Secretary Federal Energy Regulatory Commission 888 First ...€¦ · October 16, 2014 through May 31, 2015. 1. This filing revises the rates filed on August 14, 2014 in Docket ER091498-

VIA ELECTRONIC FILING November 17, 2014 Kimberly D. Bose Secretary Federal Energy Regulatory Commission 888 First Street, N.E. Washington, DC 20426

RE: Fitchburg Gas and Electric Light Company, Compliance - Revised Annual Informational Filing Under Formula Rates, Docket Nos. EL11-66-001 and ER09-1498-000

Dear Secretary Bose:

On October 16, 2014 the Federal Energy Regulatory Commission (“Commission”) issued Opinion No. 531-A in Docket EL11-66-001 which established returns on equity (“ROE”) applicable for the local and regional transmission services provided by the New England Transmission Owners (“NETOs”) for the refund period of October 1, 2011 through December 31, 2012, and the going-forward period from October 16, 2014. Opinion No. 531-A directed the NETOs to submit revised rates thirty (30) days from the date of Opinion 531-A. Fitchburg Gas and Electric Light Company (“FG&E” or the “Company”) hereby submits a revision, effective October 16, 2014, of the data and schedules used to calculate its annual transmission revenue requirement for Non-PTF Local Network Transmission Service, Firm Point-to-Point Transmission Service and Non-Firm Point-to-Point Transmission Service for the period of October 16, 2014 through May 31, 2015.1 This filing revises the rates filed on August 14, 2014 in Docket ER09-1498-000 for the period June 1, 2014 through May 31, 2015 (Attachment 1). In accordance with Opinion 531-A, FG&E calculated revised rates at the approved return on equity (ROE) of 10.57%.

FG&E will file tariff revisions in compliance with Opinion No. 531-A together with the other NETOs, concurrently with this filing. On November 6, 2014, the NETOs sought an extension of time in which to complete refunds and submit the refund reports to the Commission.

1 These rates apply to transmission services over FG&E's Non-Pool Transmission Facilities.

Ruta Kalvaitis Skucas

900 17th Street N.W. Suite 350

Washington, D.C. 20006

202.470.6428 voice 888.847.9228 fax [email protected]

www.pierceatwood.com

Admitted in: Maryland and DC

{W4587160.1}

20141117-5287 FERC PDF (Unofficial) 11/17/2014 4:44:56 PM

Page 2 November 17, 2014

FG&E asks that this extension, if granted, also apply to FG&E’s completion of refunds and submission of refund reports for its Pool Transmission Facilities.

Service beginning October 16, 2014 will be charged at the revised rates shown in Attachment 1. Customers under FG&E’s local service schedule are being served with a copy of this filing. This filing has also been sent to the Massachusetts Department of Public Utilities.

Correspondence or communications with respect to this filing may be addressed to the following persons:

Karen M. Asbury Director of Regulatory Services Unitil Service Corp. 6 Liberty Lane West Hampton, NH 03842-1720 Phone: (603) 773-6441 [email protected]

Ruta Kalvaitis Skucas Pierce Atwood LLP 900 17th St. NW, Suite 350 Washington, DC 20006 Phone: (202) 470-6428 Fax: (888) 847-9228 [email protected]

Sincerely,

Ruta Kalvaitis Skucas Attorney to Fitchburg Gas and Electric Light Company

Enclosure

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mailto:[email protected]


Attachment 1: Transmission Rate Calculations1 Revised Effective October 16, 2014

Exhibit FGE-2: Calculation of Annual Transmission Revenue

Requirement based on calendar year 2013 data Exhibit FGE-3: Workpapers in support of revenue requirement

Workpaper 1: Cost of Capital Workpaper 5: Internal Transmission Revenue Workpaper 5.1: Internal Transmission Revenue Workpaper 6: Labor Allocator Workpaper 10: Accumulated Deferred Income Tax Workpaper 10.1: Detail of Accumulated Deferred Income Tax Worrkpaper 11: Other Regulatory Assets/Liabilities-FAS 109 Workpaper 12: Equity AFUDC Portion of Depreciation

Expense Workpapers 13-25: PTF Revenue Requirements Workpapers 26-29: Schedule 1 Revenue Requirements

Exhibit FGE-6: Summary of Rates for Local Service

1 For ease of reference FG&E has maintained the same numbering of exhibits and workpapers from its September 30, 2003 filing in which the initial rates were approved effective October 1, 2003. Exhibit FGE-3, workpapers 10, 11 and 12 have been added since the initial filing. Some exhibits and workpapers have been omitted as they are not relevant to this filing. Additional workpapers, 5.1, 10.1, and 13 through 29, included in support of the amounts shown on Worksheet 1, Columns 5 and 6, have been added to comply with Staff’s Guidance on Formula Rate Updates issued July 17, 2014.


Attachment 2: List of Filing Recipients


Attachment 2 Fitchburg Gas and Electric Light Company List of Filing Recipients Customers Mr. Benjamin Vautrin Chief Financial Officer Keolis Commuter Services 470 Atlantic Avenue, 3rd Floor Boston, MA 02110 617-849-7968 [email protected] Mr. John R. Shue, PE VP operations – New England GDF SUEZ Energy Generation, NA, Inc. 20 City Square, Suite 3 Charlestown, MA 02129 Local - 617-886-8734 HQ – TX – 713-636-1143 [email protected] Mr. Elliott Stewart Director of Origination – New England GDF SUEZ Energy Generation, NA, Inc. 20 City Square, Suite 3 Charlestown, MA 02129 Local - 617-886-8725 HQ – TX – 713-636-1284 [email protected] Mr. Mike Giordano Deputy Director of Finance and Administration MBTA Building 3 21 Arlington Avenue Charlestown, MA 02129 617-222-1522 [email protected] Regulators Mr. Mark D. Marini Secretary - Department of Public Utilities One South Station, 5th Floor Boston, MA 02110





CERTIFICATE OF SERVICE

I HEREBY certify that I have this day caused the foregoing document to be

served, via electronic mail, upon each person designated on the Official Service List

compiled by the Secretary in these proceedings.

DATED at Washington, D. C. as of the 17th day of November, 2014.

/s/ Ruta Kalvaitis Skučas Ruta Kalvaitis Skučas, Esq.

{W3954615.1}


Fitchburg Gas and Electric Light Company Exhibit FGE-2Revenue Requirement of Non-PTF Internal Transmission Services Worksheet 1 of 6

Twelve Months Ended December 31, 2013 Shading denotes an input Revised Effective October 16, 2014 per FERC Order, EL11-66

(5) (6)

(4)(1) Total (8)

Line (2) (3) Internal System Control (7) Worksheet ReferenceNo. Description Attachment H Transmission PTF* and Dispatch*** Non-PTF For Column (4)

INVESTMENT BASE:1 Transmission Plant III. A.1.(a) 12,659,061 4,861,283 0 7,797,778 Worksheet 3, line 12 Transmission Related Intangible Plant III. A.1.(b) 67,152 0 67,152 Worksheet 3, line 23 Transmission Related General Plant III. A.1.(c) 143,876 129,037 ** 0 14,839 Worksheet 3, line 34 Transmission Related Common Plant III. A.1.(d) 243,388 0 0 243,388 Worksheet 3, line 45 Transmission Plant Held For Future Use III. A.1.(e) 0 0 0 0 Worksheet 3, line 66 Total Utility Plant 13,113,477 4,990,320 0 8,123,157

7 Transmission Related Depreciation & Amortization Reserve III. A.1.(f) 4,964,271 1,852,768 0 3,111,503 Worksheet 3, line 108 Transmission Related Accumulated Deferred Income Taxes III. A.1.(g) 2,409,598 922,951 0 1,486,647 Worksheet 3, line 139 Transmission Related Loss On Reacquired Debt III. A.1.(h) 0 0 0 0 Worksheet 3, line 1410 Transmission Related Other Regulatory Assets/Liabilities III. A.1.(i) 750,178 218,872 0 531,306 Worksheet 3, line 1811 Net Investment (Lines 6-7-8+9+10) 6,489,786 2,433,473 0 4,056,313

12 Transmission Prepayments III. A.1.(j) 225,173 86,470 0 138,703 Worksheet 3, line 1913 Transmission Plant Materials & Supplies III. A.1.(k) 120,012 46,087 0 73,925 Worksheet 3, line 2014 Transmission Related Cash Working Capital III. A.1.(l) 62,418 18,042 0 44,376 Worksheet 3, line 27

15 Total Investment Base (Lines 11+12+13+14) 6,897,389 2,584,072 0 4,313,317

REVENUE REQUIREMENT:16 Return and Associated Income Taxes III. A. 833,894 312,448 0 521,446 Worksheet 2, line 2117 Depreciation Expense III. B. 359,848 138,187 0 221,661 Worksheet 4, line 418 Amortization of Intangible Plant and Other Regulatory

Assets/Liabilities III. C. 29,848 0 0 29,848 Worksheet 4, line 719 Amortization of Rate Case Expenses III. D. 0 0 0 0 Worksheet 4, line 820 Amortization of Loss on Reacquired Debt III. E. 0 0 0 0 Worksheet 4, line 921 Amortization of Investment Tax Credits III. F. 0 0 0 0 Worksheet 4, line 1022 Property Tax Expense III. G. 155,167 59,434 0 95,733 Worksheet 4, line 1323 Payroll Tax Expense III. H. 6,658 2,557 0 4,101 Worksheet 4, line 3024 Transmission Operation & Maintenance Expense III. I. 169,908 32,354 39,065 98,489 Worksheet 4, line 1725 Customer Accounting Bad Debts Expense III. J. 37,818 0 0 37,818 Worksheet 4, line 1826 Administrative & General Expense III. K. 291,617 111,983 0 179,634 Worksheet 4, line 2927 Transmission Related Taxes and Fees Charge III. L. 0 0 0 028 Transmission Rents Received from Electric Property III. M. 0 0 0 029 Revenues for Through or Out Service III. N. 0 0 (354) 35430 Total Revenue Requirement (Lines 16 through 29) 1,884,758 656,963 38,711 1,189,084

* Excludes Support Revenues and Expenses to the extent that they are not included in Column (4). In accordance with Attachment H, III A. of Schedule 21 - FG&E, 1208896for purposes of this computation, the PTF amount was calculated using the same cost of capital rate as used for Total Internal Transmission in column (4). 19,812See Exh. FGE-3, Workpapers 13-25.** Includes common plant allocated to PTF.*** See Exh. FGE-3, Workpapers 26-29.

ISO New England, Inc. Less PTF Recovery Through

FERC Electric Tariff No. 3


Fitchburg Gas and Electric Light Company Exhibit FGE-2Total Internal Transmission Return and Associated Income Taxes Worksheet 2 of 6

Shading denotes an input(1)Line (2)No. Description

Capital Structure & Cost of Capital:(3) (4) (5) (6)

CAPITALIZATION CAPITALIZATION COST OF COST OF EQUITY12/31/13* RATIOS CAPITAL CAPITAL PORTION

1 LONG-TERM DEBT $ 68,100,000 51.19% 6.99% * 3.58%2 PREFERRED STOCK 0 0.00% 0.00% * 0.00% 0.00%3 COMMON EQUITY 64,923,997 48.81% 10.57% 5.16% 5.16%

4 TOTAL INVESTMENT RETURN $ 133,023,997 100.00% 8.74% 5.16%

*See Exhibit FGE-3, Workpaper 1

Cost of Capital Rate:

5 (a) Weighted Cost of Capital = 8.74%

6 Total IT Inv. Eq. AFUDC 7 (b) Federal Income Tax = ( R.O.E. + ( (Tax Credit + of Deprec. Exp.** ) / Totl IT Inv. Base) x Federal Income Tax Rate )8 ( 1 - Federal Income Tax Rate )

9 = ( 0.0516 +( 0 + 1,380 ) / 6,897,389 ) x 0.34 )10 ( 1 - 0.34 )

11 = 2.67%

12 Total IT Inv. Eq. AFUDC 13 (c) State Income Tax = ( R.O.E. + ( (Tax Credit + of Deprec. Exp.** ) / Total IT Inv. Base) + Federal Income Tax )* State Income Tax Rate14 ( 1 - State Income Tax Rate )

15 = ( 0.0516 +( 0 + 1,380 ) / 6,897,389 ) + 0.0267000 )* 0.0816 ( 1 - 0.08 )

17 = 0.68%

18 Cost of Capital Rate [(a)+(b)+(c)] 12.09%

Total Internal Transmission Return and Associated Income Taxes:

Amount19 Total IT Investment Base $ 6,897,389 Worksheet 1, Line 15

20 Cost of Capital Rate 12.09%

21 Total IT Return and Associated Income Taxes 833,894


Fitchburg Gas and Electric Light Company Exhibit FGE-2Investment Base Detail Worksheet 3 of 6

Shading denotes an input

(4)Internal (5)

(1) Transmission Internal (6)Line (2) (3) Allocation Transmission FERC Form 1/OtherNo. Description Total Electric Factors Related Reference for column (3)

Utility Plant In Service1 Transmission Plant 12,659,061 NA 12,659,061 Page 207.58g less Account No. 353.1 Station Eqpt. Joint

Owned of $02 Intangible Plant 1,083,188 6.1995% (a) 67,152 Page 205.5g3 General Plant 2,320,777 6.1995% (a) 143,876 Page 207.99g4 Common Plant 3,925,961 6.1995% (a) 243,388 Page 201, lines 3h plus 6h times 50.20% (c) (d)5 Total 13,113,477

6 Plant Held for Future Use 35,698 0 Page 214

Depreciation & Amortization Reserve7 Transmission Plant Depreciation 4,699,686 (1) NA 4,699,686 Page 219.25c8 Intangible Plant & Common Plant Amortization 2,251,131 6.1995% (a) 139,558 Page 200.21c9 General Plant & Common Plant Depreciation 2,016,744 (2) 6.1995% (a) 125,027 Page 219.28c

10 Total 4,964,271

Accumulated Deferred Income Taxes11 Accumulated Deferred Taxes (281-283) (23,513,552) 10.2920% (b) (2,420,015) Page 275.2k + 277.9k. See Exhibit FGE-3, Workpaper 10.12 Accumulated Deferred Taxes (190) 101,216 10.2920% (b) 10,417 Page 234.8c13 Total (2,409,598)

14 Total Loss on Reacquired Debt 0 10.2920% (b) 0 Page 111.81d

Other Regulatory Assets/Liabilities15 FAS 106 Regulatory Assets/Liabilities 759,148 6.1995% (a) 47,063 Page 232.17f16 FAS 109 Regulatory Assets/Liabilities 5,093,641 10.2920% (b) 524,238 Page 232.16f - 278.1f 17 Other Regulatory Assets/Liabilities 1,738,020 10.2920% (b) 178,877 Page 232.18f18 Total 750,178

19 Prepayments 3,632,139 6.1995% (a) 225,173 Page 111.57c *p.200.8.c/p.200.8.b (c)

20 Transmission Plant Materials and Supplies 120,012 NA 120,012 Page 227.8c

21 Transmission Related Cash Working Capital22 Transmission Operation & Maintenance Expense 169,908 Worksheet 1, Column (4), Line 2423 Customer Accounting Bad Debts Expense 37,818 Worksheet 1, Column (4), Line 2524 Administrative & General Expense 291,617 Worksheet 1, Column (4), Line 2625 Subtotal 499,34326 0.125 x 45 / 36027 Total 62,418

(a) Wages and Salaries. See Worksheet 5, line 5(b) Plant. See Worksheet 5, line 14(c) Electric only (gas portion removed). FERC Form 1 includes gas and electric divisions. Schedule FG&E-21, Attachment H, Annual Revenue Requirement for Local Network Service of ISO-NE's Transmission, Markets and Services Tariff specifies that transmission related common plant is allocated based on Common Plant multiplied by the Transmision Wages and Salaries Allocation Factor. (d) See Exhibit FGE-3, Workpaper 6, Gas and Electric Labor Allocator. Electric portion of common plant derived using a labor allocatoras discussed in the Company's September 30, 2003 ER03-1410 filing, FGE-1, page 25 of 53 approved November 25, 2003. (1) Includes depreciation adjustment of $33,554.42 for 2009 and 2010 depreciation rate changes approved in ER12-1453-000 (see Exhibit FG&E-2). Actual adjustment differs due to rounding. (2) Includes depreciation adjustment of $16,319.93 for 2009 and 2010 depreciation rate changes approved in ER12-1453-000 (see Exhibit FG&E-2). Actual adjustment differs due to rounding.


Fitchburg Gas and Electric Light Company Exhibit FGE-2Revenue Requirements Detail Worksheet 4 of 6


(4)Internal (5)

(1) Transmission Internal (6)Line (2) (3) Allocation Transmission FERC Form 1/OtherNo. Description Total Electric Factors Related Reference for column (3)

Depreciation Expense1 Transmission Plant 347,642 NA 347,642 Page 336.7b2 General Plant 81,060 6.1995% (a) 5,025 Page 336.10b3 Common Plant 115,828 6.1995% (a) 7,181 Page 336.11b4 Total Depreciation 359,848

Amortization of Intangible Plant and Other Regulatory Assets/Liabilities

5 Intangible Plant & Common Plant 188,353 6.1995% (a) 11,677 Page 336.12d6 Other Regulatory Assets/Liabilities-FAS 109 (and other) 176,557 10.2920% (b) 18,171 Page 115.10h see Workpaper 117 Total 29,848

8 Amortization of Rate Case Expenses 0 NA 0

9 Amortization of Loss on Reacquired Debt 0 10.2920% (b) 0 Page 117.64c

10 Amortization of Investment Tax Credits 0 10.2920% (b) 0 Page 266.8f

Property Tax Expense11 Total Property Taxes 1,507,645 10.2920% (b) 155,167 Page 263.9i, 10i, 11i, 16i12 Less amounts billed to Select Energy 0 10.2920% (b) 0 Page 263.11i Represents costs billed to

Select Energy, Inc. under Entitlement Sales and Administrative Services Agreement, Ended September 2007

13 Total 155,167

Transmission Operation & Maintenance Expense (e)14 Total Transmission Expense 7,193,944 NA 7,193,944 Page 321.112b + 322.131b15 Less Transmission of Electricity by Others--Acct. 565 (6,857,446) NA (6,857,446) Page 321.96b16 Less amounts billed to Select Energy, excluding Acct.565 0 NA 0 Represents costs in Account No. 562

billed to Select Energy, Inc. under Entitlement Sales and Administrative Services Agreement

17 Less Account No. 561.4 (142,351) NA (142,351) Page 321.88b less costs recovered through Schedule 1, see Exh FGE-3, Workpaper 28.

18 Less Account No. 575.7 (24,239) NA (24,239) Page 322.121b19 Total 169,908 169,908

20 Customer Accounting Bad Debts Expense 1,473,287 2.5669% (c) 37,818 Page 322.162b

Administrative & General Expense21 Total Administrative and General Expense 4,960,299 Page 323.197b22 Less Acct. 924 Property Insurance (39,507) Page 323.185b23 Less Acct. 928 Regulatory Commission Expense (392,636) Page 323.189b24 Less Acct. 930.1 General Advertising Expense 0 Page 323.191b25 Subtotal 4,528,156 6.1995% (a) 280,72126 Plus Allocated Acct. 924 Property Insurance 39,507 10.2920% (b) 4,066 Page 323.185b less ($0) billed to Select

Energy, Inc. under Entitlement Sales and Administrative Services Agreement

27 Plus Acct. 928 FERC fees and assessments 6,830 NA 6,830 Page 351.6h28 Plus Acct. 928 Other Transmission Related Expense 0 NA 0 Page 351.12h29 Plus Acct. 930.1 General Advertising Exp.-Int. Transmission 0 NA 030 Less amounts billed to Select Energy 0 6.1995% (a) 0 Represents costs in Account Nos. 920,

921, 923, 925, 926 & 931 billed to Select Energy, Inc. under Entitlement Sales and Administrative Services Agreement

31 Net Administrative & General Expense 4,574,493 291,617

32 Payroll Tax Expense 107,395 6.1995% (a) 6,658 Footnote (d)

(a) Wages and Salaries. See Worksheet 5, line 5(b) Plant. See Worksheet 5, line 14(c) Revenue. See Worksheet 5, line 19(d) Payroll taxes:

Federal Unemployment 1,395 Page 263.4i FICA 198,197 Page 263.2i Medicare 0 State Unemployment 11,270 Page 263.6i MA Universal Health 2,078 Page 263.8i Payroll Taxes Capitalized (105,545) Page 263.15i Total 107,395

(e) Subtract PTF Support Expense only if included in Line 19.


Fitchburg Gas and Electric Light Company Exhibit FGE-2Allocation Factors Worksheet 5 of 6


(1) (4)Line (2) (3) FERC Form 1/OtherNo. Description Amounts Reference for column (3)

Allocations From Total Electric To Internal Transmission

Wages and Salaries Allocation Factor

1 Direct Transmission Wages and Salaries 47,639 Page 354.21b

2 Total Electric Wages and Salaries 797,046 Page 354.28b3 Less Administrative and General Wages and Salaries (28,608) Page 354.27b4 Total Electric Wages and Salaries net of A&G 768,438

5 Allocation Percent 6.1995%

Plant Allocation Factor

6 Transmission Plant 12,659,061 Worksheet 3, Column 5, Line 17 Plus Transmission-Related Intangible Plant 67,152 Worksheet 3, Column 5, Line 28 Plus Transmission-Related General Plant 143,876 Worksheet 3, Column 5, Line 39 Plus Transmission-Related Common Plant 243,388 Worksheet 3, Column 5, Line 4

10 Total Transmission-Related Plant In Service 13,113,477

11 Total Electric Plant in Service 123,488,869 Page 207.104g12 Plus Total Electric-Related Common Plant 3,925,961 Worksheet 3, Column 3, Line 413 Total Electric-Related Plant in Service 127,414,830


Revenue Allocation Factor

15 Total Internal Transmission Revenue 1,228,463 Exhibit FGE-3, Workpaper 5

16 Total Electric Sales to Ultimate Customers 49,016,698 Page 300.10b17 Less Unbilled Revenue (1,159,430) Page 301, footnote18 Total Billed Revenue From Sales to Ultimate Customers 47,857,268



Exhibit FGE-2Worksheet 6 of 6

Summary of Fitchburg Gas and Electric Light Company SystemMonthly Coincident Peaks for 2013

(Megawatts) Shading denotes an input

(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12) (13) (14)Line No. Description JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC

1 Day 23 4 4 2 31 24 18 21 11 30 25 172 Hour 18:00 18:00 18:00 20:00 16:00 17:00 15:00 16:00 19:00 18:00 18:00 17:00

3 Megawatts 78 74 68 64 74 87 94 77 86 67 73 83

4 Total Megawatts 925

5 Annual FG&E System Average 12 CP Load 77

NOTE: Numbers represent FERC Form 1 Page 401b coincident peaks.


Exhibit FGE-3WORKPAPER 2 Workpaper 1

Fitchburg Gas and Electric Light Company2013 Cost of Capital

FERC Form 1 Amount Reference

Line Outstanding WeightedNo. 12/31/13 C.O.C. Weight Cost of Capital

1 Common Stock Equity $64,923,997 10.57% 48.81% 5.16%2 Long Term Debt 68,100,000 6.99% 51.19% 3.58%

3 Total $133,023,997 8.74%

Common Equity

4 Common Stock $22,627,257 Page 112.2.c + p.112.6.c5 Retained Earnings 12,803,823 Page 112.11.c + 112.12c6 Capital Stock Expense (1,507,083) Page 254.9.b x -17 Misc. Paid in Capital 31,000,000 Page 112.7.c

8 Total $64,923,997

Long Term Debt (1)

Amount Annual AnnualOutstanding Issuance Interest Total Annual Effective

Series 12/31/13 Expense (2) Expense (3) Cost Cost %

9 30 Year Note, due Nov 30, 2023 6.75% 17,100,000 10,671 1,154,250 (3) 1,164,921 6.81%10 30 Year Note, due Jan 15, 2029 7.37% 12,000,000 3,279 884,400 887,679 7.40%11 30 Year Note, due Jun 1, 2031 7.98% 14,000,000 11,857 1,117,200 1,129,057 8.06%12 22 year Notes, due Oct 15, 2025 6.79% 10,000,000 7,851 679,000 686,851 6.87%13 25 year Notes, due Dec 15, 2030 5.90% 15,000,000 9,221 885,000 894,221 5.96%

14 Total $68,100,000 $42,879 $4,719,850 $4,762,729 6.99%

(1) Pages 256 - 257, FERC Form 1. (2) Total ties to FERC Form 1, page 117.63c.(3) Proformed interest, outstanding balance reduction in 2013. Detail of Annual Interest Expense, FERC Form 1:30 Year Note, due Nov 30, 2023 1,282,500 30 Year Note, due Jan 15, 2029 884,400 30 Year Note, due Jun 1, 2031 1,117,200 22 year Notes, due Oct 15, 2025 679,000 25 year Notes, due Dec 15, 2030 885,000

$4,848,100 Page 117.62c


Fitchburg Gas and Electric Light Company Exhibit FGE-3Internal Transmission Revenues (1) Workpaper 5


LineNo. Customer Class Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13 Oct-13 Nov-13 Dec-13 Total1 RES R1 $37,455.42 $41,726.74 $35,395.21 $33,888.83 $29,384.22 $34,674.55 $44,729.89 $44,008.67 $38,997.75 $28,905.63 $34,313.14 $39,106.93 $442,586.982 R-2 $8,741.66 $10,165.12 $8,861.60 $8,594.47 $7,490.99 $7,856.70 $9,382.01 $9,420.10 $8,322.87 $6,277.52 $8,016.36 $9,618.96 $102,748.363 R-4 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.004 G-1 $1,310.23 $1,536.51 $1,304.97 $1,284.49 $1,153.54 $1,166.26 $1,279.64 $1,268.34 $1,241.08 $1,072.69 $1,264.75 $1,437.31 $15,319.815 G-2 $22,083.13 $26,053.55 $23,803.81 $24,228.76 $24,275.09 $26,197.83 $27,929.89 $28,134.16 $27,986.48 $24,387.13 $24,620.36 $24,969.72 $304,669.916 G3 $25,462.52 $27,492.77 $25,348.57 $27,616.25 $28,422.12 $30,270.33 $29,450.18 $29,523.15 $29,398.96 $28,055.81 $28,444.98 $26,378.94 $335,864.587 G4 $20.58 $50.40 $27.89 $43.32 $52.30 $60.24 $52.07 $57.26 $68.68 $62.11 $59.53 $48.61 $602.998 G5 $117.58 $223.92 $174.34 $132.65 $80.36 $64.25 $72.46 $85.21 $71.30 $54.49 $68.82 $122.57 $1,267.959 G6 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.0010 Housing Authority $863.87 $1,048.69 $793.35 $682.53 $433.93 $368.79 $362.80 $365.79 $335.46 $373.65 $681.41 $960.71 $7,270.9811 Special Contracts $579.03 $513.52 $535.60 $645.88 $420.10 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $2,694.1312 OL & Mun. & St Ltg. $1,151.83 $1,271.61 $1,329.61 $1,398.25 $792.97 $1,686.91 $1,204.47 $1,388.41 $1,416.32 $1,349.97 $1,611.45 $835.41 $15,437.2113 OL & Gen Dusk Ltg. $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.0014 G3 Accrual $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.0015 Total IT revenues 97,785.85$ 110,082.83$ 97,574.95$ 98,515.43$ 92,505.62$ 102,345.86$ 114,463.41$ 114,251.09$ 107,838.90$ 90,539.00$ 99,080.80$ 103,479.16$ $1,228,462.90

(1) Exh. FGE-3, Workpaper 5.1 provides a reconciliation to FERC Form 1.

Calendar Year 2013


Exhibit FGE-3

Fitchburg Gas and Electric Light Company d/b/a Unitil Workpaper 5.1

Year: 2013Col 1 #2 #3 #4 #5 #6 #7 #8 #9

Account 440 442 442 444 445 446 448 Total

Distribution Revenue 11,374,452 5,583,217 2,839,564 328,074 137,301 20,262,607

Internal Transmission Revenue 545,335 321,861 338,559 15,437 7,271 1,228,463

External Transmission Revenue 2,501,986 1,558,753 2,194,976 34,877 33,354 6,323,946

Other (Energy Efficiency) 444,163 275,244 381,500 6,189 5,921 1,113,018

Other (Energy Efficiency Rate Adj) 1,141,263 777,189 1,042,771 17,485 18,543 2,997,252

Other (Transition) 4,290,825 2,623,213 3,512,869 59,400 57,316 10,543,624

Other (Transition Surcharge) 521,908 315,883 411,313 6,687 6,639 1,262,430

Other (Transformer Ownership Credit) - (5,950) - - - (5,950)

Other (Unbilled Revenue)(1) 453,105 267,133 449,975 (10,783) 1,159,430

Other (Accrued Revenue) (1) (7,246,833) (3,736,635) (2,656,074) (128,604) (62,721) (13,830,867)

Other (Default Adder) 435,039 174,894 8,378 3,363 - 621,674

Other (Pension Adjustment Factor) 416,982 258,552 358,576 5,826 5,562 1,045,498

Other (Residential Assistance Ad Factor) 620,710 384,911 534,007 8,613 8,279 1,556,521

Other (Net Metering Credit) (19,267) (143,043) - - - (162,310)

Other (Net Metering Surcharge) 6,859 4,286 6,081 52 92 17,370

Other (Revenue Decoupling Adjustment Clause) (87,044) (53,725) (73,458) (1,202) (1,161) (216,591)

Other (Attorney General Adjustment Clause) 44,556 26,924 34,214 525 596 106,814

Energy Supply 11,531,191 4,563,849 257,215 88,270 37 16,440,562

Low Income Credit (1,446,794) - - - -

Total 25,528,438 13,196,556 9,640,466 434,210 217,028 - - 49,016,697 Where the total line is equivalent toFERC FORM I, page 300, line 2 4 5 6 7 8 9 10

(1) Ties to FERC Form I, p. 304 (see footnote).

2013 Electric Division RevenueReconciliation to FERC Form 1


Exhibit FGE-3Workpaper 6

Gas Electric TotalSalaries & Wages - Operation & Maintenance (1) (2)

Production - Maint 46,385$ 46,385$ Production - Oper 155,154 155,154 Transmission - Maint 61,080 61,080 Transmission - Oper 4,543 26,177 30,720 Distribution - Maint 198,382 296,528 494,910 Distribution - Oper 436,055 408,821 844,876 Customer Accounting 31,787 17,581 49,369 Admin & General 23,982 33,118 57,100 Total - O&M Direct Labor 896,289 843,306 1,739,595

Construction (3)Direct Payroll 484,147 480,595 964,743 Overhead Payroll 490,888 562,529 1,053,418 Total - Construction Direct Labor 975,036 1,043,125 2,018,160

Total Direct Labor 1,871,325$ 1,886,430$ 3,757,755$

Labor Allocator 49.80% 50.20% 100.00%

(1) 2012 FERC Form 1, p. 355.52b through p.355.61b.(2) 2012 FERC Form 1, p.354.20b through p.354.27b.Total - FERC Form 1, p.355.65b.

(3) Detail of total construction wages and salaries (FF1, p.355.71b):

Direct Payroll - Gas $484,147Direct Payroll - Electric $480,595Overhead Payroll - Gas $490,888Overhead Payroll - Electric $562,529Subtotal $2,018,160Direct Payroll - Common $65,555Overhead Payroll - Common $162,818Incentive Compensation 71,659.00 Mobile Data Systems 8,630.56 Subtotal $308,662Total (FF1, p.355.71b) $2,326,822

Labor AllocatorFitchburg Gas and Electric Light Company

2012 percentages applicable to 2013 costs



20131. Account 281 Accumulated Deferred Income Taxes - Accelerated Amortization Property -$ FF1, Page 273.8k2. Account 282 Accumulated Deferred Income Taxes - Other Property 22,433,476$ FF1, Page 275.2k3. Account 283 Account 283 - Electric (1) 560,530$ FF1, Page 277.3k4. Account 283 Less FAS 158 (6,446,269)$ Workpaper 10.1, L. 485. Account 283 Less Storm Restoration 5,305,423$ Workpaper 10.1, L. 526. Account 283 FAS 109 Gross-up 621,299$ Workpaper 10.1, L. 54

23,513,552$ Worksheet 3, Line 11

(1) In accordance with Schedule 21-FG&E, Attachment H, total Accumulated Deferred Income Taxes shall equal the net of the deferred tax balance as recorded in FERC Account Nos. 281-283 and FERC Account 190. FG&E has adjusted Account 283 for FAS 158 as required by AI07-1-000, Commission Accounting and Reporting Guidanceto Recognize the Funded Status of Defined Benefit Postretirement Plans, and and FAS 109 Gross-up as required by AI93-5-000, Accounting for Income Taxes. FG&E has adjusted Account 283 for Storm Restoration as storm costs are recovered separately.See Workpaper 10.1 for Account 283 detail.

Fitchburg Gas and Electric Light CompanyAccumulated Deferred Income Tax


Fitchburg Gas and Electric Light Company Exhibit FGE-3Accumulated Deferred Income Tax Detail Workpaper 10.1

Account Number Description 2013

1. 20 20 00 00 283 01 30 DEF FIT - OTHER - ELEC 0.002. 20 20 00 00 283 01 32 DEF FIT - PRA 0.003. 20 20 00 00 283 01 34 DEF FIT - SFAS 106 OPEB 1,611,558.834. 20 20 00 00 283 01 35 DEF FIT - PENSION FAS 87 -1,476,127.465. 20 20 00 00 283 01 38 DEF FIT - BAD DEBT 140,197.116. 20 20 00 00 283 01 39 DEF FIT - ACCRUED REVENUE -384,193.927. 20 20 00 00 283 01 41 DEF FIT - PREPAID PROPERTY TAX 18,082.598. 20 20 00 00 283 01 42 DEF FIT - DEF RATE CASE COSTS -237,740.809. 20 20 00 00 283 01 47 DEF FIT - PENSION FAS 87 REG ASSET -670,023.85

10. 20 20 00 00 283 01 49 DEF FIT - SFAS 106 OPEB REG ASSET -265,687.3511. 20 20 00 00 283 01 50 DEF FIT - BAD DEBT-REG ASSET -79,585.3312. 20 20 00 00 283 01 51 DEF FIT - INSURANCE SETTLEMENTS -7,474.4613. 20 20 00 00 283 01 59 DEF FIT- FAS 158 PBOP - E 1,950,134.9114. 20 20 00 00 283 01 60 DEF FIT- PENSION FAS 158 - E 2,925,200.3415. 20 20 00 00 283 01 63 DEF FIT- SERP FAS 158 - E 360,840.1316. 20 20 00 00 283 01 67 DEF FIT- STORM RESTORATION -4,404,789.1717. 20 20 00 00 283 01 68 DEF FIT- ADIT UTILITY PLANT DIFFERENCES 0.0018. 20 20 00 00 283 03 01 ACCUM DEF (SFAS 109) GROSS-UP -621,298.8419. Total Electric Deferred Federal Income Tax -1,140,907.2720.21.22. 20 20 00 00 283 02 32 DEF SIT- PRA 0.0023. 20 20 00 00 283 02 34 DEF SIT- SFAS 106 OPEB 300,926.6224. 20 20 00 00 283 02 35 DEF SIT- PENSION FAS 87 -239,869.3125. 20 20 00 00 283 02 38 DEF SIT- BAD DEBT 37,568.5426. 20 20 00 00 283 02 39 DEF SIT- ACCRUED REVENUE -65,546.1427. 20 20 00 00 283 02 41 DEF SIT- PREPAID PROPERTY TAXES -6,199.9828. 20 20 00 00 283 02 42 DEF SIT- DEF RATE CASE COSTS 469.4929. 20 20 00 00 283 02 47 DEF SIT - PENSION FAS 87 REG ASSET -137,029.0330. 20 20 00 00 283 02 49 DEF SIT - SFAS 106 OPEB REG ASSET -54,319.9731. 20 20 00 00 283 02 50 DEF SIT - BAD DEBT-REG ASSET -16,273.1432. 20 20 00 00 283 02 51 DEF SIT - INSURANCE SETTLEMENTS 1,450.3333. 20 20 00 00 283 02 59 DEF SIT FASB 158 ADJ - PBOP - G 454,755.7834. 20 20 00 00 283 02 60 DEF SIT- PENSION FAS 158 - E 656,745.2235. 20 20 00 00 283 02 63 DEF SIT- SERP FAS 158 - E 98,592.1336. 20 20 00 00 283 02 67 DEF SIT- STORM RESTORATION -900,634.0337. Total Electric Deferred State Income Tax 130,636.5138. Total Electric Federal & State -1,010,270.7639. Accrued Revenue, p. 277.4k -449,740.0640. FERC Form 1, p. 277.3k -560,530.70 Workpaper 10, L.341. Less:42. 20 20 00 00 283 01 59 DEF FIT- FAS 158 PBOP - E 1,950,134.9143. 20 20 00 00 283 01 60 DEF FIT- PENSION FAS 158 - E 2,925,200.3444. 20 20 00 00 283 01 63 DEF FIT- SERP FAS 158 - E 360,840.1345. 20 20 00 00 283 02 59 DEF SIT FASB 158 ADJ - PBOP - G 454,755.7846. 20 20 00 00 283 02 60 DEF SIT- PENSION FAS 158 - E 656,745.2247. 20 20 00 00 283 02 63 DEF SIT- SERP FAS 158 - E 98,592.1348. 6,446,268.51 Workpaper 10, L.449.50. 20 20 00 00 283 01 67 DEF FIT- STORM RESTORATION -4,404,789.1751. 20 20 00 00 283 02 67 DEF SIT- STORM RESTORATION -900,634.0352. -5,305,423.20 Workpaper 10, L.553.54. 20 20 00 00 283 03 01 ACCUM DEF (SFAS 109) GROSS-UP -621,298.84 Workpaper 10, L.6



2013

20 20 10 00 407 09 00 FAS 109 NET REG ASSET AMORT 368,288.0420 20 10 00 407 09 01 AMORT EXP-FAS 109 REG LIABILITY - ELECTRIC (107,375.04)20 20 10 00 407 09 02 AMORT EXP-FAS 109 REG GROSS-UP - ELECTRIC (84,355.68) 176,557.32 (1) Worksheet 4, Line 620 20 10 00 407 10 00 AMORT OF PROP LOSS - 20 20 10 00 407 11 00 SEABRK DF DR AMORT - 20 20 10 00 407 12 00 AMORT RATE CASE COSTS - ELEC - 20 20 10 00 407 13 00 AMORT IT RATE CASE COSTS - 20 20 10 00 407 14 00 AMORT OF GENERATION ASSETS20 20 10 00 407 16 00 AMORT OF GENERATION ASSETS - 20 20 10 00 407 31 00 AMORTIZATION - 2008 ICE STORM 1,629,183.9620 29 01 08 407 01 00 AMORT ACCESS CHG REGLRY ASSET - 20 29 01 08 407 01 02 RESIDUAL VALUE CREDIT (RETURN OF INVESTMENT) - 20 29 01 08 407 03 00 Trans Chg-Amort Carry Chg Fxd Costs-Retn ON Invst Gen Assets - 20 29 01 08 407 03 88 Trans Chg-Amort Carry Chg Fxd Costs-Retn ON Invst Gen Assets - 20 29 01 23 407 01 00 PAF RECONCILIATION ADJ-ELECTRIC - 20 29 01 23 407 15 00 PAF RECONCILIATION ADJ-ELEC -

407 Amortization - Electric 1,805,741.28 FF1, Page 115.12g - 115.13g

(1) FG&E's formula rate provides for recovery of Amortization of Other Regulatory Assets/Liabilities-FAS 109 as recorded in account No. 404. In 2005, the account number for these costs was changed to Account No. 407. Schedule 21-FG&E was revised effective November 30, 2012 in docket ER13-474.

Fitchburg Gas & Electric Light CompanyOther Regulatory Assets/Liabilities-FAS 109



Source: Fixed Assets

Vintage Cost AFUDC % to Total1 Prior to 2012 (1) $9,326,582 $0 0.00%2 2012 (2) $82,438 $1,043 1.27%3 2013 (3) $2,905,915 $46,186 1.59%

4 Total $12,314,935 $47,229 0.38%

5 Internal Transmission Depreciation (Worksheet 4) $359,848

6 Equity AFUDC Portion of Depreciation Expense (L.4 * L.5) (Worksheet 2) $1,380

PTF Portion of AFUDC Expense7 PTF Allocation Factor (Exh FGE-3, Workpaper 18) 38.4016%

8 PTF Equity AFUDC Portion of Depreciation Expense $530 (Exh FGE-3, Workpaper 15) (L.5 * L.7)

(1) No data available prior to 2012. Cost derived from 2012 total transmission shown on 2012 FF1, p. 207.58g - 2012 qualifying projects. (2) 2012 AFUDC qualifying projects, Workpaper 22.(3) 2013 AFUDC qualifying projects, Workpaper 22.

Equity AFUDC Portion of Depreciation Expense Fitchburg Gas and Electric Light Company


Exh FGE-3, Workpaper 13


Sheet: Input PanelISO New England Inc.

Annual Transmission Revenue RequirementsPer FERC Electric Tariff No. 3, Section II - Attachment F


Submitted on: 15-May-14

Revenue Requirements for (year): Calendar Year 2013

Customer: Fitchburg Gas and Electric Light Company

Customer's NABs Number: 38

Name of Participant responsible for customer's billing: Fitchburg Gas and Electric Light Company

DUNs number of Participant responsible for customer's billing: 006-954-4317

PTF RevenueRequirements

Total of Attachment F - Sections A through I = $656,963 (a)

Total of Attachment F - Section J - Support Revenue $0 (b)

Total of Attachment F - Section K - Support Expense $0 (c)

Total of Attachment F - Section (L through O) $0 (d)

Sub Total - Sum (A through I) - J + K + (L through O) $656,963 (e)=(a)-(b)+(c)+(d)

Forecasted Transmission Revenue Requirements (per Appendix C to Attachment F Implementation Rule) N/A

Annual True-up (per Appendix C to Attachment F Implementation Rule) $0 (k)

Interest Charge on Annual True-up $0 (l)

Total $656,963 (p) =(e)+(k)+(l)

EFFECTIVE JUNE 1, 2014 @ 11.14% ROE

Page 15


Fitchburg Gas and Electric Light Company Exhibit FGE-3

Sheet: Worksheet 1 Annual Revenue Requirements of PTF Facilities Workpaper 14

for costs in 2013

Shading denotes an inputAttachment F FG&E

Reference Total ReferenceLine No. I. INVESTMENT BASE Section:

1 Transmission Plant (A)(1)(a) 4,861,283 Workpaper 16, line 1 column 52 General Plant (A)(1)(b) 129,037 Workpaper 16, line 2 column 53 Plant Held For Future Use (A)(1)(c) 0 Workpaper 16, line 4 column 54 Total Plant (Lines 1+2+3) 4,990,320

5 Accumulated Depreciation (A)(1)(d) 1,852,768 Workpaper 16, line 7 column 56 Accumulated Deferred Income Taxes (A)(1)(e) 922,951 Workpaper 16, line 10 column 57 Loss On Reacquired Debt (A)(1)(f) 0 Workpaper 16, line 11 column 58 Other Regulatory Assets (A)(1)(g) 218,872 Workpaper 16, line 14 column 59 Net Investment (Line 4-5-6+7+8) 2,433,473

10 Prepayments (A)(1)(h) 86,470 Workpaper 16, line 15 column 511 Materials & Supplies (A)(1)(i) 46,087 Workpaper 16, line 16 column 512 Cash Working Capital (A)(1)(j) 18,042 Workpaper 16, line 23 column 5

13 Total Investment Base (Line 9+10+11+12) 2,584,072

II. REVENUE REQUIREMENTS14 Investment Return and Income Taxes (A) 312,448 Workpaper 1515 Depreciation Expense (B) 138,187 Workpaper 17, line 3 column 516 Amortization of Loss on Reacquired Debt (C) 0 Workpaper 17, line 4 column 517 Investment Tax Credit (D) 0 Workpaper 17, line 5 column 518 Property Tax Expense (E) 59,434 Workpaper 17, line 8 column 519 Payroll Tax Expense (F) 2,557 Workpaper 17, line 17 column 520 Operation & Maintenance Expense (G) 32,354 Workpaper 17, line 13 column 521 Administrative & General Expense (H) 111,983 Workpaper 17, line 16 column 522 Transmission Related Integrated Facilities Charge (I) 0 Workpaper 2023 Transmission Support Revenue (J) 0 Workpaper 2024 Transmission Support Expense (K) 0 Workpaper 2025 Transmission Related Expense from Generators (L) 0 Workpaper 2026 Transmission Related Taxes and Fees Charge (M) 027 Revenue for ST Trans. Service Under NEPOOL Tariff (N) 028 Transmission Rents Received from Electric Property (O) 0

29 Total Revenue Requirements (Line 14 thru 28) 656,963


Exhibit FGE-3

Sheet: Worksheet 2 Fitchburg Gas and Electric Light Company Workpaper 15

Annual Revenue Requirements for costs in 2013


CAPITALIZATION CAPITALIZATION COST OF COST OF EQUITY12/31/13* RATIOS CAPITAL CAPITAL PORTION

LONG-TERM DEBT $ 68,100,000 51.19% 6.99% 3.58%PREFERRED STOCK 0 0.00% 0.00% 0.00% 0.00%COMMON EQUITY 64,923,997 48.81% 10.57% 5.16% 5.16%

TOTAL INVESTMENT RETURN $ 133,023,997 100.00% 8.74% 5.16%

*See Workpaper 1

Cost of Capital Rate=

(a) Weighted Cost of Capital = 0.0874

PTF Inv. Eq. AFUDC (b) Federal Income Tax = ( R.O.E. + ( (Tax Credit + of Deprec. Exp.** ) / PTF Inv. Base) x Federal Income Tax Rate )

( 1 - Federal Income Tax Rate )

= ( 0.0516 +( 0 + 530 ) / 2,584,072 ) x 0.34 )( 1 - 0.34 )

= 0.0266875

PTF Inv. Eq. AFUDC (c) State Income Tax = ( R.O.E. + ( (Tax Credit + of Deprec. Exp.** ) / PTF Inv. Base) + Federal Income Tax )* State Income Tax Rate

( 1 - State Income Tax Rate )

= ( 0.0516 +( 0 + 530 ) / 2,584,072 ) + 0.0266875 )* 0.08( 1 - 0.08 )

= 0.0068254

(a)+(b)+(c) Cost of Capital Rate = 0.1209129

(PTF)

INVESTMENT BASE $ 2,584,072 From Workpaper 14

x Cost of Capital Rate 0.1209129

= Investment Return and Income Taxes 312,448 To Workpaper 14

**See Workpaper 12.



Sheet: Worksheet 3 Workpaper 16

Shading denotes an input(2) (4)

Wage/Plant (3) = (1)*(2) PTF (5) = (3)*(4)Line (1) Allocation Transmission Allocation PTF FERC Form 1

No. Total Factors Allocated Factor (b) Allocated Reference for col (1)Transmission Plant

1 Transmission Plant 0 4,861,283 Line 1, Workpaper 18

2 General Plant 5,420,111 6.1995% (a) 336,020 38.4016% 129,037

Page 207.99g + (Page 201.3h + 201.6h - Total A/C 303 - Total A/C 310)*50.20% (d) See Workpaper 25

3 Total (line 1+2) 336,020 4,990,320

4 Transmission Plant Held for Future Use 0 0 38.4016% 0 Page 214

Transmission Accumulated Depreciation5 Transmission Accum. Depreciation 4,699,686 4,699,686 38.4016% 1,804,755 Page 219.25b (1)

6 General Plant Accum.Depreciation 2,016,744 6.1995% (a) 125,028 38.4016% 48,013Page 219.28c (includes common allocated to electric) (2)

7 Total (line 5+6) 4,824,714 1,852,768

Transmission Accumulated Deferred Taxes8 Accumulated Deferred Taxes (281-283) (23,513,552) 10.2656% (c) (2,413,807) 38.4016% (926,941) Page 273.8k + 275.2k + 277.3k, See Workpaper 109 Accumulated Deferred Taxes (190) 101,216 10.2656% (c) 10,390 38.4016% 3,990 Page 234.8c

10 Total (line 8+9) (2,403,417) (922,951)

11 Transmission loss on Reacquired Debt 0 10.2656% (c) 0 38.4016% 0 Page 111.81c

Other Regulatory Assets12 FAS 106 759,148 6.1995% (a) 47,063 38.4016% 18,073 Page 232.17f13 FAS 109 5,093,641 10.2656% (c) 522,893 38.4016% 200,799 Page 232.16f - 278.1f 14 Other Regulatory Liabilities (254.DK) 0 10.2656% (c) 0 38.4016% 015 Total (line 12+13+14) 5,852,789 569,956 218,872

16 Transmission Prepayments 3,632,139 6.1995% (a) 225,174 38.4016% 86,470 Page 111.57c *p.200.8.c/p.200.8.b

17 Transmission Materials and Supplies 120,012 120,012 38.4016% 46,087 Page 227.8c

18 Cash Working Capital19 Operation & Maintenance Expense 32,354 Workpaper 14, Line 20 20 Administrative & General Expense 111,983 Workpaper 14, Line 21 21 Transmission Support Expense 0 Workpaper 14, Line 24 22 Subtotal (line 19+20+21) 144,33723 0.125 x 45 / 36024 Total (line 22 * line 23) 18,042

(a) Workpaper 18, line 11 (b) Workpaper 18, line 3 (c) Workpaper 18, line 16 (d) 50.20% is FGE's gas and electric labor allocator used for allocating common plant. See Workpaper 6.

(1) Adjusted by $33,554,42 to exclude prior period depreciation rate change.See ER12-1453-000, Exhibit FG&E-2. Actual adjustment differs due to rounding. (2) Adjusted by $16,319.93 to exclude prior period depreciation rate change.See ER12-1453-000, Exhibit FG&E-2. Actual adjustment differs due to rounding.



Sheet: Worksheet 4 Workpaper 17(2) (4)


Wage/Plant (3) = (1)*(2) PTF (5) = (3)*(4)Line (1) Allocation Transmission Allocation PTF FERC Form 1

No. Total Factors Allocated Factor (b) Allocated Reference for col (1)Depreciation Expense

1 Transmission Depreciation 347,642 347,642 38.4016% 133,500 Page 336.7b2 General Depreciation 196,888 6.1995% (a) 12,206 38.4016% 4,687 Page 336.10b & 336.11b (includes common allocated to electric)3 Total (line 1+2) 359,848 138,187

4 Amortization of Loss on Reacquired Debt 0 10.2656% (c) 0 38.4016% 0 Page 117.64c

5 Amortization of Investment Tax Credits 0 10.2656% (c) 0 38.4016% 0 Page 266.8f

Property Taxes 6 Transmission Property Taxes 1,507,645 10.2656% (c) 154,769 38.4016% 59,434 Page 263i, lines 9, 10, 11 & 167 General Property Taxes 0 6.1995% (a) 0 38.4016% 0 Page 262-2638 Total (line 6+7) 154,769 59,434

Transmission Operation and Maintenance9 Operation and Maintenance 7,169,705 7,169,705 38.4016% 2,753,281 Page 321.112b

10 Transmission of Electricity by Others - #565 6,857,446 6,857,446 38.4016% 2,633,369 Page 321.96b11 Load Dispatch & Scheduling - #561.0 to #561.4 228,007 228,007 38.4016% 87,558 Page 321.84b-.88b12 **Station Expenses & Rents - #562 / #567 0 0 38.4016% 0 Page 321.93b & .98b13 O&M less lines 10, 11 & 12 84,252 84,252 38.4016% 32,354

Transmission Administrative and General14 Administrative and General 4,960,299 Page 323.197b15 less Property Insurance (#924) 39,507 Page 323.185b16 less Regulatory Commission Expenses (#928) 392,636 Page 323.189b17 less General Advertising Expense (#930.1) 0 Page 323.191b18 Subtotal [line 14 minus (15 thru 17)] 4,528,156 6.1995% (a) 280,723 38.4016% 107,80219 PLUS Property Insurance alloc. using Plant Allocatior 39,507 10.2656% (c ) 4,056 38.4016% 1,55820 PLUS Regulatory Comm. Exp. (FERC Assessments - Transmission) 6,830 6,830 38.4016% 2,623 Page 351.6h21 PLUS Trans. Related General Advertising Expense 0 10.2656% (c ) 0 38.4016% 022 Total A&G [line 18 plus (19 thru 21)] 4,574,493 291,609 111,983

23 Payroll Tax Expense 107,395 6.1995% (a) 6,658 38.4016% 2,557 Footnote (d)

(a) Workpaper 18, line 11(b) Workpaper 18, line 3(c) Workpaper 18, line 16(d) Payroll taxes FERC Form 1, page 263.i ,263.1i

Federal Unemployment 1,395 Page 263.4i FICA 198,197 Page 263.2i Medicare 0 State Unemployment 11,270 Page 263.6i MA Universal Health 2,078 Page 263.8i Payroll Taxes Capitalized (105,545) Page 263.15i

Total 107,395 To Line 23

** Subtract Accounts #562 & #567 from O&M Expense to the extent that they include PTF Support Payments.


Exhibit FGE-3Sheet: Worksheet 5 Workpaper 18

. Shading denotes an input

Line FERC Form 1No. Reference

PTF Transmission Plant Allocation Factor FG&E

1 PTF Transmission Investment 4,861,283 See Workpaper 222 Total Transmission Investment 12,659,061 Page 207.58g

3 Percent Allocation (Line 1/Line 2) 38.4016%

Transmission Wages and Salaries Allocation Factor

4 Direct Transmission Wages and Salaries 47,639 Page 354.21b5 Affiliated Company Transmission Wages and Salaries 0 Workpaper 196 Total Transmission Wages and Salaries (Line 4 + Line 5) 47,639

7 Total Wages and Salaries 797,046 Page 354.28b + Line 58 Administrative and General Wages and Salaries 28,608 Page 354.27b9 Affiliated Company Wages and Salaries less A&G 0 Workpaper 19

10 Total Wages and Salaries net of A&G (Line 7 - 8 + 9) 768,438

11 Percent Allocation (Line 6/Line 10) 6.1995%

Plant Allocation Factor12 Total Transmission Investment 12,659,061 Page 207.58g13 plus Transmission-Related General Plant (Line 2 of Wkst. 3) 336,020 Workpaper 16, Line 2, col.(3)14 = Revised Numerator (Line 12 + Line 13) 12,995,081

15 Total Plant in Service 126,588,203Page 207.104g + Total Common Plant Allocated to Electric, See Workpaper 25

16 Percent Allocation (Line 14 / Line 15) 10.2656%



Affiliated Company Wages and Salaries Shading denotes an input

Line FG&E

"Affiliated" Transmission Wages and Salaries #560 - 573

1 560 02 562 03 564 04 566 05 568 06 569 07 570 08 571 09 572 010 573 0

11 = 1 thru 10 Total Transmission 0

12 = Total "Affiliated" Wages and Salaries 0

Less "Affiliated" Administrative and General Salaries #920 - 935

13 920 014 921 015 923 016 925 017 926 018 928 019 930 020 935 0

21 = 13 thru 20 0

22 = 12 less 21 Total "Affiliated" less A&G 0



Input Revenues associated with the PTF Supporting Facilities in columns (a) and expenses associatedwith the facilities in columns (b). The totals are then linked to Worksheet 1, Lines 23 and 24.

FG&E TOTALParticipant PTF Supporting Facilities Revenues Expenses Revenues Expenses

(a) (b) (a) (b)

BECO 345 kV Sherman - Medway 336 line115 kV Somerville 402 Substation115/345 kV North Cambridge 509 Substation345 kV Golden Hills -Mystic 389 (x&y) lineWest Medway 345 kV breaker115 kV Millbury-Medway 201 lineHQ Phase II - AC in MA 0 0 0 0345 kV "stabilizer" 342 line345 kV Walpole - Medway 325 line345 kV Carver - Walpole 331 line345 kV Jordan Rd - Canal 342 line

CEC Second Canal line345 kV Pilgrim-Bridgewater - 355 line345 kV Myles Standish - Canal 342 line

CMP 345 kV Buxton-South Gorham 386 line 0 0 0 0115 kV Wyman 164-167 lines 0 0 0 0115 kV Maine Yankee transmission

EUA 345 kV Carver - Walpole 331 line345 kV Medway - Bridgewater 344 LineNorthern Rhode Island transmission

NEP Chester SVC 0 0 0 0Comerford 115 kV Substation345 kV Sandy-Tewksbury 337 line345 kV Tewksbury-Woburn 338 line115 kV Tewksbury - Woburn M139 line115 kV Tewksbury - Woburn N140 lineMoore 115 kV SubstationHQ Phase II - AC in MA 0 0 0 0345 kV Golden Hills-Mystic 349 line345 kV NH/MA border-Tewksbury 394 line115 kV Read - Washington V148 line

NU 345 kV 363, 369 and 394 Seabrook linesFairmont 115 kV Substation345 kV Millstone-Manchester 310 lineUI SubstationsBlack Pond

Total = 0 0 0 0

Amount by which Support Expense exceeds Support Revenues 0 (To Workpaper 14, Line 21, Column 5)

Note: Support Expense included in Regional Network Service rates.


Sheet: Worksheet 8 Exhibit FGE-3Workpaper 21

Summary of Fitchburg Gas and Electric Light Company SystemMonthly Coincident Peaks for 2013

(Megawatts)


JAN '13 FEB '13 MAR '13 APR '13 MAY '13 JUN '13 JUL '13 AUG '13 SEP '13 OCT '13 NOV '13 DEC '13

Day 23 4 4 2 31 24 18 21 11 30 25 17Hour 18:00 18:00 18:00 20:00 16:00 17:00 15:00 16:00 19:00 18:00 18:00 17:00

FG&E 78 74 68 64 74 87 94 77 86 67 73 83

Annual FG&E System Average 12 CP Load 77

NOTE: Numbers represent FERC Form 1 Pages 401/401b coincident peaks.


Page 24

PTF Non-PTF PTF XMFRDate Description In Service Value Classification 1 2 3Land1977 Cost of Land purchased from New England Power Co. 6,663.35 5 0 0 0Oct-78 Acquisition Costs for land at Flagg Pond Sub 817.70 5 0 0 0ImprovementsAug-65 Structures and Improvements 24,143.99 5 0 0 0Nov-77 Purchased from NEP on 6/1/77, Tx Portion S/N's 6994207 & 34891 443,407.08 4 0 0 0

Purchased from NEP on 6/1/77, 115 kV Portion 414,449.05 1 414449.05 0 0Purchased from NEP on 6/1/77, 69 kV Portion 414,449.05 2 0 414449.05 0

Oct-78 Transfer acquisition costs to acct 2-353-99, Tx's (29,370.17) 4 0 0 0Transfer acquisition costs to acct 2-353-99, 115 (27,452.06) 1 -27452.06 0 0Transfer acquisition costs to acct 2-353-99, 69 (27,452.06) 2 0 -27452.06 0

Dec-81 Retire 2 600 amp OCB plus installation (21,975.62) 1 -21975.62 0 0Oct-82 Install 115kv breaker status for REMVEC 14,556.40 1 14556.40 0 0Nov-82 See F-2172 924,949.40 1 924949.40 0 0Jun-83 Install 2 1000w Lucalox Floodlights near control shack 2,938.12 5 0 0 0Nov-84 Install Potential Transformers 21,174.57 5 0 0 0Nov-84 Retire PT 1977 (4,628.41) 5 0 0 0Jun-85 Metering 41,916.83 5 0 0 0Sep-88 Install #27 & #28 airbreak switch on #2 Feeder 17,310.44 2 0 17310.44 0Sep-88 Retire #27 & #28 airbreak switch on #2 Feeder 1977 (5,762.36) 2 0 -5762.36 0Jul-91 Adjust to above entry 183.25 2 0 183.25 0Feb-90 Install PT on 02 Line 8,435.83 2 0 8435.83 0Feb-90 Retire PT on 02 Line 1984 (21,174.57) 2 0 -21174.57 0Dec-89 Install 2016 of 4/0 st bare copper 1,868.89 5 0 0 0Dec-89 Install 50' of 2" PVC Pipe 4,033.47 5 0 0 0Dec-89 785' of 4/0 st 600 volt 1977 (1,198.75) 5 0 0 0Dec-89 50' of 4/0 wire 1977 (31.55) 5 0 0 0Dec-89 760' of 4/0 hard drawn wire 1977 (1,310.88) 5 0 0 0Dec-89 50' of 4/0 wire 1977 (106.74) 5 0 0 0Dec-89 965' of 4/0 wire 1977 (2,876.75) 5 0 0 0Dec-89 50' of 2" PVC Pipe 1977 (164.50) 5 0 0 0Aug-91 GE 69kv Bushing in OCB s/n 0139A4928-201 1977 (14,231.56) 2 0 -14231.56 0Aug-91 69kv 1200amp bushing in OCB 2,405.57 2 0 2405.57 0Feb-87 Data Star Recorders 3,780.00 5 0 0 0Mar-87 Installed Data Star Recorder Software Level #2 750.00 5 0 0 01987 Payroll & overheads for above install 1,014.38 5 0 0 01978 Recorder Tape System GE 1978 (5,300.00) 5 0 0 01978 Universal Mag Tape Cartridges 1978 (637.20) 5 0 0 0Aug-90 Watt/Var Transducer 5,950.00 5 0 0 0Aug-90 Vollt Transducer 185.00 5 0 0 0Aug-90 Shipping & Handling 34.92 5 0 0 0Aug-90 500' 4/C #12 AWG Control Cable 1,142.10 5 0 0 0Aug-90 50' 1/2 watt precision resistors 41.39 5 0 0 0Aug-90 350' T&B Stakon Terminals 86.45 5 0 0 0Aug-90 69' Copper Wire 10.35 5 0 0 0Aug-90 Cable Tie 17.55 5 0 0 0Aug-90 Misc Parts 52.76 5 0 0 0Aug-90 Labor for fixing recorder 368.80 5 0 0 0Aug-90 Labor for wiring 124.20 5 0 0 0Jun-92 Install GETEC Telemetering to REMVAC (Liabilities) 422.31 5 0 0 0Jun-92 Overheads 6,638.54 5 0 0 0Jun-92 Payroll 8,030.61 5 0 0 0Nov-91 Bristol DPC 333010A computer 4,230.71 5 0 0 0Nov-91 Bristol SLC 371140A Recorders 5,771.41 5 0 0 0Oct-91 Bristol Power Supply 515.05 5 0 0 0Sep-91 Labor to set up Bristol 2,355.00 5 0 0 0Aug-90 Spare Interrupter Assembly for 115kv Circuit breaker 9,512.00 2 0 9512.00 01993 Retire Westinghouse auto transformer 1977 (152,101.77) 4 0 0 01992 Redesign Rewind & Rebuild 30/40/50 MVA West 0.00 4 0 0 0

Auto Transformer s/n 34891 includes all charges 514,480.75 4 0 0 01992 Purch used Auto Transformer 24/40 mva Magntek 200,032.04 4 0 0 0Apr-94 Fused Disconnect 1977 (505.26) 5 0 0 0May-94 Replace Fused Disconnect 434.21 5 0 0 0Sep-94 Install & purch EM-GRO Air Compressor 1,273.97 5 0 0 0Sep-94 Install Deadend Structure 3-arrestors & 6-bushings 30,233.66 5 0 0 0Sep-95 Construct 115 Kv facilities & connect spare transformer 0.00 2 0 0 0

in place of failed #1 autotrans. 237,601.84 2 0 237601.84 0Repair and rewind of 115-69 KV #1 Autotransformer 0.00 3 0 0 0including uprating to a rated capacity of 60/80/100 MVA 335,776.00 4 0 0 0Insurance Recovery less deductible of $25K (321,696.66) 4 0 0 0

Nov-95 Lightning arrestors, delivery and testing 6,840.09 2 0 6840.09 0Sep-96 60/80/100 MVA 115-69kV Autotransformer (1996) S/N=MNL9258 544,772.08 4 0 0 0Sep-96 Installation cost for above (1996) 42,610.39 4 0 0 0Nov-97 Current Transformers 1977 (8,000.00) 5 0 0 0

Workpaper 1Detail of PTF Transmission Plant as of 12/31/13


Page 25

PTF Non-PTF PTF XMFRDate Description In Service Value Classification 1 2 3LandMar-98 Autotransformer Disconnect Switch 1977 (2,700.00) 2 0 -2700.00 0May-98 D-30 Oil Circuit Breaker 1977 (14,590.00) 2 0 -14590.00 0May-98 Disconnect Switch for above 1977 (2,700.00) 2 0 -2700.00 0

C29 Breaker Disconnect Switch 1977 (5,858.61) 2 0 -5858.61 0Aug-00 Three Phase overcurrent relays 1977 (2,100.00) 2 0 -2100.00 0

Ground overcurrent relays 1977 (1,400.00) 2 0 -1400.00 0Nov-05 Retire Meters & Relays, Control Power System 1978 (25,490.00) 1 -25490.00 0 0Nov-05 Retire Ann. & events Recorder, Rochester Instrument #449-1462 1978 (15,400.00) 1 -15400.00 0 0Nov-05 Retire 200 Ampere Hour Battery, Excide 1978 (3,042.00) 1 -3042.00 0 0Nov-05 Retire Engineering Services and Testing Services 1978 (11,269.53) 1 -11269.53 0 0Nov-05 Retire Antenna Installed 1978 (302.00) 1 -302.00 0 0Nov-05 Retire Encoders Installed 1978 (547.00) 1 -547.00 0 0Nov-05 Retire AC Power Surge Kit 1978 (21.00) 1 -21.00 0 0Nov-05 Retire Coaxial Antenna, Lead, Fittings & Installation of Antenna 1978 (261.35) 1 -261.35 0 0Nov-05 Retire BBA15-AA11 Desk Top 50 Watt #6161 4030A 1978 (1,195.00) 1 -1195.00 0 0Nov-05 Retire B169 AC Power Surge Kit MI 559429 1978 (21.00) 1 -21.00 0 0Nov-05 Retire Sales Tax on Above 1978 (10.03) 1 -10.03 0 0Nov-05 Retire Cleverdon, Varney & Pike Invoices 1978 (14,094.12) 1 -14094.12 0 0Nov-05 Retire Cleverdon, Varney & Pike Engineering Services Invoices 1978 (9,047.75) 1 -9047.75 0 0Nov-05 Retire General Electric Company Invoices for computer services 1978 (76.19) 1 -76.19 0 0Nov-05 Retire Events Recorder & Accessories (from Rochester Instruments) 1978 (69.24) 1 -69.24 0 0Nov-05 Retire Metering 1984 (20,742.26) 1 -20742.26 0 0Nov-05 Retire 'Watt/Var Transducer Aug-90 (5,950.00) 5 0 0 0Nov-05 Retire Vollt Transducer Aug-90 (185.00) 5 0 0 0Nov-05 Retire Shipping & Handling Aug-90 (34.92) 5 0 0 0Nov-05 Labor for fixing recorder Aug-90 (368.80) 5 0 0 0


Page 26

PTF Non-PTF PTF XMFRDate Description In Service Value Classification 1 2 3LandNov-05 Labor for wiring Aug-90 (124.20) 5 0 0 0Nov-05 Retire 'Install GETEC Telemetering to REMVAC (Liabilities) Aug-90 (422.31) 5 0 0 0Nov-05 Retire Overheads Aug-90 (6,638.54) 5 0 0 0Nov-05 Retire 'Payroll Aug-90 (8,030.61) 5 0 0 0Nov-05 Retire Duct Tone Receivers Installed 1978 ($447.00) 1 -447.00 0 0Nov-05 Retire B166 Emergency Power Option #CT 1009-0 1978 ($102.00) 1 -102.00 0 0Nov-05 Retire Data Star Recorders Feb-87 (3,780.00) 5 0 0 0Nov-05 Retire Installed Data Ster REcorder Software Level #2 Mar-87 (750.00) 5 0 0 0Nov-05 Retire Payroll & overheads for above install 1987 (1,014.38) 5 0 0 0Nov-05 Retire 500' 4/C #12 AWG Control Cable Aug-90 (1,142.10) 5 0 0 0Nov-05 Retire 50' 1/2 watt precision resistors Aug-90 (41.39) 5 0 0 0Nov-05 Retire 350' T&B Stakon Terminals Aug-90 (86.45) 5 0 0 0Nov-05 Retire 69' Copper Wire Aug-90 (10.35) 5 0 0 0Nov-05 Retire Cable Tie Aug-90 (17.55) 5 0 0 0Nov-05 Retire Misc Parts Aug-90 (52.76) 5 0 0 0Nov-05 Retire 'Bristol DPC 333010A computer Aug-90 (4,230.71) 5 0 0 0Nov-05 Retire Bristol SLC 371140A Recorders Aug-90 (5,771.41) 5 0 0 0Nov-05 Retire Bristol Power Supply Aug-90 (515.05) 5 0 0 0Nov-05 Retire Labor to set up Bristol Aug-90 (2,355.00) 5 0 0 0Dec-06 Retired used Auto Transformer 24/40 mva Magntek 1992 (200,032.04) 4 0 0 0Jul-08 Retire Deadend Structure 3-arrestors & 6-bushings 1994 (30,233.66) 5 0 0 0Dec-12 Retire 115kv breaker status for REMVEC Oct-82 (14,556.40) 1 (14,556.40) 0.00 0Dec-12 Retire 69kv 1200amp bushing in OCB Aug-91 (2,405.57) 2 0.00 (2,405.57) 0Oct-13 Foundation for OCB 09/01/2013 00:00:00 Jul-67 (1,661.00) 1 (1,661.00) 0.00 0Oct-13 2 - GE 1200 amp 14.4KV oil Circuit Breaker Jul-65 (2,682.75) 1 (2,682.75) 0.00 0Nov-13 115-69 KV #1 Autotransformer (less insurance recovery) (14,079.34) 1 (14,079.34) 0.00 0Total Pre-97 PTF 3,224,156.31 1,169,410.21 596,363.34 0.00Nov-97 69kv Post Insulators 7,125.43 2 0 7125.43 0Feb-98 Install Metering & Test Switches 8,836.13 5 0 0 0Mar-98 Install Lightning Arrester #1 Auto 1,990.46 2 0 1990.46 0Mar-98 Repl Autotransformer 69kv Disconnect Switches 14,416.88 2 0 14416.88 0Apr-98 Additional charges for above 3,799.62 2 0 3799.62 0Apr-98 Install new Ammeters on Auto #1 & Auto #2 3,414.14 5 0 0 0May-98 40kA interrupting rated breaker w/disconnect switch 71,361.36 2 0 71361.36 0Nov-98 Voltage Potential Transformer 6,864.00 5 0 0 0May-99 Southern States TA-OC 69kV 1200A Switch 19,419.24 2 0 19419.24 0Dec-99 UV Relay installed 605.13 2 0 605.13 0Mar-00 Modifications for 3rd 69kV line to River St S/S 162,000.94 2 0 162000.94 0Apr-00 Dead Station Tripping Scheme 2,212.64 5 0 0 0Aug-00 Replace 02 line ground relays 7,085.89 2 0 7085.89 0Aug-00 Additional charges for modifications for 3rd line 9,717.74 2 0 9717.74 0Oct-02 Replace #5 Bushing on 7A1 Oil Circuit Breaker 7,705.53 2 0 7705.53 0Nov-02 Install Spare PT s/n 1024577 26,749.83 2 0 26749.83 0Nov-02 Purchase spare PT JVZ350VT 350/600 s/n 1890057484 9,479.40 2 0 9479.40 0Feb-03 Installation cost for Spare Bushing #5 (C-9293) 7,268.29 2 0 7268.29 0Mar-03 Cable Trenches and Conduit for new Control House 95,020.03 5 0 0 0Mar-03 Installation of cable trench for new Control House 113,635.68 5 0 0 0Nov-05 Retire UV Relay Installed Dec-99 (605.13) 2 0 -605.13 0Nov-05 Retire Dead Station Tripping Scheme Apr-00 (2,212.64) 5 0 0 0Nov-05 Retire Replace 02 line ground relays Aug-00 (7,085.89) 2 0 -7085.89 0Dec-06 Repl Autotransformer 69kv Disconnect Switches 1997 (14,416.88) 2 0.00 -14,416.88 0.00Dec-06 Repl Autotransformer 69kv Disconnect Switches additional chgs 1997 (3,799.62) 2 0 -3799.62 0Total POST-96 PTF $550,588.20 $0.00 $322,818.22 $0.00


Page 27

PTF Non-PTF PTF XMFRDate Description In Service Value Classification 1 2 3LandJan-04 Replace 69Kv Pin & Cap Insulator 529.89 2 0 529.89 0Nov-05 FGE Control House Project (PTF)(See Workpaper 23 for detail) 438,483.13 1 438483.13 0 0Nov-05 FGE Control House Project (Non-PTF) (See Workpaper 23 for detail) 574,504.78 2 0 574504.78 0Dec-06 #1 AutoTransformer Install 169 grd oper 69kv airbrake switch 21,720.43 2 0 21720.43 0Dec-06 Purchase new Spare Auto Transformer 60/80/100MVA 959,517.11 4 0 0 0Dec-06 Foundation for Spare Auto Transformer 31,222.40 4 0 0 0Aug-07 Purchase & Install Battery Monitoring System - 115kV 11,450.47 1 11450.47 0 0Aug-07 Purchase & Install Battery Monitoring System - 69kV 11,450.48 2 0 11450.48 0Sep-07 Installation of Yard Lighting (PTF) (See Workpaper 24 for detail) 21,239.46 1 21239.46 0 0Sep-07 Installation of Yard Lighting (Non-PTF) (See Workpaper 24 for detail) 21,239.41 2 0 21239.41 0Nov-07 Labor Cost to install replacement line back-up relays - 115kV 2006 18,753.78 1 18753.78 0 0Dec-07 Labor Cost to install replacement line back-up relays - 69kV 2006 18,753.78 2 0 18753.78 0Oct-08 Labor and Materials to Install anchors & guys to support buss work 69kV 5,870.49 2 0 5870.49 0

Mar-10Labor and Materials to upgrade and withstand additional load related to NGrid conductor replacement 29,891.16 1 29891.16 0 0

Mar-10 Capacitor Voltage Transformer 115kv $18,731.61 1 18731.61 0 0Jul-11 Electric Plant Acquisition Adjustment $122,600.09 5 0 0 0Dec-12 Protection Relay (Modify J136N Line) $18,121.88 1 18121.88 0 0Dec-12 Breaker Failure (135N Line Relay, Fitzwilliam Project) $40,543.14 1 40543.14 0 0Dec-12 Setting new anchor and taps pm 69 lv Bus Section $16,719.33 2 0 16719.33 0Dec-12 8B2 Bushing Replacement ($18,794.09) 1 -18794.09 0 0Dec-12 115 kv Switch contacts $25,847.93 1 25847.93 0 0Dec-13 Modification of CT Wiring $141,568.78 1 141568.78 0 0Oct-13 Capacitor Voltage Transformer $15,601.16 1 15601.16 0 0Nov-13 Replace (2) Sub Station Batteries $11,441.60 2 0 11441.6 0Nov-13 Spare 115kV Breaker $120,788.74 1 120788.74 0 0Nov-13 Upgrade 115kV Ring Bus $2,377,473.75 1 2377473.75 0 0Dec-13 Replace 2 of the 8B2 breaker bushings 115kV $94,804.40 2 0 94804.4 0Oct-13 40W39 Breaker $99,953.25 1 99953.25 0 0Oct-13 Foundation for 40W39 Breaker $18,435.04 1 18435.04 0 0Nov-13 Misc Electrical Materials 8/1/2013 Jul-04 ($18.22) 1 (18.22) 0 0Nov-13 Misc Electrical Materials 8/1/2013 Jul-04 ($18.22) 1 (18.22) 0 0Total Post-03 PTF $5,268,426.94 $3,378,052.75 $777,034.59 $0.00

PTF 4,547,462.96 9,043,171.45$ 4,547,462.96$ 1,696,216.15$ -$ non-PTF 1,696,216.15

72.83% 27.17%PTF Ratio 0.7283

Pre-97 PTF 1,169,410 POST-96 PTFXFRM Pre-97 PTF - XFRM POST-96 PTFCOMMON Pre-97 PTF 58,634 COMMON POST-96 PTF

Total Pre-97PTF 1,228,045 Total POST-96 PTF

POST-03 PTF 3,378,053 XFRM POST-03 PTF - COMMON POST-03 PTF 89,293

Total POST-03 PTF 3,467,346


Page 28

Exhibit FGE-3

Workpaper 22

Non-PTF XMFR Common4 5

0 6663.350 817.70

0 24143.99443407.08 0

0 00 0

-29370.17 00 00 00 00 00 00 2938.120 21174.570 -4628.410 41916.830 00 00 00 00 00 1868.890 4033.470 -1198.750 -31.550 -1310.880 -106.740 -2876.750 -164.500 00 00 3780.000 750.000 1014.380 -5300.000 -637.200 5950.000 185.000 34.920 1142.100 41.390 86.450 10.350 17.550 52.760 368.800 124.200 422.310 6638.540 8030.610 4230.710 5771.410 515.050 2355.000 0

-152101.77 00 0

514480.75 0200032.04 0

0 -505.260 434.210 1273.970 30233.660 00 00 0

335776.00 0-321696.66 0

0 0544772.08 042610.39 0

0 -8000.00


Page 29


0 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 -5950.000 -185.000 -34.920 -368.80


Page 30


0 -124.200 -422.310 -6638.540 -8030.610 00 00 -3780.000 -750.000 -1014.380 -1142.100 -41.390 -86.450 -10.350 -17.550 -52.760 -4230.710 -5771.410 -515.050 -2355

-200,032.04 00 -30233.660 00 00 00 00 0

1,377,877.70 80,505.060 00 8836.130 00 00 00 3414.140 00 6864.000 00 00 00 2212.640 00 00 00 00 00 00 95020.030 113635.680 00 -2212.640 0

0.00 0.000 0

$0.00 $227,769.98


Page 31


0 00 0.000 0.000 0.00

959517.11 0.0031222.40 0.00

0 0.000 0.000 0.000 0.000 0.000 0.000 0.00

0 0.000 0.000 122,600.090 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.00

$990,739.51 $122,600.09

2,368,617.21$ 430,875.13$

POST-96 PTF - XFRM POST-96 PTF - COMMON POST-96 PTF 165,892

Total POST-96 PTF 165,892


Fitchburg Gas and Electric Light Company Exhibit FGE-3Detail of 2005 Control House Project Workpaper 23

Nov-05 115 kv portion of control houseNov-05 ABB & Relaying portion Control House $65,060.87 1Nov-05 Control Building w/12 relay panels $61,811.68 1Nov-05 Detention Crane Charges $400.00 1Nov-05 Heating element kit for Sun HVAC unit $65.15 1Nov-05 RF45 8 Wire Modular Adapter $34.90 1Nov-05 Router configuration $291.00 1Nov-05 Construction overheads on above $38,299.08 1Nov-05 115 kv portion SCADA EquipmentNov-05 ABB & Relaying portion Control House $2,439.13 1Nov-05 Control Building w/12 relay panels $2,317.32 1Nov-05 PowerEdge Server 600SC $1,061.95 1Nov-05 XP Software $178.85 1Nov-05 1kVA/800W Utility Inverter $632.00 1Nov-05 Cisco Modem Router s/n SFHK072621U0 $1,180.02 1Nov-05 Cisco Modem Router s/n SFHK072621U0 $1,180.02 1Nov-05 Port 4 Wire WanInterface $540.00 1Nov-05 Port 4 Wire WanInterface $581.78 1Nov-05 DSU/CSUModule $729.95 1Nov-05 TG5700 RTU $3,045.00 1Nov-05 ESCA License $5,200.00 1Nov-05 Misc Electrical Materials $18.22 1Nov-05 Postage Charges $30.79 1Nov-05 PC Modem, Termination Card, & Cable $195.30 1Nov-05 Router configuration $291.00 1Nov-05 Sundry Cash ($2,982.92) 1Nov-05 Construction overheads $7,527.03 1Nov-05 115 kv portion Installation of Control HouseNov-05 Fuses $724.42 1Nov-05 Cutouts $1,256.70 1Nov-05 Bussman NTN-R30 Neutral $168.70 1Nov-05 Labor $130,350.95 1Nov-05 SWC Engineering Services $75.00 1Nov-05 Construction Overheads $107,747.46 1Nov-05 115 kv portion Nov-05 Switching - Company Labor $6,245.00 1Nov-05 115 kv portion Nov-05 Witness factory testing $1,676.13 1Nov-05 115 kv portion Installation of Control HouseNov-05 Company Labor $97.92 1Nov-05 115 kv portion Installation of Control HouseNov-05 Late charges $12.73 1

Control House (PTF) $438,483.13


Fitchburg Gas and Electric Light Company Workpaper 23Detail of 2005 Control House Project Page 2

Date Description Value ClassificationNov-05 69 kv portion of control house purchaseNov-05 Detention Crane Charges $400.00 2Nov-05 ABB & Relaying portion Control House $65,060.87 2Nov-05 Control Building w/12 relay panels $61,811.68 2Nov-05 Control Building $128,258.00 2Nov-05 Heating element kit for Sun HVAC unit $65.15 2Nov-05 RF45 8 Wire Modular Adapter $34.91 2Nov-05 12 foot Wall Mount Enclosure (qty 2) $74.72 2Nov-05 6 Port Panel Insert (qty 2) $41.50 2Nov-05 Camlite Connectors (qty 24) $263.76 2Nov-05 PVC (qty 1000) $617.18 2Nov-05 Cash Reimbursement - Pine Tree Power Portion ($20,157.00) 2Nov-05 Construction Overheads $77,536.77 2Nov-05 69 kv portion of SCADA EquipmentNov-05 PowerEdge Server 600SC $1,061.95 2Nov-05 XP Software $178.84 2Nov-05 ABB & Relaying portion Control House $2,439.13 2Nov-05 1kVA/800W Utility Inverter $632.00 2Nov-05 Control Building w/12 relay panels $2,317.32 2Nov-05 Cisco Modem Router s/n SFHK072621U0 $1,180.02 2Nov-05 Port 4 Wire WanInterface $270.00 2Nov-05 DSU/CSUModule $729.95 2Nov-05 ESCA License $5,200.00 2Nov-05 Port 4 Wire WanInterface $581.79 2Nov-05 TG5700 RTU $3,045.00 2Nov-05 Misc Electrical Materials $18.22 2Nov-05 Postage Charges $30.80 2Nov-05 PC Modem, Termination Card, & Cable $195.30 2Nov-05 Police Detail $139.00 2Nov-05 Construction overheads $6,715.20 2Nov-05 69 kv portion Installation of Control House, etc.Nov-05 SW&C Engineering Services $75.00 2Nov-05 current limiting fuses $197.81 2Nov-05 fuses $353.66 2Nov-05 Bussman NTN-R30 Neutral $168.70 2Nov-05 fuse link $8.85 2Nov-05 Labor $135,238.28 2Nov-05 Misc Dumpster Charges $90.78 2Nov-05 Cash Reimbursement - Pine Tree Power Portion ($13,250.00) 2Nov-05 Construction Overheads $109,905.29 2Nov-05 69 kv portion Nov-05 Switching - Company Labor $1,298.22 2Nov-05 69 kv portion Nov-05 Witness factory testing $1,676.13 2

Control House (Non-PTF) $574,504.78Total Control House Project Cost $1,012,987.91


Exh FGE-3Workpaper 24

Fitchburg Gas and Electric Light CompanyDetail of Installation of Yard Lighting - 2007

Sep-07 115 kv portion - Installation of Yard Lighting: ClassificationSep-07 Contract Labor 5,046.89 1Sep-07 Company Labor & Transportation 157.89 1Sep-07 2000 ft. 3C/#10 Tray Cable 1,035.00 1Sep-07 Pipe, boxes, switches, breakers, marking tape 483.00 1Sep-07 Other Materials - connections & hardware 43.13 1Sep-07 8 - 400 watt HPS Floodlights 3,012.67 1Sep-07 4 - light poles (plastic) 0.00 1Sep-07 Circuit Breaker 3.55 1Sep-07 Construction Overheads 11,457.33 1

Yard Lighting (PTF) 21,239.46Sep-07 69 kv portion - Installation of Yard Lighting:Sep-07 Contract Labor 5,046.88 2Sep-07 Company Labor & Transportation 157.88 2Sep-07 2000 ft. 3C/#10 Tray Cable 1,035.00 2Sep-07 Pipe, boxes, switches, breakers, marking tape 483.00 2Sep-07 Other Materials - connections & hardware 43.12 2Sep-07 8 - 400 watt HPS Floodlights 3,012.67 2Sep-07 4 - light poles (plastic) 0.00 2Sep-07 Circuit Breaker 3.54 2Sep-07 Construction Overheads 11,457.32 2

Yard Lighting (Non-PTF) 21,239.41Total Yard Lighting Cost 42,478.87


Exh FGE-3

20131 General Plant $2,320,777 FF1, Page 207.99g23 Common Depreciable Plant4 Structures:5 390 STRUCTURES AND IMPROVEMENTS $580,0226 390.2 IMPROV. TO LEASED SVC CENTER $1,132,2667 TOTAL STRUCTURES $1,712,28889 General Plant:10 391 OFFICE FURNITURE $375,60111 393 STORES EQUIPMENT $53,05712 394 TOOLS, SHOP & GARAGE EQUIPMENT $169,35113 396 POWER OPERATED EQUIPMENT $1,69714 397 COMMUNICATION EQUIPMENT $1,867,19115 398 MISC. EQUIPMENT $85,59016 TOTAL GENERAL PLANT $2,552,4871718 Transportation Equipment:19 392 TRANSPORTATION EQUIPMENT $02021 Non-Depreciable Plant:22 310 LAND AND RIGHTS - PRODUCTION PLANT $023 389 LAND AND RIGHTS - GENERAL PLNT $3,61724 Amortizable Plant:25 303 INTANGIBLE SOFTWARE $1,646,78926 399 OTHER INTANGIBLE PLANT $1,905,45827 390.1 SVC CNTR BLDG - CAP LEASE (101.10) $028 TOTAL COMMON NON-DEPRECIABLE $3,555,86429

30 Total Common Plant $7,820,639Sum: L. 7, 16, 19, & 28; ties to FF1, Page 201.3h + 201.6h

31 Less: Account 303 ($1,646,789) L. 2532 Less: Account 310 $0 L. 2233 Total Common, A/C 389 - 399 $6,173,850 Sum: L. 30, 31, & 3234 Labor Allocator 50.20% Workpaper 635 Total Common Plant Allocated to Electric $3,099,334 L. 33 *L. 343637 Total General Plant $5,420,111 L. 35 + L. 1, Workpaper 16, Line 2

Note: Att F allows accounts 389 - 399 in General Plant.

Workpaper 25Fitchburg Gas and Electric Light Company

General Plant



1 Total of FERC account 561-561.4 (exclude ME, REMVEC, CONVEX /ESCC costs) 217,987$ 1

2 Less ISO & OATT Sch 1 costs included in above accounts 142,351 2

3 Sub-total (1-2) 75,636 3

4 Amount allocated to transmission function 75,636 4

5 Transmission related S&D costs from SCADA or other systems - 5

6 Sub-total (4+5) 75,636 6

7 PTF allocation factors (see Workpaper 27 for details) 38.4016% 7

8 Sub-total after applying PTF allocation factors (from Workpaper 27) 29,045 8

9 Maine LCC costs - 9

10 REMVEC II costs 10,020 10

11 CONVEX costs - 11

12 Sub-total (9+10+11) 10,020 12

13 100% allocated to transmission function 10,020 13

14 Revenues credited for short-term Transmission Service (354) 14

15 Total transmission related system & dispatch revenue requirement (8+13+14) 38,711 15

16 12 month CP LOAD (kW) as defined in section 46.1 of the ISO-NE Tariff 16

17 Long Term Firm PTP Capacity (kW) - 17

18 Scheduling System Control and Dispatch Service Rate ($/kW-YR): (15/(16+17)) 18

Effective June 1, 2014 - May 31, 2015 FG&E Data Only

ISO NE Transmission, Markets & Services TariffOATT Regional Schedule 1 - Scheduling System Control and Dispatch Service Rate



1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16

Customer # DUNS DUNS Name

Total of FERC acct 561 -

561.4 (exclude ME, REMVEC,

CONVEX /ESCC costs)

Less Reg Sch 1 & ISO costs

included in Column 1 accounts

Sub-total (1-2)

100% allocated to transmission

function

Transmission related S&D costs from

SCADA or other Local Control

Centers

Sub-total (4+5)

PTF Allocation

Factor

Sub-total (6x7)

Maine LCC - PTF RELATED

SCH 1 REV REQ'TS.

REMVEC II Costs

CONVEX/ESCC Costs

Sub-total (9+10+11)

100% allocated to transmission

function

Revenues credited for short-term

transmission service must be negative

TOTAL(8+13+14)

SCHEDULE 1 Revenue

Allocation %

.

1 5 17-057-1897 Braintree Electric Light Department - - - - - - - 1 0.00000% Braintree2 6 00-694-8954 Central Maine Power Company - - - - - - - 2 0.00000% CMP3 2 00-694-9002 Emera Maine - - - - - - - 3 0.00000% EM4 38 00-695-4317 Fitchburg Gas and Electric Light Company 217,987 142,351 75,636 75,636 75,636 38.4016% 29,045 10,020 10,020 10,020 (354) 38,711 4 100.00000% FG&E5 45 10-775-5126 Hudson Light & Power Department - - - - - - - 5 0.00000% Hudson6 6 06-099-4258 Maine Electric Power Company - - - - - - - 6 0.00000% MEPCO7 76 07-172-4900 Massachusetts Municipal Wholesale Electric - - - - - - - 7 0.00000% MMWEC8 79 15-597-6665 Middleborough Gas & Electric Department - - - - - - - 8 0.00000% Middleboro9 81 00-695-2881 New England Power Company - - - - - - - 9 0.00000% NGRID

10 Connecticut Light & Power Company - - - - - - - 10 0.00000% CL&P11 Public Service of New Hampshire - - - - - - - 11 0.00000% PSNH12 Western Massachusetts Electric Co. - - - - - - - 12 0.00000% WMECO13 112 95-910-8929 Northeast Utilities - - - - - - - - - 0 - 13 0.00000% Total submitted by NU14 3 00-695-1552 NSTAR Electric Company - - - - - - - 14 0.00000% NSTAR15 148 86-703-4654 Reading Municipal Light Plant - - - - - - - 15 0.00000% Reading16 153 04-661-6033 Taunton Municipal Light Plant - - - - - - - 16 0.00000% Taunton17 181 00-691-7967 United Illuminating Company - - - - - - - 17 0.00000% UI18 50853 78-039-9163 Vermont Transco LLC - - - - - - - 18 0.00000% VT Transco

19 TOTALS 217,987$ 142,351$ 75,636$ 75,636$ -$ 75,636$ 38.4010% 29,045$ -$ 10,020$ -$ 10,020$ 10,020$ (354)$ 38,711$ 19 100.00% TOTALS

0

ISO NE Transmission, Markets & Services Tariff

OATT Regional Schedule 1 - Scheduling System Control and Dispatch Service Rate

Effective June 1, 2014 - May 31, 2015(Reflecting 2013 Schedule 1 Costs)

FG&E Data Only


Exhibit FGE-3Fitchburg Gas and Electric Light Company Workpaper 28Schedule 1 - Account 561

L. # Account Number Account Description 20131 20-10-00-561-01-00 LOAD DISPATCH-RELIABILITY $38,4352 20-13-00-561-01-00 REMVEC EXPENSES NRI $03 20-10-00-561-02-10/11 DISPATCHING TRANSMISSION $36,9734 20-26-00-561-02-00 LOAD DISPATCH-MONITOR & OPER TRANS SYS $2285 20-70-00-561-02-00 LOAD DISPATCH-MONITOR & OPER TRANS SYS $06 20-13-00-561-04-00 SCHED SYS CONTROL & DISP-RTO BILLGS $10,0207 29-13-03-561-04-00 SCHED SYS CONTROL & DISP-RTO BILLGS-ET $142,3518 Total $228,007 FF1, Page 321, Lines 84-889 Less Remvec Expense, L. 6 ($10,020) Schedule 1, Column 10 (Workpaper 27)

10 $217,987 Schedule 1, Column 1 (Workpaper 27)11 Less ISO Costs, L. 7 ($142,351) Schedule 1, Column 2 (Workpaper 27)12 $75,636 Schedule 1, Column 3 (Workpaper 27)


Exhibit FGE-3

Workpaper 29

94,369.15 46,206.82 89,244.61 97,047.08 94,544.06 103,043.29 97,905.85 108,761.49 108,776.33 122,980.28 68,285.74 60,631.33 1,091,796.03$

Customer Id Customer Name Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13 Oct-13 Nov-13 Dec-13Total Annual Revenue

2 Bangor Hydro-Electric Company 1,586.98 777.05 1,500.80 1,632.01 1,589.92 2,264.25 2,151.36 2,389.90 2,390.23 2,702.34 1,500.50 1,332.30 $21,817.643 NSTAR Electric Company 13,603.88 6,660.99 12,865.15 13,989.92 13,629.09 15,835.29 15,045.79 16,714.04 16,716.32 18,899.13 10,493.89 9,317.59 $163,771.085 Braintree Electric Light Depar 20.74 10.16 19.62 21.33 20.78 24.46 23.24 25.82 25.82 29.20 16.21 14.39 $251.776 Central Maine Power Company 10,615.54 5,197.78 10,039.09 10,916.78 10,635.22 12,312.55 11,698.68 12,995.81 12,997.59 14,694.80 8,159.40 7,244.78 $127,508.0238 Fitchburg Gas and Electric Lig 27.54 13.48 26.04 28.32 27.59 35.58 33.81 37.56 37.56 42.46 23.58 20.94 $354.4645 Hudson Light & Power Departmen 14.90 7.30 14.09 15.32 14.93 17.57 16.69 18.54 18.55 20.97 11.64 10.34 $180.8476 Massachusetts Municipal Whol 144.80 70.90 136.94 148.91 145.07 170.70 162.19 180.18 180.20 203.73 113.12 100.44 $1,757.1879 Middleborough Gas & Electric D 6.59 3.22 6.23 6.77 6.60 7.77 7.38 8.20 8.20 9.27 5.15 4.57 $79.9581 New England Power Company 21,004.17 10,284.46 19,863.57 21,600.21 21,043.10 19,035.92 18,086.84 20,092.28 20,095.02 22,719.02 12,614.91 11,200.86 $217,640.36

112 Northeast Utilities Service Co 40,910.57 20,031.41 38,689.00 42,071.50 40,986.40 45,693.30 43,415.17 48,228.97 48,235.55 54,534.12 30,280.49 26,886.23 $479,962.71148 Reading Municipal Light Depart 21.85 10.70 20.66 22.47 21.89 25.76 24.48 27.19 27.19 30.74 17.07 15.16 $265.16153 Taunton Municipal Lighting Pla 27.75 13.59 26.25 28.54 27.81 32.72 31.09 34.53 34.54 39.05 21.68 19.25 $336.80181 United Illuminating Company, T 73.95 36.21 69.93 76.05 74.08 33.62 31.95 35.49 35.49 40.13 22.28 19.78 $548.96

50853 Vermont Transco LLC 6,309.89 3,089.57 5,967.24 6,488.95 6,321.58 7,553.80 7,177.18 7,972.98 7,974.07 9,015.32 5,005.82 4,444.70 $77,321.10

Source: ISO-NE.

Monthly & Annual Revenue Totals:

Customer Information Summary of Monthly and Annual Revenues by Customer

OATT Sched 1 TOUT 2013


Fitchburg Gas and Electric Light Company Exhibit FGE-6Summary of Rates for Local Service Page 1 of 1

Revised Effective 10/16/2014*(1)

Line (2) (3) (4)No. Description 10/16/2014 (1) Reference/Explanation

Annual Transmission Revenue Requirement forLocal Network Service:

1 June 1, 2014 Revenue Requirement $1,208,896 FG&E June 1, 2014 Rate2 October 16, 2014 Revenue Requirement $1,189,084 Exhibit FGE-2, Worksheet 1 of 6, Column (7), line 303 Increase/(Decrease) in Revenue Requirement ($19,812)

4 FG&E Peak Load (kW) 77,000 Exhibit FGE-2, Worksheet 6 of 6, line 55 Less CP of All Firm Point-to-Point (kW) 06 Plus Contract Demand Reservation for Firm Pt-Pt (kW) 07 Total Peak Load (kW) 77,000

Schedule 7: Firm Point-to-Point 8 Annual Charge $/kW $15.443 Line 2 / Total Peak Load9 Monthly Charge $/kW $1.287 Annual Charge / 1210 Weekly Charge $/kW $0.297 Annual Charge / 5211 Daily Charge $/kW $0.042 Annual Charge / 365

Schedule 8: Non-Firm Point-to-Point (2)

12 Monthly Charge $/kW $0.965 Firm Pt to Pt Charge * 75%13 Weekly Charge $/kW $0.223 Firm Pt to Pt Charge * 75%14 Daily Charge $/kW $0.032 Firm Pt to Pt Charge * 75%15 Hourly Charge $/Mwh $1.322 Daily Charge / 24 * 1000

(1) Represents rates based on calendar year 2013 data. Rates shall be recalculated annually, effective June 1, based on data from the prior calendar year in accordance with the formula established in Attachment H of Schedule 21 - FG&E.

(2) Rates reflect a 25% discount off the Firm Point-to-Point rates*Revised in accordance with FERC Order 531-A, issued October 16, 2014 in EL11-66.


Document Content(s)

2014 11 17 FGE EL11-66 filing (W4588386x7AC2E).PDF....................1-6

FGE LNS Rates (W4588410x7AC2E).XLS....................................7-46


Secretary Federal Energy Regulatory Commission 888 First ...€¦ · October 16, 2014 through May 31, 2015. 1. This filing revises the rates filed on August 14, 2014 in Docket ER091498-

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