railroad commission of texas gas services division … · 11 relief from the commission; and...

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Direct Testimony of Richard D. HatchettWest Texas Gas, Inc.

RAILROAD COMMISSION OF TEXASGAS SERVICES DIVISION

WEST STATEMENT OF INTENT OF WESTTEXAS GAS, INC. TO INCREASE GASDISTRIBUTION RATES IN THEUNINCORPORATED AREAS OF TEXAS

))))

GUD NO. ________

DIRECT TESTIMONY OF RICHARD D. HATCHETT1

TABLE OF CONTENTS2

I. WITNESS IDENTITY AND QUALIFICATIONS.......................................................................... 23

II. PURPOSE OF TESTIMONY .................................................................................................. 34

III. BACKGROUND ................................................................................................................. 45

IV. NEED FOR RATE RELIEF .................................................................................................... 66

V. OVERVIEW OF WEST TEXAS GAS, INC. ............................................................................... 87

VI. RATE BASE....................................................................................................................... 98

VII. DEPRECIATION EXPENSE ............................................................................................... 139

VIII. RATE OF RETURN AND COST OF DEBT .......................................................................... 1410

IX. REVENUE AND EXPENSES ............................................................................................... 1511

X. LOST & UNACCOUNTED FOR GAS .................................................................................... 1912

XI. AFFILIATE TRANSACTIONS.............................................................................................. 1913

XII. CONCLUSION ................................................................................................................ 2414

15

EXHIBITS16Exhibit Description17

RDH-1 Texas System Map18

RDH-2 Midland Commercial Office Space Rental Survey19

20

Rate Study Schedules: F-4, G-12, G-13, H-3, J-1, J-2, N, and O.21

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I. WITNESS IDENTITY AND QUALIFICATIONS12

Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.3

A. My name is Richard D. Hatchett and my business address is 211 N. Colorado, Midland,4

Texas 79701.5

Q. BY WHOM ARE YOU EMPLOYED AND WHAT IS YOUR CURRENT TITLE6AND DUTIES?7

A. I am employed by West Texas Gas, Inc. (“WTG” or “the Company”) as an Executive8

Vice President. I am the corporate officer responsible for the utility pipeline operations of9

WTG and its subsidiaries with operations in Texas and Oklahoma. I also function as the10

Chief Financial Officer of WTG, its subsidiaries, and affiliates. I report directly to Mr. J.11

L. Davis, the President and sole stockholder of WTG.12

Q. PLEASE DESCRIBE YOUR EDUCATION AND PROFESSIONAL13EXPERIENCE.14

A. I graduated from Texas Tech University with a Bachelor of Business Administration15

degree in Accounting in 1979. In September 1983, I successfully completed the CPA16

exam and experience requirements to obtain my Certified Public Accounting license in17

the State of Texas. I have maintained my public accounting certification since 1983.18

From September 1976 until September 1979, while I was in school at Texas Tech and19

immediately following graduation, I was a member of the corporate accounting staff for20

Lubbock-based Furr’s Cafeterias, Inc. and one of its affiliates. In October 1979, I began21

my employment with WTG in Midland, as a staff accountant. During my career with22

WTG I have served as the company’s Accounting Manager, Assistant Controller, and23

Controller, before being named a Vice President24

During my 33 years in the industry, I have at various times, I have served on committees25

of the Texas Gas Association (TGA), and on the TGA’s Board of Directors. I have also26

served as a guest speaker or presenter at industry forums, city councils, and local27

professional associations.28

Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE RAILROAD29COMMISSION OF TEXAS OR OTHER AGENCIES?30

A. Yes. I testified before the Railroad Commission (“ the Commission”) in GUD No. 948831

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(Consolidated) when the Commission approved WTG’s current rates. I have also1

testified in other WTG cases before the Commission. I have appeared before the Federal2

Energy Regulatory Commission (“FERC”), the Oklahoma Corporation Commission, and3

numerous Texas cities in various rate matters and other regulatory proceedings.4

II. PURPOSE OF TESTIMONY56

Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?7

A. The purpose of my testimony is to provide an overview of WTG’s service territory and8

operations; introduce supporting witnesses who will be sponsoring various financial9

schedules and exhibits filed in this proceeding; explain the reasons WTG is seeking rate10

relief from the Commission; and explain WTG’s affiliate transactions.11

Q. PLEASE DESCRIBE THE COMPANY’S OTHER WITNESSES TESTIFYING IN12SUPPORT OF THE COMPANY’S APPLICATION.13

A. In addition to my direct testimony, the following witnesses are testifying on WTG’s14

behalf:15

Ms. Barbara Geffken, WTG Controller, will testify as to the authenticity of our16

books and records. She will attest to the financial records of WTG contained in17

various schedules of the Company’s rate filing, which were provided to Mr.18

Underwood for purposes of preparing the Rate Study used in this proceeding.19

Mr. Jack J. (JJ) King, WTG Gas Marketing Manager, will testify to the changes in20

WTG’s tariff schedules, the proposed elimination of the Farwell Gas Cost Zone,21

and provide information about customer gas usage as well as the lack of uniform22

customer growth. He will also explain the procedures used to give our customers23

public notice regarding the proposed increase in rates in this proceeding.24

Mr. James Barton (Bart) Bean, WTG Manager of Operations, will testify about25

WTG’s gas distribution field operations and expenses, construction and26

maintenance programs, management integrity programs, steel pipeline27

replacement programs and the Company’s lost and unaccounted for gas28

(“LUFG”) history.29

Mr. Carson Watt, WTG Gas Supply Manager, will testify about WTG’s gas30

supply protocol and the advantages of combining WTG's gas supply efforts with31

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affiliated entities.1

Mr. Dane A. Watson, Alliance Consulting Group, presents the depreciation study.2

Dr. Bruce H. Fairchild, Financial Concepts and Applications, Inc., presents the3

rate of return study for the Company.4

Mr. Rodney Pennington, Consultant, Pendulum Energy, presents billing5

determinants and peak day design calculations to establish customer charges.6

Mr. John Randolph (Randy) Underwood, Consultant, Pendulum Energy, presents7

the Company’s proposed cost of service and rate design, including cost of equity8

and debt, capital structure, and overall rate of return.9

Q. WHAT EXHIBITS ARE YOU SPONSORING?10

A. I am sponsoring the following exhibits and schedules: Exhibit RDH-1 Texas System Map11

and Exhibit RDH-2 Midland Commercial Office Rental Survey as well as Rate Study12

Schedules F-4, G-12, G-13, H-3, J-1, J-2, N, and O.13

III. BACKGROUND1415

Q. PLEASE DESCRIBE WTG?16

A. WTG is a Texas corporation organized in 1976 and solely owned by Mr. J.L. Davis of17

Midland, Texas. WTG is a Subchapter S entity and is not publically traded on any stock18

exchange. WTG operates facilities in Texas and Oklahoma. WTG is a natural gas utility19

in the States of Texas and Oklahoma that owns and operates gas distribution, gathering,20

and transmission pipeline systems. WTG has subsidiary and affiliate entities in six states21

involved in natural gas marketing, intrastate and interstate gas transmission facilities, oil22

and gas exploration and production, gas gathering and processing facilities, refined23

products distribution, retail gasoline/convenience stores, banking, and a fixed-base24

private aircraft operation. WTG’s gas distribution facilities in Texas are located in sixty-25

eight Texas counties and currently serve more than 22,000 domestic and non-domestic26

jurisdictional and irrigation and agricultural non-jurisdictional customers. A Texas27

System Map is attached as Exhibit RDH-1.28

Q. PLEASE EXPLAIN THE NATURE AND EXTENT OF WEST TEXAS GAS,29INC.’S UTILITY OPERATIONS IN TEXAS.30

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A. WTG’s utility operations began in 1976 with the acquisition of three rural natural gas1

systems primarily serving a few hundred irrigation and residential customers along a2

Northern Natural Gas transmission mainline running from the Permian Basin to the3

northern Texas Panhandle. WTG has grown its local distribution company (“LDC”)4

operations through numerous acquisitions and pipeline construction projects. Today,5

WTG operates nearly 5,000 miles of distribution mains serving approximately 27,0006

residential, commercial, irrigation and agricultural customers in Texas and Oklahoma.7

Q. WHERE IS WTG’S PRINCIPAL OFFICE LOCATED?8

A. WTG’s principal office is located at 211 North Colorado, Midland, Texas. All corporate,9

legal, and accounting records of WTG are maintained at this principal office, or located10

in nearby storage facilities. WTG also maintains a regional field operations office in11

Amarillo and twelve district field offices serving WTG’s Texas service area.12

Q. DOES WTG OWN ANY TRANSMISSION LINES IN TEXAS?13

A. Yes. WTG operates 664.57 miles of transmission pipeline in Texas that are used to14

supply downstream WTG distribution facilities and a few end-use or resale customers.15

WTG’s affiliates WTG Gas Transmission Company (“WTGGT”) and Western Gas16

Interstate Company (“WGI”), are regulated by the Railroad Commission or FERC, and17

operate 511.57 miles and 82.59 miles, respectively, of transmission pipelines in Texas.18

Q. ARE WTG’S AFFILIATE OPERATED TRANSMISSION PIPELINES SHOWN19ON THE TEXAS SYSTEM MAP?20

A. Yes. WTGGT and WGI intrastate and interstate transmission pipeline systems are shown21

on Exhibit RDH-1.22

Q. DOES WTGGT OR WGI TRANSPORT ANY GAS TO WTG’S DISTRIBUTION23SYSTEMS?24

A. Yes, there are a few WTG distribution systems that are served upstream by WTGGT or25

WGI. In these instances, both WTGGT and WGI charge only their FERC or26

Commission-approved tariff rates, which WTG recognizes as an allowed gas cost27

element and includes these transport charges in WTG’s monthly Gas Cost Adjustment28

clause.29

Q. WHO REGULATES THE RATES, OPERATIONS, AND ACCOUNTING30PRACTICES OF WTG?31

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A. WTG’s gas distribution rates are regulated by the cities and the Railroad Commission of1

Texas. Pipeline safety regulations issued and enforced by the Railroad Commission and2

the US Department of Transportation regulate WTG's pipeline operations. The Railroad3

Commission has adopted FERC’s Uniform System of Accounts for accounting reporting4

purposes and WTG complies with this reporting system.5

IV. NEED FOR RATE RELIEF67

Q. PLEASE SUMMARIZE WHY THE COMPANY HAS MADE THIS RATE CASE8FILING.9

A. There are a number of reasons why WTG has filed this rate case.10

WTG has not received an increase in rates since December 2004 and operating11

costs have increased over the years.12

WTG has invested significant capital in major infrastructure extensions and13

improvements, and initiated a steel service line replacement program without any14

corresponding return on these investments.15

WTG has made significant personnel additions since December 2004 in an effort16

to comply with new or expanded regulatory requirements relating to operator17

qualification, distribution integrity management, public awareness, and third party18

pipeline damage reporting requirements.19

WTG’s annual jurisdictional customer throughput volumes in many locations20

continue to decline due to the decreasing population base in most of WTG’s21

service areas, improved energy-efficient appliances, and customer conservation22

efforts.23

Q. WHAT STEPS DOES WTG TAKE TO CONTROL ITS OPERATING COSTS?24

A. WTG’s single largest cost of service item is personnel costs. The Company’s employee25

count, employee pay rates, and related personnel benefits compare very favorably to26

other Texas distribution utilities. As a privately-held utility with only one shareholder,27

WTG is also very cost-conscious. WTG also avoids some costs incurred by publicly28

traded utilities, such as SEC related compliance and reporting expenses as well as29

stockholder relations expenses.30

Q. PLEASE DESCRIBE THE FILINGS MADE BY WTG.31

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A. WTG filed its Statements of Intent with its twenty-seven municipalities on September 271

& 28, 2012, using a test year ending June 30, 2012. Fifteen of these municipalities2

accepted a settlement offer made by WTG equal to approximately 50% of the requested3

increase. The remaining twelve municipalities suspended the rates for the allowed 90-4

day period. WTG expects that these municipalities will deny WTG’s request.5

Q. ARE THERE ANY CITIES THAT HAVE SURRENDERED THEIR ORIGINAL6JURISDICTION TO THE COMMISSION?7

A. No.8

Q. PLEASE DESCRIBE WTG’S PROPOSED RATE INCREASE.9

A. WTG proposed a $1,166,778.52 revenue increase for its unincorporated areas with the10

intent of continuing to use generally applicable, statewide rates in Texas, subject to final11

settlement with all affected parties. The use of statewide rates was initially approved in12

WTG’s last rate proceeding before the Commission in GUD Nos. 9488 (Consolidated).13

The continuation of a uniform statewide rate structure for WTG customers, along with14

the recognition of the differences in the cost of gas in the various regions that WTG15

serves, will help ensure that all customers pay rates that closely reflect WTG’s actual cost16

of service.17

Q. WHAT ARE THE KEY CHANGES IN EXPENSES SINCE THE LAST RATE18CASE?19

A. The details of expenses incurred are contained in the Company’s filing, and are being20

addressed by Mr. Underwood. However, I will highlight several examples in the larger21

categories of expenses. Significant expenses for WTG are payroll, and payroll-related22

costs, regulatory compliance costs, and insurance expense. All of these categories have23

seen significant increases since rates were last changed in 2004. Some are directly24

related to actions that the Company has taken to comply with the Commission’s pipeline25

safety and integrity management initiatives, as well as other factors over which the26

Company has no control. Like many businesses, WTG is experiencing significant27

increases in employee health care costs and other expenses. These increases, coupled28

with a static or declining customer base, have adversely impacted the Company’s ability29

to earn its allowed rate of return on its jurisdictional service. Absent rate relief, the30

Company will suffer in its ability to earn a return sufficient to cover the expenses31

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associated with its jurisdictional operations, including compliance with regulatory safety1

requirements imposed by regulation, and earn a fair return on utility investment.2

V. OVERVIEW OF WEST TEXAS GAS, INC.34

Q. HOW IS WTG DIFFERENT FROM MOST GAS UTILITY COMPANIES?5

A. WTG is smaller, and therefore quite different, from the larger natural gas utility6

companies.7

A significant portion of WTG’s load profile is represented by non-jurisdictional8

agricultural markets. These markets are largely composed of interruptible short-term9

service agreements where customers pay no demand charges and have no minimum10

throughput requirements.11

WTG does not serve any large metropolitan areas as WTG’s jurisdictional customers12

are generally located in small municipalities and rural environs. The Company has13

nearly 5,000 miles of distribution pipelines situated in sixty-eight Texas counties.14

WTG’s average miles of pipeline per customer meter and cost of service per customer15

are likely higher than a gas utility serving large metropolitan areas, which are much16

more densely populated.17

WTG is a privately held entity with one stockholder that cannot take advantage of the18

public debt markets that are available to publicly held utilities. This requires WTG to19

maintain a lower debt leverage by limiting dividend distributions and using profits for20

capital investment and debt service.21

Due to our limited staff, WTG's management and supervisory personnel are22

responsible for a wide range of duties. Risk management, legal, safety training, fleet23

management, engineering and drafting, rate regulation, and other functions are shared24

by a limited number of staff members, or outside consultants must be retained.25

Finally, WTG is a Subchapter S entity whose federal income tax liability is passed26

through to its stockholder to avoid double taxation on company income and dividend27

distributions.28

Q. WHY DOES WTG USE GAAP ACCOUNTING IN THE ORDINARY COURSE29OF BUSINESS?30

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A. Due to bank loan covenants, WTG, its subsidiaries, and affiliates are required to maintain1

their books and records in accordance with generally accepted accounting principles2

(GAAP). Therefore, WTG, its subsidiaries and affiliates utilize a common accounting3

software system, chart of accounts, and financial reporting software to satisfy the GAAP4

requirement. WTG utilizes a cross reference to its chart of accounts for FERC5

accounting and reporting purposes. WTG files all regulatory reports and annual filings,6

on a FERC accounting basis. The schedules contained in this rate filing all use the FERC7

code of accounts.8

Q. WHAT IS THE IMPACT OF THE PROPOSED RATES ON THE DOMESTIC9AND NON-DOMESTIC CUSTOMERS IN TEXAS?10

A. Inclusive of the $3.43 per Mcf average cost of gas during the test period, an average11

domestic customer using 6 Mcf in a billing period will experience an increase of $22.94,12

a 52.02% increase. Using the same average cost of gas, a non-domestic customer using13

30 Mcf in a billing period will experience an increase of $11.30, a 6.17% increase.14

VI. RATE BASE1516

Q. PLEASE DESCRIBE WTG’S PROPERTY AND PLANT THAT IS INCLUDED IN17THE COMPANY’S TEST YEAR RATE BASE.18

A. WTG’s requested rate base, the amount on which a utility is entitled to earn a fair rate of19

return, is developed in Schedule B-1. As shown in this Schedule B-1, rate base consists20

of WTG’s investment in property, plant and equipment, plus materials and supplies, less21

contributions in aid of construction provided by WTG customers, and deferred income22

taxes. WTG’s investment includes assets exclusively serving customers in Texas and an23

allocated portion of assets serving customers in the Texas and Oklahoma service areas.24

Q. PLEASE EXPLAIN WTG’S ORIGINAL COST, ACCUMULATED25DEPRECIATION AND NET BOOK COST CALCULATIONS TO DEVELOP26THE COMPANY’S NET COST USED FOR PROPERTY, PLANT AND27EQUIPMENT.28

A. The original cost and accumulated depreciation of WTG’s property, plant, and equipment29

are reflected on Lines 1 and 3 of Schedule B, with detail of this property by FERC30

account being contained in Schedules C and D, respectively. Schedules C and D reflect31

the test year-end balances for WTG, and adjustments made by Mr. Randy Underwood.32

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Q. HAS THE COMPANY MADE ANY ACQUISITIONS SINCE ITS LAST RATE1CASE IN 2004?2

A. Yes. In 2007, WTG acquired North Texas Gas Company of Dalhart, Texas and in 20103

the City of Devine’s gas distribution system in Medina County, Texas.4

Q. PLEASE DESCRIBE THE NORTH TEXAS GAS COMPANY ACQUISITION.5

A. Effective October 1, 2007, WTG acquired the assets of North Texas Gas Company in6

Hartley, Moore, Sherman, and Dallam Counties, Texas. These North Texas Gas7

Company assets consisted of more than 650 miles of distribution pipeline systems serving8

approximately 300 jurisdictional domestic and non-domestic customers, along with9

numerous non-jurisdictional irrigation customers.10

Q. PLEASE DESCRIBE THE CITY OF DEVINE ACQUISTION.11

A. Effective September 1, 2010, WTG acquired the City of Devine, Texas gas distribution12

system. This gas distribution system is situated mainly in the incorporated limits of the13

City of Devine and serves almost 900 jurisdictional domestic and non-domestic14

customers. This system is composed of about 6 miles of steel mainline and more than 3015

miles of poly mainline and service laterals.16

Q. HOW IS WTG TREATING DISTRIBUTION INTEGRITY MANAGEMENT17PROGRAM (“DIMP”) COSTS IN THIS CASE?18

A. Capital costs related to WTG’s DIMP are included in Construction Work in Progress19

(Schedule C-3) and are not included as a part of WTG’s rate base. Schedule C-3 reflects20

a little less than $1Million in DIMP related 2012 capital replacement costs. WTG21

anticipates spending significantly more than $1Million annually in DIMP related capital22

replacement costs for the foreseeable future and may consider a separate mechanism for23

collection of these costs at a later date.24

Q. PLEASE DESCRIBE THE MATERIALS AND SUPPLIES SHOWN ON25SCHEDULE E-3.26

A. WTG maintains pipe and other inventories at some of its larger field offices, including:27

steel and poly pipe, regulators, meters, steel and poly fittings and valves, risers, anodes,28

marker signage, replacement parts for valves, regulators, and meters. WTG has included29

$660,304 as shown on Schedule E-3 for materials and supplies inventory. The30

calculations of the amount sought are sponsored by consulting witness Mr. Randy31

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Underwood.1

Q. ARE ANY MATERIALS AND SUPPLIES RECOVERED THROUGH WTG’S2GAS COST ADJUSTMENT CLAUSE?3

A. No.4

Q. PLEASE EXPLAIN THE TREATMENT OF CUSTOMER DEPOSITS SHOWN5ON SCHEDULE E-4.6

A. The balance of Customer Deposits reflected on Schedule E-4 are not included as a7

reduction of WTG’s rate base, because WTG pays interest on these customer deposits at8

the interest rate stipulated by the Public Utility Commission of Texas and adopted by the9

Railroad Commission.10

Q. WITH RESPECT TO SCHEDULE E-4, PLEASE DESCRIBE WHY WTG11REQUIRES SOME CUSTOMERS TO MAKE A CONTRIBUTION IN AID OF12CONSTRUCTION.13

A. Typically, WTG requires customer contributions in aid of construction for projects that14

do not qualify under WTG’s extension policy because it fails to meet minimum15

investment criteria (e.g., rate of return or capital investment thresholds) based on16

published tariff rates or standard non-jurisdictional rates. These contributions are17

amortized over the life of the related capital investment, not to exceed 20 years, and used18

to offset depreciation expense on WTG’s books.19

Q. HOW IS WTG’S INVESTMENT IN RATE BASE VALUED?20

A. For purposes of this case, the original cost of property, plant, and equipment at the time21

of dedication to public service is used as the value of invested capital. However, WTG22

explicitly reserves the right to request a return on the adjusted value of invested capital as23

provided for in Section 104.053 of Title 3 of the Texas Utilities Code in future cases.24

Q. PLEASE DESCRIBE THE METER COST ANALYSIS (SCHEDULE N) THAT25WAS MADE A PART OF THE RATE MODEL. EXPLAIN WHERE THE26REPLACEMENT COST ESTIMATES CAME FROM AND WHY ORIGINAL27COST IS UNAVAILABLE.28

A. The distribution assets of WTG are composed of more than fifteen different acquisitions29

made by WTG over the past 30+ years. Most of these acquisitions were previously30

owned by small municipalities or small, family-owned businesses that did not maintain31

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their original cost historical data. As a result, WTG cannot provide an accurate original1

cost analysis of its distribution plant.2

For this Meter Replacement Cost Analysis, WTG used conservative replacement cost3

estimates for the four primary types of customer meter settings. These estimates include4

the cost of the service rider and meter run including any regulation, valves, and fittings.5

Residential – these are low-volume positive displacement meters, typically6

represented by AL-175 or Rockwell 200 type meters.7

Small Commercial – these are higher volume positive displacement meters,8

typically represented by AL-800 or Rockwell 750 type meters.9

Irrigation – the same positive displacement meter type used in Small Commercial10

applications, or for larger irrigation customers, a Roots rotary type meter is11

installed.12

Large Commercial – these meter sets are usually connected with high volume13

turbine type meters, or an orifice meter run tied to an electrical measurement unit14

(Total Flow).15

Q. PLEASE DESCRIBE THE SCHEDULE O PIPELINE COST ANALYSIS.16

A. For this Pipeline Replacement Cost Analysis, WTG used very conservative estimates for17

pipeline materials and construction. Pipeline footages for this analysis come directly off18

of WTG’s Form 7100 filing and DIMP assessment plan. In addition to the assumptions19

listed on the workpaper, the estimated price-per-foot used in the analysis includes the cost20

of materials (based on SDR 11 poly pipe or steel pipe with 0.188 wall thickness),21

installation costs based on recent WTG experience in rural Class I locations, and minimal22

right of way costs. WTG believes this is a very conservative estimate compared to23

current replacement costs actually being experienced by Texas utilities.24

Q. HAS WTG INCLUDED AN ALLOWANCE FOR CASH WORKING CAPITAL25AS A COMPONENT OF ITS RATE BASE?26

A. No. WTG has not performed a lead lag study to reduce rate case expenses, WTG has not27

included in the company’s rate base any provision for cash working capital.28

Q. HAS THE COMPANY’S RATE BASE BEEN ADJUSTED FOR NON-INVESTOR29SUPPLIED CAPITAL?30

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A. Yes. As reflected on Schedule B, WTG’s rate base has been adjusted for Contributions1

in Aid of Construction and Accumulated Deferred Income Taxes. The calculation of the2

adjustments for non-investor supplied capital is sponsored by consulting witness John3

Underwood.4

Q. IS WTG’S ENTIRE RATE BASE USED AND USEFUL FOR SERVING ITS5CUSTOMERS?6

A. Assets that are not used and useful and have been removed from the rate base7

calculations. In addition to transmission assets and those assets identified with WTG’s8

Oklahoma operations, amounts related to acquisition premiums and out-of-service assets9

have also been removed from WTG’s rate base. Schedules C-1.1, C-1.2 and D-1.110

provide the detail of these adjustments to the rate base.11

Q. IS THERE ANY PLANT, PROPERTY OR EQUIPMENT IN THE RATE BASE12THAT COULD BE CLASSIFIED AS PLANT HELD FOR FUTURE USE OR13CONSTRUCTION WORK IN PROGRESS?14

A. No. There is no plant held for future use or construction work in progress included in15

WTG’s rate base. Out-of-Service plant, which might be considered gas plant for future16

use, has also been removed from the rate base. All of WTG’s property plant and17

equipment included in the rate base is currently dedicated to serving WTG customers.18

VII. DEPRECIATION EXPENSE1920

Q. PLEASE DESCRIBE WTG’S DEPRECIATION EXPENSE.21

A. In WTG’s 2004 rate case, the Cities and WTG negotiated depreciation rates that were22

approved by the Commission. In an effort to avoid preparing an expensive depreciation23

study, the Company used the depreciation rates approved in 2004 when it filed its 201124

rate case. The Cities and the Commission Staff opposed using the 2004 depreciation rates25

and took a position that without a new depreciation study, they would oppose WTG26

recovering any depreciation expense because the company could not prove its case. The27

risk to continue without a depreciation study was too great, so WTG non-suited its 201128

rate case. The Company retained Mr. Dane Watson of Alliance Consulting Services in29

Plano, Texas to conduct a depreciation study. His studies, conclusions, and30

recommendations are included in this rate case.31

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Q. AS A RESULT OF THE NEW DEPRECIATION STUDY, HOW MUCH IS WTG1SEEKING TO RECOVER IN DEPRECIATION EXPENSE?2

A. WTG is seeking to recover $1,085,355 in depreciation expense from its jurisdictional3

customers as shown in Schedule A. Schedules D-2 and D-3 provide additional4

information to support this request.5

VIII. RATE OF RETURN AND COST OF DEBT67

Q. WHAT RATE OF RETURN WAS USED IN CALCULATING WTG’S REVENUE8REQUIRMENT?9

A. As reflected in Schedule F-1, WTG utilized a rate of return of 9.03% in calculating its10

revenue requirement. Please see the direct testimony of Dr. Bruce H. Fairchild11

supporting WTG’s proposed cost of capital and overall return.12

Q. WHAT IS WTG’S ACTUAL COST OF DEBT?13

A. The weighted average cost of debt calculated on Schedule F-4 is 1.55%. However, the14

cost of long-term debt claimed in this filing is 5.32% and is supported by Dr. Fairchild.15

Q. DOES WTG’S CAPITAL STRUCTURE INCLUDE ANY SHORT-TERM DEBT16IN WTG’S CAPITAL STRUCTURE?17

A. No. The inclusion of short-term debt in the capital structure is only appropriate when a18

company historically relies on a short-term debt as a permanent form of capital. WTG19

does not rely on short-term debt as a permanent form of capital, and therefore, no short-20

term debt is included.21

Q. WHAT BANKING INSTITUTIONS HAVE LOANED MONEY TO WTG?22

A. WTG and its affiliates are parties to a credit facility provided by a syndicate of national23

and regional banks lead by Wells Fargo Bank. Other banks invested in this syndicate24

include the Bank of Oklahoma and Amarillo National Bank. WTG and its affiliates are25

jointly and severally liable for all outstanding amounts owed under this credit facility.26

Q. DOES ANY DEBT COME FROM YOUR AFFILIATE WEST TEXAS27NATIONAL BANK?28

A. No.29

Q. HAS WTG RECENTLY RENEGOTIATED ITS CREDIT FACILITY?30

A. Yes. Effective February 28, 2012, WTG renegotiated its credit facility with the syndicate31

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of banks as WTG’s previous loan agreement was scheduled to mature on March 9, 2012.1

Q. DID WTG’S COST UNDER THE RENEGOTIATED CREDIT FACILITY2CHANGE?3

A. Yes. The interest rate pricing of WTG’s new credit facility is set at 1.75% over the 90-4

day LIBOR rate. The previous rate under WTG’s old credit facility was 0.75% over the5

90-day LIBOR rate.6

Q. DOES WTG HAVE ANY OUTSTANDING DEBT?7

A. Yes. WTG has an intercompany note with its affiliate, WTG Gas Processing, L.P., in the8

face amount of $12,500,000.00. This note was originally dated March 19, 2008, and was9

recently renewed on November 5, 2012. The maturity date of this note is February 28,10

2017 and is priced at the same rate of interest as WTG’s credit facility with the Wells11

Fargo syndicate.12

IX. REVENUE AND EXPENSES1314

Q. IN SCHEDULE A-1.1, MR. UNDERWOOD HAS REMOVED AN AMOUNT OF15$3,000 ASSOCIATED WITH AN EXPIRED CONTRACT ON LINE 1. PLEASE16DESCRIBE THE CONTRACT IN QUESTION AND EXPLAIN WHY IT WAS17NOT REPLACED.18

A. WTG field personnel out of Groom, Texas had previously monitored a compressor19

station for Aztec Gas, Inc. (an affiliate of WTG) in exchange for a monthly fee of $50020

per month. This service arrangement was cancelled at December 31, 2011. Mr.21

Underwood’s adjustment removed the $3,000 of revenue received from this arrangement22

between July 1, 2011 and December 31, 2011.23

Q. SCHEDULE A-2.3 SHOWS THE LABOR ADJUSTMENT. THE DETAILS FOR24THIS ADJUSTMENT ARE CONTAINED IN A SET OF CONFIDENTIAL25WORKPAPERS DESIGNATED LABOR ANNUALIZATION. PLEASE26DESCRIBE THE PROCEDURES USED TO DEVELOP THIS WORKPAPER.27

A. This workpaper represents the adjustment necessary to annualize an employee’s wages28

when there was a change in the employee’s rate of pay during the test period (July 1,29

2011 through June 30, 2012). In developing this workpaper, we identified the effective30

date of any rate change and the amount of the wage increase for each affected employee.31

This amount of change was then multiplied by the number of days the employee was paid32

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at their previous rate to calculate the adjustment necessary to reflect a full 12 month1

period of wages paid based on the employee’s current, higher, rate of pay.2

Q. WHY ARE THERE NO ADJUSTMENTS FOR SALARY DECREASES OR3TERMINATIONS?4

A. There were no salary decreases or net terminations (staff reductions) during the test5

period. Our labor adjustment for the test period makes the following assumptions: the6

pay rate of any replacement employee hired during the test period was equal to or greater7

than the predecessor employee, and at no time during the test period was there a vacant8

position (i.e., a replacement employee started immediately upon the termination of the9

predecessor employee).10

Q. ARE THERE ANY MOVING EXPENSES OR START-UP BONUSES INCLUDED11IN WTG’S LABOR COSTS?12

A. Yes. During the test period there were two charges for moving expenses, $500 charged13

to FERC account 880.0 and $1,390 charged to FERC account 926.0. There were no start-14

up bonuses paid by WTG during the test period.15

Q. WHAT STEPS DOES THE COMPANY TAKE TO ENSURE THAT ITS16COMPENSATION IS NOT EXCESSIVE?17

A. For administrative and accounting personnel in WTG’s home office, we utilize the18

Robert Half “Salary Guide” for pay rate guidance, in addition to informal surveys with19

other employers in the Midland area. Regarding field pay scales, WTG believes its salary20

scale is generally average, but below the level of some larger companies with identical21

positions in our service area. During this test period WTG has lost employees due to22

higher wage opportunities offered by Enbridge, DCP Field Services, Oneok, Atmos,23

Eagle Rock, and Centerpoint Energy.24

Q. WITH RESPECT TO SCHEDULE G-1, COLUMN B, WHAT AMOUNTS ARE25ASSOCIATED WITH BONUSES?26

A. A total of $ CONFIDENTIAL in employee bonuses is included in column B of27

Schedule G-1.28

Q. WHAT WAS THE PURPOSE OF THESE BONUSES?29

A. There were two types of bonuses paid during the test period. There was one employee30

that was paid a service award bonus for 25-years of service with WTG. All other31

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bonuses were discretionary year-end bonuses made in December 2011 to one executive1

officer and five managers of WTG for their years of service to WTG and specifically2

their contributions during the 2011 calendar year.3

Q. COULD YOU RETAIN OR REPLACE YOUR CURRENT STAFF WITH4COMPARABLE EMPLOYEES WITHOUT THESE BONUSES?5

A. In my opinion, the bonuses paid to the one service award recipient and the five WTG6

department managers are necessary to properly compensate these employees (ranging7

from 12 to 34 years of service with WTG) with a competitive salary package when8

compared to similar positions with other companies in the Midland employment market.9

I believe that employee retention is an important factor in controlling labor costs.10

Retention of long-term employees preserves institutional memory and experience, which11

enhances pipeline safety and reliability.12

Q. PLEASE DESCRIBE THE ADVERTISING EXPENSES SHOWN ON SCHEDULE13G-5.14

A. The majority of advertising expenses charged to FERC Account 913 are costs incurred15

associated with advertising in telephone yellow pages. Account 913 also covers the cost16

of newspaper employment ads as well as sponsorships paid to local schools and other17

community organizations.18

Q. PLEASE DESCRIBE THE COMPANY’S POLICY REGARDING DONATIONS19AND CONTRIBUTIONS (SCHEDULE G-6).20

A. WTG does not have a written policy with regard to donations, but our general guidelines21

are to limit corporate donations to small denominations to charities that provide a direct22

community service within the area or municipality served by WTG.23

Q. PLEASE EXPLAIN WHY IT IS APPROPRIATE FOR RATE PAYERS TO PAY24THE FINES IDENTIFIED ON SCHEDULE G-8.25

A. Most of the Penalties and Fines reflected on Schedule G-8 were paid under protest either26

to the US Department of Transportation, related to the Integrity Management audit or the27

Railroad Commission, related to Underground Pipeline Damage. These penalties were28

incurred in the normal course of business. Most of the alleged violations were disputed29

by WTG. WTG’s dispute was eventually denied by the regulator. The penalties were not30

the result of WTG’s negligence. WTG decided to pay these penalties as the cost to31

appeal the regulator’s decision exceeded the cost of the penalty.32

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Q. WHAT IS WTG’S POLICY REGARDING MEALS AND ENTERTAINMENT?1

A. WTG does not have a written policy with regard to meals and entertainment expense, but2

our general guidelines are that reimbursable expenses should be incurred while away3

from the employee’s home in the performance of the his or her assigned duties or4

incurred while fulfilling a company responsibility or company function. Reimbursable5

expenses must be supported with a receipt or invoice that indicates the goods or services6

provided and the individuals that received those goods or services. Exceptions are made7

to this guideline if the amount being reimbursed is considered immaterial, generally $258

or less. Acceptable entertainment is generally considered to be a meal with a customer,9

vendor, business associate, or subordinate employee.10

Q. WHAT IS THE COMPANY’S TRAVEL POLICY?11

A. Because most of WTG's assets are situated in rural or remote areas of the state,12

automobile travel is the predominate method of travel for WTG management and13

supervisory personnel. In some instances, when two or more management personnel can14

coordinate a trip, a chartered flight may be arranged with Basin Aviation (a WTG15

affiliate), to minimize lost time for management personnel and related overnight16

expenses.17

Q. WHAT IS THE COMPANY’S LODGING POLICY?18

A. WTG does not have a written policy with regard to lodging, but our general guidelines19

allow employees to stay overnight in hotels that are tailored for business travel. The cost20

for this type lodging runs from $100 - $300 per night, depending on the area of the state.21

WTG also has contracted a discounted corporate rate at the Overton Hotel in Lubbock,22

and with Holiday Inn Express in Amarillo.23

Q. PLEASE DESCRIBE SCHEDULE G-11.24

A. Schedule G-11 reflects legal fees paid to various attorneys during the test period. Those25

charges identified as Other Legal Matters pertain to fees incurred in the renegotiation and26

renewal of WTG’s credit facility with the Wells Fargo syndicate group, as well as fees27

paid for bad account collection, miscellaneous regulatory matters, and general corporate28

business.29

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X. LOST & UNACCOUNTED FOR GAS12


A. Schedule G-12 reflects the LUFG volumes experienced by WTG for the twelve-month4

periods ending June 30, 2009 through June 30, 2012. Any LUFG volumes from WTG5

transmission systems have been eliminated in this Schedule G-12 in order to reflect only6

the actual LUFG on WTG’s Texas distribution systems. LUFG is discussed in the direct7

testimony of Mr. Bart Bean.8

XI. AFFILIATE TRANSACTIONS910

Q. PLEASE DESCRIBE THE STATUTORY STANDARD GOVERNING THE11RECOVERY OF AFFILIATE EXPENSES.12

A. Section 104.055 of the Gas Utility Regulatory Act (“GURA”) establishes that affiliate13

expenses must be reasonable and necessary and that the price charged to the gas utility14

not be higher than the price charged by the affiliate to its other affiliates, or to a non-15

affiliated person for the same items or class of items.16

Q. IN YOUR OPINION, DO WEST TEXAS GAS, INC.’S AFFILIATE EXPENSES17MEET THE AFFILIATE STANDARD YOU JUST DESCRIBED?18

A. Yes.19

Q. ARE THE EXPENSE AMOUNTS WTG PAID TO AFFILIATES DURING THE20TEST YEAR REASONABLE AND NECESSARY?21

A. Yes. WTG does not pay any affiliate charges that exceed normal charges from arms-22

length third party transactions.23

Q. ARE THE PRICES WTG PAID TO AFFILIATES HIGHER THAN PRICES24CHARGED BY THE SUPPLYING AFFILIATE TO OTHER AFFILIATES OR25NON-AFFILIATES FOR THE SAME ITEM OR CLASS OF ITEM?26

A. No. The amounts paid by WTG to affiliates are equal to, or less than, similar charges27

paid by non-affiliate entities.28

Q. HAVE AFFILIATE COSTS BEEN INCLUDED IN WEST TEXAS GAS, INC.’S29OPERATING EXPENSES?30

A. Yes, affiliate expenses are as shown on Schedule J-3 of the Rate Study.31

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Q. PLEASE DESCRIBE SCHEDULE J-2 AND THE NATURE OF WTG, ITS1AFFILIATES, PARENT, AND SUBSIDIARIES.2

A. Schedule J-2 is an organization chart depicting the wholly-owned businesses owned by3

Mr. J.L. Davis. WTG has ten subsidiaries, and some of those subsidiary entities have4

subsidiaries of their own. All of WTG’s subsidiaries, except for Basin Aviation, are5

energy-related businesses (e.g., exploration, production, gathering, processing,6

transmission, gas marketing, and refined fuel retailer.) Basin Aviation is a fixed-base7

operator that provides fuel, hangar space, maintenance, flying lessons, and charter service8

to the private aircraft market in the Midland, Texas area.9

The remaining affiliate entities owned by J.L. Davis and shown in this organization chart10

are also in energy-related fields as the WTG subsidiaries, except for Whiskey Tango,11

LLC and First West Texas Bancshares, Inc. Whiskey Tango owns a fleet of private12

aircraft that lease their fleet to Basin Aviation for private charter purposes. First West13

Texas Bancshares is the majority shareholder of West Texas National Bank, a retail and14

commercial banking network with multiple branches in the Permian Basin and Trans-15

Pecos areas.16

Q. FOR EACH AFFILIATE, PLEASE DESCRIBE THE NATURE OF ITS17BUSINESS WITH WTG DURING THE TEST YEAR.18

A. Test year charges paid to affiliates are as follows:19

Line 1 - Aztec Gas, Inc. (“Aztec”) provides some wellhead gas supply to WTG’s20

Shamrock distribution system. Aztec gathers, dehydrates, and compresses21

this gas supply before delivery into WTG’s distribution system. WTG pays22

Aztec a lower price for this supply than what is available to WTG off the23

Enbridge transmission line that also serves the Shamrock system.24

Line 2 - WTG Exploration, Inc. (“WTGX”) also provides some wellhead gas supply25

to WTG’s Shamrock distribution system. WTGX gathers and dehydrates26

this gas supply before delivery into WTG’s distribution system. WTG pays27

WTGX a lower price for this supply than what is available to WTG off the28

Enbridge transmission line that also serves the Shamrock system.29

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Line 3 - Schleicher County System is a gas gathering system owned by Davis Gas1

Processing, Inc., a subsidiary of WTG. WTG fills the role as the LDC for2

this affiliate to provide service to a few customers electing to receive gas3

from this gathering system pursuant to the terms of existing right of way4

agreements.5

Line 4 - WTG Gas Marketing, Inc. (“WTGGM”) provides gas procurement services6

to WTG for nearly all of WTG’s distribution systems. WTG utilizes7

WTGGM for gas procurement in order to benefit from WTGGM’s8

volumetric advantages (e.g., transportation discounts, imbalance accounting9

thresholds, and purchasing power). WTGGM does not markup its gas10

supply to WTG. WTGGM gas cost is calculated and invoiced to WTG at11

cost (inclusive of direct costs only - cost of commodity, upstream transport,12

and balancing costs). Gas supply from WTGGM is made available to WTG13

at lower prices than gas supply available from third parties.14

Line 6 - Western Gas Interstate, Inc. (“WGI”) is the upstream interstate transmission15

pipeline operator that provides transportation service to several WTG16

distribution systems in Sherman and Moore Counties, Texas. WTG pays17

WGI for firm transportation service pursuant to WGI’s FERC approved18

tariff rates.19

Line 8 - WTG purchases a significant portion of its fleet gasoline and diesel supplies20

from WTG Fuels, Inc. (“WTGF”) by utilizing WTGF’s GasCard fleet21

management system to control fuel usage in WTG company vehicles.22

Vehicle fuel is usually purchased by WTG personnel at retail sites that are23

owned and operated by third parties. Fuel is paid using the GasCard fleet24

system. The price WTG pays to WTGF is the posted price that is offered to25

all retail customers at these sites, including other WTG affiliates and non-26

affiliated third parties.27

Line 9 - Occasionally WTG purchases oils, lubes, or propane parts at a WTGF28

warehouse facility. These are usually small and inexpensive items that are29

purchased at the market price available to any WTGF affiliate or third party.30

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Line 15 - WTG pays J.L. Davis a monthly administrative fee for personnel, services,1

and facilities provided to WTG. This affiliate charge is explained in more2

detail in testimony below.3

Line 17 - The Bowie Gas Plant is owned by Davis Gas Processing. The personnel at4

the Bowie Gas Plant handle daily operations for WTG’s Jack County5

transmission system for an agreed fee of $2,500 per month. This charge6

should be excluded from the rate case as it does not relate to distribution7

activities.8

Line 19 - The Pearsall Gas Plant is owned by Davis Gas Processing. The Pearsall9

Plant rented this 2,000 sq. ft. office space with shop for WTG’s South Texas10

personnel.11

Line 20 - WTG rents office space (approximately 1,200 sq. ft.) and shop from WTG12

Fuels in Perryton for use by WTG’s area distribution operations personnel.13

Line 21 - WTG rents office space (approximately1,500 sq. ft.) and shop from WTG14

Fuels in Seminole, Texas for use by WTG’s area distribution operations15

personnel.16

Line 22 - WTG rents approximately 10,000 sq. ft. of office space from J.L. Davis in17

downtown Midland for WTG officer and administrative personnel. The18

rental rates per square foot charged by J. L. Davis are the same for all19

affiliates and are substantially less than comparative rates charged in20

Midland for "Class B" office space. Exhibit RDH-2, Midland Commercial21

Office Rental Survey is a WTG business record that supports this22

conclusion.23

Line 24 - Aztec Gas provides WTG with OSHA safety training materials, safety24

equipment, as well as drug and alcohol testing kits. These items are billed to25

WTG at Aztec’s cost.26

Line 28 - Occasionally WTG purchases oils, lubes, or propane parts at a WTGF27

warehouse facility. These are usually small and inexpensive items that are28

purchased at the market price available to any WTGF customer.29

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Line 30 - Basin Aviation provides private aircraft charter services to WTG. The rates1

paid by WTG for these charter services are the same rates that Basin2

publishes and makes available to other affiliated or non-affiliated customers.3

Q. ARE THERE ANY PAYMENTS MADE TO AFFILIATES DURING THE TEST4YEAR THAT ARE NOT REFLECTED IN SCHEDULE J-3, AS AMENDED?5

A. Yes. WTG did not schedule out certain payments made to, or received from, affiliates6

that fall into two categories.7

Balance Sheet items that do not represent an income or expense item to WTG or8

the Affiliate (e.g., dividend payments, intercompany principal payments); or,9

An item paid to, or received from, affiliates that do not represent a revenue item10

to WTG or the affiliate, but is an expense pass-through from a non-affiliated third11

party (e.g., vendors that combine goods or services to multiple companies on a12

single invoice, accounting errors where a vendor bills an incorrect company for13

goods or services).14

Q. PLEASE DESCRIBE THE SUPPORT SERVICES PROVIDED BY J.L. DAVIS15REFLECTED IN SCHEDULE J-3, AS AMMENDED.16

A. J.L. Davis provides various administrative personnel and support for WTG’s Midland17

administrative offices. These items and support services include:18

Human Resource services19

Information Technology services20

Accounts Payable services21

Mailroom personnel & equipment22

Engineering services23

Mapping services24

Office equipment25

Office furniture26

Office supplies27

Office utilities28

Office cleaning & maintenance services29

Secretarial services30

Risk Management services31

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These items and services are paid for by WTG, its subsidiaries, and affiliates to J.L.1

Davis through a monthly management fee. The monthly management fee was2

established in order to reimburse J.L. Davis for his actual costs to provide these items and3

services. J.L. Davis does not markup his costs (i.e., earn a profit) to provide these items4

and support services.5

For purposes of this rate case, the cost of items and support services from J.L. Davis were6

allocated among WTG, its subsidiaries, and affiliates. The allocation methodology will is7

discussed in direct testimony provided by Randy Underwood.8

Q. WHAT ARE THE BENEFITS OF A CENTRALIZED CORPORATE SUPPORT9SERVICE STRUCTURE?10

A. Without the centralized corporate services provided by its stockholder, J. L. Davis, it11

would be necessary for WTG to add at least five administrative and professional staff12

positions to maintain its accounts payable, human resources, tax compliance, risk13

management, and information technology functions. By sharing these services with other14

affiliates, WTG recognizes significant savings in salaries and related overhead.15

Q. ARE THERE FORMAL AGREEMENTS BETWEEN J.L. DAVIS AND THE16AFFILIATES GOVERNING AFFILIATE TRANSACTIONS?17

A. No.18

Q. DOES WTG SEEK RECOVERY OF REASONABLE RATE CASE EXPENSES?19

A. WTG seeks recovery of its reasonable rate case expenses as well as any reasonable rate20

case expenses WTG reimbursed to Cities. WTG requests the Commission hold a short21

hearing at the conclusion of the case to determine the reasonable rate case expenses to be22

recovered through a surcharge.23

XII. CONCLUSION2425

Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?26

A. Yes, it does.27

Direct Testimony of Barbara GeffkenWest Texas Gas, Inc.

Page 1 of 10


STATEMENT OF INTENT OF WESTTEXAS GAS, INC. TO INCREASE GASDISTRIBUTION RATES IN THEUNINCORPORATED AREAS OF TEXAS

)))))

GUD NO. _________

DIRECT TESTIMONY OF BARBARA GEFFKEN

TABLE OF CONTENTS1



III. BOOKS AND RECORDS...................................................................................................... 34

IV. COMPLIANCE WITH COMMISSION RULES......................................................................... 85

VI. EXCLUDABLE EXPENSES ................................................................................................... 96

VII. OTHER.......................................................................................................................... 107

VIII. CONCLUSION ............................................................................................................... 1089

10

11

12

EXHIBITS13

Exhibit DescriptionBEG-1 WTG General Ledger Chart of Accounts

14Rate Study Schedules (co-sponsor): Schedules A-3, A-4.2, C-2, C-3, C-4, C-5, E-2, E-4 Page 1,15F-2, F-3, F-5, G-1, G-2, G-4 Pages 1, 2, 3, G-5, G-6, G-7, G-8, G-9, G-10, G-11, I-1, I-3, J-3, J-165, J-6, J-7, K-2.1, and K-2.3.17

18


Page 2 of 10



A. My name is Barbara Geffken and my business address is 211 N. Colorado, Midland,4

Texas 79701.5

Q. BY WHOM ARE YOU EMPLOYED AND IN WHAT CAPACITY?6

A. I am employed by West Texas Gas, Inc. (“WTG” or “Company”) as the Controller for7

WTG, its subsidiaries, and affiliates.8

Q. WHAT ARE YOUR DUTIES AS CONTROLLER?9

A. My duties include day-to-day supervision of accounting staff, daily cash management,10

preparation of monthly consolidated financial statements, preparation of quarterly and11

annual regulatory filings as well as oversight of the annual corporate audit.12


A. I graduated from East Texas State University in 1977 with a Bachelor Degree in Business15

Administration, majoring in Accounting. I began my employment with WTG in16

November 1978 as a staff accountant and was later promoted to Controller in the early17

1990’s.18

Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE RAILROAD19COMMISSION AND OTHER REGULATORY AGENCIES?20

A. No. I prefiled direct testimony in GUD No. 10118, but the case was withdrawn.21

Therefore, this is the first time I will be presenting testimony before a regulatory22

authority.23



A. The purpose of my testimony is to attest to the accuracy of the company’s books and26

records that were used to develop the rate study performed by Pendulum Energy, and27

provide any supporting documentation or information concerning the company’s28

financial records.29


Page 3 of 10

Q. WHAT EXHIBITS ARE YOU SPONSORING?1

A. I am sponsoring Exhibit BG-1, WTG’s General Ledger Chart of Accounts. I am co-2

sponsoring Schedules A-3, A-4.2, C-2, C-3, C-4, C-5, E-2, E-4 Page 1, F-2, F-3, F-5, G-3

1, G-2, G-4 Pages 1, 2, 3, G-5, G-6, G-7, G-8, G-9, G-10, G-11, I-1, I-3, J-3, J-5, J-6, J-7,4

K-2.1, and K-2.3.5

III. BOOKS AND RECORDS6

Q. WOULD YOU BRIEFLY DESCRIBE THE METHOD BY WHICH WTG’S7BOOKS AND RECORDS ARE MAINTAINED AND NOTE ANY SIGNIFICANT8CHANGES IN THOSE METHODS SINCE THE COMPANY’S LAST RATE9CASE?10

A. The books and records are maintained in accordance with generally accepted accounting11

principles and presented pursuant to the Uniform System of Accounts, as prescribed by12

the Federal Energy Regulatory Commission (“FERC”), and the Texas Railroad13

Commission (the “Commission). I have attached a cross reference to this testimony14

(Exhibit BEG-1), which shows the corresponding FERC account number to WTG’s15

general ledger chart of accounts. Except for revised depreciation rates pursuant to16

Commission order, there have been no significant changes in the methods by which the17

Company keeps its books and records since WTG presented its last full rate case in GUD18

No. 9488, Consolidated.19

Q. IN THE PROCESS OF PROVIDING TEST PERIOD DATA TO MR.20UNDERWOOD, DID YOU DISCOVER ITEMS IN THE COMPANY’S BOOKS21AND RECORDS THAT YOU NEEDED TO CORRECT?22

A. There were no corrections made to our general ledger. We did discover, however, that an23

entry was recorded on our books in the test period that offset an entry recorded in a24

month prior to the test period. The entry was to Texas Franchise Tax expense and was25

removed from test period data.26

Q. WITH THIS EXCEPTION, ARE WTG’S REVENUES AND EXPENSES FOR27THE TEST YEAR, AS SHOWN ON THE BOOKS AND RECORDS OF THE28COMPANY, TRUE AND CORRECT TO THE BEST OF YOUR KNOWLEDGE?29

A. Yes.30


Page 4 of 10

Q. PLEASE SUMMARIZE HOW THE BOOKS AND RECORDS OF WTG ARE1MAINTAINED AND UTILIZED IN THE REGULAR COURSE OF BUSINESS.2

A. WTG maintains its books and records in accordance with Generally Accepted3

Accounting Principles (“GAAP”). They are presented pursuant to the Uniform System of4

Accounts (“USOA”). The USOA is the prescribed methodology for maintaining records5

in all of the state jurisdictions which regulate WTG’s natural gas distribution operations.6

WTG’s accounting procedures utilize integrated computerized business systems to7

efficiently process, record and maintain transactions generated in the regular course of8

business. Financial transactions are created and entered into the system at or near the9

time of the transactions by personnel having personal knowledge of the transactions, as10

well as of the applicable accounting procedure requirements.11

Q. AS CONTROLLER, HOW DO YOU ASSURE YOURSELF THAT12TRANSACTIONS ARE RECORDED PROPERLY?13

A. As Controller, I have personal knowledge of the company’s business processes,14

accounting systems, and integrity of its financial reporting. The organization is staffed15

with qualified accounting personnel. WTG has established and maintained controls that16

ensure the accuracy of its books and records. These controls help identify any necessary17

adjustments to accounting entries which are then recorded to the original books and18

records. Additionally, WTG engages the Johnson & Miller accounting firm to perform19

an annual audit of the Company’s books to help ensure the continued integrity of WTG’s20

financial reporting to customers, vendors, regulatory authorities, and others.21

Q. ARE THE COSTS RECORDED ON WTG’S BOOKS AND RECORDS22SUPPORTED BY UNDERLYING INVOICES OR OTHER RECORDS?23

A. Yes. In order for a cost to be recorded in WTG’S general ledger, there must be a vendor24

invoice, or other underlying documentation, that has been properly approved or25

authorized, to support the entries recorded on WTG’s books. Examples of other26

documentation include timesheets, contracts, leases, or other agreements.27

Q. ARE WTG’S BOOKS AND RECORDS MAINTAINED IN A MANNER BY28WHICH REVENUES, EXPENSES, AND CAPITAL INVESTMENTS OF THE29VARIOUS LOCATIONS CAN BE IDENTIFIED?30


Page 5 of 10

A. Yes, WTG’s books and records are generally maintained for each field (district) office in1

order to identify revenues, expenses and capital expenditures by location. To accomplish2

this, WTG has set up a unique entity ID number for each district location.3

Q. DOES THE COMPANY HAVE IN PLACE ANY PROCESS OR SYSTEM FOR4THE REVIEW AND VALIDATION OF INVOICES?5

A. Vendors are generally instructed to mail invoices to the district office location where the6

service(s) was performed. District managers are responsible for reviewing invoices billed7

to their district operation for validity and approving the invoice for payment by adding8

their initials and the applicable entity ID number. District clerks are responsible for9

coding invoices with the proper GL account code and forwarding those invoices to the10

Midland office for further review and payment. A WTG staff accountant is responsible11

for reviewing the invoices to ensure they have been approved by a district manager and12

are properly coded before payment is made. Invoices mailed by vendors directly to13

Midland are reviewed by management and/or the accounting staff to determine the14

appropriate district ID code.15

Q. PLEASE DESCRIBE THE PROCESS USED TO TEST INTERNAL CONTROLS.16

A. Internal controls are reviewed annually for effectiveness by WTG’s independent auditors.17

Upon the completion of the audit, the auditors provide WTG with an “audit wrap up”18

report that identifies any weaknesses in internal controls and makes specific19

recommendations to management for solutions, if needed.20

Q. CAN YOU SUMMARIZE THE PROCESS USED BY JOHNSON & MILLER TO21PERFORM ITS AUDIT FUNCTION?22

A. Johnson & Miller auditors utilize generally accepted auditing standards to perform the23

annual audit of WTG’s books and records. These auditing standards establish a level of24

protocol the auditors must recognize during the performance of their field work and the25

reporting of their finished work. The auditing standards used by Johnson & Miller are as26

follows:27

Standards of Field Work28


Page 6 of 10

1. The auditor must adequately plan the work and must properly supervise any assistants.12. The auditor must obtain a sufficient understanding of the entity and its environment, including its internal2

control, to assess the risk of material misstatement of the financial statements whether due to error or fraud,3and to design the nature, timing, and extent of further audit procedures.4

3. The auditor must obtain sufficient appropriate audit evidence by performing audit procedures to afford a5reasonable basis for an opinion regarding the financial statements under audit.6

Standards of Reporting7

1. The auditor must state in the auditor's report whether the financial statements are presented in accordance8with generally accepted accounting principles.9

2. The auditor must identify in the auditor's report those circumstances in which such principles have not been10consistently observed in the current period in relation to the preceding period.11

3. When the auditor determines that informative disclosures are not reasonably adequate, the auditor must so12state in the auditor's report.13

4. The auditor must either express an opinion regarding the financial statements, taken as a whole, or state that14an opinion cannot be expressed, in the auditor's report. When the auditor cannot express an overall opinion,15the auditor should state the reasons therefore in the auditor's report. In all cases where an auditor's name is16associated with financial statements, the auditor should clearly indicate the character of the auditor's work,17if any, and the degree of responsibility the auditor is taking, in the auditor's report.18

Q. HOW DOES THE ACCOUNTING SYSTEM ALLOW FOR THE SEPARATE19RECORDING AND TRACKING OF COSTS FOR WTG’S UTILITY20DISTRICTS?21

A. WTG’s accounting books and records are maintained separately and apart from its22

subsidiaries. Within this accounting system, revenues and expenses must be identified to23

a specific individual profit center (i.e., WTG’s home office or district office). This24

identification process allows WTG to create accounting reports for each profit center.25

Q. WERE THE BOOKS AND RECORDS OF THE COMPANY PROVIDED TO26COMPANY WITNESSES FOR UTILIZATION IN THEIR ANALYSIS FOR27RATEMAKING PURPOSES?28

A. Yes.29

Q. DO THE AMOUNTS SHOWN IN THE RATE MODEL THAT ARE CLAIMED30AS “PER BOOKS” ACCURATELY REFLECT THE COMPANY’S BOOKS?31

A. Yes.32

Q. WHAT STEPS DID WTG TAKE TO ASSURE CONSISTENCY BETWEEN THE33COMPANY’S BOOKS AND RECORDS AND THE RATE MODEL?34

A. Upon completion of the rate model, all schedules containing “Per Book” balances were35

compared directly to WTG’s Balance Sheet at June 30, 2012 and WTG’s Income36

Statement for the twelve month test period ending June 30, 2012. Any differences37


Page 7 of 10

between the rate model and WTG’s trial balance were discussed with the consultants for1

correction or reference, as applicable.2

Q. Please describe Schedule A-3.3

A. Schedule A-3 is the WTG Working Trial Balance. It includes asset, liability and equity4

account balances as of June 30, 2012 along with income and expense account balances5

for the twelve month period ending June 30, 2012. WTG’s general ledger account6

number and the corresponding FERC account number are shown for each account. The7

schedule also shows that asset accounts tie to liability and equity accounts, and net8

income for the test period ties to income summary in the equity section.9

Q. Please describe Schedule C-2.10

A. C-2 is a schedule of plant account balances, by FERC account number, by month for each11

month in the test period. The total plant shown at December 31, 2011 ties to our TRC12

annual report at December 31, 2011 with the exception of CIAC. CIAC was netted13

against plant in the annual report, but is not reflected in this schedule.14

Q. Please describe Schedule C-3.15

A. Schedule C-3 is a listing of Construction Work in Progress as of June 30, 2012. It16

includes the project name and number, date started, estimated completion date and cost17

figures.18

Q. Looking at Schedule D-1, column C, does the accumulated depreciation reflect the19depreciation rates approved in the last case?20

A. Yes, the accumulated depreciation balances shown in column C do reflect rates approved21

in the last rate case. Note, however, WTG’s accounting software calculates depreciation22

based on life in months rather than using a percentage rate, therefore the approved rates23

were converted to months before the calculation was made.24

Q. The per books reserve in the case that WTG filed and withdrew in 2011 did not25reflect the approved depreciation rates. What steps did WTG take to ensure that26this one does?27


Page 8 of 10

A. WTG recalculated its reserve using the depreciation rates approved in its last rate case1

GUD No. 9488 Consolidated. An adjustment was recorded on WTG’s books in2

December 2011 to reflect the change.3

Q. Looking at Schedule D-2, page 2 column C, does the depreciation expense reflect the4depreciation rates approved in the last case?5

A. Yes.6

Q. Are the depreciation rates on Schedule D-2, page 3, column C, the rates that WTG is7using to record monthly depreciation?8

A. Yes, except as previously noted. WTG’s accounting software calculates depreciation9

based on life in months rather than using a rate. It was necessary therefore, to convert the10

approved rates to life in months in order for WTG’s software to calculate monthly11

depreciation.12

Q. Schedule E-2. Is this correct?13

A. Yes, WTG does not factor or sale its receivables.14

Q. Does WTG have any plans to factor or sale receivables in the future?15

A. No.16

Q. Please describe Schedule G-1. How were the amounts calculated?17

A. Schedule G-1 is a payroll expense report for WTG. It shows a breakdown by month of18

regular pay, overtime pay, holiday pay, vacation pay, sick pay and total payroll expense19

for the test period along with employee count. In addition, total payroll is shown for the20

twelve month period ending June 30, 2009, 2010 and 2011. WTG is unable to pull21

payroll data by pay type out of its software, therefore, a special program was written to22

pull the reported data for the test period out of WTG’s payroll system. WTG contracted23

this work with an outside vendor. Total payroll expense for the years prior to the test24

period was pulled from WTG’s general ledger software.25

IV. COMPLIANCE WITH COMMISSION RULES26

Q. PLEASE DISCUSS THE SYSTEM OF ACCOUNTS THAT THE COMPANY27UTILIZES.28


Page 9 of 10

A. WTG has set up a cross reference of its general ledger chart of accounts with the Uniform1

System of Accounts. For regulatory reporting purposes, general ledger balances are2

entered into an excel spreadsheet which includes both sets of account numbers. This3

allows WTG to do regulatory reporting as needed using the Uniform System of Accounts4

and still tie balances back to its general ledger.5

Q DO THE BOOKS AND RECORDS, AS WELL AS THE SUMMARIES AND6EXCERPTS THEREFROM, QUALIFY FOR THE PRESUMPTION SET FORTH7IN THE COMMISSION’S RULE 7.503?8

A. Yes. Since the Company maintains its books and records in accordance with the9

Commission’s Rule 7.310, the amounts referenced on its books and records, as well as10

summaries and excerpts from those books and records, are presumed to be reasonable and11

necessary under the provisions of Rule 7.503.12

Q. ARE WTG’S BOOKS AND RECORDS AVAILABLE FOR REVIEW?13

A. Yes. The Company’s books and records are available to a party for review at the14

Company’s offices in Midland, Texas. Confidential information will be made available15

to those qualified individuals who have executed a confidentiality agreement.16

VI. EXCLUDABLE EXPENSES17

Q. DOES WTG SELL OR LEASE APPLIANCES, FIXTURES, EQUIPMENT OR18OTHER MERCHANDISE?19

A. No.20

Q. HAS WTG INCURRED ANY EXPENSE FOR LEGISLATIVE ADVOCACY21DURING THE TEST YEAR?22

A. Yes, lobbying expense, shown on Schedule G-7, totaled $ 30,667 during the test year and23

has been removed by Mr. Randy Underwood to comply with Rule 7.5414.24

Q. HAS WTG INCURRED ANY EXPENSES FOR BUSINESS GIFTS,25ENTERTAINMENT OR CHARITABLE OR CIVIL CONTRIBUTIONS?26

A. Yes, donations and contributions, shown on Schedule G-6, totaled $15,163 during the test27

year and are addressed by Mr. Randy Underwood in his direct testimony.28


Page 10 of 10

Q. HAS WTG INCURRED ANY ADVERTISING EXPENSE DURING THE TEST1YEAR?2

A. Yes, advertising expense, shown on Schedule G-5, totaled $ 58,279 during the test year3

and are addressed by Mr. Underwood in his direct testimony.4

VII. OTHER5

Q. WHAT IS THE TEST YEAR IN THIS CASE?6

A. July 1, 2011 through June 30, 2012.7

Q. WHAT AMOUNTS OF INCOME TAX SAVINGS HAS WTG ACCRUED FROM8LIBERALIZED DEPRECIATION OR AMORTIZATION?9

A. WTG is a Subchapter S entity where income tax liability is assumed by the stockholder;10

therefore GAAP accounting does not provide for WTG to record federal income tax11

liability or deferred income tax liability. Schedule B-1 of WTG’s rate study, has12

calculated a pro forma Accumulated Deferred Income Tax balance based on the13

difference between accelerated (tax basis) depreciation and book depreciation rates.14

VIII. CONCLUSION15


A. Yes, it does.17

of 8

Direct Testimony of Jack J. KingWest Texas Gas, Inc.



))))

GUD NO. ________

DIRECT TESTIMONY OF JACK J. KING

TABLE OF CONTENTS1



III. WTG’S TEXAS SERVICE AREA ............................................................................................ 34

IV. GAS COST ADJUSTMENT CLAUSE...................................................................................... 65

V. PROPOSED TARIFF – RATE SCHEDULES .............................................................................. 76

VI. PUBLIC NOTICE ................................................................................................................ 77

VII. CONCLUSION.................................................................................................................. 88

9

10

EXHIBITS11

Exhibit Description12

APPENDIX A WTG’s Proposed Tariff13

APPENDIX B Public Notice14

JJK - 1 Map of WTG Gas Cost Zones15

JJK - 2 WTG’s Existing Tariff16

17

of 8




A. My name is Jack J. (JJ) King. My business address is 211 N. Colorado, Midland, Texas3

79701.4


A. I am employed by West Texas Gas, Inc. (“WTG” or “the Company”) as the Manager of6

Gas Marketing.7

Q. WHAT ARE YOUR DUTIES AS MANAGER OF GAS MARKETING?8

A. I am responsible for managing our marketing personnel, contract maintenance activities,9

and project evaluations relating to the retail and wholesale customers served by WTG. I10

also oversee the preparation and filing of WTG’s rates and tariffs with state agencies. I11

am the primary point of contact for WTG-served cities as well as its domestic and non-12

domestic customers. I answer any questions concerning rates, gas costs, and quality of13

service. I am also responsible for reviewing and approving most mainline extensions.14


A. I received a bachelor’s degree in Business Administration from Abilene Christian17

University in 1994. From 1994 to 1996, I was the Sales Coordinator for Compressor18

Systems, Inc. I joined WTG in May 1996 as the Gas Contracts Administrator.19

Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE RAILROAD20COMMISSION OF TEXAS OR OTHER STATE AGENCIES?21

A. Yes. I testified before the Railroad Commission in GUD No. 9488 Consolidated and22

other cases before the Commission. In 2011, I prefiled direct testimony in GUD No.23

10118, but the case was withdrawn. I have also appeared before the Oklahoma24

Corporation Commission and various Texas municipalities in rate and other regulatory25

proceedings.26

of 8




A. The purpose of my testimony is to describe WTG’s Texas service area, including the3

changes in customer growth since WTG’s last full rate case; describe the settlement offer4

made by WTG that accompanied its Statement of Intent to Increase Rates and identify the5

cities that accepted the offer; support WTG’s request to merge the Farwell Gas Cost Zone6

into the North Gas Cost Zone; support the need to continue WTG’s Gas Cost Adjustment7

(“GCA”) clause; explain and support the proposed changes to WTG’s tariff, including the8

proposed rate schedules; and attest to WTG’s compliance in providing the required public9

notice to all affected customers.10

Q. ARE YOU SPONSORING ANY EXHIBITS?11

A. Yes, I am sponsoring APPENDIX A, WTG’s Proposed Tariff and APPENDIX B, the12

Public Notice that are part of the Statement of Intent. I am also sponsoring exhibits: JJK13

- 1, Map of WTG Gas Cost Zones and JJK - 2, WTG’s Existing Tariff. Exhibit JJK - 2 is14

located under the Existing Tariff tab of the rate filing package.15

III. WTG’S TEXAS SERVICE AREA16

Q. WHICH CUSTOMERS ARE LIKELY TO BE AFFECTED BY THE RATE17INCREASE PROPOSED BY WTG?18

A. WTG serves domestic and non-domestic customers within 28 municipalities and the19

adjacent environs areas in Texas. However, WTG’s customers within the City of20

Lubbock have been excluded from this rate case. Of the 27 remaining municipalities, 1521

cities accepted WTG’s offer of settlement that accompanied each rate request. The cities22

that accepted WTG’s settlement offer are: Balmorhea, Claude, Darrouzett, Farwell,23

Follett, Groom, Higgins, Junction, Menard, Mobeetie, Paint Rock, Shamrock, Texhoma,24

Texline, and Wheeler. WTG expects the remaining municipalities will reject WTG’s rate25

request. Assuming this case is consolidated with appeals of the cities’ actions denying26

WTG’s request, WTG’s retail customers within the municipalities of Cactus, Canadian,27

Canyon, Dalhart, Devine, Eden, Kermit, Miami, Natalia, Somerset, Sonora, and Stratford,28

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as well as, the customers served by WTG within the Commission’s original jurisdiction1

are likely to be affected by the Commission’s final order.2

Q. PLEASE DESCRIBE WTG’S SETTLEMENT OFFER TO THE CITIES.3

A. WTG made a settlement offer to the cities that reduced the requested rate increase in4

revenues by approximately 50%, delayed the implementation of the reduced rate increase5

until April 1, 2013, limited the rate case surcharge to recover WTG’s rate case expenses6

incurred through November 5, 2011, and protected the city if the Railroad Commission,7

or an appellate court, establishes final rates that are lower than the settlement rates.8

Q. WHY DIDN’T WTG FILE FOR A RATE INCREASE WITH THE CITY OF9LUBBOCK?10

A. ATMOS Energy Corp. serves the vast majority of the natural gas customers within the11

City of Lubbock. WTG only has 23 customers within the City of Lubbock. At the city’s12

request, WTG will separately file for a rate increase in Lubbock that proposes rates for13

gas service in Lubbock be set at the same level as the ATMOS rates in effect as a result14

of the settlement with the city and final order in GUD No. 10191. The result is expected15

to be that all customers in Lubbock will receive gas service at the same rates without16

regard to which local distribution company provides their service.17

Q. PLEASE DESCRIBE WTG’S JURISDICTIONAL CUSTOMER CLASSES.18

A. WTG has two jurisdictional customer classes: domestic and non-domestic customers.19

Domestic customers are residential customers. All other jurisdictional customers fall20

under the non-domestic customer class.21

Q. HOW MANY DOMESTIC AND NON-DOMESTIC CUSTOMERS ARE SERVED22BY WTG IN TEXAS?23

A. As of June 30, 2012, WTG has a total of 17,062 jurisdictional Texas customers consisting24

of 14,928 domestic and 2,134 non-domestic customers. Geographically, 10,535 are25

domestic customers and 1,735 are non-domestic customers within the jurisdictional limits26

of the twenty-eight (28) Texas cities served by WTG. The remaining 4,792 domestic and27

non-domestic customers in Texas are served in rural or environs areas.28

Q. HAS THE NUMBER OF JURISDICTIONAL CUSTOMERS GROWN IN THE29

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LAST SEVEN YEARS?1

A. The number of customers served by WTG has not grown substantially since the 2004 rate2

case. The following chart shows our customer count as reported in WTG’s Annual3

Report to the Railroad Commission at December 31 for each year from 2005 through4

2011, and at June 30, 2012.5

Domestic Non-Domestic Total6

2005 14,333 2,188 16,5217

2006 14,261 2,174 16,4358

2007 14,486 2,173 16,6599

2008 14,484 2,159 16,64310

2009 14,438 2,222 16,66011

2010 15,028 2,329 17,35712

2011 15,067 2,320 17,38713

2012(6/30) 14,928 2,134 17,06214

If WTG had not purchased the City of Devine distribution system in 2010, the15

Company’s total customer count would be substantially less than at test year16

end.17

Q. WHAT FACTORS HAVE CONTRIBUTED TO WTG’S SLIGHT INCREASE IN18CUSTOMER GROWTH WITHIN TEXAS?19

A. The primary factors contributing to WTG’s uneven increase in jurisdictional customer20

count growth are: the acquisition of the Devine distribution system in September 2010,21

some growth in the environs areas southwest of the City of Amarillo, and extensions into22

new subdivisions in the San Antonio area. At the same time, several areas served by23

WTG in the smaller rural municipalities and their environs have experienced negative24

growth.25

Q. WHAT IS THE AVERAGE MONTHLY CONSUMPTION FOR WTG’S TEXAS26JURISDICTIONAL CUSTOMERS?27

A. During the test year, the average monthly consumption for domestic customers was 4.428

Mcf, and 17.2 Mcf for non-domestic customers.29

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IV. GAS COST ADJUSTMENT CLAUSE1

Q. HOW DOES WTG RECOVER ITS COST OF GAS?2

A. WTG’s Commission-approved GCA clause has several components that capture gas3

purchase costs, upstream transportation costs, and any applicable revenue-related taxes,4

fees, or other charges imposed by regulatory and governmental authorities. The GCA5

clause establishes how these gas cost components are calculated and passed through to6

customers. WTG calculates a monthly gas cost estimate and updates its Commission7

Tariff on a monthly basis. WTG provides the Commission with an annual reconciliation8

of actual gas costs versus the monthly estimated filings. Any over or under collection9

balances are calculated and correction factors are applied prospectively to ensure that10

WTG collects only its allowed cost of gas.11

Q. ARE ANY GAS COSTS IMBEDDED IN THE MONTHLY CUSTOMER12CHARGE OR CONSUMPTION CHARGE UNDER WTG’S TARIFF?13

A. No. All gas costs are recovered through the Tariff’s GCA clause.14

Q. IS WTG PROPOSING ANY CHANGE TO ITS GCA CLAUSE?15

A. Yes, WTG is proposing to eliminate the Farwell Gas Cost Zone and merge the Farwell16

area customers into WTG’s North Gas Cost Zone. No other changes in the GCA clause17

are sought. A map marked Exhibit JJK - 1 is attached showing the geographical areas of18

each gas cost zone.19

Q. WHY IS WTG PROPOSING TO ELIMINATE THE FARWELL GAS COST20ZONE?21

A. Gas supply was provided to the City of Farwell and its environs via special discounted22

backhaul transportation rates on El Paso Natural Gas Company’s transmission system23

connected to the San Juan Basin in Northern New Mexico. El Paso Natural Gas24

eliminated those special backhaul rates in a 2007 rate case before the Federal Energy25

Regulatory Commission.26

WTG proposes to include Farwell in the North Gas Cost Zone to eliminate the necessity27

of making a separate gas cost filing for the limited number of customers in the Farwell28

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Zone. There will be no material adverse impact on the customers of Farwell or the1

customers of the North Gas Cost Zone if this recommendation is adopted by the2

Commission.3

Q. IS THERE A NEED TO CONTINUE WTG’S GCA CLAUSE?4

A. Yes. The GCA clause was approved by the Commission in GUD No. 9488 Consolidated5

and has been in effect since then. The GCA clause functions well in today’s gas markets.6

The continued use of WTG’s GCA clause operates to ensure that WTG neither over-7

recovers nor under-recovers its cost of gas, and that WTG customers pay only the8

Company’s actual gas cost, including its authorized components. Mr. Carson Watt, in his9

direct testimony, addresses the conditions that exist in gas markets today.10

V. PROPOSED TARIFF – RATE SCHEDULES11

Q. IS WTG PROPOSING CHANGES TO ITS CURRENT RATE SCHEDULES?12

A. Yes, APPENDIX A to the Statement of Intent is a copy of the Proposed Tariff that13

includes proposed rate schedules for the unincorporated areas at pages 8-9.14

Q. WHAT ARE THE CHANGES PROPOSED TO WTG’S TARIFF?15

A. WTG’s current tariff consists of rates approved by the Commission in GUD No. 948816

Consolidated. WTG proposes the following changes:17

Elimination of the Farwell Gas Cost Zone and merging the affected18

customers into WTG’s North Gas Cost Zone as described above;19

Increasing rates for domestic and non-domestic customers to reflect the20

company’s higher cost of service.21

Updating the tariff formatting.22

WTG does not propose to change the fee, deposit, or general terms of service provisions23

in the tariff.24

VI. PUBLIC NOTICE25

Q. HAS WTG GIVEN PUBLIC NOTICE OF THE PROPOSED RATE INCREASE26

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TO ITS CUSTOMERS?1

A. Public Notice for municipal customers has been completed by publishing the notice once2

a week for four consecutive weeks in the following nine newspapers: Canadian Record,3

Canyon News, Dalhart Texan, Devil’s River News, Devine News, Eden Echo, Junction4

Eagle, Moore County News, and the Winkler County News.5

All customers situated inside the affected municipalities with a population of less than6

2,500, were sent notice by first class mail to the address shown in WTG’s billing records7

on October 1, 2012.8

A copy of the Public Notice that will be published and mailed to our customers within the9

original jurisdiction of the Commission is attached as APPENDIX B to WTG’s Statement10

of Intent. After WTG receives all of the publishers’ affidavits, I will execute an affidavit11

regarding publication of notice and our attorneys will file it with the Commission.12

VII. CONCLUSION13


A. Yes, it does.15

of 7

Direct Testimony of James B. BeanWest Texas Gas, Inc.



))))

GUD NO. ___________

DIRECT TESTIMONY OF JAMES B. BEAN1

TABLE OF CONTENTS2

3

I. INTRODUCTION...............................................................................................24

II. PURPOSE OF TESTIMONY ...............................................................................35

III. WTG’s FIELD OPERATIONS.............................................................................36

IV. LOST AND UNACCOUNTED FOR GAS .............................................................67

V. CONCLUSION .................................................................................................78

9

10

11

12

EXHIBITS13No Exhibits14

15

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1

I. INTRODUCTION2

3Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.4

A. My name is James Barton “Bart” Bean and my business address is 7517 Canyon Drive,5

Amarillo, TX 79110.6


A. I am employed by West Texas Gas, Inc. (“WTG” or “the Company”) as the Operations8

Manager for its regulated pipeline systems.9

Q. WHAT ARE YOUR RESPONSIBILITIES AS OPERATIONS MANAGER FOR10WTG?11

A. I am responsible for the execution of, and compliance with, WTG’s Operations and12

Maintenance Plan applicable to it’s distribution and transmission pipeline systems in13

Texas and Oklahoma. Additionally, I help to coordinate and oversee various levels of14

directors, managers, and supervisors. WTG directors are responsible for the oversight15

and execution of Integrity Management, Distribution Integrity Management, Operator16

Qualification, and Public Awareness Plans. District managers are responsible for the17

pipeline systems within certain assigned geographical areas. Field supervisors are18

responsible the work performed by the service and maintenance staff.19

Q. PLEASE DESCRIBE YOUR BACKGROUND AND EXPERIENCE.20

A. After attending Baylor University from 1978 to 1980, I was employed by Lone Star Gas21

Company for two years as a field operator. In 1982, I accepted a position with High22

Plains Natural Gas Company (“HPNG”) as a welder and field operator. In May, 1994,23

WTG acquired the assets of HPNG. During my tenure at WTG, I have been promoted24

from a field supervisor to District Manager, and eventually to my current position as25

Operations Manager in 2006.26

In addition to my more than 31 years of experience in the natural gas industry, I have27

attended numerous workshops and training meetings put on by the Railroad Commission,28

the Pipeline and Hazardous Materials Safety Administration, and various consulting29

of 7


firms and equipment manufacturers. Since 1990, I have been a member of the Texas Gas1

Association (“TGA”). I have served on various TGA committees and served as2

Chairman from 2006 – 2007.3

Q. HAVE PREVIOUSLY TESTIFIED BEFORE ANY REGULATORY4COMMISSION?5

A. Yes, I testified in before the Railroad Commission in Docket No. 9959 which was a6

WTG complaint filed against Enterprise Texas Pipeline, L.L.C.7


9Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS PROCEEDING?10

A. The purpose of my testimony is to describe certain key WTG’s field operations and11

expenses as well as support WTG’s test year lost and unaccounted for gas percentage.12

Q. ARE YOU SPONSORING ANY EXHIBITS?13

A. No.14

III. WTG’s FIELD OPERATIONS15

16Q. PLEASE PROVIDE A GENERAL DESCRIPTION OF WTG’S DISTRICT17

OFFICES.18

A. WTG currently maintains twelve (12) district offices that are located from the Oklahoma19

Panhandle down to Frio County in South Texas. These offices function as “report-to -20

duty” stations for district managers, supervisors, field personnel and customer service21

staff. The Texas district offices are located in: Somerset, Junction, Fort Stockton,22

Kermit, Wolfforth, Plainview, Shamrock, Canadian, Stratford, and Dalhart. The23

Oklahoma offices are located in Texhoma and Beaver.24

Q. PLEASE EXPLAIN WHY WTG’S DISTRICT OFFICES IN WHEELER AND25TEXOMA ARE RESPONSIBLE FOR OPERATIONS IN TWO STATES26

A. Based on their geographic location it it more efficient and cost effective to assign the27

Wheeler and the Texhoma Offices with responsibility for field operations in both Texas28

and Oklahoma.29

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Q. WHAT IS WTG’S PIPELINE SAFETY DISTRIBUTION INTEGRITY1MANAGEMENT PLAN PROGRAM?2

A. WTG’s Distribution Integrity Management Plan (“DIMP”) program is a written plan that3

was developed in compliance with 49 CFR Part 192 - Subpart P. The purpose of the4

DIMP plan is to gather knowledge of WTG’s distribution systems, identify threats to5

systems’ integrity, evaluate and rank the risks to the systems, implement measures to6

address those risks, and evaluate the effectiveness of the plan.7

WTG has generated a detailed digital mapping system of it’s distribution pipeline system8

and initiated an automated leak tracking system to help monitor the system risks and the9

plan’s effectiveness. WTG also utilizes a detailed engineering model to evaluate10

performance and rank the priority of identified risks.11

Q. WHAT IS WTG’S PROCESS TO ENSURE THAT COMPANY OPERATIONS12AND MAINTENANCE EXPENSES ARE FAIR, JUST, AND REASONABLE?13

A. Each manager is held responsible for the O&M expenses charged to their district. These14

expenses are reviewed for reasonableness and compared to the prior year performance for15

the same period.16

Q. WHAT IS THE BIDDING PROCESS FOR CONSTRUCTION JOBS?17

A. WTG distributes formal requests for bids on large construction and replacement projects.18

Interested contractors are given project specifications and an opportunity for a field19

inspection. After bids are received, WTG evaluates them, accepts the lowest reasonable20

bid proposal, and executes a construction contract with the contractor.21

For smaller projects, WTG compares informal price quotes from local area suppliers and22

contractors to insure that a competitive price is received for goods and services.23

Q. HOW DOES WTG MONITOR CONSTRUCTION PROJECT SPENDING?24

A. Before beginning a project, costs are estimated based on historical experience and are25

submitted for approval to a corporate officer. Each approved project is assigned a project26

identification number. Costs are accumulated under the project ID number as invoices27

are received from suppliers and contractors. Accumulated project costs are reviewed on28

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an ongoing basis during construction and, at the completion of the project, they are1

reviewed against the initial estimated budget.2

Q. WHAT ADDITIONAL OVERSIGHT DO YOU HAVE ON OTHER3EXPENDITURES?4

A. Each district manager must request a purchase order for any non-recurring expenditure5

(e.g. equipment, inventory, service, tools, maintenance, etc.) for amounts in excess of6

$500.00. Purchase order requests are reviewed by me, or a corporate officer.7

Q. EXPLAIN WTG’S STEEL LINE REPLACEMENT PROGRAM?8

A. Prior to August 1, 2011, 16 TAC §8.209, required WTG to submit it’s risk-based removal9

or replacement program to the Commission’s Pipeline Safety Division. WTG’s risk-10

based program uses information collected by the DIMP plan to determine a risk ranking11

of factors threatening the distribution system. Based on the risk analysis, WTG12

determines the pipeline segments or facilities posing the highest risk and schedules the13

replacement of at least 5% of these facilities annually.14

In 2012, WTG spent more than $1.5 million to replace suspect mains and service lines15

situated primarily within WTG’s older municipal distribution systems serving16

jurisdictional customers.17

Q. WHAT CHANGES HAVE BEEN MADE TO COMPLY WITH PIPELINE18SAFETY AND OTHER REGULATORY REQUIREMENTS SINCE WTG’S 200419RATE CASE?20

A. WTG has added numerous staff positions relating to pipeline safety and other regulatory21

requirements, including: directors for IMP, DIMP, and operator qualification, as well as22

underground damage reporting and digital mapping personnel. Along with these staffing23

additions, WTG has retained professional engineering and consulting services to assist24

with both developing our IMP and DIMP plans and risk assessment models, and25

complying with periodic public awareness requirements.26

Q. PLEASE BRIEFLY EXPLAIN HOW WTG DECIDES WHAT DIAMETER PIPE27TO INSTALL?28

A. The primary factor that determines the pipeline size for installation projects is the29

maximum expected throughput requirements of downstream customers. We generally do30

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not install any pipe less than 2” in diameter. The possible exception to this minimum1

pipeline diameter size occurs when field personnel install a replacement line by insertion2

into a larger existing line (e.g. 1.25” pipeline inserted into an existing 2” pipeline).3

Q. WHAT IS THEPOLICY FOR EXTENDING WTG’S FACILITIES TO SERVE4IRRIGATION LOAD?5

A. If there is excess unused capacity on an existing WTG distribution system, WTG will6

connect non-jurisdictional irrigation load to its system. If excess capacity does not exist,7

WTG will consider an extension or expansion of its system based on the economics of8

the incremental business and, when necessary, a customer contribution in aid of9

construction.10

Q. WITH REGARD TO FIELD OPERATIONS, PLEASE DESCRIBE ANY11AFFILIATE RELATED TRANSACTIONS.12

A. WTG owns a small gathering pipeline in Jack County, Texas. Because WTG does not13

maintain an office or have personnel in the general vicinity of this asset, a WTG affiliate14

located in Jack County, the Bowie Gas Plant, maintains the daily operations and15

maintenance on this WTG asset.16

Q. DO WTG FIELD PERSONNEL PERFORM SERVICES FOR ANY OF17WTG’S AFFILIATES OR SUBSIDIARIES?18

A. WTG field personnel coordinate activities from time-to-time with other WTG operations19

just as they would any unaffiliated entity upstream or downstream of WTG’s facilities.20

However, WTG field personnel do not regularly perform services for WTG affiliates.21

IV. LOST AND UNACCOUNTED FOR GAS2223


A. Schedule G-12 of the Rate Study presents the lost and unaccounted for gas (LUFG)25

volumes experienced by WTG for the twelve-month periods ending June 30, 200926

through June 30, 2012. LUFG volumes from WTG transmission systems have been27

eliminated in order to demonstrate the actual LUFG experienced on WTG’s Texas28

distribution systems.29

30

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Q. WHAT STEPS DOES WTG TAKE TO MINIMIZE LUFG?1

A. WTG has taken a number of steps to minimize its LUFG volumes, including the2

following :3

o Replacement of pipeline facilities with a history of pipeline failures and related4

LUFG problems.5

o Installation of new check metering and regulation facilities to better isolate6

WTG’s pipeline systems for LUFG accounting purposes.7

o Acquisition of new RMLD leak detection equipment to replace older “flame8

ionization” technology.9

o Increased frequency of leak surveys beyond the required intervals set out in Part10

192.11

o Digitization of WTG pipeline maps to improve the effectiveness of WTG’s leak12

surveys.13

o Implementation of internal LUFG reports on a system by system basis at local14

WTG field offices to access volume information earlier in the monthly cycle.15

o Increased focus on LUFG in WTG’s DIMP, operator qualification and public16

awareness plans.17

Q. WHAT IS THE MAXIMUM AMOUT OF LUFG ALLOWED FOR18RATEMAKING PURPOSES?19

A. Commission Substantive Rule 7.5525 establishes a maximum rate of 5% for LUFG using20

a twelve-month period ending June 30, but the Commission may allow a greater21

percentage. As shown on Schedule G-12, WTG LUGF during the test year was 1.43%,22

which is the lowest level in the last four years.23

V. CONCLUSION2425

Q. DOES THIS CONCLUDE YOUR TESTIMONY?26

A. Yes.27

of 40

Direct Testimony of Bruce H. FairchildWest Texas Gas, Inc.



))))

GUD NO. _________

DIRECT TESTIMONY OF BRUCE H. FAIRCHILD

TABLE OF CONTENTS

I. INTRODUCTION..................................................................................................... 3

A. Qualifications ...................................................................................................... 3B. Overview ............................................................................................................. 4C. Summary of Conclusions ...................................................................................... 5

II. FUNDAMENTAL ANALYSES .................................................................................... 5

A. West Texas Gas, Inc. ............................................................................................ 6B. Natural Gas Distribution Industry......................................................................... 7C. Capital Markets.................................................................................................... 9

III. CAPITAL STRUCTURE AND COST OF DEBT ............................................................ 12

A. Principles........................................................................................................... 12B. Capital Structure Ratios ..................................................................................... 13C. Cost of Debt....................................................................................................... 16

IV. RATE OF RETURN ON EQUITY .............................................................................. 16

A. Cost of Equity Concept ....................................................................................... 17B. Discounted Cash Flow Model ............................................................................. 20C. Capital Asset Pricing Model ................................................................................ 27D. Risk Premium Method ....................................................................................... 31E. Comparable Earnings Method ............................................................................ 33F. Cost of Equity Range........................................................................................... 33

V. RETURN ON EQUITY RECOMMENDATION............................................................ 34

A. Outlook for Capital Costs ................................................................................... 34C. Recommended Return on Equity ........................................................................ 39D. Check of Reasonableness ................................................................................... 39

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VI. OVERALL RATE OF RETURN.................................................................................. 40

EXHIBITS


Schedule BHF-1 Overall Rate of Return2

Schedule BHF-2 LDC Industry Group Capital Structure3

Schedule BHF-3 LDC Industry Group Embedded Cost of Debt & Preferred Stock4

Schedule BHF-4 DCF Model – Dividend Yield5

Schedule BHF-5 DCF Model – Earnings Growth Rates6

Schedule BHF-6 DCF Model – Sustainable Growth Rates7

Schedule BHF-7 DCF Model – Other Projected and Historical Growth Rates8

Schedule BHF-8 Bond Ratings, Beta, and Market Capitalization9

Schedule BHF-9 Capital Asset Pricing Model10

Schedule BHF-10 Risk Premium Method – LDC Authorized Rates of Return on Equity11

Schedule BHF-11 Comparable Earnings Method12

Appendix A Experience and Qualifications13

Appendix B Prior Testimony14

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I. INTRODUCTION



A. Bruce H. Fairchild, 3907 Red River, Austin, Texas 78751.3

Q. BY WHOM ARE YOU EMPLOYED AND IN WHAT POSITION.4

A. I am a principal in Financial Concepts and Applications, Inc. (FINCAP), a firm engaged5

in financial, economic, and policy consulting to business and government.6

A. Qualifications

Q. DESCRIBE YOUR EDUCATIONAL BACKGROUND, PROFESSIONAL7QUALIFICATIONS, AND PRIOR EXPERIENCE.8

A. I hold a BBA degree from Southern Methodist University and MBA and PhD degrees9

from the University of Texas at Austin. I am also a Certified Public Accountant. My10

previous employment includes working in the Controller's Department at Sears, Roebuck11

and Company and serving as Assistant Director of Economic Research at the Public12

Utility Commission (“PUC”) of Texas. I have also been on the business school faculties13

at the University of Colorado at Boulder and the University of Texas at Austin, where I14

taught undergraduate and graduate courses in finance and accounting.15

Q. BRIEFLY DESCRIBE YOUR EXPERIENCE IN UTILITY-RELATED16MATTERS.17

A. While at the Texas PUC, I assisted in managing a division comprised of approximately18

twenty-five professionals responsible for financial analysis, cost allocation and rate de-19

sign, economic and financial research, and data processing systems. I testified on behalf20

of the PUC staff in numerous cases involving most major investor-owned and coopera-21

tive electric, telephone, and water/sewer utilities in the state regarding a variety of finan-22

cial, accounting, and economic issues. Since forming FINCAP in 1979, I have partici-23

pated in a wide range of analytical assignments involving utility-related matters on behalf24

of utilities, industrial consumers, municipalities, and regulatory commissions. I have also25

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prepared and presented expert testimony before a number of regulatory authorities ad-1

dressing revenue requirements, cost allocation, and rate design issues for gas, electric,2

telephone, and water/sewer utilities. I have been a frequent speaker at regulatory confer-3

ences and seminars and have published research concerning various regulatory issues. A4

resume that contains the details of my experience and qualifications is attached as Ap-5

pendix A, with Appendix B listing my prior testimony before regulatory agencies since6

leaving the Texas PUC.7

B. Overview


A. The purpose of my testimony is to recommend an overall rate of return to apply to the9

original cost invested capital of West Texas Gas, Inc. (“WTG”).10

Q. WHAT IS THE ROLE OF THE RATE OF RETURN IN SETTING A UTILITY'S11RATES?12

A. The rate of return serves to compensate investors for the use of their capital to finance the13

plant and equipment necessary to provide utility service to customers. Investors only14

commit money in anticipation of earning a return on their investment commensurate with15

that from other investment alternatives having comparable risks. Consistent with both16

sound regulatory economics and the standards specified in the U.S Supreme Court cases17

of Bluefield Water Works & Improvement Co. (1923) and Hope Natural Gas Co. (1944),18

rates should provide the utility a reasonable opportunity to earn a rate of return sufficient19

to: 1) fairly compensate capital presently invested in the utility, 2) enable the utility to20

offer a return adequate to attract new capital on reasonable terms, and 3) maintain the21

utility's financial integrity.22

Q. IN GENERAL, HOW DID YOU GO ABOUT DEVELOPING A FAIR RATE OF23RETURN FOR WTG?24

A. My evaluation began with a brief review of the operations and finances of WTG and gen-25

eral conditions in the natural gas industry and capital markets. With this background, I26

next developed a mix of investor-supplied capital (i.e., debt and common equity) to be27

used as weightings in calculating an overall rate of return. An average cost of debt appli-28

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cable to the debt component of the capital structure was then calculated. Next, various1

analyses were conducted to determine a fair rate of return on common equity (“ROE”).2

These included applications of the discounted cash flow (“DCF”) model, capital asset3

pricing model (“CAPM”), risk premium method, and comparable earnings method to de-4

velop a cost of equity range. From this range, I selected my recommended ROE giving5

consideration to the outlook for capital costs. Finally, the above findings were combined6

to calculate my recommended overall rate of return for WTG.7

C. Summary of Conclusions

Q. WHAT IS YOUR RATE OF RETURN RECOMMENDATION?8

A. As summarized on Schedule BHF-1, I recommend that WTG be authorized an overall9

rate of return of 9.03%. Although WTG is actually financed with approximately 18%10

debt and 82% common equity, I recommend that capital structure ratios of 40% debt and11

60% equity, which are consistent with natural gas local distribution company (“LDC”)12

industry norms, be used for present purposes. I correspondingly recommend that the debt13

component of this capital structure be assigned an industry average embedded cost of14

5.32%. Finally, I recommend that WTG be allowed an ROE of 11.50%, which is based15

on a proxy group of publicly traded LDCs, adjusted to reflect investors’ higher required16

return due to WTG’s greater risk and smaller size.17

II. FUNDAMENTAL ANALYSES

Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR TESTIMONY?18

A. As a predicate to subsequent quantitative analyses, this section briefly reviews the opera-19

tions and finances of WTG and compares it to the major LDCs in Texas. It also exam-20

ines the natural gas distribution industry along with conditions in the capital markets and21

U.S. economy.22

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A. West Texas Gas, Inc.

Q. BRIEFLY DESCRIBE WTG.1

A. WTG is primarily a natural gas distribution company, although it also has ownership in-2

terests in entities that perform natural gas marketing, transmission, and gathering and3

processing, oil and gas production, and refined products distribution. Formed in 1976,4

WTG is headquartered in Midland, Texas. WTG’s gas distribution operations consist of5

some 5,000 miles of mainlines that currently serve approximately 27,000 customers pri-6

marily situated in West Texas and the Oklahoma Panhandle.7

Q. BRIEFLY DESCRIBE WTG’S FINANCIAL POSITION.8

A. At December 31, 2011, WTG’s balance sheet reflected approximately $155 million in9

total assets, of which approximately $23 million was investments in non-gas distribution10

entities. During 2011, WTG recorded 2011 operating revenues of almost $180 million.11

Except for a relatively small amount of short-term bank debt and a note payable to an af-12

filiate, WTG is mostly financed with equity, with its common stock being wholly owned13

and privately held by a single individual. Because WTG has no long-term bonds out-14

standing, it is not rated by any of the major bond rating agencies.15

Q. HOW DOES WTG COMPARE WITH THE OTHER MAJOR LDCS IN TEXAS?16

A. In the following table, WTG is compared to the gas distribution operations of the three17

largest LDCs serving Texas – Atmos Energy Corporation (through its Mid-Tex and West18

Texas divisions), CenterPoint Energy, Inc. (through its Entex and Arkla divisions), and19

ONEOK, Inc. (through its Texas Gas Service division). Besides their Texas operations,20

Atmos, CenterPoint, and ONEOK also have substantial gas distribution activities in other21

states across the U.S. (dollar amounts in millions):22

Customers Revenues Net PlantCompany Texas U.S. Texas U.S. Texas U.S.

Atmos 1,859,890 3,161,610 $ 1,439 $ 2,689 $ 2,076 $ 4,745CenterPoint 1,563,892 3,282,487 $ 989 $ 3,374 $ 919 $ 4,535ONEOK 607,513 2,089,930 $ 308 $ 1,621 $ 518 $ 3,392

WTG 22,224 26,992 $ 168 $ 176 $ 88 $ 93

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Q. WHAT ARE THE IMPLICATIONS OF THE ABOVE COMPARISON FOR1DETERMINING WTG’S RATE OF RETURN?2

A. The significance of the above table is that, while WTG may be the fourth largest LDC in3

Texas, it is not in the same financial league as Atmos, Entex, and Texas Gas Service.4

This size difference affects various aspects of WTG’s finances, which will be discussed5

later in my testimony. Suffice it to say, that WTG cannot obtain capital from the same6

sources and on the same terms as large LDCs in Texas and elsewhere. This fundamental7

fact must be recognized and accounted-for in determining a fair rate of return for WTG.8

B. Natural Gas Distribution Industry

Q. PLEASE DESCRIBE THE NATURAL GAS DISTRIBUTION INDUSTRY.9

A. LDCs typically transport, deliver, and sell natural gas from receipt points on inter- and10

intrastate pipelines to households and businesses. LDCs often have an exclusive right to11

operate in a specified geographic area, with their rates and operations being subject to the12

jurisdiction of state or local regulatory authorities. Historically, LDCs provided only13

“bundled” service, which included the transportation, distribution, and natural gas itself,14

although a number now allow customers to choose their own gas supplier, with the LDC15

providing the delivery and service of that gas. Such structural changes, which have oc-16

curred on both the demand and supply sides, have eroded the traditional monopoly status17

of many gas utilities, with LDCs experiencing "bypass" as large commercial and indus-18

trial customers seek to acquire gas supplies at the lowest possible prices and, in the pro-19

cess, abandoned traditional "full-service" utility suppliers.20

Q. WHAT BUSINESS RISKS DO LDCS FACE THAT ARE OF CONCERN TO21INVESTORS?22

A. LDCs face a variety of market, operating, capital-related, and regulatory risks. The natu-23

ral gas business is increasingly competitive and complex, with LDCs having to vie with24

electric companies, oil and propane suppliers, and, in some cases, energy marketers and25

trading companies. Moreover, past volatility in natural gas prices may negatively impact26

customers’ perception of natural gas. The demand for natural gas is highly weather sen-27

sitive (due both to normal variations and severe conditions) and seasonal, with energy ef-28

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ficiency and technological advances adversely affecting growth over time, especially in1

the residential sector. The financial results of LDCs are heavily dependent on general2

economic conditions, not only in terms of the overall activity of businesses but also in the3

growth of households and use per customer. Consider, for example, the following obser-4

vation by The Value Line Investment Survey (Value Line) in its September 7, 2012 dis-5

cussion of the Natural Gas Utility industry:6

Unfortunately, the economy remains constrained by a struggling housing7sector and persistently high unemployment (hovering around 8% at pre-8sent). The lingering European debt crisis has added more fuel to the fire.9It is also important to mention that there are some tax hikes and spending10cuts that are set to take effect by yearend unless the current Congress can11take control and, hopefully, address these issues. In this difficult operating12environment, customers have been focusing on energy conservation,13which, if course, acts as a restraint on the revenues of the companies in-14cluded in the Natural Gas Utility Industry. (p. 539)15

With respect to operations, gas distribution inherently involves a variety of haz-16

ards and operating risks, including leaks, accidents, and third-party damages. Many17

LDCs are faced with substantial known and unknown environmental costs (e.g., clean-up18

of manufactured gas plant sites) and post-retirement employee costs (e.g., pensions and19

medical benefits). Inflation and other increases could adversely impact LDCs’ ability to20

control operating expenses and costs, and interruptions in gas supply, strikes, natural dis-21

asters, security breaches, and terrorist activities could disrupt or shutdown operations.22

Finally, most LDCs are involved in ongoing legal or administrative proceedings before23

courts and governmental bodies related to a variety of matters (e.g., general claims, taxes,24

environmental issues, billing, credit issues, and collection disputes), which could result in25

detrimental outcomes.26

Regarding capital-related risks, virtually all LDCs are facing significant infra-27

structure improvements to meet customer service requirements and improve system relia-28

bility, as well as satisfy a number of government-mandated safety initiatives. The ability29

of LDCs to fund these and other capital expenditures is affected by a variety of factors,30

including regulatory decisions, maintenance of a sufficient bond rating, capital market31

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conditions (e.g., interest rates), and availability of credit facilities and access to capital1

markets. In addition, LDCs’ ability to retain and attract capital is subject to changes in2

state and federal tax laws and accounting standards, which could adversely affect their3

cash flows and financial condition.4

Finally, because most aspects of an LDC’s operations (e.g., rates; operating terms5

and conditions of service; types of services offered; construction of new facilities; the in-6

tegrity, safety, and security of facilities and operations; acquisition, extension, or aban-7

donment of services or facilities; reporting and information posting requirements;8

maintenance of accounts and records; and relationships with affiliate companies) are sub-9

ject to government oversight, investors are understandably concerned with rate, safety,10

and environmental regulation. Potential changes in laws, regulations, and policies, as11

well as the inherent uncertainty surrounding regulatory decisions, all represent significant12

risks to LDCs.13

C. Capital Markets

Q. WHAT HAS BEEN THE PATTERN OF INTEREST RATES OVER THE LAST14TWO DECADES?15

A. Average long-term public utility bond rates, the monthly average prime rate, and inflation16

as measured by the Consumer Price Index (CPI) since 1990 are plotted in the graph be-17

low. After rising to approximately 10% in mid-1990, the average yield on long-term18

public utility bonds generally fell because of monetary and fiscal policies designed to19

keep the economy growing. This ended abruptly with the 2008 financial market melt-20

down and global recession. Investors became exceedingly risk averse, causing interest21

rates on corporate bonds to spike, while government policies pushed down the prime rate22

and depressed economic conditions and lower energy prices reduced inflation.23

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-4%

-2%

0%

2%

4%

6%

8%

10%

12%

J-9 0 J -9 2 J -9 4 J -9 6 J -98 J -00 J-0 2 J-0 4 J-0 6 J -0 8 J-10 J -12

Prime Rate

Average Public Utility

Inflat ion

Q. HOW HAS THE MARKET FOR COMMON EQUITY CAPITAL PERFORMED?1

A. Between 1990 and early 2000, stock prices climbed steadily higher as the longest bull2

market in United States history continued unabated. In mid-2000, mounting concerns3

over prospects for future growth, particularly for firms in the high technology and tele-4

communications sectors, pushed equity prices lower, in some cases precipitously. Com-5

mon stock prices generally recovered and reached record highs, buoyed in large part by6

widespread acquisition activity, until the capital market crisis and global recession hit in7

2008. Stock prices tumbled by some 40%, and although they have largely recovered, the8

market remains volatile, with share values routinely changing in full percentage points9

during a single day’s trading. The graph below plots the performances of the Dow-Jones10

Industrial Average, the S&P 500, and the Dow Jones Utility Average since 1990 (the lat-11

ter two indices were scaled for comparability).12

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500

2,500

4,500

6,500

8,500

10,500

12,500

14,500

16,500

J -90 J -92 J -9 4 J -96 J-98 J -00 J -02 J -0 4 J-06 J -08 J -10 J -12

Ind

ex

S&P 500 (x10)

DJIA

DJUA (x10)

Q. WHAT IS THE OUTLOOK FOR THE U.S. ECONOMY?1

A. While there are signs that the U.S. economy is beginning to recover from the Great Re-2

cession, unemployment remains high, business and consumer spending continues to be3

cautious, and economic activity is guarded. There are questions whether the federal4

stimulus package and the actions by the Federal Reserve Board (“Fed”) to keep interest5

rates low are having their desired effects on economic recovery. Indeed, the outlook re-6

mains tenuous, with persistent stock and bond price volatility providing tangible evidence7

of the uncertainties faced by the U.S. economy.8

Q. HOW DO THESE ECONOMIC UNCERTAINTIES AFFECT LDCS?9

A. Uncertainties over an economic recovery heighten the risks faced by LDCs, which, as10

described earlier, face a variety of operating and financial challenges. Current levels of11

unprecedented federal deficit spending and government borrowing portend higher infla-12

tion and interest rates, which will place additional pressure on the adequacy of existing13

service rates. The capital markets continue to be in a state of turmoil, affecting both the14

availability and cost of debt and equity that utilities rely on to fund their capital spending15

requirements. Overshadowing everything, the U.S. and global economies remain precar-16

ious, which only increases the risks faced by the natural gas industry, including LDCs.17

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III. CAPITAL STRUCTURE AND COST OF DEBT

Q. WHAT IS THE PURPOSE OF THIS SECTION?1

A. This section discusses the implications of capital structure on risk and rate of return, and2

examines the capital structures maintained by WTG and other LDCs. Based on these3

analyses, I recommend capital structure ratios for use in determining WTG’s rate of4

return. This section also identifies a cost of debt to be applied to the debt component of5

the capital structure.6

A. Principles

Q. WHAT IS THE ROLE OF CAPITAL STRUCTURE IN SETTING A UTILITY'S7RATE OF RETURN?8

A. A utility's capital structure reflects the mix of capital – debt, preferred stock, and com-9

mon equity – used to finance the utility’s assets. The proportions of a utility's total capi-10

talization attributable to each source of capital are typically used to weight the costs of11

debt and preferred stock, and rate of return on common equity, in calculating an overall12

rate of return.13

Q. WHY DOES THIS WEIGHTING MATTER?14

A. The capital structure ratios determine how much weight is given to a particular source of15

capital and, because the costs of debt and preferred stock, and the rate of return on com-16

mon equity, are not the same, the weighted average cost, or overall rate of return, of all17

sources of capital is affected.18

Q. HOW DOES THE USE OF GREATER AMOUNTS OF DEBT AFFECT THE19RATES OF RETURN REQUIRED BY INVESTORS?20

A. A higher debt ratio, or lower common equity ratio, translates into increased financial risk21

for all investors. A greater amount of debt, and preferred stock, means more investors22

have a senior claim on available cash flow, thereby reducing the certainty that each will23

receive his contractual payments. This, in turn, increases the risks to which lenders and24

preferred stockholders are exposed, and they require correspondingly higher rates of in-25

terest and dividends, respectively, for bearing this increased risk. From common share-26

holders' viewpoint, higher debt and preferred stock ratios mean that there are proportion-27

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ately more investors ahead of them, thereby increasing the uncertainty as to the amount1

of cash flow, if any, that will remain. Again, in accordance with the fundamental2

risk-return trade-off principle to be discussed in greater detail later, common shareholders3

require a correspondingly higher rate of return to compensate them for bearing the greater4

financial risk associated with a lower common equity ratio.5

B. Capital Structure Ratios

Q. WHAT SOURCES OF CAPITAL ARE USED TO FINANCE WTG’S6INVESTMENT IN UTILITY PLANT?7

A. As described earlier, WTG’s investment in utility assets is financed mostly with common8

equity. As shown on the table below, at June 30, 2012, WTG’s permanent capitalization9

consisted of a 5-year $13 million bank loan, a $12.5 million note payable due in 2017 to10

an affiliated company, and the remainder common equity:11

Capital Component Amount % of Total

Bank Loan $ 13,000,000 9.10%Note Payable 12,500,000 8.75%Common Equity 117,391,942 82.15%

Total $ 142,891,942 100.00%

Thus, WTG’s capital structure ratios at test year-end were approximately 18% debt and12

82% equity.13

Q. HOW ARE LDCS NORMALLY FINANCED?14

A. Based on data published by the American Gas Association (“AGA”), the gas distribution15

industry maintained the following composite structure ratios between 2006 and 2010:16

Capital Component 2010 2009 2008 2007 2006

Long-term Debt 40.3% 42.2% 43.7% 41.7% 43.2%Preferred Stock 0.9% 0.8% 1.1% 0.8% 0.9%Common Equity 58.8% 57.0% 55.2% 57.5% 55.9%

Total 100.0% 100.0% 100.0% 100.0% 100.0%

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The table above indicates that gas distribution companies currently finance their invest-1

ment in utility plant with approximately 41% long-term debt and preferred stock and 59%2

common equity.3

Alternatively, Schedule BHF-2 displays the capital structure ratios over the 2008-4

2011 period and at June 30, 2012 for a group of nine LDCs with publicly traded common5

stock. These are the firms included in Value Line’s Natural Gas Utility industry that are6

predominantly involved in natural gas distribution. The average capital structure ratios7

for this group of LDCs are summarized below:8

Capital Component 6/30/2012 2011 2010 2009 2008

Long-term Debt 43.3% 43.5% 44.6% 45.5% 44.9%Preferred Stock 0.2% 0.2% 0.2% 0.2% 0.2%Common Equity 56.5% 56.4% 55.2% 54.4% 54.9%

Total 100.0% 100.0% 100.0% 100.0% 100.0%

As evidenced above, there has been a general trend by these LDCs to rely less on debt9

financing and increase the amount of common equity used to finance gas utility plant, to10

where they are currently financed with an average of approximately 44% debt and 56%11

equity. Around the June 30, 2012 averages, the individual LDC debt ratios ranged from12

31% to 51%, with equity ratios extending from a low 49% to high of almost 68%.13

Q. WHAT DO YOU CONCLUDE FROM THESE DATA?14

A. A comparison of WTG’s capital structure ratios with those maintained by the AGA and15

Value Line publicly traded LDC groups shows that WTG’s approximately 18% debt and16

82% equity does not comport with industry averages of approximately 41%-43% debt17

and 57-59% equity.18

Q. WHY ARE WTG’S CAPITAL STRUCUTRE RATIOS NOT CONSISTENT WITH19LDC INDUSTRY NORMS?20

A. As a relatively small firm, WTG does not have access to long-term debt capital in the21

same way that the large LDCs comprising the AGA and Value Line groups do. As a re-22

sult, common equity is about the only permanent capital available to a smaller utility such23

as WTG to finance its investment in long-lived gas utility plant.24

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Q. PLEASE EXLAIN WHY A UTILITY LIKE WTG DOES NOT HAVE THE SAME1ACCESS TO DEBT CAPITAL AS A LARGE LDC.2

A. Most large LDCs obtain debt capital by selling bonds in the public debt markets. If WTG3

were to attempt to finance itself consistent with industry norms, it would need to sell4

some $50 million in bonds. While a sizeable amount, this would be a small debt issue by5

typical LDC standards (e.g., ONEOK’s last bond offering was for $700 million and At-6

mos’s was for $400 million). As WTG’s first (and likely only) bond issue, a public offer-7

ing would entail considerable administrative costs (e.g., legal fees, bond ratings, and un-8

derwriting expenses). Additionally, the bonds would almost certainly rated below in-9

vestment grade and carry an illiquidity premium because they would not be widely traded10

after being sold. For these reasons, a public offering of long-term bonds is generally not11

regarded as a practical or cost-effective source of debt for a utility the size of WTG.12

While smaller businesses often rely on bank loans for debt capital, such commer-13

cial credit is not particularly well-suited to financing a gas utility. Besides typically car-14

rying variable rate interest rates (as does WTG’s bank loan), bank loans are normally rel-15

atively short-term, requiring frequent renegotiation and renewal. Meanwhile, the private16

placement of notes with financial institutions (e.g., insurance companies and pension17

plans) typically results in a variety of restrictions (e.g., mortgage requirements, minimum18

coverage ratios, dividend limits, asset sale and acquisition conditions, and letter of credit19

requirements) that increase the cost of the debt and limit the utility’s operating and finan-20

cial flexibility. Additionally, this type of debt is usually only medium-term in length, so21

it too is an imperfect source of debt to finance the long-lived assets of a utility.22

Q. WHAT CAPITAL STRUCTURE DO YOU RECOMMEND BE USED TO23CALCUALTE WTG’S RATE OF RETURN?24

A. Because WTG does not have ready access to long-term debt to finance its gas utility as-25

sets, its actual capital structure of approximately 18% debt and 82% equity could reason-26

ably be used for developing its rate of return. However, because this capital structure27

does not reflect how LDCs are generally financed, I recommend that WTG’s rate of re-28

turn be based on imputed, or hypothetical, capital structure ratios of 40% debt and 60%29

equity. These imputed capital structure ratios are consistent with LDC industry norms30

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and give customers the benefits of less expensive and tax deductible financing that, alt-1

hough not reflective of WTG’s actual capital structure, are representative of typical LDC2

financing.3

C. Cost of Debt

Q. WHAT COST OF DEBT DO YOU RECOMMEND BE ASSIGNED TO THE 40%4DEBT PORTION OF YOUR RECOMMENDED CAPITAL STRUCTURE?5

A. Consistent with the use of industry capital structure ratios, the interest rate assigned to the6

debt component should reflect the cost of long-term debt. As indicated above, if WTG7

were to attempt to issue bonds, they would almost certainly be rated below investment8

grade. During August 2012, the Fed reports that the average yield on double-B and sin-9

gle-B corporate bonds was 5.25% and 6.65%, respectively. While an interest rate from10

the middle or upper end of this range could be reasonably assigned to the debt imputed to11

WTG, I recommend that the average embedded cost of debt of the LDCs in the Value12

Line proxy group at June 30, 2012 of 5.32% (Schedule 3) be used for present purposes.13

III. RATE OF RETURN ON EQUITY

Q. WHAT IS THE PURPOSE OF THIS SECTION?14

A. The purpose of this section of my testimony is to determine a cost of equity range for15

WTG. It begins by introducing the cost of equity concept, explaining the risk-return16

tradeoff principle fundamental to capital markets, and discussing the importance of using17

multiple approaches to estimate the cost of equity. The DCF model is then developed18

and applied to a group of publicly traded LDCs to estimate their costs of equity, which is19

then adjusted to reflect WTG’s greater risk and smaller size. Next, the CAPM is de-20

scribed and alternative cost of equity estimates developed using this method. The cost of21

equity is also estimated using the risk premium method based on authorized ROEs and22

the comparable earnings method applied. The results of these analyses are combined to23

arrive at a cost of equity range for WTG, from which my recommended ROE is selected24

in the next section.25

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A. Cost of Equity Concept

Q. HOW IS A RETURN ON COMMON EQUITY CUSTOMARILY DETERMINED?1

A. Unlike debt capital, there is no contractually guaranteed return on common equity capital,2

since shareholders are the residual owners of the utility. Nonetheless, common equity in-3

vestors still require a return on their investment, with the "cost of equity" being the min-4

imum rent that must be paid for the use of their money.5

Q. WHAT FUNDAMENTAL ECONOMIC PRINCIPLE UNDERLIES THIS COST6OF EQUITY CONCEPT?7

A. The cost of equity concept is predicated on the notion that investors are risk averse and8

willingly accept additional risk only if they expect to be compensated for bearing that9

risk. In capital markets where relatively risk-free assets are available, such as U.S.10

Treasury securities, investors can be induced to hold more risky assets only if they are of-11

fered a premium, or additional return, above the rate of return on a risk-free asset. Since12

all assets compete with each other for investors' funds, riskier assets must yield a higher13

expected rate of return than less risky assets in order for investors to be willing to hold14

them.15

Given this risk-return tradeoff, the minimum required rate of return (k) from an16

asset (i) can be generally expressed as:17

ki = Rf + RPi18

where: Rf = Risk-free rate of return; and19RPI = Risk premium required to hold more risky asset i.20

Thus, the minimum required rate of return for a particular asset at any point in time is a21

function of: 1) the yield on risk-free assets, and 2) its relative risk, with investors de-22

manding correspondingly larger risk premiums for assets bearing greater risk.23

Q. IS THERE EVIDENCE THAT THE RISK-RETURN TRADEOFF PRINCIPLE24ACTUALLY OPERATES IN THE CAPITAL MARKETS?25

A. Yes. The risk-return tradeoff can be readily documented in certain segments of the capi-26

tal markets where required rates of return can be directly inferred from market data and27

generally accepted measures of risk exist. For example, bond yields are reflective of in-28

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vestors' expected rates of return, and bond ratings are indicative of the risk of fixed in-1

come securities. The observed yields on government securities and bonds of various rat-2

ing categories demonstrate that the risk-return tradeoff does, in fact, exist in the capital3

markets.4

To illustrate, average yields during August 2012 on 30-year U.S. Treasury bonds,5

investment grade public utility bonds of different ratings reported by Moody's, and below6

investment grade corporate bonds reported by the St. Louis Fed are shown in the follow-7

ing table. As evidenced there, as risk increases (measured by progressively lower bond8

ratings), the required rate of return (measured by yields) rises accordingly. Also shown9

are the indicated risk premiums over long-term government securities for the additional10

risk associated with each bond rating category.11

Bond and Rating

U.S. Treasury30-Year

Public UtilityAaABaa

CorporateBbBCcc

August 2012Yield

2.77%

3.65%4.00%4.88%

5.25%6.65%11.59%

Risk Premium Over30-Year Treasury

--

0.88%1.23%2.11%

2.48%3.88%8.82%

Q. DOES THE RISK-RETURN TRADEOFF OBSERVED WITH FIXED INCOME12SECURITIES EXTEND TO COMMON STOCKS AND OTHER ASSETS?13

A. Documenting the risk-return tradeoff for assets other than fixed income securities is com-14

plicated by two factors. First, there is no standard measure of risk applicable to all assets.15

Second, for most assets (e.g., common stock), required rates of return cannot be directly16

observed. Yet there is every reason to believe that investors exhibit risk aversion in de-17

ciding whether to hold common stocks and other assets, just as when choosing among18

fixed income securities. Accordingly, it is generally accepted that the risk-return tradeoff19

evidenced with long-term debt extends to all assets.20

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The extension of the risk-return tradeoff from assets with observable required1

rates of return (e.g., bonds) to other assets is represented by the concept of a "capital2

market line." In particular, competition between securities and among investors in the3

capital markets drives the prices of assets to equilibrium such that the expected rate of re-4

turn from each is commensurate with its risk. Thus, the expected rate of return from any5

asset is a risk-free rate of return plus a corresponding risk premium. This concept of a6

capital market line is illustrated in the graph below. The vertical axis represents required7

rates of return and the horizontal axis indicates relative riskiness, with the intercept of the8

capital market line being the risk-free rate of return.9

Capital Market Line

Q. IS THIS RISK-RETURN TRADEOFF LIMITED TO DIFFERENCES BETWEEN10FIRMS?11

A. No. The risk-return tradeoff principle applies not only to investments in different firms,12

but also to different securities issued by the same firm. As discussed earlier, the securi-13

ties issued by a utility vary considerably in risk because they have different characteris-14

tics and priorities. Long-term debt secured by a mortgage on property is senior among all15

capital in its claim on a utility's net revenues and is, therefore, the least risky because16

mortgage bondholders have a direct claim on the utility’s property. Following first mort-17

gage bonds are other debt instruments also holding contractual claims on the utility's net18

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revenues, such as debentures. The last investors in line are common shareholders. They1

only receive the net revenues, if any, that remain after all other claimants have been paid.2

As a result, the minimum rate of return that investors require from a utility's common3

stock, the most junior and riskiest of its securities, must be considerably higher than the4

yield offered by the utility's senior, long-term debt.5

Q. WHAT DOES THE ABOVE DISCUSSION IMPLY WITH RESPECT TO6ESTIMATING THE COST OF EQUITY FOR A UTILITY?7

A. Although the cost of equity cannot be observed directly, it is a function of the returns8

available from other investment alternatives and the risks to which the equity capital is9

exposed. Because it is unobservable, the cost of equity for a particular utility must be es-10

timated by analyzing information about capital market conditions generally, assessing the11

relative risks of the utility specifically, and employing various quantitative methods that12

focus on investors' required rates of return. These various quantitative methods typically13

attempt to infer investors' required rates of return from stock prices, by extrapolating in-14

terest rates, or through an analysis of other financial data.15

Q. DID YOU RELY ON A SINGLE METHOD TO ESTIMATE THE COST OF16EQUITY?17

A. No. Despite the theoretical appeal of, or precedent for, using a particular method to esti-18

mate the cost of equity, no single approach can be regarded as wholly reliable. There-19

fore, I used multiple methods to estimate the cost of equity. Indeed, it is essential that es-20

timates of investors' minimum required rate of return produced by one method be com-21

pared with those produced by other methods, and that all cost of equity estimates be re-22

quired to pass fundamental tests of reasonableness and economic logic.23

B. Discounted Cash Flow Model

Q. HOW ARE DCF MODELS USED TO ESTIMATE THE COST OF EQUITY?24

A. The use of DCF models to estimate the cost of equity is essentially an attempt to replicate25

the market valuation process which led to the price investors are willing to pay for a share26

of a company's common stock. It is predicated on the assumption that investors evaluate27

the risks and expected rates of return from all securities in the capital markets. Given28

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these expected rates of return, the price of each share of stock is adjusted by the market1

so that investors are adequately compensated for the risks to which they are exposed.2

Therefore, we can look to the market to determine what investors believe a share of3

common stock is worth, and by estimating the cash flows they expect to receive from the4

stock in the way of future dividends and stock price, their required rate of return can be5

mathematically imputed. In other words, the cash flows that investors expect from a6

stock are estimated, and given the stock’s current market price, we can "back-into" the7

discount rate, or cost of equity, investors presumably used in arriving at that price.8

Q. WHAT MARKET VALUATION PROCESS UNDERLIES DCF MODELS?9

A. DCF models are derived from a theory of valuation which posits that the price of a share10

of common stock is equal to the present value of the expected cash flows (i.e., future div-11

idends and stock price) that will be received while holding the stock, discounted at inves-12

tors' required rate of return, or the cost of equity. Notationally, the general form of the13

DCF model is as follows:14

te

t

te

t

ee K

P

K

D

K

D

K

DP

)1()1()1()1( 2

2

1

10

15

where: P0 = Current price per share;16Pt = Future price per share in period t;17Dt = Expected dividend per share in period t;18Ke = Cost of equity.19

Q. HAS THIS GENERAL FORM OF THE DCF MODEL CUSTOMARILY BEEN20SIMPLIFIED FOR USE IN ESTIMATING THE COST OF EQUITY IN RATE21CASES?22

A. Yes. In an effort to reduce the number of required estimates and computational difficul-23

ties, the general form of the DCF model has been simplified to a "constant growth" form.24

In order to convert the general form of the DCF model to the constant growth DCF mod-25

el, a number of assumptions must be made. These include:26

A constant growth rate for both dividends and earnings;27 A stable dividend payout ratio;28 The discount rate exceeds the growth rate;29

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A constant growth rate for book value and price;1 A constant earned rate of return on book value;2 No sales of stock at a price above or below book value;3 A constant price-earnings ratio;4 A constant discount rate (i.e., no changes in risk or interest rate5

levels and a flat yield curve); and6 All of the above extend to infinity.7

Given these assumptions, the general form of the DCF model can be reduced to the more8

manageable formula of:9

gK

DP

e 1

010

where: g = Investors’ long-term growth expectations.11

The cost of equity (“Ke”) can be isolated by rearranging terms:12

gP

DK e

0

113

The constant growth form of the DCF model recognizes that the rate of return to stock-14

holders consists of two parts: 1) dividend yield (D1/P0), and 2) growth (g). In other15

words, investors expect to receive a portion of their total return in the form of current div-16

idends and the remainder through price appreciation.17

While the constant growth form of the DCF model provides a more manageable18

formula to estimate the cost of equity, it is important to note that the assumptions re-19

quired to convert the general form of the DCF model to the constant growth form are20

never strictly met in practice. In some instances, where earnings are derived solely from21

stable activities, and earnings, dividends, and book value track fairly closely, the constant22

growth form of the DCF model may be a reasonable working approximation of stock val-23

uation. However, in other cases, where the circumstances cause the required assumptions24

to be severely violated, the constant growth DCF model may produce widely divergent25

and meaningless results. This is especially the case if the firm's earnings or dividends are26

unstable, or if investors are expecting the stock price to be affected by factors other than27

earnings and dividends.28

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Q. HOW DID YOU ESTIMATE THE COST OF EQUITY USING THE DCF1MODEL?2

A. Because WTG has no publicly traded common stock, the DCF model cannot be used to3

estimate its cost of equity directly. Therefore, I applied the constant growth form of the4

DCF model to the group of nine publicly traded LDCs identified earlier (Schedule BHF-5

2); namely, those firms included in Value Line’s Natural Gas Utility industry that are6

predominantly engaged in natural gas distribution.7

Q. HOW IS THE CONSTANT GROWTH FORM OF THE DCF MODEL8TYPICALLY USED TO ESTIMATE THE COST OF EQUITY?9

A. The first step in implementing the constant growth DCF model is to determine the ex-10

pected dividend yield (D1/P0) for the firm in question. This is usually calculated based on11

an estimate of dividends to be paid in the coming year divided by the current price of the12

stock.13

Q. HOW DID YOU CALCULATE THE DIVIDEND YIELD COMPONENT OF THE14CONSTANT GROWTH DCF MODEL FOR THE GAS UTILITY GROUP?15

A. Because estimating the cost of equity using the DCF model is an attempt to replicate how16

investors arrived at an observed stock price, all of its components should be contempora-17

neous. Price, dividend, and growth data from different points in time, or averaged over18

long time periods, violate the matching principle underlying the DCF model. Therefore,19

dividend yield was calculated by dividing an estimate of dividends to be paid by each of20

the LDCs in the group over the next twelve months, obtained from the index to Value21

Line’s September 7, 2012 edition, by the average closing price of each firm’s stock dur-22

ing the month of August 2012. The expected dividends, representative price, and result-23

ing dividend yield for each of the nine gas utilities are displayed on Schedule BHF-4. As24

also shown there, the average dividend yield for the industry group is 3.67%.25

Q. EXPLAIN HOW ESTIMATES OF INVESTORS' LONG-TERM GROWTH26EXPECTATIONS ARE CUSTOMARILY DEVELOPED FOR USE IN THE27CONSTANT GROWTH DCF MODEL.28

A. In constant growth DCF theory, earnings, dividends, book value, and market price are all29

assumed to grow in lockstep, and the growth horizon of the DCF model is infinite. But30

implementation of the DCF model is more than just a theoretical exercise; it is an effort31

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to replicate the mechanism investors used to arrive at observable stock prices. Therefore,1

the only “g” that matters in using the DCF model to estimate the cost of equity is that2

which investors expect and have embodied in current market prices.3

Q. WHAT DRIVES INVESTORS’ GROWTH EXPECTATIONS?4

A. Trends in earnings, which ultimately support future dividends and share price, play a piv-5

otal role in determining investors’ long-term growth expectations. The 5-year earnings6

growth projections by security analysts for each of the nine gas utilities reported by Value7

Line, Thomson Reuters’ Institutional Brokers Estimate System (I/B/E/S), and Zacks In-8

vestment Research (Zacks) are displayed on Schedule BHF-5, with the averages for the9

group being summarized in the following table:10

LDCGroup

Value Line 5.3%

I/B/E/S 4.6%

Zack’s 4.6%

Also shown on Schedule BHF-5 are the 10-year and 5-year historical earnings growth11

rates for each of the nine gas utilities, which average 6.4% and 5.2%, respectively.12

Q. HOW ELSE ARE INVESTOR EXPECTATIONS OF FUTURE LONG-TERM13GROWTH PROSPECTS FOR A FIRM OFTEN ESTIMATED FOR USE IN THE14CONSTANT GROWTH DCF MODEL?15

A. In DCF theory and practice, growth in book equity comes from the reinvestment of earn-16

ings within the business and the effects of external financing. Accordingly, conventional17

applications of the constant growth DCF model often examine the relationships between18

variables that determine the “sustainable” growth attributable to these two factors.19

Q. HOW IS A FIRM’S SUSTAINABLE GROWTH ESTIMATED?20

A. The sustainable growth rate is calculated by the formula:21

g = br + sv22

where “b” is the expected earnings retention ratio (one minus the dividend payout ratio),23

“r” is the expected rate of return earned on book equity, “s” is the percent of common eq-24

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uity expected to be issued annually as new common stock, and “v” is the equity accretion1

ratio. The “br” term represents the growth from reinvesting earnings within the firm2

while the “sv” term represents the growth from external financing. This external financ-3

ing growth results because existing shareholders share in a portion of any excess received4

from selling new shares at a price above book value.5

Q. WHAT GROWTH RATE DOES THE SUSTAINABLE GROWTH METHOD6SUGGEST FOR THE GAS UTILITY GROUP?7

A. The sustainable growth rate for each of the gas utilities in the industry group based on8

Value Line's projections for 2015-2017 is developed in Schedule BHF-6. As shown9

there, the sustainable growth method implies an average long-term growth rate for the gas10

utility group of 6.2%.11

Q. WHAT ARE OTHER PROJECTED AND HISTORICAL GROWTH RATES FOR12THE INDUSTRY GROUP?13

A. Schedule BHF-7 displays Value Line projected growth rates and 10- and 5-year historical14

growth rates in book value per share, dividends per share, and stock price for each of the15

nine gas utilities in the industry group. The averages for the LDC group range from 3.6%16

to 6.7%. Besides the fact that several of these growth rates, when combined with the17

group’s 3.67% dividend yield, imply implausible cost of equity estimates, the variation in18

these other growth rates results in them providing limited guidance as to the prospective19

growth that investors expect.20

Q. WHAT IS YOUR CONCLUSION AS TO THE GROWTH THAT INVESTORS21ARE EXPECTING FROM THE INDUSTRY GROUP?22

A. After excluding clearly unreliable indicators of growth, the plausible growth rates shown23

on Schedules BHF-5, BHF-6, and BHF-7 indicated a range for the LDC group of be-24

tween approximately 5.0% and 6.5%. Meanwhile, Yahoo Finance and Zacks report pro-25

jected earnings growth rates for their gas distribution industries of 8.06% and 8.7%, re-26

spectively. Taken together, I concluded that investors expect long-term growth from the27

LDC group in the 5.5% to 6.5% range.28

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Q. WHAT DCF COST OF EQUITY ESTIMATES DO THESE GROWTH RATE1RANGES IMPLY FOR THE GAS UTILITY GROUP?2

A. Summing the LDC group’s average dividend yield of approximately 3.7% with a 5.5% to3

6.5% growth rate range indicates a DCF cost of equity for the industry group of between4

9.2% and 10.2%.5

Q. IS THIS DCF COST OF EQUITY RANGE DIRECTLY APPLICABLE TO WTG?6

A. No. The 9.2% to 10.2% DCF cost of equity range developed above is for the group of7

nine LDCs with publicly-traded common stock that, as shown on Schedule BHF- 8, have8

an average bond rating, which is generally regarded as the most comprehensive indicator9

of a firm’s risk, of single-A. In contrast, as discussed earlier, if WTG were to have a10

bond rating, it would almost certainly be below investment grade, which means that it is a11

considerably more risky investment than the LDC group. Similarly, as will be discussed12

more completely in the next section on the CAPM, it is well accepted in the financial lit-13

erature that investors require a higher return from smaller firms than from larger firms, all14

other things equal. Schedule BHF-8 shows that the average market capitalization of the15

LDCs in the proxy group is over $2.2 billion versus WTG with a book capitalization of16

approximately $117 million. Accordingly, to make the LDC industry DCF cost of equity17

range applicable to WTG, an adjustment is necessary to account for the greater invest-18

ment risk and smaller size of WTG relative to the firms in the LDC group.19

Q. WHAT IS THE MAGNITUDE OF THE ADJUSTMENT NECESSARY TO20ACCOUNT FOR THE GREATER RISK AND SMALLER SIZE OF WTG21VERSUS THE LDC INDUSTRY GROUP?22

A. Determining the additional return investors require for investing in the common stock of23

a below investment grade rated, smaller utility versus a less risky single-A, larger utility24

is complicated by the fact that the cost of equity is unobservable. However, the minimum25

risk premium shareholders require for bearing the additional risks can be measured as the26

difference, or spread, between the yields on double-B or single-B bonds versus single-A27

rated utility bonds. As shown in the table presented earlier, the August 2012 yield on28

double-B and single-B rated corporate bonds was 5.25% and 6.65%, respectively, where-29

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as the yield on single-A utility bonds was 4.00%. Thus, the cost of equity to WTG for its1

greater risk is, at a minimum, 125 to 265 basis points higher than for the LDC group.2

Meanwhile, Morningstar's (formerly Ibbotson Associates) Stocks, Bonds, Bills3

and Inflation publishes a schedule of rate of return premiums to account for differences in4

the market capitalization of a firm’s equity relative to the S&P 500. For the LDC group5

with an average market capitalization of $2.2 billion, the size premium is 1.74%. Alt-6

hough WTG does not have a market capitalization per se because its stock is not publicly7

traded, the size premium for firms with common stock worth between approximately8

$207 and $423 million is 2.80% and for firms with a market capitalization of between9

$129 and $207 million it is 4.34%. Thus, the return premium necessary to account for10

WTG’s smaller size relative to the LDC group is at least 1.06% (i.e., 2.80% minus the11

LDCs’ 1.74%) and more likely 2.60% (i.e., 4.34% minus the LDCs’ 1.74%).12

Q. WHAT COST OF EQUITY FOR WTG IS IMPLIED BY YOUR DCF ANALYSIS?13

A. Although the 1.25% to 2.65% premium for risk differences and the minimum 1.06% to14

2.60% premium for size differences are theoretically additive, for present purposes, I15

have adjusted the DCF cost of equity range for the LDC group by 1.5% to account for16

both factors. In turn, adding a 1.5% adjustment for WTG’s greater risk and smaller size17

to the 9.2% to 10.2% percent DCF cost of equity range for the LDC industry group pro-18

duces a DCF cost of equity range for WTG of at least 10.7% to 11.7%.19

C. Capital Asset Pricing Model

Q. HOW ELSE DID YOU ESTIMATE THE COST OF EQUITY?20

A. The cost of equity to WTG was also estimated using the CAPM, which is a theory of21

market equilibrium that serves as the basis for current financial education and manage-22

ment. Under the CAPM, investors are assumed fully diversified, so that the relevant risk23

of an individual asset (e.g., common stock) is its volatility relative to the market as a24

whole, which is measured using a "beta" coefficient. Beta reflects the tendency of a25

stock's price to follow changes in the market, with stocks having a beta less than 1.00 be-26

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ing considered less risky and stocks with a beta greater than 1.00 being regarded as more1

risky. The CAPM is mathematically expressed as:2

Rj = Rf +βj (Rm - Rf)3

where: Rj = required rate of return for stock j;4Rf = risk-free interest rate;5Rm = expected return on the market portfolio; and6

βj = beta, or systematic risk, for stock j.7

While the CAPM is not without controversy, it is routinely referenced in the financial8

literature and regulatory proceedings, and firms’ beta values are widely reported.9

Q. HOW DID YOU APPLY THE CAPM?10

A. I applied the CAPM using two methods to determine the risk premium for the market as a11

whole, or the (Rm - Rf) term in the CAPM formula. The first was based on historical12

rates of return and the second was based on forward-looking estimates of investors’ re-13

quired rates of return. In both instances, the companies included in the S&P 500 index14

were used as a proxy for the market portfolio and the 30-year U.S. Treasury bond served15

as the risk-free investment.16

Q. PLEASE DESCRIBE THE FIRST METHOD BASED ON HISTORICAL RATES17OF RETURN.18

A. Under the historical rate of return approach, equity risk premiums are calculated by first19

measuring the rate of return (including dividends and capital gains and losses) actually20

realized on an investment in common stocks over historical time periods. The historical21

return on bonds is then subtracted from that earned on common stocks to measure equity22

risk premiums. Widely used in academia, the historical rate of return approach is based23

on the assumption that, given a sufficiently large number of observations over long his-24

torical periods, average market rates of return will converge to investors' required rates of25

return. From a more practical perspective, investors may base their expectations for the26

future on, or may have come to expect that they will earn, rates of return corresponding to27

those in the past.28

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Q. WHAT IS THE MARKET RISK PREMIUM BASED ON HISTORICAL RATES1OF RETURN?2

A. Perhaps the most exhaustive study of historical rates of return, and the one most frequent-3

ly cited in regulatory proceedings, is that contained in Morningstar's Stocks, Bonds, Bills4

and Inflation. In their 2012 Valuation Yearbook, Morningstar reports that the annual rate5

of return realized on the S&P 500 averaged 11.80% over the period 1926 through 2011,6

while the annual average income rate of return on 30-year Treasury bonds over this same7

period averaged 5.20%. Thus, the market risk premium based on historical average an-8

nual rates of return is 6.60%.9

Q. PLEASE DESCRIBE THE SECOND METHOD BASED ON FORWARD-10LOOKING REQUIRED RATES OF RETURN.11

A. Consistent with the CAPM being an expectational (i.e., forward-looking) model, the se-12

cond method estimated the market risk premium using current indicators of investors’ re-13

quired rates of return. For the market portfolio, the cost of equity was estimated by ap-14

plying the DCF model to the firms in the S&P 500 paying cash dividends, with each15

firm’s dividend yield and growth rate being weighted by its proportionate share of total16

market value. The expected dividend yield for each firm was obtained from Value Line,17

with the expected growth rate being based on the earnings forecasts published for each18

firm by Value Line, I/B/E/S, and Zacks. As shown in footnote (b) on Schedule BHF-9,19

summing the 2.60% expected dividend yield for this market group, which is composed20

primarily of non-regulated firms, with the average Value Line, I/B/E/S, and Zacks pro-21

jected growth rate of 10.57% produced a required rate of return from the market portfolio22

(Rm) of 13.17%.23

Q. WHAT IS THE MARKET RISK PREMIUM BASED ON FORWARD-LOOKING24REQUIRED RATES OF RETURN?25

A. From the 13.17% required rate of return on the market portfolio, a market risk premium26

was calculated by subtracting the average yield on 30-year Treasury bonds during August27

2012 of 2.77%. This produced a forward-looking market risk premium of 10.40%.28

of 40


Q. WHAT WAS THE NEXT STEP IN APPLYING THE CAPM?1

A. Having calculated market risk premiums of 6.60% and 10.40% using historical rates of2

return and forward-looking rates of return, respectively, the next step was to calculate3

specific risk premiums for the LDC industry group. Because WTG does not have a pub-4

lished beta, the LDC group’s average beta of 0.66, calculated using firm betas obtained5

from Value Line and shown on Schedule BHF-8, was used as a proxy for WTG’s beta.6

Multiplying the alternative market risk premium estimates by a beta of 0.66 produced risk7

premiums of 4.36% and 6.87%.8

Q. WHAT ARE THE RESULTING THEORETICAL CAPM COST OF EQUITY9ESTIMATES FOR WTG?10

A. As developed in Schedule BHF-9, summing the risk premiums of 4.36% and 6.87% with11

the 30-year Treasury bond yield of 2.77% produced theoretical CAPM cost of equity es-12

timates for WTG of 7.13% and 9.64%.13

Q. ARE THESE THEORETICAL CAPM COST OF EQUITY ESTIMATES14ACCURATE MEASURES OF INVESTORS’ REQUIRED RATE OF RETURN15FROM WTG?16

A. No. These cost of equity estimates are based on CAPM theory. However, as referred to17

earlier and explained by Morningstar in its 2012 Valuation Yearbook edition of Stocks,18

Bonds, Bills and Inflation:19

One of the most remarkable discoveries of modern finance is that of a re-20lationship between firm size and return. The relationship cuts across the21entire size spectrum but is most evident among smaller companies, which22have higher returns on average than larger ones. (page 85, footnote omit-23ted)24

In other words, in addition to the systematic risk measured by beta, investors’ required25

rate of return depends on a firm’s relative size. To account for this, Morningstar has de-26

veloped size premiums that need to be added to the theoretical CAPM cost of equity es-27

timates to account for the level of a firm’s market capitalization in determining the28

CAPM cost of equity.29

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Q. WHAT ARE THE CAPM COST OF EQUITY ESTIMATES FOR WTG ONCE1SIZE EFFECTS ARE TAKEN INTO ACCOUNT?2

A. As discussed in the previous section, WTG’s market capitalization is not known because3

its stock is not publicly traded. However, based on its approximately $114 million book4

equity presented earlier, Morningstar’s relevant size premiums are 2.80% for firms with a5

market capitalization of between approximately $207 and $423 million and 6.10% for6

firms having common stock valued at less than $297 million. This means that the theo-7

retical CAPM cost of equity estimates need to be increased by a least 2.80%, and poten-8

tially up to 4.34%, to account for WTG’s small size relative to the market as a whole. As9

shown on Schedule BHF-9, increasing the theoretical CAPM cost of equity estimates for10

WTG by a minimum size premium of 2.80% results in CAPM cost of equity estimates,11

based on historical rates of return and forward-looking rates of return, of at least 9.93%12

and 12.44%, respectively.13

D. Risk Premium Method

Q. HOW ELSE DID YOU ESTIMATE THE COST OF EQUITY?14

A. The cost of equity to WTG was also estimated using a risk premium method based on15

ROEs previously authorized LDCs by state regulatory commissions. The risk premium16

method to estimate investors' required rate of return is an extension of the risk-return17

tradeoff observed with bonds to common stocks. The cost of equity is estimated by de-18

termining the additional return investors require to forego the relative safety of a bond19

and bear the greater risks associated with common stock, and then adding this equity risk20

premium to the current yield on bonds.21

Q. GENERALLY DESCRIBE THE APPLICATION OF THE RISK PREMIUM22METHOD USING AUTHORIZED ROES.23

A. Application of the risk premium method based on authorized ROEs is predicated on the24

presumption that allowed returns reflect regulatory commissions' best estimates of the25

cost of equity, however determined, at the time they issued their final orders. A current26

risk premium is estimated based on the difference between past authorized ROEs and27

then-prevailing interest rates. This risk premium is then added to current interest rates to28

estimate the cost of equity.29

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Q. WHAT WAS THE PRINCIPAL SOURCE OF THE DATA USED TO APPLY1THIS RISK PREMIUM METHOD?2

A. Regulatory Research Associates, Inc. (RRA) and its predecessor have compiled the ROEs3

authorized major electric, gas, and telephone utilities by regulatory commissions across4

the U.S. The average ROE authorized natural gas utilities published by RRA in each5

quarter between 1980 and mid-2012 are displayed in Schedule BHF-10. As shown there,6

the ROEs granted LDCs over this approximately 31-year period have averaged 12.01%,7

while the average single-A utility bond yield has averaged 8.83%, resulting in an average8

risk premium of 3.18%.9

Q. IS THIS 3.18% AVERAGE RISK PREMIUM THE RELEVANT BENCHMARK10FOR ESTIMATING THE COST OF EQUITY?11

A. No. It is necessary to account for the fact that authorized ROEs do not move in lockstep12

with interest rates. In particular, when interest rate levels are relatively high, ROEs tend13

to be lower (i.e., equity risk premiums narrow), and when interest rates are relatively low,14

authorized ROEs are greater (i.e., equity risk premiums increase).15

Q. HOW DID YOU ACCOUNT FOR THE RELATIONSHIP BETWEEN EQUITY16RISK PREMIUMS AND INTEREST RATES IN ESTIMATING THE COST OF17EQUITY FOR WTG USING PAST AUTHORIZED ROES?18

A. To account for the fact that equity risk premiums are lower when interest rates are high19

and higher when interest rates are low, I developed two regression equations relating au-20

thorized past equity risk premiums to single-A bond yields. The first was a simple linear21

regression between equity risk premiums and interest rates and the second equation ad-22

justed for first order autocorrelation using the Prais-Winsten algorithm. Shown at the23

bottom of Schedule BHF-10, substituting the August 2012 yield of 4.00% on single-A24

public utility bonds into the regression equation indicates that the equity risk premium for25

an LDC at current interest rate levels is between approximately 5.37% and 5.77%.26

Q. WHAT COST OF EQUITY DOES THIS RISK PREMIUM IMPLY FOR WTG?27

A. Adding the 5.37% and 5.77% equity risk premiums developed on Schedule BHF-10 to28

the August 2012 yields on double-B and single-B bonds of 5.25% and 6.65%, respective-29

of 40


ly, produces a risk premium cost of equity range for WTG of between 10.62% and1

12.42%.2

E. Comparable Earnings Method

Q. WHAT WAS THE LAST METHOD THAT YOU USED TO ESTIMATE THE3COST OF EQUITY?4

A. Often referred to as the comparable earnings method, this approach looks to the rates of5

return that other firms of comparable risk and that compete for investors’ capital are ex-6

pected to earn on their book equity. Reference to the expected return on book equity of7

other LDCs demonstrates the level of earnings that WTG needs in order to offer investors8

a competitive return, be able to attract capital on reasonable terms, and maintain its finan-9

cial integrity.10

Q. WHAT RETURN ON BOOK EQUITY ARE OTHER LDCS EXPECTED TO11EARN?12

A. Schedule BHF-11 displays the return on book equity projected for each of the nine LDCs13

in the industry group for the 2012, 2013, and 2015-2017 time frames, calculated by divid-14

ing Value Line’s projected earnings per share by average book value per share. As shown15

there, the average expected book ROE for the group is 10.8% in 2012, 11.4% for 2013,16

and 11.8% for 2015-2017.17

F. Cost of Equity Range

Q. WHAT IS YOUR CONCLUSION AS TO THE COST OF EQUITY RANGE FOR18WTG?19

A. The DCF method indicated a cost of equity range for WTG of between 10.7% and 11.7%,20

and the CAPM indicated a cost of equity range of between approximately 9.93% and21

12.44%. Meanwhile, the risk premium method based on authorized ROEs for LDCs and22

current interest rates indicated a cost of equity for WTG between 10.62% and 12.42%,23

and the comparable earnings method showed that other LDCs are expected to earn be-24

tween 10.8% and 11.8% on their book equity. Taken together, I conclude that the cost of25

equity for WTG is in the 10.5% to 12% range.26

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IV. RETURN ON EQUITY RECOMMENDATION

Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR TESTIMONY?1

A. Having identified a cost of equity range for WTG, this section discusses other factors2

properly considered in selecting a return on equity for WTG.3

A. Outlook for Capital Costs

Q. IS THERE ANYTHING THAT SHOULD BE CONSIDERED IN SELECTING A4SPECIFIC ROE FROM THE COST OF EQUITY RANGE?5

A. Yes. As illustrated earlier, interest rates have dropped to historic lows following the fi-6

nancial crisis of 2008 and early 2009. This was a direct result of reduced loan demand7

due to the recession, reluctance by lenders to make loans, the U.S. government having ex-8

tended credit to financial institutions at artificially suppressed interest rates approaching9

zero, and the Fed purchasing hundreds of billions of dollars in U.S. Treasury bonds.10

Simultaneously, the federal government authorized hundreds of billions of dollars in11

spending to stimulate the economy, which it is borrowing to finance. As the recession12

ends and the government subsidies subside, long-term interest rates are expected to rise in13

response to market forces and inflationary pressures. This rise in interest rates will in14

turn increase the cost of permanent capital, including common equity, above current lev-15

els.16

Q. CAN YOU PROVIDE EVIDENCE OF THESE EXPECTATIONS FOR RISING17INTEREST RATES?18

A. Yes. Projections by investment advisors, forecasting services, and government agencies19

all show long-term interest rates increasing over the next few years. The table below20

compares current interest rates (as reported by the Fed and Moody’s) on 30-year U.S.21

Treasury, triple-A corporate bonds, and double-A utility bonds with those projected for22

2013 through 2016 by Value Line in its Forecast for the U.S. Economy (August 24,23

2012), Blue Chip Financial Forecasts (June 1, 2012), Global Insight in its The U.S.24

Economy: The 30-Year Focus (First Quarter 2012), and the Energy Information Admin-25

istration in its Annual Energy Outlook 2012 (January 2012):26

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August2012

2013 2014 2015 2016

30-Year TreasuryValue Line 2.8% 3.7% 4.0% 4.6% 5.0%Blue Chip Forecast 2.8% 3.6% 4.2% 4.9% 5.3%Global Insight 2.8% 3.6% 3.8% 4.1% 5.0%

AAA CorporateValue Line 3.5% 4.4% 4.7% 5.5% 6.0%Blue Chip Forecast 3.5% 4.3% 4.9% 5.6% 6.0%Global Insight 3.5% 4.4% 4.6% 5.1% 6.0%

AA-UtilityGlobal Insight 3.7% 4.8% 5.0% 5.6% 6.5%EIA 3.7% 4.8% 5.7% 6.8% 6.9%

1

These projections evidence a clear consensus that the cost of permanent capital will be2

higher in the 2013-2016 timeframe, when the rates being set in this proceeding will be in3

effect, than it is today. In order for WTG to offer investors a competitive return, attract4

capital on reasonable terms, and maintain its financial integrity, its ROE needs to reflect5

capital market requirements during the time when rates are in effect.6

Q. HOW SHOULD THIS OUTLOOK FOR INCREASED CAPITAL COSTS BE7INCORPORATED INTO THE RETURN ON EQUITY?8

A. So that the rates approved in this proceeding reflect the capital costs prevailing when9

those rates are in effect, an adjustment to the current cost of equity is necessary to ac-10

count for the higher capital costs expected in 2013 and beyond. However, while there is11

a consensus that capital costs will be higher in the 2013-2016 timeframe than they are12

currently, there is some disagreement about the magnitude of that increase. Therefore, I13

recommend that the higher capital costs expected when rates are in effect be accommo-14

dated by selecting an ROE from the upper end of the cost of equity range.15

16

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B. Tariff Riders1

Q. DOES WTG HAVE ANY TARIFF RIDERS?2

A. The only riders to WTG’s current tariff are its gas cost adjustment (“PGC”) and associat-3

ed revenue related tax adjustment provision. Notably, WTG does not have a weather4

normalization adjustment (“WNA”) clause under which it can adjust rates to account for5

warmer- or colder-than-normal weather. And while WTG has not previously adjusted its6

rates under the Gas Reliability Infrastructure Program (“GRIP”) that allows a gas utility7

to increase rates to recover higher capital costs attributable to investments in system im-8

provements, WTG is requesting findings in this case that will allow it to do so in the fu-9

ture.10

Q. DO MOST LDCS HAVE A WNA OR SIMILAR PROVISION TO MITIGATE11THE IMPACT OF WARMER- OR COLDER-THAN NORMAL ON THEIR12EARNINGS?13

A. Yes. Virtually all of the LDCs in the industry group used as the basis for estimating14

WTG’s cost of equity are regarded by the investment community as having a weather15

mitigant (e.g., WNA clause and decoupled rates). Therefore, the greater weather risk16

faced by WTG because it does not have a WNA has not been accounted-for in the cost of17

equity range developed above.18

Q. WOULD A WNA ELIMINATE ALL THE RISKS THAT WTG FACES?19

A. No. Weather is but one of the many risks faced by WTG. For example, operating and20

financing risks related to rate regulation, gas costs, loss of industrial customers, costs dis-21

allowances, customer growth, bypass, non-rate regulatory changes, asset impairment, tax22

laws, environmental laws and regulations, operating hazards, industry restructuring, gen-23

eral economic conditions, inflation, credit requirements, and capital market conditions,24

just to name a few, remain. Thus, while a WNA would largely reduce certain revenue25

risks associated with the warmer or colder than normal weather, it does not reduce the26

multitude of other risks faced by WTG.27

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Q. WHAT ABOUT WTG’S REQUEST IN THIS CASE FOR FINDINGS THAT1WILL ALLOW IT TO ADJUST RATES UNDER GRIP?2

A. GRIP and riders that achieve similar end-results are generally viewed favorably by the3

investment community, but they do not have a material impact on WTG’s overall invest-4

ment risk. Moreover, any reduced risk associated with WTG’s future ability to adjust its5

rates under GRIP is largely already accounted for in the ROE range developed above.6

Q. WHY DO YOU SAY THAT GRIP WOULD NOT HAVE A MATERIAL IMPACT7ON WTG’S OVERALL INVESTMENT RISK?8

A. GRIP addresses changes in expenditures for additional plant investment between rate9

cases and entails at least a one-year lag between when the expenditures are incurred and10

ultimately reflected in rates. Because changes in plant investment are re-established in11

each rate case, the need to reflect additional investment in gas plant assets can be accom-12

plished by more frequent rate cases. Accordingly, the benefit of GRIP is not that it mate-13

rially reduces investment risks, but that it tends to reduce the number of rate cases, which14

is a general benefit to WTG, its regulators, and customers.15

Q. WHAT IS THE BASIS FOR YOUR EARLIER STATEMENTS THAT THE ROE16RANGE DEVELOPED ABOVE LARGELY REFLECTS THE REDUCED RISKS17ASSOCIATED WITH A WNA AND GRIP?18

A. LDCs throughout the U.S. are adopting rate designs that decouple rates from customer19

usage in various ways and have riders and surcharges that include selected expenditures20

in rates outside of a rate case. In my review of the Form 10-Ks of the LDCs included in21

the industry group identified earlier, most have rate provisions that are viewed by inves-22

tors’ as achieving end-results similar to a WNA and GRIP. For example, AGL Re-23

sources’ namesake LDC, Atlanta Gas Light, has a straight-fixed-variable rate that is paid24

by marketers who sell gas to retail customers. Its Virginia Natural Gas, Elizabethtown25

Gas, and Chattanooga Gas LDCs all have WNAs, with Chattanooga Gas also having de-26

coupled rates. Atlanta Gas Light and Elizabethtown Gas also have infrastructure im-27

provement riders, and AGL’s recently acquired Nicor Gas LDC has a bad debt rider and a28

flat monthly fee rate design with only a small variable charge. Atmos Energy has WNA29

mechanisms that serve to minimize the effects of weather on approximately 94% of its30

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gross margin, mechanisms that provide for annual rate reviews and adjustments to rates1

for approximately 73% of its gross margin, rate structures providing for accelerated re-2

covery of all or a portion of expenditures for approximately 84% of its gross margin, and3

riders to recover the gas portion of bad debts and ad valorem taxes. Laclede has a weath-4

er mitigation rate design that provides better assurance of the recovery of its fixed costs5

and margins during winter months despite variations in sales volumes due to the impacts6

of weather and other factors that affect customer usage.7

The rates of New Jersey Resources’ LDC have a provision that permit it to adjust8

rates to recover its allowed margins regardless of weather or customer usage, as well as9

three riders covering remediation, accelerated infrastructure, and energy efficiency ex-10

penditures. Northwest Natural has a conservation tariff in its primary Oregon service ar-11

ea (90% of revenues) that decouples customer usage from its earnings with periodic ad-12

justments. Piedmont Natural Gas’ rates in North Carolina adjust monthly to recover its13

approved margins independent of consumption, while its rates in South Carolina are ad-14

justed annually pursuant to state statute and those in both South Carolina and Tennessee15

are covered by WNAs. It also has riders in all three jurisdictions that allow for the recov-16

ery of uncollectible gas costs.. The rates of South Jersey Industries’ LDC include a con-17

servation incentive program that preserves its profit margin per customer through annual18

adjustments and an adjustment clause that covers remediation, clean energy, universal19

service, and consumer education expenditures. Southwest Gas’ rates are decoupled in all20

three of the states in which it serves (i.e., Arizona, California, and Nevada). Finally,21

Washington Gas Light has decoupled residential rates and a rider for energy efficiency22

program expenditures in Virginia, although these rate features have not been approved in23

the District of Columbia or Maryland.24

Q. WHAT DOES THE ABOVE DISCUSSION IMPLY WITH RESPECT TO25SELECTING AN ROE FOR WTG FROM WITHIN THE COST OF EQUITY26RANGE?27

A. Because virtually all of the LDCs in the industry group have rate provisions that mitigate28

the effects weather and cover various types of expenditures incurred between rate cases,29

the cost of equity range developed for WTG implicitly assumes the lower risk associated30

of 40


with both a WNA and GRIP. This implies that no adjustment is required for WTG’s re-1

quest for findings that will enable it to implement GRIP, but that an upward adjustment to2

WTG’s ROE is warranted because it does not have a WNA. However, as discussed3

above, a WNA is only one of the many risks faced by an LDC, and its impact on overall4

investment risk and, in turn, the cost of equity is measured in just a few basis, not per-5

centage, points.6

C. Recommended Return on Equity

Q. WHAT IS YOUR RECOMMENDED ROE FOR WTG?7

A. To account primarily for the outlook for higher capital costs and to a lesser extent for the8

fact that WTG does not have a WNA, I recommend an ROE for WTG at the upper end of9

my 10.5% to 12.0% cost of equity range, or 11.5%. There is a clear consensus that the10

cost of capital will be appreciably higher in the 2013-2016 timeframe than it is today. If11

WTG is to be able to offer investors a competitive return, attract capital on reasonable12

terms, and maintain its financial integrity, its ROE needs to reflect the higher capital13

market requirements when rates will be in effect.14

D. Check of Reasonableness

Q. HAVE YOU CONDUCTED ANY CHECKS OF REASONABLENESS OF YOUR15RECOMMENDED ROE FOR WTG?16

A. Yes. The reasonableness of my recommended 11.5% ROE for WTG can also be judged17

by reference to the ROEs previously granted by the Railroad Commission of Texas (“the18

Commission”). In their most recent cases, Atmos, Entex, and Texas Gas Service were19

authorized ROEs of between 10.05% and 10.70%, which when adjusted for WTG’s20

greater risk and smaller size fully supports my recommended ROE. Meanwhile, the21

ROEs granted by the Commission for smaller LDCs have varied, but the majority have22

been between 10.27% and 12.5%, which is also consistent with my 11.5% recommended23

ROE for WTG.24

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Q. HOW ELSE CAN THE REASONABLENESS OF YOUR RECOMMENDED ROE1FOR WTG BE EVALUATED?2

A. My recommended 11.5% ROE for WTG is based on and corresponds to industry capital3

structure ratios of 40% debt and 60% equity. Recall, however, that WTG’s actual capital4

structure is not nearly as highly levered, consisting of approximately 18% debt and 82%5

equity. If my recommended overall rate of return of 9.03% (developed in the next sec-6

tion) is income tax adjusted and WTG’s actual interest expense deducted, the implied7

ROE on WTG ’s actual capital structure is only 9.78%. Put another way, including an al-8

lowed ROE of 11.5% with hypothetical capital structure ratios of 40% debt/60% equity9

capital structure will only result in WTG expecting to earn 9.78% on its actual equity,10

which for a utility of WTG’s greater risk and smaller size is certainly not unreasonable.11

V. OVERALL RATE OF RETURN

Q. WHAT OVERALL RATE OF RETURN DO YOU RECOMMEND BE APPLIED12TO WTG’S ORIGINAL COST INVESTED CAPITAL?13

A. I recommend that WTG be authorized an overall rate of return on the original cost of its14

invested capital of 9.03%. As developed in Schedule BHF-1, this overall rate of return is15

the result of combining my recommended capital structure ratios of 40% debt and 60%16

equity with a cost of debt of 5.32% and an ROE of 11.50%.17

Q. DOES THAT CONCLUDE YOUR DIRECT TESTIMONY IN THIS CASE?18

A. Yes, it does.19

of 14

Direct Testimony of William R. PenningtonWest Texas Gas, Inc.


STATEMENTOF INTENT OF WEST )TEXAS GAS, INC. TO INCREASE GAS )DISTRIBUTION RATES IN THE ) GUD NO._______UNINCORPORATED AREAS OF TEXAS )

DIRECT TESTIMONY OF WILLIAM RODNEY PENNINGTON

TABLE OF CONTENTS1

I. POSITION AND QUALIFICATIONS........................................................................................ 32


III. ANNUAL SALES VOLUMES ................................................................................................ 64

IV. DESIGN DAY SALES VOLUMES ........................................................................................ 135

V. CONCLUSION.................................................................................................................. 146

7

EXHIBITS8

9


WRP-01 North Division Test Period Sales By District11

WRP-02 North Division Test Period Sales Summarized To Division12

WRP-03 North Division Monthly HDDs13

WRP-04 North Division Monthly Precipitation14

WRP-05 North Division Historical and Test Period Irrigation Sales15

WRP-06 North Division Adjusted Test Period Sales16

WRP-07 North Division Adjusted Test Period Sales By District17

WRP-08 West Division Test Period Sales By District18

WRP-09 West Division Test Period Sales Summarized To Division19

WRP-10 West Division Monthly HDDs20

WRP-11 West Division Monthly Precipitation21

of 14


WRP-12 West Division Historical and Test Period Irrigation Sales1

WRP-13 West Division Adjusted Test Period Sales2

WRP-14 West Division Adjusted Test Period Sales By District3

WRP-15 South Division Test Period Sales By District4

WRP-16 South Division Test Period Sales Summarized To Division5

WRP-17 South Division Monthly HDDs6

WRP-18 South Division Monthly Precipitation7

WRP-19 South Division Historical and Test Period Irrigation Sales8

WRP-20 South Division Adjusted Test Period Sales9

WRP-21 South Division Adjusted Test Period Sales By District10

WRP-22 Transmission Test Period Sales (Non-Regulated)11

WRP-23 Oklahoma Test Period Sales12

WRP-24 All Divisions - Test Period Sales13

WRP-25 Adjusted Test Period Sales All Divisions14

WRP-26 Design Day Sales - All Divisions15

16

of 14


I. POSITION AND QUALIFICATIONS1


A. My name is William Rodney Pennington, and my business address is 10330 Lake Road,3

Suite Z, Houston, Texas 77070-1866.4

Q. WHAT IS YOUR CURRENT OCCUPATION?5

A. I am a partner and founding member of Pendulum Energy, LLC (“Pendulum”). My firm6

provides various consulting services to natural gas industry market participants, including7

rate and regulatory analysis, expert witness support for rate and certificate proceedings,8

pipeline tariff analysis, supply and capacity planning, industry training, economic9

analysis, market research, and strategic planning support10

Q. ON WHOSE BEHALF ARE YOU SUBMITTING TESTIMONY?11

A. I am presenting testimony on behalf of West Texas Gas, Inc. ("WTG").12

Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE TEXAS RAILROAD13

COMMISSION AND OTHER AGENCIES?14

A. Yes. I testified before the Texas Railroad Commission in Docket No. 9364. I have also15

testified before the Oklahoma Corporation Commission, the Arkansas Public Service16

Commission, the Missouri Public Service Commission, the Minnesota Public Utilities17

Commission and the Federal Energy Regulatory Commission. I have also testified in18

both state and federal courts.19

Q. PLEASE DESCRIBE YOUR EDUCATION AND PROFESSIONAL20

BACKGROUND.21

A. I received a Bachelor of Science degree in Mathematics from Northwestern State22

University in 1974. I joined Texas Eastern Transmission Corporation in 1974 in the23

Measurement Department. I served as a Measurement Technician from 1975 until 1976.24

In that capacity, I worked as a technician in the field, responsible for field measurement25

and corrosion activities. This included the testing of meters, cathodic protection of26

facilities, BTU sampling, project installation, and installation and testing of electronic27

and pneumatic measurement equipment.28

In 1976, I transferred to Gas Supply and served in various gas supply related29

positions until 1981. While in Gas Supply, I was involved in supply planning, cost of gas30

of 14


forecasting, gas purchase invoice payments, contract administration and interpretation,1

and royalty related issues.2

In 1981, I joined Tenneco Gas in the Rate Department as Supervisor of Rates. In3

that capacity, I worked on the development of PGA filings and rate case filings, among4

other matters. I was responsible for the development of the dekatherm (“Dth”) mile5

study for Tennessee Gas Pipeline. In 1984, I was promoted to Manager of Gas Purchase6

Administration, with responsibilities for the payment of all gas purchase related payments7

to suppliers.8

In 1985, I was appointed Manager of Operations Planning and in 1986, I was9

promoted to Director of Operations Coordination. In these functions, I was responsible10

for coordinating all physical and contractual volume flows on the Tennessee Gas Pipeline11

system. My department developed and implemented storage inventory utilization plans12

and monitored the company lost and unaccounted for volume account. From 1984 until13

1991, the Operations Coordination Department developed all supply portfolio plans and14

was responsible for all transportation and exchange nominations and scheduling as well15

as imbalance management.16

In 1991, I formed what is now Pendulum. As a consultant, I have represented17

local distribution companies (“LDCs”), pipelines, end-use customers, marketing18

companies, producers, and public utility commissions. I have consulted with clients on19

issues such as cost allocation, storage usage, supply planning, gas purchase prudence,20

royalty disputes, and other operational concerns.21

In my role as a consultant, I have bought and sold natural gas and capacity for my22

LDC clients, prepared and evaluated Requests for Proposals, assisted in the preparation23

and filing of Gas Procurement Plans, and performed various storage and capacity plan24

analyses.25

26

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A. My testimony will discuss the methodology used to determine the annual and design day3

sales volume estimates relied upon by Dr. John R. Underwood in determining billing4

determinants used for the allocation of costs to the various customers.5

Q. ARE YOU SPONSORING EXHIBITS TO THIS TESTIMONY?6

A. Yes. I am sponsoring the following exhibits.7

WRP-01 North Division Test Period Sales By District8

WRP-02 North Division Test Period Sales Summarized To Division9

WRP-03 North Division Monthly HDDs10

WRP-04 North Division Monthly Precipitation11

WRP-05 North Division Historical and Test Period Irrigation Sales12

WRP-06 North Division Adjusted Test Period Sales13

WRP-07 North Division Adjusted Test Period Sales By District14

WRP-08 West Division Test Period Sales By District15

WRP-09 West Division Test Period Sales Summarized To Division16

WRP-10 West Division Monthly HDDs17

WRP-11 West Division Monthly Precipitation18

WRP-12 West Division Historical and Test Period Irrigation Sales19

WRP-13 West Division Adjusted Test Period Sales20

WRP-14 West Division Adjusted Test Period Sales By District21

WRP-15 South Division Test Period Sales By District22

WRP-16 South Division Test Period Sales Summarized To Division23

WRP-17 South Division Monthly HDDs24

WRP-18 South Division Monthly Precipitation25

WRP-19 South Division Historical and Test Period Irrigation Sales26

WRP-20 South Division Adjusted Test Period Sales27

WRP-21 South Division Adjusted Test Period Sales By District28

WRP-22 Transmission Test Period Sales (Non-Regulated)29

WRP-23 Oklahoma Test Period Sales30

WRP-24 All Divisions - Test Period Sales31

of 14


WRP-25 Adjusted Test Period Sales All Divisions1

WRP-26 Design Day Sales - All Divisions2

3

Q. PLEASE EXPLAIN HOW THE EXHIBITS ARE ORGANIZED.4

A. As shown above, I have prepared 26 exhibits as part of this testimony. The first 255

exhibits are associated with the annual sales volumes analysis. WRP-01 through WRP-6

07 present the annual sales volume analysis for the North Division (Texas). WRP-087

through WRP-14 present the annual sales volume analysis for the West Division (Texas).8

WRP-15 through WRP-21 present the annual sales volume analysis for the South9

Division (Texas). WRP-22 presents the unregulated transmission annual sales while10

WRP-23 shows the annual sales in Oklahoma. WRP-24 summarizes the total unadjusted11

test period Texas regulated annual sales (North, West, and South Divisions). WRP-2512

summarizes the adjusted test period Texas regulated annual sales for the three Texas13

divisions. WRP-26 includes calculations regarding the forecasted design day sales for14

all Texas regulated divisions.15

III. ANNUAL SALES VOLUMES16

Q. WHY ARE ANNUAL SALES VOLUMES RELEVANT IN A RATE CASE?17

A. Annual sales volumes, once adjusted for normal weather and customer count changes, are18

used to allocate costs to the various jurisdictional customer classes. Dr. Underwood19

discusses the annual sales volumes and how they are used to allocate costs in his20

testimony.21

Q. HOW DID YOU DETERMINE THE ANNUAL SALES VOLUMES, BOTH22

UNADJUSTED AND ADJUSTED, TO BE USED BY DR. UNDERWOOD?23

A. First, I reviewed the historical sales volumes (including some transport volumes) for each24

of the divisions by district for the test period (July 1, 2011, through June 30, 2012). I25

then summarized the district level data to the division level. Next, I analyzed the weather26

data, both heating degree days ("HDDs") and precipitation, over the last ten years for27

each of the divisions and noted the difference between the ten-year average and the test28

period. I then made adjustments to the test period sales data by division to account for29

the deviations between the test period weather and the ten-year average weather data.30

of 14


Once the adjusted test period sales volumes were calculated by division, I allocated the1

sales volumes to the district level. Although I have used the term "sales volumes"2

throughout this testimony and associated exhibits, it should be noted that this includes a3

small amount of transport gas (about 16% in Texas).4

Q. YOU MENTIONED EARLIER THAT CUSTOMER COUNT CHANGES ARE5

INCLUDED AS PART OF THIS ANALYSIS. WERE THERE SIGNIFICANT6

CHANGES IN CUSTOMER COUNT DURING THE TEST PERIOD?7

A. No. The customer count for each division was very stable during the test period, and8

WTG personnel foresee no significant changes in the future. As a result, I have made no9

adjustments to the test period sales volumes for possible customer count changes in the10

future.11

Q. PLEASE EXPLAIN IN DETAIL THE DATA AND CALCULATIONS INCLUDED12

IN YOUR ANALYSIS OF THE ANNUAL SALES VOLUMES FOR THE NORTH13DIVISION IN TEXAS.14

A. As stated previously, WRP-01 through WRP-07 present the analysis of annual sales15

volumes for the North Division of Texas. WRP-01 presents the monthly test period sales16

volumes, dollars paid, and customer count by district for each of the individual customer17

classes within the North Division. These data were provided by WTG, with no18

adjustments by me. Pages 1 and 2 present the test period sales data for July 2011, the19

first month of the test period. As illustrated on pages 1 and 2, there are ten districts20

within the North Division. As noted in Column A, there are 13 customer classifications21

for each of the districts. Also shown on pages 1 and 2 are the dollars of revenue billed by22

WTG for each customer class for each of the districts. There are two pages within the23

exhibit for each month of the test period. Pages 25 and 26 present the totals for the24

twelve-month test period.25

WRP-02 summarizes the district level data contained in WRP-01 to the division26

level. The data in Column L of WRP-01 are consistent with the data contained in WRP-27

02. As example, the first row of data on page 1 of 26 of WRP-01 shows the Mcf @ 14.6528

psi for Jurisdictional Domestic customers for July 2011 for each of the 10 districts in the29

North Division. Column L illustrates the total test period sales volume (11,275 Mcf) for30

the Jurisdictional Domestic customers. This same volume (11,275 Mcf) is recorded as31

the test period sales volume for the Jurisdictional Domestic customers for July 2011 in32

of 14


Column B of WRP-02. All data shown in Column B of WRP-02 are taken from Column1

L of Pages 1 and 2 of WRP-01. Similarly, all data shown in Column C of WRP-02 are2

taken from Column L of pages 3 and 4 of WRP-01 while all data shown in Column D of3

WRP-02 are taken from Column L of pages 5 and 6 of WRP-01, etc.4

WRP-03 presents the Monthly Heating Degree Days ("HDDs") data for the last5

ten years as recorded by the National Weather Service at the Amarillo Weather Station.6

The Amarillo Weather Station is the appropriate location for analyzing weather7

deviations within the North Division. This analysis is required because WTG has several8

temperature sensitive customer classes, primarily the residential and small commercial9

loads. As illustrated in this exhibit, the test year total HDDs for the Amarillo area was10

3,543 (Column K) while the ten-year average was 3,944 HDDs. This means that the total11

HDDs for the ten-year average is approximately 111.30% of the test period total HDDs.12

Based on this difference, all weather sensitive test period sales in the North division will13

need to be adjusted upward by 111.30% for forecasting purposes.14

WRP-04 represents the Monthly Precipitation data for the last ten years as15

recorded by the National Weather Service at the Amarillo Weather Station. This analysis16

is required because WTG serves a large irrigation market. As shown in Column K, the17

Amarillo Weather Station reported 12.91 inches of precipitation (rain plus snow) during18

the test year while the average over the ten-year period was 19.59 inches (Column L).19

This means that the Amarillo area suffered through drought conditions during the test20

period, which lead to much higher irrigation related annual sales than would be expected21

during a period of normal rainfall. Based on this wide differential between test period22

precipitation and ten-year average precipitation, it was deemed necessary to adjust the23

test period irrigation sales to a level expected during a normal precipitation period.24

WRP-05 represents a four-year history of irrigation sales, including monthly25

volumes, customer count, and precipitation. The direct correlation between annual26

precipitation and annual irrigation sales is clearly shown by this data. For example,27

during the period July 2009 through June 2010, the Amarillo Weather Station reported28

24.91 inches of precipitation. The WTG irrigation sales for the North Division during29

this period were 12,078,570 Mcf. During the drought period of July 2011 through June30

of 14


2012, the Amarillo Weather Station reported 12.91 inches of precipitation, while the1

irrigation sales were 19,413,591 Mcf. A comparison of the two years shows that the2

irrigation sales for the 2011-12 period are about 60% higher than 2009-10, while the3

precipitation level is about 48% less. Significantly, the customer counts during the two4

periods were virtually the same.5

As shown at the bottom of WRP-05 (Column N), the average precipitation for the6

four-year period was 19.15 inches, similar to the ten-year average of 19.59 inches shown7

in WRP-04. The average annual irrigation sales equal 15,634,516 Mcf. Based on this8

data, I have determined that the annual test period irrigation sales volumes should be9

adjusted. The average annual irrigation sales of 15,634,516 Mcf, which correlates to the10

four-year average precipitation level of 19.15 inches, is a more appropriate level for11

expected irrigation sales in the future. This equates to 80.53% of the volumes sold during12

the test period. This factor of 80.53% is applied to the monthly irrigation sales volumes13

in WRP-06.14

WRP-06 presents the determination of the Adjusted Test Period Sales for the15

North Division. Most of the adjustments made to the test period sales volumes are16

weather related. Four sales categories are temperature (HDDs) sensitive. They are: 1)17

Jurisdiction Domestic; 2) Jurisdictional Non-Domestic; 3) Commercial; and 4) Public18

Authority. For each of these categories, I have estimated the portion of the monthly sales19

that are baseload in nature. This is the load that one would expect if the weather was at20

least 65 degrees (0 HDDs). The remainder of the monthly sales volumes is deemed to be21

temperature sensitive. Because the test period was warmer than the ten-year average, the22

temperature sensitive volumes must be adjusted upward for future forecasting purposes.23

The temperature sensitive volumes are adjusted upward by using the Heat Load Factor24

calculated in WRP-03 (111.30%).25

An adjustment was also required for the irrigation load. As discussed previously,26

the test period precipitation of 12.91 inches was lower than the ten-year average of 19.5927

inches. As a result, the test period irrigation sales were much higher than should be28

expected. The Irrigation Volume Adjustment Factor (80.53%), as determined in WRP-29

of 14


05, was used to lower the test period irrigation sales volume (19,413,591 Mcf) to1

15,634,516 Mcf. This represents a reduction of 3,779,075 Mcf.2

Two of the sales categories have been adjusted to zero: 1) Interdepartmental3

Sales, and 2) Unbilled Revenues. Six categories have not been adjusted: 1) Gathering, 2)4

Interstate Sales, 3) Leakage, 4) Resale, 5) Transport, and 6) Other.5

Overall, the test period total volume of 27,351,888 Mcf was reduced to6

23,533,570 Mcf, a reduction of 3,818,318 Mcf. Virtually the entire reduction is7

associated with the irrigation load, partially offset with the increases related to the8

temperature sensitive load.9

WRP-07 allocates the Adjusted Test Period Volumes (as calculated in WRP-0610

for the North Division) to the various districts within the division. For example, the first11

sales category is Jurisdictional Domestic. The first line represents the actual test period12

MCF@ 14.65 and the MCF Billed. These data are as shown in WRP-01, pages 25 and13

26. The line labeled Volume Adjustment Factor is from WRP-06. The lines labeled14

Adjusted Test Period Volumes and Adjusted Test Period Volumes To Be Billed are15

derived by multiplying the first two lines by the Volume Adjustment Factor. This same16

set of calculations is performed for each of the customer classes.17

Q. WHAT DATA AND CALCULATIONS ARE INCLUDED IN YOUR ANALYSIS18OF THE ANNUAL SALES VOLUMES FOR THE WEST DIVISION IN TEXAS?19

A. WRP-08 through WRP-014 present the analysis of annual sales volumes for the West20

Division of Texas. The exhibits are identical in format to WRP-01 through WRP-07.21

WRP-08 shows that the West Division has six districts and that the irrigation load is the22

largest customer class by volume (about 40%). The West Division also has some23

temperature sensitive load. WRP-09 presents the compiling of the district level data to24

the division level.25

WRP-10 presents the historical Monthly HDDs as reported by the Midland26

Weather Station. Similar to the North Division, the West Division experienced warmer27

weather during the test period (2,305 HDDs) than the ten-year average (2,531 HDDs).28

As such, a Heat Load Factor was determined to be 109.79%. This factor is applied to the29

temperature sensitive load in WRP-13.30

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WRP-11 shows that the West Division suffered through the same type of drought1

conditions during the test period. The Midland Weather Station recorded 9.99 inches of2

precipitation during the test period while the ten-year average precipitation level was3

14.27 inches. WRP-12 illustrates the four-year history of irrigation sales and4

precipitation for the West Division. As with the North Division, the range between the5

various periods is significant. And as with the North Division, I have assumed that the6

four-year average precipitation (12.05 inches) and irrigation sales (1,489,731 Mcf) are7

reasonable for forecasting purposes. Although the use of 12.05 inches of precipitation8

instead of the ten-year average of 14.27 inches probably causes an over-forecasting of9

future irrigation sales, using the four-year average of actual sales appeared to be10

reasonable.11

WRP-13 illustrates the calculation of the Adjusted Test Period Sales Volumes for12

the West Division. Similar to the North Division, the West Division experienced a13

warmer and dryer than normal test period. Upward adjustments were therefore made to14

the temperature sensitive loads and a downward adjustment was made to the irrigation15

sales volumes. The total Adjusted Test Period Sales Volume is forecasted at 3,947,93616

Mcf, a reduction of about 3%. WRP-14 allocates the Adjusted Test Period Sales Volume17

to the district level.18

Q. WHAT DATA AND CALCULATIONS ARE INCLUDED IN YOUR ANALYSIS19OF THE ANNUAL SALES VOLUMES FOR THE SOUTH DIVISION IN TEXAS?20

A. WRP-15 through WRP-021 presents the analysis of annual sales volumes for the South21

Division of Texas. These exhibits are identical in format to WRP-01 through WRP-07.22

As shown in WRP-15, the South Division is made up of nine districts and had total test23

period sales of 4,238,962 Mcf. The South Division is made up of a small residential and24

commercial load, a small irrigation load, and a much larger transport load. WRP-1625

summarizes this data to the division level.26

WRP-17 compiles the ten-year history of Monthly HDDs as reported by the San27

Antonio Weather Station. Column K shows the monthly HDDs for the test period as well28

as the total for the test period (1,130 HDDs). The ten-year average of 1,317 HDD's is29

shown in Column L This equates to a Heat Load Factor of 116.50%.30

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WRP-18 presents the compilation of the ten-year history of precipitation as1

reported by the San Antonio Weather Station. The total precipitation for the test period2

was 34.82 inches (Column K) as compared to the ten-year average of 31.78 inches3

(Column L). Unlike the West and North Divisions, the South Division experienced more4

rain than the ten-year normal. WRP-19 summarizes the irrigation sales and precipitation5

for the last four years. Based on this data, an Irrigation Volume Adjustment Factor was6

determined to be 91.01%, and the forecasted irrigation load is 102,965 Mcf.7

WRP-20 applies the volume adjustment factors included in WRP-17 and WRP-198

and calculates an Adjusted Test Period Volume of 4,247,925 Mcf, an increase of about9

0.2%. WRP-21 allocates the Adjusted Test Period Sales Volumes to the district level.10

Q. WHAT DATA ARE PRESENTED IN WRP-22 THROUGH WRP-25.11

A. WRP-22 shows the volume flows in Texas during the test period that are classified as12

non-jurisdictional transmission. As shown on page 2, the total non-jurisdictional13

transmission load during the test period was only 328,297 Mcf. WRP-23 represents the14

test period sales volumes in Oklahoma. As illustrated in this exhibit, there are five15

districts in Oklahoma, and the total test period sales volume was 4,055,325 Mcf. WRP-16

24 summarizes the test period sales data for the three Texas Divisions (North, West, and17

South) as well as non-jurisdictional transmission and Oklahoma.18

WRP-25 shows the test period sales volumes as well as the total adjusted test19

period volumes for the three Texas divisions. Page 26 of the exhibit compares the totals.20

They are:21

Test Period Adjusted Difference22

Division Volume Volume Volume23

North 27,351,888 23,533,570 (3,818,318)24

West 4,070,537 3,947,936 ( 122,601)25

South 4,238,962 4,247,925 8,96326

Total 35,661,387 31,729,431 (3,931,956)27

28

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The difference between the test period volume and the adjusted test period volume is a1

reduction of 3,931,956 Mcf or an 11% decrease. As discussed above, virtually all of this2

reduction is associated with the irrigation sales volumes. The reduction was required to3

normalize the higher than normal sales caused by the drought conditions experienced in4

the North and West Divisions.5

IV. DESIGN DAY SALES VOLUMES6

Q. WHY ARE DESIGN DAY SALES VOLUMES RELEVANT IN A RATE CASE?7

A. Estimated design day sales volumes are also used to allocate costs to the various8

jurisdictional customer classes. Dr. Underwood discusses the design day volumes and9

how they are used to allocate costs in his testimony.10

Q. PLEASE DISCUSS HOW YOU DETERMINED THE ANTICIPATED DESIGN11

DAY VOLUMES AND THE RESULTS.12

A. WRP-26 presents my calculations in connection with the anticipated design day volumes.13

Much of the data shown in WRP-26 are derived from the data contained in Column H14

(January 2012) of WRP-06 (North Division), WRP-13 (West Division) and WRP-2015

(South Division). As example, the first line item in WRP-26 is associated with the16

Jurisdictional Domestic customer class and is labeled Mcf/Day @ 14.65psi Actual17

January 2012. Column B shows that the daily volume for the North Division is 3,372.8418

Mcf/day. This is calculated by dividing the monthly sales volume for this sales category19

(104,558 Mcf as shown on page 1, Column H of WRP-06), by the number of days in the20

month (31). The second line item (Baseload Volume - Mcf/Day), the third line item21

(Heat Load -Mcf/Day), and the fourth line item (Average Daily January 2012 HDDs)22

contained in Column B of WRP-26 are similarly determined by dividing the correlating23

data as shown in Column H of WRP-06 by the number of days in the month. The next24

line item, labeled Heat Load Volume Per HDD, is calculated by dividing the Heat Load -25

Mcf/Day by the Average Daily January 2012 HDDs (2,566.38 Mcf/day / 22.65 HDDs =26

113.33 Mcf/HDDs).27

The Design Day HDDs represents the coldest daily temperature recorded by the28

three related weather stations in the last 30 years (December 23, 1989). On that day the29

coldest temperature was -8 degrees in Amarillo (North), -1 in Midland (West), and 630

of 14


degrees in San Antonio (South). This equates to 73 HDDs in Amarillo (North), 66 HDDs1

in Midland (West) and 59 HDDs in San Antonio (South).2

The next line item is labeled Design Day Heat Load Volume - Mcf/Day. This is3

calculated by multiplying the Heat Load Volume Per HDD (113.33 Mcf/HDD) times the4

Design Day HDDs (73 HDDs). The resulting Design Day Heat Load Volume as shown5

in Column B is 8,273.11 Mcf/Day. When this Design Day Heat Load Volume (8,273.116

Mcf/day) is added to the Baseload Volume (806.45 Mcf/Day), the result is an Anticipated7

Design Day Volume of 9,079.57 Mcf/day. The volumes and values contained in the8

other customer classes as well as the West and South Division are determined in the same9

manner. Irrigation load was adjusted to zero because this load will not flow when10

temperature drops well below zero.11

As shown on page 2 of WRP-26, the Total Anticipated Design Day Volume -12

Mcf/Day for each division is::13

North West South Total14

Mcf/Day Mcf/Day Mcf/Day Mcf/Day15

46,306.87 10,247.21 21,453.15 78,007.2316

V. CONCLUSION17

Q. DOES THIS COMPLETE YOUR TESTIMONY?18

A. Yes.19

of 24

Direct Testimony of John R. UnderwoodWest Texas Gas, Inc.


STATEMENT OF INTENT OF WESTTEXAS GAS, INC. TO INCREASE GASDISTRIBUTION RATES IN THEUNICORPORATED AREAS OF TEXAS

))))

GUD NO. _________

DIRECT TESTIMONY OF JOHN R. UNDERWOOD1

2

TABLE OF CONTENTS3

I. WITNESS IDENTITY AND QUALIFICATIONS .................................................................... 24

II. RATE STUDY – COST OF SERVICE .................................................................................. 35

III. RATE STUDY – COST CLASSIFICATION, ALLOCATION AND RATE DESIGN..................... 156

IV. CONCLUSION ........................................................................................................... 247

8

9

10

11

EXHIBITS12

13

Exhibit Description

14

JRU-1

JRU-2

Rate Study (Located Under a Separate Tab)

Gas Services Division’s Suggested Best Practices

of 24



Q. PLEASE STATE YOUR NAME AND YOUR BUSINESS ADDRESS.2

A. My name is John R. (Randy) Underwood and my business address is 10330 Lake3

Road, Suite Z, Houston, Texas 77070.4

Q. WHAT IS YOUR CURRENT OCCUPATION?5

A. I am a consultant performing working through Pendulum Energy, a consulting firm6

providing services to various sectors of the energy industry.7

Q. PLEASE DESCRIBE YOUR EDUCATION AND WORK EXPERIENCE IN8THE ENERGY INDUSTRY.9

A. I received a B.A. in mathematics and philosophy from Rice University in 1971 and a10

Ph.D. in mathematics in 1973 from the same institution.11

I joined Texas Eastern Transmission Corporation ("Texas Eastern") in 1979 in the12

Rate Department. I was a supervisor responsible for filing rate cases for Texas13

Eastern, a pipeline running from Texas to New England. In 1984 I joined Tenneco14

Gas and worked in that company until late 1993. At Tenneco Gas, I held numerous15

positions. At various times, I was responsible for Market Forecasting, Planning,16

Reserves and Basin Analysis, Econometric Analysis, Project Analysis, Risk17

Assessment and Business Development. These services were performed for interstate18

and intrastate pipelines and for Tenneco’s marketing company. Positions held ranged19

from Senior Analyst to Manager.20

since 1993, I have been a consultant working primarily through Pendulum Energy21

("Pendulum"). As a consultant, I have represented LDCs, pipelines, end use22

customers, marketing companies, producers and public service commissions. I have23

offered testimony in state and federal court proceedings, Federal Energy Regulatory24

Commission (“FERC”) cases and state regulatory agency proceedings. I have25

testified as an expert witness concerning issues such as gas supply prudency, cost26

functionalization, rate design, gas contracts, risk management, portfolio analysis, gas27

of 24


supply planning, billing determinants, and rate of return. In my role as a consultant, I1

have bought and sold natural gas and capacity for LDC clients, prepared and2

evaluated RFP’s, assisted in the preparation and filing of Gas Procurement Plans,3

prepared rate filings at the State and Federal level, evaluated rate cases for clients,4

evaluated design day and service mix, developed project economics, audited contract5

performance and performed audits of gas supply, risk management and marketing6

departments.7

Q. ON WHOSE BEHALF ARE YOU TESTIFYING?8

A. West Texas Gas, Inc. ("WTG").9

Q. WHAT ISSUES ARE YOU ADDRESSING?10

A. I will describe the rate increase filing made by WTG in this proceeding and explain11

the rate study that I developed to calculate WTG's proposed cost of service and rate12

design.13

II. RATE STUDY – COST OF SERVICE14

Q. WITH RESPECT TO THE OVERALL PROPOSED RATE INCREASE,15PLEASE IDENTIFY THE RELEVANT EXHIBIT AND BRIEFLY DESCRIBE16ITS COMPONENTS.17

A. Attached under the tab RATE STUDY (JRU-1) is the rate study that underlies the rate18

increase proposed by WTG in this proceeding. Schedules A through Q delineate the19

cost of service and its various components and show the development of the proposed20

Domestic and Non-Domestic rates. A copy of the rate study in Excel format has been21

filed with my testimony. Schedules A through L1.1 of the Rate Study show the22

company’s cost of service, cost allocation and rate design. Schedules M through Q23

support various aspects of the study. The first page of the Rate Study contains a list24

of the witnesses for WTG who support individual schedules. I am supporting the25

overall calculations and the underlying logic used to develop rates, but others26

provided critical inputs, such as accounting data, the recommended rate of return, and27

depreciation rates.28

The rate study was prepared by me using a document from the Gas Services Division29

that was provided to me by WTG’s attorney. The document sets out Commission30

of 24


Staff's suggestions for which schedules should be included in a request for a rate1

increase. WTG has endeavored to follow this outline as closely as possible, while2

adding a few additional schedules and tailoring the schedule formats where, in my3

opinion, it would provide greater clarity. A copy of the Railroad Commission Staff4

document is attached as Exhibit JRU-2.5

Q. ARE THE COST OF SERVICE AND RATES IDENTICAL TO THOSE FILED6WITH THE CITIES?7

A. Yes. However, as the filing for the unincorporated area was being prepared, Ms.8

Barbara Geffken and I noticed that there were some schedules that had incorrect9

labels and omissions of data. These have been corrected in this filing. Behind any10

sheet with an error is a comparable sheet with the corrections. In each instance, the11

entry corrected is highlighted. None of these corrections change the overall cost of12

service as they are either incorrect notes or labels or items contained on schedules13

whose purpose is to provide accounting detail, but additions and deletions of such14

items where errors were detected, did not cause a change in the overall cost of15

service.16

We discovered one substantive item. WTG’s expenses include $15,163 in donations17

and charitable contributions that are not includable for rate making purposes under18

the Commission’s Rule 7.5414. These amounts are detailed on Schedule G-6. After19

allocation, the Domestic rate amount is $4,842 and the Non-Domestic amount is20

$1,012. Unfortunately, this error was discovered while the case was in production, so21

it was not possible to make the corrections in time. However, WTG will not seek to22

collect this item from its jurisdictional customers, will correct the proposed rates, and23

will provide the parties with a revised Rate Study prior to the hearing on the merits.24

Q. PLEASE DESCRIBE THE COMPONENTS OF THE COST OF SERVICE.25

A. The cost of service was derived from the books and records of WTG for the twelve26

months ending June 30, 2012, with adjustments for known and measurable changes.27

As shown on Schedule A, the total (non-gas) cost of service associated with Texas28

Operations, both jurisdictional and non-jurisdictional, is $ 21.8 million. Schedule A29

shows the major components of the Cost of Service including Operating &30

of 24


Maintenance and Administrative Expenses, Depreciation Expense, Taxes Other Than1

Income, State and Federal Income Taxes, and Return.2

Q. IN GENERAL TERMS, HOW WAS THE COST OF SERVICE DERIVED3FROM THE COMPANY’S BOOKS AND RECORDS?4

A. WTG is a wholly owned by Mr. J.L. Davis (“JLD”). JLD also owns WTG Gas5

Processing, LP and other companies, which are therefore affiliates of WTG. In6

addition, WTG has numerous subsidiaries which do not provide end-use gas service.7

Both affiliates and subsidiaries maintain their own books and records, which are8

distinct from WTG’s books and records. The organizational chart for JLD and WTG9

is shown on Schedule J-2 of the Rate Study and is sponsored by Richard Hatchett.10

WTG is a public utility which provides jurisdictional and non-jurisdictional sales and11

transportation in Texas and Oklahoma. The company maintains its utility accounting12

records by district (i.e., cost center). There are twenty-nine district cost centers,13

including a Corporate District for general corporate management.14

Although most of the districts operate solely in Texas or Oklahoma, the Wheeler and15

Texhoma districts operate in both states. In the Wheeler and Texhoma districts, plant16

and revenue is assigned a sub code which designates the state in which the plant or17

customer is located, however operating and maintenance expenses are not designated18

by state. Therefore plant and revenue can be directly assigned to Texas versus19

Oklahoma, but allocations must be made for expenses. In addition, there are a few20

districts that provide solely non-jurisdictional transportation. The Guymon District,21

designated SUG in the model and on company records, is a field office that22

supervises field operations for pipeline maintenance and meter reading for all of23

Oklahoma (except the Wheeler District), and Texhoma, Texas.24

Finally, there is the Corporate District, which oversees the total corporation. Some25

individuals, such as billing clerks whose salary and expenses are part of the corporate26

office, perform work solely for the gas utility operations, but work for both Texas and27

Oklahoma. Some individuals perform work for Texas utility operations only. Some28

individuals perform work for both the utility and WTG’s subsidiaries. For example,29

Mr. J. J. King manages all gas-related marketing for WTG and its subsidiaries. Some30

individuals also perform work for affiliates and subsidiaries, such as Ms. Barbara31

of 24


Geffken who is WTG’s Comptroller. As a result, only a portion of the costs1

contained in the Corporate District can be properly allocated to Texas utility2

operations. Except for the salaries and some related expenses recorded in the3

Corporate District, no other expenses or assets on WTG’s books have anything to do4

with any of WTG’s subsidiaries or other affiliates.5

In summary, the Rate Study shows detail for six general categories: Other Texas (any6

district that is solely related to Texas and provides both jurisdictional and non-7

jurisdictional sales in Texas), Transmission (non-jurisdictional transportation),8

Wheeler, Texhoma, SUG, Oklahoma (any district that is solely related to Oklahoma9

and provides sales and transportation in Oklahoma), and Corporate. The filing10

contains an accumulation of costs for each of these categories so the parties can see11

the total utility plant, expenses and revenues, and, where needed, allocations that are12

needed to derive a Texas utility cost of service, excluding costs that are incurred for13

other operations. For example, Oklahoma costs and revenues are shown, but14

excluded entirely when deriving the rate increase for Texas customers.15

Q. PLEASE DESCRIBE SCHEDULE A IN GREATER DETAIL.16

A. Schedule A is a high level summary schedule that is built up from the schedules17

referenced in Column B. Column C, Lines 1 through 8, shows cost of service18

components for the entire company. Two items are necessarily missing: return and19

income taxes. WTG’s return - i.e., net income, including interest expense, but after20

income taxes - is not shown because it includes numerous irrelevant items. For21

example, since WTG owns numerous subsidiaries, the per-books return includes22

changes in undistributed earnings of subsidiaries. Income is also affected by the23

earnings from non-jurisdictional sales and Oklahoma operations. Finally, WTG pays24

no income taxes, but flows through the tax liability to the owners. Per-books return is25

really a pre-tax return, and no federal income taxes are recorded on WTG's books.26

Column D, Line 1 through 8, shows adjustments to per-book numbers to derive total27

company amounts. For example, the company has annualized labor and removed any28

lobbying expenses. The labor annualization and lobby expense deletions, along with29

other expense adjustments are summarized on Line 1, Column D. As discussed30

of 24


above, not all of WTG’s costs are attributable to Texas, so an allocation adjustment is1

shown to remove non-Texas costs in Column F. The total cost of service attributable2

to Texas operations is shown on Column G., Lines 1 through 8. Lines 9 through 163

displays the Texas cost of service allocated to Domestic, Non-Domestic and Non-4

Jurisdictional customers classes.5

In general, Schedule A is a template for how the rate model was developed. For each6

category of costs, I have:7

(1) Provided the total per books amount;8

(2) Annualized and normalized the total for known and measureable changes,9

deleting any items that are not appropriately recoverable from jurisdictional10

customers, such as lobbying expenses;11

(3) Calculated the portion of the adjusted amount that is attributable to Texas12

operations; and13

(4) Allocated the appropriate amount to the Domestic, Non-Domestic, and Non-14

Jurisdictional customers.15

To perform step (3), I had to develop numerous schedules that are not normally found16

in a rate filing. Rather than append these schedules as work papers, I have directly17

incorporated them in the model as sub-schedules that generally follow the schedule18

where the amount is recorded.19

Q. WHAT INFORMATION IS CONTAINED IN SCHEDULE A-1?20

A. Schedule A-1 summarizes the actual and adjusted revenues, volumes, and customer21

counts. Page 1 shows revenues. Column B shows total company revenue by22

customer class. Columns C through E show the amounts that must be deducted to23

obtain Texas jurisdictional revenues - namely, non-jurisdictional revenues,24

transmission revenues, and Oklahoma revenues. Column G deducts cost of gas. All25

the actual revenues, volumes, and customer counts are shown in total and by month26

on Exhibits WRP 21 through 25 and are further explained by Mr. Rodney Pennington27

in his direct testimony. Finally, Column I shows the revenue adjustment for domestic28

and non-domestic customers. This adjustment is shown on Schedule A-2.1 and the29

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calculations supporting the adjustment are on Schedule A-2.2. The adjustment is1

obtained by calculating revenues at the proposed rates and volumes and then taking2

the difference with actual revenues.3

Page 2 of Schedule A-1 shows actual volumes and adjusted volumes in a comparable4

manner. All numbers are from Exhibit WRP-25, and explanations for the adjustments5

are contained in Mr. Pennington’s direct testimony. Similarly, page 3 of Schedule A-6

1 shows actual and adjusted customer count and again is taken from Exhibit WRP-25.7

Notice that, unlike page 1, which shows no non-jurisdictional revenues, pages 2 and 38

show adjusted non-jurisdictional volumes and customer count. The reason is that9

non-jurisdictional volumes and customer counts are used to apportion costs between10

the various customer classes, so it is necessary to calculate and show them.11

Q. PLEASE DESCRIBE SCHEDULE A-2.12

A. Schedule A-2 summarizes the adjustments to operating and maintenance expenses13

and taxes other than income taxes. Line 1 shows the effect of removing Account 858,14

Transmission and Compression by Others, from the cost of service. This account is15

recovered through the Cost of Gas. There is no work paper associated with this16

adjustment since the effect is simply to zero out the total account. Line 2 removes fuel17

and company use. Again, this account is recoverable through the Cost of Gas, and18

there is no need for work papers as the numbers were furnished by the company. The19

entire amount is contained in Account 880.0, and is in the Texas divisions as shown20

on Schedule A-4.1, Line 34. Lines 3, 4 and 5 show the effect of removing all21

lobbying expenses, all rate case preparation expenses (which will be surcharged22

separately), and a penalty associated with non-Texas operations. Details supporting23

these three adjustments are shown on Schedules G-7, G-11, and G-8, respectively.24

The labor annualization and the related payroll tax adjustment are shown on Lines 625

and 7. These adjustments are detailed by account on Schedule A-2.3. Mr. Hatchett is26

supporting this adjustment and his direct testimony addresses the rationale. Finally,27

there are two adjustments on Lines 8 and 9 that remove those O&M expenses and28

taxes other than income taxes that are not attributable to Texas Operations.29

Q. HOW DID YOU DERIVE THE ADJUSTMENT TO REMOVE NON-TEXAS30O&M EXPENSES?31

of 24


A. The amount of the adjustment is $4,813,995. Schedule A-4, Column F, shows the1

adjustment by FERC account. The detailed calculations are shown on Schedule A-2

4.1. Schedules A-4.1.1, A-4.1.1.2, A-4.1.1.3 and A-4.1.1.4 support the calculations.3

In Schedule A-4.1, Lines 1 through 25 show total O&M expenses by FERC account,4

aggregated into several categories: namely Texas, Transmission, Oklahoma,5

Texhoma, Wheeler, SUG, and Corporate. Lines 26 through 50 show adjustments by6

FERC account, by category. These adjustments are listed on Schedule A-2, Lines 17

through 6. Total company O&M Expenses, after adjustment, are then calculated by8

summation on Lines 51 through 75. Line 76 shows the percentage of the adjusted9

amounts that are attributable to Texas operations. The amount attributable to Texas10

operations is then shown on Lines 77 through 101.11

Q. HOW ARE THE PERCENTAGES ON LINE 76 DERIVED AND APPLIED?12

A. Except for Corporate, the percentage attributable to Texas customers is multiplied by13

the amount in each account (Line 51 through 74) to calculate the amounts attributable14

to Texas operations. So, for example, 51.91% of Texhoma expenses are attributable15

to Texas operations.16

The expenses in Column D, labeled “Texas,” are from districts that are only in Texas17

and are related only to Texas operations. Hence, 100% of these costs are attributable18

to Texas operations. Column E consists of districts that maintain several small,19

isolated pipelines that provide no jurisdictional service, so 0% of these costs are20

claimed in this case. Similarly, 0% of Oklahoma costs are claimed. With respect to21

Texhoma, 51.91% of the costs are allocated to Texas. This percentage is the portion22

of Texhoma plant that is in Texas, the rest being Oklahoma-related plant. The23

calculation of the percentage is shown on Schedule A-4.1.2. Details of the Texhoma24

plant are shown on Schedule C-1.3. By the same token, Gross Plant is used as the25

allocator for Wheeler is shown on Schedule 4.1.3 and plant details in Schedule C-1.3.26

SUG is slightly different. SUG is a field office that oversees field operations for all27

of Oklahoma, except the Wheeler district and for Texhoma, Texas. Again the28

allocator is gross plant. The calculations are shown on Schedule A-4.1.4.29

Q. WHY IS GROSS PLANT THE APPROPRIATE ALLOCATION30DETERMINANT FOR WHEELER, TEXHOMA, AND SUG COSTS?31

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A WTG’s personnel do not keep time sheets as to which state they are working in, so a1

reasonable proxy must be developed that should reflect how such people spend their2

time. The standard, in my opinion, should not be arbitrary but some measure that3

approximates how and on what they actual work. These costs are associated with field4

operations – i.e. the maintenance and operations of facilities. Therefore the business5

of the staff at these locations is the operation and maintenance of pipe and related6

facilities. In my experience, field people are not concerned with volumes except if7

they become so high as to breach MAOP. Billing and revenue related items are8

handled by WTG’s corporate staff. Field personnel certainly worry about their9

expenses and do not want to adversely affect income, but total company expenses,10

corporate income and similar measures are outside of their purview. That basically11

leaves gross plant as the basis for apportioning costs.12

Q. DID YOU DETERMINE THE PERCENTAGE OF CORPORATE COSTS13THAT ARE ALLOCATED TO TEXAS OPERATIONS?14

A. The costs are allocated using two different factors. The relevant work paper is15

Schedule A-4.1.1. The allocation factors were used as shown on Lines 26 and 27.16

Again, the procedure is to apportion costs based on how the individual employees17

work and type of cost (e.g., materials, outside services). The calculations are shown18

in Schedule Q. One allocation factor, 87.01%, is developed by calculating the ratio of19

WTG Texas costs to WTG Other (generally Oklahoma) using four factors: Operating20

Expenses, Gross Plant, Net income, and Gross Revenue. This calculation is shown21

on Lines 18 – 20 of WP Salary Allocation. Many of WTG’s accounts represent costs22

that have been assigned to WTG because they are solely due to utility operations.23

These costs are assigned to Texas based on that factor. In particular, this factor is24

used to assign costs to Texas for mains, maintenance, outside services, miscellaneous,25

advertising, and property insurance expenses on Schedule A-4.1.1.26

However, there are certain employees whose salaries are recorded in WTG but who27

also perform non-utility work or work only in one state. Some of these employees28

work for (1) WTG, Texas only, some for (2) WTG, Texas and Oklahoma, some for29

(3) WTG and its subsidiaries, and some for (4) WTG, its affiliates and its30

subsidiaries. In each case, a portion of the salary based on four factors - plant,31

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income, revenue and operating expenses - is allocated to Texas. In total, I have1

calculated that 31.15% of these employees’ expenses should be allocated to Texas2

operations. This percentage is shown on Line 26 of Schedule A-4.1.1. Thus, only3

31.15% of administrative and general salaries is allocated to Texas operations. There4

are also several other categories of expenses that support personnel in their day to day5

activities that should be allocated on a similar basis. The other accounts that were6

allocated using the 31.15% are Office Supplies, Employee Pensions and Benefits, and7

(Office) Rents.8

Q. WHY DID YOU CHOOSE THE FOUR FACTORS, INCOME, REVENUE,9GROSS PLANT, AND OPERATING EXPENSE AS THE BASIS FOR10APPORTIONING COSTS?11

A. The ideal is to apportion costs based on cost causation. The corporate office performs12

an oversight function, managing the assets and personnel to minimize costs, operate13

safely, and generate revenues. Therefore, management will concern itself primarily14

with costs, revenues, and, for a capital-intensive business with limited inventory, hard15

assets. Therefore plant, revenues, and either total operating expenses or payroll are16

three of the main factors determining management time and focus. I have used total17

operating expenses, rather than payroll, because it seems to be the preferred allocator18

in this jurisdiction. I have included net income for the same reason -i.e., apparent19

Commission preference. In my experience, however, good management rarely20

concerns itself with income per se unless it is engaged in either managing stockholder21

expectations or exotic financing. Neither of these seems to be a concern of WTG.22

Nonetheless, inclusion of income does have the effect of lowering the amount of23

corporate expenses allocated to Texas operations and is in line with Commission24

precedent.25

Another possible allocator is customer count, which can be used in lieu of revenue.26

In my opinion, customer count would not be an appropriate allocator for a27

conglomerate as complex as WTG. The Company has some subsidiaries with many28

customers who interact little with management, such as WTG Fuels, which sells29

gasoline retail, and others such as the processing plants, which have large revenues30

and few customers. In general, management will worry more about a customer that is31

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generating big bills than a small customer. Using customer count as opposed to1

revenue would, for example, have the implicit effect of treating a small residential2

customer the same as, say, Conoco Phillips, and would over-allocate costs to the3

utility.4

Q. PLEASE DESCRIBE SCHEDULE B-1 THROUGH B-3.5

A. Schedule B-1 is a summary of WTG’s rate bases, both for the total company and for6

Texas Operations. All amounts on this schedule are calculated on the schedules7

referenced in Column B. Schedule B-2 summarizes the adjustments to per-books8

figures on Schedule B-1 and is a summary schedule. Schedule B-3 states that WTG9

is proposing no post-test year adjustments to rate base – i.e., WTG claims no10

construction work in progress and no annualizations relying on post-test year events.11

Q. PLEASE DESCRIBE SCHEDULE C-1.12

A. Schedule C-1 shows Gas Plant in Service by FERC account. Column C shows per-13

books amounts. Column D consists of adjustments that are explained on Schedule C-14

1.2. The amount allocated to Texas operations is shown on Column F and is derived15

on Schedule C-1.1.16

Q. WHAT ADJUSTMENTS WERE MADE TO GAS PLANT IN SERVICE?17

A. I made three adjustments. WTG has built its system in part by acquisitions. In some18

instances, the company paid premiums over net book for assets. I have removed such19

premiums, because they are typically not recoverable absent a strong showing of20

planned benefits to all customers. These adjustments are shown on Schedule C-1.2,21

Lines 1, and Lines 5 through 8. The second adjustment removes gas plant held for22

future use that was recorded in Accounts 303.0 and 367.0. This calculation is shown23

on Lines 2 and 3 of Schedule C-1.2. The third adjustment removes plant that is not24

Texas related (Line 9) and is shown in Schedule C-1.1.25

Q. PLEASE DESCRIBE SCHEDULE C-1.1.26

A. WTG per-books plant is shown on Lines1 through 34. It is broken out into four27

categories: Texas Plant (plant that is physically located in Texas), Oklahoma Plant,28

Non-utility Transmission Plant, and Corporate Plant. The location of the plant was29

determined from the company’s records. The adjustments from Schedule C-1.2 are30

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made on Lines 35 through 68 to derive an adjusted plant – i.e., plant without gas1

acquisition premiums or plant held for future use. The adjusted plant is the allocated2

to Texas operations using the percentages shown on Line 103.3

Q WHAT PERCENTAGE OF PLANT WAS ALLOCATED TO TEXAS4OPERATIONS?5

A. 100% of Texas Plant was allocated, 0% of Oklahoma Plant, 0% of Non-Utility6

Transmission, and 89.6% of Corporate Plant. The Corporate Plant allocated is based7

on the ratio of Texas Plant to total plant. Since 89.6% of the plant is attributable to8

Texas, the same proportion of Corporate Plant is assigned to Texas. The ratio method9

used here for Corporate Plant is the Kansas-Nebraska method used by FERC for10

assigning general and intangible plant to different services for systems with11

incremental projects and for systems that offer services other than firm transportation.12

Q. PLEASE DESCRIBE SCHEDULE D-1.13

A. Schedule D-1 is comparable to Schedule C-1, except that it shows accumulated14

depreciation by FERC account. It is similar to Schedule C-1 with the adjustments15

referenced on Schedule D-1.2 and the allocation to Texas operations on Schedule D-16

1.1.17

Q. PLEASE DESCRIBE SCHEDULE D-2.18

A. This is a three-page schedule. The first page shows plant attributable to Texas in19

Column D and applies the depreciation rates claimed in this case (Column E) to that20

plant to calculate total depreciation expense for WTG-Texas. The second page shows21

the depreciation expense that would be obtained if the same rates were applied to total22

WTG plant, including Oklahoma. The third page shows current versus proposed23

depreciation rates. The depreciation rates claimed in this case are supported by Mr.24

Dane Watson and discussed in his direct testimony.25

Q. SCHEDULE E-4 PAGE 1 SHOWS CUSTOMER DEPOSITS. HAS THIS26AMOUNT BEEN CREDITED TO RATE BASE IN THIS PROCEEDING?27

A. No. WTG accrues interest on customer deposits and refunds the deposits with28

interest to customers at the appropriate times, as explained by Mr. Richard Hatchett.29

Reasonable treatment of these amounts is either to pay interest on deposits or to credit30

the principal to rate base. Since WTG’s tariff provides for interest, I have not31

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credited these amounts to rate base. The amounts shown include both deposits for1

jurisdictional rate schedules, which are governed by the tariff, and non-jurisdictional2

services which are covered by individual contracts.3

Q. PLEASE DESCRIBE SCHEDULE H-1.4

A. Schedule H-1 shows the calculation of Federal Income Taxes using the corporate tax5

rate of 35%. The return and interest expense on Lines 2 and 3 are calculated by6

multiplying the rate of return and interest components of return times rate base. The7

return and interest rate used are that shown on Schedule F-1 supported by Mr. Bruce8

Fairchild in his direct testimony. The use of a tax rate of 35% is standard industry9

practice, designed to ensure that small utilities and partnerships receive comparable10

treatment and have equal access to capital markets. Moreover, WTG’s counsel11

informs me that, as a matter of statute, the use of the corporate tax rate is mandated12

by Texas law.13

Q. WHAT IS THE PURPOSE OF SCHEDULE H-2?14

A. As shown on Schedule H-3, WTG is not an income-tax paying entity and has no15

deferred income taxes on its books. Instead, the benefits of accelerated depreciation16

are flowed through to the owner of the company. However, the use of the standard17

income tax rate on Schedule H-1 without an adjustment for accelerated depreciation18

in the calculation of income taxes means that WTG is collecting a portion of the19

owner’s deferred tax liability in rates. It is standard practice in such cases to deduct20

deferred taxes from rate base in order to flow the benefit of this funding through to21

rate payers. The schedule nets the difference between WTG’s book-basis plant and22

tax-basis plant (Lines 1 through 3) and multiplies that difference by the federal tax23

rate of 35% to calculate a total WTG deferred tax balance of $23,768,476 (Line 5).24

To determine the amount associated with Texas operation I prorated the total deferred25

tax balance using gross plant. WTG was not able to provide tax basis plant by26

district, so a proration was necessary to derive an amount that should be credited to27

rate base.28

Q. PLEASE EXPLAIN SCHEDULE I-2.29

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A. This Schedule is comparable to Schedule A-4 in format. It shows total Taxes other1

than Income Taxes for WTG, shows the adjustments for each item and then the2

amount allocated to WTG’s Texas operations. The details are shown on Schedule I-3

2. There is one adjustment on Schedule I-2.1, namely to payroll taxes on Line 20,4

which is associated with the labor adjustment described on Schedule A-2.3. The5

factors used to determine the amount associated with Texas Operations (Line 34) are6

the same as those used to allocate O&M expenses to Texas operations on Schedule A-7

4.1, Line 76.8

Q. PLEASE EXPLAIN SCHEDULE J-4.9

A. Schedule J-4 shows which charges from affiliate companies shown on Schedule J-310

are included in the claimed cost of service. As shown on Column E, no cost of gas,11

transportation fees, or interest paid is included in the cost of service. Column H12

shows, for informational purposes, the amount of each claimed item that is included13

in Texas operations. Column H was derived by working through the rate model.14

Q. PLEASE EXPLAIN SCHEDULE K-2.2.15

A Schedule K 2.2 shows credits to cost of service – i.e., those minor sources of revenue16

to which costs are not, and in general cannot be, allocated in a rate case. For17

example, penalty revenue is a standard credit. Penalties, by their very nature, are not18

cost based. Another credit is drip and condensate sales. This is revenue from liquids19

that drop out of the gas stream during transportation, which is collected by the utility.20

Strict cost allocation to such sales typically requires a chemical analysis of the gas21

stream that is beyond the physical capabilities of most utilities.22

III. RATE STUDY – COST CLASSIFICATION, ALLOCATION AND RATE DESIGN23

Q. WHAT IS THE PURPOSE OF SCHEDULE K-1 THROUGH K-1.6.24

A. Schedule A-1, Lines 9 through 16, shows the cost of service for Texas operations25

broken out among Domestic, Non-Domestic, and Non-Jurisdictional services.26

Schedules K-1.1 through K-1.6 displays the calculations that lead to that result.27

28

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Schedule K-1 is a summary of the cost of service as allocated to the three categories.1

Schedule K-1.4 shows the rate base, return, and income taxes as allocated to the three2

categories, while Schedules K-1.2 and K-1.3 show the allocation for gross plant and3

accumulated depreciation, respectively. Schedule K-1.5 is the allocation of O&M4

expenses. Schedule K-1.6 is the allocation of taxes other than income taxes. Schedule5

K-1.1 shows the major factors that were used to make the allocations shown on6

Schedules K -1.2 through K-1.6. Page 2 of Schedule K-1 is the rate design. Since7

Schedule K-1 depends on Schedules K-1.1 through K-1.6, it is best to start with the8

sub-schedules in order to understand the logic of the rate design.9


A. This schedule shows the most important factors used to split costs between the11

various customer categories. The top four Lines show how costs are apportioned12

between the Customer and Capacity classifications. “Customer” is used to allocate13

those costs that would be incurred by WTG irrespective of customer size and14

consumption –i.e., those costs that WTG would incur simply because of the existence15

of a customer and his or her geographical location. “Capacity” is used to apportion16

costs that depend on customers’ normal or expected consumption. In order to17

determine “Customer” costs, WTG constructed a replacement cost model of its18

system. This model, shown on Schedules N and O, is explained by Mr. Richard19

Hatchett is his direct testimony. For example, Schedule N (Meter Cost Analysis),20

WTG has about 22,000 customer meters of varying size (Column B). If all the meters21

were rebuilt today at the basic minimum size, the cost would be about $7.8 million22

(Column F). If all the meters were replaced with comparable meters the cost would23

be approximately $11.7 million (Column E). In summary, 66% (Column F, Line 10)24

of the meter cost is incurred just because 22,000 customers are on the system, spread25

out along different locations. The balance of the costs is incurred because some of26

the customers need larger or more sophisticated meters.27

Similarly, Schedule O (Pipeline Cost Analysis) splits the cost of pipe between28

customer and commodity. The critical factor in this case is the minimum pipe size of29

2-inches used to connect customers, without regard to customer size. Schedule M30

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(Summary Plant Study) summarizes the cost calculations from the two1

aforementioned work papers and calculates an aggregate customer cost on Line 9.2

The first step in apportioning costs between Domestic, Non-Domestic, and Non-3

Jurisdictional categories is to classify costs between Customer and Capacity.4

Schedule K-1.1 (Lines 1-3) shows the results from Summary Plant Study. These are5

used repeatedly to classify costs between Capacity and Customer. These factors are6

used to apportion transmission and distribution plant between the three customer7

categories. When the results are summarized for transmission and distribution plant8

(Accounts 332 through 378), a percentage can be calculated and used to apportion9

costs for intangible and general plant. The calculation is done on Schedule K-1.2,10

Line 29 through 32 and displayed as Line 4 on Schedule K-1.1.11

Customer costs and Capacity costs are split differently between the three service12

categories. The factors are shown on Lines 5 through 10 of Schedule K-1.1 Errata.13

(Note: In the original schedule, the last line, Line 10, is incorrectly labeled Line 4.)14

The factors are customer count, design day, throughput, and a total gas plant factor15

derived on Schedule K-1.1 as discussed above. Column B references the schedule16

from which the numbers are derived.17

Q. WHAT IS THE “DESIGN DAY WORKPAPER” ON SCHEDULE P THAT IS18REFERENCED IN SCHEDULE M?19

A. One of the standard allocators for costs is Design Day. Mr. Pennington has20

discussed, in his testimony, WRP-26, the calculation of WTG’s Design Day. The21

results from that exhibit have been summarized and brought forward as Columns A22

through E on Schedule P. To this I have made one adjustment. Irrigation gas is23

primarily a summer phenomena which is sold on an interruptible basis. In point of24

fact, field irrigation is not physically possible when temperatures are below freezing.25

Under strict cost causation any cost allocation factors using design day would assign26

zero costs to the irrigation load. However, it is fairly common for both sellers of27

summer services and regulators to insist that such load, albeit interruptible on peak,28

should pick up some portion of costs as a matter of equity. Accordingly I have added29

back an adjustment for irrigation load in Column F for off-peak irrigation. The30

amount added back is the annual average day - i.e., average annual sales divided by31

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365. This has the effect of allocating more costs to the non-jurisdictional load than a1

more rigorous cost causation-based allocation. The rationale is that even though no2

facilities are sized based on interruptible off-peak irrigation load, the irrigation3

customers absorb a portion of such costs based on their average test year utilization of4

the system.5


A. This schedule first allocates gross plant by account to the Customer and Capacity7

categories and then to the Domestic, Non-Domestic, and Jurisdictional customer8

classes. To see how it works, look at Lines 23 and 24. The total balance of9

Distribution Mains, Account 367, is $71,442,183 (Line 23, Column C). The allocator10

“Pipe” is used to apportion this amount between Customer and Capacity. This11

references back to the Pipe Allocator on Line 1 of Schedule K-1.1, which states that12

39% should be allocated to Customer and 61% to Capacity. The Customer amount is13

on Line 23 Column D. To split the Customer amount among customer classes, the14

allocator “Customer Count” is used. This refers to the Customer Count percentages15

shown on Schedule K-1.1, Line 6. The resulting allocation is shown on Line 23,16

Columns F through H. Finally, Column I, labeled “Basis,” summarizes the factors17

used to make the allocation. For example, Line 23, Column I, contains the entry18

“Pipe, Customer Count.” This means that the allocation to the first category,19

“Customer,” was made bases on the Pipe allocator on Schedule K-1.1, and the20

allocation to the customer classes was made based on the Customer Count allocator21

on the same schedule.22

Q. WHAT RATIONALE WAS USED TO DETERMINE THE ALLOCATORS23LISTED IN COLUMN I.24

A. The schedule is laid out by FERC account in ascending order of account number, but25

it is more logical to work through the Schedule in a different order.26

Account 367.0 – Distribution Mains. The allocation to Customer/Capacity is based27

on Pipe. Pipe, recall, is in turn based on a plant study that determines the percentage28

cost of plant that would be necessary to serve WTG’s customers, irrespective of29

customer size. This determines the Customer percentage (39%). The balance of the30

cost, 61%, is assigned to capacity and is due to the different customer demand.31

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Larger pipe, more capacity, is needed to serve larger customers. It is therefore1

reasonable to split Distribution mains based on the Pipe allocator. The customer costs2

are then allocated based on Customer Count, thus assigning to each customer a pro3

rata share of this cost based not on size or load, but on the fact that he or she is one4

customer among many attached to the system.5

The capacity costs are then allocated based on Design Day. Distribution mains are6

generally smaller diameter pipe that is sized to deliver to each customer the maximum7

amount of gas he is likely to take. This maximum occurs on Design Day. Each8

customer is thus assigned that portion of Capacity Distribution Mains, based on the9

maximum amount he or she is likely to take. This, in turn, drives pipeline size.10

Account 378.0 – Distribution Measurement and Regulating Stations. As with Mains,11

there is a study that determines the percentage of meter cost that is caused by a12

customer, qua customer, irrespective of size, and the percentage of costs related to13

different customers’ maximum likely takes. This study is encapsulated in the Meter14

allocator on Schedule K-1 (Line 2). As with Mains, given the nature of the15

Customer/Capacity split the appropriate way to spread costs to the customer classes is16

Customer Count for Customer Costs and Design Day for Capacity Costs. Meters,17

like Distribution Pipe are sized based on maximum throughput.18

Account 377.0 – Distribution Compressor Station Equipment. The allocation19

between Customer and Capacity is based on the Aggregate Allocator (Line 3 of20

Schedule K-1). This allocator is a weighted average of the Pipe Study and the Meter21

study. WTG has not done a compressor replacement cost study, so a composite of22

pipe and meter costs were used instead. In my opinion, this is reasonable.23

Compressor stations are individually engineered and installed. Unlike pipe and24

meters, this is not an ongoing construction item for WTG or most other utilities.25

Hence, it would require a separate analysis involving bid solicitation and engineering26

schematics and possibly transient flow modeling. Given the small size of the27

account, less than $400,000, the required expense would not be justified. Moreover,28

the basic drivers of the differences between replacement cost and actual cost,29

inflation, and tightening environmental standards are the same as for meters and pipe.30

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The rationale for apportioning costs between customer classes is the same as for the1

above two accounts.2

Accounts 332.0, 3333.0 and 334.0. Field related mains, measurement, and3

equipment. Small diameter pipe and related facilities expense is booked to these4

accounts. The primary purpose of these facilities is to deliver gas supply into the5

system, although WTG does have customers on these lines. I have used Pipe as the6

allocator between Customer and Capacity, but in the case of both Customer and7

Capacity used throughput to allocate between customer classes. Since these are8

primarily gas supply related, the size of the pipe is determined not by number of9

customers or the size of individual customers, but rather by the amount of gas that is10

likely to be gathered and/or transported to the mainlines. I have not used Meters to11

apportion Account 334.0, even though some metering equipment can be included in12

this account. The meters that underlie the Meter Replacement Study are delivery13

meters. The meters in this account are receipt meters.14

Accounts 365.2 through 371.0 These accounts, transmission accounts, are generally15

associated with higher pressure and larger diameter pipe. The Aggregate allocator16

was used to apportion costs between Customer and Commodity except for17

Transmission Mains (where Pipe was used since this is a pipe-related account.)18

Aggregate was used to apportion costs in the case of measurement and regulating19

stations since again, these are not, generally, distribution delivery meters, but receipt20

meters and check meters. Large diameter pipe is installed based on the maximum21

expected throughput. In designing such facilities, customer count per se is not a22

major consideration because the purpose of the pipe is to get gas to a sub-division or23

town where it will be fed into the smaller diameter pipe to reach the individual24

customers. The consideration in sizing these facilities is maximum expected25

throughput, or Design Day. Hence, Design Day was used to apportion costs between26

the customer classes for both Customer and Commodity categories.27

Lines 29 through 32 tallies the resulting allocated costs for Transmission and28

Distribution plant and calculates the associated percentages by Customer/Capacity29

and by customer class. These percentages are used to allocate the remaining plant30

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accounts. The other accounts include such items as trucks, communication1

equipment, land, and office furniture. In effect, these items that support the basic2

pipe-and-meters system. Hence, a proration on the results on the Transmission and3

Distribution Plant allocation is reasonable.4

Q. PLEASE DESCRIBE SCHEDULE K-1.3.5

A. This is a schedule showing the allocation of accumulated depreciation to the three6

customer categories, Domestic, Non-Domestic, and Non-Jurisdictional. The7

accumulated depreciation for each account is prorated on the results of the8

corresponding gross plant account.9


A. This displays the allocated rate base. The first two lines are a summary of Gross Plant11

and Accumulated Depreciation shown on Schedules K-1.2 and K-1.3, respectively.12

Line 3 is the allocation of Aids to Construction, which like Accumulated13

Depreciation, reduces rate base. The allocation of this item is a two-step process.14

First, based on Schedule E-4, page 2, there is a clearly defined assignment between15

jurisdictional service (Domestic and Non-Domestic). The number in Column F, Non -16

Jurisdictional Aid in Construction is thus a direct assignment. The remaining balance17

is assigned to the jurisdictional classes based on a proration using Gross Plant. As18

will become clear later, because of the way rates are designed, it is irrelevant as to19

how the Domestic, or Non-Domestic, Aid in Construction is split between the20

Customer and Capacity categories.21

Materials and Supplies (Line 7) and Deferred Taxes (Line 9) are prorated on Gross22

Plant, which is the primary driver from a cost-causation perspective of these items.23

Return (Line 11) and Federal Income Taxes (Line 12) are allocated based on the total24

Rate Base. This method is mathematically equivalent to going through the return and25

tax calculations (Schedule H-1) for each column.26

Depreciation Expense is prorated on Gross Plant because Depreciation Expense is a27

function of Gross Plant.28


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A. This schedule shows the allocation to Customer/Capacity, then among Domestic,1

Non-Domestic, and Non-Jurisdictional customer classes. It is calculated in the same2

manner as Schedule K-1.2, with the allocators shown in Column I. The first3

descriptor in each line designates the allocator for the Customer/Capacity Split and4

the second designates the allocator used to split costs between customer classes. The5

rationale for the allocators selected is as follows:6

Account 813 – Other Gas Supply Expenses. As with most O&M accounts the7

Capacity/Commodity split is based on Total Gas Plant (Line 4, Schedule K-1.1)8

because the O&M accounts (813 through 894) are generally associated with the9

maintenance and operations of facilities. Throughput is used to allocate to the10

customer classes since this is a supply related account. Note that because of the way11

rates are designed, if the same allocator is used to apportion both Customer costs and12

Capacity costs to customer classes, the selection of the allocator used to split costs13

between Customer and Commodity is irrelevant.14

Accounts 863, 874 and 887. These are accounts associated with the operation and15

maintenance of pipe, so Pipe was used to apportion costs between Customer and16

Capacity. Customer Count is used for allocating Customer costs, and Design Day, for17

Capacity costs. Operation and maintenance of mains is recorded in these accounts so18

the same allocators are used here that are used to allocate the underlying plant19

accounts.20

Account 889 – Measurement and Regulating Expenses. Since this is a meter-related21

account the Meter Replacement Study (Line 2, Schedule K-1) results are used to split22

costs between Customer and Capacity. Customer Count and Design Day are used to23

allocate costs between customer classes. Again the same allocation is employed here24

as is used to apportion the meter-related distribution plant.25

The balance of the 800 Accounts are apportioned between Customer and Capacity26

based on Total Plant (Line 4, Schedule K-1.1), as are the plant accounts. The costs are27

then split between customer classes using Customer Count and Design Day as is the28

underlying distribution plant.29

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Account 924. Property Insurance. This account is split based on Total Gas Plant1

since this account records the insurance associated with the underlying gas plant.2

Generally, insurance varies directly with the cost of the property being insured, so3

this account is apportioned in the same ratios as Total Gas Plant and customer classes4

are apportioned in the same manner as for the accounts discussed above.5

The balance of the A&G accounts from 920 to 931 (Except for Account 924), which6

include such items as administrative salaries, pensions and benefits, office supplies,7

etc., are apportioned using Lines 52 and 53 of Schedule K-1.5. Lines 52 and 53 are a8

summary of the allocated expenses for all the 800 accounts. Basically,9

Administrative and General Expenses are apportioned based on those accounts that10

can be more directly related to specific facilities and customer classes.11

In the model Account 904 and Account 913 are allocated using first Total Gas Plant12

and then Customer Count and Design Day. Upon reflection, I believe that these13

accounts should more appropriately be apportioned in the same manner as the other14

900 accounts. However, since the use of that method will allocate slightly more costs15

to the jurisdictional services, less than $1,000, I have elected not to make that change16

in the model at this time.17


A. This schedule shows the allocation of Taxes Other Than Income Taxes. It is19

constructed in the same manner as Schedule K-1.5. Ad Valorem Taxes and Franchise20

Taxes, which are ultimately due to the existence, value and cost of the underlying21

physical plant, are allocated in the same manner as overall distribution plant.22

Namely, the apportionment between Customer and Capacity is based on Total Gas23

Plant and the allocated to customer class using Customer Count and Design Day.24

Miscellaneous Receipts Tax, which is assessed on a per Mcf basis, is allocated using25

throughput as are Other Taxes. Payroll Taxes are allocated using the same ratios as26

the underlying payroll. I have allocated them with a proration using Account 920,27

Administrative Salaries.28

Q. ONCE A COST OF SERVICE BY CUSTOMER CATEGORY WAS29DEVELOPED AND SUMMARIZED ON SCHEDULE K-1, PAGE 1, HOW30WERE RATES DESIGNED?31

of 24


A. The rate design is shown on Schedule K-1, Page 2. The allocated cost for Domestic1

and Non-Domestic customers is shown on Line 1 and compared to the revenue that2

would be generated at current rates, using the billing determinants calculated on3

Schedule A-1. Allocated cost is 97.53% higher than generated revenue for Domestic4

customers and 14.18% higher for Non-Domestic customers (Line 9). The last step is5

to increase current rates by the percentages listed above to equate proposed revenue6

and allocated cost.7

This method represents a deviation from rates designed under cost behavior. In cost8

behavior rate design the allocated Customer Cost is divided by the annual customer9

count to yield the Demand Charge and the allocated Capacity Cost is divided by10

annual sales billing determinants to generate the Commodity Charge. Cost Behavior11

rate design is the standard procedure used by FERC. However, in the opinion of12

WTG marketing staff it generates too high of a Demand Charge, so the procedure13

outlined above has been used instead in this case to keep the fixed Demand Charge14

lower.15

Q. WHAT IS SCHEDULE L?16

A. Schedule L shows the impact of the rate increase on an individual customer’s17

monthly bill. The assumption is that a Domestic customer will use 6 Mcf and a Non-18

Domestic customer will use 30 Mcf. The effect of the increase is shown both with19

cost of gas (Line 16) and without (Line 7). The cost of gas per Mcf is shown on Line20

17. This is the average cost of gas for the Test Year.21

IV. CONCLUSION22

Q. DOES THAT COMPLETE YOUR DIRECT TESTIMONY?23

A. Yes.24

25

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Direct Testimony of Dane A. WatsonWest Texas Gas, Inc.



))))

GUD NO. _____________

DIRECT TESTIMONY OF DANE A. WATSON, PE, CDP1

TABLE OF CONTENTS2

EXECUTIVE SUMMARY OF DANE A. WATSON, PE, CDP............................................................23

I. POSITION AND QUALIFICATIONS ........................................................................................34

II. PURPOSE AND SUMMARY OF DIRECT TESTIMONY .............................................................45

III. WEST TEXAS GAS DEPRECIATION STUDY...........................................................................66

A. Summary Of The Depreciation Study Results..........................................................67

B. Overview of Depreciation Study.............................................................................88

C. Service Lives...........................................................................................................99

D. Net Salvage..........................................................................................................1310

IV. CONCLUSION .................................................................................................................1311

12

EXHIBITS13


Exhibit DAW-1 West Texas Gas Depreciation Study at December 31, 201115

Exhibit DAW-2 List of Testimony Provided in Previous Regulatory Proceedings16

17

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EXECUTIVE SUMMARY OF DANE A. WATSON, PE, CDP1

I have performed a depreciation study of West Texas Gas (“WTG”) based on the2

depreciable plant in service at December 31, 2011. The results of my depreciation study3

support an annualized depreciation expense for West Texas Gas of approximately $3.04

million. This represents an increase of approximately $355,000 over the annualized5

depreciation expense calculated on year-end 2011 investment using the current6

depreciation rates on a system-wide basis. Specifically, compared to the depreciation7

rates currently in effect, my proposed depreciation rates will result in an increase in8

annual depreciation expense of approximately $66,000 in Intangible assets, a decrease in9

annual depreciation expense of approximately $10,000 in Gathering assets, an increase of10

$69,000 in Transmission assets, an increase of $439,000 in Distribution assets, and a11

decrease of $208,000 in General Plant assets.12

Detailed information regarding the service life and net salvage characteristics that13

support my proposed depreciation rates can be found in the depreciation study14

accompanying my testimony, as well as my workpapers.15

16

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I. POSITION AND QUALIFICATIONS1

Q. PLEASE STATE YOUR NAME AND BY WHOM YOU ARE2

EMPLOYED.3

A. My name is Dane A. Watson. I am a Partner of Alliance Consulting Group.4

Alliance Consulting Group provides consulting and expert services to the utility5

industry.6

Q. ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING?7

A. I am filing testimony on behalf of the West Texas Gas (“WTG” or “Company”).8

Q. PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND.9

A. I hold a Bachelor of Science degree in Electrical Engineering from the University10

of Arkansas at Fayetteville and a Master’s Degree in Business Administration11

from Amberton University.12

Q. DO YOU HOLD ANY SPECIAL CERTIFICATION AS A13

DEPRECIATION EXPERT?14

A. Yes. The Society of Depreciation Professionals (“SDP”) has established national15

standards for depreciation professionals. The SDP administers an examination16

and has certain required qualifications to become certified in this field. I met all17

requirements and hold a Certified Depreciation Professional certification.18

Q. PLEASE DESCRIBE YOUR PROFESSIONAL EXPERIENCE.19

A. Since graduating from college in 1985, I have worked in the area of depreciation20

and valuation. I founded Alliance Consulting Group in 2004 and am responsible21

for conducting depreciation, valuation, and certain accounting-related studies for22

clients in various industries. My duties related to depreciation studies include the23

assembly and analysis of historical and simulated data, conducting field reviews,24

determining service life and net salvage estimates, calculating annual25

depreciation, presenting recommended depreciation rates to utility management26

for its consideration, and supporting such rates before regulatory bodies.27

My prior employment from 1985 to 2004 was with Texas Utilities Electric28

Company and successor companies (“TXU”). During my tenure with TXU, I was29

responsible for, among other things, conducting valuation and depreciation30

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studies for the domestic TXU companies. During that time, I served as Manager1

of Property Accounting Services and Records Management in addition to my2

depreciation responsibilities.3

I have twice been Chair of the Edison Electric Institute (“EEI”) Property4

Accounting and Valuation Committee and have been Chairman of EEI’s5

Depreciation and Economic Issues Subcommittee. I am a Registered Professional6

Engineer in the State of Texas. I am a Senior Member of the Institute of7

Electrical and Electronics Engineers (“IEEE”) and served for several years as an8

officer of the Executive Board of the Dallas Section of IEEE. I am also a Past-9

President of the Society of Depreciation Professionals.10

Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE ANY REGULATORY11

COMMISSIONS?12

A. I have testified before the Railroad Commission of Texas (“Commission”) in the13

following Dockets: Gas Utilities Docket (“GUD”) Nos. 8976, 9145-9148, 9225,14

9313, 9400, 9670, 9762, 9869, 9902, 10000, 10038, 10041. 10147, 10170 10174,15

and 10182 on behalf of Atmos Energy Corporation’s (“Atmos”) Pipeline-Texas16

Division (formerly known as TXU Lone Star Pipeline) and Mid-Tex Division17

(formerly known as TXU Gas Distribution), and the CenterPoint Houston18

Division, South Texas Division, and Beaumont/ East Texas Davison. I have19

appeared before numerous other state and federal agencies in my 27-year career in20

performing depreciation studies. I have also appeared in Federal Energy21

Regulatory Commission (“FERC”) Docket No. 02-07-00 as an industry panelist22

on asset retirement obligations. A list of regulatory proceedings in which I have23

previously provided testimony is provided as Exhibit DAW-2.24

II. PURPOSE AND SUMMARY OF DIRECT TESTIMONY25

Q. WHAT IS THE PURPOSE OF YOUR DIRECT TESTIMONY IN THIS26

PROCEEDING?27

A. The purpose of my testimony is to:28

Discuss the recent depreciation study completed for West Texas Gas.29

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Support and justify the recommended depreciation rate changes for the1

West Texas Gas based on the results of the depreciation study.2

Q. WHAT DEPRECIATION EXPENSE ARE YOU RECOMMENDING IN3

THIS PROCEEDING FOR WEST TEXAS GAS?4

A. Based on the depreciation study, which analyzed the Company’s depreciable plant5

in service at December 31, 2011, I recommend an annualized depreciation6

expense of approximately $2.990 million. This represents an increase of7

approximately $355,000 over the annualized depreciation expense calculated on8

investment as of December 31, 2011, using the current depreciation rates which9

are based on the current item-based depreciation rates.10

Q. WHAT ARE THE PRIMARY FACTORS THAT HAVE INFLUENCED THE CHANGE IN11

THE COMPANY’S DEPRECIATION RATES?12

A. West Texas Gas is currently using an item-based depreciation system where13

individual assets have an assigned component life. Also, the Company is14

capitalizing removal cost for old assets into the new installation. In this study, I15

am recommending a change to group depreciation, where each plant account or16

sub group is depreciated based on a common rate for the group as well as17

recommend the Company begin to record removal cost against the depreciation18

reserve instead of as part of the new asset. For this study, I analyzed historic19

results with an experience band of 1998-2011 including retirement of fully20

accrued assets. As a result, I am recommending an average service life and Iowa21

curve for each account as compared to the item-based accrual rates currently in22

place in order to more accurately reflect the Company’s more recent and specific23

retirement experience. Based on my analysis of both the Company’s statistical24

data and field experience, the recommended lives are longer than currently being25

used for components.26

Q. DOES THE DEPRECIATION STUDY YOU SPONSOR IN THIS CASE REFLECT THE27

MOST CURRENT DATA AVAILABLE FOR WEST TEXAS GAS ASSETS?28

A. Yes. The data used reflects the most recent experience and future expectations for29

life and net salvage characteristics for West Texas Gas assets.30

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III. WEST TEXAS GAS DEPRECIATION STUDY1

A. Summary Of The Depreciation Study Results2

Q. DID YOU PREPARE THE WEST TEXAS GAS DEPRECIATION STUDY?3

A. Yes. The West Texas Gas Study is attached to my testimony as Exhibit DAW–1.4

The study in Exhibit DAW-1 analyzes the life and net salvage percentage for the5

property groups associated with the Texas intangible, gathering, transmission,6

distribution and general plant assets of West Texas Gas at December 31, 2011.7

Q. WHAT PROPERTY IS INCLUDED IN THE DEPRECIATION STUDY?8

A. There are five general classes, or functional groups, of depreciable property:9

Intangible Property, Gathering Property, Transmission Property, Distribution10

Plant property, and General Plant property. The Intangible Function includes11

Organization costs, software, and related assets. Gathering Plant assets collect12

gas from natural gas producers who wish to market their gas. Transmission Plant13

takes the natural gas using intermediate pressure to send gas to the Distribution14

System. The Distribution Plant functional group primarily consists of pipes and15

associated facilities used to distribute gas within the cities served by the16

Company. General Plant property is not location-specific but is used to support17

the overall distribution of gas to customers.18

Q. ARE THE RESULTS OF YOUR DEPRECIATION STUDY REFLECTED19

IN THE TEST YEAR ENDING DECEMBER 31, 2011 COST OF SERVICE20

CALCULATION?21

A. Yes. The cost of service calculation for depreciation expense applies my22

recommended depreciation rates to the adjusted plant balances as of December23

31, 2011.24

Q. WHEN DID THE LAST CHANGE IN THE COMPANY’S25

DEPRECIATION RATES OCCUR?26

A. The last change in the Company’s depreciation lives occurred in December 2004.27

The depreciation rates were established in GUD No. 9488-9512 and were based28

on a settlement agreement between the Company and intervenors in GUD No.29

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9488, et al and authorized in the Final Order signed by the Commissioners on1

November 23, 2004.2

Q. ARE YOU PROPOSING A CHANGE IN DEPRECIATION EXPENSE3

FOR INTANGIBLE ASSETS?4

A. Yes. Based on my study, the annual depreciation expense for Intangible assets5

should be increased by approximately $66,000 per year. This amount was6

determined by comparing the depreciation expense computed using current item-7

based rates and the proposed rates as shown in Exhibit DAW-1, Appendix A.8


FOR GATHERING PLANT ASSETS?10

A. Yes. Based on my study, the annual depreciation expense for Gathering Plant11

assets should be decreased by approximately $10,000 per year. This amount was12




FOR TRANSMISSION PLANT ASSETS?16

A. Yes. Based on my study, the annual depreciation expense for Transmission17





FOR DISTRIBUTION ASSETS?22

A. Yes. Based on my study, the annual depreciation expense for Distribution assets23



based rates and the proposed rates.26


FOR GENERAL ASSETS?28

A. Yes. Based on my study the annual depreciation expense for General Depreciated29

assets should be decreased by approximately $207,000 per year. This amount was30

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B. Overview of Depreciation Study3

Q. WHAT DEFINITION OF DEPRECIATION HAVE YOU USED FOR4

PURPOSES OF CONDUCTING A DEPRECIATION STUDY AND5

PREPARING YOUR TESTIMONY?6

A. The term “depreciation,” as used herein, is considered in the accounting sense;7

that is, a system of accounting that distributes the cost of assets, less net salvage8

(if any), over the estimated useful life of the assets in a systematic and rational9

manner. Depreciation is a process of allocation, not valuation. Depreciation10

expense is systematically allocated to accounting periods over the life of the11

properties. The amount allocated to any one accounting period does not12

necessarily represent the loss or decrease in value that will occur during that13

particular period. Thus, depreciation is considered an expense or cost, rather than14

a loss or decrease in value. The Company accrues depreciation based on the15

original cost of all property included in each depreciable plant account. On16

retirement, the full cost of depreciable property, less the net salvage amount, if17

any, is charged to the depreciation reserve.18

Q. PLEASE DESCRIBE YOUR APPROACH TO PERFORMING A19

DEPRECIATION STUDY.20

A. I conducted the depreciation study in four phases as shown in my Exhibit DAW-21

1. The four phases are: Data Collection, Analysis, Evaluation, and Calculation.22

During the initial phase of the study, I collected historical data to be used in the23

analysis. After the data was assembled, I performed analyses to determine the life24

and net salvage percentages for the different property groups being studied. As25

part of this process, I conferred with field personnel responsible for the26

installation, operation, and removal of the assets to gain their input into the27

operation, maintenance, and salvage of the assets. The information obtained from28

field personnel, combined with the study results, was then evaluated to determine29

how the results of the historical asset activity analysis, in conjunction with the30

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Company’s expected future plans, should be applied. Using all of these1

resources, I then calculated the depreciation rate for each function.2

Q. WHAT DEPRECIATION METHODOLOGY DID YOU USE?3

A. The straight-line, Equal Life Group (“ELG”) remaining-life depreciation system4

was employed to calculate annual and accrued depreciation in this study. The5

ELG remaining-life depreciation system was also used to develop the depreciation6

rates currently in place.7

Q. HOW ARE DEPRECIATION RATES DETERMINED USING THE ELG8

PROCEDURE?9

A. In this procedure, the annual depreciation expense for each group is computed by10

dividing the original cost of the asset, less allocated depreciation reserve, plus or11

minus estimated net salvage, by its respective equal life group remaining life.12

The resulting annual accrual amounts of all depreciable property within a function13

is accumulated, and the total is divided by the original cost of all functional14

depreciable property to determine the depreciation rate. The calculated remaining15

lives and annual depreciation accrual rates are based on attained ages of plant in16

service and the estimated service life and salvage characteristics of each17

depreciable group. The computations of the annual functional depreciation rates18

are shown in Exhibit DAW-1, Appendix B. The remaining life calculations are19

discussed below and are shown in Exhibit DAW-1, Appendix B-1.20

C. Service Lives21

Q. WHAT IS THE SIGNIFICANCE OF AN ASSET’S USEFUL LIFE IN22

YOUR DEPRECIATION STUDY?23

A. An asset’s useful life is used to determine the remaining life over which the24

remaining cost (original cost plus or minus net salvage, minus accumulated25

depreciation) can be allocated to normalize the asset’s cost and spread ratably26

over future periods.27

Q. WHAT ISSUES DID YOU FIND WITH WEST TEXAS GAS ASSETS IN28

ESTIMATING SERVICE LIFE?29

A. West Texas Gas has added most of its plant through acquisition of assets from30

other natural gas companies. When assets are acquired by WTG, the asset is31

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booked with a vintage year of the acquisition date. Acquiring assets a portion of1

the way through their lives and the recording of the vintages of those assets as the2

year of acquisition affect the book life of the asset groups. In other words, assets3

acquired that are 30 years old will appear to be new in the Company’s accounting4

system. As such a 60 year total life for the assets will only carry a 30 year life for5

depreciation purposes. The vintage year assigned to acquired assets will have a6

material effect on the service life of those assets.7

Q. WILL ASSETS FOR WEST TEXAS GAS HAVE SERVICE LIVES8

SIMILAR TO OTHER NATURAL GAS COMPANIES?9

A. No. The lives of assets for West Texas Gas will be much shorter than other10

natural gas companies. An asset acquired in 2012 will be given 2012 as its year11

of installation, even though the asset may have an original in-service year many12

years earlier than the acquisition year. With that in mind, the age at acquisition13

will reduce the life of WTG assets as compared to the lives of similar assets in14

other companies where the vintage and the original in-service dates match.15

Q. WHAT LIFE TO YOU RECOMMEND FOR THE TWO LARGEST16

ACCOUNTS, 367 (TRANSMISSION MAINS) AND 376 (DISTRIBUTION17

MAINS)?18

A. For both accounts, I recommend a 45 year life. For Account 367 Transmission19

Mains, I propose a 45 R2. For Account 376 Distribution Mains, I propose a 4520

R3 curve. Given the assets are, in reality, much older (20-30 years) than the21

vintage year, a 45 year life is a reasonable proxy for future expectations in these22

accounts. The 45 year proposed life compares to a 20 year component life23

currently being used. Graphs of each proposed curves are found in Exhibit DAW-24

1 in the life analysis section.25

Q. HOW DID YOU DETERMINE THE AVERAGE SERVICE LIVES FOR26

EACH ACCOUNT?27

A. The establishment of an appropriate average service life for each account within a28

functional group was determined by using the Actuarial Analysis method. The29

results of the Actuarial Analysis and the chosen Iowa Curves used to determine30

the average service lives for each account are found in my Exhibit DAW-1 and in31

my depreciation study workpapers.32

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Q. YOU MENTIONED PREVIOUSLY THAT ASSET LIVES WERE1

CHANGING. WHAT IS THE GENERAL CAUSE OF THE CHANGE IN2

ASSET LIVES?3

A. This depreciation study is the first one for WTG that incorporates the principles of4

group depreciation, which other regulated utilities use for their fixed assets. In5

general, the life indications are longer than the current item based lives.6

Q. DOES YOUR DEPRECIATION STUDY REFLECT THE CHANGES IN7

THE USEFUL LIVES OF WEST TEXAS GAS ASSETS?8

A. Yes. My study strikes a reasonable balance between the historical statistical9

indications seen in the analysis and Company-specific expectations based on10

current and future plans, regulations and requirements to serve its customers.11

Q. IF ASSET LIVES ARE INCREASING, WHY ARE DEPRECIATION12

RATES SHOWING AN INCREASE OVER CURRENT LEVELS?13

A. In 2012, the Company restated its books and reduced the depreciation reserve by14

$20 million and depreciation expense for 2011 by $3 million. The restated15

reserves and expense amounts change the net book value and have caused16

depreciation rates to increase.17

Q. WHAT PROCESS HAVE YOU UNDERTAKEN TO GIVE EFFECT TO18

BOTH HISTORICAL DATA AND COMPANY-SPECIFIC19

EXPECTATIONS IN DEVELOPING YOUR SERVICE LIFE20

RECOMMENDATIONS?21

A. In order to achieve a reasonable balance between these critical components of the22

life analysis, I evaluated the statistical historical data and then applied informed23

judgment to make the most appropriate service life selections. The objective in24

any depreciation study is to project the remaining cost (installation, material and25

removal cost) to be recovered and the remaining periods over which to recover26

the costs. This necessarily requires that the service life selections reflect both the27

Company’s historic experience and its current expectations of asset lives. In28

order to understand the Company’s expectations regarding asset lives, I29

interviewed Company engineers working in both operations and maintenance to30

confirm the historical activity and indications, current and future plans,31

expectations and the applicability to the future surviving assets. The interview32

process provides important information regarding changes in materials, operation33

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and maintenance, as well as the Company’s current expectation regarding the1

service life of the assets currently in use. This information is then considered2

along with the historical statistical data to develop the most reasonable and3

representative expected service lives for the Company’s assets. The result of this4

analysis is reflected in the service life recommendations set forth in my5

depreciation study.6

Q. HAVE YOU PREPARED A SUMMARY OF THE RECOMMENDED7

LIVES BY ACCOUNT?8

A. Yes. Table 1 below provides the proposed lives for the each account.9

TABLE 1

Recommended Lives West Texas Gas

Recommended

Iowa

Account Description Life Curve

301 Organization 20 SQ

302 Franchise and Consents 20 SQ

303 Intangible Plant 12 SQ

332 Field Lines 20 R3

333 Field Compressor Station Equipment 25 R3

334 Field Measuring and Regulating Equipment 20 R3

365.2 Land Rights 45 SQ

367 Transmission Mains 45 R2

368 Transmission Compressors 15 R2

369 Measuring and Regulating Equipment 20 R3

371 Other Equipment 15 R2

376 Distribution Mains 45 R3

377 Compressor Station Equipment 18 R5

378Distribution Measuring and RegulatingEquipment 25 R3

387 Other Equipment 20 R2

389 General Plant Land Rights 40 SQ

390 Structures and Improvements 25 R2.5

391 Office Furniture and Equipment 20 L2

392 Transportation Equipment 9 L2

394 Tools, Shop, and Garage Equipment 20 L2

397 Communication Equipment 17 L2

398 Miscellaneous Equipment 15 SQ

10

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D. Net Salvage1

Q. WHAT IS NET SALVAGE?2

A. As discussed more fully in Exhibit DAW-1, net salvage is the difference between3

the gross salvage (what is received in scrap value for the asset when retired) and4

the removal cost (cost to remove and dispose of the asset). Salvage and removal5

cost percentages are calculated by dividing the current cost of salvage or removal6

by the original installed cost of the asset. When salvage exceeds removal cost7

(positive net salvage), the net salvage reduces the amount to be depreciated over8

time. When removal cost exceeds salvage (negative net salvage), the negative net9

salvage increases the amount to be depreciated.10

Q. DOES WEST TEXAS GAS HAVE ANY NET SALVAGE REFLECTED IN11

ITS EXISTING DEPRECIATION RATES?12

A. No. Currently the Company is booking removal cost toward the cost of a new13

asset. We recommend that WTG change its accounting practice and record cost14

of removal and gross salvage to the depreciation reserve, similar to other15

regulated natural gas utilities. If the Company converts its accounting practice,16

we propose to incorporate net salvage in the next depreciation study. Given17

current accounting practice for WTG, I recommend 0% net salvage for all18

accounts.19

IV. CONCLUSION20

Q. DO YOU HAVE ANY CONCLUDING REMARKS?21

A. Yes. The depreciation study and analysis performed under my supervision fully22

support setting depreciation rates at the level I have indicated in my testimony and23

exhibits. The Company should continue to periodically review the annual24

depreciation rates for its property. In this way, all customers will be charged for25

their appropriate share of the capital expended for their benefit. The depreciation26

study included as Exhibit DAW-1 describes the extensive analysis performed and27

the resulting rates that are now appropriate for Company property. The28

Company’s depreciation rates should be set at my recommended amounts in order29

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to recover the Company’s total investment in property over the estimated1

remaining life of the assets.2


A Yes, it does.4

railroad commission of texas gas services division … · 11 relief from the commission; and...

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