the municipally owned utility,
177-22 subject to Sections 40.054 and 40.056, including nondiscriminatory
177-23 and comparable rates for distribution but excluding wholesale
177-24 transmission rates, terms of access, and conditions for wholesale
177-25 transmission service set by the commission under this subtitle,
177-26 provided that the rates for distribution access established by the
178-1 municipal governing body shall be comparable to the distribution
178-2 access rates that apply to the municipally owned utility and the
178-3 municipally owned utility's affiliates;
178-4 (2) determine whether to unbundle any energy-related
178-5 activities and, if the municipally owned utility chooses to
178-6 unbundle, whether to do so structurally or functionally;
178-7 (3) reasonably determine the amount of the municipally
178-8 owned utility's stranded investment;
178-9 (4) establish nondiscriminatory transition charges
178-10 reasonably designed to recover the stranded investment over an
178-11 appropriate period of time, provided that recovery of retail
178-12 stranded costs shall be from all existing or future retail
178-13 customers, including the facilities, premises, and loads of those
178-14 retail customers, within the utility's geographical certificated
178-15 service area as it existed on May 1, 1999;
178-16 (5) determine the extent to which the municipally
178-17 owned utility will provide various customer services at the
178-18 distribution level, including other services that the municipally
178-19 owned utility is legally authorized to provide, or will accept the
178-20 services from other providers;
178-21 (6) manage and operate the municipality's electric
178-22 utility systems, including exercise of control over resource
178-23 acquisition and any related expansion programs;
178-24 (7) establish and enforce service quality and
178-25 reliability standards and consumer safeguards designed to protect
178-26 retail electric customers, including safeguards that will
179-1 accomplish the objectives of Sections 39.101(a) and (b), consistent
179-2 with this chapter;
179-3 (8) determine whether a base rate reduction is
179-4 appropriate for the municipally owned utility;
179-5 (9) determine any other utility matters that the
179-6 municipal governing body or body vested with power to manage and
179-7 operate the municipally owned utility believes should be included;
179-8 and
179-9 (10) make any other decisions affecting the
179-10 municipally owned utility's participation in customer choice that
179-11 are not inconsistent with this chapter.
179-12 (b) In multiply certificated areas, a retail customer,
179-13 including a retail customer of an electric cooperative or a
179-14 municipally owned utility, may not avoid stranded cost recovery
179-15 charges by switching to another electric utility, electric
179-16 cooperative, or municipally owned utility.
179-17 Sec. 40.056. ANTICOMPETITIVE ACTIONS. (a) If, on complaint
179-18 by a retail electric provider, the commission finds that a
179-19 municipal rule, action, or order relating to customer choice is
179-20 anticompetitive or does not provide other retail electric providers
179-21 with nondiscriminatory terms and conditions of access to
179-22 distribution facilities or customers within the municipally owned
179-23 utility's certificated retail service area that are comparable to
179-24 the municipally owned utility's and its affiliates' terms and
179-25 conditions of access to distribution facilities or customers, the
179-26 commission shall notify the municipally owned utility.
180-1 (b) The municipally owned utility shall have three months to
180-2 cure the anticompetitive or noncompliant behavior described in
180-3 Subsection (a), following opportunity for hearing on the complaint.
180-4 If the rule, action, or order is not fully remedied within that
180-5 time, the commission may prohibit the municipally owned utility or
180-6 affiliate from providing retail service outside its certificated
180-7 retail service area until the rule, action, or order is remedied.
180-8 Sec. 40.057. BILLING. (a) A municipally owned utility that
180-9 opts for customer choice may continue to bill directly electric
180-10 customers located in its certificated retail service area, as that
180-11 area exists on the date of adoption of customer choice, for all
180-12 transmission and distribution services. The municipally owned
180-13 utility may also bill directly for generation services and customer
180-14 services provided by the municipally owned utility to those
180-15 customers.
180-16 (b) A municipally owned utility that opts for customer
180-17 choice may not adopt anticompetitive billing practices that would
180-18 discourage customers in its service area from choosing a retail
180-19 electric provider.
180-20 (c) A customer that is being provided wires service by a
180-21 municipally owned utility at distribution or transmission voltage
180-22 and that is served by a retail electric provider for retail service
180-23 has the option of being billed directly by each service provider or
180-24 to receive a single bill for distribution, transmission, and
180-25 generation services from the municipally owned utility.
180-26 Sec. 40.058. TARIFFS FOR OPEN ACCESS. A municipally owned
181-1 utility that owns or operates transmission and distribution
181-2 facilities shall file with the commission tariffs implementing the
181-3 open access rules established by the commission under Section
181-4 39.203 and shall file with the commission the rates for open access
181-5 on distribution facilities as set by the municipal regulatory
181-6 authority, before the 90th day preceding the date the utility
181-7 offers customer choice. The commission does not have authority to
181-8 determine the rates for distribution access service for a
181-9 municipally owned utility.
181-10 Sec. 40.059. MUNICIPAL POWER AGENCY; RECOVERY OF STRANDED
181-11 COSTS. (a) In this section, "member city" means a municipality
181-12 that participated in the creation of a municipal power agency
181-13 formed under Chapter 163 by the adoption of a concurrent resolution
181-14 by the municipality on or before August 1, 1975.
181-15 (b) After a member city adopts a resolution choosing to
181-16 participate in customer choice under Section 40.051(b), a member
181-17 city may include stranded costs described in Subsection (c) in its
181-18 distribution costs and may recover those costs through a
181-19 nonbypassable charge. The nonbypassable charge shall be as
181-20 determined by the member city's governing body and may be spread
181-21 over 16 years.
181-22 (c) The stranded costs that may be recovered under this
181-23 section are those costs that were determined by the commission and
181-24 stated in the commission's April 1998 Report to the Texas Senate
181-25 Interim Committee on Electric Utility Restructuring entitled
181-26 "Potentially Strandable Investment (ECOM) Report: 1998 Update" and
182-1 specifically stated in the report at Appendix A (ECOM Estimates
182-2 Including the Effects of Transition Plans) under the commission
182-3 base case benchmark base market price for the year 2002.
182-4 (d) The stranded cost amounts described in this section may
182-5 not be included in the generation costs used in setting rates by
182-6 the member city's governing body.
182-7 (e) The provisions of this section are cumulative of all
182-8 other provisions of this chapter, and nothing in this section shall
182-9 be construed to limit or restrict the application of any provision
182-10 of this chapter to the member cities.
182-11 (f) The municipal power agency shall extinguish the agency's
182-12 indebtedness by sale of the electric facility to one or more
182-13 purchasers, by way of a sale through the issuance of taxable or
182-14 tax-exempt debt to the member cities, or by any other method. The
182-15 agency shall set as an objective the extinguishment of the agency's
182-16 debt by September 1, 2000. In the event this objective is not met,
182-17 the agency shall provide detailed reasons to the electric utility
182-18 restructuring legislative oversight committee by November 1, 2000,
182-19 why the agency was not able to meet this objective.
182-20 (g) The municipal power agency or its successor in interest
182-21 may, at its option, use the rate of return method for calculating
182-22 its transmission cost of service. If the rate of return method is
182-23 used, the return component for the transmission cost of service
182-24 revenue requirement shall be sufficient to meet the transmission
182-25 function's pro rata share of levelized debt service and debt
182-26 service coverage ratio (1.50) and other annual debt obligations;
183-1 provided, however, that the total levelized debt service may not
183-2 exceed the total debt service under the current payment schedule.
183-3 Any additional revenue generated by the methodology described in
183-4 this subsection shall be applied to reduce the agency's outstanding
183-5 indebtedness.
183-6 Sec. 40.060. NO POWER TO AMEND CERTIFICATES. Nothing in
183-7 this chapter empowers a municipal governing body or a body vested
183-8 with the power to manage and operate a municipally owned utility to
183-9 issue, amend, or rescind a certificate of public convenience and
183-10 necessity granted by the commission. This subsection does not
183-11 affect the ability of a municipal governing body or a body vested
183-12 with the power to manage and operate the municipally owned utility
183-13 to pass a resolution under Section 40.051(b).
183-14 (Sections 40.061-40.100 reserved for expansion
183-15 SUBCHAPTER C. RIGHTS NOT AFFECTED
183-16 Sec. 40.101. INTERFERENCE WITH CONTRACT. (a) This subtitle
183-17 may not interfere with or abrogate the rights or obligations of
183-18 parties, including a retail or wholesale customer, to a contract
183-19 with a municipally owned utility or river authority.
183-20 (b) This subtitle may not interfere with or abrogate the
183-21 rights or obligations of a party under a contract or agreement
183-22 concerning certificated utility service areas.
183-23 Sec. 40.102. ACCESS TO WHOLESALE MARKET. Nothing in this
183-24 subtitle shall limit the access of municipally owned utilities to
183-25 the wholesale electric market.
183-26 Sec. 40.103. PROTECTION OF BONDHOLDERS. Nothing in this
184-1 subtitle or any rule adopted under this subtitle shall impair
184-2 contracts, covenants, or obligations between this state, river
184-3 authorities, municipalities, and the bondholders of revenue bonds
184-4 issued by the river authorities or municipalities.
184-5 Sec. 40.104. TAX-EXEMPT STATUS. Nothing in this subtitle
184-6 may impair the tax-exempt status of municipalities, electric
184-7 cooperatives, or river authorities, nor shall anything in this
184-8 subtitle compel any municipality, electric cooperative, or river
184-9 authority to use its facilities in a manner that violates any
184-10 contractual provisions, bond covenants, or other restrictions
184-11 applicable to facilities financed by tax-exempt debt.
184-12 Notwithstanding any other provision of law, the decision to
184-13 participate in customer choice by the adoption of a resolution in
184-14 accordance with Section 40.051(b) is irrevocable.
184-15 CHAPTER 41. ELECTRIC COOPERATIVES AND COMPETITION
184-16 SUBCHAPTER A. GENERAL PROVISIONS
184-17 Sec. 41.001. APPLICABLE LAW. Notwithstanding any other
184-18 provision of law, except Sections 39.155, 39.157(e), 39.203,
184-19 39.903, and 39.904, this chapter governs the transition to and the
184-20 establishment of a fully competitive electric power industry for
184-21 electric cooperatives. Regarding the regulation of electric
184-22 cooperatives, this chapter shall control over any other provision
184-23 of this title, except for sections in which the term "electric
184-24 cooperative" is specifically used.
184-25 Sec. 41.002. DEFINITIONS. In this chapter:
184-26 (1) "Board of directors" means the board of directors
185-1 of an electric cooperative as described in Section 161.071.
185-2 (2) "Rate" includes any compensation, tariff, charge,
185-3 fare, toll, rental, or classification that is directly or
185-4 indirectly demanded, observed, charged, or collected by an electric
185-5 cooperative for any service, product, or commodity and any rule,
185-6 practice, or contract affecting the compensation, tariff, charge,
185-7 fare, toll, rental, or classification.
185-8 (3) "Stranded investment" means:
185-9 (A) the excess, if any, of the net book value of
185-10 generation assets over the market value of the generation assets;
185-11 and
185-12 (B) any above market purchased power costs.
185-13 Sec. 41.003. SECURITIZATION. (a) Electric cooperatives may
185-14 adopt and use securitization provisions having the effect of the
185-15 provisions provided by Subchapter G, Chapter 39, to recover through
185-16 rates stranded costs at a recovery level deemed appropriate by the
185-17 board of directors up to 100 percent, under rules and procedures
185-18 that shall be established by the commission.
185-19 (b) The rules and procedures for securitization established
185-20 under Subsection (a) shall include rules and procedures for the
185-21 recovery of stranded costs under the terms of a rate order adopted
185-22 by the board of directors of the electric cooperative, which rate
185-23 order shall have the effect of a financing order.
185-24 (c) The rules and procedures established by the commission
185-25 under Subsection (b) shall include rules and procedures for the
185-26 issuance of transition bonds issued in a securitized financing
186-1 transaction. The issuance of any transition bonds issued in a
186-2 securitized financing transaction by an electric cooperative is
186-3 expressly authorized and shall be governed by the laws governing
186-4 the issuance of bonds or other obligations by the electric
186-5 cooperative. Findings made by the board of directors of an
186-6 electric cooperative in a rate order issued under the rules and
186-7 procedures described by this subsection shall be conclusive, and
186-8 any transition charges incorporated in the rate order to recover
186-9 the principal, interest, and all reasonable expenses associated
186-10 with any securitized financing transaction shall constitute
186-11 property rights, as described in Subchapter G, Chapter 39, and
186-12 shall otherwise conform in all material respects to the transition
186-13 charges provided by Subchapter G, Chapter 39.
186-14 Sec. 41.004. JURISDICTION OF COMMISSION. Except as
186-15 specifically provided otherwise in this chapter, the commission has
186-16 jurisdiction over electric cooperatives only as follows:
186-17 (1) to regulate wholesale transmission rates and
186-18 service, including terms of access, to the extent provided in
186-19 Subchapter A, Chapter 35;
186-20 (2) to regulate certification to the extent provided
186-21 in Chapter 37;
186-22 (3) to establish a code of conduct as provided in
186-23 Section 39.157(e) subject to Section 41.054;
186-24 (4) to establish terms and conditions, but not rates,
186-25 for open access to distribution facilities for electric
186-26 cooperatives providing customer choice, as provided in Section
187-1 39.203; and
187-2 (5) to require reports of electric cooperative
187-3 operations only to the extent necessary to:
187-4 (A) ensure the public safety;
187-5 (B) enable the commission to satisfy its
187-6 responsibilities relating to electric cooperatives under this
187-7 chapter;
187-8 (C) enable the commission to determine the
187-9 aggregate electric load and energy requirements in the state and
187-10 the resources available to serve that load; or
187-11 (D) enable the commission to determine
187-12 information relating to market power as provided in Section 39.155.
187-13 Sec. 41.005. LIMITATION ON MUNICIPAL AUTHORITY.
187-14 Notwithstanding any other provision of this title, a municipality
187-15 may not directly or indirectly regulate the rates, operations, and
187-16 services of an electric cooperative, except, with respect to
187-17 operations, to the extent necessary to protect the public health,
187-18 safety, or welfare. This section does not prohibit a municipality
187-19 from making a lawful charge for the use of public rights-of-way
187-20 within the municipality as provided by Section 182.025, Tax Code,
187-21 and Section 33.008. An electric cooperative shall be an electric
187-22 utility for purposes of Section 182.025, Tax Code, and Section
187-23 33.008.
187-24 (Sections 41.006-41.050 reserved for expansion
187-25 SUBCHAPTER B. ELECTRIC COOPERATIVE UTILITY CHOICE
187-26 Sec. 41.051. BOARD DECISION. (a) The board of directors
188-1 has the discretion to decide when or if the electric cooperative
188-2 will provide customer choice.
188-3 (b) Electric cooperatives that choose to participate in
188-4 customer choice may do so at any time on or after January 1, 2002,
188-5 by adoption of an appropriate resolution of the board of directors.
188-6 The decision to participate in customer choice by the adoption of a
188-7 resolution may be revoked only if no customer has opted for choice
188-8 within four years of the resolution's adoption. An electric
188-9 cooperative may initiate a customer choice pilot project at any
188-10 time.
188-11 Sec. 41.052. ELECTRIC COOPERATIVES NOT OFFERING CUSTOMER
188-12 CHOICE. (a) An electric cooperative that chooses not to
188-13 participate in customer choice may not offer electric energy at
188-14 unregulated prices directly to retail customers outside its
188-15 certificated retail service area.
188-16 (b) An electric cooperative under Subsection (a) retains the
188-17 right to offer and provide a full range of customer service and
188-18 pricing programs to the customers within its certificated retail
188-19 service area and to purchase and sell electric energy at wholesale
188-20 without geographic restriction.
188-21 (c) A generation and transmission electric cooperative may
188-22 offer electric energy at unregulated prices directly to retail
188-23 customers outside of its parent electric cooperatives' certificated
188-24 service areas only if a majority of the parent electric
188-25 cooperatives of the generation and transmission electric
188-26 cooperative have chosen to offer customer choice.
189-1 (d) A subsidiary of an electric cooperative may not provide
189-2 electric energy at unregulated prices outside of its parent
189-3 electric cooperative's certificated retail service area unless the
189-4 electric cooperative offers customer choice inside its certificated
189-5 retail service area.
189-6 Sec. 41.053. RETAIL CUSTOMER RIGHT OF CHOICE. (a) If an
189-7 electric cooperative chooses to participate in customer choice,
189-8 after that choice, all retail customers within the certificated
189-9 service area of the electric cooperative shall have the right of
189-10 customer choice, and the electric cooperative shall provide
189-11 nondiscriminatory open access for retail service.
189-12 (b) Notwithstanding Section 39.107, the metering function
189-13 may not be deemed a competitive service for customers of the
189-14 electric cooperative within that service area and may, at the
189-15 option of the electric cooperative, continue to be offered by the
189-16 electric cooperative as sole provider.
189-17 (c) On its initiation of customer choice, an electric
189-18 cooperative shall designate itself or another entity as the
189-19 provider of last resort for retail customers within the electric
189-20 cooperative's certificated service area and shall fulfill the role
189-21 of default provider of last resort in the event no other entity is
189-22 available to act in that capacity.
189-23 (d) If a retail electric provider fails to serve a customer
189-24 described in Subsection (c), on request by the customer, the
189-25 provider of last resort shall offer the customer the standard
189-26 retail service package for the appropriate customer class, with no
190-1 interruption of service, at a fixed, nondiscountable rate that is
190-2 at least sufficient to cover the reasonable costs of providing that
190-3 service, as approved by the board of directors.
190-4 (e) The board of directors may establish the procedures and
190-5 criteria for designating the provider of last resort and may
190-6 redesignate the provider of last resort according to a schedule it
190-7 considers appropriate.
190-8 Sec. 41.054. SERVICE OUTSIDE CERTIFICATED AREA.
190-9 (a) Notwithstanding any provisions of Chapter 161:
190-10 (1) an electric cooperative participating in customer
190-11 choice shall have the right to offer electric energy and related
190-12 services at unregulated prices directly to retail customers who
190-13 have customer choice without regard to geographic location; and
190-14 (2) any person, without restriction, except as may be
190-15 provided in the electric cooperative's articles of incorporation
190-16 and bylaws, may be a member of an electric cooperative.
190-17 (b) In providing service under Subsection (a) to retail
190-18 customers outside its certificated service area as that area exists
190-19 on the date of adoption of customer choice, an electric cooperative
190-20 becomes subject to commission jurisdiction as to the commission's
190-21 rules establishing a code of conduct regulating anticompetitive
190-22 practices under Section 39.157(e), except to the extent those rules
190-23 conflict with this chapter.
190-24 (c) For electric cooperatives participating in customer
190-25 choice, the commission shall have jurisdiction to establish terms
190-26 and conditions, but not rates, for access by other electric
191-1 providers to the electric cooperative's distribution facilities.
191-2 (d) Notwithstanding Subsections (b) and (c), the commission
191-3 shall make accommodation in the code of conduct for specific legal
191-4 requirements imposed by state or federal law applicable to electric
191-5 cooperatives. The commission shall accommodate the organizational
191-6 structures of electric cooperatives and may not prohibit an
191-7 electric cooperative and any related entity from sharing officers,
191-8 directors, or employees.
191-9 (e) The commission does not have jurisdiction to require the
191-10 unbundling of services or functions of, or to regulate the recovery
191-11 of stranded investment of, an electric cooperative or, except as
191-12 provided by this section, jurisdiction with respect to the rates,
191-13 terms, and conditions of service for retail customers of an
191-14 electric cooperative within the electric cooperative's certificated
191-15 service area.
191-16 (f) An electric cooperative shall maintain separate books
191-17 and records of its operations and the operations of any subsidiary
191-18 and shall ensure that the rates charged for provision of electric
191-19 service do not include any costs of its subsidiary or any other
191-20 costs not related to the provision of electric service.
191-21 Sec. 41.055. JURISDICTION OF BOARD OF DIRECTORS. A board of
191-22 directors has exclusive jurisdiction to:
191-23 (1) set all terms of access, conditions, and rates
191-24 applicable to services provided by the electric cooperative, except
191-25 as provided by Sections 41.054 and 41.056, including
191-26 nondiscriminatory and comparable rates for distribution but
192-1 excluding wholesale transmission rates, terms of access, and
192-2 conditions for wholesale transmission service set by the commission
192-3 under Subchapter A, Chapter 35, provided that the rates for
192-4 distribution established by the electric cooperative shall be
192-5 comparable to the distribution rates that apply to the electric
192-6 cooperative and its subsidiaries;
192-7 (2) determine whether to unbundle any energy-related
192-8 activities and, if the board of directors chooses to unbundle,
192-9 whether to do so structurally or functionally;
192-10 (3) reasonably determine the amount of the electric
192-11 cooperative's stranded investment;
192-12 (4) establish nondiscriminatory transition charges
192-13 reasonably designed to recover the stranded investment over an
192-14 appropriate period of time;
192-15 (5) determine the extent to which the electric
192-16 cooperative will provide various customer services, including
192-17 nonelectric services, or accept the services from other providers;
192-18 (6) manage and operate the electric cooperative's
192-19 utility systems, including exercise of control over resource
192-20 acquisition and any related expansion programs;
192-21 (7) establish and enforce service quality standards,
192-22 reliability standards, and consumer safeguards designed to protect
192-23 retail electric customers;
192-24 (8) determine whether a base rate reduction is
192-25 appropriate for the electric cooperative;
192-26 (9) determine any other utility matters that the board
193-1 of directors believes should be included;
193-2 (10) sell electric energy and capacity at wholesale,
193-3 regardless of whether the electric cooperative participates in
193-4 customer choice; and
193-5 (11) make any other decisions affecting the electric
193-6 cooperative's method of conducting business that are not
193-7 inconsistent with the provisions of this chapter.
193-8 Sec. 41.056. ANTICOMPETITIVE ACTIONS. (a) If, after notice
193-9 and hearing, the commission finds that an electric cooperative
193-10 providing customer choice has engaged in anticompetitive behavior
193-11 by not providing other retail electric providers with
193-12 nondiscriminatory terms and conditions of access to distribution
193-13 facilities or customers within the electric cooperative's
193-14 certificated service area that are comparable to the electric
193-15 cooperative's and its subsidiaries' terms and conditions of access
193-16 to distribution facilities or customers, the commission shall
193-17 notify the electric cooperative.
193-18 (b) The electric cooperative shall have three months to cure
193-19 the anticompetitive or noncompliant behavior described in
193-20 Subsection (a). If the behavior is not fully remedied within that
193-21 time, the commission may prohibit the electric cooperative or its
193-22 subsidiary from providing retail service outside its certificated
193-23 retail service area until the behavior is remedied.
193-24 Sec. 41.057. BILLING. (a) An electric cooperative that
193-25 opts for customer choice may continue to bill directly electric
193-26 customers located in its certificated service area for all
194-1 transmission and distribution services. The electric cooperative
194-2 may also bill directly for generation and customer services
194-3 provided by the electric cooperative or its subsidiaries to those
194-4 customers.
194-5 (b) A customer served by an electric cooperative for
194-6 transmission and distribution services and by a retail electric
194-7 provider for retail service has the option of being billed directly
194-8 by each service provider or receiving a single bill for
194-9 distribution, transmission, and generation services from the
194-10 electric cooperative.
194-11 Sec. 41.058. TARIFFS FOR OPEN ACCESS. An electric
194-12 cooperative that owns or operates transmission and distribution
194-13 facilities shall file tariffs implementing the open access rules
194-14 established by the commission under Section 39.203 with the
194-15 appropriate regulatory authorities having jurisdiction over the
194-16 transmission and distribution service of the electric cooperative
194-17 before the 90th day preceding the date the electric cooperative
194-18 offers customer choice.
194-19 Sec. 41.059. NO POWER TO AMEND CERTIFICATES. Nothing in
194-20 this chapter empowers a board of directors to issue, amend, or
194-21 rescind a certificate of public convenience and necessity granted
194-22 by the commission.
194-23 Sec. 41.060. CUSTOMER SERVICE INFORMATION. (a) The
194-24 commission shall keep information submitted by customers and retail
194-25 electric providers pertaining to the provision of electric service
194-26 by electric cooperatives.
195-1 (b) The commission shall notify the appropriate electric
195-2 cooperative of information submitted by a customer or retail
195-3 electric provider, and the electric cooperative shall respond to
195-4 the customer or retail electric provider. The electric cooperative
195-5 shall notify the commission of its response.
195-6 (c) The commission shall prepare a report for the Sunset
195-7 Advisory Commission that includes information submitted and
195-8 responses by electric cooperatives in accordance with the Sunset
195-9 Advisory Commission's schedule for reviewing the commission.
195-10 Sec. 41.061. RETAIL RATE CHANGES BY ELECTRIC COOPERATIVES.
195-11 (a) This section shall apply to retail rates of an electric
195-12 cooperative that has not adopted customer choice and to the retail
195-13 delivery rates of an electric cooperative that has adopted customer
195-14 choice. This section may not apply to rates for:
195-15 (1) sales of electric energy by an electric
195-16 cooperative that has adopted customer choice; or
195-17 (2) wholesale sales of electric energy.
195-18 (b) An electric cooperative may change its rates by:
195-19 (1) adopting a resolution approving the proposed
195-20 change;
195-21 (2) mailing notice of the proposed change to each
195-22 affected customer whose rate would be increased by the proposed
195-23 change at least 30 days before implementation of the proposed
195-24 change, which notice may be included in a monthly billing; and
195-25 (3) holding a meeting to discuss the proposed rate
195-26 changes with affected customers, if any change is expected to
196-1 increase total system annual revenues by more than $100,000 or one
196-2 percent, whichever is greater.
196-3 (c) An electric cooperative may implement the proposed rates
196-4 on completion of the requirements under Subsection (b), and those
196-5 rates shall remain in effect until changed by the electric
196-6 cooperative as provided by this section or, for rates other than
196-7 retail delivery rates, until this section is no longer applicable
196-8 because the electric cooperative adopts customer choice.
196-9 (d) The electric cooperative may reconsider a rate change at
196-10 any time and adjust the rate by board resolution without additional
196-11 notice or meeting of customers if the rate as adjusted is not
196-12 expected to increase the revenues from a customer class. However,
196-13 if notice is given to a customer class that would receive an
196-14 increase as a result of the adjustment, then the rates for the
196-15 customer class may be increased without additional meeting of the
196-16 customers. A customer may petition to appeal within the time
196-17 provided in Subsection (f).
196-18 (e) Retail rates set by an electric cooperative that has not
196-19 adopted customer choice and retail delivery rates set by an
196-20 electric cooperative that has adopted customer choice shall be just
196-21 and reasonable, not unreasonably preferential, prejudicial, or
196-22 discriminatory; provided, however, if the customer agrees, an
196-23 electric cooperative may charge a market-based rate to customers
196-24 who have energy supply options if rates are not increased for other
196-25 customers as a result.
196-26 (f) A customer of the electric cooperative who is adversely
197-1 affected by a rate setting resolution of the electric cooperative
197-2 is entitled to judicial review. A person initiates judicial review
197-3 by filing a petition in the district court of Travis County not
197-4 later than the 90th day after the resolution is implemented.
197-5 (g) The resolution of the electric cooperative setting
197-6 rates, as it may have been amended as described in Subsection (d),
197-7 shall be presumed valid, and the burden of showing that the
197-8 resolution is invalid rests on the persons challenging the
197-9 resolution. A court reviewing a change of a rate or rates by an
197-10 electric cooperative may consider any relevant factor including the
197-11 cost of providing service.
197-12 (h) If the court finds that the electric cooperative's
197-13 resolution setting rates violates the standards contained in
197-14 Subsection (e), or that the electric cooperative's rate violates
197-15 Subsection (e), the court shall enter an order:
197-16 (1) stating the specific basis for its determination
197-17 that the rates set in the electric cooperative's resolution violate
197-18 Subsection (e); and
197-19 (2) directing the electric cooperative to:
197-20 (A) set, within 60 days, revised retail rates
197-21 that do not violate the standards of Subsection (e); and
197-22 (B) refund or credit against future bills, at
197-23 the electric cooperative's option, revenues collected under the
197-24 rate found to violate the standards of Subsection (e) that exceed
197-25 the revenues that would have been collected under the revised
197-26 rates. The refund or credit shall be made over a period of not
198-1 more than 12 months, as determined by the court.
198-2 (i) The court may not enter an order delaying or prohibiting
198-3 implementation of a rate change or set revised rates either for the
198-4 period the challenged resolution was in effect or prospectively.
198-5 (j) A person having obtained an order of the court requiring
198-6 an electric cooperative to set revised retail rates pursuant to
198-7 Subsection (h)(2)(A) may, once the order is no longer subject to
198-8 appeal, initiate an original proceeding in the district court of
198-9 Travis County either to:
198-10 (1) seek enforcement of the court's order by writ of
198-11 mandamus if the electric cooperative has failed to adopt a
198-12 resolution approving revised rates within the time prescribed; or
198-13 (2) seek judicial review of the electric cooperative's
198-14 most current resolution setting rates as provided in this section,
198-15 if the electric cooperative has set revised rates pursuant to the
198-16 order of the court within the time prescribed. In the event of
198-17 such enforcement proceeding or judicial review the court may, in
198-18 addition to the other remedies provided for in this section, award
198-19 reasonable costs, including reasonable attorney's fees, to the
198-20 party prevailing on the case as a whole. Additionally, if the
198-21 court finds that either party has acted in bad faith solely for the
198-22 purpose of perpetuating the rate dispute between the parties, the
198-23 court may impose sanctions on the offending party in accordance
198-24 with the provisions of Subsections (b), (c), and (e), Section
198-25 10.004, Civil Practice and Remedies Code.
198-26 (k) An electric cooperative that has not adopted customer
199-1 choice and that has not changed each of its nonresidential rates
199-2 since January 1, 1999, shall, on or before May 1, 2002, adopt a
199-3 resolution setting rates. The resolution shall be subject to
199-4 judicial review as provided in this section whether or not any rate
199-5 is changed. In the event the electric cooperative fails to adopt a
199-6 resolution setting rates pursuant to this subsection, a customer
199-7 may petition for judicial review of the electric cooperative's
199-8 rates. A person initiates judicial review by filing a petition in
199-9 the district court of Travis County not later than November 1,
199-10 2002.
199-11 Sec. 41.062. ALLOCATION OF STRANDED INVESTMENT. Any
199-12 competition transition charge shall be allocated among retail
199-13 customer classes based on the relevant customer class
199-14 characteristics as of the end of the electric cooperative's most
199-15 recent fiscal year before implementation of customer choice, in
199-16 accordance with the methodology used to allocate the costs of the
199-17 underlying assets or expenses in the electric cooperative's most
199-18 recent cost of service study certified by a professional engineer
199-19 or certified public accountant or approved by the commission. In
199-20 multiply certificated areas, a retail customer may not avoid
199-21 stranded cost recovery charges by switching to another electric
199-22 cooperative, an electric utility, or a municipally owned utility.
199-23 Sec. 41.063. RETAIL RATES OF SUCCESSOR ELECTRIC UTILITY TO
199-24 ELECTRIC COOPERATIVE. (a) For purposes of this section, an
199-25 electric cooperative as described by Section 11.003(9)(C) is a
199-26 "successor cooperative" and the rates of a successor cooperative
200-1 are subject to this section. Effective January 1, 2000, a customer
200-2 of a successor cooperative who has reason to believe the customer
200-3 is being charged a rate in violation of Subsection (b) is entitled
200-4 to judicial review by filing a petition in a district court of
200-5 Travis County. The customer has the burden of proving the rate
200-6 violates Subsection (b).
200-7 (b) Retail rates of a successor cooperative shall be just
200-8 and reasonable and not unreasonably preferential, prejudicial, or
200-9 discriminatory. However, a successor cooperative may charge a
200-10 lower, market-based rate to customers who have energy supply
200-11 options, and in that event the standards that would otherwise
200-12 govern the rates charged to other customers are modified only to
200-13 the minimum extent necessary to enable those customers having
200-14 energy supply options to receive lower, market-based rates.
200-15 (c) A court reviewing a rate by a successor cooperative may
200-16 consider any relevant factor that may be considered by a court in
200-17 reviewing a decision of the commission, including the cost of
200-18 providing service.
200-19 (d) If the court finds that the successor cooperative's rate
200-20 violates the standards contained in Subsection (b), the court shall
200-21 enter an order:
200-22 (1) stating the specific basis for its determination
200-23 that the rate violates Subsection (b); and
200-24 (2) directing the successor cooperative to:
200-25 (A) set, within 60 days, a revised retail rate
200-26 that does not violate the standards of Subsection (b); and
201-1 (B) refund or credit against future bills, at
201-2 the successor cooperative's option, revenues collected under the
201-3 rate found to violate the standards of Subsection (b) that exceed
201-4 the revenues that would have been collected under the revised
201-5 rates.
201-6 (e) The refund or credit shall be made over a period of not
201-7 more than 12 months, as determined by the electric cooperative. If
201-8 the court has ordered relief under Subsection (d), and after 60
201-9 days the court finds that the successor cooperative's resolution
201-10 setting rates still violates the standards contained in Subsection
201-11 (b), the court shall enter an order imposing any sanction
201-12 authorized by Section 10.004(c), Civil Practice and Remedies Code.
201-13 (f) No remedy other than or additional to a remedy under
201-14 Subsections (d) and (e) may be ordered by the court. The court may
201-15 not set revised rates either for the period the challenged
201-16 resolution was in effect or prospectively.
201-17 (Sections 41.064-41.100 reserved for expansion
201-18 SUBCHAPTER C. RIGHTS NOT AFFECTED
201-19 Sec. 41.101. INTERFERENCE WITH CONTRACT. (a) This subtitle
201-20 may not interfere with or abrogate the rights or obligations of
201-21 parties, including a retail or wholesale customer, to a contract
201-22 with an electric cooperative or its subsidiary.
201-23 (b) No provision of this subtitle may interfere with or be
201-24 deemed to abrogate the rights or obligations of a party under a
201-25 contract or an agreement concerning certificated service areas.
201-26 Sec. 41.102. ACCESS TO WHOLESALE MARKET. Nothing in this
202-1 subtitle shall limit the access of an electric cooperative or its
202-2 subsidiary, either on its own behalf or on behalf of its customers,
202-3 to the wholesale electric market.
202-4 Sec. 41.103. PROTECTION OF BONDHOLDERS. Nothing in this
202-5 subtitle or any rule adopted under this subtitle shall impair
202-6 contracts, covenants, or obligations between an electric
202-7 cooperative and its lenders and holders of bonds issued on behalf
202-8 of or by the electric cooperative.
202-9 Sec. 41.104. TAX-EXEMPT STATUS. Nothing in this subtitle
202-10 may impair the tax-exempt status of electric cooperatives, nor
202-11 shall anything in this subtitle compel any electric cooperative to
202-12 use its facilities in a manner that violates any contractual
202-13 provisions, bond covenants, or other restrictions applicable to
202-14 facilities financed by tax-exempt or federally insured or
202-15 guaranteed debt.
202-16 SECTION 40. Subchapter A, Chapter 163, Utilities Code, is
202-17 amended by adding Section 163.002 to read as follows:
202-18 Sec. 163.002. REPORT ON PROBLEMS. (a) The commission shall
202-19 analyze the financial problems of the municipal power agency
202-20 described by Subsection (b). Before September 1, 2000, the
202-21 commission shall present recommendations for solving the problems
202-22 to the speaker of the house of representatives, the lieutenant
202-23 governor, the members of the legislature, and the municipal power
202-24 agency.
202-25 (b) This subsection applies to a municipal power agency as
202-26 defined by this chapter that has stranded costs in excess of $6,000
203-1 per customer as determined by the April 1998 Report to the Texas
203-2 Senate Interim Committee on Electric Utility Restructuring entitled
203-3 "Potentially Strandable Investment (ECOM) Report: 1998 Update."
203-4 SECTION 41. Section 252.022, Local Government Code, is
203-5 amended by amending Subsection (a) and by adding Subsection (c) to
203-6 read as follows:
203-7 (a) This chapter does not apply to an expenditure for:
203-8 (1) a procurement made because of a public calamity
203-9 that requires the immediate appropriation of money to relieve the
203-10 necessity of the municipality's residents or to preserve the
203-11 property of the municipality;
203-12 (2) a procurement necessary to preserve or protect the
203-13 public health or safety of the municipality's residents;
203-14 (3) a procurement necessary because of unforeseen
203-15 damage to public machinery, equipment, or other property;
203-16 (4) a procurement for personal, professional, or
203-17 planning services;
203-18 (5) a procurement for work that is performed and paid
203-19 for by the day as the work progresses;
203-20 (6) a purchase of land or a right-of-way;
203-21 (7) a procurement of items that are available from
203-22 only one source, including:
203-23 (A) items that are available from only one
203-24 source because of patents, copyrights, secret processes, or natural
203-25 monopolies;
203-26 (B) films, manuscripts, or books;
204-1 (C) [electricity,] gas, water, and other utility
204-2 services;
204-3 (D) captive replacement parts or components for
204-4 equipment;
204-5 (E) books, papers, and other library materials
204-6 for a public library that are available only from the persons
204-7 holding exclusive distribution rights to the materials; and
204-8 (F) management services provided by a nonprofit
204-9 organization to a municipal museum, park, zoo, or other facility to
204-10 which the organization has provided significant financial or other
204-11 benefits;
204-12 (8) a purchase of rare books, papers, and other
204-13 library materials for a public library;
204-14 (9) paving drainage, street widening, and other public
204-15 improvements, or related matters, if at least one-third of the cost
204-16 is to be paid by or through special assessments levied on property
204-17 that will benefit from the improvements;
204-18 (10) a public improvement project, already in
204-19 progress, authorized by the voters of the municipality, for which
204-20 there is a deficiency of funds for completing the project in
204-21 accordance with the plans and purposes authorized by the voters;
204-22 (11) a payment under a contract by which a developer
204-23 participates in the construction of a public improvement as
204-24 provided by Subchapter C, Chapter 212;
204-25 (12) personal property sold:
204-26 (A) at an auction by a state licensed
205-1 auctioneer;
205-2 (B) at a going out of business sale held in
205-3 compliance with Subchapter F, Chapter 17, Business & Commerce Code;
205-4 (C) by a political subdivision of this state, a
205-5 state agency of this state, or an entity of the federal government;
205-6 or
205-7 (D) under an interlocal contract for cooperative
205-8 purchasing administered by a regional planning commission
205-9 established under Chapter 391;
205-10 (13) services performed by blind or severely disabled
205-11 persons; [or]
205-12 (14) goods purchased by a municipality for subsequent
205-13 retail sale by the municipality; or
205-14 (15) electricity.
205-15 (c) This chapter does not apply to expenditures by a
205-16 municipally owned electric or gas utility or unbundled divisions of
205-17 a municipally owned electric or gas utility in connection with any
205-18 purchases by the municipally owned utility or divisions of a
205-19 municipally owned utility made in accordance with procurement
205-20 procedures adopted by a resolution of the body vested with
205-21 authority for management and operation of the municipally owned
205-22 utility or its divisions that sets out the public purpose to be
205-23 achieved by those procedures. This subsection may not be deemed to
205-24 exempt a municipally owned utility from any other applicable
205-25 statute, charter provision, or ordinance.
205-26 SECTION 42. Subtitle C, Title 9, Local Government Code, is
206-1 amended by adding Chapter 303 to read as follows:
206-2 CHAPTER 303. ENERGY AGGREGATION MEASURES FOR LOCAL GOVERNMENTS
206-3 Sec. 303.001. AGGREGATION BY POLITICAL SUBDIVISIONS.
206-4 (a) In this chapter, "political subdivision" means a county,
206-5 municipality, hospital district, or any other political subdivision
206-6 receiving electric service from an entity that has implemented
206-7 customer choice, as defined in Section 31.002, Utilities Code.
206-8 (b) A political subdivision may join with another political
206-9 subdivision or subdivisions to form a political subdivision
206-10 corporation or corporations to act as an agent to negotiate the
206-11 purchase of electricity, or to likewise aid or act on behalf of the
206-12 political subdivisions for which the corporation is created, with
206-13 respect to their own electricity use for their respective public
206-14 facilities.
206-15 (c) The articles of incorporation and the bylaws of a
206-16 political subdivision corporation must be approved by ordinance,
206-17 resolution, or order adopted by the governing body of each
206-18 political subdivision for which the corporation is created.
206-19 (d) A political subdivision corporation may negotiate on
206-20 behalf of its incorporating political subdivisions for the purchase
206-21 of electricity, make contracts for the purchase of electricity,
206-22 purchase electricity, and take any other action necessary to
206-23 purchase electricity for use in the public facilities of the
206-24 political subdivision or subdivisions represented by the political
206-25 subdivision corporation. In this subsection, "electricity" means
206-26 electric energy, capacity, energy services, ancillary services, or
207-1 other electric services for retail or wholesale consumption by the
207-2 political subdivisions.
207-3 (e) A political subdivision corporation may recover the
207-4 expenses of the political subdivision corporation through the
207-5 assessment of dues to the incorporating political subdivisions or
207-6 through an aggregation fee charged per kilowatt hour, or a
207-7 combination of both.
207-8 (f) A political subdivision corporation may appear on behalf
207-9 of its incorporating political subdivisions before the Public
207-10 Utility Commission of Texas, the Railroad Commission of Texas, the
207-11 Texas Natural Resource Conservation Commission, any other
207-12 governmental agency or regulatory authority, the Texas Legislature,
207-13 and the courts.
207-14 (g) A political subdivision corporation has the powers of a
207-15 corporation created and incorporated pursuant to the provisions of
207-16 the Texas Non-Profit Corporation Act (Article 1396-1.01 et seq.,
207-17 Vernon's Texas Civil Statutes) and such other powers as specified
207-18 in Section 39.3545, Utilities Code.
207-19 (h) The provisions of the Texas Non-Profit Corporation Act
207-20 (Article 1396-1.01 et seq., Vernon's Texas Civil Statutes) relating
207-21 to powers, standards of conduct, and interests in contracts apply
207-22 to the directors and officers of a political subdivision
207-23 corporation.
207-24 (i) A member of the board of directors of a political
207-25 subdivision corporation:
207-26 (1) is not a public official by virtue of that
208-1 position; and
208-2 (2) unless otherwise ineligible, may be elected to
208-3 serve as an official of a political subdivision or be employed by a
208-4 political subdivision.
208-5 Sec. 303.002. AGGREGATION BY POLITICAL SUBDIVISION FOR
208-6 CITIZENS. (a) A political subdivision aggregator may negotiate
208-7 for the purchase of electricity and energy services on behalf of
208-8 the citizens of the political subdivision. The citizens must
208-9 affirmatively request to be included in the aggregation services by
208-10 the political subdivision aggregator.
208-11 (b) A political subdivision may contract with a third party
208-12 or another aggregator to administer the aggregation of electricity
208-13 and energy services purchased under Subsection (a).
208-14 (c) The political subdivision aggregator may use any mailing
208-15 from the subdivision to invite participation by its citizens.
208-16 SECTION 43. Section 272.001, Local Government Code, is
208-17 amended by adding Subsection (j) to read as follows:
208-18 (j) This section does not apply to sales or exchanges of
208-19 land owned by a municipality operating a municipally owned electric
208-20 or gas utility if the land is held or managed by the municipally
208-21 owned utility, or by a division of the municipally owned electric
208-22 or gas utility that constitutes the unbundled electric or gas
208-23 operations of the utility, provided that the governing body of the
208-24 municipally owned utility shall adopt a resolution stating the
208-25 conditions and circumstances for the sale or exchange and the
208-26 public purpose that will be achieved by the sale or exchange. For
209-1 purposes of this subsection, "municipally owned utility" includes a
209-2 river authority engaged in the generation, transmission, or
209-3 distribution of electric energy to the public, and "unbundled"
209-4 operations are those operations of the utility that have, in the
209-5 discretion of the utility's governing body, been functionally
209-6 separated.
209-7 SECTION 44. Subsection (c), Section 402.002, Local
209-8 Government Code, is amended to read as follows:
209-9 (c) The municipality may manufacture its own electricity,
209-10 gas, or anything else needed or used by the public. It may
209-11 purchase, and make contracts for the purchase of, gas, electricity,
209-12 oil, or any other commodity or article used by the public and may
209-13 sell it to the public on terms as provided by the municipal
209-14 charter, ordinance, or resolution of the governing body of the
209-15 municipally owned utility.
209-16 SECTION 45. Subchapter D, Chapter 551, Government Code, is
209-17 amended by adding Section 551.086 to read as follows:
209-18 Sec. 551.086. CERTAIN PUBLIC POWER UTILITIES: COMPETITIVE
209-19 MATTERS. (a) Notwithstanding anything in this chapter to the
209-20 contrary, the rules provided by this section apply to competitive
209-21 matters of a public power utility.
209-22 (b) In this section:
209-23 (1) "Public power utility" means an entity providing
209-24 electric or gas utility services that is subject to the provisions
209-25 of this chapter.
209-26 (2) "Public power utility governing body" means the
210-1 board of trustees or other applicable governing body, including a
210-2 city council, of a public power utility.
210-3 (3) "Competitive matter" means a utility-related
210-4 matter that the public power utility governing body in good faith
210-5 determines by a vote under this section is related to the public
210-6 power utility's competitive activity, including commercial
210-7 information, and would, if disclosed, give advantage to competitors
210-8 or prospective competitors but may not be deemed to include the
210-9 following categories of information:
210-10 (A) information relating to the provision of
210-11 distribution access service, including the terms and conditions of
210-12 the service and the rates charged for the service but not including
210-13 information concerning utility-related services or products that
210-14 are competitive;
210-15 (B) information relating to the provision of
210-16 transmission service that is required to be filed with the Public
210-17 Utility Commission of Texas, subject to any confidentiality
210-18 provided for under the rules of the commission;
210-19 (C) information for the distribution system
210-20 pertaining to reliability and continuity of service, to the extent
210-21 not security-sensitive, that relates to emergency management,
210-22 identification of critical loads such as hospitals and police,
210-23 records of interruption, and distribution feeder standards;
210-24 (D) any substantive rule of general
210-25 applicability regarding service offerings, service regulation,
210-26 customer protections, or customer service adopted by the public
211-1 power utility as authorized by law;
211-2 (E) aggregate information reflecting receipts or
211-3 expenditures of funds of the public power utility, of the type that
211-4 would be included in audited financial statements;
211-5 (F) information relating to equal employment
211-6 opportunities for minority groups, as filed with local, state, or
211-7 federal agencies;
211-8 (G) information relating to the public power
211-9 utility's performance in contracting with minority business
211-10 entities;
211-11 (H) information relating to nuclear
211-12 decommissioning trust agreements, of the type required to be
211-13 included in audited financial statements;
211-14 (I) information relating to the amount and
211-15 timing of any transfer to an owning city's general fund;
211-16 (J) information relating to environmental
211-17 compliance as required to be filed with any local, state, or
211-18 national environmental authority, subject to any confidentiality
211-19 provided under the rules of those authorities;
211-20 (K) names of public officers of the public power
211-21 utility and the voting records of those officers for all matters
211-22 other than those within the scope of a competitive resolution
211-23 provided for by this section;
211-24 (L) a description of the public power utility's
211-25 central and field organization, including the established places at
211-26 which the public may obtain information, submit information and
212-1 requests, or obtain decisions and the identification of employees
212-2 from whom the public may obtain information, submit information or
212-3 requests, or obtain decisions; or
212-4 (M) information identifying the general course
212-5 and method by which the public power utility's functions are
212-6 channeled and determined, including the nature and requirements of
212-7 all formal and informal policies and procedures.
212-8 (c) This chapter does not require a public power utility
212-9 governing body to conduct an open meeting to deliberate, vote, or
212-10 take final action on any competitive matter, as that term is
212-11 defined in Subsection (b)(3). Before a public power utility
212-12 governing body may deliberate, vote, or take final action on any
212-13 competitive matter in a closed meeting, the public power utility
212-14 governing body must first make a good faith determination, by
212-15 majority vote of its members, that the matter is a competitive
212-16 matter that satisfies the requirements of Subsection (b)(3). The
212-17 vote shall be taken during the closed meeting and be included in
212-18 the certified agenda or tape recording of the closed meeting. If a
212-19 public power utility governing body fails to determine by that vote
212-20 that the matter satisfies the requirements of Subsection (b)(3),
212-21 the public power utility governing body may not deliberate or take
212-22 any further action on the matter in the closed meeting. This
212-23 section does not limit the right of a public power utility
212-24 governing body to hold a closed session under any other exception
212-25 provided for in this chapter.
212-26 (d) For purposes of Section 551.041, the notice of the
213-1 subject matter of an item that may be considered as a competitive
213-2 matter under this section is required to contain no more than a
213-3 general representation of the subject matter to be considered, such
213-4 that the competitive activity of the public power utility with
213-5 respect to the issue in question is not compromised or disclosed.
213-6 (e) With respect to municipally owned utilities subject to
213-7 this section, this section shall apply whether or not the
213-8 municipally owned utility has adopted customer choice or serves in
213-9 a multiply certificated service area under the Utilities Code.
213-10 (f) Nothing in this section is intended to preclude the
213-11 application of the enforcement and remedies provisions of
213-12 Subchapter G.
213-13 SECTION 46. Subchapter C, Chapter 552, Government Code, is
213-14 amended by adding Section 552.131 to read as follows:
213-15 Sec. 552.131. EXCEPTION: PUBLIC POWER UTILITY COMPETITIVE
213-16 MATTERS. (a) In this section:
213-17 (1) "Public power utility" means an entity providing
213-18 electric or gas utility services that is subject to the provisions
213-19 of this chapter.
213-20 (2) "Public power utility governing body" means the
213-21 board of trustees or other applicable governing body, including a
213-22 city council, of a public power utility.
213-23 (3) "Competitive matter" means a utility-related
213-24 matter that the public power utility governing body in good faith
213-25 determines by a vote under this section is related to the public
213-26 power utility's competitive activity, including commercial
214-1 information, and would, if disclosed, give advantage to competitors
214-2 or prospective competitors but may not be deemed to include the
214-3 following categories of information:
214-4 (A) information relating to the provision of
214-5 distribution access service, including the terms and conditions of
214-6 the service and the rates charged for the service but not including
214-7 information concerning utility-related services or products that
214-8 are competitive;
214-9 (B) information relating to the provision of
214-10 transmission service that is required to be filed with the Public
214-11 Utility Commission of Texas, subject to any confidentiality
214-12 provided for under the rules of the commission;
214-13 (C) information for the distribution system
214-14 pertaining to reliability and continuity of service, to the extent
214-15 not security-sensitive, that relates to emergency management,
214-16 identification of critical loads such as hospitals and police,
214-17 records of interruption, and distribution feeder standards;
214-18 (D) any substantive rule of general
214-19 applicability regarding service offerings, service regulation,
214-20 customer protections, or customer service adopted by the public
214-21 power utility as authorized by law;
214-22 (E) aggregate information reflecting receipts or
214-23 expenditures of funds of the public power utility, of the type that
214-24 would be included in audited financial statements;
214-25 (F) information relating to equal employment
214-26 opportunities for minority groups, as filed with local, state, or
215-1 federal agencies;
215-2 (G) information relating to the public power
215-3 utility's performance in contracting with minority business
215-4 entities;
215-5 (H) information relating to nuclear
215-6 decommissioning trust agreements, of the type required to be
215-7 included in audited financial statements;
215-8 (I) information relating to the amount and
215-9 timing of any transfer to an owning city's general fund;
215-10 (J) information relating to environmental
215-11 compliance as required to be filed with any local, state, or
215-12 national environmental authority, subject to any confidentiality
215-13 provided under the rules of those authorities;
215-14 (K) names of public officers of the public power
215-15 utility and the voting records of those officers for all matters
215-16 other than those within the scope of a competitive resolution
215-17 provided for by this section;
215-18 (L) a description of the public power utility's
215-19 central and field organization, including the established places at
215-20 which the public may obtain information, submit information and
215-21 requests, or obtain decisions and the identification of employees
215-22 from whom the public may obtain information, submit information or
215-23 requests, or obtain decisions; or
215-24 (M) information identifying the general course
215-25 and method by which the public power utility's functions are
215-26 channeled and determined, including the nature and requirements of
216-1 all formal and informal policies and procedures.
216-2 (b) Information or records are excepted from the
216-3 requirements of Section 552.021 if the information or records are
216-4 reasonably related to a competitive matter, as defined in this
216-5 section. Excepted information or records include the text of any
216-6 resolution of the public power utility governing body determining
216-7 which issues, activities, or matters constitute competitive
216-8 matters. Information or records of a municipally owned utility
216-9 that are reasonably related to a competitive matter are not subject
216-10 to disclosure under this chapter, whether or not, under the
216-11 Utilities Code, the municipally owned utility has adopted customer
216-12 choice or serves in a multiply certificated service area. This
216-13 section does not limit the right of a public power utility
216-14 governing body to withhold from disclosure information deemed to be
216-15 within the scope of any other exception provided for in this
216-16 chapter, subject to the provisions of this chapter.
216-17 (c) In connection with any request for an opinion of the
216-18 attorney general under Section 552.301 with respect to information
216-19 alleged to fall under this exception, in rendering a written
216-20 opinion under Section 552.306 the attorney general shall find the
216-21 requested information to be outside the scope of this exception
216-22 only if the attorney general determines, based on the information
216-23 provided in connection with the request:
216-24 (1) that the public power utility governing body has
216-25 failed to act in good faith in making the determination that the
216-26 issue, matter, or activity in question is a competitive matter; or
217-1 (2) that the information or records sought to be
217-2 withheld are not reasonably related to a competitive matter.
217-3 SECTION 47. Subsection (d), Section 791.011, Government
217-4 Code, is amended to read as follows:
217-5 (d) An interlocal contract must:
217-6 (1) be authorized by the governing body of each party
217-7 to the contract unless a party to the contract is a municipally
217-8 owned electric utility, in which event the governing body may
217-9 establish procedures for entering into interlocal contracts that do
217-10 not exceed $100,000 without requiring the approval of the governing
217-11 body;
217-12 (2) state the purpose, terms, rights, and duties of
217-13 the contracting parties; and
217-14 (3) specify that each party paying for the performance
217-15 of governmental functions or services must make those payments from
217-16 current revenues available to the paying party.
217-17 SECTION 48. Subchapter A, Chapter 2256, Government Code, is
217-18 amended by adding Section 2256.0201 to read as follows:
217-19 Sec. 2256.0201. AUTHORIZED INVESTMENTS; MUNICIPAL UTILITY.
217-20 (a) A municipality that owns a municipal electric utility that is
217-21 engaged in the distribution and sale of electric energy or natural
217-22 gas to the public may enter into a hedging contract and related
217-23 security and insurance agreements in relation to fuel oil, natural
217-24 gas, and electric energy to protect against loss due to price
217-25 fluctuations. A hedging transaction must comply with the
217-26 regulations of the Commodity Futures Trading Commission and the
218-1 Securities and Exchange Commission. If there is a conflict between
218-2 the municipal charter of the municipality and this chapter, this
218-3 chapter prevails.
218-4 (b) A payment by a municipally owned electric or gas utility
218-5 under a hedging contract or related agreement in relation to fuel
218-6 supplies or fuel reserves is a fuel expense, and the utility may
218-7 credit any amounts it receives under the contract or agreement
218-8 against fuel expenses.
218-9 (c) The governing body of a municipally owned electric or
218-10 gas utility or the body vested with power to manage and operate the
218-11 municipally owned electric or gas utility may set policy regarding
218-12 hedging transactions.
218-13 (d) In this section, "hedging" means the buying and selling
218-14 of fuel oil, natural gas, and electric energy futures or options or
218-15 similar contracts on those commodity futures as a protection
218-16 against loss due to price fluctuation.
218-17 SECTION 49. Section 52.133, Natural Resources Code, is
218-18 amended by amending Subsections (a), (c), and (d) and adding
218-19 Subsection (f) to read as follows:
218-20 (a) Each oil or gas lease covering land leased by the board,
218-21 by a board for lease [other than the Board for Lease of University
218-22 Lands], or by the surface owner of land under which the state owns
218-23 the minerals, commonly referred to as Relinquishment Act land,
218-24 which shall be subject to approval by the commissioner before it is
218-25 effective, shall include a provision granting the board authorized
218-26 to lease the land or the owner of the soil of Relinquishment Act
219-1 land and the commissioner authority to take their royalty in kind,
219-2 and the commissioner and the boards for lease may include any other
219-3 reasonable provisions that are not inconsistent with this section.
219-4 (c) The commissioner, the owner of the soil under Subchapter
219-5 F [of this chapter], or the commissioner[,] acting on the behalf of
219-6 and at the direction of an owner of the soil under Subchapter F [of
219-7 this chapter], the board, or a board for lease, or at the direction
219-8 of the Board for Lease of University Lands, may negotiate and
219-9 execute contracts or any other instruments or agreements necessary
219-10 to dispose of or enhance their portion of the royalty taken in
219-11 kind, including contracts for sale, marketing, purchase,
219-12 transportation, including purchase and exchange agreements
219-13 necessary to transport gas, and storage and including insurance
219-14 contracts or other agreements, to secure or guarantee payment.
219-15 (d) The commissioner, the owner of the soil under Subchapter
219-16 F, or the commissioner acting on behalf of and at the direction of
219-17 an owner of the soil under Subchapter F, the board, or a board for
219-18 lease may negotiate and execute contracts or any other instruments
219-19 or agreements necessary to convert that portion of the royalty
219-20 taken in kind into other forms of energy, including electricity.
219-21 [This section does not apply to or have any effect on the Board for
219-22 Lease of University Lands or any lease executed on university
219-23 land.]
219-24 (f) For the purposes of this section, royalty taken in kind
219-25 includes oil or gas sold or marketed by the commissioner that has
219-26 been produced on state mineral lands or from the first three miles
220-1 of federal waters adjacent to the state boundaries, also known as
220-2 the 8g zone.
220-3 SECTION 50. Section 53.026, Natural Resources Code, is
220-4 amended to read as follows:
220-5 Sec. 53.026. In Kind Royalty. (a) The commissioner or the
220-6 commissioner acting on behalf of and at the direction of the board
220-7 or a board for lease may negotiate and execute a contract or any
220-8 other instrument or agreement necessary to dispose of or enhance
220-9 their portion of the royalty taken in kind, including contracts [a
220-10 contract] for sale, purchase, transportation, or storage.
220-11 (b) The commissioner or the commissioner acting on behalf of
220-12 and at the direction of the board or a board for lease may
220-13 negotiate and execute a contract or any other instrument or
220-14 agreement necessary to convert that portion of the royalty taken in
220-15 kind to other forms of energy, including electricity.
220-16 (c) This section shall not be construed to surrender or in
220-17 any way affect the right of the state under an existing or future
220-18 lease to receive monetary royalty from its lessee.
220-19 SECTION 51. Section 53.077, Natural Resources Code, is
220-20 amended to read as follows:
220-21 Sec. 53.077. In Kind Royalty. (a) The commissioner, each
220-22 owner of the soil under this subchapter, or the commissioner acting
220-23 on the behalf of and at the direction of an owner of the soil under
220-24 this subchapter may negotiate and execute a contract or any other
220-25 instrument or agreement necessary to dispose of or enhance their
220-26 portion of the royalty taken in kind, including a contract for
221-1 sale, transportation, or storage.
221-2 (b) The commissioner, each owner of the soil under this
221-3 subchapter, or the commissioner acting on behalf of and at the
221-4 direction of the owner of the soil under this subchapter may
221-5 negotiate and execute a contract or any other instrument or
221-6 agreement necessary to convert that portion of the royalty taken in
221-7 kind to other forms of energy, including electricity.
221-8 (c) This section shall not be construed to surrender or in
221-9 any way affect the right of the state or the owner of the soil
221-10 under an existing or future lease to receive monetary royalty from
221-11 its lessee.
221-12 SECTION 52. Chapter 245, Acts of the 67th Legislature,
221-13 Regular Session, 1981 (Article 717p, Vernon's Texas Civil
221-14 Statutes), is amended by adding Section 4C to read as follows:
221-15 Sec. 4C. (a) This section applies only to a river authority
221-16 that is engaged in the distribution and sale of electric energy to
221-17 the public.
221-18 (b) Notwithstanding any other law, a river authority may:
221-19 (1) provide transmission services, as defined by the
221-20 Utilities Code or the Public Utility Commission of Texas, on a
221-21 regional basis to any eligible transmission customer at any
221-22 location within or outside the boundaries of the river authority;
221-23 and
221-24 (2) acquire, including by lease-purchase, lease from
221-25 or to any person, finance, construct, rebuild, operate, or sell
221-26 electric transmission facilities at any location within or outside
222-1 the boundaries of the river authority; provided, however, that
222-2 nothing in this section shall:
222-3 (A) allow a river authority to construct
222-4 transmission facilities to an ultimate consumer of electricity to
222-5 enable an ultimate consumer to bypass the transmission or
222-6 distribution facilities of its existing provider; or
222-7 (B) relieve a river authority from an obligation
222-8 to comply with the provisions of the Utilities Code concerning a
222-9 certificate of convenience and necessity for a transmission
222-10 facility.
222-11 SECTION 53. Sections 1 and 2, Article 1115a, Revised
222-12 Statutes, are amended to read as follows:
222-13 Sec. 1. This article applies only to a home-rule
222-14 municipality that owns an electric utility system, that by
222-15 ordinance or charter elects to have the management and control of
222-16 the system governed by a board of trustees [this article], and
222-17 that:
222-18 (1) has outstanding obligations payable in whole or
222-19 part [solely] from and secured by a lien on and pledge of net
222-20 revenues of the system; or
222-21 (2) issues obligations that are payable in whole or
222-22 part [solely] from and secured by a lien on and pledge of the net
222-23 revenues of the system and that are approved by the attorney
222-24 general.
222-25 Sec. 2. A municipality by ordinance may transfer management
222-26 and control of the electric utility system to a [five-member] board
223-1 of trustees appointed by the municipality's governing body. The
223-2 municipality by ordinance shall determine [set] the qualifications
223-3 for appointment to the board and the number of members. The
223-4 municipality may by ordinance vest the power to establish rates and
223-5 related terms and conditions for its municipally owned electric
223-6 utility in the board of trustees appointed under this section.
223-7 SECTION 54. Subsection (a), Section 151.0101, Tax Code, is
223-8 amended to read as follows:
223-9 (a) "Taxable services" means:
223-10 (1) amusement services;
223-11 (2) cable television services;
223-12 (3) personal services;
223-13 (4) motor vehicle parking and storage services;
223-14 (5) the repair, remodeling, maintenance, and
223-15 restoration of tangible personal property, except:
223-16 (A) aircraft;
223-17 (B) a ship, boat, or other vessel, other than:
223-18 (i) a taxable boat or motor as defined by
223-19 Section 160.001;
223-20 (ii) a sports fishing boat; or
223-21 (iii) any other vessel used for pleasure;
223-22 (C) the repair, maintenance, and restoration of
223-23 a motor vehicle; and
223-24 (D) the repair, maintenance, creation, and
223-25 restoration of a computer program, including its development and
223-26 modification, not sold by the person performing the repair,
224-1 maintenance, creation, or restoration service;
224-2 (6) telecommunications services;
224-3 (7) credit reporting services;
224-4 (8) debt collection services;
224-5 (9) insurance services;
224-6 (10) information services;
224-7 (11) real property services;
224-8 (12) data processing services;
224-9 (13) real property repair and remodeling;
224-10 (14) security services; [and]
224-11 (15) telephone answering services; and
224-12 (16) a sale by a transmission and distribution
224-13 utility, as defined in Section 31.002, Utilities Code, of
224-14 transmission or delivery of service directly to an electricity
224-15 end-use customer whose consumption of electricity is subject to
224-16 taxation under this chapter.
224-17 SECTION 55. Subdivision (1), Section 182.021, Tax Code, is
224-18 amended to read as follows:
224-19 (1) "Utility company" means a person:
224-20 (A) who owns or operates a gas[, electric light,
224-21 electric power,] or water works, or water [and light] plant used
224-22 for local sale and distribution located within an incorporated city
224-23 or town in this state; or
224-24 (B) who owns or operates an electric light or
224-25 electric power works, or light plant used for local sale and
224-26 distribution located within an incorporated city or town in this
225-1 state, or who is a retail electric provider, as that term is
225-2 defined in Section 31.002, Utilities Code, that makes local sales
225-3 within an incorporated city or town in this state; provided,
225-4 however, that a person who owns an electric light or electric power
225-5 or gas plant used for distribution but who does not make retail
225-6 sales to the ultimate consumer within an incorporated city or town
225-7 in this state is not included in this definition.
225-8 SECTION 56. Effective January 1, 2002, Section 182.025, Tax
225-9 Code, is amended to read as follows:
225-10 Sec. 182.025. CHARGES BY A CITY. (a) An incorporated city
225-11 or town may make a reasonable lawful charge for the use of a city
225-12 street, alley, or public way by a public utility in the course of
225-13 its business.
225-14 (b) The total charges, however designated or measured, may
225-15 not exceed two percent of the gross receipts of the public utility
225-16 for the sale of gas[, electric energy,] or water within the city.
225-17 (c) The total charges, however designated or measured,
225-18 relating to distribution service of an electric utility or
225-19 transmission and distribution utility within the city may not
225-20 exceed the amount or amounts prescribed by Section 33.008,
225-21 Utilities Code. The charges paid by an electric utility or
225-22 transmission and distribution utility under this subsection may be
225-23 only for distribution service.
225-24 (d) If a public utility taxed under this subchapter pays a
225-25 special tax, rental, contribution, or charge under a contract or
225-26 franchise executed before May 1, 1941, the city shall credit the
226-1 payment against the amount owed by the public utility on any charge
226-2 allowable under Subsection (a) of this section.
226-3 (e) In this section:
226-4 (1) "Distribution service" has the meaning assigned by
226-5 Section 33.008, Utilities Code.
226-6 (2) "Electric utility" has the meaning assigned by
226-7 Section 31.002, Utilities Code.
226-8 (3) "Public utility" means:
226-9 (A) a person who owns or operates a gas or water
226-10 works or water plant used for local sale and distribution located
226-11 within an incorporated city or town in this state; or
226-12 (B) an electric utility or transmission and
226-13 distribution utility providing distribution service within an
226-14 incorporated city or town in this state.
226-15 (4) "Transmission and distribution utility" has the
226-16 meaning assigned by Section 31.002, Utilities Code.
226-17 SECTION 57. Subchapter B, Chapter 182, Tax Code, is amended
226-18 by adding Section 182.027 to read as follows:
226-19 Sec. 182.027. NO EXEMPTION. Notwithstanding anything to the
226-20 contrary in Chapter 161, Utilities Code, this subchapter applies to
226-21 a retail electric provider as defined in Section 31.002(17),
226-22 Utilities Code, that is owned, operated, or controlled by an
226-23 electric cooperative.
226-24 SECTION 58. (a) Subchapter H, Chapter 49, Water Code, is
226-25 amended by adding Section 49.233 to read as follows:
226-26 Sec. 49.233. ELECTRIC GENERATION, TRANSMISSION, AND
227-1 DISTRIBUTION FOR CERTAIN DISTRICTS. (a) A district that owns or
227-2 operates raw water pipelines that convey surface water,
227-3 groundwater, or both surface water and groundwater, through more
227-4 than 10 counties for municipal and industrial purposes may:
227-5 (1) develop, generate, transmit, or distribute water
227-6 power and electric energy inside the district's boundaries for its
227-7 own use;
227-8 (2) purchase electric energy from any available source
227-9 for use at a facility the district owns, operates, and maintains
227-10 inside the district's boundaries;
227-11 (3) enter into an agreement to acquire, install,
227-12 construct, finance, operate, make an addition to, own, or operate
227-13 an electric energy generating, transmission, or distribution
227-14 facility jointly with another person; or
227-15 (4) sell or otherwise dispose of any of the district's
227-16 interest in a jointly owned facility described by Subdivision (3).
227-17 (b) A district governed by this section:
227-18 (1) is subject to the transmission line certification
227-19 provisions of Chapter 37, Utilities Code;
227-20 (2) may not generate electricity by means of
227-21 hydroelectric generation.
227-22 (b) This section takes effect January 1, 2002.
227-23 SECTION 59. The Texas Public Finance Authority Act (Article
227-24 601d, Vernon's Texas Civil Statutes) is amended by adding Section
227-25 9E to read as follows:
227-26 Sec. 9E. FINANCING OF STRANDED COSTS. (a) The authority
228-1 shall, either directly or by means of a trust or trusts established
228-2 by it, have the power to issue bonds, notes, certificates of
228-3 participation, or other obligations or evidences of indebtedness
228-4 ("indebtedness") for the purpose of financing stranded costs of a
228-5 municipal power agency created by concurrent resolution by its
228-6 member cities on or before November 1, 1979, pursuant to Chapter
228-7 163, Utilities Code, or a predecessor statute to that chapter. The
228-8 stranded costs of the municipal power agency are set forth as
228-9 allocated to the member cities in the "Potentially Strandable
228-10 Investment (ECOM) Report: 1998 Update" issued by the Public
228-11 Utility Commission of Texas.
228-12 (b) At the request of any member city of a municipal power
228-13 agency, which shall include a statement of the payment terms for
228-14 recovering stranded costs, the authority shall issue indebtedness
228-15 in the amount of the requesting member city's stranded costs, plus
228-16 the costs described in Subdivision (1) along with issuance costs,
228-17 and shall make a grant of the proceeds of such indebtedness to the
228-18 municipal power agency, subject to conditions that:
228-19 (1) the municipal power agency shall use such grant to
228-20 reduce the outstanding principal of the agency's debts allocable to
228-21 stranded costs of the requesting member city for federal income tax
228-22 purposes, whether by redemption, defeasance, or tender offer,
228-23 together with any interest expenses, call premium, tender premium,
228-24 or administrative expenses associated with such principal payment;
228-25 and
228-26 (2) the municipal power agency shall reduce the amount
229-1 payable by the requesting member city under its power sales
229-2 contract with the agency to reflect the reduced debt service on the
229-3 agency's debt as a result of the foregoing payments.
229-4 (c) Indebtedness issued by the authority pursuant to this
229-5 section shall be secured by nonbypassable charges imposed by the
229-6 authority upon retail customers receiving transmission and
229-7 distribution services provided by the requesting member city, which
229-8 shall be consistent with the stranded cost recovery terms set forth
229-9 in the requesting member city's application unless otherwise
229-10 approved by the requesting member city. Indebtedness issued by the
229-11 authority pursuant to this section shall not be the debt of the
229-12 State of Texas, the municipal power agency, or any member of the
229-13 municipal power agency.
229-14 (d) The Public Utility Commission of Texas shall provide
229-15 such assistance to the authority as is necessary to ensure the
229-16 collection and enforcement of the nonbypassable charges, whether
229-17 directly or by using the assistance and powers of the requesting
229-18 member city.
229-19 (e) The authority and the Public Utility Commission of Texas
229-20 are granted all such powers necessary to effectuate the foregoing
229-21 duties and responsibilities. This section shall be interpreted
229-22 broadly in a manner consistent with the most cost-effective
229-23 financing of stranded costs. To the extent possible, the
229-24 indebtedness issued by the authority shall be structured so that
229-25 the interest thereon is excluded from gross income for federal
229-26 income tax purposes. In all events, the interest thereon shall not
230-1 be subject to tax or included as part of the measurement of tax by
230-2 the state or any of its political subdivisions.
230-3 SECTION 60. Subsection (a), Section 11, Texas Public Finance
230-4 Authority Act (Article 601d, Vernon's Texas Civil Statutes), is
230-5 amended to read as follows:
230-6 (a) The board's authority under this Act is limited to the
230-7 financing of the acquisition or construction of a building, [or]
230-8 the purchase or lease of equipment, or the financing of stranded
230-9 costs of a municipal power agency. That authority does not affect
230-10 the authority of the commission or any other state agency.
230-11 SECTION 61. The following provisions are repealed:
230-12 (1) Section 12.104, Utilities Code;
230-13 (2) Chapter 34, Utilities Code;
230-14 (3) Subchapters F and G, Chapter 36, Utilities Code;
230-15 and
230-16 (4) Section 37.058, Utilities Code.
230-17 SECTION 62. (a) Nothing in this Act shall restrict or limit
230-18 a municipality's historical right to control and receive reasonable
230-19 compensation for use of public streets, alleys, rights-of-way, or
230-20 other public property to convey or provide electricity.
230-21 (b) Nothing in this Act shall affect a retail electric
230-22 utility's right to provide electric service in accordance with its
230-23 certificate of public convenience and necessity. A certificate of
230-24 convenience and necessity may, however, be revoked or modified as
230-25 provided by Section 37.059, Utilities Code, and Section 37.060,
230-26 Utilities Code, as added by this Act.
231-1 SECTION 63. Notwithstanding any other provision of this Act
231-2 or Title 2, Utilities Code, any person or entity that provides
231-3 electric service to a four-year state university, upper-level
231-4 institution, Texas state technical college, or college, as provided
231-5 by Section 36.351, Utilities Code, on December 31, 2001, shall
231-6 continue to offer electric service to a four-year state university,
231-7 upper-level institution, Texas state technical college, or college,
231-8 as provided by Section 36.351, Utilities Code, until September 1,
231-9 2007, at a total rate that is no higher than the rate applicable to
231-10 the university, institution, or college on December 31, 2001. The
231-11 rate applicable to a four-year state university, upper-level
231-12 institution, Texas state technical college, or college, as provided
231-13 by Section 36.351, Utilities Code, on December 31, 2001, shall be
231-14 based on the rates provided for or described in Section 36.351,
231-15 Utilities Code. However, a person or entity that is not an
231-16 electric cooperative or a municipally owned utility that provides
231-17 electric service to a four-year state university, upper-level
231-18 institution, Texas state technical college, or college, as provided
231-19 by Section 36.351, Utilities Code, shall be allowed to adjust its
231-20 fuel factor as provided by Subsection (l), Section 39.202,
231-21 Utilities Code, as added by this Act. A person or entity that is
231-22 an electric cooperative that provides electric service under this
231-23 section shall be allowed to adjust its fuel factor in accordance
231-24 with the procedures provided by Section 36.203, Utilities Code. A
231-25 person or entity that is a municipally owned utility that provides
231-26 electric service under this section shall be allowed to adjust its
232-1 fuel factor in accordance with the applicable provisions of the
232-2 Utilities Code. As used in this section, "person or entity"
232-3 includes an electric utility, affiliated retail electric provider,
232-4 municipal corporation, cooperative corporation, or river authority.
232-5 SECTION 64. The Public Utility Commission of Texas shall
232-6 study and make recommendations by December 15, 2000, to the
232-7 legislature for additional legislation that would move to and
232-8 establish a competitive electric market in accordance with the
232-9 changes in law made by this Act.
232-10 SECTION 65. Not later than the 180th day after the effective
232-11 date of this Act, the Public Utility Commission of Texas shall
232-12 establish rules and procedures for the securitization of stranded
232-13 costs for river authorities, as provided by Subdivision (2),
232-14 Subsection (a), Section 40.003, Utilities Code, as added by this
232-15 Act, and for electric cooperatives, as provided by Section 41.003,
232-16 Utilities Code, as added by this Act.
232-17 SECTION 66. This Act takes effect September 1, 1999.
232-18 SECTION 67. The importance of this legislation and the
232-19 crowded condition of the calendars in both houses create an
232-20 emergency and an imperative public necessity that the
232-21 constitutional rule requiring bills to be read on three several
232-22 days in each house be suspended, and this rule is hereby suspended.
_______________________________ _______________________________
President of the Senate Speaker of the House
I hereby certify that S.B. No. 7 passed the Senate on
March 17, 1999, by a viva-voce vote; and that the Senate concurred
in House amendments on May 27, 1999, by a viva-voce vote.
_______________________________
Secretary of the Senate
I hereby certify that S.B. No. 7 passed the House, with
amendments, on May 21, 1999, by a non-record vote.
_______________________________
Chief Clerk of the House
Approved:
_______________________________
Date
_______________________________
Governor