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PUC DOCKET NO. 22348 SOAH DOCKET NO. 473-00-1013

APPLICATION OF SHARYLAND § PUBLIC UTILITY COMMISSION UTILITIES, LP FOR APPROVAL OF § UNBUNDLED COST OF SERVICE RATE § PURSUANT TO PURA § 39.201 AND § PUBLIC UTILITY COMMISSION § OF TEXAS SUBSTANTIVE RULE § 25.344 §

Table of Contents

Table of Pleadings...... iii List of Acronyms...... vii I. Introduction...... 2 A. Statutory Background...... 2 B. Procedures...... 3 1. Generic Docket...... 3 2. Sharyland Docket...... 5 II. Discussion...... 7 A. Generic Docket...... 7 B. Generic Proceeding...... 7 1. Transmission And Distribution Rates...... 8 a. Recovery of Certain Costs By TDU’s...... 8 b. Return on Equity and Capital Structure...... 11 c. Generic O&M Escalation Factors...... 14 d. Uniform Customer Classification Scheme and Uniform Rate Design...... 18 e. Recovery of Transmission Charges...... 28 f. Forecasted ERCOT 2002 Four Coincident Peak...... 34 2. Other Issues...... 36 a. System Benefit Fund...... 39 b. Payment of Stranded Costs and Discontinuation of Service...... 40 C. Code of Conduct...... 41 D. Business Separation Plan...... 42 E. ECOM...... 43 F. Transmission and Distribution...... 43 G. Other Issues...... 45 1. Meter Reading as Competitive Energy Service...... 45 PUC Docket No. 22348 Table of Contents Page ii SOAH Docket No. 473-00-1013

2. Commitment to File New Rate Case...... 46 3. Residential Rate Cap...... 46 III. Findings of fact...... 47 A. Generic Docket...... 47 1. Procedural History...... 47 a. Category “A” and “B” Issues...... 50 b. Payment of Stranded Costs...... 52 c. Generic Operation and Maintenance Escalators...... 53 d. Natural Gas Prices and Market Prices...... 53 e. Rate Design and Customer Classification...... 54 f. Incentive Plan, Return on Equity, and Capital Structure...... 55 g. Four Coincident Peak...... 57 h. Retail Transmission Charges...... 58 2. Transmission and Distribution (T&D) Rates...... 59 a. T&D Cost of Service...... 59 b. Uniform Customer Classification...... 63 c. Generic T&D Rate Design...... 64 d. Exceptions to Generic Rate Design and Customer Classification...... 73 e. Other Non-Bypassable Charges...... 74 f. Tariffs...... 74 3. Other Generic Issues...... 75 a. Targeted Incentive Plan (TIP)...... 75 b. Pilot Project...... 75 B. Code of Conduct, Business Separation Plan, Transmission and Distribution...... 76 1. Procedural History...... 76 2. Settlement...... 78 3. Informal Disposition...... 81 IV. Conclusions of Law...... 81 A. General...... 81 B. Generic Proceeding...... 82 1. Procedural History...... 82 2. Transmission and Distribution (T&D) Rates...... 83 a. T&D Cost of Service...... 83 b. Uniform Customer Classification...... 87 c. Generic T&D Rate Design...... 87 d. Exceptions to Generic Rate Design and Customer Classification...... 89 e. Other Non-Bypassable Charges...... 89 3. Other Generic Issues...... 90 a. Targeted Incentive Plan (TIP)...... 90 b. Pilot Project...... 90 C. Code of Conduct, Business Separation Plan, Transmission and Distribution...... 90 V. Ordering Paragraphs...... 92 A. Generic Ordering Paragraphs...... 92 B. Code of Conduct, Business Separation Plan, Transmission and Distribution...... 95 PUC Docket No. 22348 Table of Contents Page iii SOAH Docket No. 473-00-1013

APPENDIX A: Code of Conduct – Revised Paragraph F...... 97 ATTACHMENT: TRANSMISSION RATE DESIGN SCHEDULES, EXCERPT OF AUGUST 1, 2000 FILING...... 99 TABLE OF PLEADINGS

Docket No. 22344 – Generic UCOS Proceeding Date AIS No. Abbreviated Pleading Title Reference 04/06/00 4 Order Initiating Order Initiating Proceeding Proceeding 04/07/00 5 Notice of Notice of Proceeding to Address Issues Proceeding Generic to Applications for Approval of Unbundled Cost of Service Rate Dockets 05/09/00 50 Order No. 3 Order No. 3 – Granting Interventions, Identifying Issues, and Requesting Briefing 05/12/00 53 Order No. 4 Order No. 4 – Granting Interventions 05/23/00 62 Order No. 5 Order No. 5 – Granting Interventions

06/05/00 138 Order No. 7 Order No. 7 – Addressing Motions to Intervene 06/13/00 187 Order No. 11 Order No. 11 – Consolidating Docket No. 22633 with Docket No. 22344 06/13/00 188 Order No. 10 Order No. 10 – Granting Intervention, Designating a New Generic Issue, and Establishing Briefing Schedule 06/14/00 189 Order No. 12 Order No. 12 – Designating a New Generic Issue and Establishing Briefing Schedule 07/13/00 254 Order No. 15 Order No. 15 – Interim Order Ruling on Order No. 12 Issue 07/18/00 256 Order No. 14 Order No. 14 – Ruling on Category A Issues 07/18/00 257 Order No. 18 Order No. 18 – Memorializing Pre-Hearing Conference of July 17, 2000 07/24/00 261 Order No. 17 Order No. 17 – Ruling on Category B Issues 08/01/00 283 Order No. 20 Order No. 20 – Memorializing Pre-Hearing Conference on July 28, 2000 08/11/00 341 Order No. 21 Order No. 21 – Interim Order Expanding Scope of Generic Customer Classification and Rate Design Issues 08/11/00 342 Order No. 22 Order No. 22 – Interim Order Ruling Setting Natural Gas Prices and Market Prices for Use in ECOM Model 08/15/00 363 Target Incentive Target Incentive Program Program 08/16/00 366 Order No. 23 Order No. 23 – Memorializing Ruling On PUC Docket No. 22348 Table of Contents Page v SOAH Docket No. 473-00-1013

Date AIS No. Abbreviated Pleading Title Reference ORA’s Motion To Clarify Order No. 14 and Granting ORA’s Motion To Modify Procedural Schedule With Respect To Factual Hearing On Customer Classification and Rate Design 08/25/00 405 Order No. 25 Order No. 25: Interim Order Ruling On Escalator Issues 09/08/00 438 Customer Distribution Service Customer Classification Classification Non-Unanimous Stipulation And Agreement NUA 09/18/00 452 Targeted Incentive Targeted Incentive Program and Report On Program Settlement Conference 09/22/00 456 Order No. 28 Order No. 28 – Interim Order Ruling On Incentive Plan and Return On Equity Issues 10/19/00 533 ROE and Capital Return on Equity and Capital Structure Non- Structure NUA Unanimous Stipulation and Agreement 11/22/00 655 Order No. 40 Order No. 40 : Interim Order Establishing Generic Customer Classification and Rate Design 12/14/00 678 Order No. 43 Order No. 43 Expanding Scope of Generic Proceeding, Admitting Additional Parties, Identifying Issue For Resolution, and Scheduling Pre-Hearing Conference 12/21/00 685 Order No. 44 Order No. 44 Clarifying Scope of 4CP Issue 12/22/00 687 Order No. 42 Order No. 42: Interim Order Establishing Return on Equity and Capital Structure 01/12/01 696 Order No. 46 Order No. 46 – Memorializing Prehearing Conference Held on January 12, 2001 02/21/01 708 ERCOT 4CP NUA Forecast ERCOT 2002 Four Coincident Peak Stipulation and Agreement 03/21/01 717 Order No. 51 Order No. 51 Identifying Issue for Resolution, Providing Notice, and Establishing Procedural Schedule 03/22/01 719 Order No. 50 Order No. 50 – Interim Order Establishing Forecasted ERCOT 2002 Four Coincident Peak 04/06/01 731 ERCOT Retail ERCOT Retail Transmission Charge Transmission Calculation Stipulation and Agreement Charge NUA 04/26/01 735 Order No. 53 Order No. 53: Interim Order Addressing Issue Identified in Order No. 51: ERCOT Retail Transmission Charge Calculation PUC Docket No. 22348 Table of Contents Page vi SOAH Docket No. 473-00-1013

Docket No. 22348 – Sharyland Specific UCOS Proceeding

Date Filed AIS No. Abbreviated Reference Pleading Title 03/31/2000 2 Application of Sharyland Utilities, L.P. for Approval of Unbundled Transmission and Distribution Rates 05/01/2000 20 Supplement to Application of Sharyland Utilities, L.P. 06/07/2000 43 Preliminary Order 03/02/2001 93 Agreement Joint Motion for Approval of Stipulation and Agreement 06/04/2001 111 Interim Order-Rate Phase 07/20/2001 115 Revised Interim Order-Rate Phase LIST OF ACRONYMS

4CP – four-month coincident peak (June through September)

A&G – administrative and general

AEP – American Electric Power Company

ALJ – administrative law judge

CPL – Central Power and Light Company

CTC – competition transition charge

ECOM – excess cost over market

ERCOT – Electric Reliability Council of Texas

FERC – Federal Electric Regulatory Commission

IDR – interval data recorder

NCP – non-coincident peak

NUA – non-unanimous stipulation and agreement

O&M – operation and maintenance

PFD – proposal for decision

PTB – price-to-beat

PURA – Public Utility Regulatory Act

REP – retail electric provider

ROE – return on equity

SB7 – Senate Bill 7 (76th Legislature)

SBF – System Benefit Fund

SIHL – state institution of higher learning PUC Docket No. 22348 Consolidated Interim Order Page viii SOAH Docket Nos. 473-00-1013

SOAH – State Office of Administrative Hearings

SWEPCO – Southwestern Electric Power Company

T&D – transmission and distribution

TC – transition charge

TCOS – transmission cost of service

TCRF – transmission cost recovery factor

TDU – transmission and distribution utility

TIP – targeted incentive plan

TSP – transmission service provider UCOS – unbundled cost of service PUC DOCKET NO. 22348 SOAH DOCKET NO. 473-00-1013

APPLICATION OF SHARYLAND § PUBLIC UTILITY COMMISSION UTILITIES, LP FOR APPROVAL OF § UNBUNDLED COST OF SERVICE RATE § PURSUANT TO PURA § 39.201 AND § PUBLIC UTILITY COMMISSION § OF TEXAS SUBSTANTIVE RULE § 25.344 §

CONSOLIDATED INTERIM ORDER

This Order addresses Sharyland Utilities, L.P.’s (Sharyland) application for approval of unbundled cost of service (UCOS) rates. Primarily, this Order addresses Sharyland’s code of conduct, separation of business functions (business separation plan), and transmission and distribution rates; however, it addresses a number of other issues as well. It incorporates and supercedes the decisions and orders of the Commission in the Generic Proceeding1 as well as all interim orders in this docket. While this Order systematically addresses final restructuring issues, parties who are interested in a greater level of detail are encouraged to refer to the initial decisions of the Commission as reflected in the various interim orders entered in both the Generic Proceeding and this company-specific docket. The Table of Pleadings identifies these interim orders to aid in this process.

This Order contains a brief discussion of statutory and procedural background, addresses issues considered in the Generic Proceeding, and then addresses issues decided in the various phases of the company-specific docket.

Sharyland’s application for approval of UCOS rates, consistent with the settlement of the settling parties, is hereby approved.

1 Generic Issues Associated with Applications for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and Public Utility Commission Substantive Rule 25.344, Docket No. 22344 (Generic Proceeding), Order No. 14 (July 18, 2000) and Order No. 17 (July 24, 2000). PUC Docket No. 22348 Consolidated Interim Order Page 2 SOAH Docket Nos. 473-00-1013

I. INTRODUCTION

A. Statutory Background

Having formulated a public policy shift from comprehensive regulation to increased competition and having determined that the production and retail sale of electricity should no longer be subject to extensive governmental regulation, on May 27, 1999, the Texas Legislature enacted, and on June 18, 1999 Governor George W. Bush signed, Senate Bill 7 (SB7)2 relating to electric utility restructuring and requiring electric utilities in most areas of Texas to prepare for retail electric competition to begin January 1, 2002.

Material portions of SB7 are codified amendments to Title II of the Texas Utilities Code. Specifically, amendments were made to the Public Utility Regulatory Act (PURA),3 Chapter 39. PURA, Chapter 39, was enacted to protect the public interest during the transition to and the establishment of a fully competitive electric market power industry in Texas.4 These modifications establish the perimeters within which deregulation restructuring is to take place in Texas and allow prices of electricity to be set in accordance with customer choice and competition. PURA Chapter 39, Restructuring of Electric Utility Industry, provides the framework for the restructuring of the electric utility industry by January 1, 2002. This Order specifically addresses the provisions of PURA § 39.201, requiring the initiation of the utilities’ tariff applications for the establishment of rates and charges following the initiation of competition in Texas.

2 Tex. S.B. 7, 76th Leg., R.S. (1999) codified at Tex. Utilities Code Ann. § § 11.001-64.158 (Vernon 1998 & Supp. 2001). 3 Public Utility Regulatory Act, Tex. Util. Code Ann. § § 11.001-64.158 (Vernon 1998 & Supp. 2000) (PURA). See also current Supp. 2001. 4 PURA § 39.001(a) (Vernon 1998 & Supp. 2001) PUC Docket No. 22348 Consolidated Interim Order Page 3 SOAH Docket Nos. 473-00-1013

B. Procedures

1. Generic Docket

To institute retail competition in the electric industry, SB7 requires electric utilities to unbundle their business functions and establish transmission and distribution (T&D) rates for various non-bypassable “wires” charges to reflect costs that are reasonable and necessary. 5 In compliance with SB7, Sharyland filed an application proposing rates based on costs it projects will exist in the future, using 2002 as its forecast test year.6 This application has been commonly referred to by the Commission and the parties as the Company’s unbundled cost of service, or UCOS, case.

The 1999 statute requires existing utilities to separate themselves into three distinct units: a power generation company, a T&D utility, and a retail company. Because all retail competitors will depend on the T&D utility’s power lines to deliver electricity to the retailer’s customers, the rates and services of the T&D utility remain regulated by the Commission.

The Commission determined that a generic proceeding was the most efficient and appropriate method for determining threshold issues relevant to those utilities involved in the deregulation and restructuring process.7 On April 6, 2000, the Commission’s ALJ issued Order

5 See generally, Public Utility Regulatory Act, TEX. UTIL. CODE ANN. Chapter 39 (Vernon 1998 & Supp. 2001) (PURA).

6 See P.U.C. SUBST. R. 25.344(d). 7 Application of Sharyland Utilities, L.P. for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and Public Utility Commission Substantive Rule 25.344, Docket No. 22348 (pending); Application of Texas-New Mexico Power Company for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and Public Utility Commission Substantive Rule 25.344, Docket No. 22349 (pending); Application of TXU Electric for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and Public Utility Commission Substantive Rule 25.344, Docket No. 22350 (pending); Application of Southwestern Public Service Company for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and Public Utility Commission Substantive Rule 25.344, Docket No. 22351 (pending); Application of Central Power and Light Company for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and Public Utility Commission Substantive Rule 25.344, Docket No. 22352 (pending); Application of Southwestern Electric Power Company for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and Public Utility Commission Substantive Rule 25.344, Docket No. 22353 (pending); Application of West Texas Utilities Company for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and Public Utility Commission Substantive Rule 25.344, Docket No. 22354 (pending); Application of Reliant Energy HL&P for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and Public Utility Commission Substantive Rule 25.344, Docket No. 22355 (pending); and Application of Entergy Gulf States, Inc. for Approval of Unbundled Cost of Service Rate PUC Docket No. 22348 Consolidated Interim Order Page 4 SOAH Docket Nos. 473-00-1013

No. 1, initiating Docket No. 22344, Generic Issues Associated with Applications for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 25.344 (Generic Proceeding).

The Commission directed all parties to file lists of issues to be addressed and to separately identify those issues generic to all unbundled cost of service filings. In addition, parties were encouraged to identify any issues that should not be addressed in the docket and to identify any threshold legal and/or policy issues or matters of precedent that necessitated briefing. The Commission made clear its intent that all matters decided in the Generic Proceeding would be applied to each individual, utility-specific proceeding.

On May 9, 2000, the Commission identified and requested briefing on thirteen issues for resolution to be made during the June open meetings. The breadth and complexity of the issues necessitated that the issues be heard over the course of two open meetings. Seven issues were slated for consideration at the June 14 open meeting and six were assigned to the June 29 open meeting. Briefs and reply briefs were scheduled accordingly. The Commission’s decisions at the June 14 open meeting (commonly referred to as “Category A” issues) were memorialized in Generic Proceeding Order No. 14; the June 29 (“Category B”) rulings were set out in Generic Proceeding Order No. 17. The Commission’s decisions regarding these generic issues are discussed in further detail in this Order. The Commission further addresses some of these generic issues, as well as additional generic issues, in subsequent Orders in the Generic Proceeding.

In separate company-specific proceedings, the Commission addressed related issues in multiple phases. The business separation phase reviewed the company’s plan for dividing itself into a power generation company, a T&D utility, and a retail company. In the stranded cost phase, an examination was made of those stranded costs reasonably projected to exist when retail competition begins January 1, 2001. Stranded costs are the anticipated difference between the book value of an existing utility’s generation assets and the market value of those same assets. The final phase was conducted to determine what level of rates the T&D utility would be authorized to charge retailers. In this portion of the proceeding, the utility’s costs for providing

Pursuant to PURA § 39.201 and Public Utility Commission Substantive Rule 25.344, Docket No. 22356 (pending). PUC Docket No. 22348 Consolidated Interim Order Page 5 SOAH Docket Nos. 473-00-1013

T&D service were examined. In addition to memorializing the Commission’s decisions on each of these matters, this Order provides details relevant to both the Generic Proceeding and this company-specific docket.

2. Sharyland Docket

Sharyland is a start-up retail electric utility, providing electric utility service to residential, commercial and industrial customers of Sharyland Plantation, a 6,000-acre planned community located between the Cities of McAllen and Mission in Hildalgo County. On July 9, 1999, the Commission granted to Sharyland a certificate of convenience and necessity to begin providing retail electric service in Hildalgo County,8 and on July 26, 2000, the Commission approved its initial rates.9 On May 31, 2000, Sharyland filed its application for approval of unbundled transmission and distribution rates,10 and on May 1, 2000, Sharyland filed a supplement to its application.11 Sharyland intends to provide only transmission and distribution (T & D) service after December 31, 2001.

Just prior to the instant Order, the Commission issued an Interim Order-Rate Phase in this docket in which it approved Sharyland’s application for approval of UCOS rates consistent with

8 Application of Sharyland Utilities, L.P. for a Certificate of Convenience and Necessity in Hildlago County, Texas, Docket No. 20292, Order (July 9, 1999). 9 Application of Sharyland Utilities, L.P. for Authority to Establish Initial Rates and Tariff, Docket No. 21591, Order (July 26, 2000). Pursuant to its initial rate order, Sharyland is to file a general rate proceeding no later than May 1, 2003, which is in addition to the instant UCOS rate case and which will only apply to Sharyland’s transmission and distribution (T&D) rates since the proceeding will occur after the onset of competition. See Docket No. 21591, Order at 4 (July 26, 2000). Further, Sharyland is to abide by a residential rate cap, subject to certain conditions, through May 1, 2005. See Docket No. 21591, Order at 5 (July 26, 2000). Generally, pursuant to this rate cap, Sharyland agreed that its average bundled residential rate will not exceed Central Power & Light Company’s (CPL) average bundled residential rate; and, Sharyland agreed to keep its average unbundled T&D rates at or below the average unbundled T&D (including non-bypassable charges) rates of CPL. See Docket No. 21591, Proposal for Decision at 3 (May 26, 2000). For a more detailed treatment of the terms of Sharyland’s residential rate cap, see Docket No. 21591, Stipulation and Agreement at 13 (March 6, 2000). 10 Application of Sharyland Utilities, L.P., for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and Public Utility Commission Substantive Rule § 25.344, Docket No. 22348, Application of Sharyland Utilities, L.P. for Approval of Unbundled Transmission and Distribution Rates (March 31, 2000) 11 Supplement to Application of Sharyland Utilities, L.P. (May 1, 2000). In its supplement, Sharyland noted that it was unable to include in its application a complete set of rate schedules due to a then pending settlement in Docket No. 21591 in which it agreed to a residential rate cap tied to the average residential rates of CPL. Because Sharyland filed its application on the same day that CPL filed its unbundled transmission and distribution application, Sharyland did not know what its rate cap was for purposes of the settlement. See Supplement to Application of Sharyland Utilities, L.P. at 2-3 (May 1, 2000). PUC Docket No. 22348 Consolidated Interim Order Page 6 SOAH Docket Nos. 473-00-1013 a settlement among the parties.12 In that interim order, the Commission noted that Sharyland and Commission Staff (Settling Parties) filed a stipulation and agreement of settlement (Settlement) that provided for approval of Sharyland’s application, and that the Settling Parties were authorized to state that the remaining parties to the proceeding, Office of Public Utility Counsel, TXU Electric Company, and the National Association of Energy Service Companies did not oppose the Settlement.13

Sharyland filed a motion for modification/reconsideration of the Commission’s Interim Order– Rate Phase, in which it requested that the time requirement for filing its compliance tariff for its transmission and distribution rates be changed from “no later than 30 days after the effective date of the Interim Order” to “no later than 20 days after Central Power and Light Company’s T & D tariff for January 1, 2002, is approved in Docket No. 22352.”14 In a supplement to its motion for modification, Sharyland noted that Commission Staff concurred in this requested change.15 Because Sharyland agreed in its initial rate case, Docket No. 21591, to a residential rate cap that was linked to CP&L’s average residential rates, the Commission approved Sharyland’s requested modification and issued a Revised Interim Order–Rate Phase to allow Sharyland to comply with its initial rate settlement.16 With the instant Order, the Commission approves Sharyland’s application for approval of UCOS rates consistent with the Settling Parties’ Settlement.

12 Interim Order-Rate Phase (June 4, 2001). 13 Interim Order-Rate Phase at 1 (June 4, 2001). 14 Motion of Sharyland Utilities, L.P. for Modification or, in the Alternative, Reconsideration of Interim Order-Rate Phase at 1 (June 14, 2001). 15 Supplement to the Motion of Sharyland Utilities, L.P. for Modification or, in the Alternative, Reconsideration of Interim Order-Rate Phase (June 19, 2001). 16 Revised Interim Order-Rate Phase (July 20, 2001). PUC Docket No. 22348 Consolidated Interim Order Page 7 SOAH Docket Nos. 473-00-1013

II. DISCUSSION

A. Generic Docket

This discussion section is divided into two parts: The Generic Proceeding issues are first discussed, followed by the utility-specific-docket issues. The discussion of the Generic Proceeding is broken into two general areas (T&D and Other) and incorporates the Commission’s decisions in the Generic Proceeding.17 Much of the Commission’s directive for application of procedural and policy matters is contained in Generic Proceeding Order Nos. 14 and 17; however, those two Orders must be read in conjunction with the other Generic Proceeding Orders and instruments to determine the full scope of the Commission’s final decisions. Application of the Commission’s Generic Proceeding decisions is reflected in many of the utility-specific docket Orders. Thus, the second portion of this Discussion Section expands on the Commission’s Orders in both dockets.

B. Generic Proceeding

In order to develop a list of issues to be considered in this proceeding, the Commission directed all parties, including TXU, to file by April 26, 2000, a list of issues to be addressed and separately to identify those issues generic to all unbundled-cost-of-service filings.18 In addition,

17 Generic Proceeding, Order Nos. 12, 14, 15, 17, 21, 22, 25, 28, 40, 42, 43, 44, 50, 51, and 53. 18 Application of Sharyland Utilities, L.P., for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and P.U.C. SUBST. R. 25.344, Docket No. 22348 (pending); Application of Texas-New Mexico Power Company for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and P.U.C. SUBST. R. 25.344, Docket No. 22349 (pending); Application of TXU Electric Company for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and P.U.C. SUBST. R. 25.344, Docket No. 22350 (pending); Application of Southwestern Public Service Company for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and P.U.C. SUBST. R. 25.344, Docket No. 22351 (pending); Application of Central Power & Light Company for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and P.U.C. SUBST. R. 25.344, Docket No. 22352 (pending); Application of Southwestern Electric Power Company for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and P.U.C. SUBST. R. 25.344, Docket No. 22353 (pending); Application of West Texas Utilities Company for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and P.U.C. SUBST. R. 25.344, Docket No. 22354 (pending); Application of Reliant Energy HL&P for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and P.U.C. SUBST. R. 25.344, Docket No. 22355 (pending); Application of Entergy Gulf States, Inc, for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and P.U.C. SUBST. R. 25.344, Docket No. 22356 (pending); hereinafter, individual UCOS cases. PUC Docket No. 22348 Consolidated Interim Order Page 8 SOAH Docket Nos. 473-00-1013 parties were encouraged to identify any issues that should not be addressed in the docket and to identify any threshold legal and policy issues or matters of precedent that required briefing.19 The Commission informed all parties that the decisions made by the Commission in the Generic Proceeding would be applied to each utility-specific docket.20

The Commission’s Administrative Law Judge (ALJ) issued Order No. 3,21 identifying generic issues, dividing those issues into two groups, and requesting parties’ briefs on generic threshold issues in the Generic Proceeding. Because of the extensive number of issues, they were divided into two groups, Category A and Category B, based on the time sensitivity of each issue rather than by substantive alliance. The issues were extensively briefed. The Commission discussed the Category A and Category B issues during the June 14, 2001 and June 29, 2001 open meetings, respectively. The following discussion of issues addressed in the Generic Proceeding is organized by subject matter as follows: T&D and other miscellaneous issues.

1. Transmission And Distribution Rates a. Recovery of Certain Costs By TDU’s

(Generic Proceeding Order No. 17: Category B Issue No. 2)

Are the following costs recoverable as costs of the T&D utility: rate case expenses, restructuring costs, energy efficiency costs, and costs of the pilot project? Are special cost- recovery mechanisms for costs incurred prior to January 2002 permitted under PURA, and if so, are they appropriate? Do the rate freeze and rate path prescribed by SB7 limit the recovery of these costs?

The Commission notes that recovery of costs by an electric utility is addressed in both chapters 36 and 39 of PURA. The overall purpose of PURA Subtitle B, Electric Utilities, “is to establish a comprehensive and adequate regulatory system for electric utilities to assure rates,

19 Id., Order Initiating Proceeding at 2 (April 6, 2000). 20 See Preliminary Order at 2 and 5 (June 1, 2000); Generic Proceeding, Order No. 3 at 5 (May 9, 2000). 21 Generic Proceeding, Order No. 3, Granting Interventions, Identifying Issues, and Requesting Briefing at 2-5 (May 9, 2000). PUC Docket No. 22348 Consolidated Interim Order Page 9 SOAH Docket Nos. 473-00-1013 operations, and services that are just and reasonable to the consumers and the electric utilities.” 22 Chapter 39 was subsequently “enacted to protect the public interest during the transition to and in the establishment of a fully competitive electric power industry.”23 In the event that “there is a conflict between the specific provisions of [chapter 39] and any other provisions of [PURA], . . . the provisions of [chapter 39] control.”24 In light of these statutory provisions, the Commission agrees that PURA § 36.051 provides guidance for determining T&D rates. PURA § 39.201, which provides a general framework for establishing post-2002 cost-of-service tariffs and charges, must take precedence in the event of any conflict.

Accordingly, the Commission concludes that the recovery of expenses incurred prior to January 2002, is generally not appropriate because PURA § 39.201(b)(1) requires that the rates set in this proceeding are to be “based upon a forecasted 2002 test year” and because PURA § 39.052 freezes existing retail base-rate tariffs until January 1, 2002. As noted by some parties, the rate-freeze provision of PURA § 39.052 benefit both retail consumers and utilities prior to the onset of competition. Furthermore, the annual-report process provides an avenue for utilities to recover some costs during the transition period.25

In addition, the Commission determines that any expenses or costs recoverable through T&D rates in the 2002 forecasted test year must be demonstrably related to the T&D function. Costs related to generation or retail sales cannot be included in T&D rates. This determination is consistent with, if not mandated by, the provisions of Chapter 39 that require business separation and with the Commission’s mandate pursuant to PURA § 39.201 to establish rates for the transmission and distribution utility (TDU). Allocation of recoverable costs to the appropriate T&D functions should occur in the company-specific proceeding.

The Commission finds, however, that rate-case expenses related to the T&D function and determined reasonable and necessary, including those incurred prior to January 2002, are recoverable and may be amortized over an appropriate time period to mitigate rate impact. This

22 PURA § 31.001(a). 23 Id. § 39.001(a). 24 Id. § 39.002. 25 See Id. §§ 39.256 – 39.262. PUC Docket No. 22348 Consolidated Interim Order Page 10 SOAH Docket Nos. 473-00-1013 treatment is consistent with Commission precedent, as just and reasonable rate-case litigation expenses incurred outside of the test year have traditionally been allowed pursuant to PURA § 36.061(b)(2).26

The Commission also finds that T&D-related restructuring costs for capital expenditures and associated depreciation, as well as annual expenses, should generally be treated according to traditional rate-making principles and the provisions of PURA § 36.051. T&D restructuring expenses that are determined reasonable and necessary and are expected to be incurred in the 2002 forecasted test year may be included in the T&D rates. Where appropriate, extraordinary expenses may be amortized over a suitable time period to mitigate rate impact. Restructuring expenses incurred prior to the 2002 forecasted test year may not be included in T&D rates, but recovery may be requested in the annual-report process. The Commission acknowledges that debt restructuring expenses are unique, and the recovery of such expenses should be limited to the proportionate share of T&D assets expressed as a percentage of total assets prior to business separation on a net book value basis.

Further, the Commission finds that energy efficiency costs that are recurring, are incurred in the 2002-forecasted test year, and comply with the energy efficiency rule27 are recoverable in T&D rates. Recovery of energy-efficiency costs incurred prior to the 2002 forecasted test year may also be requested in the annual-report process.

Finally, the Commission concludes that costs of the pilot project are not recoverable in the T&D rates established in this proceeding pursuant to PURA § 39.201 because they are not related to the provision of T&D service after January 1, 2002, and will not be incurred during the 2002 forecasted test year. For pilot project expenses incurred prior to the 2002 forecasted test, recovery may be requested in the annual-report process.

26 See Application of Texas-New Mexico Power Company for Authority to Change Rates and Petition of Texas-New Mexico Power Company for Deferred Accounting Treatment for TNP One-Unit Two, Docket Nos. 10200 and 10034, Examiners’ Report, 19 P.U.C. Bull. 89, 269 (Mar. 18, 1993).

27 P.U.C. SUBST. R. 25.181. PUC Docket No. 22348 Consolidated Interim Order Page 11 SOAH Docket Nos. 473-00-1013 b. Return on Equity and Capital Structure

(Generic Proceeding, Order No. 28 - Incentive Plan and Return on Equity)

(Generic Proceeding, Order No. 42 – Establishing Return on Equity and Capital Structure)

TARGETED INCENTIVE PROGRAM Early in the Generic Proceeding, the Commission concluded that a standard targeted incentives program (TIP), that could be opted into by companies, would be beneficial and should be developed in this proceeding.28 The Commission directed parties to seek a consensus plan. Commission Staff filed several versions of TIP, but no agreement could be reached by all parties. The Commission, therefore, concluded that a generic TIP is not appropriate at this time, and that neither a TIP nor performance-based ratemaking plans proposed by some utilities in their original UCOS filings should be considered in setting an ROE in either the Generic Proceeding or in the individual UCOS cases.

Given the basic underlying similarities of unbundled TDUs, including the level of regulatory oversight and comparable levels of risk, the Commission concluded that it was appropriate to conduct a factual hearing in the Generic Proceeding to address generic ROE and capital structure. Sharyland Utilities was exempted from the consideration of the generic ROE and capital structure; instead those issues would be determined in Docket No. 22348.29 On November 6, 2000, the Commission heard evidence in connection with the establishment of ROE rates and capital structure ratios for use in the utilities’ individual UCOS cases. Initial and reply post-hearing briefs were filed by the parties on November 22, 2000, and December 4, 2000, respectively. The Commission considered this matter in the open meeting on December 13, 2000.

In approaching the issues of the appropriate ROE and capital structure, the Commission notes two underlying considerations that served as a starting point in the decision-making

28 See Generic Proceeding, Order No. 17 at 12-13; Order No. 17 at 1. 29 Sharyland Utilities’ UCOS case. PUC Docket No. 22348 Consolidated Interim Order Page 12 SOAH Docket Nos. 473-00-1013 process. First, these decisions are made for ratemaking purposes for the newly unbundled TDUs during the transition period; and, second, the decisions are based on the close correlation between the ROE and capital structure.

The factors the Commission considered when determining an appropriate and reasonable ROE for the unbundled TDUs in Texas include: (1) the levels of business and financial risk; (2) the Commission’s decisions in the rate design phase of this case; (3) the need to maintain reasonable rates; (4) the need for new transmission capacity; (5) the maintenance of adequate reliability standards; and (6) the companies’ ability to attract new capital.

The Commission reviewed analyses of various proxy groups, including generation- divested, integrated, and water utilities and local gas distribution companies, for indications of risk levels and market concerns. The Commission finds that, while the generation-divested utilities most closely resembled the functions of the unbundled TDUs, significant differences in market restructuring in Texas and the size of the sample group do not allow for generalizations. The Commission also finds that the other sample groups provided useful information and need to be considered.

Based on these reviews, the Commission concludes there is strong evidence to support the presumption that, relative to the existing market structure, unbundled TDUs in the Electric Reliability Council of Texas (ERCOT) will be exposed to less risk.30 The following observations support the assertion that the Texas market is significantly different from other jurisdictions and should result in lower risk for the TDUs: (1) complete separation of generation and T&D functions, thus virtual elimination of commodity risk; (2) a requirement on retail electric providers (REPs) to be the point of sales for retail customers; (3) Commission-approved substantive rules related to registration and financial requirements to minimize a possibility of a

REP default on payments for contracted services;31 and (4) P.U.C. SUBST. R. 25.193 to ensure speedy recovery of transmission expenditures related to expansion of the transmission network.

30 Direct Testimony of Martha Hinkle, pp. 8 -9, 17, and 19, and NUS Joint Reply Brief, pp. 3-10.

31 P.U.C. SUBST. R. 25.107, relating to Certification of Retail Electric Providers (REPs), and P.U.C. SUBST. R. 25.108, relating to Financial Standards for Retail Electric Providers Regarding the Billing and Collection of Transition Charges. PUC Docket No. 22348 Consolidated Interim Order Page 13 SOAH Docket Nos. 473-00-1013

Therefore, the Commission concludes these favorable market and regulatory conditions in Texas should result in a lower business risk to Texas TDUs.

Additionally, in its consideration of what is an appropriate and reasonable ROE, the Commission reviewed a range of methods and models, as proposed by the parties: discounted cash flow (DCF), multi-stage DCF, capital asset pricing model (CAPM), and risk premium method. The Commission finds that the multi-stage DCF analysis as proposed by the IOUs does not accurately capture the lower business risk for Texas TDUs.32

In its determination of an appropriate ROE, the Commission considered the NUS recommendation of 10.75% as a reasonable starting point.33 This number lies in the middle of the ranges of reasonable ROE admitted into evidence. Further review of OPUC/EGSI Cities CAPM analysis indicated that the NUS ROE is compatible with a 60% debt in the capital structure.34 The Commission, however, provides for an upward adjustment to the ROE of 0.5% to account for (1) the Commission decision in the rate design phase of this proceeding; 35 (2) potential rating uncertainty due to higher debt, based on the adoption of 60% debt and 40% equity for capital structure in this proceeding; and (3) a risk premium recalculation as indicated in a Commission Staff witness’ errata testimony.36 Accordingly, the Commission approves an ROE of 11.25% for the Texas unbundled TDUs, starting in 2002.

With regard to the issue of capital structure, the Commission recognizes that the ultimate determination of the appropriate relationship between the level of debt and equity and the corresponding ROE is not an exact science. As a general proposition, however, the Commission finds that an increase in debt should result in an increase in ROE unless offset by lower business risk.

32 Direct Testimony of D. Tietjen, pp. 8-10. 33 Direct Testimony of D. Tietjen and M. Hinkle; see also NUS Initial Brief, pp. 12-19. 34 IOU Reply Brief, Exhibit C; see also Direct Testimony of Hill, Schedule 7. 35 The Commission adopted a Transmission Cost Recovery Factor, which may increase risk for the distribution company. Also adopted was an 80% ratchet for the distribution company, which may result in more streamlined cash flow; however, the adopted ratchet was the lowest one proposed. 36 Staff Exhibit 1B, Errata to Martha Hinkle’s Direct Testimony; see also November 6, 2000 Hearing Transcript at 1309-11. PUC Docket No. 22348 Consolidated Interim Order Page 14 SOAH Docket Nos. 473-00-1013

Both the NUS and OPUC/EGSI Cities proposed debt to equity ratio of 60/40. These parties presented substantial evidence showing that the unbundled TDUs would not be adversely affected by higher levels of debt, either in terms of adequate cash flows or market perception. The Commission agrees with these parties that any increase in the financial risk due to the higher debt leverage would be offset by the lower business risk to the TDUs. The Commission is not persuaded by the IOUs’ arguments that greater debt leverage would have a detrimental impact on the TDUs. The Commission finds that the TDUs are able to carry a higher level of debt and still achieve a favorable credit rating, which will allow capital to be raised at acceptable rates.

Therefore, the Commission finds that a capital structure of 60/40 debt to equity ratio is reasonable and that it will allow TDUs to attract sufficient capital at reasonable rates, while minimizing costs to the ratepayers. The Commission also finds that any increase in the financial risk due to the higher debt leverage is offset by the lower business risk faced by the TDUs. The Commission, therefore, adopts a 60% debt and 40% equity ratio as the capital structure for ratemaking purposes for Texas TDUs.37 c. Generic O&M Escalation Factors

(Generic Proceeding Order No. 17: Category B Issue No. 3)

(Generic Proceeding, Order No. 25)

Are there criteria for determining whether operations and maintenance (O&M) expenses and capital investments for the forecasted 2002 test year are reasonable and necessary, such as use of generic escalation factor(s)?

CAPITAL INVESTMENT ESCALATORS The majority of parties argued each utility should prove that capital investment is reasonable and necessary in the company-specific proceedings. Commission Staff, however, asserted that a 5% generic escalation factor for distribution net plant-in-service after 2002 would

37 NUS Initial Brief, pp. 4-11. PUC Docket No. 22348 Consolidated Interim Order Page 15 SOAH Docket Nos. 473-00-1013 be appropriate,38 and that investment in the transmission function is best determined in the company-specific proceedings. The Commission finds that capital investment costs for the T&D functions in the 2002 forecasted test year are more appropriately addressed in the company- specific dockets. A company-specific analysis appears appropriate for two reasons: (1) some utilities would over-recover their costs if they are making no or limited capital investment, and (2) for some utilities, an escalator would not provide adequate recovery for needed capital investment.

O&M EXPENSE ESCALATORS The Commission finds that operations and maintenance (O&M) expenses for the 2002 forecasted test year are appropriately determined by the application of generic escalation factors. Those parties seeking a company-specific determination to account for unique service areas and demand characteristics of the utilities generally failed to acknowledge that the historic test-year baseline should satisfactorily compensate for these factors. While a company-specific analysis is certainly possible, there is no assurance that the result will be any better than that achieved by applying some generic escalation factor to the historic test-year baseline for O&M expenses. As noted by TNMP, the use of a generic escalator is practical and at the very heart of forecasting. The Commission found that a factual hearing to determine the appropriate type of escalation factors was in order.

The Commission identified the following matters upon which evidence would be considered at the hearing: (1) evidence in support of either a single generic escalation factor or a limited number of generic escalation factors that appropriately account for O&M expenses and (2) evidence relating to labor costs that are currently known and measurable for the 2002 forecasted test year or that relate to unusual labor costs that would not be properly encompassed in generic escalation factors. The Commission indicated that, should a utility’s labor costs justify an exception to the generic escalators, the Commission reserved the right to determine how those labor costs are to be treated in the company-specific UCOS dockets.

38 This factor was derived from data in Standard & Poor’s DRI “Power Planner-Cost Information for Power System Analysis,” First Quarter, 2000. PUC Docket No. 22348 Consolidated Interim Order Page 16 SOAH Docket Nos. 473-00-1013

The Commission heard evidence in connection with this issue on August 7, 2000. Briefs were filed on August 14, 2000, and reply briefs on August 18, 2000. After reading and hearing evidence, reviewing briefs and reply briefs, and discussion at the Open Meeting on August 24, 2000, the Commission determines the issues in connection with O&M escalators as follows.

The Commission finds that the generic escalation factors developed by the IOU-aligned group witness John Mothersole for the fourth quarter of 1999, and the years 2000, 2001, and 2002, as set forth in Table 1 below, appropriately account for growth in O&M expenses.

Table 1 (Mothersole Escalator Factors)

4th Qtr, Category 1999 2000 2001 2002 Materials and Services, T&D Expenses 0.4% 2.6% 1.7% 1.5% Materials and Services, A&G (excluding 0.8% 3.6% 3.6% 3.3% labor) Labor – Managerial, Professional & Technical, and Clerical 0.9% 3.9% 3.8% 3.6% Labor – Other 0.5% 3.0% 3.8% 3.7%

Additionally, the Commission finds that a productivity offset should be applied to each escalation factor and that the 1.2% factor developed by Steven Andersen properly accounts for productivity enhancements. This factor shall be applied to each of the Mothersole escalation factors for the fourth quarter of 1999, and the years 2000, 2001, and 2002.39 The escalation factors that result from the application of this offset are summarized in Table 2 and shall be used to escalate 1999 historic test year O&M expenses in the company-specific dockets.

Table 2 (Generic O&M Escalation Factors Adopted by the Commission after Productivity Offset)

4th Qtr, 2000 2001 2002 Category quarter Materials and Services, T&D Expenses 0.1% 1.4% 0.5% 0.3% Material and Services, A&G (excluding 0.5% 2.4% 2.4% 2.1% labor)

39 For the 4th quarter of 1999, a productivity offset of 0.3025% (i.e. 1.21% divided by 4) should be applied. PUC Docket No. 22348 Consolidated Interim Order Page 17 SOAH Docket Nos. 473-00-1013

Labor – Managerial, Professional & 0.6% 2.7% 2.6% 2.4% Technical, and Clerical Labor-Other 0.2% 1.8% 2.6% 2.5%

The Commission agrees with Commission Staff that demand-side management (energy efficiency) expenses and transmission-access charges are “new” O&M expenses of the T&D utility and may be included in the 2002 future test year. Consequently, the Commission finds that these expenses may be included in the 2002 future test year to the extent they are found to be reasonable and necessary40 in the company-specific dockets.

Additionally, the Commission finds that “new” SB7-mandated corporate restructuring expenses may be included in the 2002 future test year, subject to reasonable and necessary review in the company-specific dockets. Expenses that are properly functionalized in the 1999 historic test year and subsequently escalated, are not “new” SB7 expenses.

The Commission agrees with the majority of the parties that UCOS Rate Filing Package (RFP) methodology for determining O&M expenses in the 2002 future test year is appropriate. The Commission disagrees with AEP that “new” O&M expenses included in the 2002 future test should be reflected in terms of 1999 dollars and subject to escalation. Additionally, the Commission agrees that 1999 historic test year data is subject to review pursuant to PURA § 36.051. To avoid double recovery, expenses that are recovered as “new” may not be recovered in the 1999 historic test year.

TNMP YEAR-2000 LABOR COSTS TNMP argued that its 2000 labor costs are known and measurable. TNMP maintained that it has put in effect wage increases of approximately 5% for 2000. The Commission finds that the generic escalators adopted in this order should be applied to TNMP’s 1999 historic test year labor costs in the same manner as other IOUs. TNMP shall not make other adjustments in addition to the application of the escalation factor in this order.

40 See PURA § 36.051. PUC Docket No. 22348 Consolidated Interim Order Page 18 SOAH Docket Nos. 473-00-1013

SHARYLAND Sharyland took no position concerning whether the Commission should adopt a generic escalator or how such an escalator should be designed. Sharyland, a new utility lacking historical data, maintained that its O&M costs can only be determined in its individual UCOS proceeding.41 The Commission finds that Sharyland has few of the characteristics of the other IOUs in the Generic Proceeding. In short, Sharyland, which only recently began service, has no 1999 historic test year for application of a generic escalation factor. Consequently, Sharyland is exempt from the application of this ruling.

LCRA AND STEC The Commission finds that the application of generic O&M escalation factors should only be applied in the UCOS filing of the IOUs. Consequently, the Commission finds that LCRA and STEC are exempt from the application of this ruling. d. Uniform Customer Classification Scheme and Uniform Rate Design

(Generic Proceeding Order No. 17: Category B Issue No. 6(A)

(Generic Proceeding, Order No. 21 – Generic Customer Classification and Rate Design Issues)

(Generic Proceeding, Order No. 40 -- Establishing Generic Customer Classification and Rate Design)

Should the Commission adopt a uniform classification scheme and uniform rate design for T&D service?

The Commission strongly agrees with parties which argued that, with nearly all of the IOUs having a rate case pending before the Commission, this is a unique opportunity to make and implement standardized policy decisions regarding customer classification and rate design. These parties contended that uniformity would facilitate the development of a competitive market because it would allow REPs to standardize products, reducing REPs’ costs to enter the

41 Application of Sharyland Utilities, L.P., for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and P.U.C. SUBST. R. 25.344, Docket No. 22348 (pending). PUC Docket No. 22348 Consolidated Interim Order Page 19 SOAH Docket Nos. 473-00-1013 market. Furthermore, they maintained, T&D services are similar among all service areas, so customers are easily grouped by the type of T&D service they require. In support of deferring such standardization, some argued that both the proposed customer classes and rate design filed by the utilities in their respective UCOS cases go a long way toward achieving the goal of uniformity, with new classes that necessarily reflect similarities across all the utilities.

The Commission finds that a uniform rate design and customer classification scheme is appropriate for the purposes of standardizing T&D rates in Texas. A reasonable approach to this end is to establish a small number of classes, as compared to the approximately twenty or more served by the typical integrated utility today, for standardized use, with a goal of uniformity. The Commission also recognizes that certain exceptions to the standard classifications established in this proceeding will be required. The goal for rate design is also to develop a standardized model, such that, to the greatest possible extent, rates are cost driven.

Generic Proceeding, Order No. 21 –

Generic Customer Classification and Rate Design Issues

On August 8, 2000, during its open meeting factual hearing on generic escalator issues, the Commission took up the motion by Commission Staff to expand the scope of the customer classification and rate design issues. The Commission found the motion appropriate, and determined that the scope of the customer classification should include identification of uniform customer classes and determination of clear definitions for each class. Furthermore, determination of any utility-specific exceptions to uniform classes is also appropriate, such that a final identification of both uniform classes and exceptions and/or additional classes is completed for each company. The Commission also agreed to consider the need for a “stand-by” classification, and if such classification were to be adopted, a rate design for that class would be determined. By way of example, the Commission identified the types of criteria that might lead to a determination of what constitutes a customer class as voltage level, or the size of the customer’s load, or the type of business, or, perhaps, the relationship to the price-to-beat classifications. PUC Docket No. 22348 Consolidated Interim Order Page 20 SOAH Docket Nos. 473-00-1013

The Commission also decided that the rate design issue would result in the development of a cost driven, standardized rate design for transmission rates and distribution rates, by class, including stand-by, time-of-day, and seasonal rates, if those are determined to be appropriate or necessary. The Commission determined that the rate design would identify types and measurement units of billing determinates by class, and would determine the need and/or justification for a transmission cost recovery factor (TCRF), and, if necessary, a methodology for determining the TCRF. The actual application, however, should be conducted at SOAH. The Commission wanted to complete the rate design so that, at the “second phase” hearings at SOAH, it would be a matter of plugging in numbers and assuring accuracy. In other words, the Commission determined a method for a compliance process.

In addition, the Commission determined that the following issues would not be heard in the generic proceeding because they were to be addressed in the securitization cases, in rules, or during the utility-specific SOAH hearings: distributed generation (DG) tariffs, discretionary services, miscellaneous fees, nuclear decommissioning, wholesale rates, system benefit fund (SBF) fees, competitive transition charges (CTC), transition charges (TC), and tariff language.

Generic Proceeding, Order No. 40 -

Establishing Generic Customer Classification And Rate Design

After considering the parties’ briefs, the Commission concluded that a uniform rate design and customer classification scheme is appropriate for the purpose of standardizing T&D rates in Texas.42 The Commission concluded, however, that resolution of this issue should await an evidentiary hearing where the Commission could evaluate the proposed customer classifications and rate designs.43 The customer classification and rate design (CC/RD) phase of the Generic Proceeding satisfies this requirement.

NON-UNANIMOUS AGREEMENT ON CUSTOMER CLASSIFICATION On September 8, 2000, a Distribution Service Customer Classification Non-Unanimous Stipulation and Agreement (NUA) was filed in the Generic Proceeding by American Electric

42 Generic Proceeding, Order No. 17 at 10. 43 Id. PUC Docket No. 22348 Consolidated Interim Order Page 21 SOAH Docket Nos. 473-00-1013

Power Company, Inc. (AEP); Texas-New Mexico Power Company (TNMP); TXU Electric Company (TXU); Southwestern Public Service Company (SPS); the Commission Staff of the Public Utility Commission of Texas (Commission Staff); Texas Industrial Energy Consumers (TIEC); Enron Energy Services, Inc. (Enron); and Texas Industries, Inc (TXI).44 The following parties did not oppose the NUA: ALCOA and Floresville Electric Light and Power Systems.45 The NUA addressed customer classifications for all of the utilities participating in the proceeding, including the NUA-signatory utilities (AEP, TNMP, TXU, SPS), Reliant Energy HL&P (Reliant), and Entergy Gulf States, Inc. (EGSI).

Direct testimony in the CC/RD phase of this proceeding was filed by the parties on October 16, 2000, and rebuttal testimony was filed October 23, 2000. On November 2 and 3, 2000, the Commission heard evidence in connection with the establishment of generic customer classifications and rate design for use in the utilities’ individual UCOS cases currently pending at SOAH. Initial and reply post-hearing briefs were filed by the parties on November 8 and 10, 2000, respectively. The Commission considered this matter in open meeting on November 16, 2000.

As previously discussed, Generic Proceeding Order No. 17 provided the Commission’s decision that a uniform rate design and customer classification scheme is appropriate for the purpose of standardizing T&D rates in Texas.46 Having convened a factual hearing on this matter, the Commission maintains this decision. Therefore, based upon the evidence, briefs, and arguments of the parties, the Commission adopts a generic customer classification and rate design for T&D rates. The Commission finds that the six customer classes, as proposed in the NUA, shall be adopted by each of the utilities participating in this proceeding. The six customer classes are: (1) Residential, (2) Secondary less than 10 kW or kVA (less than 5 kW for TNMP and EGSI), (3) Secondary greater than 10 kW or kVA (greater than 5 kW for TNMP and EGSI), (4) Primary, (5) Transmission, and (6) Lighting.

44 Distribution Service Customer Classification Non-Unanimous Stipulation and Agreement at 2 (NUA). 45 NUA at 1. 46 Generic Proceeding, Order No. 17 at 10 (July 24, 2000). PUC Docket No. 22348 Consolidated Interim Order Page 22 SOAH Docket Nos. 473-00-1013

The Commission agrees with the proponents of the generic customer classifications who cited cost causation as a significant factor in developing a uniform customer class configuration47 and the need for flexibility in addressing reconciliation with the price to beat (PTB).48 The adopted generic class design will best achieve these goals. Accordingly, the Commission adopts the six customer classes proposed in the NUA.

To recognize its unique characteristics, the Commission grants Sharyland an exemption from some of the classifications. All of Sharyland’s customers are equipped with interval data recorder (IDR) meters, obviating the need for classes to accommodate non-demand-metered customers.49 Therefore, to the extent that such classes are unnecessary for Sharyland, a modified version of the NUA classes for Sharyland is appropriately addressed in its individual UCOS case.50 This exemption does not, however, excuse Sharyland from meeting the underlying principles cited above. Additionally, Sharyland’s classifications should mirror those in the NUA for demand-metered classes.

GENERIC DESIGN OF TRANSMISSION AND DISTRIBUTION RATES The Commission agrees with the proponents of a generic rate design that the primary principles to be considered in the design of T&D rates are cost causation, simplicity, and equity to customers within the given rate classes.51 Further, uniform T&D rates help to ensure a more vibrant competitive electric market because the uniformity will facilitate entry by new competitors. The Commission finds that such a generic rate design is appropriate, and shall therefore be adopted by T&D utilities. Additionally, the Commission agreed that adoption of a generic rate design for lighting is not realistic given the complexity of the topic. Accordingly, lighting rate design shall be addressed in the individual UCOS cases.

47 See Entergy Gulf States’ (EGSI) Initial Brief at 2-3; Nucor’s Initial Brief at 3; Texas Industrial Electric Customers’ (TIEC) Initial Brief at 5. 48 See Cleco ConnexUS et. al., Initial Brief at 1; Texas Retailers Association’s (TRA) Initial Brief at 5. 49 See Sharyland Statement of Position at 1. 50 Docket No. 22348. 51 See Southwestern Public Service Company’s (SPS) Reply Brief at 6; American Electric Power Company’s (AEP) Initial Brief at 4. PUC Docket No. 22348 Consolidated Interim Order Page 23 SOAH Docket Nos. 473-00-1013

CUSTOMER CHARGE The testimony in the Generic Proceeding revealed that the inclusion of a customer charge was generally favored by the parties. Specifically, these parties proposed that the customer charge be comprised of costs that are incurred regardless of system usage, such as billing, metering, and customer service.52 One party maintained that customer charges should not be applied to the residential class because a fixed charge would discriminate against low use/low income customers.53 With the exception of TXU, the parties were not opposed to having costs related to metering, which is expected to become a competitive service in the future, recovered through a separately stated charge.54

The Commission finds that the adoption of a uniform rate design that includes a customer charge is appropriate. Specifically, the customer charge shall be comprised of costs that vary by customer such as metering, billing, and customer service.55 A customer charge comprised of these elements appropriately tracks cost causation. Additionally, the metering portion of such charges, at a wholesale level, should be separately stated. This will facilitate the unbundling of metering charges when they become a competitive offering.

FACILITIES/DELIVERY CHARGE Also considered in the Generic Proceeding was whether the generic rate design should include a facilities/deliveries charge. The majority of the parties maintain that a facilities/delivery charge is appropriate and that the manner in which the charge is to be recovered will be contingent on the metering capabilities of each customer. Because the residential and small commercial56 classes typically do not have demand meters in place, the majority of the parties agree that a facilities/delivery charge should be recovered on a monthly per-kilowatt-hour (kWh) basis for these customers.57 Many of the parties propose that demand-

52 See Commission Staff’s Initial Brief at 4-5. 53 See Texas Legal Services Center’s (TLS) Initial Brief at 5-7. 54 See TXU Electric Company’s (TXU) Initial Brief at 4-5. 55 See Nucor’s Initial Brief at 5; TXU’s Initial Brief at 4. 56 More properly, the secondary less than 10 kW or kVA (less than 5 kW for TNMP and Reliant) class. 57 See Office of Public Utility Counsel’s (OPUC) Reply Brief at 2; EGSI’s Initial Brief at 4. PUC Docket No. 22348 Consolidated Interim Order Page 24 SOAH Docket Nos. 473-00-1013 metered classes should be billed based on non-coincident peak (NCP) demand. There was greater disparity among the parties as to the issue of whether IDR demand-metered locations should be given different billing treatment from non-IDR locations. Parties opposing the use of a 4CP-billing determinant cited cost shifting and intra-class subsidies as the primary concerns.58

With respect to a facilities/delivery charge, the Commission finds that the non-coincident peak (NCP) billing determinant should be used for non-IDR metered customers. For those possessing IDR meter capabilities, the transmission per-kilowatt (kW) rate shall be billed according to the Commission’s relevant transmission rule, which currently mandates a four coincident peak (4CP) method.59 In the event that “gaming” of the 4CP methodology becomes a problem, the advisability of broadening the relevant peak period may be examined at that point. The distribution facilities/delivery charge for IDR metered customers shall be billed on the NCP billing determinant. The interval for billing of demand charges shall be that interval, which conforms to the protocols of the reliability council, power pool, or independent organization to which each utility belongs. For the majority of utilities participating in this proceeding, in accordance with ERCOT protocols, a 15-minute demand interval shall be applied to demand charges. Finally, facilities/delivery charges shall be recovered on a per-kWh basis for residential and small commercial customers that do not have demand meters. The method established for the recovery of a facilities/delivery charge from each customer class, appropriately reflects the best available metering data from each class, is a reasonable proxy for cost causation, and maintains continuity with past rate design methodology.

RATCHETS The Commission agrees with the parties who, with little opposition, recommended adoption of a demand ratchet in the distribution rates because ratchets stabilize utility revenues and because ratchets are an effective method to recover fixed distribution infrastructure costs. The Commission finds arguments that ratchets are not cost-justified or place an excessive burden on low load factor customers to be unpersuasive. The Commission determines that an 80%

58 See TXU’s Initial Brief at 6.

59 See P.U.C. SUBST. R. 25.192(c). PUC Docket No. 22348 Consolidated Interim Order Page 25 SOAH Docket Nos. 473-00-1013 ratchet is appropriate for recovery of distribution costs from demand-metered customers.60 The Commission holds that although a 100% ratchet properly reflects the fixed nature of distribution costs, the 80% level more appropriately recognizes load diversity on the distribution system. In addition, parties generally agreed that an exception is appropriate for seasonal agriculture customers, based on testimony that applying a ratchet to these customers could result in charges higher than their current bundled rate on an annual basis. The Commission acknowledges these unique characteristics of seasonal agricultural customers, and therefore grants an exception to the establishment of generic ratcheted distribution demand charges for these customers. The design for each customer class that includes seasonal agricultural customers shall contain a provision for the recovery of distribution charges without the use of a demand ratchet for those customers.

KVA BILLING Interested parties agreed that the practice of billing on a per-kilovolt-ampere (kVA) basis should continue for a utility that has historically billed on a per-kVA basis. Proponents of this practice claimed that kVA billing sends customers the proper price signal to maintain a high power factor and obviates the need for power factor correction formula.61 The proposed NUA classes allow this practice to continue. The Commission agrees that kVA billing should continue as recognized by the NUA.

TRANSMISSION COST RECOVERY FACTOR (TCRF) Proponents of a transmission cost recovery factor (TCRF) argued that a TCRF would be needed if the distribution utility were to act as the billing agent for transmission service providers. There were two general approaches proposed for such a mechanism. The first approach, proposed by Commission Staff, would allow a distribution utility to pass through to retail customers only the changes in ERCOT transmission costs approved by the Commission or allowed by P.U.C. SUBST. R. 25.193(a)(4).62 The second approach would serve as a true-up

60 The parties’ proposals ranged from an 80% ratchet (See Dallas-Fort Worth Hospital Council and the Coalition of Independent Colleges and Universities Initial Brief at 4-5) to be applied to customers with demand charges to a 100% ratchet for all customer classes (See AEP’s Initial Brief at 9-10). Most parties supported or were willing to accept an 85% ratchet for distribution rate classes with demand charges. 61 See Reliant’s Direct Testimony of Purdue at 15; Reliant’s Initial Brief at 10. 62 See Commission Staff’s Direct Testimony of Pevoto at 26-29; Commission Staff’s Initial Brief at 14. PUC Docket No. 22348 Consolidated Interim Order Page 26 SOAH Docket Nos. 473-00-1013 mechanism to allow distribution utilities to adjust for under or over recovery of transmission costs. The latter approach would address the distribution utility’s risk as a billing agent for transmission service providers.63 Several parties argued there should be no TCRF, because such an automatic rate adjustment is prohibited by PURA.64

The Commission adopts the Commission Staff’s methodology for a TCRF. The Commission agrees with Commission Staff that the TCRF should only be used to pass through wholesale transmission cost changes approved or allowed by the Commission. While this approach does not address the risk to the distribution utility for under- and over-collection of the transmission service charges, the Commission may take such risk into account when setting the distribution utility’s rate of return.

DIRECT SUBSTATION SERVICE One party asserted that a separate rate for customers taking service directly out of the substation is warranted on the grounds that these customers are basically the same as transmission-level customers, with one additional transformation.65 Opponents argued that such a rate would create a discrete class that would have significant impacts on other primary class customers.66

The Commission concludes that a separate rate or adjustment for customers taking service directly out of the substation is not warranted. To establish a rate based on the location of a customer in relation to a substation represents a significant departure from longstanding ratemaking principles with respect to the shared costs of the distribution infrastructure. The Commission declines to institute a separate rate for customers who happen to be either closer to, or farther from, a particular substation.

INTERRUPTIBLE AND STANDBY TRANSMISSION RATES (Generic Proceeding Order No. 17: Category B Issue No. 6(B))

63 See AEP’s Initial Brief at 12-14; Reliant’s Initial Brief at 11-12. TXU’s Initial Brief at 11-12. 64 See City of Houston Direct Testimony of Daniel at 19. OPC’s Initial Brief at 8. 65 See TIEC Direct Testimony of Jeffry Pollock at 20-23. 66 See TRA’s Rebuttal Testimony of Saunders at 2-3; TXU’s Rebuttal Testimony of Sherburne at 11-12. PUC Docket No. 22348 Consolidated Interim Order Page 27 SOAH Docket Nos. 473-00-1013

(Generic Proceeding Order No. 40: Standby Transmission Rate)

Should transmission and distribution rates include intermittent or stand-by service?

Some parties argued that transmission and distribution rates should include intermittent and standby rates in order to reflect the willingness and ability of some customers to curtail usage during period of high demand and, therefore, reduce stress on T&D system. These parties argued that traditional cost-of-service principles require that there is recognition of cost causation, and therefore these types of rates are appropriate. Opponents of such rates argued that intermittent or standby services are largely generation-related services and costs. These parties argued that facilities are largely the same whether a retail customer takes intermittent or firm service because they must be sized to meet maximum demand. Furthermore, these parties suggested that the Commission already addressed this question in Project No. 2108367 and determined that intermittent transmission and distribution rates were inappropriate.

The Commission finds that it is important to distinguish between interruptible and standby services. The Commission agrees that interruptible T&D rates are inappropriate. As the Commission stated in the Second Order on Rehearing in Docket No. 16705,68 the bundled, interruptible rate design approved in that docket was meant to ensure that those rates recover T&D costs from interruptible customers. The Commission notes that interruptible customers will receive value in the generation market for their willingness to curtail at high-priced periods and, to the extent such interruptibility eases transmission congestion, may also receive value in the congestion market for the ability and willingness to curtail their load.

Upon initiation of the Generic Proceeding, the Commission acknowledged that standby service is different from interruptible service and agreed to consider argument on whether a standby T&D rate may be appropriate. Proponents of a standby T&D rate argued that this load is infrequently on the grid, and customers with on-site generation who need to take standby services for maintenance or planned outages typically only do so in off-peak hours because the

67 Cost Unbundling and Separation of Business Activities, including Separation of Competitive Energy Services and Distributed Generation, Project No. 21083. 68 Application of Entergy Texas for Approval of Its Transition to Competition Plan and the Tariffs Implementing the Plan, and for the Authority to Reconcile Fuel Costs, to Set Revised Fuel Factors, and to Recover a Surcharge for Under-Recovered Fuel Costs, Second Order on Rehearing, Docket No. 16705 (Oct. 148). PUC Docket No. 22348 Consolidated Interim Order Page 28 SOAH Docket Nos. 473-00-1013 corresponding generation prices are low. Furthermore, these parties stated, back-up services are taken when a forced outage occurs, and this occurs infrequently and randomly. Again, the Commission recognizes that these customers use the T&D system in significantly different ways from normal firm-requirements customers. However, the Commission declines to establish a standby rate for transmission service to be offered by the regulated transmission utility. Such a rate is more appropriately offered in the competitive market. Furthermore, assuming that standby customers do not take transmission service during peak periods, coincident peak billing for transmission service will recognize the intermittent usage of the transmission system by such customers.

POWER FACTOR CORRECTION FORMULA The standard-power-factor-correction formula is being addressed in Project No. 22187.69 Consequently, the Commission finds there is no need to consider this issue in this proceeding. e. Recovery of Transmission Charges

ERCOT (Generic Proceeding Order No. 14: Category A Issue No. 3)

(Order No. 40 affirms the Order No. 14 decision)

How should ERCOT transmission providers recover their transmission costs? Should they bill retail electric providers, either directly or through an ERCOT settlement, or bill a transmission and distribution utility, which would then bill REPs a combined transmission and distribution charge.

The Commission initially considered two different billing methods for cost-recovery by ERCOT transmission service providers (TSPs). In the direct-billing approach, TSPs would bill retail electric providers (REPs) directly for transmission service. This would result in REPs receiving over 30 bills for transmission service and a bill for distribution service for each distribution service area. Under the other method, TSPs would bill distribution utilities for

69 Terms and Conditions of Transmission and Distribution Utilities' Retail Distribution Service, Project No. 22187. PUC Docket No. 22348 Consolidated Interim Order Page 29 SOAH Docket Nos. 473-00-1013 transmission service, and the distribution utility in each area would bill REPs for all transmission charges and for distribution service. Several parties proposed modifications of the direct-billing approach, such as using the ERCOT settlement system, to make the direct-billing approach simpler to implement. Ultimately, the Commission was presented, through pre-filed and live testimony, a number of models for the recovery of transmission charges within ERCOT. The options presented by the parties included (1) the “Order No. 14 model”, (2) the “Staff Exhibit 3 model”, and (3) the “Direct Billing model,” as well as variations on each of these.

In Order No. 14, the Commission considered whether ERCOT transmission service providers (TSPs) should recover transmission costs by billing retail electric providers (REPs) for transmission service either directly or through an ERCOT settlement process, or by billing a distribution utility, which would in turn bill the REP.70 There, the Commission concluded that the ERCOT TSPs should bill distribution utilities, which would then bill REPs a combined T&D charge.71 Specifically, under the Order No. 14 model, each TSP would bill each distribution company based on its share of the ERCOT four coincident peaks (4CP). The distribution company would then bill each REP a combined T&D charge based on each REP’s customer composition and billing determinants.72

Alternatively, under the Staff Exhibit 3 model, transmission costs for ERCOT utilities would be allocated on a 4CP basis, then collected from the REP, based on statewide rates, either through a distribution utility or through an ERCOT settlement process.73 Finally, the Direct Billing model contemplates that TSPs bill REPs for transmission service directly, without going through a distribution company or settlement procedure.74

The Commission concludes that the ERCOT TSPs should bill T&D utilities, which would then bill REPs a combined T&D charge. The direct-billing method, in which TSPs bill REPs directly for transmission service would introduce a new billing relationship in addition to

70 Generic Proceeding, Order No. 14 at 6-8. 71 Id. at 9. 72 See Commission Staff’s Initial Brief at 7. 73 See Id. at 8. 74 Generic Proceeding, Order No. 14 at 6. PUC Docket No. 22348 Consolidated Interim Order Page 30 SOAH Docket Nos. 473-00-1013 those that exist today. It would also result in REPs paying each month over 30 TSPs for transmission service and the local distribution utility for distribution service. The selected method, in which the distribution utility bills the REP for all T&D service, would result in billing and payment relationships that parallel existing relationships (from TSPs to distribution utilities) or new ones that must be created (from a distribution utility to a REP). If a distribution utility bills for transmission service provided by all TSPs in addition to billing for the distribution service it is providing, the REP will be able to avoid multiple bills for delivery service. A cost- recovery factor to pass changes in the Commission-approved rates of a TSP through to customers can be used to obviate some of the risks to the distribution utility under this method. The Commission affirms its conclusion as previously articulated in Generic Proceeding Order No. 14 and as developed in detail by Commission Staff’s testimony and briefs.75 The Commission acknowledges that market participants have been developing the necessary processes to comply with Order No. 14 since its issuance, and agrees with Commission Staff that “altering the Order No. 14 model by substituting ERCOT as the settlement agent at this late date is impractical.”76

The direct-billing method poses serious concerns in connection with the statutory objections that parties have raised concerning class allocation and the right of municipal utilities and cooperatives to bill for delivery service. With the distribution utility billing all transmission charges and its own distribution charges, the costs can be allocated among customer classes using consumption information for the distribution utility. If each TSP bills REPs directly, it is difficult to see how customer-class transmission rates could be calculated. It is also difficult to see how the direct-billing approach can be reconciled with the right of municipal utilities and cooperatives to bill customers in their service areas if they opt-in to competition.

NON-ERCOT Non-ERCOT utilities generally agreed that the distribution delivery tariff should not include any transmission costs and that REPs should be wholesale purchasers of transmission service pursuant to Federal Energy Regulatory Commission (FERC) Open Access Transmission

75 See Commission Staff’s Initial Brief at 7-13. 76 See Id. at 10. PUC Docket No. 22348 Consolidated Interim Order Page 31 SOAH Docket Nos. 473-00-1013

Tariffs.77 Others argued that cost should be recovered in a manner similar to ERCOT utilities, with certain modifications.78 In Order No. 17, the Commission decided that the FERC transmission rates for retail-access customers should be used where such a rate has been set. Otherwise, a rate would have to be calculated in the respective individual UCOS cases. This process will entail converting a FERC wholesale rate to a retail transmission rate based on the rate design adopted for residential and commercial customers.79

The Commission affirms its decision in Order No. 17 that transmission cost recovery for non-ERCOT utilities shall be consistent with the FERC Open Access Transmission Tariff. Specific compliance with Order No. 17 shall be addressed in the individual UCOS cases.

T&D Charge For Non-ERCOT Utilities

Generic Proceeding Order No. 17: Category B Issue No. 5

Does the Commission have authority to establish a combined delivery charge (T&D) for non-ERCOT utilities?

In response to several parties’ position that FERC has exclusive jurisdiction to establish unbundled transmission service charges under retail wheeling, up to the point of local distribution, the Commission acknowledges that under the Federal Power Act (FPA), the FERC would set the transmission rate. Where a FERC transmission rate for retail-access customers has been set, the Commission will employ that rate. Where there is no such FERC rate on the books, a rate will have to be calculated in the company-specific proceeding. The Commission will use the FERC wholesale rate, and, through its rate design, convert that wholesale rate to the retail transmission rate to be used in this proceeding. The Commission does not dispute in any way the FERC's jurisdiction with respect to non-ERCOT transmission rates. The Commission also acknowledges arguments that utilities’ charges on a per-kVA basis may provide incentive for customers to maintain a reasonable power factor. Therefore, where the customer is demand metered, the wholesale, per kW rate can be used. Otherwise, the Commission will utilize the

77 See EGS’s Initial Brief at 10; SPS’s Initial Brief at 5-10. 78 See AEP’s Direct Testimony of Moncrief at 23-25. 79 Generic Proceeding, Order No. 17 at 9. PUC Docket No. 22348 Consolidated Interim Order Page 32 SOAH Docket Nos. 473-00-1013 wholesale rate in place today in the open access tariffs and set rates for retail-access customers, based on the rate design adopted for residential and commercial customers.

ORDER NO. 40: EXCEPTIONS TO GENERIC CUSTOMER CLASSIFICATION AND RATE DESIGN The Commission was asked to consider a number of exceptions to generic customer classification and rate design. The requests included both those of a general nature, relating to the NUA classes and associated rate design, as well as specific questions regarding particular rates to be offered by individual utilities. Reliant requested a waiver from the NUA classes and generic rate design.

The Commission finds that exceptions to the generic customer classifications described in the NUA, other than that requested by Sharyland, are inappropriate and are hereby denied. Exceptions to the generic rate design established in this proceeding shall be considered in each utility’s individual UCOS proceeding, only if necessary to address extraordinary impacts on the ability of customers to obtain service from a competitive provider due to the restrictions of the price to beat (i.e., “headroom” concerns). The Commission recognizes that a tension exists between two interests of the competitive market: the need for standardization and predictability among T&D service areas and the necessity of recognizing the headroom concerns unique to particular service areas. Furthermore, because the T&D rates addressed by this Order represent a relatively small proportion of an end-use customer’s bill, the design of such rates shall be amended only in the case of exceptional headroom concerns. Such headroom concerns shall not, however, automatically mandate the granting of an exception to the generic rate design.

ORDER NO. 40: RATE XFMR TXU proposed a separate rate (Rate XFMR) for its transmission utility to recover distribution-related costs associated with transformation service. TXU asserted that a separate rate is necessary because transformation service is a distribution-related charge and is therefore not eligible for inclusion in the transmission cost of service.

The Commission finds that a rate such as the proposed Rate XFMR is appropriate for the transmission utility to charge the distribution utility at wholesale. The distribution utility shall PUC Docket No. 22348 Consolidated Interim Order Page 33 SOAH Docket Nos. 473-00-1013 then include charges paid under this rate in its cost of service; a separate Rate XFMR or similar rate shall not be established for REPs or for end-use customers.

ORDER NO. 40: PRIMARY CUSTOMERS WITHOUT DEMAND METERS Both TXU and SPS testified that, in their service areas, the primary class would include customers without a demand meter. Therefore, a separate rate design from that generically established for the primary class is necessary to accommodate these customers. TXU proposed to charge its customers based on a minimum demand charge of 5 kW, while SPS asserted that the billing demands should be determined through the load profiling process.

For primary class customers without demand meters, the Commission notes that the best solution would be for such customers to obtain demand meters. Recognizing the practical limitations of that solution, the Commission finds that an adaptation of the generic rate design to accommodate these customers shall be examined in each utility’s individual UCOS case. The Commission recognizes that such customers are a small subset of the primary class and as such, within the narrow confines of this group of customers, determines that the use of load profiling to accomplish such an adaptation is appropriate. f. Forecasted ERCOT 2002 Four Coincident Peak

(Generic Proceeding, Order No. 50 – Establishing Forecasted ERCOT 2002 Four Coincident Peak)

Should there be a uniform projection for the 2002 test year 4CP (denominator) for all utilities setting future test year 2002 transmission rates? If so, what uniform projection should be adopted?

Order No. 43 issued December 14, 2000, in the Generic Proceeding posed this question and expanded the scope of the 4CP issue in the generic proceeding to include transmission cost of service (TCOS) dockets for City Public Service of San Antonio, Lower Colorado River Authority, South Texas Electric Cooperative, and the City of Bryan.80 Parties to these four

80 Application of City Public Service of San Antonio for Approval of Non-IOU Transmission Cost of Service Filing, Docket No. 22532; Application of Lower Colorado River Authority to Change Rates for Transmission Utility Cost of Service (non-IOU), Docket No. 22533; Application of South Texas Electric Cooperative Inc. to Change PUC Docket No. 22348 Consolidated Interim Order Page 34 SOAH Docket Nos. 473-00-1013

TCOS proceedings were invited to intervene in the 4CP phase of the generic UCOS docket. Southwestern Public Service Company subsequently requested clarification that the 4CP issue related only to ERCOT transmission rates and has no application to areas outside ERCOT. The ALJ issued Order No. 44 to that effect on December 21, 2000. At a prehearing conference January 12, 2001, parties raised concerns related to the interconnectedness of some methodologies for projecting the 2002 ERCOT 4CP with the calculation of billing units, and the potential link between the rates set in the UCOS cases and the Pilot Project. Order No. 46 expanded the ERCOT 4CP issue to include these concerns.

The Commission adopts 56,800 megawatts (MW) as the forecasted 2002 four-coincident- peak (4CP) demand within the Electric Reliability Council of Texas (ERCOT) system and approves its use for the purpose of calculating wholesale transmission rates for 2002 within

ERCOT. The Commission also grants a good-cause waiver of P.U.C. SUBST. R. 25.431(h) so that wholesale transmission service rates currently in effect in ERCOT in 2001 may remain in effect for billing to utilities during the pilot projects.

These decisions are based on the February 21, 2001 unopposed stipulation created after numerous workshops and entered by Austin Energy; City of Garland; City Public Service of San Antonio (CPS); Central Power and Light Company; Lower Colorado River Authority (LCRA); Reliant Energy HL&P; South Texas Electric Cooperative, Inc.; the Staff of the Public Utility Commission of Texas; Texas-New Mexico Power Company; TXU Electric Company (TXU); Texas Industrial Energy Consumers (not opposing); and West Texas Utilities Company in the Generic Proceeding.

The Commission finds that 56,800 MW is a reasonable forecast of the 2002 ERCOT 4CP demand and approves its use for the purpose of calculating wholesale transmission service rates in ERCOT.81 For transmission service providers (TSPs) who have filed a TCOS case using a forecast 2002 test year, the wholesale transmission service rate shall be calculated by dividing

Rates for Wholesale Transmission Service and Distribution Level Wholesale Transmission Service (Non-IOU), Docket NO. 22534; and Application of Bryan, Texas Utilities to Change Rates for Wholesale Transmission Service, Docket No. 22616. 81 In the Stipulation, parties cited the testimony of TXU witness King, who said 56,800 MW represented a reasonable compromise of three independent forecasts by TXU, LCRA, and CPS. PUC Docket No. 22348 Consolidated Interim Order Page 35 SOAH Docket Nos. 473-00-1013 the individual TSP’s Commission-approved TCOS revenue requirement by a forecast of the 2002 ERCOT 4CP demand. In 2002, such TSPs will bill distribution utilities by applying their Commission-approved wholesale transmission service rates to the prior year (2001) ERCOT 4CP billing units. Specifically, the rate determination and 2002 billing for each such TSP will be as follows:

Rate Determination

TSP’s TCOS Revenue Requirement (based on test year ended 12/31/02) TSP’s Wholesale Transmission Service Rate, = effective January 1, 2002 56,800 MW PUC Docket No. 22348 Consolidated Interim Order Page 36 SOAH Docket Nos. 473-00-1013

2002 Billing

TSP’s Wholesale Transmission Service Each Distribution Utility’s 2001 Actual X Rate Effective January 1, 2002 ERCOT 4CP

ERCOT TSPS THAT HAVE NOT FILED A TCOS CASE The wholesale transmission service rates for ERCOT TSPs which have not filed a TCOS case to establish new wholesale transmission service rates effective January 1, 2002, will not change. The wholesale transmission service rates of such TSPs will continue to be their existing, Commission-approved rates. In 2002, these TSPs will bill distribution utilities by applying their existing Commission-approved wholesale transmission service rates to the prior year (2001) ERCOT 4CP billing units.

2. Other Issues

Pilot Project

(Generic Proceeding, Order No. 51 – Distribution Utilities’ Calculation of Retail Charges For Pilot Project and Full Competition in 2002)

(Generic Proceeding, Order No. 53 – ERCOT Retail Transmission Charge Calculation)

How should retail transmission charges for the pilot projects and full competition in 2002 be calculated by the distribution utilities in ERCOT and billed to the retail electric providers to implement Order No. 40?

This issue was initiated on March 21, 2001, through the joint motion to establish a new generic issue filed in the Generic Proceeding by American Electric Power Company, Inc., Enron Energy Services, Inc., Pasadena Cogeneration L.P., Reliant Energy HL&P, Texas Industrial Energy Consumers, Texas-New Mexico Power Company, and TXU Electric Company.

After a number of workshops and informal meetings, parties entered into a Stipulation and Agreement filed on April 6, 2001, along with supporting testimony. The Stipulation and PUC Docket No. 22348 Consolidated Interim Order Page 37 SOAH Docket Nos. 473-00-1013

Agreement along with the supporting testimony were admitted into evidence. No opposition was filed to the stipulation and agreement. The Commission finds that the unopposed stipulation and agreement entered by and among certain parties to this proceeding82 is reasonable and appropriate. The Commission approves and incorporates the April 6, 2001 Stipulation and Agreement and supporting testimony.

Therefore, the Commission deems that retail transmission charges billed by ERCOT distribution utilities to retail electric providers (“REPs”) during the pilot projects, from June 1, 2001, through December 31, 2001, and after full competition begins on January 1, 2002, or at such later date as the Commission may order, will be calculated in accordance with the following procedures. For the reasons set forth in the testimony of J. Michael Sherburne, these procedures are a reasonable method of calculating retail transmission rates that should be approved by the Commission for use by the ERCOT distribution utilities in billing REPs during the pilot project and after full competition begins. This approach is consistent with the billing method specified in the Commission’s wholesale transmission rules and the billing model specified in Order No. 40 in Generic Proceeding No. 22344. This approach will also provide uniformity among distribution utilities in ERCOT and will facilitate the filing of compliance tariffs after interim orders are issued by the Commission in the UCOS cases.

A. The transmission service provider wholesale transmission rates that will be in effect on January 1, 2002, shall be used to set the distribution utility’s transmission revenue requirement;

B. The distribution utility shall use its 2002 4CP demand from its UCOS case to determine the distribution utility’s retail transmission revenue requirement;

C. The retail rate class 2002 4CP allocation factors from the distribution utility’s UCOS case shall be used to establish the retail transmission rates;

82 Central Power and Light Company (CP&L); Reliant Energy HL&P (Reliant); the Staff of the Public Utility Commission of Texas (Staff); Texas-New Mexico Power Company; TXU Electric Company (TXU); Texas Industrial Energy Consumers (TIEC); West Texas Utilities (WTU); Enron Energy Services, Inc. (ENRON); Pasadena Cogeneration L.P.; Cleco ConnexUs, L.L.C.; and AES New Energy, Inc. PUC Docket No. 22348 Consolidated Interim Order Page 38 SOAH Docket Nos. 473-00-1013

D. The 2002 retail billing units from the distribution utility’s UCOS case shall be used to determine the retail transmission rates;

E. REPs serving IDR-metered customers that have established an average 4CP demand for the previous calendar year will be billed retail transmission charges in the following calendar year using the retail customer’s prior year’s average 4CP demand as the transmission billing determinant. The retail customer’s average 4CP demand will be updated effective on January 1 of each calendar year and remain fixed throughout the calendar year. REPs serving non-IDR-metered customers will be billed retail transmission charges for those customers based on current year actual billing determinants; and

F. Billing determinants for the transmission service charges that will be billed to the REPs serving new IDR-metered retail customers (including formerly non-IDR metered retail customers that switch to IDR meters) will be calculated in accordance with the following procedures:83

(1) Transmission Voltage Retail Customers:

(a) REPs serving retail customers having IDR data for fewer than 4CPs, but at least 2CPs, will be billed based on the average of the actual CPs, so long as the CPs are representative of the retail customer’s expected load, as derived from engineering estimates. If the CPs are not representative of the expected load, the billing demand will be set based on mutual agreement between the retail customer and the distribution utility.

(b) REPs serving retail customers that do not have at least 2 CPs will be billed by estimating the retail customer’s 4CP demand by applying a class coincidence factor to the customer’s non-coincident peak demand, using the formula:

Estimated 4CP = (NCPkW * TCCF) where:

NCPkW is the highest 15-minute integrated demand of each individual transmission customer during the month (i.e., customer NCP); and

83 Utilities that have historically billed on a per-kVA basis will bill on kVA rather than kW (e.g., NCP kVA and CP kVA). See Generic Proceeding, Order No. 40. PUC Docket No. 22348 Consolidated Interim Order Page 39 SOAH Docket Nos. 473-00-1013

TCCF is the Transmission Class Coincidence Factor for the months June, July, August, and September calculated from the distribution utility’s most recent UCOS proceeding using the following formula:

TCCF =  CPkW (for June, July, August, September)

 NCPkW (for June, July, August, September)

Where:

CPkW is the transmission voltage rate class’ 15 minute demand at the time of the ERCOT CP and NCPkW is the transmission voltage rate class’ maximum 15 minute demand during the month.

(2) Secondary or Primary IDR-metered Retail Customers:

(a) REPs serving retail customers without 4CP data will be billed on actual kW at the applicable non-coincident peak rate.

Pilot Project

Wholesale transmission service rates currently in effect in 2001 shall remain in effect for billing to the distribution utilities during the pilot projects. The Commission grants a good-cause waiver of P.U.C. SUBST. R. 25.431(h) so that these rates may be used. a. System Benefit Fund

(Generic Proceeding Order No. 14 : Category A Issue No. 7)

How should system benefits fund fees be determined and how should they be recovered?

The Commission concludes that, for the purposes of the UCOS cases, the system benefit fee (SBF) should be $0.50 per megawatt hour. Consequently, the only issue in the UCOS cases related to the SBF is whether a utility has used this specific rate. This approach comports with

P.U.C. SUBST. R. 25.344(f)(4) which requires a utility’s initial filing to assume a rate of $0.50 per megawatt hour. PUC Docket No. 22348 Consolidated Interim Order Page 40 SOAH Docket Nos. 473-00-1013

Expedited Recovery

(Generic Proceeding Order No. 17: Category B Issue No. 4)

Is the 2002 test year concept satisfied by the new procedures adopted by the

Commission for expedited recovery of transmission investment pursuant to P.U.C. SUBST. R. 25.193?

The Commission withdraws this issue from consideration. b. Payment of Stranded Costs and Discontinuation of Service

(Generic Proceeding, Order Nos. 12 & 15 – Payment of Stranded Costs and Discontinuation of Service)

What responsibility for stranded costs does a retail customer have under PURA if the customer discontinues taking retail electric service due to shutting down operations, moving outside of the state, or relocating to an area of the state that is outside their existing utility’s geographically certificated service area, and how is any such responsibility satisfied?

All of the briefing parties agreed that, under the circumstances described in the question posed, a retail customer ceases to be responsible for, and would not be required to continue to pay the stranded cost of their existing utility. The parties consistently interpreted the language in PURA § 39.252(b)(1) requiring recovery of stranded costs from “all existing or future retail customers” to exclude those existing customers who shut down operations, move outside of the state, or relocate to an area of the state that is outside their existing utility’s geographically certificated service area. The parties’ positions were based on their interpretations of PURA, a consideration of fairness, or both. Many of the parties noted that those retail customers that relocate in the state and begin taking service within another the geographically certificated area that is burdened with charges to recover stranded costs will become responsible for those stranded-cost charges.

The Commission agrees with the parties that a customer who discontinues taking retail electric service due to shutting down operations, moving outside of the state, or relocating to an area of the state that is outside their existing utility’s geographically certificated has no further PUC Docket No. 22348 Consolidated Interim Order Page 41 SOAH Docket Nos. 473-00-1013 responsibility for the recovery of stranded costs in their existing service area. The requirement in PURA § 39.252(b)(1) that “[r]ecovery of retail stranded costs by an electric utility shall be from all existing or future retail customers, including the facilities, premises, and loads of those retail customers, within the utility's geographical certificated service area as it existed on May 1, 1999” has no application in those circumstances. A customer who shuts down operations, moves outside the state, or relocates to another geographical service area is no longer a retail customer within the original utility’s service area. The Commission recognizes that special provisions apply to certain customers that are outside the scope of this issue.84

The alternative reading of PURA § 39.252(b)(1) that would impose a continuing responsibility for stranded costs on every retail customer taking service on May 1, 1999, does not comport with the overall structure of stranded-costs recovery. A requirement imposing a continuing responsibility for stranded costs would be impractical, if not impossible, from a billing and record-keeping perspective. Moreover, it would unfairly burden some retail customers by requiring them to pay twice for stranded costs. Not only would such a customer have to pay stranded costs as a new retail customer in the area to which they relocated, but also as an “existing customer” for the area where they were taking service on May 1, 1999. The ramifications of this alternative reading bolster the Commission’s conclusion that there is no continuing obligation for stranded costs for a retail customer who shuts down operations, moves outside the state, or relocates to another geographical service area is no longer a retail customer within the original utility’s service area.

84 See PURA §§ 39.252(b)(1), (2), 39.262(k) (relating to on-site generation), and PURA § 39.252(c) (relating to multiply certificated areas). PUC Docket No. 22348 Consolidated Interim Order Page 42 SOAH Docket Nos. 473-00-1013

C. Code of Conduct

As noted in the Preliminary Order issued in this docket,85 pursuant to a settlement in Sharyland’s Business Separation Plan docket,86 Sharyland’s proposed code of conduct was transferred to this docket for consideration and approval. As approved in the Interim Order-Rate Phase in this docket, the Settling Parties agreed that Sharyland’s proposed code of conduct, as amended with the revised Paragraph F87 (attached to this Order as Appendix A), is reasonable and complies with all applicable provisions of PURA and Commission regulations.

D. Business Separation Plan

On May 3, 2000, the Commission approved via an interim order Sharyland’s Business Separation Plan as settled,88 finding that Sharyland’s proposed plan does not create a functional separation as opposed to creating legally distinct entities89 and that the proposed plan is consistent with PURA § 39.051.90 In that interim order, the Commission noted that Sharyland established in its application for approval of its business separation plan that Sharyland does not own any generation facilities and does not plan to form a generation affiliate after the introduction of customer choice.91 Further, the Commission noted that Sharyland indicated that

85 Application of Sharyland Utilities, L.P., for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and Public Utility Commission Substantive Rule § 25.344, Preliminary Order at 2 (June 7, 2000). 86 Application of Sharyland Utilities, L.P. for Approval of Business Separation Plan Pursuant to PURA § 39.051, Docket No. 21954, Interim order Approving Stipulation and Settlement Regarding Approval of Business Separation Plan at 3 (May 3, 2000). 87 Revised Paragraph F, Sharing of Officers and Directors, Property, Equipment, Computer Systems, Information Systems and Corporate Support Services. 88 Docket No. 21954, Interim Order Approving Stipulation and Settlement Regarding Approval of Business Separation Plan (May 3, 2000). 89 As established in Docket No. 21954, Order Memorializing Pre-hearing Conference and Clarifying Nature of Referral to SOAH at 4 (Feb. 16, 2000), the scope of the expedited hearing before the Commission in that docket was “whether the proposed plan creates a functional separation, as opposed to creating legally distinct entities, and if such functional separation fulfills the requirements of PURA.” 90 Docket No. 21954, Interim order Approving Stipulation and Settlement Regarding Approval of Business Separation Plan at 2 (May 3, 2000). 91 See Docket No. 21954, Interim Order Approving Stipulation and Settlement Regarding Approval of Business Separation Plan at 1 (May 3, 2000). PUC Docket No. 22348 Consolidated Interim Order Page 43 SOAH Docket Nos. 473-00-1013

Sharyland will not need to separate various activities into separate business functions and, instead, will contract with unaffiliated third parties to provide functions such as power supply acquisition and customer service, and that, therefore, such activities will already be separated when they become competitive.92 The interim order found that issues related to Sharyland’s business separation plan that were not addressed by the settlement in that docket may be considered in the instant docket, including issues related to Sharyland’s code of conduct.93 On February 21, 2001, the SOAH ALJ issued Order No. 12 in Sharyland’s business separation docket, consolidating and closing Sharyland’s business separation docket.94 In Order No. 12, the ALJ noted that Sharyland had incorporated its business separation issues into the UCOS docket (instant docket), which was being resolved by settlement, and that there was no longer any reason to retain a separate docket for the business separation case.95

E. ECOM

The ECOM determinations of the generic proceeding are inapplicable to Sharyland. Sharyland owns no generation facilities and, therefore, has no potentially stranded costs to recover.

F. Transmission and Distribution

Because of Sharyland’s unique situation as a relatively new start-up utility, 96 commencing operations in mid-February 2000, the Commission provided for a number of

92 See Docket No. 21954, Interim Order Approving Stipulation and Settlement Regarding Approval of Business Separation Plan at 1 (May 3, 2000) (Generic Proceeding). 93 See Docket No. 21954, Interim Order Approving Stipulation and Settlement Regarding Approval of Business Separation Plan at 3 (May 3, 2000). 94 Docket No. 21954, Order No. 12 – Consolidating and Closing Business Separation Docket (Feb. 21, 2001). 95 Docket No. 21954, Order No. 12 – Consolidating and Closing Business Separation Docket at 1-2 (Feb. 21, 2001). 96 Because of Sharyland’s recent start date, it does not posses operating experience upon which to provide historical test year information requested by P.U.C. SUBST. R. 25.344(d) as the basis for a forecast test year in this proceeding. Therefore, Sharyland used an operational forecast in lieu of a historical test year in its UCOS application. PUC Docket No. 22348 Consolidated Interim Order Page 44 SOAH Docket Nos. 473-00-1013 transmission and distribution issues to be handled specifically in the instant docket, as opposed to being handled in the UCOS docket dealing with generic issues.97

First, in Order No. 25 in the instant docket, the Commission exempted Sharyland from application of the generic operations and maintenance escalator factors. In that order the Commission stated:

The Commission finds that Sharyland has few of the characteristics of the other IOUs in this docket. In short, Sharyland, which only recently began service, has no 1999 historic test year to apply a generic escalation factor. Consequently, Sharyland is exempt from application of this ruling.98

Next, the Commission moved the determination of Sharyland’s return on equity and capital structure from the Generic Proceeding to the instant proceeding.99 In the instant docket, as approved in the Interim Order-Rate Phase, the Settling Parties agreed that Sharyland is entitled to a higher than average return on equity because of Sharyland’s unique circumstances as a start-up electric utility serving a small number of customers in a developing 6,000-acre service area. The Settling Parties agreed that a return on equity of 12.75% and a cost of debt of 8.5%, resulting in an overall rate of return of 10.84%, is reasonable and appropriate given Sharyland’s unique circumstances.100 The Settling Parties also agreed that a capital structure consisting of 55% equity and 45% debt appropriately reflects the proper consideration of loans to the Sharyland limited partnership.101 Further, the Settling Parties agreed that Sharyland’s proposed cost of transmission and distribution service of $1,119,945 is reasonable and properly calculated pursuant to the UCOS Rate-Filing Package.102

97 Generic Issues Associated with Applications for Approval of Unbundled Cost of service Rate Pursuant to PURA § 39.201 and Public Utility Commission Substantive Rule 25.344, Docket No. 22344 (April 26, 2001). 98 Docket No. 22344, Order No. 25 – Interim Order Ruling on Escalator(s) Issues at 9 (Aug. 25, 2000). 99 Docket No. 22344, Order No. 28 – Interim Order Ruling on Incentive Plan and Return on Equity Issues at 2 (Sept. 22, 2000). 100 Revised Interim Order-Rate Phase at 4 (July 20, 2001). 101 Revised Interim Order-Rate Phase at 4 (July 20, 2001). 102 Revised Interim Order-Rate Phase at 4 (July 20, 2001). PUC Docket No. 22348 Consolidated Interim Order Page 45 SOAH Docket Nos. 473-00-1013

Finally, with regard to customer classification and rate design, the Commission exempted Sharyland from certain of the six customer classes adopted in the Generic Proceeding for use by each of the utilities and moved the determination of Sharyland’s specific customer classification and rate design to the instant proceeding.103 In Order No. 40 in the Generic Proceeding, the Commission stated as follows:

The Commission finds that the six customer classes as proposed in the NUA [Non-Unanimous Stipulation and Agreement (NUA)] should be adopted by each of the utilities participating in this proceeding. . . . To recognize its unique characteristics, the Commission grants Sharyland Utilities, L.P. (Sharyland) and exemption from certain of the classifications. All of Sharyland’s customers are equipped with interval data recorder (IDR) meters, obviating the need for classes to accommodate non-demand-metered customers. [F.N. omitted]. Therefore, to the extent that such classes are unnecessary for Sharyland, a modified version of the NUA classes for Sharyland shall be addressed in its individual UCOS case. [F.N. omitted]. This exemption does not, however, excuse Sharyland from meeting the underlying principles cited above. Additionally, Sharyland’s classifications should mirror those in the NUA for demand-metered classes.104

In the instant docket, as approved in the Interim Order-Rate Phase, the Settling Parties agreed that Sharyland’s proposed design for transmission and distribution rates is reasonable.105

G. Other Issues

1. Meter Reading as Competitive Energy Service

The Commission addressed in Docket No. 21988106 the severance of competitive energy services from Sharyland’s application for approval of its business separation plan. On May 10, 2000, the Commission issued an order resolving the proceeding consistent with a settlement

103 Docket No. 22344, Order No. 40 – Interim Order Establishing Generic Customer Classification and Rate Design at 4, 13 (Nov. 22, 2000). 104 Docket No. 22344, Order No. 40 – Interim Order Establishing Generic Customer Classification and Rate Design at 4 (Nov. 22, 2000). 105 Revised Interim Order-Rate Phase at 5 (July 20, 2001). 106 Competitive Energy Services Issues Severed from Application of Sharyland Utilities, L.P. for Approval of Business Separation Plan Pursuant to PURA Section 39.051, Docket No. 21988 (May 10, 2000). PUC Docket No. 22348 Consolidated Interim Order Page 46 SOAH Docket Nos. 473-00-1013 among the parties.107 In that order, the Commission found that Sharyland does not currently offer competitive energy services, as defined in P.U.C. SUBST. R. 25.341(6), and it does not intend to offer such services in the future.108 Further, the Commission found that the agreement among the parties did not resolve the issue of whether meter reading is a competitive energy service within the meaning of P.U.C. SUBST. R. 25.341(6) and that the parties reserved the right to raise this issue in other proceedings as appropriate.109 In its Preliminary Order in the instant docket issued on June 7, 2000, the Commission identified as an issue to be addressed this issue of whether meter reading is a competitive energy service.110 In the instant docket, as approved in the Interim Order-Rate Phase, the Settling Parties agreed that meter reading is not a competitive energy service.111

2. Commitment to File New Rate Case

In the instant docket, as approved in the Interim Order-Rate Phase, the Settling Parties agreed that Sharyland would abide by the commitment it made in its initial rate case to file a new rate case.112 As discussed previously in footnote 2 of this Order, Sharyland agreed in its initial rate case to file a general rate proceeding no later than May 1, 2003, which is in addition to the instant UCOS rate case and which will only apply to Sharyland’s transmission and distribution (T&D) rates since the proceeding will occur after the onset of competition.113

3. Residential Rate Cap

In the instant docket, as approved in the Interim Order-Rate Phase, the Settling Parties agreed that Sharyland would abide by the settlement in its initial rate case.114 As discussed previously in footnote 2 of this Order, Sharyland agreed, subject to certain conditions, to keep its

107 Docket No. 21988, Order (May 10, 2000). 108 Docket No. 21988, Order at 2 (May 10, 2000). 109 Docket No. 21988, Order at 2 (May 10, 2000). 110 Preliminary Order at 5 (June 7, 2000). 111 Revised Interim Order-Rate Phase at 7 (July 20, 2001). 112 See Docket No. 21591, Order at 4 (July 26, 2000). 113 See Docket No. 21591, Order at 4 (July 26, 2000). 114 Revised Interim Order-Rate Phase at 3 (July 20, 2001). PUC Docket No. 22348 Consolidated Interim Order Page 47 SOAH Docket Nos. 473-00-1013 average unbundled T&D rates at or below the average unbundled T&D (including non- bypassable charges) rates of CPL.115

III. FINDINGS OF FACT

A. Generic Docket

1. Procedural History

1. The Public Utility Regulatory Act § 39.201116 requires each electric utility to file proposed tariffs for its transmission and distribution utility on or before April 1, 2000.

2. Reliant Energy HL&P (Reliant); Central Power and Light Company (CPL), West Texas Utilities Company (WTU), Southwestern Electric Power Company (SWEPCO) (collectively also referred to as American Electric Power Company (AEP)); TXU Electric Company (TXU); El Paso Energy; Southwestern Public Service Company (SPS); Texas New Mexico Power Company (TNMP); Entergy Gulf States, Inc., (EGSI); and Sharyland Utilities, LLC, (Sharyland) filed their Applications for Approval of Unbundled Cost of

Service Rate Pursuant to PURA § 39.201 and P.U.C. SUBST. R. § 25.344 on March 31,

115 See Docket No. 21591, Order at 5 (July 26, 2000); see also Docket No. 21591, Proposal for Decision at 3 (May 26, 2000).

116 TEX. UTIL. CODE ANN. §§ 11.001 – 64.158 (Vernon 1998 & Supp. 2001) (PURA). PUC Docket No. 22348 Consolidated Interim Order Page 48 SOAH Docket Nos. 473-00-1013

2000.117 These cases were generally referred to as Unbundled Cost of Service (UCOS) cases.

3. In filing their cases, in addition to PURA requirements, the utilities also followed instructions outlined in the Unbundled Cost of Service Rate Filing Package (UCOS –

RFP),118 as required by P.U.C. SUBST. R. 25.345(f).

4. On March 29, 2000, the Commission initiated Docket No. 22344, Generic Issues Associated with Applications for Approval of Unbundled Cost of Service Rate Pursuant

to PURA § 39.201 and P.U.C. SUBST. R. § 25.344 (Generic Proceeding). The purpose of the Generic Proceeding was to address all issues that were similar in each of the utilities’ proceedings filed pursuant to PURA § 39.201.

5. Initial Texas Register notice of Docket No. 22344 was provided by the Commission at 25 TexReg 3652, on April 21, 2000. Additional notices were provided on January 17, 2001, and on March 21, 2001.

6. On April 6, 2000, the Commission administrative law judge (ALJ) issued Order No. 1, stating that all parties to the individual UCOS cases as of April 6, 2000, would be considered parties to the Generic Proceeding.

7. The following parties to individual UCOS cases were made parties to this proceeding pursuant to Order No. 1: City of Houston; Dallas-Fort Worth Hospital Council

117 Application of Sharyland Utilities, L.P., for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and P.U.C. SUBST. R. 25.344, Docket No. 22348 (pending); Application of Texas-New Mexico Power Company for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and P.U.C. SUBST. R. 25.344, Docket No. 22349 (pending); Application of TXU Electric Company for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and P.U.C. SUBST. R. 25.344, Docket No. 22350 (pending); Application of Southwestern Public Service Company for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and P.U.C. SUBST. R. 25.344, Docket No. 22351 (pending); Application of Central Power & Light Company for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and P.U.C. SUBST. R. 25.344, Docket No. 22352 (pending); Application of Southwestern Electric Power Company for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and P.U.C. SUBST. R. 25.344, Docket No. 22353 (pending); Application of West Texas Utilities Company for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and P.U.C. SUBST. R. 25.344, Docket No. 22354 (pending); Application of Reliant Energy HL&P for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and P.U.C. SUBST. R. 25.344, Docket No. 22355 (pending); Application of Entergy Gulf States, Inc., for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and P.U.C. SUBST. R. 25.344, Docket No. 22356 (pending); hereinafter, individual UCOS cases. 118 Cost Unbundling and Separation of Business Activities, including Separation of Competitive Energy Services and Distributed Generation, Project No. 21083 (December 16, 1999). PUC Docket No. 22348 Consolidated Interim Order Page 49 SOAH Docket Nos. 473-00-1013

(DFWHC); Coalition of Independent Colleges and Universities (CICU); NUCOR Steel; Consumer-Owned Power Systems (COPS); Alcoa, Inc.; Competitive Power Advocates; Tex-La Electric Cooperative, Inc.; Sam Rayburn G&T Electric Cooperative, Inc.; Northeast Texas Electric Cooperative, Inc.; Brazos Electric Cooperative; State of Texas; Texas Legal Services; Texas Industries, Inc., and its subsidiary, Chaparral Steel Company (collectively TXI); Brownsville Public Utility Board; Cities of Beaumont, Bridge City, Conroe, Groves, Huntsville, Nederland, Pine Forest, Port Arthur, Port Neches, Orange, Silsbee, Somerville, and Vidor; Cap Rock Electric Cooperative; Greenville Electric Cooperative; City of Denton; and City of Garland.

8. Intervention in the Generic Proceeding was granted to the following parties in Order Nos. 2, 3, 4, and 5: Floresville Electric Light & Power Systems; Tenaska Frontier Partners, L.P.; Pasadena Cogeneration, L.P.; the Lower Colorado River Authority (LCRA); Cities of Abilene, Addison, Alice, Allen, Andrews, Aransas Pass, Arlington, Belton, Brownwood, Buffalo, Burkburnett, Burleson, Camp Wood, Carrizo Springs, Carrollton, Charlotte, Cleburne, Comanche, Copperas Cove, Corpus Christi, Dallas, Dennison, Dilley, Eagle Pass, Edinburg, Edna, Flower Mound, Fort Stockton, Fort Worth, Ganado, George West, Grand Prairie, Gregory, Harker Heights, Harlingen, Henrietta, Highland Park, Honey Grove, Howe, Irving, Kerens, Laredo, Leakey, Lewisville, Los Fresnos, Lytle, Malakoff, Mathis, McAllen, Mercedes, North Richland Hills, Odem, O’Donnell, Orange Grove, Pantego, Plano, Pleasanton, Port Aransas, Port Isabel, Port Lavaca, Ranch Viejo, Raymondville, Refugio, Rhome, Richardson, Richland Hills, Rio Hondo, Roanoake, Robinson, Rockport, Rockwall, Roma, San Benito, San Juan, Sinton, Smiley, Snyder, Sulphur Springs, Taft, University Park, Vernon, Victoria, Waco, Watauga, Wichita Falls, and Woodway (“Cities”); City of Friendswood; City Public Service of San Antonio (CPS); City of Austin, d/b/a Austin Energy; Texas Independent Energy, L.P.; Cleco ConnexUS, LLC; Occidental Chemical Corporation.; Texas Retailers Association (TRA); National Association of Energy Services Companies; Enron Energy Services (Enron); City of Alvin; Texas Cotton Ginners Association; Automated Energy, Inc.; and APS Energy Services Company, Inc. PUC Docket No. 22348 Consolidated Interim Order Page 50 SOAH Docket Nos. 473-00-1013

9. On April 7, 2000, the Commission issued notice of a proceeding to address issues in the Generic Proceeding. Subsequently, various parties to the case filed lists of issues, from which the Commission developed issues to be briefed. a. Category “A” and “B” Issues

10. On May 9, 2000, the Commission issued Order No. 3 in the Generic Proceeding, granting intervention to parties and requesting briefing on the generic issues, which were divided into seven category “A” issues and six category “B” issues. While the Commission, at the March 23, 2000 Open Meeting, discussed that some issues related to law and policy decisions and some would require a hearing, the division into “A” and “B” was done for procedural reasons only.

11. The issues were as follows:

CATEGORY “A” 1. What changes may be made to the inputs in the Commission’s 1998 Update to the Excess Cost Over Market (ECOM) model in calculating ECOM pursuant to PURA § 39.201(h)? Specify what changes should be allowed and why. Are there inputs that are generic to all utilities with stranded costs, which should be used in calculating ECOM pursuant to PURA § 39.201(h)?

2. In determining the structure for the recovery of costs through competition transition charges (CTC), should the Commission emphasize the preservation of the headroom or the expeditious recovery of stranded costs? Are there other mechanisms than varying the period for the recovery of stranded costs that the Commission should use to ensure sufficient headroom for all customers?

3. How should Electric Reliability Council of Texas (ERCOT) transmission providers recover their transmission costs? Should they bill retail electric providers (REPs), either directly or through an ERCOT settlement, or bill a transmission distribution utility, which would then bill REPs a combined transmission and distribution charge?

4. Should the following factors be reflected in the ECOM calculation in setting the CTC: environmental clean-up costs and the salvage value of retired plants, including emissions allowances and the PUC Docket No. 22348 Consolidated Interim Order Page 51 SOAH Docket Nos. 473-00-1013

market value of retired plant sites? Alternately, should any of these factors be deferred to the true-up?

5. Should regulatory assets for which the Commission has issued a securitization order be removed from ECOM? If so, when?

6. Should investment tax credits be included in the calculation of ECOM?

7. How should system benefits fund fees be determined and how should they be recovered?

CATEGORY “B” 1. Where the Commission has adopted an allocation of regulatory assets for a utility in a securitization case, should the same allocation apply to any stranded costs that the utility includes in a CTC?

2. Are the following costs recoverable as costs of the transmission and distribution utility: rate case expenses, restructuring costs, energy efficiency costs, and costs of the pilot project? Are special cost- recovery mechanisms for costs incurred prior to January 2002 permitted under PURA, and if so, are they appropriate? Do the rate freeze and rate path prescribed by Senate Bill 7 (SB7)119 limit the recovery of these costs?

3. Are there criteria for determining whether expenses or capital investments for the forecasted 2002 test year are reasonable and necessary, such as generic escalation factors for operations and maintenance expenses?

4. Is the 2002 test year concept satisfied by the new procedures adopted by the Commission for expedited recovery of transmission investment pursuant to P.U.C. SUBST. R. 25.193?

5. Does the Commission have authority to establish a combined delivery charge (transmission and distribution) for non-ERCOT utilities?

6. Should the Commission adopt a uniform classification scheme and uniform rate design for transmission and distribution service? Should transmission and distribution rates include intermittent or stand-by service? Should the Commission adopt uniform or generic standards for incentive- or performance-based rates, the appropriate capital structure of a transmission and distribution utility, and for authorizing

119 Senate Bill 7 – Act of May 27, 1999, 76th Legislature, R.S., chapter 405, 1999 Texas Session Law Service 2543 (Vernon) (SB7). PUC Docket No. 22348 Consolidated Interim Order Page 52 SOAH Docket Nos. 473-00-1013

a return on equity of more than 200 basis points above the utility’s average yield on bonds? Parties filed briefs on category “A” issues on May 25, 2000; replies were filed on June 1 and 5, 2000. Briefs on category “B” issues were filed on May 31, 2000; and replies were filed on June 7, 2000.

12. Parties filed briefs on Category “A” issues on May 25, 2000; replies were filed on June 1, 2000. Briefs on Category “B” issues were filed on May 31, 2000; replies were filed on June 7, 2000.

13. The Commissioners considered Categories “A” and “B” issues at the open meetings on June 14, 2000, and June 29, 2000, respectively.

14. On July 17, 2000, the ALJ held a prehearing conference, at which the parties discussed procedures for and the scope of hearings in this Generic Proceeding.

15. Order No. 18, issued on July 18, 2000, memorialized the prehearing conference on July 17, 2000. Specifically, it set out issues for factual hearings by the Commission on (a) natural gas prices; (b) operation and maintenance escalators; (c) customer classification and transmission and distribution rate design; and (d) incentive plan, return on equity, and capital structure.

16. On July 18, 2000, the Commission issued Order No. 14 in the Generic Proceeding, which ruled on category “A” issues.

17. On July 24, 2000, the Commission issued Order No. 17 in the Generic Proceeding, which ruled on category “B” issues. b. Payment of Stranded Costs

18. On June 13, 2000, the Commission issued Order No. 11, which consolidated Docket No. 22633120 with Docket No. 22344.

120 Petition of the Navy for Declaratory Ruling Regarding Payment of Stranded Costs for Retail Customers Leaving Current Electricity Provider in Texas, Docket No. 22633 (June 13, 2000). PUC Docket No. 22348 Consolidated Interim Order Page 53 SOAH Docket Nos. 473-00-1013

19. Order No. 12, issued by the Commission added a new issue regarding payment of stranded costs by customers who cease operations in or move out of a utility’s area to the generic issues and requested briefing.121

20. Initial briefs were filed by parties on June 22, 2000; reply briefs were filed on June 28, 2000.

21. On July 12, 2000, the Commission issued Order No. 15, which ruled on the issue added by Order No. 12. c. Generic Operation and Maintenance Escalators

22. Based on the discussion at the June 29, 2000 open meeting, the July 17, 2000 prehearing conference, and the ruling in Order No. 17, the Commission convened a hearing on the merits on August 7, 2000, in the Generic Proceeding, to address the issue of the generic operation and maintenance (O&M) escalators for the 2002 test year (Issue “B” 3).

23. On July 27 and August 3, 2000, respectively, various parties filed direct and rebuttal testimony.

24. On August 14, 2000, parties filed initial post-hearing briefs; replies were filed on August 18, 2000.

25. On August 25, 2000, the Commission issued Order No. 25 in the Generic Proceeding, ruling on the issues relating to generic O&M escalators. d. Natural Gas Prices and Market Prices

26. The Commission considered the issue of generic natural gas prices and market prices at the June 29, 2000 open meeting.

121 This new issue was raised by the U.S. Department of the Navy, which has a pending case at the Commission, Petition of the Navy for Declaratory Ruling on Wholesale Electric Customer Status for Three Bases in Texas, Docket No. 17180 (pending). PUC Docket No. 22348 Consolidated Interim Order Page 54 SOAH Docket Nos. 473-00-1013

27. On August 8, 2000, the parties filed statements of position and testimony regarding natural gas prices.122

28. Based on the June 29, 2000 open meeting, the July 17, 2000 prehearing conference, and the rulings on Category “A” issues, on August 10, 2000, a hearing on the merits was convened in the Generic Proceeding to address the natural gas prices to be used in the ECOM model (Issue “A” 1).

29. On August 11, 2000, the Commission issued Order No. 22 in the Generic Proceeding, which established the natural gas prices and market prices to be used in the ECOM model. e. Rate Design and Customer Classification

30. The Commission considered rate design and customer classification issues at the June 29, 2000 open meeting.

31. The Commission issued Order No. 19 on July 19, 2000; it set out the timeline and scope for consideration of rate design and customer classification issues (Issue “B” 6).

32. On July 26, 2000, the Commission Staff,123 filed a Motion for Reconsideration of Order No. 19.

33. On August 1, 2000, the Commission issued Order No. 20, memorializing the prehearing conference of July 28, 2000, and granting the Commission Staff’s July 26th motion. The Commission ALJ proposed a new hearing schedule and an expansion of the customer classification and rate design issues to include identification of uniform customer classes and the development of a cost-driven, standardized rate design for T&D rates.124

122 The UCOS-RFP described the initial bid methodology to be used for determining gas prices for the ECOM model calculation at 61. 123 Formerly referred to as the Office of Regulatory Affairs (ORA). 124 Order No. 20 at 6. PUC Docket No. 22348 Consolidated Interim Order Page 55 SOAH Docket Nos. 473-00-1013

34. On August 11, 2000, the Commission issued Order No. 21 in the Generic Proceeding, expanding the scope of generic customer classification and rate design issues, as proposed in Order No. 20.

35. On September 8, 2000, a Distribution Service Customer Classification Non-Unanimous Stipulation and Agreement (NUA) was filed in this proceeding by AEP; TNMP; TXU; SPS; the Commission Staff; TIEC; Enron; and TXI.125 The following parties did not oppose the NUA: ALCOA and Floresville Electric Light and Power Systems.126

36. The NUA addressed only some issues regarding uniform customer classification scheme.

37. On October 16, 2000, various parties to the case filed statements of position and direct testimony; rebuttal testimony was filed on October 26, 2000.

38. On November 2 and 3, 2000, a hearing on the merits was convened in the Generic Proceeding by the Commission to address the issues relating to customer classification and rate design.

39. Initial post-hearing briefs were filed by the parties on November 7 and 8, 2000; reply briefs were filed on November 10, 2000.

40. The Commission considered the generic customer classification and rate design issues at the Open Meeting on November 16, 2000.

41. On November 22, 2000, the Commission issued its Order No. 40, establishing generic customer classifications and rate design.

125 Distribution Service Customer Classification Non-Unanimous Stipulation and Agreement at 2 (NUA). 126 NUA at 1. PUC Docket No. 22348 Consolidated Interim Order Page 56 SOAH Docket Nos. 473-00-1013 f. Incentive Plan, Return on Equity, and Capital Structure

42. The Commission considered the issues of an incentive plan and return on equity at the June 29, 2000 open meeting. The Commission instructed parties to seek consensus regarding incentive plan.

43. On August 15, 2000, the Commission Staff filed a proposed targeted incentive plan (TIP).

44. On August 22, 2000, parties filed comments on the proposed TIP.

45. On September 5, 2000, the Commission Staff filed a report on settlement conference regarding the TIP and other parties filed comments regarding this issue.

46. A report on additional settlement conference was filed by the Commission Staff on September 18, 2000.

47. The Commission considered the issue of TIP at the September 7 and 20, 2000 open meetings.

48. On September 22, 2000, the Commission issued Order No. 28, regarding the Generic Target Incentive Plan and Return on Equity Issues.

49. On September 27, 2000, parties filed testimony on the issue of capital structure

50. On October 19, 2000, the following parties filed a Non-Unanimous Stipulation and Agreement on the issues of return on equity and capital structure: Commission Staff; Certain Cities Served by TXU, Reliant, CPL, and WTU; City of Houston, TIEC, State of Texas; New Energy; Enron; TXI; DFWHD; CICU; COPS; CPS; STEC; East Texas Cooperatives; and Brazos.

51. On October 20, 2000, parties filed direct testimony on the issues of return on equity and capital structure; rebuttal testimony was filed on October 27, 2000. PUC Docket No. 22348 Consolidated Interim Order Page 57 SOAH Docket Nos. 473-00-1013

52. On November 6, 2000, a hearing on the merits was convened in the Generic Proceeding by the Commission to address the return on equity and capital structure to be used in the UCOS proceedings.

53. The initial post-hearing briefs were filed on November 22, 2000; replies were filed on December 4, 2000.

54. On December 22, 2000, the Commission issued Order No. 42, establishing generic return on equity and capital structure. g. Four Coincident Peak

55. Based on the Commission’s discussion at the December 13, 2000 open meeting,127 the Commission ALJ issued Order No. 43 on December 14, 2000, which posed a generic question regarding a uniform projection for the 2002 test year four coincident peak (4CP) (denominator) for all utilities setting future test year 2002 transmission rates.

56. Order No. 43 also expanded the scope of the 4CP issue to include the transmission cost of service (TCOS) dockets for the City Public Service of San Antonio (CPS), Lower Colorado River Authority (LCRA), South Texas Electric Cooperative (STEC), and the City of Bryan. Parties to these four TCOS proceedings were invited to intervene in the 4CP phase of the generic docket.

57. On December 20, 2000, SPS requested clarification whether the 4CP issue related only to ERCOT transmission rates and had no application to areas outside ERCOT. The ALJ issued Order No. 44 clarifying the issue on December 21, 2000.

58. At the prehearing conference on January 12, 2001, parties raised concerns related to the interconnectedness of some methodologies for projecting the 2002 ERCOT 4CP with the calculation of billing units, and the potential link between the rates set in the UCOS cases

127 Transcript at 185. PUC Docket No. 22348 Consolidated Interim Order Page 58 SOAH Docket Nos. 473-00-1013

and the Pilot Project. Order No. 46, issued on January 12, 2001, expanded the ERCOT 4CP issue to include these concerns.

59. On February 21, 2001, the following parties filed Forecasted ERCOT 2002 4CP Stipulation and Agreement: Commission Staff, Austin Energy, City of Garland, CPS, CPL, LCRA, Reliant, STEC, TNMP, TXU, WTU, and TIEC (not opposing).

60. On March 22, 2001, the Commission issued Order No. 50 adopting the Stipulation and

Agreement and granted a good-cause waiver of P.U.C. SUBST. R.. 25.431(h). h. Retail Transmission Charges

61. On March 16, 2001, the following parties filed a joint motion to establish a new issue in the Generic Proceeding: AEP, Enron, Pasadena Cogeneration, L.P., Reliant, TIEC, TNMP, and TXU. Commission Staff filed a response in support of the motion on March 19, 2001.

62. On March 21, 2001, the Commission issued Order No. 51, expanding the scope of the proceeding to address the issue of how retail transmission charges for the pilot project and full competition in 2002 should be calculated by the distribution utilities in ERCOT and billed to the retail electric providers (REPs). Notice of the issue was provided to all parties in this docket and the various individual UCOS proceedings.

63. On April 6, 2001, the following parties filed an unopposed Stipulation and Agreement regarding the Retail Transmission Charges issue: CPL, Reliant, TXU, TIEC, WTU, Commission Staff, Enron, Pasadena Cogeneration, L.P., Cleco ConnexUS, L.L.C., and AES New Energy, Inc.

64. On April 26, 2001, the Commission issued Order No. 53, establishing the method for calculating and billing the Retail Transmission Charges consistent with the parties’ Stipulation and Agreement.

PUC Docket No. 22348 Consolidated Interim Order Page 59 SOAH Docket Nos. 473-00-1013

2. Transmission and Distribution (T&D) Rates a. T&D Cost of Service

65. PURA § 39.201 provides a framework for establishing unbundled cost-of-service tariffs and charges for transmission and distribution utilities (TDUs) to be effective on January 1, 2002, when retail competition goes into effect.

66. The Commission made an initial ruling on the T&D rates in Order No. 40.

67. Recovery of expenses incurred prior to January 2002, is generally128 not appropriate because PURA § 39.201(b)(1) states that the charges are to be based upon a forecasted 2002 test year and because PURA § 39.052 freezes existing retail base rate tariffs until January 1, 2002.

68. The annual report process pursuant to PURA §§ 39.257-39.262 provides a way for the electric utilities to recover some costs during the freeze period, from September 1, 1999, through December 31, 2001.129

69. Any expenses or costs recoverable through the T&D rates in the 2002 forecasted test year must be demonstrably related to the T&D function. This is consistent with the provisions of PURA Chapter 39, requiring business separation and with the Commission’s mandate to establish T&D rates pursuant to PURA § 39.201. It is reasonable to allocate recoverable costs to the transmission or distribution functions, as appropriate, in the company-specific UCOS proceedings.

70. It is appropriate for TDUs to recover rate case expenses that are related to the T&D function and determined reasonable and necessary, including those incurred prior to January 2002. To mitigate rate impact, it may be reasonable to amortize recoverable rate case expenses over an appropriate time period. This is consistent with Commission

128 It is appropriate to recover rate case expenses related to the T&D functions that incurred prior to 2002, if they are determined to be reasonable and necessary. See Finding of Fact No. 120. 129 PURA §§ 39.256 – 39.262 (Vernon 1998 & Supp. 2001). PUC Docket No. 22348 Consolidated Interim Order Page 60 SOAH Docket Nos. 473-00-1013

precedent, as just and reasonable rate case litigation expenses have traditionally been allowed pursuant to PURA § 36.061(b)(2).130

71. T&D-related restructuring costs for capital expenditures and associated depreciation, as well as annual expenses, should generally be treated according to traditional rate-making principles and the provisions of PURA § 36.051.

72. Because TDUs will continue to be regulated after January 1, 2002, it is appropriate to include in T&D rates the T&D-related restructuring expenses that are determined reasonable and necessary and are expected to be incurred in the 2002 forecasted test year.

73. It is reasonable to amortize extraordinary expenses over an appropriate time period to mitigate rate impact.

74. Restructuring expenses incurred prior to the 2002 forecasted test year are eligible to be included in the annual-report process. Because debt restructuring expenses are unique, the recovery of such expenses should not exceed the proportionate share of T&D assets expressed as a percentage of total assets prior to business separation on a net book value basis.

75. P.U.C. SUBST. R. 25.181(h)(5) provides that funds for achieving the energy efficiency goal pursuant to PURA § 39.905 be placed in each utility’s T&D rates. Therefore, it is appropriate for TDUs to recover through T&D rates the energy efficiency program costs that: (1) are recurring, (2) are incurred in the 2002 forecasted test year, and (3) comply with the energy efficiency rule.131

76. It is reasonable to request recovery in the annual-report process of those energy efficiency costs associated with existing contract obligations that are incurred prior to the 2002 forecasted test year.

130 See Application of Texas-New Mexico Power Company for Authority to Change Rates and Petition of Texas-New Mexico Power Company for Deferred Accounting Treatment for TNP One-Unit Two, Docket Nos. 10200 and 10034, Examiners’ Report, 19 P.U.C. Bull. 89, 269 (Mar. 18, 1993). 131 P.U.C. SUBST. R. 25.181 PUC Docket No. 22348 Consolidated Interim Order Page 61 SOAH Docket Nos. 473-00-1013

77. Costs of the pilot project are not recoverable in the T&D rates established pursuant to PURA § 39.201 because they are not related to the provision of T&D service after January 1, 2002, and will not be incurred during the 2002 forecasted test year. Pilot project expenses incurred prior to the 2002 forecasted test year are eligible to be included in the annual-report process.

78. The capital investment costs for the T&D functions in the 2002 forecasted test year are more appropriately addressed in the individual UCOS dockets because: (1) some utilities would over-recover their costs if they are making no or limited capital investment, and (2) for some utilities an escalator would not provide adequate recovery for needed capital investment.

GENERIC ESCALATION FACTORS FOR O&M EXPENSES

79. The Commission made an initial ruling on this issue in Order No. 25.

80. It is reasonable to use a generic escalation factor, including a productivity offset, applied to 1999 historic test year O&M expenses, to calculate the utilities’ 2002 O&M expense. The following O&M escalation factors, which include a productivity offset, are reasonable:

Category 4th Qtr. 2000 2001 2002 1999 Materials and Services, T&D Expenses 0.1% 1.4% 0.5% 0.3% Materials and Services, A&G 0.5% 2.4% 2.4% 2.1% (excluding labor) Labor – Managerial, Professional & 0.6% 2.7% 2.6% 2.4% Technical, and Clerical Labor – Other 0.2% 1.8% 2.6% 2.5% PUC Docket No. 22348 Consolidated Interim Order Page 62 SOAH Docket Nos. 473-00-1013

81. Only “new” corporate restructuring expenses mandated by SB7132 may be included in the 2002 future test year, subject to reasonable and necessary review. Demand-side management expenses and transmission access charges are “new” SB7-mandated O&M expenses.

82. Expenses that are properly functionalized in the 1999 historic test year, and subsequently escalated, are not “new” SB7 expenses.

83. The UCOS-RFP methodology for determining O&M expenses in the 2002 future test year is appropriate. The 1999 historic test year data is subject to review pursuant to PURA § 36.051. Expenses that are recovered as “new” may not be recovered in the 1999 historic test year.

RETURN ON EQUITY AND CAPITAL STRUCTURE

84. In their UCOS filings pursuant to PURA § 39.201, several utilities proposed identical capital structures. This established the trend towards uniformity regarding ROE and capital structures.

85. The Commission made its initial ruling on the issues of ROE and capital structures in Order No. 17.133

86. A degree of uniformity among the newly unbundled TDUs is reflected in the similarities of business and financial risk levels, regulatory oversight, purpose, and structure.

87. It is, therefore, appropriate to set a uniform ROE and capital structure for all TDUs in Texas, with the exception of Sharyland.134

88. It is appropriate to establish Sharyland’s ROE and capital structure in its UCOS case.

132 PURA § 39.051 133 Order No. 17 at 13-15. 134 Sharyland, as a new company, most likely faces greater risk than other Texas TDUs. PUC Docket No. 22348 Consolidated Interim Order Page 63 SOAH Docket Nos. 473-00-1013

89. ROE of 11.25% and capital structure of 60% debt and 40% equity are reasonable and appropriate for the Texas TDUs for ratemaking purposes, beginning in 2002. b. Uniform Customer Classification

90. It is reasonable and appropriate to have uniform customer classification scheme for the purposes of standardizing T&D rates and facilitating the development of a competitive market in Texas.

91. Because T&D services are similar among all utility service areas, customer classes can be grouped by the type of T&D service they require. Cost causation, uniformity, and standardization are significant factors in developing a customer class configuration.135 The need for flexibility in addressing reconciliation with the price to beat (PTB) is also a reasonable guiding principle.136

92. In response to the Commission’s guidance in Order No. 17137 to create a uniform customer classification scheme, certain parties filed a Non-Unanimous Stipulation and Agreement (NUA) for Distribution Service Customer Classification.138 The NUA addresses customer classifications for all of the utilities participating in this proceeding, including the NUA-signatory utilities, as well as Reliant Energy HL&P (Reliant) and Entergy Gulf States, Inc. (EGSI).

93. The NUA provides for the following six customer classes: 1. Residential 2. Secondary less than 10 kW or kVA (less than 5 kW for TNMP and EGSI) 3. Secondary greater than 10 kW or kVA (greater than 5 kW for TNMP and EGSI) 4. Primary 5. Transmission 6. Lighting

135 Order No. 17 at 10; Order No. 40 at 4. 136 Order No. 40 at 4. 137 Order No. 17 at 10. 138 Distribution Service Customer Classification Non-Unanimous Stipulation and Agreement (NUA) at 2. PUC Docket No. 22348 Consolidated Interim Order Page 64 SOAH Docket Nos. 473-00-1013

94. The six customer classes proposed in the NUA encompass the principles of cost causation, uniformity, and standardization. Therefore, it is reasonable for each of the utilities in this proceeding to adopt the six customer classes, as proposed in the NUA.139

95. Reliant proposed to be exempted from the NUA customer class classifications based on the assertion that Reliant’s current commercial and lighting classes do not align with those proposed in the NUA.

96. Reliant failed to demonstrate adequately that it should be exempted from the uniform customer classification proposed in the NUA.

97. To recognize its unique characteristics, it is appropriate to exempt Sharyland from some of the customer classifications in the NUA. All of Sharyland’s customers are equipped with interval data recorder (IDR) meters, obviating the need for classes to accommodate non-demand-metered customers.140

98. To the extent that such classes are unnecessary for Sharyland, it is appropriate to address a modified version of the NUA classes for Sharyland in its individual UCOS case.141 Additionally, it is appropriate that Sharyland continues to meet the underlying principle regarding cost causation and that its classifications mirror those in the NUA for demand- metered classes. c. Generic T&D Rate Design

99. The Commission made an initial ruling on the generic T&D rate design issues in Order No. 40.

100. It is reasonable to consider the following principles in the design of T&D rates: cost causation, simplicity, and equity for customers within the given rate classes.

139 Order No. 40 at 4. 140 See Sharyland Statement of Position at 1. 141 Docket No. 22348. PUC Docket No. 22348 Consolidated Interim Order Page 65 SOAH Docket Nos. 473-00-1013

101. A uniform rate design for T&D rates achieves these goals and will facilitate entry by new competitors in the Texas electricity market. Therefore, it is appropriate for TDUs to adopt uniform T&D rate structures for each customer class.

CUSTOMER CHARGE

102. The adoption of a uniform rate design that includes a customer charge is appropriate because certain costs are incurred regardless of the customer’s use of electricity.

103. It is reasonable to include in the customer charge for each class those costs that vary by customer such as metering, billing, and customer service.142 A customer charge comprised of these elements appropriately tracks cost causation.

104. It is appropriate to state separately the metering portion of such charges, at a wholesale level, to facilitate the unbundling of metering charges when they become a competitive offering.

DELIVERY / FACILITIES CHARGES

105. It is appropriate to include a delivery/facilities charge for each class in the generic rate design. The method established for the recovery of a facilities/delivery charge from each customer class should reflect the best available metering data for each class, be a reasonable proxy for cost causation, and maintain continuity with past rate design methodology.

106. The manner in which the delivery/facilities charge is to be recovered should be contingent on the metering capabilities of each customer.

107. Because the residential and small commercial classes143 typically do not have demand meters in place, a facilities/delivery charge should be recovered on a monthly per- kilowatt-hour (kWh) basis for these customers.

142 See Nucor’s Initial Brief at 5; TXU’s Initial Brief at 4. 143 These classes include the residential and secondary less than 10 kilowatt (kW) or kilovolt-ampere (kVA) (less than 5 kW for TNMP and EGSI). PUC Docket No. 22348 Consolidated Interim Order Page 66 SOAH Docket Nos. 473-00-1013

108. The delivery/facilities charge for customers with demand meters should be recovered on a per kilowatt (kW) basis.

109. With respect to the facilities/delivery charge, it is appropriate to use non-coincident peak (NCP) billing determinant for non interval data recorder (IDR) metered customers.

110. For those customers possessing IDR meter capabilities, it is appropriate for the transmission per-kilowatt (kW) rate to be billed according to the Commission’s transmission rule,144 which currently mandates a four coincident peak (4CP) method. In order to track cost causation, it is appropriate to bill the distribution facilities/delivery charge for IDR metered customers based on the NCP billing determinant.

111. For the utilities located within the Electric Reliability Council of Texas (ERCOT) region, it is appropriate to use a 15-minute interval for demand charges in accordance with the ERCOT protocols.

112. For non-ERCOT utilities, it is appropriate that the interval used for the billing of demand charge conform to the protocols and procedures of the regional transmission organization or power pool to which the individual utility belongs.

RATCHETED DEMAND CHARGE

113. A ratcheted demand charge calculates billing demand as the greater of either current monthly demand or a certain percentage of the customer’s maximum demand over a set of previous billing periods.

114. Due to the fixed nature of distribution system costs and the need to build distribution facilities to meet customers’ maximum demands, it is appropriate to apply a ratchet to distribution charges.

115. Although a 100% ratchet reflects the fixed nature of distribution costs, the 80% level appropriately recognizes the load diversity on the distribution system. Therefore, a

144 P.U.C. SUBST. R. 25.192(d) PUC Docket No. 22348 Consolidated Interim Order Page 67 SOAH Docket Nos. 473-00-1013

ratchet of 80% is reasonable for recovery of distribution costs from demand-metered customers.

116. Due to the unique characteristics of seasonal agriculture customers (i.e., highly variable usage patterns within the year), it is appropriate to grant an exception to the establishment of generic ratcheted distribution demand charges for these customers.

BILLING METHOD FOR ERCOT TRANSMISSION CHARGES145

117. In the competitive market, it is reasonable for ERCOT transmission service providers (TSPs) to bill distribution utilities, which would then bill REPs a combined T&D charge. This billing method results in billing and payment relationships that parallel existing relationships. It also respects the right of municipal utilities and electric cooperatives that opt-in to retail competition to bill for T&D delivery service pursuant.

118. The direct-billing method, in which TSPs bill REPs directly for transmission service, would introduce a billing relationship that does not exist today and would result in REPs paying each month over 30 TSPs for transmission service, as well as the local distribution utility for distribution service.

ERCOT FOUR COINCIDENT PEAK (4CP) AND WHOLESALE TRANSMISSION RATES

119. An unopposed Stipulation and Agreement (“4CP Stipulation”) filed by parties in the Generic Proceeding146 proposed: (1) a number for the ERCOT demand to be used in calculating wholesale transmission rates for utilities that are proposing a new transmission rate based on a 2002 test year; (2) a methodology for billing distribution utilities for ERCOT transmission service in 2002; and (3) a methodology for charging for ERCOT transmission service during the pilot.

145 The Commission has jurisdiction over both transmission and distribution rates within the ERCOT region. In areas outside out the ERCOT region, the Commission only has jurisdiction over distribution rates. See Finding of Fact Nos. 184-188 for transmission rate issues regarding non-ERCOT utilities. 146 Docket No. 22344, Forecasted ERCOT 2002 Four Coincident Peak Stipulation and Agreement, (Feb. 21, 2001). PUC Docket No. 22348 Consolidated Interim Order Page 68 SOAH Docket Nos. 473-00-1013

120. The Commission ruled on this issue initially in Order No. 50.

121. In accordance with the 4CP Stipulation, 56,800 megawatts (MW) is a reasonable forecast of the 2002 4CP demand within ERCOT for use in calculating 2002 wholesale transmission rates within ERCOT.

122. For TSPs that have filed a transmission cost of service (TCOS) case using a forecast 2002 test year, it is reasonable to calculate their wholesale transmission service rates by dividing the individual TSP’s Commission-approved TCOS revenue requirement by a forecast of the 2002 ERCOT 4CP demand. In 2002, it is appropriate that such TSPs bill distribution utilities by applying their Commission-approved wholesale transmission service rates to the prior year (2001) ERCOT 4CP billing units. Consistent with the 4CP Stipulation, it is reasonable to determine the rate and 2002 billing for each such TSP according to the methodology below.

Rate Determination

TSP’s TCOS Revenue Requirement (based on test year ended 12/31/02) TSP’s Wholesale Transmission = Service Rate, effective January 1, 2002 56,800 MW

2002 Billing

TSP’s Wholesale Transmission Service Each Distribution Utility’s 2001 X Rate Effective January 1, 2002 Actual ERCOT 4CP

123. Consistent with the 4CP Stipulation, it is reasonable that there be no change in the wholesale transmission rates for ERCOT TSPs that have not filed a TCOS case to PUC Docket No. 22348 Consolidated Interim Order Page 69 SOAH Docket Nos. 473-00-1013

establish new wholesale transmission service rates effective January 1, 2002. It is also appropriate that the wholesale transmission service rates of such TSPs continue to be their existing, Commission-approved rates. In 2002, it is appropriate that these TSPs bill distribution utilities by applying their existing Commission-approved wholesale transmission service rates to the prior year (2001) ERCOT 4CP billing units.

124. It is reasonable to grant a good cause waiver of P.U.C. SUBST. R. 25.431(h) to allow wholesale transmission rates currently in effect in 2002 to remain in effect for billing to the distribution utilities during the pilot program.

125. The 4CP issue relates only to ERCOT transmission rates and has no application to areas outside ERCOT.147

TRANSMISSION COST RECOVERY FACTOR (TCRF)

126. The Commission initially ruled on this issue in Order No. 40.

127. It is appropriate to use a Transmission Cost Recovery Factor (TCRF) to allow distribution utilities to pass through changes in ERCOT wholesale transmission costs, which are approved by the Commission or allowed under the Commission’s transmission pricing rules.148

128. In P.U.C. SUBST. R. 25.193, the Commission established a TCRF mechanism that applies to investor-owned distribution utilities within ERCOT.

ERCOT RETAIL TRANSMISSION CHARGE

129. It is reasonable to design transmission service rates such that costs are allocated among customer classes using consumption information for the distribution utility. The transmission revenue requirement for the distribution utility to be recovered from REPs should be based on the ERCOT transmission pricing system and should be the

147 Order No. 44 (Dec. 21, 2000).

148 P.U.C. SUBST. R. 25.192(g). PUC Docket No. 22348 Consolidated Interim Order Page 70 SOAH Docket Nos. 473-00-1013

distribution utility’s share of the total ERCOT transmission costs based on its load share at the ERCOT system 4CP.

130. The ERCOT Retail Transmission Charge Calculation Stipulation and Agreement filed by certain parties in Docket No. 22344 establishes procedures for calculating retail transmission rates for use by ERCOT distribution utilities in billing REPs during the pilot program and after full competition begins on January 1, 2002.149

131. The Stipulation proposes to: (1) use the TSP’s wholesale transmission rates, in effect on January 1, 2002, to set the distribution utility’s transmission revenue requirement; (2) require the distribution utility to use its 2002 4CP demand from its UCOS case to determine the distribution utility’s retail transmission revenue requirement; (3) use the retail-rate class 2002 4CP allocation factors from the distribution utility’s UCOS case to establish the retail transmission rates; (4) use the 2002 retail billing units from the distribution utility’s UCOS case to determine the retail transmission rates; (5) require the REPs to use specified billing methods for their IDR- and non-IDR-metered customers; and (6) require the REPs to use specified billing methods for transmission voltage retail customers.

132. The ERCOT Retail Transmission Charge Stipulation is consistent with the billing method specified in the Commission’s transmission rules150 and the billing model specified in Order No. 40 in Docket No. 22344.

133. Therefore, it is reasonable to adopt the Stipulation for the purposes of calculating retail transmission rates for use by ERCOT distribution utilities in billing REPs during the pilot program and after full competition begins.

TRANSMISSION RATES FOR NON-ERCOT UTILITIES

134. The Commission ruled on this issue in Order No. 40.

149 Docket No. 22344, ERCOT Retail Transmission Charge Calculation Stipulation and Agreement (Apr. 6, 2001).

150 P.U.C. SUBST. R. 25.192 and 25.202. PUC Docket No. 22348 Consolidated Interim Order Page 71 SOAH Docket Nos. 473-00-1013

135. Under the Federal Power Act (FPA), the Federal Electric Regulatory Commission (FERC) would set the transmission rates for utilities located outside the Electric Reliability Council of Texas (ERCOT) region. There is no dispute as to the FERC’s jurisdiction with respect to non-ERCOT transmission rates.

136. Where a FERC transmission rate for retail-access customers has been set, it is reasonable to employ that rate for non-ERCOT utilities. Where there is no such FERC rate in effect, the implementation of retail access transmission rates for non-ERCOT utilities would require FERC approval.

137. It is therefore appropriate to sever transmission rate issues for non-ERCOT utilities from the affected UCOS cases, which include EGSI,151 SWEPCO,152 and WTU.153

138. Because this is a FERC implementation issue, it is appropriate to resolve this issue by the Commission intervening and participating in the FERC Open Access Transmission Tariff proceedings of the non-ERCOT utilities and/or Southwest Power Pool.154

MISCELLANEOUS T&D RATE DESIGN ISSUES

139. Interruptible and standby services are largely generation-related services. The T&D facilities needed to serve interruptible and standby customers are the same regardless of whether the customer takes firm or non-firm service.

140. There is no need for interruptible T&D rates because interruptible customers will receive value in the generation market for their willingness to curtail load during high-price periods.

151 Application of Entergy Gulf States for Approval of Unbundled Cost of Service Rate Pursuant to PURA §39.201 and Public Utility Commission Substantive Rule 25.344, Docket No. 22356 (pending). 152 Application of Southwestern Electric Power Company for Approval of Unbundled Cost of Service Rate Pursuant to PURA §39.201 and Public Utility Commission Substantive Rule 25.344, Docket No. 22353 (pending). 153 Application of West Texas Utilities Company for Approval of Unbundled Cost of Service Rate Pursuant to PURA §39.201 and Public Utility Commission Substantive Rule 25.344, Docket No. 22354 (pending). 154 Transcript at 49-51 (Mar. 20, 2001). PUC Docket No. 22348 Consolidated Interim Order Page 72 SOAH Docket Nos. 473-00-1013

141. Standby service is different from interruptible service, mainly because this type of load is infrequently on the grid. It is not appropriate for a standby rate for transmission service to be offered by the regulated transmission utility. Such a rate is more appropriately offered in the competitive market.

142. If standby customers do not take transmission service during peak periods, coincident- peak billing for transmission service will recognize the intermittent usage of the transmission system by such customers.

143. The adoption of a generic rate design for lighting is not realistic given the complexity of the topic and differences among service areas. Therefore, it is reasonable to address lighting rate design in the individual UCOS cases.

144. Some utilities have historically billed on a per-kilovolt-ampere (kVA) basis. It is therefore appropriate to continue kVA billing as recognized in the NUA on customer classification.

145. To establish a rate based on the location of a customer in relation to a substation represents a significant departure from longstanding ratemaking principles with respect to the shared costs of the distribution infrastructure. Therefore, a separate rate or adjustment for customers taking service directly out of the substation is not reasonable at this time.

146. Because the standard-power-factor-correction formula is being addressed in Project No. 22187,155 there is no need to consider the issue in this proceeding. d. Exceptions to Generic Rate Design and Customer Classification

147. The Commission initially ruled on these issues in Order No. 40.

155 Terms and Conditions of Transmission and Distribution Utilities' Retail Distribution Service, Project No. 22187. PUC Docket No. 22348 Consolidated Interim Order Page 73 SOAH Docket Nos. 473-00-1013

148. Exceptions to the generic customer classifications described in the NUA, other than that requested by Sharyland, are not appropriate.

149. It is reasonable to consider exceptions to the generic rate design in each utility’s individual UCOS proceeding only if necessary to address extraordinary impacts on the ability of customers to obtain service from a competitive provider due to the restrictions of the price to beat (i.e., “headroom” concerns). Such headroom concerns should not automatically mandate the granting of an exception to the generic rate design.

150. TXU Electric Company’s proposed transformation rate (Rate XFMR) is reasonable for the transmission utility to charge the distribution utility at wholesale. It is appropriate to develop the rate design of such wholesale rate in TXU’s individual UCOS case.156

151. For primary class customers without demand meters, the best solution would be to obtain demand meters. However, it is appropriate to consider an adaptation of the generic rate design to accommodate these customers in each utility’s individual UCOS case. The use of load profiling to accomplish such an adaptation is appropriate because such customers are a small subset of the primary class. e. Other Non-Bypassable Charges

152. PURA § 39.903 established a system benefit fund to be financed by a non-bypassable charge set by the Commission.

153. Consistent with this PURA provision and the UCOS rate-filing package, it is reasonable to assess the system benefit fund fee at $0.50 per MWh to be effective beginning January 1, 2002.

156 Application of TXU Electric Company for Approval of Unbundled Cost of Service Rate Pursuant to PURA §39.201 and Public Utility Commission Substantive Rule 25.344, Docket No. 22350 (pending). PUC Docket No. 22348 Consolidated Interim Order Page 74 SOAH Docket Nos. 473-00-1013 f. Tariffs

154. The July 20, 2001 Order Requesting Number Run required Staff to incorporate the Commission’s decisions made during the May 24, 2001 open meeting and to recalculate revenue requirements to determine new transmission rates.157

155. On August 1, 2001 Staff submitted the updated number runs which have a flow through effect on transmission rates for other ERCOT utilities.

156. The August 1, 2001 updated number runs158 for transmission rates supercede earlier transmission rate determinations.

157. These number runs affect Sharyland to the extent that pursuant to the Settlement in the instant case, Sharyland’s residential rates are capped at CPL’s residential rates, which were determined in the updated number runs.

3. Other Generic Issues a. Targeted Incentive Plan (TIP)

158. The TIP was first raised under Category “B” issues and the Commission made its initial ruling on the TIP in Order No. 17.159

159. At the June 29, 2000 open meeting discussion on the TIP, the Commission instructed parties to seek consensus on the issue of an incentive plan that would be tied to the return on equity.

157 See Open Meeting Tr. at 219 (May 24, 2001) requiring Reliant’s final transmission rates to account for and correct consolidated tax, amortization expense, and depreciation. See Open Meeting Tr. at 225 (May 24, 2001) requiring TXU Electric’s final transmission rates to account for and correct the pension fund over-funding and future excess earnings of TXU SESCO. 158 Commission Staff’s Updated Number Run (August 2, 2001). 159 Order No. 17 at 13. PUC Docket No. 22348 Consolidated Interim Order Page 75 SOAH Docket Nos. 473-00-1013

160. The Commission Staff filed several versions of the TIP proposal; subsequently, various parties filed comments. Finally, the parties were unable to reach an agreement on the TIP.

161. Therefore, a generic, targeted incentive plan is not appropriate at this time. b. Pilot Project

162. It is appropriate that wholesale transmission service rates currently in effect in 2001 remain the same for billing to the distribution utilities during the pilot projects.

163. A good cause waiver of P.U.C. SUBST. R. 25.431(h) is reasonable so that wholesale transmission service rates currently in effect in ERCOT in 2001 may remain in effect for billing to utilities during pilot projects.

B. Code of Conduct, Business Separation Plan, Transmission and Distribution

1. Procedural History

1. On March 31, 2000, Sharyland filed an application for approval of unbundled cost of

service rates pursuant to PURA § 39.201 and P.U.C. SUBST. R. 25.344.

2. On May 1, 2000, Sharyland filed a supplemental application that contained certain information that was unavailable at the time of its initially-filed application, including its proposed rate schedules.

3. Sharyland is a retail electric utility that commenced service in mid-February, 2000, pursuant to Certificate of Convenience and Necessity (CCN) No. 30192 granted by the Public Utility Commission of Texas (Commission) in Docket No. 20292.160

160 Application of Sharyland Utilities, L.P. for a Certificate of Convenience and Necessity in Hildalgo County, Texas, Docket No. 20292, Order (July 9, 1999). PUC Docket No. 22348 Consolidated Interim Order Page 76 SOAH Docket Nos. 473-00-1013

4. On April 3, 2000, the Commission referred this proceeding to the State Office of Administrative Hearings (SOAH) for purposes of conducting a hearing on the merits and issuing a proposal for decision.

5. Motions to intervene in this proceeding were filed by TXU Electric Company (TXU), the National Association of Energy Service Companies (NAESCO), and the Office of Public Utility Counsel (OPC). The motions were granted without opposition on May 31, 2000.

6. On June 7, 2000, the Commission issued a Preliminary Order in this case. The Preliminary Order provided, inter alia, that threshold issues addressed in Docket No. 22344161 would not be addressed in the instant proceeding.

7. On June 27, 2000, a partial waiver of the notice requirements was granted. Sharyland was authorized to publish notice of its application once each week for four non- consecutive weeks in The Monitor, a newspaper of general circulation in Hildalgo County. Sharyland also provided written notice to the Cities of McAllen and Mission. On July 14, 2000, Sharyland filed its affidavit evidencing completion of notice.

8. On August 25, 2000, the Commission issued Order No. 25 in Docket No. 22344, which exempted Sharyland from the application of the generic operations and maintenance (O&M) escalator factors.

9. On September 22, 2000, the Commission issued Order No. 28 in Docket No. 22344, which provided that determination of Sharyland’s rate of return and capital structure would not be decided in the generic proceeding but instead would be determined in the instant proceeding.

10. On November 22, 2000, the Commission issued Order No. 40 in Docket No. 22344, which provided an exemption to Sharyland regarding customer classification/rate design

161 Generic Issues Associated with Applications for Approval of Unbundled Cost of Service Rate Pursuant to PURA § 39.201 and Public Utility Commission Substantive Rule 25.344 (pending). PUC Docket No. 22348 Consolidated Interim Order Page 77 SOAH Docket Nos. 473-00-1013

determinations in the generic proceeding to instead be determined in the instant proceeding.

11. On February 5, 2001, Sharyland and the Commission Staff reached an agreement in principle to resolve all issues in this proceeding.

12. On February 7, 2001, the procedural schedule was suspended and a deadline of March 2, 2001, was established for Sharyland to submit a stipulation and agreement, including proposed findings of fact and conclusions of law.

13. On March 2, 2001, Sharyland and the Commission Staff (Settling Parties) executed and filed a Stipulation and Agreement of Settlement (Settlement) proposing to resolve all issues in this proceeding. The Settling Parties authorized and stated that OPC, TXU, and NAESCO did not oppose the Settlement.

14. On March 16, 2001, SOAH returned this proceeding to the Commission and established an evidentiary record for purposes of entering an interim order because no issue was raised by any party that required an evidentiary hearing on the merits.

14A. On June 4, 2001, the Commission issued an Interim Order–Rate Phase, in which it approved Sharyland’s application for approval of unbundled cost of service rates.

14B. On June 14, 2001, Sharyland filed its Motion of Sharyland Utilities, L.P. for Modification or, in the alternative, Reconsideration of Interim Order-Rate Phase, in which it requested that the time requirement for filing its compliance tariff for its transmission and distribution rates be changed from “no later than 30 days after the effective date of the Interim Order” to “no later than 20 days after Central Power and Light Company’s T & D tariff for January 1, 2002, is approved in Docket No. 22352.” On June 19, 2001, in a supplement to its motion for modification/reconsideration, Sharyland noted that Commission Staff concurred in its requested change. PUC Docket No. 22348 Consolidated Interim Order Page 78 SOAH Docket Nos. 473-00-1013

14C. On July 20, 2001, the Commission issued a Revised Interim Order–Rate Phase, in which it approved the change requested by Sharyland in Sharyland’s motion for reconsideration/modification to the Interim Order–Rate Phase.

2. Settlement

15. The Settling Parties desire to compromise and settle the issues raised by the Commission’s Preliminary Order to avoid the unnecessary burden and delay, as well as the expense and uncertainty, associated with possible appeal from the ultimate decision on the issues raised and litigated.

16. The Settling Parties have, through various compromises, achieved a reasonable resolution of all of the issues in this proceeding that is particularly appropriate for a start-up utility such as Sharyland.

17. The Settlement generally provides that:

 Sharyland’s unbundled transmission and distribution rates and tariff are approved as filed.

 Sharyland’s authorized overall rate of return shall be 10.84%, consisting of a cost of debt of 8.5% and a return on equity of 12.75%.

 Sharyland’s capital structure for ratemaking purposes shall be 55% equity and 45% debt.

 Sharyland shall incorporate a revised Paragraph F, attached to this Order as Appendix A, into its Code of Conduct.

 Except as specifically provided otherwise in the Settlement, the Stipulation and Agreement approved by the Commission in Sharyland’s initial rate case, Docket No. 21591,162 shall remain in full force and effect, including Sharyland’s commitment to file a new rate case by May 1, 2003.

162 Application of Sharyland Utilities, L.P. for Authority to Establish Initial Rates and Tariff, Docket No. 21591 (July 26, 2000). PUC Docket No. 22348 Consolidated Interim Order Page 79 SOAH Docket Nos. 473-00-1013

18. Sharyland is a start-up utility that commenced operations in mid-February, 2000, and therefore does not have operating experience upon which to provide historical test year information as the basis for a forecast test year in this proceeding.

19. Sharyland’s proposed use of operational forecasts in lieu of a historical test year provides a reasonable basis for its forecasted test in this proceeding. Future rate cases can be based upon historical test year information.

20. Sharyland’s proposed cost of transmission and distribution service is reasonable and properly calculated pursuant to the Unbundled Cost of Service Rate-Filing Package.

21. Sharyland’s proposed transmission cost of service of $1,119,945 is reasonable.

22. The appropriate and reasonable overall rate of return for Sharyland is 10.84%, consisting of a cost of debt of 8.5% and a return on equity of 12.75%.

23. Sharyland’s overall rate of return of 10.84%, consisting of a cost of debt of 8.5% and a return on equity of 12.75%, is reasonable and appropriate, considering its unique circumstances.

24. Sharyland’s proposed capital structure of 55% equity and 45% debt appropriately reflects the proper consideration of loans to the Sharyland limited partnership.

25. Because of Sharyland’s unique circumstances as a start-up electric utility serving a small number of customers in a developing 6000 acre service area, Sharyland is entitled to a higher than average return on equity.

26. Costs have been appropriately assigned to Sharyland and its affiliates. Sharyland has met the standard of recovery for affiliate costs.

27. Sharyland is a limited partnership, and, therefore, a consolidated tax return would not be appropriate. Accordingly, Sharyland’s income tax expense need not reflect consolidated tax savings. PUC Docket No. 22348 Consolidated Interim Order Page 80 SOAH Docket Nos. 473-00-1013

28. Sharyland’s class allocation of costs is reasonable. Sharyland has no non-jurisdictional costs.

29. Sharyland’s proposed forecasted billing determinants are reasonable.

30. Sharyland’s proposed design for transmission and distribution rates is reasonable.

31. Sharyland’s proposed rates are no higher than those of neighboring utilities for comparable services.

32. Sharyland’s proposed transmission and distribution rates are reasonable.

33. Sharyland has identified all corporate support services to be used by it as a transmission and distribution utility.

34. To the extent that Sharyland has proposed sharing of information, employees, facilities or other resources, it has demonstrated that such sharing will not compromise the public interest.

35. To the extent that Sharyland has proposed sharing of officers and directors, property, equipment, computer systems, information systems, and corporate support services, it has demonstrated that adequate safeguards have been put in place to prevent circumvention of the code of conduct.

36. Sharyland has instituted adequate employee training and compliance programs.

37. Sharyland’s January 31, 2001, proposed Energy Efficiency Action Plan is reasonable.

38. Sharyland’s proposed Wholesale Transmission Tariff is just and reasonable.

39. Sharyland’s proposal to collect the applicable Commission-approved system benefit fee, when determined, for 2002 and subsequent years is reasonable. Sharyland has no nuclear decommissioning costs or competition transition charges. PUC Docket No. 22348 Consolidated Interim Order Page 81 SOAH Docket Nos. 473-00-1013

3. Informal Disposition

40. More than 15 days have passed since completion of notice provided in this docket.

41. No issues of fact or law are disputed by any party; therefore, no hearing is necessary.

IV. CONCLUSIONS OF LAW

A. General

1. The Commission has jurisdiction over Sharyland (or the “Company”), the company’s application, and over all the proceedings in this docket and in the related Docket No. 22344, pursuant to PURA §§ 14.001, 32.001, and 39.001-39.909.

2. The State Office of Administrative Hearings (SOAH) has jurisdiction over all matters relating to the hearing in this case as well as in Docket No. 22344, including the preparation of the various proposals for decision pursuant to PURA §14.053 and

TEX.GOV’T CODE ANN. §2003.049(b) (Vernon 2000 & Supp. 2001).

3. Sharyland is an electric utility as that term is defined in PURA §31.002(6) because it owns and operated for compensation in Texas equipment and facilities to produce, generate, transmit, distribute, sell, or furnish electricity in this state. Sharyland is an integrated investor-owned utility providing electric service in Texas within the Electric Reliability Council of Texas (ERCOT).

4. Appropriate notice of this application and hearing, as well as the proceedings in Docket No. 22344, was provided in compliance with Administrative Procedure Act163, PURA

§ 36.103, and P.U.C. PROC. R. 22.55.

163 TEX.GOV’T.CODE ANN. §§ 2001.051 & 2001.052 (Vernon 2000 & Supp. 2001)(APA) PUC Docket No. 22348 Consolidated Interim Order Page 82 SOAH Docket Nos. 473-00-1013

5. The Commission conducted this docket in accordance with the requirements of the Administrative Procedure Act and with the provisions of PURA.

B. Generic Proceeding

1. Procedural History

1. The PURA § 39.201 requires each electric utility to file proposed tariffs for its proposed transmission and distribution utility on or before April 1, 2000.

2. The Generic Proceeding and the merger of other dockets into the Generic Proceeding were necessary and proper methods for addressing issues arising from deregulation that were similar in each of the utilities’ UCOS proceedings filed pursuant to PURA § 39.201. Use of the Generic Proceeding allowed the Commission to address such issues in a timely manner insure consistent treatment of such issues in each UCOS case. Failure to decide such issues generically would have resulted in significant delays and would have prevented the setting of rates for use in the competitive market.

3. Notice of the Generic Proceeding was reasonable and sufficient and was provided in

compliance with the APA and P.U.C. PROC. R. 22.55.

4. The Commission’s decision to group portions of the generic issues and address them separately was done for reasons of procedural and administrative efficiency and did not affect the substantive rights of the parties.

2. Transmission and Distribution (T&D) Rates a. T&D Cost of Service

5. PURA § 39.201(b)(1) requires that rates be established for transmission and distribution utilities based upon a forecasted 2002 test year. PUC Docket No. 22348 Consolidated Interim Order Page 83 SOAH Docket Nos. 473-00-1013

6. Any expenses or costs recoverable through T&D rates in the 2002 forecasted test year must be demonstrably related to the T&D function. This requirement is consistent with the provisions of PURA Chapter 39 requiring business separation and with the Commission’s mandate to establish T&D rates pursuant to PURA § 39.201. Recoverable costs are appropriately allocated to the transmission or distribution functions, in the company-specific UCOS proceedings.

7. T&D related annual expenses that are reasonable and necessary and are expected to be incurred in the 2002 forecasted test year are recoverable in the T&D rates that will be effective January 1, 2002. T&D related expenses incurred prior to January 2002 cannot be recovered in the T&D rates that are effective January 1, 2002.

8. T&D related capital expenditures and associated depreciation, including restructuring costs, for plant that is reasonably expected to be used and useful by December 31, 2002 are recoverable in the T&D rates that will be effective January 1, 2002.

9. Rate case expenses related to the T&D function and determined reasonable and necessary, including those incurred prior to January 2002, are recoverable and may be amortized over an appropriate time period to mitigate rate impact. This is consistent with Commission precedent, as just and reasonable rate case litigation expenses have traditionally been allowed pursuant to PURA § 36.061(b)(2).164

10. T&D-related restructuring costs for capital expenditures and associated depreciation, as well as annual expenses, should generally be treated according to traditional rate-making principles and the provisions of PURA § 36.051. T&D restructuring expenses that are determined reasonable and necessary and are expected to be incurred in the 2002 forecasted test year may be included in the T&D rates. Where appropriate, extraordinary expenses may be amortized over an appropriate time period, to mitigate rate impact. Restructuring expenses incurred prior to the 2002 forecasted test year are eligible to be

164 Application of Texas-New Mexico Power Company for Authority to Change Rates and Petition of Texas- New Mexico Power Company for Deferred Accounting Treatment for TNP One-Unit Two, Docket Nos. 10200 and 10034, Examiners’ Report, 19 P.U.C. Bull. 89, 269 (Mar. 18, 1993). PUC Docket No. 22348 Consolidated Interim Order Page 84 SOAH Docket Nos. 473-00-1013

requested in the annual report process. Debt restructuring expenses are unique, and the recovery of such expenses should not exceed the proportionate share of T&D assets expressed as a percentage of total assets prior to business separation on a net book value basis.

11. Energy efficiency costs that are recurring, are incurred in the 2002 forecasted test year, and comply with the energy efficiency rule165 are recoverable in T&D rates. Energy efficiency costs incurred prior to the 2002 forecasted test year are eligible to be requested in the annual report process.

12. The costs of the pilot project are not recoverable in the T&D rates established pursuant to PURA § 39.201 because they are not related to the provision of T&D service after January 1, 2002 and will not be incurred during the 2002 forecasted test year. Pilot project expenses incurred prior to the 2002 forecasted test year are eligible to be requested in the annual report process.

13. Capital investment costs for the T&D functions in the 2002 forecasted test year are most appropriately addressed in the individual UCOS dockets.

14. PURA § 36.051 applies to this proceeding and requires application of the used and useful standard in determining the T&D rates that will be effective January 1, 2002.

15. There is no conflict between § 36.051 and § 39.201 because the 2002 T&D rates can be based on the cost of T&D plant that is reasonably expected to be used and useful, and T&D expenses that are reasonable and necessary, in the 2002 forecasted year.

16. Costs and expenses that are demonstrably related to the T&D function are recoverable through T&D rates that will be effective January 1, 2002.

165 P.U.C. SUBST. R. 25.181. PUC Docket No. 22348 Consolidated Interim Order Page 85 SOAH Docket Nos. 473-00-1013

GENERIC ESCALATION FACTORS FOR O&M EXPENSES

17. Application of escalation factors, adjusted to reflect productivity gains, to historic test- year operation and maintenance costs and the recognition of pro forma adjustments to account for new O&M expense attributed to restructuring, allows the utility to collect its just and reasonable O&M expense and complies with § 36.051 and § 36.201(b) of PURA.

18. Benchmarked growth rates are generic to all utilities.

19. O&M expenses for the 2002 forecasted test year are appropriately determined by the application of generic escalation factors.

20. Demand-side management (energy efficiency) expenses and transmission access charges are “new” O&M expenses of the transmission and distribution utility. Consequently, these expenses may be included in the 2002 forecast test year to the extent they are found to be reasonable and necessary in the company specific dockets.

21. New SB 7 mandated corporate restructuring expenses may be included in the 2002 forecast test year, subject to reasonable and necessary review in the company specific dockets. Expenses that are properly functionalized in the 1999 historic test year and subsequently escalated, are not “new” SB 7 expenses.

22. The UCOS Rate Filing Package (RFP) methodology for determining O&M expenses in the 2002 forecast test year is appropriate.

RETURN ON EQUITY AND CAPITAL STRUCTURE

23. A generic targeted incentive plan (TIP) plan is not appropriate at this time. Neither a TIP nor performance based ratemaking plan, proposed by some utilities in their original unbundled cost of service (UCOS) filings, should be considered in the individual UCOS cases. PUC Docket No. 22348 Consolidated Interim Order Page 86 SOAH Docket Nos. 473-00-1013

24. It is appropriate to recognize the reduction in risk resulting from both the guarantee of stranded cost recovery by the Legislature and the shortened recovery term compared with traditional regulation. These factors should be reflected in a lowered rate of return for the utility.166

25. A uniform ROE and capital structure for all TDU’s in Texas, with the exception of Sharyland, is appropriate.

26. Given its unique characteristics, the ROE for Sharyland should be established in its UCOS case.

27. A capital structure of 60 percent debt and 40 percent equity and a return on equity of 11.25% is just and reasonable and complies with § 36.051 and § 36.052 of PURA. b. Uniform Customer Classification

28. It is reasonable and appropriate to adopt the uniform customer classification scheme set forth in Findings of Fact 140 to 148, for each utility except Sharyland.

29. To recognize its unique characteristics, it is reasonable and appropriate to grant Sharyland an exemption from certain of the classifications. All of Sharyland’s customers are equipped with interval data recorder (IDR) meters, obviating the need for classes to accommodate non-demand-metered customers. Therefore, to the extent that such classes are unnecessary for Sharyland, a modified version of the NUA classes for Sharyland should be addressed in its individual UCOS case. Additionally, Sharyland’s classifications should mirror those in the NUA for demand-metered classes.

30. The Commission finds that exceptions to the generic customer classifications described in the NUA, other than that requested by Sharyland, are inappropriate and are hereby denied.

166 See, e.g., Application of Central Power and Light Company to Revise Rates, Docket No. 14965, Second Order on Rehearing (Oct. 16, 1997). PUC Docket No. 22348 Consolidated Interim Order Page 87 SOAH Docket Nos. 473-00-1013 c. Generic T&D Rate Design

31. The primary principles to be considered in the design of transmission and distribution rates are cost causation, simplicity, and equity to customers within the given rate classes.

32. A uniform rate design for T&D rates is appropriate, and therefore, shall be adopted by transmission and distribution utilities.

CUSTOMER CHARGE

33. The adoption of a uniform rate design that includes a customer charge is appropriate.

DELIVERY/FACILITY CHARGES

34. The method established for the recovery of a facilities/delivery charge from each customer class appropriately reflects the best-available metering data from each class, is a reasonable proxy for cost causation, and maintains continuity with past rate design methodology.

RATCHETED DEMAND CHARGE

35. A demand ratchet of 80% is reasonable for recovery of distribution costs from demand- metered customers. It is appropriate to grant an exception for seasonal agricultural customers.

BILLING METHOD FOR ERCOT TRANSMISSION CHARGES

36. ERCOT TSPs should bill transmission and distribution utilities, which should then bill REPs a combined transmission and distribution charge.

ERCOT FOUR COINCIDENT PEAK (4CP) AND WHOLESALE TRANSMISSION RATES

37. The stipulation referenced in Findings of Fact 169 to 175 is reasonable and is in the public interest. PUC Docket No. 22348 Consolidated Interim Order Page 88 SOAH Docket Nos. 473-00-1013

TRANSMISSION COST RECOVERY FACTOR (TCRF)

38. The use of a TCRF is an appropriate method to allow distribution utilities to pass through changes in ERCOT wholesale transmission costs.

ERCOT RETAIL TRANSMISSION CHARGE

39. The stipulation referenced in Findings of Fact 179 to 183 is reasonable and in the public interest.

TRANSMISSION RATES FOR NON-ERCOT UTILITIES

40. Under the Federal Power Act (FPA), the Federal Energy Regulatory Commission (FERC) has exclusive jurisdiction to establish unbundled retail transmission service rates for non- ERCOT utilities.

MISCELLANEOUS T&D RATE DESIGN ISSUES

41. Lighting rate design is addressed in the company-specific UCOS cases because of the complexity of lighting rate design, as well as the variance in lighting tariffs among utilities.

42. Interruptible T&D rates are not appropriate.

43. Standby service is qualitatively different from interruptible service and a standby T&D rate may be appropriate.

44. A standby rate for transmission service to be offered by the regulated transmission utility is not appropriate.

45. A separate rate or adjustment for customers taking service directly out of the substation is not warranted. PUC Docket No. 22348 Consolidated Interim Order Page 89 SOAH Docket Nos. 473-00-1013 d. Exceptions to Generic Rate Design and Customer Classification

46. Except as described therein, exceptions to the generic customer classifications described in Finding of Fact are not appropriate.

47. Primary class customers without demand meters are a small subset of the primary class and as such, within the narrow confines of this group of customers, use of load profiling to accomplish such an adaptation is appropriate. e. Other Non-Bypassable Charges

48. Establishing a system benefit fund fee of $0.50/mwh to be effective beginning January 1, 2002 complies with PURA § 39.903.

3. Other Generic Issues a. Targeted Incentive Plan (TIP)

49. The generic TIP proposed in this proceeding is unreasonable and inconsistent with traditional ratemaking principles regarding the establishment of a utility’s return on equity. To the extent that a utility proposed a TIP or a performance based ratemaking plan in their original UCOS filing, it will not be considered in setting the utility’s return on equity. b. Pilot Project

50. A good cause waiver of P.U.C. SUBST. R. 25.431(h) is reasonable so that wholesale transmission service rates currently in effect in ERCOT in 2001 may remain in effect for billing to utilities during pilot projects. PUC Docket No. 22348 Consolidated Interim Order Page 90 SOAH Docket Nos. 473-00-1013

C. Code of Conduct, Business Separation Plan, Transmission and Distribution

1. Sharyland is a public utility as that term is defined in § 11.004 of the Public Utility

Regulatory Act, TEX. UTIL. CODE ANN. §§ 11.001-64.158 (Vernon 1998 & Supp. 2001) (PURA) and an electric utility as that term is defined in § 31.002(6) of PURA.

2. The Commission has jurisdiction in this proceeding pursuant to PURA §§ 14.001, 32.001, 36.001, and 39.201.

3. Sharyland’s provision of notice in this docket complied with P.U.C. PROC. R. 22.55.

4. Sharyland’s proposed transmission and distribution rates and tariff comply with PURA § 39.201 and all applicable Commission rules and precedent and are just and reasonable.

5. Sharyland’s proposed code of conduct, as amended with the revised Paragraph F, attached to this Order as Appendix A, is reasonable and complies with all applicable provisions of PURA and Commission regulations.

6. Sharyland has fully complied with the provisions of PURA § 39.051 and P.U.C. SUBST. R. 25.341-25.343 and 25.346.

7. Sharyland is a start-up utility that commenced operations in mid-February, 2000; therefore, Sharyland does not have operating experience upon which to provide the

historical test year information required by P.U.C. SUBST. R. 25.344(d) as the basis for a forecast test year in this proceeding.

8. Sharyland’s proposed use of operational forecasts in lieu of a historical test year provides a reasonable basis for Sharyland’s forecasted test year in this case. Future rate cases shall be based upon historical test year information as required by P.U.C. SUBST. R. 25.344(d). PUC Docket No. 22348 Consolidated Interim Order Page 91 SOAH Docket Nos. 473-00-1013

9. Good cause exists for the Commission to waive the P.U.C. SUBST. R. 25.344(d) requirement that historical test year information be used as the basis for a forecast test year in this proceeding.

10. Sharyland’s January 31, 2001, proposed Energy Efficiency Action Plan complies with applicable Commission regulations.

11. Sharyland’s proposed Wholesale Transmission Tariff complies with all applicable Commission regulations.

12. Costs are appropriately assigned to Sharyland and its affiliates. Sharyland has met the

standard of recovery for affiliate costs in P.U.C. SUBST. R. 25.344(g)(1) and PURA § 36.058.

13. Sharyland’s class allocation of costs complies with P.U.C. SUBST. R. 25.344(h) and PURA § 36.003(b).

14. The proposed interim and permanent codes of conduct for Sharyland meet the

requirements of PURA § 39.157 and P.U.C. SUBST. R. 25.272.

15. Sharyland does not propose to offer any products or services to any third party without

the use of a tariff in accordance with P.U.C. SUBST. R. 25.272(e)(1)(A).

16. With respect to Sharyland, meter reading is not a competitive energy service within the

meaning of P.U.C. SUBST. R. 25.341(6).

17. Given that Sharyland does not have historical operational data, good cause exists for the

Commission to grant an exception from the P.U.C. SUBST. R. 25.344(d) requirement that Sharyland provide the historical test year information as the basis for a forecast test year in this proceeding.

18. Sharyland’s proposed allocation of nonbypassable charges complies with the applicable provisions of PURA and the Commission’s regulations. PUC Docket No. 22348 Consolidated Interim Order Page 92 SOAH Docket Nos. 473-00-1013

19. Sharyland’s application was processed in accordance with the requirements of PURA and

the Administrative Procedure Act, TEX. GOV’T CODE ANN. §§ 2001.001-.902 (Vernon 2000 & Supp. 2001) (APA).

V. ORDERING PARAGRAPHS

A. Generic Ordering Paragraphs

1. The natural gas prices, as listed in Attachment JAC-2 of the Direct Testimony of Commission Staff witness Andy Curtis, shall be used in determining the market price of power for inclusion in the ECOM model. The market prices listed in Attachment JAC-3 of the Direct Testimony of Staff witness Andy Curtis, which result from the approved natural gas prices proposed by Staff, shall be used as inputs into the ECOM model.

2. Investment tax credits shall be included in the ECOM calculation. Commission staff shall and other interested parties may participate in drafting any request to the Internal Revenue Service for a ruling on this issue.

3. The generic customer classifications described in the Findings of Fact shall be used in the individual UCOS cases.

4. With respect to a facilities/delivery charge, the NCP billing determinant shall be used for non-IDR metered customers. For those possessing IDR meter capabilities, the transmission per-kilowatt (kW) rate shall be billed according to the Commission’s relevant transmission rule, which currently mandates a four coincident peak (4CP) method.167

5. The distribution facilities/delivery charge for IDR metered customers shall be billed on the NCP billing determinant. The interval for billing of demand charges shall be that

167 See P.U.C. SUBST. R. 25.192(c). PUC Docket No. 22348 Consolidated Interim Order Page 93 SOAH Docket Nos. 473-00-1013

interval which conforms to the protocols of the reliability council, power pool, or independent organization to which each utility belongs. Facilities/delivery charges shall be recovered on a per-kWh basis for residential and small commercial customers that do not have demand meters.

6. The Commission acknowledges the unique characteristics of seasonal agricultural customers, and grants an exception to the establishment of generic ratcheted distribution demand charges for these customers; the design for each customer class that includes seasonal agricultural customers shall contain a provision for the recovery of distribution charges without the use of demand ratchet for those customers.

7. Transmission cost recovery for non-ERCOT utilities shall be consistent with the FERC Open Access Transmission Tariff.

8. Demand in the amount of 56,800 megawatts (MW) shall be used as the forecasted 2002 four-coincident-peak (4CP) demand within the Electric Reliability Council of Texas (ERCOT) system for the purpose of calculating wholesale transmission rates for 2002

within ERCOT. A good-cause waiver of P.U.C. SUBST. R. 25.431(h) is granted whereby wholesale transmission service rates currently in effect in ERCOT in 2001 may remain in effect for billing to utilities during the pilot projects.

9. A generic rate design shall be adopted by transmission and distribution utilities.

10. The customer charge shall be comprised of costs that vary by customer such as metering, billing and customer service. Additionally, the metering portion of such charges, at a wholesale level, shall be separately stated.

11. A customer charge shall be comprised of costs that vary by customer such as metering, billing and customer service. The metering portion of such charges, at a wholesale level, shall be separately stated. PUC Docket No. 22348 Consolidated Interim Order Page 94 SOAH Docket Nos. 473-00-1013

12. Where a FERC transmission rate for retail-access customers has been set, the Commission will employ that rate. Where there is no such FERC rate in effect, a rate will be calculated in the company-specific UCOS dockets. The Commission will use the FERC wholesale rate, and, through its rate design, convert that wholesale rate to the retail transmission rate to be used in this proceeding. Where the customer is demand metered, the wholesale, per kW rate should be used. Otherwise, the Commission will utilize the wholesale rate in place today in the open access tariffs and set rates for retail-access customers, based on the rate design adopted for residential and commercial customers.

13. Sharyland’s transmission rates shall be consistent with the August 2, 2001 Updated Number Run.

B. Code of Conduct, Business Separation Plan, Transmission and Distribution

1. Sharyland’s application, consistent with the Settling Parties’ Settlement, is approved.

2. Sharyland’s revised Paragraph F, attached to this Order as Appendix A, is approved.

3. Sharyland shall file its compliance tariff for transmission and distribution electric service

in accordance with this Order and in conformance with the requirements of P.U.C. SUBST. R. 25.214 not later than 20 days following the date on which Central Power and Light Company’s transmission and distribution tariff for January 1, 2002, is approved in Docket No. 22352. Sharyland’s filing shall be styled Sharyland Utilities, L.P. Tariff for Transmission and Distribution Electric Service in Compliance with Docket No. 22348, Tariff Control No. 23919.

4. The entry of an order consistent with the Settling Parties’ Settlement does not indicate the Commission’s endorsement or approval of any principle or methodology that may underlie the Settlement and may not be regarded as a binding holding or precedent as to the appropriateness of any principle that may underlie the Settlement. PUC Docket No. 22348 Consolidated Interim Order Page 95 SOAH Docket Nos. 473-00-1013

5. All motions, applications, and requests for entry of specific findings of fact and conclusions of law, and other requests for relief, general and specific, if not expressly granted herein are denied for want of merit. PUC Docket No. 22348 Consolidated Interim Order Page 96 SOAH Docket Nos. 473-00-1013

SIGNED AT AUSTIN, TEXAS the ______day of ______2001.

PUBLIC UTILITY COMMISSION OF TEXAS

MAX YZAGUIRRE, CHAIRMAN

BRETT A. PERLMAN, COMMISSIONER

REBECCA KLEIN, COMMISSIONER

D:\Docs\2017-12-12\054ece469852b3517a4f58df969ebfe6.doc 8/24/2001 03:46:00 AM PUC Docket No. 22348 Consolidated Interim Order Page 97 SOAH Docket Nos. 473-00-1013

APPENDIX A: CODE OF CONDUCT – REVISED PARAGRAPH F

F. Sharing of Officers and Directors, Property, Equipment, Computer Systems, Information Systems and Corporate Support Services.

1. Sharyland and a competitive affiliate may share common officers and directors, property, equipment, computer systems, information systems, and corporate support services. Sharyland will implement the following safeguards to preclude employees of a competitive affiliate from gaining access to information in a manner that would allow or provide a means to transfer confidential information from Sharyland to an affiliate, create an opportunity for preferential treatment or unfair competitive advantage, lead to customer confusion, or create significant opportunities for cross-subsidization of affiliates.

2. Sharyland’s Affiliate Compliance Officer (“ACO”) shall be responsible for compliance with the procedures in this paragraph F.

3. Shared Officers and Directors are those individuals who are officers and directors of both Sharyland and a Sharyland competitive affiliate.

4. Shared Officers and Directors shall not provide confidential utility information to officers, directors or employees of a Sharyland competitive affiliate.

5. Shared Officers and Directors will not, with the intent of giving the competitive affiliate an unfair advantage, participate in decisions as a competitive affiliate officer or director, or attempt to influence the decisions of other competitive affiliate officers and directors, while relying on confidential utility information.

6. During Sharyland and Sharyland competitive affiliate board of directors meetings, Shared Officers and Directors shall not disclose to competitive affiliate employees or officers or PUC Docket No. 22348 Consolidated Interim Order Page 98 SOAH Docket Nos. 473-00-1013

directors who are not shared with Sharyland any confidential utility information. A Shared Officer or Director attending such a board meeting will review the agenda to identify any agenda items that present the opportunity for such disclosure and will communicate his or her concern to the appropriate meeting participants to ensure that an appropriate disclosure does not occur.

7. The Sharyland Affiliate Compliance Officer shall maintain a current list of Shared Officers and Directors.

8. Annually, Shared Officers and Directors shall sign a statement that they understand and abide by the information-sharing provisions contained in Sharyland’s Code of Conduct.

9. Subject to these safeguards, Sharyland and Sharyland competitive affiliates may share common officers and directors, property, equipment, computer systems, information systems, and corporate support services. ATTACHMENT: TRANSMISSION RATE DESIGN SCHEDULES, EXCERPT OF AUGUST 1, 2000 FILING

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