THIS FILING IS Form 1 Approved OMB No.1902-0021 Item 1:X An Initial (Original) OR Resubmission No. ____ (Expires 11/30/2022) Submission Form 1-F Approved OMB No.1902-0029 (Expires 11/30/2022) Form 3-Q Approved OMB No.1902-0205 (Expires 11/30/2022)
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) Year/Period of Report Appalachian Power Company End of 2020/Q4
FERC FORM No.1/3-Q (REV. 02-04) INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-Q
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-Q ( FERC Form 3-Q)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-Q (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-Q 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.gov/docs-filing/forms/form-1/elec-s ubm-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-Q 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-Q (ED. 03-07) i 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 Pages
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-Q free of charge from http://www.ferc.gov/docs-filing/forms/form-1/form-1.pdf and http://www.ferc.gov/docs-filing/forms.asp#3Q-gas .
IV. When to Submit:
FERC Forms 1 and 3-Q 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 18 th of the following year (18 CFR § 141.1), and b) FERC Form 3-Q 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 1,168 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-Q collection of information is estimated to average 168 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 NE, 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.
OS - 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*.10
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 § 316(a) (2005), 16 U.S.C. § 825o(a).
FERC FORM 1 & 3-Q (ED. 03-07) vii FERC FORM NO. 1/3-Q: REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER IDENTIFICATION 01 Exact Legal Name of Respondent 02 Year/Period of Report Appalachian Power Company End of 2020/Q4 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) 1 Riverside Plaza, Columbus, Ohio 43215-2373 05 Name of Contact Person 06 Title of Contact Person Jason M. Johnson Accountant 07 Address of Contact Person (Street, City, State, Zip Code) AEP Service Corporation, 1 Riverside Plaza, Columbus, OH 43215-2373 08 Telephone of Contact Person,Including 09 This Report Is 10 Date of Report (Mo, Da, Yr) Area Code (1) X An Original (2) A Resubmission (614) 716-1000 / / 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 contained in this report are correct statements of the business affairs of the respondent and the financial statements, and other financial information contained in this report, conform in all material respects to the Uniform System of Accounts.
01 Name 03 Signature 04 Date Signed Jeffrey W.Hoersdig (Mo, Da, Yr) 02 Title Assistant Controller Jeffrey W.Hoersdig 04/13/2021 Title 18, U.S.C. 1001 makes it a crime for any person to knowingly and willingly to make to any Agency or Department of the United States any false, fictitious or fraudulent statements as to any matter within its jurisdiction.
FERC FORM No.1/3-Q (REV. 02-04) Page 1 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) 2020/Q4 Appalachian Power Company End of (2) A Resubmission / / 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".
Line Title of Schedule Reference Remarks No. Page No. (a) (b) (c) 1 General Information 101 2 Control Over Respondent 102 3 Corporations Controlled by Respondent 103 4 Officers 104 5 Directors 105 6 Information on Formula Rates 106(a)(b) 7 Important Changes During the Year 108-109 8 Comparative Balance Sheet 110-113 9 Statement of Income for the Year 114-117 10 Statement of Retained Earnings for the Year 118-119 11 Statement of Cash Flows 120-121 12 Notes to Financial Statements 122-123 13 Statement of Accum Comp Income, Comp Income, and Hedging Activities 122(a)(b) 14 Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep 200-201 15 Nuclear Fuel Materials 202-203 16 Electric Plant in Service 204-207 17 Electric Plant Leased to Others 213 18 Electric Plant Held for Future Use 214 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) 24 Extraordinary Property Losses 230 25 Unrecovered Plant and Regulatory Study Costs 230 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 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 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) 2020/Q4 Appalachian Power Company End of (2) A Resubmission / / 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 Title of Schedule Reference Remarks No. Page No. (a) (b) (c) 37 Other Deferred Credits 269 38 Accumulated Deferred Income Taxes-Accelerated Amortization Property 272-273 39 Accumulated Deferred Income Taxes-Other Property 274-275 40 Accumulated Deferred Income Taxes-Other 276-277 41 Other Regulatory Liabilities 278 42 Electric Operating Revenues 300-301 43 Regional Transmission Service Revenues (Account 457.1) 302 44 Sales of Electricity by Rate Schedules 304 45 Sales for Resale 310-311 46 Electric Operation and Maintenance Expenses 320-323 47 Purchased Power 326-327 48 Transmission of Electricity for Others 328-330 49 Transmission of Electricity by ISO/RTOs 331 50 Transmission of Electricity by Others 332 51 Miscellaneous General Expenses-Electric 335 52 Depreciation and Amortization of Electric Plant 336-337 53 Regulatory Commission Expenses 350-351 54 Research, Development and Demonstration Activities 352-353 55 Distribution of Salaries and Wages 354-355 56 Common Utility Plant and Expenses 356 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 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) 2020/Q4 Appalachian Power Company End of (2) A Resubmission / / 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 Title of Schedule Reference Remarks No. Page No. (a) (b) (c) 67 Transmission Line Statistics Pages 422-423 68 Transmission Lines Added During the Year 424-425 69 Substations 426-427 70 Transactions with Associated (Affiliated) Companies 429 71 Footnote Data 450 Stockholders' Reports Check appropriate box: Two copies will be submitted No annual report to stockholders is prepared
FERC FORM NO. 1 (ED. 12-96) Page 4 Name of Respondent This Report Is: Date of Report Year/Period of Report Appalachian Power Company (1) X An Original (Mo, Da, Yr) 2020/Q4 (2) A Resubmission / / End of
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. Jeffrey W Hoersdig, Assistant Controller American Electric Power Company 1 Riverside Plaza Columbus, OH 43215-2373
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. Virginia March 4, 1926
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. None
4. State the classes or utility and other services furnished by respondent during the year in each State in which the respondent operated.
Electric - West Virginia Electric - Virginia Electric - Tennessee
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) Yes...Enter the date when such independent accountant was initially engaged: (2) X No
FERC FORM No.1 (ED. 12-87) PAGE 101 Name of Respondent This Report Is: Date of Report Year/Period of Report Appalachian Power Company (1) X An Original (Mo, Da, Yr) (2) A Resubmission / / End of 2020/Q4
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. American Electric Power Company, Inc. - Ownership of 100% of the Common Stock.
FERC FORM NO. 1 (ED. 12-96) Page 102 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) 2020/Q4 Appalachian Power Company End of (2) A Resubmission / / 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 Kind of Business Percent Voting Footnote No. Stock Owned Ref. (a) (b) (c) (d) 1 Cedar Coal Company Coal Mining - Inactive 100 2 Central Appalachian Coal Company Coal Mining - Inactive 100 3 Central Coal Company Coal Mining - Inactive 50 Footnote 4 Southern Appalachian Coal Company Coal Mining - Inactive 100 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27
FERC FORM NO. 1 (ED. 12-96) Page 103 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 FOOTNOTE DATA
Schedule Page: 103 Line No.: 3 Column: d Central Coal Company is jointly controlled by Respondent and AEP Generation Resources, also a subsidiary of American Electric Power Company, Inc.
FERC 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) 2020/Q4 Appalachian Power Company End of (2) A Resubmission / / OFFICERS 1. Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive officer" of a respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function (such as sales, administration or finance), and any other person who performs similar policy making functions. 2. If a change was made during the year in the incumbent of any position, show name and total remuneration of the previous incumbent, and the date the change in incumbency was made. Line Title Name of Officer Salary for Year No. (a) (b) (c) 1 Footnote 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44
FERC FORM NO. 1 (ED. 12-96) Page 104 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 FOOTNOTE DATA
Schedule Page: 104 Line No.: 1 Column: a
Summary Compensation Table
The following table provides summary information concerning compensation earned by our Chief Executive Officer, our Chief Financial Officer and the three other most highly compensated executive officers, to whom we refer collectively as the named executive officers.
Change in Pension Value and Non-Equity Nonqualified Incentive Deferred All Plan Compensation Other Name and Principal Year Salary ($)(1) Bonus ($) Stock Awards Compensation Earnings Compensation Total Position ($)(2) ($)(3) ($)(4) ($)(5) ($) Nicholas K. Akins— Chairman of the Board and Chief Executive Officer 2020 1,521,615 — 9,615,116 3,500,000 698,612 168,091 15,503,434 Brian X. Tierney— Executive Vice President and Chief Financial Officer 2020 826,308 — 2,160,666 1,050,000 422,536 107,217 4,566,727 David M. Feinberg— Executive Vice President, General Counsel and Secretary 2020 699,339 — 1,512,527 847,000 235,404 81,738 3,376,008 Lisa M. Barton— Executive Vice President- Transmission 2020 665,077 — 1,620,475 856,000 206,833 81,600 3,429,985 Lana L. Hillebrand— Executive Vice President- Chief Administrative Officer 2020 637,365 — 1,688,344 771,862 247,260 1,186,196 4,531,027
(1) Amounts in the salary column are composed of executive salaries earned for the year shown, which include 262 days of pay for 2020. This is two days more than the standard 260 calendar work days and holidays in a year.
(2) The amounts reported in this column reflect the aggregate grant date fair value calculated in accordance with FASB ASC Topic 718 of the performance shares, restricted stock units (RSUs) and unrestricted shares granted under our Long-Term Incentive Plan. See Note 15 to the Consolidated Financial Statements included in our Form 10-K for the year ended December 31, 2020 for a discussion of the relevant assumptions used in calculating these amounts. The number of shares realized and the value of the performance shares, if any, will depend on the Company’s performance during a 3 year performance period. The potential payout can range from 0 percent to 200 percent of the target number of performance shares, plus any dividend equivalents. The value of the 2020 performance shares will be based on three measures: a Board approved cumulative operating earnings per share measure (Cumulative EPS 50%), a total shareholder return measure (Relative TSR 40%) and a carbon free capacity mix (Carbon Free Capacity 10%). The grant date fair value of the 2020 performance shares that are based on Cumulative EPS was computed in accordance with FASB ASC Topic 718 and was measured based on the closing price of AEP’s common stock on the grant date. The maximum amount payable for the 2020 performance shares that are based on Cumulative EPS is equal to $6,674,985 for Mr. Akins; $1,499,955 for Mr. Tierney; $1,050,051 for Mr. Feinberg; $1,124,966 for Ms. Barton and $824,996 for Ms. Hillebrand. The maximum amount payable for the 2020 performance shares that are based on Non-Emitting Generation Capacity is equal to $1,334,997 for Mr. Akins; $299,991 for Mr. Tierney; $210,010 for Mr. Feinberg; $224,993 for Ms. Barton and $164,999 (pro-rated $55,000) for Ms. Hillebrand. The grant date fair value of the 2020 performance shares that are based on Relative TSR is calculated using a Monte-Carlo model as of the date of grant, in accordance with FASB ASC Topic 718. Because the performance shares that are based on Relative TSR are subject to market conditions as defined under FASB ASC Topic 718, they did not have a maximum value on the grant date that differed from the grant date fair values presented in the table. Instead, the maximum value is factored into the calculation of the grant date fair value.
(3) The amounts shown in this column reflect annual incentive compensation.
(4) The amounts shown in this column are attributable to the increase in the actuarial values of each of the named executive officer’s combined benefits under AEP’s qualified and non-qualified defined benefit pension plans determined using interest rate and mortality assumptions consistent with those used in the Company’s financial statements. See the Pension Benefits for 2020 table and related footnotes for additional information. See Note 8 to the Consolidated Financial Statements included in our Form 10-K for the year ended December 31, 2020 for a discussion of the relevant assumptions. None of the named executive officers received preferential or above-market earnings on deferred compensation.
FERC 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) Appalachian Power Company (2) A Resubmission / / 2020/Q4 FOOTNOTE DATA
(5) Amounts shown in the All Other Compensation column for 2020 include: (a) Company matching contributions to the Company’s Retirement Savings Plan, (b) Company matching contributions to the Company’s Supplemental Retirement Savings Plan and (c) perquisites and (d) severance benefits. The 2020 values for these items are listed in the following table:
Nicholas K. Brian X. David M. Lisa M. Lana L. Akins Tierney Feinberg Barton Hillebrand Type Retirement Savings Plan Match $ 12,825 $ 12,825 $ 12,825 $ 12,825 $ 12,825
Supplemental Retirement Savings Plan Match $ 134,671 $ 58,492 $ 54,989 $ 52,692 $ 74,392 Perquisites $ 20,595 $ 20,000 $ 10,421 $ 13,786 $ 13,804
Severance $ 1,106,875 Total $ 168,091 $ 107,217 $ 81,738 $ 81,600 $ 1,186,196
Perquisites provided in 2020 included: financial counseling and tax preparation services, and, for Mr. Akins, director’s group travel accident insurance premium. Executive officers may also have the occasional personal use of event tickets when such tickets are not being used for business purposes, however, there is no associated incremental cost. From time to time executive officers may receive customary gifts from third parties that sponsor events (subject to our policies on conflicts of interest).
Mr. Akins has entered into an Aircraft Time Sharing Agreement that allows him to use our corporate aircraft for personal use for a limited number of hours each year. The Aircraft Time Sharing Agreement requires Mr. Akins to reimburse the Company for the cost of his personal use of corporate aircraft in accordance with limits set forth in Federal Aviation Administration regulations. The incremental costs incurred in connection with personal flights for which Mr. Akins fully reimbursed the Company under the Aircraft Timesharing Agreement include fuel, oil, hangar costs, crew travel expenses, catering, landing fees and other incremental airport fees. Accordingly, no value is shown for these amounts in the Summary Compensation Table. If the aircraft flies empty before picking up or after dropping off Mr. Akins at a destination on a personal flight, the cost of the empty flight is included in the incremental cost for which Mr. Akins reimburses the Company. Since AEP aircraft are used predominantly for business purposes, we do not include fixed costs that do not change in amount based on usage, such as depreciation and pilot salaries.
Ms. Hillebrand's employment as the Company's Chief Administrative Officer terminated effective December 31, 2020 due to the elimination of her position. In anticipation of this, the Company entered into a severance, stock award, release of all claims and noncompetition agreement with Ms. Hillebrand on October 21, 2020 pursuant to which the Company agreed to provide, among other benefits, $1,106,875 in severance benefits due to the elimination of her position and separation from service, effective December 31, 2020. This amount is equivalent to 1× her annual base salary and target annual incentive award, which is the current severance benefit for all participants under AEP’s Executive Severance plan. Half of this amount will be paid 6 months after her termination date and the remainder will be paid over the following 13 biweekly pay periods. In addition, the Company agreed to provide Ms. Hillebrand $500,000 in unrestricted AEP shares under AEP’s Long-Term Incentive Plan upon her separation from AEP service. Ms. Hillebrand is also qualified for 12 months of retiree medical and dental insurance at active employee rates for up to 12 months. Ms. Hillebrand also agreed to a one-year non-competition restriction and affirmed certain non-solicitation, confidentiality and cooperation obligations.
FERC FORM NO. 1 (ED. 12-87) Page 450.2 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) 2020/Q4 Appalachian Power Company End of (2) 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. Line Name (and Title) of Director Principal Business Address No. (a) (b) 1 Nicholas K. Akins, Chairman of the Board and Columbus, Ohio 2 Chief Executive Officer 3 4 Brian X. Tierney, Vice President Columbus, Ohio 5 6 Lana L. Hillebrand, Vice President Columbus, Ohio 7 8 Lisa M. Barton, Vice President Columbus, Ohio 9 10 Mark C. McCullough, Vice President Columbus, Ohio 11 12 David M. Feinberg, Secretary Columbus, Ohio 13 14 Paul Chodak III, Vice President Columbus, Ohio 15 16 Charles R. Patton, Vice President Columbus, Ohio 17 18 NOTE: The Respondent does not have an Executive Committee. 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 48
FERC FORM NO. 1 (ED. 12-95) Page 105 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / INFORMATION ON FORMULA RATES FERC Rate Schedule/Tariff Number FERC Proceeding
Does the respondent have formula rates? X Yes 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 Rate Schedule or Tariff Number FERC Proceeding 1 PJM Interconnection LLC - Attachment H-14 ER17-405 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
FERC FORM NO. 1 (NEW. 12-08) Page 106 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / INFORMATION ON FORMULA RATES FERC Rate Schedule/Tariff Number FERC Proceeding
Does the respondent file with the Commission annual (or more frequent) X Yes filings containing the inputs to the formula rate(s)? No
2. If yes, provide a listing of such filings as contained on the Commission's eLibrary website
Document Formula Rate FERC Rate Line Date Schedule Number or No. Accession No. \ Filed Date Docket No. Description Tariff Number 1 20200526-524405/26/2020 ER17-405 AEP PJM OATT Proj Transmission PJM OATT Attachment H-14 2 20200602-515006/02/2020 ER17-405 AEP PJM OATT Proj Transmission PJM OATT Attachment H-14 3 20201102-524511/02/2020 ER17-405 AEP PJM OATT Proj Transmission PJM OATT Attachment H-14 4 20201116-503911/16/2020 ER17-405 AEP PJM OATT Proj Transmission PJM OATT Attachment H-14 5 20201119-512611/19/2020 ER17-405 AEP PJM OATT Proj Transmission PJM OATT Attachment H-14 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
FERC FORM NO. 1 (NEW. 12-08) Page 106a Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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 1 204-207 Electric Plant in Service g 49 2 214 Electric Plant Held for Future Use d 46 3 216 Construction Work In Progress b 1 4 219 Accumulated Depreciation b 21 5 310-311 Sales for Resale k 1 6 320 Electric Operations & Maintenance Expense b 5 7 320 Electric Operations & Maintenance Expense b 25 8 320 Electric Operations & Maintenance Expense b 31 9 321 Electric Operations & Maintenance Expense b 93 10 323 Electric Operations & Maintenance Expense b 185 11 336 Depreciation Expense b 7 12 354 Distribution of Wages and Salaries b 28 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44
FERC FORM NO. 1 (NEW. 12-08) Page 106b Name of Respondent This Report Is: Date of Report Year/Period of Report Appalachian Power Company (1) X An Original End of 2020/Q4 (2) A Resubmission / / 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.
FERC FORM NO. 1 (ED. 12-96) Page 108 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
1.)
Date Acquired Community Period of Franchise & Consideration Or Extended (full name) Termination ($ amount or “None”) (month/day/year) Automatic Renewal on Hillsville, Virginia Five (5) years expiring None March 14, 2020 (Carroll County, March 13, 2025 Virginia)
2.) None
3.) None
4.) None
5.) None
6.) Long Term - $500M, Virginia State Commission Authority: PUR-2019-00177, Tennessee State Commission Authority: Docket No. 19-00102, SEC Registration Statement: 333-236613, Issued: 5/14/2020, Maturity: 5/1/2050
Remarketed - $50M WVEDA Series 2010A Pollution Control Bond Issued: 12/23/2020, Mandatory Tender: 12/15/2025, Maturity: 12/1/2038
7.) None
8.)
(FERC) AEP 2020 Q-2 Labor / Wage Negotiations Status – December 31, 2020
Effective Status Business Unit Union Contract Total Settlement Date Operating Local Or Personnel Amount % Company, # Wages Represente Location d
04/01/20 Previously Appalachian IBEW Wages 359 2.5% + Market Negotiated Power 978 Adjustment & Ratified Adders (Wires & Gen) (11 CBA’s )
05/01/20 Previously Appalachian USW Wages 176 2.5% + Market Negotiated Power 8621 Adjustment & Ratified Adders John Amos Plant
FERC FORM NO. 1 (ED. 12-96) Page 109.1 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
9.) Please refer to the Notes to Financial Statements Pages 122-123
10.) None
11.) (Reserved)
12.) Not used
13.) Robert W. Bradish elected as Vice President effective 1/28/2020 Deggendorf, Michael L elected as Vice President on 07/31/2020. Walker, Aaron D elected as Vice President – Customer Experience on 09/05/2020. House, David C elected as Assistant Secretary on 09/25/2020. Brekemeyer, Thomas G resigned as Assistant Secretary on 09/25/2020. Wright, Philip A resigned as Vice President – Distribution Region Operations on 07/31/2020. Ferguson, Steven H resigned as VP – Regulatory & Finance on 09/01/2020. Rogier, Daniel J resigned as Vice President on 07/31/2020 Scalzo, John J elected as Vice President - Regulatory & Finance effective 10/03/2020 Zwick, Michael J elected as Vice President - Generation Assets effective 10/03/2020 Hillebrand, Lana resigned as Director & Vice President on 12/31/2020 Tierney, Brian X resigned as Chief Financial Officer on 12/31/2020 Osborne, Debra L resigned as Vice President - Generation Assets on 12/31/2020 Sloat, Julia A resigned as Treasurer on 12/31/2020
14.) Proprietary capital ratio exceeds 30%
FERC FORM NO. 1 (ED. 12-96) Page 109.2 Name of Respondent This Report Is: Date of Report Year/Period of Report (Mo, Da, Yr) Appalachian Power Company (1) X An Original (2) A Resubmission / / End of 2020/Q4 COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) Current Year Prior Year Line Ref. End of Quarter/Year End Balance No. Title of Account Page No. Balance 12/31 (a) (b) (c) (d) 1 UTILITY PLANT 2 Utility Plant (101-106, 114) 200-201 15,655,993,813 14,952,938,408 3 Construction Work in Progress (107) 200-201 485,037,217 593,367,054 4 TOTAL Utility Plant (Enter Total of lines 2 and 3) 16,141,031,030 15,546,305,462 5 (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115) 200-201 5,412,843,611 5,043,796,030 6 Net Utility Plant (Enter Total of line 4 less 5) 10,728,187,419 10,502,509,432 7 Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1) 202-203 0 0 8 Nuclear Fuel Materials and Assemblies-Stock Account (120.2) 0 0 9 Nuclear Fuel Assemblies in Reactor (120.3) 0 0 10 Spent Nuclear Fuel (120.4) 0 0 11 Nuclear Fuel Under Capital Leases (120.6) 0 0 12 (Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5) 202-203 0 0 13 Net Nuclear Fuel (Enter Total of lines 7-11 less 12) 0 0 14 Net Utility Plant (Enter Total of lines 6 and 13) 10,728,187,419 10,502,509,432 15 Utility Plant Adjustments (116) 0 0 16 Gas Stored Underground - Noncurrent (117) 0 0 17 OTHER PROPERTY AND INVESTMENTS 18 Nonutility Property (121) 13,295,545 13,295,545 19 (Less) Accum. Prov. for Depr. and Amort. (122) 5,198,888 5,282,924 20 Investments in Associated Companies (123) 0 0 21 Investment in Subsidiary Companies (123.1) 224-225 5,257,849 4,873,440 22 (For Cost of Account 123.1, See Footnote Page 224, line 42) 23 Noncurrent Portion of Allowances 228-229 22,044,921 22,085,545 24 Other Investments (124) 232,115,959 256,382,619 25 Sinking Funds (125) 0 0 26 Depreciation Fund (126) 0 0 27 Amortization Fund - Federal (127) 0 0 28 Other Special Funds (128) 0 0 29 Special Funds (Non Major Only) (129) 146,605,009 91,880,694 30 Long-Term Portion of Derivative Assets (175) 123,974 135,689 31 Long-Term Portion of Derivative Assets – Hedges (176) 0 0 32 TOTAL Other Property and Investments (Lines 18-21 and 23-31) 414,244,369 383,370,608 33 CURRENT AND ACCRUED ASSETS 34 Cash and Working Funds (Non-major Only) (130) 0 0 35 Cash (131) 5,766,797 3,335,406 36 Special Deposits (132-134) 18,832,104 28,198,147 37 Working Fund (135) 0 0 38 Temporary Cash Investments (136) 0 0 39 Notes Receivable (141) 0 0 40 Customer Accounts Receivable (142) 154,423,761 142,461,144 41 Other Accounts Receivable (143) 295,970 460,018 42 (Less) Accum. Prov. for Uncollectible Acct.-Credit (144) 3,060,607 2,562,493 43 Notes Receivable from Associated Companies (145) 0 0 44 Accounts Receivable from Assoc. Companies (146) 61,647,732 61,989,741 45 Fuel Stock (151) 227 182,954,925 142,401,216 46 Fuel Stock Expenses Undistributed (152) 227 10,651,652 7,344,137 47 Residuals (Elec) and Extracted Products (153) 227 4,821 0 48 Plant Materials and Operating Supplies (154) 227 99,205,804 104,792,085 49 Merchandise (155) 227 0 0 50 Other Materials and Supplies (156) 227 0 0 51 Nuclear Materials Held for Sale (157) 202-203/227 0 0 52 Allowances (158.1 and 158.2) 228-229 22,422,049 22,509,880
FERC FORM NO. 1 (REV. 12-03) Page 110 Name of Respondent This Report Is: Date of Report Year/Period of Report (Mo, Da, Yr) Appalachian Power Company (1) X An Original (2) A Resubmission / / End of 2020/Q4 COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)(Continued) Current Year Prior Year Line Ref. End of Quarter/Year End Balance No. Title of Account Page No. Balance 12/31 (a) (b) (c) (d) 53 (Less) Noncurrent Portion of Allowances 22,044,921 22,085,545 54 Stores Expense Undistributed (163) 227 0 0 55 Gas Stored Underground - Current (164.1) 0 0 56 Liquefied Natural Gas Stored and Held for Processing (164.2-164.3) 0 0 57 Prepayments (165) 6,969,431 8,475,538 58 Advances for Gas (166-167) 0 0 59 Interest and Dividends Receivable (171) 290 29,512 60 Rents Receivable (172) 1,345,780 2,776,929 61 Accrued Utility Revenues (173) 80,063,530 59,691,955 62 Miscellaneous Current and Accrued Assets (174) 0 14,500,000 63 Derivative Instrument Assets (175) 20,103,677 39,560,623 64 (Less) Long-Term Portion of Derivative Instrument Assets (175) 123,974 135,689 65 Derivative Instrument Assets - Hedges (176) 2,386,411 0 66 (Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176 0 0 67 Total Current and Accrued Assets (Lines 34 through 66) 641,845,232 613,742,604 68 DEFERRED DEBITS 69 Unamortized Debt Expenses (181) 27,812,762 25,119,818 70 Extraordinary Property Losses (182.1) 230a 82,485,469 86,410,135 71 Unrecovered Plant and Regulatory Study Costs (182.2) 230b 0 0 72 Other Regulatory Assets (182.3) 232 883,585,010 695,306,657 73 Prelim. Survey and Investigation Charges (Electric) (183) 1,597,802 1,146,055 74 Preliminary Natural Gas Survey and Investigation Charges 183.1) 0 0 75 Other Preliminary Survey and Investigation Charges (183.2) 0 0 76 Clearing Accounts (184) 28,199 259,613 77 Temporary Facilities (185) 0 0 78 Miscellaneous Deferred Debits (186) 233 84,954,431 84,236,474 79 Def. Losses from Disposition of Utility Plt. (187) 0 0 80 Research, Devel. and Demonstration Expend. (188) 352-353 0 0 81 Unamortized Loss on Reaquired Debt (189) 82,060,027 85,452,559 82 Accumulated Deferred Income Taxes (190) 234 494,843,653 480,143,225 83 Unrecovered Purchased Gas Costs (191) 0 0 84 Total Deferred Debits (lines 69 through 83) 1,657,367,353 1,458,074,536 85 TOTAL ASSETS (lines 14-16, 32, 67, and 84) 13,441,644,373 12,957,697,180
FERC FORM NO. 1 (REV. 12-03) Page 111 Name of Respondent This Report is: Date of Report Year/Period of Report (mo, da, yr) Appalachian Power Company (1) x An Original (2) A Resubmission / / end of 2020/Q4 COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS) Current Year Prior Year Line Ref. End of Quarter/Year End Balance No. Title of Account Page No. Balance 12/31 (a) (b) (c) (d) 1 PROPRIETARY CAPITAL 2 Common Stock Issued (201) 250-251 260,457,768 260,457,768 3 Preferred Stock Issued (204) 250-251 0 0 4 Capital Stock Subscribed (202, 205) 0 0 5 Stock Liability for Conversion (203, 206) 0 0 6 Premium on Capital Stock (207) 0 0 7 Other Paid-In Capital (208-211) 253 1,828,626,950 1,828,626,950 8 Installments Received on Capital Stock (212) 252 0 0 9 (Less) Discount on Capital Stock (213) 254 0 0 10 (Less) Capital Stock Expense (214) 254b 0 0 11 Retained Earnings (215, 215.1, 216) 118-119 2,251,598,527 2,081,873,058 12 Unappropriated Undistributed Subsidiary Earnings (216.1) 118-119 -3,463,213 -3,463,213 13 (Less) Reaquired Capital Stock (217) 250-251 0 0 14 Noncorporate Proprietorship (Non-major only) (218) 0 0 15 Accumulated Other Comprehensive Income (219) 122(a)(b) 7,921,384 5,040,772 16 Total Proprietary Capital (lines 2 through 15) 4,345,141,416 4,172,535,335 17 LONG-TERM DEBT 18 Bonds (221) 256-257 225,471,913 250,362,438 19 (Less) Reaquired Bonds (222) 256-257 0 0 20 Advances from Associated Companies (223) 256-257 0 0 21 Other Long-Term Debt (224) 256-257 4,650,495,969 4,150,570,347 22 Unamortized Premium on Long-Term Debt (225) 0 0 23 (Less) Unamortized Discount on Long-Term Debt-Debit (226) 14,079,660 12,020,150 24 Total Long-Term Debt (lines 18 through 23) 4,861,888,222 4,388,912,635 25 OTHER NONCURRENT LIABILITIES 26 Obligations Under Capital Leases - Noncurrent (227) 98,735,304 99,037,628 27 Accumulated Provision for Property Insurance (228.1) 0 0 28 Accumulated Provision for Injuries and Damages (228.2) 6,321,471 325,878 29 Accumulated Provision for Pensions and Benefits (228.3) 10,293,072 24,777,781 30 Accumulated Miscellaneous Operating Provisions (228.4) 0 0 31 Accumulated Provision for Rate Refunds (229) 584,830 0 32 Long-Term Portion of Derivative Instrument Liabilities 100,332 6,199 33 Long-Term Portion of Derivative Instrument Liabilities - Hedges 0 0 34 Asset Retirement Obligations (230) 313,144,616 111,051,232 35 Total Other Noncurrent Liabilities (lines 26 through 34) 429,179,625 235,198,718 36 CURRENT AND ACCRUED LIABILITIES 37 Notes Payable (231) 0 0 38 Accounts Payable (232) 211,962,187 307,741,732 39 Notes Payable to Associated Companies (233) 18,639,896 236,724,314 40 Accounts Payable to Associated Companies (234) 97,012,806 92,751,691 41 Customer Deposits (235) 77,819,096 85,797,019 42 Taxes Accrued (236) 262-263 100,698,572 66,830,813 43 Interest Accrued (237) 49,916,651 47,925,456 44 Dividends Declared (238) 0 0 45 Matured Long-Term Debt (239) 0 0
FERC FORM NO. 1 (rev. 12-03) Page 112 Name of Respondent This Report is: Date of Report Year/Period of Report (mo, da, yr) Appalachian Power Company (1) x An Original (2) A Resubmission / / end of 2020/Q4 COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)(continued) Current Year Prior Year Line Ref. End of Quarter/Year End Balance No. Title of Account Page No. Balance 12/31 (a) (b) (c) (d) 46 Matured Interest (240) 0 0 47 Tax Collections Payable (241) 4,508,998 4,920,790 48 Miscellaneous Current and Accrued Liabilities (242) 76,064,233 82,724,622 49 Obligations Under Capital Leases-Current (243) 22,269,913 22,027,371 50 Derivative Instrument Liabilities (244) 1,244,910 1,883,241 51 (Less) Long-Term Portion of Derivative Instrument Liabilities 100,332 6,199 52 Derivative Instrument Liabilities - Hedges (245) 3,449,077 0 53 (Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges 0 0 54 Total Current and Accrued Liabilities (lines 37 through 53) 663,486,007 949,320,850 55 DEFERRED CREDITS 56 Customer Advances for Construction (252) 0 0 57 Accumulated Deferred Investment Tax Credits (255) 266-267 318,791 502,367 58 Deferred Gains from Disposition of Utility Plant (256) 0 0 59 Other Deferred Credits (253) 269 34,315,356 45,006,038 60 Other Regulatory Liabilities (254) 278 857,824,376 1,000,273,166 61 Unamortized Gain on Reaquired Debt (257) 0 0 62 Accum. Deferred Income Taxes-Accel. Amort.(281) 272-277 152,137,429 160,551,222 63 Accum. Deferred Income Taxes-Other Property (282) 1,406,964,317 1,356,619,158 64 Accum. Deferred Income Taxes-Other (283) 690,388,834 648,777,691 65 Total Deferred Credits (lines 56 through 64) 3,141,949,103 3,211,729,642 66 TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65) 13,441,644,373 12,957,697,180
FERC FORM NO. 1 (rev. 12-03) Page 113 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A 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 (j) the quarter to date amounts for gas utility, and in column (l) 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 Total Total Current 3 Months Prior 3 Months No. Current Year to Prior Year to Ended Ended (Ref.) Date Balance for Date Balance for Quarterly Only Quarterly Only Title of Account Page No. Quarter/Year Quarter/Year No 4th Quarter No 4th Quarter (a) (b) (c) (d) (e) (f) 1 UTILITY OPERATING INCOME 2 Operating Revenues (400) 300-301 2,857,247,281 2,946,228,901 3 Operating Expenses 4 Operation Expenses (401) 320-323 1,379,799,825 1,537,193,037 5 Maintenance Expenses (402) 320-323 226,820,833 255,428,601 6 Depreciation Expense (403) 336-337 511,822,169 523,747,065 7 Depreciation Expense for Asset Retirement Costs (403.1) 336-337 2,978,914 3,533,259 8 Amort. & Depl. of Utility Plant (404-405) 336-337 34,704,003 25,584,686 9 Amort. of Utility Plant Acq. Adj. (406) 336-337 10 Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407) 4,094,894 3,987,119 11 Amort. of Conversion Expenses (407) 12 Regulatory Debits (407.3) 4,190,246 -2,842,340 13 (Less) Regulatory Credits (407.4) 48,957,692 14 Taxes Other Than Income Taxes (408.1) 262-263 149,716,603 145,906,459 15 Income Taxes - Federal (409.1) 262-263 27,790,428 44,138,282 16 - Other (409.1) 262-263 8,378,083 12,277,497 17 Provision for Deferred Income Taxes (410.1) 234, 272-277 1,193,050,491 1,462,319,773 18 (Less) Provision for Deferred Income Taxes-Cr. (411.1) 234, 272-277 1,222,271,015 1,583,913,319 19 Investment Tax Credit Adj. - Net (411.4) 266 -170,592 20 (Less) Gains from Disp. of Utility Plant (411.6) 486,254 425,454 21 Losses from Disp. of Utility Plant (411.7) 24,345 24,345 22 (Less) Gains from Disposition of Allowances (411.8) 102,181 271,473 23 Losses from Disposition of Allowances (411.9) 24 Accretion Expense (411.10) 8,917,931 5,926,843 25 TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24) 2,280,301,031 2,432,614,380 26 Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117,line 27 576,946,250 513,614,521
FERC FORM NO. 1/3-Q (REV. 02-04) Page 114 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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 Current Year to Date Previous Year to Date Current Year to Date Previous Year to Date Current Year to Date Previous Year to Date Line (in dollars) (in dollars) (in dollars) (in dollars) (in dollars) (in dollars) No. (g) (h) (i) (j) (k) (l) 1 2,857,247,281 2,946,228,901 2 3 1,379,799,825 1,537,193,037 4 226,820,833 255,428,601 5 511,822,169 523,747,065 6 2,978,914 3,533,259 7 34,704,003 25,584,686 8 9 4,094,894 3,987,119 10 11 4,190,246 -2,842,340 12 48,957,692 13 149,716,603 145,906,459 14 27,790,428 44,138,282 15 8,378,083 12,277,497 16 1,193,050,491 1,462,319,773 17 1,222,271,015 1,583,913,319 18 -170,592 19 486,254 425,454 20 24,345 24,345 21 102,181 271,473 22 23 8,917,931 5,926,843 24 2,280,301,031 2,432,614,380 25 576,946,250 513,614,521 26
FERC FORM NO. 1 (ED. 12-96) Page 115 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / STATEMENT OF INCOME FOR THE YEAR (continued) Line TOTAL Current 3 Months Prior 3 Months No. Ended Ended (Ref.) Quarterly Only Quarterly Only Title of Account Page No. Current Year Previous Year No 4th Quarter No 4th Quarter (a) (b) (c) (d) (e) (f)
27 Net Utility Operating Income (Carried forward from page 114) 576,946,250 513,614,521 28 Other Income and Deductions 29 Other Income 30 Nonutilty Operating Income 31 Revenues From Merchandising, Jobbing and Contract Work (415) 32 (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) 33 Revenues From Nonutility Operations (417) 9 34 (Less) Expenses of Nonutility Operations (417.1) 990 680 35 Nonoperating Rental Income (418) -15,157 -69,546 36 Equity in Earnings of Subsidiary Companies (418.1) 119 37 Interest and Dividend Income (419) 1,345,705 1,825,158 38 Allowance for Other Funds Used During Construction (419.1) 14,619,304 16,589,692 39 Miscellaneous Nonoperating Income (421) 97,249 602,172 40 Gain on Disposition of Property (421.1) 240,546 2,562,655 41 TOTAL Other Income (Enter Total of lines 31 thru 40) 16,286,657 21,509,460 42 Other Income Deductions 43 Loss on Disposition of Property (421.2) 401,163 44 Miscellaneous Amortization (425) 45 Donations (426.1) 1,241,165 24,819,038 46 Life Insurance (426.2) 47 Penalties (426.3) -698,326 913,499 48 Exp. for Certain Civic, Political & Related Activities (426.4) 1,424,584 1,654,295 49 Other Deductions (426.5) 6,111,130 9,366,855 50 TOTAL Other Income Deductions (Total of lines 43 thru 49) 8,479,716 36,753,687 51 Taxes Applic. to Other Income and Deductions 52 Taxes Other Than Income Taxes (408.2) 262-263 320,687 335,038 53 Income Taxes-Federal (409.2) 262-263 -6,077,353 -7,300,722 54 Income Taxes-Other (409.2) 262-263 892,790 -364,471 55 Provision for Deferred Inc. Taxes (410.2) 234, 272-277 4,218,526 3,635,372 56 (Less) Provision for Deferred Income Taxes-Cr. (411.2) 234, 272-277 1,435,083 8,380,561 57 Investment Tax Credit Adj.-Net (411.5) -12,984 -477,264 58 (Less) Investment Tax Credits (420) 59 TOTAL Taxes on Other Income and Deductions (Total of lines 52-58) -2,093,417 -12,552,608 60 Net Other Income and Deductions (Total of lines 41, 50, 59) 9,900,358 -2,691,619 61 Interest Charges 62 Interest on Long-Term Debt (427) 211,822,330 201,244,487 63 Amort. of Debt Disc. and Expense (428) 3,761,971 3,579,752 64 Amortization of Loss on Reaquired Debt (428.1) 3,800,583 3,839,844 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) 2,818,979 2,144,242 68 Other Interest Expense (431) 2,826,301 3,070,967 69 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 7,916,223 9,255,233 70 Net Interest Charges (Total of lines 62 thru 69) 217,113,941 204,624,059 71 Income Before Extraordinary Items (Total of lines 27, 60 and 70) 369,732,667 306,298,843 72 Extraordinary Items 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 Items After Taxes (line 75 less line 76) 78 Net Income (Total of line 71 and 77) 369,732,667 306,298,843
FERC FORM NO. 1 (ED. 12-96) Page 117 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) 2020/Q4 Appalachian Power Company End of (2) A Resubmission / / 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.
Current Previous Quarter/Year Quarter/Year Contra Primary Year to Date Year to Date Line Item Account Affected Balance Balance No. (a) (b) (c) (d) UNAPPROPRIATED RETAINED EARNINGS (Account 216) 1 Balance-Beginning of Period 2,063,881,888 1,908,019,866 2 Changes 3 Adjustments to Retained Earnings (Account 439) 4 CECL adoption of ASC 326 -7,198 5 6 7 8 9 TOTAL Credits to Retained Earnings (Acct. 439) -7,198 10 11 12 13 14 15 TOTAL Debits to Retained Earnings (Acct. 439) 16 Balance Transferred from Income (Account 433 less Account 418.1) 369,732,667 306,298,843 17 Appropriations of Retained Earnings (Acct. 436) 18 Excess Earnings on Hydro Licensed Projects -259,220 ( 436,821) 19 20 21 22 TOTAL Appropriations of Retained Earnings (Acct. 436) -259,220 ( 436,821) 23 Dividends Declared-Preferred Stock (Account 437) 24 25 26 27 28 29 TOTAL Dividends Declared-Preferred Stock (Acct. 437) 30 Dividends Declared-Common Stock (Account 438) 31 Common Stock -200,000,000 ( 150,000,000) 32 33 34 35 36 TOTAL Dividends Declared-Common Stock (Acct. 438) -200,000,000 ( 150,000,000) 37 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings 38 Balance - End of Period (Total 1,9,15,16,22,29,36,37) 2,233,348,137 2,063,881,888 APPROPRIATED RETAINED EARNINGS (Account 215) 39 40
FERC FORM NO. 1/3-Q (REV. 02-04) Page 118 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) 2020/Q4 Appalachian Power Company End of (2) A Resubmission / / 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.
Current Previous Quarter/Year Quarter/Year Contra Primary Year to Date Year to Date Line Item Account Affected Balance Balance No. (a) (b) (c) (d) 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 (Acct. 215.1) 18,250,390 17,991,170 47 TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46) 18,250,390 17,991,170 48 TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1) 2,251,598,527 2,081,873,058 UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account Report only on an Annual Basis, no Quarterly 49 Balance-Beginning of Year (Debit or Credit) -3,463,213 ( 3,463,213) 50 Equity in Earnings for Year (Credit) (Account 418.1) 51 (Less) Dividends Received (Debit) 52 53 Balance-End of Year (Total lines 49 thru 52) -3,463,213 ( 3,463,213)
FERC FORM NO. 1/3-Q (REV. 02-04) Page 119 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (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. Current Year to Date Previous Year to Date Line Description (See Instruction No. 1 for Explanation of Codes) No. Quarter/Year Quarter/Year (a) (b) (c) 1 Net Cash Flow from Operating Activities: 2 Net Income (Line 78(c) on page 117) 369,732,667 306,298,843 3 Noncash Charges (Credits) to Income: 4 Depreciation and Depletion 553,599,980 556,852,129 5 Amortization of Regulatory Debits and Credits -44,767,446 -2,842,340 6 Customer Depositd -7,977,923 -2,636,638 7 Carrying Costs -27,828 8 Deferred Income Taxes (Net) -26,437,081 -126,338,735 9 Investment Tax Credit Adjustment (Net) -183,576 -477,264 10 Net (Increase) Decrease in Receivables -9,498,073 31,643,340 11 Net (Increase) Decrease in Inventory -38,279,764 -93,462,584 12 Net (Increase) Decrease in Allowances Inventory 87,831 208,259 13 Net Increase (Decrease) in Payables and Accrued Expenses -12,482,084 33,581,390 14 Net (Increase) Decrease in Other Regulatory Assets -96,551,619 -29,911,659 15 Net Increase (Decrease) in Other Regulatory Liabilities 12,022,095 -39,543,963 16 (Less) Allowance for Other Funds Used During Construction 14,619,304 16,589,692 17 (Less) Undistributed Earnings from Subsidiary Companies 18 Other (provide details in footnote): -14,188,912 -111,207,976 19 Impairment of Long-lived Assets 92,881,361 20 Over/Under Recovered Fuel, Net 37,245,483 57,059,308 21 22 Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21) 707,702,274 655,485,951 23 24 Cash Flows from Investment Activities: 25 Construction and Acquisition of Plant (including land): 26 Gross Additions to Utility Plant (less nuclear fuel) -784,634,596 -878,044,809 27 Gross Additions to Nuclear Fuel 28 Gross Additions to Common Utility Plant 29 Gross Additions to Nonutility Plant -21,477 -1,103,849 30 (Less) Allowance for Other Funds Used During Construction -14,619,304 -16,589,692 31 Other (provide details in footnote): 32 33 Aquired Assets -771,426 -885,251 34 Cash Outflows for Plant (Total of lines 26 thru 33) -770,808,195 -863,444,217 35 36 Acquisition of Other Noncurrent Assets (d) 37 Proceeds from Disposal of Noncurrent Assets (d) 6,935,976 13,470,706 38 39 Investments in and Advances to Assoc. and Subsidiary Companies 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)
FERC FORM NO. 1 (ED. 12-96) Page 120 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (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. Current Year to Date Previous Year to Date Line Description (See Instruction No. 1 for Explanation of Codes) No. Quarter/Year Quarter/Year (a) (b) (c) 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 43,494 52 Net Increase (Decrease) in Payables and Accrued Expenses 53 Other (provide details in footnote): 2,605,552 11,569,800 54 (Increase) Decrease in other special deposits 158,275 305,031 55 56 Net Cash Provided by (Used in) Investing Activities 57 Total of lines 34 thru 55) -761,064,898 -838,098,680 58 59 Cash Flows from Financing Activities: 60 Proceeds from Issuance of: 61 Long-Term Debt (b) 615,350,000 486,000,000 62 Preferred Stock 63 Common Stock 64 Other (provide details in footnote): 65 Long-Term Issuance Costs -8,484,216 -7,804,243 66 Net Increase in Short-Term Debt (c) 67 Proceeds on Capital Leaseback 741,695 865,943 68 Notes Payable to Associates Companies 31,083,435 69 70 Cash Provided by Outside Sources (Total 61 thru 69) 607,607,479 510,145,135 71 72 Payments for Retirement of: 73 Long-term Debt (b) -140,314,903 -180,463,069 74 Preferred Stock 75 Common Stock 76 Other (provide details in footnote): 77 Notes Payable to Associates Companies -218,084,418 78 Net Decrease in Short-Term Debt (c) 79 80 Dividends on Preferred Stock 81 Dividends on Common Stock -200,000,000 -150,000,000 82 Net Cash Provided by (Used in) Financing Activities 83 (Total of lines 70 thru 81) 49,208,158 179,682,066 84 85 Net Increase (Decrease) in Cash and Cash Equivalents 86 (Total of lines 22,57 and 83) -4,154,466 -2,930,663 87 88 Cash and Cash Equivalents at Beginning of Period 26,832,033 29,762,696 89 90 Cash and Cash Equivalents at End of period 22,677,567 26,832,033
FERC FORM NO. 1 (ED. 12-96) Page 121 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 FOOTNOTE DATA
Schedule Page: 120 Line No.: 18 Column: b 2020 2019 Cash Flow Cash Flow Incr / (Decr) Incr / (Decr) Utility Plant, Net $(42,872,559) $(139,312,668) Property and Investments, Net 24,160,608 26,461,242 Margin Deposits 2,621,912 7,891,732 Mark-to-Market of Risk Management Contracts 18,818,615 19,835,349 Prepayments (13,845,073) (2,112,652) Accrued Utility Revenues, Net (20,371,575) 3,780,147 Miscellaneous Current and Accr Assets 14,500,000 (8,537) Unamortized Debt Expense 2,428,222 2,552,122 Other Deferred Debits, Net 7,011,262 7,835,831 Proprietary Capital, Net (7,198) - Other Comprehensive Income, Net (891,858) (891,858) Unamortized Discount/Premium on Long-Term Debt 895,490 814,579 Accumulated Provisions - Misc 6,842,236 7,104,717 Current and Accrued Liabilities, Net (8,320,752) (31,864,528) Other Deferred Credits, Net (5,158,241) (13,293,452) Total $(14,188,912) $(111,207,976)
Schedule Page: 120 Line No.: 37 Column: b 2020 2019 Cash Flow Cash Flow Incr / (Decr) Incr / (Decr) Sale of transformers between various operating companies $ 2,387,731 $ 413,428 Sale of meters between various operating companies $ 3,510,391 $ 4,713,890 Sale of land to Vogel & Cromwell $ 910,354 $ - Sale of 23.24 +/- acres located in Buffalo Power Plant site $ 127,500 $ - Sale of turbines to Gavin Power $ - $ 5,000,000 Sale of land to Volvo Group $ - $ 154,815 Sale of land to Plyler Properties $ - $ 1,302,741 Sale of land to Bowles Rice $ - $ 1,376,317 Sales of transformer to TCI of AL $ - $ 100,000 Transco Transfer of Assets $ - $ 409,515 Total $ 6,935,976 $ 13,470,706
Schedule Page: 120 Line No.: 53 Column: b 2020 2019 Cash Flow Cash Flow Incr / (Decr) Incr / (Decr) CIAC Proceeds $ 2,605,552 $ 11,569,800 Total $ 2,605,552 $ 11,569,800
FERC FORM NO. 1 (ED. 12-87) Page 450.1 Name of Respondent This Report Is: Date of Report Year/Period of Report Appalachian Power Company (1) X An Original End of 2020/Q4 (2) A Resubmission / / 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 3Q 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 3Q 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.
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FERC FORM NO. 1 (ED. 12-96) Page 122 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
INDEX OF NOTES TO FINANCIAL STATEMENTS
Glossary of Terms for Notes 1. Organization and Summary of Significant Accounting Policies 2. New Accounting Standards 3. Comprehensive Income 4. Rate Matters 5. Effects of Regulation 6. Commitments, Guarantees and Contingencies 7. Impairments 8. Benefit Plans 9. Business Segments 10. Derivatives and Hedging 11. Fair Value Measurements 12. Income Taxes 13. Leases 14. Financing Activities 15. Related Party Transactions 16. Property, Plant and Equipment 17. Revenue from Contracts with Customers 18. FERC Order NO. 784-A 19 Subsequent Events
FERC FORM NO. 1 (ED. 12-88) Page 123.1 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
GLOSSARY OF TERMS FOR NOTES
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.
Term Meaning
AEP American Electric Power Company, Inc., an investor-owned electric public utility holding company which includes American Electric Power Company, Inc. (Parent) and majority-owned subsidiaries and affiliates. AEP Credit AEP Credit, Inc., a subsidiary of AEP which securitizes accounts receivable and accrued utility revenues for affiliated electric utility companies. AEP East Companies APCo, I&M, KGPCo, KPCo, OPCo and WPCo. AEP System American Electric Power System, an electric system, owned and operated by AEP subsidiaries. AEPSC American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries. AFUDC Allowance for Equity Funds Used During Construction. AMI Advanced Metering Infrastructure. AMT Alternative Minimum Tax. AOCI Accumulated Other Comprehensive Income. APCo Appalachian Power Company, an AEP electric utility subsidiary. ARO Asset Retirement Obligations. ASU Accounting Standards Update. CAA of 2021 Consolidated Appropriations Act of 2021 signed into law in December 2020. CARES Act Coronavirus Aid, Relief, and Economic Security Act signed into law in March 2020. COVID-19 Coronavirus 2019, a highly infectious respiratory disease. In March 2020, the World Health Organization declared COVID-19 a worldwide pandemic. EIS Energy Insurance Services, Inc., a nonaffiliated captive insurance company. ENEC Expanded Net Energy Cost. Excess ADIT Excess accumulated deferred income taxes. FAC Fuel Adjustment Clause. FASB Financial Accounting Standards Board. Federal EPA United States Environmental Protection Agency. FERC Federal Energy Regulatory Commission. FTR Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices. GAAP Accounting Principles Generally Accepted in the United States of America. I&M Indiana Michigan Power Company, an AEP electric utility subsidiary. IRS Internal Revenue Service. ITC Investment Tax Credit. KGPCo Kingsport Power Company, an AEP electric utility subsidiary. KPCo Kentucky Power Company, an AEP electric utility subsidiary. MTM Mark-to-Market. MW Megawatt. MWh Megawatt-hour. NOL Net operating losses. NO x Nitrogen oxide. OATT Open Access Transmission Tariff. OPCo Ohio Power Company, an AEP electric utility subsidiary. OPEB Other Postretirement Benefits.
FERC FORM NO. 1 (ED. 12-88) Page 123.2 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
Operating Agreement Agreement, dated January 1, 1997, as amended, by and among PSO and SWEPCo governing generating capacity allocation, energy pricing, and revenues and costs of third-party sales. AEPSC acts as the agent. OTC Over-the-counter. OVEC Ohio Valley Electric Corporation, which is 43.47% owned by AEP. Parent American Electric Power Company, Inc., the equity owner of AEP subsidiaries within the AEP consolidation. PCA Power Coordination Agreement among APCo, I&M, KPCo and WPCo. PJM Pennsylvania – New Jersey – Maryland regional transmission organization. PPA Purchase Power and Sale Agreement. PSO Public Service Company of Oklahoma, an AEP electric utility subsidiary. Reference Rate Reform The global transition away from referencing the London Interbank Offered Rate and other interbank offered rates, and toward new reference rates that are more reliable and robust. Risk Management Contracts Trading and non-trading derivatives, including those derivatives designated as cash flow and fair value hedges. ROE Return on Equity. RPM Reliability Pricing Model. RTO Regional Transmission Organization, responsible for moving electricity over large interstate areas. SIA System Integration Agreement, effective June 15, 2000, as amended, provides contractual basis for coordinated planning, operation and maintenance of the power supply sources of the combined AEP. SSO Standard service offer. SWEPCo Southwestern Electric Power Company, an AEP electric utility subsidiary. Tax Reform On December 22, 2017, President Trump signed into law legislation referred to as the “Tax Cuts and Jobs Act” (the TCJA). The TCJA includes significant changes to the Internal Revenue Code of 1986, including a reduction in the corporate federal income tax rate from 35% to 21% effective January 1, 2018. Utility Money Pool Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries. Virginia SCC Virginia State Corporation Commission. WPCo Wheeling Power Company, an AEP electric utility subsidiary. WVPSC Public Service Commission of West Virginia.
FERC FORM NO. 1 (ED. 12-88) Page 123.3 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION
As a public utility, APCo engages in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to approximately 964,000 retail customers in its service territory in southwestern Virginia and southern West Virginia. APCo sells power at wholesale to municipalities.
To minimize the credit requirements and operating constraints when operating within PJM, participating AEP companies, including APCo, agreed to a netting of certain payment obligations incurred by the participating AEP companies against certain balances due to such AEP companies and to hold PJM harmless from actions that any one or more AEP companies may take with respect to PJM.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Rates and Service Regulation
APCo’s rates are regulated by the FERC, the Virginia SCC and the WVPSC. The FERC also regulates APCo’s affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over the issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system.
The FERC regulates wholesale power markets and wholesale power transactions. APCo’s wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that APCo has “market power” in the region where the transaction occurs. Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued-up to actual costs annually.
The Virginia SCC and the WVPSC regulate all of the retail distribution operations and rates of APCo’s, retail public utility subsidiaries on a cost basis. They also regulate the retail generation/power supply operations and rates.
FERC FORM NO. 1 (ED. 12-88) Page 123.4 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
The FERC also regulates APCo’s wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. Retail transmission rates are based on formula rates included in the PJM OATT that are cost-based and are unbundled in Virginia Bundled retail transmission rates are regulated, on a cost basis, by the Virginia SCC and WVPSC.
In West Virginia, APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis.
In addition, the FERC regulates the SIA, Operating Agreement, Transmission Agreement and Transmission Coordination Agreement, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement. The FERC also regulates the PCA. See Note 15 - Related Party Transactions for additional information.
FERC FORM NO. 1 (ED. 12-88) Page 123.5 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
Basis of Accounting
APCo’s accounting is subject to the requirements of the Virginia SCC, the WVPSC and the FERC. The financial statements have been prepared in accordance with the Uniform System of Accounts prescribed by the FERC. The principal differences from GAAP include:
• Accounting for subsidiaries on an equity basis. • The classification of deferred fuel as noncurrent rather than current. • The requirement to report deferred tax assets and liabilities separately rather than as a single amount. • The classification of accrued taxes as a single amount rather than as assets and liabilities. • The exclusion of current maturities of long-term debt from current liabilities. • The classification of accrued non-ARO asset removal costs as accumulated depreciation rather than regulatory liabilities. • The classification of finance lease payments as operating activities instead of financing activities. • The classification of gains/losses from disposition of allowances as utility operating expenses rather than as operating revenues. • The classification of PJM hourly activity for physical transactions as purchases and sales instead of net sales. • The classification of regulatory assets and liabilities related to the accounting guidance for “Accounting for Income Taxes” as separate assets and liabilities rather than as a single amount. • The presentation of finance leased assets and their associated accumulated amortization as a single amount instead of as separate amounts. • The classification of factored accounts receivable expense as a nonoperating expense instead of as an operating expense. • The classification of certain nonoperating revenues as miscellaneous nonoperating income instead of as operating revenue. • The classification of certain nonoperating expenses as miscellaneous nonoperating expense instead of as operating expense. • The separate classification of income tax expense for operating and nonoperating activities instead of as a single income tax expense. • The classification of gas procurement sales as a reduction of fuel expense rather than as revenue. • The classification of unamortized loss on reacquired debt in deferred debits rather than in regulatory assets. • The classification of accumulated deferred investment tax credits in deferred credits rather than in regulatory liabilities and deferred investment tax credits. • The classification of deferred equity income in other deferred credits rather than in other noncurrent assets as securitized transition assets. • The classification of amortization of deferred equity in operating revenues rather than in depreciation and amortization. • The classification of certain other assets and liabilities as current instead of noncurrent.
FERC FORM NO. 1 (ED. 12-88) Page 123.6 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
• The classification of certain other assets and liabilities as noncurrent instead of current. • The classification of debt issuance costs as noncurrent assets instead of noncurrent liabilities. • The classification of change in emission allowances held for speculation as investing activities instead of operating activities. • The classification of rents receivable as rents receivable instead of customer accounts receivable. • The classification of Non-Service Cost Components of Net Periodic Benefit Cost as Operating Expense instead of Other Income (Expense). • The classification of operating lease assets as Utility Plant rather than as a noncurrent asset. • The presentation of obligations under finance and operating leases as a single amount in Obligations Under Capital Leases rather than as separate items. • The classification of certain expenses in operating income rather than operating expenses. • The classification of interest on regulated finance leases as operating expense instead of Other Income (Expense). • The classification of certain write offs as depreciation expense rather than as operating expenses. • The classification of cloud computing implementation costs as Utility Plant rather than as a noncurrent asset.
• The classification of accelerated depreciation caused by regulatory orders as accumulated depreciation rather than regulatory liabilities. • The classification of deferred FICA taxes as taxes accrued rather than as a noncurrent liability. • The classification of expenses and revenues caused by regulatory orders as depreciation expense rather than operating revenues.
Accounting for the Effects of Cost-Based Regulation
APCo’s financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates.
Use of Estimates
The preparation of these financial statements requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and
FERC FORM NO. 1 (ED. 12-88) Page 123.7 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates.
Cash and Cash Equivalents
Cash and Cash Equivalents include Cash, Working Fund and Temporary Cash Investments on the balance sheets with original maturities of three months or less.
Supplementary Information
2020 2019 For the Years Ended December 31, (in millions) Cash was Paid (Received) for: Interest (Net of Capitalized Amounts) $ 207.1 $ 190.7 Income Taxes (Net of Refunds) 0.6 62.9 Noncash Acquisitions Under Capital Leases 7.2 8.8 As of December 31, Construction Expenditures Included in Current and Accrued Liabilities 105.6 149.7
Special Deposits
Special Deposits include funds held by trustees primarily for margin deposits for risk management activities.
Inventory
Fossil fuel and materials and supplies inventories are carried at average cost.
Accounts Receivable
Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities.
Revenue is recognized over time as the performance obligations of delivering energy to customers are satisfied. To the extent that deliveries have occurred but a bill has not been issued, APCo accrues and recognizes, as Accrued Utility Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing.
AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to
FERC FORM NO. 1 (ED. 12-88) Page 123.8 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
AEP Credit. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables they acquire from affiliated utility subsidiaries. See “Securitized Accounts Receivable – AEP Credit” section of Note 14 for additional information.
Allowance for Uncollectible Accounts
Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from APCo. The assessment is performed by APCo which inherently contemplates any differences in geographical risk characteristics for the allowance. For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For miscellaneous accounts receivable, bad debt expense is recorded based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable, unless specifically identified. In addition to these processes, management contemplates available current information, as well as any reasonable and supportable forecast information, to determine if allowances for uncollectible accounts should be further adjusted in accordance with the accounting guidance for “Credit Losses.” Management’s assessments contemplate expected losses over the life of the accounts receivable.
Concentrations of Credit Risk and Significant Customers
APCo does not have any significant customers that comprise 10% or more of its operating revenues.
APCo monitors credit levels and the financial condition of its customers on a continuous basis to minimize credit risk. The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs. Management believes adequate provisions for credit loss have been made in the accompanying financial statements.
Property, Plant and Equipment
Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review. Removal costs accrued are charged to accumulated depreciation. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses.
FERC FORM NO. 1 (ED. 12-88) Page 123.9 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in-service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed or is not probable, the cost of that asset shall be removed from plant-in-service or construction work in progress and charged to expense. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals.
Subsidiary Companies
APCo has three wholly-owned coal company subsidiaries, Cedar Coal Company, Central Appalachian Coal Company and Southern Appalachian Coal Company and one jointly owned subsidiary, Central Coal Company. The coal companies were formerly engaged in coal-mining operations and currently lease and sublease portions of their coal rights and land to nonaffiliated companies. Investment in the net assets of the coal company subsidiaries is carried at cost plus equity in their undistributed earnings since acquisition.
Appalachian Consumer Rate Relief Funding LLC, a wholly-owned subsidiary of APCo, was formed for the purpose of issuing and servicing securitization bonds related to the under-recovered ENEC deferral balance and is consolidated in APCo’s financial statements.
Allowance for Funds Used During Construction
AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant.
FERC FORM NO. 1 (ED. 12-88) Page 123.10 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
Valuation of Nonderivative Financial Instruments
The book values of Cash, Special Deposits, Working Fund, Notes Receivable from Associated Companies, Notes Payable to Associated Companies, accounts receivable and accounts payable approximate fair value because of the short-term maturity of these instruments.
Fair Value Measurements of Assets and Liabilities
The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability.
For commercial activities, exchange-traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange-traded derivatives where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket-based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility.
FERC FORM NO. 1 (ED. 12-88) Page 123.11 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes.
Assets in the benefit trusts are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Investments classified as Other are valued using Net Asset Value as a practical expedient. Items classified as Other are primarily cash equivalent funds, common collective trusts, commingled funds, structured products, private equity, real estate, infrastructure and alternative credit investments. These investments do not have a readily determinable fair value or they contain redemption restrictions which may include the right to suspend redemptions under certain circumstances. Redemption restrictions may also prevent certain investments from being redeemed at the reporting date for the underlying value.
Deferred Fuel Costs
The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Operation Expenses when the fuel is burned or the allowance or consumable is utilized. Fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel-related revenues) are generally deferred as regulatory assets. These deferrals are amortized when refunded or when billed to customers in later months with the Virginia SCC’s and the WVPSC’s review and approval. The amount of an over-recovery or under-recovery can also be affected by actions of the Virginia SCC and the WVPSC. On a routine basis, the Virginia SCC and the WVPSC review and/or audit APCo’s fuel procurement policies and practices, the fuel cost calculations and FAC deferrals. FAC deferrals are adjusted when costs are no longer probable of recovery or when refunds of fuel reserves are probable. APCo shares the majority of its Off-system Sales margins to customers either through an active FAC or other rate mechanisms. Where the FAC or Off-system Sales sharing mechanism is capped, frozen or non-existent, changes in fuel costs or sharing of off-system sales impact earnings.
FERC FORM NO. 1 (ED. 12-88) Page 123.12 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
Revenue Recognition
Regulatory Accounting
APCo’s financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses or alternative revenues recognized in accordance with the guidance for “Regulated Operations”) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching revenue with its passage to customers in cost-based regulated rates.
When regulatory assets are probable of recovery through regulated rates, assets are recorded on the balance sheets. Regulatory assets are tested for probability of recovery at each balance sheet date or whenever new events occur. Examples of new events include the issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, the regulatory asset is derecognized as a charge against income.
Retail and Wholesale Supply and Delivery of Electricity
APCo recognizes revenues from customers for retail and wholesale electricity sales and electricity transmission and distribution delivery services. APCo recognizes such revenues on the statements of income as the performance obligations of delivering energy to customers are satisfied. Recognized revenues include both billed and unbilled amounts.
Wholesale transmission revenue is based on FERC-approved formula rate filings made for each calendar year using estimated costs. Revenues initially recognized per the annual rate filing are compared to actual costs, resulting in the subsequent recognition of an over or under-recovered amount, with interest, that is refunded or recovered, respectively, in a future year’s rates. These annual true-ups meet the definition of alternative revenues in accordance with the accounting guidance for “Regulated Operations”, and are recognized by APCo in the second quarter of each calendar year following the filing of annual FERC reports. Any portion of the true-ups applicable to an affiliated company is recorded as Accounts Receivable from Associated Companies or Accounts Payable to Associated Companies on the balance sheets. Any portion of the true-ups applicable to third-parties is recorded as regulatory assets or regulatory liabilities on the balance sheets. See Note 17 - Revenue from Contracts with Customers for additional information.
Gross versus Net Presentation of Certain Electricity Supply and Delivery Activities
Most of the power produced at the generation plants is sold to PJM. APCo also purchases power from PJM to supply power to customers. Generally, these power sales and purchases are reported on a net basis as revenues on the statements of income. However, purchases of power in excess of sales to PJM, on an hourly net basis, used to serve retail load are recorded gross as Operation Expenses on the statements of income.
FERC FORM NO. 1 (ED. 12-88) Page 123.13 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
Physical energy purchases arising from non-derivative contracts are accounted for on a gross basis in Operation Expenses on the statements of income. Energy purchases arising from non-trading derivative contracts are recorded based on the transaction’s facts and circumstances. Purchases under non-trading derivatives used to serve accrual based obligations are recorded in Operation Expenses on the statements of income. All other non-trading derivative purchases are recorded net in revenues.
In general, APCo records expenses when purchased electricity is received and when expenses are incurred. APCo defers unrealized MTM amounts as regulatory assets (for losses) and regulatory liabilities (for gains).
Energy Marketing and Risk Management Activities
APCo engages in power, capacity and, to a lesser extent, natural gas marketing as major power producer and participant in electricity and natural gas markets. APCo also engages in power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity risk management activities focused on markets where the AEP System owns assets and on adjacent markets. These activities include the purchase-and-sale of energy under forward contracts at fixed and variable prices. These contracts include physical transactions, exchange-traded futures, and to a lesser extent, OTC swaps and options. Certain energy marketing and risk management transactions are with RTOs.
APCo recognizes revenues from marketing and risk management transactions that are not derivatives as the performance obligation of delivering the commodity is satisfied APCo uses MTM accounting for marketing and risk management transactions that are derivatives unless the derivative is designated in a qualifying cash flow hedge relationship or elected normal under the normal purchase normal sale election. APCo includes realized gains and losses on marketing and risk management transactions in revenues or expense based on the transaction’s facts and circumstances. The unrealized MTM amounts and some realized gains and losses are deferred as regulatory assets (for losses) and regulatory liabilities (for gains).
Certain qualifying marketing and risk management derivatives transactions are designated as hedges of variability in future cash flows as a result of forecasted transactions (cash flow hedge). In the event APCo designates a cash flow hedge, the cash flow hedge’s gain or loss is initially recorded as a component of AOCI. When the forecasted transaction is realized and affects net income, APCo subsequently reclassifies the gain or loss on the hedge from AOCI into revenues or expenses within the same financial statement line item as the forecasted transaction on their statements of income. See “Accounting for Cash Flow Hedging Strategies” section of Note 10 for additional information.
FERC FORM NO. 1 (ED. 12-88) Page 123.14 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
Maintenance
APCo expenses maintenance costs as incurred. If it becomes probable that APCo will recover specifically-incurred costs through future rates, a regulatory asset is established to match the expensing of those maintenance costs with its recovery in cost-based regulated revenues. APCo defers costs above the level included in base rates and amortizes those deferrals commensurate with recovery through rate riders.
Income Taxes and Investment Tax Credits
APCo uses the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which the temporary differences are expected to be recovered or settled.
When the flow-through method of accounting for temporary differences is required by a regulator to be reflected in regulated revenues (that is, when deferred taxes are not included in the cost-of-service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense.
APCo applies the deferral methodology for the recognition of ITCs. Deferred ITCs are amortized to income tax expense over the life of the asset that generated the credit. Amortization of deferred ITCs begins when the asset is placed in-service, except where regulatory commissions reflect ITCs in the rate-making process, then amortization begins when the cash tax benefit is recognized.
APCo accounts for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” APCo classifies interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classifies penalties as Penalties on the statements of income.
Excise Taxes
As an agent for some state and local governments, APCo collects from customers certain excise taxes levied by those state or local governments on customers. APCo does not record these taxes as revenue or expense.
Debt
Gains and losses from the reacquisition of debt used to finance regulated electric utility plants are deferred and amortized over the remaining term of the reacquired debt in accordance with their rate-making treatment unless the debt is refinanced. If the reacquired debt associated with the regulated business is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost-based regulatory accounting are generally deferred and amortized over the term of the replacement debt consistent with its recovery in rates.
FERC FORM NO. 1 (ED. 12-88) Page 123.15 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
Debt discount or premium and debt issuance expenses are deferred and amortized generally utilizing the straight-line method over the term of the related debt. The straight-line method approximates the effective interest method and is consistent with the treatment in rates for regulated operations.
Pension and OPEB Plans
APCo participates in an AEP sponsored qualified pension plan and an unfunded nonqualified pension plan. Substantially all APCo’s employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. APCo also participates in OPEB plans sponsored by AEP to provide health and life insurance benefits for retired employees. APCo is allocated a proportionate share of benefit costs and account for their participation in these plans as multiple-employer plans. See Note 8 -Benefit Plans for additional information including significant accounting policies associated with the plans.
Investments Held in Trust for Future Liabilities
AEP has several trust funds with significant investments intended to provide for future payments of pension and OPEB benefits. All of the trust funds’ investments are diversified and managed in compliance with all laws and regulations. The investment strategy for the trust funds is to use a diversified portfolio of investments to achieve an acceptable rate of return while managing the investment risk of the assets relative to the associated liabilities. To minimize investment risk, the trust funds are broadly diversified among classes of assets, investment strategies and investment managers. Management regularly reviews the actual asset allocations and periodically rebalances the investments to targeted allocations when appropriate. Investment policies and guidelines allow investment managers in approved strategies to use financial derivatives to obtain or manage market exposures and to hedge assets and liabilities. The investments are reported at fair value under the “Fair Value Measurements and Disclosures” accounting guidance.
Benefit Plans
All benefit plan assets are invested in accordance with each plan’s investment policy. The investment policy outlines the investment objectives, strategies and target asset allocations by plan.
The investment philosophies for AEP’s benefit plans support the allocation of assets to minimize risks and optimize net returns. Strategies used include:
Maintaining a long-term investment horizon. Diversifying assets to help control volatility of returns at acceptable levels. Managing fees, transaction costs and tax liabilities to maximize investment earnings. Using active management of investments where appropriate risk/return opportunities exist. Keeping portfolio structure style-neutral to limit volatility compared to applicable benchmarks. Using alternative asset classes such as real estate and private equity to maximize return and provide additional portfolio diversification.
FERC FORM NO. 1 (ED. 12-88) Page 123.16 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
The objective of the investment policy for the pension fund is to maintain the funded status of the plan while providing for growth in the plan assets to offset the growth in the plan liabilities. The current target asset allocations are as follows: Pension Plan Assets Target Equity 25 % Fixed Income 59 % Other Investments 15 % Cash and Cash Equivalents 1 %
OPEB Plans Assets Target Equity 49 % Fixed Income 49 % Cash and Cash Equivalents 2 %
The investment policy for each benefit plan contains various investment limitations. The investment policies establish concentration limits for securities and prohibit the purchase of securities issued by AEP (with the exception of proportionate and immaterial holdings of AEP securities in passive index strategies or certain commingled funds). However, the investment policies do not preclude the benefit trust funds from receiving contributions in the form of AEP securities, provided that the AEP securities acquired by each plan may not exceed the limitations imposed by law.
For equity investments, the concentration limits are generally as follows:
No security in excess of 5% of all equities. Cash equivalents must be less than 10% of an investment manager’s equity portfolio. No individual stock may be more than 10% and 7% for pension and OPEB investments, respectively, of each manager’s equity portfolio. No securities may be bought or sold on margin or other use of leverage.
For fixed income investments, each investment manager’s portfolio is compared to investment grade, diversified long and intermediate benchmark indices.
A portion of the pension assets is invested in real estate funds to provide diversification, add return and hedge against inflation. Real estate properties are illiquid, difficult to value and not actively traded. The pension plan uses external real estate investment managers to invest in commingled funds that hold real estate properties. To mitigate investment risk in the real estate portfolio, commingled real estate funds are used to ensure that holdings are diversified by region, property type and risk classification. Real estate holdings include core, value-added and opportunistic classifications.
A portion of the pension assets is invested in private equity. Private equity investments add return and provide diversification and typically require a long-term time horizon to evaluate investment performance. Private equity
FERC FORM NO. 1 (ED. 12-88) Page 123.17 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) is classified as an alternative investment because it is illiquid, difficult to value and not actively traded. The pension plan uses limited partnerships to invest across the private equity investment spectrum. The private equity holdings are with multiple general partners who help monitor the investments and provide investment selection expertise. The holdings are currently comprised of venture capital, buyout and hybrid debt and equity investments.
AEP participates in a securities lending program with BNY Mellon to provide incremental income on idle assets and to provide income to offset custody fees and other administrative expenses. AEP lends securities to borrowers approved by BNY Mellon in exchange for collateral. All loans are collateralized by at least 102% of the loaned asset’s market value and the collateral is invested. The difference between the rebate owed to the borrower and the collateral rate of return determines the earnings on the loaned security. The securities lending program’s objective is to provide modest incremental income with a limited increase in risk. As of December 31, 2020 and 2019, the fair value of securities on loan as part of the program was $177 million and $246 million, respectively. Cash and securities obtained as collateral exceeded the fair value of the securities loaned as of December 31, 2020 and 2019.
Trust owned life insurance (TOLI) underwritten by The Prudential Insurance Company is held in the OPEB plan trusts. The strategy for holding life insurance contracts in the taxable Voluntary Employees’ Beneficiary Association trust is to minimize taxes paid on the asset growth in the trust. Earnings on plan assets are tax-deferred within the TOLI contract and can be tax-free if held until claims are paid. Life insurance proceeds remain in the trust and are used to fund future retiree medical benefit liabilities. With consideration to other investments held in the trust, the cash value of the TOLI contracts is invested in two diversified funds. A portion is invested in a commingled fund with underlying investments in stocks that are actively traded on major international equity exchanges. The other portion of the TOLI cash value is invested in a diversified, commingled fixed income fund with underlying investments in government bonds, corporate bonds and asset-backed securities.
Cash and cash equivalents are held in each trust to provide liquidity and meet short-term cash needs. Cash equivalent funds are used to provide diversification and preserve principal. The underlying holdings in the cash funds are investment grade money market instruments including commercial paper, certificates of deposit, treasury bills and other types of investment grade short-term debt securities. The cash funds are valued each business day and provide daily liquidity.
Comprehensive Income (Loss)
Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from non-owner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners.
FERC FORM NO. 1 (ED. 12-88) Page 123.18 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
COVID-19
In March 2020, COVID-19 was declared a pandemic by the World Health Organization and the Centers for Disease Control and Prevention. Its rapid spread around the world and throughout the United States prompted many countries, including the United States, to institute restrictions on travel, public gatherings and certain business operations. These restrictions significantly disrupted economic activity in APCo’s service territory and reduced demand for energy, particularly from commercial and industrial customers in 2020. APCo has taken steps to mitigate the potential risks to customers, suppliers and employees posed by the spread of COVID-19.
As of December 31, 2020 and through the date of this report, APCo assessed certain accounting matters that require consideration of forecasted financial information, including, but not limited to, the allowance for credit losses and the carrying value of long-lived assets. While there were not any impairments or significant increases in credit allowances resulting from these assessments for the year ended December 31, 2020, the ultimate impact of COVID-19 also depends on factors beyond management’s knowledge or control, including the duration and severity of this outbreak as well as third-party actions taken to contain its spread and mitigate its public health effects. Therefore, management cannot estimate the potential future impact to financial position, results of operations and cash flows, but the impacts could be material.
Subsequent Events
Management has evaluated the impact of events occurring after December 31, 2020 through February 25, 2021, the date that AEP’s Form 10-K was issued, and has updated such evaluation for disclosure purposes through April 13, 2021 . These financial statements include all necessary adjustments and disclosures resulting from these evaluations.
FERC FORM NO. 1 (ED. 12-88) Page 123.19 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
2. NEW ACCOUNTING STANDARDS
During the FASB’s standard-setting process and upon issuance of final standards, management reviews the new accounting literature to determine its relevance, if any, to APCo’s business. The following standards will impact the financial statements.
ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13)
In June 2016, the FASB issued ASU 2016-13 requiring the recognition of an allowance for expected credit losses for financial instruments within its scope. Examples of financial instruments that are in scope include trade receivables, certain financial guarantees and held-to-maturity debt securities. The allowance for expected credit losses should be based on historical information, current conditions and reasonable and supportable forecasts. Entities are required to evaluate, and if necessary, recognize expected credit losses at the inception or initial acquisition of a financial instrument (or pool of financial instruments that share similar risk characteristics) subject to ASU 2016-13, and subsequently as of each reporting date. The new standard also revises the other-than-temporary impairment model for available-for-sale debt securities.
New standard implementation activities included: (a) the identification and evaluation of the population of financial instruments within the AEP system that are subject to the new standard, (b) the development of supporting valuation models to also contemplate appropriate metrics for current and supportable forecasted information and (c) the development of disclosures to comply with the requirements of ASU 2016-13. As required by ASU 2016-13, the financial instruments subject to the new standard were evaluated on a pool-basis to the extent such financial instruments shared similar risk characteristics.
Management adopted ASU 2016-13 and its related implementation guidance effective January 1, 2020, by means of a cumulative-effect adjustment to the balance sheets. The adoption of the new standard did not have a material impact to financial position and had no impact on the results of operations or cash flows. Additionally, the adoption of the new standard did not result in any changes to current accounting systems.
ASU 2020-04 “Reference Rate Reform: Facilitation of the Effects of Reference Rate Reform on Financial Reporting” (ASU 2020-04)
In March 2020, the FASB issued ASU 2020-04 providing guidance to ease the potential burden in accounting for Reference Rate Reform on financial reporting. The new standard is elective and applies to all entities, subject to meeting certain criteria, that have contracts, hedging relationships, and other transactions that reference the London Interbank Offered Rate (LIBOR) or another reference rate expected to be discontinued because of Reference Rate Reform. The new standard establishes a general contract modification principle that entities can apply in other areas that may be affected by Reference Rate Reform and certain elective hedge accounting expedients. Under the new standard, an entity may make a one-time election to sell or to transfer to the available-for-sale or trading classifications (or both sell and transfer), debt securities that both reference an affected rate, and were classified as held-to-maturity before January 1, 2020.
FERC FORM NO. 1 (ED. 12-88) Page 123.20 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
Management adopted ASU 2020-04 and its related implementation guidance effective January 1, 2021. There was no impact to results of operations, financial position or cash flows upon initial adoption. Management is applying the accounting guidance as relevant contract and hedge accounting relationship modifications are made during the course of the reference rate reform transition period, which ends on December 31, 2022. The guidance generally allows for contract modifications solely related to the replacement of the reference rate to be accounted for as a continuation of the existing contract instead of as an extinguishment of the contract, and would therefore, not trigger certain accounting impacts that would otherwise be required. It also allows entities to change certain critical terms of existing hedge accounting relationships that are affected by reference rate reform. These changes would not require de-designating the hedge accounting relationship.
FERC FORM NO. 1 (ED. 12-88) Page 123.21 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
3. COMPREHENSIVE INCOME
Presentation of Comprehensive Income
The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the years ended December 31, 2020 and 2019. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 8 - Benefit Plans for additional information.
Pension and OPEB Amortization Changes in Cash Flow Hedge – of Deferred Funded For the Year Ended December 31, 2020 Interest Rate Costs Status Total
(in millions) Balance in AOCI as of December 31, 2019 $ 0.9 $ 9.2 $ (5.1) $ 5.0 Change in Fair Value Recognized in AOCI (0.7) — 8.4 7.7 Amount of (Gain) Loss Reclassified from AOCI Interest on Long-Term Debt (a) (1.3) — — (1.3) Amortization of Prior Service Cost (Credit) — (5.3) — (5.3) Amortization of Actuarial (Gains) Losses — 0.5 — 0.5 Reclassifications from AOCI, before Income Tax (Expense) Benefit (1.3) (4.8) — (6.1) Income Tax (Expense) Benefit (0.3) (1.0) — (1.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (1.0) (3.8) — (4.8) Net Current Period Other Comprehensive Income (Loss) (1.7) (3.8) 8.4 2.9
Balance in AOCI as of December 31, 2020 $ (0.8) $ 5.4 $ 3.3 $ 7.9
FERC FORM NO. 1 (ED. 12-88) Page 123.22 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
Pension and OPEB
Amortization Changes in Cash Flow Hedges - of Deferred Funded For the Year Ended December 31, 2019 Interest Rate Costs Status Total
(in millions) Balance in AOCI as of December 31, 2018 $ 1.8 $ 11.7 $ (18.5) $ (5.0)
Change in Fair Value Recognized in AOCI — — 13.4 13.4 Amount of (Gain) Loss Reclassified from AOCI Interest on Long-Term Debt (a) (1.1) — — (1.1) Amortization of Prior Service Cost (Credit) — (5.3) — (5.3) Amortization of Actuarial (Gains) Losses — 2.1 — 2.1 Reclassifications from AOCI, before Income Tax (Expense) Benefit (1.1) (3.2) — (4.3) Income Tax (Expense) Benefit (0.2) (0.7) — (0.9)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit (0.9) (2.5) — (3.4) Net Current Period Other Comprehensive Income (Loss) (0.9) (2.5) 13.4 10.0
Balance in AOCI as of December 31, 2019 $ 0.9 $ 9.2 $ (5.1) $ 5.0 (a) Amounts reclassified to the referenced line item on the statements of income.
FERC FORM NO. 1 (ED. 12-88) Page 123.23 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
4. RATE MATTERS
APCo is involved in rate and regulatory proceedings at the FERC and the Virginia SCC and the WVPSC. Rate matters can have a material impact on net income, cash flows and possibly financial condition APCo’s recent significant rate orders and pending rate filings are addressed in this note.
COVID-19 Pandemic
During the first quarter of 2020, AEP’s electric operating companies informed both retail customers and state regulators that disconnections for non-payment were temporarily suspended. Shortly thereafter, APCo’s state regulators also imposed temporary moratoria on customary disconnection practices. During the third and the fourth quarters of 2020, the Virginia SCC and the WVPSC began lifting restrictions on disconnects. As of December 31, 2020, APCo had resumed disconnections in its regulated jurisdictions with the exception of Virginia. APCo continues to work with regulators and stakeholders in Virginia and management currently anticipates resuming customary disconnection practices in the first half of 2021. However, this timing could change if there is new legislation or other regulatory directives issued in the future. Continuing adverse economic conditions may result in the inability of customers to pay for electric service, which could affect revenue recognition and the collectability of accounts receivable. APCo has worked with the Virginia SCC and the WVPSC to achieve deferral authority for incremental expenses incurred due to COVID-19. All of APCo’s regulated jurisdictions have issued COVID-19 orders, granting deferral authority for incremental COVID-19 expenses. If any costs related to COVID-19 are not recoverable, it could reduce future net income and cash flows and impact financial condition.
2017-2019 Virginia Triennial Review
Amendments to Virginia law impacting investor-owned utilities were enacted, effective July 1, 2018, that required APCo to file a generation and distribution base rate case by March 31, 2020 using 2017, 2018 and 2019 earnings test years (triennial review). Triennial reviews are subject to an earnings test, which provides that 70% of any earnings in excess of 70 basis points above APCo’s Virginia SCC authorized ROE would be refunded to customers. In such case, the Virginia SCC could also lower APCo’s Virginia retail base rates on a prospective basis. In November 2018, the Virginia SCC authorized a ROE of 9.42% applicable to APCo base rate earnings for the 2017-2019 triennial period.
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Virginia law provides that costs associated with asset impairments of retired coal generation assets, or automated meters, or both, which a utility records as an expense, shall be attributed to the test periods under review in a triennial review proceeding, and be deemed recovered. In 2015, APCo retired the Sporn Plant, the Kanawha River Plant, the Glen Lyn Plant, Clinch River Unit 3 and the coal portions of Clinch River Units 1 and 2 (collectively, the retired coal-fired generation assets). The net book value of the Virginia jurisdictional share of these plants was $93 million before cost of removal, including materials and supplies inventory and ARO balances. Based on management’s interpretation of Virginia law and more certainty regarding APCo’s triennial revenues, expenses and resulting earnings upon reaching the end of the three-year review period, APCo recorded a pretax expense of $93 million related to its previously retired coal-fired generation assets in December 2019. As a result, management deemed these costs to be substantially recovered by APCo during the triennial review period.
In March 2020, APCo submitted its 2017-2019 Virginia triennial earnings review filing and base rate case with the Virginia SCC as required by state law. APCo requested a $65 million annual increase in base rates based upon a proposed 9.9% ROE. The requested annual increase included $19 million related to depreciation for updated test year end depreciable balances and a proposed increase in APCo’s Virginia depreciation rates and $8 million related to APCo’s calculated shortfall in 2017-2019 Virginia earnings. Inclusive of the Virginia jurisdictional share of the $93 million expense associated with APCo’s retired coal-fired generation assets, APCo calculated its 2017-2019 Virginia earnings for the triennial period to be below the authorized ROE range.
APCo is currently in the process of retiring and replacing its Virginia jurisdictional Automated Meter Reading (AMR) meters with AMI meters. As of December 31, 2020 and 2019, APCo had approximately $35 million and $51 million of Virginia jurisdictional AMR meters as well as $73 million and $75 million of Virginia jurisdictional AMI meters recorded on its balance sheets. APCo pursued full recovery of these assets through its Virginia depreciation rates as discussed above.
In November 2020, the Virginia SCC issued an order concluding that APCo earned above its authorized ROE but within its ROE band for the 2017-2019 period, resulting in no refund to customers and no change to APCo base rates on a prospective basis. The Virginia SCC approved a prospective 9.2% ROE for APCo's 2020-2022 triennial review period with the continuation of a 140 basis point band (8.5% bottom, 9.2% midpoint, 9.9% top). This 9.2% authorized ROE will also be applied to certain APCo rate adjustment clauses. APCo’s earnings for the 2020-2022 triennial review will continue to be subject to an earnings test, which provides that 70% of any earnings in excess of 70 basis points above APCo’s Virginia SCC authorized ROE would be refunded to customers. Conversely, as defined by Virginia law, APCo is also eligible to defer for future recovery certain environmental and major storm operation and maintenance expenses up to the bottom of APCo’s authorized Virginia 2020-2022 earnings ROE band. The Virginia SCC also disagreed with APCo’s treatment of the retired coal-fired generation assets for regulatory purposes, and instead adopted the Virginia SCC Staff’s recommendation to treat the remaining unrecovered costs of the retired coal-fired generation assets as a regulatory asset to be amortized over 10 years as of the June 2015 retirement date. The Virginia SCC’s adoption of the Staff’s recommended regulatory treatment of the coal-fired generation assets resulted in a net $40 million increase to APCo’s 2020 pretax income. In addition, the Virginia SCC’s order also included: (a) implementation of the Staff-modified APCo 2017 depreciation study effective January 1, 2018 and (b) implementation of the Staff-
FERC FORM NO. 1 (ED. 12-88) Page 123.25 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) modified APCo 2019 depreciation study effective January 1, 2020. The adoption of these depreciation studies resulted in an approximate $47 million reduction to APCo’s 2020 pretax income comprised of a $44 million reduction to revenues for amounts recognized in advance of the recording of depreciation expense for the periods January 2018 through October 2020 and a $3 million increase in depreciation expense for the periods November and December 2020. A corresponding regulatory liability was recorded for the $44 million reduction to revenues. The Virginia SCC’s approval of APCo’s 2019 depreciation study included the ongoing depreciation and recovery of APCo’s Virginia AMI/AMR meter balances. In November 2020, APCo filed a notice of appeal with the Virginia Supreme Court.
In December 2020, an intervenor filed a petition at the Virginia SCC requesting reconsideration of: (a) the failure of the Virginia SCC to apply a threshold earnings test to the approved regulatory asset for APCo’s closed coal-fired generation assets, (b) the Virginia SCC’s use of a 2011 benchmark study to measure the replacement value of capacity for purposes of APCo’s 2017 – 2019 earnings test and (c) the reasonableness and prudency of APCo’s investments in AMI meters.
In December 2020, APCo filed a petition at the Virginia SCC requesting reconsideration of: (a) certain issues related to APCo’s going-forward rates and (b) the Virginia SCC’s decision to deny APCo tariff changes that align rates with underlying costs. For APCo’s going-forward rates, APCo requested that the Virginia SCC clarify its final order and whether APCo’s current rates will allow it to earn a fair return. If the Virginia SCC’s order did conclude on APCo’s ability to earn a fair return through existing base rates, APCo further requested that the Virginia SCC clarify whether it has the authority to also permit an increase in base rates. If the Virginia SCC did not conclude on APCo’s ability to earn a fair return, APCo requested the Virginia SCC provide such a conclusion. In January 2021, as requested by the Virginia SCC, APCo filed briefs related to the petition for reconsideration.
If the Virginia SCC issues an unfavorable ruling related to the intervenor petition, it could reduce future net income and cash flows and impact financial condition.
West Virginia ENEC and Vegetation Management Riders
In June 2020, the WVPSC issued an order directing APCo and WPCo to increase rider rates relating to ENEC and vegetation management by a combined $101 million ($81 million related to APCo) over twelve months beginning September 2020. This increase will be partially offset by a refund of $38 million ($31 million related to APCo) of Excess ADIT that is not subject to normalization requirements over ten months beginning September 2020. These transactions will result in no overall impact to net income.
FERC FORM NO. 1 (ED. 12-88) Page 123.26 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
AFUDC Waiver
In June 2020, FERC granted a temporary waiver providing utilities the option to elect to modify the existing AFUDC rate calculations in response to the COVID-19 pandemic. As a result of the waiver, the AFUDC formula for the 12-month period starting with March 2020 may be calculated using the simple average of the actual historical short-term debt balances for 2019, instead of current period short-term balances. All other aspects of the AFUDC formula remained unchanged. AEP subsidiaries including certain APCo Subsidiaries elected to apply the waiver in July 2020. The impact upon election was immaterial on APCo’s financial statements. In February 2021, FERC issued an order extending the waiver through September 2021.
FERC FORM NO. 1 (ED. 12-88) Page 123.27 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
5. EFFECTS OF REGULATION
Regulatory assets and liabilities are comprised of the following items:
Remaining December 31, Recovery Regulatory Assets: 2020 2019 Period (in millions)
Regulatory assets pending final regulatory approval:
Regulatory Assets Currently Earning a Return COVID-19 - Virginia $ 3.7 $ — Plant Retirement Costs – Materials and Supplies — 0.5 Total Regulatory Assets Currently Earning a Return 3.7 0.5 Regulatory Assets Currently Not Earning a Return 29.8 Plant Retirement Costs - Asset Retirement Obligation Costs 30.1 Environmental Expense Deferral - Virginia 9.3 — COVID-19 - West Virginia 1.5 — Other Regulatory Assets Pending Final Regulatory Approval 3.5 — Total Regulatory Assets Currently Not Earning a Return 44.1 30.1
Total Regulatory Assets Pending Final Regulatory Approval 47.8 30.6
Regulatory assets approved for recovery:
Regulatory Assets Currently Earning a Return Plant Retirement Costs – Unrecovered Plant –Virginia 40.0 — 23 years Under-recovered Fuel Costs - Virginia 3.3 36.8 Other Regulatory Assets Approved for Recovery 1.0 0.6 various Total Regulatory Assets Currently Earning a Return 44.3 37.4 Regulatory Assets Currently Not Earning a Return Income Tax Assets 356.4 362.4 Plant Retirement Costs - Asset Retirement Obligation Costs 198.8 — 15 years Pension and OPEB Funded Status 114.4 160.8 12 years Vegetation Management Program - West Virginia 45.4 43.6 2 years Virginia Transmission Rate Adjustment Clause 18.8 — 2 years Peak Demand Reduction/Energy Efficiency 16.8 19.5 6 years Postemployment Benefits 13.5 15.9 3 years Under-recovered Fuel Costs (a) 2.0 10.7 1 year PJM Annual Formula Rate True-up 12.7 — 2 years Other Regulatory Assets Approved for Recovery 12.7 14.4 various Total Regulatory Assets Currently Not Earning a Return 791.5 627.3
Total Regulatory Assets Approved for Recovery 835.8 664.7
Total FERC Account 182.3 Regulatory Assets $ 883.6 $ 695.3
(a) December 31, 2020 amount includes Virginia and West Virginia jurisdictions. December 31, 2019 amount includes West Virginia jurisdiction.
FERC FORM NO. 1 (ED. 12-88) Page 123.28 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
Remaining December 31, Refund Regulatory Liabilities: 2020 2019 Period (in millions)
Regulatory liabilities approved for payment:
Regulatory Liabilities Currently Not Paying a Return PJM Transmission Enhancement Refund 16.3 19.5 5 years Virginia Transmission Rate Adjustment Clause — 28.1 Other Regulatory Liabilities Approved for Payment 12.4 23.0 various Total Regulatory Liabilities Currently Not Paying a Return 28.7 70.6 Income Tax Related Regulatory Liabilities (a) Excess ADIT Associated with Certain Depreciable Property 690.0 718.9 (b) Excess ADIT that is Not Subject to Rate Normalization Requirements 139.1 210.7 8 years Income Taxes Subject to Flow Through — 0.1 24 years Total Income Tax Related Regulatory Liabilities 829.1 929.7
Total Regulatory Liabilities Approved for Payment 857.8 1,000.3
Total FERC 254 Account Regulatory Liabilities $ 857.8 $ 1,000.3
(a) This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform. The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base. (b) Refunded using ARAM.
FERC FORM NO. 1 (ED. 12-88) Page 123.29 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
6. COMMITMENTS, GUARANTEES AND CONTINGENCIES
APCo is subject to certain claims and legal actions arising in the ordinary course of business. In addition, APCo’s business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates.
For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements.
COMMITMENTS
APCo has substantial commitments for fuel, energy and capacity contracts as part of the normal course of business. Certain contracts contain penalty provisions for early termination.
In accordance with the accounting guidance for “Commitments”, the following table summarizes APCo’s actual contractual commitments as of December 31, 2020:
Less Than After Contractual Commitments 1 Year 2-3 Years 4-5 Years 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 362.8 $ 217.6 $ 11.6 $ 16.3 $ 608.3 Energy and Capacity Purchase Contracts 35.5 72.5 73.9 230.2 412.1 Total $ 398.3 $ 290.1 $ 85.5 $ 246.5 $ 1,020.4
(a) Represents contractual commitments to purchase coal, natural gas and other consumables as fuel for electric generation along with related transportation of the fuel.
FERC FORM NO. 1 (ED. 12-88) Page 123.30 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
GUARANTEES
Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third-parties unless specified below.
Indemnifications and Other Guarantees
Contracts
APCo enters into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of December 31, 2020, there were no material liabilities recorded for any indemnifications.
AEPSC conducts power purchase-and-sale activity on behalf of APCo, I&M, KPCo and WPCo, who are jointly and severally liable for activity conducted on their behalf.
Lease Obligations
APCo leases equipment under master lease agreements. See “Master Lease Agreements” section of Note 13 for additional information.
ENVIRONMENTAL CONTINGENCIES
The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation
By-products from the generation of electricity include materials such as ash, slag and sludge. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and non-hazardous materials. APCo currently incurs costs to dispose of these substances safely.
Superfund addresses clean-up of hazardous substances that are released to the environment. The Federal EPA administers the clean-up programs. Several states enacted similar laws. As of December 31, 2020, APCo was named as a Potentially Responsible Party (PRP) for one site by the Federal EPA for which alleged liability is unresolved. There are 11 additional sites for which APCo received information requests which could lead to PRP designation. In those instances where a PRP or defendant has been named, disposal or recycling activities were in accordance with the then-applicable laws and regulations. Superfund does not recognize compliance as a defense,
FERC FORM NO. 1 (ED. 12-88) Page 123.31 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued) but imposes strict liability on parties who fall within its broad statutory categories. Liability has been resolved for a number of sites with no significant effect on net income.
Management evaluates the potential liability for each Superfund site separately, but several general statements can be made about potential future liability. Allegations that materials were disposed at a particular site are often unsubstantiated and the quantity of materials deposited at a site can be small and often non-hazardous. Although Superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises. As of December 31, 2020, management’s estimates do not anticipate material clean-up costs for identified Superfund sites.
Virginia House Bill 443
In March 2020, Virginia’s Governor signed House Bill 443 (HB 443), effective July 2020, requiring APCo to close certain ash disposal units at the retired Glen Lyn Station by removal of all coal combustion material. As a result, in June 2020, APCo recorded a $199 million revision to increase estimated Glen Lyn Station ash disposal ARO liabilities. The closure is required to be completed within 15 years from the start of the excavation process. HB 443 provides for the recovery of all costs associated with closure by removal through the Virginia environmental rate adjustment clause (E-RAC). APCo is permitted to record carrying costs on the unrecovered balance of closure costs at a weighted-average cost of capital approved by the Virginia SCC. HB 443 also allows any closure costs allocated to non-Virginia jurisdictional customers, but not collected from such non-Virginia jurisdictional customers, to be recovered from Virginia jurisdictional customers through the E-RAC. APCo will submit filings with the Virginia SCC and the WVPSC requesting recovery of the respective Virginia and West Virginia jurisdictional shares of these Glen Lyn Station ARO costs. As of December 31, 2020, APCo has not yet incurred any incremental costs associated with the removal of coal combustion material at the Glen Lyn Station.
OPERATIONAL CONTINGENCIES
Insurance and Potential Losses
APCo maintains insurance coverage normal and customary for electric utilities, subject to various deductibles. APCo also maintains property and casualty insurance that may cover certain physical damage or third-party injuries caused by cyber security incidents. Insurance coverage includes all risks of physical loss or damage to nonnuclear assets, subject to insurance policy conditions and exclusions. Covered property generally includes power plants, substations, facilities and inventories. Excluded property generally includes transmission and distribution lines, poles and towers. The insurance programs also generally provide coverage against loss arising from certain claims made by third-parties and are in excess of retentions absorbed by APCo. Coverage is generally provided by a combination of the protected cell of EIS and/or various industry mutual and/or commercial insurance carriers.
FERC FORM NO. 1 (ED. 12-88) Page 123.32 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to a cyber-security incident. Future losses or liabilities, if they occur, which are not completely insured, unless recovered from customers, could reduce future net income and cash flows and impact financial condition.
7. IMPAIRMENTS
Virginia Jurisdictional Book Value of Retired Coal-Fired Plants
In December 2019, based on management’s interpretation of Virginia law and more certainty regarding APCo’s triennial revenues, expenses and resulting earnings upon reaching the end of the three-year review period, APCo recorded a pretax expense of $93 million in Asset Impairments and Other Related Charges on the statements of income related to its previously retired coal-fired generation. As a result, management deemed these costs to be substantially recovered by APCo during the triennial review period. See “2017-2019 Virginia Triennial Review” section of Note 4 for additional information.
FERC FORM NO. 1 (ED. 12-88) Page 123.33 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
8. BENEFIT PLANS
For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Fair Value Measurements of Assets and Liabilities” and “Investments Held in Trust for Future Liabilities” sections of Note 1.
APCo participates in an AEP sponsored qualified pension plan and an unfunded nonqualified pension plan. Substantially all employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. APCo also participates in OPEB plans sponsored by AEP to provide health and life insurance benefits for retired employees.
APCo recognizes the funded status associated with defined benefit pension and OPEB plans on its balance sheets. Disclosures about the plans are required by the “Compensation - Retirement Benefits” accounting guidance. APCo recognizes an asset for a plan’s overfunded status or a liability for a plan’s underfunded status and recognizes, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. APCo records a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.
Actuarial Assumptions for Benefit Obligations
The weighted-average assumptions used in the measurement of benefit obligations are shown in the following table: Pension Plans OPEB December 31, Assumptions 2020 2019 2020 2019 Discount Rate 2.50 % 3.25 % 2.55 % 3.30 % Interest Crediting Rate 4.00 % 4.00 % NA NA Rate of Compensation Increase 4.85 % (a) 4.80 % (a) NA NA
(a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees. NA Not applicable.
A duration-based method is used to determine the discount rate for the plans. A hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability. The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan.
FERC 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) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
For 2020, the rate of compensation increase assumed varies with the age of the employee, ranging from 3% per year to 11.5% per year, with the average increase shown in the table above.
Actuarial Assumptions for Net Periodic Benefit Costs
The weighted-average assumptions used in the measurement of benefit costs are shown in the following table: Pension Plans OPEB Years Ended December 31, Assumptions 2020 2019 2020 2019 Discount Rate 3.25 % 4.30 % 3.30 % 4.30 % Interest Crediting Rate 4.00 % 4.00 % NA NA Expected Return on Plan Assets 5.75 % 6.25 % 5.50 % 6.25 % Rate of Compensation Increase 4.85 % (a) 4.75 % (a) NA NA
(a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees. NA Not applicable.
The expected return on plan assets was determined by evaluating historical returns, the current investment climate (yield on fixed income securities and other recent investment market indicators), rate of inflation, third party forecasts and current prospects for economic growth.
The health care trend rate assumptions used for OPEB plans measurement purposes are shown below:
December 31, Health Care Trend Rates 2020 2019 Initial 6.50 % 6.00 % Ultimate 4.50 % 4.50 % Year Ultimate Reached 2029 2026
Significant Concentrations of Risk within Plan Assets
In addition to establishing the target asset allocation of plan assets, the investment policy also places restrictions on securities to limit significant concentrations within plan assets. The investment policy establishes guidelines that govern maximum market exposure, security restrictions, prohibited asset classes, prohibited types of transactions, minimum credit quality, average portfolio credit quality, portfolio duration and concentration limits. The guidelines were established to mitigate the risk of loss due to significant concentrations in any investment. Management monitors the plans to control security diversification and ensure compliance with the investment policy. As of December 31, 2020, the assets were invested in compliance with all investment limits. See “Investments Held in Trust for Future Liabilities” section of Note 1 for limit details.
FERC FORM NO. 1 (ED. 12-88) Page 123.35 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
Benefit Plan Obligations, Plan Assets, Funded Status and Amounts Recognized on the Balance Sheets
For the year ended December 31, 2020, the pension plans had an actuarial loss primarily due to a decrease in the discount rate, partially offset by a decrease in the assumed rate used to convert account balances to annuities. For the year ended December 31, 2020, the OPEB plans had an actuarial loss primarily due to a decrease in the discount rate and an update to the health care trend assumption, partially offset by updated projected per capita claims costs due to rate negotiations for Medicare advantage premium rates. For the year ended December 31, 2019, the pension plans had an actuarial loss due to a decrease in the discount rate, partially offset by updates to the mortality table. For the year ended December 31, 2019, the OPEB plans had an actuarial loss due to a decrease in the discount rate and an update to the persistency assumption, partially offset by an update to the projected per capita cost assumption as well as savings resulting from legislation signed in December 2019 which eliminated two Affordable Care Act taxes. The following tables provides a reconciliation of the changes in the plans’ benefit obligations, fair value of plan assets, funded status and the presentation on the balance sheets. The benefit obligation for the defined benefit pension and OPEB plans are the projected benefit obligation and the accumulated benefit obligation, respectively.
Pension Plans OPEB 2020 2019 2020 2019 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 644.9 $ 600.6 $ 178.7 $ 175.7 Service Cost 10.5 9.4 1.1 1.0 Interest Cost 20.2 25.1 5.8 7.5 Actuarial Loss 39.8 53.0 4.7 9.0 Plan Amendments — — (1.8) (1.7) Benefit Payments (46.9) (43.2) (21.1) (18.6) Participant Contributions — — 6.3 5.8 Benefit Obligation as of December 31, $ 668.5 $ 644.9 $ 173.7 $ 178.7
Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 632.0 $ 588.8 $ 270.6 $ 237.9 Actual Gain on Plan Assets 103.6 86.4 36.8 45.5 Company Contributions 7.0 — — — Participant Contributions — — 6.3 5.8 Benefit Payments (46.9) (43.2) (21.1) (18.6) Fair Value of Plan Assets as of December 31, $ 695.7 $ 632.0 $ 292.6 $ 270.6
Funded (Underfunded) Status as of December 31, $ 27.2 $ (12.9) $ 118.9 $ 91.9
FERC FORM NO. 1 (ED. 12-88) Page 123.36 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
Amounts Recognized on the Balance Sheets Pension Plans OPEB December 31, 2020 2019 2020 2019 (in millions) Special Funds - Prepaid Benefit Costs $ 27.7 $ — $ 118.9 $ 91.9 Accumulated Provision for Pensions and Benefits - Long-term Benefit Liability (0.5) (12.9) — — Funded (Underfunded) Status $ 27.2 $ (12.9) $ 118.9 $ 91.9
Amounts Included in Regulatory Assets, Deferred Income Taxes and AOCI
The following table shows the components of the plans included in Regulatory Assets, Deferred Income Taxes and AOCI:
Pension Plans OPEB December 31, 2020 2019 2020 2019 Components (in millions) Net Actuarial Loss $ 124.7 $ 166.3 $ 11.5 $ 30.0 Prior Service Credit — — (33.2) (41.5)
Recorded as Regulatory Assets $ 124.7 $ 166.3 $ (10.3) $ (5.5) Deferred Income Taxes — — (2.4) (1.3) Net of Tax AOCI — — (9.0) (4.7)
Components of the change in amounts included in Regulatory Assets, Deferred Income Taxes and AOCI were as follows:
Pension Plans OPEB 2020 2019 2020 2019 Components (in millions) Actuarial (Gain) Loss During the Year $ (30.4) $ 3.7 $ (17.6) $ (22.3) Amortization of Actuarial Loss (11.2) (7.0) (0.9) (3.5) Prior Service Credit — — (1.9) (1.2) Amortization of Prior Service Credit — — 10.2 10.1 Change for the Year Ended December 31, $ (41.6) $ (3.3) $ (10.2) $ (16.9)
FERC FORM NO. 1 (ED. 12-88) Page 123.37 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
Determination of Pension Expense
The determination of pension expense or income is based on a market-related valuation of assets which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return.
Pension and OPEB Assets
The fair value tables within Pension and OPEB Assets present the classification of assets for AEP within the fair value hierarchy. All Level 1, 2, 3 and Other amounts can be allocated to APCo using the percentages in the table below: Pension Plan OPEB December 31, 2020 2019 2020 2019 12.5 % 12.6 % 15.0 % 15.2 %
FERC FORM NO. 1 (ED. 12-88) Page 123.38 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2020:
Year End Asset Class Level 1 Level 2 Level 3 Other Total Allocation (in millions) Equities (a): Domestic $ 542.3 $ — $ — $ — $ 542.3 9.7 % International 676.3 — — — 676.3 12.2 % Common Collective Trusts (c) — — — 650.0 650.0 11.7 % Subtotal - Equities 1,218.6 — — 650.0 1,868.6 33.6 %
Fixed Income (a): United States Government and Agency Securities (1.4) 1,134.1 — — 1,132.7 20.4 % Corporate Debt — 1,425.0 — — 1,425.0 25.6 % Foreign Debt — 214.0 — — 214.0 3.9 % State and Local Government — 56.0 — — 56.0 1.0 % Other - Asset Backed — 0.8 — — 0.8 — % Subtotal - Fixed Income (1.4) 2,829.9 — — 2,828.5 50.9 %
Infrastructure (c) — — — 91.1 91.1 1.6 % Real Estate (c) — — — 231.6 231.6 4.2 % Alternative Investments (c) — — — 431.8 431.8 7.8 % Cash and Cash Equivalents (c) — 49.3 — 58.2 107.5 1.9 % Other - Pending Transactions and Accrued Income (b) — — — (2.5) (2.5) — %
Total $ 1,217.2 $ 2,879.2 $ — $ 1,460.2 $ 5,556.6 100.0 %
(a) Includes investment securities loaned to borrowers under the securities lending program. See the “Investments Held in Trust for Future Liabilities” section of Note 1 for additional information. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (c) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share.
FERC FORM NO. 1 (ED. 12-88) Page 123.39 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2020: Year End Asset Class Level 1 Level 2 Level 3 Other Total Allocation (in millions) Equities: Domestic $ 399.9 $ — $ — $ — $ 399.9 20.6 % International 290.7 — — — 290.7 14.9 % Common Collective Trusts (b) — — — 264.7 264.7 13.6 % Subtotal - Equities 690.6 — — 264.7 955.3 49.1 %
Fixed Income: Common Collective Trust - Debt (b) — — — 186.4 186.4 9.6 % United States Government and Agency Securities (0.2) 199.7 — — 199.5 10.2 % Corporate Debt — 248.7 — — 248.7 12.8 % Foreign Debt — 34.9 — — 34.9 1.8 % State and Local Government 73.9 13.1 — — 87.0 4.5 % Subtotal - Fixed Income 73.7 496.4 — 186.4 756.5 38.9 %
Trust Owned Life Insurance: International Equities — 64.8 — — 64.8 3.3 % United States Bonds — 135.9 — — 135.9 7.0 % Subtotal - Trust Owned Life Insurance — 200.7 — — 200.7 10.3 %
Cash and Cash Equivalents (b) 26.3 — — 5.7 32.0 1.6 % Other - Pending Transactions and Accrued Income (a) — — — 2.2 2.2 0.1 %
Total $ 790.6 $ 697.1 $ — $ 459.0 $ 1,946.7 100.0 %
(a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (b) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share.
FERC FORM NO. 1 (ED. 12-88) Page 123.40 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2019:
Year End Asset Class Level 1 Level 2 Level 3 Other Total Allocation (in millions) Equities (a): Domestic $ 387.8 $ — $ — $ — $ 387.8 7.8 % International 609.1 — — — 609.1 12.1 % Common Collective Trusts (c) — — — 547.3 547.3 10.9 % Subtotal - Equities 996.9 — — 547.3 1,544.2 30.8 %
Fixed Income (a): United States Government and Agency Securities (5.8) 1,248.6 — — 1,242.8 24.8 % Corporate Debt — 1,143.7 — — 1,143.7 22.8 % Foreign Debt — 211.6 — — 211.6 4.2 % State and Local Government — 55.1 — — 55.1 1.1 % Other - Asset Backed — 3.6 — — 3.6 0.1 % Subtotal - Fixed Income (5.8) 2,662.6 — — 2,656.8 53.0 %
Infrastructure (c) — — — 85.8 85.8 1.7 % Real Estate (c) — — — 239.4 239.4 4.8 % Alternative Investments (c) — — — 448.3 448.3 8.9 % Cash and Cash Equivalents (c) — 24.4 — 37.2 61.6 1.2 % Other - Pending Transactions and Accrued Income (b) — — — (20.7) (20.7) (0.4) %
Total $ 991.1 $ 2,687.0 $ — $ 1,337.3 $ 5,015.4 100.0 %
(a) Includes investment securities loaned to borrowers under the securities lending program. See the “Investments Held in Trust for Future Liabilities” section of Note 1 for additional information. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (c) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share.
FERC FORM NO. 1 (ED. 12-88) Page 123.41 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2019:
Year End Asset Class Level 1 Level 2 Level 3 Other Total Allocation (in millions) Equities: Domestic $ 312.2 $ — $ — $ — $ 312.2 17.5 % International 251.5 — — — 251.5 14.1 % Common Collective Trusts (b) — — — 260.8 260.8 14.7 % Subtotal - Equities 563.7 — — 260.8 824.5 46.3 %
Fixed Income: Common Collective Trust - Debt (b) — — — 177.6 177.6 10.0 % United States Government and Agency Securities (0.1) 214.4 — — 214.3 12.0 % Corporate Debt — 206.7 — — 206.7 11.6 % Foreign Debt — 35.5 — — 35.5 2.0 % State and Local Government 58.8 14.8 — — 73.6 4.1 % Other - Asset Backed — 0.2 — — 0.2 — % Subtotal - Fixed Income 58.7 471.6 — 177.6 707.9 39.7 %
Trust Owned Life Insurance: International Equities — 60.2 — — 60.2 3.4 % United States Bonds — 151.6 — — 151.6 8.5 % Subtotal - Trust Owned Life Insurance — 211.8 — — 211.8 11.9 %
Cash and Cash Equivalents (b) 26.7 — — 6.7 33.4 1.9 % Other - Pending Transactions and Accrued Income (a) — — — 4.2 4.2 0.2 %
Total $ 649.1 $ 683.4 $ — $ 449.3 $ 1,781.8 100.0 %
(a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (b) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share.
FERC FORM NO. 1 (ED. 12-88) Page 123.42 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
Accumulated Benefit Obligation
The accumulated benefit obligation for the pension plans was as follows:
December 31, Accumulated Benefit Obligation 2020 2019 (in millions) Qualified Pension Plan $ 643.5 $ 625.0 Nonqualified Pension Plans 0.2 0.2 Total as of December 31, $ 643.7 $ 625.2
Obligations in Excess of Fair Values
The tables below show the underfunded pension plans that had obligations in excess of plan assets.
Projected Benefit Obligation
December 31, 2020 2019 (in millions) Projected Benefit Obligation $ 0.5 $ 644.9 Fair Value of Plan Assets — 632.0 Underfunded Projected Benefit Obligation $ (0.5) $ (12.9)
Accumulated Benefit Obligation
December 31, 2020 2019 (in millions) Accumulated Benefit Obligation $ 0.2 $ 0.2 Fair Value of Plan Assets — — Underfunded Accumulated Benefit Obligation $ (0.2) $ (0.2)
Estimated Future Benefit Payments and Contributions
APCo expects contributions and payments for the Pension plans of $2 million during 2021. The estimated contributions to the pension trust are at least the minimum amount required by the Employee Retirement Income Security Act and additional discretionary contributions may also be made to maintain the funded status of the plan.
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The table below reflects the total benefits expected to be paid from the plan or from APCo’s assets. The payments include the participants’ contributions to the plan for their share of the cost. Future benefit payments are dependent on the number of employees retiring, whether the retiring employees elect to receive pension benefits as annuities or as lump sum distributions, future integration of the benefit plans with changes to Medicare and other legislation, future levels of interest rates and variances in actuarial results. The estimated payments for pension benefits and OPEB are as follows:
Estimated Payments Pension Plans OPEB (in millions) 2021 $ 44.5 $ 19.2 2022 44.9 19.1 2023 44.9 18.0 2024 45.5 18.8 2025 43.8 18.4 Years 2026 to 2030, in Total 209.0 85.7
Components of Net Periodic Benefit Cost
The following table provides the components of net periodic benefit cost (credit) for the plans:
Pension Plans OPEB Years Ended December 31, 2020 2019 2020 2019 (in millions) Service Cost $ 10.5 $ 9.4 $ 1.1 $ 1.0 Interest Cost 20.2 25.1 5.8 7.5 Expected Return on Plan Assets (33.4) (37.1) (14.5) (14.7) Amortization of Prior Service Credit — — (10.2) (10.1) Amortization of Net Actuarial Loss 11.2 7.0 0.9 3.5 Net Periodic Benefit Cost (Credit) 8.5 4.4 (16.9) (12.8) Capitalized Portion (4.5) (4.0) (0.5) (0.4) Net Periodic Benefit Cost (Credit) Recognized in Expense $ 4.0 $ 0.4 $ (17.4) $ (13.2)
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American Electric Power System Retirement Savings Plan
APCo participates in an AEP sponsored defined contribution retirement savings plan, the American Electric Power System Retirement Savings Plan, for substantially all employees. This qualified plan offers participants an opportunity to contribute a portion of their pay, includes features under Section 401(k) of the Internal Revenue Code and provides for company matching contributions. The matching contributions to the plan are 100% of the first 1% of eligible employee contributions and 70% of the next 5% of contributions. The cost for matching contributions to the retirement savings plan for the years ended December 31, 2020 and 2019 was $8 million and $8 million, respectively.
9. BUSINESS SEGMENTS
APCo has one reportable segment, an electricity generation, transmission and distribution business. APCo’s other activities are insignificant.
10. DERIVATIVES AND HEDGING
OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS
AEPSC is agent for and transacts on behalf of APCo.
APCo is exposed to certain market risks as major power producer and participant in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk and credit risk. These risks represent the risk of loss that may impact APCo due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks.
STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES
Risk Management Strategies
The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, APCo primarily employs risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance.
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APCo utilizes power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. APCo utilizes interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. APCo also utilizes derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors.
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The following table represents the gross notional volume of outstanding derivative contracts:
Notional Volume of Derivative Instruments
Volume December 31, Primary Risk Exposure 2020 2019 Unit of Measure (in millions) Commodity: Power 46.9 61.0 MWhs Heating Oil and Gasoline 1.1 1.1 Gallons Interest Rate on Long-term Debt $ 200.0 $ — USD
Cash Flow Hedging Strategies
APCo utilizes cash flow hedges on certain derivative transactions for the purchase-and-sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. APCo, does not hedge all commodity price risk.
APCo utilizes a variety of interest rate derivative transactions in order to manage interest rate risk exposure. APCo also utilizes interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt APCo does not hedge all interest rate exposure.
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ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS
The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes and other assumptions. In order to determine the relevant fair values of the derivative instruments, APCo, applies valuation adjustments for discounting, liquidity and credit quality.
Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts.
According to the accounting guidance for “Derivatives and Hedging,” APCo reflects the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, APCo is required to post or receive cash collateral based on third-party contractual agreements and risk profiles. The netted cash collateral from third-parties against short-term and long-term risk management assets and netted cash collateral paid to third-parties against short-term and long-term risk management liabilities were immaterial as of December 31, 2020 and 2019.
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The following tables represent the gross fair value of APCo’s derivative activity on the balance sheets:
December 31, 2020 Gross Amounts Risk of Risk Gross Amounts Net Amounts of Assets/ Management Hedging Management Offset in the Liabilities Presented in Contracts - Contracts - Assets/Liabilities Statement of the Statement of Balance Sheet Location Commodity (a) Interest Rate (a) Recognized Financial Position (b) Financial Position (c)
(in millions) Derivative Instrument Assets $ 39.5 $ 2.4 $ 41.9 $ (19.4) $ 22.5 Long-Term Portion of Derivative Instrument Assets 0.7 — 0.7 (0.6) 0.1
Derivative Instrument Liabilities 20.3 3.4 23.7 (19.0) 4.7 Long-Term Portion of Derivative Instrument Liabilities 0.6 — 0.6 (0.5) 0.1
December 31, 2019
Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c)
(in millions) Derivative Instrument Assets $ 125.3 $ (85.8)$ 39.5 Long-Term Portion of Derivative Instrument Assets 0.9 (0.8) 0.1
Derivative Instrument Liabilities 86.9 (85.0) 1.9 Long-Term Portion of Derivative Instrument Liabilities 0.7 (0.7) —
(a) Derivative instruments within this category are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) All derivative contracts subject to a master netting arrangement or similar agreement are offset in the statement of financial position.
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The table below presents the activity of derivative risk management contracts:
Amount of Gain (Loss) Recognized on Risk Management Contracts
Years Ended December 31, Location of Gain (Loss) 2020 2019 (in millions) Operating Revenues $ 0.4 $ 0.1 Operation Expenses 1.0 1.5 Maintenance Expenses (0.4) (0.2) Other Regulatory Assets (a) — 0.3 Other Regulatory Liabilities (a) 20.3 2.4 Total Gain (Loss) on Risk Management Contracts $ 21.3 $ 4.1
(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment.
Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis.
The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge.
For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”
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Accounting for Cash Flow Hedging Strategies
For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), APCo initially reports the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income on the balance sheets until the period the hedged item affects Net Income.
Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Operating Revenues or Operation Expenses on the statements of income or in Other Regulatory Assets or Other Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the years ended 2020 and 2019, APCo, did not apply cash flow hedging to outstanding power derivatives.
APCo reclassifies gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income on the balance sheets into Interest on Long-term Debt on the statements of income in those periods in which hedged interest payments occur. During the year ended 2020, APCo applied cash flow hedging to outstanding interest rate derivatives. During the year ended 2019, APCo did not apply cash flow hedging to outstanding interest rate derivatives.
For details on effective cash flow hedges included in Accumulated Other Comprehensive Income on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 - Comprehensive Income.
Cash flow hedges included in Accumulated Other Comprehensive Income on the balance sheets were:
Impact of Cash Flow Hedges on the Balance Sheets
December 31, 2020 December 31, 2019 Interest Rate Expected to be Expected to be Reclassed to Reclassed to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Net of Tax Twelve Months Net of Tax Twelve Months (in millions) $ (0.8)$ 0.4$ 0.9$ 0.9
The actual amounts reclassified from Accumulated Other Comprehensive Income to Net Income can differ from the estimate above due to market price changes.
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Credit Risk
Management mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses credit agency ratings and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.
Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required.
Collateral Triggering Events
Credit Downgrade Triggers
A limited number of derivative contracts include collateral triggering events, which include a requirement to maintain certain credit ratings. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering events in contracts. APCo has not experienced a downgrade below a specified credit rating threshold that would require the posting of additional collateral. APCo had no derivative contracts with collateral triggering events in a net liability position as of December 31, 2020 and 2019.
Cross-Default Triggers
In addition, a majority of APCo’s non-exchange-traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third-party obligation that is $50 million or greater. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. Amounts for APCo were immaterial for years ended December 31, 2020 and 2019.
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11. FAIR VALUE MEASUREMENTS
Fair Value Measurements of Long-term Debt
The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
The book values and fair values of Long-term Debt are summarized in the following table:
December 31, 2020 2019 Book Value Fair Value Book Value Fair Value (in millions) $ 4,861.9 $ 6,391.8 $ 4,388.9 $ 5,253.1
Fair Value Measurements of Financial Assets and Liabilities
For a discussion of fair value accounting and the classification of assets and liabilities within the fair value hierarchy, see the “Fair Value Measurements of Assets and Liabilities” section of Note 1.
The following tables set forth, by level within the fair value hierarchy, APCo’s financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.
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Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2020
Level 1 Level 2 Level 3 Other Total Assets: (in millions)
Special Deposits $ 16.9 $ — $ — $ — $ 16.9
Derivative Instrument Assets Risk Management Commodity Contracts (a) (b) — 19.4 19.9 (19.2) 20.1 Cash Flow Hedges: Interest Rate Hedges — 2.4 — — 2.4 Total Derivative Instrument Assets — 21.8 19.9 (19.2) 22.5
Total Assets $ 16.9 $ 21.8 $ 19.9 $ (19.2) $ 39.4
Liabilities:
Derivative Instrument Liabilities Risk Management Commodity Contracts (a) (b) $ — $ 19.5 $ 0.6 $ (18.8) $ 1.3 Cash Flow Hedges: Interest Rate Hedges — 3.4 — — 3.4 Total Derivative Instrument Liabilities $ — $ 22.9 $ 0.6 $ (18.8) $ 4.7
December 31, 2019
Level 1 Level 2 Level 3 Other Total Assets: (in millions)
Special Deposits $ 23.5 $ — $ — $ — $ 23.5
Derivative Instrument Assets Risk Management Commodity Contracts (a) (b) — 84.6 40.5 (85.6) 39.5
Total Assets $ 23.5 $ 84.6 $ 40.5 $ (85.6) $ 63.0
Liabilities:
Derivative Instrument Liabilities Risk Management Commodity Contracts (a) (b) $ — $ 84.0 $ 2.8 $ (84.9) $9
(a) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.” (b) Substantially comprised of power contracts.
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The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy:
Derivative Instrument Year Ended December 31, 2020 Assets (Liabilities) (in millions) Balance as of December 31, 2019 $ 37.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 13.2 Settlements (51.6) Transfers into Level 3 (c) (d) — Transfers out of Level 3 (d) 0.7 Changes in Fair Value Allocated to Regulated Jurisdictions (e) 19.3 Balance as of December 31, 2020 $ 19.3
Derivative Instrument Year Ended December 31, 2019 Assets (Liabilities) (in millions) Balance as of December 31, 2018 $ 57.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) (13.9) Settlements (42.5) Transfers into Level 3 (c) (d) (0.5) Transfers out of Level 3 (d) (0.7) Changes in Fair Value Allocated to Regulated Jurisdictions (e) 37.5 Balance as of December 31, 2019 $ 37.7 (a) Included in revenues on the statements of income. (b) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (c) Represents existing assets or liabilities that were previously categorized as Level 2. (d) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (e) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities or accounts payable.
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The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions:
December 31, 2020 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (b) (in millions) Discounted Forward Market Energy Contracts $ 1.0 $ 0.6 Cash Flow Price $10.84 $ 41.09 $ 25.08 Discounted Forward Market FTRs 18.9 — Cash Flow Price 0.04 5.61 1.13 Total $ 19.9 $ 0.6
December 31, 2019 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (b) (in millions) Discounted Forward Market Energy Contracts $ 5.7 $ 2.6 Cash Flow Price $12.70 $ 41.20 $ 25.92 Discounted Forward Market FTRs 34.8 0.2 Cash Flow Price (0.14) 7.08 1.70 Total $ 40.5 $ 2.8 (a) Represents market prices in dollars per MWh. (b) The weighted-average is the product of the forward market price of the underlying commodity and volume weighted by term.
The following table provides the measurement uncertainty of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts, Natural Gas Contracts and FTRs as of December 31, 2020 and 2019:
Uncertainty of Fair Value Measurements Impact on Fair Value Significant Unobservable Input Position Change in Input Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher)
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12. INCOME TAXES
Income Tax Expense (Credit)
The details of APCo’s income taxes as reported are as follows:
Years Ended December 31, 2020 2019 (in millions) Charged (Credited) to Operating Expenses, Net: Current $ 36.2 $ 56.4 Deferred (29.4) (121.6) Total 6.8 (65.2)
Charged (Credited) to Non-Operating Income, Net: Current (5.2) (7.7) Deferred 2.8 (5.2) Total (2.4) (12.9) Total Income Tax Expense (Benefit) $ 4.4 $ (78.1)
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The following is a reconciliation of the difference between the amount of federal income taxes computed by multiplying book income before income taxes by the federal statutory tax rate and the amount of income taxes reported:
Years Ended December 31, 2020 2019 (in millions) Net Income $ 369.7 $ 306.3 Income Tax Expense (Benefit) 4.4 (78.1) Pretax Income $ 374.1 $ 228.2
Income Taxes on Pretax Income at Statutory Rate (21%) $ 78.6 $ 47.9 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 12.7 10.8 State and Local Income Taxes, Net 7.9 9.0 Removal Costs (5.7) (6.4) AFUDC (4.5) (5.2) Parent Company Loss Benefit (6.2) (4.1) Tax Reform Excess ADIT Reversal (72.3) (130.4) Return to Provision Adjustment (7.1) (1.0) Other 1.0 1.3 Income Tax Expense (Benefit) $ 4.4 $ (78.1)
Effective Income Tax Rate 1.2% (34.2)%
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Net Deferred Tax Liability
The following table shows elements of APCo’s net deferred tax assets (liabilities) and significant temporary differences:
December 31, 2020 2019 (in millions) Deferred Tax Assets $ 494.8 $ 480.1 Deferred Tax Liabilities (2,249.5) (2,165.9) Net Deferred Tax Liabilities $ (1,754.7) $ (1,685.8)
Property Related Temporary Differences $ (1,412.0) $ (1,420.0) Amounts Due to Customers for Future Income Taxes 198.3 222.8 Deferred State Income Taxes (336.5) (337.2) Regulatory Assets (114.8) (49.3) Securitized Assets (44.7) (71) Operating Lease Liability 16.7 16.5 All Other, Net (61.7) (47.6) Net Deferred Tax Liabilities $ (1,754.7) $ (1,685.8)
AEP System Tax Allocation Agreement
APCo and other AEP subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax loss of the parent company (Parent Company Loss Benefit) to the AEP System subsidiaries with taxable income reducing their current tax expense proportionately. The consolidated NOL of the AEP System is allocated to each company in the consolidated group with taxable losses. With the exception of the allocation of the consolidated AEP System NOL, the loss of the Parent and tax credits, the method of allocation reflects a separate return result for each company in the consolidated group.
Federal and State Income Tax Audit Status
The statute of limitations for the IRS to examine APCo and other AEP subsidiaries originally filed federal return has expired for tax years 2016 and earlier. In the third quarter of 2019, APCo and other AEP subsidiaries elected to amend the 2014 and 2015 federal returns. In the first quarter of 2020, the IRS notified APCo and other AEP subsidiaries that it was beginning an examination of these amended returns, including the NOL carryback to 2015 that originated in the 2017 return. As of December 31, 2020, the IRS has not challenged any items on these
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Federal Tax Legislation
In March 2020, the CARES Act was signed into law. The CARES Act includes tax relief provisions such as: (a) an AMT Credit Refund, and (b) a 5-year NOL carryback from years 2018-2020. Pursuant to the CARES Act, APCo and other AEP subsidiaries requested a partial refund of taxes paid in 2014 under the 5-year NOL carryback provision of the CARES Act. Management will continue to monitor potential legislation and any impacts to the AMT Credit and NOL refunds that were filed in 2020 pursuant to the CARES Act.
In December 2020, the CAA of 2021 was signed into law. The CAA of 2021 includes: (a) COVID-19 tax relief and tax extender provisions including extensions of time to begin construction on and placed in-service assets generating ITCs, (b) 100% deductibility of business meals in 2021 and 2022 and (c) an extension of the work opportunity tax credit. The ITC percentage has been increased for projects starting construction through 2023 and placed in-service by the end of 2025. These provisions provide time and flexibility on the construction start and in-service dates.
In September and November 2020, the IRS issued final regulations that provide guidance regarding the additional first-year depreciation deduction under Section 168(k). The final regulations reflect changes as a result of Tax Reform, which affects taxpayers with qualified depreciable property acquired and placed in-service after September 27, 2017. Generally, AEP’s regulated utilities will not be eligible for any bonus depreciation for property acquired and placed in-service after December 31, 2017. APCo and other AEP subsidiaries’ competitive businesses will be eligible for 100% expensing.
The IRS issued final regulations in 2020 that provide guidance concerning potential limitations on the deduction of business interest expense. These regulations require an allocation of net interest expense between regulated and competitive businesses within the consolidated tax return. This allocation is based upon net tax basis, and the proposed regulations provide de minimis tests under which all interest is deductible if less than 10% is allocable to the competitive businesses. APCo and other AEP subsidiaries will deduct materially all business interest expense under this de minimis provision.
On December 30, 2020, the IRS issued regulations that provide guidance on the non-deductibility of certain executives compensation above $1 million under Internal Revenue Code Section 162(m). The regulations clarify the application of rules passed under Tax Reform that expanded the application of Section 162(m) to SEC registered companies that issue either public equity or debt. These rules also expanded the type of compensation and the number of executives subject to this deduction disallowance. APCo and other AEP subsidiaries limit certain executives compensation to the $1 million limitation on its federal income tax return.
FERC FORM NO. 1 (ED. 12-88) Page 123.60 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
13. LEASES
APCo adopted ASU 2016-02 effective January 1, 2019 by means of a cumulative-effect adjustment to the balance sheets.
APCo leases property, plant and equipment including, but not limited to, fleet, information technology and real estate leases. These leases require payments of non-lease components, including related property taxes, operating and maintenance costs. APCo does not separate non-lease components from associated lease components. Many of these leases have purchase or renewal options. Leases not renewed are often replaced by other leases. Options to renew or purchase a lease are included in the measurement of lease assets and liabilities if it is reasonably certain APCo will exercise the option.
Lease obligations are measured using the discount rate implicit in the lease when that rate is readily determinable. AEP has visibility into the rate implicit in the lease when assets are leased from selected financial institutions under master leasing agreements. When the implicit rate is not readily determinable, APCo measures its lease obligation using its estimated secured incremental borrowing rate. Incremental borrowing rates are comprised of an underlying risk-free rate and a secured credit spread relative to the lessee on a matched maturity basis.
Operating and Finance lease rental costs are generally charged to Operation Expense and Maintenance Expense in accordance with rate-making treatment for regulated operations. Lease costs associated with capital projects are included in Utility Plant on the balance sheets. For regulated operations with finance leases, a finance lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. The components of rental costs were as follows:
Years Ended December 31, 2020 2019 (in millions) Operating Lease Cost $ 19.1 $ 19.5 Finance Lease Cost Amortization of Right-of-Use Assets 7.4 6.7 Interest on Lease Liabilities 2.7 2.9 Total Lease Rental Costs (a) $ 29.2 $ 29.1 (a) Excludes variable and short-term lease costs, which were immaterial for the twelve months ended December 31, 2020 and December 31, 2019.
FERC FORM NO. 1 (ED. 12-88) Page 123.61 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
Supplemental information related to leases are shown in the tables below:
December 31 2020 2019 Weighted-Average Remaining Lease Terms (years): Operating Leases 6.27 6.28 Finance Leases 5.75 6.12 Weighted-Average Discount Rate: Operating Leases 3.48% 3.64% Finance Leases 7.33% 8.08%
Year Ended December 31, 2020 2019 (in millions) Cash paid for amounts included in the measurement of lease liabilities: Operating Cash Flows from Operating Leases $ 19.2 $ 19.0 Operating Cash Flows from Finance Leases 10.1 9.6
Non-cash Acquisitions Under Operating Leases $ 16.2 $ 10.2
FERC FORM NO. 1 (ED. 12-88) Page 123.62 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
The following tables show the property, plant and equipment under finance, operating leases and related obligations recorded on APCo’s balance sheets:
December 31, 2020 2019 (in millions) Property, Plant and Equipment Under Finance Leases Utility Plant (a) $ 41.7 $ 41.8 Net Property, Plant and Equipment Under Finance Leases $ 41.7 $ 41.8
Obligations Under Finance Leases: Noncurrent $ 34.4 $ 35.0 Current 7.3 6.8 Total Obligations Under Finance Leases $ 41.7 $ 41.8
(a) Includes $22 million and $17 million of accumulated provision for depreciation and amortization for the years ended December 31, 2020 and 2019, respectively.
December 31, 2020 2019 (in millions) Property, Plant and Equipment Under Operating Leases Utility Plant (a) $ 78.8 $ 78.5 Net Property, Plant and Equipment Under Operating Leases $ 78.8 $ 78.5
Obligations Under Operating Leases Noncurrent $ 64.4 $ 64.0 Current 14.9 15.2 Total Obligations Under Operating Leases $ 79.3 $ 79.2
(a) Includes $25 million and $15 million of accumulated provision for depreciation and amortization for the years ended December 31, 2020 and 2019, respectively.
FERC FORM NO. 1 (ED. 12-88) Page 123.63 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
Future minimum lease payments consisted of the following as of December 31, 2020:
Finance Operating Leases Leases (in millions) 2021 $ 9.9 $ 17.7 2022 9.4 17.0 2023 8.7 14.2 2024 8.1 11.3 2025 7.0 8.5 Later Years 6.4 20.0 Total Future Minimum Lease Payments 49.5 88.7 Less: Imputed Interest 7.8 9.4 Estimated Present Value of Future Minimum Lease Payments $ 41.7 $ 79.3
Future minimum lease payments consisted of the following as of December 31, 2019:
Finance Operating Leases Leases (in millions) 2020 $ 9.6 $ 18.3 2021 8.9 15.7 2022 8.2 14.7 2023 7.7 11.9 2024 7.1 9.0 Later Years 9.8 20.0 Total Future Minimum Lease Payments 51.3 89.6 Less: Imputed Interest 9.5 10.4 Estimated Present Value of Future Minimum Lease Payments $ 41.8 $ 79.2
FERC FORM NO. 1 (ED. 12-88) Page 123.64 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
Master Lease Agreements
APCo leases certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, APCo is committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the amount guaranteed. As of December 31, 2020, the maximum potential loss by APCo for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was $7 million.
Lessor Activity
APCo’s lessor activity was immaterial as of and for the twelve months ended December 31, 2020 and December 31, 2019, respectively.
14. FINANCING ACTIVITIES
Long-term Debt
The following table details long-term debt outstanding:
Weighted-Average Interest Rate Ranges as of Outstanding as of Interest Rate as of December 31, December 31, Maturity December 31, 2020 2020 2019 2020 2019
(in millions)
Senior Unsecured Notes 2021-2050 4.94% 3.30%-7.00% 3.30%-7.00% $ 3,975.0 $ 3,475.0 Pollution Control Bonds (a) 2020-2036 (b) 1.77% 0.19%-4.63% 1.67%-5.38% 548.5 548.5 Securitization Bonds 2023-2028 (c) 3.29% 2.01%-3.77% 2.008%-3.772% 225.5 250.3 Other Long-term Debt 2022-2026 1.51% 1.32%-13.72% 2.97%-13.718% 127.0 127.1 Unamortized Discount, Net (14.1) (12.0)
Total Long-term Debt Outstanding $ 4,861.9 $ 4,388.9
(a) For certain series of Pollution Control Bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets. (b) Certain Pollution Control Bonds are subject to redemption earlier than the maturity date. (c) Dates represent the scheduled final payment dates for the securitization bonds. The legal maturity date is one to two years later. These bonds have been classified for maturity and repayment purposes based on the scheduled final payment date.
FERC FORM NO. 1 (ED. 12-88) Page 123.65 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
As of December 31, 2020, long-term debt was payable as follows:
(in millions) 2021 $ 518.3 2022 355.4 2023 26.6 2024 113.5 2025 443.9 After 2025 3,418.3 Principal Amount 4,876.0 Unamortized Discount, Net (14.1) Total Long-term Debt $ 4,861.9
Long-term Debt Subsequent Events
In February 2021, APCo retired $12 million of Securitization Bonds.
Dividend Restrictions
APCo pays dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of APCo to transfer funds to Parent in the form of dividends.
All of the dividends declared by APCo are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. However, the Federal Power Act creates a reserve on retained earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to APCo.
APCo has credit agreements that contain covenants that limit their debt to capitalization ratio to 67.5%. The method for calculating outstanding debt and capitalization is contractually-defined in the credit agreements.
The most restrictive dividend limitation for APCo is through the Federal Power Act restriction. As of December 31, 2020, the maximum amount of restricted net assets of APCo that may not be distributed to the Parent in the form of a loan, advance or dividend was $2.3 billion.
The Federal Power Act restriction limits the ability of APCo to pay dividends out of retained earnings because of their ownership in hydroelectric generation. As of December 31, 2020, the amount of any such restrictions was $175 million.
FERC FORM NO. 1 (ED. 12-88) Page 123.66 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
Corporate Borrowing Program – AEP System
The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of its agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of December 31, 2020 and 2019 are included in Notes Receivable from Associated Companies and Notes Payable to Associated Companies, respectively, on the balance sheets. APCo’s money pool activity and corresponding authorized borrowing limits are described in the following table:
Maximum Average Borrowings Maximum Borrowings Average Borrowings from Authorized from the Loans to the from the Loans to the the Utility Money Short-term Years Ended Utility Utility Utility Utility Pool as of Borrowing December 31, Money Pool Money Pool Money Pool Money Pool December 31, Limit (in millions) 2020 $ 434.3$ 167.3$ 292.7$ 94.3$ 18.6$ 500.0 2019 270.0 209.3 116.0 113.3 236.7 500.0
The maximum, minimum and average interest rates for funds either borrowed from or loaned to the Utility Money Pool are summarized in the following table:
Maximum Minimum Maximum Minimum Average Average Interest Rates Interest Rates Interest Rates Interest Rates Interest Rate Interest Rate for Funds for Funds for Funds for Funds for Funds for Funds Borrowed from Borrowed from Loaned to the Loaned to the Borrowed from Loaned to the Years Ended the Utility the Utility Utility Money Utility Money the Utility Utility Money December 31, Money Pool Money Pool Pool Pool Money Pool Pool 2020 2.70% 0.27% 2.14% 0.27% 2.13% 0.72% 2019 3.43% 1.77% 2.79% 2.41% 2.45% 2.76%
Interest expense and interest income related to the Utility Money Pool financing relationship are included in Interest on Debt to Associated Companies and Interest and Dividend Income, respectively, on the statements of income. The interest expense and interest income related to the corporate borrowing programs were immaterial for the years ended December 31, 2020 and 2019.
FERC FORM NO. 1 (ED. 12-88) Page 123.67 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
Securitized Accounts Receivables – AEP Credit
Under this sale of receivables arrangement, APCo sells, without recourse, certain of its customer accounts receivable and accrued utility revenue balances to AEP Credit and is charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for APCo’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Deductions on APCo’s statements of income. APCo manages and services its customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for APCo and retains the remainder.
AEP Credit has a receivables securitization agreement that provides a commitment of $750 million from bank conduits to purchase receivables and expires in September 2022.
The amount of accounts receivable and accrued utility revenues under the sale of receivables agreement as of December 31, 2020 and 2019 were $136 million and $121 million, respectively.
The fees paid to AEP Credit for customer accounts receivable sold were $5 million and $7 million for the years ended December 31, 2020 and 2019, respectively.
The proceeds on the sale of receivables to AEP Credit were $1.3 billion and $1.3 billion for the years ended December 31, 2020 and 2019, respectively.
FERC FORM NO. 1 (ED. 12-88) Page 123.68 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
15. RELATED PARTY TRANSACTIONS
For other related party transactions, also see “AEP System Tax Allocation Agreement” section of Note 12 in addition to “Corporate Borrowing Program – AEP System” and “Securitized Accounts Receivables – AEP Credit” sections of Note 14.
Power Coordination Agreement
Effective January 1, 2014, the FERC approved the PCA. Under the PCA, APCo, I&M, KPCo and WPCo are individually responsible for planning their respective capacity obligations. The PCA allows, but does not obligate, APCo, I&M, KPCo and WPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities.
AEPSC conducts power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other risk management activities on behalf of APCo, I&M, KPCo, PSO, SWEPCo and WPCo. Certain power and natural gas risk management activities for APCo, I&M, KPCo and WPCo are allocated based on the four member companies’ respective equity positions, while power and natural gas risk management activities for PSO and SWEPCo are allocated based on the Operating Agreement.
System Integration Agreement
Under the SIA, AEPSC allocates physical and financial revenues and expenses from transactions with neighboring utilities, power marketers and other power and natural gas risk management activities based upon the location of such activity. Margins resulting from trading and marketing activities originating in PJM generally accrue to the benefit of APCo, I&M, KPCo and WPCo. Margins resulting from other transactions are allocated among APCo, I&M, KPCo, PSO, SWEPCo and WPCo based upon the equity positions of these companies.
FERC FORM NO. 1 (ED. 12-88) Page 123.69 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
Affiliated Revenues and Purchases
The following table shows the revenues derived from direct sales to affiliates, auction sales to affiliates, net transmission agreement sales and other revenues for the years ended December 31, 2020 and 2019:
Years Ended December 31, Related Party Revenues 2020 2019 (in millions) Direct Sales to East Affiliates $ 112.5 $ 128.6 Auction Sales to OPCo (a) 5.3 11.4 Transmission Revenues 49.1 58.5 Other Revenues 7.8 6.8
(a) Refer to the Ohio Auction section below for further information regarding these amounts.
PJM and SPP Transmission Service Charges
The AEP East Companies are parties to the TA, which defines how transmission costs through the PJM OATT are allocated among the AEP East Companies on a 12-month average coincident peak basis. APCo’s net charges for the years ended December 31, 2020 and 2019 related to the TA were $243 million and $222 million, respectively. The charges were recorded in Operation Expenses on the statements of income.
Joint License Agreement
AEPTCo entered into a 50-year joint license agreement with APCo allowing either party to occupy the granting party’s facilities or real property. In addition, AEPTCo entered into a 5-year joint license agreement with APCo and WPCo. After the expiration of the agreement, the term shall automatically renew for successive one-year terms unless either party provides notice. The joint license billing provides compensation to the granting party for the cost of carrying assets, including depreciation expense, property taxes, interest expense, return on equity and income taxes. For the years ended December 31, 2020 and 2019, AEPTCo billed APCo $900 thousand and $200 thousand, respectively.
Ohio Auctions
In connection with OPCo’s June 2012 - May 2015 ESP, the Public Utilities Commission of Ohio ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015. APCo, KPCo, I&M and WPCo participate in the auction process and have been awarded tranches of OPCo’s SSO load. Refer to the Affiliated Revenues and Purchases section above for amounts related to these transactions.
FERC FORM NO. 1 (ED. 12-88) Page 123.70 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
I&M Barging, Urea Transloading and Other Services
I&M provides barging, urea transloading and other transportation services to affiliates. Urea is a chemical used to control NO x emissions at certain generation plants in the AEP System. APCo recorded the costs paid to I&M of $44 million and $39 million for the years ended December 31, 2020 and 2019, respectively, as Operation Expenses.
Central Machine Shop
APCo operates a facility which repairs and rebuilds specialized components for the generation plants across the AEP System. APCo defers the cost of performing these services on the balance sheet and then transfers the cost to the affiliate for reimbursement. APCo billed its affiliates $8 million and $7 million for the years ended December 31, 2020 and 2019, respectively.
OVEC
AEP and several nonaffiliated utility companies jointly own OVEC. As of December 31, 2020, the ownership and investment in OVEC were as follows:
December 31, 2020 Company Ownership Investment (in millions) Parent 39.17%$ 4.0 OPCo 4.30 % 0.4 Total 43.47 % $ 4.4
OVEC’s owners, along with APCo and I&M, are members to an intercompany power agreement. Participants of this agreement are entitled to receive and obligated to pay for all OVEC generating capacity, approximately 2,400 MWs, in proportion to their respective power participation ratios. The aggregate power participation ratio of certain AEP utility subsidiaries, including APCo, I&M and OPCo, is 43.47%. The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs, including outstanding indebtedness, and provide a return on capital. The intercompany power agreement ends in June 2040.
FERC FORM NO. 1 (ED. 12-88) Page 123.71 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
AEP and other nonaffiliated owners authorized environmental investments related to their ownership interests. OVEC financed capital expenditures in connection with the engineering and construction of FGD projects and the associated waste disposal landfills at its two generation plants. These environmental projects were funded through debt issuances. As of December 31, 2020 and 2019, OVEC’s outstanding indebtedness was approximately $1.3 and $1.4 billion. Although they are not an obligor or guarantor, AEP utility subsidiaries are responsible for their respective ratio of OVEC’s outstanding debt through the intercompany power agreement. Principal and interest payments related to OVEC’s outstanding indebtedness are disclosed in accordance with the accounting guidance for “Commitments.” See the “Commitments” section of Note 6 for additional information.
Purchased Power from OVEC
APCo paid $94 million and $105 million for power purchased from OVEC for the years ended December 31, 2020 and 2019, respectively. The amounts shown above are recoverable from customers and are included in Operating Revenues and Operation Expenses on the statement of income.
Sales and Purchases of Property
APCo had affiliated sales and purchases of electric property amounting to $100 thousand or more, sales and purchases of meters and transformers, and sales and purchases of transmission property. There were no gains or losses recorded on the transactions. The following table shows the sales and purchases, recorded at net book value:
Years Ended December 31, 2020 2019 (in millions) Sales $ 5.7 $ 5.5 Purchases 1.3 6.0
The amounts above are recorded in Utility Plant on the balance sheets.
Intercompany Billings
APCo performs certain utility services for each other when necessary or practical. The costs of these services are billed on a direct-charge basis, whenever possible, or on reasonable basis of proration for services that benefit multiple companies. The billings for services are made at cost and include no compensation for the use of equity capital.
FERC FORM NO. 1 (ED. 12-88) Page 123.72 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
AEPSC
AEPSC provides certain managerial and professional services to APCo. The costs of the services are based on a direct charge or on a prorated basis and billed to APCo at AEPSC’s cost. AEPSC and its billings are subject to regulation by the FERC. APCo’s total billings from AEPSC were $295 million and $308 million for the years ended December 31, 2020 and 2019, respectively.
Charitable Contributions to AEP Foundation
The American Electric Power Foundation is funded by American Electric Power and its utility operating units. The Foundation provides a permanent, ongoing resource for charitable initiatives and multi-year commitments in the communities served by AEP and initiatives outside of AEP’s 11-state service area. Charitable contributions to the AEP Foundation were recorded in Donations on the statements of income. In 2020, there were no charitable contributions made to the AEP Foundation APCo’s charitable contributions to the AEP Foundation recorded were $9 million for the year ended December 31, 2019.
FERC FORM NO. 1 (ED. 12-88) Page 123.73 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
16. PROPERTY, PLANT AND EQUIPMENT
Depreciation
APCo provides for depreciation of Utility Plant, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class. The following table provides total regulated annual composite depreciation rates by functional class:
Other Year Production Steam Hydro Transmission Distribution General (in percentages) 2020 2.6 3.4 3.0 2.2 3.7 7.8 2019 2.6 3.3 2.7 1.8 3.7 7.2
The composite depreciation rate generally includes a component for non-ARO removal costs, which is credited to accumulated depreciation on the balance sheets. Actual removal costs incurred are charged to accumulated depreciation.
Asset Retirement Obligations
APCo records ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities and certain coal-mining facilities. APCo has identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since APCo plans to use its facilities indefinitely. The retirement obligation would only be recognized if and when APCo abandons or ceases the use of specific easements, which is not expected.
In June 2020, APCo recorded a revision to increase estimated Glen Lyn Station ash disposal ARO liabilities by $199 million due to the enactment of House Bill 443. This bill requires APCo to close the ash disposal units at the retired Glen Lyn Station by removal of all coal combustion material. The legislation provides for regulatory recovery of these costs. See Note 6 - Commitments, Guarantees and Contingencies for additional information.
FERC FORM NO. 1 (ED. 12-88) Page 123.74 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
The following is a reconciliation of the 2020 and 2019 aggregate carrying amounts of ARO:
Revisions in ARO at Accretion Liabilities Cash Flow ARO at Year January 1, Expense Settled Estimates(a) December 31, (in millions) 2020 $ 111.1 $ 8.9 $ $ (7.8) $ 200.9 $ 313.1 (b)(c) 2019 116.1 5.9 (17.6) 6.7 111.1 (b)(c)
(a) Unless discussed above, primarily related to ash ponds, landfills and mine reclamation, generally due to changes in estimated closure area, volumes and/or unit costs. (b) Includes ARO related to ash disposal facilities. (c) Includes ARO related to asbestos removal.
FERC FORM NO. 1 (ED. 12-88) Page 123.75 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
17. REVENUE FROM CONTRACTS WITH CUSTOMERS
Disaggregated Revenues from Contracts with Customers
The tables below represent revenues from contracts with customers, net of respective provisions for refund, by type of revenue for APCo:
Years Ended December 31, 2020 2019 (in millions) Retail Revenues: Residential Revenues $ 1,273.0 $ 1,266.9 Commercial Revenues 526.9 559.9 Industrial Revenues 563.9 592.2 Other Retail Revenues 68.9 75.2 Total Retail Revenues 2,432.7 2,494.2
Wholesale Revenues Generation Revenues (a) 247.1 273.5 Transmission Revenues (b) 130.9 103.6 Total Wholesale Revenues 378.0 377.1
Other Revenues from Contracts with Customers (b) 59.2 61.0
Total Revenues from Contract with Customers 2,869.9 2,932.3
Other Revenues Alternative Revenues (b) (13.0) 13.6 Other Revenues (b) 0.3 0.3 Total Other Revenues (12.7) 13.9
Total Operating Revenues $ 2,857.2 $ 2,946.2
(a) Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $112 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial. (b) Amounts include affiliated and nonaffiliated revenues.
FERC FORM NO. 1 (ED. 12-88) Page 123.76 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
Performance Obligations
APCo has performance obligations as part of its normal course of business. A performance obligation is a promise to transfer a distinct good or service, or a series of distinct goods or services that are substantially the same and have the same pattern of transfer to a customer. The invoice practical expedient within the accounting guidance for “Revenue from Contracts with Customers” allows for the recognition of revenue from performance obligations in the amount of consideration to which there is a right to invoice the customer and when the amount for which there is a right to invoice corresponds directly to the value transferred to the customer.
The purpose of the invoice practical expedient is to depict an entity’s measure of progress toward completion of the performance obligation within a contract and can only be applied to performance obligations that are satisfied over time and when the invoice is representative of services provided to date. APCo elected to apply the invoice practical expedient to recognize revenue for performance obligations satisfied over time as the invoices from the respective revenue streams are representative of services or goods provided to date to the customer. Performance obligations for APCo are summarized as follows:
Retail Revenues
APCo has performance obligations to generate, transmit and distribute electricity for sale to rate-regulated retail customers. The performance obligation to deliver electricity is satisfied over time as the customer simultaneously receives and consumes the benefits provided. Revenues are variable as they are subject to the customer’s usage requirements.
Rate-regulated retail customers typically have the right to discontinue receiving service at will, therefore these contracts between APCo and their customers for rate-regulated services are generally limited to the services requested and received to date for such arrangements. Retail customers are generally billed on a monthly basis, and payment is typically due within 15 to 20 days after the issuance of the invoice.
FERC FORM NO. 1 (ED. 12-88) Page 123.77 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
Wholesale Revenues - Generation
APCo has performance obligations to sell electricity to wholesale customers from generation assets in PJM. The performance obligation to deliver electricity from generation assets is satisfied over time as the customer simultaneously receives and consumes the benefits provided. Wholesale generation revenues are variable as they are subject to the customer’s usage requirements.
APCo also has performance obligations to stand ready in order to promote grid reliability. Stand ready services are sold into PJM’s RPM capacity market. RPM entails a base auction and at least three incremental auctions for a specific PJM delivery year, with the incremental auctions spanning three years. The performance obligation to stand ready is satisfied over time and the consideration for which is variable until the occurrence of the final incremental auction, at which point the performance obligation becomes fixed.
Payments from the RTO for stand ready services are typically received within one week from the issuance of the invoice, which is typically issued weekly. Gross margin resulting from generation sales are primarily subject to margin sharing agreements with customers and vary by state, where the revenues are reflected gross in the disaggregated revenues tables above.
APCo has a performance obligation to supply wholesale electricity to KGPCo through a PPA. The FERC regulates the cost-based wholesale power transactions between APCo and KGPCo. The purchased power agreement includes a component for the recovery of transmission costs under the FERC OATT. The transmission cost component of purchased power is cost-based and regulated by the Tennessee Regulatory Authority. APCo’s performance obligation under the purchased power agreement is satisfied over time as KGPCo simultaneously receives and consumes the wholesale electricity. APCo’s revenues from the purchased power agreement are presented within the Generation Revenues line in the disaggregated revenues tables above.
Wholesale Revenues - Transmission
APCo has performance obligations to transmit electricity to wholesale customers through assets owned and operated. The performance obligation to provide transmission services in PJM encompass a time frame greater than a year, where the performance obligation within each RTO is partially fixed for a period of one year or less. Payments from the RTO for transmission services are typically received within one week from the issuance of the invoice, which is issued weekly for PJM.
APCo collects revenues through transmission formula rates. The FERC-approved rates establish the annual transmission revenue requirement (ATRR) and transmission service rates for transmission owners. The formula rates establish rates for a one year period and also include a true-up calculation for the prior year’s billings, allowing for over/under-recovery of the transmission owner’s ATRR. The annual true-ups meet the definition of alternative revenues in accordance with the accounting guidance for “Regulated Operations,” and are presented as such in the disaggregated revenues tables above.
FERC FORM NO. 1 (ED. 12-88) Page 123.78 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
The AEP East Companies are parties to the TA, which defines how transmission costs are allocated among the AEP East Companies on a 12-month average coincident peak basis. Affiliate revenues as a result of the respective transmission agreement are reflected as Transmission Revenues in the disaggregated revenues tables above.
Fixed Performance Obligations
The following table represents the remaining fixed performance obligations satisfied over time as of December 31, 2020. Fixed performance obligations primarily include wholesale transmission services, electricity sales for fixed amounts of energy and stand ready services into PJM’s RPM market. The amounts shown in the table below include affiliated and nonaffiliated revenues.
2021 2022-2023 2024-2025 After 2025 Total (in millions) $ 173.4 $ 32.3 $ 23.2 $ 11.6 $ 240.5
Contract Assets and Liabilities
Contract assets are recognized when APCo has a right to consideration that is conditional upon the occurrence of an event other than the passage of time, such as future performance under a contract. APCo did not have any material contract assets as of December 31, 2020 and 2019.
When APCo receives consideration, or such consideration is unconditionally due from a customer prior to transferring goods or services to the customer under the terms of a sales contract, they recognize a contract liability on the balance sheets in the amount of that consideration. Revenue for such consideration is subsequently recognized in the period or periods in which the remaining performance obligations in the contract are satisfied. APCo’s contract liabilities typically arise from services provided under joint use agreements for utility poles. APCo did not have any material contract liabilities as of December 31, 2020 and 2019.
Accounts Receivable from Contracts with Customers
Accounts receivable from contracts with customers are presented on APCo’s balance sheets within the Customer Accounts Receivable line item. APCo’s balances for receivables from contracts that are not recognized in accordance with the accounting guidance for “Revenue from Contracts with Customers” included in Customer Accounts Receivables were not material as of December 31, 2020 and 2019. See “Securitized Accounts Receivable - AEP Credit” section of Note 14 for additional information.
The amount of affiliated accounts receivable from contracts with customers included in Accounts Receivable from Associated Companies on APCo’s balance sheets were $53 million and $47 million, as of December 31, 2020 and 2019.
FERC FORM NO. 1 (ED. 12-88) Page 123.79 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
Contract Costs
Contract costs to obtain or fulfill a contract for APCo are accounted for under the guidance for “Other Assets and Deferred Costs” and presented as a single asset and are neither bifurcated nor reclassified between current assets and deferred debits on the balance sheets. Contract costs to acquire a contract are amortized in a manner consistent with the transfer of goods or services to the customer in Operation Expenses on the income statements. APCo did not have material contract costs as of December 31, 2020 and 2019.
FERC FORM NO. 1 (ED. 12-88) Page 123.80 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
18. FERC ORDER NO. 784-A
On July 18, 2013, the FERC issued Order No. 784 that revised certain aspects of the accounting and reporting requirements under the Uniform System of Accounts related to energy storage accounts. Due to software limitations, the newly adopted and revised schedules in the FERC Forms that would contain the energy storage accounts are not available to filers of the forms for use as of the effective date. Utilities with energy storage assets must use the existing schedules in the FERC Forms to report energy storage assets pending availability of the new and revised schedules. FERC directed filers to submit the requested energy storage information as part of pages 122-123.
APCo has energy storage operations as follows:
Operation Maintenance Project Functional Project Project Costs Expenses Expenses Name Classification Location Account Amount Account Amount Account Amount (dollars in millions)
Year Ended December 31, 2020
Balls Gap Station Distribution Balls Gap, WV 363 $ 5.4 562 $ –– 592 $ –– Chemical Station Transmission N. Charleston, WV 351 –– 562 –– 592 ––
Year Ended December 31, 2019
Balls Gap Station Distribution Balls Gap, WV 363 $ 5.4 562 $ –– 592 $ –– Chemical Station Transmission N. Charleston, WV 351 –– 562 –– 592 ––
FERC FORM NO. 1 (ED. 12-88) Page 123.81 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)
19. SUBSEQUENT EVENTS
Impacts of Severe Winter Weather in February 2021
In February 2021, many of AEP’s service territories and customers were impacted by severe winter weather and extreme cold temperatures resulting in power outages, extensive damage to transmission and distribution infrastructure and disruption to the energy markets.
Storm Costs
Based on the information currently available, APCo currently estimates significant February 2021 storm restoration expenditures ranging between $65 million and $75 million. Management currently anticipates the storm restoration expenditures will be more heavily weighted towards other operation and maintenance expenses as compared to capital expenditures. Management will continue to refine these storm cost estimates as restoration efforts are completed and final costs become available. Management plans to seek regulatory recovery of these costs. If any of the storm costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
FERC FORM NO. 1 (ED. 12-88) Page 123.82 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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.
Item Unrealized Gains and Minimum Pension Foreign Currency Other Line Losses on Available- Liability adjustment Hedges Adjustments No. for-Sale Securities (net amount) (a) (b) (c) (d) (e) 1 Balance of Account 219 at Beginning of Preceding Year ( 64,151) ( 6,668,541) 2 Preceding Qtr/Yr to Date Reclassifications from Acct 219 to Net Income 1,170,462 3 Preceding Quarter/Year to Date Changes in Fair Value ( 37) 9,704,833 4 Total (lines 2 and 3) ( 37) 10,875,295 5 Balance of Account 219 at End of Preceding Quarter/Year ( 64,188) 4,206,754 6 Balance of Account 219 at Beginning of Current Year ( 64,188) 4,206,754 7 Current Qtr/Yr to Date Reclassifications from Acct 219 to Net Income ( 3,438,622) 8 Current Quarter/Year to Date Changes in Fair Value ( 36) 8,050,598 9 Total (lines 7 and 8) ( 36) 4,611,976 10 Balance of Account 219 at End of Current Quarter/Year ( 64,224) 8,818,730
FERC FORM NO. 1 (NEW 06-02) Page 122a Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Other Cash Flow Other Cash Flow Totals for each Net Income (Carried Total Line Hedges Hedges category of items Forward from Comprehensive No. Interest Rate Swaps [Specify] recorded in Page 117, Line 78) Income Account 219 (f) (g) (h) (i) (j) 1 1,790,027 ( 4,942,665) 2 ( 891,821) 278,641 3 9,704,796 4 ( 891,821) 9,983,437 306,298,843 316,282,280 5 898,206 5,040,772 6 898,206 5,040,772 7 ( 1,731,328) ( 5,169,950) 8 8,050,562 9 ( 1,731,328) 2,880,612 369,732,667 372,613,279 10 ( 833,122) 7,921,384
FERC FORM NO. 1 (NEW 06-02) Page 122b Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / SUMMARY 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 Line Classification Electric Current Year/Quarter Ended No. (c) (a) (b) 1 Utility Plant 2 In Service 3 Plant in Service (Classified) 14,375,521,597 14,375,521,597 4 Property Under Capital Leases 120,360,990 120,360,990 5 Plant Purchased or Sold 6 Completed Construction not Classified 1,156,193,729 1,156,193,729 7 Experimental Plant Unclassified 8 Total (3 thru 7) 15,652,076,316 15,652,076,316 9 Leased to Others 10 Held for Future Use 3,735,818 3,735,818 11 Construction Work in Progress 485,037,217 485,037,217 12 Acquisition Adjustments 181,679 181,679 13 Total Utility Plant (8 thru 12) 16,141,031,030 16,141,031,030 14 Accum Prov for Depr, Amort, & Depl 5,412,843,611 5,412,843,611 15 Net Utility Plant (13 less 14) 10,728,187,419 10,728,187,419 16 Detail of Accum Prov for Depr, Amort & Depl 17 In Service: 18 Depreciation 5,301,065,124 5,301,065,124 19 Amort & Depl of Producing Nat Gas Land/Land Right 20 Amort of Underground Storage Land/Land Rights 21 Amort of Other Utility Plant 111,600,956 111,600,956 22 Total In Service (18 thru 21) 5,412,666,080 5,412,666,080 23 Leased to Others 24 Depreciation 25 Amortization and Depletion 26 Total Leased to Others (24 & 25) 27 Held for Future Use 28 Depreciation -4,148 -4,148 29 Amortization 30 Total Held for Future Use (28 & 29) -4,148 -4,148 31 Abandonment of Leases (Natural Gas) 32 Amort of Plant Acquisition Adj 181,679 181,679 33 Total Accum Prov (equals 14) (22,26,30,31,32) 5,412,843,611 5,412,843,611
FERC FORM NO. 1 (ED. 12-89) Page 200 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION. AMORTIZATION AND DEPLETION Gas Other (Specify) Other (Specify) Other (Specify) Common Line No. (d) (e) (f) (g) (h) 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. 12-89) Page 201 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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.
Line Description of item Balance Changes during Year No. Beginning of Year Additions (a) (b) (c) 1 Nuclear Fuel in process of Refinement, Conv, Enrichment & Fab (120.1) 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) 9 In Reactor (120.3) 10 SUBTOTAL (Total 8 & 9) 11 Spent Nuclear Fuel (120.4) 12 Nuclear Fuel Under Capital Leases (120.6) 13 (Less) Accum Prov for Amortization of Nuclear Fuel Assem (120.5) 14 TOTAL Nuclear Fuel Stock (Total 6, 10, 11, 12, less 13) 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 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157)
Changes during Year Balance Line Amortization Other Reductions (Explain in a footnote) End of Year No. (d) (e) (f) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22
FERC FORM NO. 1 (ED. 12-89) Page 203 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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 Balance Additions No. Beginning of Year (a) (b) (c) 1 1. INTANGIBLE PLANT 2 (301) Organization 133,394 3 (302) Franchises and Consents 15,259,243 4 (303) Miscellaneous Intangible Plant 208,820,116 54,501,339 5 TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4) 224,212,753 54,501,339 6 2. PRODUCTION PLANT 7 A. Steam Production Plant 8 (310) Land and Land Rights 12,363,468 9 (311) Structures and Improvements 396,657,288 5,181,653 10 (312) Boiler Plant Equipment 4,364,903,229 49,579,746 11 (313) Engines and Engine-Driven Generators 12 (314) Turbogenerator Units 451,752,987 4,701,898 13 (315) Accessory Electric Equipment 179,930,159 2,217,145 14 (316) Misc. Power Plant Equipment 80,465,958 1,255,011 15 (317) Asset Retirement Costs for Steam Production 88,590,982 2,219,407 16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15) 5,574,664,071 65,154,860 17 B. Nuclear Production Plant 18 (320) Land and Land Rights 19 (321) Structures and Improvements 20 (322) Reactor Plant Equipment 21 (323) Turbogenerator Units 22 (324) Accessory Electric Equipment 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 9,800,667 28 (331) Structures and Improvements 29,092,351 1,525,228 29 (332) Reservoirs, Dams, and Waterways 79,829,625 3,663,752 30 (333) Water Wheels, Turbines, and Generators 111,414,338 2,429,655 31 (334) Accessory Electric Equipment 24,695,162 2,161,807 32 (335) Misc. Power PLant Equipment 21,456,657 1,557,294 33 (336) Roads, Railroads, and Bridges 1,241,854 34 (337) Asset Retirement Costs for Hydraulic Production 2,682,605 35 TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34) 280,213,259 11,337,736 36 D. Other Production Plant 37 (340) Land and Land Rights 3,196,932 38 (341) Structures and Improvements 50,264,743 231,047 39 (342) Fuel Holders, Products, and Accessories 26,968,818 40 (343) Prime Movers 41 (344) Generators 502,770,070 6,282,895 42 (345) Accessory Electric Equipment 48,015,092 141,519 43 (346) Misc. Power Plant Equipment 37,303,922 294,098 44 (347) Asset Retirement Costs for Other Production 45 TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44) 668,519,577 6,949,559 46 TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45) 6,523,396,907 83,442,155
FERC FORM NO. 1 (REV. 12-05) Page 204 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued) Line Account Balance Additions No. Beginning of Year (a) (b) (c) 47 3. TRANSMISSION PLANT 48 (350) Land and Land Rights 187,020,568 14,462,768 49 (352) Structures and Improvements 98,399,822 21,916,838 50 (353) Station Equipment 1,650,756,489 228,181,728 51 (354) Towers and Fixtures 503,531,980 6,787,169 52 (355) Poles and Fixtures 454,672,331 35,310,590 53 (356) Overhead Conductors and Devices 663,830,139 37,515,926 54 (357) Underground Conduit 3,730,144 6,402,374 55 (358) Underground Conductors and Devices 20,497,576 3,091,626 56 (359) Roads and Trails 57 (359.1) Asset Retirement Costs for Transmission Plant 58 TOTAL Transmission Plant (Enter Total of lines 48 thru 57) 3,582,439,049 353,669,019 59 4. DISTRIBUTION PLANT 60 (360) Land and Land Rights 70,026,026 1,353,115 61 (361) Structures and Improvements 54,535,856 6,903,943 62 (362) Station Equipment 635,719,892 38,477,535 63 (363) Storage Battery Equipment 5,402,895 8,277 64 (364) Poles, Towers, and Fixtures 795,611,593 48,229,050 65 (365) Overhead Conductors and Devices 960,748,945 120,686,569 66 (366) Underground Conduit 128,793,771 11,479,666 67 (367) Underground Conductors and Devices 306,540,691 9,231,695 68 (368) Line Transformers 619,392,911 22,334,607 69 (369) Services 351,928,802 13,214,020 70 (370) Meters 179,351,847 38,886,478 71 (371) Installations on Customer Premises 61,071,280 4,377,216 72 (372) Leased Property on Customer Premises 771 73 (373) Street Lighting and Signal Systems 29,890,004 1,440,704 74 (374) Asset Retirement Costs for Distribution Plant 3,069 75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74) 4,199,018,353 316,622,875 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) 85 6. GENERAL PLANT 86 (389) Land and Land Rights 15,224,417 87 (390) Structures and Improvements 149,785,873 3,909,099 88 (391) Office Furniture and Equipment 11,758,031 72,268 89 (392) Transportation Equipment 8,674 90 (393) Stores Equipment 1,960,487 86,109 91 (394) Tools, Shop and Garage Equipment 38,152,482 1,998,228 92 (395) Laboratory Equipment 3,166,290 48,105 93 (396) Power Operated Equipment 94 (397) Communication Equipment 70,281,638 31,127,744 95 (398) Miscellaneous Equipment 7,169,385 468,208 96 SUBTOTAL (Enter Total of lines 86 thru 95) 297,507,277 37,709,761 97 (399) Other Tangible Property 98 (399.1) Asset Retirement Costs for General Plant 1,204,128 99 TOTAL General Plant (Enter Total of lines 96, 97 and 98) 298,711,405 37,709,761 100 TOTAL (Accounts 101 and 106) 14,827,778,467 845,945,149 101 (102) Electric Plant Purchased (See Instr. 8) 102 (Less) (102) Electric Plant Sold (See Instr. 8) 103 (103) Experimental Plant Unclassified 104 TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103) 14,827,778,467 845,945,149
FERC FORM NO. 1 (REV. 12-05) Page 206 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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 End of Year (d) (e) (f) (g) No. 1 133,394 2 15,259,243 3 29,428,379 233,893,076 4 29,428,379 249,285,713 5 6 7 12,363,468 8 1,015,425 400,823,516 9 9,372,684 4,405,110,291 10 11 3,102,770 453,352,115 12 661,073 181,486,231 13 60,131 81,660,838 14 90,810,389 15 14,212,083 5,625,606,848 16 17 18 19 20 21 22 23 24 25 26 28 9,800,639 27 17,779 30,599,800 28 615,382 82,877,995 29 101,539 113,742,454 30 885,786 25,971,183 31 7,975 23,005,976 32 1,241,854 33 2,682,605 34 1,628,489 289,922,506 35 36 3,196,932 37 65,407 50,430,383 38 26,968,818 39 40 207,887 508,845,078 41 77,115 48,079,496 42 183,125 37,414,895 43 44 533,534 674,935,602 45 16,374,106 6,590,464,956 46
FERC FORM NO. 1 (REV. 12-05) Page 205 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued) Retirements Adjustments Transfers Balance at Line End of Year (d) (e) (f) (g) No. 47 681 -7,468 201,475,187 48 987,569 -1,141,174 118,187,917 49 23,742,076 -666,770 1,854,529,371 50 1,526,674 508,792,475 51 7,077,360 482,905,561 52 2,087,242 699,258,823 53 10,132,518 54 23,589,202 55 56 57 35,421,602 -1,815,412 3,898,871,054 58 59 143,359 978,878 72,214,660 60 344,695 1,141,174 62,236,278 61 3,603,758 666,770 671,260,439 62 5,411,172 63 4,983,465 838,857,178 64 6,465,578 1,074,969,936 65 89,242 140,184,195 66 611,167 315,161,219 67 8,086,744 633,640,774 68 2,553,999 362,588,823 69 25,571,881 192,666,444 70 3,014,063 62,434,433 71 771 72 363,182 30,967,526 73 3,069 74 55,831,133 2,786,822 4,462,596,917 75 76 77 78 79 80 81 82 83 84 85 15,224,417 86 467,585 153,227,387 87 11,830,299 88 8,674 89 2,046,596 90 40,150,710 91 118,260 3,096,135 92 93 5,291,843 96,117,539 94 46,792 7,590,801 95 5,924,480 329,292,558 96 97 1,204,128 98 5,924,480 330,496,686 99 142,979,700 971,410 15,531,715,326 100 101 102 103 142,979,700 971,410 15,531,715,326 104
FERC FORM NO. 1 (REV. 12-05) Page 207 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 FOOTNOTE DATA
Schedule Page: 204 Line No.: 43 Column: g Amounts are reflected in account 34600 because, as of this reporting, the FERC Form 1 application has not been updated to include a reporting line for 34800 assets separate from 34600 assets.
Schedule Page: 204 Line No.: 49 Column: g The investment and related accumulated depreciation in Generation Step-Up Units (GSUs) in plant accounts 352-353 included in APCo's generation formula rates are identified by a query of the plant accounting system.
Schedule Page: 204 Line No.: 50 Column: g Per FERC Docket Nos. RM11-24-000 and AD10-13-000 Order No. 784- Accounting and Financial Reporting for New Electric Storage Technologies - In compliance with this order, in September, 2013, Appalachian Power Company transferred $3,054,157.23 out of account 35300 - Station Equipment into 35100 - Electric Storage Batteries. Amounts are reflected in account 35300 because, as of this reporting, the FERC Form 1 application has not been updated to include a reporting line for 35100 assets separate from 35300 assets.
FERC 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) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / ELECTRIC PLANT LEASED TO OTHERS (Account 104)
Line Name of Lessee Expiration (Designate associated companies Description of Commission Date of Balance at No. with a double asterisk) Property Leased Authorization Lease End of Year (a) (b) (c) (d) (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 46
47 TOTAL
FERC FORM NO. 1 (ED. 12-95) Page 213 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company 2020/Q4 (2) A Resubmission / / End of ELECTRIC PLANT HELD FOR FUTURE USE (Account 105) 1. Report separately each property held for future use at end of the year having an original cost of $250,000 or more. Group other items of property held for future use. 2. For property having an original cost of $250,000 or more previously used in utility operations, now held for future use, give in column (a), in addition to other required information, the date that utility use of such property was discontinued, and the date the original cost was transferred to Account 105. Line Description and Location Date Originally IncludedDate Expected to be used Balance at No. Of Property in This Account in Utility Service End of Year (a) (b) (c) (d) 1 Land and Rights: 2 3 Amos-Gavin 765KV Comm Solvents Tract Land, WV (2639) 9/23/74 256,070 4 5 John E. Amos Fly Ash Area 3, Putnam Co., WV - approx 6/30/73 287,901 6 132.65 acres of land (0745) 7 8 Shadwell 69KV Substation, Roanoke County, VA 8/1/09 2021 431,124 9 10.637 acres (7662) 10 11 Sheridan 69KV Substation, Lincoln County, WV 11/1/15 2021 327,042 12 4.947 acres (2041) 13 14 Bridge 69KV Substation, Kanawha County, WV 11/1/18 2021 536,487 15 .275 acres (3173) 16 17 18 19 20 Items under $250,000 1,897,194 21 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 3,735,818
FERC FORM NO. 1 (ED. 12-96) Page 214 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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.
Line Description of Project Construction work in progress - No. Electric (Account 107) (a) (b) 1 AM CCR/ELG Compliance 7,395,189 2 AM FGD Landfill Sequence 4-10 2,024,079 3 Amos 1&2 DSI Project 2,119,211 4 AMU1 SCR 4th Layer Catalyst 2,236,586 5 AP/Network Risk Mit: Roanoke 1,188,585 6 APCo - T Baseline Work 3,517,201 7 APCo D Supplemetal Work 1,043,704 8 APCO Distr Pre Eng Parent 2,565,775 9 APCo Distr Station Failure 1,342,372 10 APCo DISTR Work 2,412,623 11 APCo Distribution Work 2,456,753 12 APCO Next Generation Radio Sys 37,667,259 13 APCo T (Station) 7,203,620 14 APCo T Supplemental Work 3,716,377 15 APCo T Work 3,449,836 16 APCo T Work 2,994,300 17 APCo T Work 1,943,067 18 APCo T Work 1,113,834 19 APCo T Work (Supplemental) 1,241,266 20 APCo T-BlnktProj Under $3M 4,299,034 21 APCO Trans Pre Eng Parent 96,360,651 22 APCo Transmission Work 15,494,728 23 APCo Transmission Work 3,184,752 24 APCo Transmission Work 2,342,405 25 APCo VA Major Eq/ Spares-Trans 14,563,944 26 APCo VA Major Eq/Spares- Distr 2,025,991 27 APCO: 2020-2021 MW Upgrades 1,287,197 28 APCO: 2020 - 2022 RBB Grayson 1,952,006 29 APCo-D BlnktProj Under $3M 1,228,496 30 APCo-D Service Restoration Blk 1,473,320 31 APCo-D Small Cap Adds Blkt 1,558,520 32 APCO-D Telecom 2,558,985 33 APCo-T Work 1,381,754 34 APCO-Tranco Line Rebuild-T 2,035,561 35 Chemical to Capitol APCO 1,882,373 36 Corp Prgrm Billing - APCO Tran 1,272,756 37 D/AP/Capital Blanket - APCo 3,221,199 38 D/AP/Distribution Work 6,731,274 39 D/AP/TranscoRenewl&Refurb 1,261,753 40 Dist station Renew-Refurb VA 2,606,569 41 Ed-Ci-Apco-D Ast Imp 22,891,734 42 Ed-Ci-Apco-D Cust Serv 2,791,771
43 TOTAL 485,037,217
FERC FORM NO. 1 (ED. 12-87) Page 216 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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.
Line Description of Project Construction work in progress - No. Electric (Account 107) (a) (b) 1 Fieldale Station Project 13,399,074 2 GT 1B Adv. Gas Path Parts 5,985,413 3 LDH U#2 GENERATOR REWIND 1,729,676 4 LDH2 DISCHARGE RING CI 1,158,800 5 Milton-Transformer Upgrade 1,375,790 6 MT ELG/CCR Compliance 7,830,280 7 Purchase of Grundy SC 2,222,830 8 Roanoke, VA TOC 18,239,901 9 SMH U2 Replace Headgate 1,063,191 10 SS-CI-APCo-D GEN PLT 4,405,216 11 T/AP TRANS-TCOM Modernization 8,814,096 12 T/AP/Capital Blanket - APCo 6,742,952 13 T/AP/NERC Physical Security 13,743,452 14 T/AP/Roanoke to Kingsport Tele 1,569,804 15 T/AP/Sheridan Trans CI 1,126,405 16 T/AP/Telecom Modernization Pro 4,954,185 17 Tams Mtn APCO-T Work 3,255,097 18 Teays Valley SC Land Purchase 1,163,470 19 Trans line Renew-Refurb WV, VA 1,481,978 20 Trans statn Renew-Refurb WV-VA 15,471,966 21 Transmission Asset Health/VA,W 1,085,108 22 Trinity - Station Work 2,502,833 23 U3 IP ROTOR & CYLINDER REFURBI 1,022,432 24 VA Brkr Rplc DSta Parent 2019 1,351,406 25 West Virginia Uphill Widen CI 2,026,789 26 Wo 020749999 8,206,655 27 WS-CI-APCo-G PPB 39,044,424 28 Other Minor Projects under $1,000,000 32,025,584 29 30 31 32 33 34 35 36 37 38 39 40 41 42
43 TOTAL 485,037,217
FERC FORM NO. 1 (ED. 12-87) Page 216.1 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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.
Section A. Balances and Changes During Year Line Item Total Electric Plant in Electric Plant Held Electric Plant (c+d+e) Service for Future Use Leased to Others No. (a) (b) (c) (d) (e)
1 Balance Beginning of Year 4,937,289,018 4,937,293,166 -4,148 2 Depreciation Provisions for Year, Charged to 3 (403) Depreciation Expense 509,849,935 509,849,935 4 (403.1) Depreciation Expense for Asset 2,978,914 2,978,914 Retirement Costs 5 (413) Exp. of Elec. Plt. Leas. to Others 6 Transportation Expenses-Clearing 7 Other Clearing Accounts 609,068 609,068 8 Other Accounts (Specify, details in footnote): -350,671 -350,671 9 10 TOTAL Deprec. Prov for Year (Enter Total of 513,087,246 513,087,246 lines 3 thru 9) 11 Net Charges for Plant Retired: 12 Book Cost of Plant Retired 113,551,321 113,551,321 13 Cost of Removal 47,270,797 47,270,797 14 Salvage (Credit) 11,506,830 11,506,830 15 TOTAL Net Chrgs. for Plant Ret. (Enter Total 149,315,288 149,315,288 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, 5,301,060,976 5,301,065,124 -4,148 10, 15, 16, and 18) Section B. Balances at End of Year According to Functional Classification 20 Steam Production 2,521,348,460 2,521,348,460 21 Nuclear Production 22 Hydraulic Production-Conventional 74,086,010 74,086,010 23 Hydraulic Production-Pumped Storage 84,294,978 84,294,978 24 Other Production 235,452,561 235,452,561 25 Transmission 762,867,121 762,871,269 -4,148 26 Distribution 1,532,247,333 1,532,247,333 27 Regional Transmission and Market Operation 28 General 90,764,513 90,764,513 29 TOTAL (Enter Total of lines 20 thru 28) 5,301,060,976 5,301,065,124 -4,148
FERC FORM NO. 1 (REV. 12-05) Page 219 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 FOOTNOTE DATA
Schedule Page: 219 Line No.: 8 Column: c FERC Generation Wholesale Amortization-Clinch River ARO ($32,124) FERC KGPCo Wholesale Amortiation-Clinch River ARO ($50,700) FERC Generation Wholesale Expense-1823377 VA Plants ($103,875) FERC KGPCo Wholesale Expense-1823377 VA Plants ($163,972) ($350,671)
Schedule Page: 219 Line No.: 13 Column: c Includes ($3,461,214) of removal cost in retirement work in progress (RWIP). Schedule Page: 219 Line No.: 14 Column: c Includes $10,793,203 of salvage in retirement work in progress (RWIP).
FERC 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) Appalachian Power Company 2020/Q4 (2) A Resubmission / / End of INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) 1. Report below investments in Accounts 123.1, investments in Subsidiary Companies. 2. Provide a subheading for each company and List there under the information called for below. Sub - TOTAL by company and give a TOTAL in columns (e),(f),(g) and (h) (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 current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity date, and specifying whether note is a renewal. 3. Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for Account 418.1.
Line Description of Investment Date Acquired Date Of Amount of Investment at Maturity Beginning of Year No. (a) (b) (c) (d) 1 Central Appalachian Coal Company 2 SEC File 70-1841, 6-18-48 3 SEC File 70-2749, 8.14-50 4 3,000 shares common stock 3,000 5 Capital Contributions 10/09/90 449,990 6 Undistributed earnings/losses 7 and dividends 194,057 8 9 SUBTOTAL 647,047 10 11 Central Coal Company 12 SEC File 70-1770, 4-30-48 13 1,500 shares common stock 1,500 14 Capital Contributions 602,368 15 Investment in Central Coal Company 16 Undistributed earnings/losses 17 and dividends 18 19 SUBTOTAL 603,868 20 21 Southern Appalachian Coal Company 22 SEC File 70-5144, 3-23-72 23 6,950 shares common stock 6,950 24 Capital Contributions 25 Investment in Premium on Common Stock 900,000 26 Undistributed earnings/losses 27 and dividends 690,462 28 29 SUBTOTAL 1,597,412 30 31 Cedar Coal Company 32 SEC File 70-5470, 4-30-74 33 2,000 shares common stock 04/10/74 200,000 34 Capital Contributions 4,868,403 35 Investment in Subsidiary AOCI -560,216 36 Undistributed earnings/losses 37 and dividends -2,483,074 38 39 SUBTOTAL 2,025,113 40 41
42 Total Cost of Account 123.1 $ 0 TOTAL 4,873,440
FERC FORM NO. 1 (ED. 12-89) Page 224 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company 2020/Q4 (2) A Resubmission / / End of INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) (Continued) 4. For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee and purpose of the pledge. 5. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission, date of authorization, and case or docket number. 6. Report column (f) interest and dividend revenues form investments, including such revenues form securities disposed of during the year. 7. 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 in column (f). 8. Report on Line 42, column (a) the TOTAL cost of Account 123.1 Equity in Subsidiary Revenues for Year Amount of Investment at Gain or Loss from Investment Line Earnings of Year End of Year Disposed of (e) (f) (g) (h) No. 1 2 3 3,000 4 449,990 5 6 194,057 7 8 647,047 9 10 11 12 1,500 13 602,368 14 15 16 17 18 603,868 19 20 21 22 6,950 23 24 900,000 25 26 690,462 27 28 1,597,412 29 30 31 32 200,000 33 4,868,403 34 384,409 -175,807 35 36 -2,483,074 37 38 384,409 2,409,522 39 40 41
384,409 5,257,849 42 FERC FORM NO. 1 (ED. 12-89) Page 225 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company 2020/Q4 (2) A Resubmission / / End of 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) 142,401,216 182,954,925 Electric 2 Fuel Stock Expenses Undistributed (Account 152) 7,344,137 10,651,652 Electric 3 Residuals and Extracted Products (Account 153) 4,821 Electric 4 Plant Materials and Operating Supplies (Account 154) Electric 5 Assigned to - Construction (Estimated) 63,891,288 52,071,664 Electric 6 Assigned to - Operations and Maintenance 7 Production Plant (Estimated) 39,902,812 45,758,604 Electric 8 Transmission Plant (Estimated) 51,574 67,643 Electric 9 Distribution Plant (Estimated) 678,703 1,009,953 Electric 10 Regional Transmission and Market Operation Plant (Estimated) 11 Assigned to - Other (provide details in footnote) 267,708 297,940 Electric 12 TOTAL Account 154 (Enter Total of lines 5 thru 11) 104,792,085 99,205,804 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) 17 18 19 20 TOTAL Materials and Supplies (Per Balance Sheet) 254,537,438 292,817,202
FERC FORM NO. 1 (REV. 12-05) Page 227 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 FOOTNOTE DATA
Schedule Page: 227 Line No.: 11 Column: b Assigned to - Other includes Customer Account, Administrative, and General Expenses. Schedule Page: 227 Line No.: 11 Column: c Assigned to - Other includes Customer Account, Administrative, and General Expenses.
FERC 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) Appalachian Power Company 2020/Q4 (2) A Resubmission / / End of 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 SO2 Allowances Inventory Current Year 2021 No. (Account 158.1) No. Amt. No. Amt. (a) (b) (c) (d) (e) 1 Balance-Beginning of Year 1,186,920.00 22,509,880 185,894.00 2 3 Acquired During Year: 4 Issued (Less Withheld Allow) 61,581.00 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 13,650.00 163,031 19 Other: 20 21 Cost of Sales/Transfers: 22 Consent Decree Surrenders 138,982.00 147,823.00 23 Fathom Energy LLC 30,000.00 24 25 26 27 28 Total 168,982.00 147,823.00 29 Balance-End of Year 1,065,869.00 22,346,849 38,071.00 30 31 Sales: 32 Net Sales Proceeds(Assoc. Co.) 33 Net Sales Proceeds (Other) 29,250 34 Gains 29,250 35 Losses Allowances Withheld (Acct 158.2) 36 Balance-Beginning of Year 1,746.00 1,746.00 37 Add: Withheld by EPA 38 Deduct: Returned by EPA 39 Cost of Sales 1,746.00 40 Balance-End of Year 1,746.00 41 42 Sales: 43 Net Sales Proceeds (Assoc. Co.) 231 44 Net Sales Proceeds (Other) 231 45 Gains 46 Losses
FERC FORM NO. 1 (ED. 12-95) Page 228a Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company 2020/Q4 (2) A Resubmission / / End of Allowances (Accounts 158.1 and 158.2) (Continued) 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.
2022 2023 Future Years Totals Line No. Amt. No. Amt. No. Amt. No. Amt. No. (f) (g) (h) (i) (j) (k) (l) (m) 185,894.00 185,894.00 4,207,520.00 5,952,122.00 22,509,880 1 2 3 186,300.00 247,881.00 4 5 6 7 8 9 10 11 12 13 14 15 16 17 13,650.00 163,031 18 19 20 21 286,805.00 22 30,000.00 23 24 25 26 27 316,805.00 28 185,894.00 185,894.00 4,393,820.00 5,869,548.00 22,346,849 29 30 31 32 29,250 33 29,250 34 35
1,746.00 1,746.00 95,375.00 102,359.00 36 3,491.00 3,491.00 37 38 1,745.00 3,491.00 39 1,746.00 1,746.00 97,121.00 102,359.00 40 41 42 231 43 231 44 45 46
FERC FORM NO. 1 (ED. 12-95) Page 229a Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company 2020/Q4 (2) A Resubmission / / End of 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 2021 No. (Account 158.1) No. Amt. No. Amt. (a) (b) (c) (d) (e) 1 Balance-Beginning of Year 12,266.00 22,771.00 2 3 Acquired During Year: 4 Issued (Less Withheld Allow) 43,454.00 5 Returned by EPA 6 7 8 Purchases/Transfers: 9 Regional Greenhouse Gas 10,000.00 74,100 10 Other 10.00 1,100 11 12 13 14 15 Total 10,010.00 75,200 16 17 Relinquished During Year: 18 Charges to Account 509 11,980.00 19 Other: 20 21 Cost of Sales/Transfers: 22 Associated Electric Coop. 550.00 23 Fathom Energy LLC 300.00 24 Mississippi Power Company 200.00 25 Macquarie Energy LLC 100.00 26 27 28 Total 1,150.00 29 Balance-End of Year 52,600.00 75,200 22,771.00 30 31 Sales: 32 Net Sales Proceeds(Assoc. Co.) 33 Net Sales Proceeds (Other) 72,700 34 Gains 72,700 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 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company 2020/Q4 (2) A Resubmission / / End of Allowances (Accounts 158.1 and 158.2) (Continued) 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.
2022 2023 Future Years Totals Line No. Amt. No. Amt. No. Amt. No. Amt. No. (f) (g) (h) (i) (j) (k) (l) (m) 22,058.00 17,129.00 74,224.00 1 2 3 4,929.00 22,055.00 70,438.00 4 5 6 7 8 10,000.00 74,100 9 10.00 1,100 10 11 12 13 14 10,010.00 75,200 15 16 17 11,980.00 18 19 20 21 550.00 22 300.00 23 200.00 24 100.00 25 26 27 1,150.00 28 22,058.00 22,058.00 22,055.00 141,542.00 75,200 29 30 31 32 72,700 33 72,700 34 35
36 37 38 39 40 41 42 43 44 45 46
FERC FORM NO. 1 (ED. 12-95) Page 229b Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 FOOTNOTE DATA
Schedule Page: 229 Line No.: 29 Column: c NOX has no book value associated with the quantity. $75,200 is for 10,010 units of CO2, that was purchased in December 2020.
FERC 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) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / EXTRAORDINARY PROPERTY LOSSES (Account 182.1) Line Description of Extraordinary Loss Total Losses WRITTEN OFF DURING YEAR Balance at No. [Include in the description the date of Amount Recognised Commission Authorization to use Acc 182.1 of Loss During Year Account End of Year and period of amortization (mo, yr to mo, yr).] Charged Amount (a) (b) (c) (d) (e) (f) 1 Bluefield Office Building 365,177 24,345 6,087 2 3 Glen Lyn Unit 6 5,703,621 173,574 4,358,028 4 5 Kanawha Plant 27,432,795 1,086,280 21,655,990 6 7 Sporn Plant 10,478,046 458,519 8,238,108 8 9 Clinch River Units 1-3 58,709,555 2,181,948 48,227,256 10 11 12 13 14 15 16 17 18 19
20 TOTAL 102,689,194 3,924,666 82,485,469
FERC FORM NO. 1 (ED. 12-88) Page 230a Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.2) Line Description of Unrecovered Plant Total Costs WRITTEN OFF DURING YEAR Balance at No. and Regulatory Study Costs [Include Amount Recognised in the description of costs, the date of of Charges During Year Account Amount End of Year Commission Authorization to use Acc 182.2 Charged and period of amortization (mo, yr to mo, yr)] (a) (b) (c) (d) (e) (f) 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
FERC FORM NO. 1 (ED. 12-88) Page 230b Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 FOOTNOTE DATA
Schedule Page: 230 Line No.: 1 Column: a Authorized by the West Virginia commission on April 10, 2006. Amortization period: April 2006 to March 2021. Schedule Page: 230 Line No.: 3 Column: a Authorized by the West Virginia commission on May 26, 2015. Amortization period: June 2015 to July 2032. Schedule Page: 230 Line No.: 5 Column: a Authorized by the West Virginia commission on May 26, 2015. Amortization period: June 2015 to July 2041. Schedule Page: 230 Line No.: 7 Column: a Authorized by the West Virginia commission on May 26, 2015. Amortization period: June 2015 to February 2040. Schedule Page: 230 Line No.: 9 Column: a Clinch River Units 1 & 2 were authorized by the West Virginia commission on May 26, 2015. Amortization period: October 2015 to November 2052. Coal Blending Assets amortized through June 2048. Clinch River Unit 3 was authorized by the West Virginia commission on May 26, 2015. Amortization period: June 2015 to January 2040. The amortization period for all Clinch River units was updated to end in December 2040 by the West Virginia commission on February 27, 2019.
FERC 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) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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 Costs Incurred During Account Credited No. Received During Description Period Account Charged the Period With Reimbursement (a) (b) (c) (d) (e) 1 Transmission Studies 2 AG1-316 Rustburg 138kV 243 186 93 186 3 AG1-468 Martinsville-Figsboro 34.5 1,627 186 752 186 4 AG1-508 Independence 69kV 933 186 435 186 5 AG1-509 Jubal Early 138kV 506 186 208 186 6 AG1-540 Berry Hill 138kV 242 186 92 186 7 CITY OF BEDFORD - DELIVERY POINT 84 186 186 8 PJM - #AC2-180 ( 7) 186 9 PJM - #AD1-017 495 186 10 PJM - #AD1-102 15,201 186 8,263 186 11 PJM - #AD1-102 ( 8) 12 PJM - #AD2-001 14 186 13 PJM - #AD2-022 1,384 186 1,346 186 14 PJM - #AD2-022 11,658 186 3,462 186 15 PJM - #AD2-178 71,140 186 41,107 186 16 PJM - #AD2-178 485 186 511 186 17 PJM - #AD2-179 34,349 186 26,870 186 18 PJM - #AD2-179 534 186 604 186 19 PJM - #AE1-064 ( 134) 186 186 20 PJM - #AE1-100 ( 82) 186 21 Generation Studies 22 Dresden Plant 68,229 500 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / Transmission Service and Generation Interconnection Study Costs (continued)
Line Reimbursements Costs Incurred During Account Credited No. Received During Description Period Account Charged the Period With Reimbursement (a) (b) (c) (d) (e) 1 Transmission Studies 2 PJM - #AE1-108 ( 108) 186 3 PJM - #AE1-121 19,027 186 4,212 186 4 PJM - #AE1-121 ( 95) 186 5 PJM - #AE1-130 2,387 186 2,455 186 6 PJM - #AE1-176 286 186 271 186 7 PJM - #AE1-178 ( 172) 186 8 PJM - #AE1-212 22,230 186 9,911 186 9 PJM - #AE1-212 32 186 102 186 10 PJM - #AE1-250 2,265 186 2,124 186 11 PJM - #AE1-250 145 186 345 186 12 PJM - #AE2-047 31,270 186 11,850 186 13 PJM - #AE2-047 789 186 1,318 186 14 PJM - #AE2-047 868 186 811 186 15 PJM - #AE2-140 11,134 186 3,846 186 16 PJM - #AE2-140 1,423 186 2,727 186 17 PJM - #AE2-140 1,757 186 1,388 186 18 PJM - #AE2-159 59 186 19 PJM - #AE2-160 ( 120) 186 20 PJM - #AE2-166 26,841 186 10,072 186 21 Generation Studies 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.1 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / Transmission Service and Generation Interconnection Study Costs (continued)
Line Reimbursements Costs Incurred During Account Credited No. Received During Description Period Account Charged the Period With Reimbursement (a) (b) (c) (d) (e) 1 Transmission Studies 2 PJM - #AE2-166 744 186 1,295 186 3 PJM - #AE2-166 746 186 676 186 4 PJM - #AE2-185 1,356 186 1,509 186 5 PJM - #AE2-187 448 186 707 186 6 PJM - #AE2-196 ( 391) 186 7 PJM - #AE2-245 34 186 66 186 8 PJM - #AE2-245 9 PJM - #AE2-280 3,367 186 1,130 186 10 PJM - #AE2-280 1,530 186 2,364 186 11 PJM - #AE2-280 667 186 604 186 12 PJM - #AE2-283 284 186 567 186 13 PJM - #AE2-291 331 186 331 186 14 PJM - #AE2-292 1,047 186 1,218 186 15 PJM - #AE2-326 1,618 186 494 186 16 PJM - #AE2-326 272 186 17 PJM - #AF1-049 2,726 186 2,575 186 18 PJM - #AF1-312 272 186 19 PJM - #AF1-323 1,894 186 2,374 186 20 PJM - #AF1-323 2,094 186 1,990 186 21 Generation Studies 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.2 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / Transmission Service and Generation Interconnection Study Costs (continued)
Line Reimbursements Costs Incurred During Account Credited No. Received During Description Period Account Charged the Period With Reimbursement (a) (b) (c) (d) (e) 1 Transmission Studies 2 PJM - #AF2-105 4,401 186 4,140 186 3 PJM - #AF2-106 5,018 186 4,643 186 4 PJM - #AF2-106 72 186 46 186 5 PJM - #AF2-107 2,289 186 2,156 186 6 PJM - #AF2-107 72 186 46 186 7 PJM - #AF2-220 3,179 186 2,960 186 8 PJM - #AF2-291 2,306 186 2,158 186 9 PJM - #AF2-291 72 186 46 186 10 PJM - #AF2-302 2,079 186 1,911 186 11 PJM - #AF2-302 72 186 46 186 12 PJM - #AF2-382 2,436 186 2,269 186 13 PJM - #AF2-382 165 186 46 186 14 PJM - #AG1-022 1,296 186 888 186 15 PJM - #AG1-089 1,974 186 1,262 186 16 PJM - #AG1-091 726 186 17 PJM - #AG1-092 772 186 18 PJM - #AG1-123 1,008 186 481 186 19 PJM - #AG1-124 698 186 304 186 20 PJM - #AG1-136 1,082 186 577 186 21 Generation Studies 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.3 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / Transmission Service and Generation Interconnection Study Costs (continued)
Line Reimbursements Costs Incurred During Account Credited No. Received During Description Period Account Charged the Period With Reimbursement (a) (b) (c) (d) (e) 1 Transmission Studies 2 PJM - #AG1-155 1,820 186 920 186 3 PJM - #AG1-194 753 186 357 186 4 PJM - #AG1-219 846 186 357 186 5 PJM - #AG1-240 1,198 186 667 186 6 PJM - #AG1-311 1,652 186 959 186 7 PJM - #AG1-314 926 186 522 186 8 PJM - #AG1-426 1,082 186 540 186 9 PJM - #AG1-494 652 186 251 186 10 PJM - #AG1-528 1,518 186 800 186 11 PJM - AF1-173 GRETNA 674 186 668 186 12 PJM AC1-122 & 123 SMITH 32,964 186 53,273 186 13 PJM AC2-123 JACKSONS 5,371 186 14 15 16 17 18 19 20 21 Generation Studies 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.4 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) 2020/Q4 Appalachian Power Company End of (2) A Resubmission / / 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 Balance at Debits CREDITS Balance at end of No. Other Regulatory Assets Beginning of Written off During Written off During Current Quarter/Year Current the Quarter/Year the Period Quarter/Year Account Charged Amount (a) (b) (c) (d) (e) (f) 1 Under Recovery of PJM True-Up 1,198,387 1,676,282 Footnote 1,680,375 1,194,294 2 3 SFAS 112 Postemployment Benefits 15,892,808 228 2,357,542 13,535,266 4 - Rate Order: WV PSC Case 14-1152-E-42T 5 6 Demand Side Management Under Recovery 6,910,431 532,117 Footnote 695,576 6,746,972 7 - Rate Order: WV Public Service Commission 8 - Case No: 10-0261-E-GI 9 - Case No: WV PSC Case 15-0301-E-GI 10 11 Unrealized Loss on Forward Commitments 1,141,940 Footnote 6,377,219 -5,235,279 12 13 Netting of Trading Activities related to 9,573,356 254 4,338,077 5,235,279 14 Unrealized Gains/Losses on Forward 15 Commitments between Regulated Assets/Liabilities 16 17 Environmental Compliance Costs 196,781 196,781 18 - Rate Orders: VA Code Section 56-582B (vi) 19 - VA SCC PUE-2005-00056 20 21 Carrying Chgs-Capital Environmental Compliance Csts ( 100,873) -100,873 22 - Rate Orders: VA Code Section 56-582B (vi) 23 - VA SCC PUE-2005-00056 24 25 Capital Environmental Equity Costs ( 12,017) -12,017 26 - Rate Orders: VA Code Section 56-582B (vi) 27 - VA SCC PUE-2005-00056 28 29 Defd System Reliability Costs 75,018 75,018 30 - Rate Orders: VA Code Section 56-582B (vi) 31 - VA SCC PUE-2005-00056 32 33 Equity Costs - Capital Reliability ( 44,977) -44,977 34 - Rate Orders: VA Code Section 56-582B (vi) 35 - VA SCC PUE-2005-00056 36 37 Defd Carrying Charges - Reliability Capital 54,445 54,445 38 - Rate Orders: VA Code Section 56-582B (vi) 39 - VA SCC PUE-2005-00056 40 41 Unrecovered Fuel Cost - VA 36,786,151 49,683,506 501 83,138,732 3,330,925 42 43 Unrecovered Fuel Cost - WV 9,964,919 31,496,848 254/501 37,198,552 4,263,215
44 TOTAL 695,306,657 645,274,706 456,996,353 883,585,010
FERC FORM NO. 1/3-Q (REV. 02-04) Page 232 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) 2020/Q4 Appalachian Power Company End of (2) A Resubmission / / 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 Balance at Debits CREDITS Balance at end of No. Other Regulatory Assets Beginning of Written off During Written off During Current Quarter/Year Current the Quarter/Year the Period Quarter/Year Account Charged Amount (a) (b) (c) (d) (e) (f) 1 2 SFAS 158 Employers' Accounting for Defined Benefit 160,827,250 148,259,072 Footnote 194,733,190 114,353,132 3 Pension and Other Postretirement Plans 4 5 Mtr Carbon Capture and Storage 263,001 506 263,001 6 - Rate Orders: WV PSC Case 14-1152-E-42T 7 - Amortization Period: 06/2015 to 05/2020 8 - 8/18 WV Tax Reform Settlement 9 10 VA Demand Response Program 5,755,440 1,024,393 442,908 2,729,374 4,050,459 11 - Rate Order: VA SCC PUE-2011-0001 12 13 Dresden Operating Costs - VA 5,068,758 1,962,730 403 3,940,842 3,090,646 14 - Rate Order: VA SCC PUE-2011-00036 15 16 SFAS 106 Medicare Subsidy 2,944,092 926 588,819 2,355,273 17 - Amortization period - 1/2013 to 12/2024 18 19 SFAS 109 Deferred Federal Income Tax 102,547,573 31,229,811 282/283 35,700,392 98,076,992 20 21 SFAS 109 Deferred State Income Tax 259,884,682 7,763,225 282/283 9,218,839 258,429,068 22 23 Carbon Capture and Storage Project FEED Study Costs 444,416 506 183,896 260,520 24 - Rate Order: WV PSC Case 13-0467-E-GI 25 26 WV Vegetation Management Program Costs 43,606,337 13,080,060 593 11,317,569 45,368,828 27 - Rate Order: WV PSC Case 13-0557-E-P 28 - Rate Order: WV PSC Case 14-1152-E-42T 29 30 NBV ARO's Retired Plants 30,109,657 Footnote 350,671 29,758,986 31 - Rate Order: VA SCC PUE-2014-0026 32 - Rate Order: WV PSC 14-1151-E-D 33 34 M&S Retiring Plants 472,104 12,108 Footnote 48,432 435,780 35 - Rate Order: VA SCC PUE-2014-0026 36 - Rate Order: WV PSC 14-1151-E-D 37 38 Unrecovered Fuel - Common Wealth Virginia 740,268 532,706 254/501 1,006,945 266,029 39 - Per Agreement with Commonwealth 40 of Virginia. Effective June 4, 2015. 41 42 Recoverable Coal Company Write Off 329,167 506 329,167 43 - Rate Order: WV PSC 14-1152-E-42-T
44 TOTAL 695,306,657 645,274,706 456,996,353 883,585,010
FERC FORM NO. 1/3-Q (REV. 02-04) Page 232.1 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) 2020/Q4 Appalachian Power Company End of (2) A Resubmission / / 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 Balance at Debits CREDITS Balance at end of No. Other Regulatory Assets Beginning of Written off During Written off During Current Quarter/Year Current the Quarter/Year the Period Quarter/Year Account Charged Amount (a) (b) (c) (d) (e) (f) 1 2 WV Delayed Base Rate Increase 570,865 570,865 3 - Case No. 16-0179-E-T-PC 4 - Amortization Period: 7/2016 - 6/2018 5 6 IGCC Pre Construction Cost 154,134 506 154,134 7 - Rate Order: WV PSC 14-1152-E-42-T 8 - 8/18 WV Tax Reform Settlement 9 10 WV Air Quality Permit Fees 514,249 506 123,419 390,830 11 - Rate Order: WV 15-0722-E-P 12 13 VA EE-RAC Efficient Products 164,987 164,987 14 - Case No. PUE-2014-00039 15 16 VA EE-RAC C&I Prescriptive 1,090,548 1,090,548 17 - Case No. PUE-2014-00039 18 19 WV EE/DR - Company Funded 5,620,756 152,109 Footnote 1,071,717 4,701,148 20 - Case No. PUE-2014-00039 21 22 Greenhat Default Contingency 199,613 Footnote 194,247 5,366 23 24 WV Deferred Rate Case Expenses 385,405 928 177,879 207,526 25 - WVPSC Case #18-0646-E-42T 26 - Amortization Period: 03/2019 - 02/2022 27 28 VA Renewable Energy Portfolio Standard 2,692,282 13,866,409 445 10,303,725 6,254,966 29 - VA SCC Case No. PUE-2009-00038 30 31 WV Felman Premium/Discount ENEC 13,764,060 254 16,349,757 -2,585,697 32 33 COVID-19 Costs 34 - WV General Order: WVPSC 262.4 35 - VA SCC Case No. PUR-2020-00074 6,991,310 Footnote 1,753,120 5,238,190 36 37 Carrying Chgs-COVID-19 Costs 38 - VA SCC Case No. PUR-2020-00074 97,972 431 18,314 79,658 39 40 Equity Carrying Chgs-COVID-19 Costs 8,289 431 41,930 -33,641 41 - VA SCC Case No. PUR-2020-00074 42 43 Glen Lyn Ash Pond ARO
44 TOTAL 695,306,657 645,274,706 456,996,353 883,585,010
FERC FORM NO. 1/3-Q (REV. 02-04) Page 232.2 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) 2020/Q4 Appalachian Power Company End of (2) A Resubmission / / 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 Balance at Debits CREDITS Balance at end of No. Other Regulatory Assets Beginning of Written off During Written off During Current Quarter/Year Current the Quarter/Year the Period Quarter/Year Account Charged Amount (a) (b) (c) (d) (e) (f) 1 - VA HB443 198,802,442 198,802,442 2 3 VA EE-RAC C&I Lighting 4 - VA SCC Case No. PUE-2014-0039 146,627 908 59,320 87,307 5 6 Carrying Chgs-VA Broadband Pilot 7 - VA SCC Case No. PUR-2019-00145 13,074 403 2,940 10,134 8 9 Equity Carrying Chgs-VA Broadband Pilot 10 - VA SCC Case No. PUR-2019-00145 1,229 403 5,530 -4,301 11 12 VA T-RAC Costs 13 - VA SCC Case No. PUE-2009-00031 36,282,563 566 17,522,396 18,760,167 14 15 2020 PJM Transmission True-up 16 - VA SCC Case No. PUR-2020-00015 12,012,226 456 505,597 11,506,629 17 - Amortization Period: 01/2022 - 12/2022 18 19 VA Retired Coal Plants 20 - VA SCC Case No. PUR-2020-00015 21 - Amortization Period: 01/2020 - 05/2025 48,957,692 403 9,038,343 39,919,349 22 23 VA E-RAC CCR Expenses 24 - VA SCC Case No. PUR-2020-00015 9,257,000 9,257,000 25 26 Major Storm Expense 27 - VA SCC Case No. PUR-2020-00015 6,953,550 593 3,476,775 3,476,775 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43
44 TOTAL 695,306,657 645,274,706 456,996,353 883,585,010
FERC FORM NO. 1/3-Q (REV. 02-04) Page 232.3 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 FOOTNOTE DATA
Schedule Page: 232 Line No.: 1 Column: d 234,242,456,447,229 Schedule Page: 232 Line No.: 6 Column: d 440,442,908 Schedule Page: 232 Line No.: 11 Column: d 244,254,175 Schedule Page: 232.1 Line No.: 2 Column: d 228,165,242,129 Schedule Page: 232.1 Line No.: 30 Column: d 411,403,244 Schedule Page: 232.1 Line No.: 34 Column: d 411,506,154 Schedule Page: 232.2 Line No.: 19 Column: d 440, 442, 908 Schedule Page: 232.2 Line No.: 22 Column: d 232, 253, 561, 566 Schedule Page: 232.2 Line No.: 35 Column: d 903, 904, 426, 506
FERC 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) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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.
Line Description of Miscellaneous Balance at Debits CREDITS Balance at No. Deferred Debits Beginning of Year Account End of Year Charged Amount (a) (b) (c) (d) (e) (f) 1 Property Taxes: 2 West Virginia 76,825,395 52,274,821 107,408 52,270,909 76,829,307 3 4 Ohio 2,473,075 1,976,830 107,408 2,473,075 1,976,830 5 6 Agency Fees - Factored A/R 2,418,044 26,126,433 184,426 25,825,040 2,719,437 7 8 Labor Accruals - Balance Sheet 17,903 75,627 183.152 92,865 665 9 10 Miscellaneous 59,670 88,054 Footnote 85,781 61,943 11 12 Prop. Taxes - Capital Leases: 13 West Virginia 85,576 654,731 408 653,322 86,985 14 15 Unamortized Credit Line Fees 482,898 711,498 431,234 705,187 489,209 16 Amortization through June 2022 17 18 Def Lease Assets - Non Taxable 426,154 902,396 143,184 1,180,491 148,059 19 20 Deferred Urea Expense 797,516 10,424,748 Footnote 10,229,038 993,226 21 22 VA Sales/Use Tax Surcharge -1,258,232 2,219,876 142 1,980,162 -1,018,518 23 24 Estimated Barging Bills 484,245 43,681,293 Footnote 43,909,139 256,399 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 1,424,230 2,410,889 Deferred Regulatory Comm. 48 Expenses (See pages 350 - 351) 49 TOTAL 84,236,474 84,954,431
FERC FORM NO. 1 (ED. 12-94) Page 233 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 FOOTNOTE DATA
Schedule Page: 233 Line No.: 10 Column: d 142,143,232,253,593,243,588 Schedule Page: 233 Line No.: 20 Column: d 142,232,154 Schedule Page: 233 Line No.: 24 Column: d 151,154,232,234
FERC 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) Appalachian Power Company End of 2020/Q4 (2) 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 Balance of Begining Balance at End No. of Year of Year (a) (b) (c) 1 Electric 2 Interest Expense Capitalized for Tax 50,481,095 51,506,694 3 Net Operating Loss and Tax Credit Carryforwards 4,987,603 1,633,254 4 DSIT Normalized 16,237,089 16,391,724 5 Accrued Book Removal Costs 63,037,782 66,976,322 6 Accrued Book ARO Expenses 23,303,239 65,742,850 7 Other 37,479,140 34,685,591 8 TOTAL Electric (Enter Total of lines 2 thru 7) 195,525,948 236,936,435 9 Gas 10 11 12 13 14 15 Other 16 TOTAL Gas (Enter Total of lines 10 thru 15 17 Other (Specify) 284,617,277 257,907,218 18 TOTAL (Acct 190) (Total of lines 8, 16 and 17) 480,143,225 494,843,653 Notes Line 17 Other - Detail Balance at Balance at Beginning of Year End of Year ------
Non-Utility 190.2 4,999,960 2,430,900 SFAS 109 280,138,850 256,441,653 SFAS 133 (521,533) (965,335)
------Total $ 284,617,277 $ 257,907,218 ======
Line 18 Reconciliation of details applicable to Account 190, Line 18, Columns (b) and (c):
Balance at Beginning of Year $ 480,143,225
(Less) Amounts Debited to: (a) Account 410.1 (91,952,318) (b) Account 410.2 (4,004,143) (c) 1823/254/282.1 (310,179,711)
(Plus) Amounts Credited to: (a) Account 411.1 99,947,698 (b) Account 411.2 1,435,083 (c) 1823/254/282.1 319,453,819
Balance at End of Year $ 494,843,653
FERC FORM NO. 1 (ED. 12-88) Page 234 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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.
Line Class and Series of Stock and Number of shares Par or Stated Call Price at No. Name of Stock Series Authorized by Charter Value per share End of Year
(a) (b) (c) (d) 1 Account 201 - Common Stock 2 Authorized: No Par Value 30,000,000 3 Outstanding: 4 No Par Value 5 Total Account 201 - Common Stock 30,000,000 6 7 Account 204 - Preferred Stock - None 8 Total Account 204 - Preferred Stock 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
FERC FORM NO. 1 (ED. 12-91) Page 250 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / CAPITAL STOCKS (Account 201 and 204) (Continued) 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 HELD BY RESPONDENT Line (Total amount outstanding without reduction No. for amounts held by respondent) AS REACQUIRED STOCK (Account 217) IN SINKING AND OTHER FUNDS Shares Amount Shares Cost Shares Amount (e) (f) (g) (h) (i) (j) 1 2 3 13,499,500 260,457,768 4 13,499,500 260,457,768 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
FERC FORM NO. 1 (ED. 12-88) Page 251 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A 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.
Line Item Amount No. (a) (b) 1 Account 208 - Donations Received From Stockholders 2 Contributions Received From Parent Company 3 Prior Years Contributions Received 1,825,984,502 4 5 6 Subtotal Account 208 - Donations Received From Stockholders 1,825,984,502 7 8 Account 209 - Reduction in Par or Stated Value of Capital Stock 9 Current Year 10 Subtotal Account 209 - Reduction in Par or Stated Value of Capital Stk 11 12 Account 210 - Gain on Resale or Cancellation of Reacquired Capital Stk 13 Balance Beginning of Year For All Series 433 14 Current Year Activity 15 Subtotal Account 210 - Gain On Resale or Cancel of Reacq Capital Stk 433 16 17 Account 211 - Miscellaneous Paid-In Capital 18 Balance Beginning of Year 2,642,015 19 Acquired and initial surplus as reduced by write-down of 20 utility plant to original cost prior to year 1947 21 22 Subtotal Account 211 - Miscellaneous Paid-In Capital 2,642,015 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39
40 TOTAL 1,828,626,950
FERC FORM NO. 1 (ED. 12-87) Page 253 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / CAPITAL STOCK EXPENSE (Account 214) 1. Report the balance at end of the year of discount on capital stock for each class and series of capital stock. 2. If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars (details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.
Line Class and Series of Stock Balance at End of Year No. (a) (b) 1 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 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / LONG-TERM DEBT (Account 221, 222, 223 and 224) 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.
Line Class and Series of Obligation, Coupon Rate Principal Amount Total expense, No. (For new issue, give commission Authorization numbers and dates) Of Debt issued Premium or Discount (a) (b) (c) 1 ACCOUNT 221 - BONDS 2 Appalachian Consumer Rate Relief Funding LLC 3 Tranche A-1, 2.0076%, Due 2024 215,800,000 2,416,193 4 - Expense, Premium (P), Discount (D) 9,879 D 5 6 Appalachian Consumer Rate Relief Funding LLC 7 Tranche A-2, 3.7722%, Due 2031 164,500,000 1,841,815 8 - Expense, Premium (P), Discount (D) 7,530 D 9 SUBTOTAL ACCOUNT 221 - BONDS 380,300,000 4,275,417 10 11 ACCOUNT 222 - REACQUIRED BONDS 12 None 13 SUBTOTAL ACCOUNT 222 - REACQUIRED BONDS 14 15 ACCOUNT 223 - ADVANCES FROM ASSOCIATED COMPANIES 16 None 17 SUBTOTAL ACCOUNT 223 - ADVANCES FROM ASSOCIATED COMPANIES 18 19 ACCOUNT 224 - OTHER LONG-TERM DEBT 20 INSTALLMENT PURCHASE CONTRACTS 21 Amos Project, Series 2009A, Due 2042 54,375,000 410,584 22 -WV Economic Development Authority, Solid Waste Disposal Facility 23 -Variable Rate Demand Bonds 24 25 Amos Project, Series 2009B, Due 2042 50,000,000 377,548 26 -WV Economic Development Authority, Solid Waste Disposal Facility 27 -Variable Rate Demand Bonds 28 29 Mountaineer Project, Series 2008A, Due 2036 75,000,000 370,548 30 -WV Economic Development Authority, Solid Waste Disposal Facility 31 -Variable Rate Demand Bonds 32
33 TOTAL 5,031,359,040 67,944,353
FERC FORM NO. 1 (ED. 12-96) Page 256 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / LONG-TERM DEBT (Account 221, 222, 223 and 224) 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.
Line Class and Series of Obligation, Coupon Rate Principal Amount Total expense, No. (For new issue, give commission Authorization numbers and dates) Of Debt issued Premium or Discount (a) (b) (c) 1 Mountaineer Project, Series 2008B, Due 2036 50,275,000 291,961 2 -WV Economic Development Authority, Solid Waste Disposal Facility 3 -Variable Rate Demand Bonds 4 5 Russell County, VA, Series K, Due 2021, Industrial Development Authority 17,500,000 297,241 6 -Pollution Control Revenue Refunding Bonds 7 - 4.625% Bonds 8 9 Amos Project, Series 2010A, Due 2038 50,000,000 649,267 10 -WV Economic Development Authority, Solid Waste Disposal Facility 11 - 5.375% Bonds 12 - Subject to mandatory tender for purchase (puttable) on 12/01/2020 13 -Remarketed 12-23-2020 14 - 0.625% Bonds 293,857 15 16 Mason County, WV, Series L, Due 2022 100,000,000 674,863 17 -Pollution Control Revenue Bonds 18 - 1.625% Bonds 19 - Subject to mandatory tender for purchase (puttable) on 10/01/2018 20 -Remarketed 10/01/2018 21 - 2.750% Bonds 608,622 22 23 Amos Project, Series 2015A, Due 2040 86,000,000 642,924 24 -WV Economic Development Authority, Solid Waste Disposal Facility 25 - 1.900% Bonds 26 - Subject to mandatory tender for purchase (puttable) on 04/01/2019 27 -Remarketed 04/01/2019 28 - 2.550% Bonds 555,367 29 30 31 32
33 TOTAL 5,031,359,040 67,944,353
FERC FORM NO. 1 (ED. 12-96) Page 256.1 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / LONG-TERM DEBT (Account 221, 222, 223 and 224) 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.
Line Class and Series of Obligation, Coupon Rate Principal Amount Total expense, No. (For new issue, give commission Authorization numbers and dates) Of Debt issued Premium or Discount (a) (b) (c) 1 Amos Project, Series 2011A, Due 2041 65,350,000 416,278 2 -WV Economic Development Authority, Solid Waste Disposal Facility 3 - 1.700% Bonds 4 - Subject to mandatory tender for purchase (puttable) on 09/01/2020 5 -Remarketed 09/01/2020 6 - 1.000% Bonds 427,620 7 8 SENIOR UNSECURED NOTES 9 4.600% Senior Unsecured Notes, Series T, Due 2021 350,000,000 2,716,391 10 - Expense, Premium (P), Discount (D) 976,500 D 11 - Interest Expense re amortization of Cash Flow Hedges 12 13 5.800% Senior Unsecured Notes, Series L, Due 2035 250,000,000 2,334,997 14 - Expense, Premium (P), Discount (D) 1,900,000 D 15 16 5.950% Senior Unsecured Notes, Series H, Due 2033 200,000,000 1,900,000 17 - Expense, Premium (P), Discount (D) 422,000 D 18 - Interest Expense re amortization of Cash Flow Hedges D 19 20 6.375% Senior Unsecured Notes, Series N, Due 2036 250,000,000 2,266,382 21 - Expense, Premium (P), Discount (D) 757,500 D 22 - Interest Expense re amortization of Cash Flow Hedges 23 24 6.700% Senior Unsecured Notes, Series P, Due 2037 250,000,000 2,348,344 25 - Expense, Premium (P), Discount (D) 62,500 D 26 27 7.000% Senior Unsecured Notes, Series Q, Due 2038 500,000,000 4,447,060 28 - Expense, Premium (P), Discount (D) 3,300,000 D 29 - Interest Expense re amortization of Cash Flow Hedges 30 31 4.400% Senior Unsecured Notes, Series U, Due 2044 300,000,000 2,973,178 32 - Expense, Premium (P), Discount (D) 2,082,000 D
33 TOTAL 5,031,359,040 67,944,353
FERC FORM NO. 1 (ED. 12-96) Page 256.2 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / LONG-TERM DEBT (Account 221, 222, 223 and 224) 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.
Line Class and Series of Obligation, Coupon Rate Principal Amount Total expense, No. (For new issue, give commission Authorization numbers and dates) Of Debt issued Premium or Discount (a) (b) (c) 1 2 3.400% Senior Unsecured Notes, Series V, Due 2025 300,000,000 2,312,703 3 - Expense, Premium (P), Discount (D) 1,065,000 D 4 5 4.450% Senior Unsecured Notes, Series W, Due 2045 350,000,000 3,483,819 6 - Expense, Premium (P), Discount (D) 2,530,500 D 7 8 3.300% Senior Unsecured Notes, Series X, Due 2027 325,000,000 2,648,060 9 - Expense, Premium (P), Discount (D) 1,657,500 D 10 11 4.500% Senior Unsecured Notes, Series Y, Due 2049 400,000,000 4,158,436 12 - Expense, Premium (P), Discount (D) 2,736,000 D 13 14 3.700% Senior Unsecured Notes Series Z, Due 2050 500,000,000 5,106,633 15 - Expense, Premium (P), Discount (D) 2,955,000 D 16 17 18 SALE / LEASEBACK OF PROPERTY 19 Agreement with City of Bedford, VA re Skimmer Station 2,559,040 20 21 22 CREDIT FACILITY 23 Floating Credit Facility 125,000,000 511,753 24 SUBTOTAL ACCOUNT 224 - OTHER LONG-TERM DEBT 4,651,059,040 63,668,936 25 26 27 28 29 30 31 32
33 TOTAL 5,031,359,040 67,944,353
FERC FORM NO. 1 (ED. 12-96) Page 256.3 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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 Outstanding Line Nominal Date Date of (Total amount outstanding without Interest for Year reduction for amounts held by No. of Issue Maturity Date From Date To respondent) Amount (d) (e) (f) (g) (h) (i) 1 2 11/15/2013 02/01/2024 11/15/2013 02/01/2023 60,971,913 1,948,315 3 4 5 6 11/15/2013 08/01/2031 11/15/2013 08/01/2028 164,500,000 5,649,941 7 8 225,471,913 7,598,256 9 10 11 12 13 14 15 16 17 18 19 20 5/15/2018 12/01/2042 5/15/2018 12/01/2042 54,375,000 1,427,344 21 22 23 24 5/15/2018 12/01/2042 03/25/2018 12/01/2042 50,000,000 1,312,500 25 26 27 28 03/17/2011 02/01/2036 1/13/2016 02/01/2036 75,000,000 536,440 29 30 31 32
4,875,967,882 211,822,330 33
FERC FORM NO. 1 (ED. 12-96) Page 257 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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 Outstanding Line Nominal Date Date of (Total amount outstanding without Interest for Year reduction for amounts held by No. of Issue Maturity Date From Date To respondent) Amount (d) (e) (f) (g) (h) (i) 03/17/2011 02/01/2036 03/10/2016 02/01/2036 50,275,000 406,637 1 2 3 4 03/17/2010 11/01/2021 03/17/2010 11/01/2021 17,500,000 809,375 5 6 7 8 05/19/2010 12/01/2038 05/19/2010 12/01/2038 2,687,500 9 10 11 12 13 12/23/2020 12/01/2038 12/23/2020 2025-12-5 50,000,000 6,944 14 15 10/1/2014 10/01/2022 10/1/2014 10/1/2018 16 17 18 19 20 10/01/2018 10/01/2022 10/01/2018 10/01/2022 100,000,000 2,750,000 21 22 04/01/2015 03/01/2040 04/01/2015 04/01/2019 23 24 25 26 27 04/01/2019 04/01/2024 04/01/2019 04/01/2024 86,000,000 2,193,000 28 29 30 31 32
4,875,967,882 211,822,330 33
FERC FORM NO. 1 (ED. 12-96) Page 257.1 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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 Outstanding Line Nominal Date Date of (Total amount outstanding without Interest for Year reduction for amounts held by No. of Issue Maturity Date From Date To respondent) Amount (d) (e) (f) (g) (h) (i) 09/01/2016 01/01/2041 09/01/2016 09/01/2020 740,633 1 2 3 4 5 09/01/2020 01/01/2041 09/01/2020 09/01/2025 65,350,000 217,834 6 7 8 03/25/2011 03/30/2021 03/25/2011 03/30/2021 350,000,000 16,100,000 9 10 -1,131,432 11 12 09/29/2005 10/01/2035 09/29/2005 10/01/2035 250,000,000 14,500,000 13 14 15 05/05/2003 05/15/2033 05/05/2003 05/15/2033 200,000,000 11,900,000 16 17 37,071 18 19 04/10/2006 04/01/2036 04/10/2006 04/01/2036 250,000,000 15,937,500 20 21 -194,198 22 23 08/17/2007 08/15/2037 08/17/2007 08/15/2037 250,000,000 16,750,000 24 25 26 03/25/2008 04/01/2038 03/25/2008 04/01/2038 500,000,000 35,000,000 27 28 159,671 29 30 05/08/2014 05/15/2044 05/08/2014 5/15/2044 300,000,000 13,200,000 31 32
4,875,967,882 211,822,330 33
FERC FORM NO. 1 (ED. 12-96) Page 257.2 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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 Outstanding Line Nominal Date Date of (Total amount outstanding without Interest for Year reduction for amounts held by No. of Issue Maturity Date From Date To respondent) Amount (d) (e) (f) (g) (h) (i) 1 05/18/2015 06/01/2025 05/18/2015 06/01/2025 300,000,000 10,200,000 2 3 4 05/18/2015 06/01/2045 05/18/2015 06/01/2045 350,000,000 15,575,000 5 6 7 05/11/2017 06/01/2027 05/11/2017 06/01/2027 325,000,000 10,725,000 8 9 10 03/06/2019 03/01/2049 03/06/2019 03/01/2049 400,000,000 18,000,000 11 12 13 05/14/2020 05/01/2050 05/14/2020 05/01/2050 500,000,000 11,665,278 14 15 16 17 18 06/07/1996 06/06/2026 06/07/1996 06/06/2026 1,995,969 276,283 19 20 21 22 06/05/2019 06/05/2022 06/05/2019 06/05/2022 125,000,000 2,435,694 23 4,650,495,969 204,224,074 24 25 26 27 28 29 30 31 32
4,875,967,882 211,822,330 33
FERC FORM NO. 1 (ED. 12-96) Page 257.3 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 FOOTNOTE DATA
Schedule Page: 256 Line No.: 3 Column: g Issuance : Tranche A-1, 2.0076%, Due 2024 Principal Amount : $215,800,000 Date of Issuance : 11/15/2013 Date of Maturity : 02/01/2024 - Date of maturity (02/01/2024) is when all required payments must be made. - The amortization period end date being used (02/01/2023) is the scheduled final payment date.
Schedule Page: 256 Line No.: 7 Column: g Issuance : Tranche A-2, 3.7722%, Due 2031 Principal Amount : $164,500,000 Date of Issuance : 11/15/2013 Date of Maturity : 08/01/2031 - Date of maturity (08/01/2031) is when all required payments must be made. - The amortization period end date being used (08/01/2028) is the scheduled final payment date.
Schedule Page: 256 Line No.: 21 Column: a Issuance : Amos Project, Series 2009A, Due 2042 Principal Amount: $54,375,000 Issuance Date : 03/25/2011 Maturity Date : 12/01/2042 Interest Rate : Variable Rate Demand Bonds Reacquired Date : 01/19/2017 Remarketed Date : 05/15/2018
Schedule Page: 256 Line No.: 25 Column: a These are the re-marketed bonds from May 15, 2018.
FERC 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) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES 1. Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show computation of such tax accruals. Include in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for the year. Submit a reconciliation even though there is no taxable income for the year. Indicate clearly the nature of each reconciling amount. 2. If the utility is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net income as if a separate return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group member, tax assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members. 3. A substitute page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements of the above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.
Line Particulars (Details) Amount No. (a) (b) 1 Net Income for the Year (Page 117) 369,732,667 2 3 4 Taxable Income Not Reported on Books 5 6 7 8 9 Deductions Recorded on Books Not Deducted for Return 10 11 12 13 14 Income Recorded on Books Not Included in Return 15 16 17 18 19 Deductions on Return Not Charged Against Book Income 20 21 22 23 24 25 26 27 Federal Tax Net Income 233,166,905 28 Show Computation of Tax: 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44
FERC FORM NO. 1 (ED. 12-96) Page 261 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 FOOTNOTE DATA
Schedule Page: 261 Line No.: 28 Column: b
FOOTNOTE DATA
Schedule Page: 261 Line No.: 28 Column: b
Net Income for the Year per Page 117 369,733 Federal Income Taxes (5,616) State Income Taxes 9,979 Pre-Tax Book Income 374,096
Other (19,317) Excess Tax vs Book Depr 107,201 AFUDC & Other Capitalization Differences (5,449) Book/Tax Mixed Service Cost Adj (62,954) Removal Costs (12,659) Pollution Control Equipment 40,065 Provision for Possible Revenue Refunds (2,780) Deferred Fuel Costs 64,443 Pension Expenses 6,337 State Income Tax - Exp & Interest 0 Defd Costs & Carrying Charges (253,373) Premium of Reacquired Debt 3,393 SFAS 106 - Post Retire Benefit Exp (13,105) Accrued Bk ARO Expense - SFAS 143 200,351 Capitalized Software (872) Book/Tax Unit of Property Adj (168,865) Virginia T-RAC (18,760) Deferred Storm Damage 178 Incentive Compensation Plans 1,804 Accrued Book Severance Benefits 1,210 Extra Loss - Plant Retirements 3,900 Stock Compensation (212)
Taxable Income before State Taxes 244,632
State & Local Current Tax 11,465
Federal Taxable Income 233,167 FIT on Current Year Taxable Income Adjustment due to System Consolidation (a) 48,965 SEC ALLOC - Parents Savings (6,236) NOL Deferred Tax Asset (3,041) Tax Credits (4,047) R & D CREDIT - CURRENT (225) Alt Min 0 Tax Provision Adjustments 0 Estimated Tax Currently Payable (b) 35,416
Adjustments of Prior Year's Accruals (13,703) Tax Expense for R/C of Net Operating Loss (Prior Yr)
FERC 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) Appalachian Power Company (2) A Resubmission / / 2020/Q4 FOOTNOTE DATA
Estimated Current Federal Income Taxes 21,713
(a) Represents the allocation of the estimated current year net operating tax income of American Electric Power Company, Inc.
(b) The Company joins in the filing of a consolidated Federal income tax return with its affiliated companies in the AEP system. The allocation of the AEP System's consolidated Federal income tax to the System companies allocates the benefit of current tax losses to the System companies giving rise to them in determining their current tax expense. The tax loss of the System parent company, American Electric Power Company, Inc., is allocated to its subsidiaries with taxable income. With the exception of the loss of the parent company, the method of allocation approximates a separate return result for each company in the consolidating group.
INSTRUCTION 2. * The tax computation above represents an estimate of the Company's allocated portion of the System consolidated Federal income tax. The computation of actual 2020 System Federal income taxes will not be available until the consolidated Federal income tax return is completed and filed by October 2021. The actual allocation of the System consolidated Federal income tax to the members of the consolidated group will not be available until after the consolidated federal income tax return is filed.
FERC FORM NO. 1 (ED. 12-87) Page 450.2 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR 1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the 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.
Line BALANCE AT BEGINNING OF YEAR Taxes Taxes Kind of Tax Charged Paid Adjust- No. (See instruction 5) Taxes Accrued Prepaid Taxes During During ments (Account 236) (Include in Account 165) Year Year (a) (b) (c) (d) (e) (f) 1 FEDERAL TAXES 2 Income Taxes -32,673,461 21,713,074 -560,164 3 FIN 48 4 5 FICA - 2020 2,311,222 13,338,063 8,145,818 5,665,972 6 Unemployment - 2020 41,677 49,875 77,857 7 8 Federal Excise Tax - 2019 9 10 STATE OF WEST VIRGINIA 11 STATE AND LOCAL TAXES 12 WV Business & Occupation 13 2019 1,700,328 -239,103 1,461,225 14 2020 31,553,194 29,824,688 15 WV Public Serv Commission 16 2019 1,685,883 1,685,883 17 2020 679,378 2,782,630 2,743,512 18 WV Sales and Use - 2019 336,672 -27,491 309,181 19 WV Sales and Use - 2020 1,708,946 1,452,992 20 WV Real and Personal 21 2016 382 382 22 2017 363 363 23 2018 25,689,310 -74 25,689,236 24 2019 52,430,844 -223,646 26,138,317 25 2020 52,249,589 4 26 WV Pers Prop - Leased 2018 60,764 60,764 27 WV Pers Prop - Leased 2019 181,000 16,575 131,426 28 WV Pers Prop - Leased 2020 184,620 29 WV Municipal B&O Tax 30 2019 3,109,338 -4,438 3,104,900 31 2020 13,171,896 10,149,487 32 WV Municipal License 2020 33 WV State License 2019 -52 34 WV Income - 2017 -1,489,463 35 WV Income - 2018 -767,996 36 WV Income - 2019 8,254,337 8,756,867 37 WV Income - 2020 439,442 887,200 38 WV State Unemployment 39 2020 68,342 148,648 195,339 40 STATE OF OHIO
41 TOTAL 66,830,813 2,376,537 191,372,842 156,515,402
FERC FORM NO. 1 (ED. 12-96) Page 262 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR 1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the 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.
Line BALANCE AT BEGINNING OF YEAR Taxes Taxes Kind of Tax Charged Paid Adjust- No. (See instruction 5) Taxes Accrued Prepaid Taxes During During ments (Account 236) (Include in Account 165) Year Year (a) (b) (c) (d) (e) (f) 1 OH Use Tax - 2018 -1 2 OH Use Tax - 2019 94,673 11,276 -49,402 33,995 3 OH Use Tax - 2020 182,846 171,690 4 OH CAT Tax - 2019 7,500 -9,290 -1,790 5 OH CAT Tax - 2020 68,152 43,252 6 OH Pers Prop Leased 2019 9 9 7 OH Property Tax - 2018 2,429,988 -47,396 2,382,592 8 OH Property Tax - 2019 2,473,075 9 OH Property Tax - 2020 1,976,830 10 OH Misc State/Local Taxes 11 OH State Unemployment 12 2020 1,013 1,214 1,890 13 14 STATE OF VIRGINIA 15 STATE AND LOCAL TAXES 16 VA State Income 17 VA Minimum Tax - 2018 -68,884 18 VA Minimum Tax - 2019 -51,363 474,174 2,773,800 19 VA Minimum Tax - 2020 9,372,559 8,578,000 20 VA Use Tax - 2019 707,640 107,627 815,267 21 VA Use Tax - 2020 3,771,988 3,591,886 22 VA Real and Personal - 2018 2,414 2,414 23 VA Real and Personal - 2019 503,578 -6,702 496,876 24 VA Real and Personal - 2020 25,894,439 25,476,033 25 VA Pers Prop-Leased - 2018 -183 -183 26 VA Pers Prop-Leased - 2019 6,875 20,587 27,462 27 VA Pers Prop-Leased - 2020 469,243 462,749 28 VA Real Prop-Leased - 2019 14,624 14,624 29 VA Real Prop-Leased - 2020 65,874 36,047 30 VA State Unemployment - 20,938 26,629 38,940 31 VA State License 2020 32 33 STATE OF DELAWARE 34 DE License Fee 2020 35 36 STATE OF TENNESSEE 37 TN State Franchise - 2017 88,451 38 TN State Franchise - 2018 9,373 39 TN State Franchise - 2019 206,373 -10,155 40 TN State Franchise - 2020 262,218
41 TOTAL 66,830,813 2,376,537 191,372,842 156,515,402
FERC FORM NO. 1 (ED. 12-96) Page 262.1 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR 1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the 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.
Line BALANCE AT BEGINNING OF YEAR Taxes Taxes Kind of Tax Charged Paid Adjust- No. (See instruction 5) Taxes Accrued Prepaid Taxes During During ments (Account 236) (Include in Account 165) Year Year (a) (b) (c) (d) (e) (f) 1 TN Real and Personal - 2019 1,451,800 -50,781 1,401,019 2 TN Real and Personal - 2020 1,407,500 3 TN State License/Registration 4 2020 5 TN State Income Tax - 2016 -4,104 6 TN State Income Tax - 2017 -501,939 7 TN State Income Tax - 2018 432,376 8 TN State Income Tax - 2019 -477,568 272,977 9 TN State Income Tax - 2020 -183,201 284,700 10 TN State Unemployment - 2 2 3 11 TN State Inspection Fee 12 TN State Sales/Use Tax - 21,942 4,867 26,809 13 TN State Sales/Use Tax - 6,375 14 TN State Gross Receipts Priv 100 15 16 TX Use Tax 17 18 NC License Fee 2020 19 NC State Franchise - 2017 -4,035 20 NC State Franchise - 2018 200 21 NC State Franchise - 2019 200 1,710 22 NC State Franchise - 2020 1,910 23 24 Property Taxes-Rail Cars 25 AR-2019 1,988 1,988 26 CO-2019 656 656 27 IN-2020 72 72 28 LA-2020 1,990 1,990 29 MO-2020 22,970 22,970 30 WY-2019 3,581 3,581 31 32 STATE OF MICHIGAN 33 STATE & LOCAL TAXES 34 MI State License 2020 35 MI State Income Tax - 2017 -6,145 36 MI State Income Tax - 2018 6,918 37 MI State Income Tax - 2019 1,486 1,740 38 MI State Income Tax - 2020 -2,414 39 40
41 TOTAL 66,830,813 2,376,537 191,372,842 156,515,402
FERC FORM NO. 1 (ED. 12-96) Page 262.2 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR 1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the 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.
Line BALANCE AT BEGINNING OF YEAR Taxes Taxes Kind of Tax Charged Paid Adjust- No. (See instruction 5) Taxes Accrued Prepaid Taxes During During ments (Account 236) (Include in Account 165) Year Year (a) (b) (c) (d) (e) (f) 1 STATE OF ILLINOIS 2 IL State License 2017 3 IL State Income Tax - 2017 -163,298 4 IL State Income Tax - 2018 149,310 5 IL State Income Tax - 2019 226,686 97,706 6 IL State Income Tax - 2020 -122,797 7 8 PA Gross Receipts - Audit 9 PA Gross Receipts Tax 2013 10 State Taxes - FIN 48 11 12 STATE OF KENTUCKY 13 KY State Franchise 2019 1,637 14 KY State Franchise 2020 1,637 15 State Unemployment 2020 296 16 KY State Income Tax 2020 10,553 17 Other State License Tax 18 UT State License 2020 19 AR State License 2020 20 MULTI ST INCOME -8,915 21 Local Income Taxes 8,906 22 WV Muni License Fee 2019 -20 23 WV Muni License Fee 2019 240 24 Excise tax 13,194 13,194 25 26 2360104 FICA - -2,832,986 27 2360105 FICA - CARES ACT -2,832,986 28 29 30 31 32 33 34 35 36 37 38 39 40
41 TOTAL 66,830,813 2,376,537 191,372,842 156,515,402
FERC FORM NO. 1 (ED. 12-96) Page 262.3 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued) 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 (l) 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 (l) 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 (l) 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.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line (Taxes accrued Prepaid Taxes Electric Extraordinary Items Adjustments to Ret. Other No. Account 236) (Incl. in Account 165) (Account 408.1, 409.1) (Account 409.3) Earnings (Account 439) (g) (h) (i) (j) (k) (l) 1 -10,400,223 27,790,428 -6,077,354 2 3 4 1,837,495 7,848,861 5,489,202 5 13,695 16,828 33,047 6 7 8 9 10 11 12 -239,103 13 1,728,506 34,290,973 -2,737,779 14 15 1,685,883 16 731,496 1,371,756 2,782,630 17 -27,491 18 255,954 1,708,946 19 20 382 21 363 22 25,091,766 -25,091,840 23 26,068,881 25,424,425 -25,648,071 24 52,249,585 52,249,589 25 26 66,149 102,151 -85,576 27 184,620 97,635 86,985 28 29 -4,438 30 3,022,409 13,116,920 54,976 31 32 -52 33 -1,489,463 34 -767,996 35 17,011,204 8,748,076 8,791 36 -447,758 -389,953 829,395 37 38 21,651 72,041 76,607 39 40
100,698,572 1,386,856 185,885,114 5,487,728 41
FERC FORM NO. 1 (ED. 12-96) Page 263 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued) 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 (l) 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 (l) 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 (l) 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.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line (Taxes accrued Prepaid Taxes Electric Extraordinary Items Adjustments to Ret. Other No. Account 236) (Incl. in Account 165) (Account 408.1, 409.1) (Account 409.3) Earnings (Account 439) (g) (h) (i) (j) (k) (l) -1 1 92 -49,494 2 26,156 15,000 -6,001 188,847 3 -9,290 4 24,900 68,152 5 9 6 -47,396 7 2,473,075 2,473,075 -2,473,075 8 1,976,830 1,976,830 9 10 11 337 474 740 12 13 14 15 16 -68,884 17 -2,350,989 474,174 18 794,559 9,372,559 19 -27 107,654 20 180,102 47 3,771,941 21 2,414 22 -6,702 23 418,406 24,972,398 922,041 24 -183 25 20,548 39 26 6,494 469,243 27 28 29,827 6,220 59,654 29 8,627 11,522 15,107 30 31 32 33 34 35 36 88,451 37 9,373 38 196,218 -10,155 39 262,218 262,218 40
100,698,572 1,386,856 185,885,114 5,487,728 41
FERC FORM NO. 1 (ED. 12-96) Page 263.1 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued) 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 (l) 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 (l) 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 (l) 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.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line (Taxes accrued Prepaid Taxes Electric Extraordinary Items Adjustments to Ret. Other No. Account 236) (Incl. in Account 165) (Account 408.1, 409.1) (Account 409.3) Earnings (Account 439) (g) (h) (i) (j) (k) (l) -50,738 -43 1 1,407,500 1,400,342 7,158 2 3 4 -4,104 5 -501,939 6 432,376 7 -204,591 272,566 411 8 -467,901 -221,959 38,758 9 1 1 1 10 11 4,867 12 6,375 6,375 13 100 14 15 1,766 -1,766 16 17 18 -4,035 19 200 20 1,910 1,710 21 1,910 1,910 22 23 24 1,988 25 656 26 72 27 1,990 28 22,970 29 3,581 30 31 32 33 34 -6,145 35 6,918 36 3,226 1,738 2 37 -2,414 -2,656 242 38 39 40
100,698,572 1,386,856 185,885,114 5,487,728 41
FERC FORM NO. 1 (ED. 12-96) Page 263.2 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued) 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 (l) 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 (l) 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 (l) 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.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line (Taxes accrued Prepaid Taxes Electric Extraordinary Items Adjustments to Ret. Other No. Account 236) (Incl. in Account 165) (Account 408.1, 409.1) (Account 409.3) Earnings (Account 439) (g) (h) (i) (j) (k) (l) 1 2 -163,298 3 149,310 4 324,392 97,564 142 5 -122,797 -129,315 6,518 6 7 8 9 10 11 12 1,637 1,637 13 1,637 1,637 14 296 15 10,553 2,020 8,533 16 17 18 19 -8,915 20 8,906 21 -20 22 -240 23 13,194 24 25 2,832,986 26 2,832,986 27 28 29 30 31 32 33 34 35 36 37 38 39 40
100,698,572 1,386,856 185,885,114 5,487,728 41
FERC FORM NO. 1 (ED. 12-96) Page 263.3 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255) Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and nonutility operations. Explain by footnote any correction adjustments to the account balance shown in column (g).Include in column (i) the average period over which the tax credits are amortized. Line Account Balance at Beginning Allocations to Deferred for Year Current Year's Income No. Subdivisions of Year Adjustments (a) (b) Account No. Amount Account No. Amount (c) (d) (e) (f) (g) 1 Electric Utility 2 3% 411.1 3 4% 411.1 4 7% 411.1 5 10% 502,367 411.1 411.1 183,576 6 State DITC 411.1 411.1 7 30% 411.1 8 TOTAL 502,367 183,576 9 Other (List separately and show 3%, 4%, 7%, 10% and TOTAL) 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 266 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255) (continued)
Balance at End Average Period ADJUSTMENT EXPLANATION Line of Year of Allocation to Income No. (h) (i) 1 2 3 4 318,791 33Years 5 6 7 318,791 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 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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.
Line Description and Other Balance at DEBITS Balance at No. Deferred Credits Beginning of Year Contra Amount Credits End of Year Account (a) (b) (c) (d) (e) (f) 1 T.V. Pole Attachments 2,283,823 454/172 6,946,792 6,537,206 1,874,237 2 3 Deferred Gain - Fiber Optic Leases 4 Amortize through June 2026 4,170,960 124 784,194 3,386,766 5 6 Deferred Revenue - Fiber Optic 7 Lines Sold 365,572 451 173,751 191,821 8 Amortize IRU through May 2021 9 Amortize KDL through Jan 2025 10 11 Rents Billed in Advance 552,451 451 184,150 368,301 12 13 Customer Advance Receipts 15,958,328 142 15,958,328 17,275,460 17,275,460 14 15 IPP - System Upgrade Credits 3,199,750 132,979 3,332,729 16 17 Federal Mitigation Deferral - NSR 3,979,306 242 1,750,000 2,229,306 18 19 Other Deferred Credits 864,300 Footnote 11,937,316 12,260,850 1,187,834 20 21 Def Equity Income-Securitization 2,831,795 456 295,863 2,535,932 22 23 Asbestos Accrual - Non-Current 5,443,409 228/242/925 5,452,951 9,542 24 25 Reliability First FAC-003 1,769,481 426 700,000 1,069,481 26 Assessment 27 28 Contr In Aid of Constr Advance 3,583,821 107/108 3,583,821 635,839 635,839 29 30 Associated Business Development 3,042 186 3,042 227,650 227,650 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46
47 TOTAL 45,006,038 47,770,208 37,079,526 34,315,356
FERC FORM NO. 1 (ED. 12-94) Page 269 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 FOOTNOTE DATA
Schedule Page: 269 Line No.: 19 Column: c 232,234,561,566,565,131,143,411,186,509,142
FERC 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) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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 No. Beginning of Year Amounts Debited Amounts Credited to Account 410.1 to Account 411.1 (a) (b) (c) (d) 1 Accelerated Amortization (Account 281) 2 Electric 3 Defense Facilities 4 Pollution Control Facilities 260,692,189 101,316,018 114,070,824 5 Other (provide details in footnote): 6 7 8 TOTAL Electric (Enter Total of lines 3 thru 7) 260,692,189 101,316,018 114,070,824 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 Other - SFAS 109 -100,140,967 17 TOTAL (Acct 281) (Total of 8, 15 and 16) 160,551,222 101,316,018 114,070,824 18 Classification of TOTAL 19 Federal Income Tax 160,551,222 101,316,018 114,070,824 20 State Income Tax 21 Local Income Tax
NOTES
FERC FORM NO. 1 (ED. 12-96) Page 272 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / ACCUMULATED DEFERRED INCOME TAXES _ ACCELERATED AMORTIZATION PROPERTY (Account 281) (Continued) 3. Use footnotes as required.
CHANGES DURING YEAR ADJUSTMENTS Line Amounts Debited Amounts Credited Debits Credits Balance at to Account 410.2 to Account 411.2 Account Amount Account Amount End of Year No. Credited Debited (f) (j) (e) (g) (h) (i) (k) 1 2 3 247,937,383 4 5 6 7 247,937,383 8 9 10 11 12 13 14 15 254 101,316,018 254 105,657,031 -95,799,954 16 101,316,018 105,657,031 152,137,429 17 18 101,316,018 105,657,031 152,137,429 19 20 21
NOTES (Continued)
FERC FORM NO. 1 (ED. 12-96) Page 273 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 FOOTNOTE DATA
Schedule Page: 272 Line No.: 16 Column: b Description Balance at Beginning Amounts Debited Amounts Credits Debit Credit Balance End of Year Page 272-273 to Acc 410.2 to Acc 411.2 Adjust Adjust
SFAS 109 (100,140,967) 101,316,018 105,657,031 (95,799,954)
Total line 16 (100,140,967) 101,316,018 105,657,031 (95,799,954)
FERC 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) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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 No. Beginning of Year Amounts Debited Amounts Credited to Account 410.1 to Account 411.1 (a) (b) (c) (d) 1 Account 282 2 Electric 2,047,477,994 747,220,267 781,717,033 3 Gas 4 5 TOTAL (Enter Total of lines 2 thru 4) 2,047,477,994 747,220,267 781,717,033 6 Others -690,858,836 7 8 9 TOTAL Account 282 (Enter Total of lines 5 thru 1,356,619,158 747,220,267 781,717,033 10 Classification of TOTAL 11 Federal Income Tax 1,356,619,158 747,220,267 781,717,033 12 State Income Tax 13 Local Income Tax
NOTES
FERC FORM NO. 1 (ED. 12-96) Page 274 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282) (Continued) 3. Use footnotes as required.
CHANGES DURING YEAR ADJUSTMENTS Line Amounts Debited Amounts Credited Debits Credits Balance at to Account 410.2 to Account 411.2 Account Amount Account Amount End of Year No. Credited Debited (f) (j) (e) (g) (h) (i) (k) 1 33,415,108 2,046,396,336 2 3 4 33,415,108 2,046,396,336 5 1823/254 611,691,6051823/254 663,118,422 -639,432,019 6 7 8 611,691,605 696,533,530 1,406,964,317 9 10 611,691,605 696,533,530 1,406,964,317 11 12 13
NOTES (Continued)
FERC FORM NO. 1 (ED. 12-96) Page 275 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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. CHANGES DURING YEAR Line Account Balance at Amounts Debited Amounts Credited No. Beginning of Year to Account 410.1 to Account 411.1 (a) (b) (c) (d) 1 Account 283 2 Electric 3 Extra. Loss on Retired Plants 18,139,738 819,067 4 CAPITALIZED SOFTWARE COST?BOOK 22,682,473 4,776,352 1,490,914 5 DSIT ENTRY - NORMALIZED 91,825,852 1,774,027 6 Deferred Fuel Costs 59,845,228 3,951,745 17,484,863 7 Book Pension Expense 27,645,704 1,933,155 2,263,911 8 Other -76,120,016 241,900,636 202,702,678 9 TOTAL Electric (Total of lines 3 thru 8) 144,018,979 252,561,888 226,535,460 10 Gas 11 12 13 14 15 16
17 TOTAL Gas (Total of lines 11 thru 16) 18 Other 504,758,712 19 TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18) 648,777,691 252,561,888 226,535,460 20 Classification of TOTAL 21 Federal Income Tax 311,545,652 248,065,107 222,747,149 22 State Income Tax 337,232,039 4,496,781 3,788,311 23 Local Income Tax
NOTES
FERC FORM NO. 1 (ED. 12-96) Page 276 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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.
CHANGES DURING YEAR ADJUSTMENTS Amounts Debited Amounts Credited Debits Credits Balance at Line to Account 410.2 to Account 411.2 Account Amount Account Amount End of Year No. Credited Debited (e) (f) (g) (h) (i) (j) (k) 1 2 17,320,671 3 25,967,911 4 90,051,825 5 46,312,110 6 27,314,948 7 -36,922,058 8 170,045,407 9 10 11 12 13 14 15 16 17 214,383 1823/254 173,821,001 1823/254 189,191,333 520,343,427 18 214,383 173,821,001 189,191,333 690,388,834 19 20 214,383 164,602,162 181,428,109 353,903,940 21 9,218,839 7,763,225 336,484,895 22 23
NOTES (Continued)
FERC FORM NO. 1 (ED. 12-96) Page 277 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 FOOTNOTE DATA
Schedule Page: 276 Line No.: 18 Column: b
Line 18 Footnote Beg Bal Dr Cr 411.1 Dr 410.2 Cr 411.2 Debits Credits End Bal 410.1 SFAS 133 967,340 2,572 222,319 1,187,087 Non-Utility (70,158) 214,383 144,225 SFAS 109 503,861,530 173,818, 188,969,014 519,012,115 429 Total 504,758,712 214,383 173,821, 189,191,333 520,343,427 001
FERC 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) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / OTHER REGULATORY LIABILITIES (Account 254) 1. Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if 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), may be grouped by classes. 3. For Regulatory Liabilities being amortized, show period of amortization.
Balance at Begining DEBITS Balance at End Line Description and Purpose of of Current of Current No. Other Regulatory Liabilities Account Amount Credits Quarter/Year Credited Quarter/Year (a) (b) (c) (d) (e) (f)
1 Unrealized Gain On Forward Commitments 9,265,032Footnote 15,642,251 6,638,107 260,888 2
3 Netting of Trading Activities related to 182 4,338,077 9,573,356 5,235,279 4 Unrealized Gains/Losses on Forward 5 Commitments between Regulated Assets/Liabilities 6
7 FAS 109 Deferred Federal Income Tax 929,717,554Footnote 1,226,109,946 1,125,559,945 829,167,553 8
9 VA Transmission Rate Adjustment Clause (T-RAC) 28,146,708566 30,224,688 2,077,980 10 Over - Recovered Costs 11 -Rate Order: VA SCC PUE-2009-00031 12
13 Felman Prem/Discount ENEC - WV 4,971,383501 5,635,928 664,545 14
15 EE-RAC Mobile Home Energy Star 94,265 94,265 16 -Rate Order: VA SCC 17 -Case No: PUE-2014-00039 18
19 EE-RAC Appliance Recycling 1,315,948 118,836 1,434,784 20 -Rate Order: VA SCC 21 -Case No: PUE-2014-00039 22
23 EE-RAC Home Energy Program 421,421 421,421 24 -Rate Order: VA SCC 25 -Case No: PUE-2014-00039 26
27 PJM trans enhancement settlement for refund 19,491,938142 3,226,340 16,265,598 28
29 VA EE-RAC Residential eScore 113,482254/908 76,694 154,424 191,212 30 -Case No. PUR - 2017-00126 31
32 VA EE-RAC BYO Smart Thermostat 170,705254/908 173,557 193,532 190,680 33 -Case No. PUR - 2017-00126 34
35 VA EE-RAC C&I Lighting 42,620182/254 209,686 167,066 36 -Case No. PUR - 2017-00126 37
38 VA EE-RAC C&I Standard 878,963 254/908 23 912,139 1,791,079 39 -Case No. PUR - 2017-00126 40
41 TOTAL 1,000,273,166 1,292,424,033 1,149,975,243 857,824,376
FERC FORM NO. 1/3-Q (REV 02-04) Page 278 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / OTHER REGULATORY LIABILITIES (Account 254) 1. Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if 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), may be grouped by classes. 3. For Regulatory Liabilities being amortized, show period of amortization.
Balance at Begining DEBITS Balance at End Line Description and Purpose of of Current of Current No. Other Regulatory Liabilities Account Amount Credits Quarter/Year Credited Quarter/Year (a) (b) (c) (d) (e) (f)
1 VA EE-RAC Small Business Install 286,502254/908 47,545 199,766 438,723 2 -Case No. PUR - 2017-00126 3
4 APCO Consumer Rate Relief Over Recovery 5,364,836407 6,739,298 1,891,201 516,739 5 -Rate Order: WV Public Service Commission 6 -Case No. 12-1188-E-PC 7 8 OCI - Excess DFIT ( 8,191) 8,191 9
10 VA EE-RAC Energy Star Housing 109,163 109,163 11 -Case No. VA SCC PUR-2019-00122 12
13 VA EE-RAC Low Income Multifamily 942,761 942,761 14 -Case No. VA SCC PUR-2019-00122 15
16 VA EE-RAC Low Income Single Family 764,231 764,231 17 -Case No. VA SCC PUR-2019-00122 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40
41 TOTAL 1,000,273,166 1,292,424,033 1,149,975,243 857,824,376
FERC FORM NO. 1/3-Q (REV 02-04) Page 278.1 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 FOOTNOTE DATA
Schedule Page: 278 Line No.: 1 Column: c 175, 182, 244, 456 Schedule Page: 278 Line No.: 7 Column: c 190,282,283
FERC 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) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / ELECTRIC OPERATING REVENUES (Account 400) 1. The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (f), and (g). Unbilled revenues and MWH related to unbilled revenues need not be reported separately as required in the annual version of these pages. 2. Report below operating revenues for each prescribed account, and manufactured gas revenues in total. 3. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accounts; except that where separate meter readings are added for billing purposes, one customer should be counted for each group of meters added. The -average number of customers means the average of twelve figures at the close of each month. 4. If increases or decreases from previous period (columns (c),(e), and (g)), are not derived from previously reported figures, explain any inconsistencies in a footnote. 5. Disclose amounts of $250,000 or greater in a footnote for accounts 451, 456, and 457.2.
Line Title of Account Operating Revenues Year Operating Revenues No. to Date Quarterly/Annual Previous year (no Quarterly) (a) (b) (c) 1 Sales of Electricity 2 (440) Residential Sales 1,273,007,898 1,272,324,395 3 (442) Commercial and Industrial Sales 4 Small (or Comm.) (See Instr. 4) 526,854,763 562,202,007 5 Large (or Ind.) (See Instr. 4) 563,789,888 594,602,826 6 (444) Public Street and Highway Lighting 7,783,854 7,814,732 7 (445) Other Sales to Public Authorities 61,094,193 67,743,839 8 (446) Sales to Railroads and Railways 9 (448) Interdepartmental Sales 10 TOTAL Sales to Ultimate Consumers 2,432,530,596 2,504,687,799 11 (447) Sales for Resale 253,242,272 284,420,338 12 TOTAL Sales of Electricity 2,685,772,868 2,789,108,137 13 (Less) (449.1) Provision for Rate Refunds 4,670,543 10,383,762 14 TOTAL Revenues Net of Prov. for Refunds 2,681,102,325 2,778,724,375 15 Other Operating Revenues 16 (450) Forfeited Discounts 4,470,847 4,568,032 17 (451) Miscellaneous Service Revenues 1,896,615 3,251,323 18 (453) Sales of Water and Water Power 19 (454) Rent from Electric Property 24,503,541 24,577,129 20 (455) Interdepartmental Rents 21 (456) Other Electric Revenues 21,427,718 17,432,999 22 (456.1) Revenues from Transmission of Electricity of Others 123,846,235 117,675,043 23 (457.1) Regional Control Service Revenues 24 (457.2) Miscellaneous Revenues 25 26 TOTAL Other Operating Revenues 176,144,956 167,504,526 27 TOTAL Electric Operating Revenues 2,857,247,281 2,946,228,901
FERC FORM NO. 1/3-Q (REV. 12-05) Page 300 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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.
MEGAWATT HOURS SOLD AVG.NO. CUSTOMERS PER MONTH Line Year to Date Quarterly/Annual Amount Previous year (no Quarterly) Current Year (no Quarterly) Previous Year (no Quarterly) No. (d) (e) (f) (g) 1 10,915,394 11,253,416 810,840 806,338 2 3 5,886,796 6,364,462 137,143 136,120 4 8,873,357 9,546,233 4,210 4,250 5 64,508 64,367 1,716 1,724 6 729,260 792,616 6,253 6,256 7 8 9 26,469,315 28,021,094 960,162 954,688 10 5,600,007 5,820,714 11 32,069,322 33,841,808 960,162 954,688 12 13 32,069,322 33,841,808 960,162 954,688 14
Line 12, column (b) includes $ 21,370,473 of unbilled revenues. Line 12, column (d) includes 193,534 MWH relating to unbilled revenues
FERC FORM NO. 1/3-Q (REV. 12-05) Page 301 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 FOOTNOTE DATA
Schedule Page: 300 Line No.: 10 Column: b Detail of Unmetered Sales included in Total Sales to Ultimate Customers: Account Revenues MWH Sold Average No. of Customers
440 Residential 10,818,968 68,099 83,744
442 Commercial 8,342,548 66,784 23,544
442 Industrial 733,763 6,617 910
444 Street Lighting 22,739 173 50
445 Other Public Sales 370,709 3,022 702
20,288,727 144,695 108,950
Total Sales to Ultimate Consumers include $556,313 of Operating Revenues for distribution service provided to Open Access Customers. Megawatt hours delivered to Open Access Consumers were 374,911 and are included in the reported megawatt hours sold on Pg. 301(d).
Schedule Page: 300 Line No.: 17 Column: b Customer service revenue, including connects, reconnects, disconnects, temporary services and other charges billed to customer. Schedule Page: 300 Line No.: 21 Column: b
Descrption YTD 2020 YTD 2019
Assoc. Business Development 7,924,270 8,387,914 Sale of Renewable Energy Credits 13,061,259 8,594,796 Amort. Of Deferred Equity 295,863 290,135 All Other (under $250K each) 146,326 160,154 Total 21,427,718 17,432,999
FERC 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) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / /
REGIONAL TRANSMISSION SERVICE REVENUES (Account 457.1)
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 Description of Service Balance at End of Balance at End of Balance at End of Balance at End of No. Quarter 1 Quarter 2 Quarter 3 Year (a) (b) (c) (d) (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
46 TOTAL
FERC FORM NO. 1/3-Q (NEW. 12-05) Page 302 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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 Number and Title of Rate schedule MWh Sold Revenue Average Number KWh of Sales Revenue Per of Customers Per Customer KWh Sold No. (a) (b) (c) (d) (e) (f) 1 440 - RESIDENTIAL SALES 2 GS - General Sales 3 OL-Outdoor Lighting 68,100 10,819,060 0.1589 4 RS - Residential Service 10,701,111 1,242,751,064 806,375 13,271 0.1161 5 RSE - Residential Emp. 69,124 7,908,529 4,246 16,280 0.1144 6 RS-LM-TOD Res. Load MGMT TOD 358 40,101 17 21,059 0.1120 7 RS-TOD-Residential TOD 3,129 324,385 196 15,964 0.1037 8 RS - Plug In Elec Veh Charging 23 -673 6 3,833 -0.0293 9 SGS-Small Gen. Service 1 138 0.1380 10 Subtotal -Total Billed 10,841,846 1,261,842,604 810,840 13,371 0.1164 11 Unbilled Revenue 73,548 11,165,294 0.1518 12 TOTAL 440 RESIDENTIAL 10,915,394 1,273,007,898 810,840 13,462 0.1166 13 14 442 - COMMERCIAL 15 Commonwealth of VA 30 16 GS-General Service 3,535,717 308,625,201 20,950 168,769 0.0873 17 GS-PA -General Service -PA 1,654 146,660 7 236,286 0.0887 18 GS-TOD-General Service TOD 44,050 3,873,100 646 68,189 0.0879 19 IP-Industrial Power Service 6,950 426,387 1 6,950,000 0.0614 20 LCP-Large Capacity Power 483,965 34,852,202 49 9,876,837 0.0720 21 LGS-Large General Service 12 1,118 0.0932 22 LGS-TOD - Large General Service-T 22,204 1,972,945 77 288,364 0.0889 23 LPS-Large Power Service 309,174 18,293,767 25 12,366,960 0.0592 24 LPS-TOD-Large Power Ser TOD 38,037 2,803,560 6 6,339,500 0.0737 25 MGS-Medium General Service 217,866 22,384,994 2,890 75,386 0.1027 26 Net Estimated Billing 8 865 0.1081 27 OL-Outdoor Lighting 66,817 8,345,281 0.1249 28 RS-Residential Service 66 7,007 0.1062 29 SGS-Small General Service 771,130 83,800,630 106,941 7,211 0.1087 30 SGS-PA - Small General Service-PA 31 SGS-TOD-Small General Service 3,165 355,970 548 5,776 0.1125 32 SL-Street Lighting 16 2,532 1 16,000 0.1583 33 SS-School Service 242,986 24,618,813 1,083 224,364 0.1013 34 SWS-Sanctuary Worship 90,613 10,815,075 3,918 23,127 0.1194 35 Winterplace 2,151 285,216 1 2,151,000 0.1326 36 Estimated 5,911 392,754 0.0664 37 LGS - TOD - Large General Service 38 Provision for Refund VA 39 Subtotal - Total Billed 5,842,492 522,004,107 137,143 42,601 0.0893 40 Unbilled Revenue 44,304 4,850,656 0.1095
41 TOTAL Billed 26,275,781 2,411,160,123 960,162 27,366 0.0918 42 Total Unbilled Rev.(See Instr. 6) 193,534 21,370,473 0 0 0.1104 43 TOTAL 26,469,315 2,432,530,596 960,162 27,568 0.0919 FERC FORM NO. 1 (ED. 12-95) Page 304 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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 Number and Title of Rate schedule MWh Sold Revenue Average Number KWh of Sales Revenue Per of Customers Per Customer KWh Sold No. (a) (b) (c) (d) (e) (f) 1 TOTAL 442 COMMERCIAL 5,886,796 526,854,763 137,143 42,925 0.0895 2 3 4 5 6 442 - INDUSTRIAL 7 Armstrong 63,443 2,969,669 1 63,443,000 0.0468 8 Constellium Rolled Products 188,236 10,681,205 1 188,236,000 0.0567 9 Felman 245,618 6,623,536 1 245,618,000 0.0270 10 GS-General Service 800,256 67,237,945 1,409 567,960 0.0840 11 GS - PA - General Service - PA 29 2,812 1 29,000 0.0970 12 GS-TOD-General Service TOD 2,013 195,651 22 91,500 0.0972 13 IP-Industrial Power Service 323,326 19,797,813 3 107,775,333 0.0612 14 LCP-Large Capacity Power 2,358,636 165,959,875 105 22,463,200 0.0704 15 LGS-Large General Service 3,744 269,318 1 3,744,000 0.0719 16 LGS-TOD - Large General Service-T 446 57,500 3 148,667 0.1289 17 LPS-Large Power Service 3,305,853 184,692,324 103 32,095,660 0.0559 18 LPS-TOD-Large Power Ser TOD 977,559 60,950,378 41 23,842,902 0.0623 19 MGS-Medium General Service 132,169 13,772,973 409 323,152 0.1042 20 Net Estimated Billings -26,204 -1,064,133 0.0406 21 OL-Outdoor Lighting 6,617 733,763 0.1109 22 SGS-Small General Service 20,132 2,107,183 2,108 9,550 0.1047 23 WV Manufacturing 395,236 21,930,772 1 395,236,000 0.0555 24 Mis Adjustments 929,070 25 WV Recycle 7,467 1,111,321 1 7,467,000 0.1488 26 Subtotal - Total Billed 8,804,576 558,958,975 4,210 2,091,348 0.0635 27 Unbilled Revenue 68,781 4,830,913 0.0702 28 TOTAL 442 INDUSTRIAL 8,873,357 563,789,888 4,210 2,107,686 0.0635 29 30 444 - PUBLIC STREET & HIGHWAY 31 Commonwealth of VA 3,700 375,038 539 6,865 0.1014 32 GS-General Service 1,390 140,147 24 57,917 0.1008 33 GS-TOD-General Service TOD 679 48,669 5 135,800 0.0717 34 MGS-PA-Med Gen Ser - PA 480 45,913 1 480,000 0.0957 35 Net Estimated Billings 36 OL-Outdoor Lighting 173 22,739 0.1314 37 SGS-Small General Service 2,711 344,902 600 4,518 0.1272 38 SGS-PA -Small Gen Ser - PA 1,078 135,030 354 3,045 0.1253 39 SL-Street Lighting 54,172 6,657,482 193 280,684 0.1229 40 Subtotal - Total Billed 64,383 7,769,920 1,716 37,519 0.1207
41 TOTAL Billed 26,275,781 2,411,160,123 960,162 27,366 0.0918 42 Total Unbilled Rev.(See Instr. 6) 193,534 21,370,473 0 0 0.1104 43 TOTAL 26,469,315 2,432,530,596 960,162 27,568 0.0919 FERC FORM NO. 1 (ED. 12-95) Page 304.1 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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 Number and Title of Rate schedule MWh Sold Revenue Average Number KWh of Sales Revenue Per of Customers Per Customer KWh Sold No. (a) (b) (c) (d) (e) (f) 1 Unbilled Revenue 125 13,934 0.1115 2 TOTAL 444 STREET & HIGHWAY 64,508 7,783,854 1,716 37,592 0.1207 3 4 5 6 7 445 - PUBLIC AUTHORITIES 8 Commonwealth of VA 124,005 10,060,123 910 136,269 0.0811 9 Flood Walls 217 9,268 22 9,864 0.0427 10 GS-General Service 22,777 1,604,379 16 1,423,563 0.0704 11 GS-PA -General Service -PA 327,263 26,248,801 635 515,375 0.0802 12 GS-TOD-PA-Gen Ser TOD -PA 2,131 198,192 92 23,163 0.0930 13 LGS-PA-Large Gen Service - PA 14 LPS-TOD-PA Large Pow Ser 61,740 4,529,198 11 5,612,727 0.0734 15 MGS-Medium General Service 1,193 117,559 10 119,300 0.0985 16 MGS-PA-Med Gen Ser - PA 134,902 13,189,722 669 201,647 0.0978 17 Net Estimated Billings 173 13,712 0.0793 18 OL-Outdoor Lighting 3,022 370,709 0.1227 19 SGS-Small General Service 491 48,247 33 14,879 0.0983 20 SGS-PA- Small Gen Ser - PA 43,037 4,266,662 3,835 11,222 0.0991 21 Misc Adjustments -212,653 22 PA - Large General Svc-TOD-Sec 1,443 132,911 19 75,947 0.0921 23 PA - :arge General Svc-TOD-Pri 90 7,687 1 90,000 0.0854 24 Subtotal - Total Billed 722,484 60,584,517 6,253 115,542 0.0839 25 Unbilled Revenue 6,776 509,676 0.0752 26 TOTAL 445 PUBLIC 729,260 61,094,193 6,253 116,626 0.0838 27 28 29 30 31 32 Fuel Adj Clause - See Footnote 33 34 35 36 37 38 39 40
41 TOTAL Billed 26,275,781 2,411,160,123 960,162 27,366 0.0918 42 Total Unbilled Rev.(See Instr. 6) 193,534 21,370,473 0 0 0.1104 43 TOTAL 26,469,315 2,432,530,596 960,162 27,568 0.0919 FERC FORM NO. 1 (ED. 12-95) Page 304.2 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 FOOTNOTE DATA
Schedule Page: 304.2 Line No.: 32 Column: a
2020 Fuel Adjustment Clause Acct F1 Codes Sum of Fuel 4400 RE OL - OUTDOOR LIGHTING 718,701 RS - RESIDENTIAL SERVICE 134,059,261 RSE - RESIDENTIAL SERVICE - EMPLOYEE 521,936 RS-TOD - RESIDENTIAL SERVICE TOD 69,133 SGS - SMALL GENERAL SERVICE 30 Unbilled (66,936) 4400 RE Total 135,302,126 4420 CO Commonwealth of VA 5 Estimated 47,982 GS - GENERAL SERVICE 35,367,944 GS-PA - GENERAL SERVICE-PA 37,809 GS-TOD - GENERAL SERVICE TOD 668,745 LGS - LARGE GENERAL SERVICE 274 LGS-TOD - LARGE GENERAL SERVICE-TOD 492,688 LPS - LARGE POWER SERVICE 6,296,195 LPS-TOD - LARGE POWER SERVICE TOD 860,884 MGS - MEDIUM GENERAL SERVICE 4,887,609 MGS-PA - MEDIUM GENERAL SERVICE-PA 190 OL - OUTDOOR LIGHTING 784,083 RS - RESIDENTIAL SERVICE 80 SGS - SMALL GENERAL SERVICE 12,701,918 SGS-TOD - SMALL GENERAL SERVICE-TOD 698 SL - STREET LIGHTING 376 SWS - SANCTUARY WORSHIP SERVICE 555,217 Unbilled 129,396 4420 CO Total 62,832,093 4420 IN Estimated (362,071) GS - GENERAL SERVICE 11,055,067 GS-PA - GENERAL SERVICE-PA 664 GS-TOD - GENERAL SERVICE TOD 16,471 LGS - LARGE GENERAL SERVICE 86,112 LGS-TOD - LARGE GENERAL SERVICE-TOD 10,064 LPS - LARGE POWER SERVICE 67,698,994 LPS-TOD - LARGE POWER SERVICE TOD 22,052,536 MGS - MEDIUM GENERAL SERVICE 2,993,652 OL - OUTDOOR LIGHTING 89,750 SGS - SMALL GENERAL SERVICE 313,746 Unbilled 652,849 4420 IN Total 104,607,835 4440 PU Commonwealth of VA 87,650 MGS-PA - MEDIUM GENERAL SERVICE-PA 10,818 OL - OUTDOOR LIGHTING 2,074 SGS - SMALL GENERAL SERVICE 209 SGS-PA - SMALL GENERAL SERVICE-PA 24,409 SL - STREET LIGHTING 676,453 Unbilled 670
FERC 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) Appalachian Power Company (2) A Resubmission / / 2020/Q4 FOOTNOTE DATA
4440 PU Total 802,284 4450 OT Commonwealth of VA 2,937,676 Estimated 4,099 GS - GENERAL SERVICE 516,112 GS-PA - GENERAL SERVICE-PA 7,416,080 GS-TOD-PA - GEN SERVICE TOD-PA 48,328 LPS-TOD-PA - LARGE POW SER TOD-PA 1,401,718 MGS - MEDIUM GENERAL SERVICE 26,996 MGS-PA - MEDIUM GENERAL SERVICE-PA 3,056,098 OL - OUTDOOR LIGHTING 68,207 Public Authority-Large General Svc-TOD-Pri 2,039 Public Authority-Large General Svc-TOD-Sec 32,786 SGS - SMALL GENERAL SERVICE 11,161 SGS-PA - SMALL GENERAL SERVICE-PA 973,745 Unbilled 36,439 4450 OT Total 16,531,484 Grand Total 320,075,821
FERC FORM NO. 1 (ED. 12-87) Page 450.2 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / SALES FOR RESALE (Account 447) 1. Report all sales for resale (i.e., 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). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any 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). In addition, the reliability of requirements service must 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. The same as LF service except that "intermediate-term" means longer than one year but Less than five years. SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is 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. The same as LU service except that "intermediate-term" means Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW) Classifi- Schedule or Monthly Billing Average Average No. (Footnote Affiliations) cation Tariff Number Demand (MW) Monthly NCP Demand Monthly CP Demand (a) (b) (c) (d) (e) (f) 1 AMEREX POWER, LTD OS NOTE 1 2 B.P. ENERGY COMPANY OS NOTE 1 3 BGC FINANCIAL LP OS NOTE 1 4 CITIGROUP ENERGY INC. OS NOTE 1 5 CITY OF RADFORD, VA RQ NOTE 1 6 CITY OF SALEM, VA RQ NOTE 1 7 COMMONWEALTH EDISON COMPANYOS NOTE 1 8 CRAIG-BOTETOURT ELECTRIC COOPRQ NOTE 1 9 DP&L POWER SERVICES OS NOTE 1 10 DUKE ENERGY OHIO, INC OS NOTE 1 11 DUQUESNE LIGHT COMPANYOS NOTE 1 12 EVOLUTION MARKETS FUTURES, LLCOS NOTE 1 13 FIRSTENERGY TRADING SERVICESOS NOTE 1 14 ICAP ENERGY LLC OS NOTE 1
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO. 1 (ED. 12-90) Page 310 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / SALES FOR RESALE (Account 447) 1. Report all sales for resale (i.e., 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). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any 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). In addition, the reliability of requirements service must 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. The same as LF service except that "intermediate-term" means longer than one year but Less than five years. SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is 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. The same as LU service except that "intermediate-term" means Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW) Classifi- Schedule or Monthly Billing Average Average No. (Footnote Affiliations) cation Tariff Number Demand (MW) Monthly NCP Demand Monthly CP Demand (a) (b) (c) (d) (e) (f) 1 ICE TRADE VAULT LLC OS NOTE 1 2 IVG ENERGY, LTD OS NOTE 1 3 KINGSPORT RQ 23 4 MIZUHO SECURITIES USA INCOS NOTE 1 5 MORGAN STANLEY CAPT. OS NOTE 1 6 OHIO POWER COMPANY (AUCTION) OS NOTE 1 7 OLD DOMINION ELECTRICRQ NOTE 1 8 PJM INTERCONNECTION OS NOTE 1 9 PJM INTERCONNECTION RQ VARIOUS 10 PPL ELECTRIC UTILITIES CORPOS NOTE 1 11 PVM FUTURES, INC. OS NOTE 1 12 RBC CAPITAL MARKET, LLCOS NOTE 1 13 SPSR2 - MAREX SPECTRONOS NOTE 1 14 TFS ENERGY FUTURES, LLCOS NOTE 1
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO. 1 (ED. 12-90) Page 310.1 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / SALES FOR RESALE (Account 447) 1. Report all sales for resale (i.e., 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). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any 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). In addition, the reliability of requirements service must 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. The same as LF service except that "intermediate-term" means longer than one year but Less than five years. SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is 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. The same as LU service except that "intermediate-term" means Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW) Classifi- Schedule or Monthly Billing Average Average No. (Footnote Affiliations) cation Tariff Number Demand (MW) Monthly NCP Demand Monthly CP Demand (a) (b) (c) (d) (e) (f) 1 TRIDENT BROKERAGE SERVICES, LLCOS NOTE 1 2 TULLETT PREBON AMERICAS CORP.OS NOTE 1 3 UNITED LIGHT & POWER COMPANYRQ 151 4 VIRGINIA TECH RQ 155 5 WABASH VALLEY POWER ASSN INC.OS NOTE 1 6 WELLS FARGO SECURITIES, LLCOS NOTE 1 7 8 9 10 11 12 13 14
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO. 1 (ED. 12-90) Page 310.2 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / SALES FOR RESALE (Account 447) (Continued) OS - for other service. 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 of the service in a footnote. 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. 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 "Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k) 5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under which service, as identified in column (b), is provided. 6. 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 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 (60-minute integration) demand in a month. 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. 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. 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 total charge shown on bills rendered to the purchaser. 9. 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 Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24. 10. Footnote entries as required and provide explanations following all required data.
REVENUE MegaWatt Hours Total ($) Line Other Charges Sold Demand Charges Energy Charges (h+i+j) No. ($) ($) ($) (g) (h) (i) (j) (k) -18,632 -18,632 1 -17,916 -812,515 -812,515 2 -673 -673 3 -295,784 -295,784 4 170,239 5,201,930 7,650,448 12,852,378 5 352,552 10,617,697 14,520,604 25,138,301 6 12,797 354,491 354,491 7 51,935 1,804,967 2,681,558 4,486,525 8 8,104 394,432 394,432 9 39,814 1,925,504 1,925,504 10 19,196 778,842 778,842 11 -20,402 -20,402 12 273,428 12,390,374 12,390,374 13 -10,910 -10,910 14
2,778,691 74,788,594 87,824,109 10,220,796 172,833,499
2,821,316 1,456,362 68,723,497 10,228,914 80,408,773
5,600,007 76,244,956 156,547,606 20,449,710 253,242,272
FERC FORM NO. 1 (ED. 12-90) Page 311 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / SALES FOR RESALE (Account 447) (Continued) OS - for other service. 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 of the service in a footnote. 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. 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 "Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k) 5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under which service, as identified in column (b), is provided. 6. 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 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 (60-minute integration) demand in a month. 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. 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. 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 total charge shown on bills rendered to the purchaser. 9. 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 Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24. 10. Footnote entries as required and provide explanations following all required data.
REVENUE MegaWatt Hours Total ($) Line Other Charges Sold Demand Charges Energy Charges (h+i+j) No. ($) ($) ($) (g) (h) (i) (j) (k) -39,551 -39,551 1 -10,853 -10,853 2 1,700,362 41,659,458 40,428,721 30,239,049 112,327,228 3 -375,452 -375,452 4 26,025 26,025 5 112,718 5,326,116 5,326,116 6 147,082 5,497,240 7,689,393 13,186,633 7 1,962,049 1,456,362 41,279,588 4,902,798 47,638,748 8 -20,018,253 -20,018,253 9 411,126 18,450,068 18,450,068 10 -94 -94 11 -2,079,168 -2,079,168 12 -179 -179 13 -12,395 -12,395 14
2,778,691 74,788,594 87,824,109 10,220,796 172,833,499
2,821,316 1,456,362 68,723,497 10,228,914 80,408,773
5,600,007 76,244,956 156,547,606 20,449,710 253,242,272
FERC FORM NO. 1 (ED. 12-90) Page 311.1 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / SALES FOR RESALE (Account 447) (Continued) OS - for other service. 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 of the service in a footnote. 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. 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 "Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k) 5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under which service, as identified in column (b), is provided. 6. 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 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 (60-minute integration) demand in a month. 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. 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. 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 total charge shown on bills rendered to the purchaser. 9. 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 Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24. 10. Footnote entries as required and provide explanations following all required data.
REVENUE MegaWatt Hours Total ($) Line Other Charges Sold Demand Charges Energy Charges (h+i+j) No. ($) ($) ($) (g) (h) (i) (j) (k) -6,593 -6,593 1 -42,829 -42,829 2 52,524 1,757,845 2,572,241 4,330,086 3 303,997 8,249,457 12,281,144 20,530,601 4 1,372,825 1,372,825 5 -4,522,622 -4,522,622 6 7 8 9 10 11 12 13 14
2,778,691 74,788,594 87,824,109 10,220,796 172,833,499
2,821,316 1,456,362 68,723,497 10,228,914 80,408,773
5,600,007 76,244,956 156,547,606 20,449,710 253,242,272
FERC FORM NO. 1 (ED. 12-90) Page 311.2 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 FOOTNOTE DATA
Schedule Page: 310 Line No.: 1 Column: c FERC Electric Tariff, First Revised Volume No. 5 Schedule Page: 310 Line No.: 5 Column: k Margins for Off System Sales (OSS) reported in APCo’s generation formula rates are included in the total revenue amount. The margins are specifically identified in the ledger as a subset of the accounts that make up these OSS revenues. Schedule Page: 310.1 Line No.: 3 Column: a An affiliated company Schedule Page: 310.1 Line No.: 3 Column: j Amount represents transmission services and related charges. Schedule Page: 310.1 Line No.: 6 Column: a An affiliated company Schedule Page: 310.1 Line No.: 6 Column: c The PUCO (Public Utilities Commission Ohio) ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning June 2015. APCo, KPCo, I&M and WPCo participated in the auction process and were awarded tranches of OPCo's SSO load. Schedule Page: 310.1 Line No.: 9 Column: j PJM transmission expenses related to wholesale customers.
FERC 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) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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 Amount for Current Year Previous Year No. (a) (b) (c) 1 1. POWER PRODUCTION EXPENSES 2 A. Steam Power Generation 3 Operation 4 (500) Operation Supervision and Engineering 19,580,783 24,883,610 5 (501) Fuel 485,092,339 567,523,063 6 (502) Steam Expenses 45,366,636 44,334,487 7 (503) Steam from Other Sources 8 (Less) (504) Steam Transferred-Cr. 9 (505) Electric Expenses 158,435 265,727 10 (506) Miscellaneous Steam Power Expenses 24,830,921 25,762,882 11 (507) Rents 33,986 34,546 12 (509) Allowances 163,232 160,796 13 TOTAL Operation (Enter Total of Lines 4 thru 12) 575,226,332 662,965,111 14 Maintenance 15 (510) Maintenance Supervision and Engineering 1,492,108 4,816,499 16 (511) Maintenance of Structures 5,364,801 3,894,362 17 (512) Maintenance of Boiler Plant 48,740,249 52,906,182 18 (513) Maintenance of Electric Plant 12,987,780 14,348,709 19 (514) Maintenance of Miscellaneous Steam Plant 13,756,943 16,179,033 20 TOTAL Maintenance (Enter Total of Lines 15 thru 19) 82,341,881 92,144,785 21 TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20) 657,568,213 755,109,896 22 B. Nuclear Power Generation 23 Operation 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 32 (525) Rents 33 TOTAL Operation (Enter Total of lines 24 thru 32) 34 Maintenance 35 (528) Maintenance Supervision and Engineering 36 (529) Maintenance of Structures 37 (530) Maintenance of Reactor Plant Equipment 38 (531) Maintenance of Electric Plant 39 (532) Maintenance of Miscellaneous Nuclear Plant 40 TOTAL Maintenance (Enter Total of lines 35 thru 39) 41 TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40) 42 C. Hydraulic Power Generation 43 Operation 44 (535) Operation Supervision and Engineering 1,994,342 1,623,530 45 (536) Water for Power -4,328 32,374 46 (537) Hydraulic Expenses 1,548,939 1,157,614 47 (538) Electric Expenses 341,514 102,780 48 (539) Miscellaneous Hydraulic Power Generation Expenses 3,564,001 3,834,398 49 (540) Rents 358,157 321,833 50 TOTAL Operation (Enter Total of Lines 44 thru 49) 7,802,625 7,072,529 51 C. Hydraulic Power Generation (Continued) 52 Maintenance 53 (541) Mainentance Supervision and Engineering 132,398 397,307 54 (542) Maintenance of Structures 2,595,229 3,559,314 55 (543) Maintenance of Reservoirs, Dams, and Waterways 2,929,688 3,362,154 56 (544) Maintenance of Electric Plant 3,703,409 3,563,324 57 (545) Maintenance of Miscellaneous Hydraulic Plant 228,146 302,094 58 TOTAL Maintenance (Enter Total of lines 53 thru 57) 9,588,870 11,184,193 59 TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58) 17,391,495 18,256,722
FERC FORM NO. 1 (ED. 12-93) Page 320 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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 for Amount for Current Year Previous Year No. (a) (b) (c) 60 D. Other Power Generation 61 Operation 62 (546) Operation Supervision and Engineering 243,960 295,350 63 (547) Fuel 2,852,066 9,810,099 64 (548) Generation Expenses 497,146 380,408 65 (549) Miscellaneous Other Power Generation Expenses 98,398 18,155 66 (550) Rents 67 TOTAL Operation (Enter Total of lines 62 thru 66) 3,691,570 10,504,012 68 Maintenance 69 (551) Maintenance Supervision and Engineering 70 (552) Maintenance of Structures 71 (553) Maintenance of Generating and Electric Plant 352,118 617,471 72 (554) Maintenance of Miscellaneous Other Power Generation Plant 73 TOTAL Maintenance (Enter Total of lines 69 thru 72) 352,118 617,471 74 TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73) 4,043,688 11,121,483 75 E. Other Power Supply Expenses 76 (555) Purchased Power 377,188,759 413,014,666 77 (556) System Control and Load Dispatching 2,355,977 2,239,090 78 (557) Other Expenses 5,349,298 7,130,025 79 TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78) 384,894,034 422,383,781 80 TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74 & 79) 1,063,897,430 1,206,871,882 81 2. TRANSMISSION EXPENSES 82 Operation 83 (560) Operation Supervision and Engineering 12,930,558 15,586,110 84 85 (561.1) Load Dispatch-Reliability 86 (561.2) Load Dispatch-Monitor and Operate Transmission System 2,188,799 2,505,558 87 (561.3) Load Dispatch-Transmission Service and Scheduling 88 (561.4) Scheduling, System Control and Dispatch Services 5,987,262 6,557,271 89 (561.5) Reliability, Planning and Standards Development 588,212 649,169 90 (561.6) Transmission Service Studies 91 (561.7) Generation Interconnection Studies 92 (561.8) Reliability, Planning and Standards Development Services 1,737,955 1,714,380 93 (562) Station Expenses 1,454,374 1,439,319 94 (563) Overhead Lines Expenses 174,437 126,378 95 (564) Underground Lines Expenses 1,465 324,888 96 (565) Transmission of Electricity by Others 254,463,359 204,657,356 97 (566) Miscellaneous Transmission Expenses -40,014,724 20,771,532 98 (567) Rents 85,275 128,681 99 TOTAL Operation (Enter Total of lines 83 thru 98) 239,596,972 254,460,642 100 Maintenance 101 (568) Maintenance Supervision and Engineering 94,722 230,935 102 (569) Maintenance of Structures 89,901 77,481 103 (569.1) Maintenance of Computer Hardware 31,683 40,940 104 (569.2) Maintenance of Computer Software 772,637 808,964 105 (569.3) Maintenance of Communication Equipment 44,801 100,463 106 (569.4) Maintenance of Miscellaneous Regional Transmission Plant 107 (570) Maintenance of Station Equipment 2,864,569 3,586,885 108 (571) Maintenance of Overhead Lines 13,217,088 19,153,144 109 (572) Maintenance of Underground Lines 5,447 2,160 110 (573) Maintenance of Miscellaneous Transmission Plant 95,731 153,410 111 TOTAL Maintenance (Total of lines 101 thru 110) 17,216,579 24,154,382 112 TOTAL Transmission Expenses (Total of lines 99 and 111) 256,813,551 278,615,024
FERC FORM NO. 1 (ED. 12-93) Page 321 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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 for Amount for Current Year Previous Year No. (a) (b) (c) 113 3. REGIONAL MARKET EXPENSES 114 Operation 115 (575.1) Operation Supervision 116 (575.2) Day-Ahead and Real-Time Market Facilitation 117 (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 5,580,830 5,845,904 122 (575.8) Rents 123 Total Operation (Lines 115 thru 122) 5,580,830 5,845,904 124 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 125 thru 129) 131 TOTAL Regional Transmission and Market Op Expns (Total 123 and 130) 5,580,830 5,845,904 132 4. DISTRIBUTION EXPENSES 133 Operation 134 (580) Operation Supervision and Engineering 4,433,265 5,730,651 135 (581) Load Dispatching 15,388 25,081 136 (582) Station Expenses 1,206,100 1,532,122 137 (583) Overhead Line Expenses 1,687,661 2,854,385 138 (584) Underground Line Expenses 2,261,467 1,511,747 139 (585) Street Lighting and Signal System Expenses 87,371 55,929 140 (586) Meter Expenses 594,852 2,243,508 141 (587) Customer Installations Expenses 746,941 925,747 142 (588) Miscellaneous Expenses 19,071,388 17,017,994 143 (589) Rents 1,597,629 1,605,860 144 TOTAL Operation (Enter Total of lines 134 thru 143) 31,702,062 33,503,024 145 Maintenance 146 (590) Maintenance Supervision and Engineering 169,496 165,195 147 (591) Maintenance of Structures 179,931 179,324 148 (592) Maintenance of Station Equipment 1,312,620 1,472,415 149 (593) Maintenance of Overhead Lines 96,387,866 103,852,599 150 (594) Maintenance of Underground Lines 1,227,471 1,260,011 151 (595) Maintenance of Line Transformers 2,242,445 2,502,657 152 (596) Maintenance of Street Lighting and Signal Systems 463,857 498,138 153 (597) Maintenance of Meters 314,981 390,441 154 (598) Maintenance of Miscellaneous Distribution Plant 4,570,775 4,923,167 155 TOTAL Maintenance (Total of lines 146 thru 154) 106,869,442 115,243,947 156 TOTAL Distribution Expenses (Total of lines 144 and 155) 138,571,504 148,746,971 157 5. CUSTOMER ACCOUNTS EXPENSES 158 Operation 159 (901) Supervision 428,418 534,298 160 (902) Meter Reading Expenses 4,109,056 4,873,104 161 (903) Customer Records and Collection Expenses 22,414,866 26,777,725 162 (904) Uncollectible Accounts 4,605,308 6,495,370 163 (905) Miscellaneous Customer Accounts Expenses 156,085 186,037 164 TOTAL Customer Accounts Expenses (Total of lines 159 thru 163) 31,713,733 38,866,534
FERC FORM NO. 1 (ED. 12-93) Page 322 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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 for Amount for Current Year Previous Year No. (a) (b) (c) 165 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES 166 Operation 167 (907) Supervision 539,955 581,007 168 (908) Customer Assistance Expenses 15,531,464 19,175,093 169 (909) Informational and Instructional Expenses 170 (910) Miscellaneous Customer Service and Informational Expenses 71,606 41,383 171 TOTAL Customer Service and Information Expenses (Total 167 thru 170) 16,143,025 19,797,483 172 7. SALES EXPENSES 173 Operation 174 (911) Supervision 539 2,459 175 (912) Demonstrating and Selling Expenses 279,273 321,871 176 (913) Advertising Expenses 177 (916) Miscellaneous Sales Expenses 178 TOTAL Sales Expenses (Enter Total of lines 174 thru 177) 279,812 324,330 179 8. ADMINISTRATIVE AND GENERAL EXPENSES 180 Operation 181 (920) Administrative and General Salaries 45,730,119 43,855,062 182 (921) Office Supplies and Expenses 3,359,025 4,726,718 183 (Less) (922) Administrative Expenses Transferred-Credit 6,760,299 5,992,645 184 (923) Outside Services Employed 8,899,129 10,095,870 185 (924) Property Insurance 4,902,652 4,696,745 186 (925) Injuries and Damages 6,771,456 5,909,079 187 (926) Employee Pensions and Benefits 5,754,311 6,211,060 188 (927) Franchise Requirements 189 (928) Regulatory Commission Expenses 6,065,976 3,355,864 190 (929) (Less) Duplicate Charges-Cr. 134,872 128,387 191 (930.1) General Advertising Expenses 340,179 509,375 192 (930.2) Miscellaneous General Expenses 6,591,353 6,606,769 193 (931) Rents 1,649,801 1,624,177 194 TOTAL Operation (Enter Total of lines 181 thru 193) 83,168,830 81,469,687 195 Maintenance 196 (935) Maintenance of General Plant 10,451,943 12,083,823 197 TOTAL Administrative & General Expenses (Total of lines 194 and 196) 93,620,773 93,553,510 198 TOTAL Elec Op and Maint Expns (Total 80,112,131,156,164,171,178,197) 1,606,620,658 1,792,621,638
FERC FORM NO. 1 (ED. 12-93) Page 323 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 FOOTNOTE DATA
Schedule Page: 320 Line No.: 5 Column: b The portion of account 501 that is excluded from the fuel costs in APCo's generation formula rate is identified by a query of the general ledger. Schedule Page: 320 Line No.: 59 Column: b ydraulic Power Generation:
Hydraulic Power Generation includes Pumped Storage – See Page 408. Schedule Page: 320 Line No.: 93 Column: b Generation Step-Up Units’ (GSUs) O&M expenses included in APCo’s generation formula rates are the ratio of GSU balances to all investment for plant accounts 352 & 353 multiplied by the balance in O&M accounts 562, 569, 570. Schedule Page: 320 Line No.: 103 Column: b Allocated maintenance expenses for joint use computer hardware, computer software and communication equipment are determined by using various factors, which include number of remote terminal units, number of radios, number of employees and other factors assigned to each function. Schedule Page: 320 Line No.: 148 Column: b Account 592.2 contains $0 for maintenance of energy storage equipment. Schedule Page: 320 Line No.: 185 Column: b The insurance expenses for generation included in APCo’s generation formula rate are identified by a query of the general ledger.
FERC 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) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / PURCHASED POWER (Account 555) (Including power exchanges) 1. 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. 2. 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 acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller. 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 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 which meets the definition of RQ 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 than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is 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 the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc. and any settlements for imbalanced exchanges.
OS - for other service. 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 of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW) Classifi- Schedule or Monthly Billing Average Average No. (Footnote Affiliations) cation Tariff Number Demand (MW) Monthly NCP Demand Monthly CP Demand (a) (b) (c) (d) (e) (f) 1 BEECH RIDGE ENERGY LLC OS 2 BLUFF POINT WIND ENERGY CENTER OS 3 CAMP GROVE WIND FARM LLC OS 4 FOWLER RIDGE III WIND FARM LLC OS 5 GAULEY RIVER POWERS PARTNERS OS 6 GRAND RIDGE ENERGY II LLC OS 7 GRAND RIDGE WIND FARM 3 OS 8 ICE TRADE VAULT LLC OS 9 LUMINAIRE TECHNOLOGIES, INC. OS 10 OLD DOMINION ELECTRIC OS 11 OVEC POWER SCHEDULING OS 12 PJM INTERCONNECTION OS 13 WIND DEFERRAL OS 14
Total
FERC FORM NO. 1 (ED. 12-90) Page 326 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / PURCHASED POWER(Account 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 (60-minute integration) demand in a month. 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. Footnote any demand not stated on a megawatt basis and explain. 6. 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-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). 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 (l) 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.
POWER EXCHANGES COST/SETTLEMENT OF POWER MegaWatt Hours Line MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l) Purchased No. Received Delivered ($) ($) ($) of Settlement ($) (g) (h) (i) (j) (k) (l) (m) 277,057 24,603,731 24,603,731 1 370,848 13,703,252 13,703,252 2 200,251 13,312,860 13,312,860 3 220,299 15,299,203 15,299,203 4 234,869 10,803,831 10,803,831 5 121,415 11,568,426 11,568,426 6 116,705 11,117,057 11,117,057 7 3,697 3,697 8 1,390 5,329 91,849 97,178 9 4 2,891 2,891 10 1,442,042 55,465,545 38,923,097 94,388,642 11 9,129,832 140,778 185,922,550 186,063,328 12 -3,775,337 -3,775,337 13 14
12,114,712 55,611,652 321,577,107 377,188,759
FERC FORM NO. 1 (ED. 12-90) Page 327 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 FOOTNOTE DATA
Schedule Page: 326 Line No.: 13 Column: a Deferral to track incremental costs related to approved RPS program, PER Virginia State Corporation Commission in APCo's RPS-RAC Case No. PUE-2020-00015.
FERC 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) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as 'wheeling') 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 column (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, 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 periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical (Company of Public Authority) (Company of Public Authority) (Company of Public Authority) Classifi- No. (Footnote Affiliation) (Footnote Affiliation) (Footnote Affiliation) cation (a) (b) (c) (d) 1 PJM Network Integ Trans Rev Whlsle Various Various FNO 2 PJM Network Integ Trans Serv Various Various FNO 3 PJM Trans Enhancement Rev Various Various FNO 4 PJM Trans Enhancement Rev Whlsle Various Various FNO 5 PJM Trans Enhancement Rev - Affil Various Various FNO 6 PJM Network Integ Rev - Affil Various Various FNO 7 PJM Point to Point Trans Serv Various Various LFP 8 PJM Trans Owner Admin Revenue Various Various OLF 9 PJM Trans Owner Serv Rev Whlsle Various Various OLF 10 PJM Power Factor Credits Rev Whlsl Various Various OS 11 PJM Power Factor Credits Rev Nonaffiliated Various Various OS 12 PJM Trans Distribution & Meter Various Various OS 13 RTO Formation Costs Recovery Various Various OS 14 SECA Transmission Rev Various Various OS 15 PJM Trans Owner Serv Revenue Affiliated Various Various OLF 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34
TOTAL
FERC FORM NO. 1 (ED. 12-90) Page 328 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued) (Including transactions reffered to as 'wheeling') 5. In column (e), 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 (d), is provided. 6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. 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 contract. 7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain. 8. Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY Line Schedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours MegaWatt Hours No. Tariff Number Designation) Designation) (MW) Received Delivered (e) (f) (g) (h) (i) (j) PJM OATT Various Various 1 PJM OATT Various Various 2 PJM OATT Various Various 3 PJM OATT Various Various 4 PJM OATT Various Various 5 PJM OATT Various Various 6 PJM OATT Various Various 7 PJM OATT Various Various 8 PJM OATT Various Various 9 PJM OATT Various Various 10 PJM OATT Various Various 11 PJM OATT Various Various 12 PJM OATT Various Various 13 PJM OATT Various Various 14 PJM OATT Various Various 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34
0 0 0
FERC FORM NO. 1 (ED. 12-90) Page 329 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued) (Including transactions reffered to as 'wheeling') 9. 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 amount of energy transferred. 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 (n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered. 10. 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. 11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS Demand Charges Energy Charges (Other Charges) Total Revenues ($) Line ($) ($) ($) (k+l+m) No. (k) (l) (m) (n) 11,914,596 11,914,596 1 43,122,306 43,122,306 2 6,825,591 6,825,591 3 256,159 256,159 4 -5,490 -5,490 5 52,880,927 52,880,927 6 6,838,493 6,838,493 7 600,473 600,473 8 85,536 85,536 9 108,148 108,148 10 195,255 195,255 11 105,184 105,184 12 -23,371 -23,371 13 80,536 80,536 14 861,892 861,892 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34
121,809,211 1,547,901 489,123 123,846,235
FERC FORM NO. 1 (ED. 12-90) Page 330 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 FOOTNOTE DATA
Schedule Page: 328 Line No.: 1 Column: e Effective October 1, 2004, the administration of the transmission tariff was turned over to PJM. PJM does not provide any detail except for the total revenue by the major classes listed. OATT (Open Access Transmission Tariff) 3rd revised Volume No. 6. Schedule Page: 328 Line No.: 10 Column: m Per Proforma ILDSA (Interconnection and Local Delivery Service Agreement) AEP Tariff 3rd Revised Volume No. 6 Schedule Page: 328 Line No.: 11 Column: m Per Proforma ILDSA (Interconnection and Local Delivery Service Agreement) AEP Tariff 3rd Revised Volume No. 6 Schedule Page: 328 Line No.: 12 Column: m Per Proforma ILDSA (Interconnection and Local Delivery Service Agreement) AEP Tariff 3rd Revised Volume No. 6
Schedule Page: 328 Line No.: 14 Column: m Settlement of Seams Elimination Cost Allocation (SECA) revenue, which was subject to refund. Amount represents reserves that exceeded settlement.
FERC 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) Appalachian Power Company End of 2020/Q4 (2) A 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 periods. 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 Payment Received by Statistical FERC Rate Schedule Total Revenue by Rate Total Revenue No. (Transmission Owner Name) Classification or Tariff Number Schedule or Tarirff (a) (b) (c) (d) (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 TOTAL
FERC FORM NO. 1/3-Q (REV 03-07) Page 331 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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 OTHERS No. Name of Company or Public Statistical Magawatt- Magawatt- Demand Energy Other Total Cost of hours hours Charges Charges Charges Transmission Authority (Footnote Affiliations) Classification Received Delivered ($) ($) ($) ($) (a) (b) (c) (d) (e) (f) (g) (h) 1 PJM-Enhancements OS 38,609,281 38,609,281 2 PJM-NITS OS 214,810,453 214,810,453 3 PJM - Trans Owner Serv OS 1,043,625 1,043,625 4 5 6 7 8 9 10 11 12 13 14 15 16
TOTAL 254,463,359 254,463,359
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 FOOTNOTE DATA
Schedule Page: 332 Line No.: 1 Column: g Transmission Enhancement Charges and Credits (PJM OATT Schedule 12) Schedule Page: 332 Line No.: 2 Column: g Network Integration Transmission Service Charges - NITS (PJM OATT Attachment H) Schedule Page: 332 Line No.: 3 Column: g Transmission Owner Charges and Credits (PJM OATT Tariff Sixth Revised Volume No. 1.)
FERC 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) Appalachian Power Company X End of 2020/Q4 (2) A Resubmission / / MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC) Line Description Amount No. (a) (b) 1 Industry Association Dues 538,895 2 Nuclear Power Research Expenses 3 Other Experimental and General Research Expenses 356 4 Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities 5 Oth Expn >=5,000 show purpose, recipient, amount. Group if < $5,000 6 Associated Business Development 5,062,828 7 Affiliated Intercompany Billings 521,046 8 Broadband Study 178,660 9 Corporate Contributions and Memberships 84,259 10 Various Chambers of Commerce 83,199 11 Trustee Fees 75,720 12 Utility Corp Borrowing Program Shared Costs 43,451 13 Various Expenses 2,939 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 6,591,353
FERC FORM NO. 1 (ED. 12-94) Page 335 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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 (Account 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 composite 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 plant 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. Summary of Depreciation and Amortization Charges Depreciation Amortization of Line Depreciation Expense for Asset Limited Term Amortization of Functional Classification Expense Retirement Costs Electric Plant Other Electric Total No. (Account 403) (Account 403.1) (Account 404) Plant (Acc 405) (a) (b) (c) (d) (e) (f) 1 Intangible Plant 34,304,380 34,304,380 2 Steam Production Plant 206,910,855 2,866,016 209,776,871 3 Nuclear Production Plant 4 Hydraulic Production Plant-Conventional 8,625,283 30,476 8,655,759 5 Hydraulic Production Plant-Pumped Storage 5,696,544 45,648 5,742,192 6 Other Production Plant 18,909,499 18,909,499 7 Transmission Plant 81,853,641 81,853,641 8 Distribution Plant 179,230,020 69 179,230,089 9 Regional Transmission and Market Operation 10 General Plant 10,596,327 36,705 399,623 11,032,655 11 Common Plant-Electric 12 TOTAL 511,822,169 2,978,914 34,704,003 549,505,086
B. Basis for Amortization Charges
Section A Line 1 Column D represents amortization of capitalized software development costs over a 5 year life and costs associated with the Oracle strategic partnership which are over a 10 year life.
Section A Line 10, Column D represents amortization of leasehold improvements over the lives of the related assets.
FERC FORM NO. 1 (REV. 12-03) Page 336 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges Line Depreciable Estimated Net Applied Mortality Average No. Account No. Plant Base Avg. Service Salvage Depr. rates Curve Remaining (In Thousands) Life (Percent) (Percent) Type Life (a) (b) (c) (d) (e) (f) (g) 12 STEAM 13 311 - Amos U1&2 56,637 61.00 3.00 3.07 14 311 - Amos U3 115,483 60.00 3.00 2.97 15 311 - Central Plt Maint 86 2.02 16 311 - Clinch River 26,863 67.00 4.00 0.94 17 311 - Little Broad Mtn 267 3.62 18 311 - Mountaineer 200,250 60.00 5.00 2.92 19 312 - Amos U1&2 1,368,332 61.00 3.00 3.91 20 312 - Amos U1&2 SCR 20,163 61.00 3.00 7.26 21 312 - Amos U3 1,562,655 60.00 3.00 4.06 22 312 - Amos U3 SCR 18,634 60.00 3.00 9.72 23 312 - Clinch River 214,668 67.00 4.00 5.43 24 312 - Little Broad Mtn 50,334 3.71 25 312 - Mountaineer 1,148,820 60.00 5.00 3.07 26 312 - Mountaineer SCR 18,740 8.00 5.00 10.85 27 314 - Amos U1&2 126,026 61.00 3.00 4.96 28 314 - Amos U3 159,507 60.00 3.00 4.50 29 314 - Clinch River 40,581 67.00 4.00 -2.37 30 314 - Mountaineer 127,081 60.00 5.00 3.10 31 315 - Amos U1&2 57,003 61.00 3.00 3.91 32 315 - Amos U3 37,053 60.00 3.00 2.85 33 315 - Clinch River 10,953 67.00 4.00 -1.31 34 315 - Little Broad Mtn 65 3.76 35 315 - Mountaineer 76,225 60.00 5.00 1.87 36 316 - Amos U1&2 5,350 61.00 3.00 5.08 37 316 - Amos U3 28,765 60.00 3.00 3.20 38 316 - Centrl Mach Shop 18,478 2.63 39 316 - Clinch River 6,380 67.00 4.00 4.26 40 316 - Mountaineer 22,701 60.00 5.00 2.54 41 TOTAL STEAM 5,518,100 42 43 HYDRO 44 331 - Buck Hydro 570 112.00 24.00 4.90 45 331 - Byllesby Hydro 1,216 112.00 24.00 9.83 46 331 - Claytor Hydro 3,863 102.00 24.00 3.08 47 331 - Leesville Hydro 3,839 76.00 24.00 2.77 48 331 - London Hydro 617 109.00 24.00 2.69 49 331 - Marmet Hydro 707 109.00 24.00 2.01 50 331 - Niagara Hydro 678 118.00 24.00 16.63
FERC FORM NO. 1 (REV. 12-03) Page 337 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges Line Depreciable Estimated Net Applied Mortality Average No. Account No. Plant Base Avg. Service Salvage Depr. rates Curve Remaining (In Thousands) Life (Percent) (Percent) Type Life (a) (b) (c) (d) (e) (f) (g) 12 331 - Winfield Hydro 2,754 106.00 24.00 2.97 13 332 - Buck Hydro 7,894 112.00 24.00 9.32 14 332 - Byllesby Hydro 7,434 112.00 24.00 12.90 15 332 - Claytor Hydro 12,714 102.00 24.00 2.19 16 332 - Leesville Hydro 11,070 76.00 24.00 2.19 17 332 - London Hydro 1,500 109.00 24.00 1.97 18 332 - Marmet Hydro 1,880 109.00 24.00 2.33 19 332 - Niagara Hydro 6,442 118.00 24.00 9.35 20 332 - Winfield Hydro 2,767 106.00 24.00 2.22 21 333 - Buck Hydro 1,937 112.00 24.00 6.77 22 333 - Byllesby Hydro 3,697 112.00 24.00 11.69 23 333 - Claytor Hydro 4,184 102.00 24.00 3.08 24 333 - Leesville Hydro 3,764 76.00 24.00 2.02 25 333 - London Hydro 5,413 109.00 24.00 2.99 26 333 - Marmet Hydro 8,696 109.00 24.00 3.40 27 333 - Niagara Hydro 640 118.00 24.00 5.23 28 333 - Winfield Hydro 7,175 106.00 24.00 3.32 29 334 - Buck Hydro 2,518 112.00 24.00 7.71 30 334 - Byllesby Hydro 1,081 112.00 24.00 7.18 31 334 - Claytor Hydro 3,103 102.00 24.00 2.65 32 334 - Leesville Hydro 1,975 76.00 24.00 4.03 33 334 - London Hydro 1,904 109.00 24.00 2.16 34 334 - Marmet Hydro 2,191 109.00 24.00 2.21 35 334 - Niagara Hydro 500 118.00 24.00 13.51 36 334 - Winfield Hydro 270 106.00 24.00 3.18 37 335 - Buck Hydro 938 112.00 24.00 14.45 38 335 - Byllesby Hydro 1,016 112.00 24.00 9.53 39 335 - Claytor Hydro 3,032 102.00 24.00 3.27 40 335 - Leesville Hydro 3,111 76.00 24.00 3.34 41 335 - London Hydro 480 109.00 24.00 2.66 42 335 - Marmet Hydro 668 109.00 24.00 2.44 43 335 - Niagara Hydro 307 118.00 24.00 8.85 44 335 - Winfield Hydro 3,210 106.00 24.00 2.02 45 336 - Buck Hydro 3 112.00 24.00 2.44 46 336 - Claytor Hydro 32 102.00 24.00 0.98 47 336 - Leesville Hydro 81 76.00 24.00 0.99 48 336 - London Hydro 49 109.00 24.00 1.19 49 336 - Marmet Hydro 1 109.00 24.00 1.16 50 336 - Winfield Hydro 24 106.00 24.00 2.09
FERC FORM NO. 1 (REV. 12-03) Page 337.1 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges Line Depreciable Estimated Net Applied Mortality Average No. Account No. Plant Base Avg. Service Salvage Depr. rates Curve Remaining (In Thousands) Life (Percent) (Percent) Type Life (a) (b) (c) (d) (e) (f) (g) 12 TOTAL HYDRO 127,945 13 14 HYDRO PUMPED 15 331 16,356 75.00 24.00 2.14 16 332 31,177 75.00 24.00 1.54 17 333 78,238 75.00 24.00 3.38 18 334 12,428 75.00 24.00 3.66 19 335 10,235 75.00 24.00 3.66 20 336 1,052 75.00 24.00 1.05 21 TOTAL HYDRO PUMPED 149,486 22 23 OTHER GENERATION 24 341 Ceredo Plant 1,652 40.00 1.27 25 341 Dresden Plant 47,150 35.00 -1.00 3.34 26 341 Dresden - VA AFUDC 900 17.78 27 342 Dresden Plant 26,155 35.00 -1.00 3.01 28 342 Dresden - VA AFUDC 450 17.78 29 344 Ceredo Plant 180,835 40.00 1.32 30 344 Dresden Plant 316,990 35.00 -1.00 3.07 31 344 Dresden - VA AFUDC 6,207 17.78 32 345 Ceredo Plant 19,380 40.00 1.48 33 345 Dresden Plant 27,885 35.00 -1.00 3.26 34 345 Dresden - VA AFUDC 450 17.78 35 346 Ceredo Plant 1,269 40.00 3.70 36 346 Dresden Plant 30,257 35.00 -1.00 3.74 37 346 Dresden - VA AFUDC 73 17.78 38 348 Battery Storage 5,726 5.00 39 TOTAL OTHER 665,379 40 41 TRANSMISSION 42 350 - VA (Rights) 94,628 0.66 43 352 114,248 60.00 20.00 1.86 R3 44 353 1,816,067 43.00 10.00 2.52 R2 45 353 Dresden Plant - VA 908 17.78 46 353.16 8,286 43.00 10.00 2.52 R2 47 354 508,606 75.00 19.00 1.67 R4 48 355 479,078 37.00 20.00 3.03 L1.5 49 356 664,248 68.00 8.00 1.66 R4 50 356.16 25,717 68.00 8.00 1.66 R4
FERC FORM NO. 1 (REV. 12-03) Page 337.2 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges Line Depreciable Estimated Net Applied Mortality Average No. Account No. Plant Base Avg. Service Salvage Depr. rates Curve Remaining (In Thousands) Life (Percent) (Percent) Type Life (a) (b) (c) (d) (e) (f) (g) 12 357 9,739 42.00 2.97S6 13 358 20,733 24.00 4.70 L3.5 14 358.16 2,819 24.00 4.70 L3.5 15 TOTAL TRANSMISSION 3,745,077 16 17 DISTRIBUTION 18 360 - VA (Rights) 24,144 1.49 19 361 - VA 35,945 50.00 10.00 2.46 R5 20 361 - WV 25,453 55.00 12.00 1.90 R3 21 361-373 - TN 47 4.00 22 362 - VA 388,201 50.00 19.00 2.32 L0.5 23 362 - WV 269,706 45.00 16.00 2.52 R1 24 362.16 - VA 4,269 50.00 19.00 2.32 L0.5 25 362.16 - WV 3,097 45.00 16.00 2.52 R1 26 363 - VA 8 15.00 6.67SQ 27 363 - WV 5,403 15.00 7.38SQ 28 364 - VA 418,536 40.00 72.00 3.65 R0.5 29 364 - WV 416,334 33.00 67.00 4.77 R0.5 30 365 - VA 540,198 35.00 18.00 3.30 R0.5 31 365 - WV 495,498 35.00 16.00 3.38 R0.5 32 366 - VA 78,718 57.00 1.61R4 33 366 - WV 61,144 55.00 1.73R4 34 367 - VA 199,531 51.00 1.83 R2.5 35 367 - WV 115,028 48.00 2.05 R1.5 36 368 - VA 391,392 35.00 21.00 3.05 L0 37 368 - WV 240,666 27.00 20.00 4.65 R0.5 38 369 - VA 189,481 35.00 28.00 3.48 L1.5 39 369 - WV 172,039 30.00 26.00 4.22 R0.5 40 370 - VA 31,132 15.00 6.00 8.14 L1 41 370 - WV 51,573 15.00 10.00 12.43 S6 42 370.16 - VA 84,846 15.00 6.00 8.14 L1 43 370.16 - WA 24,606 15.00 10.00 12.43 S6 44 371 - VA 38,390 16.00 21.00 4.73 L0 45 371 - WV 23,842 12.00 22.00 9.30 R0.5 46 372 - VA 1 25.00 2.01L3 47 373 - VA 20,439 23.00 33.00 4.91 R0.5 48 373 - WV 10,468 20.00 31.00 8.17 R0.5 49 TOTAL DISTRIBUTION 4,360,135 50
FERC FORM NO. 1 (REV. 12-03) Page 337.3 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges Line Depreciable Estimated Net Applied Mortality Average No. Account No. Plant Base Avg. Service Salvage Depr. rates Curve Remaining (In Thousands) Life (Percent) (Percent) Type Life (a) (b) (c) (d) (e) (f) (g) 12 GENERAL PLANT 13 390 147,817 45.00 -8.00 1.98 R2.5 14 391 11,830 30.00 3.21SQ 15 392 9 27.00 3.44SQ 16 393 2,047 55.00 1.88SQ 17 394 39,957 43.00 10.00 2.63 SQ 18 395 3,096 37.00 3.92SQ 19 397 74,117 24.00 8.00 4.94 SQ 20 397.12 41 24.00 8.00 4.94 SQ 21 397.16 18,414 24.00 8.00 4.94 SQ 22 398 7,583 35.00 2.73SQ 23 TOTAL GENERAL PLANT 304,911 24 25 DEPRECIABLE SUM 14,871,033 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
FERC FORM NO. 1 (REV. 12-03) Page 337.4 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 FOOTNOTE DATA
Schedule Page: 336.4 Line No.: 25 Column: b The depreciable plant base is the November 30, 2020 total company depreciable plant.
FERC 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) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / REGULATORY COMMISSION EXPENSES 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 Assessed by Expenses Total Deferred Expense for in Account No. (Furnish name of regulatory commission or body the Regulatory of Commission Current Year 182.3 at docket or case number and a description of the case) Utility (b) + (c) Beginning of Year (a) (b) (c) (d) (e) 1 Smith Mountain Combination Project #2210 - 2 Proportion of cost of administering the 1,106,985 1,106,985 3 Federal Water Power Act 4 5 Leesville Hydro Project #2210 - Proportion of 6 cost of administering the Federal Water 7 Power Act 90,454 90,454 8 9 Claytor Hydro Project #739 - Proportion of 10 cost of administering the Federal Water 11 Power Act 212,182 212,182 12 13 Byllesby Buck Hydro Project #2514 - Proportion 14 of cost of administering the Federal Water 15 Power Act 76,949 76,949 16 17 Marmet and London Hydro Project #1175 - 18 Proportion of cost of administering the 19 Federal Water Power Act 76,564 76,564 20 21 Winfield Hydro Project #1290 - Proportion of 22 cost of administering the Federal Water 23 Power Act 47,908 47,908 24 25 Niagara Hydro Project #2466 - Proportion of 26 cost of administering the Federal Water 27 Power Act 7,700 7,700 28 29 Misc Exp - items less than $25,000 162,659 162,659 30 31 West Virginia Base Case 228,877 228,877 385,405 32 33 West Virginia ENEC Filing 150,523 150,523 34 35 West Virginia Broadband Filing 54,352 54,352 36 37 Virginia Broadband Pilot Filing 259,804 259,804 38 39 Virginia Fuel Filing 51,427 51,427 40 41 FERC 205 Filing 48,081 48,081 42 43 FERC Formula Rate Filing 65,308 65,308 44 45 Virginia Energy Efficiency RAC filing 248,426 248,426
46 TOTAL 1,618,742 4,447,234 6,065,976 385,405
FERC FORM NO. 1 (ED. 12-96) Page 350 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / REGULATORY COMMISSION EXPENSES 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 Assessed by Expenses Total Deferred Expense for in Account No. (Furnish name of regulatory commission or body the Regulatory of Commission Current Year 182.3 at docket or case number and a description of the case) Utility (b) + (c) Beginning of Year (a) (b) (c) (d) (e) 1 2 West Virginia Integrated Resource Plan Filing 109,473 109,473 3 4 Virginia Integrated Resource Plan Filing 92,857 92,857 5 6 2020 Virginia Triennial Filing 2,975,447 2,975,447 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 TOTAL 1,618,742 4,447,234 6,065,976 385,405
FERC FORM NO. 1 (ED. 12-96) Page 350.1 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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 (f), (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.
EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR CURRENTLY CHARGED TO Deferred to Contra Amount Deferred in Line Department Account Amount Account Account 182.3 No. Account 182.3 End of Year No. (f) (g) (h) (i) (j) (k) (l) 1 928 1,106,985 2 3 4 5 6 928 90,454 7 8 9 10 928 212,182 11 12 13 14 928 76,949 15 16 17 18 928 76,564 19 20 21 22 928 47,908 23 24 25 26 928 7,700 27 28 928 162,659 29 30 928 50,998 928 177,879 207,526 31 32 928 150,523 33 34 928 54,352 35 36 928 259,804 37 38 928 51,427 39 40 928 48,081 41 42 928 65,308 43 44 928 248,426 45
5,888,097 177,879 207,526 46 FERC FORM NO. 1 (ED. 12-96) Page 351 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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 (f), (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.
EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR CURRENTLY CHARGED TO Deferred to Contra Amount Deferred in Line Department Account Amount Account Account 182.3 No. Account 182.3 End of Year No. (f) (g) (h) (i) (j) (k) (l) 1 928 109,473 2 3 928 92,857 4 5 928 2,975,447 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
5,888,097 177,879 207,526 46 FERC FORM NO. 1 (ED. 12-96) Page 351.1 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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.(Identify 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 Council or the Electric f. Siting and heat rejection Power Research Institute (2) Transmission Line Classification Description No. (a) (b) 1 ELECTRIC UTILITY RESEARCH, DEVELOPMENT & 2 DEMONSTRATION PERFORMED INTERNALLY 3 4 A(1)b Generation: Fossil - Fuel Steam 3 Item(s) Under $50,000 5 6 A(1)e Generation: Unconventional generation 2 Item(s) Under $50,000 7 8 A(2) Transmission: 1 Item(s) Under $50,000 9 10 A(3) Distribution: 1 Item(s) Under $50,000 11 12 A(5) Environment: (Other Than Equipment) 2 Item(s) Under $50,000 13 14 A(6) Other: 2 Item(s) Under $50,000 15 16 A(6)a: 1 Item(s) Under $50,000 17 18 A(6)f Metering: 1 Item(s) Under $50,000 19 20 A(6)g Research - General: 1 Item(s) Under $50,000 21 22 A(7) TOTAL COST INCURRED INTERNALLY 23 24 ELECTRIC UTILITY RESEARCH, DEVELOPMENT & 25 DEMONSTRATION PERFORMED EXTERNALLY 26 27 B(1) Research Support to Elec. Research 28 Council & Elec. Power Research Inst. EPRI Environmental Science 29 EPRI Research Portfolio 30 EPRI Environmental Controls 31 IT-EPRI Annual Research Port 32 Low Carbon Resource Initiative 33 34 32 Item(s) Under $50,000 35 36 B(4) Research Support to Others 3 Item(s) under $50,000 37 38 B(5) TOTAL COST INCURRED EXTERNALLY
FERC FORM NO. 1 (ED. 12-87) Page 352 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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, D & D 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, D & D (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, D & D 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, D &D 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.
Unamortized Costs Incurred Internally Costs Incurred Externally AMOUNTS CHARGED IN CURRENT YEAR Line Current Year Accumulation (c) Current Year Account Amount No. (d) (e) (f) (g) 1 2 3 58,486 506 58,486 4 5 128 506,588 128 6 7 19,707 566 19,707 8 9 14,824 588 14,824 10 11 11,814 506 11,814 12 13 71,414 Footnote 71,414 14 15 6,887 506 6,887 16 17 3,051 588 3,051 18 19 2,140 566,588 2,140 20 21 188,451 188,451 22 23 24 25 26 27 654,388 506 654,388 28 1,174,478 Footnote 1,174,478 29 111,032 506 111,032 30 61,791 506,588 61,791 31 186,207 Footnote 186,207 32 33 176,238 Footnote 176,238 34 35 4,990 506,566 4,990 36 37 2,369,124 2,369,124 38
FERC FORM NO. 1 (ED. 12-87) Page 353 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 FOOTNOTE DATA
Schedule Page: 352 Line No.: 14 Column: e 506,566,588 Schedule Page: 352 Line No.: 29 Column: e 506,566,588 Schedule Page: 352 Line No.: 32 Column: e 506,566,588 Schedule Page: 352 Line No.: 34 Column: e 506,566,588
FERC 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) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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.
Line Classification Direct Payroll Allocation of Distribution Payroll charged for Total No. Clearing Accounts (a) (b) (c) (d) 1 Electric 2 Operation 3 Production 27,619,347 4 Transmission 94,536 5 Regional Market 6 Distribution 12,958,762 7 Customer Accounts 6,772,886 8 Customer Service and Informational 2,601,238 9 Sales 10 Administrative and General 1,623,148 11 TOTAL Operation (Enter Total of lines 3 thru 10) 51,669,917 12 Maintenance 13 Production 27,620,753 14 Transmission 78,986 15 Regional Market 16 Distribution 24,732,267 17 Administrative and General 2,919,206 18 TOTAL Maintenance (Total of lines 13 thru 17) 55,351,212 19 Total Operation and Maintenance 20 Production (Enter Total of lines 3 and 13) 55,240,100 21 Transmission (Enter Total of lines 4 and 14) 173,522 22 Regional Market (Enter Total of Lines 5 and 15) 23 Distribution (Enter Total of lines 6 and 16) 37,691,029 24 Customer Accounts (Transcribe from line 7) 6,772,886 25 Customer Service and Informational (Transcribe from line 8) 2,601,238 26 Sales (Transcribe from line 9) 27 Administrative and General (Enter Total of lines 10 and 17) 4,542,354 28 TOTAL Oper. and Maint. (Total of lines 20 thru 27) 107,021,129 7,042,442 114,063,571 29 Gas 30 Operation 31 Production-Manufactured Gas 32 Production-Nat. Gas (Including Expl. and Dev.) 33 Other Gas Supply 34 Storage, LNG Terminaling and Processing 35 Transmission 36 Distribution 37 Customer Accounts 38 Customer Service and Informational 39 Sales 40 Administrative and General 41 TOTAL Operation (Enter Total of lines 31 thru 40) 42 Maintenance 43 Production-Manufactured Gas 44 Production-Natural Gas (Including Exploration and Development) 45 Other Gas Supply 46 Storage, LNG Terminaling and Processing 47 Transmission
FERC FORM NO. 1 (ED. 12-88) Page 354 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / DISTRIBUTION OF SALARIES AND WAGES (Continued)
Line Classification Direct Payroll Allocation of Distribution Payroll charged for Total No. Clearing Accounts (a) (b) (c) (d) 48 Distribution 49 Administrative and General 50 TOTAL Maint. (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) 107,021,129 7,042,442 114,063,571 66 Utility Plant 67 Construction (By Utility Departments) 68 Electric Plant 52,146,139 3,431,436 55,577,575 69 Gas Plant 70 Other (provide details in footnote): 71 TOTAL Construction (Total of lines 68 thru 70) 52,146,139 3,431,436 55,577,575 72 Plant Removal (By Utility Departments) 73 Electric Plant 11,684,434 768,885 12,453,319 74 Gas Plant 75 Other (provide details in footnote): 76 TOTAL Plant Removal (Total of lines 73 thru 75) 11,684,434 768,885 12,453,319 77 Other Accounts (Specify, provide details in footnote): 78 152 - Fuel Stock Undistributed 9,278,354 9,278,354 79 154 - Materials and Supplies 413 413 80 163 - Stores Expense Undistributed 4,830,410 -4,830,410 81 183 - Prelim Survey 16,976 -16,976 82 184 - Clearing Accounts 6,395,377 -6,395,377 83 185 - ODD Temporary Facilities 217,789 217,789 84 186 - Misc Deferred Debits 2,930,251 2,930,251 85 188 - Research & Development -1,061 -1,061 86 242 - Misc Current & Accrued Liab 428 428 87 418 - Nonoperating Rental Income 15,772 15,772 88 426 - Political Activities 350,066 350,066 89 90 91 92 93 94 95 TOTAL Other Accounts 24,034,775 -11,242,763 12,792,012 96 TOTAL SALARIES AND WAGES 194,886,477 194,886,477
FERC FORM NO. 1 (ED. 12-88) Page 355 Name of Respondent This Report Is: Date of Report Year/Period of Report Appalachian Power Company (1) X An Original (Mo, Da, Yr) (2) A Resubmission / / End of 2020/Q4
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 This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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 Settlement Statements. Transactions should be separately netted 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 megawatt 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.
Line Description of Item(s) Balance at End of Balance at End of Balance at End of Balance at End of No. Quarter 1 Quarter 2 Quarter 3 Year (a) (b) (c) (d) (e) 1 Energy 2 Net Purchases (Account 555) 203,912,628 3 Net Sales (Account 447) ( 65,293,975) 4 Transmission Rights ( 24,836,384) 5 Ancillary Services 9,162,343 6 Other Items (list separately) 7 Congestion 13,770,646 8 Operating Reserves ( 890,126) 9 Transmission Purchase Expense 20,660,347 10 Transmission Losses 7,430,955 11 Meter Correction 259,235 12 Inadvertent 85,616 13 Capacity Credits ( 5,175,064) 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 159,086,221 FERC FORM NO. 1/3-Q (NEW. 12-05) Page 397 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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 2 Reactive Supply and Voltage 3 Regulation and Frequency Response 4 Energy Imbalance 5 Operating Reserve - Spinning 6 Operating Reserve - Supplement 7 Other 8 Total (Lines 1 thru 7)
FERC FORM NO. 1 (New 2-04) Page 398 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 FOOTNOTE DATA
Schedule Page: 398 Line No.: 1 Column: b The final grandfathered contracts (under the AEP OATT) expired 12/31/2010. Currently, services are provided under the SPP and PJM OATTs.
FERC 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) Appalachian Power Company End of 2020/Q4 (2) 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 (j) 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 Reservations Service Reservation (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) 1 January 2 February 3 March 4 Total for Quarter 1 5 April 6 May 7 June 8 Total for Quarter 2 9 July 10 August 11 September 12 Total for Quarter 3 13 October 14 November 15 December 16 Total for Quarter 4 17 Total Year to Date/Year
FERC FORM NO. 1/3-Q (NEW. 07-04) Page 400 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 FOOTNOTE DATA
Schedule Page: 400 Line No.: 1 Column: b Appalachian Power Company's transmission service is administered through an RTO/ISO and requested information is not available on an individual operating company basis.
FERC 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) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / MONTHLY ISO/RTO 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 Column (c) and (d) the specified information for each monthly transmission - system peak load reported on Column (b). (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 (j) 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 Through and Network Point-to-Point Total Usage No. Month MW - Total Monthly Monthly ISO/RTO ISO/RTO Out Service Service Usage Service Usage Peak Peak (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) 1 January 2 February 3 March 4 Total for Quarter 1 5 April 6 May 7 June 8 Total for Quarter 2 9 July 10 August 11 September 12 Total for Quarter 3 13 October 14 November 15 December 16 Total for Quarter 4 17 Total Year to Date/Year
FERC FORM NO. 1/3-Q (NEW. 07-04) Page 400a Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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 MegaWatt Hours Line Item MegaWatt Hours No. No. (a) (b) (a) (b) 1 SOURCES OF ENERGY 21 DISPOSITION OF ENERGY 2 Generation (Excluding Station Use): 22 Sales to Ultimate Consumers (Including 26,469,315 3 Steam 15,996,872 Interdepartmental Sales) 4 Nuclear 23 Requirements Sales for Resale (See 2,778,691 5 Hydro-Conventional 831,452 instruction 4, page 311.) 6 Hydro-Pumped Storage 577,329 24 Non-Requirements Sales for Resale (See 2,821,316 7 Other 4,725,165 instruction 4, page 311.) 8 Less Energy for Pumping 505,545 25 Energy Furnished Without Charge -374,224 9 Net Generation (Enter Total of lines 3 21,625,273 26 Energy Used by the Company (Electric through 8) Dept Only, Excluding Station Use) 10 Purchases 12,114,712 27 Total Energy Losses 2,044,887 11 Power Exchanges: 28 TOTAL (Enter Total of Lines 22 Through 33,739,985 12 Received 27) (MUST EQUAL LINE 20) 13 Delivered 14 Net Exchanges (Line 12 minus line 13) 15 Transmission For Other (Wheeling) 16 Received 17 Delivered 18 Net Transmission for Other (Line 16 minus line 17) 19 Transmission By Others Losses 20 TOTAL (Enter Total of lines 9, 10, 14, 18 33,739,985 and 19)
FERC FORM NO. 1 (ED. 12-90) Page 401a Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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: Monthly Non-Requirments MONTHLY PEAK Line Sales for Resale & No. Month Total Monthly Energy Associated LossesMegawatts (See Instr. 4) Day of Month Hour (a) (b) (c) (d) (e) (f) 29 January 3,209,104 156,902 6,521 22 800 30 February 2,917,287 108,977 5,840 15 800 31 March 2,557,833 77,525 5,166 1 800 32 April 2,387,069 267,921 4,046 15 900 33 May 2,849,657 643,480 4,255 28 1800 34 June 2,662,796 309,517 4,937 9 1700 35 July 3,226,108 318,148 5,503 20 1600 36 August 3,293,796 605,303 5,194 25 1700 37 September 2,553,455 252,706 4,849 2 1600 38 October 2,317,666 58,392 4,056 5 1200 39 November 2,499,750 86,094 5,101 19 800 40 December 3,154,727 71,013 5,870 26 900
41 TOTAL 33,629,248 2,955,978
FERC FORM NO. 1 (ED. 12-90) Page 401b Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 FOOTNOTE DATA
Schedule Page: 401 Line No.: 25 Column: b Represents Megawatt Hours included in Line 22, Sales to Ultimate Consumers, that were delivered and billed to shopping customers and provided by external suppliers. This total also includes hydropower Megawatt Hours provided free of charge to the Government. Sales to Ultimate Consumers (374,911) Hydropower to Government 687 ______(374,224)
FERC 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) Appalachian Power Company 2020/Q4 (2) A Resubmission / / End of
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. Indicate by a footnote any plant leased or operated as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 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 fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Line Item Plant Plant No. Name: Clinch River Name: Amos (a) (b) (c)
1 Kind of Plant (Internal Comb, Gas Turb, Nuclear STEAM STEAM 2 Type of Constr (Conventional, Outdoor, Boiler, etc) CONVENTIONAL CONVENTIONAL 3 Year Originally Constructed 1958 1971 4 Year Last Unit was Installed 1961 1973 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 712.50 2963.00 6 Net Peak Demand on Plant - MW (60 minutes) 454 2936 7 Plant Hours Connected to Load 1346 6638 8 Net Continuous Plant Capability (Megawatts) 0 0 9 When Not Limited by Condenser Water 465 2930 10 When Limited by Condenser Water 455 2930 11 Average Number of Employees 37 247 12 Net Generation, Exclusive of Plant Use - KWh 271022000 10450838000 13 Cost of Plant: Land and Land Rights 501098 7307834 14 Structures and Improvements 26863712 172962664 15 Equipment Costs 272586258 3380523576 16 Asset Retirement Costs 4831339 77161191 17 Total Cost 304782407 3637955265 18 Cost per KW of Installed Capacity (line 17/5) Including 427.7648 1227.7946 19 Production Expenses: Oper, Supv, & Engr 1073111 12790240 20 Fuel 10774748 253905780 21 Coolants and Water (Nuclear Plants Only) 0 0 22 Steam Expenses 3282819 29932928 23 Steam From Other Sources 0 0 24 Steam Transferred (Cr) 0 0 25 Electric Expenses 0 156371 26 Misc Steam (or Nuclear) Power Expenses 2019964 7858667 27 Rents 0 23549 28 Allowances 1991 99767 29 Maintenance Supervision and Engineering 44772 442966 30 Maintenance of Structures 684359 2531556 31 Maintenance of Boiler (or reactor) Plant 1904143 29441782 32 Maintenance of Electric Plant 733453 7422818 33 Maintenance of Misc Steam (or Nuclear) Plant 1079493 8254808 34 Total Production Expenses 21598853 352861232 35 Expenses per Net KWh 0.0797 0.0338 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) Gas Coal Oil 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) MCF's Tons Barrels 38 Quantity (Units) of Fuel Burned 2979019 0 0 4244306 95369 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 1036000 0 0 12346 137417 0 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 3.679 0.000 0.000 54.173 69.975 0.000 41 Average Cost of Fuel per Unit Burned 3.699 0.000 0.000 53.869 74.961 0.000 42 Average Cost of Fuel Burned per Million BTU 3.570 0.000 0.000 2.182 12.988 0.000 43 Average Cost of Fuel Burned per KWh Net Gen 0.041 0.000 0.000 0.022 0.000 0.000 44 Average BTU per KWh Net Generation 11268.000 0.000 0.000 10078.000 0.000 0.000
FERC FORM NO. 1 (REV. 12-03) Page 402 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company 2020/Q4 (2) A Resubmission / / End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 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. Indicate by a footnote any plant leased or operated as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 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 fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Line Item Plant Plant No. Name: Name: (a) (b) (c)
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) 0.00 0.00 6 Net Peak Demand on Plant - MW (60 minutes) 0 0 7 Plant Hours Connected to Load 0 0 8 Net Continuous Plant Capability (Megawatts) 0 0 9 When Not Limited by Condenser Water 0 0 10 When Limited by Condenser Water 0 0 11 Average Number of Employees 0 0 12 Net Generation, Exclusive of Plant Use - KWh 0 0 13 Cost of Plant: Land and Land Rights 0 0 14 Structures and Improvements 0 0 15 Equipment Costs 0 0 16 Asset Retirement Costs 0 0 17 Total Cost 0 0 18 Cost per KW of Installed Capacity (line 17/5) Including 0 0 19 Production Expenses: Oper, Supv, & Engr 0 0 20 Fuel 0 0 21 Coolants and Water (Nuclear Plants Only) 0 0 22 Steam Expenses 0 0 23 Steam From Other Sources 0 0 24 Steam Transferred (Cr) 0 0 25 Electric Expenses 0 0 26 Misc Steam (or Nuclear) Power Expenses 0 0 27 Rents 0 0 28 Allowances 0 0 29 Maintenance Supervision and Engineering 0 0 30 Maintenance of Structures 0 0 31 Maintenance of Boiler (or reactor) Plant 0 0 32 Maintenance of Electric Plant 0 0 33 Maintenance of Misc Steam (or Nuclear) Plant 0 0 34 Total Production Expenses 0 0 35 Expenses per Net KWh 0.0000 0.0000 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) 38 Quantity (Units) of Fuel Burned 0 0 0 0 0 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 0 0 0 0 0 0 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 0.000 0.000 0.000 0.000 0.000 0.000 41 Average Cost of Fuel per Unit Burned 0.000 0.000 0.000 0.000 0.000 0.000 42 Average Cost of Fuel Burned per Million BTU 0.000 0.000 0.000 0.000 0.000 0.000 43 Average Cost of Fuel Burned per KWh Net Gen 0.000 0.000 0.000 0.000 0.000 0.000 44 Average BTU per KWh Net Generation 0.000 0.000 0.000 0.000 0.000 0.000
FERC FORM NO. 1 (REV. 12-03) Page 402.1 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company 2020/Q4 (2) A Resubmission / / End of 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 report period and other physical and operating characteristics of plant. Plant Plant Plant Line Name: Mountaineer Name: Ceredo Name: Dresden No. (d) (e) (f)
STEAM GAS TURBINE COMBINED CYCLE 1 OUTDOOR BOILER NO BOILER OUTDOOR HRSG 2 1980 2001 2012 3 1980 2001 2012 4 1320.00 519.18 669.00 5 1360 544 664 6 5644 280 8253 7 0 0 0 8 1320 516 665 9 1305 450 570 10 164 6 33 11 5275012000 110347000 4614818000 12 4554535 910000 2286932 13 200911370 1652232 48778150 14 1444477107 201270517 414311521 15 8817858 0 0 16 1658760870 203832749 465376603 17 1256.6370 392.6052 695.6302 18 5188433 246609 526350 19 109316006 2791393 49098742 20 0 0 0 21 11773753 121801 255335 22 0 0 0 23 0 0 0 24 2064 497146 0 25 10190180 112108 4748400 26 10437 0 0 27 61280 0 194 28 503789 0 500581 29 1836374 0 312512 30 16913432 3 480889 31 2425622 352089 2405916 32 2775362 0 1647280 33 160996732 4121149 59976199 34 0.0305 0.0373 0.0130 35 Coal Oil Gas Gas 36 Tons Barrels MCFs MCFs 37 2081223 45677 0 1253904 0 0 29544594 0 0 38 12527 137438 0 1089000 0 0 1064000 0 0 39 47.891 62.650 0.000 2.183 0.000 0.000 1.695 0.000 0.000 40 45.944 75.138 0.000 2.177 0.000 0.000 1.695 0.000 0.000 41 1.834 13.017 0.000 1.999 0.000 0.000 1.593 0.000 0.000 42 0.018 0.000 0.000 0.025 0.000 0.000 0.011 0.000 0.000 43 9933.000 0.000 0.000 12354.000 0.000 0.000 6822.000 0.000 0.000 44
FERC FORM NO. 1 (REV. 12-03) Page 403 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company 2020/Q4 (2) A Resubmission / / End of 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 report period and other physical and operating characteristics of plant. Plant Plant Plant Line Name: Name: Name: No. (d) (e) (f)
1 2 3 4 0.00 0.00 0.00 5 0 0 0 6 0 0 0 7 0 0 0 8 0 0 0 9 0 0 0 10 0 0 0 11 0 0 0 12 0 0 0 13 0 0 0 14 0 0 0 15 0 0 0 16 0 0 0 17 0 0 0 18 0 0 0 19 0 0 0 20 0 0 0 21 0 0 0 22 0 0 0 23 0 0 0 24 0 0 0 25 0 0 0 26 0 0 0 27 0 0 0 28 0 0 0 29 0 0 0 30 0 0 0 31 0 0 0 32 0 0 0 33 0 0 0 34 0.0000 0.0000 0.0000 35 36 37 0 0 0 0 0 0 0 0 0 38 0 0 0 0 0 0 0 0 0 39 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 40 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 41 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 42 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 43 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 44
FERC FORM NO. 1 (REV. 12-03) Page 403.1 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 FOOTNOTE DATA
Schedule Page: 402 Line No.: 20 Column: b Deferred Fuel expenses totaling $62,057,736 are not included in the Fuel totals that are broken down by generating plants. Deferred fuel expenses for Virginia and West Virginia were $33,929,464 and $28,128,272 respectively.
FERC 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) Appalachian Power Company 2020/Q4 (2) A Resubmission / / End of 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. 739 FERC Licensed Project No. 2210 No. Plant Name: CLAYTOR Plant Name: LEESVILLE (a) (b) (c)
1 Kind of Plant (Run-of-River or Storage) STORAGE STORAGE 2 Plant Construction type (Conventional or Outdoor) CONVENTIONAL OUTDOOR 3 Year Originally Constructed 1939 1964 4 Year Last Unit was Installed 1939 1964 5 Total installed cap (Gen name plate Rating in MW) 75.00 40.00 6 Net Peak Demand on Plant-Megawatts (60 minutes) 80 50 7 Plant Hours Connect to Load 8,641 2,391 8 Net Plant Capability (in megawatts) 9 (a) Under Most Favorable Oper Conditions 88 48 10 (b) Under the Most Adverse Oper Conditions 0 0 11 Average Number of Employees 5 1 12 Net Generation, Exclusive of Plant Use - Kwh 361,311,000 106,314,000 13 Cost of Plant 14 Land and Land Rights 1,612,350 1,784,759 15 Structures and Improvements 3,863,364 3,838,701 16 Reservoirs, Dams, and Waterways 12,713,953 11,069,689 17 Equipment Costs 10,318,889 8,849,978 18 Roads, Railroads, and Bridges 31,799 80,790 19 Asset Retirement Costs 362,724 196,310 20 TOTAL cost (Total of 14 thru 19) 28,903,079 25,820,227 21 Cost per KW of Installed Capacity (line 20 / 5) 385.3744 645.5057 22 Production Expenses 23 Operation Supervision and Engineering 355,054 98,492 24 Water for Power -6,254 -2,188 25 Hydraulic Expenses 696,081 277,696 26 Electric Expenses 69,947 20,582 27 Misc Hydraulic Power Generation Expenses 700,982 158,669 28 Rents 528 0 29 Maintenance Supervision and Engineering 22,306 2,057 30 Maintenance of Structures 301,951 621,059 31 Maintenance of Reservoirs, Dams, and Waterways 96,720 123,398 32 Maintenance of Electric Plant 303,242 513,243 33 Maintenance of Misc Hydraulic Plant 13,686 24,260 34 Total Production Expenses (total 23 thru 33) 2,554,243 1,837,268 35 Expenses per net KWh 0.0071 0.0173
FERC FORM NO. 1 (REV. 12-03) Page 406 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company 2020/Q4 (2) A Resubmission / / End of 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. 1175 FERC Licensed Project No. 0 No. Plant Name: MARMET Plant Name: (a) (b) (c)
1 Kind of Plant (Run-of-River or Storage) RUN OF RIVER 2 Plant Construction type (Conventional or Outdoor) CONVENTIONAL 3 Year Originally Constructed 1935 4 Year Last Unit was Installed 1935 5 Total installed cap (Gen name plate Rating in MW) 14.40 0.00 6 Net Peak Demand on Plant-Megawatts (60 minutes) 17 0 7 Plant Hours Connect to Load 7,476 0 8 Net Plant Capability (in megawatts) 9 (a) Under Most Favorable Oper Conditions 20 0 10 (b) Under the Most Adverse Oper Conditions 0 0 11 Average Number of Employees 3 0 12 Net Generation, Exclusive of Plant Use - Kwh 75,398,000 0 13 Cost of Plant 14 Land and Land Rights 4,100 0 15 Structures and Improvements 706,507 0 16 Reservoirs, Dams, and Waterways 1,880,489 0 17 Equipment Costs 11,555,116 0 18 Roads, Railroads, and Bridges 1,275 0 19 Asset Retirement Costs 125,314 0 20 TOTAL cost (Total of 14 thru 19) 14,272,801 0 21 Cost per KW of Installed Capacity (line 20 / 5) 991.1667 0.0000 22 Production Expenses 23 Operation Supervision and Engineering 215,339 0 24 Water for Power 6,185 0 25 Hydraulic Expenses 6,617 0 26 Electric Expenses 14,596 0 27 Misc Hydraulic Power Generation Expenses 371,579 0 28 Rents 110,756 0 29 Maintenance Supervision and Engineering 2,079 0 30 Maintenance of Structures 213,750 0 31 Maintenance of Reservoirs, Dams, and Waterways 192,485 0 32 Maintenance of Electric Plant 78,633 0 33 Maintenance of Misc Hydraulic Plant 23,003 0 34 Total Production Expenses (total 23 thru 33) 1,235,022 0 35 Expenses per net KWh 0.0164 0.0000
FERC FORM NO. 1 (REV. 12-03) Page 406.1 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company 2020/Q4 (2) A Resubmission / / End of 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 FERC Licensed Project No. 0 No. Plant Name: Plant Name: (a) (b) (c)
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 0.00 6 Net Peak Demand on Plant-Megawatts (60 minutes) 0 0 7 Plant Hours Connect to Load 0 0 8 Net Plant Capability (in megawatts) 9 (a) Under Most Favorable Oper Conditions 0 0 10 (b) Under the Most Adverse Oper Conditions 0 0 11 Average Number of Employees 0 0 12 Net Generation, Exclusive of Plant Use - Kwh 0 0 13 Cost of Plant 14 Land and Land Rights 0 0 15 Structures and Improvements 0 0 16 Reservoirs, Dams, and Waterways 0 0 17 Equipment Costs 0 0 18 Roads, Railroads, and Bridges 0 0 19 Asset Retirement Costs 0 0 20 TOTAL cost (Total of 14 thru 19) 0 0 21 Cost per KW of Installed Capacity (line 20 / 5) 0.0000 0.0000 22 Production Expenses 23 Operation Supervision and Engineering 0 0 24 Water for Power 0 0 25 Hydraulic Expenses 0 0 26 Electric Expenses 0 0 27 Misc Hydraulic Power Generation Expenses 0 0 28 Rents 0 0 29 Maintenance Supervision and Engineering 0 0 30 Maintenance of Structures 0 0 31 Maintenance of Reservoirs, Dams, and Waterways 0 0 32 Maintenance of Electric Plant 0 0 33 Maintenance of Misc Hydraulic Plant 0 0 34 Total Production Expenses (total 23 thru 33) 0 0 35 Expenses per net KWh 0.0000 0.0000
FERC FORM NO. 1 (REV. 12-03) Page 406.2 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company 2020/Q4 (2) A Resubmission / / End of 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 FERC Licensed Project No. 0 No. Plant Name: Plant Name: (a) (b) (c)
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 0.00 6 Net Peak Demand on Plant-Megawatts (60 minutes) 0 0 7 Plant Hours Connect to Load 0 0 8 Net Plant Capability (in megawatts) 9 (a) Under Most Favorable Oper Conditions 0 0 10 (b) Under the Most Adverse Oper Conditions 0 0 11 Average Number of Employees 0 0 12 Net Generation, Exclusive of Plant Use - Kwh 0 0 13 Cost of Plant 14 Land and Land Rights 0 0 15 Structures and Improvements 0 0 16 Reservoirs, Dams, and Waterways 0 0 17 Equipment Costs 0 0 18 Roads, Railroads, and Bridges 0 0 19 Asset Retirement Costs 0 0 20 TOTAL cost (Total of 14 thru 19) 0 0 21 Cost per KW of Installed Capacity (line 20 / 5) 0.0000 0.0000 22 Production Expenses 23 Operation Supervision and Engineering 0 0 24 Water for Power 0 0 25 Hydraulic Expenses 0 0 26 Electric Expenses 0 0 27 Misc Hydraulic Power Generation Expenses 0 0 28 Rents 0 0 29 Maintenance Supervision and Engineering 0 0 30 Maintenance of Structures 0 0 31 Maintenance of Reservoirs, Dams, and Waterways 0 0 32 Maintenance of Electric Plant 0 0 33 Maintenance of Misc Hydraulic Plant 0 0 34 Total Production Expenses (total 23 thru 33) 0 0 35 Expenses per net KWh 0.0000 0.0000
FERC FORM NO. 1 (REV. 12-03) Page 406.3 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company 2020/Q4 (2) A Resubmission / / End of 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. 1175 FERC Licensed Project No. 2514 FERC Licensed Project No. 1290 Line Plant Name: LONDON Plant Name: BYLLESBY Plant Name: WINFIELD No. (d) (e) (f)
RUN OF RIVER STORAGE RUN OF RIVER 1 CONVENTIONAL CONVENTIONAL CONVENTIONAL 2 1935 1912 1938 3 1935 1912 1938 4 14.40 21.60 14.80 5 12 15 22 6 7,504 7,737 8,192 7 8 19 23 24 9 0 0 0 10 1 4 4 11 68,003,000 56,370,000 101,746,000 12 13 21,043 170,420 0 14 616,623 1,216,147 2,754,498 15 1,500,268 7,433,785 2,767,066 16 7,796,959 11,530,122 10,654,543 17 48,853 0 23,567 18 93,690 72,046 137,743 19 10,077,436 20,422,520 16,337,417 20 699.8219 945.4870 1,103.8795 21 22 63,590 129,945 104,853 23 6,400 -1,160 5,646 24 8,702 5,062 7,245 25 12,584 15,140 19,697 26 224,962 110,183 184,003 27 110,756 0 135,371 28 1,258 1,607 1,969 29 79,889 160,157 135,263 30 507,462 265,300 333,829 31 1,101,267 119,829 244,397 32 22,235 9,866 19,362 33 2,139,105 815,929 1,191,635 34 0.0315 0.0145 0.0117 35
FERC FORM NO. 1 (REV. 12-03) Page 407 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company 2020/Q4 (2) A Resubmission / / End of 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. 0 FERC Licensed Project No. 0 FERC Licensed Project No. 0 Line Plant Name: Plant Name: Plant Name: No. (d) (e) (f)
1 2 3 4 0.00 0.00 0.00 5 0 0 0 6 0 0 0 7 8 0 0 0 9 0 0 0 10 0 0 0 11 0 0 0 12 13 0 0 0 14 0 0 0 15 0 0 0 16 0 0 0 17 0 0 0 18 0 0 0 19 0 0 0 20 0.0000 0.0000 0.0000 21 22 0 0 0 23 0 0 0 24 0 0 0 25 0 0 0 26 0 0 0 27 0 0 0 28 0 0 0 29 0 0 0 30 0 0 0 31 0 0 0 32 0 0 0 33 0 0 0 34 0.0000 0.0000 0.0000 35
FERC FORM NO. 1 (REV. 12-03) Page 407.1 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company 2020/Q4 (2) A Resubmission / / End of 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. 0 FERC Licensed Project No. 0 FERC Licensed Project No. 0 Line Plant Name: Plant Name: Plant Name: No. (d) (e) (f)
1 2 3 4 0.00 0.00 0.00 5 0 0 0 6 0 0 0 7 8 0 0 0 9 0 0 0 10 0 0 0 11 0 0 0 12 13 0 0 0 14 0 0 0 15 0 0 0 16 0 0 0 17 0 0 0 18 0 0 0 19 0 0 0 20 0.0000 0.0000 0.0000 21 22 0 0 0 23 0 0 0 24 0 0 0 25 0 0 0 26 0 0 0 27 0 0 0 28 0 0 0 29 0 0 0 30 0 0 0 31 0 0 0 32 0 0 0 33 0 0 0 34 0.0000 0.0000 0.0000 35
FERC FORM NO. 1 (REV. 12-03) Page 407.2 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company 2020/Q4 (2) A Resubmission / / End of 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. 0 FERC Licensed Project No. 0 FERC Licensed Project No. 0 Line Plant Name: Plant Name: Plant Name: No. (d) (e) (f)
1 2 3 4 0.00 0.00 0.00 5 0 0 0 6 0 0 0 7 8 0 0 0 9 0 0 0 10 0 0 0 11 0 0 0 12 13 0 0 0 14 0 0 0 15 0 0 0 16 0 0 0 17 0 0 0 18 0 0 0 19 0 0 0 20 0.0000 0.0000 0.0000 21 22 0 0 0 23 0 0 0 24 0 0 0 25 0 0 0 26 0 0 0 27 0 0 0 28 0 0 0 29 0 0 0 30 0 0 0 31 0 0 0 32 0 0 0 33 0 0 0 34 0.0000 0.0000 0.0000 35
FERC FORM NO. 1 (REV. 12-03) Page 407.3 Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 FOOTNOTE DATA
Schedule Page: 406 Line No.: 10 Column: b Operated to fit into System load curve at or near full capacity. Schedule Page: 406 Line No.: 10 Column: c Operated to fit into System load curve at or near full capacity. Schedule Page: 406 Line No.: 10 Column: e Operated to fit into System load curve at or near full capacity. Schedule Page: 406 Line No.: 17 Column: e Equipment cost amount also includes $5,726,249 of battery storage investment in account 34800.
FERC 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) Appalachian Power Company 2020/Q4 (2) A Resubmission / / End of 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."
Line Item FERC Licensed Project No. 2210 No. Plant Name: SMITH MOUNTAIN (a) (b)
1 Type of Plant Construction (Conventional or Outdoor) OUTDOOR 2 Year Originally Constructed 1965 3 Year Last Unit was Installed 1980 4 Total installed cap (Gen name plate Rating in MW) 647 5 Net Peak Demaind on Plant-Megawatts (60 minutes) 597 6 Plant Hours Connect to Load While Generating 1,356 7 Net Plant Capability (in megawatts) 565 8 Average Number of Employees 17 9 Generation, Exclusive of Plant Use - Kwh 577,329,000 10 Energy Used for Pumping 505,545,000 11 Net Output for Load (line 9 - line 10) - Kwh 71,784,000 12 Cost of Plant 13 Land and Land Rights 6,168,641 14 Structures and Improvements 16,356,288 15 Reservoirs, Dams, and Waterways 31,176,552 16 Water Wheels, Turbines, and Generators 78,237,978 17 Accessory Electric Equipment 12,428,478 18 Miscellaneous Powerplant Equipment 10,235,079 19 Roads, Railroads, and Bridges 1,052,133 20 Asset Retirement Costs 1,687,175 21 Total cost (total 13 thru 20) 157,342,324 22 Cost per KW of installed cap (line 21 / 4) 243.1875 23 Production Expenses 24 Operation Supervision and Engineering 965,873 25 Water for Power -11,675 26 Pumped Storage Expenses 541,129 27 Electric Expenses 176,905 28 Misc Pumped Storage Power generation Expenses 1,726,747 29 Rents 746 30 Maintenance Supervision and Engineering 99,917 31 Maintenance of Structures 998,516 32 Maintenance of Reservoirs, Dams, and Waterways 1,031,324 33 Maintenance of Electric Plant 1,308,452 34 Maintenance of Misc Pumped Storage Plant 103,484 35 Production Exp Before Pumping Exp (24 thru 34) 6,941,418 36 Pumping Expenses 10,454,334 37 Total Production Exp (total 35 and 36) 17,395,752 38 Expenses per KWh (line 37 / 9) 0.0301
FERC FORM NO. 1 (REV. 12-03) Page 408 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company 2020/Q4 (2) A Resubmission / / 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 leave Lines 36, 37 and 38 blank and describe at the bottom of the schedule the company's principal sources of pumping power, the estimated amounts of energy from each station or other source that individually provides more than 10 percent of the total energy used for pumping, and production expenses per net MWH as reported herein for each source described. Group together stations and other resources which individually provide less than 10 percent of total pumping energy. If contracts are made with others to purchase power for pumping, give the supplier contract number, and date of contract.
FERC Licensed Project No. 0 FERC Licensed Project No. 0 FERC Licensed Project No. 0 Line Plant Name: Plant Name: Plant Name: No. (c) (d) (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
FERC FORM NO. 1 (REV. 12-03) Page 409 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / GENERATING PLANT STATISTICS (Small Plants) 1. Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and pumped storage plants of less than 10,000 Kw installed capacity (name plate rating). 2. Designate any plant leased from others, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, and give a concise statement of the facts in a footnote. If licensed project, give project number in footnote. Year Installed Capacity Net Peak Net Generation Line Name of Plant Orig. Name Plate Rating Demand Excluding Cost of Plant Const. MW No. (In MW) (60 min.) Plant Use (a) (b) (c) (d) (e) (f) 1 HYDRO-ELECTRIC 2 Niagara - Project #2466 1906 3.60 2.4 8,033,000 8,613,258 3 Buck - Project #2514 1912 8.40 9.5 54,277,000 13,859,693 4 5 TOTAL HYDRO (Small Plants) 62,310,000 22,472,951 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
FERC FORM NO. 1 (REV. 12-03) Page 410 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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 Plant Cost (Incl Asset Operation Fuel Costs (in cents Line Retire. Costs) Per MW Exc'l. Fuel Kind of Fuel (per Million Btu) Fuel Maintenance No. (g) (h) (i) (j) (k) (l) 1 27,421 146,448 2 137,839 365,167 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
FERC FORM NO. 1 (REV. 12-03) Page 411 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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. Do not report 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. Show in column (f) the pole miles of line on structures the cost of which is 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 (Pole miles) (Indicate where Type of (In the case of Number No. other than underground lines 60 cycle, 3 phase) Supporting report circuit miles) Of On Structure On Structures Circuits From To Operating Designed Structure of Line of Another Designated Line (a) (b) (c) (d) (e) (f) (g) (h) 1 STATE OF TENNESSEE 2 3 0188 BRADFORD, VA SULLIVAN, TN 500.00 500.00 3 0.17 1 4 0400 CANE RIVER, TN CIR-A NAGEL, TN 230.00 230.00 3 45.58 1 5 0400 CANE RIVER, TN CIR-B NAGEL, TN 230.00 230.00 3 0.69 44.90 1 6 0351 CLINCH RIVER, VA NAGEL, TN 138.00 138.00 3 0.19 1 7 0353 NAGEL, TN REEDY CREEK, TN 138.00 138.00 3 0.27 1 8 0349 BROADFORD, VA NAGEL, TN 138.00 138.00 3 12.63 1 9 0349 BROADFORD, VA NAGEL, TN 1 0.15 10 0355 NAGEL, TN WEST KINGSPORT, TN 138.00 138.00 3 1.27 1 11 0355 NAGEL, TN WEST KINGSPORT, TN 1 0.25 12 0176 NORTH BRISTOL, VA WEST KINGSPORT, VA 138.00 138.00 3 5.70 11.27 1 13 0176A HOLSTON, TN REEDY CREEK, TN 138.00 138.00 3 5.62 1 14 0179 BOONE DAM, TN HOLSTON, TN 138.00 138.00 3 0.19 1 15 0179 BOONE DAM, TN HOLSTON, TN 1 7.71 16 0180 HOLSTON, TN WALTERS, NC 138.00 138.00 3 65.16 1 17 0180 HOLSTON, TN WALTERS, NC 138.00 138.00 1 0.09 1 18 19 STATE OF VIRGINIA 20 21 0186 BAKER, KY BROADFORD, VA 765.00 765.00 3 0.45 1 22 0186 BAKER, KY BROADFORD, VA 3 47.26 23 0187 BROADFORD, VA JACKSONS FERRY, VA 765.00 765.00 3 48.87 1 24 0253 CLOVERDALE, VA JACKSONS FERRY, VA 765.00 765.00 3 65.16 1 25 0310 CLOVERDALE, VA JOSHUA FALLS, VA 765.00 765.00 3 56.65 1 26 0406 JACKSON FERRY WYOMING 765.00 765.00 3 57.42 1 27 0334 AXTON, VA JACKSONS FERRY, VA 765.00 765.00 3 73.48 1 28 0181 BROADFORD, VA SULLIVAN, TN 500.00 500.00 3 33.35 1 29 0001CLOVERDALE, VA LEXINGTON, VA 500.00 500.00 3 35.85 1 30 0001 CLOVERDALE LEXINGTON, VA 500.00 500.00 2 0.46 1 31 32 0182 JACKSONS FERRY, VA MCGUIRE, NC 500.00 500.00 3 25.68 1 33 0008A KANAWHA, WV MATT FUNK, VA 345.00 345.00 3 8.26 1 34 0008A KANAWHA, WV MATT FUNK, VA 3 34.05 35 0008 CLOVERDALE, VA MATT FUNK, VA 345.00 345.00 3 8.26 1
36 TOTAL 5,102.45 1,348.53 429
FERC FORM NO. 1 (ED. 12-87) Page 422 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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. Do not report 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. Show in column (f) the pole miles of line on structures the cost of which is 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 (Pole miles) (Indicate where Type of (In the case of Number No. other than underground lines 60 cycle, 3 phase) Supporting report circuit miles) Of On Structure On Structures Circuits From To Operating Designed Structure of Line of Another Designated Line (a) (b) (c) (d) (e) (f) (g) (h) 1 0008 CLOVERDALE, VA MATT FUNK, VA 3 19.02 2 0142 EAST DANVILLE NO. ROXBORO, NC 230.00 230.00 3 7.63 1 3 0142 EAST DANVILLE NO. ROXBORO, NC 230.00 230.00 3 7.63 1 4 0417 BAILEYSVILLE, WV HALES BRANCH, VA 138.00 138.00 3 0.06 1 5 0417 BAILEYSVILLE, WV HALES BRANCH, VA 1 6.36 6 0054 GARDEN CREEK, VA HALES BRANCH, VA 138.00 138.00 3 0.13 1 7 0054 GARDEN CREEK, VA HALES BRANCH, VA 1 7.03 8 0409 LOONEY CREEK TAP, 138.00 138.00 3 9.68 1 9 0434 GRASSY CREEK, VA HALES BRANCH, VA 138.00 138.00 3 0.40 2 10 0434 GRASSY CREEK, VA HALES BRANCH, VA 138.00 138.00 3 6.29 1 11 0434 GRASSY CREEK, VA HALES BRANCH, VA 1 1.73 12 0110 CLAYTOR, VA MATT FUNK, VA 138.00 138.00 3 30.13 1 13 0110 CLAYTOR, VA MATT FUNK, VA 138.00 138.00 3 0.48 1 14 0112 MATT FUNK, VA ROANOKE, VA 138.00 138.00 3 12.90 4.53 1 15 0113 CLAYTOR, VA HANCOCK, VA 138.00 138.00 3 0.08 38.93 1 16 0114 HANCOCK, VA ROANOKE, VA 138.00 138.00 3 4.91 4.46 1 17 0229 MERRIMAC TAP, VA 138.00 138.00 1 7.16 1 18 0138 COLLINSVILLE TAP LINE 138.00 138.00 19 8161 CVEC SCOTTSVILLE 46.00 138.00 3 1.39 1 20 0422 JACKSONS FERRY, VA PEAK CREEK, VA 138.00 138.00 1 13.26 1 21 0422 JACKSONS FERRY, VA PEAK CREEK, VA 138.00 138.00 3 0.59 22 0129 PHILPOTT TAP, VA 138.00 138.00 1 0.34 1 23 0248 CLAYTOR, VA FIELDALE 138.00 138.00 3 0.12 1 24 0248 CLAYTOR, VA FIELDALE 1 37.89 25 0249 FIELDALE, VA WEST BASSETT, VA 138.00 138.00 3 0.12 1 26 0249 FIELDALE, VA WEST BASSETT, VA 1 6.37 27 0120 BEAVER CREEK, KY CLINCH RIVER, VA 138.00 138.00 3 26.27 1 28 0120 BEAVER CREEK, KY CLINCH RIVER, VA 138.00 138.00 1 0.36 29 0122 CLINCH RIVER, VA FREMONT, VA 138.00 138.00 3 17.99 1 30 0123 BEAVER CREEK, KY FREMONT, VA 138.00 138.00 3 8.86 1 31 0289 COOPER RIDGE LOOP, 138.00 138.00 1 0.10 1 32 0350 CLINCH RIVER, VA NAGEL, TN 138.00 138.00 3 4.53 36.83 1 33 0352 NAGEL, TN REEDY CREEK, TN 138.00 138.00 3 5.36 1 34 0365 DICKENS TAP 138.00 138.00 1 3.47 1 35 0259A EAST DANVILLE, WV EAST MONUMENT 138.00 138.00 3.91
36 TOTAL 5,102.45 1,348.53 429
FERC FORM NO. 1 (ED. 12-87) Page 422.1 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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. Do not report 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. Show in column (f) the pole miles of line on structures the cost of which is 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 (Pole miles) (Indicate where Type of (In the case of Number No. other than underground lines 60 cycle, 3 phase) Supporting report circuit miles) Of On Structure On Structures Circuits From To Operating Designed Structure of Line of Another Designated Line (a) (b) (c) (d) (e) (f) (g) (h) 1 0125 CLINCH RIVER, VA MORELAND DRIVE, TN 138.00 138.00 3 49.11 0.01 1 2 0148 CLINCH RIVER, VA SALTVILLE #1A, VA 138.00 138.00 3 25.35 1 3 0148 CLINCH RIVER, VA SALTVILLE #1B, VA 138.00 138.00 3 25.50 1 4 0256 LEBANON 138KV TAP 138.00 138.00 1 0.18 1 5 7539 DAN, VA CAROLINA 138.00 138.00 6 0154 CLINCH RIVER, VA SALTVILLE #2, VA 138.00 138.00 3 2.56 39.67 1 7 0193 BROADFORD, VA SALTVILLE, VA 138.00 138.00 3 4.79 1 8 0191 BROADFORD, VA NAGEL, TN 138.00 138.00 3 44.61 0.13 1 9 0354 NAGEL, TN WEST KINGSPORT, TN 138.00 138.00 3 5.04 1 10 0361 CLINCH RIVER, VA SPRING CREEK, VA 138.00 138.00 3 18.49 3.54 1 11 0192 NORTH BRISTOL, VA SPRING CREEK, VA 138.00 138.00 3 8.82 1 12 0153 NORTH BRISTOL, VA WEST KINGSPORT, VA 138.00 138.00 3 3.61 1 13 0167 CLINCH RIVER, VA GARDEN CREEK, VA 138.00 138.00 3 1.98 1 14 0167 CLINCH RIVER, VA GARDEN CREEK, VA 1 21.78 15 0298 FLETCHERS RIDGE 138.00 138.00 1 0.01 1 16 0313 SKEGGS BRANCH, VA 138.00 138.00 1 0.39 1 17 0167A CLINCHFIELD LOOP 138.00 138.00 1 0.09 0.09 1 18 0416 CLOVERDALE, VA HUNTINGTON COURT, VA 138.00 138.00 3 5.91 1 19 0124 CLOVERDALE, VA SMITH MOUNTAIN, VA 138.00 138.00 3 32.41 1 20 0141 DANVILLE B CIR, VA EAST DANVILLE, VA 138.00 138.00 3 2.78 1 21 1020 CLINCH RIVER VIRGINA CITY 138.00 138.00 22 0358 AXTON, VA DANVILLE #1-A, VA 138.00 138.00 3 16.38 1 23 0359 AXTON, VA MARTINSVILLE, VA 138.00 138.00 3 11.38 1 24 0135 AXTON, VA DANVILLE #2, VA 138.00 138.00 3 16.00 1 25 0135 AXTON, VA DANVILLE #2, VA 1 2.99 26 0135 AXTON, VA DANVILLE #2, VA 138.00 138.00 3 1.39 1 27 0135 AXTON, VA DANVILLE #2, VA 1 16.75 28 0146 FIELDDALE, VA RIDGEWAY, VA 138.00 138.00 1 10.34 1 29 0300 DAN RIVER, NC RIDGEWAY, VA 138.00 138.00 2 4.16 1 30 0300 DAN RIVER, NC RIDGEWAY, VA 138.00 138.00 1 0.33 1 31 0300 DAN RIVER, NC RIDGEWAY, VA 138.00 138.00 1 0.10 1 32 0391 SHEFFIELD LOOP 138.00 138.00 3 0.02 0.02 1 33 0025 GLEN LYN, VA SOUTH PRINCETON, WV 138.00 138.00 3 0.42 1 34 0025 GLEN LYN, VA SOUTH PRINCETON, WV 138.00 138.00 3 0.42 1 35 0058 GLEN LYN, VA WYTHE, VA 138.00 138.00 3 29.03 1
36 TOTAL 5,102.45 1,348.53 429
FERC FORM NO. 1 (ED. 12-87) Page 422.2 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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. Do not report 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. Show in column (f) the pole miles of line on structures the cost of which is 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 (Pole miles) (Indicate where Type of (In the case of Number No. other than underground lines 60 cycle, 3 phase) Supporting report circuit miles) Of On Structure On Structures Circuits From To Operating Designed Structure of Line of Another Designated Line (a) (b) (c) (d) (e) (f) (g) (h) 1 0058 GLEN LYN, VA WYTHE, VA 0.61 2 0058 GLEN LYN, VA WYTHE, VA 138.00 138.00 3 0.60 29.43 1 3 0375 PROGRESS PARK EXT 138.00 138.00 3 3.00 1 4 0427 EVINGTON 138KV TAP 138.00 138.00 2 0.03 5 6 0063 BROADFORD, VA SALTVILLE 1A, VA 138.00 138.00 3 3.80 3.57 1 7 0063 BROADFORD, VA SALTVILLE 1B, VA 138.00 138.00 3 3.71 1 8 0061B RURAL RETREAT LOOP, WV 138.00 138.00 3 0.02 0.02 1 9 0333 BROADFORD, VA RICHLANDS, VA 138.00 138.00 1 14.55 1 10 0368 CLAY POOL HILL 138.00 138.00 1 0.09 0.09 1 11 0241A HUFFMAN, VA JACKSONS FERRY, VA 138.00 138.00 3 1.88 1 12 0241A HUFFMAN, VA JACKSONS FERRY, VA 1 7.99 13 0241 HUFFMAN, VA WYTHE, VA 138.00 138.00 3 1.96 1.00 1 14 0241 HUFFMAN, VA WYTHE, VA 138.00 138.00 1 37.21 1 15 0061 ATKINS, VA BROADFORD CIR A, VA 138.00 138.00 3 19.99 0.43 1 16 0061 ATKINS, VA BROADFORD CIR B, VA 138.00 138.00 3 16.02 1 17 0063 ATKINS, VA WYTHE CIR A, VA 138.00 138.00 3 21.90 0.03 1 18 0063 ATKINS, VA WYTHE CIR B, VA 138.00 138.00 3 20.52 1 19 0433 HUFFMAN, VA WILLIS GAP, VA 138.00 138.00 1 14.10 1 20 0106 CLAYTOR, VA GLEN LYN #1, VA 138.00 138.00 3 25.82 1 21 0106 CLAYTOR, VA GLEN LYN #2, VA 138.00 138.00 3 25.82 1 22 0109 MORGANS CUT LOOP, 138.00 138.00 3 0.02 0.02 1 23 0117 HANCOCK, VA MATT FUNK, VA 138.00 138.00 3 11.21 0.07 1 24 0118 CLOVERDALE, VA MATT FUNK, VA 138.00 138.00 3 20.98 1 25 0119 CLOVERDALE, VA GLEN LYN, VA 138.00 138.00 3 20.14 39.17 1 26 0119 CLOVERDALE, VA GLEN LYN, VA 138.00 138.00 1 0.06 1 27 0374 PATRIOT CENTRE EXT 138.00 138.00 3 3.00 1 28 0367 BURLINGTON 138.00 138.00 3 0.02 0.02 1 29 0383 WEST SALEM LOOP, 138.00 138.00 3 0.30 0.30 1 30 0116 CELANESE, VA GLEN LYN, VA 138.00 138.00 3 3.59 1 31 0116 CELANESE, VA GLEN LYN, VA 1 3.58 32 0462 MATT FUNK EXT 138.00 138.00 3 4.50 33 0115 CELANESE, VA MATT FUNK, VA 138.00 138.00 3 34.10 1 34 0115 CELANESE, VA MATT FUNK, VA 138.00 138.00 1 2.44 1 35 0115 CELANESE, VA MATT FUNK, VA 138.00 138.00 3 0.20 2
36 TOTAL 5,102.45 1,348.53 429
FERC FORM NO. 1 (ED. 12-87) Page 422.3 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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. Do not report 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. Show in column (f) the pole miles of line on structures the cost of which is 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 (Pole miles) (Indicate where Type of (In the case of Number No. other than underground lines 60 cycle, 3 phase) Supporting report circuit miles) Of On Structure On Structures Circuits From To Operating Designed Structure of Line of Another Designated Line (a) (b) (c) (d) (e) (f) (g) (h) 1 0038 BRADLEY CIR-A, WV GLEN LYN-HINTON, VA 138.00 138.00 3 0.32 3.55 1 2 0224 BRADLEY CIR-B, WV GLEN LYN-HINTON 138.00 138.00 3 3.55 0.32 1 3 0145 ALTAVISTA, VA REUSENS, VA 138.00 138.00 3 5.49 1 4 0145 ALTAVISTA, VA REUSENS, VA 138.00 138.00 2 20.44 1 5 0311 OPOSSUM CREEK, VA REUSENS, VA 138.00 138.00 3 9.30 5.49 1 6 0311 OPOSSUM CREEK, VA REUSENS, VA 138.00 138.00 1 0.01 2 7 0312 BRUSH TAVERN TAP, 138.00 138.00 1 2.89 1 8 0145A BOONSBORO LOOP, 138.00 138.00 3 0.02 0.02 1 9 0394 GRAVES MILLS LOOP, 138.00 138.00 3 0.04 0.04 1 10 7119 HANCOCK, VA ROANOKE, VA TOWER 198 138.00 138.00 11 0156A CLIFFORD, VA REUSENS, VA 138.00 138.00 3 22.63 3.63 1 12 0156 CLIFFORD, VA SCOTTSVILLE, VA 138.00 138.00 3 28.56 1 13 0156B BREMO, VA SCOTTSVILLE, VA 138.00 138.00 3 7.11 1 14 0170 OPOSSUM CREEK, VA SMITH MOUNTAIN, VA 138.00 138.00 3 14.51 1 15 0170 OPOSSUM CREEK, VA SMITH MOUNTAIN, VA 1 18.93 16 0170 LEESVILLE, VA SMITH MOUNTAIN, VA 138.00 138.00 3 8.13 1 17 0173 ALTAVISTA, VA LEESVILLE, VA 138.00 138.00 3 0.06 5.12 1 18 0173 ALTAVISTA, VA LEESVILLE, VA 1 3.42 19 0258 OPOSSUM CREEK, VA PEAKSVIEW, VA 138.00 138.00 1 0.38 1 20 0258 OPOSSUM CREEK, VA PEAKSVIEW, VA 138.00 138.00 2 0.82 1 21 0258 OPOSSUM CREEK, VA PEAKSVIEW, VA 138.00 138.00 3 0.24 1 22 0309 EAST LYNCHBURG, VA OPOSSUM CREEK, VA 138.00 138.00 3 2.93 1 23 0322 JOSHUA FALLS, VA REUSENS, VA 138.00 138.00 3 6.36 1 24 0322 JOSHUA FALLS, VA REUSENS, VA 4 0.31 25 0322 JOSHUA FALLS, VA REUSENS, VA 138.00 138.00 3 2.71 6.90 1 26 0321 JOSHUA FALLS, VA OPOSSUM CREEK, VA 138.00 138.00 3 6.52 1 27 0320 EAST LYNCHBURG, VA JOSHUA FALLS, VA 138.00 138.00 3 3.03 1 28 0320 EAST LYNCHBURG, VA JOSHUA FALLS, VA 4 0.61 29 0366 RUSTBURG TAP, VA 138.00 138.00 1 4.46 1 30 0395 MONEL LOOP, VA 138.00 138.00 3 0.03 0.03 1 31 0399 TANK HILL TAP, VA 138.00 138.00 1 0.95 1 32 0161 CLOVERDALE, VA ROANOKE, VA 138.00 138.00 3 16.43 1 33 0161 CLOVERDALE, VA ROANOKE, VA 3 0.66 34 0160 CLOVERDALE, VA REUSENS, VA 138.00 138.00 3 36.17 7.89 1 35 0160 CLOVERDALE, VA REUSENS, VA 138.00 138.00 1 1.11
36 TOTAL 5,102.45 1,348.53 429
FERC FORM NO. 1 (ED. 12-87) Page 422.4 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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. Do not report 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. Show in column (f) the pole miles of line on structures the cost of which is 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 (Pole miles) (Indicate where Type of (In the case of Number No. other than underground lines 60 cycle, 3 phase) Supporting report circuit miles) Of On Structure On Structures Circuits From To Operating Designed Structure of Line of Another Designated Line (a) (b) (c) (d) (e) (f) (g) (h) 1 MOSELEY, VA REUSENS, VA 138.00 138.00 3 22.19 1 2 0163 MOSELEY, VA ROANOKE, VA 138.00 138.00 3 0.56 20.25 1 3 0421 MOUNT UNION CLOVERDALE 138.00 138.00 2 7.38 1 4 0292 VINTON LOOP, VA 138.00 138.00 3 0.02 0.02 1 5 0396 BONSACK LOOP, VA 138.00 138.00 3 0.33 0.33 1 6 0168 EAST DANVILLE, VA SMITH MOUNTAIN, VA 138.00 138.00 3 32.10 1 7 0168A BEARSKIN TAP, VA 138.00 138.00 3 0.02 1 8 0419 PENHOOK, VA SMITH MOUNTAIN, VA 138.00 138.00 3 6.55 1 9 0371 PENHOOK, VA WESTLAKE 138.00 138.00 1 14.76 1 10 0371 PENHOOK, VA WESTLAKE 138.00 138.00 1 0.10 2 11 0369 BLAINE, VA WESTLAKE 138.00 138.00 3 10.56 1 12 0423 STONEWALL TAP 69.00 138.00 1 8.14 1 13 0423 STONEWALL TAP 3 0.51 14 0259 REGIS, VA MONUMENT, VA 138.00 138.00 1 1.90 0.70 1 15 0266 HANCOCK, VA ROANOKE ELECTRIC 138.00 138.00 3 1.28 1 16 0266 HANCOCK, VA ROANOKE ELECTRIC 1 0.47 17 0042 SALTVILLE, VA TAZEWELL, VA 138.00 138.00 3 20.61 0.09 1 18 0042 SALTVILLE, VA TAZEWELL, VA 138.00 138.00 3 20.64 1 19 0042 SALTVILLE, VA TAZEWELL, VA 138.00 138.00 1 0.15 1 20 0270 BLUEFIELD, WV TAZEWELL, VA 138.00 138.00 1 20.41 1 21 0270 BLUEFIELD, WV TAZEWELL, VA 138.00 138.00 2 0.15 1 22 23 BAILEYSVILLE, WV TAZEWELL, VA 138.00 138.00 3 8.71 1 24 BAILEYSVILLE, WV TAZEWELL, VA 138.00 138.00 3 0.06 8.71 1 25 0338 BLUEFIELD, VA SOUTH PRINCETON, VA 138.00 138.00 1 5.97 1 26 0414 RIVERVILLE TAP, VA 138.00 138.00 3 0.11 1 27 0132 ROANOKE CAROLINA 138.00 138.00 1 9.02 28 0132 ROANOKE CAROLINA 138.00 138.00 3 44.09 57.16 1 29 0385 CAPITALIZED SPARE MAX MEADOW 138.00 138.00 1 30 1004 KEYWOOD TAP 138.00 138.00 1 0.38 31 0467 CLEARBROOK, VA MATT FUNK, VA 138.00 138.00 1 0.09 1 32 0380 FALLING BRANCH MERRIMAC 138.00 138.00 1 6.41 1 33 0380 FALLING BRANCH MERRIMAC 138.00 138.00 1 0.59 1 34 0380 FALLING BRANCH MERRIMAC 69.00 138.00 1 0.58 1 35 0381 LAKE FOREST, VA 138.00 138.00 3 3.30 2
36 TOTAL 5,102.45 1,348.53 429
FERC FORM NO. 1 (ED. 12-87) Page 422.5 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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. Do not report 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. Show in column (f) the pole miles of line on structures the cost of which is 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 (Pole miles) (Indicate where Type of (In the case of Number No. other than underground lines 60 cycle, 3 phase) Supporting report circuit miles) Of On Structure On Structures Circuits From To Operating Designed Structure of Line of Another Designated Line (a) (b) (c) (d) (e) (f) (g) (h) 1 0464 HUNTINGTON COURT ROANOKE 138.00 138.00 1 6.21 1 2 0464 HUNTINGTON COURT ROANOKE 138.00 138.00 1 0.07 1 3 0465 SUNSCAPE 138.00 138.00 1 1.40 2 4 0470 LOCKHART, VA 138.00 138.00 3 0.30 1 5 0435 DUTY, VA 138KV EXTENSION 138.00 138.00 1 6 0388 TECH DRIVE 138KV EXTENSION 138.00 138.00 3 0.04 1 7 0484 HORSEPEN 138KV EXTENSION 138.00 138.00 8 0485 JACKSONS FERRY WYTHE 138.00 138.00 2 4.95 1 9 0485 JACKSONS FERRY WYTHE 138.00 138.00 3 12.82 2 10 0502 PROGRESS PARK TAP 138.00 138.00 2 0.53 1 11 0502 PROGRESS PARK TAP 138.00 138.00 1 0.06 1 12 0512 CLOVERDALE 765 CLOVERDALE 138 345.00 345.00 3 0.47 1 13 0508 CLOVERDALE EAST CLOVERDALE TIE LINE NO 2 345.00 345.00 1 0.40 1 14 0509 CLOVERDALE 765 CLOVERDALE EAST 500.00 500.00 2 0.44 1 15 0516 RICHLANDS WHITEWOOD 138.00 138.00 2 7.50 1 16 0513 WHITEWOOD EXT 138.00 138.00 1 0.60 2 17 0513 WHITEWOOD EXT 138.00 138.00 3 0.18 2 18 0519 OWENS DRIVE EXT 69.00 138.00 1 2.10 1 19 0459 GEORGE STREET LYNBROOK 138.00 138.00 1 0.64 1 20 0459 GEORGE STREET LYNBROOK 138.00 138.00 2 2.18 1 21 0110A FALLING BRANCH LOOP 138.00 138.00 2 0.63 1 22 0460 BRUSH TAVERN LYNBROOK 138.00 138.00 1 3.70 1 23 0501 JACKSONS FERRY BUS TIE #3 138.00 138.00 1 0.42 1 24 0461 George Street South Lynchburg 138.00 138.00 1 2.70 1 25 0461 George Street South Lynchburg 138.00 138.00 2 0.20 1 26 0507 Cloverdale East Cloverdale Tie Line No. 1 345.00 345.00 1 0.36 1 27 0517 Town Creek Progress Park 138.00 138.00 1 2.89 1 28 0517 Town Creek Progress Park 138.00 138.00 2 7.49 1 29 0517 Town Creek Progress Park 138.00 138.00 3 2.79 1 30 0518 TOWN CREEK SOUTH BLUEFIELD 138.00 138.00 1 1.13 1 31 0518 TOWN CREEK SOUTH BLUEFIELD 138.00 138.00 2 1.10 1 32 0518 TOWN CREEK SOUTH BLUEFIELD 138.00 138.00 3 9.75 1 33 0514 BEARWALLOW FARADAY 138.00 138.00 2 1.70 1 34 0515 FARADAY TAZEWELL 138.00 138.00 2 6.70 1 35 0545 Tazewell Bus Tie No 1 138.00 138.00 1 0.10 1
36 TOTAL 5,102.45 1,348.53 429
FERC FORM NO. 1 (ED. 12-87) Page 422.6 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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. Do not report 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. Show in column (f) the pole miles of line on structures the cost of which is 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 (Pole miles) (Indicate where Type of (In the case of Number No. other than underground lines 60 cycle, 3 phase) Supporting report circuit miles) Of On Structure On Structures Circuits From To Operating Designed Structure of Line of Another Designated Line (a) (b) (c) (d) (e) (f) (g) (h) 1 0569 HINTON WEST VACO (VA) 138.00 138.00 3 0.25 1 2 0522 SOUTH ABINGDON 138.00 138.00 1 3.85 2 3 0541 IRONTO EXTENSION 138.00 138.00 1 0.10 2 4 0537 WOLF GLADE 138.00 138.00 1 2.00 2 5 6 STATE OF WEST VIRGINIA 7 8 0276 AMOS, WV HANGING ROCK, H 765.00 765.00 3 24.70 1 9 0297 GAVIN, OH MOUNTAINEER, WV 765.00 765.00 3 8.29 1 10 0296 KAMMER, WV MOUNTAINEER, WV 765.00 765.00 3 19.37 1 11 3 95.48 12 0183 AMOS, WV CULLODEN, WV 765.00 765.00 3 15.20 1 13 0183A BAKER, KY CULLODEN, WV 765.00 765.00 3 33.86 1 14 0324 CULLODEN, WV WYOMING, WV 765.00 765.00 3 58.08 1 15 0344 CULLODEN, WV GAVIN, OH 765.00 765.00 3 41.56 1 16 0405 JACKSONS FERRY WYOMING 765.00 765.00 3 32.30 1 17 0295 AMOS, WV MOUNTAINEER, WV 765.00 765.00 3 46.58 1 18 0185 BAKER, KY BROADFORD, VA 765.00 765.00 3 4.32 1 19 0263 AMOS, WV GAVIN 765.00 765.00 1 20 0012 BAKER, KY TRI STATE, WV 345.00 345.00 3 5.58 1 21 0003 KYGER CREEK, OH SPORN, WV 345.00 345.00 3 12.12 1 22 0004 MUSKINGUM, WV SPORN, WV 345.00 345.00 3 2.21 1 23 0004 MUSKINGUM, WV SPORN, WV 345.00 345.00 1 2.40 2 24 0005 KANAWHA, WV MATT FUNK, VA 345.00 345.00 3 0.91 1 25 0005 KANAWHA, WV MATT FUNK, VA 345.00 345.00 3 64.16 1 26 0218 AMOS, WV SPORN, WV 345.00 345.00 3 46.29 1 27 0006 KANAWHA, WV SPORN, WV 345.00 345.00 3 62.08 1 28 0006A AMOS, WV KANAWHA, WV 345.00 345.00 3 27.90 12.10 1 29 0011 KYGER CREEK, WV TRI-STATE, WV 345.00 345.00 3 62.87 30 0011 KYGER CREEK, WV TRI-STATE, WV 345.00 345.00 2 0.36 31 0228A BETH TAP WV 138.00 138.00 1 1.15 1 32 0053 SOURWOOD LOOP, 138.00 138.00 3 0.06 0.06 1 33 0308 PAD FORK LOOP, WV 138.00 138.00 1 0.24 1 34 0330 JIM BRANCH, WV WYOMING, WV 138.00 138.00 3 6.88 1 35 0330 JIM BRANCH, WV WYOMING, WV 1 15.54 0.05
36 TOTAL 5,102.45 1,348.53 429
FERC FORM NO. 1 (ED. 12-87) Page 422.7 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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. Do not report 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. Show in column (f) the pole miles of line on structures the cost of which is 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 (Pole miles) (Indicate where Type of (In the case of Number No. other than underground lines 60 cycle, 3 phase) Supporting report circuit miles) Of On Structure On Structures Circuits From To Operating Designed Structure of Line of Another Designated Line (a) (b) (c) (d) (e) (f) (g) (h) 1 0210 BAILYESVILLE, WV WYOMING, WV 138.00 138.00 3 0.24 5.46 1 2 0332 WELCH TAP, WV 138.00 138.00 1 0.47 1 3 0053 BAILEYSVILLE, WV HALES BRANCH, VA 138.00 138.00 1 21.43 1 4 0035 STOTESBURY TAP, 138.00 138.00 1 0.06 1 5 0035 STOTESBURY TAP, 138.00 138.00 2 5.72 1 6 0211 MULLENSVILLE LOOP, 138.00 138.00 3 0.99 0.99 1 7 0212 PINNACLE CREEK 138.00 138.00 3 2.98 2.98 1 8 0294 NORTH BECKLEY 138.00 138.00 3 0.65 0.65 1 9 0210 BAILEYSVILLE, WV WYOMING, WV 138.00 138.00 3 0.15 5.73 1 10 MULLENS, WV WYOMING, WV 138.00 138.00 3 6.01 1 11 MULLENS, WV WYOMING, WV 1 17.09 12 0356 PEMBERTON TAP, WV 138.00 138.00 1 0.10 1 13 0356 PEMBERTON TAP, WV 138.00 138.00 2 1.31 1 14 0356 PEMBERTON TAP, WV 138.00 138.00 3 0.51 1 15 0216B BRADLEY, WV TAMS MOUNTAIN, WV 138.00 138.00 1 1.27 1 16 0216B BRADLEY, WV TAMS MOUNTAIN, WV 138.00 138.00 2 13.77 1 17 0216B BRADLEY, WV TAMS MOUNTAIN, WV 138.00 138.00 3 0.55 1 18 0216 MULLENS, WV TAMS MOUNTAIN, WV 138.00 138.00 2 9.09 1 19 0216 MULLENS, WV TAMS MOUNTAIN, WV 138.00 138.00 1 0.05 20 0094 BIG SANDY, KY DEWEY, KY 138.00 138.00 3 0.18 1 21 0426 BIG SANDY, KY INEZ A&B, KY 138.00 138.00 3 7.73 1 22 0092 BELLEFONTE, KY TRI STATE, WV 138.00 138.00 3 3.70 1 23 0429 MIDKIFF, WV TRI STATE, WV 138.00 138.00 1 26.17 1 24 0028 CABIN CREEK, WV KANAWHA #1, WV 138.00 138.00 3 3.48 1 25 0029 CABIN CREEK, WV KANAWHA #2, WV 138.00 138.00 3 3.48 1 26 0098 CAPITOL HILL, WV KANAWHA, WV 138.00 138.00 3 17.59 1 27 0098 CAPITOL HILL, WV KANAWHA, WV 138.00 138.00 3 2.70 1 28 0326 RENSFORD LOOP, WV KANAWHA, WV 138.00 138.00 3 0.54 1 29 0098A FLATWOOD TAP, WV 138.00 138.00 3 4.63 1 30 0245 GILBOA, WV KANAWHA, WV 138.00 138.00 3 0.44 0.27 1 31 0245 GILBOA, WV KANAWHA, WV 1 14.68 32 0390 BELVA TAP, WV 138.00 138.00 3 0.64 0.64 1 33 0372 JEHU EXT WV 138.00 138.00 3 0.60 1 34 0097 CAPITOL HILL, WV CHEMICAL, WV 138.00 138.00 3 6.08 1 35 0101 DEXTER, WV SPORN CIR B, OH 138.00 138.00 3 8.89 1
36 TOTAL 5,102.45 1,348.53 429
FERC FORM NO. 1 (ED. 12-87) Page 422.8 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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. Do not report 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. Show in column (f) the pole miles of line on structures the cost of which is 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 (Pole miles) (Indicate where Type of (In the case of Number No. other than underground lines 60 cycle, 3 phase) Supporting report circuit miles) Of On Structure On Structures Circuits From To Operating Designed Structure of Line of Another Designated Line (a) (b) (c) (d) (e) (f) (g) (h) 1 0101 DEXTER, WV SPORN CIR B, OH 138.00 138.00 1 0.25 1 2 0104 BANCROFT TAP, WV 138.00 138.00 3 1.03 1 3 0101 DEXTER, OH SPORN CIR A, WV 138.00 138.00 3 9.07 1 4 0225A LEON LOOP, WV 138.00 138.00 3 0.17 0.17 1 5 AMERICAN ALLOYS, WV SPORN, WV 138.00 138.00 3 0.03 1 6 0402 SISSON TAP, WV 138.00 138.00 3 10.48 1.17 1 7 0402 SISSON TAP, WV 1 0.09 8 0225 AMOS, WV SOUTH BUFFALO CIR B, WV 138.00 138.00 3 12.23 5.86 1 9 0225 SOUTH BUFFALO, WV SPORN CIR A, WV 138.00 138.00 3 31.46 1 10 0225 SOUTH BUFFALO, WV SPORN CIR B WV 138.00 138.00 3 36.34 1 11 0023 MINNIX MOUNTAIN 138.00 138.00 3 0.04 0.04 1 12 0024 SPEEDWAY TAP, WV 138.00 138.00 3 0.03 1 13 0024 SPEEDWAY TAP, WV 1 7.22 14 0020 GLEN LYN, VA SOUTH PRINCETON, WV 138.00 138.00 3 12.84 1 15 0424 GLEN LYN, VA SOUTH PRINCETON, WV 138.00 138.00 3 0.02 12.86 1 16 0020A SOUTH PRINCETON, SWITCHBACK A, WV 138.00 138.00 3 15.46 1 17 0020B SOUTH PRINCETON, SWITCHBACK B, WV 138.00 138.00 3 15.46 1 18 0055 GLEN LYN, VA WYTHE, VA 138.00 138.00 3 1.42 1 19 0055 GLEN LYN, VA WYTHE, VA 138.00 138.00 3 1.42 1 20 0093 BIG SANDY WEST HUNTINGTON, WV 138.00 138.00 2 0.02 2 21 0093 BIG SANDY WEST HUNTINGTON, WV 138.00 138.00 3 3.26 0.05 1 22 0093 BIG SANDY WEST HUNGINGTON, WV 3 15.70 23 0031 BRADLEY, WV KANAWHA #1, WV 138.00 138.00 3 26.94 1 24 0222 BRADLEY, WV KANAWHA #2, WV 138.00 138.00 3 26.94 1 25 0032 BRADLEY CIR A, WV GLEN LYN-HINTON, VA 138.00 138.00 3 0.08 40.85 1 26 0223 BRADLEY CIR B, WV GLEN LYN-HINTON, VA 138.00 138.00 3 42.93 2.08 1 27 0219 KINCAID LOOP, WV 138.00 138.00 3 0.09 0.09 1 28 0246 BRADLEY, WV DAMERON, WV 138.00 138.00 1 9.52 1 29 0415 CLIFFTOP TAP, WV 138.00 138.00 3 2.81 1 30 0049 BAILEYSVILLE, WV KANAWHA #1, WV 138.00 138.00 3 46.42 1 31 0049 BAILEYSVILLE, WV KANAWHA #2, WV 138.00 138.00 3 0.04 46.42 1 32 0049 BAILEYSVILLE, WV KANAWHA #2, WV 1 0.17 33 0052 BIM TAP, WV 138.00 138.00 1,3 11.56 1 34 3827 BRADLEY LAYLAND 69.00 138.00 1 11.59 1 35 3484 COBB TAP 46.00 138.00 1 0.13 1
36 TOTAL 5,102.45 1,348.53 429
FERC FORM NO. 1 (ED. 12-87) Page 422.9 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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. Do not report 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. Show in column (f) the pole miles of line on structures the cost of which is 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 (Pole miles) (Indicate where Type of (In the case of Number No. other than underground lines 60 cycle, 3 phase) Supporting report circuit miles) Of On Structure On Structures Circuits From To Operating Designed Structure of Line of Another Designated Line (a) (b) (c) (d) (e) (f) (g) (h) 1 0420 FRANKS BRANCH 46.00 138.00 1 5.17 1 2 2123 SOUTH NEAL WEST HUNTINGTON 69.00 138.00 3 2.12 1 3 0220 KOPPERSTON LOOP, 138.00 138.00 3 0.19 0.19 1 4 0243 BOLT TAP, WV 138.00 138.00 1 5.80 1 5 0301 WHARTON TAP, WV 138.00 138.00 1 0.20 1 6 0384 HINTON WESTVACO, WV 138.00 138.00 3 12.62 1 7 0384 HINTON WESTVACO, WV 138.00 138.00 3 22.80 1 8 0389 GREENBRIER LOOP, 138.00 138.00 3 0.49 0.49 1 9 0393 RONCEVERTE LOOP, 138.00 138.00 3 0.01 0.01 1 10 0357 GRASSY FALLS, WV MCCLUNG, WV 138.00 138.00 1 1 11 0304 RUM CREEK TAP, WV 138.00 138.00 1 2.48 1 12 0318 M&B TAP, WV 138.00 138.00 1 0.31 1 13 0013 LOGAN, WV WYOMING #1-A, WV 138.00 138.00 3 11.52 14.48 1 14 0013 LOGAN, WV WYOMING #1-B, WV 138.00 138.00 3 21.88 1 15 0387 LOGAN, WV WYOMING #2, WV 138.00 138.00 3 23.34 1 16 0387 LOGAN, WV WYOMING #2, WV 138.00 138.00 2 0.35 1 17 0045 LOGAN, WV SPRIGG #1 & #2, WV 138.00 138.00 3 18.00 2 18 3791 BOLT, WV TRAP HILL, WV 46.00 138.00 1 6.03 1 19 0048 CHAUNCEY TAP, WV 138.00 138.00 3 3.67 1 20 0328 RAGLAND LOOP, WV 138.00 138.00 1 0.56 1 21 0317 GRANT BRANCH TAP, 138.00 138.00 1 6.76 1 22 0346 PINE CREEK TAP, WV 138.00 138.00 1 1.83 1 23 0401 HATFIELD, WV SPRIGG, WV 138.00 138.00 1 10.69 1 24 0401A CINDERELLA LOOP, 138.00 138.00 3 0.37 0.37 1 25 0325 JIM BRANCH, WV SWITCHBACK, WV 138.00 138.00 2 17.58 0.59 1 26 0077 MILLBROOK, OH SPORN, WV 138.00 138.00 3 9.36 1 27 0077A ADDISON LICK, WV SPORN, WV 138.00 138.00 3 9.36 1 28 0075 SOUTH POINT, OH SPORN, WV 138.00 138.00 3 10.18 0.40 1 29 0075 SOUTH POINT, OH SPORN, WV 138.00 138.00 1 1.32 1 30 NORTH PROCTORVILLE, OH SPORN, WV 138.00 138.00 3 9.79 1 31 0076 DARRAH, WV NORTH PROCTORVILLE, OH 138.00 138.00 3 1.89 1 32 0076 DARRAH, WV NORTH PROCTORVILLE, OH 138.00 138.00 3 1.83 1 33 0081 RAVENSWOOD, WV SPORN #1, WV 138.00 138.00 3 1.04 1 34 0081 RAVENSWOOD, WV SPORN #2, WV 138.00 138.00 3 1.07 1 35 0083 RAVENSWOOD, WV SPORN #3, WV 138.00 138.00 3 1.19 1
36 TOTAL 5,102.45 1,348.53 429
FERC FORM NO. 1 (ED. 12-87) Page 422.10 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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. Do not report 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. Show in column (f) the pole miles of line on structures the cost of which is 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 (Pole miles) (Indicate where Type of (In the case of Number No. other than underground lines 60 cycle, 3 phase) Supporting report circuit miles) Of On Structure On Structures Circuits From To Operating Designed Structure of Line of Another Designated Line (a) (b) (c) (d) (e) (f) (g) (h) 1 0083 RAVENSWOOD, WV SPORN #4, WV 138.00 138.00 3 0.74 1 2 0247 EAST HUNTINGTON, NORTH PROCTORVILLE, OH 138.00 138.00 3 0.60 1 3 0067 JOHNS CREEK, KY SPRIGG, WV 138.00 138.00 1 1.46 1 4 0271 BLUEFIELD, WV TAZEWELL, VA 138.00 138.00 1 1.24 1 5 0017 BAILEYSVILLE, WV TAZEWELL, VA 138.00 138.00 3 31.33 0.32 1 6 0016 BAILEYSVILLE, WV TAZEWELL, VA 138.00 138.00 3 2.78 27.64 1 7 0016A CARSWELL TAP, WV 138.00 138.00 3 1.37 1.37 1 8 0069 CABIN CREEK, WV TURNER #1 CIR A, WV 138.00 138.00 3 23.24 1 9 0070 CABIN CREEK, WV TURNER #1 CIR B. WV 138.00 138.00 3 4.53 19.45 1 10 0194 CHESTERFIELD TAP, 138.00 138.00 11 0071 CABIN CREEK, WV TURNER #2, WV 138.00 138.00 3 0.08 1.36 1 12 0071 CABIN CREEK, WV TURNER #2, WV 1 22.11 13 0268 ST ALBANS LOOP, WV 138.00 138.00 3 0.34 0.34 1 14 0230 AMOS, WV TURNER #1, WV 138.00 138.00 3 11.97 1 15 0230 AMOS, WV TURNER #2, WV 138.00 138.00 3 11.96 1 16 0226 AMOS, WV CHEMICAL #1 A, WV 138.00 138.00 3 1.32 8.49 1 17 0226 AMOS, WV CHEMICAL #1 B, WV 138.00 138.00 3 5.98 1 18 0226 AMOS, WV CHEMICAL #2 A, WV 138.00 138.00 3 7.60 8.95 1 19 0226 AMOS, WV CHEMICAL #2 B, WV 138.00 138.00 3 4.13 1 20 0226 AMOS, WV CHEMICAL 1A-2A AND 1B-2B 138.00 138.00 3 0.60 2 21 0343 STONE BRANCH TAP, 138.00 138.00 1 6.24 1 22 HOPKINS, WV LOGAN, WV 138.00 138.00 3 7.56 11.16 1 23 HOPKINS, WV LOGAN, WV 138.00 138.00 3 18.69 1 24 0228 AMOS, WV HOPKINS, WV 138.00 138.00 3 1.89 17.20 1 25 0228 AMOS, WV HOPKINS, WV 138.00 138.00 3 28.24 0.31 1 26 0228 AMOS, WV HOPKINS, WV 138.00 138.00 3 1.60 1 27 0364 GRASSY FORK TAP, 138.00 138.00 1 2.18 1 28 0376 DINGESS LOOP, WV 138.00 138.00 3 0.16 0.16 1 29 0376 DINGESS LOOP, WV 1 0.19 0.19 30 0306 INEZ, KY LOGAN, WV 138.00 138.00 3 0.02 0.79 1 31 0306 INEZ, KY LOGAN, WV 1 23.27 32 0428 SHARPLES TAP 138KV 138.00 138.00 1 6.98 1 33 0432 MUD FORK LOOP, WV 138.00 138.00 3 0.76 0.76 1 34 0087 DARRAH, WV TRI STATE, WV 138.00 138.00 3 10.28 4.05 1 35 0436 DAWES LOOP, 138KV, 138.00 138.00
36 TOTAL 5,102.45 1,348.53 429
FERC FORM NO. 1 (ED. 12-87) Page 422.11 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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. Do not report 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. Show in column (f) the pole miles of line on structures the cost of which is 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 (Pole miles) (Indicate where Type of (In the case of Number No. other than underground lines 60 cycle, 3 phase) Supporting report circuit miles) Of On Structure On Structures Circuits From To Operating Designed Structure of Line of Another Designated Line (a) (b) (c) (d) (e) (f) (g) (h) 1 0088 TRI-STATE, WV WEST HUNTINGTON, WV 138.00 138.00 3 5.79 1 2 0090 SOUTH POINT, OH TRI-STATE CIR A, WV 138.00 138.00 3 7.85 1 3 0090 SOUTH POINT, OH TRI-STATE CIR B, WV 138.00 138.00 3 0.28 6.76 1 4 0225 AMOS SPORN 138.00 138.00 3 11.04 5 0237 AMOS, WV DARRAH, WV 138.00 138.00 3 35.06 1 6 0238 AMOS, WV WEST HUNTINGTON, WV 138.00 138.00 3 5.33 40.83 1 7 0238 AMOS, WV WEST HUNTINGTON, WV 1 0.10 8 0238 PARK HILL TAP, WV 138.00 138.00 3 0.01 1 9 0277 CABELL LOOP, WV 138.00 138.00 3 0.77 0.77 1 10 0302 MILTON LOOP, WV 138.00 138.00 3 1.71 1.71 1 11 0378 CURRY LOOP, WV 138.00 138.00 3 1.67 1.67 1 12 0095 CARBIDE MAIN, WV TURNER, WV 138.00 138.00 3 0.15 0.08 1 13 0096 CARBIDE #8, WV CHEMICAL-TURNER A, WV 138.00 138.00 3 0.04 1.21 1 14 0096 CARBIDE #8, WV CHEMICAL-TURNER B, WV 138.00 138.00 3 6.79 1 15 0096 CARBIDE #8, WV CHEMICAL-TURNER B, WV 138.00 138.00 3 1.30 2 16 0337 BLUEFIELD, WV SOUTH PRINCETON, WV 138.00 138.00 2 8.24 1 17 0337 BLUEFIELD, WV SOUTH PRINCETON, WV 138.00 138.00 1 0.26 2 18 0336 CLENDENIN TAP 138.00 138.00 1 8.30 19 CAPITALIZED SPARE 0373,0379 138.00 138.00 1 20 1005 CHERRY CREEK CLIFFTOP 138.00 138.00 1 7.20 1 21 0377 SPORN CLINE ENERGY EXTENSION 138.00 138.00 1 0.07 1 22 0370 SOUTHRIDGE 138.00 138.00 1 1.86 2 23 0098A FLATWOOD TAP 24 0386 GARRISON WV 138.00 138.00 1 0.20 2 25 0382 LANHAM, WV 138.00 138.00 1 1.40 2 26 0473 CARETTA JIM BRANCH 138.00 138.00 27 0471 HALLS RIDGE SOUTH PRINCETON, WV 138.00 138.00 3 0.42 1 28 0466 IAEGER WHARNCLIFFE, WV 46.00 138.00 3 6.38 1 29 1050 ROCKHOUSE 138.00 138.00 30 1072 CLENDENIN, WV MORRIS BRANCH 138.00 138.00 3 2.20 1 31 0474 COBB, WV THOROFARE CREEK 138.00 138.00 3 0.45 1 32 0463 CROOKED CREEK, WV 138.00 138.00 3 1.29 1 33 0472 MERRITS CREEK, WV 138.00 138.00 3 3.83 1 34 3843 BIM, WV 47.00 138.00 3 0.16 1 35 3843 BIM, WV 1 11.17
36 TOTAL 5,102.45 1,348.53 429
FERC FORM NO. 1 (ED. 12-87) Page 422.12 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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. Do not report 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. Show in column (f) the pole miles of line on structures the cost of which is 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 (Pole miles) (Indicate where Type of (In the case of Number No. other than underground lines 60 cycle, 3 phase) Supporting report circuit miles) Of On Structure On Structures Circuits From To Operating Designed Structure of Line of Another Designated Line (a) (b) (c) (d) (e) (f) (g) (h) 1 0478 POLYMER LOOP, WV 138.00 138.00 3 3.10 1 2 0478 POLYMER LOOP, WV 138.00 138.00 1 0.02 1 3 0477 BROAD RUN, WV THOROFARE CREEK 138.00 138.00 1.40 1 4 0475 PATRIOT COAL, WV POINT LICK 138.00 138.00 3 0.05 1 5 0482 CLARK BRANCH, WV 138KV EXTENSION 138.00 138.00 1 6 0481 LAKEVIEW 138KV EXTENSION 138.00 138.00 7 0483 HERNSHAW 138KV EXTENSION 138.00 138.00 3 1.55 2 8 0486 PAX BRANCH 138KV EXTENSION 138.00 138.00 3 1.44 2 9 0487 PIERPONT 138KV EXTENSION 138.00 138.00 3 1.25 1 10 0479 HARMON BRANCH 138KV EXTENSION 138.00 138.00 3 0.96 2 11 0492 TRI-STATE TWELVEPOLE CREEK 138.00 138.00 3 1.09 2 12 0503 CLINTWOOD 69.00 138.00 1 0.30 2 13 3827 BRADLEY LAYLAND NO.2B 69.00 138.00 1 0.75 1 14 0015 BERWIND FARADAY 138.00 138.00 15 0018 BERWIND YUKON 138.00 138.00 16 0016 JIM BRANCH YUKON 138.00 138.00 17 0568 GRANGSTON LOOP 138.00 138.00 3 0.25 2 18 0526 COMMONWEALTH 138KV EXTENSION 138.00 138.00 1 5.79 2 19 0527 COCO Extension 138.00 138.00 1 0.23 2 20 0528 CAPITOL HILL CHESTERFIELD AVE 69.00 138.00 1 0.25 1 21 22 23 24 Lines Under 138KV 1,593.18 181.37 25 26 Line cost and expense are not available by individual 27 transmission line Total shown in Column j - p 28 29 30 31 32 33 34 35
36 TOTAL 5,102.45 1,348.53 429
FERC FORM NO. 1 (ED. 12-87) Page 422.13 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / TRANSMISSION LINE STATISTICS (Continued) 7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g) 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 (j) to (l) on the book cost at end of year.
COST OF LINE (Include in Column (j) Land, EXPENSES, EXCEPT DEPRECIATION AND TAXES Size of Land rights, and clearing right-of-way) Conductor and Material Land Construction and Total Cost Operation Maintenance Rents Total Line Other Costs Expenses Expenses Expenses (i) (j) (k) (l) (m) (n) (o) (p) No. 1 2 2049KCM ACAR 3 1590KCM ACSR 4 1590KCM ACSR 5 1590KCM ACSR 6 1590KCM ACSR 7 397KCM ACSR 8 9 556KCM 10 11 397KCM ACSR 12 397KCM ACSR 13 636KCM ACSR 14 15 250KCM CU 16 1033KCM ACSR 17 18 19 20 954KCM ACSR 21 22 954KCM ACSR 23 954KCM ACSR 24 1351KCM ACSR 25 795 KCM ACSR 26 1351KCM ACSR 27 2049KCM ACAR 28 2-1780KCM ACSS 29 2-1780kcm ACSS 30 31 2049KCM ACAR 32 1563KCM ACAR 33 34 954 KCM ACSR 35
193,479,185 1,695,216,241 1,888,695,426 175,902 13,222,535 13,398,437 36
FERC FORM NO. 1 (ED. 12-87) Page 423 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / TRANSMISSION LINE STATISTICS (Continued) 7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g) 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 (j) to (l) on the book cost at end of year.
COST OF LINE (Include in Column (j) Land, EXPENSES, EXCEPT DEPRECIATION AND TAXES Size of Land rights, and clearing right-of-way) Conductor and Material Land Construction and Total Cost Operation Maintenance Rents Total Line Other Costs Expenses Expenses Expenses (i) (j) (k) (l) (m) (n) (o) (p) No. 1 1590KCM ACSR 2 1590KCM ACSR 3 636KCM ACSR 4 5 636KCM ACSR 6 7 795KCM ACSR 8 1033.5KCM ACSR 9 795KCM ACSR 10 11 397KCM ACSR 12 556KCM ACSR 13 397KCM ACSR 14 397KCM ACSR 15 397KCM ACSR 16 556KCM ACSR 17 18 19 795KCM ACSR 20 954KCM ACSR 21 4/0KCM ACSR 22 556KCM ACSR 23 24 556KCM ACSR 25 26 636KCM ACSR 27 636KCM ACSR 28 636KCM ACSR 29 636KCM ACSR 30 636KCM ACSR 31 636KCM ACSR 32 556KCM ACSR 33 795KCM ACSR 34 35
193,479,185 1,695,216,241 1,888,695,426 175,902 13,222,535 13,398,437 36
FERC FORM NO. 1 (ED. 12-87) Page 423.1 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / TRANSMISSION LINE STATISTICS (Continued) 7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g) 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 (j) to (l) on the book cost at end of year.
COST OF LINE (Include in Column (j) Land, EXPENSES, EXCEPT DEPRECIATION AND TAXES Size of Land rights, and clearing right-of-way) Conductor and Material Land Construction and Total Cost Operation Maintenance Rents Total Line Other Costs Expenses Expenses Expenses (i) (j) (k) (l) (m) (n) (o) (p) No. 636KCM ACSR 1 636KCM ACSR 2 1033KCM ACSR 3 336KCM ACSR 4 5 397KCM ACSR 6 795KCM ACSR 7 397KCM ACSR 8 1590KCM ACSR 9 636KCM ACSR 10 795 KCM ACSR 11 397KCM ACSR 12 636KCM ACSR 13 14 300KCM CU 15 397KCM ACSR 16 636KCM ACSR 17 795KCM ACSR 18 556KCM ACSR 19 336KCM ACSR 20 21 336 KCM ACSR 22 966KCM ACSR 23 336KCM ACSR 24 25 795KCM SSAC 26 27 397KCM ACSR 28 397KCM ACSR 29 397KCM ACSR 30 1033KCM ACSR 31 795KCM ACSR 32 1590KCM ACSR 33 1590KCM ACSR 34 556KCM ACSR 35
193,479,185 1,695,216,241 1,888,695,426 175,902 13,222,535 13,398,437 36
FERC FORM NO. 1 (ED. 12-87) Page 423.2 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / TRANSMISSION LINE STATISTICS (Continued) 7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g) 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 (j) to (l) on the book cost at end of year.
COST OF LINE (Include in Column (j) Land, EXPENSES, EXCEPT DEPRECIATION AND TAXES Size of Land rights, and clearing right-of-way) Conductor and Material Land Construction and Total Cost Operation Maintenance Rents Total Line Other Costs Expenses Expenses Expenses (i) (j) (k) (l) (m) (n) (o) (p) No. 1590KCM ACSR 1 556KCM ACSR 2 1590KCM ACSR 3 397KCM ACSR 4 5 795KCM ACSR 6 556KCM ACSR 7 795KCM ACSR 8 1033KCM ACSR 9 1033KCM ACSR 10 1033KCM ACSR 11 12 795KCM ACSR 13 795KCM ACSR 14 556KCM ACSR 15 556KCM ACSR 16 1590KCM ACSR 17 556KCM ACSR 18 1033KCM ACSR 19 397KCM ACSR 20 397KCM ACSR 21 397KCM ACSR 22 556KCM ACSR 23 636KCM ACSR 24 556KCM ACSR 25 556KCM ACSR 26 795KCM ACSR 27 795KCM ACSR 28 795KCM ACSR 29 556KCM ACSR 30 31 1590 KCM ACSR 32 556KCM ACSR 33 556KCM ACSR 34 1033KCM ACSR 35
193,479,185 1,695,216,241 1,888,695,426 175,902 13,222,535 13,398,437 36
FERC FORM NO. 1 (ED. 12-87) Page 423.3 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / TRANSMISSION LINE STATISTICS (Continued) 7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g) 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 (j) to (l) on the book cost at end of year.
COST OF LINE (Include in Column (j) Land, EXPENSES, EXCEPT DEPRECIATION AND TAXES Size of Land rights, and clearing right-of-way) Conductor and Material Land Construction and Total Cost Operation Maintenance Rents Total Line Other Costs Expenses Expenses Expenses (i) (j) (k) (l) (m) (n) (o) (p) No. 556KCM ACSR 1 556KCM ACSR 2 397KCM ACSR 3 397KCM ACSR 4 397KCM ACSR 5 1033KCM ACSR 6 556KCM ACSR 7 397KCM ACSR 8 795KCM ACSR 9 10 795KCM ACSR 11 397KCM ACSR 12 397KCM ACSR 13 556KCM ACSR 14 15 556KCM ACSR 16 556KCM ACSR 17 18 556KCM ACSR 19 556KCM ACSR 20 556KCM ACSR 21 1590KCM ACSR 22 556KCM ACSR 23 24 1590KCM ACSR 25 1590KCM ACSR 26 1590KCM ACSR 27 28 795KCM ACSR 29 1590KCM ACSR 30 795KCM ACSR 31 556KCM ACSR 32 795KCM ACSR 33 397KCM ACSR 34 636 KCM ACSR 35
193,479,185 1,695,216,241 1,888,695,426 175,902 13,222,535 13,398,437 36
FERC FORM NO. 1 (ED. 12-87) Page 423.4 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / TRANSMISSION LINE STATISTICS (Continued) 7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g) 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 (j) to (l) on the book cost at end of year.
COST OF LINE (Include in Column (j) Land, EXPENSES, EXCEPT DEPRECIATION AND TAXES Size of Land rights, and clearing right-of-way) Conductor and Material Land Construction and Total Cost Operation Maintenance Rents Total Line Other Costs Expenses Expenses Expenses (i) (j) (k) (l) (m) (n) (o) (p) No. 397KCM ACSR 1 795KCM ACSR 2 795KCM ACSR 3 795KCM ACSR 4 795KCM ACSR 5 556KCM ACSR 6 556KCM ACSR 7 1033KCM ACSR 8 1033KCM ACSR 9 1033KCM ACSR 10 1033.5 KCM ACSR 11 12 795 KCM ACSR 13 795KCM ACSR 14 795KCM ACSR 15 16 1272KCM ACSR 17 397KCM ACSR 18 1033KCM ACSR 19 795KCM ACSR 20 1033KCM ACSR 21 22 397KCM ACSR 23 397KCM ACSR 24 556KCM ACSR 25 795KCM ACSR 26 27 795KCM ACSR 28 29 30 1590KCM ACSR 31 1033 KCM ACSR 32 1033 KCM ACSR 33 1033 KCM ACSR 34 1590KCM ACSR 35
193,479,185 1,695,216,241 1,888,695,426 175,902 13,222,535 13,398,437 36
FERC FORM NO. 1 (ED. 12-87) Page 423.5 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / TRANSMISSION LINE STATISTICS (Continued) 7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g) 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 (j) to (l) on the book cost at end of year.
COST OF LINE (Include in Column (j) Land, EXPENSES, EXCEPT DEPRECIATION AND TAXES Size of Land rights, and clearing right-of-way) Conductor and Material Land Construction and Total Cost Operation Maintenance Rents Total Line Other Costs Expenses Expenses Expenses (i) (j) (k) (l) (m) (n) (o) (p) No. 795 ACSR 1 1590KCM ACSR 2 1590KCM ACSR 3 795KCM ACSR 4 5 1590 KCM ACSR 6 7 1590KCM 8 1590KCM 9 1590KCM 10 1590KCM 11 1590KCM ACSS 12 2-1926.9KCM 13 4-954KCM ACSR 14 1033.5KCM ACSR 15 1033.5KCM ACSR 16 1033.5KCM ACSR 17 795KCM ACSR 18 1233.6KCM 19 1233.6KCM 20 556.5 KCM 26/7 AC 21 1233.6KCM 22 1590 KCM ACSR 23 1233.6KCM 24 1233.6KCM 25 2 - 1926.9 KCM AC 26 1033.5KCM ACSR 27 1033.5KCM ACSR 28 1033.5KCM ACSR 29 1033.5KCM ACSR 30 1033.5KCM ACSR 31 1033.5KCM ACSR 32 1033.5KCM ACSR 33 1033.5KCM ACSR 34 1033.5KCM ACSR 35
193,479,185 1,695,216,241 1,888,695,426 175,902 13,222,535 13,398,437 36
FERC FORM NO. 1 (ED. 12-87) Page 423.6 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / TRANSMISSION LINE STATISTICS (Continued) 7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g) 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 (j) to (l) on the book cost at end of year.
COST OF LINE (Include in Column (j) Land, EXPENSES, EXCEPT DEPRECIATION AND TAXES Size of Land rights, and clearing right-of-way) Conductor and Material Land Construction and Total Cost Operation Maintenance Rents Total Line Other Costs Expenses Expenses Expenses (i) (j) (k) (l) (m) (n) (o) (p) No. 336KCM ACSR 1 1033.5KCM ACSR 2 1033.5KCM ACSR 3 795KCM ACSR 4 5 6 7 954KCM ACSR 8 1351KCM ACSR 9 1351KCM ACSR 10 11 954KCM ACSR 12 954KCM ACSR 13 1351KCM ACSR 14 1351KCM ACSR 15 795KCM ACSR 16 1351KCM ACSR 17 954KCM ACSR 18 19 954KCM ACSR 20 1414KCM ACSR 21 1275KCM ACSR 22 959.6 KCM ACSS 23 2156KCM ACSR 24 2-954KCM ACSR 25 1563KCM ACSR 26 1414KCM ACSR 27 1563KCM ACSR 28 2303KCM ACSR 29 2303KCM ACSR 30 336KCM ACSR 31 636KCM ACSR 32 397KCM ACSR 33 1590KCM ACSR 34 35
193,479,185 1,695,216,241 1,888,695,426 175,902 13,222,535 13,398,437 36
FERC FORM NO. 1 (ED. 12-87) Page 423.7 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / TRANSMISSION LINE STATISTICS (Continued) 7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g) 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 (j) to (l) on the book cost at end of year.
COST OF LINE (Include in Column (j) Land, EXPENSES, EXCEPT DEPRECIATION AND TAXES Size of Land rights, and clearing right-of-way) Conductor and Material Land Construction and Total Cost Operation Maintenance Rents Total Line Other Costs Expenses Expenses Expenses (i) (j) (k) (l) (m) (n) (o) (p) No. 1590KCM ACSR 1 795KCM ACSR 2 636KCM ACSR 3 795KCM ACSR 4 795KCM ACSR 5 556KCM ACSR 6 556KCM ACSR 7 556KCM ACSR 8 1590KCM ACSR 9 556KCM ACSR 10 11 336KCM ACSR 12 336KCM ACSR 13 336KCM ACSR 14 556KCM ACSR 15 556KCM ACSR 16 556KCM ACSR 17 556KCM ACSR 18 556KCM ACSR 19 636KCM ACSR 20 795KCM ACSR 21 795KCM ACSR 22 795KCM ACSR 23 556KICM ACSR 24 556KCM ACSR 25 556KCM ACSR 26 556KCM ACSS 27 556KCM ACSR 28 795KCM ACSR 29 795KCM ACSR 30 31 954KCM ACSR 32 556KCM ACSR 33 556KCM ACSR 34 397KCM ACSR 35
193,479,185 1,695,216,241 1,888,695,426 175,902 13,222,535 13,398,437 36
FERC FORM NO. 1 (ED. 12-87) Page 423.8 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / TRANSMISSION LINE STATISTICS (Continued) 7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g) 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 (j) to (l) on the book cost at end of year.
COST OF LINE (Include in Column (j) Land, EXPENSES, EXCEPT DEPRECIATION AND TAXES Size of Land rights, and clearing right-of-way) Conductor and Material Land Construction and Total Cost Operation Maintenance Rents Total Line Other Costs Expenses Expenses Expenses (i) (j) (k) (l) (m) (n) (o) (p) No. 397KCM ACSR 1 556KCM ACSR 2 397KCM ACSR 3 1033KCM ACSR 4 556KCM ACSR 5 795KCM ACSR 6 7 397KCM ACSR 8 397KCM ACSR 9 1351KCM ACSR 10 1033KCM ACSR 11 556KCM ACSR 12 13 397KCM ACSR 14 1351KCM ACSR 15 397KCM ACSR 16 397KCM ACSR 17 556KCM ACSR 18 556KCM ACSR 19 1780KCM ACSR 20 1351KCM ACSR 21 22 556KCM ACSR 23 556KCM ACSR 24 556KCM ACSR 25 1590KCM ACSR 26 556KCM ACSR 27 795KCM ACSR 28 795KCM ACSR 29 636KCM ACSR 30 636KCM ACSR 31 32 556KCM ACSR 33 34 35
193,479,185 1,695,216,241 1,888,695,426 175,902 13,222,535 13,398,437 36
FERC FORM NO. 1 (ED. 12-87) Page 423.9 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / TRANSMISSION LINE STATISTICS (Continued) 7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g) 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 (j) to (l) on the book cost at end of year.
COST OF LINE (Include in Column (j) Land, EXPENSES, EXCEPT DEPRECIATION AND TAXES Size of Land rights, and clearing right-of-way) Conductor and Material Land Construction and Total Cost Operation Maintenance Rents Total Line Other Costs Expenses Expenses Expenses (i) (j) (k) (l) (m) (n) (o) (p) No. 1 2 1033KCM ACSR 3 795KCM ACSR 4 556KCM ACSR 5 556KCM ACSR 6 336KCM ACSR 7 246KCM ACAR 8 4/0 ACSR 9 954KCM ACSR 10 556KCM ACSR 11 556KCM ACSR 12 1590KCM ACSR 13 1590KCM ACSR 14 1033KCM ACSR 15 1033KCM ACSR 16 397KCM ACSR 17 18 397KCM ACSR 19 556KCM ACSR 20 556KCM ACSR 21 556KCM ACSR 22 1033KCM ACSR 23 1035KCM ACSR 24 1033KCM ACSR 25 477KCM ACSR 26 477KCM ACSR 27 397KCM ACSR 28 397KCM ACSR 29 397KCM ACSR 30 795KCM ACSR 31 556KCM ACSR 32 795KCM ACSR 33 795KCM ACSR 34 795KCM ACSR 35
193,479,185 1,695,216,241 1,888,695,426 175,902 13,222,535 13,398,437 36
FERC FORM NO. 1 (ED. 12-87) Page 423.10 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / TRANSMISSION LINE STATISTICS (Continued) 7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g) 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 (j) to (l) on the book cost at end of year.
COST OF LINE (Include in Column (j) Land, EXPENSES, EXCEPT DEPRECIATION AND TAXES Size of Land rights, and clearing right-of-way) Conductor and Material Land Construction and Total Cost Operation Maintenance Rents Total Line Other Costs Expenses Expenses Expenses (i) (j) (k) (l) (m) (n) (o) (p) No. 795KCM ACSR 1 795KCMACSR 2 397KCM ACSR 3 795KCM ACSR 4 1590KCM ACSR 5 397KCM ACSR 6 397KCM ACSR 7 336KCM ACSR 8 1590KCM 9 10 250KCM ACSR 11 12 1033KCM ACSR 13 1033KCM ACSR 14 1033KCM ACSR 15 397KCM ACSR 16 1033KCM ACSR 17 1033KCM ACSR 18 397KCM ACSR 19 1033 KCM ACSR 20 795KCM ACSR 21 336KCM ACSR 22 336KCM ACSR 23 336KCM ACSR 24 795KCM ACSR 25 1590KCM 26 795KCM ACSR 27 1033KCM ACSR 28 29 795KCM ACSR 30 31 795KCM ACSR 32 795KCM ACSR 33 397KCM 34 35
193,479,185 1,695,216,241 1,888,695,426 175,902 13,222,535 13,398,437 36
FERC FORM NO. 1 (ED. 12-87) Page 423.11 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / TRANSMISSION LINE STATISTICS (Continued) 7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g) 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 (j) to (l) on the book cost at end of year.
COST OF LINE (Include in Column (j) Land, EXPENSES, EXCEPT DEPRECIATION AND TAXES Size of Land rights, and clearing right-of-way) Conductor and Material Land Construction and Total Cost Operation Maintenance Rents Total Line Other Costs Expenses Expenses Expenses (i) (j) (k) (l) (m) (n) (o) (p) No. 397KCM ACSR 1 397KCM ACSR 2 1351KCM ACSR 3 397KCM ACSR 4 397KCM ACSR 5 1033KCM ACSR 6 7 397KCM ACSR 8 954KCM ACSR 9 795KCM ACSR 10 1033KCM ACSR 11 1590 KCM ACSR 12 397KCM ACSR 13 1033KCM ACSR 14 1033KCM ACSR 15 556KCM ACSR 16 556KCM ACSR 17 18 19 795 ACSR 20 397KCM ACSR 21 1590KCM 22 23 795 KCM ACSR 24 795 KCM ACSR 25 26 1590KCM ACSR 27 556.5KCM26/7 AC 28 29 795 KCM ACSR 30 795 KCM ACSR 31 1033KCM ACSR 32 1033KCM ACSR 33 34 35
193,479,185 1,695,216,241 1,888,695,426 175,902 13,222,535 13,398,437 36
FERC FORM NO. 1 (ED. 12-87) Page 423.12 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / TRANSMISSION LINE STATISTICS (Continued) 7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g) 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 (j) to (l) on the book cost at end of year.
COST OF LINE (Include in Column (j) Land, EXPENSES, EXCEPT DEPRECIATION AND TAXES Size of Land rights, and clearing right-of-way) Conductor and Material Land Construction and Total Cost Operation Maintenance Rents Total Line Other Costs Expenses Expenses Expenses (i) (j) (k) (l) (m) (n) (o) (p) No. 795 KCM ACSR 1 795KCM ACSR 2 3 556.5 KCM 26/7 AC 4 5 6 1590 KCM ACSR 7 1033.5 KCM ACSR 8 1033.5 KCM 9 1033.5 KCM ACSR 10 795 KCM ACSR 11 1033.5 KCM ACSR 12 1158.4KCM 13 14 15 16 556.5KCM ACSR 17 1033 KCM ACSR 18 1033.5 KCM ACSR 19 1033.5 KCM ACSR 20 21 22 23 24 25 193,479,185 1,695,216,241 1,888,695,426 175,902 13,222,535 13,398,437 26 27 28 29 30 31 32 33 34 35
193,479,185 1,695,216,241 1,888,695,426 175,902 13,222,535 13,398,437 36
FERC FORM NO. 1 (ED. 12-87) Page 423.13 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / TRANSMISSION LINES ADDED DURING YEAR 1. Report below the information called for concerning Transmission lines added or altered during the year. It is not necessary to report minor revisions of lines. 2. Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. If actual costs of competed construction are not readily available for reporting columns (l) to (o), it is permissible to report in these columns the
Line LINE DESIGNATION Line SUPPORTING STRUCTURE CIRCUITS PER STRUCTURE Length Average No. From To in Type Number per Present Ultimate Miles Miles (a) (b) (c) (d) (e) (f) (g) 1 0541 IRONTO EXTENSION 0.10 1 2 2 2 0537 WOLF GLADE 2.00 1 2 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 TOTAL 2.10 4 4
FERC FORM NO. 1 (REV. 12-03) Page 424 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A Resubmission / / 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 (l) with appropriate footnote, and costs of Underground Conduit in column (m). 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 Voltage LINE COST Line Size Specification Configuration KV Land and Poles, Towers Conductors Asset Total No. and Spacing (Operating) Land Rights and Fixtures and Devices Retire. Costs (h) (i) (j) (k) (l) (m) (n)(o) (p) 1033.5 KCMACSR 138 241,328 157,884 399,212 1 795 KCMACSR 138 576,189 3,699,709 1,146,158 5,422,056 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
576,189 3,941,037 1,304,042 5,821,268 44
FERC FORM NO. 1 (REV. 12-03) Page 425 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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 VOLTAGE (In MVa) Name and Location of Substation Character of Substation No. Primary Secondary Tertiary (a) (b) (c) (d) (e) 1 ABERT - VA D 69.00 12.00 2 ABERT - VA D 69.00 3 ABINGDON - VA T 138.00 13.09 4 ABINGDON - VA T 138.00 70.50 13.09 5 ABINGDON - VA T 138.00 34.50 6 ACCOVILLE - WV D 69.00 46.00 1.60 7 ALLOY - WV D 46.00 13.09 8 ALUM CREEK - WV D 46.00 12.00 9 ALUM RIDGE - VA D 138.00 33.00 12.00 10 AMBLER RIDGE - WV D 138.00 138.00 34.50 11 AMBLER RIDGE - WV D 138.00 36.20 34.50 12 AMEAGLE - WV D 46.00 7.20 13 AMHERST - VA D 69.00 14 AMHERST - VA D 69.00 13.09 15 AMONATE LIGHTS - WV D 34.50 7.20 16 AMOS 138KV - WV T 138.00 17 AMOS 345KV - WV T 345.00 138.00 34.50 18 AMOS 345KV - WV T 34.50 7.20 19 AMOS 765KV - WV T 765.00 138.00 13.80 20 AMOS 765KV - WV T 765.00 345.00 34.50 21 AMOS 765KV - WV T 138.00 69.00 46.00 22 AMOS 765KV - WV T 765.00 345.00 34.50 23 APPLE GROVE - WV T 138.00 69.00 12.00 24 APPLE GROVE - WV T 69.00 12.00 25 ARCHER CREEK - VA D 69.00 12.00 26 ARROWHEAD - VA D 69.00 13.09 27 ATKINS - VA D 138.00 34.50 28 ATKINS - VA D 69.00 12.00 29 ATKINS - VA D 138.00 34.50 12.00 30 AUSTINVILLE - VA D 138.00 34.50 31 AXTON - VA T 765.00 138.00 13.80 32 AXTON - VA T 138.00 33 AXTON - VA T 765.00 34 BAILEYSVILLE - WV T 46.00 12.00 35 BAILEYSVILLE - WV T 138.00 36 BAILEYSVILLE - WV T 46.00 37 BAILEYSVILLE - WV T 138.00 46.00 38 BALD KNOB - WV D 46.00 12.00 39 BALLOU - VA D 69.00 34.50 40 BALLOU - VA D 69.00
FERC FORM NO. 1 (ED. 12-96) Page 426 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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 VOLTAGE (In MVa) Name and Location of Substation Character of Substation No. Primary Secondary Tertiary (a) (b) (c) (d) (e) 1 BANCROFT - WV T 138.00 13.09 2 BANCROFT - WV T 138.00 69.00 12.00 3 BANCROFT - WV T 138.00 34.50 4 BARNETT - WV D 69.00 13.09 5 BARNETT - WV D 69.00 12.00 6 BASSETT - VA D 69.00 12.00 7 BASSETT WALKER - VA D 34.50 7.50 8 BASSETT WALKER - VA D 34.50 7.20 9 BEALE - WV D 69.00 13.09 10 BEARWALLOW - VA T 138.00 70.50 13.09 11 BECCO - WV D 46.00 12 BECCO - WV D 46.00 12.00 13 BECKLEY - WV D 46.00 14 BECKLEY - WV D 46.00 4.16 15 BECKLEY - WV D 46.00 12.00 16 BELCHER MOUNTAIN - WV D 88.00 14.00 17 BELLE - WV T 46.00 12.00 18 BELVA - WV T 46.00 36.20 19 BELVA - WV T 138.00 46.00 20 BENS CREEK - WV D 46.00 13.20 21 BENT MOUNTAIN - VA D 138.00 34.00 22 BENT MOUNTAIN - VA D 138.00 13.09 23 BIG BRANCH - WV T 46.00 24 BIG ROCK - VA D 34.50 13.65 25 BIM - WV T 138.00 69.00 46.00 26 BIM - WV T 69.00 27 BIM - WV T 46.00 28 BLACKWATER - VA D 34.50 12.00 29 BLACKWATER - VA D 34.50 30 BLAINE - VA D 138.00 31 BLAINE - VA D 138.00 13.09 32 BLAINE - VA D 138.00 34.50 33 BLUE PENNANT - WV T 69.00 34 BLUE RIDGE - VA D 12.00 4.00 35 BLUE RIDGE - VA D 34.50 12.00 36 BLUEFIELD AVENUE - WV D 138.00 13.09 37 BOLT - WV T 138.00 69.00 46.00 38 BOLT - WV T 46.00 39 BONSACK - VA D 138.00 34.50 40 BOONE - WV D 46.00
FERC FORM NO. 1 (ED. 12-96) Page 426.1 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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 VOLTAGE (In MVa) Name and Location of Substation Character of Substation No. Primary Secondary Tertiary (a) (b) (c) (d) (e) 1 BOONE - WV D 46.00 12.00 2 BOONSBORO - VA D 138.00 13.09 3 BORDERLAND - WV D 138.00 13.09 4 BOWYER - WV D 46.00 7.20 5 BOXWOOD - VA D 138.00 13.09 6 BRADLEY - WV T 138.00 69.00 46.00 7 BRADLEY - WV T 138.00 8 BRADLEY - WV T 46.00 12.00 9 BRIAR MOUNTAIN - WV D 46.00 7.20 10 BRIDGE - WV D 69.00 13.09 11 BROADFORD 138KV - VA T 138.00 12 BROADFORD 765KV - VA T 765.00 138.00 13.80 13 BROADFORD 765KV - VA T 765.00 14 BROADFORD 765KV - VA T 765.00 500.00 13.80 15 BROCKWAY GLASS - VA D 69.00 4.00 16 BROOKVILLE - VA D 138.00 13.09 17 BROWNSVILLE (AP) - WV D 69.00 12.00 18 BRUSH TAVERN - VA D 138.00 34.50 19 BUCKHORN - VA D 138.00 34.50 20 BURLINGTON HEIGHTS - VA D 138.00 34.50 21 BYLLESBY - VA T 69.00 7.20 22 BYLLESBY - VA T 69.00 23 CABELL - WV D 138.00 36.20 24 CABELL - WV D 138.00 34.50 25 CABIN CREEK 46KV - WV T 138.00 46.00 26 CABIN CREEK 46KV - WV T 138.00 46.20 27 CABIN CREEK 46KV - WV T 46.00 12.00 28 CAMBRIA - VA D 69.00 13.09 29 CAMPBELL AVENUE - VA D 69.00 12.00 30 CAMPBELL AVENUE - VA D 69.00 31 CAMPBELL AVENUE - VA D 34.50 32 CAMPBELL AVENUE - VA D 69.00 34.50 33 CANDLERS MOUNTAIN - VA D 138.00 13.09 34 CAPITOL HILL 138KV - WV T 138.00 46.00 35 CAPITOL HILL 138KV - WV T 138.00 69.00 46.00 36 CAPITOL HILL 138KV - WV T 138.00 13.09 37 CAPITOL HILL 46KV - WV T 46.00 38 CARBONDALE - WV T 138.00 69.00 46.00 39 CARBONDALE - WV T 46.00 36.20 40 CARSWELL - WV T 138.00 88.00 13.20
FERC FORM NO. 1 (ED. 12-96) Page 426.2 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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 VOLTAGE (In MVa) Name and Location of Substation Character of Substation No. Primary Secondary Tertiary (a) (b) (c) (d) (e) 1 CARSWELL - WV T 138.00 88.00 7.98 2 CATAWBA - VA T 138.00 34.50 3 CATAWBA - VA T 138.00 4 CATAWBA - VA T 69.00 5 CATAWBA - VA T 138.00 69.00 34.50 6 CAVE SPRING - VA D 138.00 13.09 7 CEDAR GROVE (AP) - WV D 46.00 12.00 8 CENTERVILLE - VA T 138.00 13.09 9 CENTERVILLE - VA T 138.00 69.00 34.50 10 CENTRAL AVENUE (AP) - WV D 46.00 11 CENTRAL MACHINE SHOP - WV D 46.00 4.00 12 CEREDO - WV D 34.50 4.00 13 CHAUNCEY - WV T 46.00 12.00 14 CHAUNCEY - WV T 138.00 46.00 19.50 15 CHEMICAL - WV T 138.00 69.00 46.00 16 CHEMICAL - WV T 138.00 46.00 17 CHEMICAL - WV T 46.00 12.00 18 CHEMICAL - WV T 46.00 19 CHERRY CREEK - WV D 138.00 13.09 20 CHERRY CREEK - WV D 138.00 34.50 21 CHESTERFIELD AVENUE - WV T 138.00 13.09 22 CHESTERFIELD AVENUE - WV T 138.00 70.50 46.00 23 CINDERELLA - WV D 138.00 13.09 24 CLAREMONT - WV D 69.00 12.00 25 CLAYPOOL HILL - VA D 138.00 13.09 26 CLAYTOR HILLTOP - VA T 27 CLEARBROOK - VA D 138.00 13.09 28 CLENDENIN - WV T 46.00 34.50 20.90 29 CLENDENIN - WV T 138.00 46.00 30 CLIFFORD - VA T 138.00 46.00 31 CLIFFORD - VA T 138.00 69.00 46.00 32 CLIFFORD - VA T 46.00 33 CLIFFTOP - WV D 138.00 13.09 34 CLIFFVIEW - VA D 69.00 13.00 35 CLIFFVIEW - VA D 69.00 36 CLIFFVIEW - VA D 69.00 36.20 37 CLINCHFIELD - VA T 138.00 70.50 36.20 38 CLINCHFIELD - VA T 69.00 39 CLINTWOOD - VA D 69.00 12.00 40 CLINTWOOD - VA D 69.00
FERC FORM NO. 1 (ED. 12-96) Page 426.3 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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 VOLTAGE (In MVa) Name and Location of Substation Character of Substation No. Primary Secondary Tertiary (a) (b) (c) (d) (e) 1 CLOVERDALE 138KV - VA T 345.00 137.50 13.80 2 CLOVERDALE 138KV - VA T 138.00 70.50 36.20 3 CLOVERDALE 138KV - VA T 345.00 137.50 13.14 4 CLOVERDALE 138KV - VA T 345.00 138.00 34.50 5 CLOVERDALE 138KV - VA T 138.00 36.20 6 CLOVERDALE 138KV - VA T 69.00 13.09 7 CLOVERDALE 765KV - VA T 765.00 528.00 13.80 8 CLOVERDALE 765KV - VA T 138.00 12.00 9 CLOVERDALE 765KV - VA T 138.00 34.00 10 CLOVERDALE 765KV - VA T 69.00 34.50 11 CLOVERDALE 765KV - VA T 138.00 69.00 13.10 12 CLOVERDALE 765KV - VA T 138.00 13.09 13 CLOVERDALE 765KV - VA T 34.50 7.20 14 CLOVERDALE 765KV - VA T 138.00 12.00 15 CLOVERDALE 765KV - VA T 138.00 70.50 46.00 16 CLOVERDALE 765KV - VA T 138.00 70.50 13.09 17 CLOVERDALE 765KV - VA T 138.00 70.50 13.09 18 CLOVERDALE 765KV - VA T 138.00 70.50 13.09 19 CLOVERDALE 765KV - VA T 138.00 70.50 13.09 20 CLOVERDALE 765KV - VA T 138.00 70.50 13.09 21 CLOVERDALE 765KV - VA T 138.00 70.50 13.09 22 CLOVERDALE 765KV - VA T 138.00 70.50 13.09 23 CLOVERDALE 765KV - VA T 138.00 70.50 13.09 24 CLOVERDALE 765KV - VA T 138.00 70.50 13.09 25 CLOVERDALE 765KV - VA T 138.00 70.50 13.09 26 CLOVERDALE 765KV - VA T 138.00 70.50 13.09 27 CLOVERDALE 765KV - VA T 138.00 70.50 13.09 28 CLOVERDALE 765KV - VA T 138.00 70.50 13.09 29 CLOVERDALE 765KV - VA T 138.00 70.50 13.09 30 CLOVERDALE 765KV - VA T 138.00 70.50 13.09 31 CLOVERDALE 765KV - VA T 138.00 70.50 13.09 32 CLOVERDALE 765KV - VA T 138.00 70.50 13.09 33 CLOVERDALE 765KV - VA T 138.00 70.50 13.09 34 CLOVERDALE 765KV - VA T 138.00 70.50 13.09 35 CLOVERDALE 765KV - VA T 138.00 70.50 13.09 36 CLOVERDALE 765KV - VA T 138.00 70.50 13.09 37 CLOVERDALE 765KV - VA T 138.00 70.50 13.09 38 CLOVERDALE 765KV - VA T 138.00 70.50 13.09 39 CLOVERDALE 765KV - VA T 138.00 70.50 13.09 40 CLOVERDALE 765KV - VA T 138.00 70.50 13.09
FERC FORM NO. 1 (ED. 12-96) Page 426.4 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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 VOLTAGE (In MVa) Name and Location of Substation Character of Substation No. Primary Secondary Tertiary (a) (b) (c) (d) (e) 1 CLOVERDALE 765KV - VA T 138.00 70.50 13.09 2 CLOVERDALE 765KV - VA T 138.00 70.50 13.09 3 CLOVERDALE 765KV - VA T 138.00 34.50 4 CLOVERDALE 765KV - VA T 69.00 12.00 5 CLOVERDALE 765KV - VA T 69.00 13.09 6 CLOVERDALE 765KV - VA T 138.00 70.50 13.09 7 CLOVERDALE 765KV - VA T 138.00 70.50 13.09 8 CLOVERDALE 765KV - VA T 138.00 70.50 13.09 9 CLOVERDALE 765KV - VA T 138.00 70.50 13.09 10 CLOVERDALE 765KV - VA T 138.00 70.50 36.20 11 CLOVERDALE 765KV - VA T 138.00 70.50 36.20 12 CLOVERDALE 765KV - VA T 138.00 70.50 36.20 13 CLOVERDALE 765KV - VA T 138.00 70.50 36.20 14 CLOVERDALE 765KV - VA T 138.00 13.09 34.50 15 CLOVERDALE 765KV - VA T 138.00 13.09 34.50 16 CLOVERDALE 765KV - VA T 138.00 345.00 34.50 17 CLOVERDALE 765KV - VA T 138.00 345.00 34.50 18 CLOVERDALE 765KV - VA T 69.00 12.00 19 CLOVERDALE 765KV - VA T 138.00 13.09 20 CLOVERDALE 765KV - VA T 69.00 13.09 21 CLOVERDALE 765KV - VA T 69.00 13.09 22 CLOVERDALE 765KV - VA T 69.00 12.00 23 CLOVERDALE 765KV - VA T 69.00 12.00 24 CLOVERDALE 765KV - VA T 765.00 345.00 34.50 25 CLOVERDALE 765KV - VA T 765.00 26 CLOVERDALE EAST 500KV - VA T 500.00 345.00 13.80 27 COAL CREEK - VA D 69.00 12.00 28 COAL MOUNTAIN - WV D 46.00 7.20 29 COFFEE - VA D 138.00 13.09 30 COLLINSVILLE (AP) - VA D 138.00 13.09 31 CORNING GLASS (AP) - VA D 69.00 4.00 32 CORNING GLASS (AP) - VA D 69.00 33 COTTAGEVILLE - WV D 69.00 12.00 34 COVE ROAD - VA D 69.00 13.09 35 CRAB ORCHARD - WV D 46.00 12.00 36 CROOKED CREEK - WV D 138.00 13.09 37 CROSSROADS (AP) - VA D 69.00 13.09 38 CROSSROADS (AP) - VA D 69.00 39 CURRY - WV D 138.00 13.09 40 DALEWOOD - WV D 138.00 13.09
FERC FORM NO. 1 (ED. 12-96) Page 426.5 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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 VOLTAGE (In MVa) Name and Location of Substation Character of Substation No. Primary Secondary Tertiary (a) (b) (c) (d) (e) 1 DAMASCUS - VA D 69.00 12.00 2 DAMERON - WV T 138.00 69.00 46.00 3 DAMERON - WV T 46.00 34.50 4 DAMERON - WV T 46.00 5 DAN RIVER RESEARCH - VA D 7.62 0.60 6 DAN RIVER RESEARCH - VA D 12.00 0.60 7 DAN RIVER RESEARCH - VA D 69.00 12.00 8 DANVILLE - VA T 138.00 69.00 12.00 9 DARRAH - WV T 138.00 34.50 10 DARRAH - WV T 138.00 13.09 11 DARRAH - WV T 138.00 69.00 34.50 12 DARRAH - WV T 138.00 34.50 13 DEARINGTON - VA D 69.00 14 DEARINGTON - VA D 69.00 12.00 15 DEARINGTON - VA D 69.00 13.09 16 DEHUE - WV D 46.00 13.09 17 DINGESS - WV D 138.00 34.50 18 DISMAL RIVER - VA D 69.00 12.00 19 DISMAL RIVER - VA D 69.00 20 DISSTON - VA D 69.00 4.00 21 DOROTHY - WV D 46.00 2.30 22 DUBLIN (AP) - VA D 34.50 12.00 23 DUNBAR - WV D 46.00 13.09 24 DUPONT (AP) - VA D 69.00 12.00 25 EAST DANVILLE - VA T 69.00 26 EAST DANVILLE - VA T 138.00 69.50 13.09 27 EAST DANVILLE - VA T 69.00 12.00 28 EAST DANVILLE - VA T 230.00 138.00 34.50 29 EAST DANVILLE - VA T 138.00 30 EAST HUNTINGTON - WV T 138.00 34.50 31 EAST HUNTINGTON - WV T 34.50 12.00 32 EAST HUNTINGTON - WV T 138.00 69.00 34.50 33 EAST LYNCHBURG - VA T 138.00 69.00 34.50 34 EAST LYNCHBURG - VA T 138.00 35 EAST MONUMENT - VA T 138.00 36 EAST RIVER MOUNTAIN - WV D 138.00 34.50 37 EDGEMONT - VA D 138.00 13.09 38 EDWIGHT - WV D 46.00 7.20 39 ELK CREEK - WV D 46.00 12.00 40 ELK GARDEN - VA D 138.00 36.20
FERC FORM NO. 1 (ED. 12-96) Page 426.6 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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 VOLTAGE (In MVa) Name and Location of Substation Character of Substation No. Primary Secondary Tertiary (a) (b) (c) (d) (e) 1 ELK GARDEN - VA D 138.00 34.50 2 ELK GARDEN - VA D 138.00 13.09 3 ELM STREET - VA D 34.50 12.00 4 ELM STREET - VA D 34.50 5 ELMO - WV D 69.00 12.00 6 ESMONT - VA D 46.00 12.00 7 EXPRESSWAY - VA D 69.00 12.00 8 EXPRESSWAY - VA D 69.00 9 FALLING BRANCH - VA D 138.00 13.09 10 FARADAY 138KV - WV D 34.50 11 FARADAY 138KV - WV D 34.50 12 FAYETTEVILLE (AP) - WV D 69.00 13.09 13 FIELDALE - VA T 69.00 14 FIELDALE - VA T 138.00 15 FIELDALE - VA T 138.00 70.50 36.20 16 FIELDALE - VA T 34.50 12.00 17 FIELDALE - VA T 34.50 18 FIELDCREST MILLS - VA D 69.00 4.00 19 FLATWOOD - WV D 138.00 34.50 20 FLATWOOD - WV D 138.00 12.47 21 FLETCHERS RIDGE - VA D 138.00 13.09 22 FLOYD - VA T 138.00 13.09 23 FLOYD - VA T 138.00 69.00 34.50 24 FLOYD - VA T 138.00 12.00 25 FOREST (AP) - VA D 138.00 13.09 26 FRANKLIN - VA D 138.00 13.09 27 FRANKLIN - VA D 138.00 34.50 28 FRANKLIN STREET - VA D 34.50 12.00 29 FREMONT (AP) - VA T 138.00 70.50 13.09 30 FRIES - VA D 69.00 31 FRIES - VA D 69.00 12.00 32 FULKS - WV D 34.50 34.50 5.00 33 FULKS - WV D 34.50 13.09 34 FULKS - WV D 34.50 34.50 6.50 35 GALAX - VA D 69.00 12.00 36 GALAX - VA D 69.00 37 GALLAGHER - WV D 46.00 12.00 38 GARDEN CREEK - VA T 69.00 12.00 39 GARDEN CREEK - VA T 138.00 69.50 13.09 40 GARDEN CREEK - VA T 138.00
FERC FORM NO. 1 (ED. 12-96) Page 426.7 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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 VOLTAGE (In MVa) Name and Location of Substation Character of Substation No. Primary Secondary Tertiary (a) (b) (c) (d) (e) 1 GATE CITY - VA D 69.00 12.00 2 GAULEY MOUNTAIN - WV D 69.00 12.00 3 GILBERT - WV D 46.00 4 GILBERT - WV D 46.00 12.00 5 GLADE - VA D 69.00 6 GLADE - VA D 69.00 34.50 7 GLADE - VA D 69.00 12.00 8 GLAMORGAN - VA D 34.50 4.00 9 GLEN LYN - VA T 138.00 10 GLEN LYN - VA T 88.00 69.00 13.10 11 GLEN LYN - VA T 138.00 13.20 12 GLEN WHITE - WV D 46.00 12.00 13 GLENWOOD (AP) - VA D 23.00 12.00 14 GLENWOOD (AP) - VA D 12.00 0.24 15 GLENWOOD (AP) - VA D 13.20 0.24 16 GLENWOOD (AP) - VA D 12.00 0.24 17 GLENWOOD (AP) - VA D 23.00 12.00 18 GOMINGO - VA D 138.00 13.09 19 GRAPEVINE - WV D 46.00 7.20 20 GRASSY FORK - WV D 138.00 34.50 21 GRAVES MILL - VA D 138.00 13.09 22 GREENBRIER - WV D 69.00 13.09 23 GREENBRIER METERING - WV T 138.00 24 GRUNDY - VA T 69.00 34.50 25 GRUNDY - VA T 69.00 26 GRUNDY - VA T 69.00 12.00 27 GUTHRIE - WV D 46.00 34.50 28 HALES BRANCH - VA T 69.00 29 HALES BRANCH - VA T 138.00 69.00 12.00 30 HALES BRANCH - VA T 138.00 31 HALLS RIDGE - WV D 138.00 34.50 32 HAMPTON - WV D 46.00 12.00 33 HAMPTON - WV D 46.00 7.20 34 HANCOCK - VA T 34.50 35 HANCOCK - VA T 34.50 36.20 36 HANCOCK - VA T 138.00 37 HANCOCK - VA T 138.00 34.50 11.00 38 HANCOCK - VA T 138.00 69.00 34.50 39 HANS MEADOW - VA D 69.00 12.00 40 HANS MEADOW - VA D 69.00 13.09
FERC FORM NO. 1 (ED. 12-96) Page 426.8 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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 VOLTAGE (In MVa) Name and Location of Substation Character of Substation No. Primary Secondary Tertiary (a) (b) (c) (d) (e) 1 HANSONVILLE - VA D 138.00 13.09 2 HARDY - WV D 46.00 7.20 3 HARMON BRANCH - WV D 138.00 12.00 4 HARTLAND - WV D 46.00 13.09 5 HARTLAND - WV D 46.00 6 HASH RIDGE - WV D 138.00 34.50 7 HAYSI - VA D 69.00 12.00 8 HENRY S.D. - VA D 34.50 13.00 9 HEWETT - WV D 46.00 12.00 10 HICKMAN - VA D 69.00 13.09 11 HICKORY GAP - WV D 34.50 12.00 12 HILL - VA T 138.00 69.00 34.50 13 HILL - VA T 69.00 14 HILL - VA T 138.00 13.09 15 HILLMAN HIGHWAY - VA D 69.00 13.09 16 HILLMAN HIGHWAY - VA D 69.00 12.00 17 HILLSVILLE - VA D 34.50 12.00 18 HINTON (AP) - WV T 138.00 19 HOPKINS - WV T 138.00 13.09 20 HOPKINS - WV T 138.00 34.50 21 HOPKINS - WV T 138.00 22 HOPKINS - WV T 138.00 69.00 46.00 23 HOPKINS FORK - WV D 46.00 7.20 24 HUBBARDSTOWN - WV D 138.00 34.50 25 HUFF CREEK - WV T 46.00 26 HUFF CREEK - WV T 46.00 13.09 27 HUFF CREEK - WV T 138.00 69.00 46.00 28 HUFFMAN - VA D 138.00 29 HUGHESTON - WV D 46.00 2.40 30 HUNTINGTON COURT - VA D 69.00 34.50 31 HUNTINGTON COURT - VA D 69.00 12.00 32 HUNTINGTON COURT - VA D 138.00 69.00 34.50 33 HUNTINGTON COURT - VA D 69.00 34 HUNTINGTON COURT - VA D 138.00 35 HURLEY - VA D 69.00 12.00 36 HURRICANE - WV D 69.00 37 HURRICANE - WV D 69.00 12.00 38 INDEPENDENCE - VA D 69.00 12.00 39 INDEPENDENCE - VA D 69.00 34.50 40 INGLES - VA D 69.00 13.09
FERC FORM NO. 1 (ED. 12-96) Page 426.9 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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 VOLTAGE (In MVa) Name and Location of Substation Character of Substation No. Primary Secondary Tertiary (a) (b) (c) (d) (e) 1 INGLES - VA D 69.00 34.50 2 INGLES - VA D 69.00 3 ITMANN - WV D 138.00 13.09 4 IVY HILL - VA D 138.00 13.09 5 JACKSONS FERRY - VA T 765.00 13.80 6 JACKSONS FERRY - VA T 20.78 7 JACKSONS FERRY - VA T 765.00 8 JACKSONS FERRY - VA T 765.00 20.65 13.80 9 JACKSONS FERRY - VA T 13.20 10 JACKSONS FERRY - VA T 765.00 500.00 13.80 11 JACKSONS FERRY - VA T 13.80 12 JACKSONS FERRY - VA T 765.00 138.00 13 JACKSONS FERRY - VA T 765.00 138.00 13.80 14 JARROLD - WV D 46.00 13.09 15 JEWELL RIDGE - VA D 69.00 12.00 16 JIM BRANCH - WV T 69.00 12.00 17 JIM BRANCH - WV T 138.00 69.00 46.00 18 JOHNSONS LANE - WV D 34.50 34.50 5.00 19 JOSHUA FALLS - VA T 765.00 138.00 13.80 20 JUBAL EARLY - VA T 138.00 21 JUBAL EARLY - VA T 138.00 69.00 34.50 22 KANAWHA CITY - WV D 46.00 12.00 23 KANAWHA CITY - WV D 46.00 24 KANAWHA RIVER - WV T 345.00 138.00 13.80 25 KANAWHA RIVER - WV T 138.00 13.09 26 KENOVA - WV T 138.00 34.50 27 KENOVA - WV T 34.50 13.09 28 KENOVA - WV T 138.00 69.00 34.50 29 KENOVA - WV T 138.00 69.00 46.00 30 KENOVA - WV T 34.50 4.00 31 KENOVA - WV T 69.00 32 KILLARNEY - WV D 46.00 7.20 33 KILLARNEY - WV D 46.00 7.20 34 KINCAID - WV T 138.00 69.00 46.00 35 KNOTTY POPLAR - VA D 69.00 12.00 36 KOPPERSTON - WV D 138.00 13.09 37 KUMIS - VA D 138.00 13.09 38 LAKE FOREST - VA D 138.00 36.20 39 LAKEVIEW - WV D 138.00 13.09 40 LAKIN - WV T 138.00 69.00 12.00
FERC FORM NO. 1 (ED. 12-96) Page 426.10 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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 VOLTAGE (In MVa) Name and Location of Substation Character of Substation No. Primary Secondary Tertiary (a) (b) (c) (d) (e) 1 LAKIN - WV T 138.00 13.09 2 LATROBE - WV D 46.00 7.20 3 LAVALETTE - WV D 138.00 34.50 4 LAYLAND - WV D 69.00 13.09 5 LEBANON - VA D 138.00 13.09 6 LEE HIGHWAY - VA D 69.00 12.00 7 LEIVASY - WV D 69.00 12.00 8 LICK FORK - VA D 69.00 34.50 9 LOCK LANE - WV D 69.00 12.00 10 LOCKHART - VA D 138.00 13.04 11 LOGAN - WV T 138.00 13.09 12 LOGAN - WV T 138.00 13 LONESOME PINE - VA D 138.00 13.09 14 LOONEY CREEK - VA T 138.00 69.00 34.50 15 LOUDENDALE - WV D 46.00 12.00 16 LOUP CREEK - WV D 46.00 12.00 17 LUKENS - VA D 69.00 13.09 18 MAMMOTH - WV D 46.00 12.00 19 MARIANNA - WV D 46.00 12.00 20 MARMET - WV D 46.00 12.00 21 MARSH FORK - WV D 46.00 12.00 22 MARTINSVILLE - VA T 138.00 34.50 23 MARTINSVILLE - VA T 138.00 70.50 36.20 24 MARTINSVILLE - VA T 138.00 69.00 34.50 25 MASON CREEK - VA D 69.00 12.00 26 MATT FUNK 138KV - VA T 138.00 27 MATT FUNK 345KV - VA T 345.00 138.00 13.10 28 MATT FUNK 345KV - VA T 345.00 138.00 34.50 29 MCDOWELL - WV T 34.50 13.20 30 MCGRAWS - WV D 46.00 13.09 31 MCROSS - WV D 69.00 34.50 32 MCROSS - WV D 69.00 33 MEADOW BRIDGE - WV D 69.00 34.50 34 MEADOWVIEW - VA D 138.00 13.09 35 MEADOWVIEW - VA D 138.00 69.00 34.50 36 MELROSE - VA D 69.00 12.00 37 MERRIMAC - VA T 138.00 69.00 13.09 38 MERRIMAC - VA T 69.00 39 MERRIMAC - VA T 138.00 69.00 12.00 40 MERRITTS CREEK - WV D 138.00 36.20
FERC FORM NO. 1 (ED. 12-96) Page 426.11 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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 VOLTAGE (In MVa) Name and Location of Substation Character of Substation No. Primary Secondary Tertiary (a) (b) (c) (d) (e) 1 MIDDLE BURNING CREEK - WV D 34.50 12.00 2 MIDKIFF - WV D 138.00 34.50 3 MIDWAY (AP) - VA D 69.00 4.00 4 MIKES RUN - WV D 46.00 12.00 5 MILBURN - WV D 46.00 7.20 6 MILL RUN - WV D 69.00 12.00 7 MILTON - WV T 138.00 69.00 34.50 8 MILTON - WV T 138.00 36.20 9 MILTON - WV T 138.00 13.09 10 MILTON - WV T 69.00 36.20 11 MINK SHOALS - WV D 69.00 13.09 12 MINNIX MOUNTAIN - WV D 138.00 34.00 13 MOHAWK RUBBER - VA D 69.00 2.40 14 MONEL - VA D 138.00 13.09 15 MONETA - VA D 138.00 34.50 16 MONROE (AP) - VA D 69.00 13.09 17 MONTEREY - VA D 69.00 12.00 18 MONTGOMERY - WV D 46.00 12.00 19 MORGANS CUT - VA T 138.00 69.00 34.50 20 MORGANS CUT - VA T 138.00 69.00 34.50 21 MORGANS CUT - VA T 34.50 22 MORRIS NOVELTY - VA D 34.50 12.00 23 MORRIS NOVELTY - VA D 34.50 24 MOSELEY - VA T 138.00 69.00 12.00 25 MOSS - VA D 69.00 12.00 26 MOUNT AIRY - VA D 138.00 34.50 27 MOUNT HOPE - WV D 46.00 4.00 28 MOUNT UNION - VA T 69.00 29 MOUNT UNION - VA T 69.00 34.50 30 MOUNT UNION - VA T 69.00 12.00 31 MOUNT VIEW - VA D 69.00 12.00 32 MUD FORK - WV D 138.00 13.09 33 MUDLICK - VA D 69.00 12.00 34 MULLENS - WV T 138.00 35 MULLENS - WV T 138.00 34.50 36 MULLENS - WV T 138.00 46.00 37 MULLENS TOWN - WV D 34.50 4.00 38 MULLENSVILLE - WV T 138.00 46.00 39 NAGEL - TN T 138.00 34.50 40 NAGEL - TN T 500.00 138.00 13.80
FERC FORM NO. 1 (ED. 12-96) Page 426.12 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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 VOLTAGE (In MVa) Name and Location of Substation Character of Substation No. Primary Secondary Tertiary (a) (b) (c) (d) (e) 1 NAGEL - TN T 500.00 230.00 13.80 2 NEECE CREEK - VA D 69.00 12.00 3 NEW CASTLE - VA D 34.50 4 NEW CASTLE - VA D 34.50 12.00 5 NEW HOPE (AP) - WV D 138.00 13.09 6 NEW HOPE (AP) - WV D 138.00 34.50 7 NEW LONDON - VA T 138.00 34.50 8 NITRO - WV D 69.00 12.00 9 NORTH BECKLEY - WV D 138.00 34.50 10 NORTH BECKLEY - WV D 138.00 13.09 11 NORTH BLACKSBURG - VA T 138.00 69.00 12.00 12 NORTH BLACKSBURG - VA T 138.00 13.09 13 NORTH CLAYTOR - VA T 138.00 69.00 34.50 14 NORTH CLAYTOR - VA T 138.00 69.00 34.50 15 NORTH POINTE - WV D 138.00 34.50 16 OAK HILL (AP) - WV D 69.00 12.00 17 OAK LEVEL - VA D 138.00 13.09 18 OCEANA - WV D 46.00 12.00 19 OPOSSUM CREEK - VA T 138.00 20 ORCHARD - VA D 34.50 12.00 21 ORTIN - WV D 138.00 13.09 22 PACKSVILLE - WV T 46.00 23 PAD FORK - WV D 138.00 34.50 24 PANTHER - WV D 46.00 7.20 25 PARK HILL - WV D 138.00 13.09 26 PATRICK STREET - WV D 46.00 13.09 27 PATRIOT CENTRE - VA D 138.00 34.50 28 PAX BRANCH 138KV - WV T 138.00 12.00 29 PAX BRANCH 138KV - WV T 138.00 46.00 30 PAX BRANCH 138KV - WV T 138.00 13.09 31 PEAK CREEK - VA D 138.00 34.50 32 PEAK CREEK - VA D 138.00 13.09 33 PEAKLAND - VA D 69.00 12.00 34 PEAKSVIEW - VA T 138.00 69.00 34.50 35 PEARISBURG - VA D 34.50 12.00 36 PEMBERTON - WV T 138.00 69.00 46.00 37 PEMBERTON - WV T 46.00 4.00 38 PENHOOK - VA D 138.00 34.50 39 PERKINS PARK - VA D 69.00 12.00 40 PETERS MOUNTAIN - VA D 138.00 34.50
FERC FORM NO. 1 (ED. 12-96) Page 426.13 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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 VOLTAGE (In MVa) Name and Location of Substation Character of Substation No. Primary Secondary Tertiary (a) (b) (c) (d) (e) 1 PEYTONA - WV D 46.00 13.09 2 PHOENIX - VA D 46.00 7.20 3 PIGEON CREEK - WV D 138.00 34.50 4 PINE CREEK - WV D 138.00 13.09 5 PINE GAP - WV D 46.00 12.00 6 PINNACLE CREEK - WV D 138.00 34.50 12.00 7 PINNACLE CREEK - WV D 138.00 34.50 8 PIPERS GAP - VA D 138.00 34.00 9 PIPERS GAP - VA D 138.00 36.20 10 PLANT ROAD - WV D 69.00 12.00 11 PLANTATION PIPELINE - VA D 34.50 7.50 12 POAGES MILL - VA D 138.00 13.09 13 POINT PLEASANT - WV D 69.00 14 POLEYARD - WV D 138.00 13.09 15 POPLAR FORK - WV D 138.00 13.09 16 POPLAR GAP - WV D 46.00 7.20 17 POUND - VA D 69.00 12.00 18 POUND - VA D 69.00 34.50 19 POWELLTON - WV D 46.00 7.20 20 PRICES FORK - VA D 69.00 12.00 21 PRICES FORK - VA D 22 PRICES FORK - VA D 69.00 13.09 23 PRINCE - WV D 69.00 13.09 24 PRINCETON - WV D 34.50 12.00 25 PROGRESS PARK - VA D 138.00 34.50 26 PROGRESS PARK - VA D 138.00 27 PROGRESS PARK - VA D 138.00 36.20 28 PUTNAM VILLAGE - WV D 69.00 13.09 29 RADFORD - VA D 34.50 30 RAGLAND - WV D 138.00 34.50 31 RAVENSWOOD - WV D 69.00 32 RAVENSWOOD - WV D 69.00 13.09 33 RED HILL - VA D 138.00 13.09 34 RENSFORD - WV D 138.00 34.50 35 REUSENS - VA T 138.00 36 REUSENS - VA T 138.00 69.00 13.09 37 REUSENS - VA T 138.00 34.50 38 REUSENS - VA T 69.00 39 RICH ACRES - VA D 69.00 34.50 40 RICH CREEK - WV D 46.00 12.00
FERC FORM NO. 1 (ED. 12-96) Page 426.14 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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 VOLTAGE (In MVa) Name and Location of Substation Character of Substation No. Primary Secondary Tertiary (a) (b) (c) (d) (e) 1 RICHLANDS - VA T 138.00 69.00 13.10 2 RICHLANDS - VA T 138.00 69.00 13.09 3 RIDGEWAY - VA T 138.00 69.00 4.00 4 RIDGEWAY - VA T 138.00 13.09 5 RIDGEWAY - VA T 138.00 6 RIDGEWAY - VA T 138.00 34.50 7 RIDGEWAY - VA T 138.00 69.00 7.20 8 RIGIS - VA T 138.00 69.00 12.00 9 RIPLEY - WV D 138.00 69.00 13.09 10 RIPLEY - WV D 69.00 13.09 11 RIPLEY - WV D 69.00 12 RIPLEY - WV D 69.00 34.50 13 RIVERBEND - VA D 69.00 14 RIVERBEND - VA D 69.00 12.00 15 RIVERBEND - VA D 69.00 12.00 16 RIVERMONT - VA D 69.00 12.00 17 RIVERVILLE - VA D 138.00 18 RIVERVILLE - VA D 138.00 13.09 19 ROANOKE (AP) - VA T 138.00 69.00 12.00 20 ROANOKE (AP) - VA T 138.00 34.50 21 ROANOKE (AP) - VA T 138.00 22 ROANOKE (AP) - VA T 34.50 23 ROANOKE (AP) - VA T 138.00 13.09 24 ROANOKE ELECTRIC STEEL - VA D 138.00 34.50 25 ROANOKE ELECTRIC STEEL - VA D 34.50 26 ROANOKE ELECTRIC STEEL - VA D 138.00 34.50 27 ROBINSON - WV D 69.00 12.00 28 ROBINSON - WV D 69.00 29 RONDA - WV D 46.00 12.00 30 RONDA - WV D 46.00 31 RURAL RETREAT - VA D 138.00 34.50 32 RUSTBURG - VA D 138.00 13.09 33 RUTH - WV D 138.00 13.09 34 SALTVILLE - VA T 138.00 69.00 34.50 35 SALTVILLE - VA T 138.00 13.09 36 SALTVILLE - VA T 138.00 34.50 37 SCARBRO - WV T 46.00 38 SCHUYLER - VA D 46.00 7.20 39 SCHUYLER - VA D 46.00 7.20 40 SCOTTSVILLE (AP) - VA T 46.00 12.00
FERC FORM NO. 1 (ED. 12-96) Page 426.15 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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 VOLTAGE (In MVa) Name and Location of Substation Character of Substation No. Primary Secondary Tertiary (a) (b) (c) (d) (e) 1 SCOTTSVILLE (AP) - VA T 138.00 46.00 2 SCOTTSVILLE (AP) - VA T 46.00 3 SCOTTSVILLE (AP) - VA T 46.00 13.09 4 SEVENTH STREET - VA D 69.00 5 SEVENTH STREET - VA D 69.00 12.00 6 SHABDUE - WV T 46.00 7 SHARPLES - WV D 46.00 12.00 8 SHARPLES - WV D 46.00 9 SHAWSVILLE - VA D 138.00 13.09 10 SHEFFIELD (AP) - VA D 138.00 34.50 11 SHERIDAN (AP) - WV D 69.00 12.00 12 SHERWILL - VA D 69.00 12.00 13 SHIPMAN - VA D 46.00 12.00 14 SISSON - WV D 138.00 34.50 15 SKEGGS BRANCH - VA T 138.00 69.00 4.00 16 SKIMMER - VA D 69.00 12.00 17 SKIMMER - VA D 115.00 69.00 18 SKIMMER - VA D 69.00 19 SKIN FORK - WV D 46.00 20 SKIN FORK - WV D 46.00 12.00 21 SLAB FORK - WV D 46.00 7.20 22 SLATE CREEK - VA D 69.00 13.09 23 SMITH LANE - VA D 34.50 12.00 24 SMYTH - VA D 138.00 34.50 25 SMYTH - VA D 138.00 36.20 26 SOLITE - VA D 69.00 12.00 27 SOPHIA - WV T 46.00 28 SOURWOOD - WV D 138.00 13.09 29 SOUTH BLUEFIELD - WV T 138.00 13.09 30 SOUTH BUFFALO - WV D 138.00 13.09 31 SOUTH BUFFALO - WV D 138.00 36.20 32 SOUTH CHARLESTON - WV D 46.00 12.00 33 SOUTH CHRISTIANSBURG - VA T 138.00 69.00 12.00 34 SOUTH CHRISTIANSBURG - VA T 138.00 13.09 35 SOUTH HILLS - WV D 46.00 13.09 36 SOUTH HILLS - WV D 46.00 12.00 37 SOUTH LYNCHBURG - VA T 138.00 13.09 38 SOUTH LYNCHBURG - VA T 138.00 69.00 34.50 39 SOUTH NEAL - WV D 69.00 40 SOUTH NEAL - WV D 69.00 12.00
FERC FORM NO. 1 (ED. 12-96) Page 426.16 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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 VOLTAGE (In MVa) Name and Location of Substation Character of Substation No. Primary Secondary Tertiary (a) (b) (c) (d) (e) 1 SOUTH PRINCETON - WV D 138.00 34.50 2 SOUTHRIDGE - WV D 138.00 13.09 3 SPEEDWAY - WV D 138.00 34.50 4 SPORN 138KV - WV T 138.00 13.09 5 SPORN 345KV - WV T 345.00 137.50 13.80 6 SPRIGG - WV T 138.00 13.20 12.00 7 SPRIGG - WV T 138.00 34.50 8 SPRIGG - WV T 138.00 9 SPRIGG - WV T 138.00 69.00 46.00 10 SPRIGG - WV T 46.00 11 SPRING CREEK - VA D 138.00 13.09 12 ST. ALBANS - WV D 138.00 13.09 13 STANLEYTOWN - VA D 69.00 12.00 14 STARKEY - VA D 138.00 13.09 15 STOCKTON - VA D 138.00 34.50 16 STONE BRANCH - WV D 138.00 34.50 17 STONE BRANCH - WV D 138.00 13.09 18 STOTESBURY - WV D 138.00 13.09 19 STUART - VA D 69.00 34.50 20 STUART - VA D 69.00 21 STUART - VA D 69.00 12.00 22 SUN MINE - WV D 46.00 12.00 23 SUNDIAL - WV T 138.00 69.00 46.00 24 SUNDIAL - WV T 46.00 25 SUNSCAPE - VA D 138.00 12.00 26 SWITCHBACK - WV T 138.00 34.50 27 SWITCHBACK - WV T 138.00 28 TACKETT CREEK - WV D 138.00 13.09 29 TANK HILL - VA D 138.00 13.09 30 TAZEWELL - VA T 34.50 13.00 31 TAZEWELL - VA T 138.00 34.50 32 TAZEWELL - VA T 34.50 12.00 33 TAZEWELL - VA T 138.00 34 TEAYS - WV D 69.00 12.00 35 TECH DRIVE - VA D 138.00 12.00 36 THOMAS (AP) - VA D 34.50 7.20 37 THORNTON - VA D 138.00 34.50 12.00 38 THORNTON - VA D 138.00 13.09 39 TOMS FORK - WV D 46.00 12.00 40 TOMS FORK - WV D 46.00
FERC FORM NO. 1 (ED. 12-96) Page 426.17 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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 VOLTAGE (In MVa) Name and Location of Substation Character of Substation No. Primary Secondary Tertiary (a) (b) (c) (d) (e) 1 TONEY FORK - WV D 46.00 12.00 2 TOWER 117 - WV T 69.00 3 TRAIL FORK - WV D 138.00 13.09 4 TRAMMEL - VA T 69.00 12.00 5 TRAP HILL - WV D 46.00 36.20 6 TRI-STATE - WV T 345.00 137.50 13.80 7 TRI-STATE - WV T 345.00 138.00 13.80 8 TULTEX - VA D 34.50 7.50 9 TULTEX - VA D 34.50 7.20 10 TURKEY PEN - VA D 69.00 12.00 11 TURNER - WV T 46.00 13.09 12 TURNER - WV T 138.00 70.50 46.00 13 TURNER - WV T 69.00 12.00 14 TURNER - WV T 138.00 13.09 15 TURNER - WV T 138.00 69.00 11.00 16 TURNER - WV T 138.00 69.00 46.00 17 TURNER - WV T 46.00 4.00 18 TURNER - WV T 138.00 13.09 19 TWENTY FOURTH STREET - WV D 34.50 4.00 20 UNITED FUEL GAS COMPANY - WV D 69.00 4.00 21 UPPER BRANCH - WV D 46.00 7.20 22 URY - WV D 46.00 12.00 23 VAN - WV D 69.00 12.00 24 VETERANS HOSPITAL - VA D 34.50 4.00 25 VICKER - VA D 138.00 13.09 26 VINTON - VA D 138.00 13.09 27 VINTON - VA D 138.00 34.50 28 WALNUT AVENUE - VA D 69.00 12.00 29 WALTON PARK - VA D 69.00 2.40 30 WARD HOLLOW - WV T 46.00 12.00 31 WARD HOLLOW - WV T 46.00 32 WASENA - VA D 69.00 12.00 33 WASENA - VA D 69.00 13.09 34 WAYNE - WV D 34.50 12.00 35 WAYNE - WV D 34.50 13.09 36 WELCH - WV D 138.00 13.09 37 WEST BASSETT - VA T 138.00 69.00 34.50 38 WEST BASSETT - VA T 69.00 39 WEST BASSETT - VA T 34.50 34.50 40 WEST HUNTINGTON - WV T 138.00 69.00 34.50
FERC FORM NO. 1 (ED. 12-96) Page 426.18 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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 VOLTAGE (In MVa) Name and Location of Substation Character of Substation No. Primary Secondary Tertiary (a) (b) (c) (d) (e) 1 WEST HUNTINGTON - WV T 34.50 2 WEST HUNTINGTON - WV T 138.00 13.09 3 WEST HUNTINGTON - WV T 138.00 34.50 4 WEST SALEM - VA D 138.00 13.09 5 WESTLAKE - VA D 138.00 34.50 6 WHARNCLIFFE - WV T 46.00 7 WHEATLAND - VA D 69.00 12.00 8 WHETSTONE BRANCH - VA T 69.00 9 WHITESTICK - WV D 46.00 12.00 10 WILLIS GAP - VA D 138.00 34.50 11 WITT - VA D 69.00 4.36 12 WOOLWINE - VA D 69.00 34.50 13 WURNO - VA D 138.00 34.50 14 WURNO - VA D 138.00 34.50 15 WURNO - VA D 138.00 16 WYOMING - WV T 765.00 138.00 12.00 17 WYOMING - WV T 138.00 18 WYOMING - WV T 765.00 138.00 13.80 19 WYOMING - WV T 765.00 20 WYTHE - VA T 138.00 21 WYTHE - VA T 138.00 34.50 22 WYTHE - VA T 138.00 69.00 34.50 23 WYTHE - VA T 138.00 34.00 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40
FERC FORM NO. 1 (ED. 12-96) Page 426.19 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line Transformers Spare (In Service) (In MVa) In Service Transformers Type of Equipment Number of Units Total Capacity No. (In MVa) (f) (g) (h) (i) (j) (k) 22 1 1 STATCAP 1 10 2 22 1 3 90 1 4 50 2 5 8 1 6 9 1 7 6 1 8 9 1 9 36 3 10 72 6 11 2 3 12 STATCAP 1 10 13 25 1 14 1 3 15 STATCAP 2 173 16 1350 2 17 2 2 18 750 3 19 1500 3 20 130 1 21 1 22 56 1 23 11 1 24 11 1 25 12 1 26 30 1 27 11 1 28 9 1 29 1 30 750 3 31 AIR CORE REACTOR 3 32 REACTOR 4 400 33 6 1 34 STATCAP 2 126 35 STATCAP 1 10 36 90 1 37 3 1 38 75 1 39 STATCAP 2 32 40
FERC FORM NO. 1 (ED. 12-96) Page 427 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line Transformers Spare (In Service) (In MVa) In Service Transformers Type of Equipment Number of Units Total Capacity No. (In MVa) (f) (g) (h) (i) (j) (k) 25 1 1 67 1 2 20 1 3 20 1 4 20 1 5 25 1 6 4 3 7 6 3 8 8 1 9 54 1 10 STATCAP 1 10 11 9 1 12 STATCAP 1 12 13 6 1 14 40 2 15 5 3 16 20 1 17 11 1 18 30 1 19 3 1 20 11 1 21 8 1 22 STATCAP 1 10 23 5 1 24 84 1 25 STATCAP 1 13 26 STATCAP 1 14 27 20 1 28 STATCAP 1 10 29 STATCAP 1 53 30 8 1 31 30 1 32 STATCAP 1 14 33 3 34 11 2 35 45 2 36 129 1 37 STATCAP 1 10 38 30 1 39 STATCAP 1 10 40
FERC FORM NO. 1 (ED. 12-96) Page 427.1 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line Transformers Spare (In Service) (In MVa) In Service Transformers Type of Equipment Number of Units Total Capacity No. (In MVa) (f) (g) (h) (i) (j) (k) 5 1 1 20 1 2 20 1 3 3 3 4 20 1 5 130 1 6 STATCAP 1 50 7 8 1 8 3 3 9 45 2 10 AIR CORE REACTOR 2 11 672 3 12 REACTOR 3 300 13 1500 3 14 9 1 15 22 1 16 6 1 17 60 2 18 30 1 19 30 1 20 1 1 21 STATCAP 1 13 22 30 1 23 30 1 24 75 1 25 75 1 26 22 1 27 25 1 28 45 2 29 STATCAP 1 10 30 STATCAP 1 10 31 30 1 32 22 1 33 45 1 34 90 1 35 20 1 36 STATCAP 1 18 37 129 1 38 11 1 39 20 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.2 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line Transformers Spare (In Service) (In MVa) In Service Transformers Type of Equipment Number of Units Total Capacity No. (In MVa) (f) (g) (h) (i) (j) (k) 60 3 1 30 1 2 STATCAP 1 65 3 STATCAP 1 16 4 1 5 42 2 6 5 1 7 11 1 8 84 1 9 STATCAP 1 20 10 4 1 11 6 1 12 11 1 13 30 3 14 84 1 15 290 3 16 22 1 17 STATCAP 2 52 18 20 1 19 30 1 20 40 2 21 90 1 22 20 1 23 8 1 24 40 2 25 STATCAP 1 58 26 42 2 27 25 1 28 125 1 29 20 1 30 50 1 31 STATCAP 1 4 32 20 1 33 9 1 34 STATCAP 1 13 35 96 4 36 90 1 37 STATCAP 1 14 38 20 1 39 STATCAP 1 10 40
FERC FORM NO. 1 (ED. 12-96) Page 427.3 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line Transformers Spare (In Service) (In MVa) In Service Transformers Type of Equipment Number of Units Total Capacity No. (In MVa) (f) (g) (h) (i) (j) (k) 450 1 1 200 1 2 448 1 3 675 1 4 30 1 5 20 1 6 1950 3 7 15 1 8 20 1 9 20 1 10 84 1 11 20 1 12 2 1 13 13 1 14 90 1 15 54 1 16 78 1 17 54 1 18 54 1 19 78 1 20 54 1 21 54 1 22 78 1 23 54 1 24 54 1 25 78 1 26 54 1 27 54 1 28 78 1 29 54 1 30 54 1 31 78 1 32 54 1 33 54 1 34 78 1 35 54 1 36 54 1 37 78 1 38 54 1 39 54 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.4 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line Transformers Spare (In Service) (In MVa) In Service Transformers Type of Equipment Number of Units Total Capacity No. (In MVa) (f) (g) (h) (i) (j) (k) 78 1 1 54 1 2 9 1 3 20 1 4 20 1 5 78 1 6 78 1 7 78 1 8 78 1 9 78 1 10 78 1 11 78 1 12 78 1 13 500 1 14 15 1 15 500 1 16 15 1 17 5 1 18 11 1 19 8 1 20 9 1 21 8 1 22 9 1 23 5400 32 24 REACTOR 5 500 25 3500 7 26 10 1 27 2 2 28 20 1 29 22 1 30 8 1 31 STATCAP 1 8 32 6 1 33 20 1 34 4 1 35 20 1 36 22 1 37 STATCAP 1 10 38 20 1 39 20 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.5 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line Transformers Spare (In Service) (In MVa) In Service Transformers Type of Equipment Number of Units Total Capacity No. (In MVa) (f) (g) (h) (i) (j) (k) 20 1 1 129 1 2 20 1 3 STATCAP 1 10 4 1 2 5 1 6 1 1 7 115 1 8 46 1 9 22 1 10 90 1 11 30 1 12 STATCAP 1 14 13 20 1 14 25 1 15 9 1 16 30 1 17 11 1 18 STATCAP 1 14 19 3 1 20 2 3 21 19 3 22 20 1 23 4 1 24 STATCAP 1 14 25 60 1 26 8 1 27 1500 2 28 STATCAP 1 53 29 30 1 30 9 1 31 90 1 32 196 1 33 STATCAP 1 58 34 STATCAP 1 53 35 9 1 36 22 1 37 2 3 38 4 1 39 30 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.6 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line Transformers Spare (In Service) (In MVa) In Service Transformers Type of Equipment Number of Units Total Capacity No. (In MVa) (f) (g) (h) (i) (j) (k) 30 1 1 8 1 2 20 1 3 STATCAP 1 10 4 5 1 5 5 1 6 42 2 7 STATCAP 1 11 8 9 1 9 AIR CORE REACTOR 3 10 STATCAP 1 6 11 20 1 12 STATCAP 1 26 13 STATCAP 2 101 14 78 1 15 9 2 16 STATCAP 1 7 17 20 1 18 30 1 19 22 1 20 11 1 21 11 1 22 56 1 23 9 1 24 42 2 25 22 1 26 30 1 27 6 1 28 208 2 29 STATCAP 1 14 30 10 2 31 25 1 32 9 1 33 30 1 34 45 2 35 STATCAP 2 26 36 5 1 37 22 1 38 84 1 39 STATCAP 1 50 40
FERC FORM NO. 1 (ED. 12-96) Page 427.7 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line Transformers Spare (In Service) (In MVa) In Service Transformers Type of Equipment Number of Units Total Capacity No. (In MVa) (f) (g) (h) (i) (j) (k) 22 1 1 8 1 2 STATCAP 1 10 3 20 1 4 STATCAP 1 10 5 30 1 6 11 1 7 9 1 8 STATCAP 4 204 9 84 1 10 19 3 11 6 1 12 9 1 13 2 14 1 15 1 16 4 1 17 22 1 18 7 6 19 20 1 20 40 2 21 25 1 22 STATCAP 1 29 23 25 1 24 STATCAP 1 13 25 11 1 26 25 1 27 STATCAP 1 14 28 84 1 29 STATCAP 1 50 30 1 31 4 1 32 5 3 33 STATCAP 1 12 34 15 1 35 STATCAP 1 50 36 45 3 37 129 1 38 11 1 39 25 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.8 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line Transformers Spare (In Service) (In MVa) In Service Transformers Type of Equipment Number of Units Total Capacity No. (In MVa) (f) (g) (h) (i) (j) (k) 20 1 1 5 3 2 15 1 3 13 1 4 STATCAP 1 5 5 30 1 6 20 1 7 4 1 8 11 1 9 20 1 10 3 1 11 40 1 12 STATCAP 1 13 13 8 1 14 25 1 15 22 1 16 7 2 17 STATCAP 1 43 18 20 1 19 20 1 20 AIR CORE REACTOR 4 21 56 1 22 2 3 23 20 1 24 STATCAP 1 10 25 20 1 26 130 1 27 STATCAP 1 29 28 2 3 29 75 1 30 20 1 31 175 1 32 STATCAP 1 29 33 STATCAP 1 65 34 22 1 35 STATCAP 1 22 36 25 1 37 11 1 38 20 1 39 20 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.9 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line Transformers Spare (In Service) (In MVa) In Service Transformers Type of Equipment Number of Units Total Capacity No. (In MVa) (f) (g) (h) (i) (j) (k) 50 1 1 STATCAP 1 14 2 22 1 3 20 1 4 250 2 5 STATCAP 3 889 6 250 2 7 1 8 STATCAP 1 4 9 500 3 10 STATCAP 1 4 11 250 2 12 1750 8 13 5 1 14 9 1 15 10 1 16 129 1 17 25 1 18 750 3 19 STATCAP 1 43 20 84 1 21 22 1 22 STATCAP 1 16 23 1 24 20 1 25 30 1 26 9 1 27 200 1 28 150 1 29 4 1 30 STATCAP 1 14 31 1 1 32 1 2 33 84 1 34 6 1 35 20 1 36 22 1 37 30 1 38 20 1 39 90 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.10 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line Transformers Spare (In Service) (In MVa) In Service Transformers Type of Equipment Number of Units Total Capacity No. (In MVa) (f) (g) (h) (i) (j) (k) 20 1 1 5 3 2 30 1 3 3 1 4 22 1 5 10 1 6 8 1 7 11 1 8 6 1 9 20 1 10 22 1 11 STATCAP 2 115 12 22 1 13 90 1 14 11 1 15 3 1 16 20 1 17 4 1 18 11 1 19 7 1 20 11 1 21 90 3 22 54 1 23 129 1 24 25 1 25 STATCAP 2 148 26 672 1 27 675 1 28 8 1 29 13 1 30 30 1 31 STATCAP 1 10 32 8 1 33 20 1 34 56 1 35 22 1 36 78 1 37 STATCAP 1 27 38 128 1 39 30 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.11 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line Transformers Spare (In Service) (In MVa) In Service Transformers Type of Equipment Number of Units Total Capacity No. (In MVa) (f) (g) (h) (i) (j) (k) 5 1 1 20 1 2 12 2 3 4 1 4 2 3 5 9 1 6 90 1 7 25 1 8 25 2 9 30 1 10 20 1 11 25 1 12 25 2 13 20 1 14 30 1 15 20 1 16 11 1 17 22 1 18 200 1 19 84 1 20 STATCAP 1 14 21 4 1 22 STATCAP 1 16 23 56 1 24 8 1 25 20 1 26 4 1 27 STATCAP 1 13 28 30 1 29 20 1 30 22 1 31 22 1 32 22 1 33 STATCAP 1 50 34 25 1 35 30 1 36 5 1 37 30 1 38 30 1 39 3 40
FERC FORM NO. 1 (ED. 12-96) Page 427.12 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line Transformers Spare (In Service) (In MVa) In Service Transformers Type of Equipment Number of Units Total Capacity No. (In MVa) (f) (g) (h) (i) (j) (k) 750 3 1 8 1 2 STATCAP 1 4 3 7 1 4 22 1 5 25 1 6 30 1 7 20 1 8 30 1 9 25 1 10 129 1 11 22 1 12 200 1 13 84 1 14 20 1 15 22 1 16 20 1 17 17 2 18 STATCAP 2 106 19 6 1 20 20 1 21 STATCAP 1 10 22 20 1 23 5 3 24 22 1 25 20 1 26 30 1 27 20 2 28 216 4 29 20 2 30 30 1 31 20 1 32 20 1 33 130 1 34 6 1 35 90 1 36 5 1 37 30 1 38 20 1 39 30 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.13 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line Transformers Spare (In Service) (In MVa) In Service Transformers Type of Equipment Number of Units Total Capacity No. (In MVa) (f) (g) (h) (i) (j) (k) 11 1 1 1 3 2 60 2 3 13 1 4 3 1 5 13 1 6 9 1 7 30 1 8 30 1 9 22 1 10 5 3 11 20 1 12 STATCAP 1 10 13 25 1 14 20 1 15 5 3 16 6 1 17 25 1 18 2 3 19 22 1 20 STATCAP 1 21 25 1 22 5 1 23 20 2 24 30 1 25 STATCAP 1 58 26 30 1 27 20 1 28 STATCAP 1 11 29 25 1 30 STATCAP 1 14 31 25 1 32 8 1 33 25 1 34 STATCAP 1 58 35 130 1 36 60 2 37 STATCAP 1 14 38 30 1 39 11 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.14 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line Transformers Spare (In Service) (In MVa) In Service Transformers Type of Equipment Number of Units Total Capacity No. (In MVa) (f) (g) (h) (i) (j) (k) 130 1 1 78 1 2 40 1 3 9 1 4 REACTOR 48 3,230 5 25 1 6 35 1 7 115 1 8 78 1 9 13 1 10 STATCAP 1 10 11 25 1 12 STATCAP 1 14 13 9 1 14 7 1 15 20 1 16 STATCAP 1 32 17 104 3 18 130 1 19 30 1 20 STATCAP 2 122 21 STATCAP 1 7 22 20 1 23 197 2 24 STATCAP 4 279 25 17 1 26 10 1 27 STATCAP 1 13 28 4 1 29 STATCAP 1 7 30 25 1 31 20 1 32 20 1 33 56 1 34 11 1 35 20 1 36 STATCAP 1 10 37 2 3 38 1 1 39 5 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.15 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line Transformers Spare (In Service) (In MVa) In Service Transformers Type of Equipment Number of Units Total Capacity No. (In MVa) (f) (g) (h) (i) (j) (k) 40 3 1 STATCAP 1 4 2 9 1 3 STATCAP 1 14 4 70 3 5 STATCAP 1 10 6 5 1 7 STATCAP 1 10 8 11 1 9 30 1 10 22 1 11 20 1 12 5 1 13 30 1 14 30 1 15 30 1 16 112 2 17 STATCAP 1 26 18 STATCAP 1 10 19 8 1 20 1 3 21 20 1 22 6 1 23 25 1 24 30 1 25 5 1 26 STATCAP 1 14 27 8 1 28 30 1 29 60 3 30 30 1 31 22 1 32 56 1 33 20 1 34 25 1 35 22 1 36 40 2 37 50 1 38 STATCAP 1 14 39 40 2 40
FERC FORM NO. 1 (ED. 12-96) Page 427.16 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line Transformers Spare (In Service) (In MVa) In Service Transformers Type of Equipment Number of Units Total Capacity No. (In MVa) (f) (g) (h) (i) (j) (k) 55 2 1 20 1 2 30 1 3 20 1 4 1350 3 5 9 1 6 25 1 7 STATCAP 1 72 8 84 1 9 STATCAP 1 10 10 21 2 11 50 2 12 22 1 13 40 2 14 30 1 15 25 1 16 20 1 17 11 1 18 30 1 19 STATCAP 1 11 20 11 1 21 20 1 22 90 1 23 STATCAP 1 10 24 20 1 25 25 1 26 STATCAP 1 50 27 25 1 28 40 2 29 6 1 30 30 1 31 6 1 32 STATCAP 1 29 33 22 1 34 20 1 35 3 3 36 8 1 37 9 1 38 5 1 39 STATCAP 1 10 40
FERC FORM NO. 1 (ED. 12-96) Page 427.17 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line Transformers Spare (In Service) (In MVa) In Service Transformers Type of Equipment Number of Units Total Capacity No. (In MVa) (f) (g) (h) (i) (j) (k) 8 1 1 STATCAP 1 13 2 13 1 3 6 1 4 40 2 5 270 1 6 2 7 3 2 8 5 4 9 11 1 10 9 1 11 54 1 12 6 1 13 20 1 14 50 1 15 84 1 16 3 1 17 22 1 18 6 1 19 6 1 20 2 3 21 20 1 22 6 1 23 10 2 24 20 1 25 25 1 26 30 1 27 22 1 28 2 1 29 40 2 30 STATCAP 1 32 31 20 1 32 20 1 33 5 1 34 11 1 35 22 1 36 128 1 37 STATCAP 1 29 38 25 1 39 130 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.18 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) 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.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line Transformers Spare (In Service) (In MVa) In Service Transformers Type of Equipment Number of Units Total Capacity No. (In MVa) (f) (g) (h) (i) (j) (k) STATCAP 1 10 1 9 1 2 25 1 3 12 1 4 60 2 5 STATCAP 1 10 6 20 1 7 STATCAP 1 14 8 22 1 9 20 1 10 13 1 11 25 1 12 30 1 13 30 1 14 STATCAP 1 14 15 250 1 16 AIR CORE REACTOR 6 17 1250 5 18 REACTOR 3 300 19 STATCAP 1 50 20 35 1 21 84 1 22 25 1 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40
FERC FORM NO. 1 (ED. 12-96) Page 427.19 Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A 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. Name of Account Amount Line Associated/Affiliated Charged or 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 Administrative and General Expenses-Maintenance AEPSC 935 4,481,986 3 Audit Services AEPSC 920,923 1,319,810 4 Barging I&M 151 43,732,023 5 Civil & Political Activities and Other Svcs AEPSC 426 879,674 6 Construction Services AEPSC 107, 108 127,063,518 7 Construction Services KGPCo 107, 108 1,525,002 8 Construction Services KPCo 107, 108 271,137 9 Corporate Accounting AEPSC 920,923 4,962,423 10 Corporate Communications AEPSC 920,923 1,382,191 11 Corporate Planning & Budgeting AEPSC 920,923 2,067,942 12 Customer Accounts Expenses KGPCO 920,923 255,059 13 Customer Accounts Expenses AEPSC 901-903,905 15,507,538 14 Customer Service and Informational Expenses-Oper AEPSC 907-908, 910 375,737 15 Distribution Expenses-Maintenance AEPSC 590-598 1,407,044 16 Distribution Expenses-Maintenance KgPCo 590,593-598 543,048 17 Customer Support AEPSC 920,923 1,899,685 18 Distribution Expenses-Operation AEPSC Footnote 6,310,072 19 Distribution Expenses-Operation KgPCo 580,583-588 374,873 20 Non-power Goods or Services Provided for Affiliate 21 Building and Property Leases AEPSC 454 3,924,951 22 Leased Equipment I&M 417.1 5,015,866 23 Central Machine Shop I&M Footnote 3,237,451 24 Central Machine Shop KPCo Footnote 853,666 25 Central Machine Shop PSO Footnote 900,362 26 Central Machine Shop SWEPCo Footnote 459,996 27 Distribution Expenses-Maintenance KgPCo 593-595,597,598 355,117 28 Distribution Expenses-Maintenance KPCo 593,595,598 437,873 29 Distribution Expenses-Maintenance WPCo 593,595,598 428,538 30 Facility Rent WVTCo 454 2,783,515 31 Fleet and Vehicle Charges AEPSC Footnote 4,156,595 32 Materials and Supplies KPCo 154 453,029 33 Use of Jointly Owned Facility APTCo 454 615,265 34 Use of Jointly Owned Facility WVTCo 454 250,701 35 Urea KPCo 154 438,139 36 Other Operating Revenues OPCo 920,923 288,845 37 Construction Services KGPCo 107, 108 938,341 38 Construction Services KPCo 107, 108 464,457 39 Construction Services OPCO 107, 108 293,015 40 Construction Services WPCo 107, 108 304,064 41 Construction Services WVTCo 107 330,219 42 1 Non-power Goods or Services Provided by Affiliated 2 Environmental Services AEPSC 920,923 862,060
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) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A 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. Name of Account Amount Line Associated/Affiliated Charged or Charged or No. Description of the Non-Power Good or Service Company Credited Credited (a) (b) (c) (d) 3 Factored Customer A/R Bad Debts AEP Credit Inc. 426.5 4,380,105 4 Factored Customer A/R Expense AEP Credit Inc. 426.5 2,641,339 5 Fuel & Storeroom Services AEPSC 152,154,163 11,669,547 6 Human Resources AEPSC 920,923 3,144,169 7 Hydraulic Power Generation-Maintenance AEPSC 541-545 1,293,664 8 Hydraulic Power Generation-Operation AEPSC 535-540 4,092,951 9 Information Technology AEPSC 920,923 11,915,123 10 Legal GC/Administration AEPSC 920,923 7,411,265 11 Material and Supplies I&M Footnote 773,891 12 Material and Supplies KgPCo Footnote 369,042 13 Material and Supplies OPCO Footnote 6,162,806 14 Administrative and General Exp - Operaton AEPSC Footnote 6,984,097 15 Other Power Supply Expenses AEPSC 556,557 6,941,985 16 Real Estate & Workplace Svcs AEPSC 920,923 2,280,004 17 Regulatory Services AEPSC 920,923 2,143,422 18 Research and Other Services AEPSC 183,184,186,188 5,130,674 19 Corporate Safety & Health AEPSC 920,923 810,749 20 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 1 Non-power Goods or Services Provided by Affiliated 2 Steam Power Generation-Maintenance AEPSC 510-514 6,668,322 3 Steam Power Generation-Operation AEPSC 500-502,506 21,557,440 4 Transmission Expenses-Maintenance AEPSC 568-573 5,335,545
FERC FORM NO. 1 (New) Page 429.1 FERC FORM NO. 1-F (New) Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A 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. Name of Account Amount Line Associated/Affiliated Charged or Charged or No. Description of the Non-Power Good or Service Company Credited Credited (a) (b) (c) (d) 5 Transmission Expenses-Operation AEPSC Footnote 23,613,635 6 Urea KPCo 154 322,188 7 Utility Operations AEPSC 920,923 804,451 8 O&M Services for Jointly Owned Facility - Sporn AEP Generating Resources Footnote 570,815 9 Treasury & Risk AEPSC 920,923 3,109,356 10 Strategy & transformation AEPSC 920,923 945,342 11 Other Operating Revenues I&M 456 269,731 12 Other Operating Revenues OPCo 456 840,303 13 Other Operating Revenues PSO 456 306,466 14 15 16 17 18 19 20 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 1 Non-power Goods or Services Provided by Affiliated 2 3 4 5 6
FERC FORM NO. 1 (New) Page 429.2 FERC FORM NO. 1-F (New) Name of Respondent This Report Is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company End of 2020/Q4 (2) A 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. Name of Account Amount Line Associated/Affiliated Charged or Charged or No. Description of the Non-Power Good or Service Company Credited Credited (a) (b) (c) (d) 7 8 9 10 11 12 13 14 15 16 17 18 19 20 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 429.3 FERC FORM NO. 1-F (New) Name of Respondent This Report is: Date of Report Year/Period of Report (1) X An Original (Mo, Da, Yr) Appalachian Power Company (2) A Resubmission / / 2020/Q4 FOOTNOTE DATA
Schedule Page: 429 Line No.: 2 Column: b Certain managerial and professional services provided by AEPSC are allocated among multiple affiliates. The costs of the services are billed on a direct-charge basis, whenever possible. Costs incurred to perform services that benefit more than one company are allocated to the benefiting companies using one of 80 FERC accepted allocation factors. The allocation factors used to bill for services performed by AEPSC are based upon formulae that consider factors such as number of customers, number of employees, number of transmission pole miles, number of invoices and other factors. The data upon which these formulae are based is updated monthly, quarterly, semi-annually or annually, depending on the particular factor and its volatility. The billings for services are made at cost and include no compensation for a return on investment. Schedule Page: 429 Line No.: 18 Column: c 580, 582-584,586,588 Schedule Page: 429 Line No.: 23 Column: c 107,108,163,500,506,512-513,524,530,531,532,544,920 Schedule Page: 429 Line No.: 24 Column: c 107,108,500,506,512,513,514,920 Schedule Page: 429 Line No.: 25 Column: c 107,108,512,513,514,531,920 Schedule Page: 429 Line No.: 26 Column: c 107,108,502,512-513,920 Schedule Page: 429 Line No.: 31 Column: c Costs related to AEP's fleet vehicles are allocated in the same manner as the labor of each department utilizing the vehicles. To the extent a department provides service to another affiliate company, an applicable share of their fleet costs are also assigned to that affiliate company. Schedule Page: 429.1 Line No.: 11 Column: c 107,108,506,512,513,514,570,571,592,935 Schedule Page: 429.1 Line No.: 12 Column: c 107,163,184,593,594,903,921 Schedule Page: 429.1 Line No.: 13 Column: c 107,108,184,186,502,560,562,566,570,571,592,593,930,935 Schedule Page: 429.1 Line No.: 14 Column: c 920,921,923,925,926,928,930,931 Schedule Page: 429.2 Line No.: 5 Column: c 560,561,562,563,564,566,567,920,923 Schedule Page: 429.2 Line No.: 8 Column: c 108,186,408,500,506,920,921,923,925,926,931
FERC 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 Earnings ...... 118-119 Associated Companies advances from ...... 256-257 corporations controlled by respondent ...... 103 control over respondent ...... 102 interest on debt to ...... 256-257 Attestation ...... i Balance sheet comparative ...... 110-113 notes to ...... 122-123 Bonds ...... 256-257 Capital Stock ...... 251 expense ...... 254 premiums ...... 252 reacquired ...... 251 subscribed ...... 252 Cash flows, statement of ...... 120-121 Changes important during year ...... 108-109 Construction work in progress - common utility plant ...... 356 work in progress - electric ...... 216 work in progress - other utility departments ...... 200-201 Control corporations controlled by respondent ...... 103 over respondent ...... 102 Corporation controlled by ...... 103 incorporated ...... 101 CPA, background information on ...... 101 CPA Certification, this report form ...... i-ii
FERC FORM NO. 1 (ED. 12-93) Index 1 INDEX (continued)
Schedule Page No. Deferred credits, other ...... 269 debits, miscellaneous ...... 233 income taxes accumulated - accelerated amortization property ...... 272-273 income taxes accumulated - other property ...... 274-275 income taxes accumulated - other ...... 276-277 income taxes accumulated - pollution control facilities ...... 234 Definitions, this report form ...... iii Depreciation and amortization of common utility plant ...... 356 of electric plant ...... 219 336-337 Directors ...... 105 Discount - premium on long-term debt ...... 256-257 Distribution of salaries and wages ...... 354-355 Dividend appropriations ...... 118-119 Earnings, Retained ...... 118-119 Electric energy account ...... 401 Expenses electric operation and maintenance ...... 320-323 electric operation and maintenance, summary ...... 323 unamortized debt ...... 256 Extraordinary property losses ...... 230 Filing requirements, this report form General information ...... 101 Instructions for filing the FERC Form 1 ...... i-iv Generating plant statistics hydroelectric (large) ...... 406-407 pumped storage (large) ...... 408-409 small plants ...... 410-411 steam-electric (large) ...... 402-403 Hydro-electric generating plant statistics ...... 406-407 Identification ...... 101 Important changes during year ...... 108-109 Income statement of, by departments ...... 114-117 statement of, for the year (see also revenues) ...... 114-117 deductions, miscellaneous amortization ...... 340 deductions, other income deduction ...... 340 deductions, other interest charges ...... 340 Incorporation information ...... 101
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 nonutility property ...... 221 subsidiary companies ...... 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 Materials and supplies ...... 227 Miscellaneous general expenses ...... 335 Notes to balance sheet ...... 122-123 to statement of changes in financial position ...... 122-123 to statement of income ...... 122-123 to statement of retained earnings ...... 122-123 Nonutility property ...... 221 Nuclear fuel materials ...... 202-203 Nuclear generating plant, statistics ...... 402-403 Officers and officers' salaries ...... 104 Operating expenses-electric ...... 320-323 expenses-electric (summary) ...... 323 Other paid-in capital ...... 253 donations received from stockholders ...... 253 gains on resale or cancellation of reacquired capital stock ...... 253 miscellaneous paid-in capital ...... 253 reduction in par or stated value of capital stock ...... 253 regulatory assets ...... 232 regulatory liabilities ...... 278 Peaks, monthly, and output ...... 401 Plant, Common utility accumulated provision for depreciation ...... 356 acquisition adjustments ...... 356 allocated to utility departments ...... 356 completed construction not classified ...... 356 construction work in progress ...... 356 expenses ...... 356 held for future use ...... 356 in service ...... 356 leased to others ...... 356 Plant data ...... 336-337 401-429
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 capital stock ...... 250 Reacquired long-term debt ...... 256-257 Receivers' certificates ...... 256-257 Reconciliation of reported net income with taxable income from Federal income taxes ...... 261 Regulatory commission expenses deferred ...... 233 Regulatory commission 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 Salaries and wages directors fees ...... 105 distribution of ...... 354-355 officers' ...... 104 Sales of electricity by rate schedules ...... 304 Sales - for resale ...... 310-311 Salvage - nuclear fuel ...... 202-203 Schedules, this report form ...... 2-4 Securities exchange registration ...... 250-251 Statement of Cash Flows ...... 120-121 Statement of income for the year ...... 114-117 Statement of retained earnings for the year ...... 118-119 Steam-electric generating plant statistics ...... 402-403 Substations ...... 426 Supplies - materials and ...... 227
FERC FORM NO. 1 (ED. 12-90) Index 4 INDEX (continued)
Schedule Page No. Taxes accrued and prepaid ...... 262-263 charged during year ...... 262-263 on income, deferred and accumulated ...... 234 272-277 reconciliation of net income with taxable income for ...... 261 Transformers, line - electric ...... 429 Transmission lines added during year ...... 424-425 lines statistics ...... 422-423 of electricity for others ...... 328-330 of electricity by others ...... 332 Unamortized debt discount ...... 256-257 debt expense ...... 256-257 premium on debt ...... 256-257 Unrecovered Plant and Regulatory Study Costs ...... 230
FERC FORM NO. 1 (ED. 12-90) Index 5