francis w. seymore

1 decontamination of contaminated systems, e.g., ,using aggressive chemical solvents

2 to dissolve corrosionfilms holding radionuclides, thereby reducing radiation levels.

3 While effective, the on-site decontamination processes are nof expected to

4 reduce residual, radioactivity to the levels necessary to release the material as clean

5 scrap. Therefore, all contaminated components will have to be removed for

6 controlled burial. However, decontamination will reduce personnel exposure and will

7 permit workers to operate in the immediate vicinity of most components, cutting and

8 removing them for controlled disposition at a low-level radioactive waste burial

9 facility.

10

Contaminated piping to and from major components will be cut and removed.

11

Selected major components such as the reactor coolant pumps, steam generators,

12

pressurizers, and other large 6omponents will then tie removed intact and sealed so

13

that they may be transported off-site. Smaller components, such as sampling

14

system pumps, filters, filter housings, strainers, etc., will be loaded into containers

15

and shipped for controlled disposal.

16

The reactor vessel and its internals will be segmented and remotely loaded

17

into,steel liners for transport to the burial facility in heavily shielded shipping casks.

18

The =reactor vessel and internals will have sufficiently high radiation levels to require

19

all cutting to be done underwater or behind heavy shields, using cutting tools

20

operated by remote control to reduce radiation exposure to the workers.

21

Concrete immediately surrounding the reactor vessel is expected to be

22

radioactive and will be removed by controlled blasting. This blasting process is well

23

developed, safe, and is the most cost effective way to remove the heavily-reinforced

24

concrete from the structure.

25 Some surfaces of sections of interior floors within areas of the Containment

26 and other buildings in the power block are expected to be contaminated from

21 DIRECT TESTIMONY OF FRANCIS W. SEYMORE

600

1 exposure to contaminated air/water as a result of plant operations. This

2 contamination will be removed by scarification (surface removal) so that the

3 remaining surfaces will be cleaned to release levels and will not require disposal as

4 Class A radioactive waste.

5 Contaminated process equipment, pipe hangers, supports, dnd el,ectrical

6 components will be removed and routed for controlled disposal.

7 Finally, an extensive radiation survey will be performed to ensure all

8 radioactive materials above the levels specified by the NRC have been removed

9 from the site. With NRC confirmation, the NRC license for Most of the site (excluding

10 the ISFSI) will be terminated.

11

12 C. Period 3 — Site Restoration

13, This period begins once license termination activities have concluded and

14 involves the demolition of all remaining structures, typically to a depth, of three feet

15 below grade. Clean concrete rubble would be used on-site for fill and additional soil

16 would be used to cover each subgrdde structure. Excess rubble is trucked, off-site

17 for disposal.,

18

19 D. Post Period 3 — Spent Fuel Storage

20 The ISFSI wilF pontinue to operate under a Part 50 license following the

21 transfer of the spent fuel inventory from the Fuel Building. Transfer of spent fuel to a

22 DOE or interim facility will be exclusively from the ISFSI once the fuel pools have

23 been emptied and the struciures 'released for decommissioning. Palo Verde will

24 continue shipping spent fuel canisters to DOE through the year 2098.

25 At the conclusion of the spent fuel transfer process, the ISFSI will be

26 decommissioned. TLG's estimate includes the cost to decommission the ISFSI. In


601 ,

the ISFSI, the spent fuel assemblies are contained within stainless .steel canisters.

2 On the IŠFSI pad, these canisters are housed within reinforced concrete and steel

3 shield cylinders khown as gverpacks. The canisters are assumed to 'be removed,

4 shipped, and disposed of by the DOE. The steel overpack liners are assumed to

5 have some level of neutron-indUced, activation as a result of the long-term storage of

6 the fuel, i.e., to levels exceeding free-release limits. As an allowance, seven

7 overpacks per unit (site total of 21) are assumed to require remediation, equivalent to

8. the number of overpacks required to accommodate the final core- offloads at Palo,

9 Verde (241 assemblie5 per unit for a site total of 723 assernblies).. The cost of the

10 disposition of, this material, as well as the demolition of the ISFSI facility, is included

11 in. the estimate. The NRC will terminate the remaining license if it determines that

12 site remediation has been performed in accordance with a license .termination plan

13 and the terminal radiation survey and' associated documentation demonstrate that

14 the facility meets the release criteria. Once the requirements are satisfied, the NRC

15 can terminate the remaining license for the ISFSI.

16 The remaining reinforced concrete dry storage modules are then demolished,

17 the concrete storage pad,is removed, and the area graded and landscaped to 11.

18 conform to the surrounding environment.

19 '

20 Q. HOW DOES THE PRESENCE OF SPENT FUEL ON SITE AFTER PLANT

21 SHUTDOWN AFFECT THE DECOMMISSIONING PROCESSES?

22 A. Although the study does not address the transport or disposal of spent fuel from the

23 •Palo Verde site, it does consider the:constraint that the presence of spent fuel on the

24 site can impose on other decommissioning activities. •In particular, the

25 decommissioning scheduling developed in support of the last four cycles of cost

26 updates for• the Palo Verde estimates incorporates an APS request for a six-year


• 602

1 rninimum cooling prerequisite for off-loading the fuel from the storage pools. As

2 such, these spent.fuel management activities will necessarily delay the final release

3 of the power blocks-for alternatiVe/unrestricted use. This delay is reflected in the

4 increased cost of the period-dependent activities. To the extent possible, the

5 decommissioning estimates were structured around the spent fuel areas of the units

6 and their availability for decontamination, such that delays in decommissioning other

7 portions of the facility could be minimized. Decommissioning would proceed on the

8 surrounding facilities and non-essential systems during the approximately six-year

9 pool off-load period. The operating licenses can then be amended with the.

10 remaining fuel placed in dry storage.

11 Some small portion of the existing.Palo Verde site will continue to be licensed

12 by the NRC under the existing Part 50 license for the ISFSI. The endpoint of this

13 storage period is estimated to be in 2098. Following this, the ISFSI will be

14 decommissioned, the license terminated, and the concrete storage casks and pads

15 crushed and removed.

16

17- Q. DOES THE PROCESS OF DECOMMISSIONING EXTEND BEYOND REMOVAL OF

18 CONTAMINATED AND ACTIVATED MATERIAL FROM THE SITE?

19 A. Yes. There are additional activities .beyonct the removal of contaminated' material

20 that will be undertaken in the process ofreleasing the šite for alternative use. This

21 work includes costs for the remaining dismantling and .grading operations and is

22 generally referred to assite restoration.

23

24 Q. PLEASE DESCRIBE THE SITERESTORATION ACTIVITIES.

25 A. These activities begin once license termination activities have concluded and involve

26 the demolition of all remaining structures, typically to a depth of three feet below


603

1

2

3-

4

5

6

7

8

9

10

11

12

13 Q.

14

15 A.

16

17

18

19

20

21

22

23

24

25*

26

grade. Clean concrete rubble generated from the demolition of the Containment,

Auxiliary, Fuel, Radwaste, and Turbine Buildings, etc., would be used on-site for fill

and additional soil would be used to cover each subgrade structure. Excess rubble

is trucked off-site for disposal. Either any below grade structures will be removed, or

voids below grade, such as the 31-mile buried water line from Phoenix to the Water

Reclamation Facility, will belilled with sand or concrete. The object is to prevent any

future surface subsidence.

Once the below grade features of the site have been addresed, the surface

of the site will be graded to conform to the surrounding environs. The evaporation

and makeup water reservoir walls will be breached to prevent retaining water. At thie

point, the site is available for reuse, except for the footprint otthe ISFSI.

WHY WERE THE REMAINING STRUCTURES ON SITE ASSUMED TO BE .

DISMANTLED?

Efficient removal of the contaminated materials and verification that the radionuclide

concentrations are below the stringent NRC limits will require substantial damage to

many of the structures. Blasting, coring, drilling, scarification (surface removal), and

the other décontamination work will damage power block structures including the

Containrnent, Radwaste, Auxiliary, •and Fuel Buildings. Verifying that subsurface

radionuclide concentrations meet NRC site release requirements may require

removal, of grade slabs and lower floors, potentially weakening footings and

structural supports.

It is also important 4o remember that the Palo Verde-structures were custom

designed and built to supp'Ort a specific nutlear unit design that went into service in

the 1980s. They would most likely be an impediment rather than a benefit to any

potential future plant, if one were ever to be constructed at the site. Moreover, the


604

1 facilitys infrastructure degrades without continual maintenance. Unless the site is

2 redeveloped shortly after release of its NRC license, the value in reusing plant

3 facilities quickly diminishes.

4 As demonstrated by U.S. experience, dismantling is clearly the most

5 appropriate and cost-effective option and should serve as the foundation for the

6 decommissioning cost estimates. It is unreasonable to anticipate that these

7 structures would be repaired and preserved after the radiological contamination is

8 removed.

9

10 Q. WHAT ASSURANCE IS THERE THAT THE ESTIMATED COST' FOR

11 DECOMMISSIONING WILL REFLECT FUTURE DEVELOPMENTS AND

12 INCREASES OR DECREASES IN COSTS?

13 A. The cost estimate prepared for Palo Verde is based on present technology, the

14 current information available on decornmissioning costs, and on existing federal

15 regulations. No provision is made to include future costs or savings due to the

16 uncertainties in improvements in technology, major regulatory changes, inflation

17 factors, etc. It should be noted that the contingency, as used in the estimates, only

18 covers uncertainties within the decommissioning schedule timeframe.

19 ,

20 VII. RECOMMENDATIONS

21 Q. IS IT NECESSARY TO SELECT A SPECIFIC DECOMMISSIONING METHOD• AT

22 THIS TIME?'

23 A. No. The .actual method or •combination of methods selected to decommission

24 Palo Verde should be based on a detailed. economic, engineering, and

25 environmental evaluation of the alternatives considering the site and surroundings at

26 the time of decommissioning and reflecting the latest experience in the

26• DIRECT TESTIMONY OF FRANCIS W. SEYMORE

605

1 decommissioning of similar nuclear power facilities. The owners of Palo Verde will

2 make such evaluations near the time of final.shutdown of the units.

3

4 Q. WHAT ARE YOUR RECOMMENDATIONS?

5 A. I recommend that, for planning purpose§, the decommissioning cost funding be

6 based upon reinoval of Palo Verde using- the DECON alternative. This alternative

7 provides the most reasonable mbans for amending/terminating the license for the

8 site in the shortest possible time. Furthermore, this alternative avoids the long-term

9 costs and commitments associated with the maintenance, surveillance and security

10 requirements of the conventional delayed dismantling alternatives. The Commission

11 has adopted the DECON alternative as a basis for ,funding nuclear plant

12 decommissioning in every case in which a TLG witness has testified.

13 The DECON alternative also allows use of the plants knowledgeable

14 operating staff, a valuable asset to a well-managed, efficient decommissioning

15 program. Equipment needed to support decommissioning operations such as

16 cranes, ventilation. systems, and radwaste processing equipment would be fully

17 operational. In addition, the site would be available for other use in the near term,

18 with the exception of the area immediately surrounding the plants fuel storage,

19 facility.

20

21 VIII. CONCLUSION

22 Q. PLEASE SUMMARIZE YOUR ;TESTIMONY.

23 A. In 2016, TLG performed site-specific cost estimates for the decommissioning of

24 Palo Verde. The total estimated cost for the decommissioning in 2016 dollars was

25 $2,739.1 million. The study shows an increase of approximately $330 million dollars,

26 or 13.7 percent, from the 2013 estimate. These amounts includes costs to remove


1 all radioactive materials from the site which exceed the release criteria, terminate the

2 NRC operating licenses, remove all structures above the three foot below grade

3 elevation and backfill all below grade voids to the surface elevation, transfer all spent

4 fuel from all three Fuel Buildings to the on-site ISFSI, operate thisiSFSI until 2098

5 (excluding ISFSI security and operating staff and ISFSI operating expenses, which

6 •are assumed to be recovered from the DOE and therefore not included), and

7 decommissiOn the ISFSI following removal of all spent fuel and GTCC material by

8 the DOE, currently estimated to occur in the year 2099..

10 Q. DOES THIS CONCLUDE YOUR TESTIMONY?

11 A. Yes, it does.


607

FRANCIS W. SEYMORE, PE EXHIBIT FWS-1

Manager, Engineering Design Page 1 of 6

EDUCATION:

Rensselaer Polytechnic Institute, Troy, New York B.S. Nuclear Engineering, Rensselaer Polytechnic Institute, 1977 M.E Nuclear Engineering, Rensselaer Polytechnic Institute, 1979

CERTIFICATIONS:

Licensed Professional Engineer: State of Connecticut Registered'Professional Engineer, Commonwealth of Pennsylvania

WORK EXPERIENCE:

TLG Services, Inc. (An Entergy Company)

Project Managementand •Regulatory Support 1982 - Present

As the Manager, Engineering Design, directS the technical aspect's and acceptance .criteria of technical and financial studies supporting the planning of nuclear power plant decommissioning. These studies provide both the engineering scope and financial resources associated with the projected disposition of a nuclear generating unit at its end of operating life.

Project Manager for the following U.S. commercial decommissioning cost estimates:

• Beaver Valley • Perry • Browns.Ferry • Prairie Island' • Brunswick • H.B. Robinson Unit' No. 2 • Calvert Cliffs . San Onofre • Davis-Besse . Sequoyah • R.E. Ginna • Shearon Harris • Millstone . Shoreham • Monticello • Three Mile Island Unit 2 • Nine Mile Point ' . Watts Bar

Technical Manager or provided calculations for the decommissioning costs for the folliming U.S. commercial decommissioning cost estimates:

• Arkansas Nuclear One • North Anna . Big Rock Point • 'Oconee ., Braidwood • •Oyster Creek . Byron • Palisades .. Callaway • Peach Bottom . Catawba . Pilgrim • Clinton • Point Beach . Comanche Peak • Quad Cities . Cooper • Rancho Seco • Crystal River 3 •' River Bend . Diablo Canyon . SI. Lucie . Dresden • ISaleM . Duane Arnold . Seabrook • Farley • South Texas Project • FitzPatrick • Surry'

As of 08/20.12 608

Francis W. Seymore EXHIBIT FWS-1 Page 2 of 6

• Fort Calhoun • Susquehanna • Grand Gulf • Three Mile Island Unit 1 • Hatch • Trojan (aka Columbia) • Hope Creek • Turkey Point • Humboldt Bay Unit 3 • V.C. Summer • Indian Point' • Vermont Yankee • Kewaunee • Vogtle • LaSalle County • Waterford 3 • Limerick • Wolf Creek • McGuire • Zion

Project Manager or provided calculations for the financial escal6tion and present value model of future decommissioning costs for the following U.S. commercial nuclear power plantš:

• Beaver Valley • Palo Verde • Braidwood • Peach Bottom • ; Byron • Perry • Clinton • Pilgrim • Comanche Peak • Quad Cities • Davis-Bessel • Salem • Dresden • Three Mile Island Unit 1 • Indian Point Energy Center • Three Mile Island Unit 2. • LaSalle County • Vermont Yankee • Limerick • Zion

Oyster Creek

Project Manager for the following U.S. cornmercial fossil dismantling cost estimates: • • Pacific Gas & Electric Renewable (2 stations)

• Westar Energy (32 units / 3 wind farms), • Xcel Energy / Northern States Power (46 units / 2 wind farms) • Xcel Energy / Public Service of Colorado (27 units) • Xcel Energy / Southwestem Public Service (32.units)

609

Francis W. Seymore EXHIBIT FWS-1 Page 3 of 6

Project Manager for the following neutron activation analyses for commercial nuclear power reactors:

• Humboldt Bay Power Plant Unit 3' • Fort Calhoun Station • Oyster Creek Nuclear Generating Station • Pathfinder • Rancho Seco Nuclear Generating Station • Saxton Experimental Nuclear Facility • Shoreham Nuclear Power Station • Trojan Nuclear Plant (aka Columbia) • Yankee-Rowe

Developed a finite element analysis model for the Trojan Reactor Pressure Vessel and Internals package to determine the thermal profile during shipping conditions, using the FEA computer code ALGOR.

Project manager for• estimates to determine the cost to stabilize, decontaminate and decommission a PWR and a BWR commercial power reactor following a severe nuclear accident involving a reactor core meltdown and breach of the reactor vessel

Contributing author on a study for the Atomic, Industrial Forum on the standardization of cost' estimating in decommissioning as used in the support of regulatory and/or rate case hearings.

While stationed on site at Three, Mile Island Unit 2 (1982-83) as part of the recovery effort, wrote, tested, and implemented procedures for removal of the Unit 2 reactor vessel closure head as well as sampling and remote examination of the damaged core:

DECCER Cost Model Development 1984 -.Present

Converted and expanded the DECCER (DECcommissioning Costs, Exposures and Radwaste) BASIC computer logic to become the leading decommissioning cost estimating model for the U.S. comrnercial nuclear power industry. Handles all revisions and. verifications for over 40,000 lines of computer code, supporting data files, and specialized Microsoft Excel spreadsheets. Provides training to TLG users and.to customers regarding process and capabilities of the cost model.

TLG Computer Support 1984 — Present

Lead technical specialist at TLG for supporting TLG employees in the day-to-day operations of Windows-based compLiter equipment. Local Area Network Administrator. Procures and implements computer hardware and software installation and upgrades for servers and workstations.

Nuclear Energy Services, inc. Waste Management Engineer 1979 - 1982

Provided technical expertise in the planning and engineering of nuclear facility decontamination and decommissioning. Developed methodologies and cost-benefit approaches to dismantle a nuclear facility while minimizing occupational expOSure and 'waste generation. Participated in

610

Francis W. Seymore EXHIBIT-FWS-1 Page 4 of 6

developing engineering criteria and recommendations for the design of a radioactive waste immobilization system slated for use at the Western New York Nuclear Service Center.

Participated in the engineering planning for decommissioning the Shippingport Atomic Power Station, where he was involved in- the development of activity specifications associated with the decontamination of the nuclear steam supply system end the dismantling of radioactive structures.

Project Engineer responsible for a technical assessment of the costs associated with decommissioning the Humboldt Bay Unit • 3 generating station: The assessment, involved in establishing of a methodology for dismantling the facility, necessitated supporting analyses such as detailed activation study to determine the radioactive inventory of the reactor vessel and surrounding structures.

Provided general staff support for various nuclear engineering projects, including the Nine Mile Point Unit 1 shielding design review, Cooper Nuclear Station high-density spent fuel rack. boron depletion, Humboldt Bay Unit 3 spent fuel rack criticality analysis, and the LaCrosse BWR off-site dose calculation manual

EXPERT TESTIMONY:

Regulatory supporrfor nuclear utilities on decommissioning funding in state and federal dockets. Preparation of expert testimony, briefs, rebuttal, and responses to discovery and witness cross.

Testified: September 2016, before the Califomia Public Utilities Comrnission, for Pacific Gas and Electric Company on the 2015 Nuclear Decommissioning Cost Triennial Proceeding, Application 16-03-006.

Testified: April 2016, before the State of Illinois Property Tax Appeal Board, regarding the 2012 AssessMent of Byron Nuclear Power Station, Docket Nos. 12-01248 & 12-02297

Testimony Filed: October 2015, before the New Mexico Public Regulation Commission on dismantling cost estimates for 27 fossil units in Texas and New Mexico. Case settled before hearing. Case No. 15-00296-UT

Testimony Filed: August 2015, before the Public Utilities Commission of Texas for El Paso Electric Company for the Palo Verde Nuclear Generating Station. Not called at hearing. PUC docket No. 44941

Testified: June 2015, before the Texas Public Utility Commission for Southwestern Public Service Company on dismantling cost estimates for 27 fossil units in Texas and New Mexico. PUCT docket No. 43695

Testimony Filed: February 2013, before the New Mexico Public Regulation Commission for Southwestern Public Service Company on dismantling cost estimates for 28 fossil units in Texas and New Mexico. Case settled before hearing. Case No. 12-00350-UT

Testimony Filed: November 2012, before the Texas Public Utility Commission for Southwestem Public Service Company on dismantling cost estimates for 28 fossil units in Texas- and New Mexico. ease settled before hearing. PUCT docket ,No. 40824

Deposition: February 2012, before the United States Court of Federal Claims for Amergen Energy Co. LLC on decommissioning cost eitimates for the Oyster Creek, Three Mile Island Unit 1, and Clinton Power Station units. Docket No. 09-108 T.

611

Francie W. Seynnore EXHIBIT FWS-1 Page 5 of 6

Testimony Filed: February 2012,, before. the Public Utilities Commission of Texas for El Paso Electric Company for the Palo Verde Nuclear Generating Station. Case settled before hearing. PUC docket No. 40094.

Testimony Filed: November 2011, before the Public Service Commission for the State of Colorado for Public Service.Company for 32 fossil units in Colorado. Case settled before hearing. PSC docket No. 11AL-947E.

Testimony Filed: August 2011, before the Kansas Corporation Commission for Westar Energy on dismantling cost estimates for seven fossil units in Kansas. Not called at hearing. KCC docket No. 12-WSEE-112-RTS.

Testimony Filed: April 2010 before the U.S. Tax Couft for Entergy Nuclear on the decommissioning costs for the Pilgrim Nuclear Power Station. Not called at the trial due to an agreement between the parties. Docket No. 10557-08.

Deposition: October 2008, before the Texas Public Utilities Commission for Southwestern Public Service Company on dirnantling cost estimates for 28 fossil units in Texas and New tvlexico. PUCT docket no. 35763.

Testified: May 2006, before the Califomia Public Utilities Commission, for Pacific Gas and Electric Company on the Nuclear Decommissioning Costs 2005 Triennial Proceedings, Application 05-11-009.

Deposition: March 2004, by the U.S. Department of Justice for Exelon Generation Company on decommissioning cost estimates and their relation to spent fuel disposition, Commonwealth Edison Company v. United States, Case No. 98-621C

Testified: January 1990, before the New York State Public Service Commission, for Rochester Gas & Electric Company, on the Robert E. Ginna Power Plant rate case, docket 89-E-166, 167 and 168.

Testified: December 1990, before the Alabama Public Service Commission, for Alabama Power Company on the Joseph M. Farley Nuclear Plant, docket U3295.

Testified: August 1989, before the North Carolina Utilities Commission, for Duke Power Company, Carolina Power & Light, and Virginia Power Company on -decommissioning costs and waste volumes for decommissioning the Catawba Nuclear Station and Brunswick Steam Electric Plant, docket E-100, Sub 56.

PUBLICATIONS:

"Impediments to Nuclear Decommissioning Due to the Presence of Spent Fuel On Site," with William A. Cloutier Jr., presented at the ASTM Las Vegas meeting, January 1990.

"Influence of Decommissioning on Radioactive Waste Stream", with J. Adler and W. Cloutier, presented at the 1988 ANS Topical Conference: Radiological Effects on the Environment Due to Electrical Generation, July 1988.

"Decommissioning of Commercial Power Reactors: Rationale, Impetus, Execution and Consequence," with William A. Cloutier Jr., presented ai the Low Level Waste Forum, January 1986.

AIF/NESP-036, "Guidelines for Producing Commercial Nuclear Power Plant Decommissioning Cost Estimates," with Thomas S. LaGuardia et al, May 1986.

612

Francis W. Sernore EXHIBIT-FWS-1 Page 6 of 6

PROFESSIONAL ORGANIZATIONS:

National Society of Professional Engineers Connecticut Society of Professional Engineers American Nuclear Society Association for the Advancement of Cost Engineering International

613

DOCKET NO. 46831

APPLICATION OF EL ?ASO ELECTRIC COMPANY TO CHANGE RATES

PUBLIC UTILITY COMMISSION OF TEXAS

DIRECT TESTIMONY

OF

CYNTHIA S. PRIETO

FOR

EL PASO ELECTRIC COMPANY

FEBRUARY 2017

614

EXECUTIVE SUMMARY

Cynthia S. Prieto, Director of Tax for El Paso Electric Company (the. "Company" or

"EPE"), presents the payroll -and tax schedules and amounts included in the cost of service

and deferred tax amounts considered 'in the determination of rate base for the Company for

the historical Test Year. In her testimony,..she specifically discusses:

• Federal and State Income taxes included in'.Cost of Service

• Tax and Payroll Schedules provided in the Rate Filing Package (RFP"),

• Taxes Other Than Income

Federal and state income tax expense included in EPE's cost of service. has been

calculated using • the "return" method for the historical Test Year, as required by the

Instructions and Schedules, to the RFP. This refurn, method calculation reflects a

"stand-alõne" approach that includes in cost of service only federal and state income taxes

that result from the provision of utility service to customers. Ms., Prieto demonstrates that it

is neither appropriate nor equitable to increase or reduce cost of service by tax costs or

benefits that are not related to the rendition of utility service to custorners.

'Use of the return method also .satisfies the provisions ,of PURA § 36.060. In -the

Companys filing, requested tax expense is based solely on the income and expenses used

in determining the Companys revenue requirement and rate base. The Companys

stand-alone method ensures that customers benefit from the tax deductions that are

generated by the expenses included in cost olservice. This approach is reasonable and fair

for all parties.

Ms. Prieto demonstrates that the federal and state income tax schedules that are

part of the CompanY's filing are in compliance -with the prescribed RFP and are in

accordance with the Substantive Rules of the Public Utility Commission of Texas (pucr).

Adjustments made to tax expense, cost of sei-vice, and to rate base are both reasonable

and appropriate:

DIRECT TESTIMONY OF • CYNTHIA S. PRIETO.

61'5

Ms. Prieto also explains that the treatment of state deferred income taxes is iñ

compliance with the Final Order in PUCT Docket No. 44941.

In her discussion of "taxes other than income," Ms. Prieto discusses th.e Test Year

property tax amount and demonstrates that the remaining "revenue-related taxes,"

(e.g., local franchise fees, sales, ,use and gross receipts taxes and other miscellaneous

taxes plus state regulatory assessments) are reasonable and necessary.

in her discussion of payroll schedules Ms. Prieto describes the calculation of- the

salaries and wages and payroll taxes included in the revenue requirement including all

applicable proforma adjustments.

DIRECT TESTIMONY OF CYNTHIA S. PRIETO

616

TABLE OF CONTENTS

SUBJECT PAGE

I. INTRODUCTION AND QUALIFICATIONS 1

II. PURPOSE OF TESTIMONY 2

III. BACKGROUND-OF INCOME TAX ACCOUNTING AND RATEMAKING 3

IV. NORMALIZATION REQUIREMENit 8

V. FEDERAL INCOME TAXES 10

VI. STATE INCOME TAXES 14

VII. INCOME TAX SCHEDULES 16

VIII. TAXES OTHER' THAN INCOME 26

A. Property Taxes 26

B. Revenue-Related Taxes 28

IX. FAYROLL INFORMATION (G-1 SCHEDULES) 30

X. CONCLUSION 31

EXHIBITS

CSP-1 — Listing of Rate Filing Package Schedules Sponsored or Co-sponsored by Cynthia S. Prieto

DIRECT TESTIMONY OF CYNTHIA S. PRIETO

617

1 l. INTRODUCTION AND QUALIFICATIONS

2 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.

3 A. IVly name is Cynthia S. Prieto. My business address is 100 North Stanton Street,

4 El_Paso, Texas 79901.

5

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

7 A. I am, employed by El Paso Electric Company ("EPE" or the "Company") as Director

8 of Tax.

9

10 Q. DESCRIBE BRIEFLY YOUR EDUCATIONAL BACKGROUND ANp

11 PROFESSIONAL EXPERIENCE.

12 A. I earned a Bachelor of Eusiness Administration Degree with a concentration in-

13 Accounting from the University of New Mexico in 1985. I was employed by Ernst &'

14 YoUng in the Audit section from 1985 to 1992 where I was assigned to various

15 clients, including various oil and gas companies. I was employed as an Audit Senior

16 Manager by KPMG LLP from, 1993 to 1996 where I was assigned to various clients:

17 I accepted a position with the Company in 2006 as a financial accountant where I

18 worked until I was transferred to the Tax department in 2007. Since that time, Lhave

19 held various positions until I was promoted to my current position in September.

20 2009.

21

22 Q. WHAT ARE YOUR PRINCIPAL AREAS OF RESPONSIBILITY?

23 A. I am responsible for preparing the federal and state income tax returns and

24 maintaining tax accounting data for the Company. This includes the preparation of

25 tax accounting and related tax data used 'in regulatory filings. I am also responsible

1 DIRECT TESTIMONY OF CYNTHIA S. PRIETO

618

1 for the payroll department, which includes thepreparation of payroll and related tax

2 data used in regulatory filings.

3

4 Q. HAVE YOU PREVIOUSLY FILED TESTIMONY OR TESTIFIED BEFORE ANY

5 REGULATORY AUTHORITIES?

6 A. Yes. l-have filed testimony before the Public Utility Commission of Texas (pucr or

7 "Commission") and have filed testimony and testified before the New Mexico Public

8 Regulation Commission.

9

10 II. PURPOSE OF TESTIMONY

11 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?

12 A. My direct testimony addresses a nurnber of topics. First, l support the Companys

13 federal and state income tax amounts found in the G-7 schedules of the Rate Filing

14 Package (RFP") and included in EPE's requested cost of service and rate base. My

15 testimony will also address the calculation of income tax expense on a stand-alone

16 basis and explains that the Cornpany began normalizing state income tax expense in

17 accordance with. the settlement agreement approved by the Commission in the

18 Company's last rate case, PUCT Docket No. 44941. V.also sponsor EPE's taxes

19 other Than income, referenced on the 0-9 schedules. Finally, my testimony supports

20 the Company's requested payroll expense reflected in the RFP's G-1 schedules.

21

22 Q. WHY ARE YOU THE APPROPRIATE-PERSON TO SPONSOR THESE TOPICS?

23 A. In thy role as Director of Tax, I have detailed knowledge, regarding the income tax

24 accounts used to determine income tax expense as well as the amounts included in,

25 current income taxes payable, unamortized investment tax credit, a"ccumulated

26 deferred income taxes, and ta.xes other than income paid by the Company. As


619

1 indicated earlier, I assumed responsibility for the Company's payroll department in

2 2016.

3

4 Q. WHAT TEST YEAR IS THE COMPANY USING IN THIS FILING?

5 A. This filing uses the 12 months énded September 30, 2016, as the Test Year.

6

7 Q. WHAT RFP SCHEDULES DO YOU SPONSOR OR CO-SPONSOR IN THIS

8 PROCEEDING?

9 A. Exhibit CSP-1 indicates the *schedules that I am sponsoring or co-sponsoring wi6

10 other witnesses.

11

12 Q. WERE THE SCHEDULES AND EXHIBITS YOU ARE SPONSORING OR CO-

13 SPONSORING PREPARED BY YOU OR UNDER YOUR DIRECT SUPERVISION?

14 A. Yes, they were.

15

16 Q. ON WHAT BASIS.WERE THE REFERENCED SCHEDULES PREPARED?'

17 A. The schedules were prepared using the books and records of the Company, and

18 they are accurate summaries of the business records upon which they are based.

19

20 III. BACKGROUND OF INCOME TAX ACCOUNTING AND RATEMAKING

21 Q. CAN YOU PLEASE DESCRIBE THE ACCOUNTING" FOR INCOME TAXES

22 REQUIRED UNDER GENERALLY ACCEPTED ACCOUNTING PRINCOLES

23 ("GAAP")?

24 A. Yes. Accounting for income taxes under GAAP is contained in the Accounting

25 .Standards Codification ("ASC") in section ASC 740 (formerly SFAS No. 109,

26' Accounting for Income Taxes ("SFAS 109)). There are several components to the


620

1 calculation: currently payable income taxes, deferred income taxes, and investment

2 tax credits.

3

4 Q. WHAT IS THE FIRST COMPONENT, CURRENTLY PAYABLE INCOME TAXES?

5 A. Currently, payable income tax expense represents the estimated amount of current

6 year income taxes payable based on current year taxable income. Taxable income

7 for -ihe year is determined in accordance with the Internal Revenue Code ("IRC").

8 For purposes of preparing an income tax return each year, the- IRC contains

9 procedures for determining if and when an item is "taxable-or "deductible."

10

11 Q. WHAT IS THE SECOND COMPONENT, DEFERRED INCOME TAXES?

12 A. The IRC rules for determining what is taxable or deductible rnay differ from what is

13 reportable as -"revenue" or "expense" under GAAP. For instance,. certain expenses

14 recorded on the financial statements under GAAP in.one year may be dedUctible on

15 the tax return in. a different period. There are also instances where the amounts

16 shown as deductions on the tax. return in one year are not reflected on the financial

17 statements until a later year. As a result; at the end of each reporting period, there

18 will likely be accumulated differences.of reported assets and liabilities resulting frorn,

19 different book and tax return treatment of revenues and expenses. These

20 differences are referred to as temporary differences.

21

22 Q. CAN YOU FURTHEI3 EXPLAIN WHAT IS MEANT BY THE TERM "TEMPORARY

23 DIFFERENCES" AND PROVIDE AN EXAMPLE?

24 A. Yes. One common temporary difference iš depreciation. For book purposes, GAAP

25 requires that the asset be depreciated over-its estimated useful life in a sSisternatic

26 and rational manner. As a result, straight-line depreciation. over the useful life- of

4 DIRECT TESTIMONY OF CYNTHIA'S. PRIETO

621

1 assets is used for book purposes. For income, tax purposes, the asset may be

2 depreciated using an accelerated depreciation method which is generally shorter

than the estimated useful life. Initially, tax depreciation will exceed book

4 depreciation. In the later years, the reverse will be true because given the same

5 capitalized asset cost, over the life of the asset total depreciation will be the same.

6

7 Q. WHAT IS THE ACCOUNTING FOR TEMPORARY DIFFERENCES UNDER

8 ASC 740?

9 A. Under GARP, because the financial statements reflect accrual and not cash basis

10 accounting, deferred income taxes are recorded on temporary. differences. As a

11 result, income tax expense under GAAP includes both a currentlji payable,

12 component (as previously described, based on the.tax return) as well as a "deferred"

13 income tax component (based on temporary differences). Such- deferred, income

14 taxes reflect the liability or asset forincome taxes payable or receivable in the future

15 stemming from transactions recorded in the financial statements currently. The

16 balance sheet liability or asset- for future taxes is referred to as Accumulated

17 i Deferred Income Tax ("ADIT'). In other words; to the extent that accelerated tax

18 depreciation iš claimed on the income tax return in an amount that exceeds book

19 depreciation reported on the financial statements, a liability for future taxes results.

20 This future tax liability is due to the fact that greater depreciation claimed in early

21 years will "use ur the tax basis of'assets and result in higher taxes in the future.

22 Under ASC 740, a calculation of required ADIT is performed at the end of

23 each reporting period. The required ADIT is measured by multiplying the temporary

24 differences by the currently applicable income tax rates. Comparing the ADIT at the

25 current balance sheet date to the ADIT at the previous balance sheet date results in

26 "deferred income tax expense." For regulated, entities, such as EPE, the process of


622

1

recording deferred income taxes on temporary differences is referred to as

2

"normalization," "deferred tax accounting," or "comprehensive interperiod income tax

3

allocation."

4

5 Q. DOES CLAIMING DEDUCTIONS FOR INCOME TAX PURPOSES IN EXCESS OF

6 EXPENSES RECORDED FOR BOOK .PURPOSES PROVIDE INCENTIVES TO

7 THE COMPANY THAT BENEFIT CUSTOMERS?

8 A. Yes. By claiming tax deductions for such things as accelerated depreciation, the

Company reduces its current income tax payments. But, with respect to temporary

10 differences, tax payments will be higher in the future when the temporary differences

11 reverse. As a result, ADIT balances are "interest free loans" from the U.S. Treasury.

12 This was the objective Congress intended when it included accelerated depreciation

13 provisions in the IRC. Congress believed that allowing companies to increase their tax

14 depreciation deductions (and thereby reduce curreni income tax payments), would

15 lower the financing costs of their investment ih capital assets and thus they would be

16 incented to make such expenditures. For accounting purposes, using up the tax basis

17 of capital assets is both a cost to be recognized in the- financial statements when

18 claimed (i.e., deferred tax expense) and a liability for future taxes due when the

19 turnaround occurs and book depreciation exceeds tax depreciation (i.e., ADIT).

20

21 Q. ARE ALL BOOK/TAX DIFFERENCES "TEMPORARY DIFFERENCES" AND

22 SIMPLY A MATTER OF WHEN THE ITEM IS INCLUDED ON THE TAX RETURN

23 VERSUS WHEN THE ITEM IS SHOWN ON THE FINANCIAL STATEMENTS?

24 A. No. Most differences between their treatment on the books and ihcome tax return

25 are simply. "temporary" and over time, the same amount will be included on the

26 financial statements and tax returns. However, certain items of revenue and

6 DIRECT TESTIMONY OF CYNTHIA-S. PRIETO

623

1 expense are, over time, treated differently for financial reporting purposes than for

2 incorne tax purposes. These are referred to as permanent differences.

3

Deferred income taxes are not required on permanent differences. In the

4

period reported, current income taxes will be adjusted to reflect the jncreased

5 deduction or non-deductibility of these costs and there will be no deferred income

6 taxes since these amounts will "never" be included in the financial statements or

7 deducted on the tax retum thereby permanently decreasing or increasing current tax

8 expense.

9

10 Q. IS THE DISTINCTION BETWEEN PERMANENT AND TEMPORARY

11 DIFFERENCES IMPORTANT IN THE INCOME TAX CALCULATION?

12 A. Yes. Permanent differences need to bd separately identified and included in the

13 income tax. calculation because they 'do not require deferred income tax accounting,

14 and permanently increase or decrease total income tax expense that needs to be

15 recovered in revenue requirements in a rate case.

16

17. Q. IS THERE ANOTHER COMPONENT OF THE INCOME TAX CALCULATION?

18 A. Yes. In addition to current and deferred income taxes, a third element of the tax

19 computation is the Investment Tax Credit ("ITC").

20

21 Q. CAN YOU PLEASE SUMMARIZE WHAT THE ITC IS AND HOW IT IS TREATED

22 FOR ACCOUNTING/RATEMAKING PURPOSES?

23 A. The ITC, which has gone in and out of existence over.the years, lowers income tax

24 expense permanently, if ceqain qualifying investments are made. It, is intended as

25 an incentive for companies to invest in qualifying assets. To make. sure that its


624

1 objectives are !net for regulated •utilities, the IRC prescribes methods of sharing the

2 benefit between customers and-shareholders.

3 The ITC is a direct reduction of incipme taxes payable in a given year. pnlike

4 accelerated depre9iation and other book/tax differences that will eventually reverse

5 or turn around, the ITC is comparable to a rebate. The ITC provides an incentive to

6 capital investment by granting a tax credit (a direct dollar-for-dollar• offset to current

7 taxes, payable) based on a percentage applied to investMent in tangible personal

property (most generation, transmission and distribution assets).

9 The accounting for the ITC is contained in ASC 740, codifying the accounting

10 for ITC -previously contained in Accounting Principles Board Opinions 2 and 4,

11 Accounting for the Investment Credit. Most utilities, like EPE, account for the ITC by

12 reducing current income taxes payable in the year the credit is earned for the full

13 amount of the credit but recognize an equal and offsetting amount of deferred tax

14 expense. The amount of the credit is then. amortized to reduce income tax expense

15 over the book life of the property giving rise to the ITC.

16 " In 1972, for ratemaking purposes, the IRS required utilities to elect how they

• 17 intended to share the ITC between customers and shareholders. Most utilities,

18 including EPE, elected to share the ITC as described in the preceding paragraph, by

19 including the annual amortization to income tax expense as a reduction to income tax

20 expense. In accordance with- this election, the unamortized ITC basis is not deducted

21 from rate base. Reduced income tax expense benefits customers when it is included in

22 . rates.

23

24 IV. NORMALIZATION REQUIREMENtS

25 .Q. WHAT IS THE FEDERAL ENERGY REGULATOIRY COMMISSION'S (FERC")

26 POSITION ON DEFERRED INCOME TAXES?


625

-1 A. The FERC Uniform System of Accounts embraces "normalization" of deferred

income taxes by requiring comprehensive interperiod income tax allocation for all

3 book/tax timing/temporary differences. FERC Order Nos. 144 and 144A provide

4 guidance in this area. This has been the FERC methodology since the early 1980s.

5

6 Q. IS NORMALIZATION ACCOUNTING REQUIRED. FOR A UTILITY TO REFLECT

7 CERTAIN DEDUCTIONS AND CREDITS ON ITS FEDERAL TAX RETURN?

8 A. Yes. The IRC requires that regulated utilities rnust use the normalization method,

9 and not the flow-through method, to calculite the tax expense related to

10 depreciation-related temporary differences (IRC Section 168), Contributions In Aid of

11 Construction (IRS Notice 87-82), investment tax credits, excess deferred taxes, and

12 net operating losses (NOLus) created by accelerated depreciation in orderto avoid

13 certain penalties.

14

15 Q. IN THE PREVIOUS QUESTION, YOU MENTIONED THAT NOLS CREATED BY

16 ACCELERATED DEPRECIATION WERE REQUIRED TO BE NORMALIZED. IS

17 EPE IN A NOL CARRYFORWARD POSITION?

18 A. Yes. EPE is currently in a. NOL carlyforward position. EPE's NOL was created in

19 tax year 2015 and the Test Year from tax deductions which exceeded taxable

20 income. These deductions "arose from temporary differences related to accelerated

21 tax depreciation allowed by the extension of bonus depreciation in the Protecting

22 Americans from ,Tax Hikes Act of 2015 (PATH Acr), whiCh was signed into law

23 December 2015 and applicable retroactively to January 1, 2015.

24

25 Q. HAS EPE INCLUDED A NOL CARRYFORWARD ADIT ASSET IN RATE BASE IN

26 THE TEST YEAR?

9 DIRECT TESTIMONY OF CYNTHIA S. PRIÈTO

'626

1 A. Yes, it has,, consistent with IRS normalization requirements. When a company has

negative current taxable income, it cannot realize the cash benefit of all of its

3 deductions, because it cannot reduce its tax payments below zero. The NdLs must

4 be.deferred and carried forward to be used against taxable income in future periods,

5 subject to certain limitations. Only then will the taxpayer receive the cash tax benefit

6 of these NOLs. When carried forward, the NOL is'a temporary difference for which

7 an ADIT asset must be recorded. The net of the ADIT liability created by the bonus

8 •depreciation and the AD1T asset created by the NOL carryforward represents the

9 cash tax benefits that were actually received by the Company.

10

11- Q. WHAT IS THE PENALTY FOR VIOLATING THE IRS• NORMALIZATION

12 REQUIREMENT REGARDING NOLS?

13 A. The NOL normalization rules are a subset of the depreciation normalization rules,

14 therefore, a violation of the NOL normalization requirement would result in the loss of

15 the ability to ,u,se accelerated tax depreciation on all public utility property. held by the

16 utility.

17

18 V. FEDERAL INCOME TAXES

19 Q. 'HOW HAVE FEDERAL INCOME TAXES INCLUDED IN COST OF SERVICE BEEN

20 CALCULATED?

21, A. Federal income taxes have been calculated using the "return" method for the

22 historical year, as required by the Instructions and Schedules to the RFP.

23

24 Q. WHAT IS THE "RETURN" METHOD?

25 A. The calculation of federal income takes provided on Schedule G-7.8 is comrnonly

26 referred to as the "return" method because it calculates federal income taxes using

' 10 DIRECT TESTIMONY OF CYNTHIA S. PRIETO

627

after-tax return as the starting point. Under this method, equity retum, or total retum

2

less interest, is adjusted for items for which there is no tax deduction to offset

3

amounts recovered through revenues — such as book amortization of Allowance kr

4

Funds Used During Construction ("AFUDC") equity, "flow-through differences,"

5

permanent differences, ITC amortization, and the amortization of excess ADIT. The

6

"return" method calculates federal income tax expense in total, with no segregation

7

between current and deferred federal income taxes. The return method tax

8

calculation provided on Schedule G-7.8 reflects a stand-alone approach to

9

cglculating federal income taxes.

10

11 Q. WHAT IS THE BASIS FOR' THE PERMANENT DIFFERENCES INCLUDED IN THE

12. RETURN METHOD?

13 A. Permanent differences can arise when costs are reported as expenses in the

14 financial statements but will never be deductible on the income tax return. In

15 addition, permanent differences can also arise when deductions are allowed on the

16 income tax return that will never be reported as expenses in the financial statements.

17 Examples of permanent differences in EPE's tax Calculation are the cost of meals

18 and entertainnient and the domesti6 próduction'activities- deduction (DPAD"). The-

19 cost of meals and entertainment are reported as expenses in the financial

20 s-tatements but, under the IRC, are not completely deductible on the income tax

21 return and is therefore a permanent difference which increases current tax expense.

22 The ,DPAD is a deduction allowed by the IRC for domestic manufacturing activities

23 but is limited by several factors including taxable income. This deduction will never

24 be an expense in the GAAP financial statements and is therefore a perManent

25 difference which decreases current tax expense.

26

11 DIRECT TESTIMONY OF CYNTHIA S. PRIETO-

628

1 Q. WHAT IS MEANT BY A "STAND-ALONE" APPROACH?

2 A. The ."stand-alone" methodology calculates federal income taxes on utility revenues

3 and expenses that are included in the utility's revenue requirement. This approach

4 appropriately allocates federal income taxes between customers and shareholders

5 using the benefits/burdens criteria outlined by FERC Opinion No. 173. Under this

6 methodology, federal income tax expense relates to, and results from, the provision

7 of utility service to customers. Additionally, the "stand-alone federal income tax

8 calculation includes an adjustment -to synchronize interest. Synchronized interest

9 represents the portion of return that is deductible for -tax purposes and ie calculated

10 by multiplying'the weighted cost of debt by rate 'base. Use of synchronized interest

11 in the tax calculation effectively "synchronizes" the calculation of federal income tax

12 expense with rate base and' rate of return. Synchronized interest may be more or

13 less than the actual interest deducted on the tax return.

14

15 Q. WHY IS THE "STAND-ALONE" APPROACH THE PROPER METHODOLOGY TO USE

16 IN CALCULATING FEDERAL INCOMETAXES,FOR RATEMAKING PURPOSES?

17 A. The "stand-alone approach; required by Section 36.060 of the Public Utility

18 Regulatory Act ("PURA") as amended, in 2013, includes in cost of service only

19 federal incometaxes that result from the provision of utility service to customers.

20 Federal income taxes requested by the Company are based on revenues and

21 expenses included in the cost of service calculation. There are no additions to or

22 reductions from tax expense resulting from revenues or expenses notincluded in the

23 Company's request.' It is rieither appropriate nor equitable to increase or reduce cost

24 of service by tax costs or benefits that are not related to the rendition of utility service

25 to customers.


629

1 Said another way, income taxes have no independentexistence of their own.

2 They are based on revenues and expenses. Once the Commission decides on the

3 appropriate reVenues and expenses that are necessary for the provision of electric

4 service, the related income taxes can be determined.

5

6 Q. WHAT IS THE AMOUNT OF FEDERAL INCOME TAX EXPENSE THE COMPANY

7 'IS REQUESTING TO BE INCLUDED IN RATES?

8 A. The Company is requesting the amount of federal income tax expense that is

9 included in cost of service reflected on Schedule G-7.8.

10

11 Q HAS THE COMPANY COMPUTED FEDERAL INCOME TAXES IN ACCORDANCE

12 WITH SECTIONS 36.059 AND 36.060 OF PURA?

13 A. Yes. PURA Sections 36.059 'and 36.060 address the treatment of certain tax

14 benefits; including ITC and consolidated tax savings. PURA Sections 36.059(b) and

15 36.060(c) specifically require a utility .that retains ITC to deduct it from the rate base

16 to which tlie credit applied, to the extent allowed by the IRC. The post-1970 portion

17 of unamortized ITC is not included as a r.eduction of rate base because. the Company.

18 is an "Option 2" company for ITC purposes. Under IRC Section 46(f), an "Option 2"

19 election requires that the post-1970 ITC be returned to customers as a reduction of

20 cost-of-service, rather than as a reduction of rate base.

21 Additionally, PURA Section 36.060(b) requires that income taxes related to

22 intercompany profits on affiliated purchases be applied tb reduce 'the cost of the

23 property or service purchased., The Comioany had no affiliates or subsidiaries for the

24 Test Year ended September 30, 2016, or during the Test Year. As a result, tax

25 expense included in this filing has been, calculated in accordance with PURA

26 Section 36.060(b).


630

1

Further, PURA SeOtion 36.060(a) requires that income tax expense included

2

in cost of service reflect only expenses and investments- included in cost of service

3

and rate base. The Companys income tax amounts included in cost of service are

consistent with this provision.

5

6 VI. STATE INCOME TAXES

7 Q. WHAT IS THE AMOUNT OF STATE INCOME TAX EXPENSE THE COMPANY IS

8 REQUESTING TO BE INCLUDED IN RATES?

9 A. The Company is requesting the amount of state income tax expense that is included

10 in cost of service reflected on Schedule G-7.8.

11

12 Q. WHICH ACCOUNTING METHOD HAS EPE USED TO DETERMINE STATE

13 INCOME TAX EXPENSE IN THIS CASE?

14 A. Pursuant to the settlement agreement that was approved by the Commission Final

15 Order in the Company's last rate case, PUCT Docket No. 44941, the Company has

16 used the normalization method to determine the state income tax expense included

17 in cost of service.

18

19 Q. WHAt DID THE SETTLEMENT IN PUCT DOCKET NO. 44941 PROVIDE WITH

20 RESPECT TO STATE INCOME TAX EXPENSE?

21 A. Prior to, PUCT Docket No. 44941, the Company used the flow through method to

22 calculate state income tax' expense: However, in- PUCT Docket No. 44941, the

23 Company requested to switch to the normalization method. The settlement

24 approved in the case authorized the change in methodologies. Article I. Section F. of

25 the Settlement Agreement stated:


631.

1

Beginning January 1, 2016, EPE should begin normalizing state income tax

2

expense. In other words, it should begin including both current and deferred

3

state income tax expenše in its revenue requirement (just as it- does for

4

federal incõme tax expense) instead of just the current portion of state

5

income tax expense. On that date, it should also begin amortizing the test

6

year-end balance of accumulated deferred state income tax expense that has

7

not yet been included in cost of service over a 15-year period.

8

This provision was. adopted in Findings of Fabt Nos. 40 and 60 in the Final Order

9 issued in PUCT Docket No. 44941.

10

11 Q. HAS THE COMPANY COMPLIED WITH THIS PROVISION?

12 A. Yes, it has. In August ,2016, after the Final Order was issued in PUCT Docket

13 No. 44941, the Company began normalizing state income tax expense and recorded

14 adjustments to make the change retroactive to January 1, 20161. In this filing it has

15 included both ci.Frent and deferred state income tax,expense in its state income tax

16 expense request. Further, the Company also began amortizing its balance of

1T accumulated deferred state income tax expense• that has not yet been included in

18 cost of service over a 15-year period.

19

20 Q. WHAT IS THE AMOUNT OF STATE INCOME TAX EXPENSE THE COMPANY IS

21 REQUESTING BE INCLUDED IN ITS COST OF SERVICE?

22 A. State income tax expense is shown on pages 3 to 5 of Schedule G-7.8. The annual

23 amortization of the January 1, 2016 balance of accumulated deferred state income

24 tax not yet included in cost of service is calculated on Schedule G-7.9(a), line 59,

Although the Final Order in PUCT DoCket No. 44941 was issued August 25, 2016, the Company's accounting treatment was"retroactive to January 1, 2016.


632

1 column (c) and included in incorrie tax expense on Schedule G-7.8, page 1, line 17,

2 column (c).

3

4 \ill. INCOME TAX SCHEDULES

5 Q. PLEASE DESCRIBE SCHEDULE G-7.1, RECONCILIATION OF TEST YEAR BOOK

6 NET INCOME TO TAXABLE NET INCOME.

7 A. Schedule G-7.1 is the reconciliation .of book net income to taxable net income on a

8 total company basis for the Test Year and for the most recently filed federal' income

9 tax return. Schedule G-7.1 contains explanations of all iterns in the reconciliation for

10 both the Test Year and the ta-x return.

11

12 Q: PLEASE ,DESCRIBE SCHEDULE G-7.1(a), RECONCILIATION OF TIMING

13 DIFFERENCES.

14 A. This schedule includes a listing of timing differences and other items that produce

15 federal income tax for the Test Year at a tax rate different than the statutory 35% tax

16 rate, with explanations describing each item.

17

18 Q. PLEASE DESCRIBE SCHEDULE G-7.2, PLANT ADJUSTMENTS.

19 A. This schedule provides the tax.basis, tax in-service date, tax depreciation rnethods,

20 and tax depreciation in the Test Year and projected for the two subsequent years,

21 and the amount of ADFIT as of the Test Year-end for any new generating unit

22 requested (purchased or constructed since the Companys last rate case) and any

23 requested plant adjustments to the Test Year.

24


633

1 Q. PLEASE.DESCRIBE SCHEDULE G-7.3, CONSOLIDATED TAXES.

2 A. This schedule is not applicable. The Company, did not have any subsidiaries in the

3 Test Year ended September 30, 2016 or during the Test. Year.

4

5 Q. PLEASE DESCRIBE SCHEDULE G-7.3(a), CONSOLIDATION BENEFITS.

6 A. This schedule is not applicable. The Company did not have any subsidiaries in the

7 Test Year ended September 30, 2016.

8

9 Q. IS THE COMPANY A MEMBER OF A CONSOLIDATED GROUP OR DOES THE.

10 COMPANY HAVE ANY SUBSIDIARIES?

11 A. No. The Company did not have any subsidiaries in the Test Year, and it is not part

12 of a consolidated group.

13

14 Q. PLEASE DESCRIBE SCHEDULE G-7.3(b), CONSOLIDATION/INTER-CORPORATE

15 TAX ALLOCATION.

16 A. This schedule is not applicable to the Company. The Company-did not have an9

17 subsidiaries in the Test Year ended September 30, 2016.

18

19, Q. PLEASE DESCRIBE SCHEDULE G-7.4, ADFIT.

20 A. This schedule shows the balance sheet amourit of ADIT for each of the twelve

21 months of the• Test Year; at the end of the Test Year; and the additions and

22 reductions during the Test Year as well as the requested adjustments to the

23 balances. Each item that gives rise to ADIT is shown separately on this schedule.

24

25 Q. PLEASE DESCRIBE StHEDULE G-7.4(a), ADFIT-DESCRIPTION OF TIMING

26 DIFFERENCES.


634

A. This schedule includes a description of the nature and remaining life, where

2 applicable, of each timing difference listed in Schedule G-7.4.

3.

4 Q. PLEASE DESCRIBE'SCHEDULEG-7.4(b), ADJUSTMENTS TO ADFIT.

5 A. This schedule shows the details of the adjustments to the balance sheet ADIT

6 accounts. The reasons for these adjustments are included as well as the supporting

7 calculations, if any.

8

9 Q. DOES THIS SCHEDULE REFLECT THE IMPACTS OF BONUS DEPRECIATION?

10 A. Yes. The Company can and has claimed bonus depreciation as permitted by the

11 IRC. Depending on the year certain capital assets were placed in service, the

12 additions are eligible 'for 50 percent or 100 percent bonus depreciation. This

13 effectively means that for income tax purposes; in addition to tax depreciation

14 computed using the Modified Accelerated Cost Recovery System ("MACRS"), the

15 Company can claim an additional 50 percent or 100 percent of the eligible tax basis

16 as a tax depreciation deduction in the first year. As a result, EPEs Test Year end

17 ADIT related to these book/tax depreciation temporary differences has increased to

18 reflect the future tax liability associated with these accelerated deductions.

19

20 Q. DID THE COMPANY REMOVE TEST YEAR END ADIT FOR AMOUNTS RELATED

21 TO UNCERTAIN TAX POSITIONS REQUIRED TO BE IDENTIFIED AND

22 ACCOUNTED FOR BY FINANCIAL ACCOUNTING STANDARDS BOARD

23 INTERPRETATION 48 ("FIN 48")?

24 A. NO reductions were made'to Test Year end ADIT in rate base for FIN 48 reserves.

25


635

1 Q. PLEASE DESCRIBE SCHEDULE G-7.4(c), ADFIT AND ITC — PLANT

2 ADJUSTMENTS AND ALLOCATIONS.

3 A. This schedule provides the accumulated deferred income tax balances at Test Year

4 end related to additions to new generating plant in service since the Company's last

filing and any plant adjustments to the Test Year end requested by the Company and

6 the supporting calculations.

7

8 Q. PLEASE DESCRIBE SCHEDULE G7.4(d), ADFIT-RATE CASE EXPENSE.

9 A. This schedule is not applicable. The Company does not have any ADIT assóciated

10 with rate case expense reflected on the books at September 30, 2016.

11-

12 Q. PLEASE DESCRIBE SCHEDULE G-7.5; ANALYSIS OF ITCS.

13 A. This sthedule presents the analysis of the ITC adjustment for Deferred Investment

14 Tax Credit (DITC") to be included in cost of service. The Company's election under

15 Section 46(f)(2) of the IRC does not permit amortization of ITC to reduce income tax

16 expense in cost of service at a rate more rapidly than ratably — no faster than over

17 the book life-of the assets that generated the ITC. The "stripped" book depreciation

18 rate requested is derived from the book depreciation calculation reflecting , the life

19 extension of the Palo Verde Nuclear Generating Station ("PVNGS") unit where

20 applicable. This rate represents the life or investrnent portion of the book

21 depreciation rate without regard to amounts for cost of removal or salvage. The

22 stripped depreciation rate is multiplied by the ITC amortization base to calculate the

23 annual amount of DITC amortization included in cost of service. The stripped

24 depreciation rate is used in this computation to avoid a potential normalization

25 violation that could result if the ITCs were amortized in cost of service at a rate more

26' rapid than ratably. Workpaper G-7.5 shows the calculation of the Test Year ITC. For


636

1

3

4

each class of assets generating the ITC, the Company applied the stripped

depreciation rate to the ITC amortization base to arrive at the ITC amortization used

to reduce income tax expense.

5 Q. PLEASE pESCRIBE SCHEDULE G-7.5(a), UTILIZED.

A. This schedule shows the ITC utilized (claimed on the income tax return) each year.

7

8 Q. PLEASE DESCRIBE SCHEDULE G-7.5(b), GENERATED BUT NOT UTILIZED.

9 A. This schedule presents the ITC generated but not utilized at the Test Year end

10 September 30, 2016. This schedule is not applicable to the Company. All

11 investment credits that were generated prior to September 30, 2016 have been

12 utilized by EPE.

13

14 Q. PLEASE DESCRIBE SCHEDULE G-7.5(c), UTILIZED — STAND-ALONE BASIS.

15. A. This schedule is not applicable to the Company. All investment credits have been

16 utilized by EPE.

17

18 Q. PLEASE DESCRIBE SCHEDULE G-7.5(d), ITC ELECTION.

19 A. This schedule describes the tax elections made by EPE with regard to ITC.

20

21 Q. PLEASE DESCRIBE SCHEDULE G-7.5(e), FERC ACCOUNT 255 BALANCE.

22 A. This schedule shows the account balance for FERC Account No. 255 — Accumulated

23 Deferred Investment Tax Credits as of September 30, 2016.

24

25 Q. PLEASE DESCRIBE SCHEDULE G-7.6, ANALYSIS OF TEST YEAR FIT AND

26 REQUESTED EIT — TAX METHOD 2.


637

1 A. This schedule calculates federal and state income tax expense for the Test Year

2 using Tax Method 2. This method of calculating federal and state jncome tax

3 expense determines the current and deferred components of tax expense

4 separately. The components of tax expense shown on this schedule include taxes

5 currently payable, deferred taxes, and D1TC amoriizkion. The Tax Method 2

6 calculation is equal to the amount of tax expense computed under the return method

7 (see Schedule G-7.8).

9 Q. PLEASE DESCRIBE SCHEDULE G-7.6(a), ANALYSIS OF DEFERRED FIT.

10 A. This schedule is an analysis of each deferred tax item that makes up the federal

11 deferred tax expense,in Schedule G-7.6.

12

13 Q. PLEASE DESCRIBE SCHEDULE G-7.7, ANALYSIS OF ADDITIONAL

14. DEPRECIATION REQUESTED.

15 A. This schedule provides the detail stipport for the requested adjustment to return for

16 additional depre,ciation. This schedule summarizes the major components related to

17 flow-through book depreciation for which there is no tax benefit. Workpaper G-7.7

18 provides the detail calculations for this schedule.

19

20 Q. PLEASE DESCRIBE SCHEDULE G-7.8, ANALYSIS OF TEST YEAR FIT &

21 REQUESTED FIT — TAX METHOD 1.

22 A. This schedule calculates federal and state income tax expense for the Test Year

23 using Tax Method 1, corniputed under the return method. The Tax Method 1

24 calculation is equal to the amourit of tax expense computed under Tax Method -2

25 (see Schedule G-7:6).

26


638

1 Q. DID THE COMPANY REFLECT AN ADJUSTMENT TO ITS TEST YEAR DPAD

2 AMOUNT ON SCHEDULE G-7.8?

3 A. Yes. Although the DPAD is generally a deduction for income tax purposes, the

4 federal income tax calculation for the Test Year has an adpition of $4 million related

5 to the DPAD on Schedule G-7.8, line 8, column (b). This situation arose due to the

6 enactment of the PATH Act in December 2015. In the third quarter of 2015, the

7 Company was projecting taxable income for 2015 and therefore was eligible- to

8 deduct the DPAD. Based on the projection of taxable income, the Company

9 recorded a deduction of $4 million for the DPAD in its tax accrual in the third quarter

10 of 2015. However, when the PATH Act was enacted in December 2015,. additional

11 tax depreciation. deductions for bonus depreciation resulted in a net operating loss

12 'for the Company for the tax year 2015. Because the Company did not have taxable

13 income, it was no longer eligible for the DPAD and reversed this 'deduction in the

14 December 2015 tax accrual. The tax accrual for the Test Year includes the fourth

15 quarter of 2015 and therefore includes the reversal of the DPAD in the amolint of

16 $4 million. The Companys requested income .tax calculation does not include a

17 reversal or deduction for the'DPAD because the requested dncome tax calculation

18 results in a net operating loss for the rate year and threfore the Company is not

19 eligible for the DPAD. As explained earlier, the net operating loss was due to tax

20 depreciation deductions from bonus depreciation.

21

22 Q. PLEASE DESCRIBE SCHEDUCE G-7.9, AMORTIZATION OF 11.'ROTECTED AND'

23 UNPROTECTED EXCESS DEFERRED TAXES..

24 A. This schedule summarizes the amortization of protected and unprotected excess

25 deferred federal income tax and the amortization methodology utilized.. Taxes that

26 relate to timing differences that are in excess of the statutory tax rate of 35 percent


639

1

are referred to as "excess deferred tax6s." These "excess deferred taxes" are

2

further categorized as "protected" or "unprotected." Protected excess deferred taxes

3

refer to specific rate treatments in the IRC that dictate how these amounts of excess

4

deferred taxes should 'reverse. Violation of the rate treatment specified by the IRC is

5

a nórmalization violation which, as described previously, results in the loss of

6

favorable income tax treatment of certain tax deductions (such as accelerated

7

depreciation), requiring the payment of higher current federal income taxes than

8

would have been paid if the proper rate treatment were followed. Unprotected

9

excess deferred taxes have no such rate treatment required in the IRC.

10

11 Q. PLEASE DESCRIBE SCHEDULE G-7.9(a), ANALYSIS OF EXCESS DEFERRED

12 TAXES BY TIMING DIFFERENCE.

13 A. This schedule shows the details of the information contained in Schedule G-7.9 by

14 timing difference. Workpaper G-7.9(a) includes the remaining excess deferred tax

15 balance at the end of the Test Year and the requested amortization for each item.

16 This schedule includes the calculation of the amortization of the excess deferred

.17 taxes that arose from the change to the normalization method for state income taxes

18 at January 1, 2016 that was described previously.

19

20 Q. PLEASE DESCRIBE SCHEDULE G-7.9(b), RECONCILIATION OF EXCESS.

21 A. This schedule provides the unamortized excess deferred tax balances at the Test

22 Year end September 30,. 2016, and a reconciliation, by timing difference, to the

23 unamortized excess tax balances ,at March 31, 2015, that were filed with the

24 Commission in Docket No. 44941.

25


640

1 Q. PLEASE DESCRIBE SCHEDULE G-7.9(c), ANALYSIS OF RESERVE

2 ACCOUNTING FOR EXCESS DEFERRED TAXES.

3 A. This schedule is, not applicable to the Company. The Company was not required by

4 prior Commission order to establish reserve accounting for excess deferred taxes.

5

6 Q. PLEASE DESCRIBE SCHEDULE G-7.10, EFFECTS OF ACCOUNTING ORDER

7 DEFERRALS.

8 A. This schedule is not applicable. The Company does not have any ADIT or fedèral

9 income tax as 9f September 30, 2016, relate'd to accounting order deferrals.

10

11 Q. PLEASE DESCRIBE SCHEDULE G-7.11,, EFFECTS OF POST-TEST YEAR

12 ADJUSTMENT.

13 A. This schedule is not applicable. The Companys request does not include post-test

14 year adjustments to plant.

15

16 Q. PLEASE DESCRIBE SCHEDULE G-7.12, EFFECT.S OF RATE MODERATION

17 PLAN.

18 A. The Company does not have an existing rate moderation plan and is not requesting

19 a rate moderation plan. Rate moderation plans adopted in the past have no effect on

20 federal income tax and ADIT.

21

22 Q. PLEASE DESCRIBE SCHEDULE G-7.12(a), TREATMENT pF FIT AND ADFIT IN

23 RATE MODERATION PLAN.

24 The.Company does not have an existing rate moderation plan and all federal income

25' tax and ADIT from previous rate moderation plans have been fully amortized.

26


641

1 Q. PLEASE DESCRIBE SCHEDULE G-7.13, LIST OF FIT TESTIMONY.

2 A. This schedule lists all witnesses that are filing testimony in this case that support the

3 Company's federal income tax and ADIT requests. The most 'recent tax return filed

(for the year 2015) is included as part of the. cqnfidential workpapers for this

5 schedule.

6

Q. PLEASE DESCRIBE SCHEDULE G-7.13(a), HISTORY OF TAX NORMALIZATION.

8 A. This schedule details the history • of tax normalization for the Company and also

9 provides details of the first year for each timing difference and the first year normalized.

10

11 Q. PLEASE DESCRIBE SCHEDULE G-7.13(b), TAX ELECTIONS.

12 A. Tax elections made by the Company since the Test Year end reflected in the last

13 rate filing, Docket No. 44941, are detailed' in this schedule.

•14

15 Q. PLEASE DESCRIBE THE CHANGES IN ACCOUNTING FOR DEFERRED TAXES•

16 SHOWN ON SCHEDULE G-7.13(c)?

17 A. There have been no changes, in accounting for federal deferred income taxes. •As

18 previously discussed, the Company has included deferred state income taxes in cost

19 of service and has proposed recovery of the prior accumulated state ADIT usinT a

20 South deorgia methodology.

21

22 Q. PLEASE DESCRIBE SCHEDULE G-7.13(d), IRS'AUDIT.STATUS.

23 A. This schedule explains the Companyš current federal income tax audit status. For

24 tax years 2016 and 2017, the Company is participating in the IRS Compliance

25 Assurance Process ('CAP) Program. As described in this Schedule, the CAP is a

26 method of resolving tax issues between the taxpayer and the IRS through open and


, 642

1 transparent interactions and communications to resolve issues prior to the filing of

2 tax returns.

3

4 Q. SCHEDULE G=7.13(e) RELATES TO PRIVATE LETTER RULINGS SINCE THE

5. LAST RATE FILING. HAVE, THERE BEEN ANY PRIVATE LETTER RULINGS

6 RECEIVED SINCE THE LAST RATE FILING THAT AFFECT THE FEDERAL

7 INCOME TAX OF THE COMPANY?

8 A. There have been no private letter rulings received by the Company since the last

9 rate filing..

10

11 Q. PLEASE DESCRIBE SCHEDULE G-7.13(f),, METHOD OF ACCOUNTING- FOR

12 ADFIT RELATED TO NOL CARRYFORWARD.

13 A. This schedule describes the method of accounting for the Company's NOL

14 Carryforwards and the balances included in ADIT at the Test Year end

15 September 30, 2016.

16

17 VIII. TAXES OTHER THAN INCOME

18 Q-. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR TESTIMONY?

19 A. In this section of my testimony, I first discuss the Companys property taxes. I then

20 discuss the remaining taxes other than income that the Company incurs.

21

22 A. Property Taxes

23 Q. WHAT-WAS THE TOTAL AMOUNT OF PROPERTY TAXES DURING THE TEST

24 YEAR?

25 A. The total• amount of property, taxes for the Company in the Test Year is shown on

26 ScheclUle G-9, column' (e), lines 1 to 3.


643

1 Q WHAT IS THE NET REQUESTED RECOVERY AMOUNT FOR THE COMPANY'S,

2 • PROPERTY TAXES?

3 A. The total amount of requested property taxes can be found on Schedule G-9,

4 column (g), lines 1 to 3.

5

6 Q. • HOW ARE THE PROPERTY TAXES FOk THE COMPANY DETERMINED?

7 A. The property taxes charged to the Company' are the amounts imposed by taxing

8 authorities. to which the Company is. subject. Property taxes are capitalized to

9 construction work in proce 'Ss for assets currently under construction based on an

'10 assessed value, or are expensed for assets placed in service.

11

12 Q. PLEASE DESCRIBE THE VARIOUS TAXING AUTHORITIES , THAT LEVY

13 PROPERTY TAXES AGAINST THE COMPANY'S PROPERTY.

14 A. The Company is subject to property taxation by many different taxing jurisdictions.

15 These taxing jurisdictions include, but are not limited to, counties, cities, independent*

16 school districts, fire districts, and industrial districts. Also, various taxing jurisdictions.

17 overlap, and, for example, a single piece 9f utility property may be the basis for-

18 property tax levied by as many as six or more jurisdictions.

19

20 Q. HOW ARE THE PROPERTY TAX AMOUNTS IMPOSED BY THE TAXING

21 JURISDICTIONS DETERMINED?

22 A. Property tax is typically assessed against the appraised or taxable valUe of the

23 Companys property located within the jurisdiction of a taxing authority. Generally,

24 the property tax appraisal process is a two-step process for a regulated utility. The

25 first step is to establish a market value for all of the utilitys property, collectively.


644

1 This is referred to as a "unir valuation. The second step is to allocate that market

2 value of the unit to the taxing-jurisdictions in which the utility owns taXable proOerty.

3 Once the taxable value for a tax jUrisdiction is determined and final; the

4 jurisdiction calculates and sends a bill to the taxpayer. The billed amount' is

5 determ.ined by multiplying the' jurisdiction's tax rate by the taiable value of EPE's

6 property in that jurisdiction.

7

8 Q. PLEASE DESCRIBE SCHEDULE G-9.1, AD VALOREM TAXES AND PLANT

9 BALANCES.

10 À. This schedule shows the amount of ad valorem taxes assessed, penalties paid, and

11 discounts taken for the three calendar years shown on Schedule G-9, as well as the

12

net plant balances at the beginning of each of those years.

13.

14 Q. . HAS THE COMPANY. MADE ANY PRO FORMA ADJUSTMENTS TO ITS TEST

15 YEAR PROPERTY TAX AMOUNT?

16

Yes. The-Company has made pro forma adjustments to its Test Year property tax

17

amounts to reflect an effective rate of tax assessed on adjusted net plant in service

18

balances at September 30, 2016. The adjustment is included in Workpaper A-31

19

Adjustment No. 15.

20

21 B. Revenue-Related Taxes

22 Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR TESTIMONY?

23 A. In this section of my testimony, I sponsor the Company'S revenue-related taxes. By

24 "revenue-related taxes," l mean the Companys directly-incurred local franchise fees,

25 sales, use and gross receipts taxes, and other miscellaneous taxes plus, state

26 regulatory assessments.


645

1 Q. WHAT WAS THE TOTAL AMOUNT OF REVENUE-RELATED TAXES DURING

2 THE TEST YEAR?

3 A. The total amount revenue-related taxes for the Company in the Test Year is shcwn

4 on Schedule G-9, column-(e), lines 10, 11 and 13 to 17.

5

6 Q WHAT IS THE NET REQUESTED RECOVERY AMOUNT FOR THE COMPANY'S

7 REVENUE-RELATED TAXES?

8 A. The total amount of requested revenue-related taxes can be found on Schedule G-9,

9 column (g), lines 10; 11 and' 13 to 17.

10

11 Q. HAS THE COMPANY MADE ANY PRO FORMA ADJUSTMENTS TO ITS

12 TEST-YEAR REVENUE-RELATED TAXES?

13 A. Yes. Adjustments were made to revenue-related taxes where necessary to reflect

14 adjustments to the underlying amounts in cost of service. The adjustments were

15 calculated based on an effective tax rate determined by dividing the applicable taxes

16 expensed by taxable Company revenues. These effective tax rates were adjusted

17 for the uncollectible rate and then applied to requested -revenues to determine the

18 amount of taxes included in the requested cost of -service. These adjustments are

19 reflected oiT Schedule G-9 and are calculated in Workpaper A-3, Adjustment No. 17.

20

21 Q. ARE THESE EXPENSES NECESSARY AND REASONABLE?

22 A. Yes. These taxes are necessary because they are required by law in order to.allow

23 the Company to operate in its applicable jurisdictions. The amounts are reasonable

24 because the taxes are imposed by law and calculated in accordance with applicable

25. law.

26


646

1 IX. PAYROLL INFORMATION (G-1_ SCHEDULES)

2 Q. WHAT DO THE G-1 SCHEDULES CONTAIN?

3 A. The G-1 Schedules (G-1 through G-1.6) contain payroll' information.

4

5 Q. WHAT INFORMATION I's IN SCHEDULE G-1 (PAYROLL INFORMATION)?

6 A. Schedule G-1 provides a narrative of EPE's payroll practices.

7

8 Q. WHAT INFORMATION IS IN SCHEDULES.G-1.1, G-1.2, AND G-1.3?

9 A. Schedules G-1.1, 1.2, and 1.3 provide gross payroll information for each month in

10 the October 2015 — September 2016 Test Year as well as the three most recent

11 calendar years before the Test Year — 2013, 2014, and 2015.

12 • In Schedule G-1.1 (Regular and Overtime Payroll), the categories are regular payroll,

13 overtime payroll, other, and total payroll.

14 • In Schedule G-1.2 (Regular Payroll by Category), the categories are union payroll,

15 non-union payroll, and total payroll.

16 • In Schedule G-1.3 (Payroll Capitalized vs. Expensed), the categories are payroll

17 expensed, payroll capitalized, other payroll, and total payroll.

18

19 Q. DESCRIBE SCHEDULE G-1.4 (PAYROLL BY COMPANY).

20 A. Schedule G-1.4 does not apply to EPE. Schedule G-1.4 asks for gross payroll

21 charged by the operator of a joint plant to other participants. While EPE owns a

22 portion of PVNGS and owned a Portion of the Four Corners Power Plant during a

23 portion of the Test Year, it was not the operator of .either plant and did not disburse

24 payroll to employees who work at those units. EPE- sold its interest in Four Corners

25 in July 2016.

26


647

1 Q. WHAT ,INFORMAT1ON IS IN SCHEDULES G-1:5 (NUMBER OF EMPLOYEES)

2 AND G-1.6 (PAYMENTS OTHER THAN STANDARD PAY)?

3 A. Both of these schedules provide employee information for each month in the Test

4 Year as well as the three most recent calendar years before the Test Year - 2013,

5 2014, and 2015.

6 • Schedule G-1.5 provides an employee count for full-time employees, part-time

7 employees, and total employees:

8 • Schedule G-1.6 reports all payments other than standard pay or overtime pay made

9 to. employees.

10

1,1 Q. HAS THE COMPANY MADE ANY PRO FORMA ADJUSTMENTS TO ITS

12 TEST-YEAR PAYROLL AMOUNT?

13 A. Yes. Salaries and wages requested in cost of service were annualized based on

14 payroll data'as of December 2016 and were adjusted to.reflect a 3% increase in non-

15 union salaries effective January 1, 2017. In addition, the portion of the annual bonus

16 related to financial incentives was removed frpm the requested cost of service.

17 Payroll taxes were calculated based on .the rates effective in 2017. In addition; the

18 payroll taies related to Four Corners were removed from the Companys request.

19 The payroll tax adjustments are reflected on Schedule G-9 and are caldulated in

20 Workpaper A-3, Adjustment No. 16: The payroll adjustments are reflected on

21 Schedule A-3 and are calculated, in Workpaper A-3, Adjustment No. 3.

22

23 X. CONCLUSION

24 Q. PLEASE STATE YOUR CONCLUSIONS.

25 A. The Companys per, books and Test Year federaí and state income tax amounts

26 found in the G17 schedules and included in the Company's requeted cost of service


648

1

and rate base are reasonable and necessary and calculated in accordance with

2

PURA and the Commission's Substantive Rules. The Company's income tax

3

calculation includes amortization, of the deficiency in state ADIT using a 15-year

4

amortization as approved in the Final Order for PUCT Docket No. 44941.

5

Additionally, the amounts of the Companys taxes other than income fiiund in the G-9

6

schedules arid included in the Companys requested cost of service are also

7

reasonable and necessary and calculated in accordance with applicable law. The

8

G-1 schedules accurately reflect the Test Year payroll amounts including the'

9 proforma salary and wage and payroll tax adjustments reflected on Schedule A-3.

10

11 Q. DOES THIS CONCLUDEYQUR TESTIMONY?

12 A. Yes, it does.


649

...

Exhibit CSP-1 Page 1 of 2

SCHEDULES SPONSORED BY C. PRIETO

Schedule Description Sponsorship

G-1 PAYROLL INFORMATION Sponsor

G-1.1 REGULAR AND_OVERTIME PAYROLL Sponsor

G-1.2 REGULAR PAYROLL BY CATEGORY Sponsdr

G-1.3 PAYROLL CAPITALIZED VS. EXPENSED Sponsor

G-1.4 PAYROLL BY COMPANY Sponsor

G-1.5 NUMBER OF EMPLOYEES Sponsor

G-1.6 PAYMENTS OTHER THAN STANDARD PAY Sponsor

G-7.1 RECONCILIATION OF TY BOOK NET INCOME TO TAXABLE NET INCOME Sponsor

G-7.1a . RECONCILIATION OF TIMING DIFFERENCES Sponsor

G-7.2 PLANT ADJUSTMENTS Sponsor

G-7.3 CONSOLIDATED TAXES, Sponsor

G-7.3a CONSOLIDATION BENEFITS Sponsoi-

G-7.3b CONSOLIDATION / INTER-CORPORATE TAX ALLOCATION Sponsor

G-7.4 ADFIT . Sponsor

G-7.4a ADFIT - DESCRIPTION OF TIMING DIFFERENCES . Sponsor

G-7.4b ADJUSTMENTS TO ADFIT Sponsor

G-7.4c ADFIT AND ITC - PLANT ADJUSTMENTS & ALLOCATIONS Sponsor

G-7.4d ADFIT - RATE CASE EXPENSE Sponsor ,

G-7.5 ANALYSIS OF INVESTMENT TAX CREDITS Sponsor

G-7.5a UTILIZED Sponsor

G-7.5b GENERATED BUT NOT UTILIZED Sponsor

G-7.5c UTILIZED -.STAND ALONE BASIS Sponsor

G-7.5d INVESTMENT TAX CREDIT ELECTION Sponsor

G77.5e FERC ACCOUNT 255 BALANCE Sponsor

650

Exhibit CSP-1 Page 2 of 2

SCHEDULES SPONSORED BY C. PRIETO

G-7.6. ANALYSIS OF TYE FIT & REQUESTED FIT - TAX METHOD 2 Sponsor

0-7.6a ANALYSIS OF DEFERRED FIT . Sponsor

G-7.7 ANALYSIS OF ADDITIONAL DEPRECIATION REQUESTED Sponsor

G-7.8 ANALYSIS OF TYE FIT & REQUESTED FIT - TAX METHOD 1 Sponsor

G-7.9 AMORT OF PROTECTED AND UNPROTECTED EXCESS DEFERRED TAXES s Sponsor

G-7.9a ANALYSIS OF EXCESS DEFERRED TAXES BY TIMING DIFFERENCE Sponsor

G-7..9b RECONCILIATION OF EXCESS Sponsor

G-7.9c ANALYSIS OF RESERVE ACCOUNTING FOR EXCESS DEFERRED TAXES Sponsor

G-7.10 EFFECTS OF ACCOUNTING ORDER DEFERRALS Sponsor'

G-7.11 EFFECTS OF POST TEST YEAR ADJUSTMENT Sponsor

G-7.12 EFFECTS OF RATE MODERATION PLAN Sponsor

G-7.12a TREATMENT OF FIT AND ADF1T IN RATE MODERATION PLAN Sponsor

G-7.13 LIST OF FIT TESTIMONY , Sponsor

G-7: 13a HISTORY OF. TAX NORMALIZATION Sponsor

G-7.13b TAX ELECTIONS Sponsor

G-7.13c CHANGES IN ACCOUNTING FOR DEFERRED FIT -Sponsor

G=7.13d IRS AUDIT STATUS Sponsor

G-7.13e PRIVATE LETTER RULINGS Sponsor

G-7.13f METHOD OF ACCOUNTING FOR ADFIT RELATED TO NOL CARRYFORWARD Sponsor

G-9 TAXES OTHER THAN INCOME TAXES Sponsor

G-9.1 AD VALOREM TAXES &PLANT BALANCES Sponsor

651

DOCKET NO. 46831

APPLICATION OF EL PASO ELECTRIC COMPANY TO CHANbE RATES

PUE3LIC UTILITY COMMISSION OF TEXAS

DIRECT TESTIMONY

OF

DAVID C. HAWKINS

FOR


FEi3RUARY 2017

652

EXECUTIVE SUMMARY

David C. Hawkins is the Vice President—System Operations, Resource Planiiing and

Management for El Paso Electric Company (EPE"). He is responsible for all activities of

EPE's System Operations department, which is responsible for the, reliable, real time

operation of EPE's electric grid, and EPE's Resourde Planning and Management

department, which is responsible for daily and long-term wholesale power transactions;

contract negotiation, scheduling and accounting, and resouree modeling.

Mr. Hawkins presents an overview of EPE's system operations activities. He also

, summarizes the selection and regulatory approval of the two new generation units that are

requested for inclusion in rate base in this proceeding: Montana Power Station Units 3 and

4. He also explains that the addition of these two units have benefitted EPE's system as

expected. Mr: Hawkins also reviews the companys calculated imputed capacity charge that

should be assigned to two renewable generation purchased-power agreements.

DIRECT TESTIMONY OF DAVID C. HAWKINS

653

TABLE OF CONTENTS

SUBJECT PAGE



III. NEW EPE GENERATION FACIUTIES 5

IV. IMPUTED CAPACITY 1 1

EXHIBItS

DCH-1 — Schedu!e Sponsor List DCH-2 .--'CCN Order Docket No. 41763

DIRECT, TESTIMONY OF DAVID C. HAWKINS

654

1 I.. INTRODUCTION AND QUALIFICATIONS


3 A. My narne is David C. Hawkins, and my business address is- 100,N. Stanton Street,

4 El Paso, Texas 79901-1341.

5

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

7 A. I am employed by El Paso Electric ,Company ("EPE" or the "Company") as

8 Vice President—System Operations, Resource Planning and Management.'

9

10 Q. PLEASE DISCUSS YOUR EDUCATIONAL AND PROFESSIONAL BACKGROUND.

11 A. I graduated from New Mexico State University with a Bachelor of Science degree in

12 Electrical Engineering in 1993 and a Master of Science degree in Electrical

13 Engineering in 1994. Upon graduation," I v;ias employed by West Texas Utilities

14 Company in- Abilene, Texas, as à Power Marketing Engineer until July 1996. In

15 August 1996, I began working for Public Service Company of New Mexico as a

16 Power Marketing Analyst where my job duties' included analysis of the wholesale

17 ,, • power market, and economic evalue,tion of wholesale transactions.

18 In April 2002, I began Working for EPE as a Pre-scheduler, where my duties

19 included optimization of EPE's generation' dispatch through wholesale power

20 transactions, daily and monthly natural gas procurement estimates, and regulatory

21 compliance. In October 2004, I was promoted to Supervisor of Resource

22 Management. Resource Management is responsible for daily and long-term

23 wholesale power transactions, contract negOtiation, scheduling and accounting, and

24. running ,PROMOD cases for financial planning. In March 2006, the responsibility of

.25 fuels planning and procurement for EPE's generating units was incorporated into

26 Resdurce Management. , In November 2007, I was promoted to Manager of

• 1,

DIRECT TESTIMONY OF DAVID C. HAWKINS

655

1 Long-Term Trading and Fuels. The section responsibilities include wholesale power

2 transactions, fuel supply planning and procurement, and development of PROMOD

3 for financial planning and regulatory filings. In February 2010, I was promoted to

4 DireCtor of Energy Trading, where my additional responsibilities included oversight of

5 the Company's real-time marketing operation.

6 In October 2011, I was laterally moved to Power Generation as

7 Director-Generation Operations, where I supervised EPEis local generating plant

8 operations and maintenance. In April 2013, I was promoted to Vice President-

9 Power Marketing & Fuels and Resource Delivery Planning where I oversaw the long

10 term planning of new generation resources as well as those previously mentioned

11 throughout my time serving as Director of Energy Trading. In June, 2014, I was

12 promoted to Vice President—System Operations,, Resource Planning and

13 Management where l'have retained the job functions of my previous position, and, in

14 addition, I oversee the System Operations department which is responsible for the

15 reliable, real time Operation of EPE's electric grid.

16

17 Q. HAVE YOU PREVIOUSLY PRESENTED TESTIMONY BEFORE ANY

18 REGULATORY AGENCY?

19 A. Yes. I have provided testimony before the Public Utility Commission of Texas (PUCT"

20 or "Commission") as well as the New Mexico Public Regulation Commission

21 (NMPRC").

22

23 II. PURPOSE OF 'TESTIMONY

24 Q. WHAT IS`THE PURPOSE OF YOUR TESTIMONY?

25 A. The purpose of my testimony i to present an overview of EPE's system operations

26 activities, such that EPE can meet its load serving responsibilities. I also describe

2 DIRECT TESTIMONY OF DAVID C. HAWKINS

656

1 the selecticin, regulatory approval; and the benefits of the two new generating units

2 added to EPE's fleet since EPE's rate case filed in 2015. Last, I also present EPE's

A

3 proposal concerning the Value of capacity that should be imputed based on two long

4 term renewable energy contracts.

5

6 Q. WHAT EXHIBITS AND SCHEDULES DO YOU SPONSOR?

7 A. The exhibits that I sponsOr are identified in the Table of Contents of my testimony.

8 The schedüles that I sponsor or co7sponsor are identified in Exhibit DCH-1.

9

10 Q. - WERE THE SCHEDULES AND EXHIBITS THAT YOU SPONSOR 'OR

11 CO-SPONSOR PREPARED BY YOU OR UNDER YOUR SUPERVISION?


13

14 III. , SYSTEM OPERATIONS OVERVIEW

15 Q. PLEASE PROVIDE AN OVERVIEW OF EPE'S LOAD SERVING RESPONSIBILITIES.

16 A. From an operational standpoint, EPE monitors its resource and transmission system

17 to ensure that the system load obligations can be rnet on. a real time basis. This

18 means EPE's generation must prbvide dynamic response to system changes in load,

19 frequency, and voltage. In addition, EPE must have sufficient re'sources to meet

20 daily peak load and load profile requirements, as well as have sufficient reserves for

21 a resource or transmission contingency.

22 114.

23 Q. DOES EPE HAVE SIGNIFICANT LOAD SERVING RESPONSIBILITIES OUTSIDE

24 OF THE SUMMER PEAK PERIOD?

25 A. Yes. EPE is a summer peaking utility, so demand is "much higher in the sumrner

• 26 relative to .other times of the year. However the dynamic resrionse of resources to


657

1 system reliability remains a 24 hour, year round obligation. As EPE witness

2 Andres R. Ramirez describes in his testimony, EPE's generation mix is composed of

3 base load, load following and peaking units which provide system operational

benefits during all seasons.

5

6 Q. HOW DO PEAKING GENERATION RESOURCES PROVIDE AN OPERATIONAL

7 BENEFIT OUTSIDE OF THE SUMMER MONTHS?

8 ' A. The term peak, or peak load, for long-term resource planning, typically refers to an

9 annual projected maximum hourly load usage. However, from an operational

10 perspective, every day has an hour in which there is a maximum daily energy usage,

11 which is the peak load of that day. Peaking resources can be used outside of the

12 summer months to meet each day's peak load requirements, particularly in the winter

13 months, as can be seen in the capacity factor characteristics in Schedule H-12.3a.

14

15 Q. WHY DO EPE'S PEAKING RESOURCES PROVIDE A PARTICULAR BENEFIT IN

16 THE WINTER MONTHS?

17 A. EPE'S peaking resources benefit EPE's system in the winter months and are

18 particularly useful during that season, in managing the impact of solar resources,

19 large scale and residential, on EPE's system. EPE's peak energy usage in the

20 winter months typically occurs in the evening. As the sun goes down, EPE loses

21 solar resource contributions to load and this loss is sequentially followed with an

22 increase in customer energy usage, which results in a relatively steep demand

23 increase. Peaking resources serve not only to replace the contribution from solar

24 generation, but to meet the additional energy usage of a typical winter evening. In

25 addition, in the pre-dawn morning hours prior to the solar resources contribution,

26 and as customer energy usage begins to climb, ,EPE has utilized peaking generation


658

1 resources to meet increasing energy demand. As solar contribution increases as the

2 sun rises, EPE 'is Ale to reduce its peaking generation, primarily from its General

3 Electric LMS100 ("LMS100") generation units that EPE witness Ramirez describes,

4 due to their flexibility and dispatchability.

5

6 IN/. NEW EPE GENERATION FACILITIES

Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR TESTIMONY?

• 8 A. The purpose of this section of my testirridny is to provide planning and regulatory

9 backgrCund information on the two new, natural gas-fired generation units for which

10 EPE seeks rate base treatment in thg case: the Montana Power Station ("MPS")

11 Units 3 and 4, which are nomin'ally rated at 89 MegaWatts ("MW") each. Specifically,

12 I presenta brief overview of the selection of the units and the proceedings in which

13 EPE obtained CCN approval. EPE witness Ramirez explains the technical

14 information about these new units and supports the prudence of their construction

15 costs.

16

17 Q. WERE MPS UNITS 3 AND 4 PART OF ONE SELECTION PkOCESS?

18 A. Yes, in fact MPS Units- 1 - 4 resulted from the same planning and selection process.

19 However, EPE deliyed requesting Certificate of Convenience and Necessity (CCN")

20 authorization for MPS Units 3 ahd 4 until a later date. Thus, they were subject to a

21 later proceedirt before the Commission than the CCN prbceeding for Units .1 and 2.

22 In simple terms, the process EPE followed to select the MPS Units began

23 with a determination that additional capacity resources were needed based on its

24 load forecasts and planning reserve margin criteria. Then EPE issued a request for

25 proposals ("RFP") to acquire those resources and was assisted by an independent

26 monitor or evaluator in analyzing the bid proposals. EPE then obtained CCN


659'

1 approvals for the new generation projeds from both the Commission and the

2 NMPRC.

3

4 Q. HAVE EPE'S NEWEST GENERATION ADDITIONS SERVED TO BENEFIT THE _

5 OPERATION OF EPE'S SYSTEM?

6 A. Yes they have. As witness Ramirez addresses in his testimony, apart from Copper

7 Power Plaht, Rio Grande Power Plant Unit 9, and the MPS Units 1 through 4, EPE's

8 local generation fleet was originally designed for base-load generation. But now the

9 older local gas-fired generating units operate as intermediate or load following duty

10 units. These g6s-fired units were nOt meant for cycling during summer peak loads

11

and, therefore; that type of operation would ,increase wear and tear on the units,

12 shorten their lives, and have a negative impact on unit reliability. Gas turbines,

13 particularly Rio Grande Unit 9 and the MPS-Units which -are LMS100 units, can be.

14 cycled daily and have a faster response to system changes, and they have reduced '

15 the load following and Cycling impact on EPE's other gas-fired generation.

16 , Additionally, the LMS100 units are more efficient unifs as compared to EPE's -„

17 conventional stea' m turbines, as shown by comparison of their heat rates" in'

18 Schedule H-12.3a. As the LMS100 resources are dispatched, offsetting productiOn

19 from EPErs older and less efficient generators, fuel savings are incurred.

20 '

21 MPS Units 3 and 4

22 Q. DESCRIBE IN GENERAL THE PROCESS FOR SELECTING MPS UNITS 3 AND 4.

23 A. As I mentioned above, MPS Units 3 and 4 resulted from the same planning and RFP

24 process.

25 EPE's 2011 annual planning process indicated that EPE would need additional

26 peaking capacity beginning in 2014 and increasing thereafter. To meet this need for

6 , DIRECT TESTIMONY OF DAVID C. HAWKINS

660

1 additional resources, EPE issued an RFP ih June 2011, once again being assisted by

2 an independent evaluator to oversee the- process. After all the bid proposals were

3 analyzed, the optimal resource was a combination of two bids—a solar purchased

4 power agreement from a facility located in Luna County, New Mexico (Macho Springs),

and an EPE self-build proposal for four LMS100 units to be built in phases and located

6 east of the City of El Paso on a new power plant site—the MP."' These four neW

7 self-build units would be called MPS Units 1, 2, 3, and 4.

8

9 Q. YOU MENTIONED FOUR MPS GENERATION UNITS. WHICH OF THOSE FOUR

10 UNITS ARE WITHIN THE SCOPE OF THIS RATE CASE?

11 A. Only MPS Uriits 3•and 4 are within the scope' of this rate case. _These two units have

12 been conštructed and entered service within the Test Year, and as EPE' witness

13 ,Ramirez explains, those two. units are used and useful. MPS Units 1 and 2 had

14 already been construciad and were included in rates in EPE's last rate proceeding,

15 Docket No. 44941.

16

17 Q. DID EIDE Gb ON 21-0 SECURE THE SOLAR PURCHASER POWER PROPOSAL

18 FOR THE FACILITY IN LUNA COUNTY, NEW MEXICO?

19 A. Yes. This is the Macho Springs Solar Facility. EPE negotiated and signed a

20 long-term power purchase agreement. I discuss the cbnsideration of the capacity

21 value for planning purposes from that purchase in'the next section of my testimony.

22

23 Q. . AFTER THE BID PROPOSAL FOR THE MPS UNITS WAS SELECTED, DID EPE

24 SEEK CCN APPROVAL FOR MPS UNITS 3 AND 4?

25 A. Yes, but as I mentioned- above, approval for 'these two units was not sought

26 immediately after selection. The reason that the request for CCN authority for MPS


661

Units 3 and 4 was delayed was that EPE.projected a need for MPS Units 1 and 2 in

2 the near future at the time, and the Company decided to limit its first request (Docket

3 No. 40301) to the first iwo units at the MPS site, in an effort to simplify the filing.

4 EPE did file for CCN approval of Units 1 and 2 in Texas in April 2012 in Docket

5 No. 40301. Ultimately, EPE and all the other parties to the case filed a settlement

6 recommending that the CCN'request be granted. In its December 2012 order, the,

7 PUCT amended EPE's CCN to include MPS Units 1 and 2.

8

9 Q. WHEN DID EPE SEEK AND OBTAIN CCN APPROVAL OF MPS UNITS 3 AND 4?

10 A. MPS Units 3 and 4 were presented in and received CCN approval in Docket

11 No. 41763, which was filed on September 6, 2013. The Final Order granting

12 approval was i'ssued July 11, 2014, and is attached as my Exhibit DCH-2. The case

13 itself was contested, but the. Commission found that the selection procesš (Finding of

14 Fact No. 24) and the sèlection itself were reasonable (Conclusions of Law Nos. 7

15 and 8).

16

17 Q. DID EPE RECEIVE CCN ApPROVAL FOR THE NEW GENERATION UNITS FROM

18 THE NEW MEXICO COMMISSION?

19 A. Yes, it did. EPE made CCN appro'val filings before both the Commission and the

20 NMPRC. Both Commissions issued the requested CCN approvals.

• 21

22 Q. ABOVE YOU MENTIONED THAT THE INTENDED BENEFITS OF THE NEW

23 GENERATION UNITS HAVE MATERIAEIZED. PLEASE SUMMARIZE THESE

24 BENEFITS TO EPE AND ITS CUSTOMERS.

25 A. EPE and its customers are benefitting from these neW generation projects in ways ,

26 the CCN proceedings intended.

8 DIRECT TESTINIONY OF DAVID C. HAWKINS

662

1 First, these units help EPE cóntinue to provide reliable service by, for

2 eiample, helping EPE h6e the resources to meet load growth, reserve margin

3 needs and provide local voltage support.

4 Second, these two new generation units-help to continue to modernize EPE's

5 aging local generation fleet. Table D6-1-1 below lists EPE's local generating units

6 based on in-service dáte from earliest to most recent. The,table illustrates that out of

7 1,444 MW of local genertion capability, EPE has seven generating units comprising

8 726 MW of net generating capacity With an average of 48 years in service. EPE's

9 most recent reserve margin, planning document. (the Loads & Resources' or L&R

10 document) shows that EPE does not anficipate retiring any .of the identified

11 generating assets until the end of 2022, (Rio Grande Unit 7, Newman Power Station

12 Units 1 and 2), at which times these generating •units will have 60+ years in service,

13 well beyond their original planned life of 50 years.

14

15

16

17

18

19

20

21

22

23

24

25

26


663


1

Table DCH-1

Age in years as of 2016 Unit Name

In-Service Date

Net Dependable

Capacity (MW)

Cumulative Capacity .of this and all units above

this unit

Average Cumulative age of this

and all units above ttii

unit OLDER LOCAL UNITS

58 Rio Grande 7 06/1958 46 46 , 58

56 Newman 1 05/1960 74 120 '57

53 Newman 2 06/1963 76 196 55.67

50 Newman 3 03/1966 97 293 54.25

44 Rio Graride 8 07/1972 :142 435 52.2 -

41 Newman 4 06/1975 227 662 50.3

36 Copper 07/1980 64 726 48.29

NEWER LOCAL UNITS

7 Newman 5 (Phase 1)

05/2009 140

5 Newman 5 . (Phase 2)

04/2011 138

3 Rio'Grande 9 05/2013 88

1 MPS 1 03/2015 88,

1 MPS 2 03/2015 88

0 MPS 3 05/2016 89

0 MPS 4 09/2016 89 1446

22 Third, the two new units unquestionably bring fuel and efficiency tenefits

23 through their lower heat rates, which EPE witness Ramirez describes in his

24 testimony.

25 Last, the new LMS100 units (MPS Units 3 and 4) continue to add operational

26 flexibility to EPE's fleet that was not achievable with the older units. These new

664,

2

3

4

5

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

LMS100 uriits. operate as peaking and intermediate duty units. Moreover, unlike

2 EPE's older units, the LMS100 units can come on-line and be at, full load within ten

3 minutes and ,can be ramped up and down as needed: EPE's load 'can change

4 dramatically from day-to-day, and the LMS100 units will allow EPE to more efficiently

5 meet those fluctuations as well as help meet its daily peak demands. In contrast,

6 EPE's older generation unitS are not capable of performing this type of operation in

7 nearly as efficient a manner.

8

9 Q. ARE THE NEW MPS UNITS USED AND USEFUL?

10 A. Yes. Schedule H-12.3a shows during the t'ate year the extent at which MPS Units 1,

11 2, and 3 were relied on, as indicated by their respected capacity factors. In

12 particular, since their commercial operation dates, MPS Unit 3, which had an

13 average capacity factor of 44%, and MPS Unit 4 with a capacity factor of 46% have

14 both been used and useful. Although MPS 4 became commercial in September

15 2016, it is expected to be utilized in a similar manner as that of MI7S Units 1 through

16 3. The MPS Units are used.and useful.

17

18 V. IMPUTED CAPACITY

19 Q. IS EPE SEEKING TO INCLUDE PURCHASED POWER CAPACITY -COSTS IN

20 EPE'S COST OF ŠERVICE?

21 A. Yes. EPE is seeking to include capacity costs associated with two renewable energy

22 Purchased Power Agreements ("Solar PI5As") used to serve Texas customers. The •

23 first Solar PPA is * the Macho Springs 50 MW solar agreement which began

24 commercial operation in May 2014. The second Solar PPA is the Newmen 10 MW

25 solar agreement, whiCh began in December 2014. I develop the imputed capacity

11 DIRECT TESTIMONY OF, DAVID C. HAWKINS

665

1 costs associated with these contracts and EPE witness Jennifer I. Borden sponsors

2 the adjustment to reflect the revised costs ihcost of service.

3

4 Q. DO THE SOLAR PPAs INCLUDE SPECIFIED CAPACITY CHARGES?

5 A. No, they do not: However, in a past fuel reconciliation, PUCT Docket No. 41852,

6 which is the fuel reconciliation previous to the currently pending one, EPE imputed a

7 capacity charge associated with an energy-only PPA that served to meet EPE's

8 planning reserve criterion. Then, in bóth EPE's last rate case proceeding, Docket

9 No. 44941, and in the pending ,fuel, reconciliation, Docket No. 46308, EPE irnputed

10 capacity to both of these solar agreements I mention above. The Solar PPAs are

11 accounted for in EPE's Loads and Resources ("L&R") document, which s used to

12 calculate' EPE's planning reseeve margin.

13

14 Q. ARE THERE OTHER PPAs INCLUDED IN EPE'S CURRENT L&R WHICH

15 CONTRIBUTE TO EPE'S PLANNING RESERVE MARGIN?

16 A. Yes. Although these contracts are similar to the Solar PPAs in that they are included

17 in EPE's L&R, are renewablë, and are energy-only contracts, EPE is not seeking to

18 impute associated capacity charges to include in its Texas jurisdictional c9st of

19 service. EPE •included the full contract charges for these remaining PPAs without

20 dispute in PUCT Docket No. 41852 ahd are allocatetho the New Mexico judidiction,

21 as they were procured under the New Mexico Renewable Portfolio Standard. All of

22 the costs for these contracts are recoveredirom New Mexico customers through the

23 New Mexico fuel rebovery charge.

24

25 Q. WHAT IS THE IMPUTED CAPACITY AMOUNT FROM THE SOLAR ,PPAs EPE IS

26 SEEKING TO INCLUDE IN ITS COST OF,SERVICE?

12 DI'IRECT TESTIMONY OF DAVID C. HAWKINS

666 r

A. EPE is proposing the same methodology used in Docket No. 44941, however, EPE

2

is now using Test Year operational data, and EPE's current Federal Energy

3

Regulatory Cdmmission ("FERC") approved Open Access Transmission Tariff

4

("OATr) language td calculate the imputed capacity charge. The methodology to

5

calculatè the imputed capacity charge was previously based on the'projected energy

6

productiOn of the two solar projects 6ecause their Oommercial operation dates

7

occurred within the Test Year in Docket No. 44941. EPE is seeking to include a

8

capacity charge of $2.35/kW/Month for the Macho Springs PPA and a charge of

9

$2.33/kW/Month for the Newman PPA. These charges are based on the .WSPP

10 (formerly known aš Western Systems Power Pool) Agreement capacity rate of

11 $7.32/kW/Month, with adjustments made based on the intermittency of these two

12 resources.

13

14 Q. IS THIS THE SAME CAPACITY CHARGE THAT EPE USED FOR IMPUTED

15 CAPACITY FOR THESEIWO CONTRACT§ IN DOCKET NOS. 44941 AND 46308?

16 A. No. The imputed capacity charge is currently $2.05/kWMonth for the Macho Springs

17. PPA and $1.91/kW/Month for Newman PPA in Docket Nos. 44941 and 46308. If a

18 higher imputed capacity charge is approved in this case, the change will

19 proportionally reduce the associated energy thsts reflected in fuel and purchased

20 power expenses recovered through the Texas Fixed Fuel Factor once the new

21 imputed capacity charges go into effect. A

22

23 Q. HAS EPE RELIED ON A DIFFERENT METHODOLOGY THAN THAT USED IN

24 DOCKET NOS. 44941 AND 46308 TO CALCULATE THE IMPUTED CAPACITY

25 CHARGE?


667

1 A. Only to the extent that actual energy production data was used-instead of projected

2 data., While Docket No. 46308, the fuel reconciliation, is still pending, in Docket

3 No. 4494'1, no party challenged the-imputed capacity or the calculation methodology

4 EPE presented in the rate proceeding. The case was settled, however, without a

5 finding expressly addressing the imputed 'capacity charge.

6

7 Q. DID EPE REFERENCE A DIFFERENT CAPACITY CHARGE WHEN IMPUTING A

8 CAPACITY CHARGE IN PUCT DOCKET NO. 41852?

9 A. Yes, EPE Lised .an imputed capacity rate cif $7.56/kW/Month in PUCT Docket

10 No. 41852 for'a then existing PPA with ŠPS. This rate was based on SPS's

11 FERC-accepted cost of service rates, as reflected in Service Schedule Q of the

12 WSPP Agreernent. The two-providers associated with the Solar PPAs do not have

13 FERC-accepted cost of service capacity rates. As such, after EPE reviewed the

14 WSPP Agreement Service Schedule C, which is the service schedule for firm

15 capacity and energy transactions, EPE capped the capacity charge at

16 $7.32/kW/Month, -which is the general tapped capacity chkge under" the WSPP

17- Agreement that pplies to suppliers who do not' have a specific FERC approved

18 capacity rate.

19

20 Q. WHY bOES EPE REFER TO THE WSPP AGREEMENT WHEN DETERMINING AN

21 IMPUTED CAPACITY CHARGE?

22 A. In EPE's fuel reconciliation in PUCT Docket No. 26194, the Commission imputed a

23 capacity charge to a PPA that * had no explicit. capacity charge. The Commission

24 determined the WSPP price cap is reasonable and should be used for that purpose.

25

14-, DIRECT TESTIMONY OF DAVID C. HAWKINS

668 •

1 Q. IF THE COMMIS'SION DEtERMINED THAT THE WSPP PRICE CAP IS

2 REi?kSONABLE, WHY IS EPE IMPUTING A CAPACITY CHAR6E AT A LESSER

3 RATE?

4 A. The rates used by EPE in previous PUCT Dockets were associated with PPAs

5 having firm energy. By the very nature of the Solar PPAs, the output from •these

6 resources is intermittent. I am not aWare of the Commission having addressed the

7 methodology, or even a requirement, to impute capacity to a resource that is _

8 intermittent in its output. As such, EPE is using a lower imputed capacity charge to

9 reflect the appropriate level of dependable output that EPE can' rely on to meet its

10 jurisdictional load requirements. Additionally, the providers for each PPA have no

11 obligation to produce energy to meet EPE's peak load requirements. The obligations

12 of the providers are limited to an annual minimum total energy output, so

13 consequently the capacity associated with these renewable PPAs is of much lower

14 value.

15

16 Q. WHY WOULD EPE NOT USE AN IMPUTED CAPACITY CHARGE THAT

17 CORRELATES TO THE E?(PECTED RESOURCE OUTPUT USED IN ITS L&R?

18 A. EPE used an expected capacity factor of 70 percent for solar resources in,its L&R.

19 This value is approximate to butpLit verified by EPE over its peak load hour.

20 However, this capacity factor is representative of a solar facilitys output at one

21 specific hour of the year. There are other periods of the year in which EPE's monthly

22 peak load occurs at night and the output from solar facilities produce 0 MW. The Se

23 Solar PPAs are long-term agreements,, and the capacity associated with these

24 agreements is not comparable to a summer-only PPA or any firm energy agreement.'

25 , Intermittent generation requires additional ancillary services to maintain a

26 stable electric grid. These ancillary services include regulation and operating and

15 DIRECT TESTIMONY C* DAVID C. HAWKINS

669

supplemental reserves that should be deducted from any imputed . capacity value.-

2 For these reasons, the imputed capacity charge does not correlate to the expected

3 capacity factor.

4

5 Q. HOW Dlp EPE CALCULATE THE IMPpTED CAPACITY RATES FOR THE SOLAR-

6 PPAs?

A. EPE adjusted the imputed capacity charges to reflect the additional ancillary services

8 attributable to an intermittent resource. This adjustment is based on the

9 FERC-accepted ancillary service rates within EPE's OATT. Additionally, EPE made

10 adjustments to reflect the Test Year energy output associated with the Solar PPAs.

11

12 Q. WHAT WAS THE IMPUTED CAPACITY CHARGE AFTER ADJUSTING FOR

13 ANCILLARY SERVICE REQUIREMENTS?

14 A. The imputed capacity Charge .w'es $7.20/kW/Month after adjusting for the associated -

15 ancillary service schedules found in EPE's OATT. The applicable schedules are

16 Schedule 3 (Regulation and Frequency Response), Schedule 5 (Operating

17, Reserve-Spinning Reserve Service), and Schedule 6 (Operating

18 Reserve-Supplemental Reserve Service). The rate for each of these schedules is

19 $3.10/kW/Month. Schedule 3 requires 0.87 -percent of rated MW obligation, and

20 'Schedules 5 and 6 each requires 1.5 percent of rated MW obligation. Adjusting the

21 WSPP rate of $7.32/kW/Month, by the Combined Schedules 3, 5, and 6 obligations of

22 3.87 percent (i.e., -0.87% .+ 1.50% + 1.50%), multiplied by the rate of

23 $3.10/kW/month, the "net capacity rate" is $7.20/kW/Month (i.e., $7.32/kW/Month —

24 (.0387 X 3.10/0WMonth)).

25


670

1 Q. WHAT WERE THE FINAL IMPUTED CAPACITY CHARGES AFTER ADJUSTING

2 FOR THE ENERGY PRODUCTION OUTPUT?

3 A. EPE based the energy production.output component of the imputed 'capacity charge

4 on actual Test Year production. Macho Springs had a 32.6 percent energy

5 production output level, and Newman Solar had a 32.3 percent energy production

6 output. The final imputed capacity charges are the products of the "net capacity

7 rate".and the Test Year energy Output percentages. The resulting imputed capacity

8 charges are'$2.35/kW/Month for the Macho Springs PPA, and $2.33/kW/Month for

9 the Newman Solar PPA. EPE witness Borden adjusts the revenue requirements ,for

10 the total dollar amount in imputed capacity charges for each facility.

11

12 Q. DO YOU BELIEVE THIS IS A• PRUDENT VALUATION OF THE 'CAPACITY

13 COMPONENT OF THE SOLAR PPAs?

14 A. Yes, I do. Renewable resources such as those in the Solar PPAs require EPE's

15 local generation to resPond to the intermittency of such resources. Although energy

16 is expected from the Solar PPAs during the summer peak load hours, the output

17 from Solar PPAs is weather dependent and not guaranteed (for example, a storm in

. 18 Deming, New`Mexico, will -reduce the output of the Macho Springs facility, while

19 El Paso may be experiencing clear skies and a temperature of 100 degrees). The ,

20 primary value from the Solar PPAs is from the 'fuel that iS saved while these

21 resources are producing energy, not from capacity that can be utilized to respond to f

22 system contingencies. Therefore, I believe the imputed capacity charges as

23 determined recognize the Solar PPAs contribution to EPE's planning reserves, while

24 at the same time recognizing these resources are primarily energy resources given

25 their intermittency and contribution to serving loads throughout all hours Of the year.

26


671

t A CO 0 r:t 471 "1"

MI WI yr in

1 Q. DO YOU HAVE ANY SPECIFIC EXAMPLES OF SOLAR RESOURCES'

2 INTERMITTENCY DURING PERIODS OF HIGH NATIVE PEAK DEMAND?

3 A. Yes. On June 23, 2016 EPE's native peak demand reached 1,871 MW, surpassing

4 the previous year's native péak demand. Within that peak demand hour, EPE's large

5

scale utility,solar varied from 96 MW to'39 MW. This intermittency is demonstrated

6

in the following chart.

7

Y•8 EPE June 23, 2016 Over Peaki-161ur, Minute Data

9

10

11

12 ,

13

14

15

16

11-17/-,—"

1 I 11-

r I ••••••,-•

N

IA-, tn 01, v.4

I 7747, +1..!

I 1 , • tj •

2000 ; --1900 / 1800 1700 4--1600 1500 -"pi.- 1400 1300 1.—; I 1200 -7-1-

2 1100 l000

118 900 r 800 fij 700 600 4- 1- 500 ; - 400 300 200 1 .1;' 100

0 42,-1-1-1-1.. 0 .4 51 51 1.0tn U1 let

I . 1 i

•

,to co 0 1,1 tO (ri 11

1.11 t8 *I lfl 1.11 IA 01 •-• 1.4 e•I r.4 t-I

05 0 ,s1 tn to et ill LA 41 t.t; cl eg r4

00 o

c15 00 o

1;1 th tn rt /-1 4.4

-r 110

100

90

It 80

1, 70

60

SO

40

30 20

10

0

;

Load, MW — — —Solar, MW

17

18 Q. DOES THIS CONCLUDE YOUR TESTIMONY?

19 A. Yes; it dOes.


672

EXhibit DCH-1' 'Page 1 of 2

SCHEDULES SPONSORED BY D: HAWKINS

SChedule Description ' Sponsorship

E-2.1 FOSSILFUEL INVENTORY POLICIES Sponsor

E-2.2 FOSSIL FUEL INVENTORY EVALUATION Sponsor

E-2.5 FOSSIL FUEL INVENTORY VALUES Co-Sponsor

E-3.1 ' FUEL OIL BURNS Co-Sponsor

H-12.4a FIRM PURCHASED POWER (NET MWh)„ Sponsor

H-12.4b FIRM PURCHASED'POWER ENERGY COSTS - Sponsor ,

H-12.4c FIRM PURCHASED POWER FIXED COSTS Sponsor

H-12.4d FIRM PURCHASED POWER ENERGY COSTS PER MWh Sponsor

H-'12.4e NON-FIRM PURCHASED POWER (Net MWh) Sponsor

H-12.4f NON-FIRM PURCHASED POWER ENERGY COSTS ' Sponsor

H-12.4g NON-FIRM PURCHASED POWER ENERGY COSTS PER MWh .-

Sponsor

H-12.5b OFF SYSTEM SALES - ECONOMY AND FIRM (NET MWh) Sponsor

H-12.5c OFF SYSTEM SALES REVENUE (ENERGY CHARGE COMPONENT)

Sponsor

H-12.5d OFF SYSTEM SALES REVENUE (FIXED CHARGE COMPONENT)

Sponsor

H-12.5e OFF SYSTEM SALES REVENUE (ENERGY CHARGE PER KWh)

Sponsor

1-1A NON-RECURRING FUEL AND PURCHASED POWER ' EXpENSES Co-Sponsor

1-2 . FUEL AND PURCHASED POWER PROCUREMENT PRACTICES ' Sponsor

1-3 FUEL AND PURCHASED POWER COMMITTEES Co-Sponsor

1-4 FUEL AND FUEL-RELATED CONTRACTS . Sponsor

1-6 NATURAL GAS DELIVERY SYSTEM ,

Sponsor

1-7 NATURAL GAS STORAGE DESCRIPTION Sponsor

1-8 FUEL PROPERTIES Sponsor

673

SCHEbULES SPONSORED BY D. HAWKINS

Exhibit DCH-1 Page 2 of 2

Schedule Description Sponsorship

1-9 EMPLOYEE ORGANIZATIONAL CHARTS Sponsor

1-10 EMPLOYEE ETHICS Sponsor

1-11 FUEL AND PURCHASED POWER ASSUMPTIONS NARRATIVE '

Sponsor

1-12 - FOSSIL FUEL MIX Sponsor

1-13 ETHICS - RELATIONSHIP WITH FUEL SUPPLIER Sponsor

1-15 FUEL CONTRACT ANALYSES - RECONCILIATION PERIOD

Sponsor

1-16.1 FOSSIL FUEL MIX (BURNED) (NA-fuel rec) Co-Sponsor

1-16.2 FOSSIL FUEL MIX (PURCHASED) (NA-fUel rec). Co-Sponsor

- . 1 16 3 COMPETITIVE SPOT FOSSIL FUEL PURCHASES (NA- fuel rec)

Co-Sponsor

1-16.4 OTHER SPOT FOSSIL FUEL PURCHASES Sponsor

1-17.1 COAL COST BREAKDOWN Co-Sponsor

1-17.2 LIGNITE COST BREAKDOWN Sponsor

1-17.3 COAL COST DESCRIPTION Sponsor

1-18 COAL AND LIGNITE SUPPLIER LOCATIONS Sponsor

1-19.1 RAIL HAUL DISTANCE .

Sponsor

1-19.2 UNIT TRAINS Sponsor

1-19.3 CYCLE TIME Sponsor

1-19.4 RAIL CARS Sponsor

1-19.5 RAIL CAR LEASES Sponsor

1-19.6 RAIL CAR MAINTENANCE Sponsor

1-19.7 RAIL CAR REPAIRS Sponsor

1-21 FUEL' MANAGEMENT Sponsor

674

Exhibit DCI-1-2 Page 1 of 13 .

4 jilz , PUC DOCKET NO. 41763 , /

SOAII DOCKET NO. 473-14-1419 2 1 ' " 39

e-l.Geir • APPLICATIoN OF EL PASO § PUBLIC UTILITY COMMISSION ELECTRIC COMPANY TO AMEND ITS § CERTIFICATE OF CONVENIENCE § OF TEXAS AND NECESSITY FOR TWCO ADDITIONAL GENERATING UNITS § AT THE MONTANA POWER STATION § IN EL PASO COUNTY

ORDER

This Order addresses the application of El Paso Electric Company to amenkl its certificate

of convenience and necessity for two additional generating units at the Montana power station in

El Paso County. On June 5, 2014, the administrative law itidge at the State Office of

Administrative Hearings issued a proposal for decision finding that EPE established a need for

additional "capacity and recommending that the Public Utility Commission of Texas approve the

appliCation. The CoMmission agrees that the utility met its burden ti) establish need and that the

application should be Oproved. The Commission adopts the following findings of fact ind

conclusions of law:

I. Finding; of Fact

Procedural History

1. El Paso Electric (EPE) is an investor-owned electric utility providing retail electric

service in Texas under certificate of convenience and necessity (CCN) No. 30050.

2. On September 6, 2013, EPE filed with the Commission an application for CCN

authorization to build and operate-two additional 88 megawatt (MW) natural gas-fired

generating units, Montana units 3 and 4. The site for the proposed units is the Montana

power.station, in EPE's service area in eastern El Paso County, just east of the city of El

Paso.

12. 675


MC Docket NO. 41763 Order Page 2 of 13 SOAR Docket No. 473-14-1419

3. EPE published notice of the application on September 13, 2013 in the El Paso Times, a

newspaper having general circulation in EPE's Texas jurisdictional service territory.

4. On September 6, 2013, EPE delivered direct notice of the application to the city 'of

El Paso and the county of El Paso and mailed notice of the filing to all parties in EPE's

most recent base rate case, Application of El Paso Electric Company to Change Rates

and to Reconcile Fuel Costs, Docket No. 40094 (May 23, 2012).

5. On September 6, 2013, EPE mailed a complete copy of the filing, including the

environmental assessment studies (minus some of ihe appendices of one of the studies) to

the Texas Parks and Wildlife Department (TPWD). On September 24, 2013, EPE mailed

a complete copy of all three environmental assessrnents (including all the appendices) to

TPWD.

6. On September 25, 2013, EPE filed proof that, notice of this proceeding had been

provided.

7. The city of El Paso, Texas Industrial Energy Consumers, Rockney Bacchus, the Far East

El Paso Citizens United, and the county of El Paso filed requests to intervene and were

granted intervener status in this matter.

8. The Far East El Paso Citizens United and the county of El Paso requested to withdraw

their interventions, and the requestSvere granted.

9. TPWD did not seek intervention in this docket. TPWD filed comments in this docket on

October 30, 2013, but the comments were not offered or admitted into evidence.

10. On December 17, 2013, the Commission referred this docket to the State Office of

Administrative Hearings (SOAH) for assignment of an administrative law judge to

conduct a hearing and issue a proposal for decision, if necessary.

11. On January 9, 2014, the Commission isaued the preliminary order in this matter. The

- preliminary order identified the issues to be addressed by SOAH.

12. The hearing on the merits was held on February 19, 20, and 21, 2014.

13. The record closed on April 15, 2014, with the filing of reply briefs.

676


PUC Docket No. 41763 Order Page 3 of 13 SOAR Docket No. 473-14-1419

BackEround on EPE

14. EPE serVes retail customers in Texas and New Mexico, where it is subject to the

jurisdiction of the New Mexico Public Regulation Commission.

15. Retail competition has not been implemented in EPE's service area., As a result, EPE

contiiiues to provide bundled, regulated service to its Texas customers.

16. EPE's 2011 annual planning process indicated that, based on its load forecasts, expected

generating unit retirements, and reserve margin criteria; EPE would need additional

peaking capacity beginning in 2014 and would be faced with an increasing need for

capacity thereafter.

17. To meet this need for additional resources, EPE issued a request for proposals (RFP) in

June 2011, seeking 80 to 100 MW in 2014., 80 to 100 MW in 2015, and 160 to 200 MW

in 2016.

18. EPE retained Wayne Oliver, of the Merrimack Energy Group, Inc., as independent

evaluator to oversee EPE's RFP process by monitoring the bid evaluation and selection

process.

19. In response to its RFO, EPE i-eceived 38 proposals from 23 different companies.

20. Of the 38 proposals, five were solar-powered, 19 were gas-fired, four were wind-N.' wered

and 10 were demand-side or used power-storage technology.

21. EPE's generation projects group submitted eight self-build options.

22. EPE, during the RFP process, treated the. generation projects group as a different entity

• and did not communicate with them.

23. EPE and Mr. OliVer evaluated the bids and detennined that the optimal resource was a

combination of two bids—a solar purchased power agreement and one of EPE's self-

build propoials.

24. The RFP process that EPE undertook was reasonable.

25. - The EPE self-build proposal consisted of four General Electric (GE) LMS100 units to be

built in phases alid located east of the city of El Paso. on a new power plant site, the

Montana power station.

677 ,

PM Docket No. 41763 Order SOAR Docket No. 473-14-1419

Exhibit DCF-I-2 Page 4 of 13

Page 4 of 13

26. EPE ieceived CCN authorization for the first twO of these four Montana units—Montana ,

units 1 and 2—in December 2612 in:Application of El Paso Electrie Company to Amend

'Its Certificate of Convenience and Necessity for Generating units Montana 1 and 2 at the

Montana Site in Texas, Docket No. 40301 (Dec. 13, 2012).

27. Montana units 3 and 4 are expected to be added in 2016 and 2017, respectively.

28. EPE's recent 2013 load forecast continues to confirm-the need for Montana units 3 and 4.

Description of Montana Units 3 and 4

29. Montana units 3 and 4 will each consist of a GE LMS100 simple-cycle, aern-derivative

combustion turbine that will be fueled by natural gas, with the capability to burn fu61 oil

as their secondary fiiel source.

30. Montana units 3 ande4 will be the same size as, use the same technology as, and will be

built at the same site as Montana units 1 and 2.

31. The relatively high elevation (approximately 4,020) and high temperatures in the area

will affect the performance of the units, compared to their Performance if located at sea

level and under other International Organization for Standardization (ISO) site reference

Cmiditions (which are sea level elevatidn, temperature of 59 degrees Fahrenheit and 60%

relative humidity). Thus, although it would have a nameplate rating of 103 MW at ISO

conditions, each unit will deliver 88 MW het to EPE under summer peak conditions.

32. The high elevation in the area also means that the units heat rate' will be higher than it

would be at'ISO conditions.

33. The units' guaranteed full load heat rate is 9,074 British thermal units per kilowatt-hour,

with a themial efficiency ranging from 44% to 50%.

34. The units' relatively low heat rate compared to -the average heat rate of EPE's other

gas-fired generating tinits will result in fuel savings for EPE's customers.

35. The units will be used for peaking service and also intermediate serviCe and are expected

to operate at approximately a 40% capacity factor.

36. The units will be quick start units because they can be brought on-line within three

minutes and reach full load within 10 minutes.

678


MC Docket No. 41763 Order Page 5 of 13 SOAH Docket No. 473-14-1419

37. There is no limit on the units number of starts or on its minimum off-line or on-line time.

38. 'The units can be ramped up and down as needed (for example, they can be shut down

during off-peak hours) without negatively impacting maintenance costs.

39. Evaporative coolers will be used to cool the combustion turbine—inlet air for maximum

operating efficiency.

40. No other existing EPE operating generation unit (except Rio 'Grande unit 9, an LMS100

generating unit) has this combination of features.

41. EPE's system will also benefit from4the Units by the additional voltage support, an

additional type of contingency reserves, and additional flexibility in scheduling

maintenance outages.

42. Montana units 3 and 4 are expected to be operational by the summer peaks of 2016 and

2017, respectively.

43. , No other utility is or will be directly served by or connected to the proposed facilities or

involved in their construction.

44. The total estimated cash capital cost of the units is $151.2 million.

45. The estimated amount of allowance for fimds used during construction is $17.9 million,

for an overall estimated total cost of $169.1 million.

Stanitorv CCN Factors Adequacy of F41stine Service/Need for Additional Service

46. For reliability reasons, EPE needs the additional 'resources that .Montana units 3 and 4

will provide, and EPE's system will benefit from the units' operational features.

47. Through its 2011 RFP process, EPE prOperly considered and rejected alternatives to

Montana units 3 and 4.

48. As a member of the Western Electricity Coordinating Council (WECC), EPE maintains a

15% annual reserve margin, an amount of firm supply-side resources in excess of its firm

demand.

49: Although WECC does not require utilities to maintain a specific annual margin level,

EPE's 15% annual reserve margin is reasonable considering EPE's location on the grid.

679


PUC Docket No. 41763 Order Page 6 of 13 SOAH Docket No. 473-14-1419

50. EPE will hal'ie a capacity deficit starting in 2016. In 2018, the' deficit will grow to an

amount greater than the 176' MW output from Montana units 3 and 4, which EPE

proposes to build in_this proceeding.

51. EPE's need for additional capacity cannot be. significantly addressed by delaying the

retirement of Four Corners units 4 and 5 and Rio Grande unit 6.

52. EPE's need for additional capacity - cannot be significantly resolved by importing

purchased power because EPE's remote transmission system is being used to the

maximum extent feasible.

53. EPE's need, for additional capacity is greater than the amount of interruptible capacity on

its system.

54. EPE cannot replace its need for capacity solely with renewable resources.

55. Expanded energy efficiency programs could not meet EPE's projected need for peaking

and intermediate capacity.

The Effect of Grantine the CCN on EPE and Any Electric Utility SerYinzthe ProxintoteArea

56. There will be a two-fold effect on EPE in granting the CCN authorization for Montana

units 3 and 4—financial and operational.

57. The financial impact on EPE of Montana units 3 and 4 will be minimal. The construction

costs will be financed with cash geherated from operations or debt or a combination of

the two.

58. The financing will not impair EPE's ability to attract additional capital on reasonable

terms and at reasonable prices.

59. Operationally, the effect on EPE of granting the CCN willbe positive.

60. Montana uniis 3 and 4 will enhance EPE's ability to provide reliable service, since the

generating units are needed to meet customers' demand and EPE's reserve margin

criteria.

680


PUC Docket No. 41763 Order Page 7 of 13 SOAH Docket No'. 473-14-1419

61. The effect will also be positive from a systeni and transmission perspective. With the

addition orlocal generation in Montana units 3 and 4,:EPE will receive flexibility in

scheduling maintenance outages and voltage support in the local system.

62. Montana units 3 and 4 will provide voltage support in EPE's local system, an additional

type of contingency reserves, and additional flexibility in scheduling maintenance

outages.

63. Montana units 3 and 4 will not be located in the certificated service area of any other

utility.

64. There will be no adverse effects on any other electric Utility.:

Community Values

65. When EPE selected the Montana power station site, it was undeveloped, open -desert

scrubland, which people have used as a dumping gound.

66. The Montana site is surrounded by a mixture of different developments: indukrial

(Magellan fuel farm), commercial (mostly automotive salvage yards), military

development (U.S. Anny—Fort Bliss), but with very little residential development.

67. The Montana site is bounded on the north by Fort Bliss. An indukrial facility, the

Magellan oil storage/transfer facility is located adjacent, to the south of the proposed

Montana units 1 and 2. The southernmost portion of the site' is bounded by Montana

Avenue (State Highway 62/180).

68. There are go ,Tesidents on-site, and no signifiCant populations are anticipated in the near

future.

69. There is some residential development near the western boundarY of the Montana site,

where residential areas are located approximately one quarter of a mile to the west of the

units.

70. By the time they are constructed, Möntana units 3 and 4 will be. located on an existing

Power plant site.

71. The location of the units iS approximately 1,200 feet from the nearest residential

structures.

•-;

681 ."


PVC Docket No. 41763 Order Page 8 of 13 SOAR Docket No. 473-14-1419

72. Existing development in the area will be minimally affected by the addition of the units.

73. While the Montana units -3 and 4 will create an incremental amount of noise, they are not

likely to significantly impact the closest noise receiver.

74. The units and associated access route are located in a rural area of El Paso County.

Residences in the area are sparse and are located on large lots (gieater than 0.75 acres),

and the residential structures are some distance (1,200 feet or more) from the proposed

units.

75. During construction, noise levels may increase, but this activity will be only temporary.

Additionally, the new units are not expected to operate continuously.

76. The units employ newer technology, and the design incorporates sound reduction features

to protect workers. These aspects result in less noise at the site bnundaries.

77. To a large extent, the incremental noise produced by the construction and operation of the

units will likely 'not stand out given the existing background noise from the existing

development, including roads, in this area.

78. The effect on community values will be minimal.

Recreational and Park Areas

79. There are no parks or recreational areas within one-half mile of the units. -

80. Because there are no recreational or park areas in proximity to the proposed units, there

will be no adverse effect on any recreational or park areas.

Historical and Aesthetic Values

81. By the time they are constructed, Montana units 3 and 4 will be located on an existing

power plant site.

82. The site of the units is an undeveloped desert scrubland.

83. No areas listed on the National Register of Historic places in Texas are located in

proximity to the units.

84. Any effect -on historical or aesthetic values will be minimal.

682

Exhibit DCH-2

PUc Page 9 of 13

Doeiet No. 41763 Order Page 9 of 13 SOME bocket No. 473-14-1419

Environmental Integrity

85. By the time they are constructed, Montana units 3 and 4 will be located on an existing

power plant site.

86. The Montana Units 3 and 4 fall under the jurisdiction of the Texas Commission on

Environmental Quality (TCEQ); and the U.S. Environmental .Protection Agency (EPA)

has authority over some of the permitting aspects.

87. Various types of environmental ilerrnits, including air quality permits, must be obtained

from the TCEQ or EPA.

88. The environmental permitting regime, to which the units are 'and will be subject, along

with EPE's compliance with those permits, will help ensure the environmental integrity

of the surrounding area.

89. The units design will reduce the area of influence of potential environmental impacts

from emissions. In addition, mandatory compliance with the environmental components

of •those permits issued by state and federal agencies will help ensure that the

environmental integrity of the surrounding area is retained.

90. Montana units 3 and 4 will be equipped with emissions technology that is considered best

available control technology.

91. The city *Of El Paso Water Utilities/Public Service Board has agreed to provide water for

the units.

92. Montana units 3 and 4 are expected to have at most a minimal impiact on the

environmental integrity of the area.

Probable Imarovement of Service or Lowerini of Cost to Consumers itt Area if CCN is Granted

93. The capacity that will be proVided by Montana units 3 and 4 will improve electric service

because of the reliability and operational flexibility they will add to EPEs system, their

relatively lower heat rate within EPE's system, and their contribution to meeting EPE's

reserve margin needs.

683


PUC Docket No. 41763 Order Page 10 of 13 SOAH Docket No. 473-14-1419,

= 94. In addition, EPE's transinission system will benefit because the new units can be 'started

to provide voltage support for the eastern Tart of the EPE high-voltage system during

normal conditions or during transmission outages.

95. A PROMOD operating simulation tO calculate the impact of Montana units 3 and 4 on

annual fuel cbsts estimated that fuel ciists would decline approximately $2.3 million in

the first ftill year of Operation for both units.

96. EPE predicted that the cost irnpact of the new generation units, considering the

combination of both base rates and fuel, would be $1.77 or a 2.41% increase in rates for

an average Texas residential customer using 600 lcilowatt-hours per month, for the first

year of operation.

To Extent Applicable, Effect of Grantinz CCN on Abiliti of this State to Meet PURA Goal for Addinz Renewable Energy Resources in § 39.904(a)

97. This statutory factor is not directly applicable because this- application does nen include

renewable generating facilities. ,

98. Becausé of the ability of the GE LMS100 units to ramp up and down easily, however, the

addition of Montana units 3 and 4 to EPE's fleet will accommodate the addition of

renewable energy resources.

Whether CCN Is Neceisary fot Service, Accommodation, Convenience, or Safetv of the Public under PURA 37.056

99. Considering all the above factors, EPE's requested CCN authorization to construct, own

and oPerate Montana units 3 and 4 is necessary for the service, accommodation,

convenience or safety of the public.

Effect ofCCN on Implementation of Customer Choice

100. Cnstonier choice has bben delayed in EPE's Texas service area.

101. Under Public Utility Regulatory Act (PURA), Texas Utilities Code §§ 11.001-66617, and

• § 39.553 and P.U.C: SUBST: R. 25.421, the timeline for implementation of retail

compefition in EPE's service territory is dependent upon completion of a five-stage

process; the first of which is development, approval and operation of a regional

transmission organization (RTO) for _the EPE region.


PUC Docket No. 41763 Order Page 11 of 13 SOAH Docket No. 47344-1419

102. No plan is in place to Ron or request FERC approval of an RTO, and EPE cannot

unilaterally form an RTO.

103. Approval of a CCN for the proposed generating units will not affect the development of

an RTO in which EPE could participate.

104. The approval of this CCN will also not affect any subsequent stage toward full retail

competition in EPE's service area.

11. Contlusions of Law

1. EPE is an electric utility as defined in § 31.002 of PURA.

2. The Commission has jurisdiction over the application pursuant to PURA §§ 14.001,

14.002, 37.051, 37.053, and 37.056.

3. SOAH has jurisdiction oVèr this proceeding, including the preparation of this proposal for

decision with findings of fact and conclusions of law, pursuant to PURA § 14.053 and

Texas Government Code §§ 2001.058 and 2003.049.

4. Notice of the' apPlication was provided in compliance with PURA § 37.054 and P.U.C.

PROC. R. 22.52(a).

5. This docket was processed in accordance with the requirements of PURA, the

Administrative Procedure Act, Texas Government Code Chapter 2001, and Commission

rules.

6. EPE has met its burden to show that it has a need for additional generation pursuant to

PURA § 37.056(c)(2).

-7. EPE has met its burden to show that the Montana Units 3 and 4 would improve service or

lower costs to retail customers pursuant to PURA § 37.056(U)(4)(e).

8. EPE is entitled to approval of its application because it demonstrated that the Montana

units 3 and 4 are necesSary for the service, accommodation, convenience, or safety of the

public within the meaning of PURA § 37.056(a), taking into consideration the factors Set

out in PURA § 37.056(c).


PUC Docket No. 41763 Order Page 12 oi 13 SOAH Docket No. 473-14-1419

III. Ordering Paragraphs

In accordance with these findings of fact and conclusions of law, the Commission issues

the following order:

1. EPE's application to amend its CCN No. 30050 to include Montana units 3 and 4 is

granted.

2. The rate recovery of the costs , of Montana units 3 and 4 was not considered and is not

determined in this docket.

3. EPE shall take reasonable and feasible precautions for the protection of state-listed

threatened species and rare or protected species.

4. EPE shall implement the following noise mitigation measures:

a. All construction equipment should be operated and maintained to minimize noise

generation, should be kept in good repair and fitted with "manufacturer

recommender mufflers.

b. Construction activities that 'may create noise and vibration exceeding the city of

El Paso chapter 9.40 noise standards shall not take place between the hours of

8 p.m. and 7 a.m. on weekdays and Saturdays, or-at any time on Sunday or a

holiday.

c. Portable noise screens or enclosures to provide shielding for high noise activities

or equipment should be used as necessary during c;nstruction.

d. Noisy operations during construction should be combined to occur in the same

period.

e. The measures to reduce adverse sound effects on the surrounding community

during operation of the facility that have been planned in the design of Mdntana

units 3 and 4 should be implemented, including silencers for both the gas turbines

air inlet's and exhaust 'stacks and_ containment of the major components of the

power turbine within an acoustical enclosure.

5. All other motions, requests for entry of specific fmdings of fact or conclusions of law,

and any other requests for general or specific relief, if not expressly granted, are denied.

DONNA L. NELSON, CHAIRMAN

NETH W. ANDERSON, JR., COMMISSIONER


PUC Docket No. 41763

Order Page 13 of 13 SOAR Docket No. 473-14-1419

SIGNED AT AUSTIN,NEXAS the fi day of July 2014.

PUBLIC UTILITY COMMISSION OF TEXAS

BRANDY D. MARJ, CO i!4 qAcadWorders\fma1141000\41763fo.ctocx

687

DOCKET NO. 46831

APPLICATION OF EL PASO ELECTRIC § PUBLIC UTILITY COMMISSION COMPANY TO CHANGE RATES § OF TEXAS

DIRECT TESTIMONY

OF

ANDRES R. RAMIREZ

FOR


FEBRUARY 2017

' 688

EXECUTIVE SUMMARY

Andres (Andy) R. Ramirez is the Vice President-Power Generation for El Paso

Electric Company ("EPE"). He is responsible for all activities of -EPE's Power Geperation-

Division, which includes power plant operations and maintenance, new plant construction,

and oversight management of EPE's interest in its remote generation (Palo Verde Nuclear

Generating Station).

Mr. Ramirez describes EPE's generation fleet and supports the recovery of.the costs

of new investments in that fleet and of the costs to Operate and maintain it. EPE's

generation fleet consists of its local units and the remote generation at Palo Verde.

Mr. Ramirez explains that as of July 2016, .EPE's generation fleet no longer contains its

interest in the Four Corners Power Plant.

Mr. Ramirez addresses the capital additions to EPE's local generation fleet, including

the two new generation units (the Montana Power Station Units 3 and 4), that EPE placed in"

service.from April 2015 ihrough September 2016. These capital additions were reasonable

and are used and useful.

In addition, Mr. Ramirez addresses the operation and maintenance expenses and

practices that EPE employs to manage its local generation, fleet, together with the level of

O&M expenses that should be included in rates.

Last, he supports the reasonableness of the capital additions placed in service at

Palo Verde from April 2015 through September 2016, together with the reasonableness of

the Palo Verde Test Year O&M expenses.

DIRECT TESTIMONY OF ANDRES R. RAMIREZ-

689

TABLE OF CONTENTS

SUBJECT PAGE



III. EPE'S GENERATING.FACILITIES 4

IV. EPE'S LOCAL GENERATION FLEET—CAPITAL ADDITIONS 7

A. MOS Units 3 and 4 8

B. Other Capital Additions to Local Generation Fleet 16

a. Plant Efficiency Improvement 21

b. Productivity Improvement 22

c. Reliability, 22

d. Habitability 22

V: EPE'S LOCAL GENERATION FLEET- OPERATION AND MAINTENANCE 23

A. Local Unit-General 23

B. Local Unit Maintenance 25

Ci LoCal Unit Performance 28

D. Local Generatiqn Fleet Non-Fuel O&M Costs andRate Request 32

VI. PALO VERDE 35

A. Overview of Palo Verde ......... 36

B. PVNGS Performance During the Test Year 37

C. PVNGS Cipital Monitoring and Approval Process of Capital Costs 37

D. PVNGS Capital Additions to Rate Base 40

E. PVNGS-O&M Expense 41

VII. CONCLUSION 43

EXHIBITS

ARR-1 — List of Schedules ARR-2A— Map of Local Generation ARR-2B — Map of Local Generation ARR-3 — Photo of Montana Units 3 and 4 ARR-4 — Photo of Montana Units 3 and 4 ARR-5 — Procurement Flowchart ARR-6 — Photo/diagram of LMS100 Supercore

DIRECT TESTIMONY OF ANDRES R. RAMIREZ

690

1 l. INTRODUCTION AND QUALIFICATIONS


3 A. My narne is Andres R. Ramirez. My business address is 100 North ,Stanton Street,

4 El Paso, Texas 79901.

5

6 Q. HOW ARE YOU EMPLOYED?

7 A. I am employed" by El Paso Electric Company ("EPE" or the "Company") as

8 Vice President-Power Generation.

9

10 Q. PLEASE SUMMARIZE YOUR EDUCATIONAL AND BUSINESS BACKGROUND.

11 A. I received a Bachelor of Science in Electrical Engineering from Texas A&M

12 University-Kingsville and a Master of Business Administration from Texas State

13 University. I am a registered professional engineer in Texas. Prior to My

14 employment with EPE, I served in various management and engineering positions in

15 Generation at Central Power & Light Co., from 1982 through 1996. Thereafter, I

16 served as Senior Vice President of Power Production for Austin Energy, the

17 municipally-oWned electric utility for Austin, Texas, until 2004. I also served as

18 Managing Director of Gulf Region Operations for Sempra Energy, a California-based

19 energy company that acquired various Texas generation assets from American

20 Electric Power.

21 In July 2005, I began working for EPE as Vice President, Safety,

22 Environmental and Resource Planning: I became Vice President-Power Generation

23 in 2006.

24

1


691

1 Q. PLEASE DESCRIBE YOUR PRINCIPAL AREAS OF RESPONSIBILITY.

2 A. During. the period covered by my testimony, as Vice President-Power Generation, I

3 was responsible for all activities of the Power Generation Division, which included

4 power plant operations and maintenance, new plant construction, and oversight

5 management of EPE's interest in the Palo Verde Nuclear Gerierating Station

6 ("PVNGS" or "Palo Verde").

7

8 Q. HAVE YOU PREVIOUSLY SUBMITTED TESTIMONY BEFORE A REGULATORY

9 BODY?

10 A. Yes, I have presented testimony to the Public Utility Commission of Texas ("PUCT"

11 or "Commission"), the New Mexico Public Regulation Commission, and the Texas

12 Commission on Environmental Quality ("TCEQ").

13

14 11. PURPOSE OF TESTIMONY

15 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?

16 A. The, purpose of my testimony is to describe EPE's generation fleet and to' support

17 recovery of the costs of new investments in that fleet and of the costs to operate and

18 maintain it. EPE's generation fleet consists of its local gas-fired units and remote

19 generation at PVNGS, but as of July 2016, no longer includes the rernote generation

20 at the coal-fired Four Corners Power Plant ("Four Cornere) Units 4 and 5, which

21 EPE sold.

22 I address the capital additions to EPE's local generation fleet, including the

23 two new generating units that EPE placed in. service during the October 2015

24 through September 2016 Test Year in this case. These two units are the Montana

25 Power Station ("MPS") Units 3 and 4, which are not yet included in Texas rate base.

26 I also address the reasonableness and prudence of the costs of other capital

2 DIRECT TESTIMONY OF ANDRES R. RAMIREZ

692

1 - additions and improvements for the local generation fleet that entered service from

2 April 2015 through September 2016, which covers the period that starts with the first

3 month after the test-year end in EPE's last rate proceeding, Docket No. 44941,

4 through the end of the Test Year in this case.

5 In addition, I address the operations and maintenance ("O&M") expenses and

6 practices that EPE employs to manage its local generation .fleet, together with the

7 level of O&M expenses that should be included in rates.

8 Last, I also support the reasonableness of the capital additions placed in

9 service at Palo Verde from April 2015 through September 2016, together with the

10 reasonableness of the Palo Verde Test Year O&M expenses.

11- I discuss total Company local generation fleet capital investments and

12 operating costs in my testimony. EPE witness Rene F. Gonzalez discusses the

13 allocation of total Company costs to the Texas jurisdiction in his testimony.

14

15 Q. WHAT DOES YOUR.TESTIMONY DEMONSTRATE?

16 A. My testimony demonstrates that the capital additions to EPE's local generation fleet

17 added from April 1, 2015, through the September 30, 2016, Test Year-end were

18 prudent and reasonable and are used and useful in, providing safe, reliable, and

19 'efficient power to meet customers neecl. The costs to add the new MPS Units 3

20 and, 4 were lower than the estimated costs refiepted in the final order in Docket

21 No. 41763, which was the MPS Units 3 and 4 Certificate of Convenience and

22 Necessity ("CCN") proceeding. ,

23 I also demonstrate that EPE mainta' ins effective cost controls at its local

24 generating facilities. The O&M practices that 'EPE employs to manage its local'

25 generation fleet are reasonable, and the Test Year O&M cdsts, as adjusted, are

26 reasonable and should be included in rates.


693

1

Last, my testimony also demonstrates that the O&M and capital cost

2

processes at Palo Verde are prudent. The resulting requested level of Palo Verde

3

O&M expenses included in rates is reasonable and necessary, and the resulting -

4

capital additions are prudent and reasoriable and used and useful in serving

5

customers.

6

7 Q. WHAT RATE CASE SCHEDULES DO YOU SPONSOR OR CO-SPONSOR?

8 A. The schedules that I sponsor or co-sponsor are listed in Exhibit ARR-1.

9

10 Q. WERE THE SCHEDULES AND EXHIBITS YOU ARE SPONSORING OR

11 .CO-SPONSORING PREPARED BY YOU OR UNDER YOUR DIRECT

12 SUPERVISION?


'14

15

111. EPE'S GENERATING FACILITIES

16 Q. WHAT ARE EPE'S GENERATING FACILITIES?

17 A. EPE meets the bulk of its customers electrical requirements, with power produced at

18 ifs generating stations, which are fueled by a mix of natural gas, uranium, and

19 renewable resources. Table ARR-1 identifies EPE's generating stations, with

20 nominal capacities and fuel types, as of the September 30, 2016, end of the Test

21 Year. These reflect the capacity resources EPE includes in, its planning reserve

22 margin analyses.

23

24

25

26

4


694

1 Table ARR-1

Generating Station

Net Peak

Capacity

(MW)

Primary

Fuel Type

Secondary

Fuel Type Duty

Palo Verde (Units 1, 2, and 3)

633 Uranium ' N/A Base load'

Rio,Grande' (Uriits 7, 8, 9)

276 Natural Gas N/A Peaking and Load-following

Newman (Units 1, 2, 3, 4, and

5)

752 Natural Gas Fuel Oil

(Units 1-3 only)

Peaking and Load-following; for Unit 5, lc* following

and base load in combined cycle mode

Copper (Unit 1)

64 Natural Gas N/A Peaking

MPS (Units 1, 2, 3, and 4)

354 Natural Gas Fuel Oil Peaking and load-following

Total 2,079

10

11

EPE also owns several small solar facilities with a combined capacity of less

12

than'l Mega-Watt ("MW").

13

The Newman and Copper power plants are located in EPE's Texas service

14

area within the City of EI,Paso, Texas. The Rio.Grande power plant is located ih

15

EPE's southern.New Mexico service area, and adjacent to the City of El Paso. The

16

Montana Power,Station or MPS is located in EPE's Texas service territory just east

17

qf the pity of El Paso, in uriincorporated El' Paso County. The Copper, Newman,

18

Rio Grande, and MPS generating stations are considered EPE's "local" generation.

19

Exhibit ARR-2A and ARR-2B are maps depicting, the location of EPE's local

20

generating stations.

21

PVNGS, which is located in Arizona, is considered EPE's "remote"

22 generation. I, as well as EPE witness John Cadogan, address the costs and

23 oper'ations of PVNGS.

24

25 Q. DOES THE RIO GRANDE POWER PLANT HAVE ANY GENERATION NOT

26 REFLECTED IN THE TABLE ABOVE?


2

3

4

5

6

7

8

9

695

1 A. Yes, it does. Rio Grande Unit 6 entered inactive reserve status on November 17,

2 2015; -it is no longer considered available capacity for planning reserve rnargin

3 purposes. However, Rio Grande Unit 6 was temporarily reactivated during the 2016

4 summer peak period due to systern constraints.

5

6 Q. IS THE COMPANY SEEKING TO RECOVER ANY COSTS ASSOCIATED WITH

7 THE RIO GRANDE UNIT 6?

8 A. No. As EPE witness Jennifer I. Borden describes, EPE,is not seeking to include any

9 Rio Grande'Unit 6 costs in rate base or in cost of service.

10

11 Q. DID EPE ADD ANY NEW GENERATION UNITS FROM. MARCH 31, 2015 (THE

12 END 6F THE TEST YEAR IN EPE'S LAST BASE RATE CASE IN DOCKET

13 NO. 44941) THROUGH, SEPTEMBER 30,.2016 (THE END' OF THE TEST YEAR IN

14 THIS DOCKET)?

15 A. Yes, as I mentioned above, EPE added two new generation units at the- MPS. MPS,

16 Unit 3 entered service on May 4, 2016,. and MPS Unit' 4 entered service on

17 September 15, 2016. MPS Units 3 and 4 are:gas-fired, nominally rated 89 MW

18 General Electric LMS100 simple cycle aero derivative combustion turbines that

19 provide peaking and load following capability, just like MPS Units 1 and' 2. MPS

20 Units.3 and 4 are included in the generation Table ARR-1 above. .

21,

22 Q. DtD EPE DIVEST ITSELF OF ANY GENERATION UNITS SINCE ITS LAST BASE,

23 RATE CASE?

24 A. Yes, it did. For decades EPE had been a minority owner of Units 4 and 5 of the coal-

25 fired Four Corners Power Plant located in northwestern New Mexico. EPE's interest

26 equated to 108 MW. In July 2016, when the controlling project agreements Were

6 DIRECT TESTIMONY OF ANDRES R. RAMIREZ,

696

1 scheduled to expire, EPE sold all of its ownership interest in Units 4 and 5. and

2 common facilities. As a result, Four Corners is excluded from the generation

3 Table.ARR-1 above.

4

5 Q. IS THE COMPANY SEEKING TO INCLUDE FOUR CORNERS IN BASE RATES?

6 A. lt is my understanding that EPE is not seeking to include any Four Corners'

7 investment and operating expenses in base rates. EPE witnesses James Schichtl

8 and Russell G. Gibson explain EPE's Four Corners rate proposal in their testimony.

9

10. IV. EPE'S LOCAL GENERATION FLEET—CAPITAL ADDITIONS

11 Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR TESTIMONY?

12 A. The'purpose of this section of my testimony is to describe and support cost recovery

13 •of the capital additions to EPE's local generation fleet that EPE requests in this case.

14 The scope , of thiš request is those capital additions placed in service from.April 1,

15 2015,• through the Test Year 6nding September 30, 2016. First; I will address the

16 two most significant additions, which are MPS Units 3 and 4. With the completion of

17 these two units, EPE no longer has any generating 'units under construction. Then I.

18 will address the other capital additions.

19

20 Q. IS THERE A LIST OF THE MAJOR PRODUCTION PLANT CAPITAL ADDITIONS

21 TO THE LOCAL GENERATION FLEET THAT EPE SEEKS TO INCLUDE IN RATE

22 BASE?

23 A. Yes, EPE witness Larry J. Hancock includes a list of all plant additions that EPE has

24 made from April 2015 through September 2016 for local generation. The local

25 generation capital additions fall under the "Stearn & Other Production" category in•his-

26 exhibit. I sponsor the reasonableness of the coristruction expenditures.


697

1

2 A. MPS Units 3 and 4

3 Q. DO MPS UNITS 3 AND 4 MARK THE COMPLETION OF RECENT SIGNIFICANT

4 ADDITIONS TO EPE'S LOCAL GENERATION FLEET?

5 A. Yes, they do. Beginning in 2009 and ,continuing through September 2016, EPE

6 added six new generation units to its local fleet. These new units are: Newman

7 Unit 5 (Phases I and II); Rio Grande Unit 9; and NIPS Units 1, 2, 3, and 4. Pie total

8 capacity of all these units is 720 MW. The addition of these new generation units is

9 consistent with the plans outlined in the.filings for and approval of CCNs for. all of

10 these units. No additional generating units are currently under construction or the

11 subject of a CCN request.

12 Newman Unit 5, Rio Grande Unit 9, and MPS Units 1 and 2 have already

13 been included in rate base. In this current rate proceeding,. EPE is requesting that

14 the last two new generation units (MPS Units 3- and 4) be included in rate base. I

15 support the reasonabléness and prudence of the costs of these two units and show

16 that they are used and useful in serving EPE's customers. EPE witness Hancock

17 addresses the Company's Allowance for Funds Used During Construction

18 ("AFUDC") practices, and his list of capital addition,s includes these two units.

19

20 Q. PLEASE BRIEFLY DESCRIBE MPS UNITS 3 AND 4.

21 A. The MPS site was a greenfield (i.e., undeveloped) site before the four rvIPS units

22 were built. MPS Units 3 and 4 weré built after Units 1 and 2, which entered service

23 in March 2015. MPS Units 3 and A; like Clnits 1 and 2, consist of General Electric

24 LMS100 simple cycle aero derivative combustion turbines fueled by natural gas, with

25 fuel oil as an emergency backup. Although each unit has a nameplate rating of

26 100 MW at Internationl Organization for Standardization ("ISO") condition, MPS


698

1

Units 1 and 2 are rated at 88 MW under summer conditions and MPS Units 3 and 4

are rated at 89 MW under summer conditions, owing to the high summer

3

temperatures and the high elevation of the MPS. Compared to EPEs older local

4

units, MPS Units 3 and 4 can be started quickly and are designed to be ramped up

5, and down to meet load fluctuations. Their heat rates are also more efficient than

6

those of the older units. CCN authorization for Units 3 and 4 occurred in Docket

7

No. 41763, as EPE witness David C. Hawkins explains.

8

9 Q. DOES 'EPE HAVE ANY OTHER GENERAL ELECTRIC LMS100 SIMPLE CYCLE

10 AERO DERIVATIVE COMBUSTION TURBINES?

•11 A. Yes, Rio Grande Unit 9, which entered servith in 2013, iš also a General- Electric "

12 LMS100 simple-cycle aero-derivative combustion turbine.

13

14 Q. WHAT ARE THE COMMON FACILITIES AT THE MONTANA- POWER STATION?

15 A. The common. facilities at the MPS are those facilities that support all of the units at'

16 the plant. The common facilities fall .into several major categories or plant functions

1,7 including:

18 1. Land and security,

19 2. Water supply and treatment,

20 3. Gas deliyery and distribution,

21 4. Compressed air system,

22 5. Fire protection,

23 6. Power distribution, and

24 7. Administrative and support activities.

25 Land and security include's the cost of the land, fencing, and other security

26 facilities at the plant. These facilities are not distinguishable between units at the


699 .

francis w. seymore

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