BEFORE THE PUBLIC UTILITIES COMMISSION
OF THE STATE OF COLORADO
*****
RE: IN THE MATTER OF ADVICE
)
LETTER NO. 1597-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
)
CHANGES EFFECTIVE DECEMBER 23, 2011 )
DOCKET NO. 11AL-_____E
DIRECT TESTIMONY AND EXHIBITS OF LISA H. PERKETT
ON
BEHALF OF
PUBLIC SERVICE COMPANY OF COLORADO
November 22, 2011
BEFORE THE PUBLIC UTILITIES COMMISSION
OF THE STATE OF COLORADO
*****
RE: IN THE MATTER OF ADVICE
)
LETTER NO. 1597-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
)
CHANGES EFFECTIVE DECEMBER 23, 2011 )
DOCKET NO. 11AL-_____E
DIRECT TESTIMONY AND EXHIBITS OF LISA H. PERKETT
INDEX
SECTION
PAGE
I.
INTRODUCTION AND QUALIFICATIONS ...................................................... 2
II.
PURPOSE OF TESTIMONY ............................................................................ 2
III. PLANT-RELATED BALANCES AND EXPENSES .......................................... 7
IV. DEPRECIATION RATES FOR ELECTRIC AND COMMON PLANT.............. 20
V.
REGULATORY ACCOUNTING FOR EARLY RETIREMENT OF
GENERATION FACILITIES............................................................................ 27
VI. CALPINE ACQUISITION ADJUSTMENT ...................................................... 35
VII. BONUS TAX DEPRECIATION & DEFERRED INCOME TAXES .................. 41
LIST OF EXHIBITS
Exhibit No. LHP-1
Future Test Year Plant-Related Roll Forward
Exhibit No. LHP-2
Link of Exhibit No. LHP-1 to Exhibit No. DAB-1
Exhibit No. LHP-3
Comparison of Actual Plant Additions to Budgeted
Plant Additions - May 2011 through August 2011
Exhibit No. LHP-4
Comparison of Depreciation Expense for FTY
Based on Current and Proposed Depreciation
Rates and Calculation of Pro Forma Adjustment to
Depreciation Expense and Accumulated Reserve
for Depreciation
Exhibit No. LHP-4a
Comparison of Current and Proposed Depreciation
Rates by Plant Account
Exhibit No. LHP-5
Sample Accounting for Regulatory Assets/Liabilities
for Retired Steam Production Units, Using Cameo
Unit 1 as an Example
Exhibit No. LHP-6
Roll Forward by Facility for Steam Plant Early
Retirements
Exhibit No. LHP-7
Proposed Amortization Rates for Regulatory Assets
Associated with Early Plant Retirements
Exhibit No. LHP-8
Calculation of Acquisition Adjustment for the Assets
Purchased from Calpine (for Accounting Purposes
Only)
Exhibit No. LHP-9
Plant-Related Accumulated Deferred Income Tax
Impact of Bonus Depreciation Due to Various Laws
Enacted Since 2009
BEFORE THE PUBLIC UTILITIES COMMISSION
OF THE STATE OF COLORADO
*****
RE: IN THE MATTER OF ADVICE
)
LETTER NO. 1597-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
)
CHANGES EFFECTIVE DECEMBER 23, 2011 )
DOCKET NO. 11AL-_____E
DIRECT TESTIMONY AND EXHIBITS OF LISA H. PERKETT
1
I. INTRODUCTION AND QUALIFICATIONS
2
Q.
PLEASE, STATE YOUR NAME AND BUSINESS ADDRESS.
3
A.
Lisa H. Perkett, 414 Nicollet Mall, Minneapolis, MN 55401-1993.
4
Q.
BY WHOM ARE YOU EMPLOYED AND WHAT IS YOUR POSITION?
5
A.
I am employed by Xcel Energy Services Inc. (“XES”), the service company
6
subsidiary of Xcel Energy Inc.
7
Accounting.
My position is Director, Capital Asset
8
Q.
ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING?
9
A.
I am testifying on behalf of Public Service Company of Colorado (“Public
10
Service” or “Company”).
1
Q.
2
3
HAVE YOU INCLUDED A DESCRIPTION OF YOUR QUALIFICATIONS,
DUTIES AND RESPONSIBILITIES?
A.
4
Yes. A description of my qualifications, duties, and responsibilities is included
as Attachment A.
5
6
II. PURPOSE OF TESTIMONY
Q.
7
8
WHAT IS THE PURPOSE OF YOUR DIRECT TESTIMONY IN THIS
PROCEEDING?
A.
My testimony is divided into five main parts, which address the following:
9
(1) the calculation of plant-related balances for the future test year (“FTY”); (2)
10
presentation of updated depreciation rates for numerous electric and common
11
plant accounts that are being proposed by the Company for approval in this
12
case, as supported by the Electric and Common Utility Plant Depreciation
13
Rate Study at December 31, 2010 (“Depreciation Study”) sponsored by
14
Company witness Mr. Dane A. Watson of the Alliance Consulting Group and
15
the separate 2011 Dismantling Cost Study (“Dismantling Study”) sponsored by
16
Company witness Mr. Francis W. Seymore of TLG Services, Inc.; (3) a
17
discussion of the Company’s planned steam production retirements, the
18
regulatory asset and liability accounting for these retired assets, and the
19
Company’s proposal for the amortization of these regulatory assets and
20
liabilities; (4) the potential inclusion of an accounting acquisition adjustment
21
related to Blue Spruce Energy Center (“BSEC” or “Blue Spruce”) and Rocky
22
Mountain Energy Center (“RMEC” or “Rocky Mountain”), the generation
23
stations recently acquired from Calpine; and (5) the impact of bonus
2
1
depreciation on accumulated deferred income taxes as the result of recent
2
changes to the federal tax laws.
3
Q.
4
5
CAN YOU BRIEFLY SUMMARIZE WHAT YOU WILL ADDRESS IN EACH
OF THESE FIVE AREAS?
A.
As to the first part of my testimony, I will support the plant in-service and other
6
plant-related balances for the 2012 forecast test year, which have been used
7
to determine the forecast rate base in the FTY cost-of-service study, Exhibit
8
No. DAB-1 sponsored by Company witness Ms. Deborah A. Blair.
9
discuss the derivation of the plant balances as they are built from a starting
10
point of per-book balances (April 30, 2011) through December 31, 2012, which
11
is the end of the FTY in this case. The plant balances are the basis for
12
developing the related expenses (such as depreciation and deferred taxes)
13
and the resulting balances that are part of the rate base used in determining
14
the revenue requirements. With respect to projects that are a part of the
15
Company’s approved plan to comply with the Clean Air Clean Jobs Act
16
(“CACJA”), for which Construction Work In Progress (“CWIP”) is included in
17
rate base and not offset by the associated allowance for funds used during
18
construction (“AFUDC”), I will describe the process used for tracking the
19
estimated financing costs of construction applicable to Public Service’s retail
20
jurisdiction. This tracking mechanism is referred to as Pre-funded AFUDC and
21
is the same process used previously and approved by the Commission for
22
Comanche Unit 3 and certain transmission projects.
23
I will
With regard to book depreciation, the new depreciation rates proposed
3
1
by the Company for approval by the Commission for its electric and common
2
plant, along with the associated book depreciation accruals, is supported by a
3
Depreciation Study sponsored by Company Witness Dane Watson of Alliance
4
Consulting Group (“Alliance”), and the
5
Company Witness Fran Seymore of TLG Services, Inc. (“TLG Services”) I will
6
provide background information with respect to these Public Service studies
7
and the extent to which the recommendations included in those studies have
8
been incorporated into the depreciation rates the Company is proposing in this
9
case. As I will explain, we have elected not to adopt the depreciation rates
10
recommended by Mr. Watson for certain steam production units that will be
11
retired early, but rather to continue the current depreciation rates pending the
12
filing of applications with the Commission regarding the Company’s retirement
13
plans.
Dismantling Study sponsored by
14
With regard to the issue of generating unit retirements, Public Service
15
has retired several of its coal facilities and will be retiring two more coal units
16
within the test period of this proceeding. The Commission has approved these
17
retirements. Ms. Hyde provides details on the regulatory approval history of
18
the retirements in her Direct Testimony. These retirements will entail either
19
the final decommissioning of the entire station or, if a new unit is to be built in
20
its place, the partial decommissioning of the individual unit. I will discuss the
21
regulatory asset and regulatory liability accounting being followed for these
22
units, which is necessary because the costs of these assets have not been
23
fully recovered upon retirement. I recommend specific accounting treatment
4
1
to assure that the decommissioning costs are fully funded based on the
2
eventual actual costs incurred. The retired, or soon to be retired, units for
3
which this accounting treatment is being used are Cameo Units 1 and 2, and
4
Cherokee Units 1 and 2. I will discuss the accumulation of costs into the
5
regulatory assets and regulatory liabilities for these units, as well as the
6
appropriate amortization period for the balances once the facility has been
7
retired or decommissioning is underway.
8
Since the last electric rate case proceeding in Docket No. 09AL-299E,
9
two generating stations have been added to Public Service’s fleet. The two
10
stations are BSEC and RMEC, which the Company acquired from affiliates of
11
Calpine Corporation (“Calpine”) in December 2010. In Decision No. C10-1196
12
in Docket No. 10A-327E, the Commission approved the purchase of these
13
facilities from Calpine and the recovery of the costs associated with these
14
facilities through the Purchased Capacity Cost Adjustment (“PCCA”).
15
Recovery of these costs through the PCCA was approved only for an interim
16
period before the Company filed a Phase 1 rate case to include these costs in
17
base rates.
18
required for the Calpine asset acquisition have been debated with the Staff of
19
the Federal Energy Regulatory Commission (“FERC”), which also has
20
jurisdiction over the Company’s accounting. Although the process is not done
21
yet, we expect that the FERC Staff will require, for accounting purposes (not
22
ratemaking purposes), that the Company record on its books Calpine’s original
23
cost and associated accumulated book depreciation for these assets, with the
Subsequent to that approval, the specific accounting entries
5
1
amount of the purchase price above Calpine’s net book cost reflected as an
2
acquisition adjustment. I will discuss the accounting layout for these assets
3
and show that this accounting treatment does not result in any change to what
4
has been included in rate base in the case. Should this acquisition adjustment
5
accounting be required by the FERC, the depreciation rates for BSEC and
6
RMEC recommended by Mr. Watson and reflected in Exhibit No. LHP-4a will
7
need to be revised and the amortization of the acquisition adjustment would
8
need to be included in the cost of service.
9
Finally, with regard to the issue of plant-related deferred income taxes, I
10
will discuss the changes resulting from bonus tax depreciation allowed under
11
three tax laws enacted since the test year in the Company’s last electric rate
12
case. I will discuss the impact that these laws have on tax depreciation with
13
respect to certain investment placed in-service from 2009 through 2012, which
14
in turn affects the plant-related deferred tax balance in FTY. The three tax
15
laws allow companies to use the various bonus depreciation provisions on
16
qualified capital additions placed in-service in 2009 and continuing through
17
2013.
18
Q.
19
20
ARE YOU SPONSORING ANY EXHIBITS AS PART OF YOUR DIRECT
TESTIMONY?
A.
Yes. I am sponsoring the following exhibits:
21
•
Exhibit No. LHP-1 (future test-year plant-related roll forward);
22
•
Exhibit No. LHP-2 (schedule linking Exhibit No. LHP-1 to Exhibit No.
23
DAB-1);
6
•
1
2
Exhibit No. LHP-3 (comparison of actual plant additions to budgeted
plan additions for May 2011 through August 2011);
•
3
Exhibit No. LHP-4 (comparison of depreciation expense for FTY based
4
on current and proposed depreciation rates and calculation of pro forma
5
adjustment to depreciation expense and accumulated depreciation);
•
6
7
Exhibit No. LHP-4a (comparison of current and proposed depreciation
rates by plant account);
•
8
9
Exhibit No. LHP-5 (sample accounting for regulatory assets/liabilities for
retired steam production units);
•
10
11
Exhibit No. LHP-6 (roll forward by facility for steam plant early
retirement);
•
12
13
Exhibit No. LHP-7 (proposed amortization rates for regulatory assets
associated with early plant retirements);
•
14
15
Exhibit No. LHP-8 (calculation of the acquisition adjustment for assets
purchased from Calpine); and
•
16
17
Exhibit No. LHP-9 (plant-related accumulated deferred income tax
impact of bonus depreciation).
18
III. PLANT-RELATED BALANCES AND EXPENSES
19
Q.
WHAT GOVERNS THE COMPANY’S ACCOUNTING PRACTICES?
20
A.
The Company follows the applicable accounting rules established by generally
21
accepted accounting principles (“GAAP”), the uniform system of accounts
22
established by the FERC and policies and guidelines established by the
23
Company’s Capital Asset Accounting department, such as the Capitalization
7
1
Policy.
2
records in compliance with the FERC Uniform System of Accounts (“USofA”).
3
Q.
The Commission requires that the Company keep its books and
HOW ARE YOU INVOLVED IN THE DEVELOPMENT OF THE FORECAST
4
PLANT IN-SERVICE BALANCES USED TO DETERMINE THE TEST YEAR
5
AVERAGE RATE BASE IN THE REVENUE REQUIREMENTS STUDY
6
SPONSORED BY COMPANY WITNESS DEBORAH BLAIR?
7
A.
My department within XES, Capital Asset Accounting, is responsible for all
8
aspects of the fixed asset accounting for Public Service. It has developed and
9
provided information regarding forecasted plant information that has been
10
used in the rate base and revenue requirements analyses presented in this
11
case by Company witness Deborah Blair. One of the main components to
12
influence rate base, and thus revenue requirements, is additions to plant, also
13
known as capital additions.
14
Q.
HOW DO CAPITAL ADDITIONS INFLUENCE RATE BASE?
15
A.
In regard to plant assets, rate base has two main components -- plant
16
balances and accumulated reserve for depreciation. Capital additions cause
17
increases to plant-related rate base.
18
causes rate base to decrease. If capital additions were equal to depreciation
19
expense, the plant-related rate base would remain constant. If plant-related
20
rate base increases from one year to the next, it is because capital additions
21
are greater than the depreciation expense.
Additionally, depreciation expense
22
Exhibit No. LHP-1, which I will explain in more detail later in my
23
testimony, includes forecasted capital expenditures for additions that have
8
1
projected in-service dates during the test year and will thus affect test year
2
plant additions, rate base, and revenue requirements. The overall rate base
3
used in the cost-of-service study in this case reflects an increase from the one
4
filed with the Company’s last electric rate case in Docket No. 09AL-299E.
5
Q.
ARE YOU PROVIDING SUPPORT FOR THE NEED OR PRUDENCE OF
6
THE UNDERLYING CAPITAL ADDITIONS THAT HAVE INCREASED RATE
7
BASE?
8
9
A.
No. Other Company witnesses are providing testimony to support the plant inservice associated with their organizations within the Company, as follows:
George Hess
—
Production and related general plant.
Ian Benson
—
Transmission and related general plant.
Timothy Brossart
—
Distribution and related general plant.
Charles Anderson
—
General plant (related to information technology)
and software.
10
These witnesses are involved in the analysis and review that their
11
respective areas perform to assure the capital expenditures are crucial and
12
necessary to support their areas.
13
theirs finishes. I am responsible for the calculations of plant-related balances
14
and expenses, which can only be derived once the indicated business areas
15
have completed their analyses. The process of moving the construction from
16
CWIP to plant produces the capital additions that then form the basis from
17
which all the other plant-related information can be provided.
My area of responsibility begins where
9
1
Q.
WHAT IS INCLUDED IN PLANT-RELATED INFORMATION?
2
A.
Plant and plant-related information consists of account balances for plant in-
3
service and the balances and expenses directly derived from plant, such as
4
book depreciation expense, book depreciation reserve, tax depreciation,
5
deferred income taxes, and accumulated deferred income taxes (“ADIT”).
6
Plant-related balances consist of construction work in progress, depreciation
7
reserve, and ADIT. Plant-related expenses are AFUDC, book depreciation,
8
and annual deferred taxes. Plant and plant-related information is an important
9
part of the overall development of rate base and revenue requirements. Plant
10
in rate base consists of plant in-service less depreciation reserve less ADIT
11
associated with the plant.
12
Q.
13
14
IS THE FTY PLANT AND PLANT-RELATED INFORMATION BASED ON
ESTABLISHED PLANT ACCOUNTING PRINCIPLES?
A.
Yes. In an FTY presentation, the development of the plant information follows
15
the applicable accounting rules established by GAAP, the FERC, and policies
16
and guidelines established by the Company’s Capital Asset Accounting
17
department, such as the Capitalization Policy. Thus, the FTY plant and plant-
18
related information is formulated using the same methods, rules, calculations,
19
and factors as the Company uses to record actuals each month. For example,
20
the tax depreciation and deferred taxes for the FTY use the same accounting
21
module and routines that are employed by the Company to prepare deferred
22
tax journal entries and to produce the tax filing information filed with the
23
Internal Revenue Service (“IRS”).
10
1
Q.
2
3
PLEASE DESCRIBE THE DEVELOPMENT OF FTY PLANT AND PLANTRELATED INFORMATION.
A.
The forecasted information is extracted from the Company’s 2012 budget
4
information for plant assets for the 13 months ending with December 31, 2012.
5
As with any plant information, the forecasted balances are influenced by the
6
activity in the preceding years.
7
forward month by month (known as a “monthly roll forward”) from the last
8
month’s actuals at the time the forecast was prepared, which in this case was
9
April 2011, and forecasted plant and plant-related balances are built upon
10
these actuals using the forecasted changes in plant and plant related
11
expenses until all months have been calculated through the end of the FTY.
12
Exhibit No. LHP-1 summarizes this roll forward calculation from the actual
13
plant in-service balances as of April 30, 2011 through December 31, 2012.
14
This roll forward serves as the basis for the FTY plant in-service balances
15
used by Company witness Deborah Blair in the determination of the FTY rate
16
base.
17
related data between my Exhibit No. LHP-1 and the revenue requirements
18
study contained in Ms. Blair’s Exhibit No. DAB-1. Lastly, Exhibit No. LHP-3
19
has been provided to show how the forecasted closings to plant since
20
completion of the budget compare to actuals for the months of May through
21
August, 2011.
Therefore, the plant information is rolled
Exhibit No. LHP-2 has been provided as a numerical link of plant
11
1
Q.
2
3
WHAT IS THE DIFFERENCE BETWEEN BUDGETED AND ACTUAL
CLOSING?
A.
It is very small. The difference in closings through August 2011 is only $266
4
thousand.
The differences in closings are reviewed to determine if the
5
difference is due to timing within the current year, timing between 2012 with
6
2011, or a change in the estimated project cost. The timing within 2011 is
7
assumed to have no effect on the FTY, since all projects placed in service by
8
December 2011 become part of the 13-month average rate base in the FTY
9
and the exact point in time during the year they were placed in service does
10
not impact the resulting 13-month average.
11
decrease in the FTY for the other two categories -- the timing between 2012
12
and 2011 and changes in estimates -- is dependent upon the timing or
13
change.
14
represents a 0.02 percent overall impact on net plant in rate base
15
Q.
16
17
However, the increase or
It is estimated that the difference between actuals and forecast
WHAT ARE THE MAIN COMPONENTS OF PLANT AND PLANT-RELATED
INFORMATION?
A.
There are several components that comprise the plant and plant-related
18
information, as I mentioned above. The three most influential components are
19
CWIP, plant in-service, and the accumulated reserve for depreciation.
20
CWIP is an account that is used to gather all the construction-related
21
costs together as they are being incurred during the construction of the asset.
22
The costs incurred to build or install a fixed asset in the construction process
23
are capital expenditures. The accumulation of the construction expenditures
12
1
continues until the asset is ready to be used for its intended purpose and then
2
the asset is placed into service.
3
accumulated CWIP to plant in-service is known as the capital addition, or plant
4
addition.
The amount transferred from the
5
Plant in-service represents facilities that are “used and useful” in
6
providing utility service, including facilities currently in service, capital projects
7
completed but not classified, and plant held for future use. Forecasted plant
8
in-service represents historical and projected additions and retirements to
9
Public Service’s electric and common utilities. Common utility represents all
10
the general property that is used in the general operations of the business that
11
affect more than one utility, such as electric and gas operations.
12
additions represent plant that will be placed in service during the month.
Plant
13
Accumulated reserve for book depreciation, also known as the book
14
depreciation reserve, is the accumulation of book depreciation expense taken
15
on assets that are in service. When an asset is retired, the original cost of the
16
asset reduces the book depreciation reserve based on the assumption that the
17
asset is fully expensed (i.e., depreciated) at that time. The average monthly
18
plant balance multiplied by the applicable depreciation rate results in the
19
depreciation expense, which increases the depreciation reserve.
20
into the depreciation rate is a net salvage rate to provide for future removal
21
less any gross salvage value. Lastly, actual removal expenditures decrease
22
the reserve and salvage proceeds increase it.
13
Factored
1
Q.
PLEASE PROVIDE A SUMMARY OF THE CWIP ACTIVITY IN A MONTH.
2
A.
During the course of each month, the beginning CWIP balance is increased by
3
CWIP expenditures incurred during the month and AFUDC, and is reduced by
4
the CWIP balances associated with projects that are placed in service during
5
the month. Table 1 summarizes the monthly transactions for CWIP:
Table 1
CWIP Beginning Balance
+
CWIP Expenditures
+
AFUDC
-
CWIP Closings (equal to
Additions to Plant In-service)
=
CWIP Ending Balance
6
Q.
PLEASE PROVIDE A SUMMARY OF PLANT ACTIVITY IN A MONTH.
7
A.
During the course of each month, the beginning plant balance is increased to
8
reflect plant additions and reduced to reflect plant retired from service. Table 2
9
summarizes the monthly transactions for plant.
10
Table 2
Plant Beginning Balance
+
Additions (equal to CWIP
Closings from Table 1)
-
Plant Retirements
=
Plant Ending Balance
14
1
Q.
2
3
PLEASE PROVIDE A SUMMARY OF DEPRECIATION RESERVE ACTIVITY
IN A MONTH.
A.
During the course of each month, the beginning depreciation reserve is
4
increased by depreciation expense and any salvage proceeds realized, and is
5
reduced by the depreciation reserve attributable to retirements (equal to the
6
gross plant cost of the retired assets) and removal costs. Table 3 summarizes
7
the monthly transactions for depreciation reserve.
Table 3
Depreciation Reserve Beginning Balance
+
Depreciation Expense
-
Plant Retirements
+
Salvage Value Realized
-
Plant Removal Expenditures
=
8
Q.
9
WHEN YOU PRESENTED THE ITEMS RECOGNIZED IN THE CWIP
ROLLFORWARD IN EXHIBIT NO. LHP-1, YOU LISTED AFUDC. WHAT IS
10
11
Depreciation Reserve Ending Balance
AFUDC?
A.
AFUDC is used to assign the assumed cost of financing construction to the
12
asset that would normally be on the income statement during construction.
13
Once the asset goes into service, the total cost of the asset is systematically
14
allocated back to the income statement in the form of depreciation expense
15
over the life of the asset. Since the AFUDC is part of the asset cost, the
16
construction financing costs move from the balance sheet to the income
17
statement as a part of depreciation over the life of the asset. Public Service
15
1
follows the FERC USofA in calculating the AFUDC rate and its application to
2
the construction. The AFUDC rate is a weighted cost of capital that first gives
3
weight to short-term debt as a function of the CWIP balance and then factors
4
in the costs of long-term debt and common equity.
5
Q.
6
7
WHAT IS PRE-FUNDED AFUDC AND WHY IS IT NOT SHOWN AS AN ITEM
IN THE CWIP ROLLFORWARD IN EXHIBIT NO. LHP-1?
A.
Pre-funded AFUDC is a mechanism used by the Company to track the
8
estimated financing costs of construction when a jurisdiction is allowing for
9
recovery of these financing costs in current rates while the asset is in CWIP.
10
This is the mechanism that we use to effect the “current recovery of CWIP”
11
allowed by the Commission for certain projects. It ensures that the customers
12
in jurisdictions allowing CWIP in rate base get the appropriate credit for the
13
policy decision, while in those jurisdictions not allowing for such treatment,
14
AFUDC continues to accrue for the asset.
15
Q.
HOW IS PRE-FUNDED AFUDC CALCULATED?
16
A.
To keep appropriate accounting across all jurisdictions, we continue to use the
17
traditional method of calculating the AFUDC at the total Company level. For
18
those construction assets included in rate base, Pre-funded AFUDC is
19
recognized concurrently, which in effect reverses the jurisdictional portion of
20
the regular AFUDC. This offset, referred to as Pre-funded AFUDC, reduces
21
the amount of AFUDC associated with the projects afforded this ratemaking
22
treatment, leaving only that portion that is allocated to Colorado non-retail
23
jurisdictions.
16
1
The Pre-funded AFUDC and regular AFUDC are not commingled, but
2
are tracked separately such that the Colorado jurisdictional customers are
3
assured their entire benefit. Pre-funded AFUDC is recorded in FERC Account
4
No. 253, Other Deferred Credits, during the construction process as AFUDC is
5
incurred. The amount is a jurisdictional amount. Once the associated asset is
6
placed into service, the Pre-funded AFUDC balance is amortized over the
7
same time period as the associated asset.
8
Q.
9
10
WHICH ASSETS HAVE PRE-FUNDED AFUDC ASSOCIATED WITH THEM
IN THIS PROCEEDING?
A.
In accordance with the Settlement Agreement in Docket No. 06S-234EG,
11
approved by the Commission in Decision No. C06-1379, Public Service
12
included the December 31, 2006 ending CWIP balance for Comanche Unit 3
13
and its related projects (pollution control projects at Comanche Units 1 and 2
14
and Comanche Unit 3 transmission) in rate base, thereby establishing the
15
2006 layer for accumulation of Pre-funded AFUDC.
16
transmission projects in CWIP as of December 31, 2007 were included in the
17
rate base calculation for the Transmission Cost Adjustment rider (“TCA Rider”).
18
As a result of the treatment authorized by the Commission in Decision No.
19
C06-1379, the Colorado retail jurisdiction does not have to provide for AFUDC
20
on a portion of the CWIP balance for the Comanche project and for certain
21
transmission projects included in the TCA Rider. In Decision No. C09-1446 in
22
Docket No. 09AL-299E, a second Pre-funded layer for Comanche 3 project
23
was established based on the ending 2009 CWIP balance.
17
Beginning in 2008,
1
Q.
COULD YOU EXPLAIN HOW THIS LAYERING WORKS?
2
A.
To summarize for Comanche Unit 3, prior to January 2007, all customers bear
3
the costs for AFUDC.
From January 2007 through December 2009, the
4
portion of AFUDC incurred on the ending 2006 CWIP balance will be borne by
5
wholesale customers only, with AFUDC taken on the CWIP balance greater
6
than the 2006 ending CWIP being borne by all customers. Finally, the AFUDC
7
on the balance beginning with January 2010 will be borne by wholesale
8
customers. This layering effect for the Comanche Unit 3 project is shown
9
pictorially below.
The portions of the triangle not labeled “Wholesale
10
Customers Only” represent AFUDC funded by all customers. The “Wholesale
11
Customers Only” areas represent the portion of total AFUDC that is not funded
12
by retail customers, due to the various layers being included in rate base, and
13
the Pre-funded AFUDC amounts will assure that the retail customers are not
14
charged with this cost throughout the life of Comanche Unit 3.
Wholesale
Customers
Only
Wholesale Customers Only
Start of
Construction
15
16
Q.
December
2006
December
2009
IS THE COMPANY INCLUDING A RETURN ON CWIP FOR CERTAIN
CACJA-RELATED PROJECTS IN THIS RATE CASE?
18
1
A.
Yes. As authorized in paragraph 204 of Decision No. C10-1328 in Docket No.
2
10M-245E, Public Service has included CWIP for certain CACJA-related
3
projects in its rate base in this rate case filing. The projects included in rate
4
base for the test year are the Synchronous Condenser for Cherokee Unit 2,
5
the Combined Cycle for Cherokee (Units 5, 6, and 7), and the pollution control
6
equipment for Pawnee.
7
forecasted beginning with the June 30, 2012-ending CWIP balance, based on
8
the presumption that rates would be in effect beginning with July 2012.
9
Q.
10
11
For these projects, the Pre-funded AFUDC was
HOW IS THE COMPANY PROPOSING TO TREAT PRE-FUNDED AFUDC IN
THE 2012 FTY COST OF SERVICE?
A.
Pre-funded AFUDC has been included in both the determination of rate base
12
and income statement, so that Colorado jurisdictional ratepayers do not bear
13
the costs of AFUDC for projects where they have already provided for a
14
current return on CWIP. Inclusion of Pre-funded AFUDC results in excluding
15
costs that would otherwise be recovered from ratepayers twice, once through
16
a current return on CWIP, as provided for in either general rates or rate riders,
17
and once through the recovery of AFUDC. Pre-funded AFUDC is provided for
18
assets once they begin to earn a return on their CWIP balance.
19
In the revenue requirements study for the 2012 FTY sponsored by
20
Company witness Deborah Blair, all Colorado jurisdictional Pre-funded AFUDC
21
has been directly assigned to the Colorado retail jurisdiction, according to (i)
22
the functional class of the associated asset for CWIP, depreciation reserve,
23
plant in-service, and accumulated deferred income taxes in rate base, and
19
1
(ii) AFUDC, depreciation expense, and deferred taxes expense included in the
2
income statement. Accumulated Pre-funded AFUDC is a reduction to rate
3
base after it has been allocated by jurisdiction, with the amortization of the
4
Pre-funded AFUDC balance being a reduction to depreciation expense after
5
the total Company expense was assigned to the retail jurisdiction. These Pre-
6
funded AFUDC items are already at a jurisdictional level; thus, any offset must
7
be made once the rate base and the income statement are allocated by
8
jurisdiction.
9
IV. DEPRECIATION RATES FOR ELECTRIC AND COMMON PLANT
10
Q.
PLEASE DEFINE "DEPRECIATION."
11
A.
The FERC's definition of depreciation as set forth in its USofA is the loss in
12
service value not restored by current maintenance, incurred in connection with
13
the consumption or prospective retirement of electric plant in the course of
14
service from causes which are known to be in current operation and against
15
which the utility is not protected by insurance. Among the causes to be given
16
consideration are wear and tear, decay, action of the elements, inadequacy,
17
obsolescence, changes in the art, changes in demand and requirements of
18
public authorities.
20
1
Q.
2
3
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
4
case, approve the specific depreciation rates for the electric and common
5
utility plant accounts as shown on Exhibit No. LHP-4a.
6
changes are being proposed for nearly all of the Company’s Steam
7
Production,
8
Distribution, General, and Common plant accounts. These deprecation rate
9
changes are supported by the Depreciation Study conducted by Alliance,
10
which incorporates the updated cost of removal estimates pursuant to the TLG
11
Services Dismantling Study.
12
Q.
Hydraulic
Production,
OF
14
REQUESTING IN THIS PROCEEDING.
A.
Production,
Transmission,
PLEASE DESCRIBE THE STUDIES THAT WERE PREPARED IN SUPPORT
13
15
Other
Depreciation rate
THE
DEPRECIATION
CHANGES
THAT
THE
COMPANY
IS
In 2011, Public Service requested Alliance to perform a depreciation study
16
covering electric and common utility assets. Alliance personnel have over 50
17
years of combined experience in conducting depreciation studies, as well as
18
many years of utility experience managing and studying utility assets. The
19
discussion of the process and conclusions for the electric and common assets
20
is discussed by Company witness Dane A. Watson of Alliance.
21
Depreciation Study is provided as Exhibit No. DAW-1.
21
The
1
Q.
2
3
HOW WERE ESTIMATES FOR DISMANTLING GENERATING FACILITIES
PREPARED?
A.
The Company retained TLG Services to prepare a revised demolition study,
4
referred to as the Dismantling Study (dated September 2011), for various
5
identified Company-owned generating facilities. The Dismantling Study was
6
incorporated into the Depreciation Study for the determination of the
7
depreciation rates. The Dismantling Study is discussed by Company witness
8
Francis W. Seymore of TLG Services. The Dismantling Study is provided as
9
Exhibit No. FWS-1.
10
Q.
11
12
PLEASE DESCRIBE THE DISMANTLING COST STUDY PERFORMED BY
TLG SERVICES.
A.
A dismantling study examines the cost of removing the boilers, turbine
13
generators, fuel handling systems, and other systems and structures, and
14
provides the removal or dismantling cost estimate for an entire facility. That
15
cost estimate is used to develop the net salvage component of the proposed
16
depreciation rate.
17
estimate refer to the same cost.
Thus, a removal cost estimate and a dismantling cost
18
The TLG Services Dismantling Study is a site specific and
19
comprehensive cost estimate for the dismantling costs, including an estimate
20
of residual salvage value, for the Public Service fleet of fossil-fuel generating
21
units. The specific units included in the Dismantling Study are as follows:
22
Arapahoe Units 1, 2, 3, and 4;
23
Blue Spruce Units 1 and 2;
24
Cameo Units 1 and 2;
22
1
Cherokee Units 1, 2, 3, and 4;
2
Comanche Units 1, 2 and 3;
3
Craig Units 1 and 2;
4
Fort St. Vrain Units 1-6;
5
Hayden Units 1 and 2;
6
Pawnee Unit 1;
7
Rocky Mountain Units 1-3;
8
Valmont Unit 5; and
9
Zuni Units 1 and 2.
10
Periodic analyses of expected cost of removal are needed to ensure
11
that depreciation rates are set appropriately to recover both the original cost of
12
the asset and the net salvage value. TLG Services personnel are well known
13
throughout the utility industry for their work in estimating dismantling costs of
14
all types of generating units.
15
personnel look at all of the activities needed to dismantle a facility and develop
16
costs for these detailed activities customized to the power plant.
17
Q.
In performing its studies, TLG Services
IS THE COMPANY PROPOSING TO CHANGE ITS DEPRECIATION RATES
18
TO REFLECT ALL OF THE DEPRECIATION RATE CHANGES REFLECTED
19
BY THE DEPRECIATION STUDY?
20
A.
No, there are three exceptions related to three steam production generating
21
units that will be retired early for which the Company is electing not to adopt
22
the revised depreciation rates indicated by the Depreciation Study and
23
recommended by Mr. Watson. For Arapahoe Unit 3, Valmont Unit 5, and
24
Cherokee Unit 3, Public Service is not proposing any change to its currently-
25
approved depreciation rates, but rather will maintain the current depreciation
23
1
rates for purposes of recovering depreciation expense in its rates until these
2
units are retired. As discussed by Ms. Hyde in her Direct Testimony, the
3
Commission approved an emissions reduction plan for Public Service in the
4
CACJA proceedings in Docket No. 10M-245E that includes the early
5
retirement of Arapahoe 3, Valmont 5 and Cherokee 3. However, the Company
6
has not yet filed its applications to modify the Certificate of Public
7
Convenience and Necessity (“CPCNs”) for those stations for the early
8
retirement of those units.
9
appropriate to request depreciation cost recovery in this case based on the
10
As such, the Company did not consider it
early retirement dates and updated costs of removal for these three units.
11
In all other respects, the Company is proposing in this case to
12
implement the depreciation rate changes indicated by the Depreciation Study
13
and recommended by Mr. Watson.
14
Q.
PLEASE SUMMARIZE THE DEPRECIATION EXPENSE CHANGE BEING
15
REQUESTED IN THIS PROCEEDING RESULTING FROM THE PROPOSED
16
DEPRECIATION RATES.
17
A.
The effect of incorporating the proposed new depreciation rates into the FTY
18
results in a depreciation expense increase of approximately $18.2 million for
19
2012 (total Company without common utility allocated). Exhibit No. LHP-4
20
shows this calculation which takes the depreciation expense calculated for
21
each facility for generation and for each functional group for transmission and
22
distribution using currently approved rates and recalculates the forecasted
23
depreciation expense using the proposed depreciation rates.
24
1
Mr. Watson goes into detail on all the updates and changes made to
2
the depreciation study for the electric and common utility assets. The majority
3
of the $18.2 million change to depreciation is in the Steam Production
4
functional group.
5
remaining life technique whereby the change can be the result of a change in
6
the terminal retirement date for a production unit.
7
Depreciation Study, Public Service requested that the retirement dates for
8
production facilities be revised in as follows in Table 4:
The depreciation rate is calculated using an average
25
For purposes of the
Table 4
Retirement Year
(Approved
Depreciation
Rates)
Retirement Year
(Proposed
Depreciation
Rates)
Arapahoe Unit 3
2011
2013
+2
Arapahoe Unit 4
2015
2013
-2
Cherokee Unit 2 –
Condenser
New
2027
+ 15
Cherokee Unit 3
2022
2016
-6
Hayden Unit 1
2025
2030
+5
Valmont Unit 5
2024
2017
-7
Zuni Unit 2
2013
2014
+1
Ames
2040
2050
+ 10
Cabin Creek
2067
2044
- 23
Georgetown
2039
2036
-3
Salida Hydro
2029
2027
-2
Shoshone
2039
2058
+ 19
Tacoma Hydro
2049
2050
+1
Alamosa
2013
2019
+6
Arapahoe Unit 4 – Gas
New
2023
+ 10
Cherokee Units 5, 6, & 7
New
2055
+ 40
Fort Lupton
2015
2020
+5
Fruita
2013
2019
+6
Valmont CT
2013
2019
+6
Wind to Hydrogen
New
2021
+ 15
Generating Unit
Change
(in
years)
Steam Production
Hydraulic Production
Other Production
1
The remaining change to the depreciation rate is the result of an update
2
in (1) the average remaining life rate calculation using current net investment
3
amounts or a revised dismantling study for production units and (2) updated
26
1
average service lives and net salvage rates for transmission, distribution, and
2
general plant. The details of these adjustments are discussed in Mr. Watson’s
3
testimony.
4
Q.
ARE ANY OF THE COMPANY’S PROPOSED DEPRECIATION RATES
5
SUBJECT TO POSSIBLE MODIFICATION DURING THE COURSE OF THIS
6
RATE CASE?
7
A.
Yes.
If the FERC requires the Company to recognize the acquisition
8
adjustments for the assets purchased from Calpine on its books, then a
9
modification of the proposed depreciation rates for the BSEC and RMEC units
10
will be required, along with the amortization of the associated acquisition
11
adjustments associated. This is discussed in greater detail in the Calpine
12
Acquisition Adjustment section in my testimony below. The calculation of the
13
resulting revised depreciation rates for BSEC and RMEC in the event FERC
14
requires the recognition of an acquisition adjustment is shown in Exhibit No.
15
LHP-8.
16
17
18
V.
Q.
REGULATORY ACCOUNTING FOR EARLY RETIREMENT OF
GENERATION FACILITIES
PLEASE DESCRIBE THE REGULATORY ASSETS RELATED TO THE
19
EARLY RETIREMENT OF THE GENERATION FACILITIES REFLECTED IN
20
THE COST OF SERVICE.
21
A.
In accordance with Decision No. C09-1446 in Docket No. 09AL-299E,
22
paragraph 119, Public Service has included certain regulatory assets for
23
Cameo Units 1 and 2 in the cost of service. Consistent with Decision No. C10-
27
1
1328, Docket No. 10M-245E, Public Service has included certain regulatory
2
assets for Arapahoe Units 3 and 4, Cherokee Units 1 through 4, and Valmont
3
Unit 5 in the cost of service.
4
accounting and ratemaking treatment when the Company was previously
5
ordered to retire a generating unit earlier than the retirement date used in the
6
authorized depreciation rate in order to address the under recovery of the
7
original cost and the estimated final removal cost resulting from the early
8
retirement.
Public Service has employed this same
9
Briefly, this accounting treatment is employed for those assets which
10
have specifically received approval from the Commission and in those
11
instances where the financial remaining life is shorter than the Commission-
12
approved remaining life used to develop the current depreciation rate. The
13
accounting treatment results in a regulatory asset equal to the unrecovered
14
plant costs (both original cost and estimated removal costs) at the early
15
retirement date. The amount included in the regulatory asset is equal to the
16
sum of all the depreciation expense that would have been recognized between
17
the early retirement date and the retirement date used in the depreciation rate
18
to fully depreciate the asset by that later date. Additionally, Public Service has
19
included this regulatory asset in rate base and its amortization in the revenue
20
requirement of the FTY, which effectively replicates the recovery of the asset
21
as if it were still an operating asset over the original remaining life. Upon
22
retirement, the accounting transactions are split into two components -- that
23
for the original cost of the asset with its accumulated depreciation based on
28
1
the regulatory remaining life (referred to as the “Life” component) and the
2
other for the cost of final removal with its portion of accumulated depreciation
3
(referred to as the “COR” component). Each component is tracked separately
4
through the remaining recovery period.
5
Q.
6
7
PLEASE DESCRIBE THE BASIC ACCOUNTING BEING USED FOR THE
LIFE COMPONENT.
A.
For the Life component, the depreciation expense is recorded in FERC
8
Account 403, Depreciation Expense, using the shorter financial remaining life.
9
The difference in depreciation expense between the amount recognized in
10
FERC Account 403 and the amount based on the regulatory remaining life is
11
recognized in FERC Account 407, Amortization of Unrecovered Plant Costs,
12
thus accumulating the difference in the two depreciation recoveries in FERC
13
Account No. 182.2, Regulatory Assets – Unrecovered Plant Costs.
14
transaction occurs during the final operating period of the unit and ceases
15
once the plant is retired. After retirement, the regulatory asset (Life) would be
16
amortized over the remaining number of years from retirement until the
17
regulatory remaining life is exhausted. For example, Cameo Unit 1 retired in
18
2010 and had a regulatory remaining life based on a 2017 retirement date.
19
Until a different recovery period is proposed and approved, the Cameo Unit 1
20
regulatory asset (Life) would amortize to zero based on a seven-year period.
21
The original cost of plant, the financial accumulated depreciation, and the
22
regulatory asset are included in rate base in the final years of operation to
23
assure that the asset’s rate base is maintained.
29
This
Once retirement has
1
occurred, only the regulatory asset remains in rate base. The following graph
2
shows an asset’s net plant balance throughout its life with the financial
3
remaining life differentiating from the regulatory remaining life toward the end.
Financial <
Regulatory
Remaining Life
Same
Financial &
Regulatory
Remaining Life
Reg.
Asset
(Life) Build-up
Reg.
Asset (Life)
Amortization
Financial
Recovery
Retirement
Date
4
Q.
5
6
PLEASE DESCRIBE THE BASIC ACCOUNTING BEING USED FOR THE
COR COMPONENT.
A.
For the COR component, while the generating unit is in service, the
7
accumulated reserve associated with this component is tracked as a
8
regulatory liability for financial purposes, but is considered part of FERC
9
Account 108, Accumulated Provision for Depreciation for ratemaking. Thus,
10
this regulatory liability is an offset to rate base, the same as the accumulated
11
reserve. At retirement, the regulatory liability is transferred to a sub account of
12
FERC Account 182.2, Unrecovered Plant Costs, where the effect is a
13
reduction in the regulatory asset account until the actual removal costs are
14
recognized. The amortization for the COR component after retirement is still
15
recognized over the remaining life that was used in the depreciation rate from
30
1
the last rate case in Docket No. 09AL-299E, factoring in any actual or
2
estimated removal costs.
3
Q.
HOW IS THE COMPANY PROPOSING TO TREAT THESE REGULATORY
4
ASSETS AND LIABILITIES FOR RATEMAKING PURPOSES IN THIS
5
CASE?
6
A.
Public Service requests that the regulatory assets and the regulatory liabilities
7
be included in rate base (netted), and that it be permitted in future rate cases
8
to earn a full rate of return on the net amount. The purpose of this accounting
9
and rate treatment is to preserve the rate base that would be present toward
10
the end of each asset’s useful life, given that there is a removal cost factor in
11
the depreciation rate and an under-recovery of the original cost.
12
shows how the various components would contribute to rate base under the
13
proposed accounting:
Table 5
Table 5
+ Regulatory Asset - Plant
+ Regulatory Asset – COR (negative balance)
= Rate Base
14
For illustrative purposes, the proposed accounting for a hypothetical
15
unit is shown in Exhibit No. LHP-5.
16
examples: (1) the accounting layout assuming that the Life and COR
17
components are both under-recovered at retirement and after actual removal
18
is recognized; (2) the layout assuming that the COR actuals are less than what
19
was recovered, but the under-recovery of the COR component is less than the
31
This exhibit shows three accounting
1
under-recovery of the Life component; and (3) the layout whereby the COR
2
component under-recovery is greater than the remaining recovery for the Life
3
component. A second exhibit, Exhibit No. LHP-6, shows the regulatory assets
4
included in the FTY (at this time, there is no regulatory liability forecasted to
5
exist for these early retired units). There are regulatory assets that are being
6
established in the final years for units at several facilities, as well as seven
7
units that are or will be retired in the FTY. A third exhibit, Exhibit No. LHP-7,
8
contains further detail for those units currently retired or which will be retired
9
by the end of the FTY and the proposed amortization rates for the regulatory
10
assets. Exhibit No. LHP-7 contains the regulatory assets as of the end of
11
2011 for Cameo Units 1 and 2 and Cherokee Units 1 and 2. For simplicity,
12
Cameo common plant has been added to Cameo Unit 2. The exhibit contains
13
an estimated recovery schedule run out through the year amortization ends for
14
the facilities that are not fully recovered in the Life component and that are
15
actively being decommissioned for the COR component. It also shows the
16
recovery based on current rates and the change in amortization rate that
17
would be necessary to fully amortize the regulatory assets. Arapahoe Units 1
18
and 2 and Zuni Unit 1 are retired in place waiting for the remaining units to
19
retire before actual removal commences. Although there is the possibility that
20
the early retirement accounting may be necessary for the COR component for
21
these units when the actual costs are incurred, the removal costs are not
22
expected to be incurred for several years. Therefore, these three units are not
23
showing any current amortization expense.
32
1
Q.
2
3
IS THE COMPANY SEEKING COMMISSION APPROVAL OF THE
ACCOUNTING TREATMENT SET FORTH ABOVE?
A.
No. The Commission already approved this accounting treatment in Decision
4
Nos. C09-1446 and C10-1328. The purpose of this information is to define
5
how the approved accounting for the various assets affects the rate base and
6
how revenue requirements are impacted.
7
Q.
8
9
PLEASE SUMMARIZE THE AMORTIZATION EXPENSE CHANGE BEING
REQUESTED.
A.
The Company is requesting approval of the proposed amortization rates for
10
Cameo Units 1 and 2 and Cherokee Units 1 and 2. We are currently using the
11
depreciation rate split into a Life component and a COR component. The
12
amortization rate for each unit is based on the remaining period from January
13
2012 until the end of the retirement year that was assumed in the depreciation
14
rates previously approved by the Commission in Decision No. C06-1379 from
15
Docket No. 06S-234EG. The period remaining and the amortization rate are
16
shown in Table 6 below:
33
Table 6
Retirement
Year
Remaining
Years
Amortization
Rate
Cameo Unit1
2017
6
16.67%
Cameo Unit 2
2020
9
11.11%
Cherokee Unit 1
2017
5.5 *
18.18%
Cherokee Unit 2
2019
8
12.50%
Generating Unit
*
Amortization for Cherokee Unit 1 is assumed to begin July 2012, the
month after the unit is retired.
1
For Cameo Units 1 and 2 and Cherokee Units 1 and 2, the change in
2
expense for 2012 is estimated to be an increase of $1,259,922. The change
3
in expense is shown in Table 7 below:
Table 7
Change in Expense
Generating Unit
Life
Component
COR
Component
Total
Cameo Unit1
0
564,789
564,789
Cameo Unit 2
0
153,460
153,460
Cherokee
1
Unit
0
132,561
132,561
Cherokee
2
Unit
0
409,112
409,112
0
1,259,922
1,259,922
Total
4
The amortization rates and the calculation of the expense are shown in Exhibit
5
No. LHP-7.
34
1
Q.
2
3
ARE THERE UNITS WHERE REGULATORY ASSET TREATMENT HAS
BEEN AUTHORIZED BUT IS NOT BEING USED CURRENTLY?
A.
Yes. Arapahoe Units 1 and 2 and Zuni Unit 1 are retired currently and do not
4
have regulatory assets set up for the life component. These assets were fully
5
depreciated on the life component when they retired. Also, the three units
6
have an accumulated depreciation associated with the removal cost recovery
7
that occurred when the units where operating that is still an offset to rate base.
8
Nothing is anticipated to occur with these units at this time.
9
Zuni Unit 2 was expected to be retired in 2012 in the currently approved
10
depreciation rates. However, the expectation is that the unit will be used until
11
2014, so that the proposed depreciation rate reflects a lengthening of the life in
12
the new depreciation study.
13
necessary for this unit.
14
15
Thus, at this time a regulatory asset is not
VI. CALPINE ACQUISITION ADJUSTMENT
Q.
PLEASE PROVIDE SOME BACKGROUND ON THE CHANGES AND
16
POTENTIAL CHANGES RELATING TO THE COMPANY’S ACQUISITION
17
OF THE BSEC AND RMEC GENERATING STATIONS FROM CALPINE.
18
A.
Since the last rate case proceeding in Docket No. 09AL-299E, two generating
19
stations have been added to Public Service’s fleet -- BSEC and RMEC. In
20
Decision No. C10-1196 (Docket No. 10A-327E), the Commission approved the
21
purchase of these facilities from Calpine, in which we estimated the plant in-
22
service to be valued at $739 million.
23
proceeding have resulted in the modification of the total costs of the Calpine
35
Circumstances arising since that
1
assets and may potentially modify the accounting recognition regarding these
2
two generating stations.
3
Q.
4
5
WHAT CIRCUMSTANCES HAVE GIVEN RISE TO A MODIFICATION OF
THE COSTS OF THESE FACILITIES AND WHAT HAS CHANGED?
A.
The final purchase price is now known and the resulting assets that were
6
added equates to $735,208,723 as of December 31, 2010. The difference
7
between the final cost and the estimated cost relates to materials and supplies
8
that were part of the original purchase. The materials and supply inventory in
9
FERC Account 154 was valued at $3,791,277 at purchase.
10
Q.
WHAT CIRCUMSTANCES HAVE GIVEN RISE TO POTENTIAL CHANGES
11
IN THE COMPANY’S ACCOUNTING RECOGNITION OF THESE ASSETS
12
AND WHAT IS THE NATURE OF THOSE CHANGES?
13
A.
In June 2011, the Company made a compliance filing with FERC in Docket
14
No. EC10-71-000 proposing the final accounting entries associated with the
15
acquisition of the Calpine assets.
16
pending, the FERC Staff has informed the Company that, for purposes of
17
accounting recognition, the plant asset should be further split into the original
18
cost from Calpine’s books, less Calpine’s accumulated depreciation, with the
19
balance being recognized in FERC Account 114, Acquisition Adjustment.
20
Exhibit No. LHP-8, Calculation of Acquisition Adjustment for the Assets
21
Purchased from Calpine (for Accounting Purposes Only), has been included in
22
order to demonstrate the accounting that may result from the Company’s
36
Although that proceeding is currently
1
proceeding before the FERC in Docket No. EC10-71-000. The summary of
2
these numbers at December 31, 2010 is shown in Table 8 below:
Table 8
Purchase Price
$ 739,000,000
Materials and Supplies
Total Plant Asset
735,208,723
Plant In-service
613,966,057
Plant Acquisition Adjustment
225,557,122
Accumulated Depreciation
(104,314,456)
Total Net Plant
3
Q.
4
5
3,791,277
$ 735,208,723
HOW DOES RECOGNITION OF SUCH AN ACQUISITION ADJUSTMENT
COME INTO PLAY IN THIS PROCEEDING?
A.
There is no impact on the rate base as a result of these refinements to the
6
balance sheet. Public Service was allowed recovery of the $739 million in
7
Decision No. C10-1196 in Docket No. 10A-327E. Subsequent to that filing,
8
the total cost was split between plant in-service and materials and supplies,
9
both of which are part of rate base. To preserve the allowed amount in rate
10
base for plant, Public Service has included FERC Account 114, Acquisition
11
Adjustment, as a placeholder in the Plant In-service rate base.
12
accumulated amortization on this acquisition adjustment would be recognized
13
in FERC Account 115, Accumulated Provision for Amortization of Electric
14
Plant Acquisition Adjustment.
The
The accumulated amortization would be an
37
1
offset to rate base. The resulting asset added to rate base for plant will still
2
equate to $735,208,723. There also will be corresponding changes to the
3
depreciation rates and expense for BSEC and RMEC in this case.
4
Q.
PLEASE SUMMARIZE THE DEPRECIATION EXPENSE THE COMPANY IS
5
PROPOSING TO INCLUDE IN THE COST OF SERVICE IN THIS RATE
6
CASE FOR BSEC AND RMEC, AS COMPARED TO WHAT WAS
7
REPRESENTED IN DOCKET NO. 10A-327E.
8
9
A.
The annual depreciation expense related to the acquired Calpine assets, as
shown in an exhibit to my testimony in Docket No. 10A-327E, was
10
$19,444,050.
In this case, the depreciation expense is calculated to be
11
$19,437,375, a reduction of $6,675. Table 9 below summarizes these two
12
depreciation calculations:
13
Table 9
Docket No.
10A-327E
Production Plant
Current
Case
Difference
$ 18,554,400
$ 13,206,008
$ (5,348,392)
889,650
697,553
(192,097)
Production
0
5,253,610
5,253,610
Transmission
0
280,203
280,203
0
0
0
$ 19,444,050
$ 19,437,375
Transmission Plant
Acquisition Adjustment
Inventory
Total
38
$
(6,675)
1
Q.
PLEASE DESCRIBE THE CHANGES TO DEPRECIATION EXPENSE
2
PROPOSED IN THIS RATE CASE FOR BSEC AND RMEC THAT WOULD
3
RESULT
4
ACQUISITION ADJUSTMENT.
5
A.
FROM
THE
COMPANY’S
RECOGNITION
OF
SUCH
AN
If the Company is required to recognize an acquisition adjustment as indicated
6
by the FERC Staff, there will be several changes to depreciation and
7
amortization for these assets that were not addressed by Mr. Watson in the
8
Depreciation Study. First, the acquisition adjustment would be amortized over
9
the remaining period of the asset to which it relates Public Service would
10
recommend using 40 years (or an amortization rate of 2.50 percent) for the
11
other production portion of the acquisition adjustment, and 55 years (or an
12
amortization rate of 1.818 percent) for the transmission portion of the
13
acquisition adjustment, both as of January 1, 2011. Second, Mr. Watson, in
14
his Exhibit No. DAW-1, Appendix A, determined an average remaining life
15
depreciation rate for BSEC and RMEC assuming no acquisition adjustment. I
16
recalculated the average remaining life rate using the revised plant values if an
17
acquisition adjustment were to be recognized. A comparison of the potential
18
revised depreciation rates to the depreciation rates proposed in the
19
Company’s direct case, as reflected in the Depreciation Study presented in Mr.
20
Watson’s Exhibit No. DAW-1 (Appendix B), is shown in Table 10 below:
39
Table 10
Production Depreciation Rates
Proposed
(per Exhibit No. LHP-4a)
Conditional
(per Exhibit No. LHP-8)
Blue Spruce
2.5985%
2.6887%
Rocky Mountain
2.6181%
2.8491%
1
Mr. Watson’s exhibit shows depreciation expense for the Calpine
2
production facilities that equates to $17,839,209 without factoring the change
3
in accounting to recognize the acquisition adjustment.
4
production facility depreciation expense of $13,206,008 (a reduction of
5
$4,633,201), plus an increase in the acquisition adjustment amortization of
6
$5,253,610. This results in a total production expense of $18,459,618, or
7
$620,409 more than Mr. Watson calculated.
8
expense for the transmission assets moved to the acquisition adjustment
9
would decrease by $310,995, with amortization expense increasing by
10
$280,203, or a net decrease in expense of $30,792. The overall expense
11
would increase by approximately $589,617 ($620,409 less $30,792).
12
Q.
13
14
My exhibit shows
In addition, the depreciation
HOW WOULD YOU SUMMARIZE THE CHANGES PRESENTED IN THIS
SECTION?
A.
Simply put, the changes discussed above are mostly to lay out potential
15
accounting for the investment to different accounts than were presented
16
originally, but the overall impact to the case for this different presentation is
17
very small. Public Service has not recognized an acquisition adjustment for
18
these assets, as the FERC has not yet directed us to do so. The presentation
40
1
of numbers here was merely to demonstrate how the acquisition adjustment
2
would look should we have to follow through on this accounting during the
3
course of this rate case. Should the FERC require this change in accounting
4
presentation, the difference in presentation should not be of concern in the
5
calculation of the revenue requirement, as the difference is rather small.
6
VII. BONUS TAX DEPRECIATION & DEFERRED INCOME TAXES
7
Q.
WHAT IS THE BONUS TAX DEPRECIATION?
8
A.
For income tax determinations, Public Service uses accelerated methods to
9
calculate its tax depreciation as defined by current tax laws and regulations.
10
The most current accelerated method is the Modified Accelerated Cost
11
Recovery System (“MACRS”). At various times, Congress has enacted laws
12
to spur investment that have allowed a further acceleration than the MACRS
13
method. Various laws were enacted that allowed 30 percent, 50 percent, and
14
now even 100 percent of the tax asset to be depreciated in the first year, with
15
the remaining investment following the MACRS method (at least for the 30
16
percent and 50 percent accelerations). This additional acceleration over the
17
MACRS method is referred to as bonus depreciation. The individual federal
18
tax laws, when enacted, contained construction timeframes that established
19
when construction had to begin and end for an entity to qualify for the bonus
20
depreciation.
21
Q.
ARE THERE NEW TAX LAWS THAT AFFECT THIS CASE?
22
A.
Yes. Since the 2008 historic test year used in Public Service’s last electric
23
rate case in Docket No. 09AL-299E, there have been three new tax laws
41
1
allowing for bonus depreciation. Each law contains a provision allowing for
2
bonus depreciation on assets acquired after December 31, 2008. The three
3
laws are as follows.
4
The American Recovery and Reinvestment Act of 2009 (“ARRA”) was
5
signed into law on February 17, 2009. Bonus depreciation under the ARRA
6
allows for the tax expensing of 50 percent of the cost of an asset in the year it
7
is placed in service between January 1, 2009 and December 31, 2009.
8
The Small Business Jobs Act of 2010 (“SBJA”) was signed into law on
9
September 27, 2010. Bonus depreciation under the SBJA allows for the tax
10
expensing of 50 percent of the cost of an asset if it is placed in service
11
between January 1, 2010 and December 31, 2010.
12
The Tax Relief, Unemployment Insurance Reauthorization, and Job
13
Creation Act of 2010 (“2010 Tax Relief Act”) was signed into law on December
14
17, 2010. Bonus depreciation under this law begins with the tax expensing of
15
100 percent of the cost of an asset if it is placed in service between
16
September 9, 2010 and December 31, 2011, with some carry over into 2012
17
for certain assets where the construction began within the timeframe allowed
18
and was placed into service before January 1, 2013. Bonus depreciation for
19
tax expensing 50 percent of the cost of an asset is allowed for assets placed in
20
service between January 1, 2012 and December 31, 2012, with the same
21
carry over into 2013 for large constructed assets beginning within the
22
timeframe and placed into service by December 31, 2013.
42
1
Q.
2
3
PLEASE DESCRIBE HOW THE THREE LAWS WERE APPLIED TO THE
DATA IN THIS CASE.
A.
For all three laws, the depreciable base for tax purposes is reduced by the
4
amount of the bonus deduction and, if there is a balance, it is depreciated
5
based on the existing MACRS depreciation rate tables starting with the current
6
year. Thus, an asset will get bonus depreciation and the first year of MACRS
7
tax depreciation (if the bonus depreciation is less than 100 percent) the year
8
the asset is placed in-service.
9
The bonus depreciation for 2009 through 2012 allowed by the ARRA,
10
SBJA, and the 2010 Tax Relief Act has been included in the base data. For
11
an item to qualify for bonus depreciation under these three laws, it must meet
12
four requirements.
13
1.
It must be property that has a MACRS recovery period of less
14
than or equal to 20 years, computer software subject to 36-
15
month amortization or qualified leasehold improvements.
16
2.
17
18
The original use of the property must be after December 31,
2008.
3.
The property must be acquired after December 31, 2007 or, if
19
self-constructed, the construction must begin in 2008. Under all
20
three laws, this means that a binding contract to purchase
21
property cannot be in place before January 1, 2008. For self-
22
constructed property, significant physical work is presumed to
23
have started if more than 10 percent of the total property cost of
24
incurred construction begins after January 1, 2008.
25
26
4.
Finally, the property must be placed in service before
December 31, 2012 unless it qualifies as having a lengthy
43
1
construction period. For these assets only, the costs incurred in
2
the year ending December 31, 2012 will be eligible for the bonus
3
depreciation in the year the asset is placed in service, if that in-
4
service date is on or before December 31, 2013. This exception
5
applies to self-constructed assets with a MACRS recovery period
6
of 10 years or longer. Under the first three tax laws mentioned,
7
the bonus depreciation is 50 percent of the tax basis of the asset
8
except for assets placed in-service between September 9, 2010
9
and December 31, 2011, with these assets receiving 100 percent
10
11
bonus depreciation as a result of the fourth tax law.
Q.
12
13
PLEASE DESCRIBE THE EXPECTED IMPACT OF THESE THREE NEW
TAX LAWS ON PLANT DEFERRED TAXES.
A.
For all three laws, the depreciable base for tax purposes is reduced by the
14
amount of the bonus deduction. The effects of these three laws have been
15
calculated and incorporated into the data used in developing the revenue
16
requirements in this case. Basically, the allowance of bonus depreciation for
17
2009 and 2010 has a carryover effect in 2011 and 2012 by increasing the
18
ADIT balance. An increase in this balance causes a decrease in plant-related
19
rate base. The 2010 Tax Relief Act is the only law that generates a bonus
20
depreciation deduction in 2012. Exhibit No. LHP-9 reflects the expected 2012
21
cumulative effect of the three tax laws on deferred tax balances for the FTY.
22
Unlike for the 2011 test year used for the Gas Department in Public Service’s
23
recent gas rate case in Docket No. 10AL-963G, the Company’s Electric
24
Department is not projected to realize a net operating loss (“NOL”) for income
25
tax purposes in 2012 (the FTY in this case), as a result of the significant
44
1
amount of bonus tax depreciation extended under the earlier two tax laws and
2
then the 2010 Tax Relief Act.
3
Q.
HOW DOES A NOL RESULT FROM BONUS DEPRECIATION?
4
A.
A NOL results when the Company or, in this case, the Company’s Electric
5
Department, has more income tax deductions, including accelerated and
6
bonus depreciation, than taxable income for the tax year.
7
Q.
8
9
IS IT POSSIBLE THAT THE ELECTRIC DEPARTMENT COULD FIND
ITSELF IN A NOL SITUATION IN 2012?
A.
Yes, but it is unlikely unless Congress enacts a new law to extend the 100
10
percent bonus depreciation to include plant placed in service in 2012. Under
11
current laws and with the assumptions of recovery in this case, the Company
12
does not project that its Electric Department will be in a NOL situation.
13
Q.
14
15
WHAT WOULD BE THE EFFECT IF THE ELECTRIC DEPARTMENT WERE
TO INCUR A NOL FOR INCOME TAX PURPOSES IN 2012?
A.
In the case of a NOL, Public Service would not realize current tax savings for
16
the portion of the bonus depreciation deduction that exceeded the taxable
17
income it would have recognized without the bonus depreciation deduction.
18
The excess deduction results in a NOL that can be carried forward to offset
19
future taxable income. If the Company found itself in a NOL position, we
20
would need to make similar adjustments to the test year as those discussed in
21
the gas rate case to maintain tax normalization.
45
1
Q.
HOW IS A NOL CARRYFORWARD ACCOUNTED FOR?
2
A.
The NOL carryforward amount is recorded on the balance sheet as a deferred
3
tax asset in FERC Account 190, Accumulated Deferred Income Taxes. For
4
ratemaking purposes, this deferred tax asset would be netted against FERC
5
Account 282, Accumulated Deferred Income Taxes – Other Property in the
6
cost of service to reflect the reduced level of tax savings actually generated in
7
the test year by the bonus depreciation.
8
reduction to rate base. The deferred tax asset is calculated by multiplying the
9
jurisdictional NOL times the current composite tax rate.
The effect is to offset the ADIT
10
Q.
DOES THIS CONCLUDE YOUR TESTIMONY?
11
A.
Yes.
46
Attachment A
Statement of Qualifications
Lisa H. Perkett
PROFESSIONAL EXPERIENCE
DIRECTOR CAPITAL ASSET ACCOUNTING
1994-Present
•
Establish corporate capitalization policies and include the development,
enhancement, and maintenance of the Corporate Continuing Property Record
process for all of the plant assets of the Corporation.
•
Manage capital investment cost recovery process, which includes the
development of detailed actuarial analysis, regulatory filings with the various
state and federal rate regulatory commissions, and expert testimony to
support recovery levels in rate proceedings.
•
Direct nuclear plant decommissioning funding process which includes the
development of detailed engineering cost studies combined with a complete
financial and economic analysis to develop detailed regulatory filings which
establish the rate payer funding levels necessary to accumulate to the total
future decommissioning cost requirement.
•
Maximize corporate income tax deductions from the computation and support
of accelerated income tax depreciation expenses and provide for the
computation and support of deferred income taxes, which normalize the
impact of these accelerated deductions for ratemaking and book accounting
purposes.
•
Maintain the plant asset related ratemaking forecast process, which supports
the Company’s rate filings for all retail and wholesale jurisdictions. This
process provides the information which supports the vast majority of rate
base (plant investment net of depreciation reserve and deferred taxes) as well
as all capital investment related cost of service information (book
depreciation, tax depreciation deductions, deferred taxes and deferred
investment tax credits).
•
Oversee capital asset reporting and information process necessary to
disseminate capital asset information as required by various regulatory
authorities (FERC, SEC, state commissions) as well as meeting all internal
information requirements necessary to sustain efficient and effective business
operations.
Lisa H. Perkett
MANAGER CAPITAL RECOVERY
1990-1994
•
Coordinate preparation and filing of remaining life study for production
facilities, average service life study, and general amortization study.
Coordinate Minnesota Public Utilities Commission review process within
Company including data requests.
•
Review and assist in the calculation of tax depreciation and deferred income
taxes for the IRS filing and year end close.
•
Work with Rate Department and jurisdictional personnel within NSP to provide
capital recovery information scenarios, answer data requests, review
necessary rate schedules, and provide expert testimony.
•
Oversee the gathering of information from plants and work with outside
consultant to determine cost estimate, review escalation analysis, work with
finance for fund earnings analysis, and compile all of above into filing with
Minnesota Public Utilities Commission.
PRINCIPAL CAPITAL RECOVERY ANALYST
1987-1990
SENIOR DEPRECIATION ANALYST
1985-1987
DEPRECIATION ANALYST
1982-1985
ASSOCIATE DEPRECIATION ANALYST
1981-1982
ASSISTANT OPERATIONS ANALYST
1980-1981
EDUCATION/PROFESSIONAL LICENSES
University of Minnesota - B.S. Degree, Major-Business
Certificate in Management Information Systems
Certified Management Accountant
BUSINESS/INDUSTRY ACTIVITIES:
Society of Depreciation Professionals
American Gas Association Accounting Services Committee
Edison Electric Institute Property Accounting and Valuation Committee
Institute of Certified Management Accountants