HomeMy WebLinkAboutResolution - 2000-R0045a - Deny Rate Increase Proposed By Energas Co. - 02_10_2000Resolution No. 2000-R 0045A
February 10, 2000
Item No. 53
RESOLUTION AND ORDER
WHEREAS, a Statement of Intent to increase rates within the City of Lubbock
was filed August 4, 1999, with the City Secretary of the City of Lubbock by Energas
Company; and
WHEREAS, the City Council of the City of Lubbock, sitting as a regulatory
authority under Sec. 103.001 of the Utilities Code has conducted a public hearing to
inquire into whether such proposed gas rate change is fair, just and reasonable; and
WHEREAS, the City Council has received extensive evidence with regard to said
rate change request from Energas Company, Diversified Utility Consultants, Inc., of
Austin, Texas, and City of Lubbock staff, and
WHEREAS, it is the opinion of the City Council of the City of Lubbock that no
rate increase should be allowed for the sale of natural gas and natural gas service by
Energas at the present time and that the requested rate would not be fair, just and
reasonable; NOW THEREFORE:
BE IT ORDERED AND RESOLVED BY THE CITY COUNCIL OF THE CITY OF
LUBBOCK:
SECTION 1. THAT the City Council of the City of Lubbock, sitting as a
regulatory authority pursuant to Chapter 103 of the Utilities Code, at a public hearing
called for such purpose, hereby denies and refuses to grant the rate increase for the City
of Lubbock as proposed by Energas Company in a Statement of Intent to Change Gas
Rates filed with the City of Lubbock on August 4, 1999.
SECTION 2. THAT the City Council of the City of Lubbock, based on the
evidence submitted by Diversified Utility Consultants, Inc., whose final report is attached
hereto as Exhibit A and made a part of this Order and Resolution for all purposes, and
evidence submitted by Energas Company and by City staff has determined that no
increase in rates is justified at the present time and that the proposed rates would not be
fair, just and reasonable.
SECTION 3. THAT the gas utility is hereby ordered and directed to reimburse the
City of Lubbock for the reasonable cost of rate consultants, attorneys, accountants,
auditors, attorneys and engineers engaged by the City of Lubbock in connection with the
conduct of this ratemaking proceeding.
SECTION 4. THAT the City Secretary of the City of Lubbock is hereby
authorized and directed to give Energas Company immediate written notice of this Order
and Resolution by serving a copy of this Resolution and Order upon them at their
business office located in the City of Lubbock.
RESOLVED AND ORDERED by the City Council this lothday of February , 1999.
Max Ince, Mayor Pro Tem
AqTMST:
/(4&1 j �I&WA
kaj Darnell, City Secretary
PROVED A5 TO CONTENT:
e-7 0
Ric ar urdine, Assistant City Manager
APPROVED AS TO FORM:
G. Vandiver, First Assistant City
Ddres/Gasrate.res
January 18, 2000
b1/UJ/1deU 13:55 5122572243 i]IJCT
PAGE 01
To:
From:
Date:
Subject:
Resolution No. 2000 R 0045A
February 10, 2000
Item No. 53
Memorandum
Steering Committee of Energas Company West Texas Cities
Richard Burdine
Greg Ingham
Mike McGreggor
Richard Morton
Chester Nolan
(806) 775-2051
(806)894-0119
(915)686-1600
(915)335-3281
(806)363-7106
Diversified Utility Consultants, Inc.
January 3, 2000
Technology Expenditures
On December 10, 1999 DUCT requested additional information from
Energas Company pertaining to the current rate increase request in its West Texas
Service Area. This request was initiated at your direction in order to afford the
Company yet another opportunity to support a large revenue requirement portion
of its overall request which it had not adequately justified or supported in this
case.
Mr. Guy was requested to provide Board of Directors Meeting Minutes
that address the $132 million of technology related expenditures contained in the
rate request. In addition, Mr. Guy was also requested to provide any information
that categorizes the expenditures into greater detail than the very limited breakout
previously provided.
On December 22, 1999 DUCI received three Items from Energas: 1)
Project Overview and Value Proposition for Oracle Financials; 2) Project Charter
for Oracle Financials; and 3) Board Minutes and Presentation for CSI. DUCI has
reviewed each document and concludes that Energas Company must not have any
documentation which would adequately support such expenditures. Based on
review of these documents and all prior information provided, DUCI cannot
change its position regarding the inclusion of such amounts in rates. If anything,
the additional information clearly identifies non regulated business opportunities
and much lower cost expectations associated with these significant expenditures.
If you have any questions regarding this matter, please do not hesitate to
contact Jack Pous or Dan Lawton.
e
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Resolution No. 2000-R0045A
1
Summary of Findings and Conclusions --
Regarding the Energas West Texas
Statement of Intent to Increase Rates
'
October 26, 1999
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Resolution No. 2000-R 0045A
1 I DUCI
1
October 26, 1999
DIVERSIFIED UTILITY
CONSULTANTS, INC.
18113 ROSIE DRIVE, SUITE 110. AUSTIN. T% 78789
TXL"HONE 45121 257-2600 PAX 16121 257-2243
' Steering Committee of the
West Texas Distribution System
' llnlrWei a 1�
i l• l 9618 rITM I a OJIl
' Dear Steering Committee:
This report contains the results of Diversified Utility Consultants, Inc.'s ("DUCI") review,
analyses and investigation regarding the proposed increase in retail gas rates filed by Energas
("Company"). Presented in this report are discussions of DUCI's analyses and proposed adjustments
to Energas' requested rate increase and tariff riders. It must be noted that any issues not specifically
addressed in this report does not imply DUCI's concurrence with Energas' proposal.
' On August 4, 1999, the Company filed a rate request for an increase in revenues of
$9,838,725 in the West Texas Distribution System ("Cities" or "West Texas"). The proposed rate
increase for the Company's West Texas service area is based on a 12 month test year ended April
30, 1999. Based on the Statement of Intent, the increase requested represents an 8.4% increase in
total revenues including gas costs. The Company is requesting an increase for all costs except cost
of gas. Cost of gas is regulated by the Railroad Commission of Texas ("RCT" or "Commission").
' The Company's proposed increase reflects costs associated with return of and return on invested
capital, taxes, and operating expenses. Therefore, the proposed increase is best evaluated by
excluding gas costs and examining the base rate change. The base rate increase requested in this
' case is approximately 22.21 %. The Company's proposed increase by any measure is a substantial
increase for the West Texas ratepayers.
Energas has requested an after tax return to common equity shareholders of 12.25%. The
Company has proposed several tariff riders related to expected future investments. The tariff riders
include Steel Pipe Improvement Program Rider ("SPIP") and a System Expansion Rider ("SER").
The proposed tariff riders are best categorized as automatic adjustment clauses. In other words, the
Company's proposal, if accepted by the Cities, will adjust future rates based on expected future
investment.
' Presented herein are what we believe to be appropriate and necessary adjustments to the
Company's proposed cost of service based on the limited information provided by the Company.
' The recommended adjustments set forth in this report results in a $16,965,305 rate decrease in retail
revenue requirements from the $9.8 million increase requested by Energas. In other words, DUCI's
analysis indicates that the current rates should be reduced, not increased, by up to $7.1 million. As
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discussed later, the Company has obviously not met its burden of proof and has failed to provide
timely or complete responses to data requests. Given the problems associated with the Company's
presentations, an alternative the Cities have to rolling back rates, is to retain the existing rates.
In response to the Company's overall filing, DUCI recommends the following:
• A reduction of $16,965,305 to the Company's requested annual rate increase
of $9,838,725 resulting in an annual decrease of $7,126,579 to the Company's
existing base rate revenues.
• Denial of the implementation of the SPIP and SER riders or investment
adjustment -clauses.
• Allowing the Company's requested increase for other service charges as set
forth in Attachment 7, attached hereto.
The impact of DUCI's recommendations and results are set forth in the following table:
VILEST TEXAS DISTRIBUTION SYSTEM --- —
COST OF SERVICE
COMPANY
REQUEST
DUCI'S
ADJUSTMENT
DUCI'S
RECOMMENDATION
Cost of Gas
0
0
0
O&M Expense
$27,092,915
<$5;081,699>
$22,01 1,216
Depreciation Expense
$7,409,647
<$4,378,311>
$3,031,336
Taxes Other than FIT
$2,618,685
<$65,434>
$2,553,251
Return
$12,484,922
<$4,117,675>
$8,367,247
Federal Income Taxes
$4,130,300
<$1,844,617>
$2,285,682
Int. on Customer Deposits
$10,381
0
$70,381
Total COS
$53,806,849
<$15,487,736>
$38,319,113
Base Rate Revenues
$44,459,765
$629,812
$45,089,577
Net Revenue Defic. <Excess>
$9,347,084
<$16,117,548>
<$6,770,464>
Applicable Revenue Taxes
$491,641
<$847,756>
<$356,115>
Total Revenue Adjustment and Revenue Tax
$9,838,725
<$ 1 6,965,305>
<$7,126,579>
A discussion of each of the issues raised and changes recommended by DUCI are presented
in the balance of this report and the overall impact is set forth on Schedule 1.
It must be noted that in the review of this filing, DUCI has encountered a number of
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' problems in obtaining information relevant to the rate request from the Company. Energas' chronic
lateness in responding to the requested information and basic lack of infonnation has hindered
' DUCI's.,ability to analyze the overall reasonableness of the Company's request. The Company was
late in responding to approximately 85% to 90% of the data requests submitted by DUCI. The
Company's failure to timely and adequately provide basic supporting data severely hindered DUCI's
t efforts to gain additional information on crucial subject areas regarding allocation issues, various
expense items and the requested increase in rate base related to the customer infonnatio_ n system
and other capital investments.
' An issue that arose late in the analysis of this case deserves special mention. The Company
included $2.4 million of investment for a new pipeline in its request. This pipeline was completed
after the end of the test year set for determining appropriate revenue requirements to the residential
and commercial customers. While Energas elected not to include even a dollar of new revenue
associated with a contract it had with the user of the new pipeline, the real problem rests elsewhere.
' This is a transmission pipeline investment for a transportation customer. The case filed by Energas
is a "burner tip" or distribution system case basically attributable to residential and commercial
customers, not transportation customers. Since Energas elected to account for such costs as
distribution costs, it must call into question the validity of the Company's entire accounting process
used to set its revenue requirements. This inappropriate inclusion of non -regulated investment into
regulated costs also calls into question the allocation and assignment process used by Atmos and
' Energas, a division of Atmos. There very well may be other non -regulated costs included by the
Company in its request that cannot be uncovered in this type of preceding. The Cities may want to
consider initiating a detailed audit of the Company's internal assignment of costs between its
regulated and non -regulated businesses.
While DUCI is recommending a reduction of $16,965,305 to the Company's requested
' increase, a further reduction may be warranted if DUCI was provided with more complete and timely
data. DUCI has had numerous problems getting responses to key discovery questions from the
Company. Moreover, often times when the Company did respond, such responses were inadequate
' or incorrect. The Company's lack of cooperation with discovery in this case is surprising in light of
past experience. DUCI has never encountered this degree of lack of cooperation from Energas since
it began reviewing Energas' rates over 15 years ago.
' We invite the Steering Committee and/or City Representatives to review in detail the various
sections of this report and the various recommendations and adjustments made to the Company's
' cost of service. We appreciate the opportunity to provide this service to the Cities, and we are
prepared to answer any questions that may arise from your review of this report. If the City
Representatives desires any additional analyses or assistance, we will be available to assist you, your
' staff or your legal counsel to the extent required.
' DIVERSIFIED UTILITY CONSULTANTS, INC.
' iii
'
TABLE-0— CONTENTS
Section I - OVERVIEW OF COMPANY .......................
1
'
A.
Introduction...................................................
1
B.
Financial Performance . ..............
1
C.
Ratemaking Activity ...........................................................
2
'
1. Energas/West Texas Rate Request .........................................
2. Evaluation Standard and Guidelines ........................................
3
6
3. Analysis Process ................................... .. ...............
7
4. Discovery Problems ..................................................
8
Section II -
ANALYSIS OF ISSUES .........................................................
8
A.
Overall Recommendation.......................................................
8
'
Section III-
RATE BASE............................................................ .........
9
A.
Investment........................................................ .........
9
1. I Oracle..............................................................
11
2. Customer Information System ("CIS")
12
'
3. Call Center . .................... ..............
13
4. Start Up Costs ........................................................
14
5. Cash Working Capital ...................................................
Allocation Adjustment for Rate Base ......................................
14
15
B.
Investment Conclusion ......... __ ""_.
'
Section IV -EXPENSE ISSUES...............................................................
A. Depreciation
16
16
B.
Benefits......................................................... .........
18
C.
Payroll ..................................................................
1. Salary Updated.......................................................
19
20
2. Unfilled Positions
20
3. Bonuses.............................................................
21
'
D.
E.
Allocation Adjustment of Expenses ............................................
Merger Related Costs
21
22
F.
Uncollectible Accounts ......................... I ..............................
23
G.
Taxes Other Than FIT .........................................................
23
'
1. Payroll Taxes .....................
24
2. Revenue Related Taxes ..................................
24
H.
Rate Case Expenses ................................ .. ......................
24
'
I.
J.
Year End Customer Growth Expense Adjustment ...................................
Summary of Expense Adjustments ....... .. ..... ...... .........
. . ...... ... .... .....
25
26
Section V -
RETURN ......................................................................
26
'
A.
Cost of Capital - Cost of Equity Capital ...........................................
26
Section VI - FEDERAL INCOME TAXES ("FIT") ................................................
32
'
Section VII-
REVENUE.....................................................................
32
A.
Proposed Annual Increase, Revenues, Billing Determinants and Pro Forma Adjustments .....
32
B.
The Energas Proposed Rates Are Overstated .....................................
33
C.
The Company's Customer Adjustment Substantially Understates Customer Growth .........
34
'
D.
Alternative Customer Growth Adjustment .
35
E.
Weather Normalization.....................................................
36
'
F.
G.
Other Revenues ..............................................................
Adjusted Present Rate Revenues .................................................
36
37
Section VIII-
TARIFF ................................................ ............. .....
37
' Resolution No. 2000—R 0045A
' Section I - Oy-ERYIF COMPANY
A. Inxrodszetion
' Atmos Energy Corporation ("Atmos") distributes natural gas and propane to more than one
million customers in 13 states through its five gas utility operating divisions and Atmos Propane.
Energas is one of the Atmos gas utility operating divisions.' Atmos became an independent entity
in 1983 and has more than tripled its size over recent years through various acquisitions.' The
' following table summarizes the relative size of the Energas, West Texas, and Texas operations
relative to the remainder of the Company.
' TABLE 1
ATMOS, ENERGAS, AND WEST TEXAS COMPARISON
1)essriptinn
Atmas
Energas
West -Texas
Customers
975,461
288,553
218,192
Revenues
$644,779,554
$142,823,073
$106,391,341 -- -----
O&M Expense
$591,262,428
$125,226,139
$92,612,973
Investment
$744,764,017
$113,547,423
$87,156,275
As is shown in the above table, West Texas Energas operations are a small part of total
Atmos.
B. Eiaaance
Atmos has been and continues to be a strong financial performer for its shareholders. The
Atmos 1998 Annual Report to Shareholders states, "[a] company's accomplishments can be gauged
in a variety of ways, but the ultimate measure of a company's performance is its total return to
shareholders.i4 (Emphasis Added) Thus, in its reports to the financial community, the Company
has set forth a standard and goal that the Atmos performance be evaluated by its bottom line
'
'Atmos Energy Corporation 1998 Annual Report to Shareholders.
'Atmos Homepage, see www.inrestquest.com.
'Energas Company 1998 General Annual Report to the Railroad Commission of Texas.
'
4Ammos 1998 Annual Report at page 2.
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contribution to shareholder wealth. Atmos goes on to state; "[f]or fiscal 1998, Atmos' total return
to shareholders... was 19.2 percent during the period when U.S. equity markets experienced dramatic
volatility."'
A 19.2 percent return to shareholder's equity demonstrates the Company's goal of
maximizing shareholder returns is being achieved. Moreover, Atmos states that shareholder returns
"[] for the past three-, five-, and 10-year periods... was 18.2 percent, 11.7 percent, and 16.2 percent,
respectively.i6 Atmos characterizes these recent historical returns as reflecting Atmos' "financial
and operational successes."'
More recently, the investment community has upgraded the Atmos stock to a buy from a
market perform.' Investment community analysts project a further substantial growth in earnings
and price appreciation in the short-term. Further, on or about October 19, 1999, Atmos announced
an agreement to purchase Southwest Energy Company, a Missouri natural gas utility of 48,000
customers. The proposal is to purchase the Company for $32 million in cash.
C. Rat_emaking_ ctivit_y_
Despite the "operational successes" and recent successful financial performance by Atmos
for its shareholders, the Company is now requesting substantial rate increases throughout the system.
In May 1999, Atmos Western Kentucky Division requested a $14.1 million increase.9 In June 1999
the Trans La. Division went before the Louisiana Public Service Commission for a rate investigation
and to redesign rates to mitigate the impacts of warm weather.10 On or about August 4, 1999, the
'Id.
"Id.
7Id.
$See Deutsche Banc upgrade of September 24, 1999.
9Atmos Energy Corp. SEC Form 10-Q, August 1999.
'old.
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Texas or Energas Division filed West Texas and Amarillo Texas rate cases totaling approximately
$13.2 million in annual rate increases." In addition, the Company plans additional rate filings in
Texas of about $1.1 million for the environs areas served by the Energas Division.12 Thus, in 1999
Atmos' requests for increases to total annual revenues amounted to about $28.3 million.
1. Energas/West Texasgate RegU01
On or about August 4, 1999, the Atmos Energas Division filed a Statement of Intent to
increase rates in the West Texas Distribution System." The Company stated that the expected
increase to West Texas customers was about $9,838,726 or an 8.4% annual increase in revenues.14
The impact of the proposed increase on a total revenue basis by class is shown in the
following table:
11Id.
12Id.
"See Attachment 8 that breaks out the proposed increase by City.
14See Company's response to RFI 1-41
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TABLE 2 15
ENERGAS PROPOSED TOTAL REVENUE INCREASE
WEST TEXAS
CLASS
REVENUE
CURRENT
REVENUE
PROPOSED
REVENUE
INCREASE
PERCENT
CHANGE
Residential
$78,375,254
$86,026,291
$7,651,037
9.76%
Commercial
$20,333,076
$21,779,287
$1,446,211
7.11%
Industrial
$6,336,631
$6,498,090
$161,459
2.55%
Public Authority
$6,449,963
$6,555,745
$105,782
1.64%
State Institutions
$265,399
$301,172
$35,773
13.48%
Large Air Cond.
$146,977
$147,615
$638
0.43%
Air Cond.-Residential
$4,479
$4,722
$243.
5 43°lo
TOTAL
$.111.911.780 I
$121.312,922
M 01-JAV
8 D%
The Company is requesting an increase for all costs except cost of gas." In other words, the
Company's proposed increase reflects costs associated with return of and return on capital, taxes,
operating expense, etc. Therefore, the proposed increase is best evaluated by excluding gas costs.
The following table reflects the base rate (excluding gas/commodity costs) increase proposed by
Energas.
"See Company response to West Texas First Request, Q. 41.
16The difference between the claimed annual revenue increase of $9,838,725 and the
annual revenue increase shown in Table 2 above of $9,401,143 is accounted for by $376,290 of
allocated increased revenues for the proposed new "miscellaneous service charges," and $41,497
of unrecovered revenues in rate design.
$9,347,081 net revenue deficiency Schedule 1, line 20.
less '9376T290 increased service charge rev., First Request, Q. 47.
$8,970,791 net revenue deficiency from rates.
$9,442,640 deficiency with rev. related gross up @ 0.04997
$9,401,143 revenue produces by proposed rates
$41,497 shortfall from rate design
"Gas costs on the gate rate is regulated by the Railroad Commission of Texas.
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TABLE 3I s
ENERGAS PROPOSED BASE REVENUE INCREASE
WEST TEXAS
CLASS
BASE REVENUE
CURRENT
BASE REVENUE
PROPOSED
REVENUE
INCREASE
PERCENT
CHANGE
Residential
$32,726,826
$40,377,864
$7,651,038
2138%
Commercial
$6,458,767
$7,904,967
$1,446,200
22.39%
Public Authority
$1,730,629
$1,836,416
$105,787
6.11%
State Institutions
$66,967
$102,740
$35,773
53.42%
Industrial
$1,311,411
$1,472,870
$161,459
12.31%
Large Air Cond.
$27,187
$27,824
$637
2.34%
Air Cond.-Residential
$1,177
$1,420
$243
20.S5.%
TOTAL
$A2.= 964
S51J24.M1
. 4 40 .137
As indicated by the above table, the base rate increase requested in this case is about 22.21 %.
Thus, the proposed increase by any measure is substantial for the West Texas ratepayers.
The last general rate case by Energas for the West Texas System was decided by the Cities
on or about May 31, 1996. The three years since the last case does not come close to explaining the
magnitude of the Company's current proposal. This is especially true given that Atmos continues
to grow through acquisitions and efficiencies are gained by spreading shared services or corporate
costs over more jurisdictions.
The following table compares the costs the Company requested in West Texas' last rate case
to the Company's current request.
18See Energas response to West Texas' First Request, Q. 47.
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TABLE 4
COMPARISON OF COMPANY COST
1996 -1999
Description
Current Case
Company's Request
March 1996
Difference
Operation & Maintenance
$27,092,915
$24,404,043
$2,688,872
Depreciation & Amortization
$7,409,647
$A3,591,044
$3,818,603
Taxes Other Than Income
$2,618,685
$7,172,156
<$4,553,471>
Return on Investment
$12,484,922
$8,556,313,
$3,928,609
Federal Income Taxes
$4,130,300
$2,741,891
$1,388,409
Interest on Customer Deposits
$70,381.
120,698
<$50,317_>
Total Cost of Service
$1346..5$6,145
$7 2220 705
Rate Base Investment
$124,724,492
$74,359,755
$50,364,737
Rate of Return
10.01%
9.89%
Return on Equity
12.25%
10.50%
' While the Company's claimed cost of service has increased relative to the Cities last decision,
' the largest increases appear to be in investment and associated return, taxes, and depreciation. In
addition, O&M expenses have increased, but by a much smaller percentage than other cost
' categories.
' 2. Evaluatio -Standard and Guidelines
The Company's rate filing and proposed rate increase was examined and evaluated based on
' the standards set forth in the Texas Utilities Code. The goal was to determine whether the proposed
rates were fair, just, and reasonable and that no rate was unreasonable, preferential, prejudicial, or
' discriminatory. In evaluating the overall revenues requested by the Company, DUCI's recommends
that Energas' overall revenues be set at a level that will permit Energas 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.
6
' In addition to the statutory requirements, basic ratemaking principles established by the RCT
in previous cases, RCT rules, along with basic ratemaking tenants were employed in evaluating the
' Company's request.
3. Analis�io�ess
In the process of analyzing the Company's earning position, several factors are taken into
taccount. The ultimate goal is to determine whether the normalized overall rate of return experienced
by the Company is above a "just and reasonable" level. The multi -step process first analyzes the
1 various components of the following formula in order to determine which side of the equation is
greater and by what magnitude.
Base Rate Revenue19 = O&M expense20 + Taxes + Depreciation + Return
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' 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:
IReturn = Weighted Cost of Capital x Adjusted Rate Base
' In other words, there are four main areas that require investigation. The four areas are: (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 the
jurisdictional retail service; and (4) the appropriate cost and weighting of capital (i e., long-term
debt, preferred and common stock).
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' "T
otal revenues less fuel or gas revenues.
20Total operating and maintenance expenses less gas expense.
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This report enumerates the various adjustments DUCI recommends to the cost as reported
by Energas' rate request with the Cities. While there are numerous adjustments recommended
herein, it should be noted that other additional adjustments may have been made if more information
were provided by the Company.
4. Discovery Prohlems
DUCI has been reviewing Energas' rates for over fifteen years. The Company has never been
as unresponsive as it has been in this proceeding. Energas has made it difficult, if not impossible,
in some areas to adequately review its request. A further reduction may be warranted if DUCI was
provided with more accurate and timely data. First, the Company filed 19 pages in support of its
significant rate increase. These mainly consisted of proposed tariffs and riders. Due to the
Company's strategy to request an increase without providing any supporting documentation, DUCI
was required to ask a significant number of data requests. DUCI had numerous problems getting -
responses to key discovery issues. Energas was late in responding to over 85% or more of the data
requests submitted by DUCI. Some of the responses were over a month late.
Compounding the problem surrounding lack of supporting documentation, a majority of the
responses received by the Company were either unresponsive, incorrect, inadequate or lacked
supporting information. While DUCI does not know if limiting the supporting data is part of the
Company's overall litigation strategy, such approach makes the case review more difficult.
' Section II - ANALYSIS—OF_ISSUES
A. OmerallRemmm-endatian
' 11 The following is a listing and description of each adjustment DUCI is recommending. A
stand alone impact is also included with each adjustment. Numerous adjustments interact with
' each other, therefore, the combined impact of the "stand alone" adjustment are not a sum of the
individual impacts. The combined impact of DUCI's recommendations results in a $16,965,305
' reduction to the Company's proposed revenue requirement. The following table shows the revenue
requirement impacts for each of DUCI's adjustments.
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D-escription
Remanu.eRe-quiremmUmpact
Oracle Software
$488,395
Customer Information System
$1,208,183
Start Up
$792,731
Accumulated Depreciation
<$44,361>
Cash Working Capital
$1,047,648
Allocation - Rate Base
$49,609
Rate of Return
$1, 621,418
Depreciation
$4,378,311
Call Center
$1,203,566
Benefits
$1,287,097
Payroll
$1,164,789
Allocation - Expenses
$637,510
Merger Related Costs
$405,280
Uncollectible
$335,715
Taxes Other Than FIT
$65,434
Rate Case Expenses
$38,400
Customer Growth Expense
$9,337
Federal Income Taxes
$1,844,617
Revenue
$629,812
Section III- RATEJBASE
A. InYestment
A major factor driving the size of the requested increase in this case is the enormous amount
- of money apparently spent by the Company on various new projects for computers and enhanced
computer software. Most of these new investments were booked at the end of the test year in this
case.
E
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I
I
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Based on data provided by the Company, it appears that about $130 million has been spent
throughout Atmos for these new projects. The following table contains a summary of the project
and dollar amount of investment.
TABLE 6
ATMOS NEW PROGRAM INVESTMENTS
Descri to ion
Tata1 luvestmennt
1. Oracle (CWIP)
$20,880,00021
2. Customer Service (CWIP)
$15,500,00022
Other Investment
3. Call Center
$17,375,092"
4. CIS Banner
$40,794,43624
5. Field Hardware
$14,625,38524
6. Start -Up Costs
$22,715,74024
7. Meters
$.1,025,37Z24
Total
$132.9Lb 9L00
As can be seen from the above table, Atmos is making an additional $132,916,030
investment in mostly computer and software enhancements. As of December 31, 1998 the total
Atmos net utility plant value was $744,764,017.24 The new computers, other technology, and
enhanced software investment represent about 18% of total Atmos net utility plant. This investment
does not represent more pipe in the ground or even pipe replacements, but rather a major technology
enhancement. The various categories of investment are addressed in the following paragraphs.
21Company filing WP 7-3.
22Id
21Company response to West Texas 7th RFI, Question 7.
24See 1998 Annual Report to Railroad Commission of Texas, page 35, line 61.
10
' To evaluate the reasonableness of charging ratepayers for these investments DUCI requested
that the Company provide a description of the various projects, the claimed need for the project, and
' any cost/benefit analyses supporting these investments. Obviously, before making any major
investment such as that shown in Table 6, a prudent manager would have fully evaluated the
' costs/benefits prior to making the investment decision. Alternatively, an imprudent manager would
not perform any analysis and assume all investment costs just get passed on to captive ratepayers.
_ 1. O1-acle Einancial..;zaft�ar�
' The Company is requesting that West Texas' pro rata share of the $20.9 million Oracle
financial system be passed on to ratepayers through inclusion of Construction Work in Progress
' ("CWIP"). The Company's describes Oracle as the most significant part of Atmos' overall
Information Technology ("IT") strategy.2s
' The Oracle implementation project is a new software system for the overall Atmos company.
Functional areas affected include: general ledger, accounts payable, purchasing, inventory, fixed
assets, payroll, budgeting and others.26 Completion of implementation of Oracle was expected in
1 July 1999.27
' The Company's cost/benefit analysis indicates savings of about $2.153 million annually and
a one time cost avoidance of about $3.157 million.28 It should be noted that the cost benefit analysis
' is dated December 1998,29 but the implementation of the Oracle project began in August 1998.so
' "Direct Testimony of Conrad E. Gruber, Cause No. 99-070, In the Matter of Rate
Application Western Kentucky Gas Company, page 16.
' 26Id.
' 27Id.
28Company response to West Texas 9th RFI, Question 4. These are cost savings based on
' the current Company size. Higher cost savings are estimated assuming the Company increases
its size by 2.5 times in four years.
29Id.
11
tThus, the cost/benefit analysis provided by the Company could not have been employed in the
original Oracle investment decision.
Even employing the Company's belated cost/benefit analysis indicates that the $20.8 million
1 Oracle investment will not provide any ratepayers savings for at least 20 years (See Attachment 1).
Given that the computer software has a relatively short life with fast paced technology changes, it
would appear that the Oracle investment costs ratepayers more than it is worth. Even with Y2K
considerations, which the Company touts as an important benefit worth $500,000 a one time savings
1 does not justify a $20.8 million investment.
' For all of the above reasons, DUCI recommends that the $20.8 million Oracle investment
not be allowed in this case.
2. Cust-omerJnformatiun�y-stem-("_CIS'_)
' Atmos incurred approximately $41 million for its new Customer Information System.
Energas' portion of this cost is $12,768,496 and West Texas is allocated 71.0377% or $9,070,446
According to the Company, these costs were booked sometime between January 1, 1999 and April
30, 1999."
' DUCI requested the cost/benefit analysis the Company should have performed prior to
entering into this type of project. However, according to the Company, no cost/benefit analysis was
performed.32 We find it difficult to believe that the Company would take on this magnitude of a
project without determining whether the benefits outweigh the costs. The Company talks about cost
' savings related to reduction of employees from 1997 to 1999. These reductions appear to be
associated with a previous merger rather than the CIS system. Per Energas, this system was not
"Direct Testimony of Conrad E. Gruber, Cause No. 99-070, In the Matter of Rate
' Application Western Kentucky Gas Company, page 16.
"Company's response to Amarillo's RFI 2-18 and West Texas' RFI 7-9.
' "Company's response to West Texas RFI 7-5.
12
11
implemented until sometime in 1999.
Energas has not provided any support justifying its new CIS system. DUCI is unable to
justify leaving in this type of cost for the ratepayers without showing equivalent benefits. Therefore,
DUCI is recommending removing the total CIS costs from rate base. This results in a reduction to
gross plant in the amount of $9,070,446 and a corresponding adjustment to accumulated depreciation
in the amount of $191,298.
3. -Call Center
Energas has included approximately $2,488,879 in the West Texas' requested revenue
requirement for its newly implemented call center." This is an increase in call center costs of
$2,361,612 to the Company's calendar year 1998 level of $127,267. The following chart summarizes
the Company's call center revenue requirement request:
TABLE 7
CALL CENTER REVENUE REQUIREMENT
Description
IMLEncrgas
TWAKest_T_exas
O&M ExpenseSM
$2,249,256
$1,597,820
Depreciation Expense73
$539,181
$383,022
Return36
$115,166
$ 5.0.8,03.7
Total Revenue Requirement
$IJQI&03
$2,48.8,872
' Energas has provided information documenting the number of Energas calls the call center
has taken for the eleven months ending August 1999. DUCI annualized this number and calculated
"According to Energas, the call center began in October 1998.
1
34Company's workpaper 4-4.
' "Company's call center investment x requested depreciation rates (Company's workpaper
6-3 and West Texas RFI response 7-7).
' 3'Company call center investment x grossed up return.
13
' 551,628 total calls for Energas for the year ending September 1999." This calculates to a cost per
call of $6.35 38 This cost is not reasonable and it is not consistent with other utilities and companies
that provide this service. DUCI recommends the Cities deny the Company's requested cost and
allow a more reasonable level of call center expenses.
1 .
DUCI is recommending a call center total cost of $1,285,313. This is a reduction of
t$1,203,566 to the Company's request. This amount is calculated by taking the annualized calls
provided by the Company times the call center cost per call authorized by the RCT in Southern
Union Gas Company GUD Docket No. 8878. This cost per call amount has been compared with
outside sources who provide call center services and determined to be reasonable by the
Commission. DUCI believes using the Company's actual annualized calls times the $3.28 cost per
call as a proxy is a reasonable basis for total call center costs. Another option for the Cities is to
allow only the, Company's calendar year 1998 call center costs. The Company's requested call
center costs are exorbitant and ratepayers should not be charged a cost that is almost two times the
going and authorized rate. If the Cities chooses this alternative option, it would be a reduction of
$2,361,612 to the Company's request.
' 4. Startup Costs
Energas is requesting recovery of $8,377,879 in start up costs or $5,951,453 for West Texas'
Distribution System. These costs relate to the new call center and CIS system that DUCI is
recommending be removed. To be consistent, DUCI is recommending that the start up costs also
' be removed. This results in a reduction of $5,951,453 to gross plant and a reduction to accumulated
depreciation in the amount of $141,744.
' 5. Cash-'_arking Capital
' Cash working capital represents the investment that either the Company's shareholders or
ratepayers provide to meet the Company's day to day cash operating requirements. Cash working
' "Company's
s response to West Texas RFI 2-44 ($505,659 x 12/11).
' "Total cost ($3,503,603) _ total number of calls (551,628).
' 14
capital requirements can either be positive or negative. The amount is a component of rate base.
The most accurate means of establishing the appropriate level of cash working capital is to perform
a lead -lag study.39
The Company has not performed a lead -lag study since its West Texas Cities 1996 rate case.
The Company has elected to ignore any cash working capital impact in its rate base by assuming a
zero level. In order to quantify the Company's cash working capital requirement, a lead -lag study
was performed. In certain instances (e.g., collection lag) where the Company could not provide
current data, the results of the Company's 1996 lead -lag study were relied on.
Based on the analyses and current expense levels, a negative $7,865,226 level of cash
working capital is appropriate. It is inappropriate to reward the Company for failing to perform a
lead -lag study.
6.. Allocation-&dj-ustment_£orRa-te-Base
Energas has allocated approximately $23,062,487 in plant from Atmos and Energas to the
West Texas System. The allocation percentages were based on data as of September 1997 and
September 1998.
DUCI has made an allocation adjustment to rate base components similar to the allocation
adjustment discussed in the expense section (See Section IV. D). DUCI is recommending a rate
reduction in rate base in the amount of $372,440.
B. Inv_estment Conclusion
All the various systems and enhancements that the Atmos Company has expanded over $130
million for, essentially perform the same functions that are already in place. The Company admits
' "A lead -lag study measures the time between when a Company receives a product or
service and has to pay for such product or service versus the time between when the Company
provides gas to its customers on a monthly basis and receives payment from customers for the
gas purchased.
15
1
' to this.40 But, the Company claims this enormous investment will allow for better service through
economics of scale, improved communications, better response time, and longer customer service
' hours.41 We believe $130 million is too high a price to pay for the marginal benefits claimed in this
case.
DUCI would urge that these costs not be passed on to ratepayers until the Company can
' clearly show that there is a quantifiable benefit or savings to ratepayers or that these projects and
associated investment was necessary for the continued reasonable and safe operation of the system..
In all of the Company's published reports, quality service was rated quite high before these initiatives
were implemented by the Company. Given the cost/benefit report provided for Oracle and the
cost/benefit analysis of the call center, and the Company's failure to provide supporting
documentation to justify this investment, DUCI would recommend exclusion of all costs.
I Section IV - EXP-ENSE ISSUES
A. Depreciation
The Company is requesting approximately $8.9 million annually in depreciation expense.`
This represents a significant increase in the Company's test year depreciation expense. The Company
' claims its request is based on depreciation studies performed by DeLoitte & Touche ("D&T").
The Company's request reflects a new calculation procedure rarely used by gas utilities which
results in increased depreciation expense. In addition, a portion of the depreciation expense is based
' on depreciation studies now in excess of seven years old. Moreover, the Company's data, as well
as the analysis performed by D&T contains problems, both in theory and in numerical analysis. The
' Company's depreciation request is not adequately supported by its own data and studies. DUCI has
analyzed the available information and recommends numerous adjustments. In total, these
' adjustments still result in an increase in depreciation and clearing account expense above test year
4'See Gruber Testimony before the Kentucky Public Utility Commission, page 15.
41 Id.
41Company WP 6-1 through 6-3, includes expense assigned to clearing accounts.
1 16
' levels, but represent a significant reduction from the level of increase requested by the Company.
' The two largest adjustments which represent over 75% of the adjusted dollars pertain to
distribution mains and all other distribution investment depreciation expense. The recommended
1 - changes to the two accounts reflect a change in calculation procedure, an increase in service life for
distribution mains, and a less negative level of net salvage for distribution investment.
The Company's proposal reflects the utilization of the Equal Life Group depreciation
calculation procedure ("ELG"). The existing rates are based on the Average Life Group calculation
procedure ("ALG").4' The Company's proposal for ELG depreciation is calculated incorrectly and
' its effects, one way or the other, are inappropriate since they result in significant acceleration of
depreciation. An example of the proposed impact of the ELG proposal and D&T's calculation can
be seen for Account 376,'Distribution Mains which represents over 505 of all investment. The
Company has proposed a 60 year average service life for this investment, yet its ELG calculation
' procedure starts off with new plant being assigned a 35.7 year remaining life. This loss of over 24
years of service life based on a rarely used calculation procedure and D&T's calculations is neither
reasonable or appropriate.
' The next major issue is service life. While the Company has proposed a -60 year average
J P Y P P Y g
' service life for Account 376, Distribution Mains, D&T's analyses indicates that a 76 to 80 year
average service life is appropriate, and DUCI's independent analyses indicates that a 70 year average
' service life is appropriate. At this time, nothing less than a 70 year average service life should be
considered.
The last major adjustment pertains to net salvage. The Company does not maintain net
' salvage data by account, but rather for its entire distribution investment. According to the
Company's workpapers, a negative 1% net salvage has been experienced during the historical period
' analyzed. The Company has proposed a negative 25% net salvage for Account 378 all distribution
' 43The Railroad Commission of Texas Docket No. 8205, FOF 88.
' 17
' plant excluding Account 376 and land rights, and a negative 15% net salvage for Account 376. The
Company's proposal is on its belief that cost of removal will exceed salvage. Based on the
' Company's questionable historical data base, its admissions that the majority of its investment is
abandoned in place, and the accounting treatment it employs for meter retirements, there should be
' a minimal level of negative net salvage. DUCI recommends a negative 15% net salvage for Account
378 and.a negative 10% net salvage for Account 376.
The balance of DUCI's recommended adjustments pertain to the ELG versus ALG
calculation procedure and one additional adjustment. DUCI recommends an increase from 5 years
to 7 years for PC hardware. This adjustment is based on a review of the Company's actual historic
' activity, as well as recognition that while CPUs may be changed out frequently, printers, monitors,
networking equipment are retained for longer periods of time. Therefore, a 7 year average service
life is warranted.
' The net impact of the various adjustments discussed above represents a $2,380,063 reduction
to test year revenue requirements. This amount includes both direct West Texas and allocated
' Energas General Office depreciation and clearing account expense adjustments.
The final adjustment DUCI is recommending to depreciation expense is a reduction of
$1,998,249 related to disallowed plant. In Section III. A, DUCI is recommending the Cities disallow
the Company's investment in Oracle, CIS and start-up costs. To be consistent, DUCI is
' recommending an adjustment to depreciation expense for these plants.
' B. Benefits
Energas has requested approximately $2,226,929 for employee benefits. DUCI is
1 recommending a reduction of $1,287,097 to the Company's benefit request. This is comprised of
two adjustments.
The first adjustment relates to DUCI's recommended decrease in payroll. The Company has
J P p Y
proposed adjustments to benefits expense based on benefits being approximately 25.1% of salary
n
' expense.44 DUCI is not opposing the Company's percentage of benefits to total payroll cost. DUCT
is proposing a reduction to payroll in the amount of $736,998.45 Therefore, to be consistent, DUCT
tis recommending a reduction of $184,986 for benefits costs associated with the reduction in
payro11.16
The second adjustment DUCI is making to benefits relates to pension expense. The
' Company has proposed a $1,102,111 adjustment to pension expense to set it at a zero level. The
Company's pension plan is overfunded; therefore, its books reflect a negative expense level. TY>!e
' Company states it proposed this adjustment so the Company will not flow back cash to ratepayers.
The Company states that ratepayers receive the benefit of the overfunded plan in setting a zero level
in this proceeding.
- DUCI recommends the Cities deny the Company's request. Cost of service expenses should
be as of test year end adjusted for known and measurable differences. The Company has been and
continues to be in an overfunded situation for several years and foresees this to continue in the
future. Current rates have a pension expense level built in. Therefore, West Texas ratepayers have
been paying for pension expenses for several years; however, the Company has not had to pay into
' the fund based on its overfunded situation. Ratepayers have not benefited in the past several years
as the Company contends they will be if the Cities sets its negative pension expense to zero. Other
' utilities are in a similar overfunded situation. They are properly requesting a negative pension
expense in requested revenue requirements. The Company's argument has no merit. DUCI
' recommends that the Company's pension expense adjustment of $1,102,111 be denied.
' C. Payroll
1
' 44See Company's WP 4-3 and response to RFI 7-1.
4'DUCI is not calculating benefits expense on the bonus/incentive adjustment.
' 46($736,998 x 25.1 % _ $184,986).
19
' Energas is requesting total payroll expense of $11,871,550 47 The Company has based its
request on annualized salaries as of April 30, 1999, and an adjustment for unfilled positions as of
' test year end. DUCI is recommending a total payroll expense of $10,706,761 or a $1,164,789
reduction to the Company's request. This is comprised of three adjustments. Each adjustment is
' explained in detail below.
' 1. Salary IJPA&ted
The first adjustment DUCI is proposing to the Company's payroll request is to update the
' payroll request through August 1999. The update will provide an employee level that will be more
representative of rates that will be in effect during the rate year. Per the Company's data responses,
Atmos' employee level has increased by six employees and Energas has reduced its employee level
by seven.4' To calculate Atmos' updated payroll calculation, DUCI multiplied the average salary
times six employees and allocated this amount by DUCI's recommended West Texas' allocation
factor to arrive at an increase to the Company's payroll request of $32,466.4' A similar calculation
was developed and applied to the reduction of employees for Energas' general office. This resulted
in a reduction in payroll of $180,368.50 Therefore, DUCI is recommending a net reduction to salary
' in the amount of $147,90251 related to updating the employee level through August 1999.
' 2. Unfilled -Posit' s
' The second adjustment DUCI is recommending relates to the Company's unfilled position
adjustment. In addition to annualizing salaries as of April 30, 1999, Energas also proposed an
' increase to O&M of $589,096 for unfilled positions. As is typical in all companies, Energas has
47Annualized salaries (WP 4-2) $11,282,454 + unfilled positions (WP 4-6) $589,096.
' 411Company's response to West Texas 6-12 and 6-13.
4'Annualized salaries at April 1999 $15,016,643 employee, count 414 = average salary
' $36,272, average salary $36,272 x six employees x 14.91792% allocation factor = $32,466.
"Average salary $36,272 x seven employees x 71.0377% allocation factor = $180,368.
' S1<$180,368> + $32,466 = $147,902 net salary change.
1 20
' vacancies throughout the year.
' The Company's adjustment does not take into account terminations that have occurred since
April 1999. DUCI's adjustment to update salaries up through August 1999 is a better reflection of
what the Company can expect in the rate year. It takes into account both increases and decreases of
employees that have occurred subsequent to test year end. DUCI recommends that the Company's
' adjustment for unfilled positions.be disallowed. Therefore, DUCI is recommending a $589,096
reduction to salary.
' 3. Bonuses
Energas is requesting approximately $427,791 in bonuses.12 According to the Company,
seven months of the bonus amount included in its requested revenue requirement is based on
projections rather than actual expenses. Expenses included in cost of service should be based on
known and measurable amounts. Projections are neither known nor measurable. Therefore, the
' Cities should deny these costs in rates.
DUCI requested the Company provide a complete description of each bonus plan and the
' total amounts included for each plan. Instead, the Company provided descriptions of the bonus plans
that went into effect in February 1999.53 Per DUCI's review of the various programs, the employee
' bonuses are based on target projection's to enhance the Company's earnings and cash flow. As this
will benefit the shareholders, the shareholders should bare the costs.
1
Based on the bonus expenses being projections and the intent of the various plans to enhance
' the Company's earnings and cash flow to the benefit of shareholders, DUCI recommends disallowing
bonus/incentive costs in the amount -of $427,791.
1
D. Allocation Adyusxment-oiExpenses
1
s2Company's response to RFI 5-8.
' "Company's response to RFI 1-30.
21
' Energas has allocated a significant amount of Atmos and Energas cost to the West Texas
Cities based on allocation percentages developed from September 1997 and September 1998 data.
rThe allocation is developed on averaging property plant and equipment ("PP&E"), operation and
maintenance ("O&M") and average number of customers.
DUCI is recommending an adjustment to Atmos' allocation percentage based on more
updated and verifiable numbers. Utilizing the Company's December 1998 Annual Report to the
RCT, DUCI developed an allocation percentage as of December 1998 based on PPE, O&M and
average number of customers. DUCI is recommending an Atmos allocation percentage of
14.91792% versus the Company's 17.5605%. This results in a reduction of $637,510 to the
' Company's cost of service. This adjustment could be higher; however, the Company did not provide
adequate information to determine any further changes to the allocation adjustment.
' E. Merger Relat d Costs
Energas has included $405,28054 in merger related costs in its requested revenue requirement.
According to the Company, these costs relate to the United Cities Gas Company July 1997 merger.
The Company states that the merger created synergies; therefore, all divisions of Atmos should be
allocated a portion of the $62 million cost to merge United Cities. According to the June 30, 1999
' 1OQ filing with the Security and Exchange Commission, Energas states it received a one time $20
million cost savings as a result of the United Cities merger. The Company stated in a data response
that these savings relate to United Cities Division, not the rest of Atmos." Therefore, none of the
savings were included in West Texas' filing.
' DUCI recommends that the Cities deny the Company's requested merger costs in the amount
of $405,280. First, these costs relate to the United Cities division, not West Texas. These are non-
recurring costs and should not be included in developing rates for the future. Non -recurring costs
are normally not allowed in a rate case. Finally, the Company wants to pass the costs through but
"Company's
s response to RFI 1-57.
' 55company's response to West Texas RFI 2-3.
22
I
not any of the savings.
' An alternative would be to realize West Texas' share of the savings along with the cost. If
the Cities allow the Company to include these merger costs, the Company should also be required
to pass on the savings. West Texas would be allocated its 14.91792% share of Atmos realized
savings over three years.
If the Cities recognized its allocated share of the $20 million savings over three years, an off
1 setting adjustment to expenses in the amount of $994,528 should be made."
' F. Untollectible Accounts
Energas has requested $1,261,765 in uncollectible expense. According to the Company, this
_is based on an accrual basis rather than actual write-offs.
IDUCI is recommending two adjustments to the Company's requested uncollectible expense.
The first adjustment DUCI is recommending is that the Company should only be allowed to collect
' actual uncollectible expenses rather than the Company's accrual amount. Expense included in a
' Company requested cost of service should be based on actual expenses adjusted for known and
measurable changes, not a hypothetical accrual amount set by the Company.
' The second adjustment DUCI is recommending is that the Cities allow a three year average
' of the Company's actual write offs. Per review of the Company's uncollectible expense, the test year
level was significantly higher than prior years. Therefore, DUCI believes a three year average would
' be a more representative level of uncollectibles than allowing the Company's proposed high test year
level. DUCI is recommending an adjustment to the Company's uncollectible expense in the amount
of $335,715.
' G. TaxesAXILezThaaF1T
' `$20 million savings x 14.91792% allocation divided by a three year amortization.
23
11
1. Payroll Taxes
Energas is requesting total payroll tax in the amount of $517,521. Energas based its request
on a factor of 5.6177% to total payroll expense to calculate total payroll taxes.
DUCI is recommending a reduction to payroll taxes in the amount of $65,434, based on its
recommended reduction of payroll expenses.s'
2. Remenue-RelatedTaxes.
Energas is requesting a revenue related tax percentage of4.997%. The following breaks out
this percentage:
City Franchise Tax
3.0000A
State Gross Receipts Tax
1.997%
Revenue Related Tax
4 99Z%
DUCI is not recommending any adjustments to the Company's tax percentages. However,
DUCI is recommending a reduction of $847,756 to revenue related taxes as a result of the other
adjustments made to Energas' proposed revenue requirement.
' H. Ra_teSaseExRensts
In the Company's Statement of Intent, Energas proposed to recover rate case expenses plus
' interest over an eighteen month surcharge. However, the Company has stated in a data response that
it is not requesting interest on rate case expenses and it has calculated a base rate recovery over three
' years. The Company has included a $38,400 increase in O&M expenses for rate case expenses.
DUCI recommends three adjustments to the Company's request.
First, DUCI recommends removing the request from rates and allow the Company to
57Total payroll reduction of $1,164,789 x 5.6177% _ $65,434. Note: DUCI is reducing
' payroll taxes for bonuses as a company is required to pay taxes on bonuses.
24
' surcharge only actual rate case expenses. If the Cities allow Energas to include the actual rate case
expense amount in cost of service, Energas will continue to recover the annual amount until the next
' rate case, not just the eighteen month period the Company contends.SB Therefore, this amount should
be removed from O&M adjustments. This is also consistent with the RCT's findings in the last
Energas case for the West Texas service area, GUD No. 8205. The RCT ordered the Company to
remove rate case expenses from O&M and only surcharge actual expenses over a three year period.59
Second, the Company should not be allowed to include interest on rate case expenses.
1 According to § 7.57 of the Substantive Rules, Energas should only be allowed recovery of its actual
reasonable rate case expenses. DUCI is not aware of any company that the RCT has allowed interest
calculated on rate case expenses.
The third adjustment DUCI is recommending is a three year surcharge of rate case expenses --
' instead of the eighteen month proposed by the Company in its Statement of Intent. The Company
has not filed a rate case in West Texas since 1996. DUCI is recommending a conservative three year
period. The three year period is also consistent with the RCT's decision in West Texas' prior case.
DUCI is recommending removing the entire $38,400 from the Company's O&M expense and
surcharging actual reasonable rate case expenses over a three year period. This is a reduction of
I$38,400 to the Company's request.
' L Year Fnd�us�2mer Growth xnense Adjustment
The Company has proposed a proforma adjustment to O&M expense for customer growth
' in the amount of $9,337. This adjustment assumes that O&M expenses will increase proportionately
to new customers added to the system. This assumption is not correct. Adding a few new customers
Ito its system will not cause O&M to increase. A significant increase in customer base may increase
O&M expenses. For example, the Company will not need to add new administrative personnel or
I
"'Or three year period stated in the Company's data response.
' S9GUD Docket No. 8420.
1 25
Imeter readers if it adds 10 new customers.
' The test year level of O&M adjusted for known and measurable changes is the most
representative level for rates to be set for a future time period. The customer growth adjustment is
' neither known nor measurable. Utilizing the test year end level of expenses is more representative
of the Company's level of costs in the future. Therefore, DUCI recommends a decrease of $9,337
' to the Company's requested O&M expense.
' J. Summaly—afExpense Adjustments
Energas' proposed revenue requirement includes $37,121,247 in O&M, depreciation and
other taxes expense. DUCI is recommending a total revenue requirement expense of $27,595,803.
' This results in a reduction of $9,525,444 to the Company's request.
' Section V RETURN
A. Cost oS CapitaL- Cos_"f.Equity—Capital
' In this section of the report, we present our analyses used in estimating Energas' cost of
equity in this case. In addition, we discuss the details of the analysis and conclusions resulting from
' the analysis.
' We applied the DCF method employing market data, as well as forecasted data of various
financial parameters for a group of 14 natural gas utilities including the Energas parent company,
' Atmos Energy Corporation. The comparable group of 14 natural gas utilities employed in this
analysis is shown on Attachment 2.
' The foundation of the DCF model is in the theoryof security valuation. The rice that an
Y P
' investor is willing to pay for a share of common stock today is determined by what income stream
the investor expects to receive from the investment. The return the investor expects to receive over
' the investment time horizon is composed of. (i) dividend payments, and (ii) the appreciated sale
value of the investment. One must keep in mind that one cannot merely add dividends to the gain
1 on the final sale value, but rather must discount these expected future earnings to a percent value.
i
' To determine or estimate investor requirements using the DCF model, one computes a cost
of capital requirement, or discount rate from the current market data and the expected dividend
' stream. The DCF model stated as a formula is as follows:
K=D/P+G -
where:
K = required return on equity,
D = dividend rate,
1 P = stock price,
D/P = dividend yield, and
G = growth in dividends.
The -dividend -yield is the ratio of the dividend rate to the stock price. When calculating the
' dividend yield, one must be cautious and not rely on spot stock prices. One must be equally cautious
as to not rely on long periods of time as the data becomes unrepresentative of market conditions
The objective is to use a period of time such that the resulting dividend yield is not unrepresentative
of the prospective period when rates will be in effect.
While there is no fixed period for selecting the denominator of the dividend yield (i.e., stock
' price), the key guideline is that the yield not be distorted due to fluctuations in stock market prices.
On the other hand, dividends, the numerator of the yield calculation, are relatively stable, as opposed
' to the stock prices which are subject to daily and cyclical market fluctuations. The selection of a
representative time period will dampen the effect of stock market changes.
The price and dividend data used for each of the companies in the natural gas company
' comparable group is contained in Attachment 3. We have utilized a 6 week period for calculating
average price-. In our opinion, the 6 week average price is representative of the Company's stock
' prices.
' As can be seen from Attachment 2 the average dividend yield (before adjustment to an
27
1
expected yield) for the 14 natural gas company group is 4.38%. The dividend yield calculation in
each comparable group are consistent with the most recent yield as reported by Value Line.
The expected dividend yield shown on Attachment 2 was calculated by increasing the
dividend yield developed in Attachment 4 by one half of the estimated growth rate in dividends.
Growth rates are discussed in the following section of this report.
Like dividend yields, there exists no single or simple method to calculate growth rates. The
calculation of investor growth expectations is the most difficult part of the DCF analysis. To
estimate investor expectations of growth, we examined both historical growth, forecasted growth
rates, and other financial data for each of the companies in the natural gas company comparable
-' group.
The first measures of growth examined are the Value Line historical five and ten year growth
rates in book value, earnings and dividends per share. Attachment 4 shows these growth rates for
the companies.
The second set of growth rates examined were the Institutional Brokers' Estimate System
("IBES") growth rates. These growth rates represent consensus earnings estimates of professional
securities analysts, brokerage and research firms. We have relied upon the mean estimate produced
by these IBES estimates. The IBES earnings estimate for each of the companies in the group is
contained at Attachment 4.
The third set of growth rates examined were the V_alu-eLine forecast of earnings, dividends
and book value per share.
The fourth set of growth rates examined are the ZACKS estimates of individual Company
earnings. These growth rates are shown on Attachment 4.
' In our opinion, these four growth rates when examined for each company in the comparable
28
1
' group result in a reasonable estimate of what investor expectations are for each company.
' It is very important to note that we examined each company's individual growth rates,
historical and forecasted. For these analyses, we employed the average of the forecasted growth
rates which is shown in Attachment 4.
The range of growth rates estimated at Attachment 4 provides a reasonable estimate of
investor expectations of growth for each of the companies in the group. Attachment 2 shows the
average cost of equity capital for the group is about 9.94%.
' We have also examined a non -constant growth model as an alternative estimate to the
constant growth DCF. The reason for analyzing the multi -stage or non -constant growth DCF
approach is -to. -Address the issue often raised regarding present market and utility -conditions; that the
constant growth DCF may not provide reliable results.
Fluctuating growth rates for many utilities creates an inconsistency in the constant growth
DCF assumption. Moreover, because of merger and acquisitions in the industry, stock prices for
some utility companies may be more closely related to future price expectations than to traditional
' dividend growth prospects. Thus, in some situations the multi -stage model is a more reliable cost
of equity estimation method.
' The non -constant DCF results shown in Attachment 5 are Internal Rate of Return ("IRR")
calculations of the cash flows associated with each of the companies in the comparable group. It is
' assumed that the stock is purchased at current prices, dividend received, and the stock is sold in
2004.
' Attachment 5 contains the results of the non -constant growth DCF for each comparable group
' in this analysis. The 14 company natural gas utility group average results are 10.7% with a truncated
mean at 10.7%.
I
' 29
i
' The results for the 8 company natural gas group provide a range of 9.9% to 10.7%, again
based on the truncated average. A reasonable range for cost of capital in this case is between 9.93%
' to 10.7%.
' Given the lower risks facing Atmos/Energas relative to the comparable group, where risk is
measured by beta, we would recommend a return in the 10% range. The lower end of the 9.94% to
' 10.7% range was selected to take into consideration the lower risks facing Energas discussed above.
' A 10% return on equity will provide Energas financial integrity. For example, a 10% return
on equity and the resulting overall return of 8.71 % will result in a pre-tax coverage ratio of about
' 3.2x. The after-tax coverage ratio is approximately 2.5x. These average ratios are not inconsistent
with coverage ratios experienced by gas utility companies.
' The overall cost of capital is the sum of the weighted average cost rates of various sources
of capital. The quantity or portion of each type of capital, combined with the cost rate of capital,
determines the overall rate of return which Energas should be allowed to earn in this proceeding.
' M The most significant relationship in any capital structure is the debt to equity ratio because of the
impact on the overall cost of capital to the Company and the impact on financial risk, and its ultimate
' effect on capital costs.
' There exists no set relationship for all firms or all industries in terms of leveraging.
' However, the ideal capital structure is one which minimizes the overall cost of capital to the firm,
while still maintaining financial integrity so as to maintain the ability to attract capital at reasonable
' costs to meet future needs. Because the cost of debt is generally lower than the cost of equity, and
also because the cost of debt represents a tax deductible expense, any increase in the quantity of debt
' capital tends to decrease the overall cost of capital relative to equity financing. One must keep in
mind that increases in the quantity of debt financing can cause the financial risk of the Company to
' increase. In other words, there is a cost for the savings associated with increased debt leveraging.
That cost is increased financial risk to the firm.
30
In summary, it is not possible to determine with precision the exact proportion of debt and
equity which minimizes the overall cost of capital without imposing undue financial risk upon the
Company. There does exist some range of capital structure which, generally, meets the goal of
minimizing the overall cost of capital while maintaining the firm's financial integrity.
The Company's proposed capital structure, cost rates and overall rate of return requested in
this filing areas follows:
TABLE 8
ENERGAS' PROPOSED CAPITAL STRUCTURE
DESCRIPTION
RATIO
COST
WEIGHTED COST
Long -Term Debt
40.40%
8.06%
3.2562%
Short -Term Stock
9.40%
6.35%
0.5969%
Common Stock
50.20%
12.25%
6.1495%
Total:
100.00%
10.01 %
- As can be seen from the above table, the Company's overall requested cost of capital to be
applied to rate base in this case is 10.01%.
The adjustments we are recommending is that the capital structure be based on actual data
and the equity cost rates be reduced from the requested 12.25% to our recommended 10%. Thus,
the capital structure and cost rates we are recommending are as follows:
TABLE 9
RECOMIENDED CAPITAL STRUCTURE AND COST RATES
DESCRIPTION
RATIO
COST RATE
WEIGHTED COST
Long -Term Debt
43.72%
8.06%
3.52%
Short -Term Stock
12.09%
6.35%
0.77%
Common Stock
44.19%
10.0%
4.42%
Total:
100.00%
8.71 %
31
As can be seem from the above, our recommended overall return in this case is 8.71 %.
The problem with the Company's proposed capital structure is that it is based on a forecasted
capital structure based on a 13 month average for the forwarding looking period.60 The Company
claims that various anomalous factors occurred in 1998 causing the Atmos capital structure to
deviate from normal.
Actually, the Atmos 1998 capitalization ratios for debt and equity is well in line with the
1998 capitalization ratios of the 14 companies in the comparable group. Moreover, the forecasted
capitalization depends on a number of factors which include; adoption of a weather normalization
adjustment mechanism in the Western Kentucky case, a return to normal weather patterns for other
Atmos utility divisions, issuance of new equity in November 1999, raising $20 million of new -equity
annually under the Company's DSPP and ESOP plans, no significant acquisitions, sufficient cash
flow to fund ongoing capital spending, and no new debt issue. Thus, the 500/o/50% debt/equity ratio
forecast and requested in this case is dependent on a number of factors including the weather. Such
assumptions are too tenuous to rely on in setting rates; thus, we recommend using actual data.
Section VI - FE XXAL INCOME T_AXF' ("FIT")
1
Energas requested total FIT of $4,130,300. This is calculated by using the return method.
DUCI agrees with the Company's methodology. The reduction of $1,844,617 recommended by
DUCI is a result of the decrease in rate base and change in the rate of return recommended in other
parts of the report. Schedule 5 supports the adjusted federal income tax computation.
Section VII - RF -FN- IE
A. Pr_oposed_.Annu.al_.In.creas_e,_Rev-eaues,-Billing-Reter_minants__and-Pro Forma
A.djarstm_ents
60See Western Kentucky Gas Company Rate Application Before the Public Service
Commission Commonwealth of Kentucky, Case No. 99-070 Direct Testimony of John P. Reddy
at page 3, lines 13 through 15.
32
The Company's proposed rate increase for the West Texas Distribution System is a
$9,838,722 or 8.4% annual overall increase in rates.61 The following table provides a summary
breakdown of the Company's proposed rate change by customer class.
TABLE 1062
ENERGAS PROPOSED TOTAL REVENUE INCREASE
WEST TEXAS
CLASS
REVENUE
CURRENT
REVENUE
PROPOSED
REVENUE
INCREASE
PERCENT
CHANGE
Residential
$78,375,254
$86,026,291
$7,651,037
9.76%
Commercial
$20,333,076
$21,779,287
$1,446,211
7.11%
Industrial
$6,336,631
$6,498,090
$161,459
2.55%
Public Authority
$6,449,963
$6,555,745
$105,782
1.64%
State Institutions
$265,399
$301,172
$35,773
13.48%
Large Air Cond.
$146,977
$147,615
$638
0.43%
Air Cond.-Residential
$4_,4 9
$4,222
$2.4.3
5.4.3,%
TOTAL
$111.911.780
$1 u-12m
$9,_49.1.,14a
8,_40%
B. The Fnergre-Omer-stated
A review of the Company's calculations of present and proposed rate revenues shows that
the Company's calculated rate revenues and billing determinants are understated. In other words,
the Company's calculation of proposed revenues is understated because Energas failed properly
calculate customer growth and weather normalization adjustment.
61The proposed annual increase in revenues by City is included in Attachment 8.
Attachment 8 breaks down the increase between the individual Cities. The $1,011,569 difference
relates to the environs rate increase. The Company has not yet filed a case in the environs.
62See Company response to West Texas First Request, Q. 41.
63See Footnote 17.
33
11
C. The—C-Qmpany's--ustamer Adjusxment-S-ubstantially Un.derstates_Customer. .
Growth
Test year present rate revenues were adjusted by the Company to reflect customer growth.
The following table reflects the Company's proposed adjustment to test year revenues.
TABLE 11
ENERGAS TEST YEAR REVENUE ADJUSTMENT
TO REFLECT CUSTOMER GROWTH
CLASS
BILL�ADJUSTIVLF.NT
VOLUME ADJ I TMENT
General Services
7,161 bills6°
61,370 McF"
Small Industrials
<85> bills
<28,521> MCF67
TOTAL
7,076 bills
32,849 McF
A review of the Company's proposed customer growth adjustment in this case reveals a
number of problems. First, the Company calculates the difference between 1998 and 1999 customer
levels. For the general services class that difference is 7,161 bills. Second, the Company divides
the 1998 - 1999 bill growth by two essentially to determine average bill growth. For the general
services class calculated average bill growth is 7,161 bills (14,322 bills/2).
Third, the Company multiplies the average bill growth by the average normalized use per
customer to arrive at a volume adjustment. For the general services class the volume adjustment is
61,370 McF (7,161 bills x 8.57 McF of normalized average use). Lastly, test year revenues and
billing determinants are increased by the bill and associated McF consumption adjustments resulting
from the calculated customer growth.
The first problem with the Company's customer growth adjustment is that reliance on average
d4See Energas Rate Filing WP 2-6.
65Id.
66Id.
67Id.
34
rather than year end growth results in a downward bias in test year revenues. In other words, the
Company calculates a growth adjustment, but cuts the growth in half to arrive at "average growth."
Given that the Company is calculating growth from 1998 to 1999, the average growth assumption
takes customer levels to the beginning of the test year, not test year end. Stated another way, real
customer growth during the test year is not counted in the Company's analysis.
A final problem with the Company's limited growth adjustment is that the analysis fails to
match test year revenues, expenses, and plant investment. Under the Company's filing, plant is
adjusted through September 1999, while revenue adjustments go to May 1998. Clearly there is a
mismatch.
D. Altu"tLw Customer Growth.Adjustment
To properly match test year revenues and plant balances, and have an internally consistent
or reliable customer growth adjustment, the Company's proposal must be rejected. As an alternative
and more reliable approach, DUCI recommends annualizing the test year end level of customers.
This is very similar to the Company's payroll expense annualization adjustment.
Thus, the April 30, 1999 customer levels were multiplied by 12 to annualize test year end
customers. This annualized value was then compared to actual total customers during the test year.
The difference between annualized and actual customer levels is the growth adjustment in bills by
class. The actual calculations for each customer class for growth in bills and volumes is shown in
' Attachment 6.
The following table summarizes the proposed charges in bills and customer volumes to
properly annualize test year revenues.
35
' TABLE 12
CUSTOMER GROWTH IN BILLS
' AND VOLUME COMPARISON
1
ENERGAS
Bills
McF Volumes
General Services
18,996
162,796
Small Industrial
<116>
<38.,923?
TOTAL
18,880
123,873
' E. Weather Normalization
The Company's test year sales levels were adjusted to reflect normal weather. In this case,
' test year sales were below normal as measured by heating degree days.68 To arrive at a normalized
level of test year volumes, sales were increased to adjust for warmer than normal weather conditions
' in the test year.
DUCI employed regression analyses to calculate the sensitivity of weather sensitive demand
relative to degree days. The resulting regression coefficients were then applied to normal degree
' days to arrive at a normalized test year level of sales. The weather adjustment made to the
Company's proposed test year sales levels is an increase of 2,799,166 McF.
F. Qth-erA mnues
' Energas is requesting a change in other revenues. According to the Company's workpapers,
it is requesting an increase of $325,985 for the various charges. These charges are mainly for turning
' service on or off, NSF charges, meter set, etc. Attachment 7 breaks down the current charges and
proposed charges by type. DUCI is recommending that the Cities grant the changes to other service
' charges.
' 68Heating degree days measures actual versus normal weather.
36
tG. A.djusted_Present_Rat{ReYenm
Given the adjustments described above for customer growth and weather, DUCI has
' recalculated present rate revenues and recommends an increase to the Company's proposed revenues
of $629,812.
Section VIII - TARIFF
' The Company has proposed several tariff rider's related to future investment. These tariff
rider's, steel pipe improvement program rider ("SPIP"), and the system expansion rider ("SER") are
1 best characterized as automatic adjustment clauses. In other words, the Company is requesting that
the Cities authorize currently, the carrying costs, depreciation and tax expenses of investment that
' may take place in the future.
�. As discussed below, DUCI urges the Cities to decline the Company's invitation to engage
in authorizing such automatic rate increases on customers. First, these proposed riders should be
' denied because they are authorizing actual increases for potential or speculative costs. Second, these
riders fail to recognize that annual depreciation expense provides more than sufficient cash flow to
cover these incremental investments. Third, these tariff riders, if adopted, are likely to result in a
Iwindfall to shareholders at the expense of ratepayers.
' In evaluating the need for these proposed tariffs, the Cities should consider the Company's
claimed need for these riders. Basically, the Company claims annual investment in new facilities
Iincrease the Company's costs. But the Company fails to point out that annual depreciation expense
is normally higher than additional investment. The recognition of this situation would require
Iratepayers rates to decrease each year. The Company's proposal produces bottom line shareholder
windfalls at the expense of ratepayers.
For the reasons stated above, DUCI recommends that the Cities deny Energas request for
Ithe SPIP and SER.
i
37
Resolution No. 2000-R 0045A
1
1
1
1
1
1
1
1
1
1
1
S
C
H
E
D
U
L
E
S
Resolution No. 2000-R0045A
SCHEDULE1
WEST TEXAS DISTRIBUTION SYSTEM
COST OF SERVICE
TWELVEMONTHS
ENDED APRIL
30, 1999
Company's
DUCI's
DUCI's _
Description
Request
Adjustment Recommendation
Cost of Gas
0
0
0
Operations & Maintenance Exp
27,092,915
(5,081,699)
22.011,216
Depreciation & Amortization Exp
7,409,647
(4,378.311)
3,031,336
Taxes Other Than Income Taxes
2,618,685
(65,434)
2,553,251
Return
12,484,922
(4,117,675)
8,367,247
Income Tax
4,130$00
(1,844,617)_
_ _ _ ___2,2_05,682_
Interest on Customer Deposits
70,381
0
70,381
Total Cost of Service
53,806,849
(15,487,736)
38,319,113
Revenue at Present Rates
44,459,765
629,812
45.089,577
Net Revenue Deficiency
9,347,084
(16,117,548)
(6,770,464)
Deficient Revenue Related Taxes
491,641
(847,756)
(356,115)
Total Rev Increase & Appl. Taxes 9,838,725
(16,965,305)
(7,126,579)
SCHEDULE 2
WEST TEXAS DISTRIBUTION SYSTEM
PAG_IOF2
'
OPERATIONS & MAINTENANCE EXPENSES
TWELVE MONTHS
ENDED APRIL 30,1999
Company's Company's Company's
DUCI's
DUCrs
'
AectfE
Desc on
UNDERGROUND STORAGE EXPENSES:
Test Year Adjustments
Regue51
AtlO3tmCII1
$ecommendation
'
818
QpeII04II:
Compressor Station Expense
148
148
148
Total Operation
148
148
148
'
OTHER STORAGE XP NSES:
Maintenance
'
847
Maintenance of Liquefaction Equip
Total Maintenance
658
658
658
658
658
658
TRANSMISSION
EXPENSES*
Q=ration-
856
Mains Expense
17
17
17
857
Measuring 6 Reg Station
M
In
177
'
Total Operation:
Maintenance -
194 0
194
0
194
Maintenance of Mains
113
113
113
- 865
Maint of Meas 3 Reg Station
Al
Al
81
Total Maintenance:
194 0
194
0
194
'
DISTRIBUTION
Total Transmission Expenses:
EXPENSE'S•
a$$ Il
Il
38fl
'
870
Olgraflaw
Supervision
394,732
394,732
394,732
1171
Load Dispatching & Odor.
8,058
8,058
8,068
872
Compr Station Labor 3 Equip
379
379
379
874
Mains 6 Services
1,962,495
1,962,495
1,962.495
'
875
Meas 8: Reg Station - Gen
255,051
255MI
255,051
876
Maas 6 Reg Station - Ind
31,002
31,002
31,002
877
Meal 6 Reg Station - City Gate
18,570
18,570
18,570
878
Meter a House Reg
2,967,192
2,967,192
2.967,192
879
Customer Installation
1.032.415
1,032,415
1.032,415
'
880
Other Expense
40,354
40,354
40,354
881
Rents
1A41.337
1,041"337
1.041,337
Total Operation:
Maintenance:
7,751,585 0
7,751,585
0
7,751.585
885
Supervision
0
0
0
$86
Structure - Improvements
23,253
23,253
23,253
887
Maims
350,435
350,435
350.435
'
889
Maas 3 Reg Station - Gen
22,372
22.372
22,372
890
Maas d. Reg Station - Ind
37.183
37,183
37,183
$91
Meas 3 Reg Station - City Gate
5,ew
5,830
5,830
892
Servk,s
54.144
54,144
54,144
893
Meter 6 House Regulators
97,507
97,507
97.507
894
Other Equip
20-55,9
2Il.559
20,559
Total Maintenance:
611,283 0
611.283
0
611,283
'
Total Distribution Expense:
8,36296$ 12
8.362AW
Il
8-362.95$
-
SCHEDULE2
PAGE 2 OF
WEST TEXAS DISTRIBUTION SYSTEM
-2
OPERATIONS
& MAINTENANCE EXPENSES
TWELVE MONTHS ENDED APRIL 30,1999
Aug
Derr 1ption
CUSTOMER EXPENSE:
Company's
Test Year
Company's Company's
Adiustments Request
DUCrs
apt
DUCrs
Recommendation
901
Customer Accounts E nse.
Supervision
3,307
3,307
3.307
902
Meter Reading Lenses
899,913
W9,913
899,913
903
Customer Records If Coll
792,163
161=
953,368
953,368
Call CenterAdjuslment
613,829
613,829
(1,2031566)
(W9,737)
904
Un oliectibie Acct
1.261,765
1,261,765
(335,715)
926,050
Customer Growth Adj
9,337
9,337
(9,337)
0
905
M4sc Customer Acct Exp
445
445
445
Total Customer Accounts
2,957,593
794,371
3,741.%4
(1,548,618)
2,193.346
'
909
Supervision90
74,9
74,9W
74,990
910
Customer Assistance Expenses
326,999
326,999
326,999
'
911
Informational Advertising
Total Customer Service
225A44
627.433
0
225,444
627.433
0
225,444
627,433
915
Sales Pmmntion Ex
Supervision
31,166
31.166
31,166
916
Demonstrating S Selling
124.212
(22,541)
101,671
101,671
917
Promotional Advertising
1.513
Il
1AU
1,513
Total Sales Promotion
156,891
(22,541)
134,350
0
134,350
--
Total Customer Expenses:
3.741.917
761.830
4.503.747
(1.548.618)
2.955.129
'
921
ADMINISTRATIVE b GENERAL EXPENSES,
Office Supplies 6 Expenses
250
250
250
922
Admin. Exp Transferred
12,105,535
12.105,535
(1,042,795)
11,062.740
-
Payroll Adj - Annualized
0
(945 365)
(945,365)
(575,693)
(1,521,058)
-
Payroll Adj - Unfilled Positions
0
589.096
589,096
(W9,096)
0
-
Benefits Adj
0
(89,424)
(99,424)
(89.424)
'
024
Property bits
925
Injuries 3 �
233,590
233,5W
233,5W
926
Employee Welfare/Penslons
1.124.818
1.102,111
2=,929
(1,287.097)
939,832
928
Regulatory Commission Exp
18,415
18,415
18,415
'
929
Duplicate Charges
(23,839)
(23,839)
(23,839)
Lease Vehicle Adj
49,080
49,080
49,080
Rate Case Amort Adj
38,400
36,400
(38,400)
0
930
Mist. General
22.439
2
22.433
22.439
'
Total AdG Expenses
13,481.208
743.898
14,225.106
(3.533,081)
10192.025
I
TOTAL OPERATION i MAINTENANCE EXPENSES
25587.187
1 SM 728
27.09? 915_
15 081 69M
22.011 216
SCHEDULES
WEST TEXAS DISTRIBUTION SYSTEM
'
RATE BASE
TWELVE MONTHS ENDED APRIL 30, 1999
'
Descri tR ion
Company's
Request
DUCI's
Adjustment Recommendation
DUCI's
'
Gross Plant In Service
Accumulated Depreciation
209,458,913
(L,616,4L%
(15,394,322)
333,041
209,458,914
(77,283,444)
Net Plant In Service
131,842,428
(15,061.281)
116,781,147
1
Plant Not Completed (est 9199
5,739,189
0
(5,739,189)
'
ADFIT
(13,087,426)
0
(13,087,426)
Customer Advances for Const
(351,216)
0
(351,216)
'
Customer Deposits
(1,357,854)
0
(1,357,854)
ITC
(441,351)
0
(441,351)
'
Working Capital
'
Prepayments
332,409
0
332,409
Materials & Supplies
2,048,313
0
2,048,313
'
Cash Working Capital
Q
(Z,865,22W
(j.865,2:20
TOTAL RATE BASE
$1 4.7 4-49
1$28.665.6961
$96.058.796
'
ROR
10.01 %
8.71 %
RETURN
$ 2,484,922
$4,117,675
,$8-367,247
1
WEST TEXAS DISTRIBUTION SYSTEM
RATE OF RETURN
TWELVE MONTHS ENDED APRIL 30, 1999
Line # Description
1 Long Term Debt Capital
1 2 Short Term Debt Capital
' 3 Equity Capital
4 Total Rate of Return
Line #
' 1
2
' 3
4
1
Description
Long Term Debt Capital
Short Term Debt Capital
Equity Capital
Total Rate of Return
• •TTj��
Capital
Percentage
40.4%
9.4%
55,Q.2%
l 00�.0%
DUCI'S RECOMMENDATION:
Capital
Percentage
43.7%
12.1%
44.2%
JQQAM
Cost Rate
8.06%
6.35%
12.25%
Cost Rate
8.06%
6.35%
%
,SCHEDULE 4
Overall Cost
of Capital
3.26%
0.60%
%
Overall Cost
of Capital
3.52%
0.77%
4 °
.7105%
'
SCHEDULE 5
WEST TEXAS
DISTRIBUTION SYSTEM
FEDERAL INCOME TAXES
TWELVE MONTHS ENDED APRIL 30, 1999
Company DUCI'S
DUCI'S
'
Description
Request Adjustment
Recommendation
'
Rate Base
124,724,492 (28,665,696)
96,058,796
Rate of Return
10.01 %
8.71 %
'
Required Return
12,484.922
(4,117,675)
8,367,247
'
Less: Interest Expense
4,814,365 (691,957)
4,122,408
Net After Tax Income
7,670,556 (3,425,718)
4,244,838
'
Gross UP Factor
1.538462
1.538462
'
Net Taxable Income
11,800,856 (5,270,335)
6,530,520
Tax Rate
55%,
35%
FEDERAL INCOME TAX
Gil
' Debt Component 3.86% 4.29%
Rate Base 124,724,492 96,058,796
' Int On LTD 4,814,365 4,122,408
1
d
Ln
0
0
z
q
O
44
Q
q
4
a
to
IR
J
'
Resolution No. 2000-R 0045A
ATTACHMENT 1
'
WEST TEXAS DISTRIBUTION SYSTEM
CUMMULATIVE SAVINGS ON
ORACLE PURCHASE
'
TO RATEPAYERS OVER
20 YEARS
DISC. RATE
0.12
LINE
PROJECTED
DISCOUNT
CUMM.
NO.
SAVINGS
VALUE
SAVING
1
$2,784,400
$2,486,071
$2,486,071
2
$2,784,400
$2,219,707
$4,705,778
3
$2,784,400
$1,981,881
$6,687,659
'
4
$2,784,400
$1,769,537
$8,457,196
5
$2,784,400
$1,579,943
$10,037,139
6
$2,153,000
$1,090,777
$11,127,916
7
$2,153,000
$973,908
$12,101,824
8
- - $2,153,000
$869,56t_
$12,971,384 - _ -
9
$2,153,000
$776,393
$13,747.777
'
10
$2,153,000
$693,208
$14,440,986
11
$2,153,000
$618,936
$15,059,922
12
$2,153,000
$552,621
$15,612,543
13
$2,153,000
$493,412
$16,105,955 - - -- -----
14
$2,153,000
$440,546
$16, 546,502
15
$2,153,000
$393,345
$16, 939,847
'
16
$2,153,000
$351,201
$17,291,048
17
$2,153,000
$313,572
$17,604,620
18
$2,153,000
$279, 975
$17,884, 595
'
19
$2,153,000
$249,978
$18,134,573
20
$2,153,000
$223,195
$18,357,768
WEST TEXAS DISTRIBUTION SYSTEM
COST OF EQUITY ANALYSIS
MOODY'S GAS UTILITIES
Average
Base
Expected
Adjusted
Line #
,Y
Company
Price
Dividend
Yie Ld
Growth
)fLeid
BQ
1
ATG
AGL Resources, Inc.
$18.28
$1.08
5.91%
4.54%
6.04%
10.58%
2
CTG
CTG Resources, Inc.
$36.21
$1.04
2.87%
4.92%
2.94%
7.86%
3
CGC
Cascade Natural Gas
$17.59
$0.96
5.46%
3.99%
5.57%
9.56%
4
CNE
Connecticut Energy
$37.63
$1.34
3.56%
5.41%
3.66%
9.07%
5
IEI
Indiana Energy, Inc.
$21.15
$0.93
4.41 %
5.62%
4.53%
10.15%
6
LG
Laclede Gas
$22.25
$1.34
6.02%
2.87%
6.11%
8.98%
7
NJR
New Jersey Resources
$39.51
$1.68
4.25%
5.84%
4.38%
10.22%
8
NWNG
Northwest Natural Gas
$26.89
$1.22
4.54%
4.46%
4.64%
9.10%
9
NUI
NUI Corp
$26.03
$0.98
3.76%
8.74%
3.93%
12.67%
10
PGL
Peoples Energy Corp
$36.99
$1.96
5.30%
3.98%
5.40%
9.38%
11
PNY
Piedmont Natural Gas
$33.22
$1.38
4.15%
6.11%
4.28%
10.39%
12
PVY
Providence Energy
$28.30
$1.08
3.82%
5.60%
3.92%
9.52%
13
WGL
Washington Gas Light
$27.61
$1.22
4.42%
4.77%
4.52%
9.29%
14
Average
$28.59
$1.25
4.50%
5.14%
4.61 %
106.26% 9.75%
15
ATO
Atmos Energy Corp
$25.13
$1.10
4.38%
7.86%
4.55%
12.41 %
139.20% 9.94%
I_ M M I• I• 11i1i1il♦ i1i1i1il♦ lil• lil• M M ii. I• 1=1 1111in r 1=1 1=1 r
WEST TEXAS DISTRIBUTION SYSTEM
DMDEND YIELD
MOODY'S GAS UTILITIES
August
August
August
August
September September
4 Week
6 Week
8 Week
12 Week
Lines
;SYM
Company
81h
Mh
23sd
=11
6Ih
IM
Axerag
Average
Average
Axerag
1
ATG
AGL Resources, Inc.
$18.31
$18.44
$18.19
$18.38
$18.56
$17.81
$18.24
$18.28
$18.41
$18.70
2
CTG
CTG Resources, Inc.
$36.63
$36.50
$36.50
$36.13
$35.75
$35.75
$36.03
$36.21
$36.43
$36.56
3
CGC
Cascade Natural Gas
$16.56
$17.31
$17.50
$17.88
$18.50
$17.81
$17.92
$17.59
$17.60
$17.72
4
CNE
Connecticut Energy
$38.19
$37.75
$37.31
$37.63
$37.69
$37.19
$37.46
$37.63
$37.68
$37.88
5
IEI
Indiana Energy, Inc.
$20.94
$21.19
$21.44
$21.44
$21.19
$20.69
$21.19
$21.15
$21.20
$21.18
6
LG
Laclede Gas
$22.38
$22.00
$22.19
$22.63
$22.44
$21.88
$22.29
$22.25
$22.54
$22.85
7
NJR
New Jersey Resources
$39.63
$40.00
$39.38
$39.25
$39.94
$38.88
$39.36
$39.51
$39.52
$39.36
8
NWNG
Northwest Natural Gas
$27.38
$27.19
$26.75
$27.00
$26.75
$26.25
$26.69
$26.89
$26.73
$20.52
9
NUI
NUI Corp
$26.13
$26.63
$26.19
$25.81
$25.56
$25.88
$25.86
$26.03
$26.09
$26.33
10
PGL
Peoples Energy Corp
$36.75
$37.31
$37.06
$37.06
$37.31
$36.44
$36.97
$36.99
$36.91
$37.34
11
PNY
Piedmont Natural Gas
$33.06
$33.50
$33.38
$33.19
�33.31
$32.88
$33.19
$33.22
$33.34
$33.14
12
PVY
Providence Energy
$28.63
$28.00
$27.38
$27.00
�29.56
$29.25
$28.30
$28.30
$28.55
$28.75
13
WGL
Washington Gas Light
$27.31
$27.56
$27.44
$28.06
$28.13
$27.19
. $27.71
$27.62
$27.68
$27.34
14
Average
$28.55
$28.59
$28.67
$28.74
15
ATO
Atmos Energy Corp
$24.75
$26.38
$25.38
$25.38
$24.63
$24.25
$24.91
$25.13
$25.09
$25.18
� s m s mI mI mi mi swin imi J■m mimmi min *iimi iimi imi
Line it
;zICM
COX
1
AM
AGL Resources, inc.
2
CTO
CTO Resouroes, Ino.
3
CGC
Cascade Natural Gas
4
CNE
Gonnectic t Energy
5
IEI
Indiana Energy, Inc.
8
LG
Laclede Gas
7
NJR
New Jersey Resources
8
NWNG
Northwest Natural Gas
9
NUI
NUI Corp
10
PGL
Peoples Energy Corp
11
PNY
Piedmont Natural Gas
12
PVY
Providence Energy
13
WGL
Washhugton Gee LIgM
14
Average
15
ATO
Atmos Energy Corp
WEST TEXAS DISTRIBUTION SYSTEM
GROWTH RATE
MOODrS GAS UTILITIES
81STi?B�AI.
V,L 10 Yr V.L 10 Yr V.L 10 Yr V.L 5 Yr V.L 5 Yr V.L 5 Yr
EPA
RE3
BYES
Em
Lt2B
BYP.B
3.50%
3.00%
3.00%
5.00%
1.00%
2.50%
1.00%
3.00%
0.50%
-1.50%
2.50%
5.00%
0.50%
3.00%
-0.50%
-1.00%
2.00%
3.00%
1.50%
3.50%
4.W%
1.00%
4.50%
6.50%
5.00%
5.50%
9.50%
4.00%
4.50%
1.00%
2.00%
2.50%
5.50%
1.50%
3.50%
8.50%
3.00%
4.00%
9,50%
1.00%
2.50%
2.50%
1.50%
4.00%
8.50%
1.00%
5.00%
-2,00%
-5.00%
2.00%
3.50%
-10.00%
3.50%
2.50%
3.00%
3.50%
5.00%
1.50%
3.00%
6.00%
8.50%
6.50%
8.00%
0.00%
6.50%
-2.50%
4.50%
0."
7.00%
-1.50%
3.50%
4.00%
250%
3.50%
7,00%
2.00%
5.00%
4.50%
4.00%
4.50%
9.50%
4.00%
4.00%
�V.L
V.L
FORECAST
V.L
V.L
ZACKS
A>d=
ma
cm
BM AYERAGE
5Yt
3.00%
5.50%
2.00%
5.00%
4.17%
4.80%
1.75%
6.50%
-2.00%
4.00%
5.25%
4.00%
2.63%
I9.50%
0.50%
4.50%
4.83%
3.70%
3.00%
; 4.00%
3.50%
4.00%
3.83%
5.20%
5.83%
6.00%
4,00%
5.00%
5.00%
5.80%
2.67%
4.00%
2.00%
3.50%
3.17%
260%
4.42%
7.50%
3.00%
7.00%
5.83%
5.70%
3.75%
8.00%
2.00%
4.50%
4,17%
4.60%
3.00%
10.00%
3.50%
5.50%
8.33%
10.20%
3.08%
4.00%
2.00%
4.50%
3.50%
3.80%
6.58%
1 7.00%
5.00%
5.50%
5.83%
6.40%
3.67%
8.00%
5.00%
5.00%
8.00%
3.80%
4.00%
4.50%
250%
5.00%
4.00%
5.60%
5.08%
'11.50%
4.50%
8.50%
8.17%
7.30%
mm
4.66%
5.50%
3.45%
7.20%
6.05%
2-85%
8.00%
4.42%
9.70%
4.64%
8.10%
7.00%
4.71 %
8.12%
FORECAST
4.54%
4.92%
3.99%
5.41 %
5.82%
287%
5.84%
4.46%
8.74%
3.98%
6.11 %
5.00%
4,77%
f1♦ � � f1♦ � f1♦ � � f1♦ � � � � � filiii� fiilii� f1♦ filiii� fiilii�
WEST TEXAS DISTRIBUTION SYSTEM
NON CONSTANT GROWTH DCF
MOODY'S GAS UTILITIES
Div 4 +
IRR
L!!L
1
Compact
P-0
Div 1
Div 2
D?v3
Price
Return
1
ATG
AGL Resources, Inc.
($18.28)
$1.08
$1.12
$1.16
$23.61
11.00%
2
CTG
CTG Resources, Inc.
($36.21)
$1.08
$1.12
$1.16
$45.56
8.12%
3
CGC
Cascade Natural Gas
($17.59)
$0.97
$0.98
$0.99
$23.73
11.72%
4
CNE
Connecticut Energy
($37.63)
$1.37
$1.45
$1.52
$47.15
8.56%
5
IEI
Indiana Energy, Inc.
($21.15)
$0.97
$1.01
$1.04
$26.85
9.57%
6
LG
Laclede Gas
($22.25)
$1.36
$1.39
$1.42
$29.26
11.56%
7
NJR
New Jersey Resources
($39.51)
$1.72
$1.78
$1.84
$51.65
10.14%
8
NWNG
Northwest Natural Gas
($26.89)
$1.24
$1.28
$1.31
$34.96
10.17%
9
NUI
NUI Corp
($26.03)
$1.04
$1.08
$1.11
$36.94
12.03%
10
PGL
Peoples Energy Corp
($36.99)
$1.99
$2.03
$2.08
$48.01
10.68°%
11
PNY
Piedmont Natural Gas
($33.22)
$1.42
$1.48
$1.54
$43.12
9.92%
12
PVY
Providence Energy
($28.30)
$1.08
$1.20
$1.33
$41.07
12.69%
13
WGL
Washington Gas Light
($27.61)
$1.24
$1.28
$1.31
$35.68
9.92%
14
Average
($28.59)
10.47°%
15
ATO
Atmos Energy Corp
($25.13)
$1.15
$1.20
$1.25
$38.99
14.87%
WEST TEXAS DISTRIBUTION SYSTEM
NON CONSTANT GROWTH DCF
MOODY'S GAS UTILITIES
Current
Next 12 Months
VL Est 04
Annual
VL Est
VL Est
EST 04
Line #
GYM
Company
Price
Dividend
Dividend
Change PE
Ratio
EP_S_00
EPS 04
Price
1
ATG
AGL Resources, Inc.
$18.28
$1.08
$1.20
$0.04
13.10
$1.55
$1.90
$22.41
2
CTG
CTG Resources, Inc.
$36.21
$1.08
$1.20
$0.04
16.60
$2.00
$2.45
$44.36
3
CGC
Cascade Natural Gas
$17.59
$0.97
$1.00
$0.01
15.70
$1.20
$1.55
$22.73
4
CNE
Connecticut Energy
$37.63
$1.37
$1.60
$0.08
19.20
$1.90
$2.30
$45.55
5
IEI
Indiana Energy, Inc.
$21.15
$0.97
$1.08
$0.04
15.20
$1.60
$1.95
$25.77
6
LG
Laclede Gas
$22.25
$1.36
$1.45
$0.03
13.90
$1.80
$225
$27.81
7
NJR
New Jersey Resources
$39.51
$1.72
$1.90
$0.06
15.40
$270
$3.40
$49.75
8
NWNG
Northwest Natural Gas
$26.89
$1.24
$1.35
$0.04
16.30
$1.80
$2.25
$33.61
9
NUI
NUI Corp
$26.03
$1.04
$1.15
$0.04
13.70
$2.00
$2.75
$35.79
10
PGL
Peoples Energy Corp
$36.99
$1.99
$2.12
$0.04
15.10
$2.70
$3.35
$45.89
11
PNY
Piedmont Natural Gas
$33.22
$1.42
$1.60
$0.06
16.10
$2.20
$275
$41.52
12
PVY
Providence Energy
$28.30
$1.08
$1.45
$0.12
15.80
$1.50
$2.10
$39.53
13
WGL
Washington Gas Light
$27.61
$1.24
$1.35
$0.04
13.90
$1.85
$2.30
$34.33
14
Average
$28.59
15
ATO
Atmos Energy Corp
$25.13
$1.15
$1.30
$0.05
16.90
$2.00
$3.00
$37.69
a
a
`° to
Nz
N LA
LINE
�l4 DESCRIPTION
1 GENERAL SERVICE RATE
2 CUSTOMER CHARGE
3 1-4
4 6.10
5 11-m
6 OVER 60
7 TOTAL GENERAL SERVICE
8
9 GEN. SERVICE -STATE INSTITUTIONS
10 CUSTOMER CHARGE
11 1-4
12 5-10
13 11-60
14 OVER 60
15 TOTAL OS STATE INSTITUTIONS
16
17 SMALL INDUSTRIAL
18 CUSTOMER CHARGE
19 1S0
20 61-100
21 OVER 100
22 TOTAL SMALL INDUSTRIAL
23
24 LARGE A/CJ ELECTRIC GENERATING
25 MINIMUM BILL
26 ALL GAS
27 TOTAL LARGE A/C
28
29 AIR CONDITIONING OS RESIDENTIAL
30 CUSTOMER CHARGE
31 1-2
32 OVER 2
33 TOTAL
34
35 TOTAL ALL CLASSES
WEST TEXAS DISTRIBUTION SYSTEM
REVENUE ADJUSTMENT - CUSTOMER ADJUSTMENT
CURRENT
VOLUMES
TO BILLS
TOTAL
PRESENT
REMOVE
PRESENT
WITH
ELLS
METERED
a VOLUMES
VOLUMES
BALES.
GAS COST
REMME
GAS COS ADJUSTMENTS
2,650,385
18,996
$6.5000
$17,350,977
$17,350,977
$76,928
7,692,052
31,175
7,723,227
$3.9000
$2.8200
$8,341,085
$30,120,586
$2,734
4,956,796
1,090,581
6,047,377
t3.8600
$2.8200
$6,289,272
$23,342,874
$92,084
4,098,618
872,315
4,970,933
$3.8300
$2.8200
$5,020,642
$19,038,673
$71,530
3,510,422
747,129
4,257,551
$3.8100
$2.8200
$4,214.976
$16,221,271
$60,052
2,650,385
20,257,888
2,741,200 22.999,088
$41,216,952
$106,074,380
$303,327
1,556
0
I
$6.1800
$9,616
$9,616
$0
4,783
668
5,451
0.7100
$2.8200
$4,852
$20,224
$595
5,232
731
5,963
$3.6700
$2.8200
$5,068
$21,884
$621
18,319
2,559
20,878
$3.6400
$2.8200
$17,120
$75,996
$2,098
42,032
5,872
47,904
$3.6200
$2.8200
$38.323
$173,412
$4,697
1,556
70,366
9,830
80,196
$74,979
$301,132
$8,012
5,396
(116)
$28.50
$150,480
$150,480
($884)
190,004
(4,008)
185,996
$3.5500
$2.8200
$135,777
$660.287
$177
142,681
(4,008)
138,673
$3.4900
$2.8200
$92,911
$483,970
$162
1,266,968
180,024
1,446,992
$3.4600
$2.8200
$928,075
$5.006,593
($6,967)
5,396
1,599,653
172,009
1,771,662
$1.305,244
$6,301,330
($7,512)
36
42,479
0
42,479
3.46
$2.8200
$27.187
$146,977
$0
36
42,479
0
42,479
3.46
2.82
$27,187
$146,977
$0
58
$6.5000
$377
$377
$0
115
0
115
$3,9000
$2.8200
$124
$449
$0
1,056
0
1,056
$3.4600
$2.8200
$676
$3,654
$0
58
1,171
0
1,171
$1,177
$4,479
$0
2,657,431
21,971,557
2,923,039 24.894,596
$42,625,538
$112,828,299
�r �r� s s �� �■� aim �� f1f1f1f1fi
WEST TEXAS DISTRIBUTION SYSTEM
SERVICE CHARGE INFORMATION
TWELVE MONTHS ENDED APRIL 30, 1999
Meter Set
New Set Transfer
Turn On
Turn On New Customer
Turn On Transfer
Turn On Read Only
Read Only
Transfer Read Only
Turn On From Temporary Off
Turn On From Non -Pay
NSF Charge
Miscellaneous Service Charge
Current Charges
Business After
Hours Hours
23.50
35.25
23.50
35.25
19.00
28.50
19.00
28.50
10.50
15.75
10.50
15.75
29.50
39.00
29.50
39.00
25.00
13.00
osed Charaes
Business After
HouM Hours
40.00 60.00
30.00 45.00
10.00 15.00
40.00 60.00
25.00
10.00
WEST TEXAS DISTRIBUTION SYSTEM
CITIES PERCENTAGE OF DECREASE
(7,126,679)
Amount % of ProRata Share
Una # cu Requested Inergase of DecreLse
1
Abernathy
46,640
0.53%
2
Amherst
12,613
0.14%
3
Anton
20,008
0.23%
4
Big Spring
342,453
3.88%
5
Bovina
26,088
0.30%
6
Brownfield
159,612
1.81 %
7
Buffalo Spring Lake
4,492
0,05%
8
Canyon
182,251
Z.06%
9
Coahoma
14,791
0.17%
10
Crosbyton
35,888
0.41 %
11
Dimmitt
72,864
0.83%
12
Earth
18,556
0.21 %
13
Edmondson
1,9%
0.02%
14
Floydada
67,284
0.76%
15
Forsan
3,176
0.04%
16
Friona
60,750
0.69%
17
Hale Center
38,247
0.43%
18
Happy
11,642
0.13%
19
Hart
17,921
0.20%
20
Hereford
223,583
2.53%
21
Idalou
38,519
0.44%
22
Kress - -
12,930
0.15%
23
Lake Ransom
15,244
0.17%
24
Lamesa
178,758
2.03%
25
Levelland
209,292
2.37%
26
Littlefield
112,654
1.28%
27
Lockney
33,347
0.38%
28
Lorenzo
22,685
0.26%
_ 29
Los Ybanez
45
0.00%
30
Lubbock
2,794,111
31.65% -
31
Meadow
9,755
0.11 %
32
Midland
1,267,547
14.36%
33
Muleshoe
76,5W
0.87%
34
Nazareth
6,624
0.08%
35
New Deal
9,165
0.10%
36
New Home
4,446
0.05%
37
O'Donnell
16,148
0.21%
38
Odessa
1,154,530
13.08%
39
Ofton
34,708
0.39%
40
Opydyke
2,405
0.03%
41
Palisades
5,172
0.06%
42
Pampa
360.192
4.08%
43
Panhandle
46,595
0.53%
44
Petersburg
21,097
0.24%
45
Plainview
344,993
3.91%
46
Post
60,977
0.69%
47
Quitaque
10,798
0.12%
48
Ralis
38,519
0.44%
49
Ropesvllle
8,575
0.10%
50
Seagraves
33,347
0.38%
51
Seminole
89,787
1.02%
52
Shallowater
31,351
0.36%
53
Silverton
16,832
0.19%
54
Slaton
101,720
1.15%
55
Smyer
7,123
0.08%
56
Springlake
3,040
0.03%
57
Stanton
34.617
0.39%
58
Sudan
16,832
0.19%
59
Tahoka
44,916
0.51%
60
Tanglewood
15,350
0.17%
61
Timbercreek
4,265
0.05%
62
Tulia
89,515
1.01 %
63
Turkey
10,843
0.12%
64
Vega
18,647
0.21 %
65
Wellman
3,357
0.04%
65
Wilson
8.620
0.10%
67 Wolfforth
(37,655)
(10,183)
(16,153)
(276,479)
(21.064
(128,862)
(3,6M
(147,140)
(11,941)
(28,974)
(58,827)
(14,981)
(1,611)
(54,322)
(2,564)
(49.046)
(30,879)
(9,561)
(14,468)
(180,509)
(31,098)
(10.439)
(12,307)
(144,320)
(168,971)
(90,951)
(26.923)
(18,315)
(36)
(2,255,818)
(7,876)
(1,023,351)
(61,794)
(5.348)
(7.399)
(3,589)
(14,652)
(932,107)
(28,021)
(1,942)
(4,176)
(290.8W)
(37,618)
(17.033)
(278,529)
(49,230)
(8,718)
(31.098)
(6,923)
(26,923)
(72,489)
(25,311)
(13,589)
(82,123)
(5,751)
(2,454)
(27,948)
(13,689)
(36,263)
(12,393)
(3,443)
(72,270)
(8.754)
(1S.D55)
(2,710)
(6.9w)
W-329)