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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)
(2) D A Resubmission
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".
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
FERC FORM NO.1 (ED. 12-96) Page 3
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)
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".
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)
FERC FORM NO.1 (ED. 12-96) Page 4
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
Green Mountain Power Corporation
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.
FERC FORM NO.1 (ED. 12-96) Page 102
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
Green Mountain Power Corporation
Respondent has full control over the following
Green Mountain Power Investment Company
Northern Water Resources, Inc.
Vermont Electric Power Co., Inc.
Joint Owners:
Green Mountain Power Corporation
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)
FERC FORM NO.1 (ED. 12-96) Page 103
l
Name of Respondent This ~ort Is: Date of Report Year/Period of Report
Green Mountain Power Corporation (1) (2)
~An Original0 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 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.
Percent Voting Stock Owned
(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
Green Mountain Power Corporation
This ~ort Is: Date of Report (1) ~An Original (Mo, Da, Yr) (2) 0 A Resubmission 04/15/2013
CORPORATIONS CONTROLLED BY RESPONDENT
Year/Period of Report 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.
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.
Name of Company Controlled
(a)
Kind of Business
(b)
Percent Voting Stock Owned
(c)
Footnote Ref. (d)
1 Joint Owners:
2 Green Mountain Power Corporation
3 Lyndonville Electric Department
4 Massachusetts Municipal Wholesale Electric Co.
5
6
7
8 Joseph C. McNeil Plant
9
10 Joint Owners:
11 Green Mountain Power Corporation
12 Burlington Electric Department
13 Vermont Public Power Supply Authority
14
15
16
17 Highgate Transmission InterConnection
18 Joint Owners:
19 Green Mountain Power Corporation
20 Vermont Electric Co-Op.
21 Burlington Electric Department
22 Village of Johnson Water & Light Dept
23 Vermont Public Power Supply Authority
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%
FERC FORM NO.1 (ED. 12-96) Page 103.2
------
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
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 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%.
FERC FORM NO.1 (ED. 12-96) Page 103.3
Name of Respondent This ~ort Is: Date of Report Year/Period of Report
Green Mountain Power Corporation (1) (2)
~An Original0 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 Name of Company Controlled No.
(a)
1 VT Dedicated Metallic Neutral
2 Return Conductor
3
4 Joint Owners:
5
6 Green Mountain Power Corporation
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
22 Green Mountain Power Corporation
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
Percent Voting Stock Owned
(c)
Ownership %
59.40%
4060%
100.00%
100%
100%
1.73%
94.47%
4.80%
100.00%
Footnote Ref. (d)
FERC FORM NO.1 (ED. 12-96) Page 103.4
Name of Respondent
Green Mountain Power Corporation
This ~ort Is: (1) An Original (2) FiA Resubmission
Date of Report (Mo, Da, Yr) 04/15/2013
Year/Period of Report
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
FERC FORM NO.1 (ED. 12-96) Page 104
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
FERC FORM NO.1 (ED. 12-95) Page 105
Name of Respondent
Green Mountain Power Corporation
This 00rt Is: (1) An Original
(2)0 A Resubmission
Date of Report (Mo, Da, Yr)
04/15/2013
Year/Period of Report
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
Green Mountain Power Corporation
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
FERC FORM NO.1 (ED. 12-96) Page 108
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.
Title of Account (a)
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.
Title of Account (a)
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
FERC FORM NO.1 (ED. 12-96) Page 115
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
Year/Period of Report
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
FERC FORM NO. 1/3-Q (REV. 02-04) Page 119
Name of Respondent
Green Mountain Power Corporation
This ~ort Is: (1) An Original (2) n A Resubmission
Date of Report (Mo, Da, Yr)
04/15/2013
Year/Period of Report
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
53 Other (provide details in footnote):
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
64 Other (provide details in footnote):
65
66 Net Increase in Short-Term Debt (c)
67 Other (provide details in footnote):
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
76 Other (provide details in footnote):
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
Green Mountain Power Corporation
This Report Is: (1) 0 An Original (2) 0 A Resubmission
Date of Report
04/15/2013
Year/Period of Report End of 2012/04
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.
FERC FORM NO.1 (ED. 12-96) Page 122
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
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.
IFERC FORM NO.1 (ED. 12-88) Page 123.1
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/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(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
IFERC FORM NO.1 (ED. 12-88) Page 123.2
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
NOTES TO FINANCIAL STATEMENTS (Continued)
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.
IFERC FORM NO.1 (ED. 12-88) Page 123.3
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 2012104
NOTES TO FINANCIAL STATEMENTS (Continued)
(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.
IFERC FORM NO.1 (ED. 12-88) Page 123.4
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
NOTES TO FINANCIAL STATEMENTS (Continued)
(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
IFERC FORM NO.1 (ED. 12-88) Page 123.5
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
NOTES TO FINANCIAL STATEMENTS (Continued)
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
IFERC FORM NO.1 (ED. 12-88) Page 123.6
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
NOTES TO FINANCIAL STATEMENTS (Continued)
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%.
IFERC FORM NO.1 (ED. 12-88) Page 123.7
Name of Respondent This Report is: Date of Report Year/Period of Report (1) .6 An Original (Mo, Da, Yr)
Green Mountain Power Corporation (2) A Resubmission 04/15/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
• 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.
IFERC FORM NO.1 (ED. 12-88) Page 123.8
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 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
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
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
IFERC FORM NO.1 (ED. 12-88) Page 123.9
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
NOTES TO FINANCIAL STATEMENTS (Continued)
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.
IFERC FORM NO.1 (ED. 12-88) Page 123.10
Name of Respondent
Green Mountain Power Corporation
This Report is: (1) 6 An Original (2) A Resubmission
Date of Report (Mo, Da, Yr)
04/15/2013
Year/Period of Report
2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(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
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
NOTES TO FINANCIAL STATEMENTS (Continued)
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:
Year ended December 31, 2012 2011
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
Company's equity in net assets $ 10,068 $ 7,597
Amounts due to VELCO, net $ 9,330 $ 3,880
IFERC FORM NO.1 (ED. 12-88) Page 123.12
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 2012104
NOTES TO FINANCIAL STATEMENTS (Continued)
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:
Year ended December 31, 2012 2011
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
Company's equity in net assets $ 4,429 $ 1,620
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.
IFERC FORM NO.1 (ED. 12-88) Page 123.13
Name of Respondent
Green Mountain Power Corporation
This Report is: (1) 6 An Original (2) A Resubmission
Date of Report (Mo, Da, Yr)
04/15/2013
Year/Period of Report
2012104
NOTES TO FINANCIAL STATEMENTS (Continued)
(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.
IFERC FORM NO.1 (ED. 12-88) Page 123.14
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 2012/04
NOTES TO FINANCIAL STATEMENTS (Continued)
(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.
IFERC FORM NO.1 (ED. 12-88) Page 123.15
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 2012/04
NOTES TO FINANCIAL STATEMENTS (Continued)
(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
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 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
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.
IFERC FORM NO.1 (ED. 12-88) Page 123.17
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
NOTES TO FINANCIAL STATEMENTS (Continued)
(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,
IFERC FORM NO.1 (ED. 12-88) Page 123.18
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
NOTES TO FINANCIAL STATEMENTS (Continued)
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
IFERC FORM NO.1 (ED. 12-88) Page 123.19
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 2012/04
NOTES TO FINANCIAL STATEMENTS (Continued)
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:
Year ended September 30 2012 2011
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
IFERC FORM NO.1 (ED. 12-88) Page 123.20
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 2012/04
NOTES TO FINANCIAL STATEMENTS (Continued)
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.
IFERC FORM NO.1 (ED. 12-88) Page 123.21
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 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
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
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
NOTES TO FINANCIAL STATEMENTS (Continued)
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.
IFERC FORM NO.1 (ED. 12-88) Page 123.23
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 2012/04
NOTES TO FINANCIAL STATEMENTS (Continued)
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
IFERC FORM NO.1 (ED. 12-88) Page 123.24
Name of Respondent
Green Mountain Power Corporation
This Report is: (1) 6 An Original (2) A Resubmission
Date of Report (Mo, Da, Yr)
04/15/2013
Year/Period of Report
2012104
NOTES TO FINANCIAL STATEMENTS (Continued)
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 ========
IFERC FORM NO.1 (ED. 12-88) Page 123.25
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 2012/04
NOTES TO FINANCIAL STATEMENTS (Continued)
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:
Year ended September 30 2012 2011
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
IFERC FORM NO.1 (ED. 12-88) Page 123.26
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
NOTES TO FINANCIAL STATEMENTS (Continued)
(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.
IFERC FORM NO.1 (ED. 12-88) Page 123.27
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
NOTES TO FINANCIAL STATEMENTS (Continued)
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
IFERC FORM NO.1 (ED. 12-88) Page 123.28
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/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
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
IFERC FORM NO.1 (ED. 12-88) Page 123.29
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 2012104
NOTES TO FINANCIAL STATEMENTS (Continued)
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
IFERC FORM NO.1 (ED. 12-88) Page 123.30
Name of Respondent
Green Mountain Power Corporation
This Report is: (1) XAn Original (2) A Resubmission
Date of Report (Mo, Da, Yr)
04/15/2013
Year/Period of Report
2012/04
NOTES TO FINANCIAL STATEMENTS (Continued)
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
IFERC FORM NO.1 (ED. 12-88) Page 123.31
Name of Respondent This Report is: Date of Report Year/Period of Report (1) 6 An Original (Mo, Da, Yr)
Green Mountain Power Corporation (2) A Resubmission 04/15/2013 2012104
NOTES TO FINANCIAL STATEMENTS (Continued)
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:
IFERC FORM NO.1 (ED. 12-88) Page 123.32
Name of Respondent
Green Mountain Power Corporation
This Report is: (1) ~ An Original (2) A Resubmission
NOTES TO FINANCIAL STATEMENTS (Continued)
Date of Report (Mo, Da, Yr)
04/15/2013
Year/Period of Report
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)
Green Mountain Power Corporation (2) A Resubmission 04/15/2013 2012/04
NOTES TO FINANCIAL STATEMENTS (Continued)
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.
IFERC FORM NO.1 (ED. 12-88) Page 123.34
Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr)
Green Mountain Power Corporation (2) A Resubmission 04/15/2013 2012/04
NOTES TO FINANCIAL STATEMENTS (Continued)
(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.
IFERC FORM NO.1 (ED. 12-88) Page 123.35
l\lame of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr)
Green Mountain Power Corporation (2) A Resubmission 04/15/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
(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
IFERC FORM NO.1 (ED. 12-88) Page 123.36
Name of Respondent
Green Mountain Power Corporation
This Report is: (1) ~ An Original
1(2) A Resubmission
Date of Report (Mo, Da, Yr)
04/15/2013
Year/Period of Report
2012104
NOTES TO FINANCIAL STATEMENTS (Continued)
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.
IFERC FORM NO.1 (ED. 12-88) Page 123.37
Name of Respondent
Green Mountain Power Corporation
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
FERC FORM NO.1 (ED. 12-89) Page 200
Name of Respondent
Green Mountain Power Corporation
This ~ort Is: (1) ~ An Original (2) A Resubmission
Date of Report (Mo, Da, Yr) 04/15/2013
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
FERC FORM NO.1 (ED. 12-89) Page 201
Name of Respondent
Green Mountain Power Corporation
This ~ort Is: Date of Report (1) ~ An Original (Mo, Da, Yr) (2) A Resubmission 04/15/2013
Year/Period of Report
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
21 Other (provide details in footnote):
22 TOTAL Nuclear Materials held for Sale (Total 19, 20, and 21)
FERC FORM NO.1 (ED. 12-89) Page 202
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
FERC FORM NO.1 (ED. 12-89) Page 203
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
FERC FORM NO.1 (REV. 12-05) Page 204
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
FERC FORM NO.1 (REV. 12-05) Page 205
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
FERC FORM NO.1 (REV. 12-05) Page 206
----
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
FERC FORM NO.1 (REV. 12-05) Page 207
This [!J0rt Is: (1) An Original (2) n A Resubmission
ELECTRIC PLANT LEASED TO OTHERS (Account 104)
Description of prope1bfeased
Name of Respondent
Green Mountain Power Corporation
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)
FERC FORM NO.1 (ED. 12-95) Page 213
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)
(2) D A Resubmission
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
FERC FORM NO.1 (ED. 12-96) Page 214
0
Name of Respondent This ~ort Is: Date of Report Year/Period of Report
Green Mountain Power Corporation (1) (2)
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
FERC FORM NO.1 (ED. 12-87) Page 216
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
FERC FORM NO.1 (REV. 12-05) Page 219
This ~ort Is: (1) An Original (2) Fi A Resubmission
Name of Respondent
Green Mountain Power Corporation
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
13 Undistributed Equity in Earnings
14 Return of Capital
15 SUBTOTAL
16 C. New England Hydro Electric
17 Transmission Company
18 Common stock
19 Undistributed Equity in Earnings
20 SUBTOTAL
21
22 D. New England Hydro Transmission
23 Corporation
24 Common stock and Additional paid in capital
25 Return of Capital
26 Undistributed Equity in Earnings
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
FERC FORM NO.1 (ED. 12-89) Page 224
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
FERC FORM NO.1 (ED. 12-89) Page 225
Name of Respondent
Green Mountain Power Corporation
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
Equity in undistributed earnings
Acquired in CVPS merger=11 0485
SUBTOTAL
Catamount Resources Corporation
Common Stock
Equity in undistributed earnings
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
FERC FORM NO.1 (ED. 12-89) Page 224.1
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)
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
FERC FORM NO.1 (ED. 12-89) Page 225.1
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
FERC FORM NO.1 (REV. 12-05) Page 227
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)
36 Balance-Beginning of Year
37 Add: Withheld by EPA
38 Deduct: Returned_b"--y_E_P_A +- -+- -+- +- -----j
39 Cost of Sales
40 Balance-End of Year
41
42 Sales:
43 Net Sales Proceeds (Assoc. Co.)
44 Net Sales Proceeds (Other)
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)
1 Balance-Beginning of Year
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
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)
36 Balance-Beginning of Year
37 Add: Withheld by EPA
38 Deduct: Returned by EPA
39 Cost of Sales
40 Balance-End of Year
41
42 Sales:
43 Net Sales Proceeds (Assoc. Co.)
44 Net Sales Proceeds (Other)
45 Gains
46 Losses
FERC FORM NO.1 (ED. 12-95) Page 228b
Year/Period of ReportName of Respondent
Green Mountain Power Corporation
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)
FERC FORM NO.1 (ED. 12-95) Page 229a
Year/Period of ReportName of Respondent
Green Mountain Power Corporation
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)
FERC FORM NO.1 (ED. 12-95) Page 229b
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
Green Mountain Power Corporation
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
FERC FORM NO.1 (ED. 12-88) Page 230a
Date of ReportThis ~ort Is: (Mo, Da, Yr)(1) An Original 04/15/2013
UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.2)
(2) D A Resubmission
Total Costs Amount
of Charges RecognisedDuring Year Account
Charged
(b) (c) (d)
Name of Respondent
Green Mountain Power Corporation
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
Year/Period of Report
End of 2012/04
WRITIEN OFF DURING YEAR Balance at
Amount End of Year
(e) (f)
FERC FORM NO.1 (ED. 12-88) Page 230b
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
FERC FORM NO. 1/3-Q (REV. 02-04) Page 232
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
Date of Report (Mo, Da, Yr) 04/15/2013
CREDITS
Amount
(e)
Year/Period of Report
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
FERC FORM NO.1 (ED. 12-94) Page 233
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
FERC FORM NO.1 (ED. 12-88) Page 234
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
FERC FORM NO.1 (ED. 12-91) Page 250
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
FERC FORM NO.1 (ED. 12-87) Page 253
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)
(2) D A Resubmission
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
FERC FORM NO.1 (ED. 12-87) Page 254b
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
FERC FORM NO.1 (ED. 12-96) Page 256
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
FERC FORM NO.1 (ED. 12-96) Page 257
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
(2) D A Resubmission
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
FERC FORM NO.1 (ED. 12-96) Page 261
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
(2) D A Resubmission
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
FERC FORM NO.1 (ED. 12-96) Page 262
Name of Respondent
Green Mountain Power Corporation
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 foot- note. 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
FERC FORM NO.1 (ED. 12-96) Page 263
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
FERC FORM NO.1 (ED. 12-89) Page 267
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)
Balance at End of Year
(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
FERC FORM NO.1 (ED. 12-94) Page 269
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
5 Other (provide details in footnote):
6
7
8 TOTAL Electric (Enter Total of lines 3 thru 7)
9 Gas
10 Defense Facilities
11 Pollution Control Facilities
12 Other (provide details in footnote):
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)
FERC FORM NO.1 (ED. 12-96) Page 272
Name of Respondent
Green Mountain Power Corporation
This ~ort Is: Date of Report (1) ~ An Original (Mo, Da, Yr) (2) A Resubmission 04/15/2013
Year/Period of Report End of 2012/04
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
Balance at End of Year
Line No.
3
4
5
6
7
8
12
13
14
15
16
17
19
20
21
NOTES (Continued)
FERC FORM NO.1 (ED. 12-96) Page 273
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
2. For other (Specify),include deferrals relating to other income and deductions.
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
FERC FORM NO.1 (ED. 12-96) Page 274
Name of Respondent
Green Mountain Power Corporation
This ~ort Is: Date of Report (1) ~ An Original (Mo, Da, Yr) (2) A Resubmission 04/15/2013
Year/Period of Report
End of 2012/04
ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282) (Continued)
3. Use footnotes as required.
CHANGES DURING YEAR
Amounts Debited Amounts Credited to Account 410.2 to Account 411.2
ADJUSTMENTS
Debits
various
NOTES (Continued)
Amount
Balance at End of Year
Line No.
5
6
7
12
13
FERC FORM NO.1 (ED. 12-96) Page 275
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.
2. For other (Specify),include deferrals relating to other income and deductions.
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
FERC FORM NO.1 (ED. 12-96) Page 276
Name of Respondent
Green Mountain Power Corporation
This ~ort Is: Date of Report (1) ~An Original (Mo, Da, Yr) (2) A Resubmission 04/15/2013
Year/Period of Report
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.
4. Use footnotes as required.
Line No.
Balance at End of Year
(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
FERC FORM NO.1 (ED. 12-96) Page 277
Name of Respondent
Green Mountain Power Corporation
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
Other Regulatory Liabilities
(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
Date of Report (Mo, Da, Yr) 04/15/2013
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
Year/Period of Report
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)
(2) D A Resubmission
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
Green Mountain Power Corporation
This ~ort Is: Date of Report (1) ~ An Original (Mo, Da, Yr) (2) A Resubmission 04/15/2013
Year/Period of Report
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
FERC FORM NO. 1/3-Q (REV. 12-05) Page 301
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
(2) 0 A Resubmission
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
FERC FORM NO.1 (ED. 12-95) Page 304
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
FERC FORM NO.1 (ED. 12-95) Page 304.1
Name of Respondent
Green Mountain Power Corporation
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
FERC FORM NO.1 (ED. 12-90) Page 310
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
FERC FORM NO.1 (ED. 12-90) Page 311
20
15
14
11
10
12
Name of Respondent
Green Mountain Power Corporation
This ~ort Is: (1) ~An Original (2) A Resubmission
Date of Report (Mo, Da, Yr) 04/15/2013
YearlPeriod of Report
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
FERC FORM NO.1 (ED. 12-93) Page 320
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
Green Mountain Power Corporation
This ~ort Is: (1) ~An Original (2) A Resubmission
Date of Report (Mo, Da, Yr) 04/15/2013
Year/Period of Report
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
Amount for Previous Year
(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
FERC FORM NO.1 (ED. 12-93) Page 322
Name of Respondent
Green Mountain Power Corporation
This ~ort Is: (1) ~ An Original (2) A Resubmission
Date of Report (Mo, Da, Yr) 04/15/2013
Year/Period of Report
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)
Amount for Previous Year
(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
FERC FORM NO.1 (ED. 12-93) Page 323
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
FERC Rate Schedule or
Tariff Number (c)
07B-0136-000
124
07B-0335-009-1
na
na
07B-0 133-000-03
07B-0133-000-03
45
FERC FORM NO.1 (ED. 12-90) Page 326
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
Green Mountain Power Corporation
1.
2. acronyms. 3.
which meets the definition of RQ service.
IF - for inl:ermediate-term firm service. than five years.
SF - for short-term service. year or less.
IU - for intermediate-term service from a designatlonger than one year but less than five years.
and any settlements for imbalanced exchanges.
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.
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 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
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 service, aside from transmission constraints, must match the availability and reliability of the designated unit.
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)
This wort Is: (1) X An Original (2) DA Resubmission
PURCHASED POWER hAccount 555)(Including power exc anges)
Statistical Classification
(b)
FERC Rate Schedule or
Tariff Number (c)
FPC1
FPC1
FPC1
FPC1
FERC FORM NO.1 (ED. 12-90) Page 326.1
Year/Period of Report End of 2012/04
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)
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 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
FERC FORM NO.1 (ED. 12-90) Page 327.1
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
Green Mountain Power Corporation
1.
2. acronyms. 3.
which meets the definition of RQ service.
than five years.
SF - for short-term service. year or less.
IU - for intermediate-term service from a designlonger than one year but less than five years.
and any settlements for imbalanced exchanges.
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
8 Vermont Public Power Supply Authority
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.
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 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
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 service, aside from transmission constraints, must match the availability and reliability of the designated unit.
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
AverageStatistical Classifi- Monthly Billing cation Demand (MW)
(b) (d)
LU
LU
LU
LU
OS
OS
OS
OS
FERC Rate Schedule or
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)
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. 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
FERC FORM NO.1 (ED. 12-90) Page 327.2
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
FERC FORM NO.1 (ED. 12-90) Page 328
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
FERC FORM NO.1 (ED. 12-90) Page 329
Name of Respondent
Green Mountain Power Corporation
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
FERC FORM NO.1 (ED. 12-90) Page 330
(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)
Statistical Classification
(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
FERC FORM NO.1 (ED. 12-94) Page 335
I
Name of Respondent This ~ort Is: Date of Report Year/Period of Report
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)
FERC FORM NO.1 (REV. 12-03) Page 336
Name of Respondent
Green Mountain Power Corporation
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
Green Mountain Power Corporation
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)
Date of Report Year/Period of Report (Mo, Da, Yr)
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
FERC FORM NO.1 (ED. 12-96) Page 350
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»: }'" ~ ~ % "
FERC FORM NO.1 (ED. 12-96) Page 351
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
(2) D A Resubmission
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
FERC FORM NO.1 (ED. 12-87) Page 352
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 _
FERC FORM NO.1 (ED. 12-87) Page 352
Year/Period of Report
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
FERC FORM NO.1 (ED. 12-87) Page 353
Name of Respondent
Green Mountain Power Corporation
This ~ort Is: Date of Report (1) ~An Original (Mo, Da, Yr) (2) A Resubmission 04/15/2013
Year/Period of Report
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)
10 Administrative and General
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
40 Administrative and General
44 Production-Natural Gas (Including Exploration and Development)
Line No.
FERC FORM NO.1 (ED. 12-88) Page 354
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
49 Administrative and General
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
70 Other (provide details in footnote):
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
75 Other (provide details in footnote):
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
FERC FORM NO.1 (ED. 12-88) Page 355
Year/Period of ReportName of Respondent
Green Mountain Power Corporation
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.
FERC FORM NO.1 (ED. 12-87) Page 356
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
FERC FORM NO. 1/3-0 (NEW. 12-05) Page 397
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
FERC FORM NO. 1/3-0 (NEW. 07-04) Page 400
-
Date of Report Year/Period of Report (Mo, Da, Yr)
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)
FERC FORM NO.1 (ED. 12-90) Page 401a
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
FERC FORM NO.1 (ED. 12-90) Page 401b
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
Date of Report Year/Period of Report (Mo, Da, Yr)
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
FERC FORM NO.1 (REV. 12-03) Page 402
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
FERC FORM NO.1 (REV. 12-03) Page 403
Date of Report (Mo, Da, Yr) 04/15/2013
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
YearlPeriod of Report
End of 2012/04
Name of Respondent This 00rt Is: (1) An Original
Green Mountain Power Corporation (2) D A Resubmission
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)
3 Year Originally Constructed
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
Date of Report Year/Period of Report (Mo, Da, Yr)
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
FERC FORM NO.1 (REV. 12-03) Page 402.1
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
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
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
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
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 (REV. 12-03) Page 403.1
Year/Period of Report
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)
3 Year Originally Constructed
4 Year Last Unit was Installed
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
11 Average Number of Employees
12 Net Generation, Exclusive of Plant Use - Kwh
13 Cost of Plant
14 Land and Land Rights
15 Structures and Improvements
16 Reservoirs, Dams, and Waterways
17 Equipment Costs
18 Roads, Railroads, and Bridges
19 Asset Retirement Costs
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
26 Electric Expenses
27 Misc Hydraulic Power Generation Expenses
28 Rents
29 Maintenance Supervision and Engineering
30 Maintenance of Structures
31 Maintenance of Reservoirs, Dams, and Waterways
32 Maintenance of Electric Plant
33 Maintenance of Misc Hydraulic Plant
34 Total Production Expenses (total 23 thru 33)
35 Expenses per net KWh 0.0000
FERC FORM NO.1 (REV. 12-03) Page 406
Year/Period of ReportName of Respondent
Green Mountain Power Corporation
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
FERC FORM NO.1 (REV. 12-03) Page 407
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)
2 Year Originally Constructed
3 Year Last Unit was Installed
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)
8 Average Number of Employees
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
14 Structures and Improvements
15 Reservoirs, Dams, and Waterways
16 Water Wheels, Turbines, and Generators
17 Accessory Electric Equipment
18 Miscellaneous Powerplant Equipment
19 Roads, Railroads, and Bridges
20 Asset Retirement Costs
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
27 Electric Expenses
28 Misc Pumped Storage Power generation Expenses
29 Rents
30 Maintenance Supervision and Engineering
31 Maintenance of Structures
32 Maintenance of Reservoirs, Dams, and Waterways
33 Maintenance of Electric Plant
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
FERC Licensed Project No. 0 Plant Name:
(b)
FERC FORM NO.1 (REV. 12-03) Page 408
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
FERC Licensed Project No. 0 Plant Name:
(c)
FERC Licensed Project No. 0
Plant Name: (d)
FERC Licensed Project No.
Plant Name: (e)
Year/Period of Report
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
FERC FORM NO.1 (REV. 12-03) Page 409
Name of Respondent
Green Mountain Power Corporation
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
Date of Report Year/Period of Report (Mo, Da, Yr)
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
FERC FORM NO.1 (REV. 12-03) Page 410
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
FERC FORM NO.1 (REV. 12-03) Page 411
Name of Respondent This R~Ort Is: (1) An Original
Green Mountain Power Corporation (2) D A Resubmission
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
Date of Report (Mo, Da, Yr) 04/15/2013
Year/Period of Report
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
FERC FORM NO.1 (ED. 12-87) Page 422
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
FERC FORM NO.1 (ED. 12-87) Page 423
Date of Report (Mo, Da, Yr) 04/15/2013
Name of Respondent This [!]Ortls:
Green Mountain Power Corporation (1) An Original
(2) 0 A Resubmission
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
Year/Period of Report
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
FERC FORM NO.1 (ED. 12-87) Page 422.1
Name of Respondent Date of Report Year/Period of ReportThis ~ort Is: (1) An Original (Mo, Da, Yr)
End of 2012/04Green Mountain Power Corporation 04/15/2013
TRANSMISSION LINE STATISTICS (Continued)
(2) D A 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) 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
FERC FORM NO.1 (ED. 12-87) Page 423.1
Name of Respondent Date of Report Year/Period of Report This ~ort Is: (1) An Original (Mo, Da, Yr)
End of 2012/04Green Mountain Power Corporation 04/15/2013
TRANSMISSION LINES ADDED DURING YEAR
(2) D A Resubmission
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 under- ground 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
FERC FORM NO.1 (REV. 12-03) Page 425
Date of Report (Mo, Da, Yr) End of04/15/2013
Name of Respondent This @ort Is: (1) X An Original
Green Mountain Power Corporation (2) D A Resubmission
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)
FERC FORM NO.1 (ED. 12-96) Page 426
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
2411 1 Condenser 2 6
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
FERC FORM NO.1 (ED. 12-96) Page 427
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
(2) D A Resubmission
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).
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
FERC FORM NO.1 (ED. 12-96) Page 426.1
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
FERC FORM NO.1 (ED. 12-96) Page 427.1
(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
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 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
Year/Period of Report
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
FERC FORM NO.1 (ED. 12-96) Page 426.2
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
3632 2 Condenser 2 32
37241 78
3852 31
3923 10
1912 40264 3 13 76
FERC FORM NO.1 (ED. 12-96) Page 427.2
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)
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 2012/Q4
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
IFERC FORM NO.1 (ED. 12-87) Page 450.1
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
FOOTNOTE DATA
Schedule Page: 266 Line No.: 5 Column: g amount acquired in CVPS merger=1713711 plus east barnet hydro 259484
IFERC FORM NO.1 (ED. 12-87) Page 450.1
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
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
IFERC FORM NO.1 (ED. 12-87) Page 450.1
Name of Respondent This Report is: Date of Report Year/Period of Report (1) 6 An Original (Mo, Da, Yr)
Green Mountain Power Corporation (2) A Resubmission 04/15/2013 2012104
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
IFERC FORM NO.1 (ED. 12-87) Page 450.1
Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr)
Green Mountain Power Corporation (2) A Resubmission 04/15/2013 2012/04
FOOTNOTE DATA
Schedule Page: 352 Line No.: 1 Column: a RKS Research & Consulting - Customer Survey
IFERC FORM NO.1 (ED. 12-87) Page 450.1
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 2012/04
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
IFERC FORM NO.1 (ED. 12-87) Page 450.1
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
FERC FORM NO.1 (ED. 12-90) Index 4
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
FERC FORM NO.1 (ED. 12-90) Index 5