National Grid Niagara Mohawk Power Corporation INVESTIGATION AS TO THE PROPRIETY OF PROPOSED ELECTRIC TARIFF CHANGES Testimony and Exhibits of: Revenue Requirements Panel Exhibits __ (RRP-1), (RRP-3), (RRP-4) and (RRP-5) Book 11 January 29, 2010 Submitted to: New York Public Service Commission Docket No. 10-E-____ Submitted by:
Testim
ony of
Revenue R
equirements Panel
Before the Public Service Commission
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID
Direct Testimony
of
The Revenue Requirements Panel
Dated: January 29, 2010
1
Testimony of the Revenue Requirements Panel
Page 1 of 110
Q. Please introduce the members of the Revenue Requirements Panel. 1
A. The Panel consists of Howard Gorman, James M. Molloy and Peter T. 2
Zschokke. 3
4
Q. Mr. Gorman, by whom are you employed and in what capacity? 5
A. I am employed by Black & Veatch Corporation as a Principal Consultant 6
in the Rate & Regulatory Advisory Group of its Enterprise Management 7
Solutions (“EMS”) Division. 8
9
Q. Mr. Gorman, please summarize your educational background and 10
professional experience. 11
A. My educational background and professional experience are outlined in 12
my curriculum vitae provided as Exhibit __ (RRP-11). 13
14
Q. Have you previously testified before this commission? 15
A. Yes, a brief description of my testimony experience is included as Exhibit 16
__ (RRP-11). 17
18
Q. Mr. Molloy, by whom are you employed and in what capacity? 19
A. I am the Director of Regulatory Accounting for National Grid USA 20
Service Company Inc. (“National Grid Service Company”). 21
2
Testimony of The Revenue Requirements Panel
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Q. Please briefly describe your educational background. 1
A. In 1992, I graduated from Catholic University with a Bachelor of Arts 2
degree in Accounting. In 1994, I receive a Masters in Business 3
Administration with a concentration in Finance from the William E. 4
Simon Graduate School of Business Administration at the University of 5
Rochester. 6
7
Q. What is your professional background? 8
A. In 1995 I was hired by the New England Power Service Company as an 9
Assistant Rate Analyst. In 1996 I was promoted to the position of Rate 10
Analyst. In 1998 I was promoted to Senior Rate Analyst. In those 11
positions, I was responsible for rate design analysis for various New 12
England Electric System (“NEES”) companies. Specifically, I conducted 13
allocated distribution cost of service studies and supported others in the 14
development of cost allocation and rate design studies. In addition, I 15
performed rate and cost allocation analytical work in the unbundling of 16
rates for the NEES retail companies in preparation for industry 17
restructuring. Further, I developed and implemented the rate plan for the 18
merger of Narragansett Electric, Blackstone Electric and Newport Electric. 19
In 2001 I was promoted to Principal Regulatory Analyst. In this position, 20
I was responsible for the development and implementation of the Niagara 21
3
Testimony of The Revenue Requirements Panel
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Mohawk Power Corporation d/b/a “National Grid” (“Niagara Mohawk” or 1
the “Company”) and National Grid plc (“National Grid”) merger rate plan. 2
In 2004 I was promoted to Manager of New York accounting. In this 3
position, I was responsible for the books and records of Niagara Mohawk 4
as well as the regulatory filings associated with the acquisition of 5
KeySpan Corporation. In 2008 I was promoted to Director of Regulatory 6
Compliance. 7
8
Q. Mr. Molloy, have you previously testified before a regulatory 9
commission? 10
A. Yes. I have testified numerous times before the New York State Public 11
Service Commission (“Commission”), the Massachusetts Department of 12
Public Utilities and the Rhode Island Public Utilities Commission. 13
14
Q. Mr. Zschokke, by whom are you employed and in what capacity? 15
A. I am employed by the National Grid Service Company in Waltham, 16
Massachusetts as a Director of Special Projects in the Regulatory Affairs 17
Department. 18
19
Q. Please briefly describe your educational background. 20
4
Testimony of The Revenue Requirements Panel
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A. I received a Bachelors of Arts Degree in Economics from Boston 1
University in 1979. I received a Masters of Arts degree in Economics 2
from Boston University in 1981. 3
4
Q. What is your professional background? 5
A. Since 1981 I have served as an expert witness on various rate and 6
regulatory matters. From April 1981 through March 1986 I performed 7
rate analyses for Central Vermont Public Service and Boston Edison 8
Company. From April 1986 onwards I conducted regulatory analysis, 9
supported testimony and testified in numerous regulatory proceedings for 10
National Grid predecessor companies in New England. I have testified 11
regarding rate designs, allocated cost of service, interruptible credits, real 12
time pricing rates, reconciling cost trackers and related subjects in front of 13
the regulatory commissions in New Hampshire, Rhode Island and 14
Massachusetts. In addition, from 1998 to 2000 I lead the function that 15
resolved large customer and municipality issues and conducted the energy 16
efficiency programs in Rhode Island. Lastly, from August 2004 to July 17
2006, I was on assignment to National Grid’s Group Strategy Department 18
in the United Kingdom. Since my return in July 2006 I have been 19
assisting the Electric Distribution Operations and Transmission groups 20
5
Testimony of The Revenue Requirements Panel
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with the filings regarding the Company’s Asset Condition Report and 1
Capital Investment Plan along with other activities in regulation. 2
3
Q. What is the purpose of the Panel’s testimony? 4
A. First, the Panel supports the Company’s request to increase its Delivery 5
Revenue and presents Niagara Mohawk’s historical and forecast data for 6
various periods in a manner consistent with the Commission’s regulations 7
and policies. Second, the Panel’s testimony supports the Company’s 8
forecast of the Operation and Maintenance (“O&M”) Expenses and 9
amortizations of regulatory assets used to compute the revenue 10
requirement for electric rates in the three proposed Rate Years, which are 11
the twelve months ending December 31, 2011, 2012 and 2013, 12
respectively. Third, the testimony supports the continued use of trackers 13
for regulatory assets that the Commission has previously approved and 14
new cost trackers. 15
16
Q. Does the Panel sponsor any exhibits? 17
A. Yes. The Panel sponsors the following Exhibits, which were prepared 18
under our supervision and direction and which, in all cases, refer to 19
Niagara Mohawk: 20
6
Testimony of The Revenue Requirements Panel
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Exhibit __ (RRP-1) Statement of Electric Operating Income, by 1 Component, for the Year Ended September 30, 2 2009 and Rate Years Ending December 31, 2011, 3 December 31, 2012 and December 31, 2013; 4
5 Exhibit __ (RRP-2) Operating and Maintenance Expenses by Expense 6
Type for the Year Ended September 30, 2009 and 7 Rate Years Ending December 31, 2011, December 8 31, 2012 and December 31, 2013; 9
10 Exhibit __ (RRP-3) Electric Depreciation Expense for the Year Ended 11
September 30, 2009 and Rate Years Ending 12 December 31, 2011, December 31, 2012 and 13 December 31, 2013; 14
15 Exhibit __ (RRP-4) Taxes Other than Income Taxes for the Year Ended 16
September 30, 2009 and Rate Years Ending 17 December 31, 2011, December 31, 2012 and 18 December 31, 2013; 19
20 Exhibit __ (RRP-5) Federal and State Income Taxes for the Year Ended 21
September 30, 2009 and Rate Years Ending 22 December 31, 2011, December 31, 2012 and 23 December 31, 2013; 24
25 Exhibit __ (RRP-6) Electric Rate Base for the Year Ended September 26
30, 2009 and Rate Years Ending December 31, 27 2011, December 31, 2012 and December 31, 2013; 28
29 Exhibit __ (RRP-7) Table of Inflation Factors; 30 31 Exhibit __ (RRP-8) Deferral Account Exhibit; 32 33 Exhibit __ (RRP-9) Various Historic Financial Exhibits for the Calendar 34
Years 2004 Through 2008; 35 36 Exhibit __ (RRP-10) Workpaper Data Supporting Certain Exhibits; and 37 38 Exhibit __ (RRP-11) Resume of Howard Gorman 39 40
7
Testimony of The Revenue Requirements Panel
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Q. Please describe the historical test year in this proceeding. 1
A. The historical test year in this proceeding is the twelve months ended 2
September 30, 2009 (“Historical Test Year” or “Test Year”). The 3
Historical Test Year data consists of the costs recorded on the books of 4
Niagara Mohawk. These include: (1) costs from within the Company, (2) 5
costs charged to Niagara Mohawk from National Grid Service Company 6
(3) costs charged to Niagara Mohawk from the KeySpan Service 7
Companies, and (4) costs charged to Niagara Mohawk from other 8
affiliated companies. 9
10
Q. What Historical Test Year and Rate Year information is the 11
Company presenting? 12
A. The Company is presenting operating results for the Historical Test Year 13
and forecast data for the Rate Years ending December 31, 2011 (“Rate 14
Year” or “Rate Year 1”), December 31, 2012 (“Rate Year 2”) and 15
December 31, 2013 (“Rate Year 3”) (collectively, the three years are 16
referred to as “Rate Years”). The Panel also refers to the Rate Years as the 17
“Rate Plan Period” or “Rate Plan.” The forecast data provides the basis for 18
computing the revenue increases requested in this proceeding. The 19
information presented in this filing is consistent with that required under 20
8
Testimony of The Revenue Requirements Panel
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the Commission’s “Statement of Policy On Test Periods In Major Rate 1
Proceedings.” 2
3
Q. What increase in base rate electric revenues is required in Rate Year 4
1 to achieve an 11.1 percent rate of return on equity, as recommended 5
by Company Witness Dr. Roger Morin, applied to the Company’s 6
actual capital structure? 7
A. The Company requires increased base rate electric transmission and 8
distribution delivery revenues of $391 million. However, the Company 9
proposes to offset this increase by reshaping recovery of certain stranded 10
costs that would otherwise be recovered in Rate Year 1 to achieve a zero 11
net increase in base electric revenues as shown in the table below. 12
Revenue Requirement Change 13 14 Due to CTC Increase/ 15 Deficiency Amortization Change (Decrease) 16 17
T&D $337 M - $337 M 18 CTC $ 54 M ($391 M) ($337 M) 19 Total $391 M ($391 M) - 20
21
Q. Please generally describe the Company’s proposal to increase electric 22
transmission and distribution base delivery revenues. 23
A. As explained by Company Witness Thomas B. King, as an alternative to a 24
traditional one-year rate case, Niagara Mohawk is proposing a three-year 25
9
Testimony of The Revenue Requirements Panel
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Rate Plan. The Rate Plan is designed to continue rate stability for Niagara 1
Mohawk electric customers and to update base transmission and 2
distribution delivery rates to reflect the Company’s cost of providing 3
service. The Company’s proposal is designed to produce, in the 4
aggregate, no net increase in electric delivery rates over the course of the 5
Rate Plan Period. The Company’s proposal achieves this result by 6
reshaping the current amortization schedule of certain fixed stranded costs. 7
Pursuant to the Merger Rate Plan approved by the Commission in Case 8
01-M-0075, the Company is authorized to recover certain deferred Fixed 9
Competitive Transition Charges (“CTC”) associated with the divestiture of 10
generation (referred to as “stranded” or “fixed” costs).1 As explained later 11
in our testimony, the balance of these stranded costs is approximately 12
$557 million. But for this filing, Niagara Mohawk would recover these 13
stranded costs by December 31, 2011.2 In consideration of current 14
economic conditions, Niagara Mohawk proposes to extend the 15
amortization of these deferred costs to achieve no net increase in base rate 16
electric transmission and distribution delivery revenues. At the expiration 17
of the Rate Plan Period, approximately $63 million of stranded costs will 18
remain. The Company’s proposal for addressing this balance is discussed 19 1 Case No. 01-M-0075, Niagara Mohawk Power Corporation – Opinion and Order Authorizing Merger and Adopting Rate Plan, Opinion No. 01-6 (Issued and Effective December 3, 2001) (“Merger Joint Proposal” or “Merger Rate Plan”). 2 Merger Rate Plan at Section 1.2.2.3.
10
Testimony of The Revenue Requirements Panel
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later in our testimony. The Company submits this proposal conditioned 1
upon the understanding that it will not be precluded from submitting a 2
proposal in a separate proceeding to unbundle transmission and 3
distribution delivery rates during the Rate Plan Period, and that any such 4
unbundling proposal will not terminate this Rate Plan, nor will it affect the 5
stay-out premium associated with the rate of return on equity. Otherwise, 6
if the Company files to reset base rates prior to the expiration of the 7
approved Rate Plan Period in this proceeding, the Company would refund 8
to customers any approved stay-out premium. The Company would also 9
retain the right to propose revenue-neutral adjustments to its base electric 10
delivery rates during the Rate Plan. 11
12
Should the Commission approve a reduced revenue requirement for the 13
Rate Plan Period, the Company proposes to carry forward for recovery 14
during the Rate Years an offsetting balance of stranded costs remaining at 15
the expiration of Rate Year 3. In such event, if the reduction exceeds the 16
remaining stranded costs, the Company would propose to fully amortize 17
those costs during the Rate Plan Period and proportionately reduce base 18
rates in the Rate Years. Should the Commission approve a one year rate 19
plan in this proceeding, the Company would still be willing to reshape the 20
stranded costs to the extent necessary to mitigate delivery rate increases. 21
11
Testimony of The Revenue Requirements Panel
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To accommodate the reshaping of stranded costs beyond December 31, 1
2011, under either the Company’s proposed three year rate plan or a one 2
year alternative plan, the Company requests that the Commission waive 3
the Merger Rate Plan requirement that the stranded costs be recovered by 4
December 31, 2011 and permit the Company to continue to defer such 5
costs until such time as they are fully recovered.3 6
7
Q. Pursuant to the Commission Order in Case 09-M-0435, does the 8
Historical Test Year reflect savings from austerity measures? 9
A. Yes. In September 2008 Niagara Mohawk reviewed its budgets and 10
spending and implemented a number of austerity measures that could be 11
undertaken in the short term. Specifically, salaries for top executives were 12
frozen and the overall increase in the management payroll budget was 13
limited to 1.5 percent with salary increases generally limited to 14
promotions or employees whose existing pay levels were below market. 15
This austerity measure is estimated to have reduced Niagara Mohawk’s 16
costs for Fiscal Year 2010 by approximately $2 million. The Company 17
also deferred certain capital projects that did not compromise safety or 18
reliability. This austerity measure is estimated to have reduced capital 19
expenditures for Fiscal Year 2010 by approximately $78 million. As a 20
3 Merger Rate Plan at Sections 1.2.2.3 and 1.2.6.
12
Testimony of The Revenue Requirements Panel
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result of this reduction, operation and maintenance expense associated 1
with capital investments was reduced by approximately $6 million. The 2
Company further chose to defer certain electric line repair work 3
categorized as priority level 3 maintenance work in the short term. This is 4
estimated to have reduced Niagara Mohawk’s costs for Fiscal Year 2010 5
by approximately $4.6 million. In total these measures are estimated to 6
have reduced Niagara Mohawk’s revenue requirement by approximately 7
$12.6 million. These are savings that are embedded in the Historical Test 8
Year. In addition to the austerity measures already implemented, the 9
Company proposes an additional austerity measure in this rate proceeding. 10
As discussed in Mr. King’s and Mr. Zschokke’s stand alone testimony, the 11
Company is not proposing to recover the costs associated with 12
implementing new initiatives associated with the Management Audit 13
recommendations for the duration of the proposed Rate Plan Period. The 14
Company has also (i) reduced its research and development budget to 15
minimize discretionary spending, (ii) reduced operation and maintenance 16
expense by eliminating accrued vacation from its forecast of labor expense 17
and (iii) reduced its proposed level of transmission and distribution capital 18
investment and associated operating expenses from its January 2009 19
Capital Investment Plan budget and from the level that was discussed with 20
the Department of Public Service Staff in December. The Company is 21
13
Testimony of The Revenue Requirements Panel
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further proposing to reshape the amortization of stranded costs over four 1
years as opposed to recovering these costs from customers in one year to 2
mitigate the impact of the proposed increase in base rate electric 3
transmission and distribution delivery rates. 4
5
Operating Income By Component for the Historical Test Year and 6
Rate Years 7
Q. Please describe Exhibit __ (RRP -1). 8
A. Exhibit __ (RRP-1) consists of a Summary sheet showing the calculation 9
of the Company’s electric operating income for the Historical Test Year 10
and for the Rate Years at present rates. This Exhibit presents the 11
computation of the base electric revenue in this proceeding, comprising: 12
• Revenues and Gross Margin for the Rate Years at present rates 13
supported by Exhibit __ (RDCM-4). 14
• Operation and Maintenance Expenses supported by Exhibit __ 15
(RRP-2). 16
• Amortization of Regulatory Deferrals supported by Exhibit __ 17
(RRP-6). 18
• Depreciation, Amortization & Loss on Disposition supported by 19
Exhibit___(RRP-3). 20
• Taxes Other Than Income Taxes supported by Exhibit___ (RRP-4). 21
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Testimony of The Revenue Requirements Panel
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• Total Income Taxes supported by Exhibit ___ (RRP-5). 1
• Rate Base supported by Exhibit___ (RRP-6). 2
3
Based on the operating income calculated for the Rate Year, we 4
determined the amount of base electric revenue increase, including federal 5
income taxes, required to earn an 11.1 percent rate of return on equity for 6
the Company’s electric operations based on its actual capital structure 7
which includes 50% common equity. In the absence of the rate relief 8
proposed in this proceeding, the Company projects that it would earn a 9
rate of return of 2.32 percent in Rate Year 1, which equates to an ROE of -10
0.32 percent. 11
12
Q. What is the basis for the Rate Year allocations between expense and 13
capital, and between electric operations and other operations? 14
A. Except as otherwise indicated, Rate Year costs are allocated according to 15
the Historical Test Year allocation for each Expense Type. Certain 16
Expense Types include allocations to expense, construction and other 17
charge categories. The general expense allocations of 83 percent to 18
electric operations and 17 percent to gas operations used in the Historical 19
Test Year were established in the Merger Rate Plan. 20
21
15
Testimony of The Revenue Requirements Panel
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Operation and Maintenance Expenses 1
Q. Please explain the methodology for developing the Rate Year forecasts 2
of O&M Expenses. 3
A. In general, the Company used O&M Expense in the Historical Test Year 4
and made normalizing adjustments to reflect operating conditions 5
expected in Rate Year 1. The inflation factors set forth in Exhibit __ 6
(RRP-7) were applied to the majority of Expense Types. Certain Rate 7
Year Expenses were developed using a more comprehensive methodology 8
than simply adjusting for inflation. For example, Labor Expense was 9
developed by annualizing the monthly and weekly employees on payroll 10
as of September 30, 2009 and applying contractual and other wage 11
increases to forecast the Rate Years. 12
13
Q. What assumptions did you make regarding non-labor inflation? 14
A. Except where specifically identified, the Company applied the non-labor 15
inflation factor of 3.2146 percent to all non-labor expense items in the 16
Historical Test Year to forecast Rate Year 1 for the period September 30, 17
2009 to December 31, 2011. The Company applied the non-labor 18
inflation factor of 1.8 percent to forecast Rate Year 2 and 1.9 percent to 19
forecast Rate Year 3. These factors represent the forecast change in the 20
16
Testimony of The Revenue Requirements Panel
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Gross Domestic Product (“GDP”) price deflator index, as provided in 1
Exhibit __ (RRP-7). 2
3
Q. Please explain Exhibit __ (RRP-2). 4
A. As described above, Exhibit __ (RRP-2) includes 45 Schedules and a 5
Summary. It shows total Departmental Electric O&M Expense for the 6
Historical Test Year of $834.4 million and a forecast for Rate Year 1 of 7
$1,112.6 million. It also shows forecasts of total Departmental Electric 8
O&M Expense for Rate Years 2 and 3 of $1,114.5 million. 9
10
Each Schedule pertains to an Expense Type and contains a minimum of 4 11
sheets of detail. Sheet 1 of each Schedule consists of three sections that 12
show for each expense type: (i) the Historical Test Year actual electric 13
and gas expense per books by Provider Company; (ii) the adjustments to 14
normalize the Historical Test Year electric and gas expense by Provider 15
Company; and (iii) the adjusted Historical Test Year electric and gas 16
expense by Provider Company. A Provider Company (also referred to as 17
an Originating Company) is any company that charged Niagara Mohawk 18
for services. Sheet 2 of each Schedule also consists of three sections that 19
show for each expense type: (i) the adjusted Historical Test Year 20
information from Sheet 1; (ii) the adjustments made to the electric and gas 21
17
Testimony of The Revenue Requirements Panel
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expenses in the Historical Test Year to reflect conditions in the Rate Year 1
(e.g. inflation) by Provider Company; and (iii) the adjusted Rate Year 2
electric and gas expenses by Provider Company. Sheet 3 consists of the 3
adjusted Rate Year information from Sheet 2; the adjustments made to the 4
electric and gas expenses in the Rate Year to reflect conditions in Rate 5
Years 2 and 3 (e.g. inflation) by Provider Company; and the adjusted Rate 6
Years 2 and 3 electric and gas expenses by Provider Company. Sheet 4 7
consists of an explanation of the adjustments presented on Sheets 1, 2 and 8
Sheet 3. Certain Schedules contain additional information as needed. 9
10
Q. Please explain the derivation of the Provider Company O&M Expense 11
on Sheets 1, 2 and 3 of each Schedule of Exhibit __ (RRP-2). 12
A. As explained by Company Witness Andrew Sloey, National Grid plc 13
holds multiple companies that provide various services directly and 14
indirectly to Niagara Mohawk and its affiliates. The charges associated 15
with those services are either directly charged to individual affiliate 16
companies, or aggregated into bill pools and allocated among the 17
companies that receive the services. For example, when the National Grid 18
Service Company performs a service for the benefit of a single company, 19
that company is directly charged for that service. Sheets 1 and 2 detail 20
charges to Niagara Mohawk from the Provider Companies, including the 21
18
Testimony of The Revenue Requirements Panel
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National Grid Service Company, and from all other affiliated companies 1
providing the Company with services. Charges originating within Niagara 2
Mohawk, for services performed by Niagara Mohawk for affiliates, are 3
charged directly to the affiliate. 4
5
Q. Please explain the expense specific Schedules in Exhibit __ (RRP-2). 6
A. Schedule 1 – Consultants 7
This Schedule consists of 4 sheets and shows the costs associated with 8
external Consultants performing services for the Company. Sheet 4 9
details several onetime adjustments to normalize the Historical Test Year 10
and an adjustment to increase the remaining Historical Test Year costs by 11
inflation. 12
13
Schedule 2 – Contractors 14
This Schedule consists of 4 sheets and shows the costs associated with 15
external Contractors performing services for the Company. Sheet 4 details 16
several onetime adjustments to normalize the Historical Test Year 17
including an adjustment to transfer $44.6 million of deferred storm costs 18
from Schedule 7 (Other) to this Schedule to more accurately reflect the 19
costs in the appropriate expense type. The Company also made an 20
19
Testimony of The Revenue Requirements Panel
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adjustment to increase the remaining Historical Test Year costs by 1
inflation. 2
3
Schedule 3 – Donations 4
This Schedule consists of 4 sheets and shows the costs of Donations by the 5
Company. The Company is not seeking recovery of these costs. 6
Therefore, Sheet 4 shows the removal of these costs from the Historical 7
Test Year. 8
9
Schedule 4 – Employee Expenses 10
This Schedule consists of 4 sheets and shows the costs of Employee 11
Expenses. Sheet 4 details several onetime adjustments to normalize the 12
Historical Test Year and an adjustment to increase the remaining 13
Historical Test Year costs by inflation. 14
15
Schedule 5 –Computer Hardware 16
This Schedule consists of 4 sheets and shows the costs of Computer 17
Hardware used by the Company. Sheet 4 details several onetime 18
adjustments to normalize the Historical Test Year and an adjustment to 19
increase the remaining Historical Test Year costs by inflation. 20
21
20
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Schedule 6 – Computer Software 1
This Schedule consists of 4 sheets and shows the costs of Computer 2
Software used by the Company. Sheet 4 details several onetime 3
adjustments to normalize the Historical Test Year and an adjustment to 4
increase the remaining Historical Test Year costs by inflation. 5
6
Schedule 7 – Other 7
This Schedule consists of 4 sheets and shows costs incurred by the 8
Company for electric utility purposes that are not otherwise identified in 9
specific Expense Types. Sheet 4 details several onetime adjustments, for 10
example Management Audit, Smart Grid, Solar, Enterprise Resource 11
Planning Project and Entertainment Expense, to normalize the Historical 12
Test Year for costs that are not recurring in the Rate Years. The Company 13
made an adjustment to increase the remaining Historical Test Year costs 14
by inflation. 15
16
Schedule 8 - Rents 17
This Schedule consists of 17 sheets and shows the Rent Expense incurred 18
by the Company. The Schedule consists of a Summary Sheet by FERC 19
account, a Summary Sheet by sub-function, including Facilities, 20
Information Technology, Transmission and Other, and detailed sheets for 21
21
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each sub-function. Sheets 7 through 9 detail Facilities lease expense by 1
leased property, segregated by directly owned facilities and allocated 2
facilities. The Rate Year amounts are based on the expected lease 3
payments for the Niagara Mohawk lease obligations and Niagara 4
Mohawk’s allocated share of existing Service Company lease obligations 5
plus Reservoir Woods capital costs. Reservoir Woods capital costs 6
include depreciation of leasehold improvements plus a return on the 7
average net leasehold improvements at National Grid’s Waltham, 8
Massachusetts facility. Sheets 10 and 11 detail Information Technology 9
leased from National Grid Service Company, segregated by projects 10
placed into service prior to or during the Historical Test Year, and by 11
projects to be placed into service subsequent to the Historical Test Year. 12
The Rate Year amounts are based on the scheduled amortization of 13
existing projects and the forecasted amortization and return on new 14
projects. The return on the new projects is based on the projected long 15
term debt rate at the National Grid Service Company. This return is 16
applied to the unamortized asset balance less accumulated deferred taxes 17
for the new projects. Sheets 12 and 13 detail Transmission related lease 18
costs, consisting mainly of right of way rent payments. The Rate Year 19
amounts are based on the existing contract for the Volney Marcy Right of 20
Way plus the Test Year values for other transmission related rates inflated 21
22
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to the Rate Year using the inflation rate in Exhibit __ (RRP-7). Sheets 14 1
through 17 detail all other Rent Expenses, such as data center, printing and 2
copying equipment leases, both directly and indirectly incurred. The Rate 3
Year amounts are based on the Historical Test Year values inflated to the 4
Rate Year using the inflation rate in Exhibit __ (RRP-7). The Company is 5
also making three adjustments to the Historical Test Year. The first 6
adjustment is to remove costs to achieve merger synergy savings. The 7
second adjustment is to remove the Sacandaga Reservoir payment that 8
relates to Non-Utility Property. The third adjustment is to annualize the 9
Historical Test Year expense related to costs for the Reservoir Woods 10
facility. 11
12
Schedule 9 – AFUDC Debt 13
This Schedule consists of 4 Sheets and shows the reversal of AFUDC in 14
the Rate Years. The forecast expense for AFUDC debt in the Rate Years 15
is zero. 16
17
Schedule 10 – Service Company Equity Credits 18
This Schedule consists of 4 sheets and shows the Service Company Equity 19
Credits accrued by the Company relating to Service Company benefits 20
(such as tax benefits) allocated to affiliated companies. Sheet 4 details the 21
23
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reallocation of a portion of this item from electric to gas to normalize the 1
Historical Test Year. The remaining Historical Test Year costs are 2
adjusted by inflation. 3
4
Schedules 11 – 17 Other Costs and Credits 5
These Schedules each consist of 4 sheets and show other costs incurred by 6
the Company and reimbursements by customers to the Company. Sheet 4 7
details several onetime adjustments to normalize the Historical Test Year 8
and an adjustment to increase the remaining Historical Test Year costs by 9
inflation. 10
11
The Schedules consists of the following: 12
Schedule 11 – Conservation Load Management 13
Schedule 12 – Construction Reimbursement 14
Schedule 13 – Company Contributions/Credits to Jobs 15
Schedule 14 – Bill Interface Expense Type 16
Schedule 15 – Capital Overheads 17
Schedule 16 – Supervision and Administration 18
Schedule 17 – Service Company Operating Costs 19
20
21
24
Testimony of The Revenue Requirements Panel
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Schedule 18 - Sales Tax 1
This Schedule consists of 4 sheets and shows miscellaneous Sales Taxes 2
incurred by the Company related to purchases. Sheet 4 details an 3
adjustment to normalize the Historical Test Year and an adjustment to 4
increase the remaining Historical Test Year costs by inflation. 5
6
Schedules 19 and 24 – Other Post Employment Benefits and Pension 7
Schedules 19 and 24 each consist of 8 sheets that detail the estimated costs 8
and assumptions associated with Other Post Employment Benefits 9
(“OPEB”) Expense and Pension Expense. 10
11
Q. How were these costs addressed in the Merger Joint Proposal? 12
A. In the Merger Rate Plan, Niagara Mohawk stipulated to allowed levels of 13
Pension and OPEB Expenses and agreed to reconcile and defer under or 14
over recoveries of these Expenses pursuant to the Commission’s 15
Statement of Policy on Pensions and Other Post Employment Benefits 16
based on the rate allowances.4 17
18
Q. How did you develop the forecasts of Pension and OPEB Expense? 19
4 Section 1.2.4.13, Section 1.6.1.4 and Attachment 16 of the Merger Rate Plan.
25
Testimony of The Revenue Requirements Panel
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A. We developed the forecasts using the estimates of the Company’s 1
actuaries, Hewitt and Associates, of Pension and OPEB Expense. 2
Attachment 16 of the Merger Joint Proposal set the allowances for the Test 3
Year at approximately $17,674 million and $31,657 million for Pension 4
and OPEB Expense, respectively. The Company’s Pension and OPEB 5
Expenses have significantly exceeded these amounts, resulting in deferred 6
debit balances as of September 30, 2009 of $165.5 million and $269.9 7
million, respectively. Based on Hewitt and Associates’ projections of the 8
anticipated expense in the Rate Years shown in Schedules 19 and 24, and 9
the objective of minimizing deferrals that will burden future rates, Niagara 10
Mohawk proposes to increase the amounts included in rates in the Rate 11
Years to $50.8 million, $44.6 million and $35.8 million for Pension 12
Expense and $ 108.9 million, $ 92.5 million and $ 83.2 million for OPEB 13
Expense, as illustrated on Sheet 3 of Schedules 19 and 24. The Company 14
proposes to continue the reconciliation procedures set forth in Attachment 15
16 of the Merger Rate Plan and the Commission’s Statement of Policy on 16
Pensions and Other Post Employment Benefits. These reconciliation 17
procedures are more fully described in our discussion below of the 18
Pension and OPEB deferrals and in Exhibit __ (RRP-6). The Company’s 19
efforts to control these costs are described in the testimony of Maureen P. 20
Heaphy. 21
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Schedules 20, 21, 22, 23, 25 and 26 – Fringe Benefits 1
These Schedules represent employee fringe benefits, exclusive of Pension 2
and OPEB costs, as follows: 3
Schedule 20 - FAS 112 Long-Term Disability Retirement 4
Schedule 21 - Healthcare 5
Schedule 22 - Group Life Insurance 6
Schedule 23 - Other Benefits (primarily aid to education) 7
Schedule 25 - Thrift Plan (401k matching) 8
Schedule 26 – Worker’s Compensation 9
10
Each Schedule consists of 5 Sheets. Sheets 1 through 3 present the 11
Historical Test Year normalization adjustments and the forecast Rate 12
Years. Sheet 4 details onetime adjustments to normalize the Historical 13
Test Year and the forecast of the Rate Years and adjustments to increase 14
the remaining Historical Test Year costs by inflation, where necessary. 15
Sheet 5 presents the fully normalized Historical Test Year balances 16
allocated to electric operations. 17
18
Q. How were the adjustments to normalize the Historical Test Year 19
developed? 20
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A. Sheet 5 sets forth the standard process utilized to normalize costs incurred 1
in the Historical Test Year. For charges made directly to Niagara 2
Mohawk, we started with the Historical Test Year’s total expenses (gross 3
expenses prior to any adjustment for capitalization, but net of charges or 4
credits that apply to another time period). Next, except for Expense Type 5
B05 (Other Benefits), we applied a uniform Historical Test Year 6
capitalization rate of 33.02 percent, which is based on the ratio in the 7
Historical Test Year of capitalized labor to total labor for Niagara 8
Mohawk, to arrive at the total (electric and gas) fringe benefit expense, 83 9
percent of which was then allocated to electric operations. 10
11
Q. How did the Company treat Group Life Expense detailed in Schedule 12
22? 13
A. In January 2009, the Company’s Group Life benefits were changed. The 14
current benefit includes an insurance benefit to employees equal to one 15
times their annual salary as opposed to the former benefit of two times 16
their annual salary. An adjustment to the Historical Test Year was made 17
to reflect this reduction in cost. 18
19
Q. How did the Company treat Expense Type B05 detailed in Schedule 20
23? 21
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A. Expense Type B05 - Other Benefits (primarily aid to education) is not 1
capitalized. This is largely due to the relatively small dollars associated 2
with this expense. 3
4
Q. Please explain the methodology for allocating fringe benefits to 5
Capital. 6
A. The portion of total fringe benefit expense allocated to Capital was the 7
same as the portion of total labor allocated to Capital, which was based on 8
historical percentages. 9
10
Q. Please explain the electric allocation percentage adjustments on Sheet 4 11
of the Schedules. 12
A. These adjustments adjust to an 83/17 allocation for those occasions when 13
fringe benefit charges in the Historical Test Year were not allocated 83 14
percent / 17 percent between the electric and gas operations. 15
16
Q. Please describe the method for normalizing the fringe benefits of 17
Service Company employees charged to Niagara Mohawk. 18
A. Similar to the fringe benefits charged to Niagara Mohawk, we started with 19
the total Service Company charges to Niagara Mohawk for the fringe 20
benefit expense (gross expenses prior to any adjustment for capitalization) 21
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and removed any out-of-period charges or credits. We then allocated the 1
total fringe benefit expense on the same basis that Service Company 2
historical labor is allocated to Niagara Mohawk, or 25.58 percent. As 3
discussed above, the fringe benefits were then allocated 83 percent to 4
electric operations. This is shown on Sheet 4 of the Schedules. 5
6
Schedule 27 – Payroll Taxes 7
This Schedule consists of 4 sheets and pertains to Payroll Taxes incurred 8
by the Company. Because the costs associated with Payroll Taxes are 9
more properly presented in Taxes Other Than Income Taxes, Sheet 1 10
shows the reclassification of payroll taxes from O&M to Taxes Other 11
Than Income Taxes, as noted on Sheet 4. 12
13
Schedules 28 through 30 - Materials 14
These Schedules each consist of 4 sheets and show costs related to 15
materials purchased from outside vendors, materials released from 16
inventory and material stores handling costs incurred by the Company. 17
Sheet 4 details several onetime adjustments to normalize the Historical 18
Test Year, including an adjustment to reflect a known increase in postage 19
occurring in Rate Year 1 as shown on Schedule 28. The Company also 20
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made an adjustment to increase the remaining Historical Test Year costs 1
by inflation. 2
3
The Schedules consist of the following: 4
Schedule 28 – Materials from Outside Vendors 5
Schedule 29 – Materials from Inventory 6
Schedule 30 – Materials Stores Handling 7
8
Schedule 31 - Labor 9
Schedule 31 contains all O&M labor expense. It consists of 33 Sheets and 10
presents the labor expense forecasts for the Rate Years. Schedule 31 also 11
presents the adjustments made to normalize the Historical Test Year and 12
forecast the labor expense for the Rate Years. The Schedule provides this 13
information by Provider Company. 14
15
Q. Please explain the components of Schedule 31. 16
A. The first four Sheets are the total labor charges that were expensed for the 17
Historical Test Year and Rate Years. Sheets 5 and 6 are the calculation of 18
adjusted Historical Test Year and forecast Rate Years Operating Expense 19
labor for electric operations only. Sheets 7 through 12 present the 20
allocated total annualized adjusted base labor expense and adjusted 21
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variable pay labor expense for all Provider Companies to Niagara 1
Mohawk. Sheets 13 through 16 present labor expense charged by 2
Provider Company by electric and gas, capital, expense and other for the 3
Historical Test Year. Sheets 17 through 20 present the same information 4
for the adjusted Historical Test Year. Sheets 21 through 24 present the 5
same information for Rate Year 1. Sheets 25 through 28 present this 6
information for Rate Year 2 and Sheets 29 through 32 present this 7
information for Rate Year 3. Sheet 33 presents the number of forecast 8
full-time equivalent employees before any adjustments for additional 9
consumer advocates. 10
11
Q. Please explain the general methodology used to forecast labor for the 12
Company. 13
A. The Company incurs labor charges from its own employees and from 14
employees of the National Grid Service Company. The Company also 15
incurs labor charges from the three KeySpan Service Companies (National 16
Grid Corporate Services LLC, National Grid Engineering & Survey, Inc. 17
and National Grid Utilities Services LLC, collectively the “KeySpan 18
Service Companies”) and other affiliated companies (“All Other 19
Companies”) allocated to Niagara Mohawk. The forecast in Schedule 31 20
starts with the Historical Test Year aggregate operating expense labor 21
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costs for Niagara Mohawk, which are shown segregated by Provider 1
Company on Sheet 1. Additionally, Sheets 14 through 16 show the 2
Historical Test Year allocations of total labor incurred by Niagara 3
Mohawk among itself, the National Grid Service Company and the 4
KeySpan Service Companies. The Company forecast both components: 5
the labor costs Niagara Mohawk incurred and charged to itself and other 6
companies and the labor costs incurred by the National Grid Service 7
Company, the KeySpan Service Companies and All Other Companies and 8
charged to Niagara Mohawk. The forecast of total labor costs by Provider 9
Company Niagara Mohawk and the forecast of total labor costs charged 10
by National Grid Service Company and the KeySpan Service Companies 11
were developed utilizing full time equivalents (“FTEs”) at September 30, 12
2009, which was the basis for the forecast Rate Years. The results are 13
then prorated back by the accounting allocations for each Provider 14
Company based on the Historical Test Year. Electric labor expense 15
incurred by and for Niagara Mohawk was the basis for the estimate of 16
O&M Expense, as set forth in the Summary Schedule of Exhibit __ (RRP-17
2). 18
19
Q. How did you determine the appropriate headcount for the Rate 20
Years? 21
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Testimony of The Revenue Requirements Panel
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A. We began with the labor headcount in the Historical Test Year for Niagara 1
Mohawk, the National Grid Service Company and the KeySpan Service 2
Companies. The management FTE headcount at September 30, 2009 as 3
presented on Sheet 33, was 643, 2,293 and 2,110 respectively. The 4
collective bargaining unit headcount at September 30, 2009 was 3,224, 5
543, and 1,985 respectively. The Niagara Mohawk collective bargaining 6
unit headcount was adjusted to 3,229 FTEs to establish the base for the 7
forecast as shown in Exhibit __ (RRP-10), the workpapers supporting 8
Exhibit __ (RRP-2) Schedule 31. This adjustment was made to reflect 9
minimum staffing levels established in the collective bargaining contract. 10
11
Q. Please describe the process used to convert full time employees and 12
part-time employees into FTEs. 13
A. Full time equivalent status, shown on Sheet 33, was computed by the 14
following method: 15
(i) All full time employees were considered FTEs. 16
(ii) Part time employees were converted to FTEs using the following 17
formula: Average Part Time Salary per Employee divided by Average Full 18
Time Salary per Employee times Part Time Employee Count. For Niagara 19
Mohawk, National Grid Service Company and the KeySpan Service 20
Companies, there were 9, 33 and 42 part time management employees, 21
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Testimony of The Revenue Requirements Panel
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respectively, which equated to 4, 22 and 14 full time equivalents. The 1
same procedure was used for represented employees. The companies had 2
21, 11 and 166 part time employees included in the represented labor base, 3
which equated to 8, 5 and 45 full time equivalents, respectively. 4
5
Q. How was management labor calculated for the Rate Years? 6
A. Management labor for the Rate Years was calculated using average 7
salaries in effect at September 30, 2009, including base and variable 8
compensation. The average base salaries were adjusted for salary 9
increases, applying a 3 percent salary increase to management labor 10
annually in July 2010 through July 2013, as shown on Sheets 7 through 12 11
of Schedule 31. This salary increase and an explanation of the base and 12
variable compensation structure are addressed in the testimony of 13
Maureen Heaphy and Richard Meischeid. 14
15
Q. How was management variable pay calculated for the Rate Years? 16
A. Management Rate Year variable pay was calculated by first applying 17
maximum plan payout ratios to average base salaries adjusted for salary 18
increases. A target payout rate of 45 percent was then applied to 50 19
percent of the maximum variable pay plan payout associated with 20
attainment of financial goals. The Historical Test Year payout rate of 68 21
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Testimony of The Revenue Requirements Panel
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percent was applied to 50 percent of the maximum plan payout associated 1
with individual objectives. 2
3
Q. How was represented employees’ variable pay calculated for the Rate 4
Years? 5
A. Represented employees’ Rate Year variable pay was calculated by 6
applying the Historical Test Year payout rate of 3.4 percent to average 7
base wages adjusted for wage increases, double time and shift premiums 8
and overtime. 9
10
Q. Have you reflected senior leadership variable pay in the forecast? 11
A. No. Senior leadership variable pay is reflected on the books of the 12
Company under the other income and deduction section of the income 13
statement. As such, these costs are not included in O&M Expense. 14
15
Q. How was represented employees’ labor expense calculated for the 16
Rate Years? 17
A. We first normalized the historic September 30, 2009 represented labor 18
expense for items such as double time and shift premiums. Employees’ 19
labor expense for the Rate Years was determined by increasing average 20
base wages in the adjusted Historical Test Year by 3 percent in April of 21
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Testimony of The Revenue Requirements Panel
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2010 and by 2.5 percent in April of 2011, 2012 and 2013, in accordance 1
with the labor agreement between the Union and the Company. 2
3
Q. Please describe how overtime was calculated for the adjusted 4
September 30, 2009 total labor amounts. 5
A. The ratio of overtime pay to base salary and wages was calculated for the 6
Historical Test Year. These overtime rates were applied to the adjusted 7
forecast management salaries and represented employees’ wages for the 8
Rate Year. Overtime rates were calculated by expense, capital, and other 9
charge categories and by electric and gas accounts. 10
11
Q. Please describe the adjustments to miscellaneous pay for the Rate 12
Years. 13
A. The miscellaneous pay adjustments were prorated based on the Historical 14
Test Year. 15
16
Q. Were any other adjustments made to the base Historical Test Year 17
labor? 18
A. Yes. The Company made two additional adjustments. One adjustment 19
pertains to Voluntary Early Retirement (“VERO”) Employees and the 20
other pertains to consumer advocates. 21
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Q. Please explain the adjustment relating to VERO employees. 1
A. An adjustment was made to the Historical Test Year to include the actual 2
incurred labor expense for VERO employees. As shown in Schedule 42, 3
the Company reduced the synergy savings relating to these employees to 4
reflect the embedded savings in the Historical Test Year. To illustrate, if a 5
VERO employee making $100,000 worked three months in the Historical 6
Test Year, the Company incurred $25,000 in labor expense. That $25,000 7
is included in the forecasted Rate Year inflated by the inflation factor 8
shown in Exhibit __ (RRP-7). The Company therefore would have 9
$25,750 of labor expense forecast in the Rate Year and $74,250 of savings 10
embedded in the Historical Test Year relative to that VERO employee. 11
The synergy savings credit would be $25,750. 12
13
If an adjustment were not made to reflect the embedded savings associated 14
with VERO employees leaving during the Historical Test Year, the credit 15
to synergy savings would be higher and the savings would be double 16
counted. 17
18
Q. Please explain the adjustment relating to consumer advocates. 19
A. Pursuant to a settlement with Staff, the Company adjusted the base 20
Historical Test Year labor expense to remove the labor expense associated 21
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Testimony of The Revenue Requirements Panel
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with four consumer advocates in Rate Year 1. The settlement precludes 1
the Company from recovering this labor expense through the end of the 2
Merger Rate Plan or December 31, 2011. The Company included the 3
labor expense for these advocates in the Rate Years 2 and 3. 4
5
Q. Please describe 53rd week labor costs. 6
A. Every calendar year does not contain 52 pay weeks. Every 5 years there is 7
an additional pay week. Therefore, an amount equal to one-fifth of the 8
weekly cost (i.e. one day) is added to the labor cost to reflect the 9
normalized cost of the 53rd week. 53rd week labor costs impact any 10
employee who is paid weekly. Typically, these are represented 11
employees. The 53rd week labor costs are added to the total Rate Year 12
represented labor costs found on Sheets 7 through 12 of Schedule 31. 13
14
Q. How were 53rd week labor costs calculated? 15
A. 53rd week labor costs were calculated for the Rate Years by taking the 16
estimated annual Rate Year labor costs for weekly paid employees divided 17
by 2,080 hours and multiplied by 8 hours. The 2,080 hours represents the 18
total number of hours worked in a normal calendar year and the 8 hours 19
represents the normal work hours in a day (i.e. one-fifth of the week). The 20
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Testimony of The Revenue Requirements Panel
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calculation was done by salary band for full-time represented employees 1
and part-time represented employees. 2
3
Schedule 32 – Transportation 4
This Schedule consists of 16 Sheets and shows Transportation costs 5
incurred by the Company. The first 4 sheets are the same as all other 6
schedules, with Sheet 4 detailing adjustments to normalize the Historical 7
Test Year and inflation adjustments to reflect the conditions in the Rate 8
Years. Sheets 5 through 16 provide greater detail on the elements of costs 9
relating to Transportation such as registration, fees and taxes, lease 10
expenses and fuel costs. 11
12
Q. What are the major cost drivers of Transportation expense? 13
A. The majority of costs associated with Transportation pertain to lease 14
expense, vehicle parts, vehicle maintenance and motor fuel. Sheets 5 15
through 7 of Schedule 32 detail the cost components in the Historical Test 16
Year and the Rate Years. Sheets 8 through 16 provide a further 17
breakdown of the components in developing the forecast. 18
19
Q. Please explain why there is no credit balance for the Lease Refinance 20
Amortization reflected in the Rate Years. 21
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Testimony of The Revenue Requirements Panel
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A. The Lease Refinance Amortization is a static credit to the Fleet 1
Management Department that will be fully amortized on March 31, 2010 2
and therefore is not reflected in the Rate Years, as shown on Sheet 5 of 3
Schedule 32. 4
5
Q. What gave rise to the Lease Refinance Amortization Credit? 6
A. In late 2006, the National Grid Service Company refinanced 7
approximately 1,000 leased vehicles to reduce the monthly cash outflow in 8
lease expense by extending lease terms. Accordingly, the National Grid 9
Service Company had the leasing company, Peterson, Howell & Heather 10
(“PHH”), recalculate operating leases using longer terms and refund the 11
difference between what the Service Company had paid and the 12
recalculated amounts. The total cash refunded to the National Grid Service 13
Company was $2.4 million. 14
15
Q. What did the National Grid Service Company do with this refund? 16
A. The National Grid Service Company amortized the refund over four years, 17
which represents the approximate average remaining life of the units that 18
were refinanced; $444,630 is credited to Niagara Mohawk annually until 19
March 31, 2010. 20
21
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Testimony of The Revenue Requirements Panel
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Q. Please describe the components of transportation lease expenses. 1
A. Transportation lease expenses consist of two components: (1) vehicles on 2
lease in the Historical Test Year that will remain on lease through the Rate 3
Years and (2) vehicles on lease in the Historical Test Year that will be 4
replaced before or during the Rate Years. 5
6
Q. Please explain the lease expense forecast for the Rate Years. 7
A. We started with the existing leases at the end of the Historical Test Year 8
and adjusted for vehicles eligible for replacement. Vehicles become 9
eligible for replacement when fully amortized or upon reaching the end of 10
their expected life cycle. Based on a schedule from PHH, the base line 11
level of lease expense is reduced by the vehicles reaching full 12
amortization. 13
14
Q. Please explain how lease expenses are calculated. 15
A. Estimated delivery dates are established for the new units along with 16
projected acquisition costs. Lease expenses are then calculated using the 17
acquisition cost, term of the lease and projected interest rate from PHH. 18
19
Q. Please explain how motor fuel costs are calculated. 20
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Testimony of The Revenue Requirements Panel
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A. The forecast for the Rate Years assumes the same level of consumption as 1
the Historical Test Year. The dollars were calculated using the annualized 2
Historical Test Year price per gallon and inflating that price per gallon out 3
to the Rate Years and multiplying that price by the historical level of 4
consumption. 5
6
Q. Please explain how vehicle parts and maintenance costs were 7
calculated. 8
A. Vehicle parts costs are the actual costs paid to vendors for procured parts. 9
Vehicle maintenance costs consist of employee payroll and actual costs 10
paid to vendors when work is performed on Company vehicles by outside 11
vendors. Payroll costs are reflected in Schedule 31 of Exhibit __ (RRP-2). 12
13
Q. Please explain the allocation of transportation costs between the 14
electric and gas businesses. 15
A. The allocation between electric and gas operations is based on actual 16
usage hours of vehicles, as included in the Time Entry System or 17
STORMS. 18
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Schedule 33 - Energy Efficiency Program 1
This Schedule consists of 4 Sheets. The Company assumes that the 2
revenues offset the expenses associated with the Company’s Energy 3
Efficiency Programs. The costs associated with these programs are not 4
included in base rates but rather recovered through the reconciling System 5
Benefits Charge. The Company is not seeking recovery of costs 6
associated with these programs in base rates. 7
8
Schedule 34 – Injuries and Damages 9
This Schedule consists of 7 sheets and shows the costs associated with 10
damage claims and insurance premiums. Sheet 4 details adjustments to 11
normalize the Historical Test Year by utilizing a 3-year average of claims 12
and an adjustment to increase the adjusted Historical Test Year costs by 13
inflation. 14
15
Schedule 35 –Other Initiatives 16
This Schedule consists of 4 Sheets and shows the costs of other initiatives 17
to be implemented by the Company. These costs represent the following: 18
• Operation Expense Related to Capital Expense; 19
• Elevated Voltage – Testing and Repairs; 20
• Transmission Infrared; 21
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Testimony of The Revenue Requirements Panel
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• Transmission Footer Inspection; 1
• Vegetation Management; 2
• Inspection and Maintenance; and 3
• Research and Development; 4
The Company’s Infrastructure and Operations Panel provides support for 5
these costs. 6
7
The Schedule also includes adjustments for costs relating to the Low 8
Income Customer Assistance Program, two additional Customer 9
Advocates and the Conservation Advertising Campaign, as discussed in 10
the testimony of Company Witness Rudolph Wynter, and to the Economic 11
Development Fund as discussed in the testimony of the Rate Design, 12
Customer and Markets Panel. There is also an adjustment relating to 13
accounting changes that is discussed later in this testimony in the Rate 14
Base section on Plant and Accounting Changes. 15
16
Schedule 36 – Productivity 17
This Schedule consists of 4 sheets and shows the credits related to the 18
estimated productivity adjustment of a cumulative annual 1 percent of 19
labor costs and payroll taxes consistent with past Commission practice. 20
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Testimony of The Revenue Requirements Panel
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The adjustment represents a credit (i.e., reduction in revenue 1
requirements) of approximately $27 million over the Rate Plan Period. 2
3
Q. Did the Company employ efficiency programs in the 4
Historical Test Year? 5
A. The Company completed a number of efficiency initiatives identified in 6
the KeySpan merger proceeding. The savings associated with those 7
efficiency initiatives are credited to customers as shown on Schedule 42. 8
In addition to the merger related initiatives, the Company has 9
implemented other efficiency programs such as the Electric Distribution 10
Operations (“EDO”) transformation initiative that are intended to improve 11
the Company’s performance. The productivity adjustment to labor and 12
payroll tax expense is based on the assumption that employee productivity 13
increases each year. These initiatives are designed to better enable the 14
achievement of continuous improvement and efficient performance. The 15
costs to achieve these additional efficiency initiatives in the Historical Test 16
Year provide the means to achieve the productivity adjustment. 17
18
Schedule 37 – Rate Case Expenses 19
This Schedule consists of 4 Sheets and shows the forecast costs of 20
preparing this rate filing. These costs are not in the Historical Test Year 21
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Testimony of The Revenue Requirements Panel
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and represent the prudently incurred costs necessary to submit this rate 1
filing. The Company requests authority to amortize these costs over three 2
years. 3
4
Schedule 38 – Regulatory Assessment Fees 5
This Schedule consists of 8 Sheets and shows the costs associated with the 6
annual Commission assessment paid by the Company. The assessment 7
consists of two components – the General & ERDA and the Temporary 8
State Energy & Utility Service Conservation Assessment (“18-A 9
Assessment”). The General & ERDA portion of the assessment is 10
recovered in base rates and the 18-A Assessment portion is recovered 11
through a reconciling surcharge mechanism. Sheet 4 details adjustments 12
to normalize the Historical Test Year and is supported by Sheets 13 and 14 13
of this Schedule. 14
15
Schedule 39 – Renewable Portfolio Standard 16
This Schedule consists of 4 Sheets. The costs associated with the 17
Renewable Portfolio Standard (“RPS”) are not included in base rates but 18
rather recovered through a reconciling surcharge mechanism. 19
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Schedule 40 – Site Investigation and Remediation 1
This Schedule consists of 4 sheets and shows the costs associated with Site 2
Investigation and Remediation. Sheet 4 details adjustments to normalize 3
the Historical Test Year. 4
5
Q. How was the SIR expense forecast developed? 6
A. Given the anticipated levels of SIR spending, the Company is proposing to 7
increase the amount in electric base rates for SIR costs from the current 8
annual level of approximately $12.75 million to approximately $29.75 9
million. The $12.75 million threshold amount represents the electric 10
portion of an overall $15 million electric and gas SIR allowance in base 11
delivery rates. The Company is deferring SIR costs in excess of $12.75 12
million per year. 13
14
The current rate allowance of $12.75 million was established when much 15
of the SIR activity was focused on investigation, planning and design. In 16
recent years, site remediation, which typically requires a greater level of 17
spending per site, has increased. As discussed in the testimony of the 18
Infrastructure and Operations Panel, SIR spending in the Historical Test 19
Year significantly exceeded the Merger Rate Plan allowance and this trend 20
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Testimony of The Revenue Requirements Panel
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is expected to continue through Rate Year 3 as site remediation 1
progresses. 2
3
Resetting the SIR allowance to a more realistic $29.75 million will 4
appropriately update Niagara Mohawk’s rates and serve to minimize SIR 5
deferral balances. The work plan developed by the Company, in 6
conjunction with the New York State Department of Environmental 7
Conservation (“DEC”), establishes the sites to be cleaned up over the next 8
few years. The work plan beyond the Historical Test Year anticipates 9
spending in excess of $29.75 million per year. However, because several 10
variables can affect the actual costs of remediation required by the work 11
plan, the Company is including a conservative estimate in order to 12
mitigate Rate Year revenue requirements. 13
14
Schedule 41 – Storms 15
This Schedule consists of 4 Sheets. The Company is proposing to include 16
a Storm Fund of $30 million as explained in the testimony of the 17
Infrastructure and Operations Panel. 18
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Schedule 42 – Synergy Savings 1
This Schedule consists of 6 sheets and shows the credits associated with 2
the Synergy Savings relating to the KeySpan merger that accrued to the 3
Company in the Historical Test Year. The Company proposes to allocate 4
100 percent of the synergy and efficiency savings allocable to Niagara 5
Mohawk. 6
7
Q. Please explain the calculation of the synergy and efficiency credit 8
relating to the KeySpan merger. 9
A. Schedule 42 sets forth the forecast savings arising from KeySpan merger 10
synergy savings, as well as the amount allocated to Niagara Mohawk. The 11
Company is proposing to reflect in the revenue requirement 100 percent of 12
the estimated synergy savings in the Rate Years allocated to Niagara 13
Mohawk. The supporting workpapers detail the calculation. The 14
workpapers reflect the calculation of the total synergy savings and reduce 15
this amount by the approximately $28 million per year reflected in the 16
Historical Test Year; the incremental savings are applied to reduce the 17
revenue requirement in the Rate Years. 18
19
Q. What are the total synergy savings expected from the KeySpan 20
merger? 21
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Testimony of The Revenue Requirements Panel
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A. Total synergy savings are expected to be $156 million. In addition to 1
those savings, $44 million of efficiency savings are also expected, 2
resulting in total savings of $200 million. 3
4
Q. What percentage of the total savings is allocable to Niagara Mohawk 5
customers? 6
A. Based on the methodology established in the KeySpan Merger Joint 7
Proposal, 20.22 percent, or approximately $40 million, of the total savings 8
are allocable to Niagara Mohawk customers. However, based on the bill 9
pool allocations of actual savings achieved in the Historical Test Year, 10
24.93 percent, or approximately $49.9 million, of the total savings are 11
allocable to Niagara Mohawk customers. 12
13
Q. What percentage of savings is the Company allocating to Niagara 14
Mohawk customers in this proceeding? 15
A. The Company proposes to allocate 24.93 percent of the total savings to 16
Niagara Mohawk customers. 17
18
Q. Is the Company distinguishing between synergy and efficiency 19
savings? 20
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Testimony of The Revenue Requirements Panel
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A. No. The Company proposes to credit 100 percent of Niagara Mohawk’s 1
share of total savings to Niagara Mohawk customers. 2
3
Q. Please explain how you calculated Niagara Mohawk’s share of the 4
total savings. 5
A. As shown on Sheet 3, as of the period ended September 30, 2009, National 6
Grid’s run rate reflected total annualized achieved savings of 7
approximately $141 million. Niagara Mohawk’s run rate reflected total 8
annualized achieved savings of approximately $35 million or 24.93 9
percent of total savings. The actual savings realized by National Grid in 10
the Historical Test Year was $113.7 million as shown on Sheet 3. This is 11
less than the annualized amount because some of the savings were realized 12
for less than the full twelve months. Niagara Mohawk’s actual share of 13
savings in the Historical Test Year, based on bill pool allocations, was 14
approximately $28 million. These savings reduced Niagara Mohawk’s 15
Historical Test Year costs and are embedded in the Rate Years. 16
17
Q. Please explain how the savings reflected in the Historical Test Year 18
were identified. 19
A. During the KeySpan merger proceeding, National Grid identified a 20
number of synergy and efficiency savings initiatives. Each initiative 21
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Testimony of The Revenue Requirements Panel
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established a savings target, generally a dollar savings, to be achieved. 1
National Grid tracks synergy and efficiency savings by these initiatives. 2
Specifically, a database has been created that lists each initiative, the 3
savings target and when the target is expected to be achieved. The data 4
for each initiative includes future annual savings, actual fiscal savings to 5
date and FTE basis for the future annual savings. Each quarter, an 6
integration tracking team requests savings data and other information, 7
including a brief synopsis of the drivers behind the savings from each line 8
of business. Actual savings data is provided by initiative. This enables 9
the Company to identify when savings have been achieved and initiatives 10
completed. This process is the basis for the calculation of savings in the 11
Historical Test Year. 12
13
Q. What is the credit to Niagara Mohawk customers in the Rate Years? 14
A. The credit to customers in the Rate Years is as follows: 15
Rate Year 1 Rate Year 2 Rate Year 3 16
Synergy Savings $22,213,500 $22,613,300 $23,043,000 17
Costs to Achieve ($5,614,600) ($5,533,200) $(4,471,000) 18
Net Synergy Savings $16,598,900 $19,080,100 $18,572,000 19
20
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Q. Does this credit reflect 100 percent the allocable savings in the Rate 1
Years? 2
A. Yes. The credit reflects that $28 million in total savings were reflected in 3
the Historical Test Year through a reduction in costs charged to certain bill 4
pools. These savings reduced Niagara Mohawk’s cost of service. The 5
credit in the Rate Years reflects 100 percent of the forecast incremental 6
allocable savings. These savings are net of costs to achieve. 7
8
Q. Please explain how the Company calculated the costs to achieve. 9
A. Sheet 6 reflects the total costs to achieve the KeySpan merger synergy 10
savings of approximately $400 million and reflects that Niagara 11
Mohawk’s share of the total costs to achieve is 20.22 percent, or $80.9 12
million as set forth in the KeySpan Joint Proposal. Sheet 6 sets forth the 13
annual phase-in of these costs. Niagara Mohawk’s share of the total costs 14
to achieve is approximately $5.6 million, $5.5 million and $4.5 million in 15
the Rate Years respectively. 16
17
Q. Please explain the calculation of the synergy savings credit relating to 18
the New England Gas acquisition. 19
A. In August 2006, National Grid completed the acquisition of the Rhode 20
Island gas business of Southern Union Company of Rhode Island (“New 21
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Testimony of The Revenue Requirements Panel
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England Gas Acquisition” or “Acquisition”). The Historical Test Year is 1
3 years beyond the Acquisition and National Grid has achieved the 2
anticipated $19 million of total synergy savings. The Historical Test Year 3
reflects Niagara Mohawk’s share of all initiatives and savings related to 4
the Acquisition and no additional initiatives were implemented in the 5
Historical Test Year or are planned in the Rate Years. 6
7
Schedule 43 – System Benefits Charge 8
This Schedule consists of 4 sheets and shows the electric System Benefits 9
Charge. The costs associated with the System Benefits Charge are not 10
included in base rates but rather recovered through a reconciling surcharge 11
mechanism. The Company is therefore not seeking recovery of costs in 12
base rates. 13
14
Schedule 44 – Uncollectible Accounts 15
This Schedule consists of 4 sheets and shows the uncollectible expense 16
associated with electric operations. These costs are more fully discussed 17
in the testimony of the Company’s Witness Rudolph Wynter. 18
19
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Schedule 45 – O&M Summary 1
Schedule 45 provides a summary checklist of the O&M adjustments to the 2
Historical Test Year. These adjustments are described throughout the 3
Panel’s testimony or by other Company witnesses as identified. 4
5
Depreciation Expense 6
Q. Please describe Exhibit __ (RRP-3). 7
A. Exhibit __ (RRP-3) presents the Company’s actual Historical Test Year 8
electric and common depreciation expense and a forecast of electric and 9
common depreciation expense for the Rate Years based on depreciable 10
plant in service in the Rate Years. 11
12
Q. Please describe how you developed depreciation expense for the Rate 13
Years. 14
A. Depreciation expense for the Rate Years was developed by multiplying the 15
monthly depreciable base for each Electric and Common Plant grouping 16
by applicable composite depreciation rates. The monthly depreciable base 17
for each plant account is the monthly forecast beginning balance, which 18
includes the prior month’s estimated additions to plant in service, less the 19
prior month’s estimated retirements from plant in service. The composite 20
depreciation rates were developed based on depreciable plant balances as 21
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Testimony of The Revenue Requirements Panel
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of the Historical Test Year ended September 30, 2009 for each electric and 1
common plant grouping forecast. 2
3
Q. Did the Company perform a depreciation study of electric and 4
common plant? 5
A. Yes. The Company performed a study to determine the appropriate 6
depreciation and amortization amounts based on the Company’s Electric 7
and Common plant in service as of December 31, 2008. The depreciation 8
rates determined from the study are included in the direct testimony of 9
Company Witness Dr. Ron White and are used in computing Rate Year 10
depreciation and amortization expense. 11
12
Q. What is the forecast depreciation expense for the Rate Years? 13
A. The annual provision for depreciation and amortization expense for 14
Electric Plant studied is approximately $197.5 million, $209.7 million and 15
$223.3 million for the respective Rate Years, as shown on Exhibit __ 16
(RRP-3). 17
18
Q. What was the effect of the new depreciation rates on depreciation 19
expense in the Rate Years? 20
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A. The annual provision for depreciation and amortization for Electric Plant 1
and the electric allocation of Common Plant studied would decrease 2
(compared to the existing rates) by approximately $0.6 million in Rate 3
Year 1 and increase by $0.1 million and $1.2 million for Rate Years 2 and 4
3, respectively, as a result of using the proposed depreciation rates 5
effective January 1, 2011. Depreciation expense would decrease in Rate 6
Year 1 because of the proposed changes in rates and increase in Rate 7
Years 2 and 3 as a result of forecast capital expenditures. 8
9
Q. Were there any other recommendations from the study that were 10
incorporated into the forecast of net utility plant for the Rate Years? 11
A. Yes. We have incorporated the rebalancing of the electric and common 12
book depreciation reserves as of December 31, 2008 at account levels 13
within functions, as explained in the testimony of Company Witness Dr. 14
Ronald White. 15
16
Taxes Other Than Income Taxes 17
Q. Please describe Exhibit __ (RRP-4). 18
A. Exhibit __ (RRP-4) consists of a Summary and 5 Schedules showing Real 19
Estate Taxes, Payroll Taxes, Sales and Use Taxes, Other Taxes and Gross 20
Revenue Taxes for the Historical Test Year and Rate Years to present 21
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Total Electric Taxes Other Than Income Taxes booked to FERC Account 1
408.1. Schedule 1 of Exhibit __ (RRP-4) presents Real Estate Taxes for 2
the Historical Test Year and Rate Years. Schedule 2 reflects that the 3
computation of payroll taxes for the Rate Years is based on tax rates 4
currently in effect relative to labor costs forecast in Exhibit __ (RRP-2) 5
and allocated among expense, capital and other accounts. Schedule 3 6
shows that Sales and Use Tax and Other Taxes are based on amounts 7
recorded in the Historical Test Year, plus escalation using inflation rates 8
provided in Exhibit __ (RRP-7). Schedule 4 presents Other Taxes and 9
Schedule 5 presents Electric Revenue Taxes for the Historical Test Year 10
and for the Rate Years. Schedule 5 provides a calculation of electric 11
revenue taxes for the Rate Years and is based on the electric operating 12
revenues shown on Exhibit __ (RDCM-4). 13
14
Q. Please explain how Niagara Mohawk manages real estate tax expense. 15
A. Actual real estate taxes declined slightly from Fiscal Years 2005 through 16
2009. This decline can be attributed to the Company’s success in 17
managing property tax expense through several means including 18
aggressively protesting overvaluations, reviewing cost data supplied to 19
taxing authorities, and successfully petitioning for obsolescence 20
allowances to be applied to the valuation of Special Franchise property. 21
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Q. Please explain how the Company forecast Real Estate taxes for the 1
Rate Years. 2
A. The forecast of Rate Year Real Estate Taxes is based on actual 2009 3
School, Town, Village and City taxes and 2009 County taxes paid plus an 4
assumed baseline inflation factor of 3 percent per year. Additionally, the 5
Company anticipates a significant increase in real estate taxes due to new 6
additions to plant. Over calendar years 2009 through 2013, property taxes 7
are projected to increase by approximately 4.5 percent per year on 8
average. 9
10
Federal And State Income Tax (FIT/SIT) 11
Q. Please describe Exhibit __ (RRP-5). 12
A. Exhibit __ (RRP-5) consists of 4 Sheets. Sheet 1 shows the computation 13
of Electric Federal Income Taxes (“FIT”) and State Income Taxes (“SIT”) 14
for Rate Year 1. Sheet 2 shows the computation of Electric FIT and SIT 15
for Rate Year 2. Sheet 3 shows the computation of Electric FIT and SIT 16
for Rate Year 3. Sheet 4 shows the computation of the deductions for 17
interest expense for the Rate Years. If changes in the tax laws become 18
known during these proceedings, the Company will provide appropriate 19
adjustments of income tax expenses. 20
21
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Q. Please describe the method used to calculate the provision for FIT and 1
SIT in the Rate Years. 2
A. Beginning with operating income before income taxes, adjustments were 3
made for those items that are treated differently for book and income tax 4
purposes. For example, book depreciation is computed on a straight-line 5
basis and tax depreciation is computed using a variety of methods in 6
accordance with the provisions of the Internal Revenue Code. 7
Specifically, Sheets 1 through 3 of Exhibit __ (RRP-5) details the FIT and 8
SIT calculation beginning with net income before tax multiplied by the 9
statutory Federal or State tax rate presently effective for the Rate Year. 10
Tax additions and deductions are separately listed to arrive at net current 11
Federal and State Tax expense. The Federal portion includes the benefit 12
of the State Tax deduction. New York State instituted state income taxes 13
for utilities effective January 1, 2000. The New York State tax calculation 14
incorporates the transition rules that are in effect for utilities. 15
16
Rate Base 17
Q. Please describe Exhibit __ (RRP-6). 18
A. Exhibit __ (RRP-6) consists of a Summary Sheet and 6 Schedules. The 19
Summary Sheet presents the Electric rate base for the Historical Test Year 20
and the Rate Years. Schedule 1 presents the monthly average balances of 21
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Electric Net Utility plant with allocated Common Plant for the Historical 1
Test Year. Schedule 1 consists of 5 sheets. Sheets 1, 2 and 3 present the 2
monthly average balances of Electric and Common Net Utility Plant with 3
85 percent of Common Plant allocated for the Rate Years. Sheets 4 and 5 4
present the forecast of capital expenditures and cost of removal. Schedule 5
2 presents the monthly average balances of Electric Regulatory Assets and 6
Liabilities for the Historical Test Year by account. Schedule 2 consists of 7
58 sheets. Sheets 5 and 6 present forecast monthly average balances of 8
Electric Regulatory Assets and Liabilities for the Rate Years by account. 9
Schedule 3 presents Federal and State Accumulated Deferred Income 10
Taxes (“ADIT”) for the Rate Years. Schedule 4 presents the monthly 11
average balances of Electric Working Capital for the Historical Test Year 12
by account and the Rate Years. Schedule 5 consists of 35 sheets and 13
presents the lead lag study reflecting the working capital requirements 14
associated with electric purchases. Schedule 6 consists of 24 sheets and 15
presents the comparison of Average Historical Rate Base and Historical 16
Capitalization. The difference between these components represents the 17
adjustment for Excess Earnings Base included on Sheet 4 of Schedule 6. 18
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Forecast of Net Utility Plant in Service 1
Q. Please generally describe the methodology utilized to determine the 2
forecast of average net utility plant for the Rate Years. 3
A. Estimates of monthly plant in service, depreciation reserve and non-4
interest bearing construction work in progress (“CWIP”) balances are 5
required to forecast the average net utility plant for the Rate Years, which 6
is included in rate base pursuant to established Commission precedent. 7
Our projection of these monthly balances incorporated the following data: 8
(1) historical plant in-service, (2) historical depreciation reserve, (3) 9
historical construction work in progress, (4) historical retirement work in 10
progress, (5) forecast capital expenditures, (6) forecast cost of removal, (7) 11
forecast closings to plant in-service, (8) forecast retirements and (9) 12
forecast depreciation. 13
14
Schedule 1, Sheet 4 of Exhibit __ (RRP-6) shows the estimated forecast 15
capital expenditures grouped by various categories along with plant 16
closing rules and/or in service dates for several projects for electric and 17
common plant. The categories were determined by grouping capital 18
expenditures together that would have similar construction periods for 19
purposes of closing expenditures to plant in service and for applying 20
similar composite depreciation rates. Schedule 4 shows a six month 21
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forecast for the fiscal year ended March 31, 2010 and a five year forecast 1
for fiscal years ended March 31, 2011 through March 31, 2015. The 2
capital forecasts provided by the Infrastructure and Operations Panel 3
included all capital related overheads, for example, Capital Addition 4
Distributables (“CAD”) and Allowance for Funds Utilized During 5
Construction (“AFUDC”). For the Transmission and Distribution capital 6
forecasts (with two exceptions noted below), we allocated fiscal year total 7
construction expenditures into monthly cash flows based on the two year 8
average percentage for calendar years 2007 and 2008 consistent with the 9
Company’s responses to Information Request No. RAV-3 in Case 06-M-10
0878. The two exceptions to this cash flow methodology are the Tri-11
Lakes and Luther Forest cash outlays to purchase assets anticipated in 12
January 2011 and March 2012, respectively. These exceptions are 13
discussed more fully below. For the Shared Services and Information 14
Services capital forecasts, we utilized the monthly cash flows provided by 15
the Infrastructure and Operations Panel. Those estimated monthly 16
expenditures were added to the CWIP balances at September 30, 2009. 17
Although the capital forecast figures are provided by fiscal year from the 18
Infrastructure and Operations Panel, by cash flowing them monthly, we 19
are able to develop a calendar rate year forecast. Closing rules were 20
developed to forecast additions to plant in service by analyzing and 21
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adjusting the Historical Test Year’s plant closings for each electric and 1
common plant grouping level being forecast. Consistent with the analysis, 2
the following closing rules were developed: 3
Transmission Substations 12 months 4
Transmission Lines 6 months 5
Distribution Substations 9 months 6
Distribution Lines and Street Lighting 3 months 7
Meters, Line Transformers, Land and Land Rights 1 month 8
Electric and Common general plant 1 month 9
10
The monthly expenditures were closed to plant in service the month after 11
the applicable closing rule. For major projects with in service dates 12
provided, the expenditures were closed to plant in service in the month of 13
the estimated in-service date. The Historical Test Year ended September 14
30, 2009 CWIP balance was adjusted to exclude the Tri-Lakes project of 15
approximately $38.8 million and Regional Delivery Venture (“RDV”) 16
overhead costs of approximately $4.9 million. The Tri-Lakes $38.8 17
million balance represents an asset that has been included in CWIP and 18
there is a corresponding liability on the Company’s books. We are 19
excluding the Tri-Lakes September 30, 2009 CWIP balance as the starting 20
point for the Net Utility Plant forecast because the Company has not yet 21
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paid for the asset. Additionally, we have also excluded both the CWIP 1
balance and the corresponding liability from our historic Excess Earnings 2
Base Exhibit __ (RRP-6). 3
4
The Company is including the Tri-Lake assets in rate base beginning 5
January 2011 when the cash outlay is forecasted. The RDV overhead 6
costs in CWIP represent the core team costs that will be allocated to 7
transmission capital projects through an overhead allocation. As discussed 8
in the testimony of the Infrastructure and Operations Panel, core team 9
costs are RDV management and infrastructure costs that are assessed 10
annually pursuant to the RDV contracts. The Company is reclassifying 11
these costs from CWIP to a deferred debit as discussed below. The 12
outstanding CWIP balances were allocated each month between Interest 13
and Non-Interest Bearing CWIP based on an average historic percentage. 14
The average historic percentage was developed by analyzing and adjusting 15
the Historical Test Year’s non-interest bearing CWIP and total CWIP. 16
Forecast plant in-service was developed by adding the monthly closings 17
from CWIP for the period October 2009 through the Rate Year ending 18
December 31, 2013 to the September 30, 2009 Historical Test Year plant 19
in service balance, and forecast retirements for the same period were 20
subtracted. Electric transmission and distribution retirements were 21
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developed by analyzing and adjusting the Historical Test Year retirements 1
as a percentage of adjusted Historical Test Years additions for electric 2
transmission and distribution in aggregate. The historic retirement 3
percentage was applied to forecast electric transmission and distribution 4
plant additions (with the exception of the two asset purchases relating to 5
the Tri-Lakes and Luther Forest Projects). For electric and common 6
general equipment, retirements were estimated based on the Historical 7
Test Year’s retirements. Additionally, the Infrastructure and Operations 8
Panel provided specific retirements related to facility consolidations and 9
the replacement of the EMS information system. Estimated retirements 10
were included in both the plant in service and depreciation reserve ending 11
balances each month. The depreciation reserve was developed starting 12
with the Historical Test Year ending Reserve Balance, including 13
retirement work in progress (“RWIP”) at September 30, 2009, and adding 14
forecast Depreciation Expense and subtracting forecast Retirements and 15
Net Cost of Removal (“COR”) each month for the period October 2009 16
through December 2013. The September 30, 2009 RWIP balance was 17
reduced to exclude $0.7 million of RWIP associated with the Texaco Tank 18
Farm property pursuant to the Commission’s Order in Case 09-E-0593 19
issued and effective December 23, 2009. Schedule 4, Sheet 5 of Exhibit 20
__ (RRP-6) shows the estimated forecast cost of removal grouped by the 21
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same categories used for capital expenditures in Schedule 4, Sheet 4. 1
Schedule 4, Sheet 5 shows a six month forecast for the fiscal year ending 2
March 31, 2010 and a five year forecast for fiscal years ending March 31, 3
2011 through March 31, 2015. Cost of removal was allocated pro-rata to 4
the various categories based on the capital forecast and cash flowed 5
consistent with the methodology utilized to cash flow the associated 6
capital forecast. 7
8
Q. Are any capitalization policy changes included in the forecast of net 9
utility plant? 10
A. There are four capitalization policy changes included in the forecast of net 11
utility plant. As explained in more detail later in our testimony, the 12
Company is requesting authority to capitalize distribution cut outs, 13
distribution lightning arrestors and variable pay, which increase the 14
forecast of capital expenditures by approximately $10.2 million, $10.4 15
million and $10.7 million for the Rate Years, respectively. The Company 16
is also requesting to increase the current capitalization threshold from 17
$200 to $2,500, which decreases the forecast of capital expenditures by 18
approximately $4.2 million, $4.3 million and $4.4 million for the Rate 19
Years, respectively. The associated net reduction to operating expense of 20
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these proposed changes is included in the revenue requirement in Exhibit 1
__ (RRP-2), Schedule 35, Sheet 4. 2
3
Q. Please summarize the accounting treatment included in the revenue 4
requirement for the Tri-Lakes asset purchase described in the 5
testimony of the Infrastructure and Operations Panel. 6
A. As noted above, the $38.8 million CWIP balance and corresponding 7
liability as of September 30, 2009 were excluded from both the historic 8
Excess Earnings Base Exhibit __ (RRP-6), Schedule 6, along with the 9
beginning CWIP balance utilized in the forecast of net utility plant. The 10
Company is forecasting a $35 million cash outlay in January 2011 to 11
purchase the Tri-Lakes assets by including it in CWIP and then closing the 12
amount to plant in service the same month. There were no associated 13
retirements included in the forecast and the assets are being depreciated 14
beginning February 2011. A specific composite depreciation rate was 15
developed based on the project estimate provided by the Infrastructure and 16
Operations Panel assuming 60 percent of the assets are transmission 17
substation equipment and 40 percent of the assets are transmission line 18
equipment. 19
20
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Q. Please summarize the accounting treatment included in the revenue 1
requirement for the Luther Forest asset purchase described in the 2
testimony of the Infrastructure and Operations Panel. 3
A. As described in the testimony of the Infrastructure and Operations Panel, it 4
is intended that the Luther Forest facilities, once completed, will be 5
transferred to the Company for $1. However, due to the uncertainty as to 6
whether the Federal Energy Regulatory Commission (the “FERC”) will 7
authorize the transfer for $1, the Company is forecasting a $57 million 8
cash outlay in March 2012 to purchase the Luther Forest assets by 9
including it in CWIP and then closing the amount to plant in service the 10
same month. There were no associated retirements included in the 11
forecast and the assets are being depreciated beginning April 2012. A 12
specific composite depreciation rate was developed based on the project 13
estimate provided by the Infrastructure and Operations Panel assuming 46 14
percent of the assets are transmission substation equipment and 54 percent 15
of the assets are transmission line equipment. In the event that the FERC 16
authorizes the transfer of the assets for $1, and the Company incurs no tax 17
liability, the $57 million asset and associated depreciation would need to 18
be excluded from net plant. An alternative outcome is that Niagara 19
Mohawk purchases the assets for $1 and incurs an approximate $22.8 20
million tax liability not funded by the transferor. In that case, the $57 21
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Testimony of The Revenue Requirements Panel
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million asset and associated depreciation reserve would need to be 1
excluded from net utility plant; however, there would be a tax expense and 2
deferred tax liability that would need to be included in the revenue 3
requirement. The Company’s proposed capital expenditure tracker, 4
discussed in the new reconciliation mechanism section of our testimony, 5
would true up the forecast to the actual result. 6
7
Q. Please summarize the accounting treatment included in the revenue 8
requirement for the RDV overhead costs described in the testimony of 9
the Infrastructure and Operations Panel. 10
A. As noted above, the $4.9 million CWIP balance for RDV overhead as of 11
September 30, 2009 was excluded from the beginning CWIP balance 12
utilized in the forecast of net utility plant and reclassified as a deferred 13
debit. The RDV overhead costs have been and will continue to be 14
accumulated in a project that will be allocated to transmission capital 15
projects through an overhead allocation. The Infrastructure and 16
Operations Panel provided a forecast of RDV overhead costs, the RDV 17
costs to be allocated to capital projects and the associated unallocated 18
balances for the five year contract for the fiscal years ended March 31, 19
2010 through March 31, 2014. Based on the monthly forecast of RDV 20
overhead costs provided, we increased the deferred debit balance. We 21
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decreased the deferred debit balance for the RDV overhead costs to be 1
allocated to capital projects consistent with the cash flow percentages 2
utilized to cash flow transmission capital projects. The forecast net 3
deferred balance at the end of each fiscal year is consistent with the 4
unallocated balance provided. As previously stated, the capital related 5
forecast provided by the Infrastructure and Operations Panel includes all 6
overheads, including the RDV overhead costs. Reducing the deferred 7
debit balance for the RDV overhead costs to be allocated to capital 8
projects, consistent with the cash flow methodology of capital 9
expenditures, ensures that we are not double counting the overhead costs. 10
Therefore, the deferred debit forecast (Exhibit __ (RRP-6), Schedule 2) in 11
the revenue requirement represents the unallocated RDV overhead costs 12
that have been incurred by the Company and yet to be allocated to capital 13
projects included in CWIP. 14
15
Q. Please summarize the accounting treatment included in the revenue 16
requirement for the Hydro-One Transformer costs described in the 17
testimony of the Infrastructure and Operations Panel. 18
A. The Company expects to pay fifty percent of the approximate total $9 19
million cost of a replacement transformer to Hydro-One, an Ontario 20
utility. The transformer will enable a key tie-line between New York and 21
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Ontario to operate. The Company’s estimated cost has been included in a 1
deferred debit in Exhibit __ (RRP-6), Schedule 2 as of September 2010 2
(which represents our initial estimate of the in service date of the 3
transformer) and is proposed to be amortized over the three years 4
beginning October 2010 through September 2013. Both the declining 5
deferred debit balance and the associated amortization are included in the 6
revenue requirement for the Rate Years. Hydro-One recently confirmed 7
that it intends to purchase the replacement transformer once the Company 8
provides Hydro-One notice of agreement to share the costs of the new 9
transformer. The Company will adjust the in-service date if necessary at 10
the time the Company submits Corrections and Updates in this 11
proceeding. 12
13
Changes in Accounting 14
Q. Is the Company proposing any changes to its current accounting 15
policies? 16
A. Yes. The Company is proposing changing its accounting policies in four 17
categories: (1) lightning arrestors; (2) fused cutouts; (3) variable pay; and 18
(4) direct purchases of general equipment. Currently, the first three 19
categories are expensed when the expenditure is incurred. The Company 20
proposes that, effective January 1, 2011, expenditures for these three items 21
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Testimony of The Revenue Requirements Panel
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be capitalized. The fourth item represents a change to increase the current 1
capitalization threshold from $200 to $2,500 for direct purchases of 2
general equipment. The Company proposes that effective January 1, 2011 3
the direct purchase of general equipment items under $2,500 be expensed. 4
5
Q. Why is the Company proposing these accounting changes? 6
A. The Company’s primary objective is to establish an accounting policy that 7
is accurately aligned with the nature of the asset. For example, the 8
Company is proposing to capitalize lightning arrestors because they are 9
long-lived assets. In addition, these changes will create greater 10
consistency between the Company’s accounting methods and those of 11
other large New York State utilities and the Company’s affiliate 12
companies. 13
14
Lightning Arrestors 15
Q. What are lightning arrestors? 16
A. A lightning arrestor is an electrical device inserted in a power line to 17
protect the equipment from overvoltages or sudden fluctuations in current 18
by discharging the current to earth. 19
20
Q. Please explain the rationale for the accounting change. 21
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A. Lightning arrestors are devices that are permanently inserted in the 1
Company’s power lines until they become defective. They are not 2
consumed in performing maintenance but are an indispensable part of the 3
Company’s infrastructure. Therefore, in the Company’s accounting 4
system, lightning arrestors should be treated as capital rather than 5
expenses. Lightning arrestors are capitalized by other major utilities in 6
New York including Consolidated Edison, Central Hudson, Rochester Gas 7
and Electric and Long Island Power Authority. 8
9
Q. What is the impact to the revenue requirement? 10
A. With the proposed change for lightning arrestors, it is forecast that 11
approximately $1.8 million per year will shift from pre-tax expenses to 12
capital expenditures. 13
14
Cutouts 15
Q. What are fused cutouts? 16
A. A fused cutout (“cutout”) is a device that operates during high levels of 17
current to isolate and protect electric distribution lines and equipment from 18
overload conditions. 19
20
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Q. Please summarize the Company’s current accounting treatment of 1
cutouts. 2
A. Currently, the Company does not identify cutouts as a unit of plant and 3
cutout replacements are expensed. The costs associated with cutout 4
installations are capitalized only when the cutouts are installed as part of 5
another unit of plant (for example, a conductor or transformer). 6
7
Q. Please explain the rationale for the accounting change. 8
A. Cutouts remain in place until they become defective or fail. They are not 9
consumed in performing maintenance but are an indispensable part of the 10
Company’s infrastructure and should therefore be treated as capital rather 11
than expense. Cutouts are capitalized by other New York State utilities 12
including Consolidated Edison, Central Hudson, Rochester Gas & Electric 13
and the Long Island Power Authority. 14
15
Q. What is the impact to the revenue requirement? 16
A. With the proposed change to accounting for cutouts, it is forecast that 17
approximately $5 million per year will shift from pre-tax expenses to 18
capital expenditures. 19
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Variable Pay 1
Q. What is the Company’s proposal with respect to variable pay? 2
A. The Company proposes to capitalize variable pay based on actual base 3
labor and base overtime charged to capital in the Historical Test Year as 4
shown on Schedule 31, Sheet 14. 5
6
Q. Why is the Company proposing this change? 7
A. The Company’s purpose is to better align the accounting treatment of 8
variable pay with actual work being performed. 9
10
Q. What is the impact to the revenue requirement? 11
A. With the proposed change to capitalize a portion of variable pay, it is 12
forecast that approximately $3.5 million, $3.6 million and $3.7 million per 13
Rate Year respectively will shift from pre-tax expenses to capital 14
expenditures. 15
16
Direct Purchases of General Equipment 17
Q. What is general equipment? 18
A. General equipment includes personal computers and other computer 19
peripheral equipment, small tools and equipment, office furniture and 20
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equipment, shop, garage equipment, communications and other 1
miscellaneous items. 2
3
Q. Please summarize the Company’s current treatment of general 4
equipment. 5
A. The Company has different capitalization thresholds for different types of 6
general equipment. Currently, the Company capitalizes general equipment 7
purchases of $200 or more. The Company is proposing to increase the 8
threshold and capitalize purchases of $2,500 or more. 9
10
Q. Please explain the rationale for the accounting change. 11
A. The Company’s purchases of general equipment have increased over time 12
and cost inflation demands that capitalization thresholds increase 13
accordingly. 14
15
Q. What is the impact to the revenue requirement? 16
A. With the proposed change to accounting for general equipment, it is 17
forecast that approximately $4.3 million per year will shift from capital 18
expenditures to pre-tax expenses for the first three years after the change. 19
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Non-Utility Plant 1
Q. Please explain how Non-Utility Plant has been accounted for in this 2
filing. 3
A. The costs and carrying charges associated with Non-Utility Plant are 4
normally excluded from the cost of service used to determine the revenue 5
requirement. Pursuant to the Commission’s Order in Case 09-E-0593 6
issued and effective December 23, 2009, the Company has excluded costs 7
related to Non-Utility properties (with the exception of the properties 8
identified below) from the revenue requirement. The Company reviewed 9
the property included in FERC Account 121, Non-Utility Plant, and 10
identified that $52,200 of property tax costs were booked above the line in 11
the Historical Test Year. As shown on Schedule 1 of Exhibit __ (RRP-4), 12
the Company adjusted the Historical Test Year to remove these costs and 13
to exclude them from the forecast Rate Years. At this time, the Company 14
has not identified other O&M, capitalized or SIR costs that require 15
adjustment. As explained in the testimony of Company Witness Andrew 16
F. Sloey, the Company will continue to review the properties included in 17
FERC Account 121 and other accounts to determine if the properties are 18
properly classified and the costs are appropriately allocated. Any 19
adjustments based on this review will be provided in Corrections and 20
Updates submitted in this proceeding. To the extent properties are 21
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identified as providing benefits to customers through reduced SIR costs, 1
the Company will include in Corrections and Updates the proper 2
classification of these properties and the appropriate regulatory recovery 3
mechanisms for the associated costs. 4
5
With respect to the Texaco Tank Farm, the Company has removed 6
approximately $0.7 million of remediation expenditures included in the 7
Historical Test Year RWIP balance from the starting point of the forecast 8
of Net Utility Plant. Property taxes were removed as discussed above. 9
Additionally, the Historical Test Year Net Utility Plant Schedule 1 10
included in the Excess Earnings Base Exhibit __ (RRP-6) has been 11
adjusted accordingly. 12
13
Q. Did the Company identify any Non-Utility Plant costs in the SIR 14
deferral account? 15
A. Yes. The Company accounts for certain Non-Utility Plant remediation 16
costs in the SIR deferral account pursuant to agreements with Staff. The 17
Company includes incremental costs associated with remediation, 18
including current O&M and property taxes, if those costs were incurred to 19
mitigate SIR costs. For example, properties such as Gratwick Park, the 20
Rome Sentinel purchase and certain properties in the City of Saratoga 21
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Springs and City of Fulton were purchased to reduce the overall cost of 1
remediation. Therefore, the current O&M and property taxes associated 2
with these properties are properly included in the SIR Deferral account. 3
4
Assets and Liabilities 5
Q. Please explain Schedule 2 of Exhibit __ (RRP-6). 6
A. The Company proposes to amortize the December 31, 2010 balance of 7
certain existing regulatory deferral accounts, Attachment 11 Deferrals, 8
over the first 2 years of the Rate Plan. Exhibit __ (RRP-6) sets forth the 9
regulatory deferrals that will be recovered during the Rate Plan Period. 10
The Company is seeking to recover $701.4 million of net regulatory assets 11
over various amortization periods commencing at the beginning of Rate 12
Year 1. Beginning January 1, 2011, the unamortized balances, except for 13
non-cash Pension and OPEB items, are included in Rate Base. 14
Schedule 2 sets forth the monthly forecast balances of electric rate base 15
regulatory assets and liabilities for the Rate Years by account. 16
17
Q. Please describe each deferral. 18
A. Schedule 2 of Exhibit __ (RRP-6) details the basis for each of the existing 19
regulatory deferral accounts. Table 1 below sets forth each of the 20
accounts described in Exhibit __ (RRP-6), Schedule 2, Sheets 9 through 21
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58 and summarizes the actual deferral balance at the end of the Historical 1
Test Year and the forecast of the deferral balance through December 31, 2
2010. The accounts in Table 1 are set forth in Attachment 11 of the 3
Merger Rate Plan and are commonly referred to as “Attachment 11 4
Deferrals”. 5
Table 1 – Attachment 11 Deferrals 6
Existing Regulatory Deferral Accounts 7
Deferral Account
Actual Deferral Balance
Through 9/30/09
Additional Deferral Balance Through 12/31/10
Storm Restoration Costs $172 million No additional balance forecast
Power For Jobs Tax Credit $3.6 million No additional balance forecast
Customer Service Backout Credit (Pre-merger period)
$10.3 million No additional balance forecast
New York Power Authority (“NYPA”) Transmission Access Charge (“NTAC”) (Pre-merger period)
$13.1 million No additional balance forecast
New York Independent System Operator Tariff Schedule Costs- Schedules 1 and 2
$85.5 million and $13.3 million respectively
No additional balance forecast
Generation Sale Incentive $18.6 million No additional balance forecast
Low Income Discount Program $3.9 million $4.2 million Elevated Voltage Deferral Program $10.2 million $19.6 million Customer Service Backout Credit (Post merger period)
$109.8 million $117.7 million
Religious Rate Deferral $4.0 million $4.2 million City of Buffalo – Settlement Agreement
$0.7 million No additional balance forecast
SC-7 Standby Service Lost Revenue $12.2 million $14.6 million SC-7 Standby Service Lost Revenue Offset
($11.7 million) ($14.1 million)
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Deferral Account
Actual Deferral Balance
Through 9/30/09
Additional Deferral Balance Through 12/31/10
Site Investigation and Remediation Program Costs
$82.3 million $109 million
Generation Stranded Cost Adjustments $32.1 million $33.3 million Incentive Return on Retirement Funding
$70 million $85 million
Amortization of Regulatory Asset ($65 million) ($105 million) Incremental Capex $18.5 million Medicare Act Tax Benefit Deferred ($67.3 million) ($85.2 million) CSS-Conversion Service Penalties ($1.4 million) ($1.4 million) Electric Customer Service Penalties ($24 million) No additional
balance forecast PowerChoice Appendix E Netting ($86.7 million) No additional
balance forecast Electric deferral for Property Tax Normalization
($0.9 million) ($2.5) million
Loss on Sale of Building ($2.8 million) ($3.4 million) MRA Interest Savings Deferral ($92.5 million) No additional
balance forecast Petroleum Business Tax Audit Refund ($5.8 million) No additional
balance forecast Affiliate Rule Employee Transfer Credit
($0.2 million) No additional balance forecast
IRS Audit Refund Liability (89-90) ($0.05 million) No additional balance forecast
Electric Service Re-establishment Charge
($0.5 million) No additional balance forecast
Delay in Start Date ($12.5 million) No additional balance forecast
Currently Provided Incidental Services ($0.5 million) ($0.5 million) NYS Sales Tax Refund ($1.5 million) No additional
balance forecast Economic Development Fund ($33.9 million) ($38.4 million) Meter Read Connect/Disconnect Service Charge
($0.1 million) ($0.1 million)
NYPA MOU ($16.7 million) No additional balance forecast
Bonus Depreciation Adjustment ($24.3 million) ($27.8 million)
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Deferral Account
Actual Deferral Balance
Through 9/30/09
Additional Deferral Balance Through 12/31/10
Pension/OPEB Interest on Recovery ($4.1 million) No additional balance forecast
Station Service Sales Growth Deferral ($2.4 million) No additional balance forecast
NYS GRT Refund (91-94) ($3.3 million) No additional balance forecast
MHP Program Deferral ($0.4 million) ($0.6 million) New England Gas Merger Savings ($3.2 million) ($8.3 million) KeySpan Energy Merger Savings ($3.1 million) ($22.7 million) Gratwick Park Property Credit Zero ($0.04 million) 91-95 Federal Tax Refund – Electric ($2.4 million) ($18.1 million) 1
Q. How does the Company propose to treat the deferral account balances 2
as of December 31, 2010 for the accounts identified in Table 1 above? 3
A. The Company proposes an amortization period of 24 months. 4
5
Other Assets and Liabilities 6
Q. Please describe the other existing accounts shown in Exhibit __ (RRP-7
6), Schedule 2. 8
A. Schedule 2 of Exhibit __ (RRP-6) also provides a description of each of 9
these deferral accounts. Table 2 below summarizes the actual deferral 10
balance at September 30, 2009, forecast balance at December 31, 2010 11
and proposed treatment for that balance. 12
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Table 2 1
Account
Actual Account
Balance at 9/30/09
Forecast Account Balance through
12/31/10
Proposed treatment of
12/31/10 account balance
Enhanced Severance Plan
$0.05 million $0.025 million 12 month amortization period
Deferred Loss- Sale of Oswego
$0.9 million $0.4 million 24 month amortization period
NIMO-RPS Program Cost Deferred
$1.2 million Zero No request for amortization
NY- Electric Data Interchange cost
$3.8 million No additional balance forecast
24 month amortization period
NY Merger Empl Separation Cost
$1.9 million $0.7 million 12 month amortization period
NY Merger Rate Plan Stranded Cost
$1,201.4 million $557 million 4 years
RDV- Transmission
$3.3 million $9.5 million 3+ years
Transmission Hydro-One Transformer Project5
$4.1 million 36 months
Electric R&D Ventures Deferral
($0.03 million) No additional balance forecast
24 month amortization period
NIMO-Purchase ERC’s Economic Development
($1 million) No additional balance forecast
24 month amortization period
NIMO- Gain- ($0.4 million) ($0.3 million) The Company will
5 The Company is requesting authority to capitalize costs of operation and maintenance expense associated with the work the Company is performing for Hydro-One and requests to defer and amortize those costs over three years. These costs are included in the testimony of the Infrastructure and Operations Panel.
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Account
Actual Account
Balance at 9/30/09
Forecast Account Balance through
12/31/10
Proposed treatment of
12/31/10 account balance
Redempt-8.35% Bonds
continue to amortize bonds at the current level of $60,460 per year based on the maturity of the bonds in December 2015.
NIMO IRS Audit Refund (83-84)
($0.3 million) No additional balance forecast
24 month amortization period
NIMO – Exit Fees Deferred
($3.4 million) ($1.4 million) Maintaining current amortization, this balance will be fully amortized in Rate Year 1.
Voltage Migration Fee Deferred
($0.02 million) ($0.02 million) The Company will continue to amortize at the current level of $1,368 annually.
Unbilled Revenue- Electric
$143.9 million No additional balance forecast
No request for amortization.
TCC Auction Revenue
($19.6 million) ($36 million) Projected revenues and amortization levels remain the same and there is no request for additional amortization.
NY-Nuclear Fuel Disposal Costs
($167.2 million) ($167.6 million) The Company is not proposing to amortize the balance.
1
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Q. Please explain the remaining regulatory accounts. 1
A. As shown in Schedule 2 of Exhibit __ (RRP-6), the following accounts 2
have a zero forecast balance at December 31, 2010 and no recovery is 3
sought in base rates for these accounts: 4
• New York Power Authority Hydropower Benefit Reconciliation; 5
• Systems Benefit Charge Program Cost; 6
• Excessive AFUDC Electric Plant in Service; 7
• Environmental Insurance Recovery – Net; 8
• CTC Reset Reserve; 9
• Service Aggregation Lost Revenue; and 10
• Large Project Salvage. 11
12
Deferred Taxes 13
Q. Please explain Schedule 3. 14
A. Schedule 3 shows the average Electric Accumulated Deferred Income 15
Taxes (“ADIT”) that serve to reduce Rate Base as presented in Exhibit __ 16
(RRP-6). 17
18
Q. Was the new Bonus Tax Depreciation allowed under the Economic 19
Stimulus Act provided in the calculation of tax depreciation for the 20
Rate Year? 21
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A. Yes, but for Federal Income Tax purposes only. The assumption was 1
made that New York State will elect to decouple and not allow bonus 2
depreciation deductions. 3
4
Q. How was the Provision for ADIT beyond the Historical Test Year 5
developed? 6
A. The forecast for ADIT for the Rate Year was based upon actual balances 7
at September 30, 2009. It was then forecast through the Rate Years. 8
9
Q. What major items are included in the ADIT balances for the 10
forecasted Rate Years? 11
A. ADIT includes the difference between normal book to tax depreciation, 12
any changes in regulatory assets related to book to tax changes and the 13
change relating to the increase in deferred income tax credit associated 14
with repair costs. 15
16
Q. Please explain the income tax credit associated with repair costs. 17
A. In its Fiscal Year 2009 Federal Income Tax return filed December 11, 18
2009, National Grid Holdings, Inc. changed its method of accounting for 19
routine repair maintenance costs deductible under Internal Revenue Code 20
Section 162 that had been capitalized and depreciated. In connection with 21
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this change, National Grid Holdings, Inc recorded a one-time tax expense, 1
included in repairs and maintenance costs, equal to the undepreciated 2
amount of prior costs of this nature on its books at the time of the change. 3
This change results in a $2.3 billion reduction in National Grid Holdings, 4
Inc.’s taxable income for Fiscal Year 2009. The resulting tax benefit for 5
Niagara Mohawk is approximately $200 million. 6
7
Q. How is the Company accounting for this tax credit? 8
A. The Company is crediting accumulated deferred taxes by approximately 9
$200 million, representing its portion of the tax benefit. The Company 10
recognizes that the Company’s tax position is subject to audit and 11
adjustment by the Internal Revenue Service. The Company is providing 12
the full benefit of the tax credit (i.e. reduction in rate base) to customers in 13
the Rate Years, but requests authorization to defer for future recovery the 14
amount of any future adjustments or disallowance with carrying charges at 15
the weighted average cost of capital approved in this proceeding. 16
17
Working Capital 18
Q. Have you recognized any cash allowance requirements associated with 19
electric power purchases? 20
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A. Schedule 5 presents the calculation of the carrying charge applicable to the 1
working capital requirements associated with electric power purchases 2
based on the lead-lag study data contained in this schedule. 3
4
Q. What is the lead-lag study used to measure? 5
A. The lead-lag study is used to measure the working capital needed by the 6
Company to support its electric power purchases. The Company is 7
required to provide working capital for the number of days between the 8
time the Company pays its suppliers for electric power purchases and the 9
time the Company receives payments for such purchases from its 10
customers. The results of the study are used in determining the return 11
requirement on working capital related to purchased electric power 12
expense. 13
14
Inflation Factors 15
Q. Please explain Exhibit __ (RRP-7). 16
A. Exhibit __ (RRP-7) sets forth the table of inflation factors used to escalate 17
expense and capital expenditures from the Historical Test Year to the Rate 18
Years. The Exhibit consists of a Summary Sheet detailing the escalation 19
rates. The cost adjustment factors reflecting changes in price levels as 20
forecast in the Blue Chip Economic Indicators were utilized to escalate 21
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various elements of the cost of service, as discussed in the testimony of 1
Dr. Alfred P. Morrissey. 2
3
Proposed Treatment of Existing Regulatory Deferral Accounts and 4
New Reconciliation Mechanisms 5
Q. Please describe the use and nature of Regulatory Deferral Accounts. 6
A. Regulatory Deferral Accounts are used to track and reconcile expenses 7
and associated revenue recoveries to ensure that the proper amount of 8
costs is recovered from customers. As discussed above, Niagara Mohawk 9
has a number of deferral accounts previously approved in the Merger Rate 10
Plan or in various Commission orders. This section of the testimony will 11
discuss the following: 12
1. the Company’s proposal to maintain or discontinue existing 13
accounts, 14
2. the Company’s proposal for new regulatory reconciliation accounts 15
for certain significant expenses, 16
3. the Company’s proposal to include a return on any balances in the 17
accounts using the weighted average cost of capital established in 18
this proceeding and 19
4. the Company’s proposed recovery mechanism for these accounts. 20
21
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Q. Is the Company proposing to continue existing deferral mechanisms? 1
A. Yes, the Company proposes to continue deferring for recovery or refund 2
amounts above or below the rate allowances established in this proceeding 3
associated with SIR Expenses, Pension Expenses and OPEB Expenses. 4
As discussed later in our testimony, the Company proposes to recover or 5
refund amounts associated with these deferral accounts through the 6
Electric Delivery Adjustment Mechanism. The Company also seeks to 7
fully reconcile the Low Income Discount Allowance and the Economic 8
Development Fund. The Company further seeks to defer for credit to 9
customers any Service Quality Penalties incurred during the Rate Plan 10
Period. Exhibit __ (RRP-8), Schedule 3 sets forth the Company’s 11
proposal for the SIR deferral mechanism. The Company also proposes to 12
maintain the current ratemaking treatment of the following accounts: 13
• NYISO Tariff Schedule Costs - Schedules 1 and 2 for any NYISO 14
Rebills; 15
• Generation Stranded Cost Adjustments; 16
• RPS Program Costs; 17
• Exit Fees; 18
• Aggregation Fees; 19
• Voltage Migration Fees; 20
• NYPA Residential Hydropower Benefit Reconciliation; 21
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• SBC Program Cost; and 1
• Transmission Revenue Adjustment Charge. 2
3
In addition, the Company proposes certain commodity-related 4
reconciliation accounts as discussed in the testimony of the Rate Design 5
and Customer and Markets Panel. 6
7
Furthermore, the Company proposes to continue deferring the Revenue 8
Requirement impacts of any Mandated Regulatory, Legislative or 9
Accounting Changes or changes in industry standards (“Exogenous 10
Event”) that occur during the Rate Plan Period that individually have an 11
annual impact of $5.0 million or greater. 12
13
Q. What is the Company’s proposal with respect to the other existing 14
accounts? 15
A. The Company proposes to discontinue the following accounts because 16
they will no longer apply as of Rate Year 1 (i.e., no additional balance is 17
forecast beyond December 31, 2010): 18
• Power For Jobs Tax Credit 19
• Customer Service Backout Credit (Pre-merger period) 20
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• New York Power Authority Transmission Access Charge (Pre-1
merger period) 2
• Elevated Voltage Deferral 3
• Customer Service Backout Credit (Post merger period) 4
• Religious Rate Deferral 5
• City of Buffalo – Settlement Agreement 6
• SC-7 Standby Service Lost Revenue and offset 7
• Generation Sale Incentive 8
• Incentive Return on Retirement Funding 9
• Amortization of Regulatory Assets 10
• Medicare Act Tax Benefit Deferred 11
• CSS-Conversion Service Penalties 12
• Power Choice Appendix E netting 13
• Electric deferral for Property Tax Normalization 14
• Loss on Sale of Building 15
• MRA Interest Savings Deferral 16
• Petroleum Business Tax Audit Refund 17
• Affiliate Rule Employee Transfer Credit 18
• IRS Audit Refund Liability (1989-1990) 19
• Electric Service Re-establishment Charge 20
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• Delay in Start Date 1
• Currently Provided Incidental Services 2
• NYS Sales Tax Refund 3
• Meter Read/Disconnect Service Charge 4
• NYPA MOU 5
• Bonus Depreciation Adjustment 6
• Pension/OPEB Interest on Recovery 7
• Station Services Sales Growth Deferral 8
• NYS GRT Refund (1991-1994) 9
• New England Gas Merger Savings 10
• KeySpan Energy Merger Savings 11
• Gratwick Park Property Credit 12
• 1991-1995 Federal Tax Refund – Electric 13
• Enhanced Severance Plan 14
• Deferred Loss-Sale of Oswego Fire School 15
• NY-Electric Data Interchange Cost 16
• NY Merger Employee Separation Cost 17
• Electric R&D Ventures Deferral 18
• Purchase ERC’s Economic Development 19
• Gain-Redempt.-8.35% Bonds 20
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• IRS Audit Refund (1983-1984) 1
• Excess AFUDC Electric Plan in Service (1991- 1996) 2
3
Q. Is the Company proposing any new deferral mechanisms in this 4
filing? 5
A. Yes. The Company is proposing annual reconciliation of incremental 6
costs associated with Capital Expenditures, Bad Debt, Property Taxes, 7
Storm Costs, Variable Pay, Interest on Pollution Control Auction Debt and 8
Changes to the Service Company Allocation Methodology. The 9
mechanism for refund or recovery will be the Electric Delivery 10
Adjustment Mechanism (“EDAM”) described below with the exception of 11
commodity related bad debt expense, which will be recovered through the 12
Merchant Function Charge as discussed in the testimony of the Rate 13
Design and Customer and Markets Panel. 14
15
Q. Please explain Exhibit __ (RRP-8). 16
A. Exhibit __ (RRP-8) consists of 6 Schedules. Schedule 1 presents an 17
example of the calculation of the Capital Investment reconciliation. 18
Schedule 2 shows the annual thresholds for the Property Tax, Variable 19
Pay, Low Income, Pension, Other Post Employment Benefits, SIR, and 20
Economic Development deferral accounts. Schedule 3 shows the Storm 21
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Fund threshold and recovery mechanism. Schedule 4 presents an example 1
of the recovery mechanism for the Auction Rate Debt. Schedule 5 reflects 2
the exclusion of labor expense from the SIR deferral account. Schedule 6 3
reflects the proposed RDM threshold after the Rate Plan Period. 4
5
Q. Please explain the Company’s proposal to defer incremental costs 6
associated with Capital Expenditures. 7
A. Subject to a 10 percent cap described below, the Company proposes to 8
reconcile annually the difference between x) the net revenue requirement 9
(including return on assets, depreciation expense, deferred taxes, and any 10
operating expense related to capital expenditures, including those relating 11
to third party actions) associated with actual capital expenditures in the 12
subject Rate Year and y) the net revenue requirement associated with 13
capital expenditures approved by the Commission for the Rate Year, and 14
to refund to or recover from customers the difference. The Company 15
proposes that the annual amount to be recovered be capped to the extent 16
that it is caused by actual capital expenditures exceeding approved capital 17
expenditures in such Rate Year by more than 10 percent, subject to limited 18
exceptions, as shown in Schedule 1 of Exhibit __ (RRP-8) (“10 Percent 19
Cap”). The maximum additional amounts to be recovered under this 20
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provision, expect as provided below, are shown on Exhibit __(RRP- ), 1
Schedule 4. 2
3
The Company proposes that the 10 Percent Cap not apply to the extent the 4
difference in the net revenue requirement is caused by third-party actions 5
that trigger the need for capital expenditures. The calculation of the 6
reconciliation will be adjusted to exclude any Exogenous Event, as shown 7
in Schedule 1 of Exhibit __ (RRP-8). 8
9
Q. Please explain the reasons for the Company’s proposal to track and 10
reconcile capital investments to actual investments. 11
A. The Company’s proposed reconciliation mechanism will facilitate the 12
provision of safe and reliable service to customers at just and reasonable 13
rates, and will mitigate risk to the Company’s financial health. The 14
Company’s proposal protects customers from unforeseen large capital 15
expenditures and provides discipline to drive the Company to achieve 16
targeted spending, but provides for circumstances largely beyond the 17
Company’s control. 18
19
Without the Company’s proposed reconciliation mechanism, it may be 20
faced with having to delay projects that benefit customers to address 21
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factors largely outside its control. As discussed in the testimony of the 1
Infrastructure & Operations Panel, the Company’s proposed reconciliation 2
mechanism allows the Company to provide safe, reliable service to 3
customers over the Rate Plan Period with acceptable levels of financial 4
risk to the Company. 5
6
The flexibility provided by the 10 Percent Cap would address cases where 7
changed circumstances significantly impact Niagara Mohawk’s ability to 8
execute its infrastructure investment plan, such as unforeseen reliability 9
events on the system or unforeseen price increases for equipment or 10
services. The Company’s proposal does not create an open checkbook, 11
but rather incorporates a reasonable cap on reconcilable costs to recognize 12
that the actual capital expenditures will likely differ from the amounts 13
including in the approved revenue requirement. 14
15
Q. Please explain the Company’s proposal to reconcile above the 10 16
Percent Cap for capital expenditures that arise from third party 17
actions. 18
A. The Infrastructure and Operations Panel discusses situations when 19
reliability improvements made to one utility’s system can have a ripple 20
effect on neighboring systems. For instance, in order for one utility’s 21
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project to be put into service, the completion of related upgrades on a 1
neighboring system may be required. The Company proposes that it be 2
permitted to include in the reconciliation the net revenue requirement 3
associated with capital expenditures that exceed the 10 Percent Cap to the 4
extent that the excess was caused by third-party action. This will assure 5
that unanticipated capital expenditures caused by third-party actions will 6
not crowd out projects that will strengthen or enhance the system for the 7
benefit of customers. 8
9
Q. In developing this proposal, did the Company consider the issues 10
raised in the recent Management Audit of Niagara Mohawk 11
regarding the Company’s ability to estimate capital investment 12
projects and manage those projects for efficient delivery of its capital 13
plan? 14
A. Yes. The Company evaluated and considered the Findings and 15
Recommendations from the Management Audit in developing this 16
reconciliation proposal. Mr. Zschokke’s stand-alone testimony addresses 17
our efforts to improve capabilities in these areas and address the concerns 18
raised by the Audit. 19
20
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Q. Please discuss Commission precedent regarding capital investment 1
trackers and how the Company’s proposal addresses it. 2
A. Recently, the Commission has approved downward-only adjustment 3
capital trackers to reimburse customers for capital investment under 4
spending. The Commission did approve a capital tracker that allowed 5
recovery of additional investment in Case 07-E-0523 for Consolidated 6
Edison of New York (“Con Edison”). However, Con Edison’s actual 7
investments were significantly greater than the approved budget for the 8
rate plan years 2004-2006. 9
10
To address the Commission’s concerns, Niagara Mohawk proposes the 10 11
Percent Cap on its ability to reconcile for differences between actual and 12
approved capital expenditures. The 10 Percent Cap is designed to balance 13
the fact that a number of factors may affect the Company’s ability to 14
deliver its capital expenditures plan at the spending target with the 15
recognition that open-ended, two-way capital expenditure reconciliation 16
mechanisms have not been favored by the Commission in recent years. 17
This approach protects customers by limiting the Company’s ability to 18
recover capital expenditures above approved amounts while providing 19
flexibility for the Company to accommodate unforeseen events or 20
unforeseen price increases for equipment or services. 21
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Moreover, the Company will continue the quarterly review of progress on 1
its Capital Investment Plan with Commission Staff, as required by the 2
Commission’s August 15, 2008 order in Case 06-M-0878. The Company 3
fully recognizes its burden to demonstrate that its investments are 4
appropriate and efficiently delivered and that any investment above the 5
approved budget was necessary and efficiently managed. The reporting 6
process in place provides Staff with the opportunity to review the 7
Company’s progress on annual investment plans by project and require 8
explanations for any changes to the investment plan. Any significant 9
investment that arises during the Rate Plan will be discussed with Staff at 10
our quarterly meetings. Staff will be apprised of any additional 11
investments for which the Company seeks recovery through the 12
reconciliation mechanism. We believe that the combination of the 10 13
Percent Cap and the quarterly review meetings to discuss progress on the 14
investment plan with Staff should allay the Commission’s concerns 15
regarding a two-way tracker on infrastructure investment. 16
17
Q. Please explain the Company’s proposal to defer incremental costs 18
associated with Bad Debt. 19
A. As discussed in the testimony of Company Witness Rudolph Wynter, the 20
Company forecast the net write-off rate for each of the three years of the 21
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Rate Plan at 1.687 percent of total tariff, late payment and purchase of 1
receivables revenues. The Company proposes a full reconciliation for 2
recovery of incremental bad debt costs associated with commodity 3
revenues through the Merchant Function Charge, as discussed in the 4
testimony of the Rate Design and Customer and Markets Panel. The 5
Company is not proposing this reconciliation with respect to transmission 6
and distribution delivery revenues. Commodity-related bad debt expense 7
would be reconciled annually to the net write-off rate established in this 8
case and for changes in commodity prices. 9
10
Q. Please explain the Company’s proposal to defer incremental or 11
decremental costs associated with Property Taxes. 12
A. The Company proposes to reset base rates to reflect $141.8 million, 13
$150.9 million and $162.6 million of real property and special franchise 14
taxes in the Rate Years respectively. The Company has a very limited 15
ability to control these expenses. In light of current economic conditions, 16
state budget cuts and significant increases in plant additions, the Company 17
proposes to reconcile for refund or recovery any difference between its 18
actual expenses and the forecasted Rate Year levels. Schedule 2 of 19
Exhibit __ (RRP-8) shows the threshold for this deferral account. The 20
reconciliation mechanism also protects customers if property taxes fall as 21
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a result of capital investment that is below the rate allowance or other, 1
unanticipated events. 2
3
Q. Please explain the Company’s proposal to defer incremental costs 4
associated with Storm costs and other items. 5
A. The Company proposes establishing a fully reconciling storm fund by 6
including an annual amount of $30 million in the revenue requirement, to 7
offset the costs of responding to “major storms,” as defined in the 8
testimony of the Infrastructure and Operations Panel. This annual storm 9
fund amount is approximately 88 percent of the average annual amount of 10
major storm costs that have been eligible for deferral during the same 4.5 11
year period. 12
13
Q. How would the storm fund operate? 14
A. As discussed in the testimony of the Infrastructure and Operations Panel, 15
the Company would include $30 million in base rates and would add this 16
amount to the general ledger storm fund account. Only major storm costs 17
would be assessed against this account balance. If the balance of the 18
storm fund falls below zero as of December 31 of any year because of 19
major storm costs, the Company would recover an amount to bring the 20
fund balance to zero through the EDAM described below. Schedule 3 21
104
Testimony of The Revenue Requirements Panel
Page 104 of 110
presents the threshold level and recovery mechanism. Further details of 1
the storm fund are addressed in the testimony of the Infrastructure and 2
Operations Panel. 3
4
Q. Does the Company propose to reconcile and defer variable pay? 5
A. As discussed in the testimony of Mr. King and Ms. Heaphy, the Company 6
proposes to defer and credit to customers any unpaid variable 7
compensation amounts reflected in rates, plus the appropriate carrying 8
charges, that are not paid to employees for any reason. Schedule 4 9
presents the threshold level. 10
11
Q. Please explain the Company’s proposal to reconcile Interest for 12
Pollution Control Auction Debt. 13
A. As discussed in the testimony of Company Witness Andrew Dinkel and 14
shown in Schedule 4 of Exhibit __(RRP-8), the Company proposes that 15
the variable rate interest expense on auction rate debt and associated fees 16
allocated to electric operations be fully reconciled. Any difference 17
between the actual expense and the level reflected in rates will be deferred 18
and recovered or credited through the EDAM. 19
20
105
Testimony of The Revenue Requirements Panel
Page 105 of 110
Q. Please explain the Company’s proposal to reconcile costs associated 1
with changes to the Service Company allocation methodology? 2
A. As discussed in the testimony of Company Witness Andrew F. Sloey, the 3
Company is planning to consolidate the service companies and move to 4
one common cost allocation methodology. The Company proposes to 5
debit or credit to the EDAM any cost shifting to or from Niagara Mohawk 6
electric operations resulting from the change in allocation methodology. 7
Costs charged to Niagara Mohawk under the existing service company 8
allocation methodology would be calculated at the time of the change, and 9
the difference between those costs and the costs allocated under any new 10
allocation methodology, applied to the most recent annual historic service 11
company costs, would be included on the EDAM. 12
13
Q. What does the Company propose with respect to these various new 14
reconciliation mechanisms for the years following the Rate Plan 15
Period? 16
A. The reconciliation mechanisms would continue to operate in the years 17
after the Rate Plan. The Company will use the authorized revenue 18
requirement in Rate Year 3 of the Rate Plan as the baseline costs in each 19
year after the Rate Plan for every account except capital investment. For 20
106
Testimony of The Revenue Requirements Panel
Page 106 of 110
capital investment, the Company will propose a level of investment and 1
associated revenue requirement for each subsequent calendar year. 2
3
Q. Please explain the process to request and approve the revenues 4
associated with capital investment in the post-Rate Plan Period. 5
A. The Company requests authority to annually update its Capital Investment 6
to recover the associated incremental or decremental revenue requirement 7
post Rate Plan through the EDAM for the years following the Rate Plan 8
(“Capital Investment Update”). The Company currently submits its five 9
year Capital Investment Plan on January 31 each year. The Company 10
proposes to file its Capital Investment Update in the first quarter of each 11
year (beginning in the first quarter of Rate Year 3) for recovery of the 12
associated revenue requirement effective January 1 the following year. 13
Each year the Company will document the Capital Investment forecast for 14
the subsequent year and the associated revenue requirement. Every year 15
the Company will reconcile the prior year actual investment with the 16
amount approved for recovery in the same manner as proposed for the 17
Rate Plan Period. Any prospective revenue increase or decrease approved 18
as a result of the Capital Investment Update filing would flow through the 19
EDAM as explained below. Any changes to the revenue requirement 20
107
Testimony of The Revenue Requirements Panel
Page 107 of 110
resulting from the reconciliation of actual capital investment to the prior 1
year rate allowance will be reflected in the EDAM as well. 2
3
Q. If the Company has not filed to reset base rates to take effect in the 4
year ending December 31, 2014, how does the Company propose to 5
treat stranded costs in that year? 6
A. At the end of Rate Year 3, the revenue requirement will include $198 7
million of fixed CTC costs and the Company’s remaining balance will be 8
approximately $63 million. As shown on Schedule 6 of Exhibit __ (RRP-9
8), the Company therefore proposes on January 1, 2014 to credit 10
customers approximately $132 million to reflect the actual remaining 11
balance of stranded costs. Schedule 6 also shows a credit to customers on 12
January 1, 2015 bringing the fixed stranded costs to zero. The Company 13
will apply this reduction to base rates pro rata by service classification 14
based on the forecast of revenues associated with fixed CTC. 15
16
Q. How does the Company propose to perform the annual reconciliation 17
for the deferral accounts? 18
A. The Company proposes to reconcile and recover the incremental costs 19
through a new mechanism called the Electric Delivery Adjustment 20
Mechanism (“EDAM”). The EDAM will be computed by the sum of the 21
108
Testimony of The Revenue Requirements Panel
Page 108 of 110
year-end balances in all deferral and reconciliation accounts plus interest 1
accrued on that balance in the year the charge or credit is collected or 2
refunded to customers. The resulting sum will be allocated to each rate 3
class as discussed in the testimony of the Rate Design and Customer and 4
Markets Panel. An example of this calculation is provided in Exhibit __ 5
(RDCM-9). The Company proposes to file the reconciliation annually 6
with the Commission after January 1 for rates effective April 1. 7
8
Q. Is the Company proposing any carrying charges associated with the 9
total net deferral recovery? 10
A. Yes. To the extent that the Company has funded the deferral accounts, 11
except for non-cash Pension and non-cash OPEB items, carrying charges 12
calculated at the weighted average cost of capital used to set rates in this 13
case should be applied. 14
15
Q. Why are Pension and OPEB assets and liabilities exempt from 16
carrying charges? 17
A. Pursuant to the Commission’s Policy Statement on Pension and OPEBs, 18
utilities need only fund the respective trusts when the amounts deferred 19
are collected from customers. Therefore, because the Company has not 20
yet paid cash to fund the deferred amount, no carrying charge is 21
109
Testimony of The Revenue Requirements Panel
Page 109 of 110
warranted. When the Company recovers the deferral, it places the funds 1
into the Pension or OPEB trusts. 2
3
Q. Please explain Schedule 6 of Exhibit __ (RRP-8). 4
A. Schedule 6 presents the general inflation example discussed by Company 5
Witness Dr. Susan Tierney relating to the Company’s proposal for a cost-6
side adjustment to revenue associated with inflationary pressures on 7
operating expenses within the Revenue Decoupling Mechanism for the 8
post-Rate Plan Period. 9
10
Historical Financial Data 11
Q. Please describe Exhibit ___ (RRP-9). 12
A. Exhibit____ (RRP-9) consists of 12 schedules that set forth various 13
historical financial data in accordance with Commission regulations. 14
15
Workpapers 16
Q. Please describe Exhibit __ (RRP-10). 17
A. Exhibit __ (RRP-10) contains the workpapers supporting the exhibits 18
sponsored by this Panel. 19
110
Testimony of The Revenue Requirements Panel
Page 110 of 110
Update 1
Q. Does the Company propose to update any information throughout 2
this proceeding? 3
A. Yes. The Company proposes to update the regulatory deferral accounts if 4
necessary. This is consistent with updates made in prior Company rate 5
cases. If necessary, additional updates will be provided as appropriate. 6
7
Q. Does this conclude your direct testimony? 8
A. Yes it does. 9
111
Exhibits of
R
evenue Requirem
ents Panel
Testimony of the Revenue Requirements Panel
Index of Exhibits Exhibit __ (RRP-1) Statement of Electric Operating Income, by
Component, for the Year Ended September 30, 2009 and Rate Years Ending December 31, 2011, December 31, 2012 and December 31, 2013
Exhibit __ (RRP-2) Operating and Maintenance Expenses by Expense Type
for the Year Ended September 30, 2009 and Rate Years Ending December 31, 2011, December 31, 2012 and December 31, 2013
Exhibit __ (RRP-3) Electric Depreciation Expense for the Year Ended
September 30, 2009 and Rate Years Ending December 31, 2011, December 31, 2012 and December 31, 2013
Exhibit __ (RRP-4) Taxes Other than Income Taxes for the Year Ended
September 30, 2009 and Rate Years Ending December 31, 2011, December 31, 2012 and December 31, 2013
Exhibit __ (RRP-5) Federal and State Income Taxes for the Year Ended
September 30, 2009 and Rate Years Ending December 31, 2011, December 31, 2012 and December 31, 2013
Exhibit __ (RRP-6) Electric Rate Base for the Year Ended September 30,
2009 and Rate Years Ending December 31, 2011, December 31, 2012 and December 31, 2013
Exhibit __ (RRP-7) Table of Inflation Factors Exhibit __ (RRP-8) Deferral Account Exhibit Exhibit __ (RRP-9) Various Historic Financial Exhibits for the Calendar
Years 2004 Through 2008 Exhibit __ (RRP-10) Workpaper Data Supporting Certain Exhibits Exhibit __ (RRP-11) Resume of Howard Gorman
112
Exhibit __ (R
RP-1)
Exhibit (RRP-1) Witness: Revenue Requirement Panel
NIAGARA MOHAWK POWER COPORATION d/b/a NATIONAL GRID
Statement of Electric Operating Income, By Component, for the
Year Ended September 30, 2009 and Rate Years Ending December 31, 2011,
December 31, 2012 and December 31, 2013 Summary Dated: January 29, 2010
113
Exh
ibit
(
RR
P-1)
Sum
mar
ySh
eet 1
of 4
Adj
. to
Nor
mal
ize
Rat
e Y
ear E
ndin
g H
isto
ric Y
ear a
ndB
ase
Rev
enue
Dec
embe
r 31,
201
1Ex
hibi
tH
isto
ric Y
ear E
nded
Ref
lect
Con
ditio
nsR
ate
Yea
r End
ing
Incr
ease
with
Bas
e R
even
ueR
efer
ence
Sept
embe
r 30,
200
9in
the
Rat
e Y
ear
Dec
embe
r 31,
201
1R
equi
red
Req
uire
men
t
Ope
ratin
g R
even
ues
2,98
1,23
2$
237,
720
$
3,
218,
952
$
-$
3,21
8,95
2$
Ded
uctio
nsPu
rcha
sed
Pow
er C
osts
919,
609
72,4
4899
2,05
799
2,05
7R
even
ue T
axes
32,8
7296
233
,834
033
,834
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tal D
educ
tions
952,
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73,4
101,
025,
891
01,
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ss M
argi
n2,
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164,
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2,19
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1
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l Ope
ratio
n &
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nten
ance
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ense
s83
4,38
927
8,15
61,
112,
545
01,
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545
Am
ortiz
atio
n of
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ulat
ory
Def
erra
ls59
1,61
4(3
46,2
54)
245,
360
245,
360
Dep
reci
atio
n, A
mor
t. &
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s on
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posi
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183,
478
14,0
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7,52
119
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1
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er T
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146,
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13,8
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8
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1,75
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715,
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g In
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e B
efor
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e Ta
xes
273,
033
204,
544
477,
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-
47
7,57
7
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me
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l Inc
ome
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s12
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212
0,16
20
120,
162
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e In
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26,7
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$
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(0)
$
330,
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$
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e B
ase
4,56
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(448
,313
)$
4,11
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4,
118,
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$
Rat
e of
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urn
5.98
%8.
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%
Ret
urn
On
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ty7.
00%
11.1
0%11
.10%
NIA
GA
RA
MO
HA
WK
PO
WE
R C
OR
POR
AT
ION
d/b
/a N
AT
ION
AL
GR
ID (C
OM
PAN
Y 3
6)St
atem
ent o
f Ele
ctri
c O
pera
ting
Inco
me
For
the
Yea
r E
nded
Sep
tem
ber
30, 2
009
and
the
Rat
e Y
ear
End
ing
Dec
embe
r 31
, 201
1($
000'
s)
Exhibit (RRP-1) Summary Sheet 1 of 4
114
Exh
ibit
(
RR
P-1)
Sum
mar
ySh
eet 2
of 4
Rat
e Y
ear E
ndin
g B
ase
Rev
enue
Dec
embe
r 31,
201
2Ex
hibi
tR
ate
Yea
r End
edR
efle
ct C
ondi
tions
Rat
e Y
ear E
ndin
g In
crea
sew
ith B
ase
Rev
enue
Ref
eren
ceD
ecem
ber 3
1, 2
011
in th
e R
ate
Yea
r 2D
ecem
ber 3
1, 2
012
Req
uire
dR
equi
rem
ent
Ope
ratin
g R
even
ues
3,21
8,95
2$
38,9
79$
3,
257,
931
$
-$
3,25
7,93
1$
Ded
uctio
nsPu
rcha
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er C
osts
992,
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even
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axes
33,8
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tal D
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9
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ss M
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s1,
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ortiz
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ulat
ory
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e B
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477,
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9
-
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l Inc
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ate
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me
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ase
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$
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$
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6,59
6$
Rat
e of
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urn
8.03
%8.
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8.27
%
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urn
On
Equi
ty11
.10%
11.1
0%11
.10%
NIA
GA
RA
MO
HA
WK
PO
WE
R C
OR
POR
AT
ION
d/b
/a N
AT
ION
AL
GR
ID (C
OM
PAN
Y 3
6)St
atem
ent o
f Ele
ctri
c O
pera
ting
Inco
me
For
the
Rat
e Y
ear
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ed D
ecem
ber
31, 2
011
and
the
Rat
e Y
ear
End
ing
Dec
embe
r 31
, 201
2($
000'
s)
Exhibit (RRP-1) Summary Sheet 2 of 4
115
Exh
ibit
(
RR
P-1)
Sum
mar
ySh
eet 3
of 4
Rat
e Y
ear E
ndin
g B
ase
Rev
enue
Dec
embe
r 31,
201
3Ex
hibi
tR
ate
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r End
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efle
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ondi
tions
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ear E
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ith B
ase
Rev
enue
Ref
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ecem
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in th
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ate
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r 3D
ecem
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013
Req
uire
dR
equi
rem
ent
Ope
ratin
g R
even
ues
3,25
7,93
1$
59,9
60$
3,
317,
891
$
-$
3,31
7,89
1$
Ded
uctio
nsPu
rcha
sed
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er C
osts
1,00
6,93
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,436
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Rev
enue
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es34
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l Ded
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ss M
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s1,
114,
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451,
114,
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114,
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Am
ortiz
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n of
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ulat
ory
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ls21
8,15
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1,05
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7,09
918
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9
Dep
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mor
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209,
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9
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l Inc
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ate
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me
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ase
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975
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urn
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%
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urn
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ty11
.10%
11.1
0%11
.10%
NIA
GA
RA
MO
HA
WK
PO
WE
R C
OR
POR
AT
ION
d/b
/a N
AT
ION
AL
GR
ID (C
OM
PAN
Y 3
6)St
atem
ent o
f Ele
ctri
c O
pera
ting
Inco
me
For
the
Rat
e Y
ear
End
ed D
ecem
ber
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012
and
the
Rat
e Y
ear
End
ing
Dec
embe
r 31
, 201
3($
000'
s)
Exhibit (RRP-1) Summary Sheet 3 of 4
116
Niagara Mohawk Power Corporation d/b/a NATIONAL GRID (Company 36)Capital Structure
Exhibit (RRP-1)Summary
Sheet 4 of 4
123 Electric Rate Case Capital Structure 4 last update: 5 Total NM Weighting Weighted6 Annual Avg Percent Cost Cost7 Long Term Debt 1,978,321$ 48.04% 5.03% 2.42% 2.42%8 Notes Payable 33,768 0.82% 2.21% 0.02% 0.02%9 Gas Supplier Refunds - 0.00% 0.00% 0.00% 0.00%
10 Customer Deposits 26,356 0.64% 2.45% 0.02% 0.02%11 Preferred Stock 21,002 0.51% 3.62% 0.02% 0.03%12 Common Equity 2,058,624 49.99% 11.10% 5.55% 9.19%1314 Total $4,118,071 100.00% 8.0300% 11.68%15 =====================================================================================================
Revenue Requirement of $0
123 Electric Rate Case Capital Structure 4 last update: 5 Total NM Weighting Weighted6 Annual Avg Percent Cost Cost7 Long Term Debt 2,006,151$ 46.91% 5.58% 2.62% 2.62%8 Notes Payable 82,538 1.93% 3.28% 0.06% 0.06%9 Gas Supplier Refunds - 0.00% 0.00% 0.00% 0.00%
10 Customer Deposits 26,515 0.62% 2.45% 0.02% 0.02%11 Preferred Stock 21,383 0.50% 3.62% 0.02% 0.03%12 Common Equity 2,140,009 50.04% 11.10% 5.55% 9.19%1314 Total $4,276,596 100.00% 8.27% 11.92%15 =====================================================================================================
Revenue Requirement of $0
123 Electric Rate Case Capital Structure 4 last update: 5 Total NM Weighting Weighted6 Annual Avg Percent Cost Cost7 Long Term Debt 2,014,649$ 44.83% 6.12% 2.74% 2.74%8 Notes Payable 188,298 4.19% 4.28% 0.18% 0.18%9 Gas Supplier Refunds - 0.00% 0.00% 0.00% 0.00%
10 Customer Deposits 25,616 0.57% 2.45% 0.01% 0.01%11 Preferred Stock 20,223 0.45% 3.62% 0.02% 0.03%12 Common Equity 2,245,190 49.96% 11.10% 5.55% 9.19%1314 Total $4,493,975 100.00% 8.50% 12.15%15 =====================================================================================================
Revenue Requirement of $0
Niagara Mohawk, a National Grid CompanyFor the Rate year Ending December 31, 2011
Niagara Mohawk, a National Grid CompanyFor the Rate year Ending December 31, 2012
Niagara Mohawk, a National Grid CompanyFor the Rate year Ending December 31, 2013
117
Exhibit __ (RR
P-2)
Exhibit (RRP-2) Witness: Revenue Requirement Panel
(INCLUDED IN BOOK 12)
NIAGARA MOHAWK POWER COPORATION d/b/a NATIONAL GRID
Operation and Maintenance Expenses by Expense Type
for the Year Ended September 30, 2009 and Rate Years Ending December 31, 2011,
December 31, 2012 and December 31, 2013 Summary
Dated: January 29, 2010
118
Exhibit __ (R
RP-3)
Exhibit (RRP-3) Witness: Revenue Requirement Panel
NIAGARA MOHAWK POWER COPORATION d/b/a NATIONAL GRID
Electric Depreciation Expense for the
Year Ended September 30, 2009 and Rate Years Ending December 31, 2011,
December 31, 2012 and December 31, 2013 Summary
Dated: January 29, 2010
119
Exh
ibit
(
RR
P-3)
Sum
mar
ySh
eet 1
of 1
Adj
. to
Nor
mal
ize
His
toric
Yea
r and
His
toric
Yea
r End
edR
efle
ct C
ondi
tions
inR
ate
Yea
r End
ing
Rat
e Y
ear E
ndin
g R
ate
Yea
r End
ing
Sept
embe
r 30,
200
9th
e 20
11 R
ate
Yea
rD
ecem
ber 3
1, 2
011
Dec
embe
r 31,
201
2D
ecem
ber 3
1, 2
013
Dep
reci
atio
n Ex
pens
e (a
cct 4
03)
178,
798
$
18
,457
$
197,
255
209,
522
223,
144
Am
ortiz
atio
n Ex
pens
e (a
cct 4
04-4
06)
4,28
4(4
,018
)26
619
915
5
(Gai
n) L
oss o
n D
ispo
sitio
n of
Util
ity P
lant
(acc
t 411
.7)
396
(396
)0
00
Tota
l Dep
reci
atio
n &
Am
ortiz
atio
n Ex
pens
e18
3,47
8$
14,0
43$
197,
521
$
20
9,72
1$
223,
299
$
Am
ortiz
atio
n ex
pens
e in
the
hist
oric
test
yea
r rel
ates
larg
ely
to in
tang
ible
softw
are
amor
tized
ove
r 10
year
life
- pr
inci
pally
the
Cus
tom
er S
ervi
ce C
ente
r (C
SS) w
hich
is fu
lly a
mor
itize
dpr
ior t
o th
e R
ate
Yea
rs.
Loss
on
disp
ositi
on o
f util
ity p
lant
in h
isto
ric te
st y
ear r
efle
cts m
onth
ly a
mor
tizat
ion
of e
xpen
se re
late
d to
Osw
ego
Fire
Sch
ool s
ale.
Rat
e Y
ears
' Dep
reci
atio
n &
Am
ortiz
atio
n - E
xhib
it (R
RP-
6), S
ched
ule
1 su
ppor
ted
by W
orkp
aper
s for
Exh
ibit
(RR
P-6)
, Sch
edul
e 1,
Wor
kpap
er 1
, Pag
es 2
8-30
for E
lect
rican
d W
orkp
aper
2, P
ages
13-
15 fo
r Com
mon
.
($00
0's)
NIA
GA
RA
MO
HA
WK
PO
WE
R C
OR
POR
AT
ION
d/b
/a N
AT
ION
AL
GR
ID (C
OM
PAN
Y 3
6)Su
mm
ary
of D
epre
ciat
ion
and
Am
ortiz
atio
n E
xpen
seFo
r th
e Y
ear
End
ed S
epte
mbe
r 30
, 200
9 an
d th
e R
ate
Yea
rs E
ndin
g D
ecem
ber
31, 2
011
- Dec
embe
r 31
, 201
3
Exhibit (RRP-3) Summary Sheet 1 of 1
120
Exhibit __ (R
RP-4)
Exhibit (RRP-4) Witness: Revenue Requirement Panel
NIAGARA MOHAWK POWER COPORATION d/b/a NATIONAL GRID
Taxes Other Than Income Taxes for the
Year Ended September 30, 2009 and Rate Years Ending December 31, 2011,
December 31, 2012 and December 31, 2013 Summary Dated: January 29, 2010
121
Exh
ibit
(RR
P-4)
Sum
mar
ySh
eet 1
of 3
Witn
ess:
Rev
enue
Req
uire
men
t Pan
el
Adj
. to
Nor
mal
ize
His
toric
Yea
r and
Reg
Sche
dule
His
toric
Yea
r End
edR
efle
ct C
ondi
tions
Rat
e Y
ear E
ndin
g El
ectri
c Ta
xes O
ther
Tha
n In
com
e Ta
xes (
Acc
t 408
.1)
Acc
tR
efer
ence
Sept
embe
r 30,
200
9in
the
Rat
e Y
ear
Dec
embe
r 31,
201
1
Rea
l Est
ate
Taxe
sR
eal P
rope
rty40
8140
70,6
95.1
$
7,68
1.4
$
78,3
76.6
$
Spec
ial F
ranc
hise
4081
8057
,198
.86,
205.
763
,404
.5
Tota
l Rea
l Est
ate
Taxe
sSc
hedu
le 1
127,
893.
913
,887
.114
1,78
1.0
Payr
oll T
axes
4081
00, 4
0811
0Sc
hedu
le 2
18,9
49.1
(778
.4)
18,1
70.7
Sale
s & U
se T
axes
4081
95Sc
hedu
le 3
88.2
2.8
91.0
Oth
er
4081
50Sc
hedu
le 4
(695
.3)
710.
114
.8
Tota
l Ele
ctric
Tax
es O
ther
Tha
n R
even
ue a
nd In
com
e Ta
xes
146,
235.
9$
13,8
21.6
$
16
0,05
7.5
$
Gro
ss R
even
ue T
axes
G
ross
Inco
me
4081
9023
,109
.5$
(1
2,13
4.4)
$
10
,975
.2$
M
unic
ipal
Gro
ss R
even
ue40
8191
9,76
2.0
13,0
96.4
22,8
58.5
Tota
l Gro
ss R
even
ue T
axes
Sche
dule
532
,871
.696
2.1
33,8
33.6
Tota
l Ele
ctric
Tax
es O
ther
Tha
n In
com
e Ta
xes (
Acc
t 408
.1)
179,
107.
5$
14,7
83.7
$
19
3,89
1.2
$
Tax
es O
ther
Tha
n In
com
e T
axes
NIA
GA
RA
MO
HA
WK
PO
WE
R C
OR
POR
AT
ION
d/b
/a N
AT
ION
AL
GR
ID (C
OM
PAN
Y 3
6)
For
the
Yea
r E
nded
Sep
tem
ber
30, 2
009
and
the
Rat
e Y
ear
End
ing
Dec
embe
r 31
, 201
1($
000'
s)
Exhibit (RRP-4) Summary Sheet 1 of 3
122
Exh
ibit
(RR
P-4)
Sum
mar
ySh
eet 2
of 3
Witn
ess:
Rev
enue
Req
uire
men
t Pan
el
Reg
Sche
dule
Rat
e Y
ear E
nded
Ref
lect
Con
ditio
nsR
ate
Yea
r End
ing
Elec
tric
Taxe
s Oth
er T
han
Inco
me
Taxe
s (A
cct 4
08.1
Acc
tR
efer
ence
Dec
embe
r 31,
201
1in
the
Rat
e Y
ear 2
Dec
embe
r 31,
201
2
Rea
l Est
ate
Taxe
sR
eal P
rope
rty40
8140
78,3
76.6
$
5,03
6.7
$
83
,413
.2$
Spec
ial F
ranc
hise
4081
8063
,404
.54,
074.
567
,479
.0
Tota
l Rea
l Est
ate
Taxe
sSc
hedu
le 1
141,
781.
09,
111.
215
0,89
2.3
Payr
oll T
axes
4081
00, 4
0811
0Sc
hedu
le 2
18,1
70.7
337.
618
,508
.3
Sale
s & U
se T
axes
4081
95Sc
hedu
le 3
91.0
1.7
92.7
Oth
er
4081
50Sc
hedu
le 4
14.8
0.3
15.0
Tota
l Ele
ctric
Tax
es O
ther
Tha
n R
even
ue a
nd In
com
e Ta
xes
160,
057.
5$
9,45
0.8
$
169,
508.
4$
Gro
ss R
even
ue T
axes
G
ross
Inco
me
4081
9010
,975
.2$
20
8.1
$
11,1
83.3
$
M
unic
ipal
Gro
ss R
even
ue40
8191
22,8
58.5
505.
723
,364
.2
Tota
l Gro
ss R
even
ue T
axes
Sche
dule
533
,833
.671
3.9
34,5
47.5
Tota
l Ele
ctric
Tax
es O
ther
Tha
n In
com
e Ta
xes (
Acc
t 408
.1)
193,
891.
2$
10,1
64.7
$
204,
055.
9$
($00
0's)
NIA
GA
RA
MO
HA
WK
PO
WE
R C
OR
POR
AT
ION
d/b
/a N
AT
ION
AL
GR
ID (C
OM
PAN
Y 3
6)T
axes
Oth
er T
han
Inco
me
Tax
esFo
r th
e R
ate
Yea
r E
nded
Dec
embe
r 31
, 201
1 an
d th
e R
ate
Yea
r E
ndin
g D
ecem
ber
31, 2
012
Exhibit (RRP-4) Summary Sheet 2 of 3
123
Exh
ibit
(RR
P-4)
Sum
mar
ySh
eet 3
of 3
Witn
ess:
Rev
enue
Req
uire
men
t Pan
el
Reg
Sche
dule
Rat
e Y
ear E
nded
Ref
lect
Con
ditio
nsR
ate
Yea
r End
ing
Elec
tric
Taxe
s Oth
er T
han
Inco
me
Taxe
s (A
cct 4
08.1
Acc
tR
efer
ence
Dec
embe
r 31,
201
2in
the
Rat
e Y
ear 3
Dec
embe
r 31,
201
3
Rea
l Est
ate
Taxe
sR
eal P
rope
rty40
8140
83,4
13.2
$
6,44
7.0
$
89
,860
.3$
Spec
ial F
ranc
hise
4081
8067
,479
.05,
215.
572
,694
.5
Tota
l Rea
l Est
ate
Taxe
sSc
hedu
le 1
150,
892.
311
,662
.516
2,55
4.7
Payr
oll T
axes
4081
00, 4
0811
0Sc
hedu
le 2
18,5
08.3
316.
318
,824
.6
Sale
s & U
se T
axes
4081
95Sc
hedu
le 3
92.7
1.8
94.5
Oth
er
4081
50Sc
hedu
le 4
15.0
0.3
15.3
Tota
l Ele
ctric
Tax
es O
ther
Tha
n R
even
ue a
nd In
com
e Ta
xes
169,
508.
4$
11,9
80.8
$
181,
489.
2$
Gro
ss R
even
ue T
axes
G
ross
Inco
me
4081
9011
,183
.3$
23
9.1
$
11,4
22.3
$
M
unic
ipal
Gro
ss R
even
ue40
8191
23,3
64.2
573.
623
,937
.8
Tota
l Gro
ss R
even
ue T
axes
Sche
dule
534
,547
.581
2.6
35,3
60.1
Tota
l Ele
ctric
Tax
es O
ther
Tha
n In
com
e Ta
xes (
Acc
t 408
.1)
204,
055.
9$
12,7
93.4
$
216,
849.
3$
($00
0's)
NIA
GA
RA
MO
HA
WK
PO
WE
R C
OR
POR
AT
ION
d/b
/a N
AT
ION
AL
GR
ID (C
OM
PAN
Y 3
6)T
axes
Oth
er T
han
Inco
me
Tax
esFo
r th
e R
ate
Yea
r E
nded
Dec
embe
r 31
, 201
2 an
d th
e R
ate
Yea
r E
ndin
g D
ecem
ber
31, 2
013
Exhibit (RRP-4) Summary Sheet 3 of 3
124
SCHEDULE 1
Property Taxes
125
Exh
ibit
(R
RP-
4)Sc
hedu
le 1
Shee
t 1 o
f 4
Witn
ess:
Rev
enue
Req
uire
men
t Pan
el
His
toric
Yea
r End
edH
isto
ric Y
ear E
nded
Adj
. to
Nor
mal
ize
Sept
embe
r 30,
200
9R
efle
ct C
ondi
tions
Rat
e Y
ear E
ndin
g R
eal E
stat
e Ta
xes
Sept
embe
r 30,
200
9H
isto
ric Y
ear
Adj
uste
din
the
Rat
e Y
ear 1
Dec
embe
r 31,
201
1
Rea
l Pro
perty
(40
8140
)C
ity20
,842
.2$
(8
.8)
$
20,8
33.4
$
2,
430.
0$
23
,263
.5$
C
ount
y7,
456.
2(1
5.9)
7,
440.
391
7.5
8,35
7.8
Scho
ol1,
159.
0(2
7.4)
1,
131.
615
5.2
1,28
6.8
Vill
age
41,5
92.9
-
41
,592
.93,
875.
645
,468
.5
subt
otal
Rea
l Pro
perty
71,0
50(5
2.2)
70
,998
7,37
878
,377
Spec
ial F
ranc
hise
(40
8180
)C
ity16
,863
.3$
-
$
16
,863
.3$
1,95
6.2
$
18,8
19.5
$
Cou
nty
6,03
2.8
-
6,03
2.8
728.
4
6,76
1.2
Scho
ol93
7.8
-
93
7.8
10
3.2
1,
041.
0
V
illag
e33
,652
.4
-
33,6
52.4
3,
130.
4
36
,782
.8
subt
otal
Spe
cial
Fra
nchi
se57
,486
.2
-
57,4
86.2
5,
918.
2
63
,404
.5
Tota
l Rea
l Est
ate
Taxe
s12
8,53
6.6
$
(5
2.2)
$
12
8,48
4.5
$
13
,296
.6$
141,
781.
0$
($00
0's)
NIA
GA
RA
MO
HA
WK
PO
WE
R C
OR
POR
AT
ION
d/b
/a N
AT
ION
AL
GR
ID (C
OM
PAN
Y 3
6)T
axes
Oth
er T
han
Inco
me
Tax
es -
Rea
l Est
ate
Tax
esFo
r th
e Y
ear
End
ed S
epte
mbe
r 30
, 200
9 an
d th
e R
ate
Yea
r E
ndin
g D
ecem
ber
31, 2
011
Exhibit (RRP-4) Schedule 1 Sheet 1 of 4
126
Exh
ibit
(RR
P-4)
Sche
dule
1Sh
eet 2
of 4
Witn
ess:
Rev
enue
Req
uire
men
t Pan
el
Rat
e Y
ear E
ndin
g R
efle
ct C
ondi
tions
Rat
e Y
ear E
ndin
g R
efle
ct C
ondi
tions
Rat
e Y
ear E
ndin
g R
eal E
stat
e Ta
xes
Dec
embe
r 31,
201
1in
the
Rat
e Y
ear 2
Dec
embe
r 31,
201
2in
the
Rat
e Y
ear 3
Dec
embe
r 31,
201
3
Rea
l Pro
perty
(40
8140
)C
ity23
,263
.5$
1,
495.
0$
24,7
58.4
$
1,
913.
6$
26
,672
.0$
C
ount
y8,
357.
853
7.1
8,89
4.9
687.
59,
582.
4Sc
hool
1,28
6.8
82.7
1,36
9.5
105.
81,
475.
3V
illag
e45
,468
.52,
921.
948
,390
.53,
740.
152
,130
.6
subt
otal
Rea
l Pro
perty
78,3
76.6
5,03
6.7
83,4
13.2
6,44
7.0
89,8
60.3
Spec
ial F
ranc
hise
(40
8180
)C
ity18
,819
.5$
1,
209.
4$
20,0
28.9
$
1,
548.
0$
21
,576
.9$
C
ount
y6,
761.
243
4.5
7,19
5.7
556.
27,
751.
9Sc
hool
1,04
1.0
66.9
1,10
7.9
85.6
1,19
3.5
Vill
age
36,7
82.8
2,36
3.8
39,1
46.6
3,02
5.6
42,1
72.2
subt
otal
Spe
cial
Fra
nchi
se63
,404
.54,
074.
567
,479
.05,
215.
572
,694
.5
Tota
l Rea
l Est
ate
Taxe
s14
1,78
1.0
$
9,
111.
2$
15
0,89
2.3
$
11
,662
.5$
162,
554.
7$
($00
0's)
NIA
GA
RA
MO
HA
WK
PO
WE
R C
OR
POR
AT
ION
d/b
/a N
AT
ION
AL
GR
ID (C
OM
PAN
Y 3
6)T
axes
Oth
er T
han
Inco
me
Tax
es -
Rea
l Est
ate
Tax
esFo
r th
e R
ate
Yea
r E
nded
Dec
embe
r 31
, 201
1 th
roug
h th
e R
ate
Yea
r E
ndin
g D
ecem
ber
31, 2
013
Exhibit (RRP-4) Schedule 1 Sheet 2 of 4
127
Exh
ibit
(RR
P-4)
Sche
dule
1Sh
eet 3
of 4
Witn
ess:
Rev
enue
Req
uire
men
t Pan
el
78.3
0%3.
00%
Tran
smis
sion
Dis
tribu
tion
3.00
%Tr
ansm
issi
onD
istri
butio
n3.
00%
Tran
smis
sion
Dis
tribu
tion
3.00
%Tr
ansm
issi
onD
istri
butio
nC
Y20
09In
flatio
nPl
ant A
djPl
ant A
djC
Y20
10In
flatio
nPl
ant A
djPl
ant A
djC
Y20
11In
flatio
nPl
ant A
djPl
ant A
djC
Y20
12In
flatio
nPl
ant A
djPl
ant A
djC
Y20
13(a
)(b
)(c
)(d
)(e
)(f
)(g
)(h
)(i)
(j)(k
)(l)
(m)
(n)
(o)
(p)
(q)
Reg
Acc
ount
408
140
1Tx
Acc
r-N
Y S
tate
/Cnt
y/To
wn
21,2
60,8
36
63
7,82
5
13
7,09
5
43,2
84
22
,079
,040
662,
371
374,
411
147,
646
23,2
63,4
68
69
7,90
4
58
6,03
0
21
1,04
0
24
,758
,442
74
2,75
3
91
4,43
9
25
6,39
2
26
,672
,026
2
Tx A
ccr-
NY
City
Tax
es7,
638,
297
229,
149
49,2
53
15
,551
7,93
2,24
9
23
7,96
7
13
4,51
3
53
,044
8,35
7,77
4
250,
733
210,
541
75,8
20
8,
894,
867
26
6,84
6
32
8,52
7
92
,113
9,58
2,35
3
3
Tx A
ccr-
NY
Vill
age
Taxe
s1,
176,
000
35,2
80
7,58
3
2,
394
1,22
1,25
8
36
,638
20,7
10
8,
167
1,
286,
772
38
,603
32,4
15
11
,673
1,36
9,46
3
41,0
84
50
,580
14,1
82
1,
475,
309
4Tx
Acc
r-N
Y S
choo
l Tax
es41
,554
,385
1,24
6,63
2
267,
952
84
,599
43,1
53,5
68
1,
294,
607
73
1,78
7
28
8,57
5
45
,468
,537
1,36
4,05
6
1,14
5,39
7
412,
478
48,3
90,4
68
1,45
1,71
4
1,78
7,27
4
501,
120
52,1
30,5
76
5To
tal
71,6
29,5
18
2,
148,
886
46
1,88
3
145,
828
74
,386
,115
2,23
1,58
3
1,26
1,42
0
497,
432
78,3
76,5
51
2,
351,
297
1,
974,
382
71
1,01
1
83
,413
,241
2,
502,
397
3,
080,
819
86
3,80
7
89
,860
,264
Reg
Acc
ount
408
180
6Tx
Acc
r-N
Y S
tate
/Cnt
y/To
wn
17,1
99,4
32
51
5,98
3
11
0,90
6
35,0
16
17
,861
,336
535,
840
302,
888
119,
442
18,8
19,5
06
56
4,58
5
47
4,08
2
17
0,72
6
20
,028
,898
60
0,86
7
73
9,75
6
20
7,41
4
21
,576
,935
7
Tx A
ccr-
NY
City
Tax
es6,
179,
172
185,
375
39,8
45
12
,580
6,41
6,97
2
19
2,50
9
10
8,81
7
42
,911
6,76
1,21
0
202,
836
170,
322
61,3
36
7,
195,
703
21
5,87
1
26
5,76
9
74
,517
7,75
1,86
0
8
Tx A
ccr-
NY
Vill
age
Taxe
s95
1,35
2
28
,541
6,
135
1,93
7
98
7,96
4
29
,639
16,7
54
6,
607
1,
040,
963
31
,229
26,2
23
9,
443
1,
107,
858
33
,236
40,9
18
11
,473
1,19
3,48
5
9
Tx A
ccr-
NY
Sch
ool T
axes
33,6
16,3
55
1,
008,
491
21
6,76
6
68,4
38
34
,910
,050
1,04
7,30
1
591,
995
233,
449
36,7
82,7
96
1,
103,
484
92
6,59
5
33
3,68
4
39
,146
,558
1,
174,
397
1,
445,
855
40
5,39
2
42
,172
,202
10
Tota
l57
,946
,311
1,73
8,38
9
373,
651
11
7,97
1
60,1
76,3
22
1,
805,
290
1,
020,
454
40
2,40
9
63
,404
,474
1,90
2,13
4
1,59
7,22
1
575,
189
67,4
79,0
18
2,02
4,37
1
2,49
2,29
8
698,
796
72,6
94,4
83
Reg
Acc
ount
408
240
11Tx
Acc
r-N
Y S
tate
/Cnt
y/To
wn
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
12
Tx A
ccr-
NY
City
Tax
es-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
13Tx
Acc
r-N
Y V
illag
e Ta
xes
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
14
Tx A
ccr-
NY
Sch
ool T
axes
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
15
Tota
l-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Tota
l Pro
perty
Tax
es16
Tx A
ccr-
NY
Sta
te/C
nty/
Tow
n38
,460
,268
1,15
3,80
8
248,
000
78
,300
39,9
40,3
76
1,
198,
211
67
7,29
8
26
7,08
8
42
,082
,974
1,26
2,48
9
1,06
0,11
1
381,
766
44,7
87,3
40
1,34
3,62
0
1,65
4,19
4
463,
807
48,2
48,9
61
17Tx
Acc
r-N
Y C
ity T
axes
13,8
17,4
69
41
4,52
4
89
,098
28,1
31
14
,349
,221
430,
477
243,
330
95,9
56
15
,118
,984
453,
570
380,
862
137,
155
16,0
90,5
71
482,
717
594,
296
166,
630
17,3
34,2
14
18Tx
Acc
r-N
Y V
illag
e Ta
xes
2,12
7,35
2
63
,821
13
,718
4,33
1
2,
209,
222
66,2
77
37
,463
14,7
73
2,
327,
735
69
,832
58,6
38
21
,117
2,47
7,32
2
74,3
20
91
,498
25,6
55
2,
668,
794
19Tx
Acc
r-N
Y S
choo
l Tax
es75
,170
,740
2,25
5,12
2
484,
718
15
3,03
8
78,0
63,6
18
2,
341,
909
1,
323,
782
52
2,02
4
82
,251
,332
2,46
7,54
0
2,07
1,99
2
746,
162
87,5
37,0
26
2,62
6,11
1
3,23
3,12
9
906,
512
94,3
02,7
78
20To
tal
129,
575,
829
3,
887,
275
83
5,53
4
263,
799
13
4,56
2,43
7
4,03
6,87
3
2,28
1,87
4
899,
840
141,
781,
025
4,
253,
431
3,
571,
603
1,
286,
200
15
0,89
2,25
9
4,
526,
768
5,
573,
117
1,
562,
604
16
2,55
4,74
7
21R
eg A
ccou
nt 4
0814
055
.28%
22R
eg A
ccou
nt 4
0818
044
.72%
23R
eg A
ccou
nt 4
0824
00.
00%
Nia
gara
Moh
awk
Pow
er C
orpo
ratio
nC
Y20
10 -
CY
2013
Est
imat
ed P
rope
rty
Tax
esN
ovem
ber
12th
, 200
9
Cou
nty
City
Vill
age
Scho
olT
ota l
CY
2008
Act
uals
48,0
48,2
01
16
,107
,599
2,
711,
955
94,4
50,1
84
161,
317,
940
C
Y20
09 E
stim
ate
49,1
19,1
16
17
,646
,831
2,
716,
925
96,0
03,5
00
165,
486,
372
10
2.22
9%10
9.55
6%10
0.18
3%10
1.64
5%10
2.58
4%
Tot
a lG
asE
lect
ric
Ele
ctri
c In
crea
seC
Y20
1017
1,55
0,29
6
36,9
87,8
59
134,
562,
437
CY
2011
179,
878,
520
38
,097
,495
14
1,78
1,02
5
5%
CY
2012
190,
132,
678
39
,240
,420
15
0,89
2,25
9
6%
CY
2013
202,
972,
380
40
,417
,632
16
2,55
4,74
7
8%
*CY
10-1
3 w
ere
calc
ulat
ed b
y in
crea
sing
3%
per
yea
r fro
m th
e cu
rren
t CY
09 fo
reca
st th
en a
ddin
g an
est
imat
e of
the
addi
tiona
l tax
es
on p
lann
ed C
apEx
surg
e ex
pend
iture
s. P
ortio
ns o
f the
mod
el u
sed
to e
stim
ate
Cap
Ex S
urge
impa
ct is
in S
heet
4.
NIA
GA
RA
MO
HA
WK
PO
WE
R C
OR
POR
AT
ION
d/b
/a N
AT
ION
AL
GR
ID (C
OM
PAN
Y 3
6)T
axes
Oth
er T
han
Inco
me
Tax
es -
Rea
l Est
ate
Tax
esFo
r th
e R
ate
Yea
r E
nded
Dec
embe
r 31
, 200
9 th
roug
h th
e R
ate
Yea
r E
ndin
g D
ecem
ber
31, 2
013
($00
0's)
Shee
t 4, T
ax Im
pact
CY
Tot
alSh
eet 4
, Tax
Impa
ct C
Y T
otal
Shee
t 4, T
ax Im
pact
CY
Tot
alSh
eet 4
, Tax
Impa
ct C
Y T
otal
Exhibit (RRP-4) Schedule 1 Sheet 3 of 4
128
Exh
ibit
(RR
P-4)
Sche
dule
1Sh
eet 4
of 4
(a)
(b)
(c)
(d)
(e)
(f)
(g)
(h)
(i)W
itnes
s: R
even
ue R
equi
rem
ent P
anel
(b) -
(c) -
(d)
(e) -
Lin
e 11
or 2
3 (f
)(f
)*(g
)*(h
)/100
0T
rans
mis
sio n
Estim
ated
Pla
nt
Clo
sing
sEs
t. N
on-T
axab
le
Dol
lars
Estim
ated
R
etire
men
tsN
et C
hang
e to
RB
Inc.
/(Dec
.) fr
om
Nor
mal
Avg
Eq.
R
ate
Avg
Tax
R
ate
Adj
. To
Fore
cast
Split
FY10
FY11
FY12
FY13
FY14
Tax
Impa
ct
CY
T
otal
s1
CY
0967
,297
,070
7,40
2,67
8
1,
566
59
,892
,827
(7
,392
,199
)
78
.78%
29.9
2(1
74,2
35)
75%
FY
10; 2
5% F
Y11
(130
,676
)
(43,
559)
2
CY
1014
2,86
3,93
6
18,8
41,6
65
12
4,02
2,27
1
65
,484
,298
1,54
3,47
2
75%
FY
11; 2
5% F
Y12
1,15
7,60
4
38
5,86
8
3
CY
1121
1,02
9,47
8
23,2
15,7
15
18
7,81
3,76
3
12
9,27
5,79
0
3,04
7,04
4
75%
FY
12; 2
5% F
Y13
2,28
5,28
3
761,
761
4
CY
1226
1,42
7,67
6
26,9
61,0
22
23
4,46
6,65
4
17
5,92
8,68
2
4,14
6,65
8
75%
FY
13; 2
5% F
Y14
3,10
9,99
3
1,
036,
664
5C
Y13
399,
994,
646
52
,753
,447
347,
241,
199
288,
703,
227
6,
804,
765
75
% F
Y14
; 25%
FY
155,
103,
574
6C
Y 1
442
3,55
9,86
3
55,8
61,3
55
36
7,69
8,50
8
30
9,16
0,53
5
7,28
6,94
6
75%
FY
15; 2
5% F
Y16
7-
1,
114,
045
2,67
1,15
1
3,87
1,75
4
6,
140,
238
805
-'08
Avg
Pla
nt C
losi
ngs
67,2
85,0
26
FY
2011
= A
pril-
Dec
201
0 an
d Ja
n-M
ar 2
011
9R
etire
men
ts a
s a %
of P
lt C
losi
ngs
13%
CY
2010
= 2
5% o
f FY
10 a
nd 7
5% o
f FY
11-
83
5,53
4
835,
533.
85
CY
2010
1005
-'08
Avg
Ret
irem
ent s
8,74
7,05
3
CY
2011
= 2
5% o
f FY
11 a
nd 7
5% o
f FY
1227
8,51
1
2,00
3,36
3
2,28
1,87
4.49
CY
2011
1105
-'08
Net
Cha
nge
to R
ateb
ase
58,5
37,9
72
C
Y20
12 =
25%
of F
Y12
and
75%
of F
Y13
667,
788
2,90
3,81
6
3,
571,
603.
36
C
Y20
1212
CY
2013
= 2
5% o
f FY
13 a
nd 7
5% o
f FY
1496
7,93
9
4,60
5,17
9
5,
573,
117.
41
C
Y20
13
Dis
trib
utio
nEs
timat
ed P
lant
C
losi
ngs
Est.
Non
-Tax
able
D
olla
rsEs
timat
ed
Ret
irem
ents
Net
Cha
nge
to R
BIn
c./(D
ec.)
from
N
orm
alA
vg E
q.
Rat
eA
vg T
ax
Rat
eA
dj. T
o Fo
reca
stSp
litFY
10FY
11FY
12FY
13FY
14T
ax Im
pact
C
Y
Tot
als
13C
Y09
124,
637,
710
13
,710
,148
(8
,750
,663
)
11
9,67
8,22
4
(7
2,27
2,27
6)
78
.78%
29.9
2(1
,703
,465
)
75%
FY
10; 2
5% F
Y11
(1,2
77,5
99)
(4
25,8
66)
14C
Y10
245,
105,
830
34
,121
,069
210,
984,
761
43,9
87,8
26
1,
036,
798
75
% F
Y11
; 25%
FY
1277
7,59
8
259,
199
15C
Y11
248,
297,
264
34
,724
,729
213,
572,
535
46,5
75,6
00
1,
097,
792
75
% F
Y12
; 25%
FY
1382
3,34
4
27
4,44
8
16C
Y12
267,
889,
824
39
,819
,067
228,
070,
757
61,0
73,8
22
1,
439,
516
75
% F
Y13
; 25%
FY
141,
079,
637
359,
879
17
CY
1327
7,38
8,09
3
38,4
22,5
64
23
8,96
5,52
9
71
,968
,594
1,69
6,30
7
75%
FY
14; 2
5% F
Y15
1,27
2,23
1
18
CY
14
288,
674,
246
39
,884
,665
248,
789,
581
81,7
92,6
46
1,
927,
861
75
% F
Y15
; 25%
FY
1619
-
351,
732
1,
082,
543
1,
354,
085
1,63
2,11
0
20
07-'0
8 A
vg P
lant
Clo
sing
s19
1,95
0,50
0
FY20
11 =
Apr
il-D
ec 2
010
and
Jan-
Mar
201
121
Ret
irem
ents
as a
% o
f Plt
Clo
sing
s13
%So
CY
2010
= 2
5% o
f FY
10 a
nd 7
5% o
f FY
11-
26
3,79
9
263,
798.
99
CY
2010
2205
-'08
Avg
Ret
irem
ent s
24,9
53,5
65
So
CY
2011
= 2
5% o
f FY
11 a
nd 7
5% o
f FY
1287
,933
81
1,90
7
89
9,84
0.45
C
Y20
1123
05-'0
8 N
et C
hang
e to
Rat
ebas
e16
6,99
6,93
5
So C
Y20
12 =
25%
of F
Y12
and
75%
of F
Y13
270,
636
1,01
5,56
4
1,
286,
199.
77
C
Y20
1224
So C
Y20
13 =
25%
of F
Y13
and
75%
of F
Y14
338,
521
1,
224,
082
1,56
2,60
3.53
CY
2013
Line
1, C
olum
n (b
) - (d
) - W
orkp
aper
1
Line
1 a
nd L
ine
13, C
olum
n (g
) - W
orkp
aper
2Li
ne 1
and
Lin
e 13
, Col
umn
(h) -
Wor
kpap
er 3
Line
2 -
6, C
olum
n (b
) and
(d) -
Wor
kpap
er 4
, Lin
e 3
and
Line
5, f
or re
spec
tive
yea
Line
8, C
olum
n (f
) - W
orkp
aper
4, L
ine
1Li
ne 9
and
Lin
e 21
, Col
umn
(f) -
Wor
kpap
ers f
or E
xhib
it (R
RP-
6), S
hedu
le 1
, Wor
kpap
er 1
5, S
heet
2Li
ne 1
0 - L
ine
8 *
Line
9Li
ne 1
1 - L
ine
8 le
ss L
ine
10Li
ne 1
3, C
olum
n (b
) - (d
) - W
orkp
aper
1
Line
14
- 18,
Col
umn
(b) a
nd (c
) - W
orkp
aper
4, L
ine
4 an
d Li
n 6,
for r
espe
ctiv
e ye
aLi
ne 2
0, C
olum
n (f
) - W
orkp
aper
4, L
ine
2Li
ne 2
2 - L
ine
20 *
Lin
e 2
1 Li
ne 2
3 - L
ine
20 le
ss L
ine
2 2
Tax
Impa
ct
Tax
Impa
ct
NIA
GA
RA
MO
HA
WK
PO
WE
R C
OR
POR
AT
ION
d/b
/a N
AT
ION
AL
GR
ID (C
OM
PAN
Y 3
6)T
axes
Oth
er T
han
Inco
me
Tax
es -
Rea
l Est
ate
Tax
esT
rans
mis
sion
& D
istr
ibut
ion
5-Y
ear
Cap
Ex
Prop
erty
Tax
Impa
ct A
naly
sis
Exhibit (RRP-4) Schedule 1 Sheet 4 of 4
129
SCHEDULE 2
Payroll Taxes
130
Exh
ibit
(R
RP-
4)Sc
hedu
le 2
Shee
t 1 o
f 2
Prov
ider
Com
pany
Lab
or C
harg
edTo
Nia
gara
Moh
awk
Pow
er C
orp.
(Co.
36)
Rat
e Y
ear E
ndin
g D
ecem
ber 3
1, 2
011
Prov
ider
Com
pany
Lab
or C
harg
edTo
Nia
gara
Moh
awk
Pow
er C
orp.
(Co.
36)
Rat
e Y
ear E
ndin
g D
ecem
ber 3
1, 2
012
Tota
lN
iaga
ra M
ohaw
k Po
wer
Cor
p.N
atio
nal G
rid U
S ASe
rvic
e C
o.K
eysp
an S
ervi
ceC
o.A
ll O
ther
Com
pani
esTo
tal
Nia
gara
Moh
awk
Pow
er C
orp.
Nat
iona
l Grid
USA
Serv
ice
Co.
Key
span
Serv
ice
Co.
All
Oth
erC
ompa
nies
Pror
atio
n of
Nia
gara
Moh
awk'
s Tot
al P
ayro
ll C
harg
es10
0.0%
100.
0%10
0.0%
100.
0%10
0.0%
100.
0%A
lloca
tion
Perc
ent t
o Ex
pens
e64
.5%
85.3
%95
.8%
64.5
%85
.3%
95.8
%
Tota
l Pro
vide
r Com
pany
Pay
roll
Taxe
s31
,867
.29
$
27,6
07.4
$
3,
327.
77$
932.
11$
32,4
62.1
5$
28,1
30.9
$
3,
380.
19$
951.
11$
Payr
oll E
xpen
se T
ax A
lloca
tion
21,4
63.8
3$
17
,733
.3$
2,83
7.78
$
89
2.77
$
21
,862
.95
$
18
,069
.5$
2,88
2.48
$
91
0.96
$
Elec
tric
18,1
70.7
4$
15
,083
.2$
2,44
3.78
$
64
3.74
$
18
,508
.34
$
15
,369
.2$
2,48
2.28
$
65
6.86
$
Gas
3,29
3.09
$
2,
650.
1$
39
4.00
$
249.
03$
3,35
4.61
$
2,70
0.3
$
400.
20$
25
4.10
$
($00
0's)
NIA
GA
RA
MO
HA
WK
PO
WE
R C
OR
POR
AT
ION
d/b
/a N
AT
ION
AL
GR
ID (C
OM
PAN
Y 3
6)T
axes
Oth
er T
han
Inco
me
Tax
es -
Payr
oll T
axes
For
the
Rat
e Y
ear
End
ing
Dec
embe
r 31
, 201
1 an
d D
ecem
ber
31, 2
012
Exhibit (RRP-4) Schedule 2 Sheet 1 of 2
131
Pror
atio
n of
Nia
gara
Moh
awk'
s Tot
al P
ayro
ll C
harg
esA
lloca
tion
Perc
ent t
o Ex
pens
e
Tota
l Pro
vide
r Com
pany
Pay
roll
Taxe
s
Payr
oll E
xpen
se T
ax A
lloca
tion
Elec
tric
Gas
Exh
ibit
(R
RP-
4)Sc
hedu
le 2
Shee
t 2 o
f 2
Prov
ider
Com
pany
Lab
or C
harg
edTo
Nia
gara
Moh
awk
Pow
er C
orp.
(Co.
36)
Rat
e Y
ear E
ndin
g D
ecem
ber 3
1, 2
013
Tota
lN
iaga
ra M
ohaw
k Po
wer
Cor
p.N
atio
nal G
rid U
S ASe
rvic
e C
o.K
eysp
an S
ervi
ceC
o.A
ll O
ther
Com
pani
es10
0.0%
100.
0%10
0.0%
64.5
%85
.3%
95.8
%
33,0
17.3
3$
28
,612
.6$
3,43
4.08
$
97
0.62
$
22,2
37.0
6$
18
,379
.0$
2,92
8.43
$
92
9.65
$
18,8
24.6
0$
15
,632
.4$
2,52
1.85
$
67
0.33
$
3,41
2.45
$
2,
746.
6$
40
6.58
$
259.
32$
($00
0's)
NIA
GA
RA
MO
HA
WK
PO
WE
R C
OR
POR
AT
ION
d/b
/a N
AT
ION
AL
GR
ID (C
OM
PAN
Y 3
6)T
axes
Oth
er T
han
Inco
me
Tax
es -
Payr
oll T
axes
For
the
Rat
e Y
ear
End
ing
Dec
embe
r 31
, 201
3
Exhibit (RRP-4) Schedule 2 Sheet 2 of 2
132
SCHEDULE 3
Sales Taxes
133
Exh
ibit
(RR
P-4)
Sche
dule
3Sh
eet 1
of 3
His
toric
Yea
r End
edH
isto
ric Y
ear E
nded
Adj
. to
Nor
mal
ize
Sept
embe
r 30,
200
9R
efle
ct C
ondi
tions
Rat
e Y
ear E
ndin
g Sa
les a
nd u
se T
ax -
4081
95Se
ptem
ber 3
0, 2
009
His
toric
Yea
rA
djus
ted
in th
e R
ate
Yea
r 1D
ecem
ber 3
1, 2
011
Com
pany
Use
Tax
88.2
$
-$
88
.2$
2.8
$
91.0
$
Tota
l Sal
es a
nd u
se T
axes
88.2
$
-$
88
.2$
2.8
$
91.0
$
($00
0's)
NIA
GA
RA
MO
HA
WK
PO
WE
R C
OR
POR
AT
ION
d/b
/a N
AT
ION
AL
GR
ID (C
OM
PAN
Y 3
6)T
axes
Oth
er T
han
Inco
me
Tax
es -
Sale
s and
Use
Tax
esFo
r th
e Y
ear
End
ed S
epte
mbe
r 30
, 200
9 an
d th
e R
ate
Yea
r E
ndin
g D
ecem
ber
31, 2
011
Exhibit (RRP-4) Schedule 3 Sheet 1 of 3
134
Exh
ibit
(RR
P-4)
Sche
dule
3Sh
eet 2
of 3
Rat
e Y
ear E
ndin
g R
efle
ct C
ondi
tions
Rat
e Y
ear E
ndin
g R
efle
ct C
ondi
tions
Rat
e Y
ear E
ndin
g R
eal E
stat
e Ta
xes
Dec
embe
r 31,
201
1in
the
Rat
e Y
ear 2
Dec
embe
r 31,
201
2in
the
Rat
e Y
ear 3
Dec
embe
r 31,
201
3
Com
pany
Use
Tax
91.0
$
1.6
$
92.6
$
1.
8$
94
.4$
Tota
l Sal
es a
nd u
se T
axes
91.0
$
1.6
$
92.6
$
1.
8$
94
.4$
($00
0's)
NIA
GA
RA
MO
HA
WK
PO
WE
R C
OR
POR
AT
ION
d/b
/a N
AT
ION
AL
GR
ID (C
OM
PAN
Y 3
6)T
axes
Oth
er T
han
Inco
me
Tax
es -
Sale
s and
use
Tax
esFo
r th
e R
ate
Yea
r E
nded
Dec
embe
r 31
, 201
1 th
roug
h th
e R
ate
Yea
r E
ndin
g D
ecem
ber
31, 2
013
Exhibit (RRP-4) Schedule 3 Sheet 2 of 3
135
Exh
ibit
(RR
P-4)
Sche
dule
3Sh
eet 3
of 3
Tota
lEx
plan
atio
n of
Adj
ustm
ents
:
Line
sA
djus
tmen
ts:
(to n
orm
aliz
e H
isto
ric Y
ear)
1$
-
2TO
TAL
-$
Adj
ustm
ents
: (to
refle
ct c
ondi
tions
in th
e R
ate
Yea
r)G
ener
al in
flatio
n %
33.
2146
%2.
8$
TOTA
L2.
8$
A
djus
tmen
ts:
(to re
flect
con
ditio
ns in
the
Rat
e Y
ear 2
012)
Gen
eral
infla
tion
%4
1.80
%1.
6$
TOTA
L1.
6$
A
djus
tmen
ts:
(to re
flect
con
ditio
ns in
the
Rat
e Y
ear 2
013)
Gen
eral
infla
tion
%5
1.90
%1.
8$
TOTA
L1.
8$
NIA
GA
RA
MO
HA
WK
PO
WE
R C
OR
POR
AT
ION
d/b
/a N
AT
ION
AL
GR
ID (C
OM
PAN
Y 3
6)T
axes
Oth
er T
han
Inco
me
Tax
es -
Sale
s and
Use
Tax
es
($00
0's)
Exhibit (RRP-4) Schedule 3 Sheet 3 of 3
136
SCHEDULE 4
Other Taxes
137
Exh
ibit
(
RR
P-4)
Sche
dule
4Sh
eet 1
of 3
His
toric
Yea
r End
edH
isto
ric Y
ear E
nded
Adj
. to
Nor
mal
ize
Sept
embe
r 30,
200
9R
efle
ct C
ondi
tions
Rat
e Y
ear E
ndin
g O
ther
Tax
es -
4081
50Se
ptem
ber 3
0, 2
009
His
toric
Yea
rA
djus
ted
in th
e R
ate
Yea
r 1D
ecem
ber 3
1, 2
011
Haz
ardo
us W
aste
Tax
8.6
$
-$
8.
6$
0.
3$
8.
9$
Pr
oper
ty T
erro
rism
5.6
-
5.
6
0.2
5.8
Oth
er(7
09.5
)
70
9.6
0.
1
0.0
0.1
Tota
l Oth
er T
axes
(695
.3)
$
709.
6$
14.3
$
0.
5$
14
.8$
($00
0's)
NIA
GA
RA
MO
HA
WK
PO
WE
R C
OR
POR
AT
ION
d/b
/a N
AT
ION
AL
GR
ID (C
OM
PAN
Y 3
6)T
axes
Oth
er T
han
Inco
me
Tax
es -
Oth
er T
axes
For
the
Yea
r E
nded
Sep
tem
ber
30, 2
009
and
the
Rat
e Y
ear
End
ing
Dec
embe
r 31
, 201
1
Exhibit (RRP-4) Schedule 4 Sheet 1 of 3
138
Exh
ibit
(
RR
P-4)
Sche
dule
4Sh
eet 2
of 3
Rat
e Y
ear E
ndin
g R
efle
ct C
ondi
tions
Rat
e Y
ear E
ndin
g R
efle
ct C
ondi
tions
Rat
e Y
ear E
ndin
g R
eal E
stat
e Ta
xes
Dec
embe
r 31,
201
1in
the
Rat
e Y
ear 2
Dec
embe
r 31,
201
2in
the
Rat
e Y
ear 3
Dec
embe
r 31,
201
3
Haz
ardo
us W
aste
Tax
8.9
$
0.
2$
9.
0$
0.2
$
9.2
$
Pr
oper
ty T
erro
rism
5.8
0.
1
5.
9
0.1
6.0
O
ther
0.1
0.
0
0.
1
0.0
0.1
Tota
l Rea
l Est
ate
Taxe
s14
.8$
0.
3$
15
.0$
0.3
$
15.3
$
($00
0's)
NIA
GA
RA
MO
HA
WK
PO
WE
R C
OR
POR
AT
ION
d/b
/a N
AT
ION
AL
GR
ID (C
OM
PAN
Y 3
6)T
axes
Oth
er T
han
Inco
me
Tax
es -
Oth
er T
axes
For
the
Rat
e Y
ear
End
ed D
ecem
ber
31, 2
011
thro
ugh
the
Rat
e Y
ear
End
ing
Dec
embe
r 31
, 201
3
Exhibit (RRP-4) Schedule 4 Sheet 2 of 3
139
Exh
ibit
(
RR
P-4)
Sche
dule
4Sh
eet 3
of 3
Tota
lEx
plan
atio
n of
Adj
ustm
ents
:
Line
sA
djus
tmen
ts:
(to n
orm
aliz
e H
isto
ric Y
ear)
1To
adj
ust o
ne ti
me
recl
ass f
or o
f Ins
uran
ce P
rem
ium
sW
orkp
aper
1$
7
09.6
2TO
TAL
709.
6$
Adj
ustm
ents
: (to
refle
ct c
ondi
tions
in th
e R
ate
Yea
r)G
ener
al in
flatio
n %
33.
2146
%0.
5$
TOTA
L0.
5$
A
djus
tmen
ts:
(to re
flect
con
ditio
ns in
the
Rat
e Y
ear 2
012)
Gen
eral
infla
tion
%4
1.80
%0.
3$
TOTA
L0.
3$
A
djus
tmen
ts:
(to re
flect
con
ditio
ns in
the
Rat
e Y
ear 2
013)
Gen
eral
infla
tion
%5
1.90
%0.
3$
TOTA
L0.
3$
NIA
GA
RA
MO
HA
WK
PO
WE
R C
OR
POR
AT
ION
d/b
/a N
AT
ION
AL
GR
ID (C
OM
PAN
Y 3
6)T
axes
Oth
er T
han
Inco
me
Tax
es -
Oth
er T
axes
($00
0's)
Exhibit (RRP-4) Schedule 4 Sheet 3 of 3
140
SCHEDULE 5
GRT Taxes
141
Exh
ibit
(RR
P-4)
Sche
dule
5Sh
eet 1
of 3
His
toric
Yea
r End
edH
isto
ric Y
ear E
nded
Adj
. to
Nor
mal
ize
Sept
embe
r 30,
200
9R
efle
ct C
ondi
tions
Rat
e Y
ear E
ndin
g G
ross
Rev
enue
Tax
Sept
embe
r 30,
200
9H
isto
ric Y
ear
Adj
uste
din
the
Rat
e Y
ear 1
Dec
embe
r 31,
201
1
Gro
ss In
com
e (4
0819
0)A
ccru
al A
djus
tmen
ts10
,504
.7$
5,46
0.3
$
15
,965
.0$
(4
,989
.9)
$
10,9
75.2
$
PFJ C
redi
t Adj
ustm
ents
5,83
7.6
(5,8
37.6
)-
-
-
R
eser
ve A
djus
tmen
ts6,
767.
2(6
,767
.2)
-
-
-
subt
otal
Gro
ss In
com
e23
,109
.5(7
,144
.5)
15,9
65.0
(4,9
89.9
)10
,975
.2
Mun
icip
al G
ross
Inco
me
(408
191)
Acc
rual
Adj
ustm
ents
10,8
42.8
2,80
6.1
13,6
48.9
9,20
9.6
22,8
58.5
Adj
ustm
ents
(1,0
80.8
)1,
080.
80.
04
(0
.04)
-
subt
otal
Mun
icip
al9,
762.
03,
886.
913
,649
.09,
209.
522
,858
.5
Tota
l Gro
ss R
even
ue T
a x32
,871
.6$
(3
,257
.6)
$
29,6
14.0
$
4,21
9.6
$
33,8
33.6
$
($00
0's)
NIA
GA
RA
MO
HA
WK
PO
WE
R C
OR
POR
AT
ION
d/b
/a N
AT
ION
AL
GR
ID (C
OM
PAN
Y 3
6)T
axes
Oth
er T
han
Inco
me
Tax
es -
Gro
ss R
even
ue T
axFo
r th
e Y
ear
End
ed S
epte
mbe
r 30
, 200
9 an
d th
e R
ate
Yea
r E
ndin
g D
ecem
ber
31, 2
011
Exhibit (RRP-4) Schedule 5 Sheet 1 of 3
142
Exh
ibit
(RR
P-4)
Sche
dule
5Sh
eet 2
of 3
Rat
e Y
ear E
ndin
g R
efle
ct C
ondi
tions
Rat
e Y
ear E
ndin
g R
efle
ct C
ondi
tions
Rat
e Y
ear E
ndin
g G
ross
Rev
enue
Tax
Dec
embe
r 31,
201
1in
the
Rat
e Y
ear 2
Dec
embe
r 31,
201
2in
the
Rat
e Y
ear 3
Dec
embe
r 31,
201
3
Gro
ss In
com
e (4
0819
0)A
ccru
al10
,975
.2$
208.
1$
11
,183
.3$
23
9.1
$
11,4
22.3
$
PF
J Cre
dit A
djus
tmen
ts-
-
-
-
-
R
eser
ve A
djus
tmen
ts-
-
-
-
-
subt
otal
Gro
ss In
com
e10
,975
.2
208.
1
11
,183
.3
23
9.1
11,4
22.3
Mun
icip
al G
ross
Inco
me
(408
191)
Acc
rual
22,8
58.5
$
50
5.7
$
23,3
64.2
$
573.
6$
23
,937
.8$
Adj
ustm
ents
-
-
-
-
-
subt
otal
Mun
icip
al22
,858
.5
505.
7
23
,364
.2
57
3.6
23,9
37.8
Tota
l Gro
ss R
even
ue T
a x33
,833
.6$
71
3.9
$
34
,547
.5$
81
2.6
$
35
,360
.1$
($00
0's)
NIA
GA
RA
MO
HA
WK
PO
WE
R C
OR
POR
AT
ION
d/b
/a N
AT
ION
AL
GR
ID (C
OM
PAN
Y 3
6)T
axes
Oth
er T
han
Inco
me
Tax
es -
Gro
ss R
even
ue T
axFo
r th
e R
ate
Yea
r E
nded
Dec
embe
r 31
, 201
1 th
roug
h th
e R
ate
Yea
r E
ndin
g D
ecem
ber
31, 2
013
Exhibit (RRP-4) Schedule 5 Sheet 2 of 3
143
Exhibit (RRP-4)Schedule 5
Sheet 3 of 3
Type of Tax Workpaper TotalExplanation of Adjustments:
Adjustments: (to normalize Historic Year)Sheet 1 Accrual Add back PFJ Credits Gross Income Workpaper 1 $ 7,461.6
Reserve One Time Reserve Adjustments Gross Income Workpaper 1 (6,767.2)PFJ PFJ Credit adjustments Gross Income Workpaper 1 (5,837.6)Accrual Adjustment to Revenue Analysis Gross Income Workpaper 1 (2,001.3)
(7,144.5)
Adjustments One time accrual adjustments Municipal Income Workpaper 1 1,080.8 Accrual Adjustment to Revenue Analysis Municipal Income Workpaper 1 2,806.1
3,886.9
TOTAL (3,257.6)$
Sheet 1 Adjustments: (to Reflect Conditions in Rate Year)
Historic year ended Gross Income amount Gross Income 15,965.0$ Forecasted Amount for Rate Year 2011 Gross Income Exhibit RDCM-4, Schedule 2 (less PFJ credit) 10,975.2 Difference to adjust to Forecast year 2011 Gross Income (4,989.9)
Historic year ended Municipal Income amount Municipal Income 13,649.0$ Forecasted Amount for Rate Year 2011 Municipal Income Exhibit RDCM-4, Schedule 2 (less PFJ credit) 22,858.5 Difference to adjust to Forecast year 2011 Municipal Income 9,209.5
Historic year ended Gross Income amount Total GRT 29,614.0$ Forecasted Amount for Rate Year 2011 Total GRT Exhibit RDCM-4, Schedule 2 (less PFJ credit) 33,833.6 Difference to adjust to Forecast year 2011 Total GRT 4,219.6$
Sheet 2 Adjustments: (to Reflect Conditions in Rate Year 2012)
Forecasted Amount for Rate Year 2011 Gross Income 10,975.2$ Forecasted Amount for Rate Year 2012 Gross Income Exhibit RDCM-4, Schedule 3 (less PFJ credit) 11,183.3 Difference to adjust to Forecast year 2012 Gross Income 208.1
Forecasted Amount for Rate Year 2011 Municipal Income 22,858.5$ Forecasted Amount for Rate Year 2012 Municipal Income Exhibit RDCM-4, Schedule 3 (less PFJ credit) 23,364.2 Difference to adjust to Forecast year 2012 Municipal Income 505.7
Forecasted Amount for Rate Year 2011 Total GRT 33,833.6$ Forecasted Amount for Rate Year 2012 Total GRT Exhibit RDCM-4, Schedule 3 (less PFJ credit) 34,547.5 Difference to adjust to Forecast year 2012 Total GRT 713.9$
Sheet 2 Adjustments: (to Reflect Conditions in Rate Year 2013)
Forecasted Amount for Rate Year 2012 Gross Income 11,183.3$ Forecasted Amount for Rate Year 2013 Gross Income Exhibit RDCM-4, Schedule 4 (less PFJ credit) 11,422.3 Difference to adjust to Forecast year 2013 Gross Income 239.1
Forecasted Amount for Rate Year 2012 Municipal Income 23,364.2$ Forecasted Amount for Rate Year 2013 Municipal Income Exhibit RDCM-4, Schedule 4 (less PFJ credit) 23,937.8 Difference to adjust to Forecast year 2013 Municipal Income 573.6
Forecasted Amount for Rate Year 2012 Total GRT 34,547.5$ Forecasted Amount for Rate Year 2013 Total GRT Exhibit RDCM-4, Schedule 4 (less PFJ credit) 35,360.1 Difference to adjust to Forecast year 2013 Total GRT 812.6$
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID (COMPANY 36)Taxes Other Than Income Taxes - Gross Revenue Tax
($000's)
144
Exhibit __ (RR
P-5)
Exhibit (RRP-5) Witness: Revenue Requirement Panel
NIAGARA MOHAWK POWER COPORATION d/b/a NATIONAL GRID
Federal and State Income Taxes for the
Year Ended September 30, 2009 and Rate Years Ending December 31, 2011,
December 31, 2012 and December 31, 2013 Summary
Dated: January 29, 2010
145
Exh
ibit
(RR
P-5)
Sum
mar
ySh
eet 1
of 4
Ele
ctri
cSo
urce
FED
ER
AL
BO
OK
@ T
HE
TA
XA
BL
ED
EFE
RR
AB
LE
TA
XA
BL
EST
AT
UT
OR
YD
FIT
NE
TIN
CO
ME
BA
SIS
INC
OM
ER
AT
ER
EV
ER
SAL
SFI
T1
NET
INC
OM
E B
EFO
RE
FED
ERA
L &
STA
TE IN
CO
ME
TAX
ESEx
hibi
t RR
P-1
477,
577,
117
477,
577,
117
167,
152,
000
167,
152,
000
2 3A
DD
ITIO
NS
4M
ERG
ER R
ATE
PLA
N S
TRA
ND
ED C
OST
S-A
MO
RTI
ZATI
ON
Exhi
bit R
RP-
516
4,80
4,54
816
4,80
4,54
857
,682
,000
(57,
682,
000)
05
PRO
VIS
ION
FO
R D
EPR
ECIA
TIO
NEx
hibi
t RR
P-3
197,
521,
169
197,
521,
169
69,1
32,0
0069
,132
,000
6R
EAL
ESTA
TE T
AX
ES P
ER B
OO
KS
Exhi
bit R
RP-
414
1,78
1,02
514
1,78
1,02
549
,623
,000
49,6
23,0
007
BU
SIN
ESS
MEA
LS 5
0% D
ISA
LLO
WA
NC
E H
isto
ric Y
ears
330,
000
330,
000
116,
000
116,
000
8D
ED
UC
TIO
NS
9G
AIN
ON
RED
EMPT
ION
BO
ND
SH
isto
ric Y
ears
(60,
460)
(60,
460)
(21,
000)
(21,
000)
10IN
TER
EST
Shee
t 4 o
f 4(1
01,3
04,5
50)
(101
,304
,550
)(3
5,45
7,00
0)(3
5,45
7,00
0)11
V-M
BO
OK
GA
IN A
MO
RTI
ZATI
ON
0
00
375,
000
375,
000
12O
SWEG
O 6
TR
AN
SMIS
SIO
N S
ERV
ICE
CO
NTR
AC
T EX
IT A
GR
EEM
ENT
00
00
13N
EW Y
OR
K S
TATE
INC
OM
E TA
XES
- C
UR
REN
T PR
OV
ISIO
NLi
ne 4
1(2
6,73
4,00
0)(2
6,73
4,00
0)(9
,357
,000
)(9
,357
,000
)14
OTH
ER S
TATE
INC
OM
E TA
XES
His
toric
Yea
rs(6
,000
)(6
,000
)(2
,000
)(2
,000
)15
CO
ST O
F R
EMO
VA
L H
isto
ric Y
ears
(44,
186,
073)
35,3
48,8
59(8
,837
,215
)(3
,093
,000
)(8
,836
,000
)(1
1,92
9,00
0)16
TAX
DEP
REC
IATI
ON
H
isto
ric Y
ears
(141
,153
,930
)(2
9,83
7,14
3)(1
70,9
91,0
73)
(59,
847,
000)
(59,
847,
000)
17R
EAL
ESTA
TE T
AX
ES F
OR
TA
X
Exhi
bit R
RP-
3(1
41,7
81,0
25)
(141
,781
,025
)(4
9,62
3,00
0)(4
9,62
3,00
0)18
AM
OR
TIZA
TIO
N P
ASN
Y C
ON
TRA
CT
00
00
19C
LASS
B C
ON
TRA
CTS
AM
OR
TIZA
TIO
N0
00
00
20T
OT
AL
FIT
EX
PEN
S E52
6,78
7,82
15,
511,
716
532,
299,
537
186,
305,
000
(66,
143,
000)
120,
162,
000
21 22ca
lcul
ated
eff
ectiv
e Fe
dera
l tax
rate
31.9
%
23 24 25 26 27ST
AT
EB
OO
K@
BL
EN
DE
D *
28T
AX
AB
LE
DE
FER
RA
BL
ET
AX
AB
LE
STA
TU
TO
RY
DSI
TN
ET
29IN
CO
ME
BA
SIS
INC
OM
ER
AT
ER
EV
ER
SAL
SSI
T30
NET
INC
OM
E B
EFO
RE
FED
ERA
L &
STA
TE IN
CO
ME
TAX
ESLi
ne 1
477,
577,
117
477,
577,
117
33,9
08,0
0033
,908
,000
31 32A
DD
ITIO
NS
33R
EAL
ESTA
TE T
AX
ES P
ER B
OO
KS
Line
614
1,78
1,02
514
1,78
1,02
510
,066
,000
10,0
66,0
0034
BU
SIN
ESS
MEA
LS 5
0% D
ISA
LLO
WA
NC
E Li
ne 7
330,
000
330,
000
23,0
0023
,000
35D
ED
UC
TIO
NS
36G
AIN
ON
RED
EMPT
ION
BO
ND
SLi
ne 9
(60,
460)
(60,
460)
(4,0
00)
(4,0
00)
37IN
TER
EST
Line
10
(101
,304
,550
)(1
01,3
04,5
50)
(7,1
93,0
00)
(7,1
93,0
00)
38V
-M B
OO
K G
AIN
AM
OR
TIZA
TIO
N
00
00
39O
SWEG
O 6
TR
AN
SMIS
SIO
N S
ERV
ICE
CO
NTR
AC
T EX
IT A
GR
EEM
ENT
00
00
40R
EAL
ESTA
TE T
AX
ES F
OR
TA
X
Line
17
(141
,781
,025
)(1
41,7
81,0
25)
(10,
066,
000)
(10,
066,
000)
41T
OT
AL
SIT
EX
PEN
S E37
6,54
2,10
70
376,
542,
107
26,7
34,0
000
26,7
34,0
0042 43
7.1%
44ca
lcul
ated
eff
ectiv
e N
YS
tax
rate
7.1%
45 46ca
lcul
ated
eff
ectiv
e C
ombi
ned
Fed
& N
YS
tax
rate
39.0
%
Nia
gara
Moh
awk,
a N
atio
nal G
rid
Com
pany
Ele
ctri
c -
As A
djus
ted
Fede
ral I
ncom
e T
axes
- E
lect
ric
For
the
Rat
e Y
ear
End
ed D
ecem
ber
31, 2
011
(Who
le $
)
Ele
ctri
c -
As A
djus
ted
Stat
e In
com
e T
axes
- E
lect
ric
(Who
le $
)Fo
r th
e R
ate
Yea
r E
nded
Dec
embe
r 31
, 201
1
Exhibit (RRP-5) Summary Sheet 1 of 4
146
Exh
ibit
(RR
P-5)
Sum
mar
ySh
eet 2
of 4
Ele
ctri
cSo
urce
FED
ER
AL
BO
OK
@ T
HE
TA
XA
BL
ED
EFE
RR
AB
LE
TA
XA
BL
EST
AT
UT
OR
YD
FIT
NE
TIN
CO
ME
BA
SIS
INC
OM
ER
AT
ER
EV
ER
SAL
SFI
T1
NET
INC
OM
E B
EFO
RE
FED
ERA
L &
STA
TE IN
CO
ME
TAX
ESEx
hibi
t RR
P-1
504,
589,
173
504,
589,
173
176,
606,
000
176,
606,
000
2 3A
DD
ITIO
NS
4M
ERG
ER R
ATE
PLA
N S
TRA
ND
ED C
OST
S-A
MO
RTI
ZATI
ON
Exhi
bit R
RP-
518
5,70
7,76
018
5,70
7,76
064
,998
,000
(64,
998,
000)
05
PRO
VIS
ION
FO
R D
EPR
ECIA
TIO
NEx
hibi
t RR
P-3
209,
721,
266
209,
721,
266
73,4
02,0
0073
,402
,000
6R
EAL
ESTA
TE T
AX
ES P
ER B
OO
KS
Exhi
bit R
RP-
415
0,89
2,25
915
0,89
2,25
952
,812
,000
52,8
12,0
007
BU
SIN
ESS
MEA
LS 5
0% D
ISA
LLO
WA
NC
E H
isto
ric Y
ears
330,
000
330,
000
116,
000
116,
000
8D
ED
UC
TIO
NS
9G
AIN
ON
RED
EMPT
ION
BO
ND
SH
isto
ric Y
ears
(60,
460)
(60,
460)
(21,
000)
(21,
000)
10IN
TER
EST
Shee
t 4 o
f 4(1
15,4
68,0
86)
(115
,468
,086
)(4
0,41
4,00
0)(4
0,41
4,00
0)11
V-M
BO
OK
GA
IN A
MO
RTI
ZATI
ON
0
00
375,
000
375,
000
12O
SWEG
O 6
TR
AN
SMIS
SIO
N S
ERV
ICE
CO
NTR
AC
T EX
IT A
GR
EEM
ENT
00
00
13N
EW Y
OR
K S
TATE
INC
OM
E TA
XES
- C
UR
REN
T PR
OV
ISIO
NLi
ne 4
1(2
7,64
7,00
0)(2
7,64
7,00
0)(9
,676
,000
)(9
,676
,000
)14
OTH
ER S
TATE
INC
OM
E TA
XES
His
toric
Yea
rs(6
,000
)(6
,000
)(2
,000
)(2
,000
)15
CO
ST O
F R
EMO
VA
L H
isto
ric Y
ears
(50,
278,
961)
40,2
23,1
69(1
0,05
5,79
2)(3
,520
,000
)(9
,724
,750
)(1
3,24
4,75
0)16
TAX
DEP
REC
IATI
ON
H
isto
ric Y
ears
(152
,205
,397
)(3
0,28
8,57
1)(1
82,4
93,9
68)
(63,
873,
000)
(63,
873,
000)
17R
EAL
ESTA
TE T
AX
ES F
OR
TA
X
Exhi
bit R
RP-
3(1
50,8
92,2
59)
(150
,892
,259
)(5
2,81
2,00
0)(5
2,81
2,00
0)18
AM
OR
TIZA
TIO
N P
ASN
Y C
ON
TRA
CT
00
00
19C
LASS
B C
ON
TRA
CTS
AM
OR
TIZA
TIO
N0
00
00
20T
OT
AL
FIT
EX
PEN
S E55
4,68
2,29
49,
934,
598
564,
616,
892
197,
616,
000
(74,
347,
750)
123,
268,
250
21 22ca
lcul
ated
eff
ectiv
e Fe
dera
l tax
rate
31.7
%
23 24 25 26 27ST
AT
EB
OO
K@
BL
EN
DE
D *
28T
AX
AB
LE
DE
FER
RA
BL
ET
AX
AB
LE
STA
TU
TO
RY
DSI
TN
ET
29IN
CO
ME
BA
SIS
INC
OM
ER
AT
ER
EV
ER
SAL
SSI
T30
NET
INC
OM
E B
EFO
RE
FED
ERA
L &
STA
TE IN
CO
ME
TAX
ESLi
ne 1
504,
589,
173
504,
589,
173
35,8
26,0
0035
,826
,000
31 32A
DD
ITIO
NS
33R
EAL
ESTA
TE T
AX
ES P
ER B
OO
KS
Line
615
0,89
2,25
915
0,89
2,25
910
,713
,000
10,7
13,0
0034
BU
SIN
ESS
MEA
LS 5
0% D
ISA
LLO
WA
NC
E Li
ne 7
330,
000
330,
000
23,0
0023
,000
35D
ED
UC
TIO
NS
36G
AIN
ON
RED
EMPT
ION
BO
ND
SLi
ne 9
(60,
460)
(60,
460)
(4,0
00)
(4,0
00)
37IN
TER
EST
Line
10
(115
,468
,086
)(1
15,4
68,0
86)
(8,1
98,0
00)
(8,1
98,0
00)
38V
-M B
OO
K G
AIN
AM
OR
TIZA
TIO
N
00
00
39O
SWEG
O 6
TR
AN
SMIS
SIO
N S
ERV
ICE
CO
NTR
AC
T EX
IT A
GR
EEM
ENT
00
00
40R
EAL
ESTA
TE T
AX
ES F
OR
TA
X
Line
17
(150
,892
,259
)(1
50,8
92,2
59)
(10,
713,
000)
(10,
713,
000)
41T
OT
AL
SIT
EX
PEN
S E38
9,39
0,62
70
389,
390,
627
27,6
47,0
000
27,6
47,0
0042 43
7.1%
44ca
lcul
ated
eff
ectiv
e N
YS
tax
rate
7.1%
45 46ca
lcul
ated
eff
ectiv
e C
ombi
ned
Fed
& N
YS
tax
rate
38.8
%
(Who
le $
)E
lect
ric
- A
s Adj
uste
d
Nia
gara
Moh
awk,
a N
atio
nal G
rid
Com
pany
Fede
ral I
ncom
e T
axes
- E
lect
ric
For
the
Rat
e Y
ear
End
ed D
ecem
ber
31, 2
012
Ele
ctri
c -
As A
djus
ted
Stat
e In
com
e T
axes
- E
lect
ric
For
the
Rat
e Y
ear
End
ed D
ecem
ber
31, 2
012
(Who
le $
)
Exhibit (RRP-5) Summary Sheet 2 of 4
147
Exh
ibit
(RR
P-5)
Sum
mar
ySh
eet 3
of 4
Ele
ctri
cSo
urce
FED
ER
AL
BO
OK
@ T
HE
TA
XA
BL
ED
EFE
RR
AB
LE
TA
XA
BL
EST
AT
UT
OR
YD
FIT
NE
TIN
CO
ME
BA
SIS
INC
OM
ER
AT
ER
EV
ER
SAL
SFI
T1
NET
INC
OM
E B
EFO
RE
FED
ERA
L &
STA
TE IN
CO
ME
TAX
ESEx
hibi
t RR
P-1
538,
750,
400
538,
750,
400
188,
563,
000
188,
563,
000
2 3A
DD
ITIO
NS
4M
ERG
ER R
ATE
PLA
N S
TRA
ND
ED C
OST
S-A
MO
RTI
ZATI
ON
Exhi
bit R
RP-
50
00
00
5PR
OV
ISIO
N F
OR
DEP
REC
IATI
ON
Exhi
bit R
RP-
322
3,29
8,56
022
3,29
8,56
078
,154
,000
78,1
54,0
006
REA
L ES
TATE
TA
XES
PER
BO
OK
SEx
hibi
t RR
P-4
162,
554,
747
162,
554,
747
56,8
94,0
0056
,894
,000
7B
USI
NES
S M
EALS
50%
DIS
ALL
OW
AN
CE
His
toric
Yea
rs33
0,00
033
0,00
011
6,00
011
6,00
08
DE
DU
CT
ION
S9
GA
IN O
N R
EDEM
PTIO
N B
ON
DS
His
toric
Yea
rs(6
0,46
0)(6
0,46
0)(2
1,00
0)(2
1,00
0)10
INTE
RES
TSh
eet 4
of 4
(131
,673
,455
)(1
31,6
73,4
55)
(46,
086,
000)
(46,
086,
000)
11V
-M B
OO
K G
AIN
AM
OR
TIZA
TIO
N
00
037
5,00
037
5,00
012
OSW
EGO
6 T
RA
NSM
ISSI
ON
SER
VIC
E C
ON
TRA
CT
EXIT
AG
REE
MEN
T0
00
013
NEW
YO
RK
STA
TE IN
CO
ME
TAX
ES -
CU
RR
ENT
PRO
VIS
ION
Line
41
(28,
921,
000)
(28,
921,
000)
(10,
122,
000)
(10,
122,
000)
14O
THER
STA
TE IN
CO
ME
TAX
ESH
isto
ric Y
ears
(6,0
00)
(6,0
00)
(2,0
00)
(2,0
00)
15C
OST
OF
REM
OV
AL
His
toric
Yea
rs(5
3,90
0,22
5)43
,120
,180
(10,
780,
045)
(3,7
73,0
00)
(10,
860,
501)
(14,
633,
501)
16TA
X D
EPR
ECIA
TIO
N
His
toric
Yea
rs(1
62,7
88,2
50)
(32,
931,
429)
(195
,719
,679
)(6
8,50
2,00
0)(6
8,50
2,00
0)17
REA
L ES
TATE
TA
XES
FO
R T
AX
Ex
hibi
t RR
P-3
(162
,554
,747
)(1
62,5
54,7
47)
(56,
894,
000)
(56,
894,
000)
18A
MO
RTI
ZATI
ON
PA
SNY
CO
NTR
AC
T 0
00
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SS B
CO
NTR
AC
TS A
MO
RTI
ZATI
ON
00
00
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L F
IT E
XPE
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385,
029,
570
10,1
88,7
5139
5,21
8,32
113
8,32
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0(1
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5,50
1)12
7,84
1,49
921 22
calc
ulat
ed e
ffec
tive
Fede
ral t
ax ra
te31
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23 24 25 26 27ST
AT
EB
OO
K@
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EN
DE
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28T
AX
AB
LE
DE
FER
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BL
ET
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LE
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RY
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ME
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ER
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ER
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ER
SAL
SSI
T30
NET
INC
OM
E B
EFO
RE
FED
ERA
L &
STA
TE IN
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ME
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ESLi
ne 1
538,
750,
400
538,
750,
400
38,2
51,0
0038
,251
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31 32A
DD
ITIO
NS
33R
EAL
ESTA
TE T
AX
ES P
ER B
OO
KS
Line
616
2,55
4,74
716
2,55
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,541
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11,5
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BU
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ESS
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ne 7
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EMPT
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BO
ND
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ne 9
(60,
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(60,
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(4,0
00)
(4,0
00)
37IN
TER
EST
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10
(131
,673
,455
)(1
31,6
73,4
55)
(9,3
49,0
00)
(9,3
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00)
38V
-M B
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TIO
N
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AN
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NTR
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T EX
IT A
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ENT
00
00
40R
EAL
ESTA
TE T
AX
ES F
OR
TA
X
Line
17
(162
,554
,747
)(1
62,5
54,7
47)
(11,
541,
000)
(11,
541,
000)
41T
OT
AL
SIT
EX
PEN
SE40
7,34
6,48
50
407,
346,
485
28,9
21,0
000
28,9
21,0
0042 43
7.1%
44ca
lcul
ated
eff
ectiv
e N
YS
tax
rate
7.1%
45 46ca
lcul
ated
eff
ectiv
e C
ombi
ned
Fed
& N
YS
tax
rate
38.5
%
Ele
ctri
c -
As A
djus
ted
Ele
ctri
c -
As A
djus
ted
For
the
Rat
e Y
ear
End
ed D
ecem
ber
31, 2
013
(Who
le $
)
Fede
ral I
ncom
e T
axes
- E
lect
ric
For
the
Rat
e Y
ear
End
ed D
ecem
ber
31, 2
013
(Who
le $
)
Stat
e In
com
e T
axes
- E
lect
ric
Exhibit (RRP-5) Summary Sheet 3 of 4
148
Exh
ibit
(RR
P-5)
Sum
mar
ySh
eet 4
of 4
Nia
gara
Moh
awk,
a N
atio
nal G
rid
Com
pany
Tax
Ded
uctio
n fo
r In
tere
st E
xpen
se
Ref
eren
ce20
1120
1220
131
Avg
Rat
e B
ase
Per B
ooks
Exhi
bit R
RP-
64,
118,
071
$
4,27
6,59
6$
4,
493,
975
$
2 3W
eigh
ted
Cos
t of L
TD D
ebt
Exhi
bit R
RP-
12.
42%
2.62
%2.
74%
4W
eigh
ted
Cos
t of N
otes
pay
able
Exhi
bit R
RP-
10.
02%
0.06
%0.
18%
Wei
ghte
d C
ost o
f Gas
Sup
plie
r Ref
Exhi
bit R
RP-
10.
00%
0.00
%0.
00%
5W
eigh
ted
Cos
t of C
ust D
epos
itsEx
hibi
t RR
P-1
0.02
%0.
02%
0.01
%6
s
ubto
tal w
eigh
ted
cost
of d
ebt
Exhi
bit R
RP-
12.
46%
2.70
%2.
93%
7 8In
com
e T
ax In
tere
st D
educ
tion
Shee
t 1 th
ru 3
101,
305
$
11
5,46
8$
131,
673
$
9
($00
0's)
Exhibit (RRP-5) Summary Sheet 4 of 4
149