3 of 6 - depreciation and remaining lives - perkett testimony

Before the Minnesota Public Utilities Commission State of Minnesota
In the Matter of the Application of Northern States Power Company for Authority to Increase Rates for Electric Service in Minnesota
Docket No. E002/GR-15-826 Exhibit___(LHP-1)
Depreciation and Remaining Lives
B. Traditional Approach for 2016, 2017, and 2018 ........................................ 17
IV. Passage of Time .................................................................................................. 24
V. Depreciation for Production Assets ................................................................... 27
A. 2015 Remaining Lives Filing (2016 Impact) ............................................... 29
B. 2017 through 2020 Remaining Lives Changes ........................................... 40
VI. Depreciation for TD&G Assets ........................................................................ 41
A. 2017 Five-year Depreciation Study .............................................................. 41
B. Regulatory Asset for TD&G Theoretical Reserve Adjustments ............. 43
VII. Triennial Nuclear Decommissioning Costs .................................................... 47
VIII. Tax and Deferred ............................................................................................. 50
IX. Other Asset Issues ............................................................................................... 57
X. Conclusion ............................................................................................................. 63
Schedules Statement of Qualifications Schedule 1 CWIP, Plant, and Accumulated Depreciation Roll Forwards by
Functional Class Schedule 2
CWIP Roll Forward by Business Area Witness Schedule 3 Expenditures and Additions by Business Area Witness Schedule 4 Roll Forward Link to Heuer and Burdick Revenue Requirement Schedule 5 Passage of Time Exhibit Schedule 6 2016 Depreciation Impact from 2015 Remaining Lives Filing Schedule 7 New or Revised Remaining Life due to Additions Schedule 8 2016 – 2018 Depreciation Impact for Forecasted Additions Schedule 9 Theoretical Reserve Amortization Summary Schedule 10 Accumulated Deferred Taxes Prorate Method Schedule 11 Like-Kind Exchange Accumulated Depreciation Adjustment Schedule 12 Pre-Filed Discovery Appendix A
ii Docket No. E002/GR-15-826 Perkett Direct
I. INTRODUCTION 1
Q. PLEASE STATE YOUR NAME AND OCCUPATION. 3
A. My name is Lisa H. Perkett. I am the Director of Capital Asset Accounting for 4
Xcel Energy Services Inc. (XES), which provides services to Northern States 5
Power Company (NSPM or the Company). 6
7
Q. PLEASE SUMMARIZE YOUR QUALIFICATIONS AND EXPERIENCE. 8
A. I have 35 years of experience in utility accounting. In my current role, I am 9
responsible for managing the Company’s capital asset accounting policies, 10
maintaining accounting and tax records for capital assets, ensuring capital 11
asset-related reporting and regulatory requirements are met, maintaining plant 12
information for ratemaking purposes, and managing the capital investment 13
cost recovery process. My resume is included as Exhibit ___(LHP-1), 14
Schedule 1. 15
16
Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS PROCEEDING? 17
A. I support the level of depreciation expense included in the test year, providing 18
information on remaining lives, net salvage rates, and depreciation expense for 19
all Company assets. My testimony also provides discussion on the overall 20
structure of forecasted capital assets in this case for the test year of 2016 and 21
for the plan years 2017 and 2018. I provide information on various plant and 22
plant related issues that have been included in this case. Unless noted 23
specifically, all numbers presented in my testimony are at Total Company 24
(Minnesota, North Dakota and South Dakota) level. 25
26
1 Docket No. E002/GR-15-826 Perkett Direct
A. I recommend that the Commission adopt the amounts the Company has 1
calculated for the forecast depreciation in this proceeding, based on the 2
recommended changes in useful life and net salvage percentage. 3
4
Q. HOW IS THE REMAINDER OF YOUR TESTIMONY STRUCTURED? 5
A. I have organized the remainder of my testimony in eight parts. First, I 6
provide some general background on the issue of depreciation along with a 7
brief discussion of other dockets that impact the consideration of the 8
depreciation issues in this case. 9
10
Second, I discuss the accounting for the Company’s capital expenditures, or 11
“Capital Additions,” including a discussion of construction work in progress 12
(CWIP), allowance for funds during construction (AFUDC), depreciation 13
expense and accumulated depreciation. In this section of my testimony, I also 14
discuss how the Company’s business areas work within their capital forecasts, 15
yet deal with the business realities they face, including the need to occasionally 16
pursue similar yet different projects than originally anticipated in order to 17
respond to emergent issues and typical yet unanticipated business changes. I 18
also discuss how the Company’s overall capital additions over time align with 19
budgeted capital additions in any given year and how variances in the 20
Company’s capital additions and capital expenditures in any given year tend to 21
balance out with regard to revenue requirements impacts. 22
23
Third, I discuss the concept of “passage of time,” as it relates to depreciation, 24
including an analysis of CWIP, plant balances, book depreciation expense, and 25
depreciation reserve over the term of the Company’s multi-year rate plan. I 26
explain how the Company’s rate request has appropriately incorporated the 1
impact of passage of time. 2
3
Fourth, I discuss depreciation for the Company’s production assets. This 4
section discusses the impact of the Company’s 2015 Remaining Lives filing 5
and the impact of the Commission investigation regarding net salvage 6
percentages. In this section, I also discuss the significant new projects that 7
impact depreciation expense in this case. 8
9
Fifth, I discuss depreciation for the Company’s transmission, distribution and 10
general (TD&G) assets. As I note, the Company will file a new five-year 11
depreciation study for TD&G assets in 2017 and this rate case filing reflects 12
and changes to depreciation that are known at this time for 2017 and beyond. 13
This section of my testimony also discusses the Company’s theoretical 14
depreciation reserve adjustments and the impact of the “unwinding” of the 15
theoretical reserve surplus and the necessary accounting and regulatory 16
responses to this change in the Company’s accumulated depreciation position. 17
18
Sixth, I discuss the impact of the Commission’s decision in the Company’s 19
Triennial Nuclear Decommissioning docket and how this rate case filing 20
reflects that decision. This section also includes discussion of Department of 21
Energy settlement payments and how those payments have been incorporated 22
into the rate request. 23
24
Seventh, I discuss certain other asset issues, including distribution meters and 25
line transformers, a like-kind exchange issue, and the accounting for 26
Monticello extended power uprate (EPU). 27
Finally, I discuss two tax issues that impact tax depreciation in this case, and 1
the potential for additional bonus tax depreciation and the proper calculation 2
of deferred taxes to avoid a normalization violation with the Internal Revenue 3
Service (IRS). As I explain, the resolution of these issues is currently uncertain 4
as Congress has not yet acted on a tax bill. However, resolution of this issue is 5
anticipated before January 1, 2017 and, should that resolution occur, the 6
impacts of any tax law changes should be incorporated into the final decision 7
in this proceeding. Also, the Company presents deferred taxes in this case 8
that are compliant with all IRS regulations including IRS Code section 9
1.167(l)-1(h)(6)(i). Without this compliance, the accelerated tax methods are at 10
risk of being disallowed. 11
12
14
Q. IS THE ISSUE OF DEPRECIATION IMPACTED BY VARIOUS COMMISSION DOCKETS 15
AND DECISIONS? 16
A. Yes. While the Commission can make depreciation decisions in rates cases 17
(which happened in the Company’s 2012 and 2013 rate cases, Docket Nos. 18
E002/GR-12-961 and 13-868), the Commission also investigates and makes 19
depreciation decisions in separate proceedings for: 20
• Production assets, 21
• Nuclear decommissioning costs. 23
24
Q. DID THE COMPANY RECENTLY RECEIVE A FINAL DECISION FROM THE 25
COMMISSION WITH RESPECT TO ANY OF THESE MATTERS? 26
A. Yes. As discussed further in Section VII, below, the Company submitted its 1
Triennial Review of Nuclear Decommissioning on December 1, 2014. In the 2
Triennial Review, the Company requested the approval of the nuclear 3
decommissioning accrual for years 2016 through 2018. The Commission 4
recently approved this Triennial Review of Nuclear Decommissioning and the 5
Commission’s ordered accruals have been incorporated into this rate case. 6
This miscellaneous filing also included a change to the end of life nuclear fuel 7
accrual that the Commission approved on August 27, 2015. The effect of 8
these recently approved changes is a decrease to nuclear decommissioning 9
accrual for the Minnesota jurisdiction of $0.2 million ($0.7 million Total 10
Company) decrease to the end of life nuclear accrual. 11
12
Q. DOES THE COMPANY CURRENTLY HAVE ANY SIGNIFICANT UNDECIDED 13
DOCKETS RELATED TO DEPRECIATION BEFORE THE COMMISSION? 14
A. No. However, while two important dockets have been decided, written orders 15
have not been issued. The Company’s 2015 Annual Remaining Lives petition, 16
Docket No. E,G002/D-15-46 (Docket 15-46) was decided by the 17
Commission on October 22, 2015. In addition, the Commission’s recent 18
decision in its investigation to discontinue the use of probabilities in the 19
calculation of net salvage percentages (Docket No. E,G999/CI-13-626) has a 20
bearing on the Annual Remaining Lives petition. 21
22
Q. WHAT IS THE RELATIONSHIP BETWEEN THE ANNUAL REMAINING LIVES 23
PROCEEDING AND THE CURRENT GENERAL RATE CASE? 24
A. Since Docket 15-46 was undecided until October 22 and no written Order 25
has yet been received, the Company was not able to reflect the Commission’s 26
decision regarding depreciation in this Initial Filing. For purposes of the 27
Initial Filing, the Company incorporated its proposals from Docket 15-46, as 1
well as certain future expected changes in depreciation, to calculate the 2016 2
test-year revenue requirement. However, the Company agrees that the 3
Commission’s final decision should be incorporated into the final calculation 4
of the revenue requirement in this case and will update the case as this 5
proceeding moves forward. In addition, while we did not have the time to 6
revise all of the Schedules and supporting work papers to reflect the 7
Commission’s oral decision, we were able to reflect our understanding of the 8
Commission’s decision in our the interim rate request, as explained by 9
Company witness Ms. Anne E. Heuer. 10
11
Q. PLEASE SUMMARIZE THE ESTIMATED IMPACT OF DOCKET 15-46. 12
A. The Company included its filed position with proposed changes resulting in a 13
$1.4 million (Total Company) increase to electric production depreciation 14
expense for 2016. This amount differs from the 2015 annual remaining lives 15
depreciation filing which reported a $5.1 million increase and was an estimate 16
based on beginning balances for the period. The adjustment shown in this 17
case for the 2016, 2017, and 2018 test years has incorporated the 18
recommended depreciation changes when calculating depreciation in its rate 19
request using forecasted monthly balances. The difference between the 20
remaining life filing and this case for 2016 is explained later in the testimony. 21
In addition, the Commission’s final decision in Docket 15-46 should be 22
incorporated into the calculation of the revenue requirement in this case and 23
the decrease resulting from this decision is estimated to be $11.2 million (Total 24
Company). 25
Q. HAVE YOU REVIEWED OTHER ASPECTS OF DEPRECIATION FOR THIS 1
PROCEEDING? 2
A. Yes. I have reviewed the depreciation lives, net salvage rates and, where 3
applicable, the depreciation rates for the 2016, 2017, and 2018 test years. This 4
review included the following: 5
• Known changes to the remaining lives of the production assets 6
resulting from the forecasted changes to plant balances; 7
• New facilities coming on line for production assets; 8
• Treatment of the theoretical depreciation reserve amount for the 2016, 9
2017, and 2018 test years; and 10
• Amortization of the regulatory asset established for the unwinding of 11
the theoretical depreciation reserve surplus and the request for 12
amortization rates. 13
14
Q. IN THIS CASE, THE COMPANY SEEKS APPROVAL OF A MULTI-YEAR RATE PLAN 15
(MYRP). GIVEN THE MULTI-YEAR NATURE OF THIS FILING, WHAT 16
DEPRECIATION INFORMATION IS REQUIRED? 17
A. The Commission’s June 17, 2013 Order Establishing Conditions, and 18
Procedures for Multiyear Rate Plans, contains the following requirements 19
related to depreciation that apply to our MYRP request:1 20
• Depreciation lives related to capital additions in each year of the plan. 21
This requirement applies to capital additions in 2016, 2017, and 2018 22
and is provided in Schedule 8; and 23
1 Docket No. E,G999/M-12-587, June 17, 2013, Order Point 18.
• Changes expected in the lives of all depreciable assets for two years 1
after the plan. This requirement applies to all depreciable assets during 2
2019 and 2020. 3
In addition, given the multi-year nature of the Company’s request, we explain 4
how the Company adjusts rates in years following the first year for the passage 5
of time, showing all increased and decreased adjustments clearly, and provide 6
support for how the Company’s calculations tie out to the rate case revenue 7
requirement requested by the Company. I discuss the issue of passage of time 8
in Section IV of my testimony, and Exhibit____(LHP-1), Schedule 6 reflects 9
its impact on the case. The impact is also discussed in in the Multi-Year Rate 10
Plan testimony of Company witness Mr. Charles Burdick. 11
12
Q. ARE YOU ANTICIPATING ANY CHANGES IN DEPRECIABLE ASSETS IN 2019 AND 13
2020? 14
A. No, we therefore have not reflected those years in Schedule 8 and 15
Exhibit____(LHP-1), Schedule 9. 16
A. General Structure of Plant Forecast 20
Q. HOW IS THE FORECASTED PLANT INFORMATION PROVIDED IN THIS 21
PROCEEDING? 22
A. The Company’s approach mirrors that taken in the past several rate cases. 23
The Company has laid out the capital forecasted information by utility (electric 24
and common) and by functional class within utility production, transmission, 25
distribution, general, and intangible (where applicable). In this case we have 26
also provided a further breakdown for the CWIP showing capital budget 27
groupings, the categories which the business areas used to identify capital 1
projects and create their overall capital budgets. The forecasted plant 2
process begins with the determination of the necessary capital expenditures 3
for the forecast period. Capital expenditures are the sum of both the 4
construction and removal work, where construction expenditures are part of 5
CWIP and removal expenditures are part of retirement work in progress 6
(RWIP) in the accumulated depreciation account. 7
8
CWIP is built using the forecasted construction expenditures, adding AFUDC 9
while the work is being completed, and closing the construction work to plant 10
in-service on the forecasted in-service date. The plant in-service balance will 11
show the addition of the construction expenditures in the month CWIP closes 12
for that work. AFUDC is stopped when the in-service date is achieved; 13
depreciation begins when the addition is recognized. Depreciation expense is 14
added to accumulated depreciation once the asset is placed in-service. 15
16
The CWIP, plant, and accumulated depreciation information is shown 17
monthly through the entire forecast period, 2016, 2017, and 2018 in Exhibit 18
___(LHP-1), Schedule 2. These reports are referred to as “roll forwards” 19
because the monthly information is rolled forward from the beginning balance 20
in a month by adding the monthly changes to arrive at the ending balance. 21
This ending balance then becomes the beginning balance in the next month. 22
This is similar to rolling forward your checking account by adding deposits 23
and subtracting withdrawals to get to the balance at the end of the month. 24
CWIP balances increase with construction expenditures and AFUDC, and 25
decrease with plant closings. Plant balances increase with additions and 26
decrease with retirements. Accumulated depreciation balances increase with 27
depreciation expense and salvage recognized and decreases with retirements 1
and removal expense spent. 2
3
Q. PLEASE DESCRIBE WHAT YOU MEAN BY THE TERM “CAPITAL BUDGET 4
GROUPINGS” FOR EACH BUSINESS AREA? 5
A. Capital Budget groupings are the major categories of work performed within a 6
particular business area. 7
8
In essence, business areas calculate their budgets based on what work they 9
deem critical to assure continued operation of the system, identifying projects 10
by these capital budget groupings. Therefore, the Company has presented the 11
CWIP information aligned with each business area’s capital budget groupings 12
and the budgeted projects within these groupings are shown in Exhibit 13
___(LHP-1), Schedule 3. The budgeting process is discussed in more detail in 14
the various business unit witnesses’ testimonies and in the Budgeting 15
testimony of Company witness Mr. Greg Robinson. 16
17
Of course, as new facts are discovered, the individual projects performed by a 18
business unit may change to deal with the new situations, but overall the 19
business areas stay within the overall construction and removal expenditure 20
amounts budgeted. As the Commission recognized in the Company’s last rate 21
case, substituting one project for another is a natural part of operating a 22
business. 23
24
Q. DID THIS FLUIDITY IN CONSTRUCTION WORK EXIST IN PRIOR CASES? 25
A. Yes. In the Company’s most recent case, the Company explained that capital 26
expenditures were shifted out of the 2014 test year and were offset by other 27
capital projects that were being shifted into the 2014 test year. The ALJ and 1
Commission agreed that these new projects should be included for rate 2
making purposes. A prudently managed Company simply must respond to 3
changes in the condition of equipment, severe weather events, changes to 4
business or customer priorities, or the emergence of regulatory requirements 5
that were not foreseen at the time its budget was created. Additionally, a 6
change in any one of these factors from what was assumed when calculating 7
the budget can impact the timing of capital project completion (either through 8
delay or acceleration). 9
10
Q. CAN YOU PROVIDE MORE SPECIFIC INFORMATION ABOUT THESE CHANGES? 11
A. Yes. For simplicity I have summarized the changes into three general 12
categories where the Company has experienced necessary replacement 13
projects: (1) like-kind replacements, (2) emergent work, and (3) normal 14
business changes. These three categories are discussed in more detail below. 15
16
Q. WHAT ARE LIKE-KIND REPLACEMENTS? 17
A. Like-kind replacements are new projects with work similar in scope, timing, 18
and cost to the original projects. An example of a like-kind replacement is 19
that of motor replacement/rewind projects. Often these projects are intended 20
to assure safe and reliable operation through the period of plant operations. 21
However, as inspections are conducted throughout the year, the Company 22
determines with more certainty which motors require capital repairs. The 23
motors that require capital repairs may have been forecasted in the first year of 24
the budget or they may have been included in a later year. If motors were 25
originally forecasted to be replaced in the first year, but based on the 26
Company’s business and engineering judgment as the year progresses, the 27
Company determines that replacement is not necessary during the first year; it 1
will postpone the originally forecasted motor projects to a future year of the 2
budget. At the same time, the Company may determine that it needs to bring 3
new motors needing replacement or repair into the current year forecast. This 4
reprioritized motor replacement schedule can be driven by the following 5
factors: plant scheduling, manufacture lead-time and efficiencies, budget 6
constraints due to regulatory project costs, and assuring the availability of the 7
spare motors during the installation of new motors for risk reduction and 8
assurance. Overall plant reliability, and project scope, timing and cost will not 9
be significantly impacted by this exchange of like-kind replacements. In fact, 10
by moving lower priority items out of the forecasted year and bringing higher 11
priority items into the forecasted test year, overall plant reliability is 12
maintained. 13
Q. WHAT IS EMERGENT WORK? 15
A. During the course of a year, the Company’s business areas may encounter 16
work that was not originally planned for during the budgeting process (e.g., 17
major break-fix projects, projects needed to be responsive to new regulatory 18
requirements, etc.). This is known as emergent work. Once emergent work is 19
identified, the business areas determine whether room exists within the 20
current budget to support the additional work or if the emergent work is 21
higher priority than work currently underway or planned for the year. In the 22
latter case, the Company reallocates funds to the emergent work and delays or 23
cancels the initially budgeted capital projects. An example of emergent work 24
from the last case was the bin wall project at the Company’s Monticello 25
nuclear generating facility. During the Fukushima Daiichi flooding reviews 26
initiated by the Nuclear Regulatory Commission (NRC), the NRC determined 27
that Monticello needed to take further action to minimize risks associated with 1
river flooding. This required an emergent capital project to mitigate those 2
risks by constructing additional flood protection structures at the river. After 3
reviewing the capital budget for 2014 and assessing which projects needed to 4
go into service that year as compared to which projects could be delayed, the 5
Company decided to move forward with the bin wall project, while delaying 6
several other capital projects at the plant. 7
8
Q. WHAT ARE NORMAL BUSINESS CHANGES? 9
A. During the course of a year, the Company’s business areas may postpone or 10
cancel a project and replace it with a different, more time-sensitive project that 11
can be completed during the year. Although the cancelled project would no 12
longer be pursued in that year, the capital associated with it will be reallocated 13
to other priorities. These changes can occur due to unpredictable events that 14
require unbudgeted capital expenditures after the budget is finalized. For 15
example, Energy Supply may postpone a new roof or the resurfacing of a 16
parking area in favor of an emergent project needed to maintain or even 17
improve plant reliability. Ultimately, the Company will manage its capital 18
projects to operate within its budget, comply with regulatory requirements, 19
and adapt to changing circumstances. The flexibility to adapt to changing 20
circumstances allows the Company to reprioritize capital projects, which 21
ultimately benefits its customers. 22
23
Q. WERE ANY PROJECTS CANCELLED OR ABANDONED? 24
A. Based on the premise that there is fluidity in the capital projects as 25
circumstances change, there are projects that are not done to allow others to 26
take their place. This is a normal occurrence. Thus, truly cancelled or 27
abandoned projects in the normal context of construction means that the 1
forecasted dollars do not get used elsewhere as the business works within its 2
capital budgeting expectations. With that definition in mind, there is one 3
project that we determined we would not complete and that has not been 4
replaced by other projects. This is highly unusual as generally other needed 5
projects will simply replace any cancelled projects. The St. Cloud Loop 6
project was cancelled after a fire at the Verso Paper Mill on May 29, 2012 that 7
eventually resulted in permanent closure of the plant. This project was 8
originally proposed in a prior budget and there were no substitutions made for 9
it. 10
11
Q. YOU HAVE EXPLAINED HOW BUDGETS NEED TO BE FLEXIBLE BECAUSE 12
CIRCUMSTANCES CHANGE, BUT HOW DOES THE ESTIMATED IN SERVICE DATE 13
IMPACT THE CAPITAL ADDITION? 14
A. Think of the estimated in-service date as the asset’s birth date. At the 15
beginning of the planning cycle, the business areas estimate the time it will 16
take to get ready for construction (obtain permits or certificate of needs, order 17
material, perform required studies, and complete the required engineering or 18
project planning), the time it will take to actually build or create the asset, and 19
then to complete construction (testing the asset, connecting it to the grid, 20
satisfying permit requirements, and gaining the necessary agency approvals). 21
After they lay out this process, then the business area can estimate the 22
estimated in service date. Only when all the actual work is complete will the 23
business area know whether their estimated in service date was precise. 24
However, the business areas understand the necessary steps to get a project to 25
its in service date and have significant experience moving them through this 26
process, so we can reasonably anticipate that the estimated in service date will 27
be in line with expectations, absent some changed circumstance that 1
significantly alters the expected timeline. 2
3
Q. WITH ALL OF THESE CHANGES HAPPENING IN ANY GIVEN YEAR, HOW CAN THE 4
COMMISSION HAVE CONFIDENCE THAT THE COMPANY’S CAPITAL BUDGETS 5
PROVIDE A REASONABLE BASIS FOR SETTING RATES? 6
A. Mr. Robinson discuss this in greater detail, but from a capital asset accounting 7
perspective, it is important to recognize that overall actual capital additions 8
have closely aligned with budgeted additions. There are slight variations in 9
any given year; however, the overall impact to the revenue requirement is 10
small. For example, if a project is forecasted to be in service in July and it 11
actually goes into service one month earlier or later, the impact for a $1 12
million project assuming a 40 year useful life is approximately $2,000 in 13
change in revenue requirement. Even if the addition was forecast to be a 14
December occurrence and ending up occurring January of the next year, the 15
impact to revenue requirements is not dramatic, since the inclusion of CWIP 16
in rate base leaves the revenue requirement difference to be basically one 17
month’s depreciation. 18
19
Variations in capital expenditures may have an even more indirect impact on 20
the revenue requirements, especially when the total spend to the project is met 21
and the in service date does not change. The variation of capital expenditures 22
may not change the overall level of additions in a given year. Thus, capital 23
expenditures need to affect the level of additions in order to cause an impact 24
to the revenue requirement. Lastly, capital expenditures in one project work 25
order may vary in one direction with another varying in the opposite direction. 26
This may also occur with capital additions. For all of these reasons, the total 27
capital expenditure and addition picture must be considered when evaluating 1
the impact to the revenue requirement and considering whether the 2
Company’s capital budgets provide a reasonable basis for setting rates. 3
4
Q. DO YOU PROVIDE AN ANALYSIS ON ACTUAL CAPITAL EXPENDITURES AND 5
ADDITIONS COMPARED TO BUDGET? 6
A. Yes. We compared 2010 through 2014, the last five full actual years, for both 7
capital expenditures and additions. The following table shows the comparison 8
for capital expenditures: 9 Table 1 10
Capital Expenditures for 2010 through 2014 11 12 13 14 15 16 17
This shows that the Company on average spent 103.8 percent of what it 18
forecast. This represents the overall construction spend, excluding projects 19
that were unusual and are not representative of base construction for our 20
routine course of business, such as replacing assets at the end of their life, 21
solving capacity constraints, meeting environment criteria, and new customer 22
business requirements. The excluded projects were Merricourt, Monticello 23
EPU, Prairie Island EPU, and the earlier version of Black Dog Unit 6. 24
However, this is just the beginning of the necessary analysis, because how 25
these capital expenditures resulted in capital additions influences the overall 26
impact on revenue requirements. After removing the same projects 27
mentioned above, the following table shows the comparison for capital 1
additions for the past five years: 2 Table 2 3
Plant Additions for 2010 through 2014 4 5 6 7 8 9 10
11
Thus, the actual capital additions over this five-year period were within one 12
percent of budgeted additions, for those additions representative of routine 13
course of business. This, combined with the capital expenditures analysis, 14
demonstrates the reliability of the Company’s budgeting process and the 15
reasonableness of using the Company’s capital budgets as the basis for setting 16
rates. 17
Q. WHAT IS THE TRADITIONAL APPROACH? 20
A. The traditional approach means that the expenditures are forecasted at project 21
level in order to provide the appropriate spend within the various business 22
areas. The projects have been summarized by the capital budget groupings for 23
each business area in Exhibit___(LHP-1), Schedule 3, and the annual effect of 24
these additions is included in the calculation of revenue requirements for the 25
years 2016, 2017, and 2018. In addition, Exhibit___(LHP-1), Schedule 4 26
provides detail on the expenditures and additions by each Business Area 27
witness. 28
Q. WHAT IS THE INTENT OF THESE CAPITAL BUDGET GROUPINGS? 1
A. The capital budget groupings by business area were created to help identify and 2
categorize the critical work needed to be done by each business unit. 3
4
Q. CAN YOU PROVIDE THE CAPITAL BUDGET GROUPINGS THAT ARE USED FOR 5
CAPITAL IN 2016, 2017, AND 2018? 6
A. Yes. The following table summarizes the capital budget groupings by business 7
area for the capital work in 2016, 2017, and 2018, including the witness 8
supporting the business area. These same groupings are used for the entire 9
forecast as well, continuing for 2019 and 2020. 10
Table 3 11 Capital Budget Groupings by Business Area 12
13
Nuclear – Timothy O’Connor
Transmission – Ian Benson
Distribution – Kelly Bloch
• Asset Health & Reliability • New Business • Capacity • Fleet, Tools, and Equipment
Business Systems – David Harkness
Facilities – Lisa Perkett
• Buildings and General 1
Q. ARE YOU SUPPORTING PART OF THE CAPITAL EXPENDITURES IN THIS CASE? 2
A. Yes. I am presenting a small part of the capital expenditure forecast. No 3
business area witness has been provided for some miscellaneous capital for the 4
general facilities used by the Company. While I do not directly oversee the 5
construction or purchase of these assets, I can speak to the capital budget 6
groupings. The facilities capital expenditures are shown under the capital 7
budgeting group Buildings and General. This grouping includes work on the 8
building systems, furniture, leasehold improvements, structural components, 9
tools, and other equipment necessary to support the operations of the office 10
buildings and service centers. 11
12
Q. CAN YOU DESCRIBE THE CAPITAL WORK BEING DONE IN THE BUILDINGS AND 13
GENERAL? 14
A. The work in this grouping can be subdivided into three categories as follows: 15
• New construction at 401 Nicollet Mall, 16
• Renovations at 414 Nicollet Mall, and 17
• Renovations at various other facilities. 1
2
The capital expenditures and additions that are included in this case for 2016 – 3
2018 for this grouping are as follows: 4
5
6
7
8
Q. CAN YOU DESCRIBE THE CAPITAL WORK BEING DONE AT 401 NICOLLET MALL? 9
A. Xcel Energy’s 10-year lease for office space at 250 Marquette Plaza will be 10
terminating at the end of June 2016. We evaluated various scenarios for 11
housing half our general office staff in Minneapolis. In this process, we 12
considered rental rates, proximity to the owned headquarter facility, improving 13
adjacencies, and finding ways to increase collaborative work and productivity. 14
Ultimately, we determined to move forward with OPUS (both builder and 15
landlord) to build a new facility, as the cost effective solution to meet our 16
needs and specifications. As with moving from one leased building to 17
another, leasehold improvements are needed to complete the build-out of the 18
new leased space for items that are not included within the tenant 19
improvement funds provided by the landlord. This includes interior offices, 20
phone and data equipment, furniture, and other equipment that is necessary 21
for the Company to operate the facility. The new location will be at 401 22
Nicollet Mall and be leased for 15 years. The addition associated with this 23
new location is approximately $16.7 million. 24
25
Capital expenditures will include new interior construction of the corporate 26
headquarters campus and includes the design and engineering for all 27
architectural, mechanical, electrical, and special systems to be incorporated in 1
the new facility. It also includes the labor and material to build out the space 2
per design, including all furniture, fixtures, and equipment (inclusive of 3
business systems, security, and property) to make the new building functional 4
for assigned work groups. 5
6 Q. CAN YOU DESCRIBE THE CAPITAL WORK BEING DONE AT 414 NICOLLET MALL? 7 8 A. The move to the new leased facility at 401 Nicollet Mall allows the Company 9
to align office space functionality with changing business unit needs. Thus, 10
the Company evaluated how to most effectively use the space at 401 and 414 11
Nicollet Mall and allow us to better utilize the old space as well as the new. In 12
order to fully utilize the old space, it will be renovated to meet current and 13
future office needs. These changes will improve operations by co-locating 14
like-groups together (groups or departments that benefit by being next to 15
another department), improve adjacencies of groups to better productivity. 16
For example, the Business Systems staff would be located in the same building 17
and adjacent to their computer and server rooms, the Transmission group 18
could be located next to its control room, and the Nuclear group would be 19
adjacent to their disaster recovery center. These changes, along with 20
providing space for more collaborative work will help with recruiting and 21
retaining a talented workforce. Capital projects have been forecast for new 22
windows, plumbing, realigning heating, ventilating and air conditioning 23
(HVAC) and building control systems, and overall renovations. 24
25
Additional expenditures will include design, and engineering to re-purpose the 26
floors as well as labor and material to build out the space per design to 27
accommodate the operations groups that will be relocated to the facility. The 28
entire plumbing system will be replaced due to aging and to address continued 1
leaks, bursts, floods, sewer gas odors, and air quality complaints. Windows 2
also will be replaced across the entire facility, as the existing windows are 3
original from 1965 and cause increasing energy loss with age. The existing 4
roof will be replaced with a new energy efficient roofing system. Aging and 5
multiple roof penetrations from mechanical projects have caused deterioration 6
over the years. Capital additions for 414 Nicollet Mall are estimated at $3.2 7
million for 2016, $9.8 million for 2017, and $1.3 million for 2018. 8
9
Q. CAN YOU DESCRIBE THE RENOVATION AND REPLACEMENT CAPITAL WORK 10
BEING DONE ACROSS THE REMAINING PROPERTY SERVICES PORTFOLIO? 11
A. Property Services is responsible for operating and maintaining Company 12
owned and leased sites for regional and headquarters offices, service centers, 13
and call centers. They are not responsible for facilities at power plants, 14
substations, gas regulator sites, or transmission sites. Capital projects are 15
required to bring sites up to code and keep the asset in operations. 16
17
Building capital projects typically include replacing the electrical, mechanical 18
and plumbing systems, as well as replacing structural components such as 19
windows and roofs, and replacing carpet. Pavement replacements address 20
deteriorating surfaces which hinder vehicle traffic and parking. Mechanical 21
projects typically include replacing HVAC equipment for control of offices, 22
and exhausting and heating vehicle and warehouse areas. Roof replacements 23
are completed based on age and condition, and expanded upon when 24
necessary to include any repairs caused by leaks or other issues (mold 25
remediation, condensation, etc.). Dollars are also budgeted for emergencies 26
that may arise such as storm damage or flooding causing interior and exterior 27
damage. The capital additions for this section are expected to be $6.3 million 1
in 2016, $7.2 million in 2017, and $25.6 million in 2018. 2
Major projects include the following: 3
• Rice Street Service Center – Complete renovations to the 1st and 2nd 4
floors and the locker rooms, roof replacement, construction of a new 5
meter warehouse, and replacement of outdoor lighting. Substantial 6
aging and deterioration at this facility have necessitated substantial 7
capital investment. 8
• Chestnut Service Center – Renovations to the fleet garage office and 9
locker rooms, chiller and cooling tower replacements, pavement 10
replacement, HVAC replacement at the meter building, and Siemens 11
panel upgrades. Substantial aging and deterioration at this facility have 12
necessitated substantial capital investment. 13
• Other major projects include renovations to the Edina, Winona, and 14
Grand Forks Service Centers, replacement of the HVAC system at 15
White Bear Lake, and roof replacement at Fargo. 16
17 Q. MUCH OF THIS CONSTRUCTION WORK IS TO COMMON FACILITIES. ARE THE 18
COSTS OF THESE ASSETS SHARED WITH OTHER OPERATING COMPANIES WITHIN 19
XCEL ENERGY? 20
A. To the extent that the NSPM common facility is used by employees that 21
perform functions for more than one operating company, the costs of the 22
facility are shared among all operating companies. This sharing of the asset 23
costs has been used since the merger that created Xcel Energy. The asset is 24
fully on NSPM asset records along with its depreciation and deferred taxes. 25
To compensate Minnesota customers for the portion used by the other 26
operating companies, a revenue (or expense credit) is issued to NSPM for the 27
use of its common assets shared within Xcel Energy. Basically, a revenue 1
requirement is calculated for the NSPM shared assets and this amount is 2
charged to Xcel Energy Services which in turn bills the various operating 3
companies. 4
7
Q. PLEASE EXPLAIN WHY THE CONCEPT OF PASSAGE OF TIME IS RELEVANT TO 8
THIS CASE. 9
A. The concept of passage of time pertains to how the Company’s rate base and 10
revenue requirements change from one year to each subsequent year. This 11
includes an analysis of CWIP, plant balances, book depreciation expense, and 12
accumulated depreciation reserve over the course of a multi-year plan. 13
14
Q. HOW DOES THE RATE BASE CHANGE FOR A SINGLE ASSET AS IT PASSES 15
THROUGH TIME? 16
A. The first year an asset is in use, the beginning and ending average is based on 17
the beginning CWIP balance (if there is one) and the ending plant balance. 18
This asset is only partially included in rate base, assuming that the CWIP 19
balance at the beginning of the year was less than the total asset value when it 20
moved to plant in service. The second year and beyond, the asset’s original 21
cost remains constant until the year it is retired, which is a partial year. The 22
accumulated depreciation grows each year with the depreciation expense 23
recognized, with the first and last years of the asset’s life being a partial 24
expense. Combining the plant and accumulated depreciation each year for 25
this single asset, one would see a decreasing rate base until the asset is fully 26
depreciated. 27
Q. HOW DOES A PLANT RETIREMENT IMPACT RATE BASE OVER THE PASSAGE OF 1
TIME? 2
A. A retirement transaction results in the plant and reserve balances being 3
decreased by the same amount. The act of “retirement” has no direct effect 4
on rate base, but it does have an indirect impact as discussed below. 5
6
Q. CAN RETIREMENTS IMPACT DEPRECIATION AND THUS INDIRECTLY IMPACT 7
RATE BASE OVER THE PASSAGE OF TIME? 8
A. Yes, but it depends on the type of asset and depreciation method used for that 9
asset as to whether there is a depreciation impact resulting from the 10
retirement. A retirement reduces the plant balance and the accumulated 11
depreciation by the same amount when the transaction is recognized , 12
resulting in no impact to rate base from the transaction. However, there are 13
assets where the depreciation is calculated from the original cost of the plant 14
and not the net plant value. For those assets (depreciation on original cost), 15
the retirement does change the calculation of the depreciation going forward 16
and this change impacts the accumulated depreciation and, hence, rate base. 17
For all transmission and distribution assets and general plant buildings, there is 18
an impact on the depreciation expense going forward from the point a 19
retirement is made because the retirement decreases the original cost of plant 20
and these assets use a depreciation rate applied to the original cost of plant. 21
Thus, indirectly these retirements impact the overall rate base because of the 22
change to depreciation expense in the year the asset retires and its change to 23
accumulated depreciation. 24
25
For electric production assets, the remaining life method of depreciation is 26
used, which depreciates the net plant over the remaining life. For these assets 27
a retirement does not change the net plant, thus there is no change to 1
depreciation expense going forward from the retirement of the asset. Thus 2
there is no impact to rate base for the electric production retirements. For 3
plant assets using the vintage group method as described in Federal Energy 4
Regulatory Commission (FERC) Accounting Release No. 15 (AR-15), 5
distribution meters, line transformers, and general plant assets (excluding 6
general plant buildings), a retirement is not recognized until the assets for a 7
particular vintage are fully depreciated. There is no impact to rate base for the 8
vintage group retirements. 9
10
Q. HAS THE COMPANY INCORPORATED THE FULL PASSAGE OF TIME CHANGES 11
INTO THE 2017 AND 2018 PLAN YEAR? 12
A. Yes. All assets in plant at the end of 2016 were advanced forward into the 13
2017 plan year, and 2017 balances were advanced forward into the 2018 plan 14
year. The Company has included all changes in plant balances, depreciation 15
expense, and accumulated depreciation during 2017 and 2018 in its request for 16
both plan years, using a full cost of service approach, which is addressed in 17
Mr. Burdick’s testimony. The roll forward of CWIP, plant, and accumulated 18
depreciation are included in Exhibit___(LHP-1), Schedule 2. We also 19
provided a summary for 2016, 2017, and 2018 in Exhibit___(LHP-1), 20
Schedule 5. This schedule provides a link from the information in my 21
Exhibit___(LHP-1), Schedule 2 to Ms. Heuer’s Schedule 9 for the 2016 test 22
year and provides the unadjusted information for the 2017 and 2018 test years. 23
24
Q. HOW IS THIS DIFFERENT FROM THE LAST RATE CASE THE COMPANY FILED? 25
A. In the Company’s previous rate case (Docket No. E002/GR-13-868), it did 26
not use a full cost of service model for the second year of the multi-year plan. 27
In the current case, the Company is using a full cost of service model for 1
2016, 2017, and 2018, which captures both additions and retirements for 2
complete rate base and revenue requirement recognition. Mr. Burdick 3
discusses this approach in more detail in his Direct Testimony. 4
5
7
Q. WHAT PROCESS DOES THE COMMISSION USE TO REVIEW DEPRECIATION FOR 8
PRODUCTION ASSETS? 9
A. In general, each year in February, the Company files an annual review of 10
remaining lives for production assets, proposing changes to depreciation 11
expense based on any changes to remaining lives or net salvage rates identified 12
in its annual review. This year, however, the Company requested and received 13
Commission approval for an extension to submit its 2015 Review of 14
Remaining Lives petition. 15
16
Q. PLEASE DESCRIBE THE PROCESS USED TO IDENTIFY CHANGES THAT THE 17
COMPANY INCLUDED IN A REVIEW OF REMAINING LIVES FILING. 18
A. The Company follows the same process used to complete each remaining life 19
filing. Annually, the Company’s depreciation analysts meet with the 20
employees who are knowledgeable about the planning, construction, and 21
operations at each facility. During these meetings, the Company reviews each 22
facility to: 23
projects performed in the past few years; 25
• Consider the scope of current and upcoming projects; and 26
• Forecast the likelihood of the facility achieving the currently-approved 1
remaining life in light of the past, current, and near future projects. 2
If the Company determines that the current remaining life is no longer 3
appropriate, the Company proposes a modification to the remaining life for 4
that facility. 5
6
The Company also considers the likelihood that a planned major overhaul, 7
rebuild, or routine construction project will occur in the next 10 to 12 months, 8
and its probable effect on each facility. If there is uncertainty whether the 9
work will occur, the Company reduces the weight given to this factor in its 10
remaining life analysis. Each year, the Company reviews the projects 11
scheduled for each plant to gauge if there is more or less certainty of 12
completion, and it adjusts its analysis accordingly. 13
14
Occasionally, there is a significant individual event that influences a change to 15
remaining life – for example, the operating license renewal at Monticello. 16
More often, however, it is a culmination of several smaller factors that, when 17
considered together, support a change in the remaining life. If just one or two 18
of these small changes are present, the factors may not be strong enough to 19
influence a life change. As time passes each year, more of these smaller 20
factors may be realized such that a change would become appropriate. 21
22
Q. WHY DOES THE COMPANY PRESENT A REVIEW OF REMAINING LIVES IN THIS 23
RATE CASE? 24
A. The Commission’s June 16, 2010 Order in the Company’s 2010 Remaining 25
Lives proceeding (Docket No. E,G002/D-10-173) requires that rate case 26
filings provide information on significant changes to depreciation that the 27
Company requests in its annual remaining lives filing. Specifically, the 1
Commission required Xcel Energy “in its pre-filed direct testimony in its next 2
rate case, to identify significant additions to plant investment proposed to be 3
included in rates, and discuss how a life extension for each such plant has 4
been reflected in the depreciation rates used in the rate case, or why a life 5
extension has not been proposed.” The Company has provided such 6
information since it was so ordered. 7
8
A. 2015 Remaining Lives Filing (2016 Impact) 9
Q. PLEASE SUMMARIZE THE STATUS OF THE COMPANY’S 2015 REVIEW OF 10
REMAINING LIVES. 11
A. The Company submitted its 2015 Annual Remaining Lives petition i on May 12
18, 2015. The Commission made its oral decision on October 22, 2015 in this 13
docket, however no final Order has been issued and there was not enough 14
time between the decision and the filing of this case to incorporate the 15
Commission’s decision to change the remaining lives for Sherco Unit 1, Angus 16
Anson Units 2 and 3, and Granite City Units 1 through 4. Thus, the 17
Company used its proposed position from our supplemental reply comments 18
as the initial position in this case. We will incorporate the remainder of the 19
Commission’s decision into this case as it progresses. 20
21
Q. WHY DOES THE COMPANY PRESENT INFORMATION ON ITS 2015 REVIEW OF 22
REMAINING LIVES IN THIS RATE CASE? 23
A. Typically, the changes requested in the annual filing are incorporated into the 24
rate case data. This year, the Company requested the changes to expense be 25
effective for 2016 instead of 2015. While the 2015 Review of Remaining Lives 26
is not technically a future docket, it is anticipated that this filing will replace a 27
2016 filing. As a result this docket is assumed to provide both the estimation 1
of current effective depreciation lives and net salvage rates for 2016. 2
3
Q. WHAT DID THE COMPANY INCLUDE FROM 2015 REMAINING LIVES FILING IN 4
THE INITIAL CASE? 5
A. The remaining lives and net salvage rates currently in use were approved in the 6
Company’s 2014 Annual Remaining Lives filing (Docket No. E,G002/D-14-7
181). In the Company’s 2015 filing, it requested approval of changes to both 8
electric and gas production facilities. The Company included its supplemental 9
reply position which included the following: 10
• Reduction of one year to move forward the remaining lives for all 11
electric facilities from the life previously approved that were not 12
recommended for a further change; 13
• Modification to the remaining life extensions for Blue Lake Units 1 14
through 4, Red Wing, and Wilmarth; 15
• Initial remaining lives and net salvage rates for Pleasant Valley Wind 16
and Borders Wind Projects; 17
• Modifications to net salvage rates for all electric production facilities 18
based on an updated Dismantling Cost study without the use of 19
probabilities; 20
• Reallocation of depreciation reserve between electric production 21
facilities to fully depreciate Minnesota Valley, Key City and Black Dog 22
Units 3 and 4 electric production facilities based on updated 23
dismantling cost estimates; and 24
• Transfer of Wind to Battery assets to the new FERC Account 348.1. 25
• Effective date for the changes to be January 1, 2016 26
27
The Company’s supplemental reply comments reflected an increase in Total 1
Company depreciation for 2016 of $5.1 million based on beginning year 2
balances for electric production assets not presently included in rate riders. 3
4
On October 1, 2015, in Docket No. E,G999/CI-13-626, In the Matter of a 5
Commission Inquiry into Decommissioning Policies Related to Depreciation, the 6
Commission decided to discontinue the use of decommissioning probabilities, 7
and the Company’s supplemental reply comments to its 2015 Annual 8
Remaining Lives filing removed the probabilities from the calculation of the 9
net salvage rates to align with the Commission’s decision. We have included 10
the depreciation expense in this case based on our proposed lives and net 11
salvage rates as presented in our supplemental reply comments. 12
13
Q. DOES THE CHANGE TO DEPRECIATION EXPENSE IN 2016 IN THIS PROCEEDING 14
ALIGN WITH THE AMOUNT PROPOSED IN THE SUPPLEMENTAL REPLY 15
COMMENTS? 16
A. The depreciation lives and net salvage rates do align with what was provided 17
in the reply comments. However the amount of change to depreciation 18
expense in this case is a factor of the life and rate changes applied to the 19
forecasted changing plant balances. Thus, the change in 2016 between the 20
2015 Annual Remaining Lives filing and this rate proceeding can be seen in 21
Table 4. 22
Table 4 1 Comparison of Remaining Life Filing To Rate Case for 2016 2
3 4 5 6 7 8 9 10 11 12
13
The calculation of the rate case impact of these changes can be seen in 14
Exhibit___(LHP-1), Schedule 7. Ms. Heuer presents the revenue requirement 15
impact of these adjustments in her testimony. 16
17
Q. CAN YOU EXPLAIN WHY THE STEAM PRODUCTION IMPACT FOR 2016 IS A 18
DECREASE FOR THIS CASE WHEN THE IMPACT WAS SHOWN AS AN INCREASE IN 19
THE 2015 ANNUAL REMAINING LIVES FILING? 20
A. This difference is being driven primarily by the Red Wing and Wilmarth 21
facilities. In the Annual Remaining Lives filing, depreciation is estimated 22
based on beginning of period balances. In that filing, additions during the 23
year are ignored in order to better present the impact driven only by changes 24
in the remaining life or net salvage rate. In this proceeding, all additions 25
during the period are taken into account when calculating the depreciation. 26
In the cases of Red Wing and Wilmarth, they have additions of over $5 million 27
and $3.5 million respectively that were not accounted for in the Remaining 28
Life filing that are reflected in this case. This higher amount of plant leads to 29
a significantly higher recommended change, especially when you take into 1
account that the currently approved remaining life for each plant is only two 2
years as of the beginning of 2016. 3
4
The larger recommended decreases for Red Wing and Wilmarth outweigh any 5
changes in the rest of the steam production facilities, which are mostly 6
increases. A summary by plant of the differences between our Remaining Life 7
filing recommended changes versus the changes recommended in this case are 8
shown in Table 5 below. 9 Table 5 10
2016 Steam Production Depreciation Change Comparison 11 12 13 14 15 16 17 18 19 20 21
Q. CAN YOU DISCUSS THE OTHER CHANGES THAT HAVE NOW BEEN APPROVED BY 22
THE COMMISSION BUT HAVE NOT YET BEEN INCLUDED IN THIS CASE? 23
A. Yes. On October 22, 2015, the Commission orally approved changes to 24
Sherco Unit 1, Angus Anson Units 2 and 3, and Granite City Units 1 through 25
4. The remaining life for Sherco Unit 1 and Angus Anson Units 2 and 3 were 26
lengthened to 10 years beginning January 1, 2016. This is results in an 27
estimated decrease of depreciation of $8.6 million for Sherco Unit 1 and a 28
decrease of $2.4 million for the two Angus Anson units. The remaining lives 29
for the Granite City units were extended to 8 years resulting in an estimated 1
decrease of $0.2 million. The total estimated impact is $11.2 million that will 2
be included in this case as it proceeds. While we were not able to incorporate 3
the impact of the Commission’s decision into our Initial Filing, we will do so 4
as this case moves forward. In order to inform the record at this time, I show 5
the calculation of the impact of the Commission’s decision in my Appendix A. 6
Ms. Heuer discusses the revenue requirement impact of this change as well as 7
its inclusion in interim rates. 8
9
Q. CAN YOU BRIEFLY DISCUSS THE REASONS FOR THE INCREASE IN THE 10
MINNESOTA VALLEY REMOVAL COST ESTIMATE? 11
A. The cost estimate for the Minnesota Valley facility increased due to an 12
increase in the amount of estimated asbestos and lead contaminants that need 13
to be removed. Estimating the volume of these two contaminants is very 14
difficult as the amounts are not readily visible thus lending it to easy 15
measurement. The estimate also increased due to the change in Minnesota 16
rules that requires the Company to excavate down below the foundation and 17
remove all this structure, whereas the previous requirements only required 18
removal of three feet below grade. Lastly, there were increased labor costs 19
due to increases in craft labor rates and additional dismantling planning and 20
additional costs to remove the coal pile on the site. 21
22
Q. THE REMAINING LIFE FILING EMPLOYED A RESERVE REALLOCATION. CAN 23
YOU DISCUSS WHY THIS IS A PRUDENT WAY TO HANDLE THE IMBALANCE IN 24
COSTS AT THE END OF FACILITIES LIFE? 25
A. Yes. The Company proposed a reserve reallocation in order to balance the 26
impact of the change in cost estimate for several facilities that were beyond 27
their end of life and had changes in their removal cost estimates. In the steam 1
production functional class, this reserve reallocation encompassed the 2
Minnesota Valley plant where the estimate showed not enough was recovered 3
for removal costs and Black Dog Units 3 and 4, where it was estimated that 4
too much would be recovered for removal costs. The reserve reallocation in 5
this case had the benefit of balancing out plants that had variations in cost 6
estimates after the end of their useful life. 7
8
Reserve reallocations have been used by the Company in similar situations in 9
the past. This includes a previous reallocation of reserve for Minnesota Valley 10
in 2012, when the cost of removal estimate increased to account for the 11
increased cost to remove the dam. The Company also used a reserve 12
reallocation in 2010 when the West Faribault plant was dismantled and had 13
approximately $3 million in excess reserve collected for removal costs. In this 14
case, the reserve reallocation benefited customers by decreasing the amount of 15
depreciation that needed to be collected from other facilities to which it was 16
spread. 17
18
While the Company has used the reserve reallocation method in the past, it 19
recognizes that this technique should not be used as a substitute for providing 20
the best estimate of the needed recovery for dismantling costs. The Company 21
will continue to complete estimates every five years to account for changes in 22
removal costs and when changes occur within this five year span, we will bring 23
those changes forward in the interim in the annual depreciation filing. 24
Spreading these costs over the useful life of the asset is the goal of estimating 25
net salvage and coming as close as possible with estimates is key to this goal. 26
27
However, as long as the reserve reallocation is used sparingly, and is used both 1
when a plant estimate is too low and too high, the method can provide a 2
benefit to customers by allowing the Company to be conservative with its net 3
salvage estimates and not over estimate the costs to assure full recovery. If 4
the Company believed there was no recourse to account for small shortfalls 5
that may occur when estimating removal costs well before dismantlement, 6
then the natural inclination would be to provide overly pessimistic removal 7
costs estimates. While doing so would ensure that the Company collects 8
enough to complete dismantling, it would correspondingly increase the risk 9
that customers overpay for removal during the life of the plant. Having 10
reserve reallocation as an option, allows the Company to provide realistic 11
removal cost estimates. 12
13
Q. HAS THE COMPANY PERFORMED ANY ADDITIONAL ANALYSIS TO COMPLY WITH 14
THE 2010 ANNUAL REMAINING LIVES ORDER? 15
A. As required by that Order, the Company included an evaluation of the 16
“significant” additions to plant investment expected in the next several years. 17
As the Company does for each remaining life filing, it reviewed the 18
appropriateness of the currently approved end-of-life dates for production 19
facilities. The Company also reviewed any significant changes to operating 20
plans or other regulatory changes that could provide an impetus to change the 21
remaining life in this proceeding. 22
23
Q. HOW DID THE COMPANY DEFINE THE TERM “SIGNIFICANT” AS SET FORTH IN 24
THE 2010 ANNUAL REMAINING LIVES ORDER? 25
A. For purposes of my testimony, “significant” additions refer to any 26
construction activities that either singly or in combination with another 27
project lead to a probable extension of the current remaining life of a 1
particular facility or unit. I believe this definition is consistent with the 2010 2
Remaining Lives Order as it addresses the Commission’s concerns related to 3
changes in remaining lives and the impacts of the changes on rates for 4
customers. 5
6
Q. ARE THERE SIGNIFICANT PROJECTS THAT WOULD FURTHER IMPACT THE 7
DEPRECIATION EXPENSE IN 2016 AND ARE THESE IMPACTS INCLUDED IN THIS 8
CASE? 9
A. Yes, there are two significant production projects that would impact 10
depreciation expense in 2016, however only one is included in this rate case. 11
There is a new capital project at the fully depreciated St. Croix Falls hydro 12
production facility that will be completed in July 2016. The Company is 13
requesting a new remaining life for the facility in order to depreciate this asset 14
over its useful life. The impact for this hydro addition has been included in 15
this case. 16
17
In addition, the Courtenay Wind Project will go into service in 2016. Due to 18
the production assets, the Courtenay Wind Project is considered a significant 19
addition for 2016. The Courtenay Wind Project is a 200 MW wind farm to be 20
located near Courtenay, North Dakota. However, the Company expects this 21
project will be included as a part of the Renewable Energy Standard rate rider. 22
As such, Ms. Heuer explains in her testimony that the asset costs of the 23
Courtenay Wind Project and their related depreciation are removed from 24
general rates. Company witness Mr. Steven Mills also provides further 25
discussion of the Courtenay Wind project. 26
27
Q. PLEASE EXPLAIN THE NEW SIGNIFICANT PROJECT AT THE ST. CROIX HYDRO 1
PRODUCTION FACILITY 2
A. The St. Croix Falls Hydro facility is a 23.2 MW hydro production plant located 3
on the St. Croix River on the border between Minnesota and Wisconsin. The 4
production facility is owned by Northern States Power Company-Wisconsin. 5
NSPM owns the west end portion of the dam for the hydro plant that is 6
located on the Minnesota side of the river. This portion of the facility consists 7
of one small control house and one spillway gate. The facility is still being 8
used to produce electricity for Northern States Power Company-Wisconsin, 9
which may provide service to NSPM customers through the interchange 10
agreement. 11
12
On the Minnesota side, the remaining life for depreciation purposes was 13
allowed to expire on December 31, 1996. Since that time, there have not been 14
any major capital additions to the Minnesota portion of the facility, so annual 15
depreciation has remained at zero dollars. In July 2016, the Company is 16
expecting a project to replace the overlay wall on the Minnesota side of the 17
river to go into service. The project will have a capitalized value of 18
approximately $2.3 million to go in-service. 19
20
Q. WHAT DOES THE COMPANY RECOMMEND RELATED TO DEPRECIATION OF THE 21
NEW PROJECT AT ST. CROIX FALLS? 22
A. Without a new remaining life being approved for the facility, the entire $2.3 23
million addition would be expensed through depreciation during 2016. To 24
avoid this situation and to acknowledge the fact that the facility is still in use 25
for its intended purpose, the Company recommends that the remaining life be 26
set to correspond with the term of the facility’s current FERC operating 1
license, which is set to expire in December 31, 2027. 2
3
Accordingly, the Company is recommending a remaining life of 12 years as of 4
January 1, 2016. With this new remaining life, 2016 depreciation will be 5
approximately $97,000. Depreciation will be approximately $215,000 in 2017 6
when a full year of depreciation is taken on the new project. These 7
depreciation amounts are reflected in the depreciation impact shown in Table 8
5. 9
10
Q. WHAT DOES THE COMPANY RECOMMEND FOR THE REMAINING LIFE AND NET 11
SALVAGE FOR THE NEW COURTENAY WIND PROJECT? 12
A. The Company proposes the remaining life be set to 25 years for the Courtenay 13
Wind Project at its in service date of October 2016, which is consistent with 14
the treatment of the Company’s Grand Meadow and Nobles Wind Farms. 15
This 25-year life is comparable to the expected remaining life stated by the 16
manufacturer of the turbines being used at these facilities. While wind farms 17
have become more common over the last decade, there is little retirement 18
history available to analyze when assessing whether a different remaining life 19
may be more accurate. The main components that would influence the life of 20
a wind turbine are the life of the nacelle and the blade. The Company has 21
experienced some early failures of these components, but not to a magnitude 22
that would suggest that a different life is more appropriate. 23
24
The Company is also recommending a net salvage rate of negative 8.5 percent 25
for this project. This is consistent with the net salvage rate proposed for the 26
new Borders Wind and Pleasant Valley Wind Projects. 27
B. 2017 through 2020 Remaining Lives Changes 1
Q. ARE THERE SIGNIFICANT PROJECTS IN 2017 AND BEYOND THAT WOULD 2
FURTHER IMPACT THE DEPRECIATION EXPENSE IN THIS CASE? 3
A. Yes. For the production assets, the Black Dog Unit 6 Project is a 215 MW 4
simple cycle gas plant in Burnsville, Minnesota. Please see the Direct 5
Testimony of Mr. Mills for further discussion of this project. 6
7
Q. WHAT DOES THE COMPANY RECOMMEND FOR THE REMAINING LIFE AND NET 8
SALVAGE FOR THE NEW BLACK DOG UNIT 6? 9
A. The Company proposes the remaining life be set to 40 years for the Black 10
Dog Unit 6 simple cycle gas plant, measured from its in-service date of March 11
2018. The 40-year remaining life is consistent with the lives assumed for 12
another recently added gas-fired unit, the High Bridge Other Production plant. 13
The Company also proposes to use a net salvage of negative five percent. 14
15
Based on the expected capital additions in 2018 for Black Dog Unit 6, the 16
proposed remaining life of 40 years as of the in-service date of the facility, and 17
the proposed net salvage rate of negative five percent, the Company is 18
estimating 2018 depreciation for Black Dog Unit 6 of approximately $2.2 19
million. This represents 9.5 months of depreciation based on project being in 20
service in mid-March 2018. A schedule showing the Total Company 21
calculation of the depreciation expense for the new gas plant is provided as 22
Schedule 8. 23
24
Q. ARE THERE SIGNIFICANT PROJECTS IN 2019 AND 2020 THAT WOULD FURTHER 25
IMPACT THE DEPRECIATION EXPENSE IN THIS CASE? 26
A. At this time there we do not know of any specific projects that would modify 1
the remaining lives or net salvage rates in 2019 and 2020. The next removal 2
cost study for non-nuclear generating units will be filed in 2020. However, we 3
do not have any estimate of the impact that study will have at this time. 4
5
7
A. 2017 Five-year Depreciation Study 8
Q. WHAT IS THE PROCESS FOR CONDUCTING A TD&G STUDY? 9
A. The five-year TD&G Depreciation Study is an analysis of annual depreciation 10
for depreciable plant in service as of a certain date. The Depreciation Study 11
recommends new depreciation rates for Transmission Plant, Distribution 12
Plant, and General Plant based on average life calculations and net salvage 13
rates. 14
15
The Depreciation Study encompasses four distinct phases. The first phase 16
involves data collection and field interviews. The second phase is an initial 17
data analysis. The third phase evaluates the information and analysis. Finally, 18
the fourth phase involves the calculation of depreciation rates and documents 19
the corresponding recommendations. 20
21
Q. WHAT CHANGES DOES THE COMPANY FORESEE RESULTING FROM ITS NEXT 22
FILING? 23
A. At this time we do not foresee changes in the current average service lives and 24
net salvage rates, except for two new assets. First, we do know that a second 25
large base software system will be in service late in 2016 and early in 2017. 26
This system is the Work and Asset Management (WAM) system and is part of 27
the conversion to the SAP system. This system replaces the PassPort and the 1
Maximo systems. There are two versions of the PassPort system in use at 2
NSPM, one for nuclear and one for all non-nuclear work. Since three work 3
management systems are being replaced, the WAM additions are projected to 4
occur over a 10 month period from November 2016 through August 2017. 5
Company witness Mr. David Harkness discusses this project in more detail. 6
My testimony discusses the asset because we are requesting that the WAM 7
system be assigned a 15-year amortization period, the same amortization 8
period approved for the new general ledger system on SAP. The system is 9
estimated to have additions of $29.4 million in 2016 and $92.1 million in 2017. 10
This results in a depreciation of $0.3 million in 2016, $5.6 million in 2017, and 11
$8.1 million in 2018. 12
13
Also, there is the new general ledger that will go into service in December 14
2015 and the Company is not recommending any change to the amortization 15
period from what was approved in the last case for this 2015 project. In the 16
last rate proceeding, the Company proposed a 15-year amortization period for 17
the new general ledger system when it goes into service in December 2015. 18
The new general ledger is a large base system, which is expected to be used 19
over a 15-year period similar to the current JD Edwards general ledger system 20
that is being replaced. The total addition is estimated to be $35.2 million, with 21
$32.4 million being placed in service in December 2015 and $2.8 million of 22
trailing charges as bills are finalized in the first three months of 2016. It will 23
have a half month of depreciation in 2015 with a full year of amortization in 24
2016. The 2016 amortization is estimated to be $2.3 million. 25
Second, there are new leasehold improvements for the new general office 26
building at 401 Nicollet Mall. The Company recommends that the leasehold 27
improvements be recovered over the period of the lease, which is 15 years. 1
The leasehold improvements are an addition of $16.7 million with the 2
depreciation expense being $0.5 million in 2016 and $1.2 million in 2017 and 3
beyond. 4
5
Q. IN TOTAL, WHAT IMPACT TO DEPRECIATION EXPENSE HAS THE COMPANY 6
INCLUDED IN THIS CASE FOR 2017? 7
A. Based on the expected capital additions in 2017 of $527 million, the Company 8
is estimating 2017 depreciation to increase approximately $13.4 million. A 9
schedule showing the Total Company calculation of the depreciation expense 10
for the new gas plant is provided in Schedule 8. 11
12
Q. IS THE COMPANY RECOMMENDING ANY OTHER CHANGES TO AVERAGE 13
SERVICE LIVES OR NET SALVAGE PERCENTAGES FOR TD&G ASSETS IN THIS 14
FILING? 15
B. Regulatory Asset for TD&G Theoretical Reserve Adjustments 18
Q. WHAT IS A THEORETICAL RESERVE SURPLUS? 19
A. A theoretical reserve is calculated by determining what the depreciation 20
reserve would be at a point in time, if the current information and 21
assumptions about the life, salvage, and cost of removal had been known since 22
the beginning of each asset’s life. For NSPM, the theoretical reserve is 23
currently lower than the actual book depreciation reserve, resulting in a 24
theoretical reserve surplus. It is possible for the opposite to be true - that the 25
theoretical reserve is higher than the actual book depreciation reserve, 26
resulting in a theoretical reserve deficiency. 27
Q. DID THE COMMISSION’S ORDER FROM THE COMPANY’S LAST RATE CASE, 1
DOCKET NO. E-002/GR-13-868, DEFINE HOW THE REMAINING THEORETICAL 2
RESERVE SURPLUS WAS TO BE APPLIED TO 2014 THROUGH 2016? 3
A. Yes. The Commission approved the Company’s proposal to accelerate the 4
previously approved amortization of the theoretical reserve surplus relating to 5
transmission, distribution, and general plant from eight years to three years. 6
Pursuant to the Commission’s decision, Xcel Energy is reducing its book 7
depreciation reserve to the theoretical reserve by amortizing the reserve 8
surplus of $261.2 million by 50 percent of the remaining surplus in 2014, 30 9
percent in 2015, and 20 percent in 2016. The following table shows the 10
annual unwinding of the surplus over the four year period for a total of $261.2 11
million, on a Minnesota jurisdictional basis. 12 Table 6 13
Theoretical Reserve Surplus 14 15 16 17 18 19 20 21
In 2017, the accumulated depreciation will no longer be in a surplus position, 22
the negative amortization of the surplus will be complete, and total 23
depreciation expense will therefore increase. Also, the rate base over the four-24
year period increases by $261.2 million, resulting in additional upward pressure 25
on revenue requirement. 26
Q. WHAT WILL HAPPEN TO DEPRECIATION IN 2017 AND BEYOND AFTER THE 1
NEGATIVE AMORTIZATION OF THEORETICAL RESERVE SURPLUS ENDS? 2
A. It will increase due to the expiration of the amortization of the theoretical 3
reserve surplus. Currently, the depreciation rates for the TD&G assets are set 4
based on the average service lives and net salvage rates as approved in Docket 5
E,G002/D-12-858. The amortization of the theoretical reserve surplus over 6
the last four years rebalances the reserve to where it should be for the 7
currently approved rates, assuming that these current rates were in effect since 8
each asset’s in service date. Thus, the depreciation expense in this case is 9
based on the approved average service life rates. 10
11
Q. DOES THIS AMORTIZATION OF THE THEORETICAL RESERVE CREATE A 12
REGULATORY ASSET? 13
A. Yes. The FERC required the Company to set up the negative amortization of 14
the theoretical reserve surplus in Account 182.3, Other Regulatory Assets, 15
when the Company reversed the depreciation expense through Account 407.3, 16
Regulatory Debits. In other words, the FERC does not allow the Company to 17
record the negative amortization of the theoretical reserve surplus in FERC 18
Account 403, Depreciation Expense and does not allow it to be offset against 19
Account 108, Accumulated Depreciation. Therefore, the Company’s 20
reporting of depreciation expense for Minnesota regulatory purposes 21
represents Depreciation Expense, as offset by the Regulatory Debits. 22
23
Q. IS THE COMPANY RECOMMENDING ANY CHANGES IN THIS PROCEEDING TO 24
DEAL WITH THIS THEORETICAL RESERVE REGULATORY ASSET? 25
A. Yes. The Company proposes to unwind this regulatory asset and requests 1
Commission approval of amortization rates to do this. These rates are shown 2
in Exhibit___(LHP-1), Schedule 10. 3
4
Q. DOES THIS AMORTIZATION OF THE REGULATORY ASSET CHANGE THE TOTAL 5
DEPRECIATION EXPENSE RECOGNIZED IN THIS CASE? 6
A. No. This regulatory asset is the presentation used for the Company’s U.S 7
generally accepted accounting principles (GAAP) books, and does not affect 8
regulatory reporting or ratemaking. The amortization expense for Minnesota 9
regulatory purposes is still computed and booked based on the average service 10
life depreciation rates applied to the original plant balance. The only 11
difference is that a portion of this depreciation expense is recorded in 12
depreciation expense, and a portion is recorded in amortization expense. In 13
the same manner, the accumulated depreciation for Minnesota regulatory 14
purposes consists of both accumulated depreciation and the regulatory asset. 15
This accounting is necessary to comply with the FERC’s requirements. 16
17
Q. WHEN DOES THE COMPANY PROPOSE TO BEGIN AMORTIZING THE 18
REGULATORY ASSETS? 19
A. The Company proposes to begin amortizing the regulatory assets in 2017, 20
after the completion of the amortization of the theoretical reserve surplus that 21
created the regulatory assets. 22
23
Q. HOW WERE THE PROPOSED AMORTIZATION RATES CALCULATED? 24
A. For most asset accounts, the amortization rates were calculated to amortize 25
the regulatory assets over the average remaining life of that asset account as of 26
the beginning of 2017. Exceptions to this are proposed for assets with 27
average remaining lives of less than five years as of the beginning of 2017. 1
For those assets, the Company proposes to amortize the regulatory asset over 2
five years. 3
6
Q. WHAT IS NUCLEAR DECOMMISSIONING? 7
A. Nuclear decommissioning is the method used to accumulate the final removal 8
costs for the Company’s three nuclear units. The amounts collected through 9
general rates are funded externally in a trust fund per NRC rules. The annual 10
accruals are calculated from a detailed engineering cost estimate to remove the 11
plant and to store the fuel until the federal government takes possession of all 12
the fuel assemblies. 13
14
Q. PLEASE FURTHER EXPLAIN THE COMPANY’S PROPOSAL REGARDING NUCLEAR 15
DECOMMISSIONING COSTS? 16
A. The Company submitted its petition for approval of the 2016-2018 Nuclear 17
Decommissioning accrual in Docket No. E002/M-14-761 on December 1, 18
2014. The accrual was to be effective January 1, 2016. The Company 19
received approval for the Minnesota Retail jurisdiction accrual in the amount 20
of $14.0 million on August 27, 2015. 21
22
Q. HOW WILL THIS ACCRUAL BE FACTORED INTO THE CURRENT REVENUE 23
REQUIREMENT? 24
A. The new accrual has been factored into the revenue requirement starting in 25
2016, as approved by the Commission. 26
27
Q. WHAT WAS THE PREVIOUSLY APPROVED NUCLEAR DECOMMISSIONING 1
ACCRUAL? 2
A. The previously approved Minnesota Retail jurisdictional accrual was 3
approximately $14.2 million dollars. This amount will be accrued through the 4
end of 2015, before switching to the new approved level on January 1, 2016. 5
6
Q. WERE THERE ANY OTHER RELEVANT CHANGES REQUESTED IN THE 2014 7
NUCLEAR DECOMMISSIONING FILING? 8
A. Yes. The study included an updated analysis of the End-of-Life (EOL) nuclear 9
fuel to be recovered over the life of the plant. The EOL nuclear fuel is a 10
mechanism to estimate the spike in fuel amortization that will occur in the in 11
the last two reload periods and to spread that increase to customers over the 12
remaining life of the nuclear units. Due to improved fuel utilization from 13
updated multi-cycle core designs and decreased projected nuclear fuel 14
commodity prices, the total amount to be accrued decreased by approximately 15
$28 million. 16
17
Q. WHAT WAS THE RESULTING IMPACT OF THIS DECREASE TO THE EOL NUCLEAR 18 FUEL TO BE RECOVERED? 19
A. The decrease in the amount of EOL nuclear fuel to be recovered had a 20
resulting decrease of $505,514 over the accrual calculated using the previous 21
EOL nuclear fuel cost estimate. The new accrual for EOL nuclear fuel in the 22
Minnesota jurisdiction is $2,020,602. The accrual using the previously 23
approved components was $2,526,116. 24
25
Q. HAS THIS IMPACT BEEN INCLUDED IN THE 2016 REVENUE REQUIREMENT? 26
A. Yes, the update to the EOL nuclear fuel accrual has been included in the base 1
data for the revenue requirement. 2
3
Q. HOW IS THE COMPANY PROPOSING TO HANDLE THE USE OF SETTLEMENT 4
PAYMENTS RECEIVED FROM THE U.S. DEPARTMENT OF ENERGY (DOE)? 5
A. The Company proposes that settlement payments received from the DOE 6
related to spent nuclear fuel storage costs be refunded to customers at the 7
time that the amount is known. We believe this addresses the Commission’s 8
order point 9 in Docket 14-761 which states; 9
10
Within 120 days of the date of this order or in its next rate case, Xcel 11 shall make a filing to enable the Commission to determine the 12 appropriate method for crediting any future Department of Energy 13 Settlement proceeds resulting from the Settlement extension. 14
15
We will also address this in the compliance filing in the DOE Settlement 16
Payment Docket , Docket No. E002/M-11-807, that we will file when we get 17
our next DOE payment (which is expected in the next 120 days). 18
19
Q. IS THIS TREATMENT DIFFERENT FROM HOW THE COMPANY PREVIOUSLY 20
TREATED THESE CREDITS? 21
A. Yes. In the triennial study approved by the Commission in December 2012 22
(Docket No. E002/M-11-939), the Company funded its annual nuclear 23
decommissioning accrual using the

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