FERC FINANCIAL REPORT FERC FORM No.1: Annual Report of ... · The public reporting burden for the...

THIS FILING IS

Item 1: [!] An Initial (Original) Submission

OR 0 Resubmission No.

Form 1 Approved OMS NO.1902-0021 (Expires 12/31/2014)

Form 1-F Approved OMS NO.1902-0029 (Expires 12/31/2014)

Form 3-0 Approved OMS NO.1902-0205 (Expires 05/31/2014)

FERC FINANCIAL REPORT FERC FORM No.1: Annual Report of

Major Electric Utilities, Licensees and Others and Supplemental

Form 3-Q: Quarterly Financial Report

These reports are mandatory under the Federal Power Act, Sections 3, 4(a), 304 and 309, and

18 CFR 141.1 and 141.400. Failure to report may result in criminal fines, civil penalties and

other sanctions as provided by law. The Federal Energy Regulatory Commission does not

consider these reports to be of confidential nature

Exact Legal Name of Respondent (Company)

Green Mountain Power Corporation

Year/Period of Report

End of 2012/04

FERC FORM No.1/3-Q (REV. 02-04)

INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-0

GENERAL INFORMATION

I. Purpose

FERC Form NO.1 (FERC Form 1) is an annual regulatory requirement for Major electric utilities, licensees and others (18 C.F.R. § 141.1). FERC Form No. 3-0 (FERC Form 3-0)is a quarterly regulatory requirement which supplements the annual financial reporting requirement (18 C.F.R. § 141.400). These reports are designed to collect financial and operational information from electric utilities, licensees and others subject to the jurisdiction of the Federal Energy

Regulatory Commission. These reports are also considered to be non-confidential public use forms.

II. Who Must Submit

Each Major electric utility, licensee, or other, as classified in the Commission's Uniform System of Accounts Prescribed for Public Utilities and Licensees Subject To the Provisions of The Federal Power Act (18 C.F.R. Part 101), must submit FERC Form 1 (18 C.F.R. § 141.1), and FERC Form 3-0 (18 C.F.R. § 141.400).

Note: Major means having, in each of the three previous calendar years, sales or transmission service that exceeds one of the following:

(1) one million megawatt hours of total annual sales, (2) 100 megawatt hours of annual sales for resale, (3) 500 megawatt hours of annual power exchanges delivered, or (4) 500 megawatt hours of annual wheeling for others (deliveries plus losses).

III. What and Where to Submit

(a) Submit FERC Forms 1 and 3-0 electronically through the forms submission software. Retain one copy of each report for your files. Any electronic submission must be created by using the forms submission software provided free by the

Commission at its web site: http://www.ferc.qov/docs-filinq/eforms/form-1/elec-subm-soft.asp. The software is

used to submit the electronic filing to the Commission via the Internet.

(b) The Corporate Officer Certification must be submitted electronically as part of the FERC Forms 1 and 3-0 filings.

(c) Submit immediately upon publication, by either eFiling or mail, two (2) copies to the Secretary of the Commission, the latest Annual Report to Stockholders. Unless eFiling the Annual Report to Stockholders, mail the stockholders report to the Secretary of the Commission at:

Secretary Federal Energy Regulatory Commission 888 First Street, NE Washington, DC 20426

(d) For the CPA Certification Statement, submit within 30 days after filing the FERC Form 1, a letter or report (not applicable to filers classified as Class C or Class D prior to January 1, 1984). The CPA Certification Statement can be either eFiled or mailed to the Secretary of the Commission at the address above.

FERC FORM 1 & 3-0 (ED. 03-07)

The CPA Certification Statement should:

a) Attest to the conformity, in all material aspects, of the below listed (schedules and pages) with the Commission's applicable Uniform System of Accounts (including applicable notes relating thereto and the Chief Accountant's published accounting releases), and

b) Be signed by independent certified public accountants or an independent licensed public accountant certified or licensed by a regulatory authority of a State or other political subdivision of the U. S. (See 18

C. F.R. §§ 41 .10-41 .12 for specific qualifications.)

Reference Schedules

Comparative Balance Sheet 110-113 Statement of Income 114-117 Statement of Retained Earnings 118-119 Statement of Cash Flows 120-121 Notes to Financial Statements 122-123

e) The following format must be used for the CPA Certification Statement unless unusual circumstances or conditions, explained in the letter or report, demand that it be varied. Insert parenthetical phrases only when exceptions are reported.

"In connection with our regular examination of the financial statements of __ for the year ended on which we have reported separately under date of , we have also reviewed schedules

_________of FERC Form NO.1 for the year filed with the Federal Energy Regulatory Commission, for conformity in all material respects with the requirements of the Federal Energy Regulatory Commission as set forth in its applicable Uniform System of Accounts and published accounting releases. Our review for this purpose included such

tests of the accounting records and such other auditing procedures as we considered necessary in the circumstances.

Based on our review, in our opinion the accompanying schedules identified in the preceding paragraph (except as noted below) conform in all material respects with the accounting requirements of the Federal Energy Regulatory Commission as set forth in its applicable Uniform System of Accounts and published accounting releases."

The letter or report must state which, if any, of the pages above do not conform to the Commission's requirements. Describe the discrepancies that exist.

(f) Filers are encouraged to file their Annual Report to Stockholders, and the CPA Certification Statement using eFiling. To further that effort, new selections, "Annual Report to Stockholders," and "CPA Certification Statement" have been added to the dropdown "pick list" from which companies must choose when eFiling. Further instructions are found on the

Commission's website at http://www.ferc.gov/help/how-to.asp.

(g) Federal, State and Local Governments and other authorized users may obtain additional blank copies of FERC Form 1 and 3-0 free of charge from http://www.ferc.gov/docs-filing/eforms/form-1/form-1.pdf and

http://www.ferc.gov/docs-filing/eforms.asp#3Q-gas .

IV. When to Submit:

FERC Forms 1 and 3-0 must be filed by the following schedule:

FERC FORM 1 & 3-Q (ED. 03-07) ii

a) FERC Form 1 for each year ending December 31 must be filed by April 18th of the following year (18 CFR § 141.1), and

b) FERC Form 3-0 for each calendar quarter must be filed within 60 days after the reporting quarter (18 C.F.R. § 141.400).

v. Where to Send Comments on Public Reporting Burden.

The public reporting burden for the FERC Form 1 collection of information is estimated to average 1,144 hours per response, including the time for reviewing instructions, searching existing data sources, gathering and maintaining the data-needed, and completing and reviewing the collection of information. The public reporting burden for the FERC Form 3-0 collection of information is estimated to average 150 hours per response.

Send comments regarding these burden estimates or any aspect of these collections of information, including suggestions for reducing burden, to the Federal Energy Regulatory Commission, 888 First Street I\IE, Washington, DC 20426 (Attention: Information Clearance Officer); and to the Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, DC 20503 (Attention: Desk Officer for the Federal Energy Regulatory Commission). No person shall be subject to any penalty if any collection of information does not display a valid control number (44 U.S.C. § 3512 (a)).

FERC FORM 1 & 3-Q (ED. 03-07) iii

GENERAL INSTRUCTIONS

I. Prepare this report in conformity with the Uniform System of Accounts (18 CFR Part 101) (USofA). Interpret all accounting words and phrases in accordance with the USofA.

II. Enter in whole numbers (dollars or MWH) only, except where otherwise noted. (Enter cents for averages and figures per unit where cents are important. The truncating of cents is allowed except on the four basic financial statements where rounding is required.) The amounts shown on all supporting pages must agree with the amounts entered on the statements that they support. When applying thresholds to determine significance for reporting purposes, use for balance sheet accounts the balances at the end of the current reporting period, and use for statement of income accounts the current year's year to date amounts.

III Complete each question fully and accurately, even if it has been answered in a previous report. Enter the word "None" where it truly and completely states the fact.

IV. For any page(s) that is not applicable to the respondent, omit the page(s) and enter "NA," "NONE," or "Not Applicable" in column (d) on the List of Schedules, pages 2 and 3.

V. Enter the month, day, and year for all dates. Use customary abbreviations. The "Date of Report" included in the header of each page is to be completed only for resubmissions (see VII. below).

VI. Generally, except for certain schedules, all numbers, whether they are expected to be debits or credits, must be reported as positive. Numbers having a sign that is different from the expected sign must be reported by enclosing the numbers in parentheses.

VII For any resubmissions, submit the electronic filing using the form submission software only. Please explain the reason for the resubmission in a footnote to the data field.

VIII. Do not make references to reports of previous periods/years or to other reports in lieu of required entries, except as specifically authorized.

IX. Wherever (schedule) pages refer to figures from a previous period/year, the figures reported must be based upon those shown by the report of the previous period/year, or an appropriate explanation given as to why the different figures were used.

Definitions for statistical classifications used for completing schedules for transmission system reporting are as follows:

FNS - Firm Network Transmission Service for Self. "Firm" means service that can not be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission Service as described in Order No. 888 and the Open Access Transmission Tariff. "Self' means the respondent.

FNO - Firm Network Service for Others. "Firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission Service as described in Order No. 888 and the Open Access Transmission Tariff.

LFP - for Long-Term Firm Point-to-Point Transmission Reservations. "Long-Term" means one year or longer and" firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Point-to-Point Transmission Reservations" are described in Order No. 888 and the Open Access Transmission Tariff. For all transactions identified as LFP, provide in a footnote the

FERC FORM 1 &3-Q (ED. 03-07) iv

termination date of the contract defined as the earliest date either buyer or seller can unilaterally cancel the contract.

OLF - Other Long-Term Firm Transmission Service. Report service provided under contracts which do not conform to the terms of the Open Access Transmission Tariff. "Long-Term" means one year or longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. For all transactions identified as OLF, provide in a footnote the termination date of the contract defined as the earliest date either buyer or seller can unilaterally get out of the contract.

SFP - Short-Term Firm Point-to-Point Transmission Reservations. Use this classification for all firm point-to-point transmission reservations, where the duration of each period of reservation is less than one-year.

NF - Non-Firm Transmission Service, where firm means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions.

as - Other Transmission Service. Use this classification only for those services which can not be placed in the above-mentioned classifications, such as all other service regardless of the length of the contract and service FERC Form. Describe the type of service in a footnote for each entry.

AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment.

DEFINITIONS I. Commission Authorization (Comm. Auth.) -- The authorization of the Federal Energy Regulatory Commission, or any other Commission. Name the commission whose authorization was obtained and give date of the authorization.

II. Respondent -- The person, corporation, licensee, agency, authority, or other Legal entity or instrumentality in whose behalf the report is made.

FERC FORM 1 & 3-Q (ED. 03-07) v

EXCERPTS FROM THE LAW

Federal Power Act, 16 U.S.C. § 791a-825r

Sec. 3. The words defined in this section shall have the following meanings for purposes of this Act, to with:

(3) 'Corporation' means any corporation, joint-stock company, partnership, association, business trust, organized group of persons, whether incorporated or not, or a receiver or receivers, trustee or trustees of any of the foregoing. It shall not include 'municipalities, as hereinafter defined;

(4) 'Person' means an individual or a corporation;

(5) 'Licensee, means any person, State, or municipality Licensed under the provisions of section 4 of this Act, and any assignee or successor in interest thereof;

(7) 'municipality means a city, county, irrigation district, drainage district, or other political subdivision or agency of a State competent under the Laws thereof to carry and the business of developing, transmitting, unitizing, or distributing power; .

(11) "project' means. a complete unit of improvement or development, consisting of a power house, all water conduits, all dams and appurtenant works and structures (including navigation structures) which are a part of said unit, and all storage, diverting, or fore bay reservoirs directly connected therewith, the primary line or lines transmitting power there from to the point of junction with the distribution system or with the interconnected primary transmission system, all miscellaneous structures used and useful in connection with said unit or any part thereof, and all water rights, rights-of-way, ditches, dams, reservoirs, Lands, or interest in Lands the use and occupancy of which are necessary or appropriate in the maintenance and operation of such unit;

"Sec. 4. The Commission is hereby authorized and empowered

(a) To make investigations and to collect and record data concerning the utilization of the water 'resources of any region to be developed, the water-power industry and its relation to other industries and to interstate or foreign commerce, and concerning the location, capacity, development -costs, and relation to markets of power sites; ... to the extent the Commission may deem necessary or useful for the purposes of this Act."

"Sec. 304. (a) Every Licensee and every public utility shall file with the Commission such annual and other periodic or special* reports as the Commission may be rules and regulations or other prescribe as necessary or appropriate to assist the Commission in the -proper administration of this Act. The Commission may prescribe the manner and FERC Form in which such reports salt be made, and require from such persons specific answers to all questions upon which the Commission may need information. The Commission may require that such reports shall include, among other things, full information as to assets and Liabilities, capitalization, net investment, and reduction thereof, gross receipts, interest due and paid, depreciation, and other reserves, cost of project and other facilities, cost of maintenance and operation of the project and other facilities, cost of renewals and replacement of the project works and other facilities, depreciation, generation, transmission, distribution, delivery, use, and sale of electric energy. The Commission may require any such person to make adequate provision for currently determining such costs and other facts. Such reports shall be made under oath unless the Commission otherwise specifies*.1 0

FERC FORM 1 & 3-Q (ED. 03-07) vi

"Sec. 309. The Commission shall have power to perform any and all acts, and to prescribe, issue, make, and rescind such orders, rules and regulations as it may find necessary or appropriate to carry out the provisions of this Act. Among other things, such rules and regulations may define accounting, technical, and trade terms used in this Act; and may prescribe the FERC Form or FERC Forms of all statements, declarations, applications, and reports to be filed with the Commission, the information which they shall contain, and the time within which they shall be field ..."

General Penalties

The Commission may assess up to $1 million per day per violation of its rules and regulations. See FPA § 3l6(a) (2005), 16 U.S.c. § 8250(a).

FERC FORM 1 & 3-Q (ED. 03-07) vii

FERC FORM NO. 1/3-Q: REPORT OF MAJOR ELECTRIC UTILITIES.. LICENSEES AND OTHER

02 Year/Period of Report

End of 2012/Q4

1 1

06 Title of Contact Person Chief Financial Officer

(2) D A Resubmission

IDENTIFICATION 01 Exact Legal Name of Respondent

IGreen Mountain Power Corporation

contained in this report are correct statements ined in this report, conform in all material

I

03 Previous Name and Date of Change (if name changed during year)

04 Address of Principal Office at End of Period (Street, City, State, Zip Code)

163 Acorn Lane, Colchester, VT 05446

05 Name of Contact Person Dawn D. Bugbee

07 Address of Contact Person (Street, City, State, Zip Code) 163 Acorn Lane, Colchester, VT 05446

08 Telephone of Contact person,tnclUdingl 09 This Report Is

Area Code (1) 00 An Original (802) 655-8768 I

ANNUAL CORPORATE OFFICER CERTIFICATION

The undersigned officer certifies that:

I have examined this report and to the best of my knowledge, information, and belief all statements of fact of the business affairs of the respondent and the financial statements, and other financial information contarespects to the Uniform System of Accounts.

01 Name I03 S;,o",,,Dawn D. Bugbee

02 Title Chief Financial Officer Dawn D. Bugbee

Title 18, U.S.C. 1001 makes it a crime for any person to knowingly and willingly to make to any Agency or false, fictitious or fraudulent statements as to any matter within its jurisdiction.

Department of the United States any

10 Date of Report (Mo, Da, Yr)

04/15/2013

04 Date Signed

(Mo, Da, Yr)

/ /

FERC FORM No.1/3-Q (REV. 02-04) Page 1

Year/Period of Report Date of Report Name of Respondent This ~ort Is: (1) An Original (Mo, Da, Yr) 2012/04End ofGreen Mountain Power Corporation 04/15/2013

LIST OF SCHEDULES (Electric Utility)

Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for

certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".

(2) Fi A Resubmission

RemarksReferenceLine Title of Schedule Page No. No.

(c)

1

(b)(a)

101

2

General Information

102

3

Control Over Respondent

103

4

Corporations Controlled by Respondent

104

5

Officers

105

6

Directors

106(a)(b)

7

Information on Formula Rates

108-109

8

Important Changes During the Year

110-113

9

Comparative Balance Sheet

114-117

10

Statement of Income for the Year

118-119

11

Statement of Retained Earnings for the Year

120-121

12

Statement of Cash Flows

122-123

13

Notes to Financial Statements

Statement of Accum Comp Income, Comp Income, and Hedging Activities 122(a)(b)

14 200-201

15

Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep

Nuclear Fuel Materials 202-203

16 204-207

17

Electric Plant in Service

213 N/A

18

Electric Plant Leased to Others

Electric Plant Held for Future Use 214 N/A

19 Construction Work in Progress-Electric 216

20 Accumulated Provision for Depreciation of Electric Utility Plant 219

21 Investment of Subsidiary Companies 224-225

22 Materials and Supplies 227

23 Allowances 228(ab)-229(ab) N/A

24 Extraordinary Property Losses 230 N/A

25 Unrecovered Plant and Regulatory Study Costs 230 N/A

26 Transmission Service and Generation Interconnection Study Costs 231

27 Other Regulatory Assets 232

28 Miscellaneous Deferred Debits 233

29 Accumulated Deferred Income Taxes 234

30 Capital Stock 250-251

31 Other Paid-in Capital 253

32 Capital Stock Expense 254 N/A

33 Long-Term Debt 256-257

34 Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax 261

35 Taxes Accrued, Prepaid and Charged During the Year 262-263

36 Accumulated Deferred Investment Tax Credits 266-267

FERC FORM NO.1 (ED. 12-96) Page 2

Year/Period of ReportDate of ReportName of Respondent This ~ort Is: (Mo, Da, Yr)(1) An Original 2012/04End of Green Mountain Power Corporation 04/15/2013

LIST OF SCHEDULES (Electric Utility) (continued)




RemarksTitle of Schedule ReferenceLine No. Page No.

I (c)

37

(b)(a)

269

38

Other Deferred Credits

272-273 N/A

39

Accumulated Deferred Income Taxes-Accelerated Amortization Property

274-275

40

Accumulated Deferred Income Taxes-Other Property

276-277

41

Accumulated Deferred Income Taxes-Other

278

42

Other Regulatory Liabilities

300-301

43

Electric Operating Revenues

N/A

44

302Regional Transmission Service Revenues (Account 457.1)

Sales of Electricity by Rate Schedules 304

45 310-311

46

Sales for Resale

320-323

47

Electric Operation and Maintenance Expenses

326-327

48

Purchased Power

328-330

49

Transmission of Electricity for Others

331 N/A

50

Transmission of Electricity by ISO/RTOs

Transmission of Electricity by Others 332

51 Miscellaneous General Expenses-Electric 335

52 Depreciation and Amortization of Electric Plant 336-337

53 350-351

54

Regulatory Commission Expenses

352-353

55

Research, Development and Demonstration Activities

Distribution of Salaries and Wages 354-355

56 Common Utility Plant and Expenses 356 N/A

57 Amounts included in ISO/RTO Settlement Statements 397

58 Purchase and Sale of Ancillary Services 398

59 Monthly Transmission System Peak Load 400

60 Monthly ISO/RTO Transmission System Peak Load 400a

61 Electric Energy Account 401

62 Monthly Peaks and Output 401

63 Steam Electric Generating Plant Statistics 402-403

64 Hydroelectric Generating Plant Statistics 406-407

65 Pumped Storage Generating Plant Statistics 408-409

66 Generating Plant Statistics Pages 410-411


67

68

69

70

71

Year/Period of Report Name of Respondent This ~ort Is: Date of Report (1) ~ An Original (Mo, Da, Yr) End of 2012/04Green Mountain Power Corporation (2) 0 A Resubmission 04/15/2013

LIST OF SCHEDULES (Electric Utility) (continued)



Line No.

Title of Schedule

(a)

Transmission Line Statistics Pages

Transmission Lines Added During the Year

Substations

Transactions with Associated (Affiliated) Companies

Footnote Data

Stockholders' Reports Check appropriate box:

D Two copies will be submitted

D No annual report to stockholders is prepared

Reference Page No.

(b)

422-423

424-425

426-427

429

450

Remarks

(c)


Year/Period of ReportDate of ReportName of Respondent This Report Is: (Mo,Da, Yr)(1) !Xl An Original Green Mountain Power Corporation

2012/04End of(2) D A Resubmission 04/15/2013

GENERAL INFORMATION

1. Provide name and title of officer having custody of the general corporate books of account and address of office where the general corporate books are kept, and address of office where any other corporate books of account are kept, if different from that where the general corporate books are kept.

Dawn Bugbee, Chief Financial Officer

163 Acorn Lane

Colchester, Vermont 05446

2. Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation. If incorporated under a special law, give reference to such law. If not incorporated, state that fact and give the type of organization and the date organized.

Inc. in Vermont as Vergennes electric Co. on 4/8/1893. Name changed to Peoples Hydro electric Vt. Corp.

on 7/30/26 and to Green Mountain Power Corp. on 8/29/28.

3. If at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of receiver or trustee, (b) date such receiver or trustee took possession, (c) the authority by which the receivership or trusteeship was created, and (d) date when possession by receiver or trustee ceased.

The property of the respondent was not held by a receiver or a trustee at any time during 2010.

4. State the classes or utility and other services furnished by respondent during the year in each State in which the respondent operated.

Electric service in the state of Vermont.

5. Have you engaged as the principal accountant to audit your financial statements an accountant who is not the principal accountant for your previous year's certified financial statements?

(1) D Yes ...Enter the date when such independent accountant was initially engaged: (2) [K] No

1 _

FERC FORM NO.1 (ED. 12-87) PAGE 101

Year/Period of ReportName of Respondent


This Report Is:

(1) 00 An Original (2) D A Resubmission

Date of Report (Mo,Da, Yr)

04/15/2013 End of 2012/04

CONTROL OVER RESPONDENT

1. If any corporation, business trust, or similar organization or a combination of such organizations jointly held control over the repondent at the end of the year, state name of controlling corporation or organization, manner in which control was held, and extent of control. If control was in a holding company organization, show the chain of ownership or control to the main parent company or organization. If control was held by a trustee(s), state name of trustee(s), name of beneficiary or beneficiearies for whom trust was maintained, and purpose of the trust.

On April 12, 2007, Northstars Merger Subsidiary Corporation ("Merger Sub"), a wholly-owned subsidiary of NNEEC("Parent"), was

merged with and into Green Mountain Power Corporation (the "Company") (the "Merger") pursuant to the Agreement and Plan of

Merger, dated as of June 21,2006 (the "Merger Agreement"), by and among Parent, Merger Sub and the Company. As a result of the

Merger, which was effective as of 7:45 a.m. Eastern Daylight Time on April 12, 2007, the Company became a wholly-owned subsidiary

of the Parent.

At the effective time of the Merger, each issued and outstanding share of the Company's common stock, par value $3.33 1/3 per

share, subject to certain limitations, was converted into the right to receive $35.00 in cash, without interest thereon. All of the

remaining unexercised stock options were converted to shares, and any remaining unvested stock grants were immediately vested.

The shares were exchanged for cash, and all stock compensation plans were discontinued.

As a result of the Merger, all of the Company's issued and outstanding capital stock is held by Parent and all of the issued and

outstanding capital stock of Parent is owned, directly or indirectly, by Gaz Metro Limited Partnership ("Gaz Metro"), a limited

partnership organized under the laws of the Province of Quebec.

The purchase price premium has not been pushed down by the parent to the Company and is not reflected in the Company's

accounts. All of the purchase price paid in excess of net book value has been allocated by the parent to goodwill. Amounts allocated

to goodwill are not recoverable in rates. The accompanying financial statements are presented on an original cost basis consistent

with the Company's regulatory model.


I

Name of Respondent This ~ort Is: Date of Report Year/Period of Report

Green Mountain Power Corporation (1) (2)

~An OriginalD A Resubmission

(Mo, Da, Yr) 04/15/2013

End of 2012/04

CORPORATIONS CONTROLLED BY RESPONDENT

1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote. 2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming any intermediaries involved. 3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.

Definitions 1. See the Uniform System of Accounts for a definition of control. 2. Direct control is that which is exercised without interposition of an intermediary. 3. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control. 4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of control in the Uniform System of Accounts, regardless of the relative voting rights of each party.

Line No.

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

Name of Company Controlled

(a)

VT Yankee Nuclear Power Corp

Joint Owners


Respondent has full control over the following

Green Mountain Power Investment Company

Northern Water Resources, Inc.

Vermont Electric Power Co., Inc.

Joint Owners:


VLite

City of Burlington Electric Light Department

Vermont Electric Cooperative

Stowe Electric

Washington Electric

Ludlow Electric

Swanton Electric

Others

VT Public Power Supply Authority

Kind of Business

(b)

Nuclear Generation Contract

Management

Percent Voting Stock Owned

(c)

Ownership %

100%

100.00%

Passive Investments

Alternative Energy Developmet

100.00%

100.00%

Electric Power Common Stock

Owners%:

38.8%

37.5%

6.0%

7.0%

0.7%

1.5%

1.1%

1.0%

3.5%

2.9%

100%

Note: The above figures represent the share of Common Stock. The

Responent also owns 30% of VELCO's Preferred Stock.

Footnote Ref. (d)


l



~An Original0 A Resubmission

(Mo, Da, Yr) 04/15/2013

End of 2012/04


1, Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote. 2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming any intermediaries involved. 3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.


Line Name of Company Controlled No.

(a)I

1

2 Transco LLC

3 Joint Owners:

4 Velco Electric Power Company

5 Burlington Electric Dept.

6 Green Mountain Power

7 Village of Stowe

8 Vermont Electric Cooperative

9 VPPSA

10 Other

11

12

13

14 W.F. Wyman Station

15 Joint Owners:

16 Green Mountain Power Corporation

17 Exelon New England

18 Florida Power & Light

19 Lyndonville Electric Department

20 Massachusetts Municipal Wholesale Electric Co.

21 Northeast Utilites

22

23

24

25 Stony Brook

26

27

Kind of Business

(b)

Oil fired steam

electric generating

unit.

352MW Oil fired, combined

cycle intermediate

generating unit.


(c)

10.12%

3.51%

71.40%

6.12%

1.72%

7.84%

1.29%

100%

Ownership %

2.92%

5.89%

84.34%

0.03%

3.67%

3.14%

100.00%

Footnote Ref. (d)

FERC FORM NO.1 (ED. 12-96) Page 103.1

Name of Respondent


This ~ort Is: Date of Report (1) ~An Original (Mo, Da, Yr) (2) 0 A Resubmission 04/15/2013


Year/Period of Report End of 2012/04



Line No.

Name of Company Controlled

(a)

Kind of Business

(b)


(c)

Footnote Ref. (d)

1 Joint Owners:


3 Lyndonville Electric Department

4 Massachusetts Municipal Wholesale Electric Co.

5

6

7

8 Joseph C. McNeil Plant

9

10 Joint Owners:


12 Burlington Electric Department

13 Vermont Public Power Supply Authority

14

15

16

17 Highgate Transmission InterConnection

18 Joint Owners:


20 Vermont Electric Co-Op.

21 Burlington Electric Department

22 Village of Johnson Water & Light Dept


24

25

26

27

Wood fueled electric

generating station

Converter Facility

Ownership %

8.80%

0.44%

90.76%

100.00%

Ownership %

31.00%

50.00%

19.00%

100.00%

Ownership %:

82.29%

022%

7.70%

0.43%

9.36%

100.00%


------

Year/Period of Report Name of Respondent Date of Report This ~ort Is: (1) An Original (Mo, Da, Yr) 2012/04End ofGreen Mountain Power Corporation (2) n A Resubmission 04/15/2013


1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent

at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote. 2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming any intermediaries involved. 3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.

Definitions 1. See the Uniform System of Accounts for a definition of control. 2. Direct control is that which is exercised without interposition of an intermediary. 3. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control. 4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the

voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of control in the Uniform System of Accounts, regardless of the relative voting rights of each party.

Line Percent Voting Footnote No.

Name of Company Controlled Kind of Business Stock Owned Ref.

(a) (b) (c) (d)

1 NEHTC AND NEHTEC Ownership %

2 National Grid 50.43%

3 Northeast Utilities 22.65%

4 Boston Edison Company 11.05%

Vermont Electric Power Company, Inc.5 Note: Vermont Electric 4.33%

6 Canal Electric Company Power Co. Inc. as 3.42%

New England Power Company 7 agent for GMP 3.27%

8 Connecticut Municipal Electric Energy Corp 3.18% and also as 0.84%

9 Massachusetts Municipal Wholesale Electric Co agent for Citizens 0.59% I

Town of Reading 10 1.15%. 0.47%

11 City of Taunton 0.36%

12 City of Chicopee 0.32%

City of Braintree 13 0.30%

City of Peabody 14 0.27%

15 City of Holyoke 0.27%

16 City of Westfield 0.26%

17 Town of Danvers 0.24%

18 Town of Shrewsbury 0.16%

19 Town of Hudson 0.15%

20 Town of Wakefield 0.13%

21 Town of Hingham 0.12%

22 Town of Concord 0.12%

23 Town of North Attleborough 0.11%

24 Town of Middleborough 0.11%

25 Town of Groton 0.03%

26 Note: Vermont Electric Power Co .. Inc. Respondent's equity 100.00

27 is acting agent for Respondent. share equals 3.18%.




~An Original0 A Resubmission

(Mo, Da, Yr) 04/15/2013

End of 2012/04




Line Name of Company Controlled No.

(a)

1 VT Dedicated Metallic Neutral

2 Return Conductor

3

4 Joint Owners:

5


7 Vermont Electric Co-Op.

8

9

10

11

12 CY Realty, Inc

13

14

15

16 Catamount Resources Corporation

17

18

19

20

21 Millstone Unit #3


23 Dominion Nuclear CT

24 Mass Municipal Wholesale Elec. Co.

25

26

27

Kind of Business

(b)

DMNR Conductor

To own, acquire, buy, sell

and lease real and personal

property. & interests therein

Holding company of

subsidiaries that invest in

unregulated business

opportunities.

Nuclear generation


(c)

Ownership %

59.40%

4060%

100.00%

100%

100%

1.73%

94.47%

4.80%

100.00%

Footnote Ref. (d)


Name of Respondent


This ~ort Is: (1) An Original (2) FiA Resubmission

Date of Report (Mo, Da, Yr) 04/15/2013


End of 2012/Q4

OFFICERS

1. Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive officer" of a respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function

(such as sales, administration or finance), and any other person who performs similar policy making functions. 2. If a change was made during the year in the incumbent of any position, show name and total remuneration of the previous

incumbent, and the date the change in incumbency was made.

Line Salaryfor Year

Name of Officer Title No. (c)

1

(b)(a) 406,848Mary Powell President

2

3 234,957Dawn D. BugbeeVice President & CFO

4

5 230,360Robert Griffin VP of Power Supply & Risk Mgmt.

6

7 240,552Donald Rendall Vice President/General Counsel/Corp Sec.

8

9 234,957Brian Otley Vice President & Chief Operating Officer

10

11 119,286Steve Terry Vice President Development & External Affairs(6/27/12)

12

13 87,490

14

15

VP-Renewable Generation & Energy Innovation(6/27/12) Steve Costello

95,004Greg White VPJield Operations(6/27/12)

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44


Year/Period of ReportDate of ReportName of Respondent This ~ort Is: (Mo. Da. Yr) (1) An Original 2012/Q4End ofGreen Mountain Power Corporation 04/15/2013(2) D A Resubmission

DIRECTORS

1. Report below the information called for concerning each director of the respondent who held office at any time during the year. Include in column (a). abbreviated

titles of the directors who are officers of the respondent.

2. Designate members of the Executive Committee by a triple asterisk and the Chairman of the Executive Committee by a double asterisk.

I Line Name (and Title) of Director No. (a)

1 Robert Tessier

2 Chair of the Board

3

4

5 Nordahl L. Brue, Esq.

6 Director

7

8 David R. Coates

9 Director

10

11 Euclid A. Irving

12 Director

13

14 Elizabeth A. Bankowski

15 Director

16

17 Kathleen C. Hoyt

18 Director

19

20 Robert Benoit

21 Director

22

23 Pierre Despars

24 Director

25

26

27 Mary G. Powell

28 President & CEO. Director

29

30 David Wolk

31 Director

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

Principal Business Address (b)

Caisse de depot et placement du Quebec

174 Edison Avenue

SI. Lambert. QC J4R2P5

49 Oakledge Drive

Burlington. VT 05401

474 Coates Island

Colchester, VT 05446

3 Wilkinson Way

Princeton, NJ 08540

34 Tyler St.

Brattleboro. VT 05301

246 Pattrell Rd.

Norwich, VT 05055

1101 Route 139 South

Sutton Quebec JOE2KO

GazMetro

1717, reu du havre

Montreal QC H2K 2X3

Green Mountain Power

163 Acorn Lane, Colchester, VT 05446

119 Alumni Drive

Castleton. VT 05735


Name of Respondent


This 00rt Is: (1) An Original

(2)0 A Resubmission

Date of Report (Mo, Da, Yr)

04/15/2013


End of 2012/04

INFORMATION ON FORMULA RATES FERC Rate Schedule/Tariff Number FERC Proceeding

Does the respondent have formula rates? o Yes

[Z] No

1. Please list the Commission accepted formula rates including FERC Rate Schedule or Tariff Number and FERC proceeding (i.e. Docket No) accepting the rate(s) or changes in the accepted rate.

Line No. FERC Proceeding

1 FERC Electric Tariff No. 3 Section 1/ - OATT

FERC Rate Schedule or Tariff Number

Docket EC11-117-00

2 Docket ER 12-2304-000

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

Schedule 21-GMP

FERC FORM NO.1 (NEW. 12-08) Page 106

YearlPeriod of Report Date of Report (Mo, Da, Yr) 2012/Q4End of

04/15/2013

o Yes

[Z] No

Name of Respondent This ~ort Is:

Green Mountain Power Corporation (1) An Original

(2)0 A Resubmission

INFORMATION ON FORMULA RATES FERC Rate Schedulerrariff Number FERC Proceeding

Does the respondent file with the Commission annual (or more frequent) filings containing the inputs to the formula rate(s)?

2. If yes, provide a listing of such filings as contained on the Commission's eLibrary website

Document Line Date No. Accession No. \ Filed Date Docket No. Description

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

Formula Rate FERC Rate Schedule Number or Tariff Number

FERC FORM NO.1 (NEW. 12-08) Page 106a

Name of Respondent This R~ort Is: Date of Report Year/Period of Report

Green Mountain Power Corporation (1) An Original (Mo, Da, Yr) End of 2012/04 (2) n A Resubmission 04/15/2013

INFORMATION ON FORMULA RATES Formula Rate Variances

1. If a respondent does not submit such filings then indicate in a footnote to the applicable Form 1 schedule where formula rate inputs differ from amounts reported in the Form 1.

2. The footnote should provide a narrative description explaining how the "rate" (or billing) was derived if different from the reported amount in the Form 1.

3. The footnote should explain amounts excluded from the ratebase or where labor or other allocation factors, operating expenses, or other items impacting formula rate inputs differ from amounts reported in Form 1 schedule amounts.

4. Where the Commission has provided guidance on formula rate inputs, the specific proceeding should be noted in the footnote.

Line No. Page No(s). Schedule Column Line No

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

FERC FORM NO.1 (NEW. 12-08) Page 106b

Name of Respondent


This Report Is: (1) Q9 An Original (2) D A Resubmission

Date of Report

04/15/2013

Year/Period of Report End of 2012/Q4

IMPORTANT CHANGES DURING THE QUARTER/YEAR

Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in accordance with the inquiries. Each inquiry should be answered. Enter "none," "not applicable," or "NA" where applicable. If information which answers an inquiry is given elsewhere in the report, make a reference to the schedule in which it appears. 1. Changes in and important additions to franchise rights: Describe the actual consideration given therefore and state from whom the franchise rights were acquired. If acquired without the payment of consideration, state that fact. 2. Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to Commission authorization. 3. Purchase or sale of an operating unit or system: Give a brief description of the property, and of the transactions relating thereto, and reference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accounts were submitted to the Commission. 4. Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Give effective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give reference to such authorization. 5. Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operations began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of customers added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major new continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location and approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc. 6. Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as appropriate, and the amount of obligation or guarantee. 7. Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments. 8. State the estimated annual effect and nature of any important wage scale changes during the year. 9. State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any such proceedings culminated during the year. 10. Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an officer, director, security holder reported on Page 104 or 105 of the Annual Report Form No.1, voting trustee, associated company or known associate of any of these persons was a party or in which any such person had a material interest. 11. (Reserved.) 12. If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are applicable in every respect and furnish the data required by Instructions 1 to 11 above, such notes may be included on this page. 13. Describe fUlly any changes in officers, directors, major security holders and voting powers of the respondent that may have occurred during the reporting period. 14. In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30 percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.

PAGE 108 INTENTIONALLY LEFT BLANK SEE PAGE 109 FOR REQUIRED INFORMATION.

--~-__-------.J


Name of Respondent This Report is: Date of Report Year/Period of Report (1) XAn Original (Mo, Da, Yr)

Green Mountain Power Corporation (2) A Resubmission 04/15/2013 2012/04

IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)

Important changes during the quarter/year 1. No changes to or purchases of franchise rights occurred. 2. See Notes for changes in ownership of affiliated companies. 3. No operating units were purchased or sold. Central Vermont Public Service Corporation (NYSE-CV) (CVPS)

was purchased by Gaz Metro Limited Partnership (Gaz Metro) on June 27, 2012, and the combination ofCVPS and Green Mountain Power Corporation (GMP), a subsidiary of Gaz Metro, was approved by the Vermont Public Service Board and the Federal Energy Regulatory Commission, and occurred on October 1,2012.

4. No important leaseholds were entered into or surrendered. 5. No important extensions or reductions of the distribution system occurred. See Notes for a discussion of

changes to the transmission system owned by affiliated company Transco LLC. 6. See notes for changes in short term debt and long term debt. 7. No changes to articles of incorporation occurred. 8. No significant changes to wage scale occurred. 9. See notes for a discussion oflegal proceedings. 10. See notes for a discussion of related party transactions, including the note for investment in affiliated

compames. 11. (reserved) 12. See notes for disclosure and changes in power supply contracts, pension obligations, rate cases and

regulatory assets and liabilities. l3.David S. Wolk was elected to the Board by our Sole Shareholder NNEEC on June 19,2012. No other

changes have occurred with respect to officers. No other changes have occurred with respect to directors. 14. Not Applicable

IFERC FORM NO.1 (ED. 12-96) Page 109.1

Year/Period of ReportDate of ReportThis Report Is:Name of Respondent (Mo,Da, Yr)(1 ) An OriginalGreen Mountain Power Corporation ~

2012/0404/15/2013 End of (2) A Resubmission 0 COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)

Line Ref.

No. Page No.Title of Account

(b)(a)I

1 UTILITY PLANT

200-201Utility Plant (101-106,114) 2

200-201Construction Work in Progress (107) 3

TOTAL Utility Plant (Enter Total of lines 2 and 3)4

200-201(Less) Accum. Provo for Depr. Amort. Depl. (108,110,111,115)5

6 Net Lltility Plant (Enter Total of line 4 less 5)

202-2037 Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1)

Nuclear Fuel Materials and Assemblies-Stock Account (120.2) 8

Nuclear Fuel Assemblies in Reactor (120.3) 9

Spent Nuclear Fuel (120.4) 10

Nuclear Fuel Under Capital Leases (120.6) 11

202-203(Less) Accum. Provo for Amort. of Nucl. Fuel Assemblies (120.5) 12

Net Nuclear Fuel (Enter Total of lines 7-11 less 12) 13

14 Net Utility Plant (Enter Total of lines 6 and 13)

15 Utility Plant Adjustments (116)

16 Gas Stored Underground - Noncurrent (117)

17 OTHER PROPERTY AND INVESTMENTS

18 Nonutility Property (121)

(Less) Accum. Provo for Depr. and Amort. (122) 19

20 Investments in Associated Companies (123)

224-225Investment in Subsidiary Companies (123.1) 21

(For Cost of Account 123.1, See Footnote Page 224, line 42) 22

228-22923 Noncurrent Portion of Allowances

Other Investments (124) 24

25 Sinking Funds (125)

26 Depreciation Fund (126)

27 Amortization Fund - Federal (127)

Other Special Funds (128) 28

29 Special Funds (Non Major Only) (129)

30 Long-Term Portion of Derivative Assets (175)

31 Long-Term Portion of Derivative Assets - Hedges (176)

32 TOTAL Other Property and Investments (Lines 18-21 and 23-31)

33 CURRENT AND ACCRUED ASSETS

Cash and Working Funds (Non-major Only) (130) 34

35 Cash (131)

36 Special Deposits (132-134)

37 Working Fund (135)

38 Temporary Cash Investments (136)

39 Notes Receivable (141)

40 Customer Accounts Receivable (142)

41 Other Accounts Receivable (143)

42 (Less) Accum. Provo for Uncollectible Acct.-Credit (144)

43 Notes Receivable from Associated Companies (145)

44 Accounts Receivable from Assoc. Companies (146)

45 Fuel Stock (151) 227

46 Fuel Stock Expenses Undistributed (152) 227

47 Residuals (Elec) and Extracted Products (153) 227

48 Plant Materials and Operating Supplies (154) 227

Merchandise (155) 49 227

50 Other Materials and Supplies (156) 227

51 Nuclear MaterialS Held for Sale (157) 202-203/227

Allowances (158.1 and 158.2) 52 228-229

Current Year Prior Year End of OuarterlYear End Balance

Balance 12/31 (c) (d)

1,340,682,453 472,084,329

109,313,860 81,325,140

1,449,996,313 553,409,469

517,692,242 192,666,081

932,304,071 360,743,388

0 0

2,141,107 0

3,189,051 0

12,378,457 0

0 0

14,494,146 0

3,214,469 0

935,518,540 360,743,388

0 0

0 0

6,813,765 6,138,196

5,011,633 5,008,574

0 0

351,218,881 138,721,026

0 0

19,535,234 10,814,592

0 0

0 0

0 0

6,691,554 0

0 0

0 0

0 0

379,247,801 150,665,240

0 0

1,129,048 10,573,005

5,615,053 4,793,417

7,500 5,500

0 0

0 0

46,969,829 19,143,059

7,754,556 4,018,516

2,990,572 432,080

0 0

1,480,098 24,433

4,915,371 3,350,626

51,796 6,472

0 0

11,060,531 4,566,534

0 0

0 0

0 0

0 0

FERC FORM NO.1 (REV. 12-03) Page 110 -'

Year/Period of ReportDate of Report (Mo,Oa, Yr)

2012/0404/15/2013 End of

This Report Is:Name of Respondent

(1 ) [ZJ An OriginalGreen Mountain Power Corporation (2) A Resubmission0

COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)Continued)

Line No.

Title of Account (a)

53 (Less) Noncurrent Portion of Allowances

54 Stores Expense Undistributed (163)

55 Gas Stored Underground - Current (164.1)

56 Liquefied Natural Gas Stored and Held for Processing (164.2-164.3)

57 Prepayments (165)

58 Advances for Gas (166-167)

59 Interest and Dividends Receivable (171)

60 Rents Receivable (172)

61 Accrued Utility Revenues (173)

62 Miscellaneous Current and Accrued Assets (174)

63 Derivative Instrument Assets (175)

64 (Less) Long-Term Portion of Derivative Instrument Assets (175)

65 Derivative Instrument Assets - Hedges (176)

66 (Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176

67 Total Current and Accrued Assets (Lines 34 through 66)

68 DEFERRED DEBITS

69 Unamortized Debt Expenses (181)

70 Extraordinary Property Losses (182.1 )

71 Unrecovered Plant and Regulatory Study Costs (182.2)

72 Other Regulatory Assets (182.3)

73 Prelim. Survey and Investigation Charges (Electric) (183)

74 Preliminary Natural Gas Survey and Investigation Charges 183.1)

75 Other Preliminary Survey and Investigation Charges (183.2)

76 Clearing Accounts (184)

77 Temporary Facilities (185)

78 Miscellaneous Deferred Debits (186)

79 Def. Losses from Disposition of Utility PIt. (187)

80 Research, Devel. and Demonstration Expend. (188)

81 Unamortized Loss on Reaquired Debt (189)

82 Accumulated Deferred Income Taxes (190)

83 Unrecovered Purchased Gas Costs (191)

84 Total Deferred Debits (lines 69 through 83)

85 TOTAL ASSETS (lines 14-16, 32, 67, and 84)

FERC FORM NO.1 (REV. 12-03) Page 111

Ref. Page No.

(b)

227

230a

230b

232

233

352-353

234

Prior Year Current Year End BalanceEnd of Ouarter/Year

12/31Balance (d)

0

(c)

0

980,835 585,204

0 0

0 0

19,888,158 1,838,565

0 0

1,615 0

1,726,711 1,487,762

31,849,163 10,719,166

3,993,395 443,601

0 0

0 0

0 0

0 0

134,433,087 61,123,780

5,269,859 1,465,876

0 0

0 0

2,249,344 1,598,748

4,385,285 1,993,616

0 0

0 0

0 13

0 0

143,779,489 64,807,593

0 0

0 0

0 0

48,179,568 27,981,984

0 0

203,863,545 97,847,830

1,653,062,973 670,380,238

Year/Period of ReportDate of ReportName of Respondent This Report is: (mo, da, yr)(1 ) An Original Green Mountain Power Corporation ~

201210404/15/2013 end of (2) A Resubmission 0 COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)

Line No.


1 PROPRIETARY CAPITAL

2 Common Stock Issued (201)

3 Preferred Stock Issued (204)

4 Capital Stock Subscribed (202, 205)

5 Stock Liability for Conversion (203, 206)

6 Premium on Capital Stock (207)

7 Other Paid-In Capital (208-211)

8 Installments Received on Capital Stock (212)

9 (Less) Discount on Capital Stock (213)

10 (Less) Capital Stock Expense (214)

11 Retained Earnings (215, 215.1, 216)

12 Unappropriated Undistributed Subsidiary Earnings (216.1)

13 (Less) Reaquired Capital Stock (217)

14 Noncorporate Proprietorship (Non-major only) (218)

15 Accumulated Other Comprehensive Income (219)

16 Total Proprietary Capital (lines 2 through 15)

17 LONG-TERM DEBT

18 Bonds (221)

19 (Less) Reaquired Bonds (222)

20 Advances from Associated Companies (223)

21 Other Long-Term Debt (224)

22 Unamortized Premium on Long-Term Debt (225)

23 (Less) Unamortized Discount on Long-Term Debt-Debit (226)

24 Total Long-Term Debt (lines 18 through 23)

25 OTHER NONCURRENT LIABILITIES

26 Obligations Under Capital Leases - Noncurrent (227)

27 Accumulated Provision for Property Insurance (228.1)

28 Accumulated Provision for Injuries and Damages (228.2)

29 Accumulated Provision for Pensions and Benefits (228.3)

30 Accumulated Miscellaneous Operating Provisions (228.4)

31 Accumulated ProviSion for Rate Refunds (229)

32 Long-Term Portion of Derivative Instrument Liabilities

33 Long-Term Portion of Derivative Instrument Liabilities - Hedges

34 Asset Retirement Obligations (230)

35 Total Other Noncurrent Liabilities (lines 26 through 34)

36 CURRENT AND ACCRUED LIABILITIES

37 Notes Payable (231)

38 Accounts Payable (232)

39 Notes Payable to Associated Companies (233)

40 Accounts Payable to Associated Companies (234)

41 Customer Deposits (235)

42 Taxes Accrued (236)

43 Interest Accrued (237)

44 Dividends Declared (238)

45 Matured Long-Term Debt (239)

Ref. Page No.

(b)

250-251

250-251

253

252

254

254b

118-119

118-119

250-251

122(a)(b)

256-257

256-257

256-257

256-257

262-263

Current Year Prior Year End of Ouarter/Year End Balance

Balance 12/31

(c) (d)

333 333

0 0

0 0

0 0

0 0

499,852,980 144,781,543

0 0

0 0

0 0

26,097,407 61,859,015

64,377,456 13,837,872

0 0

0 0

-120,409 0

590,207,767 220,478,763

533,490,046 213,145,046

0 0

0 0

0 0

0 0

0 0

533,490,046 213,145,046

3,321,984 2,115,224

0 0

2,323,341 1,185,204

11,868,719 3,636,552

0 0

0 0

0 0

3,520,593 4,107,850

3,599,457 799,997

24,634,094 11,844,827

46,410,673 19,000,000

58,051,070 21,575,437

0 0

4,429,510 11,875,059

3,187,179 911,632

3,817,384 2,253,404

4,234,581 3,106,984

0 0

0 0

FERC FORM NO.1 (rev. 12-03) Page 112

Year/Period of ReportDate of ReportName of Respondent This Report is: (mo, da, yr)(1 ) An OriginalGreen Mountain Power Corporation ~

2012/Q404/15/2013 end of

COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDIT~ntinued)

(2) 0 A Resubmission

Line No.


46 Matured Interest (240)

47 Tax Collections Payable (241)

48 Miscellaneous Current and Accrued Liabilities (242)

49 Obligations Under Capital Leases-Current (243)

50 Derivative Instrument Liabilities (244)

51 (Less) Long-Term Portion of Derivative Instrument Liabilities

52 Derivative Instrument Liabilities - Hedges (245)

53 (Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges

54 Total Current and Accrued Liabilities (lines 37 through 53)

55 DEFERRED CREDITS

56 Customer Advances for Construction (252)

57 Accumulated Deferred Investment Tax Credits (255)

58 Deferred Gains from Disposition of Utility Plant (256)

59 Other Deferred Credits (253)

60 Other Regulatory Liabilities (254)

61 Unamortized Gain on Reaquired Debt (257)

62 Accum. Deferred Income Taxes-Accel. Amort.(281)

63 Accum. Deferred Income Taxes-Other Property (282)

64 Accum. Deferred Income Taxes-Other (283)

65 Total Deferred Credits (lines 56 through 64)

66 TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)

Ref. Page No.

(b)

266-267

269

278

272-277

Current Year Prior Year End of QuarterlYear End Balance

Balance 12/31 (c) (d)

0 0

907,992 559,070

17,803,861 422,271

0 0

0 0

0 0

5,786,223 5,297,910

3,520,593 4,107,850

141,107,880 60,893,917

11,175,834 7,525,152

4,092,082 2,248,393

0 0

96,172,578 45,698,748

1,182,102 1,202,747

0 0

0 0

163,363,967 76,019,350

87,636,623 31,323,385

363,623,186 164,017,775

1,653,062,973 670,380,328

FERC FORM NO.1 (rev. 12-03) Page 113

Name of Respondent YearlPeriod of Report Date of Report This ~ort Is: (Mo, Da, Yr)(1) An Original 2012/Q4End of Green Mountain Power Corporation 04/15/2013(2) EjA Resubmission

STATEMENT OF INCOME

Quarterly 1. Report in column (c) the current year to date balance. Column (c) equals the total of adding the data in column (g) plus the data in column (i) plus the data in column (k). Report in column (d) similar data for the previous year. This information is reported in the annual filing only. 2. Enter in column (e) the balance for the reporting quarter and in column (f) the balance for the same three month period for the prior year. 3. Report in column (g) the quarter to date amounts for electric utility function; in column (i) the quarter to date amounts for gas utility, and in column (k) the quarter to date amounts for other utility function for the current year quarter. 4. Report in column (h) the quarter to date amounts for electric utility function; in column U) the quarter to date amounts for gas utility, and in column (I) the quarter to date amounts for other utility function for the prior year quarter. 5. If additional columns are needed, place them in a footnote.

Annual or Quarterly if applicable 5. Do not report fourth quarter data in columns (e) and (f) 6. Report amounts for accounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility columnin a similar manner to a utility department. Spread the amount(s) over lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals. 7. Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above.

Line INo.

Total

Current Year to Total

Prior Year to Current 3 Months

Ended

Prior 3 Months

Ended

(Ref.) Date Balance for Date Balance for Quarterly Only Quarterly Only

Title of Account Page No. QuarterlYear QuarterlYear No 4th Quarter No 4th Quarter

(a) (b) (c) (d) (e) (f)

1 UTILITY OPERATING INCOME

2 Operating Revenues (400) 300-301 ~ 3 Operating Expenses

4 Operation Expenses (401) 320-323 263,829.761 190,807,307

5 Maintenance Expenses (402) 320-323 22,218,089 14,354,849

6 Depreciation Expense (403) 336-337 18,351,830 13,592,119

7 Depreciation Expense for Asset Retirement Costs (403.1) 336-337

8 Amort & DepL of Utility Plant (404-405) 336-337 7,086,301 4,628,933

9 Amort. of Utility Plant Acq. Adj. (406) 336-337

10 Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)

11 Amort. of Conversion Expenses (407)

12 Regulatory Debits (407.3)

13 (Less) Regulatory Credits (4074)

14 Taxes Other Than Income Taxes (4081) 262-263 14,869,740 8,969,259

15 Income Taxes Federal (409.1) 262-263 -6,691,495 3,474,359

16 - Other (4091) 262-263

17 Provision for Deferred Income Taxes (410.1) 234,272-277 25,058,135 9,710,243

18 (Less) Provision for Deferred Income Taxes-Cr (411.1) 234, 272-277

19 Investment Tax Credit Adj. - Net (411 4) 266 -276,138 -234,430

20 (Less) Gains from Disp. of Utility Plant (411.6)

21 Losses from Disp. of Utility Plant (4117)

22 (Less) Gains from Disposition of Allowances (411.8)

23 Losses from Disposition of Allowances (411.9)

24 Accretion Expense (411.10)

25 TOTAL Utility Operating Expenses (Enter Total or lines 4 thru 24) 344,446,223 245,302,639

26 Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pgl17,line 27 22,649,036 9,986,686

FERC FORM NO. 1/3-Q (REV. 02-04) Page 114

Year/Period of ReportName of Respondent This ~ort Is: Oate of Report (1) ~ An Original (Mo, Oa, Yr) End of 2012/04Green Mountain Power Corporation (2) 0 A Resubmission 04/15/2013

STATEMENT OF INCOME FOR THE YEAR (Continued)

9. Use page 122 for important notes regarding the statement of income for any account thereof. 10. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be made to the utility's customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effected the gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights of the utility to retain such revenues or recover amounts paid with respect to power or gas purchases. 11 Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rate proceeding affecting revenues received or costs incurred for power or gas purches, and a summary of the adjustments made to balance sheet. income, and expense accounts. 12. If any notes appearing in the report to stokholders are applicable to the Statement of Income, such notes may be included at page 122.

13. Enter on page 122 a concise explanation of only those changes in accounting methods made during the year which had an effect on net income, including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes. 14. Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports. 15. If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to this schedule.

ELECTRIC UTILITY GAS UTILITY OTHER UTILITY r---:C""'u-r-re-n-'-t""y'--e-ar-t'--o--:D""'a--:t-e-'---"P:-re-v""'io-u-s-Y:-:-ea-r--:t-o-=O:-a--:te--I--C-=-ur-re-n--:t"""y""'e-a-r-'-to-=:O-at:-e---'---:P:-r-e--:vi'--o-us---""'y'--e-ar-t:--o--:D""'a--:t-e-+"C-ur-re-n"'ty"e-a-rt'--o"D:--a:-te--'--'P"r-ev--:io-u-s"y'--ea--:r'7to-;D"a'7te---1 Line

(in dollars) (in dollars) (in dollars) (in dollars) (in dollars) (in dollars) No.

(g) (h) (i) U) (k) (I)

263,829,761 190,807,307 4

22,218,089 14,354,849 5

18,351,830 13,592,119 6

7

7,086,301 4,628,933 8

9

10

11

12

13

14,869,740 8,969,259 14

-6,691,495 3,474,359 15

16

25,058,135 9,710,243 17

18

-276,138 -234,430 19

20

21

22

23

24

344,446,223 245,302,639 25

22,649,036 9,986,686 26


Date of Report Name of Respondent This ~ort Is: (Mo, Da, Yr)(1) An Original

Green Mountain Power Corporation 04/15/2013

STATEMENT OF INCOME FOR THE YEAR (continued)

(2) n A Resubmission

Line TOTAL No.

(Ref.) Title of Account Page No. Current Year Previous Year

(a) (b) (c) (d)

27 Net Utility Operating Income (Carried fOlWard from page 114) 22,649,036 9,986,686

28 Other Income and Deductions

29 Other Income

30 Nonutilty Operating Income

31 Revenues From Merchandising, Jobbing and Contract Work (415) 514,363 638,027

32 (Less) Costs and Exp, of Merchandising, Job. &Contract Work (416) 385,911 435,614

33 Revenues From Nonutility Operations (417)

34 (Less) Expenses of Nonutility Operations (417.1)

35 Nonoperating Rental Income (418) 515,331 252,255

36 Equity in Earnings of Subsidiary Companies (418,1) 119 23,599,423 21,171,534

37 Interest and Dividend Income (419) 28,595 46.633

38 Allowance for Other Funds Used During Construction (419.1) 138.070

39 Miscellaneous Nonoperating Income (421) 233,471 48,455

40 Gain on Disposition of Property (4211) 423,079 35,865

41 TOTAL Other Income (Enter Total of lines 31 thru 40) 25,066,421 21,757,155

42 Other Income Deductions

43 loss on Disposition of Property (421,2) 4,880

44 Miscellaneous Amortization (425)

45 Donations (426,1) 209,798 101,206

46 Life Insurance (426,2) 18,204 -317.892

47 Penalties (426.3) -17

48 Exp, for Certain Civic, Political & Related Activities (426.4) 291,953 247,156

49 Other Deductions (426,5) 1,136.063 388,148

50 TOTAL Other Income Deductions (Total of lines 43 thru 49) 1,660,881 418,618

51 Taxes Applic, to Other Income and Deductions ~

52 Taxes Other Than Income Taxes (408,2) 262-263 34,472 30,200

53 Income Taxes-Federal (409,2) 262-263

54 Income Taxes-Other (409,2) 262-263

55 Provision for Deferred Inc, Taxes (410.2) 234, 272-277

56 (Less) Provision for Deferred Income Taxes-Cr. (411,2) 234,272-277

57 Investment Tax Credit Adj,-Net (411 ,5)

58 (Less) Investment Tax Credits (420)

59 TOTAL Taxes on Other Income and Deductions (Total of lines 52-58) 34,472 30,200

60 Net Other Income and Deductions (Total of lines 41,50,59) 23,371,068 21,308,337

61 Interest Charges

62 Interest on Long-Term Debt (427) 17,094,172 10,925,799

63 Amort, of Debt Disc, and Expense (428) 132,099 29,458

64 Amortization of loss on Reaquired Debt (428,1)

65 (Less) Amort of Premium on Debt-Credit (429)

66 (Less) Amortization of Gain on Reaquired Debt-Credit (429,1)

67 Interest on Debt to Assoc, Companies (430)

68 Other Interest Expense (431) 223,497 541.741

69 (Less) Allowance for Borrowed Funds Used During Construction-Cr, (432)

70 Net Interest Charges (Total of lines 62 thru 69) 17,449,768 11,496,998

71

72

Income Before Extraordinary Items (Total of lines 27, 60 and 70)

Extraordinary Items

28,570,336 . 19,798,025 'm

73 Extraordinary Income (434)

74 (Less) Extraordinary Deductions (435)

75 Net Extraordinary Items (Total of line 73 less line 74)

76 Income Taxes-Federal and Other (409.3) 262-263

77 Extraordinary Hems After Taxes (line 75 less line 76)

78 Net Income (Total of line 71 and 77) 28,570,336 19,798,025


End of 2012/04

Current 3 Months Ended

Quarterly Only No 4th Quarter

(e)

Prior 3 Months Ended

Quarterly Only No 4th Quarter

(D

v

FERC FORM NO. 1I3-Q (REV. 02-04) Page 117

Year/Period of ReportThis ~ort Is: Date of ReportName of Respondent (1) ~An Original (Mo, Da, Yr) End of 2012/Q4

Green Mountain Power Corporation (2) A Resubmission 04/15/2013

STATEMENT OF RETAINED EARNINGS

1. Do not report Lines 49-53 on the quarterly version. 2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated undistributed subsidiary earnings for the year. 3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436 - 439 inclusive). Show the contra primary account affected in column (b) 4. State the purpose and amount of each reservation or appropriation of retained earnings. 5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow by credit, then debit items in that order. 6. Show dividends for each class and series of capital stock. 7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings. 8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated. 9. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.

Item

No.

Line

(a)

UNAPPROPRIATED RETAINED EARNINGS (Account 216)

1 Balance-Beginning of Period

2 Changes

3 Adjustments to Retained Earnings (Account 439)

4

5 CVPS Merger Adjustment

6 (Post-acquisition retained earnings 6/28/12 to 9/30/12)

7

8

9 TOTAL Credits to Retained Earnings (Accl. 439)

10

11

12

13

14

15 TOTAL Debits to Retained Earnings (Accl. 439)

16 Balance Transferred from Income (Account 433 less Account 418.1)

17 Appropriations of Retained Earnings (Accl. 436)

18 Amortization Reserve, Federal

19 (CVPS Merger Adjustment - transfer 9/30/12 balance)

20

21

22 TOTAL Appropriations of Retained Earnings (Accl. 436)

23 Dividends Declared-Preferred Stock (Account 437)

24

25

26

27

28

29 TOTAL Dividends Declared-Preferred Stock (Accl. 437)

30 Dividends Declared-Common Stock (Account 438)

31

32

33

34

35

36 TOTAL Dividends Declared-Common Stock (Accl. 438)

37 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings

38 Balance - End of Period (Total 1,9,15,16,22,29,36,37)

Contra Primary Account Affected

(b)

Current QuarterlYear Year to Date

Balance

(c)

-15,710,603

-15,710,603

-26,940,161

27,531,168

Previous Quarter/Year Year to Date

Balance

(d)

( 10,798,976)

10,798,976)

16,941,265

62,508,322

1,918,243

215.1

1,918,243

4,970,913

784,454

784,454

APPROPRIATED RETAINED EARNINGS (Account 215) ~~~ ---'------------,-------"

FERC FORM NO. 1/3-0 (REV. 02-04) Page 118

Year/Period of ReportName of Respondent This ~ort Is: Date of Report (1) ~An Original (Mo, Da, Yr) End of 2012/Q4Green Mountain Power Corporation (2) A Resubmission 04/15/2013

STATEMENT OF RETAINED EARNINGS

1. Do not report Lines 49-53 on the quarterly version. 2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated undistributed subsidiary earnings for the year. 3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436 - 439 inclusive). Show the contra primary account affected in column (b) 4. State the purpose and amount of each reservation or appropriation of retained earnings. 5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow by credit, then debit items in that order. 6. Show dividends for each class and series of capital stock. 7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings. 8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated. 9. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.

Line Item

No. (a)

39

40

41

42

43

44

45 TOTAL Appropriated Retained Earnings (Account 215)

APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)

46 TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Accl. 215.1)

47 TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)

48 TOTAL Retained Earnings (Accl. 215, 215.1, 216) (Total 38, 47) (216.1)

UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account

Report only on an Annual Basis, no Quarterly

49 Balance-Beginning ot Year (Debit or Credit)

50 Equity in Earnings for Year (Credit) (Account 418.1)

51 (Less) Dividends Received (Debit)

52 CVPS Merger transfer ot $44,716,277 and other.

53 Balance-End of Year (Total lines 49thru 52)

Contra Primary Account Affected

(b)

Current Previous Quarter/Year Quarter/Year Year to Date Year to Date

Balance Balance

(c) (d)

13,837,872

23,599,423

18,835,241

45,775,402

64,377,456

8,958,296

21,171,534

15,232,833

1,059,125)

13,837,872


Name of Respondent


This ~ort Is: (1) An Original (2) n A Resubmission


04/15/2013


End of 2012/Q4

STATEMENT OF CASH FLOWS

(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as investments, fixed assets, intangibles, etc. (2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and Cash Equivalents at End of Period" with related amounts on the Balance Sheet. (3) Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid. (4) Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acqUired with liabilities assumed in the Notes to the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the dollar amount of leases capitalized with the plant cost.

Current Year to DateDescription (See Instruction No. 1 for Explanation of Codes)Line QuarterlYear No.

(a) (b)

1 Net Cash Flow from Operating Activities:

2 Net Income (Line 78(c) on page 117) 28,570,336

3 Noncash Charges (Credits) to Income:

4 17,537,374Depreciation and Depletion

1,780,332Amortization of Utility Plant 5

6,241,2286 Amortization of Other

7

8 25,058,135Deferred Income Taxes (Net)

-276,138

10

Investment Tax Credit Adjustment (Net)9

-10,274,017

11

Net (Increase) Decrease in Receivables

-2,294,236

12

Net (Increase) Decrease in Inventory

Net (Increase) Decrease in Allowances Inventory

13 -4,622,356

14

Net Increase (Decrease) in Payables and Accrued Expenses

-225,004Net (Increase) Decrease in Other Regulatory Assets

20,64515 Net Increase (Decrease) in Other Regulatory Liabilities

138,070

17

(Less) Allowance for Other Funds Used During Construction 16

4,732,266(Less) Undistributed Earnings from Subsidiary Companies

-645,073Other (provide details in footnote):18

-8,050,416

20

19 Change in Deferred Revenues

-289,928

21

Net Gain on Disposal of Assets

-12,514,762

22

Other

35,145,784

23

24

Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21)

Cash Flows from Investment Activities:

25 Construction and Acquisition of Plant (including land):

26 -168,935,720

27

Gross Additions to Utility Plant (less nuclear fuel)

-829,557

28

Gross Additions to Nuclear Fuel

Gross Additions to Common Utility Plant . 29 Gross Additions to Nonutility Plant -527,622

30 (Less) Allowance for Other Funds Used During Construction -138,070

31 Other (provide details in footnote):

32

33 -179,852

34 Cash Outflows for Plant (Total of lines 26 thru 33) -170,334,681

35

36 Acquisition of Other Noncurrent Assets (d)

37 Proceeds from Disposal of Noncurrent Assets (d) 181,787

38 Cash acquired from CVPS Merger 6,343,385

39 Investments in and Advances to Assoc. and Subsidiary Companies -34,271,616

40 Contributions and Advances from Assoc. and Subsidiary Companies

41 Disposition of Investments in (and Advances to)

42 Associated and Subsidiary Companies

43

44 Purchase of Investment Securities (a)

45 Proceeds from Sales of Investment Securities (a) 606,716

Previous Year to Date QuarterlYear

(c)

19,798,025

13,587,401

1,387,558

3,246,093

9,710,243

-234,430

-3,750,328

-434,024

9,873,867

92,460

-52,662

6,089,338

19,162

-4,389,680

42,764,347

-84,761,890

-305,571

-85,067,461

12,520

FERC FORM NO.1 (ED. 12·96) Page 120

Year/Period of ReportDate of ReportName of Respondent This ~ort Is: (Mo, Da, Yr)(1) ~An Original End of 2012/04Green Mountain Power Corporation 04/15/2013(2) A Resubmission

STATEMENT OF CASH FLOWS

(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as investments, fixed assets, intangibles, etc. (2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and Cash Equivalents at End of Period" with related amounts on the Balance Sheet. (3) Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid. (4) Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the dollar amount of leases capitalized with the plant cost.

Description (See Instruction NO.1 for Explanation of Codes)

(a)

46 Loans Made or Purchased

47 Collections on Loans

48

49 Net (Increase) Decrease in Receivables

50 Net (Increase) Decrease in Inventory

51 Net (Increase) Decrease in Allowances Held for Speculation

52 Net Increase (Decrease) in Payables and Accrued Expenses


54 Increase in Restricted Cash - Project Fund Investments

55

56 Net Cash Provided by (Used in) Investing Activities

57 Total of lines 34 thru 55)

58

59 Cash Flows from Financing Activities:

60 Proceeds from Issuance of:

61 Long-Term Debt (b)

62 Preferred Stock

63 Common Stock


65

66 Net Increase in Short-Term Debt (c)


68

69

70 Cash Provided by Outside Sources (Total 61 thru 69)

71

72 Payments for Retirement of:

73 Long-term Debt (b)

74 Preferred Stock

75 Common Stock


77

78 Net Decrease in Short-Term Debt (c)

79 Capital Contribution from Parent

80 Dividends on Preferred Stock

81 Dividends on Common Stock

82 Net Cash Provided by (Used in) Financing Activities

83 (Total of lines 70 thru 81)

84

85 Net Increase (Decrease) in Cash and Cash Equivalents

86 (Total of lines 22,57 and 83)

87

88 Cash and Cash Equivalents at Beginning of Period

89

90 Cash and Cash Equivalents at End of period

Current Year to Date Ouarter/Year

(b)

18,286

-58,114

108,944,600

75,000,000

77,632

184,022,232

Previous Year to Date Ouarter/Year

(c)

50,000,045

10,000,000

10,900,000

70,900,045

-7,384,500 -6,620,000

-357,265

-8,565,774

500,000

-15,625,995 -10,798,976

5,726,133 15,371,922

FERC FORM NO, 1 (ED. 12-96) Page 121

Name of Respondent


This Report Is: (1) 0 An Original (2) 0 A Resubmission

Date of Report

04/15/2013


NOTES TO FINANCIAL STATEMENTS

1. Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement, providing a subheading for each statement except where a note is applicable to more than one statement. 2. Furnish particulars (details) as to any significant contingent assets or liabilities eXisting at end of year, inclUding a brief explanation of any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of a claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrears on cumulative preferred stock. 3. For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plant adjustments and requirements as to disposition thereof. 4. Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give an explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts. 5. Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such restrictions. 6. If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein. 7. For the 30 disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information not misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be omitted. 8. For the 30 disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements; status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such matters shall be provided even though a significant change since year end may not have occurred. 9. Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are applicable and furnish the data required by the above instructions, such notes may be included herein.

PAGE 122 INTENTIONALLY LEFT BLANK SEE PAGE 123 FOR REOUIRED INFORMATION.




NOTES TO FINANCIAL STATEMENTS (Continued)

GlVIP FERC FORlVI 1 - DECEMBER 31,2012 (dollars in thousands)

(1) Nature of Operations

Green Mountain Power Corporation (the Company or GMP), a wholly owned subsidiary of Northem New England Energy Corporation (NNEEC), operates as an electric utility that purchases, generates, transmits, distributes, and sells electricity, and utility construction services, in Vermont to approximately 256,000 customer accounts. The Company was acquired by NNEEC (itself a wholly owned subsidiary of Gaz Metro Limited Partnership of Canada), on April 12, 2007.

(a) Acquisition ofCentral Vermont Public Service Corporation by NNEEC

On June 27,2012, NNEEC, through a merger subsidiary, purchased the outstanding stock of former Central Vermont Public Service Corporation (CVPS) and former CVPS became a wholly owned subsidiary ofNNEEC, and a related party to GMP. The acquisition of former CVPS required and received prior approval from the VemlOnt Public Service Board (VPSB), the Federal Energy Regulatory Commission (FERC) and a variety of additional state and federal regulatory entities.

(b) Merger ofCVPS and GMP

On October 1, 2012, after receiving all requisite state and federal regulatory approvals, fonner CVPS was merged with and into GMP, with GMP as the surviving entity (the Merger). Under U.S. generally accepted accounting principles (GAAP), the merger of former CVPS with GMP represents a combination of entities under common control. Accordingly, the transfer of the assets and liabilities of former CVPS to GMP are recognized in the consolidated financial statements of GMP at their respective carrying amounts as of October 1,2012. Subsequent to the merger, the operations (three months) and net assets of fonner CVPS were incorporated with GMP.

In connection with the Merger, on June 27,2012, VYNPC, became a wholly owned subsidiary ofNNEEC. On October I, 2012, VYl\JPC became a direct wholly owned subsidiary of the Company, resulting from the merger of former CVPS and GMP, and GMP's direct control of its 100% ownership in VYl\JPc.

The Company operates primarily under one business segment and most of the Company's revenue is generated from sales in its regulated electric utility operation. The Company is regulated by the VPSB and uses the Unifom1 System of Accounts established by the FERC.

The Company's unregulated wholly owned subsidiaries include:

• Catamount Resources Corporation (CRC), formed to hold investments in unregulated business opportunities. CRCs wholly owned subsidiary, SmartEnergy Water Heating Services, Inc., engages in the sale and rental of electric water heaters in Vermont and New Hampshire.

• C.V. Realty, Inc., a real estate company that owns, buys, sells and leases real and personal property and interests therein related to the utility business.

• Northern Water Resources, Inc., which holds a limited partnership interest in a Califomia wind farm. Though no book value remains for the wind farn1 assets, a deferred tax liability of $3,938 exists at December 31,2012.



Green Mountain Power Corporation (2) A Resubmission 04/15/2013 2012/Q4


(2) Summary of Significant Accounting Policies

(aj Principles ofConsolidation and Presentation

The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. All intercompany transactions with consolidated affiliates have been eliminated upon consolidation.

The Company accounts for its investments in Vennont Yankee Nuclear Power Corporation (VYNPC), Vermont Electric Power Company, Inc. (VELCO), Vennont Transco LLC (Transco), New England Hydro-Transmission Corporation, New England Hydro-Transmission Electric Company, Connecticut Yankee Atomic Power Company (Connecticut Yankee), Maine Yankee Atomic Power Company (Maine Yankee), Yankee Atomic Electric Company (Yankee Atomic), Catamount Resources Corporation and C.V, Realty, Inc. using the equity method of accounting. The Company's share of the net earnings or losses of these companies is included in the "other income (expenses)" section of the consolidated statements of income. See Note 4 for additional infonnation.

The Company's interests in jointly owned generating and transmission facilities are accounted for on a pro rata basis using the Company's ownership percentages and are recorded in the Company's consolidated balance sheets within utility plant in service. The Company's share of operating expenses for these facilities is included in the corresponding operating accounts on the consolidated statements of income.

The preparation of consolidated financial statements in conforn1ity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. The Company believes it has taken reasonable positions, where assumptions and estimates are used. In management" s opinion, the areas of the Company where the most significant judgment is exercised is in the valuation of unbilled and deferred regulatory revenue, pension and postretirement plan assumptions, contingency reserves, asset retirement obligations. regulatory assets and liabilities, the allowance for uncollectible accounts receivable, the valuation of utility plant, income tax uncertainties, deferred tax assets, and derivative financial instruments. Actual results could differ from those estimates.

The Company considers events or transactions that occur after the balance sheet date, but before the financial statements are available to be issued, to provide additional evidence relative to certain estimates or to identify matters that require additional disclosure.

(bj Regulatory Accounting

The Company's utility operations, including accounting records. rates, operations, and certain other practices, are subject to the regulatory authority of the FERC and the VPSB.

The Company accounts for certain transactions in accordance with pem1itted regulatory treatment. As such, regulators may pennit specific incurred costs, typically treated as expenses by unregulated entities, to be deferred and expensed in future periods when it is probable that such costs will be recovered in customer rates. Incurred costs are de felTed as regulatory assets when the Company concludes that it is probable that future revenues will be provided to pennit recovery of the previously incurred cost. The Company analyzes evidence supporting defelTa!, including provisions for recovery in regulatory orders, past regulatory precedent, other regulatory correspondence, and legal representations. A regulatory liability is recorded when amounts that have been recorded by the Company are likely to be refunded to customers through the rate-setting process. Regulatory assets and liabilities also include changes in fair value relative to derivative


Name of Respondent This Report is: Date of Report Year/Period of Report (1) ~ An Original (Mo, Da, Yr)

Green Mountain Power Corporation (2) A Resubmission 04/15/2013 2012104


financial instruments that cannot be considered as income or expense for rate-making purposes until the derivative financial instrument is settled, and the recognition of the other comprehensive income portion of the unfunded status of the Company's benefit plans. Notes 3, 12, and 13 provide further infonnation.

(c) Cash and Cash Equivalents

The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. Cash that is restricted for use under the tenns of VPSB regulatory orders amounted to $1,025 and $205 at December 31, 2012 and 2011, respectively, and is included in cash and cash equivalents in the consolidated financial statements. Included in cash are deposits, subject to the Company's exclusive control, provided as collateral under perfonnance assurance requirements for certain power supply contracts amounting to $3,811 and $3,305 at December 31, 2012 and 2011, respectively.

(d) Revenue Recognition, Accounts Receivable, and Deferred Regulatory Revenue

Operating revenues consist principally of retail sales of electricity at regulated rates. Revenue is recognized when electricity is delivered. The Company accrues utility revenues based on estimates of electric service rendered and not billed at the end of an accounting period. The unbilled revenues, which totaled $31,849 and $10,719 at December 31, 2012 and 2011, respectively, are included in trade accounts receivable in the accompanying consolidated balance sheets. Wholesale revenues represent sales of electricity to other utilities, typically for resale, and to ISO New England for amounts by which the Company's power supply resources exceed customer loads. Revenues in excess of allowed costs or earnings in excess of the earnings limitation are deferred, if and when applicable. See Note 3 for additional infonnation. Sales taxes collected from conunercia1 customers are accounted for as a liability until remitted to the government, and are excluded from operating revenues in the consolidated statements of income.

The Company estimates the amount of accounts receivable that will not be collected and records an allowance for estimated uncollectible amounts based upon historical experience. Account charge-offs against the allowance are considered after reviewing the facts of each individual account.

(e) Inventories

The Company's inventories of generation and truck fuel, materials, and supplies are recorded at lower of cost or market, with cost being detennined on a weighted average basis.

(I) Utility Plant and Long-Lived Assets

Utility plant is stated at cost. Major expenditures for plant additions are recorded at original cost and include all construction-related direct labor and materials, as well as indirect construction costs. The costs of renewals and improvements of significant property units are capitalized. The costs of maintenance, repairs, and replacements of minor property items are charged to maintenance expense. The costs of units of property removed from service, net of salvage value, are charged to accumulated depreciation.

Depreciation expense is recognized on a straight-line basis based on depreciation rates adopted as a rcsult of depreciation studies requested in prior years by the VPSB. The Company amortizes nearly all of its intangible and regulatory assets using the straight-line method based on the cost and amortization period approved by the VPSB for the intangible prope11y outstanding at the beginning of the year. Utility plant-related amortization expense totaled $1,780 and $1,388 for the years ended December 31,2012 and 2011, respectively.





(g) Impairment ofLong-Lived Assets

The Company performs an evaluation oflong-lived assets, including utility plant, regulatory assets subject to amortization, and other long-lived assets, for potential impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the carrying value of the long-lived asset is not recoverable based on undiscounted cash flows expected to be generated by the asset, an impaimlent charge is recognized to the extent that the carrying value exceeds its fair value, with fair value being determined based upon discounted cash flow models. Regulatory assets are charged to expense in the period in which they are no longer probable of future recovery. As of December 31,2012 and 2011, based upon management's analysis of the regulatory environment within which the Company currently operates, the Company does not believe that an impairment loss for long-lived assets should be recorded.

(h) Environmental Liabilities

The Company is subject to federal, state, and local regulations addressing air and water quality, hazardous and solid waste management and other environmental matters. Only those site investigation, characterization, and remediation costs currently known and determinable can be considered "probable and reasonably estimable". As costs become probable and reasonably estimable, reserves are adjusted as appropriate. As reserves are recorded, regulatory assets are recorde.d to the extent environmental expenditures will be recovered in future rates. Estimates are based on studies performed by third parties.

(i) Derivative Financial Instruments

All derivative instruments are recorded on the consolidated balance sheets at their fair value. Gains or losses resulting from changes in the values of those derivatives are accounted for pursuant to regulatory accounting orders issued by the VPSB as discussed below. The Company uses derivative instruments primarily to hedge the cash t10w effects of price fluctuations in its power supply costs. The Company is exposed to credit loss in the event of nonperformance by the other parties to the hedge agreements. The credit risk related to the hedge agreements is limited to the cost to the Company to replace the aforementioned hedge arrangements with like instruments. The Company anticipates that the counterparties will be able to fully satisfy their obligations under the hedge agreements. The Company monitors the credit standing of the counterparties.

On April II, 200 I, the VPSB issued an accounting order that requires the Company to defer recognition of any eamings or other comprehensive income effects relating to future periods caused by changes in the fair value of power supply arrangements that qualify as derivatives. Any changes in the fair value of the derivative financial instrument are recorded as a regulatory asset or liability, as appropriate. As these derivative contracts are settled, realized gains or losses are reclassified into earnings through electricity power supply costs.

OJ Purchased Power

The Company records the annual cost of power obtained under long-term executory contracts as operating expenses. The contracts do not convey to the Company the right to use the related property, plant, or equipment. The Company is not the sole taker of power from these sources except for the Moretown Landfi II contract. See Note 15 for additional infomlation.





(k) Income Taxes

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Investment tax credits are recorded as a liability and amortized as a tax expense benefit over the lives of the relevant assets. See Note II.

The Company recognizes the effect of uncertain income tax positions only if those positions are more likely than not of being sustained. When recognized, income tax positions are measured and recorded at the largest amount that is greater than 50% likely of being realized. Changes in recognition or measurement are reflected in the period in which the change in judgment occurs.

The Company files a consolidated tax return with its Parent, NNEEC. NNEEC pays all federal income taxes on behalf of the Company. The Company has a tax-sharing agreement with NNEEC to pay an amount equal to the tax that would be paid if the Company filed tax returns on a separate return basis.

(I) Pension and Other Postretirement Benefit Plans

The Company has defined benefit pension plans covering certain of its employees. The benefits are based on years of service and the employee's compensation during the five years before retirement. The Company also sponsors a defined benefit health care plan for retired employees and their dependents. The Company records annual amounts relating to its pension and postretirement plans based on calculations that incorporate various actuarial and other assumptions, including discount rates, mortality, assumed rates of return, compensation increases, turnover rates, and healthcare cost trend rates. The Company reviews its assumptions on an annual basis and makes modifications to the assumptions based on current rates and trends. The effect of modifications to those assumptions is recorded as a regulatory asset. The Company believes that the assumptions utilized in recording its obligations under its plans are reasonable based on its experience and market conditions.

The net periodic costs are recognized as employees render the services necessary to earn the postretirement benefits. Unamortized amounts that are expected to be recovered from rate payers in future years are recorded as a regulatory asset. See notes 3 and 12.

(m) Contingent Liabilities

Liabilities for loss contingencies arising from claims, assessments, litigation, fines and penalties, and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.

(n) Fair Value

The Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible. The Company detennines fair value based on assumptions that market participants would use in pricing an asset or liability in the principal or most advantageous market. When considering market participant assumptions in fair value measurements, the following fair value hierarchy distinguishes between


Year/Period of Report Date of Report Name of Respondent This Report is: (Mo, Da, Yr) (1) 2S. An Original

2012/0404/15/2013(2) A Resubmission Green Mountain Power Corporation


observable and unobservable inputs, which are categorized in one of the following levels:

• Level I Inputs: Unadjusted quoted prices in active markets for identical assets or liabilities accessible to the reporting entity at the measurement date.

• Level 2 Inputs: Other than quoted prices included in Level I inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the asset or liability.

• Level 3 Inputs: Unobservable inputs for the asset or liability used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at measurement date.

The level in the fair value hierarchy within which a fair value measurement in its entirety falls is based on the lowest level input that is available for that particular financial instrument.

The Company's financial instruments consist primarily of cash and cash equivalents, accounts receivable, prepaid expenses and other current assets, income taxes receivable (payable), accounts payable, accrued liabilities, short-tenn-debt, long-term debt, and pension assets. The carrying value of financial instruments approximates fair value, except for long-term debt and pension assets, due to the short-term nature of the instruments. See notes 12, 13 and 14.

(0) Government Grants

Government grants are recognized when there is reasonable assurance that the Company will comply with the conditions attached to the grant arrangement and the grant will be received. Government grants are recognized in the consolidated statements of income over the periods in which the related costs for which the government grant is intended to compensate are recognized. When govenm1ent grants are related to reimbursements of operating expenses, the grants are recognized as a reduction of the related expense in the consolidated statements of income. For govermnent grants related to reimbursements of capital expenditures, the grants are recognized as a reduction of the basis of the asset and recognized in the consolidated statements of income over the estimated useful life of the depreciable asset as reduced depreciation expense.

(3) Rate Regulation and Regulatory Assets and Liabilities

(a) Rate Regulation

In April 201 0, the VPSB approved an Altemative Regulation Plan for the Company (the Plan), effective October I, 2010 through September 30, 2013. During September 2012, the VPSB approved a 0.4% rate decrease efJective October 1,2012 through September 30, 2013, reflecting some of the merger savings agreed upon as part of gaining regulatory approval of the acquisition of former CVPS and merger with GMP. In September 2011, the VPSB approved 3.2% rate increase for the Company, etJective October I, 20 II through September 30, 2012, pursuant to the Plan. In September 20 10, the VPSB approved 3.1 % rate increase for the Company, effective October I, 20 I0 through September 30, 20 II, pursuant to the Plan. The Plan contains the principal elements described below:

• A power supply cost adjustment mechanism (PSA, or PCAM) under which the Company recovers or credits to customers, on a quarterly basis, 90% of energy costs that are $300 (per quarter) higher or lower than energy costs included in rates and the full amount of transmission and capacity costs higher or lower than included in rates.

• An allowed rate ofretum on equity (ROE) 01'9.93% in 2012 and 9.45% in 2013. The allowed ROE under the Plan adjusts annually, up or down, at the rate of one-half of the change in the average IO-year Treasury Note rate, over a specified 20-day trading period. The ROE is further adjusted based on the Company's operational cost performance benchmarked against 19 other utility companies, using a specified set of criteria based on historical





FERC financial reports. Under the Plan, the Company has the ability to achieve up to 50 basis points of additional incremental ROE if the Company's ranking is within the top four (first quintile) of performance, and could lose up to 50 basis points of ROE if the Company's ranking is within the bottom four (last quintile) of performance. For 2012, the allowed ROE included a 50 basis point adder pursuant to this benchmarking formula under the Plan.

• An miliual earnings sharing mechanism (ESAM) under which the Company has the opportunity to earn up to 75 basis points above its allowed ROE and to recover earning shortfalls in excess of 125 basis points below the allowed ROE. Under the Plan, certain exclusions, commonly made in setting rates, are applied to determine the Company's earnings and are expected to reduce the Company's ability to earn its allowed rate of return on equity for core utility operations.

• Base rates are adjusted annually, based on the Company's cost of service.

• The VPSB retains the authority to investigate the Company's rates at any time and to modify or terminate the Plan.

• Nonpower supply cost increases are generally capped at the amount currently allowed in rates, increased by inflation less a productivity factor of 1.00%. For 2012, a fornmla calculates the nonpower supply cost cap at $13,938. Nonpower supply costs under the Plan include return, taxes, depreciation on incremental plant investment, efJiciency spending and preliminary survey costs. The productivity factor is subject to an incentive reduction based on the Company's benchmarked performance. using the same criteria as ROE. The incentive adjustment ranges from 0.50% for excellent (first quintile) performance to - 0.50% for poor (last quintile) performance. Under the Plan, GMP's benchmarking results applicable to 2011 ranked GMP 4th of the 20 utility companies in the benchmarking group, resulting in first quintile performance. Accordingly. GMP's incentive adjustment under the Plan is 0.50% for 2012.

The Company may recover extraordinary unforeseeable costs (exogenous changes) in excess of $600 per year.

(b) Acquisition and Changes to the Plan

The acquisition of former CVPS by NNEEC included the planned merger of former CVPS into GMP. to create a single operating utility subsidiary of NNEEC, effective October 1,2012. As part of the regulatory approval process for the acquisition, the Company and fanner CVPS proposed to amend GMP's Alternative Regulation Plan to extend the duration of the Plan through September 30, 2014 and to file a single base rate adjustment under the Plan for 2013 based on a combined cost of service for both GMP and forn1er CVPS. The VPSB approved the proposed amendments to the Plan.

On September 21,2012. the VPSB approved a 0.40% rate decrease effective October I, 2012 for the Company and former CVPS, pursuant to the Plan.

The Plan' s elements. as amended to ret1ect the acquisition of former CVPS, remain essentially the same. The material tenns of certain modifications to ret1ect the acquisition, effective October I, 2012, are described below:

• The Plan is extended for one year. through September 30. 2014.

• The power supply cost mechanism (PSA) under which the combined companies recover or credit to customers certain energy costs is modified to include 90% of energy costs that are $615 (per quarter) higher or lower than energy costs included in rates and the full amount of transmission and capacity cots higher or lower than included in rates.

• The allowed rate of return for 2013 is 8.84%.


Name of Respondent This Report is: Date of Report Year/Period of Report (1) .6 An Original (Mo, Da, Yr)



• The Plan implements a synergies-savings plan approved by the VPSB as part of the CVPS merger, which includes providing customers with $2,SOO in merger savings in 2013 and fixes the combined companies' operations and maintenance expenses included in rates (the O&M Platform) for the purpose of measuring synergy savings over a 1O-year period. O&M Platfonn expenses will be recovered in rates through 2020, increasing each rate year by the rate of inflation.

• The Company's opportunity to recover costs of "exogenous events" under the Plan is limited to such amounts in excess of $1 ,200 per year.

As a condition of the VPSB's approval of the former CVPS acquisition, the Company has agreed to a plan for sharing merger synergies with the following material elements:

• The Company is obligated to provide customers at least $144 million (nominal dollars) in customer savings over 10 years: 2013 through 2022. Savings will be measured by comparing actual operating and maintenance costs (O&M costs) with the O&M Platform included in rates.

• In years 2013 through 20 IS, customer savings are fixed in the amounts of $2.S million, $S million and $8 million, respectively.

• In years 2016 through 2020, customers and the Company share synergy savings on a SO/SO basis.

• In years 2021 through 2022, all synergy savings will be credited to customers.

• If total measured savings to customers are less than $144 million after 2022, the Company shall provide the difference to retail customers through a bill credit.

(c) Regulatory Assets and Liabilities

Regulatory assets and Iiabilities at December 31, 2012 and 2011 are reported on page 232 - Other Regulatory Assets, page 233 - Miscellaneous Deferred Debits, page 269 ~ Other Deferred Credits and page 278 - Other Regulatory Liabilities.

Regulatory assets and liabilities do not include the recognition of tax effects, which generally would be approximately 40.S%. Significant items are described below:

Pine Street Barge Canal Costs

The Company has recorded a regulatory asset of $14,387 to reflect unrecovered past and future Pine Street Barge Canal costs, and will amortize the full amount of incurred costs over 20 years without a retum. The past unrecovered costs regulatory asset of $8,798 is included in rates. The estimated future unrecovered cost liability of $S,S89 has a matching regulatory asset that is not yet included in rates. The amortization is expected to be recovered in future rates. See note 16.

Derivative Financial Instrument Regulatory Assets

The derivative financial instrument regulatory assets represent the fair value of certain power supply derivative liabilities that are expected to be recognized in future rates as the derivative contracts are settled. Settlement gains or losses related to the derivative contracts are retumed to or fully recovered from customers in the rates the Company charges and are discussed in detail in note 13.

Unfunded Pension and Other Postretirement Benefits Regulatory Assets

The pension and other postretirement benefit regulatory assets reflected above represent the unrecognized pension costs and other postretirement benefit costs that would nonnally be recorded as a component of other comprehensive income.





Since these amounts represent costs that are expected to be recovered in future rates, they are recorded as regulatory assets. Also included are other employee benefit costs that have been deferred for regulatory purposes. For the years ended December 31,2012 and 2011, the balances were $87,450 and $38,631, respectively.

Efficiency Fund

One of the conditions associated with VPSB approval of the 2007 acquisition by NNEEC (2007 acquisition) was that the Company agreed to create an Efficiency Fund (EF) and an income-based discount program that would be capitalized with an amount of $8,000, adjusted for inflation since 2001. As of December 31, 2012 and 20 II, the total regulatory assets recorded were $6,894 and $6,610, respectively. The EF permits customers to seek reimbursement for approved projects meeting certain energy conservation requirements. The income-based discount program was available for qualified customers to help pay for utility services in 2007 through 2009. After amounts are expended by the Company, they become eligible to be recovered in rates. Management believes that expended amounts are probable of recovery.

ESAM Deferred Costs

The ESAM deferred costs are related to amounts the Company is allowed to defer and collect under the exogenous effects provision of the Plan, if the unexpected impact is in excess of $1 ,200 per year. Exogenous effects include changes in GAAP, tax laws, FERC or ISO-NE rules and major unplanned operation, maintenance costs, such as those due to major storms and other factors including loss of load not due to variations in heating and cooling temperatures. In 2011, the fonner CVPS deferred $7,518 of costs related to Tropical StOnll Irene and legislative and tax law changes. The VPSB approved the Company's recovery of these costs commencing on July 1,2012.

Other Regulatory Assets

Othcr regulatory assets consist of regulatory deferrals of right-of-way maintenance, other employee benefits, transmission interconnection charges, and various other projects and deferrals that the Company expects to be recovered in future rates.

Accumulated Nonlegal Costs of Removal

Accumulated nonlegal costs of removal represent asset retirement costs previously recovered from ratepayers for other-than-Iegal obligations. The Company reflects these amounts as a regulatory liability. The Company expects, over time, to recover or settle through future revenues any over- or under-collected net costs of removal. For the years ended December 31, 2012 and 20 II, the balances were $36,042 and $24,244, respectively.

Deferred Regulatory Revenues

Under the Plan, 90% of extraordinary power costs in excess of $615 per quarter are eligible to be recovered through the Plan's PSA. For the years ended December 31, 2012 and 20 11, the Company deferred revenues of $6,920 and $2,687, respectively, through the PSA. Deferred amounts are recovered from or credited to customers on a quarterly basis.


Other regulatory liabilities consist of amounts received from VYNPC that are subject to a regulatory deferral order and regulatory tax liabilities.

Community Energy & Efficiency Fund (CEED Fund)

One or the conditions associated with the VPSB approval of the acquisition of former CVPS by NNEEC was that fonner CVPS create the CEED Fund. The CEED Fund will be capitalized with an amount equal to approximately $21,000 (Required Investment) as of the date the VPSB approved the acquisition, June 15,2012. Interest will accrue at





the rate of inf1ation on uninvested amounts until the Required Investment has been made. The Required Investment will be required to provide net customer benefits to customers in the CVPS legacy territory equal to or greater than 1.2 times the Required Investment or approximately $25,000 (Required Benefit).

Through the CEED Fund, the Company was required to invest $6,000 in Vennont's weatherization program before December I, 2012, at least an additional $4,000 before December I, 2013, and at least $2,000 in thennal efficiency improvements by December I, 2013. The remaining Required Investment must be made by June 2019. If at the end of this period, the Company has not provided the Required Benefit, the Company is required to file a plan for approval by the VPSB specifying how the remaining Required Benefit will be delivered. Any shortfall would be provided to fonner CVPS customers on a unifonn percentage basis in the fonn of a bill refund.

The Company"s investments into the CEED fund will be included in rate base and recovered through rates over a IO-year period. If additional investments in excess of the Required Investment are needed to deliver the Required Benefit such additional investments will not be recoverable through rates. In November 2012, the Company invested approximately $6,000 in a weatherization fund and a regulatory asset was recorded.

Nuclear Plant Dismantling Costs

The nuclear plant dismantling costs regulatory assets represent estimated decommissioning costs that are being collected through existing retail rate tariffs.

Income Taxes

A regulatory asset or liability is established if it is probable that a future increase or decrease in income taxes payable will be recovered fro111 or returned to customers through future rates. Income tax regulatory assets and liabilities have been established for the equity component of the allowance for funds used during construction, federal and state changes in enacted tax rates, and for federal investment tax credits. These income tax regulatory assets and liabilities are combined into a net income tax regulatory asset.

Asset Retirement Obligations - Millstone Unit #3 - Regulatory Liabilities

The Company has legal retirement obligations for deconm1issioning related to its joint-owned nuclear plant, Millstone Unit #3, and has an external trust fund dedicated to funding its share of future costs. This regulatory liability represents the exct:ss of the decommissioning trust fund asset balance over the asset retirement obligation for decommissioning. The plant is currently operating and the ultimate decommissioning cost is an estimate at this time. The liability balance will be decreased when decommissioning of the asset is underway, or when the forecasted decommissioning obligation exceeds the trust fund asset, resulting in a regulatory asset.


Name of Respondent


This Report is: (1) 6 An Original (2) A Resubmission


04/15/2013


2012/Q4


(4) Investments in Associated Companies

Investments in associated companies at December 31, 2012 and 2011 are composed of the following:

Ownership Interest Investment in Equity

December 31 December 31 2012 2011 2012 2011

VELCO 38.8% 29.2% $ 10,068 $ 7,597 Transco LLC 64.9% 28.4% 333,092 128,496

VYNPC- Common 100.0% 33.6% 4,429 1,620 New England Hydro Transmission - Common 3.2% 3.2% 124 246 New England Hydro Transmission Electric - Common 3.2% 3.2% 445 445 Connecticut Yankee Atomic Power Company 2.0% 2.0% 44 Maine Yankee Atomic Power Company 2.0% 2.0% 44 Yankee Atomic Electric Company 3.5% 3.5% 55

Total investment in associated companies $ 338,233 $ 138,404

Vermont Electric Power Company and Vermont Transco LLC

Vermont Electric Power Company, Inc. (VELCO) and Vermont Transco LLC (Transco) own and operate the transmission system in Vermont over which bulk power is delivered to all electric utilities in the state. Transco owns the transmission assets comprising the system. Transco was formed by VELCO and VELCO's owners in 2006 and VELCO was appointed as the manager of Transco. On June 30,2006, VELCO contributed substantially all of its operating assets to Transco, in exchange for 2.4 million Class A Membership Units and Transco's assumption of VELCO's debt. Transco is govemed by an Amended and Restated Operating Agreement (the Transco Operating Agreement) by and among VELCO, the Company, Central Vermont Public Service Corporation (CVPS) and most of Vennon!' s other electric utilities. VELCO operates the Transco system under a Management Services Agreement with Transco.

Transco is also govemed by certain Amended and Restated Three-Party Agreements, assigned to Transco from VELCO, by and among the Company, VELCO and Transco, and VELCO remains subject to an Amended Four-Party Agreement among the Company, and VELCO. VELCO cUlTently has an 9.2% ownership interest in Transco. The remaining ownership interest in Transco is held by other VemlOnt-based utilities, one of which has a larger ownership interest.

The Company most recently made capital investments in Transco of $34,272 in December 2012 to support various transmission projects. The Company receives its CUlTent rate ofretum on the investment in Transco, since results are accounted for as a regulated business for Vennont rate-setting purposes. The Company's capital contributions to Transco are based on, and consistent with, the original equity commitments to VELCO. The Company and other taxable Transco owners also receive additional eamings and distributions to compensate for differences in taxability with other nontaxable Transco owning entities.

!FERC FORM NO.1 (ED. 12-88) Page 123.11




Summarized unaudited financial infonnation for Transco follows:

Year ended December 31, 2012 2011

Net income $ 54,657 $ 64,424

Company's equity in net income 22,182 19,124

Total assets $ 942,966 $ 851,205 Liabilities and long-tenn debt 466,539 416,640

Net assets $ 476,427 $ 434,565

Company's equity in net assets $ 333,092 $ 128,496

Transco provides transmission services to the Company and others pursuant to a transmission tariff known as the 1991 Transmission Agreement (the VTA), to which all Vennont electric utilities and the State ofVennont are parties. Under the VTA, the Company and all other Vennont utilities pay their pro rata share of Transco' s total costs, including interest on debt and a fixed return on equity, less revenues collected by Transco under the ISO-New England Open Access Transmission Tariff and other agreements.

Transco provided transmission services to the Company (reflected as transmission expenses in the accompanying consolidated statements of income) amounting to $10,686 and $10,263 for the years ended December 31, 2012 and 20 II, respectively.

In addition to its equity ownership interest in Transco, the Company also owns 38.8% ofVELCO's common stock and 80.1 % of its preferred stock. The Company's ownership interest in VELCO entitles it to approximately 39% of the dividends distributed by VELCO. The Company has recorded its equity in earnings on this basis and is also required to pay for its share ofVELCO's and Transco's operating costs, including debt service costs.

Summarized unaudited financial infonnation for VELCO is as follows:


Net income $ 3,494 $ 2,514

Company's equity in net income 897 907 Total assets $ 81,293 $ 85,24 I Liabilities and long-term debt 56,116 59,704

Net assets $ 25,177 $ 25,537


Amounts due to VELCO, net $ 9,330 $ 3,880





Vermont Yankee Nuclear Power Corporation

The Company's ownership share of VYNPC is 100%. The Company had a 10ng-tenn power purchase contract with VYNPC which expired March 2012. Prior to March 2012, the Company received approximately 17% of the total production of the ENVY nuclear power plant (Vennont Yankee) through a purchased power agreement (PPA) between VYNPC and ENVY. See Note 15 for infonnation regarding the PPA.

Summarized unaudited financial information for VYNPC is as follows:


Net income $ 340 $ 473

Company's equity in net income 165 159

Total assets $ 154,813 $ 171,435

Liabilities and 10ng-teml debt 150,384 166,648

Net Assets $ 4,429 $ 4,787


Amounts due from VYNPC $ 95 $ 3,552

Power purchased from VYNPC $ 8,695 $ 35,833

Other Investments i/1 Associated Companies

GMP's share of income from other associated companies not discussed above totaled $142 and $148 during the years ended December 31, 2012 and 2011, respectively.


Name of Respondent




04/15/2013


2012104


(5) Utility Plant

The major classes of utility plant are as follows as of December 31, 2012 and 2011:

In Thousands Property Summary Approximate

average depreciable December 31 life in years 2012 2011

Property, plant and equipment: Intangible, FERC licenses and software 50-30 $ 48,581 $ 9,851 Generation 25-100 417,860 110,316 Transmission 42-60 149,870 50,794 Transmission capital lease asset 30 4,232 2, lIS Distribution 16-45 630,842 256,304 General 10-25 23,140 10,1 07 Transponation 12 17,205 11,399 Buildings 20-60 36,789 14,843 Office equipment 5-15 12,164 6,355 Nuclear fuel, net 3-10 3,214

Total plant in service 1,343,897 472,084 Accumulated depreciation and amortization ___(~5_17,692) --'-(l=-c9-=2=,6=66)

Net plant in service 826,205 279.418 Construction work in progress 109,314 81,325

Total utility plant, net $ 935,519 $ 360,743

Smart Grid Department ofEnergy Grant

In April 2010, the Company and most other Vennont electric utilities received a grant of$69,000 from the U.S. Department of Energy (DOE), as part of the U.S. federal government stimulation measures, to finance and implement a statewide smart electricity distribution system (Smart Grid). The Governor, the Vennont Congressional delegation and the Vennont regulatory authorities supported the grant application. The grant requires a matching investment by the Vermont utility recipients and completion of grant related investments over a three-year period ending April 2013. The Company's share in the grant is $50,000, which equals the $50,000 investment by the Company, for a total Smart Grid investment of$100,000. The project consists of, among other activities, replacing GMP's current customer infonnation system, installing technology to improve distribution system automation, purchasing and installing 272,500 advanced technology meters for customers, and participating in dynamic rates pilots with other electric utilities in Vermont. The Company and other Vennont electric utilities are implementing this major project.

GMP is nearing completion of this major project. As of March 31, 2013, $37.6 million has been received from the DOE under the grant.





(6) Revolving credit

In connection with the Merger, effective October 1, 2012, the revolving credit facilities in place for GMP and CVPS were terminated. The amount outstanding and accrued interest payable on the individual credit facilities were paid off through the execution of a new revolving credit facility (the revolver) for the merged company. The new facility with Keybank National Association consists of a $70,000 revolving line of credit that expires on September 30, 2016. In addition to the $70,000 revolving line of credit, GMP has the ability to request an increase in the credit agreement up to $15,000 provided there exists no event of default. The revolver includes a letter of credit for $6,100 for the decommissioning liability at the Company's KCW facility.

The purpose of the facility is to provide liquidity for general corporate purposes, in the form of funds borrowed and letters of credit. The revolver is unsecured, and allows the Company to choose a rate based on a thirty (30) day LIBOR, Overnight LIBOR or the Alternative Base Rate plus the Applicable Rate (as defined in the revolver), with a margin based upon our unsecured credit ratings ofBaa2 and BBB for Moody's and Standard and Poor's, respectively. The Overnight LlBOR rate at December 31, 2012 was 1.6375% and the 30 day LIBOR was 1.35%. The Company had $46,411 and $10,000 in cash borrowings, and $6,100 and $0 in letters of credit outstanding under its credit facilities at December 31, 2012 and 2011, respectively. The revolver balance has been classified as long tenn debt at December 31,2012 and 2011, as each facility in place had a maturity date in 2016.

The revolver includes certain restrictive financial covenants, and management believes that the Company was in compliance with these covenants at December 31, 2012.


Name of Respondent This Report is: Date of Report Year/Period of Report (1 ) ~ An Original (Mo, Da, Yr)



(7) Long-Term Debt

Substantially all of the property and franchises of the Company are subject to the lien of the indentures under which the First Mortgage Bonds have been issued. The First Mortgage Bonds are callable at the Company's option at any time upon payment of a make-whole premium. The Company's long-ternl debt consists of the following:

December 31 LONG-TERM DEBT 2012 2011 First mortgage bonds Interest Rate Maturity Annual Sinking Fund

6.04% Dec. 1, 2017 $6,000 begins Dec. 2011 $ 30,000 $ 36,000 6.70% Nov. 1,2018 15,000 15,000 5.98% Apr. 16, 2019 15,000 15,000 5.72% June 1,2019 55,000 9.64% Sept. 1,2020 9,000 9,000 5.0% Dec. 15,2020 30,000

8.65% Mar. 1,2022 $500 begins Mar. 2012 12,500 13,000 6.9% Dec. 1,2023 17,500 6.83% May 1,2028 60,000 8.91% Dec. 1,2031 15,000

2.6% to 5.0% Apr. I, 2035 $655 repayment begins 2012 23,490 24,145 6.00% Apr. I, 2035 5,000 5,000 6.53% Aug. I, 2036 30,000 30,000 6.17% Dec. 1,2037 16,000 16,000 4.56% Nov. 18, 2041 50,000 50,000 4.61% Nov. 18,2041 25,000 5.89% June 15,2041 40,000 3.99% Dec. 5, 2042 85,000

Total first mortgage bonds outstanding 533,490 213,145

Less current maturities (due within one year) 7,155 7,155

Total tirst mortgage bonds outstanding, less current maturities

Revolving line of credit 46,411 19,000

Totallong-tenll debt outstanding $ 572,746 $ 224,990 weighted average interest rate on first mortgage bonds 5.71% 5.95% weighted average interest rate on revolving line of credit 1.35% 1.42%

The current senior secured debt credit ratings for the Company's first mortgage bonds are A3 by Moody's and BBB by S&P. The weighted average rate on first mortgage bonds outstanding was 5.71 % and 5.95% at December 31, 2012 and 20 II, respectively. Amortization of capitalized bond issue expenses totaled $132 and $29 for the years ended December 31, 2012 and 2011, respectively.

In November 2011, GMP issued, by way of private placement, $50,000 in Series A First Mortgage Bonds, and also issued

!FERC FORM NO.1 (ED. 12-88) Page 123.16




an additional $25,000 in Series B First Mortgage Bonds in April 2012. The proceeds from the issuance of these bonds were used to finance a portion of GMP' s utility plant investment in the Kingdom Community Wind Project. The Series A and Series B First Mortgage Bonds will bear interest at rates of 4.56% and 4.61 %, respectively, and will mature in November 2041.

The Company issued two first mortgage bonds in March 2010 for $24,765 and $5,000 (VEDA bonds). These were Recovery Zone Facility Bonds issued by the Vermont Economic Development Authority (VEDA) and they mature in 2035. The $5,000 bond (the 2010 B bond) has a fixed interest rate of6.0%. The $24,765 bond (the 2010 A bond) is tax exempt, has a variable interest rate and annual scheduled principal reductions. The VEDA bonds are not callable at the Company's option.

In connection with the Merger, effective October 1, 2012, GMP acquired all outstanding CVPS first mortgage bonds, in the amount of $217,500, by exchanging them for newly issued Exchange Bonds issued under the GMP First Mortgage Bond Indenture. The Exchange Bonds have the same principal amount, maturities, interest rate and redemption terms as the CVPS bonds. The GMP First Mortgage Bond Indenture was modified to include a maintenance covenant that requires GMP's long term debt not to exceed 65% of total capitalization.

In December 2012, GMP issued additional bonds of $85,000, with a fixed interest rate of 3.99% and they mature in 2042.

The financial agreements with the Company's debtors contain various restrictive covenants; management believes that the Company was in compliance with all restrictive covenants and limitations as of December 31, 2012.

(8) Obligations under Transmission Interconnection Support Agreement

Agreements executed in 1985 among the GMP, VELCO, and other NEPOOL members and Hydro Quebec provided for the construction of the second phase (Phase II) of the interconnection between the New England electric systems and that of Hydro Quebec. Phase II provides 2,000 megawatts of capacity for transmission of Hydro Quebec power to Sandy Pond, Massachusetts. Construction of Phase II commenced in 1988 and was completed in late 1990. Total construction costs for Phase II were approximately $487,000. The New England participants, including the Company, have contracted to pay monthly their proportionate share of the total cost of constructing, owning, and operating the Phase II facilities, including capital costs.

The Company has an 8.3% Phase II percentage interest. As a supporting participant, the Company must make support payments under 30-year agreements. At December 31, 2012 and 2011, the present value of the Company's obligation under the support agreements was $3,322 and $2,115, respectively. The obligation expires in 2019.

The Phase II portion of the project is owned by New England Hydro-Transmission Electric Company and New England Hydro-Transmission Corporation, subsidiaries of National Grid USA. Certain of the Phase II participating utilities, including the Company, own equity interests in such companies. The Company holds approximately 3.2% of the equity of the corporations owning the Phase II facilities and accounts for its ownership under the equity method of accounting.

(9) Asset Retirement Obligation The Company continually reviews the regulations, laws, (md contractual obligations to which it is a p31iy to identify situations where there are legal obligations to perform asset retirement activities. The Company has identified certain easements that may obligate it to perfom1 asset retirement activities upon termination of the related agreements. The present value of such obligation identified and recorded was $3,599 and $800 at December 31, 2012 and 2011, respectively.





(10) Retained Earnings

Appropriated Retained Earnings

The Company had appropriated retained earnings of $1,434 and $649 at December 31,2012 and 2011, respectively, relating to regulatory requirements arising from ownership of hydroelectric facilities.

Dividend Restrictions

Cel1ain restrictions on the payment of cash dividends on common stock are contained in the Company's indentures relating to long-term debt and in the Amended and Restated Articles of Incorporation. Under the most restrictive of such provisions, $42,894 and $34,461 of retained earnings were free of restrictions at December 31, 2012 and 20 11, respectively.

Cel1ain restrictions on the payment of cash dividends on common stock exist as a result of conditions of the VPSB' s approval of the 2007 acquisition of the Company and the approval of the merger between the Company and Central Vennont Public Service Corporation. The Company is required to notify the VPSB of any changes that result in a 3% or greater change in capital structure from the structure approved in the Company's last rate proceeding. The Company is also required to provide notice within 10 days after declaring each regular common stock cash dividend and to provide 30-day advance notice before declaring any special cash dividend.

During the years ended December 31, 2012 and 2011, the only required notices were related to regular common stock cash dividends.

(11) Income Taxes

Measurements and valuations associated with accounting for income taxes occur only at the Company's fiscal year end of September 30. As a result, only the September 30 fiscal year amounts are presented. Also see former CVPS FERC Fonn 1, for the period ended December 31, 2012, for additional information.

The provision for income taxes for the years ended September 30, 2012 and 2011 is surmnarized as follows:

Year ended September 30 2012 2011

Current federal income taxes $ (928) 117 Current state income taxes .. 1,163 .. 6

Total current income taxes 235 123

Deferred federal income taxes 11,384 10,016 Deferred state income taxes 2,074 2,412

Total deferred income taxes 13,458 12,428

Investment tax credits-net (240) (233)

Income tax expense $ 13,453 12,318

The significant items that reconcile between income taxes computed by applying the U.S. federal statutory rate and the repol1ed income tax expense (benefit), for the rep0I1ing period, include the dividends received deduction,





amortization of investment tax credits, energy credits and production deductions, corporate owned life insurance, nondeductible transaction costs and state income tax.

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at September 30, 2012 and 2011 are presented below:

September 30 2012 2011

Deferred tax assets: Customer advances for construction $ 5,214 4,784 Net operating losses and tax credits 197 1.483 Self insurance and other reserves 212 257 Deferred regulatory revenues 644 218 Accumulated costs of removal 9,827 9,494 Deferred compensation and other benefit plans 16,767 14,976 Other liabilities and deferred credits 4,270 4,842 Derivative financial instruments 1,818 3,646

Total deferred tax assets 38,949$ ===~===:,=

39,700

Deferred tax liabilities: Accelerated tax depreciation on property $ 74,265 65,573 Regulatory assets pension and other postretirement

benefits 18,883 16,994 Deferred purchased power costs 77 311 Pine Street Barge Canal 3,630 3,749 Investment in associated companies 26,554 22,778 Other deferred charges and other assets 384 o Nonutility subsidiary investment in wind farm 4,115 3,798 Derivative financial instrument regulatory assets 1,818 3,646

Tota I deferred ta x lia bilities 129,726$ ----~----'--

116,849

Net deferred income ta x liability $ 90,776 77,149 Amount inc luded in other current assets or (current lia bilities) 346 (350) Amount included in other liabilities and deferred credits 91,122 76,799

The change in the net deferred tax liability arises from the defelTed income tax expense included in the consolidated financial statements for the periods presented, primarily affected by accelerated tax depreciation, tax versus book differences in investment in affiliates, and changes in regulatory assets and liabilities.

The Company records the benefits of investment tax credits through the amortization, as approved by the VPSB, of the unamortized investment tax credits, which are initially recorded as a liability. The remaining balance of unamortized investment credits shown separately on the consolidated balance sheets at September 30, 2012 and 20 II were $2,215 and $2,308. respectively.

A valuation allowance is required against de1crred tax assets if. based on the weight of available evidence, it is more likely than not that some or all of the deferred tax assets will not be realized. Although realization is not assured. at September 30. 2012, the Company believes that the results of future operations will provide sufficient taxable income to realize deferred tax assets. At September 30, 2012 and 20 11, no valuation allowance was recorded. This valuation





allowance is different than reserves described below for uncertain tax return positions.

During 2012, the Company adopted certain safe harbor rules and eliminated reserves for an uncertain tax position for benefits claimed on its tax return for the year ended September 30, 2009 in relation to its change in accounting method for incidental repairs and maintenance costs adopted for that year. A net expense of $247 was recognized for state net operating deductions lost as a result of the reserve elimination. While the Company believes it has adequately provided for all tax positions, amounts asserted by taxing authorities could be greater than the Company's accrued position. Accordingly, additional provisions on federal and state tax-related matters could be recorded in the future as revised estimates are made or the underlying matters are settled or otherwise resolved. During the year ended September 30, 2012, the Company recorded a benefit for previously accrued interest related to the uncertain tax positions of approximately $251. As of September 30, 2012 and 2011, the Company had $0 and $251, respectively, of interest accrued related to unrecognized tax benefits. Changes in unrecognized tax benefits for the years ended September 30, 2012 and 2011 were as follows:


Unrecognized tax benefits at beginning of period $ 3,654 3,654 Other decreases .. (3,654) .. o

Unrecognized tax benefits September 30 $ ---'0_ 3,654

At September 30,2012, there are no amounts of unrecognized tax benefits that, if recognized, would impact the effective tax rate.

The Company is subject to income taxes in the United States. but no foreign jurisdictions.

Internal Revenue Service (IRS) and State ofVennont examinations of the Company's tax returns have been completed for years through 2006. A State of Vennont audit is currently in progress for the years 2008 through 2010. State tax liabilities have been adjusted to account for changes in federal taxable income for years 2004 through 2006, since those years were ultimately resolved with the IRS. Open tax years for federal tax returns are 2009 and forward, open tax years for Vermont are 2008 and forward.

(12) Employee Benefit Plans

Actuarial measurements and valuations associated with accounting for employee benefit plans occur only at the Company's fiscal year end of September 30. As a result, only the September 30 balances are presented, unless otherwise indicated. Also see fonner CVPS FERC Fonn 1, for the period ended December 31,2012, for additional infonnation.

(aj Defined Benefit Pension Plan and Other Postretirement Benefit Plan

The Company has a qualified noncontributory defined benefit pension plan (the Pension Plan) covering substantially all of its employees. New employees are not eligible to participate in the defined benefit plans. The retirement benefits are based on the employees' level of compensation and length of service. Under the terms of the Pension Plan, employees are vested after completing five years of service, and can receive a pcnsion benefit wben tbey are at least age 55 with a minimum of 10 years of service or when their combined years of service and age total 80 or 85 for GMP or fanner CVPS plans, respectively. Nonnal retirement age is 65. The Company makes annual contributions to the plans up to the maximum amount that can be deducted for income tax purposes.

The Company also provides certain healthcare benefits for retired employees and their dependents. Employees become





eligible for these benefits if they reach retirement age while working for the Company. GMP employees hired after December 31,2007 are not eligible to receive post-retirement health care benefits. The Company accrues the cost of these benefits during the service life of covered employees.

Postretirement healthcare benefits are recovered in rates. In order to maximize the tax deductible contributions that are allowed under IRS regulations, GMP amended its postretirement healthcare plan to establish a 401 (h) sub account and separate Voluntary Employee Benefit Account (VEBA) trusts for its union and nonunion employees. The VEBA plan assets consist primarily of cash equivalent funds, fixed income securities and equity securities.

At September 30, 2012 and 2011, the unfunded pension and other postretirement benefit obligations totaled $32,713 and $28,368, respectively. The Company recorded an offsetting regulatory asset for the total unfunded pension and other postretirement benefit obligation.

The following provides a summary of activity affecting the pension and postretirement plans' benefit obligations and assets for the years ended September 30, 2012 and 2011 :

Year ended September 30,2012

Pension plan benefits

Other pos tretire me nt

benefits

Fair value of plan assets Projected benefit obligation

$ 47,808 70,803

16,350 26,068

Funded status $ ===(=2==2,==99==5==) (9,718)

Accumula ted benefit obliga tion Net actuarial loss recognized in regulatory assets

$ 66,338 32.043

26,068 9,792

Year ended September 30,2011 Other

Pe ns io n plan pos tretireme nt be nefits benefits

Fair va lue of plan assets $ 40,258 13,540 Projected benefit obligation 58,595 23,571

Funded status (10,031)$ ====(1=8~,3==37==:)

Accumulated benefit obligation $ 58,595 23,571 Net actuarial loss recognized in regulatory assets 26,484 9,952

The Company pays for certain post retirement health benefits, and those payments are included in the determination of the projected benefit obligation.





Net periodic pension expense and other postretirement benefit costs, employer and participant contributions, and benefits paid by plan are:

Year ended Year ended September 30, 2012 September 30,2011

Other Other Pension plan postretirement Pension plan postretiremenl

benefits benefits be n efi ts ben efi ts

Net periodic benefit cost $ 3,461 902 2,943 1,090

Emp 10 yer co ntrib utio n s $ 4,360 1,322 3,893 1,286 Paliicipant contributions 266 231 Benefits paid 2,323 1,453 2,221 1,409

Assumptions used to determine the Company's pension and postretirement benefit obligations were:

Year ended September 30 Pension plan Other postretirement

benefits benefits 2012 2011 2012 2011

Weighted average assumptions

as of year end: Discount rate Rate ofcornpensation

Increase Medical inflation

4.05'%

3.25

4.90'%

3.25

4.05'%

7.50

4.90'%

8.20

/FERC FORM NO.1 (ED. 12-88) Page 123.22




Assumptions used to detennine the Company's pension and postretirement benefit costs were:

Year ended September 30 Pension plan Other postretirement

benefits benefits 2012 2011 2012 2011

Weighted average assumptions

as of year end: Discount rate 4.90% Expected return on plan

as sets 7.50 Rate ofcompensation

Increase 3.25

Current year trend Ultimate year trend Year of ultimate trend

For measurement purposes, a 7.5% and 8.2% annual rate of increase in the per capita cost of covered medical benefits was assumed for 2012 and 2011. This rate of increase gradually declines to 4.3% in 2069. The medical trend rate assumption has a significant effect on the amounts reported. For example, increasing the assumed healthcare cost trend rMe by one percentage point for all future years would increase the total of the service and interest cost components of net periodic postretirement cost for the years ended September 30, 2012 and 20 II by $121 and $154, or 9.0% and 10.2%, respectively. Decreasing the trend rate by one percentage point for all future years would decrease the total of the service and interest cost components of net periodic postretirement cost for the years ended September 30, 2012 and 20 I I by $99 and $126 or 7.4% and 8.3%, respectively. Increasing the assumed healthcare cost trend rate by one percentage point for all future years would increase the postretirement benefit obligation for the years ended September 30, 20 I2 and 2011 by $2,613 and $2,264, or 10.0% and 9.6%, respectively. Decreasing the trend rate by one percentage point for all future years would decrease the postretirement benefit obligation for the years ended September 30,20 I2 and 20 II by $2,135 and $1,838 or 8.2% and 7.8%, respectively.

The Company's defined benefit plan investment policy seeks to achieve sufficient growth to enable the defined benefit plans to meet their future obligations and to maintain certain funded ratios and minimize near-tenn cost volatility. Current guidelines specify generally that 60% of combined plan assets be invested in equity securities, 20% of combined plan assets be invested in debt securities, and the remainder be invested in alternative investments.

The Company expects an annual Iong-tenn return for the defined benefit plan asset portfolios of 7.5% at September 30, 2012, based on a representative target asset allocation described above. In formulating this assumed rate of return, the Company considered historical returns by asset category and expectations for future returns by asset category based, in part, on expected capital market performance over the next 10 years.





Asset categories and weighted average allocation percentages are provided in the following table.

Weighted average asset allocation

asset category Pension p

2013 Target lan assets

2012

Other postretirement benefit assets

2013 Target 2012

Equity securities

Debt securities

57% 20

66% 23

57% 20

57% 22

Other 23 "

11 23

" 21

Total 100% 100% 100% 100%

(b) Pension and Post Retirement Benefit Plans Asset Fair Values

The fair values of the pension and other postretirement benefit plan investments are presented for the periods below:

Pension plan assets fair value measurements at September 30,2012

Quoted prices in active markets Significant Significant

for identical observable unobservable as sets inputs in pu ts

Total (Levell) (Level 2) (Level 3)

Asset category: Cash $ 1,081 1,081 Limited Partnerships 8,742 1,426 7,316 Exchange Traded Funds 2,890 2,890

Equity securities: U.S. companies 7,977 7,750 227 International companies 2,479 1,273 1,206

Fixed income securities: U.S. Treasury securities 1,885 1,885 Mortgage-backed securities 347 347

Corporate Bonds-U.S. Companies 1,667 1,667 Comingled funds:

Equity funds 13,481 13,481 Fixed-income funds 7,259 7,259

Total $ 47,808 35,160 5,105 7,543


Name of Respondent




04/15/2013


2012104


Pension plan assets fair value measurements at September 30, 2011

Quoted prices in active markets Significant Significant

for identical observable unobservable as sets inputs inputs

Total (Levell) (Level 2) (Level 3)

Asset category:

Cash $ 1,453 1,453 Limited Partnerships 8,281 1,038 7,243

Exchange Traded Funds 2,378 2,378 Equity securities:

U.S. companies 3,854 3,564 290 Intemational companies 2,341 1,222 1,119

Fixed income securities: U.S. Treasury securities 1,810 1,810 Mortgage-backed securities 621 621

Corporate Bonds-U.S. Companies 1,300 1,300 Comingled funds:

Equity funds 13,308 13,308 Fixed -income fu n d s 4,912 4,912

Total $ 40,258 27,875 4,850 7,533

Other postretirement benefit plan assets fair val ue meas urements at September 30,20 12

Quoted prices in active markets

for identical Significant observable

Significant unobs ervable

Total as sets

(Level I) inputs

(Level 2) inputs

(Level 3)

Asset category: Cash Limited Partnerships

$ 322 322

Exc h a nge T rad ed Fu nd s Comingled funds:

Equity funds

Fixed-income funds

3,133

9,337 3,558

3,133

9,337 3,558

Total $ 16,350 16,350 ========





Other pos tretirement benefit plan as sets fair value measurements at September 30, 2011

Quoted prices in active markets

for identical S ignific ant observable

Significant unobs ervable

Total as sets

(Level I) inputs

(Level 2) inputs

(Level 3)

Asset category: Cash $ 309 309 Limited Partnerships

Exchange Traded Fu nds Comingled funds:

Equity funds

Fixed-income funds

2,663

7,217

3,351

2,663

7,217

3,351

Total $ 13,540 13,540==="==='=====

Changes in the net fair value of pension and other postretirement benefit plan assets that are classified Level 3 are as follows:


Balance at beginning of period $ 7,533 Gains and losses (realized and unrealized) 10 Transfers in from level 2 7,533.. .. Balance at end of period 7,533$ ===7""",5==43===

(c) Pension and Other Postretirement Benefit Plan Cash Flow

Projected benefits and contributions are as follows:

Pension plan Other pos tretirement benefits Projected Projected

Benefit Benefit Contributions payments Contributions payments

Years ending September 30: "2013 $ 4,800 2,414 1,010 1,135 "2014 2,645 1,191 "'2015 2,787 1,226 "2010 2,901 1,253 "2017 3.145 1.285 20lS through 2022 19.303 7.039





(d) Defined Contribution Plan

The Company maintains a 40 I(k) Savings Plan for substantially all employees. This plan provides for employee contributions up to specified limits. The Company matches employee pretax contributions up to 4.00%, and contributes an additional 0.50% each year of eligible compensation, made on a nonmatching basis. Employees hired on or after January 1, 2008 receive an additional company contribution of 2.75% each year of eligible compensation. The Company's matching contribution is immediately vested. The Company's matching and nonmatching contributions for the years ended September 30, 2012 and 20 II totaled $800 and $717, respectively.

(e) Supplemental Executive Retirement Plan

The Company provides a nonqualified retirement plan (SERP) for certain employees. Benefits under the SERP are funded on a cash basis. The amount of expense recognized for this plan for the years ended September 30, 2012 and 20 II was $594 and $598, respectively. As of September 30, 2012, the SERP benefit obligation, based on a discount rate of 4.20%, was $5,593. The current and long-ternl portions were $583 and $5,010, respectively. As of September 30, 2011, the SERP benefit obligation, based on a discount rate of 4.25%, was $5,352. The current and long-term portions were $578 and $4,774, respectively. Corresponding regulatory assets were recorded for both the current and long term p0l1ions.

(f) Deferred Compensation

The Company has a deferred compensation plan for current and past officers and past directors. Amounts deferred are at the option of the officer or director, and include annual interest on the amounts deferred. The total deferred compensation liability at September 30,2012 and 2011 was $2,988 and $3,308, respectively.

(13) Derivative Financial Instruments

The majority of the Company's derivative instruments are cash flow hedges used to hedge power supply costs. The Company records contract-specified prices for electricity as an expense in the period used, as opposed to the changes occurring in fair market values. Due to a regulatory order from the VPSB that requires the Company to defer recognition of any earnings or other comprehensive income effects relating to future periods from power supply arrangements that qualify as derivatives, the Company records an offsetting regulatory asset or liability for the fair value of their derivative instruments.

The current portion of derivative assets, if any, is presented separately in the consolidated balance sheets. The current and non-current portions of derivative liabilities both are presented separately in the consolidated balance sheets for both periods presented.

The Company purchases the majority of its power supply, and uses long-term power supply contracts to mitigate rate volatility to rate payers. The Company enters into physical power supply agreements with various counterparties to hedge against fossil fuel price increases. Many of these contracts are derivatives but because they meet the exception for a normal purchase and sale contract, they are not carried at fair value. See Note 15. The Company currently has an agreemcnt (the 9701 Agreement) that grants HQ an option to call power from the Company's power supply contract at prices below current and estimated future market rates. This Agreement is effective through October 2015.





The following table shows the calculated fair value of the derivative contracts, including the risk that the Company or the counterparty will not execute upon the arrangement. Actual value upon settlement may differ materially from the fair values shown below:

September 30, Derivatives 2012 2011

Fair Value Assets Liabilities Assets Liabilities

Forward MWh sales $ 183 17 Forward MWh purchases 1,284 Power supply swaps 891 9701 agreement 4,485 8,086

Total power supply derivative liability $ 5,952 8,994

The tables below present assumptions used to estimate the fair value of derivatives, including the 9701 Agreement, forward purchase contracts, and forward sales contracts at September 30, 2012 and 2011. The forward prices for electricity used in this analysis are consistent with the Company's current long-term wholesale energy price forecast.

September 30, 2012 Option Value Risk Free Price Average Contract

Interest Forward Model Rate Volatility Price/MWh Expires

9701 agreement Black-Scholes 0.2% 20%-29% $66 2015 DeterministicForward MWh purchases 0.05% N/A $43 2012

Forward MWh sales Deterministic 0.05% N/A $43 2013

September 30, 2011 Option Value Risk Free Price Average Contract

Interest Forward Model Rate Volatility Price/MWh Expires

970 I agreement Black-Scholes 0.3% 16%-26% $77 2015 Power supply swaps Deterministic 0.01% n/a $48 2011 Forward sales Detem1inistic 0.05% n/a $28 2012





Certain of the Company's derivative instruments contain reciprocal provisions that require the counter parties and the Company's debt to maintain an investment grade credit rating from the major credit rating agencies. A failure to maintain an investment grade rating would oblige the counterparties or Company to deposit collateral in an amount equal to the fair value adjustment to the notional amount of the contract for derivative instruments in a liability position. A failure to maintain an investment grade rating would obligate the counterparties or Company to deposit collateral of $5,602, which is equal to the fair value adjustment to the notional amount of the contract for derivative instruments in a liability position.

Collateral required if

below investment

grade

5,299

184

At September 30, 2012 and 2011, the Company had a total power supply derivative liability of$5,952 and $8,994, respectively, reflecting the fair value of the 9701 Agreement, forward sales, power supply swaps and forward purchases. The Company records corresponding regulatory assets and regulatory liabilities. Amounts due during the next fiscal year are classified in current assets and current liabilities.

(14) Fair Value of Financial Instruments

Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The carrying amounts for cash and cash equivalents, accounts receivable, prepaid expenses, income tax receivable, accounts payable and accrued liabilities approximate their fair values because of their short-term maturities. The fair value of the Company's revolving line of credit included in long-term debt approximates the carrying values due to the short-tenn nature of the related borrowings and the variable interest rate, which is adjusted daily.

The Company estimates of fair value of financial assets and financial liabilities are based on the framework and hierarchy established in applicable accounting pronouncements. The framework is based on the inputs used in valuation, gives the highest priority to quoted prices in active markets and requires that observable inputs be used in the valuations when available. The disclosure of fair value estimates in the hierarchy is based on whether the significant inputs into the valuation are observable.

The fair value of the Company's first mortgage bonds included in long-tenn debt, less current maturities (with a carrying





amount of$236,990 and $169,145 at September 30,2012 and 2011, respectively) was $295,486 and $210,934 at September 30,2012 and 2011, respectively. The fair value of the Company's first mortgage bonds are measured using quoted offered-side prices when quoted market prices are available. If quoted market prices are not available, the fair value is detennined based on quoted market prices for similar issues with similar remaining time to maturity and similar credit ratings.

The following table sets forth by level the September 30, 2012 and 2011 fair value hierarchy of our financial assets and liabilities that are accounted for at fair value on a recurring basis. The Company's assessment of the significance of a particular input to the fair value measure requires judgment, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy:

Fair Value as of September 30, 2012

Levell Level 2 Level 3 Total

Assets:

Millstone decommissioning trust fund

Investments in marketable securities:

Marketable equity securities $ 1,832 3,209 5,041

Marketable debt securities

Corporate bonds 358 358

U.S. Government issued debt securities (Agency and Treasury) 996 996

State and municipal 96 96

Other 32 32

Total marketable debt securities 1,482 ______1,482

Cash equivalents and other 77 -- 77

Total investments in marketable securities 1,832 4,768 6,600

Total assets 1,832 4,768 6,600

Liabilities:

Power-related derivatives - current _________5-:..,9_5-=2 5,952

Total liabilities $ 5,952 5,952


Name of Respondent


This Report is: (1) XAn Original (2) A Resubmission


04/15/2013


2012/04


Fair Value at September 30,2011 Levell Level 2 Level 3 Total

Liabilities:

Derivative financial instruments $ $ 8,994 $ $ 8,994

Total $ $ 8,994 $ $ 8,994

Investment Securities - Millstone Decommissioning Trust Fund

The Company has decommissioning trust fund investments related to the joint-ownership interest in Millstone Unit #3. The decommissioning trust fund was established pursuant to various federal and state guidelines. Among other requirements, the fund must be managed by an independent and prudent fund manager. Any gains or losses, realized and unrealized, are expected to be refunded to or collected from ratepayers and are recorded as regulatory assets or liabilities.

An investment is impaired if the fair value of the investment is less than its cost and if management considers the impairment to be other-than-temporary. Regulatory authorities limit the Company's ability to oversee the day-to-day management of its nuclear decommissioning trust fund investments and therefore the Company lacks investing ability and decision-making authority. Accordingly, all equity securities held by the nuclear decommissioning trusts with fair values below their cost basis are considered to be other-than-temporarily impaired. For debt securities, other-than-temporary impairment exists if: I) there is the intent to sell a debt security; 2) it is more likely than not that the security will be required to be sold prior to recovery; or 3) the entire unamortized cost of the security is not expected to be recovered. For the majority of the investments shown below, the Company owns a share of the trust fund investments.

For the period ended September 30, 2012, there were minimal realized gains and no realized losses. The realized losses include minimal impairments associated with equity securities; however, there were no permanent impaim1ents or 'credit losses' associated with debt securities. There were also no non-credit loss impairments of debt securities in 2012.

The fair values of these investments are summarized below: As of September 30, 2012

Amortized Unrealized Unrealized Estimated

Security Types Cost Gains Losses Fair Value

Marketable equity securities $ 3,125 1,916 5,041

Marketable debt securities

Corporate bonds 316 42 358

U.S. Govemment issued debt securities

(Agency and Treasury) 918 78 996

State and municipal 94 2 96

Other 30 2 32

Total marketable debt securities 1,358 124 1,482

Cash equivalents and other 77 77

Total $ 4,560 2,040 $ $ 6,600


Name of Respondent This Report is: Date of Report Year/Period of Report (1) 6 An Original (Mo, Da, Yr)



Infonnation related to the fair value of debt securities at September 30, 2012 follows:

Fair value of debt securities at contractual maturity dates

After 10Less than 1 1 to 5 years 5 to 10 years years Total

Debt Securities $45 $358 $355 $724 $1,482

(15) Long-Term Power Purchase and Other Commitments

Purchased power expense by significant contract supplier for the years ended December 31, 2012 and 20 II was as follows:

Year ended December 31 2012 2011

In thousands

Hydro Quebec $ 71,788 $ 50,034

Small Power Producers 20,878 17,732

Nextera 17,091

JP Morgan 12,577

VYNPC 8,695 35,377

Macquarie 4,457

Granite Reliable 3,407 Morgan Stanley 306 8,219

These contracts qualify for normal purchases and sales treatment under ASC Topic 815, Derivatives and Hedging, and are not subject to fair value accounting treatment as they are for the purchase of electricity to fulfilJ the Company's power supply needs. The expense related to these contracts is recorded and recognized in power supply expense at the time that the contracts are settled and the Company takes delivery of the electricity.

Information with regard to significant purchased power contracts of this type in effect as of September 30,2012, including estimates for the Company's portion of certain minimum costs. is as follows:


Name of Respondent


This Report is: (1) ~ An Original (2) A Resubmission



04/15/2013


2012/04

$ _.......;..:3,.;.,84~1..:.;;.,3.;...96~

"2013 "'2014 '"2015 "'2016 "2017 Beyond 2017

Total

$ 241,251 219,550 223,295 182,975 164,589

2,809,736

(g) Hydro Quebec Contracts

Undcr various contracts, the Company purchases capacity and associated energy produced by the Hydro Quebec (HQ). These contracts obligate the Company to pay certain fixed capacity costs whether or not energy purchases above a minimum level set forth in the contracts are made. These minimum cncrgy purchases must be made whether or not other less expensive energy sources might be available in the short-term market. These contracts are intended to complement the other components in the Company's power supply.

The Company currently purchases power pursuant to the Vermont Joint Owners (VJO) contract with Hydro Quebec entered into in December 1987, which expires in October 2015. In the event any VJO Contract participant fails to meet its obligation under the VJO contract with HQ, the remaining contract participants, including the Company, will assume the defaulting participant's share on a prorated basis.

To detennine the "maximum potential" amount of future payments the Company could be required to make under its guarantee included in the VJO contract, the Company must assume that all other members of the VJO contract simultaneously default. The Company estimates that its undiscounted purchase obligation under the "step-up" provision would be $108,371 for the remainder of the contract, assuming that all other members of the VJO defaulted by September 30, 2012 and remained in default for the duration of the contract. In such a scenario, the Company would then own the power and could seek to recover its costs from the defaulting VJO contract participants, its retail customers, or resell the power in the wholesale power markets in New England. The range of outcomes (full cost recovery, potential loss, or potential profit) would be highly dependent on Vermont regulation and on wholesale market prices at the time.

Under the VJO Contract, HQ retains the right to curtail annual energy deliveries by 10% up to five times, over the 2001 to 2015 period, ifdocumented drought conditions exist in Quebec. HQ has never curtailed GMP energy deliveries due to documented drought conditions.

Commencing April 1, 1998, and effective through October 2015, Hydro Quebec can exercise an option to purchase up to 52,500 MW pursuant to the 9701 Agreement on an annual basis, at energy prices established in accordance with thc VJO Contract. The cumulative amount of energy purchased under the 970 I Agreement shall not exceed 950,000 MWh. Annually, HQ has exercised and received power for the 970 I Agreement option. The replacement cost of this power is amortized over the calendar year. Approximately $1,158 and $3,593 were amortized during the years ended December 3 J , 2012 and 20 II, respectively. At current energy prices, it is expected that HQ will continue to exercise its 970 I Agreement option annually.

On April] 5, 20] ]. The VPSB approved a long-tenn power purchase and sale agreement between Hydro-Quebec Energy Services (U.S.) Inc. (HQUS). a subsidiary of HQ, and a group of Vennont utilities including GMP. The Company detennined that the contract qualifies for "normal purchase normal sale" accounting treatment. Under the HQUS agreement, GMP will receive a portion of a statewidc total of up to 218 to 225 MW of energy, delivered in a fixed 16 hour/day (i.e. 7x 16) profile, and a corresponding portion of the environmental attributes (such as, for example, credits, benefits or emissions reductions) associated with this power. Such environmental attributes must meet a requirement specifying a hydropower content of at least 90%. HQUS markets electricity from HQ's generating fleet, whose output is

IFERC FORM NO.1 (ED. 12-88) Page 123.33 I

Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr)



presently well in excess of 90% hydroelectric. The contract lays a foundation that will guarantee GMP continued access to a reliable supply of power from HQ facilities, which should help GMP to maintain its favorable carbon footprint. Deliveries under this purchase will commence on November I, 2012 at very small volumes, increase substantially in 2016 (as the existing VJO contract is expiring), and end in 2038. The energy volumes under the contract represent an estimated 22% ofGMP's projected annual energy requirements beginning 2017.

The new HQUS contract does not feature options for the buyer or seller to adjust the annual load factor of deliveries or a delivery curtailment option comparable to the 9701 option, and does not contain a step-up provision. The new HQUS contract does not include capacity, which must be purchased from other parties or left open to market prices.

The Company's contracts with HQ call for the delivery of system power and are not related to any particular facilities in the HQ system. Consequently, there are no identifiable debt-service charges associated with any particular HQ facility that can be distinguished from the overall charges paid under the contracts, and there are no generation plant outage risks although there are outage risks related to the operation of the transmission system.

(It) Vermont Yankee Nuclear Power Corporation

The Company had a long-term power purchase contract with VYNPC which expired March 2012. See note 4.

The VYNPC sale of its nuclear power plant to ENVY in 2002 also called for ENVY, through its power contract with VYNPC, to provide between 100MW to 106MW of the plant output to the Company through March 2012.

ENVY's license to operate the nuclear power plant expired in 2012, and ENVY has obtained a 20-year license renewal from the Federal Nuclear Regulatory Commission. ENVY is currently involved in litigation in the United States Federal cOUlis and administrative regulatory proceedings before the VPSB to detennine what Vermont state approvals are required to continue to operate the plant through the federal license renewal period. The plant is continuing to operate during the consideration of these proceedings. If the plant receives the state approvals required to continue operations, the Company has no contract to purchase power from ENVY. The Company has contracts with other power supply resources to replace most of this power, on a short and long-term basis.

(i) System Energy Contracts

The Company enters into system energy purchase contracts with various counterparties in the nonnal course of its business. The system contracts are usually less than five years in duration and call for finn physical delivery of specified hourly quantities that are not associated with any specific generation source and not subject to outage risk. The Company presently has in place several layered system energy purchases for deliveries beginning in 2012, for terms from 2 to 5 years.

(j) NextEra Seabrook Purchase

The Company agreed on terms for a power purchase agreement in May 2011 to purchase long-term energy, capacity and generation attributes from the Seabrook Nuclear Power Plant in New Hampshire owned by NextEra Seabrook LLC. This contract commenced in 2012 with purchases of approximately 131,000 MWh per year of System Power that is not related to any specific facility. Beginning in 2015, all purchases will be unit contingent purchases from the Seabrook Nuclear Power Plant beginning at 60MW, which will decrease to 50 MW and then to 40 MW over the life of the contract that ends in 2034. The VPSB approved this purchase and sale agreement in December 2011.





(k) Other Renewable Power Contracts

The Company has committed to several contract to purchase output from new renewable power plants, some for periods of up to 20 years, on a plant-contingent basis (the Company receives and pays only for its share of quantities actually generated by the plant). These purchases typically include energy, capacity, and renewable energy certificates and are derived from wind or landfill gas plants. The largest such purchase is a 20-year purchase from the Granite Reliable wind project in New Hampshire, which began in April 2012.

(I) Unit Purchases

Under a long-term contract with Massachusetts Municipal Wholesale Electric Company (MMWEC), the Company is purchasing a percentage of the electrical output of the Stony Brook production plant constructed by MMWEC. The contract obligates the Company to pay certain minimum annual amounts representing the Company's proportionate share of fixed costs, including debt service requirements, whether or not the production plant is operating, for the life of the unit. The cost of power obtained under this long-term contract, including payments required when the production plant is not operating, is included in "purchases from others" in the accompanying consolidated statements of income.

(m) Jointly Owned Facilities

GMP's joint-ownership interests in electric generating and transmission facilities as of December 31, 2012 are as follows:

Share of Share of Ownership Share of Utility Accumulated

Interest Capacity Plant Depreciation (In %) (In MW)

Joseph C. McNeil 31.0 ]6.7 $ 29,191 $ 23,029

Wyman (No.4) 2.9 ]7.6 6,100 5,300

Stony Brook (No. I) 8.8 31.0 11,598 10,692

Highgate Transmission Facility 81.3 162.6 24,918 16,778 Metallic Neutral Return 59.4 1,563 1,369

Millstone (No.3) 1.7 21.4 79,027 44,] ] 9

Metallic Neutral Return is a neutral conductor for the NEPOOL/Hydro-Quebec Interconnection.

GMP's share of expenses for these facilities is included in operating expenses in the consolidated statements of income under the caption "Power supply expenses - Company-owned generation" for the listed generation plants (Wyman, Stony Brook, McNeil, and Millstone, under the caption "Transmission expenses" for the MetalJic Neutral Return and Highgate facilities, and under the caption "Depreciation and amortization expenses" for all facilities. Each participant in these facilities must provide their own financing.


l\lame of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr)



(n) Kingdom Community Wind (KCW)

At the end of fiscal 2011 , GMP began construction of its KCW project, a 63-megawatt wind power project located in Lowell, Vermont. This 21-turbine wind power project can supply power to more than 24,000 households consisting of GMP's customers and members of the Vermont Electric Cooperative, Inc. (VEC). The Company will sell 8 MW of the project's output to VEC, under a long-term contract. Construction of the wind farm has been completed, and the 21 turbines have been in service since November 20, 2012. As of December 31,2012, GMP had invested $145 million in this project.

(0) Other Commitments

The Company was required to set aside $1,025 and $205 as of December 31, 2012 and 2011, respectively, for renewable generation development under a VPSB regulatory order. These amounts are included in the accompanying consolidated balance sheets in cash and cash equivalents.

Also, included in cash and cash equivalents are deposits, that the Company provides as collateral under performance assurance requirements for certain power supply contracts amounting to $3,811 and $3,305 as of December 31, 2012 and 2011, respectively.

In connection with the Company's acquisition of the Vermont Marble Power Division ofOmya Inc. (Omya or VMPD) on September 1, 2011, the Company received $1,191 from Omya for the repayment obligation for the five-year rate phase-in plan of the former Vermont Marble customers, as specified in the acquisition agreement. As of December 31,2012, $418 is reflected as prepaid expenses and other current assets in the consolidated balance sheets, compared to $0 as of December 31, 20 I I.

(16) Environmental Matters

General

The electric industry typically uses or generates a range of potentially hazardous products in its operations. The Company must meet various land, water, air, and aesthetic requirements as administered by local, state, and federal regulatory agencies. The Company believes that it is in substantial compliance with these requirements. and that there are no outstanding material complaints about the Company's compliance with present environmental protection regulations.

Pine Street Barge Canal Superfund Site

In 1999, the Company entered into a United States District COUl1 Consent Decree constituting a final settlement with the United States Environmental Protection Agency (EPA), the State of Vermont and numerous other pal1ies of claims relating to a federal Superfund site in Burlington, Vermont, known as the "Pine Street Barge Canal". The consent decree resolves claims by the EPA for past site costs, natural resource damage claims, and claims for past and future remediation costs. The consent decree also provides for the design and implementation of response actions at the site. The Company has estimated total costs of the Company's future obligations under the consent decree to be approximately $4,696, net of recoveries. The estimated liability is not discounted, and it is possible that the Company's estimate of future costs could change by a material amount. The Company has recorded a regulatory asset of $13.608 to reflect unrecovered past and future Pine Street Barge Canal costs. Pursuant to the Company's 2003 Rate Plan, as approved by the VPSB, the Company began to amortize and recover these costs in 2005. The Company will amortize the full amount of incurred costs over 20 years without a retum. The amortization is


Name of Respondent


This Report is: (1) ~ An Original

1(2) A Resubmission


04/15/2013


2012104


expected to be allowed in current and future rates, without disallowance or adjustment, until fully amortized.

Clean Air Act

The Company purchases most of its power supply from other utilities and does not anticipate it will incur any material direct costs as a result of the Federal Clean Air Aet or proposals to make more stringent regulations under that Act.

(17) Other Contingent Liabilities

Other Legal Matter8

The Company does not expect any litigation to result in a material adverse effect on its operating results or financial condition.

(18) Related-Party Transactions

Effective April 12,2007, the Company became related to Vennont Gas Systems (VGS) when it was acquired by NNEEC. The rates at which the Company buys gas for facility heating from VGS and the rates at which VGS buys electricity from the Company are regulated and required to be transacted at rates approved by the VPSB, and applicable to similar customers of similar usage, and amounts are insignificant and immaterial with respect to these regulated revenues. VGS is also a responsible party in the Pine Street Barge Canal Superfund Site and remits funds related to this matter annually to the Company. Payments totaling $10 I and $481 were received for the Pine Street Barge Canal Superfund Site during the years ended December 31, 2012 and 2011, respectively, and there were no other transactions between VGS and the Company during the years ended December 31, 2012 and 20] 1.

(19) Major Customers and Other Concentration Risks

(a) Customers During the] 2 months ended September 30, 20] 2 and 2011, the Company had one major retail customer, International Business Machines Corporation (IBM) that accounted for 22.3% and 22.6%, respectively, of retail megawatt-hour sales, and 15.1 % and IS .5%, respectively, of the Company's retail operating revenues.

(h) HQ Power Supp~v Contracts

The Company's material power supply contracts are principally with Hydro Quebec, IP Morgan, and prior to March 2], 2012, VYNPC. The Company has contracts with other power supply resources to replace most of the VYNPC power, on a short and long-tenn basis. These contracts are expected to meet approximately 85% to 90% of the Company's anticipated annual demand requirements through 2013. Under the Company's Plan II Alternative Regulation Plan, there is a power supply adjustment mechanism to minimize the risk of rising power supply costs.

(c) Number ofEmployees

At December 31. 2012, we had 720 employees. Of these employees. 306 were represented by Local Union No. 300. affiliated with the International Brotherhood of Electrical Workers. On January 14, 2013. we agreed to a new five-year contract with our employees represented by the union, which is effective on January I. 2013 and expires on December 31. 2017.


Name of Respondent


STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES

1. Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate. 2. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges. 3. For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote. 4. Report data on a year-to-date basis.

Line Item

No.

(a)

1 Balance of Account 219 at Beginning of

Preceding Year

2 Preceding QtrlYr to Date Reclassifications

from Acct 219 to Net Income

3 Preceding QuarterlYear to Date Changes in

Fair Value

I 4 Total (lines 2 and 3)

5 Balance of Account 219 at End of

Preceding QuarterlYear

6 Balance of Account 219 at Beginning of

Current Year

7 Current Qtr/Yr to Date Reclassifications

from Acct 219 to Net Income

8 Current QuarterlYear to Date Changes in

Fair Value

9 Total (lines 7 and 8)

10 Balance of Account 219 at End of Current

Quarter/Year

This ~ort Is: (1) An Original (2) DA Resubmission

Unrealized Gains and Losses on Available-for-Sale Securities

(b)

Date of Report Year/Period of Report (Mo, Da, Yr) End of 2012/Q4 04/15/2013

Minimum Pension I Foreign Currency I

Other

Liability adjustment Hedges Adjustments (net amount)

(c) (d) (e)

( 1,446)

121,855

120,409

120,409

FERC FORM NO.1 (NEW 06-02) Page 122a

Name of Respondent Year/Period of Report This ~ort Is: Date of Report (1) ~ An Original (Mo, Da, Yr) End of 2012/04Green Mountain Power Corporation (2) A Resubmission 04/15/2013

STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES

Line No.

Other Cash Flow Hedges

Interest Rate Swaps

(f)

Other Cash Flow Totals for each

Hedges category of items

[Specify] recorded in Account 219

(g) (h)

Net Income (Carried Forward from

Page 117, Line 78)

Total Comprehensive

Income

(i) U)

2

3

4

5

6

7 1,446)

8 121,855

9 120,409

10 120,409

FERC FORM NO.1 (NEW 06-02) Page 122b

I

a eportIS ~ort s: (1) ~An Original 2012/Q4End of (2) A Resubmission 04/15/2013

SUMMA Y OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION. AMORTIZATION AND DEPLETION

'Report in Column (c) the amount for electric function. in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and in column (h) common function.

Total Company for the ElectricClassificationLine Current Year/Quarter Ended (c)No.

(b)(a)

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

Utility Plant

In Service

Plant in Service (Classified) 1,336,450,549 1,336,450,549

Property Under Capital Leases 4,231,904

Plant Purchased or Sold

Completed Construction not Classified

Experimental Plant Unclassified

Total (3 thru 7)

4,231,904

1,340,682,453 1,340,682,453

Leased to Others

Held for Future Use

Construction Work in Progress 109,313,860 109,313,860

Acquisition Adjustments ------~--------------__+_----------t_--------__I

1,449,996,313 1,449,996,313

Accum Prov for Depr, Amort, & Depl

Total Utility Plant (8 thru 12)

517,692,242 517,692,242

Net Utility Plant (13 less 14) 932,304,071

Detail of Accum Prov for Depr, Amort & Depl

In Service:

Depreciation

Amort & Depl of Producing Nat Gas Land/Land Right

Amort of Underground Storage Land/Land Rights

Amort of Other Utility Plant

Total In Service (18 thru 21)

Leased to Others

Depreciation

Amortization and Depletion

Total Leased to Others (24 & 25)

Held for Future Use

Depreciation

Amortization

Total Held for Future Use (28 & 29)

Abandonment of Leases (Natural Gas)

Amort of Plant Acquisition Adj

Total Accum Prov (equals 14) (22,26,30,31,32)

932,304,071

517,692,242 517,692,242


Name of Respondent


This ~ort Is: (1) ~ An Original (2) A Resubmission


YearlPeriod of Report

End of 2012/Q4

SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS

FOR DEPRECIATION. AMORTIZATION AND DEPLETION

Gas Other (Specify) Other (Specify) Other (Specify) Common Line

(d) (e) (f) (9) (h) No.

~ ~~~ "<

~-" -'-- ----~~_ ~"'- ~~ - ~~~---~~ ---~- -~ -.,."..,~ ~~~ - ~~--~~- ~-

" ---~~~ -~""<"=-'-- - ~-=--~------ _~_ - -- :,;:-~-;~~-- ",,,,,~

~ -""'~"'<:3",,~--"

i%;&~O; " "" 1% ':%hi lli&1 ","" '" ~" _ fib ~ "''' '-' "'''' ""'1<.:*,, 1itb& }::" "» G"i~",,, " _' *' >:; '" ,", :;; ~.¥ $*,,*k~ 3

4

5

6

7

8

9

10

11

12

13

14


Name of Respondent


This ~ort Is: Date of Report (1) ~ An Original (Mo, Da, Yr) (2) A Resubmission 04/15/2013


End of 2012/04

NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157)

1. Report below the costs incurred for nuclear fuel materials in process of fabrication, on hand, in reactor, and in cooling; owned by the respondent. 2. If the nuclear fuel stock is obtained under leasing arrangements, attach a statement showing the amount of nuclear fuel leased, the quantity used and quantity on hand, and the costs incurred under such leasing arrangements.

1 Nuclear Fuel in process of Refinement, Conv, Enrichment & Fab (120.1)

Line No.

Description of item

(a)

Balance Beginning of Year

(b)

Changes during Year Additions

(c)

2 Fabrication

3 Nuclear Materials

4 Allowance for Funds Used during Construction

5 (Other Overhead Construction Costs, provide details in footnote)

6 SUBTOTAL (Total 2 thru 5)

7 Nuclear Fuel Materials and Assemblies

8 In Stock (120.2) 1,311,550

9 In Reactor (120.3) 3,189,051

10 SUBTOTAL (Total 8 & 9) 4,500,601

11 Spent Nuclear Fuel (120.4) 12,378,457

12 Nuclear Fuel Under Capital Leases (120.6)

13 (Less) Accum Prov for Amortization of Nuclear Fuel Assem (120.5) 14,214,391

14 TOTAL Nuclear Fuel Stock (Total 6, 10, 11, 12, less 13) 2,664,667

15 Estimated net Salvage Value of Nuclear Materials in line 9

16 Estimated net Salvage Value of Nuclear Materials in line 11

17 Est Net Salvage Value of Nuclear Materials in Chemical Processing

18 Nuclear Materials held for Sale (157)

19 Uranium

20 Plutonium


22 TOTAL Nuclear Materials held for Sale (Total 19, 20, and 21)


Year/Period of Report Name of Respondent This ~ort Is: Date of Report (1) ~An Original (Mo, Da, Yr) End of 2012/04IIGee" Moo,',;, Powee eo,,,,,,';oo I (2) A Resubmission 04/15/2013

NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157)

,------=-~--------,---~-~Changes during Year Balance Line Other Reductions [~XPlain in a footnote) End ~f) Year No.

2

3

4

5

6

7

2.141,107 8

3,189,051 9

5,330.158 10

12,378,457 11

12

14,494,146 13

3,214,469 14

15

16

17

18

19

20

'-- ---'---~ ~L 21


1

YearlPeriod of ReportDate of Report Name of Respondent This [!J0rt Is: (Mo, Da, Yr) (1) An Original 2012/Q4End ofGreen Mountain Power Corporation 04/15/2013(2) n A Resubmission

ELECTRIC PLANT IN SERVICE (Account 101,102,103 and 106)

1. Report below the original cost of electric plant in service according to the prescribed accounts. 2. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold; Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric. 3. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year. 4. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and reductions in column (e) adjustments. 5. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts. 6. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included in column (c) are entries for reversals of tentative distributions of prior year reported in column (b). Likewise, if the respondent has a significant amount of plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d)

Line Account Beginning of Year No.

(a) (b) (c)

1. INTANGIBLE PLANT ~ 2 (301) Organization 12,146

3 (302) Franchises and Consents 2,804,929

4 (303) Miscellaneous Intangible Plant 7,033,961

5 TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4) 9,851,036

6 2. PRODUCTION PLANT

7 A. Steam Production Plant

2,158,883

2,158,883

36,368

2,631,081

5,927,359

1,840,049

438,745

1,664,469

8 (310) Land and Land Rights

9 (311) Structures and Improvements

10 (312) Boiler Plant Equipment

11 (313) Engines and Engine-Driven Generators

12 (314) Turbogenerator Units

13 (315) Accessory Electric Equipment

14 (316) Misc. Power Plant Equipment

15 (317) Asset Retirement Costs for Steam Production

16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)

B. Nuclear Production Plant 17 18 (320) Land and Land Rights

19 (321) Structures and Improvements

(322) Reactor Plant Equipment 20 (323) Turbogenerator Units 21

(324) Accessory Electric Equipment 22 23 (325) Misc. Power Plant Equipment

24 (326) Asset Retirement Costs for Nuclear Production

25 TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24) ,.

26 C. Hydraulic Production Plant

27 (330) Land and Land Rights 1,281,933

28 (331) Structures and Improvements 6,149,421 43,170

29 (332) Reservoirs, Dams, and Waterways 29,999,010 284,821 30 (333) Water Wheels, Turbines, and Generators 17,531,451 37,026 31 (334) Accessory Electric Equipment 5,356,508 278,718 32 (335) Misc. Power PLant Equipment 1,203,853 65,467 33 (336) Roads, Railroads, and Bridges 672,328 34 (337) Asset Retirement Costs for Hydraulic Production

35 TOTAL HydraUlic Production Plant (Enter Total of lines 27 thru 34) 62,194,504 709,202 36 D. Other Production Plant

37 (340) Land and Land Rights 128,195

(341) Structures and Improvements 38 3,198,841

39 (342) Fuel Holders, Products, and Accessories 3,201,185 4,301

40 (343) Prime Movers 11,416,569 29,922 41 (344) Generators 15,620,311

42 (345) Accessory Electric Equipment 1,164,026 4,816 43 (346) Misc. Power Plant Equipment 854,653 123,603,465 44 (347) Asset Retirement Costs for Other Production

45 TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44) 35,583,780 123,642,504 46 TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45) 110,316,355 124,351,706


YearlPeriod of ReportName of Respondent This ~ort Is: Date of Report (1) ~An Original (Mo, Da, Yr) End of 2012/04Green Mountain Power Corporation (2) A Resubmission 04/15/2013

ELECTRIC PLANT IN SERVICE (Account 101,102,103 and 106) (Continued)

distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of respondent's plant actually in service at end of year. 7. Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column (f) the additions or reductions of primary account classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary account classifications. 8. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing subaccount classification of such plant conforming to the requirement of these pages. 9. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase, and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also date

Retirements Adjustments Transfers Balance at Line

1

2

3

4

5

6

7

76,029 112,397 8

4,623,063 7,254,144 9

13,116,670 19,044,029 10

11

3,187,868 5,027,917 12

794,824 1,233,569 13

277,055 1,941,524 14

6,624 6,624 15

22,082,133 34,620,204 16

17

11,720 11,720

22,034,297 22,034,297

35,720,169 35,720,169

9,988,636 9,988,636

8,573,448 8,573,448

2,040.689 2,040,689

78,368,959 78,368,959

End 9f Year NoIg) .

18

19

20 21

22

23

24

25

2,465,485

5,956,605

30,274,423

25,387,889

13,110,154

27,395

37,497

34,327

77,293,775

3,747,418 27

12,149,196 28

60,558,254 29

42,956,366 30 18,745,380 31

1,296,715 32

709,825 33 34,327 34

140,197,481 35

2,280 36

130,475 37 16,329 3,215,170 38

557,603 3,763,089 39 805,160 4,053,282 14,694.613 40

696,547 16,316,858 41 935,317 2,104,159 42

31,313 124,489,431 43 39,261 39,261 44

805,160 6,331,932 164,753,056 45 805,160 184,076,799 417,939,700 46


26

2012/Q4

(c)

YearlPeriod of Report (Mo, Da, Yr) End of 04/15/2013

Beginning of Year (b)~

Date of Report Name of Respondent This ~ort Is: (1) An Original

Green Mountain Power Corporation (2) nA Resubmission

ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)

Line Account No.

(a) 47 3. TRANSMISSION PLANT

48 (350) Land and Land Rights

49 (352) Structures and Improvements (353) Station Equipment

51

50 (354) Towers and Fixtures

52 (355) Poles and Fixtures

I 53 (356) Overhead Conductors and Devices

54 (357) Underground Conduit

55 (358) Underground Conductors and Devices (359) Roads and Trails 56

57 (359.1) Asset Retirement Costs for Transmission Plant

58 TOTAL Transmission Plant (Enter Total of lines 48 thru 57)

59 4. DISTRIBUTION PLANT

60 (360) Land and Land Rights 61 (361) Structures and Improvements

62 (362) Station Equipment

63 (363) Storage Battery Equipment 64 (364) Poles, Towers, and Fixtures

65 (365) Overhead Conductors and Devices (366) Underground Conduit 66

67 (367) Underground Conductors and Devices (368) Line Transformers

69

68 (369) Services

70 (370) Meters 71 (371) Installations on Customer Premises

72 (372) Leased Property on Customer Premises

73 (373) Street Lighting and Signal Systems 74 (374) Asset Retirement Costs for Distribution Plant

75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74)

76 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT 77 (380) Land and Land Rights 78 (381) Structures and Improvements 79 (382) Computer Hardware

80 (383) Computer Software 81 (384) Communication Equipment 82 (385) Miscellaneous Regional Transmission and Market Operation Plant

83 (386) Asset Retirement Costs for Regional Transmission and Market Oper

84 TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83) 6. GENERAL PLANT

86

85

(389) Land and Land Rights 87 (390) Structures and Improvements

(391) Office Furniture and Equipment 88 89 (392) Transportation Equipment 90 (393) Stores Equipment 91 (394) Tools, Shop and Garage Equipment 92 (395) Laboratory Equipment 93 (396) Power Operated Equipment 94 (397) Communication Equipment

95 (398) Miscellaneous Equipment

96 SUBTOTAL (Enter Total of lines 86 thru 95)

97 (399) Other Tangible Property

98 (399.1) Asset Retirement Costs for General Plant

99 TOTAL General Plant (Enter Total of lines 96, 97 and 98)

100 TOTAL (Accounts 101 and 106)

101 (102) Electric Plant Purchased (See Instr. 8)

102 (Less) (102) Electric Plant Sold (See Instr. 8) (103) Experimental Plant Unclassified 103

104 TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103)

1,050,524

295,860 27,725,885

214,078

9,092,139

12,415,137

I

50,793,623

6,593,326

2,456,959 1,209,703

10,259,988

1,255,824

243,452

31,990,626

49,768,973 52,712,704

13,561,826 19,285,150

50,869,407

16,352,523 15,175,706

5,088,570

52,014

256,356,775

116,951

4,637 6,812,852

4,540,884

3,809,178 741,876 847,679

2,908,927 950,510

10,475,819

-1,984

902,169

32,109,498

1,001,059 14,843.052 6,355,408

11,398,734 208,844

2,402,216 959,279

5,324,603

105,595

42,598,790

52,528

42,651,318

469,969,107

469,969,107

349,276 1,587,201

105,177

2,581 45,401

5,463

180,299

2,275,398

2,275,398 171,155,473

171,155,473


----

YearlPeriod of ReportDate of Report Name of Respondent This R~ort Is: (Mo, Da, Yr) (1) An Original

End ~f Yearg)

46,864

1,187,018

182,488

-182,488

2012/04End of Green Mountain Power Corporation (2) A Resubmission 04/15/2013

ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)

Retirements Adjustments Transfers Balance at Line No.

47

4,042,212 48

4,373,381

5,092,736

4,716,105 49

229,134 50

78,468

78,618,92843,341,833 51

59,736

292,546

52

74,161

28,736,41917,064,569 27,650,466 53

54

55

56

57

58

59

14,282,275

4,880

64,614

503,632

571,844

742,255

13,195

152,903

196,349

205,698

7,395,443

6,549

360,860

10,218,222

16,953,477 60

20,900,109

15,585,582 19,873,952 61

34,689,754

-1,209,632

-24,813 72,964,787 62

63

78,721,005 64

95,858,495

132,459,018

151,638,122 65

1,453,102 15,743,609 66

8,938,429 67

52,797,202

28,918,355 106,379,187 68

24,333,768 41,431,103 69

20,512,538 38,768,620 70

1,215,769 1,207,236 71

72

3,593,522 9,223,401 73

239,198 74

358,838,473

291,212

75-1,234,445 635,852,079

76

77

78

79

80 81

82

83

84

85

86 21,596,211 36,788,539 87

1,422,831 5,643,456 563 12,163,797 88 926,506 6,627,333 17,204,738 89

36 718,687 930,076 90 88,315 2,028,359 4,387,661 91 16,093 2,380,872 3,329,521 92

93 344,021 7,368,816 12,529,697 94

903 175,347 280,039 95 2,798,705 46,687,859 563 88,763,905 96

72,634 125,162 97

98 2,798,705 46,760,493 563 88,889,067 99

14,800,687 687,132,615 1,313,456,508 100

101

102

103 14,800,687 687,132,615 1,313,456,508

148,778 1,149,837

104


This [!J0rt Is: (1) An Original (2) n A Resubmission

ELECTRIC PLANT LEASED TO OTHERS (Account 104)

Description of prope1bfeased

Name of Respondent


Line Name of LesJee (Designate associate comfaniesNo. with a double asterisk

(a) 1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47 TOTAL

Year/Period of ReportDate of Report (Mo, Da, Yr) 2012/04End of 04/15/2013

Expiration Balance at Commission Date of

End of YearAuthorization Lease (d) (e)(c)


21

Date of Report Year/Period of Report Name of Respondent This wort Is: (Mo, Da, Yr) (1) An Original 2012/04Green Mountain Power Corporation End of 04/15/2013

ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)


1. Report separately each property held for future use at end of the year having an original cost of $250,000 or more. Group other items of property held for future use. 2. For property having an original cost of $250,000 or more previously used in utility operations, now held for future use, give in column (a), in addition to other required information, the date that utility use of such property was discontinued, and the date the original cost was transferred to Account 105.

Description and LocationLine in T is Account in Utility Service End of YearOf profertyNo.

(a (b) ~) ~)

1 Land and Rights: ~ 2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

Other Property: .

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47 Total


0



An Original

FiA Resubmission (Mo, Da, Yr) 04/15/2013

End of 2012/04

CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)

1. Report below descriptions and balances at end of year of projects in process of construction (107) 2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see Account 107 of the Uniform System of Accounts) 3. Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.

Construction work in progress Electric (Account 107)

Description of ProjectLine No.

(b)

1

(a)

1,111,557

2

Gorge 18 Rubber Dam

1,333,282

3

Green Lantern

1,570,304

4

KCW-34KV OH Collector

1,673,236

5

Smart Grid Program Manger

1,913,738

6

Business Intellegence

1,962,297

7

KCW Conservation Parcels

2,413,069

8

KCW VEC Jay Switching Station

2,998,254

9

OP Readiness

3,452,848

10

Kingdom Community Wind Lowell

3,491,796

11

AMI Project

3,729,798

12

Grid Automation Project

3,798,821

13

Gorge Runner Replacement

4,492,385

14

CIS Replacement Project

6,316,763

15

KCW 46KV Trans. & Jay Sub

2,347,407

16

Station Access Bridge

5,855,120Smart Meters

1,209,572

18

Purchase Bucket Trucks 17

1,561,500

19

Joint Owned Millstone

19,382,202

20

21

Joint Owned Highgate Converter

38,699,911

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

Miscellaneous less than 5% of the balance ($1,000,000)

43 TOTAL 109,313,860


Year/Period of Report Name of Respondent This ~ort Is: Date of Report (1) ~ An Original (Mo, Da. Yr) End of 2012/04Green Mountain Power Corporation (2) A Resubmission 04/15/2013

ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)

1. Explain in a footnote any important adjustments during year. 2. Explain in a footnote any difference between the amount for book cost of plant retired, Line 11, column (c), and that reported for electric plant in service, pages 204-207, column 9d), excluding retirements of non-depreciable property. 3. The provisions of Account 108 in the Uniform System of accounts require that retirements of depreciable plant be recorded when such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recorded and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional classifications. 4. Show separately interest credits under a sinking fund or similar method of depreciation accounting.

Ine em No. (a)

Balance Beginning of Year

2 Depreciation Provisions for Year. Charged to

3 (403) Depreciation Expense

4 (403.1) Depreciation Expense for Asset

Retirement Costs

5 (413) Exp. of Elec. PIt. Leas. to Others

6 Transportation Expenses-Clearing

7 Other Clearing Accounts

8 Other Accounts (Specify, details in footnote):

9 Acquistion

10 TOTAL Depree. Prov for Year (Enter Total of

lines 3 thru 9)

11 Net Charges for Plant Retired:

12 Book Cost of Plant Retired

13 Cost of Removal

14 Salvage (Credit)

15 TOTAL Net Chrgs. for Plant Ret. (Enter Total

of lines 12 thru 14)

16 Other Debit or Cr. Items (Describe. details in

footnote):

17

18 Book Cost or Asset Retirement Costs Retired

19 Balance End of Year (Enter Totals of lines 1.

10. 15. 16. and 18)

188.174,444 188.174,444

310.331,057 310.331.057

329,368,986 329.368,986

13,469.381 13,469.381

406,486 406,486

-385.589 -385.589

14.261,456 14.261,456

1.367,545 1.367.545

504.649,519 504.649.519

Section B. Balances at End of Year According to Functional Classification

20 Steam Production 27,352.003 27.352.003

21 Nuclear Production 43.815,488 43.815,488

22 HydraUlic Production-Conventional 56.554.856 56.554.856

23 Hydraulic Production-Pumped Storage

24 Other Production 29.277.210 29.277.210

25 Transmission 57,400.264 57,400.264

26 Distribution 253.394.903 253.394.903

27 Regional Transmission and Market Operation

28 General 36.854.795 36.854,795

29 TOTAL (Enter Total of lines 20 thru 28) 504.649.519 504.649.519


This ~ort Is: (1) An Original (2) Fi A Resubmission

Name of Respondent


1. 2. columns (e),(f),(g) and (h)

current settlement. date, and specifying whether note is a renewal. 3. Account 418.1.

Line Description of Investment No. (a)

1 A. Vermont Electric Power Company, Inc.

2 Common Stock - Class B, $100 par

3 17,715 shares

4 Common stock class C, $100 par 3,921 shares

5 Preferred stock Class C $100 par 30,020 shares

6 aquired in merger 9/12 $2,557,001

7 Undistributed Equity in Earnings

8 SUBTOTAL

9

10 B. Northern Water Resources, Inc..

11 Common Stock - no par value

12 and additional paid in capital


14 Return of Capital

15 SUBTOTAL

16 C. New England Hydro Electric

17 Transmission Company

18 Common stock


20 SUBTOTAL

21

22 D. New England Hydro Transmission

23 Corporation

24 Common stock and Additional paid in capital

25 Return of Capital


27 SUBTOTAL

28 E. Vermont Transco LLC

29 Membership units purchased

30 acquired in CVPS merger=166492611

31 Undistributed Earnings

32 2012 membership acquisitions=33472560

33 SUBTOTAL

34 Maine Yankee Atomic Power Corp

35 Common Stock

36 Equity in undistributed earnings

37 acquired in CVPS merger=43,993

38 SUBTOTAL

39 F. Vermont Yankee Nuclear Power Corporation

40 Common Stock

41 Paid in Capital

42 IITotal Cost of Account 123.1 $

Date of Report Year/Period of Report (Mo, Da, Yr)

End of 2012/0404/15/2013

INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)

Report below investments in Accounts 123.1, investments in Subsidiary Companies. Provide a subheading for each company and List there under the information called for below. Sub - TOTAL by company and give a TOTAL in

(a) Investment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity and interest rate. (b) Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to

With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity

Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for

Date Acquired Date Of Amount of Investment at

(b) Mat~ity Beginning of Year

(c (d)

6,499,278

499,595

43,710

554,258

7,596,841

28,062,497

-11,078,845

-16,666,243

317,409

404,589

40,327

444,916

1,333,978

-1,110,739

22,332

245,571

6-30-06

104,603,800

23,892,125

128,495,925

54,997

TOTAL 138,721,02601


Name of Respondent This wort Is:

Green Mountain Power Corporation (1)

(2)

4. and purpose of the pledge. 5. date of authorization, and case or docket number. 6. 7.

in column (f). 8. Report on Line 42, column (a) the TOTAL cost of Account 123.1

Equity in Subsidiary Earnin~s of Year

e)

Revenues for Year

(f)

982,199

982,199

110,566

110,566

121,836

17,361

139.197

17,550,286

17,550,286

18,957,077

896,717

896,717

143,410

143,410

5,506

129,532

135,038

17,313

17,313

22,181,539

22,181,539

462

462

23,604,931

YearlPeriod of ReportDate of Report An Original (Mo, Da, Yr)

2012/04End of 04/15/2013nA Resubmission

INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) (Continued)

For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee

If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission,

Report column (f) interest and dividend revenues form investments, including such revenues form securities disposed of during the year. In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (or

the other amount at which carried in the books of account if difference from cost) and the selling price thereof, not including interest adjustment includible

Amount of Investment at Gain or Loss from Investment Line End ~f Year DiSP?~)d of No.g)

1

2

8,230,978 3

499,595 4

43,710 5

6

1,294,077 7

10,068,360 8

9

10

11

12

-10,935,435

28,062,497

13

-16,666,243 14

460,819 15

16

17

410,095 18

53,787 19

463,882 20

21

22

23

1,333,978 24

-1,232,576 25

22,283 26

123,685 27

28

273,314,970 29

30

59,777,379 31

32

333,092,349 33

34

21,037 35

23,418 36

37

44,455 38

39

40

16,252,786 41

351,213,377 42


Name of Respondent


1. 2. columns (e),(f),(g) and (h)

current settlement. date, and specifying whether note is a renewal. 3. Account 418.1.

Line Description of Investment No. (a)

1 Equity in undistributed earnings

acquired in CVPS merger=2819339

SUBTOTAL

Yankee Atomic Electric Company

common stock and piad in capital

Equity in undistributed earnings

Acquired in CVPS merger=55322

subtotal

Connecticut Yankee Atomic Pwer co.

Common Stock and Paid in Capital

Equity in undistributed Earnings

Acquired in CVPS merger=43,444

SUBTOTAL

CV Realty

Common Stock


Acquired in CVPS merger=11 0485

SUBTOTAL

Catamount Resources Corporation

Common Stock


Acquired in CVPS merger=2255249

SUBTOTAL

IITotal Cost of Account 123.1 $

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

This ~ort Is: (1) An Original (2) DA Resubmission

INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)

Report below investments in Accounts 123.1, investments in Subsidiary Companies. Provide a subheading for each company and List there under the information called for below. Sub - TOTAL by company and give a TOTAL in

Year/Period of ReportDate of Report (Mo, Da, Yr)

2012/04End of04/15/2013

(a) Investment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity and interest rate. (b) Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to

With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity

Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for

Amount of Investment atDate OfDate Acquired Beginning of YearMat~ity

(d)

1,565,367

(c(b)

1,620,364

TOTAL 138,721,02601


Name of Respondent This wort Is:


4. and purpose of the pledge. 5. date of authorization, and case or docket number. 6. 7.

in column (f). 8. Report on Line 42, column (a) the TOTAL cost of Account 123.1

Equity in Subsidiary Earnin~s of Year

e)

Revenues for Year

(f)

174,829

174,829

18,957,077

164,505

164,505

-388

-388

556

556

-774

-774

66,553

66,553

23,604,931

Year/Period of ReportDate of Report (Mo, Da, Yr)

End of 2012/0404/15/2013

Line No.

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

An Original h A Resubmission

INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) (Continued)

For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee

If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission,

Report column (f) interest and dividend revenues form investments, including such revenues form securities disposed of during the year. In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (or

the other amount at which carried in the books of account if difference from cost) and the selling price thereof, not including interest adjustment includible

Amount of Investment at End ~f Year

g)

-11,823,407

4,429,379

26,800

28,134

54,934

40,694

3,306

44,000

30,002

79,710

109,712

11,398,128

-9,076,326

2,321,802

Gain or Loss from Investment Disp~sed of

h)

351,213,377


Name of Respondent Year/Period of Report Date of Report This ~ort Is: (1) An Original (Mo, Da. Yr)

Green Mountain Power Corporation 2012/04End of (2) DA Resubmission 04/15/2013

MATERIALS AND SUPPLIES

1. For Account 154. report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a);

estimates of amounts by function are acceptable. In column (d). designate the department or departments which use the class of material.

2. Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the

various accounts (operating expenses. clearing accounts. plant, etc.) affected debited or credited. Show separately debit or credits to stores expense clearing, if applicable.

Line Account Balance Balance Department or No. Beginning of Year End of Year Departments which

Use Material (a) (b) (c) (d)

1 Fuel Stock (Account 151) 3,350.626 4,915.371

2 Fuel Stock Expenses Undistributed (Account 152) 6,472 51.796

3 Residuals and Extracted Products (Account 153)

4 Plant Materials and Operating Supplies (Account 154)

5 Assigned to - Construction (Estimated) 3.561,897 8.627.214

6 Assigned to - Operations and Maintenance

7 Production Plant (Estimated) 365.323 884.842

8 Transmission Plant (Estimated) 45,665 8.627

9 Distribution Plant (Estimated) 593.650 1.539.848

10 Regional Transmission and Market Operation Plant

(Estimated)

11 Assigned to - Other (provide details in footnote)

12 TOTAL Account 154 (Enter Total of lines 5 thru 11) 4,566.535 11.060.531

13 Merchandise (Account 155)

14 Other Materials and Supplies (Account 156)

15 Nuclear Materials Held for Sale (Account 157) (Not

applic to Gas Util)

16 Stores Expense Undistributed (Account 163) 585,204 980,835

17

18

19

20 TOTAL Materials and Supplies (Per Balance Sheet) 8.508,837 17,008,533


I 2012/04

Year/Period of Report Name of Respondent This R~ort Is: Date of Report (1) ~An Original (Mo, Da, Yr)

Green Mountain Power Corporation End of(2) 0 A Resubmission 04/15/2013

Allowances (Accounts 158.1 and 158.2)

1. Report below the particulars (details) called for concerning allowances. 2. Report all acquisitions of allowances at cost. 3. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General Instruction No. 21 in the Uniform System of Accounts. 4. Report the allowances transactions by the period they are first eligible for use: the current year's allowances in columns (b)-(c), allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remaining succeeding years in columns (j)-(k).

I

5. Report on line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40.

Line S02 Allowances Inventory Current Year 2013 No. (Account 158.1) No. Am!. No. Am!.

(a) (b) (c) (d) (e)

1 Balance-Beginning of Year

2 3 Acquired During Year:

4 Issued (Less Withheld Allow)

5 Returned by EPA

6

7

8 PurchasesfTransfers:

9

10

11

12

13

14

15 Total

16

17 Relinquished During Year:

18 Charges to Account 509

19 Other:

20

21 Cost of SalesfTransfers:

22 23

24

25

26

27

28 Total

29 Balance-End of Year

30

31 Sales:

32 Net Sales Proceeds{Assoc. Co.)

33 Net Sales Proceeds (Other)

34 Gains

35 Losses

Allowances Withheld (Acct 158.2)


37 Add: Withheld by EPA

38 Deduct: Returned_b"--y_E_P_A +- -+- -+- +- -----j

39 Cost of Sales


41

42 Sales:

43 Net Sales Proceeds (Assoc. Co.)


45 Gains

46 Losses

FERC FORM NO.1 (ED. 12-95) Page 228a

Year/Period of ReportName of Respondent This ~ort Is: Date of Report (1) ~An Original (Mo, Da, Yr)

Green Mountain Power Corporation End of 2012/04(2) DA Resubmission 04/15/2013

Allowances (Accounts 158.1 and 158.2)

1. Report below the particulars (details) called for concerning allowances. 2. Report all acquisitions of allowances at cost. 3. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General Instruction No. 21 in the Uniform System of Accounts. 4. Report the allowances transactions by the period they are first eligible for use: the current year's allowances in columns (b)-(c), allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remaining succeeding years in columns (j)-(k). 5. Report on line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40.

Line NOx Allowances Inventory Current Year 2013 No. (Account 158.1) No. AmI. No. AmI.

(a) (b) (c) (d) (e)


2 3 Acquired During Year:

4 Issued (Less Withheld Allow)

5 Returned by EPA

6

7

8 Purchases/Transfers:

9

10

11

12

13

14

15 Total

16

17 Relinquished During Year:

18 Charges to Account 509

19 Other:

20

21 Cost of Sales/Transfers:

22 23

24

25

26 27 28 Total


30

31 Sales:

32 Net Sales Proceeds(Assoc. Co.)


34 Gains

35 Losses

Allowances Withheld (Acct 158.2)


37 Add: Withheld by EPA

38 Deduct: Returned by EPA

39 Cost of Sales


41

42 Sales:

43 Net Sales Proceeds (Assoc. Co.)


45 Gains

46 Losses

FERC FORM NO.1 (ED. 12-95) Page 228b



This ~ort Is: Date of Report (1) ~An Original (Mo, Da, Yr) (2) 0 A Resubmission 04/15/2013

Allowances (Accounts 158.1 and 158.2) (Continued)

End of 2012/04

6. Report on Lines 5 allowances returned by the EPA. Report on Line 39 the EPA's sales of the withheld allowances. Report on Lines 43-46 the net sales proceeds and gains/losses resulting from the EPA's sale or auction of the withheld allowances. 7. Report on Lines 8-14 the names of vendors/transferors of allowances acquire and identify associated companies (See "associated company" under "Definitions" in the Uniform System of Accounts). 8. Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of an identify associated companies. 9. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers. 10. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.

1---_-----;-.,-----__20,1_4_---:---:-__+-_---:--: ,20_1:...:.5---:---:__-+-__..,..,--_F_u..:..tu_r..:..e,Y_e_a_rs---:---,-__-+__--:-:-__T_o-,t~al_s_---:-___,_-----1Line No. Am!. No. Am!. No. Am!. No. Am!. No. (f) (g) (h) (i) Ul (k) (I) (m)




This ~ort Is: Date of Report (1) ~An Original (Mo, Da, Yr) (2) D A Resubmission 04/15/2013

Allowances (Accounts 158.1 and 158.2) (Continued)

End of 2012/04

6. Report on Lines 5 allowances returned by the EPA. Report on Line 39 the EPA's sales of the withheld allowances. Report on Lines 43-46 the net sales proceeds and gains/losses resulting from the EPA's sale or auction of the withheld allowances. 7. Report on Lines 8-14 the names of vendors/transferors of allowances acquire and identify associated companies (See "associated company" under "Definitions" in the Uniform System of Accounts). 8. Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of an identify associated companies. 9. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers. 10. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.

,,---_----:-.,----__2_0,1_4_--:---:-__+-_--:-:-__---,2-'-0:...-1_5----:-----;-__-+-__:-:-_F--.:u_tu:...-r,e,Y_e_ar_s--:--:-__-+__-,-,--__T_o..,.ta_ls_---;:----:-__-\ Line No. Am!. No. Am!. No. Amt. No. Am!. No. (f) (g) (h) (i) (j) (k) (I) (m)


This ~ort Is: (1) An Original (2) Ei A Resubmission

EXTRAORDINARY PROPERTY LOSSES (Account 182.1)

Total Losses Amount Recognisedof Loss During Year

(b) (c)

Year/Period of Report (Mo, Da, Yr) Date of Report

2012/04End of 04/15/2013

WRITTEN OFF DURING YEAR Balance at

Account End of YearAmountCharged (f)(d) (e)

Name of Respondent


Line Description of Extraordinary Loss No. [Include in the description the date of

Commissiog Authorization to use Acc 182.1 and period 0 amortization (mo, yr to mo, yr).]

(a)

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20 TOTAL


Date of ReportThis ~ort Is: (Mo, Da, Yr)(1) An Original 04/15/2013

UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.2)


Total Costs Amount

of Charges RecognisedDuring Year Account

Charged

(b) (c) (d)

Name of Respondent


Line Description of Unrecovered Plant No. and Regulatory Study Costs [Include

in the description of costs, the date of Commission Authorization to use Acc 182.2 and period of amortization (mo, yr to mo, yr)]

(a)

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49 TOTAL


End of 2012/04

WRITIEN OFF DURING YEAR Balance at

Amount End of Year

(e) (f)


Year/Period of ReportName of Respondent This ~ort Is: Date of Report (1) ~ An Original (Mo, Da, Yr) End of 2012/04Green Mountain Power Corporation (2) A Resubmission 04/15/2013

Transmission Service and Generation Interconnection Study Costs

1. Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and

generator interconnection studies. 2. List each study separately. 3. In column (a) provide the name of the study. 4. In column (b) report the cost incurred to perform the study at the end of period. 5. In column (c) report the account charged with the cost of the study. 6. In column (d) report the amounts received for reimbursement of the study costs at end of period. 7. In column (e) report the account credited with the reimbursement received for performing the study.

Line Reimbursements Account Credited Costs Incurred During Received During No. With Reimbursement Period Account Charged Description the Period

(d) (e)(a) (b) (c)

Transmission Studies

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21 Generation Studies

22 White River Jct. Solar

23 Charlotte Solar

24 VA Hospital - Fast Track Analysis

25 Marceau Solar-Fast Track

26 Marceau Solar-System Impact Study

27 Meach Cove Solar-Fast Track

28 Dynapower Battery Bank-Fast Track

29 VA Hospital - System Impact Study

30 Charlotte Solar-System Impact Stud

31 Cross Pollination

32 Ball Mountain Hydro Impact Study

33 Townshend Hydro Impact Study

34 Chester Solar Impact Study

35 Bennington Solar Impact Study

36 Clarke Solar Impact Study

37 Bennington Solar Facilities Study

38 Carthusian Hydro Impact Study

39 Limerick Road Solar Impact Study

40 Bennington Solar Facility Study

~---------

~-----------

15,664 7,500

15,230 107 39,000 107,451

291 107 300 451

1,521 107 300 451

8,567 107 23,000 107,451

1,842 107 300 451

1,015 107 300 451

253 107 10,220 107,451

3,748 107

42,029 107

3,794 186

2,900 186

2,330 186

3,803 186,920 3,625 186,451,235

9,899 186

240 186

10,000 235

10,000 235

6,000 235

FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231

Year/Period of Report Name of Respondent This ~ort Is: Date of Report (1) ~ An Original (Mo, Da, Yr) End of 2012/04Green Mountain Power Corporation (2) A Resubmission 04/15/2013

Transmission Service and Generation Interconnection Study Costs (continued)

Line Costs Incurred During

No. PeriodDescription (b)(a)

Account Charged (c)

Reimbursements Received During

the Period (d)

Account Credited With Reimbursement

(e) ~---------

1 Transmission Studies

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21 Generation Studies ~---------

22 Chester Solar Facilities Study 8,000 235

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

r-r- __ r-__•• ... n .. , .. r-,,,,, ,...,. '''Ir-,., ,.,."" n..,\

Year/Period of ReportName of Respondent This ~ort Is: Date of Report (1 ) ~ An Original (Mo. Da, Yr) End of 2012/04Green Mountain Power Corporation (2) A Resubmission 04/15/2013

OTHER REGULATORY ASSETS Account 182.3

1. Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable. 2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes. 3. For Regulatory Assets being amortized, show period of amortization. Line Description and Purpose of No. Other Regulatory Assets

(a)

1 Future revenue due to income taxes

2 Current revenue due to income taxes

3 Asset Retirement

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44 TOTAL:

CREDITSBalance at Beginning Balance at end ofDebits Written off During the Written off Duringof Current Current QuarterlYear Quarter !Year Account the Period AmountQuarterlYear

Charged (d)

185,077 244 35,996 149.081

105,310 105.310

1.308,361 694,330 various 7,738 1,994,953

(b) (c) (e) (f)

1,598,748 694.330 43,734 2,249,344


Name of Respondent This ~ort Is: (1)

Green Mountain Power Corporation (2)

MISCELLANEOUS DEFFERED DEBITS (Account 186)

1. Report below the particulars (details) called for concerning miscellaneous deferred debits.

2. For any deferred debit being amortized, show period of amortization in column (a) 3. Minor item (1 % of the Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) may be grouped by

classes.

Description of Miscellaneous Balance at

No. Line

Deferred Debits Beginning of Year

(a) (b)

1 FAS 133 (Note 1) 5.297,910

2 Efficiency fund payments 5.835,217

3 Pension Funding Offset 37,783,701

4 Pine Street 13,608,016 5 Reg Asset Low Income 775,078 6 Property Damage 85,015 7 Storm Deferral 1,368,699

8 CEED Fund

9 JT Owned Def. 10 Goodwill - Not in Rate Base 11 Dismantle Conn Yankee 12 Dismantle Maine Yankee 13 Dismantle Yankee Atomic

14 SFAS109 regulatory assets-amort

15 2011 Millstone outage enrgy/cap

16 Asset retirement oblig. #7321 17 SFAS1580PEB transition proj v.

18 Def. Tree Trimming/Pole

19 Meters retired due to smart grd

20 2011 Esam costs 12 months

21 PCAM Under collection 22 VTEL Prepayment 23 Exogenous Event Costs

24

25

26 27

28 29

30 31 32

33

34 35 36 37

38 39 40 41 42

43

44

45

46

47 Misc. Work in Progress 53,956

Deferred Regulatory Comm.

Account Char~ed

(d

404

404

404

404

vanous

253

253

253

varoius

555, 560 407.3

various 182

various 407.3

48 Expenses (See pages 350 - 351)

49 TOTAL 64,807,592

An Original DA Resubmission

Debits

(c)

488,313

1,073,636

48,060,442 1,447,187

2,482,912

6,000,000 2,405,906

1,250,000

2,856,200

280,749

1,071,508

4,651,463

321,966 433,330

2,210,072 219,330

1,719,685 5,573,631

538,963

970,300 3,979,553


CREDITS

Amount

(e)


End of 2012/04

Balance at End of Year

(f) 5,786,223

6,218,805

85,844,143 690,048

14,386,722

100,010

668,481 675,068

2,457,701 110,226

299

6,000,000

1,646,661

1,368,400

759,245 1,250,000

2,638,060

60,229

218,140 220,520

102,813 968,695

15,920 4,635,543 160,983 160,983

7,738 425,592 81,408 2,128,664 54,832 164,498 66,092 1,653,593

1,786,021 3,787,610

538,963 970,300

3,979,553

476,184

143,779,489


Year/Period of ReportName of Respondent Date of Report This ~ort Is: (1) An Original (Mo, Da, Yr) 2012/04End of Green Mountain Power Corporation

04/15/2013(2) Fi A Resubmission

ACCUMULATED DEFERRED INCOME TAXES (Account 190)

1. Report the information called for below concerning the respondent's accounting for deferred income taxes. 2. At Other (Specify), include deferrals relating to other income and deductions.

Line Description and Location No.

(a)

1 Electric

2 CAFC

3 Power Supply Derivative ASC815

4 Self Insurance & other reserves

5 Deferred Comp.lPost Ret Health ASC 715

6 Unfunded Def Income Taxes

7 Other

8 TOTAL Electric (Enter Total of lines 2 thru 7)

9 Gas

10 ASC450 reversal

11

12 envirionmental

13

14

15 Other

16 TOTAL Gas (Enter Total of lines 10 thru 15

17 Other (Specify)

18 TOTAL (Acct 190) (Total of lines 8, 16 and 17)

amounts acquired during the CVPS merger =

of Year of Year (b) (c)~

5,012,483

2,147,391

270,163

1,490,720

1,483,488

17,577,740

27,981,985

5,785,786

3,257,013

3,471,921

15,526,071

1,182,102

13,659,872

42,882,765

27,981,985

Notes

35J88~,471

1,575,097

3,721,706

5,296,803

48,179,568


Year/Period of Report Date of ReportName of Respondent This ~ort Is: (Mo, Da, Yr) (1) An Original 2012/04End ofGreen Mountain Power Corporation 04/15/2013(2) o A Resubmission

CAPITAL STOCKS (Account 201 and 204)

1. Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate series of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reporting requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (i.e., year and company title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible. 2. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year.

Class and Series of Stock andLine Name of Stock Series No.

(a)

1 ACCOUNT 201

2 * COMMON STOCK

3 TOTAL COM

4

5 See Page 102 for a discussion of control I

6 over the respondent and common stock ownership

7 review of merger documents indicated effectiver

8 with merger only 100 shares issued and o/s

9 activity and balance reflect transfer to paid

10 in capital

11

12

13

14

15

16

17

18

19

20

21

22 NOTE:AII treasury stock was retired subsequent

23 to the acquistion of GMP by NNEEC.

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

Number of shares Authorized by Charter

(b)

100

100

Call Price at Par or Stated End of Year Value per share

(d)(c)

3.33


Year/Period of Report Name of Respondent Date of Report This ~ort Is: (1) An Original (Mo, Da, Yr) 2012/Q4End ofGreen Mountain Power Corporation 04/15/2013

CAPITAL STOCKS (Account 201 and 204) (Continued)

(2) n A Resubmission

3. Give particulars (details) concerning shares of any class and series of stock authorized to be issued by a regulatory commission which have not yet been issued. 4. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or non-cumulative. 5. State in a footnote if any capital stock which has been nominally issued is nominally outstanding at end of year. Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which is pledged, stating name of pledgee and purposes of pledge.

OUTSTANDING PER BALANCE SHEET (Total amount outstanding without reduction

for amounts held by respondent) Shares Amount

(e) (f)

100 333

100 333

100 333

HELD BY RESPONDENT Line

AS REACQUIRED STOCK (Account 217)

Shares (g)

Cost (h)

No.

Shares

IN SINKING AND OTHER FUNDS

Amount (i) (j)

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

Year/Period of Report Date of Report Name of Respondent This 00rt Is: (Mo, Da, Yr) (1) An Original 2012/04End of Green Mountain Power Corporation 04/15/2013(2) FiA Resubmission

OTHER PAID-IN CAPITAL (Accounts 208-211, inc.)

Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide a subheading for each account and show a total for the account, as well as total of all accounts for reconciliation with balance sheet, Page 112. Add more columns for any account if deemed necessary. Explain changes made in any account during the year and give the accounting entries effecting such change. (a) Donations Received from Stockholders (Account 208)-State amount and give brief explanation of the origin and purpose of each donation. (b) Reduction in Par or Stated value of Capital Stock (Account 209): State amount and give brief explanation of the capital change which gave rise to amounts reported under this caption including identification with the class and series of stock to which related. (c) Gain on Resale or Cancellation of Reacquired Capital Stock (Account 210): Report balance at beginning of year, credits, debits, and balance at end of year with a designation of the nature of each credit and debit identified by the class and series of stock to which related. (d) Miscellaneous Paid-in Capital (Account 211 )-Classify amounts included in this account according to captions which, together with brief explanations, disclose the general nature of the transactions which gave rise to the reported amounts.

I

I L,lneNo.

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

ICem A('g)unta)

Account 211: 114,781,543

Amount established under approval plan of recapitalization

effective July 1951, in compliance with order of the Federal Power Com

dated April 19, 1950.

Additional investment by Parent October 2010 20,000,000

Additional investment by Parent October 2011 10,000,000

Additional investment by Parent in 2012 75,000,000

Acquired in merger with CVPS October 1,2012

21200 64,609,569

21110 4,888,795

21421 -105,889

21420 -4,194,915

20710 104,152,125

21600 110,721,753

TOTAL 499,852,981


Year/Period of ReportDate of ReportName of Respondent This ~ort Is: (Mo, Da, Yr)(1) An Original End of 2012/04Green Mountain Power Corporation 04/15/2013

CAPITAL STOCK EXPENSE (Account 214)


1. Report the balance at end of the year of discount on capital stock for each class and series of capital stock. 2. If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars (details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.

Balance at End of YearLine Class and Series of Stock (b)(a)

1

No.

common stock

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22 TOTAL


Year/Period of Report Date of Report Name of Respondent This mort Is: (Mo, Da, Yr)(1) An Original 2012/Q4End ofGreen Mountain Power Corporation 04/15/2013

LONG-TERM DEBT (Account 221, 222, 223 and 224)

(2) FiA Resubmission

1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222, Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt. 2. In column (a), for new issues, give Commission authorization numbers and dates. 3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds. 4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate demand notes as such. Include in column (a) names of associated companies from which advances were received. 5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were

issued. 6. In column (b) show the principal amount of bonds or other long-term debt originally issued. 7. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued. 8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount. Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted. 9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with issues redeemed during the year. Also, give in a footnote the date of the Commission's authorization of treatment other than as specified by the Uniform System of Accounts.

Total expense, No.

Principal Amount Line Class and Series of Obligation, Coupon Rate Premium or Discount Of Debt issued(For new issue, give commission Authorization numbers and dates)

(c)(b)(a)

1 ACCOUNT 221 BONDS

2 First Mortgage:

186,7299,000,0003 9.64 % Bonds

13,000,000 214,3544 8.65 % Bonds

15,000,000 248,0005 6.70 % Bonds

462,542

7 6.53% Bonds (8/06)

42,000,0006 6.04 % Bonds

30,000,000 242,645

8 6.17% Bonds 226,933

9 5.98% Bonds

16,000,000

191,432

10 6.00% Bonds

15,000,000

989,241

11

29.765.046

445,942

12 4.61%Bonds

4.56% Bonds 50,000.000

210,295

13 3.99% Bonds

25,000.000

85,000,000

178,357

15 6.90% Bonds, Series 00

14 8.91 % Bonds,Series JJ 15,000,000

188,420

16 5.72% Bonds, Series TT-PSB Docket No. 6943 Dated May 7, 2004

17,500,000

728,848

17 6.83% Bonds, Series UU - PSB Docket No. 7421 dated April 23, 2008

55.000,000

60,000,000 955,339I

18 5% Vermont Economic Development Authority Bonds PSB Dkt NO.7620 dtd JUly 14 2010 30.000,000 796,059

19 5.89% Bonds Series WW - PSB Docket No. 7682 dated Jun 15, 2011 40,000,000 389,116

20 Consolidationi of bonds - merger 630,084

21

22

23

24

25

26

27

28

29

30

31

32

33 TOTAL 547,265,046 7,284,336


Name of Respondent This ~ort Is' Date of Report Year/Period of Report

Green Mountain Power Corporation (1) An Onglnal (Mo, Da, Yr) End of 2012/04 (2) n A Resubmisslon 04/15/2013

LONG-TERM DEBT (Account 221,222,223 and 224) (Continued)

10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years. 11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium

on Debt Credit.

12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term

advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid during year. Give Commission authorization numbers and dates. 13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee

and purpose of the pledge. 14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of

year, describe such securities in a footnote. 15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on

Long-Term Debt and Account 430, Interest on Debt to Associated Companies. 16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.

AMORTIZATION PERIOD Nominal Date Date of

of Issue Maturity Date From Date To (d) (e) (f) (g)

090190 090120 090190 090120

031192 031122 031192 031122

110193 110118 110193 110118

121602 120117 121602 120117

8/1/06I

8/1/36 8/1/06 8/1/36

12/15/07 12/1/37 12/15/07 12/1/37

4/16/2009 4/16/2019 4/16/2009 4/16/2019

4/01/2010 4/01/2035 4/01/2010 04/01/2035

11/18/2011 11/18/2041 11/18/2011 11/18/2041

11/18/2011 11/18/2041 11/18/2011 11/18/2041

12/5/2012 12/5/2042 12/01/2012 12/01/2042

12/15/1991 12/15/2031 01101/1992 12/15/2031

12/15/1993 12/15/2023 02/01/1994 12/15/2023

07115/2004 06/15/2019 08/01/2004 06/01/2019

05/15/2008 05/15/2028 06/01/2008 05/01/2028

12/02/2010 12/15/2020 12/02/2010 12/15/2020

06/15/2011 06/15/2041 06/15/2011 06/15/2041

10/01/2012 Various 10/1/2012 10/01/2029

UUlslanOln§(Total amount outstan ing without

reduction for amounts held by reSp(\ndent)

h)

I Interest for Yea r Amount

(i)

9,000,000 867,600

12,500,000 1,084,854

15,000,000 1,005,000

30,000,000 2,144,200

30,000,000 1,959,000

16,000,000 987,202

15,000,000 897,000

28,490,046 1,309,887

50,000,000 2,280,000

25,000,000 864.378

85,000,000 241,586

15,000,000 334,125

17,500,000 301,875

55,000,000 786,500

60,000,000 1,024,500

30,000,000 375,000

40,000,000 589,000

533,490,046 17.051,707

Line No.

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33


Year/Period of Report Date of Report Name of Respondent This ~ort Is: (Mo, Da, Yr)(1) An Original 2012/04End of Green Mountain Power Corporation 04/15/2013

RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES


1. Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show computation of such tax accruals. Include in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for the year. Submit a reconciliation even though there is no taxable income for the year. Indicate clearly the nature of each reconciling amount. 2. If the utility is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net income as if a separate return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group member, tax assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members. 3. A substitute page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements of the above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.

AmountParticulars (Details) Line (b)

1 Net Income for the Year (Page 117)

(a)No. 28,570,336

2

3

4 Taxable Income Not Reported on Books

5 CAFC 2,997,037

6 Power supply adjustor -8,604,202

7 Environmental reserve 892,876

8 Gain (loss) on dispositions -360,000

9 Deductions Recorded on Books Not Deducted for Return

10 Fedeeral and state income taxes 18,102,774

11 compensation and benefits 788,335

12 deferred credits -1,902,015

13 lobbying meals officers life penalties -120,964

14 Income Recorded on Books Not Included in Return

15 Undistributed earnings of affiliates 16,364,254

16 production deduction 300,000

17 medicare reimbursements 89,695

18

Deductions on Return Not Charged Against Book Income 19

depreciation, repairs and other fixed asset differences

21

20

other

22 deferred charges

23 nondeductible merger expenses

24 Charitable contributions carryover

25 Dividends received deduction

26 state income tax expense

27 Federal Tax Net Income

28 Show Computation of Tax:

29 taxable income=-151 0361 0

30 times 35%

31 state tax expense

32 total current tax expense

33

34

35

36

37

38

39

40

41

42

43

44

30,701,016

4,419

8,953,718

-761,507

326,716

894,707

-1,405,232

-15,103,610

-5,286,263

-1,405,232

-6,691,495


Year/Period of ReportDate of ReportName of Respondent This 00rt Is: (1) An Original (Mo, Da, Yr)

End ofGreen Mountain Power Corporation 04/15/2013

TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR


1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during

the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged.

actual, or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.

2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.)

Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.

3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,

(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other

than accrued and prepaid tax accounts.

4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.

JaxesLine I~x.esBALANCE AT BEGINNING OF YEAR Kind of Tax aidChargedNo. (See instruction 5) Taxes Accrued Prepaid Taxes Dunng During

(Account 236) (Include In Account 165) Year Year (a) (b) (d)(c) (e)

I

1 Federal

2 Income

3 Income 775,818 -7,104,357 440,000

4 Unemployment -29,689 1,994 12.354

5 Fica 47,345 902,149 1,790,747

6

7 State of VT

8 Income -54,931 421,122 885,000

9 Unemployment 18,101 12,977 110,421

10 Gross Revenue 1,524,919 2,448,611

11

3,463,326

Hazardous Waste 22,364

12 Sales tax

22,364

80,000 80,000

13 State of MA

14 Income -44,308 -8,200 10,000

15I

State of ME16 16,149 -60 2,000

17 Income

18

19

20

21

22 Property Taxes

23 Vermont 924,173 10,135,642 12,260,755

24 Massachusetts 112,269 112,269

25 Maine 45,566 37,043

26 Connecticut 52,896 42,619

27 New Hampshire 27,891 7,219

28 New York 12,666

29

30

31

32

33

34

35

36

37

38

39

40

41 TOTAL 924,1732,253,404 8,178,245 18,261,402

2012/04

If the

Adjustments

(f)

12,330,085

-17,715,972

40,679

793,195

391,569

86,662

1,088,773

3,160,649

-8,558

-112,788

-1,995

-25,974

26,325


Name of Respondent


TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)

Year/Period of ReportDate of Report This ~ort Is: (Mo, Da, Yr) (1) An Original 2012/Q4End of 04/15/2013(2) riA Resubmission

5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year, identifying the year in column (a). 6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a footnote. Designate debit adjustments by parentheses. 7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending transmittal of such taxes to the taxing authority. 8. Report in columns (i) through (I) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.1 pertaining to electric operations. Report in column (I) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and amounts charged to Accounts 408.2 and 409.2. Also shown in column (I) the taxes charged to utility plant or other balance sheet accounts. 9. For any tax apportioned to more than one utility department or account. state in a footnote the basis (necessity) of apportioning such tax.

DISTRIBUTiON OF TAXES CHARGED BALANCE AT END OF YEAR Line Adjustments to Ret. Prepaid Taxes Extraordinary Items (Taxes accrued Electric No.OtherEarnings (Account 439) (Account 408.1, 409.1) (Account 409.3) (Inc/. in Account 165) Acco~nt 236)

(i)

1

12,330,085

(i) (k)g) (h) U)

2

175,659 -7,104,357 3

631 4

-48,058

1,994

902,149 5

6

7

-127,240 421,122 8

7,319 12,977 9

3,628,407 3,463,326 10

22,364 11

80,000 12

13

-62,508 -8,200 14

15

14,089 -60 16

17

18

19

20

21

22

229,085 1,743,152 10,135,642 23

112,269 24

35 45,566 25

102,511 52,896 26

-18,677 27,891 27

13,308 12,666 28

29

30

31

32

33

34

35

36

37

38

39

40

3,817,384 14,170,414 8,178,245 41 I


Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and nonutilityoperations. Explain by footnote any correction adjustments to the account balance shown in column (g).lnciude in column (i) the average period over which the tax credits are amortized. Line Account No. SUbdl~\sions

1 Electric Utility

23%

34%

47%

510%

6

7

8 TOTAL

9 Other (List separately

and show 3%, 4%, 7%, 10% and TOTAL)

Balance at Beginning of ~)ar

Page 266

1,973,195

Name of Respondent This ~ort Is: (1) ~ An Original

Green Mountain Power Corporation (2) A Resubmission

ACCUMULA ED DEFERRED INVESTMENT TAX

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

30

31 32

33 34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

FERC FORM NO.1 (ED. 12-89)

Year/Period of ReportDate of Report (Mo, Da, Yr) End of 2012/0404/15/2013

REDITS (Account 255)

Name of Respondent This ~ort Is: (1) An Original

Green Mountain Power Corporation (2) D A Resubmission

FERRED INVESTMENT TAX CRED ACCUMULATED D

Year/Period of Report Date of Report (Mo, Da, Yr) End of 2012/04 04/15/2013

TS (Account 255) (continued)

LineADJUSTMENT EXPLANATION of Year of AI ocatlon No.to Income

h i 1 1 ~

2,485,611

912,247

694,225

4,092,083

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48


Year/Period of ReportDate of ReportName of Respondent This mort Is: (Mo, Da, Yr) (1) An Original 2012/04End ofGreen Mountain Power Corporation 04/15/2013(2) F5 A Resubmission

OTHER DEFFERED CREDITS (Account 253)

1. Report below the particulars (details) called for concerning other deferred credits.

2. For any deferred credit being amortized, show the period of amortization.

3. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $100,000, whichever is greater) may be grouped by classes.

Description and Other Line Deferred Credits No.

(a)

1

2

3

4 Employee Deferred Bonuses

5 Environmental reserve

6 Minimum Pension Acct #'s

7 Deferred Taxes

8 Derivative Liability

9 Deferred Revenue S02 Emissions

10 Vt Tax Charge off

11 VY NEIL Refunds

12 Earnings Sharing

13 Vermont Yankee Outage

14 Power Adjustor

15 Warmth Liabilty

16 Low Income Discount

17 Efficiency Fund

18 Unclaimed property

19 Excess Depreciation in Rates

20 Misc SERP - current portion

21 VMPD Rate Phase In

22 FAS 5 Loss RS2 LT

23 Accrued State Tax Long Term

24 Elctricity Assistance Program

25 Equity owned dismantle Maine Yanke

26 Equity owned dismantle Yankee Atom

27 Millstone ARO

28

29 Deferred Credit pending approval

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

TOTAL47

DEBITSBalance at Beginning of Year

(b)

Contra Account

(c)

270,882

4,696,110

33,141,531

200

98,865

570,000

223,299

191,707

3,949,177

257,404

21,474

1,700,250

577,850

Amount

(d)

270,882

33,724,612

24,716

570,000

59,000

191,707

987,294

17,133,882

11,939

1,700,250

80,882

298,979

23,275

504,046

102,812

Credits

(e)


(f)

248,482

892,876

75,864,112

166,370

248,482

5,588,986

75,281,031

166,570

1,580,564

336,900

74,149

1,580,564

501,199

15,246,055

2,961,883

-1,630,423

32,784 42,319

123,598

498,554

2,690,813

272,267

2,281,186

660,257

4,544,662

701,448

417,672

2,391,834

272,267

-23,275

1,777,140

557,445

4,544,662

718,625 718,625

45,698,749 55,684,276 106,158,105 96,172,578


Year/Period of ReportName of Respondent This R~ort Is: Date of Report (1) ~ An Original (Mo, Da, Yr) End of 2012/04Green Mountain Power Corporation (2) A Resubmission 04/15/2013

ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED AMORTIZATION PROPERTY (Account 281)

1. Report the information called for below concerning the respondent's accounting for deferred income taxes rating to amortizable

property.

2. For other (Specify),include deferrals relating to other income and deductions.

CHANGES DURING YEAR Line Account Balance at

Amounts Debited Beginning of YearNo. to Account 410.1

(b) (c)

1 Accelerated Amortization (Account 281)

2

(a)

Electric

3 Defense Facilities

4 Pollution Control Facilities


6

7

8 TOTAL Electric (Enter Total of lines 3 thru 7)

9 Gas

10 Defense Facilities

11 Pollution Control Facilities


13

14

15 TOTAL Gas (Enter Total of lines 10 thru 14)

16

17 TOTAL (Acet 281) (Total of 8, 15 and 16)

18 Classification of TOTAL

19 Federallneome Tax

20 State Income Tax

21 Loeallncome Tax

NOTES

Amounts Credited to Account 411.1

(d)


Name of Respondent




ACCUMULATED DEFERRED INCOME TAXES _ ACCELERATED AMORTIZATION PROPERTY (Account 281) (Continued)

3. Use footnotes as required.

CHANGES DURING YEAR Amounts Debited Amounts Credited to Account 410.2 to Account 411.2

ADJUSTMENTS

Debits Amount


Line No.

3

4

5

6

7

8

12

13

14

15

16

17

19

20

21

NOTES (Continued)


YearlPeriod of Report Name of Respondent This ~ort Is: Date of Report (1) ~An Original (Mo, Da, Yr) End of 2012/04Green Mountain Power Corporation (2) A Resubmission 04/15/2013

ACCUMULATED DEFFERED INCOME TAXES - OTHER PROPERTY (Account 282)

1. Report the information called for below concerning the respondent's accounting for deferred income taxes rating to property not

subject to accelerated amortization


CHANGES DURING YEAR Line Account Balance at

Amounts Credited Amounts Debited Beginning of Year No. to Account 411.1 to Account 410.1

(c) (d)

1 Account 282

2 Electric

(a) (b)

76,019,350 16,530,226

3 Gas

4

5 TOTAL (Enter Total of lines 2 thru 4) 16,530,22676,019,350

6

7

8

9 TOTAL Account 282 (Enter Total of lines 5 thru 76,019,350 16,530,226

10 Classification ofTOTAL

11 Federal Income Tax 65,556,627 14,289,207

12 State Income Tax 10,462,723 2,241,019

13 Local Income Tax

NOTES


Name of Respondent




End of 2012/04

ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282) (Continued)


CHANGES DURING YEAR

Amounts Debited Amounts Credited to Account 410.2 to Account 411.2

ADJUSTMENTS

Debits

various

NOTES (Continued)

Amount


Line No.

5

6

7

12

13


Year/Period of ReportName of Respondent This ~ort Is: Date of Report (1) ~An Original (Mo, Da, Yr) End of 2012/04Green Mountain Power Corporation (2) A Resubmission 04/15/2013

ACCUMULATED DEFFERED INCOME TAXES - OTHER (Account 283)

1. Report the information called for below concerning the respondent's accounting for deferred income taxes relating to amounts

recorded in Account 283.


Line Account No.

(a)

Account 283

2 Electric

3 Transco book tax difference

CHANGES DURING YEAR Amounts Debited Amounts Credited to Account 410.1 to Account 411.1

(c) d)

6,677,42023,068,363

4 Demand Side Management

5 Other Deferred Charges

6 Other 5,588,384 -2,870,187

7 Efficiency fund reg asset 2,679,338 114,934

8

9 TOTAL Electric (Total of lines 3 thru 8) 31,336,085 3,922,167

10 Gas

11

12

13

14

15

16

17 TOTAL Gas (Total of lines 11 thru 16)

18 Non Utility -12,700

19 TOTAL (Acct 283) (Enter Total of lines 9,17 and 18) 3,922,167

20

31,323,385

Classification of TOTAL

21 Federal Income Tax 24,164,991 2,145,377

22 State Income Tax 7,158,394 1,776,790

23 Local Income Tax L f-------l-------------..J....----------j

NOTES


Name of Respondent


This ~ort Is: Date of Report (1) ~An Original (Mo, Da, Yr) (2) A Resubmission 04/15/2013


End of 2012/04

ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283) (Continued)

3. Provide in the space below explanations for Page 276 and 277. Include amounts relating to insignificant items listed under Other.


Line No.


(k)

ADJUSTMENTSCHANGES DURING YEAR Amounts Debited Amounts Credited to Account 410.2 to Account 411.2

various 30,700,762 60,446,545

4

5

various 21,690,309 24,408,506 6

2,794,272 7

8

52,391,071 87,649,323 9

11

12

13

14

15

16

17

-12,700 18

52,391,071 87,636,623

NOTES (Continued)

various

various

43,273,872

9,117,199

69,584,240

18,052,383

21

22

23


Name of Respondent


1. Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket

applicable.

2. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less),

by classes.

3. For Regulatory Liabilities being amortized, show period of amortization.

Description and Purpose of

No. Line


(a)

1 Future Revenue Due to Income Taxes

2 Current Revenue Due to Income Taxes

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

I 34

35

36

37

38

39

40

411 TOTAL I I

This ~ort Is: (1) An Original

(2) DA Resubmission


OTHER REGULATORY LIABILITIES (Account 254)

DEBITS

Amount

Balance at Begining of Current

QuarterlYear Account Credited

(b) (c)

988,720 283

214,027 283

1 11,202,747

(d)

4,257

16,388

20,645 I


End of 2012/Q4

number, if

may be grouped

Balance at End of Current

Credits QuarterlYear

(f)(e)

984,463

197,639

1,182,102

FERC FORM NO. 1/3·Q (REV 02-04) Page 278

Year/Period of ReportDate of ReportName of Respondent This 00rt Is: (Mo, Da, Yr)(1) An Original 2012/04End ofGreen Mountain Power Corporation 04/15/2013

ELECTRIC OPERATING REVENUES (Account 400)


1. The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (f), and (g). Unbilled revenues and MWH related to unbilled revenues need not be reported separately as required in the annual version of these pages. 2. Report below operating revenues for each prescribed account, and manufactured gas revenues in total 3. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accounts; except that where separate meter readings are added for billing purposes, one customer should be counted for each group of meters added. The -average number of customers means the average of twelve figures at the close of each month. 4. If increases or decreases from previous period (columns (c),(e), and (g)), are not derived from previously reported figures, explain any inconsistencies in a footnote. 5. Disclose amounts of $250,000 or greater in a footnote for accounts 451,456, and 457.2.

Operating RevenuesOperating Revenues Year

No.

Line Title of Account Previous year (no Quarterly)to Date Quarterly/Annual

(c

1

(a) (b)

Sales of Electricity

(440) Residential Sales 130,153,485 93,847,3632

3 (442) Commercial and Industrial Sales

4 120,619,471Small (or Comm.) (See Instr. 4)

70,846,2485 Large (or Ind.) (See Instr. 4)

1,600,1176 (444) Public Street and Highway Lighting I

1,142(445) Other Sales to Public Authorities7

(446) Sales to Railroads and Railways8

(448) Interdepartmental Sales9

10 TOTAL Sales to Ultimate Consumers 323,220,463

11 (447) Sales for Resale 11,386,550

12 TOTAL Sales of Electricity 334,607,013

13 (Less) (449.1) Provision for Rate Refunds -10,266,934

344,873,94714 TOTAL Revenues Net of Prov. for Refunds

90,740,066

57,619,668

1,215,815

954

243,423,866

11,363,369

254,787,235

4,514,588

250,272,647

15 Other Operating Revenues

16 (450) Forfeited Discounts 390,595

17 (451) Miscellaneous Service Revenues 4.455,231

18 (453) Sales of Water and Water Power

19 (454) Rent from Electric Property 3,981,982

20 (455) Interdepartmental Rents

21 (456) Other Electric Revenues 8,730,379

22 (456.1) Revenues from Transmission of Electricity of Others 4,663,125

23 (457.1) Regional Control Service Revenues

24 (457.2) Miscellaneous Revenues

25 (415) Business Development Revenues (Contract Work

26 TOTAL Other Operating Revenues 22,221,312

27 TOTAL Electric Operating Revenues 367,095,259

412,913

1,079,721

415,382

886,040

2,222,622

5,016,678

255,289,325

FERC FORM NO, 1/3·Q (REV. 12-05) Page 300

Name of Respondent




End of 2012/04

ELECTRIC OPERATING REVENUES (Account 400)

6. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by the respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of classification in a footnote.) 7. See pages 108-109, Important Changes During Period, for important new territory added and important rate increase or decreases. 8. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbilled revenue by accounts. 9. Include unmetered sales. Provide details of such Sales in a footnote.

AVG.NO. CUSTOMERS PER MONTH MEGAWATT HOURS SOLD Line l--y:7e-a-rC--to--;o::-a-,.te-o::::-ua-rt;-e""'rly-,/A:-n-n-u""Cal,-----,---A:-m-o-u-ntC:P=-re-v7io-u-s-ye-a-r-;-(n-o--;O=-u-a""'rte-r;-ly;-)---+-""C=-u-r-re-n-'-t-"Y"C'e-a-r-'-(-no---=O;-u-a-rt-'-e--:rl-y;-)--'-::P-re-v-cio-u-s-YC-:-e-ar----:""(n-o-O=-u-ar-'-te-r-cly--:)-+ No.

(0 ~)

890,741

745,480

5,869

59

694,268

617,424

4,866

64

20,529

38

97

14,603

29

54

4

5

6

7

8

2,428,318

302,404

2,730,722

2,730,722

1,895,087

262,764

2,157,851

2,157,851

136,210

136,210

136,210

95,542

95,542

95,542

9

10

11

12

13

14

Line 12, column (b) includes $ 7,549,112 of unbilled revenues.

Line 12, column (d) includes 49,433 MWH relating to unbilled revenues


Year/Period of ReportName of Respondent Date of ReportThis wort Is: (1) An Original (Mo, Da, Yr) 2012/Q4End of Green Mountain Power Corporation 04/15/2013

REGIONAL TRANSMISSION SERVICE REVENUES (Account 457.1)

(2) FiA Resubmission

1. The respondent shall report below the revenue collected for each service (i.e., control area administration, market administration, etc.) performed pursuant to a Commission approved tariff. All amounts separately billed must be detailed below.

Line Balance at End ofBalance at End of Balance at End ofBalance at End ofDescription of Service No. YearQuarter 1 Quarter 2 Quarter 3

(a) (e)

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

(d)(b) (c)

TOTAL46

FERC FORM NO. 1/3-0 (NEW. 12-05) Page 302

Year/Period of ReportDate of Report Name of Respondent This ~ort Is: (Mo, Da, Yr) (1) An Original 2012/04End of Green Mountain Power Corporation 04/15/2013

SALES OF ELECTRICITY BY RATE SCHEDULES


1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311. 2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. 3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. 4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). 5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. 6. Report amount of unbilled revenue as of end of year for each applicable revenue account SUbheading.

Line I\lumoer ana Ime or Kale scneaUie Kevenue Average Numoer IVlvvn ~ola K~~~~eo~er of C~~)omersNo. (f)

1 Account 440-Residential Sales

2 Rate 01 Domestic

(a) (b) (c)

506,216 85,234,419 82,210

I:SWh,ot ::>alesPer 7~stomer

6,158

7,463

7,569

7,246

11,249

6,127

10,243

6,109

8,253

68,527

6,559

13,396

4,062

14,187

22,333

314,052

3,584

1,455,222

725,000

29,133

3,000

525,000

42,517

6,841,107

35,000

101,031,600

9.880,000

7.771.200

18,637,000

17,22E (

17,57E

01684

3 Rate 02 Ripple 0.1652

4 Rate 03 General

44,345 7,326,316 5,942

0.1650

5 Rate 04 Mobile Home

79,373 13,093,000 10,486

26,666 4,419,933 3,680 0.1658

6 Rate 05 Farm 7,132 1,134,700 634 0.1591

7 Rate 08 W/Water Heating 88,154 14,046,184 14.388 0.1593

8 Rate 11/12 Option Time of Use 0.1523

9 Rate 16/18 Area Lighting

18,069 2,751,448 1,764

782 207,431 128 0.2653

10 Rate 22/23 Storage Heating 0.1607

11 Rate 61/62 Time of Use

3,846 617,950 466

11,581 1,467,556 169 0.1267

12 Rate GR Green Power 87,549

13 Low Income 5 739 0.1478

14 Power Adjuster -233,740

15 Total 786,169 130,153,485 119,867 0.1656

16 Account 442 Comm & Ind

17 Rate 06 General 240,456 37,379,847 17,950 0.1555

18 Rate 15 Cable TV 2,799 443,608 689 0.1585

19 Rate 16/18 Area Lighting 4,483 1,098,653 316 0.2451

20 Rate 20/21 Option Time of Use 268 41,361 12 0.1543

21 Rate 65/66 Time of Use 574,716 73,644,481 1,830 0.1281

22 Rate GC/CI Green Power 7,807

23 3-0ff Pk Water Heating 319 33,737 89 0.1058

24 4-Primary Service 65,485 7,913,761 45 0.1208

25 5-Transmission Service 725 83,110 1 0.1146

26 13-Space Htg Elec Load Mgmt 437 47,326 15 0.1083

27 15-Night Only Water Htg 3 247 1 0.0823

28 16-Ski Area/Snowmaking 1,050 188.723 2 0.1797

29 Special Contracts 291

30 Power Adjuster -263,481

31 Total 890,741 120.619,471 20,950 0.1354

32 Account 443 Ind

33 Rate 63/64 Time of Use 191,551 21,053,738 28 01099

34 Rate 7/16/18 Area Lighting 35 8,480 1 0.2423

35 5-TRSR-Transmission Service 505.158 44,494,781 5 0.0881

36 16-Ski Area/Snowmaking 9.880 1.263,906 1 0.1279

37 4-Primary Service 38.856 4.121.120 5 0.1061

38 Power Adjustor -95,777

39 Total 745,480 70,846,248 40 0.0950

40 Account 444 Public St & Highway

41 TOTAL Billed 2,428,311: 323,220,463 140,95" 0.1331 42 Total Unbilled Rev.(See Instr. 6) 49,43~ 7,549,112 C 0.1527 43 TOTAL 2,477,751 330,769,575 140,955 0.1335


Year/Period of Report Date of Report Name of Respondent This ~rrt Is: (Mo, Da, Yr)(1) An Original 2012/04End ofGreen Mountain Power Corporation

(2) EjA Resubmission 04/15/2013

SALES OF ELECTRICITY BY RATE SCHEDULES

1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per KWh, excluding date for Sales for Resale which is reported on Pages 310-311. 2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. 3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. 4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). 5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. 6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.

Line I\lumoer ana Ime or Kale scneaule N1vvn ~ola Kevenue Average Number ISWh_ot ~ales K~~~~~lderPer ~ustomerof Cia)omersNo. (f)

1 Rate 16/18 Area Lighting

(a) (c)(b) e)

0.2726

2 Total

5,869 1,600,117 97 60,505

0.2726

3 Account 445 Other Sales to Public

4 Contract 19

5,869 1,600,117 97 60,505

57 846 1 57,000 0.0148

52-General Service 2 296 1 2,000 0.1480

6 Total 0.0194

7 Unbilled Revenue

59 1,142 2 29,500

0.1527

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

49,433 7,549,112

41 TOTAL Billed 2,428,31E 323,220,463 140,95' 17,228 0.1331 42 (Total Unbilled Rev.(See Instr. 6) 49,43 7,549,112 0 0.1527 43 TOTAL 2,477,751 330,769,575 140,95E 17,578 0.1335


Name of Respondent


1, Report all sales for resale (Le,. sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the Purchased Power schedule (Page 326-327). 2. Enter the name of the purchaser in column (a). ownership interest or affiliation the respondent has with the purchaser. 3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projected load for this service in its system resource planning). be the same as, or second only to, the supplier's service to its own ultimate consumers. LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or setter can unilaterally get out of the contract. IF - for intermediate-term firm service.

than five years. SF - for short-term firm service. one year or less. LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of designated unit. IU - for intermediate-term service from a designated generating unit. Longer than one year but Less than five years.

I

Statistical No.

Name of Company or Public AuthorityLine (Footnote Affiliations)

(a) 1 Vermont Electric Co-Op OS

2 Washington Elec Co-Op RQ

3 ISO SF

4 DTE Energy Trading SF

5 BP Energy OS

6 Constellation Power Source SF

7 SEMPRA TRADING CORP SF

CVPS-SYSTEM ENERGY8 OS

9 CVPS Phase 1 Trans OS

10 GMP Trans Component FERC 890

11 ISO New England OS

12 New York State Electric & Gas RQ

13 Western Massachusetts Electric RQ

14 ISO New York OS

Subtotal RQ

Subtotal non-RQ

Total

Year/Period of ReportDate of ReportThis 00rt Is: (Mo, Da, Yr)(1) X An Original 2012/Q4End of 04/15/2013

SALES FOR RESALE (Account 447) (2) o A Resubmission

Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any

In addition, the reliability of requirements service must

The same as LF service except that "intermediate-term" means longer than one year but Less

Use this category for all firm services where the duration of each period of commitment for service is

The same as LU service except that "intermediate-term" means

FERC Rate Schedule or

Tariff Number (c) 0

1

N/A

2

7

79

29

8

1

Actual Demand (MW) Classifi

Avera~e Monthly illing Avera~e AverageDemand (MW) Monthly NC Deman Monthly CP Demandcation

(b) (d) (e) (f) 0 0 0

.13 .13 .13

N/A N/A N/A

N/A N/A N/A

N/A N/A N/A

N/A N/A N/A

N/A N/A N/A

N/A N/A N/A

N/A N/A N/A

0 0 0

0 0 0

0 0 0


Year/Period of ReportDate of Report(Mo, Da, Yr) 2012/04End of04/15/2013

Name of Respondent This @ort Is:

Green Mountain Power Corporation (1) X An Original (2) o A Resubmission

SALES FOR RESALE (Account 447) (Conti

non-firm service regardless of the Length of the contract and service from designated of the service in a footnote.

years. Provide an explanation in a footnote for each adjustment. 4.

"Total" in column (a) as the Last Line of the schedule. 5. which service, as identified in column (b), is provided. 6.

monthly coincident peak (CP)

metered hourly (60-minute integration) demand in a month.

Footnote any demand not stated on a megawatt basis and explain. 7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser. 8.

the total charge shown on bills rendered to the purchaser. 9. the Last -line of the schedule. 401, line 23. 401,iine 24. 10. Footnote entries as required and provide explanations following all required data.

nued)

units of Less than one year,

MegaWatt Hours Sold

(g)

531

REVENUE Demand Charges Energy Charges

($) ($) (h) (i)

15,012 21,024

9,724,251

1,595,510

2,213

-10,839

1,451

82

44,974

15,012 22,557

0 11,356,109

15,012 11,378,666

277,507

24,650

-300

9

7

547

301,857

302,404

OS - for other service, use this category only for those services which cannot be placed in the above-defined categories, such as all Describe the nature

AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting

Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter

Report subtotals and total for columns (9) through (k) In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under

For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average

demand in column (f). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum Monthly CP demand is the metered demand during the hour (60-minute

integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.

Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)

The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page

The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page

Tot,,(~)~Other Charges (h+i+j) No.($)

(k)

-41,900 (j)

-41,900

17,279 53,315

9,724,251

1,595,510

17,494 17,494

2,213

-10,839

1,451

82

44,974

17,279 54,848

-24,406 11,331,703

-7,127 11,386,551

1

2

3

4

5

6

7

8

9

10

11

12

13

14


20

15

14

11

10

12

Name of Respondent


This ~ort Is: (1) ~An Original (2) A Resubmission



End of 2012/04

ELECTRIC OPERATION AND MAINTENANCE EXPENSES

If the amount for previous year is not derived from previously reported figures, explain in footnote. Line Account Amount for N Current Year

o. (a) (b)

Amount for Previous Year

(c)

1 1. POWER PRODUCTION EXPENSES

2 A. Steam Power Generation

3 Operation

4

5

6

7

8

9

(500) Operation Supervision and Engineering

(501) Fuel

(502) Steam Expenses

(503) Steam from Other Sources

(Less) (504) Steam Transferred-Cr.

(505) Electric Expenses

(506) Miscellaneous Steam Power Expenses

(507) Rents

45,399

2,524,630

229,611

48,327

92,286

249,419

(509) Allowances

TOTAL Operation (Enter Total of Lines 4 thru 12) 3,189,672

Maintenance

(510) Maintenance Supervision and Engineering

(511) Maintenance of Structures

(512) Maintenance of Boiler Plant

(513) Maintenance of Electric Plant

(514) Maintenance of Miscellaneous Steam Plant

TOTAL Maintenance (Enter Total of Lines 15 thru 19)

TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20)

40,063

11,065

165,950

26,364

15,748

259,190

3,448,862

13

16

17

18

19

21

22 B. Nuclear Power Generation

29,823

1,866,752

169,277

10,976

65,635

66,765

2,209,228

28,627

7,948

66,252

305,468

9,381

417,676

2,626,904

23 Operation 202,043

323,765 24 (517) Operation Supervision and Engineering

25 (518) Fuel

26 (519) Coolants and Water

27 (520) Steam Expenses

28 (521) Steam from Other Sources

29 (Less) (522) Steam Transferred-Cr.

30 (523) Electric Expenses

31 (524) Miscellaneous Nuclear Power Expenses 379,668

32 (525) Rents

33 TOTAL Operation (Enter Total of lines 24 thru 32) 905,476

35 (528) Maintenance Supervision and Engineering 71,393

36 (529) Maintenance of Structures

37 (530) Maintenance of Reactor Plant Equipment 24,260

38 (531) Maintenance of Electric Plant 54.205

39 (532) Maintenance of Miscellaneous Nuclear Plant 40 TOTAL Maintenance (Enter Total of lines 35 thru 39) 149,858 41 TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40) 1,055,334

34 Maintenance

42 C. Hydraulic Power Generation

51 C. Hydraulic Power Generation (Continued)

43 Operation

44 (535) Operation Supervision and Engineering

45 (536) Water for Power 2,297 2,223 46 (537) Hydraulic Expenses 412,597 458,986 47 (538) Electric Expenses 619,147 396,143

48 (539) Miscellaneous Hydraulic Power Generation Expenses 114.432 39,002

49 (540) Rents 5,073

50 TOTAL Operation (Enter Total of Lines 44 thru 49) 1,285,813 955,015

52 Maintenance

53 (541) Mainentance Supervision and Engineering 34,704

54 (542) Maintenance of Structures 94,995 89,098

55 (543) Maintenance of Reservoirs, Dams, and Waterways 480,931 426,657

56 (544) Maintenance of Electric Plant 811,453 620,165

57 (545) Maintenance of Miscellaneous Hydraulic Plant 63,374

58 TOTAL Maintenance (Enter Total of lines 53 thru 57) 1,485,457 1,135,920

59 TOTAL Power PrOduction Expenses-Hydraulic Power (tot of lines 50 & 58) 2,771,270 2,090,935


85 (561.1) Load Dispatch-Reliability 163,836 67,122

86 (561.2) Load Dispatch-Monitor and Operate Transmission..:;S:.Ly.::.st..::e.:.:m~ _+_-----------_+_------~-_j

87 (561.3) Load Dispatch-Transmission Service and Scheduling

88 (561.4) Schedulin ,System Control and Dispatch Services

89 (561.5) Reliability, Planning and Standards Development

90 (561.6) Transmission Service Studies

91 (561.7) Generation interconnectio.;..n~S~t.::.ud::..:i.::.es~ _+_---------__~ ~

92 (561.8) Reliability, Planning and Standards Development Services

93 (562) Station Expenses 281,751 200,608

94 (563) Overhead Lines Expenses 156,181 55,779

95 (564) Underground Lines Expenses

96 (565) Transmission of Electricity by Others

97 (566) Miscellaneous Transmission Expenses

98 (567) Rents

99 TOTAL Operation (Enter Total of lines 83 thru 98

44,030,116

9,717

169,057

44,852,045

Name of Respondent


This ~ort Is: (1) ~An Original (2) A Resubmission



End of 2012/04

ELECTRIC OPERATION AND MAINTENANCE EXPENSES Continued)

If the amount for previous year is not derived from previously reported figures, explain in footnote. Line Account Amount/or N

Current ear o. (a) (b)

60 D. Other Power Generation

61 Operation

62 (546 Operation Supervision and Engineering 15,696


(c)

15,185

63 (547) Fuel 1,240.512 2,346,329

64 (548) Generation Expenses 238.282 281,634

65 (549) Miscellaneous Other Power Generation Expenses 601.833 626,060

66 (550 Rents 3,269,2082,096,32367 TOTAL Operation (Enter Total of lines 62 thru 66

68 Maintenance

69 (551) Maintenance Su ervision and En ineering 21,010 21,524

70 (552) Maintenance of Structures 25,960 12,373

f-_'_.7_'_.1+(c::5..:;5.::.3t....)M;.:..:::a::..in~te:::.n..::a"-'n.::.ce=---=-o...;,f G=e~ne::..:r.:::a.::.tin~g"-a=n~d~E..::le..::ct=ri..::c::..P...::la::.:n.::.t + ...:4=-2=6.c:....:751+ 1~9::..4:.::,5:::7:..=j3

72 (554) Maintenance of Miscellaneous Other Power Generation Plant 717,472 444,547

344,920

541,559

134,760,137

135,646,616

432,769

591,173

178,377,593

179,401,53579 TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78)

76 (555 Purchased Power

78 (557 Other Expenses

77 (556) S stem Control and Load Dispatching

73 TOTALMaiM~aoce(EMmTo~l~lin~~~t.::.hr~u~7~2~)_~ ~~- ~_~.;..1~,1..::9~1~,1~9.:::3~------..::6-'-.7.::.3,'-=0~1~7

74 TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73) 3,287.516 3,942,225

75 E. Other Power Supply Expenses

80 TOTAL Power Production Expenses (Total of lines 21. 41, 59, 74 & 79)

81 2. TRANSMISSION EXPENSES

82 Operation

83 (560) Operation Supervision and Engineering

84

189,964,517 144,306,680

100 Maintenance

101 (568) Maintenance SuperVision and Engineering 17,317 32,876

r-1_O_2+(,-5_6_9,-M_a_in_te_n_a_n_ce_of_S_t,-ru,--c""tu,--r...;,e...;,s~ -+ ~ 1...:1~6c.:,9::..:7...:4+-- ~3..:;5-,--,4:.:2~1

103 (569.1) Maintenance of Computer Hardware

104 (56~2)M~~enance~Com~p_~...;,e~r~S~0...;,ftw~~,-e~__~~~_~__~~_~~--~~-~~-~--f-------~-~ 105 (569.3) Maintenance of Communication Equipment

106 (569.4) Maintenance of Miscellaneous Regional Transmission Plant

107 (570) Maintenance of Station Equipment 250,502 264,985

108 (571) Maintenance of Overhead Lines 1,513,866 615,413

109 (572) Maintenance of Under round Lines

r-:-1~10-:i-:(=-5=7=-3),:-M~ai:-n_te_n_a_nc_e_o_f~M~is_ce_I-,la~n~e_o.;..us_T_ra_n_s_m_is~s_io_n_P_I...;,an_t:--_~ --+ ~7~1:..:::,O..:;8.::2t--- 183,838 111 TOTAL Maintenance (Total of lines 101 thru 110) 1,969,741 1,132,533

112 TOTAL Transmission Expenses (Total of lines 99 and 111) 46,821,786 32,955,723

FERC FORM NO.1 (ED, 12-93) Page 321

Year/Period of ReportDate of ReportName of Respondent This ~ort Is: (Mo, Da, Yr)(1) An Original End of 2012/04Green Mountain Power Corporation 04/15/2013

ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)

If the amount for previous year is not derived from previously reported figures. explain in footnote. Line

(2) nA Resubmission

Account urrent ear Previous Year

No. (a) (b) (c)

113 3. REGIONAL MARKET EXPENSES 114 Operation ~

(575.1) Operation Supervision

116 115

-1,657

117

(5752) Day-Ahead and Real-Time Market Facilitation (575.3) Transmission Rights Market Facilitation

118 (575.4) Capacity Market Facilitation

119 (575.5) Ancillary Services Market Facilitation

120 (575.6) Market Monitoring and Compliance

121 (575.7) Market Facilitation, Monitoring and Compliance Services

122 (575.8) Rents

123 -1,657

124 Total Operation (Lines 115thru 122) Maintenance

125 (576.1) Maintenance of Structures and Improvements

126 (576.2) Maintenance of Computer Hardware 127 (576.3) Maintenance of Computer Software 128 (576.4) Maintenance of Communication Equipment

129 (576.5) Maintenance of Miscellaneous Market Operation Plant

130 Total Maintenance (Lines 125thru 129) 131 -1,657

132

TOTAL Regional Transmission and Market Op Expns (Total 123 and 130) 4. DiSTRIBUTION EXPENSES

133 Ope"ation

134 (580) Operation Supervision and Engineering 1,750,488

135 124,090

136 (581) Load Dispatching (582) Station Expenses 94,013

137 185,505

138 (583) Overhead Line Expenses

71,883

139 (584) Underground Line Expenses

4,679

140 (585) Street Lighting and Signal System Expenses

820,761

141 (586) Meter Expenses

39,071

142 (587) Customer Installations Expenses (588) Miscellaneous Expenses 875,763

143 (589) Rents 562,856 144 TOTAL Operation (Enter Total of lines 134 thru 143) 4,529,109 145

564,132 70,167

59,184

211,185 14,073

-805 513,351

2,376 454,124

1,887,787

Maintenance

146 (590) Maintenance Supervision and Engineering 91,284 147 (591) Maintenance of Structures 217,246 148 (592) Maintenance of Station Equipment 1,094,296 149 (593) Maintenance of Overhead Lines 11,963,568

150 (594) Maintenance of Underground Lines 546,872 151 (595) Maintenance of Line Transformers 64,795 152 (596) Maintenance of Street Lighting and Signal Systems 183,834 153 (597) Maintenance of Meters 222,888 154 (598) Maintenance of Miscellaneous Distribution Plant 330,323 155 TOTAL Maintenance (Total of lines 146thru 154) 14,715,106 156 TOTAL Distribution Expenses (Total of lines 144 and 155) 19,244,215

21,801

633,108 7,609,583

487,173

25,821 181,405 206,680 291,190

9,456,761

11,344,548 157 5. CJSTOMER ACCOUNTS EXPENSES 158 Operation 159 (901) Supervision 231,281 160 (902) Meter Reading Expenses 1,100,361 161 (903) Customer Records and Collection Expenses 2,613,899

162 (904) Uncollectible Accounts 1,399,508 163 (905) Miscellaneous Customer Accounts Expenses 285,882 164 TOTAL Customer Accounts Expenses (Total of lines 159 thru 163) 5,630,931

163,145 670,581

2,089,423

502,025

292,074

3,717,248


Name of Respondent


This ~ort Is: (1) ~ An Original (2) A Resubmission



End of 2012/04

ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)

If the amcunt for previous year is not derived from previously reported figures, explain in footnote. Line Account Amount for N Current Year

o. (a) (b)


(c)

165 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES

166 Operation

167 (9071 Supervision 32,256

168 (9081 Customer Assistance Expenses 1,659,724 1,168,301

169 (909) Informational and Instructional Expenses 129,395 26,380

170 (9101 Miscellaneous Customer Service and Informational Expenses 64,590 50,085

171 TOTAL Customer Service and Information Expenses (Total 167 thru 170) 1,885,965 1,244,766

172 7. SALES EXPENSES

173 Operation

174 (911) Supervision

175 (912) Demonstrating and Selling Expenses -82

176 (913) Advertising Expenses

177 (916) Miscellaneous Sales Expenses

178 TOT AL Sales Expenses (Enter Total of lines 174 thru 177) -82

181 (920) Administrative and General Salaries 9,295,165 7,194,975

182 (921) Office Supplies and Expenses 2,215,824 1,840,750

183 (Less) (922) Administrative Expenses Transferred-Credit 4,003,732 4,684,059

184 (923) Outside Services Employed 2,459,236 2,131,365

185 (924) Property Insurance 801,878 447,229

186 (925) Injuries and Damages 1,478,261 569,952

187 (926) Employee Pensions and Benefits 5,737,075 1,347,337

188 (927) Franchise Requirements

189 (928) Regulatory Commission Expenses 1,159,119 488,142

190 (929) (Less) Duplicate Charges-Cr. 247,335 267,620

191 (930.1) General Advertising Expenses 40,039 66,032 192 (930.2) Miscellaneous General Expenses 730,090 758,836

161,312

10,054,251

333,310

19,998,930

193 (931) Rents--------------------------1I------------':...::..::.:...:..c...=t-----------'------'-"--.:..::.j194 TOTAL Operation (Enter Total of lines 181 thru 193)

179 8. ADMINISTRATIVE AND GENERAL EXPENSES 180 Opel:9.t,,-i0=-cn~ _

195 Maintenance

196 (935) Maintenance of General Plant 2,503,249 1,538,944

197 TOTAL Administrative & General Expenses (Total of lines 194 and 196) 22,502,179 11,593,195

198 TOTAL Elec Op and Maint Expns (Total 80,112,131,156,164,171,178,197) 286,047,854 205,162,160


Name of Company or Public AuthorityLine No. (Footnote Affiliations)

(a)

1 Stonybrook MMWEC

2 Reg Asset Hydro Quebec

3 Moretown (PPL)

4 ISO New England

5 NYF'A (State of VT)

6 Boltonville Hydro

7 Vermont Electric Power Producer Inc./

8 Vermont Electric Power Co. HQ Sch B

9 Vermont Electric Power Co. HQ Sch C I

10 Entergy (Vermont Yankee)

11 Soler Purchased from Customers

12 Morqan Stanley

13 Nextera

14 Renewable Energy Credits Retired

Lhta,

Name of Respondent This 00rt Is: (1) X An Original

Green Mountain Power Corporation (2) n A Resubmission PURCHASED POWER hAccount 555)

(Including power exc anges)

1. debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges. 2. Enter the name of the seller or other party in an exchange transaction in column (a). acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller. 3.

supplier includes projects load for this service in its system resource planning). be the same as, or second only to, the supplier's service to its own ultimate consumers.

which meets the definition of RQ service. defined as the earliest date that either buyer or seller can unilaterally get out of the contract.

IF - for intermediate-term firm service. than five years.

SF - for short-term service. year or less.

service, aside from transmission constraints, must match the availability and reliability of the designated unit.

IU - for intermediate-term service from a designated generating unit. longer than one year but less than five years.

and any settlements for imbalanced exchanges.

as - for other service.

of the selvice in a footnote for each adjustment.

Date of Report Year/Period of Report(Mo, Da, Yr) End of 2012/Q404/15/2013

Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of

Do not abbreviate or truncate the name or use

In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:

RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the In addition, the reliability of requirement service must

LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service

For all transaction identified as LF, provide in a footnote the termination date of the contract

The same as LF service expect that "intermediate-term" means longer than one year but less

Use this category for all firm services, where the duration of each period of commitment for service is one

LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of

The same as LU service expect that "intermediate-term" means

EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.

Use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature

Average Actual Demand (MW) Monthly Billing Average AverageDemand (MW) Monthly NCP Deman Monthly CP Demand

(d) (e) (f)

Statistical Classification

(b)

LU

LU

as as LU

LU

LU

LU

LU

SF


Tariff Number (c)

07B-0136-000

124

07B-0335-009-1

na

na

07B-0 133-000-03

07B-0133-000-03

45


Year/Period of Report Date of ReportName of Respondent This wort Is: (Mo, Da, Yr)(1 ) X An Original 2012/Q4End ofGreen Mountain Power Corporation 04/15/2013(2) o A Resubmission

PURCHAVED P.OWER(AcGOunt 555) (Continued)Including power exchanges)

AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment.

4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided. 5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (50-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. 5. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange. 7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including out-of-per-iod adjustments, in column (I), Explain in a footnote all components of the amount shown in column (I). Report in column (m) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I) include cl'edits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote. 8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13. 9. Footnote entries as required and provide explanations following all required data.

POWER EXCHANGESMegaWatt Hours

Purchased MegaWatt Hours Received

MegaWatt Hours Delivered

(g) (h) (i)

COST/SETTLEMENT OF POWER Line Demand Charges

($) Energy Charges

($) Other Charges

($) Total U+k+l)

of Settlement ($) No.

U) (k) (I) (m)

5,01 L 558,104

52,440 52,440

25,64E 118,950

449,971

3,46C 14,135

3,77C

125,00' -34,310

551,08 20,348,645

350,53~ 12,698,302

189.051 58,416

1,80

4.4H

202,80C

2,615,022 52,440 52,440 33,576,693

282,54E 840,650 1

1,157,88f 1,157,888 2

2,192,76c 2.311,710 3

29,518,72~ 29,518,722 4

17,44f 31.583 5

386,77' 386,775 6

19,781,22E 19,746,916 7

18,607,47c 38,956,115 8

11,895,21 L 24,593,516 9

8,636,59C 8,695,006 10

687,29E 687.296 11

305,94E 305.946 12

12,250,62C 12,250,620 13

22,215 22,215 14

144,546,991 253,909 178,377,59~

FERC FOI~M NO.1 (ED. 12-90) Page 327

Name of Respondent


1.

2. acronyms. 3.

which meets the definition of RQ service.

IF - for inl:ermediate-term firm service. than five years.


IU - for intermediate-term service from a designatlonger than one year but less than five years.


as - for other service.

of the service in a footnote for each adjustment.

Line No.

Name of Company or Public Authority (Footnote Affiliations)

(a)

HO I:nergy Services

JP Morgan

National Grid

Millstone FAS 5 RS 2 Amortization

Nextra Nuclear

BP [nergy

SF

SF

SF

SF

SF

SF

LU

LU

LU

LU

ed generating unit.

1

2

3

4

5

6

7 Granite Reliable

Macquire Energy

Rochester HO Amortization

8

9

10 Millstone Amortization #3

Decomission Conn Maine & Yankee Atomic11

12 ENEL North America Lower Valley Hydro

13 ENEL North America Sweetwater Hydro

14 ENEL North America Woodsville Hydro

Total

Date of Report Year/Period of Report(Mo, Da, Yr) End of 2012/0404/15/2013

Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.

Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use Explain in a footnote any ownership interest or affiliation the respondent has with the seller.


RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the same as, or second only to, the supplier's service to its own ultimate consumers.

LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic: reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service

For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally get out of the contract.

The same as LF service expect that "intermediate-term" means longer than one year but less


LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of the designated unit.




Average Actual Demand (MW) Monthly Billing Average AverageDemand (MW) Monthly NCP Deman Monthly CP Demand

(d) (e) (f)

This wort Is: (1) X An Original (2) DA Resubmission

PURCHASED POWER hAccount 555)(Including power exc anges)


(b)


Tariff Number (c)

FPC1

FPC1

FPC1

FPC1



Name of Respondent This 00rt Is: Date of Report

Green Mountain Power Corporation (1) X An Original (Mo, Da, Yr) (2) o A Resubmission 04/15/2013

PU r<CHAVED P,\.JWER(ACCOURt 555) \(Continued)Including power exc anges)


4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided. 5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (50-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. 5. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange. 7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I) include cree its or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote. 8. The data in column (g) through (m) must be totalled on the last line of the schedule. reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13. 9. Footnote entries as required and provide explanations following all required data.

MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER

Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Received Delivered ($) ($)

(g) (h) (i) 0) (k)

11::J,16E 4,840,19C

162,14E 8,238,221

92,92C 4,565,94~

183,60C 12,576,60C

49,241 3,406,88E

94,08C 4,456,57C

19 11,40

44 4,30E

15 11,70E

2,615,022 52,440 52,440 33,576,693 144,546,991

The total amount in column (g) must be

Line Other Charges Total O+k+l) No.

of Settlement ($)($)(I) (m)

4,840,190 1

8,238,221 2

4,565,949 3

12,576,600 4

1,274 1.274 5

-271,621 6

3,406,886 7

4,456,570 8

526

-271,621

526 9

54,716 1054,716

11

11,407 12

4,306

334.397 334,397

13

11.708 14

178,377,593253,909


This @ort Is: Date of Report Year/Period of Report(1) (2)

X An Original DA Resubmission

(Mo, Da, Yr) 04/15/2013

End of 2012/04 Name of ~:espondent


1.

2. acronyms. 3.

which meets the definition of RQ service.

than five years.


IU - for intermediate-term service from a designlonger than one year but less than five years.


OS - for other service.

of the service in a footnote for each adjustment.

ated generating unit.

Line No.

Name of Company or Public Authority (Footnote Affiliations)

(a)

Martinsville Hydro

NortlHartland Hydro

Cow Power

Ampersand Hydro

Bethel Mills

Lovejoy Tool Company

Florida Power & Light Wyman

1

2

3

4

5

6

7


9 Braintree

Fitchburg

Unitil

Total

10

11

12

13

14

PU~CHASED POWER Wccount 555)( ncludmg power exc anges)

Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.

Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use Explain in a footnote any ownership interest or affiliation the respondent has with the seller.


RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the same as, or second only to, the supplier's service to its own ultimate consumers.

LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service

For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally get out of the contract.

IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less


LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of the designated unit.




AverageStatistical Classifi- Monthly Billing cation Demand (MW)

(b) (d)

LU

LU

LU

LU

OS

OS

OS

OS


Tariff Number (c)

NUG

NUG

NUG

NUG

Actual Demand (MW) Average Average

Monthly NCP Deman Monthly CP Demand (e) (f)

FERC FOI~M NO.1 (ED. 12-90) Page 326.2

Year/Period of ReportName of Ftespondent This 00rt Is: (1) X An Original

Date of Report(Mo, Da, Yr)04/15/2013

2012/04End ofGreen Mountain Power Corporation (2) D A Resubmission

PURCHA~ED PQWER(ACcougt 555) (Continued)Including power exc anges)


4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided. 5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (50-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. 5. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange. 7. Repol1 demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote. 8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13. 9. Footnote entries as required and provide explanations following all required data.

COST/SETTLEMENT OF POWER Line

Purchased

(g)

MegaWatt Hours Received

(h)

MegaWatt Hours Delivered

(i)

Demand Charges ($)(j)

15C 317

3,31E 10,788

6,61E

1C

-330,428

34,522

36,650

62,602

2,615,022 52,440 52,440 33,576,693

Total (j+k+l)Energy Charges Other Charges No.of Settlement ($)($)($)

(I) (m)

6,88E

(k)

7.203 1

112,19C 122,978 2

116.253 116,253 3

589,11; 589,115 4

-3,634 -3,634 5

97E 976 6

-330,428 7

5,48E -217 5,269 8

34,522 9

36,650 10

62,602 11

12

13

14

144,546,991 253,909 178,377,59

POWER EXCHANGESMegaWatt Hours


I

Year/Period of Report Name of Respondent Date of Report This @ort Is: (Mo, Da, Yr)(1) X An Original 2012/Q4End ofGreen Mountain Power Corporation 04/15/2013

TRANSMI ~::;!ON OF ELECTRI~ITY FOR UJ"HERSJAccount 456.1) (Including transactions referred to as 'wheeling')

(2) o A Resubmission

1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives. other public authorities, qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter. 2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c). 3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to. Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c) 4. In colulln (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission Reservation, NF - non-firm transmission service, as -Other Transmission Service and AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes.

Payment By (Company of Public Authority)

No. ~ (Footnote Affiliation) (a)

1 TRANSCANADA HYDRO NE

2 CENTRAL VERMONT PUBLIC SERVICE

3 WASHINGTON ELECTRIC CO-OP

4 VERMONT ELECTRIC COOPERATIVE

5 VILLAGE OF HARDWICK

6 VILLAGE OF MORRISVILLE

7 VILLAGE OF NORTHFIELD

8 VILLAGE OF LUDLOW

9 VILLAGE OF READSBORO

10 VILLAGE OF JACKSONVILLE

11 BURLINGTON ELECTRIC DEPT.

12 PHASE 1 METALUC NEUTRAL RETURN

13 NH leLECTRIC CO-OP

14 VELCO HIGHGATE TRANSMISSION

15 VILLAGE OF JOHNSON

16 VILLAGE OF HYDE PARK

17 WOODSVILLE FIRE DISTRICT WATER &

18 PUBLIC SERVICE OF NEW HAMPSHIRE

19 MAC; ENERGY

20 ROYAL BANK OF CANADA

21 HYDRO QUEBEC ENERGY SERVICES

22 GREEN MOUNTAIN POWER

23

24

25

26

27

28

29

30

31

32

33

34

TOTAL

StatisticalEnergy Received From Energy Delivered To (Company of Public Authority) Classifi(Company of Public Authority)

(Footnote Affiliation) (Footnote Affiliation) cation (b) (c) (d)

OSN/AN/A

LFCENTRAL VERMONT PUBLIC GMP

OLFVELCO WASHINGTON ELECTRIC CO-OP

LFVELCO VERMONT ELECTRIC COOPERATIVE

LFVILLAGE OF HARDWICKVELCO

LFVELCO VILLAGE OF MORISVILLE

LFVELCO VILLAGE OF NORTHFIELD

FNOVARIOUS VILLAGE OF LUDLOW

LFVELCO VILLAGE OF READSBORO

LFVELCO VILLAGE OF JACKSONVILLE

LFGMP BURLINGTON ELECTRIC DEPT

OSHYDRO QUEBEC NEPOOL PTF

OSGMP NH ELECTRIC CO-OP

VELCO Highgate transmission facility

FNOVARIOUS VILLAGE OF JOHNSON

FNOVARIOUS VILLAGE OF HYDE PARK

FNOVARIOUS WOODSVILLE FIRE DISTRICT

FNOVARIOUS PUBLIC SERVICE CO OF NH

NFN/A N/A

N/A NFN/A

NFN/A N/A

ADVARIOUS GREEN MOUNTAIN POWER


Year/Period of Report Date of Report (Mo, Da, Yr) 2012/04End of04/15/2013

TRANSMIS::;.l.0N OF ELEL;TRICITY F9R QTHERSiAccount 456)(Continued)

In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract

In column (f), report the designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column (g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the

Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand

Footnote any demand not stated on a megawatts basis and explain.

Name of R.espondent This 00rt Is:

Green Mountain Power Corporation (1) X An Original (2) DA Resubmission

(Including transactions reffered to as 'wheeling')

5.

designations under which service, as identified in column (d), is provided. 6. Report receipt and delivery locations for all single contract path, "point to point" transmission service.

contract. 7. reported in column (h) must be in megawatts.

8. Report in column (i) and (j) the total megawatthours received and delivered.

FERC Rate Point of Receipt Point of Delivery

I Billing

Schedule of (Subsatation or Other (Substation or Other Demand Tariff Number Designation) Designation) (MW)

(e) (f) (g) (h)

124 N/A N/A

128 MCINDOES FALLS E.RYEGATE

68 VELCO WASHINGTON ELECTRIC

N/A VELCO VERMONT ELECTRIC COP

60 VELCO VILLAGE OF HARDWICK

~ VELCO VILLAGE OF MORISVILE

64 VELCO VILLAGE OF NORTHFIED

3 VARIOUS VARIOUS

72 VELCO VILLAGE OF READSBORO

~ VELCO VILLAGE OF JACKSONVI

85 VELCO BURLINGTON ELECTRIC

NA DES CANTON, CANADA SANDY POND

NA

3 VARIOUS JOHNSON

3 VARIOUS HYDE PARK

3 VARIOUS WOODSVILLE

3 VARIOUS VARIOUS

3 VARIOUS VARIOUS

3 VARIOUS VARIOUS

3 VARIOUS VARIOUS

3 VARIOUS WILDER

§

~ §

Line No.

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

0

TRANSFER OF ENERGY

MegaWatt Hours MegaWatt Hours Received Delivered

(i) m

49,356

88,460

47,567

40,403

42,267

36,849

14,184

6,750

68,163

4,867

3,741

3,011

5,977

42,346

2,163

204

166,617

622,925

49,10S

85,73E

46,582

39,191

32,65"

29,12"

13,75S

6,54E

67,42E

4,61~

3,62S

2,921

5,79E

40,76L

2,16~

20~

166,61

596,837


Name of Respondent


9.

amount of energy transferred.

(n). rendered. 10

11.

Demand Charges ($) (k)

2,464

143,625

219,000

187,963

101,378

70,331

66,135

16,387

16,795

138,256

23,803

2,352,290

16,913

16,138

26,624

198,549

8,057

747

499,850

4,105,305

Energy Charges ($) (I)

Year/Period of Report Date of Report This 00rt Is: (1) X An Original (Mo, Da, Yr) End of 2012/Q4

04/15/2013 TRANSMISSION O.F ELECTRICITY FOR OTHER? (Account 456) (Continued)

(Including transactions reffered to as 'wheeling')

(2) o A Resubmission

In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the

In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column

Provide a footnote explaining the nature of the non-monetary settlement, inclUding the amount and type of energy or service

The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report purposes only on Page 401, Lines 16 and 17, respectively.

Footnote entries and provide explanations following all required data.

Line No.

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS


(Other Charges) ($) (m)

-15,522

31,285

-6,997

-6,069

243

-1,043

-971

10,815

1,190

1,654

7,823

67,161

1,156

42

31,808

122,575

Total Revenues ($) (k+/+m)

(n)

2,464

143,625

203,478

219,248

94,381

64,262

66,378

15,344

15,824

138,256

34,618

2,352,290

18,103

17,792

34,447

265,710

9,213

499,850

31,808

4,227,8800

789

I

Year/Period of ReportName of Respondent Date of ReportThis ~ort Is: (Mo, Da, Yr) (1) An Original 2012/04End ofGreen Mou1tain Power Corporation 04/15/2013(2) nA Resubmission

TRANSMISSION OF ELECTRICITY BY ISO/RTOs

1. Report in Column (a) the Transmission Owner receiving revenue for the transmission of electricity by the ISO/RTO. 2. Use a separate line of data for each distinct type of transmission service involving the entities listed in Column (a). 3. In Column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO - Firm

Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to-Point Transmission Reservation, NF - Non-Firm Transmission Service, OS Other Transmission Service and AD- Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting pel'iods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes. 4. In column (c) identify the FERC Rate Schedule or tariff Number, on separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (b) was provided. 5. In column (d) report the revenue amounts as shown on bills or vouchers. 6. Report in column (e) the total revenues distributed to the entity listed in column (a).

Line Statistical Classification

(b)

Total Revenue No.

Payment Received by FERC Rate Schedule Total Revenue by Rate or Tariff Number Schedule or Tarirff (Transmission Owner Name)

(d) (e)(a) (c)

1

2

3

4

5

6

7

I 8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40 TOTAL ~

FERC FORM NO. 1/3-Q (REV 03-07) Page 331

Name of Hespondent Year/Period of ReportDate of ReportThis 00rt Is: (1) An Original (Mo, Da, Yr) 2012/04End ofGreen Mountain Power Corporation (2) riA Resubmission 04/15/2013

TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565) (Including transactions referred to as "wheeling")

1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public authorities, qualifying facilities, and others for the quarter. 2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company, abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided transmission service for the quarter reported. 3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications. 4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service. 5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered. 6. Enter 'TOTAL" in column (a) as the last line. 7. Footnote entries and provide explanations following all required data.

Line TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER

No. Name of Company or Public

Authority (Footnote Affiliations) (a)


(b)

Magawatthours

Received (c)

Magawauhours

Delivered (d)

!!.emana Charres

($ (e)

t:nergy Charres

($ (f)

ymer Charres

($ (g)

Total Cost of TransTission

(hl

1 Received from wheeler

2 VELCO/NEPOOL FNS 2,571,329 2,571,329 8,387,637 8,387,637

3 NYPII OLF 2,957 2,957 208,834 208,834

4 NEPCO FNS 672 672 686.118 686,118

5 VELCO Phases I & II LFP 435,546 435,546 2,298,187 2,298,187

6 ISO New England FNS 2,571,329 2,571,329 32,404,763 32,404,763

7 Central VI. Public Serv FNS 104 104 -60,175 -60,175

8 Vermont Electric Co-op 41 41 104,752 104,752

9

10

11

12

13 TOH\L 5,581,978 5,581,978 44,030,116 44030,116

14

15

16

TOTAL 5,581,97E 5,581.978 44,030,116 44,030,116

FERC FORM NO. 1/3-0 (REV. 02-04) Page 332

Date of Report I Year/Period of ReportName of F':espondent This tJ'0rt Is: (Mo, Da, Yr)(1) An Original 2012/04Green Mountain Power Corporation End of 04/15/2013

MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)

Line

(2)0 A Resubmission

AmountDescri)tionNo. (a (b)

1 108,988

2

Industry Association Dues

Nuclear Power Research Expenses

3 31,449

4

Other Experimental and General Research Expenses

Put & Dist Info to Stkhldrs ...expn servicing outstanding Securities

5 Oth Expn >=5,000 show purpose, recipient, amount. Group if < $5,000

6 146,075

7

A&(3 Expense trustee - Bank of New York Bond

68,500

8

A&G Expense - Communications

Directors Fees:

9 29,350

10

BElnkowski, Elizabeth A.

36,850

11

Brue, Nordahl L.

31,700

12

Coates, David

31,700

13

Depars, Pierre

36,700

14

Benoit, Robert

31,500

15

Hoyt, Kathleen C.

36,700

16

Irving, Euclid

TE1ssier, Robert 59,000

W)/k, David S. 14,000

18

17

Directors expenses 37,208

19 23,269

20

Other A&G Payroll undistributed

7,101

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

Otehr A&G - Various

46 TOTAL 730,090


I


Green Mountain Power Corporation (1) An Original (Mo. Da, Yr) End of 2012/04 (2) Ei A Resubmission 04/15/2013

DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403.404. 405) (Except amortization of aquisition adjustments)

1. Report in section A for the year the amounts for: (b) Depreciation Expense (Account 403; (c) Depreciation Expense for Asset Retirement Costs (Account 403.1 ; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric Plant (AcGOunt 405). 2. Report in Section 8 the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to compute charges and whether any changes have been made in the basis or rates used from the preceding report year. 3. Report all available information called for in Section C every fifth year beginning with report year 1971. reporting annually only changes to columns (c) through (g) from the complete report of the preceding year. Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount, account or functional classification. as appropriate, to which a rate is applied. Identify at the bottom of Section C the type of plant included In any sub-account used. In column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing composit8 total. Indicate at the bottom of section C the manner in which column balances are obtained. If average balances, state the method of averaging used. For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification Listed in column (a). If plCint mortality studies are prepared to assist in estimating average service Lives, show in column (f) the type mortality curve selected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. If composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis. 4. If provisions for depreciation were made during the year in addition to depreciation proVided by application of reported rates. state at the bottom of section C the amounts and nature of the provisions and the plant items to which related.

A.

Functional Classification

(a)

Line No.

1 Intan;)ible Plant

2 Stearn Production Plant

3 Nuclear Production Plant

4 Hydraulic Production Plant-Conventional

5 Hydraulic Production Plant-Pumped Storage

6 Othel' Production Plant

7 Transmission Plant

8 Distribution Plant

9 Regional Transmission and Market Operation

10 General Plant

11

12

Common Plant-Electric

TOTAL

Notes:

The total charges for the year were $914,560 ..

Summary of Depreciation and Amortization Charges

Amortization of Limited Term Electric Plant

(Account 404) (d)

7.086.301

7.086.301

Total

(f)

7.086.301

599,651

240.948

1,699,147

1,189.309

1,772,470

9,915,668

2,934,637

25,438.131

(2) Depreciation on transportation equipment is charged to a clearing account and then spread to appropriate operating expenses and capital accounts.

I

B. Basis for Amortization Charges

(1) The depreciable plant base represents the beginning of the year plant balances. For determining depreciation. units of plant are grouped by FERC account. with the exception of production plant, which is subdivided by operating unit.

I D~reCiation

xpense (Account 403)

(b)

599.651

240.948

1.699,147

1.189.309

1,772,470

9,915.668

2,934.637

18.351.830

DepreciationExpense for Asset Retirement Costs (Account 403.1)

(c)

Amortization of Other Electric

Plant (Acc 405) (e)


Name of Respondent


C. Factors Used in Estimating Depreciation Charges

Line uepreclable t.stlmatea

No. Account No. Plant Base Avg. Service

(a) (In Th(b)'andS) 7~~

12 311 2,631 33.00

13 312 5,927 30.00

14 314 1,840 33.00

15 315 439 33.00

16 316 1,664 30.00

17 Subtotal 12,501

18 331 6,149 60.10

19 332 29,999 53.20

20 333 17,531 52.10

21 334 5,357 55.90

22 335 1,204 54.20

23 336 672 61.00

24 Subtotal 60,912

25 341 3,199 22.90

26 342 3,201 23.50

27 343 11,417 17.70

28 344 15,620 16.20

29 345 1,164 36.30

30 346 855 35.80

31 Subtotal 35,456

32 352 296 56.00

33 353 27,726 39.00

34 354 214 70.00

35 355 9,092 40.00

36 356 12,415 46.00

37 Subtotal 49,743

38 361 243 35.00

39 362 31,991 36.00

40 364 49,769 36.00

41 365 52,713 36.00

42 366 13,562 42.00

43 367 19,285 39.00

44 368 50.869 44.00

45 369 16,353 39.00

46 370 15,176 25.00

47 373 5,089 25.00

48 Subtotal 255.050

49 390 14.843 30.00

50 391 6,355 24.00

This ~ort Is: (1) An Original (2) nA Resubmission

DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)

Net Appllea Salvage Depr. rates (Perg~nt) (per~;nt)

3.17

3.37

3.16

3.14

3.40

1.390.10

0.10 2.19

0.10 2.29

1.74

1.91

1.55

3.47

3.88

4.79

8.33

1.28

3.92

0.05 1.77

2.610.05

0.20 0.43

0.30 3.22

0.15 2.40

0.15 3.79

0.10 3.33

0.25 3.47

0.35 3.43

0.05 2.55

0.05 1.98

0.05 2.10

0.45 3.50

0.02 4.14

0.10 5.77

0.05 4.14

653

Year/Period of ReportDate of Report (Mo, Da, Yr) End of 2012/04 04/15/2013

Mortality Average Curve Remaining

T(~e 7~f SO

SO

SO

SO

SO

FORECAST 41.50

FORECAST 39.92

FORECAST 40.75

FORECAST 40.75

FORECAST 40.75

FORECAST 40.00

FORECAST 10.17

FORECAST 11.50

FORECAST 11.50

FORECAST 9.00

FORECAST 11.50

FORECAST 10.50

SO 42.90

S5.0 17.37

SO 42.80

S40 26.60

S4.0 29.00

R3.0 26.60

R2.5 25.20

S3.0 23.70

S3.0 24.10

R2.0 32.00

R2.5 25.00

R1.5 32.30

R1.0 28.70

R1.0 16.80

S2.0 13.70

R2.0 21.10

L1.0 19.60

FERC FOF:M NO.1 (REV. 12-03) Page 337

Name of Respondent


C. Factors Used in Estimating Depreciation Charges

Line uepreclaDie Account No. Plant Base No.

(In Th{b~andS)(a)

12 393 209

13 394 2,402

14 395 959

15 397 5,325

16 398 106

17 399 53

18 Subtotal 30,252

19 Total 443,914

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

This ~ort Is: (1) An Original (2) Ei A Resubmission

Year/Period of Report Date of Report (Mo, Da, Yr) End of 2012/04 04/15/2013

DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)

t:sumalea Applied Avg. Service Depr. rates

(per~)nt)~~) 2.1140.00

28.00 3.92

40.00 2.50

15.00 8.22

15.00 9.07

20.005.00

I\lel Salvage

(perg)ent)

0.03

Mortality Average Curve Remaining

Tr~e ~~f S1.5 21.30

S4.0 18.00

S6.0 25.60

SO 8.70

SO.O 9.30

SO

FERC FORM NO.1 (REV. 12-03) Page 337.1

This ~ort Is: (1) An Original (2) nA Resubmission

REGULATORY COMMISSION EXPENSES

Name of Respondent

Green MOJntain Power Corporation

1. Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if being amortized) relating to format cases before a regulatory body, or cases in which such a body was a party. 2. Report in columns (b) and (c), only the current year's expenses that are not deferred and the current year's amortization of amounts deferred in previous years.

Line Description No. (Furnish name of regulatory commission or body the

docket or case number and a description of the case) (a)

1 STATE OF VERMONT - PUBLIC SERV BD

2 Alternative Regulation Docket $21765

3 Alternative Regulation Docket #7770

4 VY Cooling Tower

5 Various less than $25,000

6 FERC Misc charges

7 Verr10nt Yankee Investigation

8 Solar Services Project

9 FERC Transmission Rate

10 FERC Standards of Conduct

11 Brucler Misc

12 Northwest Reliability Study Docket #6867

13 Alternative Regulation Base Rate Filing PSB d

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46 TOTAL

Assessed byRegulatory Commission

(b)


End of 2012/04 04/15/2013

DeferredTotalExpenses in AccountExpense for of Current Year 182.3 al

Utility Beginning 0 Year (b)+(c) (e)(d)(c)

45,586

174,412

45,586

174,412

106,332 106,332

92,279 92,279

28,951 28,951

280,023 280,023

40,542 40,542

139,074 139,074

42,064 42,064

50,983 50,983

82,943 82,943

85,929 85,929

1,169,118 1,169,118


Year/Period of ReportName of Respondent This ~ort Is: Date of Report (1) ~An Original (Mo, Da, Yr) End of 2012/04Green Mountain Power Corporation (2) A Resubmission 04/15/2013

REGULATORY COMMISSION EXPENSES (Continued)

3. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization.

4. List in column (t), (g), and (h) expenses incurred during year which were charged currently to income, plant, or other accounts.

5. Minor items (less than $25,000) may be grouped.

AMORTIZED DURING YEAREXPENSES INCURRED DURING YEAR

Deferred inContraCURRENTLY cRg~n

CHARGED TO Deferred to LineAmount Account 182.3 AccountDepartment Account 182.3 No.End of Year (i) (k) (I)(f) (g) (h) (j)

292810 45,586

392810 174,412

492810 106,332

592810 92,279

692810 28,951

792810 280,023

892810 40,542

9

92810

92810 139,074

10

92810

42,064

11

92810

50,983

12

92810

82,943

13

14

15

16

17

18

19

20

21

85,929

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44 45

~~ 1,169,118»: }'" ~ ~ % "


46

Year/Period of ReportDate of Report Name of Respondent This 00rt Is: (Mo, Da, Yr) (1) An Original 2012/04End of Green Mountain Power Corporation 04/15/2013

RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES


1. Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D & D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(ldentify recipient regardless of affiliation.) For any R, D & D work carried with others, show separately the respondent's cost for the year and cost chargeable to others (See definition of research, development, and demonstration in Uniform System of Accounts). 2. Indicate in column (a) the applicable classification, as shown below:

Classifications: A. Electric R, D & D Performed Internally: a. Overhead

(1) Generation b. Underground a. hydroelectric (3) Distribution

i. Recreation fish and wildlife (4) Regional Transmission and Market Operation ii Other hydroelectric (5) Environment (other than equipment)

b. Fossil-fuel steam (6) Other (Classify and include items in excess of $50,000.) c. Internal combustion or gas turbine (7) Total Cost Incurred d. Nuclear B. Electric, R, D & D Performed Externally: e. Unconventional generation (1) Research Support to the electrical Research Councilor the Electric f. Siting and heat rejection Power Research Institute

(2) Transmission

Line Classification No. (a)

1 B4

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

Description

(b)

Cust Survey & Public Opinion Strategies


Year/Period of ReportName of Respondent This ~ort Is: Date of Report (1) ~ An Original (Mo, Da, Yr) End of 2012/Q4Green Mountain Power Corporation (2) nAResubmission 04/15/2013

RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES

1. Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D &

D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(ldentify

recipient regardless of affiliation.) For any R, D & D work carried with others, show separately the respondent's cost for the year and cost chargeable to

others (See definition of research, development, and demonstration in Uniform System of Accounts).

2. Indicate in column (a) the applicable classification, as shown below:

Classifications:

A. Electric R, D & D Performed Internally: a. Overhead

(1) Generation b. Underground

a. hydroelectric (3) Distribution

i. Recreation fish and wildlife (4) Regional Transmission and Market Operation

ii Other hydroelectric (5) Environment (other than equipment)

b. Fossil-fuel steam (6) Other (Classify and include items in excess of $50,000.)

c. Internal combustion or gas turbine (7) Total Cost Incurred

d. Nuclear B. Electric, R, D & D Performed Externally:

e. Unconventional generation (1) Research Support to the electrical Research Councilor the Electric

I

f Siting and heat rejection

(2) Transmission

Power Research Institute

Description

(b)

38

L-----'-- ~~-----L _



End of 2012/04 IName of Respondent This wort Is: Date of Report

Green Mountain Power Corporation (1) An Original (Mo, Da, Yr)

(2) nA Resubmission 04/15/2013

RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES (Continued)

(2) Research Support to Edison Electric Institute (3) Research Support to Nuclear Power Groups (4) Research Support to Others (Classify) (5) Total Cost Incurred

3. Include in column (c) all R, 0 & 0 items performed internally and in column (d) those items performed outside the company costing $50,000 or more, briefly describing the specific area of R, 0 & 0 (such as safety, corrosion control, pollution, automation, measurement, insulation, type of appliance, etc.). Group items under $50,000 by classifications and indicate the number of items grouped. Under Other, (A (6) and B (4)) classify items by type of R, 0 & o activity. 4. Show in column (e) the account number charged with expenses during the year or the account to which amounts were capitalized during the year, listing Account 107, Construction Work in Progress, first. Show in column (f) the amounts related to the account charged in column (e) 5. Show in column (g) the total unamortized accumulating of costs of projects. This total must equal the balance in Account 188, Research, Development, and Demonstration Expenditures, Outstanding at the end of the year. 6. If costs have not been segregated for R, 0 &0 activities or projects, submit estimates for columns (c), (d), and (f) with such amounts identified by "Est." 7. Report separately research and related testing facilities operated by the respondent.

Costs Incurred Internally Costs Incurred Externally AMOUNTS CHARGED IN CURRENT YEAR Curreni Year Current Year Account Amount(c

(d) (e) (f)

50,466 93025 50,466

Unamortized

Accumulation (g)

Line No.

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36


Name of Respondent


This ~ort Is: Date of Report (1) ~An Original (Mo, Da, Yr) (2) A Resubmission 04/15/2013


End of 2012/04

DISTRIBUTION OF SALARIES AND WAGES

Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to Utility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns provided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation giving substantially correct results may be used.

35 Transmission

13 Production

14 Transmission

Total

1,923.955

-82

7,957,036

-82

1,143,798

2,484,585

6,887,015

6,818,409

1,143,798

1,923,955

20,825,050

14,252,147

Direct PayrollDistribution

(a)

Classification

2 Operation

4 Transmission

3 Production

7 Customer Accounts

1 Electric

6 Distribution

5 Regional Market

34 Storage, LNG Terminaling and Processing

26 Sales (Transcribe from line 9)

25 Customer Service and Informational (Transcribe from line 8)

28 TOTAL OpeL and Maint. (Total of lines 20 thru 27)

32 Production-Nat. Gas (Including Expl. and Dev.)

23 Distribution (Enter Total of lines 6 and 16)

22 Regional Market (Enter Total of Lines 5 and 15)

30 Operation

29 Gas

33 Other Gas Supply

27 Administrative and General (Enter Total of lines 10 and 17)

17 Administrative and General

16 Distribution

15 Regional Market

12 Maintenance

38 Customer Service and Informational

11 TOTAL Operation (Enter Total of lines 3 thru 10)


39 Sales

9 Sales

31 Production-Manufactured Gas

8 Customer Service and Informational

41 TOTAL Operation (Enter Total of lines 31 thru 40)

24 Customer Accounts (Transcribe from line 7)

21 Transmission (Enter Total of lines 4 and 14)

20 Production (Enter Total of lines 3 and 13)

42 Maintenance

19 Total Operation and Maintenance

43 Production-Manufactured Gas

18 TOTAL Maintenance (Total of lines 13 thru 17)

46 Storage, LNG Terminaling and Processing

45 Other Gas Supply

47 Transmission

36 Distribution

37 Customer Accounts


44 Production-Natural Gas (Including Exploration and Development)

Line No.


Year/Period of ReportDate of ReportName of Respondent This ~ort Is: (Mo, Da, Yr) (1) ~An Original End of 2012/04Green Mountain Power Corporation 04/15/2013

DISTRIBUTION OF SALARIES AND WAGES (Continued)

(2) A Resubmission

ClassificationLine No.

(a)

48 Distribution


50 TOTAL Main!. (Enter Total of lines 43 thru 49)

51 Total Operation and Maintenance

52 Production-Manufactured Gas (Enter Total of lines 31 and 43)

53 Production-Natural Gas (Including Expl. and Dev.) (Total lines 32,

54 Other Gas Supply (Enter Total of lines 33 and 45)

55 Storage, LNG Terminaling and Processing (Total of lines 31 thru

56 Transmission (Lines 35 and 47)

57 Distribution (Lines 36 and 48)

58 Customer Accounts (Line 37)

59 Customer Service and Informational (Line 38)

60 Sales (Line 39)

61 Administrative and General (Lines 40 and 49)

62 TOTAL Operation and Maint. (Total of lines 52 thru 61)

63 Other Utility Departments

64 Operation and Maintenance

65 TOTAL All Utility Dept. (Total of lines 28,62, and 64)

66 Utility Plant

67 Construction (By Utility Departments)

68 Electric Plant

69 Gas Plant


71 TOTAL Construction (Total of lines 68 thru 70)

72 Plant Removal (By Utility Departments)

73

TotalDirect PayrollDistribulion

(b)

283,127 6,410 289,537

74

Electric Plant

Gas Plant


76 283,127 6,410 289,537

77

TOTAL Plant Removal (Total of lines 73 thru 75)

Other Accounts (Specify, provide details in footnote):

78 148,192 3,355 151,547

79

Busniess Development

721,414 16,332 737,746

80

Other Work in Progress

755,117 17,095 772.212

81

Other Oper Revenue - Mise Jobbing

Rental Water Heaters 26,491 600 27,091

82 Lobbying 212,731 4,816 217,547

83 Misc. Payroll 798.189 18,070 816,259

84

85

86

87

88

89

90

91

92

93

94

95 TOTAL Other Accounts 2,662,134 60,268 2,722,402

96 TOTAL SALARIES AND WAGES 28,797,216 651,937 29,449,153




This Report Is:

(1) 00 An Original (2) 0 A Resubmission

Date of Report (Mo,Da, Yr)

04/15/2013 End of 2012/04

COMMON UTILITY PLANT AND EXPENSES

1. Describe the property carried in the utility's accounts as common utility plant and show the book cost of such plant at end of year classified by accounts as provided by Plant Instruction 13, Common Utility Plant, of the Uniform System of Accounts. Also show the allocation of such plant costs to the respective departments using the common utility plant and explain the basis of allocation used, giving the allocation factors. 2. Furnish the accumulated provisions for depreciation and amortization at end of year, showing the amounts and classifications of such accumulated provisions, and amounts allocated to utility departments using the Common utility plant to which such accumulated provisions relate, including explanation of basis of allocation and factors used. 3. Give for the year the expenses of operation, maintenance, rents. depreciation, and amortization for common utility plant classified by accounts as provided by the Uniform System of Accounts. Show the allocation of such expenses to the departments using the common utility plant to which such expenses are related. Explain the basis of allocation used and give the factors of allocation. 4. Give date of approval by the Commission for use of the common utility plant classification and reference to order of the Commission or other authorization.


Name of Respondent Year/Period of Report Date of Report This wort Is: (1) An Original (Mo, Da, Yr) End of 2012/Q4Green Mountain Power Corporation

04/15/2013(2) 0 A Resubmission

AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS

1. The respondent shall report below the details called for concerning amounts it recorded in Account 555, Purchase Power, and Account 447, Sales for Resale, for items shown on ISO/RTO Selllement Statements. Transactions should be separately nelled for each ISO/RTO administered energy market for purposes of determining whether an entity is a net seller or purchaser in a given hour. Net megawall hours are to be used as the basis for determining whether a net purchase or sale has occurred. In each monthly reporting period, the hourly sale and purchase net amounts are to be aggregated and separately reported in Account 447, Sales for Resale, or Account 555, Purchased Power, respectively.

Description of Item(s) Line

I No. (a)

1 Energy

2 Net Purchases (Account 555)

3 Net Sales (Account 447)

4 Transmission Rights

5 Ancillary Services

6 Other Items (list separately)

7 RT Regulation Selliement

8 ICAP Settlement

9

10

I 11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

TOTAL46

Balance at End of Quarter 1

(b)

1,363,546

( 2,777,547)

( 36,432)

58,901

36,890

1,022,684

I Balance at End of Quarter 2

(c)

4,087,301

( 3,645,651 )

( 62,858)

164,644

73,413

3,272,469

( 331,958) 3,889,318


Balance at End of Quarter 3

(d)

9,189,501

( 5,059,004)

( 92,116)

271,437

111,299

4,737,640

9,158,757

Balance at End of Year (e)

22,521,089

( 8,866,674)

( 163,272)

774,538

232,533

7,142,499

21,640,713

Name of Respondent This [!J0rt Is: Date of Report YearlPeriod of Report

Green Mountain Power Corporation (1) An Original (Mo, Da, Yr) End of 2012/Q4 (2) FiA Resubmission 04/15/2013

PURCHASES AND SALES OF ANCILLARY SERVICES

Report the amounts for each type of ancillary service shown in column (a) for the year as specified in Order No. 888 and defined in the respondents Open Access Transmission Tariff.

In columns for usage, report usage-related billing determinant and the unit of measure.

(1) On line 1 columns (b), (c), (d), (e), (f) and (g) report the amount of ancillary services purchased and sold during the year.

(2) On line 2 columns (b) (c), (d), (e), (f), and (g) report the amount of reactive supply and voltage control services purchased and sold

during the year.

(3) On line 3 columns (b) (c), (d), (e), (f), and (g) report the amount of regulation and frequency response services purchased and sold

during the year.

(4) On line 4 columns (b), (c), (d), (e), (f), and (g) report the amount of energy imbalance services purchased and sold during the year.

(5) On lines 5 and 6, columns (b), (c), (d), (e), (f), and (g) report the amount of operating reserve spinning and supplement services purchased and sold during the period.

(6) On line 7 columns (b), (c), (d), (e), (f), and (g) report the total amount of all other types ancillary services purchased or sold during

the year. Include in a footnote and specify the amount for each type of other ancillary service provided.

Amount Purchased for the Year Amount Sold for the Year

Usage - Related Billing Determinant Usage - Related Billing Determinant

Unit of Unit of

linE Type of Ancillary Service Number of Units Measure Dollars Number of Units Measure Dollars

No. (a) (b) (c) (d) (e) (f) (g)

1 Scheduling, System Control and Dispatch 476,073

2 Reactive Supply and Voltage 444,327

3 Regulation and Frequency Response 230,147

4 Energy Imbalance

5 Operating Reserve Spinning

6 Operating Reserve Supplement 199,789

7 Other 1,137,248

8 Total (Lines 1thru 7) 2,487,584

FERC FORM NO.1 (New 2-04) Page 398

Name of Respondent Year/Period of ReportDate of ReportThis wort Is: (1) X An Original (Mo, Da, Yr)

End of 2012/04Green Mountain Power Corporation 04/15/2013(2) o A Resubmission

MONTHLY TRANSMISSION SYSTEM PEAK LOAD

(1) Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system. (2) Report on Column (b) by month the transmission system's peak load. (3) Report on Columns (c ) and (d) the specified information for each monthly transmission - system peak load reported on Column (b). (4) Report on Columns (e) through U) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for the definition of each statistical classification.

NAME OF SYSTEM:

Line Monthly Peak Day of Hour of Firm Network Firm Network Long-Term Firm Other Long Short-Term Firm Other No. Month MW - Total Monthly Monthly Service for Self Service for Point-to-point Term Firm Point-to-point Service

Peak Peak Others Reservabons Service Reservation

(a) (b) (c) (d) (e) (f) (g) (h) (i) U)

1 January 308 4 18 266 42

2 February 281 " 19 242 39

3 March 261 ~ 19 227 40

4 Talai for Quarter 1 8~ 735 121

5 April 244 1E 14 218 26

6 May 28/ 2S 15 257 30

7 June 32/ 21 16 291 36

8 Talai for Quarter 2 8~ 766 92

9 July 319 11 16 297 22

10 August 30/ 15 281 26

11 September 280 E 15 253 27

12 Talai for Quarter 3 90 831 75

13 Oclober 66C 1~ 19 589 71

14 November 76~ 2E 19 683 86

15 December 78E 3C 18 691 95

16 Tolal for Quarler 4 2,2~ 1,963 252

17 Total Year to

DalelYear 4,83< 4,295 540


-


End of 2012/04 04/15/2013

If the Respondent has two or more power systems which are not physically

system peak load reported on Column (b).

Through and Network Point-la-Point Total Usage

Out Service Service Usage Service Usage

(g) (h) (i) (j)

Name of Respondent This ~ort Is: (1) X An Original

Green Mountain Power Corporation (2) CiA Resubmission

MONTHLY ISO/RTO TRANSMISSION SYSTEM PEAK LOAD

(1) Report the monthly peak load on the respondent's transmission system. integrated, furnish the required information for each non-integrated system. (2) Report on Column (b) by month the transmission system's peak load. (3) Report on Column (c) and (d) the specified information for each monthly transmission (4) Report on Columns (e) through (i) by month the system's transmission usage by classification. Amounts reported as Through and Out Service in Column (g) are to be excluded from those amounts reported in Columns (e) and (f). (5) Amounts reported in Column U) for Total Usage is the sum of Columns (h) and (i).

NAME OF SYSTEM:

Line Monthly Peak Day of Hour of Imports into Exports from No. Month MW - Total Monthly Monthly ISO/RTO ISO/RTO

Peak Peak

I (a) (b) (c) (d) (e) (f)

1 January

2 February

3 March

4 Total for Quarler 1

5 April -6 May

7 June

8 Tolal for Quarler 2

9 July

10 August

11 September

12 Tolal for Quarter 3

13 October -14 November

15 December

16 Total for Quarter 4

17 Total Year to

DatelYear -

FERC FORM NO. 1/3-0 (NEW. 07-04) Page 400a

Name of Respondent Year/Period of Report Date of ReportThis R~ort Is: (1) An Original (Mo, Da, Yr) 2012/Q4End of Green Mountain Power Corporation (2) n A Resubmission 04/15/2013

ELECTRIC ENERGY ACCOUNT

Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.

Line Item Line Item MegaWatt Hours MegaWatt Hours No. No.

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

DISPOSITION OF ENERGY

2 Generation (Excluding Station Use): 22

1 SOURCES OF ENERGY 21

2,477,751

3 Steam

Sales to Ultimate Consumers (Including

Interdepartmental Sales)

4 Nuclear

38,418

547

5 Hydro-Conventional

Requirements Sales for Resale (See 2346,776

instruction 4, page 311.)

6 Hydro-Pumped Storage

175,020

301,857

7 Other

Non-Requirements Sales for Resale (See 24

instruction 4, page 311.)

8 Less Energy for Pumping

39,110

Energy Furnished Without Charge 25

4,844Energy Used by the Company (Electric

through 8)

269 Net Generation (Enter Total of lines 3 299,324

Dept Only, Excluding Station Use)

10 Purchases 27 155,441Total Energy Losses 2,615,028

28 2,940,440TOTAL (Enter Total of Lines 22 Through11 Power Exchanges:

27) (MUST EQUAL LINE 20) 12 Received

13 Delivered

14 Net Exchanges (Line 12 minus line 13)

15 Transmission For Other (Wheeling)

16 Received 622,925

17 Delivered 596,837

18 Net Transmission for Other (Line 16 minus 26,088

line 17)

19 Transmission By Others Losses

20 TOTAL (Enter Total of lines 9, 10, 14, 18 2,940,440

and 19)


I

! Name of Respondent Date of Report Year/Period of ReportThis 00rt Is: (1) X An Original (Mo, Da, Yr) 2012/04End ofGreen Mountain Power Corporation 04/15/2013(2) 0 A Resubmission

MONTHLY PEAKS AND OUTPUT

1. Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the required information for each non- integrated system. 2. Report in column (b) by month the system's output in Megawatt hours for each month. 3. Report in column (c) by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales. 4. Report in column (d) by month the system's monthly maximum megawatt load (60 minute integration) associated with the system. 5. Report in column (e) and (f) the specified information for each monthly peak load reported in column (d).

NAME OF SYSTEM:

Line No. Month Total Monthly Energy

Monthly Non-Requirments Sales for Resale & Associated Losses Megawatts

MONTHLY PEAK

(See Instr. 4) I Day of Month Hour

(a) (b) (c) (d) (e) (f)

29 January 213,833 32,404 266 4 18

30 February 184,756 23,480 242 2 19

31 March 209,294 49,777 227 5 19

32 April 161,348 7,597 218 16 14

33 May 165.640 14,885 257 29 15

34 June 173,537 13,742 291 21 16

35 July 185,652 11,540 297 17 16

36 August 187,499 11,131 281 3 15

37 September 165,321 8,208 253 6 15

38 October 403,264 32,571 589 15 19

39 November 402,994 46,417 683 26 19

40 December 487,302 50,651 691 30 18

41 TOTAL 2,940,440 302,403


Name of Respondent This Rr!J0rt Is:

Green Mountain Power Corporation (1) An Original (2) o A Resubmission

1. Report data for plant in Service only. 2. this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclas a joint facility. 4. more than one plant, report on line 11 the approximate average number of employeetherm basis report the Btu content or the gas and the quantity of fuel burned convert

fuel is burned in a plant furnish only the composite heat rate for all fuels burned.

ed to Mct.

ear plants.

s assignable to each plant.

Line No.

Item

(a)

Kind of Plant (Internal Comb, Gas Turb, Nuclear

Type of Constr (Conventional, Outdoor, Boiler, etc)

Plant

#2 Oil

BBL

1

2

3 Year Originally Constructed

Total Installed Cap (Max Gen Name Plate Ratings-MW)

Year Last Unit was Installed 4

5

6 Net Peak Demand on Plant - MW (60 minutes)

Plant Hours Connected to Load

Net Continuous Plant Capability (Megawatts)

When Not Limited by Condenser Water

When Limited by Condenser Water

Average Number of Employees

Net Generation, Exclusive of Plant Use - KWh

Cost of Plant: Land and Land Rights

Structures and Improvements

Equipment Costs

Asset Retirement Costs

Total Cost

Cost per KW of Installed Capacity (line 17/5) Including

7

8

9

10

11

12

13

14

15

16

17

18

19 Production Expenses: Oper, Supv, & Engr

Fuel

Coolants and Water (Nuclear Plants Only)

Steam Expenses

Steam From Other Sources

Steam Transferred (Cr)

Electric Expenses

Misc Steam (or Nuclear) Power Expenses

Rents

Allowances

Maintenance Supervision and Engineering

Maintenance of Structures

Maintenance of Boiler (or reactor) Plant

Maintenance of Electric Plant

Maintenance of Mise Steam (or Nuclear) Plant

Total Production Expenses

Expenses per Net KWh

Fuel: Kind (Coal, Gas, Oil, or Nuclear)

Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38 Quantity (Units) of Fuel Burned

Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)

0

a39

40 Avg Cost of Fuel/unit, as Delvd LO.b. during year

Average Cost of Fuel per Unit Burned

Average Cost of Fuel Burned per Million BTU

Average Cost of Fuel Burned per KWh Net Gen

Average BTU per KWh Net Generation

0.000

0.000

0.000

0.000

0.000

41

42

43

44


2012/Q4End of 04/15/2013

STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)

Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kwor more. Report in 3. Indicate by a footnote any plant leased or operated

If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend 6. If gas is used and purchased on a

7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one

Plant Name: Colchester #16 Name: Berlin #5

(c)(b)

Gas Turbine Gas Turbine

Outdoor Steel Enc!. Outdoor Steel Enc!.

1965 1972

1965 1972

18.00 41.90

0 0

a 0

0 0

0 0

0 0

1 1

96500 1931600

2439 48218

495681 575829

3185411 10946390

0 0

3683531 11570437

204.6406 276.1441

0 a 47958 455931

0 0

20858 26485

0 0

0 0

42834 53159

0 a 0 0

0 0

3588 5136

a 0

0 0

11443 9796

23683 70696

150364 621203

1.5582 0.3216

#1 Oil

BBL

0 0 11870 0

0 0 0 0

0.000 0.000 0.000 0.000

0.000 0000 0.000 0.000

0000 0.000 0.000 0.000

0

0

0.000

0.000

0.000

0.000

0.000

0.000 0.000 0.000 0.000 I

0.000 0.000 0.000 0000


Name of Respondent This ~ort Is:

Green Mountain Power Corporation (1) An Original (2) DA Resubmission

STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)

9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses.

designed for peak load service. Designate automatically operated plants. 11.

cycle operation with a conventional steam unit, include the gas-turbine with the steam plant.

report period and other physical and operating characteristics of plant.

Plant I Plant Name: Wyman #95 Name: Stony Brook Int. #96

(d) (e)

Steam

Conventional

1978

1978

7.00

0

0

0

0

0

92

609700

5738

308917

1868478

0

2183133

311.8761

0

299771

10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants

For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined

12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the

Plant Name: McNeil #24

(f)

Gas 1Steam

Tons

0

a 0.000

0000 0.000

0.000 0.000

0.000 0.000

0.000 0.000

Steam

Comb. Cycle Indoor Conventional

1981 1984

1981 1984

5.50

0

30.20

0

0a a a 0 0

0

32

a 38

10979300 37807900

738 30630

2041838 2322163

9555012 8002143

0 0

11597588 10354936

384.0261 1882.7156

0 45399

610226 r= 2180676

0 0 0

65796 527007 229611

0 0 0

0 a a 271 99417 92015

19411 a 230008

0 a a 0 a 0

I 527 20685 39536

0 25960 11065

0 0 165950

0 384789 26364 I

0 12012 15748

I 385776 1680096 3036372

0.6327 0.1530 0.0803

#2 Gas

MLF

a a 0.000

0000

0.000

0.000

0000

Wood Oil Gas

BBL BBL MLF

0 a 0 0 a 0 0 0 0 0

0000 0000 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 0.000

0000 0.000 0.000 0.000



ILine No.

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

#6 Gas

BBL MLF

a a 0 0

0.000 0.000

0.000 0.000

0000 0.000

0.000 0.000

0000 0.000


End of 2012/04

Name of Respondent This 00rt Is: (1) An Original


STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)

1, Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. more than one plant, report on line 11 the approximate average number of employees assignable to each plant. therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. fuel is burned in a plant furnish only the composite heat rate for all fuels burned.

Plant No.

Line Item Name: Rut/and

(a) (b)

1 Kind of Plant (Internal Comb, Gas Turb, Nuclear

2 Type of Constr (Conventional, Outdoor, Boiler, etc)


4 Year Last Unit was Installed

5 Total Installed Cap (Max Gen Name Plate Ratings-MW)

6 Net Peak Demand on Plant - MW (60 minutes)

7 Plant Hours Connected to Load

8 Net Continuous Plant Capability (Megawatts)

9 When Not Limited by Condenser Water

10 When Limited by Condenser Water

11 Average Number of Employees

12 Net Generation, Exclusive of Plant Use - KWh

13 Cost of Plant: Land and Land Rights

14 Structures and Improvements

15 Equipment Costs

16 Asset Retirement Costs

17 Total Cost

18 Cost per KW of Installed Capacity (line 17/5) Including

19 Production Expenses: Oper, Supv, & Engr

20 Fuel

21 Coolants and Water (Nuclear Plants Only)

22 Steam Expenses

23 Steam From Other Sources

24 Steam Transferred (Cr)

25 Electric Expenses

26 Misc Steam (or Nuclear) Power Expenses

27 Rents

28 Allowances

29 Maintenance Supervision and Engineering

30 Maintenance of Structures

31 Maintenance of Boiler (or reactor) Plant

32 Maintenance of Electric Plant

33 Maintenance of Misc Steam (or Nuclear) Plant

34 Total Production Expenses

35 Expenses per Net KWh

36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) Oil

37 Unit (Coal-tons/Oi I-barrel/Ga s-mdiNuclear-i ndi ca te) Barrel

38 Quantity (Unils) of Fuel Burned 148

39

0

Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 138021

40

0

Avg Cost of Fuel/unit, as Delvd f.o.b. during year 0.000 0.000

41 Average Cost of Fuel per Unit Burned 92.101

42

0.000

Average Cost of Fuel Burned per Million BTU 0.000 15868.000

43 Average Cost of Fuel Burned per KWh Net Gen 0.000 0.982

44 Average BTU per KWh Net Generation 0.000 61881.768


End of 2012/Q404/15/2013

(Continued)

Indicate by a footnote any plant leased or operated 5. If any employees attend

6. If gas is used and purchased on a Quantities of fuel burned (Line 38) and average cost

8. If more than one

Plant Name: Ascutney

(c)

GasTurbine Gas Turbine

Fuel Outdoor Fuel Outdoor

19611962

19611962

13.20 13.30

a a 174

0 a 0 a a 0

0 0

12463213882

18100

1957 8856

2713675 2175964

0 39261

2715632 2225891

205.7297 167.3602

0 0

13631 86689

0 a 0 a 0 a 0 0

5490 1249

0 0

a 0

a 0

a 0

0 0

0 0

14395 61624

a a 33516 149562

2.4143 1.2000

0 0

Oil

Barrel

775

138165

0.000

111.857

19.274

0.696

36087.724

0

0 a a 0.000 0000 0.000

0.000 0000 0.000

0.000 0.000 0.000

0.000 0.000 0.000

0.000 0000 0.000


Name of Respondent This 00rt Is: Date of Report YearlPeriod of Report (1) An Original (Mo, Da, Yr)

2012/04Green Mountain Power Corporation End of04/15/2013(2) DA Resubmission I STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)

9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development: (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the

I report period and other physical and operating characteristics of plant.

Plant I Plant

Name: Name: (d) (e)

0.00

a a a a a a a a a a a a a a a a a a a a a a a a a a a a a

0.0000

a a a a a a a a 0000 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 0.000

0.000 0.000 0.000 0.000

a a 0.000

0.000

0.000

0.000

0.000

a a 0000

0.000

0.000

0.000

0.000

0.00


00000

Plant Name:

(f)

a a a a 0.000 0.000

0.000 0.000

0.000 0.000

0.000 0.000

0.000 0.000

a a 0.000

0.000

0.000

0.000

0.000

0.00


0.0000

Line No.

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44



End of 2012/04

FERC Licensed Project No. 0 Plant Name:

(c)

0.00

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0.0000

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0 0

0.0000

Name of Respondent This ~ort Is: Date of Report

Green Mountain Power Corporation (1) An Original (Mo, Da, Yr) (2) o A Resubmission 04/15/2013

HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)

1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings) 2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a footnote. If licensed project, give project number. 3. If net peak demand for 60 minutes is not available, give that which is available specifying period. 4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each plant.

Line Item FERC Licensed Project No. 0 No. Plant Name:

(a) (b)

1 Kind of Plant (Run-of-River or Storage)

2 Plant Construction type (Conventional or Outdoor)



5 Total installed cap (Gen name plate Rating in MW) 0.00

6 Net Peak Demand on Plant-Megawatts (60 minutes)

7 Plant Hours Connect to Load

8 Net Plant Capability (in megawatts)

9 (a) Under Most Favorable Oper Conditions

10 (b) Under the Most Adverse Oper Conditions


12 Net Generation, Exclusive of Plant Use - Kwh

13 Cost of Plant

14 Land and Land Rights


16 Reservoirs, Dams, and Waterways

17 Equipment Costs

18 Roads, Railroads, and Bridges


20 TOTAL cost (Total of 14 thru 19)

21 Cost per KW of Installed Capacity (line 20 / 5) 0.0000

22 Production Expenses

23 Operation Supervision and Engineering

24 Water for Power

25 Hydraulic Expenses


27 Misc Hydraulic Power Generation Expenses

28 Rents



31 Maintenance of Reservoirs, Dams, and Waterways


33 Maintenance of Misc Hydraulic Plant

34 Total Production Expenses (total 23 thru 33)

35 Expenses per net KWh 0.0000




This ~ort Is: Date of Report (1) ~An Original (Mo, Da, Yr) (2) D A Resubmission 04/15/2013 End of 2012/04

HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)

5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses

do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."

6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.

FERC Licensed Project No.

Plant Name: (d)

o FERC Licensed Project No.

Plant Name: (e)

o FERC Licensed Project No.

Plant Name:

o Line No.

0 0 0

0 0 0

0 0 0

0 0 0

0 0 0

0 0 0

0 0 0

0.0000 0.0000 0.0000

0 0 0

0 0 0

0 0 0

0 0 0

0 0 0

0 0 0

0 0 0

0 0 0

0 0 0

0 0 0

0 0 0

0 0 0

0.0000 00000 0.0000


Name of Respondent Year/Period of ReportDate of Report I This R~ort Is:(1) An Original (Mo, Da, Yr)

2012/04Green Mountain Power Corporation End of 04/15/2013I (2) D A Resubmission

PUMPED STORAGE GENERATING PLANT STATISTICS (Large Plants)

1. Large plants and pumped storage plants of 10,000 Kw or more of installed capacity (name plate ratings) 2. If any plant is leased, operating under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a footnote. Give project number. 3. If net peak demand for 60 minutes is not available, give the which is available, specifying period. 4. If a group of employees attends more than one generating plant, report on line 8 the approximate average number of employees assignable to each plant. 5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses do not include Purchased Power System Control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."

Item No.

Line

(a)

1 Type of Plant Construction (Conventional or Outdoor)



4 Total installed cap (Gen name plate Rating in MW)

5 Net Peak Demaind on Plant-Megawatts (60 minutes)

6 Plant Hours Connect to Load While Generating

7 Net Plant Capability (in megawatts)


9 Generation, Exclusive of Plant Use - Kwh

10 Energy Used for Pumping

11 Net Output for Load (line 9 - line 10) - Kwh

12 Cost of Plant

13 Land and Land Rights


15 Reservoirs, Dams, and Waterways

16 Water Wheels, Turbines, and Generators

17 Accessory Electric Equipment

18 Miscellaneous Powerplant Equipment

19 Roads, Railroads, and Bridges


21 Total cost (total 13 thru 20)

22 Cost per KW of installed cap (line 21 /4)

23 Production Expenses

24 Operation Supervision and Engineering

25 Water for Power

26 Pumped Storage Expenses


28 Misc Pumped Storage Power generation Expenses

29 Rents



32 Maintenance of Reservoirs, Dams, and Waterways


34 Maintenance of Misc Pumped Storage Plant

35 Production Exp Before Pumping Exp (24 thru 34)

36 Pumping Expenses

37 Total Production Exp (total 35 and 36)

38 Expenses per KWh (line 37/9)

I


(b)


Name of Respondent This ~ort Is: Date of Report

Green Mountain Power Corporation (1) An Original (Mo, Da, Yr) (2) o A Resubmission 04/15/2013 End of

PUMPED STORAGE GENERATING PLANT STATISTICS (Large Plants) (Continued)

6. Pumping energy (Line 10) is that energy measured as input to the plant for pumping purposes. 7. Include on Line 36 the cost of energy used in pumping into the storage reservoir. When this item cannot be accurately computed leand 38 blank and describe at the bottom of the schedule the company's principal sources of pumping power, the estimated amounts of station or other source that individually provides more than 10 percent of the total energy used for pumping, and production expenses preported herein for each source described. Group together stations and other resources which individually provide less than 10 percenenergy. If contracts are made with others to purchase power for pumping, give the supplier contract number, and date of contract.

ave Lines 36, 37

t of total pumping

energy from each er net MWH as


(c)

FERC Licensed Project No. 0

Plant Name: (d)

FERC Licensed Project No.

Plant Name: (e)


2012/04

Line No.

0

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38


Name of Respondent


1.

storage plants of less than 10,000 Kw installed capacit

give project number in footnote.

y (name plate rating).

Line No.

Name of Plant

(a)

HYDRO

Middlesex Station # 2

Marshfield Station # 6

Vergennes Station # 9 C License# 2674

W, Danville Station # 15

Gorge Station # 18

Essex station # 19 B License# 2531

Waterbury Station # 22 A License# 2090

DeForge station # 1 D License# 2879

Huntington Falls #203

Beldens #204

Proctor #205

Center Rutland #206

Pittsford #207

Glen #208

Patch #209

Carver Falls #210

Cavendish #211

Salisbury #212

Silver Lake #213

Middlebury Lower #214

Weybridge #215

Taftsville #216

Smith #217

Pierce Mills #218

Arnold Falls #219

Gage #220

Passumpsic #221

East Barnet #222

Fairfax #223

Clark Falls #224

Milton #225

Peterson #226

DIESEL

Vergennes Station # 9

Essex Station # 19

St. Albans #202

Nuclear

Millstone #227

Cost of plant for diesel plants is included in

the Hydro plant above

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

This wort Is: (1) X An Original (2) DA Resubmission

GENERATING PLANT STATISTICS (Small Plants)

2.

Year Orig.

Const. (b)

Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and pumped

the Federal Energy Regulatory Commission, or operated as a joint facility, and give a concise statement of the facts in a footnote.

1928

1927

1912

1917

1928

1917

1953

1986

1911

1913

1905

1898

1941

1920

1921

1894

1907

1917

1917

1917

1951

1910

1982

1928

1928

1921

1929

1984

1919

1937

1929

1948

1963

1947

Installed Ca~acity Name Plate atin,

(In MW) (c)

3.20

5.00

2,40

1.00

3.00

7.20

5.52

7.50

5.50

5.85

6.93

0.28

3.60

2.00

0,40

2.55

1,44

1.30

220

2.25

3.00

0.50

1.50

0.25

0.35

0.70

0.70

2.20

4.20

3.00

7.50

6.35

4.00

4.00


End of 2012/04 04/15/2013

Designate any plant leased from others, operated under a license from

If licensed project,

Net Peak Net Generation Demand Excluding Cost of Plant MW Plant Use

(60(B1in .) (e) (f)

10,201 3,443,080

7,108 12,688,106

10,894 12,313,608

1,033 3,425,128

2,357,269

40,663 14,578,828

16,947 2,427,567

22,678 14,471,417

4.5 5,684 6,869,031

5.0 5,032 7,316,170

4.0 856 5,121,707

342,475

3,4 2,260 5,760,375

2.1 1,639 4,675,344

0.2 526,067

1.7 2,536 4,114,400

1.7 1,370 1,813,485

1.2 964 1,438,712

2.2 1,515 3,003,915

1.7 2,455 3,025,512

3,4 4,437 3,491,750

0.2 385,397

1.1 900 4,734,031

0.2 302 336,757

03 89 2,102,664

0.7 575 818,378

0.5 588 434,163

20 106 6,346,914

4.0 7,748 3,897,283

2.9 5,341 3,805,038

7.0 12,807 5,147,099

6.2 8,996 1,823,179

47

59

46,776


Name of Respondent Date of Report Year/Period of ReportThis wort Is: (1) X An Original (Mo, Da, Yr)

End of 2012/04Green Mountain Power Corporation 04/15/2013(2) D A Resubmission

GENERATING PLANT STATISTICS (Small Plants) (Continued)

3. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11, Page 403. 4. If net peak demand for 60 minutes is not available, give the which is available, specifying period. 5. If any plant is equipped with combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas turbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.

Production Expenses Fuel Costs (in cents Plant Cost (Incl Asset Operation LineKind of FuelRetire. Costs) Per MW Exc'l. Fuel (per Million Btu) Fuel Maintenance No. (h) (i) (k) (I)

1

1,075,962

(g) U)

114,350 109,973 2

2,537,621 104,688 72,273 3

5,130,670 121,688 4

3,425,128

136,892

75,501 94,518 5

785,756 73,690 6

2,024,837

65,907

220,732 7

439,777

266,799

80,052 87,211 8

1,929,522 115,912 194,614 9

1,248,915 2,548 12,758 10

1,250,627 20,381 22,142 11

739,063 11,619 62,634 12

1,223,125 2,819 5,532 13

1.600,104 28,213 25,060 14

2,337,672 15,711 15

1,315,168

16,408

3,324 16

1,613,490

1,716

24,999 19,702 17

1,259,365 10,563 6,443 18

1,106,702 8,547 3,508 19

1,365,416 16,534 21,106 20

1,344,672 21,828 9,593 21

1,163,917 13,441 50,492 22

770,794 9,485 6,129 23

3,156,021 4,230 748 24

1,347,028 349 2,893 25

6,007,611 2,918 7,602 26

1,169,111 2,079 7,029 27

620,233 1,587 1,401 28

2,884,961 4,885 38,972 29

927,924 16,498 45,229 30

1,268,346 19,245 15,120 31

686,280 13,626 15,206 32

287,115 10,110 8,562 33

34

35

36

47,034 11,322 22,350 # 2 OIL 37

23.394 14,754 9,630 # 2 OIL 38

39

40

256,248 323,765 475,321 41

42

43

44

45

46


Name of Respondent This R~Ort Is: (1) An Original


TRANSMISSION LINE STATISTICS

1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132 kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage. 2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. substation costs and expenses on this page. 3. Report data by individual lines for all voltages if so required by a State commission. 4. Exclude from this page any transmission lines for which plant costs are included in Account 121 , Nonutility Property. 5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder of the line. 6. Report in columns (f) and (g) the total pole miles of each transmission line. reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with respect to such structures are included in the expenses reported for the line designated.

DESIGNATION VOLTAGE (KV) LENGTH rOle miles)Line (Indicate where

No. other than 60 cycle, 3 phase)

From To Operating Designed (a) (b) (c) (d)

1 VT/NH Border Canadian Border

2 450.0C

3

4

Metallic Neutral Return

115.00

5 69.00

6 34.5C

7 46.0C

8 118C

9

10

11 11.0C

12

13

Marble Street#2 Center Rutland

34.5C

14

15

16

17

Various Various

Various 34.5C

18

19

20

Various

Various 46.0C

21

22

23

24

Various

Various Various 46.0C

25

26

27 Various Various 69.0C

28

29

30 Various Various 690C

31

32

33 Ladder Hill m.oeVernon Road

34

35 Canadian Boarder Highgate Converter 12O.0e

36



End of 2012/04

Do not report

Show in column (f) the pole miles of line on structures the cost of which is

Type of

Supporting

Structure (e)

~In the u

Un ~tructure of Line

DesiRnated f)

35.00

2.58

11.35

248.58

16.00

2.44

275

121.37

3.72

0.16

3.79

328

50369

2322

1.26

0.74

0.11

9.04

1.26

0.61

7.58

998.53

H-frame steel

H-frame wood

Single Pole

Single Pole

Single Pole

Single Pole

Underground

Wood Pole

Wood Pole

(H. Frame)

(Steel Tower)

H. Frame

(Wood Pole)

Wood Pole

(H. Frame)

(Steel Tower)

H. Frame

(Wood Pole)

Wood Pole

(H. Frame)

H. Frame

(Wood Pole)

Wood Pole

H. Frame

TOTAL

aSJ ofdergroun lines report circuit miles)

un,:::;.tru<;iuresof Another

Line (g)

450.00

1100

34.50 1.67

3450

46.00 2.92

46.00 4.92

0.60

69.00

69.00

115.00

120.00

10.11

Number

Of

Circuits

(h)

1

4

5

35

1

1

1

22

1

97

1

3

1

1

1

175


Name of Respondent Year/Period of ReportDate of ReportThis ~ort Is: (1) An Onglnal (Mo. Da. Yr)

End of 2012/04Green Mountain Power Corporation 04/15/2013

TRANSMISSION LINE STATISTICS (Continued)

(2) nA Resubmission

7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g) 8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company. give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line. or portion thereof. for which the respondent is not the sole owner but which the respondent operates or shares in the operation of. furnish a succinct statement explaining the arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner. basis of sharing expenses of the Line. and how the expenses borne by the respondent are accounted for. and accounts affected. Specify whether lessor. co-owner. or other party is an associated company. 9. Designate any transmission line leased to another company and give name of Lessee. date and terms of lease. annual rent for year. and how determined. Specify whether lessee is an associated company. 10. Base the plant cost figures called for in columns U) to (I) on the book cost at end of year.

COST OF LINE (Include in Column U) Land. EXPENSES. EXCEPT DEPRECIATION AND TAXES

Size of Land rights. and clearing right-of-way)

Conductor Land Construction and Total Cost Operation Maintenance Rents Total Lineand Material

Other Costs Expenses ExpensesExpenses No.(0)(i) (k) (p)U) (I) (m) (n)

2839.8MCM 1

1,563,276 1.563,276 2

3

iIl,CSR

~CSR

244,69S 776,583 1.021,282 4

5

6

7

8

750 MCMCU 9

10

#2AL 44,734 44,734 11

12

Various 358,75 5,306,498 5,665.251 113.112 317,431 431,428 13

14

15

16

885

17

18

19 Various 3,087,216 22,814,039 25,901,255 570,696 2.571.920 4,464 20

21

22

23

24

25

26 Various

3.147,08C

13,43C 1.515,639 1,529,069 27

28

29

30

31

32 795 ACRS 19,81S 49,034 68,853 33

34 954 ACRS 347,00E 992,182 1,339,188 51,932 6,042 406 3558,38C

4,876,747 52,739,338 57,616.085 735,740 2,895,393 5,755 3,636,888 36



Name of Respondent This [!]Ortls:

Green Mountain Power Corporation (1) An Original


TRANSMISSION LINE STATISTICS

1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132 kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage. 2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. substation costs and expenses on this page. 3. Report data by individual lines for all voltages if so required by a State commission. 4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property. 5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder of the line. 6. Report in columns (f) and (g) the total pole miles of each transmission line. reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with respect to such structures are included in the expenses reported for the line designated.

Line DESIGNATION VOLTAGE (KV) LENGTH rOle miles)(I ndicate where

No. other than dergroun 60 cycle, 3 phase) report circuit miles)

From To Operating Designed (a) (b) (c) (d)

1

2

3 Total Group 1150(

4 Total Group 69.0C

5 Total Group 34.50

6 Total Group 118C

7 Less than 132KV

8 Total Group 34.5C

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

Type of ~In the u Supporting

Un ~tructure

Structure of Line DesiRnated(e) f)

998.53

ShlWd

TOTAL 99853


End of 2012/04

Do not report

Show in column (f) the pole miles of line on structures the cost of which is

aSJ of Numberlines

Of Un):i,truC;lures Circuitsof Another

Line (g) (h)

10.11 175

10.11 175


Name of Respondent Date of Report Year/Period of ReportThis ~ort Is: (1) An Original (Mo, Da, Yr)


TRANSMISSION LINE STATISTICS (Continued)


7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if

you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the

pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g) S. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company, give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or

other party is an associated company.

9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how

determined. Specify whether lessee is an associated company.

10. Base the plant cost figures called for in columns (j) to (I) on the book cost at end of year.

COST OF LINE (Include in Column U) Land, EXPENSES, EXCEPT DEPRECIATION AND TAXES

Size of Land rights, and clearing right-of-way)

Conductor Operation Maintenance Rents TotalLand Construction and Total Cost Lineand Material

Other Costs Expenses Expenses Expenses No.(0)(i) (j) (k) (I) (p)

1

2

4,070,92J 33,061,985 37,132,908 735,740 2,S95,393 5,755 3,636,SSE

(n)(m)

3

4

5

6

805,824 19,677,353 20,483,177 7

805,824 19,677,353 20,483,177 8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

4,876,747 52,739,338 57,616,085 735,740 2,895,393 5,755 3,636,88E 36


Name of Respondent Date of Report Year/Period of Report This ~ort Is: (1) An Original (Mo, Da, Yr)


TRANSMISSION LINES ADDED DURING YEAR


1. Report below the information called for concerning Transmission lines added or altered during the year. It is not necessary to report

minor revisions of lines.

2. Provide separate subheadings for overhead and underground construction and show each transmission line separately. If actual

costs of competed construction are not readily available for reporting columns (I) to (0), it is permissible to report in these columns the

Present Ultimate

(f) (g)

1

1

1

1

1

1

1

1

LINE DESIGNATION Line No. From

(a)

1 West Rutland

2 Florence

3 Proctor Tap

4 West Rutland

5 Omya Tap

6 Huntington Falls

7 Weybridge

8 Smead Road

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44 TOTAL

To

(b)

Danby

West Rutland

Center Rutland

Florence

New Haven

Salisbury

Line Le~gth

In Miles

(c)

21.01

6.87

1.81

2.75

0.21

28.72

5.05

1.97

68.39

SUPPORTING STRUCTURE

Type

(d)

Wood

Wood

Wood

Wood

Wood

Wood

Wood

Wood

Average Number per

Miles (e)

20.00

27.00

24.00

20.00

2300

21.00

17.00

26.00

178.00

CIRCUITS PER STRUCTUR

1

1

1

1

1

1

1

1

,

8 8

Year/Period of Report Date of ReportName of Respondent This mort Is: (Mo, Da, Yr)(1) An Original End of 2012/Q4Green Mountain Power Corporation 04/15/2013

TRANSMISSION LINES ADDED DURING YEAR (Continued)

costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and

Trails, in column (I) with appropriate footnote, and costs of Underground Conduit in column (m).

(2) nA Resubmission

3. If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase,

indicate such other characteristic.

CONDUCTORS LINE COST LineVoltage Poles, TowersSize AssetConductors No.TotalLand andSpecification Conf~uration KV and Fixturesand pacing Land Rights Retire. Costsand Devices(Operating)

(p)

#2

(m) (n) (0)(I)(h) (i) (k)(j) 1

1/0

361,042253,179107,864'-8"ACRS 46

2188,35884,104104,254ACRS 4'-8" 46

3

#2

158,08544,60327,999 85,48~4'-8" 461/0 ACRS

4

477 & 1/0

44,7349,96134,773'-10"AAC 11

26,875 58,65246 18,22'AAC&ACS 4'-8"

6

477

792,389382,26646 410,12~312.8 AAC 4'-8"

71,153,367421,0614'-8" 732,30EACRS 46

20,147 8

9

10

11

12

13

14

15

16

7,9745'-0" 12,17"4/0 ACRS 46

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

27,999 1,211,800 2,744,9971,505,19i 44


Date of Report (Mo, Da, Yr) End of04/15/2013

Name of Respondent This @ort Is: (1) X An Original


SUBSTATIONS

1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to functional character, but the number of such substations must be shown. 4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in column (f).

Line Name and Location of Substation Character of SubstationNo.

(b)(a)

Montpelier #3/Montpelier Dist.lUnattended1

2 Berlin Gas Turbine #5/Berlin Trans./Unattended

Vergennes #9/Vergennes 3 Trans./Unattended

4 Vergennes #9/Vergennes Dist.lUnattended

Gorge #16/Colchester Trans./Unattended5

Gorge #16/Colchester Dist.lUnattd.6

7 Essex #19/Essex Trans./Unattended

Essex #19/Essex Trans./Unattended8

Essex #19/Hill Top/Essex Dist.lUnatt.9

Mountain View #27/Montpelier Dist.lUnattended10

Mountain View #27/Montpelier Dist.lUnattended11

12 Queen City #32/So. Burlington Dist./Unattended

13 Sand Road #33/Essex DisUUnattended

Mallets Bay #34/Colchester Dist.lUnattended14

Dist.lUnattended15 So. End #37/Barre

16 So. End #37/Barre City Dist./Unattended

17 So. End #37/Barre City Dist./Unattended

18 Madubush #38/Warren Dist.lUnattended

19 Irasville #39/Fayston Dist.lUnattended

20 Bolton #41 /Bolton Dist.lUnattended

21 Digital #43/So. Burlington Dist.lUnattended

22 Shelburne #53/Shelburne Dist./Unattended

Wilmington #56/Wilmington 23 Dist./Unattended

Websterville #61 Barre Town 24 Dist.lUnattended

25 Barre North End #63/Barre City Dist.lUnattended

Barre North End #63/Barre City 26 Dist.lUnattended

27 Berlin #40/Berlin Dist.lUnattended

Berlin #40/Berlin 28 Dist.lUnattended

Richmond #51/Richmond (Jt Owned VEC) 29 Dist./Unattended

Wilder #71 /Hartford30 Dist./Unattended

Dorset SI. #78/So. Burlington31 Dist./Unattended

32 Dover #90/Dover Dist./Unattended

Dover #90/Dover Dist./Unattended33

34 Bolton Falls #1 /Duxbury Trans/Unattended

35 Charlotte #28/Charlotte Dist./Unattended

36 Waterbury #60/Waterbury Dist./Unattended

37 Town Line #44/Williston Dist./Unattended

38 Putney #69/Putney Dist./Unattended

Sleeply Hollow #92/Searsburg 39 Trans/Unattended

40 Tafts Corners/Williston DisUUnattened

I

Primary (c)

34.50

13.20

2.40

34.50

13.80

34.40

2.40

13.20

34.50

34.50

34.50

34.50

34.50

34.50

34.50

34.50

34.50

34.50

34.50

34.50

34.50

115.00

67.00

34.50

34.50

34.50

34.50

34.50

34.50

4.60

34.50

67.00

67.00

4.16

115.00

34.50

34.40

67.00

13.20

115.00

Year/Period of Report 2012/Q4

VOLTAGE (In MVa)

Secondary Tertiary (e)

12.47

34.50

34.50

12.47

34.50

4.16

34.50

34.50

12.47

4.16

12.47

12.47

12.47

12.47

2.40

4.16

12.47

12.47

12.47

12.47

12.47

12.47

12.47

12.47

4.16

12.47

4.16

12.47

12.47

12.47

12.47

12.47

12.47

34.50

13.20

4.16

13.20

8.32

67.00

13.20

(d)


Name of Respondent Date of Report Year/Period of Report This [8]0rt Is: (Mo, Da, Yr)(1) X An Original End of 2012/Q4Green Mountain Power Corporation 04/15/2013(2) o A Resubmission

SUBSTATIONS (Continued)

5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. 6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.

Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT IUneCapacity of Substation Transformers Spare

Total Capacity No.Type of Equipment (In Service) (In MVa) Number of Units In Service Transformers (In MVa) (f) (i) (k)(g) (h) m

111 1

256 1

37 1

414 1

518 1

65 1

79 1

814 1

936 2

107 1

1120 1

1222 1

11 1 Condenser 3 13 13

1414 1

155 1

165 1

1711 1

22 1 Condenser 4 14 18

1911 1

2011 1

2122 1 Condenser 2 11

2220 1

2314 3


253 3

2611 1

2711 1

2811 1

2911 1

3014 1

3122 1

3223 1

3314 1

3411 1

3520 1

3611 1

3714 1

3814 1

397 1

4056 1


Date of Report Year/Period of ReportName of Respondent This @ort Is: (Mo, Da, Yr) (1) X An Original 2012/Q4End ofGreen Mountain Power Corporation 04/15/2013

SUBSTATIONS



Primary(c)

34.50

34.50

34.50

34.50

34.50

34.50

115.00

34.50

34.50

34.50

34.50

46.00

13.80

67.00

34.50

34.50

34.50

34.50

44.00

67.00

44.00

69.00

115.00

44.00

44.00

44.00

44.00

44.00

46.00

44.00

44.00

44.00

44.00

34.50

44.00

44.00

34.50

44.00

46.00

44.00

VOLTAGE (In MVa) Line Character of Substation Name and Location of Substation No. Secondary Tertiary

(d) (e)

1

(a) (b)

13.20

2

Barnet #14/Barnet DisUUnattended

7.20West Danville #15/Danville DisUUnattended

Middlesex #2/Moretown DisUUnattended 2.40

4

3

4.16Little River #22/Waterbury DisUUnattended

Barre #26/Barre City DisUUnattended 2.40

6

5

Ethan Allen #36/Colchester 12.47

7

DisUUnattended

North Ferrisburgh #45/Ferrisburgh DisUUnattended 12.47

Marshfield #6/Marshfield 4.168 DisUUnattended

Riverton #62/Berlin DisUUnattended 4.16

10

9

Waterford #65/Waterford 4.16

11

DisUUnattended

Moretown #66/Moretown 4.16

12

DisUUnattended

Bridge St #67/Bellows Falls DisUUnattended 13.20

13 White River #70/Hartford DisUUnattended 4.16

14 Westminster #74/Westminster DisUUnattended 8.32

15 Airport#79/So. Burlington 4.16

16

DisUUnattended

Iroquois #81 /Colchester DisUUnattended 12.47

Legare #83/Ryegate 17 DisUUnattended 12.47

18 Ryegate #85/Ryegate DisUUnattended 13.20

19 Woodford Road -Bennington VT DisUUnattended 12.50

20 No. Brattleboro-Brattleboro VT DisU Unattended 44.00

21 No. Brattleboro-Brattleboro VT DisUUnattended 12.50

22 Brudies Road - Brattleboro VT DisUUnattended 12.50

23 Vernon Road - Brattleboro VT Transmission U 46.00

24 Vernon Road - Brattleboro VT DisUUnattended 1250

25 Fair Haven Village - Fair Haven VT DisUUnattended 4.00

26 Ely - Fairlee VT DisUUnattended 12.50

27 Mendon - Mendon VT DisUUnattended 12.50

28 Wells River - Newbury VT DisUUnattended 12.50

29 Newbury - Newbury VT DisUUnattended 12.50

30 Rochester - Rochester VT DisUUnattended 12.50

31 East Rutland - Rutland City VT DisUUnattended 12.50

32 North Rutland - Rutland Town VT DisUUnattended 12.50

33 Mill Street - Bennington VT DisUUnattended 12.50

34 Georgia - Georgia VT DisUUnattended 12.50

35 Quechee - Hartford VT DisUUnattended 12.50

36 Pleasant Street - Randolph VT DisUUnattended 12.50

37 Bay Street - SI. Johnsbury VT DisUUnattended 12.50

38 South Street - Springfield VT DisUUnattended 12.50

39 Riverside - Springfield VT DisUUnattended 12.50

40 Windsor - Windsor VT DisUUnattended 12.50


Year/Period of Report Date of Report Name of Respondent This wort is: (Mo, Da, Yr)(1) X An Original 2012/Q4End ofGreen Mountain Power Corporation 04/15/2013

SUBSTATIONS (Continued) (2) o A Resubmission

5. Show in columns (1),0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for

increasing capacity. 6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.

Number of Number of CONVERSiON APPARATUS AND SPECIAL EQUIPMENT LineCapacity of Substation Transformers Spare Total Capacity No.Type of Equipment(In Service) (In MVa) Number of UnitsIn Service Transformers (In MVa)

(k)

7 1 (i) U)(f) (g) (h)

1

21 3 3

4 4 1

8 1

6 2 5

614 1 710 1 86 3 99 3

101 3 112 1 1214 1 137 1 1414 1 15

11

2 1 16

4 1

1 17

184 1 1913 1

2013 1 2113 1 2213 1 23

13 1

72 2

24

6 1 25

4 1 26

31 27

4 1

2 1 28

6 1 29

4 1 30

13 31

11

1

32

13

1

33

13

1

34

13

1

35

13

1

36

9 1

1

37

13 38

13

1

39

13

1

401


(Mo, Da, Yr) 04/15/2013

Name of Respondent This @ort Is: (1) X An Original

Green Mountain Power Corporation (2) o A Resubmission

SUBSTATIONS


Line Name and Location of Substation Character of Substation No.

(b)(a)

1 Gas Turbine - Rutland VT Combination U

Combination U Gas Turbine - Ascutney VT2

North Hyde Park - Johnson VT DisUUnattended3

4 Lowell - Lowell VT Transmission U

5 East Thetford - Thetford VT DisUUnattended

South Rutland - Rutland VT DisUUnattended6

7 Lalor Avenue - Rutland VT DisUUnattended

Weybridge - Weybridge VT Combination U 8

Milton - Milton VT Combination U 9

10 Milton - Milton VT DisUUnattended

11 Nason Street - St Albans VT DisUUnattended

12 Rawsonville - Jamaica VT DisUUnattended I

East Barnard - Barnard VT 13 DisUUnattended

14 Silk Road - Bennington VT DisUUnattended

15 South Brattleboro - Brattleboro VT DisUUnattended

16 Manchester - Manchester VT DisUUnattended

Sheldon Springs - Sheldon VT 17 DisUUnattended

18 Underhill - Jericho VT DisUUnattended

19 Ryegate - Ryegate VT Transmission U

20 Stratton Mountain - Winhall VT DisUUnattended

21 Bromley - Winhall VT DisUUnattended

22 Woodstock - Woodstock VT DisUUnattended

Snowshed - Sherburne VT23 DisUUnattended

24 Middlebury #2 - Middlebury VT DisUUnattended

25 East Middlebury - Middlebury VT DisUUnattended

26 Sherburne - Sherburne VT DisUUnattended

North Bennington - Bennington VT 27 DisUUnattended

28 Pittsford Village - Pittsford VT DisUUnattended

29 East - St Albans VT DisUUnattended

Lyons Street - Bennington VT 30 DisUUnattended

31 North Springfield - Springfield VT DisUUnattended

32 Bethel - Royalton VT DisUUnattended

Londonderry - Londonderry VT 33 DisUUnattended

West Milton - Milton VT 34 DisUUnattended

35 North Elm Street - St Albans VT DisUUnattended

Kendall Farm - Winhall VT 36 Transmission U

37 Miscellaneous - Various (78) DisUU nattended

38 Miscellaneous - Various (31) Transmission U

39 Miscellaneous - Various (10) Combination U

Total40


End of 2012/04 Date of Report

VOLTAGE (In MVa)

TertiaryPrimary Secondary (d) (e)(c)

12.5044.00

13.2044.00

4.0034.50

44.00 34.50

4400 12.50

12.5044.00

12.5046.00

44.00 12.50

2.3034.50

34.50 12.50

34.50 12.50

44.00 12.50

44.00 34.50

44.00 12.50

12.5069.00

44.00 12.50

12.5034.50

34.50 1250

4600 34.50

46.00 12.50

44.00 12.50

12.5044.00

34.50 1250

44.00 12.50

44.00 12.50

44.00 12.50

44.00 12.50

44.00 12.50

34.50 12.50

44.00 12.50

44.00 12.50

4400 1250

44.00 12.50

34.50 12.50

34.50 12.50

4600 13.80

4861.06 1593.34


Name of Respondent YearlPeriod of Report Date of Report This ~ort Is: (Mo, Da, Yr)(1) X An Original End of 2012/Q4Green Mountain Power Corporation 04/15/2013(2) o A Resubmission

SUBSTATIONS (Continued)

5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. 6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.

Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT LineCapacity of Substation Transformers Spare

No.(In Service) (In MVa) Type of Equipment Number of Units Total Capacity In Service Transformers I (In MVa)

(f) (g) (i) (k)(h) Ul 118 3

211 1

31 3

420 1

56 1

625 2 713 1

813 2

99 1

1011 1

1113 1 1

126 1

1320 1

1413 1

1513 2

1622 2

179 1

1810 2

1919 1

2041 2 1

2113 1

229 1

2313 1

2421 2

2513 1

2625 2

2713 1

2813 1

2913 1

3013 1

3113 1

3213 1

339 1

349 1

12 351


37241 78

3852 31

3923 10

1912 40264 3 13 76


20

Year/Period of ReportName of Respondent Date of ReportThis ~ort Is: (1) An Original (Mo, Da, Yr) 2012/Q4End ofGreen Mountain Power Corporation

04/15/2013(2) nA Resubmission

TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES 1. Report below the information called for concerning all non-power goods or services received from or provided to associated (affiliated) companies. 2. The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount billed to the respondent or billed to

an associated/affiliated company for non-power goods and services. The good or service must be specific in nature. Respondents should not attempt to include or aggregate amounts in a nonspecific category such as "general".

3. Where amounts billed to or received from the associated (affiliated) company are based on an allocation process, explain in a footnote.

Line Name of

Associated/Affiliated Account

Charged or Amount

Charged or No. Description of the Non-Power Good or Service Company Credited Credited

(a) (b) (c) (d)

1 Non-power Goods or Services Provided by Affiliated

2 Construction VELCO

3 Highgate Transm Facility Operating & Maint Cost VELCO

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

107 3,853,291

568,569,570,107 3,232,909

Non-power Goods or Services Provided for Affiliate

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

FERC FORM NO.1 (New) Page 429 FERC FORM NO. 1-F (New)



FOOTNOTE OATA

Schedule Page: 224 Line No.: 6 Column: a Amounts acquired in the merger between CVPS and GMP were Schedule Page: 224 Line No.: 7 Column: g undsitributed earnings transferred in CVPS merger = 825301

Schedule Page: 224 Line No.: 31 Column: g undistributed earnings transferred in CVPS merger = 31254001 Schedule Page: 224.1 Line No.: 1 Column: g undistributed earnings transferred from CVPS merger = -13378450 Schedule Page: 224.1 Line No.: 24 Column: a Investment in affiliates and subsdidiaries acquired in the merger with CVPS were Vermont electric power company=$2,557,001 Vermont Transco LLC=$166,492,611 Maine Yankee Atomic Power Corp=$43,993 Vermont Yankee Nuclear Power Corporation=$2,819,339 Yankee Atomic electric Company (massachusetts) =$55, 322 Connecticut Yankee Atomic Power company=$43,444 CV Rea1ty=$110,485 Catamount Resources Corporation=$2,255,249




FOOTNOTE DATA

Schedule Page: 266 Line No.: 5 Column: g amount acquired in CVPS merger=1713711 plus east barnet hydro 259484




FOOTNOTE OATA

Schedule Page: 274 Line No.: 11 Column: j amount acquired in CVPS merger =68,346,190 plus east barnet hydro of 836,321

Schedule Page: 274 Line No.: 12 Column: j amount acquired in CVPS merger = 13,365506 plus east barnet hydro of 221,325


Name of Respondent This Report is: Date of Report Year/Period of Report (1) 6 An Original (Mo, Da, Yr)


FOOTNOTE OATA

Schedule Page: 276 Line No.: 3 Column: j amounts acquired in CVPS merger = 30700762 Schedule Page: 276 Line No.: 6 Column: j amounts acquired in CVPS merger, including east brnet hydro, 23,938,999




FOOTNOTE DATA

Schedule Page: 352 Line No.: 1 Column: a RKS Research & Consulting - Customer Survey




FOOTNOTE DATA

Schedule Page: 426 Line No.: 22 Column: a

Schedule Page: 426 Line No.: 35 Column: a Footnote Linked. See note on 426, Row: 22, col/item:

Schedule Page: 426 Line No.: 40 Column: a Footnote Linked. See note on 426, Row: 22, col/item:

Schedule Page: 426.1 Line No.: 7 Column: a Amounts acquired in the merger between CVPS and GMP were


INDEX

Schedule Page No.

Accrued and prepaid taxes 262-263

Accumulated Deferred Income Taxes 234

272-277

Accumulated provisions for depreciation of

common utility plant 356

utility plant 219

utility plant (summary) 200-201

Advances

from associated companies 256-257

Allowances 228-229

Amortization

miscellaneous 340

of nuclear fuel 202-203

Appropriations of Retained Eanungs 118-119

Associated Companies

advances from 256-257

corporations controlled by respondent 103

control over respondent 102

interest on debt to 256-257

Attestdtion i

Balance sheet

comparatlve 110-113

notes to 122-123

Bonds 256-257

Capital Stock ::'51

expense 254

premiums . 25::'

reacquired' 251

subscribed 252

Cash flows, statement of 120-121

Changes

important during year 108-109

Construction

vlOrl: 1n progress - common utility plant 356

work in progress - electric 216

work in progress - other utility departments '" 200-::'01

Control

corporations controlled by respondent 103

over respondent 102

Corporatlon

controlled by . 103

incorpor a ted . 101

CPA, background information on 101

CPA Certlfication, this report form i-il

FERC FORM NO.1 (ED. 12-93) Index

INDEX (continued)

Schedule Page No. Deferred

credits, other 269

debits, miscellaneous 233

income taxes accumulated - accelerated

amortization property 272-273

lncome taxes accumulated - other property 274-275

income taxes accumulated - other 276-277

income taxes accumulated - pollution control facilities 234

Definitions, this report form lii

Depreciation and amortization

of common utility plant , 356

of electric plant 219

336-337

Directors 105

Dlscount - premium on long-term debt '" 256-257

Distribution of salaries and wages 354-355

Dividend appropriations 118-119

Earrllngs, Retained 118-119

Electric energy account ' '" 401

Expenses

electric operation and maintenance 320-323

electric operation and maintenance, surmnary 323

unamorti=ed debt 256

Extraordinary property losses 230

Fi 1 ing requirement s, this report form

General information 101

lnstructions for filing the FERC Form 1 i-1V

Generatlng plant statistics

hydroelectric (large) 406-407

pumped storage (large) 408-409

sm,dl plants HO-411

steam-electric (large) 402-403

Hydro-electric generatlng plant statistics 406-407

Identl fication 101

Important changes during year 108-109

Income

statement of, by departments 114-117

statement of, for the year (see also revenuesi 114-117

deductions, miscellaneous amorti=atlon 340

deductions, other income deduction 340

deductions, other interest charges 340

Incorporation information 10]

L _ FERC FORM NO.1 (ED. 12-95) Index 2

INDEX (continued)

Schedule Page No.

Interest

charges, paid on long-term debt, advances, etc 256-257

Investments

nonutili ty property 221

subsidiary companles 224-225

Investment tax credits, accumulated deferred 266-267

Law, excerpts applicable to this report form iv

List of schedules, this report form 2-4

Long-term debt 256-257

Losses-Extraordinary property 230

Materlals and supplies _ 227

r·Ji scell aneous gene ral expense s 335

Notes

to balance sheet 122-123

to statement of changes in financlal position 122-123

to statement of income 122-123

to statement of retained earnings 122-123

tlonutility property nl

Nuclear fuel materials 202-203

Nuclear generating plant, statistics 402-403

Officers and officers' salarles 104

Operating

e~-:penses-electric 3:20-323

e:-:penses-electric (summary) 323

Other

paid-in capital 253

donations received from stockholders 2')3

gains on resale or cancellation of reacquired

capital stock 253

miscellaneous paid--in capital 253

reductlon in par or stated value of capital stock 253

regulatory assets 232

regulatory llabilities 278

Peaks, monthly, and output 401

Plant, Con@on utlllty

accumulated provislon for depreciation 356

acqulsltlon adjustments 356

allocated to utillty departments 356

,completed construction not classified 356

constnJction work in progress 356

e:'\.penses 356

held for future use _ . 356

in service . 356

leased to others . 356

Plant ddta 336-337

40J -,12'"

FERC FORM NO.1 (ED. 12-95) Index 3

INDEX (continued)

Schedule Page No. Plant - electric

accumulated provision for depreciation 219

construction work in progress 216

held for future use 214

in service 204-207

leased to others 213

Plant - utility and accumulated provisions for depreciation

amortization and depletion (summary) 201

Pollution control facilities, accumulated deferred

income taxes 234

Power Exchanges 326-327

Premium and discount on long-term debt 256

Premium on capital stock 251

Prepaid taxes 262-263

Property - losses, extraordinary 230

Pumped storage generating plant statistics 408-409

Purchased power (including power exchanges) 326-327

Reacquired capltal stack 250

Reacquired long-term debt 256-257

Receivers' certificates 256-257

Reconclliation of reported net lncome with taxable income

from Federal income taxes 261

Regulatory commlSSlon expenses deferred 233

Regulatory conumssion expenses for year 350-351

Research, development and demonstration activities 352-353

Retained Earnings

amortization reserve Federal 119

appropriated 118-119

statement of, for the year 118.-.119

unappropriated '" 118-119

Revenues - electric operating 300-301

Salarles and wages

directors fees 105

distribution of 354-355

officers' 104

Sales of electrlcity by rate schedules 304

Sales - for resale 310-311

Salvage - nuclear fuel 202-2rJ3

Schedules, this report form 2-4

Securities

e:-:change registration 250-:251

Statement of Cash Flows 120-121

Statement of lncome fOJ: the year 114-117

Statement of retained earnings for the year 118-119

Steam-electric generating plant statistlcs 402-403

Substations 426

Supplies - materials and _~7


INDEX (continued)

Schedule Taxes

accrued and prepaid

charged during year

on income, deferred and accumulated

reconciliation of net income with taxable income for

Transformers, line - electric

Transmission

lines added during year

lines statistics

of electricity for others

of electricity by others

Unamortized

debt discount

debt expense

premlurn on debt

Unrecovered Plant and Regulatory Study Costs

Page No.

262-263

262-263

234

272-277

261

429

424-425

422-423

328-330

332

256-257

256-257

256-257

230


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