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HomeMy WebLinkAboutItem 08 - TXU Gas Distribution Rate Case and Public HearingITEM MEMO TO: HONORABLE MAYOR AND MEMBERS OF THE CITY COUNCIL FROM: ROGER NELSON, CITY MANAGER MEETING DATE: JUNE 18, 2002 SUBJECT: TXU GAS DISTRIBUTION RATE CASE AND PUBLIC HEARING RECOMMENDATION: City Council to conduct a public hearing and consider an ordinance to deny the request to change rates in the North Texas Distribution System, and take any necessary action. FUNDING SOURCE: TXU Gas Distribution will reimburse the City of Grapevine (and all Steering Committee Cities) for expenses related to the consultant's review of the Statement of Intent on rate changes. The City will continue to receive franchise fees per franchise agreement. BACKGROUND: In March, TXU Gas Distribution filed a request to increase rates effective April 5, 2002. The City passed a resolution suspending the effective date for 90 days and authorized participation with other Cities in a review of the reasonableness of the company's request. The Coalition of Cities reviewing TXU's request hired legal counsel, Geoffrey Gay (Lloyd, Gosselink, Blevins, Rochelle, Baldwin & Townsend) and Diversified Utilities, rate consultants (DUCT). The consultant's report, which was finalized in late May, included recommendations against the rate increase and provided for a slight reduction in rates. Given the fact that the cities must take action before the suspension period is over (July V), Geoffrey Gay and the DUCI have recommended, at this point, the cities deny the rate increase. The consultants are attempting to negotiate a compromise rate adjustment with TXU—as we have done in the past filings. Approval of the ordinance will enable the City of Grapevine to comply with the suspension deadline while awaiting additional information from the consultants. It should be noted that this rate filing involves approximately 107 municipal jurisdictions, each with different existing rate structures. The Company is continuing its efforts to consolidate all of the old Lone Star distribution systems into six or seven regional distribution systems. This filing is a major step in creating one large Dallas -Ft. Worth Metroplex Regional Distribution System. June 12, 2002 (11:19AM) The recommendation letter from Geoffrey Gay and the DUCI report are included for your review. The Utilities Committee, the City Attorney and Staff have reviewed the TXU Gas Distribution Rates and recommend approval of this ordinance. myl June 12, 2002 (10:09AM) ORDINANCE NO. AN ORDINANCE OF THE CITY COUNCIL OF THE CITY OF GRAPEVINE, TEXAS DENYING TXU GAS DISTRIBUTION'S REQUEST TO CHANGE RATES IN THE NORTH TEXAS METROPLEX DISTRIBUTION SYSTEM; REQUIRING PROMPT REIMBURSEMENT OF CITIES' RATE CASE EXPENSES, PROVIDING A SEVERABILITY CLAUSE AND PROVIDING AN EFFECTIVE DATE WHEREAS, on or about March 1, 2002, TXU Gas Distribution, a division of TXU Gas Company filed with the City of Grapevine a Statement of Intent to change gas rates in all municipalities within the North Texas Metroplex Distribution System effective April 5,2002;and WHEREAS, the City of Grapevine suspended the effective date of the proposed new rates for 90 days to evaluate the reasonableness of existing rates and the merits of TXU's proposed changes; and WHEREAS, the City of Grapevine participated with other municipalities in a comprehensive review of TXU Gas Distribution's application; and WHEREAS, consultants and counsel retained by the coalition of cities have recommended denial of the Company's application based upon a report from consultants demonstrating that the revenue requirement of the North Texas Metroplex Distribution System is being met under current rates; and WHEREAS, that recommendation has been endorsed by the Steering Committee of city representatives who have coordinated the review of TXU Gas Distribution's rate application; and WHEREAS, the Gas Utilities Regulatory Act provides that costs incurred by Cities in ratemaking activities are to be reimbursed by the regulated utility. NOW, THEREFORE, BE IT ORDAINED BY THE CITY COUNCIL OF THE CITY OF GRAPEVINE, TEXAS: Section 1. That the TXU Gas Distribution's Statement of Intent to change gas rates within the North Texas Metroplex Distribution System be, all respects, denied. Section 2. That the costs incurred by Cities in reviewing TXU's application be promptly reimbursed by the Company. Section 3. That a copy of application be sent to Autry Warren, Street, Dallas, TX 75201-3402. this ordinance, constituting final action on TXU's Rates Manager, TXU Gas Distribution, 1601 Bryan Section 4. If any section, article, paragraph, sentence, clause, phrase or word in this ordinance, or application thereto by a Court of competent jurisdiction, such holding shall not affect the validity of the remaining portions of this ordinance; and the City Council hereby declares it would have passed such remaining portions of the ordinance despite such invalidity, which remaining portions shall remain in full force and effect. Section 5. The fact that the present ordinances and regulations of the City of Grapevine, Texas are inadequate to properly safeguard the health, safety, morals, peace and general welfare of the public creates an emergency which requires that this ordinance become effective from and after the date of its passage, and it is accordingly so ordained. PASSED AND APPROVED BY THE CITY COUNCIL OF THE CITY OF GRAPEVINE, TEXAS on this the 18th day of June, 2002. ATTEST: APPROVED AS TO FORM: K gz N LLOYD, GOSSELINK, BLEVINS, ROCHELLE, BALDWIN & TOWNSEND, P.C. ATTORNEYS AT LAW 111 CONGRESS AVENUE SUITE 1800 AUSTIN, TEXAS 78701 Mr. Gay's Direct Line: (5 12) 322-5875 Email: ggay@lglawfirm.com TO: All North Texas Metroplex Cities FROM: Geoffrey M. Gay DATE: May 31, 2002 JUN 1 0 2002 TELEPHONE (512) 322-5800 TELECOPIER (512) 472-0532 www.iglawfiirm.com RE: Need To Schedule City Action On TXU Gas Distribution's Rate Case On May 28, 2002, Diversified Utility Consultants, Inc. (DUCI) issued its report to Cities regarding TXU Gas Distribution's proposed consolidation of systems and increase in revenue requirements for the Metroplex. On May 29, City representatives met in Arlington with DUCI and counsel to discuss the consultant's report. The consensus of the group was that Cities should be urged to deny TXU's requested relief unless a settlement can be promptly negotiated. On Monday, June 3, settlement discussions will occur with TXU. If reasonable progress can be made toward settlement, TXU will extend its effective date to relieve Cities of the pressure to pass an ordinance by July 5. If settlement does not appear achievable, all Metroplex Cities will be urged to pass a resolution denying TXU's requested relief. Simple denial can be achieved through a resolution, rather than a rate ordinance, and since no rates will change, even Cities that have a three reading requirement for a rate ordinance should be able to act in one meeting. You are urged to go ahead and schedule action on a resolution denying TXU's application at a Council meeting between June 10 and July 5, preferably at the last council meeting in June. A model resolution is attached. If settlement is achievable, you will be notified of an extension in the effective date and be provided with a model ordinance and a justification for the recommended ordinance. Action Requested: Please schedule adoption of a resolution denying the Company's Application for rate relief for the last scheduled Council meeting in June. NOTE: For those receiving this communication via email, an electronic version of the report of consultants retained by the coalition of cities is attached. For those receiving this communication via fax or mail, a copy of the consultant's report will be mailed to you. 1913\00\mmo020531 gmg RESOLUTION NO. RESOLUTION DENYING TXU GAS DISTRIBUTION'S REQUEST TO CHANGE RATES IN THE NORTH TEXAS METROPLEX DISTRIBUTION SYSTEM; REQUIRING PROMPT REIMBURSEMENT OF CITIES' RATE CASE EXPENSES WHEREAS, on or about March 1, 2002, TXU Gas Distribution, a division of TXU Gas Company filed with the City of a Statement of Intent to change gas rates in all municipalities within the North Texas Metroplex Distribution System effective April 5, 2002; and WHEREAS, the City of suspended the effective date of the proposed new rates for 90 days to evaluate the reasonableness of existing rates and the merits of TXU's proposed changes; and WHEREAS, the City of participated with other municipalities in a comprehensive review of TXU Gas Distribution's application; and WHEREAS, consultants and counsel retained by the coalition of cities have recommended denial of the Company's application based upon a report from consultants demonstrating that the revenue requirement of the North Texas Metroplex Distribution System is being met under current rates; and , , WHEREAS, that recommendation has been endorsed by the Steering Committee of city representatives who have coordinated the review of TXU Gas Distribution's rate application; and WHEREAS, the Gas Utilities Regulatory Act provides that costs incurred by Cities in ratemaking activities are to be reimbursed by the regulated utility. NOW THEREFORE BE IT RESOLVED BY THE CITY COUNCIL OF THE CITY OF that: 1. The TXU Gas Distribution's Statement of Intent to change gas rates within the North Texas Metroplex Distribution System be in all respects denied. 2. The costs incurred by Cities in reviewing TXU's application be promptly reimbursed by the Company. 3. A copy of this r6blution, constituting final action on TXU's application be sent to Autry Warren, Rates Manager, _TXU Gas Distribution, 1601 Bryan Street, Dallas, TX 75201- 3402. T Mayor, City of 1 0 ATTEST: 1 May 28, 2002 Steering Committee for TXU Gas Company's North Texas Metroplex System Re: Report Addressing Summary of Findings and Conclusions Regarding TXU Gas Distribution Company's Statement of Intent to Increase Rates. Dear Cities; This report contains Diversified Utility Consultants, Inc.'s ("DUCI") review, analysis, and investigation regarding the proposed level of retail gas rates filed by TXU Gas Company ("TXU Gas" or "Company"). Presented in this report are discussions of DUCI's analysis and recommended adjustments to the Company's proposed rate increase in the 109 cities ("Cities") that comprise the North Texas Metroplex Distribution System ("N TX Metro"). ' 4n March 1, 2002, TXU Gas filed a request for an annual rate increase in the Cities, for the N TX Metro in the amount of $33,849,096. This amount is based on a test year ended September 30, 2001. The Company states that its overall requested increase is 8.01%, with an increase of 9.07% for residential customers. A customer's bill is made up of two components, an operational cost component .(base rate portion) and a cost of gas component. As is discussed in the body of this report, the Cities have jurisdiction only over the operational portion of costs, not gas costs. Therefore, when the gas component is removed from the Company's requested increase, TXU Gas is actually requesting the Cities to approve a 23% overall base rate increase, with a base rate increase to residential customers of 24%. Presented herein are what DUCI believes to be appropriate and, necessary adjustments to the Company's proposed revenue requirement and rate design requests. The recommended adjustments set forth in this report result in an annual reduction of $3,204,932 to current rates, or a reduction of $37,054,028 to the Company's requested annual increase of $33,849,096. Based on DUCI's adjusted revenue requirement and rate design, a residential customer using 6 Mcf in a month would be billed $37.17, compared to $40.67 per month if the Company's request was adopted. That represents a $3.50, or 8.6%, reduction per month on a customer's total bili including the cost of gas. In addition to the rate increase TXU Gas is requesting, it also proposes to eliminate the Weather Normalization Adjustment Clause ("WNC"), eliminate the Cost of Service Adjustment, eliminate the Plant Adjustment Clause, initiate a surcharge for uncollectible expenses, significantly change the rate design for the residential and commercial classes, and initiate a miscellaneous service charge for the temporary discontinuance of service. It is interesting to note that the Railroad Commission of Texas ("RCT") for the first time recently allowed the Company to implement its request for a WNC in Docket No. 9145, the last rate case for the City of Dallas. Now, after incurring k rate case expenses to seek and implement the WNC in other cities, the Company elects to reject it. Presented herein is what DUCI believes are necessary and appropriate adjustments to the Company's proposed revenue requirement based on the limited information obtained at the present time. The information obtained is limited due in part to TXU Gas' failure to provide updated data past test year-end on a majority of issues (12 months ended September 30, 2001), even though it is now 8 months past the end of the test year. Similarly, the Company also refused to provide data prior to January 1999. TXU Gas has taken an aggressive position in protecting its books and records, and avoided or delayed providing even some of the most basic data requested. This issue is further discussed in the body of the report. DUCI began the review process by duplicating TXU Gas' proposed revenue requirement. Next, DUCI analyzed the individual components of the request to test whether a reasonable level of costs and expenses has been requested. Data relied on for this analysis consists of respgnses to requests for information to the Company, RCT qac filings, the Texas Utility Code, and past TXU Gas proceedings. Analyzing how these costs are allocated from TXU Gas' parent company and its affiliates, and the amount allocable to the N TX Metro is an integral part of the evaluation of the Company's rate request. DUCI's analysis results in an overall base rate reduction of $3,204,932, or 2.2%, compared to present rates, rather than the 23% overall base rate increase requested by the Company. The overall reduction reflects an increase to the residential class of $3,474,577, with a decrease in commercial and industrial customer class revenue requirements of $6,051,755 and $627,646, respectively. In order to implement DUCI's recommendations, the Cities may: (1) deny TXU Gas' request and retain the existing rate, (2) implement a set percentage change for each base rate component of each rate; or (3) adopt the same average N TX Metro rate for each residential and commercial customer no matter which city the customer is located in. The first option recognizes the lack of complete data provided by the Company and the relatively small level of the rate change. As discussed later, DUCI does not recommend that the City make a determination on the reasonableness of rates charged to industrial customers. DUCI's recommendations are summarized by major category as follows: ii DESCRIPTION COMPANY REQUEST DUCI RECOMMENDED DIFFERENCE Gas Purchases $261,285,153 $261,285,153 $0 O&M Expenses $ 77,208,403 $ 64,566,091 $12,642,312 Taxes Other than FIT $ 34,352,839 $ 31,797,573 $ 2,554,905 Depreciation/Amortization $ 24,901,795 $ 23,767,573 $ 1,134,222 Int. on Cust Deposits/Advances $ 638,634 $ 638,634 $0 FIT $ 15,017,592 $ 11,036,112 $ 3,981,480 Return $ 42,874,393 1-35-4_80 ,217 $ 7,394,176 Total $456,278,809 $428,571,714 $27,707,095 Revenue Adjustment $ 9,346,803 Adjusted Total 7 0 4 02 A discussion of each of the issues raised and changes recommended by DUCI is presented in the balance of this report and the overall impact is set forth on Schedule 2. We invite the Mayors, City Council Members, City Managers, and City Staff to review in detail the various sections of this report and the various recommendations and adjustments made to the Company's proposed cost of service. We appreciate the opportunity to provide this service to the Cities, and are prepared to answer any questions that may arise from your review of this report. If the Cities desire any additional analysis or assistance, we will be available to assist you, your staff or your legal council to the extent required. Sincerely, Diversified Utility Consultants, Inc. IN TABLE OF CONTENTS TRANSMITTAL LETTER .................................................. ...................... i TABLE OF CONTENTS..........................................................................................1 SECTION I: EXECUTIVE SUMMARY....................................................................... 3 A. Introduction...............................................................................................................3 B. Company Description /Rate History............................................................................ 4 C. Discovery Issues............................................................................................................ 5 D. Consultant Recommended Rate Change........................................................................ 7 E. Rate Review Standards and Process.............................................................................. 7 1. Evaluation Standard & Guidelines................................................................................................ 7 2. Analysis Process............................................................................................................................... 8 SECTION II: COMPANY PROPOSED RATE INCREASE ...................................... 9 A. Company's Proposed Increase...................................................................................... 9 B. Recent Rate Filings in the N TX Metro........................................................................ 9 1. Investment Levels.......................................................................................................................... 10 2. Expense Increases.......................................................................................................................... 11 3. Sales and Customer levels — Billing Determinants...................................................................... 12 SECTION III: RATES TO INDUSTRIAL AND TRANSPORT CUSTOMERS.... 13 SECTION IV: ANALYSIS OF fSSUES......................................................................15 SECTION V: REVENUES...........................................................................................17 A. Introduction.............................................................................................................17 B. Weather Normalized Revenues................................................................................... 18 C. Customer Growth........................................................................................................ 20 SECTION VI: ALLOCATION.................................................................................... 22 A. Cost Allocation in the System..................................................................................... 22 B. Customer Classification.............................................................................................. 23 SECTION VII: RETURN............................................................................................. 25 SECTION VIII: EXPENSES........................................................................................ 28 A. Payroll Expenses................................................................ 28 1. Updated Salary............................................................................................................................... 28 2. Bonuses and Incentives..................................................................................................................29 3. Overtime Adiustment....................................................................................................................29 B. Benefits.............................................................................................................29 C. Amortization of Merger Related Costs....................................................................... 30 D. Normalization of Expenses......................................................................................... 30 E. Labor and Growth Adjustments.................................................................................. 32 F. Uncollectibles............................................................................................................. 33 G. Depreciation Expense......................................................................................... .... 34 H. Amortization Expense — Safety Compliance Proms ............................................... 35 SECTIONIX: RATE BASE......................................................................................... 36 A. Safety Compliance Program....................................................................................... 36 B. Cash Working Capital ("CWC")................................................................................. 36 C. Prepayments.............................................................................................................37 D. Relocation.............................................................................................................37 E. Construction Work in Process"CWIP").................................................................... 37 SECTION X: FEDERAL INCOME TAXES............................................................... 39 SECTION XI: TAXES OTHER THAN FIT................................................................ 40 A. Revenue Related Taxes.............................................................................................. 40 B. Property Taxes............................................................................................................ 40 C. Payroll Taxes........................................................................................................... 40 SECTION XIII: RATE DESIGN................................................................................. 41 A. Residential Average Rate Alternative......................................................................... 42 B. Commercial.............................................................................................................43 1 SECTION I: EXECUTIVE SUMMARY A. Introduction TXU Gas Distribution, a division of TXU Gas Company ("TXU Gas" or "Company"), filed a Statement of Intent on March 1, 2002 to increase rates over $33.8 million annually in the North Texas Metroplex Distribution System ("N TX Metro"). The N TX Metro consists of 107 cities. A list of the Cities included in the N TX Metro is provided in Schedule 1 of this report. The Company's proposed increase varies by city and by customer class depending on the particular community and specific class. The following table provides information for the Company's current and proposed revenues and rate change for the residential class, commercial class, industrial class, and service charge for N TX Metro. TABLE V NORTH TEXAS METROPLEX SYSTEM PROPOSED ANNUAL RATE INCREASE FOR THE TEST,YEAR ENDED SEPTEMBER 30, 2001 BY.CUSTOMER CLASS A) ) (C) 77W (E (FtiaRel $273,385,183 $298,173,541 9.07% 24.22% ommercial $130,858,349 $137,257,322 $6,398,9737 4.89% 20.25% Industrial $14,255,507 $16,917,272 $2,661,765 18.67% 27.05% Subtotal $418,499,039 $452,348,135 $33,849,096 8.090o 23.54% Service Charges $3,926,080 $3,930,694 $4,614 0.12% 0.12% Total 422 42 19 1 $456,278,829 $338 3 1 8.01% 22.92% Table 1 above shows the overall N TX Metro base rate increase of $33,853,710, or 23% per year. TXU Gas is requesting a base rate increase of 24.22% -for residential customers. To enable the N TX Metro Cities ("Cities") to evaluate the actual proposed increase over which they have jurisdiction, base rates percentage increases (total rates excluding the cost of gas) are presented in Column F. The Cities do not regulate the gas cost portion of customers' bills. Gas costs are exclusively regulated by the Railroad Commission of Texas ("RCT"). As can be seen, the rate increase request before the Cities is a substantial annual percentage increase in this case. 1 Company Schedule A. 3 B. Company Description / Rate History TXU Gas provides gas to over 1.4 million customers in approximately 560 cities and towns in Texas. The Company has over 25,000 miles of distribution mains. In calendar year 2000, TXU Gas' net utility plant was $600 million with annual revenues of approximately $960 million. TXU Gas is regulated at the city level with appellant jurisdiction at the RCT. On or about August 5, 1997, Texas Utilities Company ("TXU") merged with Enserch/Lone Star Gas Company ("Enserch"). Enserch focused on natural gas business operations including gathering, processing, transmission, and distribution of natural gas. Lone Star Gas Company ("LSGC") was a subsidiary of Enserch. LSGC operated the natural gas distribution business. It is the largest gas distribution company in Texas and one of the largest in the United States. Beginning in 2000, TXU Gas assigned many of its cities to new distribution systems where cities are combined for rote purposes. In this current filing, TXU Gas has again reassigned cities into this new distribution system for rate purposes. A majority of these cities experienced a rate increase approximately 6 months ago based on a settlement agreement. The assignment of cities to a region does not appear to have anything to do with shared services or grouping by location. Rather, TXU Gas has assigned certain cities to distribution systems based on unknown and arbitrary Company criteria for ratemaking purposes. At the time of the merger/purchase of Enserch by TXU, numerous promises were made regarding future rates and cost decreases. Specifically, TXU projected over $850 million of synergy savings would accrue as a result of the combination of the gas and electric companies. TXU estimated that a majority of the gas related savings would inure to the benefit of distribution customers and would be passed on to future customers through rates. Despite these past promises, the Company has been on a campaign of frequent rate increase filings across Texas. For many of the cities, this is the second major rate increase request since the merger. Given that most of the promised merger savings were to accrue during 4 the five years following the merger, it appears that such savings may not have materialized as previously indicated, or may not be being passed to customers through rates. Even more troubling is that the gas operations, when owned by Enserch, did not require frequent rate increases, but after TXU took over operations, not only did promises of savings not materialize, but frequent rate adjustments became necessary. It is our understanding that TXU Gas will be yet again requesting another rate increase in the Dallas area next year. DUCI has examined the gas operations relative to other TXU activities in an effort to determine why TXU seems to require major and frequent gas rate changes, while the remainder of TXU appears profitable. This issue is addressed in Section II of this report. C. Discovery Issues A rate request such as the current TXU Gas filing requires a review of supporting detail to ensure that the Company's requested actual and estimated expenses are correctly included in rates for customers. For example, TXU corporate affiliates, such as the business services division, allocate millions of dollars in joint costs to gas, electric and other corporate activities. Analyzing how these and other costs are allocated to TXU Gas, and the amount allocable to N TX Metro customers, is an integral part of the evaluation of the Company's rate request. Despite numerous attempts to access Company data, TXU Gas has taken an aggressive position in protecting its books and records and avoided and/or delayed providing the most basic data requested. Some examples of TXU Gas' aggressive posture in this proceeding, which delayed the data gathering process, can be found in the following examples of objection to basic data requests: • Request No. 1-2: Y2K- Please state the total amount of Y2K expense the Company has included in its revenue requirement. Is this an amortization or actual expense incurred during the test year? Objection: TXU objects to this request because it is ambiguous and vague in that "Y2K expense" is not defined. Please clarify the meaning of "Y2K expense." 5 • Reauest No. 1-5: Payroll- Please provide employee count by month from January 1, 2000 through the most current month available, and the annual count for calendar year 2000 and 2001 for the North Texas Metroplex Distribution System. Objection: TXU objects to this request because it is ambiguous and vague in that "employee count" is not defined. Please clarify whether "employee count" refers to (1) the total number of persons employed for each time period, (2) the number of persons employed at the end of each time period, (3) the average number of persons employed during the time period, or (4) some other meaning. • Request No. 1-24: Expenses- Please provide the Company's direct expenses by month, by year, for the past 3 years by account number. Include a brief description of each expense, balance at December 31 of each year. Objection: TXU objects to this request because it is vague and ambiguous to the extent "direct expenses" are not defined. Please clarify the meaning of "direct expenses." Obviously, the Company's claimed confusion with regard to the above three questions could have been resolved with a simple telephone call. Instead, the Company elected to formally object with what can only be described as frivolous arguments. DUCI has attempted to gather data from other public sources such as RCT filings and other rate case filing by TXU Cas in an effort to deal with the Company's failure to provide some of the most basic data to review its request. DUCI continues in its attempts to acquire the data necessary to review other areas of the Company's request. It may be that further adjustments are necessary in this case, but until all the data can be evaluated, some areas of expense and investment are not able to be verified. D. Consultant Recommended Rate Change DUCI recommends that TXU Gas' $33.8 million annual rate increase be denied. DUCI's analysis indicates that an annual rate reduction of $3,204,932 be implemented. Schedule 2 sets forth DUCI's recommended revenue requirement. In past cases involving TXU Gas, parties have attempted to resolve rate differences through settlement negotiations. A settlement process avoids the litigation process involved in the appeal of such matters to the RCT, as occurred in the last Dallas Distribution System case. Recent experience with TXU Gas, and its aggressive position in discovery for this case, indicates TXU Gas may not be willing to negotiate such matters. For example, in a recent transcribed rate hearing in Denton, Texas, a TXU Gas representative told the Denton City Council: "Well, we're not in the business of negotiating rates. That's one thing I need to apparently put to rest. We're a monopoly. If there are no competitive alternatives." (Emphasis added). 1 Despite the Company's aggressive posture to basic requests for supporting data, DUCI believes that the recommended $3,204,932 decrease in revenue requirement is supported by the evidence and basic ratemaking rules, regulations, and practices of cities and the RCT. E. Rate Review Standards and Process 1. Evaluation Standard & Guidelines The Company's rate filing and proposed rate increase is evaluated based on the standards set forth in the Texas Utilities Code. The goal is to determine whether the proposed Company rates are fair, just, and reasonable and that no rate is unreasonable, preferential, prejudicial, or discriminatory. In evaluating the overall revenues requested by the Company, DUCI recommends that TXU Gas' overall revenues be set at a level that will permit TXU Gas an opportunity to recover its reasonable and necessary expenses and earn a reasonable return on the Company's invested capital used and useful in providing service to the customer. Basic 7 ratemaking principles established by the RCT, RCT rules, along with requirements of the Utilities Code (herein after GURA) are employed in evaluating the Company's request. 2. Analysis Process In the process of analyzing the Company's earning position, several factors are taken into account. The ultimate goal is to determine whether the normalized overall rate of return earned by the Company is at a "just and reasonable" level. The multi -step process first analyzes the various components of the following formula in order to determine which side of the equation is greater and by what magnitude. Base Rate Revenue2 = O&M Expense + Taxes + Depreciation + Return Then the results of the above equation are compared to the results of a separate analysis, which attempts to determine an appropriate rate of return from the following formula: I Return = Weighted Cost of Capital x Adjusted Rate Base In other words, there are four main areas that require investigation: (1) the level of base rate revenues; (2) the level of base rate expenses, including the allocation of corporate joint and common expenses; (3) the overall level of investment associated with jurisdictional retail service; and (4) the appropriate cost and weighting of capital (i.e., long-term debt, preferred and common stock). This report enumerates the various adjustments DUCI recommends to the claimed cost as reported in TXU Gas' rate request for the N TX Metro. Z Total revenues less fuel or gas revenues where total revenues equals the regulated or tariff price times units of gas sold. 3 Total operating and maintenance expenses less gas expense. 8 SECTION II: COMPANY PROPOSED RATE INCREASE The starting point in DUCI's analysis is a review of the TXU Gas filed rate request. The first step of DUCI's analysis is the duplication of the Company's rate analysis. Included in Schedule 3 is DUCI's duplication of the Company's filed case. A. Company's Proposed Increase TXU Gas claims that a $33,853,710 annual rate increase is necessary to recover costs of operations in the N TX Metro. The class breakdown of the Company proposed annual increase is shown in Table 1 discussed above. This $33.8 million rate increase and class allocation has been duplicated in Schedule 3. Our review, as discussed below, indicates that TXU Gas' rate request understates present revenues, overstates expense requirements, overstates investment, and overstates the Company's capital costs. The following pages discuss each of these areas. B. Recent Rate Filings in the N TX Metro A factor that is important in evaluating the Company's claimed need for over a 23% base rate increase is that TXU Gas' rates, costs, investment levels and revenues were just recently reviewed in their entirety in a full and complete rate review before many of the Cities in the N TX Metro. For example, about 40 of the cities (formerly Northwest Metro Mid -Cities System) approved rate increases allowing about 70% of TXU Gas' request just six month ago. In other words, in February 2001, TXU Gas requested about a $7.5 million increase in 40 of these same cities 4 That case was settled around June 2001 for about 70% of the rate request or about $5.1 million. Now, TXU Gas is requesting an additional increase of over $15 million annually for these same cities.5 It strains credibility to accept that for 40 of the 107 cities, TXU Gas claimed in April 2001 that a $7.5 million annual increase would allow the Company to recover its costs and earn a return, yet now claims substantially more is needed. Of the 109 cities in this case, about 100 cities have had rate increases within the past 18 months of the current rate request. Schedule 5 provides a list of cities along with a comparison of the current and previous rate case. 4 A list of the former Northwest Metro Mid -Cities now included in the North Texas Metroplex Distribution System along with a rate request comparison is included in Schedule 4. 5 See, Schedule 4. 9 Now, in March 2002, TXU Gas is claiming that an additional $33.8 million annual increase is necessary for TXU Gas to recover its costs and earn a reasonable return. The obvious question that needs to be addressed is what set of events in the very recent past has caused this claimed need for this additional rate increase request. To address this question, DUCI has focused on three major areas: increased investment, increased expenses, and sales levels or billing determinants. The level of investment, operating expenses and sales levels will impact the need and/or level of rate adjustments required by TXU Gas. 1. Investment Levels The Company claims gross investment levels have increased $100.6 million or 24% for the N TX Metro during the December 1999 through September 2001 period. While a $100.6 million increase in gross investment is certainly a large increase in capital, further analysis reveals this investment does not explain the size or even the need for the rate request. The $100.6 million investment claim is gross investment. In other words, it does not take into account the decreases in invested capital that occurred through depreciation of capital recovered through rates over this period. When net investment is analyzed, the increase in net capital is about $57 million, not the $100.6 million as TXU Gas would have customers believe .6 The revenue requirement impact of a $57 million increase in rate base is about $9.25 million annually at a fixed charge rate of 16.218%.7 A lower return than the 9.47% requested by TXU Gas would result in an even lower fixed charge rate and thus a lower revenue requirement. The Company's claimed need for a 23% base rate annual rate increase is not explained by an increase in capital investment, especially when significant levels of the investment increases have already been recognized in the rates implemented within the past year. 6 $100.6 million less (($24,901,795/12) * 21 months) equals $57,021,859, where $24.9 million is the claimed annual depreciation expense of TXU Gas. 7 Company ROR of 9.47% adjusted for taxes and a depreciation rate of 3.5%. 10 2. Expense Increases The Company claims that O&M expenses have increased by 5.6% since December 1999, due to line locations and customer growth. While some expenses increase with growing customer levels, e.g. postage for billing, not all expenses increase. Rather, customer growth often leads to productivity increases; serving more customers with the same number of resources. In addition, along with customer increases are additional revenues to cover any increased costs. Thus, changes in customers do not explain O&M increases. The Company's second claim is at odds with its increased level of capital expenditures since the mid 1990s. Typically, investment or capital expenditure increases result in O&M decreases. In other words, new investment decreases the frequency required to repair lines and other investment. In addition, since the TXU-Enserch merger, O&M efficiencies and other operating synergies were expected to create benefits, not require frequent rate cases. In other words, rather than have an Enserch meter reader and a TXU electric meter reader, the combination or merger of the two companies with a 2/3 customer base overlap would, or at least should, result in meter reading, customer accounting, billing and other O&M cost savings. Attempts to determine the promised merger related savings were frustrated by TXU Gas' claims that such synergy -related productivity benefits are not tracked by the Company. Not only is the Company unable to measure merger savings, but also analysis of the most basic customer related costs indicates that the merger has caused costs to increase. For example, customer meter reading expenses are increasing for the gas business while the same costs are not generally increasing for TXU's electric business. Schedule 6 shows various- customer related costs before and after the merger for the electric and gas business. The results of this analysis suggest gas costs are increasing after the merger, while the cost to serve an electric customer is not increasing. Prior to the merger, Enserch operated as a successful gas provider controlling costs and maintaining rates without frequent rate adjustments. TXU thought so highly of the Enserch assets that TXU agreed to pay a handsome premium above book value to acquire these 11 operations. Since the merger, ratepayers have faced frequent rate changes, increasing costs and claims of unprofitable gas operations. Something substantial has gone wrong with the gas operations since the merger if TXU's claims of increasing costs and falling profits are to be accepted. 3. Sales and Customer levels — Billing Determinants The last key area examined is sales and customer levels, which can impact the need for a rate increase. A substantial decline in sales or billing determinants will cause the need for a rate increase. For example, if TXU Gas' costs of operation are $1,000 per year and expected sales are 1,000 units or Mcf of gas, then the cost per Mcf is $1.00 ($1,000/1,000). However, if costs remain $1,000 and sales drop to 750 units of gas, then rates need to increase to $1.33 per Mcf ($1,000/750) to collect the annual operating costs of $1,000. In TXU Gas' Executive Summary in this case, it claims that the customer base increased by 8% since December 1999, while the sales of gas have increased by an equivalent 8%. Moreover, the Company claims residential sales have increased by 29% in this same period. Normally, healthy growth is usually seen as an opportunity to enhance profits rather than a basis to claim a need for rate increases. In summary, increased investment in and of itself explains less than 27% of the $33.8 million annual rate increase, especially when prior rate cases already recognized a portion of the increased investment. Claimed increases in operating costs are not consistent with the merger related synergy savings experienced on the electric side of the business. Claimed increases in gas operating costs reflect a substantial departure from the pre -merger experience for the gas business. TXU's claimed cost increases and need for a rate increase is not explained by the claimed sales changes. 12 SECTION III: RATES TO INDUSTRIAL AND TRANSPORT CUSTOMERS This case includes a rate request that reflects a 2 661 765 annual r q $ , proposed revenue requirement increase for the industrial/transport customers. Prior to the last 2 years, the Company had filed for rate increases that included only residential and commercial customers. This case, which includes the request for approval of an annual increase for the industrial/transport customers, is a departure or change from many previous Company rate requests before certain cities. We recommend that the Cities treat this case as a residential -commercial customer class rate case, and remove the industrial transport rate request from consideration. While regulatory authorities such as cities have jurisdiction over industrial and transport rates, the Company has failed to make any showing that existing rates for the industrial/transport customer class are not reasonable For guidance on this issue, we refer you to Texas Utilities Code §104.003 Just and Reasonable Rates. ' (a) The regulatory authority shall ensure that each rate a gas utility or two or more gas utilities jointly make, demand, or receive is just and reasonable. A rate may not be unreasonably preferential, prejudicial, or discriminatory but must be sufficient, equitable, and consistent in application to each class of consumer. In establishing a gas utility's rates, the railroad commission may treat as a single class two or more municipalities that a gas utility serves if the commission considers that treatment appropriate. (b) A rate for a pipeline -to -pipeline transaction or to a transportation, industrial, or similar large volume contract customer is considered to be just and reasonable and otherwise to comply with this section and shall be approved by the regulatory authority if: (1) Neither the gas utility nor the customer had an unfair advantage during the negotiations; (2) The rate is substantially the same as the rate between the gas utility and at least two of those customers under the same or similar conditions of service; or (3) Competition does or did exist with another gas utility, or another supplier of natural gas, or a supplier of an alternative form of energy. (Emphasis added). 13 The industrial transport rates have been almost exclusively set by contract between the Company and the customers -8 The Company has presented no data, evidence, or reasonable explanation as to why the Cities should employ their regulatory authority in setting new rates. This is especially true given that the Company did not implement the industrial rates that it sought and received approval for in its last case with numerous cities in the N TX Metro. Therefore, the Company's request that the Cities determine the industrial rates should be denied. I 8 TXU Gas admits that only one industrial customer does not have a contract in place. That one customer had a rate set by a city within the past several months. 14 SECTION IV: ANALYSIS OF ISSUES Discussed in the following pages are a number of adjustments made to the Company's request. These adjustments are necessary to ensure that customer rates and charges are just, reasonable, and not discriminatory as required by the Utilities Code. The results of DUCI's analyses indicate that the Company's proposed rate request of $33.8 million is not justified and would result in an over -collection by TXU Gas of approximately $37,054,028. DUCI's analysis suggests that on a N TX Metro basis, current rates charged by the Company are overstated and the Company is over earning. Section XII sets forth a discussion of the Cities' alternatives for rate design. Schedule 7 sets forth DUCI's recommended revenue requirement, by class. Table 3 is a listing and description of each adjustment DUCI is recommending. A "stand alone" estimated impact is included with each adjustment. Because numerous adjustments interact with each other, the summation of the "stand alone" adjustments is not equivalent to the final cost of service recommendation. The combined impact of DUCI's recommendations results in a $3,204,932 reduction to the Company's currently authorized rates for the N TX Metro. 15 •, i 1Zell 04 POP I VINNI 1 i 1•. Return/Capital Structure 1 UMMLan 1 $6,038,367 Present Rate Revenue Weather/Customer $4,994,191 Rate Base — Relocations $3,111,023 Customer Records & Collections $2,252,940 Outside Services $2,237,934 Rate Base — Safety Compliance $2,166,181 Payroll Related $1,941,193 Rate Base — CWC $1,414,106 Injuries & Damages $1,403,330 Growth Adjustment $1,327,550 Maintenance of Mains $1,301,617 Property Tax $1,087,801 Merger Related Amortization $1,021,850 Meter Reading $ 864,889 Rents $ 842,826 Amortization Expense -Safety Compliance $ 628,961 Uncollectibles $ 500,757 Rate Base — Prepayments $ 289,665 Rate Base — CWIP $ 97,311 16 ISECTION V: REVENUES A. Introduction The Company has estimated the test year present rate revenues earned under present rates or tariffs assuming normal weather conditions as adjusted for customer growth. In other words, the Company starts with adjustments to the per books sales levels for normal weather conditions and adjusts customer levels for changes in test year growth levels. Next, the Company applies the adjusted customer levels and weather normalized sales levels to current tariffs to arrive at test year sales. The following table shows the Company's adjustments to per books sales and customer levels, and resulting test year revenues for the residential and commercial customers. TABLE 4 TEST YEAR CUSTOMER AND SAILES ADJUSTMENTS AND PRESENT RATE REVENUES N Per Books Customers 637,502 51,457 Customer Adjustments 5,280 1,749 Adjusted Customers 642,782 53,206 Per Books Sales (Mc 48,901,838 27,927,242 Sales Adjustment Customers (Mcf) 14 780,434 272,879 Sales Adjustment Weather (Mcf) (6,279,616) (2,563,319) Test Year Sales (Mcf) 43,402,656 25,636,802 Test Year Revenues F $273,385,183 $130,858,349 As can be seen from the above table, the Company has made adjustments to the test year for customers and weather normalization. DUCI's analysis of the Company's test year weather normalization and customer growth adjustments indicates that there is a substantial understatement of -test year sales. For example, analyzing normalized sales levels for the Northwest Metro Cities (a subset of the N TX Metro) that had cases just last year indicates substantial declines in weather normalized sales, yet customers are growing. Included in Schedule 8 is a comparison of customers and sales levels for 9 Schedule J line 2, year end customers. 10 Includes public authority. 11 Line 1 less line 3. 12 Schedule J, line 3. 13 Schedule J, line 4. 14 Schedule J, line 7. 17 MW each city for the two most recent rate cases. This data indicates the Company's current estimates are understated in terms of sales and resulting present rate revenues. DUCI has made three adjustments to present rate revenues for this report. First, DUCI has recalculated the weather normalized sales by city. Second DUCI has recalculated the Company's proposed year-end customer levels. Third, DUCI has adjusted test year revenues based on per books revenues adjusted to test year. All three of these adjustments are discussed in the following pages. B. Weather Normalized Revenues The Company adjusted test year sales to reflect colder than normal weather during the test year, the 12 months ended September 30, 2001. In other words, rates are developed assuming normal weather and if the selected test year is colder than normal, actual sales must be reduced to reflect sales under normal weather conditions. The impacts on heating load requirements due to temperatures are measured in heating degree days. A heating degree day (HDD) is calculated as the difference between a 65 -degree base temperature and the average of the high and low temperature for a particular day. Thus, if a particular day had a high of 60 degrees and a low of 40 degrees (a high and low average of 50 degrees ((60 + 40)/2)), then there would be 15 HDDs, or 65 degrees less 50 degrees. If in the alternative, the high and low average temperature exceeds 65 degrees, there are no HDDs in that day. 16 The following table shows the actual and normal HDDs by month for the test year ending September 30, 2001. is Schedule J, line 6. 16 When the average high -low temperature exceeds 65 degrees, that particular day has cooling degree days. 18 TABLE 5 ACTUAL AND NORMAL TEST YEAR HDDs October 64 51 13 November 458 275 183 December 785 566 219 January 85 670 45 February 417 484 -67 March 402 286 116 April 41 75 -34 May 0 0 0 June 0 0 0 July 0 0 0 August 0 0 0 September 3 0 3 Total 2855 2407` 448 Thus, based on National Oceanic and Atmospheric Administration ("NOAA") climatological data reports for the D/FW Airport Weather Station provided by TX L. Gas, the months of October, November, December, January, March, and September were colder than normal. The months of February and April were warmer than normal. The months of May through August did not experience HDDs. I To adjust test year sales, TXU Gas calculated a degree day difference (actual HDDs — normal HDDs) of 510 HDDs for the test year. 21 This 510 HDD differential was then multiplied by the calculated weather sensitive load per HDD usage level by class by city. The weather sensitive load is calculated by subtracting the base load sales (non -weather sensitive Mcf sales) from actual test year sales. In other words, actual sales less base load results in weather sensitive load. The weather sensitive load is divided by actual HDDs to estimate actual usage per degree day. Usage per HDD is then multiplied by the 510 HDD factor to calculate the adjustment necessary to bring actual weather sensitive load back to a normal HDD weather sensitive sales level for the test year. - A review of TXU Gas' calculation indicates that test year sales have been substantially understated. For example, in recent cases where normalized sales have been calculated, the 17 TXU response to RFI Set No. 1, Question 1-71 Attachment 2. is Id. Attachment 1. 19 TXU adjusted actual HDDs to 2864. See `VP/J-3, 8 of 24. 20 TXU reported normal HDDs as 2354. See WP/J-3, 8 of 24. 2' TXU Gas adjusted actual HDDs of 2855 by increasing the beginning of the test year by 12 HDDs and reducing TYE by 3 HDDs to reflect billing cycles, resulting in a revised actual HDD annual value of 2,864 HDDs. TXU Gas employed a 30 -year average (1961-1990) for normal HDDs and calculated a value of 2,354. 19 residential class normalized sales levels are substantially above what TXU Gas now claims are normalized sales. This fact is demonstrated in Schedule 8. As stated earlier, TXU Gas claims that the normalized sales for N TX Metro residential customers have decreased by over 3,365,916 Mcf annually. Thus, in the short period since rates were set in the last cases until the test year in this case, TXU Gas asserts customer quantities have increased, but normalized sales have fallen by over 3,000,000 Mcf. Such a conclusion lacks credibility. Clearly, something is wrong in the TXU Gas analysis. The last rate cases for many of the Cities in the N TX Metro produced a weather normalized sales level that was determined appropriate. Employing the normalized sales level on a per customer basis that was most recently approved by many of the Cities is a reasonable starting point of the analysis. By employing normalized sales on a per customer basis along with TXU Gas' claimed customer levels in this case, a new and more reasonable estimate of weather normalized sales volumes and present revenues for each customer class by city can be estimated. The net result of correcting TXU Gas' calculations of weather normalized sales is an increase of present rate revenues and Mcf of $2,939,137 and 3,325,249, respectively, as shown in Schedule 9. C. Customer Growth In addition to the weather adjustment, DUCI is recommending increasing customers and associated Mcf sales resulting from customer growth for residential customers. TXU Gas has calculated customer growth to year-end levels and employed average growth in customers. In other words, TXU Gas calculates growth and divides such result by two in an effort to compute average growth through the test year. As an alternative, DUCI has calculated growth to year-end levels. This approach is consistent with the claim&Finvestment that is also stated at year-end levels. The results of DUCI's weather and customer adjustments are contained in Schedule 10. The final impact of this adjustment is to increase test year revenues by $2,027,897. ►.1 D. Revenue Adjustment Rather than employing test year sales and customer levels applied to existing tariffs, DCUI employed test year per books revenues as reported by TXU Gas as the starting point of the present rate revenues for this case. DUCI has provided this analysis in Schedule 11. The impact of this adjustment results in an increase of present rate revenues of $1,414,072 and $2,740,670 for the residential and commercial class of customers, respectively. DUCI has found that TXU Gas has substantially understated present rate revenues in previous cases by incorrectly stating historical sales or applying incorrect tariffs in the present rate revenue analysis. It appears that TXU Gas has once again understated present rate revenues. The per books revenues analysis contained in Schedule 11 corrects any errors made by TXU . Gas. 21 A. Cost Allocation in the System Cost allocation is the process by which the costs incurred by a utility in its ownership, operation, and maintenance of a particular system are assigned (allocated) between different classes of customers served by the system. On the N TX Metro System, there are three basic customer classes that share in the assignments of costs. These customer classes are (1) residential, (2) commercial, and (3) industrial/transport customers. In any general rate proceeding, the costs to be allocated can be assigned to one of four broad categories of costs which include: (1) cost of plant; (2) investment additions and deductions; (3) operating costs, such as labor and supplies and expenses; and (4) non-operating costs, such as depreciation, taxes, and return on investment. TXU Gas' last litigated rate case at the RCT was Dallas Distribution System, Docket No. 9145 which was based on a test year'ending December 31, 1999 and decided in November 2000. In that case, TXU Gas' cost allocation study allocated about 91.87% of the investment cost responsibility to the residential and commercial class customers. The remaining 8.13% of plant investment was assigned as the cost responsibility of industrial/transport customers. • The Company's proposed cost allocation was a hotly contested issue in the last Dallas rate proceeding at the RCT. The Examiner who presided in the last case concluded that TXU Gas' proposed single peak day allocator "...ignores the monthly peak changes on the system and that it is not reasonable to select an allocation factor that exceeds all consumption statistics other than peak day usage."22 The Examiners concluded, after reviewing the evidence at the hearing, that residential and commercial customers should be allocated 82.43% of investment and the remaining 17.57% allocated to industrial/transport customers. 23 • In this case,- the Company has changed the allocation of cost responsibility — particularly with regard to Customer classification (discussed below) resulting in an allocation of plant to the residential and commercial customers of about 95.28% and the remaining 4.72% to industrial customers.2 t In other words, TXU Gas has put customers 22 See RCT Docket No. 9145 Examiners Report p. 106. 23 See RCT Docket No. 9145 Examiners Report Schedule F-2. 24 Company Schedule B-1. 22 back in the same position as proposed by the Company in the last Dallas case. TXU Gas has completely ignored the last decision by the RCT on this matter. B. Customer Classification The key or principal reason for the Company's cost shifting to residential and commercial customers in this case is its proposed heavy weighting of the investment in mains to a customer rather than a demand cost classification. In TXU Gas' last litigation proceeding at the RCT (Dallas Distribution System, Docket No. 9145), the Company testified that customer related costs represent the minimum investment associated with having all customers connected to the system. 25 This Classification/Allocation approach is also referred to as the zero -intercept method. Employing the zero -intercept method, TXU Gas classified about 16% of mains investment as customer related. 26 Any investment in mains classified as customer rather than demand related will result in a higher final allocation to residential and commercial custoMers. This occurs because the customer allocator is over 90% to the residential and commercial class while the demand allocator is much less. Thus, the Company has shifted cost responsibility to captive residential and commercial customers by merely changing its cost classification method for mains investment. To see the dramatic change to the customer classification, one need only consider that net investment in mains in this proceeding is $311,444,266.27 The customer classification under TXU Gas' new approach (minimum system) is $153,752,343, or 49.4% of the total. In other words, the Company's proposed amount of investment classified as customer related is significantly greater than what would result if the method found appropriate in the last litigated proceeding at the RCT were employed. In TXU Gas' last case, at the RCT, the Examiners concluded that, "...the zero -intercept method produces a cost ... representative of actual costs incurred for investment in mains."28 25 See RCT Docket 9145 Examiners Report p. 99. - 26 See RCT Docket 9145 Examiners Report p. 99 and Schedule F-2. Z' Schedule K-8, page 1. 28 See Docket 9145 Examiners Report p. 100. 23 Given that the RCT just recently decided this allocation issue, after extensive litigation and no other factual issues have changed, it is most likely that the RCT will continue to adopt the zero - intercept method for purposes of allocation of mains for TXU Gas in the N TX Metro. Therefore, DUCI has employed the methodology (zero -intercept) approved by the RCT. Employing the zero -intercept method most recently approved in the last Dallas case at the RCT results in changing plant classification between customer and demand related mains investment. The impact results in changing the net distribution investment allocated to residential and commercial customers from 95% to under 91%. 24 SECTION VII: RETURN TXU Gas has requested a total return on invested capital rate base of 9.47%. A 9.47% rate of return applied to the Company's $452,948,117 claimed level of invested capital, results in a total annual return requirement of $42,874,313. The total $42,874,313 return can be broken down into the following functional capital requirements: (1) $15,513,926 debt cost, (2) $430,437 cost of preferred, and (3) $26,930,030 equity return for shareholders. The total base rate annual revenue requirement as proposed by the Company is $171,686,234.'9 Return and associated federal income taxes on return amount to $57,891,985 annually under the Company's proposal .30 Thus, about 34 cents of each dollar paid in rates goes to satisfy the Company's claimed return to investors and associated income tax obligations on return. Return requested is a significant part of the overall cost requirements claimed by the Company. For example, a reduction to the Company's claimed shareholder equity return of 11.5% to 10.5% results in over a $3.3 million annual reduction in revenue requirements. Mn The Company's proposed capital structure and capital cost rates is contained in the following table: TABLE 6 TXU GAS' PROPOSED CAPITAL STRUCTURE 29 Long-term 46.60% 7.35% 3.43% Debt Preferred 1.70% 5.59% 0.10% Stock Common 51.70% 11.50% 5.95% Equity Total 100.00% 9.47% Claimed Rate Base $452,948,117 Claimed Return $ 42,874,313 Taxes on Return $ 15,017,592 Return and Taxes $ 57,891,905 Base revenue requirement excludes gas costs which are determined by the RCT and not subject of this case and excludes revenue related taxes which are 5.076%. 30 Schedule K-1, p. 3. 25 The Company's development of capital structure, capital cost rates and overall return is based on employing data from a group of 12 local distribution companies (LDCs) as a comparable group. TXU Gas is owned by TXU Corp. and the gas distribution division is not publicly traded. Thus, a comparable group of 12 LDCs was used as a proxy to reflect the costs and risks of TXU Gas as a stand-alone distribution system. DUCI has reviewed the Company's analysis and proposals on capital costs and recommends the following capital structure and cost rates for this case. Thus, DUCI is recommending an overall rate of return of 8.64% on invested capital rather than the Company's requested 9.47% return. The first adjustment recommended by DUCI is to update the capital structure to reflect more recent capitalization ratios. The same 12 company comparable group was employed, but DUCI's analysis is based on 2001 data rather than the year 2000 data employed by the Company. The second adjustment is to reduce the Company's claimed cost of equity from 11.50% to 10.00%. DUCI recommends a return based on a discounted cash flow (DCF) analysis of market data on the 12 LDC companies employed in TXU Gas' analysis. The DCF analysis indicates a cost of equity of between 10% to 11% based on forecasted growth rates estimated by Value Line Investment Survey. The midpoint of 10.5% is a fair cost of equity estimate, absent other considerations, and is 100 basis points below TXU Gas' proposed 11.5% equity return request. In terms of equity cost rates, DUCI recommends the lower end of the cost range or 10%. DUCI has become aware of numerous complaints regarding quality of service. A number of cities have stated that TXU Gas has been reluctant to cooperate with cities regarding pipe 26 TABLE 7 DUCI'S RECOMMENDED CAPITAL STRUCTURE MIM EMMKOESOMMIUM Long-term Debt 49.24% 7.35% 3.62% Preferred Stock 1.18% 5.59% 0.07% Common Equity 49.58% 10.00% 4.96% Total 100.00% 8.64% Thus, DUCI is recommending an overall rate of return of 8.64% on invested capital rather than the Company's requested 9.47% return. The first adjustment recommended by DUCI is to update the capital structure to reflect more recent capitalization ratios. The same 12 company comparable group was employed, but DUCI's analysis is based on 2001 data rather than the year 2000 data employed by the Company. The second adjustment is to reduce the Company's claimed cost of equity from 11.50% to 10.00%. DUCI recommends a return based on a discounted cash flow (DCF) analysis of market data on the 12 LDC companies employed in TXU Gas' analysis. The DCF analysis indicates a cost of equity of between 10% to 11% based on forecasted growth rates estimated by Value Line Investment Survey. The midpoint of 10.5% is a fair cost of equity estimate, absent other considerations, and is 100 basis points below TXU Gas' proposed 11.5% equity return request. In terms of equity cost rates, DUCI recommends the lower end of the cost range or 10%. DUCI has become aware of numerous complaints regarding quality of service. A number of cities have stated that TXU Gas has been reluctant to cooperate with cities regarding pipe 26 19 relocations, causing construction delays and increased cost to city projects. The GURA provides that cities may consider quality of service among other factors in setting return for a utility. Given the above, DUCI has employed the lower end of the equity return rate of 10%, a 50 basis point reduction to adjust for quality of service. The dollar impact of the quality of service adjustment is $1.6 million in revenue requirement. The resulting recommended overall return in this case to be earned on invested capital is 8.64%. 27 SECTION VIII: EXPENSES TXU Gas has requested total O&M, depreciation and amortization expense for the N TX Metro of $102,110,198. DUCI is recommending a number of expense adjustments that result in a decrease of $14,016,530 to the Company's request. This is in line with our findings regarding other utilities which have been experiencing declining O&M expenses. Each of DUCI's adjustments to the Company's requested expenses are discussed below. A. Payroll Expenses TXU Gas is requesting a total labor expense in the amount of $24,038,249.31 This amount consists of base salary, overtime, incentives/bonuses, and other payroll costs based on test year payroll level. DUCI is recommending a total payroll expense of $22,542,206, or a reduction of $1,496,043 to the Company's request. This recommendation consists of three adjustments to the Company's proposed request. I 1. Updated Salary The first adjustment DUCI is proposing to the Company's payroll request is to update the payroll request through test year-end. The update will provide an employee level that will correspond more closely to the period when rates will be in effect. The Company's termination and hiring reports state that TXU Gas has experienced a decrease in employee levels throughout the test year. The Company has not taken this decrease in employee levels into account in its filing. Reviewing additional data provided by TXU Gas, the Company continues to show a decrease in employees through March 2002. DUCI has calculated the change in payroll based on these reports. DUCI is recommending a reduction of $337,044 to reflect employees who are no longer with the Company. 31 Company Schedule G-2.1, page 2 line 62. 28 2. Bonuses and Incentives TXU Gas is requesting $617,408 in bonus and incentive expense. The Company provided a description of each of its bonus plans. 32 Based on a review of the various plans, a majority of the bonuses are based on earnings performance enhancement and growth of the Company. As this will benefit the shareholders, the shareholders should pay the costs of such bonus programs. Based on the intent of the various plans to enhance the Company's earnings, DUCI recommends disallowing bonus/incentive costs in the amount of $617,408. 3. Overtime Adjustment The final payroll related adjustment is related to the excessive overtime the Company has included in the filing. In reviewing the Company's level of overtime, the requested level of overtime in this proceeding is over $541,591 higher than the average overtime expense experienced in the past 2 years. Given that rates are to be based on expected average operations (not unusually high or low cost operating periods), DUCI is recommending a reduction to overtime payroll in the amount of $541,591. B. Benefits TXU Gas is requesting $3,602,448 in employee benefits for the N TX Metro.33 DUCI is recommending a reduction of $230,347 to the Company's request. The reduction relates to DUCI's recommended decrease in payroll expenses. The Company's test year benefits are approximately 15% of salary expense. 34 DUCI is not proposing to change the Company's percentage of benefits to total payroll cost, at this time. DUCI is proposing a total reduction to payroll in the amount of $1,496,043. Therefore, to be consistent, DUCI is recommending a reduction of $230,347 for benefits costs associated with the reduction in payroll. 32 Company response to RFI 1-15. 33 Company response to 1-26. 34 Id. 29 C. Amortization of Merger Related Costs TXU Gas proposes recovery of $969,852 in amortization expense for merger related costs, 35 These costs relate to the TXU/Enserch merger that was completed in August 1997. In 1997, TXU Gas offered an early retirement package and incurred $44 million in costs. It has deferred these costs and amortized them over 15.4 years. The Company put in place another restruction reduction of employees in 1999, related to the merger completion. DUCI recommends removing the merger related costs for several reasons. First, these are non-recurring costs, and rates in this case should not be based on non-recurring costs. Second, while the Company requests recovery of merger related cost, it does not propose an adjustment to reflect merger related synergy savings that the Company has previously received and not passed on to customers. Third, the RCT specifically denied the Company's recovery of these specific costs in Docket No. 9145.36 Therefore, a reduction of $969,852 is recommended to the Company's proposed revenue requirement. D. Normalization of Expenses TXU Gas is requesting $77,208,403 in O&M expenses (excluding cost of gas) in this case. Given that other utilities' costs are declining, this level of increase is not logical or reasonable. A cost of service is developed by taking a 12 -month level of costs and expenses (test year) and adjusting it for known and measurable changes. Expenses may be higher or lower during the test year compared to what the utility anticipates will occur in the future. The determination of the appropriate level of expenses is achieved by reviewing the expenses and events that occurred during the test year, reviewing what may transpire in the near term future when new rates will be in effect, and reviewing the historical level of expenses to determine the reasonableness of the test year level of costs. DUCI reviewed the Company's proposed expenses by account, and compared the Company's request with the prior 2 years' actual costs and cost levels found reasonable by the RCT in Docket No. 9145. In this review, DUCI noted 6 expense accounts that required further analysis and adjustment. Each of these accounts is discussed below. 35 Company's response to 1-17. 36 RCT Docket No. 9145, final order, FF 126. 30 The first account DUCI recommends normalizing is Account 887 — Maintenance of Mains. TXU Gas proposed maintenance of mains total expense of $5,992,320. The Company has stated in both prior cases and this current proceeding that it has replaced large amount of old plant in service. With the Company replacing old plant with new facilities, the maintenance expenses should decline, not increase from prior reasonable levels. The Company has further stated that this account was higher during the test year due to "catch up" associated with prior periods. Atypical costs corresponding to "catch up" activities should not be used to set average rates. An average of 2 to 3 years is a more reasonable level for these types of expense accounts. The requested Maintenance of Main expense of $6 million annually should be normalized. This was accomplished by taking the average of the past three years of actual experience. This results in a total N TX Metro expense of $4,756,902, or a reduction of $1,235,418 from the Company's request. This adjustment eliminates non-recurring and atypical maintenance expenses. The second normalization adjustment is for Account 902 — Meter Reading. One of the key expenses that should have gone down due to the merger is customer accounts expenses. Electric and gas operations both had meter readers prior to the merger. After the 1997 merger, TXU combined the meter readers (i.e., one meter reader would read both electric and gas meters), due to an overall 2/3 customer overlap between the systems. One would anticipate these costs to decrease, not increase. Instead, TXU Gas' requested expense is over $800,000 higher in the current proceeding compared to the average over the past 3 years and over $1,000,000 higher compared to the two years prior to the inflated test year level. DUCI is conservatively recommending a 3 -year average as a reasonable normalized level., This recommendation results in a Meter Reading expense amount of $4,297,334, or an $820,839 reduction to the Company's request. The next adjustment is to Account 903 — Customer Records. This account is overstated in the test year due in part to the significant increase of gas cost during the winter of 2000-2001. The higher gas cost combined with colder weather resulted in a dramatic increased level of calls from customers, higher than normal late payments, and overall customer related activities due to the unusually higher bills. Using a gas cost level that is not indicative of the future is not fair or 31 MM reasonable to ratepayers. Therefore, DUCI is recommending reliance on a 2 -year average for Account 903 costs. This results in a reduction to Account 903 of $2,138,452. Similarly, test year levels for Account 923, Outside Services and Account 925, Injuries and Damages are excessive compared to prior levels. Rates should not be based on atypical cost levels. The higher level in these accounts is not indicative of what can and may occur during the period rates will be in effect. For Account 923, the Company has stated that changes in accounting for the test year and unusual shifts in costs have caused this increase. Rates should not be based on unusual, atypical events. For Account 925, the Company historically experienced relatively lower cost levels rather than the significant increase reflected for the test year. Therefore, an average level over a few years is a more reasonable approach for setting rates. DUCI is recommending a 2 -year average on each of these accounts, excluding the test year level of costs. This results in a total expense for Account 923 of $13,309,248, or a reduction of $2,124,208. Account 925 adjustment results in a reduction of $1,331,968 to the Company's test year expense of $2,747,043. 1 The final normalization adjustment DUCI is proposing is to Account 931 — Rents. TXU Gas is asking for approximately $800,000 more in rent expense for the N TX Metro compared to the 2 years prior to the test year. Subsequent to the merger between Enserch and TXU, the Company changed its policy from owning buildings to renting. Therefore, it transferred buildings to its noxi -regulated affiliate, and in turn, the affiliate rents them back to TXU Gas. The sale- transfer occurred at net book value. These buildings were heavily depreciated and, if retained, would have resulted in a lower expense to the N TX Metro. The Company now requests an increase of rent expenses 3 times higher than the prior level. The Company has not justified how the transfer of assets and in turn higher rent expense is more beneficial to the ratepayer. DUCI is recommending rent expense of $262,686, which represents an average of the 2 years prior to the test year. This results in a reduction of $799,916. The combination of these six normalization expenses results in a reduction to the Company's proposed cost of service in the amount of $8,450,821. These adjustments reduce the Company's level of its cost of service to a more reasonable and appropriate level. E. Labor and Growth Adjustments 32 The Company has requested an increase of $1,260,035 related to an increase in customers. The adjustment is premised on a belief that the increase in customer level will proportionally increase O&M expense. This is simply not correct. One should see synergies as customer levels increase. Costs should be based on a test year level of expenses adjusted for known and measurable changes to reflect a level that will be representative during the near term future. DUCI recommends disallowing this adjustment in the amount of $1,260,035. F. Uncollectibles TXU Gas claims that its uncollectible expense was $6,565,245 in the test year. The Company has proposed to include $1,673,688 in annual test year cost of service expense and surcharge the additional $4,891,557 over a one-year time period to collect the additional uncollectible expense the Company incurred during the test year. 37 The higher costs during the test year was due in part to the very unusual run up in gas costs, and a colder than normal winter. DUCI recommends two adjustments to the Company's proposed uncollectible expenses. First, DUCI recommends a reduction to the Company's requested level of uncollectible expense to reflect a normalized 2 -year average (1999 and 2000). This results in an uncollectible expense of $1,198,478. In reviewing the Company's historical data, DUCI's recommended $1,198,478 level is more in line with what more likely will occur in the future as the cost of gas has declined significantly from the 2000-2001 winter period. TABLE 8 UNCOLLECTIBLE EXPENSE HISTORICAL COMPARISON As can be seen from the table above, the test year level of uncollectible expense is excessive compared to the historical level of expense. The winter of 2000-2001 was an extremely unusual year. .Gas prices increased significantly, which caused gas bills to be much higher than normal. Ratepayers incurred very high bills from TXU Gas and some were not able to keep up with the increase. This caused the Company's uncollectible expense to increase 33 during the test year. Gas prices have now come down to much lower levels. Since rates are not calculated using abnormal and atypical events, the test year level of expense should not be used to set a level for the future. DUCI recommends an average of the prior 2 years' expenses or $1,198,478 for test year expenses to reflect a level that is reasonably anticipated to occur during the future. This results in a reduction of $475,210 to the Company's request. The second adjustment DUCI is recommending to the Company's request is to disallow the Company's surcharge of the additional amount of expense incurred during the test year. Rates are developed using a "test year" level of costs. This does not mean that each year while rates are in effect each expense amount will remain at the same level as determined in the rate proceeding. Overall, expenses should remain at the level close to the level determined in the rate proceeding. Some expenses will go down and others up, but overall the level should remain relatively consistent with the ordered level. If enough costs/expenses increase overall, then the Company has the option to file for an increase in rates. The new rate case will be used to determine new rates to be charged in the future, not retroactively. Retroactive ratemaking is not allowed. However, this is precisely, what the Company is proposing. It wants to surcharge an expense it incurred in the past (approximately 1 %2 years ago) and collect from ratepayers in the future. The Company's request is also a form of piece -meal ratemaking and should be denied. G. Depreciation Expense DUCI is recommending two adjustments to the Company's proposed plant in service. These adjustments are to remove relocations and remove plant that was not completed by test year end. This results in a reduction to plant in the amount of $17,221,662. These adjustments are discussed in Section IX. DUCI has reduced depreciation expense in the amount of $537,316 to reflect the reduction of plant. 38 This amount was calculated by multiplying the plant reduction by the depreciation rate for Distribution plant of 3.12%. 37 Company's Schedule L-6. 38 Plant reduction. 34 H. Amortization Expense — Safety Compliance Program 19 TXU Gas has requested $941,274 in amortization expense for its Safety Compliance Program. The expense is based on amortizing the Company's requested Safety Compliance Program cost included in the rate base over 15 years. 39 DUCI recommends modifying the amortization period. It is inappropriate to propose a 15 -year amortization period for an asset that TXU Gas claims had a remaining life of approximately 41 years. Therefore, DUCI is recommending amortizing the asset over 41 years. This results in a total annual amortization expense of $344,369 or a reduction of $596,906 to the Company's proposed request. 39 Safety Compliance Program of $14,119,117 divided by 15 years. 35 LOWN 104M IM -1 9 A. Safety Compliance Program The Company has included $14,119,117 in rate base for additional investment for the safety compliance program. The safety compliance program is related to replacing the defective "Poly I pipe." The defective pipe was purchased from an affiliate that profited from the original sale, but ratepayers are asked to pay the full replacement cost of this defective product. DUCI recommends that the burden of these pipe replacements at a minimum be shared between the Company and the ratepayer. Therefore, a return of such plant over the 41 -year remaining life ensures the Company receives the recovery of its investment. However, customers should not have to pay a return on the unamortized balance of these investments. This approach shares the burden between the Company who purchased defective pipe from an affiliate and customers who received limited use of the investment. B. Cash Working Capitaf ("CWC") CWC represents the component of rate base that accounts for the day-to-day cash requirements of the Company that are not already addressed elsewhere in the cost of service analysis. This Company, or its affiliate, at the RCT, has recently litigated the calculation procedure for this component of rate base. In each litigation, the Company's approach was denied. Therefore, the proper calculation of the CWC requirement in this case should be relatively straightforward. For the most part, the Company's request for CWC does comply with RCT recent decisions. However, the Company failed to update numerical data for one significant known and measurable change that occurred since the RCT decisions. The significant change is that the Company now securitizes approximately 73% of its revenues, a level significantly greater than the approximate 23% level it� experienced at the time of the RCT case. Securitization of revenues is similar to selling accounts receivable to an outside party in order to obtain cash on a timelier basis. If cash is received on a more timely basis, it reduces CWC requirements, or as is the case for TXU Gas, it makes the CWC requirement more negative than the level proposed in 36 its filing. Recognition of the higher level of securitization of accounts receivable reduces the 19 Company's revenue lag from 30.336 days to 21.445 days. This change reduces TXU Gas' CWC request from a negative $17,353,815 to a negative $25,275,022, on a stand-alone basis. Due to the interactive impact of other adjustments, the level of this adjustment will be reduced when other recommended expense and tax changes are combined in the overall cost of service analysis. C. Prepayments The Company's request reflects a significant level of prepayments associated with local franchise fees. The Company has incorrectly characterized these payments as prepayments. These payments are paid in arrears. Correction of this error reduces the amount in rate base by $2,302,877. D. Relocation TXU Gas has included $16,7,million in plant investment associated with pipe relocations. Such relocations are city specific and the costs associated with the relocations should be paid by the party causing such costs to be incurred. The GURA §104.112 provides an alternative mechanism by which the Company may recover these amounts through a surcharge mechanism. DUCI recommends removing $16.7 million of relocation investment from the calculation of base rates in this case. TXU Gas has an opportunity to recover those cost from the particular entities that caused these costs to be incurred, through a surcharge under GURA § 104.112. E. Construction Work in Process ("CWIP") TXU Gas has requested gross plant in the amount of $749,563,229. In reviewing the Company's response to recently completed plant, DUCI noted $521,662 in plant was not used and useful by test year end. For plant to be considered in TXU Gas' revenue requirement, it must have been completed by September 30, 2001. Utility companies are normally not allowed 37 to include CWIP in revenue requirement unless there is a financial integrity issue. Clearly, that is not the case for TXU Gas. Plant in service is treated differently than expenses. It is recorded as of the last day of the test year. It normally does not reflect a future or normalized level. If the Company has additional plant that comes on-line after the end of the test year, it can request plant increases in the next proceeding. The Company does not lose the opportunity to include the additional plant, which goes into service prior to the beginning of the next rate case, unlike expenses. Therefore, DUCI is recommending a reduction to plant in the amount of $521,662 related to CWIP, which was not used or useful in the test year. This results in approximately a $97,311 reduction to the Company's revenue requirement. I 38 SECTION X: FEDERAL INCOME TAXES The Company has requested $15,017,592 in its revenue requirement for Federal Income Taxes ("FIT"). DUCI is recommending a total FIT expense of $11,036,112. This adjustment relates exclusively to DUCI's recommended rate of return discussed in Section VI and DUCI's recommended adjustments to rate base discussed in Section IX. DUCI is not recommending any adjustments to the Company's calculation of FIT. u 39 SECTION XI: TAXES OTHER THAN FIT A. Revenue Related Taxes TXU Gas has proposed a total revenue related effective tax factor of 5.076%. The following table breaks down each component of its effective rates. REVENUE RELATED TAXES DUCI is not recommending any adjustment to the Company's percentages. However, a reduction of $1,406,567 is being recommended as a result of other adjustments recommended by DUCI in the Company's proposed revenue requirement. B. Property Taxes TXU Gas is requesting $7,653,392 in property tax expense. DUCI recommends reversing the Company's proposed $1,032,456 property tax expense increase for the test year. TXU Gas proposed an adjustment to property tax to reflect the difference between the assessed value verses the actual tax paid in a calendar year. In fact, TXU Gas paid a significantly lower tax amount for 2001 than it was assessed. Therefore, DUCI recommends an adjustment to the Company's proposed expense, resulting in a total adjusted property tax expense of $6,620,936. C. Payroll Taxes T TXU Gas is requesting payroll taxes in the amount of $1,861,969. TXU Gas based its request on an effective tax rate-aof 7.7459%.40 DUCI is recommending a reduction to payroll taxes in the amount of $115,882, based on its recommended reduction of payroll expense. 40 Company's Schedule G-9. 40 SECTION XII: RATE DESIGN The last aspect of this rate review is the ultimate rate design. Once theappropriate level p � of base rate revenue requirements have been established and allocated to rate classes, individual customer class rates can be developed. As previously noted, DUCI recommends that a rate not be established for the industrial customer class. Moreover, development of new residential and commercial customer rates, corresponding to the revenue requirements of each class, possess unique concerns in this case. This case represents a situation where numerous different city rate jurisdictions are being merged into a single large system that will encompass over 100 cities. When different rate jurisdictions, with different rates for each customer class, are combined into a single average rate for the new system, certain cities will experience a greater than average rate change while others will experience a rate change less than the average. Therefore, DUCI is proposing three different alternatives for the Cities' consideration. The three alternatives are: (1) to deny TXU Gas' request for a rate change, (2) implement a set percentage change for each base rate component of each rate, or (3) adopt the same average N TX Metro rate for each residential and commercial customer no matter which city the customer is located in. If the Cities elect to deny the Company's proposed rate change, then the existing rates applicable in each of the numerous rate jurisdictions stays the same. This leaves each jurisdiction in the same relative position, compared to the other rate jurisdictions being combined in this case, as they were in before the Company's request. The second alternative is to implement a constant 2.26% reduction to each base rate component of each tariff for each of the current rate jurisdictions. In other words, each existing customer and commodity or volume charge within each current rate jurisdiction (e.g., Northwest Metro, Northeast Metro, etc.) would change by the same identical percent (2.26%). This approach leaves each of the existing rate jurisdictions in approximately the same relative position after the rate change as was in place before TXU Gas' proposed combination of systems. If this alternative is selected, it will be necessary to remove gas costs from the tariff rates in those cities where it is included in the tariff charges prior to application of the percentage reduction. 41 THE NORTH TEXAS METROPLE Addison Forest Allen Fa ft VV Anna Frisco AF, yle -Gartan Arlirlgtoit Glenn Aubrey Grand Azle Grape Balch Springs Hatto Bedford` Haslet Senbrook Heath Blue Mound Hickory ,Blue Ridge r Highia Burleson Hurst Carrollton Hutchi Cedar Hitt Irving -'Celina Joseph Colleyville Justin Coppell Keller Copper Canyon Kenn e Corinth Krum Corral City Lake Cross ,Roads Lake Crowtey Lakesi balworthingtori Gardens Lanca Denton ` Lavon DeSoto Lewisv Double Oak Lincoln Duncanville Little E Edgectiff Village Mansfi Euless Marsh Everman McKin Fairview Meliss Farmers Branch Mesqu Farmersvilie Mobile Fate Murphy Flower Mound Nevad< m Dallasr Worth; ster atl'Creek ney a SctiEOULE 1 X Df8TRIE UTION SYS'T'EM INCLUDES: North Richland Hills oritr l ' Narthial�e - Qvitla d Pantego Helga is 06rker Frame Pilot Point vine Piano Cif Ponder Princeton Creek Prosper Richardson nd Village Richland Hills River Oaks ns Roanoke Rockwall ine I Rowlett 1 Royse City l Sachse dale Saginaw Sanger Sansom Park.Village Seagoville de Shady Shores Southlake Sunnyvale isle The Colony Part Trophy Club Im Watauga; eld Westlake Westminster, L Westover Hills Westworth Village ite White Settlement City; Witmer - Wylie BE CE 2 JROPLEX IREMENT TEMBER 3Q, 2001 83 tl 94 2 B.fi3952L7 fi- ADJUSTMENTS TXU GAS DISTR 56.352;743 NtORTH TEXAS �UI $ 2.984,4GU REVENUE REQU TESTYEAR ENQED 5EP , LL14155.5D't COMPANY`S S427,B45,842 PRESENZRATES'; Oueratino'Reienues: - t 5437 775 5.3.6 3 0 Residential 5273,395,1 Gomrt erc ai 130,851 34 Industrial 14,255.50 Total S4 t 8,499.03 Other R'even6e 3 93 6 t nsc,i 12 ! i 7.394.176 TOTAL'OPERATING REvr=14UE§ - S*QZ42573 Operating Expenses_ 'Gas Cost. S261,285.15 a Operation& Maintemnce Exp 77,208,40 Taxes Other Than FIT 34.352.83 OepredaCon $ Amortization : 24,901,79 j Interest on Customer Deposits' 5 638,63 Federal Indome Taxes t5,D17,69 ReWmon Rate Base 42.874;39 TOTAL REVENUE Rg COUIREMENT t c 7 { i i ra P F f. t t , CE 2 JROPLEX IREMENT TEMBER 3Q, 2001 83 tl 94 2 B.fi3952L7 bUCI`S ADJUSTMENTS FECOh1MENDATtON 56.352;743 5279,737.92v $ 2.984,4GU 33,?,,M2.409 7 Q LL14155.5D't 9 S9,346,803 S427,B45,842 4� 3:930.gc4_ 3 S2 3b6 803 5437 775 5.3.6 3 0 t 521 2SS,i 53: 3 `12.642,392 c4,5o6,0t3' 9 2.554;965 34.797,934 5 1.134,222 23,767,573 4 0 638.634 3 2 3.981,480 t nsc,i 12 ! i 7.394.176 35:9 50.21 T 7 011� G4:8.571 714 3 a 1 'i j SC DULE 3 TxU j? i GAS D1S*18UTIION NORTH TEXAS DISTRIBUTION SYSTEM COMPANY'SPROPOSED REVENUE REQUIREMENT TEST-YEAR ENDED SEPTEMBER,30, 2001 I s LINEPRESENT; R PROPOSED PROPOSED PERCENT Nom, )EESCRIPTION RATES E RATES JNCRFA ;g. IN READ 1 OPERATING REVENUES 2 RESIDENTIAL 5273.3€35,13 S298.173.541 524,788,358 9.07!4: COM iERCIAL 3130.858;349 $137,257,322. 56,398,973 4M% 4 INDUSTRIAL $14;255,5137 $16,917,272 $2;661.765 18.670! 5 SUBTOTAL $418,499.02 9" $462,348,135- 533,849,096-" 8.0-9% 6: OTHER REtiE!WES S3 926'191 $3:930,694 1 $4,5503 .1101 7 TOTAL OPE RAZING REMWES $422:425.430 4 r 78 829 S33.853.599" �°f 8 9' DESCRIPTION TOTAL RESIDENTIA! COMMERCIAL INDU RIA .� _SL. 10 REVENUES $422,4255,234 5275,956,126 5131195,493. 514,273,4 11 TOTAL REVENUE REQ.UIREMENT 12 DESCRIPTION TOTAL ( RESIDENTIAL COMMI=RCIAL INDUSTRIAL. 13 OPERATING EXPENSES 14 TOTAL GAS COST $261,285,153 5162,762.954 594,320,423` S4,201 .786 15 OPERATION MAIN TENANCEEXP. $77208.399S64,216.04'5 511,001,400 S5 16 PRO°ERTYTAX $6,758,920 55,258.309 S1,1Z6,238 5324,313 17 PAYROLL TAX $1,861,959 81,545,716 S270.589 $45;665 18 REVENUE RELATED "TAXES, 521,442,45$ $14.007,321 S6,704,734 S730,403- 19 OEI?RECIATIaN 8 All . RTIZATIQN S24,901Y,5 $19,373,334 54.333,599 51,194,862 20 INT ERSTONCUStDEPOSITS. 5625,699 S423,153 $202,546 S0- 21 INTEREST ;ON CUST:ADVANCES 512,935 " S8,748 $4,187 so- n22 22 FEDERAL (NMMES,TAXES4 670 163 $80_ 7 5� $3.711,705 1 765:930: 23 TOTALEXPENSES : $398,767,491 $268,788,118 S121,725,422 510.253;913 24 RETURN 01`4fWTEBASE $23,657.739 $10,168,008: 59,4"70;076 S4:019;584 -25 REOUIRED'RETURN ON RATE BASE $42,874,393 $33,390:495 S7 373;911 52,109;986 26 RATE DEFICIENCY : $99;216,654- 523,222,487 (32;096,164) (51,909,598) 27 ADDITIONAL FIT REQUIREMENT 510,347,429 512.504.416 ($1128.704 (S 1,02&24 5) 28 OTHER RATE REOL11REMENTS. $2,571,083 $1,886,123 8568;633 5116,328 29 RATE INCREASE REQUIRED $32;135;1¢6 537,613,025 ($2;656,2365) (52,8211515) 30 REVENUE RELATED TAXES $9,718.4641122 553 SQ7.3211, 58:535 31 REQUIREDINerf2EA$E $3+3,$0irJ7$ 538.73504` (SZ;1M9 16) {52,782,880} 32 OTHER REVENUE INCREASE 4 634 54.614 S0` SG 33 SALES tkREASE' 533,848,961 S38,736.966, (S2,T18;915): (S2,762,G$0) 34 CbmPANY CL. iI iEG WCREASE $33.849.0 S38-,731,478 ($2:119:187), ($2:71:3,195}. 35 DIFFERENCE (5135) ($5121 $272 5215 36 PROPOSEDREVEWUES: - $456,278940 5315,692,218 S129070319 ti MQ.301 37 OTHER REVENUES $3,92(x,101 53,570,943" $337,149 517,�g9 38 SALES REVENUES' $45234&.135S3"2,116.6El 5128.739.162 ,St1442„a2 , FM E i mw r SCHEDULE d TXLl GAS O'l$TRtt]UTION PR!{7R. NORTHWEST ME7`RDPLEX CITIES COMPARItJG. PRIOR.,RATE-1fANQES TO CURRENT'CASE TOTAL i COMPANY RPfE INCR. COMPANY RATE 31R6QUARTER 2001. ', INCR. MARC'd 2002 LINE NWMETRO . NW METRO NO: 61ty, TOTAL _I TOTAL' DELTA.' 1 ADDISQIV `$179,334 $254,533: 575.199 2 ARGYLE ($549J 517.437 517,986 3. ARLINGTON $9$9,915 $2,91h,994 51,925.079 _4 AUBREY {�12,646j S21,D30 533;682 5 BEDFORD $138,475 $394,720 $256,245 6 CARROLLTON 11.333,720 $1,570,493 $236,773 7 COLLEYVILLE 3 $7,511 '5359,187 S351:676 8 COPPELL. ($19;342): - $539,715 5559,057 9: COPPER CANYON $31 5916 5885 10 CORINTH($139,60$) 5164,193 S303,79a 111 CROSS ROADS (S93) $0 eo3 12 ; DALWORTHtNGT'ON GARDENS X53,892 $34,100 530.20$ I 13 ' b NTON. �5885,8a8 . $1,207,537 5321,079 14 DOUBLE OAK $$94 S10.664 $9,770 15: EULESS $165,788 5363,7$6 �iG7'.9G3 16 FARMERS BRANCH '$537,833_ 5568.946: $31,113 17 FLOWER MOUND 515"4,459 5832,271 - $675,812 j 18 GRAPEVINE 528085 $675.432: $390.447 19 HICKORY GREEK $2,031 $26.753 .$24,727-- 24,72220 20- HlGHL ND VILLAGE $27,710 $224,788 5197,078 � 21 HURST $188;320 $454,053 $265.733 22 IRVjNG 5.1,935,071 $2;128,238 5193;167 23 JUSTIN (59,113) S33.394 542,507 24 KELLER , �u112,552 $434,213 - $4321,661 25 KRUM $13,689 527.977 $14,2SS 26 LAKE DALLAS $9,068 S82,000S�3;G55 j 27 LEWtSVILLE $165,2f4 $833,901 $568.641 28 LINCOLN PARK: ($12,053) $2,295 $1;..34$ 29 MANSFIELD $159;20$ 5282,968 5123,760 30 ' MARSHALL CREEK Sil,630 53,477 (53,213} 31 NORTHLAKE $0 51,265 ' S1.265 32 PANTEGO $16,597 840.917 51 326 33 : PILOT POINT 547.127 $73;873 34 PONDER; 511,192 58,062. 3.5 ROA,NOKE 546:320 529;366 (510 95:1} 36 SANGER ; ($29,963) $50,691 810,854 S7 SHADY SHORES jS17,614} $15,132 _ 536;146 38 SOUTHLAKE } 5396 S433,564 $433,168 39 TRflPHYCLUB, $9788 $46,420 536.�j32 40 WESTL7kKE 52, 82 513,188 _ S10,40# � 41 OTHER 385 12 $0 (5385.212} 42 TOTAL, 57.50U% 515:133.812 S7,624.416 E i mw SCHEDULES Page t of 3. TXVGAS DISTRIBUTION NOnTli,TEXAS METROPCEX iiiSTRfBUTtON SYSTENt PRIOR CASE DATA AND CURRENT PROPOSED REVENUE`INCREASE jDE kEASE) PRIOR RATE CASE' CURRENT DATE LAST PROPOSM - LM M 1EST AR, APPRQVET 1 REOPESTED S RA-¢ CHNG INCREASE DIFFERENCE I Addison 9/30100 $163,161 11189;167 8/28701 $254,533 $91,372 2 Allen 12/31/93 $230,876 5508,616 1/23101 $625,582 $394,706 31 Annie 9130100 $25.669 $27,683 916101 $9.171 -$16,498 4 Argyle 9130100 $1,542 -$50 7131101 $17,437 $18,979 5 Arlirigton 9130!00 $641;310' $1,357,568 8117/01 $2_,914,994 $2,273,684 6 .Aubrey 9130100 -515.810 -$13,697 811101 $21.015 $36,825 7 Azle I20,I99 564,507 591,659 11311.01 $27,947 -$36',560 ' 8 .Hatch Springs 92r31KJr $109,050 $109,050 518101 $108,693. -6351 9 Bedford 9130100 $69,467 $167,403 9/13101 $394,720. $325,253 1.0 Bentook. 12/31W $33,096 $95,984 2/9101 $62;328 $29,232 _ 11 Blue Mound 12131199 $18,266 $27,824 2/5101 S17,336 -S930 12 Blue Ridge 00/00 4781 $2,964 .916101 $4;732 $51513 13 Burf4soh '12/31/99 $170,651 $178,050 2!12101 $74,221 -$36,430 144 Carrolton 3130/00 $1,115,423 $1,820,688 8121/01 51,570,493 5455,070 15 CedarHi{j 6130186 $52;509 $52;509 9/4187 -$52,199 -$104,708 16 Colima MOM $20,1601 1 $10,303 8131101 $15,644 ,-$4,960 17 'Coll eyvMe 9130100 -$27;711 $3.,768 9119161 .$359,187 $386.898 .18 Coppell 9130100 -S1381594 -$25,701 8/9701 $539,716 $676,310 19 Capper Canyon 9130100 -$159 $7 817101 $916 $1,075 20 Corinth 9/30100' -$1901916 4123;986 4!30101 5164,193 S355,109 21 Coral City None None. None 12/2218T $564 $564 22 Cross Roads 9/30100 -$202 -$95 110100 $0 5202 23 'Crowley , 12/31199 S16,918 $34,409 VIZ101 $5T,825 540,907 24 DaAvorthingtonGdris 9P30/00 1 -$1,449 $3,530 9118104 :$34;100 $35,549 25.Denton 9130100 $1,307,759 $1,205,583 7131101 $1,207,538 -5100,221 26 b6806 12131197 $164,576 $322,914 3123199 $214,654 S50,078 27 Double aak 91311;00 -$1,720 5687 918101 $10,664 S12;334 28 Duncanville 12,31/98 $340,678 S484,707 2/16/00 5127;707 5212;971 29 Edgecli f Wilage 12131/99 $3,216 $16,261. 217101 $12,827 - 59,611 30 Euless 9130100 587.941 S208,711 811.6101 $363,785" $2.75,844 31' Evernian 12431/99 $2;591 $27,259 2114101 $26,108 S23,817 32` Fairview 12/31139 $5;374 t 513,218 21T101 516149 $10,775 33 Farmers Branch: 9190100 S420,976 5806,487 9110/01 5568;946' 5447,970 34' Farmersviite, 9130/00 $11,746 $43,009 9/19101 $28.628 S16,882 35. Fate 9130100 551124 -S3,860 8122101 52,24S, 57,373 36.FloweeM,ound g/30106 -581,244 5227,188 8/8101 x832.270 S913,514 37 forest ! -till 121,:31199 $33,305 5102,219 2114104 563;080 529;775 38 Fod Worth 12131139 52;948,582 $5,116,916 2/6101 $3,896;259 S947,677 39 Frisco 12/31/99 $230,751, $412,185 1/261111 $51T,436 5231,735 49 Girland 12131199 Si,263;914 $2,126,156 5110iol 52.153,835 5889.$22 $11,51s $1.5985 $58,647 $23,149 S,5,906- $89,126 '. $2,417 $964,878 $3,891 ._ 315.58/ $22,364 1 5195,150 ' -51.739 $439,453 $14,326 70 Mesquite 12/31/97 $943,959 $13;308 -5752 $49x78 . $4,$e9 $98,531 $6,644 536;646 78 Parker 1213/199 '$2,109 $3,295 573;772 - $1;d32.0$4 $576 $35;918 533,470 S648,544 85 540.341 543..198 "+7,823 -3:ta9.25o l SCFiEDt3LE 5 s Page 2 of 3 41 Glenp Tifthts 12131/.97 $16;714 a $33,977 4130199, 428,433 311.719 42. Grand Prairie i7J31197 1149,127 3264, ,d gM/OQ $1,217,865 $1,068738 43 Grapeuz�, a 9/30100 $171,883 , $340,757 8124101 $675,432 $SO3,W 44 Rglt6in City 2 f31i99 $1441275 $349,679 'i115I04 $235,754 $93,484 .I NasleE 12(31/99 -$33,007 421,067' 2./Nof $3,955 $37,862 46 Heath 9130100 $72,880 $100,956 8122Ol $19,328 -$53,552 47 Fiici otj�'reek 9/301Q0 -$674 51,550• 8/2/4!1 $26,753 $27,427 48 HighfairdViilage. 9/30/00 -$29,607 $25,084 813T(01 $2241789 $254,396 49 Hurst . 9/30100 $86.617 $209,971 846,141 $454,053 $367,436 50 Hutchins' 6130190 56;448• f $13,074 612V91 $81,033 $74;585 59 Irvingi 9/30100 $1,272,078 32.408.076 9112101 32.128,239 3356,161 52 J,asephinb 9130160 34.,950 $6250 9119!01 $2,866 -$2,084 53 Justin 9130!00 -$11,128 -$9,399" 8110101 $33,394 $44,522 54 Keller 9130100$44;748 ;$119,419 9l10101 $434,212 $389;464 55 Kennedale 12131/95 $11;297 $2&,7so 2(131oi $?2,s�z 56 Krum 9130104 51.1:9.93 $14,769 8!/3!01 $27,978 57 Lake Dallas 9130100 $3,416 $9,398 8/21171 $62,063 58 Lake Worth 12t3i1g9 $10,693 s $46,993, 315/01 $33,842 59 Lakesidd 12131199: $585:. $1,478. 3!2/01 $8,49'1 60 Lancaster 61'30194 $64,919 <$130;7f2 6(17(91 .$154,045 61 Lavdn 12131199 $520 $1,578 2/19101 ......'$2,937 62 Lewisvjlte 9130100 -$13x,978, $416,168 819141 $833,900 63 Lillian '' _$3,891.. 64 Lincoln Park 9130100 -513,267 -$12,0110 4!27/0# $2;294 65 Littl6`Elin: 12131/99: $7,23.066 $19,775 1/24(01 $29;594' Mansfield 9130M0 $87,817 $275,937 9(4101 $282,867 67 Marshall Creek 9!30/00 - $5;216 $6,652 8124101 $3,477 68 VcKinney 12131/99 S408,081 $743,862 1131/01 $847,534 69 Melissa - 9130160 -$9,969 -$6,9/0 916rro1 $4,h17 $943,959 5!8"'01 $957,267 71 Mobile C4. 9!30100 51;833 $2,403 9/2110/ 51;081 72 Murphy 12/31/99 $10,67 529,623 2/1210! $60,657 73 Nevada 9/30100' $5,814 s $12,893 4i'�910f .510,683, 74 Norah Rlohtand Hills 112J3.1199 5,158,314 $344,459 2113101 $257,145 75 ;t�ortfitake 9/30100 $2 52 8l6/Q1 $1.264 S1,Z6? 76 CYvfita 12,/31197 31;223 $3,936 3131/99.. $7�8fi7 77 Fanlego 9"'30100 $4;$76 $/5,982 9(5101 $40,916 � s�,a7a zrftitl $s,4oa 79 Filot Point 9130/Ota > -526;646 z -$26;581 8127101 $47,126 80 Ptana 12131199 51,531.1 34 $3,283,554 1123/01 52,963;2/8 81 : Ponder 9130100 S1,992 $11,555 8!6101 $3;062 82 Princelto ri 9/30100 516,411 : $23,832 W7101 $16,9$7 83 Prosper ; 12%31199 -522,040 !_$13;111 1111(01 513878 84 Rendon $"33,1}7sr 85 Rfgc ardson 42.131199 5631;984.. $1,341,028 2(1141 $1,280,523 Rkhranrt Wis 12131x'99 324,988 ? $96,351 211410E 565;329 87 kiver Oaks 121'31199 516,080 575,014 311!01 $5$,275 Sa Roanoke 9130/00 537190 !; $47;129 819101 529,3x7 89 "Rockwati 9130199 5276?22 34/7,205 1.0720!00 S127,072. $11,51s $1.5985 $58,647 $23,149 S,5,906- $89,126 '. $2,417 $964,878 $3,891 ._ 315.58/ $22,364 1 5195,150 ' -51.739 $439,453 $14,326 70 Mesquite 12/31/97 $943,959 $13;308 -5752 $49x78 . $4,$e9 $98,531 $6,644 536;646 78 Parker 1213/199 '$2,109 $3,295 573;772 - $1;d32.0$4 $576 $35;918 533,470 S648,544 85 540.341 543..198 "+7,823 -3:ta9.25o SCNEDULE5 r s Page 3 of 3 9Q f owlmr 1219;1199 $T86,640 $465,199 112810', 55+33;798 $377.153 Sri .RAYseCity 9i3(>tOQ 426,647 u1.7,06k -8121401, S1&324' $42073 92 Sacti613 't-2131199 $37;612 M3 4W 21f51ot $144,494 $!'0'$,382 93 Saginaw 12131199 5931500. $119;733. 2.151.01, 598,100 34,6fl0 94 SangeP 9!34100 344;126 -$.28,2473;` .8 vffi 1 $50,690 $94`,8116 95 Sansdfb Park.VUlage 12/31/99 $7,647 $36,4!7 21M) 528,90T 521254 96 Seagovie /2131/97 551.189 $51,18!! $18701: $70:672 $19,483 97 ShatlyShores 913(100 421,256 517.200 $12101 $19,132 $40,388 98 Southlake 9!30!04 -$59,293 $783', 61101A1 $433,563 $492,856 99' Sunnyvale. 12131197 $25,961 $25,961 518/01 $30,975 $5,014 100 Ttie Colony 'I2t31/99 : $41,107 $1072tl6 1129XI 3116,5$7 $75,480 101 Trophy Cit4b 9,t moo $1,956 $9,032 8124/01 :$46,419 $44.463 102 Watauga, . 12/31199 $17,858 $55,9!7` 2/9/ot 544,098 $26,240 103 Westtake 9130100 -5957 52,664 8/23101 $13,189 $14,146 104 Westminsier' 9(3.0/00 -51,044 -5591 916!01: 52;637 $3.681 105 Westover Kills 12131199 5836 $19,296: 2/26101 5101,458 $3,622 106 westwoith ViNaga 12/31199 $4,484 $23,609 2127(01 $17,754 $13;265 107 White Settlement 12131199 $43.,537 $121,881 2127MI $85,808 542,271 108 Wilmer 6/30190 $23,586. $26,144; 615191 111,537 -$12.049 109 Wylie.:. 12131199: $75,74412524,4 21161Q1 5131,489 $55.745 110 Daltas/NW Metro ,$T62.31 $782,31 SI5,45213S $29,017,707 s $33,855,538 518,40$,403 'Company Response is Cities RF! 2-2, Attachment 1. 2Executive Summarypages, 6,10. { SCHEULfLE q { P1kGE 'f OF 1 TXU GAS EN I8&164 NORTH TEXAS MET$OPLEX DISTRIBUTRON SYSTEM COST PEP .c4tSTomI E4R CUSTbMER ktlA'TEU COSiS BEFOREANO"AMR MERGER' =TE$T YEAR ENDED SEPTEMBEk 30, 2061 a OC:�1P1HI.7? `i .RRC REPORYP .RRC REPORT, RRC REPORT RRC REPORT RRC REP07tT RRC REPORT I>33" :3 343L. ]34E :.5323 ?OQq �. .CUSTOMER ACCOUNTS EXP6Sr;C 'SUPEFtVt,SKFI, SR..00} SfS.00 50.00 50.00 t 2 902 902 CUSTOMER ASSISTANCE EXPENSES 50.59 50.59 - $0.77 5020: 50.00 ..50.11 .00 SO>08 3 :903".;.CIISTC.t1Eii REGGRDSiCOIt.EC7tON E7tPE115ES 53:5'7 S3_�9' 512.99 ..5/288 STSB. 328.28 58.02.: S23.t8♦ 58,32. 5811 4 .804 UrK.OtLECri01.E rCQOlMT5 -" 33.05: 33,39 5244 St 56-: 528.02 5252 :. 32684 5 :905 MiSCE} ANeC {43 CUSTOMER ACCO NT8E%PEN$E5' ..50.00 : _SO DO 50.D0' 50.04 .: S9S2 6 tOTA4 CUSTOMER ACCOUkTS27(PENSES 520.20 .. 520.15 � 228.48 532$7 '.'.... 527,0? TOTAL CUSTOMER AG'f:OUNT$FXPENSES VWO 904 j2Pi4 $%T6 52502 .536.63 . 535.40'. $24.47. - 527.17 - 7 CUSTOMER SERVICE d SALES EXPENSES ... 50.00 50.00 $6.00 $0.00. 50:00 50.'30 8 9 909 910 SUPER14StON' CU3T0MEflit5S4STA. CE E[2>EN5ES - 50.00 `50.00 . $0.90 -50.00- SO 812 INFORMATIONAL ADVERTISING EXPENSES 50.00, SQ.00 SO.f .. .50.15.. $2.84 $D.07' ' 54.32'' ';a.02 55.04 43 t8 'S0.48 ti '12 912 975 MISCELLANEOUS CUSTCtAER SERVICE EXPENSES SUPEFivimm 50.00. '.50,00: .40.00. $0.03. - $4.00 50.00 13 976 DEMONSTRATION B SELUNIO EXPENSES $1.51 -,57.30 St.2�i '51.11 $Y.t9 Si.52' � '-.$0.13 �.SO.TJ ".. . � 50,05 $OAS 14 :917.. PROMOTIONALAOYERTISIR'G EXPENSES' ,. 50.00 50.00 .. $0.23 $0.05 $0.31 50:03 13 945 MISCELLANEOUS SALES PROMOTIO4 EXP� SO.tB .30,18 S0-06 50,10 S0.7T 15 TOTAL CusT SERVs SALES PROM. EXPE'NSE:S 23.0 32.74 54 .05 $0.94 , 28.65$5.50 - '.. 17 .. AOMiN75tRATPlE b GENERALEXPENSES I $OAO - SO= 50.00 50.00 50.00 'SO.CO t8 920 AOMtN15TRATWE i GENERAI.SALARIES .. $20.19 .517.40 52.87 $4.08 $207 50.99 19 022 OFFICE SUPPtIESEXPENSES 56.39 :.58.98 `53.62 5t „. 50.73 -.'50.81 822 AGNIii15TRATiVt; EXPENSES TRANSFERREDSREt3fT 52,80 .5222 30.D9 _65 $0.00. $ 0.00 5000 923 OUTS10ESakousEMPtOYEO :: ..50:53 5228 ;;529.235$0:04 524,97 22 924 RRORERTY RiSURANCE :53AT _ 52.82 (SO." SQ.63. 50.11 50.4$ I 923 INJURIES S DAMAGES S84, 5766 53.34 56.02 - 24.02 $: 9S a� + 926 EMPLQ'iEEPr`T, 35IC.VSA BENBtYTS St4,t8 513.04 `S18.0 $7.48 $6.29 57:74' 23 927 FRARMSE REOUIREMEN?S,,, : 50:60 .30.00. $6,00 $6.00: x : $0.00 50 00 . 28 929 REGULATORY COMmtSS164 EXPENS[S 50,1'7 -SI.18 S0.42 -5275 X$0.28 5093 -. ;27 '.28 929 DUPLJCATE 6WGES CRECHT $0.00 50.00 `50.00 - 50.00 50,60 $0.00 530.1 44ST, GOOOYdL AOYERT14NO EXPENSES x$0.00 :50.00 $6.07 30.00: �SOAi $0,00 29 9302 MLS'CELLANEOUS G64ERAL EXPENSES $0.82 S0.S823,74 54.23 $2,92 30 931 RENTS - _ 59.57 ::ALSO $0.24 50,43 .$1.20 .$3.23 'SIRS 37 932"NTENANCE GENERAL PLkHT - 24.23 .51.22 50.02 59.04: SO.DO 32 TOTAL AWAWISTRA4VE s' GENRAL EXPENSES 557.02 S58.96 :262.93 .: ... $47.$2 $J9„21 .50.00 '.54211 i 9 i _ SCN'cOUL£ 6" i PAGE? Or-, 2 TXU GAS DISTRIBUTION NORT}t TEXAS METROPLF-XbtSME(1TION SYSTEM £OST PER CUSTOMER FOl2 CUSTOMER ' SL�4TEFi COSTS BEFORE,AND AFTER MERGER TEST YEAR ENDED SFPTEMBER 30, 2001 .fERC.` FEfGtr FERC me " FERC' 'FERC TXU ELmiTtz .. FORgt FORM PORMi romI FOfU4I F9R511 yE'W rnu 36fS, ,..3993 20� CUSTONERAOCOU=tTSEXPERSES.. WOO, So Go .50.00 SO.Od s0.dd 50.00 4 40t SUPERV151ON50-x ". SSC._31) 30.00 . =0 SO.20 10-14 2 " 902 METER READ!NG $4.30. .1. 57;34 `S6.DZ $7.05 .. S8.29. _ 3$.67 .3 " 963 CUSTOMER REOORCS;3 OOLLECTXk7 53$294 "544.54 .:$43.68 .S43.Tt 541180'" .$3/.72 4 904 ViCOLLECTAILEACCOWTS $795;. S$.AS 5527 '340,44, $2.86: 58;7$, 5. 90b #.SCELLANEOUSCUST6UERACC=i-,S SOAS'. 50.00 .50.25 -. - EO GO �SD:OS Sa.Od 8 TOTAG.CUSTOMSR AOCOVMTS EXPENSES $520S': 537.72 - $54.18 261 -SW $51.14 .. $5031 T - TOTALOLISMMER ACCOUNTS EXPENSESw904 $44.14': .$52.82 - :$52.2i ,$S4,7A ".552.99 $4f.53 & CUSTIIMER SEANCE 31NFORMAVOUAL,EXPENSES SO.DO 50.00 "So= $0.00 50.00. 3004 9 :907" SUPERVtSKk: -" 11.97 "Sim 50,81 51.54 S120 $0.43 10 " 9G& (XUTOMEt2AS5t5UCEEX,-E1a5E Stx.87.; Sf8:98 52d17 S23.ii $21.0 Sz` 7 Ott 909 7NfORIAKt16NAC4iNSTRUCttONALEXPENSES 50.64 - 50.00 50.49 50,/5 ._.50.04 50.00 t2 Si0 MISCELLANEOUS GUST. SERV. t UVFORM'I EXP. 50,(!5'. 30.01 50.04 .:50.3{ 50.24 54.02 13 "TOTAL CUST. SERV 8 fWORACL EXP: - 520-51 ' $19.43 521,54 325.37 523.35 522.63 14 SALES EXPENSES 50.00:. 50.00 SO.OD 'SORA 50.00. $0.00 - I5 :.911 SUPERNSIQv .. 50.00" -$4.00 50.01 $003:. SO.OsT. `SO.CA) . i 16 912. OEMON5TR.i71ON dSELS.7NG ExPENSc: 50.00 .$0.39 '52.15 ZS -20 " 5283 5059 .. 17 '913 ADVERTtSiNOFXPENSES "._.. 50.00 50.00 S0.12 - $0.35 $1.09 50.36 1T. 916: MSCELLANEOUSSALE3 EXPEASES- S000'. 50.00 X5000 5276 52.04 $1.39 ... . 19 WrALSALES EXPENSES - SDAD r : M39 52.27 58.34 $5.95'. - 52.34 .... . 20 �AOMiN[S:7T2ATPf�a GENERAL E7CPENSE5" 5000'. .30.00 ,5000 SO OO SO.00 514.06 .. 21 920 AdG:SA4ARiES. - St},15 .. 511:54 59.SZ 56.27 37.34 574;00 22 921 OFF7CESUPPUSS EXPENSES: 53.56 ,.. $3.02 SZ.82 $1.84 ' - 53.25 $4.35 Z3 922 AOMiNfSTRATNT EXPENSES -CREDIT 50.00: $0"00. $0.00 52066. 58.85 53.36 24 ;$i;- Dubs JE'SERvims - - 54011.: :$43.26 54262 528.30: 543.64 569:53 25 924 PROPERTYINSURA.VCE. .. $8.]4 57,62 56,96 55.20' - 53.97 $355 26 925 PULIrES3OAUAGES - 55:43: ..$4.44 54.197 ..$243" 53.11 "56.16 27 1526 EMPLOYEE. PERSON Z BENEFITS $34:77! $SS24 SM83 $29:23 MJ9 520.57 28 9ZT FRANCNSE-RCUDzEMENT9 5Q00: 10.00 $0.00 30.00- 50,00 "50:00 " 29 928 REGULATORY COMMiSWON EXPENSES 52.06 ' $240 - 51.55 $2;0"7` SCF 5§ ' 50.2? - . ." 10 '929 DURICATEC7tAAGES-CFMAT .. $0.00 .50.00 -x.$0.00 30.00 80;00 50.04 31 930:7 <GENERAL AOVERTr..NaEXP6N5ES 5148. U,42 SC.99 $0.01 50.02. 50.03 32 9342 MISCELLANEOUS GENERAt. EAP04SES . 522.13 517,97 S18.66 51 t,36 $13.44 527,12 33 931 Rem $2.22 St.79 SL?2 . S1,42 S1,43 $13t 34 TOTAL QPERATIOA ASG 5131.19 .$725.76 $17925 $108.74. S11S.21 513729 35 925. AI&G,,%WNTENANCE $0.87 . 50.56 50.43 $0.37 50.28 50.47 35 TOTAL X-0 $132.06 5129.42 -St19.T0 5109.21 $118.49:: $131.76 SCHEQUCj T` )'aGE fi Of S. i TXV GAS DISTRIBUTtON NORTH TEXAS DISTRIBUTION SYSTEM TOTAL Dlidi-S RECOMMENDED REVENUE REQUIREMENT 'TEST YEAR ENDED SEPTEMBER 30,'2001. LINE I PRESENT3 PROPOSED PROPOSED PERCENT NO, DESCRiPT16N RATES { RATES INCREASE j4EREAS 1 OPERATNG REVENUES s 2 RESIDENTIAL 5278,737,926 $298,173,541 518,435,615 6.59' 3 CONIMAERCIAL $133,852,4Q9 5137,257;322 S3.404,913 2.54% t 4 INDUSTRIAL $14255,507 S16.917.272 52.661.765. 18,67of, 5 SUBTOTAL 5427,845;842 $452,348,135 524;502,293 5.73% s 6 OTHER REVENUES 53.926.191 53.430,694 $4,503 7 TOTAL OPERATING REVENUES- $4,11 772.033 - A55.276:$29 524.506.796' g A $ DESCRIPTION' TOTAL I RES108NTIAL COMMEACIAL INDUSTRIAL i 10 REVENUES '$431,772,033 $283,265,590 5134227,761 514,285.572 11 TOTAL REVENUE REQUIREMENT 12 DESCRIPTION TOTAL RESIDENTIAL:.:` COMMERCIAL INDUSTRIAL r : 13 OPERATING EXPENSES 14 TOTAL GAS COST $261,285,153 $16$ 296,2.15 $89,087,180 $3,901t,758 15 OPERATION & MAINTENANCE EXP. $64.566,0x1 $50 803,208 $15.295„455 S2,467,427 - 16 PROPERT” TAX $5.126,464 $3,790,720 �S -,475,567 $430r.176 , 17 PAYROLL TAX $1.746,067 $1,449,515 5253,748 542,824 i 18 REVENUE RELATED TAXES 52119161748 $14,329,801 $81856,69$ $73-0.250 19 DEPRECIATtON $ AMORTiZATON 523,767,573 $15,733,308" $6,124,312; 31.903;952 20 INTERST.ON CUST. DEPO,IsgS $625;649 5423,201 5202.498 $0 21 INTER EST ONCUST.ADVANCES $12.935 $$,749 $4t186 c0 22 . FEDERAL )i COMES TAXE5 512:999,24 $029,359 55,248,51. $1,221:33 122i:3?23 23 TOTAL EXPENSES $392.645,90,7 $261,364,077 $120,548,155 $10,7313,7261 24 RETURN ONRATE BASE $39.125.036 $21,901,513 513.672.606 53,551;341 25 REOUtRED:RETURN ON RATE BASE $35,480:217 $23,188,881 $9,270,574 $3,020,762 26 RATE DEFICIENCY 1$3,645;,820) $1,287,368; ($4,4402,032) (S531,085) 27 ADDITIONAL FIT REQUIREMENT ($1,963j 34 5693.198,;($2;370.325 5285509 . 28 OTHER RATE REQUIREMENTS 52,571,083 51,604,839' 3771,424 5104,820 r 29 RATE INCREASE REQUIRED ($3,037:870) $3,585,405 {56,000,933)° ($622,233)1 30 'REVENUE RELATED TAXES ($162,4481 106.213 ($56,82Z a5 413 31 REQUIRED IN" REASE (53,240,6'€8) a3,479,1ff1 ($6,4517755} (5627,646)1 32 OTHER REVENUE INCREASE 34,61?' 4 614 � +� 33 SALES INCREASE ($320+,932) S3A-(4,577 (36,051;755) (S627,646)�: 34 COMPANY &WMED INCREASE $33,849 066 538.731.4"78 ($2,119:187) (w2.763.195} I 35 DiFr=ERENCE ($37454.0?�8) ($35 256,9C1 } {53,932 5F�8} 32,135;549 36 PR OPOSED REVENUES $428.571.715 5286.744 781: 512�3_t6J000 Si3.6�5Z 928' , 37 OTHER REVENUES .� 53,926,151 33,570,943,5337,148 51789 38 SALES REVENUES 1424640.910 5283169.224 5127:831.857 $'t3.63_j, t . TXU ...E GAi D7SMSU-M* NORTH TEXAS Dt_sfFIMUTiON SYSTEM TLSTAL DUCi'9 TtECCf-MENDBo Odbi EXPERSE9'' MT YEAR ENDEo.SEPTEMSER 30, ZDDT-. . I,mB . � TOi4i NtL ACCT 'DESCRiTYGN si'STEAT *Emi.L ".LgwtnDNi ClDU mIk .. GnE�5i�X4Shv.[' SErikiGE'J�LiS;L' " x 1, CD4.. .tA ,L L CASCtirCATE vwbalu :. Z:f.WC.222'.. Stolm.3M 3t5S9D7?zOt i3Aw`1,02 T.. "a:. L4AGCC=FREDECR Gii-,-. ., i. $6772524` SS -38:.218 $2.3GP_Tu .i17f.04,:. a:S Di'1'tR'G6Ft#iCt+ASM 4J s4 Sa : .S).. .. a a:2 c:wPxNv osi6 cAs , STi.:3b S{S.39o'- S:33E3.. Siessk 5 !12 L7.DN4T trbFC GAJ CREbtt 7 ana ri5 f:3i':�1"1 8 T.CTAt GTNERC3SU%R3'-ExPEHWS S251336, 167 Si6'.2DJ::iS- 57-kn97, 1 V. S2, ,'6g . LRSTP;aL fON!1PR+DES s ro S5'ERY$gN#EKa'NEElHNG r 1'%a S}d 5)01.556 3s1�J-� Sd Cdtl .. d DTI C".ST£k'M+G4tOaD C1PATCIHlG .. �£iCE7 .3521}. {SSFB'} lSns}�i . q V. -1.1s s IM!MSEJP � $9404'sN Ss.3__.:,27 1t"I't-6. S591.m .' :� dT5 VSR:TAS7:rtExPCYSl CC'rEAAAt:. #, 33Td. 1'. $21J. 314 - $i•C; '.. 546,214 ii ,6]T M4R ST.1KP.1Sw'E�SE.^.+fY CA{£: ' S!a,E2T Sa,tTs $3.552. -'11,>59 .. Yi E79 4ETER i'CWSE R.EC. E%Paa3E {. $3;54:;%`$ 51.733.346 i'ZSt;t{i. $ AQ, . - 27 'TL S'StCMCR+S•.xT1APAMEXP. j 35"5 'd'd SJ8!. b::•b 3t.'iJ;?i6 S{i,(:id' we "nEA ExcEr+5E3. - S3,WAS11 .S i:,:3a S:..ta1a.85:... 53:2341- - -:S '38, guts uk. lui 5o. " t4 - . 't5 zDTA:DAERAI:Drtd4llMSFS, i:3 £57C :'=5 SI xn. Si.st!'r F.di-. ST,r:lO,.t� an SZ321. sno . D83 51RuCTt.%tE ♦ R,@RGY4tEN.'S 33R S' 7 SII. $4 Zi" ..+'3T Mi sex*- s S4.?s5Ad V.57& --a st SG7 X63 Wm 'Z& X25 Sfr3 u3R 57ATpN EIPEN9E G€.4ERAi'• " 59T)430 3590,'3BT S275.%3 3li6.SiS " 22 M 44R ST4Tgf{ ExPENSE GTT SLATE i :54,443 ',7.4:2 51.442 S$u - 22 802 xv.cri. sEAvicE6 , - .. .. Si.772,042 $I,D+t,tei Stw GSL- 387 '23 Sa3 Srf'rcR bMCit6£RHi E7WEHeiE 3�:c323 525t,*lt Si3D,l6a '0.294. .2s _D!1% Aue4TLNN{Cd Qitd+tfDum4YsnE5l.iX,M Val $31 ZS rCrM t.A%YTETi:NCf ETPEK553. ,: $d: Pi LEST $5,6"."..fi72 52.3%i T.rS' - ST82,%a6- - .26- Tam .YiiedrtfrxzE»"PASDW ,525,Si2,3.! 5+�,9CS.X7 so.S%5.4v Sf9S7.Sad ' i%eSrCMERACLµ4VT,bC ExPEt6Et.: .- 7; S7t SC."i ERYISSC/! : Sa=.9{J 341,2,2,2 S3482'.. . 79 Wt ' METER R£ACtVGE%A¢NSES I _4_t7',fi7C $7 zY; S3.tilT .. C,SToVER neoFtDJ#CbctSCTK`+{. yS1T73S23i 5'1,7.2251 5,337lls SD,t?3 VNCLQLEC,'At. ACOOLWS 57,1£`,{T9 9..91-i,Y6 SI9'.Ptv'.' Stvia - .. "7i ,y7y _ U,-CEUANlCUS cu 70,itAA6Li Ettli '. 513.35T 5'.2''3: 5).Y,3 E5 .ts4i;wCa sERviTF "19.1Ed . -0Z s.rT 'CMER ASSwiuva EXP nl1 s .52.420 2 i2 723.2! T s m.a--D' 17 386 - - ' •,; »:DR!+�rTJA4l ACVERT6W' F}P K .. S.3 151,402 s.t,t is }34 - -.: ?_ `.•;, MIEC GIStOtIER SEAYtGE cXAE.'aK3 se >O a.,1'. : %0- ' 33 SD:.'.0 C1.5TQkER'SERT'GE E.k457+SE5 szel 315: 32 Sz:fl' 3 S<7,tlT' SS.TL> -OOM. EXpe4ES - ,a sLa=_Rvgr�x 32" '2-. s:Z--r it :!.>r 32 3: ➢,b _ oE4GrzSTR4T27M#SELLlY.^.EZP c1",37 320.':+°e 4�.46n t1:T at<;;. d:5 314. 144 $123. '. 3i 5t6 u�;CESWtEC.xt&-as PRG E) +1. Sac <%Q SIM $27 - :07, T:: 4L 5A(ESiAD{WTY2N E]:i$RSE3 S-.PZ3 .. A.^.Me1lf TRAiid iCEKEit41 E7;iEWfS . . 41 Cl' SL4tC:SGEFF.Ri.L11bLAR 2 SIJJT.= 3 '.VU 674T46? ill 4m . .. :a2 17, oma 5::-2X3 F?REw,SE 41 is AIM 4'P--kui is"* toy 3$Z4.717i. 4T. m c"rrme SERs=19"lln1?'J S»S.t`j u' Pia: RK?ERJr a:StAAMtE 3=240 S75,6C!' EZP.11:Ll ..P.M .45 'I.-- CXPX5b➢A)M sEB St_its,w8 '35_{7..7'<i 5295.iS' 533;105 Is 421.. EMPLG15ES iE45iG(t eENEFT ' S3,9iQ757 sl"v- .3 $354.E05' . S,? -%3 :. It u:35 RSG. fA�".DS` EkP ...: .5. $w' :$0 sl - SE P.tti.i PST, GGOCW%L 4G1ki1L -SYki' S2aJ: $3^r 55.. ft rtei r4tSGlWfitTU5 GE2.'ER4LErA .:'.5771,5::4. W212"; SP 91D.: SCG ASSET ALKATSRT10H ETp'... '$4" SG SJ' .. S3' .. ... `se 3i RtrrS zEe4'.. 32:3.srJ r; -;;as sa.u7 :az7 Sainri6u+:ca cErERAi Pti.'Er .y3 sa:. 53 TMAt 4C�. MTPAIT* E GEIk'R.,L Exi i+kr.73{5. Stn `.E'S:39 iz.U$P33. swjni _ . 5. -Tt 04. ExCL TS42 cost .. -S"2Y 4) 5+{ TOTAL CdSa .5,5,'8!1%4 r,9�, T33 3`7,1*il:1 .5+ o,%6 .. '+! CE;'S:GaTCNEtPF1+3Ei _.. 51 fi5:'R+Eairx"`!r>tAMT S72ii%9ii St L�`.Tt_*w{ y?„'fid.gn SI.T':4 iR 'SfC,CiF_RA4 %t.4.N S �lC1F3, 1 l% f'E.. 5.,,1.4.14 s5 Tatu caPxE.:A*iwFSRe7+sEs .. ?�7, aT,6t? i S.i_�.;D S ,«zlz".: 51.435,52 YM�S ft4ERt Sk'iNG�ME TA>ES.. : .. 68 QRCR6:TYA?1nilEL'.tzE3 : 15.39, {ES $'s:iSC,T.0 $1 4Ys,'_riT .. - RATR'.it PESATED TAAE3 ;. Si,ZfE13r St,= -+i..`.=.4. 5711'2.9. 14;4.5%3 U2'.K4 '.42 R;vE?R;E. R"T7:3T4XE5 .�-, Si -1 WlKl _: i3 V-41..a..i�t.'. V': rCTAI."-Zlion{ER Trm nC".+lE -527,38S.iU 3'3,r^'S,G37 59 31L: S}..'39�`W ar.ESEsxExrE�raEr S+ ka'E sl3 Ct73TdERb"osrt5 Sc2`Eaq i:23.d?. SL^Z{g) . .. : :ES ai'ERES'GN C�'tU54EAAOS'!3R'7Y .5? .w,_: c<t. " .3? iC-4: XrrEFE3T E%v9EE5 5438.63+S4J i.i1S S'i!><.cl.?. :0 :BT TOTAL CAS.RATIKG ESPEHB£t: .. SJ?J fc:a. s••:7. .4>_:+'JS3$' `' T i anr;..;sa ^- .TE3 1 -.:-..:,... r Sr:a aD2,jea Ssettt.ea3 .,.a.+... ra= tx toy . v: Sa ilrse.L =rarayglaµt.-1GatYlilSnat' Sit3taT,aia _;4; m.E}s. 'SSa♦xbLW'6 . 1r.nar,as: .6 #.to++4t as>r6 r0.+. Stl35:d.SW ,FtCA if�}iT '.YriJdi,3W:.274 tlS3S�7 JTa ra'xaawa t1Ui"39 Its 325a 9a8 ED) 11aa.6R351 :. 553,4:3.30 ! ti4 aeusiirrwaetp.etti - :. q 30. tE6:z5N lAWT t>F Ft:a3l.aan _#623.ii4° -0 ' 3T4 LncnaSwr"6aCrz 4F't 9�4 1 #T.a15.o3: ' 3TA13.J.7 SST15T #'lA+W ti$ 3a6 aitttw-Ex `21754N.3TJ f t65aat.2t1 :#U;t3i.EK Sa.t20 . !T ' 32 Sas anztns i SS}; 3,'%S 13a2TSrt43 32RSi`,1,Jt22 St, 3]2 � -. {] ]ril b4yS')LaL MP.TGiOi3w4AR<aaeg4 � 54',, 3, Sd : S'. . Sat rc>K W;TE4a. � SS):73Y,553 J35.27E'4] 33aa3ay2i St.?aa ia2 , Rt : SS3. ra„ea tteAi.3TtYa1 : SSS,a3p aia 3a tWJ t2 � iF mmz , 11aa,Y31 I5 . :... T4 2a3 aonT+e.Lwam6 a�Ra3tir31aanw+a - 's .W sc 3a Sa. ... 363tGT3L KaHfl4tG.'W4 30;a90,VN Si a94.T4 $a 6tLti532 11a,21t :. t3 Taiti Ca45taaaRtxtR,aM2 ST42,52(}24 Sa6$.2a5.643 t $tDt.mta2 SSeta2a.)N OETE93L itJM2 18. i39''. '.ssah 51.+1a.f}a. SaLs,Wi 3377,Ssc . Y.17TFF 19 .1:a tT.QLi t--4ea;etal F Sl6t12TA�: SS 3"92 S2,1*' TSI 3a32,3t2.. St1 361 Vf+iSF•.aw(I,KaL3wGVP:. S3.39a DIT. :.'v'.aAn ?D%. rl a."nm - 2t' - 392. *w.Hsa�.'uas Ex+ruiax r 14.111.'M S32S".24•i- S•t5%17r . ::3615237 71. ]Oa :hYS.G4aiFMGi3WNLYL 34 .. FS. Sv ,i5 . 2i. 3�1 w.Y �+Ln.*aZ,aa TgG'EQSa #Says.}a4' '^-2-Z a. M*%.,T7 Wt-lis -' 2i- "'w- ]4T a. xCwcwrsTw mo •: StRsa. 1 St .U3.^la Say.151' 3,3I.Sm -. . 1Y: w�'F.t.`+�EhiSRt"avfM S.:T325I'2 X6%.tt6 S`Gv752 365a.bta Z7-315.01 .v4:s:r!/M3E C.^.rgLSFF L'3e7 SP.'v9 aT5 t9E"w S:`'R`J3t ?Ntl233 Zi '?f902 c9nv.!£a a;)RTFaq '.. sitwC lTI 5.; '%3 _S3 C7d.4Ts ,SkallTt .. i3 T34 ih. aak:tE+w+Y++Ka'«e. '3 $ZM.: 864 S!.. iit.iil f-MN S22!a57 .. 3B TO:K... "r $:$-klictw S30a19".^43 Sa3aA33Y 23 MUM SEit3lcx d7a4.SL3"29 7a{;&33a S!90.1a3,1W' 1 Sa.>,"„Sa SPs .iCCwutfttO VETPEa3iJ0ia. ..... Se 373 01 tw3 35 <q 33 f0 1i 3'a.02, ;Y..^fitYt7: "aaaY..41 Si2a.Lt, 3'sr 3¢4 J2 ItS 1'S n.a'T?8l asmr•W4aExis. W.3 S! t„'¢ S:.t7.'y: 5-83}". $ On . .:. LJa.pYFA aEc aiiD �. T'kw:m3. St 2msr' Sv; BF509 st-wom . LfxM.L aE:,3Ti2 aTE CtKA $52.= 9?S $22_5• aw Sit aW 36' .. 0 cau.LrvEulEaa v 531,531.142 SXYL`T 3: a 531 Ss,$2fW Zi 135 s-urns. 3t3Z4:Tt °6+. V1,323.211- 1'2,%4,t V6,11AXI `R' 3'D a3a-±?TKy: Ew.ca.al4 ) $Itloa,ayy 3 4..taa T 7.wi 3i'13aS 74 J}3' !,tAX!it3J>•.4tT.:.mL fi SSa;301 S3i$;:L*6 SSY%36a 56D.C31i 36. 3a9 SttitICTJ 257 as{2ty 3.4 TTk2 'S.^. L"..a 347 "'. #:.5m It 381' RE'Za4 :: '; $ F,2i: 351 s La YA $Sc2D tlp .530522 a2 25T w,Ra c ;riaa nwi .�.aa.� i So 44 so Sq t3 7a1 rot%a.t+k.. a 3 T,2at MA S 0.3' W Fi .36 Lal S39.t1 I is 3e.3 '-t1 tr�':F kiwAIay `,U{ iT t a] 5, w 147 . S.-It i3: n.3.xtRia ✓p.,aa rtFh`Cn:w-ttwri.v4 Sd S. Sa Sa av }63. i4+'KttVaC RLG1i1MLi i 5{iifl. UT .. Sat l... 33aat.lx 'SSa.t 2't :aT; =^L.SJ'aBt."IfY. Rami .. 1-.12 So 80 S0 Sb - a5 .4.5 xTa.^saYJa-'aanCrx5EJ.3 52 `w.�.n4 Ft 9222a' S:F4,`p3 201 ,E43y+aa:4afSfiCRM4E.'+T f36"D'�53 j•$J?`r:)f. JTT:i}T sitz,i!� :3.: 52 :il ;Cct,6%W.{aala,iC G'3,'nK4< " a :. to to Sfi - S3 .SSd mQ. f3.�OGala5v44hf F j3 aG'it31. ;2.3!5 AA9 S4$:,t92' 5:$".tSa u3:1 aMtCc�Ws^.aTavLW!- - 31,t7=.:�'1 ,�ttwi'6 SW' T.A St29 ti3.3 YE-' ,?:d HEaC3M1L36£21TK1ai bi;-$04 '33:S.Ir 313:1,Nj fru aT9.a1 aiG+raiM%.tEeaetific [C.etr <VT:514 SJ.. 3:907 Cp+44TLa'lff-MfAL S335Et1J :.t+.Y34w rs.3.T' S,ta4 3217 •S7 . w :#3- rFa.4f'aC: Jt+S.Nt .:� ':.Sa'a 35i iaS $1+3�"°:J1 k.3a±.LeT 57.4Vi?Ot 'S: t KKiswas•s:e�EaYiE+ 5...4 -kt315 5!;- C+. 3S S#'. fr. 0�"" 3"&..°3AN fi a,cr rwsyx»,a.7c«Tu+ws[sv-:t 5-_}tt,,s S5:i 3.n 5-xa i:v ?tm.5ws7a Itz £T Ga3 c2�tavt watt w.T.F'aGL aSTt?ST z{3 S 11...'1. SS 121 �l 5'tt^..Ma :.Ga r,EI aG'FigaJJt/x: 143EXu^"_`6 3342.!"44 Ai9:'ria Yz 3132116"u, 5 i'm.542 :TE1P?H?iCGYi111Y4 f. ti axa»RtZ'th11Yr'JKSaHJa 1117 �s if33 1S)LSCa'e:i !'Sa W53+j ES"3a3.426� ,0E:. aEitvEtan.�wrnKvapna>atst is 53 54 4a a} u,_ w-=�a1a,•aam++•.s 'ii:6:s71ai5} .1az1'vassr, i$a eaa7ra s5r.c/s.ttq OB ' aa:xKJisl LsxvLs ' S1..a937 3TaT.si; ..2354991 .-.'SLs1.2SS aG: aZyi>UFsts' i 522+2111. -SS 3,i?< '4°a5?7a . 3+65,a Tv' T,1Ta„isk+tal3iq+3A1. sla a.p)i1..33414N,E!t[s ;SD'S2£.2(y AS3.123.2Tj IT aCl":itfEt',Ltia+VM2L C04; g. .. to ' . S0 T2 21.. 4.A MtiitftR aPPTMi1' a'e•Ea:tK41 CCiViiYtL3 ',:".SG.390,p2t) #34y]t b3S}. :: :RF37RS3.71 154,i3Yl3ti '1a aiya!vC%'LYt0eYt5 3mrg121 $ "'ed'r54 53 ST<9%S. � i s Sr C3iF�Y/!LV:Lil"5S'GN.SITtt3N°a `wwcaa:uc'tia aa,rtr 3{§jb)m2 .ita5.3Y: � it 9a' Sr•saz j! ?32' S'wu':a3 6nsa2W r1 roi„^uETaaac,ae ra['ra saa +i OM S,t� arr 5+1s1aN tD TGth9G3sTaylsT �Lycaas 4'+2 rrn rr Sx. .f.� S_'aSs.+.s ..1q^t-a '.. SCHEDUt.E 8 PAGE 129E§ TXU GAS DISTRIBUTION NORTH TEXAS MIETROPLEX DISTRIBUTION. SYSTEM RESIDENTIAL CLASS CURRENT AND PRIOR SALES COMPARISON i BILLS ' SALES PRIOR CURRENT PERCENTAGE PRIOR CURRENT PERCENTAGE ' CtIY, CUSTOMERS CUSTOMERS: CHANG t MCF ISE CHANGE ' 1 Addison 1,,475, t,d53' -1.4945% 124,518 124,616 0,0787% 2 Allen: 8,227 -12,081 46,8458% 631,244 881;894 39.7073% 3 Anna 316; 315 -0,3165% 21,735 17,638 -17.9296% 4 Argyle 297 300 1.0101% 25,645 24,101' -6.0207% 5 Arlington 34,447 38,314 11.2259°F '2,341,374 2,373,679 1-3797% I 6 Aubrey 409 428 4,6455% 20,916 20,181 -3,5141% 7 tuEe 4,125 T,150 _ 2.2222%° 57,003 60,377 5.90971° $_ Batch Springs NIA N/A _ NIA NIA NIA NIA 9 Bedford 5,888 .5,971 1.4096% 403,389 372,738 -7.5984% 10 Benrook 2,271 2,325 2,3778% 140,186 131,939 -5.8829% 11 ,Blue Mound 584. 380' -0.6849% 30,299 27,362 -9.6934% 12 Blue Ridge i6b 157 -1.8750% 9,584 - 8,215 -14.2842% 13 Burleson 2,554 2,845; 11,3939% 130,136 148,385 14.0230°6 14 •Carmlt6n 21,181 21,837 2.15291/4 1;538,282 1,412,135 -4.30016,0 15 Cedar Hill NIA NIA N/A NIA, f41A NIA 16 Celina 529 524 -0.9452% 37,690: 31,270 -17.0337% 17 ' Colteyville 5,4$ff 5,74& 4.1545°!° 647,941 629,145 -29009% 18 Cappell 8,_365 8,581 2.5822% 763,235 725.374 .4.9606% 19 'Copper Canyon 11. 13 18.1818% 1,543 1,885 22.1646% 20 Corinth 3,264" 3,608. 10.5392% 218,154 229.508 5.2046% 21 Corral City NIA NIA NIA N!A NJA NIA 22` Cross Roads. 5 0 -100.0000% 481 0 -100.0000% 23 ,Crowley 1♦561' 1,650 5.7015% 80,128 85,541 6.7554% 24' Dallas/NW Mekro. 5.546' 7,588 36.81931/. 464,126. 519,186 11.8632% 25 Datworthington, Gdris 461. 480 4.1215% 47,717 53,126. 11.3356% 26 Denton 16,656: 17,273 3.7044% 1,113,837 1,022,680 -8.1836% 27 :DeSoto NIA NIA' N/A NIA N/A N/A i 28 Double Oak 167 179 7.1856% 18,578 18,916 1.8194%, 29 Duncanville N/A NIA , NIA N!A NIA NIA j 30 EdgediKVillage 536 533 -0.5597°,5 33,472 31,700 -5,2940°h 31 Euless. 51286 5,292 0.1135% 312,00'3 286.435 -8.1948%- 1 32 ,Everrh5n 1,142 1,136 -0:5254° 57,096 .55.224 -32787% l 33 Fairview 142 293 `1063380°J° 15,568 38„192 132.4769% 34 Farmers Branch < 7,09a 7,0! 2 -0.3949% 506,192 462,542 -8.6232% 9 35 Farmersvitle 926 911 -1.8199% 67,093 57;860. -13.7615% 36' .Fate 81` 78: -3.7037% 51159 4,772 -7.5015% 37 Flower Mound 14,635 16,277 4.3867% 1,228,873 1,201,025 -2.26661% - 38` Forest Hill 2,234 2,247` 0.5819% 137,976 129,276 -6.3.054% 39. Fod.YVoriti 99,362 104,680 5.3521% 6;452,941 6,324,620 -2.1402% 40 - Frisca 6;692 11,133 66.3628% 519,159 849,128 63.5584°l0 41 Garland 36,853 38,193 3.6361% ,2,493,875 2,445,312 -1.9473% i { scxttul1= . PAGE ZrOF 6 , 3 42 Glenn HeightsNlA NIA NIA N/A N(A MA 43 Grand Pralrte 1,138; -16,297 1429.8495 70,139 1,070,882 1426.799096 ' 44 Grapevine 8,443 $,557 r 1:35020/a :645,816 508;432 =5.833$°10: 45 Haltom City 8,303 8,442 1.6741% 481,240 45057 -5.4615°Io 46` Haslet : 4T $2 1 10.6383% 2,704 2.763 2J450%47 Heath 918 1,072 16.7756°% 108,259 117,884 8.8907% A8 'Hickory Creek. 451 521 15.5211°% 33,429 38,67055.6780°10 49 HlghiandVillage 3,932 4,053 3.0773°% 358,576 347,399 :-3.1171% 50 Hurst 7,785 7,840 0.7065% 496;277 448,473 -9.632506 51 . Hutchins NIA WA NIA NIA NIA NIA 52 rrving 26,8?6 29,297 1.4580°A 1;965,271 1,839,329. -6.4084% 53 Josephine T17 114, -2.564140 9,032 6.894 -23.6714°% 54 ,Justin 463 1 492. 4.9041% 28,645 26;346 -8.0258°% 55 Keller T,485 7,897 5.5043°% 603,528 597,161 1.05509b 56 Onnedale 737 790 7.1913%° 41,022 42,375' 3.2982% 57 Krum 532. 568, 5.7669°% 32,663 31;034 -4.9873°% ` b$ Lake Dallas 1,195: 1206 0.9205°% 73,750 68,501 -7.1173% 59 Lake Worth 1,304 1,294 4.7869°% 77,180 71,452 -7.4216% - 60 Lakeside 268 268 0.0000°% 17,905 16,226 -9.4106°IP 61 Lancaster NIA NIA NIA NIA NIA NIA 62 Lavon 3f. 69 122.58065% 1,965 3,887 97.8117°% ` 63' :LeMsVllle 12,985 13,058 ? '0.5622% 826,824 790,765 -4.3611% 64 Uitan NIA WA NIA NIA ;N/A, NIA 1 65r Lincoln Park 64, 64. - 0.0000°% 2,441 2,090 -14.3794°% 66' UttiaElm N/A N/A WA NIA N/A, NIA 67 Mansfield: 4,014 4,540 13.1041% 269,606 282,422 4.7536% 68: Marshall Creek 81 78 -3.7037°% 4,404 3,783 -14.1008% 69 McKinney 10,370 15,287 47.41560% 812,957 1,150.746 41.54370W j 70 Melissa` 145 137 -5.5172°% 9,195 7,233 -21.3377% j 71 .Mesquite NIA NIA` NIA NIA NIA N/A 72 Mobile City 39 40 2,5641% 1,828 1,638 -10.39396/0 13 Murphy. 452 1,363 201.5487°% 33,440 91,110 172.4581% 74 Nevada ip8, 106' -1.8519°% 8,035 6,569 -18.2452% 75 North Richland Hills 7,174 7,710' 7.4714°% 443,040 474,633` 7.1310% ' 76 Northlake N/A _ WA NIA NIA NIA: WA 77 'Ovilla, N/A NIA ' NIA NIA NIA NIA 78 Ponder. 97 120' 23.7113°% 5,924 6,004 1.3504'/0: 79 Pantego: 5658 576" 1.40851h 39,921 38,164 4.4012%0 80 Parker 36' 104: 188.8889°!0 5,233 11,824 125.9507°% 81 .Pilot Point 849 873 2.8269% 53,478 48,099 40.0583% 82' Plano 48,272 55,852' 15.7027°% 4,463,080 4,903,151 9.8603% 83 Princeton 556 546 -1.798611/6 43,833 29,434 •13.0027% 84 Prosper' NIA NIA' N/A NIA NIA NIA e 85 'Rendon 639. 547 1-1.4M75% 27,347 28,303 3.49581% :- 86" Richardson 22,03$- 23,450 $.4071% 1,717,275 i,728,700 0.6663°70 87 Richland Hills 2,476 2,483 0.28271% 160,859 155,052 -3.6100°% 88 River Oaks 2,447 2,440 -02861'% 144,551 131,269 -9.1885% 89 Roanoke 412 472 14..5631°% 23,310' 23,633 1.3857% 90 -Rockwall.. NIA NVA NIA: NIA NTA NIA c k: s 91 FZowlet# S,t61: 11,4$2 '92 Royse C11y fi00 539 93 Saclisa 1,913 " 3,23$ 94 Sayfinaw 2,044. 1,507 95 Sanger 9A7 9�4 96. Sansohi Park Village 1,243 1,241 97 Seagoville N%A NIA 98Shady Shores 352 ` 369 99: ",outhla'ke> 6,182' : 6;427 t 100 Sunnyvale: NIA NIA 101 The Colony 1;824. 2,511 102 TMphy Club 788 638 103 Watauga 1,706 1;759 104 Westlake 183 197 105 Westminster 99 103 106 Westover Hills N!A NIA 107 Westworth: Village, - NIA NIA t08 White Sett(emecrt 3,182 3;168 109 Wilmer N/A NIA 110 Wylie' 18,168 16,777 -7.65631% 514,647 `: 578,736 12.4530%137,321,376 39,266,265 5.211120/6 SCHEDULES FAGS OL§ ?5.3357% -666261 810,336 21.$072'l0- 10.1667% 38,264 31,373 --20.0973010 i9.1584°Ju 127;156 203,$69 50.40$536 22,6517% 107,102 02,225 -22:4510% ' 3.90110to 50 Z42 -10. 3fi29o, 0. (609% 69x015 $3 $37 -7.5©27°k NIA ',WA WA: NIA 10,51140Jo 25236 26,180 3.74070% ° 3.9fi31'Jo 779,973 - 733,789 -5.1520% NIA tVA MA_ NIA 37.6645% 127.;751 168,639 32.0060% 6.3452% 65,602 68,124 3.8444°fq 2,9859% 87,055 $2,762 -4.93140Io 4.2328% 18,168 16,777 -7.65631% 4.0404% 5,520 -5,119 -7-2645% NIA ' NIA; NIA NIA N/A NIA NIA. NIA -0.44000/1 166,305 150,606 -9.4339%: NIA NIA N/A N!A . 5.47660% 133.759 143,830 2 qi29% 12.4530%137,321,376 39,266,265 5.211120/6 SCHEDULE 8 i PAGE 4 OF E UU GAS DISTRIBUTION, NORTH TEXAS METROPLEX DISTRIB'UT10N SYSTEM COMMERCIAL CLASS CURRENT AND PRIOR SALESCOMPARISON i o� BILLS SALES PRIOR CURRENT PERCENTAGE PRIOR CURRENT PERCENTAGE" LiY CUSTOMERS C I TOMERs CHANGE jtBSE l E :: DHAP 1 Addison' 936 972 t 3.8462% 565,209 531,027 -6.0477% 2 Alten 536' 487 -9.1418% 136,887 215,971 57.7732°% 3 Anna 34: 35 2.9412% 7,216 7,049 -2.3143% 4 Argyte - 17 25 47.0588% 4,025 ,5.099 26.6832° 5 Arlington 1 -3,--703 3,953 6.7513% 2,418,814 2,508,146 3.6932% Aubrey. 33 33 i "0.0000% 8,839 7;526 -14.&5464% i 7 .Azle 169-: 172" 1.7751% .28,125 ' 36,558 29.9840% 6 . Balch Springs N/A 240 NIA N/A 73,585 NIA 9, `Bedford 5D9` 538 5.6974% 312,036 328;168 5.1699% 10 Benrbok 151 146 -3.3113% .66,433 66,893 Ti Blue Mound 33 32 -3.0303% 12,717 : 111757 7,54900 12 Blue Ridge 25 27 8.0000% 2,879 3,419 18.75WA 13 ;Burleson 314 342 8.9172% 9428& 110,647 17.3500% 14 Carrolton 2,142 2,217 3.5014% 1,060,044. 1,026,565 -3.152rA 15 Cedar Hilt N/A 316 N/A NIA 108,737 NIA 16 Celina _ 65 69 4,6154% 90,102 11,962 '184122° 17 Collepille 211' 257 17.3516% 56,006 66,923 19.4926% 18 Coppell 316 379 19.1824% 195,363 246,902 n.381IVa 19 Copper Canyons (VIA NIA NIA 0 p NIA 20 Corinth 39 53 35.8974% 15,319. _ 25;361 65.5526% 21 Corral City - NIA : N/A N/A N/A N/A NIA 22 Cross Roads 1 0 -100.0000% 23& 0 -100.0000% 23 Crowley 99; 94 -5.0505% 23,970 25,112 4.7643% 24 Daitas/NW Metro 544 657 20.7721% 342,773 421,963 23.1028% 25, Dalworthington Grins 73 76 4.1096% 9,259 12,413 34.0642% 26 'De6ton 1,856'' 1,933 4.1487% 771.,333 742,719: -3.7097% 27 DeSoto NIA 585 NIA NIA 230;954- NIA 28 Double Oak 1 0 -100.0000% 80 0 -100.0000% 29 ,Duncanville N/A 676 N/A 0 224,795. NIA 30 Edgecrff.Village 5 4 -20.0000% 1,121, 1,083 3.3898°% 31 'Euless 452 469 3.7611% 292,885 294,167 0.4377% 32.' .Evermars 66` 84 ': -2.3256% 19,092 18,425 3.4936'1° 33 Pairoiety: 19. 11 -42.10530/. 3,242, 1,359 -58.0814l/. 34 Farmers Branch 1;172; 1,177 0.4266% 559,751 542,345. -3.1096% 35 Farmersviile 95 91 -4.2105% 32,319 33.236 2.8373°la 36 'Fate 13' 13 0.0600°10 1,109 1,329 19.&377%' 37 ,Flower Mound 244 319 '30.7377% 89,494 116;525 30.2043°/o s 38. Forest Hill '179 169 -5.5866% 98,812 71,839 -272973% 39 .Fort Worth -1.5054% 4,536,623 4,709,167 3.8034°)0 ' 4Q Frisco o 541 307 i 43.2532'10 , s 82,334 104,080 26.41i9°fo SCHEDUt_E_$ PAGE 5 QF.6 41 Gad*6nd 3,493 3,095 -11.3942% 1;259,508 1,218560: 3.2512%, 42 Glenn Neight; WA35- 1 NlA NTA 6,993 NIA 43 Grand ptairte 1422146 111998,77751Y.78,684 1,054,838 1240,60(,-0% 44 'Grapeir-ne 790,' 865 9.4937°J° 562,241 566,728. 0.7981`Yo 45 ?FYafsom c>y 852 833 -2.2014% 242 28 2401,790 -0.8393% 46 .Haslet 32 2151 1 '25,669 19,482. -25.2717% 47 He4#h , 19 22 15.7895% 4,457 5,01;6 12.5421% 48 H`tCkoi}E€7ee[d' S' 7 40-0000°% 340 626 84-1176% 49-Hi0fand UiUge 65 87 33.84621/. 15,452 19,873 28 6112-t 50_ ,14urst 703 754 7.2546% 252,359 268,561 6.4202% 51 Hutchins NIA 72 WA NIA 30,424 NIA ' 52, (ruing 3,293 3,437 4.3656% 2,486,427 2,474,533 -0.4784% 53Josephine 5 5 0.0000% 546 471 -1333631% 54 Justin 41 45 9.7561 % 8,735 9,399 7.5524% 55 Keller 202' 269 33.1683% 56,979 73,239 28.5368% 56` Kennedale 112 122 8.9286% 29,414 28,143 -4.3211°,% 57 Krum 37 40 8.1081% 6,994 7,000 0.085810 58 Lake Dallas 88 85 -1,1628% 21,271 2i,959 3.234504 59 1_oke Worth 164 158 -3.6585% 44,830 48,250 7.6288% 60 lakeside 3 1 -66.6667% 1,060' $03 -242453% 61 Lancaster NIA 302 N/A N/A 134,162' N/A 62 lavon 4 -20.00004% 5i6 476 -7:7519°1 63 Lewisvflia 1',285 1,445 12.4514% 553,219 608,321 9,9603% 64 t_itiian NIA 7 N/A N[A .21190 N/A'- 65 LimbolnPark . 31 4 33:3333% 1,694 2,016 19.008346 66 .little Etna NO 41 NIA NIA: 6,489 FNA 6T Mansfield 335 23.1618% 148,559 161,331 8.5973°!0 68 Marshall Creek 2 2 0.0000% 68 51 -25.0000% y 69 McKinney 1,152 925 -19.7049% 335,989 364,424 8.4631% 70 Melissa : 25 28 12.0000% 3,305 1;697 11.8608% 71 Mesquite N/A 1,450 N/A N/A 843,258 NIA 72 Mobile City 2 2 0.0000% 389 315 -19-0231% 73 Milrphy 25, 36 44.0000% 1,406 9.519' 577.0270% 74 Nevada 7 9 28.5714% 312 337 8.0128% 76 North Richland Hills 609 630 3,4483% 291,965 322.151 10.3389°16 76 Northlake - N/A 1 NIA NTA 223 N/A 77 OvAla, NIA 7' N/A NIA 1,083 NIA 78 Ponder 1.9' 15 -21,0526!% "15,343 8,719 -431728% 79 Pantega 4 2' 2= 241 -0.4132% 33,075 35,748 8:0816% 80 Parker 35; 0 '-100.0000% 1,031 4 109.0006°6 81 Pilot Point 105 108 2.8571°1 25,629 25,295 -1.3032% . 82 Piano, 3;946. 3,139 -20.4511% 1,258,129 1,464,665 16.4161% 83 Princeton 52'51 -17.7419% 14,567 16,090 10.3037°1° 84 Prosper NIA 31 NIA NIA 7,085 N/A 85 Rer don 39 36 2.5641% 3,976 5,167 29.9547% 86 Richardson 2,256 2,092 1 -7.2695% 835,313 866,785 3.7677.% 8T R'rchland,Hills 253 252' -0:3953% 61.817 62,362 0.8816% 88 River Oaks 138. 135 -2.1739% 30,862 - 34;238 10.9390% 89 Roanoke 92 106 15.2174% 18,227 : 23;301 27,8378/° _SCNEiSlItEB _ PAGE s a s . 90Rockwall WA 443 NIA NfA 172.065 NIA 971 R6w}ett 498' 444-- A0,4839% 68,25y 89,616; 3t 292095 92 Royse City 65' 6tk -T.693% "7- 17;230 -3.0006%r 93' Saehse 73 81 10.0589"C 8.918 16,272 82:504% 94 5aglgarf. 164 168; ; 2-4, , 76,122 72,tl79 -5.31 q°, 95 Sanger' 12 112 :4 0.0000% '23484 22,557 4.9351% 9& Sansom Park Vittage: 74 84 13.6135°l0 11,735 13,162 12.160; 9,% 97 SeagavitC6 NfA 163 NIA NIA 4U68 NIA 98' shadyShor@s ': 3 2 ` -33.3333% 350 281' =t 9.7143°1°: 9S §OuthtAel 353, 432:. 22.3796% 80,170 105,416' 31.490o6ib 100 Sunnyvale NIA 55' NIA ' WA 11,459 NIA 101 The Colony 186 145 ! -22.0430°f° 46.777 56.432: 20.64b5°l 102 Trophy Club _ 6 21 2504000% 2,231 ' 7,417 232A518l/a 103 Vtatauga 1.46 170. " 16,43846!° 32,646 51,140 56.6501% 104 VJest1814e 10, 1"i 10.0000% 14,521 16:233 11J698'fo 105 Westminsfer 5 5;.. 0,6000% 298: 284 -4.6980% 106 VVlestoverHi}ls 6 5 -16.66671% 962 - 1,052 9.3555% 107 GVe"stviorth Village 32 23 -28.1250% 8,852. 7,486 -15.4315°4 108 White Seftlement' 212 196, ' ` -7.5472% 99,839 109,068 9.24,39% 109 Wilmer NIA " 31 NIA WA 7,540 NfA 110 WYlle 174 i6 4.5917°la x.709 118,538 ZS.Q°la 47,140 `53,010 12.4513"!. 21,154541 24,990,907 18,1461e SCNEC7ULE 8 t y� f T K J g $ 1 0� PN '-°�r� �6a"j.'.. $c`a'i� ?' � .q aoc aq $.o �n� r�.�� ,-1� 57 •:e+�k Hca .. o=•fo "iA. .. n z nnr�i n.B Z. .4jq F +GUF A P B owl'. r{ea ry o « A A r O Q45 4 w �. q N = LL x v - a S tc ti z � lz 63 zC �p d aI S.3 m aS �z �C.II V g' l seHEOULE a PAGE2flF8 a!44 a o K z $�y b Cf'b o'orati abate' .�9� a oa # vzs�. 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OY '�.°� � f7iO � Qvi a .5 m+� ;z+��t� :L•>u� 'w �;e r' t h u r t"R n �u NI p u z CL 85 � cr a s a a: p K 3• °� ,W ��• tY A'Y �< G�2 �F i < z. Gt?EDt1L� A�E.6 Or' S . W gq n J k i C jo u art! uri mj Jfi s ff a } ,� � � '"_3 uA. 3 0 "�.� Ys �} 1i'i.. � ti" g,$ . �K »..- .• 'Sv a �. � e y � 4 c ... ra a. 2 gu m l Or +a 52°, z[a" wtE � K >�,�„ .4-�'. OY '�.°� � f7iO � Qvi a .5 m+� ;z+��t� :L•>u� 'w �;e r' t SCHEDULE@ ' PAGE70F8 Bt � W TQaaf SO - �'� •--.� � 4y O Tx <�qs^��J.{ a 5 •} O N> 6 c} H v�i 'd ^ xl » HA t tCCtt Me f N $ "hFOE 31 g m o It &I - m .Y ^ 'g a n-51 Y 4 0 dN�E ht af. O m i < ills g y r� ti i �* ✓.j 6.a n _' _a sL 3 z < r� � �' F` �3< E�z�rs t3�� � w• �, c�CGC, -a � �a ��..s� �� .y U •N R '7 -:rJ N N tl2 W Y RIM Sct{EDULE � s gje a � �- W 3 Sae cm u3� 3 }qCs °"err n�t Am a k m z " ri xi .ti. - n s� �n ao vvv a p �n u �a � ? 45 3 6 55rr 91 ^ Kt3 pt �� ;t O � �gf N tY q N?Y z+s jy fi N Q � R '7 -:rJ N N tl2 W Y RIM Sct{EDULE � y PAGE_.8 0 �- W Sct{EDULE s I' PAGE_.8 0 n�t ao vvv ^ qs .Na p �n �a � ? 45 3 6 55rr 91 ^ N?Y z+s jy fi i fi i3 9 Y W s # SCHEDUL510 , PAGE 1 .OF 2 t TXU GAS D(STRi4UTION SYSTEM N O RTH' TEXA S� M ETRO P Lam' REVENUE ADJUSTMENT N TX METRO'- RESIDENTIAL x' COMPAAIY ; DUCI i)RFFERENCE WEATHER $0,181,444 $3,195,444- $219861000 CUSTOMER $1,714,1794 $V14,094 S1,714,094 REVENUE ADJUSTMENT p $0 $1,414,072 $1,414;072' REV TAX $238,577 l i N TX METRO - COMMERCIAL COMPANY DUC! DIFFERENCE WEATHER S2,064,901 $46,863 (546,8c} CUSTOMER $31 $627,606 5313;803 REVENUE ADJUSTMENT ' SO $2,740,670 52.740;670 REV TAX 4 Y $13,550 i q SCHE�I3C� F ti. PAGE' 7 O�"2 Add: 6 Reverse Weather Normal. 5.278 255 7" Total Base Rete Revenges Before Adjustments $302,62$,628 $ Sales Revenue 273,3r35,i$3 Less: 9 '1'0 Revenue"Related Taxes "Cost 13,872,03 11 Gas - 1 Subtotal_ 162.78.945 176.639.977 T2 a Base Revenue 96,745,206 13 '•? Reverse Customer Adjustment (1,714;094) Reverse Weather Adjustment - &.18.444 15 Total Base Rate Revenues Beforp Adjustments $10L� t2.55$ Residenttat Revenue A'djustmeit ti L-414.072 SOURCE &'REFERENdES x i ine g Schedule, G-1' 2 Sc}iedule-9_(�a,076loi 3 Scleduie G_3 x 4 Scheduie "G 3 R 5 Surra Lines 2-4 t & Company' s,Weattier:Normalizatton 7 Line Sminiis Line 5 plus line&, 8-- Schedule. -A -t 1 9' S66du16 G-9-1 11 10 ScF�edufe iC 4" It Sum Lines 9 & 10 12 Linn 8 minus tine. III 13 Company's Customer Ads 14 Company's Weather Ae 15 Sum Lines 12="t4 16 lane 7 rriinus Line 15 S61�6LE 13 PAE,E 2 � Z oc U N• c�i a N q q CL V 0 W. •� ` o .Ca" - o �- Xui � QZ12 X F- O p cco C m E0 ' 0 v. a` o n r � z U a g =n al E °t �CHEDULE1f. TXU GAS DITRiBUTION NORTH TEXAS METRflPLEX REVENUE ADJUSTMENT COMMERd t 1 Sales Revenue S218356,81 Less: 2' Revenue Related Takes f 1,104,099 3: Gas Cost 372,382,880 4 Unacct For Gas 3.494 086 5 Subtotal 186 981,071 Ado: _ 6 Reverse Weather Normat. 2:611.$13 7 Total Base Rate Revenues Before Adjustments 533,387,323 8 Sales Revenue 13C?,t358,34. 9 Less: Revenue Related Taxes 6;642;370 10 Gas Cost 94:320;424 i Subtotal -100.962,794 12 Base Revenue F3 Reverse.Gustomer Adjustment (313,803) 14 Reverse Weather Adjustment 2 064;$01 1:5 Total Base Rate Revenues Before Adjustments c3= 46,6g,! 16 Commercial Revenue Adjustment 52 —740 i SOURCE & REFERENCES: { Line 1 Schedule G-1 2 Schedule G-9 (5.076%1 k 3 Schedule G73- 4 Schedule G-3 5 Sum Lines'2-4 6 Company's. Weather Normalization 7 Line 1 minus Line 5 plus Qne6 ' 8 Schedule A-i 9 Schedule-G-9 10 Schedule K4 1t Sum Lines 9:& 10' 12 tine 8 minus Ling 1 f 13 company's C4stomer.Rdj 14 Gompan)(sWeatherk4 16 $um Cines 12-14 16 Line 7 tirius One 15 {