FERC Form

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

NOTES TO FINANCIAL STATEMENTS

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.
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.
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.
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.
Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such restrictions.
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.
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.
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.
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.

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.Benefit Plans

8.Business Segments

9.Derivatives and Hedging

10.Fair Value Measurements

11.Income Taxes

12.Leases

13.Financing Activities

14.Related Party Transactions

15.Property, Plant and Equipment

16.Revenue from Contracts with Customers

17.FERC Order NO. 784-A

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.
AEPTCo						AEP Transmission Company, LLC, a wholly-owned subsidiary of AEP Transmission Holdco, is an intermediate holding company that owns the State Transcos.
AFUDC						Allowance for Equity Funds Used During Construction.
AMI						Advanced Metering Infrastructure.
AMR						Automated Meter Reading.
AOCI						Accumulated Other Comprehensive Income.
APCo						Appalachian Power Company, an AEP electric utility subsidiary.
ARAM						Average Rate Assumption Method, an IRS approved method used to calculate the reversal of Excess ADIT for rate-making purposes.
ARO						Asset Retirement Obligations.
CARES Act						Coronavirus Aid, Relief, and Economic Security Act signed into law in March 2020.
CCR						Coal Combustion Residual.


COVID-19						Coronavirus 2019, a highly infectious respiratory disease. In March 2020, the World Health Organization declared COVID-19 a worldwide pandemic.
CWIP						Construction Work in Progress.
EIS						Energy Insurance Services, Inc., a nonaffiliated captive insurance company.
ELG						Effluent Limitation Guidelines.
ENEC						Expanded Net Energy Cost.
ESP						Electric Security Plans, a PUCO requirement for electric utilities to adjust their rates by filing with the PUCO.
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.
MWh						Megawatt-hour.
NOL						Net operating losses.
NOx						Nitrogen oxide.
OATT						Open Access Transmission Tariff.
OPCo						Ohio Power Company, an AEP electric utility subsidiary.
OPEB						Other Postretirement Benefits.
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.
PTC						Production Tax Credits.
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.
SPP						Southwest Power Pool regional transmission organization.
SSO						Standard service offer.
SWEPCo						Southwestern Electric Power Company, an AEP electric utility subsidiary.
TA						Transmission Agreement, effective November 2010, among APCo, I&M, KGPCo, KPCo, OPCo and WPCo with AEPSC as agent.
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.
TCA						Transmission Coordination Agreement dated January 1, 1997, by and among, PSO, SWEPCo and AEPSC, in connection with the operation of the transmission assets of the two public utility subsidiaries.
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.

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 966,000 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 certain 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.

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 the 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, TA and TCA, 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 14- Related Party Transactions for additional information.

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.
·			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 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 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.
·			The classification of the amortization of certain regulatory assets as regulatory debits and credits rather than operating expenses.

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 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


		2021		2020
For the Years Ended December 31,		(in millions)
Cash was Paid (Received) for:
	Interest (Net of Capitalized Amounts)	$	207.5	$	207.1
	Income Taxes (Net of Refunds)		32.7		0.6
Noncash Acquisitions Under Finance Leases			1.7		7.2
As of December 31,
Construction Expenditures Included in Current and Accrued Liabilities			139.1		105.6

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 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 13 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.

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 CWIP 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.

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.

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.

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 reviewed 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 16 - 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.

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 a 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. Expenses from marketing and risk management activities that are not derivatives are also recognized upon delivery of the commodity.

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. Unrealized MTM gains and losses are included on APCo balance sheets as Derivative Instrument Assets or Liabilities, as appropriate, and on the statements of income in Operating Revenues. Realized gains and losses on marketing and risk management transactions are included in revenues or expenses based on the transaction’s facts and circumstances. However, in regulated jurisdictions subject to cost-based regulation, 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.

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.

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 7 - 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.

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	59	%
Fixed Income	40	%
Cash and Cash Equivalents	1	%

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 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, 2021 and 2020, the fair value of securities on loan as part of the program was $137 million and $177 million, respectively. Cash and securities obtained as collateral exceeded the fair value of the securities loaned as of December 31, 2021 and 2020.

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.

Subsequent Events

Management has evaluated the impact of events occurring after December 31, 2021 through February 24, 2022, the date that AEP’s Form 10-K was issued, and has updated such evaluation for disclosure purposes through April 14, 2022. These financial statements include all necessary adjustments and disclosures resulting from these evaluations.

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. There are no new standards expected to have a material impact on APCo’s financial statements.

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, 2021 and 2020. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 - Benefit Plans for additional information.




				Pension and OPEB
				Amortization		Changes in
		Cash Flow Hedge –		of Deferred		Funded
For the Year Ended December 31, 2021		Interest Rate		Costs		Status		Total
	(in millions)
Balance in AOCI as of December 31, 2020		$	(0.8)	$	5.4	$	2.6	$	7.2
Change in Fair Value Recognized in AOCI		9.2		—		13.1		22.3
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)
Reclassifications from AOCI, before Income Tax (Expense) Benefit		(1.1)		(5.3)		—		(6.4)
Income Tax (Expense) Benefit		(0.2)		(1.1)		—		(1.3)
Reclassifications from AOCI, Net of Income Tax (Expense) Benefit		(0.9)		(4.2)		—		(5.1)
Net Current Period Other Comprehensive Income (Loss)		8.3		(4.2)		13.1		17.2
Balance in AOCI as of December 31, 2021		$	7.5	$	1.2	$	15.7	$	24.4


			Pension and OPEB
			Amortization		Changes in
	Cash Flow Hedges -		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

(a)Amounts reclassified to the referenced line item on the statements of income.

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.

2017-2019 Virginia Triennial Review

In November 2020, the Virginia SCC issued an order on APCo’s 2017-2019 Triennial Review filing 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).

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 clarify 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.

In March 2021, an intervenor filed its assignments of error with the Virginia Supreme Court related to the appeal of the November 2020 order in which it stated the Virginia SCC erred: (a) in determining that Virginia law did not apply to its determination to permit amortization for recovery of costs associated with retired coal-fired generation assets, (b) in establishing a new regulatory asset for a cost incurred outside of the triennial review period due to its failure to apply a threshold earnings test before approving deferred cost recovery and (c) in misapplying the requirement that APCo bear the burden of demonstrating that power purchases made by APCo from its affiliate, OVEC, were priced at the lower of OVEC’s cost or the market price for nonaffiliated power.

In March 2021, APCo filed its assignments of error with the Virginia Supreme Court related to its appeal of the November 2020 order in which it stated the Virginia SCC erred: (a) in finding that costs associated with asset impairments related to early retirement determinations made by APCo for certain generation facilities should not be attributed to the test periods under review and deemed fully recovered in the period recorded, (b) in finding that it was permitted to evaluate the reasonableness of APCo’s decision to record, per books for financial reporting purposes, asset impairments related to early retirement determinations for certain generation facilities, (c) as a result of the errors described in (a) and (b), in denying APCo an increase in rates, (d) in failing to review and make any findings regarding whether APCo’s rates would allow it to earn a fair rate of return going forward, (e) in denying APCo an increase in base rates by failing to ensure that APCo has an opportunity to recover its costs and earn a fair rate of return, thereby resulting in a taking of private property for public use without just compensation and (f) in retroactively adjusting APCo’s depreciation expense for purposes of calculating APCo’s earnings for the 2017-2019 triennial period.

In March 2021, the Virginia SCC issued an order confirming certain of its decisions from the November 2020 order and rejecting the various requests for reconsideration from APCo and an intervenor. In confirming its decision to reject an intervenor’s recommendation that APCo’s AMI costs incurred during the triennial period be disallowed,

the Virginia SCC clarified that APCo established the need to replace its existing AMR meters, and that based on the uncertainty surrounding the continued manufacturing and support of AMR technology, APCo reasonably chose to replace them with AMI meters. In March 2021, APCo filed a notice of appeal of the reconsideration order with the Virginia Supreme Court. In September 2021, APCo submitted its brief before the Virginia Supreme Court. The brief was in alignment with the assignments of error filed by APCo in March 2021. In October 2021, the Virginia SCC and additional intervenors filed briefs with the Virginia Supreme Court disagreeing with APCo’s assignments of error in its appeal of the Triennial Review decision. Additionally, the Virginia SCC and APCo filed briefs disagreeing with an intervenor’s assignments of error in a separate appeal of the same decision. Oral arguments are scheduled to be held at the Virginia Supreme Court in March 2022.

APCo ultimately seeks an increase in base rates through its appeal to the Virginia Supreme Court. Among other issues, this appeal includes APCo’s request for proper treatment of the closed coal-fired plant assets in APCo’s 2017-2019 triennial period, reducing APCo’s earnings below the bottom of its authorized ROE band. If APCo’s appeals regarding treatment of the closed coal plants are granted by the Virginia Supreme Court, it could initially reduce future net income and impact financial condition. A Virginia Supreme Court decision in favor of APCo’s original expensing of the closed coal-fired plant asset balances would likely result in a remand to the Virginia SCC. Upon a subsequent Virginia SCC order, the initial negative impact for the write-off of the closed coal-fired plant asset balances could potentially be offset by an increase in base rates for earning below APCo’s 2017-2019 authorized ROE band.

CCR/ELG Compliance Plan Filings

In December 2020, APCo submitted filings with the Virginia SCC and WVPSC requesting approvals necessary to implement CCR/ELG compliance plans at the Amos and Mountaineer Plants. Intervenors in Virginia and West Virginia recommended that only the CCR-related investments be constructed at Amos and Mountaineer and, as a consequence, that APCo close these generating facilities at the end of 2028.

In August 2021, the Virginia SCC issued an order approving APCo’s request to construct CCR-related investments at the Amos and Mountaineer Plants and approved recovery of CCR-related other operation and maintenance expenses and investments through an active rider. The order denied APCo’s request to construct the ELG investments and denied recovery of previously incurred ELG costs. APCo plans to refile for approval of the ELG investments and previously incurred ELG costs in the first quarter of 2022.

Also in August 2021, the WVPSC approved the request to construct CCR/ELG investments at the Amos and Mountaineer Plants and approved recovery of the West Virginia jurisdictional share of these costs through an active rider. In October 2021, due to the Virginia SCC previously rejecting the ELG investments, the WVPSC issued an order directing APCo to proceed with CCR/ELG compliance plans that would allow the plants to continue operating beyond 2028. The October order further states that APCo will not share capacity and energy from the plants with customers from Virginia if those customers are not paying for ELG compliance costs, or for any new capital investment or continuing operations costs incurred, to allow the plants to operate beyond 2028 or prevent downgrades prior to 2028. The WVPSC also ordered that APCo will be given the opportunity to recover, from West Virginia customers, the new capital and operating costs arising solely from the WVPSC's directive to operate the plants beyond 2028 if the WVPSC finds that the costs are reasonably and prudently incurred. In October and November 2021, intervenors filed petitions for reconsideration at the WVPSC requesting clarification on certain aspects of the order, primarily the jurisdictional allocation of future operating expenses and plant costs.

APCo expects total Amos and Mountaineer Plant ELG investment, excluding AFUDC, to be approximately $197 million. As of December 31, 2021, APCo’s Virginia jurisdictional share of the net book value, before cost of removal including CWIP and inventory, of the Amos and Mountaineer Plants was approximately $1.5 billion and APCo’s Virginia jurisdictional share of its ELG investment balance in CWIP for these plants was $26 million.

If any of the ELG costs are not approved for recovery and/or the retirement dates of the Amos and Mountaineer plants are accelerated to 2028 without commensurate cost recovery, it would reduce future net income and cash flows and impact financial condition.

Fuel Adjustment Clause

The Division of Audits and Accounting in the the FERC is commencing an audit of APCo. The audit will evaluate APCo’s compliance with: (1) its Commission-approved fuel-adjustment clauses and formula rate or tariff recovery mechanisms used to recover fuel and purchased-power costs in billings to wholesale customers; and (2) accounting regulations in the Uniform System of Accounts for public utilities related to fuel and purchased-power costs. The audit will cover the period from January 1, 2019 to the present.

5. EFFECTS OF REGULATION

Regulatory Assets and Liabilities

Regulatory assets and liabilities are comprised of the following items:



	December 31,				Remaining Recovery Period
Regulatory Assets:	2021		2020
	(in millions)

Regulatory assets pending final regulatory approval:

Regulatory Assets Currently Earning a Return
COVID-19 - Virginia	$	6.8	$	3.7
Total Regulatory Assets Currently Earning a Return	6.8		3.7
Regulatory Assets Currently Not Earning a Return
Storm-Related Costs	68.8		3.5
Plant Retirement Costs - Asset Retirement Obligation Costs	25.9		29.8
Environmental Expense Deferral - Virginia	—		9.3
Other Regulatory Assets Pending Final Regulatory Approval	3.6		1.5
Total Regulatory Assets Currently Not Earning a Return	98.3		44.1

Total Regulatory Assets Pending Final Regulatory Approval	105.1		47.8

Regulatory assets approved for recovery:

Regulatory Assets Currently Earning a Return
Under-recovered Fuel Costs - Virginia	127.2		3.3		1 year
Plant Retirement Costs - Unrecovered Plant	30.9		40.0		22 years
Other Regulatory Assets Approved for Recovery	0.4		1.0		various
Total Regulatory Assets Currently Earning a Return	158.5		44.3
Regulatory Assets Currently Not Earning a Return
Income Tax Assets	327.9		356.4
Plant Retirement Costs - Asset Retirement Obligation Costs	293.1		198.8		15 years
Under-recovered Fuel Costs	74.1		2.0		1 year
Pension and OPEB Funded Status	62.7		114.4		12 years
Virginia Transmission Rate Adjustment Clause	37.2		18.8		2 years
Peak Demand Reduction/Energy Efficiency	17.8		16.8		5 years
Environmental Compliance Costs	13.7		—		2 years
Postemployment Benefits	13.3		13.5		3 years
Vegetation Management Program - West Virginia	11.9		45.4		2 years
PJM Annual Formula Rate True-up	3.5		12.7		2 years
Other Regulatory Assets Approved for Recovery	10.6		12.7		various
Total Regulatory Assets Currently Not Earning a Return	865.8		791.5

Total Regulatory Assets Approved for Recovery	1,024.3		835.8

Total FERC Account 182.3 Regulatory Assets	$	1,129.4	$	883.6



	December 31,				Remaining Refund Period
Regulatory Liabilities:	2021		2020
	(in millions)

Regulatory liabilities Pending Final Regulatory Determination

Income Tax Related Regulatory Liabilities (a)
Excess ADIT that is Not Subject to Rate Normalization Requirements (b)	$	4.5	$	—
Total Regulatory Liabilities Pending Final Regulatory Determination	4.5		—

Regulatory liabilities approved for payment

Regulatory Liabilities Currently Not Paying a Return
Unrealized Gain on Forward Commitments	$	28.2	$	5.5	3 years
PJM Transmission Enhancement Refund	13.0		16.3		4 years
Other Regulatory Liabilities Approved for Payment	15.0		6.9		various
Total Regulatory Liabilities Currently Not Paying a Return	56.2		28.7
Income Tax Related Regulatory Liabilities (a)
Excess ADIT Associated with Certain Depreciable Property	663.6		690.0		(c)
Excess ADIT that is Not Subject to Rate Normalization Requirements	83.6		139.1		7 years
Income Taxes Subject to Flow Through	13.6		—		23 years
Total Income Tax Related Regulatory Liabilities	760.8		829.1

Total Regulatory Liabilities Approved for Payment	817.0		857.8

Total FERC 254 Account Regulatory Liabilities	$	821.5	$	857.8

(a)Predominately pays a return due to the inclusion of Excess ADIT in rate base.

(b)Amount represents regulatory liabilities for Excess ADIT as a result of a change in the state income tax apportionment formula in West Virginia. See the “Federal and State Tax Legislation” section of Note 11 for additional information.

(c)Refunded using ARAM.

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, 2021:


Contractual Commitments	Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years		Total
	(in millions)
Fuel Purchase Contracts (a)(b)	$	266.9	$	171.8	$	18.7	$	18.4	$	475.8
Energy and Capacity Purchase Contracts	40.4		81.8		80.4		150.0		352.6
Total	$	307.3	$	253.6	$	99.1	$	168.4	$	828.4

(a)Represents contractual commitments to purchase coal, natural gas and other consumables as fuel for electric generation along with related transportation of the fuel.

(b)In the first quarter of 2022, APCo entered into new fuel purchase contracts related to coal procurement. The new commitments were as follows: $95 million in less than 1 year, $449 million in 2-3 years and $96 million in 4-5 years. These commitments are not included in the tables above. All other new commitments in the first quarter of 2022 were immaterial.

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, 2021, 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 12 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, 2021, APCo was named as a Potentially Responsible Party (PRP) for one site by the Federal EPA for which alleged liability is unresolved. There are 2 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, 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, 2021, management’s estimates do not anticipate material clean-up costs for identified Superfund sites.

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.

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.

Claims Challenging Transition of American Electric Power System Retirement Plan to Cash Balance Formula

Four participants in The American Electric Power System Retirement Plan (the Plan) filed a class action complaint in December 2021 in the U.S. District Court for the Southern District of Ohio against AEPSC and the Plan. When the Plan’s benefit formula was changed in the year 2000, AEP provided a special provision for employees hired before January 1, 2001, allowing them to continue benefit accruals under the then benefit formula for a full 10 years alongside of the new cash balance benefit formula then being implemented. Employees who were hired on or after January 1, 2001 accrued benefits only under the new cash balance benefit formula. The Plaintiffs assert a number of claims on behalf of themselves and the purported class, including that: (a) the Plan violates the requirements under the Employee Retirement Income Security Act (ERISA) intended to preclude back-loading the accrual of benefits to the end of a participant’s career, (b) the Plan violates the age discrimination prohibitions of ERISA and the Age Discrimination in Employment Act and (c) AEP failed to provide required notice regarding the changes to the Plan. Among other relief, the Complaint seeks reformation of the Plan to provide additional benefits and the recovery of plan benefits for former employees under such reformed plan. The Plaintiffs previously had submitted claims for additional plan benefits to AEP, which were denied. On February 15, 2022, AEPSC and the Plan filed a motion to dismiss the complaint for failure to state a claim. AEP will continue to defend against the claims. Management is unable to determine a range of potential losses that is reasonably possible of occurring.

7. 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 the 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 rate-making 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,
Assumption	2021			2020			2021		2020
Discount Rate	2.90	%		2.50	%		2.90	%	2.55	%
Interest Crediting Rate	4.00	%		4.00	%		NA		NA
Rate of Compensation Increase	4.85	%	(a)	4.85	%	(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.

For 2021, 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
	Year Ended December 31,
Assumption	2021			2020			2021		2020
Discount Rate	2.50	%		3.25	%		2.55	%	3.30	%
Interest Crediting Rate	4.00	%		4.00	%		NA		NA
Expected Return on Plan Assets	4.75	%		5.75	%		4.75	%	5.50	%
Rate of Compensation Increase	4.85	%	(a)	4.85	%	(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	2021		2020
Initial	6.25	%	6.50	%
Ultimate	4.50	%	4.50	%
Year Ultimate Reached	2029		2029

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, 2021, 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.

Benefit Plan Obligations, Plan Assets, Funded Status and Amounts Recognized on the Balance Sheets

For the year ended December 31, 2021, the pension plans had an actuarial gain primarily due to an increase in the discount rate, partially offset by less favorable demographic experience than expected, resulting from the updated census information as of January 1, 2021. For the year ended December 31, 2021, the OPEB plans had an actuarial gain primarily due to an increase in the discount rate and an update of the projected reimbursements from the Employer Group Waiver Program under Medicare Part D. 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.

The following tables provide 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
	2021		2020		2021		2020
Change in Benefit Obligation	(in millions)
Benefit Obligation as of January 1,	$	668.5	$	644.9	$	173.7	$	178.7
Service Cost	11.9		10.5		1.0		1.1
Interest Cost	16.3		20.2		4.2		5.8
Actuarial (Gain) Loss	(28.4)		39.8		(21.4)		4.7
Plan Amendments	—		—		(0.9)		(1.8)
Benefit Payments	(48.6)		(46.9)		(19.2)		(21.1)
Participant Contributions	—		—		6.6		6.3
Benefit Obligation as of December 31,	$	619.7	$	668.5	$	144.0	$	173.7

Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1,	$	695.7	$	632.0	$	292.6	$	270.6
Actual Gain on Plan Assets	30.5		103.6		22.0		36.8
Company Contributions	—		7.0		—		—
Participant Contributions	—		—		6.6		6.3
Benefit Payments	(48.6)		(46.9)		(19.2)		(21.1)
Fair Value of Plan Assets as of December 31,	$	677.6	$	695.7	$	302.0	$	292.6

Funded Status as of December 31,	$	57.9	$	27.2	$	158.0	$	118.9

Amounts Recognized on the Balance Sheets;


	Pension Plans				OPEB
	December 31,
	2021		2020		2021		2020
	(in millions)
Special Funds – Prepaid Benefit Costs	$	58.7	$	27.7	$	158.0	$	118.9
Accumulated Provision for Pensions and Benefits – Long-term Benefit Liability	(0.8)		(0.5)		—		—
Funded Status	$	57.9	$	27.2	$	158.0	$	118.9

Amounts Included in Regulatory Assets, Deferred Income Taxes and AOCI

The following tables show the components of the plans included in Regulatory Assets, Deferred Income Taxes, and AOCI:


	Pension Plans				OPEB
	December 31,
	2021		2020		2021		2020
Components	(in millions)
Net Actuarial (Gain) Loss	$	82.5	$	124.7	$	(18.5)	$	11.5
Prior Service Credit	—		—		(23.7)		(33.2)

Recorded as
Regulatory Assets	$	82.5	$	124.7	$	(19.8)	$	(10.3)
Deferred Income Taxes	—		—		(4.7)		(2.4)
Net of Tax AOCI	—		—		(17.7)		(9.0)

Components of the change in amounts included in Regulatory Assets, Deferred Income Taxes, and AOCI were as follows:


	Pension Plans				OPEB
	2021		2020		2021		2020
Components	(in millions)
Actuarial Gain During the Year	$	(30.2)	$	(30.4)	$	(30.0)	$	(17.6)
Amortization of Actuarial Loss	(12.0)		(11.2)		—		(0.9)
Prior Service Credit	—		—		(0.8)		(1.9)
Amortization of Prior Service Credit	—		—		10.3		10.2
Change for the Year Ended December 31,	$	(42.2)	$	(41.6)	$	(20.5)	$	(10.2)

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,
2021		2020		2021		2020
12.7	%	12.5	%	14.8	%	15.0	%

The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2021:


Asset Class	Level 1		Level 2		Level 3		Other		Total		Year End Allocation
	(in millions)
Equities (a):
Domestic	$	388.9	$	—	$	—	$	—	$	388.9	7.2	%
International	465.7		—		—		—		465.7		8.7	%
Common Collective Trusts (c)	—		—		—		463.9		463.9		8.7	%
Subtotal – Equities	854.6		—		—		463.9		1,318.5		24.6	%

Fixed Income (a):
United States Government and Agency Securities	0.1		1,557.6		—		—		1,557.7		29.1	%
Corporate Debt	—		1,295.9		—		—		1,295.9		24.2	%
Foreign Debt	—		259.4		—		—		259.4		4.8	%
State and Local Government	—		57.1		—		—		57.1		1.1	%
Other – Asset Backed	—		1.3		—		—		1.3		—	%
Subtotal – Fixed Income	0.1		3,171.3		—		—		3,171.4		59.2	%

Infrastructure (c)	—		—		—		92.1		92.1		1.7	%
Real Estate (c)	—		—		—		232.6		232.6		4.4	%
Alternative Investments (c)	—		—		—		448.8		448.8		8.4	%
Cash and Cash Equivalents (c)	—		64.3		—		53.4		117.7		2.2	%
Other – Pending Transactions and Accrued Income (b)	—		—		—		(28.2)		(28.2)		(0.5)	%

Total	$	854.7	$	3,235.6	$	—	$	1,262.6	$	5,352.9	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.

The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2021:


Asset Class	Level 1		Level 2		Level 3		Other		Total		Year End Allocation
	(in millions)
Equities:
Domestic	$	474.0	$	—	$	—	$	—	$	474.0	23.2	%
International	296.3		—		—		—		296.3		14.5	%
Common Collective Trusts (b)	—		—		—		265.0		265.0		13.0	%
Subtotal – Equities	770.3		—		—		265.0		1,035.3		50.7	%

Fixed Income:
Common Collective Trust – Debt (b)	—		—		—		167.7		167.7		8.2	%
United States Government and Agency Securities	—		222.4		—		—		222.4		10.9	%
Corporate Debt	—		233.2		—		—		233.2		11.4	%
Foreign Debt	—		39.8		—		—		39.8		2.0	%
State and Local Government	91.9		13.6		—		—		105.5		5.1	%
Subtotal – Fixed Income	91.9		509.0		—		167.7		768.6		37.6	%

Trust Owned Life Insurance:
International Equities	—		23.4		—		—		23.4		1.1	%
United States Bonds	—		171.3		—		—		171.3		8.4	%
Subtotal – Trust Owned Life Insurance	—		194.7		—		—		194.7		9.5	%

Cash and Cash Equivalents (b)	33.0		—		—		6.7		39.7		1.9	%
Other – Pending Transactions and Accrued Income (a)	—		—		—		6.0		6.0		0.3	%

Total	$	895.2	$	703.7	$	—	$	445.4	$	2,044.3	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.

The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2020:


Asset Class	Level 1		Level 2		Level 3		Other		Total		Year End 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	%

(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.

The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2020:


Asset Class	Level 1		Level 2		Level 3		Other		Total		Year End 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.

Accumulated Benefit Obligation

The accumulated benefit obligation for the pension plans is as follows:


	December 31,
Accumulated Benefit Obligation	2021		2020
	(in millions)
Qualified Pension Plan	$	595.0	$	643.5
Nonqualified Pension Plans	0.4		0.2
Total	$	595.4	$	643.7

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,
	2021		2020
	(in millions)
Projected Benefit Obligation	$	0.8	$	0.5
Fair Value of Plan Assets	—		—
Underfunded Projected Benefit Obligation	$	(0.8)	$	(0.5)

Accumulated Benefit Obligation


	December 31,
	2021		2020
	(in millions)
Accumulated Benefit Obligation	$	0.4	$	0.2
Fair Value of Plan Assets	—		—
Underfunded Accumulated Benefit Obligation	$	(0.4)	$	(0.2)

Estimated Future Benefit Payments and Contributions

APCo expects contributions and payments for the Pension plans of $1 million during 2022. 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.

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 the pension benefits and OPEB are as follows:


	Estimated Payments
	Pension Plans		OPEB
	(in millions)
2022	$	43.7	$	18.7
2023	44.8		17.3
2024	45.3		18.0
2025	43.0		17.5
2026	43.3		17.1
Years 2027 to 2031, in Total	202.2		80.0

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,
	2021		2020		2021		2020
	(in millions)
Service Cost	$	11.9	$	10.5	$	1.0	$	1.1
Interest Cost	16.3		20.2		4.2		5.8
Expected Return on Plan Assets	(28.8)		(33.4)		(13.4)		(14.5)
Amortization of Prior Service Credit	—		—		(10.3)		(10.2)
Amortization of Net Actuarial Loss	12.0		11.2		—		0.9
Net Periodic Benefit Cost (Credit)	11.4		8.5		(18.5)		(16.9)
Capitalized Portion	(5.2)		(4.5)		(0.4)		(0.5)
Net Periodic Benefit Cost (Credit) Recognized in Expense	$	6.2	$	4.0	$	(18.9)	$	(17.4)

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, 2021 and 2020 were $8 million and $8 million, respectively.

8. BUSINESS SEGMENTS

APCo has one reportable segment, an electricity generation, transmission and distribution business. APCo’s other activities are insignificant.

9. 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.

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.

The following table represents the gross notional volume of outstanding derivative contracts:


Notional Volume of Derivative Instruments

	Volume
	December 31,
Primary Risk Exposure	2021		2020		Unit of Measure
	(in millions)
Commodity:
Power	33.1		46.9		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.

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, 2021 and 2020.

The following tables represent the gross fair value of APCo’s derivative activity on the balance sheets:


	December 31, 2021
	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	$	47.7	$	(5.7)	$	42.0
Long-Term Portion of Derivative Instrument Assets	0.2		(0.2)		—

Derivative Instrument Liabilities	7.4		(6.6)		0.8
Long-Term Portion of Derivative Instrument Liabilities	0.2		(0.2)		—


	December 31, 2020
	Risk				Gross Amounts 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

(a)Derivative instruments within this category are disclosed as 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.

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)	2021		2020
	(in millions)
Operating Revenues	$	(0.5)	$	0.4
Operation Expenses	2.1		1.0
Maintenance Expenses	0.5		(0.4)
Other Regulatory Assets (a)	(2.7)		—
Other Regulatory Liabilities (a)	55.9		20.3
Total Gain (Loss) on Risk Management Contracts	$	55.3	$	21.3

(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 line item on the statements of income as that of the associated risk being hedged. 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.”

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 2021 and 2020, 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 years ended 2021 and 2020, APCo applied 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, 2021

December 31, 2020

Interest Rate

Expected to be

Reclassed to

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)

7.5

0.8

(0.8)

0.4

The actual amounts reclassified from Accumulated Other Comprehensive Income to Net Income can differ from the estimate above due to market price changes.

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, 2021 and 2020.

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, 2021 and 2020.

10. 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,
2021				2020
Book Value		Fair Value		Book Value		Fair Value
(in millions)
$	4,967.7	$	6,037.1	$	4,861.9	$	6,391.8

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.


	December 31, 2021
	Level 1		Level 2		Level 3		Other		Total
Assets:	(in millions)

Special Deposits	$	17.6	$	—	$	—	$	—	$	17.6

Derivative Instrument Assets
Risk Management Commodity Contracts (a) (b)	—		5.8		42.0		(5.8)		42.0

Total Assets	$	17.6	$	5.8	$	42.0	$	(5.8)	$	59.6

Liabilities:

Derivative Instrument Liabilities
Risk Management Commodity Contracts (a) (b)	$	—	$	7.2	$	0.3	$	(6.7)	$	0.8


	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

(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.

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, 2021	Assets (Liabilities)
	(in millions)
Balance as of December 31, 2020	$	19.3
Realized Gain Included in Net Income (or Changes in Net Assets) (a) (b)	8.3
Settlements	(28.0)
Transfers out of Level 3 (c)	—
Changes in Fair Value Allocated to Regulated Jurisdictions (d)	42.1
Balance as of December 31, 2021	$	41.7

	Derivative Instrument
Year Ended December 31, 2020	Assets (Liabilities)
	(in millions)
Balance as of December 31, 2019	$	37.7
Realized Gain Included in Net Income (or Changes in Net Assets) (a) (b)	13.2
Settlements	(51.6)
Transfers out of Level 3 (c)	0.7
Changes in Fair Value Allocated to Regulated Jurisdictions (d)	19.3
Balance as of December 31, 2020	$	19.3

(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)Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.

(d)Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These changes in fair value are recorded as regulatory liabilities for net gains and as regulatory assets for net losses or accounts payable.

The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions:


December 31, 2021
						Significant	Input/Range
	Fair Value				Valuation	Unobservable					Weighted
	Assets		Liabilities		Technique	Input (a)	Low		High		Average (b)
	(in millions)
Energy Contracts	$	—	$	0.3	Discounted Cash Flow	Forward Market Price	$	32.20	$	56.54	$	44.77
FTRs	42.0		—		Discounted Cash Flow	Forward Market Price	(0.30)		26.38		2.63
Total	$	42.0	$	0.3


December 31, 2020
						Significant	Input/Range
	Fair Value				Valuation	Unobservable					Weighted
	Assets		Liabilities		Technique	Input (a)	Low		High		Average (b)
	(in millions)
Energy Contracts	$	1.0	$	0.6	Discounted Cash Flow	Forward Market Price	$	10.84	$	41.09	$	25.08
FTRs	18.9		—		Discounted Cash Flow	Forward Market Price	0.04		5.61		1.13
Total	$	19.9	$	0.6

(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, 2021 and 2020:

Uncertainty of Fair Value Measurements

Significant Unobservable Input

Position

Change in Input

Impact on Fair Value

Measurement

Forward Market Price

Buy

Increase (Decrease)

Higher (Lower)

Forward Market Price

Sell

Increase (Decrease)

Lower (Higher)

11. INCOME TAXES

Income Tax Expense (Credit)

The details of APCo’s income taxes as reported are as follows:


	Years Ended December 31,
	2021			2020
	(in millions)
Charged (Credited) to Operating Expenses, Net:
Current	$	12.0		$	36.2
Deferred			17.2			(29.4)
Total			29.2			6.8

Charged (Credited) to Non-Operating Income, Net:
Current			(4.9)			(5.2)
Deferred			(1.7)			2.8
Total			(6.6)			(2.4)
Total Income Tax Expense	$	22.6		$	4.4

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:



	2021				2020

Net Income	$	348.9			$	369.7
Income Tax Expense			22.6				4.4
Pretax Income	$	371.5			$	374.1

Income Taxes on Pretax Income at Statutory Rate (21%)	$	78.0			$	78.6
Increase (Decrease) in Income Taxes Resulting from the Following Items:
Reversal of Origination Flow-Through			11.7				12.7
State and Local Income Taxes, Net			1.0				7.9
Removal Costs			(7.3)				(5.7)
AFUDC			(4.6)				(4.5)
Parent Company Loss Benefit			—				(6.2)
Tax Reform Excess ADIT Reversal			(60.5)				(72.3)
Return to Provision Adjustment			(0.5)				(7.1)
Tax Adjustments (a)			4.9				—
Other			(0.1)				1.0
Income Tax Expense	$	22.6			$	4.4

Effective Income Tax Rate	6.1			%	1.2			%

(a) Represents the correction of an out of period adjustment related to Deferred Income Taxes and Income Tax Expense. Management concluded the misstatement and subsequent correction was not material to prior or current period financial statements.

Net Deferred Tax Liability

The following table shows elements of APCo’s net deferred tax assets (liabilities) and significant temporary differences:


	December 31,
	2021		2020
	(in millions)
Deferred Tax Assets	$	488.8	$	494.8
Deferred Tax Liabilities	(2,298.7)		(2,249.5)
Net Deferred Tax Liabilities	$	(1,809.9)	$	(1,754.7)

Property Related Temporary Differences	$	(1,476.5)	$	(1,412.0)
Amounts Due to Customers for Future Income Taxes	182.1		198.3
Deferred State Income Taxes	(289.2)		(336.5)
Regulatory Assets	(177.0)		(114.8)
Securitized Assets	(39.3)		(44.7)
Operating Lease Liability	14.2		16.7
All Other, Net	(24.2)		(61.7)
Net Deferred Tax Liabilities	$	(1,809.9)	$	(1,754.7)

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.

Net Income Tax Operating Loss Carryforward

As of December 31, 2021, APCO had West Virginia net income tax operating loss carryforward of $62.9 million. As a result, APCO recognized deferred state income tax benefits. Management anticipates future taxable income will be sufficient to realize the state net income tax operating loss tax benefits before the state carryforward expires.

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 through 2017 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, 2021, the IRS has not issued any proposed adjustments and the IRS is limited in their proposed adjustments to the amount APCo and other AEP subsidiaries claimed on the amended returns. APCo has agreed to extend the statute of limitations on the 2017 tax return to December 31, 2022 to allow time for the audit to be completed and the Congressional Joint Committee on Taxation to approve the associated refund claim.

APCo and AEP subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine the tax returns, and APCo and other AEP subsidiaries are currently under examination in several state and local jurisdictions. The Registrants are no longer subject to state or local examinations by tax authorities for years before 2012. In addition, management is monitoring and continues to evaluate the potential impact of federal legislation and corresponding state conformity.

State Tax Legislation

In April 2021, West Virginia enacted House Bill (HB) 2026. HB 2026 changes the state income tax apportionment formula from a ratio that includes property, payroll and sales to a single sales factor apportionment regime effective for tax years beginning on or after January 1, 2022. HB 2026 also eliminates the “throw out” rule related to sales of tangible personal property for sales factor apportionment calculation purposes and introduces a market-based sourcing for sales of services and intangible property.

12. LEASES

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,
	2021		2020
	(in millions)
Operating Lease Cost	$	19.3	$	19.1
Finance Lease Cost:
Amortization of Right-of-Use Assets	7.7		7.4
Interest on Lease Liabilities	2.4		2.7
Total Lease Rental Costs (a)	$	29.4	$	29.2

(a)Excludes variable and short-term lease costs, which were immaterial.

Supplemental information related to leases are shown in the tables below:


	December 31,
	2021		2020
Weighted-Average Remaining Lease Term (years):
Operating Leases	5.68		6.27
Finance Leases	4.97		5.75
Weighted-Average Discount Rate:
Operating Leases	3.42	%	3.48	%
Finance Leases	7.16	%	7.33	%


	Year Ended December 31,
	2021		2020
	(in millions)
Cash paid for amounts included in the measurement of lease liabilities:
Operating Cash Flows from Operating Leases	$	19.3	$	19.2
Operating Cash Flows from Finance Leases	10.1		10.1

Non-cash Acquisitions Under Operating Leases	$	4.2	$	16.2

The following tables show property, plant and equipment under finance leases, operating leases and related obligations recorded on APCo’s balance sheets:


	December 31,
	2021		2020
	(in millions)
Property, Plant and Equipment Under Finance Leases:
Utility Plant (a)	$	35.7	$	41.7
Net Property, Plant and Equipment Under Finance Leases	$	35.7	$	41.7

Obligations Under Finance Leases:
Noncurrent	$	28.1	$	34.4
Current	7.6		7.3
Total Obligations Under Finance Leases	$	35.7	$	41.7

(a) Includes $28 million and $22 million of accumulated provision for depreciation and amortization for

the years ended December 31, 2021 and 2020, respectively.


	December 31,
	2021		2020
	(in millions)
Property, Plant and Equipment Under Operating Leases:
Utility Plant (a)	$	66.9	$	78.8
Net Property, Plant and Equipment Under Operating Leases	$	66.9	$	78.8

Obligations Under Operating Leases:
Noncurrent	$	52.4	$	64.4
Current	15.1		14.9
Total Obligations Under Operating Leases	$	67.5	$	79.3

(a) Includes $38 million and $25 million of accumulated provision for depreciation and amortization for

the years ended December 31, 2021 and 2020, respectively.

Future minimum lease payments consisted of the following as of December 31, 2021:


	Finance Leases		Operating Leases
	(in millions)
2022	$	9.8	$	17.5
2023	9.1		14.8
2024	8.3		11.9
2025	7.2		9.1
2026	2.7		7.2
After 2026	4.1		14.1
Total Future Minimum Lease Payments	41.2		74.6
Less: Imputed Interest	5.5		7.1
Estimated Present Value of Future Minimum Lease Payments	$	35.7	$	67.5

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, 2021, 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 $6 million.

Lessor Activity

APCo’s lessor activity was immaterial as of and for the twelve months ended December 31, 2021 and December 31, 2020, respectively.

13. 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, 2021	2021	2020	2021		2020
Senior Unsecured Notes	2021-2050	4.70%	2.70%-7.00%	3.30%-7.00%	$	4,125.0	$	3,975.0
Pollution Control Bonds (a)	2021-2036 (b)	1.67%	0.19%-2.75%	0.19%-4.63%	531.0		548.5
Securitization Bonds	2023-2028 (c)	3.46%	2.01%-3.77%	2.01%-3.77%	200.1		225.5
Other Long-term Debt	2022-2026	1.42%	1.24%-13.72%	1.32%-13.72%	126.9		127.0
Unamortized Discount, Net					(15.3)		(14.1)
Total Long-term Debt Outstanding					$	4,967.7	$	4,861.9

(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.

As of December 31, 2021, long-term debt was payable as follows:


	(in millions)
2022	$	480.7
2023	26.6
2024	113.5
2025	443.9
2026	30.9
After 2026	3,887.4
Principal Amount	4,983.0
Unamortized Discount, Net	(15.3)
Total Long-term Debt	$	4,967.7

Long-term Debt Subsequent Events

In February 2022, APCo retired $13 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, 2021, 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 $2.4 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, 2021, the amount of any such restrictions was $313 million.

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 borrowings from the Utility Money Pool as of December 31, 2021 and 2020 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)
2021	$	199.3	$	595.9	$	87.5	$	118.3	$	199.3	$	500.0
2020	434.3		167.3		292.7		94.3		18.6		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
	(in millions)
2021	0.48	%	0.06	%	0.40	%	0.02	%	0.41	%	0.25	%
2020	2.70	%	0.27	%	2.14	%	0.27	%	2.13	%	0.72	%

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, 2021 and 2020.

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 and was amended in September 2021 to include a $125 million and a $625 million facility, which expire in September 2023 and 2024, respectively.

The amount of accounts receivable and accrued utility revenues under the sale of receivables agreement as of December 31, 2021 and 2020 were $153 million and $136 million, respectively.

The fees paid to AEP Credit for customer accounts receivable sold were $5 million and $5 million for the years ended December 31, 2021 and 2020, respectively. In 2020, an increase in allowance for doubtful accounts was recognized in response to the anticipated impact of COVID-19 on the collectability of accounts receivable, which caused an increase in fees paid by APCo. In 2021, due to higher than expected collections of accounts receivables, allowance for doubtful accounts was adjusted resulting in the issuance of credits to offset the higher fees previously paid and to lower subsequent fees paid.

The proceeds on the sale of receivables to AEP Credit were $1.3 billion and $1.3 billion for the years ended December 31, 2021 and 2020, respectively.

14. RELATED PARTY TRANSACTIONS

For other related party transactions, also see “AEP System Tax Allocation Agreement” section of Note 11 in addition to “Corporate Borrowing Program – AEP System” and “Securitized Accounts Receivables – AEP Credit” sections of Note 13.

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.

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, 2021 and 2020:


		Years Ended December 31,
Related Party Revenues		2021		2020
		(in millions)
Direct Sales to East Affiliates		$	128.6	$	112.5
Auction Sales to OPCo (a)		—		5.3
Transmission Revenues		60.3		49.1
Other Revenues		9.0		7.8

(a)	Refer to the Ohio Auctions 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. Additional costs for transmission services provided by AEPTCo and other transmission affiliates are billed to AEP East Companies through the PJM OATT. APCo’s net charges for the years ended December 31, 2021 and 2020 related to the TA were $302 million and $243 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, 2021 and 2020, AEPTCo billed APCo $2 million and $900 thousand, respectively.

OVEC

AEP and several nonaffiliated utility companies jointly own OVEC. As of December 31, 2021, the ownership and investment in OVEC were as follows:


	December 31, 2021
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.

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, 2021 and 2020, OVEC’s outstanding indebtedness was approximately $1.1 billion and $1.3 billion, respectively. 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 $104 million and $94 million for power purchased from OVEC for the years ended December 31, 2021 and 2020, respectively. The amounts shown above are recoverable from customers and are included in Operating Revenues and Operation Expenses on the statement of income.

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.

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 NOx emissions at certain generation plants in the AEP System. APCo recorded the costs paid to I&M of $40 million and $44 million for the years ended December 31, 2021 and 2020, 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 $8 million for the years ended December 31, 2021 and 2020, respectively.

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,
	2021		2020
	(in millions)
Sales	$	6.2	$	5.7
Purchases	1.0		1.3

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.

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 $313 million and $295 million for the years ended December 31, 2021 and 2020, respectively.

15. 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:


Year	Other Production	Steam	Hydro	Transmission	Distribution	General
	(in percentages)
2021	2.6	3.6	5.9	2.1	3.5	8.5
2020	2.6	3.4	3.0	2.2	3.7	7.8

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 2020, Virginia’s Governor signed House Bill 443 (HB 443) requiring APCo to close certain ash disposal units at the retired Glen Lyn Station by removal of all coal combustion material. 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. In June 2021, management completed fully designed and costed project plans for the Glen Lyn Station site and increased ash disposal ARO liabilities by an additional $79 million. House Bill 443 provides for the recovery of all costs associated with closure by removal through the Virginia environmental rate adjustment clause. APCo is permitted to record carrying costs on the unrecovered balance of closure costs as a weighted-average cost of capital approved by the Virginia SCC. The legislation provides for regulatory recovery of these costs.

The following is a reconciliation of the 2021 and 2020 aggregate carrying amounts of ARO:


Year	ARO at January 1,		Accretion Expense		Liabilities Settled		Revisions in Cash Flow Estimates (a)		ARO at December 31,
	(in millions)
2021	$	313.1	$	13.7	$	(6.9)	$	84.7	$	404.6	(b)(c)
2020	111.1		8.9		(7.8)		200.9		313.1		(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.

16. 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,
	2021		2020
	(in millions)
Retail Revenues:
Residential Revenues	$	1,378.3	$	1,273.0
Commercial Revenues	555.8		526.9
Industrial Revenues (a)	583.7		563.9
Other Retail Revenues	70.7		68.9
Total Retail Revenues	2,588.5		2,432.7

Wholesale Revenues:
Generation Revenues (b)	342.7		247.1
Transmission Revenues (a)	128.8		130.9
Total Wholesale Revenues	471.5		378.0

Other Revenues from Contracts with Customers (a)	69.9		59.2

Total Revenues from Contracts with Customers	3,129.9		2,869.9

Other Revenues:
Alternative Revenues (a)	12.3		(13.0)
Other Revenues	(0.2)		0.3
Total Other Revenues	12.1		(12.7)

Total Operating Revenues	$	3,142.0	$	2,857.2

(a)Amounts include affiliated and nonaffiliated revenues.

(b)Amounts include affiliated and nonaffiliated revenues. The affiliated revenue for APCo was $129 million primarily relating to the PPA with KGPCo. The remaining affiliated amounts were immaterial.

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.

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 table 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 table 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 therefore presented as such in the disaggregated revenues table above.

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 TA are reflected as Transmission Revenues in the disaggregated revenues table above.

Fixed Performance Obligations

The following table represents the remaining fixed performance obligations satisfied over time as of December 31, 2021. 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.


2022		2023-2024		2025-2026		After 2026		Total
(in millions)
$	201.5	$	32.2	$	23.2	$	11.6	$	268.5

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, 2021 and 2020.

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, 2021 and 2020.

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 Receivable were not material as of December 31, 2021 and 2020. See “Securitized Accounts Receivable - AEP Credit” section of Note 13 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 $118 million and $53 million, as of December 31, 2021 and 2020.

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, 2021 and 2020.

17. 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.

The following table presents APCo’s energy storage operations for small plants for the years ended December 31, 2021 and 2020, as required by FERC Order No. 784:


							Operation			Maintenance
Project	Functional	Project	Project Costs				Expenses			Expenses
Name	Classification	Location	Account	Amount			Account	Amount		Account	Amount (a)
			(dollars in millions)
Year Ended December 31, 2021
Balls Gap Station	Distribution	Balls Gap, WV	363	$	5.4		562	$	—	592	$	—
Byllesby Hydro Plant	Generation	Ivanhoe, Virginia	348			5.7	562		—	592		—
Chemical Station	Transmission	N. Charleston, WV	351			—	562		—	592		—

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		—

(a) This amount would have been recorded in Account 592.2 in accordance with FERC Order No. 784.

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges. 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. Report data on a year-to-date basis.
Line No.	Item (a)	Unrealized Gains and Losses on Available-For-Sale Securities (b)	Minimum Pension Liability Adjustment (net amount) (c)	Foreign Currency Hedges (d)	Other Adjustments (e)	Other Cash Flow Hedges Interest Rate Swaps (f)	Other Cash Flow Hedges [Specify] (g)	Totals for each category of items recorded in Account 219 (h)	Net Income (Carried Forward from Page 116, Line 78) (i)	Total Comprehensive Income (j)
1	Balance of Account 219 at Beginning of Preceding Year			64,188	4,206,754	898,206		5,040,772
2	Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income				3,438,622	1,731,328		5,169,950
3	Preceding Quarter/Year to Date Changes in Fair Value			36	8,050,598			8,050,562
4	Total (lines 2 and 3)			36	4,611,976	1,731,328		2,880,612	369,732,667	372,613,279
5	Balance of Account 219 at End of Preceding Quarter/Year			64,224	8,818,730	833,122		7,921,384
6	Balance of Account 219 at Beginning of Current Year			64,224	8,818,730	833,122		7,921,384
7	Current Quarter/Year to Date Reclassifications from Account 219 to Net Income				4,891,938	8,337,016		3,445,078
8	Current Quarter/Year to Date Changes in Fair Value			36	13,012,772			13,012,736
9	Total (lines 7 and 8)			36	8,120,834	8,337,016		16,457,814	348,937,055	365,394,869
10	Balance of Account 219 at End of Current Quarter/Year			64,260	16,939,564	7,503,894		24,379,198

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

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.
Line No.	Classification (a)	Total Company For the Current Year/Quarter Ended (b)	Electric (c)	Gas (d)	Other (Specify) (e)	Other (Specify) (f)	Other (Specify) (g)	Common (h)
1	UtilityPlantAbstract UTILITY PLANT
2	UtilityPlantInServiceAbstract In Service
3	UtilityPlantInServiceClassified Plant in Service (Classified)	14,952,499,535	14,952,499,535
4	UtilityPlantInServicePropertyUnderCapitalLeases Property Under Capital Leases	102,541,648.90	102,541,648.90
5	UtilityPlantInServicePlantPurchasedOrSold Plant Purchased or Sold
6	UtilityPlantInServiceCompletedConstructionNotClassified Completed Construction not Classified	1,342,813,476	1,342,813,476
7	UtilityPlantInServiceExperimentalPlantUnclassified Experimental Plant Unclassified
8	UtilityPlantInServiceClassifiedAndUnclassified Total (3 thru 7)	16,397,854,660	16,397,854,660
9	UtilityPlantLeasedToOthers Leased to Others
10	UtilityPlantHeldForFutureUse Held for Future Use	3,144,691.00	3,144,691.00
11	ConstructionWorkInProgress Construction Work in Progress	471,403,315	471,403,315
12	UtilityPlantAcquisitionAdjustment Acquisition Adjustments	181,679.00	181,679.00
13	UtilityPlantAndConstructionWorkInProgress Total Utility Plant (8 thru 12)	16,872,584,345	16,872,584,345
14	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Accumulated Provisions for Depreciation, Amortization, & Depletion	5,765,578,075	5,765,578,075
15	UtilityPlantNet Net Utility Plant (13 less 14)	11,107,006,270	11,107,006,270
16	DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17	AccumulatedProvisionForDepreciationAmortizationAndDepletionUtilityPlantInServiceAbstract In Service:
18	DepreciationUtilityPlantInService Depreciation	5,627,412,008	5,627,412,008
19	AmortizationAndDepletionOfProducingNaturalGasLandAndLandRightsutilityPlantInService Amortization and Depletion of Producing Natural Gas Land and Land Rights
20	AmortizationOfUndergroundStorageLandAndLandRightsutilityPlantInService Amortization of Underground Storage Land and Land Rights
21	AmortizationOfOtherUtilityPlantUtilityPlantInService Amortization of Other Utility Plant	137,988,536	137,988,536
22	DepreciationAmortizationAndDepletionUtilityPlantInService Total in Service (18 thru 21)	5,765,400,544	5,765,400,544
23	DepreciationAmortizationAndDepletionUtilityPlantLeasedToOthersAbstract Leased to Others
24	DepreciationUtilityPlantLeasedToOthers Depreciation
25	AmortizationAndDepletionUtilityPlantLeasedToOthers Amortization and Depletion
26	DepreciationAmortizationAndDepletionUtilityPlantLeasedToOthers Total Leased to Others (24 & 25)
27	DepreciationAndAmortizationUtilityPlantHeldForFutureUseAbstract Held for Future Use
28	DepreciationUtilityPlantHeldForFutureUse Depreciation	4,147.90	4,147.90
29	AmortizationUtilityPlantHeldForFutureUse Amortization
30	DepreciationAndAmortizationUtilityPlantHeldForFutureUse Total Held for Future Use (28 & 29)	4,148	4,148
31	AbandonmentOfLeases Abandonment of Leases (Natural Gas)
32	AmortizationOfPlantAcquisitionAdjustment Amortization of Plant Acquisition Adjustment	181,679.00	181,679.00
33	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility Total Accum Prov (equals 14) (22,26,30,31,32)	5,765,578,075	5,765,578,075

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157)
Report below the costs incurred for nuclear fuel materials in process of fabrication, on hand, in reactor, and in cooling; owned by the respondent. 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 No.	Description of item (a)	Balance Beginning of Year (b)	Changes during Year Additions (c)	Changes during Year Amortization (d)	Changes during Year Other Reductions (Explain in a footnote) (e)	Balance End of Year (f)
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)

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106)
Report below the original cost of electric plant in service according to the prescribed accounts. 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. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year. 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. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts. 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 the 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) 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. 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. 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. 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.
Line No.	Account (a)	Balance Beginning of Year (b)	Additions (c)	Retirements (d)	Adjustments (e)	Transfers (f)	Balance at End of Year (g)
1	1. INTANGIBLE PLANT
2	(301) Organization	133,394					133,394
3	(302) Franchise and Consents	15,259,243	1,791	477			15,260,557
4	(303) Miscellaneous Intangible Plant	233,893,075	45,456,779	14,868,256			264,481,598
5	TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)	249,285,713	45,458,570	14,868,733			279,875,549
6	2. PRODUCTION PLANT
7	A. Steam Production Plant
8	(310) Land and Land Rights	12,363,468					12,363,468
9	(311) Structures and Improvements	400,823,516	3,324,684	1,327,754		0	402,820,446
10	(312) Boiler Plant Equipment	4,405,110,291	37,742,644	19,349,074			4,423,503,861
11	(313) Engines and Engine-Driven Generators
12	(314) Turbogenerator Units	453,352,114	4,241,758	3,875,562			453,718,309
13	(315) Accessory Electric Equipment	181,486,230	2,240,560	1,014,835			182,711,955
14	(316) Misc. Power Plant Equipment	81,660,838	5,655,568	550,279		65,865	86,700,262
15	(317) Asset Retirement Costs for Steam Production	90,810,389	6,115,057				96,925,446
16	TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)	5,625,606,846	59,320,271	26,117,505		65,865	5,658,743,747
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	9,800,639				174	9,800,813
28	(331) Structures and Improvements	30,599,801	239,785				30,839,586
29	(332) Reservoirs, Dams, and Waterways	82,877,994	2,950,589	464,154			85,364,429
30	(333) Water Wheels, Turbines, and Generators	113,742,454	3,626,658	117,425			117,251,688
31	(334) Accessory Electric Equipment	25,971,183	621,129	272,069			26,320,244
32	(335) Misc. Power Plant Equipment	23,005,977	225,648				23,231,625
33	(336) Roads, Railroads, and Bridges	1,241,854					1,241,854
34	(337) Asset Retirement Costs for Hydraulic Production	2,682,604					2,682,604
35	TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)	289,922,507	7,663,810	853,648		174	296,732,843
36	D. Other Production Plant
37	(340) Land and Land Rights	3,196,932					3,196,932
38	(341) Structures and Improvements	50,430,382	1,513,778	146,364			51,797,796
39	(342) Fuel Holders, Products, and Accessories	26,968,819	466,127	412,199			27,022,746
40	(343) Prime Movers
41	(344) Generators	508,845,078	8,813,791	748,956			516,909,913
42	(345) Accessory Electric Equipment	48,079,497	287,034	180,647			48,185,884
43	(346) Misc. Power Plant Equipment	31,688,645	2,523,736	1,879,243			32,333,138
44	(347) Asset Retirement Costs for Other Production
44.1	(348) Energy Storage Equipment - Production	5,726,249					5,726,249
45	TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)	674,935,601	13,604,467	3,367,409			685,172,659
46	TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)	6,590,464,954	80,588,548	30,338,562		65,691	6,640,649,250
47	3. Transmission Plant
48	(350) Land and Land Rights	201,475,187	14,626,949	260,858		54,640	215,895,917
48.1	(351) Energy Storage Equipment - Transmission
49	(352) Structures and Improvements	118,187,918	55,729,167	1,424,127			(a) 172,492,959
50	(353) Station Equipment	1,854,529,371	228,260,255	23,083,836		207,998	2,059,913,788
51	(354) Towers and Fixtures	508,792,476	7,979,631	2,203,442			514,568,666
52	(355) Poles and Fixtures	482,905,560	53,838,772	9,951,510			526,792,822
53	(356) Overhead Conductors and Devices	699,258,823	90,679,600	4,925,660			785,012,763
54	(357) Underground Conduit	10,132,518	7,267,560				17,400,078
55	(358) Underground Conductors and Devices	23,589,203	5,171,662	5,886			28,754,978
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)	3,898,871,056	463,553,597	41,855,319		262,638	4,320,831,972
59	4. Distribution Plant
60	(360) Land and Land Rights	72,214,660	1,913,216	114,206		536,487	74,550,158
61	(361) Structures and Improvements	62,236,280	7,274,596	510,231			69,000,645
62	(362) Station Equipment	671,260,440	40,255,872	6,439,452		199,721	704,877,139
63	(363) Energy Storage Equipment – Distribution	5,411,171	91,756	155,807		8,277	5,338,844
64	(364) Poles, Towers, and Fixtures	838,857,178	39,822,649	7,000,805			871,679,023
65	(365) Overhead Conductors and Devices	1,074,969,935	97,214,805	7,692,722			1,164,492,018
66	(366) Underground Conduit	140,184,194	4,440,247	91,270			144,533,172
67	(367) Underground Conductors and Devices	315,161,218	9,914,143	779,810			324,295,551
68	(368) Line Transformers	633,640,774	25,769,510	8,534,890			650,875,394
69	(369) Services	362,588,824	13,953,554	2,446,074			374,096,304
70	(370) Meters	192,666,444	25,584,855	15,926,420			202,324,879
71	(371) Installations on Customer Premises	62,434,434	4,362,955	2,816,396			63,980,992
72	(372) Leased Property on Customer Premises	771					771
73	(373) Street Lighting and Signal Systems	30,967,525	1,544,455	441,166			32,070,814
74	(374) Asset Retirement Costs for Distribution Plant	3,069					3,069
75	TOTAL Distribution Plant (Enter Total of lines 60 thru 74)	4,462,596,917	272,142,614	52,949,248		328,489	4,682,118,772
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	779,440				16,003,857
87	(390) Structures and Improvements	153,227,387	2,350,165	540,510			155,037,041
88	(391) Office Furniture and Equipment	11,830,299	336,363	142,768			12,023,894
89	(392) Transportation Equipment	8,674					8,674
90	(393) Stores Equipment	2,046,596	29,332				2,075,929
91	(394) Tools, Shop and Garage Equipment	40,150,710	1,429,505				41,580,214
92	(395) Laboratory Equipment	3,096,136	255,052	278,274			3,072,914
93	(396) Power Operated Equipment		132,662				132,662
94	(397) Communication Equipment	96,117,540	38,144,353	1,832,665			132,429,228
95	(398) Miscellaneous Equipment	7,590,800	527,730	77,434		65,865	8,106,961
96	SUBTOTAL (Enter Total of lines 86 thru 95)	329,292,558	43,984,603	2,871,651		65,865	370,471,374
97	(399) Other Tangible Property
98	(399.1) Asset Retirement Costs for General Plant	1,204,129	161,967				1,366,095
99	TOTAL General Plant (Enter Total of lines 96, 97, and 98)	330,496,686	44,146,570	2,871,651		65,865	371,837,469
100	TOTAL (Accounts 101 and 106)	15,531,715,326	905,889,899	142,883,514		591,301	16,295,313,011
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)	15,531,715,326	905,889,899	142,883,514		591,301	16,295,313,011

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: StructuresAndImprovementsTransmissionPlant

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

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

ELECTRIC PLANT LEASED TO OTHERS (Account 104)
Line No.	LesseeName Name of Lessee (a)	IndicationOfAssociatedCompany * (Designation of Associated Company) (b)	LeaseDescription Description of Property Leased (c)	CommissionAuthorization Commission Authorization (d)	ExpirationDateOfLease Expiration Date of Lease (e)	ElectricPlantLeasedToOthers Balance at End of Year (f)
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

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)
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. 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 No.	ElectricPlantHeldForFutureUseDescription Description and Location of Property (a)	ElectricPlantPropertyClassifiedAsHeldForFutureUseOriginalDate Date Originally Included in This Account (b)	ElectricPlantPropertyClassifiedAsHeldForFutureUseExpectedUseInServiceDate Date Expected to be used in Utility Service (c)	ElectricPlantHeldForFutureUse Balance at End of Year (d)
1	Land and Rights:
2	Amos-Gavin 765KV Comm Solvents Tract Land, WV (2639)	09/23/1974		256,070.00
3	John E. Amos Fly Ash Area 3, Putnam Co., WV - approx 132.65 acres of land (0745)	06/30/1973		287,900.66
4	Shadwell 69KV Substation, Roanoke County, VA 10.637 acres (7662)	08/01/2009	12/31/2022	431,124.17
5	Sheridan 69KV Substation, Lincoln County, WV 4.947 acres (2041)	11/01/2015	12/31/2022	327,041.50
6	Items under $250,000			1,842,554.27
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			3,144,691

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
Report below descriptions and balances at end of year of projects in process of construction (107). 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). Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
Line No.	ConstructionWorkInProgressProjectDescription Description of Project (a)	ConstructionWorkInProgress Construction work in progress - Electric (Account 107) (b)
1	AM CCR/ELG Compliance	43,630,657
2	Amos 1&2 DSI Project	2,340,518
3	AMU2 Air Heater Basket Replace	1,931,992
4	APCO - T Work Supplemental	1,166,242
5	APCo AMI Project VA	11,904,524
6	APCO AMI Project WV	9,929,265
7	APCo D (Floyd-Stuart Area)	1,800,265
8	APCo D Work (Supplemental)	2,927,933
9	APCO Distr Pre Eng Parent	4,966,372
10	APCo DISTR Work	3,081,856
11	APCo Distribution Work	3,457,862
12	APCO Next Generation Radio Sys	14,070,199
13	APCo T (Station)	1,529,770
14	APCo T Work	12,857,374
15	APCo T Work (Supplemental)	2,143,584
16	APCo T-BlnktProj Under $3M	2,909,516
17	APCO Trans Pre Eng Parent	13,013,528
18	APCo Transmission Work	8,139,980
19	APCo VA Major Eq/ Spares-Trans	4,056,731
20	APCO: 2020 - 2022 RBB Grayson	8,983,858
21	APCO: 2020-2021 MW Upgrades	1,508,080
22	APCO: 2021 - 2023 RBB LOGAN &	3,052,352
23	APCO-D	4,091,476
24	APCo-D Service Restoration Blk	1,667,233
25	APCo-D Small Cap Adds Blkt	1,454,077
26	APCO-D Telecom	1,272,574
27	APCo-D Third Party Work Blkt	1,880,559
28	APCo-T Work	1,618,673
29	APCo-T Work 1	1,773,536
30	APCO-Tranco Line Rebuild-T	2,275,019
31	Berry Hill Station	2,385,013
32	CIS-Common Deployment-APC D	1,193,067
33	CLH 3 Tailrace Disolved Oxygen	1,089,241
34	CLH 4 Tailrace Disolved Oxygen	1,089,241
35	Corp Prgrm Billing - APCO Tran	2,381,824
36	D/AP/Capital Blanket - APCo	1,744,799
37	D/AP/Distribution Work	8,594,082
38	MT CI SCR CATALYST 2ND LAYER	1,315,490
39	MT ELG/CCR Compliance	26,525,517
40	MT HP TURBINE CP REFURBISH	2,890,247
41	NIH RELICENSE NIAGARA HYDRO	1,491,701
42	Purchase New APCO HDQ Building	3,744,636
43	Roanoke, VA TOC	86,972,799
44	SS-CI-APCo-D GEN PLT	4,669,975
45	SS-CI-APCo-T GEN PLT	1,241,907
46	T/AP/Capital Blanket - APCo	3,738,868
47	Ds-Ap-Virg-Ai Recloser Repl	1,643,775
48	T/AP/Charleston to Roanoke Tel	1,235,766
49	T/AP/CrningGls-Rdgewy69kv:Relo	4,203,842
50	T/AP/Danville - Martinsville T	1,869,999
51	T/AP/NERC Physical Security	16,605,575
52	T/AP/Roanoke to Kingsport Tele	2,884,691
53	T/AP/Sheridan Trans CI	1,428,168
54	Teays Valley SC Land Purchase	1,183,128
55	U3 IP ROTOR & CYLINDER REFURBI	2,183,702
56	Unit 2 Turbine Rotors A & B	2,811,644
57	Ds-AP-WVirg-AI Recloser Repl	2,034,716
58	Wo 020749999	3,920,666
59	WS-CI-APCo-G PPB	29,576,033
60	Ed-Ci-Apco-D Ast Imp	25,198,994
61	Ed-Ci-Apco-D Cust Serv	1,854,744
62	Forestry - APCo-T	1,133,619
63	GT1A Hot Gas Path	1,944,901
64	GT1B Hot Gas Path	1,606,722
65	John Vaughan Truck Garage	3,378,768
66	Other Minor Projects under $1,000,000	50,368,652
43	Total	471,403,315

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
Explain in a footnote any important adjustments during year. Explain in a footnote any difference between the amount for book cost of plant retired, Line 12, column (c), and that reported for electric plant in service, page 204, column (d), excluding retirements of non-depreciable property. 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. Show separately interest credits under a sinking fund or similar method of depreciation accounting.
Line No.	Item (a)	Total (c + d + e) (b)	Electric Plant in Service (c)	Electric Plant Held for Future Use (d)	Electric Plant Leased To Others (e)
Section A. Balances and Changes During Year
1	AccumulatedProvisionForDepreciationOfElectricUtilityPlant Balance Beginning of Year	5,301,060,976	5,301,065,124	4,148
2	Depreciation Provisions for Year, Charged to
3	DepreciationExpenseExcludingAdjustments (403) Depreciation Expense	498,113,773	498,113,773
4	DepreciationExpenseForAssetRetirementCosts (403.1) Depreciation Expense for Asset Retirement Costs	3,452,247	3,452,247
5	ExpensesOfElectricPlantLeasedToOthers (413) Exp. of Elec. Plt. Leas. to Others
6	TransportationExpensesClearing Transportation Expenses-Clearing
7	OtherClearingAccounts Other Clearing Accounts	690,473	690,473
8	OtherAccounts Other Accounts (Specify, details in footnote):
9.1	Other Accounts (Specify, details in footnote):	350,671	(a) 350,671
10	DepreciationProvision TOTAL Deprec. Prov for Year (Enter Total of lines 3 thru 9)	501,905,823	501,905,823
11	Net Charges for Plant Retired:
12	BookCostOfRetiredPlant Book Cost of Plant Retired	128,014,780	128,014,780
13	CostOfRemovalOfPlant Cost of Removal	60,429,540	(b) 60,429,540
14	SalvageValueOfRetiredPlant Salvage (Credit)	12,885,382	(c) 12,885,382
15	NetChargesForRetiredPlant TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14)	175,558,938	175,558,938
16	OtherAdjustmentsToAccumulatedDepreciation Other Debit or Cr. Items (Describe, details in footnote):
17.1	Other Debit or Cr. Items (Describe, details in footnote):
18	BookCostOfAssetRetirementCosts Book Cost or Asset Retirement Costs Retired
19	AccumulatedProvisionForDepreciationOfElectricUtilityPlant Balance End of Year (Enter Totals of lines 1, 10, 15, 16, and 18)	5,627,407,860	5,627,412,008	4,148
Section B. Balances at End of Year According to Functional Classification
20	AccumulatedDepreciationSteamProduction Steam Production	2,694,240,440	2,694,240,440
21	AccumulatedDepreciationNuclearProduction Nuclear Production
22	AccumulatedDepreciationHydraulicProductionConventional Hydraulic Production-Conventional	73,678,460	73,678,460
23	AccumulatedDepreciationHydraulicProductionPumpedStorage Hydraulic Production-Pumped Storage	92,462,599	92,462,599
24	AccumulatedDepreciationOtherProduction Other Production	248,613,514	248,613,514
25	AccumulatedDepreciationTransmission Transmission	799,298,358	799,302,506	4,148
26	AccumulatedDepreciationDistribution Distribution	1,621,676,367	1,621,676,367
27	AccumulatedDepreciationRegionalTransmissionAndMarketOperation Regional Transmission and Market Operation
28	AccumulatedDepreciationGeneral General	97,438,122	97,438,122
29	AccumulatedProvisionForDepreciationOfElectricUtilityPlant TOTAL (Enter Total of lines 20 thru 28)	5,627,407,860	5,627,412,008	4,148

FOOTNOTE DATA

(a) Concept: OtherAccounts


FERC Generation Wholesale Amortization-Clinch River ARO			-32,124
KGPCo Wholesale Amortiation-Clinch River ARO			-50,700
Generation Wholesale Expense-1823377 VA Plants			-103,875
KGPCo Wholesale Expense-1823377 VA Plants			-163,972

			-350,671

(b) Concept: CostOfRemovalOfPlant

Includes $10,938,351 of removal cost in retirement work in progress (RWIP).

Includes ($7,726,052) of salvage in retirement work in progress (RWIP).

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)
Report below investments in Account 123.1, Investments in Subsidiary Companies. Provide a subheading for each company and list thereunder 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. Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for Account 418.1. 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. 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. Report column (f) interest and dividend revenues from investments, including such revenues from securities disposed of during the year. In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (or the other amount at which carried in the books of account if different from cost) and the selling price thereof, not including interest adjustment includible in column (f). Report on Line 42, column (a) the TOTAL cost of Account 123.1.
Line No.	DescriptionOfInvestmentsInSubsidiaryCompanies Description of Investment (a)	DateOfAcquisitionInvestmentsInSubsidiaryCompanies Date Acquired (b)	DateOfMaturityInvestmentsInSubsidiaryCompanies Date of Maturity (c)	InvestmentInSubsidiaryCompanies Amount of Investment at Beginning of Year (d)	EquityInEarningsOfSubsidiaryCompanies Equity in Subsidiary Earnings of Year (e)	InterestAndDividendRevenueFromInvestments Revenues for Year (f)	InvestmentInSubsidiaryCompanies Amount of Investment at End of Year (g)	InvestmentGainLossOnDisplosal Gain or Loss from Investment Disposed of (h)
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			3,000
5	Capital Contributions Central Appalachian Coal Company	10/09/1990		449,990			449,990
6	Undistributed earnings/losses and dividends - Central Appalachian Coal			194,057			194,057
7	Central Coal Company
8	SEC File 70-1770, 4-30-48
9	1,500 shares common stock			1,500			1,500
10	Capital Contributions Central Coal Company			602,368			602,368
11	Investment in Central Coal Company
12	Southern Appalachian Coal Company
13	SEC File 70-5144, 3-23-72
14	6,950 shares common stock			6,950			6,950
15	Capital Contributions - Southern Appalachian Coal Company
16	Investment in Premium on Common Stock			900,000			900,000
17	Undistributed earnings/losses and dividends - Southern Appalachian Coal Company			690,462			690,462
18	Cedar Coal Company
19	SEC File 70-5470, 4-30-74
20	2,000 shares common stock	04/10/1974		200,000			200,000
21	Capital Contributions - Cedar Coal			4,868,403			4,868,403
22	Investment in Subsidiary AOCI			175,807		616,541	792,348
23	Undistributed earnings/losses and dividends - Cedar Coal Company			2,483,074			2,483,074
42	Total Cost of Account 123.1 $		Total	5,257,849		616,541	4,641,308

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

MATERIALS AND SUPPLIES
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. 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 No.	Account (a)	Balance Beginning of Year (b)	Balance End of Year (c)	Department or Departments which Use Material (d)
1	Fuel Stock (Account 151)	182,954,925	61,380,905	Electric
2	Fuel Stock Expenses Undistributed (Account 152)	10,651,652	5,704,904	Electric
3	Residuals and Extracted Products (Account 153)	4,821	6,791	Electric
4	Plant Materials and Operating Supplies (Account 154)
5	Assigned to - Construction (Estimated)	52,071,664	63,761,224	Electric
6	Assigned to - Operations and Maintenance
7	Production Plant (Estimated)	45,758,604	43,429,835	Electric
8	Transmission Plant (Estimated)	67,643	220,485	Electric
9	Distribution Plant (Estimated)	1,009,953	1,249,262	Electric
10	Regional Transmission and Market Operation Plant (Estimated)
11	Assigned to - Other (provide details in footnote)	(a) 297,940	(b) 393,051	Electric
12	TOTAL Account 154 (Enter Total of lines 5 thru 11)	99,205,804	109,053,857
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	292,817,202	176,146,456

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: PlantMaterialsAndOperatingSuppliesOther

Assigned to - Other includes Customer Account, Administrative, and General Expenses.

(b) Concept: PlantMaterialsAndOperatingSuppliesOther

Assigned to - Other includes Customer Account, Administrative, and General Expenses.

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

Allowances (Accounts 158.1 and 158.2)
Report below the particulars (details) called for concerning allowances. Report all acquisitions of allowances at cost. 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. 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). Report on Line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40. Report on Line 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. Report on Lines 8-14 the names of vendors/transferors of allowances acquired and identify associated companies (See "associated company" under "Definitions" in the Uniform System of Accounts). Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of and identify associated companies. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.
		Current Year		Year One		Year Two		Year Three		Future Years		Totals
Line No.	SO2 Allowances Inventory (Account 158.1) (a)	No. (b)	Amt. (c)	No. (d)	Amt. (e)	No. (f)	Amt. (g)	No. (h)	Amt. (i)	No. (j)	Amt. (k)	No. (l)	Amt. (m)
1	Balance-Beginning of Year	1,103,940	22,346,849	185,894		185,894		185,897		4,207,923		5,869,548	22,346,849
2
3	Acquired During Year:
4	Issued (Less Withheld Allow)	4,404								162,274		166,678
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	18,860	228,367									18,860	228,367
19	Other:
20	Allowances Used
20.1	Allowances Used
21	Cost of Sales/Transfers:
22	Consent Decree Surrenders			149,133								149,133
23
24
25
26
27
28	Total			149,133								149,133
29	Balance-End of Year	1,089,484	(a) 22,118,482	36,761		185,894		185,894		4,370,197		5,868,230	22,118,482
30
31	Sales:
32	Net Sales Proceeds(Assoc. Co.)
33	Net Sales Proceeds (Other)
34	Gains
35	Losses
	Allowances Withheld (Acct 158.2)
36	Balance-Beginning of Year	1,746		1,746		1,746		1,746		95,375		102,359
37	Add: Withheld by EPA									3,491		3,491
38	Deduct: Returned by EPA
39	Cost of Sales	1,746								1,745		3,491
40	Balance-End of Year			1,746		1,746		1,746		97,121		102,359
41
42	Sales
43	Net Sales Proceeds (Assoc. Co.)
44	Net Sales Proceeds (Other)
45	Gains
46	Losses

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: AllowanceInventory

NOX has no book value associated with the quantity. $75,200 is for 10,010 units of CO2, that was purchased in December 2020.

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

Allowances (Accounts 158.1 and 158.2)
Report below the particulars (details) called for concerning allowances. Report all acquisitions of allowances at cost. 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. 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). Report on Line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40. Report on Line 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. Report on Lines 8-14 the names of vendors/transferors of allowances acquired and identify associated companies (See "associated company" under "Definitions" in the Uniform System of Accounts). Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of and identify associated companies. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.
		Current Year		Year One		Year Two		Year Three		Future Years		Totals
Line No.	NOx Allowances Inventory (Account 158.1) (a)	No. (b)	Amt. (c)	No. (d)	Amt. (e)	No. (f)	Amt. (g)	No. (h)	Amt. (i)	No. (j)	Amt. (k)	No. (l)	Amt. (m)
1	Balance-Beginning of Year	75,371	75,200	22,058		22,058		22,055				141,542	75,200
2
3	Acquired During Year:
4	Issued (Less Withheld Allow)	3,182		4,929		4,929		4,929				17,969
5	Returned by EPA
6
7
8	Purchases/Transfers:
9	Chicago Climate Exchange	150,000	1,329,300									150,000	1,329,300
10	Other
11
12
13
14
15	Total	150,000	1,329,300									150,000	1,329,300
16
17	Relinquished During Year:
18	Charges to Account 509	108,668	728,776									108,668	728,776
19	Other:
20	Allowances Used
20.1	Allowances Used
21	Cost of Sales/Transfers:
22	Wolverine Power Supply Cooperative, Inc.	1,120										1,120
23
24
25
26
27
28	Total	1,120										1,120
29	Balance-End of Year	112,401	(a) 675,724	17,129		17,129		17,129				163,788	675,724
30
31	Sales:
32	Net Sales Proceeds(Assoc. Co.)
33	Net Sales Proceeds (Other)
34	Gains
35	Losses
	Allowances Withheld (Acct 158.2)
36	Balance-Beginning of Year
37	Add: Withheld by EPA
38	Deduct: Returned by EPA
39	Cost of Sales
40	Balance-End of Year
41
42	Sales
43	Net Sales Proceeds (Assoc. Co.)
44	Net Sales Proceeds (Other)
45	Gains
46	Losses

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: AllowanceInventory

NOX has no book value associated with the quantity. $75,200 is for 10,010 units of CO2, that was purchased in December 2020.

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

EXTRAORDINARY PROPERTY LOSSES (Account 182.1)
				WRITTEN OFF DURING YEAR
Line No.	DescriptionOfExtraordinaryPropertyLoss Description of Extraordinary Loss [Include in the description the date of Commission Authorization to use Acc 182.1 and period of amortization (mo, yr to mo, yr).] (a)	ExtraordinaryPropertyLossesNotYetRecognized Total Amount of Loss (b)	ExtraordinaryPropertyLossesRecognized Losses Recognized During Year (c)	ExtraordinaryPropertyLossesWrittenOffAccountCharged Account Charged (d)	ExtraordinaryPropertyLossesWrittenOff Amount (e)	ExtraordinaryPropertyLosses Balance at End of Year (f)
1	(a) Bluefield Office Building	365,177	6,087
2	(b) Glen Lyn Unit 6	5,703,621	125,660			4,232,368
3	(c) Kanawha Plant	27,432,795	1,091,892			20,564,098
4	(d) Sporn Plant	10,478,046	458,519			7,779,589
5	(e) Clinch River Plant Coal Assets	58,709,555	1,720,913			46,506,344
20	TOTAL	102,689,194	3,403,071			79,082,399

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: DescriptionOfExtraordinaryPropertyLoss

Authorized by the West Virginia commission on April 10, 2006. Amortization period: April 2006 to March 2021.

(b) Concept: DescriptionOfExtraordinaryPropertyLoss

Authorized by the West Virginia commission on May 26, 2015. Amortization period: June 2015 to July 2032.

Authorized by the West Virginia commission on May 26, 2015. Amortization period: June 2015 to July 2041.

(d) Concept: DescriptionOfExtraordinaryPropertyLoss

Authorized by the West Virginia commission on May 26, 2015. Amortization period: June 2015 to February 2040.

(e) Concept: DescriptionOfExtraordinaryPropertyLoss

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.

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.2)
				WRITTEN OFF DURING YEAR
Line No.	DescriptionOfUnrecoveredPlantAndRegulatoryStudyCosts Description of Unrecovered Plant and Regulatory Study Costs [Include in the description of costs, the date of COmmission Authorization to use Acc 182.2 and period of amortization (mo, yr to mo, yr)] (a)	UnrecoveredPlantAndRegulatoryStudyCostsNotYetRecognized Total Amount of Charges (b)	UnrecoveredPlantAndRegulatoryStudyCostsRecognized Costs Recognized During Year (c)	UnrecoveredPlantAndRegulatoryStudyCostsWrittenOffAccountCharged Account Charged (d)	UnrecoveredPlantAndRegulatoryStudyCostsWrittenOff Amount (e)	UnrecoveredPlantAndRegulatoryStudyCosts Balance at End of Year (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

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

Transmission Service and Generation Interconnection Study Costs
Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and generator interconnection studies. List each study separately. In column (a) provide the name of the study. In column (b) report the cost incurred to perform the study at the end of period. In column (c) report the account charged with the cost of the study. In column (d) report the amounts received for reimbursement of the study costs at end of period. In column (e) report the account credited with the reimbursement received for performing the study.
Line No.	DescriptionOfStudyPerformed Description (a)	StudyCostsIncurred Costs Incurred During Period (b)	StudyCostsAccountCharged Account Charged (c)	StudyCostsReimbursements Reimbursements Received During the Period (d)	StudyCostsAccountReimbursed Account Credited With Reimbursement (e)
1	Transmission Studies
2	AE1-064	4,899	186	4,039	186
3	AE1-108	54,704	186	52,257	186
4	AE1-108	39,996	186	39,951	186
5	AE1-250	169,089	186	152,264	186
6	AE2-160	2,870	186	1,200	186
7	AF1-049	8,951	186	8,808	186
8	AF1-323	54,430	186	53,286	186
9	AF2-382	13,265	186	12,908	186
10	AG1-089	1,143	186	1,029	186
11	AG1-091	7,706	186	7,264	186
12	AG1-092	5,651	186	5,353	186
13	AG1-124	1,373	186	1,197	186
14	AG1-136	4,416	186	3,985	186
15	AG1-162	4,482	186	3,954	186
16	AG1-194	1,340	186	1,196	186
17	AG1-219	1,880	186	1,670	186
18	AG1-234	2,118	186	2,118	186
19	AG1-311	1,214	186	1,130	186
20	AG1-316	1,915	186	2,066	186
21	AG1-468	1,901	186	2,776	186
22	AG1-508	3,377	186	3,874	186
23	AG1-509	2,775	186	3,073	186
24	AG1-528	1,597	186	1,475	186
25	AG1-540	663	186	813	186
26	AG2-127	1,991	186	1,960	186
27	AG2-132	1,421	186	1,390	186
28	AG2-168	2,069	186	2,046	186
29	AG2-187	1,732	186	1,700	186
30	AG2-190	392	186	392	186
31	AG2-202	1,776	186	1,742	186
32	AG2-203	1,936	186	1,901	186
33	AG2-311	873	186	843	186
34	AG2-368	1,455	186	1,421	186
35	AG2-568	1,534	186	1,481	186
36	AG2-657	1,278	186	1,218	186
37	PJM - #AD1-017	24	186	519	186
38	PJM - #AD1-102	28,502	186	35,046	186
39	PJM - #AD2-022	166	186
40	PJM - #AD2-022	40,449	186	88,543	186
41	PJM - #AD2-178	9,053	186	38,753	186
42	PJM - #AD2-178	31	186
43	PJM - #AD2-179	32,903	186	40,002	186
44	PJM - #AD2-179	34	186
45	PJM - #AE1-121	2,917	186	17,733	186
46	PJM - #AE1-130	1,228	186	1,425	186
47	PJM - #AE1-176	22	186
48	PJM - #AE1-212	15,179	186	35,208	186
49	PJM - #AE1-250	2,171	186	2,377	186
50	PJM - #AE2-047	16,425	186	35,237	186
51	PJM - #AE2-047	57	186
52	PJM - #AE2-140	61,112	186	68,114	186
53	PJM - #AE2-140	369	186
54	PJM - #AE2-166	7,937	186	44,199	186
55	PJM - #AE2-166	70	186
56	PJM - #AE2-185	60	186
57	PJM - #AE2-280	154,449	186	141,255	186
58	PJM - #AE2-280	39	186
59	PJM - #AE2-280	63	186
60	PJM - #AE2-292	18	186
61	PJM - #AE2-326	2,771	186	3,752	186
62	PJM - #AF1-049	151	186
63	PJM - #AF1-323	95	186
64	PJM - #AF1-323	104	186
65	PJM - #AF2-105	261	186
66	PJM - #AF2-105	1,014	186	1,014	186
67	PJM - #AF2-106	375	186
68	PJM - #AF2-106	1,376	186	1,402	186
69	PJM - #AF2-107	133	186
70	PJM - #AF2-107	1,052	186	1,078	186
71	PJM - #AF2-220	219	186
72	PJM - #AF2-291	147	186
73	PJM - #AF2-291	764	186	790	186
74	PJM - #AF2-302	168	186
75	PJM - #AF2-302	884	186	810	186
76	PJM - #AF2-382	167	186
77	PJM - #AF2-382	2,340	186	2,218	186
78	PJM - #AG1-022	1,733	186	2,142	186
79	PJM - #AG1-089	1,483	186	2,196	186
80	PJM - #AG1-091	726	186
81	PJM - #AG1-092	772	186
82	PJM - #AG1-123	2,484	186	2,957	186
83	PJM - #AG1-124	1,453	186	1,846	186
84	PJM - #AG1-136	1,318	186	1,822	186
85	PJM - #AG1-155	1,677	186	2,577	186
86	PJM - #AG1-194	1,038	186	1,434	186
87	PJM - #AG1-219	1,784	186	2,273	186
88	PJM - #AG1-240	473	186	1,004	186
89	PJM - #AG1-311	1,603	186	2,296	186
90	PJM - #AG1-314	385	186	789	186
91	PJM - #AG1-426	1,374	186	1,916	186
92	PJM - #AG1-494	1,560	186	1,960	186
93	PJM - #AG1-528	1,641	186	2,358	186
94	PJM - AF1-173	5	186
95	PJM AC1-122 & 123			49	186
96	PJM AC2-123	2,353	186	8,817	186
20	Total
21	Generation Studies
39	Total
40	Grand Total

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

OTHER REGULATORY ASSETS (Account 182.3)
Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable. 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. For Regulatory Assets being amortized, show period of amortization.
				CREDITS
Line No.	DescriptionAndPurposeOfOtherRegulatoryAssets Description and Purpose of Other Regulatory Assets (a)	OtherRegulatoryAssets Balance at Beginning of Current Quarter/Year (b)	IncreaseDecreaseInOtherRegulatoryAssets Debits (c)	OtherRegulatoryAssetsWrittenOffAccountCharged Written off During Quarter/Year Account Charged (d)	OtherRegulatoryAssetsWrittenOffRecovered Written off During the Period Amount (e)	OtherRegulatoryAssets Balance at end of Current Quarter/Year (f)
1	Under Recovery of PJM True-Up	1,194,294	3,499,837	(a) 447	4,694,131
2	SFAS 112 Postemployment Benefits - Rate Order: WV PSC Case 14-1152-E-42T	13,535,266	161,408	228	427,503	13,269,171
3	Demand Side Management Under Recovery - Rate Order: WV Public Service Commission - Case No: 10-0261-E-GI - Case No: WV PSC Case 15-0301-E-GI	6,746,972	4,572,124	(b) 908	1,422,432	9,896,664
4	Unrealized Loss on Forward Commitments	5,235,279	15,628,050	(c) 244, 254, 175	14,230,672	3,837,901
5	Netting of Trading Activities related to Unrealized Gains/Losses on Forward Commitments between Regulated Assets/Liabilities	5,235,279	14,230,672	254	15,628,050	3,837,901
6	Environmental Compliance Costs - Rate Orders: VA Code Section 56-582B (vi) VASCCPUE-2005-00056 - Amortization Period: 01/2021 - 12/2023	196,781		407	65,594	131,187
7	Carrying Chgs-Capital Environmental Compliance Csts - Rate Orders: VA Code Section 56-582B (vi) VA SCC PUE-2005-00056 - Amortization Period: 01/2021 - 12/2023	100,873	33,624			67,249
8	Capital Environmental Equity Costs - Rate Orders: VA Code Section 56-582B (vi) VA SCC PUE-2005-00056 - Amortization Period: 01/2021 - 12/2023	12,017	4,006			8,011
9	Defd System Reliability Costs - Rate Orders: VA Code Section 56-582B (vi) VA SCC PUE-2005-00056 - Amortization Period: 01/2021 - 12/2023	75,018		182/407	44,943	30,075
10	Equity Costs - Capital Reliability - Rate Orders: VA Code Section 56-582B (vi) VA SCC PUE-2005-00056 - Amortization Period: 01/2021 - 12/2023	44,977	4,349			40,628
11	Defd Carrying Charges - Reliability Capital - Rate Orders: VA Code Section 56-582B (vi) VA SCC PUE-2005-00056 - Amortization Period: 01/2021 - 12/2023	54,445	19,734			74,179
12	Unrecovered Fuel Cost - VA	3,330,925	131,199,922	501	7,321,623	127,209,224
13	Unrecovered Fuel Cost - WV	4,263,215	94,936,489	254/501	26,530,749	72,668,955
14	SFAS 158 Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans	114,353,132	93,986,124	(d) 129, 228	145,643,703	62,695,553
15	VA Demand Response Program - Rate Order: VA SCC PUE-2011-0001	4,050,459	1,012,687	442/908	981,014	4,082,132
16	Dresden Operating Costs - VA - Rate Order: VA SCC PUE-2011-00036	3,090,646	2,670,301	403	2,424,452	3,336,495
17	SFAS 106 Medicare Subsidy - Amortization period - 1/2013 to 12/2024	2,355,273		926	588,818	1,766,455
18	SFAS 109 Deferred Federal Income Tax	98,076,992	62,555,566	282/283	63,982,724	96,649,834
19	SFAS 109 Deferred State Income Tax	258,429,068	52,140,209	282/283	79,305,907	231,263,370
20	Carbon Capture and Storage Project FEED Study Costs - Rate Order: WV PSC Case 13-0467-E-GI	260,520		506	183,897	76,623
21	WV Vegetation Management Program Costs - Rate Order: WV PSC Case 13-0557-E-P - Rate Order: WV PSC Case 14-1152-E-42T	45,368,828		593	33,459,373	11,909,455
22	NBV ARO's Retired Plants - Rate Order: VA SCC PUE-2014-0026 - Rate Order: WV PSC 14-1151-E-D	29,758,986		(e) 403	350,671	29,408,315
23	M&S Retiring Plants - Rate Order: VA SCC PUE-2014-0026 - Rate Order: WV PSC 14-1151-E-D	435,780		(f) 506	36,324	399,456
24	Unrecovered Fuel - Common Wealth Virginia - Per Agreement with Commonwealth of Virginia. Effective June 4, 2015.	266,029	1,166,691	254/501	39,581	1,393,139
25	WV Delayed Base Rate Increase - Case No. 16-0179-E-T-PC - Amortization Period: 7/2016 - 6/2018	570,865		921	570,865
26	WV Air Quality Permit Fees - Rate Order: WV 15-0722-E-P	390,830		506	123,420	267,410
27	WV EE/DR - Company Funded - Case No. PUE-2014-00039	4,701,148	84,000	(g) 908	940,216	3,844,932
28	Greenhat Default Contingency	5,366		(h) 232	5,366
29	WV Deferred Rate Case Expenses - WVPSC Case #18-0646-E-42T - Amortization Period: 03/2019 - 02/2022	207,526	79,015	928	256,894	29,647
30	VA Renewable Energy Portfolio Standard - VA SCC Case No. PUE-2009-00038	6,254,966	22,248,823	445/555	28,503,789
31	WV Felman Premium/Discount ENEC	2,585,697	2,585,697
32	COVID-19 Costs - WV General Order: WVPSC 262.4 - VA SCC Case No. PUR-2020-00074	5,238,190	5,422,420	(i) 426	2,629,923	8,030,687
33	Carrying Chgs-COVID-19 Costs - VA SCC Case No. PUR-2020-00074	79,658	427,820	182/431	7,413	500,065
34	Equity Carrying Chgs-COVID-19 Costs - VA SCC Case No. PUR-2020-00074	33,641	76	182/431	187,258	220,823
35	Glen Lyn Ash Pond ARO - VA HB443	198,802,442	90,729,926			289,532,368
36	Carrying Chgs-VA Broadband Pilot - VA SCC Case No. PUR-2019-00145	10,134	365,711	403/431	46,112	329,733
37	Equity Carrying Chgs-VA Broadband Pilot - VA SCC Case No. PUR-2019-00145	4,301	18,620	403/431	159,631	145,312
38	VA T-RAC Costs - VA SCC Case No. PUE-2009-00031	18,760,167	36,824,124	566	18,346,700	37,237,591
39	VA Retired Coal Plants - VA SCC Case No. PUR-2020-00015 - Amortization Period: 01/2020 - 05/2025	39,919,349		407	9,038,340	30,881,009
40	VA E-RAC CCR Expenses - VA SCC Case No. PUR-2020-00015 - Amortization Period: 10/2021 - 09/2022	9,257,000	8,153,428	501	4,763,104	12,647,324
41	VA Major Storm Expense - VA SCC Case No. PUR-2020-00015	3,476,775	12,147,916	571/593	473,768	15,150,923
42	VA Broadband Under Recovery		59,267	403	2	59,265
43	LSE Formula Rate Defer-Dep		2,695,884			2,695,884
44	WV Deferred Storm Expense		53,674,877			53,674,877
45	WV MRBC Surcharge Under Recovery		2,581,415	403	1,749,621	831,794
46	WV CCR/ELG AFUDC Deferral - Amortization Period: 09/2021 - 08/2022		1,107,808	403	465,343	642,465
47	VA Distribution Substation Depreciation Deferral		297,740			297,740
48	VA Distribution Substation Carrying Charge Deferral		976,499			976,499
49	VA Distribution Substation Equity Carrying Charge Deferral			182/431	696,172	696,172
50	VA E-RAC Deferral AFUDC - Amortization Period: 10/2021 - 09/2022		259,696	182	64,924	194,772
51	VA RGGI Deferral		624,847	509	283,866	340,981
52	VCEA Virginia RPS Under Recovery		9,258,775	182/557	7,108,932	2,149,843
53	VA E-RAC Under Recovery		1,333,385	501	1,099,703	233,682
54	APCO CRR Under Recovery		453,069	407	62,636	390,433
55	FERC Formula Rates Under Recovery		3,451,631			3,451,631
56	VA EE-RAC Under Recovery -Case No. PUR - 2017-00126	1,342,842	72,727	254	1,415,569
57	2020 PJM Transmission True-Up - VA SCC Case No. PUR-2020-00015	11,506,629	505,597	456	12,012,226
44	TOTAL	883,585,010	734,262,586		488,373,954	1,129,473,642

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged
234, 242, 456, 447, 229
(b) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged
440, 442, 908
(c) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged
244, 254, 175
(d) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged
228, 165, 242, 129
(e) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged
411, 403, 244
(f) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged
411, 506, 154
(g) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged
440, 442, 908
(h) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged
232, 253, 561, 566
(i) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged
903, 904, 426, 506

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

MISCELLANEOUS DEFFERED DEBITS (Account 186)
Report below the particulars (details) called for concerning miscellaneous deferred debits. For any deferred debit being amortized, show period of amortization in column (a) 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.
				CREDITS
Line No.	Description of Miscellaneous Deferred Debits (a)	Balance at Beginning of Year (b)	Debits (c)	Credits Account Charged (d)	Credits Amount (e)	Balance at End of Year (f)
1	Property Taxes West Virginia	76,829,307	84,151,835	107,408	82,438,126	78,543,016
2	Property Taxes Ohio	1,976,830	5,654,266	107,408	1,976,830	5,654,266
3	Agency Fees - Factored A/R	2,719,437	27,599,907	184,426	27,319,914	2,999,430
4	Labor Accruals - Balance Sheet	665	72,198	183.152	71,370	1,493
5	Miscellaneous	61,943	5,423,654	(a) 142, 143, 232, 253, 593, 243, 588	5,160,827	324,770
6	Property Taxes - Capital Leases West Virginia	86,985	778,570	408	778,570	86,985
7	Unamortized Credit Line Fees Amortization through June 2022	489,209	1,059,457	431,234	480,865	1,067,801
8	Def Lease Assets - Non Taxable	148,059	822,323	143,184	912,103	58,279
9	Deferred Urea Expense	993,226	25,586,429	(b) 142, 232, 154	23,976,990	2,602,665
10	VA Sales/Use Tax Surcharge	1,018,518	1,557,990	142	1,638,587	1,099,115
11	Estimated Barging Bills	256,399	67,576,611	(c) 234, 232, 151, 154	66,925,366	907,644
47	Miscellaneous Work in Progress	2,410,889				1,805,188
48	Deferred Regulatroy Comm. Expenses (See pages 350 - 351)
49	TOTAL	84,954,431				92,952,422

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: DecreaseInMiscellaneousDeferredExpenseAccountCharged

142, 143, 232, 253, 593, 243, 588

(b) Concept: DecreaseInMiscellaneousDeferredExpenseAccountCharged

142, 232, 154

151, 154, 232, 234

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

ACCUMULATED DEFERRED INCOME TAXES (Account 190)
Report the information called for below concerning the respondent’s accounting for deferred income taxes. At Other (Specify), include deferrals relating to other income and deductions.
Line No.	DescriptionOfAccumulatedDeferredIncomeTax Description and Location (a)	AccumulatedDeferredIncomeTaxes Balance at Beginning of Year (b)	AccumulatedDeferredIncomeTaxes Balance at End of Year (c)
1	Electric
2	Interest Expense Capitalized for Tax	51,506,694	52,039,166
3	CIAC	8,950,591	12,068,245
4	DSIT Normalized	16,391,724	12,165,004
5	Accrued Book Removal Costs	66,976,322	67,676,004
6	Accrued Book ARO Expenses	65,742,850	84,970,740
7	Other	27,368,254	26,378,365
8	TOTAL Electric (Enter Total of lines 2 thru 7)	236,936,435	255,297,524
9	Gas
15	Other
16	TOTAL Gas (Enter Total of lines 10 thru 15)
17.1	Other (Specify)	257,907,218	233,465,850
17	Other (Specify)
18	TOTAL (Acct 190) (Total of lines 8, 16 and 17)	494,843,653	488,763,374

Notes

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

CAPITAL STOCKS (Account 201 and 204)
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. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year. Give details concerning shares of any class and series of stock authorized to be issued by a regulatory commission which have not yet been issued. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or noncumulative. State in a footnote if any capital stock that 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 purpose of pledge.
Line No.	Class and Series of Stock and Name of Stock Series (a)	Number of Shares Authorized by Charter (b)	Par or Stated Value per Share (c)	Call Price at End of Year (d)	Outstanding per Bal. Sheet (Total amount outstanding without reduction for amounts held by respondent) Shares (e)	Outstanding per Bal. Sheet (Total amount outstanding without reduction for amounts held by respondent) Amount (f)	Held by Respondent As Reacquired Stock (Acct 217) Shares (g)	Held by Respondent As Reacquired Stock (Acct 217) Cost (h)	Held by Respondent In Sinking and Other Funds Shares (i)	Held by Respondent In Sinking and Other Funds Amount (j)
1	Common Stock (Account 201)
2		30,000,000			13,499,500	260,457,768
5	Total	30,000,000			13,499,500	260,457,768
6	Preferred Stock (Account 204)
7
8
9
10	Total
1	Capital Stock (Accounts 201 and 204) - Data Conversion
2
3
4
5	Total

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

2022-05-19

Year/Period of Report

End of:

2021

Other Paid-in Capital
1. 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 a total of all accounts for reconciliation with the balance sheet, page 112. Explain changes made in any account during the year and give the accounting entries effecting such change. Donations Received from Stockholders (Account 208) - State amount and briefly explain the origin and purpose of each donation. Reduction in Par or Stated Value of Capital Stock (Account 209) - State amount and briefly explain the capital changes that gave rise to amounts reported under this caption including identification with the class and series of stock to which related. Gain or 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. Miscellaneous Paid-In Capital (Account 211) - Classify amounts included in this account according to captions that, together with brief explanations, disclose the general nature of the transactions that gave rise to the reported amounts.
Line No.	Item (a)	Amount (b)
1	DonationsReceivedFromStockholdersAbstract Donations Received from Stockholders (Account 208)
2	DonationsReceivedFromStockholders Beginning Balance Amount	1,825,984,502
3.1	IncreasesDecreasesFromSalesOfDonationsReceivedFromStockholders Increases (Decreases) from Sales of Donations Received from Stockholders
4	DonationsReceivedFromStockholders Ending Balance Amount	1,825,984,502
5	ReductionInParOrStatedValueOfCapitalStockAbstract Reduction in Par or Stated Value of Capital Stock (Account 209)
6	ReductionInParOrStatedValueOfCapitalStock Beginning Balance Amount	433
7.1	IncreasesDecreasesDueToReductionsInParOrStatedValueOfCapitalStock Increases (Decreases) Due to Reductions in Par or Stated Value of Capital Stock
8	ReductionInParOrStatedValueOfCapitalStock Ending Balance Amount	433
9	GainOrResaleOrCancellationOfReacquiredCapitalStockAbstract Gain or Resale or Cancellation of Reacquired Capital Stock (Account 210)
10	GainOnResaleOrCancellationOfReacquiredCapitalStock Beginning Balance Amount
11.1	IncreasesDecreasesFromGainOrResaleOrCancellationOfReacquiredCapitalStock Increases (Decreases) from Gain or Resale or Cancellation of Reacquired Capital Stock
12	GainOnResaleOrCancellationOfReacquiredCapitalStock Ending Balance Amount
13	MiscellaneousPaidInCapitalAbstract Miscellaneous Paid-In Capital (Account 211)
14	MiscellaneousPaidInCapital Beginning Balance Amount	2,642,015
15.1	IncreasesDecreasesDueToMiscellaneousPaidInCapital Increases (Decreases) Due to Miscellaneous Paid-In Capital
16	MiscellaneousPaidInCapital Ending Balance Amount	2,642,015
17	OtherPaidInCapitalAbstract Historical Data - Other Paid in Capital
18	OtherPaidInCapitalDetail Beginning Balance Amount
19.1	IncreasesDecreasesInOtherPaidInCapital Increases (Decreases) in Other Paid-In Capital
20	OtherPaidInCapitalDetail Ending Balance Amount
40	OtherPaidInCapital Total	1,828,626,950

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

CAPITAL STOCK EXPENSE (Account 214)
Report the balance at end of the year of discount on capital stock for each class and series of capital stock. 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 No.	NameOfClassAndSeriesOfStock Class and Series of Stock (a)	CapitalStockExpense Balance at End of Year (b)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22	TOTAL

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

LONG-TERM DEBT (Account 221, 222, 223 and 224)
Report by Balance Sheet Account the details concerning long-term debt included in Accounts 221, Bonds, 222, Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other Long-Term Debt. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds, and in column (b) include the related account number. 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, and in column (b) include the related account number. For receivers' certificates, show in column (a) the name of the court and date of court order under which such certificates were issued, and in column (b) include the related account number. In a supplemental statement, 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) principal repaid during year. Give Commission authorization numbers and dates. If the respondent has pledged any of its long-term debt securities, give particulars (details) in a footnote, including name of the pledgee and purpose of the pledge. If the respondent has any long-term securities that have been nominally issued and are nominally outstanding at end of year, describe such securities in a footnote. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest expense in column (m). Explain in a footnote any difference between the total of column (m) and the total Account 427, Interest on Long-Term Debt and Account 430, Interest on Debt to Associated Companies. Give details concerning any long-term debt authorized by a regulatory commission but not yet issued.
Line No.	ClassAndSeriesOfObligationCouponRateDescription Class and Series of Obligation, Coupon Rate (For new issue, give commission Authorization numbers and dates) (a)	RelatedAccountNumber Related Account Number (b)	Principal Amount of Debt Issued (c)	LongTermDebtIssuanceExpensePremiumOrDiscount Total Expense, Premium or Discount (d)	LongTermDebtIssuanceExpenses Total Expense (e)	LongTermDebtPremium Total Premium (f)	LongTermDebtDiscount Total Discount (g)	NominalDateOfIssue Nominal Date of Issue (h)	DateOfMaturity Date of Maturity (i)	AmortizationPeriodStartDate AMORTIZATION PERIOD Date From (j)	AmortizationPeriodEndDate AMORTIZATION PERIOD Date To (k)	Outstanding (Total amount outstanding without reduction for amounts held by respondent) (l)	Interest for Year Amount (m)
1	Bonds (Account 221)
2	Appalachian Consumer Rate Relief Funding LLC
3	Tranche A-1, 2.0076%, Due 2024		215,800,000		2,416,193		(a) 9,879	11/15/2013	02/01/2024	11/15/2013	02/01/2023	35,579,231	1,131,296
4	- Expense, Premium (P), Discount (D)
5	Tranche A-2, 3.7722%, Due 2031		164,500,000		1,841,815		(b) 7,530	11/15/2013	08/01/2031	11/15/2013	08/01/2028	164,500,000	5,960,601
6	Subtotal		380,300,000		4,258,008		17,409					200,079,231	7,091,897
7	Reacquired Bonds (Account 222)
8
9
10
11	Subtotal
12	Advances from Associated Companies (Account 223)
13
14
15
16	Subtotal
17	Other Long Term Debt (Account 224)
18
19
20
21	Subtotal		5,151,059,040		47,474,940		22,647,500					4,782,910,721	204,855,741
33	TOTAL		5,531,359,040									4,982,989,952	211,947,638

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: BondsDiscount

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.

(b) Concept: BondsDiscount

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.

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
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. 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. 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 No.	Particulars (Details) (a)	Amount (b)
1	Net Income for the Year (Page 117)	348,937,055
2	Reconciling Items for the Year
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	36,688,668
28	Show Computation of Tax:
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

TAXES ACCRUED, PREPAID AND CHARGES DURING YEAR
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 known, show the amounts in a footnote and designate whether estimated or actual amounts. 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 (g) and (h). The balancing of this page is not affected by the inclusion of these taxes. Include in column (g) 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. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained. If any tax (exclude Federal and State income taxes) covers more than one year, show the required information separately for each tax year, identifying the year in column (d). Enter all adjustments of the accrued and prepaid tax accounts in column (i) and explain each adjustment in a foot- note. Designate debit adjustments by parentheses. 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. Report in columns (l) through (o) how the taxes were distributed. Report in column (o) 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 409.1 pertaining to other utility departments and amounts charged to Accounts 408.2 and 409.2. Also shown in column (o) the taxes charged to utility plant or other balance sheet accounts. 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 BEGINNING OF YEAR					BALANCE AT END OF YEAR		DISTRIBUTION OF TAXES CHARGED
Line No.	DescriptionOfTaxesAccruedPrepaidAndCharged Kind of Tax (See Instruction 5) (a)	TypeOfTax Type of Tax (b)	TaxJurisdiction State (c)	TaxYear Tax Year (d)	TaxesAccrued Taxes Accrued (Account 236) (e)	PrepaidTaxes Prepaid Taxes (Include in Account 165) (f)	TaxesCharged Taxes Charged During Year (g)	TaxesPaid Taxes Paid During Year (h)	TaxAdjustments Adjustments (i)	TaxesAccrued Taxes Accrued (Account 236) (j)	PrepaidTaxes Prepaid Taxes (Included in Account 165) (k)	TaxesAccruedPrepaidAndCharged Electric (Account 408.1, 409.1) (l)	IncomeTaxesExtraordinaryItems Extraordinary Items (Account 409.3) (m)	AdjustmentsToRetainedEarnings Adjustment to Ret. Earnings (Account 439) (n)	TaxesIncurredOther Other (o)
1		Federal Tax			10,400,223	0	4,943,740	32,552,283		38,008,766	0	9,367,566			4,423,826
2	Subtotal Federal Tax				10,400,223	0	4,943,740	32,552,283		38,008,766	0	9,367,566			4,423,826
3		Local Tax		2019	8,906	0				8,906	0
4		Local Tax	WV	2020	3,022,409	0	5,361	3,017,048		0	0				5,361
5		Local Tax	WV	2021	0	0	14,433,290	11,076,357		3,356,933	0	14,369,302			63,988
6	Subtotal Local Tax				3,031,315	0	14,427,929	14,093,405		3,365,839	0	14,369,302			58,627
7		Other Taxes	TN	2020
8		Other Taxes	TN	2021
9		Other Taxes	WV	2020	731,496	0		731,496		0	0
10		Other Taxes	WV	2021	0	0	1,463,000			1,463,000	0				1,463,000
11	Subtotal Other Tax				731,496	0	1,463,000	731,496		1,463,000	0				1,463,000
12		Property Tax	AR	2020	0	0	3,078	3,078		0	0				3,078
13		Property Tax	CO	2020	0	0	4,861	4,861		0	0				4,861
14		Property Tax	LA	2021	0	0	1,115	1,115		0	0				1,115
15		Property Tax	MO	2021	0	0	23,000	14,531		8,469	0				23,000
16		Property Tax	NE	2019	0	0	360	360		0	0				360
17		Property Tax	OH	2019	2,473,075	0	556,847	1,916,228		0	0	556,846			1
18		Property Tax	OH	2020	1,976,830	0	9	9		1,976,830	0	1,976,839			1,976,830
19		Property Tax	OH	2021	0	0	5,654,266			5,654,266	0				5,654,266
20		Property Tax	TN	2020	1,407,500	0	14,821	1,392,679		0	0	14,778			43
21		Property Tax	TN	2021	0	0	1,475,900			1,475,900	0	1,467,974			7,926
22		Property Tax	VA	2019	0	0	943	943		0	0	943
23		Property Tax	VA	2020	454,727	0	348,863	803,447		143	0	348,540			323
24		Property Tax	VA	2021	0	0	27,484,204	25,977,518		1,506,686	0	26,731,087			753,117
25		Property Tax	WV	2019	26,135,030	0	2,320	26,137,350		0	0	25,425,095			25,422,775
26		Property Tax	WV	2020	52,434,205	0	454,934	26,656,291		26,232,848	0	25,708,038			25,253,104
27		Property Tax	WV	2021	0	0	53,818,021	82		53,817,939	0	97,717			53,720,304
28		Property Tax	WY	2020	0	0	3,600	2,312		1,288	0				3,600
29		Property Tax	AL	2021	0	0	6	6		0	0				6
30	Subtotal Property Tax				84,881,367	0	88,703,812	82,910,810		90,674,369	0	81,184,609			7,519,203
31	UNEMPLOYMENT 2021	Unemployment Tax			13,695	0	80,710	76,346		18,059	0	47,778			32,932
32	STATE UNEMPLOYMENT 2021	Unemployment Tax	KY		296	0	317	317		296	0	3			320
33	STATE UNEMPLOYMENT 2021	Unemployment Tax	OH		337	0	3,579	3,204		712	0	2,324			1,255
34	STATE UNEMPLOYMENT 2021	Unemployment Tax	TN		1	0	4	2		3	0				4
35	STATE UNEMPLOYMENT 2021	Unemployment Tax	VA		8,627	0	47,531	45,848		10,310	0	29,575			17,956
36	STATE UNEMPLOYMENT 2021	Unemployment Tax	WV		21,651	0	201,276	194,703		28,224	0	124,223			77,053
37	Subtotal Unemployment Tax				44,607	0	333,417	320,420		57,604	0	203,897			129,520
38		Sales And Use Tax	OH	2020	26,156	15,000	8,889	2,267		0	0	1			8,888
39		Sales And Use Tax	OH	2021	0	0	181,533	115,350		79,133	12,950	715			182,248
40		Sales And Use Tax	TN	2019	0	0	112	112		0	0	97			15
41		Sales And Use Tax	TN	2020	6,375	100	100	6,375		0	0				100
42		Sales And Use Tax	TN	2021	0	0	2,191	1,483		708	0	1			2,190
43		Sales And Use Tax	VA	2020	180,102	0	62,349	242,451		0	0				62,349
44		Sales And Use Tax	VA	2021	0	0	2,945,721	2,637,029		308,692	0	113			2,945,834
45		Sales And Use Tax	WV	2020	255,954	1,371,756	1,777,633	661,831		0	0				1,777,633
46		Sales And Use Tax	WV	2021	0	0	3,703,012	5,210,147		348,533	1,855,668	816			3,702,196
47	Subtotal Sales And Use Tax				468,587	1,386,856	8,663,762	8,877,045		737,066	1,868,618	85			8,663,677
48		Income Tax	IL	2017	163,298	0				163,298	0
49		Income Tax	IL	2018	149,310	0	1			149,311	0				1
50		Income Tax	IL	2019	324,392	0				324,392	0
51		Income Tax	IL	2020	122,797	0	18,434			141,231	0				18,434
52		Income Tax	IL	2021	0	0	20,094			20,094	0	20,093			1
53		Income Tax	KY	2020	10,553	0	12,914			2,361	0				12,914
54		Income Tax	KY	2021	0	0	9,540			9,540	0	9,540
55		Income Tax	MI	2017	6,145	0				6,145	0
56		Income Tax	MI	2018	6,918	0				6,918	0
57		Income Tax	MI	2019	3,226	0				3,226	0
58		Income Tax	MI	2020	2,414	0				2,414	0
59		Income Tax	MI	2021		0	1,351			1,351	0	1,351
60		Income Tax	MULTI	2019	8,915	0				8,915	0
61		Income Tax	NOL	2011	0					0	0
62		Income Tax	TN	2002	0					0	0
63		Income Tax	TN	2016	4,104	0				4,104	0
64		Income Tax	TN	2017	501,938	0				501,938	0
65		Income Tax	TN	2018	432,375	0		16,345		416,030	0
66		Income Tax	TN	2019	204,591	0				204,591	0
67		Income Tax	TN	2020	467,901	0	16,583	20,300		504,784	0				16,583
68		Income Tax	TN	2021	0	0	56,581	147,400		90,819	0	56,581
69		Income Tax	VA	2020	0	0	8			8	0				8
70		Income Tax	VA	2021	0	0	8			8	0	8
71		Income Tax	WV	2002	0	0				0	0
72		Income Tax	WV	2017	1,489,463	0				1,489,463	0
73		Income Tax	WV	2018	767,996	0				767,996	0
74		Income Tax	WV	2019	17,011,204	0				17,011,204	0
75		Income Tax	WV	2020	447,758	0	382,402			830,160	0				382,402
76		Income Tax	WV	2021	0	0	2,504,514			2,504,514	0	2,504,514
77	Subtotal Income Tax				13,750,658	0	2,161,748	184,045		15,728,361	0	2,592,071			430,323
78		Excise Tax		2021	0	0	16,433	16,433		0	0	16,433
79					0	0				0	0
80	Subtotal Excise Tax				0	0	16,433	16,433		0	0	16,433
81		Franchise Tax	KY	2019	1,637	0				1,637	0
82		Franchise Tax	KY	2020	1,637	0				1,637	0
83		Franchise Tax	NC	2017	4,035	0	46			3,989	0	46
84		Franchise Tax	NC	2018	200	0				200	0
85		Franchise Tax	NC	2019	1,910	0				1,910	0
86		Franchise Tax	NC	2020	1,910	0				1,910	0
87		Franchise Tax	NC	2021	0	0	203	2,100		2,303	0	203
88		Franchise Tax	TN	2002	0	0	1,707			1,707	0	1,707
89		Franchise Tax	TN	2017	88,451	0				88,451	0
90		Franchise Tax	TN	2018	9,373	0				9,373	0
91		Franchise Tax	TN	2019	196,218	0				196,218	0
92		Franchise Tax	TN	2020	262,218	0				262,218	0
93		Franchise Tax	TN	2021	0	0	21,037			21,037	0	21,037
94		Franchise Tax	WV	2002	0	0	241,181			241,181	0	241,181
95	Subtotal Franchise Tax				559,519	0	221,694	2,100		779,113	0	221,694
96		Other State Tax	KY	2019	0	0	2,397	2,397		0	0				2,397
97		Other State Tax	OH	2020	24,900	0	24,580	320		0	0	24,580
98		Other State Tax	OH	2021	0	0	40,087	16,687		23,400	0	40,087
99		Other State Tax	VA	2017	0					0		218,918			218,918
100		Other State Tax	VA	2018	68,884	0				68,884	0
101		Other State Tax	VA	2019	2,350,989	0	1,625,253	1,625,277		2,350,965	0	1,625,253
102		Other State Tax	VA	2020	794,558	0	186,736	952,200		344,378	0	186,736
103		Other State Tax	VA	2021	0	0	9,185,822	6,421,600		2,764,222	0	9,185,822
104		Other State Tax	WV	2020	1,728,506	0	162,937	1,565,569		0	0	162,937
105		Other State Tax	WV	2021	0	0	34,762,184	32,682,591		2,079,593	0	38,031,196			3,269,012
106		Other State Tax	FIN48		0	0				0	0
107	Subtotal Other State Tax				128,091	0	41,986,190	40,011,293		2,102,988	0	45,038,681			3,052,491
108		Other License And Fees Tax	WV	2019	72	0				72	0
109		Other License And Fees Tax	WV	2020	240	0				240	0
110		Other License And Fees Tax	WV	2021	0	0		240		240	0
111	Subtotal Other License And Fees Tax				312	0		240		552	0
112	FICA 2021	Federal Insurance Tax			1,837,495	0	13,112,107	15,810,857	2,468,695	1,607,440	0	7,704,154			5,407,953
113	2360104 FICA	Federal Insurance Tax			2,832,986	0			2,832,986	0	0
114	2360105 FICA CARES ACT	Federal Insurance Tax			2,832,986	0			364,302	3,197,288	0
115	Subtotal Payroll Tax				7,503,467	0	13,112,107	15,810,857	11	4,804,728	0	7,704,154			5,407,953
40	TOTAL				100,698,572	1,386,856	176,033,832	195,510,427	11	81,703,750	1,868,618	160,698,492			15,335,340

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

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.
			Deferred for Year		Allocations to Current Year's Income
Line No.	Account Subdivisions (a)	Balance at Beginning of Year (b)	Account No. (c)	Amount (d)	Account No. (e)	Amount (f)	Adjustments (g)	Balance at End of Year (h)	Average Period of Allocation to Income (i)	ADJUSTMENT EXPLANATION (j)
1	Electric Utility
2	3%				411.1
3	4%				411.1
4	7%				411.1
5	10%	318,791	411.1		411.1	11,857		306,934	32 Years
6	State DITC		411.1		411.1
7	30				411.1
8	TOTAL Electric (Enter Total of lines 2 thru 7)	318,791				11,857		306,934
9	Other (List separately and show 3%, 4%, 7%, 10% and TOTAL)
10										`
47	OTHER TOTAL
48	GRAND TOTAL	318,791						306,934

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

OTHER DEFERRED CREDITS (Account 253)
Report below the particulars (details) called for concerning other deferred credits. For any deferred credit being amortized, show the period of amortization. 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.
			DEBITS
Line No.	Description and Other Deferred Credits (a)	Balance at Beginning of Year (b)	Contra Account (c)	Amount (d)	Credits (e)	Balance at End of Year (f)
1	T.V. Pole Attachments	1,874,237	454	6,430,442	6,348,784	1,792,579
2	Deferred Gain - Fiber Optic Leases
3	Amortize through June 2026	3,386,766	124	891,628		2,495,138
4	Deferred Revenue - Fiber Optic
5	Lines Sold	191,821	451	108,924		82,897
6	Amortize IRU through May 2021
7	Amortize KDL through Jan 2025
8	Rents Billed in Advance	368,301	451	184,150		184,151
9	Customer Advance Receipts	17,275,460	142	17,275,460	16,757,690	16,757,690
10	IPP - System Upgrade Credits	3,332,729	232	3,226,372	38,895	145,252
11	Federal Mitigation Deferral - NSR	2,229,306	242	600,000		1,629,306
12	Other Deferred Credits	1,187,834	(a) Footnote	26,599,694	26,649,396	1,237,536
13	Def Equity Income-Securitization	2,535,932	456	301,831		2,234,101
14	Reliability First FAC-003	1,069,481	426	431,712		637,769
15	Assessment
16	Contr In Aid of Constr Advance	635,839	107/108	635,839	5,504,231	5,504,231
17	Associated Business Development	227,650	456	227,650
47	TOTAL	34,315,356		56,913,702	55,298,996	32,700,650

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: DecreaseInOtherDeferredCreditsContraAccount

232, 234, 561, 566, 565, 131, 143, 411, 186, 509, 142

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED AMORTIZATION PROPERTY (Account 281)
Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to amortizable property. For other (Specify),include deferrals relating to other income and deductions. Use footnotes as required.
			CHANGES DURING YEAR				ADJUSTMENTS
							Debits		Credits
Line No.	Account (a)	Balance at Beginning of Year (b)	Amounts Debited to Account 410.1 (c)	Amounts Credited to Account 411.1 (d)	Amounts Debited to Account 410.2 (e)	Amounts Credited to Account 411.2 (f)	Account Credited (g)	Amount (h)	Account Debited (i)	Amount (j)	Balance at End of Year (k)
1	Accelerated Amortization (Account 281)
2	Electric
3	Defense Facilities
4	Pollution Control Facilities	247,937,383	24,825	12,021,571							235,940,637
5	Other
5.1	Other (provide details in footnote):
8	TOTAL Electric (Enter Total of lines 3 thru 7)	247,937,383	24,825	12,021,571							235,940,637
9	Gas
10	Defense Facilities
11	Pollution Control Facilities
12	Other
12.1	Other (provide details in footnote):
15	TOTAL Gas (Enter Total of lines 10 thru 14)
16	Other
16.1	Other - SFAS 109	(a) 95,799,954					254	24,825	254	3,607,778	92,217,001
17	TOTAL (Acct 281) (Total of 8, 15 and 16)	152,137,429	24,825	12,021,571				24,825		3,607,778	143,723,636
18	Classification of TOTAL
19	Federal Income Tax	152,137,429	24,825	12,021,571				24,825		3,607,778	143,723,636
20	State Income Tax
21	Local Income Tax

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxesAcceleratedAmortizationProperty

Description
Year

Balance at Beginning

Amounts Debited

Amounts Credits

Debit

Credit

Balance End of

Page 272-273

to Acc 410.2

to Acc 411.2

Adjust

SFAS 109
(95,799,954)

(95,799,954)

24,825

3,607,778

(92,217,001)

Total line 16
(95,799,954)

(95,799,954)

24,825

3,607,778

(92,217,001)

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282)
Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to property not subject to accelerated amortization. For other (Specify),include deferrals relating to other income and deductions. Use footnotes as required.
			CHANGES DURING YEAR				ADJUSTMENTS
							Debits		Credits
Line No.	Account (a)	Balance at Beginning of Year (b)	Amounts Debited to Account 410.1 (c)	Amounts Credited to Account 411.1 (d)	Amounts Debited to Account 410.2 (e)	Amounts Credited to Account 411.2 (f)	Account Credited (g)	Amount (h)	Account Debited (i)	Amount (j)	Balance at End of Year (k)
1	Account 282
2	Electric	2,046,396,336	184,686,342	187,815,038							2,043,267,640
3	Gas
4	Other (Specify)
5	Total (Total of lines 2 thru 4)	2,046,396,336	184,686,342	187,815,038							2,043,267,640
6	(a) Others	639,432,019					1823/254	40,282,361	1823/254	144,195,990	535,518,390
9	TOTAL Account 282 (Total of Lines 5 thru 8)	1,406,964,317	184,686,342	187,815,038				40,282,361		144,195,990	1,507,749,250
10	Classification of TOTAL
11	Federal Income Tax	1,406,964,317	184,686,342	187,815,038				40,282,361		144,195,990	1,507,749,250
12	State Income Tax
13	Local Income Tax

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: DescriptionOfNonUtilityAccountDetails


Line 6 Footnote

	Beg Bal	Debits	Credits	End Bal
SFAS 109	(639,432,019)	40,282,361	144,195,990	(535,518,390)
Total Other - Line 6	(639,432,019)	40,282,361	144,195,990	(535,518,390)

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283)
Report the information called for below concerning the respondent's accounting for deferred income taxes relating to amounts recorded in Account 283. For other (Specify),include deferrals relating to other income and deductions. Provide in the space below explanations for Page 276. Include amounts relating to insignificant items listed under Other. Use footnotes as required.
			CHANGES DURING YEAR				ADJUSTMENTS
							Debits		Credits
Line No.	Account (a)	Balance at Beginning of Year (b)	Amounts Debited to Account 410.1 (c)	Amounts Credited to Account 411.1 (d)	Amounts Debited to Account 410.2 (e)	Amounts Credited to Account 411.2 (f)	Account Credited (g)	Amount (h)	Account Debited (i)	Amount (j)	Balance at End of Year (k)
1	Account 283
2	Electric
3	Extra. Loss on Retired Plants	17,320,671	17,956	731,323							16,607,304
4	CAPITALIZED SOFTWARE COST?BOOK	25,967,911	4,320,040	301,123							29,986,828
5	DSIT ENTRY - NORMALIZED	90,051,825	91,863	6,186,444							83,957,244
6	Deferred Fuel Costs	46,312,110	45,072,578	9,771,927							81,612,761
7	Book Pension Expense	27,314,948	25,280	1,791,289							25,548,939
8	Other	36,922,058	169,088,122	148,945,865						3	16,779,798
9	TOTAL Electric (Total of lines 3 thru 8)	170,045,407	218,615,839	167,727,971						3	220,933,278
10	Gas
11
12
13
14
15
16
17	TOTAL Gas (Total of lines 11 thru 16)
18	TOTAL Other	(a) 520,343,427			335,093		1823/254	178,358,335	1823/254	83,977,136	426,297,321
19	TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18)	690,388,834	218,615,839	167,727,971	335,093			178,358,335		83,977,139	647,230,599
20	Classification of TOTAL
21	Federal Income Tax	353,903,938	193,480,669	143,388,474	335,093			78,129,519		31,836,930	358,038,637
22	State Income Tax	336,484,896	25,135,170	24,339,497				100,228,816		52,140,209	289,191,962
23	Local Income Tax
NOTES

FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxesOther


Line 18 Footnote
	Beg Bal	Dr 410.1	Cr 411.1	Dr 410.2	Cr 411.2	Debits	Credits	End Bal

SFAS 133	1,187,087					2,572	1,450,448	2,634,963
Non-Utility	144,225			335,093				479,318
SFAS 109	519,012,115					178,355,763	82,526,688	423,183,040
Total	520,343,427			335,093		178,358,335	83,977,136	426,297,321

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

OTHER REGULATORY LIABILITIES (Account 254)
Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if applicable. 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. For Regulatory Liabilities being amortized, show period of amortization.
			DEBITS
Line No.	Description and Purpose of Other Regulatory Liabilities (a)	Balance at Beginning of Current Quarter/Year (b)	Account Credited (c)	Amount (d)	Credits (e)	Balance at End of Current Quarter/Year (f)
1	Unrealized Gain On Forward Commitments	260,888	(a) 175, 182, 244, 456	16,801,762	40,869,986	24,329,112
2	Netting of Trading Activities related to Unrealized Gains/Losses on Forward Commitments between Regulated Assets/Liabilities	5,235,279	182	15,628,050	14,230,672	3,837,901
3	FAS 109 Deferred Federal Income Tax	829,167,553	(b) 190, 282, 283	172,369,434	86,824,650	743,622,769
4	FAS 109 Deferred State Income Tax		(c) 190, 282, 283	4,553,899	26,223,388	21,669,489
5	PJM trans enhancement settlement for refund	16,265,598	142	3,269,956		12,995,642
6	VA EE-RAC Over Recovery -Case No. PUR - 2017-00126	6,378,319	182/908	9,635,473	9,283,353	6,026,199
7	APCO Consumer Rate Relief Over Recovery -Rate Order: WV Public Service Commission -Case No. 12-1188-E-PC	516,739	407	1,633,075	1,116,336
8	WV Broadband Over Recovery				446,477	446,477
9	WV ECS Over Recovery				174,848	174,848
10	VA RPS-RAC Over-Recovery		182/555		8,376,192	8,376,192
11	Felman Prem/Discount ENEC-WV		182/501	18,284,805	18,284,805
41	TOTAL	857,824,376		242,176,454	205,830,707	821,478,629

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: OtherRegulatoryLiabilitiesDescriptionOfCreditedAccountNumberForDebitAdjustment

175, 182, 244, 456

(b) Concept: OtherRegulatoryLiabilitiesDescriptionOfCreditedAccountNumberForDebitAdjustment

190, 282, 283

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

Electric Operating Revenues
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. Report below operating revenues for each prescribed account, and manufactured gas revenues in total. 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. 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. Disclose amounts of $250,000 or greater in a footnote for accounts 451, 456, and 457.2. 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.) See page 108, Important Changes During Period, for important new territory added and important rate increase or decreases. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbilled revenue by accounts. Include unmetered sales. Provide details of such Sales in a footnote.
Line No.	Title of Account (a)	Operating Revenues Year to Date Quarterly/Annual (b)	Operating Revenues Previous year (no Quarterly) (c)	MEGAWATT HOURS SOLD Year to Date Quarterly/Annual (d)	MEGAWATT HOURS SOLD Amount Previous year (no Quarterly) (e)	AVG.NO. CUSTOMERS PER MONTH Current Year (no Quarterly) (f)	AVG.NO. CUSTOMERS PER MONTH Previous Year (no Quarterly) (g)
1	SalesOfElectricityHeadingAbstract Sales of Electricity
2	ResidentialSalesAbstract (440) Residential Sales	1,378,288,171	1,273,007,898	11,206,650	10,915,394	813,862	810,840
3	CommercialAndIndustrialSalesAbstract (442) Commercial and Industrial Sales
4	CommercialSalesAbstract Small (or Comm.) (See Instr. 4)	555,785,591	526,854,763	5,949,362	5,886,796	138,485	137,143
5	IndustrialSalesAbstract Large (or Ind.) (See Instr. 4)	584,309,527	563,789,888	8,879,317	8,873,358	4,184	4,210
6	PublicStreetAndHighwayLightingAbstract (444) Public Street and Highway Lighting	7,993,467	7,783,854	64,162	64,508	1,684	1,716
7	OtherSalesToPublicAuthoritiesAbstract (445) Other Sales to Public Authorities	62,743,388	61,094,193	745,795	729,260	6,227	6,253
8	SalesToRailroadsAndRailwaysAbstract (446) Sales to Railroads and Railways
9	InterdepartmentalSalesAbstract (448) Interdepartmental Sales
10	SalesToUltimateConsumersAbstract TOTAL Sales to Ultimate Consumers	(a) 2,589,120,143	2,432,530,596	26,845,286	26,469,315	964,442	960,162
11	SalesForResaleAbstract (447) Sales for Resale	341,751,443	253,242,272	6,967,140	5,600,008	15	27
12	SalesOfElectricityAbstract TOTAL Sales of Electricity	2,930,871,586	2,685,772,868	33,812,426	32,069,323	964,457	960,189
13	ProvisionForRateRefundsAbstract (Less) (449.1) Provision for Rate Refunds		4,670,543
14	RevenuesNetOfProvisionForRefundsAbstract TOTAL Revenues Before Prov. for Refunds	2,930,871,586	2,681,102,325	33,812,426	32,069,323	964,457	960,189
15	OtherOperatingRevenuesAbstract Other Operating Revenues
16	ForfeitedDiscounts (450) Forfeited Discounts	6,272,184	4,470,847
17	MiscellaneousServiceRevenues (451) Miscellaneous Service Revenues	(b) 2,206,090	1,896,615
18	SalesOfWaterAndWaterPower (453) Sales of Water and Water Power
19	RentFromElectricProperty (454) Rent from Electric Property	21,832,186	24,503,541
20	InterdepartmentalRents (455) Interdepartmental Rents
21	OtherElectricRevenue (456) Other Electric Revenues	(c) 41,801,314	21,427,718
22	RevenuesFromTransmissionOfElectricityOfOthers (456.1) Revenues from Transmission of Electricity of Others	138,990,094	123,846,235
23	RegionalTransmissionServiceRevenues (457.1) Regional Control Service Revenues
24	MiscellaneousRevenue (457.2) Miscellaneous Revenues
25	OtherMiscellaneousOperatingRevenues Other Miscellaneous Operating Revenues
26	OtherOperatingRevenues TOTAL Other Operating Revenues	211,101,867	176,144,956
27	ElectricOperatingRevenues TOTAL Electric Operating Revenues	3,141,973,453	2,857,247,281
Line12, column (b) includes $ 18,781,557 of unbilled revenues.
Line12, column (d) includes 333,072 MWH relating to unbilled revenues

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: SalesToUltimateConsumers

Detail of Unmetered Sales included in Total Sales to Ultimate Customers:


Account	Revenues	MWH Sold	Average No. of Customers

440 Residential	10,670,996	67,736	84,333
442 Commercial	8,232,985	66,987	23,622
442 Industrial	720,845	6,654	910
444 Street Lighting	24,167	197	50
445 Other Public Sales	367,950	3,025	706
	20,016,943	144,599	109,621

Total Sales to Ultimate Consumers include $1,565,938 of Operating Revenues for distribution service provided to Open Access Customers. Megawatt hours delivered to Open Access Consumers were 342,677 and are included in the reported megawatt hours sold on Pg. 301(d).

(b) Concept: MiscellaneousServiceRevenues

Customer service revenue, including connects, reconnects, disconnects, temporary services and other charges billed to customer.


Descrption	YTD 2021	YTD 2020

Assoc. Business Development	9,046,571	7,924,270
Sale of Renewable Energy Credits	32,293,619	13,061,259
Amort. Of Deferred Equity	301,831	295,863
All Other (under $250K each)	159,293	146,326
Total	41,801,314	21,427,718

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

REGIONAL TRANSMISSION SERVICE REVENUES (Account 457.1)
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 No.	Description of Service (a)	Balance at End of Quarter 1 (b)	Balance at End of Quarter 2 (c)	Balance at End of Quarter 3 (d)	Balance at End of Year (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

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

SALES OF ELECTRICITY BY RATE SCHEDULES
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 Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. 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. 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. 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). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1	GS - General Sales	4	605			0.1513
2	OL-Outdoor Lighting	67,736	10,671,074			0.1575
3	RS - Residential Service	11,208,849	1,367,115,931	809,497	13,847	0.1220
4	RSE - Residential Emp.	69,062	8,449,713	4,124	16,745	0.1223
5	RS-EV RESIDENTIAL SERVICE PLUG IN ELECTRIC VEHICLE CHARGING	142	3,950	33	4,309	0.0278
6	RS-LM-TOD Res. Load MGMT	332	39,694	16	20,627	0.1196
7	RS-TOD-Residential TOD	3,170	332,371	192	16,509	0.1048
8	SGS-Small Gen. Service	10	1,082		31,394	0.1082
9	PA - PUBLIC AUTHORITY		50			5.0060
10	Misc Adjustments		335,362
41	TOTAL Billed Residential Sales	11,349,305	1,386,271,208	813,862	13,945	0.1221
42	TOTAL Unbilled Rev. (See Instr. 6)	142,655	7,983,037			0.0560
43	TOTAL	11,206,650	1,378,288,171	813,862	13,770	0.1230

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

SALES OF ELECTRICITY BY RATE SCHEDULES
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 Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. 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. 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. 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). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1	Estimated	4,207	272,902			0.0649
2	SGS-Small General Service	3,617,045	329,612,491	20,320	178,004	0.0911
3	SGS-PA - Small General Service-PA	408	42,354	4	102,000	0.1038
4	SGS-TOD-Small General Service	48,906	4,412,052	675	72,453	0.0902
5	IP-Industrial Power Service	6,995	449,248	1	6,995,000	0.0642
6	LCP-Large Capacity Power	501,565	38,616,257	49	10,236,020	0.0770
7	LGS-TOD - Large General Service-T	25,728	2,219,462	79	325,671	0.0863
8	LPS-Large Power Service	303,791	17,765,347	22	13,808,682	0.0585
9	LPS-TOD-Large Power Ser TOD	28,276	2,115,617	4	7,069,000	0.0748
10	MGS-Medium General Service	239,422	25,027,641	2,830	84,601	0.1045
11	OL-Outdoor Lighting	67,020	8,235,724			0.1229
12	RS-Residential Service	3	324			0.1080
13	SGS-Small General Service	833,761	92,066,504	109,000	7,649	0.1104
14	SGS-TOD-Small General Service	3,160	376,565	547	5,777	0.1192
15	SS-School Service	255,785	27,539,373	1,060	241,307	0.1077
16	SWS-Sanctuary Worship	99,757	12,381,665	3,893	25,625	0.1241
17	Winterplace	1,178	199,335	1	1,178,000	0.1692
18	Misc Adjustments		101,132
41	TOTAL Billed Small or Commercial	6,028,593	560,685,925	138,485	43,532	0.0930
42	TOTAL Unbilled Rev. Small or Commercial (See Instr. 6)	79,231	4,900,334			0.0618
43	TOTAL Small or Commercial	5,949,362	555,785,591	138,485	42,960	0.0934

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

SALES OF ELECTRICITY BY RATE SCHEDULES
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 Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. 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. 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. 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). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1	Armstrong	69,986	3,389,492	1	69,986,000	0.0484
2	Constellium	170,577	9,910,638	1	170,577,000	0.0581
3	Estimated	117,815	6,614,538			0.0561
4	Felman	255,025	17,936,821	1	255,025,000	0.0703
5	GS-General Service	883,656	76,081,721	1,384	638,480	0.0861
6	GS-TOD-General Service TOD	1,975	197,618	21	94,048	0.1001
7	IP-Industrial Power Service	310,406	19,007,368	3	103,468,667	0.0612
8	LCP-Large Capacity Power	2,194,189	163,711,254	95	23,096,726	0.0746
9	LGS-TOD - Large General Service-T	529	69,945	3	176,333	0.1322
10	LPS-Large Power Service	3,261,288	182,593,792	98	33,278,449	0.0560
11	LPS-TOD-Large Power Ser TOD	1,031,038	63,061,879	33	31,243,576	0.0612
12	MGS-Medium General Service	136,850	14,619,375	399	342,982	0.1068
13	OL-Outdoor Lighting	6,654	720,845			0.1083
14	SGS-Small General Service	22,047	2,345,131	2,143	10,288	0.1064
15	WV Manufacturing	506,155	27,327,126	1	506,155,000	0.0540
16	WV Recycle	10,138	1,652,975	1	10,138,000	0.1630
17	Misc Adjustments		279,130
41	TOTAL Billed Large (or Ind.) Sales	8,978,328	589,519,648	4,184	2,145,872	0.0657
42	TOTAL Unbilled Rev. Large (or Ind.) (See Instr. 6)	99,011	5,210,121			0.0526
43	TOTAL Large (or Ind.)	8,879,317	584,309,527	4,184	2,122,208	0.0658

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

SALES OF ELECTRICITY BY RATE SCHEDULES
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 Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. 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. 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. 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). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1	Misc Adjustments
41	TOTAL Billed Commercial and Industrial Sales
42	TOTAL Unbilled Rev. (See Instr. 6)
43	TOTAL

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

SALES OF ELECTRICITY BY RATE SCHEDULES
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 Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. 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. 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. 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). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1	Commonwealth of VA	3,781	386,932	538	7,028	0.1023
2	Estimated
3	GS-General Service	1,442	159,667	25	57,680	0.1107
4	GS-TOD-General Service TOD	646	49,243	5	129,200	0.0762
5	MGS-PA-Med Gen Ser - PA	543	48,873	1	543,000	0.0900
6	OL-Outdoor Lighting	197	24,167			0.1227
7	SGS-Small General Service	2,579	345,788	593	4,349	0.1341
8	SGS-PA -Small Gen Ser - PA	952	120,991	329	2,894	0.1271
9	SL-Street Lighting	54,207	6,883,196	193	280,865	0.1270
10	Misc Adjustments		10,959
41	TOTAL Billed Public Street and Highway Lighting	64,347	8,007,898	1,684	38,211	0.1244
42	TOTAL Unbilled Rev. (See Instr. 6)	185	14,431
43	TOTAL	64,162	7,993,467	1,684	38,101	0.1246

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

SALES OF ELECTRICITY BY RATE SCHEDULES
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 Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. 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. 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. 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). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
1	Commonwealth of VA	128,993	10,673,717	909	141,906	0.0827
2	Estimated	101	7,905			0.0783
3	Flood Walls	211	14,832	22	9,591	0.0703
4	GS-General Service	23,789	1,679,698	17	1,399,353	0.0706
5	GS-PA -General Service -PA	359,242	28,540,986	642	559,567	0.0794
6	GS-TOD-PA-Gen Ser TOD -PA	2,542	231,056	92	27,630	0.0909
7	LPS-TOD - LARGE POWER SERVICE TOD	1,709	153,131			0.0896
8	LPS-TOD-PA Large Pow Ser	37,541	2,483,758	5	7,508,200	0.0662
9	MGS - MEDIUM GENERAL SERVICE	1,201	120,070	8	150,125	0.1000
10	MGS-PA-Med Gen Ser - PA	151,557	14,712,784	635	238,672	0.0971
11	OL-Outdoor Lighting	3,025	367,950			0.1216
12	Public Authority-Large General Svc-TOD-Pri	100	9,321	1	100,000	0.0932
13	Public Authority-Large General Svc-TOD-Sec	1,691	179,527	19	89,000	0.1062
14	SGS-Small General Service	596	60,051	40	14,900	0.1008
15	SGS-PA- Small Gen Ser - PA	45,689	4,492,767	3,837	11,907	0.0983
16	Misc Adjustments		294,720
41	TOTAL Billed Other Sales to Public Authorities	757,785	63,417,023	6,227	121,693	0.0837
42	TOTAL Unbilled Rev. (See Instr. 6)	11,990	673,635
43	TOTAL	745,795	62,743,388	6,227	119,768	0.0841

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

SALES OF ELECTRICITY BY RATE SCHEDULES
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 Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. 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. 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. 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). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
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	TOTAL Billed Provision For Rate Refunds
42	TOTAL Unbilled Rev. (See Instr. 6)
43	TOTAL

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

SALES OF ELECTRICITY BY RATE SCHEDULES
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 Page 310. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300. 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. 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. 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). For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.	Number and Title of Rate Schedule (a)	MWh Sold (b)	Revenue (c)	Average Number of Customers (d)	KWh of Sales Per Customer (e)	Revenue Per KWh Sold (f)
41	TOTAL Billed - All Accounts	27,178,358	2,607,901,702	964,442	2,363,254
42	TOTAL Unbilled Rev. (See Instr. 6) - All Accounts	333,072	18,781,557
43	TOTAL - All Accounts	26,845,286	2,589,120,145	964,442	2,363,254

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

SALES FOR RESALE (Account 447)
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). 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. 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. 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. 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 (g) through (k). 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. 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. Report in column (g) the megawatt hours shown on bills rendered to the purchaser. 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. 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,line 24. Footnote entries as required and provide explanations following all required data.
					ACTUAL DEMAND (MW)			REVENUE
Line No.	Name of Company or Public Authority (Footnote Affiliations) (a)	Statistical Classification (b)	FERC Rate Schedule or Tariff Number (c)	Average Monthly Billing Demand (MW) (d)	Average Monthly NCP Demand (e)	Average Monthly CP Demand (f)	Megawatt Hours Sold (g)	Demand Charges ($) (h)	Energy Charges ($) (i)	Other Charges ($) (j)	Total ($) (h+i+j) (k)
1	ALLEGHENY ELECTRIC COOPERATIVE	OS	(c) NOTE 1				13,306		549,164		549,164
2	AMEREX POWER, LTD	OS	NOTE 1				0		1,417		1,417
3	(a) B.P. ENERGY COMPANY	OS	NOTE 1				34,651		803,134		803,134
4	CITIGROUP ENERGY INC.	OS	NOTE 1				0		246,731		246,731
5	CITY OF RADFORD, VA	RQ	NOTE 1				177,573	5,417,397	7,341,058		12,758,455
6	CITY OF SALEM, VA	RQ	NOTE 1				363,402	10,442,087	16,180,697		26,622,784
7	CRAIG-BOTETOURT ELECTRIC COOP	RQ	NOTE 1				52,848	1,951,026	2,313,015		4,264,041
8	DUQUESNE LIGHT COMPANY	OS	NOTE 1				13,492		545,487		545,487
9	EVOLUTION MARKETS FUTURES LLC	OS	NOTE 1				0		6,745		6,745
10	FIRSTENERGY TRADING SERVICES	OS	NOTE 1				75,341		3,039,043		3,039,043
11	ICAP ENERGY LLC	OS	NOTE 1				0		2,654		2,654
12	IVG ENERGY, LTD	OS	NOTE 1				0		5,202		5,202
13	KINGSPORT	RQ	23				1,675,182	41,992,911	53,416,481	33,177,725	128,587,117
14	OHIO POWER COMPANY (AUCTION)	OS	NOTE 1				39			1,090	1,090
15	OLD DOMINION ELECTRIC	RQ	NOTE 1				151,681	5,542,987	6,868,858		12,411,845
16	PJM INTERCONNECTION	OS	NOTE 1				3,994,808	4,073,006	132,684,788	11,029,581	147,787,375
17	PJM INTERCONNECTION	RQ	VARIOUS				0			21,685,993	21,685,993
18	PPL ELECTRIC UTILITIES CORP	OS	NOTE 1				104,750		4,557,682		4,557,682
19	RBC CAPITAL MARKET, LLC	OS	NOTE 1				0		1,113		1,113
20	TRIDENT BROKERAGE SERVICES, LLC	OS	NOTE 1				0		177		177
21	TULLETT PREBON AMERICAS CORP.	OS	NOTE 1				0		215		(e) 215
22	(b) UNITED LIGHT & POWER COMPANY	RQ	(d) 151				52,346	1,818,361	2,505,997		4,324,358
23	VIRGINIA TECH	RQ	155				327,023	9,074,359	12,921,135		21,995,494
24	WELLS FARGO SECURITIES, LLC	OS	NOTE 1				0		2,939,111		2,939,111
15	Subtotal - RQ						2,800,056	76,239,128	101,547,241	11,491,732	189,278,101
16	Subtotal-Non-RQ						4,167,084	4,073,006	137,369,665	11,030,671	152,473,342
17	Total						6,967,140	80,312,134	238,916,906	22,522,403	341,751,443

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: NameOfCompanyOrPublicAuthorityReceivingElectricityPurchasedForResale

An affiliated company

(b) Concept: NameOfCompanyOrPublicAuthorityReceivingElectricityPurchasedForResale

An affiliated company

FERC Electric Tariff, First Revised Volume No. 5

(d) Concept: RateScheduleTariffNumber

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.

(e) Concept: RevenueFromSalesOfElectricityForResale

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.

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line No.	Account (a)	Amount for Current Year (b)	Amount for Previous Year (c) (c)
1	PowerProductionExpensesAbstract 1. POWER PRODUCTION EXPENSES
2	SteamPowerGenerationAbstract A. Steam Power Generation
3	SteamPowerGenerationOperationAbstract Operation
4	OperationSupervisionAndEngineeringSteamPowerGeneration (500) Operation Supervision and Engineering	19,520,337	19,580,783
5	FuelSteamPowerGeneration (501) Fuel	(a) 384,765,119	485,092,339
6	SteamExpensesSteamPowerGeneration (502) Steam Expenses	50,532,264	45,366,636
7	SteamFromOtherSources (503) Steam from Other Sources
8	SteamTransferredCredit (Less) (504) Steam Transferred-Cr.
9	ElectricExpensesSteamPowerGeneration (505) Electric Expenses	203,351	158,435
10	MiscellaneousSteamPowerExpenses (506) Miscellaneous Steam Power Expenses	19,293,080	24,830,921
11	RentsSteamPowerGeneration (507) Rents	39,073	33,986
12	Allowances (509) Allowances	612,073	163,232
13	SteamPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 4 thru 12)	474,965,297	575,226,332
14	SteamPowerGenerationMaintenanceAbstract Maintenance
15	MaintenanceSupervisionAndEngineeringSteamPowerGeneration (510) Maintenance Supervision and Engineering	2,363,425	1,492,108
16	MaintenanceOfStructuresSteamPowerGeneration (511) Maintenance of Structures	4,229,814	5,364,801
17	MaintenanceOfBoilerPlantSteamPowerGeneration (512) Maintenance of Boiler Plant	47,508,488	48,740,249
18	MaintenanceOfElectricPlantSteamPowerGeneration (513) Maintenance of Electric Plant	13,342,587	12,987,780
19	MaintenanceOfMiscellaneousSteamPlant (514) Maintenance of Miscellaneous Steam Plant	11,801,008	13,756,943
20	SteamPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of Lines 15 thru 19)	79,245,322	82,341,881
21	PowerProductionExpensesSteamPower TOTAL Power Production Expenses-Steam Power (Enter Total of Lines 13 & 20)	554,210,618	657,568,213
22	NuclearPowerGenerationAbstract B. Nuclear Power Generation
23	NuclearPowerGenerationOperationAbstract Operation
24	OperationSupervisionAndEngineeringNuclearPowerGeneration (517) Operation Supervision and Engineering
25	NuclearFuelExpense (518) Fuel
26	CoolantsAndWater (519) Coolants and Water
27	SteamExpensesNuclearPowerGeneration (520) Steam Expenses
28	SteamFromOtherSourcesNuclearPowerGeneration (521) Steam from Other Sources
29	SteamTransferredCreditNuclearPowerGeneration (Less) (522) Steam Transferred-Cr.
30	ElectricExpensesNuclearPowerGeneration (523) Electric Expenses
31	MiscellaneousNuclearPowerExpenses (524) Miscellaneous Nuclear Power Expenses
32	RentsNuclearPowerGeneration (525) Rents
33	NuclearPowerGenerationOperationsExpense TOTAL Operation (Enter Total of lines 24 thru 32)
34	NuclearPowerGenerationMaintenanceAbstract Maintenance
35	MaintenanceSupervisionAndEngineeringNuclearPowerGeneration (528) Maintenance Supervision and Engineering
36	MaintenanceOfStructuresNuclearPowerGeneration (529) Maintenance of Structures
37	MaintenanceOfReactorPlantEquipmentNuclearPowerGeneration (530) Maintenance of Reactor Plant Equipment
38	MaintenanceOfElectricPlantNuclearPowerGeneration (531) Maintenance of Electric Plant
39	MaintenanceOfMiscellaneousNuclearPlant (532) Maintenance of Miscellaneous Nuclear Plant
40	NuclearPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of lines 35 thru 39)
41	PowerProductionExpensesNuclearPower TOTAL Power Production Expenses-Nuclear. Power (Enter Total of lines 33 & 40)
42	HydraulicPowerGenerationAbstract C. Hydraulic Power Generation
43	HydraulicPowerGenerationOperationAbstract Operation
44	OperationSupervisionAndEngineeringHydraulicPowerGeneration (535) Operation Supervision and Engineering	1,612,103	1,994,342
45	WaterForPower (536) Water for Power	24,080	4,328
46	HydraulicExpenses (537) Hydraulic Expenses	984,313	1,548,939
47	ElectricExpensesHydraulicPowerGeneration (538) Electric Expenses	397,988	341,514
48	MiscellaneousHydraulicPowerGenerationExpenses (539) Miscellaneous Hydraulic Power Generation Expenses	3,347,023	3,564,001
49	RentsHydraulicPowerGeneration (540) Rents	362,506	358,157
50	HydraulicPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 44 thru 49)	6,728,013	7,802,625
51	HydraulicPowerGenerationContinuedAbstract C. Hydraulic Power Generation (Continued)
52	HydraulicPowerGenerationMaintenanceAbstract Maintenance
53	MaintenanceSupervisionAndEngineeringHydraulicPowerGeneration (541) Mainentance Supervision and Engineering	241,930	132,398
54	MaintenanceOfStructuresHydraulicPowerGeneration (542) Maintenance of Structures	2,846,737	2,595,229
55	MaintenanceOfReservoirsDamsAndWaterways (543) Maintenance of Reservoirs, Dams, and Waterways	2,840,543	2,929,688
56	MaintenanceOfElectricPlantHydraulicPowerGeneration (544) Maintenance of Electric Plant	2,698,931	3,703,409
57	MaintenanceOfMiscellaneousHydraulicPlant (545) Maintenance of Miscellaneous Hydraulic Plant	131,686	228,146
58	HydraulicPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of lines 53 thru 57)	8,759,827	9,588,870
59	PowerProductionExpensesHydraulicPower TOTAL Power Production Expenses-Hydraulic Power (Total of Lines 50 & 58)	(b) 15,487,840	17,391,495
60	OtherPowerGenerationAbstract D. Other Power Generation
61	OtherPowerGenerationOperationAbstract Operation
62	OperationSupervisionAndEngineeringOtherPowerGeneration (546) Operation Supervision and Engineering	290,411	243,960
63	Fuel (547) Fuel	18,842,965	2,852,066
64	GenerationExpenses (548) Generation Expenses	556,276	497,146
64.1	OperationOfEnergyStorageEquipment (548.1) Operation of Energy Storage Equipment
65	MiscellaneousOtherPowerGenerationExpenses (549) Miscellaneous Other Power Generation Expenses	229,348	98,398
66	RentsOtherPowerGeneration (550) Rents	29
67	OtherPowerGenerationOperationsExpense TOTAL Operation (Enter Total of Lines 62 thru 67)	19,919,028	3,691,570
68	OtherPowerGenerationMaintenanceAbstract Maintenance
69	MaintenanceSupervisionAndEngineeringOtherPowerGeneration (551) Maintenance Supervision and Engineering
70	MaintenanceOfStructures (552) Maintenance of Structures
71	MaintenanceOfGeneratingAndElectricPlant (553) Maintenance of Generating and Electric Plant	237,571	352,118
71.1	MaintenanceOfEnergyStorageEquipmentOtherPowerGeneration (553.1) Maintenance of Energy Storage Equipment
72	MaintenanceOfMiscellaneousOtherPowerGenerationPlant (554) Maintenance of Miscellaneous Other Power Generation Plant
73	OtherPowerGenerationMaintenanceExpense TOTAL Maintenance (Enter Total of Lines 69 thru 72)	237,571	352,118
74	PowerProductionExpensesOtherPower TOTAL Power Production Expenses-Other Power (Enter Total of Lines 67 & 73)	20,156,599	4,043,688
75	OtherPowerSuplyExpensesAbstract E. Other Power Supply Expenses
76	PurchasedPower (555) Purchased Power	579,121,879	377,188,759
76.1	PowerPurchasedForStorageOperations (555.1) Power Purchased for Storage Operations	0
77	SystemControlAndLoadDispatchingElectric (556) System Control and Load Dispatching	2,490,558	2,355,977
78	OtherExpensesOtherPowerSupplyExpenses (557) Other Expenses	6,760,693	5,349,298
79	OtherPowerSupplyExpense TOTAL Other Power Supply Exp (Enter Total of Lines 76 thru 78)	588,373,130	384,894,034
80	PowerProductionExpenses TOTAL Power Production Expenses (Total of Lines 21, 41, 59, 74 & 79)	1,178,228,188	1,063,897,430
81	TransmissionExpensesAbstract 2. TRANSMISSION EXPENSES
82	TransmissionExpensesOperationAbstract Operation
83	OperationSupervisionAndEngineeringElectricTransmissionExpenses (560) Operation Supervision and Engineering	14,515,410	12,930,558
85	LoadDispatchReliability (561.1) Load Dispatch-Reliability
86	LoadDispatchMonitorAndOperateTransmissionSystem (561.2) Load Dispatch-Monitor and Operate Transmission System	2,043,828	2,188,799
87	LoadDispatchTransmissionServiceAndScheduling (561.3) Load Dispatch-Transmission Service and Scheduling
88	SchedulingSystemControlAndDispatchServices (561.4) Scheduling, System Control and Dispatch Services	6,341,973	5,987,262
89	ReliabilityPlanningAndStandardsDevelopment (561.5) Reliability, Planning and Standards Development	782,506	588,212
90	TransmissionServiceStudies (561.6) Transmission Service Studies
91	GenerationInterconnectionStudies (561.7) Generation Interconnection Studies
92	ReliabilityPlanningAndStandardsDevelopmentServices (561.8) Reliability, Planning and Standards Development Services	1,852,032	1,737,955
93	StationExpensesTransmissionExpense (562) Station Expenses	(c) 1,499,414	1,454,374
93.1	OperationOfEnergyStorageEquipmentTransmissionExpense (562.1) Operation of Energy Storage Equipment
94	OverheadLineExpense (563) Overhead Lines Expenses	186,419	174,437
95	UndergroundLineExpensesTransmissionExpense (564) Underground Lines Expenses	30,398	1,465
96	TransmissionOfElectricityByOthers (565) Transmission of Electricity by Others	316,382,461	254,463,359
97	MiscellaneousTransmissionExpenses (566) Miscellaneous Transmission Expenses	14,394,958	40,014,724
98	RentsTransmissionElectricExpense (567) Rents	61,491	85,275
99	TransmissionOperationExpense TOTAL Operation (Enter Total of Lines 83 thru 98)	329,300,973	239,596,972
100	TransmissionMaintenanceAbstract Maintenance
101	MaintenanceSupervisionAndEngineeringElectricTransmissionExpenses (568) Maintenance Supervision and Engineering	171,417	94,722
102	MaintenanceOfStructuresTransmissionExpense (569) Maintenance of Structures	71,059	89,901
103	MaintenanceOfComputerHardwareTransmission (569.1) Maintenance of Computer Hardware	(d) 38,506	31,683
104	MaintenanceOfComputerSoftwareTransmission (569.2) Maintenance of Computer Software	598,061	772,637
105	MaintenanceOfCommunicationEquipmentElectricTransmission (569.3) Maintenance of Communication Equipment	44,159	44,801
106	MaintenanceOfMiscellaneousRegionalTransmissionPlant (569.4) Maintenance of Miscellaneous Regional Transmission Plant
107	MaintenanceOfStationEquipmentTransmission (570) Maintenance of Station Equipment	3,705,459	2,864,569
107.1	MaintenanceOfEnergyStorageEquipmentTransmission (570.1) Maintenance of Energy Storage Equipment
108	MaintenanceOfOverheadLinesTransmission (571) Maintenance of Overhead Lines	23,644,071	13,217,088
109	MaintenanceOfUndergroundLinesTransmission (572) Maintenance of Underground Lines	10,578	5,447
110	MaintenanceOfMiscellaneousTransmissionPlant (573) Maintenance of Miscellaneous Transmission Plant	145,042	95,731
111	TransmissionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 101 thru 110)	28,428,353	17,216,579
112	TransmissionExpenses TOTAL Transmission Expenses (Total of Lines 99 and 111)	357,729,327	256,813,551
113	RegionalMarketExpensesAbstract 3. REGIONAL MARKET EXPENSES
114	RegionalMarketExpensesOperationAbstract Operation
115	OperationSupervision (575.1) Operation Supervision
116	DayAheadAndRealTimeMarketAdministration (575.2) Day-Ahead and Real-Time Market Facilitation
117	TransmissionRightsMarketAdministration (575.3) Transmission Rights Market Facilitation
118	CapacityMarketAdministration (575.4) Capacity Market Facilitation
119	AncillaryServicesMarketAdministration (575.5) Ancillary Services Market Facilitation
120	MarketMonitoringAndCompliance (575.6) Market Monitoring and Compliance
121	MarketFacilitationMonitoringAndComplianceServices (575.7) Market Facilitation, Monitoring and Compliance Services	6,603,034	5,580,830
122	RentsRegionalMarketExpenses (575.8) Rents
123	RegionalMarketOperationExpense Total Operation (Lines 115 thru 122)	6,603,034	5,580,830
124	RegionalMarketExpensesMaintenanceAbstract Maintenance
125	MaintenanceOfStructuresAndImprovementsRegionalMarketExpenses (576.1) Maintenance of Structures and Improvements
126	MaintenanceOfComputerHardware (576.2) Maintenance of Computer Hardware
127	MaintenanceOfComputerSoftware (576.3) Maintenance of Computer Software
128	MaintenanceOfCommunicationEquipmentRegionalMarketExpenses (576.4) Maintenance of Communication Equipment
129	MaintenanceOfMiscellaneousMarketOperationPlant (576.5) Maintenance of Miscellaneous Market Operation Plant
130	RegionalMarketMaintenanceExpense Total Maintenance (Lines 125 thru 129)
131	RegionalMarketExpenses TOTAL Regional Transmission and Market Operation Expenses (Enter Total of Lines 123 and 130)	6,603,034	5,580,830
132	DistributionExpensesAbstract 4. DISTRIBUTION EXPENSES
133	DistributionExpensesOperationAbstract Operation
134	OperationSupervisionAndEngineeringDistributionExpense (580) Operation Supervision and Engineering	5,546,699	4,433,265
135	LoadDispatching (581) Load Dispatching	7,211	15,388
136	StationExpensesDistribution (582) Station Expenses	1,368,052	1,206,100
137	OverheadLineExpenses (583) Overhead Line Expenses	587,051	1,687,661
138	UndergroundLineExpenses (584) Underground Line Expenses	2,170,984	2,261,467
138.1	OperationOfEnergyStorageEquipmentDistribution (584.1) Operation of Energy Storage Equipment
139	StreetLightingAndSignalSystemExpenses (585) Street Lighting and Signal System Expenses	590,853	87,371
140	MeterExpenses (586) Meter Expenses	1,785,362	594,852
141	CustomerInstallationsExpenses (587) Customer Installations Expenses	624,927	746,941
142	MiscellaneousDistributionExpenses (588) Miscellaneous Expenses	10,652,763	19,071,388
143	RentsDistributionExpense (589) Rents	1,451,899	1,597,629
144	DistributionOperationExpensesElectric TOTAL Operation (Enter Total of Lines 134 thru 143)	24,785,802	31,702,062
145	DistributionExpensesMaintenanceAbstract Maintenance
146	MaintenanceSupervisionAndEngineering (590) Maintenance Supervision and Engineering	181,056	169,496
147	MaintenanceOfStructuresDistributionExpense (591) Maintenance of Structures	199,244	179,931
148	MaintenanceOfStationEquipment (592) Maintenance of Station Equipment	(e) 1,369,389	1,312,620
148.1	MaintenanceOfEnergyStorageEquipment (592.2) Maintenance of Energy Storage Equipment
149	MaintenanceOfOverheadLines (593) Maintenance of Overhead Lines	126,395,547	96,387,866
150	MaintenanceOfUndergroundLines (594) Maintenance of Underground Lines	1,277,470	1,227,471
151	MaintenanceOfLineTransformers (595) Maintenance of Line Transformers	1,892,232	2,242,445
152	MaintenanceOfStreetLightingAndSignalSystems (596) Maintenance of Street Lighting and Signal Systems	528,276	463,857
153	MaintenanceOfMeters (597) Maintenance of Meters	380,371	314,981
154	MaintenanceOfMiscellaneousDistributionPlant (598) Maintenance of Miscellaneous Distribution Plant	4,759,687	4,570,775
155	DistributionMaintenanceExpenseElectric TOTAL Maintenance (Total of Lines 146 thru 154)	136,983,273	106,869,442
156	DistributionExpenses TOTAL Distribution Expenses (Total of Lines 144 and 155)	161,769,075	138,571,504
157	CustomerAccountsExpensesAbstract 5. CUSTOMER ACCOUNTS EXPENSES
158	CustomerAccountsExpensesOperationsAbstract Operation
159	SupervisionCustomerAccountExpenses (901) Supervision	478,550	428,418
160	MeterReadingExpenses (902) Meter Reading Expenses	3,934,277	4,109,056
161	CustomerRecordsAndCollectionExpenses (903) Customer Records and Collection Expenses	24,315,220	22,414,866
162	UncollectibleAccounts (904) Uncollectible Accounts	5,625,956	4,605,308
163	MiscellaneousCustomerAccountsExpenses (905) Miscellaneous Customer Accounts Expenses	135,767	156,085
164	CustomerAccountExpenses TOTAL Customer Accounts Expenses (Enter Total of Lines 159 thru 163)	34,489,770	31,713,733
165	CustomerServiceAndInformationalExpensesAbstract 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166	CustomerServiceAndInformationalExpensesOperationAbstract Operation
167	SupervisionCustomerServiceAndInformationExpenses (907) Supervision	653,360	539,955
168	CustomerAssistanceExpenses (908) Customer Assistance Expenses	15,033,181	15,531,464
169	InformationalAndInstructionalAdvertisingExpenses (909) Informational and Instructional Expenses
170	MiscellaneousCustomerServiceAndInformationalExpenses (910) Miscellaneous Customer Service and Informational Expenses	83,279	71,606
171	CustomerServiceAndInformationExpenses TOTAL Customer Service and Information Expenses (Total Lines 167 thru 170)	15,769,820	16,143,025
172	SalesExpenseAbstract 7. SALES EXPENSES
173	SalesExpenseOperationAbstract Operation
174	SupervisionSalesExpense (911) Supervision		539
175	DemonstratingAndSellingExpenses (912) Demonstrating and Selling Expenses	168,708	279,273
176	AdvertisingExpenses (913) Advertising Expenses
177	MiscellaneousSalesExpenses (916) Miscellaneous Sales Expenses
178	SalesExpenses TOTAL Sales Expenses (Enter Total of Lines 174 thru 177)	168,708	279,812
179	AdministrativeAndGeneralExpensesAbstract 8. ADMINISTRATIVE AND GENERAL EXPENSES
180	AdministrativeAndGeneralExpensesOperationAbstract Operation
181	AdministrativeAndGeneralSalaries (920) Administrative and General Salaries	46,182,639	45,730,119
182	OfficeSuppliesAndExpenses (921) Office Supplies and Expenses	5,058,941	3,359,025
183	AdministrativeExpensesTransferredCredit (Less) (922) Administrative Expenses Transferred-Credit	5,484,021	6,760,299
184	OutsideServicesEmployed (923) Outside Services Employed	13,463,107	8,899,129
185	PropertyInsurance (924) Property Insurance	(f) 4,446,810	4,902,652
186	InjuriesAndDamages (925) Injuries and Damages	3,496,246	6,771,456
187	EmployeePensionsAndBenefits (926) Employee Pensions and Benefits	5,144,960	5,754,311
188	FranchiseRequirements (927) Franchise Requirements
189	RegulatoryCommissionExpenses (928) Regulatory Commission Expenses	10,695,109	6,065,976
190	DuplicateChargesCredit (929) (Less) Duplicate Charges-Cr.	145,001	134,872
191	GeneralAdvertisingExpenses (930.1) General Advertising Expenses	728,098	340,179
192	MiscellaneousGeneralExpenses (930.2) Miscellaneous General Expenses	7,759,245	6,591,353
193	RentsAdministrativeAndGeneralExpense (931) Rents	1,950,065	1,649,801
194	AdministrativeAndGeneralOperationExpense TOTAL Operation (Enter Total of Lines 181 thru 193)	93,296,199	83,168,830
195	AdministrativeAndGeneralExpensesMaintenanceAbstract Maintenance
196	MaintenanceOfGeneralPlant (935) Maintenance of General Plant	11,869,482	10,451,943
197	AdministrativeAndGeneralExpenses TOTAL Administrative & General Expenses (Total of Lines 194 and 196)	105,165,681	93,620,773
198	OperationsAndMaintenanceExpensesElectric TOTAL Electric Operation and Maintenance Expenses (Total of Lines 80, 112, 131, 156, 164, 171, 178, and 197)	1,859,923,604	1,606,620,658

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: FuelSteamPowerGeneration

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.

(b) Concept: PowerProductionExpensesHydraulicPower

ydraulic Power Generation:

Hydraulic Power Generation includes Pumped Storage – See Page 408.

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.

(d) Concept: MaintenanceOfComputerHardwareTransmission

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.

(e) Concept: MaintenanceOfStationEquipment

Account 592.2 contains $0 for maintenance of energy storage equipment.

(f) Concept: PropertyInsurance

The insurance expenses for generation included in APCo’s generation formula rate are identified by a query of the general ledger.

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

PURCHASED POWER (Account 555)
Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the same as, or second only to, the supplier's service to its own ultimate consumers. LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service 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. 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. 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. 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. Report in column (g) the megawatthours shown on bills rendered to the respondent, excluding purchases for energy storage. Report in column (h) the megawatthours shown on bills rendered to the respondent for energy storage purchases. Report in columns (i) and (j) the megawatthours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange. Report demand charges in column (k), energy charges in column (l), and the total of any other types of charges, including out-of-period adjustments, in column (m). Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (n) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (m) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote. The data in columns (g) through (n) must be totaled on the last line of the schedule. The total amount in columns (g) and (h) must be reported as Purchases on Page 401, line 10. The total amount in column (i) must be reported as Exchange Received on Page 401, line 12. The total amount in column (j) must be reported as Exchange Delivered on Page 401, line 13. Footnote entries as required and provide explanations following all required data.
					Actual Demand (MW)				POWER EXCHANGES		COST/SETTLEMENT OF POWER
Line No.	NameOfCompanyOrPublicAuthorityProvidingPurchasedPower Name of Company or Public Authority (Footnote Affiliations) (a)	StatisticalClassificationCode Statistical Classification (b)	RateScheduleTariffNumber Ferc Rate Schedule or Tariff Number (c)	AverageMonthlyBillingDemand Average Monthly Billing Demand (MW) (d)	AverageMonthlyNonCoincidentPeakDemand Average Monthly NCP Demand (e)	AverageMonthlyCoincidentPeakDemand Average Monthly CP Demand (f)	MegawattHoursPurchasedOtherThanStorage MegaWatt Hours Purchased (Excluding for Energy Storage) (g)	MegawattHoursPurchasedForEnergyStorage MegaWatt Hours Purchased for Energy Storage (h)	EnergyReceivedThroughPowerExchanges MegaWatt Hours Received (i)	EnergyDeliveredThroughPowerExchanges MegaWatt Hours Delivered (j)	DemandChargesOfPurchasedPower Demand Charges ($) (k)	EnergyChargesOfPurchasedPower Energy Charges ($) (l)	OtherChargesOfPurchasedPower Other Charges ($) (m)	SettlementOfPower Total (k+l+m) of Settlement ($) (n)
1	BEECH RIDGE ENERGY LLC	OS					255,460					22,833,465		22,833,465
2	BLUFF POINT WIND ENERGY CENTER	OS					380,595					14,169,269		14,169,269
3	CAMP GROVE WIND FARM LLC	OS					205,754					13,637,744		13,637,744
4	FOWLER RIDGE III WIND FARM LLC	OS					175,796					12,659,106		12,659,106
5	GAULEY RIVER POWERS PARTNERS	OS					139,456					5,483,542		5,483,542
6	GRAND RIDGE ENERGY II LLC	OS					116,267					11,575,519		11,575,519
7	GRAND RIDGE WIND FARM 3	OS					111,364					11,057,100		11,057,100
8	ICE TRADE VAULT LLC	OS					0
9	LUMINAIRE TECHNOLOGIES, INC.	OS					861				2,341	47,991		50,332
10	OLD DOMINION ELECTRIC	OS					3					2,673		2,673
11	OVEC POWER SCHEDULING	OS					1,578,993				61,109,292	43,173,818		104,283,110
12	PJM INTERCONNECTION	OS					8,372,173				186,822	370,889,357		371,076,179
13	(a) WIND DEFERRAL	OS					0					12,293,840		12,293,840
15	TOTAL						11,336,722	0	0	0	61,298,455	517,823,424		579,121,879

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: NameOfCompanyOrPublicAuthorityProvidingPurchasedPower

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.

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")

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.
Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
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).
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.
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.
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.
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.
Report in column (i) and (j) the total megawatthours received and delivered.
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 (0) in column (n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report purposes only on Page 401, Lines 16 and 17, respectively.
Footnote entries and provide explanations following all required data.

TRANSFER OF ENERGY

REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS

Line No.

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

(k)

(l)

(m)

(n)

PJM Network Integ Trans Rev Whlsle

Various

FNO

(a)

PJM OATT

Various

11,884,767

PJM Network Integ Trans Serv

Various

FNO

PJM OATT

Various

50,459,240

PJM Trans Enhancement Rev

Various

FNO

PJM OATT

Various

9,240,755

PJM Trans Enhancement Rev Whlsle

Various

FNO

PJM OATT

Various

284,018

PJM Trans Enhancement Rev - Affil

Various

FNO

PJM OATT

Various

192,049

PJM Network Integ Rev - Affil

Various

FNO

PJM OATT

Various

57,921,743

PJM Point to Point Trans Serv

Various

LFP

PJM OATT

Various

6,410,949

PJM Trans Owner Admin Revenue

Various

OLF

PJM OATT

Various

11,284

PJM Trans Owner Serv Rev Whlsle

Various

OLF

PJM OATT

Various

50,698

PJM Power Factor Credits Rev Whlsl

Various

PJM OATT

Various

(b)

97,325

PJM Power Factor Credits Rev Nonaffiliated

Various

PJM OATT

Various

(c)

202,870

PJM Trans Distribution & Meter

Various

PJM OATT

Various

(d)

106,004

PJM Trans Owner Serv Revenue Affiliated

Various

OLF

PJM OATT

Various

2,128,392

TOTAL

136,393,521

2,190,374

406,199

138,990,094

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: RateScheduleTariffNumber

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.

(b) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Per Proforma ILDSA (Interconnection and Local Delivery Service Agreement) AEP Tariff 3rd Revised Volume No. 6

(d) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Per Proforma ILDSA (Interconnection and Local Delivery Service Agreement) AEP Tariff 3rd Revised Volume No. 6

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

TRANSMISSION OF ELECTRICITY BY ISO/RTOs
Report in Column (a) the Transmission Owner receiving revenue for the transmission of electricity by the ISO/RTO. Use a separate line of data for each distinct type of transmission service involving the entities listed in Column (a). 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. 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. In column (d) report the revenue amounts as shown on bills or vouchers. Report in column (e) the total revenues distributed to the entity listed in column (a).
Line No.	Payment Received by (Transmission Owner Name) (a)	Statistical Classification (b)	FERC Rate Schedule or Tariff Number (c)	Total Revenue by Rate Schedule or Tariff (d)	Total Revenue (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
48
49
40	TOTAL

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
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. 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. 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. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service. 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. Enter ""TOTAL"" in column (a) as the last line. Footnote entries and provide explanations following all required data.
			TRANSFER OF ENERGY		EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
Line No.	NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers Name of Company or Public Authority (Footnote Affiliations) (a)	StatisticalClassificationCode Statistical Classification (b)	TransmissionOfElectricityByOthersEnergyReceived MegaWatt Hours Received (c)	TransmissionOfElectricityByOthersEnergyDelivered MegaWatt Hours Delivered (d)	DemandChargesTransmissionOfElectricityByOthers Demand Charges ($) (e)	EnergyChargesTransmissionOfElectricityByOthers Energy Charges ($) (f)	OtherChargesTransmissionOfElectricityByOthers Other Charges ($) (g)	ChargesForTransmissionOfElectricityByOthers Total Cost of Transmission ($) (h)
1	PJM-Enhancements	OS					(a) 39,251,568	39,251,568
2	PJM-NITS	OS					(b) 275,566,186	275,566,186
3	PJM - Trans Owner Serv	OS					(c) 1,564,707	1,564,707
	TOTAL		0	0	0	0	316,382,461	316,382,461

FOOTNOTE DATA

(a) Concept: OtherChargesTransmissionOfElectricityByOthers

Transmission Enhancement Charges and Credits (PJM OATT Schedule 12)

(b) Concept: OtherChargesTransmissionOfElectricityByOthers

Network Integration Transmission Service Charges - NITS (PJM OATT Attachment H)

Transmission Owner Charges and Credits (PJM OATT Tariff Sixth Revised Volume No. 1.)

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line No.	Description (a)	Amount (b)
1	IndustryAssociationDues Industry Association Dues	498,997
2	NuclearPowerResearchExpenses Nuclear Power Research Expenses
3	OtherExperimentalAndGeneralResearchExpenses Other Experimental and General Research Expenses	1,633
4	PublicationAndDistributionExpensesForSecuritiesToStockholders Pub and Dist Info to Stkhldrs...expn servicing outstanding Securities
5	OtherMiscellaneousGeneralExpenses Oth Expn greater than or equal to 5,000 show purpose, recipient, amount. Group if less than $5,000
6	Associated Business Development	6,123,111
7	Affiliated Intercompany Billings	699,765
8	Broadband Study	151,344
9	Corporate Contributions and Memberships	99,431
10	Various Chambers of Commerce	17,156
11	Trustee Fees	72,150
12	Utility Corp Borrowing Program Shared Costs	95,530
13	Various Expenses	128
46	MiscellaneousGeneralExpenses TOTAL	7,759,245

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

Depreciation and Amortization of Electric Plant (Account 403, 404, 405)
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). Report in Section B 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. 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 of 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. 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
Line No.	FunctionalClassificationAxis Functional Classification (a)	DepreciationExpenseExcludingAmortizationOfAcquisitionAdjustments Depreciation Expense (Account 403) (b)	DepreciationExpenseForAssetRetirementCostsExcludingAmortizationgOfAcquisitionAdjustments Depreciation Expense for Asset Retirement Costs (Account 403.1) (c)	AmortizationOfLimitedTermPlantOrProperty Amortization of Limited Term Electric Plant (Account 404) (d)	AmortizationOfOtherElectricPlant Amortization of Other Electric Plant (Acc 405) (e)	DepreciationAndAmortization Total (f)
1	Intangible Plant			40,820,370		40,820,370
2	Steam Production Plant	207,937,131	3,337,664			211,274,795
3	Nuclear Production Plant
4	Hydraulic Production Plant-Conventional	6,307,031	30,476			6,337,507
5	Hydraulic Production Plant-Pumped Storage	4,336,435	45,648			4,382,082
6	Other Production Plant	18,020,136				18,020,136
7	Transmission Plant	88,254,494				88,254,494
8	Distribution Plant	162,137,437	69			162,137,505
9	Regional Transmission and Market Operation
10	General Plant	10,628,975	38,391	435,944		11,103,309
11	Common Plant-Electric
12	TOTAL	497,621,638	3,452,247	41,256,314		542,330,199

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.

	C. Factors Used in Estimating Depreciation Charges
Line No.	AccountNumberFactorsUsedInEstimatingDepreciationCharges Account No. (a)	DepreciablePlantBase Depreciable Plant Base (in Thousands) (b)	UtilityPlantEstimatedAverageServiceLife Estimated Avg. Service Life (c)	UtilityPlantNetSalvageValuePercentage Net Salvage (Percent) (d)	UtilityPlantAppliedDepreciationRate Applied Depr. Rates (Percent) (e)	MortalityCurveType Mortality Curve Type (f)	UtilityPlantWeightedAverageRemainingLife Average Remaining Life (g)
12	STEAM
13	311 - Amos U1&2	57,973	61 years	3	3.07
14	311 - Amos U3	117,018	60 years	3	2.97
15	311 - Central Plt Maint	86	0 years		2.02
16	311 - Clinch River	26,929	67 years	4	0.94
17	311 - Little Broad Mtn	267	0 years		3.62
18	311 - Mountaineer	200,421	60 years	5	2.92
19	312 - Amos U1&2	1,376,120	61 years	3	3.91
20	312 - Amos U1&2 SCR	20,163	61 years	3	7.26
21	312 - Amos U3	1,570,144	60 years	3	4.06
22	312 - Amos U3 SCR	18,634	60 years	3	9.72
23	312 - Clinch River	214,933	67 years	4	5.43
24	312 - Little Broad Mtn	50,334	0 years		3.71
25	312 - Mountaineer	1,149,600	60 years	5	3.07
26	312 - Mountaineer SCR	18,740	8 years	5	10.85
27	314 - Amos U1&2	126,216	61 years	3	4.96
28	314 - Amos U3	159,493	60 years	3	4.5
29	314 - Clinch River	40,581	67 years	4	2.37
30	314 - Mountaineer	127,023	60 years	5	3.1
31	315 - Amos U1&2	57,653	61 years	3	3.91
32	315 - Amos U3	37,257	60 years	3	2.85
33	315 - Clinch River	10,961	67 years	4	1.31
34	315 - Little Broad Mtn	65	0 years		3.76
35	315 - Mountaineer	76,277	60 years	5	1.87
36	316 - Amos U1&2	5,493	61 years	3	5.08
37	316 - Amos U3	29,089	60 years	3	3.2
38	316 - Centrl Mach Shop	21,795	0 years		2.63
39	316 - Clinch River	6,436	67 years	4	4.26
40	316 - Mountaineer	22,949	60 years	5	2.54
41	TOTAL STEAM	5,542,650
42	HYDRO
43	331 - Buck Hydro	570	112 years	24	4.9
44	331 - Byllesby Hydro	1,216	112 years	24	9.83
45	331 - Claytor Hydro	3,863	102 years	24	3.08
46	331 - Leesville Hydro	3,839	76 years	24	2.77
47	331 - London Hydro	617	109 years	24	2.69
48	331 - Marmet Hydro	946	109 years	24	2.01
49	331 - Niagara Hydro	678	118 years	24	16.63
50	331 - Winfield Hydro	2,754	106 years	24	2.97
51	332 - Buck Hydro	7,896	112 years	24	9.32
52	332 - Byllesby Hydro	7,441	112 years	24	12.9
53	332 - Claytor Hydro	12,714	102 years	24	2.19
54	332 - Leesville Hydro	12,111	76 years	24	2.19
55	332 - London Hydro	1,696	109 years	24	1.97
56	332 - Marmet Hydro	1,880	109 years	24	2.33
57	332 - Niagara Hydro	6,734	118 years	24	9.35
58	332 - Winfield Hydro	2,767	106 years	24	2.22
59	333 - Buck Hydro	1,937	112 years	24	6.77
60	333 - Byllesby Hydro	3,697	112 years	24	11.69
61	333 - Claytor Hydro	4,184	102 years	24	3.08
62	333 - Leesville Hydro	3,764	76 years	24	2.02
63	333 - London Hydro	8,376	109 years	24	2.99
64	333 - Marmet Hydro	8,696	109 years	24	3.4
65	333 - Niagara Hydro	640	118 years	24	5.23
66	333 - Winfield Hydro	7,717	106 years	24	3.32
67	334 - Buck Hydro	2,518	112 years	24	7.71
68	334 - Byllesby Hydro	1,081	112 years	24	7.18
69	334 - Claytor Hydro	3,103	102 years	24	2.65
70	334 - Leesville Hydro	1,975	76 years	24	4.03
71	334 - London Hydro	1,923	109 years	24	2.16
72	334 - Marmet Hydro	2,191	109 years	24	2.21
73	334 - Niagara Hydro	500	118 years	24	13.51
74	334 - Winfield Hydro	270	106 years	24	3.18
75	335 - Buck Hydro	942	112 years	24	14.45
76	335 - Byllesby Hydro	1,035	112 years	24	9.53
77	335 - Claytor Hydro	3,056	102 years	24	3.27
78	335 - Leesville Hydro	3,123	76 years	24	3.34
79	335 - London Hydro	517	109 years	24	2.66
80	335 - Marmet Hydro	703	109 years	24	2.44
81	335 - Niagara Hydro	307	118 years	24	8.85
82	335 - Winfield Hydro	3,232	106 years	24	2.02
83	336 - Buck Hydro	3	112 years	24	2.44
84	336 - Claytor Hydro	32	102 years	24	0.98
85	336 - Leesville Hydro	81	76 years	24	0.99
86	336 - London Hydro	49	109 years	24	1.19
87	336 - Marmet Hydro	1	109 years	24	1.16
88	336 - Winfield Hydro	24	106 years	24	2.09
89	TOTAL HYDRO	133,399
90	HYDRO PUMPED
91	331	16,356	75 years	24	2.14
92	332	32,125	75 years	24	1.54
93	333	78,241	75 years	24	3.38
94	334	12,780	75 years	24	3.66
95	335	10,264	75 years	24	3.66
96	336	1,052	75 years	24	1.05
97	TOTAL HYDRO PUMPED	150,818
98	OTHER GENERATION
99	341 Ceredo Plant	1,652	40 years		1.27
100	341 Dresden Plant	48,517	35 years	1	3.34
101	341 Dresden - VA AFUDC	951	0 years		19.51
102	342 Dresden Plant	26,209	35 years	1	3.01
103	342 Dresden - VA AFUDC	479	0 years		19.51
104	344 Ceredo Plant	180,621	40 years		1.32
105	344 Dresden Plant	323,056	35 years	1	3.07
106	344 Dresden - VA AFUDC	6,591	0 years		19.51
107	345 Ceredo Plant	19,434	40 years		1.48
108	345 Dresden Plant	27,938	35 years	1	3.26
109	345 Dresden - VA AFUDC	477	0 years		19.51
110	346 Ceredo Plant	1,270	40 years		3.7
111	346 Dresden Plant	30,900	35 years	1	3.74
112	346 Dresden - VA AFUDC	77	0 years		19.51
113	348 Battery Storage	5,726	0 years		5
114	TOTAL OTHER	673,898
115	TRANSMISSION
116	350 - VA (Rights)	97,601	0 years		0.66
117	352	169,425	60 years	20	1.86	R3
118	353	2,013,345	43 years	10	2.52	R2
119	353 Dresden Plant - VA AFUDC	873	0 years		19.51
120	353.16	15,542	43 years	10	2.52	R2
121	354	514,149	75 years	19	1.67	R4
122	355	522,241	37 years	20	3.03	L1.5
123	356	734,356	68 years	8	1.66	R4
124	356.16	40,675	68 years	8	1.66	R4
125	357	17,385	42 years		2.97	S6
126	358	20,884	24 years		4.7	L3.5
127	358.16	7,891	24 years		4.7	L3.5
128	TOTAL TRANSMISSION	4,154,367
129	DISTRIBUTION
130	360 - VA (Rights)	24,703	0 years		1.49
131	361 - VA	41,443	50 years	10	2.46	R5
132	361 - WV	26,460	55 years	12	1.9	R3
133	361-373 - TN	47	0 years		4
134	362 - VA	412,908	50 years	19	2.32	L0.5
135	362 - WV	277,114	45 years	16	2.52	R1
136	362.16 - VA	6,173	50 years	19	2.32	L0.5
137	362.16 - WV	3,754	45 years	16	2.52	R1
138	363 - WV	5,333	15 years		7.38	SQ
139	364 - VA	431,175	40 years	72	3.65	R0.5
140	364 - WV	436,890	33 years	67	4.77	R0.5
141	365 - VA	591,814	35 years	18	3.3	R0.5
142	365 - WV	571,354	35 years	16	3.38	R0.5
143	366 - VA	80,848	57 years		1.61	R4
144	366 - WV	63,280	55 years		1.73	R4
145	367 - VA	206,401	51 years		1.83	R2.5
146	367 - WV	117,016	48 years		2.05	R1.5
147	368 - VA	404,944	35 years	21	3.05	L0
148	368 - WV	244,557	27 years	20	4.65	R0.5
149	369 - VA	195,859	35 years	28	3.48	L1.5
150	369 - WV	177,389	30 years	26	4.22	R0.5
151	370 - VA	28,790	15 years	6	8.14	L1
152	370 - WV	41,528	15 years	10	12.43	S6
153	370.16 - VA	93,017	15 years	6	8.14	L1
154	370.16 - WA	35,100	15 years	10	12.43	S6
155	371 - VA	39,417	16 years	21	4.73	L0
156	371 - WV	24,454	12 years	22	9.3	R0.5
157	372 - VA	1	25 years		2.01	L3
158	373 - VA	20,970	23 years	33	5	R0.5
159	373 - WV	11,041	20 years	31	8	R0.5
160	TOTAL DISTRIBUTION	4,613,780
161	GENERAL PLANT
162	390	149,791	45 years	8	1.98	R2.5
163	391	12,024	30 years		3.21	SQ
164	392	9	27 years		3.44	SQ
165	393	2,070	55 years		1.88	SQ
166	394	41,262	43 years	10	2.63	SQ
167	395	3,073	37 years		3.92	SQ
168	396	133	25 years		1.84	SQ
169	397	109,036	24 years	8	4.94	SQ
170	397.12	41	24 years	8	4.94	SQ
171	397.16	19,365	24 years	8	4.94	SQ
172	398	8,105	35 years		2.73	SQ
173	TOTAL GENERAL PLANT	344,909
174	DEPRECIABLE SUM	15,613,821

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

REGULATORY COMMISSION EXPENSES
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. 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. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization. List in columns (f), (g), and (h), expenses incurred during the year which were charged currently to income, plant, or other accounts. Minor items (less than $25,000) may be grouped.
						EXPENSES INCURRED DURING YEAR				AMORTIZED DURING YEAR
						CURRENTLY CHARGED TO
Line No.	RegulatoryCommissionDescription Description (Furnish name of regulatory commission or body the docket or case number and a description of the case) (a)	RegulatoryExpensesAssessedByRegulatoryCommission Assessed by Regulatory Commission (b)	RegulatoryExpensesOfUtility Expenses of Utility (c)	RegulatoryCommissionExpensesAmount Total Expenses for Current Year (d)	OtherRegulatoryAssetsRegulatoryCommissionExpenses Deferred in Account 182.3 at Beginning of Year (e)	NameOfDepartmentRegulatoryCommissionExpensesCharged Department (f)	AccountNumberRegulatoryCommissionExpensesCharged Account No. (g)	RegulatoryComissionExpensesIncurredAndCharged Amount (h)	RegulatoryCommissionExpensesDeferredToOtherRegulatoryAssets Deferred to Account 182.3 (i)	DeferredRegulatoryCommissionExpensesAmortizedInContraAccount Contra Account (j)	DeferredRegulatoryCommissionExpensesAmortized Amount (k)	OtherRegulatoryAssetsRegulatoryCommissionExpenses Deferred in Account 182.3 End of Year (l)
1	Smith Mountain Combination Project #2210 - Proportion of cost of administering the Federal Water Power Act	1,531,695		1,531,695			928	1,531,695
2	Leesville Hydro Project #2210 - Proportion of cost of administering the Federal Water Power Act	133,361		133,361			928	133,361
3	Claytor Hydro Project #739 - Proportion of cost of administering the Federal Water Power Act	284,492		284,492			928	284,492
4	Byllesby Buck Hydro Project #2514 - Proportion of cost of administering the Federal Water Power Act	107,272		107,272			928	107,272
5	Marmet and London Hydro Project #1175 - Proportion of cost of administering the Federal Water Power Act	111,399		111,399			928	111,399
6	Winfield Hydro Project #1290 - Proportion of cost of administering the Federal Water Power Act	65,931		65,931			928	65,931
7	Niagara Hydro Project #2466 - Proportion of cost of administering the Federal Water Power Act	8,430		8,430			928	8,430
8	Misc Exp - items less than $25,000		290,356	290,356			928	290,356
9	West Virginia Base Case		773,344	773,344	207,526		928	595,465		928	177,879	29,646
10	West Virginia Broadband Filing		54,294	54,294			928	54,294
11	Virginia Broadband Pilot Filing		170,628	170,628			928	170,628
12	Virginia Fuel Filing		29,005	29,005			928	29,005
13	West Virginia Environmental RAC Filing		197,879	197,879			928	197,879
14	Virginia Energy Efficiency RAC filing		113,124	113,124			928	113,124
15	Virginia Integrated Resource Plan Filing		48,915	48,915			928	48,915
16	2020 Virginia Triennial Filing		283,865	283,865			928	283,865
17	Virginia Clean Economy Act Filing		307,750	307,750			928	307,750
18	Virginia Triennial Appeal		303,099	303,099			928	303,099
19	West Virginia Coal Combustion Residuals and Effluent Limitation Guidelines Filing		187,634	187,634			928	187,634
20	Virginia Environmental RAC Filing		293,183	293,183			928	293,183
21	Virginia Blue Ridge Petition Filing		59,752	59,752			928	59,752
22	Virginia Transmission RAC Filing		48,175	48,175			928	48,175
23	Virginia Generation RAC Filing		47,848	47,848			928	47,848
24	2023 Virginia Triennial Filing		41,017	41,017			928	41,017
25	FERC Formula Rate Filing		35,719	35,719			928	35,719
26	Kanawha River Plant Demolition Filing		31,510	31,510			928	31,510
27	Virginia Broadband RAC Filing		26,581	26,581			928	26,581
28	State Commission Fees		5,108,851	5,108,851			928	5,108,851
46	TOTAL	2,242,580	8,452,529	10,695,109	207,526			10,517,230			177,879	29,646

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D and 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 and 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). Indicate in column (a) the applicable classification, as shown below: Classifications: Electric R, D and D Performed Internally: Generation hydroelectric Recreation fish and wildlife Other hydroelectric Fossil-fuel steam Internal combustion or gas turbine Nuclear Unconventional generation Siting and heat rejection Transmission Overhead Underground Distribution Regional Transmission and Market Operation Environment (other than equipment) Other (Classify and include items in excess of $50,000.) Total Cost Incurred Electric, R, D and D Performed Externally: Research Support to the electrical Research Council or the Electric Power Research Institute Research Support to Edison Electric Institute Research Support to Nuclear Power Groups Research Support to Others (Classify) Total Cost Incurred Include in column (c) all R, D and 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 and 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 and D activity. 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). 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. If costs have not been segregated for R, D and D activities or projects, submit estimates for columns (c), (d), and (f) with such amounts identified by ""Est."" Report separately research and related testing facilities operated by the respondent.
					AMOUNTS CHARGED IN CURRENT YEAR
Line No.	ResearchDevelopmentAndDemonstrationClassification Classification (a)	ResearchDevelopmentAndDemonstrationDescription Description (b)	ResearchDevelopmentAndDemonstrationCostsIncurredInternally Costs Incurred Internally Current Year (c)	ResearchDevelopmentAndDemonstrationCostsIncurredExternally Costs Incurred Externally Current Year (d)	AccountNumberForResearchDevelopmentAndDemonstrationCosts Amounts Charged In Current Year: Account (e)	ResearchDevelopmentAndDemonstrationCosts Amounts Charged In Current Year: Amount (f)	ResearchDevelopmentAndDemonstrationExpenditures Unamortized Accumulation (g)
1	ELECTRIC UTILITY RESEARCH, DEVELOPMENT &
2	DEMONSTRATION PERFORMED INTERNALLY
3	A(1)b Generation: Fossil - Fuel Steam	Adv. Generation Prog. Management	165,070		506	165,070
4		3 Item(s) Under $50,000	23,664		506	23,664
5	A(1)e Generation: Unconventional generation	2 Item(s) Under $50,000
6	A(2) Transmission:	1 Item(s) Under $50,000	13,046		566	13,046
7	A(3) Distribution:	1 Item(s) Under $50,000	10,274		588	10,274
8	A(5) Environment: (Other Than Equipment)	1 Item(s) Under $50,000	47,359		506	47,359
9	A(6) Other:	Corporate Technology Prog Mgmt	127,205		506,566,588	127,205
10		1 Item(s) Under $50,000	39		506,566,588	39
11	A(6)a:	1 Item(s) Under $50,000	72		506	72
12	A(6)f Other: Metering	1 Item(s) Under $50,000	2,006		588	2,006
13	A(6)g Research - General:	1 Item(s) Under $50,000	2,694		566, 588	2,694
14	A(7) TOTAL COST INCURRED INTERNALLY		391,430			391,430
15	ELECTRIC UTILITY RESEARCH, DEVELOPMENT & DEMONSTRATION PERFORMED EXTERNALLY	7 Item(s) Under $50,000		90,283	506,566,588	90,283
16	B(1) Research Support to Elec. Research Council & Elec. Power Research Inst.	EPRI Research Portfolio		1,313,754	506,566,588	1,313,754
17		EPRI Environmental Science		650,517	506	650,517
18		T Line Robots - Reclass		222,483	566	222,483
19		Low Carbon Resource Initiative		189,866	506,566,588	189,866
20		IT - EPRI Annual Research Port		66,276	506,566,588	66,276
21		27 Item(s) Under $50,000		99,092	506,566,588	99,092
22	B(4) Research Support to Others	3 Item(s) under $50,000		23,180	506, 566	23,180
23	B(5) TOTAL COST INCURRED EXTERNALLY			2,655,451		2,655,451

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

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 No.	Classification (a)	Direct Payroll Distribution (b)	Allocation of Payroll Charged for Clearing Accounts (c)	Total (d)
1	SalariesAndWagesElectricAbstract Electric
2	SalariesAndWagesElectricOperationAbstract Operation
3	SalariesAndWagesElectricOperationProduction Production	25,291,936
4	SalariesAndWagesElectricOperationTransmission Transmission	88,931
5	SalariesAndWagesElectricOperationRegionalMarket Regional Market
6	SalariesAndWagesElectricOperationDistribution Distribution	6,937,073
7	SalariesAndWagesElectricOperationCustomerAccounts Customer Accounts	6,558,776
8	SalariesAndWagesElectricOperationCustomerServiceAndInformational Customer Service and Informational	2,780,566
9	SalariesAndWagesElectricOperationSales Sales
10	SalariesAndWagesElectricOperationAdministrativeAndGeneral Administrative and General	2,407,593
11	SalariesAndWagesElectricOperation TOTAL Operation (Enter Total of lines 3 thru 10)	44,064,875
12	SalariesAndWagesElectricMaintenanceAbstract Maintenance
13	SalariesAndWagesElectricMaintenanceProduction Production	25,179,103
14	SalariesAndWagesElectricMaintenanceTransmission Transmission	86,132
15	SalariesAndWagesElectricMaintenanceRegionalMarket Regional Market
16	SalariesAndWagesElectricMaintenanceDistribution Distribution	26,580,660
17	SalariesAndWagesElectricMaintenanceAdministrativeAndGeneral Administrative and General	2,977,006
18	SalariesAndWagesElectricMaintenance TOTAL Maintenance (Total of lines 13 thru 17)	54,822,901
19	SalariesAndWagesElectricOperationAndMaintenanceAbstract Total Operation and Maintenance
20	SalariesAndWagesElectricProduction Production (Enter Total of lines 3 and 13)	50,471,039
21	SalariesAndWagesElectricTransmission Transmission (Enter Total of lines 4 and 14)	175,063
22	SalariesAndWagesElectricRegionalMarket Regional Market (Enter Total of Lines 5 and 15)
23	SalariesAndWagesElectricDistribution Distribution (Enter Total of lines 6 and 16)	33,517,733
24	SalariesAndWagesElectricCustomerAccounts Customer Accounts (Transcribe from line 7)	6,558,776
25	SalariesAndWagesElectricCustomerServiceAndInformational Customer Service and Informational (Transcribe from line 8)	2,780,566
26	SalariesAndWagesElectricSales Sales (Transcribe from line 9)
27	SalariesAndWagesElectricAdministrativeAndGeneral Administrative and General (Enter Total of lines 10 and 17)	5,384,599
28	SalariesAndWagesElectricOperationAndMaintenance TOTAL Oper. and Maint. (Total of lines 20 thru 27)	98,887,776	7,439,232	106,327,008
29	SalariesAndWagesGasAbstract Gas
30	SalariesAndWagesGasOperationAbstract Operation
31	SalariesAndWagesGasOperationProductionManufacturedGas Production - Manufactured Gas
32	SalariesAndWagesGasOperationProductionNaturalGas Production-Nat. Gas (Including Expl. And Dev.)
33	SalariesAndWagesGasOperationOtherGasSupply Other Gas Supply
34	SalariesAndWagesGasOperationStorageLiquifiedNaturalGasTerminalingAndProcessing Storage, LNG Terminaling and Processing
35	SalariesAndWagesGasOperationTransmission Transmission
36	SalariesAndWagesGasOperationDistribution Distribution
37	SalariesAndWagesGasCustomerAccounts Customer Accounts
38	SalariesAndWagesGasCustomerServiceAndInformational Customer Service and Informational
39	SalariesAndWagesGasSales Sales
40	SalariesAndWagesGasOperationAdministrativeAndGeneral Administrative and General
41	SalariesAndWagesGasOperation TOTAL Operation (Enter Total of lines 31 thru 40)
42	SalariesAndWagesGasMaintenanceAbstract Maintenance
43	SalariesAndWagesGasMaintenanceProductionManufacturedGas Production - Manufactured Gas
44	SalariesAndWagesGasMaintenanceProductionNaturalGas Production-Natural Gas (Including Exploration and Development)
45	SalariesAndWagesGasMaintenanceOtherGasSupply Other Gas Supply
46	SalariesAndWagesGasMaintenanceStorageLngTerminalingAndProcessing Storage, LNG Terminaling and Processing
47	SalariesAndWagesGasMaintenanceTransmission Transmission
48	SalariesAndWagesGasMaintenanceDistribution Distribution
49	SalariesAndWagesGasMaintenanceAdministrativeAndGeneral Administrative and General
50	SalariesAndWagesGasMaintenance TOTAL Maint. (Enter Total of lines 43 thru 49)
51	SalariesAndWagesGasOperationAndMaintenanceAbstract Total Operation and Maintenance
52	SalariesAndWagesGasProductionManufacturedGas Production-Manufactured Gas (Enter Total of lines 31 and 43)
53	SalariesAndWagesGasProductionNaturalGas Production-Natural Gas (Including Expl. and Dev.) (Total lines 32,
54	SalariesAndWagesGasOtherGasSupply Other Gas Supply (Enter Total of lines 33 and 45)
55	SalariesAndWagesGasStorageLngTerminalingAndProcessing Storage, LNG Terminaling and Processing (Total of lines 31 thru
56	SalariesAndWagesGasTransmission Transmission (Lines 35 and 47)
57	SalariesAndWagesGasDistribution Distribution (Lines 36 and 48)
58	SalariesAndWagesGasCustomerAccounts Customer Accounts (Line 37)
59	SalariesAndWagesGasCustomerServiceAndInformational Customer Service and Informational (Line 38)
60	SalariesAndWagesGasSales Sales (Line 39)
61	SalariesAndWagesGasAdministrativeAndGeneral Administrative and General (Lines 40 and 49)
62	SalariesAndWagesGasOperationAndMaintenance TOTAL Operation and Maint. (Total of lines 52 thru 61)
63	SalariesAndWagesOtherUtilityDepartmentsAbstract Other Utility Departments
64	SalariesAndWagesOtherUtilityDepartmentsOperationAndMaintenance Operation and Maintenance
65	SalariesAndWagesOperationsAndMaintenance TOTAL All Utility Dept. (Total of lines 28, 62, and 64)	98,887,776	7,439,232	106,327,008
66	SalariesAndWagesUtilityPlantAbstract Utility Plant
67	SalariesAndWagesUtilityPlantConstructionAbstract Construction (By Utility Departments)
68	SalariesAndWagesUtilityPlantConstructionElectricPlant Electric Plant	48,434,542	3,643,684	52,078,226
69	SalariesAndWagesUtilityPlantConstructionGasPlant Gas Plant
70	SalariesAndWagesUtilityPlantConstructionOther Other (provide details in footnote):
71	SalariesAndWagesUtilityPlantConstruction TOTAL Construction (Total of lines 68 thru 70)	48,434,542	3,643,684	52,078,226
72	SalariesAndWagesPlantRemovalAbstract Plant Removal (By Utility Departments)
73	SalariesAndWagesPlantRemovalElectricPlant Electric Plant	10,900,317	820,020	11,720,337
74	SalariesAndWagesPlantRemovalGasPlant Gas Plant
75	SalariesAndWagesPlantRemovalOther Other (provide details in footnote):
76	SalariesAndWagesPlantRemoval TOTAL Plant Removal (Total of lines 73 thru 75)	10,900,317	820,020	11,720,337
77	SalariesAndWagesOtherAccountsAbstract Other Accounts (Specify, provide details in footnote):
78	SalariesAndWagesOtherAccountsDescription Other Accounts (Specify, provide details in footnote):
79	SalariesAndWagesOtherAccountsDescription 152 - Fuel Stock Undistributed	8,591,762		8,591,762
80	SalariesAndWagesOtherAccountsDescription 154 - Materials and Supplies
81	SalariesAndWagesOtherAccountsDescription 163 - Stores Expense Undistributed	5,137,773	5,137,773
82	SalariesAndWagesOtherAccountsDescription 183 - Prelim Survey	36,855	36,855
83	SalariesAndWagesOtherAccountsDescription 184 - Clearing Accounts	6,728,308	6,728,308
84	SalariesAndWagesOtherAccountsDescription 185 - ODD Temporary Facilities	225,464		225,464
85	SalariesAndWagesOtherAccountsDescription 186 - Misc Deferred Debits	1,499,074		1,499,074
86	SalariesAndWagesOtherAccountsDescription 188 - Research & Development	2,215		2,215
87	SalariesAndWagesOtherAccountsDescription 242 - Misc Current & Accrued Liab
88	SalariesAndWagesOtherAccountsDescription 401 - Operation Expense - Nonassociated	219		219
89	SalariesAndWagesOtherAccountsDescription 426 - Political Activities	395,811		395,811
90	SalariesAndWagesOtherAccountsDescription
91	SalariesAndWagesOtherAccountsDescription
92	SalariesAndWagesOtherAccountsDescription
93	SalariesAndWagesOtherAccountsDescription
94	SalariesAndWagesOtherAccountsDescription
95	SalariesAndWagesOtherAccounts TOTAL Other Accounts	22,613,051	11,902,936	10,710,115
96	SalariesAndWagesGeneralExpense TOTAL SALARIES AND WAGES	180,835,686		180,835,686

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

COMMON UTILITY PLANT AND EXPENSES
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 Electric 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. 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. 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. Give date of approval by the Commission for use of the common utility plant classification and reference to the order of the Commission or other authorization.

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS
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 No.	Description of Item(s) (a)	Balance at End of Quarter 1 (b)	Balance at End of Quarter 2 (c)	Balance at End of Quarter 3 (d)	Balance at End of Year (e)
1	Energy
2	Net Purchases (Account 555)				350,465,570
2.1	Net Purchases (Account 555.1)
3	Net Sales (Account 447)				148,544,555
4	Transmission Rights				35,502,675
5	Ancillary Services				5,801,575
6	Other Items (list separately)
7	Congestion				37,377,583
8	Operating Reserves				1,555,354
9	Transmission Purchase Expense				21,282,169
10	Transmission Losses				21,420,123
11	Meter Correction				912,772
12	Inadvertent				108,791
13	Capacity Credits				7,548,753
46	TOTAL				244,217,246

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

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. On Line 1 columns (b), (c), (d), and (e) report the amount of ancillary services purchased and sold during the year. On Line 2 columns (b), (c), (d), and (e) report the amount of reactive supply and voltage control services purchased and sold during the year. On Line 3 columns (b), (c), (d), and (e) report the amount of regulation and frequency response services purchased and sold during the year. On Line 4 columns (b), (c), (d), and (e) report the amount of energy imbalance services purchased and sold during the year. On Lines 5 and 6, columns (b), (c), (d), and (e) report the amount of operating reserve spinning and supplement services purchased and sold during the period. On Line 7 columns (b), (c), (d), and (e) 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
Line No.	Type of Ancillary Service (a)	Number of Units (b)	Unit of Measure (c)	Dollar (d)	Number of Units (e)	Unit of Measure (f)	Dollars (g)
1	Scheduling, System Control and Dispatch	(a) 0
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)

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: AncillaryServicesPurchasedNumberOfUnits

The final grandfathered contracts (under the AEP OATT) expired 12/31/2010. Currently, services are provided under the SPP and PJM OATTs.

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

MONTHLY TRANSMISSION SYSTEM PEAK LOAD
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. Report on Column (b) by month the transmission system's peak load. Report on Columns (c ) and (d) the specified information for each monthly transmission - system peak load reported on Column (b). 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.
Line No.	Month (a)	Monthly Peak MW - Total (b)	Day of Monthly Peak (c)	Hour of Monthly Peak (d)	Firm Network Service for Self (e)	Firm Network Service for Others (f)	Long-Term Firm Point-to-point Reservations (g)	Other Long-Term Firm Service (h)	Short-Term Firm Point-to-point Reservation (i)	Other Service (j)
	NAME OF SYSTEM: 0
1	January	(a) 0
2	February
3	March
4	Total for Quarter 1				0	0	0	0	0	0
5	April
6	May
7	June
8	Total for Quarter 2				0	0	0	0	0	0
9	July
10	August
11	September
12	Total for Quarter 3				0	0	0	0	0	0
13	October
14	November
15	December
16	Total for Quarter 4				0	0	0	0	0	0
17	Total				0	0	0	0	0	0

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: MonthlyPeakLoadExcludingIsoAndRto

Appalachian Power Company's transmission service is administered through an RTO/ISO and requested

information is not available on an individual operating company basis.

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

Monthly ISO/RTO Transmission System Peak Load
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. Report on Column (b) by month the transmission system's peak load. Report on Column (c) and (d) the specified information for each monthly transmission - system peak load reported on Column (b). 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). Amounts reported in Column (j) for Total Usage is the sum of Columns (h) and (i).
Line No.	Month (a)	Monthly Peak MW - Total (b)	Day of Monthly Peak (c)	Hour of Monthly Peak (d)	Import into ISO/RTO (e)	Exports from ISO/RTO (f)	Through and Out Service (g)	Network Service Usage (h)	Point-to-Point Service Usage (i)	Total Usage (j)
	NAME OF SYSTEM: 0
1	January
2	February
3	March
4	Total for Quarter 1				0	0	0	0	0	0
5	April
6	May
7	June
8	Total for Quarter 2				0	0	0	0	0	0
9	July
10	August
11	September
12	Total for Quarter 3				0	0	0	0	0	0
13	October
14	November
15	December
16	Total for Quarter 4				0	0	0	0	0	0
17	Total Year to Date/Year				0	0	0	0	0	0

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

2022-05-19

Year/Period of Report

End of:

2021

ELECTRIC ENERGY ACCOUNT
Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.
Line No.	Item (a)	MegaWatt Hours (b)	Line No.	Item (a)	MegaWatt Hours (b)
1	SOURCES OF ENERGY		21	DISPOSITION OF ENERGY
2	Generation (Excluding Station Use):		22	Sales to Ultimate Consumers (Including Interdepartmental Sales)	26,845,286
3	Steam	19,279,417	23	Requirements Sales for Resale (See instruction 4, page 311.)	2,800,056
4	Nuclear		24	Non-Requirements Sales for Resale (See instruction 4, page 311.)	4,167,084
5	Hydro-Conventional	602,111	25	Energy Furnished Without Charge	(a) 341,985
6	Hydro-Pumped Storage	403,818	26	Energy Used by the Company (Electric Dept Only, Excluding Station Use)
7	Other	4,431,916	27	Total Energy Losses	2,146,304
8	Less Energy for Pumping	437,239	27.1	Total Energy Stored
9	Net Generation (Enter Total of lines 3 through 8)	24,280,023	28	TOTAL (Enter Total of Lines 22 Through 27.1) MUST EQUAL LINE 20 UNDER SOURCES	35,616,745
10	Purchases (other than for Energy Storage)	11,336,722
10.1	Purchases for Energy Storage	0
11	Power Exchanges:
12	Received	0
13	Delivered	0
14	Net Exchanges (Line 12 minus line 13)	0
15	Transmission For Other (Wheeling)
16	Received
17	Delivered
18	Net Transmission for Other (Line 16 minus line 17)	0
19	Transmission By Others Losses
20	TOTAL (Enter Total of Lines 9, 10, 10.1, 14, 18 and 19)	35,616,745

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

2022-05-19

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: NonChargedEnergy

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)

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

MONTHLY PEAKS AND OUTPUT
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. Report in column (b) by month the system’s output in Megawatt hours for each month. Report in column (c) by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales. Report in column (d) by month the system’s monthly maximum megawatt load (60 minute integration) associated with the system. Report in column (e) and (f) the specified information for each monthly peak load reported in column (d).
Line No.	MonthAxis Month (a)	EnergyActivity Total Monthly Energy (b)	NonRequiredSalesForResaleEnergy Monthly Non-Requirement Sales for Resale & Associated Losses (c)	MonthlyPeakLoad Monthly Peak - Megawatts (d)	DayOfMonthlyPeak Monthly Peak - Day of Month (e)	HourOfMonthlyPeak Monthly Peak - Hour (f)
	NAME OF SYSTEM: 0
29	January	3,464,932	247,297	5,966	29	8
30	February	3,434,973	493,653	5,975	8	8
31	March	2,654,975	63,293	5,393	8	8
32	April	2,425,438	150,812	4,913	2	8
33	May	2,790,683	533,168	4,842	26	17
34	June	3,236,698	724,443	5,176	29	18
35	July	3,365,867	643,829	5,309	29	17
36	August	3,413,553	645,916	5,363	25	15
37	September	2,539,650	199,584	4,914	14	17
38	October	2,310,350	33,237	4,113	15	17
39	November	2,723,639	59,967	5,335	24	8
40	December	3,255,987	570,781	5,422	9	8
41	Total	35,616,745	4,365,980

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

Steam Electric Generating Plant Statistics

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.
9. Items under Cost of Plant are based on USofA 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.

Line No.	Item (a)	Plant Name: 0	Plant Name: Amos	Plant Name: Ceredo	Plant Name: Clinch River	Plant Name: Dresden	Plant Name: Mountaineer
1	PlantKind Kind of Plant (Internal Comb, Gas Turb, Nuclear)		STEAM	GAS TURBINE	STEAM	COMBINED CYCLE	STEAM
2	PlantConstructionType Type of Constr (Conventional, Outdoor, Boiler, etc)		CONVENTIONAL	NO BOILER	CONVENTIONAL	OUTDOOR HRSG	OUTDOOR BOILER
3	YearPlantOriginallyConstructed Year Originally Constructed		1971	2001	1958	2012	1980
4	YearLastUnitOfPlantInstalled Year Last Unit was Installed		1973	2001	1961	2012	1980
5	InstalledCapacityOfPlant Total Installed Cap (Max Gen Name Plate Ratings-MW)		2,963.00	519.18	712.50	669.00	1,320.00
6	NetPeakDemandOnPlant Net Peak Demand on Plant - MW (60 minutes)		2,933	555	460	667	1,322
7	PlantHoursConnectedToLoad Plant Hours Connected to Load		5,520	791	761	7,373	6,163
8	NetContinuousPlantCapability Net Continuous Plant Capability (Megawatts)		0	0	0	0	0
9	NetContinuousPlantCapabilityNotLimitedByCondenserWater When Not Limited by Condenser Water		2,930	516	465	665	1,320
10	NetContinuousPlantCapabilityLimitedByCondenserWater When Limited by Condenser Water		2,930	450	455	570	1,305
11	PlantAverageNumberOfEmployees Average Number of Employees		231	5	36	33	157
12	NetGenerationExcludingPlantUse Net Generation, Exclusive of Plant Use - kWh		12,012,357,000	331,156,000	133,135,000	4,100,760,000	7,133,925,000
13	CostOfLandAndLandRightsSteamProduction Cost of Plant: Land and Land Rights		7,307,834	910,000	501,098	2,286,932	4,554,535
14	CostOfStructuresAndImprovementsSteamProduction Structures and Improvements		175,039,410	1,652,232	26,934,648	50,145,564	200,760,618
15	CostOfEquipmentSteamProduction Equipment Costs		3,399,619,485	203,323,571	273,185,799	421,128,110	1,445,722,724
16	AssetRetirementCostsSteamProduction Asset Retirement Costs		83,276,248	0	4,831,339	0	8,817,858
17	CostOfPlant Total cost (total 13 thru 20)		3,665,242,977	205,885,804	305,452,885	473,560,607	1,659,855,736
18	CostPerKilowattOfInstalledCapacity Cost per KW of Installed Capacity (line 17/5) Including		1,237.0040	396.5596	428.7058	707.8634	1,257.4665
19	OperationSupervisionAndEngineeringExpense Production Expenses: Oper, Supv, & Engr		12,552,669	292,470	1,207,400	510,725	5,247,484
20	FuelSteamPowerGeneration Fuel		302,440,068	18,764,167	(a) 12,438,963	89,846,704	150,802,275
21	CoolantsAndWater Coolants and Water (Nuclear Plants Only)		0	0	0	0	0
22	SteamExpensesSteamPowerGeneration Steam Expenses		31,541,666	80,301	3,120,010	189,270	15,601,017
23	SteamFromOtherSources Steam From Other Sources		0	0	0	0	0
24	SteamTransferredCredit Steam Transferred (Cr)		0	0	0	0	0
25	ElectricExpensesSteamPowerGeneration Electric Expenses		165,461	556,276	37,891	0	0
26	MiscellaneousSteamPowerExpenses Misc Steam (or Nuclear) Power Expenses		7,102,487	199,382	1,112,584	3,167,981	7,939,994
27	RentsSteamPowerGeneration Rents		27,093	1	0	0	12,008
28	Allowances Allowances		97,038	0	466,537	156	48,342
29	MaintenanceSupervisionAndEngineeringSteamPowerGeneration Maintenance Supervision and Engineering		310,606	0	3,802	588,717	1,460,300
30	MaintenanceOfStructuresSteamPowerGeneration Maintenance of Structures		1,974,018	0	967,376	130,311	1,158,109
31	MaintenanceOfBoilerPlantSteamPowerGeneration Maintenance of Boiler (or reactor) Plant		30,316,625	3	1,796,430	759,273	14,636,160
32	MaintenanceOfElectricPlantSteamPowerGeneration Maintenance of Electric Plant		6,975,232	237,409	785,947	3,380,560	2,201,010
33	MaintenanceOfMiscellaneousSteamPlant Maintenance of Misc Steam (or Nuclear) Plant		6,633,532	0	1,007,704	2,047,814	2,111,958
34	PowerProductionExpensesSteamPower Total Production Expenses	0	400,136,495	20,130,009	22,944,644	100,621,511	201,218,657
35	ExpensesPerNetKilowattHour Expenses per Net kWh		0.0333	0.0608	0.1723	0.0245	0.0282

35	FuelKindAxis Plant Name	Amos	Amos	Ceredo	Clinch River	Dresden	Mountaineer	Mountaineer
36	FuelKind Fuel Kind	Coal	Oil	Gas	Gas	Gas	Coal	Oil
37	FuelUnit Fuel Unit	T	bbl	Mcf	Mcf	Mcf	T	bbl
38	QuantityOfFuelBurned Quantity (Units) of Fuel Burned	4,839,623	94,027	3,713,406	1,598,300	26,321,820	2,779,824	27,784
39	FuelBurnedAverageHeatContent Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)	12,256	137,063	1,089,000	1,034,000	1,062,000	12,523	137,173
40	AverageCostOfFuelPerUnitAsDelivered Avg Cost of Fuel/unit, as Delvd f.o.b. during year	53.634	90.787	5.046	7.784	3.436	47.489	81.061
41	AverageCostOfFuelPerUnitBurned Average Cost of Fuel per Unit Burned	54.373	88.905	5.053	7.751	3.431	47.527	77.921
42	AverageCostOfFuelBurnedPerMillionBritishThermalUnit Average Cost of Fuel Burned per Million BTU	2.218	15.444	4.640	7.496	3.231	1.898	13.525
43	AverageCostOfFuelBurnedPerKilowattHourNetGeneration Average Cost of Fuel Burned per kWh Net Gen	0.022	0.000	0.057	0.093	0.022	0.019	0.000
44	AverageBritishThermalUnitPerKilowattHourNetGeneration Average BTU per kWh Net Generation	9,921.000	0.000	12,215.000	12,197.000	6,821.000	9,782.000	0.000

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: FuelSteamPowerGeneration

Deferred Fuel expenses totaling $(170,684,039) are not included in the Fuel totals that are broken down by generating plants. Deferred fuel expenses for Virginia and West Virginia were $(125,226,589) and $(45,457,450) respectively.

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

Hydroelectric Generating Plant Statistics

Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings).
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.
If net peak demand for 60 minutes is not available, give that which is available specifying period.
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.
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."
Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.

Line No.	Item (a)	FERC Licensed Project No. 0 Plant Name: 0	FERC Licensed Project No. 0 Plant Name: BUCK	FERC Licensed Project No. 0 Plant Name: BYLLESBY	FERC Licensed Project No. 0 Plant Name: CLAYTOR	FERC Licensed Project No. 0 Plant Name: LEESVILLE	FERC Licensed Project No. 0 Plant Name: LONDON	FERC Licensed Project No. 0 Plant Name: MARMET	FERC Licensed Project No. 0 Plant Name: WINFIELD
1	PlantKind Kind of Plant (Run-of-River or Storage)		STORAGE	STORAGE	STORAGE	STORAGE	RUN OF RIVER	RUN OF RIVER	RUN OF RIVER
2	PlantConstructionType Plant Construction type (Conventional or Outdoor)		CONVENTIONAL	CONVENTIONAL	CONVENTIONAL	OUTDOOR	CONVENTIONAL	CONVENTIONAL	CONVENTIONAL
3	YearPlantOriginallyConstructed Year Originally Constructed		1912	1912	1939	1964	1935	1935	1938
4	YearLastUnitOfPlantInstalled Year Last Unit was Installed		1912	1912	1939	1964	1935	1935	1938
5	InstalledCapacityOfPlant Total installed cap (Gen name plate Rating in MW)		10.7	21.6	75.0	40.0	14.4	14.4	14.8
6	NetPeakDemandOnPlant Net Peak Demand on Plant-Megawatts (60 minutes)		10	13	78	49	18	12	22
7	PlantHoursConnectedToLoad Plant Hours Connect to Load		8,219	4,814	5,621	1,940	7,231	6,948	8,370
8	NetPlantCapabilityAbstract Net Plant Capability (in megawatts)
9	NetPlantCapabilityUnderMostFavorableOperatingConditions (a) Under Most Favorable Oper Conditions		11	23	88	48	19	20	24
10	NetPlantCapabilityUnderMostAdverseOperatingConditions (b) Under the Most Adverse Oper Conditions
11	PlantAverageNumberOfEmployees Average Number of Employees			3	5	1	1	3	4
12	NetGenerationExcludingPlantUse Net Generation, Exclusive of Plant Use - kWh		38,270,000	35,181,000	234,622,000	61,019,000	59,702,000	50,159,000	114,210,000
13	CostOfPlantAbstract Cost of Plant
14	CostOfLandAndLandRightsHydroelectricProduction Land and Land Rights			170,420	1,612,350	1,784,759	21,043	4,100
15	CostOfStructuresAndImprovementsHydroelectricProduction Structures and Improvements		569,860	1,216,147	3,863,364	3,838,701	616,623	946,292	2,754,498
16	CostOfReservoirsDamsAndWaterwaysHydroelectricProduction Reservoirs, Dams, and Waterways		7,895,918	7,441,024	12,713,953	12,110,548	1,696,220	1,880,489	2,767,066
17	EquipmentCostsHydroelectricProduction Equipment Costs		5,396,468	(a) 11,541,773	10,343,031	8,862,027	10,820,120	11,590,411	11,223,913
18	CostOfRoadsRailroadsAndBridgesHydroelectricProduction Roads, Railroads, and Bridges		3,437		31,799	80,790	48,853	1,275	23,567
19	AssetRetirementCostsHydroelectricProduction Asset Retirement Costs			72,046	362,724	196,310	93,690	125,314	137,743
20	CostOfPlant Total cost (total 13 thru 20)		13,865,683.00	20,441,410	28,927,221	26,873,135	13,296,549	14,547,881.00	16,906,787
21	CostPerKilowattOfInstalledCapacity Cost per KW of Installed Capacity (line 20 / 5)		1,295.9	946.3616	385.6963	671.8284	923.3715	1,010.3	1,142.3505
22	ProductionExpensesAbstract Production Expenses
23	OperationSupervisionAndEngineeringExpense Operation Supervision and Engineering		35,873	68,997	310,048	63,397	62,295	198,425	107,125
24	WaterForPower Water for Power			308	502		7,743	7,785	7,742
25	HydraulicExpenses Hydraulic Expenses		2,455	2,998	434,829	187,352	16,902	8,682	13,587
26	ElectricExpensesHydraulicPowerGeneration Electric Expenses		12,999	13,982	80,594	20,727	20,279	17,038	38,794
27	MiscellaneousHydraulicPowerGenerationExpenses Misc Hydraulic Power Generation Expenses		71,861	96,702	593,037	116,544	238,024	322,872	240,851
28	RentsHydraulicPowerGeneration Rents				4,583		90,513	90,511	176,899
29	MaintenanceSupervisionAndEngineeringHydraulicPowerGeneration Maintenance Supervision and Engineering		1,947	8,823	55,378	3,105	3,563	4,488	13,771
30	MaintenanceOfStructuresHydraulicPowerGeneration Maintenance of Structures		15,463	32,013	359,582	789,283	73,652	179,109	406,195
31	MaintenanceOfReservoirsDamsAndWaterways Maintenance of Reservoirs, Dams, and Waterways		189,528	1,164,654	312,364	193,967	114,221	149,137	192,155
32	MaintenanceOfElectricPlantHydraulicPowerGeneration Maintenance of Electric Plant		39,453	121,795	207,288	81,903	310,352	86,265	58,715
33	MaintenanceOfMiscellaneousHydraulicPlant Maintenance of Misc Hydraulic Plant		1,118	3,126	24,232	15,771	22,838	11,919	9,833
34	PowerProductionExpensesHydraulicPower Total Production Expenses (total 23 thru 33)		370,697	1,513,398	2,382,437	1,472,049	960,382	1,076,231	1,265,667
35	ExpensesPerNetKilowattHour Expenses per net kWh		0.0097	0.0430	0.0102	0.0241	0.0161	0.0215	0.0111

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

FOOTNOTE DATA

(a) Concept: EquipmentCostsHydroelectricProduction

Equipment cost amount also includes $5,726,248.80 of battery storage investment in account 34800.

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

Pumped Storage Generating Plant Statistics
Large plants and pumped storage plants of 10,000 Kw or more of installed capacity (name plate ratings). 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. If net peak demand for 60 minutes is not available, give that which is available, specifying period. 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. 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." Pumping energy (Line 10) is that energy measured as input to the plant for pumping purposes. 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.
Line No.	Item (a)	FERC Licensed Project No. 0 Plant Name: 0	FERC Licensed Project No. 0 Plant Name: SMITH MOUNTAIN
1	PlantConstructionType Type of Plant Construction (Conventional or Outdoor)		OUTDOOR
2	YearPlantOriginallyConstructed Year Originally Constructed		1965
3	YearLastUnitOfPlantInstalled Year Last Unit was Installed		1980
4	InstalledCapacityOfPlant Total installed cap (Gen name plate Rating in MW)		647
5	NetPeakDemandOnPlant Net Peak Demaind on Plant-Megawatts (60 minutes)	0	597
6	PlantHoursConnectedToLoad Plant Hours Connect to Load While Generating	0	848
7	NetContinuousPlantCapability Net Plant Capability (in megawatts)	0	565
8	PlantAverageNumberOfEmployees Average Number of Employees		16
9	NetGenerationExcludingPlantUse Generation, Exclusive of Plant Use - kWh	0	403,818,000
10	EnergyUsedForPumping Energy Used for Pumping		437,239,000
11	NetOutputForLoad Net Output for Load (line 9 - line 10) - Kwh	0	33,421,000
12	CostOfPlantAbstract Cost of Plant
13	CostOfLandAndLandRightsPumpedStoragePlant Land and Land Rights		6,168,815
14	CostOfStructuresAndImprovementsPumpedStoragePlant Structures and Improvements	0	16,356,288
15	CostOfReservoirsDamsAndWaterwaysPumpedStoragePlant Reservoirs, Dams, and Waterways	0	32,125,207
16	CostOfWaterWheelsTurbinesAndGeneratorsPumpedStoragePlant Water Wheels, Turbines, and Generators	0	78,241,314
17	CostOfAccessoryElectricEquipmentPumpedStoragePlant Accessory Electric Equipment	0	12,759,209
18	CostOfMiscellaneousPowerPlantEquipmentPumpedStoragePlant Miscellaneous Powerplant Equipment	0	10,305,504
19	CostOfRoadsRailroadsAndBridgesPumpedStoragePlant Roads, Railroads, and Bridges	0	1,052,133
20	AssetRetirementCostsPumpedStoragePlant Asset Retirement Costs	0	1,687,175
21	CostOfPlant Total cost (total 13 thru 20)		158,695,645
22	CostPerKilowattOfInstalledCapacity Cost per KW of installed cap (line 21 / 4)		245.2792
23	ProductionExpensesAbstract Production Expenses
24	OperationSupervisionAndEngineeringExpense Operation Supervision and Engineering	0	752,152
25	WaterForPower Water for Power	0
26	PumpedStorageExpenses Pumped Storage Expenses	0	315,831
27	ElectricExpensesPumpedStoragePlant Electric Expenses	0	190,536
28	MiscellaneousPumpedStoragePowerGenerationExpenses Misc Pumped Storage Power generation Expenses	0	1,645,467
29	RentsPumpedStoragePlant Rents	0
30	MaintenanceSupervisionAndEngineeringPumpedStoragePlant Maintenance Supervision and Engineering	0	147,785
31	MaintenanceOfStructuresPumpedStoragePlant Maintenance of Structures	0	875,664
32	MaintenanceOfReservoirsDamsAndWaterwaysPumpedStoragePlant Maintenance of Reservoirs, Dams, and Waterways	0	459,053
33	MaintenanceOfElectricPlantPumpedStoragePlant Maintenance of Electric Plant	0	1,779,180
34	MaintenanceOfMiscellaneousPumpedStoragePlant Maintenance of Misc Pumped Storage Plant	0	38,282
35	PowerProductionExpenseBeforePumpingExpenses Production Exp Before Pumping Exp (24 thru 34)		6,203,950
36	PumpingExpenses Pumping Expenses		12,179,288
37	PowerProductionExpensesPumpedStoragePlant Total Production Exp (total 35 and 36)		18,383,238
38	ExpensesPerNetKilowattHour Expenses per kWh (line 37 / 9)		0.0455
39	ExpensesPerNetKilowattHourGenerationAndPumping Expenses per KWh of Generation and Pumping (line 37/(line 9 + line 10))

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

GENERATING PLANT STATISTICS (Small Plants)

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).
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.
List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11, Page 402.
If net peak demand for 60 minutes is not available, give the which is available, specifying period.
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

Line No.

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

(k)

(l)

(m)

HYDRO-ELECTRIC

Niagara - Project #2466

1906

3.60

2.3

8,945,000

8,904,780

40,172

123,188

TOTAL HYDRO (Small Plants)

8,945,000

8,904,780

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

ENERGY STORAGE OPERATIONS (Large Plants)
Large Plants are plants of 10,000 Kw or more. In columns (a) (b) and (c) report the name of the energy storage project, functional classification (Production, Transmission, Distribution), and location. In column (d), report Megawatt hours (MWH) purchased, generated, or received in exchange transactions for storage. In columns (e), (f) and (g) report MWHs delivered to the grid to support production, transmission and distribution. The amount reported in column (d) should include MWHs delivered/provided to a generator’s own load requirements or used for the provision of ancillary services. In columns (h), (i), and (j) report MWHs lost during conversion, storage and discharge of energy. In column (k) report the MWHs sold. In column (l), report revenues from energy storage operations. In a footnote, disclose the revenue accounts and revenue amounts related to the income generating activity. In column (m), report the cost of power purchased for storage operations and reported in Account 555.1, Power Purchased for Storage Operations. If power was purchased from an affiliated seller specify how the cost of the power was determined. In columns (n) and (o), report fuel costs for storage operations associated with self-generated power included in Account 501 and other costs associated with self-generated power. In columns (q), (r) and (s) report the total project plant costs including but not exclusive of land and land rights, structures and improvements, energy storage equipment, turbines, compressors, generators, switching and conversion equipment, lines and equipment whose primary purpose is to integrate or tie energy storage assets into the power grid, and any other costs associated with the energy storage project included in the property accounts listed.
Line No.	Name of the Energy Storage Project (a)	Functional Classification (b)	Location of the Project (c)	MWHs (d)	MWHs delivered to the grid to support Production (e)	MWHs delivered to the grid to support Transmission (f)	MWHs delivered to the grid to support Distribution (g)	MWHs Lost During Conversion, Storage and Discharge of Energy Production (h)	MWHs Lost During Conversion, Storage and Discharge of Energy Transmission (i)	MWHs Lost During Conversion, Storage and Discharge of Energy Distribution (j)	MWHs Sold (k)	Revenues from Energy Storage Operations (l)	Power Purchased for Storage Operations (555.1) (Dollars) (m)	Fuel Costs from associated fuel accounts for Storage Operations Associated with Self- Generated Power (Dollars) (n)	Other Costs Associated with Self-Generated Power (Dollars) (o)	Project Costs included in (p)	Production (Dollars) (q)	Transmission (Dollars) (r)	Distribution (Dollars) (s)
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

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

TRANSMISSION LINE STATISTICS
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. If required by a State commission to report individual lines for all voltages, do so but do not group totals for each voltage under 132 kilovolts. 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. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property. 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. 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. 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). 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. 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. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
	DESIGNATION		VOLTAGE (KV) - (Indicate where other than 60 cycle, 3 phase)			LENGTH (Pole miles) - (In the case of underground lines report circuit miles)				COST OF LINE (Include in column (j) Land, Land rights, and clearing right-of-way)			EXPENSES, EXCEPT DEPRECIATION AND TAXES
Line No.	TransmissionLineStartPoint From	TransmissionLineEndPoint To	OperatingVoltageOfTransmissionLine Operating	DesignedVoltageOfTransmissionLine Designated	SupportingStructureOfTransmissionLineType Type of Supporting Structure	LengthForStandAloneTransmissionLines On Structure of Line Designated	LengthForTransmissionLinesAggregatedWithOtherStructures On Structures of Another Line	NumberOfTransmissionCircuits Number of Circuits	SizeOfConductorAndMaterial Size of Conductor and Material	CostOfLandAndLandRightsTransmissionLines Land	ConstructionAndOtherCostsTransmissionLines Construction Costs	OverallCostOfTransmissionLine Total Costs	OperatingExpensesOfTransmissionLine Operation Expenses	MaintenanceExpensesOfTransmissionLine Maintenance Expenses	RentExpensesOfTransmissionLine Rents	OverallExpensesOfTransmissionLine Total Expenses
	(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)	(k)	(l)	(m)	(n)	(o)	(p)
1	STATE OF TENNESSEE	STATE OF TENNESSEE
2	0188 BRADFORD, VA	SULLIVAN, TN	500	500	3	0	0	1	2049KCM ACAR
3	0400 CANE RIVER, TN CIR-A	NAGEL, TN	230	230	3	46	0	1	1590KCM ACSR
4	0400 CANE RIVER, TN CIR-B	NAGEL, TN	230	230	3	1	45	1	1590KCM ACSR
5	0351 CLINCH RIVER, VA	NAGEL, TN	138	138	3	0	0	1	1590KCM ACSR
6	0353 NAGEL, TN	REEDY CREEK, TN	138	138	3	0	0	1	1590KCM ACSR
7	0349 BROADFORD, VA	NAGEL, TN	138	138	3	13	0	1	397KCM ACSR
8	0349 BROADFORD, VA	NAGEL, TN	0	0	1	0	0	0
9	0355 NAGEL, TN	WEST KINGSPORT, TN	138	138	3	0	1	1	556KCM
10	0355 NAGEL, TN	WEST KINGSPORT, TN	0	0	1	0	0	0
11	0176 NORTH BRISTOL, VA	WEST KINGSPORT, VA	138	138	3	6	11	1	397KCM ACSR
12	0176A HOLSTON, TN	REEDY CREEK, TN	138	138	3	0	6	1	397KCM ACSR
13	0179 BOONE DAM, TN	HOLSTON, TN	138	138	3	0	0	1	636KCM ACSR
14	0179 BOONE DAM, TN	HOLSTON, TN	0	0	1	8	0	0
15	0180 HOLSTON, TN	WALTERS, NC	138	138	3	65	0	1	250KCM CU
16	0180 HOLSTON, TN	WALTERS, NC	138	138	1	0	0	1	1033KCM ACSR
17	0570 SALTVILLE	KINGSPORT (TN)	138	138	3	17	0	2	397.5KCM ACSR
18	STATE OF VIRGINIA	STATE OF VIRGINIA				0	0
19	0186 BAKER, KY	BROADFORD, VA	765	765	3	0	0	1	954KCM ACSR
20	0186 BAKER, KY	BROADFORD, VA	0	0	3	47	0	0
21	0187 BROADFORD, VA	JACKSONS FERRY, VA	765	765	3	49	0	1	954KCM ACSR
22	0253 CLOVERDALE, VA	JACKSONS FERRY, VA	765	765	3	65	0	1	954KCM ACSR
23	0310 CLOVERDALE, VA	JOSHUA FALLS, VA	765	765	3	57	0	1	1351KCM ACSR
24	0406 JACKSON FERRY	WYOMING	765	765	3	57	0	1	795 KCM ACSR
25	0334 AXTON, VA	JACKSONS FERRY, VA	765	765	3	73	0	1	1351KCM ACSR
26	0181 BROADFORD, VA	SULLIVAN, TN	500	500	3	33	0	1	2049KCM ACAR
27	0001CLOVERDALE, VA	LEXINGTON, VA	500	500	3	36	0	1	2-1780KCM ACSS
28	0001 CLOVERDALE	LEXINGTON, VA	500	500	2	0	0	1	2-1780kcm ACSS
29	0182 JACKSONS FERRY, VA	MCGUIRE, NC	500	500	3	26	0	1	2049KCM ACAR
30	0008A KANAWHA, WV	MATT FUNK, VA	345	345	3	8	0	1	1563KCM ACAR
31	0008A KANAWHA, WV	MATT FUNK, VA	0	0	3	34	0	0
32	0008 CLOVERDALE, VA	MATT FUNK, VA	345	345	3	0	8	1	954 KCM ACSR
33	0008 CLOVERDALE, VA	MATT FUNK, VA	0	0	3	19	0	0
34	0142 EAST DANVILLE NO. 1,VA	ROXBORO, NC	230	230	3	8	0	1	1590KCM ACSR
35	0142 EAST DANVILLE NO. 2,VA	ROXBORO, NC	230	230	3	0	8	1	1590KCM ACSR
36	0417 BAILEYSVILLE, WV	HALES BRANCH, VA	138	138	3	0	0	1	636KCM ACSR
37	0417 BAILEYSVILLE, WV	HALES BRANCH, VA	0	0	1	6	0	0
38	0054 GARDEN CREEK, VA	HALES BRANCH, VA	138	138	3	0	0	1	636KCM ACSR
39	0054 GARDEN CREEK, VA	HALES BRANCH, VA	0	0	1	7	0	0
40	0409 LOONEY CREEK TAP, VA		138	138	3	10	0	1	795KCM ACSR
41	0434 GRASSY CREEK, VA	HALES BRANCH, VA	138	138	3	0	0	2	1033.5KCM ACSR
42	0434 GRASSY CREEK, VA	HALES BRANCH, VA	138	138	3	6	0	1	795KCM ACSR
43	0434 GRASSY CREEK, VA	HALES BRANCH, VA	0	0	1	2	0	0
44	0110 CLAYTOR, VA	MATT FUNK, VA	138	138	3	30	0	1	397KCM ACSR
45	0110 CLAYTOR, VA	MATT FUNK, VA	138	138	3	0	0	1	556KCM ACSR
46	0112 MATT FUNK, VA	ROANOKE, VA	138	138	3	13	5	1	397KCM ACSR
47	0113 CLAYTOR, VA	HANCOCK, VA	138	138	3	0	39	1	397KCM ACSR
48	0114 HANCOCK, VA	ROANOKE, VA	138	138	3	5	4	1	397KCM ACSR
49	0229 MERRIMAC TAP, VA		138	138	1	7	0	1	556KCM ACSR
50	0138 COLLINSVILLE	TAP LINE	138	138		0	0	0
51	8161 CVEC	SCOTTSVILLE	46	138	3	1	0	1
52	0422 JACKSONS FERRY, VA	PEAK CREEK, VA	138	138	1	13	0	1	795KCM ACSR
53	0422 JACKSONS FERRY, VA	PEAK CREEK, VA	138	138	3	1	0	0	954KCM ACSR
54	0129 PHILPOTT TAP, VA		138	138	1	0	0	1	4/0KCM ACSR
55	0248 CLAYTOR, VA	FIELDALE	138	138	3	0	0	1	556KCM ACSR
56	0248 CLAYTOR, VA	FIELDALE	0	0	1	38	0	0
57	0249 FIELDALE, VA	WEST BASSETT, VA	138	138	3	0	0	1	556KCM ACSR
58	0249 FIELDALE, VA	WEST BASSETT, VA	0	0	1	6	0	0
59	0120 BEAVER CREEK, KY	CLINCH RIVER, VA	138	138	3	26	0	1	636KCM ACSR
60	0120 BEAVER CREEK, KY	CLINCH RIVER, VA	138	138	1	0	0	0	636KCM ACSR
61	0122 CLINCH RIVER, VA	FREMONT, VA	138	138	3	0	18	1	636KCM ACSR
62	0123 BEAVER CREEK, KY	FREMONT, VA	138	138	3	0	9	1	636KCM ACSR
63	0289 COOPER RIDGE LOOP, VA		138	138	1	0	0	1	636KCM ACSR
64	0350 CLINCH RIVER, VA	NAGEL, TN	138	138	3	5	37	1	636KCM ACSR
65	0352 NAGEL, TN	REEDY CREEK, TN	138	138	3	0	5	1	556KCM ACSR
66	0365 DICKENS TAP		138	138	1	3	0	1	795KCM ACSR
67	0259A EAST DANVILLE, WV	EAST MONUMENT	138	138		4	0	0
68	0125 CLINCH RIVER, VA	MORELAND DRIVE, TN	138	138	3	49	0	1	636KCM ACSR
69	0148 CLINCH RIVER, VA	SALTVILLE #1A, VA	138	138	3	0	25	1	636KCM ACSR
70	0148 CLINCH RIVER, VA	SALTVILLE #1B, VA	138	138	3	26	0	1	1033KCM ACSR
71	0256 LEBANON 138KV TAP VA		138	138	1	0	0	1	336KCM ACSR
72	7539 DAN, VA	CAROLINA	138	138		0	0	0
73	0154 CLINCH RIVER, VA	SALTVILLE #2, VA	138	138	3	3	40	1	397KCM ACSR
74	0193 BROADFORD, VA	SALTVILLE NO.2, VA	138	138	3	5	0	2	795KCM ACSR
75	0191 BROADFORD, VA	NAGEL, TN	138	138	3	45	0	1	397KCM ACSR
76	0354 NAGEL, TN	WEST KINGSPORT, TN	138	138	3	0	5	1	1590KCM ACSR
77	0361 CLINCH RIVER, VA	SPRING CREEK, VA	138	138	3	18	4	1	636KCM ACSR
78	0192 NORTH BRISTOL, VA	SPRING CREEK, VA	138	138	3	0	9	1	795 KCM ACSR
79	0153 NORTH BRISTOL, VA	WEST KINGSPORT, VA	138	138	3	0	4	1	397KCM ACSR
80	0167 CLINCH RIVER, VA	GARDEN CREEK, VA	138	138	3	2	0	1	636KCM ACSR
81	0167 CLINCH RIVER, VA	GARDEN CREEK, VA	0	0	1	22	0	0
82	0298 FLETCHERS RIDGE TAP,VA		138	138	1	0	0	1	300KCM CU
83	0313 SKEGGS BRANCH, VA		138	138	1	0	0	1	397KCM ACSR
84	0167A CLINCHFIELD LOOP SITE		138	138	1	0	0	1	636KCM ACSR
85	0416 CLOVERDALE, VA	HUNTINGTON COURT, VA	138	138	3	6	0	1	795KCM ACSR
86	0124 CLOVERDALE, VA	SMITH MOUNTAIN, VA	138	138	3	32	0	1	556KCM ACSR
87	0141 DANVILLE B CIR, VA	EAST DANVILLE, VA	138	138	3	0	3	1	336KCM ACSR
88	1020 CLINCH RIVER	VIRGINA CITY	138	138		0	0	0
89	0358 AXTON, VA	DANVILLE #1-A, VA	138	138	3	0	16	1	336 KCM ACSR
90	0358 AXTON, VA	DANVILLE #1-A, VA	138	138	2	0	0	1	1033.5 ACSR
91	0359 AXTON, VA	MARTINSVILLE, VA	138	138	3	11	0	1	966KCM ACSR
92	0135 AXTON, VA	DANVILLE #2, VA	138	138	3	16	0	1	336KCM ACSR
93	0135 AXTON, VA	DANVILLE #2, VA	0	0	1	3	0	0
94	0135 AXTON, VA	DANVILLE #2, VA	138	138	3	1	0	1	795KCM SSAC
95	0135 AXTON, VA	DANVILLE #2, VA	0	0	1	17	0	0
96	0146 FIELDDALE, VA	RIDGEWAY, VA	138	138	1	10	0	1	397KCM ACSR
97	0300 DAN RIVER, NC	RIDGEWAY, VA	138	138	2	4	0	1	397KCM ACSR
98	0300 DAN RIVER, NC	RIDGEWAY, VA	138	138	1	0	0	1	397KCM ACSR
99	0300 DAN RIVER, NC	RIDGEWAY, VA	138	138	1	0	0	1	1033KCM ACSR
100	0391 SHEFFIELD LOOP		138	138	3	0	0	1	795KCM ACSR
101	0025 GLEN LYN, VA (A)	SOUTH PRINCETON, WV	138	138	3	0	0	1	1590KCM ACSR
102	0025 GLEN LYN, VA (B)	SOUTH PRINCETON, WV	138	138	3	0	0	1	1590KCM ACSR
103	0058 GLEN LYN, VA	WYTHE, VA	138	138	3	29	0	1	556KCM ACSR
104	0058 GLEN LYN, VA	WYTHE, VA	0	0		1	0	0	1590KCM ACSR
105	0058 GLEN LYN, VA	WYTHE, VA	138	138	3	1	29	1	556KCM ACSR
106	0375 PROGRESS PARK EXT		138	138	3	3	0	1	1590KCM ACSR
107	0427 EVINGTON 138KV TAP VA		138	138	2	0	0	0	397KCM ACSR
108	0063 BROADFORD, VA	SALTVILLE NO.1A&1B, VA	138	138	3	4	4	2	795KCM ACSR
109	0063 BROADFORD, VA	SALTVILLE NO.1A&1B, VA	138	138	3	0	4	2	556KCM ACSR
110	0063 BROADFORD, VA	SALTVILLE NO.1A&1B, VA	138	138	1	0	0	2	795KCM ACSR
111	0061B RURAL RETREAT	LOOP, WV	138	138	3	0	0	1	795KCM ACSR
112	0333 BROADFORD, VA	RICHLANDS, VA	138	138	2	14	0	1	1033KCM ACSR
113	0368 CLAY POOL HILL LOOP,VA		138	138	1	0	0	1	1033KCM ACSR
114	0241A HUFFMAN, VA	JACKSONS FERRY, VA	138	138	3	0	2	1	1033KCM ACSR
115	0241A HUFFMAN, VA	JACKSONS FERRY, VA	0	0	1	8	0	0
116	0241 HUFFMAN, VA	WYTHE, VA	138	138	3	2	1	1	795KCM ACSR
117	0241 HUFFMAN, VA	WYTHE, VA	138	138	1	37	0	1	795KCM ACSR
118	0061 ATKINS, VA	BROADFORD CIR A, VA	138	138	3	20	0	1	556KCM ACSR
119	0061 ATKINS, VA	BROADFORD CIR B, VA	138	138	3	0	16	1	556KCM ACSR
120	0063 ATKINS, VA	WYTHE CIR A, VA	138	138	3	22	0	1	1590KCM ACSR
121	0063 ATKINS, VA	WYTHE CIR B, VA	138	138	3	0	21	1	556KCM ACSR
122	0433 HUFFMAN, VA	WILLIS GAP, VA	138	138	1	14	0	1	1033KCM ACSR
123	0106 CLAYTOR, VA	GLEN LYN #1, VA	138	138	3	26	0	1	397KCM ACSR
124	0106 CLAYTOR, VA	GLEN LYN #2, VA	138	138	3	0	26	1	397KCM ACSR
125	0109 MORGANS CUT LOOP, VA		138	138	3	0	0	1	397KCM ACSR
126	0117 HANCOCK, VA	MATT FUNK, VA	138	138	3	11	0	1	556KCM ACSR
127	0118 CLOVERDALE, VA	MATT FUNK, VA	138	138	3	0	21	1	636KCM ACSR
128	0119 CLOVERDALE, VA	GLEN LYN, VA	138	138	3	20	39	1	556KCM ACSR
129	0119 CLOVERDALE, VA	GLEN LYN, VA	138	138	1	0	0	1	556KCM ACSR
130	0119 CLOVERDALE, VA	GLEN LYN, VA	138	138	3	0	0	2	795KCM ACSR
131	0374 PATRIOT CENTRE EXT		138	138	3	3	0	1	795KCM ACSR
132	0367 BURLINGTON HEIGHTS LOO		138	138	3	0	0	1	795KCM ACSR
133	0383 WEST SALEM LOOP, VA		138	138	3	0	0	1	795KCM ACSR
134	0116 CELANESE, VA	GLEN LYN, VA	138	138	3	4	0	1	556KCM ACSR
135	0116 CELANESE, VA	GLEN LYN, VA	0	0	1	4	0	0
136	0462 MATT FUNK EXT		138	138	3	5	0	0	1590 KCM ACSR
137	0115 CELANESE, VA	MATT FUNK, VA	138	138	3	34	0	1	556KCM ACSR
138	0115 CELANESE, VA	MATT FUNK, VA	138	138	1	2	0	1	556KCM ACSR
139	0115 CELANESE, VA	MATT FUNK, VA	138	138	3	0	0	2	1033KCM ACSR
140	0038 BRADLEY CIR-A, WV	GLEN LYN-HINTON, VA	138	138	3	0	4	1	556KCM ACSR
141	0224 BRADLEY CIR-B, WV	GLEN LYN-HINTON	138	138	3	4	0	1	556KCM ACSR
142	0145 ALTAVISTA, VA	REUSENS, VA	138	138	3	5	0	1	397KCM ACSR
143	0145 ALTAVISTA, VA	REUSENS, VA	138	138	2	20	0	1	397KCM ACSR
144	0311 OPOSSUM CREEK, VA	REUSENS, VA	138	138	3	9	5	1	397KCM ACSR
145	0311 OPOSSUM CREEK, VA	REUSENS, VA	138	138	1	0	0	2	1033KCM ACSR
146	0312 BRUSH TAVERN TAP, VA		138	138	1	3	0	1	556KCM ACSR
147	0145A BOONSBORO LOOP, VA		138	138	3	0	0	1	397KCM ACSR
148	0394 GRAVES MILLS LOOP, VA		138	138	3	0	0	1	795KCM ACSR
149	7119 HANCOCK, VA	ROANOKE, VA TOWER 198	138	138		0	0	0
150	0156A CLIFFORD, VA	REUSENS, VA	138	138	3	23	4	1	795KCM ACSR
151	0156 CLIFFORD, VA	SCOTTSVILLE, VA	138	138	3	29	0	1	397KCM ACSR
152	0156B BREMO, VA	SCOTTSVILLE, VA	138	138	3	7	0	1	397KCM ACSR
153	0170 OPOSSUM CREEK, VA	SMITH MOUNTAIN, VA	138	138	3	15	0	1	556KCM ACSR
154	0170 OPOSSUM CREEK, VA	SMITH MOUNTAIN, VA	0	0	1	19	0	0
155	0170 LEESVILLE, VA	SMITH MOUNTAIN, VA	138	138	3	0	8	1	556KCM ACSR
156	0173 ALTAVISTA, VA	LEESVILLE, VA	138	138	3	0	5	1	556KCM ACSR
157	0173 ALTAVISTA, VA	LEESVILLE, VA	0	0	1	3	0	0
158	0258 OPOSSUM CREEK, VA	PEAKSVIEW, VA	138	138	1	0	0	1	556KCM ACSR
159	0258 OPOSSUM CREEK, VA	PEAKSVIEW, VA	138	138	2	1	0	1	556KCM ACSR
160	0258 OPOSSUM CREEK, VA	PEAKSVIEW, VA	138	138	3	0	0	1	556KCM ACSR
161	0309 EAST LYNCHBURG, VA	OPOSSUM CREEK, VA	138	138	3	3	0	1	1590KCM ACSR
162	0322 JOSHUA FALLS, VA	REUSENS A&B, VA	138	138	3	7	0	2	556KCM ACSR
163	0322 JOSHUA FALLS, VA	REUSENS A&B, VA	138	138	3	0	0	2	1590KCM ACSR
164	0322 JOSHUA FALLS, VA	REUSENS A&B, VA	138	138	3	3	0	1	1590KCM ACSR
165	0322 JOSHUA FALLS, VA	REUSENS A&B, VA	138	138	1	0	0	1	1590KCM ACSR
166	0322 JOSHUA FALLS, VA	REUSENS A&B, VA	138	138	1	0	0	2	1590KCM ACSR
167	0321 JOSHUA FALLS, VA	OPOSSUM CREEK, VA	138	138	3	0	7	1	1590KCM ACSR
168	0320 EAST LYNCHBURG, VA	JOSHUA FALLS, VA	138	138	3	3	0	2	1590KCM ACSR
169	0320 EAST LYNCHBURG, VA	JOSHUA FALLS, VA	138	138	1	1	0	1	1590KCM ACSR
170	0366 RUSTBURG TAP, VA		138	138	1	4	0	1	795KCM ACSR
171	0395 MONEL LOOP, VA		138	138	3	0	0	1	1590KCM ACSR
172	0399 TANK HILL TAP, VA		138	138	1	1	0	1	795KCM ACSR
173	0161 CLOVERDALE, VA	ROANOKE, VA	138	138	3	16	0	1	556KCM ACSR
174	0161 CLOVERDALE, VA	ROANOKE, VA	0	0	3	1	0	0	795KCM ACSR
175	0160 CLOVERDALE, VA	REUSENS, VA	138	138	3	36	8	1	397KCM ACSR
176	0160 CLOVERDALE, VA	REUSENS, VA	138	138	1	1	0	0	636 KCM ACSR
177	MOSELEY, VA	REUSENS, VA	138	138	3	0	22	1	397KCM ACSR
178	0163 MOSELEY, VA	ROANOKE, VA	138	138	3	1	20	1	795KCM ACSR
179	0421 MOUNT UNION	CLOVERDALE	138	138	2	7	0	1	795KCM ACSR
180	0292 VINTON LOOP, VA		138	138	3	0	0	1	795KCM ACSR
181	0396 BONSACK LOOP, VA		138	138	3	0	0	1	795KCM ACSR
182	0168 EAST DANVILLE, VA	SMITH MOUNTAIN, VA	138	138	3	32	0	1	556KCM ACSR
183	0168A BEARSKIN TAP, VA		138	138	3	0	0	1	556KCM ACSR
184	0419 PENHOOK, VA	SMITH MOUNTAIN, VA	138	138	3	7	0	1	1033KCM ACSR
185	0371 PENHOOK, VA	WESTLAKE	138	138	1	15	0	1	1033KCM ACSR
186	0371 PENHOOK, VA	WESTLAKE	138	138	1	0	0	2	1033KCM ACSR
187	0369 BLAINE, VA	WESTLAKE	138	138	3	11	0	1	1033.5 KCM ACSR
188	0423 STONEWALL TAP		69	138	1	8	0	1
189	0423 STONEWALL TAP		0	0	3	1	0	0	795 KCM ACSR
190	0259 REGIS, VA	MONUMENT, VA	138	138	1	2	1	1	795KCM ACSR
191	0266 HANCOCK, VA	ROANOKE ELECTRIC STEEL, VA	138	138	3	1	0	1	795KCM ACSR
192	0266 HANCOCK, VA	ROANOKE ELECTRIC STEEL, VA	0	0	1	0	0	0
193	0042 SALTVILLE, VA	TAZEWELL, VA	138	138	3	21	0	1	1272KCM ACSR
194	0042 SALTVILLE, VA	TAZEWELL, VA	138	138	3	0	21	1	397KCM ACSR
195	0042 SALTVILLE, VA	TAZEWELL, VA	138	138	1	0	0	1	1033KCM ACSR
196	0270 BLUEFIELD, WV	TAZEWELL, VA	138	138	1	20	0	1	795KCM ACSR
197	0270 BLUEFIELD, WV	TAZEWELL, VA	138	138	2	0	0	1	1033KCM ACSR
198	BAILEYSVILLE, WV	TAZEWELL, VA	138	138	3	9	0	1	397KCM ACSR
199	BAILEYSVILLE, WV	TAZEWELL, VA	138	138	3	0	9	1	397KCM ACSR
200	0338 BLUEFIELD, VA	SOUTH PRINCETON, VA	138	138	1	6	0	1	556KCM ACSR
201	0414 RIVERVILLE TAP, VA		138	138	3	0	0	1	795KCM ACSR
202	0132 ROANOKE	CAROLINA	138	138	1	9	0	0
203	0132 ROANOKE	CAROLINA	138	138	3	44	57	1	795KCM ACSR
204	0385 CAPITALIZED SPARE PART	MAX MEADOW	138	138		0	0	1
205	1004 KEYWOOD TAP		138	138	1	0	0	0
206	0467 CLEARBROOK, VA	MATT FUNK, VA	138	138	1	0	0	1	1590KCM ACSR
207	0380 FALLING BRANCH	MERRIMAC	138	138	1	6	0	1	1033 KCM ACSR
208	0380 FALLING BRANCH	MERRIMAC	138	138	1	1	0	1	1033 KCM ACSR
209	0380 FALLING BRANCH	MERRIMAC	69	138	1	1	0	1	1033 KCM ACSR
210	0381 LAKE FOREST, VA		138	138	3	3	0	2	1590KCM ACSR
211	0464 HUNTINGTON COURT	ROANOKE	138	138	1	6	0	1	795 ACSR
212	0464 HUNTINGTON COURT	ROANOKE	138	138	1	0	0	1	1590KCM ACSR
213	0465 SUNSCAPE		138	138	1	1	0	2	1590KCM ACSR
214	0470 LOCKHART, VA		138	138	3	0	0	1	795KCM ACSR
215	0435 DUTY, VA	138KV EXTENSION	138	138		0	0	1
216	0388 TECH DRIVE	138KV EXTENSION	138	138	3	0	0	1	1590 KCM ACSR
217	0484 HORSEPEN	138KV EXTENSION	138	138		0	0	0
218	0485 JACKSONS FERRY	WYTHE	138	138	2	5	0	1	1590KCM ACSR/MA2
219	0485 JACKSONS FERRY	WYTHE	138	138	3	13	0	2	1590KCM ACSR/MA2
220	0502 PROGRESS PARK TAP		138	138	2	1	0	1	1590KCM ACSR/MA2
221	0502 PROGRESS PARK TAP		138	138	1	0	0	1	1590KCM ACSR/MA2
222	0512 CLOVERDALE 765	CLOVERDALE 138	345	345	3	0	0	1	1590KCM ACSS
223	0508 CLOVERDALE EAST	CLOVERDALE TIE LINE NO 2	345	345	1	0	0	1	2-1926.9KCM ACSR/
224	0509 CLOVERDALE 765	CLOVERDALE EAST	500	500	2	0	0	1	4-954KCM ACSR
225	0516 RICHLANDS	WHITEWOOD	138	138	2	8	0	1	1033.5KCM ACSR
226	0513 WHITEWOOD EXT		138	138	1	1	0	2	1033.5KCM ACSR
227	0513 WHITEWOOD EXT		138	138	3	0	0	2	1033.5KCM ACSR
228	0519 OWENS DRIVE EXT		69	138	1	2	0	1	795KCM ACSR
229	0459 GEORGE STREET	LYNBROOK	138	138	1	1	0	1	1233.6KCM ACSR/TW
230	0459 GEORGE STREET	LYNBROOK	138	138	2	2	0	1	1233.6KCM ACSR/TW
231	0110A FALLING BRANCH	LOOP	138	138	2	1	0	1	556.5 KCM 26/7 AC
232	0460 BRUSH TAVERN	LYNBROOK	138	138	1	4	0	1	1233.6KCM ACSR/TW
233	0501 JACKSONS FERRY	BUS TIE #3	138	138	1	0	0	1	1590 KCM ACSR
234	0461 George Street	South Lynchburg	138	138	1	3	0	1	1233.6KCM ACSR/TW
235	0461 George Street	South Lynchburg	138	138	2	0	0	1	1233.6KCM ACSR/TW
236	0507 Cloverdale East	Cloverdale Tie Line No. 1	345	345	1	0	0	1	2 - 1926.9 KCM AC
237	0517 Town Creek	Progress Park	138	138	1	3	0	1	1033.5KCM ACSR
238	0517 Town Creek	Progress Park	138	138	2	7	0	1	1033.5KCM ACSR
239	0517 Town Creek	Progress Park	138	138	3	3	0	1	1033.5KCM ACSR
240	0518 TOWN CREEK	SOUTH BLUEFIELD	138	138	1	1	0	1	1033.5KCM ACSR
241	0518 TOWN CREEK	SOUTH BLUEFIELD	138	138	2	1	0	1	1033.5KCM ACSR
242	0518 TOWN CREEK	SOUTH BLUEFIELD	138	138	3	10	0	1	1033.5KCM ACSR
243	0514 BEARWALLOW	FARADAY	138	138	2	2	0	1	1033.5KCM ACSR
244	0515 FARADAY	TAZEWELL	138	138	2	7	0	1	1033.5KCM ACSR
245	0545 Tazewell Bus Tie No 1		138	138	1	0	0	1	1033.5KCM ACSR
246	0569 HINTON	WEST VACO (VA)	138	138	3	0	0	1	336KCM ACSR
247	0522 SOUTH ABINGDON EXT		138	138	1	4	0	2	1033.5KCM ACSR
248	0524 Joshua Falls 765/138kV Bus Tie No. 1		138	138	1	0	0	1	1590KCM ACSR
249	0541 IRONTO EXTENSION		138	138	1	0	0	2	1033.5KCM ACSR
250	0537 WOLF GLADE EXTENSION		138	138	1	2	0	2	795KCM ACSR
251	0567 Glenmary Extension		138	138	3	0	0	2	795KCM ACSR
252	0581 Museville Extension		138	138	1	0	0	2	1272 ACSS
253	0538 Elk Garden Tap		138	138	1	0	0	1	1590KCM ACSR
254	0538 Elk Garden Tap		138	138	2	0	0	1	336KCM ACSR
255	0571 Garden Creek	Baileysville (VA)	138	138	2	13	0	1	636KCM ACSR
256	0578 Redeye Extension		138	138	1	0	0	2	795KCM ACSR
257	STATE OF WEST VIRGINIA	STATE OF WEST VIRGINIA				0	0
258	0276 AMOS, WV	HANGING ROCK, H	765	765	3	25	0	1	954KCM ACSR
259	0297 GAVIN, OH	MOUNTAINEER, WV	765	765	3	8	0	1	1351KCM ACSR
260	0296 KAMMER, WV	MOUNTAINEER, WV	765	765	3	19	0	1	1351KCM ACSR
261	0296 KAMMER, WV	MOUNTAINEER, WV	0	0	3	95	0	0
262	0183 AMOS, WV	CULLODEN, WV	765	765	3	15	0	1	954KCM ACSR
263	0183A BAKER, KY	CULLODEN, WV	765	765	3	34	0	1	954KCM ACSR
264	0324 CULLODEN, WV	WYOMING, WV	765	765	3	58	0	1	1351KCM ACSR
265	0344 CULLODEN, WV	GAVIN, OH	765	765	3	42	0	1	1351KCM ACSR
266	0405 JACKSONS FERRY	WYOMING	765	765	3	32	0	1	795KCM ACSR
267	0295 AMOS, WV	MOUNTAINEER, WV	765	765	3	47	0	1	1351KCM ACSR
268	0185 BAKER, KY	BROADFORD, VA	765	765	3	4	0	1	954KCM ACSR
269	0263 AMOS, WV	GAVIN	765	765		0	0	1
270	0012 BAKER, KY	TRI STATE, WV	345	345	3	6	0	1	954KCM ACSR
271	0003 KYGER CREEK, OH	SPORN, WV	345	345	3	12	0	1	1414KCM ACSR
272	0003 KYGER CREEK, OH	SPORN, WV	345	345	1	0	0	1	1272 ACSS
273	0004 MUSKINGUM, WV	SPORN, WV	345	345	3	0	2	1	1275KCM ACSR
274	0004 MUSKINGUM, WV	SPORN, WV	345	345	1	2	0	2	959.6 KCM ACSS
275	0005 KANAWHA, WV	MATT FUNK, VA	345	345	3	1	0	1	2156KCM ACSR
276	0005 KANAWHA, WV	MATT FUNK, VA	345	345	3	64	0	1	2-954KCM ACSR
277	0218 AMOS, WV	SPORN, WV	345	345	3	46	0	1	1563KCM ACSR
278	0006 KANAWHA, WV	SPORN, WV	345	345	3	0	62	1	1414KCM ACSR
279	0006A AMOS, WV	KANAWHA, WV	345	345	3	28	12	1	1563KCM ACSR
280	0011 KYGER CREEK, WV	TRI-STATE, WV	345	345	3	63	0	0	2303KCM ACSR
281	0011 KYGER CREEK, WV	TRI-STATE, WV	345	345	2	0	0	0	2303KCM ACSR
282	0228A BETH TAP WV		138	138	1	1	0	1	336KCM ACSR
283	0053 BAILEYSVILLE, WV	HALES BRANCH, VA	138	138	3	0	0	2	636KCM ACSR
284	0308 PAD FORK LOOP, WV		138	138	1	0	0	1	397KCM ACSR
285	0330 JIM BRANCH, WV	WYOMING, WV	138	138	3	7	0	1	1590KCM ACSR
286	0330 JIM BRANCH, WV	WYOMING, WV	0	0	1	16	0	0
287	0210 BAILYESVILLE, WV	WYOMING, WV	138	138	3	0	5	1	1590KCM ACSR
288	0332 WELCH TAP, WV		138	138	1	0	0	1	795KCM ACSR
289	0053 BAILEYSVILLE, WV	HALES BRANCH, VA	138	138	1	21	0	1	636KCM ACSR
290	0035 STOTESBURY TAP, WV		138	138	1	0	0	1	795KCM ACSR
291	0035 STOTESBURY TAP, WV		138	138	2	6	0	1	795KCM ACSR
292	0211 MULLENSVILLE LOOP, WV		138	138	3	1	1	1	556KCM ACSR
293	0212 PINNACLE CREEK LOOP, W		138	138	3	3	3	1	556KCM ACSR
294	0294 NORTH BECKLEY LOOP, WV		138	138	3	1	1	1	556KCM ACSR
295	0210 BAILEYSVILLE, WV	WYOMING, WV	138	138	3	0	6	1	1590KCM ACSR
296	MULLENS, WV	WYOMING, WV	138	138	3	6	0	1	556KCM ACSR
297	MULLENS, WV	WYOMING, WV	0	0	1	17	0	0
298	0356 PEMBERTON TAP, WV		138	138	1	0	0	1	336KCM ACSR
299	0356 PEMBERTON TAP, WV		138	138	2	1	0	1	336KCM ACSR
300	0356 PEMBERTON TAP, WV		138	138	3	1	0	1	336KCM ACSR
301	0216B BRADLEY, WV	TAMS MOUNTAIN, WV	138	138	1	1	0	1	556KCM ACSR
302	0216B BRADLEY, WV	TAMS MOUNTAIN, WV	138	138	2	14	0	1	556KCM ACSR
303	0216B BRADLEY, WV	TAMS MOUNTAIN, WV	138	138	3	1	0	1	556KCM ACSR
304	0216 MULLENS, WV	TAMS MOUNTAIN, WV	138	138	2	9	0	1	556KCM ACSR
305	0216 MULLENS, WV	TAMS MOUNTAIN, WV	138	138	1	0	0	0	556KCM ACSR
306	0094 BIG SANDY, KY	DEWEY, KY	138	138	3	0	0	1	636KCM ACSR
307	0426 BIG SANDY, KY	INEZ A&B, KY	138	138	3	8	0	1	795KCM ACSR
308	0092 BELLEFONTE, KY	TRI STATE, WV	138	138	3	4	0	1	795KCM ACSR
309	0429 MIDKIFF, WV	TRI STATE, WV	138	138	1	26	0	1	795KCM ACSR
310	0028 CABIN CREEK, WV	KANAWHA #1, WV	138	138	3	0	3	1	556KICM ACSR
311	0029 CABIN CREEK, WV	KANAWHA #2, WV	138	138	3	3	0	1	556KCM ACSR
312	0098 CAPITOL HILL, WV	KANAWHA, WV	138	138	3	18	0	1	556KCM ACSR
313	0098 CAPITOL HILL, WV	KANAWHA, WV	138	138	3	3	0	1	556KCM ACSS
314	0326 RENSFORD LOOP, WV	KANAWHA, WV	138	138	3	1	0	1	556KCM ACSR
315	0098A FLATWOOD TAP, WV		138	138	3	5	0	1	795KCM ACSR
316	0245 GILBOA, WV	KANAWHA, WV	138	138	3	0	0	1	795KCM ACSR
317	0245 GILBOA, WV	KANAWHA, WV	0	0	1	15	0	0
318	0390 BELVA TAP, WV		138	138	3	1	1	1	954KCM ACSR
319	0372 JEHU EXT WV		138	138	3	1	0	1	556KCM ACSR
320	0097 CAPITOL HILL, WV	CHEMICAL, WV	138	138	3	6	0	2	556KCM ACSR
321	0097 CAPITOL HILL, WV	CHEMICAL, WV	138	138	3	0	0	1	1272KCM ACSS
322	0101 DEXTER, WV	SPORN CIR B, OH	138	138	3	9	0	1	397KCM ACSR
323	0101 DEXTER, WV	SPORN CIR B, OH	138	138	1	0	0	1	397KCM ACSR
324	0104 BANCROFT TAP, WV		138	138	3	1	0	1	556KCM ACSR
325	0101 DEXTER, OH	SPORN CIR A, WV	138	138	3	0	9	1	397KCM ACSR
326	0225A LEON LOOP, WV		138	138	3	0	0	1	1033KCM ACSR
327	AMERICAN ALLOYS, WV	SPORN, WV	138	138	3	0	0	1	556KCM ACSR
328	0402 SISSON TAP, WV		138	138	3	10	1	1	795KCM ACSR
329	0402 SISSON TAP, WV		0	0	1	0	0	0
330	0225 AMOS, WV	SOUTH BUFFALO CIR B, WV	138	138	3	12	6	1	397KCM ACSR
331	0225 SOUTH BUFFALO, WV	SPORN CIR A, WV	138	138	3	0	31	1	397KCM ACSR
332	0225 SOUTH BUFFALO, WV	SPORN CIR B WV	138	138	3	36	0	1	1351KCM ACSR
333	0023 MINNIX MOUNTAIN LOOP		138	138	3	0	0	1	1033KCM ACSR
334	0024 SPEEDWAY TAP, WV		138	138	3	0	0	1	556KCM ACSR
335	0024 SPEEDWAY TAP, WV		0	0	1	7	0	0
336	0020 GLEN LYN, VA	SOUTH PRINCETON, WV	138	138	3	13	0	1	397KCM ACSR
337	0424 GLEN LYN, VA	SOUTH PRINCETON, WV	138	138	3	0	13	1	1351KCM ACSR
338	0020A SOUTH PRINCETON, WV	SWITCHBACK A, WV	138	138	3	15	0	1	397KCM ACSR
339	0020B SOUTH PRINCETON, WV	SWITCHBACK B, WV	138	138	3	0	15	1	397KCM ACSR
340	0055 GLEN LYN, VA	WYTHE, VA	138	138	3	1	0	1	556KCM ACSR
341	0055 GLEN LYN, VA	WYTHE, VA	138	138	3	0	1	1	556KCM ACSR
342	0093 BIG SANDY	WEST HUNTINGTON, WV	138	138	2	0	0	2	1780KCM ACSR
343	0093 BIG SANDY	WEST HUNTINGTON, WV	138	138	3	3	0	1	1351KCM ACSR
344	0093 BIG SANDY	WEST HUNGINGTON, WV	0	0	3	16	0	0
345	0031 BRADLEY, WV	KANAWHA #1, WV	138	138	3	0	27	1	556KCM ACSR
346	0222 BRADLEY, WV	KANAWHA #2, WV	138	138	3	27	0	1	556KCM ACSR
347	0032 BRADLEY CIR A, WV	GLEN LYN-HINTON, VA	138	138	3	0	41	1	556KCM ACSR
348	0223 BRADLEY CIR B, WV	GLEN LYN-HINTON, VA	138	138	3	43	2	1	1590KCM ACSR
349	0219 KINCAID LOOP, WV		138	138	3	0	0	1	556KCM ACSR
350	0246 BRADLEY, WV	DAMERON, WV	138	138	1	10	0	1	795KCM ACSR
351	0415 CLIFFTOP TAP, WV		138	138	3	3	0	1	795KCM ACSR
352	0049 BAILEYSVILLE, WV	KANAWHA #1, WV	138	138	3	46	0	1	636KCM ACSR
353	0049 BAILEYSVILLE, WV	KANAWHA #2, WV	138	138	3	0	46	1	636KCM ACSR
354	0049 BAILEYSVILLE, WV	KANAWHA #2, WV	0	0	1	0	0	0
355	0052 BIM TAP, WV		138	138	1,3	12	0	1	556KCM ACSR
356	3827 BRADLEY	LAYLAND	69	138	1	12	0	1
357	3484 COBB TAP		46	138	1	0	0	1
358	0420 FRANKS BRANCH		46	138	1	5	0	1
359	2123 SOUTH NEAL	WEST HUNTINGTON	69	138	3	2	0	1
360	0220 KOPPERSTON LOOP, WV		138	138	3	0	0	1	1033KCM ACSR
361	0243 BOLT TAP, WV		138	138	1	6	0	1	795KCM ACSR
362	0301 WHARTON TAP, WV		138	138	1	0	0	1	556KCM ACSR
363	0384 HINTON	WESTVACO, WV	138	138	3	13	0	1	556KCM ACSR
364	0384 HINTON	WESTVACO, WV	138	138	3	23	0	1	336KCM ACSR
365	0389 GREENBRIER LOOP, WV		138	138	3	0	0	1	246KCM ACAR
366	0393 RONCEVERTE LOOP, WV		138	138	3	0	0	1	4/0 ACSR
367	0357 GRASSY FALLS, WV	MCCLUNG, WV	138	138	1	0	0	1	954KCM ACSR
368	0304 RUM CREEK TAP, WV		138	138	1	2	0	1	556KCM ACSR
369	0318 M&B TAP, WV		138	138	1	0	0	1	556KCM ACSR
370	0013 LOGAN, WV	WYOMING #1-A, WV	138	138	3	12	14	1	1590KCM ACSR
371	0013 LOGAN, WV	WYOMING #1-B, WV	138	138	3	22	0	1	1590KCM ACSR
372	0387 LOGAN, WV	WYOMING #2, WV	138	138	3	23	0	1	1033KCM ACSR
373	0387 LOGAN, WV	WYOMING #2, WV	138	138	2	0	0	1	1033KCM ACSR
374	0045 LOGAN, WV	SPRIGG #1 & #2, WV	138	138	3	18	0	2	397KCM ACSR
375	3791 BOLT, WV	TRAP HILL, WV	46	138	1	6	0	1
376	0048 CHAUNCEY TAP, WV		138	138	3	4	0	1	397KCM ACSR
377	0328 RAGLAND LOOP, WV		138	138	1	1	0	1	556KCM ACSR
378	0317 GRANT BRANCH TAP, WV		138	138	1	7	0	1	556KCM ACSR
379	0346 PINE CREEK TAP, WV		138	138	1	2	0	1	556KCM ACSR
380	0401 HATFIELD, WV	SPRIGG, WV	138	138	1	11	0	1	1033KCM ACSR
381	0401A CINDERELLA LOOP, WV		138	138	3	0	0	1	1035KCM ACSR
382	0325 JIM BRANCH, WV	SWITCHBACK, WV	138	138	2	18	1	1	1033KCM ACSR
383	0077 MILLBROOK, OH	SPORN, WV	138	138	3	9	0	1	477KCM ACSR
384	0077A ADDISON LICK, WV	SPORN, WV	138	138	3	0	9	1	477KCM ACSR
385	0075 SOUTH POINT, OH	SPORN, WV	138	138	3	10	0	1	397KCM ACSR
386	0075 SOUTH POINT, OH	SPORN, WV	138	138	1	1	0	1	397KCM ACSR
387	NORTH PROCTORVILLE, OH	SPORN, WV	138	138	3	0	10	1	397KCM ACSR
388	0076 DARRAH, WV	NORTH PROCTORVILLE, OH	138	138	3	2	0	1	795KCM ACSR
389	0076 DARRAH, WV	NORTH PROCTORVILLE, OH	138	138	3	0	2	1	556KCM ACSR
390	0081 RAVENSWOOD, WV	SPORN #1, WV	138	138	3	1	0	1	795KCM ACSR
391	0081 RAVENSWOOD, WV	SPORN #2, WV	138	138	3	0	1	1	795KCM ACSR
392	0083 RAVENSWOOD, WV	SPORN #3, WV	138	138	3	1	0	1	795KCM ACSR
393	0083 RAVENSWOOD, WV	SPORN #4, WV	138	138	3	0	1	1	795KCM ACSR
394	0247 EAST HUNTINGTON, WV	NORTH PROCTORVILLE, OH	138	138	3	1	0	1	795KCMACSR
395	0067 JOHNS CREEK, KY	SPRIGG, WV	138	138	1	1	0	1	397KCM ACSR
396	0271 BLUEFIELD, WV	TAZEWELL, VA	138	138	1	1	0	1	795KCM ACSR
397	0017 BAILEYSVILLE, WV	TAZEWELL, VA	138	138	3	31	0	1	1590KCM ACSR
398	0016 BAILEYSVILLE, WV	TAZEWELL, VA	138	138	3	3	28	1	397KCM ACSR
399	0016A CARSWELL TAP, WV		138	138	3	1	1	1	397KCM ACSR
400	0069 CABIN CREEK, WV	TURNER #1 CIR A, WV	138	138	3	23	0	1	336KCM ACSR
401	0070 CABIN CREEK, WV	TURNER #1 CIR B. WV	138	138	3	5	19	1	1590KCM ACSR/MA
402	0194 CHESTERFIELD TAP, WV		138	138		0	0	0
403	0071 CABIN CREEK, WV	TURNER #2, WV	138	138	3	0	1	1	250KCM ACSR
404	0071 CABIN CREEK, WV	TURNER #2, WV	0	0	1	22	0	0
405	0268 ST ALBANS LOOP, WV		138	138	3	0	0	1	1033KCM ACSR
406	0230 AMOS, WV	TURNER #1, WV	138	138	3	12	0	1	1033KCM ACSR
407	0230 AMOS, WV	TURNER #2, WV	138	138	3	0	12	1	1033KCM ACSR
408	0226 AMOS, WV	CHEMICAL #1 A, WV	138	138	3	1	8	1	397KCM ACSR
409	0226 AMOS, WV	CHEMICAL #1 B, WV	138	138	3	6	0	1	1033KCM ACSR
410	0226 AMOS, WV	CHEMICAL #2 A, WV	138	138	3	8	9	1	1033KCM ACSR
411	0226 AMOS, WV	CHEMICAL #2 B, WV	138	138	3	0	4	1	397KCM ACSR
412	0226 AMOS, WV	CHEMICAL 1A-2A AND 1B-2B	138	138	3	1	0	2	1033 KCM ACSR
413	0343 STONE BRANCH TAP, WV		138	138	1	6	0	1	795KCM ACSR
414	HOPKINS, WV	LOGAN, WV	138	138	3	8	11	1	336KCM ACSR
415	HOPKINS, WV	LOGAN, WV	138	138	3	19	0	1	336KCM ACSR
416	0228 AMOS, WV	HOPKINS, WV	138	138	3	2	17	1	336KCM ACSR
417	0228 AMOS, WV	HOPKINS, WV	138	138	3	28	0	1	795KCM ACSR
418	0228 AMOS, WV	HOPKINS, WV	138	138	3	2	0	1	1590KCM ACSR/MA
419	0364 GRASSY FORK TAP, WV		138	138	1	2	0	1	795KCM ACSR
420	0376 DINGESS LOOP, WV		138	138	3	0	0	1	1033KCM ACSR
421	0376 DINGESS LOOP, WV		0	0	1	0	0	0
422	0306 INEZ, KY	LOGAN, WV	138	138	3	0	1	1	795KCM ACSR
423	0306 INEZ, KY	LOGAN, WV	0	0	1	23	0	0
424	0428 SHARPLES TAP 138KV		138	138	1	7	0	1	795KCM ACSR
425	0432 MUD FORK LOOP, WV		138	138	3	1	1	1	795KCM ACSR
426	0087 DARRAH, WV	TRI STATE, WV	138	138	3	10	4	1	397KCM
427	0436 DAWES LOOP, 138KV, WV		138	138		0	0	0
428	0088 TRI-STATE, WV	WEST HUNTINGTON, WV	138	138	3	0	6	1	397KCM ACSR
429	0090 SOUTH POINT, OH	TRI-STATE CIR A, WV	138	138	3	8	0	1	397KCM ACSR
430	0090 SOUTH POINT, OH	TRI-STATE CIR B, WV	138	138	3	0	7	1	1351KCM ACSR
431	0225 AMOS	SPORN	138	138	3	0	11	0	397KCM ACSR
432	0237 AMOS, WV	DARRAH, WV	138	138	3	35	0	1	397KCM ACSR
433	0238 AMOS, WV	WEST HUNTINGTON, WV	138	138	3	5	41	1	1033KCM ACSR
434	0238 AMOS, WV	WEST HUNTINGTON, WV	0	0	1	0	0	0
435	0238 PARK HILL TAP, WV		138	138	3	0	0	1	397KCM ACSR
436	0277 CABELL LOOP, WV		138	138	3	1	1	1	954KCM ACSR
437	0302 MILTON LOOP, WV		138	138	3	2	2	1	795KCM ACSR
438	0378 CURRY LOOP, WV		138	138	3	2	2	1	1033KCM ACSR
439	0095 CARBIDE MAIN, WV	TURNER, WV	138	138	3	0	0	1	1590 KCM ACSR
440	0096 CARBIDE #8, WV	CHEMICAL-TURNER A, WV	138	138	3	0	1	1	397KCM ACSR
441	0096 CARBIDE #8, WV	CHEMICAL-TURNER B, WV	138	138	3	7	0	1	1033KCM ACSR
442	0096 CARBIDE #8, WV	CHEMICAL-TURNER B, WV	138	138	3	1	0	2	1033KCM ACSR
443	0337 BLUEFIELD, WV	SOUTH PRINCETON, WV	138	138	2	8	0	1	556KCM ACSR
444	0337 BLUEFIELD, WV	SOUTH PRINCETON, WV	138	138	1	0	0	2	556KCM ACSR
445	0336 CLENDENIN TAP		138	138	1	8	0	0
446	CAPITALIZED SPARE PARTS	0373,0379	138	138		0	0	1
447	1005 CHERRY CREEK	CLIFFTOP	138	138	1	7	0	1	795 ACSR
448	0377 SPORN	CLINE ENERGY EXTENSION	138	138	1	0	0	1	397KCM ACSR
449	0370 SOUTHRIDGE EXTENSION		138	138	1	2	0	2	1590KCM ACSR/MA
450	0098A FLATWOOD TAP 138KV		0	0		0	0	0
451	0386 GARRISON WV		138	138	1	0	0	2	795 KCM ACSR
452	0382 LANHAM, WV		138	138	1	1	0	2	795 KCM ACSR
453	0473 CARETTA	JIM BRANCH	138	138		0	0	0
454	0471 HALLS RIDGE	SOUTH PRINCETON, WV	138	138	3	0	0	1	1590KCM ACSR
455	0466 IAEGER	WHARNCLIFFE, WV	46	138	3	6	0	1	556.5KCM26/7 AC
456	1050 ROCKHOUSE		138	138		0	0	0
457	1072 CLENDENIN, WV	MORRIS BRANCH	138	138	3	2	0	1	795 KCM ACSR
458	0474 COBB, WV	THOROFARE CREEK	138	138	3	0	0	1	795 KCM ACSR
459	0463 CROOKED CREEK, WV		138	138	3	1	0	1	1033KCM ACSR
460	0472 MERRITS CREEK, WV		138	138	3	4	0	1	1033KCM ACSR
461	3843 BIM, WV		47	138	3	0	0	1
462	3843 BIM, WV		0	0	1	11	0	0
463	0478 POLYMER LOOP, WV		138	138	3	3	0	1	795 KCM ACSR
464	0478 POLYMER LOOP, WV		138	138	1	0	0	1	795KCM ACSR
465	0477 BROAD RUN, WV	THOROFARE CREEK	138	138		1	0	1
466	0475 PATRIOT COAL, WV	POINT LICK	138	138	3	0	0	1	556.5 KCM 26/7 AC
467	0482 CLARK BRANCH, WV	138KV EXTENSION	138	138		0	0	1
468	0481 LAKEVIEW	138KV EXTENSION	138	138		0	0	0
469	0483 HERNSHAW	138KV EXTENSION	138	138	3	2	0	2	1590 KCM ACSR
470	0486 PAX BRANCH	138KV EXTENSION	138	138	3	1	0	2	1033.5 KCM ACSR
471	0487 PIERPONT	138KV EXTENSION	138	138	3	1	0	1	1033.5 KCM
472	0479 HARMON BRANCH	138KV EXTENSION	138	138	3	1	0	2	1033.5 KCM ACSR
473	0492 TRI-STATE	TWELVEPOLE CREEK	138	138	3	1	0	2	795 KCM ACSR
474	0503 CLINTWOOD EXTENSION		69	138	1	0	0	2	1033.5 KCM ACSR
475	3827 BRADLEY	LAYLAND NO.2B	69	138	1	1	0	1	1158.4KCM ACSR/TW
476	0015 BERWIND	FARADAY	138	138		0	0	0
477	0018 BERWIND	YUKON	138	138		0	0	0
478	0016 JIM BRANCH	YUKON	138	138		0	0	0
479	0568 GRANGSTON LOOP		138	138	3	0	0	2	556.5KCM ACSR
480	0526 COMMONWEALTH CROSSING	138KV EXTENSION	138	138	1	6	0	2	1033 KCM ACSR
481	0527 COCO Extension		138	138	1	0	0	2	1033.5 KCM ACSR
482	0528 CAPITOL HILL	CHESTERFIELD AVE	69	138	1	0	0	1	1033.5 KCM ACSR
483	0539 TRI-STATE 345KV - 138KV BUS TIE NO. 1		138	138	3	0	0	1	2-1590KCM ACSR
484						0	0
485	Lines Under 138KV					1,568	181
486	Line cost and expense are	not available by individual								207,737,217	1,823,460,928	2,031,198,146	216,817	23,654,649		23,871,466
487	transmission line	Total shown in Column j - p
36	TOTAL					5,098	1,330	462		207,737,217	1,823,460,928	2,031,198,146	216,817	23,654,649	0	23,871,466

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

TRANSMISSION LINES ADDED DURING YEAR
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. 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 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). 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.
	LINE DESIGNATION			SUPPORTING STRUCTURE		CIRCUITS PER STRUCTURE		CONDUCTORS				LINE COST
Line No.	TransmissionLineStartPoint From	TransmissionLineEndPoint To	LengthOfTransmissionLineAdded Line Length in Miles	SupportingStructureOfTransmissionLineType Type	AverageNumberOfSupportingStructuresOfTransmissionLinePerMiles Average Number per Miles	NumberOfTransmissionCircuitsPerStructurePresent Present	NumberOfTransmissionCircuitsPerStructureUltimate Ultimate	ConductorSize Size	ConductorSpecification Specification	ConductorConfigurationAndSpacing Configuration and Spacing	OperatingVoltageOfTransmissionLine Voltage KV (Operating)	CostOfLandAndLandRightsTransmissionLinesAdded Land and Land Rights	CostOfPolesTowersAndFixturesTransmissionLinesAdded Poles, Towers and Fixtures	CostOfConductorsAndDevicesTransmissionLinesAdded Conductors and Devices	Asset Retire. Costs	CostOfTransmissionLinesAdded Total	SupportingStructureConstructionType Construction
	(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)	(k)	(l)	(m)	(n)	(o)	(p)	(q)
1	0567 Glenmary Extension		0	3	3	2	2	795	ACSR		138		1,705,103	190,164		1,895,267
2	0524 Joshua Falls 765/138kV Bus Tie No. 1		0	1	1	1	1	1,590	ACSR		138		687,396	85,307		772,703
3	0581 Museville Extension		0	1	1	2	2	1272	ACSS		138	4,125	97,775	14,020		115,920
4	0578 Redeye Extension		0	1	1	2	2	795	ACSR		138		77,341			77,341
5	0539 Tri State 345kV	138kV Bus Tie No. 1	0	3	3	1	1	2 - 1590	ACSR		138		34,203	22,802		57,005
6	0538 Elk Garden Tap		0	1	1	1	1	1590	ACSR		138
7	0538 Elk Garden Tap		0	2	2	1	1	336	ACSR		138		371,735	116,070		487,805
44	TOTAL		1		12	10	10					4,125	2,973,554	428,363		3,406,041

Name of Respondent:

Appalachian Power Company

This report is:

(1)

☐ An Original

(2)

☑ A Resubmission

Date of Report:

05/19/2022

Year/Period of Report

End of:

2021

SUBSTATIONS
Report below the information called for concerning substations of the respondent as of the end of the year. Substations which serve only one industrial or street railway customer should not be listed below. 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. 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). Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. 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.
		Character of Substation		VOLTAGE (In MVa)						Conversion Apparatus and Special Equipment
Line No.	SubstationNameAndLocation Name and Location of Substation (a)	SubstationCharacterDescription Transmission or Distribution (b)	SubstationCharacterAttendedOrUnattended Attended or Unattended (b-1)	PrimaryVoltageLevel Primary Voltage (In MVa) (c)	SecondaryVoltageLevel Secondary Voltage (In MVa) (d)	TertiaryVoltageLevel Tertiary Voltage (In MVa) (e)	SubstationInServiceCapacity Capacity of Substation (In Service) (In MVa) (f)	NumberOfTransformersInService Number of Transformers In Service (g)	Number of Spare Transformers (h)	ConversionApparatusAndSpecialEquipmentType Type of Equipment (i)	NumberOfConversionApparatusAndSpecialEquipmentUnits Number of Units (j)	CapacityOfConversionApparatusAndSpecialEquipment Total Capacity (In MVa) (k)
1	ABERT - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	9.60
2	ABERT - VA	Distribution		69.00	12.00		22.40	1			0	0.00
3	ABINGDON - VA	Transmission		138.00	13.09		22.40	1			0	0.00
4	ABINGDON - VA	Transmission		138.00	70.50	13.09	90.00	1			0	0.00
5	ABINGDON - VA	Transmission		138.00	34.50		50.00	2			0	0.00
6	ACCOVILLE - WV	Distribution		69.00	46.00	1.60	7.50	1			0	0.00
7	ALLOY - WV	Distribution		46.00	13.09		9.38	1			0	0.00
8	ALUM CREEK - WV	Distribution		46.00	13.09		9.38	1			0	0.00
9	ALUM RIDGE - VA	Distribution		138.00	33.00	12.00	9.38	1			0	0.00
10	AMBLER RIDGE - WV	Distribution		138.00	138.00	34.50	36.00	3			0	0.00
11	AMBLER RIDGE - WV	Distribution		138.00	36.20	34.50	72.00	6			0	0.00
12	AMEAGLE - WV	Distribution		46.00	7.20		2.49	3			0	0.00
13	AMHERST - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	9.60
14	AMHERST - VA	Distribution		69.00	13.09		25.00	1			0	0.00
15	AMONATE LIGHTS - WV	Distribution		34.50	7.20		0.75	3			0	0.00
16	AMOS 345KV - WV	Transmission		345.00	138.00	34.50	1350.00	2			0	0.00
17	AMOS 765KV - WV	Transmission		765.00	138.00	13.80	750.00	3			0	0.00
18	AMOS 765KV - WV	Transmission		138.00	69.00	46.00	130.00	0	1		0	0.00
19	AMOS 765KV - WV	Transmission		765.00	345.00	34.50		0	1		0	0.00
20	AMOS 765KV - WV	Transmission		765.00	345.00	34.50	1500.00	3			0	0.00
21	APPLE GROVE - WV	Transmission		69.00	12.00		10.50	1			0	0.00
22	APPLE GROVE - WV	Transmission		138.00	69.00	12.00	56.00	1			0	0.00
23	ARCHER CREEK - VA	Distribution		69.00	12.00		10.50	1			0	0.00
24	ARROWHEAD - VA	Distribution		69.00	13.09		12.00	1			0	0.00
25	ATKINS - VA	Distribution		138.00	34.50	12.00	9.38	0	1		0	0.00
26	ATKINS - VA	Distribution		69.00	12.00		10.50	0	1		0	0.00
27	ATKINS - VA	Distribution		138.00	34.50		30.00	1			0	0.00
28	AUSTINVILLE - VA	Distribution		138.00	34.50			1			0	0.00
29	AXTON - VA	Transmission		765.00	138.00	13.80	750.00	3			0	0.00
30	AXTON - VA	Transmission		765.00						REACTOR	4	400.00
31	AXTON - VA	Transmission		138.00	0.00	0.00	0.00			AIR CORE REACTOR	3
32	BAILEYSVILLE - WV	Transmission		46.00	0.00	0.00	0.00			STATCAP	1	9.60
33	BAILEYSVILLE - WV	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	126.00
34	BAILEYSVILLE - WV	Transmission		138.00	46.00		90.00	1			0	0.00
35	BAILEYSVILLE - WV	Transmission		46.00	12.00		6.25	1			0	0.00
36	BALD KNOB - WV	Distribution		46.00	12.00		2.50	1			0	0.00
37	BALLOU - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	2	32.40
38	BANCROFT - WV	Transmission		138.00	13.09		25.00	1			0	0.00
39	BANCROFT - WV	Transmission			0.00	0.00	0.00			STATCAP	1
40	BANCROFT - WV	Transmission		138.00	69.00	12.00	67.20	1			0	0.00
41	BANCROFT - WV	Transmission		138.00	34.50		20.00	1			0	0.00
42	BARNETT - WV	Distribution		69.00	13.09		20.00	1			0	0.00
43	BARNETT - WV	Distribution		69.00	12.00		20.00	1			0	0.00
44	BASSETT - VA	Distribution		69.00	12.00		25.00	1			0	0.00
45	BASSETT WALKER - VA	Distribution		34.50	7.20		5.64	3			0	0.00
46	BASSETT WALKER - VA	Distribution		34.50	7.50		3.75	3			0	0.00
47	BEALE - WV	Distribution		69.00	13.09		7.50	1			0	0.00
48	BEARWALLOW - VA	Transmission		138.00	70.50	13.09	54.00	1			0	0.00
49	BECCO - WV	Distribution		46.00	0.00	0.00	0.00			STATCAP	1	9.60
50	BECCO - WV	Distribution		46.00	12.00		9.38	1			0	0.00
51	BECKLEY - WV	Distribution		46.00	4.16		6.25	1			0	0.00
52	BECKLEY - WV	Distribution		46.00	12.00		40.00	2			0	0.00
53	BECKLEY - WV	Distribution		46.00	0.00	0.00	0.00			STATCAP	1	12.00
54	BELCHER MOUNTAIN - WV	Distribution		88.00	14.00		4.50	3			0	0.00
55	BELLE - WV	Transmission		46.00	12.00		20.00	1			0	0.00
56	BELVA - WV	Transmission		138.00	46.00		30.00	1			0	0.00
57	BELVA - WV	Transmission		138.00	34.50		9.38	1			0	0.00
58	BENS CREEK - WV	Distribution		46.00	13.20		2.50	1			0	0.00
59	BENT MOUNTAIN - VA	Distribution		138.00	13.09		8.40	1			0	0.00
60	BENT MOUNTAIN - VA	Distribution		138.00	34.00		10.50	1			0	0.00
61	BIG BRANCH - WV	Transmission		46.00	0.00	0.00	0.00			STATCAP	1	9.60
62	BIG ROCK - VA	Distribution		34.50	13.65		5.00	1			0	0.00
63	BIM - WV	Transmission		138.00	69.00	46.00	84.00	1			0	0.00
64	BIM - WV	Transmission		46.00	0.00	0.00	0.00			STATCAP	1	14.40
65	BIM - WV	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	13.19
66	BLACKWATER - VA	Distribution		34.50	0.00	0.00	0.00			STATCAP	1	9.60
67	BLACKWATER - VA	Distribution		34.50	12.00		20.00	1			0	0.00
68	BLAINE - VA	Distribution		138.00	13.09		8.40	1			0	0.00
69	BLAINE - VA	Distribution		138.00	0.00	0.00	0.00			STATCAP	1	52.80
70	BLAINE - VA	Distribution		138.00	34.50		30.00	1			0	0.00
71	BLUE PENNANT - WV	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	14.40
72	BLUE RIDGE - VA	Distribution		12.00	4.00		0.30	3			0	0.00
73	BLUE RIDGE - VA	Distribution		34.50	12.00		10.94	2			0	0.00
74	BLUEFIELD AVENUE - WV	Distribution		138.00	13.09		44.80	2			0	0.00
75	BOLT - WV	Transmission		46.00	0.00	0.00	0.00			STATCAP	1	9.60
76	BOLT - WV	Transmission		138.00	69.00	46.00	129.00	1			0	0.00
77	BONSACK - VA	Distribution		138.00	34.50		30.00	1			0	0.00
78	BOONE - WV	Distribution		46.00	0.00	0.00	0.00			STATCAP	1	9.60
79	BOONE - WV	Distribution		46.00	12.00		4.69	1			0	0.00
80	BOONSBORO - VA	Distribution		138.00	13.09		20.00	1			0	0.00
81	BORDERLAND - WV	Distribution		138.00	13.09		20.00	1			0	0.00
82	BOWYER - WV	Distribution		46.00	7.20		3.00	3			0	0.00
83	BOXWOOD - VA	Distribution		138.00	13.09		20.00	1			0	0.00
84	BRADLEY - WV	Transmission		138.00	69.00	46.00	130.00	1			0	0.00
85	BRADLEY - WV	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	50.40
86	BRADLEY - WV	Transmission		46.00	12.00		8.40	1			0	0.00
87	BRIAR MOUNTAIN - WV	Distribution		46.00	7.20		3.00	3			0	0.00
88	BRIDGE - WV	Distribution		69.00	13.09		45.00	2			0	0.00
89	BROADFORD - VA	Transmission		765.00	138.00	13.80		3			0	0.00
90	BROADFORD - VA	Transmission		765.00						REACTOR	3	300.00
91	BROCKWAY GLASS - VA	Distribution		69.00	4.00		9.38	1			0	0.00
92	BROOKVILLE - VA	Distribution		138.00	13.09		22.40	1			0	0.00
93	BROWNSVILLE (AP) - WV	Distribution		69.00	12.00		6.25	1			0	0.00
94	BRUSH TAVERN - VA	Distribution		138.00	34.50		60.00	2			0	0.00
95	BUCKHORN - VA	Distribution		138.00	34.50		30.00	1			0	0.00
96	BURLINGTON HEIGHTS - VA	Distribution		138.00	34.50		30.00	1			0	0.00
97	BYLLESBY - VA	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	13.19
98	CABELL - WV	Distribution		138.00	34.50		30.00	1			0	0.00
99	CABELL - WV	Distribution		138.00	36.20		30.00	1			0	0.00
100	CABIN CREEK 46KV - WV	Transmission		138.00	46.00		75.00	1			0	0.00
101	CABIN CREEK 46KV - WV	Transmission		46.00	12.00		22.40	1			0	0.00
102	CABIN CREEK 46KV - WV	Transmission		138.00	46.20		75.00	1			0	0.00
103	CAMBRIA - VA	Distribution		69.00	13.09		25.00	1			0	0.00
104	CAMPBELL AVENUE - VA	Distribution		34.50	0.00	0.00	0.00			STATCAP	1	9.60
105	CAMPBELL AVENUE - VA	Distribution		69.00	34.50		30.00	1			0	0.00
106	CAMPBELL AVENUE - VA	Distribution		69.00	12.00		44.80	2			0	0.00
107	CANDLERS MOUNTAIN - VA	Distribution		138.00	13.09		22.40	1			0	0.00
108	CAPITOL HILL 138KV - WV	Transmission		138.00	13.09		20.00	1			0	0.00
109	CAPITOL HILL 138KV - WV	Transmission		138.00	69.00	46.00	90.00	1			0	0.00
110	CAPITOL HILL 138KV - WV	Transmission		138.00	46.00		45.00	1			0	0.00
111	CAPITOL HILL 46KV - WV	Transmission		46.00	0.00	0.00	0.00			STATCAP	1	18.00
112	CARBONDALE - WV	Transmission		46.00	36.20		10.50	1			0	0.00
113	CARBONDALE - WV	Transmission		138.00	69.00	46.00	128.80	1			0	0.00
114	CARSWELL - WV	Transmission		138.00	88.00	7.98	60.00	3			0	0.00
115	CATAWBA - VA	Transmission		138.00	69.00	34.50		1			0	0.00
116	CATAWBA - VA	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	16.20
117	CATAWBA - VA	Transmission		138.00	34.50		30.00	1			0	0.00
118	CATAWBA - VA	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	64.80
119	CAVE SPRING - VA	Distribution		138.00	13.09		42.40	2			0	0.00
120	CEDAR GROVE (AP) - WV	Distribution		46.00	12.00		5.00	1			0	0.00
121	CENTERVILLE - VA	Transmission		138.00	69.00	34.50	84.00	1			0	0.00
122	CENTERVILLE - VA	Transmission		138.00	13.09		10.50	1			0	0.00
123	CENTRAL AVENUE (AP) - WV	Distribution		46.00	0.00	0.00	0.00			STATCAP	1	20.39
124	CENTRAL MACHINE SHOP - WV	Distribution		46.00	4.00		3.75	1			0	0.00
125	CEREDO - WV	Distribution		34.50	4.00		6.25	1			0	0.00
126	CHAUNCEY - WV	Transmission		46.00	12.00		10.50	1			0	0.00
127	CHAUNCEY - WV	Transmission		138.00	46.00	19.50	30.00	3			0	0.00
128	CHEMICAL - WV	Transmission		138.00	69.00	46.00	84.00	1			0	0.00
129	CHEMICAL - WV	Transmission		138.00	46.00		290.00	3			0	0.00
130	CHEMICAL - WV	Transmission		46.00	12.00		22.40	1			0	0.00
131	CHEMICAL - WV	Transmission		46.00	0.00	0.00	0.00			STATCAP	2	52.19
132	CHERRY CREEK - WV	Distribution		138.00	34.50		30.00	1			0	0.00
133	CHERRY CREEK - WV	Distribution		138.00	46.00		90.00	0	1		0	0.00
134	CHERRY CREEK - WV	Distribution		138.00	13.09		20.00	1			0	0.00
135	CHESTERFIELD AVENUE - WV	Transmission		138.00	13.09		40.00	2			0	0.00
136	CHESTERFIELD AVENUE - WV	Transmission		138.00	70.50	46.00	90.00	1			0	0.00
137	CINDERELLA - WV	Distribution		138.00	13.09		20.00	1			0	0.00
138	CLAREMONT - WV	Distribution		69.00	12.00		8.40	1			0	0.00
139	CLAYPOOL HILL - VA	Distribution		138.00	13.09		40.00	2			0	0.00
140	CLAYTOR HILLTOP - VA	Transmission			0.00	0.00	0.00			STATCAP	1	57.60
141	CLEARBROOK - VA	Distribution		138.00	13.09		42.40	2			0	0.00
142	CLENDENIN - WV	Transmission		46.00	34.50	20.90	25.00	1			0	0.00
143	CLENDENIN - WV	Transmission		138.00	46.00		125.00	1			0	0.00
144	CLIFFORD - VA	Transmission		138.00	46.00		20.00	1			0	0.00
145	CLIFFORD - VA	Transmission		138.00	69.00	46.00	50.00	1			0	0.00
146	CLIFFORD - VA	Transmission		46.00	0.00	0.00	0.00			STATCAP	1	3.59
147	CLIFFTOP - WV	Distribution		138.00	13.09		20.00	1			0	0.00
148	CLINCHFIELD - VA	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	14.39
149	CLINCHFIELD - VA	Transmission		138.00	70.50	36.20	90.00	1			0	0.00
150	CLINTWOOD - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	9.60
151	CLINTWOOD - VA	Distribution		69.00	12.00		20.00	1			0	0.00
152	CLOVERDALE 138KV - VA	Transmission		345.00	137.50	13.14	448.00	1			0	0.00
153	CLOVERDALE 138KV - VA	Transmission		69.00	13.09		20.00	1			0	0.00
154	CLOVERDALE 138KV - VA	Transmission		138.00	70.50	36.20	200.00	0	1		0	0.00
155	CLOVERDALE 138KV - VA	Transmission		345.00	138.00	34.50	675.00	1			0	0.00
156	CLOVERDALE 138KV - VA	Transmission		345.00	137.50	13.80	450.00	1			0	0.00
157	CLOVERDALE 138KV - VA	Transmission		138.00	36.20		30.00	1			0	0.00
158	CLOVERDALE 765KV - VA	Transmission		138.00	13.09		20.00	0	1		0	0.00
159	CLOVERDALE 765KV - VA	Transmission		69.00	34.50		20.00	0	1		0	0.00
160	CLOVERDALE 765KV - VA	Transmission		765.00						REACTOR	5	500.00
161	CLOVERDALE 765KV - VA	Transmission		138.00	345.00	34.50	500.00	0	1		0	0.00
162	CLOVERDALE 765KV - VA	Transmission		138.00	13.09	34.50	500.00	0	1		0	0.00
163	CLOVERDALE 765KV - VA	Transmission		138.00	345.00	34.50	15.00	0	1		0	0.00
164	CLOVERDALE 765KV - VA	Transmission		138.00	13.09	34.50	15.00	0	1		0	0.00
165	CLOVERDALE 765KV - VA	Transmission		34.50	7.20		1.50	0	1		0	0.00
166	CLOVERDALE 765KV - VA	Transmission		138.00	34.00		20.00	0	1		0	0.00
167	CLOVERDALE 765KV - VA	Transmission		138.00	12.00		12.50	0	1		0	0.00
168	CLOVERDALE 765KV - VA	Transmission		69.00	12.00		5.25	0	1		0	0.00
169	CLOVERDALE 765KV - VA	Transmission		138.00	69.00	13.10	84.00	0	1		0	0.00
170	CLOVERDALE 765KV - VA	Transmission		69.00	34.50		75.00	0	1		0	0.00
171	CLOVERDALE 765KV - VA	Transmission		69.00	13.09		20.00	0	1		0	0.00
172	CLOVERDALE 765KV - VA	Transmission		138.00	13.09		10.50	0	1		0	0.00
173	CLOVERDALE 765KV - VA	Transmission		138.00	70.50	46.00	90.00	0	1		0	0.00
174	CLOVERDALE 765KV - VA	Transmission		138.00	12.00		15.00	0	1		0	0.00
175	CLOVERDALE 765KV - VA	Transmission		69.00	12.00		7.50	0	1		0	0.00
176	CLOVERDALE 765KV - VA	Transmission		69.00	13.09		7.50	0	1		0	0.00
177	CLOVERDALE 765KV - VA	Transmission		69.00	12.00		9.38	0	1		0	0.00
178	CLOVERDALE 765KV - VA	Transmission		69.00	13.09		9.38	0	1		0	0.00
179	CLOVERDALE 765KV - VA	Transmission		765.00	345.00	34.50	5400.00	32			0	0.00
180	CLOVERDALE 765KV - VA	Transmission		765.00	528.00	13.80	1950.00	3			0	0.00
181	CLOVERDALE 765KV - VA (A)	Transmission		138.00	70.50	13.09	78.00	0	1		0	0.00
182	CLOVERDALE 765KV - VA (B)	Transmission		138.00	70.50	13.09	78.00	0	1		0	0.00
183	CLOVERDALE 765KV - VA (C)	Transmission		138.00	70.50	13.09	78.00	0	1		0	0.00
184	CLOVERDALE 765KV - VA (D)	Transmission		138.00	70.50	13.09	78.00	0	1		0	0.00
185	CLOVERDALE 765KV - VA (E)	Transmission		138.00	70.50	36.20	78.00	0	1		0	0.00
186	CLOVERDALE 765KV - VA (F)	Transmission		138.00	70.50	36.20	78.00	0	1		0	0.00
187	CLOVERDALE 765KV - VA (G)	Transmission		138.00	70.50	36.20	78.00	0	1		0	0.00
188	CLOVERDALE 765KV - VA (H)	Transmission		138.00	70.50	36.20	78.00	0	1		0	0.00
189	CLOVERDALE EAST 500KV - VA	Transmission		500.00	345.00	13.80	3500.00	7			0	0.00
190	COAL CREEK - VA	Distribution		69.00	12.00		10.00	1			0	0.00
191	COAL MOUNTAIN - WV	Distribution		46.00	7.20		1.66	2			0	0.00
192	COFFEE - VA	Distribution		138.00	13.09		20.00	1			0	0.00
193	COLLINSVILLE (AP) - VA	Distribution		138.00	13.09		22.40	1			0	0.00
194	CORNING GLASS (AP) - VA	Distribution		69.00	4.00		8.40	1			0	0.00
195	CORNING GLASS (AP) - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	8.10
196	COTTAGEVILLE - WV	Distribution		69.00	12.00		6.25	1			0	0.00
197	COVE ROAD - VA	Distribution		69.00	13.09		20.00	1			0	0.00
198	CRAB ORCHARD - WV	Distribution		46.00	12.00		3.75	1			0	0.00
199	CROOKED CREEK - WV	Distribution		138.00	13.09		20.00	1			0	0.00
200	CROSSROADS (AP) - VA	Distribution		69.00	13.09		22.40	1			0	0.00
201	CROSSROADS (AP) - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	9.60
202	CURRY - WV	Distribution		138.00	13.09		20.00	1			0	0.00
203	DALEWOOD - WV	Distribution		138.00	13.09		20.00	1			0	0.00
204	DAMASCUS - VA	Distribution		69.00	12.00		20.00	1			0	0.00
205	DAMERON - WV	Transmission		138.00	69.00	46.00	129.00	1			0	0.00
206	DAMERON - WV	Transmission		46.00	34.50		20.00	1			0	0.00
207	DAMERON - WV	Transmission		46.00	0.00	0.00	0.00			STATCAP	1	9.60
208	DAN RIVER RESEARCH - VA	Distribution		12.00	0.60		0.25	1			0	0.00
209	DAN RIVER RESEARCH - VA	Distribution		69.00	12.00		1.00	1			0	0.00
210	DAN RIVER RESEARCH - VA	Distribution		7.62	0.60		0.50	2			0	0.00
211	DANVILLE - VA	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	57.60
212	DANVILLE - VA	Transmission		138.00	69.00	12.00	115.00	1			0	0.00
213	DARRAH - WV	Transmission		138.00	69.00	34.50	90.00	1			0	0.00
214	DARRAH - WV	Transmission		138.00	13.09		22.40	1			0	0.00
215	DARRAH - WV	Transmission		138.00	34.50		45.50	1			0	0.00
216	DARRAH - WV	Transmission		138.00	34.50		30.00	1			0	0.00
217	DEARINGTON - VA	Distribution		69.00	13.09		25.00	1			0	0.00
218	DEARINGTON - VA	Distribution		69.00	12.00		20.00	1			0	0.00
219	DEARINGTON - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	14.40
220	DEHUE - WV	Distribution		46.00	13.09		9.38	1			0	0.00
221	DINGESS - WV	Distribution		138.00	34.50		30.00	1			0	0.00
222	DISMAL RIVER - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	14.39
223	DISMAL RIVER - VA	Distribution		69.00	12.00		10.50	1			0	0.00
224	DISSTON - VA	Distribution		69.00	4.00		3.13	1			0	0.00
225	DOROTHY - WV	Distribution		46.00	2.30		1.50	3			0	0.00
226	DUBLIN (AP) - VA	Distribution		34.50	12.00		18.76	3			0	0.00
227	DUNBAR - WV	Distribution		46.00	13.09		20.00	1			0	0.00
228	DUPONT (AP) - VA	Distribution		69.00	12.00		4.20	1			0	0.00
229	EAST DANVILLE - VA	Transmission		69.00	12.00		8.40	1			0	0.00
230	EAST DANVILLE - VA	Transmission		138.00	69.50	13.09	60.00	1			0	0.00
231	EAST DANVILLE - VA	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	52.79
232	EAST DANVILLE - VA	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	14.39
233	EAST DANVILLE - VA	Transmission		230.00	138.00	34.50	1500.00	2			0	0.00
234	EAST HUNTINGTON - WV	Transmission		138.00	69.00	34.50	90.00	1			0	0.00
235	EAST HUNTINGTON - WV	Transmission		138.00	34.50		30.00	1			0	0.00
236	EAST HUNTINGTON - WV	Transmission		34.50	12.00		9.38	1			0	0.00
237	EAST LYNCHBURG - VA	Transmission		138.00	69.00	34.50	196.00	1			0	0.00
238	EAST MONUMENT - VA	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	52.79
239	EAST RIVER MOUNTAIN - WV	Distribution		138.00	34.50		9.38	1			0	0.00
240	EDGEMONT - VA	Distribution		138.00	13.09		22.40	1			0	0.00
241	EDWIGHT - WV	Distribution		46.00	7.20		2.49	3			0	0.00
242	ELK CREEK - WV	Distribution		46.00	12.00		3.75	1			0	0.00
243	ELK GARDEN - VA	Distribution		138.00	13.09		7.50	1			0	0.00
244	ELK GARDEN - VA	Distribution		138.00	36.20		30.00	1			0	0.00
245	ELK GARDEN - VA	Distribution		138.00	34.50		30.00	1			0	0.00
246	ELM STREET - VA	Distribution		34.50	0.00	0.00	0.00			STATCAP	1	9.60
247	ELM STREET - VA	Distribution		34.50	12.00		20.00	1			0	0.00
248	ELMO - WV	Distribution		69.00	12.00		5.00	1			0	0.00
249	ESMONT - VA	Distribution		46.00	12.00		4.69	1			0	0.00
250	EXPRESSWAY - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	10.80
251	EXPRESSWAY - VA	Distribution		69.00	12.00		42.40	2			0	0.00
252	FALLING BRANCH - VA	Distribution		138.00	13.09		9.38	1			0	0.00
253	FARADAY 138KV - WV	Distribution		34.50	0.00	0.00	0.00			AIR CORE REACTOR	3
254	FARADAY 138KV - WV	Distribution		34.50	0.00	0.00	0.00			STATCAP	1	6.00
255	FIELDALE - VA	Transmission		138.00	70.50	36.20	78.00	1			0	0.00
256	FIELDALE - VA	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	100.80
257	FIELDALE - VA	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	26.39
258	FIELDCREST MILLS - VA	Distribution		69.00	4.00		20.00	1			0	0.00
259	FLATWOOD - WV	Distribution		138.00	34.50		30.00	1			0	0.00
260	FLATWOOD - WV	Distribution		138.00	12.47		22.40	1			0	0.00
261	FLETCHERS RIDGE - VA	Distribution		138.00	13.09		10.50	1			0	0.00
262	FLOYD - VA	Transmission		138.00	69.00	34.50	56.00	1			0	0.00
263	FLOYD - VA	Transmission		138.00	13.09		10.50	1			0	0.00
264	FLOYD - VA	Transmission		138.00	12.00		9.38	1			0	0.00
265	FOREST (AP) - VA	Distribution		138.00	13.09		42.40	2			0	0.00
266	FOUR POLE CREEK - WV	Distribution		34.50	4.16		4.50	3			0	0.00
267	FRANKLIN - VA	Distribution		138.00	13.09		22.40	1			0	0.00
268	FRANKLIN - VA	Distribution		138.00	34.50		30.00	1			0	0.00
269	FRANKLIN STREET - VA	Distribution		34.50	12.00		6.25	1			0	0.00
270	FREMONT (AP) - VA	Transmission		138.00	70.50	13.09	208.00	2			0	0.00
271	FRIES - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	14.40
272	FRIES - VA	Distribution		69.00	12.00		10.28	2			0	0.00
273	FULKS - WV	Distribution		34.50	13.09		9.38	1			0	0.00
274	FULKS - WV	Distribution		34.50	34.50	5.00	25.00	1			0	0.00
275	FULKS - WV	Distribution		34.50	34.50	6.50	30.00	1			0	0.00
276	GALAX - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	2	26.38
277	GALAX - VA (A)	Distribution		69.00	12.00		22.40	1			0	0.00
278	GALAX - VA	Distribution		69.00	12.00		22.40	1			0	0.00
279	GALLAGHER - WV	Distribution		46.00	12.00		4.69	1			0	0.00
280	GARDEN CREEK - VA	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	50.40
281	GARDEN CREEK - VA	Transmission		138.00	69.50	13.09	84.00	1			0	0.00
282	GARDEN CREEK - VA	Transmission		69.00	12.00		22.40	1			0	0.00
283	GAULEY MOUNTAIN - WV	Distribution		69.00	12.00		8.40	1			0	0.00
284	GILBERT - WV	Distribution		46.00	12.00		20.00	1			0	0.00
285	GILBERT - WV	Distribution		46.00	0.00	0.00	0.00			STATCAP	1	9.60
286	GLADE - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	9.60
287	GLADE - VA	Distribution		69.00	34.50		30.00	1			0	0.00
288	GLADE - VA	Distribution		69.00	12.00		10.50	1			0	0.00
289	GLAMORGAN - VA	Distribution		34.50	4.00		9.38	1			0	0.00
290	GLEN LYN - VA	Transmission		138.00	13.20		18.75	3			0	0.00
291	GLEN LYN - VA	Transmission		88.00	69.00	13.10	84.00	0	1		0	0.00
292	GLEN LYN - VA	Transmission		138.00	0.00	0.00	0.00			STATCAP	4	203.99
293	GLEN WHITE - WV	Distribution		46.00	12.00		6.25	1			0	0.00
294	GLENWOOD (AP) - VA	Distribution		12.00	0.24		0.33	2			0	0.00
295	GLENWOOD (AP) - VA	Distribution		13.20	0.24		0.17	1			0	0.00
296	GLENWOOD (AP) - VA	Distribution		12.00	0.24		0.17	0	1		0	0.00
297	GLENWOOD (AP) - VA	Distribution		23.00	12.00		9.40	1			0	0.00
298	GLENWOOD (AP) - VA	Distribution		23.00	12.00		3.75	0	1		0	0.00
299	GOMINGO - VA	Distribution		138.00	13.09		22.40	1			0	0.00
300	GRAPEVINE - WV	Distribution		46.00	7.20		6.99	6			0	0.00
301	GRASSY FORK - WV	Distribution		138.00	34.50		20.00	1			0	0.00
302	GRAVES MILL - VA	Distribution		138.00	13.09		40.00	2			0	0.00
303	GREENBRIER - WV	Distribution		69.00	13.09		25.00	1			0	0.00
304	GREENBRIER METERING - WV	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	28.79
305	GRUNDY - VA	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	13.19
306	GRUNDY - VA	Transmission		69.00	12.00		10.50	1			0	0.00
307	GRUNDY - VA	Transmission		69.00	34.50		25.00	1			0	0.00
308	GUTHRIE - WV	Distribution		46.00	34.50		25.00	1			0	0.00
309	HALES BRANCH - VA	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	14.39
310	HALES BRANCH - VA	Transmission		138.00	69.00	12.00	84.00	1			0	0.00
311	HALES BRANCH - VA	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	50.40
312	HALLS RIDGE - WV	Distribution		138.00	34.50			1			0	0.00
313	HAMPTON - WV	Distribution		46.00	7.20		4.50	3			0	0.00
314	HAMPTON - WV	Distribution		46.00	12.00		3.75	1			0	0.00
315	HANCOCK - VA	Transmission		34.50	0.00	0.00	0.00			STATCAP	1	12.00
316	HANCOCK - VA	Transmission		138.00	34.50	11.00	45.00	3			0	0.00
317	HANCOCK - VA	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	50.40
318	HANCOCK - VA	Transmission		34.50	36.20		15.00	1			0	0.00
319	HANCOCK - VA	Transmission		138.00	69.00	34.50	128.80	1			0	0.00
320	HANS MEADOW - VA	Distribution		69.00	13.09		25.00	1			0	0.00
321	HANS MEADOW - VA	Distribution		69.00	12.00		10.50	0	1		0	0.00
322	HANS MEADOW - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	17.20
323	HANSONVILLE - VA	Distribution		138.00	13.09		20.00	1			0	0.00
324	HARDY - WV	Distribution		46.00	7.20		4.50	3			0	0.00
325	HARMON BRANCH - WV	Distribution		138.00	12.00		15.00	1			0	0.00
326	HARTLAND - WV	Distribution		46.00	0.00	0.00	0.00			STATCAP	1	5.40
327	HARTLAND - WV	Distribution		46.00	13.09		12.50	1			0	0.00
328	HASH RIDGE - WV	Distribution		138.00	34.50		30.00	1			0	0.00
329	HAYSI - VA	Distribution		69.00	12.00		20.00	1			0	0.00
330	HENRY S.D. - VA	Distribution		34.50	13.00		3.75	1			0	0.00
331	HEWETT - WV	Distribution		46.00	12.00		10.50	1			0	0.00
332	HICKMAN - VA	Distribution		69.00	13.09		20.00	1			0	0.00
333	HICKORY GAP - WV	Distribution		34.50	12.00		2.50	1			0	0.00
334	HILL - VA	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	13.19
335	HILL - VA	Transmission		138.00	69.00	34.50	40.00	1			0	0.00
336	HILL - VA	Transmission		138.00	13.09		8.40	1			0	0.00
337	HILLMAN HIGHWAY - VA	Distribution		69.00	12.00		22.40	1			0	0.00
338	HILLMAN HIGHWAY - VA	Distribution		69.00	13.09		25.00	1			0	0.00
339	HILLSVILLE - VA	Distribution		34.50	12.00		6.75	2			0	0.00
340	HINTON (AP) - WV	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	43.20
341	HOPKINS - WV	Transmission		138.00	0.00	0.00	0.00			AIR CORE REACTOR	4	0.00
342	HOPKINS - WV	Transmission		138.00	69.00	46.00	56.00	1			0	0.00
343	HOPKINS - WV	Transmission		138.00	34.50		20.00	1			0	0.00
344	HOPKINS - WV	Transmission		138.00	13.09		20.00	1			0	0.00
345	HOPKINS FORK - WV	Distribution		46.00	7.20		2.49	3			0	0.00
346	HUBBARDSTOWN - WV	Distribution		138.00	34.50		20.00	1			0	0.00
347	HUFF CREEK - WV	Transmission		46.00	0.00	0.00	0.00			STATCAP	1	9.60
348	HUFF CREEK - WV	Transmission		138.00	69.00	46.00	130.00	1			0	0.00
349	HUFF CREEK - WV	Transmission		46.00	13.09		20.00	1			0	0.00
350	HUFFMAN - VA	Distribution		138.00	0.00	0.00	0.00			STATCAP	1	28.80
351	HUGHESTON - WV	Distribution		46.00	2.40		2.50	3			0	0.00
352	HUNTINGTON COURT - VA	Distribution		138.00	69.00	34.50	175.00	1			0	0.00
353	HUNTINGTON COURT - VA	Distribution		138.00	0.00	0.00	0.00			STATCAP	1	64.80
354	HUNTINGTON COURT - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	28.80
355	HUNTINGTON COURT - VA	Distribution		69.00	12.00		20.00	1			0	0.00
356	HUNTINGTON COURT - VA	Distribution		69.00	34.50		75.00	1			0	0.00
357	HURLEY - VA	Distribution		69.00	12.00		22.40	1			0	0.00
358	HURRICANE - WV	Distribution		69.00	12.00		25.00	1			0	0.00
359	HURRICANE - WV	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	21.60
360	INDEPENDENCE - VA	Distribution		69.00	12.00		10.50	1			0	0.00
361	INDEPENDENCE - VA	Distribution		69.00	34.50		20.00	1			0	0.00
362	INGLES - VA	Distribution		69.00	13.09		20.00	1			0	0.00
363	INGLES - VA	Distribution		69.00	34.50		50.00	1			0	0.00
364	INGLES - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	14.40
365	ITMANN - WV	Distribution		138.00	13.09		22.40	1			0	0.00
366	IVY HILL - VA	Distribution		138.00	13.09		20.00	1			0	0.00
367	JACKSONS FERRY - VA	Transmission		765.00	138.00	13.80	1750.00	8			0	0.00
368	JACKSONS FERRY - VA	Transmission		765.00	20.65	13.80		1			0	0.00
369	JACKSONS FERRY - VA	Transmission		765.00		13.80	250.00	2			0	0.00
370	JACKSONS FERRY - VA	Transmission		765.00	138.00		250.00	2			0	0.00
371	JACKSONS FERRY - VA	Transmission		13.20	0.00	0.00	0.00			STATCAP	1	3.59
372	JACKSONS FERRY - VA	Transmission		765.00			250.00	2			0	0.00
373	JACKSONS FERRY - VA	Transmission		765.00	500.00	13.80	500.00	3			0	0.00
374	JACKSONS FERRY - VA	Transmission		20.78	0.00	0.00	0.00			STATCAP	3	888.84
375	JARROLD - WV	Distribution		46.00	13.09		5.00	1			0	0.00
376	JEWELL RIDGE - VA	Distribution		69.00	12.00		9.38	1			0	0.00
377	JIM BRANCH - WV	Transmission		69.00	12.00		10.00	1			0	0.00
378	JIM BRANCH - WV	Transmission		138.00	69.00	46.00	128.80	1			0	0.00
379	JOHNSONS LANE - WV	Distribution		34.50	34.50	5.00	25.00	1			0	0.00
380	JOSHUA FALLS - VA	Transmission		765.00	138.00	13.80	750.00	3			0	0.00
381	JUBAL EARLY - VA	Transmission		138.00	70.50	36.20	108.00	2			0	0.00
382	JUBAL EARLY - VA	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	43.20
383	KANAWHA CITY - WV	Distribution		46.00	12.00		22.40	1			0	0.00
384	KANAWHA CITY - WV	Distribution		46.00	0.00	0.00	0.00			STATCAP	1	15.60
385	KANAWHA RIVER - WV	Transmission		138.00	13.09		20.00	1			0	0.00
386	KANAWHA RIVER - WV	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	115.20
387	KANAWHA RIVER - WV	Transmission		345.00	138.00	13.80		1			0	0.00
388	KENOVA - WV	Transmission		138.00	69.00	46.00	150.00	0	1		0	0.00
389	KENOVA - WV	Transmission		34.50	4.00		3.75	1			0	0.00
390	KENOVA - WV	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	14.40
391	KENOVA - WV	Transmission		138.00	34.50		30.00	1			0	0.00
392	KENOVA - WV	Transmission		138.00	69.00	34.50	200.00	1			0	0.00
393	KENOVA - WV	Transmission		34.50	13.09		9.38	1			0	0.00
394	KILLARNEY - WV	Distribution		46.00	7.20		1.16	3			0	0.00
395	KINCAID - WV	Transmission		138.00	69.00	46.00	84.00	1			0	0.00
396	KNOTTY POPLAR - VA	Distribution		69.00	12.00		6.25	1			0	0.00
397	KOPPERSTON - WV	Distribution		138.00	13.09		20.00	1			0	0.00
398	KUMIS - VA	Distribution		138.00	13.09		22.40	1			0	0.00
399	LAKE FOREST - VA	Distribution		138.00	36.20		30.00	1			0	0.00
400	LAKEVIEW - WV	Distribution		138.00	13.09		20.00	1			0	0.00
401	LAKIN - WV	Transmission		138.00	69.00	12.00	90.00	1			0	0.00
402	LAKIN - WV	Transmission		138.00	13.09		20.00	1			0	0.00
403	LATROBE - WV	Distribution		46.00	7.20		4.50	3			0	0.00
404	LAVALETTE - WV	Distribution		138.00	34.50		30.00	1			0	0.00
405	LAYLAND - WV	Distribution		69.00	13.09		2.50	1			0	0.00
406	LEBANON - VA	Distribution		138.00	13.09		22.40	1			0	0.00
407	LEIVASY - WV	Distribution		69.00	12.00		8.40	1			0	0.00
408	LICK FORK - VA	Distribution		69.00	34.50		10.50	1			0	0.00
409	LOCK LANE - WV	Distribution		69.00	12.00		6.25	1			0	0.00
410	LOCKHART - VA	Distribution		138.00	13.04		20.00	1			0	0.00
411	LOGAN - WV	Transmission		138.00	13.09		22.40	1			0	0.00
412	LOGAN - WV	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	115.19
413	LONESOME PINE - VA	Distribution		138.00	13.09		22.40	1			0	0.00
414	LOONEY CREEK - VA	Transmission		138.00	69.00	34.50	90.00	1			0	0.00
415	LOUDENDALE - WV	Distribution		46.00	12.00		10.50	1			0	0.00
416	LOUP CREEK - WV	Distribution		46.00	12.00		3.00	1			0	0.00
417	LUKENS - VA	Distribution		69.00	12.00		20.00	1			0	0.00
418	LUKENS - VA	Distribution		69.00	13.09		20.00	1			0	0.00
419	MAMMOTH - WV	Distribution		46.00	12.00		3.75	1			0	0.00
420	MARMET - WV	Distribution		46.00	12.00		7.00	1			0	0.00
421	MARSH FORK - WV	Distribution		46.00	12.00		10.50	1			0	0.00
422	MARTINSVILLE - VA	Transmission		138.00	34.50		30.00	1			0	0.00
423	MARTINSVILLE - VA	Transmission		138.00	70.50	36.20	108.00	2			0	0.00
424	MASON CREEK - VA	Distribution		69.00	12.00		25.00	1			0	0.00
425	MATT FUNK 138KV - VA	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	147.60
426	MATT FUNK 345KV - VA	Transmission		345.00	138.00	13.10	672.00	1			0	0.00
427	MATT FUNK 345KV - VA	Transmission		345.00	138.00	34.50	675.00	1			0	0.00
428	MCDOWELL - WV	Transmission		34.50	13.20		7.50	1			0	0.00
429	MCGRAWS - WV	Distribution		46.00	13.09		12.50	1			0	0.00
430	MCROSS - WV	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	9.60
431	MCROSS - WV	Distribution		69.00	34.50		30.00	1			0	0.00
432	MEADOW BRIDGE - WV	Distribution		69.00	34.50		8.40	1			0	0.00
433	MEADOWVIEW - VA	Distribution		138.00	13.09		20.00	1			0	0.00
434	MEADOWVIEW - VA	Distribution		138.00	69.00	34.50	56.00	1			0	0.00
435	MELROSE - VA	Distribution		69.00	12.00		22.40	1			0	0.00
436	MERRIMAC - VA	Transmission		138.00	69.00	12.00	128.00	1			0	0.00
437	MERRIMAC - VA	Transmission		138.00	69.00	13.09	78.00	1			0	0.00
438	MERRIMAC - VA	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	27.00
439	MERRITTS CREEK - WV	Distribution		138.00	36.20		30.00	1			0	0.00
440	MIDDLE BURNING CREEK - WV	Distribution		34.50	12.00		5.00	1			0	0.00
441	MIDKIFF - WV	Distribution		138.00	34.50		20.00	1			0	0.00
442	MIDWAY (AP) - VA	Distribution		69.00	4.00		12.25	2			0	0.00
443	MIKES RUN - WV	Distribution		46.00	12.00		3.75	1			0	0.00
444	MILBURN - WV	Distribution		46.00	7.20		1.50	3			0	0.00
445	MILTON - WV	Transmission		69.00	36.20		30.00	1			0	0.00
446	MILTON - WV	Transmission		138.00	13.09		25.00	2			0	0.00
447	MILTON - WV	Transmission		138.00	69.00	34.50	90.00	1			0	0.00
448	MINK SHOALS - WV	Distribution		69.00	13.09		20.00	1			0	0.00
449	MINNIX MOUNTAIN - WV	Distribution		138.00	34.00		25.00	1			0	0.00
450	MOHAWK RUBBER - VA	Distribution		69.00	2.40		25.00	2			0	0.00
451	MONEL - VA	Distribution		138.00	13.09		20.00	1			0	0.00
452	MONETA - VA	Distribution		138.00	34.50		30.00	1			0	0.00
453	MONROE (AP) - VA	Distribution		69.00	13.09		20.00	1			0	0.00
454	MONTEREY - VA	Distribution		69.00	12.00		10.50	1			0	0.00
455	MONTGOMERY - WV	Distribution		46.00	12.00		22.40	1			0	0.00
456	MORGANS CUT - VA	Transmission		138.00	69.00	34.50	200.00	1			0	0.00
457	MORGANS CUT - VA	Transmission		138.00	69.00	34.50	84.00	0	1		0	0.00
458	MORGANS CUT - VA	Transmission		34.50	0.00	0.00	0.00			STATCAP	1	13.50
459	MORRIS NOVELTY - VA	Distribution		34.50	12.00		3.75	1			0	0.00
460	MORRIS NOVELTY - VA	Distribution		34.50	0.00	0.00	0.00			STATCAP	1	15.60
461	MOSELEY - VA	Transmission		138.00	70.50	13.09	1674.00	27			0	0.00
462	MOSS - VA	Distribution		69.00	12.00		8.40	1			0	0.00
463	MOUNT AIRY - VA	Distribution		138.00	34.50		20.00	1			0	0.00
464	MOUNT UNION - VA	Transmission		69.00	34.50		30.00	1			0	0.00
465	MOUNT UNION - VA	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	13.19
466	MOUNT UNION - VA	Transmission		69.00	12.00		20.00	1			0	0.00
467	MOUNT VIEW - VA	Distribution		69.00	12.00		22.40	1			0	0.00
468	MUD FORK - WV	Distribution		138.00	13.09		22.40	1			0	0.00
469	MUDLICK - VA	Distribution		69.00	12.00		22.40	1			0	0.00
470	MULLENS - WV	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	50.40
471	MULLENS - WV	Transmission		138.00	34.50		25.00	1			0	0.00
472	MULLENS - WV	Transmission		138.00	46.00		30.00	1			0	0.00
473	MULLENS TOWN - WV	Distribution		34.50	4.00		4.70	1			0	0.00
474	NAGEL - TN	Transmission		500.00	230.00	13.80	750.00	3			0	0.00
475	NAGEL - TN	Transmission		138.00	34.50		30.00	1			0	0.00
476	NAGEL - TN	Transmission		500.00	138.00	13.80		3			0	0.00
477	NEECE CREEK - VA	Distribution		69.00	12.00		8.40	1			0	0.00
478	NEW CASTLE - VA	Distribution		34.50	12.00		7.00	1			0	0.00
479	NEW CASTLE - VA	Distribution		34.50	0.00	0.00	0.00			STATCAP	1	3.59
480	NEW HOPE (AP) - WV	Distribution		138.00	34.50		25.00	1			0	0.00
481	NEW HOPE (AP) - WV	Distribution		138.00	13.09		22.40	1			0	0.00
482	NEW LONDON - VA	Transmission		138.00	34.50		30.00	1			0	0.00
483	NITRO - WV	Distribution		69.00	12.00		20.00	1			0	0.00
484	NORTH BECKLEY - WV	Distribution		138.00	34.50		30.00	1			0	0.00
485	NORTH BECKLEY - WV	Distribution		138.00	13.09		25.00	1			0	0.00
486	NORTH BLACKSBURG - VA	Transmission		138.00	69.00	12.00	128.80	1			0	0.00
487	NORTH BLACKSBURG - VA	Transmission		138.00	13.09		22.40	1			0	0.00
488	NORTH CLAYTOR - VA	Transmission		138.00	69.00	34.50	200.00	1			0	0.00
489	NORTH CLAYTOR - VA	Transmission		138.00	69.00	34.50	84.00	0	1		0	0.00
490	NORTH POINTE - WV	Distribution		138.00	34.50		20.00	1			0	0.00
491	OAK HILL (AP) - WV	Distribution		69.00	12.00		22.40	1			0	0.00
492	OAK LEVEL - VA	Distribution		138.00	13.09		20.00	1			0	0.00
493	OCEANA - WV	Distribution		46.00	12.00		16.75	2			0	0.00
494	OPOSSUM CREEK - VA	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	105.58
495	ORCHARD - VA	Distribution		34.50	12.00		6.25	1			0	0.00
496	ORTIN - WV	Distribution		138.00	13.09		20.00	1			0	0.00
497	PACKSVILLE - WV	Transmission		46.00	0.00	0.00	0.00			STATCAP	1	9.60
498	PAD FORK - WV	Distribution		138.00	34.50		20.00	1			0	0.00
499	PANTHER - WV	Distribution		46.00	7.20		4.50	3			0	0.00
500	PARK HILL - WV	Distribution		138.00	13.09		22.40	1			0	0.00
501	PATRICK STREET - WV	Distribution		46.00	13.09		20.00	1			0	0.00
502	PATRIOT CENTRE - VA	Distribution		138.00	34.50		30.00	1			0	0.00
503	PAX BRANCH 138KV - WV	Transmission		138.00	46.00		216.00	4			0	0.00
504	PAX BRANCH 138KV - WV	Transmission		138.00	13.09		20.00	2			0	0.00
505	PAX BRANCH 138KV - WV	Transmission		138.00	12.00		20.00	2			0	0.00
506	PEAK CREEK - VA	Distribution		138.00	34.50		30.00	1			0	0.00
507	PEAK CREEK - VA	Distribution		138.00	13.09		20.00	1			0	0.00
508	PEAKLAND - VA	Distribution		69.00	12.00		20.00	1			0	0.00
509	PEAKSVIEW - VA	Transmission		138.00	69.00	34.50	130.00	1			0	0.00
510	PEARISBURG - VA	Distribution		34.50	12.00		6.25	1			0	0.00
511	PEMBERTON - WV	Transmission		46.00	4.00		5.00	1			0	0.00
512	PEMBERTON - WV	Transmission		138.00	69.00	46.00	90.00	1			0	0.00
513	PENHOOK - VA	Distribution		138.00	34.50		30.00	1			0	0.00
514	PERKINS PARK - VA	Distribution		69.00	12.00		20.00	1			0	0.00
515	PETERS MOUNTAIN - VA	Distribution		138.00	34.50		30.00	1			0	0.00
516	PEYTONA - WV	Distribution		46.00	13.09		10.50	1			0	0.00
517	PHOENIX - VA	Distribution		46.00	7.20		1.00	3			0	0.00
518	PIGEON CREEK - WV	Distribution		138.00	34.50		60.00	2			0	0.00
519	PINE CREEK - WV	Distribution		138.00	13.09		12.50	1			0	0.00
520	PINE GAP - WV	Distribution		46.00	12.00		3.00	1			0	0.00
521	PINNACLE CREEK - WV	Distribution		138.00	34.50		9.38	1			0	0.00
522	PINNACLE CREEK - WV	Distribution		138.00	34.50	12.00	13.30	1			0	0.00
523	PIPERS GAP - VA	Distribution		138.00	36.20		30.00	1			0	0.00
524	PIPERS GAP - VA	Distribution		138.00	34.00		30.00	1			0	0.00
525	PLANT ROAD - WV	Distribution		69.00	12.00		22.40	1			0	0.00
526	PLANTATION PIPELINE - VA	Distribution		34.50	7.50		4.50	3			0	0.00
527	POAGES MILL - VA	Distribution		138.00	13.09		20.00	1			0	0.00
528	POINT PLEASANT - WV	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	9.60
529	POLEYARD - WV	Distribution		138.00	13.09		25.00	1			0	0.00
530	POPLAR FORK - WV	Distribution		138.00	13.09		20.00	1			0	0.00
531	POPLAR GAP - WV	Distribution		46.00	7.20		4.50	3			0	0.00
532	POUND - VA	Distribution		69.00	12.00		6.25	1			0	0.00
533	POUND - VA	Distribution		69.00	34.50		25.00	1			0	0.00
534	POWELLTON - WV	Distribution		46.00	7.20		2.49	3			0	0.00
535	PRICES FORK - VA	Distribution			0.00	0.00	0.00			STATCAP	1
536	PRICES FORK - VA	Distribution		69.00	12.00		22.40	1			0	0.00
537	PRICES FORK - VA	Distribution		69.00	13.09		25.00	1			0	0.00
538	PRINCE - WV	Distribution		69.00	13.09		5.25	1			0	0.00
539	PRINCETON - WV	Distribution		34.50	12.00		20.00	2			0	0.00
540	PROGRESS PARK - VA	Distribution		138.00	0.00	0.00	0.00			STATCAP	1	57.60
541	PROGRESS PARK - VA	Distribution		138.00	36.20		30.00	1			0	0.00
542	PROGRESS PARK - VA	Distribution		138.00	34.50		30.00	1			0	0.00
543	PUTNAM VILLAGE - WV	Distribution		69.00	13.09		20.00	1			0	0.00
544	RADFORD - VA	Distribution		34.50	0.00	0.00	0.00			STATCAP	1	10.80
545	RAGLAND - WV	Distribution		138.00	34.50		25.00	1			0	0.00
546	RAVENSWOOD - WV	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	14.40
547	RAVENSWOOD - WV	Distribution		69.00	13.09		25.00	1			0	0.00
548	RED HILL - VA	Distribution		138.00	13.09		8.40	1			0	0.00
549	RENSFORD - WV	Distribution		138.00	34.50		25.00	1			0	0.00
550	REUSENS - VA	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	57.60
551	REUSENS - VA	Transmission		138.00	69.00	13.09	130.00	1			0	0.00
552	REUSENS - VA	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	13.50
553	RICH ACRES - VA	Distribution		69.00	34.50		30.00	1			0	0.00
554	RICH CREEK - WV	Distribution		46.00	12.00		10.50	1			0	0.00
555	RICHLANDS - VA	Transmission		138.00	69.00	13.09	78.00	1			0	0.00
556	RICHLANDS - VA	Transmission		138.00	69.00	13.10	130.00	1			0	0.00
557	RIDGEWAY - VA	Transmission		138.00	69.00	7.20	35.00	1			0	0.00
558	RIDGEWAY - VA	Transmission		138.00	69.00	4.00	40.00	1			0	0.00
559	RIDGEWAY - VA	Transmission		138.00						REACTOR	48	3,230.40
560	RIDGEWAY - VA	Transmission		138.00	34.50		25.00	1			0	0.00
561	RIDGEWAY - VA	Transmission		138.00	13.09		9.38	0	1		0	0.00
562	RIGIS - VA	Transmission		138.00	69.00	12.00	115.00	1			0	0.00
563	RIPLEY - WV	Distribution		138.00	69.00	13.09	78.00	1			0	0.00
564	RIPLEY - WV	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	9.60
565	RIPLEY - WV	Distribution		69.00	34.50		25.00	1			0	0.00
566	RIPLEY - WV	Distribution		69.00	13.09		12.50	1			0	0.00
567	RIVERBEND - VA	Distribution		69.00	12.00		9.38	1			0	0.00
568	RIVERBEND - VA	Distribution		69.00	12.00		7.00	1			0	0.00
569	RIVERBEND - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	14.40
570	RIVERMONT - VA	Distribution		69.00	12.00		20.00	1			0	0.00
571	RIVERVILLE - VA	Distribution		138.00	13.09		104.00	3			0	0.00
572	RIVERVILLE - VA	Distribution		138.00	0.00	0.00	0.00			STATCAP	1	32.40
573	ROANOKE (AP) - VA	Transmission		138.00	34.50		30.00	1			0	0.00
574	ROANOKE (AP) - VA	Transmission		138.00	0.00	0.00	0.00			STATCAP	2	122.39
575	ROANOKE (AP) - VA	Transmission		34.50	0.00	0.00	0.00			STATCAP	1	7.19
576	ROANOKE (AP) - VA	Transmission		138.00	13.09		20.00	1			0	0.00
577	ROANOKE (AP) - VA	Transmission		138.00	69.00	12.00	130.00	1			0	0.00
578	ROANOKE ELECTRIC STEEL - VA	Distribution		138.00	34.50		197.00	2			0	0.00
579	ROANOKE ELECTRIC STEEL - VA	Distribution		138.00	34.50		16.67	0	1		0	0.00
580	ROANOKE ELECTRIC STEEL - VA	Distribution		34.50	0.00	0.00	0.00			STATCAP	4	278.50
581	ROBINSON - WV	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	13.19
582	ROBINSON - WV	Distribution		69.00	12.00		10.40	1			0	0.00
583	RONDA - WV	Distribution		46.00	12.00		3.75	1			0	0.00
584	RONDA - WV	Distribution		46.00	0.00	0.00	0.00			STATCAP	1	7.20
585	RURAL RETREAT - VA	Distribution		138.00	34.50		25.00	1			0	0.00
586	RUSTBURG - VA	Distribution		138.00	13.09		20.00	1			0	0.00
587	RUTH - WV	Distribution		138.00	13.09		20.00	1			0	0.00
588	SALTVILLE - VA	Transmission		138.00	69.00	34.50	56.00	1			0	0.00
589	SALTVILLE - VA	Transmission		138.00	34.50		20.00	1			0	0.00
590	SALTVILLE - VA	Transmission		138.00	13.09		10.50	1			0	0.00
591	SCARBRO - WV	Transmission		46.00	0.00	0.00	0.00			STATCAP	1	9.60
592	SCHUYLER - VA	Distribution		46.00	7.20		0.83	0	1		0	0.00
593	SCHUYLER - VA	Distribution		46.00	7.20		2.01	3			0	0.00
594	SCOTTSVILLE (AP) - VA	Transmission		46.00	0.00	0.00	0.00			STATCAP	1	3.59
595	SCOTTSVILLE (AP) - VA	Transmission		46.00	13.09		9.38	1			0	0.00
596	SCOTTSVILLE (AP) - VA	Transmission		46.00	12.00		5.00	0	1		0	0.00
597	SCOTTSVILLE (AP) - VA	Transmission		138.00	46.00		40.00	3			0	0.00
598	SEVENTH STREET - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	14.40
599	SEVENTH STREET - VA	Distribution		69.00	12.00		69.80	3			0	0.00
600	SHABDUE - WV	Transmission		46.00	0.00	0.00	0.00			STATCAP	1	9.60
601	SHARPLES - WV	Distribution		46.00	0.00	0.00	0.00			STATCAP	1	9.60
602	SHARPLES - WV	Distribution		46.00	12.00		4.69	1			0	0.00
603	SHAWSVILLE - VA	Distribution		138.00	13.09		10.50	1			0	0.00
604	SHEFFIELD (AP) - VA	Distribution		138.00	34.50		30.00	1			0	0.00
605	SHERIDAN (AP) - WV	Distribution		69.00	12.00		22.40	1			0	0.00
606	SHERWILL - VA	Distribution		69.00	12.00		20.00	1			0	0.00
607	SHIPMAN - VA	Distribution		46.00	12.00		4.70	1			0	0.00
608	SISSON - WV	Distribution		138.00	34.50		30.00	1			0	0.00
609	SKEGGS BRANCH - VA	Transmission		138.00	69.00	4.00	30.00	1			0	0.00
610	SKIMMER - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	26.40
611	SKIMMER - VA	Distribution		115.00	69.00		112.00	2			0	0.00
612	SKIMMER - VA	Distribution		69.00	12.00		30.00	1			0	0.00
613	SKIN FORK - WV	Distribution		46.00	12.00		8.40	1			0	0.00
614	SKIN FORK - WV	Distribution		46.00	0.00	0.00	0.00			STATCAP	1	9.60
615	SLAB FORK - WV	Distribution		46.00	7.20		0.99	3			0	0.00
616	SLATE CREEK - VA	Distribution		69.00	13.09		20.00	1			0	0.00
617	SMITH LANE - VA	Distribution		34.50	12.00		6.25	1			0	0.00
618	SMYTH - VA	Distribution		138.00	36.20		30.00	1			0	0.00
619	SMYTH - VA	Distribution		138.00	34.50		25.00	1			0	0.00
620	SOLITE - VA	Distribution		69.00	12.00		5.25	1			0	0.00
621	SOPHIA - WV	Transmission		46.00	0.00	0.00	0.00			STATCAP	1	14.40
622	SOURWOOD - WV	Distribution		138.00	13.09		8.40	1			0	0.00
623	SOUTH BLUEFIELD - WV	Transmission		138.00	13.09		30.00	1			0	0.00
624	SOUTH BUFFALO - WV	Distribution		138.00	13.09		60.00	3			0	0.00
625	SOUTH BUFFALO - WV	Distribution		138.00	36.20		30.00	1			0	0.00
626	SOUTH CHARLESTON - WV	Distribution		46.00	12.00		22.40	1			0	0.00
627	SOUTH CHRISTIANSBURG - VA	Transmission		138.00	69.00	12.00	56.00	1			0	0.00
628	SOUTH CHRISTIANSBURG - VA	Transmission		138.00	13.09		20.00	1			0	0.00
629	SOUTH HILLS - WV	Distribution		46.00	12.00		22.40	1			0	0.00
630	SOUTH HILLS - WV	Distribution		46.00	13.09		25.00	1			0	0.00
631	SOUTH LYNCHBURG - VA	Transmission		138.00	13.09		40.00	2			0	0.00
632	SOUTH LYNCHBURG - VA	Transmission		138.00	70.50	36.20	78.00	1			0	0.00
633	SOUTH LYNCHBURG - VA	Transmission		138.00	69.00	34.50	50.00	1			0	0.00
634	SOUTH NEAL - WV	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	14.40
635	SOUTH NEAL - WV	Distribution		69.00	12.00		40.00	2			0	0.00
636	SOUTH PRINCETON - WV	Distribution		138.00	34.50		55.00	2			0	0.00
637	SOUTHRIDGE - WV	Distribution		138.00	13.09		20.00	1			0	0.00
638	SPEEDWAY - WV	Distribution		138.00	34.50		30.00	1			0	0.00
639	SPORN 138KV - WV	Transmission		138.00	13.09		20.00	1			0	0.00
640	SPORN 345KV - WV	Transmission		345.00	137.50	13.80	1350.00	3			0	0.00
641	SPRIGG - WV	Transmission		138.00	69.00	46.00	84.00	1			0	0.00
642	SPRIGG - WV	Transmission		46.00	0.00	0.00	0.00			STATCAP	1	9.60
643	SPRIGG - WV	Transmission		138.00	13.20	12.00	9.38	1			0	0.00
644	SPRIGG - WV	Transmission		138.00	34.50		25.00	1			0	0.00
645	SPRIGG - WV	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	72.00
646	SPRING CREEK - VA	Distribution		138.00	13.09		21.00	2			0	0.00
647	ST. ALBANS - WV	Distribution		138.00	13.09		50.00	2			0	0.00
648	STANLEYTOWN - VA	Distribution		69.00	12.00		22.40	1			0	0.00
649	STARKEY - VA	Distribution		138.00	13.09		40.00	2			0	0.00
650	STOCKTON - VA	Distribution		138.00	34.50		30.00	1			0	0.00
651	STONE BRANCH - WV	Distribution		138.00	34.50		25.00	1			0	0.00
652	STONE BRANCH - WV	Distribution		138.00	13.09		20.00	1			0	0.00
653	STOTESBURY - WV	Distribution		138.00	13.09		10.50	1			0	0.00
654	STUART - VA	Distribution		69.00	0.00	0.00	0.00			STATCAP	1	10.80
655	STUART - VA	Distribution		69.00	34.50		30.00	1			0	0.00
656	STUART - VA	Distribution		69.00	12.00		10.50	1			0	0.00
657	SUN MINE - WV	Distribution		46.00	12.00		20.00	1			0	0.00
658	SUNDIAL - WV	Transmission		138.00	69.00	46.00	90.00	1			0	0.00
659	SUNDIAL - WV	Transmission		46.00	0.00	0.00	0.00			STATCAP	1	9.60
660	SUNSCAPE - VA	Distribution		138.00	12.00		20.00	1			0	0.00
661	SWITCHBACK - WV	Transmission		138.00	34.50		25.00	1			0	0.00
662	SWITCHBACK - WV	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	50.40
663	TACKETT CREEK - WV	Distribution		138.00	13.09		25.00	1			0	0.00
664	TANK HILL - VA	Distribution		138.00	13.09		40.00	2			0	0.00
665	TAZEWELL - VA	Transmission		34.50	12.00		6.25	1			0	0.00
666	TAZEWELL - VA	Transmission		34.50	13.00		6.25	1			0	0.00
667	TAZEWELL - VA	Transmission		138.00	34.50		30.00	1			0	0.00
668	TAZEWELL - VA	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	28.80
669	TEAYS - WV	Distribution		69.00	12.00		22.40	1			0	0.00
670	TECH DRIVE - VA	Distribution		138.00	12.00		20.00	1			0	0.00
671	THOMAS (AP) - VA	Distribution		34.50	7.20		3.00	3			0	0.00
672	THORNTON - VA	Distribution		138.00	34.50	12.00	7.50	1			0	0.00
673	THORNTON - VA	Distribution		138.00	13.09		9.38	1			0	0.00
674	TOMS FORK - WV	Distribution		46.00	0.00	0.00	0.00			STATCAP	1	9.60
675	TOMS FORK - WV	Distribution		46.00	12.00		4.69	1			0	0.00
676	TONEY FORK - WV	Distribution		46.00	12.00		8.40	1			0	0.00
677	TOWER 117 - WV	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	13.19
678	TRAIL FORK - WV	Distribution		138.00	13.09		12.50	1			0	0.00
679	TRAMMEL - VA	Transmission		69.00	12.00		6.25	1			0	0.00
680	TRAP HILL - WV	Distribution		46.00	36.20		40.00	2			0	0.00
681	TRI-STATE - WV	Transmission		345.00	138.00	13.80		2			0	0.00
682	TRI-STATE - WV	Transmission		345.00	137.50	13.80	270.00	1			0	0.00
683	TULTEX - VA	Distribution		34.50	7.50		2.50	2			0	0.00
684	TULTEX - VA	Distribution		34.50	7.20		5.00	4			0	0.00
685	TURKEY PEN - VA	Distribution		69.00	12.00		10.50	1			0	0.00
686	TURNER - WV	Transmission		69.00	35.40	13.80	30.00	1			0	0.00
687	TURNER - WV	Transmission		138.00	70.50	46.00	54.00	0	1		0	0.00
688	TURNER - WV	Transmission		138.00	69.00	46.00	84.00	1			0	0.00
689	UNITED FUEL GAS COMPANY - WV	Distribution		69.00	4.00		6.25	1			0	0.00
690	UPPER BRANCH - WV	Distribution		46.00	7.20		2.01	3			0	0.00
691	URY - WV	Distribution		46.00	12.00		20.00	1			0	0.00
692	VAN - WV	Distribution		69.00	12.00		6.25	1			0	0.00
693	VETERANS HOSPITAL - VA	Distribution		34.50	4.00		10.00	2			0	0.00
694	VICKER - VA	Distribution		138.00	13.09		20.00	1			0	0.00
695	VINTON - VA	Distribution		138.00	34.50		30.00	1			0	0.00
696	VINTON - VA	Distribution		138.00	13.09		25.00	1			0	0.00
697	WALNUT AVENUE - VA	Distribution		69.00	12.00		22.40	1			0	0.00
698	WALTON PARK - VA	Distribution		69.00	2.40		2.00	1			0	0.00
699	WARD HOLLOW - WV	Transmission		46.00	0.00	0.00	0.00			STATCAP	1	32.40
700	WARD HOLLOW - WV	Transmission		46.00	13.80		40.00	2			0	0.00
701	WASENA - VA	Distribution		69.00	13.09		20.00	1			0	0.00
702	WASENA - VA	Distribution		69.00	12.00		20.00	1			0	0.00
703	WAYNE - WV	Distribution		34.50	13.09		10.50	1			0	0.00
704	WAYNE - WV	Distribution		34.50	12.00		5.00	1			0	0.00
705	WELCH - WV	Distribution		138.00	13.09		22.40	1			0	0.00
706	WEST BASSETT - VA	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	28.80
707	WEST BASSETT - VA	Transmission		138.00	69.00	34.50	128.00	1			0	0.00
708	WEST BASSETT - VA	Transmission		34.50	34.50		25.00	1			0	0.00
709	WEST HUNTINGTON - WV	Transmission		138.00	69.00	34.50	130.00	1			0	0.00
710	WEST HUNTINGTON - WV	Transmission		34.50	0.00	0.00	0.00			STATCAP	1	9.60
711	WEST HUNTINGTON - WV	Transmission		138.00	13.09		9.38	1			0	0.00
712	WEST HUNTINGTON - WV	Transmission		138.00	34.50		25.00	1			0	0.00
713	WESTLAKE - VA	Distribution		138.00	34.50		60.00	2			0	0.00
714	WHARNCLIFFE - WV	Transmission		46.00	0.00	0.00	0.00			STATCAP	1	9.60
715	WHEATLAND - VA	Distribution		69.00	12.00		20.00	1			0	0.00
716	WHETSTONE BRANCH - VA	Transmission		69.00	0.00	0.00	0.00			STATCAP	1	14.39
717	WHITESTICK - WV	Distribution		46.00	12.00		22.40	1			0	0.00
718	WITT - VA	Distribution		69.00	4.36		12.50	1			0	0.00
719	WOLF GLADE - VA	Transmission		138.00	70.50	13.09	78.00	1			0	0.00
720	WOOLWINE - VA	Distribution		69.00	34.50		25.00	1			0	0.00
721	WURNO - VA	Distribution		138.00	0.00	0.00	0.00			STATCAP	1	14.40
722	WURNO - VA (A)	Distribution		138.00	34.50		30.00	1			0	0.00
723	WURNO - VA (B)	Distribution		138.00	34.50		30.00	1			0	0.00
724	WYOMING - WV	Transmission		765.00	138.00	13.80	1250.00	5			0	0.00
725	WYOMING - WV	Transmission		765.00	138.00	12.00	250.00	1			0	0.00
726	WYTHE - VA	Transmission		138.00	34.00		25.00	1			0	0.00
727	WYTHE - VA	Transmission		138.00	0.00	0.00	0.00			STATCAP	1	50.40
728	WYTHE - VA	Transmission		138.00	34.50		35.00	1			0	0.00
729	TotalTransmissionSubstationMember											8,935
730	Total											8,935

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

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 1 Riverside PlazaColumbus, Ohio 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. State of Incorporation: VA Date of Incorporation: 1926-03-04 Incorporated Under Special Law:
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. (a) Name of Receiver or Trustee Holding Property of the Respondent: (b) Date Receiver took Possession of Respondent Property: (c) Authority by which the Receivership or Trusteeship was created: (d) Date when possession by receiver or trustee ceased:
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 VirginiaElectric - VirginiaElectric - 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 (2) ☑ No

OFFICERS
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. 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 No.	OfficerTitle Title (a)	OfficerName Name of Officer (b)	OfficerSalary Salary for Year (c)	DateOfficerIncumbencyStarted Date Started in Period (d)	DateOfficerIncumbencyEnded Date Ended in Period (e)
1	(a) Footnote

DIRECTORS
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), name and abbreviated titles of the directors who are officers of the respondent. Provide the principle place of business in column (b), designate members of the Executive Committee in column (c), and the Chairman of the Executive Committee in column (d).
Line No.	NameAndTitleOfDirector Name (and Title) of Director (a)	PrincipalBusinessAddress Principal Business Address (b)	MemberOfTheExecutiveCommittee Member of the Executive Committee (c)	ChairmanOfTheExecutiveCommittee Chairman of the Executive Committee (d)
1	Nicholas K. Akins, Chairman of the Board and Chief Executive Officer	Columbus, Ohio	false	false
2	Lisa M. Barton, Vice President	Columbus, Ohio	false	false
3	Christian T. Beam - President and Chief Operating Officer	Charleston, WV	false	false
4	Paul Chodak, Vice President	Columbus, Ohio	false	false
5	David M. Feinberg, Secretary	Columbus, Ohio	false	false
6	Charles R. Patton, Vice President	Columbus, Ohio	false	false
7	Therace M. Risch, Vice President	Columbus, Ohio	false	false
8	Julia A. Sloat, Vice President and Chief Financial Officer	Columbus, Ohio	false	false
9	Toby L. Thomas, Vice President	New Albany, Ohio	false	false
10	Note: The Respondent does not have an Executive Committee.

INFORMATION ON FORMULA RATES
Does the respondent have formula rates?		☑ Yes ☐ No
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.	RateScheduleTariffNumber FERC Rate Schedule or Tariff Number (a)	ProceedingDocketNumber FERC Proceeding (b)
1	PJM Interconnection LLC - Attachment H-14	ER17-405

FERC FINANCIAL REPORT
FERC FORM No. 1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report

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

GENERAL INFORMATION

Purpose

Who Must Submit

What and Where to Submit

When to Submit

Where to Send Comments on Public Reporting Burden.

GENERAL INSTRUCTIONS

EXCERPTS FROM THE LAW

GENERAL PENALTIES




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

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 No.	Title of Schedule (a)	Reference Page No. (b)	Remarks (c)
	ScheduleIdentificationAbstract Identification	1
	ScheduleListOfSchedulesAbstract List of Schedules	2
1	ScheduleGeneralInformationAbstract General Information	101
2	ScheduleControlOverRespondentAbstract Control Over Respondent	102
3	ScheduleCorporationsControlledByRespondentAbstract Corporations Controlled by Respondent	103
4	ScheduleOfficersAbstract Officers	104
5	ScheduleDirectorsAbstract Directors	105
6	ScheduleInformationOnFormulaRatesAbstract Information on Formula Rates	106
7	ScheduleImportantChangesDuringTheQuarterYearAbstract Important Changes During the Year	108
8	ScheduleComparativeBalanceSheetAbstract Comparative Balance Sheet	110
9	ScheduleStatementOfIncomeAbstract Statement of Income for the Year	114
10	ScheduleRetainedEarningsAbstract Statement of Retained Earnings for the Year	118
12	ScheduleStatementOfCashFlowsAbstract Statement of Cash Flows	120
12	ScheduleNotesToFinancialStatementsAbstract Notes to Financial Statements	122
13	ScheduleStatementOfAccumulatedOtherComprehensiveIncomeAndHedgingActivitiesAbstract Statement of Accum Other Comp Income, Comp Income, and Hedging Activities	122a
14	ScheduleSummaryOfUtilityPlantAndAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep	200
15	ScheduleNuclearFuelMaterialsAbstract Nuclear Fuel Materials	202
16	ScheduleElectricPlantInServiceAbstract Electric Plant in Service	204
17	ScheduleElectricPropertyLeasedToOthersAbstract Electric Plant Leased to Others	213
18	ScheduleElectricPlantHeldForFutureUseAbstract Electric Plant Held for Future Use	214
19	ScheduleConstructionWorkInProgressElectricAbstract Construction Work in Progress-Electric	216
20	ScheduleAccumulatedProvisionForDepreciationOfElectricUtilityPlantAbstract Accumulated Provision for Depreciation of Electric Utility Plant	219
21	ScheduleInvestmentsInSubsidiaryCompaniesAbstract Investment of Subsidiary Companies	224
22	ScheduleMaterialsAndSuppliesAbstract Materials and Supplies	227
23	ScheduleAllowanceInventoryAbstract Allowances	228
24	ScheduleExtraordinaryPropertyLossesAbstract Extraordinary Property Losses	230a
25	ScheduleUnrecoveredPlantAndRegulatoryStudyCostsAbstract Unrecovered Plant and Regulatory Study Costs	230b
26	ScheduleTransmissionServiceAndGenerationInterconnectionStudyCostsAbstract Transmission Service and Generation Interconnection Study Costs	231
27	ScheduleOtherRegulatoryAssetsAbstract Other Regulatory Assets	232
28	ScheduleMiscellaneousDeferredDebitsAbstract Miscellaneous Deferred Debits	233
29	ScheduleAccumulatedDeferredIncomeTaxesAbstract Accumulated Deferred Income Taxes	234
30	ScheduleCapitalStockAbstract Capital Stock	250
31	ScheduleOtherPaidInCapitalAbstract Other Paid-in Capital	253
32	ScheduleCapitalStockExpenseAbstract Capital Stock Expense	254b
33	ScheduleLongTermDebtAbstract Long-Term Debt	256
34	ScheduleReconciliationOfReportedNetIncomeWithTaxableIncomeForFederalIncomeTaxesAbstract Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax	261
35	ScheduleTaxesAccruedPrepaidAndChargedDuringYearDistributionOfTaxesChargedAbstract Taxes Accrued, Prepaid and Charged During the Year	262
36	ScheduleAccumulatedDeferredInvestmentTaxCreditsAbstract Accumulated Deferred Investment Tax Credits	266
37	ScheduleOtherDeferredCreditsAbstract Other Deferred Credits	269
38	ScheduleAccumulatedDeferredIncomeTaxesAcceleratedAmortizationPropertyAbstract Accumulated Deferred Income Taxes-Accelerated Amortization Property	272
39	ScheduleAccumulatedDeferredIncomeTaxesOtherPropertyAbstract Accumulated Deferred Income Taxes-Other Property	274
40	ScheduleAccumulatedDeferredIncomeTaxesOtherAbstract Accumulated Deferred Income Taxes-Other	276
41	ScheduleOtherRegulatoryLiabilitiesAbstract Other Regulatory Liabilities	278
42	ScheduleElectricOperatingRevenuesAbstract Electric Operating Revenues	300
43	ScheduleRegionalTransmissionServiceRevenuesAbstract Regional Transmission Service Revenues (Account 457.1)	302
44	ScheduleSalesOfElectricityByRateSchedulesAbstract Sales of Electricity by Rate Schedules	304
45	ScheduleSalesForResaleAbstract Sales for Resale	310
46	ScheduleElectricOperationsAndMaintenanceExpensesAbstract Electric Operation and Maintenance Expenses	320
47	SchedulePurchasedPowerAbstract Purchased Power	326
48	ScheduleTransmissionOfElectricityForOthersAbstract Transmission of Electricity for Others	328
49	ScheduleTransmissionOfElectricityByIsoOrRtoAbstract Transmission of Electricity by ISO/RTOs	331
50	ScheduleTransmissionOfElectricityByOthersAbstract Transmission of Electricity by Others	332
51	ScheduleMiscellaneousGeneralExpensesAbstract Miscellaneous General Expenses-Electric	335
52	ScheduleDepreciationDepletionAndAmortizationAbstract Depreciation and Amortization of Electric Plant (Account 403, 404, 405)	336
53	ScheduleRegulatoryCommissionExpensesAbstract Regulatory Commission Expenses	350
54	ScheduleResearchDevelopmentOrDemonstrationExpendituresAbstract Research, Development and Demonstration Activities	352
55	ScheduleDistributionOfSalariesAndWagesAbstract Distribution of Salaries and Wages	354
56	ScheduleCommonUtilityPlantAndExpensesAbstract Common Utility Plant and Expenses	356
57	ScheduleAmountsIncludedInIsoOrRtoSettlementAbstract Amounts included in ISO/RTO Settlement Statements	397
58	SchedulePurchasesSalesOfAncillaryServicesAbstract Purchase and Sale of Ancillary Services	398
59	ScheduleMonthlyTransmissionSystemPeakLoadAbstract Monthly Transmission System Peak Load	400
60	ScheduleMonthlyIsoOrRtoTransmissionSystemPeakLoadAbstract Monthly ISO/RTO Transmission System Peak Load	400a
61	ScheduleElectricEnergyAccountAbstract Electric Energy Account	401a
62	ScheduleMonthlyPeakAndOutputAbstract Monthly Peaks and Output	401b
63	ScheduleSteamElectricGeneratingPlantStatisticsAbstract Steam Electric Generating Plant Statistics	402
64	ScheduleHydroelectricGeneratingPlantStatisticsAbstract Hydroelectric Generating Plant Statistics	406
65	SchedulePumpedStorageGeneratingPlantStatisticsAbstract Pumped Storage Generating Plant Statistics	408
66	ScheduleGeneratingPlantStatisticsAbstract Generating Plant Statistics Pages	410
0	ScheduleEnergyStorageOperationsLargePlantsAbstract Energy Storage Operations (Large Plants)	414
67	ScheduleTransmissionLineStatisticsAbstract Transmission Line Statistics Pages	422
68	ScheduleTransmissionLinesAddedAbstract Transmission Lines Added During Year	424
69	ScheduleSubstationsAbstract Substations	426
70	ScheduleTransactionsWithAssociatedAffiliatedCompaniesAbstract Transactions with Associated (Affiliated) Companies	429
71	FootnoteDataAbstract Footnote Data	450
	StockholdersReportsAbstract Stockholders' Reports (check appropriate box)
	Stockholders' Reports Check appropriate box: ☐ Two copies will be submitted ☐ No annual report to stockholders is prepared

CONTROL OVER RESPONDENT
1. If any corporation, business trust, or similar organization or a combination of such organizations jointly held control over the respondent 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 beneficiaries for whom trust was maintained, and purpose of the trust.

American Electric Power Company, Inc. - Ownership of 100% of the Common Stock.

CORPORATIONS CONTROLLED BY RESPONDENT
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. 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. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests. Definitions See the Uniform System of Accounts for a definition of control. Direct control is that which is exercised without interposition of an intermediary. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of control in the Uniform System of Accounts, regardless of the relative voting rights of each party.
Line No.	NameOfCompanyControlledByRespondent Name of Company Controlled (a)	CompanyControlledByRespondentKindOfBusinessDescription Kind of Business (b)	VotingStockOwnedByRespondentPercentage Percent Voting Stock Owned (c)	FootnoteReferences Footnote Ref. (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	(a) Footnote
4	Southern Appalachian Coal Company	Coal Mining - Inactive	100

INFORMATION ON FORMULA RATES - FERC Rate Schedule/Tariff Number FERC Proceeding
Does the respondent file with the Commission annual (or more frequent) filings containing the inputs to the formula rate(s)?			☑ Yes ☐ No
If yes, provide a listing of such filings as contained on the Commission's eLibrary website.
Line No.	AccessionNumber Accession No. (a)	DocumentDate Document Date / Filed Date (b)	DocketNumber Docket No. (c)	DescriptionOfFiling Description (d)	RateScheduleTariffNumber Formula Rate FERC Rate Schedule Number or Tariff Number (e)
1	20211221-5274	12/21/2021	ER17-405	AEP PJM OATT Proj Transmission	PJM OATT Attachment H-14
2	20211101-5315	11/01/2021	ER17-405	AEP PJM OATT Proj Transmission	PJM OATT Attachment H-14
3	20210525-5243	05/25/2021	ER17-405	AEP PJM OATT Proj Transmission	PJM OATT Attachment H-14

INFORMATION ON FORMULA RATES - Formula Rate Variances
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. 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. 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. Where the Commission has provided guidance on formula rate inputs, the specific proceeding should be noted in the footnote.
Line No.	PageNumberOfFormulaRateVariances Page No(s). (a)	ScheduleOfFormulaRateVariances Schedule (b)	ColumnOfFormulaRateVariances Column (c)	LineNumberOfFormulaRateVariances Line No. (d)
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

COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line No.	Title of Account (a)	Ref. Page No. (b)	Current Year End of Quarter/Year Balance (c)	Prior Year End Balance 12/31 (d)
1	UtilityPlantAbstract UTILITY PLANT
2	UtilityPlant Utility Plant (101-106, 114)	200	16,401,181,030	15,655,993,813
3	ConstructionWorkInProgress Construction Work in Progress (107)	200	471,403,315	485,037,217
4	UtilityPlantAndConstructionWorkInProgress TOTAL Utility Plant (Enter Total of lines 2 and 3)		16,872,584,345	16,141,031,030
5	AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115)	200	5,765,578,075	5,412,843,611
6	UtilityPlantNet Net Utility Plant (Enter Total of line 4 less 5)		11,107,006,270	10,728,187,419
7	NuclearFuelInProcessOfRefinementConversionEnrichmentAndFabrication Nuclear Fuel in Process of Ref., Conv., Enrich., and Fab. (120.1)	202
8	NuclearFuelMaterialsAndAssembliesStockAccountMajorOnly Nuclear Fuel Materials and Assemblies-Stock Account (120.2)
9	NuclearFuelAssembliesInReactorMajorOnly Nuclear Fuel Assemblies in Reactor (120.3)
10	SpentNuclearFuelMajorOnly Spent Nuclear Fuel (120.4)
11	NuclearFuelUnderCapitalLeases Nuclear Fuel Under Capital Leases (120.6)
12	AccumulatedProvisionForAmortizationOfNuclearFuelAssemblies (Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5)	202
13	NuclearFuelNet Net Nuclear Fuel (Enter Total of lines 7-11 less 12)
14	UtilityPlantAndNuclearFuelNet Net Utility Plant (Enter Total of lines 6 and 13)		11,107,006,270	10,728,187,419
15	OtherElectricPlantAdjustments Utility Plant Adjustments (116)
16	GasStoredUndergroundNoncurrent Gas Stored Underground - Noncurrent (117)
17	OtherPropertyAndInvestmentsAbstract OTHER PROPERTY AND INVESTMENTS
18	NonutilityProperty Nonutility Property (121)		13,295,371	13,295,545
19	AccumulatedProvisionForDepreciationAndAmortizationOfNonutilityProperty (Less) Accum. Prov. for Depr. and Amort. (122)		5,192,401	5,198,888
20	InvestmentInAssociatedCompanies Investments in Associated Companies (123)
21	InvestmentInSubsidiaryCompanies Investment in Subsidiary Companies (123.1)	224	4,641,308	5,257,849
23	NoncurrentPortionOfAllowances Noncurrent Portion of Allowances	228	22,004,289	22,044,921
24	OtherInvestments Other Investments (124)		205,198,349	232,115,959
25	SinkingFunds Sinking Funds (125)
26	DepreciationFund Depreciation Fund (126)
27	AmortizationFundFederal Amortization Fund - Federal (127)
28	OtherSpecialFunds Other Special Funds (128)
29	SpecialFunds Special Funds (Non Major Only) (129)		216,680,819	146,605,010
30	DerivativeInstrumentAssetsLongTerm Long-Term Portion of Derivative Assets (175)			123,974
31	DerivativeInstrumentAssetsHedgesLongTerm Long-Term Portion of Derivative Assets - Hedges (176)
32	OtherPropertyAndInvestments TOTAL Other Property and Investments (Lines 18-21 and 23-31)		456,627,735	414,244,369
33	CurrentAndAccruedAssetsAbstract CURRENT AND ACCRUED ASSETS
34	CashAndWorkingFunds Cash and Working Funds (Non-major Only) (130)
35	Cash Cash (131)		2,496,136	5,766,797
36	SpecialDeposits Special Deposits (132-134)		89,614,237	18,832,104
37	WorkingFunds Working Fund (135)
38	TemporaryCashInvestments Temporary Cash Investments (136)
39	NotesReceivable Notes Receivable (141)
40	CustomerAccountsReceivable Customer Accounts Receivable (142)		166,951,944	154,423,761
41	OtherAccountsReceivable Other Accounts Receivable (143)		162,884	295,970
42	AccumulatedProvisionForUncollectibleAccountsCredit (Less) Accum. Prov. for Uncollectible Acct.-Credit (144)		1,629,934	3,060,608
43	NotesReceivableFromAssociatedCompanies Notes Receivable from Associated Companies (145)
44	AccountsReceivableFromAssociatedCompanies Accounts Receivable from Assoc. Companies (146)		127,358,814	61,647,732
45	FuelStock Fuel Stock (151)	227	61,380,905	182,954,925
46	FuelStockExpensesUndistributed Fuel Stock Expenses Undistributed (152)	227	5,704,904	10,651,652
47	Residuals Residuals (Elec) and Extracted Products (153)	227	6,791	4,821
48	PlantMaterialsAndOperatingSupplies Plant Materials and Operating Supplies (154)	227	109,053,857	99,205,804
49	Merchandise Merchandise (155)	227
50	OtherMaterialsAndSupplies Other Materials and Supplies (156)	227
51	NuclearMaterialsHeldForSale Nuclear Materials Held for Sale (157)	202/227
52	AllowanceInventoryAndWithheld Allowances (158.1 and 158.2)	228	22,794,207	22,422,049
53	NoncurrentPortionOfAllowances (Less) Noncurrent Portion of Allowances	228	22,004,289	22,044,921
54	StoresExpenseUndistributed Stores Expense Undistributed (163)	227
55	GasStoredCurrent Gas Stored Underground - Current (164.1)
56	LiquefiedNaturalGasStoredAndHeldForProcessing Liquefied Natural Gas Stored and Held for Processing (164.2-164.3)
57	Prepayments Prepayments (165)		7,799,236	6,969,431
58	AdvancesForGas Advances for Gas (166-167)
59	InterestAndDividendsReceivable Interest and Dividends Receivable (171)		365	291
60	RentsReceivable Rents Receivable (172)		1,277,779	1,345,780
61	AccruedUtilityRevenues Accrued Utility Revenues (173)		54,013,000	80,063,530
62	MiscellaneousCurrentAndAccruedAssets Miscellaneous Current and Accrued Assets (174)
63	DerivativeInstrumentAssets Derivative Instrument Assets (175)		41,975,558	20,103,677
64	DerivativeInstrumentAssetsLongTerm (Less) Long-Term Portion of Derivative Instrument Assets (175)			123,974
65	DerivativeInstrumentAssetsHedges Derivative Instrument Assets - Hedges (176)			2,386,411
66	DerivativeInstrumentAssetsHedgesLongTerm (Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176)
67	CurrentAndAccruedAssets Total Current and Accrued Assets (Lines 34 through 66)		666,956,394	641,845,232
68	DeferredDebitsAbstract DEFERRED DEBITS
69	UnamortizedDebtExpense Unamortized Debt Expenses (181)		28,847,639	27,812,762
70	ExtraordinaryPropertyLosses Extraordinary Property Losses (182.1)	230a	79,082,399	82,485,469
71	UnrecoveredPlantAndRegulatoryStudyCosts Unrecovered Plant and Regulatory Study Costs (182.2)	230b
72	OtherRegulatoryAssets Other Regulatory Assets (182.3)	232	1,129,473,642	883,585,010
73	PreliminarySurveyAndInvestigationCharges Prelim. Survey and Investigation Charges (Electric) (183)		5,487,298	1,597,802
74	PreliminaryNaturalGasSurveyAndInvestigationChargesAndOtherPreliminarySurveyAndInvestigationCharges Preliminary Natural Gas Survey and Investigation Charges 183.1)
75	OtherPreliminarySurveyAndInvestigationCharges Other Preliminary Survey and Investigation Charges (183.2)
76	ClearingAccounts Clearing Accounts (184)		144,576	28,199
77	TemporaryFacilities Temporary Facilities (185)
78	MiscellaneousDeferredDebits Miscellaneous Deferred Debits (186)	233	92,952,422	84,954,431
79	DeferredLossesFromDispositionOfUtilityPlant Def. Losses from Disposition of Utility Plt. (187)
80	ResearchDevelopmentAndDemonstrationExpenditures Research, Devel. and Demonstration Expend. (188)	352
81	UnamortizedLossOnReacquiredDebt Unamortized Loss on Reaquired Debt (189)		78,193,342	82,060,027
82	AccumulatedDeferredIncomeTaxes Accumulated Deferred Income Taxes (190)	234	488,763,374	494,843,653
83	UnrecoveredPurchasedGasCosts Unrecovered Purchased Gas Costs (191)
84	DeferredDebits Total Deferred Debits (lines 69 through 83)		1,902,944,692	1,657,367,353
85	AssetsAndOtherDebits TOTAL ASSETS (lines 14-16, 32, 67, and 84)		14,133,535,091	13,441,644,373

COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line No.	Title of Account (a)	Ref. Page No. (b)	Current Year End of Quarter/Year Balance (c)	Prior Year End Balance 12/31 (d)
1	ProprietaryCapitalAbstract PROPRIETARY CAPITAL
2	CommonStockIssued Common Stock Issued (201)	250	260,457,768	260,457,768
3	PreferredStockIssued Preferred Stock Issued (204)	250
4	CapitalStockSubscribed Capital Stock Subscribed (202, 205)
5	StockLiabilityForConversion Stock Liability for Conversion (203, 206)
6	PremiumOnCapitalStock Premium on Capital Stock (207)
7	OtherPaidInCapital Other Paid-In Capital (208-211)	253	1,828,626,950	1,828,626,950
8	InstallmentsReceivedOnCapitalStock Installments Received on Capital Stock (212)	252
9	DiscountOnCapitalStock (Less) Discount on Capital Stock (213)	254
10	CapitalStockExpense (Less) Capital Stock Expense (214)	254b
11	RetainedEarnings Retained Earnings (215, 215.1, 216)	118	2,538,035,582	2,251,598,527
12	UnappropriatedUndistributedSubsidiaryEarnings Unappropriated Undistributed Subsidiary Earnings (216.1)	118	3,463,213	3,463,213
13	ReacquiredCapitalStock (Less) Reaquired Capital Stock (217)	250
14	NoncorporateProprietorship Noncorporate Proprietorship (Non-major only) (218)
15	AccumulatedOtherComprehensiveIncome Accumulated Other Comprehensive Income (219)	122(a)(b)	24,379,199	7,921,383
16	ProprietaryCapital Total Proprietary Capital (lines 2 through 15)		4,648,036,287	4,345,141,416
17	LongTermDebtAbstract LONG-TERM DEBT
18	Bonds Bonds (221)	256	200,079,231	225,471,913
19	ReacquiredBonds (Less) Reaquired Bonds (222)	256
20	AdvancesFromAssociatedCompanies Advances from Associated Companies (223)	256
21	OtherLongTermDebt Other Long-Term Debt (224)	256	4,782,910,721	4,650,495,969
22	UnamortizedPremiumOnLongTermDebt Unamortized Premium on Long-Term Debt (225)
23	UnamortizedDiscountOnLongTermDebtDebit (Less) Unamortized Discount on Long-Term Debt-Debit (226)		15,252,087	14,079,660
24	LongTermDebt Total Long-Term Debt (lines 18 through 23)		4,967,737,864	4,861,888,222
25	OtherNoncurrentLiabilitiesAbstract OTHER NONCURRENT LIABILITIES
26	ObligationsUnderCapitalLeaseNoncurrent Obligations Under Capital Leases - Noncurrent (227)		80,452,977	98,735,304
27	AccumulatedProvisionForPropertyInsurance Accumulated Provision for Property Insurance (228.1)
28	AccumulatedProvisionForInjuriesAndDamages Accumulated Provision for Injuries and Damages (228.2)		5,159,571	6,321,471
29	AccumulatedProvisionForPensionsAndBenefits Accumulated Provision for Pensions and Benefits (228.3)		10,921,258	10,293,071
30	AccumulatedMiscellaneousOperatingProvisions Accumulated Miscellaneous Operating Provisions (228.4)
31	AccumulatedProvisionForRateRefunds Accumulated Provision for Rate Refunds (229)			584,830
32	LongTermPortionOfDerivativeInstrumentLiabilities Long-Term Portion of Derivative Instrument Liabilities		2,137	100,332
33	LongTermPortionOfDerivativeInstrumentLiabilitiesHedges Long-Term Portion of Derivative Instrument Liabilities - Hedges
34	AssetRetirementObligations Asset Retirement Obligations (230)		404,622,571	313,144,616
35	OtherNoncurrentLiabilities Total Other Noncurrent Liabilities (lines 26 through 34)		501,158,515	429,179,625
36	CurrentAndAccruedLiabilitiesAbstract CURRENT AND ACCRUED LIABILITIES
37	NotesPayable Notes Payable (231)
38	AccountsPayable Accounts Payable (232)		262,186,705	211,962,187
39	NotesPayableToAssociatedCompanies Notes Payable to Associated Companies (233)		199,282,967	18,639,896
40	AccountsPayableToAssociatedCompanies Accounts Payable to Associated Companies (234)		118,534,546	97,012,806
41	CustomerDeposits Customer Deposits (235)		73,923,266	77,819,096
42	TaxesAccrued Taxes Accrued (236)	262	81,703,750	100,698,572
43	InterestAccrued Interest Accrued (237)		47,869,294	49,916,651
44	DividendsDeclared Dividends Declared (238)
45	MaturedLongTermDebt Matured Long-Term Debt (239)
46	MaturedInterest Matured Interest (240)
47	TaxCollectionsPayable Tax Collections Payable (241)		4,696,419	4,508,999
48	MiscellaneousCurrentAndAccruedLiabilities Miscellaneous Current and Accrued Liabilities (242)		51,649,564	76,064,233
49	ObligationsUnderCapitalLeasesCurrent Obligations Under Capital Leases-Current (243)		22,748,700	22,269,913
50	DerivativesInstrumentLiabilities Derivative Instrument Liabilities (244)		819,652	1,244,910
51	LongTermPortionOfDerivativeInstrumentLiabilities (Less) Long-Term Portion of Derivative Instrument Liabilities		2,137	100,332
52	DerivativeInstrumentLiabilitiesHedges Derivative Instrument Liabilities - Hedges (245)			3,449,077
53	LongTermPortionOfDerivativeInstrumentLiabilitiesHedges (Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges
54	CurrentAndAccruedLiabilities Total Current and Accrued Liabilities (lines 37 through 53)		863,412,725	663,486,007
55	DeferredCreditsAbstract DEFERRED CREDITS
56	CustomerAdvancesForConstruction Customer Advances for Construction (252)
57	AccumulatedDeferredInvestmentTaxCredits Accumulated Deferred Investment Tax Credits (255)	266	306,934	318,791
58	DeferredGainsFromDispositionOfUtilityPlant Deferred Gains from Disposition of Utility Plant (256)
59	OtherDeferredCredits Other Deferred Credits (253)	269	32,700,650	34,315,356
60	OtherRegulatoryLiabilities Other Regulatory Liabilities (254)	278	821,478,629	857,824,376
61	UnamortizedGainOnReacquiredDebt Unamortized Gain on Reaquired Debt (257)
62	AccumulatedDeferredIncomeTaxesAcceleratedAmortizationProperty Accum. Deferred Income Taxes-Accel. Amort.(281)	272	143,723,636	152,137,429
63	AccumulatedDeferredIncomeTaxesOtherProperty Accum. Deferred Income Taxes-Other Property (282)		1,507,749,250	1,406,964,317
64	AccumulatedDeferredIncomeTaxesOther Accum. Deferred Income Taxes-Other (283)		647,230,599	690,388,834
65	DeferredCredits Total Deferred Credits (lines 56 through 64)		3,153,189,698	3,141,949,103
66	LiabilitiesAndOtherCredits TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)		14,133,535,089	13,441,644,373

STATEMENT OF INCOME
Quarterly 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. 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. 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. 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. If additional columns are needed, place them in a footnote. Annual or Quarterly if applicable Do not report fourth quarter data in columns (e) and (f) Report amounts for accounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility column in 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. Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above. Use page 122 for important notes regarding the statement of income for any account thereof. 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. 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 purchases, and a summary of the adjustments made to balance sheet, income, and expense accounts. If any notes appearing in the report to stockholders are applicable to the Statement of Income, such notes may be included at page 122. 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. Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports. If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to this schedule.
Line No.	Title of Account (a)	(Ref.) Page No. (b)	Total Current Year to Date Balance for Quarter/Year (c)	Total Prior Year to Date Balance for Quarter/Year (d)	Current 3 Months Ended - Quarterly Only - No 4th Quarter (e)	Prior 3 Months Ended - Quarterly Only - No 4th Quarter (f)	Electric Utility Current Year to Date (in dollars) (g)	Electric Utility Previous Year to Date (in dollars) (h)	Gas Utiity Current Year to Date (in dollars) (i)	Gas Utility Previous Year to Date (in dollars) (j)	Other Utility Current Year to Date (in dollars) (k)	Other Utility Previous Year to Date (in dollars) (l)
1	UtilityOperatingIncomeAbstract UTILITY OPERATING INCOME
2	OperatingRevenues Operating Revenues (400)	300	3,141,973,453	2,857,247,281			3,141,973,453	2,857,247,281
3	OperatingExpensesAbstract Operating Expenses
4	OperationExpense Operation Expenses (401)	320	1,594,399,774	1,379,799,825			1,594,399,774	1,379,799,825
5	MaintenanceExpense Maintenance Expenses (402)	320	265,523,828	226,820,833			265,523,828	226,820,833
6	DepreciationExpense Depreciation Expense (403)	336	497,621,638	511,822,169			497,621,638	511,822,169
7	DepreciationExpenseForAssetRetirementCosts Depreciation Expense for Asset Retirement Costs (403.1)	336	3,452,247	2,978,914			3,452,247	2,978,914
8	AmortizationAndDepletionOfUtilityPlant Amort. & Depl. of Utility Plant (404-405)	336	41,256,314	34,704,003			41,256,314	34,704,003
9	AmortizationOfElectricPlantAcquisitionAdjustments Amort. of Utility Plant Acq. Adj. (406)	336
10	AmortizationOfPropertyLossesUnrecoveredPlantAndRegulatoryStudyCosts Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)		4,094,894	4,094,894			4,094,894	4,094,894
11	AmortizationOfConversionExpenses Amort. of Conversion Expenses (407.2)
12	RegulatoryDebits Regulatory Debits (407.3)		8,179,991	4,190,246			8,179,991	4,190,246
13	RegulatoryCredits (Less) Regulatory Credits (407.4)		524,237	48,957,692			524,237	48,957,692
14	TaxesOtherThanIncomeTaxesUtilityOperatingIncome Taxes Other Than Income Taxes (408.1)	262	148,738,854	149,716,603			148,738,854	149,716,603
15	IncomeTaxesOperatingIncome Income Taxes - Federal (409.1)	262	9,367,566	27,790,428			9,367,566	27,790,428
16	IncomeTaxesUtilityOperatingIncomeOther Income Taxes - Other (409.1)	262	2,592,072	8,378,083			2,592,072	8,378,083
17	ProvisionsForDeferredIncomeTaxesUtilityOperatingIncome Provision for Deferred Income Taxes (410.1)	234, 272	449,012,755	1,193,050,491			449,012,755	1,193,050,491
18	ProvisionForDeferredIncomeTaxesCreditOperatingIncome (Less) Provision for Deferred Income Taxes-Cr. (411.1)	234, 272	431,854,357	1,222,271,015			431,854,357	1,222,271,015
19	InvestmentTaxCreditAdjustments Investment Tax Credit Adj. - Net (411.4)	266	9,420	170,592			9,420	170,592
20	GainsFromDispositionOfPlant (Less) Gains from Disp. of Utility Plant (411.6)		531,291	486,254			531,291	486,254
21	LossesFromDispositionOfServiceCompanyPlant Losses from Disp. of Utility Plant (411.7)		6,086	24,345			6,086	24,345
22	GainsFromDispositionOfAllowances (Less) Gains from Disposition of Allowances (411.8)		59	102,181			59	102,181
23	LossesFromDispositionOfAllowances Losses from Disposition of Allowances (411.9)
24	AccretionExpense Accretion Expense (411.10)		1,381,730	8,917,931			1,381,730	8,917,931
25	UtilityOperatingExpenses TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)		2,592,708,386	2,280,301,030			2,592,708,386	2,280,301,031
27	NetUtilityOperatingIncome Net Util Oper Inc (Enter Tot line 2 less 25)		549,265,067	576,946,250			549,265,067	576,946,250
28	OtherIncomeAndDeductionsAbstract Other Income and Deductions
29	OtherIncomeAbstract Other Income
30	NonutilityOperatingIncomeAbstract Nonutilty Operating Income
31	RevenuesFromMerchandisingJobbingAndContractWork Revenues From Merchandising, Jobbing and Contract Work (415)
32	CostsAndExpensesOfMerchandisingJobbingAndContractWork (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)
33	RevenuesFromNonutilityOperations Revenues From Nonutility Operations (417)
34	ExpensesOfNonutilityOperations (Less) Expenses of Nonutility Operations (417.1)		684	990
35	NonoperatingRentalIncome Nonoperating Rental Income (418)		21,806	15,157
36	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings of Subsidiary Companies (418.1)	119
37	InterestAndDividendIncome Interest and Dividend Income (419)		898,177	1,345,705
38	AllowanceForOtherFundsUsedDuringConstruction Allowance for Other Funds Used During Construction (419.1)		15,567,699	14,619,304
39	MiscellaneousNonoperatingIncome Miscellaneous Nonoperating Income (421)		637,741	97,249
40	GainOnDispositionOfProperty Gain on Disposition of Property (421.1)		59,242	240,546
41	OtherIncome TOTAL Other Income (Enter Total of lines 31 thru 40)		17,183,980	16,286,657
42	OtherIncomeDeductionsAbstract Other Income Deductions
43	LossOnDispositionOfProperty Loss on Disposition of Property (421.2)		417,560	401,163
44	MiscellaneousAmortization Miscellaneous Amortization (425)
45	Donations Donations (426.1)		1,708,560	1,241,165
46	LifeInsurance Life Insurance (426.2)
47	Penalties Penalties (426.3)		212,059	698,326
48	ExpendituresForCertainCivicPoliticalAndRelatedActivities Exp. for Certain Civic, Political & Related Activities (426.4)		1,680,552	1,424,584
49	OtherDeductions Other Deductions (426.5)		6,758,655	6,111,130
50	OtherIncomeDeductions TOTAL Other Income Deductions (Total of lines 43 thru 49)		10,353,267	8,479,716
51	TaxesApplicableToOtherIncomeAndDeductionsAbstract Taxes Applic. to Other Income and Deductions
52	TaxesOtherThanIncomeTaxesOtherIncomeAndDeductions Taxes Other Than Income Taxes (408.2)	262	314,263	320,687
53	IncomeTaxesFederal Income Taxes-Federal (409.2)	262	4,423,826	6,077,354
54	IncomeTaxesOther Income Taxes-Other (409.2)	262	430,325	892,790
55	ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions Provision for Deferred Inc. Taxes (410.2)	234, 272	2,317,737	4,218,526
56	ProvisionForDeferredIncomeTaxesCreditOtherIncomeAndDeductions (Less) Provision for Deferred Income Taxes-Cr. (411.2)	234, 272	4,004,143	1,435,083
57	InvestmentTaxCreditAdjustmentsNonutilityOperations Investment Tax Credit Adj.-Net (411.5)		2,437	12,984
58	InvestmentTaxCredits (Less) Investment Tax Credits (420)
59	TaxesOnOtherIncomeAndDeductions TOTAL Taxes on Other Income and Deductions (Total of lines 52-58)		6,228,731	2,093,417
60	NetOtherIncomeAndDeductions Net Other Income and Deductions (Total of lines 41, 50, 59)		13,059,443	9,900,358
61	InterestChargesAbstract Interest Charges
62	InterestOnLongTermDebt Interest on Long-Term Debt (427)		211,947,638	211,822,330
63	AmortizationOfDebtDiscountAndExpense Amort. of Debt Disc. and Expense (428)		4,116,805	3,761,971
64	AmortizationOfLossOnReacquiredDebt Amortization of Loss on Reaquired Debt (428.1)		3,866,685	3,800,583
65	AmortizationOfPremiumOnDebtCredit (Less) Amort. of Premium on Debt-Credit (429)
66	AmortizationOfGainOnReacquiredDebtCredit (Less) Amortization of Gain on Reaquired Debt-Credit (429.1)
67	InterestOnDebtToAssociatedCompanies Interest on Debt to Assoc. Companies (430)		137,743	2,818,980
68	OtherInterestExpense Other Interest Expense (431)		854,617	2,826,301
69	AllowanceForBorrowedFundsUsedDuringConstructionCredit (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)		7,536,033	7,916,223
70	NetInterestCharges Net Interest Charges (Total of lines 62 thru 69)		213,387,455	217,113,942
71	IncomeBeforeExtraordinaryItems Income Before Extraordinary Items (Total of lines 27, 60 and 70)		348,937,055	369,732,667
72	ExtraordinaryItemsAbstract Extraordinary Items
73	ExtraordinaryIncome Extraordinary Income (434)
74	ExtraordinaryDeductions (Less) Extraordinary Deductions (435)
75	NetExtraordinaryItems Net Extraordinary Items (Total of line 73 less line 74)
76	IncomeTaxesExtraordinaryItems Income Taxes-Federal and Other (409.3)	262
77	ExtraordinaryItemsAfterTaxes Extraordinary Items After Taxes (line 75 less line 76)
78	NetIncomeLoss Net Income (Total of line 71 and 77)		348,937,055	369,732,667

STATEMENT OF RETAINED EARNINGS
Do not report Lines 49-53 on the quarterly report. Report all changes in appropriated retained earnings, unappropriated retained earnings, and unappropriated undistributed subsidiary earnings for the year. 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). State the purpose and amount for each reservation or appropriation of retained earnings. 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. Show dividends for each class and series of capital stock. Show separately the State and Federal income tax effect of items shown for Account 439, Adjustments to Retained Earnings. 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. If any notes appearing in the report to stockholders are applicable to this statement, attach them at page 122.
Line No.	Item (a)	Contra Primary Account Affected (b)	Current Quarter/Year Year to Date Balance (c)	Previous Quarter/Year Year to Date Balance (d)
	UnappropriatedRetainedEarningsAbstract UNAPPROPRIATED RETAINED EARNINGS (Account 216)
1	UnappropriatedRetainedEarnings Balance-Beginning of Period		2,233,348,137	2,063,881,888
2	ChangesAbstract Changes
3	AdjustmentsToRetainedEarningsAbstract Adjustments to Retained Earnings (Account 439)
4	AdjustmentsToRetainedEarningsCreditAbstract Adjustments to Retained Earnings Credit
4.1	AdjustmentsToRetainedEarningsCredit CECL adoption of ASC 326			7,198
9	AdjustmentsToRetainedEarningsCredit TOTAL Credits to Retained Earnings (Acct. 439)			7,198
10	AdjustmentsToRetainedEarningsDebitAbstract Adjustments to Retained Earnings Debit
15	AdjustmentsToRetainedEarningsDebit TOTAL Debits to Retained Earnings (Acct. 439)
16	BalanceTransferredFromIncome Balance Transferred from Income (Account 433 less Account 418.1)		348,937,055	369,732,667
17	AppropriationsOfRetainedEarningsAbstract Appropriations of Retained Earnings (Acct. 436)
17.1	AppropriationsOfRetainedEarnings Appropriations of Retained Earnings (Acct. 436)		835,594	259,220
17.2	AppropriationsOfRetainedEarnings Excess Earnings on Hydro Licensed Projects
22	AppropriationsOfRetainedEarnings TOTAL Appropriations of Retained Earnings (Acct. 436)		835,594	259,220
23	DividendsDeclaredPreferredStockAbstract Dividends Declared-Preferred Stock (Account 437)
29	DividendsDeclaredPreferredStock TOTAL Dividends Declared-Preferred Stock (Acct. 437)
30	DividendsDeclaredCommonStockAbstract Dividends Declared-Common Stock (Account 438)
30.1	DividendsDeclaredCommonStock Common Stock		62,500,000	200,000,000
36	DividendsDeclaredCommonStock TOTAL Dividends Declared-Common Stock (Acct. 438)		62,500,000	200,000,000
37	TransfersFromUnappropriatedUndistributedSubsidiaryEarnings Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
38	UnappropriatedRetainedEarnings Balance - End of Period (Total 1,9,15,16,22,29,36,37)		2,518,949,598	2,233,348,137
39	AppropriatedRetainedEarningsAbstract APPROPRIATED RETAINED EARNINGS (Account 215)
45	AppropriatedRetainedEarnings TOTAL Appropriated Retained Earnings (Account 215)
	AppropriatedRetainedEarningsAmortizationReserveFederalAbstract APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)
46	AppropriatedRetainedEarningsAmortizationReserveFederal TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1)		19,085,984	18,250,390
47	AppropriatedRetainedEarningsIncludingReserveAmortization TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)		19,085,984	18,250,390
48	RetainedEarnings TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1)		2,538,035,582	2,251,598,527
	UnappropriatedUndistributedSubsidiaryEarningsAbstract UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account Report only on an Annual Basis, no Quarterly)
49	UnappropriatedUndistributedSubsidiaryEarnings Balance-Beginning of Year (Debit or Credit)		3,463,213	3,463,213
50	EquityInEarningsOfSubsidiaryCompanies Equity in Earnings for Year (Credit) (Account 418.1)
51	DividendsReceived (Less) Dividends Received (Debit)
52	ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits TOTAL other Changes in unappropriated undistributed subsidiary earnings for the year
53	UnappropriatedUndistributedSubsidiaryEarnings Balance-End of Year (Total lines 49 thru 52)		3,463,213	3,463,213

STATEMENT OF CASH FLOWS
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. 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. 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. 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.
Line No.	Description (See Instructions No.1 for explanation of codes) (a)	Current Year to Date Quarter/Year (b)	Previous Year to Date Quarter/Year (c)
1	NetCashFlowFromOperatingActivitiesAbstract Net Cash Flow from Operating Activities
2	NetIncomeLoss Net Income (Line 78(c) on page 117)	348,937,055	369,732,667
3	NoncashChargesCreditsToIncomeAbstract Noncash Charges (Credits) to Income:
4	DepreciationAndDepletion Depreciation and Depletion	546,425,093	553,599,980
5	NoncashAdjustmentsToCashFlowsFromOperatingActivities Amortization of (Specify) (footnote details)
5.1	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Amortization of Regulatory Debits and Credits	7,655,755	44,767,446
5.2	NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription Customer Deposits	3,895,830	7,977,923
8	DeferredIncomeTaxesNet Deferred Income Taxes (Net)	15,471,992	26,437,082
9	InvestmentTaxCreditAdjustmentsNet Investment Tax Credit Adjustment (Net)	11,857	183,576
10	NetIncreaseDecreaseInReceivablesOperatingActivities Net (Increase) Decrease in Receivables	79,468,006	9,498,073
11	NetIncreaseDecreaseInInventoryOperatingActivities Net (Increase) Decrease in Inventory	116,670,745	38,279,765
12	NetIncreaseDecreaseInAllowancesInventoryOperatingActivities Net (Increase) Decrease in Allowances Inventory	372,157	87,830
13	NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities Net Increase (Decrease) in Payables and Accrued Expenses	15,762,573	12,482,084
14	NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities Net (Increase) Decrease in Other Regulatory Assets	65,247,305	96,551,619
15	NetIncreaseDecreaseInOtherRegulatoryLiabilitiesOperatingActivities Net Increase (Decrease) in Other Regulatory Liabilities	28,775,303	12,022,095
16	AllowanceForOtherFundsUsedDuringConstructionOperatingActivities (Less) Allowance for Other Funds Used During Construction	15,567,699	14,619,304
17	UndistributedEarningsFromSubsidiaryCompaniesOperatingActivities (Less) Undistributed Earnings from Subsidiary Companies
18	OtherAdjustmentsToCashFlowsFromOperatingActivities Other (provide details in footnote):
18.1	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Other (provide details in footnote):	(a) 105,960,212	14,188,912
18.2	OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription Over/Under Recovered Fuel, net	195,996,845	37,245,483
22	NetCashFlowFromOperatingActivities Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 21)	613,178,605	707,702,272
24	CashFlowsFromInvestmentActivitiesAbstract Cash Flows from Investment Activities:
25	ConstructionAndAcquisitionOfPlantIncludingLandAbstract Construction and Acquisition of Plant (including land):
26	GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities Gross Additions to Utility Plant (less nuclear fuel)	859,309,687	784,634,596
27	GrossAdditionsToNuclearFuelInvestingActivities Gross Additions to Nuclear Fuel
28	GrossAdditionsToCommonUtilityPlantInvestingActivities Gross Additions to Common Utility Plant
29	GrossAdditionsToNonutilityPlantInvestingActivities Gross Additions to Nonutility Plant	10,598	21,477
30	AllowanceForOtherFundsUsedDuringConstructionInvestingActivities (Less) Allowance for Other Funds Used During Construction	15,567,699	14,619,304
31	OtherConstructionAndAcquisitionOfPlantInvestmentActivities Other (provide details in footnote):
31.1	OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription Other (provide details in footnote):
31.2	OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription Aquired Assets	684,622	771,426
34	CashOutflowsForPlant Cash Outflows for Plant (Total of lines 26 thru 33)	844,437,208	770,808,195
36	AcquisitionOfOtherNoncurrentAssets Acquisition of Other Noncurrent Assets (d)
37	ProceedsFromDisposalOfNoncurrentAssets Proceeds from Disposal of Noncurrent Assets (d)	(b) 6,497,418	6,935,976
39	InvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies Investments in and Advances to Assoc. and Subsidiary Companies
40	ContributionsAndAdvancesFromAssociatedAndSubsidiaryCompanies Contributions and Advances from Assoc. and Subsidiary Companies
41	DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompaniesAbstract Disposition of Investments in (and Advances to)
42	DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies Disposition of Investments in (and Advances to) Associated and Subsidiary Companies
44	PurchaseOfInvestmentSecurities Purchase of Investment Securities (a)
45	ProceedsFromSalesOfInvestmentSecurities Proceeds from Sales of Investment Securities (a)
46	LoansMadeOrPurchased Loans Made or Purchased
47	CollectionsOnLoans Collections on Loans
49	NetIncreaseDecreaseInReceivablesInvestingActivities Net (Increase) Decrease in Receivables
50	NetIncreaseDecreaseInInventoryInvestingActivities Net (Increase) Decrease in Inventory
51	NetIncreaseDecreaseInAllowancesHeldForSpeculationInvestingActivities Net (Increase) Decrease in Allowances Held for Speculation		43,494
52	NetIncreaseDecreaseInPayablesAndAccruedExpensesInvestingActivities Net Increase (Decrease) in Payables and Accrued Expenses
53	OtherAdjustmentsToCashFlowsFromInvestmentActivities Other (provide details in footnote):
53.1	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Other (provide details in footnote):	(c) 8,748,660	2,605,552
53.2	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription (Increase) Decrease in other special deposits	6,470,985	158,275
53.3	OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription Notes Receivable from Associated Companies
57	CashFlowsProvidedFromUsedInInvestmentActivities Net Cash Provided by (Used in) Investing Activities (Total of lines 34 thru 55)	835,662,115	761,064,898
59	CashFlowsFromFinancingActivitiesAbstract Cash Flows from Financing Activities:
60	ProceedsFromIssuanceAbstract Proceeds from Issuance of:
61	ProceedsFromIssuanceOfLongTermDebtFinancingActivities Long-Term Debt (b)	500,000,000	615,350,000
62	ProceedsFromIssuanceOfPreferredStockFinancingActivities Preferred Stock
63	ProceedsFromIssuanceOfCommonStockFinancingActivities Common Stock
64	OtherAdjustmentsToCashFlowsFromFinancingActivities Other (provide details in footnote):
64.1	OtherAdjustmentsToCashFlowsFromFinancingActivitiesDescription Other (provide details in footnote):
64.2	OtherAdjustmentsToCashFlowsFromFinancingActivitiesDescription Long-Term Issuance Costs	5,998,004	8,484,216
66	NetIncreaseInShortTermDebt Net Increase in Short-Term Debt (c)
67	OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Other (provide details in footnote):
67.1	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Proceeds on Capital Leaseback	741,069	741,695
67.2	DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities Notes Payable to Associates Companies	180,643,071
70	CashProvidedByOutsideSources Cash Provided by Outside Sources (Total 61 thru 69)	675,386,136	607,607,479
72	PaymentsForRetirementAbstract Payments for Retirement of:
73	PaymentsForRetirementOfLongTermDebtFinancingActivities Long-term Debt (b)	392,977,930	140,314,903
74	PaymentsForRetirementOfPreferredStockFinancingActivities Preferred Stock
75	PaymentsForRetirementOfCommonStockFinancingActivities Common Stock
76	OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities Other (provide details in footnote):
76.1	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Other (provide details in footnote):
76.2	DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities Notes Payable to Associates Companies		218,084,418
78	NetDecreaseInShortTermDebt Net Decrease in Short-Term Debt (c)
80	DividendsOnPreferredStock Dividends on Preferred Stock
81	DividendsOnCommonStock Dividends on Common Stock	62,500,000	200,000,000
83	CashFlowsProvidedFromUsedInFinancingActivities Net Cash Provided by (Used in) Financing Activities (Total of lines 70 thru 81)	219,908,206	49,208,159
85	NetIncreaseDecreaseInCashAndCashEquivalentsAbstract Net Increase (Decrease) in Cash and Cash Equivalents
86	NetIncreaseDecreaseInCashAndCashEquivalents Net Increase (Decrease) in Cash and Cash Equivalents (Total of line 22, 57 and 83)	2,575,304	4,154,468
88	CashAndCashEquivalents Cash and Cash Equivalents at Beginning of Period	22,677,565	26,832,033
90	CashAndCashEquivalents Cash and Cash Equivalents at End of Period	20,102,261	22,677,565

TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES
Report below the information called for concerning all non-power goods or services received from or provided to associated (affiliated) companies. 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". Where amounts billed to or received from the associated (affiliated) company are based on an allocation process, explain in a footnote.
Line No.	Description of the Good or Service (a)	Name of Associated/Affiliated Company (b)	Account(s) Charged or Credited (c)	Amount Charged or Credited (d)
1	Non-power Goods or Services Provided by Affiliated
2	Administrative and General Expenses - Maintenance	AEPSC	(a) 935	5,243,052
3	Distribution Expenses - Maintenance	AEPSC	590-598	1,513,942
4	Regulatory Services	AEPSC	920, 923	1,800,779
5	Administrative and General Expenses - Operation	AEPSC	920-923,925-926,928,930,931	4,529,118
6	Distribution Expenses - Maintenance	I&M	593,594,595	529,658
7	Real Estate & Workplace Svcs	AEPSC	920, 923	3,797,285
8	Audit Services	AEPSC	920,923	1,563,091
9	Distribution Expenses - Maintenance	KgPCo	590, 593-598	933,610
10	Physical & Cyber Security	AEPSC	920, 923	1,611,607
11	Bus Ops & Perf Assurance	AEPSC	920,923	1,817,542
12	Distribution Expenses - Maintenance	OPCo	593-596	1,749,030
13	Other Power Supply Expenses	AEPSC	556, 557	7,073,149
14	Civil & Political Activities and Other Svcs	AEPSC	426	1,319,132
15	Factored AR	AEP Credit Inc.	426.5	2,406,043
16	Construction Services	AEPSC	107, 108	144,023,051
17	Distribution Expenses - Operation	AEPSC	580-586, 588	5,014,791
18	Materials and Supplies	KgPCo	107,163, 426,592-594,588,903,930	586,659
19	Construction Services	I&M	107, 108	729,672
20	Distribution Expenses - Operation	KgPCo	580,583,586-588	300,184
21	Barging	I&M	151	40,129,351
22	Construction Services	KgPCo	107, 108	2,077,631
23	Environmental Services	AEPSC	920, 923	836,885
24	Materials and Supplies	OPCo	107,108,163,184,186,562,563,566,569-571,592,593,921,930,935	6,376,213
25	Construction Services	OPCo	107, 108	1,809,573
26	Urea	KPCo	154	964,517
27	Materials and Supplies	KPCo	107,502,511-514,592,930,935	251,959
28	Corp Safety & Health	AEPSC	920,923	1,812,019
29	Treasury & Risk	AEPSC	920, 923	2,284,779
30	Materials and Supplies	I&M	107,186,502,511-514,570,571,592,935	561,541
31	Corporate Accounting	AEPSC	920,923	3,206,310
32	Transmission Expenses - Operation	AEPSC	560,561-564,566-567, 920, 923	21,375,898
33	Legal GC/Administration	AEPSC	920, 923	8,423,789
34	Corporate Communications	AEPSC	920, 923	1,394,259
35	Transmission Expenses - Maintenance	AEPSC	568-573	6,042,635
36	Infrastructure Ops & Support	AEPSC	920, 923	1,340,290
37	Corporate Human Resources	AEPSC	920,923	4,131,452
38	Tax Services	AEPSC	920,923	1,295,235
39	Information Technology	AEPSC	920, 923	11,140,939
40	Corporate Planning & Budgeting	AEPSC	920, 923	2,019,177
41	Strategy & Transformation	AEPSC	920, 923	1,227,454
42	Hydraulic Power Generation - Maintenance	AEPSC	541-545	994,943
43	Customer Accounts Expenses	AEPSC	901-905	16,766,026
44	Steam Power Generation - Operation	AEPSC	500-502,506	17,954,930
45	Hydraulic Power Generation - Operation	AEPSC	535,537-539	3,586,934
46	Customer Accounts Expenses	KgPCo	902, 903	273,344
47	Steam Power Generation - Maintenance	AEPSC	510-514	5,674,767
48	Grid Solutions	AEPSC	920, 923	1,152,480
49	Customer Service and Informational Expenses	AEPSC	(b) 907,908,910	418,595
50	Other Operating Revenues	OPCo	456	1,078,555
51	Fuel & Storeroom Services	AEPSC	152,163	11,559,394
52	Customer Support	AEPSC	920, 923	2,262,305
53	Research and Other Services	AEPSC	183, 184, 186, 188	6,590,121
54	Factored Customer A/R Bad Debts	AEP Credit Inc.	426.5	4,600,616
19
20	Non-power Goods or Services Provided for Affiliated
21	Building and Property Leases	AEPSC	454	3,974,794
22	Fleet and Vehicle Charges	AEPSC	103	4,103,749
23	Expenses of Nonutility Operations	I&M	417	5,016,568
24	Materials and Supplies	KPCo	154	310,746
25	Facility Rent	WVTCo	(c) 454, 567	2,610,035
26	O&M Services for Jointly Owned Facility - Sporn	AEP Generation Resources	108,186,408.1,500,506,920,921,923,925,926,931	302,950
27	Other Operating Revenues	I&M	(d) 456	305,346
28	Other Operating Revenues	OPCo	(e) 456	923,114
29	Other Operating Revenues	PSO	(f) 456	341,076
30	Urea	KPCo	154	1,367,952
31	Use of Jointly Owned Facility	APTCo	454	1,963,379
32	Use of Jointly Owned Facility	WVTCo	(g) 454	399,449
33	Administrative and General Expenses - Maintenance	KPCo	935	291,189
34	Central Machine Shop	I&M	107,108,163,500,506	2,352,794
35	Central Machine Shop	KPCo	592,107,108,500,506,000	972,875
36	Central Machine Shop	OPCo	107,108,592.00	367,854
37	Central Machine Shop	PSO	107,108,512,514,532,000	738,638
38	Central Machine Shop	SWEPCo	107,108,502,512,514,	2,683,567
39	Construction Services	KgPCo	107,108	924,571
40	Construction Services	KgPCo	107,108	583,838
41	Construction Services	OPCo	107,108	259,364
42	Construction Services	WPCo	107,108	648,264
43	Construction Services	WVTCo	107	908,736
44	Distribution Expenses - Maintenance	KgPCo	593,595,597,598	303,524
45	Distribution Expenses - Maintenance	WPCo	593,595,598	350,257
42

FERC FINANCIAL REPORT FERC FORM No. 1: Annual Report of Major Electric Utilities, Licensees and Others and Supplemental Form 3-Q: Quarterly Financial Report

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

GENERAL INFORMATION

Purpose

Who Must Submit

What and Where to Submit

When to Submit

Where to Send Comments on Public Reporting Burden.

GENERAL INSTRUCTIONS

EXCERPTS FROM THE LAW

GENERAL PENALTIES

FERC FINANCIAL REPORT
FERC FORM No. 1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report