TITLE 16. ECONOMIC REGULATION

PART 1. RAILROAD COMMISSION OF TEXAS

CHAPTER 7. GAS SERVICES DIVISION

The Railroad Commission of Texas (Commission) adopts amendments in Subchapter B to §§7.110, 7.115, 7.201, 7.205, 7.210, 7.220, 7.230, 7.235, 7.240, and 7.245, relating to Communications with Regulatory Authority; Definitions; Filing of Documents; Contents of Statements of Intent and Petitions for Review of Municipal Action; Increasing Residential and Commercial Rates--Statement of Intent; Environs Rates; Contents of Notice; Publication and Service of Notice; Statement of Intent to Participate; and Effective Date of Orders; in Subchapter C, §§7.301, 7.310, 7.315, and 7.351, relating to Annual Report; System of Accounts; Filing of Tariffs; and Gas Utility Pipeline Tax; in Subchapter D, §§7.455, 7.460, 7.465, 7.470, and 7.475, relating to Curtailment Standards; Suspension of Gas Utility Service Disconnection During an Extreme Weather Emergency; Abandonment; Natural Gas Bill Payment by the State or a State Agency; and Municipality Contact Information for Notice of Disconnection for Non-Payment for Non-submetered Master Metered Multifamily Properties; in Subchapter E, §7.5213, relating to Allowance for Funds Used During Construction; in Subchapter F, §§7.6001, 7.6002, and 7.6007, relating to General Provisions; Procedure for Filing and Service of an Appeal, Obligation of City to Respond, and Intervention; and Procedure for Determining and Sharing of the Commission's Costs; in Subchapter G, §7.7003 and §7.7005, relating to Administrative Penalties and Other Remedies for Discrimination; and Authority to Set Rates; and in Subchapter H, §7.7101, relating to Interim Rate Adjustments. The Commission also adopts the repeal of Subchapter I, relating to Natural Gas Pipeline Competition, including §7.7201, Natural Gas Pipeline Competition Study Advisory Committee, and proposes to change the title of Chapter 7 to "Gas Services." The amendments and the repeal are adopted without changes from the proposed text published in the February 9, 2018, issue of the Texas Register (43 TexReg 647).

Generally, the Commission adopts the amendments and repeal to correct outdated references, correct minor typographical errors, and reflect statutory changes and Commission rule changes outside of Chapter 7. For example, the Commission removes references to the National Association of Regulatory Utility Commissioners (NARUC) Uniform System of Accounts (USOA), as the Commission now solely uses the Federal Energy Regulatory Commission (FERC) USOA. Relatedly, the Commission adopts amendments to §7.315, relating to Gas Utility Pipeline Tax, to reflect changes to industry accounting, specifically, changes in FERC USOA Account Numbers 483, 489, 495, 808, 809, 813, and 824. The amendments to §7.315 will not add any new taxes or disallow any current deductions.

The Commission received no comments on the proposal.

SUBCHAPTER B. SPECIAL PROCEDURAL RULES

16 TAC §§7.110, 7.115, 7.201, 7.205, 7.210, 7.220, 7.230, 7.235, 7.240, 7.245

The Commission adopts the amendments under Texas Utilities Code Titles 3 and 4, which authorize the Commission to regulate gas utilities, to protect the public interest inherent in the rates and services of gas utilities, and to assure rates, operations, and services that are just and reasonable to the consumers and to the utilities. In addition, Texas Natural Resources Code §117.102 and Texas Utilities Code §121.2025 give the Commission exclusive jurisdiction to determine whether a city's annual charge is authorized; Texas Natural Resources Code §81.052 authorizes the Commission to adopt all necessary rules for governing and regulating persons under the jurisdiction of the Commission; Texas Utilities Code §102.001 gives the Railroad Commission exclusive original jurisdiction over the rates and services of a gas utility distributing natural gas or synthetic natural gas in areas outside a municipality; Texas Utilities Code, §102.151 requires gas utilities to file schedules showing all rates for a gas utility service, product, or commodity offered by the gas utility and each rule or regulation that relates to or affects a rate of the gas utility or a gas utility service, product, or commodity furnished by the gas utility; Texas Utilities Code, §104.001 vests in the Railroad Commission all the authority and power of this state to ensure compliance with the obligations of gas utilities in Texas Utilities Code, Title 3, Subtitle A, and authorizes the Commission to adopt rules for determining the classification of customers and services; and Texas Utilities Code §104.301, allows a utility to file with the Commission a tariff or rate schedule that provides for an interim adjustment in the utility's monthly customer charge or initial block rate to recover the cost of changes in the investment in capital for gas utility service.

Statutory authority: Texas Natural Resources Code §81.052 and §117.102; Texas Utilities Code, Titles 3 and 4, including §§102.001, 102.151, 104.001, 104.301, and 121.2025.

Cross reference to statutes: Texas Natural Resources Code Chapters 81 and 117, and Texas Utilities Code Titles 3 and 4.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on April 24, 2018.

TRD-201801840

Haley Cochran

Rules Attorney, Office of General Counsel

Railroad Commission of Texas

Effective date: May 14, 2018

Proposal publication date: February 9, 2018

For further information, please call: (512) 475-1295


SUBCHAPTER C. RECORDS AND REPORTS; TARIFFS; GAS UTILITY TAX

16 TAC §§7.301, 7.310, 7.315, 7.351

The Commission adopts the amendments under Texas Utilities Code Titles 3 and 4, which authorize the Commission to regulate gas utilities, to protect the public interest inherent in the rates and services of gas utilities, and to assure rates, operations, and services that are just and reasonable to the consumers and to the utilities. In addition, Texas Natural Resources Code §117.102 and Texas Utilities Code §121.2025 give the Commission exclusive jurisdiction to determine whether a city's annual charge is authorized; Texas Natural Resources Code §81.052 authorizes the Commission to adopt all necessary rules for governing and regulating persons under the jurisdiction of the Commission; Texas Utilities Code §102.001 gives the Railroad Commission exclusive original jurisdiction over the rates and services of a gas utility distributing natural gas or synthetic natural gas in areas outside a municipality; Texas Utilities Code, §102.151 requires gas utilities to file schedules showing all rates for a gas utility service, product, or commodity offered by the gas utility and each rule or regulation that relates to or affects a rate of the gas utility or a gas utility service, product, or commodity furnished by the gas utility; Texas Utilities Code, §104.001 vests in the Railroad Commission all the authority and power of this state to ensure compliance with the obligations of gas utilities in Texas Utilities Code, Title 3, Subtitle A, and authorizes the Commission to adopt rules for determining the classification of customers and services; and Texas Utilities Code §104.301, allows a utility to file with the Commission a tariff or rate schedule that provides for an interim adjustment in the utility's monthly customer charge or initial block rate to recover the cost of changes in the investment in capital for gas utility service.

Statutory authority: Texas Natural Resources Code §81.052 and §117.102; Texas Utilities Code, Titles 3 and 4, including §§102.001, 102.151, 104.001, 104.301, and 121.2025.

Cross reference to statutes: Texas Natural Resources Code Chapters 81 and 117, and Texas Utilities Code Titles 3 and 4.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on April 24, 2018.

TRD-201801841

Haley Cochran

Rules Attorney, Office of General Counsel

Railroad Commission of Texas

Effective date: May 14, 2018

Proposal publication date: February 9, 2018

For further information, please call: (512) 475-1295


SUBCHAPTER D. CUSTOMER SERVICE AND PROTECTION

16 TAC §§7.455, 7.460, 7.465, 7.470, 7.475

The Commission adopts the amendments under Texas Utilities Code Titles 3 and 4, which authorize the Commission to regulate gas utilities, to protect the public interest inherent in the rates and services of gas utilities, and to assure rates, operations, and services that are just and reasonable to the consumers and to the utilities. In addition, Texas Natural Resources Code §117.102 and Texas Utilities Code §121.2025 give the Commission exclusive jurisdiction to determine whether a city's annual charge is authorized; Texas Natural Resources Code §81.052 authorizes the Commission to adopt all necessary rules for governing and regulating persons under the jurisdiction of the Commission; Texas Utilities Code §102.001 gives the Railroad Commission exclusive original jurisdiction over the rates and services of a gas utility distributing natural gas or synthetic natural gas in areas outside a municipality; Texas Utilities Code, §102.151 requires gas utilities to file schedules showing all rates for a gas utility service, product, or commodity offered by the gas utility and each rule or regulation that relates to or affects a rate of the gas utility or a gas utility service, product, or commodity furnished by the gas utility; Texas Utilities Code, §104.001 vests in the Railroad Commission all the authority and power of this state to ensure compliance with the obligations of gas utilities in Texas Utilities Code, Title 3, Subtitle A, and authorizes the Commission to adopt rules for determining the classification of customers and services; and Texas Utilities Code §104.301, allows a utility to file with the Commission a tariff or rate schedule that provides for an interim adjustment in the utility's monthly customer charge or initial block rate to recover the cost of changes in the investment in capital for gas utility service.

Statutory authority: Texas Natural Resources Code §81.052 and §117.102; Texas Utilities Code, Titles 3 and 4, including §§102.001, 102.151, 104.001, 104.301, and 121.2025.

Cross reference to statutes: Texas Natural Resources Code Chapters 81 and 117, and Texas Utilities Code Titles 3 and 4.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on April 24, 2018.

TRD-201801842

Haley Cochran

Rules Attorney, Office of General Counsel

Railroad Commission of Texas

Effective date: May 14, 2018

Proposal publication date: February 9, 2018

For further information, please call: (512) 475-1295


SUBCHAPTER E. RATES AND RATE-SETTING PROCEDURES

16 TAC §7.5213

The Commission adopts the amendments under Texas Utilities Code Titles 3 and 4, which authorize the Commission to regulate gas utilities, to protect the public interest inherent in the rates and services of gas utilities, and to assure rates, operations, and services that are just and reasonable to the consumers and to the utilities. In addition, Texas Natural Resources Code §117.102 and Texas Utilities Code §121.2025 give the Commission exclusive jurisdiction to determine whether a city's annual charge is authorized; Texas Natural Resources Code §81.052 authorizes the Commission to adopt all necessary rules for governing and regulating persons under the jurisdiction of the Commission; Texas Utilities Code §102.001 gives the Railroad Commission exclusive original jurisdiction over the rates and services of a gas utility distributing natural gas or synthetic natural gas in areas outside a municipality; Texas Utilities Code, §102.151 requires gas utilities to file schedules showing all rates for a gas utility service, product, or commodity offered by the gas utility and each rule or regulation that relates to or affects a rate of the gas utility or a gas utility service, product, or commodity furnished by the gas utility; Texas Utilities Code, §104.001 vests in the Railroad Commission all the authority and power of this state to ensure compliance with the obligations of gas utilities in Texas Utilities Code, Title 3, Subtitle A, and authorizes the Commission to adopt rules for determining the classification of customers and services; and Texas Utilities Code §104.301, allows a utility to file with the Commission a tariff or rate schedule that provides for an interim adjustment in the utility's monthly customer charge or initial block rate to recover the cost of changes in the investment in capital for gas utility service.

Statutory authority: Texas Natural Resources Code §81.052 and §117.102; Texas Utilities Code, Titles 3 and 4, including §§102.001, 102.151, 104.001, 104.301, and 121.2025.

Cross reference to statutes: Texas Natural Resources Code Chapters 81 and 117, and Texas Utilities Code Titles 3 and 4.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on April 24, 2018.

TRD-201801843

Haley Cochran

Rules Attorney, Office of General Counsel

Railroad Commission of Texas

Effective date: May 14, 2018

Proposal publication date: February 9, 2018

For further information, please call: (512) 475-1295


SUBCHAPTER F. PIPELINE APPEAL OF CITY ASSESSMENT OF ANNUAL CHARGE

16 TAC §§7.6001, 7.6002, 7.6007

The Commission adopts the amendments under Texas Utilities Code Titles 3 and 4, which authorize the Commission to regulate gas utilities, to protect the public interest inherent in the rates and services of gas utilities, and to assure rates, operations, and services that are just and reasonable to the consumers and to the utilities. In addition, Texas Natural Resources Code §117.102 and Texas Utilities Code §121.2025 give the Commission exclusive jurisdiction to determine whether a city's annual charge is authorized; Texas Natural Resources Code §81.052 authorizes the Commission to adopt all necessary rules for governing and regulating persons under the jurisdiction of the Commission; Texas Utilities Code §102.001 gives the Railroad Commission exclusive original jurisdiction over the rates and services of a gas utility distributing natural gas or synthetic natural gas in areas outside a municipality; Texas Utilities Code, §102.151 requires gas utilities to file schedules showing all rates for a gas utility service, product, or commodity offered by the gas utility and each rule or regulation that relates to or affects a rate of the gas utility or a gas utility service, product, or commodity furnished by the gas utility; Texas Utilities Code, §104.001 vests in the Railroad Commission all the authority and power of this state to ensure compliance with the obligations of gas utilities in Texas Utilities Code, Title 3, Subtitle A, and authorizes the Commission to adopt rules for determining the classification of customers and services; and Texas Utilities Code §104.301, allows a utility to file with the Commission a tariff or rate schedule that provides for an interim adjustment in the utility's monthly customer charge or initial block rate to recover the cost of changes in the investment in capital for gas utility service.

Statutory authority: Texas Natural Resources Code §81.052 and §117.102; Texas Utilities Code, Titles 3 and 4, including §§102.001, 102.151, 104.001, 104.301, and 121.2025.

Cross reference to statutes: Texas Natural Resources Code Chapters 81 and 117, and Texas Utilities Code Titles 3 and 4.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on April 24, 2018.

TRD-201801844

Haley Cochran

Rules Attorney, Office of General Counsel

Railroad Commission of Texas

Effective date: May 14, 2018

Proposal publication date: February 9, 2018

For further information, please call: (512) 475-1295


SUBCHAPTER G. CODE OF CONDUCT

16 TAC §7.7003, §7.7005

The Commission adopts the amendments under Texas Utilities Code Titles 3 and 4, which authorize the Commission to regulate gas utilities, to protect the public interest inherent in the rates and services of gas utilities, and to assure rates, operations, and services that are just and reasonable to the consumers and to the utilities. In addition, Texas Natural Resources Code §117.102 and Texas Utilities Code §121.2025 give the Commission exclusive jurisdiction to determine whether a city's annual charge is authorized; Texas Natural Resources Code §81.052 authorizes the Commission to adopt all necessary rules for governing and regulating persons under the jurisdiction of the Commission; Texas Utilities Code §102.001 gives the Railroad Commission exclusive original jurisdiction over the rates and services of a gas utility distributing natural gas or synthetic natural gas in areas outside a municipality; Texas Utilities Code, §102.151 requires gas utilities to file schedules showing all rates for a gas utility service, product, or commodity offered by the gas utility and each rule or regulation that relates to or affects a rate of the gas utility or a gas utility service, product, or commodity furnished by the gas utility; Texas Utilities Code, §104.001 vests in the Railroad Commission all the authority and power of this state to ensure compliance with the obligations of gas utilities in Texas Utilities Code, Title 3, Subtitle A, and authorizes the Commission to adopt rules for determining the classification of customers and services; and Texas Utilities Code §104.301, allows a utility to file with the Commission a tariff or rate schedule that provides for an interim adjustment in the utility's monthly customer charge or initial block rate to recover the cost of changes in the investment in capital for gas utility service.

Statutory authority: Texas Natural Resources Code §81.052 and §117.102; Texas Utilities Code, Titles 3 and 4, including §§102.001, 102.151, 104.001, 104.301, and 121.2025.

Cross reference to statutes: Texas Natural Resources Code Chapters 81 and 117, and Texas Utilities Code Titles 3 and 4.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on April 24, 2018.

TRD-201801845

Haley Cochran

Rules Attorney, Office of General Counsel

Railroad Commission of Texas

Effective date: May 14, 2018

Proposal publication date: February 9, 2018

For further information, please call: (512) 475-1295


SUBCHAPTER H. INTERIM RATE ADJUSTMENTS

16 TAC §7.7101

The Commission adopts the amendments under Texas Utilities Code Titles 3 and 4, which authorize the Commission to regulate gas utilities, to protect the public interest inherent in the rates and services of gas utilities, and to assure rates, operations, and services that are just and reasonable to the consumers and to the utilities. In addition, Texas Natural Resources Code §117.102 and Texas Utilities Code §121.2025 give the Commission exclusive jurisdiction to determine whether a city's annual charge is authorized; Texas Natural Resources Code §81.052 authorizes the Commission to adopt all necessary rules for governing and regulating persons under the jurisdiction of the Commission; Texas Utilities Code §102.001 gives the Railroad Commission exclusive original jurisdiction over the rates and services of a gas utility distributing natural gas or synthetic natural gas in areas outside a municipality; Texas Utilities Code, §102.151 requires gas utilities to file schedules showing all rates for a gas utility service, product, or commodity offered by the gas utility and each rule or regulation that relates to or affects a rate of the gas utility or a gas utility service, product, or commodity furnished by the gas utility; Texas Utilities Code, §104.001 vests in the Railroad Commission all the authority and power of this state to ensure compliance with the obligations of gas utilities in Texas Utilities Code, Title 3, Subtitle A, and authorizes the Commission to adopt rules for determining the classification of customers and services; and Texas Utilities Code §104.301, allows a utility to file with the Commission a tariff or rate schedule that provides for an interim adjustment in the utility's monthly customer charge or initial block rate to recover the cost of changes in the investment in capital for gas utility service.

Statutory authority: Texas Natural Resources Code §81.052 and §117.102; Texas Utilities Code, Titles 3 and 4, including §§102.001, 102.151, 104.001, 104.301, and 121.2025.

Cross reference to statutes: Texas Natural Resources Code Chapters 81 and 117, and Texas Utilities Code Titles 3 and 4.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on April 24, 2018.

TRD-201801846

Haley Cochran

Rules Attorney, Office of General Counsel

Railroad Commission of Texas

Effective date: May 14, 2018

Proposal publication date: February 9, 2018

For further information, please call: (512) 475-1295


SUBCHAPTER I. NATURAL GAS PIPELINE COMPETITION

16 TAC §7.7201

The Commission adopts the repeal under Texas Utilities Code Titles 3 and 4, which authorize the Commission to regulate gas utilities, to protect the public interest inherent in the rates and services of gas utilities, and to assure rates, operations, and services that are just and reasonable to the consumers and to the utilities. In addition, Texas Natural Resources Code §117.102 and Texas Utilities Code §121.2025 give the Commission exclusive jurisdiction to determine whether a city's annual charge is authorized; Texas Natural Resources Code §81.052 authorizes the Commission to adopt all necessary rules for governing and regulating persons under the jurisdiction of the Commission; Texas Utilities Code §102.001 gives the Railroad Commission exclusive original jurisdiction over the rates and services of a gas utility distributing natural gas or synthetic natural gas in areas outside a municipality; Texas Utilities Code, §102.151 requires gas utilities to file schedules showing all rates for a gas utility service, product, or commodity offered by the gas utility and each rule or regulation that relates to or affects a rate of the gas utility or a gas utility service, product, or commodity furnished by the gas utility; Texas Utilities Code, §104.001 vests in the Railroad Commission all the authority and power of this state to ensure compliance with the obligations of gas utilities in Texas Utilities Code, Title 3, Subtitle A, and authorizes the Commission to adopt rules for determining the classification of customers and services; and Texas Utilities Code §104.301, allows a utility to file with the Commission a tariff or rate schedule that provides for an interim adjustment in the utility's monthly customer charge or initial block rate to recover the cost of changes in the investment in capital for gas utility service.

Statutory authority: Texas Natural Resources Code §81.052 and §117.102; Texas Utilities Code, Titles 3 and 4, including §§102.001, 102.151, 104.001, 104.301, and 121.2025.

Cross reference to statutes: Texas Natural Resources Code Chapters 81 and 117, and Texas Utilities Code Titles 3 and 4.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on April 24, 2018.

TRD-201801839

Haley Cochran

Rules Attorney, Office of General Counsel

Railroad Commission of Texas

Effective date: May 14, 2018

Proposal publication date: February 9, 2018

For further information, please call: (512) 475-1295


PART 2. PUBLIC UTILITY COMMISSION OF TEXAS

CHAPTER 25. SUBSTANTIVE RULES APPLICABLE TO ELECTRIC SERVICE PROVIDERS

The Public Utility Commission of Texas (commission) adopts the repeal of the following: 16 Texas Administrative Code (TAC) Chapter 25, Subchapter Q (Subchapter Q), relating to System Benefit Fund, including §25.451, relating to Administration of the System Benefit Account; §25.453, relating to Targeted Energy Efficiency Programs; §25.454, relating to Rate Reduction Program; §25.455, relating to One-Time Bill Payment Assistance Program; and §25.457, relating to Implementation of the System Benefit Fee by the Municipally Owned Utilities and Electric Cooperatives. The commission adopts amendments to the following: §25.5, relating to Definitions; §25.41, relating to Price to Beat Rule; §25.43, relating to Provider of Last Resort (POLR); §25.107, relating to Certification of Retail Electric Providers (REPs); §25.181, relating to Energy Efficiency Goal; §25.344, relating to Cost Separation Proceedings; §25.431, relating to Retail Competition Pilot Project; §25.475, relating to General Retail Electric Provider Requirements and Informal Disclosures to Residential and Small Commercial Customers; §25.478, relating to Credit Requirements and Deposits; §25.479, relating to Issuance and Format of Bills; §25.480, relating to Bill Payment and Adjustments; §25.491, relating to Record Retention and Reporting Requirements; §25.497, relating to Critical Load Industrial Customers, Critical Load Public Safety Customers, Critical Care Residential Customers, and Chronic Condition Residential Customers; and §25.498, relating to Prepaid Service, and adopts new §25.45, relating to the Low-Income List Administrator, with changes to the proposed text as published in the December 29, 2017, issue of the Texas Register (42 TexReg 7495). The repeal of Subchapter Q reflects the cessation of the System Benefit Fund, as required by House Bill 1101, 84th Legislative Session (Regular Session), and the proposed amendments update language in order to remove references to the System Benefit Fund. In addition, Senate Bill 1976, 85th Legislative Session (Regular Session), provides means by which electric providers and certified telecommunications utilities can continue to offer assistance to low-income customers. The repeal of Subchapter Q and amendments in other subchapters to remove references to the System Benefit Fund effectuate House Bill 1101 and Senate Bill 1976 with respect to retail electric providers. The repeals, amendments and new section are adopted under Project Number 47343.

The commission received comments on the proposed new section, amendments, and repeals from: the Alliance for Retail Markets (ARM); the Texas Coalition for Affordable Power (TCAP); the Texas Energy Association for Marketers (TEAM) and the Texas Ratepayers Organization to Save Energy and the Texas Legal Services Center (collectively, Texas ROSE and TLSC). The commission received reply comments from ARM, TEAM, the Office of Public Utility Counsel (OPUC), and Texas ROSE and TLSC. In addition, the commission received a late-filed addendum to the reply comments of Texas ROSE and TLSC on February 28, 2018. On March 5, 2018, the commission received a response to this addendum filed by ARM.

Comments Regarding the Retention and Expansion of Certain Customer Protection Provisions

Texas ROSE and TLSC asserted that the changes to allow the split deposit provision to apply to all customers should be extended to late fees and deferred payment arrangements as well. Texas ROSE and TLSC provided data asserting that, of the 9.3 million households in Texas, approximately two million of those households are classified as "hard-to-reach" customers. Texas ROSE and TLSC stated that, by comparison, only 527,366 customers qualify for the more stringent standards of the System Benefit Fund program. Texas ROSE and TLSC argued that many customers would have more secure electricity supply if the rules that were applicable to eligible recipients of the now-expired System Benefit Fund rate discount program were instead applied to all residential customers. Texas ROSE and TLSC stated that one set of rules for all residential customers would help customers understand their options, simplify the process of resolving payment issues for customer service representatives by eliminating the need to verify income qualifications, simplify enforcement, and result in cost savings for REPs.

Texas ROSE and TLSC detailed findings of its own research, in which it concluded that as household income declines below 200% of federal poverty guidelines, the proportion of that income spent on home energy increases sharply--in some cases to as much as 26%. Texas ROSE and TLSC asserted that, given these demographics, there is a rational reason for the commission to adopt changes to its rules to provide these protections to all residential customers.

In addition, TCAP argued that the rules in this project have been proposed in response to the passage of SB 1976, and SB 1976 should have no impact on existing customer protection standards. TCAP also commented that it would be an unfortunate outcome if new rules adopted in response to SB 1976 undermine customer protection standards.

In response to Texas ROSE and TLSC's claim that two-fifths of Texas residential customers are "hard-to-reach," TEAM argued that this concept only appears in §25.181, the energy efficiency rule, which applies only to transmission and distribution utilities, and therefore is not relevant. TEAM asserted that the concept of "hard-to-reach" is never mentioned in the commission's rules relating to the system benefit fund, to competitive Electric Reliability Council of Texas (ERCOT) areas, or to utility deposits outside ERCOT. TEAM further noted that the hard-to-reach concept applies to funding home energy-efficiency projects that generally represent an expensive but one-time investment designed to reduce a customer's overall electric usage, and thus overall electric cost. Finally, TEAM argued that the hard-to-reach customer concept is not reasonably applied to the policy decisions regarding deposits, or the definition of a low-income customer, because all customers have access to electric service without a deposit through pre-pay products.

In replies, ARM argued that, even if the statistics presented by Texas ROSE and TLSC were germane, the data would not, on its face, demonstrate a lack of options in the competitive retail market for low-income customers to obtain assistance in meeting deposit requirements, receiving voluntary payment deferral assistance or obtaining late fee penalty waivers on a case-by-case basis. Similarly, TEAM stated that options exist for residential customers who are not able to or do not wish to pay a deposit: pre-pay offerings, a required deposit waiver for customers with 12 months of good payment history, competitive product offerings without a deposit requirement, or competitive product offerings with some version of a split deposit. ARM asserted that Texas ROSE and TLSC provided no analytical support for the proposition that there are many customers who would have a more secure electricity supply through the retention of and expansion of the customer protection provisions that were previously applicable to recipients of the low-income rate reduction program.

In replies, ARM asserted that Texas ROSE and TLSC's general proposal to expand the scope of the customer protection rules would require REPs to offer certain benefits formerly reserved for low-income customers by rule prior to the statutory expiration of the System Benefit Fund, the associated low-income discount, and the associated low-income customer identification process, to all residential customers. ARM argued that there is no rational justification for these proposals, other than to effectively reinstate expired low-income programs and benefits by simply expanding them to apply to all residential customers. ARM asserted that, if the commission were to adopt such proposals, it would chart a radical new direction for the competitive retail market by imposing new regulatory requirements on REPs that would significantly modify current operations, without any reasonable justification. ARM asserted that the commission should look to the competitive market rather than enact new regulatory mandates that expansively reinstate expired mandates that were formerly applicable only to a subset of residential customers.

ARM argued that the instant rulemaking originated from the legislatively mandated expiration of the System Benefit Fund as authorized by HB 7 in 2013 and later modified by HB 1101 in 2015, and that the expiration of these statutory provisions is the primary driver for repealing Subchapter Q and amending other substantive rules impacted by such legislative action. ARM asserted that the scope of these amendments include the elimination of the mandatory low-income late fee penalty waiver in §25.480(c) and the mandatory low-income split deposit provision in §25.478(e)(3). ARM argued that, while SB 1976 addresses whether the commission can require a REP to offer any unreimbursed programs or benefits to low-income customers after the expiration of the System Benefit Fund provisions, that legislation is neither the sole nor proximate cause of the origination of this rulemaking project, contrary to the assertions raised by TCAP.

ARM argued that Texas ROSE and TLSC misread the legislative history underlying SB 1976 by implying that the bill originated solely with REPs. ARM argued that, absent SB 1976, a REP would not have any access to a service that objectively identifies low-income customers in a standardized manner across the competitive market and allows those REPs to provide voluntarily-offered programs and services for those customers. ARM further averred that the bill did not originate solely with the REPs, and was presented in the commission's Scope of Competition Report in 2017, after which the legislature responded by enacting a hybrid of options presented in that report.

In reply comments, ARM argued that SB 1976 amended the Public Utility Regulatory Act (PURA) §17.007 to allow a REP to timely request the commission, with the assistance of the Health and Human Services Commission (HHSC), to identify the REP's low-income electric customers for the 12-month period beginning September 1 of each year, subject to the requesting REP's agreement to reimburse the commission for the cost of development and operation of the matching process. ARM argued that the bill author's statement of intent clarified that the bill will allow voluntary low-income programs to continue to be offered on a competitive basis, given that the expiration of the System Benefit Fund includes the expiration of the mechanism by which the commission can identify customers who qualify as low-income customers. ARM asserted that, taken together, these three bills reflect a shift in emphasis from regulated low-income mandates codified by statute and rule to voluntary low-income programs offered by REPs in the competitive retail market, effective September 1, 2017. ARM argued that nothing in the language of any of those bills or their legislative histories supports the unprecedented expansion of formerly tailored customer benefits and other requested actions advocated by TCAP and Texas ROSE and TLSC.

In replies, Texas ROSE and TLSC asserted that the proposed rule would rely solely on REPs voluntarily selecting to offer low-income customer protections involving payment arrangements and late fees. Texas ROSE and TLSC argued that the proposed revisions are contrary to the commission's long-acknowledged recognition that these customer protections are necessary to protect the safety and health of low-income residential customers, and that there is no evidence that these protections are no longer needed. Texas ROSE and TLSC also asserted that Houston Mayor Sylvester Turner noted that the termination of the System Benefit Fund has made low-income residential customers' abilities to timely pay their bills harder. Texas ROSE and TLSC argued that the protections that the commission proposes to eliminate should be instead retained and strengthened.

Texas ROSE and TLSC agreed with TCAP in replies that, on its face, SB 1976 has no impact on customer protections, and that PURA §17.004 and §39.001 call for no weakening of customer protections, and provide broad authority for the commission to provide essential customer protection. Texas ROSE and TLSC asserted that, in Project No. 36131, Rulemaking Relating to Disconnection of Electric Service and Deferred Payment Plans, the commission restated its position that PURA requires the commission to address low-income customers with a higher standard of care, noting that in PURA §17.004(b) and §39.101(e) the commission is given authority to adopt and enforce rules for minimum service standards relating to the extension of credit, level and average billing programs, and termination of service.

In replies, Texas ROSE and TLSC argued that the absence of an automated list of low-income customers does not negate the commission's responsibilities to protect the health and safety of low-income customers, but it does call for a reasonable alternative to identify the low-income customer.

Texas ROSE and TLSC argued that the proposed rule establishes minimum standards and does not prevent REPs from voluntarily providing additional benefits. Texas ROSE and TLSC asserted that minimum standards are not anti-competitive, but instead foster competition, allow REPs to compete on price without compromising customer protection, and produce a more transparent marketplace.

ARM and TEAM argued that Texas ROSE and TLSC's proposals ignore the financial consequences of these changes on REPs and the ultimate trickle-down effect on all customers. ARM stated that it did not prepare a cost analysis because of the timeframe for reply comments, but that it would be reasonable to assume that such proposals would increase bad debt expense to REPs through extension of customer credit, and that these costs would trigger changes in retail product pricing and operational policies to the detriment of timely-paying customers. ARM estimated the costs of the additional proposals to be significant, given that there are approximately six million residential customers in the competitive retail market, and these low-income customers previously receiving benefits numbered 545,000. ARM asserted that this demonstrated the potential increase in financial exposure that would result from the implementation of these proposals.

Additionally, in reply comments, Texas ROSE and TLSC proposed allowing low-income customers to self-certify that they were eligible to receive the benefits. Texas ROSE and TLSC argued that the burden would be placed on the customer, rather than the REP, to verify the customer's status for REPs that do not have access to the Low-Income List Administrator (LILA) list. Texas ROSE and TLSC averred that this method removes any justifiable reason to reduce low-income customer protections or exclude low-income customers from customer protections provided to other categories of vulnerable customers such as critical care or chronic condition customers under §25.480(j)(2)(A)(ii).

Commission Response

The commission responds to the comments where any proposed changes would appear in the proposed rule below.

With respect to Texas ROSE and TLSC's proposal to allow residential customers to self-certify, the commission declines to adopt that proposal. The commission notes that this proposal was made in reply comments, and therefore other parties have not had an opportunity to sufficiently vet the proposal. The commission also finds that REPs already have the opportunity to allow customers to self-certify for programs, because neither the statute nor the commission's rules prohibit a REP from voluntarily designing a program targeted toward low-income customers, including a self-certification program.

§25.5--Definitions

§25.5(65)--Low-income Customer

Texas ROSE and TLSC stated that the proposed deletion of the income eligibility requirement in the definition of a low-income customer would restrict REPs who may want to qualify customers based on an income standard applied to all residential customers. Texas ROSE and TLSC proposed language to distinguish between automatic and voluntary enrollment by a REP, with language to state that a low-income customer is a customer whose household income is not more than 125% of the federal poverty guidelines may be voluntarily enrolled by a REP.

ARM opposed Texas ROSE and TLSC's proposed expansion of the definition, asserting that the proposed rule properly defined a "low-income" customer in the context of the automatic low-income customer identification process administrated by the LILA pursuant to PURA §17.007. ARM asserted that nothing in PURA §17.007 states that the statutory provision is the exclusive way by which low-income customers may be identified, and therefore, Texas ROSE and TLSC's proposal is not necessary. ARM argued that Texas ROSE and TLSC's proposed revision could have the unintended consequence of limiting the number of low-income customers eligible for a REP's voluntary programs and benefits, if a REP decides to qualify a customer based on alternative income-based criteria. ARM argued that Texas ROSE and TLSC's proposed revision serves no valid purpose, is not needed, should be rejected by the commission, and the commission's definition as proposed instead be adopted.

Commission Response

The commission finds that the forces of competition will encourage the REPs to create unique product offerings and opportunities for low-income customers, including customers who may not meet the criteria in the now-expired PURA definition of "low-income customer." The commission asserts that the LILA service should properly identify those customers who would have been eligible for the now-expired rate reduction program, and that a more prescriptive definition is not necessary at this time. In addition, the commission finds that the intent of the statute is to foster competition and broaden access not only to the types of product offerings, but also to the types of customers that may be served under unique accommodations the REPs may offer. The commission makes no changes and adopts the definition as proposed.

§25.5(101) - Rate reduction program

Texas ROSE and TLSC asserted that a REP offering a voluntary rate reduction program should have to meet a uniform standard in order to market a product as a rate reduction program. Additionally, TCAP, OPUC, and Texas ROSE and TLSC agreed that the commission should require this rate reduction program to be transferable to any of the REP's residential rate plans, arguing that this would prevent a rate discount from being anti-competitive or discriminatory. Texas ROSE and TLSC proposed language for a definition of rate reduction program to this effect.

In replies, ARM opposed Texas ROSE and TLSC's proposed definition, reasserting that the commission's proposed amendments appropriately removed the term and its definition in view of the expiration of the statutory provisions for the low-income electric discount.

ARM argued that PURA §17.007(a) refers to "discounts" as a form of voluntary assistance facilitated through the automated process administered by the LILA, and that nothing in the statute defines any voluntarily provisioned "discount" or "rate reduction" in the context of voluntarily-provided low-income programs and benefits. ARM argued that, additionally, what constitutes a voluntarily-provided REP discount or rate reduction in the competitive market may not exactly comport with the form of the now-expired low-income electric discount. Furthermore, ARM asserted that any definition of a term such as "rate reduction" would infringe upon the market's competitive determination of the form and content of such a discount.

ARM replied that such prescriptions against discrimination are unnecessary, given that §25.471(c) already prohibits a REP from undue discrimination in the provision of electric service due to the customer's qualification for low-income services. Furthermore, ARM argued that specific rate discounts or requirements would constitute regulation of the price of competitive retail services in contravention of PURA §39.001(d). ARM also asserted that TCAP and Texas ROSE and TLSC's proposal to regulate the form of voluntary and competitively-driven customer benefits would likely discourage a REP from offering discounts to low-income customers, given the heightened regulatory risk that would be associated with providing such benefits. ARM recommended that the commission reject such proposals, and adopt the repeal of the definition as in the proposed rule.

Commission Response

The commission finds that the intent of the statutory provisions in PURA §17.007, coupled with the expiration of the statutory provisions that mandated the low-income electric discount program, is to transition from a regulated paradigm to a competitive, market-driven opportunity in which REPs can compete for a low-income customer's business. Therefore, the commission finds that defining a rate reduction program would be overly prescriptive and contravenes the intent of the statutory changes. The commission declines to make the change and adopts the rule as proposed.

Low-income list administrator alternative

Texas ROSE and TLSC proposed a new definition in §25.5(67) for a low-income list administrator alternative, or LILA alternative, to allow a REP to provide a LILA alternative to identify customers eligible for programs offered by the REP.

Commission Response

The commission responds to the proposal of Texas ROSE and TLSC for a new definition of a LILA alternative in its response regarding proposed changes to §25.45(i) below.

§25.43--Provider of Last Resort

Subsection (p)--REP Obligations in a Transition of Customers to POLR Service

Texas ROSE and TLSC suggested language to add "or the REP's LILA alternative" throughout subsection (p) where the proposed rule referenced the LILA list, asserting that a REP should be able to identify its low-income customers using a commission-approved process. In reply comments, ARM disagreed with Texas ROSE and TLSC's proposed change. ARM asserted that allocating an existing REP's letter of credit proceeds based on a LILA alternative could be administratively problematic if the exiting REP uses different criteria than the POLR REP to identify whether the transitioning customers qualify as low-income.

Additionally, ARM proposed deleting subsection (p)(9)(C)(i) and (ii) to remove the split deposit provision. ARM also proposed a clarification in subsection (p)(9)(B), relating to a REP's obligations in a transition of customers to POLR service, changing "as" to "in" the LILA list in subparagraph (B).

Commission Response

With respect to Texas ROSE and TLSC's proposal to include references to the LILA alternative, the commission responds to that proposal in its discussion of Texas ROSE and TLSC's proposed new §25.45(i) below. With respect to ARM's recommendation to remove references to the split deposit provision in subsection (p)(9)(C)(i) and (ii), the commission responds more fully in its discussion of the comments received on the split deposit provision in §25.478(e) below.

The commission corrects the typographical error in subsection (p)(9)(B) and makes a change to the rule as proposed in order to clarify the language.

Subsection (s)(1) - Reporting Requirements

ARM reiterated that it supported the proposed rule's provisions that give the commission the ability to prioritize an existing REP's letter of credit proceeds to first assist transitioned low-income customers in meeting the POLR REP's deposit requirements.

Texas ROSE and TLSC proposed amending subsection (s)(1) to require the reporting of the number of LILA or LILA alternative customers transitioned to a REP in a given quarter. In replies, ARM asserted that, in addition to the complications that would arise from applying different criteria, Texas ROSE and TLSC failed to offer any explanation regarding the need for this information.

Commission Response

The commission declines to make the changes proposed by Texas ROSE and TLSC for the reasons noted by ARM. Texas ROSE and TLSC do not provide sufficient argument as to the value of the proposed reporting requirements to the commission.

Subsection (w)--Deposit Payment Assistance

In initial comments, ARM stated that it supported the proposed rule's language allowing the REP's letter of credit monies to assist low-income customers. ARM noted a redundancy in the proposed language in subsection (w)(2)(A) that references "a list of the ESI IDs identified by the LILA that have been or shall be transitioned to the applicable POLR (if applicable)". ARM also noted a similar redundancy in subsection (w)(2)(B). ARM suggested correcting these redundancies by replacing "if applicable" in the parenthetical with the phrase "if available" in a parenthetical.

Commission Response

The commission responds to Texas ROSE and TLSC's proposal with respect to the LILA alternative in its response to comments received on §25.45(i).

The commission adopts ARM's proposed language in order to remove the redundant language and make the rule language clearer.

POLR Terms of Service

ARM noted that, in Section 2, entitled "Security," the proposed rule had a redundant use of the term "customer" in this section that should be deleted. ARM also argued that the third provision under the heading "Cash Deposit" should be deleted in its entirety to be consistent with the deletion of proposed §25.478(e)(3).

Commission Response

The commission adopts ARM's proposed change with respect to the redundant use of the term "customer," on the basis of providing clearer language. For reasons discussed further below in the commission's response to comments received on §25.478(e), the commission adopts ARM's proposed change with respect to the third provision under "Cash Deposit" in the POLR Terms of Service.

§25.45--Low-Income List Administrator

In initial comments, ARM stated that it largely agreed with the proposed rule, but suggested that some of the subsections that may contain duplicative information be streamlined for additional efficiency and clarity. Specifically, ARM noted that subsections (a) through (d) each included an explicit or implicit definition of the LILA's functions, and in each instance there are slight variations on the verbiage used to define the term LILA as proposed in §25.5(66). To avoid uncertainty and to promote consistency, ARM proposed revising subsections (a) and (b) to more closely track the language in §25.5(66), deleting subsection (c), which defines the LILA, in its entirety as it was already addressed in §25.5(66), and combining subsection (d) with the proposed subsection (h). ARM also made additional clarifications throughout proposed subsections (e) through (h), regarding qualifying HHSC benefits and participating REPs.

In addition, ARM recommended adopting additional clarifications to specify that the REP responsibilities only apply to REPs participating in the LILA service. ARM recommended that the strictly prescriptive "monthly basis" requirement in proposed subsection (f) for participating REPs and the LILA to exchange information be modified so that the monthly basis standard be a minimum requirement. ARM asserted that this modification would facilitate more frequent exchange if that is needed in the future. In addition, ARM argued that its proposed revisions would remove language specifically referencing a "list" and more appropriately reflect that the service provided by the LILA is an identification of eligible low-income customers through a comparison of separate data sets provided by REPs and HHSC independently, as opposed to the creation and maintenance of a "master list" of all low-income electric customers, by referencing it as a "low-income customer identification service."

Commission Response

The commission makes changes to the proposed rule to adopt ARM's clarifying language throughout subsections (a) through (h) as proposed.

Subsection (g)--Confidentiality of Information

Texas ROSE and TLSC proposed language to limit the use of the LILA or the "LILA alternative" to enrolling the customer in a REP's rate reduction program or referring the customer to its bill payment assistance program or other program to help the low-income household maintain a continuous supply of electricity, as well as to acknowledge that the customer information provided to the LILA is confidential and that the information can be used only for purposes prescribed by commission rule, and that the maximum penalties apply to any misuse of that information, and proposed new language in subsection (g)(4) and (5) to this effect.

ARM opposed Texas ROSE and TLSC's proposed limitation in subsection (g)(4) of REP's use of the list, arguing that this would unreasonably restrict the purposes for which a REP may offer voluntary programs and benefits for low-income customers. ARM asserted that Texas ROSE and TLSC's proposed language would, on its face, prohibit the REP from even waiving certain fees or providing deposit assistance to a low-income customer. ARM argued that this restriction would directly conflict with SB 1976's intention to promote competitive experimentation and differentiation by REPs in the development of targeted services providing value to the low-income customer. ARM also noted that the directive in paragraph (g)(2) requires a REP to protect proprietary customer and competitively sensitive information exchanged with the LILA, which should suffice to meet Texas ROSE and TLSC's concerns.

In addition, ARM opposed Texas ROSE and TLSC's proposed changes in paragraph (g)(5) that any misuses of information by a REP shall be subject to the maximum administrative penalty allowed by law. ARM asserted that it was unclear what may constitute a REP's misuse of information, and argued that it was unnecessary given that §25.8 sets uniform standards for commission-assessed administrative penalties. ARM noted that Class A violations, which may include violations on the prohibition against discrimination in the provision of electric service or engaging in fraudulent, unfair, misleading, deceptive, or anticompetitive business practices, carry a maximum penalty of $25,000 per day. ARM asserted that Texas ROSE and TLSC's proposals would duplicate well-established provisions in the commission's rules, and would only serve to confuse the application of these provisions. ARM asserted that Texas ROSE and TLSC's proposal should be rejected.

Commission Response

The commission declines to adopt the proposals made by Texas ROSE and TLSC for the reasons asserted by ARM in its reply comments: that such language could impede a REP's ability to tailor certain benefits to customer needs and that §25.8 and §25.45(g)(2) already provide for administrative penalties for a REP abusing such information, while the language proposed by Texas ROSE and TLSC could result in overly restricting a REP's use of the LILA service.

Subsection (h)--Annual Election Process

Texas ROSE and TLSC proposed to modify subsection (h), regarding the annual election process, to reflect a LILA alternative.

In initial comments, TEAM proposed language in subsection (h) to clarify that, unless otherwise agreed by the participating REPs, the methodology for allocation of the LILA's annual fee for REPs shall include a reasonable reflection of the difference in the number of customers for each REP or a reasonable proxy for such.

In replies, ARM stated that it did not support TEAM's proposed revision at this time to base each participating REP's allocated cost on its market share. ARM asserted that PURA §17.007(d)(2) states that each participating REP agrees to reimburse the commission for the cost of development and maintenance of the LILA's matching service "on terms agreed to by the commission and the provider." ARM stated that TEAM's proposed revision may motivate some participating REPs not to reach an agreement with the commission on the cost allocation issue. ARM recommended that the commission review these issues in a future rulemaking proceeding, along with other issues relating to the codification of a specific opt-in process. In initial comments, ARM asserted that a specific codification would greatly benefit REPs and possibly encourage greater participation by REPs in the low-income customer identification service.

Commission Response

With respect to Texas ROSE and TLSC's proposal to modify subsection (h) to reflect a new LILA alternative, the commission responds to the proposal in its comments on Texas ROSE and TLSC's proposed new subsection (i) below.

In response to the comments by TEAM, the commission declines to make the proposed modification at this time for the reasons asserted by ARM. The commission finds that such a proposal would be better addressed in a future rulemaking proceeding as suggested by ARM.

Proposed new subsection (i), regarding a Low-Income List Administrator Alternative

In initial comments, Texas ROSE and TLSC proposed new subsection (i), permitting a REP to identify its low-income customers using a non-discriminatory process approved by the commission, in lieu of obtaining the LILA.

In replies, ARM opposed Texas ROSE and TLSC's proposal. ARM argued that requiring commission approval of an alternative process for identifying low-income customers was burdensome and likely to deter use of any alternative process, particularly in the absence of any specific objective criteria for the commission's evaluation of that process. ARM argued that, if the commission were to conclude that a REP must seek approval of any alternative low-income customer identification process, a better option would be to require a REP to rely solely on the low-income customer identification service provided by the LILA pursuant to PURA §17.007. ARM argued that the standardized and uniform process avoids the complications that may ensue when REPs in different markets use different criteria for determining low-income eligibility for their voluntary programs and benefits, and may encourage greater participation in funding the LILA's low-income customer identification service each year.

ARM stated that, while it supported the Texas ROSE and TLSC's interest in giving a REP flexibility to utilize an alternative means for identifying low-income customers voluntarily, it strongly opposed any requirement directing a REP to either report or seek approval of the alternative method for identifying low-income customers. ARM asserted that the REP's voluntary use of an identification process and its voluntary deployment of low-income programs and benefits should not be subject to advance approval by the commission. ARM argued that any commission regulation or oversight is inconsistent with PURA §39.001(c) and (d), which respectively preclude the commission from regulating competitive electric services and direct the commission to order competitive rather than regulatory solutions to achieve statutory goals to the greatest extent possible. ARM further averred that requiring commission approval for a REP's voluntary low-income programs and benefits is likely to dissuade REPs from considering alternatives outside procuring a list of low-income customers as directed in PURA §17.007, given the time and resources necessary to obtain such approval. ARM argued that the proposed reporting and approval requirements in §25.45(i) may entail a proprietary customer identification process and methodology the REP does not wish to publicly disclose, further dissuading the REP.

Commission Response

The commission declines to adopt the proposal for a new §25.45(i), and also declines to adopt all references to the REP's "LILA alternative" that Texas ROSE and TLSC proposed to include elsewhere throughout the proposed rule provisions. The commission finds that a secondary process like the proposed "LILA alternative" is inefficient and administratively burdensome given the availability of the LILA. In addition, the commission finds that PURA §17.007 does not provide for a "LILA alternative" as proposed by Texas ROSE and TLSC.

§25.107--Certification of Retail Electric Providers

Subsection (f)--Financial Requirements

In initial comments, ARM stated that proposed paragraph (f)(6) does not fully synchronize with the proposed amendments to §25.43 that conditionally provide for the proceeds of a defaulting REP's letter of credit to be used first for the provision of deposit payment assistance for eligible low-income customers. ARM recommended that this provision be modified to more closely track the existing language, and proposed new language in subsection (f)(6)(A) to add new clauses to parallel the existing language.

In initial comments, Texas ROSE and TLSC proposed language in subsection (f) to give priority to paying the deposits of low-income customers when a REP is receiving the LILA list or using a LILA alternative. In replies, ARM opposed Texas ROSE and TLSC's proposal, asserting that the proposed revision fail to account for the conditional availability of the LILA service. Additionally, ARM recommended that, for reasons it stated in response to §25.5(67), it opposes inclusion of any reference to a "LILA alternative" in the commission's rules.

Commission Response

The commission adopts ARM's proposed language to parallel existing language for improved clarity in the rule.

With respect to Texas ROSE and TLSC's proposal to include the term "LILA alternative,"" the commission responds in its discussion of Texas ROSE and TLSC's proposed new §25.45(i) above.

§25.431--Retail Competition Pilots

Texas ROSE and TLSC proposed language requiring a report on the number of customers receiving a low-income rate discount in subsection (j)(3)(D). Texas ROSE and TLSC asserted that if such programs are part of a retail competition pilot project, they should be reported to the commission.

In replies, ARM opposed the proposal. ARM asserted that the rule is effective between June 1, 2001, and January 1, 2002, so the proposed modification would have no effect or purpose. ARM argued that, in the event that §25.431 is modified or adopted for purposes of any future retail competition pilot project, Texas ROSE and TLSC may seek its proposed revision at such a time. ARM noted its concerns with respect to the competitively sensitive nature of such information for reporting purposes.

Commission Response

The commission declines to adopt the proposed revisions made by Texas ROSE and TLSC because such revisions are outside the scope of this rulemaking proceeding.

§25.475--General Electric Provider Requirements and Information Disclosures to Residential and Small Commercial Customers

Subsection (f)--Terms of Service Document

In initial comments, Texas ROSE and TLSC asserted that disclosures to customers should be clear as to the residential customer's rights and protections pursuant to the commission rules and any programs and services the REP voluntarily provides. Texas ROSE and TLSC asseverated that, for competition to be fair, there must be a clear distinction made between rule requirements and voluntary programs. Texas ROSE and TLSC proposed additional language requiring that the Terms of Service documents provide a description of payment arrangements and bill payment assistance programs required by the commission's rules and any additional payment arrangement, bill payment assistance program, and rate reduction program voluntarily offered by the REP.

In initial comments, ARM asserted that subsection (f)(3)(E) should be deleted to remove the inclusion of the split deposit provision in the Terms of Service document. In reply comments, ARM disagreed with Texas ROSE and TLSC's proposed revisions to subsection (f)(3)(E). ARM asserted that it would require additional detailed disclosures of certain voluntarily provided programs in the Terms of Service document, which would have the result of creating a perverse disincentive for a REP to not offer such programs or benefits, or not to modify them over time, given the significant costs that would be incurred in revising these documents. ARM argued that the commission should reject the proposed revisions given that they would require greater specification of programs in those documents than is already required. ARM asserted that requiring a REP to report payment arrangements and bill payment assistance programs in the Terms of Service provides no incremental value to the customer. ARM further stated that this would create uncertainty about how a REP would distinguish payment arrangements and assistance programs in the Terms of Service. ARM also objected to Texas ROSE and TLSC's proposal to include the term "rate reduction program" in the proposed rule, for reasons it argued elsewhere.

Commission Response

The commission finds that the proposed language regarding the Terms of Service document is clear and provides sufficient transparency to customers. The commission finds that, at this time, the additional proposals made by Texas ROSE and TLSC would unnecessarily add cost and possibly discourage REPs from participating in the low-income customer identification service. Additionally, for reasons discussed in its response to comments received on §25.478(e) below, the commission deletes §25.475(f)(3)(E).

Subsection (h)--Your Rights as a Customer Disclosure

ARM stated that, while it appreciated the intent of the proposed rule language to inform the customer of availability of discounts for qualified low-income residential customers, the proposed language may discourage REPs from offering discounts to low-income customers because the provision of any such programs will necessitate significant revisions to a key contract document. ARM noted that such a document change would entail legal and regulatory compliance reviews, brand management review, design and printing costs, write down of already printed obsolete inventory, and agent training, among other costs. ARM suggested language to achieve the intended effect of the proposed language at a lower cost, proposing language in subsection (h)(5)(D) to state that a REP may comply with this requirement by "providing the customer with instructions for how to inquire about such discounts."

In initial comments, Texas ROSE and TLSC asserted that the commission must ensure that any voluntary rate reduction program maintains a broad range of choices for the low-income customer, consistent with the commission's mission to foster competition. To that end, Texas ROSE and TLSC proposed amending references in subsection (h)(5)(D) to the term "discount" to the term "rate reduction program," which is defined as being transferable to any plan or product offered by the REP.

In replies, ARM disagreed with Texas ROSE and TLSC's proposed change, asserting that it would require additional detailed disclosures of certain voluntarily provided programs in the Your Rights As a Customer document, which would have the result of creating a perverse disincentive for a REP to not offer such programs or benefits, or not to modify them over time, given the significant costs that would be incurred in revising these documents for the purpose of listing and describing those services. ARM argued that the commission should reject the proposed revision given that they would require greater specification of programs in those documents than is already required.

Commission Response

The commission adopts the language proposed by ARM to ensure that customers receive information regarding the availability of discounts, while also reducing costs to the market of utilizing the LILA service. With respect to the proposals made by Texas ROSE and TLSC, the commission declines to adopt the proposal. The commission finds that such a proposal would be contrary to the spirit of PURA §17.007, and would be overly prescriptive in directing REPs the manner in which to develop their low-income programs.

§25.478, Credit Requirements and Deposits

Subsection (e)--Amount of Deposit

ARM and TEAM opposed the split deposit provision. TEAM argued that the proposed rule is inconsistent with PURA §17.008(h), which TEAM asserted recognizes a REP's authority to require a deposit as a condition of receiving service, and also with §25.478(c), which provides that, if satisfactory credit cannot be demonstrated by a residential applicant, a REP may require the applicant to pay a deposit prior to receiving service. Similarly, ARM asserted the proposed rule is inconsistent with PURA §17.007(c), which provides that the commission may not require a REP to offer customer service, discounts, bill payment assistance, targeted bill messaging, or other benefits for which the REP is not reimbursed. ARM asserted that the bill's sponsor acknowledged that the bill prohibits the commission from requiring a REP to take on unreimbursed costs created by special rule. ARM argued that the commission should support competitive solutions over regulatory mandates, citing 15 years of market maturity after the introduction of customer choice. ARM stated that an emphasis on competitive outcomes is consistent with the overarching legislative policies and purposes applicable to the state's restructured electric industry as enshrined in PURA §39.001. ARM argued that the shift from unfunded to voluntary low-income programs and benefits will increase the incentive for REPs to differentiate themselves in the market by offering such programs and benefits that they might not otherwise offer.

TEAM stated that the intent of the language indicates that the first deposit installment would be due in 10 days after notice of requirement for deposit, which would appear to require a REP to provide 10 days of power without any deposit payment for all customers. TEAM argued that this requirement would place a tremendous financial risk on REPs, and likely results from confusion that the rule section addresses both initial deposits and potential additional deposits on existing customers.

OPUC, TCAP, and Texas ROSE and TLSC generally supported the proposed rule. OPUC and TCAP agreed that PURA §39.101(e) requires the Commission to adopt and enforce rules for "minimum service standards for a retail electric provider relating to customer deposits and extension of credit, switching fees, and levelized billing programs (…) termination of service, and quality of service." OPUC asserted that PURA provides that, even in competitive markets, the commission has a duty to ensure that customers are protected and have access to "safe, reliable, and reasonably priced electricity" per PURA §39.101(a)(1). OPUC stated that consumers should have access to affordable electric service as a matter of policy and law. Similarly, Texas ROSE and TLSC asserted that, in Project No. 25360, Rulemaking Proceeding to Amend Requirements for Provider of Last Resort Service, the commission found that allowing low-income customers to pay deposits in installments is consistent with its obligations to protect the health and safety of electric customers. Texas ROSE and TLSC argued that allowing all residential retail customers not otherwise eligible for a deposit waiver two months to pay a security deposit significantly reduces customer barriers to choosing REPs and products of their choice, furthering the policy set out in PURA §17.004(a).

ARM argued that requiring the split deposit provision for all residential customers would contravene the policy plainly articulated in Project No. 27084, PUC Rulemaking to Revise Customer Protection Rules, in which the commission adopted an increase in the maximum deposit amount from 1/6th to 1/5th of the customer's annual billing, that "it is reasonable to permit REPs who want to fully protect themselves from a customer who is determined to be a credit risk to do so." ARM asserted that, if it cannot collect the full deposit from such a customer around the time it initiates service, it will be financially exposed until the customer has paid the deposit in full. ARM asserted that mandating a split deposit provision for all residential customers is also inconsistent with the fundamental purpose and function of a security deposit, which is to provide adequate protection from certain customers. Further, ARM cited the commission's response in the rulemaking that, under the prior rule, "REPs were permitted to request a deposit that did not adequately reflect the amount of service provided to customers on credit, and non-affiliated REPs could not request that a customer who failed to pay their bill be disconnected, thereby limiting the consequences of such non-payment. These prior rules did not permit REPs to adequately protect themselves, and their other customers, from non-paying customers if the REP so chose." ARM argued that the commission considered applying the split deposit provision to all residential customers, but rejected it on the grounds that "such a proposal would negate the protection against non-payment that a deposit provides for a REP." Similarly, ARM asserted that, in Project No. 31417, Rulemaking Relating to the Discount for Low-Income Electric Customers, the commission also considered extending the split deposit provision to all residential customers, and cited then-Commissioner Smitherman's memorandum that such a market-wide requirement would place "too great a financial risk on REPs and is not sufficiently tailored to serving low-income customers' needs, especially when alternatives exist that are more tailored."

ARM asserted that allowing the provider to collect a security deposit from customers who present a credit risk in advance of providing several weeks' worth of electric service on credit is a well-established business practice in both regulated and competitive retail markets, as codified in §25.24, which establishes deposit requirements applicable to electric utilities in the regulated retail electric market and §25.478, which establishes deposit requirements applicable to REPs in the competitive retail electric market. ARM and TEAM argued that the split deposit provision for all residential customers is without precedent in the Texas electric industry, noting that it was not required of the vertically integrated electric utilities prior to the restructuring of the market, and there is no similar provision in the commission's rules or statute for the investor-owned utilities outside of ERCOT, electric cooperatives, or municipally owned utilities. ARM and TEAM agreed that requiring a split deposit provision would fundamentally change the regulatory construct under which REPs have designed post-paid products. ARM stated that it was not aware of any split deposit provision in any other industry, and urged the commission to reaffirm its prior decisions in Project Nos. 27084 and 31417 concluding that a requiring a REP to offer installment payments on security deposits to all residential customers would "negate the protection against non-payment that a deposit provides for a REP."

OPUC and Texas ROSE and TLSC asserted that the proposed revision would help ensure that customers can afford the necessity of electric service, and fulfills the commission's mission to protect customers. Texas ROSE and TLSC argued that, in Project No. 27084, the commission reiterated a REP's requirement to notify low-income customers of their right to pay the security deposit in two payments, even though it did not require the same treatment for all other customers whose security deposits were otherwise waived. Texas ROSE and TLSC asserted that, in Project No. 31417, the commission stated that it intended for the split deposit option to be available for low-income customers "regardless of the availability of a list of customers eligible for a rate reduction program." Texas ROSE and TLSC noted that, in that project, the commission continued to require REPs to provide notice of this split deposit option and required low-income applicants to show that they were qualified, finding that the amendments would "help ensure that the deposit installment option remains available to all low-income customers, while minimizing the administrative and economic burden on REPs."

ARM stated that many REPs offer customer accommodations. Some REPs require less than the maximum commission-allowed deposit amounts, others employing lower security deposit thresholds, and yet others outright waive deposits altogether. In light of this, ARM asserted that these business decisions are best left to the competitive market. Similarly, TEAM noted that all customers have an option to receive power without a deposit through a 12 months' good payment history or a pre-pay product, and, in a competitive market, a REP has an obligation to serve all customers. ARM stated that in the absence of a REP's ability to promptly collect a security deposit that fully reflects the risk of a particular customer, the ability of a REP to engage in these types of customer courtesies will diminish, and REPs may begin to rely on a more stringent definition of what constitutes satisfactory credit to waive a deposit, resulting in a ripple effect on all customers.

In replies, Texas ROSE and TLSC asserted that ARM implies that a customer who is unable to pay a security deposit should enroll for a prepay product, and that this reasoning is contrary to ensuring that customers have access to the products offered in the retail electric market rather than a single product. Texas ROSE and TLSC asserted that prepay plans are higher, subject to change, and have barrier problems such as the initial balance, daily service charges, minimum daily usage fees, and required continued maintenance of a balance. Texas ROSE and TLSC asserted that balances are functionally deposits that are depleted and must be replenished at times when the customer lacks funds. Texas ROSE and TLSC asserted that prepay plans do not have the option to pick a due date as with other plans, noting that the customer is subject to disconnection anytime the balance falls below a certain amount, which may mean multiple disconnections in a single month. Texas ROSE and TLSC asseverated that all customers should have reasonable access to products that are fixed price, as well as variable or indexed. Texas ROSE and TLSC noted that prepaid plans do not tend to provide fixed service prices, citing recent offers on PowerToChoose.org.

In addressing the preamble question regarding the cost of extending the split deposit provision to all customers, TEAM asserted that the cost would be increased uncollectible risk, which would have the subsequent effect of increasing the financial exposure to the REP associated with that uncollectible risk. Similarly, ARM noted that a REP must provide approximately 70 days of service to a customer before it can legally issue a disconnect for non-pay, calculating for the billing cycle, the time to obtain the electric usage and issue a bill, the date by which the customer can be considered late in payment, the notice period, and time to prepare and process the disconnection. Under this timeline, ARM stated that the first date for the customer's eligibility for a disconnection for non-pay would be on the 60th day after initiating service. ARM and TEAM argued that a REP would provide an additional 30 days of service for which it may never receive payment, even assuming that the first deposit installment covered the first month's estimated billings, and that extending this split deposit to all residential customers would introduce tremendous financial exposure for the REP.

In replies, TEAM averred that a mandate for REPs to require a split deposits for all applicants could allow a customer to continually move between REPs without paying for a significant portion of electricity. TEAM argued that, even under the most conservative, streamlined approach, a REP is exposed for an additional 30 days of cost with no reasonable means of obtaining payment. TEAM argued that, on a 60 day timeline, a customer could receive 60 days of service at the cost of 30 days' deposit by turning on service with a new REP, and paying a 30 day deposit in exchange for 60 days of service. TEAM asserted that a customer could leapfrog across six REPs per year, leaving each REP with 30 days of unpaid service and the market with six months of unpaid service. Similarly, ARM asserted that a majority of customer defaults today occur within the first few months of service.

ARM stated that a REP could choose to delay initiating service until it receives the deposit, but that the forces of competition will likely exert strong pressure on a REP to initiate service before any portion of the deposit is received. ARM asserted that most REPs would likely tighten their collection practices to address the additional risk posed by the split deposit in order to maintain cash flow.

Utilizing ERCOT switching data and its timeline from flowing power to disconnection, ARM estimated the total potential cost of extending the split deposit provision to all residential customers to be in the range of $28.6 million to $158.8 million based on bad debt exposure alone, not including the costs of IT project expenditures, personnel training, documentation revising, and other implementation costs that the REPs would incur. TEAM noted that the provision would increase the cost of manual processes through increased operational costs, as the REP would need to process each of the split deposits through one-on-one contact with the customer, which would add cost and take away resources from addressing customer needs. TEAM asserted that these costs will not be recovered from some customers who switch away after disconnection. ARM asserted that, on the low end, if the REP were to delay initiating service until the rest of the deposit was received, such costs could be $15.5 million to $90.8 million. ARM stated that, even assuming a conservative scenario in which REPs tighten credit and collections processes, increase deposit amounts, expand deposit assessment rates, or shorten disconnection timelines, the impacts would still be in the range of $11.4 million to $63.5 million per year.

In replies, Texas ROSE and TLSC critiqued ARM's analysis, asserting that almost all evidentiary facts presented by ARM in their initial comments were confidential, and the few facts available involve minimal administrative burdens that, when applied uniformly, present no competitive disadvantage. With respect to the administrative burdens, Texas ROSE and TLSC stated that the REPs will be required to change their regulatory documents as a result of the termination of the System Benefit Fund, training will have to be conducted regardless, and establishing a second payment date for the REP's requested security deposit is a second line to be filled out. Texas ROSE and TLSC stated that REPs can adjust the forms currently in use for low-income customers for all customers. Texas ROSE and TLSC stated that in Project No. 31853, Rulemaking Relating to Amendment of Credit and Deposit Requirements for Victims of Family Violence and Low-Income Elderly Customers, the commission found that similar additional notice provisions would not be burdensome for REPs. Similarly, in replies, OPUC stated that ARM and TEAM have not provided any compelling evidence that the proposal will have major deleterious cost impacts, stating that the current requirement was available to the 527,366 customers eligible for the System Benefit Fund in 2016, or approximately ten percent of the customers in the competitive market. OPUC stated that it was unaware of any bankruptcies or other major financial problems that occurred as a result of providing the split deposit provision to these customers. OPUC argued that REPs have been managing split deposits for customers receiving the low-income electric discount under the System Benefit Fund for more than a decade, and that it is reasonable to assume that REPs have already streamlined business operations to account for this requirement. OPUC stated that cost increases, if any, associated with maintaining the current requirement should be minimal. OPUC stated that the assumed monetary impact asserted by ARM and TEAM is overstated and based on unrealistic assumptions, such as ARM's estimate that 25 to 55% of its customers would be eligible for this benefit.

With respect to ARM's analysis of potential financial exposure, Texas ROSE and TLSC stated that ARM fails to establish a baseline of financial exposure in what the REPs' current financial exposure is for these applicants to either not pay their deposits or fail to pay the first or second month's bills. Texas ROSE and TLSC stated that ARM failed to exclude applicants whose security deposits are waived and low-income customers, therefore making the analysis meaningless. Texas ROSE and TLSC asserted that, on the contrary, applying the proposed rule with the extended split deposit provision will reduce financial exposure because a deposit of 2.4 months' (1/5th of 12 = 2.4 months) worth of billings to be paid within 10 days could pose a significant barrier to customers, resulting in nonpayment. Texas ROSE and TLSC argued that the split deposit increases the chances a customer will be able to pay his or her bills and maintain electric service, which is in the public interest.

Furthermore, Texas ROSE and TLSC stated that ARM's analysis inappropriately assumes that applicants start obtaining service the day of signing up and receiving the deposit request. Texas ROSE and TLSC estimated the time lag between execution of contract and initiation of services to be six days, citing the right of rescission, additional days to mail the document, the date the applicant wants to switch. Texas ROSE and TLSC reference one REP's Terms of Service document available on PowerToChoose.org that states initiation of service can occur anytime between two hours and four days.

Texas ROSE and TLSC asserted that a more reasonable assumption for the first deposit due date for the average applicant would be at the midpoint of the first billing cycle, leaving only 15 days prior to the end of the billing cycle, not 30 days as asserted by ARM and TEAM. Texas ROSE and TLSC additionally questioned the days that ARM relied upon to issue a notice to terminate service, stating that PUC rules allow for the REP to issue the termination notice the day after the payment deadline, not the five days assumed by ARM. Texas ROSE and TLSC also argued that ARM understated the amount of financial protection a REP has, using the lower two months instead of the higher 1/5th of an applicant's estimated annual usage. Texas ROSE and TLSC asserted that, in general, ARM exaggerates the financial exposure to the market.

TEAM replied that Texas ROSE and TLSC failed to account for the dramatic increase in costs to the REP, and ultimately all customers, that will result from offering the split deposit provision to all residential customers. TEAM argued that, somewhat similarly, the utilities outside ERCOT are not required to offer split deposits to all residential customers, as costs would go up due to the increase in the utilities' bad debt and collection costs, ultimately raising costs to all customers.

As an alternative, OPUC proposed in reply comments that the commission implement the expanded split deposit provision for a finite period of time in order to assess the financial and other impacts on REPs and customers, requiring REPs to collect information about the costs associated with the requirement, the number of customers required to pay a deposit, the number of those customers opting for the split payment, the nonpayment rate, and any other associated costs. OPUC asserted that this would allow the commission to consider actual cost information and impact when determining whether to continue or to sunset the split payment option, while ensuring that customers do not lose an important cost management tool and that REPs do not incur unexpected costs indefinitely.

TEAM asserted that the impact to small business and local employment impact statement in the proposal for publication needed to be revised. TEAM stated that, while these statements concluded that there would be no adverse economic effect, such a rule would have an adverse economic impact on REPs that are also a small business. TEAM averred that the proposal for publication incorrectly concludes that a regulatory flexibility analysis and an employment impact statement is not required under the Administrative Procedure Act §2001.002.

Commission Response

The commission agrees with ARM that the split deposit provision would be inconsistent with PURA §17.007(c). While it is unclear the amount of the costs to the REPs as a result of the commission adopting the proposed rule to split the deposit for all customers, it is clear that there would be costs that would not be reimbursed, which would be contrary to the new provisions in SB 1976. Therefore, the commission removes the requirement for REPs to provide a two month deposit option to all customers.

§25.480--Bill Payment and Adjustments

Subsection (c)--Penalty on Delinquent Bills for Electric Service

Texas ROSE and TLSC argued that the expansion of the late fee penalty waiver to all customers is appropriate given a change in circumstances since the commission decided, in Project No. 22255, PUC Rulemaking Proceeding for Customer Protection Rules for Electric Restructuring Implementing SB 7 and SB 86, to allow a late fee penalty for all residential customers except low-income customers. Texas ROSE and TLSC asserted that, in that project, the commission determined that a late fee could be assessed to ensure timely payments in light of the fact that REPs could not disconnect for non-payment, while the commission excluded a POLR REP from charging a late fee, because it had the right to disconnect for non-pay. Texas ROSE and TLSC noted that, in that project, the commission prohibited a REP from charging low-income customers a late fee penalty.

Texas ROSE and TLSC argued that the commission initially adopted the late fee penalty not based on the cost to the REPs of non-payment or late payment, but as a proxy for the threat of disconnection, which REPs now have in the form of disconnection for non-pay. Texas ROSE and TLSC asserted that a REP can now place a switch-hold on a customer with whom it has entered into a deferred payment plan, allowing the REP to collect the amount underlying the deferred payment plan even if the customer is disconnected for non-pay. Texas ROSE and TLSC averred that, as the commission's reasoning for adopting the late fee penalty no longer exists, REPs should no longer be allowed to charge a late fee payment to residential customers. Texas ROSE and TLSC argued that this prohibition would make the competitive market consistent with the monopoly markets outside of ERCOT, as provided for in §25.28(b). To effectuate this, Texas ROSE and TLSC proposed striking language that limits the late fee penalty waiver to POLR only, and removing the protection for small commercial customers on POLR.

ARM opposed this proposal. ARM asserted that the commission has allowed a REP to assess a one-time charge for delinquent payment since the commencement of retail competition in Texas. ARM noted that the commission, in Project No. 22255, allowed a REP to charge such a fee as "an appropriate incentive to ensure timely payments." ARM argued that eliminating the ability to assess a late fee would unfairly deprive a REP of an effective tool to reduce its bad debt exposure by promoting the timely payment of electric bills and incenting the customer to avoid accumulating an unpaid balance. ARM argued that, absent late fees, a residential customer has no incentive to pay their electric bill on time, as the only consequence is disconnection for non-payment pursuant to the commission's rules.

ARM argued that the monopoly vertically integrated utilities outside ERCOT have an opportunity to recover bad debt through rates established by the commission pursuant to §25.231(b), and that the utilities' lack of authority to assess late fees can be rationalized on such grounds. ARM argued that a REP has no such regulatory backstop. ARM further noted that late payment fees are commonly used in the municipally owned utilities in ERCOT, with CPS Energy charging a two percent late payment charge, Austin Energy assessing a five percent fee, the City of Georgetown a 10% fee, and Pedernales Electric Cooperative assessing a $20 fee. ARM noted that, furthermore, none of these tariffs appeared to limit the assessment of the late fee to a single instance, unlike the one-time limitation provided by §25.480. ARM stated that even the commission itself uses late payment penalties per PURA §16.003, charging a 10% penalty against those utilities, REPs, and electric cooperatives within its jurisdiction that fail to timely remit the public utility gross receipts assessment.

Commission Response

The proposal by Texas ROSE and TLSC to expand the late fee penalty waiver to all customers is beyond the scope of this rulemaking. The commission therefore declines to adopt the proposal.

Subsection (h)--Level and Average Payment Plans

In initial comments, TCAP noted that the proposed rule extended the split deposit provision to all residential ratepayers, regardless of income status, along with a written notice of this option, and that such treatment should be extended to include level and average bill payment plans to all customers, regardless of income status and even when a customer is delinquent in payment. Texas ROSE and TLSC asserted that customers with poor credit scores and limited income need a level and average bill payment plan the most. To effectuate this, Texas ROSE and TLSC proposed to strike language limiting the level or average bill payment plan to customers who are not currently delinquent in payment, with the effect of requiring a REP to offer a level or average bill payment plan to all customers, regardless of their delinquency status. Similarly, TCAP argued that customers who access a level or average payment plan should not run the risk of having a switch-hold placed on them per §25.480(h)(6).

ARM opposed Texas ROSE and TLSC's proposal. ARM asserted that the current subsection (h) was adopted by the commission in Project No. 36131 in 2010 to expand eligibility for level and average payment plans. ARM noted that, prior to adoption of the provision in its present form, subsection (h) required a REP to only make a level or average payment plan available to a customer that is not currently delinquent in payment to the REP. In Project No. 36131, ARM noted that the commission decided to allow a delinquent customer to access such a payment plan, under certain conditions, but to permit the REP to apply a switch-hold to the delinquent customer's account at the time the level or average payment plan is executed. ARM stated that, upon adoption, the commission noted that some REPs face challenges with bad debt, and expanded eligibility for level and average payment plans would exacerbate the bad debt experience. ARM further stated that, in justifying the application of a switch-hold to a delinquent customer's account at the time the payment plan is executed, the commission stated that the rule was an expansion of the REP's responsibility to undertake significant risk of customers failing to pay by extending additional credit to customers that, under the current rules, would not qualify, and that allowing REPs to employ switch-holds would help protect customers from higher prices that may result from the increased risk of non-payment associated with the extension of additional credit. ARM argued that the commission's rationale in support of the current treatment of level and average payment plans for delinquent versus non-delinquent customers remains valid today, contrary to any proposals to amend subsection (h).

In replies, ARM argued that TCAP's proposal seeks to provide to all residential customers a protection that had not even formerly existed for low-income customers, effectively repealing a provision in the customer protection rules in blatant disregard for the lawful scope of this project. Similarly, TEAM asserted that this proposed change is outside the scope of the instant rulemaking. ARM argued that TCAP offered no credible justification for the need to expand residential customer access to such plans under the proposed terms, and provides no analysis of commission precedent or statutory law in support of the proposed modification. TEAM argued that expanding level and average payment plans to all residential customers would not be consistent with good public policy, as it would increase the financial risk associated with requiring such an extension of credit, resulting in an overall increase of costs to all customers.

In reply comments, Texas ROSE and TLSC asserted that the late fee penalty waiver is properly extended to all residential customers because a REP now has the ability to disconnect a customer for non-payment and put a switch-hold on a customer with a deferred payment arrangement to pay off a past-due balance. Texas ROSE and TLSC asserted that the switch-hold prevents a customer from switching REPs until the past debt is paid, regardless of whether or not the customer was disconnected for non-pay. Texas ROSE and TLSC asserted that the switch-hold provides adequate security to the REP to ensure that bills will be paid. Texas ROSE and TLSC asserted that all REPs who can now disconnect for non-payment of service should no longer be allowed to charge a late fee penalty to residential customers.

Commission Response

The proposal by Texas ROSE and TLSC to expand the late fee penalty waiver to all customers is beyond the scope of this rulemaking. The commission therefore declines to adopt the proposal.

With respect to the change proposed by TCAP regarding the applicability of switch-holds to low-income customers, the commission finds that TCAP's proposal regarding switch-holds is beyond the scope of this rulemaking, and therefore declines to adopt these proposed changes.

Subsection (j)--Deferred Payment Plans and Alternate Payment Arrangements

Texas ROSE and TLSC proposed language to broaden the scope of deferred payment plans from any low-income customer who requests one during high bill months to all residential customers who request one. Texas ROSE and TLSC noted that, in its adoption in Project No. 36131, in which the commission expanded payment arrangements to address low-income customers, the commission stated that PURA language reflects an explicit concern for the treatment of low-income customers, and that it was appropriate to expand deferred payment plans to low-income customers on this basis.

ARM opposed Texas ROSE and TLSC's proposal. ARM argued that the proposal would require a REP to offer deferred payment plans to all residential customers during the summer months to include customers who have been disconnected during the preceding 12 months, have submitted more than two payments during the preceding months that were found to have insufficient funds, customers who lack sufficient credit, or lack a satisfactory history of payment for electric service from a previous REP or utility, from receiving a deferred payment plan or alternate payment program.

ARM asserted that the commission adopted the current version of subsection (j) in Project No. 36131 to expand eligibility for deferred payment plans. ARM asserted that the preamble language indicates that the consumer parties supported the current subsection (j) to allow customers who have not been disconnected in the past 12 months to be eligible for a deferred payment plan. ARM asserted that the rationale by which the commission adopted the current subsection (j) still remains valid today.

In replies, TEAM asserted that this change was outside the scope of the rulemaking. Contrary to the assertion by Texas ROSE and TLSC, TEAM argued that Texas ROSE and TLSC did not provide any evidence that any applicant in the competitive market in Texas is unable to meet reasonable credit requirements and obtain electric service. In contrast to the areas outside ERCOT, TEAM argued that applicants in the competitive areas of Texas have multiple options for securing electric service.

TEAM argued that Texas ROSE and TLSC's proposal would expand the means by which REPs are mandated to finance a customer's bad debt and increase uncollectible accounts, resulting in an increase in costs to all customers, including those who were previously eligible to receive rate discounts under the System Benefit Fund. TEAM argued that this approach is directly contrary to the concept of a competitive market, where REPs use competitive offerings to attract and retain customers.

Commission Response

The commission declines to adopt the change proposed by Texas ROSE and TLSC with respect to extending the deferred payment plan to all customers, because the proposal is beyond the scope of this rulemaking.

Subsection (n)--Annual Reporting Requirement

Texas ROSE and TLSC proposed language to add "or the REP's LILA alternative" throughout subsection (n) where the proposed rule references the LILA, consistent with its overall proposal that a REP that does not opt-in to the LILA list be required to identify its low-income customers using a commission-approved process.

Texas ROSE and TLSC also proposed modifying subsection (n) to require a REP to include in its annual report a statement confirming its participation in obtaining the LILA list or its use of Texas ROSE and TLSC's proposed LILA alternative and detail any rate reduction programs, payment arrangements, and payment assistance programs that are offered by or available from the REP, in addition to those required by the commission's rules. Texas ROSE and TLSC proposed that the information be required to be publicly filed and available for consumers.

In replies, OPUC asserted that the commission should require public posting of this information. OPUC stated that it recognized, that while some information contained in the REP annual report is considered proprietary and confidential, the information is now a feature customers may consider as part of the competitive market. OPUC and TCAP supported posting this information on the PowerToChoose.org website, as well as on individual REP websites.

Similarly, OPUC asserted in reply comments that, given the commission's statutory authority in PURA §17.004(b) to protect low-income customers and ensure an affordable rate package, and in PURA §17.004(a)(4), which provides customer protection against discrimination based on income level, there is a compelling argument for the commission to ensure that inferior rate plans are not allowed for customers receiving the low-income discount or other programs allowed under these rules. OPUC asserted that the commission should amend the rule to specify that a customer receiving such a benefit may apply that discount to any product offering available from the REP.

In replies, ARM asserted that the proposed requirements in subsection (n) allow the Commission to monitor a REP's compliance with §25.480(g)(2)(A), which requires REPs to implement a bill payment assistance program for residential customers and requires that such programs solicit voluntary donations through bills, but does not require disclosure of employee or company donations, or the specific name and contact information of a company's assistance agency partners. ARM stated that, further, Texas ROSE and TLSC do not specify why such information should be included in the annual report, other than it would make the filing more meaningful.

Texas ROSE and TLSC proposed expanding the list of reporting requirements in subsection (n)(1) to include the amount of company donations, employee donations, number of customers assisted, the average amount of assistance paid out, and the name and contract information for assistance agencies selected to disburse funds to residential customers. Texas ROSE and TLSC asserted including that information would make the report more meaningful and that information publicly available. In replies, OPUC stated that it agreed with TCAP and Texas ROSE and TLSC's recommendation for additional reporting requirements on the number of customers receiving assistance and the average amount per customer.

Similarly, OPUC and TCAP asserted that reporting requirements should be expanded to disclose the total amount of company donations that a REP has pledged to support low-income rate discounts, and that this information should be posted on the PowerToChoose.org website for each certified REP. TCAP argued that the commission should ensure that rate assistance constitutes a real and tangible benefit for the low-income customer, and should adopt rules that prevent REPs from creating inferior product offerings specifically for low-income customers wherein those customers can obtain lower rates only by adopting restrictive consumption behavior, pricing deals involving block rates, or pricing deals involving usage credits and fees, and that expanding the reporting requirements will assist the commission in this task.

Texas ROSE and TLSC also proposed a new subsection (n)(3) requiring the reporting information to include the number of switch-holds applied during the year, deferred payment plans initiated during or after an extreme weather event, deferred payment plans provided during high usage summer months under §25.480(h), the number of customers who had a switch-hold removed, and the average amount of time a switch-hold was in place on a customer account.

ARM asserted that Texas ROSE and TLSC's proposal regarding additional reporting requirements for switch-holds was proposed with no rationale. ARM urged the commission to reject this proposal.

ARM opposed the Texas ROSE and TLSC's proposals, arguing that these proposals would circumvent a REP's ability under §22.71(d) to designate materials as confidential, contravening both common law and statutory principles with respect to a REP's right to protect competitively sensitive information from public disclosure. ARM asserted that, whether such information can be protected from public disclosure is a function of the scope of such law, and Texas ROSE and TLSC's proposal cannot automatically circumvent any protection that is lawfully asserted. ARM stated that, furthermore, §25.107(a)(4) acknowledges a REP may claim confidentiality when submitting its report. ARM argued that the proposal to require a REP to file information about its voluntary low-income and other programs and benefits in an annual report addendum submitted as an open record is beyond the Commission's authority, as is the proposal to require a REP to post this same information on PowerToChoose.org.

In initial comments, ARM proposed two revisions in subsection (n) to provide clearer language. It asserted that the proposed amendments include a list of examples of types of programs that the REPs might choose to offer, but that such a list can unintentionally limit the focus only to the matters listed. ARM noted that two of the listed examples are already required under the commission's rules. ARM stated that REPs are currently required to file annual reports with respect to bill payment assistance programs pursuant to §25.491(c)(4) and deferred payment plans are required to be offered by the REPs pursuant to §25.480(j) and §25.483(j). ARM asserted that information regarding voluntary payment options and payment assistance programs are generally considered competitively sensitive information, and such a broad-based reporting requirement would put such information at risk through Public Information Act requests, causing REPs to expend resources opposing such disclosure at the Office of the Attorney General. ARM asserted that it believes that the commission's intent is to monitor the types of low-income programs being offered. To this effect, ARM proposed more general language requiring the REP to report any low-income payment options and low-income payment assistance programs offered by or available from the REP, and striking the list of examples.

ARM also noted that the final subpart of proposed subsection (n) would require a REP to state whether or not it participates or plans to participate in the LILA process. ARM stated that it does not oppose the proposed language, but that the language could cause some confusion given that the REP's annual report is on a calendar-year basis while the LILA process begins on September 1. ARM proposed clarifying language to this effect.

Commission Response

The commission addresses the proposal regarding the LILA alternative in its response to comments received on §25.45(i) above.

With respect to the proposals made by Texas ROSE and TLSC to expand the reporting requirements and make certain information publicly available, the commission declines to adopt these proposals. These proposals are outside of the scope of the proposed amendments. Furthermore, as ARM notes, REPs have the right to assert that certain information be designated confidential as provided by §22.71(d). In addition, the commission adopts ARM's proposed modifications to subsection (n) make the rule language clearer.

All comments, including any not specifically referenced herein, were fully considered by the commission.

SUBCHAPTER A. GENERAL PROVISIONS

16 TAC §25.5

This amendment is adopted under §14.002 of the Public Utility Regulatory Act, Tex. Util. Code Ann. §14.002 (West 2016 and Supp. 2017) (PURA) which provides the commission with the authority to make and enforce rules reasonably required in the exercise of its powers and jurisdiction, including rules of practice and procedure; PURA §17.007, which provides for a process by which a REP can identify low-income customers; PURA §39.101, which provides the commission with the authority to ensure that retail customer protections are established to entitle a customer to safe, reliable, and reasonably priced electricity.

Cross reference to statutes: Public Utility Regulatory Act §14.002, §14.052, §17.007, §39.101.

§25.5.Definitions.

The following words and terms, when used in this chapter, shall have the following meanings, unless the context clearly indicates otherwise:

(1) Above-market purchased power costs--Wholesale demand and energy costs that a utility is obligated to pay under an existing purchased power contract to the extent the costs are greater than the purchased power market value.

(2) Affected person--means:

(A) a public utility or electric cooperative affected by an action of a regulatory authority;

(B) a person whose utility service or rates are affected by a proceeding before a regulatory authority; or

(C) a person who:

(i) is a competitor of a public utility with respect to a service performed by the utility; or

(ii) wants to enter into competition with a public utility.

(3) Affiliate--means:

(A) a person who directly or indirectly owns or holds at least 5.0% of the voting securities of a public utility;

(B) a person in a chain of successive ownership of at least 5.0% of the voting securities of a public utility;

(C) a corporation that has at least 5.0% of its voting securities owned or controlled, directly or indirectly, by a public utility;

(D) a corporation that has at least 5.0% of its voting securities owned or controlled, directly or indirectly, by:

(i) a person who directly or indirectly owns or controls at least 5.0% of the voting securities of a public utility; or

(ii) a person in a chain of successive ownership of at least 5.0% of the voting securities of a public utility;

(E) a person who is an officer or director of a public utility or of a corporation in a chain of successive ownership of at least 5.0% of the voting securities of a public utility; or

(F) a person determined to be an affiliate under Public Utility Regulatory Act §11.006.

(4) Affiliated electric utility--The electric utility from which an affiliated retail electric provider was unbundled in accordance with Public Utility Regulatory Act §39.051.

(5) Affiliated power generation company (APGC)--A power generation company that is affiliated with or the successor in interest of an electric utility certificated to serve an area.

(6) Affiliated retail electric provider (AREP)--A retail electric provider that is affiliated with or the successor in interest of an electric utility certificated to serve an area.

(7) Aggregation--Includes the following:

(A) the purchase of electricity from a retail electric provider, a municipally owned utility, or an electric cooperative by an electricity customer for its own use in multiple locations, provided that an electricity customer may not avoid any non-bypassable charges or fees as a result of aggregating its load; or

(B) the purchase of electricity by an electricity customer as part of a voluntary association of electricity customers, provided that an electricity customer may not avoid any non-bypassable charges or fees as a result of aggregating its load.

(8) Aggregator--A person joining two or more customers, other than municipalities and political subdivision corporations, into a single purchasing unit to negotiate the purchase of electricity from retail electric providers. Aggregators may not sell or take title to electricity. Retail electric providers are not aggregators.

(9) Ancillary service--A service necessary to facilitate the transmission of electric energy including load following, standby power, backup power, reactive power, and any other services the commission may determine by rule.

(10) Base rate--Generally, a rate designed to recover the cost of service other than certain costs separately identified and recovered through a rider, rate schedule, or other schedule. For bundled utilities, these separately identified costs may include items such as a fuel factor, power cost recovery factor, and surcharge. Distribution service providers may have separately identified costs such as transition costs, the excess mitigation charge, transmission cost recovery factors, and the competition transition charge.

(11) Bundled Municipally Owned Utilities/Electric Cooperatives (MOU/COOP)--A municipally owned utility/electric cooperative that is conducting both transmission and distribution activities and competitive energy-related activities on a bundled basis without structural or functional separation of transmission and distribution functions from competitive energy-related activities and that makes a written declaration of its status as a bundled municipally owned utility/electric cooperative pursuant to §25.275(o)(3)(A) of this title (relating to Code of Conduct for Municipally Owned Utilities and Electric Cooperatives Engaged in Competitive Activities).

(12) Calendar year--January 1 through December 31.

(13) Commission--The Public Utility Commission of Texas.

(14) Competition transition charge (CTC)--Any non-bypassable charge that recovers the positive excess of the net book value of generation assets over the market value of the assets, taking into account all of the electric utility's generation assets, any above market purchased power costs, and any deferred debit related to a utility's discontinuance of the application of Statement of Financial Accounting Standards Number 71 ("Accounting for the Effects of Certain Types of Regulation") for generation-related assets if required by the provisions of the Public Utility Regulatory Act (PURA), Chapter 39. For purposes of PURA §39.262, book value shall be established as of December 31, 2001, or the date a market value is established through a market valuation method under PURA §39.262(h), whichever is earlier, and shall include stranded costs incurred under PURA §39.263. Competition transition charges also include the transition charges established pursuant to PURA §39.302(7) unless the context indicates otherwise.

(15) Competitive affiliate--An affiliate of a utility that provides services or sells products in a competitive energy-related market in this state, including telecommunications services, to the extent those services are energy-related.

(16) Competitive energy efficiency services--Energy efficiency services that are defined as competitive energy services pursuant to §25.341 of this title (relating to Definitions).

(17) Competitive retailer--A retail electric provider; or a municipally owned utility or electric cooperative, that has the right to offer electric energy and related services at unregulated prices directly to retail customers who have customer choice, without regard to geographic location.

(18) Congestion zone--An area of the transmission network that is bounded by commercially significant transmission constraints or otherwise identified as a zone that is subject to transmission constraints, as defined by an independent organization.

(19) Control area--An electric power system or combination of electric power systems to which a common automatic generation control scheme is applied in order to:

(A) match, at all times, the power output of the generators within the electric power system(s) and capacity and energy purchased from entities outside the electric power system(s), with the load within the electric power system(s);

(B) maintain, within the limits of good utility practice, scheduled interchange with other control areas;

(C) maintain the frequency of the electric power system(s) within reasonable limits in accordance with good utility practice; and

(D) obtain sufficient generating capacity to maintain operating reserves in accordance with good utility practice.

(20) Corporation--A domestic or foreign corporation, joint-stock company, or association, and each lessee, assignee, trustee, receiver, or other successor in interest of the corporation, company, or association, that has any of the powers or privileges of a corporation not possessed by an individual or partnership. The term does not include a municipal corporation or electric cooperative, except as expressly provided by the Public Utility Regulatory Act.

(21) Critical loads--Loads for which electric service is considered crucial for the protection or maintenance of public health and safety; including but not limited to hospitals, police stations, fire stations, critical water and wastewater facilities, and customers with special in-house life-sustaining equipment.

(22) Customer choice--The freedom of a retail customer to purchase electric services, either individually or through voluntary aggregation with other retail customers, from the provider or providers of the customer's choice and to choose among various fuel types, energy efficiency programs, and renewable power suppliers.

(23) Customer class--A group of customers with similar electric service characteristics (e.g., residential, commercial, industrial, sales for resale) taking service under one or more rate schedules. Qualified businesses as defined by the Texas Enterprise Zone Act, Texas Government Code, Title 10, Chapter 2303 may be considered to be a separate customer class of electric utilities.

(24) Day-ahead--The day preceding the operating day.

(25) Deemed savings--A pre-determined, validated estimate of energy and peak demand savings attributable to an energy efficiency measure in a particular type of application that a utility may use instead of energy and peak demand savings determined through measurement and verification activities.

(26) Demand--The rate at which electric energy is delivered to or by a system at a given instant, or averaged over a designated period, usually expressed in kilowatts (kW) or megawatts (MW).

(27) Demand savings--A quantifiable reduction in the rate at which energy is delivered to or by a system at a given instance, or averaged over a designated period, usually expressed in kilowatts (kW) or megawatts (MW).

(28) Demand-side management (DSM)--Activities that affect the magnitude or timing of customer electrical usage, or both.

(29) Demand-side resource or demand-side management--Equipment, materials, and activities that result in reductions in electric generation, transmission, or distribution capacity needs or reductions in energy usage or both.

(30) Disconnection of service--Interruption of a customer's supply of electric service at the customer's point of delivery by an electric utility, a transmission and distribution utility, a municipally owned utility or an electric cooperative.

(31) Distribution line--A power line operated below 60,000 volts, when measured phase-to-phase, that is owned by an electric utility, transmission and distribution utility, municipally owned utility, or electric cooperative.

(32) Distributed resource--A generation, energy storage, or targeted demand-side resource, generally between one kilowatt and ten megawatts, located at a customer's site or near a load center, which may be connected at the distribution voltage level (below 60,000 volts), that provides advantages to the system, such as deferring the need for upgrading local distribution facilities.

(33) Distribution service provider (DSP)--An electric utility, municipally-owned utility, or electric cooperative that owns or operates for compensation in this state equipment or facilities that are used for the distribution of electricity to retail customers, as defined in this section, including retail customers served at transmission voltage levels.

(34) Economically distressed geographic area--Zip code area in which the average household income is less than or equal to 60% of the statewide median income, as reported in the most recently available United States Census data.

(35) Electric cooperative--

(A) a corporation organized under the Texas Utilities Code, Chapter 161 or a predecessor statute to Chapter 161 and operating under that chapter;

(B) a corporation organized as an electric cooperative in a state other than Texas that has obtained a certificate of authority to conduct affairs in the State of Texas; or

(C) a successor to an electric cooperative created before June 1, 1999, in accordance with a conversion plan approved by a vote of the members of the electric cooperative, regardless of whether the successor later purchases, acquires, merges with, or consolidates with other electric cooperatives.

(36) Electric generating facility--A facility that generates electric energy for compensation and that is owned or operated by a person in this state, including a municipal corporation, electric cooperative, or river authority.

(37) Electricity Facts Label--Information in a standardized format, as described in §25.475(f) of this title (relating to Information Disclosures to Residential and Small Commercial Customers), that summarizes the price, contract terms, fuel sources, and environmental impact associated with an electricity product.

(38) Electricity product--A specific type of retail electricity service developed and identified by a REP, the specific terms and conditions of which are summarized in an Electricity Facts Label that is specific to that electricity product.

(39) Electric Reliability Council of Texas (ERCOT)--Refers to the independent organization and, in a geographic sense, refers to the area served by electric utilities, municipally owned utilities, and electric cooperatives that are not synchronously interconnected with electric utilities outside of the State of Texas.

(40) Electric service identifier (ESI ID)--The basic identifier assigned to each point of delivery used in the registration system and settlement system managed by the Electric Reliability Council of Texas (ERCOT) or another independent organization.

(41) Electric utility--Except as otherwise provided in this Chapter, an electric utility is: A person or river authority that owns or operates for compensation in this state equipment or facilities to produce, generate, transmit, distribute, sell, or furnish electricity in this state. The term includes a lessee, trustee, or receiver of an electric utility and a recreational vehicle park owner who does not comply with Texas Utilities Code, Subchapter C, Chapter 184, with regard to the metered sale of electricity at the recreational vehicle park. The term does not include:

(A) a municipal corporation;

(B) a qualifying facility;

(C) a power generation company;

(D) an exempt wholesale generator;

(E) a power marketer;

(F) a corporation described by Public Utility Regulatory Act §32.053 to the extent the corporation sells electricity exclusively at wholesale and not to the ultimate consumer;

(G) an electric cooperative;

(H) a retail electric provider;

(I) the state of Texas or an agency of the state; or

(J) a person not otherwise an electric utility who:

(i) furnishes an electric service or commodity only to itself, its employees, or its tenants as an incident of employment or tenancy, if that service or commodity is not resold to or used by others;

(ii) owns or operates in this state equipment or facilities to produce, generate, transmit, distribute, sell or furnish electric energy to an electric utility, if the equipment or facilities are used primarily to produce and generate electric energy for consumption by that person; or

(iii) owns or operates in this state a recreational vehicle park that provides metered electric service in accordance with Texas Utilities Code, Subchapter C, Chapter 184.

(42) Energy efficiency--Programs that are aimed at reducing the rate at which electric energy is used by equipment and/or processes. Reduction in the rate of energy used may be obtained by substituting technically more advanced equipment to produce the same level of end-use services with less electricity; adoption of technologies and processes that reduce heat or other energy losses; or reorganization of processes to make use of waste heat. Efficient use of energy by customer-owned end-use devices implies that existing comfort levels, convenience, and productivity are maintained or improved at a lower customer cost.

(43) Energy efficiency measures--Equipment, materials, and practices that when installed and used at a customer site result in a measurable and verifiable reduction in either purchased electric energy consumption, measured in kilowatt-hours (kWh), or peak demand, measured in kW, or both.

(44) Energy efficiency project--An energy efficiency measure or combination of measures installed under a standard offer contract or a market transformation contract that results in both a reduction in customers' electric energy consumption and peak demand, and energy costs.

(45) Energy efficiency service provider (EESP)--A person who installs energy efficiency measures or performs other energy efficiency services. An energy efficiency service provider may be a retail electric provider or large commercial customer, if the person has executed a standard offer contract.

(46) Energy savings--A quantifiable reduction in a customer's consumption of energy.

(47) ERCOT protocols--Body of procedures developed by ERCOT to maintain the reliability of the regional electric network and account for the production and delivery of electricity among resources and market participants. The procedures, initially approved by the commission, include a revisions process that may be appealed to the commission, and are subject to the oversight and review of the commission.

(48) ERCOT region--The geographic area under the jurisdiction of the commission that is served by transmission service providers that are not synchronously interconnected with transmission service providers outside of the state of Texas.

(49) Exempt wholesale generator--A person who is engaged directly or indirectly through one or more affiliates exclusively in the business of owning or operating all or part of a facility for generating electric energy and selling electric energy at wholesale who does not own a facility for the transmission of electricity, other than an essential interconnecting transmission facility necessary to effect a sale of electric energy at wholesale, and who is in compliance with the registration requirements of §25.109 of this title (Registration of Power Generation Companies and Self-Generators).

(50) Existing purchased power contract--A purchased power contract in effect on January 1, 1999, including any amendments and revisions to that contract resulting from litigation initiated before January 1, 1999.

(51) Facilities--All the plant and equipment of an electric utility, including all tangible and intangible property, without limitation, owned, operated, leased, licensed, used, controlled, or supplied for, by, or in connection with the business of an electric utility.

(52) Financing order--An order of the commission adopted under the Public Utility Regulatory Act §39.201 or §39.262 approving the issuance of transition bonds and the creation of transition charges for the recovery of qualified costs.

(53) Freeze period--The period beginning on January 1, 1999, and ending on December 31, 2001.

(54) Generation assets--All assets associated with the production of electricity, including generation plants, electrical interconnections of the generation plant to the transmission system, fuel contracts, fuel transportation contracts, water contracts, lands, surface or subsurface water rights, emissions-related allowances, and gas pipeline interconnections.

(55) Generation service--The production and purchase of electricity for retail customers and the production, purchase and sale of electricity in the wholesale power market.

(56) Good utility practice--Any of the practices, methods, and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period, or any of the practices, methods, and acts that, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety, and expedition. Good utility practice is not intended to be limited to the optimum practice, method, or act, to the exclusion of all others, but rather is intended to include acceptable practices, methods, and acts generally accepted in the region.

(57) Hearing--Any proceeding at which evidence is taken on the merits of the matters at issue, not including prehearing conferences.

(58) Independent organization--An independent system operator or other person that is sufficiently independent of any producer or seller of electricity that its decisions will not be unduly influenced by any producer or seller.

(59) Independent system operator--An entity supervising the collective transmission facilities of a power region that is charged with non-discriminatory coordination of market transactions, systemwide transmission planning, and network reliability.

(60) Installed generation capacity--All potentially marketable electric generation capacity, including the capacity of:

(A) generating facilities that are connected with a transmission or distribution system;

(B) generating facilities used to generate electricity for consumption by the person owning or controlling the facility; and

(C) generating facilities that will be connected with a transmission or distribution system and operating within 12 months.

(61) Interconnection agreement--The standard form of agreement, which has been approved by the commission. The interconnection agreement sets forth the contractual conditions under which a company and a customer agree that one or more facilities may be interconnected with the company's utility system.

(62) License--The whole or part of any commission permit, certificate, approval, registration, or similar form of permission required by law.

(63) Licensing--The commission process for granting, denial, renewal, revocation, suspension, annulment, withdrawal, or amendment of a license.

(64) Load factor--The ratio of average load to peak load during a specific period of time, expressed as a percent. The load factor indicates to what degree energy has been consumed compared to maximum demand or utilization of units relative to total system capability.

(65) Low-income customer--An electric customer who receives Supplemental Nutrition Assistance Program (SNAP) from Texas Health and Human Services Commission (HHSC) or medical assistance from a state agency administering a part of the medical assistance program.

(66) Low-Income List Administrator (LILA)--A third-party administrator contracted by the commission to administer aspects of the low-income customer identification process established under PURA §17.007.

(67) Market power mitigation plan--A written proposal by an electric utility or a power generation company for reducing its ownership and control of installed generation capacity as required by the Public Utility Regulatory Act §39.154.

(68) Market value--For nonnuclear assets and certain nuclear assets, the value the assets would have if bought and sold in a bona fide third-party transaction or transactions on the open market under the Public Utility Regulatory Act (PURA) §39.262(h) or, for certain nuclear assets, as described by PURA §39.262(i), the value determined under the method provided by that subsection.

(69) Master meter--A meter used to measure, for billing purposes, all electric usage of an apartment house or mobile home park, including common areas, common facilities, and dwelling units.

(70) Municipality--A city, incorporated village, or town, existing, created, or organized under the general, home rule, or special laws of the state.

(71) Municipally-owned utility (MOU)--Any utility owned, operated, and controlled by a municipality or by a nonprofit corporation whose directors are appointed by one or more municipalities.

(72) Nameplate rating--The full-load continuous rating of a generator under specified conditions as designated by the manufacturer.

(73) Native load customer--A wholesale or retail customer on whose behalf an electric utility, electric cooperative, or municipally-owned utility, by statute, franchise, regulatory requirement, or contract, has an obligation to construct and operate its system to meet in a reliable manner the electric needs of the customer.

(74) Natural gas energy credit (NGEC)--A tradable instrument representing each megawatt of new generating capacity fueled by natural gas, as authorized by the Public Utility Regulatory Act §39.9044 and implemented under §25.172 of this title (relating to Goal for Natural Gas).

(75) Net book value--The original cost of an asset less accumulated depreciation.

(76) Net dependable capability--The maximum load in megawatts, net of station use, which a generating unit or generating station can carry under specified conditions for a given period of time, without exceeding approved limits of temperature and stress.

(77) New on-site generation--Electric generation capacity greater than ten megawatts capable of being lawfully delivered to the site without use of utility distribution or transmission facilities, which was not, on or before December 31, 1999, either:

(A) A fully operational facility, or

(B) A project supported by substantially complete filings for all necessary site-specific environmental permits under the rules of the Texas Natural Resource Conservation Commission (TNRCC) in effect at the time of filing.

(78) Off-grid renewable generation--The generation of renewable energy in an application that is not interconnected to a utility transmission or distribution system.

(79) Other generation sources--A competitive retailer's or affiliated retail electric provider's supply of generated electricity that is not accounted for by a direct supply contract with an owner of generation assets.

(80) Person--Includes an individual, a partnership of two or more persons having a joint or common interest, a mutual or cooperative association, and a corporation, but does not include an electric cooperative.

(81) Power cost recovery factor (PCRF)--A charge or credit that reflects an increase or decrease in purchased power costs not in base rates.

(82) Power generation company (PGC)--A person that:

(A) generates electricity that is intended to be sold at wholesale, including the owner or operator of electric energy storage equipment or facilities to which the Public Utility Regulatory Act, Chapter 35, Subchapter E applies;

(B) does not own a transmission or distribution facility in this state, other than an essential interconnecting facility, a facility not dedicated to public use, or a facility otherwise excluded from the definition of "electric utility" under this section; and

(C) does not have a certificated service area, although its affiliated electric utility or transmission and distribution utility may have a certificated service area.

(83) Power marketer--A person who becomes an owner of electric energy in this state for the purpose of selling the electric energy at wholesale; does not own generation, transmission, or distribution facilities in this state; does not have a certificated service area; and who is in compliance with the registration requirements of §25.105 of this title (relating to Registration and Reporting by Power Marketers).

(84) Power region--A contiguous geographical area which is a distinct region of the North American Electric Reliability Council.

(85) Pre-interconnection study--A study or studies that may be undertaken by a utility in response to its receipt of a completed application for interconnection and parallel operation with the utility system at distribution voltage. Pre-interconnection studies may include, but are not limited to, service studies, coordination studies and utility system impact studies.

(86) Premises--A tract of land or real estate or related commonly used tracts including buildings and other appurtenances thereon.

(87) Price to beat (PTB)--A price for electricity, as determined pursuant to the Public Utility Regulatory Act §39.202, charged by an affiliated retail electric provider to eligible residential and small commercial customers in its service area.

(88) Proceeding--A hearing, investigation, inquiry, or other procedure for finding facts or making a decision. The term includes a denial of relief or dismissal of a complaint. It may be rulemaking or nonrulemaking; rate setting or non-rate setting.

(89) Proprietary customer information--Any information compiled by a retail electric provider, an electric utility, a transmission and distribution business unit as defined in §25.275(c)(16) of this title (relating to Code of Conduct for Municipally Owned Utilities and Electric Cooperatives Engaged in Competitive Activities) on a customer in the course of providing electric service or by an aggregator on a customer in the course of aggregating electric service that makes possible the identification of any individual customer by matching such information with the customer's name, address, account number, type or classification of service, historical electricity usage, expected patterns of use, types of facilities used in providing service, individual contract terms and conditions, price, current charges, billing records, or any information that the customer has expressly requested not be disclosed. Information that is redacted or organized in such a way as to make it impossible to identify the customer to whom the information relates does not constitute proprietary customer information.

(90) Provider of last resort (POLR)--A retail electric provider (REP) certified in Texas that has been designated by the commission to provide a basic, standard retail service package in accordance with §25.43 of this title (relating to Provider of Last Resort (POLR)).

(91) Public retail customer--A retail customer that is an agency of this state, a state institution of higher education, a public school district, or a political subdivision of this state.

(92) Public utility or utility--An electric utility as that term is defined in this section, or a public utility or utility as those terms are defined in the Public Utility Regulatory Act §51.002.

(93) Public Utility Regulatory Act (PURA)--The enabling statute for the Public Utility Commission of Texas, located in the Texas Utilities Code Annotated, §§11.001 et. seq.

(94) Purchased power market value--The value of demand and energy bought and sold in a bona fide third-party transaction or transactions on the open market and determined by using the weighted average costs of the highest three offers from the market for purchase of the demand and energy available under the existing purchased power contracts.

(95) Qualified scheduling entity--A market participant that is qualified by the Electric Reliability Council of Texas (ERCOT) in accordance with Section 16, Registration and Qualification of Market Participants of ERCOT's Protocols, to submit balanced schedules and ancillary services bids and settle payments with ERCOT.

(96) Qualifying cogenerator--The meaning as assigned this term by 16 U.S.C. §796(18)(C). A qualifying cogenerator that provides electricity to the purchaser of the cogenerator's thermal output is not for that reason considered to be a retail electric provider or a power generation company.

(97) Qualifying facility--A qualifying cogenerator or qualifying small power producer.

(98) Qualifying small power producer--The meaning as assigned this term by 16 U.S.C. §796(17)(D).

(99) Rate--A compensation, tariff, charge, fare, toll, rental, or classification that is directly or indirectly demanded, observed, charged, or collected by an electric utility for a service, product, or commodity described in the definition of electric utility in this section and a rule, practice, or contract affecting the compensation, tariff, charge, fare, toll, rental, or classification that must be approved by a regulatory authority.

(100) Rate class--A group of customers taking electric service under the same rate schedule.

(101) Rate year--The 12-month period beginning with the first date that rates become effective. The first date that rates become effective may include, but is not limited to, the effective date for bonded rates or the effective date for interim or temporary rates.

(102) Ratemaking proceeding--A proceeding in which a rate may be changed.

(103) Registration agent--Entity designated by the commission to administer registration and settlement, premise data, and other processes concerning a customer's choice of retail electric provider in the competitive electric market in Texas.

(104) Regulatory authority--In accordance with the context where it is found, either the commission or the governing body of a municipality.

(105) Renewable demand side management (DSM) technologies--Equipment that uses a renewable energy resource (renewable resource) as defined in this section, that, when installed at a customer site, reduces the customer's net purchases of energy (kWh), electrical demand (kW), or both.

(106) Renewable energy--Energy derived from renewable energy technologies.

(107) Renewable energy credit (REC)--A tradable instrument representing the generation attributes of one MWh of electricity from renewable energy sources, as authorized by the Public Utility Regulatory Act §39.904 and implemented under §25.173(e) of this title (relating to Goal for Renewable Energy).

(108) Renewable energy credit account (REC account)--An account maintained by the renewable energy credits trading program administrator for the purpose of tracking the production, sale, transfer, purchase, and retirement of RECs by a program participant.

(109) Renewable energy resource (renewable resource)--A resource that produces energy derived from renewable energy technologies.

(110) Renewable energy technology--Any technology that exclusively relies on an energy source that is naturally regenerated over a short time and derived directly from the sun, indirectly from the sun or from moving water or other natural movements and mechanisms of the environment. Renewable energy technologies include those that rely on energy derived directly from the sun, on wind, geothermal, hydroelectric, wave, or tidal energy, or on biomass or biomass-based waste products, including landfill gas. A renewable energy technology does not rely on energy resources derived from fossil fuels, waste products from fossil fuels, or waste products from inorganic sources.

(111) Repowering--Modernizing or upgrading an existing facility in order to increase its capacity or efficiency.

(112) Residential customer--Retail customers classified as residential by the applicable bundled utility tariff, unbundled transmission and distribution utility tariff or, in the absence of classification under a residential rate class, those retail customers that are primarily end users consuming electricity at the customer's place of residence for personal, family or household purposes and who are not resellers of electricity.

(113) Retail customer--The separately metered end-use customer who purchases and ultimately consumes electricity.

(114) Retail electric provider (REP)--A person that sells electric energy to retail customers in this state. A retail electric provider may not own or operate generation assets.

(115) Retail stranded costs--That part of net stranded cost associated with the provision of retail service.

(116) Retrofit--The installation of control technology on an electric generating facility to reduce the emissions of nitrogen oxide, sulfur dioxide, or both.

(117) River authority--A conservation and reclamation district created pursuant to the Texas Constitution, Article 16, Section 59, including any nonprofit corporation created by such a district pursuant to the Texas Water Code, Chapter 152, that is an electric utility.

(118) Rule--A statement of general applicability that implements, interprets, or prescribes law or policy, or describes the procedure or practice requirements of the commission. The term includes the amendment or repeal of a prior rule, but does not include statements concerning only the internal management or organization of the commission and not affecting private rights or procedures.

(119) Separately metered--Metered by an individual meter that is used to measure electric energy consumption by a retail customer and for which the customer is directly billed by a utility, retail electric provider, electric cooperative, or municipally owned utility.

(120) Service--Has its broadest and most inclusive meaning. The term includes any act performed, anything supplied, and any facilities used or supplied by an electric utility in the performance of its duties under the Public Utility Regulatory Act to its patrons, employees, other public utilities or electric utilities, an electric cooperative, and the public. The term also includes the interchange of facilities between two or more public utilities or electric utilities.

(121) Spanish-speaking person--A person who speaks any dialect of the Spanish language exclusively or as their primary language.

(122) Standard meter--The minimum metering device necessary to obtain the billing determinants required by the transmission and distribution utility's tariff schedule to determine an end-use customer's charges for transmission and distribution service.

(123) Stranded cost--The positive excess of the net book value of generation assets over the market value of the assets, taking into account all of the electric utility's generation assets, any above-market purchased power costs, and any deferred debit related to a utility's discontinuance of the application of Statement of Financial Accounting Standards Number 71 ("Accounting for the Effect of Certain Types of Regulation") for generation-related assets if required by the provisions of the Public Utility Regulatory Act (PURA), Chapter 39. For purposes of PURA §39.262, book value shall be established as of December 31, 2001, or the date a market value is established through a market valuation method under PURA §39.262(h), whichever is earlier, and shall include stranded costs incurred under PURA §39.263.

(124) Submetering--Metering of electricity consumption on the customer side of the point at which the electric utility meters electricity consumption for billing purposes.

(125) Summer net dependable capability--The net capability of a generating unit in megawatts (MW) for daily planning and operational purposes during the summer peak season, as determined in accordance with requirements of the reliability council or independent organization in which the unit operates.

(126) Supply-side resource--A resource, including a storage device, that provides electricity from fuels or renewable resources.

(127) System emergency--A condition on a utility's system that is likely to result in imminent significant disruption of service to customers or is imminently likely to endanger life or property.

(128) Tariff--The schedule of a utility, municipally-owned utility, or electric cooperative containing all rates and charges stated separately by type of service, the rules and regulations of the utility, and any contracts that affect rates, charges, terms or conditions of service.

(129) Termination of service--The cancellation or expiration of a sales agreement or contract by a retail electric provider by notification to the customer and the registration agent.

(130) Tenant--A person who is entitled to occupy a dwelling unit to the exclusion of others and who is obligated to pay for the occupancy under a written or oral rental agreement.

(131) Test year--The most recent 12 months for which operating data for an electric utility, electric cooperative, or municipally-owned utility are available and shall commence with a calendar quarter or a fiscal year quarter.

(132) Texas jurisdictional installed generation capacity--The amount of an affiliated power generation company's installed generation capacity properly allocable to the Texas jurisdiction. Such allocation shall be calculated pursuant to an existing commission-approved allocation study, or other such commission-approved methodology, and may be adjusted as approved by the commission to reflect the effects of divestiture or the installation of new generation facilities.

(133) Transition bonds--Bonds, debentures, notes, certificates, of participation or of beneficial interest, or other evidences of indebtedness or ownership that are issued by an electric utility, its successors, or an assignee under a financing order, that have a term not longer than 15 years, and that are secured or payable from transition property.

(134) Transition charges--Non-bypassable amounts to be charged for the use or availability of electric services, approved by the commission under a financing order to recover qualified costs, that shall be collected by an electric utility, its successors, an assignee, or other collection agents as provided for in a financing order.

(135) Transmission and distribution business unit (TDBU)--The business unit of a municipally owned utility/electric cooperative, whether structurally unbundled as a separate legal entity or functionally unbundled as a division, that owns or operates for compensation in this state equipment or facilities to transmit or distribute electricity at retail, except for facilities necessary to interconnect a generation facility with the transmission or distribution network, a facility not dedicated to public use, or a facility otherwise excluded from the definition of electric utility in a qualifying power region certified under the Public Utility Regulatory Act §39.152. Transmission and distribution business unit does not include a municipally owned utility/electric cooperative that owns, controls, or is an affiliate of the transmission and distribution business unit if the transmission and distribution business unit is organized as a separate corporation or other legally distinct entity. Except as specifically authorized by statute, a transmission and distribution business unit shall not provide competitive energy-related activities.

(136) Transmission and distribution utility (TDU)--A person or river authority that owns, or operates for compensation in this state equipment or facilities to transmit or distribute electricity, except for facilities necessary to interconnect a generation facility with the transmission or distribution network, a facility not dedicated to public use, or a facility otherwise excluded from the definition of "electric utility", in a qualifying power region certified under the Public Utility Regulatory Act (PURA) §39.152, but does not include a municipally owned utility or an electric cooperative. The TDU may be a single utility or may be separate transmission and distribution utilities.

(137) Transmission line--A power line that is operated at 60 kilovolts (kV) or above, when measured phase-to-phase.

(138) Transmission service--Service that allows a transmission service customer to use the transmission and distribution facilities of electric utilities, electric cooperatives and municipally owned utilities to efficiently and economically utilize generation resources to reliably serve its loads and to deliver power to another transmission service customer. Includes construction or enlargement of facilities, transmission over distribution facilities, control area services, scheduling resources, regulation services, reactive power support, voltage control, provision of operating reserves, and any other associated electrical service the commission determines appropriate, except that, on and after the implementation of customer choice in any portion of the Electric Reliability Council of Texas (ERCOT) region, control area services, scheduling resources, regulation services, provision of operating reserves, and reactive power support, voltage control and other services provided by generation resources are not "transmission service".

(139) Transmission service customer--A transmission service provider, distribution service provider, river authority, municipally-owned utility, electric cooperative, power generation company, retail electric provider, federal power marketing agency, exempt wholesale generator, qualifying facility, power marketer, or other person whom the commission has determined to be eligible to be a transmission service customer. A retail customer, as defined in this section, may not be a transmission service customer.

(140) Transmission service provider (TSP)--An electric utility, municipally-owned utility, or electric cooperative that owns or operates facilities used for the transmission of electricity.

(141) Transmission system--The transmission facilities at or above 60 kilovolts (kV) owned, controlled, operated, or supported by a transmission service provider or transmission service customer that are used to provide transmission service.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on April 23, 2018.

TRD-201801808

Adriana Gonzales

Rules Coordinator

Public Utility Commission of Texas

Effective date: May 13, 2018

Proposal publication date: December 29, 2017

For further information, please call: (512) 936-7223


SUBCHAPTER B. CUSTOMER SERVICE AND PROTECTION

16 TAC §§25.41, 25.43, 25.45

The amendments and new section are adopted under §14.002 of the Public Utility Regulatory Act, Tex. Util. Code Ann. §14.002 (West 2016 and Supp. 2017) (PURA) which provides the commission with the authority to make and enforce rules reasonably required in the exercise of its powers and jurisdiction, including rules of practice and procedure; PURA §17.007, which provides for a process by which a REP can identify low-income customers; PURA §39.101, which provides the commission with the authority to ensure that retail customer protections are established to entitle a customer to safe, reliable, and reasonably priced electricity.

Cross reference to statutes: Public Utility Regulatory Act §14.002, §14.052, §17.007, §39.101.

§25.41.Price to Beat.

(a) Applicability. This section applies to all affiliated retail electric providers (REPs) and transmission and distribution utilities, except river authorities. This section does not apply to an electric utility subject to Public Utility Regulatory Act (PURA) §39.102(c) until the end of the utility's rate freeze.

(b) Purpose. The purpose of this section is to promote the competitiveness of the retail electric market through the establishment of the price to beat that affiliated REPs must offer to retail customers beginning on January 1, 2002 pursuant to PURA §39.202.

(c) Definitions. The following words and terms, when used in this section, shall have the following meanings, unless the context indicates otherwise:

(1) Affiliated electric utility--The electric utility from which an affiliated REP was unbundled in accordance with PURA §39.051.

(2) Competitive retailer--A REP or a municipally owned utility or distribution cooperative that offers customer choice in the restructured competitive electric power market or any other entity authorized to sell electric power and energy at retail in Texas.

(3) Headroom--The difference between the average price to beat (in cents per kilowatt hour (kWh)) and the sum of the average non-bypassable charges or credits approved by the commission in a proceeding pursuant to PURA §39.201, or PURA Subchapter G (in cents per kWh) and the representative power price (in cents per kWh). Headroom may be a positive or negative number. A separate headroom number shall be calculated for the typical residential customer and the typical small commercial customer. The calculation for the typical residential customer shall assume 1,000 kWh per month in usage. The calculation of the typical small commercial customer shall assume 35 kilowatts (kW) of demand and 15,000 kWh per month in usage.

(4) Nonaffiliated REP--Any competitive retailer conducting business in a transmission and distribution utility's (TDU's) certificated service territory that is not affiliated with that TDU unless the competitive retailer is a successor in interest to a retail electric provider affiliated with that TDU.

(5) Peak demand--The highest 15-minute or 30-minute demand recorded during a 12-month period.

(6) Price to beat period--The price to beat period shall be from January 1, 2002 to January 1, 2007. In a power region outside the Electric Reliability Council of Texas (ERCOT) if customer choice is introduced before the date the commission certifies the power region pursuant to PURA §39.152(a) are met, the price to beat period continues, unless changed by the commission in accordance with PURA Chapter 39, until the later of 60 months after the date customer choice is introduced in the power region or the date the commission certifies the power region as a qualified power region.

(7) Provider of last resort (POLR)--As defined in §25.43 of this title (relating to Provider of Last Resort).

(8) Representative power price--The simple average of the results of:

(A) a request for proposals (RFP) for full-requirements service of 10% of price to beat load for a duration of three years expressed in cents per kWh; and

(B) the price resulting from the capacity auctions of the affiliated power generation company (PGC) required by §25.381 of this title (relating to Capacity Auctions) for baseload capacity entitlements auctioned in the ERCOT zone where the majority of price to beat customers reside, expressed in cents per kWh. The calculation of the price resulting from the capacity auctions shall assume dispatch of 100% of the entitlement and shall use the most recent auction of a 12-month forward strip of entitlements, or the most recent aggregated forward 12 months of entitlements. The affiliated REP, at its option, may conduct an RFP or purchase auction for an amount equivalent to the amount, in MWs, of the affiliated PGC's capacity auction for the September 2001 12-month forward strip baseload entitlements.

(9) Residential customer--Retail customers classified as residential by the applicable transmission and distribution utility tariff or, in the absence of classification under a residential rate class, those retail customers that are primarily end users consuming electricity for personal, family or household purposes and who are not resellers of electricity.

(10) Small commercial customer--A non-residential retail customer having a peak demand of 1,000 kilowatts (kW) or less. For purposes of this section, the term small commercial customer refers to a metered point of delivery. Additionally, any non-residential, non-metered point of delivery with peak demand of less than 1,000 kW shall also be considered a small commercial customer. For purposes of subsection (i) of this section, unmetered guard and security lights are not considered small commercial customers unless such an account has historically been treated as a separate customer for billing purposes.

(11) Transmission and distribution utility--As defined in §25.5 of this title (relating to Definitions), except for purposes of this section, this term does not include a river authority.

(d) Price to beat offer.

(1) Beginning with the first billing cycle of the price to beat period and continuing through the last billing cycle of the price to beat period, an affiliated REP shall make available to residential and small commercial customers of its affiliated transmission and distribution utility rates that, subject to the exception listed in subsection (f)(2)(A) of this section, on a bundled basis, are 6.0% less than the affiliated electric utility's corresponding average residential and small commercial rates that were in effect on January 1, 1999, adjusted to reflect the fuel factor determined in accordance with subsection (f)(3)(D) of this section and adjusted for any base rate reduction as stipulated to by an electric utility in a proceeding for which a final order had not been issued by January 1, 1999.

(2) Unless specifically required by commission rule, an affiliated REP may only sell electricity to price to beat customers labeled or marketed as "green," "renewable," "interruptible," "experimental," "time of use," "curtailable," or "real time," if and only if such a tariff option existed on January 1, 1999 and only for service under the price to beat rate that was developed from that tariff.

(e) Eligibility for the price to beat. The following criteria shall be used in determining eligibility for the price to beat:

(1) Residential customers. All current and future residential customers, as defined by this section, shall be eligible for the price to beat rate(s) for which they meet the eligibility criteria in the applicable price to beat tariffs for the duration of the price to beat period. An affiliated REP may not refuse service under the price to beat to a residential customer except as provided by §25.477 of this title (relating to Refusal of Service). An affiliated REP may not require residential customers to enter into service agreements with a term of service as a condition of obtaining service under the price to beat, nor may an affiliated REP provide any inducements to encourage customers to agree to a term of service in conjunction with service under the price to beat.

(2) Small commercial customers.

(A) A non-residential customer taking service from the affiliated electric utility on December 31, 2001, shall be considered a small commercial customer under this section and shall be eligible for service under price to beat tariffs if that customer's peak demand during the 12 consecutive months ending on September 30, 2001, does not exceed 1,000 kilowatts (kW). A non-residential customer with a peak demand in excess of 1,000 kW during the 12 months ending September 30, 2001, or during the price to beat period, shall no longer be considered a small commercial customer under this section. However, any non-residential customer whose peak demand does not exceed 1,000 kW for any period of 12 consecutive months after it became ineligible to be a small commercial customer under this section shall be considered a small commercial customer for billing periods going forward for purposes of this section.

(B) All small commercial customers, as defined by this section, shall be eligible for the price to beat rate(s) for which they meet the eligibility criteria in the applicable price to beat tariffs for the duration of the price to beat period. An affiliated REP may not refuse service under the price to beat to a small commercial customer, except as provided by §25.477 of this title. An affiliated REP may not require small commercial customers to enter into service agreements with a term of service as a condition to obtaining service under the price to beat, nor may an affiliated REP provide any inducements to encourage customers to agree to a term of service in conjunction with service under the price to beat.

(f) Calculation of the price to beat.

(1) Rates to be used for price to beat calculation. The following criteria shall be used in determining the rates to be used for the price to beat calculation.

(A) Residential. A price to beat rate shall be calculated for each rate and service rider under which a residential customer was taking service on January 1, 1999, except as approved by the commission pursuant to subparagraph (C) of this paragraph. A price to beat rate shall not be calculated for any new service or tariff option granted to an affiliated electric utility pursuant to PURA §39.054, or any other rate or tariff option not in effect on January 1, 1999.

(i) Beginning with the first full billing cycle of the price to beat period, residential customers served by the affiliated REP shall be placed on the price to beat rate derived from the rate under which they were taking service on December 31, 2001.

(ii) Beginning with the first full billing cycle of the price to beat period, residential customers served by the affiliated REP who were taking service under a rate for which a price to beat rate was not developed, shall be placed on the price to beat rate derived from any eligible residential rate that was or would have been available to the customer on January 1, 1999.

(iii) New residential customers after December 31, 2001, may choose any price to beat rate for which they meet the eligibility requirements as detailed in the applicable price to beat tariff.

(iv) Residential customers who return to the affiliated REP after being served by a non-affiliated REP may choose any price to beat for which they meet the eligibility requirements as detailed in the applicable price to beat tariff(s).

(v) Notwithstanding clauses (i)-(iv) of this subparagraph, residential customers may request service under any price to beat rate for which they are eligible. Selection of the most advantageous rate shall be the sole responsibility of the residential customer.

(B) Small commercial. A price to beat rate shall be calculated for each rate and service rider under which a small commercial customer was taking service on January 1, 1999, except as approved by the commission pursuant to subparagraph (C) of this paragraph. A price to beat rate shall not be calculated for any new service or tariff option granted to an affiliated electric utility pursuant to PURA §39.054, or for any rate of tariff option not in effect on January 1, 1999.

(i) Beginning with the first full billing cycle of the price to beat period, small commercial customers served by the affiliated REP shall be placed on the price to beat rate derived from the rate under which they were taking service on December 31, 2001.

(ii) Beginning with the first full billing cycle of the price to beat period, small commercial customers served by the affiliated REP beginning in January of 2002, who were taking service under a rate for which a price to beat rate was not developed, shall be placed on a price to beat rate derived from an eligible rate that was or would have been available to the customer on January 1, 1999.

(iii) New small commercial customers after December 31, 2001, may choose any price to beat rate for which they meet the eligibility requirements as detailed in the applicable price to beat tariff.

(iv) Small commercial customers who return to the affiliated REP after being served by a non-affiliated REP may choose any price to beat rate for which they meet the eligibility requirements as detailed in the price to beat tariff(s).

(v) Notwithstanding clauses (i)-(iv) of this subparagraph, small commercial customers may request service under any price to beat tariff for which they are eligible. Selection of the most advantageous rate shall be the sole responsibility of the small commercial customer.

(C) An electric utility, on behalf of its future affiliated REP, shall file within 60 days of the effective date of this section, price to beat tariffs and supporting workpapers for the price to beat rates developed in accordance with subparagraphs (A) and (B) of this paragraph. At the time of this filing, the affiliated REP may request that a price to beat rate not be developed from a particular rate of service rider along with justification for the request. The electric utility shall provide notice to all customers currently taking service under such rates or service riders of the utility's request.

(2) Base rate component of price to beat. For the eligible rates identified in paragraph (1) of this subsection, the affiliated REP shall reduce each base rate component including any purchased power cost recovery factor (PCRF), in effect for the affiliated electric utility on January 1, 1999, by 6.0% in order to determine the base rate component of the price to beat, with the following exceptions:

(A) If base rates for the affiliated electric utility were reduced by more than 12% as the result of a final order issued by the commission after October 1, 1998, then the price to beat shall be the rate in effect as a result of a settlement approved by the commission after January 1, 1999.

(B) For affiliated REPs operating in a region defined by PURA §39.401, the commission may reduce rates by less than 6.0% if the commission determines a lesser reduction is necessary and consistent with the capital requirements needed to develop the infrastructure necessary to facilitate competition among electric generators.

(C) Except as provided in subparagraphs (A) and (B) of this paragraph, for any affiliated electric utility that has stipulated to rate reductions in a proceeding for which a final order had not been issued by January 1, 1999, such rate reductions shall be deducted from the base rates in effect on January 1, 1999, in addition to the 6.0% reduction. Such rate credits shall also be applied to the rates of the transmission and distribution utility.

(3) Fuel factor component of price to beat.

(A) Each affiliated electric utility shall file an application to establish one or more fuel factors, to be effective on January 1, 2002, according to the following schedule:

(i) April 1, 2001 - Reliant Houston Lighting & Power;

(ii) May 1, 2001 - TXU Electric Company;

(iii) June 1, 2001 - Texas-New Mexico Power Company and Central Power & Light Company;

(iv) July 1, 2001 - Entergy Gulf States, Inc. and West Texas Utilities;

(v) August 1, 2001 - Southwestern Electric Power Company and Southwestern Public Service Company.

(B) The rate year for the filing shall be calendar year 2002. The affiliated electric utility shall follow the requirements of §25.237(a)(1), (b), (c) and (e) of this title (relating to Fuel Factors) and the Fuel Factor Filing Package of November 23, 1993, for the filing of its fuel factor(s). To the extent that the commission has issued an order for a utility that includes provisions relating to the price to beat fuel factor, the price to beat fuel factor shall be set consistent with such an order.

(C) Subject to the limitations in clause (i) and (ii) of this subparagraph, affiliated electric utilities may utilize seasonal fuel factors to reflect the expected differences in the cost of the market price of electricity throughout the year.

(i) Affiliated electric utilities with seasonal fuel factors in effect on or before March 1, 2001, may request seasonal fuel factors for their residential and small commercial price to beat customers provided the level of seasonality is identical to that reflected in its commission-approved fuel factors on March 1, 2001.

(ii) Affiliated electric utilities without seasonal fuel factors in effect on or before March 1, 2001, may request seasonal fuel factors to be applicable to small commercial price to beat customers only. Any request for seasonal fuel factors under this clause must demonstrate that the average small commercial customer will receive, on an annual basis, a 6.0% reduction from the average bundled rate in effect on January 1, 1999, adjusted for the final fuel factor determined under subparagraph (D) of this paragraph; provided, however, that a utility subject to the exception in paragraph (2)(A) of this subsection must demonstrate that the average small commercial customer will receive, on an annual basis, the average bundled rate in effect as the result of a settlement approved by the commission after January 1, 1999, adjusted for the final fuel factor determined under subparagraph (D) of this paragraph.

(D) Each affiliated electric utility shall file additional information on October 1, 2001, to reflect changes in the price of natural gas for the rate year of 2002. The affiliated electric utility shall also file information necessary to determine the initial headroom that exists under the price to beat as a result of the setting of the initial price to beat fuel factor pursuant to this subparagraph. The adjustment shall be calculated using the following methodology:

(i) For the ten-day period ending on September 15, 2001, an average price shall be calculated for each month of 2002 in the closing forward NYMEX Henry Hub natural gas prices, as reported in the Wall Street Journal.

(ii) All other inputs into the calculation of the fuel factors will be the same as those used to calculate the fuel factor in subparagraphs (B) and (C) of this paragraph.

(iii) Except for affiliated electric utilities whose base rates were reduced by more than 12% as the result of a final order issued by the commission after October 1, 1998, the fuel factor(s) to be used at the beginning of the price to beat period shall be the fuel factor in effect on January 1, 1999, reduced by 6.0%, plus the difference between the fuel factor(s) established pursuant to this subparagraph and the fuel factor in effect on January 1, 1999.

(iv) The fuel factor(s) for affiliate electric utilities whose base rates were reduced by more than 12% as the result of a final order issued by the commission after October 1, 1998, to be used at the beginning of the price to beat period shall be the fuel factor(s) established pursuant to this subparagraph.

(E) For a non-generating investor-owned utility with no fuel factor as of January 1, 1999, its PCRF in effect on January 1, 1999, shall be the equivalent to a fuel factor for purposes of calculating its price to beat rates and future fuel cost adjustments under subsection (g) of this section. Upon expiration of a purchased power contract of an affiliated REP unbundled from such a utility, the affiliated REP may request a change in its PCRF to account for any difference in purchased power costs.

(g) Adjustments to the price to beat.

(1) Fuel factor adjustments. An affiliated REP may request that the commission adjust the fuel factor(s) established under subsection (f)(3) of this section upward or downward not more than twice in a calendar year if the affiliated REP demonstrates that the existing fuel factor(s) do not adequately reflect significant changes in the market price of natural gas and purchased energy used to serve retail customers. As part of a filing made pursuant to this paragraph, an affiliated REP may also request an adjustment to the seasonality imparted to the fuel factor in accordance with subsection (f)(3)(C) of this section. Alternatively, the commission may, as part of its approval of an adjustment to the fuel factor, impose a change in the seasonality imparted to the fuel factor. The methodology for calculating the adjustment to the fuel factor(s) shall be the following:

(A) For each day of the 20 trading-day period ending no later than two days before the filing of a fuel factor adjustment application, an average of the closing forward 12-month NYMEX Henry Hub natural gas prices, as reported by the Wall Street Journal (either in print or on-line), is calculated.

(B) The average forward price for each trading day calculated in subparagraph (A) of this paragraph will then be averaged to determine a 20 trading-day rolling price.

(C) The percentage difference between the averaged 20 trading-day rolling price calculated under subparagraphs (A) and (B) of this paragraph and the averaged price used to calculate the current fuel factor(s) is calculated. If the current fuel factor was calculated through an adjustment under subparagraph (E) of this paragraph, then the averaged 20 trading-day rolling price calculated concurrent with that adjustment shall be used. If the percentage difference is 5.0% or more, then the current fuel factor(s) may be adjusted, unless the filing is made after November 15 of a calendar year, in which event the percentage difference must be 10% or more.

(D) If the absolute value of the percentage difference calculated in subparagraph (C) of this paragraph meets or exceeds 5.0% (or 10% if applicable), then the current fuel factors are deemed to be unreflective of significant changes in the market price of natural gas and purchased energy. To adjust the current fuel factor(s), the percentage difference calculated in subparagraph (C), either positive or negative, is added to one and then multiplied by the current factor(s). The results are the adjusted fuel factor(s) that will be implemented according to the procedural schedule in clause (i) and (ii) of this subparagraph:

(i) if no hearing is requested within 15 days after the petition has been filed, a final order shall be issued within 20 days, or as soon as practicable thereafter, after the petition is filed;

(ii) if a hearing is requested within 15 days after the petition is filed, a final order shall be issued within 45 days, or as soon as practicable thereafter, after the petition is filed. The 45 day timeline for issuance of an order may be extended upon mutual agreement of the parties. Such agreement may provide for interim rate relief.

(E) In addition to the adjustment permitted under subparagraphs (A)-(D) of this paragraph, an affiliated REP may also request an adjustment to the fuel factor if the headroom under the price to beat decreases as a result of significant changes in the price of purchased energy. In making a request under this subparagraph:

(i) an affiliated REP shall demonstrate that:

(I) the representative power price has changed such that the headroom under the price to beat has decreased; and

(II) the adjustment to the fuel factor is necessary to restore the amount of headroom that existed at the time that the initial price to beat fuel factor was set by the commission using then current forecasts of the representative power price.

(III) an affiliated REP making an adjustment under this subparagraph shall also file the gas price calculation in subparagraphs (A) and (B) of this paragraph for purposes of subsequent adjustments to the fuel factor based on changes in natural gas prices.

(ii) the commission will issue a final order on an application filed under this subparagraph within 60 days, or as soon as practicable thereafter, after the application is filed. The 60 day timeline for issuance of an order may be extended upon mutual agreement of the parties. Such agreement may provide for interim rate relief.

(F) The commission shall, upon a showing made by an interested party, that a sufficiently liquid electricity commodity trading hub (or hubs) or index has developed for the affiliated REP's relevant geographic or power region, allow an affiliated REP to transition to the use of electricity commodity futures prices at that hub or index to adjust the fuel factor to adequately reflect significant changes in the price of purchased energy. After the commission has made a finding that a sufficiently liquid electricity commodity trading hub or index has developed, the affiliated REP shall be required to perform an additional adjustment under subparagraphs (A) through (D) or (E) of this paragraph before utilization of the futures prices at that trading hub or index to change the fuel factor so that a benchmark electricity price can be established. Subsequent changes to the fuel factor shall be based on the percentage change in the electricity commodity index using the same methodology for the natural gas price adjustment under subparagraphs (A) - (D) of this paragraph.

(2) Adjustment for financial integrity. Upon a finding that an affiliated REP will be unable to maintain its financial integrity if it complies with subsection (f) of this section, the commission shall set the affiliated REP's price to beat at the minimum level that will allow the affiliated REP to maintain its financial integrity. However, in no event shall the price to beat exceed the level of rates, on a bundled basis, charged by the affiliated electric utility on September 1, 1999, adjusted for fuel.

(3) True-up adjustment. The commission shall adjust the price to beat following the true-up proceedings under PURA §39.262. The commission shall consider the following adjustments to the price to beat on a schedule consistent with the processing of the TDU rate adjustment application pursuant to §25.263(n) of this title (relating to True-up Proceeding):

(A) Fuel factor adjustment. A 20 trading-day rolling price shall be calculated in accordance with paragraph (1)(A)-(D) of this subsection. If the 20 trading-day rolling price is less than the price used to calculate the then-current fuel factor (i.e. The percentage difference is negative), then the price to beat fuel factor shall be adjusted downward by the percentage difference in the prices. An adjustment required to be made in accordance with this subparagraph shall not be considered a request by an affiliated REP under paragraph (1) of this subsection.

(B) Base rate adjustment. Using the typical residential and small commercial usage calculations described in subsection (c)(3) of this section, the base rate components of the price to beat shall be adjusted, either upward or downward, such that the difference between the average price to beat base rate and the average non-bypassable charges that exist following the proceeding pursuant to §25.263(n) of this title is the same as existed on January 1, 2002. Each component of the base rates for each residential price to beat base rate tariff shall be adjusted in the same proportion in complying with this section. Each component of the base rates for each small commercial price to beat base rate tariff shall be adjusted in the same proportion in complying with this section

(C) Filing by affiliated REP. An affiliated REP shall make filings necessary to implement subparagraphs (A) and (B) of this paragraph on a schedule to be determined by the commission.

(h) Non-price to beat offers.

(1) Offers to residential customers. An affiliated REP may not offer any rates other than the price to beat rates to residential customers within the affiliated electric utility's service area until the earlier of 36 months after the date customer choice is introduced, or when the commission determines that an affiliated REP has met or exceeded the threshold target for residential customers described in subsection (i) of this section.

(2) Offers to small commercial customers. An affiliated REP may not offer rates other than the price to beat rates to small commercial customers until the earlier of 36 months after the date customer choice is introduced, or when the commission determines that an affiliated REP has met or exceeded the threshold target for small commercial customers described in subsection (i) of this section.

(3) Offers to aggregated small commercial load. Notwithstanding paragraph (2) of this subsection, an affiliated REP may charge rates different from the price to beat for service to aggregated loads having an aggregated peak demand in excess of 1,000 kW provided that all affected customers are commonly owned or are franchisees of the same franchisor.

(A) If aggregated customers whose loads are served by an affiliated REP in accordance with this subsection disaggregate, those individual customers may resume service under the applicable price to beat rate(s), provided that those customers meet the eligibility requirements of subsection (e) of this section.

(B) Any usage removed from the threshold calculation in subsection (i)(1)(B) of this section due to aggregation shall be added back into the threshold calculation upon disaggregation of the aggregated load.

(i) Threshold targets.

(1) Calculation of threshold targets.

(A) Residential target. The residential threshold target shall be equal to 40% of the total number of kilowatt-hours (kWh) consumed by residential customers served by the affiliated electric utility during the calendar year 2000.

(B) Small commercial target. The small commercial threshold target shall be equal to 40% of the following difference: the total number of kWh consumed by small commercial customers served by the affiliated electric utility during the calendar year 2000 minus the aggregated load served by the affiliated REP that complies with the requirements of subsection (h)(3) of this section. The kWh associated with a customer who becomes ineligible for the price to beat because the customer's peak demand exceeds 1,000 kW shall also be removed from the threshold target.

(2) Meeting of threshold targets. Upon a showing by the affiliated transmission and distribution utility that the electric power consumption of the relevant customer group served by nonaffiliated REPs meets or exceeds the targets determined by the calculation in paragraph (1) of this subsection, the affiliated REP may offer rates other than the price to beat.

(A) Calculation of residential consumption. The amount of electric power of residential customers served by nonaffiliated REPs shall equal the number of residential customers served by nonaffiliated REPs, except customers that the affiliated REP has dropped to the POLR, times the average annual consumption of residential customers served by the affiliated utility during the calendar year 2000.

(i) The number of customers served by nonaffiliated REPs shall be determined by summing the number of customers in the transmission and distribution utility's certificated service area with a designated REP other than the affiliated REP in the registration database maintained by the registration agent. Customers dropped to the POLR by the affiliated REP shall not count as load served by a nonaffiliated REP.

(ii) The average annual consumption shall be calculated by dividing the total kWh consumed by residential customers during the calendar year 2000 by the average number of residential customers during the calendar year 2000. The average number of residential customers during the calendar year 2000 shall be calculated by dividing the sum of the total number of such customers for each month of the year 2000 by 12.

(B) Calculation of small commercial consumption. The amount of electric power consumed by small commercial customers served by nonaffiliated REPs shall be determined using the following criteria, except that customers served by the POLR shall not count as load served by a nonaffiliated REP:

(i) The amount of electric power of small commercial customers with peak demand less than 20 kW consumed by nonaffiliated REPs shall be equal to the number of small commercial customers with peak demand less than 20 kW served by nonaffiliated REPs times the average annual consumption of small commercial customers with peak demand less than 20 kW served by the affiliated electric utility during the calendar year 2000.

(I) The number of customers served by nonaffiliated REPs shall be determined by summing the number of small commercial customers with peak demands less than 20 kW served in the transmission and distribution utility's certificated service area with a designated REP other than the affiliated REP in the registration database maintained by the registration agent.

(II) The average annual consumption shall be calculated by dividing the total kWh consumed by small commercial customers with peak demand of less than 20 kW during the calendar year 2000 by the average number of small commercial customers with peak demand of less than 20 kW during the calendar year 2000. The average number of small commercial customers with peak demand of less than 20 kW shall be calculated by dividing the total number of such customers for each month of 2000 by 12.

(ii) The amount of electric power consumed by small commercial customers with peak demand in excess of 20 kW shall be the actual usage of those customers during the calendar year 2000.

(I) If less than 12 months of consumption history exists for such a customer during the calendar year 2000, the available calendar year 2000 usage history shall be supplemented with the most recent prior history of service at that customer's location for the unavailable months.

(II) For customers with service to a new location, the annual consumption shall be deemed to be equal to the estimated maximum annual demand used by the affiliated transmission and distribution utility in sizing the facilities installed to serve that customer multiplied by the product of 8,760 hours and the average annual load factor for small commercial customers with peak demand greater than 20 kW for the year 2000.

(j) Prohibition on incentives to switch. An affiliated REP may not provide an incentive to switch to a nonaffiliated REP, promote any nonaffiliated REP, or exchange customers with any nonaffiliated REP in order to meet the requirements of subsection (f) of this section. Non-affiliated REPs may not provide an incentive to return to the price to beat.

(k) Disclosure of price to beat rate. An affiliated retail electric provider shall disclose to customers, the price to beat in accordance with §25.471 (relating to General Provisions of Customer Protection Rules). In addition, if an affiliated REP offers a rate greater than the price to beat, the price to beat rate must be disclosed along with a statement that the customer is eligible for the price to beat. This disclosure must appear on all written authorizations, Internet authorizations, the electricity facts label and Terms of Service document. It must also be disclosed during telephone solicitations before the customer authorizes service.

(l) Filing requirements.

(1) On determining that its affiliated retail electric provider has met the requirements of subsection (i) of this section, an electric utility or transmission and distribution utility shall make a filing with the commission attesting under oath to the fact that those requirements have been met and that the restrictions of subsection (h) of this section as well as the true-up in PURA §39.262(e) are no longer applicable.

(2) An electric utility or transmission and distribution utility shall file a progress report with the commission after its affiliated REP has met the requirements of subsection (i) of this section using a 35% threshold target in lieu of a 40% threshold. Such progress reports(s) shall be filed no later than 30 days after the 35% threshold has been met and shall contain the same information required in this subsection.

(3) No later than December 31, 2001, each transmission and distribution utility shall determine the power consumption threshold targets under subsection (i) of this section for residential and small commercial customers within its certificated service area and shall file this information with the commission and shall also make this information publicly available through its Internet website. Each transmission and distribution utility, together with its affiliated REP, shall update the small commercial power consumption threshold as needed to reflect additional small commercial load that has met the requirements of subsection (h)(3) of this section and therefore is appropriately removed from the calculation of the threshold target. Concurrent with this update, the transmission and distribution utility, together with its affiliated REP, shall provide, for each group of aggregated customers that have been removed from the calculation of the threshold target, the customers' names, electric service identifiers, size of the customers' loads (individually and in the aggregate), and how the customers meet the requirements of subsection (h)(3) of this section. Such information may be filed under confidential seal. All certificated REPs shall be deemed to have standing to review such filings.

(4) Any application filed pursuant to this subsection shall contain the following information:

(A) a detailed explanation of how the relevant customer group has met or exceeded the threshold consumption targets in subsection (i) of this section;

(B) calculation of the power consumption threshold target under subsection (i) of this section for the relevant customer group and the date such target was met;

(C) verification of the meeting of the threshold target in the following manner:

(i) for the residential customer class, independent verification from the registration agent verifying the number of customers in the residential customer class within the transmission and distribution utility's certificated service area that are committed to be served by non-affiliated REPs.

(ii) for the small commercial class, an affidavit detailing the number of customers in the small commercial class with peak demand below 20 kW within the transmission and distribution utility's certificated service area committed to be served by non-affiliated REPs and the customers with peak demand in excess of 20 kW with their actual usage calculated in accordance with subsection (i)(2)(B)(ii) of this section within the transmission and distribution utility's certificated service area that are committed to be served by non-affiliated REPs.

(iii) For purposes of this subsection, a residential and small commercial customer has committed to be served by a nonaffiliated retail electric provider if the registration agent has received a switch request for that customer and any mandated cancellation period pursuant to applicable commission rule has expired.

(5) The commission staff shall review all applications filed under this subsection and shall make a recommendation to the commission within ten days after the application is filed to approve or reject the application. If a filing has insufficient information from which the commission can make a determination, the commission may reject the filing without prejudice for refiling the application. The commission shall issue an order approving or rejecting the application within 30 days after the application is filed. An electric utility or transmission and distribution utility filing an application under this subsection shall not charge rates different from the price to beat until the earlier of 36 months after the date customer choice is introduced or the date such application has been approved by the commission.

§25.43.Provider of Last Resort (POLR).

(a) Purpose. The purpose of this section is to establish the requirements for Provider of Last Resort (POLR) service and ensure that it is available to any requesting retail customer and any retail customer who is transferred to another retail electric provider (REP) by the Electric Reliability Council of Texas (ERCOT) because the customer's REP failed to provide service to the customer or failed to meet its obligations to the independent organization.

(b) Application. The provisions of this section relating to the selection of REPs providing POLR service apply to all REPs that are serving retail customers in transmission and distribution utility (TDU) service areas. This section does not apply when an electric cooperative or a municipally owned utility (MOU) designates a POLR provider for its certificated service area. However, this section is applicable when an electric cooperative delegates its authority to the commission in accordance with subsection (r) of this section to select a POLR provider for the electric cooperative's service area. All filings made with the commission pursuant to this section, including filings subject to a claim of confidentiality, shall be filed with the commission's Filing Clerk in accordance with the commission's Procedural Rules, Chapter 22, Subchapter E, of this title (relating to Pleadings and other Documents).

(c) Definitions. The following words and terms when used in this section shall have the following meaning, unless the context indicates otherwise:

(1) Affiliate--As defined in §25.107 of this title (relating to Certification of Retail Electric Providers (REPs).

(2) Basic firm service--Electric service that is not subject to interruption for economic reasons and that does not include value-added options offered in the competitive market. Basic firm service excludes, among other competitively offered options, emergency or back-up service, and stand-by service. For purposes of this definition, the phrase "interruption for economic reasons" does not mean disconnection for non-payment.

(3) Billing cycle--A period bounded by a start date and stop date that REPs and TDUs use to determine when a customer used electric service.

(4) Billing month--Generally a calendar accounting period (approximately 30 days) for recording revenue, which may or may not coincide with the period a customer's consumption is recorded through the customer's meter.

(5) Business day--As defined by the ERCOT Protocols.

(6) Large non-residential customer--A non-residential customer who had a peak demand in the previous 12-month period at or above one megawatt (MW).

(7) Large service provider (LSP)--A REP that is designated to provide POLR service pursuant to subsection (j) of this section.

(8) Market-based product--For purposes of this section, a rate for residential customers that is derived by applying a positive or negative multiplier to the rate described in subsection (m)(2) of this section is not a market-based product.

(9) Mass transition--The transfer of customers as represented by ESI IDs from a REP to one or more POLR providers pursuant to a transaction initiated by the independent organization that carries the mass transition (TS) code or other code designated by the independent organization.

(10) Medium non-residential customer--A non-residential retail customer who had a peak demand in the previous 12-month period of 50 kilowatt (kW) or greater, but less than 1,000 kW.

(11) POLR area--The service area of a TDU in an area where customer choice is in effect.

(12) POLR provider--A volunteer retail electric provider (VREP) or LSP that may be required to provide POLR service pursuant to this section.

(13) Residential customer--A retail customer classified as residential by the applicable TDU tariff or, in the absence of classification under a tariff, a retail customer who purchases electricity for personal, family, or household purposes.

(14) Transitioned customer--A customer as represented by ESI IDs that is served by a POLR provider as a result of a mass transition under this section.

(15) Small non-residential customer--A non-residential retail customer who had a peak demand in the previous 12-month period of less than 50 kW.

(16) Voluntary retail electric provider (VREP)--A REP that has volunteered to provide POLR service pursuant to subsection (i) of this section.

(d) POLR service.

(1) There are two types of POLR providers: VREPs and LSPs.

(2) For the purpose of POLR service, there are four classes of customers: residential, small non-residential, medium non-residential, and large non-residential.

(3) A VREP or LSP may be designated to serve any or all of the four customer classes in a POLR area.

(4) A POLR provider shall offer a basic, standard retail service package to customers it is designated to serve, which shall be limited to:

(A) Basic firm service; and

(B) Call center facilities available for customer inquiries.

(5) A POLR provider shall, in accordance with §25.108 of this title (relating to Financial Standards for Retail Electric Providers Regarding the Billing and Collection of Transition Charges), fulfill billing and collection duties for REPs that have defaulted on payments to the servicer of transition bonds or to TDUs.

(6) Each LSP's customer billing for residential customers taking POLR service under a rate prescribed by subsection (m)(2) of this section shall contain notice to the customer that other competitive products or services may be available from the LSP or another REP. The notice shall also include contact information for the LSP, and the Power to Choose website, and shall include a notice from the commission in the form of a bill insert or a bill message with the header "An Important Message from the Public Utility Commission Regarding Your Electric Service" addressing why the customer has been transitioned to an LSP, a description of the purpose and nature of POLR service, and explaining that more information on competitive markets can be found at www.powertochoose.org, or toll-free at 1-866-PWR-4-TEX (1-866-797-4839).

(e) Standards of service.

(1) An LSP designated to serve a class in a given POLR area shall serve any eligible customer requesting POLR service or assigned to the LSP pursuant to a mass transition in accordance with the Standard Terms of Service in subsection (f)(1) of this section for the provider customer's class. However, in lieu of providing terms of service to a transitioned customer under subsection (f) of this section and under a rate prescribed by subsection (m)(2) of this section an LSP may at its discretion serve the customer pursuant to a market-based month-to-month product, provided it serves all transitioned customers in the same class and POLR area pursuant to the product.

(2) A POLR provider shall abide by the applicable customer protection rules as provided for under Subchapter R of this chapter (relating to Customer Protection Rules for Retail Electric Service), except that if there is an inconsistency or conflict between this section and Subchapter R of this chapter, the provisions of this section shall apply. However, for the medium non-residential customer class, the customer protection rules as provided for under Subchapter R of this chapter do not apply, except for §25.481 of this title (relating to Unauthorized Charges), §25.485(a)-(b) of this title (relating to Customer Access and Complaint Handling), and §25.495 of this title (relating to Unauthorized Change of Retail Electric Provider).

(3) An LSP that has received commission approval to designate one of its affiliates to provide POLR service on behalf of the LSP pursuant to subsection (k) of this section shall retain responsibility for the provision of POLR service by the LSP affiliate and remains liable for violations of applicable laws and commission rules and all financial obligations of the LSP affiliate associated with the provisioning of POLR service on its behalf by the LSP affiliate.

(f) Customer information.

(1) The Standard Terms of Service prescribed in subparagraphs (A)-(D) of this paragraph apply to POLR service provided by an LSP under a rate prescribed by subsection (m)(2) of this section.

(A) Standard Terms of Service, POLR Provider Residential Service:

Figure: 16 TAC §25.43(f)(1)(A) (.pdf)

(B) Standard Terms of Service, POLR Provider Small Non-Residential Service:

Figure: 16 TAC §25.43(f)(1)(B) (No change.)

(C) Standard Terms of Service, POLR Provider Medium Non-Residential Service:

Figure: 16 TAC §25.43(f)(1)(C) (No change.)

(D) Standard Terms of Service, POLR Provider Large Non-Residential Service:

Figure: 16 TAC §25.43(f)(1)(D) (No change.)

(2) An LSP providing service under a rate prescribed by subsection (m)(2) of this section shall provide each new customer the applicable Standard Terms of Service. Such Standard Terms of Service shall be updated as required under §25.475(f) of this title (relating to General Retail Electric Provider Requirements and Information Disclosures to Residential and Small Commercial Customers).

(g) General description of POLR service provider selection process.

(1) All REPs shall provide information to the commission in accordance with subsection (h)(1) of this section. Based on this information, the commission's designated representative shall designate REPs that are eligible to serve as POLR providers in areas of the state in which customer choice is in effect, except that the commission shall not designate POLR providers in the service areas of MOUs or electric cooperatives unless an electric cooperative has delegated to the commission its authority to designate the POLR provider, in accordance with subsection (r) of this section.

(2) POLR providers shall serve two-year terms. The initial term for POLR service in areas of the state where retail choice is not in effect as of the effective date of the rule shall be set at the time POLR providers are initially selected in such areas.

(h) REP eligibility to serve as a POLR provider. In each even-numbered year, the commission shall determine the eligibility of certified REPs to serve as POLR providers for a term scheduled to commence in January of the next year.

(1) All REPs shall provide information to the commission necessary to establish their eligibility to serve as a POLR provider for the next term. REPs shall file, by July 10th, of each even-numbered year, by service area, information on the classes of customers they provide service to, and for each customer class, the number of ESI IDs the REP serves and the retail sales in megawatt-hours for the annual period ending March 31 of the current year. As part of that filing, a REP may request that the commission designate one of its affiliates to provide POLR service on its behalf pursuant to subsection (k) of this section in the event that the REP is designated as an LSP. The independent organization shall provide to the commission the total number of ESI ID and total MWh data for each class. All REPs shall also provide information on their technical capability and financial ability to provide service to additional customers in a mass transition. The commission's determination regarding eligibility of a REP to serve as POLR provider under the provisions of this section shall not be considered confidential information.

(2) Eligibility to be designated as a POLR provider is specific to each POLR area and customer class. A REP is eligible to be designated a POLR provider for a particular customer class in a POLR area, unless:

(A) A proceeding to revoke or suspend the REP's certificate is pending at the commission, the REP's certificate has been suspended or revoked by the commission, or the REP's certificate is deemed suspended pursuant to §25.107 of this title (relating to Certification of Retail Electric Providers (REPs));

(B) The sum of the numeric portion of the REP's percentage of ESI IDs served and percentage of retail sales by MWhs in the POLR area, for the particular class, is less than 1.0;

(C) The commission does not reasonably expect the REP to be able to meet the criteria set forth in subparagraph (B) of this paragraph during the entirety of the term;

(D) On the date of the commencement of the term, the REP or its predecessor will not have served customers in Texas for at least 18 months;

(E) The REP does not serve the applicable customer class, or does not have an executed delivery service agreement with the service area TDU;

(F) The REP is certificated as an Option 2 REP under §25.107 of this title;

(G) The REP's customers are limited to its own affiliates;

(H) A REP files an affidavit stating that it does not serve small or medium non-residential customers, except for the low-usage sites of the REP's large non-residential customers, or commonly owned or franchised affiliates of the REP's large non-residential customers and opts out of eligibility for either, or both of the small or medium non-residential customer classes; or

(I) The REP does not meet minimum financial, technical and managerial qualifications established by the commission under §25.107 of this title.

(3) For each term, the commission shall publish the names of all of the REPs eligible to serve as a POLR provider under this section for each customer class in each POLR area and shall provide notice to REPs determined to be eligible to serve as a POLR provider. A REP may challenge its eligibility determination within five business days of the notice of eligibility by filing with the commission additional documentation that includes the specific data, the specific calculation, and a specific explanation that clearly illustrate and prove the REP's assertion. Commission staff shall verify the additional documentation and, if accurate, reassess the REP's eligibility. Commission staff shall notify the REP of any change in eligibility status within 10 business days of the receipt of the additional documentation. A REP may then appeal to the commission through a contested case if the REP does not agree with the staff determination of eligibility. The contested status will not delay the designation of POLR providers.

(4) A standard form may be created by the commission for REPs to use in filing information concerning their eligibility to serve as a POLR provider.

(5) If ERCOT or a TDU has reason to believe that a REP is no longer capable of performing POLR responsibilities, ERCOT or the TDU shall make a filing with the commission detailing the basis for its concerns and shall provide a copy of the filing to the REP that is the subject of the filing. If the filing contains confidential information, ERCOT or the TDU shall file the confidential information in accordance with §22.71 of this title (relating to Filing of Pleadings, Documents, and Other Materials). Commission staff shall review the filing, and shall request that the REP demonstrate that it still meets the qualifications to provide the service. The commission staff may initiate a proceeding with the commission to disqualify the REP from providing POLR service. No ESI IDs shall be assigned to a POLR provider after the commission staff initiates a proceeding to disqualify the POLR provider, unless the commission by order confirms the POLR provider's designation.

(i) VREP list. Based on the information provided in accordance with this subsection and subsection (h) of this section, the commission shall post the names of VREPs on its webpage, including the aggregate customer count offered by VREPs. A REP may submit a request to be a VREP no earlier than June 1, and no later than July 31, of each even-numbered year. This filing shall include a description of the REP's capabilities to serve additional customers as well as the REP's current financial condition in enough detail to demonstrate that the REP is capable of absorbing a mass transition of customers without technically or financially distressing the REP and the specific information set out in this subsection. The commission's determination regarding eligibility of a REP to serve as a VREP, under the provisions of this section, shall not be considered confidential information.

(1) A VREP shall provide to the commission the name of the REP, the appropriate contact person with current contact information, which customer classes the REP is willing to serve within each POLR area, and the number of ESI IDs the REP is willing to serve by customer class and POLR area in each transition event.

(2) A REP that has met the eligibility requirements of subsection (h) of this section and provided the additional information set out in this subsection is eligible for designation as a VREP.

(3) Commission staff shall make an initial determination of the REPs that are to serve as a VREP for each customer class in each POLR area and publish their names. A REP may challenge its eligibility determination within five business days of the notice of eligibility by submitting to commission staff additional evidence of its capability to serve as a VREP. Commission staff shall reassess the REP's eligibility and notify the REP of any change in eligibility status within 10 business days of the receipt of the additional documentation. A REP may then appeal to the commission through a contested case if the REP does not agree with the staff determination of eligibility. The contested status will not delay the designation of VREPs.

(4) A VREP may file a request at any time to be removed from the VREP list or to modify the number of ESI IDs that it is willing to serve as a VREP. If the request is to increase the number of ESI IDs, it shall provide information to demonstrate that it is capable of serving the additional ESI IDs, and the commission staff shall make an initial determination, which is subject to an appeal to the commission, in accordance with the timelines specified in paragraph (3) of this subsection. If the request is to decrease the number of ESI IDs, the request shall be effective five calendar days after the request is filed with the commission; however, after the request becomes effective the VREP shall continue to serve ESI IDs previously acquired through a mass transition event as well as ESI IDs the VREP acquires from a mass transition event that occurs during the five-day notice period. If in a mass transition a VREP is able to acquire more customers than it originally volunteered to serve, the VREP may work with commission staff and ERCOT to increase its designation. Changes approved by commission staff shall be communicated to ERCOT and shall be implemented for the current allocation if possible.

(5) ERCOT or a TDU may challenge a VREP's eligibility. If ERCOT has reason to believe that a REP is no longer capable of performing VREP responsibilities, ERCOT shall make a filing with the commission detailing the basis for its concerns and shall provide a copy of the filing to the REP that is the subject of the filing. If the filing contains confidential information, ERCOT or the TDU shall file it in accordance with §25.71 of this title (relating to General Procedures, Requirements and Penalties). Commission staff shall review the filing of ERCOT and if commission staff concludes that the REP should no longer provide VREP service, it shall request that the REP demonstrate that it still meets the qualifications to provide the service. The commission staff may initiate a proceeding with the commission to disqualify the REP from providing VREP service. No ESI IDs shall be assigned to a VREP after the commission staff initiates a proceeding to disqualify the VREP, unless the commission by order confirms the VREP's designation.

(j) LSPs. This subsection governs the selection and service of REPs as LSPs.

(1) The REPs eligible to serve as LSPs shall be determined based on the information provided by REPs in accordance with subsection (h) of this section. However, for new TDU service areas that are transitioned to competition, the transition to competition plan approved by the commission may govern the selection of LSPs to serve as POLR providers.

(2) In each POLR area, for each customer class, the commission shall designate up to 15 LSPs. The eligible REPs that have the greatest market share based upon retail sales in megawatt-hours, by customer class and POLR area shall be designated as LSPs. Commission staff shall designate the LSPs by October 15th of each even-numbered year, based upon the data submitted to the commission under subsection (h) of this section. Designation as a VREP does not affect a REP's eligibility to also serve as an LSP.

(3) For the purpose of calculating the POLR rate for each customer class in each POLR area, an EFL shall be completed by the LSP that has the greatest market share in accordance with paragraph (2) of this subsection. The Electricity Facts Label (EFL) shall be supplied to commission staff electronically for placement on the commission webpage by January 1 of each year, and more often if there are changes to the non-bypassable charges. Where REP-specific information is required to be inserted in the EFL, the LSP supplying the EFL shall note that such information is REP-specific.

(4) An LSP serving transitioned residential and small non-residential customers under a rate prescribed by subsection (m)(2) of this section shall move such customers to a market-based month-to-month product, with pricing for such product to be effective no later than either the 61st day of service by the LSP or beginning with the customer's next billing cycle date following the 60th day of service by the LSP. For each transition event, all such transitioned customers in the same class and POLR area must be served pursuant to the same product terms, except for those customers specified in subparagraph (B) of this paragraph.

(A) The notice required by §25.475(d) of this title to inform the customers of the change to a market-based month-to-month product may be included with the notice required by subsection (t)(3) of this section or may be provided 14 days in advance of the change. If the §25.475(d) notice is included with the notice required by subsection (t)(3) of this section, the LSP may state that either or both the terms of service document and EFL for the market-based month-to-month product shall be provided at a later time, but no later than 14 days before their effective date.

(B) The LSP is not required to transfer to a market-based product any transitioned customer who is delinquent in payment of any charges for POLR service to such LSP as of the 60th day of service. If such a customer becomes current in payments to the LSP, the LSP shall move the customer to a market-based month-to-month product as described in this paragraph on the next billing cycle that occurs five business days after the customer becomes current. If the LSP does not plan to move customers who are delinquent in payment of any charges for POLR service as of the 60th day of service to a market-based month-to-month product, the LSP shall inform the customer of that potential outcome in the notice provided to comply with §25.475(d) of this title.

(5) Upon a request from an LSP and a showing that the LSP will be unable to maintain its financial integrity if additional customers are transferred to it under this section, the commission may relieve an LSP from a transfer of additional customers. The LSP shall continue providing continuous service until the commission issues an order relieving it of this responsibility. In the event the requesting LSP is relieved of its responsibility, the commission staff designee shall, with 90 days' notice, designate the next eligible REP, if any, as an LSP, based upon the criteria in this subsection.

(k) Designation of an LSP affiliate to provide POLR service on behalf of an LSP.

(1) An LSP may request the commission designate an LSP affiliate to provide POLR service on behalf of the LSP either with the LSP's filing under subsection (h) of this section or as a separate filing in the current term project. The filing shall be made at least 30 days prior to the date when the LSP affiliate is to begin providing POLR service on behalf of the LSP. To be eligible to provide POLR service on behalf of an LSP, the LSP affiliate must be certificated to provide retail electric service; have an executed delivery service agreement with the service area TDU; and meet the requirements of subsection (h)(2) of this section, with the exception of subsection (h)(2)(B), (C), (D), and (E) of this section as related to serving customers in the applicable customer class.

(2) The request shall include the name and certificate number of the LSP affiliate, information demonstrating the affiliation between the LSP and the LSP affiliate, and a certified agreement from an officer of the LSP affiliate stating that the LSP affiliate agrees to provide POLR service on behalf of the LSP. The request shall also include an affidavit from an officer of the LSP stating that the LSP will be responsible and indemnify any affected parties for all financial obligations of the LSP affiliate associated with the provisioning of POLR service on behalf of the LSP in the event that the LSP affiliate defaults or otherwise does not fulfill such financial obligations.

(3) Commission staff shall make an initial determination of the eligibility of the LSP affiliate to provide POLR service on behalf of an LSP and publish their names. The LSP or LSP affiliate may challenge commission staff's eligibility determination within five business days of the notice of eligibility by submitting to commission staff additional evidence of its capability to provide POLR service on behalf of the LSP. Commission staff shall reassess the LSP affiliate's eligibility and notify the LSP and LSP affiliate of any change in eligibility status within 10 business days of the receipt of the additional documentation. If the LSP or LSP affiliate does not agree with staff's determination of eligibility, either or both may then appeal the determination to the commission through a contested case. The LSP shall provide POLR service during the pendency of the contested case.

(4) ERCOT or a TDU may challenge an LSP affiliate's eligibility to provide POLR service on behalf of an LSP. If ERCOT or a TDU has reason to believe that an LSP affiliate is not eligible or is not performing POLR responsibilities on behalf of an LSP, ERCOT or the TDU shall make a filing with the commission detailing the basis for its concerns and shall provide a copy of the filing to the LSP and the LSP affiliate that are the subject of the filing. If the filing contains confidential information, ERCOT or the TDU shall file it in accordance with §25.71 of this title (relating to General Procedures, Requirements and Penalties). Commission staff shall review the filing and if commission staff concludes that the LSP affiliate should not be allowed to provide POLR service on behalf of the LSP, it shall request that the LSP affiliate demonstrate that it has the capability. The commission staff shall review the LSP affiliate's filing and may initiate a proceeding with the commission to disqualify the LSP affiliate from providing POLR service. The LSP affiliate may continue providing POLR service to ESI IDs currently receiving the service during the pendency of the proceeding; however, the LSP shall immediately assume responsibility to provide service under this section to customers who request POLR service, or are transferred to POLR service through a mass transition, during the pendency of the proceeding.

(5) Designation of an affiliate to provide POLR service on behalf of an LSP shall not change the number of ESI IDs served or the retail sales in megawatt-hours for the LSP for the reporting period nor does such designation relieve the LSP of its POLR service obligations in the event that the LSP affiliate fails to provide POLR service in accordance with the commission rules.

(6) The designated LSP affiliate shall provide POLR service and all reports as required by the commission's rules on behalf of the LSP.

(7) The methodology used by a designated LSP affiliate to calculate POLR rates shall be consistent with the methodology used to calculate LSP POLR rates in subsection (m) of this section.

(8) If an LSP affiliate designated to provide POLR service on behalf of an LSP cannot meet or fails to meet the POLR service requirements in applicable laws and Commission rules, the LSP shall provide POLR service to any ESI IDs currently receiving the service from the LSP affiliate and to ESI IDs in a future mass transition or upon customer request.

(9) An LSP may elect to reassume provisioning of POLR service from the LSP affiliate by filing a reversion notice with the commission and notifying ERCOT at least 30 days in advance.

(l) Mass transition of customers to POLR providers. The transfer of customers to POLR providers shall be consistent with this subsection.

(1) ERCOT shall first transfer customers to VREPs, up to the number of ESI IDs that each VREP has offered to serve for each customer class in the POLR area. ERCOT shall use the VREP list to assign ESI IDs to the VREPs in a non-discriminatory manner, before assigning customers to the LSPs. A VREP shall not be assigned more ESI IDs than it has indicated it is willing to serve pursuant to subsection (i) of this section. To ensure non-discriminatory assignment of ESI IDs to the VREPs, ERCOT shall:

(A) Sort ESI IDs by POLR area;

(B) Sort ESI IDs by customer class;

(C) Sort ESI IDs numerically;

(D) Sort VREPs numerically by randomly generated number; and

(E) Assign ESI IDs in numerical order to VREPs, in the order determined in subparagraph (D) of this paragraph, in accordance with the number of ESI IDs each VREP indicated a willingness to serve pursuant to subsection (i) of this section. If the number of ESI IDs is less than the total that the VREPs indicated that they are willing to serve, each VREP shall be assigned a proportionate number of ESI IDs, as calculated by dividing the number that each VREP indicated it was willing to serve by the total that all VREPs indicated they were willing to serve, multiplying the result by the total number of ESI IDs being transferred to the VREPs, and rounding to a whole number.

(2) If the number of ESI IDs exceeds the amount the VREPs are designated to serve, ERCOT shall assign remaining ESI IDs to LSPs in a non-discriminatory fashion, in accordance with their percentage of market share based upon retail sales in megawatt-hours, on a random basis within a class and POLR area, except that a VREP that is also an LSP that volunteers to serve at least 1% of its market share for a class of customers in a POLR area shall be exempt from the LSP allocation up to 1% of the class and POLR area. To ensure non-discriminatory assignment of ESI IDs to the LSPs, ERCOT shall:

(A) Sort the ESI IDs in excess of the allocation to VREPs, by POLR area;

(B) Sort ESI IDs in excess of the allocation to VREPs, by customer class;

(C) Sort ESI IDs in excess of the allocation to VREPs, numerically;

(D) Sort LSPs, except LSPs that volunteered to serve 1% of their market share as a VREP, numerically by MWhs served;

(E) Assign ESI IDs that represent no more than 1% of the total market for that POLR area and customer class less the ESI IDs assigned to VREPs that volunteered to serve at least 1% of their market share for each POLR area and customer class in numerical order to LSPs designated in subparagraph (D) of this paragraph, in proportion to the percentage of MWhs served by each LSP to the total MWhs served by all LSPs;

(F) Sort LSPs, including any LSPs previously excluded under subparagraph (D) of this paragraph; and

(G) Assign all remaining ESI IDs in numerical order to LSPs in proportion to the percentage of MWhs served by each LSP to the total MWhs served by all LSPs.

(3) Each mass transition shall be treated as a separate event.

(m) Rates applicable to POLR service.

(1) A VREP shall provide service to customers using a market-based, month-to-month product. The VREP shall use the same market-based, month-to-month product for all customers in a mass transition that are in the same class and POLR area.

(2) Subparagraphs (A)-(C) of this paragraph establish the maximum rate for POLR service charged by an LSP. An LSP may charge a rate less than the maximum rate if it charges the lower rate to all customers in a mass transition that are in the same class and POLR area.

(A) Residential customers. The LSP rate for the residential customer class shall be determined by the following formula: LSP rate (in $ per kWh) = (Non-bypassable charges + LSP customer charge + LSP energy charge) / kWh used Where:

(i) Non-bypassable charges shall be all TDU charges and credits for the appropriate customer class in the applicable service territory and other charges including ERCOT administrative charges, nodal fees or surcharges, reliability unit commitment (RUC) capacity short charges attributable to LSP load, and applicable taxes from various taxing or regulatory authorities, multiplied by the level of kWh and kW used, where appropriate.

(ii) LSP customer charge shall be $0.06 per kWh.

(iii) LSP energy charge shall be the sum over the billing period of the actual hourly Real-Time Settlement Point Prices (RTSPPs) for the customer's load zone that is multiplied by the number of kWhs the customer used during that hour and that is further multiplied by 120%.

(iv) "Actual hourly RTSPP" is an hourly rate based on a simple average of the actual interval RTSPPs over the hour.

(v) "Number of kWhs the customer used" is based either on interval data or on an allocation of the customer's total actual usage to the hour based on a ratio of the sum of the ERCOT backcasted profile interval usage data for the customer's profile type and weather zone over the hour to the total of the ERCOT backcasted profile interval usage data for the customer's profile type and weather zone over the customer's entire billing period.

(vi) For each billing period, if the sum over the billing period of the actual hourly RTSPP for a customer multiplied by the number of kWhs the customer used during that hour falls below the simple average of the RTSPPs for the load zone located partially or wholly in the customer's TDU service territory that had the highest simple average price over the 12-month period ending September 1 of the preceding year multiplied by the number of kWhs the customer used during the customer's billing period, then the LSP energy charge shall be the simple average of the RTSPPs for the load zone partially or wholly in the customer's TDU service territory that had the highest simple average over the 12-month period ending September 1 of the preceding year multiplied by the number of kWhs the customer used during the customer's billing period multiplied by 125%. This methodology shall apply until the commission issues an order suspending or modifying the operation of the floor after conducting an investigation.

(B) Small and medium non-residential customers. The LSP rate for the small and medium non-residential customer classes shall be determined by the following formula: LSP rate (in $ per kWh) = (Non-bypassable charges + LSP customer charge + LSP demand charge + LSP energy charge) / kWh used Where:

(i) Non-bypassable charges shall be all TDU charges and credits for the appropriate customer class in the applicable service territory, and other charges including ERCOT administrative charges, nodal fees or surcharges, RUC capacity short charges attributable to LSP load, and applicable taxes from various taxing or regulatory authorities, multiplied by the level of kWh and kW used, where appropriate.

(ii) LSP customer charge shall be $0.025 per kWh.

(iii) LSP demand charge shall be $2.00 per kW, per month, for customers that have a demand meter, and $50.00 per month for customers that do not have a demand meter.

(iv) LSP energy charge shall be the sum over the billing period of the actual hourly RTSPPs, for the customer's load zone that is multiplied by number of kWhs the customer used during that hour and that is further multiplied by 125%.

(v) "Actual hourly RTSPP" is an hourly rate based on a simple average of the actual interval RTSPPs over the hour.

(vi) "Number of kWhs the customer used" is based either on interval data or on an allocation of the customer's total actual usage to the hour based on a ratio of the sum of the ERCOT backcasted profile interval usage data for the customer's profile type and weather zone over the hour to the total of the ERCOT backcasted profile interval usage data for the customer's profile type and weather zone over the customer's entire billing period.

(vii) For each billing period, if the sum over the billing period of the actual hourly RTSPP for a customer multiplied by the number of kWhs the customer used during that hour falls below the simple average of the RTSPPs for the load zone located partially or wholly in the customer's TDU service territory that had the highest simple average over the 12-month period ending September 1 of the preceding year multiplied by the number of kWhs the customer used during the customer's billing period, then the LSP energy charge shall be the simple average of the RTSPPs for the load zone located partially or wholly in the customer's TDU service territory that had the highest simple average price over the 12-month period ending September 1 of the preceding year multiplied by the number of kWhs the customer used during the customer's billing period multiplied by 125%. This methodology shall apply until the commission issues an order suspending or modifying the operation of the floor after conducting an investigation.

(C) Large non-residential customers. The LSP rate for the large non-residential customer class shall be determined by the following formula: LSP rate (in $ per kWh) = (Non-bypassable charges + LSP customer charge + LSP demand charge + LSP energy charge) / kWh used Where:

(i) Non-bypassable charges shall be all TDU charges and credits for the appropriate customer class in the applicable service territory, and other charges including ERCOT administrative charges, nodal fees or surcharges, RUC capacity short charges attributable to LSP load, and applicable taxes from various taxing or regulatory authorities, multiplied by the level of kWh and KW used, where appropriate.

(ii) LSP customer charge shall be $2,897.00 per month.

(iii) LSP demand charge shall be $6.00 per kW, permonth.

(iv) LSP energy charge shall be the appropriate RTSPP, determined on the basis of 15-minute intervals, for the customer multiplied by 125%, multiplied by the level of kilowatt-hours used. The energy charge shall have a floor of $7.25 per MWh.

(3) If in response to a complaint or upon its own investigation, the commission determines that an LSP failed to charge the appropriate rate prescribed by paragraph (2) of this subsection, and as a result overcharged its customers, the LSP shall issue refunds to the specific customers who were overcharged.

(4) On a showing of good cause, the commission may permit the LSP to adjust the rate prescribed by paragraph (2) of this subsection, if necessary to ensure that the rate is sufficient to allow the LSP to recover its costs of providing service. Notwithstanding any other commission rule to the contrary, such rates may be adjusted on an interim basis for good cause shown and after at least 10 business days' notice and an opportunity for hearing on the request for interim relief. Any adjusted rate shall be applicable to all LSPs charging the rate prescribed by paragraph (2) of this subsection to the specific customer class, within the POLR area that is subject to the adjustment.

(5) For transitioned customers, the customer and demand charges associated with the rate prescribed by paragraph (3) of this subsection shall be pro-rated for partial month usage if a large non-residential customer switches from the LSP to a REP of choice.

(n) Challenges to customer assignments. A POLR provider is not obligated to serve a customer within a customer class or a POLR area for which the REP is not designated as a POLR provider, after a successful challenge of the customer assignment. A POLR provider shall use the ERCOT market variance resolution tool to challenge a customer class assignment with the TDU. The TDU shall make the final determination based upon historical usage data and not premise type. If the customer class assignment is changed and a different POLR provider for the customer is determined appropriate, the customer shall then be served by the appropriate POLR provider. Back dated transactions may be used to correct the POLR assignment.

(o) Limitation on liability. The POLR providers shall make reasonable provisions to provide service under this section to any ESI IDs currently receiving the service and to ESI IDs obtained in a future mass transition or served upon customer request; however, liabilities not excused by reason of force majeure or otherwise shall be limited to direct, actual damages.

(1) Neither the customer nor the POLR provider shall be liable to the other for consequential, incidental, punitive, exemplary, or indirect damages. These limitations apply without regard to the cause of any liability or damage.

(2) In no event shall ERCOT or a POLR provider be liable for damages to any REP, whether under tort, contract or any other theory of legal liability, for transitioning or attempting to transition a customer from such REP to the POLR provider to carry out this section, or for marketing, offering or providing competitive retail electric service to a customer taking service under this section from the POLR provider.

(p) REP obligations in a transition of customers to POLR service.

(1) A customer may initiate service with an LSP by requesting such service at the rate prescribed by subsection (m)(2) of this section with any LSP that is designated to serve the requesting customer's customer class within the requesting customer's service area. An LSP cannot refuse a customer's request to make arrangements for POLR service, except as otherwise permitted under this title.

(2) The POLR provider is responsible for obtaining resources and services needed to serve a customer once it has been notified that it is serving that customer. The customer is responsible for charges for service under this section at the rate in effect at that time.

(3) If a REP terminates service to a customer, or transitions a customer to a POLR provider, the REP is financially responsible for the resources and services used to serve the customer until it notifies the independent organization of the termination or transition of the service and the transfer to the POLR provider is complete.

(4) The POLR provider is financially responsible for all costs of providing electricity to customers from the time the transfer or initiation of service is complete until such time as the customer ceases taking service under this section.

(5) A defaulting REP whose customers are subject to a mass transition event shall return the customers' deposits within seven calendar days of the initiation of the transition.

(6) ERCOT shall create a single standard file format and a standard set of customer billing contact data elements that, in the event of a mass transition, shall be used by the exiting REP and the POLRs to send and receive customer billing contact information. The process, as developed by ERCOT shall be tested on a periodic basis. All REPs shall submit timely, accurate, and complete files, as required by ERCOT in a mass transition event, as well as for periodic testing. The commission shall establish a procedure for the verification of customer information submitted by REPs to ERCOT. ERCOT shall notify the commission if any REP fails to comply with the reporting requirements in this subsection.

(7) When customers are to be transitioned or assigned to a POLR provider, the POLR provider may request usage and demand data, and customer contact information including email, telephone number, and address from the appropriate TDU and from ERCOT, once the transition to the POLR provider has been initiated. Customer proprietary information provided to a POLR provider in accordance with this section shall be treated as confidential and shall only be used for mass transition related purposes.

(8) Information from the TDU and ERCOT to the POLR providers shall be provided in Texas SET format when Texas SET transactions are available. However, the TDU or ERCOT may supplement the information to the POLR providers in other formats to expedite the transition. The transfer of information in accordance with this section shall not constitute a violation of the customer protection rules that address confidentiality.

(9) A POLR provider may require a deposit from a customer that has been transitioned to the POLR provider to continue to serve the customer. Despite the lack of a deposit, the POLR provider is obligated to serve the customer transitioned or assigned to it, beginning on the service initiation date of the transition or assignment, and continuing until such time as any disconnection request is effectuated by the TDU. A POLR provider may make the request for deposit before it begins serving the customer, but the POLR provider shall begin providing service to the customer even if the service initiation date is before it receives the deposit - if any deposit is required. A POLR provider shall not disconnect the customer until the appropriate time period to submit the deposit has elapsed. For the large non-residential customer class, a POLR provider may require a deposit to be provided in three calendar days. For the residential customer class, the POLR provider may require a deposit to be provided after 15 calendar days of service if the customer received 10 days' notice that a deposit was required. For all other customer classes, the POLR provider may require a deposit to be provided in 10 calendar days. The POLR provider may waive the deposit requirement at the customer's request if deposits are waived in a non-discriminatory fashion. If the POLR provider obtains sufficient data, it shall determine whether a residential customer has satisfactory credit based on the criteria the POLR provider routinely applies to its other residential customers. If the customer has satisfactory credit, the POLR provider shall not request a deposit from the residential customer.

(A) At the time of a mass transition, the Executive Director or staff designated by the Executive Director shall distribute available proceeds from an irrevocable stand-by letter of credit in accordance with the priorities established in §25.107(f)(6) of this title. For a REP that has obtained a current list from the Low Income List Administrator (LILA) that identifies low-income customers, these funds shall first be used to provide deposit payment assistance for that REP's transitioned low-income customers. The Executive Director or staff designee shall, at the time of a transition event, determine the reasonable deposit amount up to $400 per customer ESI ID, unless good cause exists to increase the level of the reasonable deposit amount above $400. Such reasonable deposit amount may take into account factors such as typical residential usage and current retail residential prices, and, if fully funded, shall satisfy in full the customers' initial deposit obligation to the VREP or LSP.

(B) For a REP that has obtained a current list from the LILA that identifies low-income customers, the Executive Director or the staff designee shall distribute available proceeds pursuant to §25.107(f)(6) of this title to the VREPs proportionate to the number of customers they received in the mass transition, who at the time of the mass transition were identified as low-income customers by the current LILA list, up to the reasonable deposit amount set by the Executive Director or staff designee. If funds remain available after distribution to the VREPs, the remaining funds shall be distributed to the appropriate LSPs by dividing the amount remaining by the number of low income customers as identified in the LILA list that are allocated to LSPs, up to the reasonable deposit amount set by the Executive Director or staff designee.

(C) If the funds distributed in accordance with §25.107(f)(6) of this title do not equal the reasonable deposit amount determined, the VREP and LSP may request from the customer payment of the difference between the reasonable deposit amount and the amount distributed. Such difference shall be collected in accordance with §25.478(e)(3) of this title (relating to Credit Requirements and Deposits).

(D) Notwithstanding §25.478(d) of this title, 90 days after the transition date, the VREP or LSP may request payment of an amount that results in the total deposit held being equal to what the VREP or LSP would otherwise have charged a customer in the same customer class and service area in accordance with §25.478(e) of this title, at the time of the transition.

(10) On the occurrence of one or more of the following events, ERCOT shall initiate a mass transition to POLR providers, of all of the customers served by a REP:

(A) Termination of the Load Serving Entity (LSE) or Qualified Scheduling Entity (QSE) Agreement for a REP with ERCOT;

(B) Issuance of a commission order recognizing that a REP is in default under the TDU Tariff for Retail Delivery Service;

(C) Issuance of a commission order de-certifying a REP;

(D) Issuance of a commission order requiring a mass transition to POLR providers;

(E) Issuance of a judicial order requiring a mass transition to POLR providers; and

(F) At the request of a REP, for the mass transition of all of that REP's customers.

(11) A REP shall not use the mass transition process in this section as a means to cease providing service to some customers, while retaining other customers. A REP's improper use of the mass transition process may lead to de-certification of the REP.

(12) ERCOT may provide procedures for the mass transition process, consistent with this section.

(13) A mass transition under this section shall not override or supersede a switch request made by a customer to switch an ESI ID to a new REP of choice, if the request was made before a mass transition is initiated. If a switch request has been made but is scheduled for any date after the next available switch date, the switch shall be made on the next available switch date.

(14) Customers who are mass transitioned shall be identified for a period of 60 calendar days. The identification shall terminate at the first completed switch or at the end of the 60-day period, whichever is first. If necessary, ERCOT system changes or new transactions shall be implemented no later than 14 months from the effective date of this section to communicate that a customer was acquired in a mass transition and is not charged the out-of-cycle meter read pursuant to paragraph (16) of this subsection. To the extent possible, the systems changes should be designed to ensure that the 60-day period following a mass transition, when a customer switches away from a POLR provider, the switch transaction is processed as an unprotected, out-of-cycle switch, regardless of how the switch was submitted.

(15) In the event of a transition to a POLR provider or away from a POLR provider to a REP of choice, the switch notification notice detailed in §25.474(l) of this title (relating to Selection of Retail Electric Provider) is not required.

(16) In a mass transition event, the ERCOT initiated transactions shall request an out-of-cycle meter read for the associated ESI IDs for a date two calendar days after the calendar date ERCOT initiates such transactions to the TDU. If an ESI ID does not have the capability to be read in a fashion other than a physical meter read, the out-of-cycle meter read may be estimated. An estimated meter read for the purpose of a mass transition to a POLR provider shall not be considered a break in a series of consecutive months of estimates, but shall not be considered a month in a series of consecutive estimates performed by the TDU. A TDU shall create a regulatory asset for the TDU fees associated with a mass transition of customers to a POLR provider pursuant to this subsection. Upon review of reasonableness and necessity, a reasonable level of amortization of such regulatory asset shall be included as a recoverable cost in the TDU's rates in its next rate case or such other rate recovery proceeding as deemed necessary. The TDU shall not bill as a discretionary charge, the costs included in this regulatory asset, which shall consist of the following:

(A) fees for out-of-cycle meter reads associated with the mass transition of customers to a POLR provider; and

(B) fees for the first out-of-cycle meter read provided to a customer who transfers away from a POLR provider, when the out-of-cycle meter read is performed within 60 calendar days of the date of the mass transition and the customer is identified as a transitioned customer.

(17) In the event the TDU estimates a meter read for the purpose of a mass transition, the TDU shall perform a true-up evaluation of each ESI ID after an actual meter reading is obtained. Within 10 days after the actual meter reading is obtained, the TDU shall calculate the actual average kWh usage per day for the time period from the most previous actual meter reading occurring prior to the estimate for the purpose of a mass transition to the most current actual meter reading occurring after the estimate for the purpose of mass transition. If the average daily estimated usage sent to the exiting REP is more than 50% greater than or less than the average actual kWh usage per day, the TDU shall promptly cancel and re-bill both the exiting REP and the POLR using the average actually daily usage.

(q) Termination of POLR service provider status.

(1) The commission may revoke a REP's POLR status after notice and opportunity for hearing:

(A) If the POLR provider fails to maintain REP certification;

(B) If the POLR provider fails to provide service in a manner consistent with this section;

(C) The POLR provider fails to maintain appropriate financial qualifications; or

(D) For other good cause.

(2) If an LSP defaults or has its status revoked before the end of its term, after a review of the eligibility criteria, the commission staff designee shall, as soon as practicable, designate the next eligible REP, if any, as an LSP, based on the criteria in subsection (j) of this section.

(3) At the end of the POLR service term, the outgoing LSP shall continue to serve customers who have not selected another REP.

(r) Electric cooperative delegation of authority. An electric cooperative that has adopted customer choice may select to delegate to the commission its authority to select POLR providers under PURA §41.053(c) in its certificated service area in accordance with this section. After notice and opportunity for comment, the commission shall, at its option, accept or reject such delegation of authority. If the commission accepts the delegation of authority, the following conditions shall apply:

(1) The board of directors shall provide the commission with a copy of a board resolution authorizing such delegation of authority;

(2) The delegation of authority shall be made at least 30 calendar days prior to the time the commission issues a publication of notice of eligibility;

(3) The delegation of authority shall be for a minimum period corresponding to the period for which the solicitation shall be made;

(4) The electric cooperative wishing to delegate its authority to designate an continuous provider shall also provide the commission with the authority to apply the selection criteria and procedures described in this section in selecting the POLR providers within the electric cooperative's certificated service area; and

(5) If there are no competitive REPs offering service in the electric cooperative certificated area, the commission shall automatically reject the delegation of authority.

(s) Reporting requirements. Each LSP that serves customers under a rate prescribed by subsection (m)(2) of this section shall file the following information with the commission on a quarterly basis beginning January of each year in a project established by the commission for the receipt of such information. Each quarterly report shall be filed within 30 calendar days of the end of the quarter.

(1) For each month of the reporting quarter, each LSP shall report the total number of new customers acquired by the LSP under this section and the following information regarding these customers:

(A) The number of customers from whom a deposit was requested pursuant to the provisions of §25.478 of this title, and the average amount of deposit requested;

(B) The number of customers from whom a deposit was received, including those who entered into deferred payment plans for the deposit, and the average amount of the deposit;

(C) The number of customers whose service was physically disconnected pursuant to the provisions of §25.483 of this title (relating to Disconnection of Service) for failure to pay a required deposit; and

(D) Any explanatory data or narrative necessary to account for customers that were not included in either subparagraph (B) or (C) of this paragraph.

(2) For each month of the reporting quarter each LSP shall report the total number of customers to whom a disconnection notice was issued pursuant to the provisions of §25.483 of this title and the following information regarding those customers:

(A) The number of customers who entered into a deferred payment plan, as defined by §25.480(j) of this title (relating to Bill Payment and Adjustments) with the LSP;

(B) The number of customers whose service was physically disconnected pursuant to §25.483 of this title;

(C) The average amount owed to the LSP by each disconnected customer at the time of disconnection; and

(D) Any explanatory data or narrative necessary to account for customers that are not included in either subparagraph (A) or (B) of this paragraph.

(3) For the entirety of the reporting quarter, each LSP shall report, for each customer that received POLR service, the TDU and customer class associated with the customer's ESI ID, the number of days the customer received POLR service, and whether the customer is currently the LSP's customer.

(t) Notice of transition to POLR service to customers. When a customer is moved to POLR service, the customer shall be provided notice of the transition by ERCOT, the REP transitioning the customer, and the POLR provider. The ERCOT notice shall be provided within two days of the time ERCOT and the transitioning REP know that the customer shall be transitioned and customer contact information is available. If ERCOT cannot provide notice to customers within two days, it shall provide notice as soon as practicable. The POLR provider shall provide the notice required by paragraph (3) of this subsection to commission staff at least 48 hours before it is provided to customers, and shall provide the notice to transitioning customers as soon as practicable. The POLR provider shall email the notice to the commission staff members designated for receipt of the notice.

(1) ERCOT notice methods shall include a post-card, containing the official commission seal with language and format approved by the commission. ERCOT shall notify transitioned customers with an automated phone-call and email to the extent the information to contact the customer is available pursuant to subsection (p)(6) of this section. ERCOT shall study the effectiveness of the notice methods used and report the results to the commission.

(2) Notice by the REP from which the customer is transferred shall include:

(A) The reason for the transition;

(B) A contact number for the REP;

(C) A statement that the customer shall receive a separate notice from the POLR provider that shall disclose the date the POLR provider shall begin serving the customer;

(D) Either the customer's deposit plus accrued interest, or a statement that the deposit shall be returned within seven days of the transition;

(E) A statement that the customer can leave the assigned service by choosing a competitive product or service offered by the POLR provider, or another competitive REP, as well as the following statement: "If you would like to see offers from different retail electric providers, please access www.powertochoose.org, or call toll-free 1-866-PWR-4-TEX (1-866-797-4839) for a list of providers in your area;"

(F) For residential customers, notice from the commission in the form of a bill insert or a bill message with the header "An Important Message from the Public Utility Commission Regarding Your Electric Service" addressing why the customer has been transitioned to another REP, the continuity of service purpose, the option to choose a different competitive provider, and information on competitive markets to be found at www.powertochoose.org, or toll-free at 1-866-PWR-4-TEX (1-866-797-4839);

(G) If applicable, a description of the activities that the REP shall use to collect any outstanding payments, including the use of consumer reporting agencies, debt collection agencies, small claims court, and other remedies allowed by law, if the customer does not pay or make acceptable payment arrangements with the REP; and

(H) Notice to the customer that after being transitioned to POLR service, the customer may accelerate a switch to another REP by requesting a special or out-of-cycle meter read.

(3) Notice by the POLR provider shall include:

(A) The date the POLR provider began or shall begin serving the customer and a contact number for the POLR provider;

(B) A description of the POLR provider's rate for service. In the case of a notice from an LSP that applies the pricing of subsection (m)(2) of this section, a statement that the price is generally higher than available competitive prices, that the price is unpredictable, and that the exact rate for each billing period shall not be determined until the time the bill is prepared;

(C) The deposit requirements of the POLR provider and any applicable deposit waiver provisions and a statement that, if the customer chooses a different competitive product or service offered by the POLR provider, a REP affiliated with the POLR provider, or another competitive REP, a deposit may be required;

(D) A statement that the additional competitive products or services may be available through the POLR provider, a REP affiliated with the POLR provider, or another competitive REP, as well as the following statement: "If you would like to choose a different retail electric provider, please access www.powertochoose.org, or call toll-free 1-866-PWR-4-TEX (1-866-797-4839) for a list of providers in your area;"

(E) The applicable Terms of Service and Electricity Facts Label (EFL); and

(F) For residential customers that are served by an LSP under a rate prescribed by subsection (m)(2) of this section, a notice to the customer that after being transitioned to service from a POLR provider, the customer may accelerate a switch to another REP by requesting a special or out-of-cycle meter read.

(u) Market notice of transition to POLR service. ERCOT shall notify all affected Market Participants and the Retail Market Subcommittee (RMS) email listserv of a mass transition event within the same day of an initial mass-transition call after the call has taken place. The notification shall include the exiting REP's name, total number of ESI IDs, and estimated load.

(v) Disconnection by a POLR provider. The POLR provider must comply with the applicable customer protection rules as provided for under Subchapter R of this chapter, except as otherwise stated in this section. To ensure continuity of service, service under this section shall begin when the customer's transition to the POLR provider is complete. A customer deposit is not a prerequisite for the initiation of service under this section. Once service has been initiated, a customer deposit may be required to prevent disconnection. Disconnection for failure to pay a deposit may not occur until after the proper notice and after that appropriate payment period detailed in §25.478 of this title has elapsed, except where otherwise noted in this section.

(w) Deposit payment assistance.

(1) The commission staff designee shall distribute the deposit payment assistance monies to the appropriate POLRs on behalf of customers as soon as practicable.

(2) The Executive Director or staff designee shall use best efforts to provide written notice to the appropriate POLRs of the following on or before the second calendar day after the transition:

(A) a list of the ESI IDs identified by the LILA that have been or shall be transitioned to the applicable POLR (if available); and

(B) the amount of deposit payment assistance that shall be provided on behalf of a POLR customer identified by the LILA (if available).

(3) Amounts credited as deposit payment assistance pursuant to this section shall be refunded to the customer in accordance with §25.478(j) of this title.

§25.45.Low-Income List Administrator.

(a) Purpose. The purpose of this section is to define the responsibilities of the Low-Income List Administrator (LILA) to establish and maintain a list of eligible low-income customers and to specify the process for a retail electric provider (REP) who voluntarily seeks to obtain the low-income customer identification service from the LILA pursuant to Public Utility Regulatory Act (PURA) §17.007.

(b) Application. This section applies to the LILA, which has been contracted by the commission to administer aspects of the low-income customer identification process established under PURA §17.007 in cooperation with the Texas Health and Human Services Commission (HHSC). This section also applies to REPs that provide retail electric service in an area that has been opened to customer choice and that voluntarily seek to obtain the low-income customer identification service from the LILA.

(c) Customer identification process. The LILA shall identify eligible low-income customers through a monthly automatic identification process in cooperation with HHSC.

(1) Automatic identification is an electronic process to identify customers eligible for the low-income list by matching client data from the HHSC with residential customer-specific data from participating REPs.

(A) HHSC shall provide client information to the LILA in accordance with subsection (d)(1) of this section.

(B) REPs shall provide customer information to the LILA in accordance with subsection (d)(3) of this section.

(C) The LILA shall compare the customer information from HHSC and REPs, create files of matching customers and notify the REPs of their eligible customers.

(2) Automatically identified customers shall continue to be included on the LILA's list of eligible low-income customers as long as the customers receive qualifying HHSC benefits. Once a customer no longer receives qualifying HHSC benefits, the customer will no longer be identified by the LILA's process as an eligible low-income customer that is sent to the customer's REP.

(d) Responsibilities. In addition to the requirements established in this section, program responsibilities for the LILA may be established in the commission's contract with the LILA; program responsibilities for tasks undertaken by HHSC may be established in the memorandum of understanding between the commission and HHSC.

(1) HHSC's responsibilities. HHSC shall assist in the implementation and maintenance of the automatic enrollment process by providing a database of customers receiving qualifying HHSC benefits as detailed in the memorandum of understanding between HHSC and the commission.

(2) The LILA's responsibilities. The LILA shall:

(A) receive customer lists from participating REPs on at least a monthly basis through data transfer;

(B) retrieve the database of clients from HHSC on at least a monthly basis;

(C) establish a list of eligible customers, by comparing customer lists from the REPs with HHSC databases and identifying customer records that reasonably match;

(D) make available to each participating REP, on a date prescribed by the commission on at least a monthly basis, a list of eligible low-income customers; and

(E) protect the confidentiality of the customer information provided by the REPs and the client information provided by HHSC.

(3) A participating REP's responsibilities. A REP that voluntarily seeks to obtain a list of eligible low-income customers shall:

(A) provide residential customer information to the LILA through data transfer on a date prescribed by the commission on at least a monthly basis. The customer information shall include, to the greatest extent possible, each full name of the primary and secondary customer on each account, billing and service addresses, primary and secondary social security numbers, primary and secondary telephone numbers, Electric Service Identifier (ESI ID), service provider account number, and premise code;

(B) retrieve from the LILA the list of eligible low-income customers; and

(C) assist the LILA in working to resolve issues concerning customer eligibility.

(e) Confidentiality of information.

(1) The data acquired from HHSC pursuant to this section is subject to a HHSC confidentiality agreement.

(2) All data transfers from REPs to the LILA pursuant to this section shall be conducted under the terms and conditions of a standard confidentiality agreement to protect customer privacy and REPs' competitively sensitive information.

(3) The LILA may use information obtained pursuant to this section only for purposes prescribed by commission rule.

(f) Identification of the LILA and annual election process. The commission shall maintain a project in which REPs may elect to obtain the low-income customer identification service from the LILA. As part of this project, the commission may delegate to the executive director the authority to contract with a third-party vendor to administer aspects of the low-income customer identification process established under PURA §17.007 in cooperation with HHSC, and to negotiate the LILA's annual fee for the provision of the low-income customer identification service under PURA §17.007(d)(2).

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on April 23, 2018.

TRD-201801809

Adriana Gonzales

Rules Coordinator

Public Utility Commission of Texas

Effective date: May 13, 2018

Proposal publication date: December 29, 2017

For further information, please call: (512) 936-7223


SUBCHAPTER E. CERTIFICATION, LICENSING AND REGISTRATION

16 TAC §25.107

This amendment is adopted under §14.002 of the Public Utility Regulatory Act, Tex. Util. Code Ann. §14.002 (West 2016 and Supp. 2017) (PURA) which provides the commission with the authority to make and enforce rules reasonably required in the exercise of its powers and jurisdiction, including rules of practice and procedure; PURA §17.007, which provides for a process by which a REP can identify low-income customers; PURA §39.101, which provides the commission with the authority to ensure that retail customer protections are established to entitle a customer to safe, reliable, and reasonably priced electricity.

Cross reference to statutes: Public Utility Regulatory Act §14.002, §14.052, §17.007, §39.101.

§25.107.Certification of Retail Electric Providers (REPs).

(a) Applicability. This section applies to all persons who provide or seek to provide electric service to retail customers in an area in which customer choice is in effect and to retail customers participating in a customer choice pilot project authorized by the commission. This section does not apply to the state, political subdivisions of the state, electric cooperatives or municipal corporations, or to electric utilities providing service in an area where customer choice is not in effect. An electric cooperative or municipally owned utility participating in customer choice may offer electric energy and related services at unregulated prices directly to retail customers who have customer choice without obtaining certification as a REP.

(1) A person must obtain a certificate pursuant to this subsection before purchasing, taking title to, or reselling electricity in order to provide retail electric service.

(2) A person who does not purchase, take title to, or resell electricity in order to provide electric service to a retail customer is not a REP and may perform a service for a REP without obtaining a certificate pursuant to this section.

(3) A REP that outsources retail electric functions remains responsible under commission rules for those functions and remains accountable to applicable laws and commission rules for all activities conducted on its behalf by any subcontractor, agent, or any other entity.

(4) All filings made with the commission pursuant to this section, including a filing subject to a claim of confidentiality, shall be filed with the commission's filing clerk in accordance with the commission's Procedural Rules, Chapter 22, Subchapter E, of this title (relating to Pleadings and other Documents).

(b) Definitions. The following words and terms when used in this section shall have the following meaning unless the context indicates otherwise:

(1) Affiliate--An affiliate of, or a person affiliated with, a specified person, is a person that directly, or indirectly through one or more intermediaries, controls or is controlled by, or is under the common control with, the person specified.

(2) Continuous and reliable electric service--Retail electric service provided by a REP that is consistent with the customer's terms and conditions of service and uninterrupted by unlawful or unjustified action or inaction of the REP.

(3) Control--The term control (including the terms controlling, controlled by and under common control with) means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a person, whether through ownership of voting securities, by contract, or otherwise.

(4) Customer--Any entity who has applied for, has been accepted for, or is receiving retail electric service from a REP on an end-use basis.

(5) Default--As defined in a transmission and distribution utility (TDU) tariff for retail delivery service, Electric Reliability Council of Texas (ERCOT) qualified scheduling entity (QSE) agreement, or ERCOT load serving entity (LSE) agreement.

(6) Executive officer--When used with reference to a person means its president or chief executive officer, a vice president serving as its chief financial officer, or a vice president serving as its chief accounting officer, a vice president in charge of a principal business unit, division or function, any other officer of the person who performs a policy making function for the person, or any other person who performs similar policy making functions for the person. Executive officers or subsidiaries may be deemed executive officers of the person if they perform policy making functions for the person.

(7) Guarantor--A person providing a guaranty agreement, business financial commitment, or a credit support agreement providing financial support to a REP or applicant for REP certification pursuant to this section.

(8) Investment-grade credit rating--A long-term unsecured credit rating of at least "Baa3" from Moody's Investors' Service, or "BBB-" from Standard & Poor's or Fitch, or "BBB" from A.M. Best.

(9) Permanent employee--An individual that is fully integrated into a REP's business organization. A consultant is not a permanent employee.

(10) Person--Includes an individual and any business entity, including and without limitation, a limited liability company, a partnership of two or more persons having a joint or common interest, a mutual or cooperative association, and a corporation, but does not include an electric cooperative or a municipal corporation.

(11) Principal--An executive officer; partner; owner; director; shareholder of a privately held company; shareholder of a publicly traded company who owns more than 10 % of a class of equity securities; or a person that controls the person in question.

(12) Retail electric provider--A person that sells electric energy to retail customers in this state. As provided in Public Utility Regulatory Act (PURA) §39.353(b), a REP is not an aggregator.

(13) Shareholder--The term shareholder means the legal or beneficial owner of any of the equity of any business entity, including without limitation and as the context and applicable business entity requires, stockholders of corporations, members of limited liability companies and partners of partnerships.

(14) Tangible net worth--Total shareholders' equity, determined in accordance with generally accepted accounting principles, less intangible assets other than goodwill.

(15) Working day--A day on which the commission is open for the conduct of business.

(c) Application for REP certification.

(1) A person applying for certification as a REP must demonstrate its capability of complying with this section. A person who operates as a REP or who receives a certificate under this section shall maintain compliance with this section.

(2) An application for certification shall be made on a form approved by the commission, verified by oath or affirmation, and signed by an executive officer of the applicant.

(3) Except where good cause exists to extend the time for review, the presiding officer shall issue an order finding whether an application is deficient or complete within 20 working days of filing. Deficient applications, including those without necessary supporting documentation, will be rejected without prejudice to the applicant's right to reapply.

(4) While an application for a certificate is pending, an applicant shall inform the commission of any material change in the information provided in the application within ten working days of any such change.

(5) Except where good cause exists to extend the time for review, the commission shall enter an order approving, rejecting, or approving with modifications, an application within 90 days of the filing of the application.

(d) REP certification requirements. A person seeking certification under this section may apply to provide services under paragraph (1) or (2) of this subsection, and shall designate its election in the application.

(1) Option 1. This option is for a REP whose service offerings will be defined by geographic service area.

(A) An applicant must designate one of the following categories as its geographic service area:

(i) The geographic area of the entire state of Texas;

(ii) A specific geographic area (indicating the zip codes applicable to that area);

(iii) The service area of specific TDUs or specific municipal utilities or electric cooperatives in which competition is offered; or

(iv) The geographic area of ERCOT or other independent organization to the extent it is within Texas.

(B) A REP with a geographic service area is subject to all subsections of this section, including those pertaining to basic, financial, technical and managerial, customer protection, and reporting and changing certification requirements.

(C) The commission shall grant a certificate to an applicant proposing to provide retail electric service to a geographic service area in Texas if it demonstrates that it meets the requirements of this section.

(D) The commission shall deny an application if the configuration of the proposed geographic area would discriminate in the provision of electric service to any customer because of race, creed, color, national origin, ancestry, sex, marital status, lawful source of income, disability, or familial status; because the customer is located in an economically distressed geographic area or qualifies for low income affordability or energy efficiency services; or because of any other reason prohibited by law.

(2) Option 2. This option is for a REP whose service offerings will be limited to specifically identified customers, each of whom contracts for one megawatt or more of capacity. The applicant shall be certified as a REP only for purposes of serving the specified customers. The commission shall grant a certificate under this paragraph if the applicant demonstrates that it meets the requirements of this paragraph.

(A) A person seeking certification under this paragraph must file with the commission a signed, notarized affidavit from each customer, with whom it has contracted to provide one megawatt or more of capacity. The affidavit must state that the customer is satisfied that the REP meets the standards prescribed by PURA §39.352 (b)(1)-(3) and (c).

(B) The following subsections apply to REPs certified pursuant to this paragraph:

(i) Subsection (e) of this section (relating to Basic Requirements);

(ii) Subsection (f)(5) of this section (relating to Billing and Collection of Transition Charges); and

(iii) Subsection (i) of this section (relating to Requirements for Reporting and Changing Certification).

(3) Option 3. This option is for a REP that sells electricity exclusively to a retail customer other than a small commercial and residential customer from a distributed generation facility located on a site controlled by that customer. The following subsections do not apply to REPs certified pursuant to this paragraph: subsections (f), (g), (h), and (i)(4)-(5) of this section, except that a person seeking certification under this paragraph shall file an application with the commission that identifies a power generation company that owns the distributed generation facilities and provides the information required in subsection (g)(2)(A) of this section. A person seeking certification under this paragraph shall ensure that the distributed generation facility from which it buys electricity is owned by a power generating company (PGC) that has registered in accordance with §25.109 of this title (relating to Registration of Power Generation Companies and Self Generators), and

(A) Conforms to the requirements of §25.211 of this title (relating to Interconnection of On-Site Distributed Generation (DG)) and §25.212 of this title (relating to Technical Requirements for Interconnection and Parallel Operation of On-Site Distributed Generation);

(B) Is installed by a Licensed Electrician, consistent with the requirements of the Texas Department of Licensing and Regulation; and

(C) Is installed in accordance with the National Electric Code as adopted by the Texas Department of Licensing and Regulation and in compliance with all applicable local and regional building codes.

(e) Basic requirements.

(1) Names on certificates. All retail electric service shall be provided under names set forth in the granted certificate. If the applicant is a corporation, the commission shall issue the certificate in the corporate name of the applicant.

(A) No more than five assumed names may be authorized for use by any one REP at one time.

(B) Business names shall not be deceptive, misleading, vague, otherwise contrary to §25.272 of this title (relating to Code of Conduct for Electric Utilities and Their Affiliates), or duplicative of a name previously approved for use by a REP certificate holder.

(C) If the commission determines that any requested name does not meet the requirements of subparagraph (B) of this paragraph, it shall notify the applicant that the requested name shall not be used by the REP. An application shall be dismissed if an applicant does not provide at least one suitable name.

(2) Office requirements. A REP shall continuously maintain an office located within Texas for the purpose of providing customer service, accepting service of process and making available in that office books and records sufficient to establish the REP's compliance with PURA and the commission's rules. The office satisfying this requirement for a REP shall have a physical address that is not a post office box and shall be a location where the above three functions can occur. To evaluate compliance with requirements in this paragraph, the commission staff may visit the office of a REP at any time during normal business hours. An applicant shall demonstrate that it has made arrangements for an office located in Texas.

(f) Financial requirements.

(1) Access to capital. A REP must meet the requirements of subparagraphs (A) or (B) of this paragraph.

(A) A REP or its guarantor electing to meet the requirements of this subparagraph must demonstrate and maintain:

(i) an investment-grade credit rating; or

(ii) tangible net worth greater than or equal to $100 million, a minimum current ratio (current assets divided by current liabilities) of 1.0, and a debt to total capitalization ratio not greater than 0.60, where all calculations exclude unrealized gains and losses resulting from valuing to market the power contracts and financial instruments used as supply hedges to serve load, and such calculations are supported by an affidavit from an executive officer of the REP attesting to the accuracy of the calculation.

(B) A REP electing to meet the requirements of this subparagraph must demonstrate shareholders' equity, determined in accordance with generally accepted accounting principles, of not less than one million dollars for the purpose of obtaining certification, and the REP or its guarantor must provide and maintain an irrevocable stand-by letter of credit payable to the commission with a face value of $500,000 for the purpose of maintaining certification.

(i) The required shareholders' equity of one million dollars shall be determined net of assets used for collateral pledged to secure the irrevocable stand-by letter of credit of $500,000.

(ii) For the period beginning on the date of certification and ending two years after the REP begins serving load, a REP shall not make any distribution or other payment to any shareholders or affiliates if, after giving effect to the distribution or other payment, the REP's shareholders' equity is less than one million dollars, net of assets used for collateral pledged to secure the irrevocable stand-by letter of credit of $500,000. The restriction on distributions or other payments contained in this subparagraph includes, but is not limited to, dividend distributions, redemptions and repurchases of equity securities, or loans to shareholders or affiliates.

(iii) A REP that began serving load on or before January 1, 2009 is not required to demonstrate the shareholders' equity required pursuant to subparagraph (B) of this paragraph, and is not subject to the restrictions on distributions or payments to shareholders or affiliates contained in subparagraph (B) of this paragraph.

(2) Protection of customer deposits and advance payments.

(A) A REP certified pursuant to paragraph (1)(A) of this subsection shall keep customer deposits and residential advance payments in an escrow account or segregated cash account, or provide an irrevocable stand-by letter of credit payable to the commission in an amount sufficient to cover 100% of the REPs outstanding customer deposits and residential advance payments held at the close of each month.

(B) A REP certified pursuant to paragraph (1)(B) of this subsection shall keep customer deposits and residential advance payments in an escrow account or segregated cash account, or provide an irrevocable stand-by letter of credit payable to the commission in an amount sufficient to cover 100% of the REP's outstanding customer deposits and residential advance payments held at the close of each month. For purposes of this subparagraph only, to qualify as a segregated cash account, the account must be with a financial institution whose deposits, including the deposits in the segregated cash account, are insured by the Federal Deposit Insurance Corporation, the account is designated as containing only customer deposits, the account is subject to the control or management of a provider of pervasive and comprehensive credit to the REP that is not affiliated with the REP, and the terms for managing the account protect customer deposits.

(C) In lieu of the requirements of subparagraph (B) of this paragraph, a REP certified pursuant to paragraph (1)(B) of this subsection that is providing electric service under the provisions of §25.498 of this title (relating to Retail Electric Service Using a Customer Prepayment Device or System) shall be required to keep all deposits and an amount sufficient to cover the credit balance that exceeds $50 for all customer accounts that have a credit balance exceeding $50 at the close of each month in an escrow account, or to provide an irrevocable stand-by letter of credit payable to the commission in an amount equal to or greater than the amount required to be deposited in the escrow account.

(D) Each escrow account and segregated cash account shall be reconciled no less frequently than at the close of each month to ensure that it equals or exceeds deposits and residential advance payments held as of the end of the month, and shall maintain at least that amount in the account until the next monthly reconciliation.

(E) Any irrevocable stand-by letter of credit provided pursuant to this paragraph shall be in addition to the irrevocable stand-by letter of credit required by paragraph (1)(B) of this subsection, if applicable.

(3) Protection of TDU financial integrity.

(A) A TDU shall not require a deposit from a REP except to secure the payment of transition charges as provided in §25.108 of this title (relating to Financial Standards for Retail Electric Providers Regarding Billing and Collection of Transition Charges), or if the REP has defaulted on one or more payments to the TDU. A TDU may impose credit conditions on a REP that has defaulted to the extent specified in its statewide standardized tariff for retail delivery service and as allowed by commission rules.

(B) A TDU shall create a regulatory asset for bad debt expenses, net of collateral posted pursuant to subparagraph (A) of this paragraph and bad debt already included in its rates, resulting from a REP's default on its obligation to pay delivery charges to the TDU. Upon a review of reasonableness and necessity, a reasonable level of amortization of such regulatory asset shall be included as a recoverable cost in the TDU's rates in its next rate case or such other rate recovery proceeding as deemed necessary.

(4) Financial documentation required to obtain a REP certificate. The following shall be required to demonstrate compliance with the financial requirements to obtain a REP certificate.

(A) Investment-grade credit ratings shall be documented by reports of a credit reporting agency.

(B) Tangible net worth shall be documented by the audited financial statements of the REP or its guarantor for the most recently completed calendar or fiscal year, and unaudited financial statements for the most recently completed quarter. Audited financial statements shall include the accompanying notes and the independent auditor's report. Unaudited financial statements shall include a sworn statement from an executive officer of the REP attesting to the accuracy, in all material respects, of the information provided in the unaudited financial statements. Three consecutive months of monthly statements may be submitted in lieu of quarterly statements if quarterly statements are not available. The requirement for financial statements may be satisfied by filing a copy of or by providing an electronic link to its most recent statement that contains unaudited financials filed with any agency of the federal government, including without limitation, the Securities and Exchange Commission.

(C) Shareholders' equity shall be documented by the audited and unaudited financial statements of the REP for the most recent quarter. Audited financial statements shall include the accompanying notes and the independent auditor's report. Unaudited financial statements shall include a sworn statement from an executive officer of the REP attesting to the accuracy, in all material respects, of the information provided in the unaudited financial statements. Three consecutive months of monthly statements may be submitted in lieu of quarterly statements if quarterly statements are not available. The requirement for financial statements may be satisfied by filing a copy of or by providing an electronic link to its most recent statement that contains unaudited financials filed with any agency of the federal government, including without limitation, the Securities and Exchange Commission.

(D) Segregated cash accounts shall be documented by an account statement that clearly identifies the financial institution where the account holder maintains the account, and that clearly identifies the account as an account that is designated as containing only customer deposits and residential advanced payments. Segregated cash accounts shall be maintained at a financial institution that is supervised or examined by the Board of Governors of the Federal Reserve System, the Office of the Controller of the Currency, or a state banking department, and where accounts are insured by the Federal Deposit Insurance Corporation.

(E) Escrow accounts shall be documented by the current account statement and the escrow account agreement. The escrow account agreement shall provide that the account holds customer deposits and residential advance payments only, and that the deposits are held in trust by the escrow agent and are not the property of the REP or in the REP's control unless the customer deposits are applied to a final bill or applied to satisfy unpaid amounts if allowed by the REP's terms of service. The escrow agent shall deposit the customer deposits and residential advance payments in an account at a financial institution that is supervised or examined by the Board of Governors of the Federal Reserve System, the Office of the Controller of the Currency, or a state banking department, and where accounts are insured by the Federal Deposit Insurance Corporation.

(F) Irrevocable stand-by letters of credit provided pursuant to paragraphs (1) or (2) of this subsection must be issued by a financial institution that is supervised or examined by the Board of Governors of the Federal Reserve System, the Office of the Controller of the Currency, or a state banking department, and where accounts are insured by the Federal Deposit Insurance Corporation. The REP must use the standard form irrevocable stand-by letter of credit approved by the commission. The irrevocable stand-by letter of credit must be irrevocable for a period not less than twelve months, payable to the commission, and permit a draw to be made in part or in full. The irrevocable stand-by letter of credit must permit the commission's executive director or the designee to draw on the irrevocable stand-by letter of credit if:

(i) ERCOT performs a mass transition of the REP's customers; or

(ii) the commission issues an order revoking the REP's certificate.

(G) A REP may satisfy the requirements of paragraph (1)(A) of this subsection by relying upon a guarantor that meets one of the capital requirements of paragraph (1)(A) of this subsection, provided that:

(i) The guarantor is an affiliate of the REP and has executed and maintains the standard form guaranty agreement approved by the commission, or

(ii) The guarantor is one or more persons that are affiliates of the REP and such affiliates have executed and maintain guaranty agreements, business financial commitments, or credit support agreements that demonstrate financial support for credit or collateral requirements associated with power purchase agreements and for security associated with participation at ERCOT, or

(iii) The guarantor is a financial institution that maintains an investment-grade credit rating and has executed and maintains guaranty agreements, business financial commitments, or credit support agreements that demonstrate financial support for credit or collateral requirements associated with power purchase agreements and for security associated with participation at ERCOT, or

(iv) The guarantor is a provider of wholesale power supply to the REP, or one of such power provider's affiliates, and such person has executed and maintains guaranty agreements, business financial commitments, or credit support agreements that demonstrate financial support for credit or collateral requirements associated with a power purchase agreement and for security associated with participation at ERCOT.

(5) Billing and collection of transition charges. If a REP serves customers in the service area of a TDU that is subject to a financing order pursuant to PURA §39.310, the REP shall comply with §25.108 of this title.

(6) Proceeds from an irrevocable stand-by letter of credit.

(A) Proceeds from an irrevocable stand-by letter of credit provided under this subsection may be used to satisfy the following obligations of the REP, in the following order of priority:

(i) first, if available, to assist in the payment of the deposits to retail electric providers that volunteer to provide service in a mass transition event under §25.43 of this title (relating to Provider of Last Resort (POLR)) of low-income customers as identified by the Low-Income List Administrator pursuant to §25.45 of this title;

(ii) second, if available, to assist in the payment of deposits to retail electric providers that are designated to provide service in a mass transition event under §25.43 of this title of low-income customers as identified by the Low-Income List Administrator pursuant to §25.45 of this title;

(iii) third, for customer deposits and residential advance payments of customers;

(iv) fourth, for services provided by the independent organization related to serving customer load;

(v) fifth, for services provided by a TDU; and

(vi) sixth, for administrative penalties assessed under Chapter 15 of PURA.

(B) Proceeds from an irrevocable stand-by letter of credit provided under this subsection shall, to the extent that the proceeds are not needed to satisfy an obligation set out in subparagraph (A) of this paragraph, be paid to the REP.

(g) Technical and managerial requirements. A REP must have the technical and managerial resources and ability to provide continuous and reliable retail electric service to customers, in accordance with its customer contracts, PURA, commission rules, ERCOT protocols, and other applicable laws.

(1) Technical and managerial resource requirements include:

(A) Capability to comply with all applicable scheduling, operating, planning, reliability, customer registration, and settlement policies, protocols, guidelines, procedures, and other rules established by ERCOT or other applicable independent organization including any independent organization requirements for 24-hour coordination with control centers for scheduling changes, reserve implementation, curtailment orders, interruption plan implementation, and telephone number, fax number, e-mail address, and postal address where the REP's staff can be directly reached at all times.

(B) Capability to comply with the registration and certification requirements of ERCOT or other applicable independent organization and its system rules, or contracts for services with entities registered with or certified by ERCOT or other applicable independent organization.

(C) Compliance with all renewable energy portfolio standards in accordance with §25.173 of this title (relating to Goal for Renewable Energy).

(D) Principals or permanent employees in managerial positions whose combined experience in the competitive electric industry or competitive gas industry equals or exceeds 15 years. An individual that was a principal of a REP that experienced a mass transition of the REP's customers to POLR shall not be considered for purposes of satisfying this requirement, and shall not own more than 10% of a REP or directly or indirectly control a REP.

(E) At least one principal or permanent employee who has five years of experience in energy commodity risk management of a substantial energy portfolio. Alternatively, the REP may provide documentation demonstrating that the REP has entered into a contract for a term not less than two years with a provider of commodity risk management services that has been providing such services for a substantial energy portfolio for at least five years. A substantial energy portfolio means managing electricity or gas market risks with a minimum value of at least $10,000,000.

(F) Adequate staffing and employee training to meet all service level commitments.

(G) The capability and effective procedures to be the primary point of contact for retail electric customers for distribution system service in accordance with applicable commission rules, including procedures for relaying outage reports to the TDU on a 24-hour basis.

(H) A customer service plan that describes how the REP complies with the commission's customer protection and anti-discrimination rules.

(2) An applicant shall include the following in its initial application for REP certification:

(A) Prior experience of one or more of the applicant's principals or permanent employees in the competitive retail electric industry or competitive gas industry;

(B) Any complaint history, disciplinary record and compliance record during the ten years immediately preceding the filing of the application regarding: the applicant; the applicant's affiliates that provide utility-like services such as telecommunications, electric, gas, water, or cable service; the applicant's principals; and any person that merged with any of the preceding persons;

(i) The complaint history, disciplinary record, and compliance record shall include information from any federal agency including the U.S. Securities and Exchange Commission and the U.S. Commodity Futures Trading Commission; any self-regulatory organization relating to the sales of securities, financial instruments, physical or financial transactions in commodities, or other financial transactions; state public utility commissions, state attorney general offices, or other regulatory agencies in states where the applicant is doing business or has conducted business in the past including state securities boards or commissions, the Texas Secretary of State, Texas Comptroller's Office, and Office of the Texas Attorney General. Relevant information shall include the type of complaint, status of complaint, resolution of complaint, and the number of customers in each state where complaints occurred.

(ii) The applicant may request to limit the inclusion of this information if it would be unduly burdensome to provide, so long as the information provided is adequate for the commission to assess the applicant's and the applicant's principals' and affiliates' complaint history, disciplinary record, and compliance record.

(iii) The commission may also consider any complaint information on file at the commission.

(C) A summary of any history of insolvency, bankruptcy, dissolution, merger, or acquisition of the applicant or any predecessors in interest during the 60 months immediately preceding the application;

(D) A statement indicating whether the applicant or the applicant's principals are currently under investigation or have been penalized by an attorney general or any state or federal regulatory agency for violation of any deceptive trade or consumer protection laws or regulations;

(E) Disclosure of whether the applicant or applicant's principals have been convicted or found liable for fraud, theft, larceny, deceit, or violations of any securities laws, customer protection laws, or deceptive trade laws in any state;

(F) An affidavit stating that the applicant will register with or be certified by ERCOT or other applicable independent organization and will comply with the technical and managerial requirements of this subsection; or that entities with whom the applicant has a contractual relationship are registered with or certified by the independent organization and will comply with all system rules established by the independent organization;

(G) An affidavit identifying all principals, executive management, and employees, or contract employees of the applicant that exercised influence or control over a REP that experienced a mass transition of the REP's customers to POLR. If such a relationship existed, the applicant shall include in the affidavit the name of the REP that experienced a mass transition of the REP's customers to POLR and provide factual statements as to whether and, if so, how the REP that experienced a mass transition of the REP's customers to POLR settled all outstanding obligations including the return of any owed customer deposits; and

(H) Other evidence, at the discretion of the applicant, supporting the applicant's plans for meeting requirements of this subsection.

(h) Customer protection requirements. A REP shall comply with all applicable customer protection requirements, including disclosure requirements, marketing guidelines and anti-discrimination requirements, and the requirements of this section.

(i) Requirements for reporting and changing certification. To maintain a REP certificate, a REP must keep its certification information up to date, pursuant to the following requirements:

(1) A REP shall notify the commission within five working days of any change in its business address, telephone numbers, authorized contacts, or other contact information.

(2) A REP that demonstrates compliance with certification requirements of this section by submitting an affidavit shall supply information to the commission to show actual compliance with this section.

(3) A REP shall apply to amend its certification within ten working days of a material change to the information provided as the basis for the commission's approval of the certification application. A REP may seek prior approval of a material change, including a change in control, by filing the amendment application before the occurrence of the material change. The transfer of a REP certificate is a material change.

(4) For an Option 1 REP, the REP shall notify the commission within three working days of its non-compliance with subsection (f)(1)(A) or (B) of this section. The notification shall set out a plan of recourse to correct the non-compliance with subsection (f)(1)(A) or (B) of this section within 10 working days after the non-compliance has been brought to the attention of the commission. The commission staff may initiate a proceeding to address the non-compliance.

(5) For an Option 1 REP, the REP shall file a report due on March 5, or 65 days after the end of the REP or guarantor's fiscal year (annual report), and August 15, or 225 days after the end of the REP or guarantor's fiscal year (semi-annual report), of each year.

(A) The annual report shall include:

(i) Any changes in addresses, telephone numbers, authorized contacts, and other information necessary for contacting the certificate holder.

(ii) Identification of areas where the REP is providing retail electric service to customers in Texas compiled by zip code.

(iii) A list of aggregators with whom the REP has conducted business in the reporting period, and the commission registration number for each aggregator.

(iv) A sworn affidavit that the certificate holder is not in material violation of any of the requirements of its certificate.

(v) Any changes in ownership.

(vi) Any changes in management, experience, and personnel relied on for certification in each semi-annual report before the REP begins serving customers and in the first semi-annual report after the REP serves customers.

(vii) Documentation to demonstrate ongoing compliance with the financial requirements of subsection (f) of this section, including, but not limited to, calculations showing tangible net worth, financial ratios or shareholders' equity, as applicable, and the amount of customer deposits and the balance of an account in which customer deposits are held, supported by a sworn statement from an executive officer of the REP attesting to the accuracy, in all material respects, of the information provided. Any certified calculations provided as part of the annual report to demonstrate such compliance shall be as of the end of the most recent fiscal quarter. A REP may submit any relevant documentation of the type required by subsection (f)(4) of this section to demonstrate its ongoing compliance with the financial requirements of subsection (f) of this section.

(B) The semi-annual report shall include:

(i) Documentation to demonstrate ongoing compliance with the financial requirements of subsection (f) of this section, including, but not limited to, calculations showing tangible net worth, financial ratios or shareholders' equity, as applicable, and the amount of customer deposits and the balance of an account in which customer deposits are held, and shall be supported by a sworn statement from an executive officer of the REP attesting to the accuracy of the information provided. Any certified calculations provided as part of the semi-annual report to demonstrate such compliance shall be as of the end of the most recent fiscal year and most recent fiscal quarter. A REP may submit any relevant documentation of the type required by subsection (f)(4) of this section to demonstrate its ongoing compliance with the financial requirements of subsection (f) of this section.

(ii) The audited financial statements of the REP or its guarantor for the most recent completed calendar or fiscal year with accompanying footnotes and the independent auditor's report, if not previously filed.

(iii) The unaudited financial statements for the most recent six-month financial period that immediately follows the end of its most recent fiscal year. Unaudited financial statements shall include a sworn statement from an executive officer of the REP attesting to the accuracy, in all material respects, of the information provided in the unaudited financial statements. In lieu of six-month unaudited financial statements, six consecutive months of monthly financial statements may be submitted.

(C) The requirement for financial statements may be satisfied by filing a copy of or by providing an electronic link to its most recent statement that contains unaudited financials filed with any agency of the federal government, including without limitation, the Securities and Exchange Commission. A REP that is part of a structure that is consolidated for financial reporting purposes and files financial reports with a federal agency on a consolidated company basis may provide financial statements for the consolidated company to meet this requirement.

(D) REPs or guarantors with an investment-grade credit rating are not required to provide financial statements pursuant to this section.

(6) A REP shall not cease operations as a REP without prior notice of at least 45 days to the commission, to each of the REP's customers to whom the REP is providing service on the planned date of cessation of operations, and to other affected persons, including the applicable independent organization, TDUs, electric cooperatives, municipally owned utilities, generation suppliers, and providers of last resort. The REP shall file with the commission proof of refund of any monies owed to customers. Upon the effective cessation date, a REP's certificate will be suspended. A REP must demonstrate full compliance with the requirements of this section, including but not limited to, the requirement to demonstrate shareholders' equity of not less than one million dollars and its associated restrictions pursuant to subsection (f)(1)(B) of this section, in order for the commission to reinstate the certificate. The commission may revoke a suspended certificate if it determines that the REP does not meet certification requirements.

(7) If a REP files a petition in bankruptcy, is the subject of an involuntary bankruptcy proceeding, or in any other manner becomes insolvent, it shall notify the commission within three working days of this event and shall provide the commission a summary of the nature of the matter. The commission shall have the right to proceed against any financial resources that the REP relied on in obtaining its certificate, to satisfy unpaid obligations to customers or administrative penalties.

(8) A REP shall respond within three working days to any commission staff request for additional information to confirm continued compliance with this section.

(j) Suspension and revocation. A certificate granted pursuant to this section is subject to amendment, suspension, or revocation by the commission for a significant violation of PURA, commission rules, or rules adopted by an independent organization. A suspension of a REP certificate requires the cessation of all REP activities associated with obtaining new customers in the state of Texas. A revocation of a REP certificate requires the cessation of all REP activities in the state of Texas, pursuant to commission order. The commission may also impose an administrative penalty on a person for a significant violation of PURA, commission rules, or rules adopted by an independent organization. The commission staff or any affected person may bring a complaint seeking to amend, suspend, or revoke a REP's certificate. Significant violations include the following:

(1) Providing false or misleading information to the commission, including a failure to disclose any information required by this section;

(2) Engaging in fraudulent, unfair, misleading, deceptive, or anticompetitive practices, or unlawful discrimination;

(3) Switching, or causing to be switched, the retail electric provider for a customer without first obtaining the customer's permission;

(4) Billing an unauthorized charge, or causing an unauthorized charge to be billed, to a customer's retail electric service bill;

(5) Failure to maintain continuous and reliable electric service to customers pursuant to this section;

(6) Failure to maintain financial resources in accordance with subsection (f) of this section;

(7) Bankruptcy, insolvency, or the inability to meet financial obligations on a reasonable and timely basis;

(8) Failure to timely remit payment for invoiced charges to an independent organization;

(9) Failure to observe any applicable scheduling, operating, planning, reliability, and settlement policies, protocols, guidelines, procedures, and other rules established by the independent organization;

(10) A pattern of not responding to commission inquiries or customer complaints in a timely fashion;

(11) Suspension or revocation of a registration, certification, or license by any state or federal authority;

(12) Conviction of a felony by the certificate holder, a person controlling the certificate holder, or principal employed by the certificate holder, or any crime involving fraud, theft, or deceit related to the certificate holder's service;

(13) Not providing retail electric service to customers within 24 months of the certificate being granted by the commission;

(14) Failure to serve as a POLR if required to do so by the commission;

(15) Providing retail electric service in an area in which customer choice is in effect without obtaining a certificate under this section;

(16) Failure to timely remit payment for invoiced charges to a transmission and distribution utility pursuant to the terms of the statewide standardized tariff adopted by the commission;

(17) Erroneously imposing switch-holds or failing to remove switch-holds within the timeline described in §25.480 of this title (relating to Bill Payment and Adjustments);

(18) Failure to comply with §25.272 of this title; and

(19) Other significant violations, including the failure or a pattern of failures to meet the requirements of this section or other commission rules or orders.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on April 23, 2018.

TRD-201801810

Adriana Gonzales

Rules Coordinator

Public Utility Commission of Texas

Effective date: May 13, 2018

Proposal publication date: December 29, 2017

For further information, please call: (512) 936-7223


SUBCHAPTER H. ELECTRICAL PLANNING

DIVISION 2. ENERGY EFFICIENCY AND CUSTOMER-OWNED RESOURCES

16 TAC §25.181

The amendment is adopted under §14.002 of the Public Utility Regulatory Act, Tex. Util. Code Ann. §14.002 (West 2016 and Supp. 2017) (PURA) which provides the commission with the authority to make and enforce rules reasonably required in the exercise of its powers and jurisdiction, including rules of practice and procedure; PURA §17.007, which provides for a process by which a REP can identify low-income customers; PURA §39.101, which provides the commission with the authority to ensure that retail customer protections are established to entitle a customer to safe, reliable, and reasonably priced electricity.

Cross reference to statutes: Public Utility Regulatory Act §14.002, §14.052, §17.007, §39.101.

§25.181.Energy Efficiency Goal.

(a) Purpose. The purpose of this section is to ensure that:

(1) electric utilities administer energy efficiency incentive programs in a market-neutral, nondiscriminatory manner and do not offer competitive services, except as permitted in §25.343 of this title (relating to Competitive Energy Services) or this section;

(2) all customers, in all eligible customer classes and all areas of an electric utility's service area, have a choice of and access to the utility's portfolio of energy efficiency programs that allow each customer to reduce energy consumption, summer and winter peak demand, or energy costs; and

(3) each electric utility annually provides, through market-based standard offer programs, targeted market-transformation programs, or utility self-delivered programs, incentives sufficient for residential and commercial customers, retail electric providers, and energy efficiency service providers to acquire additional cost-effective energy efficiency, subject to EECRF caps established in subsection (f)(7) of this section, for the utility to achieve the goals in subsection (e) of this section.

(b) Application. This section applies to electric utilities.

(c) Definitions. The following terms, when used in this section, shall have the following meanings unless the context indicates otherwise:

(1) Affiliate--

(A) A person who directly or indirectly owns or holds at least 5.0% of the voting securities of an energy efficiency service provider;

(B) A person in a chain of successive ownership of at least 5.0% of the voting securities of an energy efficiency service provider;

(C) A corporation that has at least 5.0% of its voting securities owned or controlled, directly or indirectly, by an energy efficiency service provider;

(D) A corporation that has at least 5.0% of its voting securities owned or controlled, directly or indirectly, by:

(i) a person who directly or indirectly owns or controls at least 5.0% of the voting securities of an energy efficiency service provider; or

(ii) a person in a chain of successive ownership of at least 5.0% of the voting securities of an energy efficiency service provider; or

(E) A person who is an officer or director of an energy efficiency service provider or of a corporation in a chain of successive ownership of at least 5.0% of the voting securities of an energy efficiency service provider;

(F) A person who actually exercises substantial influence or control over the policies and actions of an energy efficiency service provider;

(G) A person over which the energy efficiency service provider exercises the control described in subparagraph (F) of this paragraph;

(H) A person who exercises common control over an energy efficiency service provider, where "exercising common control over an energy efficiency service provider" means having the power, either directly or indirectly, to direct or cause the direction of the management or policies of an energy efficiency service provider, without regard to whether that power is established through ownership or voting of securities or any other direct or indirect means; or

(I) A person who, together with one or more persons with whom the person is related by ownership, marriage or blood relationship, or by action in concert, actually exercises substantial influence over the policies and actions of an energy efficiency service provider even though neither person may qualify as an affiliate individually.

(2) Baseline--A relevant condition that would have existed in the absence of the energy efficiency project or program being implemented, including energy consumption that would have occurred. Baselines are used to calculate program-related demand and energy savings. Baselines can be defined as either project-specific baselines or performance standard baselines (e.g., building codes).

(3) Claimed savings--Values reported by an electric utility after the energy efficiency activities have been completed, but prior to the time an independent, third-party evaluation of the savings is performed. As with projected savings estimates, these values may utilize results of prior evaluations and/or values in technical reference manuals. However, they are adjusted from projected savings estimates by correcting for any known data errors and actual installation rates and may also be adjusted with revised values for factors such as per-unit savings values, operating hours, and savings persistence rates. Can be indicated as first year, annual demand or energy savings, and/or lifetime energy or demand savings values. Can be indicated as gross savings and/or net savings values.

(4) Commercial customer--A non-residential customer taking service at a metered point of delivery at a distribution voltage under an electric utility's tariff during the prior program year or a non-profit customer or government entity, including an educational institution. For purposes of this section, each metered point of delivery shall be considered a separate customer.

(5) Competitive energy efficiency services--Energy efficiency services that are defined as competitive under §25.341 of this title (relating to Definitions).

(6) Conservation load factor--The ratio of the annual energy savings goal, in kilowatt hours (kWh), to the peak demand goal for the year, measured in kilowatts (kW) and multiplied by the number of hours in the year.

(7) Deemed savings calculation--An industry-wide engineering algorithm used to calculate energy and/or demand savings of the installed energy efficiency measure that has been developed from common practice that is widely considered acceptable for the measure and purpose, and is applicable to the situation being evaluated. May include stipulated assumptions for one or more parameters in the algorithm, but typically requires some data associated with actual installed measure. An electric utility may use the calculation with documented measure-specific assumptions, instead of energy and peak demand savings determined through measurement and verification activities or the use of deemed savings.

(8) Deemed savings value--An estimate of energy or demand savings for a single unit of an installed energy efficiency measure that has been developed from data sources and analytical methods that are widely considered acceptable for the measure and purpose, and is applicable to the situation being evaluated. An electric utility may use deemed savings values instead of energy and peak demand savings determined through measurement and verification activities.

(9) Demand--The rate at which electric energy is used at a given instant, or averaged over a designated period, usually expressed in kW or megawatts (MW).

(10) Demand savings--A quantifiable reduction in demand.

(11) Eligible customers--Residential and commercial customers. In addition, to the extent that they meet the criteria for participation in load management standard offer programs developed for industrial customers and implemented prior to May 1, 2007, industrial customers are eligible customers solely for the purpose of participating in such programs.

(12) Energy efficiency--Improvements in the use of electricity that are achieved through customer facility or customer equipment improvements, devices, processes, or behavioral or operational changes that produce reductions in demand or energy consumption with the same or higher level of end-use service and that do not materially degrade existing levels of comfort, convenience, and productivity.

(13) Energy Efficiency Cost Recovery Factor (EECRF)--An electric tariff provision, compliant with subsection (f) of this section, ensuring timely and reasonable cost recovery for utility expenditures made to satisfy the goal of PURA §39.905 that provide for a cost-effective portfolio of energy efficiency programs pursuant to this section.

(14) Energy efficiency measures--Equipment, materials, and practices, including practices that result in behavioral or operational changes, implemented at a customer's site on the customer's side of the meter that result in a reduction at the customer level and/or on the utility's system in electric energy consumption, measured in kWh, or peak demand, measured in kW, or both. These measures may include thermal energy storage and removal of an inefficient appliance so long as the customer need satisfied by the appliance is still met.

(15) Energy efficiency program--The aggregate of the energy efficiency activities carried out by an electric utility under this section or a set of energy efficiency projects carried out by an electric utility under the same name and operating rules.

(16) Energy efficiency project--An energy efficiency measure or combination of measures undertaken in accordance with a standard offer, market transformation program, or self-delivered program.

(17) Energy efficiency service provider--A person or other entity that installs energy efficiency measures or performs other energy efficiency services under this section. An energy efficiency service provider may be a retail electric provider or commercial customer, provided that the commercial customer has a peak load equal to or greater than 50 kW. An energy efficiency service provider may also be a governmental entity or a non-profit organization, but may not be an electric utility.

(18) Energy savings--A quantifiable reduction in a customer's consumption of energy that is attributable to energy efficiency measures, usually expressed in kWh or MWh.

(19) Estimated useful life (EUL)--The number of years until 50% of installed measures are still operable and providing savings, and is used interchangeably with the term "measure life". The EUL determines the period of time over which the benefits of the energy efficiency measure are expected to accrue.

(20) Evaluated savings--Savings estimates reported by the EM&V contractor after the energy efficiency activities and an impact evaluation have been completed. Differs from claimed savings in that the EM&V contractor has conducted some of the evaluation and/or verification activities. These values may rely on claimed savings for factors such as installation rates and the Technical Reference Manual for values such as per unit savings values and operating hours. These savings estimates may also include adjustments to claimed savings for data errors, per unit savings values, operating hours, installation rates, savings persistence rates, or other considerations. Can be indicated as first year, annual demand or energy savings, and/or lifetime energy or demand savings values. Can be indicated as gross savings and/or net savings values.

(21) Evaluation--The conduct of any of a wide range of assessment studies and other activities aimed at determining the effects of a program; or aimed at understanding or documenting program performance, program or program-related markets and market operations, program-induced changes in energy efficiency markets, levels of demand or energy savings, or program cost-effectiveness. Market assessment, monitoring, and evaluation, and measurement and verification (M&V) are aspects of evaluation.

(22) Evaluation, measurement, and verification (EM&V) contractor--One or more independent, third-party contractors selected and retained by the commission to plan, conduct, and report on energy efficiency evaluation activities, including verification.

(23) Free driver--Customers who do not directly participate in an energy efficiency program, but who undertake energy efficiency actions in response to program activity.

(24) Free rider--A program participant who would have implemented the program measure or practice in the absence of the program. Free riders can be total, in which the participant's activity would have completely replicated the program measure; partial, in which the participant's activity would have partially replicated the program measure; or deferred, in which the participant's activity would have completely replicated the program measure, but at a time after the time the program measure was implemented.

(25) Growth in demand--The annual increase in demand in the Texas portion of an electric utility's service area at time of peak demand, as measured in accordance with this section.

(26) Gross savings--The change in energy consumption and/or demand that results directly from program-related actions taken by participants in an efficiency program, regardless of why they participated.

(27) Hard-to-reach customers--Residential customers with an annual household income at or below 200% of the federal poverty guidelines.

(28) Impact evaluation--An evaluation of the program-specific, directly induced changes (e.g., energy and/or demand reduction) attributable to an energy efficiency program.

(29) Incentive payment--Payment made by a utility to an energy efficiency service provider, an end-use customer, or third-party contractor to implement and/or attract customers to energy efficiency programs, including standard offer, market transformation and self-delivered programs.

(30) Industrial customer--A for-profit entity engaged in an industrial process taking electric service at transmission voltage, or a for-profit entity engaged in an industrial process taking electric service at distribution voltage that qualifies for a tax exemption under Tax Code §151.317 and has submitted an identification notice pursuant to subsection (w) of this section.

(31) Inspection--Examination of a project to verify that an energy efficiency measure has been installed, is capable of performing its intended function, and is producing an energy savings or demand reduction equivalent to the energy savings or demand reduction reported towards meeting the energy efficiency goals of this section.

(32) Installation rate--The percentage of measures that receive incentives under an energy efficiency program that are actually installed in a defined period of time. The installation rate is calculated by dividing the number of measures installed by the number of measures that receive incentives under an efficiency program in a defined period of time.

(33) International performance measurement and verification protocol (IPMVP)--A guidance document issued by the Efficiency Valuation Organization with a framework and definitions describing the M&V approaches.

(34) Lifetime energy (demand) savings--The energy (demand) savings over the lifetime of an installed measure(s), project(s), or program(s). May include consideration of measure estimated useful life, technical degradation, and other factors. Can be gross or net savings.

(35) Load control--Activities that place the operation of electricity-consuming equipment under the control or dispatch of an energy efficiency service provider, an independent system operator, or other transmission organization or that are controlled by the customer, with the objective of producing energy or demand savings.

(36) Load management--Load control activities that result in a reduction in peak demand, or a shifting of energy usage from a peak to an off-peak period or from high-price periods to lower price periods.

(37) Market transformation program--Strategic programs intended to induce lasting structural or behavioral changes in the market that result in increased adoption of energy efficient technologies, services, and practices, as described in this section.

(38) Measurement and verification--A subset of program impact evaluation that is associated with the documentation of energy or demand savings at individual sites or projects using one or more methods that can involve measurements, engineering calculations, statistical analyses, and/or computer simulation modeling. M&V approaches are defined in the IPMVP.

(39) Net savings--The total change in load that is attributable to an energy efficiency program. This change in energy and/or demand use shall include, implicitly or explicitly, consideration of appropriate factors. These factors may include free ridership, participant and non-participant spillover, induced market effects, changes in the level of energy service, and/or other non-program causes of changes in energy use and/or demand.

(40) Net-to-gross--A factor representing net program savings divided by gross program savings that is applied to gross program impacts to convert them into net program impacts. The factor may be made up of a variety of factors that create differences between gross and net savings, commonly considering the effects of free riders and spillover.

(41) Non-participant spillover--Energy savings that occur when a program non-participant installs energy efficiency measures or applies energy savings practices as a result of a program's influence.

(42) Off-peak period--Period during which the demand on an electric utility system is not at or near its maximum. For the purpose of this section, the off-peak period includes all hours that are not in the peak period.

(43) Participant spillover--The additional energy savings that occur when a program participant independently installs incremental energy efficiency measures or applies energy savings practices after having participated in the efficiency program as a result of the program's influence.

(44) Peak demand--Electrical demand at the times of highest annual demand on the utility's system. Peak demand refers to Texas retail peak demand and, therefore, does not include demand of retail customers in other states or wholesale customers.

(45) Peak demand reduction--Reduction in demand on the utility's system at the times of the utility's summer peak period or winter peak period.

(46) Peak period--For the purpose of this section, the peak period consists of the hours from one p.m. To seven p.m., during the months of June, July, August, and September, and the hours of 6 to 10 a.m. and 6 to 10 p.m., during the months of December, January, and February, excluding weekends and Federal holidays.

(47) Program year--A year in which an energy efficiency incentive program is implemented, beginning January 1 and ending December 31.

(48) Projected savings--Values reported by an electric utility prior to the time the energy efficiency activities are implemented. Are typically estimates of savings prepared for program and/or portfolio design or planning purposes. These values are based on pre-program or portfolio estimates of factors such as per-unit savings values, operating hours, installation rates, and savings persistence rates. These values may utilize results of prior evaluations and/or values in the Technical Reference Manual. Can be indicated as first year, annual demand or energy savings, and/or lifetime energy or demand savings values. Can be indicated as gross savings and/or net savings values.

(49) Rate class--For the purpose of calculating EECRF rates, a utility's rate classes are those retail rate classes approved in the utility's most recent base-rate proceeding, excluding non-eligible customers.

(50) Renewable demand side management (DSM) technologies--Equipment that uses a renewable energy resource (renewable resource), as defined in §25.173(c) of this title (relating to Goal for Renewable Energy), a geothermal heat pump, a solar water heater, or another natural mechanism of the environment, that when installed at a customer site, reduces the customer's net purchases of energy, demand, or both.

(51) Savings-to-Investment Ratio (SIR)--The ratio of the present value of a customer's estimated lifetime electricity cost savings from energy efficiency measures to the present value of the installation costs, inclusive of any incidental repairs, of those energy efficiency measures.

(52) Self-delivered program--A program developed by a utility in an area in which customer choice is not offered that provides incentives directly to customers. The utility may use internal or external resources to design and administer the program.

(53) Spillover--Reductions in energy consumption and/or demand caused by the presence of an energy efficiency program, beyond the program-related gross savings of the participants and without financial or technical assistance from the program. There can be participant and/or non-participant spillover.

(54) Spillover rate--Estimate of energy savings attributable to spillover expressed as a percent of savings installed by participants through an energy efficiency program.

(55) Standard offer contract--A contract between an energy efficiency service provider and a participating utility or between a participating utility and a commercial customer specifying standard payments based upon the amount of energy and peak demand savings achieved through energy efficiency measures, the measurement and verification protocols, and other terms and conditions, consistent with this section.

(56) Standard offer program--A program under which a utility administers standard offer contracts between the utility and energy efficiency service providers.

(57) Technical reference manual (TRM)--A resource document compiled by the commission's EM&V contractor that includes information used in program planning and reporting of energy efficiency programs. It can include savings values for measures, engineering algorithms to calculate savings, impact factors to be applied to calculated savings (e.g., net-to-gross values), protocols, source documentation, specified assumptions, and other relevant material to support the calculation of measure and program savings.

(58) Verification--An independent assessment that a program has been implemented in accordance with the program design. The objectives of measure installation verification are to confirm the installation rate, that the installation meets reasonable quality standards, and that the measures are operating correctly and have the potential to generate the predicted savings. Verification activities are generally conducted during on-site surveys of a sample of projects. Project site inspections, participant phone and mail surveys and/or implementer and participant documentation review are typical activities associated with verification. Verification is also a subset of evaluation.

(d) Cost-effectiveness standard. An energy efficiency program is deemed to be cost-effective if the cost of the program to the utility is less than or equal to the benefits of the program. Utilities are encouraged to achieve demand reduction and energy savings through a portfolio of cost-effective programs that exceed each utility's energy efficiency goals while staying within the cost caps established in subsection (f)(7) of this section.

(1) The cost of a program includes the cost of incentives, measurement and verification, any shareholder bonus awarded to the utility, and actual or allocated research and development and administrative costs. The benefits of the program consist of the value of the demand reductions and energy savings, measured in accordance with the avoided costs prescribed in this subsection. The present value of the program benefits shall be calculated over the projected life of the measures installed or implemented under the program.

(2) The avoided cost of capacity is $80 per kW-year for all electric utilities through program year 2012, unless the commission establishes a different avoided cost of capacity in accordance with this paragraph. The avoided cost of capacity shall be revised beginning with program year 2013, in accordance with this paragraph.

(A) By November 15 of each year, commission staff shall post a notice of a revised avoided cost of capacity on the commission's website, on a webpage designated for this purpose, effective for the next program year. If the avoided cost of capacity has not changed, staff shall post a notice that the avoided cost of capacity remains the same.

(i) Staff shall calculate the avoided cost of capacity from the base overnight cost using the lower of a new conventional combustion turbine or a new advanced combustion turbine, as reported by the United States Department of Energy's Energy Information Administration's (EIA) Cost and Performance Characteristics of New Central Station Electricity Generating Technologies associated with EIA's Annual Energy Outlook. If EIA cost data that reflects current conditions in the industry does not exist, staff may establish an avoided cost of capacity using another data source.

(ii) If the EIA base overnight cost of a new conventional or an advanced combustion turbine, whichever is lower, is less than $700 per kW, the avoided cost of capacity shall be $80 per kW. If the base overnight cost of a new conventional or advanced combustion turbine, whichever is lower, is at or between $700 and $1,000 per kW, the avoided cost of capacity shall be $100 per kW. If the base overnight cost of a new conventional or advanced combustion turbine, whichever is lower, is greater than $1,000 per kW, the avoided cost of capacity shall be $120 per kW.

(iii) The avoided cost of capacity calculated by staff may be challenged only by the filing of a petition within 45 days of the date the avoided cost of capacity is posted on the commission's website on a webpage designated for that purpose.

(B) A utility in an area in which customer choice is not offered may petition the commission for authorization to use an avoided cost of capacity different from the avoided cost determined according to subparagraph (A) of this paragraph by filing a petition no later than 45 days after the date the avoided cost of capacity calculated by staff is posted on the commission's website on a webpage designated for that purpose. The avoided cost of capacity proposed by the utility shall be based on a generating resource or purchase in the utility's resource acquisition plan and the terms of the purchase or the cost of the resource shall be disclosed in the filing.

(3) The avoided cost of energy is $0.064 per kWh for all electric utilities through program year 2012, unless the commission establishes a different avoided cost of energy in accordance with this paragraph. The avoided cost of energy shall be revised beginning with program year 2013, in accordance with this paragraph.

(A) Commission staff shall post a notice of a revised avoided cost of energy by November 15 of each year on the commission's website, on a webpage designated for this purpose, effective for the next program year. If the cost of energy has not changed, staff shall post a notice that the cost of energy remains the same. By November 1 of each year, ERCOT shall calculate the avoided cost of energy for the ERCOT region, as defined in §25.5(48) of this title (relating to Definitions), by determining the load-weighted average of the competitive load zone settlement point prices for the peak periods covering the two previous winter and summer peaks.

(B) A utility in an area in which customer choice is not offered may petition the commission for authorization to use an avoided cost of energy other than that otherwise determined according to this paragraph. The avoided cost of energy may be based on peak period energy prices in an energy market operated by a regional transmission organization if the utility participates in that market and the prices are reported publicly. If the utility does not participate in such a market, the avoided cost of energy may be based on the expected heat rate of the gas-turbine generating technology specified in this subsection, multiplied by a publicly reported cost of natural gas.

(e) Annual energy efficiency goals.

(1) An electric utility shall administer a portfolio of energy efficiency programs to acquire, at a minimum, the following:

(A) The utility shall acquire no less than a 25% reduction of the electric utility's annual growth in demand of residential and commercial customers for the 2012 program year.

(B) Beginning with the 2013 program year, until the trigger described in subparagraph (C) of this paragraph is reached, the utility shall acquire a 30% reduction of its annual growth in demand of residential and commercial customers.

(C) If the demand reduction goal to be acquired by a utility under subparagraph (B) of this paragraph is equivalent to at least four-tenths of 1 % its summer weather-adjusted peak demand for the combined residential and commercial customers for the previous program year, the utility shall meet the energy efficiency goal described in subparagraph (D) of this paragraph for each subsequent program year.

(D) Once the trigger described in subparagraph (C) of this paragraph is reached, the utility shall acquire four-tenths of 1% of its summer weather-adjusted peak demand for the combined residential and commercial customers for the previous program year.

(E) Except as adjusted in accordance with subsection (w) of this section, a utility's demand reduction goal in any year shall not be lower than its goal for the prior year, unless the commission establishes a goal for a utility pursuant to paragraph (2) of this subsection.

(2) The commission may establish for a utility a lower goal than the goal specified in paragraph (1) of this subsection, a higher administrative spending cap than the cap specified under subsection (i) of this section, or an EECRF greater than the cap specified in subsection (f)(7) of this section if the utility demonstrates that compliance with that goal, administrative spending cap, or EECRF cost cap is not reasonably possible and that good cause supports the lower goal, higher administrative spending cap, or higher EECRF cost cap. To be eligible for a lower goal, higher administrative spending cap, or a higher EECRF cost cap, the utility must request a good cause exception as part of its EECRF application. If approved, the good cause exception is limited to the program year associated with the EECRF application.

(3) Each utility's demand-reduction goal shall be calculated as follows:

(A) Each year's historical demand for residential and commercial customers shall be adjusted for weather fluctuations, using weather data for the most recent ten years. The utility's growth in residential and commercial demand is based on the average growth in retail load in the Texas portion of the utility's service area, measured at the utility's annual system peak. The utility shall calculate the average growth rate for the prior five years.

(B) The demand goal for energy-efficiency savings for a year pursuant to paragraphs (1)(A) or (B) of this subsection is calculated by applying the percentage goal to the average growth in demand, calculated in accordance with subparagraph (A) of this paragraph. The annual demand goal for energy efficiency savings pursuant to paragraph (1)(D) of this subsection is calculated by applying the percentage goal to the utility's summer weather-adjusted five-year average peak demand for the combined residential and commercial customers.

(C) A utility may submit for commission approval an alternative method to calculate its growth in demand, for good cause.

(D) If a utility's prior five-year average load growth, calculated pursuant to subparagraph (A) of this paragraph, is negative, the utility shall use the demand reduction goal calculated using the alternative method approved by the commission beginning with the 2013 program year or, if the commission has not approved an alternative method, the utility shall use the previous year's demand reduction goal.

(E) A utility shall not claim savings obtained from energy efficiency measures funded through settlement orders or count towards the bonus calculation any savings obtained from grant incentives that have been awarded directly to the utility for energy efficiency programs.

(F) Savings achieved through programs for hard-to-reach customers shall be no less than 5.0% of the utility's total demand reduction goal.

(G) Utilities may apply peak savings on a per project basis to summer or winter peak, but not to both summer and winter peaks.

(4) An electric utility shall administer a portfolio of energy efficiency programs designed to meet an energy savings goal calculated from its demand savings goal, using a 20% conservation load factor.

(5) Electric utilities shall administer a portfolio of energy efficiency programs to effectively and efficiently achieve the goals set out in this section.

(A) Incentive payments may be made under standard offer contracts, market transformation contracts, or as part of a self-delivered program for energy savings and demand reductions. Each electric utility shall establish standard incentive payments to achieve the objectives of this section.

(B) Projects or measures under a standard offer, market transformation, or self-delivered program are not eligible for incentive payments or compensation if:

(i) A project would achieve demand or energy reduction by eliminating an existing function, shutting down a facility or operation, or would result in building vacancies or the re-location of existing operations to a location outside of the area served by the utility conducting the program, except for an appliance recycling program consistent with this section.

(ii) A measure would be adopted even in the absence of the energy efficiency service provider's proposed energy efficiency project, except in special cases, such as hard-to-reach and weatherization programs, or where free riders are accounted for using a net to gross adjustment of the avoided costs, or another method that achieves the same result. A project results in negative environmental or health effects, including effects that result from improper disposal of equipment and materials.

(C) Ineligibility pursuant to subparagraph (B) of this paragraph does not apply to standard offer, market transformation, and self-delivered programs aimed at energy code adoption, implementation, compliance, and enforcement under subsection (m) of this section, nor does it preclude standard offer, market transformation, or self-delivered programs promoting energy efficiency measures also required by energy codes to the degree such codes do not achieve full compliance rates.

(D) A utility in an area in which customer choice is not offered may achieve the goals of paragraphs (1) and (2) of this subsection by:

(i) providing rebate or incentive funds directly to eligible residential and commercial customers for programs implemented under this section; or

(ii) developing, subject to commission approval, new programs other than standard offer programs and market transformation programs, to the extent that the new programs satisfy the same cost-effectiveness standard as standard offer programs and market transformation programs using the process outlined in subsection (s) of this section.

(E) For a utility in an area in which customer choice is offered, the utility may achieve the goal of this section in rural areas by providing rebate or incentive funds directly to customers after demonstrating to the commission in a contested case hearing that the goal requirement cannot be met through the implementation of programs by retail electric providers or energy efficiency service providers in the rural areas.

(f) Cost recovery. A utility shall establish an energy efficiency cost recovery factor (EECRF) that complies with this subsection to timely recover the reasonable costs of providing a portfolio of cost-effective energy efficiency programs pursuant to this section.

(1) The EECRF shall be calculated to recover:

(A) For a utility that does not collect any amount of energy efficiency costs in its base rates, the utility's forecasted annual energy efficiency program expenditures, the preceding year's over- or under-recovery that includes municipal and utility EECRF proceeding expenses, any performance bonus earned under subsection (h) of this section, and EM&V costs allocated to the utility by the commission.

(B) For a utility that collects any amount of energy efficiency in its base rates, the utility's forecasted annual energy efficiency program expenditures in excess of the actual energy efficiency revenues collected from base rates as described in paragraph (2) of this subsection, the preceding year's over- or under-recovery that includes municipal and utility EECRF proceeding expenses, any performance bonus earned under subsection (h) of this section, and EM&V costs allocated to the utility by the commission.

(2) The commission may approve an EECRF for each eligible rate class. The costs shall be directly assigned to each rate class that receives services under the programs to the maximum extent reasonably possible. In its EECRF proceeding, a utility may request a good cause exception to combine one or more rate classes, each containing fewer than 20 customers, with a similar rate class that receives services under the same energy efficiency programs. For each rate class, the under- or over-recovery of the energy efficiency costs shall be the difference between actual EECRF revenues and actual costs for that class that comply with paragraph (12) of this subsection. Where a utility collects energy efficiency costs in its base rates, actual energy efficiency revenues collected from base rates consist of the amount of energy efficiency costs expressly included in base rates, adjusted to account for changes in billing determinants from the test year billing determinants used to set rates in the last base rate proceeding.

(3) A proceeding conducted pursuant to this subsection is a ratemaking proceeding for purposes of PURA §33.023. EECRF proceeding expenses shall be included in the EECRF calculated pursuant to paragraph (1) of this subsection as follows:

(A) For a utility's EECRF proceeding expenses, the utility may include only its expenses for the immediately previous EECRF proceeding conducted under this subsection.

(B) For municipalities' EECRF proceeding expenses, the utility may include only expenses paid or owed for the immediately previous EECRF proceeding conducted under this subsection for services reimbursable under PURA §33.023(b).

(4) Base rates shall not be set to recover energy efficiency costs.

(5) If a utility recovers energy efficiency costs through base rates, the EECRF may be changed in a general rate proceeding. If a utility is not recovering energy efficiency costs through base rates, the EECRF may be adjusted only in an EECRF proceeding pursuant to this subsection.

(6) For residential customers and for commercial rate classes whose base rates do not provide for demand charges, the EECRF rates shall be designed to provide only for energy charges. For commercial rate classes whose base rates provide for demand charges, the EECRF rates shall provide for energy charges or demand charges but not both. Any EECRF demand charge shall not be billed using a demand ratchet mechanism.

(7) The total EECRF costs outlined in paragraph (1) of this subsection, excluding EM&V costs and municipal EECRF proceeding expenses shall not exceed the amounts prescribed in this paragraph unless a good cause exception filed pursuant to subsection (e)(2) of this section is granted.

(A) For residential customers for program years 2016 and 2017, $0.001266 per kWh; and

(B) For residential customers for program year 2018, $0.001263 per kWh increased or decreased by a rate equal to the 2016 calendar year's percentage change in the South urban consumer price index (CPI), as determined by the Federal Bureau of Labor Statistics;

(C) For commercial customers for program years 2016 and 2017, rates designed to recover revenues equal to $0.000791 per kWh times the aggregate of all eligible commercial customers' kWh consumption; and

(D) For commercial customers for program year 2018, rates designed to recover revenues equal to $0.000790 per kWh increased or decreased by a rate equal to the 2016 calendar year's percentage change in the South urban CPI, as determined by the Federal Bureau of Labor Statistics times the aggregate of all eligible commercial customers' kWh consumption.

(E) For the 2019 program year and thereafter, the residential and commercial cost caps shall be calculated to be the prior period's cost caps increased or decreased by a rate equal to the most recently available calendar year's percentage change in the South urban CPI, as determined by the Federal Bureau of Labor Statistics.

(8) Not later than May 1 of each year, a utility in an area in which customer choice is not offered shall apply to adjust its EECRF effective January 1 of the following year. Not later than June 1 of each year, a utility in an area in which customer choice is offered shall apply to adjust its EECRF effective March 1 of the following year. If a utility is in an area in which customer choice is offered in some but not all parts of its service area and files one energy efficiency plan and report covering all of its service area, the utility shall apply to adjust the EECRF not later than May 1 of each year, with the EECRF effective January 1 in the parts of its service area in which customer choice is not offered and March 1 in the parts of its service area in which customer choice is offered.

(9) Upon a utility's filing of an application to establish a new EECRF or adjust an EECRF, the presiding officer shall set a procedural schedule that will enable the commission to issue a final order in the proceeding required by subparagraphs (A), (B), and (C) of this paragraph as follows:

(A) For a utility in an area in which customer choice is not offered, the presiding officer shall set a procedural schedule that will enable the commission to issue a final order in the proceeding prior to the January 1 effective date of the new or adjusted EECRF, except where good cause supports a different procedural schedule.

(B) For a utility in an area in which customer choice is offered, the effective date of a new or adjusted EECRF shall be March 1. The presiding officer shall set a procedural schedule that will enable the utility to file an EECRF compliance tariff consistent with the final order within 10 days of the date of the final order. The procedural schedule shall also provide that the compliance filing date will be at least 45 days before the effective date of March 1. In no event shall the effective date of any new or adjusted EECRF occur less than 45 days after the utility files a compliance tariff consistent with a final order approving the new or adjusted EECRF. The utility shall service notice of the approved rates and the effective date of the approved rates by the working day after the utility files a compliance tariff consistent with the final order approving the new or adjusted EECRF to retail electric providers that are authorized by the registration agent to provide service in the utility's service area. Notice under this subparagraph may be served by email. The procedural schedule may be extended for good cause, but in no event shall the effective date of any new or adjusted EECRF occur less than 45 days after the utility files a compliance tariff consistent with a final order approving the new or adjusted EECRF, and in no event shall the utility serve notice of the approved rates and the effective date of the approved rates to retail electric providers that are authorized by the registration agent to provide service in the utility's service area more than one working day after the utility files the compliance tariff.

(C) For a utility in an area in which customer choice is offered in some but not all parts of its service area and that files one energy efficiency plan and report covering all of its service area, the presiding officer shall set a procedural schedule that will enable the commission to issue a final order in the proceeding prior to the January 1 effective date of the new or adjusted EECRF for the areas in which customer choice is not offered, except where good cause supports a different schedule. For areas in which customer choice is offered, the effective date of the new or adjusted EECRF shall be March 1. The presiding officer shall set a procedural schedule that will enable the utility to file an EECRF compliance tariff consistent with the final order within 10 days of the date of the final order. The procedural schedule shall also provide that the compliance filing date will be at least 45 days before the effective date of March 1. In no event shall the effective date of any new or adjusted EECRF occur less than 45 days after the utility files a compliance tariff consistent with a final order approving the new or adjusted EECRF. The utility shall serve notice of the approved rates and the effective date of the approved rates by the working day after the utility files a compliance tariff consistent with the final order approving the new or adjusted EECRF to retail electric providers that are authorized by the registration agent to provide service in the utility's service area. Notice under this subparagraph of this paragraph may be served by email. The procedural schedule may be extended for good cause, but in no event shall the effective date of any new or adjusted EECRF occur less than 45 days after the utility files a compliance tariff consistent with a final order approving the new or adjusted EECRF, and in no event shall the utility serve notice of the approved rates and the effective date of the approved rates to retail electric providers that are authorized by the registration agent to provide service in the utility's service area more than one working day after the utility files the compliance tariff.

(D) If no hearing is requested within 30 days of the filing of the application, the presiding officer shall set a procedural schedule that will enable the commission to issue a final order in the proceeding within 90 days after a sufficient application was filed; or

(E) If a hearing is requested within 30 days of the filing of the application, the presiding officer shall set a procedural schedule that will enable the commission to issue a final order in the proceeding within 180 days after a sufficient application was filed. If a hearing is requested, the hearing will be held no earlier than the first working day after the 45th day after a sufficient application is filed.

(10) A utility's application to establish or adjust an EECRF shall include testimony and schedules, in Excel format with formulas intact, showing the following, by retail rate class, for the prior program year and the program year for which the proposed EECRF will be collected as appropriate:

(A) the utility's forecasted energy efficiency costs;

(B) the actual base rate recovery of energy efficiency costs, adjusted for load changes in load subsequent to the last base rate proceeding, with supporting calculations;

(C) the energy efficiency performance bonus amount that it calculates to have earned for the prior year;

(D) any adjustment for past over- or under-recovery of energy efficiency revenues;

(E) information concerning the calculation of billing determinants for the most recent year and for the year in which the EECRF is expected to be in effect;

(F) the direct assignment and allocation of energy efficiency costs to the utility's eligible rate classes, including any portion of energy efficiency costs included in base rates, provided that the utility's actual EECRF expenditures by rate class may deviate from the projected expenditures by rate class, to the extent doing so does not exceed the cost caps in paragraph (7) of this subsection;

(G) information concerning calculations related to the requirements of paragraph (7) of this subsection;

(H) the incentive payments by the utility, by program, including a list of each energy efficiency administrator and/or service provider receiving more than 5% of the utility's overall incentive payments and the percentage of the utility's incentives received by those providers. Such information may be treated as confidential;

(I) the utility's administrative costs, including any affiliate costs and EECRF proceeding expenses and an explanation of both;

(J) the actual EECRF revenues by rate class for any period for which the utility calculates an under- or over-recovery of EECRF costs;

(K) the utility's bidding and engagement process for contracting with energy efficiency service providers, including a list of all energy efficiency service providers that participated in the utility programs and contractors paid with funds collected through the EECRF. Such information may be treated as confidential;

(L) the estimated useful life used for each measure in each program, or a link to the information if publicly available; and

(M) any other information that supports the determination of the EECRF.

(11) The following factors must be included in the application, as applicable, to support the recovery of energy efficiency costs under this subsection.

(A) the costs are less than or equal to the benefits of the programs, as calculated in subsection (d) of this section;

(B) the program portfolio was implemented in accordance with recommendations made by the commission's EM&V contractor and approved by the commission and the EM&V contractor has found no material deficiencies in the utility's administration of its portfolio of energy efficiency programs. This subparagraph does not preclude parties from examining and challenging the reasonableness of a utility's energy efficiency program expenses nor does it limit the commission's ability to address the reasonableness of a utility's energy efficiency program expenses;

(C) if a utility is in an area in which customer choice is offered and is subject to the requirements of PURA §39.905(f), the utility met its targeted low-income energy efficiency requirements;

(D) existing market conditions in the utility's service territory affected its ability to implement one or more of its energy efficiency programs or affected its costs;

(E) the utility's costs incurred and achievements accomplished in the previous year or estimated for the year the requested EECRF will be in effect are consistent with the utility's energy efficiency program costs and achievements in previous years notwithstanding any recommendations or comments by the EM&V contractor;

(F) changed circumstances in the utility's service area since the commission approved the utility's budget for the implementation year that affect the ability of the utility to implement any of its energy efficiency programs or its energy efficiency costs;

(G) the number of energy efficiency service providers operating in the utility's service territory affects the ability of the utility to implement any of its energy efficiency programs or its energy efficiency costs;

(H) customer participation in the utility's prior years' energy efficiency programs affects customer participation in the utility's energy efficiency programs in previous years or its proposed programs underlying its EECRF request and the extent to which program costs were expended to generate more participation or transform the market for the utility's programs;

(I) the utility's energy efficiency costs for the previous year or estimated for the year the requested EECRF will be in effect are comparable to costs in other markets with similar conditions; or

(J) the utility has set its incentive payments with the objective of achieving its energy and demand goals at the lowest reasonable cost per program.

(12) The scope of an EECRF proceeding includes the extent to which the costs recovered through the EECRF complied with PURA §39.905 and this section, and the extent to which the costs recovered were reasonable and necessary to reduce demand and energy growth. The proceeding shall not include a review of program design to the extent that the programs complied with the energy efficiency implementation project (EEIP) process defined in subsection (s) of this section. The commission shall not allow recovery of expenses that are designated as non-recoverable under §25.231(b)(2) of this title (relating to Cost of Service). In addition, the order shall contain findings of fact regarding the following:

(A) the costs to be recovered through the EECRF are reasonable estimates of the costs necessary to provide energy efficiency programs and to meet the utility's goals under this section;

(B) calculations of any under- or over-recovery of EECRF costs is consistent with this section;

(C) any energy efficiency performance bonus for which recovery is being sought is consistent with this section;

(D) the costs assigned or allocated to rate classes are reasonable and consistent with this section;

(E) the estimate of billing determinants for the period for which the EECRF is to be in effect is reasonable;

(F) any calculations or estimates of system losses and line losses used in calculating the charges are reasonable;

(G) whether the proposed EECRF rates comply with the requirements of paragraph (7) of this subsection; and

(H) whether the proposed EECRF rates comply with the requirements of subsection (r) of this section, if the utility is in an area in which customer choice is offered.

(13) Notice of a utility's filing of an EECRF application is reasonable if the utility provides in writing a general description of the application and the docket number assigned to the application within 7 days of the application filing date to:

(A) All parties in the utility's most recent completed EECRF docket;

(B) All retail electric providers that are authorized by the registration agent to provide service in the utility's service area at the time the EECRF application is filed;

(C) All parties in the utility's most recent completed base-rate proceeding; and

(D) The state agency that administers the federal weatherization program.

(14) The utility shall file an affidavit attesting to the completion of notice within 14 days after the application is filed.

(g) Incentive payments. The incentive payments for each customer class shall not exceed 100% of avoided cost, as determined in accordance with this section. The incentive payments shall be set by each utility with the objective of achieving its energy and demand savings goals at the lowest reasonable cost per program. Different incentive levels may be established for areas that have historically been underserved by the utility's energy efficiency programs or for other appropriate reasons. Utilities may adjust incentive payments during the program year, but such adjustments must be clearly publicized in the materials used by the utility to set out the program rules and describe the programs to participating energy efficiency service providers.

(h) Energy efficiency performance bonus. A utility that exceeds its demand and energy reduction goals established in this section at a cost that does not exceed the cost caps established in subsection (f)(7) of this section shall be awarded a performance bonus calculated in accordance with this subsection. The performance bonus shall be based on the utility's energy efficiency achievements for the previous program year. The bonus calculation shall not include demand or energy savings that result from programs other than programs implemented under this section.

(1) The performance bonus shall entitle the utility to receive a share of the net benefits realized in meeting its demand reduction goal established in this section.

(2) Net benefits shall be calculated as the sum of total avoided cost associated with the eligible programs administered by the utility minus the sum of all program costs. Total avoided costs and program costs shall be calculated in accordance with this section.

(3) Beginning with the 2012 program year, a utility that exceeds 100% of its demand and energy reduction goals shall receive a bonus equal to 1% of the net benefits for every 2% that the demand reduction goal has been exceeded, with a maximum of 10% of the utility's total net benefits.

(4) The commission may reduce the bonus otherwise permitted under this subsection for a utility with a lower goal, higher administrative spending cap, or higher EECRF cost cap established by the commission pursuant to subsection (e)(2) of this section. The bonus shall be considered in the EECRF proceeding in which the bonus is requested.

(5) In calculating net benefits to determine a performance bonus, a discount rate equal to the utility's weighted average cost of capital of the utility and an escalation rate of 2 % shall be used. The utility shall provide documentation for the net benefits calculation, including, but not limited to, the weighted average cost of capital, useful life of equipment or measure, and quantity of each measure implemented.

(6) The bonus shall be allocated in proportion to the program costs associated with meeting the demand and energy goals and allocated to eligible customers on a rate class basis.

(7) A bonus earned under this section shall not be included in the utility's revenues or net income for the purpose of establishing a utility's rates or commission assessment of its earnings.

(i) Utility administration. The cost of administration shall not exceed 15% of a utility's total program costs. The cost of research and development shall not exceed 10% of a utility's total program costs for the previous program year. The cumulative cost of administration and research and development shall not exceed 20% of a utility's total program costs, unless a good cause exception filed pursuant to subsection (e)(2) of this section is granted. Any portion of these costs which are not directly assignable to a specific program shall be allocated among the programs in proportion to the program incentive costs. Any bonus awarded by the commission shall not be included in program costs for the purpose of applying these limits.

(1) Administrative costs include all reasonable and necessary costs incurred by a utility in carrying out its responsibilities under this section, including:

(A) conducting informational activities designed to explain the standard offer programs and market transformation programs to energy efficiency service providers, retail electric providers, and vendors;

(B) for a utility offering self-delivered programs, internal utility costs to conduct outreach activities to customers and energy efficiency service providers will be considered administration;

(C) providing informational programs to improve customer awareness of energy efficiency programs and measures;

(D) reviewing and selecting energy efficiency programs in accordance with this section;

(E) providing regular and special reports to the commission, including reports of energy and demand savings;

(F) a utility's costs for an EECRF proceeding conducted pursuant to subsection (f) of this section;

(G) the costs paid by a utility pursuant to PURA §33.023(b) for an EECRF proceeding conducted pursuant to subsection (f) of this section; however, these costs are not included in the administrative caps applied in this paragraph; and

(H) any other activities that are necessary and appropriate for successful program implementation.

(2) A utility shall adopt measures to foster competition among energy efficiency service providers for standard offer, market transformation, and self-delivered programs, such as limiting the number of projects or level of incentives that a single energy efficiency service provider and its affiliates is eligible for and establishing funding set-asides for small projects.

(3) A utility may establish funding set-asides or other program rules to foster participation in energy efficiency programs by municipalities and other governmental entities.

(4) Electric utilities offering standard offer, market transformation, and self-delivered programs shall use standardized forms, procedures, deemed savings estimates and program templates. The electric utility shall file any standardized materials, or any change to it, with the commission at least 60 days prior to its use. In filing such materials, the utility shall provide an explanation of changes from the version of the materials that was previously used. For standard offer, market transformation, and self-delivered programs, the utility shall provide relevant documents to REPs and EESPs and work collaboratively with them when it changes program documents, to the extent that such changes are not considered in the energy efficiency implementation project described in subsection (s) of this section.

(5) Each electric utility in an area in which customer choice is offered shall conduct programs to encourage and facilitate the participation of retail electric providers and energy efficiency service providers in the delivery of efficiency and demand response programs, including:

(A) Coordinating program rules, contracts, and incentives to facilitate the statewide marketing and delivery of the same or similar programs by retail electric providers;

(B) Setting aside amounts for programs to be delivered to customers by retail electric providers and establishing program rules and schedules that will give retail electric providers sufficient time to plan, advertise, and conduct energy efficiency programs, while preserving the utility's ability to meet the goals in this section; and

(C) Working with retail electric providers and energy efficiency service providers to evaluate the demand reductions and energy savings resulting from time-of-use prices, home-area network devices, such as in home displays, and other programs facilitated by advanced meters to determine the demand and energy savings from such programs.

(j) Standard offer programs. A utility's standard offer program shall be implemented through program rules and standard offer contracts that are consistent with this section. Standard offer contracts will be available to any energy efficiency service provider that satisfies the contract requirements prescribed by the utility under this section and demonstrates that it is capable of managing energy efficiency projects under an electric utility's energy efficiency program.

(k) Market transformation programs. Market transformation programs are strategic efforts, including, but not limited to, incentives and education designed to reduce market barriers for energy efficient technologies and practices. Market transformation programs may be designed to obtain energy savings or peak demand reductions beyond savings that are reasonably expected to be achieved as a result of current compliance levels with existing building codes applicable to new buildings and equipment efficiency standards or standard offer programs. Market transformation programs may also be specifically designed to express support for early adoption, implementation, and enforcement of the most recent version of the International Energy Conservation Code for residential or commercial buildings by local jurisdictions, express support for more effective implementation and enforcement of the state energy code and compliance with the state energy code, and encourage utilization of the types of building components, products, and services required to comply with such energy codes. The existence of federal, state, or local governmental funding for, or encouragement to utilize, the types of building components, products, and services required to comply with such energy codes does not prevent utilities from offering programs to supplement governmental spending and encouragement. Utilities should cooperate with the REPs, and, where possible, leverage existing industry-recognized programs that have the potential to reduce demand and energy consumption in Texas and consider statewide administration where appropriate. Market transformation programs may operate over a period of more than one year and may demonstrate cost-effectiveness over a period longer than one year.

(l) Self-delivered programs. A utility may use internal or external resources to design, administer, and deliver self-delivered programs. The programs shall be tailored to the unique characteristics of the utility's service area in order to attract customer and energy efficiency service provider participation. The programs shall meet the same cost effectiveness requirements as standard offer and market transformation programs.

(m) Requirements for standard offer, market transformation, and self-delivered programs. A utility's standard offer, market transformation, and self-delivered programs shall meet the requirements of this subsection. A utility may conduct information and advertising campaigns to foster participation in standard offer, market transformation, and self-delivered programs.

(1) Standard offer, market transformation, and self-delivered programs:

(A) shall describe the eligible customer classes and allocate funding among the classes on an equitable basis;

(B) may offer standard incentive payments and specify a schedule of payments that are sufficient to meet the goals of the program, which shall be consistent with this section, or any revised payment formula adopted by the commission. The incentive payments may include both payments for energy and demand savings, as appropriate;

(C) shall not permit the provision of any product, service, pricing benefit, or alternative terms or conditions to be conditioned upon the purchase of any other good or service from the utility, except that only customers taking transmission and distribution services from a utility can participate in its energy efficiency programs;

(D) shall provide for a complaint process that allows:

(i) an energy efficiency service provider to file a complaint with the commission against a utility; and

(ii) a customer to file a complaint with the utility against an energy efficiency service provider;

(E) may permit the use of distributed renewable generation, geothermal, heat pump, solar water heater and combined heat and power technologies, involving installations of ten megawatts or less;

(F) may factor in the estimated level of enforcement and compliance with existing energy codes in determining energy and peak demand savings; and

(G) may require energy efficiency service providers to provide the following:

(i) a description of how the value of any incentive will be passed on to customers;

(ii) evidence of experience and good credit rating;

(iii) a list of references;

(iv) all applicable licenses required under state law and local building codes;

(v) evidence of all building permits required by governing jurisdictions; and

(vi) evidence of all necessary insurance.

(2) Standard offer and self-delivered programs:

(A) shall require energy efficiency service providers to identify peak demand and energy savings for each project in the proposals they submit to the utility;

(B) shall be neutral with respect to specific technologies, equipment, or fuels. Energy efficiency projects may lead to switching from electricity to another energy source, provided that the energy efficiency project results in overall lower energy costs, lower energy consumption, and the installation of high efficiency equipment. Utilities may not pay incentives for a customer to switch from gas appliances to electric appliances except in connection with the installation of high efficiency combined heating and air conditioning systems;

(C) shall require that all projects result in a reduction in purchased energy consumption, or peak demand, or a reduction in energy costs for the end-use customer;

(D) shall encourage comprehensive projects incorporating more than one energy efficiency measure;

(E) shall be limited to projects that result in consistent and predictable energy or peak demand savings over an appropriate period of time based on the life of the measure; and

(F) may permit a utility to use poor performance, including customer complaints, as a criterion to limit or disqualify an energy efficiency service provider or its affiliate from participating in a program.

(3) A market transformation program shall identify:

(A) program goals;

(B) market barriers the program is designed to overcome;

(C) key intervention strategies for overcoming those barriers;

(D) estimated costs and projected energy and capacity savings;

(E) a baseline study that is appropriate in time and geographic region. In establishing a baseline, the study shall consider the level of regional implementation and enforcement of any applicable energy code;

(F) program implementation timeline and milestones;

(G) a description of how the program will achieve the transition from extensive market intervention activities toward a largely self-sustaining market;

(H) a method for measuring and verifying savings; and

(I) the period over which savings shall be considered to accrue, including a projected date by which the market will be sufficiently transformed so that the program should be discontinued.

(4) A market transformation program shall be designed to achieve energy or peak demand savings, or both, and lasting changes in the way energy efficient goods or services are distributed, purchased, installed, or used over a defined period of time. A utility shall use fair competitive procedures to select EESPs to conduct a market transformation program, and shall include in its annual report the justification for the selection of an EESP to conduct a market transformation program on a sole-source basis.

(5) A load-control standard-offer program shall not permit an energy efficiency service provider to receive incentives under the program for the same demand reduction benefit for which it is compensated under a capacity-based demand response program conducted by an independent organization, independent system operator, or regional transmission operator. The qualified scheduling entity representing an energy efficiency service provider is not prohibited from receiving revenues from energy sold in ERCOT markets in addition to any incentive for demand reduction offered under a utility load-control standard offer program.

(6) Utilities offering load management programs shall work with ERCOT and energy efficiency service providers to identify eligible loads and shall integrate such loads into the ERCOT markets to the extent feasible. Such integration shall not preclude the continued operation of utility load management programs that cannot be feasibly integrated into the ERCOT markets or that continue to provide separate and distinct benefits.

(n) Energy efficiency plans and reports (EEPR). Each electric utility shall file by April 1 of each year an energy efficiency plan and report in a project annually designated for this purpose, as described in this subsection. The plan and report shall be filed as a searchable pdf document.

(1) Each electric utility's energy efficiency plan and report shall describe how the utility intends to achieve the goals set forth in this section and comply with the other requirements of this section. The plan and report shall be based on program years. The plan and report shall propose an annual budget sufficient to reach the goals specified in this section.

(2) Each electric utility's plan and report shall include:

(A) the utility's total actual and weather-adjusted peak demand and actual and weather- adjusted peak demand for residential and commercial customers for the previous five years;

(B) the demand goal calculated in accordance with this section for the current year and the following year, including documentation of the demand, weather adjustments, and the calculation of the goal;

(C) the utility's customers' total actual and weather-adjusted energy consumption and actual and weather-adjusted energy consumption for residential and commercial customers for the previous five years;

(D) the energy goal calculated in accordance with this section, including documentation of the energy consumption, weather adjustments, and the calculation of the goal;

(E) a description of existing energy efficiency programs and an explanation of the extent to which these programs will be used to meet the utility's energy efficiency goals;

(F) a description of each of the utility's energy efficiency programs that were not included in the previous year's plan, including measurement and verification plans if appropriate, and any baseline studies and research reports or analyses supporting the value of the new programs;

(G) an estimate of the energy and peak demand savings to be obtained through each separate energy efficiency program;

(H) a description of the customer classes targeted by the utility's energy efficiency programs, specifying the size of the hard-to-reach, residential, and commercial classes, and the methodology used for estimating the size of each customer class;

(I) the proposed annual budget required to implement the utility's energy efficiency programs, broken out by program for each customer class, including hard-to-reach customers, and any set-asides or budget restrictions adopted or proposed in accordance with this section. The proposed budget shall detail the incentive payments and utility administrative costs, including specific items for research and information and outreach to energy efficiency service providers, and other major administrative costs, and the basis for estimating the proposed expenditures;

(J) a discussion of the types of informational activities the utility plans to use to encourage participation by customers, energy efficiency service providers, and retail electric providers to participate in energy efficiency programs, including the manner in which the utility will provide notice of energy efficiency programs, and any other facts that may be considered when evaluating a program;

(K) the utility's performance in achieving its energy goal and demand goal for the prior five years, as reported in annual energy efficiency reports filed in accordance with this section;

(L) a comparison of projected savings (energy and demand), reported savings, and verified savings for each of the utility's energy efficiency programs for the prior two years;

(M) a description of the results of any market transformation program, including a comparison of the baseline and actual results and any adjustments to the milestones for a market transformation program;

(N) a description of self-delivered programs;

(O) expenditures for the prior five years for energy and demand incentive payments and program administration, by program and customer class;

(P) funds that were committed but not spent during the prior year, by program;

(Q) a comparison of actual and budgeted program costs, including an explanation of any increase or decreases of more than 10% in the cost of a program;

(R) information relating to energy and demand savings achieved and the number of customers served by each program by customer class;

(S) the utility's most recent EECRF, the revenue collected through the EECRF, the utility's forecasted annual energy efficiency program expenditures in excess of the actual energy efficiency revenues collected from base rates as described in subsection (f)(2) of this section, and the control number under which the most recent EECRF was established;

(T) the amount of any over- or under-recovery energy efficiency program costs whether collected through base rates or the EECRF;

(U) a list of any counties that in the prior year were under-served by the energy efficiency program;

(V) a calculation showing whether the utility qualifies for a performance bonus and the amount of any bonus;

(W) a description of new or discontinued programs, including pilot programs that are planned to be continued as full programs. For programs that are to be introduced or pilot programs that are to be continued as full programs, the description shall include the budget and projected demand and energy savings; and

(X) a link to the program manuals for the current program year.

(o) Review of programs. Commission staff may initiate a proceeding to review a utility's energy efficiency programs. In addition, an interested entity may request that the commission initiate a proceeding to review a utility's energy efficiency programs.

(p) Inspection, measurement and verification. Each standard offer, market transformation, and self-delivered program shall include use of an industry - accepted evaluation and/or measurement and verification protocol, such as the International Performance Measurement and Verification Protocol (IPMVP) or a protocol approved by the commission, to document and verify energy and peak demand savings to ensure that the goals of this section are achieved. A utility shall not provide an energy efficiency service provider final compensation until the provider establishes that the work is complete and evaluation and/or measurement and verification in accordance with the protocol verifies that the savings will be achieved. However, a utility may provide an energy efficiency service provider that offers behavioral programs incremental compensation as work is performed. If inspection of one or more measures is a part of the protocol, a utility shall not provide an energy efficiency service provider final compensation until the utility has conducted its inspection on at least a sample of measures and the inspections confirm that the work has been done. A utility shall provide inspection reports to commission staff within 20 days of staff's request.

(1) The energy efficiency service provider, or for self-delivered programs the utility is responsible for the determination and documentation of energy and peak demand savings using the approved evaluation and/or measurement and verification protocol, and may utilize the services of an independent third party for such purposes.

(2) Commission-approved deemed energy and peak demand savings may be used in lieu of the energy efficiency service provider's measurement and verification, where applicable. The deemed savings approved by the commission before December 31, 2007 are continued in effect, unless superseded by commission action.

(3) Where installed measures are employed, an energy efficiency service provider shall verify that the measures contracted for were installed before final payment is made to the energy efficiency service provider, by obtaining the customer's signature certifying that the measures were installed, or by other reasonably reliable means approved by the utility.

(4) For projects involving over 30 installations, a statistically significant sample of installations will be subject to on-site inspection in accordance with the protocol for the project to verify that measures are installed and capable of performing their intended function. Inspection shall occur within 30 days of notification of measure installation.

(5) Projects of less than 30 installations may be aggregated and a statistically significant sample of the aggregate installations will be subject to on-site inspection in accordance with the protocol for the projects to ensure that measures are installed and capable of performing their intended function. Inspection shall occur within 30 days of notification of measure installation.

(6) Where installed measures are employed, the sample size for on-site inspections may be adjusted for an energy efficiency service provider under a particular contract, based on the results of prior inspections.

(q) Evaluation, measurement, and verification (EM&V). The following defines the evaluation, measurement, and verification (EM&V) framework to be implemented starting in program year 2013. The goal of this framework is to ensure that the programs are evaluated, measured, and verified using a consistent process that allows for accurate estimation of energy and demand impacts.

(1) EM&V objectives include:

(A) Documenting the impacts of the utilities' individual energy efficiency and load management portfolios, comparing their performance with established goals, and determining cost-effectiveness;

(B) Providing feedback for the commission, commission staff, utilities, and other stakeholders on program portfolio performance; and

(C) Providing input into the utilities' and ERCOT's planning activities.

(2) The principles that guide the EM&V activities in meeting the primary EM&V objectives are:

(A) Evaluators follow ethical guidelines.

(B) Important and relevant assumptions used by program planners and administrators are reviewed as part of the EM&V efforts.

(C) All important and relevant EM&V assumptions and calculations are documented and the reliability of results is indicated in evaluation reports.

(D) The majority of evaluation expenditures and efforts are in areas of greatest importance or uncertainty.

(3) The commission shall select an entity to act as the commission's EM&V contractor and conduct evaluation activities. The EM&V contractor shall operate under the commission's supervision and oversight, and the EM&V contractor shall offer independent analysis to the commission in order to assist in making decisions in the public interest.

(A) Under the oversight of the commission staff and with the assistance of utilities and other parties, the EM&V contractor will evaluate specific programs and the portfolio of programs for each utility.

(B) The EM&V contractor shall have the authority to request data it considers necessary to fulfill its evaluation, measurements, and verification responsibilities from the utilities. A utility shall make good faith efforts to provide complete, accurate, and timely responses to all EM&V contractor requests for documents, data, information and other materials. The commission may on its own volition or upon recommendation by staff require that a utility provide the EM&V contractor with specific information.

(4) Evaluation activities will be conducted by the EM&V contractor, starting with activities associated with program year 2012, to meet the evaluation objectives defined in this section. Activities shall include, but are not limited to:

(A) Providing appropriate planning documents.

(B) Impact evaluations to determine and document appropriate metrics for each utility's individual evaluated programs and portfolio of all programs, annual portfolio evaluation reports, and additional reports and services as defined by commission staff to meet the EM&V objectives.

(C) Preparation of a statewide technical reference manual (TRM), including updates to such manual as defined in this subsection.

(5) The impact evaluation activities may include the use of one or more evaluation approaches. Evaluation activities may also include, or just include, verification activities on a census or sample of projects implemented by the utilities. Evaluations may also include the use of due-diligence on utility-provided documentation as well as surveys of program participants, non-participants, contractors, vendors, and other market actors.

(6) The following apply to the development of a statewide TRM by the EM&V contractor.

(A) The EM&V contractor shall use existing Texas, or other state, deemed savings manual(s), protocols, and the work papers used to develop the values in the manual(s), as a foundation for developing the TRM. The TRM shall include applicability requirements for each deemed savings value or deemed savings calculation. The TRM may also include standardized EM&V protocols for determining and/or verifying energy and demand savings for particular measures or programs. Utilities may apply TRM deemed savings values or deemed savings calculations to a measure or program if the applicability criteria are met.

(B) The TRM shall be reviewed by the EM&V contractor at least annually, pursuant to a schedule determined by commission staff, with the intention of preparing an updated TRM, if needed. In addition, any utility or other stakeholder may request additions to or modifications to the TRM at any time with the provision of documentation for the basis of such an addition or modification. At the discretion of commission staff, the EM&V contractor may review such documentation to prepare a recommendation with respect to the addition or modification.

(C) Commission staff shall approve the initial TRM and any updated TRMs. The approval process for any TRM additions or modifications, not made during the regular review schedule determined by commission staff, shall include a review by commission staff to determine if an addition or modification is appropriate before an annual update.

(D) Any changes to the TRM shall be applied prospectively to programs offered in the appropriate program year.

(E) The TRM shall be publicly available.

(F) Utilities may use their existing deemed savings values in their 2013 program year energy efficiency plan and report, submitted in 2012, if the TRM is not available. Starting with their 2014 program year energy efficiency plan and report, submitted in 2013, utilities shall utilize the values contained in the TRM, unless the commission indicates otherwise.

(7) The utilities shall prepare projected savings estimates and claimed savings estimates. The utilities shall conduct their own EM&V activities for purposes such as confirming any incentive payments to customers or contractors and preparing documentation for internal and external reporting, including providing documentation to the EM&V contractor. The EM&V contractor shall prepare evaluated savings for preparation of its evaluation reports and a realization rate comparing evaluated savings with projected savings estimates and/or claimed savings estimates.

(8) Baselines for preparation of TRM deemed savings values or deemed savings calculations or for other evaluation activities shall be defined by the EM&V contractor and commission staff shall review and approve them. When common practice baselines are defined for determining gross energy and/or demand savings for a measure or program, common practice may be documented by market studies. Baselines shall be defined by measure category as follows (deviations from these specifications may be made with justification and approval of commission staff):

(A) Baseline is existing conditions for the estimated remaining lifetime of existing equipment for early replacement of functional equipment still within its current useful life. Baseline is applicable code, standard or common practice for remaining lifetime of the measure past the estimated remaining lifetime of existing equipment;

(B) Baseline is applicable code, standard or common practice for replacement of functional equipment beyond its current useful life;

(C) Baseline is applicable code, standard or common practice for unplanned replacements of failed equipment; and

(D) Baseline is applicable code, standard or common practice for new construction or major tenant improvements.

(9) Relevant recommendations of the EM&V contractor related to program design and reporting should be addressed in the Energy Efficiency Implementation Project (EEIP) and considered for implementation in future program years. The commission may require a utility to implement the EM&V contractor's recommendations in a future program year.

(10) The utilities shall be assigned the EM&V costs in proportion to their annual program costs and shall pay the invoices approved by the commission. The 2013 and 2014 EM&V expenses outlined in the EM&V contractor's budget shall be recovered through the EECRFs approved by the commission in the EECRF proceedings initiated by the utilities in 2013. The commission shall at least biennially review the EM&V contractor's costs and establish a budget for its services sufficient to pay for those services that it determines are economic and beneficial to be performed.

(A) The funding of the EM&V contractor shall be sufficient to ensure the selection of an EM&V contractor in accordance with the scope of EM&V activities outlined in this subsection.

(B) EM&V costs shall be itemized in the utilities' annual reports to the commission as a separate line item. The EM&V costs shall not count against the utility's cost caps or administration spending caps.

(11) For the purpose of analysis, the utility shall grant the EM&V contractor access to data maintained in the utilities' data tracking systems, including, but not limited to, the following proprietary customer information: customer identifying information, individual customer contracts, and load and usage data in accordance with §25.272(g)(1)(A) of this title (relating to Code of Conduct for Electric Utilities and Their Affiliates). Such information shall be treated as confidential information.

(A) The utility shall maintain records for three (3) years that include the date, time, and nature of proprietary customer information released to the EM&V contractor.

(B) The EM&V contractor shall aggregate data in such a way as to protect customer, retail electric provider, and energy efficiency service provider proprietary information in any non-confidential reports or filings the EM&V contractor prepares.

(C) The EM&V contractor shall not utilize data provided or received under commission authority for any purposes outside the authorized scope of work the EM&V contractor performs for the commission.

(D) The EM&V contractor providing services under this section shall not release any information it receives related to the work performed unless directed to do so by the commission.

(12) For evaluation of 2012 and 2013 program years' programs and portfolios, the EM&V contractor may implement a reduced level of EM&V activities as the EM&V contractor will not be retained by the commission until after the start of the 2012 program year. Should the EM&V contractor determine that deemed savings values utilized by the utilities for program years 2012 and/or 2013 are different than values the EM&V contractor develops for the TRM, the EM&V contractor shall report two sets of impacts - one with the TRM values and one with the utilities' values for 2012 and/or 2013 program years.

(r) Targeted low income energy efficiency program. Each unbundled transmission and distribution utility shall include in its energy efficiency plan a targeted low-income energy efficiency program. A utility in an area in which customer choice is not offered may include in its energy efficiency plan a targeted low-income energy efficiency program that utilizes the cost-effectiveness methodology provided in paragraph (2) of this subsection. Savings achieved by the program shall count toward the utility's energy efficiency goal.

(1) Each utility shall ensure that annual expenditures for the targeted low-income energy efficiency program are not less than 10% of the utility's energy efficiency budget for the program year.

(2) The utility's targeted low-income program shall incorporate a whole-house assessment that will evaluate all applicable energy efficiency measures for which there are commission-approved deemed savings. The cost-effectiveness of measures eligible to be installed and the overall program shall be evaluated using the Savings-to-Investment (SIR) ratio.

(3) Any funds that are not obligated after July of a program year may be made available for use in the hard-to-reach program.

(s) Energy Efficiency Implementation Project - EEIP. The commission shall use the EEIP to develop best practices in standard offer market transformation, self-directed, pilot, or other programs, modifications to programs, standardized forms and procedures, protocols, deemed savings estimates, program templates, and the overall direction of the energy efficiency program established by this section. Utilities shall provide timely responses to questions posed by other participants relevant to the tasks of the EEIP. Any recommendations from the EEIP process shall relate to future years as described in this subsection.

(1) The following functions may also be undertaken in the EEIP:

(A) development, discussion, and review of new statewide standard offer programs;

(B) identification, discussion, design, and review of new market transformation programs;

(C) determination of measures for which deemed savings are appropriate and participation in the development of deemed savings estimates for those measures;

(D) review of and recommendations on the commission EM&V contractor's reports;

(E) review of and recommendations on incentive payment levels and their adequacy to induce the desired level of participation by energy efficiency service providers and customers;

(F) review of and recommendations on a utility annual energy efficiency plans and reports;

(G) utility program portfolios and proposed energy efficiency spending levels for future program years;

(H) periodic reviews of the cost-effectiveness methodology; and

(I) other activities as identified by commission staff.

(2) The EEIP projects shall be conducted by commission staff. The commission's EM&V contractor's reports shall be filed in the project at a date determined by commission staff.

(3) A utility that intends to launch a program that is substantially different from other programs previously implemented by any utility affected by this section shall file a program template and shall provide notice of such to EEIP participants. Notice to EEIP participants need not be provided if a program description or program template for the new program is provided through the utility's annual energy efficiency report. Following the first year in which a program was implemented, the utility shall include the program results in the utility's annual energy efficiency report.

(4) Participants in the EEIP may submit comments and reply comments in the EEIP on dates established by commission staff.

(5) Any new programs or program redesigns shall be submitted to the commission in a petition in a separate proceeding. The approved changes shall be available for use in the utilities' next EEPR and EECRF filings. If the changes are not approved by the commission by November 1 in a particular year, the first time that the changes shall be available for use is the second EEPR and EECRF filings made after commission approval.

(6) Any interested entity that participates in the EEIP may file a petition to the commission for consideration regarding changes to programs.

(t) Retail providers. Each utility in an area in which customer choice is offered shall conduct outreach and information programs and otherwise use its best efforts to encourage and facilitate the involvement of retail electric providers as energy efficiency service companies in the delivery of efficiency and demand response programs.

(u) Customer protection. Each energy efficiency service provider that provides energy efficiency services to end-use customers under this section shall provide the disclosures and include the contractual provisions required by this subsection, except for commercial customers with a peak load exceeding 50 kW. Paragraph (1) of this subsection does not apply to behavioral energy efficiency programs that do not require a contract with a customer.

(1) Clear disclosure to the customer shall be made of the following:

(A) the customer's right to a cooling-off period of three business days, in which the contract may be canceled, if applicable under law;

(B) the name, telephone number, and street address of the energy efficiency services provider and any subcontractor that will be performing services at the customer's home or business;

(C) the fact that incentives are made available to the energy efficiency services provider through a program funded by utility customers, manufacturers or other entities and the amount of any incentives provided by the utility;

(D) the amount of any incentives that will be provided to the customer;

(E) notice of provisions that will be included in the customer's contract, including warranties;

(F) the fact that the energy efficiency service provider must measure and report to the utility the energy and peak demand savings from installed energy efficiency measures;

(G) the liability insurance to cover property damage carried by the energy efficiency service provider and any subcontractor;

(H) the financial arrangement between the energy efficiency service provider and customer, including an explanation of the total customer payments, the total expected interest charged, all possible penalties for non-payment, and whether the customer's installment sales agreement may be sold;

(I) the fact that the energy efficiency service provider is not part of or endorsed by the commission or the utility; and

(J) a description of the complaint procedure established by the utility under this section, and toll free numbers for the Office of Customer Protection of the Public Utility Commission of Texas, and the Office of Attorney General's Consumer Protection Hotline.

(2) The energy efficiency service provider's contract with the customer, where such a contract is employed, shall include:

(A) work activities, completion dates, and the terms and conditions that protect residential customers in the event of non-performance by the energy efficiency service provider;

(B) provisions prohibiting the waiver of consumer protection statutes, performance warranties, false claims of energy savings and reductions in energy costs;

(C) a disclosure notifying the customer that consumption data may be disclosed to the EM&V contractor for evaluation purposes; and

(D) a complaint procedure to address performance issues by the energy efficiency service provider or a subcontractor.

(3) When an energy efficiency service provider completes the installation of measures for a customer, it shall provide the customer an "All Bills Paid" affidavit to protect against claims of subcontractors.

(v) Grandfathered programs. An electric utility that offered a load management standard offer program for industrial customers prior to May 1, 2007 shall continue to make the program available, at 2007 funding and participation levels, and may include additional customers in the program to maintain these funding and participation levels.

(w) Identification notice. An industrial customer taking electric service at distribution voltage may submit a notice identifying the distribution accounts for which it qualifies under subsection (c)(30) of this section. The identification notice shall be submitted directly to the customer's utility. An identification notice submitted under this section must be renewed every three years. Each identification notice must include the name of the industrial customer, a copy of the customer's Texas Sales and Use Tax Exemption Certification (pursuant to Tax Code §151.317), a description of the industrial process taking place at the consuming facilities, and the customer's applicable account number(s) or ESID number(s). The identification notice is limited solely to the metered point of delivery of the industrial process taking place at the consuming facilities. The account number(s) or ESID number(s) identified by the industrial customer under this section shall not be charged for any costs associated with programs provided under this section, including any shareholder bonus awarded; nor shall the identified facilities be eligible to participate in utility-administered energy efficiency programs during the term. Beginning with the 2013 program year, notices shall be submitted not later than February 1 to be effective for the following program year. A utility's demand reduction goal shall be adjusted to remove any load that is lost as a result of this subsection.

(x) Administrative penalty. The commission may impose an administrative penalty or other sanction if the utility fails to meet a goal for energy efficiency under this section. Factors, to the extent they are outside of the utility's control, that may be considered in determining whether to impose a sanction for the utility's failure to meet the goal include:

(1) the level of demand by retail electric providers and energy efficiency service providers for program incentive funds made available by the utility through its programs;

(2) changes in building energy codes; and

(3) changes in government-imposed appliance or equipment efficiency standards.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on April 23, 2018.

TRD-201801811

Adriana Gonzales

Rules Coordinator

Public Utility Commission of Texas

Effective date: May 13, 2018

Proposal publication date: December 29, 2017

For further information, please call: (512) 936-7223


SUBCHAPTER O. UNBUNDLING AND MARKET POWER

DIVISION 1. UNBUNDLING

16 TAC §25.344

The amendment is adopted under §14.002 of the Public Utility Regulatory Act, Tex. Util. Code Ann. §14.002 (West 2016 and Supp. 2017) (PURA) which provides the commission with the authority to make and enforce rules reasonably required in the exercise of its powers and jurisdiction, including rules of practice and procedure; PURA §17.007, which provides for a process by which a REP can identify low-income customers; PURA §39.101, which provides the commission with the authority to ensure that retail customer protections are established to entitle a customer to safe, reliable, and reasonably priced electricity.

Cross reference to statutes: Public Utility Regulatory Act §14.002, §14.052, §17.007, §39.101.

§25.344.Cost Separation Proceedings.

(a) Purpose. The purpose of this section is to establish the procedure by which affected utilities will comply with the Public Utility Regulatory Act (PURA) §39.201.

(b) Application. This section shall apply to all utilities subject to PURA §39.201.

(c) Compliance and timing.

(1) All electric utilities must file a cost separation case under this section on or before April 1, 2000 according to a unbundled cost of service rate filing package (UCOS-RFP) approved by the commission. Each electric utility shall, in its cost separation filing, file proposed tariffs for its proposed transmission and distribution utility. The filings shall include supporting cost data for the determination of the utility's non-bypassable delivery charges, which shall be the sum of transmission charges, distribution charges, metering system service charges, billing system service charges, customer service system charges (if any), municipal franchise charges, nuclear decommissioning charges (if any), and a competition transition charge (if any).

(2) Notwithstanding any other provision in this section, an electric utility not subject to this section until the expiration of the exemption set forth in PURA §39.102(c), must file its cost separation case on or before 170 days prior to the expiration of the exemption.

(d) Test year. A historic test year shall be used to determine a forecast test year, defined as follows:

(1) Historic year--for utilities filing a cost separation case on or before April 1, 2000, the historic year shall be the 12-month period ended September 30, 1999. For a utility filing a cost separation case after April 1, 2000, the historic year shall be a 12-month period deemed reasonable by the commission.

(2) Forecast year--for utilities filing a cost separation case on or before April 1, 2000, the forecast year shall be the projected 12-month period ended December 31, 2002. For a utility filing a cost separation case after April 1, 2000, the forecast year shall be a 12-month period deemed reasonable by the commission.

(e) Rate of return. Each electric utility shall file a rate of return that is based on its weighted average cost of capital as determined by one of the alternative methods indicated in the Unbundled Cost of Service Rate Filing Package (UCOS-RFP) approved by the commission.

(f) Separation of affiliate costs and functional cost separation.

(1) Affiliate costs.

(A) Separation of affiliate costs. The affiliate schedules accompanying the UCOS-RFP shall provide sufficient detail to enable the commission to evaluate the necessity and reasonableness of the affiliate expenses and the "no higher than" cost provisions of PURA §36.058 (relating to Consideration of Payment to Affiliate); §25.272 of this title (relating to Code of Conduct for Electric Utilities and Their Affiliates); and §25.273 of this title (relating to Contracts Between Electric Utilities and Their Affiliates). The schedules shall provide the net total amount of affiliate expense requested for each of the historic and forecast years. This information shall be provided by class of items for all affiliate transactions between the transmission and distribution utility and its affiliates including the affiliated power generation company and the affiliated retail electric provider.

(B) Affiliated service company. If there is an affiliated service company providing support to the regulated transmission and distribution utility and the other affiliates, then the UCOS-RFP shall include the transactions between the service company, the regulated transmission and distribution utility, the power generation company, the retail electric provider, and all the other affiliates pursuant to PURA §14.154. The UCOS-RFP shall include detailed information on allocation formulas as defined by the reporting schedules.

(C) Compliance with affiliate rules. The affiliate transactions reported in the UCOS-RFP shall comply with the code of conduct rules as promulgated in §§25.84 of this title (relating to Annual Reporting of Affiliate Transactions for Electric Utilities), 25.272 of this title, and 25.273 of this title.

(2) Functional cost separation. All electric utilities shall separate their costs into nine categories, relating to the following functions, as defined by §25.341 of this title (relating to Definitions):

(A) generation;

(B) transmission;

(C) distribution;

(D) transmission and distribution utility metering system services;

(E) transmission and distribution utility billing system services;

(F) additional retail billing services;

(G) transmission and distribution utility customer service;

(H) competitive energy service; and

(I) other unregulated services.

(3) Method of cost separation. Costs shall be assigned to the nine functions using the following three-tier process. No common costs shall be assigned to regulated functions by default. If the utility cannot meet its burden of proof, the costs in question shall be assigned to competitive functions.

(A) For each Federal Energy Regulatory Commission (FERC) account, costs shall be directly assigned to functions to the extent possible, and all relevant workpapers provided.

(B) The utility shall provide detailed workpapers documenting the nature of any costs that cannot be directly assigned. For adequately documented costs, the utility may derive an account-specific functionalization factor based on the directly assigned costs or appropriate cost causation principles. The utility must justify the assignment of common costs to regulated functions, and must present evidence to support any such assignment.

(C) If adequately documented costs remain for which direct assignment or account-specific functionalization cannot be identified, an appropriate functionalization factor as described in the UCOS-RFP may be used. These functionalization factors should only be used as a last resort. If a utility deems a functionalization factor other than the functionalization factor prescribed in the UCOS-RFP to be necessary, the utility shall provide a detailed justification for the chosen functionalization factor.

(g) Jurisdiction and Texas retail class allocation. Allocation of each of the functions comprising the transmission and distribution system services revenue requirement to the existing rate classes shall be based on forecasted 2002 test year load data. Costs related to other functions may be allocated based on a test year ending September 30, 1999.

(1) Jurisdictional allocation. Functionalized total company costs for the forecast year shall be allocated to the Texas retail jurisdiction. Jurisdictional allocators shall be based on either the methodology approved by the Federal Energy Regulatory Commission (FERC), or the methodology used in the last commission-approved cost of service study.

(2) Texas retail class allocation. Total Texas retail jurisdiction costs for each of the nine categories shall be allocated among existing rate classes. Consolidation of classes shall be done only during the rate design process.

(A) Transmission revenue requirement (system services). Electric Reliability Council of Texas (ERCOT) utilities shall allocate the total transmission revenue requirement based on the average of the four coincident peaks for each existing rate class at the time of ERCOT peak, if that data is available. If that data is not available, the utility may use the average of the four coincident peaks for each existing rate class at the time of the transmission and distribution utility's system peak. Non-ERCOT utilities shall allocate transmission revenue requirement based on either the FERC-approved methodology or the methodology approved in the last commission-approved cost of service study.

(B) Distribution revenue requirement (system services). Costs purely related to demand or customers shall be allocated based on the methodology used in the last cost of service study unless otherwise determined by the commission. Other costs shall be allocated based on allocators analogous to those used during the functionalization process, or appropriate cost-causation principles.

(C) Generation costs. Total generation costs shall be allocated to the existing rate classes based on the methodology used to allocate generation costs in the last cost of service study.

(D) Retail electric provider costs. Total costs of services which will be provided by the retail electric provider as approved in the business separation plan shall be allocated among classes based on the allocators used in the last cost of service study.

(E) Decommissioning costs. Costs associated with nuclear decommissioning obligations shall be allocated based on the methodology used in the last cost of service study unless otherwise approved by the commission. Total costs shall be reported in the unbundled cost of service studies as a separate line item (or subaccount) in each account where such costs occur.

(h) Determination of ERCOT and Non-ERCOT transmission costs.

(1) ERCOT transmission costs.

(A) The transmission cost of service for an electric utility in ERCOT shall be as described in §25.192(b) of this title (relating to Transmission Service Rates).

(B) The UCOS-RFP adopted by the commission for the cost separation filings shall be used by the electric utilities filing under this section.

(C) Any redirection of transmission depreciation expense to production by an electric utility in ERCOT pursuant to PURA §39.256 should not affect the utility's wholesale transmission cost of service that is used for determining the ERCOT postage stamp rate.

(2) Non-ERCOT transmission costs. For an electric utility in Texas operating outside ERCOT, the utility's open access transmission tariff approved by FERC will be used to determine the utility's transmission cost and rates in Texas.

(i) Rate design. Utilities shall consolidate existing rate classes into the minimum number of classes needed to recognize differences in usage of the transmission and distribution systems. Class consolidation shall not materially disadvantage any customer class.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on April 23, 2018.

TRD-201801812

Adriana Gonzales

Rules Coordinator

Public Utility Commission of Texas

Effective date: May 13, 2018

Proposal publication date: December 29, 2017

For further information, please call: (512) 936-7223


SUBCHAPTER P. PILOT PROJECTS

16 TAC §25.431

The amendment is adopted under §14.002 of the Public Utility Regulatory Act, Tex. Util. Code Ann. §14.002 (West 2016 and Supp. 2017) (PURA) which provides the commission with the authority to make and enforce rules reasonably required in the exercise of its powers and jurisdiction, including rules of practice and procedure; PURA §17.007, which provides for a process by which a REP can identify low-income customers; PURA §39.101, which provides the commission with the authority to ensure that retail customer protections are established to entitle a customer to safe, reliable, and reasonably priced electricity.

Cross reference to statutes: Public Utility Regulatory Act §14.002, §14.052, §17.007, §39.101.

§25.431.Retail Competition Pilot Projects.

(a) Purpose. This section establishes the parameters under which an electric utility shall offer customer choice for 5.0% of the load in its Texas service area beginning on June 1, 2001, through the implementation of retail competition pilot projects. The commission may use these pilot projects to evaluate the ability of each power region to implement full customer choice on January 1, 2002, including the operational readiness of support systems. The pilot projects conducted under this section also will serve to encourage participation in a competitive retail market and to inform customers about customer choice.

(b) Application.

(1) This section applies to an electric utility as defined in the Public Utility Regulatory Act (PURA) §31.002(6). An electric utility exempt from PURA Chapter 39 in accordance with PURA §39.102(c) may conduct a customer choice pilot project consistent with the requirements of this section upon expiration of its exemption. A pilot project commencing before the adoption of this section may fulfill portions of the requirements of this section, as determined by the commission.

(2) Other entities, including retail electric providers (REPs) certified by the commission, and aggregators, power generation companies, and power marketers registered with the commission may participate in the pilot projects under the terms and conditions established by this section.

(c) Intent of pilot projects. Pilot projects conducted under this section are intended to implement customer choice for all applicable customers in the same manner in which full customer choice will be offered starting January 1, 2002, to the extent practicable. Unless determined otherwise through a subsequent commission proceeding, or unless stated otherwise in this section, all pilot project participants who are not retail customers shall abide by all applicable commission rules, including but not limited to, rules relating to customer protection and transmission and distribution terms and conditions, and all rules of an independent organization as defined in PURA §39.151.

(1) Utility's obligation to serve. A utility shall continue to provide electric service in accordance with PURA and the commission's substantive rules to requesting customers in its certificated service area who do not wish to take service from a REP.

(2) Indemnification. Market participants, including utilities, shall be held harmless for any damages resulting from any non-willful system or process failures during the pilot project.

(3) Performance standards.

(A) Call center performance may be compromised by potential large increases of customer inquiries generated because of the customer education program and pilot project activities. For the period February 1, 2001 through December 31, 2001, as applicable to each utility,

(i) a reduction of five percentage points will be applied to the percentage of calls to be answered in the allowable time; or

(ii) 5.0% of the calls with the longest wait time will be subtracted from the calculation of average answer time.

(B) An affected utility shall track and report such performance during the pilot project in accordance with applicable commission rules and orders. An affected utility does not waive any rights to request an adjustment or waiver of performance standards directly affected by the customer education program or pilot project.

(4) Effect of pre-existing service agreements or contracts.

(A) To the extent a customer is otherwise eligible to participate in a pilot project in accordance with this section, a utility shall not challenge a customer's right to participate:

(i) based upon a claimed failure to provide notice of cancellation in accordance with the requirements of an existing service agreement, contract, or tariff; or

(ii) in the event that the customer's service agreement or contract is beyond its primary term.

(B) To the extent a customer is otherwise eligible to participate in a pilot project in accordance with this section, customers in the primary term of a service agreement or contract shall have the right to participate in the pilot project subject to a challenge by the utility based upon a service agreement or contractual issue other than failure to provide notice of cancellation in compliance with an existing service agreement, contract, or tariff. The procedure for any such challenge shall be as follows:

(i) A utility contending that a customer that has been otherwise selected to participate in the pilot project is not eligible to participate, because of an existing service agreement or contract in its primary term, shall inform the customer not later than seven days after the date scheduled for the lottery for the applicable class in the event the class is oversubscribed or the date the customer requests participation in the event the class is undersubscribed.

(ii) If the customer wishes to dispute the utility's contention, the customer must, within seven days of receipt of the utility's notification, so inform the utility. Pending resolution of the dispute, the utility shall reserve a place for that customer on the participant list.

(iii) The customer shall be entitled to participate in the pilot project unless the utility informs the commission of the pilot project eligibility dispute within seven days of receipt of the customer's notification to the utility disputing the claim of ineligibility. Upon receipt by the commission of timely notice of the dispute, the commission will resolve the dispute within 30 days after filing, and may do so administratively.

(iv) If the commission determines that the customer is eligible to participate, the customer will be included within the pilot project as soon as practicable after the decision.

(5) Right to withdraw from pilot project. For any reason, and at a customer's request, the REP and the incumbent utility shall restore a residential customer's account to pre-pilot project services and rates. In the event a customer's REP ceases to do business in Texas during the pilot project, the incumbent utility shall restore any customer's account to pre-pilot project services and rates at the customer's request.

(6) Application of renewable energy rule. To encourage access to energy generated from renewable resources by customers participating in the pilot projects, the renewable energy mandate provisions of §25.173 of this title (relating to Goal for Renewable Energy) will be extended on a voluntary basis during the pilot projects to the competitive portion of the market, with the following changes:

(A) Each REP may acquire and retire renewable energy credits (RECs) consistent with its share of retail kilowatt-hour sales during the pilot period (June 1, 2001 through December 31, 2001), at a rate consistent with REC obligations for the year 2002, and in the manner specified in §25.173(h) of this title;

(B) Each REC retired for the pilot period will reduce the REC obligations of the REP for the year 2002 compliance period;

(C) The voluntary settlement period for the pilot project renewable energy program will commence January 1, 2002 and end March 31, 2002; and

(D) Penalty provisions of §25.173(o) of this title are not applicable.

(7) End of pilot projects. The pilot projects will end on December 31, 2001, unless determined otherwise by the commission in accordance with subsection (j) of this section. For an electric utility exempt from PURA Chapter 39 in accordance with PURA §39.102(c), the pilot project, if undertaken, will begin and end on dates deemed reasonable by the commission. A customer will remain with the REP by which he or she was served on the last day of the pilot project until the customer or the REP elects otherwise. By participating in the pilot project, a customer does not waive any right to take service under the price to beat in accordance with PURA §39.202.

(d) Definitions. The following terms when used in this section shall have the following meanings unless the context clearly indicates otherwise:

(1) Aggregation--includes the purchase of electricity from a retail electric provider, a municipally owned utility, or an electric cooperative by an electricity customer for its own use in multiple locations or as part of a voluntary association of electricity customers. An electricity customer may not avoid any non-bypassable charges or fees as a result of aggregating its load.

(2) Customer class--a grouping of customers, specific to the pilot projects, for the purpose of allocating loads available for customer choice during the pilot projects. The five customer classes used in the pilot projects are:

(A) Residential--all customers identified by an electric service identifier (ESI) who purchase electricity under a utility's residential rate schedule.

(B) Non-residential, non-demand metered--all customers identified by an ESI who:

(i) do not purchase electricity under a utility's residential rate schedule; and

(ii) do not purchase electricity under a utility's municipal or school rate schedule; and

(iii) do not purchase electricity under a utility's rate schedule that is based on metered or estimated demand during the twelve month period ending December 31, 2000.

(C) Industrial demand-metered--all customers identified by an ESI who:

(i) do not purchase electricity under a utility's residential rate schedule; and

(ii) purchase electricity under a utility's rate schedule that is based on a metered demand; and

(iii) purchase electricity under a utility's industrial rate schedules (or are identified as industrial by the utility's rate code if the utility does not have industrial rate schedules) or have filed a manufacturing or processing tax exemption certificate with the utility.

(D) Commercial and all other demand-metered--all customers identified by an ESI who:

(i) do not purchase electricity under a utility's residential rate schedule; and

(ii) do not come within the definition of the industrial demand metered customer class; and

(iii) purchase electricity under a utility's rate schedule that is based on a metered demand.

(E) Other--The other customer class is composed of all customers identified by an ESI who:

(i) purchase electricity under a utility's rate schedule that is based on known usage patterns, not actual metered data (i.e., unmetered loads); or

(ii) purchase electricity under a utility's municipal or school rate schedules; or

(iii) purchase electricity under utility rate schedules applicable to seasonal agricultural use, such as cotton gins, irrigation, or grain elevators.

(3) Electric service identifier (ESI)--premise-based identifier assigned to each electric service delivery point between a transmission and distribution utility and an end-use load, which is used in the Texas customer registration system and the Electric Reliability Council of Texas (ERCOT) settlement system.

(4) Lottery--fair process in which ESIs or aggregator packets of ESIs are selected for participation in a pilot project by using standard statistical methods for simple random sampling; each ESI or aggregator packet of ESIs should have an equal chance of actually being selected.

(5) Participation--occurs when the customer takes service from a retail electric provider that is not the incumbent, integrated utility.

(e) Requirements for participants that are not retail customers.

(1) A REP must be certified by the commission pursuant to §25.107 of this title (relating to Certification of Retail Electric Providers) prior to participating in pilot projects established pursuant to this section. An affiliated REP shall not participate in the certificated service area of the electric utility with which it is affiliated.

(2) An aggregator, other than a self-aggregator, must be registered with the commission pursuant to §25.111 of this title (relating to Registration of Aggregators) prior to participating in pilot projects established pursuant to this section.

(3) A power generation company must be registered with the commission pursuant to §25.109 of this title (relating to Registration of Power Generation Companies) prior to participating in pilot projects established pursuant to this section. A utility need not be registered as a power generation company in order to generate power for sale during the pilot projects.

(4) A power marketer must be registered with the commission pursuant to §25.105 of this title (relating to Registration and Reporting by Power Marketers) prior to participating in pilot projects established pursuant to this section.

(5) An independent transmission organization outside of ERCOT may require a market participant to register with that organization in order to become a wholesale buyer and seller of energy across the transmission system.

(f) Customer education. Customer education for the pilot projects shall be conducted as part of the statewide customer education campaign for introducing customer choice. Included in this campaign will be announcements regarding the opportunity to participate in the pilot project and instructions on obtaining further information about the pilot project. The commission shall mail information written in English and in Spanish explaining the pilot project to eligible non-residential customers no later than March 1, 2001, and to eligible residential customers no later than April 15, 2001. The utility shall provide the commission or its designee with customer information necessary to implement this subsection. For purposes of this subsection, §25.272(g)(1) of this title (relating to Code of Conduct for Electric Utilities and Their Affiliates) does not apply with regard to proprietary customer information released to the commission or its designee. The mailing may contain information including, but not limited to:

(1) a description of the pilot project;

(2) the commission's central call center phone number and Internet website operating to respond to customer questions and requests for information;

(3) a list of REPs certified as of a date certain, including the telephone number and, if available, Internet website address for each REP, and a statement disclosing that the REP list is continually updated and how the customer can obtain an updated list; and

(4) a clear, plain language description of customer choice and the price to beat.

(g) Customer choice during pilot projects. The following procedures shall be used for customers to participate in the pilot projects within the designated time periods for each applicable customer class.

(1) Administration. For all customer classes, a REP shall submit requests to switch customers participating in the pilot projects to the registration agent beginning on May 31, 2001, and power delivery in conjunction with the pilot projects may begin on June 1, 2001. For purposes of this section, any electronic submission to the utility shall be executed using a standard electronic data interface (EDI) protocol (814) to be included in the utility's compliance filing.

(A) Except where explicitly stated otherwise in this section, a REP shall electronically submit switch requests to the utility for counting and validation purposes prior to submitting such requests to the registration agent. The utility shall maintain a weekly updated list of non-matching, rejected ESIs on its pilot project Internet website.

(B) Except for the industrial demand-metered class, there shall be no out-of-cycle meter reading requests submitted for purposes of the pilot project before July 1, 2001.

(C) Members of the non-residential customer classes may elect to waive the verification and recision process of the registration agent.

(D) A participating customer shall have the right to change from one REP to another REP in accordance with the switching procedures adopted by the commission.

(E) Beginning April 16, 2001, a REP shall electronically report to the utility any switch request for a customer or an aggregation packet with a listing of the ESIs to be switched to the REP as set forth in this paragraph. After the utility confirms that a non-residential ESI or aggregation packet is on the associated participant list, the utility shall submit the ESI to the registration agent. The registration agent shall keep a record of all the ESIs identified by the utility for participation in the pilot. The REP shall be responsible for submitting to the registration agent the ESIs associated with the switch request to serve. If the ESI identified by the REP matches an ESI identified by the utility, then the registration agent shall allow the registration process to continue.

(F) Because the utility is assigned the responsibility to administer the pilot project, except for complaints arising under §25.272 of this title, which may be made in accordance with procedures established under that section, a claim by any party of unreasonableness associated with the administration of the pilot project will first be addressed by the pilot implementation working group established by subsection (j)(4) of this section. If the complaint is not resolved within ten working days of initial notification to the pilot implementation working group, the complaint may be filed with the commission.

(2) Residential customer class.

(A) Determination of the 5.0% load available for customer choice. For residential customers, the load available for customer choice shall be determined by calculating 5.0% of the number of ESIs in this customer class as of December 31, 2000. No later than January 31, 2001, the utility shall determine the amount of load available for this customer class and shall make that information publicly available through its pilot project Internet website. For this customer class, 20% of the 5.0% load available for customer choice shall be initially set aside for each customer class (hereafter referred to as the 1.0% set-aside) for aggregated loads.

(B) Initiating switching. Beginning February 15, 2001, a REP may accept authorizations to switch providers from residential customers. A REP shall notify the utility of such authorizations for residential customers.

(C) Reaching the 5.0% load limit. For purposes of this subparagraph the total number of ESIs eligible to switch determined in subparagraph (A) of this paragraph, less the number of ESIs that have already authorized a switch, shall be referred to as the amount of available load.

(i) As each customer in this class authorizes a switch to another provider, the amount of available load shall be decremented by one.

(ii) When the amount of available load reaches zero, no more switch authorizations shall be accepted.

(3) Non-residential customer classes.

(A) Determination of the 5.0% load available for customer choice. No later than January 31, 2001, the utility shall make the results of the following calculations for each non-residential customer class publicly available through its pilot project Internet website. For each non-residential customer class, 20% of the 5.0% load available for customer choice shall be initially set aside for each customer class (hereafter referred to as the 1.0% set-aside) for aggregated loads.

(i) Non-residential, non-demand metered customers. For non-residential, non-demand metered customers, the load available for customer choice shall be determined by calculating 5.0% of the number of ESIs in that customer class as of December 31, 2000.

(ii) Industrial demand-metered customers; commercial and all other demand-metered customers. For each of the demand metered customer classes, the load available for customer choice shall be determined by calculating 5.0% of the sum of the kilowatts invoiced by the utility to all ESIs in each customer class for meter reading dates during the utility's peak demand month in the year 2000. In addition, the utility shall determine the individual ESI load caps for each demand metered customer class by calculating 20% of the load available for the pilot project in each demand-metered customer class.

(iii) Other customers as defined in subsection (d)(2)(E) of this section. For all other customers, the load available for customer choice shall be determined by calculating 5.0% of the sum of the kilowatt-hours for which all ESIs in this customer class were invoiced by the utility during the twelve month period ending December 31, 2000. In addition, the utility shall determine the individual ESI load caps for this customer class by calculating 20% of the kilowatt-hours available for the pilot project in this customer class.

(B) Amount of available load. For purposes of this paragraph, the total load available for customer choice determined in subparagraph (A) of this paragraph, less the amount of the customer's ESI load used for calculation in subparagraph (A) of this paragraph, shall be referred to as the amount of available load for each non-residential customer class. For an ESI that was not included in the calculation in subparagraph (A) of this paragraph, hereinafter called a new ESI, the customer's ESI load shall be determined as follows:

(i) For the non-residential, non-demand metered class, a new ESI shall count as one ESI against the total number of ESIs.

(ii) For the demand-metered classes, the demand allocated to a new ESI shall be 95% of the utility-estimated demand for the new ESI.

(iii) For the other class as defined in subsection (d)(2)(E) of this section, the energy allocated to a new ESI shall be 95% of the utility-estimated annual kilowatt-hours for the new ESI.

(C) Open interest period. Beginning February 15, 2001, and continuing through March 15, 2001, interested customers may request the opportunity to participate in a utility's pilot project by submitting to the utility through its pilot project Internet website the account number and zip code information necessary to determine the customer's ESI. An eligible ESI is one that does not exceed the individual ESI load cap established in subparagraph (A) of this paragraph. By March 21, 2001, the utility shall determine if the non-residential customer classes are either oversubscribed or undersubscribed, including the amount of load oversubscribed or undersubscribed, and shall make such information publicly available through its pilot project Internet website.

(i) Participant list. The utility shall create a list of customers eligible to participate in the pilot project, referred to as the participant list. The participant list shall include each ESI and related service address, the name in which the customer is billed, and customer class as defined in this section. No later than March 21, 2001, the utility shall make available its integrated voice response (IVR) system or its pilot project Internet website to allow a customer having an ESI in the lottery to determine whether its ESI has been selected for the participant list. The participant list for each customer class shall be provided to the commission no later than March 21, 2001.

(ii) Oversubscription. On March 21, 2001, if a non-residential customer class is oversubscribed, the utility shall use a lottery to develop the participant list. As each ESI is selected through the lottery, the ESI's load used for the calculation in subparagraph (A) of this paragraph shall be subtracted from the total amount of load available for customer choice as determined in subparagraph (A) of this paragraph. The ESI that causes the 4.0% load limit (i.e., the 5.0% load limit less the 1.0% set-aside) to be reached shall be the final ESI selected through the lottery; the 4.0% limit may be exceeded only for the purpose of accommodating the entire load associated with the final ESI selected, except that such excess shall not cause the amount of load available for customer choice to be greater than 4.1%. Once the 4.0% load limit is reached, the selected ESIs shall be included on the participant list.

(iii) Undersubscription. If a non-residential customer class is undersubscribed, all eligible ESIs submitted shall be included on the participant list. Beginning March 21, 2001, any unsubscribed load will be available for subscription by customers in that customer class on a first come, first served basis.

(D) Negotiation period. Between March 21, 2001 and May 10, 2001, customers on the participant list may negotiate and contract with REPs. A REP shall notify the utility of execution of a contract. If a customer has not entered into a confirmed REP contract for a specific ESI by May 10, 2001, that ESI shall be removed from the participant list, and the load associated with that ESI shall be added to the amount of available load. On May 11, 2001, the utility shall post, on its pilot project Internet website, a list of submitted ESIs that do not match a customer on the participant list. REPs shall have until May 14, 2001 to correct any ESI listed by the utility on May 11, 2001. On May 17, 2001, the utility shall determine the amount of available load for each non-residential customer class and shall make such determination publicly available through its pilot project Internet website.

(E) Monitoring and adjusting the amount of available load. Following the negotiation period, participation shall be allowed on a first come, first served basis.

(i) As each non-residential customer in a class executes a contract, the amount of available load for that class shall be decremented by the amount of the customer's ESI load used for the calculation in subparagraph (A) of this paragraph.

(ii) The ESI that causes the amount of available load to reach zero shall be the final ESI selected; the amount of available load may drop below zero only for the purpose of accommodating the entire load associated with the final ESI selected, subject to the limitations described in subparagraph (C)(ii) of this paragraph.

(4) Aggregated load set-aside. Customers participating in customer choice may use aggregation to the extent they choose, and may participate by self aggregation or multiple customer aggregation. For purposes of pilot project administration, aggregators must submit to the utility their groupings of utility account numbers and associated zip codes, or ESIs if available, for participation in the pilot project subject to the 1.0% set-aside. Such groupings (hereafter referred to as aggregation packets) shall be submitted by customer class as defined in subsection (d) of this section with a listing of utility account numbers and associated zip codes.

(A) Set-aside cap. No single aggregation packet may contain an ESI or ESIs that represent more than 20% of the 1.0% set-aside for that customer class, with the exception of the residential class.

(B) Registration dates. Aggregators may register non-residential customer class aggregation packets, subject to the limitation in subparagraph (A) of this paragraph, with the utility beginning February 15, 2001. Aggregators may register residential aggregation packets beginning March 1, 2001.

(C) Undersubscription for all non-residential customer classes. If an aggregation packet contains non-residential ESIs from a class that is undersubscribed as of April 2, 2001, then that aggregation packet shall have a reserved allotment of the 1.0% set-aside until May 21, 2001. If by May 31, 2001, the 1.0% set-aside for aggregation in any non-residential class is undersubscribed, then the utility shall determine the unused class capacity and add it to the amount of available load for that class. No later than June 10, 2001, the utility shall make the updated amount of available load publicly available through the utility's pilot project Internet website.

(D) Aggregation selection process for customer classes. The eligibility for the 1.0% set-aside for each customer class shall be determined as follows:

(i) Residential customer class. Beginning on March 1, 2001, an aggregator may accept authorizations from residential customers to switch providers as a part of an aggregation packet. Aggregators shall submit aggregated utility account numbers and associated service address zip codes to the utility for tracking the 1.0% set-aside on a first come, first served basis. Aggregation packets shall be accepted until either the 1.0% set-aside is reached or June 15, 2001, whichever comes first. If the 1.0% set-aside is not fully subscribed by June 15, 2001, the utility shall determine the unused class capacity and add that unused capacity to the total amount of available load for the residential class.

(ii) Non-residential customer classes. The initial set-aside for each of the non-residential customer classes shall be 1.0% of the eligible load by customer class. To be eligible for the aggregation participant list, an aggregator must provide utility account number and service address zip code information, or ESIs if available, to the utility by April 2, 2001.

(I) Oversubscription for the non-residential, non-demand metered customer class. If the total number of ESIs in aggregation packets submitted for the pilot for a non-residential, non-demand class as of April 2, 2001 exceeds the 1.0% set-aside, then the utility shall use a lottery to determine the aggregation participant list for this class. Aggregation packets eligible for the aggregation participant list shall be selected by the utility by April 5, 2001. As each aggregation packet is selected through the lottery, the ESI count shall be subtracted from the total number of ESI available for the 1.0% set-aside. Aggregation packets shall be selected until none of the 1.0% set-aside is left. If the last aggregation packet selected causes the 1.0% set-aside to be exceeded, the selection of the final aggregation packet for this class shall be done in accordance with subparagraph (E) of this paragraph. By April 6, 2001, the utility shall determine whether an aggregation packet has been selected, and shall make such information publicly available through its pilot project Internet website.

(II) Oversubscription for the industrial demand-metered and commercial and all other demand-metered classes. If the total combined load of all aggregation packets submitted for each of the industrial demand-metered and commercial and all other demand-metered classes exceeds the 1.0% set-aside as of April 2, 2001, then the utility shall use a lottery to determine the aggregation participant list for each customer class. Aggregation packets eligible for the aggregation participant list shall be selected by the utility by April 5, 2001. As an aggregation packet is selected through the lottery, the demand for that ESI used to determine the available capacity for that customer class shall be subtracted from the total demand amount available for the 1.0% set-aside. Aggregation packets shall be selected until none of the 1.0% set-aside is left. If the last aggregation packet selected causes the 1.0% set-aside to be exceeded, the selection of the final aggregation packet for the class shall be done in accordance with subparagraph (E) of this paragraph. No later than April 6, 2001, the utility shall make the list of ESIs eligible for the pilot project publicly available through its pilot project Internet website.

(III) Oversubscription for the other customer class as defined in subsection (d)(2)(e) of this section. If the total combined load of all aggregation packets submitted for the other class exceeds the 1.0% set-aside as of April 2, 2001, then the utility shall use a lottery to determine the aggregation participant list for this class. Aggregation packets eligible for the aggregation participant list shall be selected by the utility by April 5, 2001. As each aggregation packet is selected through the lottery, the energy in kilowatt-hours for that ESI used to determine the size of the customer class shall be subtracted from the total amount of energy available for the 1.0% set-aside. Aggregation packets shall be selected until none of the 1.0% set-aside is left. If the last aggregation packet selected causes the 1.0% set-aside to be exceeded, the selection of the final aggregation packet for the class shall be done in accordance with subparagraph (E) of this paragraph. No later than April 6, 2001, the utility shall make the list of ESIs eligible for the pilot project for the class publicly available through its pilot project Internet website.

(E) Non-residential customer classes oversubscription lottery selection of last aggregation packet. If the final aggregation packet chosen in a customer class lottery causes the 1.0% set-aside for that customer class to be exceeded by more than 10%, that is, if that aggregation packet increases the size of the customer class to greater than 1.1%, that aggregation packet shall be rejected and another aggregation packet shall be chosen if available. If no other aggregation packet is available to fill each non-residential customer class without exceeding the 10% overage limit, that remaining increment of capacity set-aside will not be subscribed, but will be added to the amount of available capacity for aggregation for that non-residential customer class and will be available on a first come, first served basis. An aggregation packet that does not exceed the 10% overage limit will be allowed. When the results of the oversubscription lottery are posted by the utility, the utility shall also make publicly available the information concerning this available capacity through its pilot project Internet website.

(F) Contract notification due date for non-residential customer classes. By May 21, 2001, a REP must submit verification of executed supply contracts with ESIs and associated zip code to the utility. Any ESI that has not been validated by a REP by this date will relinquish its reserved allotment on the aggregation participant list. The relinquished allotment will then be available for aggregation in that customer class on a first come, first served basis.

(G) Notification of executed contract for non-residential customer classes. The REP shall document the existence of an executed contract for service by electronically submitting a list of ESIs representing executed contracts to the utility. The utility may rely on receipt of this list as proof of the existence of an executed contract. The REP shall file a signed affidavit with the commission attesting to the accuracy of the ESIs on the list.

(H) Electronic submissions by aggregators. All submittals required by this section by aggregators to a utility shall be made in electronic format using a Microsoft Excel spreadsheet using a spreadsheet template posted on the utility's pilot project Internet website. A utility will post its templates by January 31, 2001.

(I) New ESIs. For an ESI that was not included in the calculation in paragraph (3)(A) of this subsection, hereinafter called a new ESI, the customer's ESI load shall be determined as follows:

(i) For the non-residential non-demand metered classes, a new ESI shall count as one ESI against the total number of ESIs.

(ii) For the demand-metered classes, the demand allocated to a new ESI shall be 95% of the utility-estimated demand for the new ESI.

(iii) For the other class as defined in subsection (d)(2)(E) of this section, the energy allocated to a new ESI shall be 95% of the utility-estimated annual kilowatt-hours for the new ESI.

(h) Transmission and distribution rates and tariffs.

(1) Utilities within ERCOT. In connection with a utility's pilot project, the utility shall provide transmission service and distribution service in accordance with the rates for non-bypassable delivery charges approved by the commission, on an interim basis for application during the utility's pilot project, in the utility's unbundled cost of service case filed pursuant to PURA §39.201. Notwithstanding the provisions of §22.125 of this title (relating to Interim Relief), such interim rates shall not be subject to surcharge or refund if the rates ultimately established differ from the interim rates.

(2) Utilities outside of ERCOT.

(A) Jurisdiction of other regulatory bodies. Processes utilized by non-ERCOT participants shall support the settlement of traditional wholesale markets and shall conform to all Federal Energy Regulatory Commission (FERC) rules and regulations.

(B) Transmission service. In connection with a utility's pilot project, the utility shall provide transmission service in accordance with the rates and delivery charges approved by the FERC. A utility in transition to an independent transmission company (ITC) model shall maintain on file with the commission a copy of its current FERC-approved open access transmission tariff (OATT), as well as any proposed amendments to the OATT submitted to FERC.

(C) Distribution service. In connection with a utility's pilot project, the utility shall provide distribution service in accordance with the rates for non-bypassable delivery charges approved by the commission, on an interim basis for application during the utility's pilot project, in the utility's unbundled cost of service case filed pursuant to PURA §39.201. Notwithstanding the provisions of §22.125 of this title, such interim rates shall not be subject to surcharge or refund if the rates ultimately established differ from the interim rates.

(3) Approval of tariffs. Tariffs implementing pilot project rates must be filed within ten days following the commission's determination of those rates. The commission shall approve such tariffs by May 31, 2001, and may do so administratively.

(i) Billing requirements.

(1) A utility shall bill a customer's REP for non-bypassable delivery charges in accordance with the tariffs established pursuant to subsection (h) of this section. The REP must pay these charges.

(2) A REP shall be responsible for ensuring that its retail customers are billed for electric service provided. A utility may bill retail customers at the request of a REP, provided that any such billing service shall be offered by the utility on comparable terms and conditions for any requesting REP.

(j) Evaluation of the pilot projects by the commission; reporting. The commission shall evaluate the pilot projects and the operational readiness of each power region, including its support systems, for customer choice.

(1) Evaluation criteria.

(A) Criteria for determining the readiness of a power region for customer choice may include the following:

(i) whether a power region's operational support systems were tested, and any problems that surfaced during the pilot project were adequately rectified;

(ii) whether electric system reliability was significantly affected in an adverse way; and

(iii) any other criteria the commission determines appropriate.

(B) Criteria for determining whether commission rules may need modifications or whether certain aspects of retail competition may require more detailed monitoring by the commission may include the following:

(i) whether participants in the pilot projects represented a broad base of customers of diverse demographic characteristics;

(ii) whether customers were aware of their rights and responsibilities with respect to customer choice, and whether such awareness increased for customers as a whole over the duration of the pilot projects;

(iii) whether a broad range of electric services and products were offered;

(iv) whether the quality of customer service with respect to retail customers was affected; and

(v) any other criteria the commission determines appropriate.

(2) Information used for evaluation of pilot projects. Evaluation of the pilot projects shall be based on information including, but not limited to:

(A) reports filed in accordance with paragraph (3) of this subsection;

(B) surveys of retail customers conducted in connection with the commission's customer education program; and

(C) the quantity and nature of complaints or inquiries regarding the pilot project received by the commission's Office of Customer Protection.

(3) Reporting by market participants and independent organizations. Each market participant and independent organization shall file two status reports with the commission under a single project number as designated by the commission's central records division. The first status report shall be filed on November 15, 2001, and the second no later than 30 days following the conclusion of the pilot project. In addition, a utility subject to PURA Chapter 39, Subchapter I, shall file semi-annual reports with the commission for the duration of its pilot project to permit the commission to monitor whether proportional representation is achieved in accordance with subsection (l)(3)(B) of this section.

(A) Reporting by utilities. Each status report from a utility shall include:

(i) The percent of load switched by month and cumulatively, for each customer class as defined in this section, including supporting data;

(ii) The number of customers that have withdrawn from the pilot project, by customer class;

(iii) A summary of any technical problems encountered during the reporting period, including resolutions or proposed resolutions, as appropriate, and supporting data;

(iv) A summary of all complaints related to the pilot project received by the utility during the reporting period, including a description of the resolution of the complaints;

(v) For a utility in transition to an ITC model, a progress report on the transition to the ITC, including any updates to the initial compliance filing; and

(vi) Any other information the utility believes will assist the commission in evaluating the pilot projects and the readiness of a power region for implementation of full customer choice.

(B) Reporting by REPs. Each status report from a REP shall include:

(i) A summary of any technical problems encountered during the reporting period, including resolutions or proposed resolutions, as appropriate, and supporting data;

(ii) A summary of all complaints related to the pilot project received by the REP during the reporting period, including a description of the resolution of the complaints; and

(iii) Any other information the REP believes will assist the commission in evaluating the pilot projects and the readiness of a power region for implementation of full customer choice.

(C) Reporting by an independent organization. Each status report from an independent organization shall include:

(i) Data from the registration agent regarding the average time elapsed between a switch request and the time the switch became effective;

(ii) Data from the registration agent, categorized by residential and non-residential customers, listing the total number of switch requests for each month, as well as the average number of switch requests per day for each month, and the total number of switch requests by zip code;

(iii) Data from the registration agent regarding the number of rejected switch requests resulting from the anti-slamming verification process;

(iv) A summary of all complaints, categorized by REP and by utility, related to the pilot project captured in the registration agent's systems during the reporting period, including a description of the resolution of the complaints;

(v) A summary from the registration agent and the independent organization, as applicable, of any technical problems encountered during the reporting period, including resolutions or proposed resolutions, as appropriate, and supporting data; and

(vi) An analysis by the independent transmission organization of system reliability during the pilot projects.

(D) Other reporting. At any time, a pilot project participant who is neither a utility nor a REP may provide the commission with any information the participant believes will assist the commission in evaluating the pilot projects and the readiness of a power region for implementation of full customer choice.

(4) Pilot implementation working group. The commission will establish a pilot implementation working group to oversee the pilot projects. The commission or its designee, based upon a recommendation of the pilot implementation working group, may revise the operational requirements of the pilot projects in order to resolve technical problems encountered by market participants.

(5) Extension of pilot projects. Should the commission determine that it is necessary to delay competition and extend the pilot projects, it must make such determination by December 31, 2001, except as otherwise authorized by PURA §39.405.

(k) Pilot project administration and recovery of associated costs.

(1) Each utility shall be responsible for administering the pilot project for its service area. Costs incurred by the utility to administer the pilot project may include expenses for required communications, third-party outsourcing for any or all administration tasks, enrollment process, or lottery administration.

(2) The utility may request recovery from the commission of pilot project administrative costs through:

(A) inclusion in the annual report filed pursuant to PURA §39.257; or

(B) deferral to future retail transmission or distribution rates.

(3) Parties do not waive the right to challenge the utility's ability to seek cost recovery for costs associated with the pilot projects at the time that such relief is sought. In addition, nothing in this section shall be construed as resolving the legal issue of whether utilities may recover costs associated with the pilot projects.

(l) Compliance filings.

(1) Timing and review. Each utility shall file a pilot project implementation plan with the commission under a project number designated by the commission's central records division. An implementation plan filed under this section shall be reviewed administratively to determine whether it is consistent with the principles, instructions and requirements set forth in this section.

(A) Each utility shall file its implementation plan within 45 days of the commission's adoption of this section. Such filings do not constitute contested case proceedings, but are designed to describe the particular application of this section to the filing utility for the purpose of providing information to the public and the commission.

(B) No later than 15 days after filing, interested parties may file comments on the implementation plan.

(C) No later than 25 days after filing, commission staff may file a recommendation concerning the implementation plan.

(D) Unless the commission or presiding officer determines otherwise, an implementation plan filed under this section shall be deemed approved on the thirtieth day after filing. If the implementation plan is not approved, the utility shall resubmit its plan following consultation with commission staff under a deadline established by the presiding officer.

(2) Content. The compliance filing shall address each provision of this section with a brief narrative explaining how the utility intends to implement that provision, including the utility's pilot project Internet website address and other contact information, as applicable. Numerical and formulaic data shall also be provided where applicable. Specifically, the compliance filing shall detail the calculation of the 5.0% load available for each customer class, including the 1.0% set-aside, and demonstrate the calculation with sample data. The final calculations containing actual data shall be filed with the commission by January 31, 2001.

(3) Additional requirements for non-ERCOT utilities.

(A) A utility subject to PURA Chapter 39, Subchapter I, shall include in its transition plan filed pursuant to PURA §39.402, a plan for extending its pilot project beyond January 1, 2002. The plan for extension of the pilot project shall contain:

(i) The utility's proposed increase(s) in pilot project participation beyond 5.0%, and proposed timing for such increase(s), including supporting data and workpapers; and

(ii) A report to the commission on market conditions in the utility's power region, including an analysis of the level of competition that the region can support and all relevant data and workpapers.

(B) A utility subject to PURA Chapter 39, Subchapter I, shall include in its compliance filing, a plan to ensure proportional representation in its pilot project between customers receiving service from the utility in an area that is certificated solely to the utility and those customers of the utility located in multiply certificated areas.

(C) A utility in transition to an ITC model shall include in its compliance filing:

(i) a narrative of how its plan for transition to an ITC is expected to affect the pilot project, including relevant supporting data and workpapers; and

(ii)an explanation of any requirements of market participants that are unique to its service area (e.g., registration with ITC, data aggregation requirements).

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on April 23, 2018.

TRD-201801813

Adriana Gonzales

Rules Coordinator

Public Utility Commission of Texas

Effective date: May 13, 2018

Proposal publication date: December 29, 2017

For further information, please call: (512) 936-7223


SUBCHAPTER Q. SYSTEM BENEFIT FUND

16 TAC §§25.451. 25.453 - 25.455, 25.457

The repeals are adopted under §14.002 of the Public Utility Regulatory Act, Tex. Util. Code Ann. §14.002 (West 2016 and Supp. 2017) (PURA) which provides the commission with the authority to make and enforce rules reasonably required in the exercise of its powers and jurisdiction, including rules of practice and procedure; PURA §17.007, which provides for a process by which a REP can identify low-income customers; PURA §39.101, which provides the commission with the authority to ensure that retail customer protections are established to entitle a customer to safe, reliable, and reasonably priced electricity.

Cross reference to statutes: Public Utility Regulatory Act §14.002, §14.052, §17.007, §39.101.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on April 23, 2018.

TRD-201801814

Adriana Gonzales

Rules Coordinator

Public Utility Commission of Texas

Effective date: May 13, 2018

Proposal publication date: December 29, 2017

For further information, please call: (512) 936-7223


SUBCHAPTER R. CUSTOMER PROTECTION RULES FOR RETAIL ELECTRIC SERVICE

16 TAC §§25.475, 25.478 - 25.480, 25.491, 25.497, 25.498

The amendments are adopted under §14.002 of the Public Utility Regulatory Act, Tex. Util. Code Ann. §14.002 (West 2016 and Supp. 2017) (PURA) which provides the commission with the authority to make and enforce rules reasonably required in the exercise of its powers and jurisdiction, including rules of practice and procedure; PURA §17.007, which provides for a process by which a REP can identify low-income customers; PURA §39.101, which provides the commission with the authority to ensure that retail customer protections are established to entitle a customer to safe, reliable, and reasonably priced electricity.

Cross reference to statutes: Public Utility Regulatory Act §14.002, §14.052, §17.007, §39.101.

§25.475.General Retail Electric Provider Requirements and Information Disclosures to Residential and Small Commercial Customers.

(a) Applicability. The requirements of this section apply to retail electric providers (REPs) and aggregators, when specifically stated, in connection with the provision of service and marketing to residential and small commercial customers. This section is effective April 1, 2010. REPs are not required to modify contract documents related to contracts entered into before this date, but shall provide notice of expiration as required by subsection (e) of this section.

(b) Definitions. The following words and terms, when used in this section shall have the following meanings, unless the context indicates otherwise.

(1) Contract--The Terms of Service document (TOS), the Electricity Facts Label (EFL), Your Rights as a Customer document (YRAC), and the documentation of enrollment pursuant to §25.474 of this title (relating to Selection of Retail Electric Provider).

(2) Contract documents--The TOS, EFL and YRAC.

(3) Contract expiration--The time when the initial term contract is completed. A new contract is initiated when the customer begins receiving service pursuant to the new EFL.

(4) Contract term--The time period the contract is in effect.

(5) Fixed rate product--A retail electric product with a term of at least three months for which the price (including recurring charges) for each billing period of the contract term is the same throughout the contract term, except that the price may vary from the disclosed amount solely to reflect actual changes in the Transmission and Distribution Utility (TDU) charges, changes to the Electric Reliability Council of Texas (ERCOT) or Texas Regional Entity administrative fees charged to loads or changes resulting from federal, state or local laws that impose new or modified fees or costs on a REP that are beyond the REP's control.

(6) Indexed product--A retail electric product for which the price, including recurring charges, can vary according to a pre-defined pricing formula that is based on publicly available indices or information and is disclosed to the customer, and to reflect actual changes in TDU charges, changes to the ERCOT or Texas Regional Entity administrative fees charged to loads or changes resulting from federal, state or local laws or regulatory actions that impose new or modified fees or costs on a REP that are beyond the REPs control. An indexed product may be for a term of three months or more, or may be a month-to-month contract.

(7) Month-to-month contract--A contract with a term of 31 days or less. A month-to-month contract may not contain a termination fee or penalty.

(8) Price--The cost for a retail electric product that includes all recurring charges excluding state and local sales taxes, and reimbursement for the state miscellaneous gross receipts tax.

(9) Recurring charge--A charge for a retail electric product that is expected to appear on a customer's bill in every billing period or appear in three or more billing periods in a twelve month period. A charge is not considered recurring if it will be billed by the TDU and passed on to the customer and will either not be applied to all customers of that class within the TDU territory, or cannot be known until the customer enrolls or requests a specific service.

(10) Term contract--A contract with a term in excess of 31 days.

(11) Variable price product--A retail product for which price may vary according to a method determined by the REP, including a product for which the price, can increase no more than a defined percentage as indexed to the customer's previous billing month's price. For residential customers, a variable price product can be only a month-to-month contract.

(c) General Retail Electric Provider requirements.

(1) General Disclosure Requirements.

(A) All written, electronic, and oral communications, including advertising, websites, direct marketing materials, billing statements, TOSs, EFLs and YRACs distributed by a REP or aggregator shall be clear and not misleading, fraudulent, unfair, deceptive, or anti-competitive. Prohibited communications include, but are not limited to:

(i) Using the term or terms "fixed" to market a product that does not meet the definition of a fixed rate product.

(ii) Suggesting, implying, or otherwise leading someone to believe that a REP or aggregator has been providing retail electric service prior to the time the REP or aggregator was certified or registered by the commission.

(iii) Suggesting, implying or otherwise leading someone to believe that receiving retail electric service from a REP will provide a customer with better quality of service from the TDU.

(iv) Falsely suggesting, implying or otherwise leading someone to believe that a person is a representative of a TDU or any REP or aggregator.

(v) Falsely suggesting, implying or otherwise leading someone to believe that a contract has benefits for a period of time longer than the initial contract term.

(B) Written and electronic communications shall not refer to laws, including commission rules without providing a link or website address where the text of those rules are available. All printed advertisements, electronic advertising over the Internet, and websites, shall include the REP's certified name or commission authorized business name, or the aggregator's registered name, and the number of the certification or registration.

(C) The TOS, EFL, and YRAC shall be provided to each customer upon enrollment. Each document shall be provided to the customer whenever a change is made to the specific document and upon a customer's request, at any time free of charge.

(D) A REP shall retain a copy of each version of the TOS, EFL, and YRAC during the time the plan is in effect for a customer and for four years after the contract ceases to be in effect for any customer. REPs shall provide such documents at the request of the commission or its staff.

(2) General contracting requirements.

(A) A TOS, EFL, and YRAC shall be complete, shall be written in language that is clear, plain and easily understood, and shall be printed in paragraphs of no more than 250 words in a font no smaller than 10 point. References to laws including commission rules in these documents shall include a link or internet address to the full text of the law.

(B) All contract documents shall be available to the commission to post on its customer education website (if the REP chooses to post offers to the website).

(C) A contract is limited to service to a customer at a location specified in the contract. If the customer moves from the location, the customer is under no obligation to continue the contract at another location. The REP may require a customer to provide evidence that it is moving. There shall be no early termination fee assessed to the customer as a result of the customer's relocation if the customer provides a forwarding address and, if required, reasonable evidence that the customer no longer occupies the location specified in the contract.

(D) A TOS and EFL shall disclose the type of product being described, using one of the following terms: fixed rate product, indexed product or a variable price product.

(E) A REP shall not use a credit score, a credit history, or utility payment data as the basis for determining the price for electric service for a product with a contract term of 12 months or less for an existing residential customer or in response to an applicant's request to become a residential customer.

(F) In any dispute between a customer and a REP concerning the terms of a contract, any vagueness, obscurity, or ambiguity in the contract will be construed in favor of the customer.

(G) For a variable price product, the REP shall disclose on the REP's website and through a toll-free number the current price and, for residential customers, one year price history, or history for the life of the product, if it has been offered less than one year. A REP shall not rename a product in order to avoid disclosure of price history. The EFL of a variable price product or indexed product shall include a notice of how the current price and, if applicable, historical price information may be obtained.

(H) A REP shall comply with its contracts.

(3) Specific contract requirements.

(A) The contract term shall be conspicuously disclosed.

(B) The start and end dates of the contract shall be available to the customer upon request. If the REP cannot determine the start date, the REP may estimate the start date. After the start date is known, the REP shall specify the end date of the contract by:

(i) specifying a calendar date; or

(ii) reference to the first meter read on or after a specific calendar date.

(C) If a REP specifies a calendar date as the end date, the REP may bill the term contract price through the first meter read on or after the end date of the contract.

(4) Website requirements.

(A) Each REP that offers residential retail electric products for enrollment on its website shall prominently display the EFL for any products offered without a person having to enter any personal information other than zip code and information that allows determination of the type of offer the consumer wishes to review. Person-specific information shall not be required.

(B) The EFL for each product shall be printable in no more than a two page format. The EFL, TOS, and YRAC for any products offered for enrollment on the website shall be available for viewing or downloading.

(d) Changes in contract and price and notice of changes. A REP may make changes to the terms and conditions of a contract or to the price of a product as provided for in this section. Changes in term (length) of a contract require the customer to enter into a new contract and may not be made by providing the notice described in paragraph (3) of this subsection.

(1) Contract changes other than price.

(A) A REP may not change the price (other than as allowed by paragraph (2) of this subsection) or contract term of a term contract for a retail electric product, during its term; but may change any other provision of the contract, with notice under paragraph (3) of this subsection.

(B) A REP may not change the terms and conditions of a month-to-month product, indexed or variable price products, unless it provides notice under paragraph (3) of this subsection.

(2) Price changes.

(A) A REP may only change the price of a fixed rate product, an indexed product, or a variable product consistent with the definitions in this section and according to the product's EFL. Such price changes do not require notice under paragraph (3) of this subsection.

(B) For a fixed rate product, each bill shall either show the price changes on one or more separate line items, or shall include a conspicuous notice stating that the amount billed may include price changes allowed by law or regulatory actions.

(C) Each residential bill for a variable price product shall include a statement informing the customer how to obtain information about the price that will apply on the next bill.

(3) Notice of changes to terms and conditions. A REP must provide written notice to its customers at least 14 days in advance of the date that the change in the contract will be applied to the customer's bill or take effect. Notice is not required for a change that benefits the customer.

(4) Contents of the notice to change terms and conditions. The notice shall:

(A) be provided in or with the customer's bill or in a separate document;

(B) include the following statement, "Important notice regarding changes to your contract" clearly and conspicuously in the notice;

(C) identify the change and the specific contract provisions that address the change;

(D) clearly specify what actions the customer needs to take if the customer does not accept the proposed changes to the contract;

(E) state in bold lettering that if the new terms are not acceptable to the customer, the customer may terminate the contract and no termination penalty shall apply for 14 days from the date that the notice is sent to the customer but may apply if action is taken after the 14 days have expired. No such statement is required if the customer would not be subject to a termination penalty under any circumstances; and

(F) state in bold lettering that establishing service with another REP may take up to seven business days.

(e) Contract expiration and renewal offers. The REP shall send a written notice of contract expiration at least 30 days or one billing cycle prior to the date of contract expiration, but no more than 60 days or two billing cycles in advance of contract expiration for a residential customer, and at least 14 days but no more than 60 days or two billing cycles in advance of contract expiration for a small commercial customer. The REP shall send the notice by mail to a residential customer or shall send the required notice to a customer's e-mail address if available to the REP and if the customer has requested to receive contract-related notices electronically. The REP shall send the notice to a small commercial customer by mail or may send the notice to the customer's e-mail address if available to the REP and, if the customer has requested to receive contract-related notices electronically. Nothing in this section shall preclude a REP from offering a new contract to the customer at any other time during the contract term.

(1) Contract Expiration.

(A) If a customer takes no action in response to a notice of contract expiration for the continued receipt of retail electric service upon the contract's expiration, the REP shall serve the customer pursuant to a default renewal product that is a month-to-month product.

(B) Written notice of contract expiration shall be provided in or with the customer's bill, or in a separate document.

(i) If notice is provided with a residential customer's bill, the notice shall be printed on a separate page. A statement shall be included on the outside of the envelope sent to a residential customer's billing address by mail and in the subject line on the e-mail (if the REP sends the notice by e-mail) that states, "Contract Expiration Notice. See Enclosed."

(ii) If the notice is provided in or with a small commercial customer's bill, the REP must include a statement on the outside of the billing envelope or in the subject line of an electronic bill that states, "Contract Expiration Notice" or "Contract Expiration Notice. See Enclosed."; or

(iii) If notice is provided in a separate document, a statement shall be included on the outside of the envelope and in the subject line of the e-mail (if customer has agreed to receive official documents by e-mail) that states, "Contract Expiration Notice. See Enclosed." for residential customers or for small commercial customers, "Contract Expiration Notice" or "Contract Expiration Notice. See Enclosed."

(C) A written notice of contract expiration (whether with the bill or in a separate envelope) shall set out the following:

(i) The date as provided for in subsection (c)(3)(B) of this section that the existing contract will expire.

(ii) If the REP provided a calendar date as the end date for the contract, a statement in bold lettering no smaller than 12 point font that no termination penalty shall apply to residential and small commercial customers 14 days prior to the date stated as the expiration date in the notice. In addition, a description of any fees or charges associated with the early termination of a residential customer's fixed rate product that would apply before 14 days prior to the date stated as the expiration date in the notice must be provided. No such statements are required if the original contract did not contain a termination fee.

(iii) If the REP defined the contract end date by reference to the first meter read on or after a specific calendar date, a statement in bold lettering no smaller than 12 point font that no termination penalty shall apply to residential customers after receipt of the contract expiration notice, or that no termination penalty shall apply to small commercial customers for 14 days prior to the contract end date. No such statement is required if the original contract did not contain a termination fee.

(iv) A description of any renewal offers the REP chooses to make available to the customer and the location of the TOS and EFL for each of those products and a description of actions the customer needs to take to continue to receive service from the REP under the terms of any of the described renewal offers and the deadline by which actions must be taken.

(v) A copy of the EFL for the default renewal product if the customer takes no action, or if the EFL is not included with the contract expiration notice, the REP must provide the EFL to the customer at least 14 days before the expiration of the contract using the same delivery method as was used for the notice. The contract expiration notice must specify how and when the EFL will be made available to the customer.

(vi) A statement that if the customer takes no action, service to the customer will continue pursuant to the EFL for the default renewal product that shall be included as part of the notice of contract expiration. The TOS for the default renewal product shall be included as part of the notice, unless the TOS applicable to the customer's existing service also applies to the default renewal product.

(vii) A statement that the default service is month-to month and may be cancelled at any time with no fee.

(2) Affirmative consent. A customer that is currently receiving service from a REP may be re-enrolled with the REP for service with the same product under which the customer is currently receiving service, or a different product, by conducting an enrollment pursuant to §25.474 of this title or by obtaining the customer's consent in a recording, electronic document, or written letter of authorization consistent with the requirements of this subsection. Affirmative consent is not required when a REP serves the customer under a default renewal product pursuant to paragraph (1) of this subsection. Each recording, electronic document, or written consent form must:

(A) Indicate the customer's name, billing address, service address (for small commercial customers, the ESI ID may be used rather than the service address);

(B) Indicate the identification number of the TOS and EFL under which the customer will be served;

(C) Indicate if the customer has received, or when the customer will receive copies of the TOS, EFL and YRAC;

(D) Indicate the price(s) which the customer is agreeing to pay;

(E) Indicate the date or estimated date of the re-enrollment, the contract term, and the estimated start and end dates of contract term;

(F) Affirmatively inquire whether the customer has decided to enroll for service with the product, and contain the customer's affirmative response; and

(G) Be entirely in plain, easily understood language, in the language that the customer has chosen for communications.

(f) Terms of service document. The following information shall be conspicuously contained in the TOS:

(1) Identity and contact information. The REP's certified name and business name (dba) (if applicable), mailing address, e-mail and Internet address (if applicable), certification number, and a toll-free telephone number (with hours of operation and time-zone reference).

(2) Pricing and payment arrangements.

(A) Description of the amount of any routine non-recurring charges resulting from a move-in or switch that may be charged to the customer, including but not limited to an out-of-cycle meter read, and connection or reconnection fees;

(B) For small commercial customers, a description of the demand charge and how it will be applied, if applicable;

(C) An itemization, including name and cost, of any non-recurring charges for services that may be imposed on the customer for the retail electric product, including an application fee, charges for default in payment or late payment, and returned checks charges;

(D) A description of any collection fees or costs that may be assessed to the customer by the REP and that cannot be quantified in the TOS; and

(E) A description of payment arrangements and bill payment assistance programs offered by the REP.

(3) Deposits. If the REP requires deposits from its customers:

(A) a description of the conditions that will trigger a request for a deposit;

(B) the maximum amount of the deposit or the manner in which the deposit amount will be determined;

(C) a statement that interest will be paid on the deposit at the rate approved by the commission, and the conditions under which the customer may obtain a refund of a deposit;

(D) an explanation of the conditions under which a customer may establish satisfactory credit pursuant to §25.478 of this title (relating to Credit Requirements and Deposits); and

(E) if applicable, the customer's right to post a letter of guarantee in lieu of a deposit pursuant to §25.478(i) of this title.

(4) Rescission, Termination and Disconnection.

(A) In a conspicuous and separate paragraph or box:

(i) A description of the right of a customer, for switch requests, to rescind service without fee or penalty of any kind within three federal business days after receiving the TOS, pursuant to §25.474 of this title; and

(ii) Detailed instructions for rescinding service, including the telephone number and, if available, facsimile number or e-mail address that the customer may use to rescind service.

(B) A statement as to how service can be terminated and any penalties that may apply;

(C) A statement of customer's ability to terminate service without penalty if customer moves to another premises and provides evidence that it is moving, if required, and a forwarding address; and

(D) If the REP has disconnection authority, pursuant to §25.483 of this title (relating to Disconnection of Service), a statement that the REP may order disconnection of the customer for non-payment.

(5) Antidiscrimination. A statement informing the customer that the REP cannot deny service or require a prepayment or deposit for service based on a customer's race, creed, color, national origin, ancestry, sex, marital status, lawful source of income, level of income, disability, familial status, location of a customer in a economically distressed geographic area, or qualification for low income or energy efficiency services. For residential customers, a statement informing the customer that the REP cannot use a credit score, a credit history, or utility payment data as the basis for determining the price for electric service for a product with a contract term of 12 months or less.

(6) Other terms. Any other material terms and conditions, including exclusions, reservations, limitations of liability, or special equipment requirements, that are a part of the contract for the retail electric product.

(7) Contract expiration notice. For a term contract, the TOS shall contain a statement informing the customer that a contract expiration notice will be sent at least 14 days prior to the end of the initial contract term. The TOS shall also state that if the customer fails to take action to ensure the continued receipt of retail electric service upon the contract's expiration, the customer will continue to be served by the REP automatically pursuant to a default renewal product, which shall be a month-to-month product.

(8) A statement describing the conditions under which the contract can change and the notice that will be provided if there is a change.

(9) Version number. A REP shall assign an identification number to each version of its TOS, and shall publish the number on the terms of service document.

(g) Electricity Facts Label. The EFL shall be unique for each product offered and shall include the information required in this subsection. Nothing in this subsection precludes a REP from charging a price that is less than its EFL would otherwise provide.

(1) Identity and contact information. The REP's certified name and business name (dba) (if applicable), mailing address, e-mail and Internet address (if applicable), certification number, and a toll-free telephone number (with hours of operation and time-zone reference).

(2) Pricing disclosures. Pricing information shall be disclosed by a REP in an EFL. The EFL shall state specifically whether the product is a fixed rate, variable price or indexed product.

(A) For a fixed rate product, the EFL shall provide the total average price for electric service reflecting all recurring charges, excluding state and local sales taxes, and reimbursement for the state miscellaneous gross receipts tax, to the customer.

(B) For an indexed product, the EFL shall provide sample prices for electric service reflecting all recurring charges, excluding state and local sales taxes, and reimbursement for the state miscellaneous gross receipts tax, resulting from a reasonable range of values for the inputs to the pre-defined pricing formula.

(C) For a variable price product, the EFL shall provide the total average price for electric service for the first billing cycle reflecting all recurring charges, including any TDU charges that may be passed through and excluding state and local sales taxes, and reimbursement for the state miscellaneous gross receipts tax, to the customer. Actual changes in TDU charges, changes to the ERCOT or Texas Regional Entity administrative fees charge to loads or changes resulting from federal, state or local laws or regulatory actions that impose new or modified fees or costs on a REP that were not implemented prior to the issuance of the EFL and were not included in the average price calculation may be directly passed through to customers beginning with the customer's first billing cycle.

(D) The total average price for electric service shall be expressed in cents per kilowatt hour, rounded to the nearest one-tenth of one cent for the following usage levels:

(i) For residential customers, 500, 1,000 and 2,000 kilowatt hours per month; and

(ii) For small commercial customers, 1,500, 2,500, and 3,500 kilowatt hours per month. If demand charges apply assume a 30 percent load factor.

(E) If a REP combines the charges for retail electric service with charges for any other product, the REP shall:

(i) If the electric product is sold separately from the other products, disclose the total price for electric service separately from other products; and

(ii) If the REP does not permit a customer to purchase the electric product without purchasing the other products or services, state the total charges for all products and services as the price of the total electric service. If the product has a one-time cost up front, for the purposes of the average price calculation, the cost of the product may be figured in over a 12-month period with 1/12 of the cost being attributed to a single month.

(F) The following shall be included on the EFL for specific product types:

(i) For indexed products, the formula used to determine an indexed product, including a website and phone number customers may contact to determine the current price.

(ii) For a variable price product that increases no more than a defined percentage as indexed to the customer's previous billing month's price, a notice in bold type no smaller than 12 point font: "Except for price changes allowed by law or regulatory action, this price is the price that will be applied during your first billing cycle; this price may increase by no more than {insert percentage} percent from month-to-month." For residential customers, the following additional statement is required: "Please review the historical price of this product available at {insert specific website address and toll-free telephone number}." In the disclosure chart, the box describing whether the price can change during the contract period shall include the following statement: "The price applied in the first billing cycle may be different from the price in this EFL if there are changes in TDSP charges; changes to the Electric Reliability Council of Texas or Texas Regional Entity administrative fees charged to loads; or changes resulting from federal, state or local laws or regulatory actions that impose new or modified fees or costs that are outside our control."

(iii) For all other variable price products, a notice in bold type no smaller than 12 point font: "Except for price changes allowed by law or regulatory action, this price is the price that will be applied during your first billing cycle; this price may change in subsequent months at the sole discretion of {insert REP name}. In the disclosure chart, the box describing whether the price can change during the contract period shall include the following statement: "The price applied in the first billing cycle may be different from the price in this EFL if there are changes in TDSP charges; changes to the Electric Reliability Council of Texas or Texas Regional Entity administrative fees charged to loads; or changes resulting from federal, state or local laws or regulatory actions that impose new or modified fees or costs that are outside our control." For residential customers, the following additional statement is required: "Please review the historical price of this product available at {insert specific website address and toll-free telephone number}."

(3) Fee Disclosures.

(A) If customers may be subject to a special charge for underground service or any similar charge that applies only in a part of the TDU service area, the EFL shall include a statement in the electricity price section that some customers will be subject to a special charge that is not included in the total average price for electric service and shall disclose how the customer can determine the price and applicability of the special charge.

(B) A listing of all fees assessed by the REP that may be charged to the customer and whether the fee is included in the recurring charges.

(4) Term Disclosure. EFL shall include disclosure of the length of term, minimum service term, if any, and early termination penalties, if any.

(5) Renewable Energy Disclosures. The EFL shall include the percentage of renewable energy of the electricity product and the percentage of renewable energy of the statewide average generation mix.

(6) Format of Electricity Facts Label. REPs must use the following format for the EFL with the pricing chart and disclosure chart shown. The additional language is for illustrative purposes. It does not include all reporting requirements as outlined above. Such subsections should be referred to for determination of the required reporting items on the EFL. Each EFL shall be printed in type no smaller than ten points in size, unless a different size is specified in this section, and shall be formatted as shown in this paragraph:

Figure: 16 TAC §25.475(g)(6) (No change.)

(7) Version number. A REP shall assign an identification number to each version of its EFL, and shall publish the number on the EFL.

(h) Your Rights as a Customer disclosure. The information set out in this section shall be included in a REP's "Your Rights as a Customer" document, to summarize the standard customer protections provided by this subchapter or additional protections provided by the REP.

(1) A YRAC document shall be consistent with the TOS for the retail product.

(2) The YRAC document shall inform the customer of the REP's complaint resolution policy pursuant to §25.485 of this title (relating to Customer Access and Complaint Handling) and payment arrangements and deferred payment policies pursuant to §25.480 of this title (relating to Bill Payment and Adjustments).

(3) The YRAC document shall inform the customer of the REP's procedures for reporting outages and the steps necessary to have service restored or reconnected after an involuntary suspension or disconnection.

(4) The YRAC document shall inform the customer of the customer's right to have the meter tested pursuant to §25.124 of this title (relating to Meter Testing), or in accordance with the tariffs of a transmission and distribution utility, a municipally owned utility, or an electric cooperative, as applicable, and the REP's ability in all cases to make that request on behalf of the customer by a standard electronic market transaction, and the customer's right to be instructed on how to read the meter, if applicable.

(5) The YRAC document shall inform the customer of the availability of:

(A) Financial and energy assistance programs for residential customers;

(B) Any special services such as readers or notices in Braille or TTY;

(C) Special policies or programs available to residential customers with physical disabilities, including residential customers who have a critical need for electric service to maintain life support systems; and

(D) Any available discounts that may be offered by the REP for qualified low-income residential customers. A REP may comply with this requirement by providing the customer with instructions for how to inquire about such discounts.

(6) The YRAC document shall inform the customer of the following customer rights and protections:

(A) Unauthorized switch protections applicable under §25.495 of this title (relating to Unauthorized Change of Retail Electric Provider);

(B) The customer's right to dispute unauthorized charges on the customer's bill as set forth in §25.481 of this title (relating to Unauthorized Charges);

(C) Protections relating to disconnection of service pursuant to §25.483 of this title;

(D) Non-English language requirements pursuant to §25.473 of this title (relating to Non-English Language Requirements);

(E) Availability of a Do Not Call List pursuant to §25.484 of this title (relating to Electric No-Call List) and §26.37 of this title (relating to Texas No-Call List); and

(F) Privacy rights regarding customer proprietary information as provided by §25.472 of this title (relating to Privacy of Customer Information).

(7) Identity and contact information. The REP's certified name and business name (dba), certification number, mailing address, e-mail and Internet address (if applicable), and a toll-free telephone number (with hours of operation and time-zone reference) at which the customer may obtain information concerning the product.

(i) Advertising claims. If a REP or aggregator advertises or markets the specific benefits of a particular electric product, the REP or aggregator shall provide the name of the electric product offered in the advertising or marketing materials to the commission or its staff, upon request. All advertisements and marketing materials distributed by or on behalf of a REP or aggregator shall comply with this section. REPs and aggregators are responsible for representations to customers and prospective customers by employees or other agents of the REP concerning retail electric service that are made through advertising, marketing or other means.

(1) Print advertisements. Print advertisements and marketing materials, including direct mail solicitations that make any claims regarding price, savings, or environmental quality for an electricity product of the REP compared to a product offered by another REP shall include the EFL of the REP making the claim. In lieu of including an EFL, the following statement shall be provided: "You can obtain important standardized information that will allow you to compare this product with other offers. Contact (name, telephone number, and Internet address (if available) of the REP)." If the REPs phone number or website address is included on the advertisement, such phone number or website address is not required in the disclaimer statement. Upon request, a REP shall provide to the commission the contract documents relating to a product being advertised and any information used to develop or substantiate comparisons made in the advertisement.

(2) Television, radio, and internet advertisements. A REP shall include the following statement in any television, Internet, or radio advertisement that makes a specific claim about price, savings, or environmental quality for an electricity product of the REP compared to a product offered by another REP: "You can obtain important standardized information that will allow you to compare this product with other offers. Contact (name, telephone number and website (if available) of the REP)." If the REPs phone number or website address is included on the advertisement, such phone number or website address is not required in the disclaimer statement. This statement is not required for general statements regarding savings or environmental quality, but shall be provided if a specific price is included in the advertisement, or if a specific statement about savings or environmental quality compared to another REP is made. Upon request, a REP shall provide to the commission the contract documents relating to a product being advertised and any information used to develop or substantiate comparisons made in the advertisement.

(3) Outdoor advertisements. A REP shall include, in a font size and format that is legible to the intended audience, its certified name or commission authorized business name, certification number, telephone number and Internet address (if available).

(4) Renewable energy claims. A REP shall authenticate its sales of renewable energy in accordance with §25.476 of this title (relating to Renewable and Green Energy Verification). If a REP relies on supply contracts to authenticate its sales of renewable energy, it shall file a report with the commission, not later than March 15 of each year demonstrating its compliance with this paragraph and §25.476 of this title.

§25.478.Credit Requirements and Deposits.

(a) Credit requirements for residential customers. A retail electric provider (REP) may require a residential customer or applicant to establish and maintain satisfactory credit as a condition of providing service pursuant to the requirements of this section.

(1) Establishment of satisfactory credit shall not relieve any customer from complying with the requirements for payment of bills by the due date of the bill.

(2) The credit worthiness of spouses established during shared service in the 12 months prior to their divorce will be equally applied to both spouses for 12 months immediately after their divorce.

(3) A residential customer or applicant seeking to establish service with an affiliated REP or provider of last resort (POLR) can demonstrate satisfactory credit using one of the criteria listed in subparagraphs (A) through (E) of this paragraph.

(A) A residential customer or applicant may be deemed as having established satisfactory credit if the customer or applicant:

(i) has been a customer of any REP or an electric utility within the two years prior to the request for electric service;

(ii) is not delinquent in payment of any such electric service account; and

(iii) during the last 12 consecutive months of service was not late in paying a bill more than once.

(B) A residential customer or applicant may be deemed as having established satisfactory credit if the customer or applicant possesses a satisfactory credit rating obtained through a consumer reporting agency, as defined by the Federal Trade Commission.

(C) A residential customer or applicant may be deemed as having established satisfactory credit if the customer or applicant is 65 years of age or older and the customer is not currently delinquent in payment of any electric service account.

(D) A residential customer or applicant may be deemed as having established satisfactory credit if the customer or applicant has been determined to be a victim of family violence as defined in the Texas Family Code §71.004, by a family violence center as defined in Texas Human Resources Code §51.002, by treating medical personnel, by law enforcement personnel, by the Office of a Texas District Attorney or County Attorney, by the Office of the Attorney General, or by a grantee of the Texas Equal Access to Justice Foundation. This determination shall be evidenced by submission of a certification letter developed by the Texas Council on Family Violence. The certification letter may be submitted directly by use of a toll-free fax number to the affiliated REP or POLR.

(E) A residential customer or applicant seeking to establish service may be deemed as having established satisfactory credit if the customer is medically indigent. In order for a customer or applicant to be considered medically indigent, the customer or applicant must make a demonstration that the following criteria are met. Such demonstration must be made annually:

(i) the customer's or applicant's household income must be at or below 150% of the poverty guidelines as certified by a governmental entity or government funded energy assistance program provider; and

(ii) the customer or applicant or the spouse of the customer or applicant must have been certified by that person's physician as being unable to perform three or more activities of daily living as defined in 22 TAC §224.4, or the customer's or applicant's monthly out-of-pocket medical expenses must exceed 20% of the household's gross income. For the purposes of this subsection, the term "physician" shall mean any medical doctor, doctor of osteopathy, nurse practitioner, registered nurse, state-licensed social workers, state-licensed physical and occupational therapists, and an employee of an agency certified to provide home health services pursuant to 42 U.S.C. §1395 et seq.

(4) A residential customer or applicant seeking to establish service with a REP other than an affiliated REP or POLR can demonstrate satisfactory credit using one of the criteria listed in subparagraphs (A) through (B) of this paragraph. Notice of these options for customers or applicants shall be included in any written or oral notice to a customer or applicant when a deposit is requested. A REP other than an affiliated REP or POLR may establish additional methods by which a customer or applicant not meeting the criteria of subparagraphs (A) or (B) of this paragraph can demonstrate satisfactory credit, so long as such criteria are not discriminatory pursuant to §25.471(c) of this title (relating to General Provisions of Customer Protection Rules).

(A) The residential customer or applicant is 65 years of age or older and the customer is not currently delinquent in payment of any electric service account.

(B) The customer or applicant has been determined to be a victim of family violence as defined in the Texas Family Code §71.004, by a family violence center as defined in Texas Human Resources Code §51.002, by treating medical personnel, by law enforcement personnel, by the Office of a Texas District Attorney or County Attorney, by the Office of the Attorney General, or by a grantee of the Texas Equal Access to Justice Foundation. This determination shall be evidenced by submission of a certification letter developed by the Texas Council on Family Violence. The certification letter may be submitted directly by use of a toll-free fax number to the REP.

(5) The REP may obtain payment history information from any REP that has served the applicant in the previous two years or from a consumer reporting agency, as defined by the Federal Trade Commission. The REP shall obtain the customer's or applicant's authorization prior to obtaining such information from the customer's or applicant's prior REP. A REP shall maintain payment history information for two years after a customer's electric service has been terminated or disconnected in order to be able to provide credit history information at the request of the former customer.

(b) Credit requirements for non-residential customers. A REP may establish nondiscriminatory criteria pursuant to §25.471(c) of this title to evaluate the credit requirements for a non-residential customer or applicant and apply those criteria in a nondiscriminatory manner. If satisfactory credit cannot be demonstrated by the non-residential customer or applicant using the criteria established by the REP, the customer may be required to pay an initial or additional deposit. No such deposit shall be required if the customer or applicant is a governmental entity.

(c) Initial deposits for applicants and existing customers.

(1) If satisfactory credit cannot be demonstrated by a residential applicant, a REP may require the applicant to pay a deposit prior to receiving service.

(2) An affiliated REP or POLR shall offer a residential customer or applicant who is required to pay an initial deposit the option of providing a written letter of guarantee pursuant to subsection (i) of this section, instead of paying a cash deposit.

(3) A REP shall not require an initial deposit from an existing customer unless the customer was late paying a bill more than once during the last 12 months of service or had service terminated or disconnected for nonpayment during the last 12 months of service. The customer may be required to pay this initial deposit within ten days after issuance of a written disconnection notice that requests such deposit. The disconnection notice may be combined with or issued concurrently with the request for deposit. The disconnection notice shall comply with the requirements in §25.483(m) of this title (relating to Disconnection of Service).

(d) Additional deposits by existing customers.

(1) A REP may request an additional deposit from an existing customer if:

(A) the average of the customer's actual billings for the last 12 months are at least twice the amount of the original average of the estimated annual billings; and

(B) a termination or disconnection notice has been issued or the account disconnected within the previous 12 months.

(2) A REP may require the customer to pay an additional deposit within ten days after the REP has requested the additional deposit.

(3) A REP may disconnect service if the additional deposit is not paid within ten days of the request, provided a written disconnection notice has been issued to the customer. A disconnection notice may be combined with or issued concurrently with the written request for the additional deposit. The disconnection notice shall comply with the requirements in §25.483(m) of this title.

(e) Amount of deposit.

(1) The total of all deposits, initial and additional, required by a REP from any residential customer or applicant:

(A) shall not exceed an amount equivalent to the greater of:

(i) one-fifth of the customer's estimated annual billing; or

(ii) the sum of the estimated billings for the next two months.

(B) A REP may base the estimated annual billing for initial deposits for applicants on a reasonable estimate of average usage for the customer class. If a REP requests additional or initial deposits from existing customers, the REP shall base the estimated annual billing on the customer's actual historical usage, to the extent that the historical usage is available. After 12 months of service with a REP, a customer may request that a REP recalculate the required deposit based on actual historical usage of the customer.

(2) For the purpose of determining the amount of the deposit, the estimated billings shall include only charges for electric service that are disclosed in the REP's terms of service document provided to the customer or applicant.

(f) Interest on deposits. A REP that requires a deposit pursuant to this section shall pay interest on that deposit at an annual rate at least equal to that set by the commission on or before December 1 of the preceding calendar year, pursuant to Texas Utilities Code §183.003 (relating to Rate of Interest). If a deposit is refunded within 30 days of the date of deposit, no interest payment is required. If the REP keeps the deposit more than 30 days, payment of interest shall be made from the date of deposit.

(1) Payment of the interest to the customer shall be made annually, if requested by the customer, or at the time the deposit is returned or credited to the customer's account.

(2) The deposit shall cease to draw interest on the date it is returned or credited to the customer's account.

(g) Notification to customers. When a REP requires a customer to pay a deposit, the REP shall provide the customer written information about the provider's deposit policy, the customer's right to post a guarantee in lieu of a cash deposit if applicable, how a customer may be refunded a deposit, and the circumstances under which a provider may increase a deposit. These disclosures shall be included either in the Your Rights as a Customer disclosure or the REP's terms of service document.

(h) Records of deposits.

(1) A REP that collects a deposit shall keep records to show:

(A) the name and address of each depositor;

(B) the amount and date of the deposit; and

(C) each transaction concerning the deposit.

(2) A REP that collects a deposit shall issue a receipt of deposit to each customer or applicant paying a deposit or reflect the deposit on the customer's bill statement. A REP shall provide means for a depositor to establish a claim if the receipt is lost.

(3) A REP shall maintain a record of each unclaimed deposit for at least four years.

(4) A REP shall make a reasonable effort to return unclaimed deposits.

(i) Guarantees of residential customer accounts. A guarantee agreement in lieu of a cash deposit issued by any REP, if applicable, shall conform to the following requirements:

(1) A guarantee agreement between a REP and a guarantor shall be in writing and shall be for no more than the amount of deposit the provider would require on the customer's account pursuant to subsection (e) of this section. The amount of the guarantee shall be clearly indicated in the signed agreement. The REP may require, as a condition of the continuation of the guarantee agreement, that the guarantor remain a customer of the REP, have no past due balance, and have no more than one late payment in a 12-month period during the term of the guarantee agreement.

(2) The guarantee shall be voided and returned to the guarantor according to the provisions of subsection (j) of this section.

(3) Upon default by a residential customer, the guarantor of that customer's account shall be responsible for the unpaid balance of the account only up to the amount agreed to in the written agreement.

(4) If the guarantor ceases to be a customer of the REP or has more than one late payment in a 12-month period during the term of the guarantee agreement, the provider may treat the guarantee agreement as in default and demand a cash deposit from the residential customer as a condition of continuing service.

(5) The REP shall provide written notification to the guarantor of the customer's default, the amount owed by the guarantor, and the due date for the amount owed.

(A) The REP shall allow the guarantor 16 days from the date of notification to pay the amount owed on the defaulted account. If the sixteenth day falls on a holiday or weekend, the due date shall be the next business day.

(B) The REP may transfer the amount owed on the defaulted account to the guarantor's own electric service bill provided the guaranteed amount owed is identified separately on the bill as required by §25.479 of this title (relating to Issuance and Format of Bills).

(6) The REP may initiate disconnection for nonpayment of the guaranteed amount only if the disconnection of service was disclosed in the written guarantee agreement, and only after proper notice as described by paragraph (5) of this subsection or §25.483 of this title.

(j) Refunding deposits and voiding letters of guarantee.

(1) A deposit held by a REP shall be refunded when the customer has paid bills for service for 12 consecutive residential billings or for 24 consecutive non-residential billings without having any late payments. A REP may refund the deposit to a customer via a bill credit. REPs shall comply with this provision as soon as practicable, but no later than August 31, 2004.

(2) Once the REP is no longer the REP of record for a customer or if service is not established with the REP, the REP shall either transfer the deposit plus accrued interest to the customer's new REP or promptly refund the deposit plus accrued interest to the customer, as agreed upon by the customer and both REPs. The REP may subtract from the amount refunded any amounts still owed by the customer to the REP. If the REP obtained a guarantee, such guarantee shall be cancelled to the extent that it is not needed to satisfy any outstanding balance owed by the customer. Alternatively, the REP may provide the guarantor with written documentation that the contract has been cancelled to the extent that the guarantee is not needed to satisfy any outstanding balance owed by the customer.

(3) If a customer's or applicant's service is not connected, or is disconnected, or the service is terminated by the customer, the REP shall promptly void and return to the guarantor all letters of guarantee on the account or provide written documentation that the guarantee agreement has been voided, or refund the customer's or applicant's deposit plus accrued interest on the balance, if any, in excess of the unpaid bills for service furnished. Similarly, if the guarantor's service is not connected, or is disconnected, or the service is terminated by the customer, the REP shall promptly void and return to the guarantor all letters of guarantee or provide written documentation that the guarantees have been voided. This provision does not apply when the customer or guarantor moves or changes the address where service is provided, as long as the customer or guarantor remains a customer of the REP.

(4) A REP shall terminate a guarantee agreement when the customer has paid its bills for 12 consecutive months without service being disconnected for nonpayment and without having more than two delinquent payments.

(k) Re-establishment of credit. A customer or applicant who previously has been a customer of the REP and whose service has been terminated or disconnected for nonpayment of bills or theft of service by that customer (meter tampering or bypassing of meter) may be required, before service is reinstated, to pay all amounts due to the REP or execute a deferred payment agreement, if offered, and reestablish credit.

(l) Upon sale or transfer of company. Upon the sale or transfer of a REP or the designation of an alternative POLR for the customer's electric service, the seller or transferee shall provide the legal successor to the original provider all deposit records.

§25.479.Issuance and Format of Bills.

(a) Application. This section applies, beginning April 1, 2010, to a retail electric provider (REP) that is responsible for issuing electric service bills to retail customers, unless the REP is issuing a consolidated bill (both energy services and transmission and distribution services) on behalf of an electric cooperative or municipally owned utility. This section does not apply to a municipally owned utility or electric cooperative issuing bills to its customers in its own service territory.

(b) Frequency and delivery of bills.

(1) A REP shall issue a bill monthly to each customer, unless service is provided for a period of less than one month. A REP may issue a bill less frequently than monthly if both the customer and the REP agree to such an arrangement.

(2) Bills shall be issued no later than 30 days after the REP receives the usage data and any related invoices for non-bypassable charges, unless validation of the usage data and invoice received from a transmission and distribution utility by the REP or other efforts to determine the accuracy of usage data or invoices delay billing by a REP past 30 days. The number of days to issue a bill shall be extended beyond 30 days to the extent necessary to support agreements between REPs and customers for less frequent billing, as provided in paragraph (1) of this subsection or for consolidated billing.

(3) A REP shall issue bills to residential customers in writing and delivered via the United States Postal Service. REPs may provide bills to a customer electronically in lieu of written mailings if both the customer and the REP agree to such an arrangement. An affiliated REP or a provider of last resort shall not require a customer to agree to such an arrangement as a condition of receiving electric service.

(4) A REP shall not charge a customer a fee for issuing a standard bill, which is a bill delivered via U.S. mail that complies with the requirements of this section. The customer may be charged a fee or given a discount for non-standard billing in accordance with the terms of service document.

(c) Bill content.

(1) Each customer's bill shall include the following information:

(A) The certified name and address of the REP and the number of the license issued to the REP by the commission;

(B) A toll-free telephone number, in bold-face type, which the customer can call during specified hours for inquiries and to make complaints to the REP about the bill;

(C) A toll-free telephone number that the customer may call 24 hours a day, seven days a week, to report power outages and concerns about the safety of the electric power system;

(D) The service address, electric service identifier (ESI), and account number of the customer;

(E) The service period for which the bill is rendered;

(F) The date on which the bill was issued;

(G) The payment due date of the bill and, if different, the date by which payment from the customer must be received by the REP to avoid a late charge or other collection action;

(H) The current charges for electric service as disclosed in the customer's terms of service document, including applicable taxes and fees labeled "current charges." If the customer is on a level or average payment plan, the level or average payment due shall be clearly shown in addition to the current charges;

(I) A calculation of the average unit price for electric service for the current billing period, labeled, "The average price you paid for electric service this month." The calculation of the average price for electric service shall reflect the total of all fixed and variable recurring charges, but not include state and local sales taxes, reimbursement for the state miscellaneous gross receipts tax, and any nonrecurring charges or credits, divided by the kilowatt-hour consumption, and shall be expressed as a cents per kilowatt-hour amount rounded to the nearest one-tenth of one cent.

(J) The identification and itemization of charges other than for electric service as disclosed in the customer's terms of service document;

(K) The itemization and amount of any non-recurring charge, including late fees, returned check fees, restoration of service fees, or other fees disclosed in the REP's terms of service document provided to the customer;

(L) The balances from the preceding bill, payments made by the customer since the preceding bill, and the amount the customer is required to pay by the due date, labeled "amount due;"

(M) A notice that the customer has the opportunity to voluntarily donate money to the bill payment assistance program, pursuant to §25.480(g)(2) of this title (relating to Bill Payment and Adjustments);

(N) If available to the REP on a standard electronic transaction, if the bill is based on kilowatt-hour (kWh) usage, the following information:

(i) the meter reading at the beginning of the period for which the customer is being billed, labeled "previous meter read," and the meter reading at the end of the period for which the customer is being billed, labeled "current meter read," and the dates of such readings;

(ii) the kind and number of units measured, including kWh, actual kilowatts (kW), or kilovolt ampere (kVa);

(iii) if applicable, billed kW or kVa;

(iv) whether the bill was issued based on estimated usage; and

(v) any conversions from meter reading units to billing units, or any other calculations to determine billing units from recording or other devices, or any other factors used in determining the bill, unless the customer is provided conversion charts;

(O) Any amount owed under a written guarantee agreement, provided the guarantor was previously notified in writing by the REP of an obligation on a guarantee as required by §25.478 of this title (relating to Credit Requirements and Deposits);

(P) A conspicuous notice of any services or products being provided to the customer that have been added since the previous bill;

(Q) Notification of any changes in the customer's prices or charges due to the operation of a variable rate feature previously disclosed by the REP in the customer's terms of service document;

(R) The notice required by §25.481(d) of this title (relating to Unauthorized Charges); and

(S) For residential customers, on the first page of the bill in at least 12-point font the phrase, "for more information about residential electric service please visit www.powertochoose.com."

(2) If a REP separately identifies a charge defined by one of the terms in this paragraph on the customer's bill, then the term in this paragraph must be used to identify that charge, and such term and its definition shall be easily located on the REP's website and available to a customer free of charge upon request. Nothing in this paragraph precludes a REP from aggregating transmission and distribution utility (TDU) or REP charges. For any TDU charge(s) listed in this paragraph, the amount billed by the REP shall not exceed the amount of the TDU tariff charge(s). The label for any TDU charge(s) may also identify the TDU that issued the charge(s). A REP may use a different term than a defined term by adding or deleting a suffix, by adding the word "total" to a defined term, where appropriate, changing the use of lower-case or capital letters or punctuation, or using the acceptable abbreviation specified in this paragraph for a defined term. If an abbreviation other than the acceptable abbreviation is used for the term, then the term must also be identified on the customer's bill.

(A) Advanced metering charge--A charge assessed to recover a TDU's charges for Advanced Metering Systems, to the extent that they are not recovered in a TDU's standard metering charge. Acceptable abbreviation: Advanced Meter.

(B) Competition Transition Charge--A charge assessed to recover a TDU's charges for nonsecuritized costs associated with the transition to competition. Acceptable abbreviation: Competition Transition.

(C) Energy Efficiency Cost Recovery Factor--A charge assessed to recover a TDU's costs for energy efficiency programs, to the extent that the TDU charge is a separate charge exclusively for that purpose that is approved by the Public Utility Commission. Acceptable abbreviation: Energy Efficiency.

(D) Late Payment Penalty--A charge assessed for late payment in accordance with Public Utility Commission rules.

(E) Meter Charge--A charge assessed to recover a TDU's charges for metering a customer's consumption, to the extent that the TDU charge is a separate charge exclusively for that purpose that is approved by the Public Utility Commission.

(F) Miscellaneous Gross Receipts Tax Reimbursement--A fee assessed to recover he miscellaneous gross receipts tax imposed on retail electric providers operating in an incorporated city or town having a population of more than 1,000. Acceptable abbreviation: Gross Receipts Reimb.

(G) Nuclear Decommissioning Fee--A charge assessed to recover a TDU's charges for decommissioning of nuclear generating sites. Acceptable abbreviation: Nuclear Decommission.

(H) PUC Assessment--A fee assessed to recover the statutory fee for administering the Public Utility Regulatory Act.

(I) Sales tax--Sales tax collected by authorized taxing authorities, such as the state, cities and special purpose districts.

(J) TDU Delivery Charges--The total amounts assessed by a TDU for the delivery of electricity to a customer over poles and wires and other TDU facilities not including discretionary charges.

(K) Transmission Distribution Surcharges--One or more TDU surcharge(s) on a customer's bill in any combination. Surcharges include charges billed as tariff riders by the TDU. Acceptable abbreviation: TDU Surcharges.

(L) Transition Charge--A charge assessed to recover a TDU's charges for securitized costs associated with the transition to competition.

(3) If the REP includes any of the following terms in its bills, the term shall be applied in a manner consistent with the definitions, and such term and its definition shall be easily located on the REP's website and available to a customer free of charge upon request:

(A) Base Charge--A charge assessed during each billing cycle without regard to the customer's demand or energy consumption.

(B) Demand Charge--A charge based on the rate at which electric energy is delivered to or by a system at a given instant, or averaged over a designated period, during the billing cycle.

(C) Energy Charge--A charge based on the electric energy (kWh) consumed.

(4) A REP shall provide an itemization of charges, including non-bypassable charges, to the customer upon the customer's request and, to the extent that the charges are consistent with the terms set out in paragraph (2) of this subsection, the terms shall be used in the itemization.

(5) A customer's electric bill shall not contain charges for electric service from a service provider other than the customer's designated REP.

(6) A REP shall include on each residential and small commercial billing statement the date, as provided for in §25.475(c)(3)(B) of this title (relating to General Retail Electric Provider Requirements and Information Disclosure to Residential and Small Commercial Customers) that a fixed rate product will expire.

(7) To the extent that a REP uses the concepts identified in this paragraph in a customer's bill, it shall use the term set out in this paragraph, and the definitions in this paragraph shall be easily located on the REP's website. A REP may not use a different term for a concept that is defined in this paragraph.

(A) kW--Kilowatt, the standard unit for measuring electricity demand, equal to 1,000 watts;

(B) kWh--Kilowatt-hour, the standard unit for measuring electricity energy consumption, equal to 1,000 watt-hours; and

(8) Notice of contract expiration may be provided in a bill in accordance with §25.475 of this title.

(d) Public service notices. A REP shall, as required by the commission after reasonable notice, provide brief public service notices to its customers. The REP shall provide these public service notices to its customers on its billing statements, as a separate document issued with its bill, by electronic communication, or by other acceptable mass communication methods, as approved by the commission.

(e) Estimated bills. If a REP is unable to issue a bill based on actual meter reading due to the failure of the TDU, the registration agent, municipally owned utility or electric cooperative to obtain or transmit a meter reading or an invoice for non-bypassable charges to the REP on a timely basis, the REP may issue a bill based on the customer's estimated usage and inform the customer of the reason for the issuance of the estimated bill.

(f) Non-recurring charges. A REP may pass through to its customers all applicable non-recurring charges billed to the REP by a TDU, municipally owned utility, or electric cooperative as a result of establishing, switching, disconnecting, reconnecting, or maintaining service to an applicant or customer. In the event of a meter test, the TDU, municipally owned utility, electric cooperative, and REP shall comply with the requirements of §25.124 of this title (relating to Meter Testing) or with the requirements of the tariffs of a TDU, municipally owned utility, or electric cooperative, as applicable. The TDU, municipally owned utility, or electric cooperative shall maintain a record of all meter tests performed at the request of a REP or a REP's customers.

(g) Record retention. A REP shall maintain monthly billing and payment records for each account for at least 24 months after the date the bill is mailed. The billing records shall contain sufficient data to reconstruct a customer's billing for a given period. A copy of a customer's billing records may be obtained by that customer on request, and may be obtained once per 12-month period, at no charge.

(h) Transfer of delinquent balances or credits. If the customer has an outstanding balance or credit owed to the customer's current REP that is due from a previous account in the same customer class, then the customer's current REP may transfer that balance to the customer's current account. The delinquent balance and specific account or address shall be identified as such on the bill. There shall be no balance transfers between REPs, other than transfer of a deposit, as specified in §25.478(j)(2) of this title.

§25.480.Bill Payment and Adjustments.

(a) Application. This section applies to a retail electric provider (REP) that is responsible for issuing electric service bills to retail customers, unless the REP is issuing a consolidated bill (both energy services and transmission and distribution services) on behalf of an electric cooperative or municipally owned utility. In addition, this section applies to a transmission and distribution utility (TDU) where specifically stated. This section does not apply to a municipally owned utility or electric cooperative issuing bills to its customers in its own service territory.

(b) Bill due date. A REP shall state a payment due date on the bill which shall not be less than 16 days after issuance. A bill is considered to be issued on the issuance date stated on the bill or the postmark date on the envelope, whichever is later. A payment for electric service is delinquent if not received by the REP or at the REP's authorized payment agency by the close of business on the due date. If the 16th day falls on a holiday or weekend, then the due date shall be the next business day after the 16th day.

(c) Penalty on delinquent bills for electric service. A REP may charge a one-time penalty not to exceed 5.0% on a delinquent bill for electric service. No such penalty shall apply to residential or small commercial customers served by the provider of last resort (POLR). The one-time penalty, not to exceed 5.0%, may not be applied to any balance to which the penalty has already been applied.

(d) Overbilling. If charges are found to be higher than authorized in the REP's terms and conditions for service or other applicable commission rules, then the customer's bill shall be corrected.

(1) The correction shall be made for the entire period of the overbilling.

(2) If the REP corrects the overbilling within three billing cycles of the error, it need not pay interest on the amount of the correction.

(3) If the REP does not correct the overcharge within three billing cycles of the error, it shall pay interest on the amount of the overcharge at the rate set by the commission.

(A) Interest on overcharges that are not adjusted by the REP within three billing cycles of the bill in error shall accrue from the date of payment by the customer.

(B) All interest shall be compounded monthly at the approved annual rate set by the commission.

(C) Interest shall not apply to leveling plans or estimated billings.

(4) If the REP rebills for a prior billing cycle, the adjustments shall be identified by account and billing date or service period.

(e) Underbilling by a REP. If charges are found to be lower than authorized by the REP's terms and conditions of service, or if the REP fails to bill the customer for service, then the customer's bill may be corrected.

(1) The customer shall not be responsible for corrected charges billed by the REP unless such charges are billed by the REP within 180 days from the date of issuance of the bill in which the underbilling occurred The REP may backbill a customer for the amount that was underbilled beyond the timelines provided in this paragraph if:

(A) the underbilling is found to be the result of meter tampering by the customer; or

(B) the TDU bills the REP for an underbilling as a result of meter error as provided in §25.126 of this title (relating to Adjustments Due to Non-Compliant Meters and Meter Tampering in Areas Where Customer Choice Has Been Introduced).

(2) The REP may disconnect service pursuant to §25.483 of this title (relating to Disconnection of Service) if the customer fails to pay the additional charges within a reasonable time.

(3) If the underbilling is $50 or more, the REP shall offer the customer a deferred payment plan option for the same length of time as that of the underbilling. A deferred payment plan need not be offered to a customer when the underpayment is due to theft of service.

(4) The REP shall not charge interest on underbilled amounts unless such amounts are found to be the result of theft of service (meter tampering, bypass, or diversion) by the customer. Interest on underbilled amounts shall be compounded monthly at the annual rate, as set by the commission. Interest shall accrue from the day the customer is found to have first stolen the service.

(5) If the REP adjusts the bills for a prior billing cycle, the adjustments shall be identified by account and billing date or service period.

(f) Disputed bills. If there is a dispute between a customer and a REP about the REP's bill for any service billed on the retail electric bill, the REP shall promptly investigate and report the results to the customer. The REP shall inform the customer of the complaint procedures of the commission pursuant to §25.485 of this title (relating to Customer Access and Complaint Handling).

(g) Alternate payment programs or payment assistance.

(1) Notice required. When a customer contacts a REP and indicates inability to pay a bill or a need for assistance with the bill payment, the REP shall inform the customer of all applicable payment options and payment assistance programs that are offered by or available from the REP, such as bill payment assistance, deferred payment plans, disconnection moratoriums for the ill, or low-income energy assistance programs, and of the eligibility requirements and procedure for applying for each.

(2) Bill payment assistance programs.

(A) All REPs shall implement a bill payment assistance program for residential electric customers. At a minimum, such a program shall solicit voluntary donations from customers through the retail electric bills.

(B) A REP shall obtain a commitment from an assistance agency selected to disburse bill payment assistance funds that the agency will not discriminate in the distribution of such funds to customers based on the customer's race, creed, color, national origin, ancestry, sex, marital status, lawful source of income, disability, familial status, location of customer in an economically distressed geographic area, or qualification for low-income affordability or energy efficiency services.

(3) A REP shall provide, in a project established by the commission, information about its voluntary bill payment assistance program for burned veterans. This information shall include the REP's name, the REP's certification number, and a toll free telephone number and website address where customers can obtain additional information. The commission will publish such information on the commission website.

(h) Level and average payment plans. A REP shall make a level or average payment plan available to its customers consistent with this subsection. A customer receiving service from a provider of last resort (POLR) may be required to select a competitive product offered by the POLR REP to receive the level or average payment plan.

(1) A REP shall make a level or average payment plan available to a customer who is not currently delinquent in payment to the REP. A customer is delinquent in payment in the following circumstances:

(A) A customer whose normal billing arrangement provides for payment after the rendition of service is delinquent if the date specified for payment of a bill has passed and the customer has not paid the full amount due.

(B) A customer whose normal billing arrangement provides for payment before the rendition of service is delinquent if the customer has a negative balance on the account for electric service.

(2) A REP shall reconcile any over- or under-payment consistent with the applicable terms of service, which shall provide for reconciliation at least every twelve months. For a customer with an average payment plan, a REP may recalculate the average consumption or average bill and adjust the customer's required minimum payment as frequently as every billing period. A REP may collect under-payments associated with a level payment plan from a customer over a period no less than the reconciliation period or upon termination of service to the customer. A REP shall credit or refund any over-payments associated with a level payment plan to the customer at each reconciliation and upon termination of service to the customer. A REP may initiate its normal collection activity if a customer fails to make a timely payment according to such a level or average payment plan. All details concerning a level or average payment program shall be disclosed in the customer's terms of service document.

(3) If the customer is delinquent in payment when the level or average payment plan is established, the REP may require the customer to pay no greater than 50% of the delinquent amount due. The REP may require the remaining delinquent amount to be paid by the customer in equal installments over at least five billing cycles unless the customer agrees to fewer installments or may include the remaining delinquent amount in the calculation of the level or average payment amount. If the REP requires installment payments, the REP shall provide the customer a copy of the deferred payment plan in writing as described in subsection (j)(5) of this section.

(4) If the amount of the deferred balance does not appear on each bill the customer receives, the REP shall inform the customer that the customer may call the REP at any time to determine the amount that must be paid to be removed from the level or average payment plan.

(5) If the customer is delinquent in payment when the level or average payment plan is established, the REP may apply a switch-hold at that time.

(6) Before the REP applies a switch-hold to a customer on a level or average payment plan, the REP shall provide orally or in writing a clear explanation of the switch-hold process to the customer, prior to the customer's agreement to the plan. The explanation shall inform the customer as follows: "If you enter into this plan concerning your past due amount, we will put a switch-hold on your account. A switch-hold means that you will not be able to buy electricity from other companies until you pay the total deferred balance. If we put a switch-hold on your account, it will be removed after your deferred balance is paid and processed. While a switch-hold applies, if you are disconnected for not paying, you will need to pay {us or company name}, to get your electricity turned back on."

(7) If the customer is not delinquent in payment when the level or average payment plan is established, a switch-hold shall not be applied unless the plan is established pursuant to subsection (j)(2)(B)(ii) of this section.

(8) The REP, through a standard market process, shall submit a request to remove the switch-hold, pursuant to subsection (m) of this section, when the customer satisfies either subparagraph (A) or (B) of this paragraph, whichever occurs earlier. On the date the REP submits the request to remove the switch-hold, the REP shall notify or send notice to the customer that the customer has satisfied the obligation to pay any deferred balance owed and the removal of the switch-hold is being processed.

(A) The customer's deferred balance, including any deferred delinquent amount described in paragraph (4) of this subsection, is either zero or in an over-payment status.

(B) The customer satisfies the terms of any deferred delinquent amount described in paragraph (4) of this subsection and has paid bills for 12 consecutive billings without having been disconnected and without having more than one late payment.

(i) Payment arrangements. A payment arrangement is any agreement between the REP and a customer that allows a customer to pay the outstanding bill after its due date, but before the due date of the next bill. If the REP issues a disconnection notice before a payment arrangement was made, that disconnection should be suspended until after the due date for the payment arrangement. If a customer does not fulfill the terms of the payment arrangement, service may be disconnected after the later of the due date for the payment arrangement or the disconnection date indicated in the notice, without issuing an additional disconnection notice.

(j) Deferred payment plans and other alternate payment arrangements.

(1) A deferred payment plan is an agreement between the REP and a customer that allows a customer to pay an outstanding balance in installments that extend beyond the due date of the current bill. A deferred payment plan may be established in person, by telephone, or online, but all deferred payment plans shall be confirmed in writing by the REP in accordance with paragraph (5) of this subsection. Before the REP applies a switch-hold to a customer on a deferred payment plan, the REP shall provide a clear explanation of the switch-hold process to the customer. The explanation shall inform the customer as follows: "If you enter into this plan concerning your past due amount, we will put a switch-hold on your account. A switch-hold means that you will not be able to buy electricity from other companies until you pay the total deferred balance. If we put a switch-hold on your account, it will be removed after your deferred balance is paid and processed. While a switch-hold applies, if you are disconnected for not paying, you will need to pay {us or company name}, to get your electricity turned back on."

(A) A REP shall offer a deferred payment plan to customers, upon request, for bills that become due during an extreme weather emergency, pursuant to §25.483(j) of this title.

(B) As directed by the commission, during a state of disaster declared by the governor pursuant to Texas Government Code §418.014, a REP shall offer a deferred payment plan to customers, upon request, in the area covered by the declaration.

(C) A REP shall offer a deferred payment plan to a customer who has been underbilled, pursuant to subsection (e) of this section.

(2) A REP shall make a payment plan available, upon request, to a residential customer that meets the requirements of subparagraph (A) of this paragraph for a bill that becomes due in July, August, or September. A REP shall make a payment plan available, upon request, to a residential customer that meets the requirements of subparagraph (A) of this paragraph for a bill that becomes due in January or February if in the prior month a TDU notified the commission pursuant to §25.483(j) of this title of an extreme weather emergency for the residential customer's county in the TDU service area for at least five consecutive days during the month. A REP is not required to offer a payment plan to a customer pursuant to this paragraph if the customer is on an existing deferred, level, or average payment plan.

(A) The following residential customers are eligible for a payment plan under this paragraph:

(i) customers designated as Critical Care Residential Customers or Chronic Condition Residential Customers under §25.497 of this title (relating to Critical Load Industrial Customers, Critical Load Public Safety Customers, Critical Care Residential Customers, and Chronic Condition Residential Customers); or

(ii) customers who have expressed an inability to pay unless the customer:

(I) has been disconnected during the preceding 12 months;

(II) has submitted more than two payments during the preceding 12 months that were found to have insufficient funds available; or

(III) has received service from the REP for less than three months, and the customer lacks:

(-a-) sufficient credit; or

(-b-) a satisfactory history of payment for electric service from a previous REP or utility.

(B) The REP shall make available, at the customer's option, the plans described in clauses (i) and (ii) of this subparagraph.

(i) A deferred payment plan with the initial payment amount no greater than 50% of the amount due. The deferred amount shall be paid by the customer in equal installments over at least five billing cycles unless the customer agrees to fewer installments.

(ii) A level or average payment plan instead of requiring the balance due to be paid. The level or average payment plan shall be offered subject to the requirements of subsection (h) of this section.

(C) The REP shall not seek an additional deposit as a result of a customer's entering into a deferred payment plan under this paragraph.

(3) A REP shall not refuse customer participation in a deferred payment plan on any basis set forth in §25.471(c) of this title (relating to General Provisions of Customer Protection Rules).

(4) A REP may voluntarily offer a deferred payment plan to customers who have expressed an inability to pay.

(5) A copy of the deferred payment plan shall be provided to the customer and:

(A) shall include a statement, in a clear and conspicuous type, that states "If you are not satisfied with this agreement, or if the agreement was made by telephone and you feel this does not reflect your understanding of that agreement, contact (insert name and contact number of REP).";

(B) if a switch-hold will apply, shall include a statement, in a clear and conspicuous type, that states "By entering into this agreement, you understand that {company name} will put a switch-hold on your account. A switch-hold means that you will not be able to buy electricity from other companies until you pay this past due amount. The switch-hold will be removed after your final payment on this past due amount is processed. While a switch-hold applies, if you are disconnected for not paying, you will need to pay {us or company name}, to get your electricity turned back on.";

(C) where the customer and the REP's representative or agent meets in person, the representative shall read the statements in subparagraph (A) and, if applicable, subparagraph (B) of this paragraph to the customer;

(D) may include the one-time penalty in accordance with subsection (c) of this section but shall not include a finance charge;

(E) shall state the length of time covered by the plan;

(F) shall state the total amount to be paid under the plan;

(G) shall state the specific amount of each installment;

(H) shall state whether the amount of the deferred balance will appear on each bill the customer receives and that the customer may call the REP at any time to determine the amount that must be paid to satisfy the terms of the deferred payment plan; and

(I) shall state whether there may be a disconnection of service if the customer does not fulfill the terms of the deferred payment plan, and shall state the terms for disconnection.

(6) A REP may pursue disconnection of service if a customer does not meet the terms of a deferred payment plan. However, service shall not be disconnected until appropriate notice has been issued, pursuant to §25.483 of this title, notifying the customer that the customer has not met the terms of the plan. The requirements of paragraph (2) of this subsection shall not apply with respect to a customer who has defaulted on a deferred payment plan.

(7) A REP may apply a switch-hold while the customer is on a deferred payment plan.

(8) The REP, through a standard market process, shall submit a request to remove the switch-hold, pursuant to subsection (m) of this section, after the customer's payment of the deferred balance owed to the REP. On the day the REP submits the request to remove the switch-hold, the REP shall notify or send notice to the customer that the customer has satisfied the obligation to pay any deferred balance owed and the removal of the switch-hold is being processed.

(k) Allocation of partial payments. A REP shall allocate a partial payment by the customer first to the oldest balance due for electric service, followed by the current amount due for electric service. When there is no longer a balance for electric service, payment may be applied to non-electric services billed by the REP. Electric service shall not be disconnected for non-payment of non-electric services.

(l) Switch-hold.

(1) A REP may request that the TDU place a switch-hold on an ESI ID to the extent allowed by subsection (h) or (j) of this section, which shall prevent a switch transaction from being completed for the ESI ID and shall prevent a move-in transaction from being completed pending documentation that the applicant for electric service is a new occupant not associated with the customer for which the switch-hold was imposed. If the REP exercises its right to disconnect service for non-payment pursuant to §25.483 of this title, the switch-hold shall continue to remain in place. The TDU shall create and maintain a secure list of ESI IDs with switch-holds that REPs may access. The list shall not include any customer information other than the ESI ID and date the switch-hold was placed. The list shall be updated daily, and made available through a secure means by the TDU. The TDU may provide this list in a secure format through the web portal developed as part of its AMS deployment.

(A) The REP via a standard market process may request a switch-hold.

(B) The REP shall submit a request to remove the switch-hold as required by subsections (h)(9) and (j)(8) of this section.

(C) When the REP of record issues a move-out request for the flagged ESI ID, the REP of record's relationship with the ESI ID is terminated and the switch-hold shall be removed.

(D) At the time of a mass transition, the TDU shall remove the switch-hold flag for any ESI ID that is transitioned to a provider of last resort (POLR) provider.

(E) When the applicant for electric service is shown to be a new occupant not associated with the customer for which the switch-hold was imposed using the switch-hold process described in §25.126 of this title, the switch-hold flag shall be removed.

(F) For a move-in transaction indicating that the ESI ID is subject to a continuous service agreement, the TDU shall remove any switch-hold on that ESI ID and complete the move-in.

(2) In the first TX SET release after January 1, 2011, market transactions shall be developed that support the following requirements.

(A) REPs may request a switch-hold as allowed by subsection (h) or (j) of this section.

(B) TDUs shall provide indication of which ESI IDs have switch-holds so that during a move-in enrollment a REP can identify whether a switch-hold applies and that specific documentation must be submitted to have the switch-hold removed.

(C) A move-in subject to a switch-hold can be submitted for processing when the customer initially requests the move-in and such transaction will be held in the system for final processing depending on the approval or rejection of the move-in documentation. The TDU shall notify the submitting REP that there is a switch-hold on the ESI ID.

(3) The requirements of §25.475 of this title (relating to General Retail Electric Provider Requirements and Information Disclosures to Residential and Small Commercial Customers) shall continue to apply while a customer is subject to a switch-hold. The notice required by §25.475(e) of this title shall include a statement reminding the customer that if a switch-hold is in effect, the balance deferred must be paid in full before the customer will be able to change to a new provider.

(4) A customer who is subject to a switch-hold shall not be charged any separate fees for a switch-hold or any customer service or administrative fees related to the switch-hold.

(5) A REP shall not discriminate against any customer that is on a switch-hold in the provision of services or pricing of products. A customer on a switch-hold shall be eligible for all services and products generally available to the REPs other customers.

(6) If a REP applies a switch-hold to a customer account and the customer's contract expires while under the switch-hold, the REP shall provide notice of the contract expiration as required by §25.475 of this title. Unless a customer affirmatively chooses a different product with the REP, a customer whose term product expires while the customer is subject to a switch-hold shall be moved to the lowest priced month-to-month product currently offered by the REP to new applicants, or, if the REP does not offer month-to-month products to new applicants, shall be served on a month-to-month basis at the price equivalent to the lowest price of the shortest term fixed product currently offered by the REP to new applicants. Otherwise, the REP shall request the removal of the switch-hold in compliance with subsection (m) of this section. The offers shall include those made on www.powertochoose.com. If the customer does not affirmatively choose a product, the customer shall not be required by the REP to enter into another contract term so long as the switch-hold remains on the customer account and no early termination fees shall be applied to the customer's account.

(m) Placement and Removal of Switch-Holds.

(1) A REP may request a switch-hold only as allowed under this section.

(2) A REP shall be responsible for requesting that the TDU remove a switch-hold after the customer's obligation to the REP related to the switch-hold is satisfied. If a customer's obligation to the REP is satisfied by 10:00 p.m. on a business day, the REP shall send a request to the TDU to remove the switch-hold by Noon (12:00 p.m.) of the next business day. If the TDU receives the request by 1:00 p.m. on a business day, the TDU shall remove the switch-hold by 8:00 p.m. of the same business day in which it receives the request to remove the switch-hold from the REP.

(3) The REP shall submit a request to remove a switch-hold pursuant to subsection (l)(6) of this section to the TDU, such that the TDU will remove the switch-hold on or before the customer's contract expiration date.

(4) If a REP erroneously places a switch-hold flag on an ESI ID, thus preventing a legitimate switch, or does not remove the switch-hold within the timeline described in paragraph (2) of this subsection, the REP shall be considered to have committed a Class B Violation (as defined in §25.8(b) of this title (relating to Classification System for Violations of Statutes, Rules, and Orders Applicable to Electric Service Providers)) for purposes of any administrative penalties imposed by the commission.

(n) Annual reporting requirement. In its annual report filed pursuant to §25.107 of this title (relating to Certification of Retail Electric Providers (REPs)) and §25.491 of this title (relating to Record Retention and Reporting Requirements), each REP shall include:

(1) A statement summarizing any low-income payment options and low-income payment assistance programs that are offered by or available from the REP;

(2) Information regarding a REP's bill payment assistance program created pursuant to subsection (g) of this section shall include:

(A) the total amount of customer donations;

(B) the amount of money set aside for bill payment assistance;

(C) the assistance agency or agencies selected to disburse funds to residential customers;

(D) the amount of money disbursed by the REP or provided to each assistance agency to disburse funds to residential customers; and

(E) the number of customers who had a switch-hold applied during the year.

(3) A statement confirming whether the REP, at the time of filing its annual report, has obtained the low-income customer identification service from the Low Income List Administrator (LILA) in accordance with §25.45 of this title, and whether the REP, at the time of filing its annual report, intends to obtain the low-income identification service from the LILA in the next fiscal year.

§25.491.Record Retention and Reporting Requirements.

(a) Application. This section does not apply to a municipally owned utility where it offers retail electric power or energy outside its certificated service territory or to a retail electric provider (REP) that is an electric cooperative.

(b) Record retention.

(1) Each REP and aggregator shall establish and maintain records and data that are sufficient to:

(A) Verify its compliance with the requirements of any applicable commission rules; and

(B) Support any investigation of customer complaints.

(2) All records required by this subchapter shall be retained for no less than two years, unless otherwise specified.

(3) Unless otherwise prescribed by the commission or its authorized representative, all records required by this subchapter shall be provided to the commission within 15 calendar days of its request.

(c) Annual reports. In its annual report, a REP shall report the information required by §25.107 of this title (relating to Certification of Retail Electric Providers (REPs)) to the commission and the Office of Public Utility Counsel (OPUC) and the following additional information on a form approved by the commission for the 12-month period ending December 31 of the prior year:

(1) The number of residential customers served, by nine-digit zip code and census tract, by month;

(2) The number of written denial of service notices issued by the REP, by month, by customer class, by nine-digit zip code and census tract;

(3) The number and total aggregated dollar amount of deposits held by the REP, by month, by customer class, by nine-digit zip code and census tract;

(4) Information relating to the REP's bill payment assistance program for residential electric customers required by §25.480(n)(1) of this title (relating to Bill Payment and Adjustments);

(5) The number of complaints received by the REP from residential customers for the following categories by month, by nine-digit zip code and census tract:

(A) Refusal of electric service, which shall include all complaints pertaining to the implementation of §25.477 of this title (relating to Refusal of Electric Service);

(B) Marketing and quality of customer service, which shall include complaints relating to the interfaces between the customer and the REP, such as, but not limited to, call center hold time, responsiveness of customer service representatives, and implementation of §25.472 of this title (relating to Privacy of Customer Information), §25.475 of this title (relating to General REP Requirements and Information Disclosures to Residential and Small Commercial Customers), §25.473 of this title (relating to Non-English Language Requirements), §25.476 of this title (relating to Renewable and Green Energy Verification), and §25.484 of this title (relating to Texas Electric No-Call List), and which shall not include issues for which the REP is not responsible, such as, but not limited to, power quality, outages, or technical failures of the registration agent;

(C) Unauthorized charges, which shall encompass all complaints pertaining to §25.481 of this title (relating to Unauthorized Charges);

(D) Enrollment, which shall encompass all complaints pertaining to the implementation of §25.474 of this title (relating to the Selection of Retail Electric Provider), §25.478 of this title (relating to Credit Requirements and Deposits), and §25.495 of this title (relating to Unauthorized Change of Retail Electric Provider);

(E) Accuracy of billing services, which shall encompass all complaints pertaining to the implementation of §25.479 of this title (relating to Issuance and Format of Bills); and

(F) Collection and service termination, and disconnection, which shall encompass all complaints pertaining to the implementation of §25.480 of this title, and §25.483 of this title (relating to Disconnection of Service).

(6) In reporting the number of informal complaints received pursuant to paragraph (4) of this subsection, a REP may identify the number of complaints in which it has disputed categorization or assignment pursuant to the provisions set forth in §25.485 of this title (relating to Customer Access and Complaint Handling).

(d) Information regarding payment options and payment assistance programs. With its annual report, a REP shall include a statement containing the information described in §25.480(n) of this title to the extent such information is not included in the form approved by the commission pursuant to subsection (c) of this section.

(e) Additional information. Upon written request by the commission, a REP or aggregator shall provide within 15 days any information, including but not limited to marketing information, necessary for the commission to investigate an alleged discriminatory practice prohibited by §25.471(c) of this title (relating to General Provisions of the Customer Protection Rules).

§25.497.Critical Load Industrial Customers, Critical Load Public Safety Customers, Critical Care Residential Customers, and Chronic Condition Residential Customers.

(a) Definitions. The following words and terms, when used in this section, shall have the following meanings unless the context indicates otherwise.

(1) Critical Load Public Safety Customer--A customer for whom electric service is considered crucial for the protection or maintenance of public safety, including but not limited to hospitals, police stations, fire stations, and critical water and wastewater facilities.

(2) Critical Load Industrial Customer--An industrial customer for whom an interruption or suspension of electric service will create a dangerous or life-threatening condition on the retail customer's premises, is a "critical load industrial customer."

(3) Chronic Condition Residential Customer--A residential customer who has a person permanently residing in his or her home who has been diagnosed by a physician as having a serious medical condition that requires an electric-powered medical device or electric heating or cooling to prevent the impairment of a major life function through a significant deterioration or exacerbation of the person's medical condition. If that serious medical condition is diagnosed or re-diagnosed by a physician as a life-long condition, the designation is effective under this section for the shorter of one year or until such time as the person with the medical condition no longer resides in the home. Otherwise, the designation or re-designation is effective for 90 days.

(4) Critical Care Residential Customer--A residential customer who has a person permanently residing in his or her home who has been diagnosed by a physician as being dependent upon an electric-powered medical device to sustain life. The designation or redesignation is effective for two years under this section.

(b) Eligibility for protections. In order to be considered for designation under this section, an application for designation must be submitted by or on behalf of the customer.

(1) To be designated as a Critical Care Residential Customer or Chronic Condition Residential Customer, the commission-approved application form must be submitted to the TDU by a physician, in accordance with provisions of this section.

(2) To be designated as a Critical Load Public Safety Customer or a Critical Load Industrial Customer, the customer must notify the TDU. To be eligible for the protections provided under this section, the customer must have a determination of eligibility pending with or approved by the TDU. Eligibility shall be determined through a collaborative process among the customer, REP, and TDU, but in the event that the customer, REP and TDU are unable to agree on the designation, the TDU has the authority to make or decline to make the designation.

(c) Benefits for Critical Load Public Safety Customers, Critical Load Industrial Customers, Critical Care Residential Customers, and Chronic Condition Residential Customers.

(1) A Critical Load Public Safety Customer or a Critical Load Industrial Customer qualifies for notifications of interruptions or suspensions of service as provided in Sections 4.2.5, 5.2.5, and 5.3.7.1 of the TDU's tariff for retail delivery service.

(2) A Critical Care Residential Customer or Chronic Condition Residential Customer qualifies for notification of interruptions or suspensions of service, as provided in Sections 4.2.5, 5.2.5, and 5.3.7.1, and for Critical Care Residential Customers protections against suspension or disconnection, as provided in Section 5.3.7.4(1)(D) and (E), of the TDU's tariff for retail delivery service.

(3) A Critical Care Residential Customer or Chronic Condition Residential Customer is also eligible for certain protections as described in §25.483 (relating to Disconnection of Service).

(4) Designation as a Critical Load Customer, Critical Care Residential Customer, or Chronic Condition Residential Customer does not guarantee the uninterrupted supply of electricity.

(d) Notice to customers concerning Critical Care Residential Customer and Chronic Condition Residential Customer status.

(1) A REP shall notify each residential applicant for service of the right to apply for Critical Care Residential Customer or Chronic Condition Residential Customer designation. This notice to an applicant for residential service shall be included in the Your Rights as a Customer document.

(2) All REPs that serve residential customers shall provide information about Critical Care Residential Customer and Chronic Condition Residential Customer designations to each residential customer two times a year.

(3) Upon a customer's request, the REP shall provide to the customer the application form for Critical Care Residential Customer and Chronic Condition Residential Customer designation.

(e) Procedure for obtaining Critical Care Residential Customer or Chronic Condition Residential Customer designation.

(1) The commission-approved application form shall instruct the customer to have the physician submit the application form by facsimile or other electronic means to the TDU. If the physician submits the form to the REP, the REP shall forward it to the TDU electronically no later than two business days from receipt of the form. The application form shall include a telephone number for reaching a person at the TDU who is capable of responding to questions from a physician or customer about the form during regular business hours.

(2) After the TDU receives the form, it shall evaluate the form for completeness. If the form is incomplete, no later than two business days after receiving the form, the TDU shall mail the form to the customer and explain in writing what information is needed to complete the form.

(3) If the TDU has returned the form as incomplete or has not finished processing the form within two business days from receipt of the form, the customer shall be designated as a Critical Care Residential Customer or Chronic Condition Residential Customer on a temporary basis pending final designation by the TDU. The temporary designation shall be based on the designation selected by the physician on the form if such designation was included; otherwise, the temporary designation shall be as a Critical Care Residential Customer. The TDU shall notify the customer's REP of such temporary designation using a standard market transaction. If the form is returned to the customer as incomplete, the temporary designation shall remain in effect for 14 days, after which the temporary designation shall expire and the application process must start over.

(4) Reasons that a TDU shall consider a form incomplete for an application for Critical Care Residential Customer or Chronic Condition Residential Customer designation include the omission of the name of the person for whom the protection is sought, contact information, physician signature, the designation as a Critical Care Residential Customer or Chronic Condition Residential Customer, and medical board license number of the customer's physician. Any additional mandatory information required for completeness shall be clearly identified on the commission-approved application form. A customer may, but it is not required to, include an emergency (secondary) contact in the application.

(5) The TDU shall not challenge the physician's determination of the customer's status, but shall apply the physician's designation of the customer as a Critical Care Residential Customer or Chronic Condition Residential Customer consistent with the information provided on the form and the definitions in this section. The TDU may verify the physician's identity and signature and may deny an application for designation, if it determines that the identity or signature of the physician is not authentic.

(6) The TDU shall notify the customer's REP using a standard market transaction and the customer of the final status of the application process, including whether the customer has been designated for Critical Care Residential Customer or Chronic Condition Residential Customer status. The TDU shall also notify the customer of the date a designation, if any, will expire, and whether the customer will receive a renewal notice. The TDU shall provide the emergency contact information (if applicable) to the REP using a standard market transaction. If the customer switches to a different REP, the TDU shall provide the new REP with information on the customer's status and the emergency contact information (if applicable) using a standard market transaction.

(7) At the same time the TDU notifies the customer the final status of the customer's application, the TDU shall inform the customer of the customer's right to file a complaint with the commission pursuant to §22.242 of this title (relating to Complaints).

(8) The TDU shall notify Critical Care Residential Customers and Chronic Condition Residential Customers of the expiration of their designation in accordance with this subsection. The TDU shall notify the customer's REP using a standard market transaction when a customer is no longer designated as a Critical Care Residential Customer or a Chronic Condition Residential Customer.

(9) The TDU shall mail a renewal notice to a Chronic Condition Residential Customer whose designation was for a period longer than 90 days or a Critical Care Residential Customer, at least 45 days prior to the expiration date of the customer's designation. The renewal notice shall also be mailed to the emergency contact included on the commission-approved application form (if applicable). The renewal notice shall include the application form and an explanation of how to reapply for Critical Care Residential Customer or Chronic Condition Residential Customer designation. The renewal notice shall inform the customer that the current designation will expire unless the application form is returned by the expiration date of the existing designation.

(f) Effect of Critical Care Residential Customer or Chronic Condition Residential Customer status on payment obligations. A Critical Care Residential Customer or Chronic Condition Residential Customer designation pursuant to this section does not relieve a customer of the obligation to pay the REP for services provided, and a customer's service may be disconnected pursuant to §25.483 of this title.

(g) TX SET changes. In the first TX SET release after the effective date of this section, market transactions shall be included to address the requirements of this section.

(h) Effective date. The effective date of this section is January 1, 2011.

(i) TDU annual report. A TDU shall report to the commission by March 1 of each year beginning in 2012, the number of customers for each type of customer defined in subsection (a) of this section as of December 31 of the previous calendar year. The TDU report shall also include for the previous calendar year, for each type of customer defined in subsection (a) of this section, the number of applications that were rejected as a result of incomplete forms, the number of requests from REPs for disconnection, and the number of disconnections and reconnections completed. An interim report shall be filed by the TDU on April 1, 2011 for the time period from January 1, 2011 through March 1, 2011.

§25.498.Prepaid Service.

(a) Applicability. This section applies to retail electric providers (REPs) that offer a payment option in which a customer pays for retail service prior to the delivery of service and to transmission and distribution utilities (TDUs) that have installed advanced meters and related systems. A REP may not offer prepaid service to residential or small commercial customers unless it complies with this section. The following provisions do not apply to prepaid service, unless otherwise expressly stated:

(1) §25.479 of this title (relating to Issuance and Format of Bills);

(2) §25.480(b), (e)(3), (h), (i), (j), and (k) of this title (relating to Bill Payment and Adjustments); and

(3) §25.483 of this title (relating to Disconnection of Service), except for §25.483(b)(2)(A) and (B), (d), and (e)(1)-(6) of this title.

(b) Definitions. The following terms, when used in this section, have the following meanings unless the context indicates otherwise.

(1) Connection balance--A current balance, not to exceed $75 for a residential customer, required to establish prepaid service or reconnect prepaid service following disconnection.

(2) Current balance--An account balance calculated consistent with subsection (c)(6) of this section.

(3) Customer prepayment device or system (CPDS)--A device or system that includes metering and communications capabilities that meet the requirements of this section, including a device or system that accesses customer consumption information from a TDU's advanced metering system (AMS). The CPDS may be owned by the REP, and installed by the TDU consistent with subsection (c)(2)-(4) of this section.

(4) Disconnection balance--An account balance, not to exceed $10 for a residential customer, below which the REP may initiate disconnection of the customer's service.

(5) Landlord--A landlord or property manager or other agent of a landlord.

(6) Postpaid service--A payment option offered by a REP for which the customer normally makes a payment for electric service after the service has been rendered.

(7) Prepaid service--A payment option offered by a REP for which the customer normally makes a payment for electric service before service is rendered.

(8) Prepaid disclosure statement (PDS)--A document described by subsection (e) of this section.

(9) Summary of usage and payment (SUP)--A document described by subsection (h) of this section.

(c) Requirements for prepaid service.

(1) A REP shall file with the commission a notice of its intent to provide prepaid service prior to offering such service. The notice of intent shall include a description of the type of CPDS the REP will use, and the initial Electricity Facts Label (EFL), Terms of Service (TOS), and PDS for the service. Except as provided in subsection (m) of this section, a REP-controlled CPDS or TDU settlement provisioned meter is required for any prepaid service.

(2) A CPDS that relies on metering equipment other than the TDU meter shall conform to the requirements and standards of §25.121(e) of this title (relating to Meter Requirements), §25.122 of this title (relating to Meter Records), and section 4.7.3 of the tariff for retail electric delivery service, which is prescribed by §25.214 of this title (relating to Terms and Conditions of Retail Delivery Service Provided by Investor Owned Transmission and Distribution Utilities).

(3) A TDU may, consistent with its tariff, install CPDS equipment, including meter adapters and collars on or near the TDU's meters. Such installation does not constitute competitive energy services as this term is defined in §25.341(3) of this title (relating to Definitions).

(4) A CPDS shall not cause harmful interference with the operation of a TDU's meter or equipment, or the performance of any of the TDU's services. If a CPDS interferes with the TDU's meter or equipment, or TDU's services, the CPDS shall be promptly corrected or removed. A CPDS that relies on communications channels other than those established by the TDU shall protect customer information in accordance with §25.472 of this title (relating to Privacy of Customer Information).

(5) A REP may choose the means by which it communicates required information to a customer, including an in-home device at the customer's premises, United States Postal Service, email, telephone, mobile phone, or other electronic communications. The means by which the REP will communicate required information to a customer shall be described in the TOS and the PDS.

(A) A REP shall communicate time-sensitive notifications required by paragraph (7)(B), (D), and (E) of this subsection by telephone, mobile phone, or electronic means.

(B) A REP shall, as required by the commission after reasonable notice, provide brief public service notices to its customers. The REP shall provide these public service notices to its customers by electronic communication, or by other acceptable mass communication methods, as approved by the commission.

(6) A REP shall calculate the customer's current balance by crediting the account for payments received and reducing the account balance by known charges and fees that have been incurred, including charges based on estimated usage as allowed in paragraph (11)(E) of this subsection.

(A) The REP may also reduce the account balance by:

(i) estimated applicable taxes; and

(ii) estimated TDU charges that have been incurred in serving the customer and that, pursuant to the TOS, will be passed through to the customer.

(B) If the customer's balance reflects estimated charges and taxes authorized by subparagraph (A) of this paragraph, the REP shall promptly reconcile the estimated charges and taxes with actual charges and taxes, and credit or debit the balance accordingly within 72 hours after actual consumption data or a statement of charges from the TDU is available.

(C) A REP may reverse a payment for which there are insufficient funds available or that is otherwise rejected by a bank, credit card company, or other payor.

(D) If usage sent by the TDU is estimated or the REP estimates consumption according to paragraph (11)(E) of this subsection, the REP shall promptly reconcile the estimated consumption and associated charges with the actual consumption and associated charges within 72 hours after actual consumption data is available to the REP.

(7) A REP shall:

(A) on the request of the customer, provide the customer's current balance calculated pursuant to paragraph (6) of this subsection, including the date and time the current balance was calculated and the estimated time or days of paid electricity remaining; and

(B) make the current balance available to the customer either:

(i) continuously, via the internet, phone, or an in-home device; or

(ii) within two hours of the REP's receipt of a customer's balance request, by the means specified in the Terms of Service for making such a request.

(C) communicate to the customer the current price for electric service calculated as required by §25.475(g)(2)(A)-(E) of this title (relating to General Retail Electric Provider Requirements and Information Disclosures to Residential and Small Commercial Customers);

(D) provide a warning to the customer at least one day and not more than seven days before the customer's current balance is estimated by the REP to drop to the disconnection balance;

(E) provide a confirmation code when the customer makes a payment by credit card, debit card, or electronic check. A REP is not required to provide a confirmation code or receipt for payment sent by mail or electronic bill payment system. The REP shall provide a receipt showing the amount paid for payment in person. At the customer's request, the REP shall confirm all payments by providing to the customer the last four digits of the customer's account number or Electric Service Identifier (ESI ID), payment amount, and the date the payment was received;

(F) ensure that a CPDS controlled by the REP does not impair a customer's ability to choose a different REP or any electric service plans offered by the REP that do not require prepayment. When the REP receives notice that a customer has chosen a new REP, the REP shall take any steps necessary to facilitate the switch on a schedule that is consistent with the effective date stated on the Electric Reliability Council of Texas (ERCOT) enrollment transaction and ERCOT's rules for processing such transactions; and

(G) refund to the customer or an energy assistance agency, as applicable, any unexpended balance from the account within ten business days after the REP receives the final bill and final meter read from the TDU.

(i) In the case of unexpended funds provided by an energy assistance agency, the REP shall refund the funds to the energy assistance agency and identify the applicable customer and the customer's address associated with each refund.

(ii) In the case of unexpended funds provided by the customer that are less than five dollars, the REP shall communicate the unexpended balance to the customer and state that the customer may contact the REP to request a refund of the balance. Once the REP has received the request for refund from the customer, the REP shall refund the balance within ten business days.

(8) Nothing in this subsection limits a customer from obtaining a SUP.

(9) The communications provided under paragraph (7)(A)-(D) of this subsection and any confirmation of payment as described in paragraph (7)(E) of this subsection, except a receipt provided when the payment is made in person at a third-party payment location, shall be provided in English or Spanish, at the customer's election.

(10) A REP shall cooperate with energy assistance agencies to facilitate the provision of energy assistance payments to requesting customers.

(11) A REP shall not:

(A) tie the duration of an electric service contract to the duration of a tenant's lease;

(B) require, or enter into an agreement with a landlord requiring, that a tenant select the REP as a condition of a lease;

(C) require a connection balance in excess of $75 for a residential customer;

(D) require security deposits for electric service; or

(E) base charges on estimated usage, other than usage estimated by the TDU or estimated by the REP in a reasonable manner for a time period in which the TDU has not provided actual or estimated usage data on a web portal within the time prescribed by §25.130(g) of this title (relating to Advanced Metering) and in which the TDU-provided portal does not provide the REP the ability to obtain on-demand usage data.

(12) A REP providing service shall not charge a customer any fee for:

(A) transitioning from a prepaid service to a postpaid service, but notwithstanding §25.478(c)(3) of this title (relating to Credit Requirements and Deposits), a REP may require the customer to pay a deposit for postpaid service consistent with §25.478(b) or (c)(1) and (2) of this title and may:

(i) require the deposit to be paid within ten days after issuance of a written disconnection notice that requests a deposit; or

(ii) bill the deposit to the customer.

(B) the removal of equipment; or

(C) the switching of a customer to another REP, or otherwise cancelling or discontinuing taking prepaid service for reasons other than nonpayment, but may charge and collect early termination fees pursuant to §25.475 of this title.

(13) If a customer owes a debt to the REP for electric service, the REP may reduce the customer's account balance by the amount of the debt. Before reducing the account balance, the REP must notify the customer of the amount of the debt and that the customer's account balance will be reduced by the amount of the debt no sooner than 10 days after the notice required by this paragraph is issued.

(14) In addition to the connection balance, a REP may require payment of applicable TDU fees, if any, prior to establishing electric service or reconnecting electric service.

(15) A REP that provides prepaid service to a residential customer shall not charge an amount for electric service that is higher than the price charged by the POLR in the applicable TDU service territory. The price for prepaid service to a residential customer calculated as required by §25.475(g)(2)(A)-(E) of this title shall be equal to or lower than at least one of the tests described in subparagraphs (A)-(C) of this paragraph:

(A) The minimum POLR rate for the residential customer class at the 500 kilowatt-hour (kWh), 1,000 kWh, and 2,000 kWh usage levels as shown on the POLR EFL posted on the commission's website for the applicable TDU service territory. When an updated POLR EFL is posted on the commission's website, the REP, at the REP's option, may continue to reference the prior POLR EFL to ensure compliance with this paragraph for prepaid service prices charged during the first 30 days, beginning the date that the updated POLR EFL is posted.

(B) The maximum POLR rate for the residential customer class calculated pursuant to §25.43(l) of this title (relating to Provider of Last Resort (POLR)).

(C) The average POLR rate for the residential customer class at the 500 kWh, 1,000 kWh, and 2,000 kWh usage levels using the formula described in §25.43(l) of this title for the applicable TDU service territory, with the LSP energy charge calculated as the simple average of the RTSPPs over the prior month for the load zone located partially or wholly in the customer's TDU service territory that had the highest simple average price. For prepaid service prices charged by a REP up to and including the tenth business day of a month, the test may be met by using the average POLR rate calculation for the month preceding the prior month.

(D) For a fixed rate product, the REP must show that the prepaid service prices calculated under §25.475(g)(2)(A), (D)-(E) of this title are equal to or lower than one of the tests described in subparagraphs (A) and (C) of this paragraph at the time the REP makes the offer and provided that the customer accepts the offer within 30 days.

(d) Customer acknowledgement. As part of the enrollment process, a REP shall obtain the applicant's or customer's acknowledgement of the following statement: "The continuation of electric service depends on your prepaying for service on a timely basis and if your balance falls below {insert dollar amount of disconnection balance}, your service may be disconnected with little notice. Some electric assistance agencies may not provide assistance to customers that use prepaid service." The REP shall obtain this acknowledgement using any of the authorization methods specified in §25.474 of this title (relating to Selection of Retail Electric Provider).

(e) Prepaid disclosure statement (PDS). A REP shall provide a PDS contemporaneously with the delivery of the contract documents to a customer pursuant to §25.474 of this title and as required by subsection (f) of this section. A REP must also provide a PDS contemporaneously with any advertisement or other marketing materials not addressed in subsection (f) of this section that include a specific price or cost for prepaid service. The commission may adopt a form for a PDS. The PDS shall be a separate document and shall be at a minimum written in 12-point font, and shall:

(1) provide the following statement: "The continuation of electric service depends on you prepaying for service on a timely basis and if your current balance falls below the disconnection balance, your service may be disconnected with little notice.";

(2) inform the customer of the following:

(A) the connection balance that is required to initiate or reconnect electric service;

(B) the acceptable forms of payment, the hours that payment can be made, instructions on how to make payments, any requirement to verify payment and any fees associated with making a payment;

(C) when service may be disconnected and the disconnection balance;

(D) that prepaid service is not available to critical care or chronic condition residential customers as these terms are defined in §25.497 of this title (relating to Critical Load Industrial Customers, Critical Load Public Safety Customers, Critical Care Residential Customers and Chronic Condition Residential Customers);

(E) the means by which the REP will communicate required information;

(F) the availability of deferred payment plans and, if a REP reserves the right to apply a switch-hold while the customer is subject to a deferred payment plan, that a switch-hold may apply until the customer satisfies the terms of the deferred payment plan, and that a switch-hold means the customer will not be able to buy electricity from other companies while the switch-hold is in place;

(G) the availability of energy bill payment assistance, including the disclosure that some electric assistance agencies may not provide assistance to customers that use prepaid service and the statement "If you qualify for low-income status or low-income assistance, have received energy assistance in the past, or you think you will be in need of energy assistance in the future, you should contact the billing assistance program to confirm that you can qualify for energy assistance if you need it."; and

(H) an itemization of any non-recurring REP fees and charges that the customer may be charged.

(3) be prominently displayed in the property management office of any multi-tenant commercial or residential building at which the landlord is acting as an agent of the REP.

(f) Marketing of prepaid services.

(1) This paragraph applies to advertisements conveyed through print, television, radio, outdoor advertising, prerecorded telephonic messages, bill inserts, bill messages, and electronic media other than Internet websites. If the advertisement includes a specific price or cost, the advertisement shall include in a manner that is clear and conspicuous to the intended audience:

(A) any non-recurring fees, and the total amount of those fees, that will be deducted from the connection balance to establish service;

(B) the following statement, if applicable: "Utility fees may also apply and may increase the total amount that you pay.";

(C) the maximum fee per payment transaction that may be imposed by the REP; and

(D) the following statement: "You can obtain important standardized information that will allow you to compare this product with other offers. Contact (name, telephone number, and Internet address (if available) of the REP)." If the REP's phone number or website address is already included on the advertisement, the REP need not repeat the phone number or website as part of this required statement. The REP shall provide the PDS and EFL to a person who requests standardized information for the product.

(2) This paragraph applies to all advertisements and marketing that include a specific price or cost conveyed through Internet websites, direct mail, mass e-mails, and any other media not addressed by paragraphs (1), (3), and (4) of this subsection. In addition to meeting the requirements of §25.474(d)(7) of this title, a REP shall include the PDS and EFL on Internet websites and in direct mail, mass e-mails, and any other media not addressed by paragraphs (1), (3), and (4) of this subsection. For electronic communications, the PDS and EFL may be provided through a hyperlink.

(3) This paragraph applies to outbound telephonic solicitations initiated by the REP. A REP shall disclose the following:

(A) information required by paragraph (1)(A)-(C) of this subsection;

(B) when service may be disconnected, the disconnection balance, and any non-TDU disconnection fees;

(C) the means by which the REP will communicate required information; and

(D) the following statement: "You have the right to review standardized documents before you sign up for this product." The REP shall provide the PDS and EFL to a person who requests standardized information for the product.

(4) This paragraph applies to solicitations in person. In addition to meeting the requirements of §25.474(e)(8) of this title, before obtaining a signature from an applicant or customer who is being enrolled in prepaid service, a REP shall provide the applicant or customer a reasonable opportunity to read the PDS.

(g) Landlord as customer of record. A REP offering prepaid service to multiple tenants at a location may designate the landlord as the customer of record for the purpose of transactions with ERCOT and the TDU.

(1) For each ESI ID for which the REP chooses to designate the landlord as the customer of record, the REP shall provide to the TDU the name, service and mailing addresses, and ESI ID, and keep that information updated as required in the TDU's Tariff for Retail Delivery Service.

(2) The REP shall treat each end-use consumer as a customer for purposes of this subchapter, including §25.471 of this title (relating to General Provisions of Customer Protection Rules). Nothing in this subsection affects a REP's responsibility to provide customer billing contact information to ERCOT in the format required by ERCOT.

(h) Summary of usage and payment (SUP).

(1) A REP shall provide a SUP to each customer upon the customer's request within three business days of receipt of the request. The SUP shall be delivered by an electronic means of communications that provides a downloadable and printable record of the SUP or, if the customer requests, by the United States Postal Service. If a customer requests a paper copy of the SUP, a REP may charge a fee for the SUP, which must be specified in the TOS and PDS provided to the customer. For purposes of the SUP, a billing cycle shall conform to a calendar month.

(2) A SUP shall include the following information:

(A) the certified name and address of the REP and the number of the license issued to the REP by the commission;

(B) a toll-free telephone number, in bold-face type, that the customer can call during specified hours for questions and complaints to the REP about the SUP;

(C) the name, meter number, account number, ESI ID of the customer, and the service address of the customer;

(D) the dates and amounts of payments made during the period covered by the summary;

(E) a statement of the customer's consumption and charges by calendar month during the period covered by the summary;

(F) an itemization of non-recurring charges, including returned check fees and reconnection fees; and

(G) the average price for electric service for each calendar month included in the SUP. The average price for electric service shall reflect the total of all fixed and variable recurring charges, but not including state and local sales taxes, reimbursement for the state miscellaneous gross receipts tax, and any nonrecurring charges or credits, divided by the kilowatt-hour consumption, and shall be expressed as a cents per kilowatt-hour amount rounded to the nearest one-tenth of one cent.

(3) If a REP separately identifies a charge defined by one of the terms in this paragraph on the customer's SUP, then the term in this paragraph must be used to identify the charge, and such term and its definition shall be easily located on the REP's website and available to a customer free of charge upon request. Nothing in the paragraph precludes a REP from aggregating TDU or REP charges. For any TDU charge(s) listed in this paragraph, the amount billed by the REP shall not exceed the amount of the TDU charge(s). The label for any TDU charge(s) may also identify the TDU that issued the charge(s). A REP may use a different term than a defined term by adding or deleting a suffix, adding the word "total" to a defined term, where appropriate, changing the use of lower-case or capital letters or punctuation, or using the acceptable abbreviation specified in this paragraph for a defined term. If an abbreviation other than the acceptable abbreviation is used for the term, then the term must also be identified on the customer's SUP.

(A) Advanced metering charge--A charge assessed to recover a TDU's charges for Advanced Metering Systems, to the extent that they are not recovered in a TDU's standard metering charge. Acceptable abbreviation: Advanced Meter.

(B) Competition Transition Charge--A charge assessed to recover a TDU's charges for nonsecuritized costs associated with the transition to competition. Acceptable abbreviation: Competition Transition.

(C) Energy Efficiency Cost Recovery Factor--A charge assessed to recover a TDU's costs for energy efficiency programs, to the extent that the TDU charge is a separate charge exclusively for that purpose that is approved by the Public Utility Commission. Acceptable abbreviation: Energy Efficiency.

(D) Late Payment Penalty--A charge assessed for late payment in accordance with Public Utility Commission rules.

(E) Meter Charge--A charge assessed to recover a TDU's charges for metering a customer's consumption, to the extent that the TDU charge is a separate charge exclusively for that purpose that is approved by the Public Utility Commission.

(F) Miscellaneous Gross Receipts Tax Reimbursement--A fee assessed to recover the miscellaneous gross receipts tax imposed on retail electric providers operating in an incorporated city or town having a population of more than 1,000. Acceptable abbreviation: Gross Receipts Reimb.

(G) Nuclear Decommissioning Fee--A charge assessed to recover a TDU's charges for decommissioning of nuclear generating sites. Acceptable abbreviation: Nuclear Decommission.

(H) PUC Assessment--A fee assessed to recover the statutory fee for administering the Public Utility Regulatory Act.

(I) Sales tax--Sales tax collected by authorized taxing authorities, such as the state, cities and special purpose districts.

(J) TDU Delivery Charges--The total amounts assessed by a TDU for the delivery of electricity to a customer over poles and wires and other TDU facilities not including discretionary charges.

(K) Transmission Distribution Surcharges--One or more TDU surcharge(s) on a customer's bill in any combination. Surcharges include charges billed as tariff riders by the TDU. Acceptable abbreviation: TDU Surcharges.

(L) Transition Charge--A charge assessed to recover a TDU's charges for securitized costs associated with the transition to competition.

(4) If the REP includes any of the following terms in its SUP, the term shall be applied in a manner consistent with the definitions, and such term and its definition shall be easily located on the REP's website and available to a customer free of charge upon request:

(A) Base Charge--A charge assessed during each billing cycle of service without regard to the customer's demand or energy consumption.

(B) Demand Charge--A charge based on the rate at which electric energy is delivered to or by a system at a given instant, or averaged over a designated period during the billing cycle.

(C) Energy Charge--A charge based on the electric energy (kWh) consumed.

(5) Unless a shorter time period is specifically requested by the customer, information provided shall be for the most recent 12 months, or the longest period available if the customer has taken prepaid service from the REP for less than 12 months.

(6) In accordance with §25.472(b)(1)(D) of this title, a REP shall provide a SUP to an energy assistance agency within one business day of receipt of the agency's request, and shall not charge the agency for the SUP.

(i) Deferred payment plans. A deferred payment plan for a customer taking prepaid service is an agreement between the REP and a customer that requires a customer to pay a negative current balance over time. A deferred payment plan may be established in person, by telephone, or online, but all deferred payment plans shall be confirmed in writing by the REP to the customer.

(1) The REP shall place a residential customer on a deferred payment plan, at the customer's request:

(A) when the customer's current balance reflects a negative balance of $50 or more during an extreme weather emergency, as defined in §25.483(j)(1) of this title, if the customer makes the request within one business day after the weather emergency has ended; or

(B) during a state of disaster declared by the governor pursuant to Texas Government Code §418.014 if the customer is in an area covered by the declaration and the commission directs that deferred payment plans be offered.

(2) The REP shall offer a deferred payment plan to a residential customer who has been underbilled by $50 or more for reasons other than theft of service.

(3) The REP may offer a deferred payment plan to a customer who has expressed an inability to pay.

(4) The deferred payment plan shall include both the negative current balance and the connection balance.

(5) The customer has the right to satisfy the deferred payment plan before the prescribed time.

(6) The REP may require that:

(A) no more than 50% of each transaction amount be applied towards the deferred payment plan; or

(B) an initial payment of no greater than 50% of the amount due be made, with the remainder of the deferred amount paid in installments. The REP shall inform the customer of the right to pay the remaining deferred balance by reducing the deferred balance by five equal monthly installments. However, the customer can agree to fewer or more frequent installments. The installments to repay the deferred balance shall be applied to the customer's account on a specified day of each month.

(7) The REP may initiate disconnection of service if the customer does not meet the terms of a deferred payment plan or if the customer's current balance falls below the disconnection balance, excluding the remaining deferred amount. However, the REP shall not initiate disconnection of service unless it has provided the customer at least one day's notice that the customer has not met the terms of the plan or, pursuant to subsection (c)(7)(D) of this section, a timely notice that the customer's current balance was estimated to fall below the disconnection balance, excluding the remaining deferred amount.

(8) The REP may apply a switch-hold while the customer is on a deferred payment plan.

(9) A copy of the deferred payment plan shall be provided to the customer.

(A) The plan shall include a statement, in clear and conspicuous type, that states, "If you have any questions regarding the terms of this agreement, or if the agreement was made by telephone and you believe this does not reflect your understanding of that agreement, contact (insert name and contact number of REP)."

(B) If a switch-hold will apply, the plan shall include a statement, in a clear and conspicuous type, that states "By entering into this agreement, you understand that {company name} will put a switch-hold on your account. A switch-hold means that you will not be able to buy electricity from other companies until you pay this past due amount. The switch-hold will be removed after your final payment on this past due amount is processed. While a switch-hold applies, if you are disconnected for not paying, you will need to pay {us or company name}, to get your electricity turned back on."

(C) If the customer and the REP's representative or agent meet in person, the representative shall read to the customer the statement in subparagraph (A) of this paragraph and, if applicable, the statement in subparagraph (B) of this paragraph.

(D) The plan may include a one-time penalty in accordance with §25.480(c) of this title, but shall not include a finance charge.

(E) The plan shall include the terms for payment of deferred amounts, consistent with paragraph (6) of this subsection.

(F) The plan shall state the total amount to be paid under the plan.

(G) The plan shall state that a customer's electric service may be disconnected if the customer does not fulfill the terms of the deferred payment plan, or if the customer's current balance falls below the disconnection balance, excluding the remaining deferred amount.

(10) The REP shall not charge the customer a fee for placing the customer on a deferred payment plan.

(11) The REP, through a standard market process, shall submit a request to remove the switch-hold, pursuant to §25.480(m)(2) of this title if the customer pays the deferred balance owed to the REP. On the day the REP submits the request to remove the switch-hold, the REP shall notify the customer that the customer has satisfied the deferred payment plan and that the switch-hold is being removed.

(j) Disconnection of service. As provided by subsection (a)(4) of this section, §25.483 (b)(2)(A) and (B), (d), (e)(1)-(6), and the definition of extreme weather in §25.483(j)(1) of this title apply to prepaid service. In addition to those provisions, this subsection applies to disconnection of a customer receiving prepaid service.

(1) Prohibition on disconnection. A REP shall not initiate disconnection for a customer's failure to maintain a current balance above the disconnection balance on a weekend day or during any period during which the mechanisms used for payments specified in the customer's PDS are unavailable; or during an extreme weather emergency, as this term is defined in §25.483 of this title, in the county in which the service is provided.

(2) Initiation of disconnection. A REP may initiate disconnection of service when the current balance falls below the disconnection balance, but only if the REP provided the customer a timely warning pursuant to subsection (c)(7)(D) of this section; or when a customer fails to comply with a deferred payment plan, but only if the REP provided the customer a timely warning pursuant to subsection (i)(7) of this section. A REP may initiate disconnection if the customer's current balance falls below the disconnection balance due to reversal of a payment found to have insufficient funds available or is otherwise rejected by a bank, credit card company, or other payor.

(3) Pledge from electric assistance agencies. If a REP receives a pledge, letter of intent, purchase order, or other commitment from an energy assistance agency to make a payment for a customer, the REP shall immediately credit the customer's current balance with the amount of the pledge.

(A) The REP shall not initiate disconnection of service if the pledge from the energy assistance agency (or energy assistance agencies) establishes a current balance above the customer's disconnection balance or, if the customer has been disconnected, shall request reconnection of service if the pledge from the energy assistance agency establishes a current balance for the customer that is at or above the customer's connection balance required for reconnection.

(B) The REP may initiate disconnection of service if payment from the energy assistance agency is not received within 45 days of the REP's receipt of the commitment or if the payment is not sufficient to satisfy the customer's disconnection balance in the case of a currently energized customer, or the customer's connection balance if the customer has been disconnected for falling below the disconnection balance.

(4) Reconnection of service. Within one hour of a customer establishing a connection balance or any otherwise satisfactory correction of the reasons for disconnection, the REP shall request that the TDU reconnect service or, if the REP disconnected service using its CPDS, reconnect service. The REP's payment mechanism may include a requirement that the customer verify the payment using a card, code, or other similar method in order to establish a connection balance or current balance above the disconnection balance when payment is made to a third-party processor acting as an agent of the REP.

(k) Service to Critical Care Residential Customers and Chronic Condition Residential Customers. A REP shall not knowingly provide prepaid service to a customer who is a critical care residential customer or chronic condition residential customer as those terms are defined in §25.497 of this title. In addition, a REP shall not enroll an applicant who states that the applicant is a critical care residential customer or chronic condition residential customer.

(1) If the REP is notified by the TDU that a customer receiving prepaid service is designated as a critical care residential customer or chronic condition residential customer, the REP shall diligently work with the customer to promptly transition the customer to postpaid service or another REP in a manner that avoids a service disruption. The REP shall not charge the customer a fee for the transition, including an early termination or disconnection fee.

(2) If the customer is unresponsive, the REP shall transfer the customer to a competitively offered, month-to-month postpaid product at a rate no higher than the rate calculated pursuant to §25.43(l)(2)(A) of this title. The REP shall provide the customer notice that the customer has been transferred to a new product and shall provide the customer the new product's Terms of Service and Electricity Facts Label.

(l) Compliance period. No later than October 1, 2011, prepaid service offered by a REP pursuant to a new contract to a customer being served using a "settlement provisioned meter," as that term is defined in Chapter 1 of the TDU's tariff for retail delivery service, or using a REP-controlled collar or meter shall comply with this section. Before October 1, 2011, prepaid service offered by a REP to a customer served using a settlement provisioned meter or REP-controlled collar or meter shall comply with this section as it currently exists or as it existed in 2010, except as provided in subsection (m) of this section.

(m) Transition of Financial Prepaid Service Customers. A REP may continue to provide a financial prepaid service (i.e., one that does not use a settlement provisioned meter or REP-controlled collar or meter) only to its customer that was receiving financial prepaid service at a particular location on October 1, 2011. A customer who is served by a financial prepaid service shall be transitioned to a service that complies with the other subsections of this section by the later of October 1, 2011 or sixty days after the customer begins to be served using either a settlement provisioned meter or a REP-controlled collar or meter. The customer shall be notified by the REP that the customer's current prepaid service will no longer be offered as of a date specified by the REP by the later of either October 1, 2011 or sixty days after the customer begins to be served using either a settlement provisioned meter or REP-controlled collar or meter, as applicable. The REP shall provide the notification no sooner than 60 days and not less than 30 days prior to the termination of the customer's current prepaid service. The customer shall be notified that the customer will be moved to a new prepaid service, and the REP shall transmit an EFL and PDS to the customer with the notification, if the customer does not choose another service or REP.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on April 23, 2018.

TRD-201801815

Adriana Gonzales

Rules Coordinator

Public Utility Commission of Texas

Effective date: May 13, 2018

Proposal publication date: December 29, 2017

For further information, please call: (512) 936-7223