HomeMy WebLinkAboutItem 08 - TXU Gas Distribution Rate Case and Public Hearing ITEM 0
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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.
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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 this ordinance, constituting final action on TXU's
application be sent to Autry Warren, Rates Manager, TXU Gas Distribution, 1601 Bryan
Street, Dallas, TX 75201-3402.
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 remainingportions shall remain in full
p force and
effect.
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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.
APPROVED:
ATTEST:
APPROVED AS TO FORM:
ORD NO. 2
------------------
LLOYD, GOSSELINK, BLEVINS, ROCHELLE,
BALDWIN & TOWNSEND, P.C. I I JUN 1 0 2002
ATTORNEYS AT LAW l� -
By
111 CONGRESS AVENUE TELEPHONE (512)322-5800
SUITE 1800 Mr.Gay's Direct Line: (512)322-5875 TELECOPIER (512)472-0532
AUSTIN,TEXAS 78701 Email: ggay@lglawfirm.com www.lglawfimt.com
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MEMORANDUM 5
tr
TO: All North Texas Metroplex Cities
FROM: Geoffrey M. Gay
DATE: May 31,2002 .
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 gm.-
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
ATTEST:
2
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 bill including the cost of gas.
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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
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:
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DESCRIPTION COMPANY DUCI DIFFERENCE
REQUEST RECOMMENDED
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 35,480, 117 $ 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.
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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........................................
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
H. Amortization Expense—Safety Compliance Proms...............................................35
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SECTIONIX: RATE BASE.........................................................................................36 A. Safety Compliance Program....................................................................................... 36
B. Cash Working Capital ("CCWC")................................................................................. 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
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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
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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 li
NORTH TEXAS METROPLEX SYSTEM
PROPOSED ANNUAL RATE INCREASE
FOR THE TEST,YEAR ENDED SEPTEMBER 30, 2001
BY.CUSTOMER CLASS
A) ) (C) (E (F
Residential $273,385,183 $298,173,541 7$274,988W,358 9.07% 24.22%
Commercial $130,858,349 $137,257,322 $6,39 ,97 44.89% 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 8.09% 23.54%
Service Charges $3,926,080 $3,930,694 $4,614 0.12% 0.12%
Total S42ZA2 19 456 L78 U2 8 3 1 &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
casts 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
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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.
'st
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. l-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
* Request 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 Gas 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.
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4
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).
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 raternaking 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 pen-nit 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
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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:
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
x;
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.
a 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 moss 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
'
synergies were expected to create benefits, not require frequent rate cases. In other words, rather
~
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 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.$ 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.
a 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 XH 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 recommendhtion. 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
TABLE 3 .
REVENUE REQUIREMENT IMPACTS OF
DUCI'S PROPOSED ADJUSTMENTS -
Return/Capital Structure $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
SECTION 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 i
7Adjusted
Customers 637,502 51,457
Adjustments 5,280 1,749
ustomers 642,782 53,206
Per Books Sales (MciT 48,901,838 27,927,242
Sales Adjustment Customers (Mcf)14 780,434 272,879
Sales Adjustment Weather(Mcf)13 (6,279,616� f2,563,319)
Test Year Sales (Mcf) 43,402,656 25,636,802
Test Year Revenues $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
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
Janua 685 670 45
February417 !484 -67
March 402 116
April 41 -34
Ma 0 0
June 0 0
Jul 0 0
Au ust 0 0
Se tember 3 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.
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 RE 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.
20
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
SECTION VI: ALLOCATION
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-l.
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
v
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%
aP 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 29 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
1 + + + WWM,TIT M. + +
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
29 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.
TABLE 7
DUCI'S RECOMMENDED CAPITAL STRUCTURE
MIM
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
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%.
to
u\
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.
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 earnin s
Pg , z
;r
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 TXUIEnserch 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
}1
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
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.
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 non-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 ran 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
Calendar Year 1999 $945,860
Calendar Year 2000 $1,451,095
Test Year 2001 $6,565,245
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
SECTION IX: RATE BASE
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
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'1
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.
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.
TABLE 9
REVENUE RELATED TAXES
State Gross Receipts Tax 1.8648%
Local Gross Receipt Fee 3.2112%
Total Revenue Related Tax 5.076%
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 rato"Wof 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
r�
The last aspect of this rate review is the ultimate rate design. Once the appropriate level
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
SctiEbul-E i
THE NORTfi TEXAS METROPLr=X Df8TRIE IUTION sys'rm INCLUDES:
Addisori Forest fiill North Richland Hills
Allen Pact Worm�' Narthial�e
Anna Frisco Qvilla
AF, yle -Gartand Pantego
Arlirlgtoit Glenn Heigts Parker
Aubrey Grand Prairie Pilo#Paint'
AzleGrapevine Piano
Balch Springs Haltom Cif Ponder
Bedford` Haslet 4 Princeton
Benbropik Heath Prosper
Blue Mound Hickory Creek Richardson
,Blue Ridge Highland Village Richland Hills
Burleson' Hurst River Oaks
Carrollton Hutchins Roanoke
Cedar Hitt Irving Rockwall
Celina Josephine 'l Rowlett
Colleyville Justin Royse City
Coppell Keller Sachse
Copper Canyon Kennedale Saginaw
Corinth _ Krum Sanger
Corral City Lake Dallasf Sansom Park.Village
Cross,Roads Lake Worth; Seagoville
Crowtey Lakeside Shady Shores
tlalworthingtori Gardens Lancaster Southlake
Denton ` Lavon Sunnyvale
DeSoto Lewisville ( The Colony
Double Oak Lincoln Park Trophy Club
Duncanville Little Elm i Watauga
Edgectiff Village Mansfield Westlake
Euless Marshall'Creek Westminster
Everman McKinney Westover Hills
Fairview Melissa ' - Westworth Village
Farmers Branch Mesquite White Settlement
Farmersvilie' Mobile City' Witmer-
Fate Murphy i Wylie
Flower Mound Nevada
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SCifEDUL't2
TXU GAS DISTRIBUTION
;NORTH TEXAS MSTRoPL5X
REVENUE REQUIREMENT
TESTYEAR ENDED SEPTEMBER 30,200I
s
COMPANY`$ # bucils
PRESENT RATM AbJUSfMENTS g1Fc6mmEN6A-nbN
Ouerating'ReJanues: - '�
Residential 5273.385.183 56.352,743 5279,737,026
Gomnercai 130,85i 348 2.°84,4cp 33.1,M2.409
Industrial 14.255.507 Q LL14155.5D7
TOt$l - 5418,400.039 - S9;346,803 5427,845.B42
Other R'even6e 3 9. 3t1694 : 4� 3:030.gct"
TOTAL'OPERATING REvr=14UE§ S*422:425 733 a437 775 5.3C
Operating Expenses_
'Gas Cost. S261,285.153 0 5212SS,t53:
Operation<laintemnce Ezp 77,208,403 '12.64Z312 ca,SoB,Dt3'
Taxes Other Than FIT 34.352.839 2.554;905 797 a 4
DepreciaCon&Amortization:: 24,901,795 1.134,222 23,787.573
5
In'ereston Customer Deposits 638,634 - 0 638,634
Federal Indome Taxes t5,D17,692 3.981,480 noc.t 12
ReWmon Rate Base 42.874:30 713941176 35,450.21T
N TOTAL REVENUE RECtU1REMENT t s "27&.fi0a 7 7 7¢ G4:8.571 714
i
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SC DULE 3
TxU GAS D1STRMUTIION
NORTH TEXAS DISTRIBUTION SYSTEM
COMPANY'S PROPOSED REVENUE REQUIPEMENT
TEST-YEAR ENDED SEPTEMBER,30,2001
I
s
R
LINE PRESENT; PROPOSED PROPOSED PERCENT
0 )ESCRtPT10N RATES E RATES 1NCRFA�;g_ IN READ
-.1 OPERATING REVENUES
2 RESIDENTIAL 5273.385,153 S298.173.541 S24,788,358 9.07la:
COM iERCIAL : S130.858;349 S137,257,322. S6,398,973 4:8 %
4 INDUSTRIAL $14;255,5t37 $16,917,272 S2;661.765 18:67�!
5 SUBTOTAL $418,4MO9 $462,348,135- S33,849,096 $.IS%
6: OTHER RE%E UES S3 926'191 $33:930 694 $4,5503
7 TOTAL OPE RAZING REMWES $A22:4Zl4Q 4 r 78 829 S33.851599 �°f
8
9' DESCRIPTION TOTAL RESIDENTIA! COMMERCIAL INDUSTRIAL
10 REVENUES $422,425,234 5275,956,426 S131195,493, 514,273,4
11 TOTAL REVENUE REQ.UIREMENT
12 DESCRIPTION TOTAL (' RESIDENTIAL COMM'=RCIAL INDUSTRIAL
13 OPERATING EXPENSES
14 TOTAL GAS COST $281,285,153 S162,762.954 S94;320,423` S4,201.7E6
15 OPERATION MAIN TENANCEEXP. $77,208.399 S64,216,045 S11,001,400 Si;990.953
16 PROPERTY TAX $6,758,920 S5,258269 S1,1Z6,238 S324,313
17 PAYROLL TAX $1,861,969 S1,545,716 S270.539 $45,665
18 REVENUE RELATED"TAXES S21,442,45$ $14.007,321 S6,704,734 S730,403-
19 OEI?RECIATIaN 8 AI .RTIZATIQN S24,901Y,5 $19,373,334 $4,333,599 S1,194.862
20 INTERSTONCUSt DEPOSITS. S625,699 S423,153 $202,546 SO-
21 INTEREST ADVANCES S12,935 S8,748 $4,187 Cn
22 FEDERAL(NMMES,TAXES 4670163 $80�_7 5) $3.711,705 1765:930:
23 TOTALEXPENSES : $398,767,491 $266,788,118 S121,725,422 S10253,913
24 RETURN 01`4 RATE BASE $23,657,739 510,1fi8,008: $9,4"70,076 S4,619;584
-25 REOUIRED'RETURN ON RATE BASE $42,874,393 $33,390,495 S7 373;911 S2,109;986
26 RATE DEFICIENCY : S19;216,654- 523,222,487 (32;096,164} (51,909,598)
27 ADDITIONAL"FIT RI aQUIREMENT S10,347,429 S12.504.416 ($1128.704) (S i 028:245)
28 OTHER RATE REDUIREMENTS. $2,571,083 $1,886,123 S568,633 5116,328
29 RATE INCREASE REQUIRED $32;135,1¢6 S37,613,026 ($Z656,236) (S2,821,515)
30 REVENUE RELATED TAXES $i,718.464 $1.122 553. 937 321, 58:535
31 REOUIREDINC"5 $3+3,5NirJ7$ $36.735,6 0` (SZ116,Q.16) (S2,7B2,880)
32 OTHER REVENUE INCREASE $4,614 $4.614 54` SG
33 SALES tkREASE' S33,848,961 S38,736.96s, (S2,T18;916): (S2,762,G60)
34 cbmPANY CL.IMEG WCREASE $33.849.09a S33;731 478. ($2:119:187), ($2:7i 3,195}.
35 DIFFERENCE (S135) ($5121 $272 S215
36 PROPOSEDREVEWUES: - $456,278940 $315,692,218 512907o31i ti MQ.301
37 OTHER REVENUES $3,926,101 S3,570,94,3 $337,149 517,�g9
38 SALES REVENUES' $4523A`Ib3 S3"2,116.6El 51M8.739:162 ,St1442a2"
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SCHEDULES
c
TXLl GAS O'l$TRtt]UT10N
PR!{7R.NORTHWEST ME'T`RDPLEX CITIES
COMPARItJG PRIOR.,RATE q-14ANGES TO CURRENT'CAS-t .
TOTAL
I
COMPANY RPfE INCR. COMPANY RATE
31R6 QUARTER 2001 INCR.MARC'd 2002
LINE NWMETRO NW.METRO
NO:
61ty, TOTAL TOTAL DELTA.'
i
1 ADDISQIV ;$179,334 $254,533: S75,199
2 ARGYLE ($549J 'S17,437 S17,986
3. ARLINGTON s989,91*5 $2,914,994 S1,925.079
4 Al1sREY $138{ 12,646r S21,D3o 533,682
5 BEDFORb ,475 $394,720 $256,245
4
6 CARROLLTON 51.333,720 $1.570,493 $236773
7 COLLEYVILLE i $7,511 '5359,187 $351;67$
8 COPPELL. ($19,342), $539,715 5559,057
9 COPPER CANTON $31 �5916 5885
1Oi CF20SS ROADS CORINTH
(V39,606) ST64,193 $303'1799
(S93y $0 eo3
12 DALWORTHINGT'ON GARDENS 892 $34,100
13 (7ENTC iN. *85,858 . $1,207,537 5321;679
14. OOUBLE OAK $894 S10.684 $9,770
15: EULESS $to5.78 $363,786 SiG7,9G3
16 FARMERS BRANCH '$537,833_ 5568,946 $31,113
17 FLOWER MOUND $15"a,459 5832,271 $675,812
18 GRAPEVINE $28085 $675.432 $390,447
19 HICKORY CREEK $2,031 : $26.753 .$24,722-
20 HlGHL4ND VILLAGE $27,710 $224,788 S197,078
21 HURST $188,320 $454,053 $265,733
22 IRVING S3,935,071 $2,128,238 S193;167
23 JUSTIN (59,113} S33.394 542,507
24 KELLER r 5112,552 $434,213 :- 5321, E
25 KRUM S13,689 $27,977 $ 4,280
26 LAKE CIRLLAS $9,OCf8 S82,0o3 $o3;G85
27 LEVYISVILLE $165,264 $833,90i 5568.644
28 LINCOLN PARK ($#2,053}' $2,295 S14,348
29 MANSFIELD $159208 S282,968 S123,760
30 'MARSHALL CREEK Sil,630 $3,477 (S3,213)
31 NORTHLAKE 3a. 51,265 S1.265
32 PANTEGO $16,597 S40,917 52,,32E
33 PILOT POINT $47.127 $73,873
34 FONDER; S1{,192 58,062 (53;130}
35 ROA,NOKE 546:320 S29;366 k'slm54
36 SANGER ;($29,963) $$50,691 880.054
S7 SHADY SHORES jS17,614} $19J32 S36,146
38 SOUTHLAKIE } 5396 $433,564 $433,168
39 TRflPHY CLUB, S9788 $46,420 536.532
40 WESTLAKE $2,�82 Srt3.#88 S10,40#
41 OTHER 385 12 $0 (5385,212}
42 TOTAL. $7.509:396 S15:133.812 S7 624.416
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SCHEDULES.
Page 1 of 3.
TXVGAS DISTRIBUTION
9OnTli,TEXAS METROPCEX f]iSTRfBUTtON SYSTENt
PRIOR CASE DATA AND CURRENT PROPOSED REVENUE`INCREASE jDE kEASE}
PRIOR RATE CASE' CURRENT
DAIS LAST PROPOSM -
6tb1: M 1EST AR, APPRQVET 1 REOPESTED S RA-¢CHNG INCREASE DIFFERENCE
1 Addison 9/30100 $163,161 1189;167 8/28701 $254,533 $91,372
2 Allen 12/3i/93 $230,876 5508,616 1/2301 $625,582 $394,706
31 Anne 9f30/00 $25.669 $27,683 916101 $9,171 $16,498
4 Argyle 9130100 $1,542 -$50 7131101 $17,437 $16,679
5 Arlirigton 9r30l00 S6W,310' $1,357.568 8/17/01 $2,914,994 $2,273,684
6 .Aubrey 9130100 -S15,810 S13,697 811101 $21,015 $36,825
7 Azle I20,I99 SK507 991,659 1131401 $27,947 -$36,560
8 .Batch Springs 92r31KJr $109,050 $109,050 518101 $108,693" -5351
9 Bedford 9130100 $69,467 $167,403 03101 $394,720. $325,253
1.0 Sentook. 12/31W $33,096 $95,984 2/9101 $62,328 $29,232 _
11 Blue Mound 12131199" $18,266 $27,824 2/510i $17,336 -S930
12 Blue Ridge 00/00" 4781 $2,964 .916101 $4,732 $51513
13 Burf4soh 12131199 $110,651 $178,050 2112/01 $74,221 -$36,430
14 Carrolton 9130/00 $1,115,4"23 $1,820,688 8/21/01 S1,570,493 S455,070 "
15 Cedar Hi{j MOM $52,509 $52,509 9/4187 $52,199 4104,708
16 Colima JI30104 $20,601 1 $10,303 W31101 $15,644 ,-$4.960
17 'Coll eyvMe" 9130100 $27,711 $3.,768 9119161 .$359,187 $386,898
.18 Coppell 9f30100 S1381594 $25,701 8/9101 $539,716 $676,310
19 Capper Canyon 9=100 -$159 $7 817101 $916 $1,075
20 Corinth 9/30/00' -$1901916 4123,986 4/30101 S164,193 S355,109
21 Coral City None, None. None 12{2218T $564 $564
22"Goss Roads 9 OMO, -$202 -$95 1f0100 $0 S202
23'Crowley 12/31199 S16,918 $34,409 2r1201 $5T,825 540,907
24 DaAvorthington Gdris 9P30/90 1 $1,449 $3,530 9/18/04 534;100 $35,549
Z5.Denton 913040 '$1,307,759 $1,205,583 7131101 $1,207,538 -S100,221
26`be8oto 12131197 S164,516 $322,914 3123/99 S214,654 $50,073
27 Double aak 9130 D0 -S1;T20 S687 9f8/01 $10;6a4 S12;384
28 Duncanville 12/31/98 $340,678 S484,707 2/16/00 S127;707 -$212,974
29,Edgeclifflage 12131199 $3,216 $16,26t. 7J7101 $72,827 - $9,611
30 Euless 9130100 S87.941 S208,711 8116/01 $363,785 $275,844
31' Evernian i2?m/99 S2;591 S27,259 2114/01 $26*s S23,8i7
32 Fairview 12/31139 $5 374 t $13,21 a 21T101 518 149" $10,775
33 Farmers Branch: 9190100 S420,976 5806,487 9110/01 5568;945' ',U7,976
34' Farmersviite, 9r30/00 $11,746 $43,009 019tol $28.628 $16,882
35. Fate 9130100 $51124 -S3,860 8122101 52,24S, S7,373
36.FloweeM,ound g130106 -S81,244 3227,188 8/8/01 a832.270 S913,514
37 forestl-titl 121,31199 $33",305 SID2,219 2114M4 S63,080 S29;775
38 Fod Worth 1213169 52;948,582 56.1 i G,916 2/6/01 $3,896 259 S947,677
39 Frisco 12/31/99 $230,751, $412,185 1/26101 $51T,436 S281,735
49 G6rland 12131199 Sl,263;314 $2,126,156 511'MI, $2.153,836 5889.922
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41 Glenp Tifthts IM11.97 $16;714 $33,977 4130199, 428,433 311.719
42.Grand Prairie i7J31197 1149,10' $264, ,d gM/OQ $1,217,865 $1,068 738
43 Grapeuz�,6 9/30100 $171,883 ,S340,757 8124/01 $675,432 $503,W
44 Rglt6in-City 2 f31i99 $144TZ75 $349,679 'i115I0> $235,754 $95,484 -
.I k3asleE 12(31/93 $33,9Q7 $2i.987' 2/Slbi $3,955 $37,862
46 Heath S130100 $72,88 i $100,956 8122JOl $19,328 -$53,552
47 F8cic Greek 9130100 -$04 S1,550• 812t01 %$26,7,5a $27,427
48 HighlattdVillage. 9/30100 -$29,607 $25,084 813T/01 $2241789 $254,396
49 Hurst . 9(30lf10 $86,617 $209,971 846101 $454,053- $367,436
50 Hutchins' 6=190 S6;448 f $13,074 6121/91 $81,033 $74,585
51 truing 9/30100 $1,272 078 VA08.076 si12/01 a2.128,239 $356161
52 Jasephino 9130100 34;950 $6250 9119101 S2,866 -$2,084
53 Justin W30100 -$11,126 $9,399 '8/10101 $33,394, $44,522
54 Kellet 9130/00 S44;748 :$119,419 9/10101 $434,212 $389;464
65 Kennedale i213119S $11,297 $28,760 2113101 $22,812 $11,515
5$ Krum 9130J04 S.i;993 $14.769' 8l13l01 $27,978 $15,985
57 Lake Dallas 9130100 $3,416 $9,398 8/21t71 $62,063 $58,647
58 Lake Worth 12r31tg9 $10,693 $46,993, 3/5/91 $33,842 $23,149
59 Lakesidd:; 12131109_ $588 ; $7,478. 312101 $6,491 SS,906 -
60 Lancaster 6130/±?0 $64,919 $130,712 6/1719i $154,045 $89,126
61 Lavott 12131t99 $520 $1,578 2119/01 $2,937 $2,417
62 Lewisvjtte 91301Q0 $1341978, $416,268 8•/9/0 $833,900 $964,878
63 Oman $3,89i $3,891 ;
64 Lincoln Park 9130100 Si3.267 412,OQ0 4/2710i $2;294 $15.561
• 65 LittWEtin: 12131/99 : $$7,230 S19.775 11241011 $29,594 :$22,364
66 MansfWd 9130M0 $87,817 $275,937 914101 $282,967 $195,150
67 Marshall Creek 9130/00 $5;216 $6,052 8124/O $3,477 -$1,739
68 .McKinney 12/31/99 $408.481 $743,862 1131/01 $847,534 $439,453
69 Melfssa 9130160 $9,969 -$6,910 91610i $4,417 $14,326
70 Mesquite' 12/31/97 $943,959 $943,959 5!8l01 $957,267 $13,308
71 MobileC4. 9/30100 S1,833 $2,403 9/21/01 S1,081 -S752
72 Murphy 12/31/99 $10,679 S29,623 2112101 $60,657 $49978 .
73 Nevada 9/30/00r $5,814 $12,893 W19101 S10,683 $4,850
74 North R6c and Hills 112131199 5158,314 $344,459 2/13101 $257;145 $98,831
75 Wortlitake 9/30100 $2 $2 816101 $1.264 s1;262
76 CYvfita '12,J31197 S 1,223 $3,936 3/31/9ti $7,867 $6,644
77 Fanlego 9130100 $4,870 $15,982 9/5101 $40.516 536;046
78 Parker 1213/199 '$2,109 i 55,678 2112(01 55,404 $3,295
79 Filot Point 9/30/CO 426,646 -$26,581 8127101 $47,126 S73,772
80 Ptana 12131199 51,531.134 $3,283,554 1123/01 S2,963;218 51;432.084
81 Ponder 9130100 S1,992 $11,555 8l6101 $8,062 $6,070
82 Princeltort 9/30100 $16,411 $23,632 917101 $16,987 $576
83 Prosper 12131l99 S22,040 -$13;17 1111(O1 $13878 $35,918
84 Rendon $18,476 533;476
85 Richardson 12.131199 5631984 51.341.028 VV(YI $1280,52.3 5648 54<
86. Rkhtanri'Wis 12/31199 S24,968 $96,351 2114101 S65;329 S40.341
87 river Oaks f:i' 199 S16,080 575,010 311101 $59,278 S43,198
Sa Roanoke 9130/00 S37190 ? $47;129 8/9101 $2S,3v7 57,823
89"Rockwatt 9i30(99 $276?22 S417,205 10720t00 S127 072. 5:149.250
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Page 3 of 3
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9Q f owlmr 1219;1199 $T86,640 $465,1'99 112810', 55$3;798 $377,158
Sri .RAYseCity 9!3(110Q 426,647 u1.7,06k -8121401, S1&314' $42073
92 Sactise /2131199 $37,612 M3,4W 21f5lot $144,494 $t'0'$,382
93 Saginaw 12131199 $931500. $119;733. 215101, 598,100 $4,6fl0
94 SangeP 9134100 344;126 -$28,24c .8 vffi 1 $50,690 $94`,816
95 Sansdfb Park.VUlage 12/31/99 $7,647 $36,4t7 21M) 528,90T S21254
96 Seagoville f213119T 551.189 $52,181, $/8101: $70:672 $19,483
97 ShatlyShores 913(d00 421,256 517.200 $12101 $19,132 $40,388
98 Southlake 9t30l00 $59,293 $783' '81101A1 $433,563 $492,656
99 Sunnyvale. 12131197 $25,961 $25,961 518/01 $30,975 $5,014
100 Ttie Colony 'I2t31199 : $41,107 $1072tl6 1129MI 3116,5$7 $75,480
101 Trophy CiUb 9tmoo $1,956 $9,032 8124/01 :$48,419 $44.463
102 Watauga, . 12/31199 117,858 $55,9i7` 219/Ot 544,098 $26,240
103 Westtake ' 9130100 -$957 S2,664 8/23101 $13,189 $14,146
104 Wesim,insier' 9)n/60 S1,044 -5591 916l01: S2,637 $3,681
105 Westover Kills lls 12/31199 5836 $19,296 2/26/01 S101,458 $9,622
106 Westwoith Viltage 12/51/906 $4,484 $23.6d6 2127(01 $17,754 $13;265
107 White Settlement 12t31199 $43.,537 $121,881 2127MI S85,808 S42,271
108 Wilmer MOM $23,586 . $26,144; 615191 111,537 -$12.049
109 Wylie.:. 12/31199, $75 744 J125.24 21161Q1 1131,489 $55,745
110 DaltaslNW Metro ,$T62.31 $782,3i
SI5,45213S $29,017,707 $33,855,538 518,405,403
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'Company Response is Cities RFt 2-2,Attachment 1.
2Executive Summary pages,6,10.
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TXU GAS EN 18UT$)4
NORTH TEXAS MET$OPLEQ DISTRIBUTION SYSTEM
COST pER.CUS'FOI I E4R CUSTbMER RELATED COSTS BEFORE AWAMR MERGER'
=TE$T YEAR ENDED SEPTEMSEk 31'1,2061
a
.RR;REPORYP Jtitc REPORT, RRC REPORT 7tRC REPORT RRC REPORT RRC REPORT
OE 1PIHI.Y? 4;17
:3 -na 1.m .5323 2m 11
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.CUSTOMER ACCOUNTS EXP6Sr;C $F}..00. SO.00 $a.00 S0.0a SO.CO t 902 'SUPEFtVoc" 50.59 SO.S9 - $O.17 5020 SO.tt SO>a8 2 902 CUSTOMER ASSISTANCE EXPENSES 535T S3_�9' S7S8. 58.02 58,32 S62i 3 901' CUSTOMER RECORDS i COLt.ECT*N OTEN5£S 312.99 5/268 318.28 S23.t8♦ St 8.02" 320,61
4 904 UrK.OtLECri01.EACQOUNTS 53.04: 33,39 5244 St 56 5252 59.52 S 905- MiSCE}ANEOUB CUSTOMER:ACCOUNTbzbPEN$E5' 50.00 _SODO S0.D0' S0.0¢ 50:02 'S0_d}
6 tom CUSTOMER $2a.20 520.15 $28.48 53297 527,00 53663
TOTACCUSTOAIER AGCCXINTSEXPENSES VINO 9Ci jtZi4 $%T6 526.02 53T.40 $24.47 P7.11
T CUSTOMER SERVICE 3 SALES EXPENSES 50;00 50.00 $6.00 $0.00 S0:00 solo0 ul
8 909 SUPERVtStON' _ SO.Ob S0.00 •so= 30.00 $0.da 50.00 t
9 210 CU3T0M",k6 STA.CE EiFEN5ES SO.0. S6.D0 $2,30 3[.S2' 3s.a4 ss is SO oil INFORMATIONAL ADVERTISING EXPENSES :Sa.f .. 50.15.. $D.07' 'SO.a2 $a.Oi 'SO.t8
ti 922 MISCELLANEOUS CUSTCtAER SERVICE EXPENSES 50.00. '.$0,00' ,SO.00, - .SO.Oa,. $4.00'
' 2 9t5 SUPEFivimm 05
$1.St -,51.30 $Y.t9 -.$0.2] $0, . SOAi
13 916 DEMONSTRATION 8 SELLM E sNsES St.2'0a 50.00 Si.Y2' $0.70' .. $4,0 50:05 '14 917 PROMOTIONALAOVERTISIR'G ESYENSES' 30. SO.JS�.. $a.23 $0.31 S0.7T
t6 91B MISCELLANEOUS SALES PROMOnO464aE 30.T8 ,$all$ $O,U S0.0b SO,ta $?�.OS
15 TOTAL CUST SERV.B SALES PROM.EXPENSES 3.0 � ,32.74 $5.6530,10 - $0.05
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17 A0MiN15tRATPlE 6 GENER,ALEXPENSES SOkOU -SO= 50.00 30.00 50.00 "Sa.00
t8 920 AOMSNI5TRATiVEBGENERAL-S4ARIEB $20.19 :517.48 52.8T $1.08 $20T 30.99
19' t32T OFFICE SUPPttES EXPENSES 58.39 :. 58.98 $5,62 St_6T „. 50.73 -. S0.61
-2Q. 922 AGNIii15TRATiVE:EXK'[i+Sl:s1'RANSFERR6OtREOtT $2,eS '$222 ;0.00 $O.oO $s;00SO Oa
2T 9Z2 OUTSIDE- Pt Sakous EMOYEO 50:53 5228 Sze 29 528t{. 52T:Ea S2d,9T
"�22 924 PROPERrf INSURANCE :S7PST S2.82 (SO." SC.63. Sam
23 925 WURR 3 3 OAMAG£S S84� ST.66 53.74 5a.82- 54.02
a� + 926 EMPLQ9'EEPc`R'SIC.VSd BENEFR$ 574,)8 $t3,94 `518:38 $T.48 $6.29 57:74'
25 527 FRARMSE REOUIREMEN?S',, 50:00 30.00 $6 00 S0.00 $0.00 50 00
29 924 REGL'LATy7Rv COMwSS164 EXPENES So,t'# -SLAB SO.12 $028 S094
p 929 DUPLICATE CHARGES CREDIT $0.00 SD.00 `50.00- 30.�0 5a,60 $0.a0
'.28 t33R2 W57;GCOOi'dLAOVERTtStNG EXPENSES 50,00 $0.00 $0.01 30,00: �SOp,1 SV.1a"
29 9302 MISCELLANEOUSG6YERALEXPENSES $0.81 S0.S8 S3,74 5423 $2,92 $3.23
331 93t RENTS - 59.57 ::4.50 $0.24 Sa.43 $1.20 'SIRS
gy{ "'ITENANCE GENERAL PLkHT'" St.29 St.22 SO.OY 30.04 Sa.DO .50,00
32 TOTAL ADMtRISTRA4VE s'GENRAL EXPENSES S57.02 S58.95 $62.93 .:... $47.$2
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TXU GASDTSTRiBUi]ON
RORtH TEXAS METROPLF-X DlST bU710N SYSTEM
£0ST PER CUSTOMER F0l2 CUSTOMER R'SL kTEFi COSTS BEF0RE,AND AFTER MERGER
TEST YEAR ENDED SEPTEMRER 10,2001
.fERC.` FEfGtr FERC KE72G` FERC' 'FERC
TXU EIECTFtZ ..FORgt FORM PORMI romI FOfWI F9R511::.:
pFtru�u :. 1?fS i22f -1ZTf" 39)d ..3343 20�
CUSTONERACCOUuTSEXPERBES.. WOO, I0.00 50.00 $0.00 30.OQ Sf1.00
4 403 SUPERV151ON $O-�o SSC._31) 30.00 =0 S0.20 SA14
2 902 METER READ!NG S5730. :57134 `S6.D2 $7.01 S8.29._ 38.67
" 3 963 cusmuER RECoRG'S;S COLucro4 131129, 244.S4 :543.68 .S43.Tt 541180' $3*72
4 904 ViCOLLECTt6LEACCOWTS $7 e5, 'S6.15 5527 '310,44, 52.89. 58.78,
5. 905 fMSCELLANEQUSCUST6UERACC=i-,S 5002: $0.00 20.25 $0G0 �i0:01 Sa.OQ-
8 TOTAG.CUSTOMSR AtCOVMTS EXPENSES $520S': 537.72 - $54,16 261-SW $51.14 $5031
T - TOTALLUSTOMER ACCOUNTS EXPENSESYW904 $M.tD': .$62.82 $52.2i ,$S4,7& .552.99 $4f.53
S Cv3MMER SERVICE&1NFORMAVONAL,EXPENSES" SO.DD 50.00 "So= $0.00 50.00. SDOD
9 :907" SUPERVMrOo -" 11.97 "21.03 30,51 $1.69 S12D $0.43
50 9G& GUVOMEdRASS)SUCEEVVSE Stx.87. I18:98 52d17 S23.2i ;24.0 $zvii
Ott 909 7NFGRIAKt16NAC 4iNSTRUCttONAL EXPENSES S0.64 50.00 50.49 S0,/S _.S0.0G S0.0o
t2 4/0 >WSCELLANEOUS GUST.SERV.d IWFORXn EXP. $0.03 30.01 S0.04 .:I0.34. 50.24 so.02 '
13 "TOTAL CUST.SERV d LNFORACL EXP: - 530-$1 $19.43 $21,St S2S.37 523.35 M63
14 SALES EXPENSES 50.00:. 50.00 S0.0D 'SOAO $0.00. $0.00 .
IS 911 SUPERNSIQv .. SO.00" -$41.00 $0.01 $003:. SO.OsT. `(SO.m
16 912. OEM "
C7.YSTR.i71ON dSELS.7NG ExPENSc: SQ.00 $0.39 52.1S � ZS-20 52.83 .5059 ..
17 913 AOVER715INGEXPENSES S0.00 $0.00 'S0.12 - '$0.35 $1.09" S0.36
1d 916: MISCELLANEOUSSALE3 EXPENSES S0.00'. 50.00 5000 5273 S2.04 $1.39 ...
19 TOiALSALES EXPENSES - SDAD r So 39 52.27 58.34 55.96'.- -$2.34
20AOMiN[5'.7RATPf�a GENERAL EXPENSES" f0:00'. .30.00 ,3000 S00O $0.00 50.06 ..
21 920 attG:SA4ARiES. - St},15 .. 511:54 59.SZ �$6.27 57.34 $tt;00
22 921 OFFIMSUPPUSSEXPENSES: S3.56 $3,02 8Z.62 $1.84 - 53.25 S{a5 .
Z3 922 AOMiNfSTRATNT EXPENSES -CREDIT '50,00 $0"00. $0.00 S2066. S8.m 53.36
24 ;$�I- OLTS�'SERvims - - 3401,1'.: $43.26 S4262 528.30: 1$43,64 S69:53
25 924 PROPERTYINSURA.VCE. .. $aJs S7,62 'W,c S5.20' - 53.97 $355
26 925 PULIrES30AUAGES $5:43: S4_44 24.19. $243 53.11 "56.16
27 1526 EMPLOYEE.PENSCON z BENEFITS $34:17! $SS24 SM83 $29:23 MJ9 5MQ 7
28 9ZT FRANCNt$E-RCU-zEMENT9 50'00: SO.00 $0.00 .S0.00- SO,CO "50:00
29 923 REGULATORY COMMtSWON EXPENSES S2.06 $240 - 51.% $2,0'r SCF,S§ '$0.24 -
. 30 '929 DURICATE OtAXGES{.YiEAT $0.00 50.00 -�.$0 Da 30.00 um $0.04
31 930:T GENERAL AOVERTr..NaEXP6NSES S148. U,42 SC.99 $0.01 S0.02" 50.03
32 9342 MISCELLANEOUS GENERAt.EAP04SES 522.13 S17,9T S 8.66 31 t,36 $13A4 527,12
33 911 Reim $2.22 St.79 $L?2 . S1,42 S1:43 S19t
34 TOTAL QPERATIOA ASG V31.19 .$725.76 $11125 $108.74. ,S-IIS.21 S13729 "
35 925. AI&G,,%WNTENANCE $0.87 50.56 S0.43 $0,37 SC.28 $0A7
35 TOTAL X-0 $132.06 S129.42 St19.T0 5109.T1 $11S.49:: $137.76
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TXU'GAS QISTRtBUPON
_NORTH TEXAS DISTRIBUTION SYSTEM
TOTAL Dlidi-S RECOMMENDED REVENUE REQUIREMENT
'TEST YEAR ENDED SEPTEMBER 30,2001,
Y
d
2lNE PRESENT3 PROPOSED PROPOSED PERCENT
NO, DESCRiPT16N RATES { RATES INCREASE j4EREA3
1 OPERATING REVENUES
2- RESIDENTIA.L 527g,73'7,926 $298,173,541' 518,435,615 6.59%
3 CONIMAERCIAL $133,852,4& S137,257,322 53,404,913 2.54% I
4 INDUSTRIAL $14 255,507 S16.917.272 $2.661.765. 18,67of,
5 SUBTOTAL �S427,845,842 $452,348,135= S24 ,402,293 5.t% s
6 OTHER REVENUES 53.926.191 S3.930,694 $4,503
7 TOTAL OPERATING REVENUES 54,11 772.033 -A55 276 829 S24ZI26.796'
g" -
$ DESCRIPTION' TOTAL I RESIDIINTIAL COWAEAt 144 INDUSTRIAL i
10 REVENUES '$431,772,033 $283,265,59Q 5134227,761 514,285,572
11 T'OTAC REVENUE REQUIREMENT
12 DESCRIPTION TOTAL. RESIDENTIAL:.:` COMMERCIAL INDUSTRIAL
f ,
13 OPERATING EXPENSES
14 TOTAL GAS COST $261,285,153 $16$296,2.15 $89,081.180 $3901,758
15 OPERATION&MAINTENANCE EXP. $64.566,0a1 $50 803208 $1 f 295„455 $2,467,427
- 16 PROPERT"TAX $5.i26,464 $3.790,720 �S-,475,567 S430r.176 ,
17 PAYROLL TAX $1.746,067 $1,449,515 5253,748 S42,824 i
18 REVENUE RELATED TAXES S2119161748 $14,329,801 $81856,69$ $73a.250
19 DEPRECIATION$AMORTIZATION S23.767,573 $15,733,30$" 56,124,31Z S1.909,952
20 IbiTERST:ON CUST.DEPOSVS, $625,699 S423,201 S202A98 $0 fi
21 INTER EST ON CUST.ADVANCES. $12,935 $$,7'9 y4t1$6 s0
� 22 FEDERAL fMCOMES TAXES 512:999,24 $029,359, 55 24 10. 1 221:33t3
23 TOTAL EXPENSES $3°2.645,90,7 $261,364,077 $120,548,155 $10.733,726
24 RETURN ON RATE BASE $39,126,0 36 $21,901,513 513.672.60fi 53,551;34 i
25 REQUIRED:RETURN ON RATE BASE $35,480:217 $23,188,881 $9,270,574 $3,020,762
26 RATE DEFICIENCY f$3,645;,820} $1,287,368 (S4,402,032) (S531.085)
27 ADDITIONAL FIT REQUIREMENT t$1'963,'134} S693.198,; $f 2;3TO, 2 5 laza5 509 .
28 OTHER RATE REQUIREMENTS S2,571,083 S1,604,839' 3771,424 5I-K820
29 RATE INCREASE REQUIRED ($3,037:870) $3,585,405 {$6,000,933}° ($622,233)s
30 'REVENUE RELATED TAXES 162448 106.213 56 822 a5 113
31 REQUIRED IN REASE (53,240,6 $) 33,479,1' 1 ($6,451,755} ; ( 62�,646)I
32 OTHER REVENUE INCREASE $4,61#. 4 614 � +�
33 SA.LES 1NC.REASE ($3 204,932) S3A-(4,577 (56,051;755) (S627,645):
34 COMPANY CWMED INCREASE $33 849 1066 538.131.4"78 ($2,f 19:i87) (w2.763.195}I
35 DiFr=ERENCE (537454.0?�8) ($35 256,9C1} {53,932 56$} 32,135;543
36 mQPOSED REVEi`QEs $42$.571.715 52$6.744 i 512�3_t 6J 00o Si3.6�5Z 928' ,
37 OTHER REVENUES 53,926,i51 33,570,8 ,337.145 S1789
38 SALES REVENUES $424640.910 S283169.224 5127:$3i.857 $'t3.63 _j,
t
I
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. TXU GAi D7SMSU-M*
NORTH TEXAS Dt_sfFIMUTiON SYSTEM
TLSTAL DUCi'9 TtECCf-MENDEo Oam EXPERSE9''
TEST YEAR ENDEo.SEPTEMSER 30,ZDDT
I,md .� TOi4i
NtL A[CT 'DESCRiTYDN sym REmg i.L ".LgwtncVi ClDUt mIk
.. G�E�Si�,'4Sh43SEtiRiGE'J�LtS'.L' " x
1 ,n4.. .tu ,f LCASCtirCATEvwba19E :. �23+.WC.222'..Stolm.3M 3859D7?}Dt 6sah.ox2
z.. W'. L4AGCC=FREDET,YSGi9-'-. d.$6772524' S%-3D22A0 $2.3G8_Tu .i17f 04,:.
a:S Dt'42R'G9Ft#KS+ASM 4J s4 Sa .S)..
.. a a:2 c:wPxNv osi6 cA5 , STi.:3b SsS.39o'- 5:3,2E3.. sisns
5 !12 L7.DN4T trbFC GAJ CI'%EDtt 7 ana ri5 t:3i':�1"1
d T.CTMDTtWQC U%R3'-ExPEHWS 1261335,167 Si6'.2DJ::1S- $7-kCZ 7,1V S2,M,'6g .
LASTP;aL fON!1PR+DES s
ro S5'EAY$gN#EKa'NEElHNC a 1'%a S}d S)CS.55d 3s1�J-� Sd(5dtl
d DTI C�.ST£k'M+G4LOaD C1PATCIHlG £iCE7 .Tt2 1}. {SSFB'} lS's}�i -
q V. -1.1*S IM!MSUP �$9404's:4 Ss,3.._,527 1t"I't-6. S591.6."d" .
:� dT5 VSR:TAS7:rt ExPCYSl CC'rsAAAt:. #, 33Td.1 td $21 J.314 - $i!C; S4£,214 .
11 ,9]T MSR S2�4KPI ExAE/rSE.^.YfY CAi£: ' S!a,E2T sa,tTs $3.552. -'11,>59 ..
Yi E79 4ETER i'CWSE REC.E:fPaa3E {.$3;54:;%`$ t1.733.34E i'ZSt;t{i. i AQ, .
- 27 'TL S'$tCMCR+S•.xT1APAMEXP. j 35"5'd'd SJ8!.b::•b 3t.'iJ;?i6 54i,46'
/i we "nEA ExcEr+5f3. S3,WAS11 .S i:,:3a S:..ta1a.85:... 53:2347-
-t3VS, guts - uk� luI io. t4
. 'ti5 zDtM n_PZRs.t:or+aysHSE3. i:3357C:'=5 SI.- x.. S4.SiT,'rsy-. Fr,r:l5,it,{
i7 sa5 wP�z.'+swTa:+Gm:E€aevl'.' Sa:=:.Ta 3e2..az sZ.921. sno .
DD3 5151vtTt.%1E SR,@ROY4tEN.'S $3R S'r SII. 34
Zi" za-, Mi sex9- s S4
,?s5Ad 52.579, 3 st-wm Wm''53:,
�2d Sfr3 u3R 5TATpN EIPENSE G€.4ERIa'• " 59T)S3D $-90, T S275.%3 3liS.SiS -
M 4bR ST4T1pN ExPENSE GTT SUtE S1,443 S2.-no si.«i S$u -22 i
22 402 xv.cri.SEAYKIS ,- .. .. Si.772,042 $I,D+t,te7 Stw OM "? -
'23 Sa3 Sr£r.R bMCit6£R>il E7WEHeiE 3a:c323 525r,*lt 313D,Ma S0.294,
.2s Dw MAemv4t+eea ott�aF.Diim4Yp%t i5l.iX,M Val$31
ZS rCrM t4A%YTETi:TCf ETPEKSS3. ,:$d:9i 1-EST SS,f"."..fi7_ 52.3%1 T.rS' - STd2,%a9-
Je: TDTMneST}esvtAxiE7"PASCW ,525,572}%2 5+�,9CS.X7 SD.S%5.4t3- Sf9S7.Sad
' C%eSrCMERACLµ4VT,bC ExPEt6Et.: .-
7; A3t SC."i ERHISIC/! : Sa=.92J 341,22,5 Sa483'. -19!
79 Wt' METER R£ACtVGE%AENSES I S4_t7'Ve $Jfz;i S3.tilT..
:3 33T C,ST(k4ER RECgtaJ#COTtECTtC+t. yS1T73EZsi S'1,I:t 2H1 5,337lls SD,t?3
tNwcu-EC,aAt.ACOOLWS _ 57,1£`,4T9 9..91-i,Y5 S1,i-P,v'.' S1via -
"7i ,y7y U,-CEUANlCUS cu 70,itAA6Liw '. 513-UT S'ZZ I 5).Y,3 E5
�. Teixwsmirtrt,�erav,srt;�xa : :3Tr3Z:s"r3 F.5.C:1:'t1 S,.le,';s1; :S'+�1.Sf°1t s -
,kSt}+.,cR seRviTE EZ141c1iEd
-0Z s.rT 'CMEA Assquva kxmnF1 32.426 2 52 723.2!0' <_m.a--l' i7 386 -
•,; »:rAwYGA+tID4£R26ci'F)P !°,t".a 151,40t Sa-t 1S ,134
-.: ?_ `.•;, MIEL C+1StOtsER SEAYtGE cXAE.'aK3 se >C a.,1'. : $0-
33 :a:.a G.STQkER'SERT'GE E.k457+$E5 szel 319: 32 Sz:fl' S S<7-tlT' SS.TL>
,a spa=_wgr�x _ 3t" '2 s:Z--r it:!.>r 32
�: ➢,b DE4Gr+STA4TRkt#SELLlY.^.EZP c1",37 3t0.':+°e 4�.45n tt:T
at <;;.d:5 5:4.?43 $123.
3i 5t$ u�;CESWtEC.xtSA429 mo E) +1. 53{<%Q SIM $2,
ol, T::4L 5A(ESiAD%WTY2N E.v$KTES S-.PZ3
.. A.^.Me1lf TRAiid iCEKElt4l Ezi£N3fS .
41
",tC' 4u4tC:SGEFF.Ri.Lt'SiLAA 2 SIJJT.= S'.T.L?.T $74T4£? ill 4m
.. :a2 14, fA'c a S,-tcu F?AEw,SE ist 1:.AIM S.E.a,S.yti is"*A_9S tiZ4.1'7 i
+J. m c"rrme SERs'>=19"'+Sn1?'J S»S.t`j
u' P7+: RK?£RJr a:StAAMt$ 3=244 S74,8C!' E7"P.11:Ll -.P.963
.AS 'I.-- P:Al R)LS&OA)M sES St_its,w8 'SS-{7..7'<i i295.iS' 533;105
Is 421.. EMPLDYSES n.'s sSEtmm 'S3,9iQ7+7 sl"v-t.3 $3%.E05'. S)-%3 "
:. It u::5 RSG.fA�".DS`- EkP ...:.S. $w' :$0 S2 -
4E PJti.t PST.6COv&XL xowpL_, 53..
st rtei r4tSGlWfitTUS t.ENER4LErA :';S7T t,5::4 ($.212": T533,n921 ?Es,£:3,s- -
Sb 91D.: SCD ASSET ALKATSRT10H ETp'... '$b" S4 SJ' .. S7. ..
... `se 3Y Rtrrs zEeb'.. 37:E.srJ r,;;as 13"u3
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53 TMAt 4C�. MTPA1T*#CRIk'R.,L Exi i+kr.73�5. 314`.E'S:39 C::as.M swjni
.5. -Tt C#M ExCL Cos cost -S"2Y 4)
54 TOTAL CdSa .5,5,'b!1%4 r,9�,T33 fIr"il:1 5+ o,%5 ..
'+! CE;'S:GaTCNEtPF1+3Ei _..
51 fi5:'R+Eairx"`!r>tAMT Si2i7%9i1 St L�`.Tt_*w4 y?„'fid.gn Y1734 iR
'Sf C,CtF_AA4;•t.4.N S�lC1F3, 1 l% f'E.. 5.,,5,Q
s5 Tatu caPxE.:A*iwFSRer+sEs .. 377,ar,3t? f S.i_,.;D s ,«z1z".: 51.43✓52
YM�S ft4ERt Sk'ING�ME T.USS.. : ..
dJ cRb?6iTYA:.?lEL�E3 ':15.1:M,<92 S's:?sC,n.0 St a~f,�T Lt;A.i'3 .. -
5r RATRCtt'ESATED TARES $t=-+i.fm 32113.74E: U2'.K4
42 R;VE?X;E.P"TEST4XEd <.-, li-lWl}..: ;V-41.1£," 17=
rCTAI."-ZliDn%ER Trm C".+1E 529,38S.iU S'y.S J.G37 5d 31L: 3}.:3.1�"4
ar.EaEs2ExrE�raEr
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:W TOTAL CAS.RATIKG ErnEnaEt:.. ..S3?9S-�:i2 5c::. s•.:7..S>_5-':Js3F 4 7
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TOTAL.DVCCS RSOCm ENOED RATE BASE
TEST YEAR ENDED SE>. SER 30.2ao
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a aide x+ ' EtCt.D;t .�77?f �71�`ii It2)SS
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3 Y72 semaan}ysi�a+�+�YTlflk zu.1, sr73,71z 7➢4
ttRraarGa"•TED y ifd.bl7,jea $301i4,""d i
-3 Gs Wt9fi4tT."f^SlYl aaex sT73i47ASt v;m.m4 'tui*&* 227Aa7.4S4
.6 #30++41+a>t6 r0.+. SCT73:d.3➢k,.,0,41607 '..Y o4fl+W U,aHSu
.'t 37t TOrxwul.A .1'LMAS$ ¢ a2Sa 4E84E1 51aa.6dY341 :.S33,t2a,34a
ti4 NiRBiil:GWfGYpisM : i 34 tL6.zSN #ASUZti0. 'Traw.4pa _#625.jia°
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to 346 ELAtr<'tY `vit.1".STO SASS Witt $St;lvmq un.
tT 34s anrtns 3?%S s34Z74193 3495eXIM St, 332
12 361 rcurxa MfTEeaantwutl<.va+n4 3 Sa'.: s9 Sa 'fit:
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.. TS' T}9113. aaEiS±wR+r.Ka'-G9+'
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.26 To;,...1tG"r is Sa4.i3Etw 234ssss^'? 373.ai133Y S]TS;RTD .
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'� LfxM:L aE.a7E3 aTEPl CiKA S22.tT>;•.3?S 229_F.drt 2;4.A,at
:: cFiuluaDu'EaaM[v 33 x,5U.192 SXYL`T. STa
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PAGE 1 OE.6
TXU GAS DISTRIBUTION
NORTH TEXAS MIETROPLEX DISTRIBUTION.SYSTEM
RESIDENTIAL CLASS C�URREN-T AND PRIOR SALES COMPARISON
i
BILLS ' SALES
PRIOR CURRENT PERCENTAGE PRIOR CURRENT PERCENTAGE
CtIY, CUSTOMERS CUSTOMERS CHANG MCF ICE CHANGE
t '
1 Addison 1,,475, t,d53' -1,4945% 124,518 124,616 0,0787%
2 Alien: 8,227 -12,081 46,8458% 631,244 881;894 39.7073%
3 Anna 316; 315 0.3165% 21,735 17,438 -17.9296%
4 Argyle 297 300 1.0101% 25,645 24,101' -6.0207%
5 Arlington 34,447 38,314 11.22591/6 '2,341,374 2,373,679 1-3797%
6 Aubrey 409 428 4,6455% 20,916 20,181 -3,5141%
7 tuEe 1,125 1,150 _ 2.2222%° 57,003 60,377 5.9097%
$_ Batch Springs NIA N/A _ NIA NIA NIA NIA
9 Bedford 6,888 .5,971 1,4096% 403,389 372,738 -7.5984%
10 Benrook 2,271 2,325 2.3778% 140,186 131,939 -5.8829%
11 ,Blue Mound 584. 580' 0.6849% 30,299 27,362 -9,6934%
12 Blue Ridge i6b 167 1.8750% 9,584 8,215 -14.2842%
13 Burleson 2,554 2,84!; 11,3939% 130,M 148,385 14.0230%
14 •Carmlt6n 21,181' 21,837 2.15291/4 '1;538,282 1,412,135 -4.30016A
15 Cedar Hill NtA NIA N/A NIA, f41A NIA
16 Celina 529 524 0.9452% 37,690 31,270 -17,0337%
17 'Colteyville 5,4$ff tjf4 4.1545°!° 647,941 629,145 -2 9009%
18 Cappell 8,365 8,581 2.5822% 763,235 725.374 .4.9606%
19 'Copper Canyon 1T. 13 18.1818% 1,543 1,885 22.1646%
20 Corinth 3,26d" 3,60& 10.5392?I 218,154 229.508 5.2046%
21 Corral City NIA NIA NIA N!A NJA NIA
22` Cross Roads. 5 0 -100,0000% 431 0 -100,0000%
23 Crowley 1♦561' 1,650 5.7015% 80,128 85,541 6-7554%
24 Dallas/NW Mekro. 5,54E 7,588 36.81931/. 464,126. 519,18E 11.8632%
25 Datworthington,Gdris 461 480 4.1215% 47,71T 53,126. 11.3356%
26 Denton 16,656: 17,273 3.7044% 1,113,837 1,022,680 -8A836%
,27' DbSoto NIA NIA N/A NIA NIA N/A
28 Double Oak 167 179 7.1856% 18,578 18,916 1.8194%,
29 Duncanville NIA NIA , NIA NIA NIA NIA
30 EdgediKVillage 536 533 0.5597% 33,472 '31,700 -5,2940%,
31 Euless. 5,285 5,292 0.1135% 312,00'3 286,435 -8.1948%-
32 Everrh5n 1;142 1,136 i -0:5254% 57,096 .55,224 -32787%
33 Fairview 142 293 '1063380°J° 15,565 36,162 132.4769%
34 Farmers Branch 7,09a 7,0t 2 -0.3949% 506,152 462,542 -8.6232%
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 -Z.2661 f°
38` Forest Hill 2,23d 2,247` 0.5819% 137,976 129,276 -6.3.054%
39 Fod.YVortti 99s362 104,680 5.3521% 6;452,941 6,324,620 2.1402%
40-Frisco 6;692 11,133 66.3628% 519,159 849,129 63.5sm,".
41 Gartand 36,853 38,193 3.6361% 2,493,815 2,445,312 1.9473`/a
r.
_
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PAGE ZrOF 6 ,
l
42 Glenn Heights NIA NIA NIA NIA NIA MA
43 Grand Prairie' 1,138 -i6,297 1429.8495�; 70,139 t,076,882 1426.7995°A
44 Grapevine 8,443 8,557 r 1:3502% 645,816 609,432 5.633$°l0,
45 Haltom City 8,303 8,442 1.0741% 481,240 454,957 -5.4615'I0
46' Haslet 4T $2' 10.630/6 2,704 2.762 2.1450%
47 Heath 918 1,072 16.7756% 108,259 '117,884 8.8907% $
A8 'Hickory Creek. 451 -21 15.5211% 33,429 38,670 15.6780%
49 Hlghiand'Village 3,932 4,053' 3.0773% 358,576 347,399 :-3.1175%
50 Hurst 7,785 7,840 0.7065% 496.277 448,473 9.632506
51 Hutchins NIA WA k NIA NIA 'Hilt NIA
52 rrving 26,876 29,2W 1.4680% 1,965,271 1,839,329 6.4084% t
53 Josephine 117 114 <Z564140 9,032 6,894 23 6714%
54 JusGn 463 492. 4.9041% 28,645 26,346 -8.0258%
55 Keller T,485 7,897 5,5043°% 603,528 597,161 1.05509b
56 Onrnedale 737 790 7.1913%a 41,022 42,376 3.2982%
57 Krum 532. 668, 6.7669% 32,663 31;034 4.9873°l°
b$ Lake Dallas 1,195 1,206 0.9205% 73,750 68,501 7.1173%
59 Lake Worth 1,304 1,29.4 4,7669% 77,180 '71,452 -7.421M/.
60 Lakeside 268 268, 0.0006% 17,905 16,226 -9.4108°IP
61 Lancaster NIA NIA NIA NIA WA NIA
62 Lavon 31 69 122.5806% 1,965 3,887 97.8117%
63' :LeMsvltle 12,98.5 13,058 ? 0.5622' 826,824 790,765 4.3611°6
64 Liitan NIA WA NIA NIA iJA NIA
65r Lincoln Park 64, 64 0.0000% 2,441 2,090 -14.3794°k
66`tittle Elm N/A N114 WA NIA NIA 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 47AI560% 812,997 1,150,746 41.54370W
70 Melissa` 145 137 5,5172%° 9,195 7,233 -21.3377%
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 Sp8, 106 -1.8519% 8,035 6,569 18.24521/.
k 75 North Richland Hills 7,174 7,710= 7.4714°l0 443,040 474,633 7.7310°k
76 Northlake N/A WA NIA NIA N/A: NIA
77 'Ovilla, N/A NIA N/A NIA' NIA NIA
78 Ponder. 9T 120 23, 1 3% 5,924 6,004 1.3504'/6:'
79 Pantego: 5fi8 576 1.40851h 39,921 38,164 4.4052%0 :
80 Parker 36' 104: 188.8889°!0 5,233 11,824 125.5507%
81 .Pilot Point _ 849 873 2.8269% 53,478 48,099 40.0583%
82' Plano 48,272 55,852' 15.7027% 4,463,080 4,903151 9.8603%
83 Princeton _556' 546 1.7986 23,833 29,434 •13.0027%
84 Prosper WA NIA' N/A NIA NIA NIA
85 'Rendon 639. 547 1-943975% 27,347 28,303 3.49581%
86' Richardson 22,038- ;23,450 8.4071% 1,717,275 i,728,700 0.66636A
87 Richland Hills 2,476 2,483 0.28271% 160,859 155,052 3.6100"A
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 N1A NIA: NIA NIA NIA
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91 FZowtet# 9,t61. 11.02 25.3357% -666261 810,336 21.807270-
'92 Royce Citjl fi00 539 10.1667% P,254 31,373 --20.0sp%
83 Sadl$a 1,913 3 23$ 69.1584°!0 127156 203.$69 60AQ.B,$ 6
94 Sagfinaai 2,044. 1,507 22,6617% 107,982 02,225 22.4510%
$5 Sanger' 947 004 3.91.0T1'f 5615$ 50 Z42 -10. 3429o,
96" Sansohi Park Village 1,243 _ 1,241 01609% 69 015 .63,837 -7.5027°k
%91 Seagoville, N%A NIA NIA WA WA. NIA
98 Shady Shores 352 389 10,5114% 26;236 26,180 3.74071% °
99: Southlake' 6,162' 6;427 3196316% 179,973 73 ,789 -5.1520%
100 Sunnyvale: NIA WA, NIA WA WA_ NIA
101 The Colony I;824 2,511 37.6645% 127;751 168,639 32.00600/.
102 TMphy Club 788 63$ 6.3452% 65,602 :68,124 3.8444%
103 Watauga 1,706 1,759 2,9859% 67,055 $2,762 -4.9314%
104 Westlake 166 197 4.2328% 18,168 16,777 -7.65631%
105 Westminster 99 103 4.0404% 6,620 -5,119 -72645%
106 Westover Hills N!A NIA NIA NIA; NIA NIA
107 Westworth:Village, NIA NIA N/A NIA NIA. NIA
t0$ White Settlement 3,182 3168 -0.44000/. 166,305 150,606 -9.4399%
109 Wilmer NIA NIA NIA NIA N/A NIA
110 .Wylie_ 2 53$ 2:677 5,4768% 139 759 143,830 4 qi29%
514,647 578,736 12.4530% 37,321,376 39,266,265 5.21121/e
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SCHEDULE 8
PAGE 4 OF E
i
UU GAS DISTRIBUTION,
NORTH TEXAS METROPLEX DISTRIB'UTTON SYSTEM
COMMERCIAL CLASS CURRENT AND PRIOR SALES COMPARISON
BILLS i SALES
PRIOR CURRENT PERCENTAGE PRIOR CURRENT PERCENTAGE
SLTY CUSTOMERS C I TOMERs RANGE JSdSE MCE CHANGE
t
1 Addison' 936 972 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 -23143%
4 Argyte 17 25 471.0588% 4,025 ,5,099 26.6832%
5 Arlington 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.&54641a
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.t699'h
10 Benrbok 151 146 =3.3113% 66,433 66,893
Ti Blue Mound 33 32 3,0303% 12,717 : 111757 7,5490.
12 Blue Ridge 25 27 8.0000% 2,879 3,419 18.75WA
13 ;Burleson 314 342 8.9172% 942W 110,647 17,8500%
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% 10,102 11,962 '184122°
17 Collepille 21Q' 257 17.3516°% 56,006 66,923 19.4926%
18 Coppell 316 3.79 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 'Denton 1,856" I'Mm 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 294167 0A377%
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;171 1,177 0.4266% 559,751 542,345 -3A096%
35 Farmersville 95 91 -4,2105% 32,319 33,236 2.8373°la
36 +Fate 13, 13 1,109 1,329 19.837%'
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 9,842 9,694 $ -1,5054% 4,536,623 4,709,167 3.8034V* '
4Q Frisco 541 307 i 43.2532'l0 82,334 104,080 26.41i9°fo
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41 Garland 3,493 3,095 -11.3942% 1,259,509 1,218560: 3.2512%,
42 Glenn Nelght; WA35- 1 NlA NTA 6,993 NIA
43 Grand prairie` 142 2,146 t1998,7775°I° 78,684 1,05038 1240,60(,A%
44 'Grapeir-ne 790,' 865 9.4937°J° 562,241 566,728. 0.7981`Yo
45 ?FYaf�om city • 852 833 2.2014% 242�28 2401,790 -0m93%
46 Haslet 32 28 12.5000% 1 '25,669 19j82, 25.2717%
47 He4#h 19 22 15.7895% 4,457 5,01;6 12.5421%
48 H`tCkot}E€ree[G' S' 7 40-0000°h 340 626 84-1176%
49 -Hi0fand UiUge 65 87 33.84621/. 15,452 19,673 28 6112-1
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%
53 Josephine 5 5 0,0000% 546 471 -1333631%
54 Justin 41 45 9.7561% 8,739 9,369 7.5524%
55 Keller 202' 269 33.1683% 56,979 -73,239 28.5368%
56` Kennedale 112 122 8.91286% 29,414 28,143 -4MI11%
57 Krum 37 40 8.1081% 6,994 7,000 0.085810
58 Lake Dallas 88 85 1.1628% 21,271 2[,959 3.234504
59 1_oke Worth 164 10 -3.6585% 44,830 48,250 7.6288%
60 Lakeside 3 1 66.6667% 1,060 8G3 242453%
61 Lancaster NIA 302 N/A N/A 134,1612' N/A
62 lavon 4 20.0000% 5i6 476 T7519%
63 Lewisvflia f',285 1,445 12.4514% 553,219 608,321 9,9603%
64 t_itlian NIA 7 N/A N/A .21190 N/A'-
65 Limboln Park 31 4 W333% 1,694 2,016 19.0083 A
66 .l.ittt'e:Etna NO 41 NIA NIA 6,489 NIA
6T Mansfield 335 23.1618% 148,559 161,331 8.5973%
68 Marshall Creek 2 - 2 0.0000% 6$ 51 -25.0000%
69 McKinney 1,152 925 19.7049% 335,989 364,424 8A631%
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 -19A231%
73 Milrphy' 25, 36 44,0000% 1,406 9.519' 577.0270%
74 Nevada 7 9 23,5714% 312 337 8,0128%
75 No6 Pic Wand Hills 609 630 3.4483% 291,965 322,151 10.338A
76 Northlake - N/A 1 NIA N/A 223 N/A
77 Ovilla, NIA 7' NIA NIA 1,083 NIA
78 Ponder 1.9' 15 21,0526!% "15,343 8,719 43.172850-
79 Pantega 2a2'- 241 0,4132% 33,075 35,743 &0816%
80 Parker 15; 0 '-100.0000% 1,031 4 100.0606%
81 Pilot Point 105 108 2.8571°l 25,629 25,295 -1.3032%
82 Piano, 3;$46. 31139 20A511% 1,258,129 1,464,665 16.4161%
83 Princeton 52 51 17,7419% 14,567 16'cigo 10.3037°I°
84 Prosper N/A 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 7.2695% 835,313 866,785 3.7677.%
8T Rrchland,Hills 253 252' -0-3953°t° 61.817 62,362 6.8816%
88 River Oaks 138. 135 -2.1739% 30,862 34;238 10.9390%
89 Roanoke 92 109 15.2174% 18,227 23;361 27,8378q°
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90 Rockwall WA 443 NIA NfA 172.06,5 NIA
91 Rowleif 498' 444 A0.4839% 68,25y 89,616; 3t 292D55
92 Rayse City 65' 6tk -T.69 3% t7„763 17,230 -3.0006%r
93 .Saehse� 73 81 i 10.9589% 8,916 16,272 82:504°70' -
94 5aglgarf, i64 168; ; 24390 , 76,127 72,tl79 5.3174
95 Sanger" 12 112 : 4 Q.0Q00% 23 4$4 22,557 3.9351°�6
9& Sansom?ark Village: 74 84 I 13.�f35% I1,735 13:162 12.160;q,% j
97 SeagavltC6 NfA 1633 NIA NIA 46;668 NIA
98 Shady Shor@s 3 2` -33.3333% 360 281 =t9.7143°1°:
9S Southtake 353, 432 22.3796% 80,170 105,416' 31490o°ib t
100 Sunnyvale NIA 55" NIA WA 11,459 NIA
101 The Colony 186. 145 i -22,0430°f° 46.777 %432: �20.640�°le
102 Troph Club 6 21 2%0000°l° 2,231 7,41 T 232.4518%
103 Vtatauga 1.46 176 16A384°!° 32,646 51,140 56.6501%
104 Westlake 10, f1 100000% 14.521 10.233- 11J89$"fo
106 Vlestover Hitis 6 5... -16.66667°t° 962 1.052 9..3555 °555°!e
107 We"stworth Village 32 23 28-1250% 8,852. 7,486 -15.4315°A
108 White Settlement' -7.5472% 99,839 i09,068 9.2439°<0
109 Wilmer NIA " 31 NIA NIA 7,540 NfA
110 Wylle 174 16 4.5917°/a 6 .709 11g'538 75,06980la
47,140 53,010 12.4513"!. 2t,15454t '24,990,907 18,146f%
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TXU GAS DISTRi4 TtaN SYSTEM
NORTH'TEXAS METROPLE3'
REVENUE ADJUSTMENT
N TX METRO'-RESIDENTIAL x'
COMPAAIY; DUCI DIFFERENCE
WEATHER $6,181,444 $3,195,444- $21986;000
CUSTOMER $1,714,694 $V14,094 S1'714,094
REVENUE ADJUSTMENT p$0 $1,414,072 $1,414;072'
REV TAX $238,577
N TX METRO-'COMMERCIAL
COMPANY Dt1CI DIFFERENCE
WEATHER S2,064,901 $46,863 (546,8c }
CUSTOMER $313;803 $627,606 5313;803
REVENUE ADJUSTMENT" ' so $2,740,670 $2,740;670
REV TAX $13 55F
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TXU GAS ISTRIBUTFON
NORTH TE?CA '-METROPL
REVENUgADJUSTVfENT
1 ine# RESIDENTIAL:
"Sates Revenue Less: $442,800,058
,
2 Revenue Related,Taxes K
Gas Cost 22.475.53"1
_4 816,558�720
Unacat For Gas 6 41.6 34
5 Subtotal 345,451,665
Add:
6 Reverse Weather Normal. 5.278 255
7" Total Base Rate Revenues Before Adjustments $102,626,628
$ Sales Revenue 273,3r35,i$3
Less:
9 Revenue"Related Taxes i 3 877 03
�10 Gas'Cost
11 Subtotal_ i 162.782.945
476,639,977
a
T2 Base Revenue
96,745,206
13 Reverse Customer Adjustment 714;f394}
'•? Reverse Weather Adjustment (1,714,444
15 Total Base Rate Revenues Before,Adjustments
$10L�t2.55$
#6 Restdenttat Revenue A'djusfrn rh
ti L-4 14.0 7
mcw
SOURCE&'REFERENCES x
Line g Schedule,G-1'
2 Schedule G-9_(�a,076loi
3 Scieduie G_3 x
4 Scheduie'G 3 R
5 Sutra Lines 2-4 t
& Company's,Weattier:Normalizatton
7 Line Sminus Line 5 plus UneB,
8 Schedule.-A-t I
9' S66du16 G-9
10 ScF�edufe iC 4"
1 t Sum Lines 9&10
12 Lirts 8 Minus tine III
13 Company's Customer Ads
14 Company's Weather Adl
15 Sum Lines 12="14
16 tangy 7 rriinus,Une 15
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TXU GAS DITR1BUTION
NORTH,TEXAS tVtETRo t Ex
REVENUE ADJUSTMENT
COMMERd t
1 Sales Revenue S218356,81
Less:
2 Revenue Related Takes f 1,104,099
3: Gas Cost 172,382,886
4 Unacct For Gas 3,494 086
5 Subtotal 186 981,071
Ado: _
6 Reverse Weather Normat. Z611.513
7 Total Base Rate Revenues Before Adjustments S33,387,323
8 Sales Revenue 130.858,34 .
Less:
9 Revenue Related Taxes 6642;370
10 Gas Cost 94:320i424
1 i Subtotal 100.962,794
12 Base Revenue 29,895,555
F3 Reverse.Gustomer Adjustment (313,ew)
14 Reverse Weather Adjustment 2 064:$01
1:5 Total Base Rate Revenues Before Adjustments c3` to'?''-
16 Commercial Revenue Adjustment 52—740
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 Llne6
8 Schedule A-i
9 Schedule-G-9
10 Schedule K 4
it Sum Lines 9:&10
12 tine 8 minus Lfns I f
13 Company's Customer Rd';
14 Gompan)(sWeatherk4
15 $un Cirles 12-14
16 Line 7 tirius One'15
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