When Did You First Become Involved in Matters Related to the Applicant, Sharyland Utilities, L

1 1 2 3 4 5 6 DOCKET NO. _____ 7 8 9 APPLICATION OF § SHARYLAND UTILITIES, L.P. § PUBLIC UTILITY FOR AUTHORITY TO § COMMISSION ESTABLISH INITIAL RATES § OF TEXAS AND TARIFF § 10 11 12 13 14 15 16 17 18 DIRECT TESTIMONY AND EXHIBITS 19 20 OF 21 22 HUGH D. BAKER, JR. 23 24 FOR 25 26 SHARYLAND UTILITIES, L.P. 27 28 29 30 31 32 33 34 NOVEMBER 1, 1999

2 1 1 DIRECT TESTIMONY OF 2 HUGH D. BAKER, JR. 3 4 5 TABLE OF CONTENTS 6 7 8 PAGE 9 10 EXECUTIVE SUMMARY 11 12 I. INTRODUCTION...... 1 13 14 II. COMPLIANCE WITH DOCKET 20292 FINAL ORDER...... 3 15 16 III. PLANNING AND OPERATIONAL CHANGES...... 6 17 18 IV. FINANCING MATTERS...... 10 19 20 V. CREATION OF METERSMART, L.P...... 15 21 22 VI. ANTICIPATED REGULATORY ACTIVITIES...... 19 23 24 25 26 27 28 EXHIBITS 29 30 HDB-1 Resume of Hugh D. Baker, Jr. 31 HDB-2 SU’S 1999 Quarterly Report Regarding Equity Balances 32 HDB-3 Credit Facility Agreement Between SU and Hunt Equities, Inc. 33 (Specimen) 34

1 EXECUTIVE SUMMARY 2 3

4 Mr. Baker is a Vice President of Hunt Power Corporation. His testimony

5 describes Sharyland Utility L.P.’s (“SU”) activities with respect to compliance with

6 the Final Order in Commission Docket 20292 as well as planning and operational

7 changes which have taken place since the Final Order. He also describes financing

8 matters, the formation of MeterSmart, L.P., and SU’s anticipated future regulatory

9 activities which will give rise to regulatory expenses and capitalized regulatory costs.

10 Mr. Baker is sponsoring Schedules F and U in the Rate Filing Package. 11

1 DOCKET NO. _____

2 DIRECT TESTIMONY OF HUGH D. BAKER, JR.

4 SECTION I. INTRODUCTION

6 Q. PLEASE STATE YOUR NAME, TITLE AND BUSINESS ADDRESS.

7 A. My name is Hugh D. Baker, Jr. I am a Vice President of Hunt Power

8 Corporation (“HPC”). My business address is 1445 Ross at Field, Dallas,

9 Texas 75202.

11 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?

12 A. The purpose of my testimony is to: (1) discuss SU’s activities with respect to

13 compliance with the Settlement and Final Order in Commission Docket No.

14 20292; (2) discuss certain planning and operational changes that have

15 occurred since the Final Order in Docket 20292; (3) discuss the formation of

16 MeterSmart, L.P., which will provide metering and related services to SU; and

17 (4) discuss SU’s anticipated future regulatory activities which will give rise to

18 regulatory expenses and capitalized regulatory costs.

20 Q. ARE YOU SPONSORING ANY SCHEDULES IN THE RATE FILING

21 PACKAGE?

22 A. Yes, I am sponsoring Schedules F and U.

2 DIRECT TESTIMONY 1 HUGH D. BAKER, JR. 1

1 Q. PLEASE DESCRIBE YOUR QUALIFICATIONS AND EXPERIENCE?

2 A. I received a Bachelor of Electrical Engineering from the Georgia Institute of

3 Technology in June 1980 and a Master of Business Administration from

4 Georgia State University in August 1984. I have nineteen years of experience

5 in the electric utility industry.

6 My career began in 1978 as a coop-student at Tampa Electric

7 Company, Tampa, Florida where I worked in the system operations,

8 underground distribution, and distribution standards departments. Upon my

9 graduation from Georgia Tech, I became a Project Engineer with Southern

10 Engineering Company (“Southern Engineering”) in Atlanta, Georgia. My

11 responsibilities at Southern Engineering included power supply planning and

12 modeling using PROMOD and PROSCREEN planning software, performing

13 wholesale rate projections, and evaluating the feasibility of power supply

14 alternatives on behalf of generation and transmission cooperatives and

15 municipal joint action agencies.

16 In June 1986, I joined GDS Associates, Inc., (“GDS”) in Marietta,

17 Georgia, and became a Principal of GDS shortly thereafter. At GDS, I

18 continued to represent primarily G&T cooperatives and municipals in power

19 supply matters. My responsibilities included evaluation, negotiation,

20 implementation and administration of bulk power supply contracts and

21 ancillary service arrangements, providing litigation support, and preparation

22 of analysis in support of financing of utility infrastructure. From the period

1 February 1995 through September 1996, I was employed in the power

2 marketing business with AES Power, Inc., Arlington, Virginia, and Citizens-

3 Lehman Power LLP, Boston, Massachusetts. In September 1996, I formed

4 Capstone Energy Services, Inc. (“Capstone”) based in Atlanta, Georgia and

5 began providing consulting services to utility companies and power marketers.

6 In August of 1998, I joined HPC as a full-time employee. I have been

7 involved with Sharyland Utilities, L.P. (“SU”) since its inception. A copy of

8 my resume is attached as Exhibit HDB-1.

10 Q. HAVE YOU TESTIFIED BEFORE THIS COMMISSION AND

11 BEFORE OTHER REGULATORY AGENCIES?

12 A. Yes. I have testified before this Commission in Docket Nos. 9066, 9300, and

13 10462. Additionally, I testified on behalf of SU in Docket 20292, SU’s

14 Certificate of Convenience and Necessity (“CCN”) Application. I testified

15 before the South Carolina Public Service Commission in Docket No. 86-148-

16 E. I testified before the Federal Energy Regulatory Commission in Docket

17 Nos. TX93-1 and TX93-2.

19 SECTION II. COMPLIANCE WITH DOCKET 20292 FINAL ORDER

1 Q. SINCE THE FINAL ORDER IN DOCKET 20292, HAVE THERE BEEN

2 ANY DISCUSSIONS WITH CPL CONCERNING IDLED FACILITIES

3 CHARGES?

4 A. No. There have been no discussions with CPL regarding idled facilities

5 charges because SU does not yet have facilities in place to serve customers.

6 Additionally, prior to this rate application, SU has not had specific

7 information regarding its rates and tariffs to provide to existing CPL

8 customers.

10 Q. DOES THE PROPOSED COST OF SERVICE TAKE INTO ACCOUNT

11 PAYMENT TO CPL FOR IDLED FACILITIES CHARGES?

12 A. Yes. The cost of service in this proceeding includes an assumed cost for the

13 purchase of CPL’s existing distribution facilities located within SU’s service

14 area. These costs are based on specific facility cost information developed by

15 CPL and made a part of the record in Docket 20292. The cost of service study

16 assumes that SU purchases all of CPL’s existing distribution facilities within

17 Sharyland Plantation.

19 Q. SINCE THE FINAL ORDER IN DOCKET 20292, HAVE THERE BEEN

20 ANY DISCUSSIONS WITH MVEC?

21 A. Yes. There have been ongoing discussions with MVEC, primarily regarding

22 temporary and permanent service in certain residential subdivisions where

1 new service is required prior to the expected in-service date of SU’s

2 distribution system. As of the date of this testimony, these discussions are of

3 a continuing nature. Both parties are working to assure that new customers in

4 Sharyland Plantation receive prompt and reliable service. If these discussions

5 result in an agreement SU expects to provide service under its tariff as early as

6 January 1, 2000.

8 Q. DOES THE PROPOSED COST OF SERVICE TAKE INTO ACCOUNT

9 PAYMENT TO MVEC FOR IDLED FACILITIES CHARGES?

10 A. No. Because of the lack of specific facility cost information, the cost of

11 service study does not reflect any payments to MVEC for idled facilities

12 charges.

14 Q. HOW DOES SU PROPOSE TO ACCOUNT FOR ANY STRANDED

15 COST PAYMENTS TO CPL?

16 A. The cost of service study does not include the amount of stranded generation

17 cost payments to CPL provided for under the settlement in Docket No. 20292.

18 Rather, SU plans to recover any stranded cost payments through the specific

19 assignment of such charges to each specific customer who desires to switch

20 service from CPL to SU. This is a reasonable proposal since, if a customer

21 elects to switch to SU, the customer should be economically neutral with

1 respect to the stranded cost payment. Please refer to the Direct Testimony of

2 SU witness James W. Daniel for a further discussion of this matter.

4 Q. WHAT IS THE STATUS OF INTERCONNECTION WITH CPL’S

5 TRANSMISSION AND DISTRIBUTION FACILITIES IN ORDER TO

6 PROVIDE BULK POWER DELIVERY INTO THE SU SYSTEM?

7 A. Please refer to the Direct Testimony of SU witness Thomas H. Houle for a

8 discussion of the status of interconnection arrangements.

10 Q. HAS SU COMPLIED WITH THE MINIMUM EQUITY

11 MAINTENANCE REQUIREMENTS REQUIRED UNDER THE FINAL

12 ORDER IN DOCKET 20292.

13 A. Yes. The specific requirements of SU’s minimum equity balances are set

14 forth in a letter to Mr. Tom Best, the Commission’s Assistant General Counsel

15 from Hunter L. Hunt dated May 12, 1999, which was referred to in the Final

16 Order. SU’s most recent quarterly report as required by the May 12, 1999

17 letter is attached as Exhibit HDB-2.

19 SECTION III. PLANNING AND OPERATIONAL CHANGES

21 Q. HAVE THERE BEEN ANY CHANGES IN SU’S PLANNING SINCE

22 THE ISSUANCE OF THE FINAL ORDER IN DOCKET 20292?

1 A. Yes. There have been three major changes. First, after lengthy negotiations,

2 SU was unable to reach agreements with PSE Utility Services, Inc. which

3 were acceptable to both parties. Second, SU was unable to reach an

4 acceptable agreement with South Texas Electric Cooperative, Inc. (“STEC”)

5 with respect to STEC’s possible ownership of the 138-kV transmission

6 facilities within the Sharyland Plantation, although SU did enter into a power

7 purchase agreement with STEC. Third, SU has hired a full-time General

8 Manager who is located on-site in the Sharyland Plantation.

10 Q. WHAT WERE THE SERVICES THAT SU CONTEMPLATED

11 OBTAINING FROM PSE?

12 A. SU negotiated with PSE with the intent of consummating agreements to

13 provide three different functions: (1) management of the construction of SU’s

14 electric transmission and distribution facilities; (2) management of the

15 operations and maintenance of SU’s system; and (3) provision of certain

16 customer billing and call center services.

18 Q. HOW ARE THE FUNCTIONS THAT WERE TO BE PROVIDED

19 UNDER THE AGREEMENTS WITH PSE UTILITY SERVICES NOW

20 GOING TO BE PROVIDED?

21 A. SU developed several contingencies with respect to the services that were to

22 be provided by PSE Utility Services, Inc. First, with respect to construction,

1 the role of SU’s engineering consultant, Cornelius-Pierce Consulting

2 Engineers, Inc. (“C-PCE”) has been expanded to include construction

3 management and oversight services in connection with the construction of

4 SU’s transmission and distribution system. Second, with respect to operations

5 and maintenance services, SU plans to utilize third party line crews on an

6 outsourced basis, which is similar to the way in which PSE Utility Services

7 would have provided these functions had a contract been consummated. With

8 respect to dispatching of service crews, SU plans to enter into a contract with

9 the Brownsville Public Utility Board (“Brownsville PUB”) to provide

10 customer outage reporting and trouble call center functions. Finally, with

11 respect to customer billing and call center functions, SU contemplates that the

12 agreement with Brownsville PUB will also provide for customer service call

13 center functions and customer billing and accounting functions. All of these

14 activities are discussed in greater detail in the Direct Testimony of SU witness

15 Mark E. Caskey.

17 Q. WHY WAS THE PLANNED ARRANGEMENT FOR STEC TO OWN

18 SU’S TRANSMISSION FACILITIES NOT CONSUMMATED?

19 A. SU elected not to proceed with an arrangement for STEC to own the

20 transmission facilities in the Sharyland Plantation because the parties were

21 unable to reach an agreement that would have been in the best interest of both

22 parties and their ratepayers. As explained in the Direct Testimony of SU

1 witness Thomas H. Houle, SU did execute a power purchase agreement with

2 STEC for the year 2000, and an ancillary services agreement for 2000 and

3 2001.

5 Q. HAS SU EMPLOYED A GENERAL MANAGER?

6 A. Yes. In late August 1999, SU completed its search for a General Manager,

7 and in early September, Mark E. Caskey became the full time manager of SU.

8 He is based in the Sharyland Plantation and now resides in the McAllen area.

9 Mr. Caskey brings a great deal of hands on electric utility engineering and

10 management experience to SU. His background and credentials are discussed

11 in more detail in Mr. Caskey’s Direct Testimony in this proceeding.

13 Q. IS SU LIKELY TO RETAIN ADDITIONAL EMPLOYEES OVER THE

14 NEXT YEAR?

15 A. Yes. Over the next six to twelve months, SU anticipates hiring additional

16 staff. This additional staff may consist of additional engineering expertise, an

17 office manager/accountant, and an office assistant.

19 Q. DO ANY OF THE CHANGES IN SU’S PLANNING SINCE THE

20 FINAL ORDER IN DOCKET 20292 MATERIALLY AFFECT SU’S

21 ABILITY TO PROVIDE SERVICE?

1 A. There are no negative impacts due to the changes discussed above. There are

2 positive impacts on SU’s ability to provide service, particularly with respect to

3 SU’s hiring of an experienced General Manager.

5 SECTION IV. FINANCING MATTERS

7 Q. HOW WILL SU'S DEBT CAPITAL BE PROVIDED?

8 A. SU’s debt capital will be provided by Hunt Equities, Inc. (“HEI”), an entity

9 wholly owned and controlled by Hunt Consolidated, Inc.

11 Q. CAN YOU PLEASE DESCRIBE THE TERMS OF THE LOAN BY HEI

12 TO SU?

13 A. Yes. A specimen copy of the Credit Facility Agreement between SU and HEI

14 is attached as Exhibit HDB-3. The Credit Facility Agreement provides SU

15 with a line of credit in a maximum amount of $20 million, over a term of 5

16 years. The payment schedule calls for payment of interest, at a rate of interest

17 equal to the Prime Rate plus two percent. The amount of principal is due on

18 the maturity date of the loan.

20 Q. ARE THE TERMS OF THE LOAN TO SU BY HEI COMMERICALLY

21 REASONABLE?

1 A. Yes. With respect to the general terms and conditions, the loan structure is

2 similar to, if not more flexible than those available from a typical commercial

3 bank. The interest rate has been set to reflect the size of financing required

4 (which is relatively small compared to larger utilities) and credit risk inherent

5 in a start-up utility environment. It is reasonable to expect that a commercial

6 bank, if it would lend at all, would charge both a liquidity premium and a

7 credit risk premium in a loan to SU. In that light, the interest rate on the HEI

8 credit facility would appear to be at least as favorable as what SU could obtain

9 in the open market.

11 Q. HAVE YOU REVIEWED THE TESTIMONY OF SU WITNESS

12 BRUCE FAIRCHILD?

13 A. Yes. In his testimony, Dr. Fairchild explains the rationale for each of three

14 different methodologies for computing the rate of return on rate base for

15 purposes of this rate proceeding.

17 Q. WHICH OF THE THREE METHODOLOGIES DOES SU PROPOSE

18 TO USE FOR THE PURPOSES OF COMPUTING SU’S COST OF

19 SERVICE IN THIS RATE PROCEEDING?

20 A. SU proposes to use the methodology that Dr. Fairchild refers to as the “Rate

21 Period” methodology. The Rate Period methodology is based on Dr.

22 Fairchild’s calculation of the average amounts of equity and debt capital

1 actually employed during the first two years of SU’s operation (i.e. 2000 and

2 2001, the years in which the rates being set in this case are in effect). In Dr.

3 Fairchild's testimony, he states that the average capital structure during the

4 Rate Period is approximately 75% equity and 25% debt. Dr. Fairchild then

5 determines the return on equity and return on debt that he believes is

6 commensurate with this capital structure. Dr. Fairchild recommends a rate of

7 return on equity of 11.25% and a cost of debt of 10.25%, resulting in an

8 overall rate of return of 11.0%. The cost of service in this rate filing uses this

9 rate of return.

11 Q. WHAT IS THE BASIS FOR SU’S SELECTION OF THE RATE

12 PERIOD METHODOLOGY?

13 A. SU’s selection of the Rate Period methodology is based on the fact that the

14 capital structure associated with the Rate Period methodology most accurately

15 reflects the actual capital structure situation that will occur over the period of

16 time when the rates set in this proceeding are in effect.

18 Q. DOES SU STILL INTEND AS ITS TARGET TO UTILIZE A CAPITAL

19 STRUCTURE THAT CONSISTS OF 30% EQUITY AND 70% DEBT?

20 A. Yes. As SU indicated in Docket 20292, SU intends to seek permanent

21 financing that will allow it to achieve a 30% equity, 70% debt mix of

22 employed capital. This is the capital structure referred to in Dr. Fairchild’s

1 testimony as the “Target.” It is SU’s goal to seek permanent debt financing

2 that will result in an overall capital structure that consists of 30% equity and

3 70% debt. SU still believes that such a capital structure, utilized over the

4 long-term, will provide SU’s customers with lower costs, since the cost of

5 equity is greater than the cost of debt.

7 Q. IF, IN THE LONG TERM, SU INTENDS TO UTILIZE THE TARGET

8 CAPITAL STRUCTURE, WHY WAS THIS REJECTED FOR

9 PURPOSES OF THIS RATE PROCEEDING?

10 A. As part of the settlement of Docket 20292, the Commission has required SU

11 to maintain a minimum equity balance of $6.5 million. Therefore, the actual

12 capital employed as of the startup date of SU’s operations is 100% equity. It

13 is SU’s plan to utilize this $6.5 million of equity (which is presently

14 represented on the asset side of the balance sheet in the form of cash and cash

15 equivalents) to fund SU’s plant additions prior to the draw down of debt

16 capital. Therefore, during the period that the rates being set in this proceeding

17 are in effect, SU’s actual capital structure will be transitioning towards the

18 target capital structure. For this reason, SU proposes to use a capital structure

19 for cost of service purposes that more closely matches the actual capital

20 employed during the period the rates are in effect.

1 Q. CAN YOU COMMENT ON THE “INDUSTRY” APPROACH

2 DESCRIBED IN DR. FAIRCHILD’S TESTIMONY?

3 A. Yes. The Industry approach described by Dr. Fairchild is often used by

4 regulatory commissions when setting the rate of return for a utility. Indeed, it

5 can be a valid approach since it attempts to set a fair rate of return for a utility

6 company based on the rates of return for a group of the subject utility’s peers,

7 with adjustments for quantifiable differences in risk. That is not the case in

8 SU’s situation because the other utilities used in this approach are not similar

9 to a start-up utility such as SU.

11 Q. IS IT POSSIBLE TO QUANTITATIVELY ASSESS THE

12 ADJUSTMENTS NECESSARY TO THE PEER GROUP RATES OF

13 RETURN FOR PURPOSES OF SETTING SU’S RATE OF RETURN?

14 A. Since there are virtually no recent examples of “start-up” electric utilities, it is

15 difficult to find any true peers of SU. As Dr. Fairchild explains in his

16 testimony, the utility company group that is utilized to compute a rate of

17 return under the Industry methodology consists of well established utilities,

18 several of which have over 100 years of operating history. SU, on the other

19 hand, is a new start-up utility with no operating history and no historical

20 customer base. A start-up utility has very different business risk as compared

21 to a well-established utility. Therefore it is difficult to specifically quantify

1 adjustments to the so-called peer group rate of return to reflect the difference

2 in business risk faced by SU.

4 Q. ARE THERE OTHER REASONS THAT THE INDUSTRY

5 METHODOLOGY IS NOT APPROPRIATE?

6 A. Yes. In addition to the business risk factor described above, the industry peer

7 group enjoys a lower cost of capital which reflects: (i) the ability to easily

8 issue common and preferred equity stock, (ii) ready access to debt capital due

9 to an established credit history and public credit ratings, and (iii) better overall

10 liquidity in obtaining capital due to their relatively larger capital base. In

11 other words, the industry peer group has the ability to more easily attract

12 outside capital since there are certain economies of scale inherent in raising

13 this capital. In obtaining capital from the same sources as the peer group, SU

14 would likely incur a “liquidity premium” which would translate into a higher

15 cost of capital than that produced by the Industry methodology. For this

16 additional reason, the Industry methodology is therefore not appropriate for

17 determining SU’s rate of return in this proceeding.

19 SECTION V. CREATION OF METERSMART, L.P.

21 Q. PLEASE DESCRIBE THE FUNCTION AND BUSINESS PURPOSE OF

22 METERSMART, L.P. TO SU.

1 A. MeterSmart, L.P. (“MeterSmart”), an affiliate of Hunt Power Corporation, has

2 been formed to provide metering services to SU and other electric utilities.

3 These services include: (1) provision of the meters; (2) meter reading; (3)

4 meter maintenance and testing; and (4) meter data management, i.e.

5 formatting of meter data to interface with a utility’s billing system.

7 Q. WILL METERSMART BE RESPONSIBLE FOR PROVIDING ANY

8 ELECTRICITY RELATED SERVICES TO SU’S RETAIL

9 CUSTOMERS IN LIEU OF SU PROVIDING THOSE SERVICES FOR

10 ITSELF?

11 A. No. MeterSmart’s electric metering services will be provided directly to SU.

12 SU remains responsible to its retail customers for provision of all aspects of

13 retail electric service.

15 Q. HOW WERE THE CHARGES THAT SU PAYS TO METERSMART

16 DETERMINED?

17 A. The charges that SU will pay to MeterSmart were determined based on an

18 analysis of what SU’s own cost of service would be if it provided the metering

19 services for itself. Thus, SU’s customers will be held harmless in the

20 transaction between SU and MeterSmart.

1 Q. DOES THE OUTSOURCING OF THE METERING SERVICES TO

2 METERSMART OFFER ANY ADVANTAGES TO SU’S

3 CUSTOMERS?

4 A. Yes. By outsourcing the metering function, SU’s customers obtain a degree

5 of protection with respect to future metering costs and a degree of protection

6 with respect to technological obsolescence. There are also certain price

7 protection provisions in the agreement between SU and MeterSmart.

9 Q. CAN YOU ELABORATE ON THE PRICE PROTECTION

10 MECHANISMS IN THE AGREEMENT BETWEEN SU AND

11 METERSMART?

12 A. Yes. While the pricing in the agreement between MeterSmart and SU is based

13 on a determination of what SU’s own cost of service would be for providing

14 metering for itself, the agreement also contains a “most favored nations”

15 provision that requires MeterSmart to reduce the price of its services to that

16 offered to any future customer of MeterSmart. SU’s customers would thus

17 enjoy the benefit of any economies of scale that MeterSmart could obtain by

18 offering its services to other electric utilities. If SU offers these services for

19 itself, the potential for economies of scale in the provision of metering

20 services will be reduced.

1 Q. ARE THERE OTHER REASONS WHY IT MAKES SENSE FOR SU

2 TO OUTSOURCE THE METERING FUNCTION TO METERSMART?

3 A. Yes. The 1999 Texas electric industry restructuring law provides for the

4 “unbundling” of electric utility costs, and also allows for metering to be

5 offered as a competitive service in 2004. Thus, the outsourcing of the

6 metering function allows SU to avoid the future expense associated with

7 unbundling metering services. Further, SU gains experience in dealing with a

8 vendor of metering services several years ahead of when the service will be

9 offered competitively.

11 Q. IS SU SEEKING AN EXCEPTION TO THE COMMISSION’S RULES

12 IN ORDER TO PERMIT METERSMART TO PROVIDE THE

13 METERING SERVICES TO SU, AS DESCRIBED ABOVE?

14 A. Yes. §25.121(b) of the Substantive Rules provides:

15 Unless otherwise authorized by the Commission, each 16 electric utility shall provide and install and shall continue to 17 own and maintain all meters necessary for the measurement 18 of electric energy to its customers. 19 20 Since under the arrangement described above MeterSmart will perform all

21 metering services SU is requesting an exception to the foregoing requirement.

22 The reasons why an exception should be authorized are explained above.

24 Q. CAN YOU GENERALLY DESCRIBE THE METERING SYSTEM

25 THAT METERSMART INTENDS TO INSTALL FOR SU?

1 A. Yes. The metering system will enable the meters to be read remotely and

2 automatically. The electric industry has generally referred to such a system as

3 “Automatic Meter Reading” or “AMR.”

5 Q. WHAT ARE THE BENEFITS OF AUTOMATIC METER READING?

6 A. There are at least three benefits of an AMR system. First, a higher penetration

7 of interval metering can be established. SU’s rate schedules contemplate

8 billing of customers based on actual interval data throughout all customer

9 classes. Interval metering also provides future flexibility to offer Time of

10 Use rates and Real Time Pricing. The second benefit is the flexibility that

11 AMR offers the consumers. The customer may choose a more convenient

12 billing period that is not constrained to a meter reading route. Finally, an

13 AMR system utilizing interval meters will allow SU to quickly develop load

14 shapes by individual customer or by customer groups. This may become a

15 very important benefit of AMR in the competitive retail electric market that

16 will occur in 2002.

18 SECTION VI. ANTICIPATED REGULATORY ACTIVITIES

20 Q. DOES THE PROPOSED COST OF SERVICE IN THIS RATE

21 APPLICATION INCLUDE ANY EXPENDITURES FOR

22 ANTICIPATED FUTURE REGULATORY ACTITIVIES?

1 A. Yes. These expenditures fall into two categories. First, there are those

2 expenditures for future regulatory activities that are to be capitalized. Second,

3 there are those expenditures for future regulatory activities that are to be

4 expensed as they are incurred.

6 Q. CAN YOU IDENTIFY THOSE EXPENDITURES FOR REGULATORY

7 ACTIVITIES THAT ARE TO BE CAPITALIZED?

8 A. Yes. In late 1999, or early 2000, SU is planning to file for a Certificate of

9 Convenience and Necessity for the electric transmission facilities inside the

10 Sharyland Plantation. The cost of preparing and administering SU’s CCN

11 filing for approval to construct the transmission facilities will be capitalized

12 into the cost of SU’s transmission facilities. The projected cost of these

13 transmission facilities includes the anticipated cost of these regulatory

14 proceedings.

16 Q. CAN YOU IDENTIFY THOSE EXPENDITURES FOR REGULATORY

17 ACTIVITES THAT ARE TO BE EXPENSED?

18 A. Yes. There are a number of anticipated regulatory activities that will require

19 SU to incur costs. These activities include: (1) participation in ongoing

20 rulemaking activities and projects of this Commission related to

21 implementation of the 1999 Texas electric industry restructuring law, (2)

22 preparation of required filings pursuant to Commission orders as part of

1 implementation of the 1999 Texas electric industry restructuring law, and (3)

2 preparation and administration of future SU rate cases which may be

3 necessary to adjust SU’s rates in the future. Expenditures related to these

4 activities will be treated as Regulatory Expenses under FERC Account No.

5 928.

7 Q. DOES THIS CONCLUDE YOUR TESTIMONY?

8 A. Yes it does.

1 AFFIDAVIT

3 THE STATE OF TEXAS §

4 COUNTY OF TRAVIS §

6 BEFORE ME, the undersigned notary public, this day personally appeared

7 HUGH D. BAKER, JR., to me known, who being duly sworn according to law,

8 deposes and says:

9 “My name is HUGH D. BAKER, JR. I am of legal age and a resident of the

10 State of Texas. I certify that the foregoing testimony and exhibits, offered by me on

11 behalf of Sharyland Utilities, L. P., are true and correct to the best of my knowledge

12 and belief.”

13 ______

14 HUGH D. BAKER, JR.

16 SUBSCRIBED AND SWORN TO BEFORE ME, notary public, on this the day

17 of October, 1999.

18 ______

19 Notary Public in and for the State of Texas

21 My Commission expires: ______

1 EXHIBIT HDB-1

2 1 EXHIBIT HDB-1 2 Page 1 of 1

2 HUGH D. BAKER, JR. 3 Hunt Power Corporation 4 1445 Ross at Field 5 Dallas, Texas 75202 6 7 EDUCATION 8 9 Master of Business Administration, Finance, Georgia State University, 1984, Atlanta, Georgia. 10 Bachelor of Electrical Engineering, Georgia Institute of Technology, 1980, Atlanta, Georgia. 11 Continuing Education, Project Finance Tutorial, Infocast, Inc., 1991, Chicago, Illinois. 12 13 PROFESSIONAL QUALIFICATIONS AND AFFILIATIONS 14 15 Registered Professional Engineer in several states. 16 Member, Institute of Electrical and Electronics Engineers. 17 Original member of the New York Mercantile Exchange Electricity Futures Advisory Committee. 18 Testimony in Regulatory Forums: 19  Federal Energy Regulatory Commission (FERC) 20  Public Utility Commission of Texas (PUCT) 21  Public Service Commission of South Carolina. 22 23 ARTICLES AND SPEECHES 24 25 “Tapping the Public Power Market,” Independent Energy, 1990. 26 “Integration of Supply-Side and Demand-Side Options,” NRECA Least Cost Planning Conference, 27 1990. 28 “Power Marketing to Public Utilities,” National Hydropower Association (Annual Meeting), 1992. 29 “Competitive Bidding in Publicly-Owned Utilities,” NRECA Competitive Bidding Seminar, 1992. 30 “Purchase Power and Transmission Issues,” PUCT Task Force, 1993. 31 “Power Marketing: The Future is Now,” Private Power Executive, 1994. 32 “Introduction to Power Marketing,” National Independent Energy Producers (Spring Meeting), 1994. 33 “Introduction to Power Marketing,” Northwest Electric Light and Power Association, 1994. 34 “Introduction to Power Marketing,” Rural Utilities Management Development Council, 1995. 35 “Power Pools in a Competitive Environment,” EXNET: The Future of Power Marketing, 1995. 36 “Electricity Risk Management,” Southwestern Power Administration, 1996. 37 “Introduction to Electricity Trading and Risk Management,” presented to Capstone clients, 38 1996/97/98. 39 40 CHRONOLOGICAL WORK EXPERIENCE 41 42 1998-Present: Hunt Power Corporation, Vice President. 43 1996-1998: Capstone Energy Services, Inc., Atlanta, Georgia, President. 44 1995-1996: Citizens Lehman Power L.P., Atlanta, Georgia, Vice President. 45 1994-1995: AES Power, Inc., Atlanta, Georgia, Vice President. 46 1986-1994: GDS Associates, Inc., Marietta, Georgia, Principal 47 1980-1986: Southern Engineering Company, Atlanta, Georgia, Project Engineer. 48 1977-1978: Tampa Electric Company, Tampa, Florida, Cooperative Education Student. 49

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