BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF COLORADO * * * * *

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF COLORADO * * * * * RE: IN THE MATTER OF ADVICE LETTER NO. 1672-ELECTRIC FILED BY PUBLIC SERVICE COMPANY OF COLORADO TO REVISE ITS COLORADO PUC NO. 7-ELECTRIC TARIFF TO IMPLEMENT A GENERAL RATE SCHEDULE ADJUSTMENT AND OTHER RATE CHANGES EFFECTIVE JULY 18, 2014. ) ) ) ) PROCEEDING NO. 14AL- E ) ) ) ) ) SUMMARY OF DIRECT TESTIMONY LISA H. PERKETT Ms. Lisa H. Perkett is Director, Capital Asset Accounting, for Xcel Energy Services Inc. Ms. Perkett oversees the capital asset accounting policies, the day-today maintenance of accounting and tax records for capital assets and the related reporting and regulatory requirements for Xcel Energy Inc. and its subsidiaries, including Public Service Company of Colorado ( Public Service or Company ). Ms. Perkett sponsors the plant in-service and other plant-related balances for January 1, 2015 through December 31, 2015 Test Year ( Test Year ) and the 2013 Historic Test Year ( HTY ) that were used to determine the rate base in the revenue requirements studies, respectively, sponsored by Company witness Ms. Deborah Blair and contained in Attachment Nos. DAB-3 and DAB-9. Ms. Perkett details how the plant balances are developed from a starting point of per-book balances as of December 31, 2013, and continuing through December 31, 2015. This monthly rollforward is presented in Attachment Nos. LHP-1 and LHP-2. As she explains, these plant balances are the basis for developing the related expenses, such as

depreciation and deferred taxes, and the resulting balances that are included as part of the rate base used in determining the Test Year revenue requirements. Ms. Perkett also reviews the accounting followed by the Company for Allowance for Funds Used During Construction ( AFUDC ) to accommodate special ratemaking treatment previously approved by the Commission for certain assets. Ms. Perkett also provides the Company s support for the Test Year depreciation and amortization expenses. Ms. Perkett supports the Company s request that the Commission approve new depreciation rates for its electric and common utility plant, as developed in the Electric and Common Utility Plant Depreciation Rate Study at December 31, 2013 ( Depreciation Rate Study ) and recommended by Company witness Mr. Dane Watson, who sponsors the study. The Depreciation Rate Study includes the results of the 2014 Decommissioning Cost Study ( Decommissioning Cost Study ), presented by Company witness Mr. Jeffrey Kopp, in the recommended depreciation rates for Public Service s electric generation units. The Depreciation Rate Study includes a depreciation reserve reallocation within each functional class. Ms. Perkett provides background information with respect to the Depreciation Rate Study and Decommissioning Cost Study and the extent to which the recommendations included in those studies have been incorporated into the depreciation rates the Company is proposing in this case, along with the associated annual book depreciation accruals and amortization expense. Ms. Perkett also explains and supports the Company s accounting and proposed ratemaking treatment for the Retired and Retiring Generating Units,

consisting of twelve generating units that have been retired or soon will be retired. The Retired Generating Units are comprised of nine electric generating units -- Cameo Units 1 and 2, Arapahoe Units 1 through 4, Cherokee Units 1 and 2, and Zuni Unit 1 that were recently retired. The Retiring Generating Units are comprised of three electric generating units -- Zuni Unit 2, Valmont Unit 5, and Cherokee Unit 3 that have not yet been retired, but will be retired at the end of the Test Year, or soon thereafter. After reviewing the accounting currently being employed for the nine Retired Generating Units, Ms. Perkett explains how regulatory accounting can be used to smooth the recovery of the remaining original cost investment and the final removal costs over a period extending beyond the retirement dates that were shortened as a result of the Clean Air-Clean Jobs Act ( CACJA ) and Colorado Public Utilities Commission ( Commission ) action prior to CACJA. Ms. Perkett explains and supports the Company s proposal to mitigate the otherwise significant impact of the amortization of the remaining original cost and estimated removal costs by extending the amortization period to four years (2015 through 2018) and by reallocating the book depreciation reserve for all of the Company s generating units within the steam production functional class, including the regulatory assets attributable to the Retired Generating Units. This reserve reallocation is reflected in the Depreciation Rate Study. With respect to the three Retiring Generating Units, Ms. Perkett explains that these three units are still incurring depreciation but will switch to amortization expense upon their retirement at the end of the Test Year or shortly thereafter. To provide for the same recovery period as the Retired Generating Units, the depreciation rates for these Retiring

Generating Units were developed in the Depreciation Rate Study using a terminal retirement date of 2018, the same end date used for the proposed amortization for the Retired Generating Units. Ms. Perkett recommends that the Commission approve the Company s proposed depreciation rates, as supported by the Depreciation Rate Study, and specifically: (1) the use of the updated removal cost estimates as set forth in the Decommissioning Cost Study to develop the depreciation rates for production plant; (2) the reserve reallocation performed as part of the Depreciation Rate Study to mitigate annual cost impacts; and (3) the inclusion of the regulatory assets for the Retired Generating Units in the reserve reallocation computation. She further recommends that the Commission approve the proposed amortization of the regulatory assets for the Retired Generating Units, as adjusted to reflect the updated removal cost estimates from the Decommission Cost Study, over a four-year period, and to approve this same recovery period for the Retiring Generating Units through both depreciation accruals and amortization following their actual retirement.

LIST OF ATTACHMENTS Attachment No. LHP-1 Attachment No. LHP-2 Attachment No. LHP-3 Attachment No. LHP-4 Attachment No. LHP-5 Attachment No. LHP-6 Attachment No. LHP-7 Attachment No. LHP-8 Plant-Related Roll Forwards for actual and forecast years 2013, 2014, and 2015 (Electric and Common) Link of Attachment No. LHP-1 to Attachment Nos. DAB-3 and DAB-9 Decommissioning Cost Estimation Principles Comparison of Current and Proposed Depreciation Rates by Plant Account Comparison of Depreciation Expense Based on Current and Proposed Depreciation Rates and Calculation of Pro Forma Adjustment to Depreciation Expense and Accumulated Reserve for Depreciation Accounting Example for Retired Generating Units Amortization Schedule for Retired Generating Units Amortization Schedule for Retiring Generating Units

GLOSSARY OF ACRONYMS AND DEFINED TERMS Acronym/Defined Term ADIT AFUDC Alliance Burns & McDonnell CACJA Commission or Colorado PUC Commission Staff or Staff COR CWIP Decommissioning Cost Study Depreciation Rate Study Meaning Accumulated Deferred Income Taxes Allowance for Funds Used During Construction Alliance Consulting Group Burns & McDonnell Engineering Company, Inc. Clean Air-Clean Jobs Act Colorado Public Utilities Commission Staff of the Colorado Public Utilities Commission Cost of Removal Construction Work in Progress 2014 Decommissioning Cost Study Electric and Common Utility Plant Depreciation Rate Study at December 31, 2013 FERC GAAP HTY IRS NSP Public Service, or Company Federal Energy Regulatory Commission Generally Accepted Accounting Principles Historical Test Year Internal Revenue Service Northern States Power Public Service Company of Colorado

TCA Rider Transmission Cost Adjustment Rider Test Year January 1, 2015 through December 31, 2015 USofA Xcel Energy XES Uniform System of Accounts Xcel Energy Inc. Xcel Energy Services Inc.

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF COLORADO * * * * * RE: IN THE MATTER OF ADVICE LETTER NO. 1672-ELECTRIC FILED BY PUBLIC SERVICE COMPANY OF COLORADO TO REVISE ITS COLORADO PUC NO. 7-ELECTRIC TARIFF TO IMPLEMENT A GENERAL RATE SCHEDULE ADJUSTMENT AND OTHER RATE CHANGES EFFECTIVE JULY 18, 2014. ) ) ) ) PROCEEDING NO. 14AL- E ) ) ) ) ) DIRECT TESTIMONY AND ATTACHMENTS OF LISA H. PERKETT 1 2 3 4 5 6 7 8 9 10 11 12 13 I. INTRODUCTION, QUALIFICATIONS AND PURPOSE OF TESTIMONY, AND RECOMMENDATION Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. A. My name is Lisa H. Perkett. My business address is 414 Nicollet Mall, Minneapolis, MN 55401-1993. Q. BY WHOM ARE YOU EMPLOYED AND WHAT IS YOUR POSITION? A. I am employed by Xcel Energy Services Inc. ( XES ), as Director, Capital Asset Accounting. XES is a wholly-owned subsidiary of Xcel Energy Inc. ( Xcel Energy ), and provides an array of support services to Public Service Company of Colorado ( Public Service or Company ) and the other utility operating company subsidiaries of Xcel Energy on a coordinated basis. Q. ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING? A. I am testifying on behalf of Public Service.

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Q. PLEASE SUMMARIZE YOUR RESPONSIBILITIES AND QUALIFICATIONS. A. As Director of Capital Asset Accounting, I am responsible for and oversee the overall capital asset accounting policies, day-to-day maintenance of accounting and tax records for capital assets, and the related reporting and regulatory requirements for Xcel Energy and its subsidiaries. A description of my qualifications, duties, and responsibilities is included as Attachment A. Q. WHAT IS THE PURPOSE OF YOUR DIRECT TESTIMONY IN THIS PROCEEDING? A. My testimony is divided into three main parts, as follows: I support the calculation of plant-related balances for January 1, 2015 through December 31, 2015 Test Year ( Test Year ) and the presentation of year-end 2013 balances for the historic test year ( HTY ) in the respective revenue requirements studies presented by Company witness Ms. Deborah Blair; 16 17 18 19 20 21 22 23 24 I sponsor the updated depreciation rates for electric and common utility plant accounts being proposed by the Company for approval in this case, as supported by the Electric and Common Utility Plant Depreciation Rate Study at December 31, 2013 ( Depreciation Rate Study ) performed by Alliance Consulting Group ( Alliance ) and sponsored by Company witness Mr. Dane Watson and the separate 2014 Decommissioning Cost Study ( Decommissioning Cost Study ) performed by Burns & McDonnell Engineering Company, Inc. ( Burns & McDonnell ) sponsored by Company witness Mr. Jeffrey Kopp; and 25 26 I present the regulatory asset and liability balances for the steam generation assets that were either recently retired ( Retired Generating 2

1 2 3 4 5 6 7 8 9 Units ) 1 or will soon be retired ( Retiring Generating Units ), 2 for the most part before their current terminal retirement dates, including those retired early pursuant to the Clean Air-Clean Jobs Act ( CACJA ), and the Company s proposal for the amortization of these regulatory assets to provide for the Company s recovery of the associated remaining costs. Q. ARE YOU SPONSORING ANY ATTACHMENTS AS PART OF YOUR DIRECT TESTIMONY? A. Yes. I am sponsoring the following Attachments: 10 Attachment No. LHP-1 (plant-related roll forwards); 11 12 13 14 Attachment No. LHP-2 (schedule linking Attachment No. LHP-1 to Attachment Nos. DAB-3 and DAB-9); Attachment No. LHP-3 (documentation of decommissioning estimation principles); 1 2 The term Retired Generating Units, as used in my testimony, refers to nine electric generating units -- Cameo Units 1 and 2, Arapahoe Units 1 through 4, Cherokee Units 1 and 2, and Zuni Unit 1 that were recently retired. Public Service has established regulatory assets to account for the remaining net book costs and dismantling costs associated with these Retired Generating Units. All except one of these Retired Generating Units were retired early; i.e., prior to the terminal retirement dates upon which the last Commission-approved depreciation rates were based. Although not retired early, Zuni Unit 1 has an unrecovered regulatory asset balance and is being included as part of the Retired Generating Units for ease of reference. The term Retiring Generating Units, as used in my testimony, refers to three electric generating units -- Zuni Unit 2, Valmont Unit 5, and Cherokee Unit 3 that have not yet been retired, but will be retired at the end of the 2015 Test Year, or soon thereafter. Because they are still in operation, these Retiring Generating Units are still reflected in the Company s plant in-service and accumulated reserve for depreciation. Valmont Unit 5 and Cherokee Unit 3 will be retired before the terminal retirement dates upon which the last Commission-approved depreciation rate was based. Although not scheduled to retire early, Zuni Unit 2 will have remaining an unrecovered regulatory asset balance and is being included as part of the Retiring Generating Units for ease of reference. 3

1 2 Attachment No. LHP-4 (comparison of current and proposed depreciation rates by plant account); 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 Attachment No. LHP-5 (comparison of depreciation expense for 2015 Test Year based on current and proposed depreciation rates and calculation of the pro forma adjustment to depreciation expense and accumulated depreciation); Attachment No. LHP-6 (sample accounting for the Retired and Retiring Generating Units); Attachment No. LHP-7 (regulatory assets for Retired Generating Units and the comparison of current and proposed amortization for each station; and Attachment No. LHP-8 (regulatory assets for Retiring Generating Units and the comparison of current and proposed amortization for each station). Q. WHAT RECOMMENDATIONS ARE YOU MAKING IN YOUR TESTIMONY? A. I recommend that the Colorado Public Utilities Commission ( Commission ) approve the Company s proposed depreciation rates, as supported by the Depreciation Rate Study, and specifically: (1) the use of the updated removal cost estimates as set forth in the Decommissioning Cost Study to develop the depreciation rates for production plant; (2) the reserve reallocation performed as part of the Depreciation Rate Study to mitigate annual cost impacts; and (3) the inclusion of the regulatory assets for the Retired Generating Units in 23 the reserve reallocation computation. I further recommend that the 24 25 Commission approve the proposed amortization of the regulatory assets for the Retired Generating Units, as adjusted to reflect the updated removal cost 4

1 2 3 estimates from the Decommission Cost Study, over a four-year period, and to approve this same recovery period for the Retiring Generating Units through both depreciation accruals and amortization following their actual retirement. 5

1 II. PLANT-RELATED BALANCES AND EXPENSES 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Q. WHAT GOVERNS THE COMPANY S ACCOUNTING PRACTICES? A. The Company follows the applicable accounting rules established by Generally Accepted Accounting Principles ( GAAP ), the Uniform System of Accounts ( USofA ) established by the Federal Energy Regulatory Commission ( FERC ) for public utilities, and policies and guidelines established by the Company s Capital Asset Accounting department, such as the Capitalization Policy. The Commission requires that the Company keep its books and records in compliance with the USofA. Q. HOW WERE YOU INVOLVED IN THE DEVELOPMENT OF THE FORECASTED PLANT IN-SERVICE BALANCES USED FOR THE COST OF SERVICE STUDY SPONSORED BY MS. BLAIR? A. My department, Capital Asset Accounting, is responsible for all aspects of the fixed asset accounting for Public Service. We routinely develop and provide information regarding forecasted plant information to be used in rate base and revenue requirements analyses presented by the Revenue Analysis Group, including Ms. Blair. One of the main components affecting rate base, and thus revenue requirements, is additions to plant, also known as capital additions. Q. HOW DO CAPITAL ADDITIONS INFLUENCE RATE BASE? A. In regard to plant assets, rate base has two main components -- plant balances and accumulated reserve for depreciation (a reduction to rate base). Capital additions increases plant balances. Depreciation expense increases the accumulated reserve for depreciation, thereby lowering rate base. If 6

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 capital additions were equal to depreciation expense, the plant-related rate base would remain constant. If plant-related rate base increases from one year to the next, it is because capital additions are greater than the depreciation expense. Attachment No. LHP-1, which I will explain in more detail later in my testimony, includes forecasted capital expenditures for additions that have projected in-service dates during forecast years 2014 and 2015 (2015 being our Test Year) and thus will affect these years plant additions, which in turn affects the Test Year rate base and revenue requirement. The overall rate base used in the Test Year cost-of-service study in this case reflects the increase in plant balances from the base period ending December 31, 2013. Q. DO YOU EXPLAIN THE NEED OR PURPOSE OF THE UNDERLYING CAPITAL ADDITIONS INCLUDED IN RATE BASE? A. No. The following Company witnesses are providing testimony to support of the plant in-service associated with their organizations within the Company: Kelly Bloch - Distribution Mark Fox- Energy Supply Betty Mirzayi - Transmission David Harkness- Business Systems Greg Robinson Shared Corporate Services Each of the business areas represented by these witnesses is responsible for the actual planning and decision-making regarding the capital expenditures, as well as the analyses necessary to develop the capital budgets and project plans. My area of responsibility begins where theirs 7

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 finishes. I am responsible for the calculations of plant-related balances and expenses, which can only be derived once the various business areas have completed their analyses. The process of moving the construction costs from Construction Work in Progress ( CWIP ) to plant in-service produces the capital additions that then form the basis from which all the other plant-related information can be calculated. Q. WHAT IS INCLUDED IN PLANT-RELATED INFORMATION? A. Plant and plant-related information consists of account balances for plant inservice and the balances and expenses directly derived from plant, such as depreciation expense, depreciation reserve, tax depreciation, deferred taxes, and Accumulated Deferred Income Taxes ( ADIT ). Plant-related balances consist of CWIP, depreciation reserve, and ADIT. Plant-related expenses are Allowance for Funds Used During Construction ( AFUDC ), book depreciation, and annual deferred taxes. Plant and plant-related information are an important part of the overall development of rate base and revenue requirements. The plant component of rate base consists of plant in-service less depreciation reserve less accumulated deferred taxes on plant. Q. IS THE FORECASTED PLANT AND PLANT-RELATED INFORMATION BASED ON ESTABLISHED PLANT ACCOUNTING PRINCIPLES? A. Yes. In a forecast presentation, the development of the plant information follows the applicable accounting rules established by GAAP, the FERC, and policies and guidelines established by the Company s Capital Asset 23 Accounting department, such as the Capitalization Policy. Thus, the 8

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 forecasted plant and plant-related information are developed using the same methods, rules, calculations, and factors as the Company uses to record actuals on its books each month. For example, the tax depreciation and deferred income taxes for our Test Year (as well as the 2013 HTY that Ms. Blair presents for informational purposes) use the same accounting module and routines that are employed to prepare deferred tax journal entries and to produce the tax filing information filed with the Internal Revenue Service ( IRS ). Q. PLEASE DESCRIBE THE DEVELOPMENT OF PLANT AND PLANT- RELATED INFORMATION IN THE TEST YEAR. A. The information is extracted from the Company s 2015 forecast information for plant assets for the two 13-month periods ending December 31, 2014 and December 31, 2015. As with any plant information, the forecasted balances for these years are significantly influenced by the activity in the preceding years. Therefore, the plant information is rolled forward month by month (known as a monthly roll forward ) from the last month s actuals at the time the forecast was prepared, which in this case was December 2013, and forecasted plant and plant-related balances are built upon these actuals using the forecasted changes in plant and plant-related expenses for each month until all months have been calculated through the end of the forecast period. Attachment No. LHP-1 summarizes this roll forward calculation from the last actual plant in-service balances as of December 31, 2013 through December 31, 2015 for electric and common utility plant. This roll forward serves as the 9

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 basis for the forecasted plant in-service balances used by Ms. Blair in the determination of the forecasted rate base in Attachment Nos. DAB-3 and DAB-9. Attachment No. LHP-2 has been provided as a numerical link of plant-related data between my Attachment No. LHP-1 and the revenue requirements studies contained in Ms. Blair s Attachment Nos. DAB-3 and DAB-9. Q. WHAT ARE THE MAIN COMPONENTS OF PLANT AND PLANT-RELATED INFORMATION? A. As I mentioned above, there are several components that comprise the plant and plant-related information. The three most significant components are construction work in progress ( CWIP ), plant in-service, and the accumulated reserve for depreciation. CWIP is an account that is used to gather all the construction-related costs together as they are being incurred during the construction of the project or facility. The costs incurred to construct or install a fixed asset in the construction process are capital expenditures. The accumulation of the construction expenditures in CWIP continues until the asset becomes used and useful, which is typically when the asset is placed into service. The amount transferred from the accumulated CWIP balance to plant in-service is known as the capital addition or plant addition. Plant in-service represents facilities that are used and useful in providing utility service, including facilities currently in-service, capital projects completed but not classified, and property held for future use. Forecasted 10

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 plant in-service represents historical and projected additions and retirements to Public Service s electric and common utility plant accounts. Common utility represents all of the property that is used in the general operations of the business that affect more than one utility, such as electric and gas operations. Plant additions represent plant that will become used and useful during the month. Accumulated reserve for depreciation, also known as the depreciation reserve, is the accumulation of depreciation expense taken on assets that are in-service. When an asset is retired, the depreciation reserve is reduced by the original cost of that asset based on the assumption that the asset is fully expensed (i.e., fully depreciated) at that time. The average monthly plant balance multiplied by the applicable depreciation accrual rate results in the depreciation expense, which is added to and consequently results in an increase in the depreciation reserve. Factored into the depreciation rate is a net salvage rate component to provide for the estimated cost of future removal less any gross salvage value. Lastly, the depreciation reserve is decreased by actual removal expenditures when incurred, and increased by any salvage proceeds received. Q. PLEASE PROVIDE A SUMMARY OF THE CWIP ACTIVITY IN A MONTH. A. During the course of each month, the beginning CWIP balance is increased by CWIP expenditures incurred during the month and AFUDC, and is reduced by the CWIP balances associated with projects that are placed in service during the month. Table 1 summarizes the monthly transactions for CWIP: 11

Table 1 Construction Work in Progress CWIP Beginning Balance + CWIP Expenditures + AFUDC - CWIP Closings (equal to Additions to Plant In-service) = CWIP Ending Balance 1 2 3 4 Q. PLEASE PROVIDE A SUMMARY OF PLANT ACTIVITY IN A MONTH. A. During the course of each month, the beginning plant balance is increased to reflect plant additions and reduced to reflect plant retired from service. Table 2 summarizes the monthly transactions for plant. Table 2 Plant In-service Plant Beginning Balance + Additions (equal to CWIP Closings from Table 1) - Plant Retirements = Plant Ending Balance 5 6 7 8 9 10 11 Q. PLEASE PROVIDE A SUMMARY OF DEPRECIATION RESERVE ACTIVITY IN A MONTH. A. During the course of each month, the beginning depreciation reserve is increased by depreciation expense and any salvage proceeds realized, and is reduced by the depreciation reserve attributable to retirements (equal to the gross plant cost of the retired assets) and removal costs. Table 3 summarizes the monthly transactions for depreciation reserve. 12

Table 3 Accumulated Reserve for Depreciation Depreciation Reserve Beginning Balance + Depreciation Expense - Plant Retirements +/- Adjustments (i.e. Reserve Reallocations) + Salvage Value Realized - Plant Removal Expenditures = Depreciation Reserve Ending Balance 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Q. WHEN YOU PRESENTED THE ITEMS RECOGNIZED IN THE CWIP ROLLFORWARD IN ATTACHMENT NO. LHP-1, YOU LISTED AFUDC. WHAT IS AFUDC? A. AFUDC is used to assign the assumed cost of financing construction to the asset that would normally be expensed on the income statement during construction. Once the construction is completed and the asset is placed into service, the total cost of the asset, including the AFUDC, is systematically allocated back to the income statement in the form of depreciation expense over the life of the asset. Since the AFUDC is part of the asset cost, the construction financing costs move from the balance sheet to the income statement as a part of depreciation over the life of the asset. Public Service follows the FERC USofA in calculating the AFUDC rate and its application to construction projects. The AFUDC rate is a weighted-average cost of capital that first gives weight to short-term debt as a function of the CWIP balance and then factors in the costs of long-term debt and common equity. 13

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 Q. WHAT IS PRE-FUNDED AFUDC AND WHY IS IT NOT SHOWN AS AN ITEM IN THE CWIP ROLLFORWARD IN ATTACHMENT NO. LHP-1? A. Pre-funded AFUDC is a mechanism used by the Company and approved by the Commission to track the estimated financing costs of construction when the Company is authorized to recover these financing costs in current rates while the asset is under construction. This is the mechanism that we use to effect the current recovery of CWIP allowed by the Commission for certain projects. When construction of the asset is completed and it is placed in service, the Pre-funded AFUDC accumulated in a regulatory liability operates as an offset to rate base, or a credit to the AFUDC that accumulates as part of the asset in rate base under the FERC requirements. It ensures that the customers in jurisdictions allowing CWIP in rate base get the appropriate credit, while in those jurisdictions not allowing for such treatment, AFUDC continues to accrue for the asset. Q. HOW IS PRE-FUNDED AFUDC CALCULATED? A. To keep appropriate accounting across all jurisdictions, we continue to use the traditional method of calculating the AFUDC in accordance with the FERC requirements at the total Company level. For those construction assets for which CWIP is included in rate base, Pre-funded AFUDC is recognized concurrently, which in effect reverses the jurisdictional portion of the regular AFUDC. This offset, referred to as Pre-funded AFUDC, reduces the amount of AFUDC associated with the projects afforded this special ratemaking treatment, leaving only that portion that is allocated to wholesale jurisdictions. 14

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 The Pre-funded AFUDC and regular AFUDC are not commingled, but are tracked separately such that the retail jurisdictional customers are assured their entire benefit. Pre-funded AFUDC is recorded in FERC Account No. 253, Other Deferred Credits, during the construction process as AFUDC is incurred. From the perspective of the Commission, the amount is a jurisdictional amount. Once the associated asset is placed into service, the Pre-funded AFUDC balance is amortized over the same time period as the associated asset. Therefore the Pre-funded AFUDC amount recorded during construction unwinds over the useful life of the asset for which the amount was created during construction. Q. WHICH ASSETS HAVE PRE-FUNDED AFUDC ASSOCIATED WITH THEM IN THIS PROCEEDING? A. Currently, Comanche Unit 3 and certain transmission assets use the prefunded AFUDC method resulting from previous Commission orders. In this rate case, the Company is requesting the use of Pre-funded AFUDC for several of the new CACJA-related projects. The CACJA-related projects include costs associated with the new Cherokee 2 X 1 combined cycle (Cherokee Units 5, 6, and 7), and costs of the emissions controls on Pawnee Unit 1, Hayden Unit 1 and Hayden Unit 2. I will discuss each of these assets below. In accordance with the Settlement Agreement in Proceeding No. 06S-234EG, approved by the Commission in Decision No. C06-1379, Public Service included the December 31, 2006 ending CWIP balance for 15

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 Comanche Unit 3 and its related projects (pollution control projects at Comanche Units 1 and 2 and Comanche Unit 3 transmission) in rate base, thereby establishing the 2006 layer for accumulation of Pre-funded AFUDC. As a result of the treatment authorized by the Commission in Decision No. C06-1379, retail jurisdiction customers do not have to provide for AFUDC on a portion of the CWIP balance associated with Comanche 3 during its project phase. In Decision No. C09-1446 in Proceeding No. 09AL-299E, a second pre-funded layer for the Comanche 3 project was established based on the ending 2009 CWIP balance. The Comanche Unit 3 Pre-funded AFUDC amounts are in the amortization phase, with the amount accumulated in the regulatory liability as of December 31, 2013 of $61.9 million being amortized over the 57-year remaining life based on the 60-year whole life assigned to Comanche Unit 3. Beginning in 2008, transmission projects in CWIP as of December 31, 2007 were included in the rate base calculation for the Transmission Cost Adjustment rider ( TCA Rider ). Again, as a result of the treatment authorized by the Commission in Decision No. C06-1379, retail customers do not have to provide for AFUDC on a portion of the CWIP balance associated with certain transmission projects included in the TCA Rider. Pursuant to the settlement in the Company s last electric rate case in Proceeding No. 11AL-947E, the Company agreed to forego current recovery of CWIP in rate base on CACJA-related projects during the term of that Settlement, although entitled to such recovery under the CACJA. As 16

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 discussed by Company witness Ms. Alice Jackson in her Direct Testimony, the treatment provided for under the Settlement Agreement in the last rate case for CACJA-related project costs expires upon the effective date of rates in this rate case. Consequently, the Company is seeking in this rate case to include in rate base the full amount of CWIP associated with the ongoing CACJA-related construction projects and to accrue Pre-funded AFUDC on the amount of the associated CWIP balances at the start of 2015 for the Test Year and the end of 2013 for the 2013 HTY. Q. HOW IS THE COMPANY PROPOSING TO TREAT PRE-FUNDED AFUDC IN THE COST OF SERVICE STUDIES FOR THE TEST YEAR AND THE 2013 HTY? A. Pre-funded AFUDC has been included in both the determination of rate base and the income statement, so that retail customers do not bear the costs of AFUDC for projects where they have already provided for a current return on CWIP. Inclusion of Pre-funded AFUDC results in preventing the double recovery of costs from ratepayers, once through a current return on CWIP and again through the recovery of AFUDC. Pre-funded AFUDC is provided for assets once the Company begins to earn a return on the CWIP balance associated with that asset. In the revenue requirements studies for the 2013 HTY and the Test Year sponsored by Deborah Blair, all retail jurisdictional Pre-funded AFUDC has been directly assigned to the retail jurisdiction, according to (i) the functional class of the associated asset for CWIP, depreciation reserve, plant 17

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 in-service, and accumulated deferred income taxes in rate base, and (ii) AFUDC, depreciation expense, and deferred taxes expense included in the income statement. Accumulated Pre-funded AFUDC is a reduction to rate base after it has been allocated by jurisdiction, with the amortization of the Pre-funded AFUDC balance being a reduction to depreciation expense after the total Company expense was assigned to the retail jurisdiction. These Prefunded AFUDC items are already at a jurisdictional level; thus, any offset must be made once the rate base and the income statement are allocated by jurisdiction. Q. PLEASE EXPLAIN HOW THE RATE TREATMENT OF CWIP FOR NEW CONSTRUCTION CACJA-RELATED PROJECTS UNDER THE LAST RATE CASE SETTLEMENT IN PROCEEDING NO. 11AL-947E AFFECTS THE ABOVE-DESCRIBED ACCOUNTING FOR PRE-FUNDED AFUDC. A. Since the last rate case, the Company has been accruing AFUDC at the allowed rate of return on CWIP for the new construction projects related to CACJA. This AFUDC rate exceeds the amount provided by the FERC calculation under the USofA. The difference is Excess AFUDC. The projects with Excess AFUDC are the Combined Cycle for Cherokee (Units 5, 6, and 7) and the pollution control equipment for Pawnee and Hayden. Q. HOW DOES THE ACCOUNTING WORK FOR EXCESS AFUDC? A. Excess AFUDC is the method used to account for the difference between the AFUDC calculated in accordance with FERC requirements ( FERC AFUDC ) and the authorized return on rate base as allowed by the CACJA on CWIP for 18

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 the CACJA-related projects. This Excess AFUDC is calculated each month in tandem with the FERC AFUDC and is recorded both to the AFUDC income statement accounts and to a regulatory asset account on the balance sheet. Once the project is completed and the asset is placed in service, the associated Excess AFUDC regulatory asset is then amortized over the useful life of the asset. Excess AFUDC is being accumulated in this manner for the CACJA-related projects and will continue to be through December 31, 2014. Q. WHEN DOES EXCESS AFUDC BECOME PART OF THE RATE BASE IN COLORADO? A. In a revenue requirements study using an historical test year, CWIP is included in rate base with an AFUDC offset to operating earnings. Where there is Excess AFUDC, the Excess AFUDC regulatory asset is included in rate base and the related income statement accounts are included in the revenue requirement calculation. In a revenue requirement study using a future test year, however, the regulatory asset that is accumulating the monthly Excess AFUDC amounts is not included in rate base until the asset is placed in service. The reason for this is that CWIP is not in rate base with an AFUDC offset under a future test year convention; thus, the Excess AFUDC is also not added to the revenue requirement. 19

1 III. DEPRECIATION AND AMORTIZATION EXPENSE 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 Q. PLEASE SUMMARIZE THE COMPANY S PROPOSALS IN THIS PROCEEDING WITH REGARD TO CHANGES IN DEPRECIATION EXPENSE AND AMORTIZATION EXPENSE. A. The Company is proposing significant changes to depreciation expense for its electric and common utility plant in this proceeding and is proposing to implement a plan of amortization to recover the remaining costs associated with the Retired and Retiring Generating Units. The Company s depreciation rates for its electric assets have not been updated since 2006. The Company s proposed changes to depreciation and amortization expense are supported by the Depreciation Rate Study, sponsored by Mr. Dane Watson, and the Decommissioning Cost Study, sponsored by Company witness Mr. Jeff Kopp. Q. WHAT IS THE CHANGE IN DEPRECIATION AND AMORTIZATION THAT PUBLIC SERVICE IS REQUESTING? A. The proposed change in the Company s annual depreciation expense for the Test Year using the proposed depreciation rates as reflected in the Depreciation Rate Study and 2015 plant balances before allocation to the retail jurisdiction is an increase of $48.5 million. The change to annual amortization expense for the Test Year for the Retired Generating Units is a decrease of $9.0 million. Combining these amounts, the total increase in annual depreciation and amortization for the Test Year is $39.5 million. 20

1 2 3 4 5 6 7 As a point of reference, the corresponding change to annual depreciation expense, based on December 31, 2013 balances, resulting from the depreciation rates recommended in the Depreciation Rate Study before allocation to the retail jurisdiction is an increase of $43.5 million. The change to annual amortization expense for the Retired Generating Units is a decrease of $9.0 million. Combining these amounts, the total increase in annual depreciation and amortization expense for the HTY is $34.5 million. 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 A. DEPRECIATION RATES FOR ELECTRIC AND COMMON UTILITY PLANT Q. PLEASE DEFINE DEPRECIATION. A. The definition of depreciation as set forth in the FERC USofA is the loss in service value not restored by current maintenance, incurred in connection with the consumption or prospective retirement of electric plant in the course of service from causes which are known to be in current operation and against which the utility is not protected by insurance. Among the causes to be given consideration are wear and tear, decay, action of the elements, inadequacy, obsolescence, changes in the art, changes in demand, and requirements of public authorities. Q. WHAT CHANGES TO DEPRECIATION IS THE COMPANY PROPOSING IN THIS RATE CASE? A. The Company requests that the Commission, in its order to be issued in this case, approve the specific depreciation rates for the electric and common utility plant accounts as shown on Attachment No. LHP-4. Depreciation rate changes are being proposed for the Company s electric utility plant accounts, 21

1 2 3 4 5 including the Steam Production, Hydraulic Production, Other Production, Transmission, Distribution, and General, and Common utility plant accounts. These depreciation rate changes are supported by the Depreciation Rate Study conducted by Alliance, which incorporates the updated cost of removal estimates reflected in the Decommissioning Cost Study performed by Burns & 6 McDonnell. As mentioned earlier in my testimony, these proposed 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 depreciation rates also incorporate a reserve reallocation to mitigate some of the significant rate impact resulting from the early retirement of the Retiring Generating Units and their associated dismantling costs. I will explain this mitigation proposal in more detail in the next section of my testimony in conjunction with my discussion of the Company s proposal to amortize the regulatory assets for the Retired and Retiring Generating Units. Q. WHEN WERE THE CURRENT DEPRECIATION RATES FOR THE COMPANY S ELECTRIC UTILITY PLANT ACCOUNTS LAST APPROVED BY THE COMMISSION? A. The depreciation rates for most of the Company s electric utility plant accounts were last approved by the Commission in the Company s 2006 rate case in Proceeding No. 06S-234EG. In the Company s following rate case in Proceeding No. 08S-520E, the Company proposed depreciation rates for the new combustion turbines at Fort St. Vrain and for Comanche Unit 3, which were approved by the Commission. In the Company s next two electric rate cases Proceeding Nos. 09AL-299E and 11AL-947E the Company made various depreciation rate proposals, supported by a depreciation study, 22

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 including the incorporation of updated costs of removal for steam production plant supported by a dismantling cost study. Pursuant to the relevant terms of the settlement agreements entered in both of those cases, and approved by the Commission for purposes of resolving the depreciation issues, the Company s depreciation rates were not changed. New depreciation rates were approved by the Commission in Proceeding No. 11AL-947E with respect to two newly acquired generation stations the Blue Spruce Energy Center and the Rocky Mountain Energy Center. Q. PLEASE DESCRIBE THE STUDIES THAT WERE PREPARED IN SUPPORT OF THE DEPRECIATION AND AMORTIZATION EXPENSE CHANGES THAT THE COMPANY IS REQUESTING IN THIS PROCEEDING. A. In 2014, Public Service requested Alliance to perform a depreciation study covering electric and common utility assets. Alliance personnel have over 80 years of combined experience in conducting depreciation studies, as well as many years of utility experience managing and studying utility assets. The discussion of the process and conclusions for the electric and common utility assets is discussed by Mr. Watson of Alliance. The Depreciation Rate Study is provided as Attachment No. DAW-1. Q. IS PUBLIC SERVICE ADOPTING ALL OF THE DEPRECIATION RATES INDICATED BY THE DEPRECIATION RATE STUDY PERFORMED BY ALLIANCE? A. Yes. 23

1 2 3 4 5 6 7 8 9 10 Q. WHAT IS THE CHANGE IN ANNUAL DEPRECIATION EXPENSE THAT RESULTS FROM THE DEPRECIATION RATE STUDY? A. The Depreciation Rate Study uses calendar year 2013 ending plant balances in an effort to show the change in annual depreciation expense attributable solely to the changes in life, net salvage rates, reserve reallocation, and average remaining life incorporated in the Depreciation Rate Study without the influence of changing plant balances. The change in annual depreciation expense using the depreciation rates recommended in the Depreciation Rate Study, calculated by functional plant class using ending plant balances from calendar year 2013, are shown in Table 4 below: 24

Table 4 Change in Annual Depreciation Expense Resulting from Proposed Depreciation Rates 2013 HTY Functional Class 2013 HTY Change in Depreciation Electric Utility Steam Production 37,854,397 Other Production 1,513,251 Hydro Production 2,184,853 Transmission 3,076,832 Distribution (2,232,456) General Plant 201,607 Total Electric Utility 42,598,484 Common Utility General Plant 913,564 Total Common Utility 913,564 Total Electric & Common Utilities 43,512,048 1 2 3 4 The change in annual depreciation expense increases when the depreciation rates from the Depreciation Rate Study are applied to the plant balances in the Test Year. The resulting amount of annual depreciation expense by functional plant class for the Test Year is shown in Table 5 below: 25

Table 5 Change in Annual Depreciation Expense Resulting from Proposed Depreciation Rates 2015 Test Year Functional Class 2015 Change in Depreciation Electric Utility Steam Production 41,075,440 Other Production 1,617,374 Hydro Production 2,195,416 Transmission 3,597,058 Distribution (2,324,040) General Plant 350,371 Total Electric Utility 46,511,619 Common Utility General Plant 2,023,060 Total Common Utility 2,023,060 Total Electric & Common Utilities 48,534,679 1 2 3 4 5 6 7 8 9 10 11 In both Tables 4 and 5 above, the steam production functional class shows only the depreciation for assets that are still in operation and excludes the Retired Generating Units for which the regulatory asset accounts have been established. The Depreciation Rate Study addresses the recovery for the assets still in operation for all functional classes. In order to effectively calculate the depreciation rates, the Depreciation Rate Study performs a reserve reallocation that encompasses all operating production units within a functional class, as well as the Retired Generating Units. Because the Depreciation Rate Study does not develop depreciation rates for the Retired Generating Units, the reserve reallocation is the only part of the Depreciation Rate Study that pertains to these units. Because the Retiring Generating 26

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 Units -- Cherokee Unit 3, Valmont Unit 5 and Zuni Unit 2 -- are still in operation, the Depreciation Rate Study develops depreciation rates for those particular units. Attachment No. LHP-5 shows the comparison of annual depreciation expense between these proposed rates and the rates currently in operation based on average monthly forecasted plant balances for the Test Year. Q. WHAT ARE THE MAJOR DRIVERS OF THE CHANGE IN DEPRECIATION EXPENSE FOR THE TEST YEAR? A. The major drivers of the depreciation expense change are: (1) realigning the terminal retirement dates for the steam production assets; (2) incorporating new decommissioning cost estimates for all generation; (3) increasing the estimates of removal costs for transmission; and (4) lengthening some distribution lives. Mr. Watson discusses the depreciation rate changes in more detail in his Direct Testimony, along with the changes in net salvage for the non-generation assets, and Mr. Kopp discusses the results of the decommissioning cost analysis for the generating assets in his Direct Testimony. Q. WHAT APPROACH DID THE COMPANY TAKE IN PREPARING THE DECOMMISSIONING COST STUDY PERFORMED BY BURNS & MCDONNELL AND SPONSORED BY MR. KOPP? A. As discussed above, there was some controversy among the parties in the Company s past two electric rate cases concerning the Company s proposals to revise its depreciation rates for generating facilities to include updated 27

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 estimates of the costs of removal, and the reasonableness of the results of the dismantling studies submitted by the Company in support of those changes. Section 2.G of the Settlement Agreement approved in the last rate case in Proceeding No. 11AL-947E provides as follows: The Company and the Staff of the Commission agree to work together in good faith between now and May 1, 2014 to arrive at a mutually agreeable methodology for estimating the cost of removal for the Company's electric generating facilities to be included in the Company's cost of service filed in the Company's next Phase 1 rate case. Based on this commitment, I and other Company representatives met with members of the Commission Staff in a series of meetings following the last rate case in an effort to develop a standard process for preparing decommissioning studies for the generation assets. Company and Staff personnel completed this work in the third quarter of 2013. The resulting documentation of this work is a set of principles that have been agreed upon between the Company and the Commission Staff that should be the basis of decommissioning studies for generating assets in future proceedings. A copy of this set of principles is included as Attachment No. LHP-3. Q. HOW WERE ESTIMATES FOR DISMANTLING GENERATING FACILITIES PREPARED? A. The Company retained Burns & McDonnell to prepare a study detailing the costs and factors in dismantling and removing the generating units at the end of their useful lives for all Company-owned generating facilities, including the Retired and Retiring Generating Units (excluding Cameo). This resulted in the Decommissioning Cost Study. In issuing the Request for Proposals to 28

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 potential engineering firms for the work in developing this study, we incorporated the relevant principles and processes that were agreed upon with Staff in the Scope of Work to be followed in performing the decommissioning study. This same Scope of Work was made part of the contract with Burns & McDonnell. The decommissioning cost estimates developed pursuant to the Decommissioning Cost Study were incorporated into the Depreciation Rate Study conducted by Alliance for the determination of the depreciation rates. The Decommissioning Cost Study is discussed by Mr. Kopp of Burns & McDonnell. The Decommissioning Cost Study is provided as Attachment No. JTK-1. Q. PLEASE SUMMARIZE THE CHANGE IN TERMINAL RETIREMENT DATES BEING PROPOSED FOR THE GENERATING UNITS. A. Terminal retirement dates are incorporated into the current and proposed depreciation rates for generating units in this proceeding. These dates are one factor that was used by Alliance to derive the average remaining life depreciation rate for generation in the Depreciation Rate Study and were provided by Public Service to Alliance. The dates are consistent with current operating expectations, environmental legislation, and resource plans. 29