# GLOSSARY OF ACRONYMS AND DEFINED TERMS Acronym/Defined Term Meaning AFUDC Allowance For Funds Used During Construction 

# CCN Certificate of Convenience and Necessity CT Combustion Turbine 

# Commission Public Utility Commission of Texas DMW Dissimilar Metal Welds EPA Environmental Protection Agency FEC Farmers Electric Cooperative, Inc. 

# FRP Fiberglass Reinforced Poly GPM Gallons per Minute 

# ISO International Organization for Standards kW Kilowatt MATs Mercury and Air Toxics, a rule adopted by EPA MW Megawatt NMPRC New Mexico Public Regulation Commission O&M Operation and Maintenance Operating Companies Northern States Power Company, a Minnesota corporation; Northern States Power Company, a Wisconsin corporation; Public Service Company of Colorado, a Colorado corporation; and SPS PM Project Manger RFP Rate Filing Package RO Reverse Osmosis SPS Southwestern Public Service Company, a New

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# Acronym/Defined Term Meanin Mexico corporation 

# Test Year July 1, 2013 - June 30, 2014 Total Company or total company Total SPS (before any jurisdictional allocation) WECC Western Electricity Coordination Council Xcel Energy Xcel Energy Inc. XES Xcel Energy Services Inc.

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# LIST OF ATTACHMENTS Attachment Description 

# AJD-RR-1 Energy Supply Capital Additions for July 1, 2012 through June 30, 2014 (Filename:AJD-RR-1.xlsx) 

# AJD-RR-2 Energy Supply Capital Additions for July 1, 2014 through December 31, 2014 (Filename:AJD-RR-2.xlsx)

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# DIRECT TESTIMONY OF ALAN J. DAVIDSON 1 I. WITNESS IDENTIFICATION AND QUALIFICATIONS 2 Q. Pleasestateyourname and business address. 3 A. My name is Alan J. Davidson. My business address is 600 South Tyler St., 4 Amarillo, Texas 79101. 5 Q. On whose behalf are you testifying in this proceeding? 6 A. I am filing testimony on behalf of Southwestern Public Service Company ("SPS"), a 7 New Mexico corporation and wholly-owned electric utility subsidiary of Xcel 8 Energy Inc. ("Xcel Energy"). Xcel Energy is a registered holding company that 9 owns several electric and natural gas utility operating companies.' 10 Q. Bywhom are you employed and in what position? 11 A. Iam employed by Xcel Energy Services Inc. ("XES"), the service company 12 subsidiary of Xcel Energy, as Director, Regional Capital Projects in the Engineering 13 and Construction Department of Energy Supply, which is the generation operation 14 and maintenance business unit of Xcel Energy.

1Xcel Energy is the parent company of the following four wholly owned utility operating companies: Northern States Power Company, a Minnesota corporation; Northern States Power Company, a Wisconsin corporation; Public Service Company of Colorado, a Colorado corporation; and SPS("Operating Companies"). Xcel Energy's natural gas pipeline subsidiary isWestGas Interstate, Inc. Xcel Energy also has two transmission-only operating companies, Xcel Energy Southwest Transmission Company, LLC and Xcel Energy Transmission Development Company, LLC,which are regulated by the Federal Energy Regulatory Commission.


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# I Q. Please briefly outline your responsibilities as Director, Regional Capital 2 Projectsin the Engineering and Construction Departmentof Energy Supply. 3 A. I am responsible for managing the capital budget process and projects for the SPS 4 region within the Energy Supply business unit. Thus, I am responsible for the 5 regional capital budget, schedules, development, and construction for all of SPS's 6 capital electric generating projects. I directly manage the major projects for SPS and 7 supervise other managers handling smaller projects.My management duties include 8 safety, technical design selection, engineering and contractor oversight, managing 9 the bidding process, and negotiating major equipment supply agreements. I work 10 with the Environmental, Regulatory, and Resource Planning departments to assist 11 with scoping and planning of new generation and major generation retrofit projects. 12 Q. Pleasedescribeyoureducational background. 13 A. Ihave a Bachelor of Science degree in Mechanical Engineering from Texas Tech 14 University. 15 Q. Please describeyour professional experience. 16 A. I have worked in the electric power industry for over 30 years in various positions 17 with Xcel Energy and SPS. My experience has included: plant engineering 18 responsibilities forboilers, turbines, and the balance of plant equipment; 19 performance testing and analysis responsibilities for combustion turbines and fossil 20 units; control system design and installation for combustion turbines("CT") and 21 fossil units; photovoltaic systems installation; plant refurbishments; operation and 22 maintenance("O&M")management; project director for environmental controls

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# 1 projects on coal units; and project director for installation of simple cycle

2 combustion turbines. 3 Q. Haveyou attended or taken any special courses or seminars relating to public 4 utilities? 5 A. Yes. Over my career, I have taken numerous courses and seminars related 6 specifically to the construction and operation of power plants. I have presented 7 technical presentations on water treatment, general project management, solar project 8 installation, environmental controls for coal plants, and installation of gas turbines to 9 internal and external groups. I have presented a paper on potential turbine upgrade 10 projects at a Marcus Evans industry conference and given a "lessons learned" 11 presentation on gas turbine installation to an international group of engineers and 12 managers for Siemens. 13 Q. Doyou hold any professional licenses? 14 A. Yes. I am a Registered Professional Engineer in Texas. 15 Q. Are youa member of any professional organizations? 16 A. Yes. I am a member of the American Society of Mechanical Engineers, the Texas 17 Society of Professional Engineers, and the National Society of Professional 18 Engineers. 19 Q. Have you previouslytestified or filed testimony at any regulatory commission? 20 A. Yes. I testified before the New Mexico Public Regulation Commission ("NIVIPRC") 21 in Case No. 12-00350-UT, an SPS base rate case, on capital expenditures for the

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# 1 Energy Supply business unit. In Docket No. 408242 (base rate case) and in Docket 2 No. 420043 (base rate case) before the Public Utility Commission of Texas 3 ("Commission"), I filed testimony covering the same capital additions related 4 subjects addressed in this testimony. I also filed testimony in the following certificate 5 of convenience and necessity ("CCN") proceedings: Commission Docket No. 39541 6 (JonesUnit 4); and NMPRC Case Nos. 11-00313-UT (Jones Unit 4) and 7 12-00052-UT (Quay County Plant).

2 Application of Southwestern Public Service Company for Authority to Change Rates and to Reconcile Fuel and Purchased Power Costs for the Period January 1, 2010 through June 30, 2012,Docket No. 40824, Order (Jun. 19, 2013).

3 Application of Southwestern Public Service Company for Authority to Change Rates and to Reconcile Fuel and Purchased Power Costs for the Period January 1, 2012 through June 30, 2013,Docket No. 42004 (filed Jan. 7, 2014).



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# 1 II. ASSIGNMENT AND SUMMARY TESTIMONY AND 2 RECOMMENDATIONS 3 Q. What isyour assignment in this proceeding? 4 A. Iwill review and provide cost data for the Energy Supply-related capital 5 improvements and projects that SPS placed in service during the period July 1, 2012 6 through June 30, 2014. SPS's capital additions through June 30, 2012 either have 7 been approved in prior rate cases or approval is currently pending before the 8 Commission. The capital additions for the period after June 30, 2012 have not been 9 addressed by the Commission. Thus, the 24-months starting July 1, 2012 covers the 10 period after June 30, 2012 through June 30, 2014, the end of the Test Year (July 1, 11 2013 - June 30, 2014 ("Test Year")) in this case. In addition, I review and provide 12 cost data for Energy Supply-related capital projects budgeted to be placed in service 13 between July 1, 2014 and December 31, 2014. 14 1also provide the operational and engineering justification for proposed 15 changes in the useful lives of certain SPS generating units. 16 In addition, I sponsor Schedules H-5.2b and H-5.3b of SPS's rate filing 17 package ("RFP"). Schedule H-5.2b presents Energy Supply-related capital additions, 18 by generating station, being requested in this filing. Schedule H-5.3b presents 19 similar data for a five-year historical period, the present year, and projected for next 20 three years. 21 Q. Please summarize your testimony and recommendations. 22 A. The cost of Energy Supply-relatedcapital additions placed in service between July 1, 23 2012 andJune30, 2014,including the associated capitalizedaffiliatecharges, equals 24 $212,623,481. Thesecosts are reasonable and necessary capital costs to maintain

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# 1 and enhance the environmental, safety, performance, and reliability characteristics of 2 SPS's existing generation units and to construct Jones Unit 4 and the Quay County 3 Plant. In addition, SPS will incur additional Energy Supply-related capital costs of 4 $18,455,071 for projects to be placed in service during the period July 1, 2014 5 through December 31, 2014. These costs also are reasonable and necessary capital 6 costs to maintain and enhance the environmental, safety, performance, and reliability 7 characteristics of SPS's existing generation units. The total of these two sums, 8 $231,078,552, was prudently incurred. The changes in the useful lives of certain 9 SPS generating units set forth in Section V of this testimony are reasonable.

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# 1 III. ENERGY SUPPLY-RELATED CAPITAL PROJECTS 2 PLACED IN SERVICE BETWEEN JULY 1 2012 3 THROUGH JUNE 30. 2014 4 Q. Aspart of this rate case,is SPSasking to includeEnergySupply-related capital 5 additions in its rate base? 6 A. Yes. All of theEnergy Supply-related capital additions listed in Attachment 7 AJD-RR-1support SPS's ability to provide electric service to its customers. 8 Q. What is the time period for these Energy Supply-related capital additions? 9 A. The time period is the 24-month period starting on July 1, 2012 and ending on June 10 30, 2014. The starting date for this period (July 1, 2012) is the first day after the end 11 of the period for which capital additions were approved in Docket No. 40824, and 12 the ending date for this period (June 30, 2014) is the end of the Test Year in this 13 docket. 14 Q. Please describe the Energy Supply-related capital additions placed in service 15 between July 1, 2012 and June 30, 2014. 16 A. The Energy Supply-related capital additions fall into one of four categories. The first 17 category contains the capital additions for maintaining and enhancing the 18 environmental, safety, performance, and reliability characteristics of SPS's existing 19 production plant. The second category contains the Quay County Plant and new 20 generating capacity added to the system,i.e.,Jones Unit 4. A third category is 21 investment in certain transmission and substation facilities associated with the Quay 22 County Plant and Jones Unit 4. The fourth category is the investment in items 23 classified as "Electric General" plant.

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# 1 Q. What isthe dollar amountof the Energy Supply-related capital additions placed 2 in service between July 1, 2012 and June 30, 2014 that SPS isrequesting in this 3 docket? 4 A. The total dollar amount of Energy Supply-related capital additions that SPS is 5 requesting for additions placed in service during the period July 1, 2012 through 6 June 30, 2014 is $212,623,480.77 (total company), including Allowance for Funds 7 Used During Construction ("AFUDC"). The following table lists the Energy Supply 8 capital additions by type: 

# 9 Table AJD-RR-1

Type of Energy Supply-Related Capital

Addition Cost of Projects Closed to Plant in Service July 1, 2012 - June 30, 2014 

# Existing Production Plant $101,856,823 Jones Unit 4 (excl. substation & transmission) $83,418,968 Quay County Plant (excl. substation & trans.) $19,226,353 Jones Unit 4 Substation $1,313,695 

# Quay County Substation $3,617,725 Electric General Plant $3,189,917 TOTAL $212,623,481 10 Attachment AJD-RR-1 provides detailed information about these capital additions. 11 SPS witness Deborah A. Blair allocates the total company dollar amount 12 among SPS's three rate jurisdictions (Texas retail; New Mexico retail; and 13 wholesale).

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# 1 Q. Please describe the information in AttachmentAJD-RR-1,which provides the 2 details about the dollar amounts closed to plant in service for these Energy 3 Supply-relatedcapital additions and the associatedaffiliatecomponent. 4 A. Attachment AJD-RR-1 provides the following information:

Column A - Work Order Number Provides the Work Order number for the

Column B - Work Order

Description 

# Column C - Asset Class Column D - Witness

Column E - Parent

Column F - Parent Description

Column G - In-Service Date

Column H - Additionto Plant-inService(July 2012 - June 2014) Column I - XES Charges

(Included in Column H) project. Provides a short title for the work order.


# Identifiesthe typeof asset. Identifies the witness supporting the project. 

# Provides the parent work order number for the project. Provides a short title for the parent work order. The month and year the project was placed in-service. The total company dollar amount of the addition to plant-in-service for the project. The amount of charges from XES that are included in the total company dollar amount of addition to plant-in-service for the project in Column H. Column J Other Affiliate The amount of charges from affiliates

Charges (Included in other than XES that are included in the Column H) total company dollar amount of addition to plant-in-service for the project in Column H.

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# Column K Total Affiliate Totalof Columns I and J associated with Charges (Included in new plant-in-service shown in Column Column H) H. Column L Total Native Charges

(Column H less K) Within the TotalAdditions to Plant-inService Shown in Column H 

# The total native charges associated with new plant-in-service shown in Column H.

1 Q. Attachment AJD-RR-1 includescapitalized affiliate costs.Were thoseaffiliate 2 costsnecessary to complete the projects listed in AttachmentAJD-RR-1? 3 A. Yes.These affiliate charges are for engineering, construction, technical direction, 4 management,safety,and other relatedwork todevelop, procure, and install capital 5 additions at SPS generation facilities. Affiliate charges included in Attachment 

# 6 AJD-RR-1 are $9,123,989.29, which is approximately 4.3% of SPS's total Energy 7 Supply-related capital costs for projects placed in service during the period July 1, 8 2012 through June 30, 2014. 9 Q. Are thecosts of these capitalized affiliate charges reasonable? 

# 10 A. Yes.SPS witnessDavid A. Lowaddresses the reasonableness of affiliate charges to 11 SPS duringthe Test Yearfor the Energy Supply business area, which contains the 12 affiliate classes into which all of these costs are collected. That discussion also 13 applies to these affiliate costs for the entire 24-month capital additions period. Thus, 14 that discussion supports the reasonableness and necessity of such affiliate costs for 15 the period from July 1, 2012 through June 30, 2014. In addition, SPS witness Janet 

# 16 S. Schmidt-Petree explains that chargesfor laborand goods receivedby SPS from

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# 1 the Operating Companies, rather thanXES, (column JofAttachment AJD-RR- 1) are



# 2 reasonable and necessary. 3 Q. What isthe difference between the affiliate charges for the Energy Supply 4 affiliate classes of service discussed byMr. Low and the affiliate charges 5 included in your AttachmentAJD-RR-1? 6 A. The Energy Supply affiliate charges Mr. Low discusses reflect only O&M expenses 7 incurred during the Test Year. In contrast, the affiliate charges in my testimony refer 8 to the affiliate charges that were included in the capital costs closed to SPS's plant in 9 service during the period from July 1, 2012 through June 30, 2014. That is, I discuss 10 affiliate charges that were capitalized over a two-year period and Mr. Low discusses 11 affiliate charges that were expensed in the Test Year. 

# 12 A. Major Projectsand Project Management 13 Q. Were theEnergy Supply-related capital additions, including the capitalized 14 affiliate charges, you present reasonable and necessary? 15 A. Yes. The capital projects listed in Attachment AJD-RR-1 were necessary to maintain 16 the reliability, operational, safety, and environmental requirements of the plants. 17 Federal legislation, such as the Clean Air Interstate Rule, requires additional 18 environmental controls on generating facilities. Boiler tube replacements reduce the 19 occurrence of unplanned outages and help to maintain a high reliability factor, which 20 reduces the need for higher cost replacement energy. Safety projects ensure a safe 21 workplace for employees and enable SPS to meet the safety standards established by 22 regulatory agencies. The following project descriptions represent most ofthe various

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# types of larger projects (over $1,000,000) other than Jones Unit 4 and Quay County 2 Plant, which are discussed later in my testimony. 3 1. HarringtonUnit 1- Replace BoilerNose Tubes (Parent Work Order 4 11222845) - This project consisted of replacing the boiler nose tubes with 

# 5 membrane welded tube panels. This replacement eliminated the need for 6 refractory work, casing repairs, and pad welds that typically cost $100,000 to 7 $150,000 during each outage. The current sootblowers continued to blow the 8 refractory out from around these tubes which in turn caused the casing to 

# 9 continue to burn up. The top part of the new boiler nose tubes were weld 10 overlaid with an Inconel material to enable the tubes to better handle the 11 sootblower and flyash erosion. The boiler screen tubes, which support the 12 rear waterwall and penetrate the nose tubes, were also replaced as part of this 13 project. 14 2. Harrington Unit 1 - Replace Front Boiler Reheat Panel (Parent Work 

# 15 Order 11222850) - This project replaced the front half of the reheater, which 16 consisted of approximately 63 reheat tube panels directly above the roof 17 tubes on the inlet side to the horizontal crossover tubes in the boiler. All of 18 the T-11 tubing in the panels were upgraded to T-22 tubing to enable the 

# 19 panels to handle higher temperatures and thus better protect the panels from 20 overheating. The existing reheater panels in the Unit 1 boiler were suffering 

# 21 from long-term sootblower/flyash erosion and were overheating and warped 22 out of alignment, which made it impossible to keep these panels clean and 23 free from slag. During the past three years, SPS has had multiple tube leaks 24 in the reheater resulting in lost megawatt hours. 25 3. Harrington Unit 3-Purchase Generator Stator Coils (Parent Work Order 26 11350271) - This project consisted of purchasing stator coils to rewind the 27 Harrington Unit 3 generator. This Harrington generator had experienced 28 several failed end turns due to copper resistors. There appeared to be excess 29 greasing and dusting based on the last inspection. Siemens (the equipment 30 manufacturer) predicted, and internal experts concurred, that Harrington Unit 31 3 could fail catastrophically and be down for months without materials on 32 hand if this purchase was not made. These coils can also be utilized for the 33 other two generators at Harrington Station if needed. 34 4. Jones Unit 2-Replace Boiler Superheat Tube Panels(Parent Work Order 35 10639684) - This project replaced the original high temperature superheat 36 section in the Unit 2 boiler. The superheat section was showing signs of 37 continuous long-term overheating. X-rays ofthe tubes along with remaining 38 useful life testing showed the panels were at the end of their life due to 

# 39 thinning.X-rays also showed several cracks in the dissimilar metal welds 40 ("DMW"). The new tubes consisted of T-22 and 347 stainless steel tubing
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# 1 up to and including the terminal tubes on the outlet header located in the seal 2 box. The project included replacement of all of the DMWs along with 3 upgrade of the support lugs. 4 5. JonesPlant

-InstallDouble Pass RO Unit (ParentWork Orders 5 11486377) This project was to purchase and install double pass reverse 

# 6 osmosis ("RO") and nano filtration technology that increased the water 7 capacity from 60 gallons per minute ("GPM") to 100 GPM and utilized city 

# 8 effluent instead of potable water as the makeup source. The new double pass 9 RO unit now supplies boiler water to the steam units. The existing single 10 passRO unit was refurbished and is utilized to supply water to the 

# 11 evaporative coolers on the combustion turbines. By switching from city 12 potable water to city effluent, an annual cost savings of approximately 

# 13 $150,000 will be realized. 14 6. Blackhawk

-Gas Line PressureTest (Parent Work Order 11733376) - 

# 15 This project was to install valves, injectors, and receivers for pressure test 16 devices on SPS's gas line that supplies the Blackhawk power plant. This 

# 17 work was mandatory as part of the gas line integrity procedures and had to be 18 completed before the end of 2012. The project included project management, 19 contractor engineering and management, procurement of materials for testing 20 (pipe, sleeves, and fittings), site restoration and testing. 21 7. TolkStation

-Purchase Barrett Water Rights (ParentWork Order 22 11763413) - This project consisted of purchasing additional water rights, 

# 23 wells, electrical infrastructure, roads, and rights-of-way from the Barrett 24 family that were contiguous with SPS's current water rights. The additional 

# 25 water rights and wells will be used to offset production declines from SPS's 26 existing wells supplying water to Tolk Station and to Plant X. 27 8. TolkStation and Plant X- Water WellsPhase 6(ParentWork Order 28 11488948) - This project continued the development of new water wells to 

# 29 off-set production declines from existing wells at the Tolk Station and Plant 30 X. Three new wells, additional gathering pipelines, electrical service to the 

# 31 wells, roads, pumps, and controls were added. To maintain reliability, it is 32 critical to have adequate water supply available all year, but especially in the 

# 33 summer. Decline of SPS's current well field production puts Tolk Station 34 and Plant X at risk for a water shortage. 35 9. Cunningham Station Unit 4

-Major Upgradeto CTHotpath(Parent 36 Work Order 11629443) - New longer-life fuel nozzles, combustor baskets, 

# 37 clamshells, transitions and transitionsealswere installed in the combustion 38 section of the gas turbine. The project also included replacement of the row 

# 39 1and 2 vane and ring segments in the turbine section. The upgrades replaced 40 "end of life" equipment as well as extend the interval between outages from

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# 1 approximately every 4 years to approximately every 10 years 2 10. Tolk Station Unit 2 - Low NOxBurner Installation(Parent Work Order 3 11567088) - Low NOx burners, air registers, overfire air, duct work, 4 controls, and all associated equipment to reduce NOx emissions were 5 installed. This project was needed to comply with federal Cap and Trade 6 regulations. Environmental Services reviewed the emissions projections for 7 SPS's coal and gas-fired plants in the region and determined that SPS needs 8 to install this equipment to meet targets. 9 11. TolkStationUnit 2 -Replace Reheat Pendants(ParentWork Order 10 11338487) - This project was for the replacement of the complete reheat 

# 11 pendant section from the inlet header terminal tubes to the boiler penthouse 12 to the horizontal crossover tubes between the front and rear reheaters in the 

# 13 furnace with stainless steel tubes. During outages in 2008 and 2011, a 14 significant number of the T-22 reheat pendants were showing signs of long 15 term overheating and liquid phase corrosion in the upper sections. These 

# 16 conditions caused tube failures that degraded unit performance and required 17 several day outages to repair. 18 12. Tolk Station Unit 2 -Boiler Nose Replacement(ParentWork Order 19 11338489) - The top section of bull nose under the reheat pendants was 20 replaced with tubes containing a higher chrome content and with cladding to 21 make the area more water resistant. The bull nose area sees more ash erosion 22 than any other section of the boiler. During the last inspection of this boiler, 23 the nose tubes were eroded under the reheat pendants. 24 13. Jones StationUnit1 - Replace Superheat Tubes(ParentWork Order 25 11219850) - The original high temperature superheat boiler tubes were 26 replaced due to long-term overheating. The new tubes will consist of T-22 27 and 347 stainless steel tubing up to the stub tubes in the seal box, including 28 allDMW's and upgrade of the support lugs. Testing performed in 2006 29 showed that several of the tubes would be within the predicted window of 30 failure by 2012. Replacement of these tubes maintained or improved the 31 unit's current reliability. 32 14. HarringtonStationUnit 2-Rewind RotatingExciter (Parent Work Order 33 11937270) - The exciter on Unit 3 failed. Unit 2 was in outage and the 34 exciter was moved over to Unit 3. Siemens had a "seed exciter" that was 35 available for a core exchange of the existing exciter rotor. The rotor was 36 configured with the correct coupling and components and installed on Unit 2. 37 This replacement rotor saved weeks of outage time as compared to sending 38 the existing rotor offsite to be rewound. 39 15. JonesStation Unit 1 - Install Circulating Piping Liner(ParentWork 40 Order 10785167) - This project involved relining all of the circulating water

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# 1 line (both inlet and outlet) from the cooling tower to the condenser. The liner 2 is a polyurea liner and forms a "pipe in a pipe" once sprayed robotically onto 3 the steel circulating piping. The liner was a nominal 3/4" thick and covered 4 approximate 15,300 square feet. The existing piping had been in service for 5 over 40 years. During this time some leaks had occurred due to corrosion. 6 There had been repairs made in the past, but these were considered to be only 7 temporary. Installing the polyurea liner protected the plant from having 8 forced outages due to circulating pipe leaks or failures and adds structural 9 integrity to the existing piping. 10 16. MaddoxUnit 1-Replace CoolingTowerStructure PhaseI (Parent Work 11 Order 11747437) - This project entailed the eventual replacement of all of 12 thewood structure components on the cooling tower with fiberglass 13 components. This includes all columns, laterals, partition walls, end walls, 14 stairs and header supports. During the last outage, internal inspection found 15 the existing structure broken and the tower leaning as well as coming apart. 16 Immediate action was taken to shore up the structure. During Phase I of the 17 project, the first 3 cells were replaced while the unit was on line. The last 18 two cells will be replaced in late 2014 and early 2015. 19 17. TolkStation Replace

-Railroad Ties on the Dumper Loop(Parent Work 20 Order 11806033) - This project was to replace all of the wooden ties and 21 ballast on the dumper loop section of the train track. The rail operator 22 inspected the tracks and required that SPS replace ties and ballast over a 23 specific period of time. This is the first of 5 phases of track replacement that 24 was agreed to by the operator. It is critical that the rail line meet 25 specifications or there could be a derailment of a train. 26 18. HarringtonUnit 2-Install Circulating Water Liner(Parent Work Order 27 11629974) - This project involved installing a fiberglass reinforced poly 28 ("FRP") liner into the existing steel circulating piping for both suction and 

# 29 return lines below the finished floor from the condenser to outside of the 30 building. The liner will be 1" thick and cover approximately 14,000 sq. ft. of 31 pipe. The existing piping had been in service for over 36 years. During this 

# 32 time leaks had occurred due to corrosion. The piping was inspected during a 33 November 2011 outage. Temporary repairs were made at that time. 

# 34 Installing the FRP liner will help protect the plant from forced outages due to 35 circulating pipe leaks or failures and adds structural integrity (both 36 compression and tension) to the existing piping. ' 37 19. NicholsStation Unit 0 Inside Fire Main Addition(ParentWork Order 38 10637266) - This project was to install a firemain system on all three units at 39 the Nichols Station. The installation included a deluge system on the turbine/ 40 generator bearings, oil tanks and hydrogen seal oil systems. Also included 41 were wet pipe systems on the turbine/generator foundations and tie-in of

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# 1 existing cabinets for general fire fighting. Flame suppression systems will be 2 added and smoke detectors will be installed in control rooms, battery rooms, 3 computer rooms, etc. 4 20. JonesStationUnit 1- Rebundle #2 High Pressure Feedwater Heater 5 (ParentWork Order 11219855) - This project involved replacing the 6 feedwater heater, including abatement ofthe asbestos insulation on the heater 7 and associated piping. The project included removal of the old heater and 8 installation of the new heater, associated piping connections and 9 re-insulation.The old feedwater heater had experienced 7 leaks since 2005 10 resulting in an average annual availability loss of 53.3 hours. Each time 11 there was a repair, at least 5 tubes were plugged. The tube sheet also 12 experienced severe erosion due in part to the leaking feedwater heater. 13 21. Harrington Station Unit 1

-Replace HotWaterDeck and Westside 14 Louver Columns(Parent Work Order 11629974) - This project consisted of 15 replacing all of the Hot Water Decks on the cooling tower with fiberglass 16 panels.Also included was replacement of the Louver columns that support 17 the west side of the distribution header. It was discovered during the spring 18 2013 outage inspection that these columns were in disrepair and a failure 19 would cause the distribution header to collapse and a catastrophic failure of 20 the tower. 21 22. Harrington Unit 2 - Cooling Tower Structure Replacement Phase I) 22 (Parent Work Order 11805719) - Phase I of this project involved replacing 

# 23 all of the existing underwater wooden structures with fiberglass components. 24 The current tower was built in 1976 and earlier inspections showed that the 25 entire tower structure needed to be replaced. During the most recent cooling 26 tower inspection (1/29/2014), it was determined that the tower was in 

# 27 imminent danger of collapse if work did not start immediately. A systematic 28 plan was put together to replace the entire tower structure one cell at a time 29 ,

with work occurring while the unit is on line and during outages. Replacing 30 the remainder of the cooling tower structure will occur in subsequent phases 31 of this project. 32 Q. Isa work order closed as soon as the equipment subject tothat workorder is 33 placed inservice? 34 A. No. Frequently minor work continues after the equipment is placed in service and 35 the collection of costs related to the work order can occur for several months after the 36 equipment is placed in service. Thus, it is common for costs to be charged to a work

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# I order after the equipment is placed in service. This is why some of the in-service 2 dates in AttachmentAJD-RR-1 areearlier thanJuly 2012. Thisoccurred when costs 3 or refunds were booked on or afterJuly 1, 2012,but the equipment was placed in 4 service before that date. 5 Q. How arecapital budgets developed and then managed once a project begins? 6 A. SPS witness Raynard A. Gray describes the capital budgeting process in his direct 7 testimony. Once a capital project has been approved for execution, it is assigned to a 8 Project Manager ("PM"), typically three to six months in advance of the first planned 9 activity required to commence the project. The PM is responsible for working with 10 plant engineering and technical services personnel as well as subject matter experts 11 to review and more fully develop the final scope, schedule, and monthly cash flow 12 requirements for the assigned project. 13 The PM will typically contact vendors and contractors to firm up cost and 14 schedule data and begin engineering and purchasing activities. If the PM identifies 15 specific information related to significant potential cost or schedule variance to the 16 original approved budget, he PM advises management and recommends options for 17 consideration.Management then responds as appropriate depending on the specifics 18 of the information provided. As the PM works through the project details, the PM 19 develops a final scope of work, detailed cash flow, and schedules for the project. 20 The PM submits the updated project details to management as a funding plan to 21 receive child work orders that will collect the project charges. If the updates have 22 significant changes to the original approved budget, the funding plan is considered 23 the first change order for the project. These updated schedules and cash flows are Davidson Direct - Revenue Requirement page 21 

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# 1 entered into corporate accounting and project management systems when the child 2 work orders are assigned. 3 Once a project is funded and begins, the PM receives periodic (weekly or 4 monthly) reports that track actual expenditures and compare such expenditures to the 5 capital budget for the project.Monthly, significant budget variances are noted and 6 reviewed to ascertain the cause for the variance and what corrective actions can be 7 taken if budget limits have been exceeded or were greatly over-stated. If corrective 8 action is necessary and feasible, it is implemented. Sometimes the variance is simply 9 a timing issue and no corrective action is necessary. 10 In other cases, the budget may need to be amended because the project is 11 simply more or less costly than originally contemplated. In such situations, a scope 12 or budget change order is developed that revises the project to align with the current 13 needs. These requests are then reviewed and approved by the Regional Capital 14 Director. On a monthly basis, all of the changes are reviewed by the Regional 15 Capital Leads and then the Regional Prioritization Committee to re-rank these 16 projects along with new emergent projects to align with the year-end budget target. 17 Adjustments are made to the regional portfolio so as not to exceed the year-end 18 budget target for the SPS region. If this is not practical, the Regional Capital 19 Director will submit a regional target adjustment request to executive management 

# 20 for review and approval. 21 Typicallyduring the year, outages inspections will discover equipment that 22 needs significant repair or replacement to keep the unit reliable. In other situations, 23 equipment will fail. To address these situations, an "emergent project" will be Davidson Direct - Revenue Requirement Page 22 

# RRl 1- Page 391 of 474 05261

# 1 submitted by the plant director to fund the project. These projects are assigned to a 2 project lead or project manager and the scope and cost reviewed. Depending on the 3 time sensitivity of the project, the Regional Capital Director will fund the project if 4 deemed critical to be completed in the current year. If time permits, the project will 5 be reviewed by the Regional Prioritization Committee. To meet year end regional 6 targets, the project is funded out of the undesignated fund parent project. If funds are 7 not available, other projects will be cut or delayed or a target adjustment will be 

# 8 requested from executive management. 9 Q. Isthere any benchmarking evidence that supports your position that the Energy 10 Supply-related capital additions are reasonable? 

# 11 A. Yes. SPS witness Richard D. Starkweather presents the results of a benchmarking 12 studythat includesEnergySupply-related capital additions. 

# 13 B. Jones Unit 4 14 Q. Please describe Jones Unit 4. 15 A. Jones Unit4 is a relatively large, new, simple cycle Siemens5000F gas-fired CT 16 generating unit located at SPS's Jones Station southeastof Lubbock, Texas. This 17 unit has a summer capacity rating of approximately 172 megawatts("MW") and 18 includes a gas compressor.Thisproject was constructed to help meet capacity and 19 energy needs beginning the summerof 2013. Jones Unit 4 began commercial 20 operation on May 9, 2013, and has been used and useful to SPS in providing reliable 21 electric service since that date. 22 Q. Hasthe Commission considered the need forJones Unit 4?

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# 1 A. Yes. In July 2011, SPS applied to amend itsCCN toconstruct and operate Jones 2 Unit4.The Commission authorized construction of Jones Unit 4 by final order dated 3 October 28, 20114Jones Unit 4 was also certificated by the NMPRC by final order 4 dated February 7, 2012.5 5 Q. Hasthe cost of Jones Unit 4 been approved in prior Commission dockets? 6 A. No. I filed testimony regarding the cost of Jones Unit 4 in Docket No. 42004, but the 7 Non-Unanimous Stipulation in that docket, which is pending before the Commission 8 as of the date this current rate case is being filed, does not specifically address the 9 capital cost of this generation unit. 10 Q. At thetime it was certificated, what were the estimated cost and in-service date 11 of Jones Unit 4? 12 A. At the time Jones Unit 4 was certificated, the estimated cost was $117.6 million, 13 including AFUDC (total company). Included in this amount was substation work 14 and gas compression, but the estimate excluded transmission upgrades. The target 15 in-service date was prior to the peak demand period of 2013.

4 Application of Southwestern Public Service Company to Amend a Certificate of Convenience and Necessity for a Combustion Turbine in Lubbock County,Docket No, 39541, Final Order (Oct. 28, 2011).

5New Mex. Public Reg. Comm'n.,In the Matter of Southwestern Public Service Company's Application for: (1) Issuance of a Certificate of Public Convenience and Necessity for Jones Unit 4; (2) Authorization to Accrue an Allowance for Funds Used During Construction for Jones Unit 4; and (3) Authorization to Recover Fuel Costs for Jones Unit 4 in Accordance with Rule 550,Case No. 11-00313-UT, Final Order Approving Certification of Stipulation (Feb. 2, 2012).

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# I Q. What wasthe actual cost of Jones Unit 4? 2 A. The Energy Supply-related costs incurred as of June 30, 2014 were $83,418,968, 3 including AFUDC (total company). This cost is for the same scope ofwork included 4 in the $117.6 million estimated cost discussed above, except for the substation work 5 which cost an additional $1,313,695. Approximate costs by major category are 6 provided in the following table. 

# 7 Table AJD-RR-2 8 Major Equipment Cost $52,893,332

Construction Cost $16,737,315 Engineering and Construction Supervision $4,116,477 

# Capitalized Affiliate Charges $1,115,509 Gas Compression $3,934,040 AFUDC $4,622,295 

# Substation Work $1,313,695 Total Cost(total company) $84,732,663 9 Q. Was the $84,732,663(total company) cost of Jones Unit 4 reasonably incurred? 10 A. Yes. Jones Unit4 is neededby SPS toprovide reliable electric service and was 11 constructed for less than its original cost estimate and on a slightly faster schedule. 12 The construction project was prudently managed and the total cost of the project is 13 reasonable. General estimates from public sources show that the cost of an advanced 14 CT,like JonesUnit 4,would be approximately $488/kilowatt("kW")at 59 degrees 15 Fahrenheit and at sea level. This is considered the International Organization for 16 Standards("ISO")condition. This costdoes not include owner's cost, financing 17 costs, taxes, gas compression, and inlet cooling. By contrast, the cost of Jones Unit

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# 1 4, including owner's cost, financing cost, gas compression, and substation work, is 2 $434/kW at ISO condition, which is substantially less than a comparable market rate. 

# 3 C. Quay County Plant 4 Q. Please describe the Quay County Plant. 5 A. The Quay CountyPlant includes an existing23 MW CTgenerator that was moved 6 from SPS's Riverview Station near Borger, Texas to a site adjacent to SPS's 7 Campbell Substation in Tucumcari, New Mexico. The CT generator was refurbished 8 and retrofitted to burn No. 2 fuel oil. In addition, an existing SPS diesel generator in 9 Tucumcari was relocated to this site to provide black start capability, i.e., the ability 10 to start the CT generator without access to external power. In addition, a new 11 substation (Lopez) was constructed at the Quay County site to facilitate the 12 connection of the new power plant to the grid. The Quay County Plant primarily 13 provides system peaking service, which was the function the CT generator served at 14 the Riverview Station. The Quay County Plant has sufficient capacity to serve the 15 entireTucumcari load, including growth, when the transmission line serving 16 Tucumcari is out of service. 17 Q. When did the Quay CountyPlant begin commercial operation? 18 A. The commercial operation date was June 29, 2013. 19 Q. Why was the Quay CountyPlant necessary? 20 A. The Quay County Plant is a cost-effective solution to two issues: (1) SPS's 21 continuing need for system resources to provide peaking service; and (2) SPS's need 22 to provide reliable backup service to customers in Tucumcari. SPS serves the 23 approximate 17 MW Tucumcari load through an 80-mile long transmission line.
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# 1 Whenever this line is out of service, SPS must find an alternative way of supplying

2 power to the Tucumcari load. Historically, SPS used several diesel generators when 3 the transmission line was out of service. However, all but one these diesel generators 4 were removed from service by December 2011 because they were unreliable and 5 increasingly expensive to maintain. Thus, SPS needed to identify a solution that 6 would ensure reliable electric service to the Tucumcari customers. Moving, 7 refurbishing, and retrofitting the Riverview CT generator was the most reasonable 8 solution for the need in Tucumcari and SPS's need for peaking resources. 9 Q. DidSPS consider other alternatives, such as replacing the diesel generators at 10 the Tucumcari Plant, before deciding to developthe Quay County Plant? 11 A. Yes. SPS considered several alternatives, including replacing the diesel generators at 12 the original Tucumcari site, and decided that moving the Riverview CT generator to 13 Tucumcari was the least cost alternative that would: (i) provide a system benefit 14 (peaking service); (ii) serve Tucumcari's entire load and future growth; and (iii) 15 provide black start capability to Tucumcari. The options considered, their estimated 16 costs, and the reasons for rejecting each option are stated in the following table.

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# 1 Table AJD-RR-3 

# 1.Quay County Plant ProjectedCost $15.8 million (excluding AFUDC) 2.Construct Additional Projected Cost of $24.7 million - $42.3 Transmission Line million; Eliminated Due to Cost; No Benefit to Overall SPS System 

# 3.Install New Gas-fired Projected Cost of $39.6 million for Generation approximately 21 MW; Eliminated Due to 

# Cost 4.Install New Diesel Generation Projected Cost of $34.8 million for approximately 17 MW; Eliminated Due to 

# Cost; Insufficient Capacity for Growth 5.Upgrade the Tucumcari Plant Projected Cost of $24.5 million for Diesel Units and Install New approximately 14 MW; Eliminated Due to Diesel Unit Cost; Insufficient Capacity for Growth 6.Install Small Distributed Insufficient Capacity to Serve Tucumcari Generation (Diesel Generators) Load; Reliability Issues-Inability to Control 

# Load and Voltage; Projected Cost of $9.2 million for approximately 10 MW 7.Direct Interconnect to Western Lack of Proximity to WECC Facilities Electricity Coordination 

# Council ("WECC") 8.Purchase of Back-up Service Inadequate Transmission to Serve SPS's From Farmers Electric Tucumcari Load and FEC's Load Cooperative, Inc. ("FEC")

2 Q. WouldSPS have incurred costs in addition to those in Table AJD-RR-3 above if 3 it had pursued an option on that table and retained the Riverview Station CT as 4 a systempeaking resource? 5 A. Yes.The Riverview Station building was collapsing. To maintain the Riverview 

# 6 Station as a system resource, SPS would have had to rebuild the building. In

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# 1 addition, the availability of a firm gas supply to Riverview Station was questionable. 2 SPS may have had to expend additional funds to firm up the gas supply if the 3 generator had remained at Riverview Station. SPS avoided these expenditures at 4 Riverview by developing the Quay County Plant. 5 Q. Has the NMPRC reviewed the need for the Quay County Plant? 6 A. Yes. The NMPRC issued a CCNauthorizingSPS toconstruct and operatethe Quay 7 CountyPlant.6 In addition,theNew MexicoEnvironment Department has 8 authorizedSPS to operate the Quay County Plant. 9 Q. What was the capital cost of the Quay County Plant and when did the plant go 10 into service? 11 A. The Energy Supply-related costs incurred as of June 30, 2014 were $19,226,353, 12 including AFUDC. An additional $3,617,725 was spent for the new substation 13 portion of the project. Thus, as of the end of the Test Year, the total capital cost 14 associated with this project was $22,844,078. 15 Q. How does the cost of the Quay County Plant compare to the estimated cost 16 when the project was certificated? 

# 17 A. The estimated cost when the plant was certificated was $16.4 million including 18 AFUDC andsubstationwork,and excluding transmission up-grades. Thus, the 19 actual cost is $6.4 million (total company) more than the estimate when the plant was

6 In the Matter of Southwestern Public Service Company's Application for: (1) Issuance of a Certificate of Convenience and Necessityfor the Quay County Plant; (2) Authorization to Accrue an Allowance for Funds Used During Construction for the Quay County Plant; and (3) Authorization to Recover Fuel Costs for the Quay County Plant in Accordance with Rule 550,Case No. 12-00052-UT, Final Order (Jul. 3, 2012).

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# 1 certificated. The additional costs were due to three principal reasons. First, the costs 2 of major pieces of equipment were higher than the original estimate. Second, the 3 cost of moving the unit was higher than expected. Third, a new generation-serving 4 substation and distribution line upgrades cost more than originally estimated. In 5 budgeting the project, SPS solicited cost estimates from contractors, but the actual 6 bids received were all higher than the initial estimates provided in the budgeting 7 process. 8 Q. IfSPS had known earlier that the cost of the Quay County Plant would be 9 $22,844,078(total company), would SPS have decided to implement the project? 

# 10 A. Yes. Even at the higher cost, the Quay County Plant was the best option for 11 improving reliability in the Tucumcari area, providing a resource capable of serving 12 growthin the Tucumcari load, and simultaneously providing peaking service to the 13 SPSsystem asa whole. 14 Q. Were thecosts of theQuay CountyPlant reasonably incurred? 15 A. Yes.Given the unique nature of the project, it is not surprising that actual costs were 16 higher than the initial estimated cost. The final cost is still less than the estimated 17 cost of any alternative serving the same functions as the Quay County Plant. 18 Q. Do SPS's Texas retail customers benefit from the Quay County Plant? 19 A. Yes. The Quay County Plant is a system peaking resource. The Quay County Plant 20 produces power for the grid every month when tested and when called upon as a 21 peaking resource. All SPS customers benefit from system generation resources. As 22 a system resource, the Quay County Plant's 23 MW count towards the generation 23 reserve requirement SPS has under Southwest Power Pool rules. The Quay County Davidson Direct - Revenue Requirement Page 30 

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# Plant allowed SPS to avoid building additional network transmission facilities to

2 serve Tucumcari. If such transmission facilities had been built, that cost would have

been shared by all SPS customers.

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# 1 IV. ENERGY SUPPLY CAPITAL PROJECTS TO BE 2 PLACED IN SERVICE BETWEEN JULY 1 2014 AND 3 DECEMBER31, 2014 4 Q. Is SPSasking to recover Energy Supply-related capital costs for projects to be 5 placed in service between the end of theTest Yearand December 31, 2104? 6 A. Yes. SPS seeks to include in rate base the cost of capital additions placed in service 7 between the end of the Test Year (June 30, 2014) and December 31, 2014. 8 Attachment AJD-RR-2 identifies these projects and provides SPS's cost estimates for 9 these projects, which are budgeted amounts. SPS witness Lisa H. Perkett explains 10 the basis for these costs and an accounting adjustment. SPS witness Evan D. Evans 11 explains why these costs should be included in SPS's rate base in setting rates in this 12 docket. Mr. Evans also explains that SPS seeks to recover the lower of its actual 13 costs for these capital projects or the costs as stated on Attachment AJD-RR-2. SPS 14 will update Attachment AJD-RR-2 with actual costs after December 31, 2014. 15 Q. What isthe estimated cost of Energy Supply-related capital projects to be 16 placed in service betweenJuly 1,2014 and December31, 2014? 17 A. The total cost as reflected on Attachment AJD-RR-2 is $18,455,070.97, including 18 AFUDC (total company). Ms. Blair allocates the total company dollar amount 19 among SPS's three rate jurisdictions (Texas retail; New Mexico retail; and 20 wholesale). 21 Q. Are capitalized affiliate costs included in the total costs? 22 A. Yes, the costs include capitalized affiliate costs. However, affiliate costs are not 23 budgeted separately and therefore are not broken out on Attachment AJD-RR-2. 24 Based on historical percentages experienced in recent years, however, Ms. Perkett Davidson Direct - Revenue Requirement Page 32 

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# I has estimated in her Attachment LHP-RR-6 that $730,413.50 in affiliate charges are

2 included in the total requested amount for the period July 1, 2014 through December 3 31, 2014. 4 Q. Arethose affiliate costs necessary to complete the Energy Supply-related capital 5 projects? 6 A. Yes.Affiliate costs were incurred for the same reasons they were incurred on the 7 projects placed in service between July 1, 2012 and June 30, 2014 and discussed 8 earlier. 9 Q. Are thecosts of these capitalized affiliate charges reasonable? 10 A. Yes. These costs satisfy the standards for inclusion of affiliate costs in rates for the 11 reasons presented in the testimony of Mr. Low and Ms. Schmidt-Petree regarding the 12 reasonableness of affiliate charges. 13 Q. What isthe status of the projects listed on AttachmentAJD-RR-2? 

# 14 A. Many of these projects have already been completed and are now in service and the 15 charges incurred are to complete and close out the projects. 16 Q. Please describe the information in AttachmentAJD-RR-2,which provides the 17 estimates about the dollar amounts that are forecasted to be closed to plant in 18 service for the periodJuly 1,2014 to December31, 2014? 

# 19 A. Attachment AJD-RR-2 provides the following information:

Column A - Asset Class Identifies the type of asset. Column B - Witness Identifies the witness supporting the project. Column C - Parent Provides the parent work order number for the project.
Davidson Direct

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# Column D - Parent Description Provides a short title for the parent work order. Column E - Addition to Plant in The budgeted total company dollar

Service (July 2014 - amount of the addition to plant in Dec 2014) service.

I Q. Whydoes AttachmentAJD-RR-2 notlist the costs by individual work order as 2 is shown on AttachmentAJD-RR-1? 

# 3 A. Capital projects are budgeted at the parent project level, on a total basis, rather than 4 work order by work order. Because the costs on Attachment AJD-RR-2 reflect 5 budgeted numbers, they can be presented only at the parent work order level. 6 Q. Whydoes AttachmentAJD-RR-2have a line item of costs titled "Adjustments 7 to Additions in Second Half to Tie to Budgeted Ending Plant Balance"? 8 A. This line item reflects accounting adjustments made to ensure that the sum of (i) the 9 actual cost of projects closed to plant in service in the first half 2014 and (ii) the 10 estimated cost of projects to be closed to plant in service in the latter half of 2014 

# 11 equal SPS's total capital budget for all projects to be closed to plant in service in 12 2014. In her direct testimony, Ms. Perkett explains the need for these adjustments 13 and why there are two categories of projects scheduled to close in the second half of 14 2014.

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# Q. What typesof projects are being placed in service betweenJuly 1,2014 and



# 2 December 31, 2014? 3 A. Theyare similar to the projects placed in service during the prior 24 months and 4 discussed in Section III of this testimony in that they were necessary to maintain and

enhance the environmental,safety,performance, and reliability characteristics of 6 SPS's existing generation fleet. The following list describes the projects with a total 7 cost in excess of $ 1,000,000 that are to be placed in service between July 1, 2014 and 8 December 31, 2014. 9 1. Harrington Common- MercuryRemoval Facilities(Parent Work Order 10 11921829) - This project involves purchasing and installation of a silo, 11 blowers, grinding equipment and electrical systems to supply Activated 12 Carbon to the boilers for reduction of mercury in the flyash. This project 13 covers the common equipment that is shared between the boilers. The unit 14 specific equipment is described in a separate project. This project is 15 mandated by the Mercury and Air Toxics ("MATs") rule adopted by the 16 Environmental Protection Agency ("EPA"). 17 2. Harrington Station Units 1 and 3

-ACI Mercury Removal(Parent Work 18 Orders 10807076 10807078) - Thisproject consists of engineering, 19 purchasing and installation of a mercury reduction system to comply with 20 EPA's MATsrule.A chemical injection system(to injectActivatedCarbon) 21 consisting of lances(or an injection nozzle grid), piping, pumps and controls 22 will be installed in the duct work after the air preheater.Thisproject is being 23 duplicated on the remaining coal units in SPS's system and all must be in 24 serviceby April 2015. 25 3. TolkStation

-Common Mercury Removal Facilities(Parent Work Order 26 11921749) - This project involves installation of a silo, blowers, grinding 27 equipment and electrical systems to supply Activated Carbon to the boilers 28 for reduction of mercury in the flyash. This project covers the common 29 equipment that is shared between the boilers. The unit specific equipment is 30 described in a separate project. This project is mandated by the MATs rule 31 adopted by the EPA. 32 4. TolkStation - Purchase Rose Water Rights (ParentWork Order 33 11649187) - This project consists of purchasing additional water rights, 34 roads, and rights-of-way from the Rose family that are contiguous with SPS's
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# I current water rights. The additional water rights will be used to off-set 2 production declines from SPS's existing wells supplying water to Tolk 3 Station and to Plant X. 4 Q. What isthe project describedas "GMSOC2014 EmergentCapital" (Parent 5 Work Order 11227142)listed on AttachmentAJD-RR-2?" 6 A. This project is a placeholder in the budget to fund newly discovered work that 7 emerges throughout the year. When capital expenditures become necessary for a 8 project that was not anticipated or budgeted, a new capital project is created and 9 funds are moved from this emergent work parent work order to the new project. 10 Without this placeholder work order, if equipment fails or an unforeseen need arises, 11 a budgeted project would have to be cancelled or reduced to meet the year-end 12 capital expenditure limit. The absence of the placeholder would cause projects that 13 may already be funded and equipment ordered to be stopped and held until a future 14 outage. It is critical to the reliability of the units to continue to replace broken 15 equipment as needed. In addition, cost variances in current projects, whether over or 16 under budget, are collected in this work order. If a project is cancelled or delayed, 17 the unspent budget amounts are moved to this emergent project work order to fund 18 larger than expected emergent work and for cost increases on existing capital 19 projects.There are no capital costs actually charged to this parent work order. 20 Q. Willthe $2,086,235.38 budgetedfor GMSOC 2014EmergentCapitalbe spent 21 by yearend on necessary capital projects? 22 A. Yes, I believe it will. This work order is approximately 5% of the total Energy 23 Supply-related capital budget when the budget is initially approved. Historically, the 24 dollars in this work order are almost always reduced to zero by calendar year end.
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# 1 As Mr. Evans explains in his testimony, SPS is requesting only the lower of the 2 actual dollars closed to plant in service for the final six months of 2014 or the 3 estimated amount shown in Attachment AJD-RR-2. Thus, if there are unspent 4 dollars in this placeholder work order, SPS will not request those unspent dollars. 5 Q. Are thecapital costs presented in Attachment AJD-RR-2 reasonably reflective 6 of SPS's expected costs for Energy Supply-related capital projects to be placed 7 in service during the periodJuly 1,2014 through December 31, 2014? 8 A. Yes. Of course, more money will be spent on some projects, less will be spent on 9 others, and new projects will emerge that have to be addressed. Overall, however, 10 $18,455,070.97 (total company) is a reasonable estimate of the amount SPS will 11 spend on Energy Supply-related capital projects that will be placed in service during 12 the six-month period in question.

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# 1 V. CHANGES IN USEFUL LIVES OF GENERATING UNITS 2 Q. What topicdo you address in this section of your testimony? 3 A. Iworked with SPS witness Dane A. Watson, SPS's depreciation expert, to develop 4 revised useful lives for SPS's generating units. In this section of my testimony, I set 5 out the considerations underlying the useful lives I provided to Mr. Watson. 6 Q. What kindof considerations go into reviewing when a unit should be retired? 7 A. The current retirement dates for the units were set several years ago based on data 8 and information available at that time. There have been several changes to the 9 industry and market since that time that require some adjustments to the current 10 retirement schedules. There is no single factor that determines the appropriate 11 retirement date and several of the factors one must consider may be in opposition to 12 each other. From an economic, technology and operations point of view, the main 13 factors to be considered in setting a retirement date are summarized below. 

# 14 1.The extent to which new materials and technologies allow one to upgrade 15 and replace components that extend the useful life of a generating unit. 16 2.Computer modeling, such as the Portfolio Rationalization model used by 17 SPS, that estimates the value of specific generating units in markets such as the 18 day-ahead market operated by the Southwest Power Pool. The Portfolio 19 Rationalization model considers current and forecasted capital costs, current and 20 forecasted O&M costs of the unit, system load projections, fuel prices, type of fuel, 21 market cost of energy, market cost of capacity, book life of the unit, size, and several 22 other factors in estimating when specific generating units will no longer be

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# I competitive. The increasing efficiency of gas-fired units and lower gas prices are 2 accelerating dates when older generating units become uneconomic. 3 3. The practical need to incrementally stage unit retirements to align with 4 estimated system growth, the need for generation in specific locations, and 5 availability of replacement capacity. 6 4. The location of retired units and new construction, as well as available 7 transmission capacity, can influence subsequent retirement decisions. 8 5. The extent to which changes in the frequency of unit cycling effects 9 reliability and the associated costs. In general, units that were not designed for 10 frequent cycling will be negatively affected by the increased cycling common in 11 current market operations, but the precise effect on unit retirement is not well 12 understood at present. 13 6.The impacts of the transition to renewable technologies, such as wind and 14 solar generation. Accommodating these technologies causes more cycling and favors 15 newer generators that more easily adjust their output as generation from renewable 16 resources varies over time. 17 7. The extent to which units nearing retirement age can be reliably and 18 economically operated with a more limited capital budget. This factor suggests a 19 limitation on large equipment purchases and more emphasis on short term repair of 20 components or the use of equipment salvaged from retired units instead of 21 replacement. This change will limit the ability to extend the life of older units.

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# 1

2 Q. What changesin useful livesof generatingunitsdoes SPS proposein this rate



# 3 A. 4 5



# 6 7 Q. 8 A. 9 10 11 

# 12 13 case?

The changes vary from unit to unit, with some useful lives being shorter and others being longer. The following table summarizes the proposed changes. Table AJD-RR-4 Generating Unit Current Retirement Date Proposed

Retirement Date Yearsadded or

(subtracted) 

# Plant X Unit 1 2014 2019 5 Plant X Unit 2 2014 2020 6 Plant X Unit 3 2020 2024 4 Cunningham Unit 1 2014 2019 5 Maddox Unit 1 2030 2028 (2) Maddox Unit 2 2020 2025 5 Maddox Unit 3 2020 2025 5 Nichols Unit 1 2020 2022 2 Nichols Unit 2 2022 2023 1 Quay County 2035 2034 (1) Please explain the reasons for the changes identified above in TableAJD-RR-4. The SPS system has experienced significant growth over the past several years and this growth is forecasted to continue into the future. Thus, in general, SPS has a continuing need for capacity. Based on the Loads & Resources Balance Table, the Portfolio Rationalization model, and the current operating status and condition of the units, it is economic to continue to operate Plant X Units I and 2 and Cunningham Unit 1 until the

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# 1 2019-2020 time period. Cunningham Unit 1 currently has issues with the turbine 2 rotor and cooling tower, but mitigation plans are being implemented to keep the unit 3 viable until 2019. As of the proposed retirement dates, Plant X Units 1 and 2 will be 

# 4 67 years old and Cunningham Unit 1 will be 62 years old. At this time, it is not 5 advisable to plan to operate these units past their proposed retirement dates. 6 Nichols Units 1 and 2 are extended to the 2022-2023 timeframe due to age of 7 the units, when they will no longer be economic, and alignment with the need for 8 new generation to meet capacity needs at that time. At the proposed retirement 9 dates, these two units will be 62 and 61 years old, respectively. These units will 10 likely need substantial investment in the cooling towers and other components at that 11 time if their life is to be extended any further. 12 Plant X Unit 3 will be close to 70 years old at the proposed retirement date. 13 This unit is expected to need a few replacement items to keep it viable, but it appears 14 to still be economic and the proposed retirement date aligns with the next acquisition 15 of new resources. There are currently no serious issues associated with the 16 equipment in this unit. 17 Maddox Unit 1 was moved up by two years to align better with the economic 18 modeling. This unit is a single steam plant that is more expensive to operate than 19 multiple steam plants at a site. The retirement date would align with possible closing 20 of the plant after the combustion turbines are retired a couple of years earlier. The 21 proposed retirement date also aligns with possibly obtaining combined-cycle 22 generation in the area to replace the generation at this site. The cycling of this unit

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# 1 will increase over the next few years, and it is not clear if it can run much past 60 2 years, which will be reached in 2027. 3 Maddox Units 2 and 3 are both combustion turbines. Unit 2 is of a vintage 4 that is not efficient, but is fairly robust in nature. This unit has limited hours of 5 operation and SPS believes its life can be extended until the next major outage is 6 required. At that time, parts for this unit could be difficult to obtain and the 

# 7 continued operation of the unit may not be economic. Eventually it becomes less 8 expensive to replace a CT with new technology than continue to operate and repair 9 old technology. 10 Maddox Unit 3 is a very old technology placed in service in 1963 and is run 11 and maintained only as a black start unit. Although the life is extended, reliability 12 becomes a significant issue in the future. By aligning the retirements with the steam 

# 13 unit retirement, it is estimated to be more economic to retire the entire site and have 14 the needed generation produced at a more economical plant. 15 Quay County was moved up one year to align with the life expectancy ofthis 16 vintage of generation. Until there is more operational time on the unit at its new 17 location, it is difficult to assess the impact of the other factors listed above on the life 18 expectancy of this unit.

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# 1 VI. CONCLUSION 2 Q. Were Attachments AJD-RR-1 throughAJD-RR-2 andthe RPF schedules that 3 yousponsor or co-sponsor preparedby youor under your direct supervision 4 and control? 5 A. Attachments AJD-RR-1 and AJD-RR-2 and the RFP Schedules were prepared by 6 XES capital asset accounting personnel, and the information in Attachments 7 AJD-RR-1 and AJD-RR-2 are included in Ms. Perkett's Attachments LHP-RR-5 and 8 LHP-RR-6, respectively. My staff and I have reviewed these documents and 9 confirmed that the projects are Energy Supply-related projects and that the costs 10 appear to be correctly stated given the nature of the projects. 11 Q. Do you incorporate into your testimony the RFP Schedules that you sponsor? 12 A. Yes. 13 Q. Does this conclude your pre-filed direct testimony? 14 A. Yes.

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# AFFIDAVIT STATE OF TEXAS 

# COUNTY OF POTTER ALAN J. DAVIDSON,first being sworn on his oath, states: I am the witness identified in the preceding testimony. I have read the testimony and the accompanying attachments and am familiar with their contents. Based upon mypersonal knowledge, the facts stated in the testimony are true. In addition, in my judgment and based upon my professional experience, the opinions and conclusions stated in the testimony are true, valid, and accurate.



# . ALANJ.D IDSON

Subscribed and sworn to before me this day ofDecember2014 by ALAN J. DAVIDSON.

STELLA M. DIETRICH ^^ Notory Public.State of Texas F My CommissionExpires ^;;W March 23, 2016 

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