16 Q. - interchange.puc.texas.gov

1 ramped up and down as needed and therefore allow EPE to meet load fluctuations more

2 efficiently.

3 4 Q. IS THE AGE OF EPE'S LOCAL GENERATING FLEET AN IMPORTANT 5 CONSIDERATION WHEN EVALUATING UNIT PERFORMANCE?

6 A. Yes. In broad terms, EPE's local generation is composed of both very new units and very

7 old units. Four of EPE's local units (not counting Rio Grande Unit 6) are over 50 years

8 old (Rio Grande Unit 7 and Newman Units 1, 2, and 3). Newman Unit 4 entered service

9 in 1975 and is near the end of its operating life. As power plants of that vintage grow

10 older, they become less efficient, have infiexible operating characteristics, and are more 11 costly to run than newer units. Unless reliability must-run conditions exist, unit

12 commitment will be based on lowest heat rate first, thus having the effect of dispatching 13 older units last.

14 15 B. Local Unit Maintenance

16 Q. WHAT STEPS DOES EPE TAKE TO MAINTAIN THE EFFICIENCY AND

17 AVAILABILITY OF ITS LOCAL GENERATING FLEET?

18 A. EPE conducts a comprehensive maintenance program designed to maximize the

19 efficiency and availability of its local generation. The cornerstones of EPE's maintenance

20 practices are regularly scheduled maintenance and preventive and predictive maintenance 21 programs. 22 23 Q. CAN YOU DESCRIBE EPE'S SCHEDULED MAINTENANCE ACTIVITIES?

24 A. Yes, I can. EPE's power generation operations, maintenance, system operations, and

25 power marketing personnel collaborate to plan the timing of the outages to minimize the

26 economic impact of planned maintenance, subject to system reliability. EPE's scheduled

27 maintenance activities include periodic inspections and major unit overhauls, other 28 planned maintenance intended to maximize unit availability and efficiency, and capital 29 projects. 30 A major unit overhaul is a comprehensive tune-up where EPE takes a unit out of

31 service to inspect it for degradation of component parts, primarily in the turbine and

Page 19 of 27 DIRECT TESTIMONY OF J KYLE OLSON

1 generator, and repairs or replaces component parts as necessary to maintain or improve

2 efficiency and reliability.

3 Between major overhauls, EPE also conducts scheduled maintenance on a variety

4 of unit components (e.g., boilers, turbine control valves, and auxiliary equipment) when

5 unit efficiency or availability is likely to be impacted by the failure or potential failure of

6 these parts. 7 8 Q. CAN YOU DESCRIBE EPE'S PREVENTIVE MAINTENANCE PROGRAM?

9 A. Yes. EPE's preventive maintenance program is the practice of performing routine,

10 proactive equipment maintenance. This preventive maintenance is conducted not only

11 during maintenance outages but throughout the year while the units are under normal

12 operation. Preventive maintenance includes systematic inspection and routine tasks

13 designed to keep equipment in sound operating condition and minimize degradation of

14 equipment. EPE evaluates OEM data, equipment operating history, and operating

15 experience in conjunction with the relative significance of a generating unit's components

16 and the associated risk of failure to determine the type of preventive maintenance

17 required. If necessary, EPE then schedules a maintenance outage to inspect equipment

18 and undertake maintenance work prior to the time the equipment is expected to fail.

19 EPE's preventive maintenance program ensures greater control over the scheduling of

20 maintenance activities, which can minimize the duration and cost of outages.

21

22 Q. DOES EPE ALSO FOLLOW PREDICTIVE MAINTENANCE PROCEDURES?

23 A. Yes. EPE monitors equipment operations through various inspection techniques and

24 utilizes statistical control measures in conjunction with actual equipment operating

25 history to predict when to perform maintenance on a unit or component part prior to

26 failure. The data gathered assists with work planning and allows EPE to predict the parts

27 that will be required during an actual outage or repair phase. Predicting when a

28 component part is expected to fail also provides EPE more control over scheduling

29 maintenance and thus minimizes costs.

30


1 Q. WHAT ARE SOME OF THE PROCESSES EPE FOLLOWS IN ITS PREDICTIVE

2 MAINTENANCE PROGRAM?

3 A. EPE conducts continuous unit performance monitoring, pre- and post-overhaul unit

4 performance testing, steam path inspections during overhauls, critical equipment

5 vibration monitoring, and lubricant oil analysis. EPE also uses thermography, ultrasonic

6 sensing, and a variety of other analyses to identify, analyze, and resolve potential

7 maintenance concerns. These predictive maintenance processes give EPE's maintenance

8 and operations teams more options in planning and scheduling maintenance and

9 minimizing costs. The alternative would be to wait for equipment to fail, which would

10 create downtime since there would be no option but to repair or procure a replacement 11 which often have long lead times.

12

13 Q. ARE EPE'S PREDICTIVE AND PREVENTIVE MAINTENANCE PROGRAMS

14 IMPLEMENTED IN ALL ASPECTS OF UNIT OPERATIONS?

15 A. No. Many of the technologies available are not readily adaptable to all systems. EPE's

16 preventive and predictive maintenance practices focus on rotating equipment and are

17 being expanded to other critical areas of the plant. During operation of a plant, these

18 practices cannot be applied to internal components such as boiler tubes or within the 19 condenser. However, during plant outages, ultrasound equipment is used to check for,

20 and find tube leaks. In addition, EPE's maintenance department also conducts eddy

21 current testing and non-destructive evaluation analysis of boiler and condenser tubes and

22 main steam lines.

23

24 Q. EPE'S LMS100 UNITS EMPLOY A MORE MODERN TECHNOLOGY THAN THE

25 OLDER UNITS. DOES EPE HAVE A MORE ADVANCED MONITORING

26 CAPABILITY FOR THESE UNITS?

27 A. Yes. Through GE, EPE has a Remote Monitoring and Diagnostic program. GE has a

28 team staffed by former field service and controls experts who continually monitor the

29 performance of all five of the Company's LMS100 units. The team provides early

30 warning alerts, and in case of more severe issues, the team notifies EPE and supports the


1167

1 Company in resolving the issue. The team analyzes data-logs, trends, and alarm history,

2 and this analysis is used for predictive maintenance.

3 4 C. Local Unit Performance

5 Q. HOW DOES THE COMPANY MONITOR THE PERFORMANCE OF ITS I,OCAL

6 GENERATING UNITS?

7 A. EPE monitors the performance of these units using two key indicators: (1) net heat rate

8 and (2) equivalent availability factor ("EAF"). Both net heat rate and EAF are

9 industry-accepted measurements of generating unit performance. Net heat rate is used to

10 monitor unit thermal efficiency, while EAF is used to measure unit availability, based on

11 the percentage of time within a given period that a unit is available to generate electricity.

12

13 Q. HOW DOES NET HEAT RATE REFLECT UNIT EFFICIENCY?

14 A. A unit's net heat rate is defined as the amount of fuel energy (measured in British thermal

15 units ("Btu")) used to produce one kilowatt-hour ("kWh") of electricity delivered to the

16 transmission system. Efficient power generation equates to less fuel consumed to

17 produce a kWh and therefore lower fuel costs. A lower net heat rate means the turbine

18 generator is more efficient than a unit with a higher net heat rate. The goal is to maintain

19 a reasonable level of efficiency while satisfying system reliability requirements.

20 21 Q. DO EPE'S LOCAL GENERATING UNITS MAINTAIN CONSISTENT NET HEAT

22 RATES, AND ARE THEY REASONABLE HEAT RATES?

23 A. Yes. The annual variances for EPE's local generating fleet efficiency are minimal and are

24 within a range of reasonable operations, based on historical performance. As shown in

25 Schedule H-12.3a, the annual average composite net heat rates for EPE's local generating

26 fleet demonstrate that EPE maintained consistent and reasonable levels of efficiency

27 during the Test Year.

28

29 Q. WHAT HAS EPE BEEN DOING TO IMPROVE THE OVERALL EFFICIENCY OF

30 THE GENERATING FLEET?


1168

1 A. Most significantly, EPE has added more efficient generation facilities. Newman Unit 5

2 entered service as a combined cycle facility in April 2011. This unit is the most efficient

3 gas-fired facility in EPE's fleet. During the Test Year, this unit had a net heat rate of

4 approximately 7,970 Btu/kWh. This compares to an average net heat rate of

5 11,614 Btu/kWh for the older Rio Grande Units 7 and 8 and Newman Units 1 through 4.

6 Rio Grande Unit 9, which entered service in May 2013, and MPS Units 1 through

7 4, which entered service in 2015 and 2016, have helped improve the efficiency of EPE's

8 fleet and have provided other advantages, such as quick-start capability. During the Test

9 Year, Rio Grande Unit 9 had a net heat rate of 10,112 Btu/kWh. Also during the Test

10 Year, MPS Units 1 and 2 had heat rates of 9,553 Btu/kWh and 9,439 Btu/kWh, 11 respectively, and MPS Units 3 and 4 had heat rates of 10,463 Btu/kWh and 9,414

12 Btu/kWh, respectively.

13 The average net heat rate of the four MPS units is 9,578 Btu/kWh. This is

14 significantly less than the average net heat rate of 11,614 Btu/kWh for the older

15 Rio Grande Units 7 and 8 and Newman Units 1 through 4.

16

17 Q. WHY DOES EPE USE EAF AS AN INDICATOR OF PERFORMANCE?

18 A. As an indicator of performance, EAF takes into account all events that affect availability,

19 rather than focusing on a single type of event. EAF represents the net maximum

20 generation that can be provided by a unit after taking into account outages and derates. 21 EPE uses EAF to measure performance of EPE's local generating units because it

22 provides a clear indication of overall unit availability for a given period. For EPE, that

23 period is May through September, because EPE is a summer peaking utility.

24 25 Q. HOW HAVE EPE'S LOCAL GENERATING UNITS PERFORMED RECENTLY

26 WITH RESPECT TO AVAILABILITY?

27 A. For the years 2017 through 2020, EPE achieved consistently high levels of availability

28 during the summer peak periods (May through September), when availability matters

29 most to EPE and its customers. For the Test Year, the average EAF for all units, during

30 the summer peak months of May through September 2020, was 89.1 percent.

31 Table JKO-4 below summarizes this information.


1169

Table JKO-4 2

3 4 5

Year Total Peak (May through EAF Average September) (%)

2017 84.8

6 2018 88.3

2019 92.9 7 8 Test Year 89.1

9

10 Q. ARE THE COMPANY'S OPERATION AND MAINTENANCE PROGRAMS AND 11 PRACTICES NECESSARY AND REASONABLE?

12 A. Yes, EPE's local generation fleet requires operation and maintenance programs, as all

13 generation units do. EPE's operation and maintenance programs are methodical and

14 tailored to EPE's fleet, and they are based on engineering data gathered to set the 15 intervals between inspections. EPE's practices conform to industry-wide standards. Over

16 the past several years, they have led to good results.

17

18 Q. GIVEN THE SEVERE WEATHER AND SERVICE DISRUPTIONS IN ERCOT IN 19 FEBRUARY 2021, WHAT ACTIONS HAS EPE TAKEN AND WHAT ACTIONS 20 DOES IT PLAN TO TAKE TO PREPARE ITS LOCAL GENERATION FLEET FOR

21 EXTREME WEATHER, BOTH HOT AND COLD?

22 A. Following the severe freeze that occurred in early 2011, EPE thoroughly reviewed the

23 preparations it was taking for extreme weather, both hot and cold. As a result of this 24 review, EPE implemented additional preparations for severe cold and hot weather at its

25 local generating stations, including:

26 • Improved heat tracing, insulation, and other winterization tools to a design criterion

27 of minus 10 degrees Fahrenheit (two degrees lower than the record low temperature 28 in the El Paso area), and the design coincident wind velocity of 25 mph.

29 • Improved, both hot and cold, weatherization checklists, procedures, and preventative 30 maintenance.

31 • Construction of new gas turbine generation


1

1 o Includes quick start capability to respond to intermittent generation

2 o Designed to operate from minus 10 degrees to 105 degrees Fahrenheit

3 • Added liquid fuel (diesel) capabilities to MPS Units

4 • Added a second natural gas interconnection to MPS

5 • Preparing Rio Grande Unit 6 to return to service for the 2021 summer peak period to

6 ensure reliability 7 These measures have proved effective as EPE and its customers did not

8 experience the service disruptions that much of ERCOT did in February 2021

9 10 D. Local Generation Fleet Non-Fuel O&M Costs and Rate Request

11 Q. WHAT IS THE AMOUNT OF NON-FUEL 0&M COSTS FOR EPE'S LOCAL

12 GENERATION FLEET?

13 A. During the Test Year, the unadjusted non-fuel O&M costs for the local generation fleet

14 were $54,893,323. With one adjustment that is addressed by EPE witness Jennifer I.

15 Borden, EPE's total Company Test Year non-fuel O&M costs are $54,642,433 for its

16 local generation fleet.

17

18 Q. WHAT HAVE BEEN EPE'S RECENT LOCAL GENERATION FLEET NON-FUEL

19 0&M EXPENDITURES?

20 A. EPE's non-fuel O&M expenses for the four years since its last generation addition are

21 shown in Table JKO-5 below.

22 23 24

25 26

Year

2017 2018 2019

Test Year

Table JKO-5 Non-Fuel O&M (excluding Palo Verde 0&M, millions)

46.9 49.4 46.0 54.9

27

28 Q. GIVEN THE INCREASE IN NON-FUEL O&M EXPENSES FROM 2019 TO THE

29 TEST YEAR, DOES EPE EXPECT SUCH EXPENSES TO REMAIN AT LEVELS

30 COMPARABLE TO THE TEST YEAR?


1 A. Yes. The 2021 Non-Fuel O&M budget is $53.4M, which is close to the Test Year

2 expense. 3 As I mentioned above, EPE has several aging units in its local fleet, as

4 Table JKO-6 below indicates:

5 Table JKO-6

6 Generation Unit: In Service Date:

7 Newman 1 1960

8 Newman 2 1963

9 Newman 3 1966 10 1975 Newman 4 11

Rio Grande 7 1958 12

Rio Grande 8 1972 13

14 The youngest of these units, Newman Unit 4, is 46 years old.

15 As these units continue to age, we expect 0&M costs to continue to rise. This is

16 primarily due to increased maintenance requirements and a decreasing availability of

17 spare parts. As is typical with older units, it becomes more difficult to find vendors and

18 aftermarket parts become more expensive. As for the five newer LMS100 units, O&M

19 expenses have risen as the units entered their regularly scheduled maintenance intervals.

20

21 Q. WHY WERE NON-FUEL O&M EXPENSES FROM 2019 LOWER THAN THE TEST

22 YEAR AND THE MOST RECENT FOUR-YEAR AVERAGE?

23 A. Non-Fuel O&M expenses for 2019 were lower as a result of two primary factors. The

24 first primary factor was the reduction in 0&M expenses as a result of installing new

25 capital parts during the Newman Unit 4 GT1 and GT2 2019 outages. As a result of

26 installing new capital parts, instead of refurbishing existing parts and installing those

27 refurbished parts, planned outage expenses were capitalized instead of expensed to

28 0&M. The second primary factor was the reduction in unplanned outage expenses as a

29 result of fewer unplanned outages in 2019 compared to the other years.

30


1172

1 Q. ARE THE ADJUSTED TEST YEAR NON-FUEL O&M COSTS FOR LOCAL

2 GENERATION REASONABLE AND NECESSARY?

3 A. Yes. The Test Year costs, as adjusted by EPE witness Borden, are reasonable and

4 necessary to reliably operate and maintain the local generation units. As I described

5 previously, EPE uses a preventive maintenance program and a predictive maintenance

6 program to maintain its local generation fleet. These programs have led to very good

7 performance of the local fleet. EPE appropriately uses its engineering data to determine

8 maintenance intervals.

9 10 VI. Conclusion

11 Q. DOES THIS CONCLUDE YOUR TESTIMONY?

12 A. Yes.


1173

Exhibit JKO-1 Page 1 of 1

SCHEDULES SPONSORED BY SPONSOR

Schedule Description Sponsorship D-6 RETIREMENT DATA FOR ALL GENERATING UNITS Sponsor E-1.2 OBSOLETE ASSETS Co-Sponsor E-2.3 FUEL INVENTORIES Co-Sponsor E-2.4 FOSSIL FUEL INVENTORY LEVELS Co-Sponsor E-3.1 FUEL OIL BURNS Co-Sponsor E-3.2 NATURAL GAS SUPPLY DISRUPTIONS Co-Sponsor E-3.3 COAL OR LIGNITE SUPPLY DISRUPTIONS Sponsor

SUMMARY OF TEST YEAR PRODUCTION O&M EXPENSES (NUCLEAR & H-1 FOSSIL) Co-Sponsor H-1.2 FOSSIL COMPANY-WIDE O&M EXPENSES SUMMARY Sponsor H-1.2a NATURAL GAS PLANT O&M SUMMARY Sponsor H-1.2al NATURAL GAS (STEAM GENERATION) Sponsor H-1.2a2 NATURAL GAS (COMBUSTION TURBINE) Sponsor H-1.2b COAL PLANT O&M SUMMARY Sponsor H-1.2c LIGNITE PLANT O&M SUMMARY Sponsor H-1.2d OTHER PLANT O&M SUMMARY Sponsor H-2 SUMMARY OF ADJUSTED TEST YEAR PRODUCTION O&M EXPENSES Co-Sponsor H-3 SUMMARY OF ACTUAL PRODUCTION O&M EXPENSES INCURRED Co-Sponsor H-4 MAJOR O&M PROJECTS Co-Sponsor H-5.2b FOSSIL CAPITAL COSTS PROJECTS Co-Sponsor H-5.3b FOSSIL CAPITAL EXPENDITURES (HISTORICAL, PRESENT, PROJECTED) Co-Sponsor H-6.2a FOSSIL UNIT FORCED OUTAGE HISTORY Sponsor H-6.2b FOSSIL UNIT PLANNED OUTAGE DATA Sponsor H-6.3b FOSSIL UNIT INCREMENTAL OUTAGE COSTS Sponsor H-8 PRODUCTION OPERATIONS PROGRAMS Sponsor H-9 PRODUCTION MAINTENANCE PROGRAMS Sponsor H-11.1 0&M EXPENSES PER PRODUCTION PLANT EXPENSES Co-Sponsor H-11.2 MAINTENANCE MAN-HOUR RATIO Sponsor H-11.3 O&M COST PER MWh Co-Sponsor H-12.1 SUPPLY AND LOAD DATA Co-Sponsor H-12.2b MWh PRODUCTION BY UNIT (NATURAL GAS / OIL) Sponsor

MWh PRODUCTION BY UNIT FOR PREVIOUS 5 YEARS (NATURAL GAS / H-12.2bl OIL) Sponsor H-12.3a UNIT DATA Co-Sponsor H-12.3b UNIT CHARACTERISTICS Co-Sponsor H-12.3c EFFICIENCY AND CONTROL SYSTEMS Co-Sponsor I-5.1 COMBUSTION RESIDUAL PRODUCTION Sponsor I-5.2 COMBUSTION RESIDUAL DISPOSAL Sponsor I-5.3 COMBUSTION RESIDUAL DISPOSAL COSTS Sponsor I-6 NATURAL GAS DELIVERY SYSTEM Sponsor I-19.7 RAIL CAR REPAIRS Sponsor

1174

EPE Generation Location Map Texas Rate Case


.U Generating Station

Major Distribution Stations t - - - Hakh

- Company Lines

To Albuquerque NM

- Las Cruces

,---Et Paso

- - Van Hc

To Springervitle. AZ

Hollornan AFB I

Palo Verde. AZ (450 milesl

Luna Jt Amrad '

L" Cruels C\\ Wh,ti Sands I M rwli Range ~

Eddy County NM I Interchange

(125 milesl

Ni \ / \ - ,-Ar\ Newman McOrilgor NEW MEXICO . Range

Cal,eni. TEXAS RioGrande ~~/ Asorati L ~ .~ Montana

) To O.tt Oty T'X D.blo ,~ MEXICO ZCopper

Oudad Juarez Si,rra 81@na Van Horn

Warehouse and Access Road Overview Texas Rate Case


..;

i

it Lb,

1176

Exhibit JKO-4 Exhibit JKO-4 Newman Blanket Projects over $200,000 Page lof 1

WORK ORDER N180516.0021 -N170320.0003 -N200106.0118 -GN0030112002 GN0030114001 N190405.0005 -

N190423.0008 -N171013.0008 -

GN0030113003

Total

U2 TURBINE SYSTEM PLANT GENERAL LIGHTING AND 110V RE U4 ST CONDENSER MAIN STEAM BY PASS - U2 DETERIORATED WOOD REPL-CTWR - NEWM U4-CTWR MAIN HEADER PIPE REPL PLANT ELECTRIC GENERAL

WELL WATER SYSTEM-POTABLE WTR TREAT U2 BOILER FEED PUMP B

- UNIT 3 REWEDGE CNTRCTR SVCS

Project Description Project Cost Upgrades to the Unit 2 Turbine Rotor performed during the 2018 Unit 2 Outage $ 510,862.56 Upgrading the Newman Plant Lighting to LED $ 393,380.18 Unit 4 Main Steam Bypass Valve Upgrades $ 346,745.27 Replacement of Newman Unit 2 wood Cooling Tower Sections with Fiberglass $ 288,685.12 Replacement of the Newman Unit 4 Cooling Tower Header $ 273,245.17 Upgrading the Newman Plant Lightning Protection $ 265,185.94 Upgrading the Newman Plant Drinking Water System to comply with TCEQ Audit and Sampling Findings $ 224,692.54 Purchase of a spare rotating element for Newman 2 Boiler Feed Pumps $ 212,060.97 During the 2017 major turbine generator inspection, inspection results determined that the generator need to be rewedged. $ 208,599.06 Projects under $200k 9,850,613.11

$ 12,574,069.92

ZZLL

DOCKET NO.

APPLICATION OF EL PASO § PUBLIC UTILITY COMMISSION ELECTRIC COMPANY TO CHANGE § OF TEXAS RATES

DIRECT TESTIMONY

OF

TODD HORTON

OF

ARIZONA PUBLIC SERVICE COMPANY

FOR

EL PASO ELECTRIC COMPANY

JUNE 2021

1178

EXECUTIVE SUMMARY

Todd Horton is Senior Vice President of Site Operations at the Palo Verde Generating

Station ("Palo Verde" or "PVGS"). Mr. Horton is employed by Arizona Public Service Company

("APS"), the operator of PVGS. EPE owns a 15.8 percent share of Palo Verde and receives an

allocation of approximately 633 Mega-Watts ("MW") from PVGS when at full power. The

purpose of Mr. Horton's testimony is to describe Palo Verde and support EPE's request to include

Palo Verde invested capital in EPE's rate base and Palo Verde operations and maintenance

("O&M") expenses in EPE's cost of service. Mr. Horton's testimony describes these capital

investments and 0&M expenditures from the total plant perspective, unless otherwise noted.

EPE's share of these total plant costs is identified in other parts of EPE's Application, including

the direct testimony of EPE witness David Hawkins.

Mr. Horton's testimony begins with a description ofPalo Verde. This description includes

identification of some of the unique aspects of nuclear power and, in particular, Palo Verde,

including the Water Resources Facility that supplies water to Palo Verde. This section of the

testimony includes a description ofthe ownership structure ofPalo Verde, as well as the operations

and oversight arrangements provided for by the owners' Participation Agreement.

Mr. Horton's testimony next supports those capital projects that have been placed in service

from October 1,2016 (the first day after the end of the test year in EPE's previous rate case, Docket

No. 46831) through December 31,2020, the end of the test year in this proceeding. His testimony

discusses the efficient capital cost management approach taken at Palo Verde. That approach is

multi-tiered with several layers of scrutiny and review designed to ensure that capital expenditures

are reasonable and necessary. Mr. Horton's testimony discusses in detail major individual capital

additions with the most significant costs, explaining why they were undertaken. In supporting Palo Verde O&M expense, Mr. Horton's testimony explains that Palo Verde

has continued to lower costs while improving plant performance. His testimony describes

Palo Verde's approach to efficient O&M management and the effect of the Water Resources

Facility on O&M expenses. His testimony demonstrates that rigorous cost oversight and

management, as well as continued implementation of cost reduction actions and processes, have led to more efficient management of 0&M expenses.

DIRECT TESTIMONY OF TODD HORTON

TABLE OF CONTENTS

SUBJECT PAGE

I. INTRODUCTION AND PURPOSE OF TESTIMONY. 1

II. DESCRIPTION OF SPONSORED SCHEDULES 3

III. OVERVIEW OF PALO VERDE GENERATING STATION. 3

IV. PVGS CAPITAL 10

A. Monitoring and Approval Process of Capital Costs

B. PVGS Capital Additions to Rate Base.... 14

1. Major Capital Projects 15

a. Nuclear Administrative and Technical Manual ("NATMD Upgrade...........16

b. Polar Crane Replacement Unit 2. 16

c. NRC's Cyber Security Regulation 17

d. Main Generator Stator Rewind Unit 1, Unit 2 and Unit 3. 18

e. Digital Upgrade Generrex Unit 1 18

2. Remaining Capital Projects..... 19

a. Plant Modifications. 19

b. Plant Equipment and Replacementq ?1

c. Buildings...................................................................................................22

d. General Plant. ?3

e. Information Technology .. ?3

f. Water Resources Facility ?4

g. Overheads and Distributables ..... ........25

h. Fukushima/Major Strategic Projertq ?8

V. PVGS OPERATION AND MAINTENANCE ("O&M") EXPENSE. 79

VI. CONCLUSION 34

EXHIBITS

TH-1 - Schedules Sponsored or Co-Sponsored

DIRECT TESTIMONY OF TODD HORTON

1180

1 I. Introduction and Purpose of Testimony

2 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.

3 A. My name is Todd Horton. My business address is Palo Verde Generating Station,

4 5801 S. Wintersburg Road, Tonopah, Arizona 85354-7529.

5

6 Q. HOW ARE YOU EMPLOYED?

7 A. I am employed by Arizona Public Service Company ("APS").

8 9 Q. WHAT IS YOUR CURRENT POSITION AT APS?

10 A. I am the Senior Vice President of Site Operations at Palo Verde Generating Station

11 ("Palo Verde" or "PVGS").

12

13 Q. PLEASE DESCRIBE YOUR EDUCATIONAL AND PROFESSIONAL

14 QUALIFICATIONS.

15 A. Prior to joining APS in 2008, I held numerous positions in the nuclear industry. I graduated

16 from the U.S. Navy Nuclear Power School and Prototype Training Unit. I was a senior

17 reactor operator and control room supervisor at Enrico Fermi Nuclear Generating Station.

18 I held positions at St. Lucie Nuclear Power Plant as a senior reactor operator, on-line work

19 control manager, operations manager, and operations shift manager. I began my career at

20 Palo Verde Generating Station as work management director and held positions as

21 operations director and general plant manager. In 2020 I was named Senior Vice President

22 of Site Operations.

23 I hold an Executive MBA from Eller College of Management, University of

24 Arizona. 1 attended the Institute of Nuclear Power Operators ("INPO") Senior Nuclear

25 Plant Manager course and participated in the INPO nuclear industry executive working

26 group to identify key attributes of maintaining excellence in nuclear plant operation. The

27 resulting document, "Staying on Top" was published by INPO in 2019.

28

29 Q. PLEASE DESCRIBE YOUR CURRENT RESPONSIBILITIES WITH APS.

30 A. As Senior Vice President of Site Operations, I am responsible for overseeing the day-to-

31 day nuclear operations including engineering, training, industrial safety, water resources,

Page 1 of 35 DIRECT TESTIMONY OF TODD HORTON

1 and training activities for Palo Verde Generating Station. I function as a member of the

2 Site Senior Leadership Team in establishing policies, developing procedures and

3 maintaining standards of performance that ensure safe and economical operation of the 4 site. I am responsible for ensuring a high level of performance by directing Nuclear

5 Operations strategic planning, providing visionary leadership, developing, implementing

6 and communicating a strategic plan that meets or exceeds targets. My role includes the

7 management of the administration, budgeting and contracting functions to ensure sound

8 fiscal management, seeking out improvement opportunities, and maintaining a highly

9 skilled work force. 10 Beyond these direct responsibilities, I am experienced in shaping effectiveness

11 initiatives like technical conscience, human-error reduction, and nuclear safety culture

12 promotion which are vital underpinning elements ofthe nuclear organization.

13

14 Q. ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS CASE?

15 A. I am testifying on behalf of El Paso Electric Company ("EPE").

17 Q. WHAT IS EPE'S SHARE OF PALO VERDE?

18 A. EPE owns a 15.8 percent share of each Palo Verde unit and the common facilities. EPE

19 receives an allocation of approximately 633 Mega-Watts ("MW") from the entire PVGS

20 when at full power.

21

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

23 A. The purpose of my testimony is to describe Palo Verde and support EPE's request to include

24 Palo Verde invested capital into its rate base and Palo Verde operations and maintenance

25 ("O&M") expenses in its cost of senice. The capital investments at Palo Verde that I support

26 are those that have been placed in service from October 1, 2016 (the first day after the end

27 ofthe test year in EPE's previous rate case, Docket No. 46831) through December 31,2020,

28 the end of the test year for EPE in this proceeding. The O&M expenses I support are those

29 incurred during the 12 months ending December 31,2020, the Test Year for this proceeding.

30 My testimony describes these capital investments and O&M expenses from the total plant

31 perspective, unless otherwise noted. EPE's share of these total plant costs is identified in


1 other parts of this Application, including the direct testimony of EPE witness David

2 Hawkins.

3 4 II. Description of Sponsored Schedules

5 Q. WHAT SCHEDULES FROM THE FILING PACKAGE DO YOU SPONSOR OR

6 CO-SPONSOR?

7 A. I co-sponsor the schedules shown on Exhibit TH- 1.

8 9 III. Overview of Palo Verde Generating Station

10 Q. PLEASE DESCRIBE PALO VERDE.

11 A. Palo Verde is a nuclear electric generating station located on an approximately 4,000-acre

12 site approximately 50 miles west of Phoenix, Arizona. The facility consists of three

13 separate, standardized generating units and a variety of common support facilities with a

14 total design electrical rating of 4,003 MW (average yearly conditions). Palo Verde is the

15 largest nuclear power plant in the U.S.

16 The Unit 1 low power license (NPF-34) was approved by the Nuclear Regulatory

17 Commission (NRC) on December 31, 1984, with the full power license (NPF-41) approved

18 on June 1, 1985. The unit entered service in 1986. The Unit 2 low power License (NPF-46)

19 was approved by the NRC on December 9, 1985, with the full power License (NPF-51)

20 approved on April 24, 1986. The unit entered service in 1986. The Unit 3 low power

21 License (NPF-65) was approved by the NRC on March 25, 1987, with the full power

22 License (NPF-74) approved on November 25,1987. The unit entered service in 1988. The

23 units have been uprated twice in their operating history, to a current approximate design

24 electrical rating ofl,334 MW per Unit.

25 On December 11, 2008, APS submitted an application to the NRC to extend the

26 licenses of each unit for an additional 20 years. The NRC approved the license renewal

27 application on April 21, 2011. The new expiration dates for the NRC operating licenses

28 for the three Palo Verde Units are June 1, 2045 (Unit 1), April 24, 2046 (Unit 2), and

29 November 25,2047 (Unit 3).

30 Palo Verde also has a switchyard that operates at 500 KV. Photograph TH-1 is an

31 overhead photo ofthe Palo Verde site.


1

2

3

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9

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,

12

13 Q. HOW IS PALO VERDE OWNED AND OPERATED?

14 A As detailed in the testimony of EPE witness David Hawkins, Palo Verde is owned by seven

15 southwestern utilities ("Owners") and operated by APS. The Owners of the project are

16 APS, EPE, the Salt River Project Agricultural Improvement and Power District, Southern

17 California Edison Company, Public Service Company of New Mexico, Southern

18 California Public Power Authority, and Los Angeles Department of Water and Power.

19

20 Q. WHAT ARE BASE LOAD PLANTS AND WHAT MAKES NUCLEAR POWER BASE

21 LOAD PLANTS UNIQUE?

22 A. Base load electricity generating plants are the production facilities used to meet the steady

23 and continuous needs of electricity to run our homes, businesses, hospitals, schools,

24 military bases, and other facilities. Nuclear power plants are ideal base load generating

25 plants because their operations are predictable and reliable, and they have low incremental

26 operating costs and high capacity factors.

27

28 Q. WHAT ARE OTI1ER UNIQUE ASPECTS OF NUCLEAR POWER PLANTS IN

29 COMPARISON TO TRADITIONAL FOSSIL FUELED PLANTS?

30 A. Nuclear power plants in the United States are regulated by the Nuclear Regulatory

31 Commission ("NRC"). As a condition of its NRC license, each station is required to


1184

10

11

1 develop and maintain strict plant operating standards, plant designs, and technical

2 specifications that must be complied with to meet the license requirements. Under certain

3 off-normal conditions, technical specifications require that certain actions must be

4 performed and conditions met within specific timeframes in order to continue to operate 5 the unit. In some cases, when these prescribed actions cannot be met within predetermined

6 timeframes, the technical specifications require that the unit be taken out of service. NRC

7 regulations, radiological conditions, and prescriptive operating procedures require the unit

8 operators to follow a specific process for shutdown, outages, and restart.

9 Nuclear power plants are strictly regulated to assure their safety. The operating

10 requirements are vastly different from those applicable to coal or gas-fired plants of similar 11 size. For example, the radiological conditions of a nuclear plant are highly controlled and

12 monitored, and access to specific areas is restricted during normal plant operations. When

13 a nuclear plant is taken out of service, access to certain areas is restricted until radiological, 14 temperature, and other conditions are met. Due to radiological conditions in some areas of

15 nuclear power plants, actions not required at fossil stations are taken to minimize personnel

16 exposure. These actions, such as using protective clothing, and installing and working

17 around lead shielding, increase the amount oftime, and therefore cost, required to perform

18 work. 19 Each U.S. nuclear station contains multiple systems and operational features that

20 create redundancy - or multiple barriers - to ensure safe operations. Regulations and

21 maintenance practices in nuclear stations are in place to replace, repair, and ensure the 22 safety margin of critical primary and secondary systems. This means that the unit may be

23 down-powered or removed from service to repair a system that does not directly impact

24 the operations or output of the plant but is done to ensure the safe operation of the back-up

25 systems. Palo Verde has specific operations and maintenance procedures (and

26 corresponding training for personnel) to control plant operation. These procedures cover

27 not only normal plant operation, but a multitude of other conditions such as abnormal

28 operations and emergencies. As a result, plant operators have limited discretion in how the

29 plant is to be operated. By contrast, fossil-fueled units do not have strict technical

30 specifications that require the unit to be taken out of service under similar circumstances.


1 Additionally, from the time a nuclear unit is shut down for refueling, approximately

2 100 hours are needed to ensure the decay heat from the reactor core has reached a point 3 that it is safe to begin refueling operations. At the end of an outage, returning to the grid

4 from shutdown conditions takes about two days. To return to 100 percent power takes an

5 additional one to two days. In contrast, to remove and return a gas or coal plant to service

6 can be achieved in as little as, or less than, one day. 7

8 Q. WHAT ARE THE ADVANTAGES OF THE PALO VERDE PLANT

9 CONFIGURATION?

10 A. Palo Verde is the largest nuclear power station in the United States and consistently

11 produces the most power of any power production facility in the country. Furthermore, it

12 is the first and only power plant in the country (of any fuel source) to produce more than

13 32 million megawatt-hours ("MWh") in one year. Since startup, the plant has exceeded

14 30 million MWh twelve times. Indeed, in 2020 PVGS achieved a first ever milestone in

15 the nuclear industry when it produced a cumulative one billion MWh. The APS-operated

16 PVGS achieved its 30th consecutive year as the nation's largest power producer.

17 Palo Verde owners place a high emphasis on reliability during the summer months. During

18 the peak period of June 15 through September 15, 2020, Palo Verde achieved a 100%

19 capacity factor and produced 31.9 million MWh during the test year.

20 The Palo Verde units are three identical, independent, stand-alone Pressurized

21 Water Reactor units with an independent Water Resources Facility. The units are

22 Combustion Engineering ("CE") System 80 plants, which were designed to maximize

23 reliability and performance. As identical units, there is economy of scale with engineering

24 of modifications to the plant, training of operators and mechanics, outage planning, and 25 other activities that are replicated on each unit. 26 Other advantages include that Palo Verde provides continuous clean and reliable

27 power to the customers of the Owners in the Southwest. Since it started operation in 1986,

28 the electricity generated by Palo Verde has enabled its Owners to avoid the emission of

29 significant amounts of carbon dioxide, sulfur dioxide (which contributes to acid rain), and

30 nitrogen oxides (which contribute to the formation of ground level smog). The electricity


l EPE sells to its customers is generated using a variety of fuels and methods, the largest

2 percentage of which comes from the nuclear energy produced at Palo Verde.

3 4 Q. ARE THERE UNIQUE CHALLENGES RESULTING FROM THE PALO VERDE

5 PLANT CONFIGURATION?

6 A. Yes. The three Palo Verde units and Water Resources Facility occupy a large footprint

7 relative to other nuclear plants, with the units being approximately 1/4 mile apart. 8 Palo Verde's large footprint, approximately 4,000 acres, also gives it a unique challenge

9 relative to the country's three other three-unit nuclear power plants (which cover 840,700, 10 and 510 acres). The sheer size requires larger physical security systems and a greater

11 number of security guards in order to meet operational and regulatory requirements. There

12 also is minimal sharing of systems between the three units. All of these factors require

13 additional staff. As an example, each unit has its own separate control room (versus a

14 shared control room as is found in many two-unit plants) requiring three sets of operators.

15 Each unit also has a chemistry lab, which must be staffed by chemists at each location.

16 The CE System 80 plant, by design, has approximately 20% more pumps, motors,

17 valves, etc., than other comparably sized Pressurized Water Reactors, such as the South

18 Texas Project and Waterford nuclear stations. The CE System 80 plant was designed for

19 greater reliability; however, more people are required to maintain and operate the 20 additional equipment. Because the units are identical, an issue at one can be transportable

21 to the other units. A degraded or non-conforming condition in any one unit must

22 immediately be analyzed in the other two units to determine if it is applicable there.

23 Therefore, a design or maintenance issue in any unit could require actions (including shut

24 down) to be taken in all three units.

25

26 Q. PLEASE DESCRIBE THE PALO VERDE WATER RESOURCES FACILITY AND ITS

27 OPERATION.

28 A. One aspect of Palo Verde that distinguishes it from any other nuclear power plant in the

29 world is that it is not located on or near a large body of water. Therefore, it must obtain

30 water from other sources and must discharge any wastewater to a system that will not

31 adversely impact surface or underground water supplies. This unique aspect ofPalo Verde

Page 7 of35 DIRECT TESTIMONY OF TODD HORTON

1 1 isa necessary cost of doing business that is not incurred at any other nuclear power plant 2 in the world. The cost of water and maintaining the Water Reclamation Resources added

3 approximately $1.60/MWh to Operations and Maintenance costs during the test year.

4 Palo Verde purchases its cooling water from wastewater treatment plants located in

5 the greater Phoenix area (Glendale, Mesa, Phoenix, Scottsdale, and Tempe, (the Sub

6 regional Operating Group "SROG"), and Tolleson). The SROG and Tolleson wastewater

7 treatment plants' effluent gravity flows westward for 28 miles in an underground pipeline

8 to the Hassayampa River basin due to the natural decrease in elevation. From the

9 Hassayampa River, it is then pumped eight miles to Palo Verde overcoming the natural

10 increase in elevation from the Hassayampa River to Palo Verde.

11 Once received at Palo Verde, the effluent is treated at the Palo Verde Water

12 Resources Facility to remove minerals that would otherwise damage or cause scaling on

13 vital plant cooling components. After being treated, the water is stored in either one of

14 Palo Verde's on-site 45-acre or 85-acre reservoirs. When cooling water is needed, it is

15 pumped to the cooling towers where it is cycled more than 25 times before a small amount

16 (less than 5%) is discharged to one of the three evaporation ponds. The remaining 95% of

17 the cooling water is gradually lost to the atmosphere through cooling tower evaporation.

18 Palo Verde understands that conserving water is important for the future of the Southwest.

19 Water Resources Facility operations described above represent a separate on-site

20 water treatment plant with a staff of approximately 120 people, along with chemicals,

21 materials, and supplies. Additionally, as a zero liquid discharge plant, Palo Verde must

22 also operate and maintain three very large evaporation ponds (covering 250,220, and

23 180 acres, respectively for a total of 650 acres) until all standing water from the cooling

24 tower discharge evaporates. In all other nuclear plants, the cooling water would simply be

25 discharged into the river, lake, or ocean. Photograph TH-2 shows the PVGS path of

26 effluent water.

17 /

28 /

19

30 /

31 /


Palo Verde Effluent Flow Path A To Atmosphere

4

3 ! 1

4

5

' • : ? , I' l.'.*I"I'*"ill !1 I

5 I , Ifr.- 41* op~ 4 r '·\?' A ij~' ~Ii€ t'·.· d ~-..... --- . -1. -./.~..'..'1 1,1 1 „.. ,!1 1

4

~ Water Effluent from Phoenix and other Communities (~) Units 1, 2 and 3

~ Water Resources ~ Cooling Towers

~ 46-Acre Reservoir ~ Evaporation Ponds

~ 85-Acre Reservoir

Photograph TH-2 - Palo Verde Station Efnuent Water Flow Path

As just mentioned, PVGS could not generate electricity without the Water

Resources Facility, which is unique to PVGS relative to the rest of the nuclear industry.

Q. WHAT IS APS' ROLE IN OPERATING PALO VERDE?

A. Pursuant to the contract between and among the Owners (referred to as the Arizona Nuclear

Power Project Participation Agreement), APS is the NRC operating license holder and

operating agent of Palo Verde. In this regard, APS manages the employees and contractors

working at Palo Verde, and makes decisions with regard to the safe and reliable operation

of the Station such as scheduling maintenance and refueling outages, shutting a unit down

for an outage when an issue arises, and restarting a unit after an outage. APS confers with,

and receives approval from, the Owners on a number of things, including all major capital

projects. The involvement ofthe Owners in Palo Verde operations is facilitated by several

committees, including the Administrative Committee, which is comprised of Owner senior

executives, and the Engineering and Operating ("E&O") Committee which is a diverse


\1

C to

-

1 working level group comprised of representatives from all Owners. Many aspects of

2 nuclear power plant operations are affected by regulations promulgated by the NRC.

3 4 IV. PVGS Capital

5 A. Monitoring and Approval Process of Capital Costs

6 Q. ARE YOU PRESENTING EPE'S RATE REQUEST FOR PALO VERDE CAPITAL

7 EXPENDITURES AND COSTS?

8 A. No, I am not. As discussed previously, EPE witness David Hawkins presents EPE's rate

9 request related to Palo Verde capital costs. I support that request by providing information

10 about these capital costs and projects. By "capital" I mean those projects that are

11 capitalized for accounting purposes under the Federal Energy Regulatory Commission's

12 ("FERC") Uniform System of Accounts. I will sometimes use the terms "capital

13 additions," "capital improvements," or "capital projects" to mean the same thing.

14

15 Q. WHAT IS THE PVGS APPROACH TO EFFICIENT CAPITAL COST

16 MANAGEMENT?

17 A. The goal of cost efficiency, as stated in the PVGS mission statement, focuses on "SAFELY

18 and efficiently generating electricity for the long term." Rigorous capital project

19 development and oversight ensures that the plant continues to operate safely and efficiently, 20 while associated expenditures are managed appropriately.

21 PVGS utilizes a variety ofmeasures to ensure that costs are managed appropriately.

22 These include informal cost comparison with other peer nuclear facilities, developing our

23 leaders' business acumen, and using strategic methods such as the Site Top Ten Technical

24 Issues and Long Range Planning programs to prioritize capital projects. For example, the

25 Long Range Planning program provides guidelines to systematically plan for major projects

26 including plant modifications and major maintenance activities. Proactive project design and

27 development milestone requirements allow PVGS to anticipate and schedule the required

28 work and related activities to reduce cost. Effective Long Range Planning increases

29 equipment reliability, assures the right timing of major projects and component 30 replacements, improves outage performance, and manages future budgets and resources to

31 proactively head off technical and life-cycle issues before they emergently affect plant


1 reliability or nuclear safety. Variance reports are prepared each month and are reviewed by

2 PVGS management and the Owners. During planned refueling outages, PVGS regularly

3 reports on budget versus actuals in order to monitor and control expenses.

4 In addition, capital projects are vetted through a multi-tiered process with approvals

5 being required internally at PVGS and unanimously by the Owners. The process of review

6 and approval of capital modifications is designed to ensure that proposed projects undergo

7 several layers of scrutiny and review to demonstrate they are necessary and reasonable. 8 Plant modifications that will gain safety margin and increase plant reliability, such as the

9 Unit 1 Digital Upgrade - Generrex Project, are discussed later in my testimony. PVGS

10 management and all Owners review and approve all capital projects to ensure that capital

11 improvements at PVGS are consistent with the needs of all the Owners and are in the

12 interest of their customers. Lower-cost work authorizations are approved by the

13 E&0 Committee, whose chair is the Palo Verde Senior Vice President of Site Operations,

14 while higher-cost work authorizations require Administrative Committee approval. The

15 Administrative Committee is chaired by the PVGS Executive Vice President and Chief

16 Nuclear Officer.

17 Cost effectiveness efforts also focus on budget development and control. Budget

18 assumptions, such as staffing, timing, and duration of outages, are established by the 19 Business Operations Department after working with other groups at Palo Verde. This

20 allows each of the business groups at Palo Verde to identify necessary work and begin the

21 process of assembling their budgets. Thereafter, managers and executives review the

22 proposed budget and scope in a series of meetings. The resulting draft budget is then

23 submitted to the Owners.

24 Once the budget is unanimously approved by the Owners, Palo Verde leaders and

25 the Business Operations Department actively track the projects. Furthermore, to remain

26 current on status and emergent work, Business Operations analysts regularly interface with

27 leaders to monitor and assist in the oversight of costs throughout the year. This oversight

28 includes a review and challenge of costs, cost accruals and cash flow forecasts, contract

29 services, contract labor, staffing, and overtime. Site leaders also work together to

30 determine what work can be modified or deferred, to free up budget money should an


1 emergent funding need arise. Monthly Executive Cost Reports detailing all aspects of the

2 capital budget also are provided to the Owners for further information and oversight.

3

4 Q. WHAT IS THE STRUCTURE OF THE PALO VERDE CAPITAL BUDGET?

5 A. The capital budget is organized into categories, as discussed below, which are used for

6 management and oversight ofthe projects in the budget.

7 1. PI,ANT MODIFICATIONS - Changes to the plant design, including simulator and

8 process computers, but excluding all Water Resources Facility items and non-

9 power block buildings.

10 2. PLANT EQUIPMENT & REPLACEMENTS - This category includes the two

11 following groups:

12 • TOOLS AND EQUIPMENT - Used predominantly to perform routine and

13 repetitive maintenance, construction, and training activities. This excludes

14 items incidental with the purchase of other systems, equipment, and

15 consumable materials.

16 • REPLACEMENTS - Replacement of Retirement Units "in kind" or intended

17 to be "in kind," excluding items which are included in General Plant,

18 Computers, or the Water Resources Facility.

19 3. BUILDINGS - Initial construction and qualified remodel as required of buildings

20 structures and facilities, including roof replacements and initial furnishings.

21 4. GENERAL PLANT - Predominantly consists of communications-related

22 equipment, rolling stock (vehicles), land purchases, and road and parking lot

23 installation.

24 5. INFORMATION TECHNOLOGY ("IT") - Non-process computer hardware and

25 software, computer license agreements, and miscellaneous computer equipment in 26 support of Plant activities including Nuclear Fuel Management.

27 6. WATER RESOURCES FACILITY - All water resources facility modifications,

28 replacements, and process computers not covered in other categories.

29 7. OVERHEADS - Overheads in support of Capital Improvements and Distributables

30 in support of Plant Modifications and Plant Replacements.

31 8. EMERGENT WORK FUND - Funding for any emergent capital projects not


1 individually identified or budgeted or for unexpected costs identified during 2 previously planned capital project development or implementation. 3 9. FUKUSHIMA/MAJOR STRATEGIC PROJECTS - Category set aside for NRC-

4 mandated large strategic capital projects requiring special attention.

5

6 Q. CAN YOU DESCRIBE DISTRIBUTABLE AND OVERHEAD COSTS IN MORE

7 DETAIL? 8 A. Distributable and Overhead costs are incurred for the overall support of the capital

9 programs and personnel. These costs are charged to the capital projects monthly. The

10 Overheads budget category includes costs that are incurred in support of capital projects 11 by Palo Verde Supply Chain Management, Business Operations, and other groups.

12 Distributables include personnel support for project management and includes mainly

13 planners and schedulers for plant design modifications.

14 15 Q. ARE THERE FURTHER REVIEWS OF THE CAPITAL BUDGET BY PROJECT?

16 A. Yes. As previously discussed, Capital budget approval only indicates Owner concurrence

17 to fund the capital project program at a certain level for a budget year. Projects are 18 presented individually to the E&O Committee throughout the year using Work

19 Authorization packages that include a business case and financial analysis for the proposed

20 project. Projects above $500,000 must be approved by both the E&O and the executive-

21 level Administrative Committees. Except for emergent issues that must be addressed

22 immediately, APS may not spend money or otherwise proceed with project implementation

23 until the project has been reviewed and approved by the applicable Owner Committee(s).

24 This process allows Owners the opportunity to review and ask questions about proposed

25 projects to help ensure that these investment expenditures serve customer interests and

26 allow the site to adapt to changing conditions as needed.

27

28 Q. WHAT DO YOU CONCLUDE ABOUT THIS PROCESS FOR THE REVIEW AND

29 APPROVAL OF CAPITAL EXPENDITURES?

30 A. The process of review and approval of capital expenditures is designed to ensure that

31 proposed projects undergo several layers of scrutiny and review to demonstrate they are

Page 13 of 3 5 DIRECT TESTIMONY OF TODD HORTON

1 necessary and reasonable. Review and approval is required by PVGS management and

2 also requires unanimous approval ofthe Owners. The approval process ensures that capital

3 improvements at PVGS are consistent with the needs of all the Owners and in the interest

4 oftheir customers.

5 6 B. PVGS Capital Additions to Rate Base

7 Q. HOW HAVE YOU ORGANIZED THIS PART OF YOUR TESTIMONY?

8 A. In this part of my testimony, I discuss the capital projects at Palo Verde that have been

9 added since the test year in Docket No. 46831 and that EPE seeks to include in the rate

10 base, as explained by EPE witnesses Larry J. Hancock and David Hawkins. I first identify

11 what those capital additions are, then I discuss in more detail major individual capital

12 addition projects with significant costs, explaining why they were undertaken and general

13 project management of each. All project costs as stated are total plant dollars. Last, I

14 address the remaining projects, by category, using the categories of capital projects

15 outlined above.

17 Q. AT THE OUTSET, IS THERE ANY EVALUATION AND APPROVAL PROCESS TO

18 WHICH ALL OF THESE PROJECTS WERE SUBJECT?

19 A. Yes, there is. All of the capital additions and projects I discuss were subject to the same

20 budget and project management and oversight processes discussed previously.

21

22 Q. WHERE ARE THE CAPITAL PROJECTS AT PALO VERDE SINCE THE END OF

23 THE TEST YEAR IN EPE'S LAST RATE CASE, DOCKET NO. 46831 IDENTIFIED?

24 A. Schedule H-5.2a includes a list of all Palo Verde capitalized projects being requested in

25 rate base with actual costs of $100,000 or more (EPE share). Additional information about

26 Palo Verde capital expenditures of $100,000 or more (EPE share) for the previous five

27 years and the Test Year (together with projected projects for the next three years) is in

28 Schedule H-5.3a. The major capital projects are discussed in more detail below.

29

30 Q. HOW MUCH IN RATE BASE ADDITIONS IS THE COMPANY SEEKING FOR

31 PALO VERDE?


1 A. The testimony of EPE witness David Hawkins supports the rate base additions EPE is

2 seeking in this case for Palo Verde.

3 4 1. Major Capital Projects

5 Q. WHAT CRITERIA HAVE YOU USED TO DISTINGUISH MAJOR INDIVIDUAL

6 CAPITAL ADDITION PROJECTS FROM OTHER PROJECTS?

7 A. PVGS has focused on replacing aging plant components to ensure that it continues to run

8 SAFELY and reliably for the long term. Projects that support this focus, including some

9 of which were mandated by regulatory agencies, are discussed below. Schedule H-5.2a lists

10 EPE project costs only. Table TH -1 below lists total cash project costs; EPE's portion of

11 total cash project costs is 15.8%. Note that when I give the cash cost or total cost of the

12 projects below, it is the total Palo Verde cash cost not EPE's share of the cash cost. Projects

13 that were not placed in service by the end of EPE's test year (December 31, 2020) are not

14 included.

15 There were approximately 600 plant capital projects placed in service from the end

16 of the previous test year through December 31,2020. Approximately $1.09 billion (total

17 project) was spent on projects placed in service through December 31, 2021. Figures

18 discussed below do not include Distributable or Overhead cost allocations.

19 Table TH-1 - Major Projects 20 14%p ...:.'.:"Il,1'..1„1!1:..!'.1.'..11.11111,1%1!1'MW.':11.11111,1.1'.W.1,1H~~[;~·~©1~h¥·•=·,1,11,: ·· ;

21 ~ ' ' ·i03,}W : .11 ~~,f:::·).~~:*yfdlio)„v.,D,+.~~,~,I.r.7~.*.k~'(~.B~,„, ,. ,.:,.~~t~·),;:~.f>:~~·,~~~. ,&,i.~,*~~.#'.'$,,'4.~i:.,, ~~·,:;·::·>:vtt.<k#:39&„ :~.,i.~~,.:>„, 22 23 24

25 26

27

90064 NUCLEAR ADMIN & TECH MAN $46.6M

100158 POLARCRANE UNIT 2 $31.?M'

110060 MAIN GENERATOR STATOR REWIND U2 $25.6M

200015 MAIN GENERATOR STATORREWIND:Ul $24.#M

190017 MAIN GENERATOR STATOR REWIND U3 $23.9M

Equipment and Replacements 1%*lipment anld Replacements Equipment and Replacements Equiphient andi~: Replacements Equipment and Replaeements

28 100095 NRC'S CYBER SECU*ITY REG;.PHASE 2 $2ti.7M Equi'?m©ntand Replacements

29 110043 DIGITAL UPGRD GENERREX U1 $20.5M Plant Modifications

30


1195

1 a. Nuclear Administrative and Technical Manual ("NATM") Upgrade

2 (Budget Category - Equipment and Replacements)

3 Q. WHAT IS THE NATM Project?

4 A. The purpose of the NATM project is to upgrade existing programs, processes and

5 procedures with high quality procedures that support the safe and efficient operation of

6 Palo Verde. These upgraded procedures facilitate training, corrective action program

7 investigations and institutionalize up to date industry human factor improvements that align

8 with Site Integrated Business Plan objectives. The project scope includes

9 (1) rewriting/upgrading/dispositioning Technical and Administrative Procedures and

10 documents, (2) developing Basis Documents for each upgrade procedure, (3) developing

11 and incorporating process mapping for specific Interdepartmental Process Administrative

12 Procedures, (4) dispositioning Palo Verde Policies and Policy Guides by incorporation into

13 Administrative Procedures/Administrative Guidelines or elimination, (5) benchmarking

14 industry best Quality Assurance Program practices, (6) developing/writing the Quality

15 Assurance Program and obtaining Nuclear Regulatory Commission approval,

16 (7) incorporating and implementing the approved Quality Assurance Program, and

17 (8) revising impacted procedures and programs. The NATM project was completed in

18 multiple phases.

19

20 Q. WHAT WAS THE TOTAL COST OF THE NATM UPGRADE?

21 A. The total cost of the NATM Upgrade capital additions from October 1, 2016 through the

22 end of the test year was approximately $46.6 million.

23 24 b. Polar Crane Replacement Unit 2


26 Q. WHAT IS THE UNIT 2 POLAR CRANE REPLACEMENT PROJECT?

27 A. The polar crane is an overhead crane located in the containment building of all three units

28 used for handling various loads including radioactive material. The polar cranes in each

29 unit are original plant equipment and are at the end of useful design life. The old polar

30 crane technology is approximately 40 years old and the Electrical Power Research Institute

31 has found that degraded or failed performance of electrical equipment, corrosion of


1 equipment is exacerbated by high ambient temperatures like those found in containment.

2 Polar crane replacement for Unit 2 was completed in the Fall of 2018. Units 1 and 3 were

3 completed in the Fall of 2020 and 2019 respectively.

4

5 Q. WHAT WAS THE TOTAL COST OF THE UNIT 2 POLAR CRANE REPLACEMENT

6 PROJECT?

7 A. The first or lead unit to undergo a modification or replacement generally carries the cost of

8 engineering and design for all units. In this case Unit 2 was the lead unit and was

9 completed for approximately $ 22.5 million. Unit 1 was completed for approximately

10 $14.9 million and Unit 3 was completed for approximately $11 million dollars.

11

12 c. NRC's Cyber Security Regulation


14 Q. WHAT IS THE NRC'S CYBER SECURITY REGULATION PROJECT PHASE 2?

15 A. In 2009 the Nuclear Regulatory Commission (NRC) established a new regulatory

16 requirement in response to the increasing cyber security threat. The first requirement of

17 the new regulation was the development and submittal of a License Amendment that

18 consisted of a Cyber Security Plan and compliance schedule. This project supported the

19 development and establishment of the Cyber Security Program for Palo Verde in support

20 of the implementation of the NRC cyber security regulations. Phase 1 included the

21 development of a business case through utilization of industry expertise in the area ofcyber

22 security and development of responses to the NRC's Requests for Additional Information

23 associated with the required Palo Verde license amendment submittal. Phase 2 is the

24 development and establishment of the detailed Cyber security programs, processes,

25 procedures, documentation and supporting systems required to effectively implement a

26 regulatory-compliant Cyber Security Program at Palo Verde. The final deliverable will be

27 a fully loaded computer system that supports the management of the Cyber Security

28 Program for PV. This computer system is, essentially, a complete set of automated

29 'reference manuals' procedures and support material that PV will use to manage PV's Cyber

30 Security Program.

31


1 Q. WHAT WAS THE TOTAL COST OF THE NRC'S CYBER SECURITY REGULATION

2 PROJECT PHASE 2?

3 A. The total cost of the addition of the NRC's cyber security regulation project Phase 2 was

4 approximately $20.7 million.

5

6 d. Main Generator Stator Rewind Unit 1, Unit 2 and Unit 3


8 Q. WHAT ARE THE MAIN GENERATOR STATOR REWINDS?

9 A. Each Unit at Palo Verde has a main generator which converts mechanical energy from the

10 high and low pressure steam turbines into electrical energy. The generator is both

11 gas-cooled and liquid-cooled utilizing low conductivity stator cooling water to remove 12 resistive heat losses from the generator windings. The expected life of the main generator

13 stator windings is approximately 30 years and is limited by the winding insulation life as

14 well as cooling water leaks which can cause equipment damage, forced outages and

15 increased maintenance costs. The main generator stator rewinds were completed in the fall

16 outages in 2018,2019 and 2020.

17

18 Q. WHAT IS THE TOTAL COST OF THE MAIN GENERATOR STATOR REWINDS?

19 A. The cost of the main generator stator rewind for Unit 1 was approximately $24.8 million,

20 Unit 2, $25.6 million and Unit 3, $23.9 million.

21 22 e. Digital Upgrade Generrex Unit 1

23 (Budget Category - Plant Modifications)

24 Q. WHAT IS THE DIGITAL UPGRADE GENERREX LIFE EXTENSION PROJECT?

25 A. This project represents the replacement ofthe Main Generator Excitation system on Unit 1.

26 The purpose of the Main Generator Excitation System is to control Main Generator

27 electrical output values. Palo Verde's Main Generator excitation and voltage regulation

28 system is a General Electric Generrex current potential source system. The excitation

29 system is the shortest-lived component ofthe electrical generators, with the life expectancy

30 ranging anywhere from 15-30 years. The excitation system in Unit 1 had reached the end

31 of its useful life and the end of vendor support for this system. This project included


1 structural upgrades, design services, the purchase of new equipment, installation, simulator

2 upgrade, design change packages and demolition of old equipment. Replacement of the

3 Main Generator Excitation System for Unit 2 was completed in 2015 and Unit 3 was

4 completed in 2016. 5

6 Q. WHAT IS THE TOTAL COST OF THE DIGITAL UPGRADE GENERREX PROJECT?

7 A. The cost of the Digital Upgrade Generrex project was approximately $20.5 million.

8 9 2. Remaining Capital Projects

10 Q. HOW ARE YOU ADDRESSING THE REMAINING CAPITAL ADDITION PROJECTS?

11 A. I address the remaining capital additions using the budget categories described previously. 12 Table TI I-2 shows the approximate total by budget category placed in service from the end

13 of the previous test year through December 31,2020.

14 Table TH 2 - Capital Projects by Budget Category 15 ~ 4. L,I|!4 i-LI , 'I i,i'|, il I jkr~ ic'h' 'Il I ti i 0' 'N'L * 4 AL 9.L:4*I. 'IA·, :++~ **".Ii!,a+iAi-~k i,~ I'~

ili, ii i,!lili I' JIJTI I.L-me~It- /4% LU $ 256.6

$ 463.4

$ 39.9

$ 42.7

$ 49.8

$ 134.6

$ 20.0

$ 1,007

iill 16

17

18

19

20

21

22

1- Plant Modifications

2- Plant Equipment & Replacements

3- Buildings

4- General Plant

5- Information Technology

6- Water Resources Facility

7- Major Strategic Projects

TOTAL

23 a. Plant Modifications

24 Q. WHAT IS THE "PLANT MODIFICATIONS" CATEGORY OF PROJECTS? 25 A. The Plant Modifications category covers changes to the plant design, including simulator

26 and process computers, but excludes all Water Resources Facility items and non-power

27 block buildings. It includes NRC and other regulatory mandates such as State of Arizona

28 environmental requirements, safety improvements, plant availability improvements, and

29 improvements made for other economic reasons.


1 Q. WHAT IS AN EXAMPLE OF PLANT MODIFICATIONS?

2 A. An example of a plant modification project is the replacement ofthe Spray Pond Filtration 3 System in Unit 3. Palo Verde is equipped with six essential spray ponds which serve as an

4 ultimate heat sink for the plant. The functions of the ponds are to remove decay heat from

5 the reactor during normal shut down and accident conditions and also to remove heat from 6 the Emergency Diesel Generators.

7 Each pond is a 100 percent capacity pond and two ponds are supplied for each unit,

8 allowing for redundancy should one pond not be available. These are large outdoor ponds

9 that receive makeup water from the Water Resources Facility, cooling tower blowdown

10 makeup, or domestic service water systems. Each pond has a gravity sand filter system to

11 maintain water quality. The backwash filters were severely degraded and had lost the

12 original design capability for automatic operation. Due to several other system constraints

13 the filter system flowrates were reduced, which prevented the proper conditioning of the 14 sand filter media. This level ofdegradation required frequent manual backwash operations

15 to prevent head tank and instrumentation overflows.

16 The scope of the project included complete modification of the entire Spray Pond

17 Filtration system with a new flexible, modular design to facilitate operations and

18 maintenance. This modification reduced the number of backwashes required, thereby 19 reducing the water requirements, as well as increased redundancy by adding a third sand 20 filter vessel. It included all mechanical, electrical and controls for a modular skid based

21 system. In addition to the modifications, the following spray pond filtration system

22 components were replaced: backwash sump pumps, spray pond filter equipment, filter 23 piping, and spray pond filters and filter pumps. 24

25 Q. WHY ARE PROJECTS IN THE PLANT MODIFICATIONS CATEGORY 26 REASONABLE AND NECESSARY?

27 A. Any plant modifications that are NRC-mandated are required to continue plant operation.

28 Other projects are reasonable and necessary to maintain high capacity factors and to

29 otherwise improve PVGS performance.

30


1 Q WHAT WAS THE TOTAL CAPITAL COST OF THE PLANT MODIFICATIONS

2 CATEGORY OF PROJECTS OVER THE TIME PERIOD IN QUESTION?

3 A. The total cost ofthis category was approximately $252.4 million.

4 5 b. Plant Equipment and Replacements

6 Q. WHAT DOES THE PLANT EQUIPMENT AND REPLACEMENTS CATEGORY

7 INCLUDE? 8 A. The Plant Equipment category includes two subcategories: (1) Tools and Equipment and

9 (2) Replacements. The Tools and Equipment subcategory is used predominantly to

10 perform routine and repetitive maintenance, construction, and training activities. This

11 excludes items incidental to the purchase of other systems, equipment, and consumable 12 materials.

13 The Replacements subcategory pertains to Replacement of Retirement Units "in

14 kind" or intended to be "in kind," excluding items which are included in General Plant,

15 Computers or the Water Resources Facility.

16 17 Q. WHAT ARE SOME EXAMPLES OF THE PLANT EQUIPMENT AND

18 REPLACEMENTS CATEGORY?

19 A. One example of the plant equipment and replacements category is the Low Pressure Feed

20 Water Heater Replacement Phase 1, Unit 1. The low pressure feed water heat exchangers

21 installed inside the condensers, pre-heat feed water that is then delivered to the steam 22 generators. Pre-heating the feed water improves the thermodynamic efficiency of the

23 steam cycle. Each unit has 3 condensers, each with 4 low pressure feed water heaters. Due

24 to the system design, certain heating stages incur considerably more wear than others. Due

25 to their age and condition, the low pressure feedwater heaters were experiencing tube

26 failures, resulting in the need for replacement. The project scope for Phase 1 included

27 initial project engineering and planning, 3D laser scan of condensers, construction and

28 installation of heater support structures to extract the existing heaters and replacement of

29 the low pressure feedwater heater.

30

31 Q, WHY ARE PROJECTS IN THIS CATEGORY REASONABLE AND NECESSARY?

Page 2 ] of 35 DIRECT TESTIMONY OF TODD HORTON

1 A. These projects are needed to replace aging equipment, to ensure reliable unit operations for

2 the Owners and their customers.

3

4 Q. WHAT WAS THE TOTAL CAPITAL COST OF THE PLANT EQUIPMENT AND

5 REPLACEMENTS CATEGORY OF PROJECTS OVER THE TIME PERIOD IN

6 QUESTION?

7 A. The total cost of this category was approximately $463.4 million.

8 9 c. Buildings

10 Q. WHAT DOES THE BUILDINGS CATEGORY INCLUDE?

11 A. The Buildings category includes initial construction and qualified remodeling of all

12 buildings, structures, and facilities, including roof replacements and initial furnishings.

13

14 Q. WHAT IS AN EXAMPLE OF A BUILDING CATEGORY PROJECT?

15 A. An example of a Building Category Project is the remodel of the Fix it Now ("FIN") service

16 building. This building has been in service for over 38 years. The building was originally

17 designed to support site maintenance and facility personnel, housing the auto shop/fueling

18 station, warehouse and loading dock, maintenance, tool room, quality assurance, radiation 19 protection processing, the battery rooms and the machine shop. Many of the buildings 20 systems are showing wear, including HVAC controls, lighting, electrical, IT infrastructure,

21 the 50 ton crane and the common areas. The project scope included refurbishment of the

22 building system and reconfiguration ofthe workspaces.

23

24 Q, WHY ARE PROJECTS IN THE BUILDINGS CATEGORY REASONABLE AND

25 NECESSARY?

26 A. The projects are needed to construct and upgrade Palo Verde buildings to maintain and

27 enhance Palo Verde's operational support.

28

29 Q. WHAT WAS THE TOTAL CAPITAL COST OF THE BUILDINGS CATEGORY?

30 A. The total cost ofthis category was approximately $39.4 million.


1202

1 d. General Plant

2 Q. WHAT DOES THE GENERAL PLANT CATEGORY INCLUDE?

3 A. The General Plant category predominantly consists ofcommunications-related equipment,

4 rolling stock, land purchases, station security, and road and parking lot installation.

5

6 Q. WHAT IS AN EXAMPLE OF THE GENERAL PLANT CATEGORY?

7 A. An example of a General Plant Project is the B-Safe Parking Lot Safety Improvements

8 project. The B-Safe Parking lot is the main parking lot for all Palo Verde employees. The

9 B-Safe lot did not meet current Americans with Disability Act ("ADA") standards nor the

10 Maricopa code standard, lacked adequate pedestrian safety enhancements and impeded

11 traffic flow in several places. The B-Safe Parking Lot Safety improvement project

12 addressed the following: ADA compliance, major crosswalk lighting, added shade

13 structures and drainage as well as other modifications. The cost of the project was


15

16 Q. WHY ARE PROJECTS IN THE GENERAL PLANT CATEGORY REASONABLE AND

17 NECESSARY?

18 A. They are needed to maintain routine support equipment and infrastructure and employee

19 safety in general plant areas. This also includes projects such as vehicle purchases, road

20 work, and sidewalk repair.

21

22 Q. WHAT WAS THE TOTAL CAPITAL COST OF THE GENERAL PLANT

23 CATEGORY?


25 26 e. Information Technology

27 Q. WHAT DOES THE INFORMATION TECHNOLOGY CATEGORY INCLUDE?

28 A. The Information Technology category includes non-process computer hardware and

29 software, computer license agreements, and miscellaneous computer equipment in support

30 of Plant activities including Nuclear Fuel Management.

31


1 Q. WHAT 1S AN EXAMPLE OF THE INFORMATION TECHNOLOGY CATEGORY

2 A. One example is the NRC mandated Probabilistic Risk Assessment Fire Model project. The

3 NRC Regulatory Guide governing the fire Probabilistic Risk Assessment ("PRA") model

4 became effective in April 2010. This required PVGS to produce a fire risk model that meets

5 the American Society of Mechanical Engineers ("ASME") 2009 PRA standard. Through

6 event analysis, target determination and development of PRA modeling, a PRA fire model

7 which complies with the ASME standard was developed. The cost of this project was


9

10 Q. WHY ARE PROJECTS IN THIS CATEGORY REASONABLE AND NECESSARY?

11 A. This category of projects is reasonable and necessary because it provides non-process

12 computer hardware and software, computer license agreements, and miscellaneous

13 computer equipment in support of plant activities including nuclear fuel management

14 evaluations.

15 16 Q WHAT WAS THE TOTAL CAPITAL COST OF THE INFORMATION TECHNOLOGY

17 CATEGORY OF PROJECTS OVER THE TIME PERIOD IN QUESTION?


19 20 f. Water Resources Facility

21 Q. WHAT DOES THE WATER RESOURCES FACILITY CATEGORY INCLUDE?

22 A. The Water Resources Facility category includes all Water Resources Facility

23 modifications, replacements, and process computers not covered in other categories.

24

25 Q. WHAT IS AN EXAMPLE OF THE WATER RESOURCES FACILITY CATEGORY?

26 A. An example of a project in the Water Resources Facility is the Solid Contact Clarifier Life

27 Extension, Train 2 and Train 5 project. A clarifier train is an essential system at the Water

28 Resources Facility, and is comprised of components that make up one o f the process steps

29 to treat effluent water from the SROG 91St Avenue and the City of Tolleson Waste Water

30 Treatment Plants prior to the water's use as cooling tower makeup. As the only nuclear


1 power plant in the world not situated on a body of water, Palo Verde's original design

2 included six clarifier trains.

3 Each clarifier train has the capacity to process 10,000 gallons per minute (gpm), for

4 a total of 60,000 gpm. There are six clarifier trains that are designated as Solid Contact

5 Clarifiers. The Solid Contact Clarifier equipment in train 2 and 5 had exceeded their useful

6 life and were showing signs ofdegradation. In order to extend the life ofthe clarifier, they

7 needed to be refurbished. 8 The scope of this project was for final design, procurement and refurbishment of

9 the Solids Contact Clarifier Train 2 and 5. The cost of this project was approximately

10 $42.7 million. 11 12 Q. WHY ARE PROJECTS IN THE WATER RESOURCES FACILITY CATEGORY

13 REASONABLE AND NECESSARY?

14 A. The Water Resources Facility supplies water required for plant operation.

15 16 Q WHAT WAS THE TOTAL CAPITAL COST OF THE WATER RESOURCES

17 FACILITY CATEGORY OF PROJECTS OVER THE TIME PERIOD IN QUESTION?

18 A. During this test period, the total Water Resources Facility capital cost was approximately

19 $134.5 million.

20

21 g. Overheads and Distributables

22 Q. HOW DOES PVGS HANDLE OVERHEADS?

23 A. The Overheads budget category includes costs incurred in support of Capital Improvements

24 and Distributables, Plant Modifications, and Plant Replacements. Since it is not practical

25 to assign certain costs to individual projects, the " Overheads" budget category accounts for

26 them. In general, the finance, procurement, stores, and contracts group are included. These

27 areas are given an allocation from the Capital Budget to account for their contributions to

28 all capital projects. Each month all charges to the Overhead project are allocated to all

29 capital projects according to the amount spent during the month.

30

31 Q. WHAT ARE SOME EXAMPLES OF THE OVERHEADS?


1 A. Overhead expenses include support personnel who, broadly, work on capital projects.

2 These costs also include a portion of PVGS personnel in the Business Operations group

3 and some Supply Chain personnel who address capital materials issues. They also include

4 insurance costs. Overhead dollars are allocated proportionally across capital projects that

5 had spending during the month.

6

7 Q. DO THE PROJECT COSTS PREVIOUSLY DISCUSSED INCLUDE OVERHEAD

8 COSTS?

9 A. No. Overhead costs are not included in the project cost estimates approved by Owners but

10 are later applied by Accounting as projects and are shown as construction work in progress

11 and later also in amounts transferred to plant in service. The budget to fund the Overheads

12 category is approved by the Owners in the annual budget review process.

13

14 Q. WHY ARE THE OVERHEADS REASONABLE AND NECESSARY?

15 A. Business Operations, Warehouse, Supply Chain, and other similar departments account for

16 the capital expenditures, issue capital purchase orders, fulfill material requests, organize

17 capital expenditures, and provide other necessary support for capital projects. These

18 functions are necessary to support capital projects but are administratively impracticable 19 to assign to specific projects so are allocated across all capital projects.

20

21 Q. HOW DOES PVGS HANDLE DISTRIBUTABLES?

22 A. Distributables include personnel support for project management personnel, mainly

23 planners and schedulers for projects that constitute changes in plant design called 24 modifications. These areas are given an allocation from the Capital Budget account for

25 their contributions to capital projects related to the physical Units. Each month, charges to 26 the Distributables project are allocated to capital Plant Modification type projects

27 according to the amount spent during the month.

28

29 Q. WHAT ARE SOME EXAMPLES OF THE DISTRIBUTABLES COST CATEGORY?

30 A. Examples of the Distributables Cost Category include the following: (i) support personnel

31 charges in support of project management and scheduling, (ii) costs that are incurred in the


1 overall support ofmodifications in the capital program, and (iii) charges for APS personnel

2 and supplemental labor that support project management and scheduling Palo Verde

3 modifications. These costs are allocated to the capital projects on a monthly basis as

4 discussed earlier in the discussion of overhead cost allocation.

5 6 Q. ARE THE COSTS OF DISTRIBUTABLES INCLUDED IN THE COSTS OF THE

7 CAPITAL PROJECTS YOU JUST DISCUSSED, BOTH THE INDIVIDUAL MAIN

8 PROJECTS AND THE CATEGORIES OF PROJECTS?

9 A. No, they are not included in the cost of projects discussed above. They are discussed

10 separately. 11

12 Q. WHY ARE PROJECTS IN THIS CATEGORY REASONABLE AND NECESSARY?

13 A. The prudent management of projects requires professional personnel to manage the cost

14 and schedule. Project Management and Business Operations personnel administer the

15 capital program by developing cost analyses and budgets for the program and monitoring

16 projects to track expenses and work plans.

17

18 Q. HOW WAS THE TOTAL COST OF THE OVERHEADS AND DISTRIBUTABLES

19 APPLIED TO EACH BUDGET CATEGORY?

20 A. A summary of the budget category costs, including the major projects, are provided in

21 Table TH-3.

12 /

23 / 14

15 / 16 / 17 /

28 / 19 /

30 /

31 /

Page 27 of 35 DIRECT TESTIMONY OF TODD HORTON 1207

1 Table TH-3 - Allocation of Overhead and Distributables Total Project 2 Budget Categories (millions)

3 1. Plant Modifications $29.03

4 2. Plant Equipment and Replacements 50.57

5 3. Buildings .98 6 4. General Plant 1.1 7 8 9 10

5. Information Technology .86

6. Water Resources Facility 3.41

7. Fukushima/Major Strategic Projects 1.12

11 TOTAL $87.07

12 13 h. Fukushima/Major Strategic Projects

14 Q. WHAT DOES THE FUKUSHIMA/MAJOR STRATEGIC PROJECTS FACILITY

15 CATEGORY INCLUDE?

16 A. This category is set aside for large strategic capital projects requiring special attention such

17 as those modifications mandated by the NRC after the 2011 events at the Fukushima

18 Nuclear Power Plant in Japan.

19

20 Q. WHAT IS AN EXAMPLE OF THE FUKUSHIMA/MAJOR STRATEGIC PROJECTS

21 CATEGORY? 22 A. An example of this category is the Mitigating Strategies Beyond Design Basis Manuals.

23 This project was undertaken as a result ofthe NRC order which came out ofthe Fukushima

24 Daiichi nuclear plant accident. The NRC order required, among other things, the

25 development of mitigating strategies for beyond design basis external events - also known

26 as "FLEX". The scope consisted of site-specific engineering criteria, FLEX

27 implementation and flooding evaluations. The results of the walkdowns, assessments and

28 evaluations resulted in the Beyond Design Basis Manuals which in turn set out policies and

29 procedures that govern the responses to a beyond design basis event. The cost of this

30 project was approximately $10.5 million.

31


1208

1 Q. WHY ARE PROJECTS IN THE FUKUSHIMA/MAJOR STRATEGIC PROJECTS

2 CATEGORY REASONABLE AND NECESSARY?

3 A. Projects related to Fukushima are required for regulatory compliance and major strategic

4 projects reduce station risk. These projects are necessary to maintain the key plant safety

5 functions of core cooling, containment integrity, and spent fuel cooling during a Beyond

6 Design Basis event. Additionally, the modifications were installed to allow use during

7 outages and other nuclear risk significant events thus reducing the nuclear risk. 8 9 Q WHAT WAS THE TOTAL CAPITAL COST OF THE FUKUSHIMA/MAJOR

10 STRATEGIC PROJECTS CATEGORY OF PROJECTS OVER THE TIME PERIOD IN

11 QUESTION?

12 A. During this time period Fukushima/Major Strategic Projects capital costs were

13 approximately $3 million.

14

15 V. PVGS Operation and Maintenance ("O&M") Expense

16 Q. ARE YOU PRESENTING EPE'S COST OF SERVICE REQUEST FOR PALO VERDE

17 0&M EXPENSE? 18 A. No, I am not. EPE witness David Hawkins presents EPE's cost of service request for

19 Palo Verde. However, I support that request by providing information about O&M costs

20 and practices at Palo Verde.

21

22 Q. WHAT IS THE PALO VERDE APPROACH TO EFFICIENT O&M MANAGEMENT?

23 A. O&M expenses represent the costs required to operate equipment or facilities from

24 day-to-day or to maintain equipment and facilities in good operating condition, including 25 but not limited to labor and material costs.

26 Labor costs include both direct and contract employee expenditures to support plant

27 requirements, overtime, and other related spend such as payroll taxes, benefits, and 28 pensions. Material costs include items such as plant equipment, tools, chemicals,

29 protective clothing, and office expenditures. While managing costs are an important focus

30 at Palo Verde, it is equally important to maintain a qualified workforce as well as the

31 equipment that produces reliable power for the Palo Verde Owners.


1 Palo Verde manages 0&M costs through a variety of initiatives. Examples of those

2 initiatives are discussed below:

3 • Palo Verde is utilizing strategic alliances when selecting vendors for contracting

4 services and material purchases (e.g., the Strategic Teaming and Resource Sharing

5 ("STARS") alliance). Membership in STARS provides a fleet-like advantage to four

6 independently operated nuclear power plants, Diablo Canyon, Wolf Creek, Calloway,

7 and Palo Verde, which all have similar Pressurized Water Reactor designs. The

8 alliance results in reduced costs and improved performance.

9 • Delivering the Nuclear Promise (DNP) is a nuclear industry-wide initiative begun in

10 December 2014. It is focused on transforming the industry and ensuring its viability

11 through efficiency improvements and strengthening the industry's commitment to

12 safety and reliability while promoting changes that fully recognize the value of nuclear 13 generation. Efficiency bulletins are issued for the industry based on implementation

14 classification. These bulletins align training standards and plant access across the

15 industry, eliminate low-value preventative maintenance tasks and reduce paperwork

16 associated with routine preventative maintenance.

17 • The "Transform Efficiently Maintain the Plant Organization (TeMPO)" project is the

18 Palo Verde compliment to DNP in that it is focused on implementation ofprocess and

19 efficiency DNP bulletins and right-sizing O&M spending so that the all-in cost of

20 Palo Verde's product remains competitive with other generation options. Palo Verde

21 has seen cost reductions in procurement, work management and work order 22 pre-approval processing.

23 • With the exception of the planned long refueling outages in the Fall of 2018, 2019 and

24 2020 to support the polar crane and generator rewind capital projects, the average

25 outage length has remained consistent at 31 days over the last 5 years (2016 - 2020).

26 Palo Verde continues to focus on achieving more effective refueling outages, which

27 reduce costs by reducing the amount of time that outage contractors are needed.

28 Effective outages usually result in improved annual net generation.

29

30 Q HOW DOES PVGS' COMPENSATION STRATEGY SUPPORT EFFICIENT O&M

31 MANAGEMENT?


1 A. PVGS implements the APS Total Rewards package, which includes a market competitive

2 base salary, short-term and long-term incentives, recognition programs, health and welfare 3 benefits, time off, savings and retirement programs and career development and 4 advancement opportunities. It is our goal to offer a competitive pay program to attract and

5 retain a high-performing workforce while managing all PVGS Owners' assets most

6 effectively. The principal compensation strategy is centered around the retention of key

7 employees using a fair and competitive analysis process. The APS and Palo Verde

8 compensation strategy includes a review of the labor market, internal equity, pay for 9 performance and cost effectiveness. Base pay and total cash compensation targets are

10 established at the 50th percentile of the competitive labor market. The company's intent is

11 to differentiate pay based on performance. High performing employees have a target base

12 pay and total cash compensation between the 50th and 90th percentiles of the competitive 13 labor market. The market pricing process is conducted annually to ensure employee pay

14 level and salary structure are competitive with the external market. PVGS' effective and

15 efficient plant performance is achieved by competitively compensating the workforce 16 which ultimately impacts 0&M costs.

17 18 Q. DOES THE WATER RESOURCES FACILITY IMPACT THE YEARLY SPEND AT

19 PALO VERDE?

20 A. Yes, as already discussed, Palo Verde is the only nuclear power plant in the world that has

21 its own Water Resources Facility. Operation of the Water Resources Facility represents

22 approximately $51.9 million (2020) in annual O&M costs that are not incurred by other

23 nuclear power plants. The Water Resources Facility O&M level corresponds to

24 approximately 8.5% of Palo Verde's total operating cost.

25 26 Q. HOW DOES PALO VERDE PLAN TO MANAGE COSTS GOING FORWARD?

27 A. We continue to take a measured and strategic approach to cost controls while investing in

28 the plant and people to maintain excellent material condition ofthe station and knowledge,

29 and performance of the people who run it for the long term. Initiatives such as DNP and

30 TeMPO described above are expected to continue to uncover opportunities for cost

31 management and aligning the organization. Using both data analytics and employee


1 feedback, Palo Verde is continually searching for inefficiencies embedded in processes,

2 work practices and organizational interfaces. By addressing delays that impede the

3 efficient execution of work and reviewing frequency of maintenance activities Palo Verde

4 can focus on improved work quality and reducing administrative burden and costs.

5 Palo Verde continuously looks for ways to improve so they can remain competitive and

6 invest for the future while supporting the station mission to "SAFELY and efficiently

7 generate electricity for the long term ".

8

9 Q. WHAT PROGRAM OR PROCESS IS IN PLACE TO ADDRESS OVERSIGHT AND

10 MANAGEMENT OF O&M EXPENDITURES AT PVGS?

11 A. Similar to the process I described regarding the PVGS Capital budget, the 0&M budget is

12 assembled each year by PVGS and submitted to the Owners for review and approval.

13 Budget assumptions are established by the Business Operations department after working

14 with department leadership at Palo Verde. Assumptions include such significant aspects

15 as PVGS staffing and duration of planned outages. This allows departments to identify

16 necessary work and to begin the process of assembling their budgets. A series of challenge

17 meetings are held involving PVGS leaders and executives to review the proposed budget

18 amounts and scope, all working towards budget submittal to the Owners. Once the budget

19 is approved, status is managed and overseen by PVGS leaders and the Business Operations

20 department. Business Operations analysts regularly interface with department leaders,

21 monitoring and assisting in oversight of costs throughout the year to update current budget

22 performance and identify emergent work. This oversight includes a review and challenge

23 of costs, cost accruals, cash flow forecasts, contract services, contract labor, staffing, and

24 overtime. PVGS leaders and Business Operations analysts then routinely meet with senior

25 Palo Verde management, where further challenges, trends, and goals are addressed. These

26 meetings are also intended to look at where budget impacts in one or more department can

27 be offset through cost savings in another department. The status is then provided in an

28 Executive Cost Report which provides further detail on aspects ofthe Palo Verde budgets.

29 During outages, the Business Operations department also queries cost expenditures,

30 compiling regular cost status reports that are then shared with leaders each business day.


1 The annual O&M budget must be unanimously approved by all Owners. A budget

2 update is provided to the Owners at each E&O Committee meeting, where challenges and

3 questions are presented to Palo Verde staff. Details of budget status are provided to the

4 Owners through the monthly Executive Cost Report. In addition, budget status is routinely

5 presented and discussed at meetings of the Owner Administrative Committee, which is

6 chaired by the Executive Vice President/Chief Nuclear Officer.

7

8 Q. PLEASE DESCRIBE PVGS COST REDUCTION EFFOR rS?

9 A. Since 2018 PVGS has undergone a focused effort to reduce costs, improve equipment

10 reliability and deliver summer capacity to its owners. Various efforts, as described

11 previously, are driving PVGS' O&M costs in a downward trajectory, as shown on

12 Figure TH-1 below. The trend in operating costs is due to Palo Verde's continued emphasis

13 on the balance between long-term sustainability of Station performance and cost

14 efficiencies. At the same time, due to capital improvements that have improved reliability

15 and reduced outage duration, as well as work process improvement from projects such as

16 the NATM upgrade project, Palo Verde's capacity factor has improved, which has directly

17 improved our operating costs on a dollar per MWh basis. Rigorous cost oversight and

18 management as well as implementation of cost-reduction actions and processes, have led 19 to more-efficient management of the budget and improved plant performance. The

20 relationship of plant performance (capacity) to O&M expenditures is measured by

21 operating cost per MWh.

22 23 Q. HOW DO PVGS/OPERATING COSTS COMPARE TO THE INDUSTRY?

24 A. Since PVGS is unique in the industry in supporting a Water Reclamation Facility, those

25 costs have been removed in Figure TH-1 below in order to give an accurate comparison to

26 the industry. The graph below shows Electric Utility Cost Group data - comparison of

27 Palo Verde operating cost per MWh to the industry average. PVGS, with lower cost

28 (excluding WRF) and higher capacity factors, has operating costs per MWh that were in

29 line with the industry average.

30 /

31 /


1 Figure TH - 1

2 2010-2020 OM $/MWh 3

23.00 4

5 22.00

6 21.00

7 20.00

8 9 19.00

10 18.00 --- -11 17.00 12

16.00 13 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

14 - -PVO&M (w/Incentives) $/MWh - Industry O&M $/MWh

15 EUCG Data - all costs are actual for the represented year

16 Industry Data Source is copyrighted by EUCG, Inc.

17

18 Q. WHAT AMOUNT OF TOTAL PVGS NON-FUEL O&M EXPENSE WAS INCURRED

19 DURING THE TEST YEAR?

20 A. The amount of non-fuel, unadjusted total Palo Verde O&M cost for the Test Year was

21 $609.40 million. The EPE share ofthis was 15.8 percent.

22

23 Q. WHAT DO YOU CONCLUDE ABOUT PVGS 0&M?

24 A. I conclude that PVGS costs are carefully scrutinized and are reasonable and prudent.

25 PVGS is a valuable asset to EPE and produces large quantities of safe, clean, reliable and

26 efficient power for its customers.

27 28 VI. Conclusion

29 Q. PLEASE SUMMARIZE YOUR TESTIMONY.

30 A. Palo Verde takes a deliberate approach to efficient cost management to ensure the safe and

31 reliable operation of the plant while providing energy at a reasonable cost. We take our

Page 34 of 35 DIRECT TESTIMONY OF l'ODD HORTON

1214

responsibility to the public at large, ratepayers and stakeholders, very seriously and have

put procedures and processes in place that help us meet that responsibility. Capital and

0&M costs were necessary and prudently incurred to maintain a safe, reliable and efficient

nuclear generating facility. EPE's Palo Verde cost of service, and rate base additions

request for PVGS are presented in the testimony of EPE witness David Hawkins.

Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?

A. Yes, it does.


Exhibit TH-1 Page 1 of 1

SCHEDULES SPONSORED BY T. HORTON

Schedule Description Sponsorship

E-1.2 OBSOLETE ASSETS Co-Sponsor H-1 SUMMARY OF TEST YEAR PRODUCTION O&M EXPENSES Co-Sponsor

(NUCLEAR & FOSSIL) H-1.1 NUCLEAR COMPANY-WIDE O&M EXPENSES SUMMARY Co-Sponsor H-1.la NUCLEAR PLANT O&M SUMMARY Co-Sponsor H-1.lal NUCLEAR UNIT O&M SUMMARY Co-Sponsor H-3 SUMMARY OF ACTUAL PRODUCTION O&M EXPENSES Co-Sponsor

INCURRED H-5.2a NUCLEAR CAPITAL COSTS PROJECTS Co-Sponsor H-5.3a NUCLEAR CAPITAL EXPENDITURES (HISTORICAL, PRESENT, Co-Sponsor

PROJECTED) H-12.2al MWh PRODUCTION BY UNIT FOR PREVIOUS 5 YRS (LIGNITE, Co-Sponsor

COAL & NUCLEAR

1216

DOCKET NO.

APPLICATION OF EL PASO § PUBLIC UTILITY COMMISSION ELECTRIC COMPANY TO CHANGE § OF TEXAS RATES §

DIRECT TESTIMONY

OF

R. CLAY DOYLE

FOR

EL PASO ELECTRIC COMPANY

JUNE 2021

1217

EXECUTIVE SUMMARY

R. Clay Doyle is Vice President of Transmission & Distribution ("T&D"). He is

responsible for overseeing the execution of all functions of El Paso Electric Company's ("EPE" or

the "Company") T&D Division. The Division's function is to ensure that the T&D system operates

in a safe, reliable, and efficient manner for the benefit of EPE's customers.

Mr. Doyle presents the transmission plant additions of $114,618,871 (total Company) that

were placed in service since the 2017 Rate Case through the Test Year end for this rate proceeding,

December 31, 2020. Mr. Doyle also presents the Texas distribution plant additions of

$296,135,245 that were placed in service since the 2017 Rate Case through the Test Year end for

this rate proceeding, December 31, 2020. In addition, Mr. Doyle sponsors the Test Year

operations and maintenance ("0&M") expense for transmission on a total Company basis of

$23,716,836 and the Test Year O&M expense for distribution on a total Company basis of

$26,381,814. And finally, Mr. Doyle presents EPE's proposed changes to the distribution line

extension policy as administered in the state of Texas.

His testimony demonstrates that the costs of EPE's T&D plant additions are reasonable,

necessary, prudent, and these additions are used and useful for safe, reliable, and efficient service to Texas customers. It also demonstrates that Test Year Period O&M expenses for T&D are

reasonable and necessary for safe, reliable, and efficient service to Texas customers.

DIRECT TESTIMONY OF R. CLAY DOYLE

TABLE OF CONTENTS

SUBJECT PAGE

I. Introduction and Qualifications 1 II. Purpose of Testimony ?

III. T&D Division Organizational Structurp ? IV. EPE's Transmission and Distribution System 5 V. EPE's Overall Quality of Service 8

VI. Identifying the Need for Transmission and Distribution Capital Investments.........15 VII. Processes and Procedures for Capital Investmentq 17

VIII. Transmission Capital Projects .....19 A. PROJECT NUMBER 1 - TL249 22 B. PROJECT NUMBER 2 - TL101 26 C. PROJECT NUMBER 3 - TL174 28 D. PROJECT NUMBER 4 - TH162 29 E. PROJECT NUMBER 5 - TA100 31 F. PROJECT NUMBER 6 - TL231 .... 33 G. PROJECT NUMBER 7 - TL127 34 H. ADDITIONAL TRANSMISSION CAPITAL PROJECTS 36

IX. Distribution Capital Project{~ 37 A. PROJECT NUMBER 1 - DT359 40 B. PROJECTNUMBER 2 - DT371 41 C. PROJECT NUMBER 3 - DT229 42 D. PROJECT NUMBER 4 - DT220 43 E. PROJECTNUMBER 5 - DT186 44 F. PROJECTNUMBER 6-DT189 ....45 G. PROJECT NUMBER 7 - DT365 47 H. OTHER DISTRIBUTION PROJECTS 48

X. Other Capital Projertq 48 XI. Transmission Operations and Maintenance 50

XII. Distribution Operations and Maintenance. 5? XIII. Changes to EPE Line Extension Policy 5 5 XIV. Conclusion 61

EXHIBITS

RCD-1 - Sponsored Schedules RCD-2 - WECC System Map RCD-3 - Southwest Area EHV Transmission Map RCD-4 - EPE Transmission System Map RCD-5 - Isleta Right of Way Presentation RCD-6 - Energy Policy Act of 2005, Section 1813 Indian Land Rights-of-Way Study RCD-7 - Project TL101 Photos RCD-8 - Project TA100 Maps RCD-9 - Transmission Projects Less than $4.5M and More than $1M RCD-10 - Distribution Projects Less than $4M and More than $1M RCD-11 - Line Extension Policy

i DIRECT TESTIMONY OF R. CLAY DOYLE

1219

Acronyms

AC Alternating Current AMI Advanced Metering Infrastructure AMS Asset Management Services AMT Asset Management Technologies ANSI American National Standards Institute BES Bulk Electric System CCN Certificate of Convenience and Necessity CIAC Contribution in Aid of Construction D3 Distribution Design and Delivery DEP Distribution Expansion Plan DDCM Distribution Design, Construction and Maintenance DO Distribution Operations EHV Extra High Voltage EPE El Paso Electric Company FERC Federal Energy Regulatory Commission HVDC High Voltage Direct Current kV Kilovolt MOD Motor Operated Device MPS Montana Power Station MRFS Meter Reading and Field Services MVA Mega Volt Ampere NERC North American Electric Reliability Corporation NESC National Electric Safety Code NMPRC New Mexico Public Regulation Commission NSI Network & Systems Integration 0&M Operations and Maintenance PNM Public Service Company of New Mexico PO Purchase Order PUCT Public Utility Commission of Texas PVGS Palo Verde Generating Station ROW Right o f Ways SAIDI System Average Interruption Duration Index SAIFI System Average Interruption Frequency Index SP System Planning

ii DIRECT TESTIMONY OF R. CLAY DOYLE

1220

Acronyms SPP Southwest Power Pool SPS Southwestern Public Service Company T&D Transmission and Distribution T&D/SP Transmission and Distribution/System Planning TEP Tucson Electric Power Company TESS Technical and Engineering Support Services Department TSEP Transmission System Expansion Plan TSR Transmission, Substation and Relay WECC Western Electricity Coordinating Council WMS Work Management System

iii DIRECT TESTIMONY OF R. CLAY DOYLE

1 I. Introduction and Qualifications

2 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.

3 A. My name is Robert "Clay" Doyle. My business address is 100 North Stanton Street,

4 El Paso, Texas 79901.

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 Vice President

8 of Transmission & Distribution.

9

10 Q. PLEASE SUMMARIZE YOUR EDUCATIONAL AND BUSINESS BACKGROUND.

11 A. I have a Bachelor of Science Electrical Engineering and a Master o f Science Electric

12 Engineering from New Mexico State University. I am a registered Professional Engineer

13 in the State of New Mexico. I have been employed by EPE since August of 1992. I have

14 served the Company in the capacity of Distribution Engineer, Supervisor of Distribution

15 Dispatch, Manager of Corporate Projects, Vice President of New Mexico Affairs, and my

16 current position as Vice President of Transmission & Distribution.

17

18 Q. PLEASE DESCRIBE YOUR PRINCIPAL AREAS OF RESPONSIBILITY.

19 A. My current responsibilities are to oversee the execution of all functions of EPE's

20 Transmission and Distribution ("T&D") Division. The T&D Division is, essentially, the

21 "wires" portion of EPE, which includes the Substations and Relays, Transmission and

22 Distribution Design, Construction and Maintenance, Meter Test, and Meter Reading and

23 Field Services subdivisions. It is my responsibility to ensure that all of these subdivisions

24 operate in a safe and reliable manner to provide T&D service to EPE's customers.

25

26 Q. HAVE YOU PREVIOUSLY PRESENTED TESTIMONY BEFORE ANY

27 REGULATORY AGENCY?

28 A. Yes. I have presented testimony before the Public Utility Commission of Texas ("PUCT"

29 or "Commission") and before the New Mexico Public Regulation Commission.

30

Page 1 of 61 DIRECT TESTIMONY OF R. CLAY DOYLE

1222

1 II. Purpose of Testimony

2 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?

3 A. The purpose of my testimony is to support the reasonable, necessary, and prudent costs to

4 provide safe, reliable, and efficient T&D electric service to EPE's customers. In particular,

5 my testimony addresses the following topics:

6 • The organizational structure of EPE's T&D Division and the functions and services

7 within the T&D Division,

8 • A description of EPE's T&D system and how EPE plans and operates its T&D system,

9 • The quality of service and reliability of EPE's T&D system,

10 • That EPE's transmission and distribution capital investments that were placed in service

11 from October 2016 through the December 2020 Test Year-end in this current case

12 (i.e., since the end ofthe Test Yearused in EPE's last base rate case, Docket No. 46831)

13 are used and useful, prudent, reasonable, and necessary,

14 • That the Operations and Maintenance ("O&M") costs associated with EPE's T&D

15 system during the Test Year were reasonable and necessary and should be reflected in

16 the Company's rates, and

17 • That EPE's proposed changes to its Line Extension Policy should be adopted.

18

19 Q. WHAT RATE CASE SCHEDULES DO YOU SPONSOR? 20 A. The schedules that I sponsor or co-sponsor are identified in Exhibit RCD-1.

21

22 Q. WERE THE SCHEDULES AND EXHIBITS YOU ARE SPONSORING OR

23 CO-SPONSORING PREPARED BY YOU OR UNDER YOUR DIRECT

24 SUPERVISION?

25 A. Yes, they were.

26

27 III. T&D Division Organizational Structure

28 Q. PLEASE DESCRIBE THE ORGANIZATIONAL STRUCTURE OF EPE'S T&D

29 DIVISION.

30 A. EPE's T&D Division is structured to operate efficiently and effectively to meet the needs

31 and challenges of an expanding electric energy delivery system. The T&D Division is


1 currently composed of three field operations departments and one operational support

2 department. The field operations departments are the Transmission, Substation, and Relay

3 Department ("TSR"); the Distribution Design, Construction, and Maintenance Department

4 ("DDCM"); and the Meter Reading and Field Services Department ("MR&FS"). The

5 operational support department is the Technical and Engineering Support Services

6 Department ("TESS"). The overall organization structure is shown in Figure RCD-1:

7 Figure RCD -I

8 9

10

Transmission & Distribution Division

- February 2021 -

EPE Transmission & Distributir,

Division .JI

11

12 13

msmlmmQN-LZE221 IBANi,4!&@QN. .ET*fl RE.AD»,6 &1*D TECHNICAL & ENGINEERING SUPPORT SERVICES

{TSR) (MR&FS) (TESS)

14

15 The field operations departments are responsible for the physical construction and

16 maintenance of the T&D system. All of EPE's union workforce or skilled labor ofthe T&D

17 Division report through the TSR, DDCM, or the MR&FS field operations departments.

18 Each department also has a staff of engineers, technical specialists, administrative

19 positions, or some combination thereof that support the design, construction, maintenance, 20 and operational viability of the T&D system.

21 The operational support department provides general support services for the field

22 operations departments. The TESS is responsible for support technologies such as the

23 Geographical Information System for mapping the geo-location of assets, the Work

24 Management System for work order estimating and resource allocation, as well as the

25 Standards group that maintains EPE's material and construction standards.

26

27 Q. DOES THE T&D DIVISION HAVE ANY PROGRAMS TO SUPPORT INTEREST IN

28 T&D CAREERS AND OTHER OPPORTUNITIES TO JOIN EPE'S WORKFORCE?

29 A. Yes, the T&D Division participates, and benefits from, the corporate Summer College

30 Internship Program. This internship program is designed to provide valuable on-the-job

31 experience in one of our corporate divisions and advance the participants' technical,


1 leadership and professional competencies through challenging work projects and training.

2 This unique program allows participants to network with executives and business leaders

3 in the Company, gain electrical utility work experience, and build transferable skills such

4 as problem-solving, teamwork, and effective communication. This paid program recruits

5 rising seniors and graduate students from colleges and universities throughout the country

6 who have a vested interest in the power industry with the goal of returning that talent back

7 to El Paso, Texas, or Las Cruces, New Mexico, upon graduation.

8 Additionally, EPE has partnered with the Dofia Ana Community College

9 ("DACC") in its Line-worker Certification Program to promote, train, support, and develop

10 individuals who are interested in a career in the various skilled positions within the electric

11 utility industry. The DACC Line-worker Certification Program includes two semesters of

12 course work with physical, technical field training followed by a 10-week working

13 internship with an electric utility (investor-owned electric utility or a rural electric co-op).

14 EPE, working in conjunction with DACC, recruits between eight and ten students to the

15 program each year. EPE also provides two part-time instructors, tuition scholarships for

16 those qualified, and the 10-week internship to finish their certification. The EPE/DACC

17 Line-worker Certification Program partnership has been in place for eight consecutive

18 years and has been tremendously successful in attracting and retaining motivated

19 individuals to EPE's skilled workforce.

20 Most of the students that successfully complete their DACC Line-worker

21 Certification (including their 10-week working internship with EPE) have hired on to EPE

22 full-time and joined EPE's Lineman Apprenticeship program. It should be noted that EPE's

23 current apprenticeship program complies with the commitment reflected in Finding of Fact

24 No. 56(e) in the Commission's final order (dated January 28,2020) in Docket No. 49849,

15 Joint Report and Application of El Paso Electric Company and Sun Jupiter Holdings, LLC,

26 and IIF US Holding 2 LP for Regulatory Approvals Under PURA §§ 14.101, 39.262, and

17 39.915.

28

29 Q. DOES THE DESCRIBED T&D STRUCTURE AND ORGANIZATION PROVIDE FOR

30 AN EFFECTIVE AND EFFICIENT OPERATION?


1 A. Yes. EPE has focused on conducting T&D Operations efficiently while providing safe and

2 reliable service. The described organization has allowed for T&D to leverage synergies

3 and maximize coordination across the Division. EPE's high and consistent performance in

4 reliability as measured by System Average Interruption Duration Index ("SAIDI") and the

5 System Average Interruption Frequency Index ("SAIFI") provides an indicator for the

6 effectiveness of EPE's T&D organization. EPE's SAIDI and SAIFI performance is

7 discussed below in Section V. The efficiency of EPE's T&D operations can be gauged, in

8 part, by EPE's O&M cost in comparison to other utilities, which is also discussed below in

9 Sections XI and XII of my testimony. The comparison in O&M cost indicates EPE's T&D

10 O&M cost compares favorably to peer electric utilities. 11

12 IV. EPE's Transmission and Distribution System

13 Q. PLEASE DESCRIBE EPE'S 345 KILOVOLT ("kV") AND 500 kV TRANSMISSION

14 SYSTEM.

15 A. EPE is a member ofthe Western Electricity Coordinating Council ("WECC") and is located

16 in the far southeast corner of the Western Interconnection, commonly referred to as the

17 Western Grid. WECC spans a geographic area that, starting with EPE's Texas service

18 territory, reaches north to include two Canadian provinces and stretches west to include all

19 or part of 14 western states as well as northern Baja California, Mexico. EPE is not

20 interconnected to the Electric Reliability Council of Texas. EPE is connected to the

21 Southwest Power Pool ("SPP") through an asynchronous High-Voltage Direct Current

22 ("HVDC") tie located in the Eddy County Substation near Artesia, New Mexico. In total,

23 EPE owns, in whole or in part, approximately 946 miles of multiple 345 kV transmission

24 lines, most of which are located within New Mexico. A copy of the WECC System Map 25 is attached to this testimony as Exhibit RCD-2.

26 EPE's 345 kV transmission system is composed ofthree key components: a series

27 of 345 kV alternating current lines that connect EPE's local transmission system in and

28 around Las Cruces, New Mexico, and El Paso, Texas, to the WECC interconnected grid;

29 the single 345 kV line that interconnects EPE's local transmission system to the

30 Southwestern Public Service Company ("SPS", a subsidiary of Xcel Energy, Inc.) in the

31 SPP through an HVDC terminal; and the 345 kV transmission lines that distribute power


1 imported from the WECC and SPP to EPE's local system. A copy of the Southwest Area

2 Extra High Voltage ("EHV") Transmission map of WECC System, showing EPE's service

3 territory, is attached to this testimony as Exhibit RCD-3.

4 EPE's major 345 kV transmission interconnections with other utilities are at the

5 (1) West Mesa Switching Station near Albuquerque, New Mexico, with Public Service

6 Company of New Mexico ("PNM"); (2) Eddy County HVDC Terminal near the City of

7 Artesia in Eddy County, New Mexico, with SPS; and (3) Springerville Generating Station

8 and Greenlee Substation (both in Arizona) with Tucson Electric Power Company ('TEP").

9 EPE also has a partial ownership interest in three 500 kV transmission lines in Arizona

10 from the Palo Verde Generating Station's switchyard to the Kyrene and Westwing

11 substations in Maricopa County, outside of Phoenix, Arizona.

12

13 Q. PLEASE DESCRIBE EPE'S LOCAL HIGH VOLTAGE TRANSMISSION SYSTEM.

14 A. EPE's local high voltage transmission system consists of highly networked 115 kV and

15 69 kV lines in and around El Paso, Texas and in and around Las Cruces, New Mexico.

16 This high level ofnetworking increases the reliability ofthe system by allowing the power

17 to re-route to other transmission lines during outages. A map showing EPE's local area

18 transmission system is attached to this testimony as Exhibit RCD-4.

19 20 Q. PLEASE DESCRIBE THE ROLE OF THESE TRANSMISSION SYSTEMS IN

21 DELIVERING POWER TO EPE'S RETAIL CUSTOMERS

22 A. EPE's service territory covers approximately 10,000 square miles extending from

23 Van Horn, Texas, to El Paso, Texas, to Las Cruces, New Mexico, and then further north to

24 Hatch, New Mexico. To serve these customers, EPE utilizes power from a variety of

25 resources. The first is EPE's remote, base-load generation at the Palo Verde Generating

26 Station ("PVGS") near Phoenix, Arizona. As noted above, EPE is a joint owner of a

27 500 kV system comprised of three transmission lines from PVGS that provide power to

28 our 345 kV system. To access and deliver this power, EPE utilizes its 345 kV transmission

29 system in southern New Mexico as well as an exchange agreement with TEP, a Power

30 Purchase and Sale Agreement between EPE and Freeport-McMoRan (formerly Phelps

31 Dodge Energy Services, LLP), and transmission wheeling purchased from third-party

Page 6 of61 DIRECT TESTIMONY OF R. CLAY DOYLE

1 providers to deliver power at EPE's three WECC interconnection points at West Mesa,

2 Springerville, and Greenlee.

3 EPE also has local generation resources that are interconnected to EPE's local

4 transmission network of 115 kV lines.

5 Additionally, EPE has, from time to time, entered into power purchase agreements

6 with SPS, which utilizes the Eddy County HVDC terminal to deliver power to EPE at the

7 direct current terminal. Once the power is on EPE's 345 kV system, it is delivered to EPE's

8 local high voltage transmission system through EPE's existing 345/115 kV

9 autotransformers. Once on the local transmission system (115 kV and 69 kV), the power

10 is distributed to EPE customers through substations that step the voltage down to the

11 distribution voltage level and out across the EPE distribution system.

12 13 Q. PLEASE DESCRIBE THE ROLE OF THE DISTRIBUTION SYSTEM IN

14 DELIVERING POWER TO EPE'S RETAIL CUSTOMERS.

15 A. The distribution system is the customer connection level of an electric utility's energy

16 delivery system. Physically, the distribution system is the collection of electric lines that

17 run down streets and alleys, and to which all homes and businesses are connected. All

18 distribution lines originate at a substation where a transformer reduces (or "transforms")

19 the energy delivered at transmission voltage (i.e., 69 kV and above) to energy at the lower

20 distribution voltage (i.e., 24 kV and below). The distribution lines coming out of a

21 substation are the distribution circuits or "feeders" that extend through the service area to

22 deliver electric energy to the customers. The lower distribution level voltage allows for

23 the use of smaller support structures that are easier to construct in populated areas.

24 The final connection between a home or business and the distribution system is

25 accomplished by yet another transformer (pole mounted or pad-mounted) that steps down

26 (again, "transforms") the energy delivered at the distribution voltage (24 kV, 14 kV, or

27 4 kV) to one of the standard service voltages for the home (120/240 Volts) or business

28 (277/480 Volts). And, of course, the physical connection of the home or business is the

29 point of metering.

30


1 V. EPE's Overall Quality of Service

2 Q. WHAT IS MEANT BY THE PHRASE "QUALITY OF SERVICE"?

3 A. Quality of Service, or reliability of service, refers to the ability of electric T&D systems to 4 perform as they were designed: to deliver utility grade electric power to end users reliably, 5 consistently and safely 24 hours per day; seven days per week, 365 days a year. 6

7 Q. HOW DOES EPE MEASURE THE QUALITY OF SERVICE IT PROVIDES TO ITS

8 CUSTOMERS?

9 A. EPE utilizes the indices defined in the Institute of Electrical and Electronic Engineers

10 Standard 1366-2012 to gauge system performance. Specifically, the two major indices are

11 SAIFI and SAIDI. EPE tracks and keeps record of every customer interruption event, by 12 jurisdiction, and reports annual SAIFI and SAIDI figures to the PUCT and NMPRC.

13

14 Q. CAN YOU DESCRIBE THE SYSTEM AVERAGE INTERRUPTION FREQUENCY

15 INDEX (SAIFI)?

16 A. The SAIFI refers to the average number of times that a customer connected to an electric

17 power system experienced an outage over a given period. It is calculated by dividing the

18 total number of customer interruptions during a given period by the total number of 19 customers being served over that same period.

20 21 Q. CAN YOU DESCRIBE THE SYSTEM AVERAGE INTERRUPTION DURATION 22 INDEX (SAIDI)?

23 A. Yes. The SAIDI refers to the average outage duration, in minutes, that a customer

24 connected to an electric power system experienced over a given period. It is calculated by

25 dividing the total customer-interruption-minutes for a given period by the total number of 26 customers being served over that same period.

27 28 Q. DOES THE PUCT REQUIRE TEXAS ELECTRIC UTILITIES TO REPORT THE SAIFI

29 AND SAIDI INDICES FOR THE UTILITY'S TEXAS JURISDICTION?

30 A. Yes. Since 1996, the PUCT has required each electric utility within its jurisdiction to

31 report, annually, its reliability indices in a specific format known as the Service Quality


1 Report. Additionally, in accordance with the final order in PUCT docket approving IIF

2 US 2's acquisition ofEPE, Docket No. 49849, EPE reaffirmed its obligation to continue to

3 provide this data to the Commission.

4

5 Q. PLEASE DESCRIBE THE MOST SIGNIFICANT INFORMATION THAT THE PUCT

6 REQUIRES IN ITS ANNUAL SERVICE QUALITY REPORT.

7 A. The PUCT's annual Service Quality Report requires each electric utility to report the SAIFI

8 and SAIDI indices for the utility's Texas jurisdiction (total Texas jurisdiction system), the

9 SAIFI and SAIDI indices for each individual distribution circuit (feeder) that serves more

10 than 10 customers, as well as a listing of outage cause types. For the feeder specific indices

11 (SAIFI and SAIDI), the PUCT report also requires a comparative ranking of all feeders

12 and therefrom identification of the 10% "worst performing circuits" (feeders).

13

14 Q. AS MEASURED BY SAIFI AND SAIDI, WHAT HAS BEEN THE LEVEL OF EPE'S

15 QUALITY OF SERVICE?

16 A. EPE gauges its overall quality of service performance by comparison of EPE's SAIFI and

17 SAIDI metrics to those of the other Texas utilities. The comparison group of other Texas

18 utilities includes Texas-New Mexico Power Company; Entergy Texas, Inc.; CenterPoint

19 Energy Houston Electric, LLC; Sharyland Utilities, L.P.;1 Southwestern Electric Power

20 Company; AEP Texas, Inc.; Oncor Electric Delivery Company LLC; and SPS.

21 Reliability indices compiled by the Commission show that EPE ranked No. 1 in

22 SAIFI and SAIDI (outage frequency and duration) between the years 2016 through 2020.

23 The following tables provide EPE's performance for years 2016 through 2020 per PUCT

24 annual Service Quality Reports in PUCT Project Nos. 46717, 47924, 49068, 50413, and

25 51730, respectively.

26 /

21 / 28 /

19 /

30 /

' Sharyland Utilities no longer provides distribution service, and its last service quality report was filed in 2018.


1 Table RCD-1

2 SAIFI

3 Year EPE Ranking EPE SAIFI Average SAIFI 4 2020 lst 0.53 1.05

5 2019 1St 0.72 1.14

6 2018 l St 0.44 0.97 7 2017 1St 0.58 1.04 8 2016 ist 0.41 1.10 9 10

Table RCD-2 11

SAIDI 12

Year EPE Ranking EPE SAIDI Average SAIDI 13

2020 1St 48.57 124.15 14

2019 lst 64.74 140.11 15

2018 1St 38.82 111.22 16 2017 rt 47.03 112.70 17 2016 rt 43.06 110.24 18

19

20 Q. GIVEN THE SEVERE WEATHER AND SERVICE DISRUPTIONS THAT

21 OCCURRED IN ERCOT IN FEBRUARY 2021, WHAT STEPS HAS EPE TAKEN AND

22 WHAT STEPS DOES IT PLAN TO TAKE TO PREPARE ITS T&D SYSTEM FOR

23 EXTREME WEATHER, BOTH HOT AND COLD?

24 A. Cold Weather Hardening

25 With regard to EPE's transmission and distribution systems, extreme cold

26 temperatures without precipitation do not usually result in outages beyond normal daily or

27 seasonal averages. However, cold weather events with precipitation (snow or freezing

28 rain) can result in serious, multiple concurrent, outage events that strain the Company's

29 resources and impact response/recovery time.

30 Distribution: At the distribution level, the overwhelming majority of outages

31 resulting from cold with precipitation events are caused by tree limbs and trees on the line.


1 More specifically, it is the snow or ice weighted tree limbs or trees that break or sag into

2 distribution lines that cause the outages.

3 EPE maintains an aggressive tree trimming, line clearing, program that proactively

4 trims or removes (where possible) trees and tree limbs in proximity to the distribution lines.

5 The general rule for tree trimming is to cut the branches back to a three-year growth rate

6 (i.e., it will take three years of growth for the branches to grow and interfere with our lines 7 again.) Obviously, some distribution circuits are more susceptible to tree related outages

8 than others just because ofthe geographical area they serve. EPE relies on recorded outage

9 cause data to direct its tree trimming effort to the areas most impacted by tree related 10 outages. 11 Transmission: At the transmission level, the outages resulting from cold with

12 precipitation events are usually caused by structure failures from conductor icing and wind. 13 Specifically, it is the additional weighting of ice on the conductors that causes the structure

14 failures and the combination of conductor icing with wind is particularly devastating.

15 Some of EPE's transmission lines extend far outside of EPE's customer service territory to

16 very remote mountainous or desert terrain. The micro-climates and weather events that

17 affect portions of EPE's remotely extended transmission lines can be, and often are, much

18 different from what we experience within EPE's customer service territory.

19 Based on past experience, EPE designs and builds its transmission lines to a specific

20 standard of conductor icing and wind loading above that defined by the National Electric

21 Safety Code ("NESC"). Although EPE's service territory technically resides in the NESC

22 "light-loading district" for line design specification, many ofEPE's 345 kV interconnecting

23 transmission lines traverse regions that are within the NESC "medium-loading district" that

24 specifies a more stringent design. EPE's practice of transmission line design/build above

25 the NESC recommended standard is driven from experience. Occasionally, there will be a

26 50-year or a 100-year weather event on a section of transmission line that will test the 27 Company's older, less stringent, design/build standards. Such an event happened in

28 November 2014. That event was a 100-year ice storm event that affected EPE's Amrad to

29 Eddy 345 kV transmission line in southeastern New Mexico. In brief, the results of that

30 storm were 1.5 to 3.0 inches of icing on the conductors and wind gusts of45 mph or more.


1 And, that combination of ice and wind was beyond EPE's older design standard and it

2 resulted in 17 miles of structure damage and the loss ofthe line for 18 months.

3 Experience guides future action and EPE has modified its design/build standards

4 for new transmission construction and continues to implement a plan to fortify EPE's older

5 transmission lines that were generally constructed to meet the NESC standards at the time

6 they were constructed.

7 Hot Weather Hardening

8 With regard to EPE's transmission and distribution systems, outages related to

9 extreme hot weather or heat events are a problem with or without precipitation. Hot and

10 extremely hot weather days create cooling demand at all customer levels, and therefore

11 increases the volt-ampere demand (loading) on all electrical equipment. Hot and extremely

12 hot weather events (multiple, concurrent days of hot weather) creates additional, "duty

13 cycle" strain, on load-serving equipment. Simply stated, the energized equipment

14 experiences a higher-than-normal loading for a longer-than-normal period of time and the

15 equipment never has a chance to cool off.

16 Transmission: At the Bulk Electric System ("BES"), transmission/substation level,

17 outages from extremely hot weather usually result in equipment failure due to heat stress

18 or thermal overloading. North American Electric Reliability Corporation ("NERC")

19 reliability standards require each owning utility to operate its transmission system within 20 the capacity ratings of the electrical infrastructure. In cases where a heat wave pushes a

21 transmission line or substation transformer loading to, or above, its capacity rating the

22 controlling utility is required to take immediate mitigating action to reduce the equipment

23 loading or take the equipment out of service before it fails. Because of these NERC

24 operating standards it is rare for a transmission line and BES level substation equipment to

25 fail simply due to hot weather or heat loading. Monitoring equipment and alarms usually

26 notify the System Operators who take action before a catastrophic failure happens.

27 The key to preventing heat related outages and equipment overloading at the BES

28 level is for the utility to pay close attention to, and plan for, seasonal loading, projected

29 load growth, and line/equipment load capacities and thermal ratings. Each utility's

30 compliance with the NERC mandated transmission planning requirements helps to ensures

31 that the BES line/equipment capacities and thermal ratings are not violated in peak load


1 operating scenarios. For most electric utilities in North America the peak loading scenario

2 is summer heat related loading. The NERC mandated transmission planning process, in

3 combination with the NERC mandated BES operating requirements, help identify and

4 drive a lot of the capital project investments of the utility. EPE, like all BES

5 owning/operating utilities, is in a constant cycle of planning for, and assessing, the loading

6 capacity and thermal ratings of its BES assets (high voltage transmission and substation

7 equipment).

8 Distribution: At the distribution system level there are no national standards or

9 planning requirements that compel a utility to continually monitor the load capacity or

10 thermal rating of distribution lines and equipment to prevent failure and outages. The

11 electrical infrastructure ofthe distribution system also has capacity and thermal ratings that

12 define the safe operating limits of each piece of equipment. The distribution system is the

13 customer connected level of the electric utility system and it is within the jurisdiction of

14 the state regulators. It is the state regulators, the customers, and the reliability metrics of

15 distribution systems (SAIDI and SAIFI) that gauge overall performance.

16 EPE relies on past performance outage data, in combination with internally

17 developed algorithms using customer meter data, customer connectivity information from

18 our Outage Management System, substation feeder metering data, and regional customer

19 load growth information to identify, or predict, distribution line and/or transformer

20 overloading situations. This annual line and transformer loading assessment effort begins

21 anew every fall after the summer peak season (May through September) as soon as the

22 summer data is validated and available. The annual assessment culminates in a list of

23 summer prep field activity (new distribution lines, distribution line rebuilding, load shifting

24 between feeders, feeder phase balancing, transformer additions or transformer size

25 upgrades, protective device coordination, etc.) that is executed through the pre-summer

26 loading months of January through May.

27 It is worth noting that, until recently, with the increased penetration of new energy

28 technologies (distributed generation, advanced metering, IoT enabled line devices and

29 sensors, energy storage, electric vehicles, etc.), there was not a whole lot ofreal-time data

30 or information on the performance of the distribution system for real-time operational

31 control and response. Again, with the revolution of new energy technologies deployed at


1 the distribution system level that is changing fast. EPE fully expects that its planned

2 deployment of an advanced metering infrastructure ("AMI") will unlock and enable a lot

3 of new, real-time and near real-time, system performance and that better information will

4 better inform decisions and planning.

5

6 Q. ASIDE FROM EXTREME HOT OR COLD WEATHER EVENTS, DOES EPE PLAN 7 AND DESIGN FOR ANY OTHER WEATHER CONDITIONS OR EVENTS THAT

8 CAN NEGATIVELY IMPACT EPE'S T&D?

9 A. Yes, in EPE's service territory, the top two 'tweather-type" descriptions associated with

10 transmission and distribution outages are lightning and wind. In the winter and spring

11 months, it is not uncommon to have windstorms with sustained winds of 50 to 60 mph and 12 gusts to 70 mph and above (hurricane force winds). Again, in the winter and spring

13 months, these windstorms will affect all, or large portions of, EPE's customer service

14 territory. The annual thunderstorm season in EPE's service territory ranges from mid-May

15 through the end of September. Whereas thunderstorm events tend to affect smaller areas 16 of EPE's service territory (more localized), the lightning activity is almost always

17 accompanied by high level of wind and wind-shear force on the overhead T&D

18 infrastructure. Lightning strikes, directly on, or sufficiently close to, the Company's

19 transmission and distribution lines, almost always result in outages. And, it is not just the

20 wind force loading on poles and other overhead equipment that topples structures and

21 causes outages, it is also the high-wind effect on trees and other debris that is blown into 22 the Company's lines and structures that causes outages.

23 Transmission: EPE mitigates the impact of windstorm/thunderstorm events by way

24 of design standards that incorporate lightning mitigation, regular line inspections and 25 patrols, tree trimming and ROW clearing, and with a proactive wood pole testing program.

26 By NESC clearance standards, high voltage transmission lines are constructed at a higher

27 elevation than distribution lines and are, usually, above most ofthe trees and vegetation in 28 urban and other moderately populated areas. Transmission lines that traverse forested land

29 can be susceptible to wind/tree related outages so EPE manages that risk by way of ROW

30 clearing of any trees (or man-made structures) tall enough and close enough to the 31 transmission line to cause an outage. On regular, predetermined intervals, EPE patrols the


1 route of each transmission line looking for ROW changes or obstructions and conducts a

2 visual inspection of each structure. And, finally, on an annual basis, EPE utilizes the

3 services ofcontractors to conduct above-ground and sub-surface structural inspections and

4 testing o f wood pole transmission structures.

5 Distribution: Again, experience guides future action and recognizing that lightning

6 and wind-related events are the two leading contributors of distribution level outages, EPE

7 has implemented an proactive tree-trimming program, a wood pole testing and treatment

8 program, lightning protection construction standards, and an annual grid maintenance

9 program. As described earlier in this testimony, EPE's tree-trimming program clears trees

10 and branches in proximity to its distribution lines and energized equipment to a three-year

11 growth perimeter. EPE also utilizes the services o f contractors to conduct an above-ground

12 and sub-surface inspections and testing of its distribution wood poles. EPE's distribution

13 design standards include a static line configuration for areas of historically high-lightning

14 activity and lightning-protection equipment (lightning arresters) on all transformers, line

15 switches, and end points. And finally, EPE conducts an annual distribution system

16 maintenance blitz in the month of February. The objective of the annual maintenance blitz

17 is to proactively repair, replace, and restore infrastructure that, for whatever reason (age,

18 loading, pole rotting, splitting, loose connections, etc.), may fail and cause or contribute to

19 an outage if left unattended.

20 All-in-all, EPE prudently plans, operates, and maintains its T&D system so that

21 reliable service can continue in the face of severe weather.

22 23 VI. Identifying the Need for Transmission and Distribution Capital Investments

24 Q. PLEASE DESCRIBE EPE'S SYSTEM PLANNING DEPARTMENT AND HOW IT

25 HELPS TO IDENTIFY THE NEED FOR TRANSMISSION PROJECTS.

26 A. EPE's System Planning Department plays a major role in the process of identifying needed

27 transmission infrastructure improvement projects. Currently, EPE's System Planning

28 Department is part of EPE's Asset Management Services Division. This department is

29 responsible for planning the expansion and assessing the continued operational capability

30 of EPE's transmission and substation systems, which consists of EPE's generating

31 resources, transmission lines, interconnections with neighboring systems, and any


1 associated equipment such as transformers. The process of system planning is necessary

2 to evaluate and identify the need for facilities to meet present and future load and to comply

3 with the operational requirements mandated by the WECC and NERC Reliability

4 Standards.2

5

6 Q. ARE ALL TRANSMISSION PROJECTS IDENTIFIED AND DEFINED THROUGH

7 THE SYSTEM PLANNING EFFORTS DESCRIBED ABOVE? 8 A. No. The need for some capital projects is identified and defined in the regular course of

9 EPE's annual O&M inspections, in response to an unexpected transmission asset

10 contingency event, or both. More often than not, EPE executes these capital improvement

11 projects immediately upon discovery when restoring the operational service of a

12 transmission asset (e.g., replacing a transmission structure that collapsed under extreme

13 weather conditions to return the line to service). However, some of these

14 "inspection-identified" or "event-caused" transmission replacement or repair projects

15 require more planning, equipment procurement time, or both, so they are added to EPE's

16 10-year capital projects plan, usually in the first or second year of the 10-year plan based

17 on their need. 18 It is also important to emphasize that some transmission projects are identified and

19 initiated by EPE's Distribution, Transmission, and Substation personnel. These groups are

20 responsible for monitoring and assessing the current and future operational capability of

21 the transmission, substation, and distribution systems. Through this continual monitoring

22 and assessment process, new substation, transmission, and/or distribution projects are

23 identified and analyzed. These projects are usually driven by customer load growth or

24 public infrastructure projects (e.g., Texas Department of Transportation projects) that

25 require relocation of EPE assets.

26

27 Q. HOW DOES EPE IDENTIFY THE NEED FOR NEW DISTRIBUTION PROJECTS? 28 A. Distribution system capital projects are driven by customer service requests, customer load

29 growth, service reliability improvements, and compliance with the American National

2 Although the NERC Reliability Standards do not apply to 69 kV assets, EPE applies the same reliability standards to its 69 kV system to ensure uniform reliability standards across its system.


1 Standards Institute ("ANSI") electric service standards. The ANSI standards define service

2 voltage standards and the acceptable range of variation above and below the standard.

3 (i,e.,the electric service voltage single-phase standard is 120/240 Volts with a maximum

4 variation from that standard of plus or minus five percent.). And, of course, some capital

5 projects are identified and defined in the regular course of EPE's annual O&M inspections;

6 in response to an unexpected distribution outage events caused by weather, vegetation, 7 vehicles, construction equipment, etc.; or a combination of both Distribution system

8 expansion projects are listed and defined in an internal document referred to as the 10-year 9 Distribution System Expansion Plan.

10 11 Q. PLEASE DESCRIBE THE INTERNAL APPROVAL PROCESS FOR NEW

12 TRANSMISSION AND DISTRIBUTION PROJECTS.

13 A. Transmission as well as distribution projects that are identified and defined in the 10-year

14 Transmission System Expansion Plan and the 10-year Distribution System Expansion Plan

15 follow a scoping process to define the requirements and priority of the projects. In the

16 scoping process, each project is reviewed with the applicable EPE departments to predefine

17 and identify any obstacles or conflicts associated with the proposed route or site, any land

18 or rights-of-way acquisition or permitting requirements, and any alternatives, and finally

19 the project's priority in order to schedule the required resources for the project. On an

20 annual basis, the T&D capital projects are presented to the T&D Capital Planning

21 Committee for approval and status updates.

22

23 VII. Processes and Procedures for Capital Investments

24 Q. DOES THE COMPANY HAVE PROCEDURES AND PROCESSES IN PLACE TO

25 MANAGE THE REASONABLENESS OF THE COSTS ASSOCIATED WITH T&D

26 PROJECTS?

27 A. Yes. In particular, non-stock materials and construction services for T&D projects

28 exceeding $50,000 are solicited through a formal competitive bidding process. Excluding

29 professional services, competitive bids are required for all non-stock purchases when the

30 total value of the goods or services equals or exceeds $25,000. Informal telephone and

31 email bids conducted by the requesting department are acceptable for purchases up to

Page 17 o f 61 DIRECT TESTIMONY OF R. CLAY DOYLE

1 $50,000. Requests for competitive bid negotiations are forwarded to EPE's Supply Chain

2 Management group for further processing and review.

3 A purchase requisition with all necessary information and approvals will then be

4 submitted to EPE's Supply Chain Management group for processing. All requests for bids,

5 with appropriate EPE bid number and bid due date, will be sent to a minimum of three

6 qualified and approved suppliers, provided that three qualified and approved suppliers for

7 that particular service or material exist.

8

9 Q. WHAT INFORMATION IS INCLUDED IN THE REQUEST FOR BIDS THAT EPE

10 PROVIDES FOR CONTRACTOR SERVICES?

11 A. Bid specifications will include a statement of work and clearly state the supplier's

12 obligations and responsibilities for all areas ofthe work or services to be performed. This

13 includes but is not limited to safety, sanitation, and all other aspects of the work to be

14 performed or provided. Bid specifications will include a time frame for the completion of

15 the necessary work or service. Specifications may also include a detailed performance

16 guarantee clause, if applicable. Pre-bid meetings and tours of the project site will be

17 conducted when appropriate.

18 19 Q. WHAT PROCESS DOES EPE FOLLOW WHEN IT RECEIVES THE BIDS FROM

20 SUPPLIERS?

21 A. Upon receipt ofthe bids, the Supply Chain Management group will issue a summary report

22 to the user who requested the bid. It will include price quotes by supplier, copies of the

23 bids, the recommended supplier, and the reason for the selection. All information received

24 pertaining to bid packages will remain strictly confidential. Supplier pricing and services

25 will never be discussed with other competing suppliers. Supply Chain Management may

26 notify all participants as to which supplier the bid was awarded. Work performed by

27 contractors or consultants will not begin until a purchase order ("PO") has been issued. In

28 all cases, contractors and consultants, including subcontractors, must provide proof of

29 required insurance before a PO will be issued.

30 The Company reserves the right to reject any or all bids. Additionally, the

31 Company reserves the right to deviate from written policies and related procedures when,


1 upon a showing of good cause and with the approval of senior management, it is in the best

2 interest of the Company and its customers.

3 4 VIII. Transmission Capital Projects

5 Q. WHAT AMOUNT OF TOTAL COMPANY TRANSMISSION ADDITIONS HAS EPE

6 PLACED IN SERVICE SINCE THE 2017 RATE CASE, DOCKET NO. 46831?

7 A. The Test Year in Docket No. 46831 ended on September 30,2016. From October 1, 2016

8 through the December 31, 2020 Test Year-end in this current case, the total Company

9 amount of additional transmission plant in service is $114,618,871. A complete list ofthe

10 total Company transmission capital projects that were completed and placed into service

11 over that period is provided by EPE witness Larry J. Hancock and listed in his Capital

12 Additions exhibit. EPE witness Hancock discusses the credits shown for two capital

13 projects (Ft. Bliss Industrial Substationand Texas Department ofTransportation Collector

14 Lane Project) for which the Company was reimbursed following our last base rate filing.

15

16 Q. HAS EPE PREVIOUSLY PRESENTED TO THE COMMISSION ANY OF THE

17 TRANSMISSION PROJECTS THAT IT SEEKS TO INCLUDE IN BASE RATES IN

18 THIS CASE?

19 A. Yes, it has. The projects were presented in EPE's first and only transmission cost recovery

20 factor ("TCRF") proceeding, which was Docket No. 49148. Transmission investments

21 from October 2016 through September 2018 were presented in that case, which was

22 resolved by settlement and the Commission's December 16, 2019, order. EPE is now

23 requesting that these projects be moved to and included in base rates in this case.

24 Transmission investments from October 2018 through December 2020 are being presented

25 to the Commission for the first time in this rate case. 26 27 Q. WHATARE THELARGEST TRANSMISSION PROJECTS LISTED IN EPE WITNESS

28 HANCOCK'S CAPITAL ADDITIONS EXHIBIT?

29 A. Table RCD-3, which is derived from Exhibit LJH-2, lists the largest non-blanket

30 Transmission projects (by total Company amount):

31


1240

Table RCD-3 2 Total 3 Project Company

4 5 6 7

8 9 10

Number Project Description Amount TL249 ISLETA PUEBLO LAND RIGHTS RENEWAL $ 16,824,750 TL101 RIO GRANDE TO SUNSET AND SUNSET $ 9,111,117

NORTH TRANSMISSION LINE UPGRADES TL174 LANE - COPPER 16900 LINE REBUILD $ 7,239,999 TH162 ARROYO AUTOTRANSFORMER ADDITION $ 7,022,925 TA100 LUNA TO SPRINGERVILLE RIGHT OF WAY $ 4,853,912

ACQUISITIONS AND RENEWALS TL231 MILAGRO - LEO 69KV TO 115KV UPGRADE $ 4,789,170 TL127 FARMER - FELIPE STRUCTURE $ 4,692,597

REPLACEMENT 11

12 Q. WHAT CRITERIA DO YOU USE TO DISTINGUISH LARGE TRANSMISSION

13 PROJECTS FROM OTHER TRANSMISSION PROJECTS?

14 A. The criterion I use is a total Company cost amount. The seven non-blanket projects, in the

15 table above, with a cost of $4.5 million per project or more are described below. While all 16 ofthe transmission capital projects that EPE requests be placed into rate base are used and

17 useful and have been constructed in a prudent manner at a reasonable cost, I describe the

18 projects over $4.5 million for ease in reference and to highlight the key transmission capital

19 projects since the Company's last rate case.

20

21 Q. WERE ANY OF THESE PROJECTS PREVIOUSLY PRESENTED IN EPE'S TCRF

22 PROCEEDING, DOCKET NO. 49148?

23 A. Yes, of the seven projects listed in Table RCD-3 above, six were previously included in

24 the Company's TCRF proceeding, Docket No. 49148.

25

26 Q. ARE THERE ANY DIFFERENCES BETWEEN THE PROJECT COST AMOUNTS

27 PRESENTED IN DOCKET NO. 49148 AND THE CURRENT RATE CASE?

28 A. Yes. Table RCD-4 lists those projects and the changes in project cost totals between the

29 TCRF proceeding and the current rate case.

30 /

31 /


1241

1 Table RCD-4 2 Project Company TCRF 3 4

5 6 7 8 9 10 11

12

13

Number Pro iectDescription Total Total Changes TL249 ISLETA PUEBLO LAND $16,824,750 $16,824,750 $ 0

RIGHTS RENEWAL TL101 RIO GRANDE TO SUNSET $9,111,117 $638,184 $8,472,933

ANDSUNSET NORTH TRANSMISSION LINE UPGRADES

TL174 LANE - COPPER 16900 $7,239,999 $5,398,563 $1,841,436 LINE REBUILD

TH162 ARROYO $7,022,925 $7,023,743 $ (818) AUTOTRANSFORMER ADDITION

TL231 MILAGRO - LEO 69KV TO $4,789,170 $4,789,170 $ 0 115KV UPGRADE

TL127 FARMER - FELIPE $4,692,597 $4,292,486 $ 400,111 STRUCTURE REPLACEMENT

14

15 Q. PLEASE EXPLAIN THE REASONS FOR THE DIFFERENCES IN COSTS

16 PRESENTED IN THE TCRF PROCEEDING AND THE CURRENT RATE CASE?

17 A. Any amounts closed to plant-in-service after September 30,2018 but before December 31,

18 2020 will show up as changes for all projects previously presented in the TCRF. These are

19 not unexpected costs; they are the costs to complete the planned additional phases of the

20 relevant project. There are three projects with large changes. Project TL101 - Rio Grande

21 to Sunset/Sunset North Transmission Line Upgrades has an increase of $8.4 million, which

22 is due to the completion of another portion of the total project, the ASARCO Mountain

23 phase, placed in service February 10, 2020. Project TL174 - Lane-Copper 16900 Line

24 Rebuild has an increase of about $1.8 million, which is due to a second and final project

25 phase placed in service January 2, 2019. And, Project TL127 - Farmer-Felipe Structure

26 Replacements has an increase of $400,000, which is due to expected and ordinary trailing

27 charges from the final project phase that was placed into service September 18, 2018.

28

29 Q. PLEASE DESCRIBE IN MOREDETAIL THE LARGEST TRANSMISSION PROJECTS.

30 A. I describe the projects below in the same the order as Tables RCD-3 and RCD-4 above.

31


1242

1 A. Project Number 1 - TL249

2 Q. WHAT IS PROJECT TL249 - ISLETA PUEBLO LAND RIGHTS RENEWAL?

3 A. This $16.82 million project extended EPE's legal access and right-of-way ("ROW")

4 agreements with the Isleta Pueblo for an 8.44-mile stretch of EPE's Arroyo - West Mesa

5 345 kV Transmission Line, shown in Exhibit RCD-5 and Figure RCD-2 below.

6 Figure RCD-2

7

8 o•..w.Y,ib.t n

10

11 12

13 14

Route of existing 345 kV line through tribal land

2-, L' '..

/2969-,oute~ :/ Isleta Pueblo Tribal Land :64 75 fnle route

i j 1 J '

15 1 :

1 1*Ir

111

16 One of EPE's three WECC interconnecting transmission lines, the Arroyo - West

17 Mesa 345 kV line, traverses the Isleta Pueblo Indian Reservation property near Los Lunas,

18 New Mexico. The overall length of the transmission line is 202 miles. A small portion of

19 this line, approximately 8.4 miles, is located on a 100-foot-wide ROW easement on tribal

20 land. When the construction of this line was completed in 1967, EPE entered into a

21 fifty-year ROW agreement in the amount of $4,398.75 with the Isleta Tribe, which expired

22 in 2017. This project captures the costs of the renewal of that ROW agreement with the

23 Isleta Pueblo for a term of twenty-five years.

24

25 Q. WHY WAS THE ISLETA PUEBLO LAND RIGHTS RENEWAL INVESTMENT

26 NEEDED?

27 A. The Arroyo - West Mesa 345 kV Transmission Line is one of three 345 kV lines

28 connecting EPE with its neighboring utilities and to the WECC. As such, this line is

29 extremely important to the functional ability of EPE to reliably import power from PVGS

30 and the other WECC connected utilities and to share resources for the security of not only

31 EPE's system but also its neighboring systems (e.g., PNM, TEP, etc.). Not having this


1243

1 transmission line would result in unacceptable consequences to EPE's operating capability

2 and its ability to serve its customers and would have negative impacts on EPE's

3 interconnecting neighbor utilities.

4

5 Q. PLEASE DESCRIBE THE CONTEXT IN WHICH THE ISLETA PUEBLO LAND

6 RIGHTS WERE RENEWED.

7 A. There are a couple of key points to be aware of regarding the context in which these land

8 rights were renewed. First, I am informed by counsel that federal law prohibits use of

9 eminent domain to access tribal trust land. Accordingly, EPE could not acquire a renewal

10 of these land rights through a lawsuit for condemnation.

11 Second, tribal jurisdictions across the western U.S. have been charging increasingly

12 higher payments for ROW renewals in recent years. In support ofthis second point, I have

13 included in my workpapers, a report by the U.S. Departments of Energy and the Interior

14 dated May 2007 and presented to the U.S. Congress titled "Energy Policy Act of 2005,

15 Section 1813 Indian Land Rights-of-Way Study" ("DOE Report"). The DOE Report

16 references an Edison Electric Institute survey dated 2006 showing that ROW costs over

17 tribal land exceeded the market value of the land by a median of six to twelve times.3 The

18 DOE Report also noted that tribal negotiators sought renewal fees that were based on

19 build-around costs in five cases with 2007 costs estimated to be $500 thousand - $1 million

20 per mile.4

21

22 Q. PLEASE DESCRIBE EPE'S EXPERIENCE IN RENEGOTIATING THE ISLETA

23 PUEBLO LAND RIGHTS.

24 A. EPE's experience was consistent with that described in the DOE Report with regard to

25 increased costs, and the DOE Report helps to verify that EPE's experience with the cost to

26 acquire ROW across the Isleta Pueblo lands was not unusual or an outlier. In the end, EPE

27 was able to negotiate a renewal price that was consistent with the expected cost range

28 (i.e., the six to twelve median multiplier) presented within the DOE Report. The negotiated

3 DOE Report at 67-68. A Id.


1 renewal price also compares favorably with the Company's estimated build-around cost,

2 which as explained below, was $29.8 to $64.8 million.

3 4 Q. DOES THE COMPANY HAVE CONTEMPORANEOUS DOCUMENTATION

5 SUMMARIZING EPE'S ANALYSIS OF THE ISLETA PUEBLO LAND RIGHTS

6 RENEWAL PROJECT?

7 A. Yes, EPE's analysis at the time of the renewal is reflected in the document I have attached

8 as Exhibit RCD-5. It is a PowerPoint presentation titled "Right-of-Way Extension

9 Update." This document was prepared with input from various internal EPE departments

10 and represents the knowledge, due diligence, and experience of the teams that worked on

11 this project. The document was presented to upper management and the Company's Board

12 of Directors for approval ofthe ROW renewal.

13

14 Q. ARE THERE PARTICULAR ASPECTS OF THIS POWERPOINT PRESENTATION

15 THAT DEMONSTRATE THE PRUDENCE OF EPE'S DECISION MAKING FOR THIS

16 PROJECT?

17 A. Yes, there are several aspects that deserve highlighting. First, I should point out that this

18 presentation reflects the underlying analysis that EPE personnel went through in evaluating

19 this situation. It also identifies the context in which this decision was made, which, as I

20 noted above, includes that (1) federal law prohibits use of eminent domain to access tribal

21 trust land and (2) Indian tribes across the West are charging higher payments for ROW

22 renewals. These points are also reflected on page three of the presentation, which is a

23 collection of quotations from an April 28 , 2014 , Wall Street Journal article titled " Indian

24 Tribes New Negotiating Power Costs Utilities." These quotations were included in the

25 presentation to illustrate EPE's understanding that, like EPE, other utilities have faced and

26 continue to face, similar increased costs and negotiating issues with the renewal of ROWs

27 over tribal lands. It is also consistent with the DOE Report described above.

28 Page five, which is titled, "System Impact of the Arroyo - West Mesa

29 Abandonment," is a critical part of the presentation because it fleshes out why the

30 Arroyo - West Mesa transmission line continues to be needed and shows the effect of

31 abandoning or not having that asset. As I noted above, losing the transmission line would


1245

1 result in unacceptable consequences to EPE's system and its ability to serve its customers

2 and would have negative impacts on EPE's interconnecting neighbor utilities.

3 Page six of Exhibit RCD-5 is a map titled "No Feasible Re-Route Options." The

4 map shows the two reroute options of 29.7 miles to the west and 64.8 miles to the east.

5 There are no north to south reroute options because the Arroyo - West Mesa 345 kV

6 transmission line already runs north to south. Based on my experience, a good "rule of

7 thumb" for a rough cost estimate for constructing a 345 kV transmission line in areas such

8 as this is at least $1 million per linear mile, and I am not aware of any particular reasons

9 why this amount would be any less for this particular area. That per-mile cost estimate

10 puts the prices for the west side reroute option and the east side reroute option at 11 $29.8 million and $64.8 million, respectively. From EPE's perspective, cost feasibility, as

12 compared to the option of renewing the Isleta Pueblo ROW agreement, was the first

13 threshold ofconsideration.

14

15 Q. WHAT WOULD HAVE BEEN THE CONSEQUENCES OF NOT RENEWING THIS

16 ROW AGREEMENT?

17 A. If EPE had not been able to negotiate and secure a new ROW and access agreement with

18 the Isleta Pueblo, this 8.4-mile portion of the Arroyo - West Mesa 345 kV line would have

19 been inaccessible to EPE without trespass because, as I am informed by legal counsel, EPE

20 lacks the ability to utilize condemnation for property located on tribal lands. Without this

21 segment, the Company could not operate this 202-mile transmission line. Operationally,

22 the loss of the use of this line would have lowered EPE's power total firm import capability

23 from 645 megawatts ("MW") to 448 MW. Under these conditions, EPE would not be able

24 to meet its load serving obligations under the NERC-required contingency capabilities. The

25 NERC-required contingency capabilities call for each utility to keep enough generation

26 capacity in reserve (ready and available) to cover the loss of the utility's largest single

27 resource. In simple terms, the utility has to have enough standby generation (energy

28 resources) to suffer the loss (failure) of its largest generator (largest functioning resource)

29 and still maintain service to all customers. With the Arroyo - West Mesa 345 kV line in

30 service, EPE can count generation capacity from PNM as additional generation resource to

31 comply with the NERC reserve requirements. Likewise, PNM can count generation


1 capacity available from EPE to meet their operational reserve requirement. This "counting"

2 of remote but connected generation resources to comply with the NERC reserve

3 requirement is commonly refer to as "reserve sharing."

4

5 Q. WAS PROJECT TL249 - ISLETA PUEBLO LAND RIGHTS RENEWAL

6 REASONABLE, NECESSARY, AND PRUDENT?

7 A. As discussed above, the project was necessary to secure the continued use of the vital

8 Arroyo - West Mesa 345 kV Transmission Line: one ofthree 345 kV lines connecting EPE

9 with its neighboring utilities and to the WECC. The cost paid for the ROW was reasonable

10 and prudent in light of similar agreements entered into by other utilities and the absence of

11 a less costly alternative.

12

13 B. Project Number 2 - TL101

14 Q. WHAT IS PROJECT TL101 - RIO GRANDE TO SUNSET AND SUNSET NORTH

15 TRANSMISSION LINE UPGRADES?

16 A. This is a multi-year, multi-phase, project to rebuild and re-conductor the 1 15-kV line

17 between EPE's Rio Grande and Sunset North Substations and the two 69 kV lines between

18 EPE's Rio Grande and Sunset Substations. The project is being executed in phases based

19 on the estimated construction time and available outage windows in the off-peak season. 20 Individual work orders are opened for each construction phase and are placed in service

21 when the new structures have been installed and the conductor on them is energized. In

22 Exhibit RCD-5 to my direct testimony in the Company's TCRF filing, Docket No. 49148,

23 I provided a projectdescription for TL101 of"PAISANO CROSSING (TXDOT)" because

24 that was the name of the project phase that had just been completed. The overall project

25 description for TL101 (inclusive of all phases) is "RIO GRANDE TO SUNSET AND

26 SUNSET NORTH TRANSMISSION LINE UPGRADES."

27

28 Q. WHAT PROJECT PHASES ARE INCLUDED IN THIS RATE CASE?

29 A. The major project phases placed in service between October 2016 and December 2020

30 include the previously mentioned Paisano Crossing and the recently completed "ASARCO

31 MOUNTAIN PHASE". This latest phase of construction is located along the portion of


1247

1 the Franklin Mountains by The University of Texas at El Paso campus. This portion of

2 TL101 replaced all of the H-frame wood pole structures over on the ASARCO mountain

3 with mono-pole steel structures and reconductored, with larger conductor, all lines

4 connected to those new steel structures. This was a particularly difficult project because

5 o f the mountainous terrain that required each structure to be supported by a drilled-pier,

6 concrete reinforced foundation. 7 During the planning stage of the project, two alternatives were developed and

8 considered to rebuild the transmission lines over the mountain: (1) constructing over the

9 mountain using a helicopter and (2) constructing over the mountain using more

10 conventional methods. In the end, EPE determined that the most cost-effective and most

11 functional alternative was Option 2.

12 Exhibit RCD-7 shows the terrain and the before and after project results.

13 14 Q. WHAT PHASES REMAIN TO BE COMPLETED IN THIS PROJECT?

15 A. As presently scoped, there are three more construction phases remaining in project TL101:

16 • The Cemex phase will replace all the structures and conductor in the area of the Cemex

17 quarry and cement plat west and south of Interstate 10,

18 • The Rio Grande-Paisano phase will replace all ofthe structures and conductor in the area

19 between Paisano Rd. and Rio Grande substation, and

20 • The Rim Road/UTEP phase will replace the remaining structures from the Rim Road

21 area, through the UTEP campus, and into Sunset and Sunset North substations.

22

23 Q. WAS PROJECT TL101 - RIO GRANDE TO SUNSET AND SUNSET NORTH

24 TRANSMISSION LINE UPGRADES REASONABLE, NECESSARY, AND

25 PRUDENT? 26 A. Yes, this project is reasonable and necessary and was constructed prudently. Each of these

27 transmission lines connects to and delivers generated electric energy to EPE's network of

28 distribution substations. These lines are over 50 years old, and this portion ofthese lines was

29 difficult to access and replace or repair. When completed5 the upgraded 69 kV lines will

30 provide a continuous capacity rating of l 11 MVA and emergency capacity rating of


1 147 MVA. These lines are important to the operational integrity of EPE's 115 kV and 69 kV

2 transmission-substation network and are vital to EPE's ability to serve customers.

3 4 C. Project Number 3 - TL174

5 Q. WHAT IS PROJECT TL174 - LANE - COPPER TRANSMISSION LINE REBUILD?

6 A. This $7.24 million project reconstructed and reconductored the 6.4-mile, 115 kV line

7 between EPE's Lane and Copper Substations in central El Paso, Texas.

8

9 Q. WHY WAS THE LANE - COPPER TRANSMISSION LINE REBUILD PROJECT

10 NEEDED?

11 A. The rebuild was necessary to serve customer and load growth. In the system planning

12 process described earlier, EPE's System Planning identified this line as an overloaded line

13 under certain operational scenarios and peak load conditions. To mitigate the potential

14 overloading of this line in those operating scenarios, System Planning determined that it

15 would be necessary to increase the capacity of the line to a minimum o f 170 mega volt

16 ampere ("MVA") as a continuous rating capability and 230 MVA as an emergency rating

17 to avoid violations of the NERC operating conditions and requirements.

18

19 Q. WHAT WOULD HAVE BEEN THE CONSEQUENCES OF NOT REBUILDING THIS

20 TRANSMISSION LINE?

21 A. The NERC operating conditions and requirements would not have been satisfied in certain

22 operating scenarios due to an overloaded transmission asset. It is mandatory under the

23 NERC Operating Standard for EPE to cure the overload in such circumstances. EPE met

24 this standard by rebuilding and reconductoring the line. Had EPE not taken this approach,

25 EPE would have had to define a contingency plan to drop customer load, remove this line

26 from service, or both, if and when the operating scenario occurred.

27

28 Q. WERE THERE ALTERNATIVES TO REBUILDING THE EXISTING LINE?

29 A. Yes, EPE could have built a new line to resolve the situation, but that would have entailed

30 greater costs, including costs associated with obtaining the required regulatory approvals,

31 land acquisition and ROW costs, permitting, and other costs associated with building a new


1249

1 line, which would have needed to be at least the length of the existing line. All routes

2 between these substations are heavily populated residential or commercial areas. It is also 3 worth noting, existing TXDOT ROW along Interstate 10 are already occupied by various

4 underground utilities. The ROW acquisition alone would take years to complete and would

5 have only added significantly to the construction costs. All this would have resulted in

6 needlessly extending the potential for violating NERC operating conditions.

7

8 Q. WAS PROJECT TL174 - LANE - COPPER TRANSMISSION LINE REBUILD


10 A. Yes, this project is reasonable and necessary and was constructed prudently. An analysis

11 by EPE System Planning demonstrated that the line between EPE's Lane and Copper

12 Substations had a potential to be overloaded and thereby in violation of NERC reliability

13 standards. Reconductoring the line was the least costly alternative that would ensure

14 compliance with NERC standards and ensure the integrity of the system without the

15 prospect of having to drop customer load. 16 17 D. Project Number 4 - TH162

18 Q. WHAT IS PROJECT TH162 - ARROYO AUTOTRANSFORMER ADDITION? 19 A. Project TH162 was a $7.02 million project that improved EPE's total 345 kV to 115 kV

20 transformation capacity by adding a new 345/115 kV autotransformer at EPE's Arroyo

21 Substation located on the east side of the City of Las Cruces.

22

23 Q. WHY WAS THE ARROYO AUTOTRANSFORMER ADDITION PROJECT NEEDED? 24 A. One of the major system components that dictate the load-serving capacity of EPE's

25 115-kV transmission system is the combined capacity of the fleet ofthe 345-kV to 1 15-kV

26 autotransformers that connect and transfer energy from the 345-kV system to the 115-kV

27 system and from there to the distribution substations. Since the last time EPE added a new

28 345/115 kV autotransformer, which was six years prior to this project, new load-serving

29 substations and additional customer load have been added to the 1 15-kV transmission

30 system without any 345 kV to 115 kV autotransformer additions. In 2014, EPE's System

31 Planning identified the age of some of EPE's 345/115 kV autotransformers as a system


1 contingency risk. Simply stated, under high-loading situations, the planning studies 2 showed that there would not be enough transformation capacity on EPE's fleet of

3 345/115 kV autotransformers to maintain system security and serve customer load without

4 interruption if any single 345/115 kV autotransformer on EPE's transmission system failed.

5

6 Q. WHAT WOULD HAVE BEEN THE CONSEQUENCES OF NOT ADDING THE

7 AUTOTRANSFORMER AT ARROYO SUBSTATION?

8 A. If EPE had not added this third autotransformer at Arroyo Substation, and thereby

9 improved the total 345 kV to 115 kV transformation capacity for the system, then EPE

10 would have an unmitigated NERC system contingency scenario. That scenario, under

11 certain loading conditions and system configurations (e.g., ability to purchase power 12 utilizing a different path), would require EPE to shed customer load if EPE suffered the

13 failure of any one of EPE's existing 345/115 kV autotransformers.

14

15 Q. ARE THERE ANY OTHER REASONABLE ACTIONS THAT EPE COULD HAVE

16 TAKEN TO ADDRESS THIS ISSUE AND ENSURE SYSTEM RELIABILITY?

17 A. No. The 345 kV to 115 kV transformation is the basis of EPE's power delivery system.

18 EPE's 345 kV autotransformers are an essential step in the movement of power on the EPE

19 system to serve retail customers. These autotransformers convert the power from 345 kV 20 level to the lower 115 kV level and thereby move energy to the 115 kV and then to the

21 69 kV transmission systems (by way of 115/69 kV autotransformers). In EPE's T&D

22 system, the high side voltage (i.e., transmission level voltage) of most distribution serving

23 substation transformers is either 115 kV or 69 kV. 24

25 Q. WAS PROJECT TH162 - ARROYO AUTOTRANSFORMER ADDITION


27 A. Yes, this project is reasonable and necessary and was constructed prudently. As described

28 in more detail above, due to recent load growth at the 115 kV level and the requirements

29 to serve a large portion of that load over the 345/115 kV autotransformers, the additional

30 345 kV to 115 kV transformation capacity at Arroyo Substation was crucial in order to

31 ensure the continued integrity o f the system. There were no reasonable alternatives as an


1 autotransformer is the only way to move energy from the 345-kV transmission system to

2 the 1 15-kV transmission system.

3

4 E. Project Number 5 - TA100

5 Q. WHAT IS PROJECT TA100 - LUNA TO SPRINGERVILLE RIGHT-OF-WAY

6 ACQUISITIONS AND RENEWALS?

7 A. This $4.85 million project is the renewal ofthe federal ROW easements for EPE's 345 kV

8 transmission line, the Arizona Interconnection Project ("AIP") line, located in Southwest

9 and West New Mexico. The AIP line resides on United States Bureau of Land Management

10 ("BLM"), United States Department ofAgriculture Forest Service ("USFS"), New Mexico

11 Forest Service, New Mexico State, and privately owned land. This project was the renewal

12 and addition of land rights over Federal property only. The AIP line was originally

13 constructed as one line, the Springerville - Luna 345 kV line, was completed in 1988, and

14 is approximately 213 miles long. In 2011 a new substation, Macho Springs substation, was

15 constructed on this line, thereby separating it into two line segments; the Springerville -

16 Macho Springs line and the Macho Springs - Luna line. Exhibit RCD-8 presents a map

17 showing the path of the AIP line and provides the transmission line corridor mileage that

18 was renewed as partofthis project.

19 The first objective of this project was to renew the expiring ROW easements on all

20 federal land (BLM and USFS) exclusive of any New Mexico or private land. The second

21 objective of this project was to define and acquire permanent access routes and roads over

22 federal land to physically get to and from the transmission line. 23 Each ofthe ROW permits was amended to include additional acres and permanent

24 usage rights for various access routes and roads to get to and from the transmission corridor. 25 The updated and amended ROW easements acquired by way ofthis project granted access

26 rights totaling approximately 319 miles ofpaths or roads. Ofthat 319 miles of access paths

27 and roads, approximately 135 miles was approved for new access road construction which

28 is planned to be completed over the next several years. Project costs include the ROW fees

29 assessed by each entity, related internal labor costs, and consulting services needed to 30 comply with various Federal and regulatory reporting requirements.

31


1 Q. WHY WAS THIS PROJECT NEEDED?

2 A. As described in section IV of this testimony, the 345 kV transmission lines that

3 interconnect EPE's system with our neighboring utility systems are critical to EPE's ability

4 to import and exchange power and reliably serve our customers. The AIP line is one of

5 these critical interconnecting lines that provide a pathway for a large portion of EPE's

6 energy import. As such, the renewals ofthe ROW permits and acquisition ofaccess rights

7 for the AIP line was essential to EPE's continued operational capabilities.

8 Much ofthe physical route of this transmission line traverses very rough geological 9 terrain, and it is not always physically possible to follow the transmission line corridor

10 from one structure to the next. In many cases, the only physically maneuverable route

11 between transmission structures leads miles around difficult terrain to get to the next 12 structure. It was important to the BLM, USFS, and EPE that we define all ofthose access

13 routes and roads and procure the rights to use those route and roads going forward. Having

14 defined and pre-approved access routes and roads to and from the transmission line is 15 important to reduce response time in emergencies and provide more efficient travel paths 16 during planned maintenance activities. 17 To get new access routes and road authorizations granted by the BLM and USFS,

18 the requests had to comply with the latest Federal regulations. This included conducting

19 Environmental Assessments ("EAs"), pursuant to the National Environmental Policy Act

20 ("NEPA"), of the proposed access roads for the jurisdictional agencies (BLM, USFS). The

21 purpose of the EAs is to evaluate and determine environmental impacts and mitigation

22 measures for these access roads. The EAs required natural resource surveys and reports

23 for cultural resources, protected biological species, paleontological resources, impacts to 24 waterways, soils, and the human environment. Additionally, the requests also needed to

25 comply with section 106 of the National Historic Preservation Act ("NPHA"). EPE was

26 required to provide a complete a cultural resource survey and implement a historical

27 properties treatment plan to mitigate any impacts to eligible cultural resource sites. To

28 assist and expedite these efforts, BLM- and USFS-approved environmental consulting

29 firms were used to develop and implement these surveys and plans, as required by the terms 30 and conditions of our land use agreements, and to comply with Federal and State

31 regulations.


2 Q. WAS PROJECT TA100 - LUNA TO SPRINGERVILLE RIGHT OF WAY

3 ACQUISITIONS AND RENEWALS A REASONABLE, NECESSARY, AND

4 PRUDENT INVESTMENT?

5 A. Yes, this project is reasonable and necessary and was constructed prudently. The renewal

6 of existing ROW with the addition of access rights for new roads for the AIP line was

7 needed for the continued use of, and access to, this 345 kV transmission line and EPE's day

8 to day operational capability. 9

10 F. Project Number 6 - TL231

11 Q. WHAT IS PROJECT TL231 MILAGRO - LEO 69 KV TO 115 KV UPGRADE?

12 A. Project TL231 was a $4.79 million project to rebuild, reconductor, and change the

13 operating voltage of the 69 kV transmission line between EPE's Milagro and Leo

14 Substations to 115 kV. Both substations and this line are located within the expanding and

15 increasingly customer dense area of northeast El Paso, Texas.

16

17 Q. WHY WAS THE MILAGRO - LEO 69 KV TO 115 KV UPGRADE PROJECT

18 NEEDED? 19 A. The need for this upgrade was to reliably serve increased load due to customer growth in

20 northeast El Paso, Texas. EPE's System Planning identified this line as an overloaded line

21 under normal operating condition, summer load, and in certain NERC defined system

22 operating scenarios. The most economical solution to the overloading scenario was to

23 rebuild, reconductor, and convert the line to 115 kV. The reconductor and rebuild process

24 for this line was as described above for the Lane - Copper Transmission Line. What is

25 different about this project is that the insulating capacity of all structures had to be

26 improved to change the operating voltage from 69 kV to 115 kV. Improving, or raising,

27 the operating voltage of a transmission line is another method of increasing the capacity to

28 move more energy over the same line.

29 30 Q. WHAT WOULD HAVE BEEN THE CONSEQUENCES OF NOT REBUILDING AND

31 RECONDUCTORING THIS TRANSMISSION LINE?


1254

1

1 A. In certain operating scenarios, there would be an overloaded transmission asset. In

2 response EPE would have had to define a contingency plan to drop customer load, remove

3 this line from service, or both ifthe operating scenario occurred.

4

5 Q. WERE THERE ALTERNATIVES TO REBUILDING THE EXISTING LINE?

6 A. Yes. Similar to the Lane - Copper Transmission Line (TL174), EPE could have built a

7 new line to resolve the situation but that would have involved costs and delays beyond 8 what the selected project emailed. This transmission line is located within the El Paso city

9 limits, so the cost to construct a new, or second transmission line, which would have needed 10 to be at least the length of the existing line, would have proven too costly due to the fact

11 that any new line route would have to go through a developed area of the city-adding

12 delay and cost to the project. 13

14 Q. WAS PROJECT TL231 - MILAGRO - LEO 69 KV TO 115 KV UPGRADE



17 above, EPE's System Planning identified the line between Milagro and Leo Substations as

18 an overloaded line under certain operating conditions due to recent load growth in northeast

19 El Paso. Rebuilding, reconductoring, and changing the operating voltage of the 69 kV

20 transmission line was the least costly alternative that would ensure compliance with NERC

21 standards and ensure the integrity of the system without having to drop customer load.

22

23 G. Project Number 7 - TL127

24 Q. WHAT IS PROJECT TL127 - FARMER - FELIPE STRUCTURE REPLACEMENT?

25 A. This $4.69 million project was the final phase of a multi-year project to replace all tangent

26 wood pole structures with tangent steel structures on the 69 kV transmission line between

27 EPE's Felipe and Farmer Substations. Felipe Substation is located in the Rio Grande valley

28 south and east ofthe City ofE1 Paso, Texas and Farmer Substation is located in Van Horn,

29 Texas, as shown in Figure RCD-3. "Tangent" structures are the in-line structures between

30 the angle holding or line ending (dead-end) structures ofa transmission or distribution line.


1 The majority of transmission or distribution structures that support the line are in-line,

2 tangent, vertical load-bearing structures.

3 Figure RCD-3

4

5 · fa- yt~*·'»t~GfE~1•~I CAS 9110 11 f .

6

7 8 69 kV

lbfrwtlo Atamo TEXAS 9 0

10 Foft noock 9©

GLANCA 11 69W

Sief manca 69 kV

12 0 13 Van Hom

RO GRAM

14

9ty»+----A

15 Q. WHY WAS THE FARMER - FELIPE STRUCTURE REPLACEMENT NEEDED?

16 A. The last segment o f this 69 kV transmission line was completed in 1969. Over the years,

17 some ofthe tangent wood pole structures had been replaced; however, many ofthe original

18 structures were still in service and over forty-years old. Prior to initiating this project in

19 2008, EPE had experienced multiple weather-related structure failures on this line, and the

20 frequency of structure failure was trending up. Accordingly, EPE initiated a plan to replace

21 the tangent wood structures with steel structures over a ten-year period. Because this line

22 is the only line providing service to customers from Sierra Blanca, Texas, to Van Horn,

23 Texas, the work had to be done with the line energized: a highly specialized skill that EPE

24 line-workers possess but that is not common among construction contractors.

25 Seven years into this ten-year project approximately half ofthe structures had been

26 replaced. Then on July 7,2015, a severe thunderstorm, with localized winds gusting up to

27 80 miles per hour, blew down 38 tangent wood pole structures in one five-mile stretch of

28 this transmission line. EPE crews responded immediately and worked around the clock to

29 replace the downed structures and return the line to service, which took three full days.

30 During this line outage EPE was able to provide a very limited level of electric service to

31 the customers of Sierra Blanca and Van Horn by way ofthe distribution system.


1 Atthe beginning of2018, EPE recognized that with existing EPEtransmission crew

2 resource obligations, it was not likely that EPE crews would finish the wood-for-steel

3 structure change-out in 2018. EPE identified and contracted with a transmission

4 construction contractor qualified to do energized work to finish the project utilizing the 5 procurement practices I outlined above.

6

7 Q. WHAT WOULD HAVE BEEN THE CONSEQUENCES OF NOT REPLACING THE 8 WOOD STRUCTURES OF THIS 69 kV TRANSMISSION LINE WITH STEEL

9 STRUCTURES?

10 A. EPE anticipates that it would have continued to have structure failures during severe

11 weather conditions resulting in extended outages for the customers in Sierra Blanca, 12 Van Horn, and the areas in between, as there are no alternate transmission lines servicing 13 those areas. 14

15 Q. WAS PROJECT TL127 - FARMER - FELIPE STRUCTURE REPLACEMENT



18 in more detail above, the line between the Farmer and Felipe Substations is the only

19 transmission serving Sierra Blanca, Van Horn, and the areas in between. The age of the 20 existing structures and their demonstrated weakness due to recent severe weather events

21 necessitated the replacement to ensure continued, uninterrupted service to customers in the 22 area. 23 24 H. Additional Transmission Capital Projects

25 Q. WHAT OTHER TRANSMISSION PROJECT COSTS ARE INCLUDED IN THIS

26 CASE? 27 A. The remaining transmission projects and their associated costs are presented in

28 Exhibit RCD-9 with project descriptions for all projects with a cost greater than $1 million

29 but less than $4.5 million; transmission blanket projects are also included. Transmission

30 blanket projects are standing projects that are utilized to cover smaller, recurring initiatives 31 that arise such as transmission segment rebuilds due to forced outages, required structure


1 replacements identified during inspections, and investments to meet changing NERC

2 Reliability Standards. For those projects described as "Multi-Year" projects, the amount

3 shown in the table is the dollar value of the investment portion of the multi-year project

4 placed into service by the end of the Test Year.

5

6 Q. ARE THE COSTS INCLUDED IN THE REQUESTED TRANSMISSION PROJECTS

7 REASONABLE, NECESSARY, AND PRUDENT TO PROVIDE SAFE AND

8 RELIABLE SERVICE TO CUSTOMERS?

9 A. Yes. The costs are reasonable, necessary, and prudent to provide safe and reliable service.

10 The transmission projects are necessary to serve anticipated load growth, improve overall

11 reliability and functionality of EPE's system, adhere to applicable reliability standards, and

12 are subject to EPE's procurement processes and procedures to ensure the reasonableness

13 and prudence of the costs. All ofthe projects are used and useful as well.

14

15 IX. Distribution Capital Projects

16 Q. WHAT AMOUNT OF TEXAS DISTRIBUTION PLANT ADDITIONS HAS EPE

17 PLACED IN SERVICE SINCE THE 2017 RATE CASE? 18 A. From October 2016 through the Test Year end of December 31, 2020, EPE has placed

19 $296,135,245 of additional distribution plant in service in Texas. As described in the

20 testimony of EPE witness Adrian Hernandez, Texas distribution plant costs are directly

21 assigned to Texas. A list of these Texas distribution capital projects is provided by EPE

22 witness Hancock in his Capital Additions Exhibit LJH-2. These projects are discussed

23 further in my testimony.

24

25 Q. WHAT ARE THE MAIN FACTORS THAT DETERMINE THE NEED FOR CAPITAL

26 INVESTMENT IN THE DISTRIBUTION SYSTEM?

27 A. Load growth, reliability, and maintenance are the main factors that drive the need for

28 capital investments in the distribution system. New facilities are required to reliably serve

29 EPE's expanding customer load growth. Existing facilities need to be proactively replaced

30 as they reach the end of their useful life to maintain acceptable reliability and to be


1 reactively replaced ifthey fail due to damage (e.g., vehicle accidents) or premature failures

2 due to weather and aging.

3

4 Q. HAS EPE PREVIOUSLY PRESENTED TO THE COMMISSION ANY OF THE

5 DISTRIBUTION PROJECTS THAT IT SEEKS TO INCLUDE IN RATES IN THIS

6 RATE CASE?

7 A. Yes, it has. EPE's first two distribution cost recovery factor ("DCRF") proceedings were

8 Docket No. 49395, which was resolved through a settlement and the Commission's

9 September 27, 2019, order, and Docket No. 51348, which was resolved through a

10 settlement and the Commission's May 24,2021, order. The period of investment presented

11 in Docket No. 49395 was October 2016 through December 2018, and the period of

12 investment presented in Docket No. 51348 was January 2019 through June 2020. EPE is

13 now requesting that these distribution projects be moved to and included in base rates in

14 this case. In addition, distribution investments from July 2020 through December 2020 are

15 being presented for the first time, in this rate case.

17 Q. ARE BLANKET PROJECTS ALSO UTILIZED IN DISTRIBUTION?

18 A. Yes, they are utilized in distribution and represent $160,087,928 total distribution

19 infrastructure investment in Texas.

20

21 Q. CAN YOU DESCRIBE HOW BLANKET PROJECTS ARE USED IN DISTRIBUTION?

22 A. The Company uses Distribution Blanket Projects to account for capital costs that fall

23 within pre-defined, recurring categories. Although the individual activities are recurring

24 and comparatively small in nature, these projects span activities that apply to the entire

25 distribution system. The specific work orders under the project delineate the task by

26 location, customer, or other characteristic that facilitates both scheduling and accounting 27 processes at EPE. These projects are necessary to (1) improve reliability of the

28 distribution system, (2) improve operation of the distribution system, and (3) meet EPE's

29 continuous customer load growth. Distribution blanket projects are presented in the table

30 below:


1259

1 Table RCD-5

2 3 4

5 6 7 8 9 10 11

12 13

14

15 16

Project Company Number Pro iectDescription Total DT069 TEXAS COMMERCIAL CONSTRUCTION BLANKET $44,746,028 DT061 TEXAS RESIDENTIAL CONSTRUCTION BLANKET $35,426,072 DT062 TEXAS DISTRIBUTION BETTERMENT BLANKET $33,156,327 DT065 TEXAS DISTRIBUTION DAMAGE BLANKET $16,323,388 DT068 TEXAS OVERHEAD SERVICE NEW/REPLACE $8,505,501

BLANKET MT004 TEXAS METERS BLANKET $8,226,133 DT063 TEXAS SUBSTATION BETTERMENT BLANKET $3,674,064 DT372 POLE REPLACEMENT & IMPROVEMENTS TEXAS $3,451,028 DT121 TEXAS CABLE REPLACEMENT PROGRAM BLANKET $2,426,528 DT064 TEXAS LIGHTING BLANKET $2,391,878 DT015 RELAY UPGRADES TEXAS DISTRIBUTION $797,123

SUBSTATION BLANKET DT007 DISTRIBUTION TEXAS FACILITY SERVICES $416,577

BLANKET MT102 ERT METER INSTALLATION BLANKET $334,455 DT188 DISTRIBUTION SUBSTATION CIRCUIT BREAKER $212,826

REPLACEMENTS TEXAS BLANKET TEXAS DISTRIBUTION BLANKETS TOTAL $160,087,928

17 18 The capital investment associated with the blanket projects are, in large part, customer

19 driven investments and net of any Contribution in Aid of Construction ("CIAC") made by

20 the customer. These represent reasonable, necessary, and prudent capital investments that

21 are used and useful to serve Texas customers. 22

23 Q. CAN YOU DESCRIBE THE REMAINDER OF PROJECTS AND IDENTIFY WHAT

24 CRITERIA YOU USE TO DISTINGUISH MAJOR DISTRIBUTION PROJECTS FROM

25 OTHER PROJECTS?

26 A. The remainder of capital proj ects are larger proj ects focused on system expansion and

27 betterment to provide safe and reliable service. The single criterion that I have used is a

28 total cost amount to distinguish major distribution projects from other projects. Those non

29 blanket projects that cost more than $4 million per project and have been placed in service 30 from October 1,2016, through December 31,2020, are listed below. Non-blanket projects

31 under $4 million total $70,729,812 and are composed predominantly of distribution


1260

1 projects such as distribution substation additions or expansions, feeder additions and

2 upgrades, and other infrastructure betterments to meet load requirements and maintain

3 reliability. While the distribution capital projects that EPE requests be placed into rate base

4 are used and useful and have been constructed in a prudent manner at a reasonable cost, I

5 describe the projects over $4 million for ease in reference and to highlight the key

6 distribution capital projects since the Company's last rate case.

7

8 Q. WHAT ARE THE LARGEST NON-BLANKET DISTRIBUTION PROJECTS LISTED

9 IN THE EXHIBITS?

10 A. The largest non-blanket distribution projects by cost are as follows:

11 Table RCD-6

12

13

14

15 16

17 18

19 20

Project Company Number Project Description Total DT359 NUWAY NEW DISTRIBUTION SUBSTATION $16,471,140 DT371 EXECUTIVE (CE-1) NEW SUBSTATION $12,347,653 DT229 SCOTSDALE TRANSFORMER & SWITCHGEAR $9,942,725

REPLACEMENTS DT220 SANTA FE SUBSTATION TRANSFORMER, $8,801,042

SWITCHGEAR, AND EQUIPMENT UPGRADES DT186 LEO SUBSTATION 115 KV CONVERSION & $8,528,067

GETAWAY UPGRADE DT189 TEXAS AREA 4KV CONVERSIONS $4,860,348 DT365 SPARKS T2 TRANSFORMER, SWITCHGEAR, AND $4,366,530

VOLTAGE REGULATORS 21

22 Q. PLEASE DESCRIBE THESE LARGEST DISTRIBUTION PROJECTS.

23 A. I describe the projects below in the same order as Table RCD-6 above.

24 25 A. Project Number 1 - DT359

26 Q. WHAT IS PROJECT DT359 -NUWAY NEW DISTRIBUTION SUBSTATION?

27 A. Project DT359 is a $16.4 million project to construct Nuway substation in the upper valley

28 of West El Paso. Nuway is a 115/23.9 kV substation, with two 50 MVA transformers and

29 four distribution feeders. Nuway substation is a next generation technology substation for

30 EPE because it was constructed as our first digital substation (protection and control and

31 communication systems) with a double-bus, double-breaker (distribution feeder


1261

1 connection) configuration to facilitate remote and automated control. This substation was

2 constructed to relieve the existing and increasing load on the other substations in the area

3 (Montoya, Santa Teresa, and Anthony substations). Additionally, the new Nuway feeders

4 provide back-up service to critical loads of EPE's System Operations Control Center and

5 the Providence West Hospital. Prior to the construction of Nuway substation, the rapidly

6 growing load in the area had to be supported by a temporary substation, Transmountain

7 Temp Sub, with two distribution feeders. With the construction of Nuway substation, the

8 temporary substation has been removed. 9


11 A. Nuway substation supports the existing and rapidly expanding customer growth of West

12 El Paso. It immediately provides load relief to the other area substations and serves as the

13 critical back-up service for EPE's System Operations Control Center, the Providence West

14 Hospital, and the commercial/industrial development in the Transmountain Rd. and

15 Interstate 10 area.

16

17 Q. WAS PROJECT DT359 NUWAY NEW DISTRIBUTION SUBSTATION A

18 REASONABLE, NECESSARY, AND PRUDENT INVESTMENT?


20 above, this substation is needed for the continued load increase in this area to provide

21 reliable service to EPE customers.

22

23 B. Project Number 2 - DT371

24 Q. WHAT IS PROJECT DT371- EXECUTIVE (CE-1) NEW SUBSTATION?

25 A. DT371 is a $12.35 million project to construct a new substation, Executive substation, in

26 west-central El Paso. Executive substation is a 115/13.8 kV distribution substation serving

27 load near the Interstate 10 and Executive Center Ave. area on the west side of El Paso.

28 Executive substation was constructed as a six-position 115 kV ring bus, with two 50 MVA

29 115/13.8 kV distribution transformers, and two distribution switchgears that connect six

30 distribution feeders. This is the first substation of several planned for this area as a

31 coordinated plan to upgrade and expand transmission and distribution infrastructure. To


1 meet the rapidly growing electrical load of this area, EPE had to construct and place in

2 service in 2018 a temporary 115/13.8 kV substation, CE-1 temp, which continues to serve

3 two distribution feeders. CE-1 temp is located just west of the substation, EPE's Mesa

4 substation, that was currently serving the area. The new Executive substation is located

5 about one half a mile south and east of Mesa substation, and has helped to relieve the load

6 and provide back-up capability for the Mesa substation feeders.

7


9 A. Executive substation is needed to serve increasing customer load in the area and alleviate

10 load on Mesa substation. Most of the major equipment at Mesa substation was constructed

11 in the 1960s, expanded in the 1970s, and is now serving at full capacity in the summer 12 months. Due to development in the immediate area, our ability to completely rebuild

13 and/or add more feeders out of Mesa substation is very limited. The temporary substation,

14 CE-1, is serving near full capacity during the summer months and will be needed until

15 additional permanent solutions i.e. in addition to Executive substation can be implemented

16 for this area.

17 EPE's longer term plan for serving the area includes the construction of another

18 substation in close proximity to CE-1, and the elimination of Mesa substation all together.

19

20 Q. WAS PROJECT DT371 EXECUTIVE (CE-1) SUBSTATION A REASONABLE,

21 NECESSARY, AND PRUDENT INVESTMENT?

22 A. Yes, this project is reasonable and necessary and was constructed prudently. As previously

23 described, these substations are needed to serve the increasing load in the area and to serve

24 as the first part o f a long-term solution for the eventual retirement of Mesa substation.

25 26 C. Project Number 3 - DT229

27 Q. WHAT IS PROJECT DT229 - SCOTSDALE TRANSFORMER AND SWITCHGEAR

28 REPLACEMENT?

29 A. DT229 is a $9.94 million project to replace the transformers and distribution switchgear of

30 Scotsdale substation in central El Paso. The project included the upgrade oftwo substation

31 transformers from 30 MVA to 50 MVA, a rebuild ofthe transmission ring bus to convert
