RRP Testimony Final - National Grid · 13 my curriculum vitae provided as Exhibit __ (RRP-11). 14 15 Q. Have you previously testified before this commission? 16 A. Yes, a brief description

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

Page 2 of 110

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


Page 3 of 110

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


Page 4 of 110

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


Page 5 of 110

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


Page 6 of 110

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


20 Exhibit __ (RRP-5) Federal and State Income Taxes for the Year Ended 21


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


Page 7 of 110

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


Page 8 of 110

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


Page 9 of 110

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


Page 10 of 110

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


Page 11 of 110

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


Page 12 of 110

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

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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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Page 14 of 110

• 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


Page 15 of 110

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

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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

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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

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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


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

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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

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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


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

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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

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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

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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


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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


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.

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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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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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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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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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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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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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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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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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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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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


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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• 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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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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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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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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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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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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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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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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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


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


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


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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requirement for the Luther Forest asset purchase described in the 2


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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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


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


requirement for the Hydro-One Transformer costs described in the 17


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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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


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


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


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


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


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)


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


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


Through 9/30/09


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


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


Through 9/30/09


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


NIMO-RPS Program Cost Deferred

$1.2 million Zero No request for amortization

NY- Electric Data Interchange cost


24 month amortization period

NY Merger Empl Separation Cost


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



NIMO-Purchase ERC’s Economic Development

($1 million) No additional balance forecast


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)



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


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


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


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


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


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

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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

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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

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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

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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

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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


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


A. Exhibit __ (RRP-10) contains the workpapers supporting the exhibits 18

sponsored by this Panel. 19

110


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


Exhibit __ (RRP-5) Federal and State Income Taxes for the Year Ended


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

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mal

ize

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e Y

ear E

ndin

g H

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ric Y

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ase

Rev

enue

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embe

r 31,

201

1Ex

hibi

tH

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ric Y

ear E

nded

Ref

lect

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ditio

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ate

Yea

r End

ing

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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

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2$

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uctio

nsPu

rcha

sed

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er C

osts

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ue T

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nten

ance

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ortiz

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ulat

ory

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erra

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183,

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tions

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273,

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273,

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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

)$

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$

Rat

e of

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urn

5.98

%8.

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%

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urn

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ty7.

00%

11.1

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NIA

GA

RA

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WE

R C

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ctri

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ting

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me

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the

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nded

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tem

ber

30, 2

009

and

the

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e Y

ear

End

ing

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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

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embe

r 31,

201

2Ex

hibi

tR

ate

Yea

r End

edR

efle

ct C

ondi

tions

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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

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ber 3

1, 2

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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

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nsPu

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sed

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er C

osts

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ue T

axes

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tal D

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tions

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5,89

115

,588

1,04

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9

Gro

ss M

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ory

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tions

1,71

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35

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ase

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$

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276,

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$

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e of

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urn

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%

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urn

On

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ty11

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11.1

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.10%

NIA

GA

RA

MO

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PO

WE

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d/b

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pera

ting

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me

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ear

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and

the

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ear

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ing

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r 31

, 201

2($

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s)


115

Exh

ibit

(

RR

P-1)

Sum

mar

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eet 3

of 4

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e Y

ear E

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g B

ase

Rev

enue

Dec

embe

r 31,

201

3Ex

hibi

tR

ate

Yea

r End

edR

efle

ct C

ondi

tions

Rat

e Y

ear E

ndin

g In

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ith B

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enue

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ceD

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ber 3

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in th

e R

ate

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rem

ent

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g R

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ues

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3,

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$

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rcha

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er C

osts

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Rev

enue

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ty11

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me

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r 31

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3($

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s)


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







Niagara Mohawk, a National Grid CompanyFor the Rate year Ending December 31, 2011



117

Exhibit __ (RR

P-2)


(INCLUDED IN BOOK 12)


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


118

Exhibit __ (R

RP-3)



Electric Depreciation Expense for the




119

Exh

ibit

(

RR

P-3)

Sum

mar

ySh

eet 1

of 1

Adj

. to

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mal

ize

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toric

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r and

His

toric

Yea

r End

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ct C

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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

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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

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5

(Gai

n) L

oss o

n D

ispo

sitio

n of

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ity P

lant

(acc

t 411

.7)

396

(396

)0

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n &

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atio

n Ex

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521

$

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$

Am

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n ex

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the

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oric

test

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r rel

ates

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ely

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ible

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tized

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r 10

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the

Cus

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er S

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ce C

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r (C

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lly a

mor

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e R

ate

Yea

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on

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f util

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e Y

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n - E

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ted

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Exh

ibit

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er 1

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lect

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ages

13-

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r Com

mon

.

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0's)

NIA

GA

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MO

HA

WK

PO

WE

R C

OR

POR

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ION

d/b

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AL

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OM

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Y 3

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ary

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ion

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ortiz

atio

n E

xpen

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r th

e Y

ear

End

ed S

epte

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r 30

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e R

ate

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rs E

ndin

g D

ecem

ber

31, 2

011

- Dec

embe

r 31

, 201

3


120

Exhibit __ (R

RP-4)



Taxes Other Than Income Taxes for the


December 31, 2012 and December 31, 2013 Summary Dated: January 29, 2010

121

Exh

ibit

(RR

P-4)

Sum

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ySh

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t Pan

el

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mal

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tions

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ear E

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c Ta

xes O

ther

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n In

com

e Ta

xes (

Acc

t 408

.1)

Acc

tR

efer

ence

Sept

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r 30,

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the

Rat

e Y

ear

Dec

embe

r 31,

201

1

Rea

l Est

ate

Taxe

sR

eal P

rope

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8140

70,6

95.1

$

7,68

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$

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76.6

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Spec

ial F

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Tota

l Rea

l Est

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se T

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le 3

88.2

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114

.8

Tota

l Ele

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Tax

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ther

Tha

n R

even

ue a

nd In

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e Ta

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16

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Gro

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ue T

axes

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ross

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me

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,109

.5$

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,975

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M

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ss R

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Tota

l Gro

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axes

Sche

dule

532

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Tota

l Ele

ctric

Tax

es O

ther

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n In

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Acc

t 408

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179,

107.

5$

14,7

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$

19

3,89

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$

Tax

es O

ther

Tha

n In

com

e T

axes

NIA

GA

RA

MO

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WK

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WE

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For

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Sep

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ear

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1($

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s)


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

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nded

Ref

lect

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tric

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me

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tR

efer

ence

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Rat

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201

2

Rea

l Est

ate

Taxe

sR

eal P

rope

rty40

8140

78,3

76.6

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5,03

6.7

$

83

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Spec

ial F

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4081

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Gro

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G

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l Gro

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Sche

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Tax

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Acc

t 408

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891.

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$

204,

055.

9$

($00

0's)

NIA

GA

RA

MO

HA

WK

PO

WE

R C

OR

POR

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d/b

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ID (C

OM

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axes

Oth

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han

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me

Tax

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g D

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31, 2

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123

Exh

ibit

(RR

P-4)

Sum

mar

ySh

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of 3

Witn

ess:

Rev

enue

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men

t Pan

el

Reg

Sche

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lect

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r End

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tric

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3

Rea

l Est

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Taxe

sR

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$

89

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Spec

ial F

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572

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oll T

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le 2

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318

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Sale

s & U

se T

axes

4081

95Sc

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le 3

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94.5

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l Ele

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Gro

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G

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me

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l Gro

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t 408

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849.

3$

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NIA

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me

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nded

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013


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

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His

toric

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. to

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mal

ize

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9R

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din

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1

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l Pro

perty

(40

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23

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C

ount

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Vill

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perty

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70

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Spec

ial F

ranc

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$

16

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Cou

nty

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l Est

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13

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141,

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0$

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NIA

GA

RA

MO

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WK

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011

Exhibit (RRP-4) Schedule 1 Sheet 1 of 4

126

Exh

ibit

(RR

P-4)

Sche

dule

1Sh

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of 4

Witn

ess:

Rev

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Rat

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3

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(40

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l Pro

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554.

7$

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RA

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WK

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127

Exh

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(RR

P-4)

Sche

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Witn

ess:

Rev

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Y20

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flatio

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11In

flatio

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djC

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12In

flatio

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djC

Y20

13(a

)(b

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)(d

)(e

)(f

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)(h

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(j)(k

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(m)

(n)

(o)

(p)

(q)

Reg

Acc

ount

408

140

1Tx

Acc

r-N

Y S

tate

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y/To

wn

21,2

60,8

36

63

7,82

5

13

7,09

5

43,2

84

22

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662,

371

374,

411

147,

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23,2

63,4

68

69

7,90

4

58

6,03

0

21

1,04

0

24

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74

2,75

3

91

4,43

9

25

6,39

2

26

,672

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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

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8,35

7,77

4

250,

733

210,

541

75,8

20

8,

894,

867

26

6,84

6

32

8,52

7

92

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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

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20,7

10

8,

167

1,

286,

772

38

,603

32,4

15

11

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1,36

9,46

3

41,0

84

50

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14,1

82

1,

475,

309

4Tx

Acc

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Y S

choo

l Tax

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1,24

6,63

2

267,

952

84

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43,1

53,5

68

1,

294,

607

73

1,78

7

28

8,57

5

45

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1,36

4,05

6

1,14

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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

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71,6

29,5

18

2,

148,

886

46

1,88

3

145,

828

74

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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

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2,

502,

397

3,

080,

819

86

3,80

7

89

,860

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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

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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

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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

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6,76

1,21

0

202,

836

170,

322

61,3

36

7,

195,

703

21

5,87

1

26

5,76

9

74

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7,75

1,86

0

8

Tx A

ccr-

NY

Vill

age

Taxe

s95

1,35

2

28

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6,

135

1,93

7

98

7,96

4

29

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16,7

54

6,

607

1,

040,

963

31

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26,2

23

9,

443

1,

107,

858

33

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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

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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

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1,

174,

397

1,

445,

855

40

5,39

2

42

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10

Tota

l57

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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

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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

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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


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

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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


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


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


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


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


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)


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


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


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)


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


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


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)



Federal and State Income Taxes for the




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

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RR

AB

LE

TA

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EST

AT

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OR

YD

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NE

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INC

OM

ER

AT

ER

EV

ER

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SFI

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NET

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OM

E B

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RE

FED

ERA

L &

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TE IN

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ME

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ESEx

hibi

t RR

P-1

477,

577,

117

477,

577,

117

167,

152,

000

167,

152,

000

2 3A

DD

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ERG

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516

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816

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857

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(57,

682,

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05

PRO

VIS

ION

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R D

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t RR

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197,

521,

169

197,

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69,1

32,0

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414

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10IN

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OTH

ER S

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CO

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L H

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ric Y

ears

(44,

186,

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35,3

48,8

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)(1

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0)16

TAX

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REC

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H

isto

ric Y

ears

(141

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)(2

9,83

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(59,

847,

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17R

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TE T

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OR

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Exhi

bit R

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3(1

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(141

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)(4

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AM

OR

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TIO

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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

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ET

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AB

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ET

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ER

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E B

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ne 1

477,

577,

117

477,

577,

117

33,9

08,0

0033

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31 32A

DD

ITIO

NS

33R

EAL

ESTA

TE T

AX

ES P

ER B

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KS

Line

614

1,78

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149

Documents

RRP Testimony Final - National Grid · 13 my curriculum vitae provided as Exhibit __ (RRP-11). 14 15 Q. Have you previously testified before this commission? 16 A. Yes, a brief description